Clean Coal TechnologyDemonstration ProgramProgram Update 2001Includes Power Plant Improvement InitiatAs of September 2001

U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

July 2002
U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

Clean Coal TechnologyDemonstration ProgramProgram Update 2001Includes Power Plant Improvement InitiatAs of September 2001

July 2002
This report has been reproduced directly from the best available copy.

Available to DOE and DOE contractors from the Office of Scientific and Technical InformatioP.O. Box 62, Oak Ridge, Tennessee 37831; prices available from (615) 576-8401. http://wwwAvailable to the public from the National Technical Information Service, U.S. Department of C5285 Port Royal Rd., Springfield, Virginia 22161. http://www.ntis.gov

For further information about this publication or related U.S. DOE programs pVictor K. DerProduct Line DirectorPower SystemsU.S. Department of EnergyFE-22/Germantown Building1000 Independence Ave. S.W.Washington DC 20585-1290(301) 903-2700

DPFUF1W(

Comments, corrections, or contributive information may be directed to:Program Updatec/o Gene H. KightSr. Financial & Procurement DirectorU.S. Department of EnergyFE-20/Germantown Building1000 Independence Ave. S.W.Washington DC 20585-1290(301) 903-2624(301) 903-9301 (fax)gene.kight@hq.doe.gov

David J. BeecyProduct Line DirectorEnvironmental SystemsU.S. Department of EnergyFE-23/Germantown Building1000 Independence Ave. S.W.Washington DC 20585-1290(301) 903-2787
Preface

The Clean Coal Technology DemonstrationProgram: Program Update 2001 (ProgramUpdate 2001) not only presents the Clean CoalTechnology Demonstration Program (CCTProgram) and associated progress and accomplishments, but now includes the Power PlantInitiative (PPII) as well. Arising out of thePresident's National Energy Policy, PPII wasestablished by Congress in fiscal year 2001 tofurther improve the efficiency, reliability, andenvironmental performance of coal-based powergeneration. As directed by Congress, the Department of Energy (DOE) is applying the basicprinciples of the CCT Program to PPII, includingforging the cost-shared industry/governmentpartnerships needed to effectively demonstratepromising new clean coal technologies and bringthem into the market place.With 30 of the 38 active CCT Program projectshaving completed operations, the CCT Programhas yielded clean coal technologies that arecapable of meeting existing and emerging environmental regulations and competing in a changing electric power marketplace. As usual, factsheets for all of these projects are included withfour-page summaries for the completed projectsand two-page summaries for the ongoing projects.For existing power plants, there are cost-effectiveenvironmental control devices to control sulfurdioxide, nitrogen oxides, and particulate matter.Also ready are a new generation of technologiesthat can produce electricity and other commodities, such as clean fuels and chemicals, and

provide the efficiencies and environmentalperformance responsive to global climate changeconcerns. The CCT Program took a pollutionprevention approach as well, demonstratingtechnologies that produce clean coal-based solidand liquid fuels by removing pollutants or theirprecursors before being burned. Lastly, newtechnologies were introduced into the major coalusing industries to enhance environmentalperformance. Thanks in part to the CCT Program,coal—abundant, secure, and economical—cancontinue in its role as a key component in theU.S. and world energy markets.Building upon the successes of the CCT Programand serving as a bridge to future initiatives, PPIIwas established by Congress for the commercialscale demonstration of technologies to assure thereliability of the nation’s energy supply fromexisting and new electric coal-based generatingfacilities. The single solicitation required participants to offer significant improvements in powerplant performance leading to enhanced electricreliability. The Department of Energy selectedeight PPII projects out of 24 proposals. Two-pagefact sheets for these eight projects are nowincluded in the Program Update 2001.
Program Update 2001 Evaluation

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Executive Summary 012345Section 1. Role of the CCT Program 012345Section 2. CCT Program Implementation 012345Section 3. CCT Program Funding and Costs 012345Section 4. CCT Program Accomplishments 012345Section 5. CCT Program Projects 012345Section 6. PPII Initiative 012345Appendix A. Historical Perspective and Legislative History 012345Appendix B. CCT Program History 012345Appendix C. CCT Program Environmental Aspects 012345Appendix D. Project Contacts 012345Appendix E. Acronyms, Abbreviations, and Symbols 012345What do you find is the best and most effective part of the Program Update?

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ContentsExecutive Summary Introduction ES-1

Role of the CCT Program ES-2

Program Implementation ES-4

Funding and Costs ES-5CCT Program Accomplishments ES-6CCT Projects ES-17PPII Projects ES-21Introduction 1-1CCT Program Evolution 1-2Environmental Impetus 1-3

SO2 Regulation 1-3NO

x Regulation 1-4

Hazardous Air Pollutants 1-6Global Climate Change 1-7Regional Haze 1-7Solid Waste 1-7Toxics Release Inventory 1-7

Market Considerations 1-7Ensuring Sustainable Economic Growth 1-8Looking to the Future 1-10

Power Plant Improvement Initiative 1-10Clean Coal Power Initiative 1-10Vision 21 1-10

Introduction 2-1Implementation Principles 2-1Implementation Process 2-2Commitment to Commercial Realization 2-4

Section 1. Role of the CCT ProgramSection 2. CCT Program Implementation
ii Program Update 2001

Solicitation Results 2-5Future Implementation Direction 2-12Introduction 3-1Program Funding 3-1

General Provisions 3-1Availability of Funding 3-2Use of Appropriated Funds 3-2Project Funding, Costs, and Schedules 3-4

Cost-Sharing 3-4Recovery of Government Outlays (Recoupment) 3-10Introduction 4-1Fossil Energy R&D Benefits 4-1Marketplace Commitment 4-3

Factors Impacting Domestic Commercialization 4-4Environmental Control Devices 4-4Advanced Electric Power Generation 4-8Coal Processing for Clean Fuels 4-11Industrial Applications 4-11Awards 4-14

Market Communications—Outreach 4-14

Information Sources 4-14Publications Issued in FY2001 4-16Information Access 4-17Information Dissemination and Feedback 4-17Conferences and Workshops Held in FY2001 4-18Trade Mission Activities in FY2001 4-20

Introduction 5-1Technology Overview 5-2

Section 3. CCT Program Funding and CostsSection 4. CCT Program Accomplishments

Section 5. CCT Program Projects

Section 2. CCT Program Implementation(continued)
Environmental Control Devices 5-2Advanced Electric Power Generation Technology 5-5Coal Processing for Clean Fuels Technology 5-9Industrial Applications Technology 5-11

Project Fact Sheets 5-11

Environmental Control Devices 5-21

SO2 Control Technologies 5-21

NO

x Control Technologies 5-43

Combined SO2/NOx Control Technologies 5-73

Advanced Electric Power Generation 5-99

Fluidized-Bed Combustion 5-99Integrated Gasification Combined-Cycle 5-115Advanced Combustion/Heat Engines 5-131

Coal Processing for Clean Fuels 5-139Industrial Applications 5-155

Role of the PPII Program 6-1Program Implementation 6-1

Introduction 6-1PPII Solicitation 6-1Intellectual Property Rights 6-3Environmental Provisions 6-3

PPII Funding and Costs 6-3PPII Accomplishments 6-3PPII Projects 6-3PPII Fact Sheets 6-7CCT Historical Perspective A-1CCT Legislative History A-2PPII Historical Perspective A-3PPII Legislative History A-9

Section 5. CCT Program Projects (continued)

Section 6. Power Plant Improvement Initiative

Appendix A. Historical Perspective andLegislative History
iv Program Update 2001

Solicitation History B-1Selection and Negotiation History B-1Introduction C-1The Role of NEPA in the CCT Program C-2Compliance with NEPA C-2

Categorical Exclusions C-2Memoranda-to-File C-2Environmental Assessments C-2Environmental Impact Statements C-5

NEPA Actions in Progress C-5

Environmental Monitoring C-6Air Toxics C-6Project Contacts D-1CCT Program Environmental Control Devices D-1CCT Program Advanced Electric Power Generation D-4CCT Program Coal Processing for Clean Fuels D-6CCT Program Industrial Applications D-7PPII Projects D-8Acronyms, Abbreviations, and Symbols E-1State Abbreviations E-4Other E-4Index Index-1

Appendix E. Acronyms, Abbreviations,and Symbols

Index of Projects and Participants

Appendix C. CCT Program EnvironmentalAspectsAppendix D. Project ContactsAppendix B. CCT Program History
Exhibits

Completed Projects by Application Category ES-6Summary of Results of Completed Environmental Control Technology Projects ECommercial Successes—Environmental Control Technologies ES-12Summary of Results of Completed Advanced Electric Power Generation Projects Commercial Successes—Advanced Electric Power Generation Technologies ESSummary of Results of Completed Coal Processing for Clean Fuels Projects ES-Commercial Successes—Coal Processing for Clean Fuels Technologies ES-19Summary of Results of Completed Industrial Application Projects ES-20Commercial Successes—Industrial Application Technologies ES-20Project Fact Sheets by Application Category ES-21Award-Winning CCT Projects ES-23PPII Technology Characteristics ES-24Phase I SO2 Compliance Methods 1-3CAAA NO

x

 Emission Limits 1-4

Comparison of Energy Projections for Electric Generators 1-9Vision 21 Objectives 1-11CCT Program Selection Process Summary 2-5Clean Coal Technology Demonstration Projects by Solicitation 2-6Geographic Locations of CCT Projects—Environmental Control Devices 2-8Geographic Locations of CCT Projects—Advanced Electric Power Generation 2Geographic Locations of CCT Projects—Coal Processing for Clean Fuels 2-10Geographic Locations of CCT Projects—Industrial Applications 2-11CCT Project Costs and Cost-Sharing 3-1Relationship between Appropriations and Subprogram Budgets for the CCT ProgAnnual CCT Program Funding by Appropriations and Subprogram Budgets 3-3

Section 2. CCT Program ImplementationExecutive SummarySection 1. Role of the CCT ProgramSection 3. CCT Program Funding and Costs
vi Program Update 2001

CCT Financial Projections as of September 30, 2001 3-4Financial Status of the CCT Program as of September 30, 2001 3-5CCT Project Schedules by Application Category 3-6CCT Project Funding by Application Category 3-8National Research Council Conclusions on Fossil Energy Research 4-2Commercial Successes—SO2 Control Technology 4-6

Commercial Successes—NO

x Control Technology 4-7

Commercial Successes—Combined SO2/NOx Control Technology 4-9Commercial Successes—Advanced Electric Power Generation 4-12Commercial Successes—Coal Processing for Clean Fuels 4-13Commercial Successes—Industrial Applications 4-14Award-Winning CCT Program Projects 4-15How to Obtain CCT Program Information 4-16CCT Program SO2 Control Technology Characteristics 5-3

Group 1 and 2 Boiler Statistics and Phase II NOx Emission Limits 5-4

CCT Program NOx Control Technology Characteristics 5-6CCT Program Combined SO2/NOx Control Technology Characteristics 5-7CCT Program Advanced Electric Power Generation Technology Characteristics 5CCT Program Coal Processing for Clean Fuels Technology Characteristics 5-12CCT Program Industrial Applications Technology Characteristics 5-13Project Fact Sheets by Application Category 5-15Project Fact Sheets by Participant 5-17Key to Milestone Charts in Fact Sheets 5-19Variables and Levels Used in GSA Factorial Testing 5-24GSA Factorial Testing Results 5-24Pure Air SO2 Removal Performance 5-36

Estimated Costs for an AFGD System 5-37Flue Gas Desulfurization Economics 5-37

Section 5. CCT Program ProjectsSection 4. CCT Program AccomplishmentsSection 3. CCT Program Funding and Costs(continued)
Section 5. CCT Program Projects (continued) Operation of CT-121 Scrubber 5-40

SO2 Removal Efficiency 5-40

CT-121 Particulate Capture Performance 5-41CT-121 Air Toxics Removal 5-41LOI Performance Test Results 5-46NO

x

 vs. LOI Tests—All Sensitivities 5-46

Typical Trade-Offs in Boiler Optimization 5-46Major Elements of GNOCIS 5-47Coal Reburning Test Results 5-50Coal Reburning Economics 5-51NO

x Data from Cherokee Station, Unit No. 3 5-58

Reactor Baseline Conditions 5-66Catalysts Tested 5-66Average SO2 Oxidation Rate 5-66

SCR Design Criteria 5-67SCR Economics by Unit Size 5-67SCR Economics by NOx Removal 5-67

LNCFSTM Configurations 5-70Concentric Firing Concept 5-70Unit Performance Impacts Based on Long-Term Testing 5-71Average Annual NOx Emissions and Percent Reduction 5-71

LIMB SO2 Removal Efficiencies 5-80

LIMB Capital Cost Comparison 5-81LIMB Annual Levelized Cost Comparison 5-81Effect of Limestone Grind 5-92Pressure Drop vs. Countercurrent Headers 5-92Effect of Bed Temperature on Ca/S Requirement 5-112Calcium Requirements and Sulfur Retentions for Various Fuels 5-113Wabash Thermal Performance Summary 5-129
viii Program Update 2001

Wabash River Coal Gasification Repowering Project Production Statistics 5-129Healy Performance Goals and Demonstration Test Program Results 5-136Healy SDA Performance Test Results and Performance Guarantees 5-137ENCOAL Production 5-148ACCP Annual Production Rates 5-152ACCP Stack Emissions Survey 5-153Summary of Emissions and Removal Efficiencies 5-168Tube Pulse Heater Test — Partial Summary 5-172Geographic Locations of PPII Projects 6-2PPII Technology Characteristics 6-4PPII Project Fact Sheets by Project Name 6-5PPII Project Fact Sheets by Participant 6-6Key to Milestone Charts in Fact Sheets 6-6CCT Program Legislative History A-4PPII Legislative History A-10NEPA Reviews Completed as of September 30, 2001 C-1Memoranda-to-File Completed C-3Environmental Assessments Completed as of September 30, 2001 C-4Environmental Impact Statements Completed as of September 30, 2001 C-5NEPA Reviews in Progress as of September 30, 2001 C-5Status of Environmental Monitoring Plans for CCT Projects as of September 30, 2Status of CCT Projects Monitoring Hazardous Air Pollutants as of September 30, 2

Appendix A. Historical Perspective andLegislative HistorySection 5. CCT Program Projects (continued)Section 6. Power Plant Improvement InitiativeAppendix C. CCT Program EnvironmentalAspects
CCT Program Environmental Control DevicesProject Fact Sheets by Application Categ

SO2 Control Technologies10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) 5-22Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Co

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC-North Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the LakDemonstration of Innovative Applications of Technology for the CT-121 FGD P(Southern Company Services, Inc.) 5-38NO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler(Southern Company Services, Inc.) 5-44Demonstration of Coal Reburning for Cyclone Boiler NOx Control (The BabcocFull-Scale Demonstration of Low-NO

x Cell Burner Retrofit (The Babcock & Wi

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler(Energy and Environmental Research Corporation) 5-56Micronized Coal Reburning Demonstration for NOx Control (New York State El

Demonstration of Selective Catalytic Reduction Technology for the Control of N

Coal-Fired Boilers (Southern Company Services, Inc.) 5-64180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniqu

Emissions from Coal-Fired Boilers (Southern Company Services, Inc.) 5-68Combined SO2/NOx Control Technologies

SNOXô Flue Gas Cleaning Demonstration Project (ABB Environmental SystemLIMB Demonstration Project Extension and Coolside Demonstration (The Babc

SOx-NOx-Rox Boxô Flue Gas Cleanup Demonstration Project (The Babcock & Enhancing the Use of Coals by Gas Reburning and Sorbent Injection(Energy and Environmental Research Corporation) 5-86Milliken Clean Coal Technology Demonstration Project (New York State ElectrIntegrated Dry NOx/SO2 Emissions Control System (Public Service Company of 
x Program Update 2001

Fluidized-Bed CombustionMcIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland ElecMcIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, LakelJEA Large-Scale CFB Combustion Demonstration Project (JEA) 5-104Tidd PFBC Demonstration Project (The Ohio Power Company) 5-106Nucla CFB Demonstration Project (Tri-State Generation and Transmission AssocIntegrated Gasification Combined-CycleKentucky Pioneer IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Piñon Pine IGCC Power Project (Sierra Pacific Power Company) 5-122Wabash River Coal Gasification Repowering Project (Wabash River Coal GasificVenture) 5-126Advanced Combustion/Heat EnginesClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) 5-132Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) PrPhase Conversion Company, L.P.) 5-140Development of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc., ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) 5-146

Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) 5-15Clean Power from Integrated Coal/Ore Reduction (CPICORTM)(CPICORTM Management Company, LLC) 5-156Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem 

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (CCement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) 5-166Pulse Combustor Design Qualification Test (ThermoChem, Inc.) 5-170Achieving New Source Performance Standards Emission Standards Through Integ

with an Optimization Plan for Boiler Combustion (Sunflower Electric Power CorpBig Bend Power Station Neural Network-Sootblower Optimization (Tampa Electri

CCT Program Advanced Electric PowerGenerationCCT Program Coal Processing for CleanFuelsCCT Program Industrial ApplicationsPower Plant Improvement Initiative
Power Plant Improvement Initiative(continued)

Combustion Initiative for Innovative Cost-Effective NO

x Reduction (Alliant Energ

Commercial Demonstration of the Manufactured Aggregate Processing TechnologSpray Dryer Ash (Universal Aggregates, LLC) 6-22Demonstration of a Full-Scale Retrofit of the Advanced Hybrid Particulate Collect(Otter Tail Power Company) 6-14Development of Hybrid FLGR/SNCR/SCR Advanced NOx Control for Orion Avo

(Arthur D. Little, Inc.) 6-10Greenidge Multi-Pollutant Control Project (CONSOL Energy, Inc.) 6-12Polk Power Station Plant Improvement Project (Tampa Electric Company) 6-18
xii Program Update 2001

ABB Combustion Engineering, Inc., and CQ Inc. (Development of the Coal Quality Expertô) 5-142ABB Environmental Systems (SNOXô Flue Gas Cleaning Demonstration Project) 5-74Air Products Liquid Phase Conversion Company, L.P. (Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHô) ProceAirPol, Inc. (10-MWe Demonstration of Gas Suspension Absorption) 5-22Alaska Industrial Development and Export Authority (Healy Clean Coal Project) 5-134Alliant Energy Corporate Services, Inc. (Combustion Initiative for Innovative Cost-Effective NOx Reduction) 6-8

Arthur D. Little, Inc. (Clean Coal Diesel Demonstration Project) 5-132Arthur D. Little, Inc. (Development of Hybrid FLGR/SNCR/SCR Advanced NOx Control for Orion Avon Lake Unit 9) 6-10

Babcock & Wilcox Company, The (Demonstration of Coal Reburning for Cyclone Boiler NOx Control) 5-48

Babcock & Wilcox Company, The (Full-Scale Demonstration of Low-NOx Cell Burner Retrofit) 5-52

Babcock & Wilcox Company, The (LIMB Demonstration Project Extension and Coolside Demonstration) 5-78Babcock & Wilcox Company, The (SOx-NOx-Rox Boxô Flue Gas Cleanup Demonstration Project) 5-82Bechtel Corporation (Confined Zone Dispersion Flue Gas Desulfurization Demonstration) 5-26Bethlehem Steel Corporation (Blast Furnace Granular-Coal Injection System Demonstration Project) 5-158Coal Tech Corporation (Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control) 5-162CONSOL Energy, Inc. (Greenidge Multi-Pollutant Control Project) 6-12CPICORô Management Company, LLC (Clean Power from Integrated Coal/Ore Reduction (CPICORô) 5-156CQ Inc. (see ABB Combustion Engineering and CQ Inc.)ENCOAL Corporation (ENCOALÆ Mild Coal Gasification Project) 5-142

Energy and Environmental Research Corporation (Enhancing the Use of Coals by Gas Reburning and Sorbent Injection) 5-86Energy and Environmental Research Corporation (Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler) 5-56

JEA (JEA Large-Scale CFB Combustion Demonstration Project) 5-104Kentucky Pioneer Energy, LLC (Kentucky Pioneer IGCC Demonstration Project) 5-116Lakeland, City of, Lakeland Electric (McIntosh Unit 4A PCFB Demonstration Project) 5-100Lakeland, City of, Lakeland Electric (McIntosh Unit 4B Topped PCFB Demonstration Project) 5-102LIFAC-North America (LIFAC Sorbent Injection Desulfurization Demonstration Project) 5-30New York State Electric & Gas Corporation (Micronized Coal Reburning Demonstration for NOx Control) 5-60

Project Fact Sheets by Participant
New York State Electric & Gas Corporation (Milliken Clean Coal Technology Demonstration Project) 5-90Ohio Power Company, The (Tidd PFBC Demonstration Project) 5-106Otter Tail Power Company (Demonstration of a Full-Scale Retrofit of the Advanced Hybrid Particulate Collector Technology) 6-14Passamaquoddy Tribe (Cement Kiln Flue Gas Recovery Scrubber) 5-166Public Service Company of Colorado (Integrated Dry NOx/SO2 Emissions Control System) 5-94

Pure Air on the Lake, L.P. (Advanced Flue Gas Desulfurization Demonstration Project) 5-34Sierra Pacific Power Company (Piñon Pine IGCC Power Project) 5-122Southern Company Services, Inc. (Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler) 5-44Southern Company Services, Inc. (Demonstration of Innovative Applications of Technology for the CT-121 FGD Process) 5-38Southern Company Services, Inc. (Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High

Boilers) 5-64Southern Company Services, Inc. (180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of 

Fired Boilers) 5-68Sunflower Electric Power Corp. (Achieving New Source Performance Standards Emission Standards Through Integration of Low-NOx BurnPlan for Boiler Combustion) 6-16Tampa Electric Company (Polk Power Station Plant Improvement Project) 6-18Tampa Electric Company (Big Bend Power Station Neural Network-Sootblower Optimization) 6-20Tampa Electric Company (Tampa Electric Integrated Gasification Combined-Cycle Project) 5-118ThermoChem, Inc. (Pulse Combustor Design Qualification Test) 5-170Tri-State Generation and Transmission Association, Inc. (Nucla CFB Demonstration Project) 5-110Universal Aggregates, LLC (Commercial Demonstration of the Manufactured Aggregate Processing Technology Utilizing Spray Dryer Ash) Wabash River Coal Gasification Repowering Project Joint Venture (Wabash River Coal Gasification Repowering Project) 5-126Western SynCoal LLC (Advanced Coal Conversion Process Demonstration) 5-150
xiv Program Update 2001
IntroductionThe Clean Coal Technology Demonstration Program:Program Update 2001 (Program Update 2001) notonly presents the Clean Coal Technology Demonstration Program (CCT Program) and associated progressand accomplishments, but now includes the PowerPlant Improvement Initiative (PPII) as well. Buildingupon the successes of the CCT Program, PPII projectswill advance technologies to assure reliability of thenationís energy supply.CCT Program. The CCT Program, a model ofgovernment and industry cooperation, advances theDepartment of Energyís (DOE) mission to foster asecure and reliable energy system that is environmentally and economically sustainable. With 30 of the 38active projects having completed operations, the CCTProgram has yielded clean coal technologies (CCTs)that are capable of meeting existing and emergingenvironmental regulations and competing in a deregulated electric power marketplace.The CCT Program is providing a portfolio of technologies that will assure that the U.S. recoverable coalreserves of 274 billion tons can continue to supply thenationís energy needs economically and in an environmentally sound manner. At the dawn of the 21st century,

many of the clean coal technologies have realizedcommercial application. Industry now stands ready torespond to the energy and environmental demands ofthe new century, both domestically and internationally.For existing power plants, there are cost-effectiveenvironmental control devices to control sulfur dioxide(SO2), nitrogen oxides (NOx), and particulate matter

(PM). Also ready are a new generation of technologiesthat can produce electricity and other commodities,Executive Summary

such as steam and synthetic gas, and provide theefficiencies and environmental performance responsiveto global climate change concerns. The CCT Programtook a pollution prevention approach as well, demonstrating technologies that produce clean coal-basedsolid and liquid fuels by removing pollutants or theirprecursors before being burned. Lastly, new technologies were introduced into the major coal-using industries to enhance environmental performance. Thanks inpart to the CCT Program, coalóabundant, secure, andeconomicalócan continue in its role as a key component in the U.S. and world energy markets.CCT Program Major Accomplishments. In fiscalyear 2001, the Tampa Electric Integrated GasificationCombined-Cycle Project, the PiÒon Pine IGCC PowerProject, the Advanced Coal Conversion ProcessDemonstration, and the Pulse Combustor DesignQualification Test completed demonstration operations.The Tampa Electric Integrated Gasification CombinedCycle Project successfully demonstrated an advancedintegrated gasification combined-cycle (IGCC) systemusing Texacoís pressurized, oxygen-blown, entrainedflow gasifier technology. The project ran for four years,providing valuable data for commercializing thetechnology in the United States and abroad. Theproject received five national and state awards forexcellence.The PiÒon Pine IGCC Power Project, using KRWís airblown, pressurized fluidized-bed gasification system,provided valuable ìlessons learnedî data that willassist the next generation of plants to improve reliability, availability, and maintainability, while the IGCCplant did not proceed into commercial service, theproject succeeded in identifying and working through anumber of issues, which were only identifiable throughfull-scale system demonstration. The lessons learnedpositioned the technology for commercialization.

Tidd PFBC Demonstration Company)ó1991 Powerpmagazine.Tampa Electric Integrated Project (Tampa Electric Cpresented by Power maga
ES-2 Program Update 2001

The Advanced Coal Conversion Process Demonstration successfully produced SynCoal®—a coal product

having moisture content as low as 1 percent, sulfurcontent as low as 0.3 percent, and a heating value up to12,000 Btu/lb—from subbituminous coals and lignite.The project also advanced the understanding ofproduct stability for these types of coal products.The Pulse Combustor Design Qualification Testdemonstrated the Pulsed EnhancedTM Steam ReformingProcess using a multiple resonance-tube combustor.The technology has application in a wide variety ofpower generation and industrial applications.Final reports were issued and the following projectsclosed out:• Piñon Pine IGCC Power Project, and• Healy Clean Coal Project.Throughout the year, the CCT Program staff participated in over a dozen domestic and international eventsinvolving users and vendors of clean coal technologies,regulators, financiers, environmental groups, and otherpublic and private institutions. Four issues of the CleanCoal Today newsletter were published in the sameperiod, along with the sixth annual edition of the CleanCoal Today Index, which cross-references all articlespublished in the newsletter. Two 12-page ProjectPerformance Summary documents were issued—Demonstration of Advanced Combustion NOx Control

Techniques for a Wall-Fired Boiler and the Evaluationof Gas Reburning and Low-NOx Burners on a WallFired Boiler. Clean Coal Technology Topical Reports

were issued during the fiscal year for the Environmental Benefits of Clean Coal Technologies; The WabashRiver Coal Gasification Project—An Update; andCoproduction of Power, Fuels, and Chemicals. Also,DOE continued coverage of the program by publishingthe Clean Coal Technology Demonstration Program:Program Update 2000.These accomplishments and more are described infurther detail in this Clean Coal Technology Demonstration Program: Program Update 2001. In sum, the

CCT Program is continuing to yield advances in coaltechnologies and thus ensures that the nation’s mostabundant fossil energy resource will serve to meet theenergy needs of the United States while satisfyingnational environmental objectives.PPII. Fiscal year 2001 saw the start of a new initiativeto build upon the successes of the CCT Program and toserve as the bridge to future initiatives. The PowerPlant Improvement Initiative was established byCongress in Public Law 106-291, Department ofInterior and Related Agencies Appropriations Act,2001. The act provided for DOE to request proposalsfor the commercial scale demonstration of technologiesto assure the reliability of the nation’s energy supplyfrom existing and new electric generating facilities.The initiative arose from the brownouts and blackoutsof 1999 and 2000 in California and elsewhere. Thesingle solicitation required participants to offersignificant improvements in power plant performanceleading to enhanced electric reliability.PPII Major Accomplishments. The Department of

Energy developed a PPII solicitation, incorporatinggeneral provisions of the CCT Program (per congressional direction) with so

account lessons learned program solicitation was and 24 proposals were reSeptember 28, 2001, a toover $110 million were sRole of the CCT Program Evolutiopercent of the proven foUnited States and supplireliable electricity vital tglobal competitiveness. nation’s electricity was pprojections by the U.S. E(EIA) predict that coal welectric power productiothe 21st century. Howeve

coal resources in an envimanner.The CCT Program was ecommercial feasibility odemand for a new genertechnologies characterizeconomic, and environmsolicitation (CCT-I) for broad range of projects bproduct markets—enviroadvanced electric power for clean fuels, and induThe second solicitation (piece for satisfying the rthe Joint Report of the S(1986). The goal was to could achieve significanprecursors of acid rain, n

Demonstration of Innovative Applications of Technology forthe CT-121 FGD Process Project (Southern CompanyServices, Inc.)—1994 Powerplant Award presented by Powermagazine.
solicitation (CCT-III) furthered the goal of CCT-II andadded technologies that could produce clean fuel fromrun-of-mine coal.The fourth and fifth solicitations (CCT-IV and CCT-V,respectively) recognized emerging energy and environmental issues, such as global climate change andcapping SO2 emissions, and thus focused on technologies that were capable of addressing these issues. CCTIV called for energy efficient, economically competitive technologies capable of retrofitting, repowering, orreplacing existing facilities, while at the same timesignificantly reducing SO2 and NOx emissions. CCT-Vfocused on technologies applicable to new or existingfacilities that could significantly improve efficiencyand environmental performance.Environmental Impetus. Even before enactment ofthe Clean Air Act Amendments of 1990 (CAAA), theCCT Program was cognizant of the changes in electricpower generation that would likely be caused by thestatute. Several projects in the CCT Program wereimplemented at units designated as Phase I units inTitle IV of the CAAA, which were required to meetSO2 reductions by January 1, 1995. The CCT Programprojects at Phase I units successfully reduced SO2emissions using advanced flue gas desulfurization(AFGD) and repowering with integrated gasificationcombined-cycle. With the January 1, 2000, Phase IITitle IV CAAA provisions in effect, the CCTProgram’s portfolio of technologies helped industrymeet the more stringent SO2 emission limits. While SO2credits are being used to meet short-term goals, EIApredicts 11 GWe of capacity will be retrofitted withscrubbers to meet Phase II goals. Furthermore, theseSO2 reduction technologies may be important inmeeting new requirements for PM2.5 (particulate matter2.5 microns and smaller in diameter) because someairborne sulfur species are in this size range.In addition to SO2 reductions, Title IV also called forreductions in NOx emissions. Phase I of the NOxprovisions of Title IV requires reductions from the socalled Group 1 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 NOx emission standards. Under Phase II, EPA established NOx emission limitations for Group 2 boilers and further limited emissions for Group 1 boilers. Group 2 boilers include cell-burner, cyclone, wet-bottom wall-fired, and vertically fired boilers. The CCT Program has demonstrated NOx emission control techniques that are applicable to all of these boiler types. Furthermore, these technologies are not only applicable to Phase I and II NOx emission reductions, but can be used in ozone nonattainment areas to make deeper cuts in NOx emissions, which are a precursor to ozone. 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 nonat- tainment in the Northeast. The SIP Call requires the 23 affected jurisdictions to revise their state implementa- tion plans (SIPs) to reduce NOx emissions to 85 percent below 1990 rates or achieve a 0.15 lb/106 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 NOx credits that could be sold to unit operators unable to meet the requirements. Furthermore, an environmen- tal controls database has been developed that provides a foundation for developing technologies to meet the increasingly stringent standards for existing units. Air toxics is another important area of environmental concern addressed by the CCT Program. Under Title I of the CAAA, EPA is responsible for determining 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 

results of these and othmitigated concerns abofired power plants and emissions. In Decemberegulations for mercury three year period. The CCT Program is aglobal climate change. as IGCC) being demonoffer utilities an option (GHG) by as much as 2systems through enhantion of atmospheric fluand pressurized fluidizalso serve to reduce GHMarket Considerationmarket moves from a rmarket, the CCT Progrchanges. Whether the cfederal government thror by state governmentstrating the first generawill be needed in a comAdvanced Flue Gas Desu(Pure Air on the Lake, L.Ppresented by Power maga
ES-4 Program Update 2001

market. These new technologies will be far moreefficient than existing plants and environmentallybenign.Ensuring Sustainable Economic Growth. It is in thenation’s interest to maintain a diverse energy mix tosustain domestic economic growth. The CCT Programis contributing to this interest by developing anddeploying a technology portfolio that enhances theefficient use of the United States’ abundant coalresource while simultaneously achieving importantenvironmental goals. The advancements in coal usetechnology resulting from the CCT Program willreduce dependence on foreign energy resources andcreate an international market for these new technologies.Looking to the Future. The investment in the CCTProgram is forming a solid foundation upon which tobuild a responsible future for fossil energy whileaddressing growing global and regional environmentalconcerns and providing low-cost energy. Three programs are of particular relevance to advancing the cleancoal technologies demonstrated in the CCT Program.First is the Power Plant Improvement Initiative, secondis the Clean Coal Power Initiative, and third isVision 21.For the near term, the Office of Coal and Power Systems(OC&PS) has embarked upon the Power Plant Improvement Initiative. The rapid growth in power demand,especially peak demand, coupled with the ongoingrestructuring of the electric power industry, has resultedin a real and growing concern over the reliability of thenation’s electricity grid. This concern prompted Congress to add $95 million to the Office of Fossil Energybudget for fiscal year 2001. The Power Plant Improvement Initiative approved by Congress will have a nearterm focus on improving the efficiency and environmental performance of coal-fired power generation. Newtechnologies will be demonstrated that can boost theefficiency of a power plant—increasing the amount ofelectricity it can generate, reducing air emissions per

kilowatt-hour produced. The initial program will applyto existing and new coal-based, central power plants.The Clean Coal Power Initiative (CCPI) is a government/industry partnership designed to implement thePresident’s National Energy Policy (NEP) recommendation to increase investment in clean coal technologyfor the purpose of ensuring the reliability of ourelectric supply while simultaneously protecting ourenvironment. The CCPI is a cost-shared partnershipbetween the government and industry—like the CCTProgram. The goal is to accelerate commercial deployment of advanced technologies to ensure the UnitedStates has clean, reliable, and affordable electricity.This ten-year initiative will be tentatively funded at atotal federal cost share estimated at $2 billion with aminimum matching industry cost share of one-to-one.The Department of Energy is in the initial planning andimplementation phases of the CCPI program.For the long term, OC&PS will build upon the solidfoundation established by the CCT Program towardmeeting Vision 21 goals. Vision 21 is a long-termstrategic concept that integrates OC&PS program goalsto develop the full potential of the nation’s abundantfossil fuel resources while addressing regional andglobal environmental concerns. Vision 21 plants wouldcomprise a portfolio of fuel-flexible systems andmodules capable of producing a varied slate of highvalue commodities, such as clean fuels, chemicals, andelectricity, tailored to meet market demands in the2010-2015 time frame. The OC&PS program areas,which include Central Power Systems, DistributedGeneration, Fuels, CO2 Sequestration, and AdvancedResearch, were developed to align with and directlysupport the goals and objectives of Vision 21. TheOC&PS program addresses key domestic and globalenvironmental concerns, while being responsive toDOE strategies to enhance scientific understanding andpromote secure, efficient, and comprehensive energysystems.

Program ImImplementation Principrinciples that have been the CCT Program. These • Strong and stable fin

of a project, including government’s share o

• Multiple solicitations 

years, enabling the Crange of national needtechnologies;

• Demonstrations cond

actual user environmeof a technology’s com

• A technical agenda e

government, enhancin

• Clearly defined roles 

reflecting the degree 

• A requirement for at 

throughout all project pants’ commitment;

• An allowance for cos

and cost-sharing, recoand providing an impsystem to the program

• Industry retention of 

rights, enhancing com

• A requirement for ind

cialize the technologygoals; and

• A requirement for rep

government’s cost-shcialization of the tech
Implementation Process. Public and private sectorinvolvement is integral to the CCT Program processand has been crucial to the programís success. Environmental concerns are publicly addressed through theprocess instituted under the National EnvironmentalPolicy Act (NEPA). Through programmatic environmental assessments (PEAs) and environmental impactstatements (PEISs), project-specific environmentalassessments (EAs) and environmental impact statements (EISs), and other NEPA documents, the publicis able to comment and have its comments addressedbefore the projects proceed to implementation. Inaddition, environmental monitoring programs arerequired for all projects to address non-regulatedpollutant emissions.As to the solicitation process, Congress set the goalsfor each solicitation. The Department of Energytranslated the congressional guidance into performance-based criteria and developed approaches toaddress ìlessons learnedî from previous solicitations.The criteria and solicitation procedures were offeredfor public comment and presented at pre-proposalconferences. The solicitations were objectivelyevaluated against the pre-established criteria.Projects are managed by the participants, not thegovernment. However, to protect the public interest,safeguards are implemented to track and monitorproject progress and direction. The Department ofEnergy interacts with the project at key negotiateddecision points (budget periods) to approve or disapprove continuance of the project. Also, any changes tocost or other major project changes require DOEapproval. In addition to formal project reportingrequirements, an outreach program was instituted tomake project information available to customers andstakeholders. This Program Update 2001 is only one

of the many public reports made available through theoutreach program.Commitment to Commercial Realization. The CCTProgram has focused on achieving commercialrealization since the programís inception. All fivesolicitations required the potential participants to

address the commercial plans and approaches to beused by the participants to achieve full commercialization of the proposed technology. The cooperativeagreements contain balanced provisions that provideprotection for intellectual property but require theparticipants to make the technology available underlicense on a nondiscriminatory basis.Solicitation Results. Each solicitation was issued as aProgram Opportunity Notice (PON)óa solicitationmechanism for cooperative agreements where theprogram goals and objectives are defined, but thetechnology is not defined. The procurements followedspecific statutory requirements that eventually led to acooperative agreement between DOE and the participant. The result was a broad spectrum of technologiesinvolving customers and stakeholders from all marketsegments. In sum, 211 proposals were submitted and60 of those were selected. As of September 2001, atotal of 38 projects have been completed or arecurrently active. These 38 projects are spread acrossthe nation in 18 states.Future Implementation Direction. The futuredirection of the CCT Program focuses on completingthe existing projects as promptly as possible andassuring the collection, analyses, and reporting of theoperational, economic, and environmental performanceresults that are needed to effect commercialization. InFY2002, four projects are scheduled to completeoperations bringing the total for completed projects upto 34 out of a total of 38 projects.The body of knowledge obtained as a result of the CCTProgram is being used in decision making relative toregulatory compliance, forging plans for meeting futureenergy and environmental demands, and developing thenext generation of technologies responsive to everincreasing demands on environmental performance atcompetitive costs.Built upon the success of the CCT Program, two newinitiativesóPower Plant Improvement Initiative andClean Coal Power Initiativeówill incorporate many ofthe implementation principles of the CCT Program.

These implementation lessons learned from thenhance the return on t

Funding and Program Funding. Cofederal budget of $1.8 The participants in the projects will have contdollars for a combined billion. By law, DOEís percent of the total cosindustry has stepped founprecedented 66 percCongress has provided five solicitations throuadjustments. AdditionaProgram are the Small Program and the Small Program. Funding is aland management of the priated funds is controlvariety of financial mangovernment cost-share agreement is considerehowever, DOE obligatincrements by budget pthe governmentís finanDOE fully participates each major phase of prCost Sharing. As statecannot exceed 50 perceproject. Participant cosphases of the project. Tshare in project cost grany demonstration proj
ES-6 Program Update 2001

original project cost, but must be cost-shared by theparticipant at the same cost-share ratio of the originalagreement. The participant’s contributions under thecooperative agreement must occur as expenses areincurred and cannot be delayed based on forecastedrevenues, proceeds, or royalties. Also, prior investments in facilities by participants cannot count towardthe participant’s share.Recovery of Government Outlays (Recoupment).The policy objective of DOE is to recover an amountof the federal government’s financial contribution toeach project when a technology is successfully commercialized. A recoupment agreement accompanieseach demonstration agreement and stipulates therepayment provisions.CCT ProgramAccomplishmentsFossil Energy R&D Benefits. The CCT Program,along with other Office of Fossil Energy research anddevelopment has led to commercialization of technologies to lower emissions, improve efficiencies, generateelectricity, upgrade fuels, and improve industrialprocesses. According to a National Research Council(NRC) report, Energy Research at DOE: Was It WorthIt?, “DOE’s fossil energy program made a significantcontribution over the last 22 years to the well-being ofthe United States through the development of fossilenergy programs that led to realized economic benefits,options for the future, and significant knowledge.”Furthermore, the NRC concluded “that these benefitshave substantially exceeded their cost and led toimprovements in the economy, the environment, andthe security of the nation.”

The specific technology successes described in thisreport underscore the effectiveness of the government/industry partnerships forged and the importance of amarket-based approach in defining CCT Programneeds. After 15 years, the CCT Program is nearingcompletion, but several important projects have yet tomake their contribution.There are also a number of institutional successesassociated with the CCT Program. For example, theGeneral Accounting Office has described the CCTProgram as one of the most successful government/industry partnerships. Congress has recognized thesuccess of the CCT Program and has adopted theprogram’s general principles in establishing the PowerPlant Improvement Initiative and the Clean Coal PowerInitiative. The Department of Energy has adopted thesame principles for other programs as well.Marketplace Commitment. The success of theCCT Program ultimatelywill be measured by thecontribution the technologies make to theresolution of energy,economic, and environmental issues. Thesecontributions can only beachieved if the publicand private sectorsunderstand that cleancoal technologies canincrease the efficiency ofenergy use and enhanceenvironmental performance at costs that arecompetitive withalternative energyoptions. The demonstrations, in conjunction withan aggressive outreacheffort, are designed to

impart that understandinorganized from a market placed in four major procontrol devices, advancecoal processing for clean tions. A summary of the completed operations by ES-1.The first major product lidevices, is subdivided inttechnologies, NOx controSO2/NOx control technoland limestone-based systachieve a range of SO2 ca

99 percent. All five of the 

demonstrations have succ

Exhibit ES-1

Completed Projects by Applic

Application Category Co

O

as of S

Environmental Control DevicesSO2 Control Technology 

NOx Control Technology 

Combined SO2/NOx Control Technology 

Advanced Electric Power GenerationFluidized-Bed Combustion 

Integrated Gasification Combined-Cycle 

Advanced Combustion/Heat Engines 

Coal Processing for Clean Fuels Industrial Applications 

Total 
The PC-based software tool CQETM can be used to determinethe complete costs of various fuel options by integrating theeffects of fuel purchase decisions on power plantperformance, emissions, and power generation costs.

Wabash River Coal GasifRiver Coal Gasification R1996 Powerplant Award pFull-Scale Demonstration 

Project (The Babcock & WAward presented by R&D 

For NOx control technologies, two basic approacheswere used: (1) combustion modification techniquesincluding low-NOx burners, overfire air, advancedcontrols, and reburning systems; and (2) post-combustion techniques using selective catalytic reduction(SCR) and selective non-catalytic reduction (SNCR)systems. These NOx control techniques were applied ina variety of combinations on a diverse group of boilers,which are representative of 99 percent of existing coalfired boilers. The result of the NOx control technologydemonstrations is a portfolio of technologies that canbe applied to the full range of boiler types and used toaddress today’s pressing environmental concerns, e.g.,

ozone. Six of the seven NOx control technology

demonstrations have successfully completed operations. For the seventh project, several final reports wereissued on key facets of the project, but the project wasextended for additional demonstration activities.All six of the combined SO2/NOx control technologydemonstrations have successfully completed operations.The demonstrations tested a multiplicity of complementary and synergistic control methods to achieve cost- effective SO2 and NOx emission reductions. A summary of the results of the completed and extended environmental control device projects can be found in exhibit ES-2. The commercial successes of the environmental 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 (AFBC) and pressurized fluidized-bed combustion (PFBC). The two AFBC projects use a circulating-bed, as opposed to a bubbling-bed, operating at atmospheric pressure to generate steam for electricity production. One project is complete and the other project is ongoing. There are

three PFBC projects in the CCT Program. The completed PFBC project used a bubbling-bed operating at16 atmospheres to generate steam and drive a gasturbine in a combined-cycle mode. Plans for twointerrelated PFBC projects, which are now on holdpending further analysis for generation needs by theparticipant, are to use a circulating-bed operating at 13atmospheres, in a combined-cycle mode.During fiscal year 2001, two integrated gasificationcombined-cycle (IGCC) projects successfully completed operations and a third IGCC project was in thedesign stage. One project completed operations in theprevious year. The IGCC projects represent a diversityof gasifier types, cleanup systems, and applications.Two projects are demonstrating advanced combustion/heat engine technology. One uses an entrained (slagging) combustor, and the other uses a heavy duty dieselengine fired on a coal-water fuel. One project completed operations and the other project is ongoing.

A summary of the resuelectric power generatiExhibit ES-4. The comprojects can be seen in For the third major proclean fuels, there are foprojects used chemical 
ES-8 Program Update 2001

Exhibit ES-2

Summary of Results of Completed Environmental Control Technology Pr

Project and Participant Key Results Capital Cost

SO2 Control Technology

10-MWe Demonstration of Gas Suspension Absorption Gas suspension absorption (GSA)/electrostatic precipita- $149/kW for GSA (2.6% 

(AirPol, Inc.) tor (ESP)óSO2 removal efficiency of 90% at Ca/S molar conventional wet limesto

ratio of 1.4, 18 oF approach to saturation, and 0.12% (1990$)chloride (3.0% sulfur bituminous coal)GSA/pulse jet baghouseóSO2 removal efficiency 3ñ5%

greater than GSA/ESP (3.0% sulfur bituminous coal)

Confined Zone Dispersion Flue Gas Desulfurization SO2 reduction of 50% (1.2ñ2.5% sulfur bituminous coal) Less than $30/kW at 500 

Demonstration (Bechtel Corporation)LIFAC Sorbent Injection Desulfurization Demonstration SO2 removal efficiency of 70% at 2.0 Ca/S molar ratio $66/kW for two reactors Project (LIFACñNorth America) (2.0ñ2.8% sulfur bituminous coal) reactor (150 MWe); $99/

(1994$)

Advanced Flue Gas Desulfurization Demonstration Project SO2 removal efficiency of 95% or more at availabilities of $210/kW at 100 MWe; $(Pure Air on the Lake, L.P.) 99.5% when operating on 2.0ñ4.5% sulfur bituminous $94/kW at 500 MWe (3.

coalMaximum SO2 removal efficiency of 98%

Over 3-year demonstration, 237,000 tons of SO2removed while producing 210,000 tons of gypsumGypsum purityññ97.2%Power consumptionó5,275 kW (61% of expected)Water consumptionó1,560 gal/min (52% of expected)

Demonstration of Innovative Applications of Technology SO2 removal efficiency of over 95% at SO2 inlet $313/kW or $408/ton SO

for the CT-121 FGD Process (Southern Company concentrations of 1,000ñ3,500 ppm using 3% sulfur coal $131/kW or $171/ton SOServices, Inc.) Particulate removal efficiency of 97.7ñ99.3% $104/kW or $136/ton SO

at inlet mass loadings of 0.303ñ1.392 lb/106 Btu (Costs based on limeston

Agricultural-grade gypsum as a by-productFiberglass-reinforced-plastic constructionóchemicallyand structurally durable; eliminated the need for a flue gasprescrubber and reheat
Exhibit ES-2 (continued)

Summary of Results of Completed Environmental Control Technology P

Project and Participant Key Results Capital Cost

NO

x Control Technology

Demonstration of Advanced Combustion Techniques for Using LNB alone, NOx emissions were 0.65 lb/106 Btu at Capital cost for a 500-M

a Wall-Fired Boiler (Southern Company Services, Inc.) full load, representing a 48% reduction from baseline for LNB/AOFA, $8.80/k

conditions (1.24 lb/106 Btu) for LNB alone, and $0.5

Using AOFA only, NOx reductions of 24% below Estimated cost of NOx re

baseline conditions were achieved under normal long-term dispatch modeoperation, depending upon loadUsing LNB/AOFA, full load NOx emissions were

approximately 0.40 lb/106 Btu, which represents a 68%reduction from baseline conditions

Demonstration of Coal Reburning for Cyclone Boiler NOx NOx reductions of 52% using bituminous coal and 55% $66/kW at 110 MWe; $4

Control (The Babcock & Wilcox Company) using subbituminous coal at full load (110 MWe); 36%

and 53%, respectively, at 60 MWe

Full-Scale Demonstration of Low-NO

x

 Cell Burner NO

x reductions of 58% using bituminous coal at full load $9/kW at 600 MWe (199

Retrofit (The Babcock & Wilcox Company) (605 MWe); 48% at 350 MWeEvaluation of Gas Reburning and Low-NOx Burners on a LNB alone (second generation)—37% NOx reduction; GR-LNB $26/kW at 300

Wall-Fired Boiler (Energy and Environmental Research GR-LNB (second generation)—64% NOx reduction gas pipeline cost (1996$

Corporation) (13% gas heat input)Micronized Coal Reburning Demonstration for NOx Using a 14% reburn fuel heat input on the Milliken Station $14/kW at 300 MWe (19

Control (New York State Electric & Gas Corporation) tangentially fired (T-fired) boiler resulted in a NOx

emission rate of 0.25 lb/106 Btu, which represents a 28%NO

x

 reduction

Using a 17% reburn fuel heat input on the Kodak Parkcyclone boiler resulted in a NOx emission rate of 0.60 lb/

106 Btu, which represents a 59% NOx reduction

Demonstration of Selective Catalytic Reduction NOx reductions of over 80% at ammonia slip well under Levelized cost at 80% N

Technology for the Control of NOx Emissions from High- 5 ppm or $2,036/ton of NOx rem

Sulfur, Coal-Fired Boilers (Southern CompanyServices, Inc.)180-MWe Demonstration of Advanced Tangentially NOx reductions of 37% for LNCFSTM I and II, and 45% LNCFS I—$5–15/kW (1

Fired Combustion Techniques for Reduction of NOx for LNCFSTM III, which includes both separated overfire LNCFS II/III—$15–25/k

Emissions from Coal-Fired Boilers (Southern Company air and close-coupled overfire airServices, Inc.)
ES-10 Program Update 2001

Exhibit ES-2 (continued)

Summary of Results of Completed Environmental Control Technology Pr

Project and Participant Key Results Capital Cost

Combined SO2/NOx Control Technology

SNOXTM Flue Gas Cleaning Demonstration Project NOx reduction of over 94% at inlet concentra- $305/kW at 500 MWe (3.2

(ABB Environmental Systems) tions of 500–700 ppm

SO2 removal efficiency over 95% at inlet concentrations

of 2,000 ppmProduced salable sulfuric acid by-product in lieu of waste

LIMB Demonstration Project Extension and Coolside SO2 removal efficiency (3.8% sulfur coal, Ca/S molar ratio LIMB—$31–102/kW (10

Demonstration (McDermott Technology, Inc.) of 2.0): Coolside—$69–160/kW (

– LIMB—53–61% for ligno lime, 51–58% for calcitic lime– Coolside—70% for hydrated limeNO

x

 reduction of 40–50%

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration SO2 reductions of 80–90% using 3–4% sulfur bituminous $233/kW at 250 MWe (3.5

Project (The Babcock & Wilcox Company) coal, depending on sorbent and conditions NOx level of 1.2 lb/106 Bt

NO

x

 reduction of 90% with 0.9 NH3/NOx ratio

Enhancing the Use of Coals by Gas Reburning and Hennepin—Average NOx reduction of 67% with 18% gas $15/kW for gas reburning

Sorbent Injection (Energy and Environmental Research heat input; SO2 removal efficiency of 53% at 1.75 Ca/S

Corporation) molar ratio

Lakeside—Average NOx reduction of 66% and SO2 $50/kW for sorbent injecti

reductions of 58% during extended continuous combined(GR-SI) runs at 29 MWe, about 22% gas heat input, and1.8 Ca/S molar ratio

Milliken Clean Coal Technology Demonstration Project The maximum SO2 removal demonstrated was 98% $300/kW at 300 MWe (19

(New York State Electric & Gas Corporation) with all seven recycle pumps operating and using formic requirements

acid. The maximum SO2 removal without formic acid $217/kW at 300 MWe for 

was 95% for other related costsTesting of the LNCFSTM III indicated NOx emissions of $4,620,000/yr for O&M c

0.39 lb/106 Btu (compared to 0.64 lb/106 Btu for the

original burners), a 36% reduction
Exhibit ES-2 (continued)

Summary of Results of Completed Environmental Control Technology P

Project and Participant Key Results Capital Cost

Combined SO2/NOx Control Technology (continued)

Integrated Dry NOx/SO2 Emissions Control System NOx reduction of 62–69% with low-NOx burners and $125/kW at 300 MWe 

(Public Service Company of Colorado) maximum overfire air (50–110 MWe) $281/kW at 50 MWe f

NO

x

 reduction of 63% with low-NO

x

 burners and

minimum overfire air; steady state conditionsNO

x reduction decreased by 10–25% under load

followingSNCR obtained NO

x reduction of 30–50%,

thereby increasing total NOx control system reduction

to more than 80%SO2 removal efficiency of 70% with sodium bicarbonateat normalized stoichiometric ratio of 1.0
ES-12 Program Update 2001

Exhibit ES-3

Commercial Successes—Environmental Control Technologies

10-MWe Demonstration of Gas Suspension Absorption Sold domestically and internationally. GSA market entry was significantly enhanced 

(AirPol, Inc.) unit, worth $12.5 million, to the city of Hamilton, Ohio, subsidized by the Ohio Coal D

worth $1.3 million has been made to the U.S. Army for hazardous waste disposal. A GSwedish iron ore sinter plant. Two GSA systems valued at $1.8 million have been sold for their oil-fired cogeneration plant. AirPol sold a GSA system valued at $1.5 million India. Startup has begun in Wasatch, Utah for a GSA-based municipal waste incineratosteam. A new contract is expected for a waste incinerator in Holland using the GSA sy

Confined Zone Dispersion Flue Gas Desulfurization No sales reported. CZD/FGD can be used to retrofit existing plants or for new installaDemonstration (Bechtel Corp.) fourth the cost of a commercial wet scrubber.LIFAC Sorbent Injection Desulfurization Demonstration Project Sold domestically and internationally. The LIFAC system at Richmond Power & Lig

(LIFAC–North America) power plant using high-sulfur (2.0-2.9%) coal. The LIFAC system has been retained fo

Power & Light at Whitewater Valley Station, Unit No. 2. There are 10 LIFAC units in Finland, Japan, Russia, and the United States, including 5 projects started before the CChina, the estimated value is $44.6 million.

Advanced Flue Gas Desulfurization Demonstration Project No sales reported. The AFGD continues in commercial service at Northern Indiana P(Pure Air on the Lake, L.P.) Generating Station. Gypsum produced by the PowerChip® process is being sold comm

for 17 years of continued scrubber operations roughly equals the value of the project. Flicensee, is currently working on a potential $60 million project in Kentucky using the technology.

Demonstration of Innovative Applications of Technology for the Sold internationally. Plant Yates continues to operate with the CT-121 scrubber as an CT-121 FGD Process (Southern Company Services, Inc.) CAAA compliance strategy. There are now 22 CT-121 plants in the planning, construc

worldwide. There are 17 CT-121 plants operating in Japan, Australia, Canada, the CzeMalaysia, and Kuwait. The value of these 17 plants is estimated at $2.03 billion. For ththe value is estimated at $880 million.

Micronized Coal Reburning Demonstration for NOx Control No sales reported. Technology retained for commercial use at Kodak Park Power Plan

(New York State Electric & Gas Corp.)Demonstration of Coal Reburning for Cyclone Boiler NOx No sales reported. Technology retained for commercial use at Wisconsin Power and L

Control (The Babcock & Wilcox Company) Dewey Station.Full-Scale Demonstration of Low-NO

x

 Cell Burner Retrofit Sold domestically. Dayton Power & Light has retained the LNCB® for use in commer

(The Babcock & Wilcox Company) commercial contracts have been awarded for 196 burners or 5,475 MWe of capacity, vEvaluation of Gas Reburning and Low-NOx Burners on a Sold domestically and internationally. Public Service Company of Colorado, the hos

Wall-Fired Boiler (Energy and Environmental Research Corp.) low-NOx burners and the gas-reburning system for immediate use; however, a restorati

flue gas recirculation system. Since the CCT Program, the participant has installed or igas reburning or the gas reburning-low-NOx burner technology on 14 boilers represent

Most of the sites are domestic, but one site is the Ladyzkin Power Station in Ladyzkin

Project Commercial Use
Exhibit ES-3 (continued)

Commercial Successes—Environmental Control Technologies

Project Commercial UseDemonstration of Selective Catalytic Reduction Technology Sold domestically and internationally. Since the project was initiated, revenues frofor the Control of NO

x Emissions from High-Sulfur, Coal-Fired billion through 2001.

Boilers (Southern Company Services, Inc.)180-MWe Demonstration of Advanced Tangentially Fired Sold domestically and internationally. LNCFSTM has been retained at the host site 

Combustion Techniques for the Reduction of NOx Emissions Power has sold about 63 GWe of LNCFSTM burners. Of this amount, about 49 GWe 

from Coal-Fired Boilers (Southern Company Services, Inc.) and 14 GWe are without overfire air. Total sales are estimated at $1.3 billion.Demonstration of Advanced Combustion Techniques for a Wall- Sold domestically and internationally. The host has retained the technologies for c

Fired Boiler (Southern Company Services, Inc.) has equipped 101 boilers with low-NOx burner technology—a total of over 1,447 bu

of capacity valued at $83 million. Foreign sales make up 35 percent of the commerciinstallations of GNOCIS, the associated artificial intelligence control system, are undrepresents over 12,000 MWe of capacity. In a strict sense, this project has not been capply GNOCIS to other pieces of plant equipment, which may increase its commerc

SNOXTM Flue Gas Cleaning Demonstration Project (ABB International use. The host utility, Ohio Edison, is retaining the SNOXTM technologEnvironmental Systems) pollution control system at Niles Station to help meet its overall SO2 and NOx reduct

plants are also operating in Denmark and Sicily. In Denmark, a 305-MWe plant has boiler at this plant burns coals from various suppliers around the world, including th0.5–3.0% sulfur. The plant in Sicily, in operation since March 1991, has a capacity opetroleum coke.

LIMB Demonstration Project Extension and Coolside Sold domestically and internationally. LIMB has been sold to an independent powDemonstration (The Babcock & Wilcox Company) Wilcox has sales of 2,805 DRB-XCL® burners for 38,284 MWe of capacity. The low

value of $388 million.

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project No sales reported. Commercialization of the technology is expected to develop with (The Babcock & Wilcox Company) application equivalent to 50–100 MWe. The focus of marketing efforts is being tailo

of potential industrial, utility, and independent power producers for both retrofit and SNRBTM is a flexible technology that can be tailored to maximize control of SO2, NO

emissions to meet current performance requirements while providing flexibility to ad

Enhancing the Use of Coals by Gas Reburning and Sorbent No sales reported. Illinois Power has retained the gas-reburning system and City WInjection (Energy and Environmental Research Corp.) the full technology for commercial use. (See Evaluation of Gas Reburning and Low-

Boiler project for a complete understanding of commercial success of the technology

Milliken Clean Coal Technology Demonstration Project Sold domestically. Eight modules of DHR Technologies’ Plant Emissions Optimiza(New York State Electric & Gas Corp.) value of $280,000, have been sold. A U.S. company, SHN, has been established to m

is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABB Cmodified 116 units representing over 25,000 MWe with LNCFSTM or its derivative T

Integrated Dry NOx/SO2 Emissions Control System Sold domestically. The technology was retained by Public Service Company of Colo

(Public Service Company of Colorado) at its Arapahoe Station. Babcock & Wilcox has sales of 2,805 DRB-XCL® burners f

low-NO

x burners have an estimated value of $388 million.
ES-14 Program Update 2001

Exhibit ES-4

Summary of Results of Completed Advanced Electric Power Generation P

Tidd PFBC Demonstration Project (The Ohio Power SO2 reduction of 90–95% (Ohio bituminous coal, 2–4% $1,263/kW at 360 MWe 

Company) sulfur) at 1.1–1.5 Ca/S molar ratio

NO

x

 emissions of 0.15–0.33 lb/106 Btu

Particulate emissions of 0.02 lb/106 Btu

Heat rate—10,280 Btu/kWhCombustion efficiency—99.6%Commercially viable designGas turbine operable in PFBC environment

Nucla CFB Demonstration Project (Tri-State Generation SO2 reduction of 70–95% (up to 1.8% sulfur coal), Approximately $1,123/ne

and Transmission Association, Inc.) depending on Ca/S molar ratio

NO

x

 emissions of 0.18 lb/106 Btu

Particulate emissions of 0.0072–0.0125 lb/106 Btu

Heat rate—11,600 Btu/kWhCombustion efficiency—96.9–98.9%Commercial viability established

Tampa Electric Integrated Gasification Combined-Cycle SO2 reduction of 95% 900–1,213 $/kW (1999$)

Project (Tampa Electric Company) NO

x

 emissions of 0.27 lb/106 Btu

Heat rate—9,350 Btu/kWhCarbon burnout—95+%Commercially viable design

Piñon Pine IGCC Power Project Design SO2 reduction of 95%

(Sierra Pacific Power Company) Design NOx emissions of 70% less than conventional

coal plantSteady-state operation was not reached

Project and Participant Key Results Capital Cost

Economic performance cplant did not achieve stea
Exhibit ES-4 (continued)

Summary of Results of Completed Advanced Electric Power Generation 

Wabash River Coal Gasification Repowering Project SO2 reductions of 99% $1,318/kW (2000$) for 

(Wabash River Coal Gasification Project Joint Venture) NO

x

 emissions of 0.15 lb/106 Btu $1,260/kW (2000$) for 

coke-fueled plant

Particulate emissions below detectable limitsHeat rateó8,910 Btu/kWhCommercially viable design

Healy Clean Coal Project (Arthur D. Little, Inc.) SO2 reduction in excess of 90% (Usibelli subbituminous $1,812/kW for a 50-MW

50% run-of-mine and 50% waste coal) at 1.4ñ1.8 Ca/S $1,502/kW for a 300-Mmolar ratioNO

x

 emissions of 0.208ñ0.278 lb/106 Btu

Particulate emissions of 0.0047 lb/106 Btu

Greater than 99% carbon burnout at 100% maximumcontinuous rating

Project and Participant Key Results Capital Cost
ES-16 Program Update 2001

Exhibit ES-5

Commercial Successes—Advanced Electric Power Generation Technolo

Project Commercial UseTidd PFBC Demonstration Project (The Ohio Power Company) Sold internationally. Success of the project has led Babcock & Wilcox to in

acquire domestic licensing rights. Commercial coal-fired ventures abroad inc– Vartan Sweden is operating two P200 units to produce 135 MWe and 224 – Escatron in Spain is operating one P200 unit producing 80 MWe*;– Wakamatsu in Japan has retired one P200 unit that produced 71 MWe;– Cottbus in Germany is operating one P200 unit to produce 71 MWe and 4– Karita in Japan operates one P800 unit to produce 360 MWe;– Chuoku in Japan to produce 250 MWe; and– Tomato-Atswa plant in Japan to produce 80 MWe.The value of these projects is estimated at $1.35 billion.

Nucla CFB Demonstration Project (Tri-State Generation and Sold domestically and internationally. Since the demonstration, Foster Wh

Transmission Association, Inc.) the technology supplier for the demonstration effort, has achieved sales of $9 

25 percent of the sales through 2001 were domestic, while the remaining saletime frame, Alstom Power, also a supplier of CFB technology, has had sales 3.47 GWe) through 2001.

Tampa Electric Integrated Gasification Combined-Cycle Sold domestically and internationally. First greenfield IGCC unit in commeProject (Tampa Electric Company) and ASEA Brown Boveri signed an agreement forming an alliance to market 

Since 1996, when the Tampa IGCC began operations, Texaco has placed into domestically, including Tampa, (1 using coal, 1 using petroleum, 3 using petrgas) and 16 gasifiers internationally (3 using coal, 11 using petroleum, and 2 

Wabash River Coal Gasification Repowering Project (Wabash No sales reported. First repowered IGCC unit in commercial service and woRiver Coal Gasification Repowering Project Joint Venture) IGCC in commercial service. Preferentially dispatched over other coal-fired u

because of high efficiency. The port of Port Arthur, Texas has announced plause the E-Gas technology.

Healy Clean Coal Project (Alaska Industrial Development and No sales reported. TRW offering licensing of combustor worldwide.Export Authority)

* Parallel projects to Tidd.
transform raw coal into high-energy-density environmentally compliant fuels. Another project is convertingcoal to methanol from coal-derived synthesis gas. Afourth project in this product line is a software programused to assess the environmental and operationalperformance of and determine the least-cost option foravailable coals. Three of the four coal processing forclean fuels projects are complete.A summary of the results of the completed coalprocessing for clean fuels projects can be found inExhibit ES-6. The commercial successes of the coalprocessing for clean fuels projects can be seen inExhibit ES-7.The fourth and final major product line is industrialapplications. This product line is addressing theenvironmental issues and barriers associated with coaluse in industry. There are five diverse projects in thiscategory; four are completed and one is ongoing.A summary of the results of the industrial applicationprojects can be found in Exhibit ES-8. Commercialsuccesses of these projects can be seen in Exhibit ES-9.Market CommunicationsóOutreach. Outreach hasbeen a hallmark of the CCT Program since its inception. Commercialization of new technologies requiresacceptance by a wide range of interestsócustomers,manufacturers, suppliers, financiers, government, andpublic interest groups. The CCT Program has aggressively sought to disseminate key information to this fullrange of customers and stakeholders and to obtainfeedback on changing needs. This dissemination ofinformation takes the form of printed media, exhibits,and electronic media. Printed media consist of newsletters, proceedings, technical papers, fact sheets,program updates, and bibliographies. The CCTProgram currently uses four traveling exhibits ofvarying sizes and complexity that can be updated andtailored to specific forums. Electronic media areavailable through the World Wide Web.Feedback is another important part of the outreacheffort. From public meetings during the Program

Opportunity Notice process to open houses at demonstration sites, the CCT Program stays in contact withcustomers and stakeholders. Executive seminars,stakeholder meetings, conferences, workshops, andtrade missions are used by the CCT Program todisseminate information and obtain feedback.Several domestic and international conferences andworkshops were attended or sponsored in fiscal year2001. The forums for conferences varied from China tothe United Kingdom. Trade missions during fiscal year2001 included several visits to China. All of theseevents were used to endorse and promote the technologies demonstrated in the CCT Program.CCT ProjectsTechnology Overview. The 38 CCT Program projectsprovide a portfolio of technologies that will enable coalto continue to provide low-cost secure energy vital tothe nationís economy while satisfying energy andenvironmental goals well into the 21st century.Environmental Control Devices. The environmentalcontrol technologies provide a suite of cost-effectivecontrol options for the full range of boiler types. The18 environmental control device projects are valued at$620 million (total project funding). These includeseven NOx emission control systems installed in morethan 1,750 MWe of utility generating capacity, five SO2emission control systems installed on approximately770 MWe, and six combined SO2/NOx emission controlsystems installed or planned for installation on morethan 665 MWe of capacity.Advanced Electric Power Generation. To respond toload growth, as well as growing environmentalconcerns, the CCT Program provides a range ofadvanced electric power generation options for both

repowering and new pooptions offer greater thgreenhouse gas emissioemissions far below Nby-products in lieu of sof capacity are represemore than $2.8 billion. provide environmentalbut also will provide thnecessary to meet new century.Coal Processing for Capproaches to convertienergy-density, low-suhave application domeCAAA. Internationallycesses have excellent malmost $432 million, thprocessing for clean fufied portfolio of technoIndustrial Processes. to address pollution proin the industrial sector. include dependence of the pollutant emissions reliance of the cement and often high-sulfur, cindustrial boiler operatfuels to reduce operatinapplications projects h$1.3 billion. The projeccoal for 40 percent of cof a direct iron-making electricity; reduction osolid waste generation; scale slagging combustcombustor system.Project Fact Sheets. T2001 is the project fact are provided: (1) a brie
ES-18 Program Update 2001

Project and Participant Key Results Capital Cost

Development of the Coal Quality ExpertTM CQETM features: CQETM package sells (ABB Combustion Engineering, Inc. and CQ Inc.) - Fuel evaluator—performs system-, plant-, and/or unit-level $100,000

fuel quality, economic, and technical assessments

- Plant engineer—provides in-depth performance evaluations

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 associatedcosts

ENCOAL® Mild Gasification Project (ENCOAL The liquid (CDL®) and solid (PDF®) product fuels have been A commercial plant d

Corporation) used economically in commercial boilers and furnaces and have metric-ton/day would 

reduced SO2 and NOx emissions significantly at utility and construct with annual 

industrial facilities currently burning high-sulfur bituminous costs of $52 million pcoal or fuel oils.Almost five years of operating data have been collected for useas a basis for the evaluation and design of a commercial plantAbout 260,000 tons of coal had been processed into 120,000 tonsof PDF® and 5,101,000 gallons of CDL®

Advanced Coal Conversion Process Demonstration As of the end of 2000, seven customers were using the SynCoal® Economic data are no

(Western Syncoal LLC) product

Nine years of operating data have been collected for use as thebasis for the evaluation and design of a commercial plantOver 2.8 million tons of raw coal was processed to producealmost 1.9 million tons of SynCoal® products

Exhibit ES-6

Summary of Results of Completed Coal Processing for Clean Fuels Pro
Exhibit ES-7

Commercial Successes—Coal Processing for Clean Fuels Technolog

Project Commercial UseDevelopment of the Coal Quality ExpertTM (ABB Combustion Sold domestically and internationally. The Electric Power Research InstitEngineering, Inc. and CQ Inc.) and distributes it to EPRI members for their use. CQ Inc. and Black and Ve

commercialization agreements that give both companies nonexclusive worland offer consulting services that include use of CQE®. More than 22 U.S. 

utilities, and one French utility have received CQE® through EPRI member

Rain Advisor valued at $6,000 have been sold. EPRI estimated that the Aciutility about $26 million, more than the total cost of the demonstration projthe Windows version of the software (Vista) at an estimated value of $180,0

ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Domestic and international sales pending. In order to determine the viabi

five detailed commercial feasibility studies—two Indonesian, one Russian, been completed. Permitting of a 15,000 metric-ton/day commercial plant in 

Advanced Coal Conversion Process Demonstration (Western No sales reported. Total sales of SynCoal® product exceed 1.9 million tons

SynCoal LLC) in place to purchase the product. One domestic and five international projec

Western SynCoal LLC has a joint marketing agreement with Ube Industries exclusive marketing rights outside of the United States. Ube is pursuing sev

Commercial-Scale Demonstration of the Liquid Phase Methanol No sales reported. Nominal 80,000 gallon/day methanol production being (LPMEOHTM) Process (Air Products Liquid Phase Conversion CompanyCompany, L.P.)
ES-20 Program Update 2001

Exhibit ES-8

Summary of Results of Completed Industrial Application Projects

Project and Participant Key Results Capital Cost

Advanced Cyclone Combustor with Internal Sulfur, SO2 reduction of 58% with limestone injection in the $100–200/kW

Nitrogen, and Ash Control (Coal Tech Corporation) combustor at 2.0 Ca/S molar ratio

NO

x emissions of 160–184 ppm (75% reduction)

Slag/sorbent retention of 55–90% in combustor; inert slag

Cement Kiln Flue Gas Recovery Scrubber (Passama- SO2 reduction of 90–95% (2.5–3% sulfur bituminous $10 million for 450,000 to

quoddy Tribe) coal); 98% maximum reduction

NO

x reduction of 18.8% avg

Particulate emissions of 0.005–0.007 gr/std ft3 withloading of 0.04 gr/std ft3

Blast Furnace Granular-Coal Injection Demonstration The low-volatile, low-ash coal displaced up to 0.96 pounds $15 million for a single blProject (Bethlehem Steel Corporation) of coke for every pound of coal tons of hot metal per day

No increase in sulfur emissionsSulfur levels in product remained within specified limits

Pulse Combustor Design Qualification Test NOx emissions of 79–97 ppmv (corrected to 3% oxygen) Not available

(ThermoChem, Inc.)

Exhibit ES-9

Commercial Successes—Industrial Application Projects

Project Commercial UseAdvanced Cyclone Combustor with Internal Sulfur, No sales reported. While the combustor was not yet fully ready for sale with commercial guaNitrogen, and Ash Control (Coal Tech Corporation) to have commercial potential. Subsequent work was undertaken, which has brought the techn

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 th

(Passamaquoddy Tribe) feasibility study has been completed for a Taiwanese cement plant.Blast Furnace Granular-Coal Injection System No sales reported. Technology remains in commercial service at demonstration site.Demonstration Project (Bethlehem Steel Corporation)
ongoing projects and (2) an expanded four-pagesummary for projects that have successfully completedoperational testing. The latter contains a summary ofthe major results from the demonstrations, as well assources for obtaining further information. Technologydescriptions, costs, and schedules are provided for allprojects. A list of the projects with the participant,solicitation, and status is shown in Exhibit ES-10. A listof the award-winning CCT Program projects is shownin Exhibit ES-11.PPII ProjectsRole of the PPII Program. The Power Plant Improvement Initiative was established in fiscal year 2001 byCongress and provided ìfor a general request forproposals for the commercial scale demonstration oftechnologies to assure the reliability of the [n]ation'senergy supply from existing and new electric generating facilities for which the Department of Energy uponreview may provide financial assistance awards . . .î Inthe act, Congress transferred $95,000,000 for thispurpose from previously appropriated CCT Programfunding.Program Implementation. The Department of Energydeveloped a PPII solicitation, incorporating generalprovisions of the CCT Program (per congressionaldirection) with some modifications to take into accountlessons learned from the CCT Program.PPII Funding and Costs. The PPII was established bythe Department of the Interior and Related AgenciesAppropriations Act for Fiscal Year 2001 (Public Law106-291) through the transfer of $95,000,000 inpreviously appropriated funding for the CCT Program.DOE commitments will be approximately $50 millionwith final values determined during negotiations.Private sector sponsors are expected to contribute

nearly $61 million, exceeding the 50 percent privatesector cost-sharing mandated by Congress. Repaymentobligations start after the completion of the demonstration and last for 20 years. In accordance with congressional direction, repayments will be retained by DOEfor future projects.PPII Accomplishments. The program solicitation wasissued on February 6, 2001, and 24 proposals werereceived on April 19, 2001. On September 28, 2001, atotal of eight projects with a combined industry/government value of $110 million were selected fornegotiations. (Prior to publication of this report, oneproject was withdrawn.) Exhibit 6-1 shows thelocations of the selected projects. Contract awards areexpected by March 2002. Projects will take from oneto five years to complete.PPII Projects. Most PPII projects focus on technologies enabling coal-fired power plants to meet increasingly stringent environmental regulations at the lowest

possible cost. Many coal plants could continueoperations under stricter environmental guidelines ifmore effective and lower cost emission controls can bedeveloped. Other projects will improve the performance and reliability of power plants. A list of theselected PPII projects is presented in Exhibit ES-12.
ES-22 Program Update 2001

Exhibit ES-10

CCT Program Project Fact Sheets by Application Category

Project Participant Solicitat

Environmental Control DevicesSO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/c

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/cLIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCT-III/c

Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/c

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/cNO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/e

Demonstration of Coal Reburning for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/c

Full-Scale Demonstration of Low-NO

x

 Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/c

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/c

Micronized Coal Reburning Demonstration for NOx Control New York State Electric & Gas Corporation CCT-IV/c

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCT-II/c

for the Control of NO

x Emissions from High-Sulfur, Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion Southern Company Services, Inc. CCT-II/cTechniques for the Reduction of NOx Emissions from Coal-Fired Boilers

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/c

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/coSOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/c

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/coMilliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/c

Integrated Dry NOx/SO2 Emissions Control System Public Service Company of Colorado CCT-III/c

Advanced Electric Power GenerationFluidized-Bed CombustionMcIntosh Unit 4A PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-III/d

McIntosh Unit 4B Topped PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-V/d

JEA Large-Scale CFB Combustion Demonstration Project JEA CCT-I/co
Exhibit ES-10 (continued)

CCT Program Project Fact Sheets by Application Category

Project Participant SolicitatiTidd PFBC Demonstration Project The Ohio Power Company CCT-I/comNucla CFB Demonstration Project Tri-State Generation and Transmission CCT-I/com

Association, Inc.

Integrated Gasification Combined-CycleKentucky Pioneer Energy IGCC Demonstration Project Kentucky Pioneer Energy, LLC CCT-V/deTampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/cPiñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/cWabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering CCT-IV/c

Project Joint Venture

Advanced Combustion/Heat EnginesClean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/coHealy Clean Coal Project Alaska Industrial Development and CCT-III/c

Export Authority

Coal Processing for Clean FuelsCommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process Air Products Liquid Phase CCT-III/o

Conversion Company, L.P.

Development of the Coal Quality ExpertTM ABB Combustion Engineering, Inc. CCT-I/com

and CQ Inc.

ENCOAL® Mild Coal Gasification Project ENCOAL Corporation CCT-III/cAdvanced Coal Conversion Process Demonstration Western SynCoal LLC CCT-I/comIndustrial ApplicationsClean Power from Integrated Coal/Ore Reduction (CPICORTM) CPICORTM Management Company LLC CCT-V/deBlast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/cAdvanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/comCement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/coPulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/c
ES-24 Program Update 2001

Exhibit ES-11

Award-Winning CCT Program Projects

Project and Participant Award

Full-Scale Demonstration of Low-NO

x

 Cell Burner 1994 R&D 100 Award presented by R&D magazine to the U.S. Department of Energy for deve

Retrofit (The Babcock & Wilcox Company) burner.Evaluation of Gas Reburning and Low-NOx Burners 1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management Association 

on a Wall-Fired Boiler; Enhancing the Use of Coals Energy, Gas Research Institute, and U.S. Environmental Protection Agency for the develoby Gas Reburning and Sorbent Injection (Energy and gas-reburning technology.Environmental Research Corporation)Advanced Flue Gas Desulfurization Demonstration 1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service Com

Project (Pure Air on the Lake, L.P.) Station.

1992 Outstanding Engineering Achievement Award presented by the National Society of Profe

Demonstration of Innovative Applications of 1995 Design Award presented by the Society of Plastics Industries in recognition of the mist el

Technology for the CT-121 FGD Process (Southern 1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. Co-reciCompany Services, Inc.) Department of Energy.

1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and Waste 1993 Environmental Award presented by the Georgia Chamber of Commerce.

Tidd PFBC Demonstration Project (The Ohio Power 1992 National Energy Resource Organization award for demonstration of energy-efficient technCompany) 1991 Powerplant Award presented by Power magazine to American Electric Power Company’s 

The Babcock & Wilcox Company.

Tampa Electric Integrated Gasification Combined- 1997 Powerplant Award presented by Power magazine to Tampa Electric’s Polk Power Station

Cycle Project (Tampa Electric Company) 1996 Association of Builders and Contractors Award presented to Tampa Electric for quality of 

1993 Ecological Society of America Corporate Award presented to Tampa Electric for its innov1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of Flor

process.

1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innovative 

Wabash River Coal Gasification Repowering Project 1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc.(Wabash River Coal Gasification Repowering Project 1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 1996 AmJoint Venture) Council competition.Development of the Coal Quality ExpertTM (ABB 1996 Recognized by then Secretary of Energy Hazel O’Leary and EPRI President Richard Balz

Combustion Engineering, Inc. and CQ Inc.) DOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership P
Exhibit ES-12

PPII Technology Characteristics

Project Participant Process Combustion Initiative for Innovative Cost-Effective NO

x Alliant Energy Corporation Combustion Initiative method and re-engineering/mo

Reduction optimize system performance to reduce NOx emission

Development of Hybrid FLGR/SNCR/SCR Advanced NOx Arthur D. Little, Inc. A hybrid of Fuel-Lean Gas Reburn/Selective Non-Ca

Control for Orion Avon Lake Unit 9 Reduction, Selective Non-Catalytic Reduction, and S

Catalytic Reduction

Greenidge Multi-Pollutant Control Project CONSOL Energy, Inc. Single-bed Selective Catalytic Reduction in combinat

low-NO

x combustion technology to control NOx and 

dry scrubber to control SO2, mercury, and acid gases

Demonstration of a Full-Scale Retrofit of the Advanced Otter Tail Power Company Advanced Hybrid Particulate Collector 

Hybrid Particulate Collector TechnologyAchieving New Source Performance Standards Emission Sunflower Electric Power Ultra-low NOx burners with other combustion-stage c

Standards Through Integration of Low-NOx Burners with Corporationan Optimization Plan for Boiler CombustionPolk Power Station Plant Improvement Project Tampa Electric Company Refractory lining wear monitor (project withdrawn) Big Bend Power Station Neural Network-Sootblower Tampa Electric Company Neural-network soot-blowing system in conjunction wOptimization advanced controls and instrumentsCommercial Demonstration of the Manufactured Universal Aggregates, LLC Aggregate manufacturing plant using by-products froAggregate Processing Technology Utilizing Spray Dryer dryer desulfurization unitAsh
ES-26 Program Update 2001
1. Role of the CCT ProgramIntroductionOver the past quarter century, both nationally and internationally the energy picture has been one of continualchange, including the oil embargoes of the 1970s andthe environmental debates of the 1980s. The 1990sbrought about more changes in response to requiredemission reductions for acid rain precursors, initiationof more stringent nitrogen oxides (NOx) standards forozone nonattainment areas, tighter standards on fineparticulates, the beginning of electric utility restructuring, and concern about global warming.Upon entering the 21st century, the immediate challengeis to meet escalating domestic demands for electricpower and to assuage associated electricity deliveryreliability concerns. This challenge comes at a timewhen natural gas prices are extremely volatile andenvironmental regulations are increasingly stringent.The Clean Coal Technology Demonstration Program(CCT Program), was begun in fiscal year 1985, hasresponded to the many changes experienced throughthe 1990s. Adjustments were enabled by spacing aseries of five competitive solicitations from 1986 to1992. The CCT Program has provided a strongfoundation for responding to the challenges nowemerging in the energy market.The CCT Program is implemented through a uniquecost-shared government/industry partnership thatallows each party to best apply its expertise and carryout appropriate roles. The magnitude of the projectsand extent of industry participation in the CCT Program is unprecedented. More than $5.2 billion is beingexpended, with industry and state governments investing two dollars for every federal government dollar

invested. With 79 percent of the 38 projects havingcompleted operations by the end of fiscal year 2001,the technological successes have manifested themselves in the marketplace. New technologies to reducethe emissions of acid rain precursors, namely sulfurdioxide (SO2) and NOx, are now in the marketplace and

are being used by electric power producers and heavyindustry. Advanced electric power generation systemsthat generate electricity with greater efficiency andfewer environmental consequences are now operatingwith the nation’s most plentiful fossil energy resource—coal. Coal, which accounts for over 94 percentof the proven fossil energy reserves in the UnitedStates, supplies the bulk of the low-cost, reliable electricity vital to the nation’s economy and global competitiveness. According to the U.S. Department ofEnergy’s (DOE) Energy Information Administration(EIA) Annual Energy Review 2000 (August 2001)(AER2000), 991 million tons of coal were used to produce over 1,964 billion kilowatt-hours (net) or 52 percent of the nation’s electricity in 2000. The EIA projections count on coal continuing to dominate electricpower production, at least through 2020 (the end of theforecast period). In the Annual Energy Outlook 2002(December 2001) (AEO2002), EIA estimates 1,254million tons of coal will generate an estimated 2,472billion kilowatt-hours or 45 percent of all electricitygenerated in 2020. The coal consumption and electricity generation estimates are five percent higher than theprevious year’s estimates by EIA due to projected increased demand and new capacity.The ability of coal and coal technologies to respond tothe nation’s need for low-cost, reliable electricityhinges 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 consistent with c

restructuring. The CCT requirements by producoal-based technologieits prominent role in thfuture. Furthermore, adfrom the CCT Program petitive position in the technology advances in use of coal, will reduce greatly improving envicoal could increase its sector through cogenercoproduction of producWhile the CCT Prografor competitive and clepositions U.S. industry power market abroad. Emost rapidly growing fthe world. Projections Outlook 2001 (March 2ity demand rising from in 1999 to 22.2 trillion strongest growth is prodeveloping countries orepresents a tremendouopportunity to make a sions through the applicoal technologies.
1-2 Program Update 2001

CCT Program EvolutionThe environmentally sound and competitive performance of modern coal technologies has evolvedthrough many years of industry and government research, development, and demonstration (RD&D). Theprograms were pursued to assure that the U.S. recoverable coal reserves of 274 billion tons, which representa secure, low-cost energy source, could continue tosupply the nation’s energy needs economically and inan environmentally acceptable manner.During the 1970s and early 1980s, many of the government-sponsored technology demonstrations focused onsynthetic 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 disruptions of crude oilimports.The SFC’s purpose was accomplished by encouragingthe private sector to build and operate synthetic fuelproduction facilities that would use abundant domesticenergy resources, primarily coal and oil shale. Thestrategy was for the SFC to be primarily a financier ofpioneer commercial and near-commercial scale facilities. The goal of the SFC was to achieve productioncapacities of 500,000 barrels per day of synthetic fuelsby 1987 and 2 million barrels per day by 1992, at anestimated cost of $8.8 billion.By 1985, the market drivers for synthetic fuels dissolved as oil prices declined, world oil supplies stabilized, and a short-term supply buffer was provided bythe Strategic Petroleum Reserve. In 1986, Congressresponded to the decline of private-sector interest inthe production of synthetic fuels in light of these market conditions. Public Law 99-190, the Department ofthe Interior and Related Agencies Appropriations Actfor fiscal year 1986, abolished the SFC and transferredproject management to the Treasury Department.

The CCT Program was initiated in October 1984. PublicLaw 98-473, Joint Resolution Making Continuing Appropriation for Fiscal Year 1985 and Other Purposes,provided $750 million from the Energy Security Reserveto be deposited in a separate account in the U.S. Treasury entitled The Clean Coal Technology Reserve. Thenation moved from an energy policy based on syntheticfuels production to a more balanced policy. This policyestablished 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 essentialelement in this energy policy for the foreseeable futurebecause 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 areavailable.

• A multi-billion dollar infrastructure is in place to

gather, transport, and deliver this valuable energycommodity to serve the domestic and internationalmarketplace.

• Coal is used to produce over half of the nation’s

electric power and is vital to industrial 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 the coal industry’sproduction is dispersed and flexible, the deliverynetwork is vast, and the stockpiling capability isgreat.

• Coal is the fuel of necessity in many lesser developed economies, which provides export opportunities for U.S.-developed, coal-based technologies.

Congress recognized thacoal as a source of energonstration and commerction of advanced coal-baby enhanced operationalperformance. The CCT Pdemonstrate the commertechnology applications 1986, DOE issued the ficlean coal technology prresulted in a broad range four major product markdevices, advanced electrcessing for clean fuels, aIn 1987, the CCT Prograsatisfying the recommenReport of the Special EnPresidential initiative lauU.S. government/industracid rain formation—SO

solicitation (CCT-II), issvided for the demonstratcapable of achieving sigSO2, NOx, or both, from 

technologies were to be current technologies and ployment in the 1990s. Ithird solicitation (CCT-Iobjective as the second, technologies that would of-mine coal.The next two solicitationand environmental issuechange and capping of S

focused on seeking highpetitive, and low-emissiothe fourth solicitation (C1991, had as its objectivefficient, economically cpable of retrofitting, repofacilities while achieving 
and NO

x emissions. In July 1992, DOE issued the fifth

and final solicitation (CCT-V) to provide for demonstration projects that significantly advanced the efficiency and environmental performance of technologiesapplicable to new or existing facilities. As a result ofthese five solicitations, a total of 60 government/industry cost-shared projects were selected, of which 38,valued at more than $5.2 billion, have either been successfully completed or remain active in the CCT Program.The success of the government/industry CCT Programis directly attributable to the CCT Programís responsiveness to public and private sector needs to reduceenvironmental emissions and maximize economic andefficient energy production. The CCT Program isstrengthening the economy, enhancing energy security,and reducing the vulnerability of the economy to globalenergy market shocks.

Environmental ImpetusSO2 RegulationAcid Rain Mitigation. During the late 1980s, workbegan on drafting what was to become the Clean AirAct Amendments of 1990 (CAAA). On November 15,1990, Congress enacted the CAAA as Public Law101-549. Title IV, Acid Deposition Control, establishedemissions-reduction targets for SO2 and capped SO2emission in the post-2000 time frame. Title IV is thefirst large-scale approach to regulating overall emissions levels by using marketable allowances. The utilities can adopt a control strategy that is most cost-effective for their given systems and plants rather than having to apply a ìcommand-and-controlî approachwherein the emission-reduction method is specified.

The emission-reduction requirements for SO2 were

instituted in two phases. Phase I provided for the initialincrement of SO2 reduction, beginning on January 1,

1995. Phase II began on January 1, 2000. Title IVidentified 261 generating units (designated as ìaffectedunitsî) that were required to comply with Phase I. Mostof these are coal-fired units with fairly high emissionrates. Exhibit 1-1 summarizes the compliance methodsused by the 261 affected units listed in Title IV to satisfy Phase I requirements. An additional 174 unitsparticipated in Phase I based on U.S. EnvironmentalProtection Agency (EPA) rules that allow a utility todesignate substitution or compensating units as part ofPhase I compliance strategies. Therefore, 435 units areconsidered Phase I units. Under Phase II, all 1,063coal-fired utility boilers are affected.As a result of Phase I, SO2 emissions at electric utilitiesdeclined from 15.6 million tons per year in 1990 to12.5 million tons per year in 1997, a 20 percent decline. As shown in Exhibit 1-1, switching to low-sulfurcoal was the optionchosen by more thanhalf of the owners ofPhase I-affected units.In Phase II, all existing boilers must meetSO2 emission levels of1.2 lb/106 Btu and asliding-scale percentreduction of 70 to 90percent, dependingupon the input sulfurcontent. The resultantSO2 emission levels

are generally0.3 lb/106 Btu for lowsulfur coals and

0.6 lb/106 Btu forhigh-sulfur coals.Moreover, the CAAAcalls for SO2 emissions

to be limited to 9.48 m2000 and 2009 and 8.9ter. EIA predicts that 1fitted with scrubbers to Several projects within were designated affecteachieve compliance wiï Northern Indiana Pu

Generating Station, (Pure Air advanced ber);

ï Georgia Power Com

Unit No. 1 (Chiyoda flue gas desulfurizat

ï New York State Ele

Milliken Station, 30(S-H-U formic-acidber); and

Exhibit 1-1

Phase I SO2 Compliance 

Method No. of % of Re

Units Units 19

Fuel switching/blending 136 52 Additional SO2 allowances 83 32 

Scrubbers 27 10 Retirements 7 3 

Otherb 8 3 

 Total 261 100 

a Includes reduced coal consumption of 2.5 million tons and 16% b Includes 1 repowered unit, 2 switched to natural gas, and 5 switc

Source: The Effects of Title IV of the Clean Air Act AmendmentUtilities: An Update, Energy Information Administration, March 
1-4 Program Update 2001

• PSI Energy’s Wabash River Station, 262-MWe Unit

No. 1 (repowered with Destec integrated gasification combined-cycle unit).

The three Phase I scrubber projects served to redefinethe state-of-the-art in wet limestone scrubber technology and Wabash was the first to introduce integratedgasification combined-cycle as a repowering technology. The advanced scrubbers essentially halved thecost of conventional scrubbers of the time. The repowering project represented an option provided under theCAAA that allows a four-year extension (to December31, 2003) for compliance with Phase II requirementswhen advanced electric power generation technology isapplied. Together with the other clean coal projects, theCCT Program has afforded a portfolio of SO2 compliance options for the diverse fleet of existing coal-fired

electric generating units and the means to meet futureenergy and environmental demands. These includeadvanced scrubbers, low-capital-cost sorbent injectionsystems, clean high-energy-density fuels from botheastern and western coals, and a range of advancedelectric power generation systems.

NOxRegulationAcid Rain Mitigation. In Title IV of the CAAA, Congress also required the EPA to establish annual allowable emissions limitations for NO

x in two phases. Phase

I required NOx reductions from tangentially fired and

dry-bottom wall-fired boilers. These boilers are referred to as Group 1 boilers. In March 1994, EPA promulgated a rule establishing NOx emission limitations

of 0.45 lb/106 Btu for tangentially fired units and 0.50

lb/106 Btu for wall-fired units. Ultimately, a compliance date of January 1, 1996, was established.

On December 19, 1996, EPA issued a rule to implement Phase II. The rule established NO

x 

emission limitations for additional coal-fired boilers (Group 2) and

reduced the NO

x emissions limitations on Group 1 boilers. The types of Group 1 and 2 boilers and the Phase I and II NOx emission limits are shown in Exhibit 1-2. In response to the need to formulate NOx emission re- ductions that were realistic and achievable for Group 1, EPA was able to use data developed under the CCT Program during the Southern Company Services’ evaluation of NOx control technologies on wall-fired and tangentially fired boilers. Furthermore, NOx con- trols were developed under the CCT Program for all five major boiler types (wall-fired, tangentially fired, cyclone-fired, cell-burner, and vertically fired), which constitute over 97 percent of existing U.S. coal-fired utility boiler types. Low-NOx burners were developed for all boiler types amenable to burner modification. As a result, an estimated 75 percent of existing U.S. coal-fired utility boilers have been or currently are being retrofitted. The CCT Program also demonstrated a range of NOx control tech- niques to address boilers where burner modification is not practical and to pro- vide methods to en- hance NOx control beyond low-NOx burner capability. These options in- cluded coal and gas reburning, selective noncatalytic reduc- tion (SNCR), and selective catalytic reduction (SCR). This portfolio of NOx controls not only assured that Phase I and II emission reductions were achieved, but provided t

to develop technology careductions required to mQuality Standards (NAAticulate matter under TitSoot and Smog. In July CAAA, EPA issued finasecondary NAAQS for pozone (O3) (commonly r

regulations). The soot provisions addrtions of particulate mattemillionths of a meter (m(PM2.5). Previous fine pa

airborne material in the i

Exhibit 1-2 CAAA NOxEmission L

Group 1 Group 2 Phase I NOBoiler Type Boiler Type Emission L

(lb/106Btu) 

Tangentially fired boilers 0.45 Dry-bottom wall- fired boilersb 0.50 

Cell-burner boilers Cyclone boiler >155 MWe Wet-bottom wall- fired boilers >65 MWe Vertically fired boilers 

aEmission limits are lb/106Btu of heat input on an annual average basbOther than units applying cell-burner technology.
in diameter or less (PM10). The PM2.5 standard affectsprimary sources such as fly ash, carbon soot, and acidmists (aerosols) and secondary sources such as ammonium sulfates and nitrates from precursor SO2 and NOxgases. Monitoring to ascertain PM2.5 attainment is ongoing, with designations of non-attainment expected by

2003–2004. State Implementation Plans (SIPs) forcompliance are expected by 2007–2008, with compliance by 2013–2014.The ozone standards in turn impact NOx emissionsbecause NO

x is a precursor to ozone formation. As an

interim measure, EPA issued a rulemaking in responseto recommendations of a 37-state Ozone TransportAssessment Group (OTAG). The rulemaking, in theform of a “SIP Call,” requires 22 eastern states and theDistrict of Columbia to reduce NO

x 

emissions according to specified amounts (budgets) by May 2003. The

expected emission limits for power plants is 0.15 lb/106Btu, which generally requires relatively expensive selective catalytic reduction (SCR) technology. Under thegeneral provisions of the ozone NAAQS provisions,SIPs are expected by 2003, with compliance ranging

from 2003–2018 depending on the air quality in a particular area.The EPA is also formulating a plan for utilities andindustries to trade allowances for NO

x 

emissions. The

“cap and trade” program would apply to the 23 jurisdictions affected by the SIP Call. Under the plan, theaffected jurisdictions would establish a cap on NOxemissions and then give power plants and industries theflexibility to cut NOx emissions in the most cost-effective manner. Power plants and industries that cut NOxemissions below the caps could sell credits to facilitiesthat could not cut emissions as quickly or cost-effectively. The NOx trading program, similar to the existing

SO2 trading program, allows sources to pursue various

compliance strategies, such as fuel switching; installingpollution control devices, like the devices demonstrated in the CCT Program; or buying allowances fromsources that over-complied.New Source Performance Standards. On the nationallevel, the EPA has tightened its NOx emission standardsfor new electric utility boilers and has changed its rulesso that all generation fuels are treated the same. Underthe revised New Source Performance Standards(NSPS), electric utility and industrial steam generatingunits built or modified after July 9, 1997, must meet anemission limit of 1.6 lb/MWh regardless of fuel type.However, under EPA’s so-called “WEPCO Rule” existing units may be subject to NSPS as a result of certainmodifications. By basing the standard on electricityoutput, there is an economic incentive to use more efficient systems.Hazardous Air PollutantsHazardous Air Pollutant Monitoring. Under Title IIIof the CAAA, EPA is responsible for determining thehazards to public health posed by 189 hazardous airpollutants (HAPs), and is required to perform a studyof HAPs to determine the public health risks that arelikely to occur as a result of power plant emissions. Toaddress this issue, DOE implemented a program with

NO

x emissions at Georgia Power’s Plant Hammond were

reduced by 63 percent with Foster Wheeler’s low-NOx

burners, shown here, and advanced overfire air.

Low-NO

x burner technolog

LNCFSTM for tangentially Wheeler’s low-NO

x burner 

Babcock & Wilcox’s LNCB

right), and Babcock & Wil

boilers (bottom left).industry to monitor HAproject sites. Objective(1) improve the quality and (2) monitor a broadand emissions control eprogram, 20 CCT projemonitored HAPs, with by September 2001 (seIn a parallel effort beguthe participation of DODevelopment ProgramInstitute (EPRI), and th(UARG), began an emusing state-of-the-art sa
1-6 Program Update 2001

Emissions data were collected from eight utilities representing nine process configurations, several of whichwere CCT Program projects. These utilities represented different coal types, process configurations,furnace types, and pollution control methods. The report, A Comprehensive Assessment of Toxic Emissionsfrom Coal-Fired Power Plants: Phase I Results fromthe U.S. Department of Energy Study, was released inSeptember 1996 and provided the raw data from theemissions testing. The second phase of the DOE/EPRIeffort involved sampling at other sites, including theCCT Program’s Wabash River, Tampa Electric, andSierra Pacific integrated gasification combined-cycle(IGCC) projects.In another DOE study, HAPs data were collected from16 power plants and reported in Summary of Air ToxicsEmissions Testing at Sixteen Utility Plants. The report,issued in July 1996, provides an assessment of HAPsmeasured in the coal, across the major pollution controldevices, and emitted from the stack. The results of theHAPs program significantly have mitigated concernsabout a broad range of HAPs emissions from coal-firedpower generation, and focused attention on mercury.

Mercury. Following up on the October 1996 EPA report to Congress, Study of Hazardous Air PollutantEmissions from Electric Utility Steam GeneratingUnits—Interim Final Report (final report was issuedFebruary 1998), the Mercury Study Report to

Congress, issued December 1997, estimates that U.S.industrial sources were responsible for releasing 158tons of mercury into the atmosphere in 1994 and 1995.The EPA estimates that 87 percent of those emissionsoriginated from combustion sources such as waste andfossil fuel facilities, 10 percent from manufacturingfacilities, 2 percent from area sources, and 1 percentfrom other sources. The EPA also identified four specific categories that account for about 80 percent of thetotal anthropogenic sources: coal-fired power plants,33 percent; municipal waste incinerators, 18 percent;commercial and industrial boilers, 18 percent; andmedical waste incinerators, 10 percent.In December 2000, EPA decided to develop regulations for mercury emissions. The schedule calls forEPA to issue proposed regulations for comment by2003 and issue final regulations by 2005.

Global Climate ChangeThe CCT Program had its roots in the reduction of acidrain precursors and was responsive to the recommendations contained in the Joint Report of the Special Envoys on Acid Rain, as discussed earlier. Moreover, asconcerns over global climate change emerged, the CCTProgram began to emphasize demonstration of advanced electric power generation technology capableof achieving significantly higher efficiency than conventional systems, thus reducing carbon emissions.For example, integrated gasification combined-cycle(IGCC) has efficiencies up to 25 percent higher thanconventional coal-fired systems, which results in a likereduction in carbon emissions. There are four IGCCdemonstration projects in the CCT Program, representing a diversity of gasifier types and cleanup systems.

These projects are pionefriendly technology, whiemissions, boasts very loIGCC technology offers can be constructed in moCurrent worldwide markogy is approximately 5 ggrowing.Eight SCR catalysts with vawere evaluated side by side high-sulfur coal. NOx reduct

Wabash River was one of the sites where DOE and EPRIcollected HAPs data.
Regional HazeIn July 1999, EPA published a new rule calling forlong-term protection of and improvement in visibilityfor 156 national parks and wilderness areas across thecountry. Many environmental groups believe coal-firedpower plants are a source of regional haze in the national parks and wilderness areas.During the period 2003-2008, states are required toestablish goals for improving visibility in each of these156 areas and adopt emission-reduction strategies forthe period extending to 2018. States have flexibility toset these goals based upon certain factors, but as part ofthe process, they must consider the rate of progressneeded to reach natural visibility conditions in 60years. Coal-fired power plants are likely targets for newcontrols to reduce regional haze.Solid WasteThe CCT Program also addresses the issue of solidwaste. For example, several projects redefined thestate-of-the-art in wet flue gas desulfurization. Includedin this significant technology improvement was production of commercial-grade gypsum in lieu of the scrubber sludge associated with conventional scrubbers ofthe early 1990s. Scrubber sludge had been projected torequire over 4,500 acres per year for disposal by 2015.Advances under the CCT Program precluded that need.The balance of technologies in the CCT Program alsoaddress solid waste concerns by producing salable byproducts instead of wastes (e.g., sulfur, sulfuric acid, orfertilizer) or dry, environmentally benign materials.These dry materials can be used as construction materials (e.g., for use in soil and roadbed stabilization, or as

a cement ingredient), agricultural supplements, a meansto mitigate mine subsidence and acid mine drainage, orcan be readily disposed of in landfills.

Toxics Release InventorySection 313 of the Emergency Planning and Community Right-To-Know Act (EPCRA) and Section 6607 ofthe Pollution Prevention Act (PPA) mandate establishment of a publicly accessible database containing information on the release of toxic chemicals by facilitiesthat manufacture, process, or otherwise use them. Thisdatabase is known as the Toxics Release Inventory(TRI). Starting in 2000, electric utilities were requiredto report on releases of toxic chemicals into the air,water, and land. The EPA compiles this data in anonline TRI database that gives access to detailed information about releases of toxic chemicals in their communities. It is expected that electric utilities will exceedchemical manufacturers as the largest emitters of toxicchemicals into the environment. Although the emissionrates are low for electric utilities, the volume of emissions will likely bring pressure for further reductions.MarketConsiderationsWhen the CCT Program started in 1985,the electric utility industry was highlyregulated. The major uncertainty was thebreadth and depth of environmental regulatory requirements that would be imposed on the industry. Even this uncertainty was mitigated by the fact that theenvironmental control costs could bepassed through to the consumer if approved by the state regulatory commission. As long as the utility made prudentinvestments in plant and equipment, itseconomic future was fairly stable andpredictable. Most industry observers

assumed that coal and nburden of baseload genout, and natural gas woload requirements.By mid-1997, the pictuutility industry was in tto accommodate a comutility restructuring, porisk for new capacity acapital cost and short lesystems make them the seeable future. As a resnatural gas to be the fuadditions through 2020nuclear-based capacity based capacity is projeConsumers also becamcompetition and regulators provide the oversigsumers were paying a f

Hazardous air pollutants were measureCompany’s Demonstration of Coal Reb

at Nelson Dewey Station.
1-8 Program Update 2001

tion, end users are not required to purchase power fromtheir local utility company, but instead may purchasepower from generators or marketers located in otherstates and regions of the country. In this competitivemarket environment, power is priced according to market conditions, not necessarily according to generationcosts.Advancement in the technology of electricity production is another factor that has had an impact on restructuring. Nonutility generators have taken advantage ofthese advances, such as aero-derived gas turbines, togenerate electricity cheaper than can be achieved usingconventional fossil steam or nuclear generators. Thenew technologies are often more efficient, less environmentally obtrusive, and can be installed in a very shortperiod of time in capacity modules closely matchingthe 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 environmental regulation discussed previously. According to EIA’s AEO2002, coal

is projected to maintain its lead in the production ofelectricity in 2010 at 49 percent; however, that is downfrom 60 percent when the CCT Program started. Thedifferential has been, for the most part, made up by thegrowth in natural gas power generation. Nuclearpower’s contribution to the nation’s electric powergeneration in 2010 is expected to drop by almost 30percent between the 1985 and 2001 projections.Industry restructuring and competition will impact coaland coal technologies for the foreseeable future. Utilities are expected to

improve their operating efficiencies byusing existing plantsat higher capacityfactors. Contributingto increased capacityfactors is a projecteddrop in generatingcapacity not onlyfrom nuclear plantretirements but capacity losses fromfossil-fueled plantretirements. EIApredicts that nearly31 GW of new coalfired capacity is expected to come online between 2000and 2020, accounting for 9 percent ofcapacity expansion.

During this time, new higpower systems will enter kets. New concepts to reprices will likely be empminemouth plants that retransportation cost compAlso, cogeneration and cavailable, which allow thity potentially to be reduproducts.

Ensuring SuEconomic GIt is in the national intereenergy mix to sustain nais a key component of naof its affordability, availthe nation’s borders. The to the development and dportfolio that enhances tresource while assuring ronmental goals are achisources are large enough than 250 years at current The United States is incrported oil as lower averavolatility have resulted iduction for 13 years. Than oil production capacirels per day. In 2000, nemillion barrels per day, osumption. The AEO2002 for net imports of 16.6 mover 62 percent of the to

General Electric’s Advanced Turbine System combustion turbine.
imports are expected to grow from 15.5 percent of totalgas consumption in 2000 to 16.2 percent in 2020.These imports are primarily from Canada, which doesnot represent a supply stability problem, but does represent a drain on balance of payments. Other sources ofimports include liquefied natural gas (LNG), which isexpected to increase with two new LNG facilities, oneopened in September 2001 and the other is scheduledto open in 2002.United States coal consumption is 1,081 milliontons/year, which is equivalent to approximately 3.8billion barrels of oil per day, and equates to $106 billion/year using 2000 average oil prices. The CCT Program will provide the technologies that will enablecoal to continue as a major component in the nation’seconomy while achieving the environmental qualitythat society demands. Coal-related jobs are dispersedthrough the mining, transportation, manufacturing,utility, and supporting industries.A U.S. coal conversion industry could directly reducethe 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. TheCCT Program is responding to this opportunity throughdevelopment and demonstration of mild gasificationand liquid-phase methanol production technologies.Highlights of the EIA’s IEO2001 projections for coal

are as follows:• World coal consumption is projected to increase by

1.7 billion tons, from 4.7 billion tons in 1999 to 6.4billion tons in 2020. Alternative assumptions abouteconomic growth rates lead to forecasts of worldcoal consumption in 2020 ranging from 5.5 to 7.6billion tons per year.

• Coal use in developing Asia alone is projected to

increase by 1.7 billion tons from 1.7 billion tons in1999 to 3.4 billion tons in 2020. China and India

together are projected to account for 29 percent of thetotal increase in energy consumption worldwide between 1999 and 2020 and 92 percent of the world’stotal projected increase in coal use, on a Btu basis.

• Although coal use is expected to be displaced by

natural gas in some drop in coal’s total eby 2020 as other fuecoal in world total pexpected to decline percent in 2020. Coworldwide for electjected to decline, fropercent in 2020.

• World coal trade is p

million tons in 1999 accounting for betwworld coal consump(including coal for pfurnaces) accounts fcrease in world tradshare of this market competition from Acountries.

According to the latest wide market for power be as high as $80 billio

Exhibit 1-3

Comparison of Energy Projections for Electric Generators

Electricity Sales Coal Consumption Gas Consumption O(109 kWh/yr) (106 tons/yr) (1012 ft3/yr) (

NEPP AEO % ∆ NEPP AEO % ∆ NEPP AEO % ∆ N

1985 2002 1985 2002 1985 2002 1

1995 3,018 3,026b 0.27 924 958b 3.7 3.0 3.37b 12 

2010 4,176 4,170c -0.14 1,355 1,141 -15.8 1.7 8.91 424 

NEPP 1985: National Energy Policy Plan Projections to 2010, U.S. Department of Energy, December 1985.

AEO 2002: Annual Energy Outlook 2002 with Projections to 2020, Energy Information Agency, December 2001.% dif = percent difference between the two projections.

a Consumptions by electric generators excluding cogenerators.b Actuals from Annual Energy Outlook 1998, December 1997.c Electric generators and cogenerators.
1-10 Program Update 2001

PowerFuels

Hydrogen

Separation

Electricity

Fuel Chemicals

CO2 Sequestration

Gas Stream

Cleanup Gasification Oxygen Membrane

Coal

OtherFuels

ProcessHeatSteam

of the investment will be in developing countries. Thismarket provides opportunities for U.S. technologysuppliers, developers, architect/engineers, and otherU.S. firms to capitalize on the advantages gainedthrough experiences in the CCT Program. However,aggressive action is needed, as other governments arerecognizing the enormous economic benefits that theireconomies can enjoy if their manufacturers capture agreater share of this market.Beyond the CCT Program, DOE activities are aimed atcreating a favorable export climate for U.S. coal andcoal technology. These efforts include: (1) improvingthe visibility of U.S. firms and their products by establishing an information clearinghouse and closer liaisonwith U.S. representatives in other countries, (2)strengthening interagency coordination of federal programs pertinent to theseexports, and (3) improvingcurrent programs and policies for facilitating the financing of coal-relatedprojects abroad.

Looking to the FuturePower Plant Improvement InitiativeThe rapid growth in power demand, especially peakdemand, coupled with the ongoing restructuring of theelectric power industry, has resulted in a real and growing concern over the reliability of the nation’s electricity grid. This concern prompted Congress to add $95million to the Office of Fossil Energy budget for fiscalyear 2001 for the Power Plant Improvement Initiative,which is discussed in detail in Chapter 6.

Clean Coal Power IThe Clean Coal Power Inment/industry partnership National Energy Policy (crease investment in cleamendation, one of severadresses the national challof our electric supply whour environment. The Cbetween the government the NEP recommendatiocoal technology.” The godeployment of advanced United States has clean, rity. This ten-year initiativtotal federal cost share esmatching cost share of at ment of Energy is in the ition phases of the CCPI pVision 21The CCT Program is proto build a future generatipower systems capable oronmental demands of thand attendant databases environmental, and fuels meet the long-term goals Energy’s Coal & Power “Vision 21” goals are deexpected result is a suite pable of using a broad raand forestry, agriculturalwastes) to produce a varmodities (electricity, steaat greater than 60 percenemissions.

Vision 21 modules can be combined in a variety of configurations. One example, shownabove, incorporates modules to produce a variety of energy products.
First-generation systems emerging from the CCT Program provide: (1) the knowledge base from which tolaunch commercial systems, which will experienceincreasingly improved cost and performance over timethrough design refinement; and (2) platforms on whichto test new components, which will result in jumps incost and performance. Examples of new componentsinclude advanced hot gas particulate filtration, hot gassulfur and alkali removal, air separation membranes,high-temperature heat exchangers, artificial intelligence-based controls and sensors, and CO2 andhydrogen separation technologies. A strategy of theVision 21 effort is to develop and spin off such keycomponents to mitigate the risk and cost of integratingthe technologies into power, environmental, and fuelsystem modules.

Exhibit 1-4

Vision 21 Objectives

Efficiency—Electricity Coal-based systems 60% (HHV); natural gas-based systems 75% (LHV) withGeneration no credit for cogenerated steam.aEfficiency—Combined Overall thermal efficiency above 85% (HHV); also meetsHeat & Power efficiency goals for electricity.aEfficiency—Fuels Plant Only Fuel utilization efficiency of 75% (LHV) when producing coal derived fuels.aEnvironmental Near-zero emissions of sulfur, nitrogen oxides, particulate matter, trace elements, and

organic compounds; 40-50% reduction in CO2 emissions by efficiency improvement;

100% reduction with sequestration.

Costs Cost of electricity 10% lower than conventional systems; Vision 21 plant products

cost-competitive with market clearing prices.

Timing Major spinoffs such as improved gasifiers, advanced combustors, high-temperature

filters and heat exchangers, and gas separation membranes begin by 2004; designs formost Vision 21 subsystems and modules available by 2012; Vision 21 commercialplant designs available by 2015.

a The efficiency goal for a 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
1-12 Program Update 2001
2. CCT Program ImplementationIntroductionThe CCT Program founding principles andimplementing process resulted in one of the mostsuccessful cost-shared government/industrypartnerships forged to respond to critical nationalneeds. Through five nationwide competitions, a totalof 60 government/industry cost-shared projects wereselected, of which 38, valued at more than $5.2 billioneither have been completed or remain active at the endof fiscal year 2001. For the 38 projects, the industrycost-share is an unprecedented 66 percent. Thirty ofthe 38 projects have completed operations. Thebalance are moving forward, with operational testingunder way for one project. The remaining projects areeither in the design or construction phase.Over the nine-year period of soliciting and awardingprojects, the thrust of the environmental concernsrelative to coal use have changed. Nevertheless, theimplementing process allowed the program to remainresponsive to the changing needs. The result is aportfolio of technologies and a database of technicaland cost information that will enable coal to remain amajor contributor to the U.S. energy mix without beinga threat to the environment. This result will ensuresecure, low-cost energy requisite to a healthy economywell into the 21st century.Success of the CCT Program is measured by the degreeto which the operational, environmental, and economicperformance of a technology can be projected forcommercial applications. Decision makers must have asufficient database to project performance and assessrisk for commercial introduction and deployment ofnew technologies. This need for information was a

driving force in establishing the principles that createdthe foundation for the implementation process. Thegovernment role is non-traditional, moving away froma command-and-control approach to a performancebased approach, where the government setsperformance objectives and industry responds with itsideas and is allowed broad latitude in technicalmanagement of the projects. This approach encouragestechnology innovation and cost-sharing. Industry andthe public play major roles in the process, reflectingtheir respective roles in moving technologies into themarketplace.Implementation PrinciplesThe principles underlying the CCT Program weredeveloped after much study of previous governmentdemonstration programs, assessing both positive andnegative results. The principles represent a compositeof incentives and checks and balances that allows allparticipants 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 thegovernment’s share of selected projects wasappropriated by Congress at the start of theprogram. This up-front commitment has been vitalto getting industry’s response in terms of quantityand quality of proposals received and theachievement of 66 percent cost-sharing.

• Multiple solicitations spread over a number of

years enabled the program to address a broadrange of national needs with a portfolio of

evolving technologsolicitations enabled the program to meet provided DOE time process based on lessolicitations; and prto develop better prpropose evolving te

• Demonstrations ar

scale in actual user technology is constrfull system integraticommercial configucommercial facility commercial facility. performance potentcommercial environ

• The technical agen

and not the governestablished by Congreceived, DOE set dand performance-bawhich proposals wogiven the flexibility innovation to define project in response The Department of best met the evaluat

• Roles of the govern

defined and reflect required. The goveup front in structurinprotect public interedefinitive performanpoints throughout thbegins, the industriatechnical manageme
2-2 Program Update 2001

oversees the project through aggressive monitoringand engages in implementation only at decisionpoints. Continued government support is assured aslong as project milestones and the terms andconditions of the original cooperative agreementcontinue 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 anddirectly related to the project, with no credit forprevious work. By sharing essentially in each dollarexpended along the way, on at least an equal basis,industry’s commitment to fulfilling projectobjectives was strengthened.

• Allowance for cost growth provides an important

check-and-balance feature to the program.Statutory provisions allow for additional financialassistance beyond the original agreement in anamount up to 25 percent of DOE’s originalcontribution. Such financial assistance, if provided,must be cost-shared by the industrial participant atno less than the cost-share ratio of the originalcooperative agreement. This statutory provisionrecognizes the risk involved in first-of-a-kinddemonstrations by allowing for cost growth. At thesame time, it recognizes the need for the industrialparticipant’s commitment to share cost growth andlimits the government’s exposure.

• Industry retains real and intellectual property

rights. The level of cost-sharing warrants theindustrial participant retaining intellectual and realproperty rights and removes potential constraints tocommercialization. Industry would otherwise bereluctant to come forward with technologiesdeveloped to the point of demonstration,relinquishing their competitive position.

• Industry must make a commitment to

commercialize the technology. Consistent withprogram goals, the industrial participant is requiredto make the technology available on anondiscriminatory basis, under reasonable terms and

conditions, to all U.S. companies that seek to usethe technology. While the technology owner is notforced to divulge know-how to a competitor, thetechnology must be made available to potentialdomestic users on reasonable commercial terms.

• Upon successful commercialization of the

technology, repayment up to the government’scost-share is required. The repayment obligationoccurs only upon successful commercialization ofthe technology. It is limited to the government’slevel of cost-sharing and the 20-year periodfollowing the demonstration.

In summary, these principles provide built-in checksand balances to ensure that the industry andgovernment roles are appropriate and that thegovernment serves as a risk-sharing partner withoutimpeding industry from using its expertise and gettingthe technology into the marketplace.Implementation ProcessSignificant public and private sector involvement wasintegral to the process leading to technologydemonstration and critical to program success. Evenbefore engaging in a solicitation, a public process wasinstituted under the National Environmental Policy Act(NEPA) to review the environmental impacts. Aprogrammatic environmental impact assessment(PEIA), followed by a programmatic environmentalimpact statement (PEIS), was prepared prior toinitiating solicitations. Public comment and resolutionof comments were required prior to proceeding withthe program.As to the solicitation process, Congress set the goalsfor each solicitation in the enabling legislation andreport language (see Appendix A for legislative historyand Appendix B for program implementation history).

The Department of Energuidance and direction iand developed approachfrom previous solicitatiosolicitation, however, an solicitation and attendanpresented in a series of robtain feedback. The pualong the lines of workshand obtain comments frointerests. Comments frowere used in preparing a turn was issued for publireceived were formally rissuance.To aid proposers, preprofor the purpose of clarifysolicitation. Further, evesolicitation to impart a cbeing sought, how it woucontractual terms and cosection of the solicitation potential proposers deterand numerical quantificawas provided. The soliccooperative agreement wcontractual terms and coProject selection and negconducted under stringenpenalties for noncompliaand projects negotiated scriteria and terms and cosolicitation. In the spirit and evaluated included phealth, safety, and socioeimplementation.Upon project award, anoengaged to ensure that alconcerns were addressedtal Policy Act requires th
assessment be conducted to address all potentialenvironmental, health, safety, and socioeconomicimpacts associated with the project. The findings canprecipitate a more formal environmental impactstatement (EIS) process, or the findings can remain asan environmental assessment (EA) along with a findingof no significant impact (FONSI). During the EISprocess, public meetings are held for the purpose ofdisclosing the intended project activities, withemphasis on potential environmental, health, safety,and socioeconomic impacts, and planned mitigatingmeasures. Comments are sought and must be resolvedbefore the project can proceed. This process has led toadditional actions taken by the industrial participantsbeyond the original project scope. To facilitate theNEPA process, DOE encouraged environmental datacollection through cost-sharing during the negotiationperiod contingent upon project award.Because of the environmental nature of the CCTProgram, DOE took a proactive posture in followingthe principles of NEPA. Environmental concerns wereaggressively addressed and the public engaged prior tomajor expenditure of public funds. Furthermore, DOErequired that an in-depth environmental monitoringplan (EMP) be prepared, fully assessing potentialpollutant emissions, both regulated and unregulated,and defining the data to be collected and the methodsfor collection. All cooperative agreements requiredpreparation of environmental monitoring reports thatprovide results of the monitoring activities. Asenvironmental issues emerged, every effort was madeto address them directly with the understanding thatcommercial technology acceptance hinged onsatisfying users and the public as to acceptableenvironmental performance. Appendix C reviews theproactive environmental stance taken by the program,further delineates the NEPA process, and provides thestatus of key actions.Projects are managed by the participants, not thegovernment. However, public interests are protectedby requiring defined periods of performance referred to

as budget periods, throughout the project. Budgetperiods are keyed to major decision points. A setamount of funds is allotted to each budget period,along with performance criteria to be met beforereceiving funds for the next budget period. Thesecriteria are contained in project evaluation plans(PEPs). Progress reports and meetings during budgetperiods serve to keep the government informed. At thedecision points, progress against PEPs is formallyevaluated, as is the PEP for the next budget period.Financial data is also examined to ensure theparticipants’ capability to continue required costsharing. Failure to perform as expected results ingreater government involvement in the decision makingprocess. Proposal of major project changesprecipitates not only in-depth programmaticassessment, but legal and procurement review as well.Decisions regarding continuance into succeedingbudget periods, any increase in funding, or majorproject changes require the approval of DOE’sAssistant Secretary of Fossil Energy.

Beyond the formal prosolicitations, parallel estakeholders of ongointo engage them in discuensuring that the progrneeds. A continuing diinvolvement in the projutilities, technology suindustry-based research Power Research InstituThis was accompanied to enhance communicaindependent power prounderwriter, and financto identify those sectorthen structure seminars program and obtain the suggestions for enhancFurthermore, a periodito serve as a forum for results and discussing ithe CCT Program. Anin place to ensure that nprepared and disseminmanner, leveraging a vinternational conferencThese activities are disSection 4.During implementation precedent-setting actioinnovations were used sectors to overcome prmanagement systems aaccomplishment of shadeveloped in dealing warrangements of multimsignificant asset that haProgram’s success—an programs seeking to fopartnerships. To docum

Coal Technology Prog

The NEPA process assured environmental acceptability of theHealy Clean Coal Project on the border of Denali NationalPark in Alaska.
2-4 Program Update 2001

published in July 1994. This report documents theknowledge acquired over the course of the CCTProgram through the completion of five solicitations.The report was based on the belief that it is of mutualadvantage to the private and public sectors to identifythose factors thought to contribute to the program’ssuccess and to point out pitfalls encountered andcorrective actions taken.Subsequent to issuance of the Lessons Learneddocument in July 1994, other issues arose thatindicated further improvement in programimplementation was warranted. Several projectsrequired relocation, new partners, and redesign morethan once in order to move forward. These delaysresulted in federal resources underutilized for sometime. Also, repayment has not reached expected levels,which prompted preparation of a Repayment LessonsLearned document in 1997. The Department of Energyhas attempted to address these issues in the CCPIsolicitation issued in March 2002. Theseimprovements reflect the principles outlined in thePresident's Management Agenda, including theResearch and Development Investment Criteria.Commitment to CommercialRealizationThe CCT Program has been committed to commercialrealization since its inception. The significantenvironmental, operational, and economic benefits ofthe technologies being demonstrated in the programwill be realized when the technologies achievewidespread commercial success. The importanceattached to commercial realization of clean coaltechnologies is highlighted in Senate Report 99-82,which contains the following recommendation forproject evaluation criteria: “[t]he project must

demonstrate commercial feasibility of the technologyor process and be of commercial scale or of such sizeas to permit rapid commercial scale-up.”The commitment to commercial realization recognizesthe complementary but distinctive roles of thetechnology owner and the government. It is thetechnology owner’s role to retain and use theinformation and experience gained during thedemonstration and to promote the use of thetechnology in the domestic and internationalmarketplaces. The detailed operational, economic, andenvironmental data and the experience gained duringthe demonstration are vital to efforts to commercializethe technology. The government’s role is to capture,assess, and transfer operational, economic, andenvironmental information to a broad spectrum of theprivate sector and international community. Theinformation must be sufficient to allow potentialcommercial users to confidently screen thetechnologies and to identify those meeting operationalrequirements. The importance of commercialrealization is confirmed by the requirement in thesolicitations and cooperative agreements that theproject participant must pursue commercialization ofthe technology after successful demonstration.Each of the five solicitations contained requirementsfor the project proposals to include a discussion of thecommercialization plans and approaches to be used bythe participants. The proposer was required to discussthe following topics:• The critical factors required to achieve commercial

deployment, such as financing, licensing,engineering, manufacturing, and marketing;

• A timetable identifying major commercialization

goals and schedule for completion;

• Additional requirements for demonstration of the

technology at other operational scales, as well assignificant planned parallel efforts to thedemonstration project, that may affect thecommercialization approach or schedule; and

• The priority placed by 

accomplishing the cothe project fits into thbusiness, marketing, 

The cooperative agreemto ensure that the demonreplicated by responsible proprietary commercial owner. These three mecPressurized fluidized-bed cat Ohio Power Company’s Tcommercialization.
ï The commercialization clause requires the

technology owner to meet U.S. market demands forthe technology on a nondiscriminatory basis (thisclause ìflows downî from the project participant tothe project team members and contractors);

ï The clauses concerning rights to technical data deal

with the treatment of data developed jointly in theproject as well as data brought into the project; and

ï The patent clause affords protection for new

inventions developed in the project.

In addition to ensuring implementation of the aboveproject-specific mechanisms, the government role alsoincludes disseminating the operational, environmental,and economic performance information on thetechnologies to potential customers and stakeholders.To carry out this role, a CCT Outreach Program wasestablished to perform the following functions:ï Make the public and local, state, and federal

government policy makers aware of the CCTs andtheir operational, economic, and environmentalbenefits;

ï Provide potential domestic and foreign users of the

technologies with the information needed fordecision making;

ï Inform financial institutions and insurance

underwriters about the advancements in technologyand associated risk mitigation to increaseconfidence; and

ï Provide customers and stakeholders opportunities

for feedback on program direction and informationrequirements.

Specific accomplishments of the CCT OutreachProgram are discussed in Section 4.

Solicitation ResultsEach solicitation was issued as a Program OpportunityNotice (PON)óa solicitation mechanism forcooperative agreements where the program goals andobjectives are defined but the technology is not.Proposals for demonstration projects consistent withthe objectives of the PON were submitted to DOE byspecific deadlines. DOE evaluated, selected, andnegotiated projects strictly within the bounds of thePON provisions. Award was made only after Congresswas allowed 30 in-session days to consider the projectsas outlined in a Comprehensive Report to Congressissued after each solicitation.Exhibit 2-1 summarizes the results of solicitations.Exhibit 2-2 identifies the projects currently in the CCTProgram and the solicitation under which the projectswere selected. Appendix B provides a summary of theprocurement history and a chronology of projectselection,negotiation,restructuring, andcompletion ortermination. Projectsites are mapped inExhibits 2-3 through2-6, which indicatethe geographiclocations of projectsby applicationcategory.The resultantprojects haveachieved broadbased support.Team members forthe projects includemore than 50

utilities; more than 45 tthan 20 engineering, coOther team members inResearch Institute, the numerous state and locindustrial manufacturetribe.The contributions of thand international energsignificant. These contï Completing demons

viability of a suite ocontrol options capapercent) to deep (70reductions for the futypes;

ï Providing the databa

requisite to making combustion a commExhibit 2-1

CCT Program Selection Proc

Proposals Pr

Solicitation PON Issued Submitted SeCCT-I February 17, 1986 51 17 CCT-II February 22, 1988 55 16 CCT-III May 1, 1989 48 13 CCT-IV January 17, 1991 33 9 CCT-V July 6, 1992 24 5 Total 211 60 
2-6 Program Update 2001

Exhibit 2-2

Clean Coal Technology Demonstration Projects by Solicitation

Project and Participant LocCCT-IDevelopment of the Coal Quality Expertô (ABB Combustion Engineering, Inc. and CQ Inc.) HomLIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) LoraAdvanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) WillEnhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) HenTidd PFBC Demonstration Project (The Ohio Power Company) BrillAdvanced Coal Conversion Process Demonstration (Western SynCoal LLC) ColsNucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) NucJEA Large Scale CFB Combustion Demonstration Project (JEA) JackCCT-IISNOXô Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) NileDemonstration of Coal Reburning for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) Cass

SOx-NOx-Rox Boxô Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) DilleCement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) ThomAdvanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) CheDemonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) CooDemonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) NewDemonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High-Sulfur, Coal-Fired Boilers Pens

(Southern Company Services, Inc.)180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of NOx Emissions from Coal-Fired Lynn 

Boilers (Southern Company Services, Inc.)CCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHô) Process (Air Products Liquid Phase Conversion KingCompany, L.P.)10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) WesHealy Clean Coal Project (Alaska Industrial Development and Export Authority) HealFull-Scale Demonstration of Low-NO

x Cell Burner Retrofit (The Babcock & Wilcox Company) Abe
Exhibit 2-2 (continued)

Clean Coal Technology Demonstration Projects by Solicitation

Project and Participant LoCCT-III (continued)Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) SeBlast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) BuMcIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland Electric) LaENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Gi

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) D

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) RiIntegrated Dry NOx/SO2 Emissions Control System (Public Service Company of Colorado) D

Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) MCCT-IVMicronized Coal Reburning Demonstration for NOx Control (New York State Electric & Gas Corporation) La

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) LaPiñon Pine IGCC Power Project (Sierra Pacific Power Company) RePulse Combustor Design Qualification Test (ThermoChem, Inc.) BaWabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) W

CCT-VClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) FaClean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management Company LLC) ViKentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) TrMcIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, Lakeland Electric) La
2-8 Program Update 2001

Exhibit 2-3

Geographic Locations of CCT Projects—Environmental Control Devic
Exhibit 2-4

Geographic Locations of CCT Projects—Advanced Electric Power Gene
2-10 Program Update 2001

Exhibit 2-5

Geographic Locations of CCT Projects—Coal Processing for Clean Fu
Exhibit 2-6

Geographic Locations of CCT Projects—Industrial Applications
2-12 Program Update 2001

ï Completing demonstration of a number of coal

processes to produce high-energy-density, lowsulfur solid fuels and clean liquids from a range ofcoal types;

ï Laying the foundation for the next generation of

technologies to meet the energy and environmentaldemands of the 21st centuryóthree IGCC plants arein operation or have completed operations at threeseparate utilities; and successful demonstration ofpressurized fluidized-bed combustion at 70 MWeand two larger scale demonstrations are in progress;and

ï Demonstrating significant efficiency and pollutant

emission reduction enhancements in steel making,advanced combustion for combined SO2/NOx/PM

control for industrial and small utility boilers, andinnovative SO2 control for waste elimination in

cement production.

Future ImplementationDirectionThe future implementation direction of the CCTProgram focuses on completing the existing projects aspromptly as possible and assuring the collection,analysis, and reporting of the operational, economic,and environmental performance results that are neededto promote commercialization.In fiscal year 2002, the following projects arescheduled to commence operations:ï JEA Large-scale CFB Combustion Demonstration

Project, and

ï Clean Coal Diesel Demonstration Project.

For the same period, the following projects arescheduled to commence construction:ï Kentucky Pioneer Energy IGCC Demonstration

Project, and

ï Clean Power from Integrated Coal/Ore Reduction

(CPICORô).

In fiscal year 2002, the following project is forecastedto complete operations:ï Demonstration of Advanced Combustion

Techniques for a Wall-Fired Boiler.

The body of knowledge obtained as a result of theCCT Program demonstrations is being used inimmediate decision making relative to regulatorycompliance, forging plans for meeting future energyand environmental demands, and developing the nextgeneration of technology responsive to ever-increasingdemands on environmental performance at competitivecosts. An expanded portfolio of information will beforthcoming to make it easier for stakeholders andcustomers to sift through the already enormous amount

A Comprehensive Report to Congress was issued after each of data resulting from the demonstrations.

solicitation for each selected project.

Efforts will continue towof the program in responstakeholder needs. Towforums will be sought to view of utility restructurconcerns, and a burgeonare to ensure that CCT Pleveraged and that followResearch, Development, are appropriate.Two new initiatives arisiNational Energy PolicyóInitiative and Clean Coamany of the same implemCCT Program. These inlessons learned in the CC
3. CCT Program Funding and CostsIntroductionCongress has appropriated a federal budget of $2.2billion for the CCT Program. These funds have beencommitted to demonstration projects selected throughfive competitive solicitations. As of September 30,2001, the program consisted of 38 active or completedprojects. These 38 projects have resulted in a combined commitment by the federal government and theprivate sector of $5.2 billion. DOE’s cost-share forthese projects exceeds $1.7 billion, or approximately34 percent of the total. The project participants (i.e.,

the non-federal-government participants) are providingthe remaining $3.4 billion, or 66 percent of the total.Exhibit 3-1 summarizes the total costs of CCT projectsas well as cost-sharing by DOE and project participants. The data used to prepare Chapter 3 are based onthe 38 projects that were active in the CCT Program asof September 30, 2001.

Program FundingGeneral ProvisionsIn the CCT Program, the federal government’s contribution cannot exceed 50 percent of the total cost ofany individual project. The federal government’sfunding commitments and other terms of federal assistance are represented in a cooperative agreement negotiated for each project in the program. Each project

Exhibit 3-1

CCT Project Costs and Cost-Sha

(Dollars in Thousands)

Total Cost-Share Dollars 

Project Costs % DOEb Participants 

SubprogramCCT-I 844,363 16 239,640 604,723 CCT-II 318,577 6 139,229 179,348 

CCT-III 1,325,329 26 576,918 748,411 

CCT-IV 950,429 18 439,063 511,366 

CCT-V 1,765,009 34 360,982 1,404,027 

 Totala 5,203,707 100 1,755,832 3,447,875 

Application CategoryAdvanced Electric Power 2,864,284 55 1,118,865 1,745,419 GenerationEnvironmental Control Devices 620,110 12 252,866 367,244 

Coal Processing for Clean Fuels 431,810 8 192,029 239,781 

Industrial Applications 1,287,503 25 192,072 1,095,431 

 Totala 5,203,707 100 1,755,832 3,447,875 

a Totals may not add due to rounding.b DOE share does not include $99,840,000 obligated for withdrawn projects and audit expense
3-2 Program Update 2001

also has an agreement for the federal government torecoup up to the full amount of the federalgovernmentís contribution. This approach enablestaxpayers to benefit from commercially successfulprojects. This is in addition to the benefits derivedfrom the demonstration and commercial deployment oftechnologies that improve environmental quality andpromote the efficient use of the nationís coal resources.The project participant has primary responsibility forthe project. The federal government monitors projectactivities, provides technical advice, and assessesprogress by periodically reviewing project performance with the participant. The federal governmentalso participates in decision making at major projectjunctures negotiated into the cooperative agreement.Through these activities, the federal governmentensures the efficient use of public funds in the

achievement of individual project and overallprogram objectives.Congress has provided program funding through appropriation acts and adjustments. (See Appendix A forlegislative history and excerpts from the relevant funding legislation.)Exhibit 3-2 presents the allocation of appropriatedCCT Program funds (after adjustment) and the amountavailable for each CCT solicitation. Additional activities funded by CCT Program appropriations are theSmall Business Innovation Research (SBIR) Program,the Small Business Technology Transfer (STTR) Program, and CCT Program direction. The SBIR Programimplements the Small Business Innovation 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 Technolothat establishes a pilot psmall business concerns efforts.The CCT Program direcmanagement and adminand includes federal emptravel, site support servinational laboratories and Availability of FundAlthough all funds neceCCT Program were apprFY1990, the legislation be made available (i.e., time-phased basis. Exhiment of funding to DOEprogramís yearly fundinand by subprogram. Funsubprogram budgets to mneeds.Use of Appropriated There are five key finanment to track the status a(1) budget authority, (2) (4) costs, and (5) expendof these terms is given bï Budget Authority. Th

created by legislation that permits the federfunds.

ï Commitments. Withi

gram, a commitment selects a project for namount is equal to DOcontained in the coop

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 Budgetsa Budget Budget

P.L. 99-190 CCT-I 380,600 4,902 129,767 245,931

P.L. 100-202 CCT-II 473,939 6,781 32,512 434,646P.L. 100-446 CCT-III 541,298 6,906 22,548 511,844

P.L. 101-121b CCT-IV 332,000 7,065 25,000 299,935

P.L. 101-121b CCT-V 450,000 5,427 25,000 419,573 Total 2,177,837 31,081 234,827 1,911,929

a Small Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs.b 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,

106-113, 106-291, and 107-63.
Exhibit 3-3

Annual CCT Program Funding by Appropriations and Subprogram Bu

(Dollars in Thousands)

Fiscal Year 1986–93 1994 1995 1996 1997 1998 1999 2000 2001 Adjusted AppropriationsaP.L. 99-190 397,600 (17,000) 

P.L. 100-202 574,997 (101,000) (40,000) 9,962 14,980 P.L. 100-446 574,998 (156,000) 156,000 (3P.L. 101-121b 350,000 100,000 18,000 50,000 (91,000) (162,000) 

P.L. 101-121b 100,000 125,000 19,121 100,000 105,879  Total 1,997,595 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 8,980 

Subprogram BudgetsCCT-I Projects 387,231 (18,000) (18,000) (33,000) (15,000) (14,900) (14,400) (14,000) (CCT-II Projects 535,704 (101,000) (40,000) 9,962 14,980 CCT-III Projects 545,544 (156,000) 156,000 (3CCT-IV Projects 320,938 98,450 17,622 48,925 (91,000) (162,000) 

CCT-V Projects 74,062 123,063 18,719 97,850 105,879 

 Projects Subtotal 1,863,479 221,513 18,341 128,775 (18,121) (116,000) (54,900) (160,438) (5,020) 

Program Direction 110,527 18,000 18,000 16,000 15,000 14,900 14,400 14,000 

 Fossil Energy Subtotal 1,974,006 221,513 36,341 146,775 (2,121) (101,000) (40,000) (146,038) 8,980 SBIR & STTRc 23,589 3,487 779 3,225 

 Totald 1,997,595 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 8,980 

a Shown are appropriations less amounts sequestered under the Gramm-Rudman-Hollings Deficit Reduction Act.b 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, 10c Small Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs.d Totals may not appear to add due to rounding.
3-4 Program Update 2001

• Obligations. The cooperative agreement for each

project establishes funding increments, referred toas budget periods. The cooperative agreementdefines the tasks to be performed in each budgetperiod. An obligation occurs in the beginning ofeach budget period and establishes the incrementalamount of federal funds available to the participantfor use in performing tasks as defined in the cooperative agreement.

• Costs. A request for payment submitted by the

project participant to the federal government forreimbursement of tasks performed under the termsof 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 checksdrawn upon the U.S. Treasury.

The full government cost-share specified in the cooperative agreement is considered committed to eachproject. However, DOE obligates funds for the projectin increments. Most projects are subdivided into several time and funding intervals, or budget periods. Thenumber of budget periods is determined during negotiations and is incorporated into the cooperative agreement. DOE obligates sufficient funds at the beginningof each budget period to cover the government’s costshare for that period. This procedure limits thegovernment’s financial exposure and assures that DOEfully participates in the decision to proceed with eachmajor phase of project implementation.The overall financial profile for the CCT Program ispresented in Exhibit 3-4. The graph shows actualperformance for FY1986 through FY2001 and DOEestimates for FY2002 through program completion.Excluded from the graph are SBIR and STTR funds, asthese are used and tracked separately from the CCTProgram. The financial projections presented in Exhibit 3-4 are based on individual project schedules andbudget periods as defined in the cooperative agreements and modifications. The negative Budget

Authority values shown in Exhibit 3-4 result from rescission of $101 million in FY1998, the deferral of $40million in FY1999, and the deferral of $146 million inFY2000.The financial status of the program through September30, 2001, is presented by subprogram in Exhibit 3-5.SBIR and STTR funds are included in this exhibit toaccount for all funding. Exhibit 3-5 also indicates theapportionment sequence as modified by Public Law107-63. These values represent the amount of budgetauthority available for the CCT Program.Project Funding, Costs, and SchedulesInformation for individual CCT projects, includingfunding and the status of key milestones, is provided inSection 5. An overview of project schedules and funding is presented in Exhibits 3-6 and 3-7.

Cost-SharingA characteristic feature ocooperative funding agrand the federal governmThis cost-sharing approaCCT Program, was introAn Act Making Approprthe Interior and Related Ending September 30, 1General concepts and reprinciple as applied to thfollowing elements:• The federal governme

50 percent of the tota

Exhibit 3-4

CCT Financial Project

as of September 30, 2

aIncludes changes resulting from P.L. 107-63.
Exhibit 3-5

Financial Status of the CCT Program as of September 30, 2001c

(Dollars in Thousands)

Appropriations

Allocated to Apportioned Committed Obligated Cost

Subprogram Subprogramb to Date to Date to Date to Date

CCT-I 245,931 245,931 257,124 257,124 254,128

CCT-II 434,646 434,646 165,369 165,369 165,121

CCT-III 511,844 511,844 592,307 592,307 490,430CCT-IV 299,935 259,935 478,018 478,018 476,679

CCT-V 419,573 419,573 362,854 148,003 24,841

 Projects Subtotal 1,911,929 1,871,929 1,855,672 1,640,821 1,411,199SBIR & STTRa 31,081 31,081 31,081 31,081 31,081

Program Direction 234,827 234,827 234,827 221,522 217,773

aSmall Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) ProgramsbTotals may not appear to add due to roundingcIncludes changes from P.L. 107-63

Apportionment SeqFY A1986 91987 141988 191989 191990 551991 391992 411993 1994 221995 31996 151997 (1998 (101999 (42000 (142001 2002 2003 4
3-6 Program Update 2001

Exhibit 3-6

CCT Project Schedules by Application Category

Calendar Year
Exhibit 3-6 (continued)

CCT Project Schedules by Application Category

Calendar Year
3-8 Program Update 2001

Exhibit 3-7

CCT Project Funding by Application Category

Project DOE % Participant Environmental Control DevicesSO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption 2,315,259 30.0 5,401,930 

Confined Zone Dispersion Flue Gas Desulfurization Demonstration 5,205,800 50.0 5,205,800 LIFAC Sorbent Injection Desulfurization Demonstration Project 10,636,864 49.7 10,756,908 Advanced Flue Gas Desulfurization Demonstration Project 63,913,200 42.1 87,794,698 Demonstration of Innovative Applications of Technology for the CT-121 FGD Process 21,085,211 49.0 21,989,785 Subtotal SO2 Control Technology 103,156,334 44.0 131,149,121 

NO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 6,553,526 41.3 9,300,374 

Demonstration of Coal Reburning for Cyclone Boiler NOx Control 6,340,787 46.5 7,305,822 

Full-Scale Demonstration of Low-NO

x

 Cell Burner Retrofit 5,442,800 48.5 5,790,592 

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler 8,895,790 50.0 8,911,468 

Micronized Coal Reburning Demonstration for NOx Control 2,701,011 29.7 6,395,475 

Demonstration of Selective Catalytic Reduction Technology 9,406,673 40.5 13,823,056 for the Control of NO

x Emissions from High-Sulfur, Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion 4,149,383 48.5 4,404,282 Techniques for the Reduction of NOx Emissions from Coal-Fired Boilers

Subtotal NO

x

 Control Technology 43,489,970 43.7 55,931,069 

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project 15,719,200 50.0 15,719,208 LIMB Demonstration Project Extension and Coolside Demonstration 7,591,655 39.3 11,719,378 SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project 6,078,402 45.8 7,193,219 Enhancing the Use of Coals by Gas Reburning and Sorbent Injection 18,747,816 49.9 18,841,139 Milliken Clean Coal Technology Demonstration Project 45,000,000 28.4 113,607,807 Integrated Dry NOx/SO2 Emissions Control System 13,082,653 50.0 13,082,653 

Subtotal Combined SO2/NOx Control Technologies 106,219,726 37.1 180,163,404 

Total Environmental Controls 252,866,030 40.8 367,243,594 
Exhibit 3-7 (continued)

CCT Project Funding by Application Category

Project DOE % Participant 

Advanced Electric Power GenerationFluidized-Bed CombustionMcIntosh Unit 4A PCFB Demonstration Project 93,252,864 50.0 93,335,136 McIntosh Unit 4B Topped PCFB Demonstration Project 109,608,507 49.9 110,027,039 

JEA Large-Scale CFB Combustion Demonstration Project 74,733,833 24.2 234,362,679 Tidd PFBC Demonstration Project 66,956,993 35.3 122,929,346 Nucla CFB Demonstration Project 17,130,411 10.7 142,919,538 Subtotal Fluidized-Bed Combustion 361,682,608 34.0 703,573,738 

Integrated Gasification Combined-CycleKentucky Pioneer Energy IGCC Demonstration Project 78,086,357 18.1 353,846,225 Piñon Pine IGCC Power Project 167,956,500 50.0 167,956,500 

Tampa Electric Integrated Gasification Combined-Cycle Project 150,894,223 49.8 152,394,223 

Wabash River Coal Gasification Repowering Project 219,100,000 50.0 219,100,000 

Subtotal Integrated Gasification Combined-Cycle 616,037,080 40.8 893,296,948 

Advanced Combustion/Heat EnginesClean Coal Diesel Demonstration Project 23,818,000 50.0 23,818,000 Healy Clean Coal Project 117,327,000 48.5 124,731,000 Subtotal Advanced Combustion/Heat Engines 141,145,000 48.7 148,549,000 

Total Advanced Electric Power Generation 1,118,864,688 39.1 1,745,419,686 

Coal Processing for Clean FuelsCommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process 92,708,370 43.4 120,991,630 

Advanced Coal Conversion Process Demonstration 43,125,000 40.8 62,575,000 Development of the Coal Quality ExpertTM 10,863,911 50.0 10,882,093 ENCOAL® Mild Coal Gasification Project 45,332,000 50.0 45,332,000 

Total Coal Processing for Clean Fuels 192,029,281 44.5 239,780,723 Industrial ApplicationsClean Power from Integrated Coal/Ore Reduction (CPICORTM) 149,469,242 14.0 916,335,758 Pulse Combustor Design Qualification Test 4,306,027 50.0 4,306,027 Blast Furnace Granular-Coal Injection System Demonstration Project 31,824,118 16.4 162,477,672 Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 490,122 49.8 494,272 Cement Kiln Flue Gas Recovery Scrubber 5,982,592 33.6 11,817,408 Total Industrial Applications 192,072,101 14.9 1,095,431,137 Grand Total 1,755,832,100 33.7 3,447,875,140 
3-10 Program Update 2001

• Cost-sharing by the project participants is required

throughout the project (design, construction, andoperation);

• The federal government may share in project cost

growth (within the scope of work defined in theoriginal cooperative agreement) up to 25 percent ofthe originally negotiated government share of theproject;

• The participant’s cost-sharing contribution must

occur as project expenses are incurred and cannotbe offset or delayed based on prospective projectrevenues, 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 thecost-sharing status by subprogram and by applicationcategory for the 38 active or completed projects. Inthe advanced electric power generation category,which accounts for 55 percent of total project costs,participants are contributing 61 percent of the funds.Cost-sharing by participants for environmental controldevices, coal processing for clean fuels, and industrialapplications categories is 59 percent, 56 percent, and85 percent, respectively. For the overall program,participants are contributing 66 percent of the totalfunding, or nearly $1.7 billion more than the federalgovernment.Recovery of GovernmentOutlays (Recoupment)The policy objective of DOE is to recover an amountup to the government’s financial contribution to eachproject. Participants are required to submit a plan outlining a proposed schedule for recovering the

government’s financial contribution. The solicitationshave featured different sets of recoupment rules.Under the first solicitation, CCT-I, repayment wasderived from revenue streams that include net revenuefrom operation of the demonstration plant beyond thedemonstration phase and the commercial sale, lease,manufacture, licensing, or use of the demonstratedtechnology. In CCT-II, repayment was limited to revenues realized from the future commercialization ofthe demonstrated technology. The government’s sharewould be 2 percent of gross equipment sales and 3percent of the royalties realized on the technologysubsequent to the demonstration.The CCT-III repayment formula was adjusted to 0.5percent of equipment sales and 5 percent of royalties.Limited grace periods were allowed on a project-byproject basis. A waiver on repayment may be soughtfrom the Secretary of Energy if the project participantdetermines that a competitive disadvantage wouldresult in either the domestic or international marketplace. The recoupment provisions for CCT-IV andCCT-V were identical to those in CCT-III.As of September 30, 2001, six projects have madepayments to the federal government under the terms ofthe repayment agreements: Nucla CFB DemonstrationProject (Tri-State Generation and Transmission Association, Inc.); Full-Scale Demonstration of Low-NOxCell Burner Retrofit (The Babcock & Wilcox Company); Development of the Coal Quality ExpertTM(ABB Combustion Engineering, Inc. and CQ Inc.); 10-MWe Demonstration of Gas Suspension Absorption(AirPol, Inc.); Advanced Flue Gas DesulfurizationDemonstration Project (Pure Air on the Lake, L.P.);and Wabash River Coal Gasification RepoweringProject.In September 1997, the CCT Program office issued areport entitled Recoupment Lessons Learned—CleanCoal Technology Demonstration Program. The report:(1) reviewed the lessons learned on recoupment duringthe implementation of the CCT Program; (2) addressed

recommended actions seOffice (GAO) Report RCRCED-96-141, and InspIG-0391 relative to recointo DOE deliberations o
4. CCT Program AccomplishmentsIntroductionDuring fiscal year 2001, by the following demonstrations completing operations:• Piñon Pine IGCC Power Project,• Advanced Coal Conversion Process Demonstration,• Tampa Electric Integrated Gasification CombinedCycle Project, and• Pulse Combustor Design Qualification Test.These completed projects, along with the other 34active and completed projects, are producing a wealthof knowledge on clean coal technologies.The success of the CCT Program ultimately will bemeasured by the contribution the technologies make tothe resolution of energy, economic, and environmentalissues. These contributions can only be achieved if thepublic and private sectors understand that clean coaltechnologies can increase the efficiency of energy useand enhance environmental quality at costs that arecompetitive with other energy options.The CCT Program has continued efforts to define andunderstand the potential domestic and internationalmarkets for clean coal technologies. Domestically, thisactivity requires a continuing dialogue with electricutility executives, public utility commissioners, andfinancial institutions. Also required are analyses of theeffect that regional electric capacity requirements,environmental compliance strategies, and electric utility restructuring have on the demand for clean coaltechnologies. Internationally, activities include participating in international conferences and workshops,furnishing information on clean coal technologies, andproviding technical support to trade agencies, trademissions, and financial organizations.

Throughout the 2001 fiscal year, the CCT Programstaff participated in over a dozen domestic and international events involving users and vendors of clean coaltechnologies, regulators, financiers, environmentalgroups, and other public and private institutions. Fourissues of the Clean Coal Today newsletter were published in the same period, along with the sixth annualedition of the Clean Coal Today Index, which crossreferences all articles published in the newsletter. Two

12-page Project Performance Summary documents

were issued for the Demonstration of Advanced Combustion NOx Control Techniques for a Wall-FiredBoiler project and the Evaluation of Gas Reburningand Low-NOx Burners on a Wall-Fired Boiler project.Also, three Clean Coal Technology Topical Reportswere issued during the fiscal year: Environmental Benefits of Clean Coal Technologies; The Wabash RiverCoal Gasification Repowering Project—An Update;and Coproduction of Power, Fuels and Chemicals. TheDepartment of Energy also continued coverage of theprogram by publishing the Clean Coal TechnologyDemonstration Program: Update 2000.Fossil Energy R&D BenefitsThe CCT Program, along with other Office of FossilEnergy research and development, has led to commercialization of technologies that lower emissions andimprove efficiencies of electric power generation,upgrade fuels, and improve industrial processes. In a2001 National Research Council (NRC) report, EnergyResearch at DOE: Was It Worth It?, the NRC looked atfossil energy and energy efficiency research at DOEfrom fiscal year 1978 to fiscal year 2000. The research Some new publications p
4-2 Program Update 2001

in the late 1970s and early 1980s provided a solid foundation for demonstrations in the CCT Program as evidenced by the NRC's conclusions on DOE's constructiverole in fossil energy research as shown in Exhibit 4-1.The demonstrations moved technologies from the R&Dpipeline into commercial reality. The NRC committeeconcluded that DOE ìplayed a major roleî in AFBC,

PFBC, and IGCC RD&D, all of which have receivedfunding from the CCT Program. The NRC also creditsDOE with benefits associated with NO

x

 control R&D

because the research has resulted in technologies thatallow power plant operators the opportunity to morecost-effectively control NOx emission beyond existing

environmental requiremements are directly related In the area of NO

x contro

were developed for all boreconfiguring the burnerseffectively comply with 

Exhibit 4-1

National Research Council Conclusions on Fossil Energy Research

Technology Role CommentsAtmospheric Fluidized-Bed Majorb In the development and demonstration of industrial-scale systems using low-valued, low-cost fuels (

Combustion medical wastes, among others).

Significantc In demonstrating systems for utility applications (DOE provided 20 percent of the costs).

Pressurized Fluidized-Bed Major In improving the efficiency and environmental performance of the technology and in large-scale dem

Combustion 45 percent of the costs of the demonstrations).Integrated Gasification Major In large-scale demonstrations integrating the components into a total system for optimal electricity pCombined-Cycle performance (DOE provided 50 percent of the costs of the CCT Program demonstrations).Direct Liquefaction Major In funding basic, pilot-scale, and bench-scale research and development that improved the technologIndirect Liquefaction Significant In basic, pilot-scale, and bench-scale research and development that improved the technologies deve

DOE current.

Coal Preparation Significant In improving the removal efficiencies of ash, sulfur, and other impurities through fine grinding of co

techniques.

Flue Gas Desulfurization Significant In the development and, more importantly, the demonstration of second-generation systems that offe

removal efficiency improvements, and the ability to control emissions from a wider variety of boilerthan conventional systems.

NO

x Control Systems Significant In the development and, more importantly, the demonstration of second-generation systems that offe

removal efficiency improvements, and the ability to control a wider range of large utility boilers.

Waste Management and Utilization Significant In characterizing the solid wastes from conventional and advanced-coal systems, monitoring advanc

researching potential uses for the waste by-products.

Emissions of Mercury and Other Significant In characterizing the air toxics from conventional and advanced coal-based technologies (and determ

Toxic Substances in the Atmosphere conducting research on technologies that could remove the toxic elements from the coal feed and flu

a Taken from National Research Council, Energy Research at DOE: Was It Worth It?, pp.47-49 (2001).b A role critical to the success of the program.c An important role but not critical to the success of the program.
dards under the Clean Air Act Amendments of 1990. Anestimated 75 percent of existing coal-fired boilers havebeen or are being retrofitted with low-NOx burners, andforeign and domestic sales of burners demonstrated inthe CCT Program exceed $1.3 billion. The CCT Program developed reburning technology for NOx control

for cyclone boilers because of their incompatibility withredesign of the burners. Both foreign and domestic salesof reburning technology have been realized. The CCTProgram also demonstrated the compatibility of selectivecatalytic reduction (SCR) NOx control systems with U.S.

coals, particularly high-sulfur coals. An estimated 30percent of U.S. coal-fired generating capacity will incorporate SCR technology by 2004. The SCR sales through2000 reached $2.7 billion.Advanced wet flue gas desulfurization projects demonstrated in the CCT Program redefined the state-of-theart for sorbent-based scrubbers by nearly halvingcapital and operating costs, increasing SO2 removal to95 percent or more, producing by-products instead ofwastes, and reducing plant efficiency losses throughuse of high-capture-efficiency devices. A portfolio ofrelatively low-capital-cost sorbent injection technologies were demonstrated that provided SO2 removal up

to 90 percent for older, smaller, space constrainedplants. Technology sales for SO2 control technologies

primarily have been overseas, but an estimated 30 percent of coal-fired generating capacity will incorporateSO2 controls by 2002. The NRC report credits DOEwith net savings of $1.0 billion in SO2 controls, whichrepresent nearly a 2:1 benefit-to-cost ratio.A key demonstration provided the technical foundationand impetus for rapid commercialization of utility-scaleatmospheric circulating fluidized-bed combustion(ACFB). The demonstration of pressurized fluidized-bedcombustion served to resolve several major design issues and precipitate commercial sales of approximately1,000 megawatts to date, all in overseas applications.Fluidized-bed combustion technology demonstratedin the CCT Program has recorded sales of nearly$9 billion through 2001.

Four IGCC demonstrations, representing a diversity ofgasifier types and cleanup systems, are pioneering theintroduction of this next-generation power concept.Since the CCT Program IGCC demonstrations began in1995, the cumulative coal-based gasification capacityadded worldwide includes nine gasification projectscurrently producing in excess of 3,000 MWth (a measure of thermal energy) of syngas, which is equivalent toalmost 1,700 MWe of IGCC electric capacity (includesthe CCT Program's Tampa Electric IGCC project). Since1995, four projects were built that are currently operating on petroleum coke and producing in excess of 1,800MWth of syngas (equivalent to over 770 MWe of IGCCelectric capacity; includes the CCT Program's WabashRiver IGCC project). Another 19 projects have beenadded that use petroleum (i.e., residual heavy oil, pitch,asphalt, naphtha, and Bunker C fuel oil) as the feedstock. These petroleum projects produce over 9,000MWth of syngas (equivalent to over 4,000 MWe ofIGCC electric capacity). Petroleum coke and petroleumprojects are included because the gasifier technology isthe same as for the coal projects. This is evidenced bythe fact that the CCT Program's Wabash River IGCCproject was carried out primarily as coal, but is nowoperating commercially on petroleum coke. More plantsare under construction or in the planning phase.Two projects demonstrated the feasibility of producingclean high-energy-density solid and liquid fuels fromlow rank coals. The technical and economic feasibilityof co-producing methanol in association with IGCC isbeing proven by a project still in the operating andreporting phase. New computer tools were developedfor analyzing coal and coal blends leading to savingsthat exceed the cost of the demonstration project.Several industrial applications were demonstrated. Forexample, a major steel producer demonstrated granularcoal injection in blast furnace operations, showing thatfor every pound of coal used 0.96 pounds of cokecould be displaced. Based on the successful demonstration, another major steel producer replicated the technology at a high-volume production facility.

The specific technologthis chapter underscore ment/industry partnersof a market-based apprneeds. After 15 years, tcompletion, but severamake their contributioninstitutional successes gram. For example, the described the CCT Processful government/indhas recognized the suchas adapted the prograPower Plant ImprovemPower Initiative. The Dadapted the same princThe Tampa IGCC plant at 
4-4 Program Update 2001

Marketplace CommitmentCommensurate with CCT Program commercializationgoals, the majority of the projects involve demonstrations at commercial scale, providing the opportunityfor the participants to continue operation of the demonstrated technologies as part of their strategy to complywith the Clean Air Act.With government serving as a risk-sharing partner,industry funding has been leveraged to:ï Create jobs,ï Improve the environment,ï Reduce the cost of compliance with environmental

regulations,

ï Reduce the cost of electricity generation,ï Improve power generation efficiencies, andï Position U.S.-based industry to export innovative

services and equipment.

Reflecting the marketplace commitment, the CCTprojects are organized within four major product linesóenvironmental control devices, advanced electricpower generation, coal processing for clean fuels, andindustrial applications. Thus, the CCT Program can beviewed from a market perspective. This section of theProgram Update looks at the domestic market for these

technologies and then highlights, by market sector,some of the program and project accomplishments todate along with commercialization successes.Factors Impacting DomesticCommercializationThe domestic market for advanced SO2 control technology is not yet fully developed. Domestic utilities arelargely investing in SO2 control technology by fuelswitching, and procuring and banking SO2 allowances,rather than making capital investments in SO2 control

technologies. Also, the utilities are awaiting the outcomeof PM2.5 and other regulatory actions that may significantly impact SO2 compliance requirements. Similarly,

there has been no domestic market for advanced technologies that combine high capture efficiency for SO2

,

NOx, and particulate matter.After being proven as a viable technology in early CCTProgram projects, low-NOx burners enabled utilities tomeet the January 2000 Clean Air Act Amendment emission requirements for NOx. Until recently, the more aggressive, deeper control measures, such as coal and gasreburning, and SCR technologies were applied onlysparingly, but are coming into play as utilities are forcedto comply with new, more stringent requirements. Beginning as early as 2003, new NAAQS for PM2.5 and ozone,

and the associated EPA ìtion of the deeper SO2, Nmeasures, like those emeThe EIA estimates that 2ity will be in place by 20The domestic market haintroduction of advanced technologies. Uncertaintkets due to utility restrucgent emission standards low natural gas prices to plants. Successfully demIGCC and PFBC have reonly overseas.The market is changing. power generation, rising increasing importance bare placing a premium oelectric capacity and mation a solid option for caexisting plants, investmecontrol measures needed requirements.For capacity additions, ogeneration systems, such technologies, can meet paddress concerns over glEnvironmental ConAll but 1 of the 19 envirprojects have now comppleted demonstrations pra suite of cost-effective 

for the full range of coalsignificantly mitigated in technologies commerciadatabases and attendant through the demonstratioleveraged to provide inprequirements under the C

SO2 control technologies: AirPol (left), CT-121 (center), and LIFAC (right).
pact of emerging issues, such as air toxics, on the existing boiler population and control options. Extensive airtoxics testing was performed in conjunction with 10 ofthe environmental control projects. To a great extent,the technologies were retained for commercial serviceat the demonstration sites, and many technology suppliers have realized commercial sales.SO2 Control Technologies. All five SO2 control technology demonstrations have completed operations,

evaluating three basic approaches to address thediverse coal-fired boiler population: (1) sorbent injection, (2) gas-suspension absorption, and (3) advancedflue gas desulfurization.• Two low-capital-cost sorbent injection systems,

sponsored by LIFAC–North America and BechtelCorporation, demonstrated SO2 capture efficiencies

in the range of 50 to 70 percent. These systems holdparticular promise for the older, smaller units, particularly those with space constraints.

• A moderate-capital-cost gas-suspension-absorption

system, sponsored by AirPol, Inc., demonstratedSO2 capture efficiencies in the range of 60 to 90percent. The system has particular applicability tothe 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 somewhathigher capital costs than the other approaches, demonstrated SO2 capture efficiencies in the range of 90to 95 percent. These systems are primarily applicable to the larger, newer units that have spaceavailable.

The AFGD projects redefined the state-of-the-art inscrubber technology by proving that a single absorbermodule of advanced design could process large volumes of flue gas and provide the required availabilityand reliability. This single module design, without theusual spares, combined with integration of functions

within the absorber module and use of high throughputdesigns, nearly halved capital cost and space requirements. The AFGD testing also established that wallboard-grade gypsum could be produced in lieu of solidwaste; wastewater discharge could be eliminated; and,by mitigating corrosion, fiberglass-reinforced-plasticfabrication 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 systemcould significantly enhance particulate control. PureAir on the Lake, L.P., introduced an innovative business concept whereby the company builds, owns, andoperates scrubbers as a contracted service to a utility.The arrangement relieves utilities of the burden ofownership and operation.Commercialization successes to date for the SO2 control technologies are summarized in Exhibit 4-2.NOx Control Technology. Six of the seven NOxcontrol technology demonstrations have successfullycompleted operations. Testing was conducted on thefour major boiler types (wall-fired, tangentially fired,cyclone-fired, and cell-burner boilers), representingover 90 percent of the coal-fired boiler population;however, applicability extends to all boiler types.Typically, NOx emission reductions achieved for thevarious approaches were:• Low-NOx 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 percentThe database developed during Southern CompanyServices’ evaluation of NOx control on wall-fired andtangentially fired boilers at Plant Smith and PlantHammond, respectively, was used by EPA in formulating NOx provisions under the CAAA. ABB Combustion Engineering’s LNCFSTM proved effective for

tangentially fired boileacceptance, as did FostSplit Flame and Babco

NOx burners for wall-f

Wilcox Company’s lowprovided an effective lo

system for cell-burner their inherently high N

Integration of neural-nboiler controls, such as 

ligent System (GNOCIdemonstrated effective NOx control and boiler lowing operations.The Babcock & Wilcox technology proved not control NOx on cyclon

derating cyclone boilerlow-rank western coalsResearch Corporation’cable to all boiler typesSCR for high NOx emi

when used with low-NOIn another project, comon a range of SCR catalproviding needed insigh

economic performance systems and selective nsystems were demonstrbined SO2/NOx control 

Commercialization suctrol technologies are suCombined SO2/NOx C

of the combined SO2/Nstrations have successfuThe demonstrations evamentary and synergistic effective SO2 and NOx e
4-6 Program Update 2001

Exhibit 4-2

Commercial Successes—SO2 Control Technology

Project Commercial Use10-MWe Demonstration of Gas Suspension Absorption Sold domestically and internationally. GSA market entry was significantly enhanced (AirPol, Inc.) unit, worth $12.5 million, to the city of Hamilton, Ohio, subsidized by the Ohio Coal D

worth $1.3 million has been made to the U.S. Army for hazardous waste disposal. A Ga Swedish iron ore sinter plant. Two GSA systems valued at $1.8 million have been soration for their oil-fired cogeneration plant. Airpol sold a GSA system valued at $1.5 mcalciner in India. Startup has begun in Wasateh, Utah for a GSA-based municipal wastelectricity and steam. A new contract is expected for a waste incinerator in Holland usi

Confined Zone Dispersion Flue Gas Desulfurization No sales reported. CZD/FGD can be used to retrofit existing plants or for new installaDemonstration (Bechtel Corporation) one-tenth that of a commercial wet scrubber.LIFAC Sorbent Injection Desulfurization Sold domestically and internationally.Demonstration Project (LIFAC–North America) The LIFAC system at Richmond Power & Light is the first to be applied to a power pl

coal. The LIFAC system has been retained for commercial use by Richmond Power & Station, Unit No. 2. There are 10 full-scale LIFAC units in operation in Canada, ChinaUnited States, including 5 projects started before the CCT Program. For three sales in $44.6 million.

Advanced Flue Gas Desulfurization Demonstration Project No sales reported. The AFGD continues in commercial service at Northern Indiana Pu

(Pure Air on the Lake, L.P.) Bailly Generating Station. Gypsum produced by the PowerChip® process is being sold 

value for 17 years of continued scrubber operations roughly equals the value of the probased licensee, is currently working on a potential $60 million project in Kentucky usitechnology.

Demonstration of Innovative Applications of Sold internationally. Plant Yates continues to operate with the CT-121 scrubber as an 

Technology for the CT-121 FGD Process CAAA compliance strategy. There are now 22 CT-121 plants in the planning, construc

(Southern Company Services, Inc.) worldwide. There are 17 CT-121 plants operating in Japan, Australia, Canada, the Cze

Malaysia, and Kuwait. The value of these 17 plants is estimated at $2.03 billion. For ththe value is estimated at $880 million.
Exhibit 4-3

Commercial Successes—NO

x Control Technology

Project Commercial UseMicronized Coal Reburning Demonstration for NOx Control No sales reported. Technology retained for commercial use at Kodak Park Power 

(New York State Electric & Gas Corporation)Demonstration of Coal Reburning for Cyclone Boiler NOx Control No sales reported. Technology retained for commercial use at Wisconsin Power a

(The Babcock & Wilcox Company) Dewey Station.Full-Scale Demonstration of Low-NO

x

 Cell Burner Retrofit Sold domestically. Dayton Power & Light has retained the LNCB® for use in com

(The Babcock & Wilcox Company) commercial contracts have been awarded for 196 burners or 5,475 MWe of capaciEvaluation of Gas Reburning and Low-NOx Burners on a Sold domestically and internationally. Public Service Company of Colorado, the 

Wall-Fired Boiler (Energy and Environmental Research retain the low-NOx burners and the gas-reburning system for immediate use; howe

to Corporation) remove the flue gas recirculation system. Since the CCT Programis in the process of installing the gas reburning or the gas reburning-low-NOx burn

representing 4,814 MWe of capacity. Most of the sites are domestic, but one site is Ladyzkin, Ukraine.

Demonstration of Selective Catalytic Reduction Technology Sold domestically and internationally. Since the project was initiated, revenues ffor the Control of NO

x Emissions from High-Sulfur, $4.9 billion through 2001.

Coal-Fired Boilers (Southern Company Services, Inc.)180-MWe Demonstration of Advanced Tangentially Fired Sold domestically and internationally. LNCFSTM has been retained at the host si

Combustion Techniques for the Reduction of NOx Emissions from Power has sold about 63 GWe of LNCFSTM burners. Of this amount, about 49 GW

Coal-Fired Boilers (Southern Company Services, Inc.) and 14 GWe are without overfire air. Total sales are estimated at $1.3 billion.Demonstration of Advanced Combustion Techniques Sold domestically and internationally. The host has retained the technologies for 

for a Wall-Fired Boiler (Southern Company Services, Inc.) Wheeler has equipped 101 boilers with low-NOx burner technology—a total of ov

over 26,105 MWe capacity valued at $83 million. Foreign sales make up 35 percenTwenty-six commercial installations of GNOCIS, the associated AI control systemrepresents over 12,000 MWe of capacity. In a strict sense, this project has not been to apply GNOCIS to other pieces of plant equipment, which may increase its comm
4-8 Program Update 2001

A catalytic process developed by Haldor Topsoe a/s,SNOXô, consistently achieved 95 and 94 percent SO2and NOx reductions, respectively. The process also

demonstrated excellent particulate control, while producing a salable by-product in lieu of a solid waste.In a project sponsored by Public Service Company ofColorado, the complementary use of low-NOx burners

with SNCR resulted in NOx emission reductions of

greater than 80 percent. The SNCR process interactedsynergistically with sorbent injection to reduce ammonia slip and lower NOx emissions. Sodium-based sorbent injection achieved 70 percent SO2 removal at highsorbent utilization rates.New York State Electric & Gas Corporation (NYSEG)evaluated an advanced flue gas desulfurization system,the S-H-U scrubber process. The S-H-U process, anadvanced formic acid-enhanced wet limestone scrubbing process, demonstrated a 98 percent SO2 captureefficiency. In conjunction with the S-H-U- process,NYSEG also evaluated micronized coal as a reburnfuel using close-coupled reburning techniques anddeep-staged combustion incorporated into ABB Combustion Engineering, Inc.ís LNCFSô burners. DHRTechnologies supplied a plant optimization controlsystem known as the Plant Emission Optimization Advisor or PEOAô, which has been sold to a number ofusers in the power industry.The Babcock & Wilcox Companyís SOx-NOx-RoxBoxô, an integration of a newly developed high-temperature fabric-filter bag (for baghouse installations)with SCR and sorbent injection, proved to be an easilyinstalled, highly efficient control system for SO2, NOx

,

and particulates. Typical performance was 80 percentSO2 removal, 90 percent NOx removal, and 99.9 percent particulate removal.

Limestone injection multistage burner (LIMB) andcoolside demonstrations proved that sorbent injectionmethods could achieve up to 70 percent SO2 reduction.

The Babcock & Wilcox DRB-XCLÆ advanced lowNOx burners reduced NOx emissions by 45 percent.

Energy and Environmental Research Corporationísdemonstration of gas reburning and sorbent injectionshowed that: (1) NOx reductions greater than 60 percent could be achieved with only 13 percent natural gasheat input, and (2) SO2 removal of over 55 percent

could be achieved by using special sorbents.Commercialization successes to date for the combinedSO2 and NOx control technologies are summarized in

Exhibit 4-4.

Advanced Electric Power GenerationPollution control was the priority early in the CCTProgram. This program emphasis included technologies that could effectively repower aging plants facedwith the need to both control emissions and respond togrowing power demands. Repowering is an importantoption because existing power generation sites havesignificant value and warrant investment because theinfrastructure is in place, and siting new plants represents a major undertaking. This recognition led to earlyawards of three key repowering projectsótwo ACFBprojects and a PFBC project.As the CCT Program unfolded, a number of energy andenvironmental issues combined to change theemphasis toward seeking high-efficiency, low-emission power generation technologies for both repowering and new power gener

deemed essential to enabcontribution to the natio21st century. Environmen

concern over greenhouse SO2 emissions, increasin

nonattainment areas, and emissions (respirable pahealth threat. These issuin PFBC, initiation of pradvanced combustion anFluidized-Bed Combusand Transmission Assocrepowering project proving experience requisite cial technology option athe Nucla ACFB unit wathan any other ACFB at SO2 removal was achiev

demonstration, and NOx 

low 0.18 lb/106 Btu. The fully evaluate the environomic performance of Acomprehensive database able at the time was devedge, commercial units wWhile the Nucla project tance of ACFB at moderCCT demonstration projFlorida, is carrying on wmerly Jacksonville Elect300-MWe plant, which wbeing the largest ACFB the cleanest.Today, every major U.S. ACFB in its product linefluidized-bed combustiooperating in the United Smade significant market 

Milliken Station served as the host for two CCT Programprojects demonstrating advanced environmental controls.
Exhibit 4-4

Commercial Successes—Combined SO2/NOx Control Technology

Project Commercial UseSNOXTM Flue Gas Cleaning Demonstration Project (ABB International use. The host utility, Ohio Edison, is retaining the SNOXTM technology Environmental Systems) pollution control system at Niles Station to help meet its overall SO2 and NOx reducti

plants are also operating in Denmark and Sicily. In Denmark, a 305-MWe plant has oThe boiler at this plant burns coals from various suppliers around the world, includincontain 0.5-3.0% sulfur. The plant in Sicily, in operation since March 1991, has a capfires petroleum coke.

LIMB Demonstration Project Extension and Coolside Sold domestically and internationally. LIMB has been sold to an independent poweDemonstration (The Babcock & Wilcox Company) Wilcox has sales of 2,805 DRB-XCL® burners for 38,284 MWe of capacity. The low-

value of $388 million.

SOx-NOx-Rox BoxTM Flue Gas Cleanup No sales reported. Commercialization of the technology is expected to develop with Demonstration Project (The Babcock & Wilcox Company) equivalent to 50-100 MWe. The focus of marketing efforts is being tailored to match 

industrial, utility, and independent power producers for both retrofit and new plant cotechnology that can be tailored to maximize control of SO2, NOx, particulate, or comb

performance requirements while providing flexibility to address future needs.

Enhancing the Use of Coals by Gas Reburning and No sales reported. Illinois Power has retained the gas-reburning system and City WaSorbent Injection (Energy and Environmental Research the full technology for commercial use. (See Evaluation of Gas Reburning and Low-N

Corporation) Boiler project for a complete understanding of commercial success of the technology.Milliken Clean Coal Technology Demonstration Project Sold domestically. Eight modules of DHR Technologies’ Plant Emissions Optimizati(New York State Electric & Gas Corporation) value of $280,000, have been sold. A U.S. company, SHN, has been established to m

is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABB Comodified 116 units representing over 25,000 MWe with LNCFSTM or its derivative T

Integrated Dry NOx/SO2 Emissions Control System Sold domestically. The technology was retained by Public Service Company of Colo

(Public Service Company of Colorado) Arapahoe Station. Babcock & Wilcox has sales of 2,805 DRB-XCL® burners for 38,2

NO

x burners have an estimated value of $388 million.
4-10 Program Update 2001

Through the Ohio Power Company’s repowering of theTidd Plant (70 MWe), the potential of pressurized fluidized-bed combustion (PFBC) as a high-efficiency, lowemission technology was established, and the foundationwas laid for commercialization. This was the first utilityscale PFBC system in the United States. Efforts werefocused on fully evaluating the performance potential.Over 11,400 hours of operation, the technology successfully demonstrated SO2 removal efficiencies up to 95

percent with very high sorbent utilization (calcium-tosulfur molar ratio of 1.5), and NOx emissions in the

range of 0.15 to 0.33 lb/106 Btu.

The Tidd Plant PFBC was one of the first-generation70-MWe P200 units installed in the early 1990s. Otherswere built and operated in Sweden, Spain, and Japan.ABB Stal, the technology supplier, uses a “bubbling”fluidized-bed design, which is characterized by lowfluidization velocities and use of an in-bed heat exchanger. And, a “second generation” P200 PFBC withfreeboard-firing is operating in Cottbus, Germany. Anumber of other ABB Carbon PFBC projects are underconsideration in China, South Korea, the United Kingdom, Italy, Japan, and Israel.Plans are for two ongoing interrelated projects, McIntosh 4A and McIntosh 4B, to demonstrate pressurizedcirculating fluidized-bed combustion (PCFB) at utilityscale. PCFB uses a higher fluidization velocity thanbubbling-bed systems, that entrains the bed material.Bed material is separated from the flue gas by cyclonesand recirculated to the combustor. The economizer,which captures heat from the flue gas, is downstream ofthe cyclones to protect the heat exchanger surfacesfrom erosion. McIntosh 4A is to evaluate a 137-MWefirst-generation PCFB configuration using FosterWheeler technology. McIntosh 4B is to demonstrate asecond-generation system by integrating a small coalgasifier (pyrolyzer) to fuel the gas turbine “toppingcycle,” thereby adding 103 MWe capacity. The secondgeneration PCFB has the potential to significantlyimprove the efficiency of pressurized fluidized-bedsystems by increasing power generation from the gas

turbine, which is more efficient than the steam bottomcycle.Integrated Gasification Combined-Cycle. Three offour IGCC projects have completed operations underthe CCT Program. They represent a diversity of gasifier types, cleanup systems, and applications. PSIEnergy’s 262-MWe Wabash River Coal GasificationRepowering Project began operation in November1995, completed demonstration operations in December 1999, and now operates in commercial service. Theunit, which is the world’s largest single-train IGCC,operated on coal for over 15,000 hours and processedmore than 1.5 million tons of coal to produce over 23trillion Btu of syngas and 4 million MWh of electricity.The unit has achieved monthly production levels of onetrillion Btu of syngas on several occasions.The 250-MWe Tampa Electric Integrated GasificationCombined-Cycle Project began commercial operationin September 1996, completed demonstration operations in September 2001, and now operates in commercial service. The gasifier has accumulated over 29,000hours of operation and produced over 8.6 MWh ofelectricity on syngas. Tests have included evaluation ofvarious coal types on system performance.The Sierra Pacific Power Company’s (SPPC) 99-MWePiñon Pine IGCC Power Project at SPPC’s Tracy Station began operations in January 1998, and completeddemonstration operations in January 2001. The combined-cycle continues in commercial service. The GEFrame 6FA, the first of its kind in the world, performedwell. The system has achieved steady-state gasifieroperation for short periods, but experienced difficultywith sustained operations.The Kentucky Pioneer Energy IGCC DemonstrationProject, which is in the design stage, will offer yet another gasifier design and include the testing of a fuelcell operated on syngas from the coal gasifier. This willprovide valuable data for design of an integrated gasification fuel cell (IGFC) system. IGFC has the potentialto achieve efficiencies up to 52 percent.

Commercial configuratioIGCC and PFBC demonsefficiencies at least 20 pecoal-fired systems (with lreductions), remove 95 to reduce NOx emissions to duce particulate emissioncurrently allowed under tby-products from solid reAdvanced Combustion/are demonstrating advanctechnology. The Healy CTRW’s entrained (slagginBabcock & Wilcox’s sprrecycle. Operations were Three IGCC plants have coElectric (top), Piñon Pine (m(bottom).
Results from environmental compliance testingshowed very low emissions—0.26 lb/106 Btu for NOx

,

0.01 lb/106 Btu for SO2, and 0.0047 lb/106 Btu for

particulates. Permit levels are 0.35 lb/106 Btu for NOx

,

0.086 lb/106 Btu for SO2, and 0.03 lb/106 Btu for particulates because of the plant’s proximity to a national

park.The Clean Coal Diesel Demonstration Project is evaluating a heavy duty diesel engine operating on a low-rankcoal-water fuel. The demonstration plant is expected toachieve 41 percent efficiency, and future commercialdesigns are expected to reach 48 percent efficiency. Asof September 2001, the unit had operated on diesel, withplans for operating on coal in 2002.Commercialization successes for the advanced electricpower generation systems to date are summarized inExhibit 4-5.Coal Processing for Clean FuelsTwo of five projects in the coal processing for cleanfuels category completed operations and submittedfinal reports. Projects in this category include physicaland chemical processes that can be used to transformthe abundant U.S. coal reserves into economic, environmentally compliant solid and liquid fuels andfeedstocks. The solid products from coal processingare largely designed to be readily transportable; high inenergy density; and low in sulfur, ash, and moisture.The liquid products are designed to be suitable astransportation and stationary power generation fuels, oras chemical feedstocks. Both solid and liquidproducts, and the processes that produce them, havesubstantial market potential both domestically and internationally.The ENCOAL and Western SynCoal LLC projects arebreaking down the barrier to using the nation’s vastlow-sulfur but low-energy-density western coal resources. The resultant fuels have particular applicationdomestically for CAAA compliance and internationallyfor Pacific Rim energy markets.

ENCOAL’s solid fuel product has an energy density ofabout 11,000 Btu per pound, and the sulfur contentaverages 0.36 percent. ENCOAL’s liquid fuel productcan substitute for No. 6 fuel oil or serve as a chemicalfeedstock. During the demonstration, over 83,500 tonsof solid fuel was shipped to seven customers in sixstates, as well as 203 tank cars of liquid product toeight customers in seven states. Five commercial feasibility studies have been completed—two for Indonesia,one for Russia, and two for U.S. projects. Permitting ofa 15,000 metric ton/day commercial plant in Wyomingis nearly complete.The Western SynCoal LLC project is demonstratinganother route to producing high-quality fuel from lowrank 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 aheating value of about 12,000 Btu per pound. Duringthe demonstration, over 2.8 million tons of raw coalwas processed to produce almost 1.9 million tons ofSynCoal® product. Six agreements were in place to

purchase the product.Air Products Liquid Phase Conversion Company, L.P.,is demonstrating the LPMEOHTM process to producemethanol from coal-derived synthesis gas. TheLPMEOHTM process has been developed to enhanceintegrated gasification combined-cycle power generation facilities by co-producing a clean-burning storableliquid fuel from coal-derived synthesis gas. Theproduction of dimethyl ether (DME) as a mixed coproduct with methanol will also be demonstrated.Methanol and DME may be used as a low-SO2

,

low-NOx alternative liquid fuel, a feedstock for thesynthesis of chemicals, or as a new oxygenate fuel additive. Since startup, the LPMEOHTM demonstrationunit has produced over 80 million gallons of methanol,all of which was accepted by Eastman Chemical Company for use in downstream chemical processing. Sincerestart of the unit with fresh catalyst in December 1997,availability of the unit has been greater than 99 percentand catalyst activity decline has approached 0.4 percent/day.

ABB Combustion Engdeveloped the PC-baseExpertTM (CQETM), to environmental and opesystems for the availabmine the least-cost optibeen distributed to oveand is being marketed cU.S. utilities also have the CQETM stand-alone Commercialization suctechnologies to date arIndustrial ApplicaThe CCT Program is aissues and barriers assotrial applications. Threpleted operations in thiHistorically, production upon coke. Coke makilarge producer of hazarcement production ofteproduction costs are larBecause of its stable losubstitute for oil and gacerns over increased SO

tube fouling have impeUnder a project with BBritish Steel’s blast fur(BFGCI) technology dcoke can be replaced fodirectly into a blast furcombustion are effectivCPICORTM Managemesign stage for demonstrand smelting of iron oxThis would reduce the large amounts of pollut
4-12 Program Update 2001

Exhibit 4-5

Commercial SuccessesóAdvanced Electric Power Generation

Project Commercial UseTidd PFBC Demonstration Project Sold internationally. The projectís success has led Babcock & Wilcox to invest in the 

(The Ohio Power Company) and acquire domestic licensing rights.

Commercial coal-fired ventures abroad include the following:ñ Vartan in Sweden is operating two P200 units to produce 135 MWe and 224 MWt*ñ Escatron in Spain is operating one P200 unit producing 80 MWe*;ñ Wakamatsu in Japan has retired one P200 unit that produced 71 MWe;ñ Cottbus in Germany is operating one P200 unit to produce 71 MWe and 40 MWt;ñ Karita in Japan operates one P800 unit to produce 360 MWe;ñ Chuoku in Japan to produce 250 MWe; andñ Tomato-Atswo plant in Japan to produce 80 MWe.The value of these projects is estimated at $1.35 billion.

Nucla CFB Demonstration Project (Tri-State Generation Sold domestically and internationally. Since the demonstration, Foster Wheeler Enerand Transmission Association, Inc.) supplier for the demonstration effort, has achieved sales of $9 billion through 2001. Al

through 2001 were domestic, while the remaining sales were foreign. For a similar time supplier of CFB technology, has had sales of $4.1 billion (representing 3.47 GWe) thro

Tampa Electric Integrated Gasification Combined-Cycle Sold domestically and internationally. First greenfield IGCC unit in commercial servProject (Tampa Electric Company) Brown Boveri signed an agreement forming an alliance to market IGCC technology in 

Tampa IGCC began operations, Texaco has placed into operation 9 gasifiers domesticacoal, 1 using petroleum, 3 using petroleum coke, and 4 using natural gas) and 16 gasifi11 using petroleum, and 2 using natural gas).

Wabash River Coal Gasification Repowering Project No sales reported. First repowered IGCC unit in commercial service and is the worldí(Wabash River Coal Gasification Repowering Project in commercial service. The unit is preferentially dispatched over other coal-fireJoint Venture) system because of the unitís high efficiency. The Port of Port Arthur, Texas has announ

project to use the E-Gas technology.

Healy Clean Coal Project (Alaska Industrial Development No sales reported. TRW offering licensing of combustor worldwide. Commercial oper

and Export Authority)

* Parallel project with Tidd.
Exhibit 4-6

Commercial Successes—Coal Processing for Clean Fuels

Project Commercial UseDevelopment of the Coal Quality ExpertTM (ABB Combustion Sold domestically and internationally. The Electric Power Research Institute (EPEngineering and CQ, Inc.) software and distributes it to EPRI members for their use. CQ Inc. and Black and V

commercialization agreements that give both companies nonexclusive worldwide rconsulting services that include use of CQE®. More than 22 U.S. utilities, two Unitutility in France have received CQE® through EPRI membership. Two modules of t

$6,000 have been sold. EPRI estimated that the Acid Rain Advisor has saved one Umore than the total cost of the demonstration project. There have also been two salsoftware (Vista) at an estimated value of $180,000.

ENCOAL® Mild Coal Gasification Project (ENCOAL Domestic and international sales pending. In order to determine the viability of p

Corporation) plants, five detailed commercial feasibility studies—two Indonesian, one Russian, 

completed. Permitting of a 15,000 metric-ton/day commercial plant in Wyoming is 

Commercial-Scale Demonstration of the Liquid Phase No sales reported. Nominal 80,000 gallon/day methanol production being used by 

Methanol (LPMEOHTM) Process (Air Products LiquidPhase Conversion Company, L.P.)Advanced Coal Conversion Process Demonstration No sales reported. Total sales of SynCoal® product exceed 1.9 million tons. Six lon

(Western SynCoal LLC) place to purchase the product. One domestic and five international projects have be

SynCoal LLC has a joint marketing agreement with Ube Industries of Japan providrights outside of the United States. Ube is pursuing several projects in Asia.
4-14 Program Update 2001

Exhibit 4-7

Commercial Successes—Industrial Applications

Project Commercial UseCement Kiln Flue Gas Recovery Scrubber No sales reported. The scrubber became a permanent part of the cement plant at the end of the dem(Passamaquoddy Tribe) study has been completed for a Taiwanese cement plant.Blast Furnace Granular-Coal Injection System No sales reported. Technology remains in commercial service at demonstration site.

Demonstration Project (Bethlehem SteelCorporation)Advanced Cyclone Combustor with Internal Sulfur, No sales reported. While the combustor is not yet fully ready for sale with commercial guarantees

Nitrogen, and Ash Control (Coal Tech Corporation) commercial potential. Follow-on work to the CCT Program demonstration was undertaken, which 

close to commercial introduction.

The Passamaquoddy Tribe successfully demonstrated aunique recovery scrubber that uses cement kiln dust,otherwise disposed of as waste, to remove 90 percent ofthe SO2, produce fertilizer and distilled water, and convert the kiln dust to feedstock with no waste generated.Coal Tech Corporation moved closer to commercializing a combustor for industrial boilers that slags theash in the combustor to prevent boiler tube fouling,controls NO

x (70 to 80 percent reduction) through

staged combustion, and controls SO2 (90 percent) withsorbent injection.ThermoChem, Inc. has recently completed demonstration of its multiple resonance tube pulse combustor.Commercialization successes for the industrial applications technologies to date are summarized inExhibit 4-7.AwardsThe projects in the CCT Program have won numerousawards from news, professional, and non-profit organizations. A listing of those awards is contained inExhibit 4-8.

Market Communications—OutreachOutreach has been a hallmark of the CCT Programsince its inception. The Department of Energy recognized early on that commercialization of technologyrequires acceptance by a range of interests including:technology users; equipment manufacturers; suppliersand users of raw materials and products; financial institutions and insurance underwriters; government policymakers, legislators, and regulators; and public interestgroups. Requisite to acceptance is an outreach programto provide these customers and stakeholders with bothprogram and project information and to seek, on a continuing basis, feedback on program direction and information requirements. An ongoing outreach programhas aggressively sought to disseminate key informationto the full range of customers and stakeholders and toobtain feedback on changing needs. The effort hasrecognized the need to highlight environmental, operational, and economic performance characteristics ofclean coal technologies and to redesign information

packages as customers aspective needs, change wtives of the outreach pro• Achieving public and 

advanced coal-using options;

• Providing potential te

and domestic, with inrelevant to their decis

• Providing policy mak

with information abotechnologies;

• Informing financial in

writers that clean coations; and

• Providing forums and 

program direction and 

Information SourceA variety of publications exist and are being imprmarketplace events unfodistributed to over 4,000 
Exhibit 4-8

Award-Winning CCT Program Projects

Project and Participant AwardFull-Scale Demonstration of Low-NO

x Cell Burner 1994 R&D 100 Award presented by R&D magazine to the U.S. Department of Energy for 

Retrofit (The Babcock & Wilcox Company) burner.Evaluation of Gas Reburning and Low-NOx Burners on 1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management Associa

a Wall-Fired Boiler; Enhancing the Use of Coals by Gas Energy, Gas Research Institute, and U.S. Environmental Protection Agency for the develoReburning and Sorbent Injection (Energy and gas-reburning technology.Environmental Research Corporation)Advanced Flue Gas Desulfurization Demonstration 1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service Project (Pure Air on the Lake, L.P.) Station.

1992 Outstanding Engineering Achievement Award presented by the National Society of P

Demonstration of Innovative Applications of Technology 1995 Design Award presented by the Society of Plastics Industries in recognition of the mfor the CT-121 FGD Process(Southern Company Services, Inc.) 1994 Powerplant Award presented by Power magazine to Georgia Powerís Plant Yates. C

Department of Energy.1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and W1993 Environmental Award presented by the Georgia Chamber of Commerce.

Tidd PFBC Demonstration Project (The Ohio Power 1992 National Energy Resource Organization award for demonstration of energy-efficient 

Company)

1991 Powerplant Award presented by Power magazine to American Electric Power Compwas The Babcock & Wilcox Company.

Tampa Electric Integrated Gasification Combined-Cycle 1997 Powerplant Award presented by Power magazine to Tampa Electricís Polk Power St

Project (Tampa Electric Company)

1996 Association of Builders and Contractors Award presented to Tampa Electric for qual1993 Ecological Society of America Corporate Award presented to Tampa Electric for its 1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of process.1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innov

Wabash River Coal Gasification Repowering Project 1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc.(Wabash River Coal Gasification Repowering ProjectJoint Venture) 1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 199

Council competition.

Development of the Coal Quality Expertô (ABB In 1996 recognized by then Secretary of Energy Hazel OíLeary and EPRI President RichaCombustion Engineering, Inc. and CQ Inc.) DOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Pr
4-16 Program Update 2001

The following provides a brief synopsis of the publications and information transfer mechanisms currently inplace.Clean Coal Technology Demonstration Program: Program Update provides an annual summary of programand project progress, accomplishments, and financialstatus along with a historical backdrop and programrole relative to current policy.Clean Coal Technology Conference Proceedingsserves as an update on issues impacting the programand provides feedback on program informationrequirements, and a periodic snapshot of how each ofthe active projects is progressing with some degree oftechnical depth.Clean Coal Today newsletter offers its readers a quarterly look at the CCT Program and related issues, highlighting key events, updating project status, and listingthe latest publications and upcoming events.Project Performance Summary documents provide a12-page synopsis of completed projects, highlightingeach project’s operational, environmental, and economic performance. Thirteen have been published so far, with another one expected in early fiscal year 2002. Topical Report documents capture projects at critical junctures and highlight particular technological advan- tages, project plans, and expected outcomes. Nineteen have been published so far. The 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. gov- ernment. The NTIS has many of the CCT Program technical reports. CCT Program Bibliography of Publications, Papers, and Presentations periodically updates the key materi- als 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 

lessons learned in solicitprojects and implementiCCT Compendium is an rating the CCT Program cessed on the Internet (hcctc/).Exhibits provide a meanbroadcast videos, and inprogram messages at a vfocal points for distributof the program and inforrently four exhibits of vathat are updated and mothe appropriate message The Home Page of DOEvides the primary Internetion on DOE’s Fossil EneWorld Wide Web links (hExhibit 4-9 summarizes can be obtained and infoaccessed.

The CCT Compendium is a CCT Program.

Exhibit 4-9

How to Obtain CCT Program Information

Media Description and ActionClean Coal Today Subscription to quarterly newsletter—Send name and address to U.S.

Department of Energy, FE-24, Washington, DC 20585.

Fossil Energy Home Page Primary gateway to extensive information on DOE’s Fossil Energy

Program and to relevant Web links—On the Internet, accesshttp://www.fe.doe.gov and use menu and/or search options.

CCT Compendium On the Internet, access http://www.lanl.gov/projects/cctc/.CCT Program Update and other publications Send name and address to U.S. Department of Energy, FE-20,

Washington, DC 20585.

National Technical Information Service U.S. Department of Commerce, 5285 Port Royal Road,

Springfield, VA 22161.
Publications Issued in FY2001The following publications were issued in fiscal year2001 by the CCT Program. Similar types of publications can be expected in fiscal year 2002.• Clean Coal Technology Demonstration Program:

Program Update 2000

• Clean Coal Today: Winter 2000, Spring 2001, Summer 2001, Fall 2001

• Clean Coal Today Index• Project Performance Summary—Demonstration of

Advanced Combustion NO

x Control Techniques for

a Wall-Fired Boiler Project

• Project Performance Summary—Evaluation of Gas

Reburning and Low-NOx Burners on a Wall-Fired

Boiler

• Topical Report—Environmental Benefits of Clean

Coal Technologies

• Topical Report—The Wabash River Coal Gasification Repowering Project—An Update• Topical Report—Coproduction of Power Fuels and

Chemicals

Information AccessThe Department of Energy continues to expand its Website to provide information on federal fossil energyprograms and serve as a gateway to other related information throughout the United States and the world.Once into the DOE Web site, users can obtain generalinformation and follow links to increasingly detailedinformation, ultimately accessing specific data on individual projects and facilities. Hyperlinks allow users tomove seamlessly between DOE headquarters and fieldsites. Users can also access technical abstracts andreports maintained by DOE’s Office of Scientific andTechnical Information (OSTI) at Oak Ridge, Tennessee. The gateway links to more than a hundred energyrelated Web sites operated by private companies, tradeassociations, and other agencies worldwide.

Furthermore, the Fossil Energy International Activitiessite on the World Wide Web has been expanded withthe addition of new country pages in the WesternHemisphere region (Mexico, Ecuador and Canada).Many of the existing country pages have also beenupgraded, with new hyperlinks to business- or energyrelated information sources. An innovation at theFossil Energy International Activities Web site is aseries of newly created Country Energy Overviews.Each overview, individualized for a particular country,includes a status summary of that country’s energyinfrastructure, energy and environmental policies, andprivatization efforts. Fifteen country pages are nowavailable. The Uniform Resource Locator (URL) forthe Fossil Energy International main page is http://www.fe.doe.gov/international and can be accessed viathe “International” hyperlink in the Fossil EnergyHome Page (http://www.fe.doe.gov).

In February 1998, DOE resource on the InterneCompendium, sponsorand the National Energ(NETL), is dedicated to information derived fropendium is designed to contains a broad collecand information, makinboth managers and engaccess the latest Clean tion Program: Program published periodically CCT Compendium is ahttp://www.lanl.gov/pr

The new Coal & Power Systems exhibit at the Clean Coal and Power Conference in Washin
4-18 Program Update 2001

Representatives from DOE and Industry convened in Kbilateral cooperative agreem

Information Dissemination and FeedbackA number of mechanisms are used to disseminate program information to customers and stakeholders andobtain feedback from them on specific issues, programdirection, and information requirements. The followingprovides a brief outline of the mechanisms.Public Meetings were routinely held over the course ofthe acquisition phase of the CCT Program to solicitinput on procurement actions. Subsequently, projectparticipants have been holding open houses for thepublic, providing tours of demonstration facilities, andpublicizing projects through groundbreaking and dedication ceremonies.Executive Seminars involve program officials meetingwith key industry officials at their places of business tofacilitate discussion. Discussions seek to obtain abetter understanding of the dynamics of the decisionmaking process for adopting new power generatingtechnologies, determine how the program could bestsupport the process and achieve a positive outcome,and gain insights into the future direction of the powerindustry. Over 50 meetings have been held since 1992with influential leaders in the utility, independentpower, regulatory, and financial communities.Stakeholder Meetings bring together key stakeholderorganizations for the purpose of coordinating programs, where appropriate, and discussing pertinentissues and implementation strategies to address issuesand outreach needs. Such stakeholder organizationsinclude 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 targetedaudiences to review and discuss topics of interest,document discussions and findings, and provide recommendations, as appropriate. Trade Missions are a

subset of these and differ only in that the thrust is international in character with the purpose of promoting theexport of U.S. technology and services. The outreachprogram has participated in over 230 technical conferences, workshops, and trade missions since 1991.Conferences and Workshops Held inFY2001China. The first U.S.-China Clean Energy TechnologyForum and Exhibition was held in Beijing August 29-31, 2001. The forum moved bilateral cooperationforward as Shi Dinghuan, Secretary General of China’sMinistry of Science and Technology (MOST), outlinedthe technology goals of China’s new Five Year Plan inopening the second meeting of the Permanent Coordinating Committee. The committee was established topromote U.S.-China cooperation on fossil fuels. At theforum’s conclusion, five project task agreements relating to coal were signed. Over 500 people attended theTechnology Forum and Exhibition, which included 39U.S. and 65 Chinese presentations and a variety oftechnical sessions covering power systems, environmental control technologies, clean fuels, and energyefficiency. A Technology and Equipment Exhibitionwith over 100 displays highlighted the technologiesdiscussed throughout the conference, including threeDOE exhibits by the Office of Coal & Power Systems,Ultra-Clean Transportation Fuels Program, and theNational Petroleum Technology Office.The Fossil Energy Acting Assistant Secretary citedincreasing electric power demand, especially in rapidlyindustrializing countries such as China, as a compellingreason to develop a diversified energy strategy thatbalances energy and environmental issues. Prior to theBeijing conference, some 100 attendees gathered forthe first U.S.-China Symposium on CO2 Emission Control Science and Technology, held in Hangzhou, China.Discussions of the 40 papers presented focused onadvanced combustion technologies and alternativeenergy sources, within the context of how technologiescan capture and sequester CO2

.

In all, the meetings and cbenefit that can be realizbetween the United Statelargest energy consumergases.India. As part of the Effponent of the Greenhous(GEP) between the U.S. velopment (USAID) and NETL sponsored two traaimed at special areas of Some 35 power plant maworkshops. “Availability Through Predictive DiagJanuary 26–February 10predictive diagnostics mThe second workshop, “zation/Emissions ControPreheaters,” held on Febgeared toward methodoltion, environmental imprheater performance. In aNETL arranged training formance improvement. National Thermal Power trained in cooling tower 
United Kingdom. In May 2001, FE held a workshopin Knoxville, Tennessee called the “Introductory Meeting on Potential US-UK Interactions in Fossil Energy”as the first step toward developing the first Implementing Arrangement under a memorandum of understanding (MOU) signed in November 2000 by DOE and theUnited Kingdom Department of Trade and Industry forcooperative work in energy R&D. The two-day meeting featured talks on various coal and power systemsresearch areas with a goal of identifying commonpoints of interest. Topics discussed included IGCC,fuel cells, advanced process and environmental controlsystems, CO2 sequestration, transportation fuels and

chemicals, as well as crosscutting research in advancedmaterials and advanced modeling and instrumentation.Participants focused on advanced materials, expected tobe one of the first areas explored, through such topics asneeded research in ultrasupercritical power plants, nondestructive examination techniques for assessing theremaining life of gas turbine materials, and ceramiccomposites for combustor liners. Country collaborationis viewed as a tool for reducing overall costs by researching complementary subject areas. The workshopalso illuminated business opportunities and providedperspective on both internal and export energy markets.United States. The First National Conference on Carbon Sequestration was held in Washington, D.C. onMay 14–17, 2001, and drew over 400 representativesfrom the research community, academia, and industry.Some 150 papers were presented in the technical areasof geologic, terrestrial, and ocean sequestration; captureand separation; conversion and utilization; and modeling. Federal research in this area has grown to an activeprogram with 58 discrete projects cost-shared with theprivate sector and producing important results.A workshop on establishing an International Test Network for CO2 Capture was held October 11–12, 2000,

in Gaithersburg, Maryland. Forty-two researchers from10 countries attended, representing industry, government, and academia. The workshop was organized bythe International Energy Agency Greenhouse Gas Research and Development Programme, DOE, and ABB Lummus Global of Switzerland to identify areas for collaboration. The focus was on CO2 capture techniques that employ regenerable chemical scrubbing at atmospheric pressure, considered the most ma- ture capture technology. The Acting Assistant Secretary for Fossil En- ergy described carbon sequestration as the third leg of DOE’s climate change strategy, joining energy efficiency and the use of low- or no-carbon fuels. Capture of CO2 accounts for 75–80 percent of the cost of CO2 sequestration. Transportation costs are highly dependent on the relative locations of the capture facility and the storage site. The largest industrial application for CO2 is in the oil and gas industry for enhanced oil recov- ery (EOR). Four major areas of collaboration constituting the In- ternational Test Network were identified: (1) evalua- tion of capabilities of current CO2 scrubbing models, (2) development of an analytical framework to per- form transparent and consistent analyses of CO2 scrub- bing, (3) improvement of existing scrubbing methods through fundamental research, process development, and systems integration, and (4) initiation of a feasibil- ity study to define the characteristics of a future demonstration plant for investigating advanced CO2 capture concepts. The proposed new demonstration plant would make it possible to evaluate all CO2 scrub- bing technologies in an integrated manner at one test site. The workshop also included a visit to the Warrior Run Power Plant near Cumberland, Maryland, which uses state-of-the art gas cleaning technology. The U.S. Naval Resear

the primary sponsors ocruise conducted at the scientific research team questration Field Expeengineers from the UniCanada undertook a prtom sediments at a depa detailed mapping of ters from three local higgraduate students from also made an educationA workshop on sensors NETL and held April 1D.C., was attended by tions, including private academia, and governm21 Program, ultra-high performance would reqate at optimal conditiondemand and feedstock, for sensor and control smance can be improvecontrol systems. The wsions on advanced comfuel cells, and environmprioritize the near-term trols needs. A discussion of emergiresults indicated sensoproved for on-line or intions are extremely harfocus on robustness anlongevity with cost. Secation capabilities of inessential feature of new fuel/air ratio was identiprove power generation emissions. The challeninto meaningful informthe control system. Mu

NETL Director addressing the plenary session of the First National Conference on Carbon Sequestration.
4-20 Program Update 2001

the area of accurate measurement of on-line solid fuelflow. Feedstock characterization was also identified asa long-term need. Combustion zone measurement techniques remain a high priority. The primary need thereis to develop materials and techniques capable of accurately detecting gas path and surface temperatures inhigh-pressure corrosive environments. Such capabilities are also needed for emissions controls. Some methods exist today, but they need improvement.Advanced controls development was also identified asan important need for both existing and future powergeneration facilities. To facilitate DOE’s Vision 21Program, with its modular yet interdependent components, an umbrella approach was deemed necessary. Atthe individual modular system level, the need was discussed to develop smart feedback or feedforward controls utilizing neural networks and validated predictivemodels. The information compiled from the workshopwill be used to align FE’s Advanced Research Programsensors and controls development efforts with both theVision 21 Program and the Power Plant ImprovementInitiative.Latin America and the Caribbean. The Office ofFossil Energy, United States Energy Association, andSouthern States Energy Board were among the representatives that attended the first-of-a-kind conferencedealing with the role of cleaner fossil fuel systems(CFFS) in energy poverty reduction for Latin Americaand the Caribbean (LAC). The four-day conferencewas held in Rio de Janeiro, Brazil in February 2001;the first day and a half focused on Brazil and the remaining time focused on other LAC regions. The conference addressed LAC energy issues and energypoverty reduction with an emphasis on assuring energyand electricity access to all people including the poor.It is estimated that 220 million people, or 45 percent ofthe LAC total population, live in poverty with littleaccess to adequate and affordable electricity.Forecasts show fossil fuels will continue to play anincreasingly important role in the region as hydropowerdeclines from 62 percent in 2000 to 46 percent in 2020.

CFFS can meet the challenges of satisfying demandsfor electricity and transportation while contributing tothe economic growth and environmental protection ofthe region.Conference presenters, representing a myriad of perspectives on the problems and solutions surroundingthe goals of reducing energy poverty, identified morethan a dozen critical recommendations for achievingthis goal. The use of CFFS holds the promise of providing sustainable and affordable energy to the world’spopulation living without such energy today and is vitalto the goal of reducing energy poverty without deleterious consequences to the environment. Moreover, thedramatic population growth coupled with exponentialelectricity demand growth will mandate that all formsof energy are used in providing the necessary generation capacity.Trade Mission Activities in FY2001The U.S. Environmental Protection Agency has requested assistance from NETL in implementing a Technology Cooperation Agreement Pilot Project (TCAPP)in China. The TCAPPs help developing countries designand implement actions to attract investment in cleanenergy technologies that will meet their economic development goals, while mitigating greenhouse gas emissions. Three fossil energy-related projects are planned:Clean Coal Technology, Improving Efficiency of CoalFired Boilers, and Natural Gas Combined-Cycle PowerGeneration. The first two of these were launched at ameeting held January 9, 2001, in Beijing. The clean coaltechnology team agreed to focus on advanced CCTs forpower generation, such as integrated gasification combined-cycle, and pressurized fluidized-bed combustion,and prepared a two-year strategy including exchange ofinformation on CCT RD&D activities in both countries.The plan also includes a study tour by senior Chineseexperts to review U.S. CCT experience, visit demonstration plants, meet manufacturers, and discuss ideas withU.S. CCT suppliers and financial institutions on how toremove barriers to CCT transfer to China. An Industrial

Boiler Team’s action itemadvanced boiler products establishment of a ChineAssociation, as well as coference on Technical Imptrial Boilers to Reduce G
IntroductionCCT Program projects provide a portfolio of technologies that will enable coal to continue to provide lowcost, secure energy vital to the nation’s economy whilesatisfying energy and environmental goals well into the21st century. This is being carried out by addressing

four basic market sectors: (1) environmental controldevices 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 thenation’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 projectsthat address SO2 and NOx control for coal-fired boilers.

The resultant technologies provide a suite of cost-effective control options for the full range of boilertypes. The 19 environmental control device projectsare valued at more than $702 million (total projectfunding). These include seven NOx emission controlsystems installed in more than 1,750 MWe of utilitygenerating capacity, five SO2 emission control systems

installed on approximately 770 MWe, and seven combined SO2/NOx 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 ofadvanced electric power generation options for bothrepowering and new power generation. These advanced options offer greater than 20 percent reductionsin greenhouse gas emissions; SO2, NOx, and particulate

emissions far below New Source Performance Stan5. CCT Program Projects 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 gasifica- tion combined-cycle (IGCC) systems, and two ad- vanced combustion/heat engine systems. These projects will provide the demonstrated technology base necessary to meet new capacity requirements in the 21st century. Also addressed are approaches to converting raw run- of-mine coals to high-energy-density, low-sulfur prod- ucts. These products have application domestically 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 im- pact of utilizing coals not previously burned at a facil- ity, 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 applicati

value of nearly $1.3 bitution of coal for 40 peintegration of a direct iproduction of electricitemissions and solid wations of an industrial-spulse combustor systemThe remainder of this sthe technologies being for each project. The CCT projects are sprindicated in white.
5-2 Program Update 2001

Technology OverviewEnvironmental Control DevicesEnvironmental control devices are those technologiesretrofitted to existing facilities or installed on newfacilities for the purpose of controlling SO2 and NOxemissions. Although boilers may be modified andcombustion affected, the basic boiler configuration andfunction remain unchanged with these technologies.SO2 Control Technology. Sulfur dioxide is an acid gas

formed during coal combustion, which oxidizes theinorganic pyritic sulfur (Fe2S) and organically boundsulfur in the coal. Identified as a precursor to the formation of acid rain, SO2 was targeted in Title IV of the

CAAA. Phase I of Title IV, effective in 1995, affected261 coal-fired units nationwide. The required SO2 reduction was moderate and largely met by switching tolow-sulfur fuels. In 2000, Phase II of Title IV becameeffective, impacting all fossil fuel-fired units, but mostof all, the approximately 700 pre-NSPS coal-fired facilities. The CAAA provides utilities flexibility in control strategies through SO2 allowance trading. This

permits a range of control options to be applied by autility, as well as allowance purchasing. Recognizingthis, the CCT Program has sought to provide a portfolio of SO2 control technologies.

Sulfur dioxide control devices embody those technologies that condition and act upon the flue gas resultingfrom combustion, not the combustion itself, for thesole purpose of removing SO2. Three basic approaches,

discussed below, have evolved and are driven primarily by different conditions that exist within the preNSPS boiler population impacted by the CAAA. Thereis a tremendous range in critical factors, such as size,type, age, and space availability for these boilers.

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 isinjected into the boiler or the ductwork, and humidification is incorporated in some fashion to properlycondition the flue gas for efficient SO2 capture. Equipment size and complexity are held to a minimum tokeep capital costs and space requirements low. Bothlimestone and lime sorbents are used. Limestone costsare about one-third that of hydrated lime; but limestone must be conditioned (calcined), and even then, itis less effective in SO2 capture (under simple sorbentinjection conditions) than hydrated lime. Where limestone is used, it is injected into the boiler to producecalcium oxide, which reacts with SO2 to form solidcompounds of calcium sulfite and calcium sulfate.Both limestone and lime injection require the presenceof water (humidification) and a calcium-to-sulfur(Ca/S) molar ratio of about 2.0 for sulfur capture efficiencies of 50–70 percent.In the mid-range of the spectrum are 100- to 300-MWeboilers less than 30 years old and somewhat spaceconstrained. For many of these, an increase in equipment cost is justified by enhanced performance. Theapproach involves introduction of a reactor vessel inthe flue gas stream to create conditions to enhance SO2capture beyond that achievable with the simpler sorbent injection systems. Lime is used, as opposed tolimestone, and sulfur capture efficiencies up to 90percent can be achieved at Ca/S molar ratios of1.3–2.0. This category of control device is called aspray dryer because the solid by-product from thereaction is dry.At the other end of the spectrum are the larger(300-MWe and larger) existing boilers, with some latitude in space availability, and new plants. For theseboilers, advanced flue gas desulfurization (AFGD) wetscrubbers, with higher capital cost but higher sulfurcapture efficiency than other approaches, become costeffective. These systems apply larger and somewhatmore complex reactors that drive up the capital cost.

However, the sorbent is which reduces operating nologies reduce capital cincrease overall plant effSO2 removal efficiencie

Ca/S molar ratio of abousignificantly lower than proaches. Furthermore, asolid by-product is in sluproduce gypsum—a salaThe CCT Program succebent injection systems, otwo AFGD systems. All hibit 5-1 briefly summarperformance of the SO2 

described in the project NOx Control Technolog

from oxidation of nitrog(fuel-bound NOx) and ox

air at high temperatures To control fuel-bound N

limit oxygen at the early control thermal NOx, it itemperatures.Pure Air on the Lake L.P. dremoved 95 percent or mor

Generating Station in India
The 10-MWe AirPol gas suspension absorption demonstrationunit. LIFAC reactor being installed in Richmond, Indiana. The CT-121’s Jet Bubblin

Exhibit 5-1

CCT Program SO2 Control Technology Characteristics

Coal Sulfur 

Project Process Content 

10-MWe Demonstration of Gas Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7–3.5% 

Absorption particulate recycle (lime sorbent)Confined Zone Dispersion Flue Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.5–2.5% 

Desulfurization DemonstrationLIFAC Sorbent Injection Desulfurization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% Demonstration Project humidification vessel and sorbent recycleAdvanced Flue Gas Desulfurization AFGD—cocurrent flow, integrated quench absorber tower, and reaction 2.25–4.7% 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% of Technology for the CT-121 FGD Process Reactor®) for combined SO2 and particulate capture (gypsum by-product)
5-4 Program Update 2001

Nitrogen oxides were identified both as a precursor toacid rain (targeted under Title IV of the CAAA) and asa contributor to ozone formation (targeted under TitleI). Phase I of Title IV, effective in 1995, required 265wall- and tangentially fired coal units to reduce emissions to 0.50 and 0.45 lb/106 Btu, respectively. In2000, Phase II of Title IV impacted all fossil-fueledunits, but most notably, the balance of the pre-NSPScoal-fired units (see Exhibit 5-2). Ozone nonattainmentprompted the U.S. Environmental Protection Agency(EPA) to issue a NOx transport State Implementation

Plan (SIP) call for 22 states and the District of Columbia to cut NOx emissions to 85 percent below 1990

rates or achieve a 0.15 lb/106 Btu emission rate byMay 2003. The fate of the SIP call is uncertain as litigation proceeds.The CCT Program has sought to provide a number ofNOx control options to cover the range of boiler typesand emission reduction requirements. Control of NOxemissions can be accomplished either by modifyingthe combustion process or by acting upon the productsof combustion (or combinations thereof). Combustionmodification technologies include low-NOx burners(LNBs), advanced overfire air (AOFA), and reburningprocesses using either natural gas or coal. Postcombustion processes for treating flue gas include selective

catalytic reduction (SCR) and selective noncatalyticreduction (SNCR). Advanced controls can also help inNOx reductions.The LNBs regulate the initial fuel-air mixture, velocities, and turbulence to create a fuel-rich flame core,and control the rate at which additional air required tocomplete combustion is mixed. This staging of combustion avoids a highly oxidized environment and hotspots conducive to formation of fuel-bound NOx andthermal NOx. Alone, LNBs typically can achieve 40–50 percent NOx reduction.The AOFA technology involves injection of air abovethe primary combustion zone to allow the primarycombustion to occur without the amount of oxygenneeded for complete combustion. This oxygen deficiency mitigates fuel-bound NOx formation. TheAOFA, injected at high velocity, creates turbulentmixing to complete the combustionin a gradual fashion at lower temperatures to mitigate thermal NOxformation. Usually, AOFA is used incombination with LNBs; but alone,AOFA can achieve 10–25 percentNOx emission reductions. The LNB/AOFA systems generally can achieveNOx emission reductions of 37 to 68percent, depending upon boiler type.In reburning, a percentage of the fuelinput to the boiler is diverted to injection ports above the primary combustion zone. Either gas or coal istypically used as the reburning fuelto provide 10–30 percent of the heatinput to the boiler. The reburningfuel is injected to create a fuel-richzone deficient in oxygen (a reducingrather than oxidizing zone). The NOxentering 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. Reburnintypes, including cyclone emission reductions of 5The SCR and SNCR tecin combination with comprocesses use ammonia with NOx to form eleme

SNCR system can only b(1,600–2,200 oF) where SCR system is typically 600–800 oF. Generally, Scan achieve NOx emissio

and 80–90+ percent, resAdvanced control systemare also becoming an inttems. These systems can 

The Pure Air on the Lake, LP AFGD absorber module at base of stack with sorbent silos in the foreground.

Exhibit 5

Group 1 and 2 Boi

and Phase II NOx Em

 Numb of 

Boiler Types Boile

Group 1Tangentially fired 299 Dry-bottom, wall-fired 308 Group 2Cell burner 36 Cyclone >155 MWe 55 Wet-bottom, wall-fired >65 MWe 26 Vertically fired 28 

Source: U.S. Environmental Protection Agency, Reduction Program, Final Rule for Phase II, Gro(http://www.epa.gov/docs/acidrain/noxfs3.html)
eters and optimize performance to reduce NOx while

enhancing boiler performance.Under the CCT Program, seven NOx control technologies were assessed encompassing LNBs, AOFA,

reburning, SNCR, SCR, and combinations thereof. Sixof the seven projects have completed operations. Oneproject has been extended. Exhibit 5-3 briefly summarizes the characteristics and performance of the technologies that are described in more detail in the projectfact sheets.Combined SO2/NOx Control Technology. Combined

SO2/NOx control systems encompass those technologies that combine previously described control methods and those that apply other synergistic techniques.

Three of the projects combine either LNBs or gasreburning with sorbent injection. In one of these,SNCR is used with LNBs to enhance performance.Another project combines a number of techniques toimprove overall system performance, such as LNBswith SNCR, unique space-saving and durable wetscrubber design, sorbent additive, and artificial intelligence controls. The balance of the six projects usesynergistic methods not previously described.

SOx-NOx-Rox BoxTM incorporates an SCR catalyst ina high-temperature filter bag for NOx control and applies sorbent injection for SO2 control. The high-temperature filter bag, operated in a standard pulsed-jetbaghouse, protects the SCR catalyst, allows operationat optimal NOx control temperatures, forms a sorbent

cake on the surface to enhance SO2 capture, and provides high-efficiency particulate capture.

SNOXTM uses SCR followed by catalytic oxidation ofSO2 to SO3 with condensation of the SO3 in the presence of water to produce sulfuric acid. Following theSCR with the catalytic oxidation allows the SCR tooperate at optimal ammonia concentration withoutworry of ammonia slip (ammonia passing to the second catalyst is broken down into water vapor, nitrogen,and a small amount of NOx). Furthermore, most particulates passing through the upstream baghouse arecaptured in the sulfuric acid condensing unit. The system produces no solid waste.All six of the combined SO2/NOx control technologyprojects have completed operations. Exhibit 5-4 brieflysummarizes the characteristics and performance of thetechnologies that are described in the project factsheets.Advanced Electric Power GenerationTechnologyAdvanced electric power generation technologiesenable the efficient and environmentally superior generation of electricity. The advanced electric powergeneration projects selected under the CCT Programare responsive to capacity expansion needs requisite tomeeting long-term demand, offsetting nuclear retirements, and meeting stringent CAAA emission limitseffective in 2000. These technologies are characterizedby high thermal efficiency, very low pollutant emissions, reduced CO2 emissions, few solid waste problems, and enhanced economics. Advanced electricpower generation technologies may be deployed in

modules, allowing phademand growth, and to requirements of municgenerators.There are five generic tion technologies demoThe characteristics of tlined here, and the speare presented in more dFluidized-Bed Combution (FBC) reduces em

trolling combustion pasorbent (such as crushetion chamber along wimixed with the limestothe combustion chambas SO2 is captured by t

solid calcium compounThe resultant waste is a disposed of easily or ution applications. More be captured in this manAt combustion temperfluidized mixing of the combustion and sulfur ture range is about half ized-coal boiler and bethermal NOx is formedare about 70–80 percentional pulverized-coal combustors substantialemissions. Also, FBC hash coal, whereas convmust limit ash content levels.Two parallel paths werment—bubbling and ciized-beds use a dense fvelocity to effect good erosion of an in-bed he

Kodak Park was one of two sites demonstrating micronized coal reburning.
5-6 Program Update 2001

Foster Wheeler’s LNBs used at Cherokee Station for the GRLNB demonstration. Air and coal feed for coal reburning in a cyclone boiler at the Nelson Dewey Station. The SCR demonstration fac

Crist.

Exhibit 5-3

CCT Program NOx Control Technology Characteristics

Boiler Size/ 

Project Process Type 

Demonstration of Advanced Combustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500-MWe/wall 

for a Wall-Fired Boiler and artificial intelligence controlsDemonstration of Coal Reburning for Cyclone Coal reburning—30% heat input 100-MWe/cyclone 

Boiler NO

x

 Control

Full-Scale Demonstration of Low-NO

x Cell Burner LNB—separation of coal and air ports on plug-in unit 605-MWe/cell burner 

RetrofitEvaluation of Gas Reburning and Low-NOx Burners LNB/gas reburning/AOFA—13–18% gas heat input 172-MWe/wall 

on a Wall-Fired BoilerMicronized Coal Reburning Demonstration Coal reburning—14% heat input (tangentially fired) and 148-MWe/tangential 

for NO

x

 Control 17% heat input (cyclone) 50-MWe/cyclone 

Demonstration of Selective Catalytic Reduction SCR—eight catalysts with different shapes and 8.7-MWe/various 

Technology for the Control of NOx Emissions chemical compositions

from High-Sulfur, Coal-Fired Boilers180-MWe Demonstration of Advanced Tangentially LNB/AOFA—advanced LNB with close-coupled 180-MWe/tangential 

Fired Combustion Techniques for the Reduction of NOx and separated overfire air

Emissions from Coal-Fired Boilers
LIMB furnace sorbent injection lines The SOx-NOx-Rox Boxô and SCR catalyst holder. The sorbent injection syst

Exhibit 5-4

CCT Program Combined SO2/NOx Control Technology Characteristi

Boiler Size/ 

Project Process Type 

SNOXô Flue Gas Cleaning Demonstration SCR/oxidation catalyst/sulfuric acid condenserósynergistic 3.4% 

Project catalyst effect and no solid wasteLIMB Demonstration Project Extension and LNB/sorbent injectionófurnace and duct injection, calcium-based 1.6ñ3.8% 

Coolside Demonstration sorbentsSOx-NOx-Rox Boxô Flue Gas Cleanup SCR/high-temperature baghouse/sorbent injectionóSCR in high- 3.4% 

Demonstration Project temperature filter bag and calcium-based sorbent injectionEnhancing the Use of Coals by Gas Reburning Gas reburning/sorbent injection (GR-SI)ócalcium-based sorbents 3.0% 

and Sorbent Injection used in duct injectionMilliken Clean Coal Technology Demonstration LNB/SNCR/wet scrubberósorbent additive and space-saving, 1.5ñ4.0% 

Project durable scrubber designIntegrated Dry NOx/SO2 Emissions LNB/SNCR/sorbent injectionócalcium- and sodium-based 0.4% 

Control System sorbents used in duct injection
5-8 Program Update 2001

ized-beds use a relatively high fluidization velocity thatentrains the bed material, in conjunction with hot cyclones, to separate and recirculate the bed materialfrom the flue gas before it passes to a heat exchanger.Hybrid systems have evolved from these two basicapproaches.Fluidized-bed combustion can be either atmospheric(AFBC) or pressurized (PFBC). The AFBC systemsoperate at atmospheric pressure while PFBC operatesat pressure 6 to 16 times higher. The PFBC systemsoffer higher efficiency by using both a gas turbine andsteam turbine. Consequently, operating costs and wasteare reduced relative to AFBC, as well as boiler size perunit of power output.Second-generation PFBC integrates the combustorwith a pyrolyzer (coal gasifier) to fuel a gas turbine(topping cycle), and the waste heat is used to generatesteam for a steam turbine (bottoming cycle). The inherent efficiency of the gas turbine and waste heat re- covery in this combined-cycle mode significantly in- creases overall efficiency. Such advanced PFBC sys- tems 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), one is in construction, and the other two are in the project definition and design phase as of the end of fiscal year 2001. By the time this report is published, the project under construction will be in operation. Integrated Gasification Combined-Cycle. The IGCC process has four basic steps: (1) fuel gas is generated from coal reacting with high-temperature steam and an oxidant (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 the gas is first cooled to produce steam and then cleaned conventionally; (3) the

clean fuel gas is combusted in a gas turbine generatorto produce electricity; and (4) the residual heat in thehot exhaust from the gas turbine is recovered in a heatrecovery steam generator, and the steam is used toproduce additional electricity in a steam turbinegenerator.Integrated gasification combined-cycle systems areamong the cleanest and most efficient of the emergingclean coal technologies. Sulfur, nitrogen compounds,and particulates are removed before the fuel is burnedin the gas turbine, that is, before combustion air isadded. For this reason, there is a much lower volumeof gas to be treated than in a postcombustion scrubber.The chemical composition of the gas requires that thegas stream must be cleaned to a high degree, not onlyto achieve low emissions, but to protect downstreamcomponents, such as the gas turbine and catalysts,from erosion and corrosion.In a coal gasifier, the sulfur in the coal is released inthe form of hydrogen sulfide (H2S) rather than as SO2

.

In some IGCC systems, much of the sulfur-containing

gas is captured by a sorbOthers use existing provfide removal processes, percent of the sulfur, but which is an efficiency pecleanup systems are now hot cleanup systems, the a bed of metal oxide parZinc oxide can absorb sutures in excess of 1,000 regenerated and reused wProduced during the regsulfur, sulfuric acid, or sthat may be used to prodtechnique is capable of rcent of the sulfur in the gcleanup, IGCC systems cies of over 50 percent.High levels of nitrogen rSome of the coal’s nitrowhich can be almost totaavailable chemical procein the gas turbine can be levels by staged combusadding moisture to contrIntegrated Gasification system using coal as fuegas cleanup system, a fugenerate electricity (direverter to convert direct cand a heat recovery systwould be used to produca bottoming steam cycleEnergy conversion in futraditional energy convecent, depending on fuel cells directly transform tand an oxidant (air or oxinstead of going through boiler, turbines, and gen

The 110-MWe Nucla AFBC demonstration enabled PyropowerCorporation (now owned by Foster Wheeler) to save almostthree years in establishing a commercial line of AFBC units.
an anode and a cathode separated by an electrolytelayer. In a coal gasification/fuel cell application, coalgas is supplied to the anode and air is supplied to thecathode to produce electricity and heat.Of the four IGCC projects, three have completed operations, and one is in the project definition and designphase as of the end of fiscal year 2001. The project inthe design phase plans to incorporate a molten carbonate fuel cell (MCFC).Coal-Fired Diesel. Coal-fired diesels use either acoal-oil or coal-water slurry fuel to drive an electricgeneration system. The hot exhaust from the dieselengine is routed through a heat-recovery unit to produce steam for a steam-turbine electric generatingsystem (combined cycle). Environmental control systems for SO2, NOx, and particulate removal treat thecooled exhaust before release to the atmosphere. Thediesel system is expected to achieve a 41ñ48 percentthermal efficiency. The 5- to 20-MWe capacity rangeof the technology is most amenable to distributedpower applications. The CCT coal-fired diesel projectis in construction as of the end of fiscal year 2001.Slagging Combustor. Many new coal-burning technologies are designed to remove the coal ash as moltenslag from the combustor rather than the furnace. Mostof these slagging combustors are based on a cycloneconcept. In a cyclone combustor, coal is burned in aseparate chamber outside the furnace cavity. The hotcombustion gases then pass into the boiler where theactual heat exchange takes place.An advantage of a cyclone combustor is that the ash iskept out of the furnace cavity where it could collect onboiler tubes and lower heat transfer efficiency. To keepash from being blown into the furnace, the combustiontemperature is kept so high that mineral impuritiesmelt and form slag, hence the name slagging combustor. A vortex of air (the cyclone) forces the slag to theouter walls of the combustor where it can be removedas waste.

Results show that by positioning air injection ports sothat coal is combusted in stages, NOx emissions can bereduced by 70ñ80 percent. Injecting limestone into thecombustion chamber has the potential to reduce sulfuremissions by 90 percent in combination with a spraydryer absorber. Advanced slagging combustors couldreplace oil-fired units in both utility and industrialapplications or be used to retrofit older, conventionalcyclone boilers.Exhibit 5-5 summarizes the process characteristics andsize of the advanced electric power generating technologies presented in the project fact sheets.Coal Processing for Clean Fuels TechnologyThe coal processing category includes a range of technologies designed to produce high-energy-density,low-sulfur solid and clean liquid fuels, as well assystems to assist users in evaluating impacts of coalquality on boiler performance.Western SynCoal LLCís advanced coal conversionprocess applies mostly physical-cleaning methods tolow-Btu, low-sulfur subbituminous coals, primarilyto remove moisture and secondarily to remove ash.The objective is to enhance the energy density of thealready low-sulfur coal. Some conversion of the properties of the coal is required, however, to provide stability (prevent spontaneous combustion) in transportand handling. In the process, coal with 5,500ñ9,000 Btu/lb, 25ñ40 percent moisture content, and 0.5ñ1.5 percent sulfur is converted to a 12,000 Btu/lb product with 1.0 percent moisture and as low as 0.3 percentsulfur. The SynCoalÆ product is used at utility and industrial facilities. Project operation was completed infiscal year 2001.The ENCOAL project, which completed operationaltesting in July 1997, used mild gasification to convertlow-Btu, low-sulfur subbituminous coal to a high-energy-density, low-sulfur solid product and a clean liquidfuel comparable to No. 6 fuel oil. Mild gasification is a

pyrolysis process (heatiperformed at moderate produces condensable vto solids and gas. The cas a liquid product. Moon-site energy requiremcantly beneficiated to psulfur solid fuel. The detons per day of subbitumtons per day of solid Pr

250 barrels per day of C

Both the solid and liquiburns at utility and inducessfully completed.The liquid phase methabeing demonstrated is liquefaction process usgasifier. The unique asan inert liquid to susperemoves the heat of reafor an intermediate waaddressed in the projecity of the process by sisystem and the fuel chproduct.ABB Combustion Engdeveloped a personal cCQEÆ, that will serve a

ties in selecting optimaboiler based on operatimental considerations. verified through compand utility scale. Six laducted at five separate released for commerciaties and one U.K. utilitElectric Power ResearcIt is estimated that CQEmillion annually.
5-10 Program Update 2001

The coal slurry and sorbent injectors for the Tidd PFBCdemonstration. The Piñon Pine coal conveyor from storage dome to the plant. The TRW slagging combus

Exhibit 5-5

CCT Program Advanced Electric Power Generation Technology Characte

Project Process Size 

Fluidized-Bed CombustionMcIntosh Unit 4A PCFB Demonstration Project Pressurized circulating fluidized-bed combustion 137 MWe (net) McIntosh Unit 4B Topped PCFB Demonstration Project McIntosh 4A with pyrolyzer and topping combustor 240 MWe (net) 

JEA Large-Scale CFB Combustion Demonstration Project Atmospheric circulating fluidized-bed combustion 297.5 MWe (gross)

Tidd PFBC Demonstration Project Pressurized bubbling fluidized-bed combustion 70 MWe 

Nucla CFB Demonstration Project Atmospheric circulating fluidized-bed combustion 100 MWe 

Integrated Gasification Combined CycleKentucky Pioneer Energy IGCC Demonstration Project Oxygen-blown, slagging fixed-bed gasifier with cold gas cleanup 580 MWe (gross); 5

Tampa Electric Integrated Gasification Oxygen-blown, entrained-flow gasifier with hot and cold gas cleanup 313 MWe (gross); 2Piñon Pine IGCC Power Project Air-blown, fluidized-bed gasifier with hot gas cleanup 107 MWe (gross); 9Combined-Cycle ProjectWabash River Coal Gasification Repowering Project Oxygen-blown, two-stage entrained-flow gasifier with cold gas cleanup 296 MWe (gross); 2Advanced Combustion/Heat EnginesClean Coal Diesel Demonstration Project Coal-fueled diesel engine 6.4 MWe (net) 

Healy Clean Coal Project Advanced slagging combustor, spray dryer with sorbent recycle 50 MWe (nominal) 

a Plus a 2.0 MWe molton carbonate fuel cell.
Exhibit 5-6 summarizes the process characteristics andsize of the coal processing for clean fuels technologiespresented in the project fact sheets.Industrial Applications TechnologyTechnologies applicable to the industrial sector addresssignificant environmental issues and barriers associated with coal use in industrial processes. These technologies are directed at both continuing coal use andintroducing coal use in various industrial sectors.One of the critical environmental concerns has to dowith pollutant emissions resulting from producingcoke from coal for use in steel making. Two approaches to mitigate or eliminate this problem are being demonstrated. In one, about 40 percent of the cokeis displaced through direct injection of granular coalinto a blast furnace system. The coal is essentiallyburned in the blast furnace where the pollutant emissions are readily controlled (as opposed to first cokingthe coal). The other approach eliminates the need forcoke making by using a direct iron-making process. Inthis process, raw coal is introduced into a reactor toproduce reducing gas and heat for a unique reduction

furnace; no coke is required. Excess reducing gas iscleaned and used to fuel a boiler for electric powergeneration.Coal is often the fuel of choice in cement productionbecause production costs are largely driven by fuelcost. Faced with the need to control SO2 emissions and

to address growing solid waste management problems,industry sponsored the demonstration of an innovativeSO2 scrubber. The successfully demonstrated Passamaquoddy Technology Recovery ScrubberTM uses cement

kiln dust, otherwise discarded as waste, to control SO2emissions, convert the sulfur and chloride acid gases tofertilizer, return the solid by-product as cement kilnfeedstock, and produce distilled water. No new wastesare generated, and cement kiln dust waste is convertedto feedstock. This technology also has application forcontrolling pollutant emissions in paper production andwaste-to-energy applications.In many industrial boiler applications, the relativelylow, stable price of coal makes it an attractive substitute for oil and gas feedstock. However, drawbacks toconversion of oil- and gas-fired units to coal includeaddition of SO2 and NOx controls, tube fouling, and theneed for a coolant water circuit for the combustor. Oiland gas-fired units are not high SO2 or NOx emitters;use relatively tight tube spacing in the absence of potential ash fouling; and the flow of oil or gas cools thecombustor, precluding the need for water cooling. Forthese reasons, the CCT Program demonstrated an advanced air-cooled, slagging combustor that couldavoid these potential problems. The cyclone combustorstages introduction of air to control NOx, injects sorbent to control SO2, slags the ash in the combustor toprevent tube fouling, and uses air cooling to eliminatethe need for water circuitry.The pulse combustor demonstrated by ThermoChemhas a wide range of applications. The technology canbe used in many coal processes, including coal gasification and waste-to-energy applications.

The cement kiln, slagggranular-coal injectionare completed. The Thproject completed operthe final report has not project is in the design end of fiscal year 2001Exhibit 5-7 summarizefor the industrial applicmore detail in the projeProject FacThe remainder of this dall 38 projects. Two typa brief, two-page overvan expanded four-page successfully completed panded fact sheets for cmary of the major resulas sources for obtaining contact persons and key vided in the fact sheets and team members, proproject features, procesprogress (if ongoing) or pleted), and commerciarelease of project-specinature, process flow diasheets are highly simplitrations of the concepts The portion of the proconstration is demarcate

Shown is the Coltec coal-fired diesel being installed at theUniversity of Alaska in Fairbanks.
5-12 Program Update 2001

Western SynCoal Partnershipís advanced coal conversionprocess plant in Colstrip, Montana, has produced over 1.5million tons of SynCoalÆ products.

The ENCOAL mild gasification plant near Gillette, Wyoming,has operated 12,800 hours and processed approximately260,000 tons of raw coal and produced over 120,000 tons ofPDFÆ and 121,000 barrels of CDLÆ.

The LPMEOHô process prmethanol, all of which is usCompany in Kingsport, Ten

Exhibit 5-6

CCT Program Coal Processing for Clean Fuels Technology Characteris

Project Process Size Commercial-Scale Demonstration of the Liquid Phase Methanol Liquid phase process for methanol production from 80,000 gal/day 

(LPMEOHô) Process coal-derived syngasDevelopment of the Coal Quality Expertô Coal Quality Expertô computer software Tested at 250ñ880 ENCOALÆ Mild Coal Gasification Project Liquids-from-coal (LFCÆ) mild gasification to 1,000 tons/day* 

produce solid and liquid fuels

Advanced Coal Conversion Process Demonstration Advanced coal conversion process for upgrading 45 tons/hr 

low-rank coals

*Operated at 500 ton
The Bethlehem Steel Corporation facility, which demonstratedthe injection of granulated coal directly into two blast furnacesat Burns Harbor, Indiana.

ThermoChem demonstrated MTCI’s 253-tube resonancepulse combustor.

The Cement Kiln Flue Gacrystallizer and condense(left).

Exhibit 5-7

CCT Program Industrial Applications Technology Characteristics

Project Process Size 

Clean Power from Integrated Coal/Ore Direct reduction iron-making process to eliminate coke; 3,300 tons/day of hot 

Reduction (CPICORTM) combined-cycle electric power generation 170 MWeBlast Furnace Granular-Coal Injection System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of 

Demonstration Project metal/furnaceAdvanced Cyclone Combustor with Internal Advanced slagging combustor with staged combustion and sorbent 23x106 Btu/hr 

Sulfur, Nitrogen, and Ash Control injectionCement Kiln Flue Gas Recovery Scrubber Cement kiln dust used to capture SO2; dust converted to feedstock; 1,450 tons/day of cem

and fertilizer and distilled water produced

Pulse Combustor Design Qualification Test Advanced combustion using Manufacturing and Technology 30x106 Btu/hr 

Conversion International’s (MTCI) pulse combustor/gasifier
5-14 Program Update 2001

An index to project fact sheets by application categoryis provided in Exhibit 5-8. An index by participant isprovided in Exhibit 5-9. Ongoing projects in eachcategory appear first, followed by projects having completed operations. A shaded area distinguishes projectshaving completed operations from ongoing projects.Within these breakdowns, projects are listed alphabetically by participant. In addition, Exhibit 5-8 indicatesthe solicitation under which the project was selected;its status as of September 30, 2001; and the page number for each fact sheet. Exhibit 5-9 lists the projectsalphabetically by participant and provides project location and page numbers. A key to interpreting the milestone charts is provided in Exhibit 5-10.An appendix containing contact information for all ofthe projects is provided as Appendix D. A list of acronyms used in this document is provided as Appendix E.
Exhibit 5-8

Project Fact Sheets by Application Category

Project Participant Solicita

Environmental Control DevicesSO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III

LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCT-IIIAdvanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/c

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/NO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/e

Demonstration of Coal Reburning for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/c

Full-Scale Demonstration of Low-NO

x

 Cell Burner Retrofit The Babcock & Wilcox Company CCT-III

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III

Micronized Coal Reburning Demonstration for NOx Control New York State Electric & Gas Corporation CCT-IV

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCT-II/c

for the Control of NO

x Emissions from High-Sulfur, Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion Southern Company Services, Inc. CCT-II/c

Techniques for the Reduction of NOx Emissions from Coal-Fired Boilers

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/c

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/c

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/c

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/cMilliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV

Integrated Dry NOx/SO2 Emissions Control System Public Service Company of Colorado CCT-III

Advanced Electric Power GenerationFluidized-Bed CombustionMcIntosh Unit 4A PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-III

McIntosh Unit 4B Topped PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-V/

JEA Large-Scale CFB Combustion Demonstration Project JEA CCT-I/c

Shaded area indicates projects having completed operations.
5-16 Program Update 2001

Exhibit 5-8 (continued)

Project Fact Sheets by Application Category

Project Participant SolicitatioTidd PFBC Demonstration Project The Ohio Power Company CCT-I/compNucla CFB Demonstration Project Tri-State Generation and Transmission CCT-I/comp

Association, Inc.

Integrated Gasification Combined-CycleKentucky Pioneer Energy IGCC Demonstration Project Kentucky Pioneer Energy, LLC CCT-V/desiTampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/comPiñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/comWabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering CCT-IV/com

Project Joint Venture

Advanced Combustion/Heat EnginesClean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/conHealy Clean Coal Project Alaska Industrial Development and CCT-III/com

Export Authority

Coal Processing for Clean FuelsCommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process Air Products Liquid Phase CCT-III/ope

Conversion Company, L.P.

Development of the Coal Quality ExpertTM ABB Combustion Engineering, Inc. CCT-I/comp

and CQ Inc.

ENCOAL® Mild Coal Gasification Project ENCOAL Corporation CCT-III/com

Advanced Coal Conversion Process Demonstration Western SynCoal LLC CCT-I/comp

Industrial ApplicationsClean Power from Integrated Coal/Ore Reduction (CPICORTM) CPICORTM Management Company LLC CCT-V/desi

Blast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/comAdvanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/comp

Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/comPulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/com

Shaded area indicates projects having completed operations.
Exhibit 5-9

Project Fact Sheets by Participant

Participant Project Loca

ABB Combustion Engineering, Inc. and CQ Inc. Development of the Coal Quality ExpertTM HomABB Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project Niles

Air Products Liquid Phase Conversion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) King

Process

AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption West 

Alaska Industrial Development and Export Authority Healy Clean Coal Project HealyArthur D. Little, Inc. Clean Coal Diesel Demonstration Project Fairb

Babcock & Wilcox Company, The Demonstration of Coal Reburning for Cyclone Boiler NOx Control Cassv

Babcock & Wilcox Company, The Full-Scale Demonstration of Low-NOx Cell Burner Retrofit Aber

Babcock & Wilcox Company, The LIMB Demonstration Project Extension and Coolside Demonstration Lorai

Babcock & Wilcox Company, The SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project Dille

Bechtel Corporation Confined Zone Dispersion Flue Gas Desulfurization Demonstration Sewa

Bethlehem Steel Corporation Blast Furnace Granular-Coal Injection System Demonstration Project Burn

Coal Tech Corporation Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control WilliCPICORTM Management Company LLC Clean Power from Integrated Coal/Ore Reduction (CPICORTM) Viney

CQ Inc. (see ABB Combustion Engineering and CQ Inc.)ENCOAL Corporation ENCOAL® Mild Coal Gasification Project Gille

Energy and Environmental Research Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Henn

Sprin

Energy and Environmental Research Corporation Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Denv

JEA JEA Large-Scale CFB Combustion Demonstration Project JacksKentucky Pioneer Energy, LLC Kentucky Pioneer Energy IGCC Demonstration Project TrappLakeland, City of, Lakeland Electric McIntosh Unit 4A PCFB Demonstration Project Lake

Lakeland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project Lake

LIFAC–North America LIFAC Sorbent Injection Desulfurization Demonstration Project Richm

New York State Electric & Gas Corporation Micronized Coal Reburning Demonstration for NOx Control Lansi
5-18 Program Update 2001

Exhibit 5-9 (continued)

Project Fact Sheets by Participant

Participant Project LocatiNew York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project Lansing

Ohio Power Company, The Tidd PFBC Demonstration Project BrillianPassamaquoddy Tribe Cement Kiln Flue Gas Recovery Scrubber ThomasPublic Service Company of Colorado Integrated Dry NOx/SO2 Emissions Control System Denver

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Chester

Sierra Pacific Power Company Piñon Pine IGCC Power Project Reno, NSouthern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coosa, Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newnan

Process

Southern Company Services, Inc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensaco

NO

x Emissions from High-Sulfur, Coal-Fired Boilers

Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Combustion Lynn H

Techniques for the Reduction of NOx Emissions from Coal-Fired Boilers

Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project MulberThermoChem, Inc. Pulse Combustor Design Qualification Test BaltimoTri-State Generation and Transmission Association, Inc. Nucla CFB Demonstration Project Nucla, Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project West TeProject Joint VentureWestern SynCoal LLC Advanced Coal Conversion Process Demonstration Colstrip
Exhibit 5-10

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 pof project activities—preaward, design and construction, and operation and reporting. The key provided below explains what is included in each of these 

PreawardIncludes preaward briefings, negotiations, and other activities conducted during the period between DOE’s selection of the project and award of Design and ConstructionIncludes the NEPA process, permitting, design, procurement, construction, preoperational testing, and other activities conducted prior to the begidemonstration.MTF Memo-to-fileCX Categorical exclusionEA Environmental assessmentEIS Environmental impact statementOperation and ReportingBegins with startup and includes operational testing, data collection, analysis, evaluation, reporting, and other activities to complete the demonstr
5-20 Program Update 2001
 Environmental Control Devices 

Environmental Control Devi

SO2 Control Technologies
5-22 Program Update 2001 

Environmental Control DevicesSO2 Control Technology10-MWe Demonstration ofGas Suspension AbsorptionProject completedParticipantAirPol, Inc.Additional Team MembersFLS miljo, Inc. (FLS)—technology ownerTennessee Valley Authority—cofunder and site ownerLocationWest Paducah, McCracken County, KYTechnologyFLS’ Gas Suspension Absorption (GSA) system for fluegas desulfurization (FGD)Plant Capacity/Production10-MWe equivalent slipstream of flue gas from a175-MWe wall-fired boilerCoalWestern Kentucky bituminous: Peabody Martwick, 3.05%sulfur; Emerald Energy, 2.61% sulfur; Andalax, 3.06%sulfur; and Warrior Basin, 3.5% sulfur (used intermittently)Project FundingTotal project cost $7,717,189 100%DOE 2,315,259 30Participant 5,401,930 70Project ObjectiveTo demonstrate the applicability of Gas Suspension Absorption as an economic option for achieving Phase IICAAA SO2 compliance in pulverized coal-fired boilers

using high-sulfur coal.

Technology/Project DescriptionThe GSA system consists of a vertical reactor in whichflue gas comes into contact with suspended solids consisting of lime, reaction products, and fly ash. About 99%of the solids are recycled to the reactor via a cyclonewhile the exit gas stream passes through an electrostaticprecipitator (ESP) or pulse jet baghouse (PJBH) beforebeing released to the atmosphere. The lime slurry, prepared from hydrated lime, is injected through a spraynozzle at the bottom of the reactor. The volume of limeslurry is regulated with a variable-speed pump controlledby the measurement of the acid content in the inlet andoutlet gas streams. The dilution water added to the limeslurry is controlled by on-line measurements of the fluegas exit temperature.

A test program was structthe GSA reactor for reduc

boilers using high-sulfur ronmental control capabilmechanical performance parametric (factorial) test six variables. Beyond evacontrol SO2, air toxics con

the effectiveness of GSA/tions to control both SO2 

Factorial tests were followconsistency of performan
 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 

Calendar Year

Environmental Control Devices 

Ca

(1

GSA—3 units at 50% capacityWLFO 

Results SummaryEnvironmental• Ca/S molar ratio had the greatest effect on SO2 removal, with approach-to-saturation temperature next,

followed closely by chloride content.

• GSA/ESP achieved

– 90% sulfur capture at a Ca/S molar ratio of 1.3

with 8 oF approach-to-saturation and 0.04%chloride,

– 90% sulfur capture at a Ca/S molar ratio of 1.4

with 18 oF approach-to-saturation and 0.12%chloride, and

– 99.9+% average particulate removal efficiency.

• GSA/PJBH achieved

– 96% sulfur capture at a Ca/S molar ratio of 1.4

with 18 oF approach-to-saturation and 0.12%chloride,

– 3–5% increase in SO2 reduction relative to GSA/

ESP, and

– 99.99+% average particulate removal efficiency.

• GSA/ESP and GSA/PJBH removed 98% of the hydrogen chloride (HCl), 96% of the hydrogen fluoride

(HF), and 99% or more of most trace metals, exceptcadmium, antimony, mercury, and selenium. (GSA/PJBH removed 99+% of the selenium.)

• The solid by-product was usable as low-grade cement.Operational• GSA/ESP lime utilization averaged 66.1% and GSA/

PJBH averaged 70.5%.

• The reactor achieved the same performance as a conventional spray dryer, but at one-quarter to one-third

the size.

• GSA generated lower particulate loading than a conventional spray dryer, enabling compliance with a

lower ESP efficiency.

• Special steels were not required in construction, and

only a single spray nozzle is needed.

• High availability and reliability similar to other commercial applications were demonstrated, reflecting

simple design.

Economic• Capital and levelized 

for GSA installed in sulfur coal are compstone scrubber with fber). EPRI’s TAGTM EPRI cost studies of (1990$) for a conven

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

Ground breaking/construction started 5/92

Preaward

12/89 10/90 10/92

Design and Construction

DOE selected project

(CCT-III) 12/19/89 Environmental monitoring plan completed

10/2/92Operation initiated 10/92

Design completed 12/91

Cooperative agreement awarded 10/11/90

NEPA process completed (MTF) 9/21/90

Preoperational tests initiated 9/92Construction completed 9/92

6/95

Project completed/final rep

Operation completed 3/94
5-24 Program Update 2001 

Exhibit 5-11

Variables and Levels Used in GSA

Factorial Testing

Variable LevelApproach-to-saturation temperature (°F) 8*, 18, and 28Ca/S (moles Ca(OH)2/mole inlet SO2) 1.00 and 1.30

Fly ash loading (gr/ft3, actual) 0.50 and 2.0

Coal chloride level (%) 0.04 and 0.12Flue gas flow rate (103 scfm) 14 and 20Recycle screw speed (rpm) 30 and 45

*8 °F was only run at the low coal chloride level.

Exhibit 5-12

GSA Factorial Testing Results

Project SummaryThe GSA has a capability of suspending a high concentration of solids, effectively drying the solids, and recirculating the solids at a high rate with precise control. Thisresults in SO2 control comparable to that of wet scrubbers

and high lime utilization. The high concentration of solidsprovides the sorbent/SO2 contact area. The drying enables

low approach-to-saturation temperature and chloride usage. The rapid, precise, integral recycle system sustainsthe high solids concentration. The high lime utilizationmitigates the largest operating cost (lime) and furtherreduces costs by reducing the amount of by-product generated. The GSA is distinguished from the average spraydryer by its modest size, simple means of introducingreagent to the reactor, direct means of recirculating unused lime, and low reagent consumption. Also, injectedslurry coats recycled solids, not the walls, avoiding corrosion and enabling use of carbon steel in fabrication.Environmental PerformanceExhibit 5-11 lists the six variables used in the factorialtests and the levels at which they were applied. Inlet fluegas temperature was held constant at 320 oF. Factorialtesting showed that lime stoichiometry had the greatesteffect on SO2 removal. Approach-to-saturation temperature was the next most important factor, followed closely

by chloride levels. Although an approach-to-saturationtemperature of 8 oF was achieved without plugging thesystem, the test was conducted at a very low chloridelevel (0.04%). Because water evaporation rates decreaseas chloride levels increase, an 18 oF approach-to-saturation temperature was chosen for the higher 0.12% coalchloride level. Exhibit 5-12 summarizes key results fromfactorial testing.A 28-day continuous run to evaluate the GSA/ESP configuration was made with bituminous coals averaging2.7% sulfur, 0.12% chloride levels, and 18 oF approachto-saturation temperature. A subsequent 14-day continuous run to evaluate the GSA/PJBH configuration wasperformed under the same conditions as those of the 28-day run, except for adjustments in fly ash injection ratefrom 1.5–1.0 gr/ft3 (actual).

The 28-day run on the GSA/ESP system showed that theoverall SO2 removal efficiency averaged slightly more

than 90%, very close to the set point of 91%, at an average Ca/S molar ratio of 1.40–1.45 moles Ca(OH)2/mole

inlet SO2. The system was able to adjust rapidly to the

surge in inlet SO2 caused by switching to 3.5% sulfur

Warrior Basin coal for a week. Lime utilization averaged

66.1%. The particulate re99.9+% and emission ratelb/106 Btu. The 14-day ru

showed that the SO2 remo

than 96% at an average Cmoles Ca(OH)2/mole inle

70.5%. The particulate re99.99+% and emission ra106 Btu.

All air toxics tests were cchloride coal with a 12 oF perature and a high fly as

The GSA/ESP arrangemeefficiencies of greater thamium, lead, and vanadiumnese; and less than 99% fand selenium. The GSA/P99+% removal efficienciemium, lead, manganese, scadmium removal much llower than that of the GSAHCl and HF was dependeslurry and was relatively trol configuration. Remov98% for HCl and 96% for Operational PerformaBecause the GSA system provide a contact area for 

pressure atomizer nozzles are not required to achievAlso, recycle of solids is terial in the feed slurry, wsive abrasion-resistant maThe high heat and mass trGSA enable the GSA systhan a conventional spray one-quarter to one-third thsible for space-confined pcost. The GSA system slusolids, not the reactor waland the need for corrosionmore, the high concentratscours the reactor walls a
 Environmental Control Devices 

system generates a significantly lower dust loading than aconventional spray dryer, 2–5 gr/ft3 for GSA versus

6–10 gr/ft3 for a spray dryer, thereby easing the burden on

particulate controls. The GSA system produces a solidby-product containing very low moisture. This materialcontains both fly ash and unreacted lime. With the addition of water, the by-product undergoes a pozzuolanicreaction, essentially providing the characteristics of alow-grade cement.Economic PerformanceUsing EPRI costing methods, which have been applied to30 to 35 other FGD processes, economics were estimatedfor a moderately difficult retrofit of a 300-MWe boilerburning 2.6% sulfur coal. The design SO2 removal efficiency was 90% at a lime feed rate equivalent to 1.30

moles of Ca per mole of inlet SO2. Lime was assumed to

be 2.8 times the cost of limestone. It was estimated that(1) the capital cost was $149/kW (1990$) with three unitsat 50% capacity, and (2) the levelized cost (15-year constant 1990$) was 10.35 mills/kWh with three units at 50%capacity.A cost comparison run for a WLFO scrubber showed thecapital and levelized costs to be $216/kW and 13.04mills/kWh, respectively. The capital cost listed in EPRIcost tables for a conventional spray dryer at 300 MWe and2.6% sulfur coal was $172/kW (1990$). Also, becausethe GSA requires less power and has better lime utilization than a spray dryer, the GSA will have a lower operating cost.Commercial ApplicationsThe low capital cost, moderate operating cost, and highSO2 capture efficiency make the GSA system particularly

attractive as a CAAA compliance option for boilers in the50- to 250-MWe range. Other major advantages includethe modest space requirements comparable to duct injection systems; high availability/reliability owing to designsimplicity; and low dust loading, minimizing particulateupgrade costs.GSA market entry was significantly enhanced with thesale of a 50-MWe unit worth $10 million to the city ofHamilton, 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. AnotherGSA system has been sold to a Swedish iron ore sinterplant. Sales to Taiwan, Indonesia, and India have a combined value of $20 million. Furthermore, Taiwan contracted for technical assistance and proprietary equipmentvalued at $1.0 million.

ContactsNiels H. Kastrup, (281) 

FLS miljo, Inc.100 Glennborough D

Houston, TX 77067(281) 539-3411 (fax)

James U. Watts, NETL, References10-MWe Demonstration Final Project Performanport No. DOE/PC/90542(Available from NTIS a10-MW Demonstration Final Public Design RepT10. AirPol, Inc. June 1DE960003270.)SO2 Removal Using Gas 

ogy. Topical Report No. and AirPol, Inc. April 110-MWe Demonstration tion Process at TVA’s CeFinal Report. Report NoValley Authority. March DE96000327.)

AirPol, Inc. successfully demonstrated the GSA system atTVA’s Center for Emissions Research, located at TVA’sShawnee Plant.
5-26 Program Update 2001 

Environmental Control DevicesSO2 Control TechnologyConfined Zone DispersionFlue Gas DesulfurizationDemonstrationProject completedParticipantBechtel CorporationAdditional Team MembersPennsylvania Electric Company—cofunder and hostPennsylvania Energy Development Authority—cofunderNew York State Electric & Gas Corporation—cofunderRockwell Lime Company—cofunderLocationSeward, Indiana County, PA (Pennsylvania ElectricCompany’s Seward Station, Unit No. 5)TechnologyBechtel Corporation’s in-duct, confined zone dispersionflue gas desulfurization (CZD/FGD) processPlant Capacity/Production73.5 MWe equivalentCoalPennsylvania bituminous, 1.2–2.5% sulfurProject FundingTotal project cost* $10,411,600 100%DOE 5,205,800 50Participant 5,205,800 50Project ObjectiveTo demonstrate SO2 removal capabilities of in-duct

CZD/FGD technology; specifically, to define the optimum process operating parameters and to determineCZD/FGD’s operability, reliability, and cost-effectiveness

*Additional project overrun costs were funded 100% by the participantfor a final total project cost of $12,173,000.

during long-term testing and its impact on downstreamoperations and emissions.Technology/Project DescriptionIn Bechtel’s CZD/FGD process, a finely atomized slurryof reactive lime is sprayed into the flue gas stream between the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the center of theduct by spray nozzles designed to produce a cone of finespray. As the spray moves downstream and expands, thegas within the cone cools and the SO2 is quickly absorbedon the liquid droplets. The droplets mix with the hot fluegas, and the water evaporates rapidly. Fast drying precludes wet particle buildup in the duct and aids the fluegas in carrying the dry reaction products and theunreacted lime to the ESP.

 This project included injbents (dolomitic and calcidesigns using low- and hieffects on SO2 removal an

onstration was conducted Company’s Seward StatioOne-half of the flue gas cNo. 5 was routed through section of duct between th
 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 

Calendar Year

Environmental Control Devices 

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

Ground breaking/construction started 5/92

Preaward

12/89 10/90 10/92

Design and Construction

DOE selected project

(CCT-III) 12/19/89 Environmental monitoring plan completed

10/2/92Operation initiated 10/92

Design completed 12/91

Cooperative agreement awarded 10/11/90

NEPA process completed (MTF) 9/21/90

Preoperational tests initiated 9/92Construction completed 9/92

6/94

Project completed/final report issued 6/94

Operation completed 3/94

Results SummaryEnvironmental• Pressure-hydrated dolomitic lime proved to be a more

effective sorbent than either dry hydrated calcitic limeor freshly slaked calcitic lime.

• Sorbent injection rate was the most influential parameter on SO2 capture. Flue gas temperature was the

limiting factor on injection rate. For SO2 capture efficiency of 50% or more, a flue gas temperature of

300 oF or more was needed.

• Slurry concentration for a given sorbent did not increase SO2 removal efficiency beyond a certain threshold concentration.

• Testing indicated that SO2 removal efficiencies of 50%

or more were achievable with flue gas temperatures of300–310 oF (full load), sorbent injection rate of 52–57gal/min, residence time of 2 seconds, and a pressurehydrated dolomitic-lime concentration of about 9%.

• For operating conditions at Seward Station, data indicated that for 40–50% SO2 removal, a 6–8% lime or

dolomitic lime slurry concentration, and a stoichiometric ratio of 2–2.5 resulted in a 40–50% lime utilizationrate. That is, 2–2.5 moles of CaO or CaO•MgO wererequired for every mole of SO2 removed.

• Assuming 92% lime purity, 1.9–2.4 tons of lime was

required for every ton of SO2 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 SO2 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% SO2 reduction was

estimated at less than $30/kW and operating cost at$300/ton of SO2 removed (1994$).
5-28 Program Update 2001 

Bechtel’s demonstration showed that 50% SO2 removal efficiency waspossible using CZD/FGD technology. The extended duct into which limeslurry was injected is in the foreground.

Project SummaryThe principle of the CZD/FGD is to form awet zone of slurry droplets in the middle of aduct confined in an envelope of hot gas between the wet zone and the duct walls. Thelime slurry reacts with part of the SO2 in the

gas and the reaction products dry to formsolid particles. An ESP, downstream from thepoint of injection, captures the reaction products along with the fly ash entrained in theflue gas.CZD/FGD did not require a special reactor,simply a modification to the ductwork. Useof the commercially available Type S pressure-hydrated dolomitic lime reduced residence time requirements for CZD/FGD andenhanced sorbent utilization. The increasedhumidity of CZD/FGD processed flue gasenhanced ESP performance, eliminating theneed for upgrades to handle the increased particulateload.Bechtel began its 18-month, two-part test program for theCZD process in July 1991, with the first 12 months of thetest program consisting primarily of parametric testingand the last 6 months consisting of continuous operational testing. During the continuous operational testperiod, the system was operated under fully automaticcontrol by the host utility boiler operators. The new atomizing nozzles were thoroughly tested both outside andinside the duct prior to system testing.The SO2 removal parametric test program, which began in

October 1991, was completed in August 1992. Specificobjectives were as follows:• Achieve projected SO2 removal of 50%;

• Realize SO2 removal costs of less than $300/ton; and

• Eliminate negative effects on normal boiler operations

without increasing particulate emissions and opacity.

The parametric tests included duct injection of atomizedlime slurry made of dry hydrated calcitic lime, freshlyslaked calcitic lime, and pressure-hydrated dolomiticlime. All three reagents remove SO2 from the flue gas but

require different feed concentrations of lime slurry for the

same percentage of SO2 removed. The most efficient

removals and easiest operation were achieved using pressure-hydrated dolomitic lime.Environmental PerformanceSorbent injection rate proved to be the most influentialfactor on SO2 capture. The rate of injection possible was

limited by the flue gas temperature. This impacted a portion of the demonstration when air leakage caused fluegas temperature to drop from 300–310 oF to 260–280 oF.At 300–310 oF, injection rates of 52–57 gal/min werepossible and SO2 reductions greater than 50% were

achieved. At 260–280 oF, injection rates had to bedropped to 30–40 gal/min, resulting in a 15–30% drop inSO2 removal efficiency. Slurry concentration for a given

sorbent did not increase SO2 removal efficiency beyond a

certain threshold concentration. For example, with pressure-hydrated dolomitic lime, slurry concentrations above9% did not increase SO2 capture efficiency.

Parametric tests indicated that SO2 removals above 50%

are possible under the following conditions: flue gas temperature of 300–310 oF; boiler load of 145–147 MWe;residence time in the duct of 2 seconds; and lime slurryinjection rate of 52–57 gal/min.

Operational PerformaThe percentage of lime utnificantly affected the tot

analysis of the continuouthe percentage of lime ution two key factors: (1) pe

(2) lime slurry feed conceFor operating conditions that for 40–50% SO2 rem

lime slurry concentration2–2.5 resulted in a 40–502–2.5 moles of CaO or Camole of SO2 removed; or 

1.9–2.4 tons of lime were 

removed. In summary, the following results:• A 50% SO2 removal ef

possible.

• Drying and SO2 absorp

of 2 seconds, which rezontal gas duct of abou

• The fully automated sy

plant operation demoncess responded well to However, modificationquired to assure consis

deposition of solids w

• Availability of the syst• At Seward Station, sta

affected by the CZD/F

Economic PerformancEstimates show that the Ccosts of $300/ton of SO2 

ing a 500-MWe unit burn500-MWe plant retrofitted 

removal, the total capital $30/kW (1994$).Commercial ApplicatiAfter the conclusion of thdemonstration project at Ssystem was modified to im
 Environmental Control Devices 

CZD/FGD lime slurry injector control system.continuous operation while following daily load cycles.Bechtel and the host utility, Pennsylvania Electric Company, continued the CZD/FGD demonstration for an additional year. Results showed that CZD/FGD operation atSO2 removal rates lower than 50% could be sustained

over long periods without significant process problems.CZD/FGD can be used for retrofitting existing plants andinstallation in new utility boiler flue gas facilities to remove SO2 from a wide variety of sulfur-containing coals.

A CZD/FGD system can be added to a utility boiler witha capital investment of about $25–50/kW of installedcapacity, or approximately one-fourth the cost of buildinga conventional wet scrubber. In addition to low capitalcost, other advantages include small space requirements,ease of retrofit, low energy requirements, fully automatedoperation, and production of only nontoxic, disposablewaste. The CZD/FGD technology is particularly wellsuited for retrofitting existing boilers, independent oftype, age, or size. The CZD/FGD installation does notrequire major power station alterations and can be easilyand economically integrated into existing power plants.

ContactsJoseph T. Newman, Project Manager,(415) 768-1189Bechtel CorporationP.O. Box 193965San Francisco, CA 94119-3965(415) 768-3535 (fax)James U. Watts, NETL, (412) 386-5991ReferencesConfined Zone Dispersion Project: FinalTechnical Report. Bechtel Corporation. June1994.Confined Zone Dispersion Project: PublicDesign Report. Bechtel Corporation. October 1993.Comprehensive Report to Congress on theClean Coal Technology Program: Confined

Zone Dispersion Flue Gas Desulfurization Demonstration. Bechtel Corporation. Report No. DOE/FE-0203P.U.S. Department of Energy. September 1990. (Availablefrom NTIS as DE91002564.)
5-30 Program Update 2001 

Environmental Control DevicesSO2 Control TechnologyLIFAC Sorbent InjectionDesulfurizationDemonstration ProjectProject completedParticipantLIFAC–North America (a joint venture partnershipbetween Tampella Power Corporation and ICF KaiserEngineers, Inc.)Additional Team MembersICF Kaiser Engineers, Inc.—cofunder and project

manager

Tampella Power Corporation—cofunderTampella, Ltd.—technology ownerRichmond Power and Light—cofunder and host utilityElectric Power Research Institute—cofunderBlack Beauty Coal Company—cofunderState of Indiana—cofunderLocationRichmond, Wayne County, IN (Richmond Power &Light’s Whitewater Valley Station, Unit No. 2)TechnologyLIFAC’s sorbent injection process with sulfur capture in aunique, patented vertical activation reactorPlant Capacity/Production60 MWeCoalBituminous, 2.0–2.8% sulfurProject FundingTotal project cost $21,393,772 100%DOE 10,636,864 50Participants 10,756,908 50

Project ObjectiveTo demonstrate that electric power plants—especiallythose with space limitations and burning high-sulfurcoals—can be retrofitted successfully with the LIFAClimestone injection process to remove 75–85% of the SO2from flue gas and produce a dry solid waste product fordisposal in a landfill.Technology/Project DescriptionPulverized limestone is pneumatically injected into theupper part of the boiler near the superheater where it absorbs some of the SO2 in the boiler flue gas. The limestone is calcined into calcium oxide and is available for

capture of additional SO2 downstream in the activation, or

humidification, reactor. In the vertical chamber, watersprays initiate a series of chemical reactions leading toSO2 capture. After leaving the chamber, the sorbent is

easily separated from the the electrostatic precipitatfrom the reactor and electlated back through the reaThe waste is dry, making scrubber sludge produced scrubber systems.The technology enables ptions to use high-sulfur minjection process that rem

flue gas and produces a dfor disposal in a landfill.
 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 

Calendar Year

Environmental Control Devices 

1988 1989 1990 1991 1992 1993 1994 1995 1996

Preaward Design and Construction Operation and Reporting

Preoperational tests initiated 7/92

Environmental monitoring plancompleted 6/12/92Construction completed 6/92

12/89 11/90 9/92

DOE selected project (CCT-III) 12/19/89

NEPA process completed (MTF) 10/2/90

Cooperative agreement awarded 11/20/90

Ground breaking/construction started 5/29/91

Original design completed 7/91

Operation initiated 9/92

Operation completed 6/94

Results SummaryEnvironmental• SO2 removal efficiency was 70% at a calcium-to-sulfur

(Ca/S) molar ratio of 2.0, approach-to-saturation temperature of 7–12 oF, and limestone fineness of 80%minus 325 mesh.

• SO2 removal efficiency was reduced an additional 15%

by increasing limestone fineness to 80% minus 200mesh and maintaining a Ca/S molar ratio of 2.0 and 7–12 oF approach-to-saturation temperature.

• The four parameters having the greatest influence on

sulfur removal efficiency were limestone fineness, Ca/S molar ratio, approach-to-saturation temperature, andESP ash recycle rate.

• ESP ash recycle rate was limited in the demonstration

system configuration. Increasing the recycle rate andsustaining a 5 oF approach-to-saturation temperaturewere projected to increase SO2 removal efficiency to

85% at a Ca/S molar ratio of 2.0 and limestone fineness of 80% minus 325 mesh.

• ESP efficiency and operating levels were essentially

unaffected by LIFAC during steady-state operation.

• Fly and bottom ash were dry and readily disposed of

at a local landfill. The quantity of additional solidwaste can be determined by assuming that approximately 4.3 tons of limestone is required to remove1.0 ton of SO2.

Operational• When operating with fine limestone (80% minus 325

mesh), the sootblowing cycle had to be reduced from6.0–4.5 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 (1994$)—$66/kW for two LIFAC

reactors (300 MWe); $76/kW for one LIFACreactor (150 MWe); $99/kW for one LIFACreactor (65 MWe).

• Operating cost (1994

assuming 75% SO2 c

limestone composed $15/ton.
5-32 Program Update 2001 

The LIFAC system successValley Station Unit No. 2 is & Light for commercial use full-scale LIFAC units in Cathe United States.

Project SummaryThe LIFAC technology was designed to enhance the effectiveness of dry sorbent injection systems for SO2 control and to maintain the desirable aspects of low capital

cost and compactness for ease of retrofit. Furthermore,limestone was used as the sorbent (about 1/3 of the costof lime) and a sorbent recycle system was incorporated toreduce operating costs.The process evaluation test plan was composed of fivedistinct phases, each having its own objectives. Thesetests were:• Baseline tests characterized the operation of the host

boiler and associated subsystems prior to LIFACoperations.

• Parametric tests were designed to evaluate the many

possible combinations of LIFAC process parametersand their effect on SO2 removal.

• Optimization tests were performed after the parametric

tests to evaluate the reliability and operability of theLIFAC process over short, continuous operating periods.

• Long-term tests were designed 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 sulfurcontent from 1.4–2.8%. However, most of the testing wasconducted with the higher (2.0–2.8%) sulfur coals.

Environmental PerformanceDuring the parametric testing phase, the numerous LIFACprocess values and their effects on sulfur removal efficiency were evaluated. The four major parameters havingthe greatest influence on sulfur removal efficiency werelimestone fineness, Ca/S molar ratio, reactor bottom temperature (approach-to-saturation), and ESP ash recyclingrate. Total SO2 capture was about 15% better when injecting fine limestone (80% minus 325 mesh) than it was

with coarse limestone (80% minus 200 mesh).While injecting the fine limestone, the sootblowing frequency had to be increased from 6-hour to 4.5-hourcycles. The coarse-quality limestone did not affect sootblowing but was found to be more abrasive on the feed and transport hoses. Parametric tests indicated that a 70% SO2 reduction was achievable with a Ca/S molar ratio of 2.0. ESP ash con- taining unspent sorbent and fly ash was recycled from the ESP hoppers back into the reactor inlet duct work. Ash recycling was found to be essential for efficient SO2 cap- ture. However, the large quantity of ash removed from the LIFAC reactor bottom and the small size of the ESP hop- pers limited the ESP ash recycling rate. As a result, the amount of material recycled from the ESP was approxi- mately 70% less than had been anticipated, but even this low recycling rate was found to affect SO2 capture. Dur- ing a brief test, it was found that increasing the recycle rate by 50% resulted in a 5% increase in SO2 removal efficiency. It was estimated that if the reactor bottom ash is recycled along with ESP ash, while sustaining a reactor temperature of 5 oF above saturation temperature, an SO2 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 SO2 reductions above 70%. Reactor bot- tom temperature was about 5 oF higher than optimum to avoid ash buildup on the steam reheaters. Atomized water droplet size was smaller than optimum for the same rea- son. Other key process parameters held constant during the long-term tests included the degree of humidification, grind size of the high-calcium-content limestone, and recycle of spent sorbent from the ESP. Long-term testing showed that SO2 reductions of 70% or more can be maintained under normal boiler operating conditions. Stack opacity was low (about 10%) and ESP efficiency was high (99.2%). The amount of boiler bot- tom ash increased slightly during testing, but there was no negative impact on the power plant’s bottom and fly ash removal system. The solid waste generated was a mixture of fly ash and calcium compounds, and was readily dis- posed of at a local landfill. The LIFAC system prove

it has few moving parts aprocess can be easily shut cess is automated by a proregulates process control shutdown, and data collecwas easily managed via twin the host utility’s contro
 Environmental Control Devices 

The top of the LIFAC reactor is shown being lifted into place.During 2,800 hours of operation, long-term testing showedthat SO2 reductions of 70% or more could be sustained under

normal boiler operation.

Economic PerformanceThe economic evaluation indicated that the capital cost ofa LIFAC installation is lower than for either a spray dryeror wet scrubber. Capital costs for LIFAC technology vary,depending on unit size and the quantity of reactorsneeded:• $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 ofLIFAC’s operating costs. LIFAC requires 4.3 tons of limestone to remove 1.0 ton of SO2, assuming 75% SO2 capture, a Ca/S molar ratio of 2.0, and limestone containing

95% CaCO3. Assuming limestone costs of $15/ton,LIFAC’s operating cost would be $65/ton of SO2

removed.Commercial ApplicationsThere are 10 full-scale LIFAC units in operation inCanada, China, Finland, Russia, and the United States.The LIFAC system at Richmond Power & Light is thefirst to be applied to a power plant using high-sulfur (2.0–2.9%) coal. The LIFAC system is being retained by Richmond Power & Light at Whitewater Valley Station, UnitNo. 2. The other LIFAC installations on power plants areusing bituminous and lignite coals having lower sulfurcontents (0.6–1.5%).ContactsDarryl Brogan, (412) 497-2144

Kaiser Engineers, Inc.Gateway View Plaza1600 West Carson St.Pittsburgh, PA 15219-1031(412) 497-2212 (fax)

James U. Watts, NETL, (412) 386-5991ReferencesLIFAC Sorbent Injection Desulfurization DemonstrationProject. Final Report, Vol. II: Project Performance andEconomics. LIFAC-North America. February 1998.(Available from NTIS as DE96004421.)“LIFAC Nearing Marketability.” Clean Coal Today. Report No. DOE/FE-0215P-21. Spring 1996.“Commercialization of the LIFAC Sorbent Injection Process in North America.” Third Annual Clean Coal Technology Conference: Technical Papers. Viiala, J., et al.

September 1994.

Comprehensive Report Technology Program: Lization Demonstration PReport No. DOE/FE-02October 1990. (Availabl
5-34 Program Update 2001 

Environmental Control DevicesSO2 Control TechnologyAdvanced Flue GasDesulfurizationDemonstration ProjectProject completedParticipantPure Air on the Lake, L.P. (a subsidiary of Pure Air,which is a general partnership between Air Products andChemicals, Inc. and Mitsubishi Heavy IndustriesAmerica, Inc.)Additional Team MembersNorthern Indiana Public Service Company—cofunder and

host

Mitsubishi Heavy Industries, Ltd.—process designerStearns-Roger Division of United Engineers and

Constructors—facility designer

Air Products and Chemicals, Inc.—constructor and

operator

LocationChesterton, Porter County, IN (Northern Indiana PublicService Company’s Bailly Generating Station, Unit Nos.7 and 8)TechnologyPure Air’s advanced flue gas desulfurization (AFGD)process and PowerChip® agglomeration process

Plant Capacity/Production528 MWeCoalBituminous, 2.0–4.5% sulfurProject FundingTotal project cost $151,707,898 100%DOE 63,913,200 42Participant 87,794,698 58

PowerChip is a registered trademark of Pure Air on the Lake, L.P.

Project ObjectiveTo reduce SO2 emissions by 95% or more at approximately one-half the cost of conventional scrubbing

technology, significantly reduce space requirements, andcreate no new waste streams.Technology/Project DescriptionPure Air built a single SO2 absorber for a 528-MWe

power plant. Although the largest capacity absorber module of its time in the United States, space requirementswere modest because no spare or backup absorber modules were required. The absorber performed three functions in a single vessel: prequenching, absorbing, andoxidation of sludge to gypsum. Additionally, the absorberwas of a co-current design, in which the flue gas andscrubbing slurry move in the same direction and at a relatively high velocity compared to that in conventional

scrubbers. These features the-art SO2 absorber that 

pensive than contemporarOther technical features iized limestone directly inan air rotary sparger locatsorber, and a novel wasteair rotary sparger combinair distribution into one pthe oxidation of calcium sPure Air also demonstratetion process, PowerChip®

dling characteristics of AF
 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 

Calendar Year

Environmental Control Devices 

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward Design and Construction Operation and Reporting

9/88

Design completed 9/92 ProjecConstruction completed 9/92

12/89 6/92

Environmental monitoring plan completed 1/31/91

6/96

DOE selected project(CCT-II) 9/28/88

NEPA process completed (EA) 4/16/90Ground breaking/construction started 4/20/90

Cooperative agreement awarded 12/20/89

Preoperational tests initiated 3/92

Operation initiated 6/92 Operation completed 6/95

Results SummaryEnvironmental• The AFGD design enabled a single 600-MWe absorber

module without spares to remove 95% or more SO2 at

availabilities of 99.5% when operating with highsulfur 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 associatedwith gypsum production and showed the potential forachieving zero wastewater discharge (only a partialcapacity WES was installed).

• PowerChip® increased the market potential for AFGDderived gypsum by cost-effectively converting it to a

product with the handling characteristics of naturalrock gypsum.

• Air toxics testing established that all acid gases were

effectively captured and neutralized by the AFGD.

Trace elements largely became constituents of thesolids streams (bottom ash, fly ash, and gypsum product). Some boron, selenium, and mercury passed to thestack gas in a vapor state.

Operational• AFGD use of co-current, high-velocity flow; integration of functions; and a unique air rotary sparger

proved to be highly efficient, reliable (to the exclusionof requiring a spare module), and compact. The compactness, combined with no need for a spare module,significantly reduced space requirements.

• The own-and-operate contractual arrangement—Pure

Air took on the turnkey, financing, operating, andmaintenance risks through performance guarantees—was successful.

Economic• Capital costs and space requirements for AFGD were

about half those of conventional systems.
5-36 Program Update 2001 

Exhibit 5-13

 Pure Air SO2 Removal Performance

(100% Boiler Load)

Project SummaryThe project proved that single absorber modules of advanced design could process largevolumes of flue gas and provide the requiredavailability and reliability without the usualspare absorber modules. The major performance objectives were met.Over the three-year demonstration, the AFGDunit accumulated 26,280 hours of operationwith an availability of 99.5%. Approximately237,000 tons of SO2 were removed, 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 gypsumto U.S. Gypsum’s East Chicago, Indiana wallboard production plant.Environmental PerformanceTesting over the three-year period clearly established thatAFGD operating within its design parameters (withoutadditives) could consistently achieve 95% SO2 reduction

or more with 2.0–4.5% sulfur coals. The design range forthe calcium-to-sulfur stoichiometric ratio was 1.01–1.07,with the upper value set by gypsum purity requirements(i.e., 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 theabsorber grid (L) to the volume of flue gas (G). The design L/G range was 50–128 gal/1,000 ft3. The lower end

of the L/G ratio was determined by solids settling rates inthe slurry and the requirement for full wetting of the gridpacking. The high end of the L/G ratio was determined bywhere performance leveled out.Four coals with differing sulfur contents were selected forparametric testing to examine SO2 removal efficiency as a

function of load, sulfur content, stoichiometric ratio, andL/G. Loads tested were 33%, 67%, and 100%. High removal efficiencies, well above 95%, were possible atloads 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 parametric testingat full load.

In the AFGD process, chlorides that would have beenreleased to the air are captured, but potentially become awastewater problem. This was mitigated by the additionof the WES, which takes a portion of the wastewaterstream with high chloride and sulfate levels and injects itinto the ductwork upstream of the ESP. The hot flue gasevaporates the water and the dissolved solids are capturedin the ESP. Problems were experienced early on, with theWES nozzles failing to provide adequate atomization, andplugging as well. This was resolved by replacing theoriginal single-fluid nozzles with dual-fluid systems employing air as the second fluid.Commercial-grade gypsum quality (95.6–99.7%) wasmaintained throughout testing, even at the lower sulfurconcentrations where the ratio of fly ash to gypsum increases due to lower sulfate availability. The primaryimportance of producing a commercial-grade gypsum isavoidance of the environmental and economic consequences of disposal. Marketability of the gypsum is dependent upon whether users are in range of economictransport and whether they can handle the gypsum byproduct. For these reasons, PowerChip® technology was

demonstrated as part of the project. This technology usesa compression mill to convert the highly cohesive AFGDgypsum cake into a flaked product with handling characteristics equiv

The process aing, or pre-cabriquetting, a$4.10/ton. Air toxics tesgases are effeby the AFGDconstituents oash, fly ash, gselenium, and in a vapor staOperationaAvailability oaveraged 99.5age SO2 remo

attributable to and an effectlosophy. Mod

high availability. An examnew alloy technology, C-2material, to replace alloy the absorber tower wet/drrent rather than conventiosulted in lower pressure dafforded the flexibility to abrupt drop in removal ef

ture efficiency with limeswet scrubbers using lime, The 24-hour power consuof expected consumption1,560 gal/min, or 52% of Economic PerformancExhibit 5-14 summarizes rent dollar cost estimates capacity and coal sulfur cand a sulfur removal efficThe calculation of levelizestablished in EPRI’s TecThe incremental benefits ment, by-product utilizatiwere also evaluated. Exhi
 Environmental Control Devices 

Exhibit 5-14

Estimated Costs for an AFGD System

(1995 Current Dollars)

Cases: 1 2 3456 78 9

Plant size (MWe) 100 100 100 300 300 300 500 500 500Coal sulfur content (%) 1.5 3.0 4.5 1.5 3.0 4.5 1.5 3.0 4.5Capital cost ($/kW) 193 210 227 111 121 131 86 94 101Levelized cost ($/ton SO2)

15-year life 1,518 840 603 720 401 294 536 302 22320-year life 1,527 846 607 716 399 294 531 300 223

Levelized cost (mills/kWh)

15-year life 16.39 18.15 19.55 7.78 8.65 9.54 5.79 6.52 7.2420-year life 16.49 18.28 19.68 7.73 8.62 9.52 5.74 6.48 7.21

Ex

Flue Gas 

Ec

500-MWe plant, 30-yr lev$300/tonIncremental cases:AóConventional FGD (EBóAFGD, own-and-operCóAdds gypsum salesDóAdds emission allowa

removal

EóIncreases SO2 remova

costs of a hypothetical 500-MWe generating unit in theMidwest burning 4.3% sulfur coal with a base case conventional FGD system and four incremental cases. Thehorizontal lines in Exhibit 2-8 show the range of costs fora fuel-switching option. The lower bar is the cost of fueldelivered to the hypothetical midwest unit, and the upperbar allows for some plant modifications to accommodatethe compliance fuel.Commercial ApplicationsThe AFGD technology is positioned well to compete inthe pollution control arena of the 21st century. The AFGD

technology has markedly reduced cost and demonstratedthe ability to compete with fuel switching under certaincircumstances even with a first-generation system. Advances in 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 partof prospective users. High SO2 capture efficiency offers

the AFGD user the possibility of generating allowances orapplying credits to other units within the utility. WES andPowerChipÆ mitigate or eliminate otherwise serious environmental concerns. AFGD effectively deals with hazardous air pollutants.

The project received Power magazineís 1993 Powerplant

Award and the National Society of Professional Engineersí 1992 Outstanding Engineering AchievementAward.ContactsTim Roth, (610) 481-6257

Pure Air on the Lake, L.P.c/o Air Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501(610) 481-7018 (fax)

James U. Watts, NETL, (412) 386-5991

ReferencesSummary of Air Toxics Emissions Testing at Sixteen Utility Power Plants. Prepared by Burns and Roe ServicesCorporation for U.S. Department of Energy, PittsburghEnergy Technology Center. July 1996.Advanced Flue Gas Desulfurization (AFGD) Demonstration Project. 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.

$/Ton SO2 
5-38 Program Update 2001 

Environmental Control DevicesSO2 Control TechnologyDemonstration of InnovativeApplications of Technologyfor the CT-121 FGD ProcessProject completedParticipantSouthern Company Services, Inc.Additional Team MembersGeorgia Power Company—hostElectric Power Research Institute—cofunderRadian Corporation—environmental and analytical

consultant

Ershigs, Inc.—fiberglass fabricatorComposite Construction and Equipment—fiberglass

sustainment consultant

Acentech—flow modeling consultantArdaman—gypsum stacking consultantUniversity of Georgia Research Foundation—

by-product utilization studies consultant

LocationNewnan, Coweta County, GA (Georgia Power Company’sPlant Yates, Unit No. 1)TechnologyChiyoda Corporation’s Chiyoda Thoroughbred-121(CT-121) advanced flue gas desulfurization (AFGD) process using the Jet Bubbling Reactor®Plant Capacity/Production100 MWeCoalIllinois No. 5 & No. 6 blend, 2.4% sulfurCompliance coal, 1.2% sulfur

Project FundingTotal project cost $43,074,996 100%DOE 21,085,211 49

Participant 21,989,785 51

Project ObjectiveTo demonstrate 90% SO2 control at high reliability with

and without simultaneous particulate control requisite toeliminating spare absorber modules; to evaluate use offiberglass-reinforced plastic (FRP) vessels to eliminateflue gas prescrubbing and reheat, and to enhance reliability; and to evaluate use of gypsum to reduce waste management costs.Technology/Project DescriptionThe project demonstrated the CT-121 AFGD process,which uses a unique absorber design known as the Jet

Bubbling Reactor® (JBR)stone AFGD reaction, forcrystallization in one procchanically and chemically AFGD processes and can cost characteristics.The flue gas enters underthe JBR. The SO2 in the f

calcium sulfite (CaSO3). A

the solution to oxidize the sum. The slurry is dewateinvolves filling a diked arsolids settle in the diked aflows to a retention pond. is returned to the process.
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• Over 90% SO2 removal efficiency was achieved at SO2

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 lb/106Btu 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 (HCl) andhydrogen fluoride (HF) gases, 80–98% capture ofmost trace metals, less than 50% capture of mercuryand cadmium, and less than 70% capture of selenium.

• 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 design

resulted in 97% availability at low ash loadings and95% at high ash loadings, eliminating the need for aspare reactor module.

• Simultaneous SO2 and particulate control were

achieved at fly ash loadings similar to those of anelectrostatic precipitator (ESP) that has marginalperformance.

Economic• Capital costs for project equipment, process, and

startup were $29 million, or $293/kW at Plant Yates.

• Fixed O&M costs were $357,000/yr (1994$), and variable operating costs were $34–64/ton of SO2 removed,

depending on specific test conditions.

• Generic plant costs w

elimination of the nereheat, and a spare mrequirements far belotional flue gas desulf

1988 1989 1990 1991 1992 1993 1994 1995 1996 

4/90

Preaward Design and Construction Operation and Reporting

9/88 10/92

DOE selected project(CCT-II) 9/28/88

Cooperative agreement awarded 4/2/90

NEPA process completed (EA)8/10/90Ground breaking/constructionstarted 8/23/90

Environmental monitoringplan completed 12/18/90

Preoperational tests initiated 5/92

Design completed 9/92

Operation initiated 10/92Construction completed 10/92

Operation completed 12/94

P
5-40 Program Update 2001 

Project SummaryThe CT-121 AFGD process differs from the more common spray tower type of flue gas desulfurization systemsin that a single process vessel is used in place of the usualspray tower/reaction tank/thickener arrangement. Pumping of reacted slurry to a gypsum transfer tank is intermittent. This allows crystal growth to proceed essentiallyuninterrupted, resulting in large, easily dewatered gypsumcrystals (conventional systems employ large centrifugalpumps to move reacted slurry causing crystal attrition andsecondary nucleation).The demonstration spanned 27 months, including startupand shakedown, during which approximately 19,000hours were logged. Exhibit 5-16 summarizes operatingstatistics. Elevated particulate loading included a shorttest with the electrostatic precipitator (ESP) completelydeenergized, but the long-term testing was conductedwith the ESP partially deenergized to simulate a morerealistic scenario, i.e., a CT-121 retrofit to a boiler with a

marginally performing particulate collection device. TheSO2 removal efficiency was measured under five different

inlet concentrations with coals averaging 2.4% sulfur andranging from 1.2– 4.3% sulfur (as burned).

Operating PerformanceUse of FRP construction proved very successful. Becausetheir large size precluded shipment, the JBR and limestone slurry storage tanks were constructed on site.Except for some erosion experienced at the JBR inlettransition duct, the FRP-fabricated equipment proved tobe durable both structurally and chemically. Because ofthe high corrosion resistance, the need for a flue gas prescrubber to remove chlorides was eliminated. Similarly,the FRP-constructed chimney proved resistant to the corrosive condensates in wet flue gas, eliminating the needfor flue gas reheat.Availability of the CT-121 scrubber during the low ashtest phase was 97%. Availability dropped to 95% underthe elevated ash loading conditions due largely to spargertube plugging problems, precipitated by fly ash agglomeration on the sparger tube walls during high ash loadingwhen the ESP was deenergized. The high reliability demonstrated verified that a spare JBR is not required in acommercial design offering.Environmental PerformanceExhibit 5-17 shows SO2 removal efficiency as a function

of pressure drop across the JBR forfive different inlet concentrations.The greater the pressure drop, thegreater the depth of slurry traversedby the flue gas. As the SO2 concentration increased, removal efficiency

decreased, but adjustments in JBRfluid level could maintain the efficiency above 90% and, at lower SO2

concentration levels, above 98%.Limestone utilization remainedabove 97% throughout the demonstration. Long-term particulatecapture performance was testedwith a partially deenergized ESP(approximately 90% efficiency),and is summarized in Exhibit 5-18.Analysis indicated that a large percentage of the outlet particulatematter is sulfate, likely a result ofacid mist and gypsum carryover.

This reduces the estimate to approximately 70% of For particulate sizes greatefficiency was consistentlmicron range, capture eff0.5 and 1 micron, the parttimes to negligible valuescarryover entraining parti0.5 micron, the capture efCalculated air toxics remobased on the measuremention, are shown in ExhibiAs to solids handling, the proved effective in the lontent was initially high in tnature of the process (witing 35,000 ppm), a year lthe gypsum dropped to lewallboard and cement appchloride content was attristack.

Exhibit 5-16

Operation of CT-121 Scrubber

Low Ash Elevated Ash CumulativePhase Phase for Project

Total test period (hr) 11,750 7,250 19,000

Scrubber available (hr) 11,430 6,310 18,340

Scrubber operating (hr) 8,600 5,210 13,810

Scrubber called upon (hr) 8,800 5,490 14,290

Reliabilitya 0.98 0.95 0.96

Availabilityb 0.97 0.95 0.97Utilizationc 0.73 0.72 0.75

a Reliability = hours scrubber operated divided by the hours called upon to operateb Availability = hours scrubber available divided by the total hours in the periodc Utilization = hours scrubber operated divided by the total hours in the period

Exh

SO2 Remo
 Environmental Control Devices 

Economic PerformanceThe capital cost of the Plant Yates CT-121 project was$29,335,979, or $293/kW, which includes equipment,process, and start-up costs. The annual fixed O&M costwas $354,000/yr. (1994$). Variable operating cost was$34–64/ton of SO2 removed (1994$), depending on specific test conditions.

FRP construction eliminates the need for prescrubbingand reheating flue gas. High system availability eliminates the need for a spare absorber module. Particulateremoval capability eliminates the need for expensive(capital-intensive) ESP upgrades to meet increasinglystrict environmental regulations.Commercial ApplicationsInvolvement of Southern Company (which owns Southern Company Services, Inc.), with more than 20,000MWe of coal-fired generating capacity, is expected toenhance confidence in the CT-121 process among otherlarge high-sulfur coal boiler users. This process will beapplicable to 370,000 MWe of new and existing generating capacity by the year 2010. A 90% reduction in SO2

emissions from only the retrofit portion of this capacityrepresents more than 10,500,000 tons/yr of potential SO2control.

Plant Yates continues tooperate with the CT-121scrubber as an integral partof the site’s CAAA compliance strategy. Since the CCTProgram demonstration, over8,200 MWe equivalent ofCT-121 AFGD capacity hasbeen sold to 16 customers inseven countries.The project received Powermagazine’s 1994 PowerplantAward. Other awards includethe Georgia Chapter of theAir and Waste ManagementAssociation’s 1994 Outstanding AchievementAward, the Georgia Chamber

of Commerce’s 1993 Air Quality Citizen of the YearAward, and the Composites Institute (Society of PlasticsIndustries) 1996 Design Award of Excellence.

Exhibit 5-19

CT-121 Air Toxics Removal

(JBR Components Only)

ContactsDavid P. Burford, Proje

Southern CompanyP.O. Box 2641 / bin Birmingham, AL 352(205) 257-7161 (fax)

James U. Watts, DOE/NReferencesSouthern Company Servvative Applications of Tthe CT-121 FGD ProcesJanuary 1997.Comprehensive Report Technology Program: Dcations of Technology foSouthern Company Serv0158. U.S. Department able from NTIS as DE9

Exhibit 5-18

CT-121 Particulate Capture Performance

(ESP Marginally Operating)

JBR Pressure Boiler Inlet Mass Outlet Mass RemovalChange (inches of Load Loading Loading* Efficiencywater column) (MWe) (lb/106 Btu) (lb/106 Btu) (%)

18 100 1.288 0.02 97.710 100 1.392 0.010 99.318 50 0.325 0.005 98.510 50 0.303 0.006 98.0

*Federal NSPS is 0.03 lb/106 Btu for units constructed after September 18, 1978. Plant Yates

permit limit is 0.24 lb/106 Btu as an existing unit.
5-42 Program Update 2001 
 Environmental Control Devices 

Environmental Control Devi

NO

x Control Technologie
5-44 Program Update 2001 

Environmental Control DevicesNO

x Control Technology

Demonstration of AdvancedCombustion Techniques for aWall-Fired BoilerProject extendedParticipantSouthern Company Services, Inc. (SCS)Additional Team MembersElectric Power Research Institute (EPRI)—cofunderFoster Wheeler Energy Corporation (Foster Wheeler)—

technology supplier

Georgia Power Company—hostPowerGen—cofunderU.K. Department of Trade and Industry—cofunderEnTEC—technology supplierRadian—technology supplierTennessee Technological University—technology supplierSouthern Company—cofunderLocationCoosa, Floyd County, GA (Georgia Power Company’sPlant Hammond, Unit No. 4)TechnologyFoster Wheeler’s low-NO

x burner (LNB) with advanced

overfire air (AOFA) and EPRI’s Generic NOx Control

Intelligent System (GNOCIS) computer software.Plant Capacity/Production500 MWeCoalEastern bituminous coals, 1.7% sulfurProject FundingTotal project cost $15,853,900 100%DOE 6,553,526 41Participant 9,300,374 59

Project ObjectiveTo achieve 50% NO

x

 reduction with the LNB/AOFA

system; to determine the contributions of AOFA and LNBto NO

x reduction and the parameters for optimal LNB/

AOFA performance; and to assess the long-term effects ofLNB, AOFA, combined LNB/AOFA, and the GNOCISadvanced digital controls on NOx reduction, boiler performance, and peripheral equipment performance. Theproject has been reopened and extended to demonstratean overall unit optimization system.Technology/Project DescriptionAOFA involves: (1) improving OFA mixing to enableoperation of the burners below the air/fuel ratiotheoretically required to complete combustion (substoichiometric), without increasing combustible losses;and (2) introducing “boundary air” at the boiler walls toprevent corrosion caused by the reducing atmosphere.

In the Foster Wheeler Con(CFSF) LNB, fuel and air the primary air/fuel mixtucreate a fuel-rich core witbustion at a severely sub-burner also controls the raessary to complete combusolids and gases so as to muntil the remaining combNO

x-producing temperatu

excess air then can be alloproducts so that combustilow temperature. The CFSmixture into four streamsmixing and combustion s
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• Using LNB alone, long-term NOx emissions were 0.65

lb/106 Btu, representing a 48% reduction from baseline

conditions (1.24 lb/106 Btu).

• Using AOFA only, long-term NOx emissions were 0.94

lb/106 Btu, representing a 24% reduction from baseline

conditions.

• Using LNB/AOFA, long-term NOx emissions were

0.40 lb/106 Btu, representing a 68% reduction from

baseline conditions.

• Chemical emissions testing showed no evidence of

organic compound emissions resulting from the combustion modifications installed for NO

x

 control. Trace

element control, except for mercury and selenium,proved to be a function of electrostatic precipitator(ESP) performance.

Operational• AOFA accounted for an incremental NO

x

 reduction

beyond the use of LNB of approximately 17%, withadditional reductions resulting from other operationalchanges.

• GNOCIS achieved a boiler efficiency gain of 0.5 percentage points, a reduction in fly ash loss-on-ignition

(LOI) levels of 1–3 percentage points, and a reductionin NO

x

 emissions of 10–15% at full load.

• Fly ash LOI increased from a baseline of 7% (corrected to representative excess oxygen conditions) to

10% with AOFA and 8% with LNB and LNB/AOFA,despite significant improvements in coal fineness.

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/kWfor LNB/AOFA, and $0.5/kW for GNOCIS.

• Estimated cost of NO

x removal is $79/ton using LNB/

AOFA in a baseload dispatch scenario experienced atPlant Hammond.

Preaward

1988 1989 1990 1991 1992 1993 1994 1996 1998 

9/88 12/89 6/90

Design and Construction

DOEselectedproject(CCT-II)9/28/88

Design completed, 3/90

Construction started, AOFA 4/90

Construction completed, AOFA 5/90

Operation initiated, AOFA 6/90

Environmental monitoring plan completed 9/14/90

Construction started, LNB;Operation completed, AOFA 3/91

Construction completed, LNB;Operation initiated, LNB 4/91

NEPA process

completed (MTF)

5/22/89

Operation completed,LNB 1/92

Operation initiated, LNB/AOFA 5/93

Operation and Reporting

Operation completed, LNB/AOFA 8/93

Operation initiated,LNB/AOFA with digital controlsystem 6/94

Final report

(Phase 1-3B)

issued 1/98

**

GNOCIS testinginitiated 2/96

Fin(Phiss

Coope

re

**

Cooperative agreement awarded, 12/20/89
5-46 Program Update 2001 

Project SummarySCS 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 March1991. Following installation of the LNBs in the secondquarter of 1991, the LNBs were tested from July 1991 toJanuary 1992, excluding a three-month delay when theplant ran at reduced capacity. Post-LNB increases in flyash LOI, along with increases in combustion air requirements and fly ash loading to the electrostatic 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 ascheduled outage and for portions of the test period dueto excessive particulate emissions. However, an ammoniaflue gas conditioning system was added to improve ESPperformance, which enabled the unit to operate at fullload, and allowed testing to continue.Operational PerformanceLOI increased for the AOFA, LNB, and LNB/AOFAphases, as shown in Exhibit 5-20, despite improved millperformance due to the replacement of the mills. Increased LOI was a concern not only because of the associated efficiency loss, but also due to a potential loss of

Exhibit 5-20

LOI Performance Test Results

Exhibit 

NOx vs. LOI Tests—

Exhibit 5-2

Typical Trade-Offs in Bo

fly ash sales. The increased carbon in the flyash renders the material unsuitable for use inmaking concrete.During October 1992, SCS conducted parametric testing to determine the relationshipbetween NOx and LOI emissions. The parameters tested were: excess oxygen, mill coal

flow bias, burner sliding tip position, burnerouter register position, and burner inner register position. Nitrogen oxide emissions andLOI levels varied from 0.44–0.57 lb/106 Btu

and 3–10%, respectively. As expected, excessoxygen levels had considerable effect on bothNOx and LOI. The results showed that there is

some flexibility in selecting the optimumoperating point and making trade-offs between NOx emissions and fly ash LOI; however, much of the variation was the result of

changes in excess oxygen. This can be more clearly seenin Exhibit 5-21 in which all sensitivities are plotted. Thisexhibit shows that, for excess oxygen, mill bias, innerregister, and sliding tip, any adjustments to reduce NOx

emissions are at the expense of increased fly ash LOI. Incontrast, the slope of the outer register adjustment suggests that improvement in both NOx emissions and LOI

can be achieved by adjustment of this damper. However,

due to the relatively small impact of the outerregister adjustment on both NOx and LOI, it is

likely the positive NOx/LOI slope is an artifact of

process noise.A subsidiary goal of theproject was to evaluate advanced instrumentation andcontrols (I&C) as applied tocombustion control. The needfor more sophisticated I&Cequipment is illustrated inExhibit 5-22. There are tradeoffs in boiler operation, e.g.,as excess air increases, NOx

increases, LOI decreases, andboiler losses increase. Thegoal is to find and maintain

an optimal operating condincluded GNOCIS and caThe GNOCIS software apto identify the best set poimplemented automatical(closed-loop), or conveyeimplementation (open-looGNOCIS are shown in Extem provided advice that 

10–15% at full load, whilreducing fly ash LOI by 1
 Environmental Control Devices 

Environmental PerformanceLong-term testing showed that the AOFA, LNBs, andLNB/AOFA provide full-load NOx reductions of 24, 48,

and 68%, respectively. Although the long-term LNB/AOFA NOx level represents a 68% reduction from baseline levels, a substantial portion of the incremental change

in NOx emissions between the LNB and the LNB/AOFA

configurations is the result of operational changes and isnot the result of adding AOFA.During the LNB/AOFA test phase a total of 63 days ofvalid long-term NOx emissions data was collected. Based

on this data set, the full-load, long-term NOx emissions

were 0.40 lb/106 Btu, which was consistent with earlier

short-term test data. Earlier long-term testing had resultedin NOx emissions of 0.94 lb/106 Btu for AOFA only and

0.65 lb/106 Btu for LNB only.

Chemical emissions testing showed no evidence of organic compound emissions resulting from the combustionmodifications installed for NOx control. Trace element

control, except for mercury and selenium, proved to be afunction of electrostatic precipitator (ESP) performance.Only a small portion of the mercury and selenium, whichadopt a vapor phase, and none of the vapor-phase chlorine (as hydrochloric acid) and fluorine (as hydrofluoricacid) were captured.

Exhibit 5-23

Major Elements of GNOCIS

Economic PerformanceEstimated capital costs for a commercial 500-MWe wallfired 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 NOx reductions depend on the

assumed load profile. Based on the actual load profileobserved in the testing, the estimated annual O&M costincrease for LNB/AOFA is $333,351. Efficiency is decreased by 1.3 percent, and the NOx reduction is 68 percent of baseline, or 11,615 tons/year at full load. The

capital cost is $8,300,000 and the calculated cost of NOx

removed is $79/ton for the Hammond baseload dispatchscenario.The addition of GNOCIS to the LNB/AOFA, using theactual load profile observed in the testing, results in arange of costs depending on whether the unit is operatedto maximize NOx removal efficiency, or LOI. For the

maximum NOx removal case, the efficiency is improved

by 0.6 percent, the annual O&M cost is decreased by$228,058, the incremental NOx reduction is 11 percent

(696 tons/year), and the capital cost is $250,000. Thecalculated cost per ton of NOx removed is -$299 (net gain

due to increased efficiency).Project ExtensionOn September 15, 1999, the cooperative agreement wasextended and work began on the design and installationof an overall unit optimization system. The work will becarried out as part of Phase 4 of the project. The overallgoal of Phase 4 is to demonstrate on-line optimizationtechniques, including use of a real-time heat rate monitor,for power plant processes and for the unit as a whole. Themajor tasks include unit optimization, boiler optimization,automated sootblowing, and precipitator modeling/optimization. To date, the designs and testing of the optimization packages are complete. The total plant optimizationstudy will be completed after an April 2002 plant outage.Commercial ApplicationsThe technology is applicable to the 411 existing pre-NSPSdry-bottom wall-fired boilers in the United States, whichburn a variety of coals. The GNOCIS technology is applicable to all fossil fuel-fired boilers, including units firedwith natural gas and units cofiring coal and natural gas.

The host has retained thuse. Foster Wheeler has NOx burner technology 

tional)—1,800 burners fContactsJohn N. Sorge, Research 

Southern Company SMail stop 14N-8195P.O. Box 2641Birmingham, AL 352(205) 257-5367 (fax)jnsorge@southernco

James R. Longanbach, NReferences500-MW Demonstration bustion Techniques for t(NOx) Emissions from C

Digital Control System pany Services, Inc. Sept500-MW Demonstration bustion Techniques for t(NOx) Emissions from CFinal Report. Southern 1998.
5-48 Program Update 2001 

Environmental Control DevicesNO

x Control Technology

Demonstration of CoalReburning for Cyclone BoilerNO

x

 Control

Project completedParticipantThe Babcock & Wilcox CompanyAdditional Team MembersWisconsin Power and Light Company—cofunder and

host

Sargent and Lundy—engineer for coal handlingElectric Power Research Institute—cofunderState of Illinois, Department of Energy and Natural

Resources—cofunder

Utility companies (14 cyclone boiler operators)—

cofunders

LocationCassville, Grant County, WI (Wisconsin Power and LightCompany’s Nelson Dewey Station, Unit No. 2)TechnologyThe Babcock & Wilcox Company’s Coal Reburning System (Coal Reburning)Plant Capacity/Production100 MWeCoalIllinois Basin bituminous (Lamar), 1.15% sulfur, 1.24%nitrogenPowder River Basin (PRB) subbituminous, 0.27% sulfur,0.55% nitrogenProject FundingTotal project cost $13,646,609 100%DOE 6,340,788 46Participant 7,305,821 54

Project ObjectiveTo demonstrate the technical and economic feasibility ofCoal Reburning to achieve greater than 50% reduction inNO

x emissions with no serious impact on cyclone combustor operation, boiler performance, or other emission

streams.Technology/Project DescriptionBabcock & Wilcox Coal Reburning reduces NOx in the

furnace through the use of multiple combustion zones.The main combustion zone uses 70–80% of the total heatequivalent fuel input to the boiler, and slightly less thannormal combustion air input. The balance of the coal (20–30%), along with significantly less than the theoreticallydetermined requirement of air, is fed to the reburningzone above the cyclones to create an oxygen-deficientcondition. The NO

x formed in the cyclone burners reacts

with the resultant reducinnitrogen in this zone. Comcess occurs in the third zowhere the balance of the c
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• Coal Reburning achieved greater than 50% NOx reduction at full load with Lamar bituminous and PRB subbituminous coals.

• Reburning-zone stoichiometry had the greatest effect

on NO

x

 control.

• Gas recirculation was vital to maintaining reburningzone stoichiometry while providing necessary burner

cooling, flame penetration, and mixing.

• Opacity levels and electrostatic precipitator (ESP)

performance were not affected by Coal Reburningwith either coal tested.

• Optimal Coal Reburning heat input was 29–30% at

full load and 33–35% at half to moderate loads.

Operational• No major boiler performance problems were experienced with Coal Reburning 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 carbonlosses (UBCL).

• UBCL was the only major contributor to boiler efficiency loss, which was 0.1, 0.25, and 1.5 percentage

points at loads of 110, 82, and 60 MWe, respectively,when using Lamar coal. With PRB coal, the efficiencyloss ranged from zero at full load to 0.3 percentagepoints at 60-MWe.

• Superior flame stability was realized with PRB coal,

contributing to better NOx control than with Lamar

coal.

• Expanded volumetric fuel delivery with reburning

burners enabled switching to PRB low-rank coal without boiler derating.

Economic• Capital costs for 110- and 605-MWe plants were

$66/kW and $43/kW, respectively (1990$).

• Levelized 10- and 30

110-MWe plant were tively (constant 1990

• Levelized 10- and 30

605-MWe plant were tively (constant 1990

Operationinitiated 12/91

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Design and Construction

9/88

Preaward

DOE selected project(CCT-II) 9/28/88

4/90 12/91

Operation and Reporting

3/94

Project completed/final report issued 3/94

Operationcompleted 12/92

Environmental monitoring plan completed 11/18/91Construction completed 11/91Preoperational tests initiated 11/91

NEPA process completed (EA) 2/12/91

Design completed 6/91

Ground breaking/construction started 11/90

Cooperative agreement

awarded 4/2/90
5-50 Program Update 2001 

Wisconsin Power and Light hosted the successful demo

Boiler Load

110 MWe 82 MWe 60 MWe

Lamar coalNOx (lb/106 Btu/% reduction) 0.39/52 0.36/50 0.44/36

Boiler efficiency losses due to 0.1 0.25 1.5unburned carbon (%)Powder River Basin coalNOx (lb/106 Btu/% reduction) 0.34/55 0.31/52 0.30/53Boiler efficiency losses due 0.0 0.2 0.3to unburned carbon (%)

Exhibit 5-24

Coal Reburning Test Results

Project SummaryAlthough cyclone boilers represent only 8.5% of the preNSPS coal-fired generating capacity, they contribute 12%of the NOx formed by pre-NSPS coal-fired units. This is

due to the cyclone combustorís inherent turbulent, hightemperature combustion process. However, at the time ofthis demonstration, there was no cost-effective combustion modification available for cyclone boiler NOx control.

Babcock & Wilcox Coal Reburning offers an economicand operationally sound response to the environmentalrequirements. This technology avoids cyclone combustormodification and associated performance complications,and provides an alternative to postcombustion NOx control options, such as SCR, which have relatively high

capital and/or operating costs.The majority of the testing was performed firing IllinoisBasin bituminous coal (Lamar), because it is typical ofthe coal used by many utilities operating cyclones. Subbituminous PRB coal tests were performed to evaluate theeffect of coal switching on reburning operation. Wisconsin Power and Lightís strategy to meet Wisconsinís sulfuremission limitations as of January 1, 1993, was to firelow-sulfur coal.

Environmental PerformanceThree sequential tests of Coal Reburning used Lamarcoal. Parametric optimization testing set up the automaticcontrols. Performance testing evaluated the unit in fullautomatic control at set load points. Long-term testingassessed performance in a load-following mode. PRBcoal was used for parametric optimization and performance modes. Exhibit 5-24 shows changes in NOx emissions and boiler efficiency using the reburning system for

various load conditions and coal types.Coal Reburning tests on both the Lamar and PRB coalsindicated that variation of reburning-zone stoichiometrywas the most critical factor in changing NOx emissions

levels. The reburning-zone stoichiometry can be varied byalternating the air flow quantities (oxygen availability) tothe reburning burners, the percent reburning heat input, thegas recirculation flow rate, or the cyclone stoichiometry.Hazardous air pollutant (HAP) testing was performedusing Lamar test coal. HAP emissions were generally wellwithin expected levels, and emissions with Coal Reburning were comparable to baseline operation. No majoreffect of reburning on trace-metals partitioning was discernible. None of the 16 targeted polynuclear aromaticsemi-volatile organics (controlled under Title III of

CAAA) were present in detectable concentrations, at a detection limit of 1.2parts per billion.Operational PerformanceFor Lamar coal, the full-, medium-, andlow-load efficiency losses due to unburned carbon were higher than thebaseline by 0.1, 0.25, and 1.5 percentage points, respectively. Full-, medium-,and low-load efficiency losses withPRB coal were 0.0, 0.2, and 0.3 percentage points, respectively. Coal Reburning burner flame stability improvedwith PRB coal.During Coal Reburning operation withLamar coal, the operators continuallymonitored boiler internals for increasedash deposition and the on-line performance monitoring system 

time throughout the systeoperation period were any observed. In fact, during boiler inspections revealeactually improved. Extensurements were taken of tservable decrease in wall Another significant findinminimizes and possibly enormally associated with in a cyclone unit. This deBtu fuel in a cyclone comfeed capacity. Coal Reburthe coal feed out of the cybringing the cyclone feed while maintaining full-loaEconomic PerformancAn economic analysis of enue requirements was coPower Research Institute of 110- and 605-MWe placosts per ton of NOx remo

and 605-MWe plants over sults of these analyses are values assumed typical re
 Environmental Control Devices 

The coal pulverizer is part of Babcock & Wilcox CoalReburning. This system has been retained by WisconsinPower and Light for NOx emission control at the NelsonDewey Station.

Ex

Coal Rebu

(1990 Co

Costs Total capital cost ($/kWLevelized busbar powercost (mills/kWh)

10-year life 30-year life 

Annualized cost ($/ton of NOx removed

10-year life 

30-year life 

take into account any fuel savings from use of low-rankcoal. The pulverizers and associated coal handling weretaken into account. Site-specific parameters that can significantly impact these retrofit costs included the state ofthe existing control system, availability of flue gas recirculation, space for coal pulverizers, space for reburningburners and overfire air ports within the boiler, scope ofcoal-handling modification, sootblowing capacity, ESPcapacity, steam temperature control capacity, and boilercirculation considerations.

Commercial ApplicationsCoal Reburning is a retrofit technology applicable to awide range of utility and industrial cyclone boilers. Thecurrent U.S. coal reburning market is estimated to beapproximately 27,000 MWe and consists of about 89units ranging from 100ñ1,150 MWe with most in the100- to 300-MWe range.The project technology has been retained by WisconsinPower and Light for commercial use.ContactsDot K. Johnson, (330) 829-7395

McDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601dot.k.johnson@mcdermott.com(330) 821-7801 (fax)

John C. McDowell, NETL, (412) 386-6175ReferencesDemonstration of Coal Reburning for Cyclone BoilerNO

x Control: Final Project Report. Report No. DOE/PC/

89659-T16. The Babcock & Wilcox Company. February1994. (Available from NTIS as DE94013052, Appendix 1as DE94013053, Appendix 2 as DE94013054.)Public Design Report: Coal Reburning for CycloneBoiler NO

x

 Control. The Babcock & Wilcox Company.

August 1991. (Available from NTIS as DE92012554.)Comprehensive Report to Congress on the Clean CoalProgram: Demonstration of Coal Reburning for CycloneBoiler NO

x

 Control. Report No. DOE/FE-0157. U.S. Department of Energy. February 1990. (Available from NTIS

as DE90008111.)
5-52 Program Update 2001 

Environmental Control DevicesNO

x Control Technology

Full-Scale Demonstration ofLow-NO

x

 Cell Burner Retrofit

Project completedParticipantThe Babcock & Wilcox CompanyAdditional Team MembersThe Dayton Power and Light Company—cofunder and

host

Electric Power Research Institute—cofunderOhio Coal Development Office—cofunderTennessee Valley Authority—cofunderNew England Power Company—cofunderDuke Power Company—cofunderAllegheny Power System—cofunderCenterior Energy Corporation—cofunderLocationAberdeen, Adams County, OH (Dayton Power and LightCompany’s J.M. Stuart Plant, Unit No. 4)TechnologyThe Babcock & Wilcox Company’s low-NOx cell-burner

(LNCB®) system

Plant Capacity/Production605 MWeCoalBituminous, medium sulfurProject FundingTotal project cost $11,233,392 100%DOE 5,442,800 48Participant 5,790,592 52

Project ObjectiveTo demonstrate, through the first commercial-scale fullburner retrofit, the cost-effective reduction of NOx from

a large, baseload coal-fired utility boiler with LNCB®

technology and to achieve at least a 50% NOx reduction

without degradation of boiler performance at less costthan that of conventional low-NO

x

 burners.

Technology/Project DescriptionThe LNCB® technology replaces the upper coal nozzle of

the standard two-nozzle cell burner with a secondary airport. The lower burner coal nozzle is enlarged to the samefuel input capacity as the two standard coal nozzles. TheLNCB® operates on the principle of staged combustion to

reduce NO

x emissions. Combustion is staged by providing only about 58% of the air theoretically required for

complete combustion through the lower burner and the

balance of the air through 

port).The demonstration was coWilcox-designed, supercrequipped with an electrosunit, which is typical of ctwo-nozzle cell burners aconfiguration. Twelve bursix burners each) were mwalls of the boiler. All 24 moved and 24 new LNCB

LNCBs® on the bottom ro

port then being on the botbustion in the lower furna
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• Short-term optimization testing (all mills in service)

showed NO

x 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 NOx reduction of 58% (over 8

months).

• Long-term testing at full load (one mill out of service)

showed an average NOx reduction of 60% (over 8months).

• Carbon monoxide (CO) emissions averaged 28–55

ppm at full load with LNCB® in service.

• Fly ash increased, but ESP performance remained

virtually unchanged.

Operational• Unit efficiency remained essentially unchanged.• Unburned carbon losses (UBCL) increased by approximately 28% for all tests, but boiler efficiency loss was

offset by a decrease in dry gas loss due to a lowerboiler 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 in the Midwest, with

a 1.2 lb/106 Btu initial NO

x

 emission rate and 65%

capacity factor, was $9/kW (1994$).

• Levelized cost (15-year) for the same 600-MWe plant

was estimated at 0.284 mills/kWh and $96.48/ton ofNO

x removed (constant 1994$).

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operationinitiated 12/91

10/90

Operation and Reporting

Design and

Preaward Construction

12/91

NEPA process completed (MTF) 8/10/90

DOE selected project

(CCT-III) 12/19/89

Project complet

12/95

Operation completed 4/93

12/89

Construction completed 11/91Preoperational tests initiated 11/91

Cooperative agreement

awarded 10/11/90

Design completed 10/90

Environmental monitoring plancompleted 8/9/91

Ground breaking/construction started 9/91
5-54 Program Update 2001 

Project SummaryUtility boilers equipped with cell burners currently represent 7.4% or approximately 24,000 MWe of pre-NSPScoal-fired generating capacity. Cell burners are designedfor rapid mixing of fuel and air. The tight burner spacingand rapid mixing minimize flame size while maximizingthe heat release rate and unit efficiency. Combustion efficiency is good, but the rapid heat release produces relatively large quantities of NOx

.

To reduce NOx emissions, the LNCB® has been designed

to stage mixing of fuel and combustion air. A key designcriterion was accomplishing delayed fuel-air mixing withno modifications to boiler walls. The plug-in LNCB®

design reduces material costs and outage time required tocomplete the retrofit, compared to installing conventional,internally staged low-NOx burners, thereby providing a

lower cost alternative to address NOx reduction requirements for cell burners.

Environmental PerformanceThe initial LNCB® configuration resulted in excessive CO

and H2S emissions. Through modeling, a revised configuration was developed (inverting alternate burners on the

lower rows), which addressed the problem without compromising boiler performance. The modification served tovalidate model capabilities.Following parametric testing to establish optimal operating modes, a series of optimization tests were conductedon the LNCB® to assess environmental and operational

performance. Two sets of measurements were taken, oneby Babcock & Wilcox and the other by an independentcompany, to validate data accuracy. Consequently, thedata provided is a range reflecting the two measurements.The average NOx 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 NOx

reduction ranged from 53.3–54.5%. Average NOx reduction at intermediate load (about 460 MWe) ranged from

52.5–54.7%. At low loads (about 350 MWe), averageNOx reduction ranged from 46.9–47.9%. NOx emissions

were monitored over the long term at full load with allmills in service and one mill out of service. Each testspanned an 8-month period. The NOx emission reductions

Single LNCB® retrofit.

realized were 58% for all mills in service and about 60%for one mill out of service.Complications arose in assessing CO emissions relative tobaseline because baseline calibration was not sufficientlyrefined. However, accurate measurements were madewith LNCB® in service. Carbon monoxide emissions were

corrected for 3.0% O2 and measured at full, intermediate,and low loads. The range of CO emissions at full loadwith all mills in service was 28–55 ppm, and 20–38 ppmwith one mill out of service. At intermediate loads (about460 MWe), CO emissions were 28–45 ppm, and at lowloads (about 350 MWe), 5–27 ppm.Particulate emissions were minimally impacted. TheLNCB® had little effect on fly ash resistivity, largely due

to SO3 injection, and therefore ESP removal efficiency

remained very high. Baseline ESP collection efficienciesfor full load with all mills in service, full load with onemill in service, and intermediate load with one mill out ofservice were 99.50%, 99.49%, and 99.81%, respectively.For the same conditions, in the same sequence withLNCB® in operation, ESP collection efficiencies were

99.43%, 99.12%, and 99.35%, respectively.Operational PerformanceFurnace exit gas temperature, initially decreased by100 oF, but eventually rose to within 10 oF of baselineconditions. The UBCL increased by approximately 28%for all tests. The most significant increase from baselinedata occurred for a test with one mill out of service. A52% increase in UBCL resulted in an efficiency loss of0.69%.Boiler efficiency showed very little change from baseline.The average with all mills in service increased by 0.16%.The higher post-retrofit efficiency was attributed to adecrease in dry gas loss with lower economizer gas outlettemperature (and subsequent lower air heater gas outlettemperature), offsetting UBCL and CO emission losses.Also, increased coal fineness mitigated UBCL.Because sulfidation is the primary corrosion mechanismin substoichiometric combustion of sulfur-containingcoal, H2S 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 ewith LNCB® were roughl

Ash sample analyses indinot be a problem. The LN

baseline ash. Furthermorein furnace exit gas temperLNCB® indicated little ch

Startup and turndown of tversion to LNCB®.

Economic PerformancThe economic analyses wnominal unit size and typUnited States. A mediumnous coal was chosen as tNOx emission level of 1.2 

tor, and a 50% reduction was $9/kW (1994$). The 
 Environmental Control Devices 

The S-Type burner impellers used in the LNCB® design.

Cell burner AOFA connection with air control vanes open (right) laying next tocell burner housing showing primary air directional vanes and coal tube (left).

tricity was estimated at 0.284 mills/kWh, or $96.48/ton ofNO

x

 removed in constant 1994 dollars.

Commercial ApplicationsThe low cost and short outage time for retrofit make theLNCB® design the most cost-effective NOx 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

x

 burners.

Dayton Power & Light has retained the LNCB® for use in

commercial service. Seven commercial contracts havebeen awarded for 172 burners, valued at $24 million.LNCBs® have already been installed on more than 4,900

MWe of capacity.The demonstration project received R&D magazine’s1994 R&D Award.ContactsDot K. Johnson, (330) 829-7395

McDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601dot.k.johnson@mcdermott.com(330) 821-7801 (fax)

James U. Watts, NETL, (412) 386-5991ReferencesFinal Report: Full-Scale Demonstration of Low-NOx

CellTM Burner Retrofit. Report No. DOE/PC/90545-T2.The Babcock & Wilcox Company, Research and Development Division. December 1995. (Available from NTIS asDE96003766.)Full-Scale Demonstration of Low-NOx Cell Burner Retrofit: Public Design Report. Report No. DOE/PC/90545-

T4. The Babcock & Wilcox Company, Energy ServicesDivision. August 1991. (Available from NTIS asDE92009768.)Comprehensive Report to Congress on the Clean CoalTechnology Program: Full-Scale Demonstration of LowNO

x Cell Burner Retrofit. The Babcock & Wilcox Company. Report No. DOE/FE-0197P. U.S. Department of

Energy. July 1990. (Available from NTIS asDE90018026.)
5-56 Program Update 2001 

Environmental Control DevicesNO

x Control Technology

Evaluation of Gas Reburningand Low-NO

x

 Burners on a

Wall-Fired Boiler

Project completedParticipantEnergy and Environmental Research CorporationAdditional Team MembersPublic Service Company of Colorado—cofunder and hostGas Research Institute—cofunderColorado Interstate Gas Company—cofunderElectric Power Research Institute—cofunderFoster Wheeler Energy Corp.—technology supplierLocationDenver, Adams County, CO (Public Service Company ofColorado’s Cherokee Station, Unit No. 3)TechnologyEnergy and Environmental Research Corporation’s gasreburning (GR) system and Foster Wheeler EnergyCorp.’s low-NOx burners (LNB)

Plant Capacity/Production172 MWe (gross), 158 MWe (net)CoalColorado bituminous, 0.40% sulfur, 10% ashProject FundingTotal project cost $17,807,258 100%DOE 8,895,790 50Participant 8,911,468 50Project ObjectiveTo attain up to a 70% decrease in NOx emissions from an

existing wall-fired utility boiler, firing low-sulfur coalusing both gas reburning and low-NOx burners (GRLNB); and to assess the impact of GR-LNB on boiler

performance.

Technology/Project DescriptionGas reburning involves injecting natural gas (up to 25%of total heat input) above the main coal combustion zonein a boiler. This upper-level injection and partial combustion by limiting available oxygen creates a fuel-rich zone.NO

x moving upward from coal combustion in the lower

furnace is stripped of oxygen as the reburn fuel is partially combusted in the reburn zone and converted tomolecular nitrogen. Overfire air ports above the reburnzone provide for complete combustion in a relativelycooler region of the boiler. Reburning allows the low-NOx

burners to operate at excess air levels far below thatneeded for complete combustion, thus enhancing theireffectiveness. The synergistic effect of adding a reburningstage to wall-fired boilers equipped with low-NOx burners

was intended to lower NO

x emissions by up to 70%. Gas

reburning was demonstrated with and without the use ofrecirculated flue gas.

A series of parametric tesreburning system, varying and assessing the effect oness of combustion (carbothermal efficiency, and hetesting program was perfosistency of system outputoperation on the boiler eqoperating GR-LNB in a nment, and develop a databLNB applications. Both freburning tests were perfo
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• LNB alone reduced NO

x emissions from a pre-construction baseline of 0.73 lb/106 Btu to 0.46 lb/106 Btu

(at 3.5% O2), a 37% NOx reduction.

• First-generation GR, which incorporated flue gas recirculation in combination with LNB, reduced NOx emissions to an average 0.25 lb/106 Btu (at 3.25% O2), a

66% NO

x reduction at an 18% gas heat input rate.

• Second-generation GR, without flue gas recirculation

and in combination with LNB, reduced NOx emissions

to an average 0.26 lb/106 Btu, a 64% NOx reduction

with only 12.5% gas heat input.

• Both first- and second-generation GR with LNB were

capable of reducing NOx emissions by up to 70% for

short periods of time; the average was approximately65%.

• After modifying the overfire air system to enhance

penetration and turbulence (as part of second-generation GR), CO emissions were controlled to acceptablelevels at low gas heat input rates.

• SO2 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 firstand second-generation GR with LNB, but not with

LNB alone.

Economic• Capital cost for a GR-LNB retrofit of a 300-MWe

plant is $26.01/kW (1996$) plus the gas pipeline cost,if not already existing ($12.14/kW for GR only and$13.87/kW for LNB only).

• Operating costs were related to the gas/coal cost differential and the value of SO2 emission allowances because GR reduces SO2 emissions when displacing

coal.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward Operation and Reporting

12/89

Design and Construction

10/90 11/92

DOE selected project (CCT-III) 12/19/89

Environmental monitoring plan completed 7/26/90

NEPA process completed (MTF) 9/6/90

Cooperative agreement awarded 10/13/90

Ground breaking/construction started 6/91

Design completed 8/91

Construction completed;Operation initiated 11/92

Long-term operationsstarted 4/93

Operation completed 1/95

Restorationcompleted 11/95

Pro
5-58 Program Update 2001 

Project SummaryThe demonstration established that GR-LNB offers acost-effective option for deep NOx reductions on wallfired boilers. GR-LNB NOx control performance approached that of selective catalytic reduction (SCR), but

at significantly lower cost. The importance of cost-effective technology for deep NOx reductions is that it meets

the need for NOx reduction in ozone nonattainment areas

beyond what is currently projected in Title IV of theCAAA. Title I of the CAAA deals with ozone nonattainment and is currently the driving force for deep NOx 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 balanceddraft pulverized coal-fired unit. The GR system, includingan overfire air system, was designed and installed by

A worker inspects the support ring for the Foster Wheeler lowNOx burner installed in the boiler wall.

Baseline (lb/106 Btu) 

Avg NOx reduction (%)

LNB GR-LNB 

Avg gas heat input (%) 

Exh

NOx Data f

Station

Energy and Environmental Research Corporation. TheLNBs were designed and installed by Foster WheelerEnergy Corp.Parametric testing began in October 1992 and was completed in April 1993. The parametric tests examined theeffect of process variables (such as zone stoichiometricratio, percent gas heat input, percent overfire air, andload) on NOx reduction, SO2 reduction, CO emissions,

carbon-in-ash, and heat rates. The baseline performanceof the LNB was also established.Environmental PerformanceAt a constant load (150 MWe) and a constant oxygenlevel at the boiler exit, NOx emissions were reduced with

increasing gas heat input. At gas heat inputs greater than10%, NOx emissions were reduced marginally as gas heat

input increased. Natural gas also reduced SO2 emissions

in proportion to the gas heat input. At the Cherokee Station, low-sulfur (0.40%) coal is used, and typical SO2

emissions are 0.65 lb/106 Btu. With a gas heat input of

20%, SO2 emissions decreased by 20% to 0.52 lb/106 Btu.

The CO2 emissions were also reduced as a result of using

natural gas because it has a lower carbon-to-hydrogenratio than coal. At a gas heat input of 20%, the CO2 emissions were reduced by 8%.

Long-term testing was initiated in April 1993 and completed in January 1995. The objectives of the test were toobtain operating data over an extended period when theunit was in routine commercial service, determine theeffect 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 gasrecirculation had minimal effect on NOx emissions.

 A second series of tests was added to the demonstrationto evaluate a modified or second-generation system.Modifications included the following:• The flue gas recirculation system, originally designed

to provide momentum to the natural gas, was removed. (This change significantly reduced capitalcosts.)

• Natural gas injection was optimized at 10% gas heat

input compared to the initial design value of 18%.

Removal of the flue gainstallation of high-vegreater use of availablmodification reduced nating costs.)

• Overfire air ports were 

momentum, particular

Over 4,000 hours of operresults shown in Exhibit 5reduction performance of 45%, the overall objectivemet. Boiler efficiency decreburning due to increasefrom natural gas use. Furttube wear, and only small during the GR-LNB demoalone, carbon-in-ash and acceptable levels.Economic PerformancGR-LNB is a retrofit techbenefits are dependent on tors:• Gas availability at the • Gas/coal cost different• Boiler efficiency,
 Environmental Control Devices 

• SO2 removal requirements, and

• Value of SO2 emission credits.

Based on the demonstration, GR-LNB is expected toachieve at least a 64% NOx reduction with a gas heat

input of 12.5%. The capital cost estimate for a 300-MWewall-fired installation is $26.01/kW (1996$), plus gaspipeline costs, if required. This cost includes both equipment and installation costs and a 15% contingency. TheGR and LNB system capital costs can be easily separatedfrom 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 valueof the SO2 emission credits received due to absence of

sulfur in the gas. A fuel differential of $1.00/106 Btu was

used because gas costs more than coal on a heating valuebasis. Boiler efficiency was estimated to decline by0.80%; the cost of this decline was calculated using acomposite fuel cost of $1.67/106 Btu. Overfire air booster

and cooling fan auxiliary loads will be partially offset bylower loads on the pulverizers. No additional operatinglabor is required, but there is an increase in maintenancecosts. Allowances also were made for overhead, taxes,and insurance. Based on these assumptions and assumingan SO2 credit allowance of $95/ton (Feb. 1996$), the net

operating cost is $2.14 million per year and the NOx removal cost is $786/ton (constant 1996$).

Commercial ApplicationsThe technology can be used in retrofit, repowering, orgreenfield installations of wall-fired boilers. There is noknown limit to the size or scope of the application of thistechnology combination. GR-LNB is expected to be lesscapital intensive, or less costly, than selective catalyticreduction. GR-LNB functions equally well with any kindof coal.Public Service Company of Colorado, the host utility,decided to retain the low-NOx 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 hasbeen awarded two contracts to provide gas-reburning

systems for five cyclone coal-fired boilers: TVA’s AllenUnit No. 1, with options for Unit Nos. 2 and 3 (identical330-MWe units); and Baltimore Gas & Electric’s C.P.Crane, Unit No. 2, with an option for Unit No. 1 (similar200-MWe units). Use of the technology also extends tooverseas markets. One of the first installations of thetechnology took place at the Ladyzkin State Power Station in Ladyzkin, Ukraine.This demonstration project was one of two that receivedthe Air and Waste Management Association’s 1997 J.Deanne Sensenbaugh Award.ContactsBlair A. Folsom, Sr., V.P., (949) 859-8851, ext. 140

General Electric Energy and Environmental Research Corporation18 MasonIrvine CA 92618blair.folsom@ps.ge.com(949) 859-3194 (fax)

Jerry L. Hebb, NETL, (412) 386-6079ReferencesEvaluation of Gas Reburning and Low-NOx Burners on a

Wall-Fired Boiler: Performance and Economics Report,Gas Reburning—Low-NOx Burner System, Cherokee

Station Unit No. 3, Public Service Company of Colorado.

Final Report. July 1998.Guideline Manual: Gas Reburning—Low-NOx Burner

System, Cherokee Station Unit No. 3. Public ServiceCompany of Colorado. Final Report. July 1998.Evaluation of Gas Reburning and Low-NOx Burners on a

Wall-Fired Boiler (Long-Term Testing, April 1993–January 1995). Report No. DOE/PC/90547-T20. Energy andEnvironmental Research Corporation. June 1995. (Available from NTIS as DE95017755.)Evaluation of Gas Reburning and Low-NOx Burners on aWall-Fired Boiler (Optimization Testing, November1992–April 1993). Report No. DOE/PC/90547-T19. Energy and Environmental Research Corporation. June1995. (Available from NTIS as DE95017754.)
5-60 Program Update 2001 

Environmental Control DevicesNO

x Control Technology

Micronized Coal ReburningDemonstration for NO

x

ControlProject completedParticipantNew York State Electric & Gas CorporationAdditional Team MembersEastman Kodak Company—host and cofunderCONSOL (formerly Consolidation Coal Company)—coal

sample tester

D.B. Riley—technology supplierFuller Company—technology supplierEnergy and Environmental Research Corporation EER)—

reburn system designer

New York State Energy Research and Development

Authority—cofunder

Empire State Electric Energy Research Corporation—

cofunder

LocationsLansing, Tompkins County, NY (New York State Electric& Gas Corporation’s Milliken Station, Unit No. 1)Rochester, Monroe County, NY (Eastman KodakCompany’s Kodak Park Power Plant, Unit No. 15)TechnologyD.B. Riley’s MPS mill (at Milliken Station) and Fuller’sMicroMillTM (at Eastman Kodak) technologies for producing micronized coalPlant Capacity/ProductionMilliken Station: 148-MWe tangentially fired boilerKodak Park: 60-MWe cyclone boiler

CoalPittsburgh 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 FundingTotal project cost $9,096,486 100%DOE 2,701,011 30

Participant 6,395,475 70Project ObjectiveTo achieve at least 50% NO

x

 reduction with micronized

coal reburning technology on a cyclone boiler, to achieve25–35% NO

x reduction with micronized coal reburning

technology in conjunction with low-NOx burners on a

tangentially fired boiler, and to determine the effects ofcoal micronization on electrostatic precipitator (ESP)performance.

Technology/Project DThe reburn coal, which catotal fuel, is micronized (low 325 mesh) and injectfurnace above the primary liken tangentially fired bo

achieved by: (1) close-coreburning in which the toIIITM burner is used for inthe separated overfire air and (2) the remaining burfor deep-stage combustiofuel-rich inner zone and fcombustion air. At the KoFuller MicroMillTM is usecoal, reburn fuel is introdtor, and overfire air is emtion.
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• Using a 14.4% reburn fuel heat input on the Milliken

Station tangentially fired boiler at full load resulted ina NO

x

 emission rate of 0.25 lb/106 Btu, which represents a 29% NO

x

 reduction from the 0.35 lb/106 Btu

achieved with the LNCFS IIITM burner alone (baseline).

• Using a 17.3% reburn fuel heat input (reburn stoichiometry of 0.89) on the Kodak Park cyclone boiler

resulted in a NO

x

 emission rate of 0.59 lb/106 Btu,

which represents a 59% NOx reduction from 1.36 lb/

106 Btu (baseline). Higher reburn rates (estimated at

18.4% reburn or stoichiometry of 0.87) would be required for long-term compliance with 0.60 lb/106 Btu

NO

x

 emission limits.

Operational• Reburning was successfully applied at Milliken Station

using the top coal feed of the LNCFS IIITM burner forthe reburn fuel and reducing the top burner level airflows. This eliminated the need for a separate reburn

system. Testing on the tangentially fired boiler atMilliken Station showed:

– Unburned carbon-in-ash, also referred to as losson-ignition (LOI), was maintained under 5%;– Increasing the economizer O2 generated the classical response of higher NOx emissions and lower

LOI—the sensitivity was estimated at 0.1 lb/106Btu per 1% change in O2 and was relatively independent of coal fineness;

– Increasing coal fineness reduced both NOx emissions and LOI—the effect on NO

x was significant

only for large variations in coal fineness; and

– Pulverizing the reburn coal to the micronized level

(greater than 80% passing 325 mesh) was not arequirement for the successful application of reburning, but significantly impacted LOI.

• Testing on the cyclone boiler at Kodak Park showed:

– The reburn stoichiometry had a significant effect

on NO

x emissions and a significant effect on

LOI—lower reburn stoichiometries reduced NO

x

emissions and increased LOI to 40–45% comparedwith a LOI baseline of 10–15%.

– Short-term testing 

maintained at levout significantly a

taining a baseline 

Economic• The estimated capita

300-MWe tangentialcoal reburning is $4.$14/kW (1999$). Thestimated at $0.30 msulting total 15-year NO

x removed (curren

1999$).

• The estimated capita

300-MWe cyclone boing is $16.9 million, (1999$). The correspat $0.80 million per ylevelized cost is $74

1999$) or $571 (con

3/97

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

9/91 7/92

DOE selectedproject (CCT-IV)9/12/91

Design and Construction Operation and Reporting

Operation complete

Ground breaking/construction started (Lansing) 3/15/96

Design completed (Rochester) 9/96

Ground breaking/construction started (Rochester) 9/8/96

NEPA process completed(CX) 8/13/92

Cooperative agreement awarded 7/28/92

Preoperational tests initiated (Rochester) 1/97

Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

Operation initiated (Rochester) 4/97

Environmental monitoring plan completed Environmental monitoring plan completed 

Construction completed (Lansing) 1/97

Operation initiated (Lansing) 3/97

Project relocated to Lansing and Rochester 12/95

Operation 

Fin
5-62 Program Update 2001 

Project SummaryNYSEG demonstrated the micronized coal reburningtechnology in both tangentially fired and cyclone boilers.The tangentially fired boiler was NYSEG’s Milliken Station 148-MWe tangentially fired Unit No. 1 (also the hostfor another CCT Program demonstration). The cycloneboiler was Eastman Kodak Company’s Kodak Park PowerPlant 60-MWe cyclone Unit No. 15.The challenge with this coal reburning demonstration wasto achieve adequate combustion of the reburn coal in theoxygen-deficient, short-residence-time reburn zone toreduce NOx emissions without detrimentally increasing

the unburned carbon in the ash, i.e., loss-on-ignition. Theprimary objective of this two-site project was to demonstrate improvements in coal reburning for NOx emission

control by reducing the particle size of the reburn coal. Inthis demonstration, the coal was finely ground to 80% ormore passing 325 mesh and injected into the boilersabove the primary combustion zone. The resulting typicalparticle size is 20 microns compared to 60 microns fornormal 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), carbon combustion occurs in milliseconds andvolatiles are released at an even rate.Operating PerformanceAt the Milliken Station, the existing ABB Low-NOx Concentric Firing SystemTM (LNCFS-III), which includes

both close coupled and separated overfire air (SOFA)ports, was used for the reburn demonstration. Four D.B.Riley MPS 150 mills with dynamic classifiers providedthe pulverized coal. With LNCFS-III, there are four levelsof burners. To simulate and test the coal reburning application, the top-level coal injection nozzles fed micronizedcoal to the upper part of the furnace for this demonstration. The coal injection nozzles at the three lower elevations were biased to carry approximately 80% of the fuelrequired for full load. The speed of the dynamic classifierserving the mill feeding the top burners was increased toproduce the micronized coal (greater than 80% passing325 mesh).

During the evaluation, several conclusions were reachedon how operating variables affected performance. Whilemaintaining a constant economizer O2 level, no single

operating variable had a dominant effect on reburningperformance. A combination of operating settings determined from short-term testing were selected for long-termoperation to achieve the lowest NOx emissions and reliable operation. Operating settings for long-term operation

were 14–16% reburn coal, 105 rpm top mill classifierspeed (corresponds to 70–72% passing 325 mesh), –5degrees main burner tilt and 2.8% economizer O2. No

additional improvement in LOI was observed at top millclassifier speeds above 105 rpm.At Kodak Park, EER designed the micronized coal reburnsystem using a combination of analytical and empiricaltechniques. The reburn fuel and OFA injection components were designed with a high degree of flexibility toallow for field optimization to accommodate the complexfurnace flow patterns in the cyclone boiler. Two FullerMicroMillsTM were installed in parallel on Kodak ParkUnit No. 15 to provide the capacity necessary for highreburn rates, with the second mill serving as a spare atlower reburn rates. The mills produced the micronizedcoal reburn fuel at greater than 90% passing 325 mesh.Eight injectors, six on the rear wall and one on each ofthe side walls, introduced the micronized coal into thereburn zone. The optimization variables included thenumber of injectors, swirl, and velocity. Four ports on thefront wall provided OFA using EER’s second-generation,dual-concentric overfire air design, which has variableinjection velocity and swirl. To maximize NOx reduction,

the reburn fuel was injected with flue gas rather than air.The flue gas was extracted downstream of the electrostatic precipitator and was boosted by a single fan. A newboiler control system was also installed on Unit No. 15.Environmental PerformanceAt the Milliken Station, micronized coal reburning with14.4% reburn fuel at full load reduced NOx emissions

from the 0.35 lb/106 Btu baseline level to 0.25 lb/106 Btu,

a 29% reduction. This reduction represents an addition tothe 39% reduction achieved with the LNCFS IIITM lowNOx burner alone. Boiler efficiency was maintained at

88.4–88.8%. Furthermore, concentrating the overfire air

through fewer and higher reburn coal maintained Lterm testing consisting of ments, the achievable ann

coal reburn heat input we106 Btu (95% confidence)

ash LOI was 4.4 ± 0.4%. mance tests and a 95% coNOx emissions less than 0

LOI less than 1.5 percentof no statistical significanties with respect to the effLOI generally varied with(between 3% and 5%) in variables.With regard to reburn coaquantity, using a finer grinboth NOx emissions and L

significant (relative to the 106 Btu) only for relativel

classifier speed (and hencgrind coal (all mills) redu

LOI. Decreasing the rebu14% decreased NOx emis

Btu and had a minor effec1.5 percentage points). Th

creasing the coal reburn fexcess air levels in the pricoal was diverted to the loReducing the boiler load 

effect was greater when thservice. Thus, reducing thond mill out of service is the second mill out of serboiler load reduced NOx e

MW) and low (110 MW) longer residence times in Changes in air flow resultboth NOx reduction and L

coal transport air (top burto a 20% increase in the a2.45, increased NOx emis

This increase in NOx was 
 Environmental Control Devices 

reburn zones with the additional introduction of an oxidant with the reburn fuel. Increasing the top level auxiliary airflow increased both NOx emissions and LOI. This

increase in NOx was attributed to less reducing reburn

zones as more oxidant was introduced through the auxiliary air nozzle situated directly below the reburn coalnozzle. The increase in LOI from increasing the top levelauxiliary airflow was attributed to lower excess air levelsin the primary combustion zone as more air was divertedaway from the lower burners. Increasing the economizerO2 generated the classical response of higher NOx emissions and lower or stable LOI. The economizer O2 sensitivity was estimated at 0.1 lb NOx/106 Btu per 1% change

in O2 and was relatively independent of the reburn coal

fineness.The SOFA and main burner tilts had minimal effects onperformance. Variations in the SOFA tilt between 0 and15 degrees (above horizontal) had minor effects on bothNOx emissions and LOI in both LNCFS IIITM and reburn

configurations. Operating the main burner tilt slightlybelow the horizontal (about -5 degrees) improved thereburning performance (lower LOI without increasingNOx), relative to the horizontal setting, which was attributed to longer residence times in the furnace prior to overfire air introduction. Overall, the effect was difficult toquantify due to the limited number of tests.At Kodak Park, the application of micronized coal reburning reduced NOx emissions and increased LOI, as

expected. Micronized coal reburning with 17.3% reburnfuel at a reburn stoichometry of 0.89, reduced NOx emissions to 0.59 lb/106 Btu from a baseline of 1.36 lb/

106 Btu, a 59% reduction, and reduced the boiler efficiency from 87.8% to 87.3%. At greater reburn rates,

further NOx reduction was achieved to a degree comparable with gas reburning systems. At full load, LOI was

40–45%, compared with a baseline level of 10–12%.Based on long-term testing, the achievable annual NOx

emissions (at 15.6% reburn or stoichiometry of 0.90)were 0.69 ± 0.03 lb/106 Btu (95% confidence), corresponding to an LOI of 38% ± 2%. Higher reburn feeds

(estimated at 18.4% reburn or stoichiometry of 0.87)would be required for long-term compliance with the0.6 lb/106 Btu NOx emissions limit.

The reburn stoichiometry had a significant effect on NOx

emissions and a significant effect on the LOI. Lowerreburn stoichiometries reduced NOx emissions and increased the LOI, typically dropping below 0.6 lb/106 Btu

at reburn stoichiometries below 0.9 and corresponding to40–45% LOI. The increase in the LOI relative to baselinewas partially due to a lower cyclone heat input, whichresulted in lower temperatures in the primary combustionzone. The lower temperatures produced less thermal NOx

formation and less efficient char burnout. The LOI increase was also partially due to the staged combustionresulting in shorter residence times under oxidizing conditions. At constant heat input levels, the LOI was notsignificantly different with or without reburning, suggesting that in reburn applications, the LOI could be maintained at levels similar to baseline by maintaining a highcyclone heat input. The contribution of reburning alone(assuming no change in the cyclone heat input) to theincrease in the LOI was estimated at 0–12% (absolute).Economic PerformanceEstimates were prepared for retrofitting micronized coalreburning on generic 300-MWe tangentially fired andcyclone boilers. For the tangentially fired boiler, the capital costs were estimated at $4.3 million, or approximately$14/kW (1999$). The O&M costs were estimated at $0.30million per year (1999$). Costs were levelized both on acurrent dollar and constant dollar basis. The 15-year levelized cost for the 300-MWe unit is $1,329/ton of NOxremoved on a current dollar basis, and $1,023/ton of NOxremoved on a constant dollar basis (1999$).For the cyclone boiler, the estimated capital cost is $16.9million, or approximately $56/kW (1999$). The estimatedO&M costs are $0.80 million per year (1999$). The total15-year levelized cost is $741/ton of NOx removed on a

current dollar basis or $571 on a constant dollar basis(1999$).Commercial ApplicationsMicronized coal reburning technology can be applied toexisting and greenfield cyclone-fired, wall-fired, andtangentially fired pulverized coal units. The technologyreduces NOx emissions by 20–59% with minimal furnace

modifications for existing units.

The availability of a coafuel to the furnace, enabvalue coals without boilachieve a turndown of 8out consuming expensivContactsJim Harvilla, (607) 762-

New York State ElecCorporate Drive—KP.O. Box 5224Binghamton, NY 13jharvilla@nyseg.com(607) 762-8457 (fax)

James U. Watts, NETL, ReferencesMicronized Coal Reburn

Control. Final Report. N

Corporation and CONSReburning Technologies ides from Coal-Fired BoBabcock & Wilcox, EER Report No. 14. May 199Savichky et al. “Microntion of NOx Control.” S

Conference: Technical P
5-64 Program Update 2001 

Environmental Control DevicesNO

x Control Technology

Demonstration of SelectiveCatalytic ReductionTechnology for the Control ofNO

x Emissions from HighSulfur, Coal-Fired Boilers

Project completedParticipantSouthern Company Services, Inc.Additional Team MembersElectric Power Research Institute—cofunderOntario Hydro—cofunderGulf Power Company—hostLocationPensacola, Escambia County, FL (Gulf Power Company’sPlant Crist, Unit No. 4)TechnologySelective catalytic reduction (SCR)Plant Capacity/Production8.7-MWe equivalent (three 2.5-MWe and six 0.2-MWeequivalent SCR reactor plants)CoalIllinois bituminous, 2.7% sulfurProject FundingTotal project cost $23,229,729 100%DOE 9,406,673 40Participant 13,823,056 60Project ObjectiveTo evaluate the performance of commercially availableSCR catalysts when applied to operating conditions foundin U.S. pulverized coal-fired utility boilers using highsulfur U.S. coal under various operating conditions, whileachieving as much as 80% NOx removal.

Technology/Project DescriptionThe SCR technology consists of injecting ammonia intoboiler flue gas and passing it through a catalyst bed wherethe NO

x and ammonia react to form nitrogen and water

vapor.In this demonstration project, the SCR facility consistedof three 2.5-MWe equivalent SCR reactors, supplied byseparate 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 willallow the SCR process to be scaled up to commercialsize. Catalyst suppliers (two U.S., two European, and twoJapanese) provided eight catalysts with various shapesand chemical compositions for evaluation of processchemistry and economics of operation during the demonstration.

The project demonstratedof flue gas, the applicabilvide a cost-effective mean

from power plants burninThe demonstration plant, Power Company’s Plant Cused flue gas from the bu
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• NO

x

 reductions of over 80% were achieved at an ammonia slip well under the 5 ppm deemed acceptable

for commercial operation.

• Flow rates could be increased to 150% of design without exceeding the ammonia slip design level of 5 ppm

at 80% NO

x

 reduction.

• While catalyst performance increased above 700 oF,

the benefit did not outweigh the heat rate penalties.

• Increases in ammonia slip, a sign of catalyst deactivation, went from less than 1 ppm to approximately 3

ppm over the nearly 12,000 hours of operation, thusdemonstrating deactivation in coal-fired units was inline with worldwide experience.

• Long-term testing showed that SO2 oxidation was

within or below the design limits necessary to protectdownstream equipment.

Operational• Fouling of catalysts was controlled by adequate sootblowing procedures.

• Long-term testing showed that catalyst erosion was not

a problem.

• Air preheater performance was degraded because of

ammonia slip and subsequent by-product formation;however, solutions were identified.

• The SCR process did not significantly affect the results

of Toxicity Characteristic Leaching Procedure (TCLP)analysis of the fly ash.

Economic• Levelized costs on a 30-year basis for a 250-MWe unit

at a 0.35 lb/106 Btu NO

x emission rate were 2.39, 2.57,

and 2.79 mills/kWh (Constant 1996$) for 40, 60, and80 percent removal efficiency, respectively, whichequates to 3,502; 2,500; and 2,036 $/ton (constant1996$), respectively.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward

9/88

Design and Construction Operation and Reporting

6/90

DOE selected project(CCT-II) 9/28/88

NEPA processcompleted(MTF) 8/16/89

Cooperative agreementawarded 6/14/90

Ground breaking/construction started 3/92

7/93

Preoperational tests initiated 3/93Environmental monitoring plan completed 3/11/93

Construction completed 2/93

Design completed 12/92

Operation initiated 7/93

Operation completed 7/
5-66 Program Update 2001 

Project SummaryThe demonstration tests were designed to address severaluncertainties, including potential catalyst deactivation dueto poisoning by trace metals species in U.S. coals, performance of the technology and its effects on the balance-ofplant equipment in the presence of high amounts of SO2and SO3, and performance of the SCR catalyst under

typical U.S. high-sulfur coal-fired utility operating conditions. Catalyst suppliers were required to design thecatalyst baskets to match predetermined reactor dimensions, provide a maximum of four catalyst layers, andmeet the conditions shown in Exhibit 5-27.The catalysts tested are listed in Exhibit 5-28. Catalystsuppliers were given great latitude in providing theamount of catalyst for this demonstration.Environmental ResultsAmmonia slip, the controlling factor in the long-termoperation of commercial SCR, was usually #5 ppm because of plant and operational considerations. Ammoniaslip was dependent on catalyst exposure time, flow rate,temperature, NH3/NOx distribution, and NH3/NOx ratio

(NOx reduction). Changes in NH3/NOx ratio and consequently NOx reduction generally produced the most significant changes in ammonia slip. The ammonia slip at

60% NOx reduction was at or near the detection limit of

1 ppm. As NOx reduction was increased above 80%, amParameter Minimum Baseline Maximum Temperature (oF) 620 700 750 NH3/NOx molar ratio 0.6 0.8 1.0 Space velocity (1% design flow) 60 100 150 Flow rate Large reactor (scfm) 3,000 5,000 7,500 Small reactor (scfm) 240 400 600

Exhibit 5-27

Reactor Baseline Conditions

Exhibit 5-28

Catalysts Tested

Catalyst Reactor Size* Catalyst

Configuration

Nippon/Shokubai Large HoneycombSiemens AG Large PlateW.R. Grace/Noxeram Large HoneycombW.R. Grace/Synox Small HoneycombHaldor Topsoe Small PlateHitachi/Zosen Small PlateCormetech/High dust Small HoneycombCormetech/Low dust Small Honeycomb* Large = 2.5 MWe; 5,000 scfm Small = 0.2 MWe; 400 scfm

Exh

Average SO

(Ba

monia slip also increased and remained at reasonablelevels up to NOx reductions of 90%. Over 90%, the ammonia slip levels increased dramatically.

The flow rate and temperature effects on NOx reduction

were also measured. In general, flows could be increasedto 150% of design without the ammonia slip exceeding 5ppm, at 80% NOx reduction and at the design temperature. With respect to temperature, most catalysts exhibited

fairly significant improvements in overall performance astemperatures 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 ofhightemperature operation probably do not outweigh the heatrate penalties involved in operating SCR at the highertemperatures.Catalyst deactivation was observed by an increase in ammonia slip over time, assuming the NOx reduction efficiency was held constant. Over the 12,000 hours of the

demonstration tests, the ammonia slip did increase fromless than 1 ppm to approximately 3 ppm. These resultsdemonstrated the maturity of catalyst design and thatdeactivation was in line with prior worldwide experience.Experience has shown that the catalytic active species thatresult in NOx reduction often contributed to SO2 oxidation

(i.e., SO3 formation), whi

stream equipment. In gen

creased as the tolerance fo

upper bound for SO2 oxid

catalyst was set at 0.75% age SO2 oxidation rate for 

in Exhibit 5-29. These daover the life of the demonwere within design limitsrates below the design limOther factors affecting SO

temperature. Most of the stant SO2 oxidation with r

velocity). In theory, SO2 o

proportional to flow rate. between SO2 oxidation an

nential as temperature incshowed the relationship to in SO2 oxidation between 

hand, between 700 °F and 

creased more significantlyOther findings from the ddrop, fouling, erosion, air nia volatilization, and TC
 Environmental Control Devices 

Exhibit 5-32

SCR Economics by NOx Removal

40% 60% 80%

Capital cost ($/kW) 52 54 57Operating costs ($/yr) 926,000 1,045,000 1,181,000Constant 1996$ levelized costmills/kWh 2.39 2.57 2.79$/ton NOx removed 3,502 2,500 2,036Note: 250MWe; 0.35 lb/106 Btu of inlet NOx

Exhibit 5-30

SCR Design Criteria

Parameter SpecificationType of SCR Hot sideNumber of reactors OneReactor configuration 3 catalyst support layersInitial catalyst load 2 of 3 layers loadedRange of operation 35–100% boiler loadNOx inlet concentration 0.35 lb/106 Btu

Design NOx reduction 60%

Design ammonia slip 5 ppmCatalyst life 16,000 hrAmmonia cost $250/tonSCR cost $400/ft3

125 MWe 250 MWe 700 MWe

Capital cost ($/kW) 61 54 45Operating cost ($/yr) 580,000 1,045,000 2,667,000Constant 1996$ levelized costMills/kWh 2.89 2.57 2.22$/ton NOx removed 2,811 2,500 2,165Note: 30 year life; 60% NOx removal

Exhibit 5-31

SCR Economics by Unit Size

pressure drop was a function of the catalyst geometry andvolume, but tests were inconclusive in determining whichparameter was controlling. The fouling characteristics ofthe catalyst were important to long-term operation. During the demonstration, measurements showed a relativelylevel pressure drop over time, indicating that sootblowingprocedures were effective. The plate-type configurationhad somewhat less fouling potential than did the honeycomb configuration, but both were acceptable. Catalysterosion was not considered to be a significant problembecause most of the erosion was attributed to aggressivesootblowing. With regard to air preheater performance,the demonstration showed that the SCR process exacerbated performance degradation of the air preheatersmainly due to ammonia slip and subsequent by-productformation. Regenerator-type air heaters outperformedrecuperators in SCR applications in terms of both thermalperformance and fouling. The ammonia volatilized fromthe SCR fly ash when a significant amount of water wasabsorbed by the ash. This was caused by formation of amoist layer on the ash with a pH high enough to convertammonia compounds in the ash to gas-phase ammonia.TCLP analyses were performed on fly ash samples. TheSCR process did not significantly affect the toxics leachability of the fly ash.

Economic ResultsAn economic evaluation was performed for full-scaleapplications of SCR technology to a new 250-MWepulverized coal-fired plant located in a rural area withminimal space limitations. The fuel considered was highsulfur Illinois No. 6 coal. Other key base case designcriteria are shown in Exhibit 5-30.The economic analysis of capital, operating and maintenance (O&M), and levelized cost for various unit sizesfor an SCR system are shown in Exhibit 5-31. Results ofthe economic analysis of capital, O&M, and levelizedcost for various NOx removal efficiencies for a 250-MWe

unit are shown in Exhibit 5-32. For retrofit applications,the estimated capital costs were $59–112/kW, depending

on the size of the insscope of the retrofit. applications were $1Commercial AppliAs a result of this debeen shown to be appgenerating capacity f

gas of virtually any s1,000 coal-fired utilitservice in the United a total generating cap300,000 MWe.ContactsLarry Monroe, (205) 

Southern CompanMail Stop 14N-81P.O. Box 2641Birmingham, AL lsmonroe@southe(205) 257-5367 (f

James U. Watts, NETReferencesMaxwell, J. D., et al. 

ogy for the Control o

Coal-Fired Utility BoTechnology Conferen1997.Demonstration of SCNOx Emissions from 

Boilers: Final Reporvices, Inc. October 1as DE97050873, VolDE97050874, and VoDE97050875.)
5-68 Program Update 2001 

Environmental Control DevicesNO

x Control Technology

180-MWe Demonstration ofAdvanced Tangentially FiredCombustion Techniques forthe Reduction of NO

x

Emissions from Coal-FiredBoilersProject completedParticipantSouthern Company Services, Inc.Additional Team MembersGulf Power Company—cofunder and hostElectric Power Research Institute—cofunderABB Combustion Engineering, Inc.—cofunder and

technology supplier

LocationLynn Haven, Bay County, FL (Gulf Power Company’sPlant Lansing Smith, Unit No. 2)TechnologyABB Combustion Engineering’s Low-NOx Concentric

Firing System (LNCFSTM) with advanced overfire air(AOFA), clustered coal nozzles, and offset airPlant Capacity/Production180 MWeCoalEastern bituminous, high reactivityProject FundingTotal project cost $8,553,665 100%DOE 4,149,382 49Participant 4,404,283 51

Project ObjectiveTo demonstrate in a stepwise fashion the short- and longterm NO

x reduction capabilities of LNCFSTM levels I, II,

and III on a single reference boiler.Technology/Project DescriptionTechnologies demonstrated included LNCFSTM levels I,II, and III. Each level of the LNCFSTM used differentcombinations of overfire air and clustered coal nozzlepositioning to achieve NOx reductions. With the

LNCFSTM, primary air and coal are surrounded by oxygen-rich secondary air that blankets the outer regions ofthe combustion zone. LNCFSTM I used a close-coupledoverfire air (CCOFA) system integrated directly into thewindbox of the boiler. A separated overfire air (SOFA)system located above the combustion zone was featuredin the LNCFSTM II system. This was an advanced overfire

air system that incorporatmeasurement capabilitiesused in the LNCFSTM III Carefully controlled shortlowed by long-term testinconditions. Long-term tesmonths for each phase, becharacteristics of each tecbased on long-term test d

LNCFS is a trademark of ABB Combustion Engineering, Inc.
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• At full load, the NOx emissions using LNCFSTM I, II,

and III were 0.39, 0.39, and 0.34 lb/106 Btu, respectively, which represent reductions of 37, 37, and 45%

from the baseline emissions.

• Emissions with LNCFSTM were not sensitive to power

outputs between 100 MWe and 200 MWe, but emissions increased significantly below 100 MWe, reaching baseline emission levels at 70 MWe.

• Because of reduced effectiveness at low loads,

LNCFSTM proved marginal as a compliance option forpeaking load conditions.

• Average CO emissions increased at full load.• Air toxics testing found LNCFSTM to have no clear-cut

effect on the emissions of trace metals or acid gases.Volatile organic compounds (VOCs) appeared to bereduced and semi-volatile compounds increased.

Operational• Loss-on-ignition (LOI) was not sensitive to the

LNCFSTM retrofits, but very sensitive to coal fineness.

• Furnace slagging was reduced, but backpass fouling

was increased for LNCFSTM II and III.

• Boiler efficiency and unit heat rate were impacted

minimally.

• Unit operation was not significantly affected, but operating flexibility of the unit was reduced at low loads

with LNCFSTM II and III.

Economic• The capital cost estimate for LNCFSTM I was

$5–15/kW, and for LNCFSTM II and III, $15–25/kW(1993$).

• The cost-effectiveness for LNCFSTM I was $103/ton of

NO

x removed; LNCFSTM II, $444/ton; and LNCFSTM

III, $400/ton (1993$).

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward Operation and Reporting

9/88 9/90

Design and Construction

Project completed/final report issued 6/94

6/94

Environmental monitoringplan completed 12/27/90

Ground breaking/construction started 11/90

Design completed 4/91

Constructioncompleted 5/91Operation initiated 5/91 Operation completed 12/92

NEPA processcompleted (MTF)7/21/89

DOE selectedproject(CCT-II)9/28/88

Cooperative agreement awarded 9/20/90

5/91
5-70 Program Update 2001 

Project SummaryLNCFSTM technology was designed for tangentially firedboilers, which represent a large percentage of the preNSPS coal-fired generating capacity. The technologyreduces NOx by staging combustion vertically in the

boiler with separate coal and air injectors, and horizontally by creating fuel-rich and lean zones with offset airnozzles. The objective was to determine NOx emission

reductions and impact on boiler performance under normal dispatch and operating conditions over the long-term.By using the same boiler, the demonstration provideddirect comparative performance analysis of the threeconfigurations. Short-term parametric testing enabledextrapolation of results to other tangentially fired unitsby evaluating the relationship between NOx emissions

and key operating parameters.At the time of the demonstration, specific NOx emission

regulations were being formulated under the CAAA. Thedata developed over the course of this project providedneeded real-time input to regulation development.Exhibit 5-33 shows the various LNCFSTM configurationsused to achieve staged combustion. In addition to overfireair, the LNCFSTM incorporates other NOx-reducing techniques into the combustion process as shown in Exhibit

5-34. Using offset air, two concentric circular combustionregions are formed. The majority of the coal is containedin the fuel-rich zone. This region is surrounded by a fuellean zone containing combustion air. The size of thisouter annulus of combustion air can be varied using adjustable offset air nozzles.Operational PerformanceExhibit 5-35 summarizes the impacts of LNCFSTM onunit performance.

Environmental PerformanceAt full load, LNCFSTM I, II, and III reduced NOx emissions by 37, 37, and 45%, respectively. Exhibit 5-36

presents the NOx emission estimates obtained from the

assessment of the average annual NOx emissions for three

dispatch scenarios.Air toxics testing found LNCFSTM to have no clear-cuteffect on the emission of trace metals or acid gases. The

Exhibit 5-33

LNCFSTM Configurations

Exh

Concentric 

data provided marginal evidence for a decreased emissionof chromium. The effect on aldehydes/ketones could notbe assessed because baseline data were compromised.VOCs appeared to be reduced and semi-volatile compounds increased. The increase in semi-volatile compounds was deemed to be consistent with increases in theamount of unburned carbon in the ash.Economic PerformanceLNCFSTM II was the only complete retrofit (LNCFSTM Iand III were modifications of LNCFSTM II), and thereforecapital cost estimates were based on the Lansing SmithUnit No. 2 retrofit as well as other tangentially firedLNCFSTM retrofits. The capital cost ranges in 1993 dollars follow:• LNCFSTM I—$5–15/kW• LNCFSTM II—$15–25/kW• LNCFSTM III—$15–25/kW

Site-specific consideratiocapital costs; however, thexperience and are plannicost for LNCFSTM II at Lmillion, or $17/kW, which range.The cost-effectiveness of based on the capital and oand the NOx removal effic

cost-effectiveness of the L(based on a levelization fdollars):• LNCFSTM I—$103/ton 

• LNCFSTM II—$444/to

• LNCFSTM III—$400/to

Commercial ApplicatiThe LNCFSTM technology plication to all the 423 U.fired utility units. These u
 Environmental Control Devices 

Exhibit 5-35

Unit Performance Impacts Based on Long-Term Testing

Baseline LNCFSTM I LNCFSTM II LNCFSTM III

Avg CO at full load (ppm) 10 12 22 33Avg excess O2 at full load (%) 3.7 3.2 4.5 4.3

LOI at full load (%) 4.8 4.6 4.2 5.9

O2 (%) 4.0 3.9 5.3 4.7Steam outlet conditions Satisfactory at full Full load: 5–10 oF Same as baseline 160–200 MWe:

load; low temper- lower than baseline satisfactory

atures at low loads Low loads: 10–30 oF 80 MWe: 15–35 oF

lower than baseline lower than baseline

Furnace slagging and Medium Medium Reduced slagging, Reduced slagging,

backpass fouling but increased fouling but increased foulingOperating 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 (points) N/A +0.2 -0.3 -0.15Turbine heat rate (Btu/kWh) 9,000 9,011 9,000 9,000Unit net heat rate (Btu/kWh) 9,995 9,986 10,031 10,013Change (%) N/A -0.1 +0.36 +0.18

Exhibit 5-36

Average Annual NOx Emissions and Percent Reduction

Boiler Duty Cycle Units Baseline LNCFSTM I LNCFSTM II LNCFSTM III

Baseload Avg NOx emissions (lb/106 Btu) 0.62 0.41 0.41 0.36

(161.8 MWe avg) Avg reduction (%) 38.7 38.7 42.2

Intermediate load Avg NOx emissions (lb/106 Btu) 0.62 0.40 0.41 0.34

(146.6 MWe avg) Avg reduction (%) 39.2 35.9 45.3

Peaking load Avg NOx emissions (lb/106 Btu) 0.59 0.45 0.47 0.43

(101.8 MWe avg) Avg reduction (%) 36.1 20.3 28.0

MWe in size and fire a wvolatile bituminous throThe LNCFSTM has been mercial use. ABB Comb116 tangentially fired botive TFS 2000TM burnerContactsLarry Monroe, (205) 25

Southern Company SMail Stop 14N-8195P.O. Box 2641Birmingham, AL 352lsmonroe@southernc(205) 257-5367 (fax)

James U. Watts, NETL, References180-MWe DemonstratioCombustion Techniques Oxide (NOx) Emissions f

Report and Key Project 89653-T14. Southern C1994. (Available from N180-MWe DemonstratioCombustion Techniques Oxide (NOx) Emissions fLansing Smith—Phase IMonitoring Program Revices, Inc. December 19
5-72 Program Update 2001 
 Environmental Control Devices 

Environmental Control Devi

Combined SO2/NOx Control Techn
5-74 Program Update 2001 

Environmental Control DevicesCombined SO2 / NOx Control TechnologySNOXTM Flue Gas CleaningDemonstration ProjectProject completedParticipantABB Environmental SystemsAdditional Team MembersOhio Coal Development Office—cofunderOhio Edison Company—cofunder and hostHaldor Topsoe a/s—patent owner for process technology,

catalysts, and WSA Condenser

Snamprogetti, U.S.A.—cofunder and process designerLocationNiles, Trumbull County, OH (Ohio Edison’s Niles Station, Unit No. 2)TechnologyHaldor Topsoe’s SNOXTM catalytic advanced flue gascleanup systemPlant Capacity/Production35-MWe equivalent slipstream from a 108-MWe boilerCoalOhio bituminous, 3.4% sulfurProject FundingTotal project cost $31,438,408 100%DOE 15,719,200 50Participant 15,719,208 50Project ObjectiveTo demonstrate SNOXTM technology at an electric powerplant using U.S. high-sulfur coals in which it will catalytically remove 95% of SO2 and more than 90% of NOxfrom flue gas and produce a salable by-product of concentrated sulfuric acid.

Technology/Project DescriptionIn the SNOXTM process, the stack gas leaving the boiler iscleaned of fly ash in a high-efficiency fabric filter baghouse to minimize the cleaning frequency of the sulfuricacid catalyst in the downstream SO2 converter. The ashfree gas is reheated, and NOx is reacted with small quantities of ammonia in the first of two catalytic reactors

where the NO

x is converted to harmless nitrogen and

water vapor. The SO2 is oxidized to SO3 in a second catalytic converter. The gas then passes through a novel

glass-tube condenser that allows SO3 to hydrolyze to

concentrated sulfuric acid.Because the SO2 catalyst follows the NOx catalyst, any

unreacted ammonia (slip) is oxidized in the SO2 catalyst

largely to nitrogen and water vapor. Downstream foulingby ammonia compounds is eliminated, permitting operation at higher than norma

stoichiometries allow smareduction efficiencies. The technology was desig

and more than 90% of the 

duce a salable sulfuric acThis was accomplished wout creating waste streamThe demonstration was coStation in Niles, Ohio. T35-MWe equivalent slipstMWe Unit No. 2 boiler, wcoal. The process steps wfull-scale commercial plaponents were installed an

SNOX is a trademark of Haldor Topsoe a/s.
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• SO2 removal efficiency was normally in excess of 95%

for inlet concentrations, averaging about 2,000 ppm.

• NO

x reduction averaged 94% for inlet concentrations

ranging from 500–700 ppm.

• Particulate removal efficiency for the high-efficiency

fabric filter baghouse with SNOXTM system wasgreater 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 significantportion of the boron and almost all of the mercuryescaped to the stack; but selenium and cadmium, normally a problem, were effectively captured in the aciddrain, as were organic compounds.

• Absence of an alkali reagent contributed to elimination

of secondary pollution streams and increases in CO2

emissions.

• Presence of the SO2 catalyst virtually eliminated CO

and hydrocarbon emissions.

Operational• Having the SO2 catalyst downstream of the NOx catalyst eliminated ammonia slip and allowed the SCR to

function more efficiently.

• Heat developed in the SNOXTM process was used to

enhancet thermal efficiency.

Economic• Capital cost was estimated at $305/kW for a 500-MWe

unit firing 3.2% sulfur coal. The 15-year levelizedincremental cost was estimated at 6.1 mills/kWh,$219/ton of SO2 removed, and $198/ton of SO2 and

NO

x

 removed on a constant 1995 dollar basis.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

9/88

Preaward Design and Construction

Operation initiated 3/92

12/89 3/92

Cooperative agreement

awarded 12/20/89

NEPA process completed (MTF) 1/31/90

Construction completed 12/91Preoperational tests initiated 12/91

Dedication ceremony held 10/17/91Environmental monitoring plan completed 10/31/91

Design completed 8/91

Construction started 1/91

DOE selectedproject (CCT-II)9/28/88

7/96

Operation completed 12/94

Projefinal 
5-76 Program Update 2001 

Project SummaryNo reagent was required for the SO2 removal step because

the SNOXTM process utilized an oxidation catalyst toconvert SO2 to SO3 and ultimately to sulfuric acid. As a

result, the process produced no other waste streams.In order to demonstrate and evaluate the performance ofthe SNOXTM process, general operating data were collected and parametric tests conducted to characterize theprocess and equipment. The system operated for approximately 8,000 hours and produced more than 5,600 tons ofcommercial-grade sulfuric acid. Many of the tests for theSNOXTM system were conducted at three loads—75, 100,and 110% of design capacity.Environmental PerformanceParticulate emissions from the process were very low(<1 mg/Nm3) due to the characteristics of the SO2 catalyst

and the sulfuric acid condenser (WSA Condenser). TheNiles SNOXTM plant was fitted with a baghouse (ratherthan an ESP) on its inlet. This was not necessary for lowparticulate emissions, but rather was needed to maintainan acceptable cleaning frequency for the SO2 catalyst. At

operating temperature, the SO2 catalyst retained about

90% of the dust that entered the catalyst vessel because ofits sticky surface. Dust that passed through was subsequently removed in the WSA Condenser, which acted as acondensing particulate removal device (utilizing the dustparticulates as nuclei).Minimal or no increase in CO2 emissions by the process

resulted from two features—the lack of a carbonate-basedalkali reagent that releases CO2, and the fact that the process recovered additional heat from the flue gas to offset

its parasitic energy requirements. Under most designconditions this heat recovery results in the net heat rate ofthe boiler remaining the same or increasing after additionof the SNOXTM process, and consequently no increaseoccurs in CO2 generation.

With respect to CO and hydrocarbons, the SO2 catalyst

acted to virtually eliminate these compounds as well.This aspect also positively affected the interaction of theNOx and SO2 catalysts. Because the SO2 catalyst followed the NOx catalyst, any unreacted ammonia (slip)

was oxidized in the SO2 catalyst to nitrogen, water vapor,

The bottom portion of the S

catalyst dust collector hopp

and a small amount of NOx. As a result, downstream

fouling by ammonia compounds was eliminated, and theSCR was operated at slightly higher than typical ammonia stoichiometries. These higher stoichiometries allowedsmaller SCR catalyst volumes and permitted the attainment of very high reduction efficiencies. Normal operating stoichiometries for the SCR system were in the rangeof 1.02–1.05, and system reduction efficiencies averaged94% with inlet NOx levels of approximately 500–700

ppm.Sulfur dioxide removal in the SNOXTM process was controlled by the efficiency of the SO2-to-SO3 oxidation,

which occurred as the flue gas passed through theoxidation catalyst beds. The efficiency was controlled bytwo factors—space velocity and bed temperature. Spacevelocity governed the amount of catalyst necessary atdesign flue gas flow conditions, and gas and bed temperature had to be high enough to activate the SO2 oxidation

reaction. During the test program, SO2 removal efficiency

was normally in excess of 95% for inlet concentrationsaveraging about 2,000 ppm.Sulfuric acid concentration and composition have met orexceeded the requirements of the federal specificationsfor Class I acid. During the design and construction ofthe SNOXTM demonstration, arrangements were madewith a sulfuric acid supplier to purchase and distribute theacid from the plant. The acid has been sold to the agriculture industry for production of diammonium phosphatefertilizer and to the steel industry for pickling. OhioEdison also has used a significant amount in boiler waterdemineralizer systems throughout its plants.Air toxics testing conducted at the Niles SNOXTM plantmeasured the following substances:• Five major and 16 trace elements including mercury,

chromium, cadmium, lead, selenium, arsenic, beryllium, and nickel;

• Acids and corresponding anions (hydrogen chloride,

hydrogen fluoride, chloride, fluoride, phosphate,sulfate);

• Ammonia and cyanide;• Elemental carbon;• Radionuclides;

• Volatile organic compo• Semi-volatile compoun

matic hydrocarbons; a

• Aldehydes.Most trace elements were with the particulates. A sand almost all of the mercselenium and cadmium, ntively captured in the acid pounds.
 Environmental Control Devices 

The SNOXô demonstration at Ohio Edisonís Niles Station Unit No. 2 achieved SO2removal efficiencies exceeding 95% and NOx reduction effectiveness averaging

94%. Ohio Edison is retaining the SNOXô technology as part of its environmentalcontrol system.

Operational PerformanceHeat recovery was accomplished by the SNOXô process.In a commercial configuration, it can be utilized in thethermal cycle of the boiler. The process generated recoverable heat in several ways. All of the reactions that tookplace with respect to NOx and SO2 removal were exothermic and increased the temperature of the flue gas. This

heat, plus fuel-fired support heat added in the high-temperature SCR/SO2 catalyst loop, was recovered in the

WSA Condenser cooling air discharge for use in the furnace as combustion air. Because the WSA Condenserlowered the temperature of the flue gas to about 210 oF,compared with approximately 300 oF for a typical powerplant, additional thermal energy was recovered along withthat from the heats of reaction.Economic PerformanceThe economic evaluation of the SNOXô process showeda capital cost of approximately $305/kW for a 500-MWeunit firing 3.2% sulfur coal. The 15-year levelized incremental cost was 6.1 mills/kWh on a constant dollar basis(1995$). The equivalent costs of pollutant removed were$219/ton of SO2, and $198/ton of SO2

and NO

x

.

Commercial ApplicationsThe SNOXô technology is applicableto all electric power plants and industrial/institutional boilers firing coal,oil, or gas. The high removal efficiency for NOx and SO2 makes the

process attractive in many applications. Elimination of additional solidwaste (except ash) enhances its marketability in urban and other areaswhere solid waste disposal is a significant problem.The host utility, Ohio Edison, is retaining the SNOXô technology as a permanent part of the pollution controlsystem at Niles Station to help OhioEdison meet its overall SO2/NOx reduction goals.

Commercial SNOXô plants also are operating in Denmark and Sicily. In Denmark, a 305-MWe plant has operated since August 1991. The boiler at this plant burnscoals from various suppliers around the world, includingthe United States; the coals contain 0.5ñ3.0% sulfur. Theplant in Sicily, operating since March 1991, has a capacityof about 30 MWe and fires petroleum coke.ContactsPaul Yosick, Project Manager, (865) 694-5300

Alstom Power, Inc.1409 Center Port BoulevardKnoxville, TN 37932(865) 694-5213 (fax)

James U. Watts, NETL, (412) 386-5991ReferencesFinal Report Volume II: Project Performance and Economics. July 1996. Report No. DE-FC22-90PC89C55.Final Report Volume I: Public Design. Report No. DOE/PC/89655-T21. (Available from NTIS as DE96050312.)

A Study of Toxic EmissiPlant Utilizing the SNOnology Demonstration. Special Topics: Final R93251-T3-Vol. 1. Battel1994. (Available from NA Study of Toxic EmissioPlant Utilizing the SNOnology Demonstration. Report. Report No. DOColumbus Operations. as DE94018833.)
5-78 Program Update 2001 

Environmental Control DevicesCombined SO2 / NOx Control TechnologyLIMB Demonstration ProjectExtension and CoolsideDemonstrationProject completedParticipantThe Babcock & Wilcox CompanyAdditional Team MembersOhio Coal Development OfficeócofunderConsolidation Coal Companyócofunder and technology

supplier

Ohio Edison CompanyóhostLocationLorain, Lorain County, OH (Ohio Edisonís EdgewaterStation, Unit No. 4)TechnologyThe Babcock & Wilcox Companyís (B&W) limestoneinjection multistage burner (LIMB) system; Babcock &Wilcox DRB-XCLÆ low-NO

x burners; Consolidation

Coal Companyís Coolside duct injection of lime sorbentsPlant Capacity/Production105 MWeCoalOhio bituminous, 1.6, 3.0, and 3.8% sulfurProject FundingTotal project cost $19,311,033 100%DOE 7,591,655 39Participant 11,719,378 61Project ObjectiveTo demonstrate, with a variety of coals and sorbents, thatthe LIMB process can achieve up to 50% NOx and SO2

reductions, and to demonstrate that the Coolside processcan achieve SO2 removal of up to 70%.

Technology/Project DescriptionThe LIMB process reduces SO2 by injecting dry sorbent

into the boiler at a point above the burners. The sorbentthen travels through the boiler and is removed along withfly ash in an electrostatic precipitator (ESP) or baghouse.Humidification of the flue gas before it enters an ESP isnecessary to maintain normal ESP operation and to enhance SO2 removal. Combinations of three bituminous

coals (1.6, 3.0, and 3.8% sulfur) and four sorbents weretested. Other variables examined were stoichiometry,humidifier outlet temperature, and injection elevationlevel in the boiler.In the Coolside process, dry sorbent is injected into theflue gas downstream of the air preheater, followed by fluegas humidification. Humidification enhances ESP performance and SO2 absorption. SO2 absorption is improved

by dissolving sodium hydbonate (Na2CO3) in the hu

sorbent is collected with tprocess. Bituminous coatesting.Babcock & Wilcox DRB-

control NO

x through stag

demonstrating both LIMB 
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• LIMB SO2 removal efficiencies at a calcium-to-sulfur

(Ca/S) molar ratio of 2.0, and minimal humidificationacross the range of coal sulfur contents were 53–61%for ligno lime, 51–58% for calcitic lime, 45–52% fordolomitic lime, and 22–25% for limestone ground to80% less than 44 microns (325 mesh).

• LIMB SO2 removal efficiency increased to 32% using

limestone ground to 100% minus 325 mesh, and increased an additional 5–7% when ground to 100% lessthan 10 microns.

• LIMB SO2 removal efficiencies were enhanced by

about 10% when humidification down to 20 oF approach-to-saturation temperature was used.

• LIMB, which incorporated Babcock & Wilcox

DRB-XCL® low-NO

x burners, achieved 40–50% NOx

reduction.

• Coolside SO2 removal efficiency was 70% at a Ca/S

molar ratio of 2.0, a sodium-to-calcium (Na/Ca) ratioof 0.2, and 20 oF approach-to-saturation temperature

using commercial hydrated lime and 2.8–3.0% sulfurcoal.

• 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 availability was 95%. Coolside did not undergo

testing of sufficient length to establish availability.

• Humidifier performance indicated that operation in a

vertical rather than horizontal mode would be better.

Economic• LIMB capital costs were $31–102/kW (1992$) for

plants ranging from 100–500 MWe and coals with1.5–3.5% sulfur, with a target SO2 reduction of 60%.

Annual levelized costs (15-year) for this range of conditions were $392–791/ton of SO2 removed.

• Coolside capital costs were $69–160/kW (1992$) for

plants ranging from 100–500 MWe and coals with1.5–3.5% sulfur, with a target SO2 reduction of 70%.

Annualized levelized conditions were $482

1986 1987 1988 1989 1990 1991 1992 1993 1994 

Preaward Design and Construction

11/92

Project completed/final report issued 

LIMB operational tests completed 8/91

NEPA process

 completed (MTF)

6/2/87

Cooperative

agreement

awarded 6/25/87

Coolside operational tests initiated 7/89

Construction completed 9/89

Ground breaking/constructionstarted 8/87

Environmental monitoring plan

completed 10/19/88

Operation and Reporting

6/87

LIMB operational testsinitiated 4/90

Coolside operational testscompleted 2/90

DOE selectedproject (CCT-I)7/24/86

7/86 7/89
5-80 Program Update 2001 

Project SummaryThe initial expectation with LIMB technology was thatlimestone calcined by injection into the furnace wouldachieve adequate SO2 capture. Use of limestone in lieu of

the significantly more expensive lime would keep operating costs relatively low. However, the demonstrationshowed that, even with fine grinding of the limestone anddeep humidification, performance with limestone wasmarginal. As a result, a variety of hydrated limes wereevaluated in the LIMB configuration, demonstrating enhanced performance. Although LIMB performance wasenhanced by applying humidification to the point of approaching adiabatic saturation temperatures, performancedid not rely on this deep humidification.Coolside design was dependent upon deep humidificationto improve sorbent reactivity and the use of hydratedlime. Sorbent injection was downstream of the furnace.In addition, sorbent activity was enhanced by dissolvingsodium hydroxide (NaOH) or sodium carbonate (Na2CO3

)

in the humidification water.

Water mist, sprayed into the flue gas, enhanced sulfurcapture by the sorbent by approximately 10% in the LIMBprocess when 20 °F approach-to-saturation was used.

Exhib

LIMB SO2 Rem

(Per

No

Sorbent Ligno lime Commercial calcitic lime Dolomitic lime Limestone (80% <44 microns)

NT = Not testedTest conditions: injection at 181 minimal humidification.

Environmental Performance (LIMB)LIMB tests were conducted over a range of Ca/Smolar ratios and humidification conditions whileburning Ohio coals with nominal sulfur contents of1.6, 3.0, and 3.8% by weight. Each of four differentsorbents was injected while burning each of the threedifferent coals. Other variables examined werestoichiometry, humidifier outlet temperature, andinjection elevation level in the boiler. Exhibit 5-37summarizes SO2 removal efficiencies for the range of

sorbents and coals tested.While injecting commercial limestone with 80% ofthe particles less than 44 microns in size, removalefficiencies of about 22% were obtained at astoichiometry of 2.0 while burning 1.6% sulfur coal.However, removal efficiencies of about 32% wereachieved at a stoichiometry of 2.0 when using alimestone with a smaller particle size (i.e., all particles were less than 44 microns). A third limestonewith essentially all particles less than 10 microns wasused to determine the removal efficiency limit. Theremoval efficiency for this very fine limestone wasapproximately 5–7% higher than that obtained undersimilar conditions for limestone with particles all sizedless than 44 microns.During the design phase, it was expected that injection atthe 181-foot plant elevation level inside the boiler wouldpermit the introduction of the limestone at close to theoptimum furnace temperature of 2,300 oF. Testing confirmed that injection at this level, just above the nose ofthe boiler, yielded the highest SO2 removal. Injection was

also performed at the 187-foot level and similar removalswere observed. Removal efficiencies while injecting atthese levels were about 5% higher than while injectingsorbent at the 191-foot level.Removal efficiencies were enhanced by approximately10% over the range of stoichiometries tested when usinghumidification down to a 20 oF approach-to-saturationtemperature. The continued use of the low-NOx burners

resulted in an overall average NOx emissions level of

0.43 lb/106 Btu, which is about a 45% reduction.

Operational PerformaLong-term test data showavailable about 95% of thoperate. Even with minimmance was adequately enwell below the permitted the 2–5% range (limit waEnvironmental PerforThe Coolside process was ance (1.2–1.6% sulfur) ansulfur) coals. Objectives were to verify short-term velop a design performaneconomics for Coolside. molar ratio, Na/Ca molar tion temperatures—were hours) parametric tests ancess operability tests.The test program demonsroutinely achieved 70% S

of 2.0 Ca/S molar ratio, 0approach-to-saturation temavailable hydrated lime. 
 Environmental Control Devices 

Exhibit 5-38

LIMB Capital Cost Comparison

(1992 $/kW)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe

1.5 93 150 413 66 116 3122.5 95 154 421 71 122 3163.5 102 160 425 73 127 324

250 MWe 500 MWe

1.5 46 96 228 31 69 1632.5 50 101 235 36 76 1693.5 54 105 240 40 81 174

Exhibit 5-39

LIMB Annual Levelized Cost Comparison

(1992 $/Ton of SO2 Removed)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe

1.5 791 943 1418 653 797 10982.5 595 706 895 520 624 6923.5 525 629 665 461 570 527

250 MWe 500 MWe

1.5 549 704 831 480 589 6232.5 456 567 539 416 502 4113.5 419 526 413 392 482 321

on Ca/S molar ratio, Na/Ca molar ratio, approach-toadiabatic-saturation, and the physical properties of thehydrated lime. Sorbent recycle showed significant potential to improve sorbent utilization. The observed SO2removal with recycled sorbent alone was 22% at 0.5available Ca/S molar ratio and 18 oF approach-to-adiabatic-saturation. The observed SO2 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 oF ap- proach-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 (LSFO). Assumptions on performance were SO2 removal efficiencies of 60, 70, and 95% for LIMB, Coolside, and LSFO, respectively. The EPRI TAGTM methods were used for the eco- nomics, which are summarized in Exhibits 5-38 and 5-39. Commercial Application Both LIMB and Coolside tech- nologies are applicable to most utility and industrial coal-fired units, and provide alternatives to conventional wet flue gas desulfu- rization processes. LIMB and Coolside can be retrofitted with modest capital investment and downtime, and their space requirements are substantially less than for conven- tional 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-NOx bu

for 31,467 MWe of capaContacts Paul Nolan, (330) 860-1

The Babcock & Wilc20 South Van Buren P.O. Box 351 Barberton, OH 4420psnolan@babcock.co(330) 860-2045 (fax) John C. McDowell, NET

References T.R. Goots, M.J. DePerostration Project ExtensiFinal Report. Report NBabcock & Wilcox Comable from NTIS as DE9D.C. McCoy et al. The Demonstration: A Topic79798-T26. CONSOL, from NTIS as DE93001Coolside and LIMB: SoNearing Completion. Tment of Energy and The September 1990.
5-82 Program Update 2001 

Environmental Control DevicesCombined SO2 / NOx Control TechnologySOx-NOx-Rox Boxô Flue GasCleanup DemonstrationProjectProject completedParticipantThe Babcock & Wilcox CompanyAdditional Team MembersOhio Edison Companyócofunder and hostOhio Coal Development OfficeócofunderElectric Power Research InstituteócofunderNorton Companyócofunder and SCR catalyst supplier3M Companyócofunder and filter bag supplierOwens Corning Fiberglas Corporationócofunder and

filter bag supplier

LocationDilles Bottom, Belmont County, OH (Ohio EdisonCompanyís R.E. Burger Plant, Unit No. 5)TechnologyThe Babcock & Wilcox Companyís SOx-NOx-RoxBoxô (SNRBô) processPlant Capacity/Production5-MWe equivalent slipstream from a 156-MWe boilerCoalBituminous coal blend, 3.7% sulfur averageProject FundingTotal project cost $13,271,620 100%DOE 6,078,402 46Participant 7,193,218 54

Project ObjectiveTo achieve greater than 70% SO2 removal and 90% or

higher reduction in NOx emissions while maintaining

particulate emissions below 0.03 lb/106 Btu.

Technology/Project DescriptionThe SNRBô process combines the removal of SO2, NOx,

and particulates in one unitóa high-temperature baghouse. SO2 removal is accomplished using either calcium- or sodium-based sorbent injected into the flue gas.

The NO

x removal is accomplished by injecting ammonia

(NH3) to selectively reduce NOx in the presence of a selective catalytic reduction (SCR) catalyst. Particulate

removal is accomplished by high-temperature fiber bagfilters.The 5-MWe SNRBô demonstration unit is large enoughto demonstrate commercial-scale components while minimizing the demonstration 

also permitted cost-effectperature, which allowed fover a wide range of sorbating temperatures. Thusfor potential commercial 

SOx-NOx-Rox Box and SNRB are trademarks of The Babcock & Wilcox Company.
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• The SO2 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 oF.

• The SO2 removal efficiency of 90% was achieved with

sugar-hydrated lime and lignosulfonate-hydrated limeat a Ca/S molar ratio of 2.0 and temperature of800–850 oF.

• The SO2 removal efficiency of 80% was achieved with

sodium bicarbonate at a sodium-to-sulfur (Na2/S) molar ratio of 1.0 and temperature of 425 oF.

• The SO2 emissions were reduced to less than 1.2 lb/106

Btu with 3–4% sulfur coal, with a Ca/S molar ratio aslow as 1.5 and Na2/S molar ratio of 1.0.

• Injection of calcium-based sorbents directly upstream

of the baghouse at 825–900 oF resulted in higher overall SO2 removal than injection further upstream at

temperatures up to 1,200 oF.

• The NO

x

 reduction of 90% was achieved with an NH3/

NO

x molar ratio of 0.9 and temperature of 800–850 oF.

• Air toxics removal efficiency was comparable to that

of an electrostatic precipitator (ESP), except that hydrogen fluoride (HF) was reduced by 84% and hydrogen chloride (HCl) by 95%.

Operational• Calcium utilization was 40–45% for SO2 removals of

85–90%.

• Norton Company’s NC-300 zeolite SCR catalyst

showed no appreciable physical degradation or changein 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 andOwens Corning Fiberglas’ S-Glass filter bag.

Economic• Capital cost in 1994 dollars for a 150-MWe retrofit

was $253/kW, assuming 3.5% sulfur coal, baselineNO

x

 emissions of 1.2 lb/106 Btu, 65% capacity factor,

and 85% SO2 and 90% NOx removal.

• Levelized cost over 15 years in constant 1994 dollars

was $553/ton of SO2 and NOx removed.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

9/88

Preaward

12/89

Design completed 8/91

DOE selectedproject (CCT-II)9/28/88

Cooperative agreementawarded 12/20/89

NEPA process completed (MTF) 9/22/89

Ground breaking/construction started 5/9/91

5/92

Design and Construction Operation and Reporting

Preoperational tests initiated 11/91

Construction completed 12/91Environmental monitoring plan completed 12/31/91

Operationinitiated 5/92 Operation completed 5/93 Project completed/fina

9/95
5-84 Program Update 2001 

The sorbent injection into the duct upstream of SOx-NOx-RoxBoxô system.

Project SummarySNRBô incorporates two successful technology development efforts that offer distinct advantages over other control technologies. High-temperature filter bags and circular monolith catalyst developments enabled multipleemission controls in a single component with a low planarea space requirement. As a postcombustion controlsystem, it is simple to operate. The high-temperature bagprovides a clean, high-temperature environment compatible with effective SCR operation, and a surface for enhanced SO2/sorbent contact (creates a sorbent cake on the

surface).Environmental PerformanceFour different sorbents were tested for SO2 capture. Calcium-based sorbents included commercial grade hydrated

lime, sugar-hydrated lime, and lignosulfonate-hydratedlime. In addition, sodium bicarbonate was tested. Theoptimal location for injecting the sorbent into the flue gaswas immediately upstream of the baghouse. Essentially,the SO2 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 oF, injection ofcommercial-grade hydrated lime at Ca/S molar ratios of1.8 and above resulted in SO2 removals of over 80%. At

a Ca/S molar ratio of 2.0, sugar-hydrated lime and lignosulfonate-hydrated lime increased performance by approximately 8%, for overall removal of approximately90%. SO2 removal of 85ñ90% was obtained with calcium

utilization in the range of 40ñ45%. Injection of the calcium-based sorbents directly upstream of the baghouse at825ñ900 oF resulted in higher overall SO2 removal than

injection further upstream at temperatures up to 1,200 oF.The SO2 removal using sodium bicarbonate was 80% at

an Na2/S molar ratio of 1.0 and 98% at an Na2/S molar

ratio of 2.0, at a significantly reduced baghouse temperature of 450ñ460 oF. The SO2 emissions while burning a

3ñ4% sulfur coal were reduced to less than 1.2 lb/106 Btu

with a Ca/S molar ratio as low as 1.5 and Na2/S molar

ratio less than 1.0.To capture NOx, ammonia was injected between the sorbent injection point and the baghouse. The ammonia and

NOx reacted to form nitrogen and water in the presence of

Norton Companyís NC-300 series zeolite SCR catalyst.With the catalyst being located inside the filter bags, itwas well protected from potential particulate erosion orfouling. The sorbent reaction products, unreacted lime,and fly ash were collected on the filter bags and thusremoved from the flue gas.A NOx emission reduction of 90% was readily achieved

with ammonia slip limited to less than 5 ppm. This performance reduced NOx emissions to less than 0.10 lb/

106 Btu. NOx reduction was insensitive to temperatures

over the catalyst design temperature range of 700ñ900 oF.Catalyst space velocity (volumetric gas flow/catalyst volume) had a minimal effec

evaluated. Turndown capability for t

duction by varying the ratdemonstrated for a range 

appreciable physical degractivity was observed ovegram. The degree of oxid

zeolite catalyst appeared 

oxidation is a concern for vanadium.) Leach potentcompletion of the field teremained nonhazardous fParticulate emissions werdards of 0.03 lb/106 Btu, 

106 Btu, which correspon

99.89%. Hydrated lime iinlet particulate loading f

Emissions testing with anstalled revealed no appareefficiency. On-line clean30ñ40 lb/in2 was sufficien

assemblies. Typically, onservice was cleaned every A comprehensive air toxiperformed at the end of thprogram. The targeted etrace metals, volatile orgaorganic compounds, aldehclides. These species wersubstances identified in thmercury speciation, dioxifeatures of this test prograefficiencies achieved for vSNRBô system were genthe conventional ESP at tSNRBô system did reduand HF emissions by an aESP had no effect on thesOperation of the SNRBô production of approximatproduct solids. An evalua
 Environmental Control Devices 

Workers lower one of the mounting plate in the penbaghouse.

by-product showed that the material might be used foragricultural liming (if pelletized). Also, the solids potentially could be used as a partial cement replacement tolower the cost of concrete.Operational PerformanceA 3,800-hour durability test of three fabric filters wascompleted at the Filter Fabric Development Test Facilityin Colorado Springs, Colorado in December 1992. Nosigns of failure were observed. All of the demonstrationtests were conducted using the 3M Company Nextelceramic fiber filter bags or the Owens Corning FiberglasS-Glass filter bags. No excessive wear or failuresoccurred in over 2,000 hours of elevated temperatureoperation.Economic PerformanceFor a 150-MWe boiler fired with 3.5% sulfur coal andNO

x

 emissions of 1.2 lb/106 Btu, 65% capacity factor, and

85% SO2 and 90% NOx removal, the projected capital

cost of a SNRBTM system is approximately $253/kW(1994$), including various technology and project contingency factors. A combination of fabric filter, SCR, andwet scrubber for achieving comparable emissions controlhas been estimated at $360–400/kW. Variable operatingcosts are dominated by the cost of the SO2 sorbent for a

system designed for 85–90% SO2 removal. Fixed operating costs primarily consist of system operating labor and

projected labor and material for the hot baghouse and ashhandling systems. Levelized costs over 15 years in constant 1994 dollars are estimated at $553/ton of SO2 and

NO

x

 removed.

Commercial ApplicationsCommercialization of the technology is expected to develop with an initial application equivalent to 50–100MWe. The focus of marketing efforts is being tailored tomatch the specific needs of potential industrial, utility,and independent power producers for both retrofit andnew plant construction. SNRBTM is a flexible technologythat can be tailored to maximize control of SO2, NOx, or

combined emissions to meet current performance requirements while providing flexibility to address future needs.

ContactsDot K. Johnson, (330) 829-7395

McDermott Technology1562 Beeson StreetAlliance, OH 44601dot.k.johnson@mcdermott.com(330) 829-7801 (fax)

James U. Watts, NETL, (412) 386-5991ReferencesSOx-NOx-Rox BoxTM Flue Gas Cleanup DemonstrationFinal Report. Report No. DOE/PC/89656-T1. The Babcock & Wilcox Company. September 1995. (Availablefrom NTIS as DE96003839.)5-MWe SNRBTM Demonstration Facility: Detailed DesignReport. The Babcock & Wilcox Company. November1992.Comprehensive Report to Congress on the Clean CoalTechnology Program: SOx-NOx-Rox BoxTM Flue GasCleanup Demonstration Project. The Babcock & WilcoxCompany. Report No. DOE/FE-0145. U.S. Departmentof Energy. November 1989. (Available from NTIS asDE90004458.)
5-86 Program Update 2001 

Environmental Control DevicesCombined SO2 / NOx Control TechnologyEnhancing the Use of Coalsby Gas Reburning andSorbent InjectionProject completedParticipantEnergy and Environmental Research CorporationAdditional Team MembersGas Research Institute—cofunderState of Illinois, Department of Commerce & Community

Affairs—cofunder

Illinois Power Company—hostCity Water, Light and Power—hostLocationsHennepin, Putnam County, IL (Illinois Power Company’sHennepin Plant, Unit No. 1)Springfield, Sangamon County, IL (City Water, Light andPower’s Lakeside Station, Unit No. 7)TechnologyEnergy and Environmental Research Corporation’s gasreburning and sorbent injection (GR-SI) processPlant Capacity/ProductionHennepin: tangentially fired 80 MWe (gross), 71 MWe(net)Lakeside: cyclone-fired 40 MWe (gross), 33 MWe (net)CoalIllinois bituminous, 3.0% sulfurProject FundingTotal project cost $37,588,955 100%DOE 18,747,816 50Participant 18,841,139 50PromiSORB is a trademark of Energy and Environmental ResearchCorporation.

Project ObjectiveTo demonstrate 60% NO

x reduction with gas reburning

and at least 50% SO2 removal with sorbent injection on

two different boiler configurations—tangentially firedand cyclone-fired—while burning high-sulfur midwesterncoal.Technology/Project DescriptionIn this process, 80–85% of the fuel as coal is supplied tothe main combustion zone. The remaining 15–20% of thefuel, provided as natural gas, bypasses the main combustion zone and is injected above the main burners to form areducing (reburning) zone in which NOx is converted to

nitrogen. A calcium compound (sorbent) is injected in theform of dry, fine particulates above the reburning zone inthe boiler. Hydrated lime (Ca(OH)2) serves as the baseline sorbent.

This project demonstrated separate boilers representrations—a tangentially firIllinois Power Company’Illinois, and a cyclone-firCity Water, Light and PowSpringfield, Illinois. Illin3% sulfur was the test coaLakeside.A comprehensive test prothe two sites, operating thof boiler conditions. Oveachieved, enabling a subsobtained. Intensive measthe reductions in NO

x

 and 

boiler equipment and opeing costs.
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• On the tangentially fired boiler, GR-SI NOx reductions

of up to 75% were achieved, and an average 67%reduction was realized at an average gas heat input of18%.

• GR-SI SO2 removal efficiency on the tangentially fired

boiler averaged 53% with hydrated lime at a calciumto-sulfur (Ca/S) molar ratio of 1.75 (corresponding toa sorbent utilization of 24%).

• On the cyclone-fired boiler, GR-SI NOx reductions of

up to 74% were achieved, and an average 66% reduction was realized at an average gas heat input of 22%.

• GR-SI SO2 removal efficiency on the cyclone-fired

boiler averaged 58% with hydrated lime at a Ca/Smolar ratio of 1.8 (corresponding to a sorbent utilization of 24%).

• Particulate emissions were not a problem on either unit

undergoing demonstration, but humidification had tobe introduced at Hennepin to enhance ESP performance.

• Three advanced sorbents tested achieved higher SO2

capture efficiencies than the baseline Linwood hydrated lime. PromiSORBTM A achieved 53% SO2capture efficiency and 31% utilization without GR at aCa/S molar ratio of 1.75. Under the same conditions,PromiSORBTM B achieved 66% SO2 reduction and

38% utilization, and high-surface-area hydrated limeachieved 60% SO2 reduction and 34% utilization.

Operational• Boiler efficiency decreased by approximately 1% as a

result of increased moisture formed in combustionfrom natural gas use.

• There was no change in boiler tube wastage, tube metallurgy, or projected boiler life.Economic• Capital cost for gas reburning (GR) was approximately

$15/kW plus the gas pipeline cost, if not in place(1996$).

• Operating costs for GR were related to the gas/coal

cost differential and the value of SO2 emission allowances (because GR replaces some coal with gas, it also

reduces SO2 emissions).

• Capital cost for sorbe

mately $50/kW.

• Operating costs for S

sorbent and sorbent/amated to be competit

Preaward Design and Construction

1986 1987 1988 1989 1990 1991 1992 1993 1994 

7/86 1/91

DOE selectedproject (CCT-I)7/24/86

7/87

Operation initiated,Lakeside 5/93

Operation completed,Hennepin 1/93

Construction completed, Hennepin 8/91

Operation initiated, Hennepin 1/91

Construction started, Lakeside 6/90

Environmental monitoring plan completed,Lakeside 11/15/89

Environmental monitoring plan

completed, Hennepin 10/15/89

NEPA process completed, Lakeside (EA) 6/25/89

Design completed, both sites 5/89

Construction started, Hennepin 5/89

NEPAprocesscompleted,Hennepin(MTF) 5/9/88

Cooperativeagreementawarded7/14/87

Construction completed, Lakeside 5/92

RestoHenn

OL

Operation and Reporting
5-88 Program Update 2001 

The flexible lime-sorbent disorbent splitter to the top oLakeside Station.

Project SummaryThe GR-SI project demonstrated the success of gas reburning and sorbent injection technologies in reducingNOx and SO2 emissions. The process design conducted

early in the project combined with the vast amount ofdata collected during the testing created a database enabling effective design for any site-specific utility or industrial application.Environmental Performance (Hennepin)Following optimization testing throughout 1991, the GRSI long-term demonstration tests spanned 1992. The unitwas operated at constant loads and with the system underdispatch load following. With the system under dispatch,the load fluctuated over a wide range from 40-MWe to amaximum load of 75 MWe. Over the long-term demonstration period, the average gross power output was 62MWe.For long-term demonstration testing, the average NOx

reduction was approximately 67%. The average SO2removal efficiency was over 53% at a Ca/S molar ratio of1.75. (Linwood hydrated lime was used throughout thesetests except for a few days when Marblehead lime wasused.) CO emissions were below 50 ppm in most casesbut were higher during operation at low load.A significant reduction in CO2 was also realized. This

was due to partial replacement of coal with natural gashaving a lower carbon-to-hydrogen ratio. This cofiringwith 18% natural gas resulted in a theoretical CO2 emissions reduction of nearly 8% from the coal-fired baseline

level. With flue gas humidification, electrostatic precipitator (ESP) collection efficiencies greater than 99.8% andparticulate emissions less than 0.025 lb/106 Btu were

measured, even with an increase in inlet particulate loading resulting from sorbent injection. These levels compared favorably to baseline emissions of 0.035 lb/106 Btu

and a collection efficiency greater than 99.5%.Following completion of the long-term tests, three specially prepared sorbents were tested. Two weremanufactured by the participant and contained proprietaryadditives to increase their reactivity toward SO2, and were

referred to as PromiSORBTM A and B. The Illinois

Geological Survey developed the other sorbent—highsurface-area hydrated lime—in which alcohol is used toform a material that gives rise to a much higher surfacearea than that of conventionally hydrated limes.The SO2 capture without GR, at a nominal 1.75 Ca/S

molar ratio, was 53% for PromiSORBTMA, 66% for

PromiSORBTM B, 60% for high-surface-area hydratedlime, and 42% for Linwood lime. At a 2.6 Ca/S molarratio, the PromiSORBTM B yielded 81% SO2 removal

efficiency.Environmental Performance (Lakeside)Parametric tests were conducted in three series: GR parametric tests, SI parametric tests, and GR-SI optimizationtests. A total of 100 GR parametric tests were conductedat boiler loads of 33, 25, and 20 MWe. Gas heat inputvaried from 5–26%. The GR parametric tests achieved aNOx reduction of approximately 60% at a gas heat input

of 22–23%. Additional flow modeling and computermodeling studies indicated that smaller reburning fuel jetnozzles could increase reburning fuel mixing and thusimprove the NOx reduction performance.

A total of 25 SI parametric tests were conducted to isolatethe effects of sorbent on boiler performance and operability. Results showed that SO2 reduction levels varied with

load because of the effect of temperature on the sulfationreaction. At a Ca/S molar ratio of 2.0, 44% SO2 reduction

was achieved at full load (33 MWe); 38% SO2 reduction

was achieved at mid load (25 MWe); and 32% SO2 reduction was achieved at low load (20 MWe).

In the GR-SI optimization tests, the two technologieswere integrated. Modifications were made to the reburning fuel injection nozzles based on the results of the initial GR parametric tests and flow modeling studies. Thetotal cross-sectional area of the reburning jets was decreased by 32% to increase the reburning jet’s penetrationcharacteristics. The decrease in nozzle diameter increasedNOx reduction by an additional 3–5% compared with the

initial parametric tests. With GR-SI, total SO2 reductions

resulted from partial replacement of coal with natural gasand sorbent injection. At a gas heat input of 22% andCa/S molar ratio of 1.8, average NOx reduction during the

long-term testing of GR-S

reduction was 58%.Operational PerformaSorbent injection increaseoperation but did not adveequipment performance. Gefficiency by approximatein moisture formed with camination of the boiler bemeasurable change in tube the scheduled life of the b
 Environmental Control Devices 

The natural gas injector was installed on the corner ofHennepin Station’s tangentially fired boiler.The ESPs adequately accommodated the changes in ashloading and resistivity with the presence of sorbent in theash. No adverse conditions were found to exist. But asmentioned, humidification was added at Hennepin toachieve acceptable ESP performance with GR-SI.Economic Performance (Hennepin/Lakeside)Capital and operating costs depend largely onsite-specific factors, such as gas availability at the site,coal/gas cost differential, SO2 removal requirements, and

value of SO2 allowances. It was estimated that for most

installations, a 15% gas heat input will achieve 60% NOx

reduction. The capital cost for such a GR installation wasestimated at $15/kW for 100-MWe and larger plants plusthe cost of the gas pipeline (if required) (1996$). Operating costs were almost entirely related to the differential cost of the gas over the coal as reduced by the value of SO2 emission allowances. 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 SO2 removed. Commercial Applications The GR-SI process is a unique combination of two sepa- rate technologies. The commercial applications for these technologies, both separately 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 NOx and SO2 removal exceeding

60% and 50%, respectively, these technologies have thepotential to extend the life of a boiler or power plant andalso provide a way to use higher sulfur coals.Illinois Power has retained the gas-reburning system andCity Water, Light & Power has retained the full technology for commercial use. The project was one of tworeceiving the Air and Waste Management Association’s1997 J. Deanne Sensenbaugh Award.ContactsBlair A. Folsom, Senior V.P., (949) 859-8851, ext. 140General Electric Energy and Environmental Research

Corporation

18 MasonIrvine, CA 92618blair.folsom@ps.ge.com(949) 859-3194 (fax)Jerry L. Hebb, NETL, (412) 386-6079ReferencesEnhancing the Use of Coals by Gas Reburning and Sorbent Injection; Volume 1–Program Overview. February1997.Enhancing the Use of Coals by Gas Reburning–SorbentInjection: Volume 4: Gas Reburning Sorbent Injection atLakeside Unit 7, City Water, Light and Power, Springfield, Illinois. Final Report. Energy and Environmental

Research Corporation. PC/79796-T48-Vol.4. (DE96011869.)Enhancing the Use of CInjection; Long Term TeJanuary 15, 1993. RepEnergy and Environmenary 1995. (Available froEnhancing the Use of Cbent Injection; Volume 2tion at Hennepin Unit 1No. DOE/PC/79796-T3mental Research Corporfrom NTIS as DE95009Enhancing the Use of Cbent Injection; Volume 3tion at Edwards Unit 1, Report No. DOE/PC/79vironmental Research C(Available from NTIS a
5-90 Program Update 2001 

Environmental Control DevicesCombined SO2 / NOx Control TechnologyMilliken Clean CoalTechnology DemonstrationProjectProject completedParticipantNew York State Electric & Gas Corporation (NYSEG)Additional Team MembersNew York State Energy Research and Development

Authorityócofunder

Empire State Electric Energy Research Corporationó

cofunder

Consolidation Coal Companyótechnical consultantSaarberg-Hˆlter Umwelttechnik, GmbH (S-H-U)ó

technology supplier

The Stebbins Engineering and Manufacturing

Companyótechnology supplier

ABB Air Preheater, Inc.ótechnology supplierLocationLansing, Tompkins County, NY (New York State Electric& Gas Corporationís Milliken Station, Unit Nos. 1 and 2)TechnologyFlue gas cleanup using S-H-U formic-acid-enhanced, wetlimestone scrubber technology; ABB CombustionEngineeringís Low-NOx Concentric Firing System

(LNCFSô) Level III; Stebbinsí tile-lined split-moduleabsorber; ABB Air Preheaterís heat-pipe air preheater;and NYSEGís PEOA Control System.Plant Capacity/Production300 MWeCoalPittsburgh, Freeport, and Kittanning Coals; 1.5, 2.9 and4.0% sulfur, respectively.

LNCFS is a trademark of ABB Combustion Engineering, Inc. PEOA is atrademark of DHR Technologies, Inc.

Project FundingTotal project cost $158,607,807 100%DOE 45,000,000 28Participant 113,607,807 72Project ObjectiveTo demonstrate high sulfur capture efficiency and NOxand particulate control at minimum power requirements,zero waste water discharge, and the production of byproducts in lieu of wastes.Technology/Project DescriptionThe formic acid enhanced S-H-U process is designed toremove up to 98% SO2 at high sorbent utilization rates.

The Stebbins tile-lined, split-module reinforced concreteabsorber vessel provides superior corrosion and abrasionresistance. Placement below the stack saves space andprovides operational flexibility. NOx emissions are controlled by LNCFS IIIôlo

ized coal reburning. A hegrated to increase boiler eleakage and the air preheaTo enhance boiler efficienPlant Emission Optimizatstate-of-the-art artificial-iboiler and plant operating 
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmentalï The maximum SO2 removal demonstrated was 98%

with all seven recycle pumps operating and usingformic acid. The maximum SO2 removal without

formic acid was 95%.

ï The difference in SO2 removal between the two limestone grind sizes tested (90%ñ325 mesh and 90%ñ170

mesh) while using low-sulfur coal was an average of2.6 percentage points.

ï The SO2 removal efficiency was greater than the design 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 (kacf)of gas.

ï At full load, LNCFSô III lowered NOx emissions to

0.39 lb/106 Btu (compared to 0.64 lb/106 Btu for the

original burners)óa 39% reduction.

ï During diagnostic tests, LOI was above 4% at full

boiler load. During the validation tests (when overfireair limitations were relaxed), the LOI dropped by 0.7to 1.7 percentage points, with a minor effect on NOx

emissions.

Operationalï The cocurrent pumps had no measurable effect on

pressure drop, whereas the countercurrent pumpssignificantly increased the scrubber pressure drop.The average effect of each countercurrent header wasto increase pressure drop by 0.45 inches water column(w.c.) in the design flow tests and 0.64 inches w.c. inthe high-velocity tests.

ï Performance of a modified ESP with wider plate spacing and reduced plate area exceeded that of the original ESPs at lower power consumption.ï Boiler efficiency was 88.3ñ88.5% for LNCFSô III,

compared to a baseline of 89.3ñ89.6%.

ï Air infiltration was l

unaccounted for air lranging between 2.0ñ

ï The flue gas side pre

less than the design mprimary side pressure less than the design msecondary air side prwere less than the de

Economicï The capital cost (199

mated at $300 /kW fcapacity factor, 3.2% removal.

ï The annual operating 

(1998$); and the 15-$412/ton of SO2 rem

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Preaward Operation and Reporting

9/91 10/92

DOE selectedproject (CCT-IV)9/12/91

Cooperative agreement awarded 10/20/92

Design completed 4/93Ground breaking/construction started 4/93

NEPA process completed(EA) 8/18/93

10/

Operation completed 6/98

Operation initiated on Unit 2 1/95

6/95

Design and Construction

Environmental

monitoring

plan completed

12/1/94 Construction completed 6/95

Fully integrated operation of Units 1 and 2 initiated 6/95

P1
5-92 Program Update 2001 

Exhibit 5-40

Effect of Limestone Grind

Exh

Pressu

Countercu

Number of 

Scrubber Pressure Drop, inches w.c.

Project SummaryThe test plan was developed to cover all of the newtechnologies used in the project. In addition to the technologies tested, the project demonstrated that existingtechnologies can be used in conjunction with new processes to produce salable by-products. Supplementalmonitoring has provided operation and performance dataillustrating the success of these processes under a varietyof operating conditions. Generally, each test program wasdivided into four independent subtests: diagnostic, performance, long-term, and validation. (See Micronized CoalReburning Demonstration for NOx Control for another

CCT Program project at this unit.)Environmental PerformanceThe S-H-U FGD system was tested over a 36-month period. Typical evaluations included SO2 removal efficiency,

power consumption, process economics, load followingcapability, reagent utilization, by-product quality, andadditive effects. Parametric testing included formic acidconcentration, L/G ratio, mass transfer, coal sulfur content, and flue gas velocity. The maximum SO2 removal demonstrated was 98% with all seven recycle pumps operating and using formic acid, and the maximum SO2 removal without formic acid was 95%. The difference in SO2 removal between the two limestone grind sizes tested (90%ñ325 mesh and 90%ñ170 mesh), while using low- sulfur coal, was an average of 2.6 percentage points, as shown in Exhibit 5-40. The SO2 removal 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 gal/kacf. The cocurrent pumps had no mea- surable effect on pressure drop, whereas the countercur- rent pumps significantly increased the scrubber pressure drop. As seen in Exhibit 5-41, the average effect of each countercurrent header was to increase pressure drop by 0.45 inches water column (w.c.) in the design flow tests, and 0.64 inches w.c. in the high velocity tests. Performance of a modified ESP with wider plate spacing, reduced plate area, and reduced power consumption ex- ceeded that of the original ESP. The average particulate matter penetration before the

ESP modification was 0.22%and decreased to 0.12% afterthe modifications.At full boiler load (145ñ150 MWe) and 3.0ñ3.5%economizer O2, the LNCFSô

III lowered NOx emissions

from a baseline of 0.64 lb/106

Btu to 0.39 lb/106 Btu (39%

reduction). At 80- to 90-MWe boiler load and 4.3ñ5.0% economizer O2, the

LNCFSô III lowered NOx

emissions from a baseline of0.58 lb/106 Btu to 0.41 lb/106Btu (29% reduction). WithLNCFSô III, LOI was maintained below 4% and COemissions did not increase.

Operational PerformaThe S-H-U FGD system p

removal efficiency was acof producing a marketablFGD system was achievethe gypsum produced can exceeding 95% with a chHowever, the goal of prodchloride solution from the not achieved. The FGD awas 99.9%.The modified ESP has peESP at a lower power useuct (VïI) for ESPs is direpower requirement. The 75% of the VïI demand o
 Environmental Control Devices 

fied ESP has a smaller plant footprint with fewer internalsand a smaller SCA. Total internal plate area is less thanone-half that of the original ESPs, tending to lower capital costs.Boiler efficiency was 88.3–88.5% for LNCFSTM III, compared to a baseline of 89.3–89.6%. The lower efficiencywas attributed to higher post-retrofit flue gas excess O2requirement and higher stack temperatures which accompanied the air heater retrofit.The heat pipe was tested in accordance with ASMEPower Test Code for Air Heaters 4.3. Air infiltrationwas 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 forboth heat pipes was less than the design maximum of3.65 inches w.c. The primary side pressure drops forboth heat pipes were less than the design maximum of3.6 inches w.c. The secondary air side pressure dropsfor both heat pipes were less than the design maximumof 5.35 inches w.c.Economic PerformanceThe capital cost of the total FGD system in 1998 dollarsis estimated at $300/kW for a 300-MWe unit with a 65%capacity factor using 3.2% sulfur coal and achieving 95%sulfur removal. The annual operating cost is estimated at$4.62 million. The 15-year levelized cost is estimated at$412/ton of SO2 removed in 1998 constant dollars.

Commercial ApplicationsThe S-H-U process, Stebbins absorber module, andheat-pipe air preheater are applicable to virtually allpower plants. The space-saving design features of thetechnologies, combined with the production of marketable byproducts, offer significant incentives to generatingstations with limited space. Six modules of DHRTechnologies’ PEOATM system have been sold, with anestimated value of $210,000.

ContactsJim Harvilla, Project Manager, (607) 762-8630

New York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224jharville@nyseg.com(607) 762-8457 (fax)

James U. Watts, NETL, (412) 386-5991ReferencesMilliken Clean Coal Technology Demonstration Project:Project Performance and Economics Report, Final Report Volumes I & II. New York State Electric & Gas Corporation. October 1999.Comprehensive Report to Congress on the Clean CoalTechnology Program: Milliken Coal Technology Demonstration Project. New York State Electric & Gas Corporation. Report No. DOE/FE-0265P. U.S. Department ofEnergy. September 1992. (Available from NTIS asDE93001756.)Harvilla, James et al. “Milliken Clean Coal TechnologyDemonstration Project.” Sixth Clean Coal TechnologyConference: Clean Coal for the 21st Century—What Will

It Take? Volume II—Technical Papers. CONF-980410—VOL II. April 28–May 1, 1998.
5-94 Program Update 2001 

Environmental Control DevicesCombined SO2 / NOx Control TechnologyIntegrated Dry NOx/SO2Emissions Control SystemProject completedParticipantPublic Service Company of ColoradoAdditional Team MembersElectric Power Research Institute—cofunderStone and Webster Engineering Corp.—engineerThe Babcock & Wilcox Company—burner developerFossil Energy Research Corporation—operational testerWestern Research Institute—fly ash evaluatorColorado School of Mines—bench-scale engineering

researcher and tester

NOELL, Inc.—urea injection system providerLocationDenver, Denver County, CO (Public Service Company ofColorado’s Arapahoe Station, Unit No. 4)TechnologyThe Babcock & Wilcox Company’s DRB-XCL® low-NOxburners, in-duct sorbent injection, and furnace (urea)injectionPlant Capacity/Production100 MWeCoalColorado bituminous, 0.4% sulfurWyoming subbituminous (short test), 0.35% sulfurProject FundingTotal project cost $26,165,306 100%DOE 13,082,653 50Participant 13,082,653 50DRB-XCL is a registered trademark of The Babcock & WilcoxCompany.

Project ObjectiveTo demonstrate the integration of five technologies toachieve up to 70% reduction in NOx and SO2 emissions;

more specifically, to assess the integration of a downfired low-NO

x burner with in-furnace urea injection for

additional NO

x removal and dry sorbent in-duct injection

with humidification for SO2 removal.

Technology/Project DescriptionAll of the testing used Babcock & Wilcox’s low-NOx

DRB-XCL® down-fired burners with overfire air. These

burners control NO

x by injecting the coal and the combustion air in an oxygen-deficient environment. Additional air is introduced via overfire air ports to complete

the combustion process and further enhance NOx removal. A urea-based selective noncatalytic reduction

(SNCR) system was tested to determine how much additional NO

x can be removed from the combustion gas.

Two types of dry sorbents downstream of the boiler 

calcium-based sorbent waeconomizer, or sodium-baair heater. Humidification injection was incorporate

flue gas temperature and fabric filter dust collectorThe systems were installeColorado’s Arapahoe Stadown-fired, pulverized-coburners.
 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 

Calendar Year

Environmental Control Devices Results SummaryEnvironmental• DRB-XCL® burners with minimum overfire air reduced NO

x emissions by more than 63% under steady

state conditions.

• With maximum overfire air (24% of total combustion

air), a NOx reduction of 62–69% was achieved across

the 50- to 110-MWe load range.

• The SNCR system, using both stationary and retractable injection lances in the furnace, provided NOx

removal of 30–50% at an ammonia (NH3) slip of

10 ppm, thus increasing performance of the total NOx

control system to greater than 80% NOx reduction.

• SO2 removal with dry calcium hydroxide injection into

the boiler economizer at approximately 1,000 oF wasless than 10%; and with injection into the fabric filterduct, SO2 removal was less than 40% at a calcium/

sulfur (Ca/S) molar ratio of 2.0.

• Sodium bicarbonate injection before the air heater

demonstrated a long-term SO2 removal of approximately 70% at a normalized stoichiometric ratio (NSR) of 1.0. • Sodium sesquicarbonate injection ahead of the fabric filter achieved 70% SO2 removal at an NSR of 2.0. • NO2 emissions were generally higher when using so- dium bicarbonate than when using sodium sesquicarbonate. • Integrated SNCR and dry sodium-based sorbent injec- tion tests showed reduced NH3 and NO2 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. Availabil- ity factor was over 91%. • Control system modifications and additional operator training may be necessary to improve NOx control under load-following conditions. • Temperature differential between the top and bottom

surfaces of the Advanced Retractable Injection Lances

(ARIL) initially caus12–18 inches. Alternproblem.

Economic• When used on units b

nology offers SO2 an

wet scrubber and SC

• Total capital costs fo

$125/kW to $281/kW plants, respectively. 12.43–7.03 mills/kW

NO

x removed for 300

tively.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward Operation

Design and 8/92

Construction

12/89 3/91

NEPA process completed (MTF) 9/27/90

Design initiated 6/90

DOE selected project

(CCT-III) 12/19/89

Ground breaking/construction started 5/21/91

Design completed 3/92

Preoperational tests initiated 6/92

Construction completed 8/92Operation initiated 8/92

Environmental monitoring plancompleted 8/5/93

Cooperative agreement awarded 3/11/91
5-96 Program Update 2001 

Project SummaryThe Integrated Dry NOx/SO2 Emissions Control System

combines five major control technologies to form an integrated system to control both NOx and SO2. The low-NOx

combustion system consists of 12 Babcock & WilcoxDRB-XCL® low-NOx burners installed on the boiler roof.

The low-NO

x combustion system also incorporates three

Babcock & Wilcox dual-zone NO

x ports added to each

side of the furnace approximately 20 feet below the boilerroof. These ports inject up to 24% of the total combustion air through the furnace sidewalls.Additional NOx control was achieved using the ureabased SNCR system. The SNCR when used with the

low-NOx combustion system, allowed the goal of 70%

NOx reduction to be reached. Further, the SNCR system

was an important part of the integrated system, interactingsynergistically with the dry sorbent injection (DSI) system to reduce NO2 formation and ammonia slip.

Initially, the SNCR was designed and installed to incorporate two levels of injectors with 10 injectors at eachlevel. Levels were determined by temperature profilesthat existed with the original combustion system. However, the retrofit low-NOx combustion system resulted in a

decrease in furnace exit gas temperature of approximately200 oF, thus moving one injector level out of the temperature regime needed for effective SNCR operation. Withonly one operational injector level, load-following performance was compromised.In order to achieve the desirable NOx reduction at low

loads, two alternatives were explored. The first approachwas to substitute ammonia for urea. It was shown thatammonia was more effective than urea at low loads. Anon-line urea-to-ammonia conversion system was installedand resulted in improved low-load performance, but theimprovement was not as large as desired for the lowestload (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 lancesinto the furnace through two unused sootblower ports.Each lance was nominally 4 inches in diameter and approximately 20 feet in length with a single row of nineinjection nozzles. Each injection nozzle consisted of afixed air orifice and a replaceable liquid orifice. The

Public Service Company of Colorado demonstrated low-NOxburners, in-duct sorbent injection, and SNCR at ArapahoeStation near Denver, Colorado.ability to change orifices allowed for not only removaland cleaning but also adjustment of the injection patternalong the length of the lance to compensate for any significant maldistributions of flue gas velocity, temperature,or baseline NOx concentration. One of the key features of

the ARIL system was its ability to rotate, thus providing ahigh degree of flexibility in optimizing SNCR performance.The SO2 control system was a direct sorbent injection

system that could inject either calcium- or sodium-basedreagents into the flue gas upstream of the fabric filter.Sorbent was injected into three locations: (1) air heaterexit where the temperature was approximately 260 oF, (2)air heater entrance where the temperature was approximately 600 oF, or (3) the boiler economizer region wherethe flue gas temperature was approximately 1,000 oF. Toimprove SO2 removal with calcium hydroxide, a humidification system capable of achieving 20 oF approach-tosaturation 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 80gal/min into the flue gas duct work.Environmental PerformanceThe combined DRB-XCL® burner and minimum overfire

air reduced NOx emissions by over 63% under steady

state conditions and with Under load-following con

about 10–25% higher. At total combustion air), the 

reduced NOx emissions b

(60- to 110-MWe). The r

burners were responsible 

The original design of twproved relatively ineffectwas in a region where the low for effective operatiodesign achieved a NOx re

performance decreased si60-MWe, NOx removal w

ammonia slip of 10 ppm. lances improved low-load SNCR injection system. perature window by rotatibe an important feature in result, the SNCR system 

range of 30–50% (at a NH

fabric filter inlet), increas

greater than 80%, signific70%.Testing of calcium hydroxwithout humidification re

range of 5–8% at a Ca/S m

removal was achieved wihydroxide and humidifica

proaching 40% at a Ca/S 20–30 oF approach-to-satwere found to be much msorbents and achieved sig

during dry injection. Sodbefore the air heater demo

als of 80%. Long-term rewith an NSR of 1.0. Sod70% removal at an NSR ofabric filter. A disadvantawas that it converted som

though 5–10% of the NO

sion process, the net NO2 

creased. While NO is colbrown/orange NO2 caused 
 Environmental Control Devices 

A major objective was the demonstration of the integratedperformance of the NOx emissions control systems and

the SO2 removal technologies. The results showed that a

synergistic benefit occurred during the simultaneous operation of the SNCR and the sodium DSI system in thatthe NH3 slip from the SNCR process suppressed the NO2

emissions associated with NO-to-NO2 oxidation by dry

sodium injection.Operating PerformanceThe Arapahoe Unit No. 4 operated more than 34,000hours with the combustion modifications in place. Theavailability factor during the period was over 91%. Theoperational test objectives were met or exceeded. However, there were operational lessons learned during thedemonstration that will be useful in future deployment ofthe technologies.During the operation of the duct injection of calciumhydroxide and humidification under load-following conditions, the fabric filter pressure-drop significantly increased. This was caused by the buildup of a hard ashcake on the fabric filter bags that could not be cleanedunder normal reverse-air cleaning. The heavy ash cakewas caused by the humidification system, but it was notdetermined whether the problem was due to operation at30 oF approach-to-saturation temperature or an excursioncaused by a rapid decrease in load.The performance of the ARIL lances in NOx removal was

good; however, the location created some operationalproblems. A large differential heating pattern between thetop and bottom of the lance caused a significant amountof thermal expansion along the upper surface of the lance.This caused the lance to bend downward approximately12–18 inches after 30 minutes of exposure. Eventuallythe lances become permanently bent, thus making insertion and retraction difficult. The problem was partiallyresolved by adding cooling slots at the end of the lance.An alternative lance design provided by Diamond PowerSpecialty Company (a division of Babcock & Wilcox)was tested and found to have less bending due to evaporative cooling, even though its NOx reduction and NH3

slip performance dropped relative to the ARIL lance.

When the SNCR and dry sodium systems were operatedconcurrently, an NH3 odor problem was encountered

around the ash silo. Reducing the NH3 slip set points to

the range of 4–5 ppm reduced the ammonia concentrationin the fly ash to the 100–200 ppm range, but the odorpersisted. It was found that the problem was related tothe rapid change in pH due to the presence of sodium inthe ash. The rapid development of the high pH level andthe attendant release of the ammonia vapor appear to berelated to the wetting of the fly ash necessary to minimizefugitive dust emissions during transportation and handling. Handling ash in dry transport trucks solved thisproblem.Economic PerformanceThe technology is an economical method of obtainingSO2 and NOx reduction on low-sulfur coal units. Total

estimated capital costs range from 125–281 $/kW forcapacities ranging from 300–50 MWe. Comparably, wetscrubber and SCR capital costs range from 270–474 $/kW for the same unit size range. On a levelizedcost basis, the demonstrated system costs vary from12.43–7.03 mills/kWh (1,746–987 $/ton of SO2 and NOx

removed) compared to wet scrubber and SCR levelizedcosts of 23.34–12.67 mills/kWh (4,974–2,701 $/ton ofSO2 and NOx removed) based on 0.4% sulfur coal. The

integrated system is most efficient on smaller low-sulfurcoal units. As size and sulfur content increase, the costadvantages decrease.Commercial ApplicationsEither the entire Integrated Dry NOx/SO2 Emissions Control System or the individual technologies are applicable

to most utility and industrial coal-fired units and providelower capital-cost alternatives to conventional wet fluegas desulfurization processes. They can be retrofittedwith modest capital investment and downtime, and theirspace requirements are substantially less. They can beapplied to any unit size but are mostly applicable to theolder, small- to mid-size units.

ContactsTerry Hunt, Production 

Xcel Energy4653 Table Mountain Golden, CO 80402

Jerry L. Hebb, NETL, (4ReferencesPublic Service Company NO

x 

/SO2 Emissions Con

ume 1: Public Design. Public Service Company NO

x 

/SO2 Emissions Con

ume 2: Project PerformSeptember 1999.
5-98 Program Update 2001 
Advanced Electric Power Generation 

Advanced Electric Power Gene

Fluidized-Bed Combustion
5-100 Program Update 2001 Adva

McIntosh Unit 4A PCFBDemonstration ProjectParticipantCity of Lakeland, Lakeland ElectricAdditional Team MembersFoster Wheeler Corporation—supplier of pressurized

circulating fluidized-bed (PCFB) combustor and heatexchanger; engineer

Siemens Westinghouse Power Corporation—supplier of

hot gas filter, gas turbine, and steam turbine

LocationLakeland, Polk County, FL (Lakeland Electric’s McIntoshPower Station, Unit No. 4)TechnologyFoster Wheeler’s PCFB technology integrated with Siemens Westinghouse’s hot gas particulate filter system(HGPFS) and power generation technologiesPlant Capacity/Production137 MWe (net)CoalEastern Kentucky and high-ash, high-sulfur bituminouscoalsProject FundingTotal project cost $186,588,000 100%DOE 93,252,864 50Participant 93,335,136 50Project ObjectiveTo demonstrate Foster Wheeler’s PCFB technologycoupled with Siemens Westinghouse’s ceramic candletype HGPFS and power generation technologies, whichrepresent a cost-effective, high-efficiency, low-emissionsmeans of adding generating capacity at greenfield sites orin repowering applications.Advanced Electric Power GenerationFluidized-Bed Combustion

Technology/Project DescriptionIn the first of the two Lakeland Electric projects, McIntosh Unit No. 4A will be constructed with a PCFBcombustor adjacent to the existing Unit No. 3 (see alsoMcIntosh Unit 4B Topped PCFB Demonstration Project).Coal and limestone are mixed and fed into the combustion chamber. Combustion takes place at a temperature ofapproximately 1,560–1,600 °F and a pressure of about200 psig. The resulting flue gas and fly ash leaving thecombustor pass through a cyclone and ceramic candletype HGPFS where the particulates are removed. The hotgas leaving the HGPFS is expanded through a SiemensV64.3 gas turbine. The gas inlet temperature of less than1,650 °F allows for a simplified turbine shaft and bladecooling system. The hot gas leaving the gas turbine passesthrough a heat recovery steam generator (HRSG). Heatrecovered from both the combustor and HRSG is used to

generate steam to power a mately 5–10% of the powbine, with the steam turbiproject also includes an athat can be fired on coal owill replace the PCFB unability, allowing various mThe projected net heat ratmately 9,480 Btu/kWh (Hefficiency greater than 36include in-situ sulfur rem

than 0.3 lb/106 Btu, and p

than 0.03 lb/106 Btu. Soli

compared to conventionareadily disposable or pote
 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 

Calendar Year

Advanced Electric Power Generation Project Status/AccomplishmentsThe project resulted from a restructuring of the DMEC-1PCFB Demonstration Project awarded under CCT-III. OnDecember 19, 1997, a Cooperative Agreement modification was signed implementing the project restructuringfrom DMEC-1 to the City of Lakeland. The LakelandCity Council gave approval in April 1998 for the 10-yearplan of Lakeland Electric (formerly Department of Electric & Water Utilities), which included this project.However, the project is on hold while technical andeconomic issues are resolved.Efforts have been focused on testing the HGPFS, which iscritical to system performance. Silicon carbide and alumina/mullite candle filters proved effective under conditions simulating those of the demonstration unit. At both1,550 oF and 1,400 oF, the candle filters performed forover 1,000 hours at design levels without evidence of ashbridging or structural failure. Three new oxide-basedcandle filters showed promise as well and will undergofurther testing because of the potential for reduced costand operation at higher temperatures.

Commercial ApplicationsThe project serves to demonstrate the PCFB technologyfor widespread commercial deployment and will includethe first commercial application of hot gas particulatecleanup and will be one of the first to use a non-ruggedized gas turbine in a pressurized fluidized-bedapplication.The combined-cycle PCFB system permits the combustion of a wide range of coals, including high-sulfur coals,and would compete with the pressurized bubbling-bedfluidized-bed system. The PCFB technology can be usedto repower or replace conventional power plants.Because of modular construction capability, PCFB generating plants permit utilities to add economical incrementsof capacity to match load growth or to repower plantsusing existing coal- and waste-handling equipment andsteam turbines. Another advantage for repowering applications is the compactness of the equipment due to pressurized operation, which reduces space requirements perunit of energy generated.

1989 1996 1997 1990 1991 1998 1999 2000 2001 

12/89

DOE selected project(CCT-III) 12/19/89

Cooperative agreementawarded 8/1/91

Design and Construction

8/91

Site change approved(Lakeland) 10/29/96

Preaward

Cooperative agreement

signed 12/19/97

NEPA process started 3/99

Project on Hold

**
5-102 Program Update 2001 Adva

Advanced Electric Power GenerationFluidized-Bed CombustionMcIntosh Unit 4B ToppedPCFB Demonstration ProjectParticipantCity of Lakeland, Lakeland ElectricAdditional Team MembersFoster Wheeler Corporation—supplier of carbonizer;

engineer

Siemens Westinghouse Power Corporation—supplier of

topping combustor and high-temperature filter

LocationLakeland, Polk County, FL (Lakeland Electric’s McIntoshPower Station, Unit No. 4)TechnologyFully integrated second-generation PCFB technology withthe addition of a carbonizer island that includes SiemensWestinghouse’s multi-annular swirl burner (MASB) topping combustorPlant Capacity/Production103-MWe (net) addition to the 137-MWe (net) McIntosh4A projectCoalEastern Kentucky and high-ash, high-sulfur bituminouscoalsProject FundingTotal project cost $219,635,546 100%DOE 109,608,507 50Participant 110,027,039 50Project ObjectiveTo demonstrate topped PCFB technology in a fully commercial power generation setting, thereby advancing thetechnology for future plants that will operate at higher gasturbine inlet temperatures and will be expected to achievecycle efficiencies in excess of 45%.

Technology/Project DescriptionThe project involves the addition of a carbonizer island tothe PCFB demonstrated in the McIntosh 4A project.Dried coal and limestone are fed via a lock hopper systemto the carbonizer with part of the gas turbine dischargeair. The coal is partially gasified at about 1,750–1,800 oFto produce syngas and char solids streams. The limestoneis used to absorb sulfur compounds generated during themild gasification process. After cooling the syngas toabout 1,200 oF, the char and limestone entrained with thesyngas are removed by a hot gas particulate filter system(HGPFS). The char and limestone are then transferred tothe PCFB combustor for complete carbon combustion andlimestone utilization. The hot, cleaned, filtered syngas isthen fired in the MASB topping combustor to raise theturbine inlet temperature to approximately 2,350 °F. Thegas is expanded through the turbine, cooled in a heat

recovery steam generatornet impact of the addition crease in both power outplimestone used in McIntoin McIntosh 4A.The 240-MWe (net) plant of 8,406 Btu/kWh (40.6% SO2 capture efficiency rat

emissions are expected to 

106 Btu, respectively. In t

turbine will produce 58 Mproduce 207 MWe, while about 25 MWe.
 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 

Calendar Year

Advanced Electric Power Generation Project Status/AccomplishmentsThe project resulted from a restructuring of the Four Rivers Energy Modernization Project awarded under the fifthsolicitation. The Four Rivers project was to demonstratethe integration of a carbonizer (gasifier) and topping combustor (topping cycle) with the PCFB technology. Byusing a phased approach, Lakeland Electric will be able todemonstrate 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 restructuringfrom Four Rivers Energy Partners to the City of Lakeland.The Lakeland City Council gave approval in April 1998for the 10-year plan of Lakeland Electric (formerly Department of Electric & Water Utilities), which includedthis project. However, the project is on hold while technical and economic issues are resolved.Recent efforts focused on testing the HGPFS, which iscritical to system performance. Silicon carbide andalumina/mullite candle filters proved effective underconditions simulating those of the demonstration unit. Atboth 1,550 oF and 1,400 oF, the candle filters performed

for over 1,000 hours at design levels without evidence ofash bridging or structural failure. Three new oxide-basedcandle filters showed promise as well. These will undergofurther testing because of the potential for reduced costand operation at higher temperatures.Commercial ApplicationsThe commercial version of the topped PCFB technologywill have a greenfield net plant efficiency of 45% (whichequates to a heat rate approaching 7,500 Btu/kWh,HHV). In addition to higher plant efficiencies, the plantwill (1) have a cost of electricity that is projected to be20% lower than that of a conventional pulverized coalfired plant with flue gas desulfurization, (2) meet emission limits allowed by the New Source Performance Standard (NSPS), (3) operate economically on a wide range ofcoals, and (4) be amenable to shop fabrication. The benefits of improved efficiency include reduced cost for fuelsand a reduction in CO2 emissions.

The commercial version of the topped PCFB technologyhas other environmental attributes, which include in-situsulfur retention that can meet 95% removal requirements,NO

x emissions that will meet or exceed NSPS, and particulate matter discharge 

Btu. Although the system in solid waste compared material is a dry, readily able material.

1993 1996 1997 1994 1995 1998 1999 2000 2001 

5/93

DOE selected project(CCT-V) 5/4/93

Cooperative agreement awarded7/28/94; effective 8/1/94

Design and Construction

Site change approved(Lakeland) 10/29/96

Projec

8/94

Preaward

Cooperative agreementsigned 1/29/98

NEPA processstarted 3/99
5-104 Program Update 2001 Adva

Advanced Electric Power GenerationFluidized-Bed CombustionJEA Large-Scale CFBCombustion DemonstrationProjectParticipantJEA (formerly Jacksonville Electric Authority)Additional Team MembersFoster Wheeler Energy Corporation—technology supplierLocationJacksonville, Duval County, FL (JEA’s Northside Station,Unit No. 2)TechnologyFoster Wheeler’s atmospheric circulating fluidized-bed(ACFB) combustorPlant Capacity/Production297.5 MWe (gross), 265 MWe (net)CoalEastern bituminous, 3.39% sulfur (design)Project FundingTotal project cost $309,096,512 100%DOE 74,733,633 24Participant 234,362,679 76Project ObjectiveTo demonstrate ACFB at 297.5 MWe gross (265 MWenet) representing a scaleup from previously constructedfacilities; to verify expectations of the technology’s economic, environmental, and technical performance; toprovide potential users with the data necessary for evaluating a large-scale ACFB as a commercial alternative; toaccomplish greater than 90% SO2 removal; and to reduce

NO

x emissions by 60% when compared with conventional

technology.Technology/Project DescriptionA circulating fluidized-bed combustor, operating at atmospheric pressure, will be retrofitted into Unit No. 2 of the

Northside Station. In this process coal or the secondaryfuel (petroleum coke), primary air, and a solid sorbent(such as limestone), are introduced into the lower part ofthe combustor where initial combustion occurs. As thecoal particles decrease in size due to combustion, they arecarried higher in the combustor when secondary air isintroduced. As the coal particles continue to be reduced insize, the coal, along with some of the sorbent, is carriedout of the combustor, collected in a cyclone separator, andrecycled to the lower portion of the combustor. Primarysulfur capture is achieved by the sorbent in the bed. However, additional SO2 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’swalls and superheated in tube bundles placed downstreamof the particulate separator to protect against erosion. The

system will produce appr

steam at about 2,500 psig 

lb/hr of reheat steam at 60will be used in an existing turbine.The heat rate for the retroproximately 9,950 Btu/kWExpected environmental p

for SO2 (98% reduction), 

0.011 lb/106 Btu for total 

for PM10).
 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 

Calendar Year

Advanced Electric Power Generation Project Status/AccomplishmentsThe project was successfully resited to Jacksonville,Florida after York County Energy Partners and Metropolitan Edison Company terminated activities on the ACFBproject in September 1996. On August 26, 1997, DOEapproved the transfer of the ACFB Clean Coal Projectfrom York, Pennsylvania to Jacksonville, Florida. OnSeptember 29, 1997, DOE signed a modified cooperativeagreement with JEA to cost-share refurbishment of thefirst (Unit No. 2) of two units at Northside GeneratingStation.The Environmental Impact Statement (EIS) process wasinitiated on December 3, 1997 with the Public ScopingMeeting. Following the NEPA process of public commentand review, the final draft EIS was prepared and approvedby DOE. After incorporating comments and obtainingformal approval, the EIS was issued on June 30, 2000.Public comments were addressed and the Record of Decision was issued December 7, 2000. As of September 30,2001, construction is more than 90 percent complete. Bythe time of publication of this report, construction isscheduled to be completed and operations started.

The project moves atmospheric fluidized-bed combustiontechnology to the larger sizes of utility boilers typicallyconsidered in capacity additions and replacements. Thenominal 300-MWe demonstration unit in the JEA projectwill be more than double the size of the Nucla unit(110-MWe). Features include an integrated recycle heatexchanger (INTREXTM) in the furnace, steam-cooledcyclones, a parallel pass reheat control, an SO2 polishing

scrubber, and a fabric filter for particulate control.Commercial ApplicationsACFB technology has good potential for application inboth the industrial and utility sectors, whether for use inrepowering existing plants or in new facilities. ACFB isattractive for both baseload and dispatchable power applications because it can be efficiently turned down to 25%of full load. While the efficiency of ACFB is on par withconventional pulverized coal-fired plants, the advantageof ACFB is that coal of any sulfur or ash content can beused, and any type or size unit can be repowered. In repowering applications, an existing plant area is used, andcoal- and waste-handling equipment, as well as steamturbine equipment are retained, thereby extending the lifeof the plant.

In its commercial configseveral potential benefittional pulverized coal-fireduced SO2 and NOx em

combustion efficiency; a (including use of renewby-product material that tially salable.

Envircompstarte

1989 1990 1992 1993 1995 1997 1999 2000 2001 

Preaward

6/89

11/90

DOE selectedproject (CCT-I)6/23/89

 

Cooperative agreementawarded 11/30/90

Project restructured 6/92

Project sited

(York) 6/93

Project restructured and resited

(Jacksonville) 8/26/97

**  **

Design and Construction

NEPA process completed

(EIS York site) 8/11/95

Cooperative agreement modified 9/29/97

Project com

Pre-construction

started

8/99

NEPA process completed (EIS Jacksonville site);

design completed;

construction started 12/00
5-106 Program Update 2001 Adva

Advanced Electric Power GenerationFluidized-Bed CombustionTidd PFBC DemonstrationProjectProject completedParticipantThe Ohio Power CompanyAdditional Team MembersAmerican Electric Power Service Corporation—designer,

constructor, and manager

The Babcock & Wilcox Company—technology supplierOhio Coal Development Office—cofunderLocationBrilliant, Jefferson County, Ohio (Ohio Power Company’sTidd Plant, Unit No. 1)TechnologyThe Babcock & Wilcox Company’s pressurized fluidizedbed combustion (PFBC) system (under license from ABBCarbon)Plant Capacity/Production70 MWe (net)CoalOhio bituminous, 2–4% sulfurProject FundingTotal project cost $189,886,339 100%DOE 66,956,993 35Participant 122,929,346 65Project ObjectiveTo verify expectations of PFBC economic, environmental,and technical performance in a combined-cycle repowering application at utility scale; and to accomplish greaterthan 90% SO2 removal and NOx emission level of 0.2 lb/

106 Btu at full load.

Technology/Project DescriptionTidd was the first large-scale operational demonstrationof PFBC in the United States. The project represented a13:1 scaleup from the pilot facility.

The boiler, cyclones, bed reinjection vessels, and associated hardware were encapsulated in a pressure vessel 45feet in diameter and 70 feet high. The facility was designed so that one-seventh of the hot gases producedcould be routed to an advanced particulate filter (APF).The Tidd facility used a bubbling fluidized-bed combustionprocess operating at 12 atm (175 psi). Pressurized combustion air is supplied by the turbine compressor to fluidize thebed material, which consists of a coal-water fuel paste, coalash, and a dolomite or limestone sorbent. Dolomite orlimestone in the bed reacts with sulfur to form calciumsulfate, a dry, granular bed-ash material, which is easilydisposed of or is usable as a by-product. A low bed temperature of about 1,600 oF limits NOx formation.

The hot combustion gases exit the bed vessel with entrained ash particles, 98% of which are removed when thegases pass through cyclones. The cleaned gases are then

expanded through a 15-Mgases exiting the turbine, bundle in the fluid bed, ging 55-MWe steam turbin
 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 

Calendar Year

Advanced Electric Power Generation Results SummaryEnvironmental• Sorbent size had the greatest effect on SO2 removal

efficiency as well as stabilization and heat transfercharacteristics of the fluidized-bed.

• SO2 removal efficiency of 90% was achieved at full

load with a calcium-to-sulfur (Ca/S) molar ratio of1.14 and temperature of 1,580 oF.

• SO2 removal efficiency of 95% was achieved at full

load with a Ca/S molar ratio of 1.5 and temperature of1,580 oF.

• NO

x

 emissions were 0.15–0.33 lb/106 Btu.

• CO emissions were less than 0.01 lb/106 Btu.

• Particulate emissions were less than 0.02 lb/106 Btu.

Operational• Combustion efficiency ranged from an average 99.3%

at low bed levels to an average 99.5% at moderate tofull bed levels.

• Heat rate was 10,280 Btu/kWh (HHV, gross output)

(33.2% efficiency) because the unit was small and noattempt was made to optimize heat recovery.

• An advanced particulate filter (APF), using a silicon

carbide candle filter array, achieved 99.99% filtrationefficiency 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 partof this project.

• A recent cost estimate performed on Japan’s 360-MWe

PFBC Karita Plant projected a capital cost of$1,263/kW (1997$).

1986 1987 1988 1989 1990 1991 1992 1993 1994 

Design and Construction Operation and Reporting

3/87

Cooperative agreement awarded 3/20/87NEPA process completed (MTF) 3/5/87

Environmental monitoringplan completed 5/25/88

Ground breaking ceremony 4/6/88

Construction started 12/9/87

Operation initiated 3/91

Design completed 12/90Construction completed 12/90Preoperational tests started 12/90

3/91

DOE selected project (CCT-I) 7/24/86

7/86

Preaward
5-108 Program Update 2001 Adva

Project SummaryThe Tidd PFBC technology is a bubbling fluidized-bedcombustion process operating at 12 atmospheres (175psi). Fluidized-bed combustion is inherently efficientbecause the pressurized environment enhances combustion efficiency, allows very low temperatures that mitigatethermal NOx generation, promotes flue gas/sorbent reactions that increase sorbent utilization, and produces flue

gas energy that is used to drive a gas turbine. The lattercontributed significantly to system efficiency because ofthe high efficiency of gas turbines and the availability ofgas turbine exhaust heat that can be applied to the steamcycle. A bed design temperature of 1,580 oF was established because it was the maximum allowable temperatureat the gas turbine inlet and was well below temperaturesfor coal ash fusion, thermal NOx formation, and alkali

vaporization.Coal crushed to one-quarter inch or less was injected intothe combustor as a coal/water paste containing 25% waterby weight. Crushed sorbent, either dolomite or limestone,was injected into the fluidized bed via two pneumaticfeed lines, supplied from two lock hoppers. The sorbentfeed system initially used two injector nozzles but wasmodified to add two more nozzles to enhance distribution.In 1992, a 10-MWe equivalent APF was installed andcommissioned as part of a research and developmentprogram and not part of the CCT Program demonstration.This system used ceramic candle filters to clean oneseventh of the exhaust gases from the PFBC system. Thehot gas cleanup system unit replaced one of the sevensecondary cyclones.The Tidd PFBC demonstration plant accumulated 11,444hours of coal-fired operations during its 54 months ofoperation. The unit completed 95 parametric tests, including continuous coal-fired runs of 28, 29, 30, 31, and 45days. Ohio bituminous coals having sulfur contents of 2–4% were used in the demonstration.Environmental PerformanceTesting showed that 90% SO2 capture was achievable

with a Ca/S molar ratio of 1.14 and that 95% SO2 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 bedtemperature of 1,580 oF and full bed height. Limestoneinduced deterioration of the fluidized-bed, and as a result,testing focused on dolomite. The testing showed thatsulfur capture as well as sintering was sensitive to thefineness of the dolomite sorbent (Plum Run Greenfielddolomite was the design sorbent). Sintering of fluidizedbed materials, a fusing of the materials rather than effective reaction, had become a serious problem that requiredoperation at bed temperatures below the optimum foreffective boiler operation. Tests were conducted withsorbent size reduced from minus 6 mesh to a minus 12mesh. The result with the finer material was a major positive impact on process performance without the expectedexcessive elutriation of sorbent. The finer material increased the fluidization activity as evidenced by a 10%improvement in heat transfer rate and an approximately30% increase in sorbent utilization. In addition, the process was much more stable as indicated by reductions intemperature variations in both the bed and the evaporatortubes. Furthermore, sintering was effectively eliminated.NOx emissions ranged from 0.15–0.33 lb/106 Btu, but

were typically 0.2 lb/106 Btu during the demonstration.

These emissions were inherent in the process, which wasoperating at approximately 1,580 oF. No NOx control

enhancements, such as ammonia injection, were required.Emissions of carbon monoxide and particulates were lessthan 0.01 and 0.02 lb/106 Btu, respectively.

Operational PerformanceExcept for localized erosion of the in-bed tube bundle andthe more general erosion of the water walls, the Tiddboiler performed extremely well and was considered acommercially viable design. The in-bed tube bundle experienced no widespread erosion that would require significant maintenance. While the tube bundle experiencedlittle wear, a significant amount of erosion on each of thefour water walls was observed. This erosion posed noproblem, however, because the area affected is not criticalto heat transfer and could be protected by refractory.The prototype gas turbine experienced structural problems and was the leading cause of unit unavailabilityduring the first 3 years of operation. However, design

changes instituted over thproved effective in addresdemonstration showed tha PFBC flue gas environmEfficiency of the PFBC clated during testing from in cyclone and bed ash, tothe amount of carbon motion efficiencies averaged heights, surpassing the deUsing data for typical full10,280 Btu/kWh (HHV bsponds to a cycle thermodpoint where the cycle procal power while burning Pthe Tidd plant was a repotively small scale, the mesent what would be expecplant using Tidd technoloPFBC Utility Demonstrat

The PFBC demonstration aOhio Power’s Tidd Plant led understanding of the techno
Advanced Electric Power Generation 

cies of over 40% are likely for a larger, utility-scale PFBCplant.In summary, the Tidd project showed that the PFBCsystem could be applied to electric power generation.Further, the demonstration project led to significant refinements and understanding of the technology in theareas 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-firedoperation showed that the APF vessel was structurallyadequate; the clay-bonded silicon carbide candle filterswere structurally adequate unless subjected to side loadsfrom ash bridging or buildup in the vessel; bridging wasprecluded with larger particulates included in the particulate matter; and filtration efficiency (mass basis) was99.99%.Economic PerformanceThe Tidd plant was a relatively small-scale demonstrationfacility, so detailed economics were not prepared as partof this project. However, a recent cost estimate performedon Japan’s 360-MWe PFBC Karita Plant projected a capital cost of $1,263/kW (1997$).Commercial ApplicationsCombined-cycle PFBC permits use of a wide range ofcoals, including high-sulfur coals. The compactness ofbubbling-bed PFBC equipment allows utilities to significantly increase capacity at existing sites. Compactnessdue to pressurized operation reduces space requirementsper unit of energy generated. PFBC technology appears tobe best suited for applications of 50 MWe or larger. Capable of being constructed modularly, PFBC generatingplants permit utilities to add increments of capacity economically to match load growth. Plant life can be extended by repowering with PFBC using the existing plantarea, coal- and waste-handling equipment, and steamturbine equipment.The 360-MWe Karita Plant in Japan, which uses ABBCarbon P800 technology, represents a major move towardcommercialization of PFBC bubbling-bed technology. Asecond-generation P200 PFBC is under construction inGermany. Other PFBC projects are under consideration inChina, South Korea, the United Kingdom, Italy, and Israel.

The Tidd project received Power magazine’s 1991

Powerplant Award. In 1992, the project received theNational Energy Resource Organization award for demonstrating energy efficient technology.ContactsMichael J. Mudd, (614) 223-1585

American Electric Power1 Riverside PlazaColumbus, OH 43215mjmudd@aep.com(614) 223-1292 (fax)

George Lynch, DOE/HQ, (301) 903-9434Donald W. Geiling, NETL, (304) 285-4784References• Tidd PFBC Hot Gas Cleanup Program Final Report.

Report No. DOE/MC/26042-5130. The Ohio PowerCompany. October 1995. (Available from NTIS asDE96000650.)

• Tidd PFBC Demonstration Project Final Report, Including Fourth Year of Operation. The Ohio Power

Company. August 1995. (Available from DOE Library/

Morgantown, 1-800-DE96000623.)

• Tidd PFBC Demonst

March 1, 1994–MarcMC/24132-T8. The O1995. (Available from 

• Tidd PFBC Demonst

of Operation. Report 1 and 2. The Ohio Po(Available from NTIDE96003781 for Vol

Coal and sorbent conveyors can be seen just after enteringthe Tidd plant.
5-110 Program Update 2001 Adva

Advanced Electric Power GenerationFluidized-Bed CombustionNucla CFB DemonstrationProjectProject completedParticipantTri-State Generation and Transmission Association, Inc.Additional Team MembersFoster Wheeler Energy Corporation*—technology

supplier

Technical Advisory Group (potential users)—cofunderElectric Power Research Institute—technical consultantLocationNucla, Montrose County, CO (Nucla Station)TechnologyFoster Wheeler’s atmospheric circulating fluidized-bed(ACFB) combustion systemPlant Capacity/Production110 MWe (gross), 100 MWe (net)CoalWestern bituminous—

Salt Creek, 0.5% sulfur, 17% ashPeabody, 0.7% sulfur, 18% ashDorchester, 1.5% sulfur, 23% ash

Project FundingTotal project cost $160,049,949 100%DOE 17,130,411 11Participant 142,919,538 89Project ObjectiveTo demonstrate the feasibility of ACFB technology atutility scale and to evaluate the economic, environmental,and operational performance at that scale.

Technology/Project DescriptionNucla’s circulating fluidized-bed system operates at atmospheric pressure. In the combustion chamber, a stream ofair fluidizes and entrains a bed of coal, coal ash, and sorbent (e.g., limestone). Relatively low combustion temperatures limit NOx formation. Calcium in the sorbent

combines with SO2 gas to form calcium sulfite and sulfate

solids, and solids exit the combustion chamber and flowinto a hot cyclone. The cyclone separates the solids fromthe gases, and the solids are recycled for combustor temperature control. Continuous circulation of coal and sorbent improves mixing and extends the contact time ofsolids and gases, thus promoting high utilization of thecoal and high sulfur-capture efficiency. Heat in the fluegas exiting the hot cyclone is recovered in the economizer. Flue gas passes through a baghouse where

particulate matter is remoACFB is used to produce Three small, coal-fired, stStation were replaced witsteam generator capable oturbine generator. Extracterator powers three existiMWe gross each).

* Pyropower corporation, the original technology developer andsupplier, was acquired by Foster Wheeler Energy Corporation.
 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 

Calendar Year

Advanced Electric Power Generation Results SummaryEnvironmental• Bed temperature had the greatest effect on pollutant

emissions and boiler efficiency.

• At bed temperatures below 1,620 oF, 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, NOx emissions averaged

0.18 lb/106 Btu and did not exceed 0.34 lb/106 Btu.

• CO emissions ranged from 70–140 ppmv.• Particulate emissions ranged from 0.0072–0.0125 lb/

106 Btu, corresponding to a removal efficiency of

99.9%.

• Solid waste was essentially benign and showed potential as an agricultural soil amendment, soil/roadbed

stabilizer, or landfill cap.

Operational• Boiler efficiency ranged from 85.6–88.6% and combustion 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

normalized power production cost was 64 mills/kWh.

1987 1988 1989 1990 1991 1992 1993 1994 1995 

Preaward Operation and Reporting

10/87 10/88

DOE selectedproject (CCT-I)10/7/87

Environmental monitoringplan completed 2/27/88

NEPA process completed (MTF) 4/18/88

Operationcompleted 1/91

Operation test program initiated 8/88

Cooperative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92
5-112 Program Update 2001 Adva

Project SummaryFluidized-bed combustion evolved from efforts to find acombustion process conducive to controlling pollutantemissions without external controls. Fluidized-bed combustion enables efficient combustion at temperatures of1,400–1,700 oF, well below the thermal NOx formationtemperature (2,500 oF), and enables high SO2-capture

efficiency through effective sorbent/flue gas contact.ACFB differs from the more traditional fluid-bed combustion. Rather than submerging a heat exchanger in thefluid bed, which dictates a low fluidization velocity,ACFB uses a relatively high fluidization velocity, whichentrains the bed material. Hot cyclones capture and returnthe solids emerging from the turbulent bed to controltemperature, extend the gas/solid contact time, and 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 applicationthrough a comprehensive test program. Over a two-and-ahalf-year period, 72 steady-state performance tests wereconducted and 15,700 hours logged. The result was adatabase that remains the most comprehensive availableresource on ACFB technology.Operational PerformanceBetween July 1988 and January 1991, the plant operatedwith an average availability of 58% and an average capacity factor of 40%. However, toward the end of the demonstration, most of the technical problems had been overcome. During the last three months of the demonstration,average availability was 97% and the capacity factor was66.5%.Over the range of operating temperature at which testingwas performed, bed temperature was found to be the mostinfluential operating parameter. With the exception ofcoal-fired configuration and excess air at elevated temperatures, bed temperature was the only parameter thathad a measurable impact on emissions and efficiency.Combustion efficiency, a measure of the quantity of carbon that is fully oxidized to CO2, 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 thebottom ash stream, and the remaining feed-carbon loss(2%) was incompletely oxidized CO in the flue gas. Thefourth possible source, hydrocarbons in the flue gas, wasmeasured and found to be negligible.Boiler efficiencies for 68 performance tests varied from85.6–88.6%. The contributions to boiler heat loss wereidentified as unburned carbon, sensible heat in dry fluegas, fuel and sorbent moisture, latent heat in burninghydrogen, sorbent calcination, radiation and convection,and bottom-ash cooling water. Net plant heat rate decreased with increasing boiler load, from 12,400 Btu/kWhat 50% of full load to 11,600 Btu/kWh at full load. Thelowest value achieved during a full-load steady-state testwas 10,980 Btu/kWh. These values were affected by theabsence of reheat, the presence of the three older 12.5-MWe turbines in the overall steam cycle, the number ofunit restarts, and part-load testing.

Environmental PerforAs indicated above, bed timpact on ACFB performsions. Exhibit 5-42 shows on the Ca/S molar ratio retion. The Ca/S molar ratiocalcium content of the sorfor the calcium content of ratio of about 1.5 was sufretention in the 1,500–1,6ratio requirement jumped greater.Exhibit 5-43 shows the effur retention at average beSalt Creek and Peabody csulfur, respectively. To ac

0.4 lb/106 Btu emission ra

agreement, a Ca/S molar required. To achieve an S

molar ratio of approximat

Exh

 Effect of B

on Ca/S 

Plant layout with coal and limestone feed locations.
Advanced Electric Power Generation 

coal, averaging 1.5% sulfur content, required a somewhatlower Ca/S molar ratio for a given reduction.The NOx emissions measured throughout the demonstration were less than 0.34 lb/106 Btu, which is well below

the regulated value of 0.5 lb/106 Btu. The average level of

NOx emissions for all tests was 0.18 lb/106 Btu. The NOx

emissions indicate a relatively strong correlation withtemperature, increasing from 40 ppmv (0.06 lb/106 Btu) at

1,425 oF to 240 ppmv (0.34 lb/106 Btu) at 1,700 °F. Limestone feed rate was also identified as a variable affecting

NOx emissions, i.e., somewhat higher NOx emissions

resulted from increasing calcium-to-nitrogen (Ca/N) molar ratios. The mechanism was believed to be oxidation ofvolatile nitrogen in the form of ammonia (NH3) catalyzed

by calcium oxide. The CO emissions decreased as temperature increased, from 140 ppmv at 1,425 oF to 70ppmv at 1,700 oF.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 were99.905% and 99.959%, respectively. This equated toemission levels of 0.0125 lb/106 Btu for Peabody coal and

0.0072 lb/106 Btu for Salt Creek coal, well

below the required 0.03 lb/106 Btu.

Economic PerformanceThe final capital costs associated with theengineering, construction, and startup of theNucla ACFB system were $112.3 million.This represents a cost of $1,123/kW (net). Thetotal power cost associated with plant operations between September 1988 and January1991 was approximately $54.7 million, resulting in a normalized cost of power productionof 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 than38% of the power production costs and include fuel expenses (26.2%), non-fuel expenses (6.8%), and maintenance expenses(5.5%).

Commercial ApplicationsThe Nucla project represented the first repowering of aU.S. utility plant with ACFB technology and showed thetechnologyís ability to burn a wide variety of coalscleanly and efficiently. The comprehensive database resulting from the Nucla project enabled the resultant technology to be replicated in numerous commercial plantsthroughout the world. Nucla continues in commercialservice.The ACFB technology is being currently used in Pennsylvania, West Virginia, Montana, and Utah at several sitesto burn culm at abandoned mines. The roots of theseenvironmental reclamation projects can be traced back toefforts at Nucla.Today, every major boiler manufacturer offers an ACFBsystem in its product line. There are now more than 170fluidized-bed combustion boilers of varying capacityoperating in the U.S. and the technology has made significant market penetration abroad. The fuel flexibility andease of operation make it a particularly attractive powergeneration option for the burgeoning power market indeveloping countries.

ContactsJoe Egloff, (303) 452-6

Tri-State Generation 

Association, In

P.O. Box 33695Denver, CO 80233(303) 254-6066 (fax)

George Lynch, DOE/HQThomas Sarkus, NETL, ReferencesDemonstration Program Reports. Report No. DOUte Electric Associationfrom NTIS as DE92001Economic Evaluation RDOE/MC/25137-3127. tion, Inc., March 1992. DE93000212.)Colorado-Ute Nucla Sta(CFB) DemonstrationóEPRI Report No. GS-74Nucla CFB Demonstratsign Report. Report No. rado-Ute Electric Assoc(Available from NTIS a

Exhibit 5-43

Calcium Requirements and

Sulfur Retentions for Various Fuels
5-114 Program Update 2001 Adva
Advanced Electric Power Generation 

Advanced Electric Power Gener

Integrated Gasification Combined
5-116 Program Update 2001 Adva

Kentucky Pioneer EnergyIGCC Demonstration ProjectParticipantKentucky Pioneer Energy, LLCAdditional Team MembersFuel Cell Energy, Inc. (formerly Energy ResearchCorporation)—molten carbonate fuel cell designer andsupplier, and cofunderLocationTrapp, Clark County, KY (East Kentucky PowerCooperative’s Smith site)TechnologyIntegrated gasification combined-cycle (IGCC) using aBG/L (formerly British Gas/Lurgi) slagging fixed-bedgasification system coupled with Fuel Cell Energy’s molten carbonate fuel cell (MCFC)Plant Capacity/Production580 MWe (gross); 540 MWe (net) IGCC; 2.0 MWeMCFCCoalHigh-sulfur Kentucky bituminous coal and pelletizedrefuse-derived fuel (RDF)Project FundingTotal project cost $431,932,714 100%DOE 78,086,357 18Participant 353,846,225 82Project ObjectiveTo demonstrate and assess the reliability, availability, andmaintainability of a utility-scale IGCC system using ahigh-sulfur bituminous coal and refused derived fuel(RDF) blend in an oxygen-blown, fixed-bed, slagginggasifier and the operability of a molten carbonate fuel cellfueled by coal gas.Advanced Electric Power GenerationIntegrated Gasification Combined-Cycle

Technology/Project DescriptionThe four BG/L gasifiers are supplied with steam, oxygen,limestone flux, and a coal and pelletized RDF. Duringgasification, the oxygen and steam react with the coal andlimestone flux to produce a coal-derived fuel gas rich inhydrogen and carbon monoxide. Raw fuel gas exiting thegasifier is washed and cooled. Hydrogen sulfide and othersulfur compounds are removed. Elemental sulfur is reclaimed and sold as a by-product. Tars, oils, and dust arerecycled to the gasifier. Instead of ash, the inorganic components in the feedstock are reduced to a non-leachingsilica matrix that will be used as a synthetic aggregate.The resulting clean, medium-Btu fuel gas fires two gasturbines. A small portion of the clean fuel gas is used forthe MCFC.

The MCFC is composed osandwiched between poroFuel (desulfurized, heated steam are fed continuousl

air is fed into the cathodedirect electric current, whcurrent with an inverter.Operation will commence increasing levels of RDF This method will allow thplant performance at vari
 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 

Calendar Year

Advanced Electric Power Generation Project Status/AccomplishmentsOn May 8, 1998, DOE conditionally approved AmerenServices Company (merger of Union Electric Co. andCentral Illinois Public Service Co.) as an equity partnerand host site provider subject to completing specific business and teaming milestones. The new project site to beprovided by Ameren was at its Venice Station Plant inVenice, Illinois. On April 30, 1999, Ameren ServicesCompany withdrew from the project for economic andbusiness reasons.In May 1999, Global Energy USA Limited (Global), soleowner of Kentucky Pioneer Energy, LLC (KPE), expressed interest in acquiring the project and providing ahost site at East Kentucky Power Cooperative’s SmithSite in Clark County, Kentucky. Subsequently, Globalnegotiated all the necessary documents with DOE andClean Energy Partners, L.P. (CEP) to acquire the project.In November 1999, the cooperative agreement was novated and the new site was approved.The NEPA process was initiated with the public scopingmeeting on May 4, 2000 and the draft EIS has been prepared. As of September 30, 2001, the EIS is in the process of final approval at DOE. (As of the time of publica- tion of this report, the EIS has been approved.) The State of Kentucky air quality permit was issued June 7, 2001. The permit authorizes construction and operation of the facility, including the use of RDF as a feedstock. The comment period for the municipal solid waste permit is still open. The comment period for the construction per- mit is also still open. 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 BG/L gasification technology has successfully used a wide variety of U.S. coals. Also, the highly modular approach to system design makes the BG/L-based IGCC and MCFC competitive 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 IGC

jected to be 8,560 Btu/kcommercial embodimenheat rate of 8,035 Btu/kmercial version of the mby a BGL gasifier is ant7,379 Btu/kWh (46.2% efficiencies represent a emissions of CO2 when 

pulverized coal plant eq

emissions from the IGCthan 0.1 lb/106 Btu (99% 

less than 0.15 lb/106 Btu 

Also, the slagging charanonleaching, glass-like usable by-product.

1992 1998 1999 1993 1994 2000 2002 2003 2005 

Preaward

5/93

DOE selected project

(CCT-V) 5/4/93

Cooperative agreement

awarded 12/2/94

Design and Construction

12/94 1

Operation initiated 1

p

**

Novation of cooperativeagreement; New siteapproved 11/99 New site approved 5/98

NEPA process completed 5/02*

Site withdrawn

4/99

EIS processinitiated 5/00

** **

Construction started 9/02*
5-118 Program Update 2001 Adva

Tampa Electric IntegratedGasification Combined-CycleProjectProject CompletedParticipantTampa Electric CompanyAdditional Team MembersTexaco 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 engineerLocationMulberry, Polk County, FL (Tampa Electric Company’sPolk Power Station, Unit No. 1)TechnologyAdvanced integrated gasification combined-cycle (IGCC)system using Texaco’s pressurized, oxygen-blown entrained-flow gasifier technologyPlant Capacity/Production316 MWe (gross), 250 MWe (net)CoalIllinois #6, Pittsburgh #8, Kentucky #11, and Kentucky#9; 2.5-3.5% sulfurProject FundingTotal project cost $303,288,446 100%DOE 150,894,223 49Participant 152,394,223 51Advanced Electric Power GenerationIntegrated Gasification Combined-Cycle

Project ObjectiveTo demonstrate IGCC technology in a greenfield commercial electric utility application at the 250-MWe size usingan entrained-flow, oxygen-blown, gasifier with full heatrecovery, conventional cold-gas cleanup, and an advancedgas turbine with nitrogen injection for power augmentation and NO

x

 control.

Technology/Project DescriptionCoal/water slurry and oxygen are reacted at high temperature and pressure to produce a medium-Btu syngas in aTexaco gasifier. Molten ash flows out of the bottom of thegasifier into a water-filled sump where it forms a solidslag. The syngas moves from the gasifier to a high-temperature heat-recovery unit, which cools the syngas whilegenerating high-pressure steam. The cooled gases flow toa water wash for particulate removal.

Next, a COS hydrolysis rspecies in the gas to a forThe syngas is then further ventional amine sulfur remkeeps SO2 emissions belo

ture). The cleaned gases acombined-cycle system foA GE MS 7001FA gas turThermal NO

x

 is controlle

injecting nitrogen. A steaby cooling the syngas and bine exhaust gases in the 124 MWe. The plant heat 
 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 

Calendar Year

Advanced Electric Power Generation Results SummaryEnvironmental• The Polk Plant is one of the cleanest coal-based power

generation facilities in the world.

• Emissions of SO2, NOx, and particulates are well below the regulatory limits set for the Polk plant site.

• SO2 reduction of 95% achieved.

Operational• The gasifier operated more than 29,000 hours and

processed coal at a rate of 2,300 tons/day, while thecombustion turbine operated over 28,000 hours toproduce over 8.6 million MWh of electricity on syngas.

• Power production met the target goal of 250 MWe at a

high stream factor and plant availability.

• Carbon burnout exceeds 95%.• During the fourth and fifth year of operation, the gasifier capacity factor was 75% and 66%, respectively.

For these same years, the gasifier availability was88.7% and 84.2%, respectively.

1988 1989 1990 1991 1994 1995 1996 1997 1998 

Preaward Design and Construction

12/89 3/91

**

DOE selected project (CCT-III) 12/19/89

Cooperative agreement awarded 3/11/91

Preoperational tests initiated 6/96

Construction completed 8/96

Operation initiated 9/96

9/96

Design completed 8/94NEPA process completed (EIS) 8/17/94Construction started 8/94

Operation and Repo

Environmental monitoring plan completed 5/96

• For the fourth and fifth year of operation, the air separation unit had an availability of 93.9% and 90.5%,

respectively, and the power block had an availabilityof 86.6% and 93.9%, respectively.

Economic• The total cost of the Tampa Electric IGCC Project is

$303 million, or $1,213/kW. The total project costincludes the cost of operating the unit throughout thedemonstration period as well as experimental work onhot gas cleanup. The investment for a commercial unitwould be significantly lower than that of the Tampaproject.

Demons

c
5-120 Program Update 2001 Adva

Project SummaryThe Tampa Electric IGCC project conducted at PolkPower Station has successfully demonstrated the commercial application of Texaco coal gasification in conjunctionwith electric power generation. Power production met thetarget goal of 250 MWe at a high stream factor and plantavailability. The gasifier operated more than 29,000hours and processed coal at a rate of 2,300 tons/day,while the combustion turbine operated over 28,000 hoursto produce over 8.6 million MWh of electricity on syngas.Carbon burnout exceeds 95%, and emissions of SO2

,

NOx, and particulates are well below the regulatory limits

set for the Polk plant site. Along with other IGCC demonstrations in the CCT Program, the Polk Plant is one ofthe cleanest coal-based power generation facilities in theworld.Environmental PerformanceThe Tampa Electric IGCC Project has very low pollutionimpacts. Environmental considerations have been a majordriving force from the inception of the project. The sitewas selected by an independent Community Siting TaskForce commissioned by Tampa Electric. Members included environmentalists, educators, economists, andcommunity leaders. Economic factors were also considered. The Task Force evaluated 35 sites in six countiesand recommended three in south-western Polk Countythat had previously been mined for phosphate.About one-third of the site is used for power generationfacilities. Another third, about 1500 acres, is used to enhance the environment by creation of public fishing lakesfor the Florida Fish and Game Commission. This area wasconverted from phosphate mining spoils to wetlands anduplands, thereby providing habitat for native plants andanimals, and was transferred to the Commission in 1997.The final third of the site is used primarily for access andto provide a visual buffer. The site contains an 850-acrecooling reservoir.The permitted stack emissions are shown in Exhibit 5-44.The plant achieved SO2 reduction of 95%. A COS hydrolysis unit was installed in 1999 to reduce SO2 emissions, enabling the station to meet recent, more stringentrestrictions. Injecting nitrogen into the gas

turbine is used to control NOx emissions. The use of nitrogen that would otherwise be vented represents a novel

approach in oxygen-blown gasification technology.A brine concentration unit processes ìgreyî water discharged from the gas cleanup systems, recovering areusable water stream for slurry preparation and a landfillable solid waste stream. There is no liquid effluent.Makeup water for the power plant is provided fromon-site wells. All process water is recycled.

Exhibit 5-44

Tampa Electric IGCC

Allowable Stack Emissions

Pollutant Allowed Emissions

lb/hr lb/106 Btu

SO2 357 0.21

NOx 223 0.27

CO 98

VOC 3

PM/PM10 17

84.2%, respectively. For operation, the air separatiity of 93.9% and 90.5%, rblock had an availability tively. The lower availabiyear of operation reflects that year to replace the re28-day forced outage to win the ASU.Several modifications to tdures were required to achas been demonstrated. Splugging caused failure otemperature heat recovery damage to the combustion removed in 1997, and commade in the rest of the heparticulate removal was pPluggage in another bank perature heat recovery sysmodification in 1999. In lwere implemented. These burners and reheat the gasreducing gasifier restart tiInitially, there were probl50% larger than any previconversion in this larger gand refractory life has beeissue. Liner replacement ierable downtime. To achithe gasifier is being operadesign, which in turn resubon conversion efficiencydue to capacity limitationslag crusher and a duplicastalled in 1998 solved thiThermocouple replacemeproblem. Replacement is couple failure by shearing dissimilar materials. In eacedures were developed tin the dome of the radiant had caused two extended 

Operational PerformanceAs originally envisioned, the overall process scheme wasto have incorporated hot gas cleanup on a portion of theraw syngas stream. After some initial test work, supportfor this option was discontinued. The cleaned syngas issent to the General Electric model MS 7001FA gas combustion turbine. Nitrogen from the air separation unit (at98% purity) is mixed with the syngas at the combustorinlet. Nitrogen addition has important benefits to thepower plant: (1) the increased mass flow through the gasturbine produces more power than without the nitrogen;(2) the overall efficiency of the system is enhanced;(3) NOx emissions are reduced; and (4) the need for steam

or water injection is eliminated.During the fourth and fifth year of operation, the gasifiercapacity factor was 75% and 66%, respectively. For thesesame years, the gasifier availability was 88.7% and
Advanced Electric Power Generation 

Numerous short forced outages occurred in 1997 and1998 due to erosion and corrosion in the process waterand coal/water slurry piping systems, pumps, and valves.Various changes have virtually eliminated these problems,and no such outages occurred in 1999. Some of the corrective actions taken to solve operating and maintenanceproblems in this project have resulted in patent applications.The overall heat rate of the plant is 9,350 Btu/kWh(36.5% efficiency, HHV). The efficiency is somewhatlower than design because of removal of the high-temperature exchangers, lower than excepted carbon conversion, and a compressor failure in the brine concentrationunit which necessitates its operation as a single effectevaporator. In the second half of 2000, a slag recoverysystem was commissioned to recover and use the unconverted carbon, and the brine concentration unit will berestored to its original more efficient vapor compressioncycle. Ways are being evaluated to use the heat availableas a result of removing the high temperature exchangers.Together, these projects are expected to increase the efficiency to 38% (9,000 Btu/kWh), consistent with the original design value.The IGCC's oxygen plant requires 11.5 x 106 scfm of air

to produce enough oxygen for full load operation on avariety of fuels over the normal ambient temperaturerange and to simultaneously reprocess enough fines togenerate a slag product suitable for the cement industry.This air requirement is 8.5% above the ASU design values. The main air compressor (MAC) could almost meetthis air requirement when the compressor was new, theMAC output has deteriorated at a rate of about 2% peryear. At the end of the demonstration period. The MACis 15% deficient on a normal Florida summer day. About30% of the deficiency is attributable to pluggage of theMAC aftercooler and resulting backpressure. The aftercooler bundle will be replaced and all carbon steel partscoated to prevent further deterioration. The remaining70% of the loss is distributed throughout the compressorsystem and there are no obvious ways to resolve the deficiency.Ten coals and blends were tested in the three years ofoperation to determine the impact of feedstock properties

on system performance. These coals included KentuckyNo. 9, Kentucky No. 11, two Illinois No. 6 coals, andthree Pittsburgh No. 8 coals. Four areas were evaluatedfor each coal: (1) feasibility of processing into a highconcentration slurry, (2) carbon conversion, (3) aggressiveness of the slag to the gasifier's refractory liner, and(4) tendency toward fouling of the syngas coolers. All ofthe coals were found to be suitable with some designmodifications. Lower cost petroleum coke blends werealso tested.Economic PerformanceThe total cost of the Tampa Electric IGCC Project is $303million, or $1,213/kW. The total project cost includes thecost of operating the unit throughout the demonstrationperiod as well as experimental work on hot gas cleanup.The investment for a commercial unit would be significantly lower than that of the Tampa project.The Department of Energy estimates that future IGCCpower plants, based on mature and improved technology,will cost in the range of $900ñ1,250/kW (1999$) depending on the degree to which existing equipment and infrastructure can be utilized. Heat rate ultimately is expectedto be in the range of 7,000ñ7,500 Btu/kWh (46ñ49%;HHV).

Commercial ApplicaThe project was presentPower magazine. In 199ciation of Builders and Ction quality. Several awinnovative siting procesAmerica Corporate AwaResolution Award from Florida Audubon SocietAs a result of the Polk PTexaco-based IGCC can environmentally suitablutilizing a wide variety the project is greater tha

reductions are 90% thoscoal-fired power plant. Tproaches utilized at Polk projects using different TECO Energy is not onlcommercialize the technhas been contacted by Ecuss possible technical atechnology.ContactsMark Hornick, (813) 22

General Manager, PoTECO EnergyP.O. Box 111Tampa, FL 33601-01(863) 428-5927 (fax)

George Lynch, DOE/HQ

george.lynch@hq.do

James U. Watts, NETL, 

james.watts@netl.do

ReferencesTampa Electric IntegratProjectóAn Update. U.2000.ìPolk Power Stationó5tion.î McDeniel, John Ethe 2001 Gasification T8ñ10, 2001

Inside the Texaco gasifier.
5-122 Program Update 2001 Adva

Advanced Electric Power GenerationIntegrated Gasification Combined-CyclePiñon Pine IGCC PowerProjectProject completedParticipantSierra Pacific Power CompanyAdditional Team MembersFoster Wheeler USA Corporation—architect, engineer,

and constructor

The M.W. Kellogg Company—technology supplierBechtel Corporation—start-up engineerWestinghouse Corporation—technology supplierGeneral Electric—technology supplierLocationReno, Storey County, NV (Sierra Pacific PowerCompany’s Tracy Station)TechnologyIntegrated gasification combined-cycle (IGCC) using theKRW air-blown pressurized fluidized-bed coal gasification systemPlant Capacity/Production107 MWe (gross), 99 MWe (net)CoalSouthern Utah bituminous, 0.5–0.9% sulfur (design coal);Eastern bituminous, 2–3% sulfur (planned test)Project FundingTotal project cost $335,913,000 100%DOE 167,956,500 50Participant 167,956,500 50Project ObjectiveTo demonstrate air-blown pressurized fluidized-bed IGCCtechnology incorporating hot gas cleanup (HGCU); toevaluate a low-Btu gas combustion turbine; and to assesslong-term reliability, availability, maintainability, andenvironmental performance at a scale sufficient to determine commercial potential.

Technology/Project DescriptionDried and crushed coal and limestone are introduced intoa KRW air-blown pressurized fluidized-bed gasifier.Crushed limestone is used to capture a portion of thesulfur. The sulfur reacts with the limestone to form calcium sulfide which, after oxidation, exits as calcium sulfate along with the coal ash in the form of agglomeratedparticles suitable for landfill.Low-Btu coal gas (140 Btu/standard cubic foot) leavingthe gasifier passes through cyclones, which return most ofthe entrained particulate matter to the gasifier. The gas,which leaves the gasifier at about 1,700 oF, is cooled toabout 1,100 oF before entering the hot gas cleanup system. During cleanup, virtually all of the remaining particulates are removed by ceramic candle filters, and finaltraces of sulfur are removed by reaction with a metaloxide sorbent in a transport reactor.

The cleaned gas then ente6FA) combustion turbine, (gross) generator. Exhausbine is used to produce stgenerator (HRSG). Superdrives a condensing steam produce about 46 MWe (gThe IGCC plant is designthe sulfur in the coal and 

less CO2 than a comparab

The superior environmenthe inherent efficiency of gasifier and incorporation 
 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 

Calendar Year

Advanced Electric Power Generation Results SummaryOperational• The project succeeded in identifying and working

through a number of problems, made possible onlythrough full-scale system demonstrations, and positioned the technology for commercialization.

• Operational testing proved the ability of the KRW

gasifier to produce coal-derived synthesis gas of design quality—two runs achieved 145 Btu/standardcubic foot.

• The power island demonstrated a 94% availability in a

base load operating mode after working through aquality control problem in the HRSG, replacing anundersized turbine/generator coupling, and uncovering a shortcoming in the 2nd stage bucket shroud design in the hot gas path of the first-of-a-kind GEMS6001FA gas turbine.

• New start-up procedures for the IGCC system were

developed to avoid accelerated temperature rampsupon ignition, which threatened the integrity of therefractory and ceramic candle filters, and to avoid use

of an oxidant (air), which introduced the potential forfire. But, once up to temperature and operating, thegasifier proved to be easy to control.

• The fines removal system for the hot gas particulate

filtration vessel was modified, which included increasing the size of the Filter Fines Depressurization Binfilters, using nuclear and vibration-based level detectors in all the bins, and incorporating Skimmer valves(which provide bursts of high-pressure gas) to preventbridging of fines in bin outlet sections.

• Testing suggested modifying the hot gas particulate

filter to improve durability and enhance protection forthe gas turbine in the event of candle element failures.

• The lower section of the gasifier was enlarged to facilitate ash and limestone (LASH) removal and cooling.• The hot gas desulfurizer and regenerator system, using

a transport reactor, showed promise after replacing thesorbent with a more physically durable material.

Environmental• Steady-state operation was not reached in the course

of testing, so environmental performance could not beevaluated.

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Design and Construction Operation and Repo

9/91 8/92 

DOE selectedproject (CCT-IV)9/12/91

Cooperative agreement awarded 8/1/92

Project co

Ground breaking/construction started 2/95

NEPA process completed (EIS) 11/8/94

Design completed 8/95

Environmental monitoring plancompleted 10/31/96

Preoperational tests initiated 11/96

1/98

Operation initiated 1/98

Construction completed 2/97

Economic• Steady-state operatio

of testing, so economevaluated.
5-124 Program Update 2001 Adva

Project SummaryThe project set out to assess pressurized fluidized-bedgasification technology, hot gas (1,000 °F) sulfur andparticulate removal, and low-Btu gas combustion turbineperformance in an IGCC application. The testing provided valuable information to guide developers in completing a course of action toward design of a commercialIGCC configuration embodying the basic system technologies. But the IGCC system did not reach steady-stateoperation, so environmental and economic performancecould not be evaluated. Following is a synopsis of theresults coming out of the operational assessment completed during the demonstration period.Operational PerformanceThe power island, which includes the gas turbine, heatrecovery steam generator (HRSG), and steam turbinebegan operation on natural gas in October 1996. The gasturbine is a General Electric MS6001FA—a first-of-akind unit designed to operate at a 2,350 °F firing temperature on 140 Btu/standard cubic foot coal-derived syntheticgas (syngas). Overall, the power island performance wasgood, demonstrating a 94% availability in a base loadoperating mode. Early operations uncovered some qualitycontrol problems in the HRSG and an undersized gasturbine/generator coupling, which were easily resolved.Also identified was a shortcoming in the 2nd stage bucketshroud design, which caused a premature failure. Theshroud on the periphery of the 2nd stage bucket in the hotgas path distorted radially and contacted and damaged thehoneycomb seal blocks. General Electric replaced thebucket assembly and returned the damaged parts for rootcause analysis.Testing of the gasifier island included 18 separate start-upattempts, each ending with a malfunction and incorporation of modifications to improve system performance.The longest syngas production run was 25 hours and thecumulative hours totaled 127.5. Although brief, the operation proved the ability of the KRW gasifier to producecoal-derived syngas of the quality predicted by design—two runs achieved 145 Btu/standard cubic foot. The unitexperienced accelerated temperature ramps during startup (once the bed is ignited), which induced spalling of thegasifier refractory and threatened the integrity of the ceramic candle filters in the hot gas particulate filtration system. Moreover, start-up used hot air, an oxidant, which has the potential to cause fires in a system normally oper- ated in a reducing environment—residual fuel on or in components can catch fire if ignition temperatures are reached. A fire occurred during the last start-up and caused extensive damage to the hot gas particulate filtra- tion system. At the close of the demonstration period, new inert gas start-up schemes were developed to address both rapid heat up and oxidation problems. Once up to temperature and operating, the gasifier proved easy to control. Failure to remove fines from the hot gas particulate filtra- tion (HGPF) vessel caused the bulk of failed start-ups. The system includes the HGPF, a screw feeder/cooler at the base of the HGPF, a Filter Fines Collection Bin (Col- lection Bin) to receive the HGPF fines, a Filter Fines Depressurization Bin (Depressurization Bin) to bring the system down to atmospheric pressure, and a Filter Fines Feed Bin (Feed Bin) to serve as a surge bin for the Fines Combustor. Testing led to development of several modifi- cations to resolve the fines removal problems. Depressurization Bin filters, through which vented gas passes to prevent emissions, were increased by an order of magnitude. Capacitance-type bin level detectors, including those in the HGPF, were replaced with nuclear level detection devices and vibration- based level detection, which subse- quently functioned well. The HGPF vessel was further modified by incorpo- rating a thermocouple array. Incorpora- tion of Skimmer valves, providing a burst of high-pressure gas against the bin wall, in lieu of Evaser fluidizing nozzles, resolved the problem of fines bridging in the cone sections of the Collection and Depressurization Bins. Also, testing suggested modifying the hot gas particulate filter to improve durability and enhance protection for the gas turbine in the event of candle element failures. The ceramic candles are subject to failure from 

removal system and thermAnd, the safeguard devicecandle filter to plug upon effectively. Moreover, canshutdown because the bromoval system. Testing led candle filter system that edesigns that show promisRepeated start-ups, accelestart-up in early testing, aresulted in spalling of the plugged the LASH removnal volume of the annulus sufficient cooling of the Lplacing the original two-llayer refractory and fire bincreasing the annulus voof refractory, using a revistalled from the grid area 

HRSG in foreground and gasifier island in bac
Advanced Electric Power Generation 

the fluidized-bed region to provide the needed resistanceto fatigue failure.Failure of the fines removal system to provide a continuous output caused erratic operation of the fines combustordue to surging feed rates. The resultant surging of thecombustor also contributed to seal damage between thecombustor and HRSG. The solution was the addition of adiverter line from the fines removal system to the wastesilo to provide an option prior to establishing a steadystate feed rate. An early candle filter failure pointed outpoor SGD performance and inadequate protection for therecycle gas compressor, which experienced erosion of theimpeller as a result of particulate incursion. The onlyother major failure was in the combustion air line, whichburned through as a result of fuel accumulating in the linefollowing system shutdown and bed slump. The solutionwas simply to blow out the line prior to start-up.

The hot gas desulfurizer and regeneration systemshowed promise. After the initial sorbent did not holdup physically in the entrained bed transport reactorsystem, another sorbent was identified and installed,and it performed well during the short runs.The demonstration ended with Sierra Pacific trying todivest its power generation facilities, a condition of itsearlier merger with Nevada Power. Wisconsin PublicService had expressed intentions to pursue commercialization of the Piñon Pine IGCC system and planned topurchase Sierra’s Tracy Station, including the Piñon PinePlant; however, the sale was cancelled by the Nevadalegislature’s imposition of a moratorium on sale of generation assets until July 2003. This reflects recognitionthat despite the difficulties encountered, the IGCC systemshows promise. The demonstration resulted in the engineering knowledge requisite to establishing a commercialdesign for fluidized-bed gasification. The demonstrationalso provided valuable lessons learned for a broad rangeof advanced power generation technologies.Commercial ApplicationsThe Piñon Pine IGCC system concept is suitable for newpower generation, repowering needs, and cogenerationapplications. The net heat rate for a proposed greenfieldplant using this technology is projected to be 7,800 Btu/kWh (43.7% efficiency), representing a 20% increase inthermal efficiency compared with a conventional pulverized coal plant with a scrubber and a comparable reduction in CO2 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. Furthermore, hot gas cleanup providesfor extremely low emissions and efficiency gains throughreduced heat loss.The KRW IGCC technology offers tremendous fuelflexibility. It is capable of gasifying all types of coals,including high-sulfur, high-ash, low-rank, and highswelling coals, as well as biowaste or refuse-derivedwaste, with minimal environmental impact. There are nosignificant process waste streams that require remediConveyor leading to coal storage facility.

ation. The only solid waash and calcium sulfateContactsJeffrey W. Hill, (775) 8

Sierra Pacific Power P.O. Box 10100Reno, NV 89520-00

George Lynch, DOE/HQDonald W. Geiling, NEReferencesSierra Pacific ResourceDepartment of Energy. FCompany. January 1, 20
5-126 Program Update 2001 Adva

Wabash River CoalGasification RepoweringProjectProject completedParticipantWabash River Coal Gasification Repowering Project JointVenture (a joint venture of Dynegy and PSI Energy, Inc.)Additional Team MembersPSI Energy, Inc.—hostDynegy (formerly Destec Energy, Inc., a subsidiary of

Natural Gas Clearinghouse)—engineer and gas plantoperator

LocationWest Terre Haute, Vigo County, IN (PSI Energy’s WabashRiver Generating Station, Unit No. 1)TechnologyIntegrated gasification combined-cycle (IGCC) usingGlobal Energy’s two-stage pressurized, oxygen-blown,entrained-flow gasification system—E-GasTechnologyTMPlant Capacity/Production296 MWe (gross), 262 MWe (net)CoalIllinois Basin bituminous (Petroleum coke also used)Project FundingTotal project cost $438,200,000 100%DOE 219,100,000 50Participant 219,100,000 50Project ObjectiveTo demonstrate utility repowering with a two-stage, pressurized, oxygen-blown, entrained-flow IGCC system,including advancements in the technology relevant to theuse of high-sulfur bituminous coal; and to assess longterm reliability, availability, and maintainability of thesystem at a fully commercial scale.Advanced Electric Power GenerationIntegrated Gasification Combined-Cycle

Technology/Project DescriptionThe Destec, now E-Gas TechnologyTM, process featuresan oxygen-blown, continuous-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 2,600 °F/400 psig. In the firststage, the coal slurry undergoes a partial oxidation reaction at temperatures high enough to bring the coal’s ashabove its melting point. The fluid ash falls through a taphole at the bottom of the first stage into a water quench,forming an inert vitreous slag. The syngas flows to thesecond stage, where additional coal slurry is injected.This coal is pyrolyzed in an endothermic reaction with thehot syngas to enhance syngas heating value and improveefficiency.The syngas then flows to the syngas cooler, essentially afire tube steam generator, to produce high-pressure saturated steam. After cooling 

lates are removed in a hotgasifier. The syngas is furexchangers. The syngas is chlorides and passed throcarbonyl sulfide into hydris removed in the acid gas based absorber/stripper coproduce elemental sulfur “sweet” gas is then moistthe power block. The pow192-MWe General Electriturbine, a Foster Wheeler steam generator with rehehouse reheat steam turbin
 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 

Calendar Year

Advanced Electric Power Generation Results SummaryEnvironmental• The SO2 capture efficiency was greater than 99%,

keeping SO2 emissions consistently below

0.1 lb/106 Btu and reaching as low as 0.03 lb/106 Btu.

Sulfur-based pollutants were transformed into 99.99%pure sulfur, a highly valued by-product—33,388 tonsproduced during the demonstration period.

• The NO

x

 emissions were 0.15 lb/106 Btu, which meets

the 2003 target emission limits for ozone non-attainment areas, or 1.09 lb/MWh, which exceeds the NewSource Performance Standard of 1.6 lb/MWh.

• Particulate emissions were below detectable limits.• Carbon monoxide emissions, averaging 0.05

lb/106 Btu, were well within industry standards.

• Coal ash was converted to a low-carbon vitreous slag,

impervious to leaching and valued as an aggregate inconstruction or as grit for abrasives and roofing materials; and trace metals from petroleum coke were alsoencased in an inert vitreous slag.

Operational• Over the course of the demonstration, the IGCC unit

operated on coal for over 15,000 hrs, processed over1.5 million tons of coal, and produced over 23 trillionBtu of syngas and 4 million MWh of electricity.

• Design changes in the first year included:

– Using a less tenacious refractory in the secondstage gasifier and changing the flow path geometry

to eliminate ash deposition on the second-stagegasifier walls and downstream piping;

– Changing to improved metallic candle filters to

prevent particulate breakthrough in the hot gasfilter; and

– Installing a wet chloride scrubber and a COS catalyst less prone to poisoning to eliminate chloride

and metals poisoning of the COS catalyst.

• The second year identified cracking in the gas turbine

combustion liners and tube leaks in the heat recoverysteam generator (HRSG). Resolution involved replacement of the gas turbine fuel nozzles and liners andmodifications to the HRSG to allow for more tubeexpansion.

• The third year was es

IGCC unit underwenshowed that the unit modification, on a setwo different Illinois 

• Overall thermal perfo

petroleum coke operfrom 39.7% to 40.2%

• In the fourth year, the 

rows 14 through 17 omonth outage. But ovavailability of the gareaching 79.1% in 19

Economic• The overall cost of th

which equates to aboFor an equivalent gremated at $1,700/kW. 285 MWe (net) greenlessons learned, techrate of 8,526 Btu/kWcoal-fueled unit and coke-fueled unit.

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Operation and Reporting

DOE selectedproject (CCT-IV)9/12/91

Design and Construction

9/91 7/92

NEPA process completed (EA) 5/28/93

Design completed 5/94

Cooperative agreement awarded 7/28/92

Environmental monitoring plan completed 7/9/93Groundbreaking ceremony 7/7/93

Preoperational tests initiated 8/95

11/95 

Demonstration operati

completed 12

Construction completed 11/95Operation initiated 11/95
5-128 Program Update 2001 Adva

Project SummaryThe Wabash River Coal Gasification Repowering Projectrepowered a 1950s vintage pulverized coal-fired plant,transforming the plant from a nominally 33% efficient,90-MWe unit into a nominally 40% efficient, 262-MWe(net) unit. Cinergy, PSIís parent company, dispatchespower from the project, with a demonstrated heat rate of8,910 Btu/kWh (HHV), second only to their hydroelectricfacilities on the basis of environmental emissions andefficiency.Beyond the integration of an advanced gasification system, a number of other advanced features contributed tothe high energy efficiency. These included: (1) hot/dryparticulate removal to enable gas cleanup without heatloss, (2) integration of the gasifier high-temperature heatrecovery steam generator with the gas turbine-connectedHRSG to ensure optimum steam conditions for the steamturbine, (3) use of a carbonyl sulfide (COS) hydrolysisprocess to enable high-percentage sulfur removal,(4) recycle of slag fines for additional carbon recovery,(5) use of 95% pure oxygen to lower power requirementsfor the oxygen plant, and (6) fuel gas moisturization toreduce steam injection requirements for NOx control.

Over the four-year demonstration period starting in November 1995, the facility operated on coal for more than15,000 hours and processed over 1.5 million tons of coalto produce more than 23 trillion Btu of syngas. For several of the months, syngas production exceeded one trillion Btu. By the end of the demonstration, the 262-MWeIGCC unit had captured and produced 33,388 tons ofsulfur.Operational PerformanceThe first year of operation resolved problems with:(1) ash deposition on the second stage gasifier walls anddownstream piping, (2) particulate breakthrough in thehot gas filter system, and (3) chloride and metals poisoning of the COS catalyst. Modifications to the secondstage refractory to avoid tenacious bonds with the ash andto the hot gas path flow geometry corrected the ash deposition problem. Replacement of the ceramic candle filterswith metallic candles proved to be largely successful. A

follow-on metallic candle filter development effort ensued using a hot gas slipstream, which resulted in improved candle filter metallurgy, blinding rates, and cleaning techniques. The combined effort all but eliminateddowntime associated with the filter system by the close of1998. Installation of a wet chloride scrubber eliminatedthe chloride problem by September 1996 and use of analternate COS catalyst less prone to trace metal poisoningprovided the final cure for the COS system by October1997.The second year of operation identified cracking problems with the gas turbine combustion liners and tubeleaks in the HRSG. Replacement of the fuel nozzles andliners solved the cracking problem. Resolution of theHRSG problem required modification to the tube supportand HRSG roof/penthouse floor to allow for moreexpansion.By the third year, downtime was reduced to nuisanceitems such as instrumentation-induced trips in the oxygenplant and high-maintenance items such as replacement ofhigh-pressure slurry burners every 40ñ50 days. In thethird year, the IGCC unit underwent fuel flexibility tests.The unit operated effectively, without modification orincident, on a second coal feedstock, a blend of two different Illinois #6 coals, and petroleum coke (petcoke).These tests added to the fuel flexibility portfolio of thegasifier, which had previously processed both lignite andsubbituminous coals during its earlier development. Theoverall thermal performance of the IGCC unit actuallyimproved during petcoke operation. The unit processedover 18,000 tons of high-sulfur petcoke and produced350 billion Btu of syngas. There was a negligible amountof tar production and no problems were encountered inremoving the dry char particulate despite a higher dustloading. Exhibit 5-45 provides a summary of the thermalperformance of the unit on both coal and petcoke.The fourth year of operation was marred by a 3-monthoutage due to damage to rows 14 through 17 of the gasturbine air compressor. However, over the four years ofoperation, availability of the gasification plant steadilyimproved, reaching 79.1% in 1999. Exhibit 5-46 providesa summary of the production statistics during the demonstration period.

Environmental PerforThe IGCC unit operates w

greater than 99%. As a re

tently below 0.1 lb/106 Bt

as 0.03 lb/106 Btu. Moreo

fur-based pollutants into 9valued by-product, rather Moisturizing the syngas ition reduced NOx emissio

quirement established by non-attainment areas. Becfiltration necessary for coturbine, particulate emiss0.012 lb/106 Btu. Also, ca

quite low, averaging 0.05 

The ash component of the vitreous slag, impervious aggregate in construction ing materials. Also, the trpetcoke were effectively Economic PerformancThe overall cost of the IG$417 million, which equadollars. For an equivalent additional new equipmenestimated at $1,700/kW. Cmitting, equipment procumanagement, constructioning personnel.In the final report, the parfor a new 262-MWe greenlessons learned, technologof 8,250 Btu/kWh are $1,fueled unit and $1,150 (2fueled unit. In designing fbe reduced in size and somMore recent data developMWe (net) coal-fired greerate of 8,526 Btu/KWh wA 291-MWe (net) petrole8,400 Btu/KWh heat rate 
Advanced Electric Power Generation 

Design 

Coal Coal 

Nominal Throughput, tons/day 2,550 2,450 Syngas Capacity, 106 Btu/hr 1,780 1,690 

Combustion Turbine, MW 192 192 Steam Turbine, MW 105 96 Auxiliary Power, MW 35 36 Net Generation, MW 262 261 Plant Efficiency, % (HHV) 37.8 39.7 Sulfur Removal Efficiency, % >98 >99 

Annual fuel costs for the Wabash project ranged from$15.3–19.2 million, with an annual availability of 75%and using high-sulfur bituminous coal ranging from$1.00–1.25/106 Btu ($22–27/ton). Non-fuel operation and

maintenance (O&M) costs for the syngas facility (excluding the power block) was 6.8% of installed capital basedon 75% availability. O&M costs include operating laborand benefits, technical and administrative support on andoff site, all maintenance, chemicals, waste disposal, operating services, supplies, and 5% of the total O&M cost forbetterments. Projected O&M costs for a mature IGCCfacility (including the power block) are 5.2% of installedcapital.Commercial ApplicationsAt the end of the demonstration in December 1999, Global Energy, Inc. purchased Dynegy's gasification assetsand technology. Global Energy is marketing the technology under the name “E-Gas TechnologyTM.” The projectis continuing to operate in commercial service as WabashRiver Energy, Ltd., a subsidiary of Global Energy.The immediate future for E-Gas TechnologyTM appears tolie with both foreign and domestic applications wherelow-cost feedstocks such as petroleum coke can be usedand co-production options are afforded—bundled production of steam, fuels/chemicals, and electricity. Integrationor association with refinery operations are examples. Thisprojection is born out in a recent announcement by thePort of Port Arthur, Texas that they are entering into partnership with Sabine Power I, Limited to build the world'slargest petroleum coke-fueled IGCC facility using E-GasTechnologyTM. The Port estimates the cost of the facilityat $1.75 billion; construction jobs at 1,250; and permanent jobs at 200 to 250. In the longer term, the technologyhas application to repowering the aging fleet of existingdomestic coal-fired boilers, and new foreign and domesticcoal-fueled capacity additions. Factors favoring increaseduse of IGCC over time are continued improvement inIGCC cost and performance, projected increases in pricedifferentials between coal and gas, and continued importance placed on displacement of petroleum in chemicalsand fuels production.

Exhibit 5-45

Wabash Thermal Performance Sum

Exhibit 5-46

Wabash River Coal Gasification Repowe

Production Statistics

Coal On Spec. Steam 

On Coal Processed Gas Produced 

Time Period (Hr) (tons) (106 Btu) (106 lb) 

Start-up 1995 505 41,000a 230,784 171,613 

1996 1,902 184,382 2,769,685 820,624 1997 3,885 392,822 6,232,545 1,720,229 1998 5,279 561,495 8,844,902 2,190,393 

1999b 3,496 369,862 5,813,151 1,480,908 Overall 15,067 1,549,561 23,891,067 6,383,767 aEstimates.bThe combustion turbine was unavailable from 3/14/99 through 6/22/99.

ContactsPhil Amick, Vice President (713) 374-7252

Global Energy, Inc.1000 Louisiana St., Suite 3800Houston, TX 77002pramick@globalenergyinc.com(713) 374-7279 (fax)

George Lynch, DOE/HQ, (301) 903-9434Leo E. Makovsky, NETL, (412) 386-5814

ReferencesWabash River Coal GasFinal Technical Report. Project Joint Venture. AWabash River Coal GasProject Performance Suergy. January 2002.
5-130 Program Update 2001 Adva
Advanced Electric Power Generation 

Advanced Electric Power Gener

Advanced Combustion/Heat En
5-132 Program Update 2001 Adva

Advanced Electric Power GenerationAdvanced Combustion/Heat EnginesClean Coal DieselDemonstration ProjectParticipantArthur D. Little, Inc. (ADL)Additional Team MembersUniversity of Alaska at Fairbanks—host and cofunderFairbanks Morse Engine, Goodrich Corp.—diesel engine

technology vendor

Usibelli Coal Mine, Inc.—coal supplierLocationFairbanks, AK (University of Alaska facility)TechnologyFairbanks Morse coal-fueled diesel enginePlant Capacity/Production6.4 MWe (net)CoalUsibelli Alaskan subbituminousProject FundingTotal project cost $47,636,000 100%DOE 23,818,000 50Participant 23,818,000 50Project ObjectiveTo prove the design, operability, and durability of the coaldiesel engine during 4,000 hours of operation and test thecoal slurry in the diesel.Technology/Project DescriptionThe project is based on the demonstration of an 18-cylinder, heavy-duty engine (6.4 MWe) modified to operate onAlaskan subbituminous coal. The clean coal diesel technology, which uses a low-rank coal-water-fuel (LRCWF),is expected to have very low NOx and SO2 emission levels

(50–70% below current New Source Performance Standards). In addition, the demonstration plant is expected toachieve 41% efficiency, and future plant designs are expected to reach 48% efficiency. This will result in a 25%

reduction in CO2 emissions compared with conventional

coal-fired plants. The engine will use selective catalyticreduction (SCR) for NOx control.
 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 

Calendar Year

Advanced Electric Power Generation Project Status/AccomplishmentsOverall project system design was completed in early1999. The 18-cylinder diesel engine arrived on site atUAF in January 1999 and was mounted in the enginehouse in late February. In October 1999, the engine, afterbeing connected to the generator, was operated on dieselfuel to ensure it would function coupled with the generator. In May 2000, total system startup was attempted ondiesel fuel. The SCR system for the diesel was tested inAugust 2000 and achieved 90% reduction in NOx emissions, which was within contract specifications. Since

August 15, 2000, the diesel has been supplying all of theuniversity’s power requirements on fuel oil. Uponcompletion of system checkout, the diesel engine will bemodified to use the LRCWF. Manufacture of the hardened engine parts for the Fairbanks Morse two-cylindertest engine, coal fuel preparation and testing, and completion of the baghouse and SNCR system are in progress.With the change of site from Easton, Maryland to UAF,Alaskan subbituminous coal will now be used to manufacture the LRCWF. Usibelli Coal Mine, Inc. will supplythe coal. Samples of three different blends of LRCWF

1992 1996 1997 1993 1994 1998 1999 2001 2002 

Preaward

5/93 7/94

DOE selected project(CCT-V) 5/4/93

Cooperative agreementawarded 7/12/94

Design and Construction

NEPA processcompleted (EA)6/2/97

Construction started 6/98

Environmental monitoring

plan completed 2/99

Coal Diesel Operation initiated 10/02*

10/0

Project

restructured 8/96

Design completed 1/99

Fairbanks Morse two-cylinder

engine test on LRCWF 6/02*

** 

have been formulated and sent to Fairbanks Morse fortesting in a fuel injector test rig. As of September 30,2001, the testing was in progress. The latest additive hasproven to be effective. Tests related to long-term reliability related to clogging or damaging the needle point andfor pressure regulation of the fuel pumping system arebeing conducted. The goal of the testing is to determinewhich blend has the best fluid properties and to reduceclogging at the fuel tips. Tests on the Fairbanks Morsetwo-cylinder test engine will provide information anddata on how to optimize the operational settings, verifythe coal fuel performance, and finalize the requirementsfor hardened coatings for critical components.Commercial ApplicationsThe U.S. diesel market is projected to exceed 60,000MWe (over 7,000 engines) through 2020. The worldwidemarket is 70 times the U.S. market. The technology isparticularly applicable to distributed power generation inthe 5- to 20-MWe range, using indigenous coal in developing countries.The net effective heat rate for the mature diesel system isexpected to be 6,830 Btu/kWh (48%), which makes it

**

very competitive with sioil-fired installations. Ecommercial diesel systebetween 50% and 70% bstallation cost of a matumately $1,300/kW.
5-134 Program Update 2001 Adva

Healy Clean Coal ProjectProject completedParticipantAlaska Industrial Development and Export AuthorityAdditional Team MembersGolden Valley Electric Association, Inc.—host and

operator

Stone and Webster Engineering Corp.—engineerTRW, Inc., Space & Technology Division—combustor

technology supplier

The Babcock & Wilcox Company (B&W)—spray dryer

absorber technology supplier

Usibelli Coal Mine, Inc.—coal supplierSteigers Corporation—environmental and permitting

support

LocationHealy, Denali Borough, AK (adjacent to Healy Unit No. 1)TechnologyTRW’s Clean Coal Combustion System; Babcock &Wilcox’s spray dryer absorber (SDA) with sorbent recyclePlant Capacity/Production50 MWe (nominal)CoalUsibelli subbituminous 50% run-of-mine (ROM) coal and50% waste coalProject FundingTotal project cost $242,058,000 100%DOE 117,327,000 48Participant 124,731,000 52Project ObjectiveTo demonstrate an innovative new power plant designfeaturing integration of an advanced combustor coupledwith both high- and low-temperature emissions controlprocesses.Advanced Electric Power GenerationAdvanced Combustion/Heat Engines

Technology/Project DescriptionEmissions are controlled using TRW’s clean coal combustion system, an advanced entrained/slagging combustors through staged fuel and air injection for NOx control

and limestone injection for SO2 control. Additional SO2 is

removed using B&W’s activated recycle SDA.A coal-fired precombustor increases the air inlet temperature for optimum slagging performance. The slaggingcombustors are bottom mounted, injecting the combustion products into the boiler. The main slagging combustor consists of a water-cooled cylinder that slopes towarda slag opening. The precombustor burns 25–40% of thetotal coal input. The remaining coal is injected axiallyinto the combustor, rapidly entrained by the swirling precombustor gases and additional air flow, and burned under substoichiometric conditions for NO

x

 control. The ash

forms molten slag, which walls and is driven by aerforces through a slot into 70–80% of the ash is remis then ducted to the furnacombustion, additional aiwindbox to NO

x ports and 

verized limestone (CaCO

combustors where it is fla

to lime (CaO). The mixtunot removed in the comburial, is removed in the fabflash-calcined material is slurry, which is injected in

the flue gas reacts with thsimultaneously evaporate

from the flue gas by reactmaterial on the baghouse 
 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 

Calendar Year

Advanced Electric Power Generation Results SummaryEnvironmental• NO

x emissions ranged from 0.208–0.278 lb/106 Btu,

with typical emissions of 0.245 lb/106 Btu on a 30-day

rolling average, which is well below the permit limitof 0.350 lb/106 Btu on a rolling day average.

• SO2 emissions were consistently less than 0.09 lb/106

Btu, with typical emissions of 0.038 lb/106 Btu, which

are below the permit limit of 0.10 lb/106 Btu (3-hour

average).

• High SO2 removal efficiencies in excess of 90% were

achieved with low-sulfur coal and Ca/S molar ratios of1.4–1.8.

• Particulate matter (PM) emissions were 0.0047

lb/106 Btu, which is well below the permit limit of

0.02 lb/106 Btu.

• CO emissions were less than 130 ppm at 3.0% O2,

with typical emissions of 20–50 ppm at 3.0% O2,

which is well below the permit limit of 202 ppm at3.0% O2.

• Tests showed that the SDA system SO2 emissions, PM

emissions, and opacity were well within guarantees ofthe technology supplier.

Operational• Carbon burnout goals for the technology supplier

were achieved—greater than 99% carbon burnout at100% maximum continuous rating (MCR) for theROM, 50/50 blend of ROM/waste coal, and 55/45blend. The carbon burnout was typically 99.7%.

• The contract goal of the technology supplier for slag

recovery greater than 70% at 100% MCR for all coalswas also achieved. Slag recovery ranged from 78–87%, with a typical recovery of 83%.

• During a 90-day test in the second half of 1999, the

plant availability was 97% at a capacity factor of 95%.

• The SDA pressure drops and power consumption were

well below guarantee levels of the technology supplier.

• The system required less limestone and produced less

solid waste by-product than anticipated.

Economic• The capital costs of a 

using this system are $450.7 million ($1,5

• The variable operatin

is $7.2 million/yr (19million/yr (1993$) fopercent capacity fact

• The levelized cost of 

stant 1993$) for the 3percent capacity fact

• The levelized cost pe

$6,499/ton (constant (based on 90 percent 

1989 1990 1991 1993 1994 1995 1997 1998 1999 

Preaward Design and Construction

Designstarted 7/90

4/91

Cooperativeagreementawarded 4/11/91

DOE selected project(CCT-III) 12/19/89

Operation and 

12/89 1/98

**

Operation initiated 1/98

Preoperational testsinitiated 8/97

NEPA process completed (EIS) 3/10/94

Design completed 10/93 Ground breaking/ construction

started 5/30/95 Environmental monitoring

plan completed 4/11/97

Constructioncompleted 11/97 

**
5-136 Program Update 2001 Adva

Project SummaryThe Healy Clean Coal Project is the first utility-scaledemonstration of the TRW clean coal combustion system.The project site is adjacent to the existing Healy Unit No.1 near Healy, Alaska and the Usibelli coal mine. Power issupplied to the Golden Valley Electric Association(GVEA).Environmental PerformanceThe entrained/slagging combustor is designed to minimize NO

x emissions, achieve high carbon burnout, and

remove the majority of fly ash from the flue gas prior tothe boiler. The slagging combustor is also the first step ofa three-step process for controlling SO2 by first converting limestone to flash-calcined lime. Second, the flash

calcined-lime absorbs SO2 within the boiler. Third, the

majority of the SO2 is removed with B&W’s SDA system,

which uses the flash-calcined lime and fly ash captured inthe baghouse. Because most of the coal ash is removed bythe slagging combustors, the recycled material is richenough in calcium content that the SDA can be operatedsolely on the recycled solids, eliminating the need to purchase or manufacture lime for the back end scrubbingsystem.During a cumulative six-month combustion system characterization test, a series of tests were performed to establish baseline performance of the combustion system whileburning ROM and ROM/waste coal blends, to map combustor performance characteristics over a broad range ofoperating conditions and hardware configurations, and todetermine the best configuration and operating conditionsfor long-term operation. During the 24-month demonstration test period, the NOx, SO2, PM, opacity, and CO emission goals were met with the exception of short-term SO2

and opacity exceedences emissions, as well as permpresented in Exhibit 5-47Performance testing of th1999 showed that the techsurements of the SDA inlfeed, coal feed, air preheaelectrical power consumpas normal plant data from system, showed that the tetees. The results of the testees are shown in Exhibit environmental performan

 Exhibit 5-47

 Healy Performance Goals and Demonstration Test Program Results

(January 1998–December 1999)

Parameter NSPS Permit Goal Actual Range Actua

NO

x

0.5 lb/106 Btu (new plant after 7/97) 0.350 lb/106 Btu (30-day rolling avg) 0.20–0.35 lb/106 Btu 0.208–0.278 lb/106 Btu 0.245 

1,010 tons/yr (full load) (30-day rolling avg) (30-day rolling avg) (30-da

SO2 70% removal when emissions 0.086 lb/106 Btu (annual avg) 70% removal (minimum) ~90% removal 0.038 

<0.60 lb/106 Btu 0.10 lb/106 Btu (3-hour avg) 79.6 lb/hr max (3-hour <0.09 lb/106 Btu (30-m

65.8 lb/hr max (3-hour avg) avg) (30-minute avg correc

248 tons/yr (full load) corrected to 3% O2)

PM 0.03 lb/106 Btu 0.020 lb/106 Btu (hourly avg) 0.015 lb/106 Btu NA 0.004

99% reduction 13.2 lb/hr (hourly avg) (hourly avg)

58 tons/yr (full load)

Opacity 20% Opacity (6-minute avg) 20% Opacity (3-minute avg) 20% Opacity (3- 2–6% Opacity 3.9% 

27% Opacity (one 6-minute minute avg) (30-minute avg) (30-mperiod per hour)

CO Dependent on ambient CO 0.20 lb/106 Btu (hourly avg) 206 ppm (corrected 20–50 ppm 25.9 p

levels in the local region 202 ppm (corrected to 3% O2) to 3.0% O2) (30-minute avg (30-m

132 lb/hr, 577 tons/yr (full load) 200 ppm (corrected corrected to 3% O2) correc

to 3.5% O2)

a Measured 2.3% after correction of problems with premature filter bag failures in the baghouse.b Not measured during demonstration test program. Data are from source test in March 1999.
Advanced Electric Power Generation 

Operational PerformanceThe slagging stage of the combustor performed extremelywell and continuously demonstrated the capability to burnboth ROM and ROM/waste coal blends over a broadrange of operating conditions. The precombustor performed very well with ROM coal, but exhibited morevariable performance, in terms of slagging behavior, during the initial tests with ROM/waste coal blends.Localized slag freezing was observed in the precombustorduring early testing. A combination of hardware configuration and operational configuration changes were madethat minimized slag freezing. These changes includedrelocating the secondary air from the precombustor mixannulus to the head end of the slagging stage and completely transferring the precombustor mill air to the boilerNO

x ports following boiler warmup. These changes eliminated the mixing of excess air downstream of the precombustor chamber to minimize local slag freezing and increased the precombustor operating temperature to provide additional temperature margin. The mill air change

had the added benefit of simplifying combustor operationby eliminating the need to monitor and control coal-ladenmill air flow to the precombustor mill air ports duringsteady-state operation.Testing of the slagging combustor also showed that thecontract goals were achieved, which included greater than

 Exhibit 5-48

Healy SDA Performance Test Results and Performance Guarantees

Operating Parameter Guarantee Range of Parameter ValuesSO2 79.6 lb/hr (max) <2.15PM 0.015 lb/106 Btu 0.0014-0.0052Opacity 20% Opacity 1.0-2.0

(3-minute avg) 27% Opacity for 3 minutes per hour

System Pressure Drop 13 inches W.G. 9.6-10.0System Power Consumption 550.5 kW 324-340

99% carbon burnout at 100% maximum continuous rating(MCR) for the performance, ROM, 50/50 blend of ROM/waste coal, and 55/45 blend; and greater than 98% carbonburnout at 100% MCR for waste coal. The carbon burnout was typically 99.7%. Slag recovery ranged from 78–87%, with a typical reading of 83%, easily meeting thecontract goal for slag recovery of greater than 70% at100% MCR for all coals.The SDA system also performed well. During performance testing in June 1999, system pressure drops werewell below the 13 in. WG guarantee. The range was 9.6–10.0 in. W.G. as can be seen in Exhibit 5-48. Power consumption was approximately 38–41% less than the guaranteed level. Based on these results, Stone & Websterconcluded that the SDA system met all performance guarantees.Economic PerformanceCapital and operating cost estimates were prepared by anindependent consultant to the participant for new plantsin the “lower 48” that incorporate the technology demonstrated at Healy. The capital costs for a 50-MWe and 300-MWe plant are $90.6 million (1,812 $/kW) and $450.7million (1,502 $/kW) (1993$), respectively. The variableoperating cost for the 300-MWe plant is estimated at $7.2million per year and the fixed operating costs are estimated at $28.4 million per year based on a 90 percent

capacity factor (1993$). would then be 36.5 milllevelized cost per ton of 

$6,499/ton (constant 19Commercial ApplicaThis technology is approdustrial boiler in new or coal-fired boilers as welbecause of its high ash-rcyclone boilers may be with the entrained/slagglimited supply of high-Btemperature coal that cymercial availability of cfor SO2, NOx, and partic

tential users planning nefits to existing capacity requirements.ContactsArthur E. Copoulos, Pro

Alaska Industrial De813 West Northern LAnchorage, AK 995(907) 269-3044 (fax)

George Lynch, DOE/HQRobert M. Kornosky, NEReferencesHealy Clean Coal ProjeEconomics Report FinaApril 2001.Spray Dryer Absorber SJune 7-11, 1999. Stone tion. February 2000.
5-138 Program Update 2001 Adva
Coal Processing for Clean Fuels 

Coal Processing for Clean Fu
5-140 Program Update 2001 

Commercial-ScaleDemonstration of the LiquidPhase Methanol (LPMEOHTM)ProcessParticipantAir Products Liquid Phase Conversion Company, L.P.(a limited partnership between Air Products and Chemicals, Inc., the general partner, and Eastman ChemicalCompany)Additional Team MembersAir 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 advisorLocationKingsport, Sullivan County, TN (Eastman ChemicalCompany’s Chemicals-from-Coal Complex)TechnologyAir Products and Chemicals, Inc.’s liquid phase methanolprocessPlant Capacity/Production80,000 gallons/day of methanol (nominal)CoalEastern high-sulfur bituminous, 3–5% sulfurProject FundingTotal project cost $213,700,000 100%DOE 92,708,370 43Participant 120,991,630 57

Project ObjectiveTo demonstrate on a commercial scale the production ofmethanol from coal-derived synthesis gas using theLPMEOHTM process; to determine the suitability ofmethanol produced during this demonstration for use as achemical feedstock or as a low-SO

x emitting, low-NOx

emitting alternative fuel in stationary and transportationapplications; and to demonstrate, if practical, the production of dimethyl ether (DME) as a mixed coproduct withmethanol.Technology/Project DescriptionThis project is demonstrating, at commercial scale, theLPMEOHTM process to produce methanol from coalderived synthesis gas. The combined reactor and heatremoval system is different from other commercial methanol processes. The liquid phase not only suspends the

catalyst but functions as aheat of reaction away from ture permits the direct use to the reactor without the sion. Synthesis gas feed tproduced by the gasificatminous coal (Mason seammaximum) and 10% ash.Methanol fuel testing is btionary and mobile applicand distributed electric pomethanol from the projectest locations to study the as a feedstock in transporapplications.

Coal Processing for Clean FuelsIndirect Liquefaction
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Calendar Year

Coal Processing for Clean Fuels Project Status/AccomplishmentsThe first production of methanol from the 80,000 gal/dayunit occurred on April 2, 1997, with the first stable operation at nameplate capacity occurring on April 6, 1997. Astable test period at over 92,000 gal/day revealed no system limitations.The LPMEOHô process demonstration unit continues toexceed expectations. Tests have given increased confidence in the use of the LPMEOHô process for IGCCapplications. This confidence level will increase withadditional testing of the LPMEOHô process.Since startup in April 1997, over 84 million gallons ofmethanol have been produced. Availability since startupthrough September 2001 is 97.5%, with availability in1998 through 2000 exceeding 99%. As a result of thesuccesses achieved, the demonstration operations wereextended an additional 15 months (through June 30,2002) to allow for the opportunity to perform new teststhat are considered of significant commercial interest.Methods for the removal and control of potential catalystpoisons continue to be an important part of the ongoingplant operation. To support this effort, the catalyst guard

bed adsorbent was changed to a material which is expected to significantly reduce other catalyst poisons suchas arsenic. This new adsorbent is a commercially available copper oxide impregnated activated carbon. Thecatalyst guard bed was placed in service in August 2001after the implementation of some plant equipment modifications to allow for the adsorbent material change. Theinitial performance of the catalyst guard bed was verypromising with the new adsorbent. Performance evaluation of the new adsorbent material will continue on anongoing basis.Plant modifications to support in situ catalyst activationin the LPMEOHô reactor have been completed. Previously, catalyst was activated in small batches in a separatevessel and transferred into the LPMEOHô reactor. In situactivation of the methanol catalyst is of commercial significance as it has the potential to simplify equipment andto reduce capital requirements. The first large-scale, insitu activation of methanol synthesis catalyst was successfully completed in the slurry bubble column reactor inAugust 2001. Over 40,000 lb of catalyst (slightly greaterthan the design catalyst loading) were slurried in an inertmineral oil and transferred from a storage tank to the

LPMEOHô reactor. Thactivated in-situ using dperiod. Following the in process demonstration uhas begun operation in a mode.Commercial ApplicaThe LPMEOHô procesIGCC power generation storable-liquid fuel (metgas. Methanol also has a plications; it can be substationary and mobile coexcellent fuel for utility no sulfur and has except

when burned.DME has several commwith methanol, the mixtIGCC electric power gemethanol and DME also stock for the synthesis ofuel additives. Pure DMaerosol for personal pro

Operation and Reporting

1989 1991 1995 1992 1993 1996 1997 1998 2002 

NEPA process completed (EA) 6/30/95

Construction started 10/95

Design completed 6/96

Environmental monitoring plan completed 8/29/96

4/97

Operation initiated 4/97

Construction completed 1/97Preoperational tests initiated 1/97

Project transferred to Air Products

Liquid Phase Conversion

Company, L.P. 3/95

Project resited to

Kingsport, TN

10/93

Operaticomple6/02*

 **

**

Preaward

Design and Construction

12/89 10/92

DOE selectedproject (CCT-III)12/19/89

Cooperative agreement awarded 10/16/92

**
5-142 Program Update 2001 

Development of the CoalQuality ExpertTMProject completedParticipantsABB Combustion Engineering, Inc. and CQ Inc.Additional Team MembersBlack & Veatch—cofunder and software developerElectric Power Research Institute—cofunderThe Babcock & Wilcox Company—cofunder and pilotscale testerElectric Power Technologies, Inc.—field testerUniversity of North Dakota, Energy and Environmental

Research Center—bench-scale tester

Utility Companies—(5 hosts)LocationsGrand 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 sitesTechnologyCQ Inc.’s EPRI Coal Quality ExpertTM (CQETM) computer softwarePlant Capacity/ProductionFull-scale testing took place at utility sites ranging in sizefrom 250–880 MWe.CoalWide variety of coals and blendsCoal Processing for Clean FuelsCoal Preparation Technologies

Project FundingTotal project cost $21,746,004 100%DOE 10,863,911 50Participants 10,882,093 50Project ObjectiveThe objective of the project was to provide the utilityindustry with a PC software program it could use toconfidently and inexpensively evaluate the potential forcoal-cleaning, blending, and switching options to reduceemissions while producing the lowest cost electricity.Specifically the project was to: (1) enhance the existingCoal Quality Information System (CQISTM) database andCoal Quality Impact Model (CQIMTM) to allow assessment of the effects of coal-cleaning on specific boilercosts and performance; and (2) develop and validateCQETM, a model that allows accurate and detailed prediction of coal quality impacts on total power plant operatingcost and performance.

Technology/Project DThe CQETM is a software sophistication to fueling dsystem-wide impact of fufired power plant performgeneration costs. The impimprovements; operationacompliance alternatives omance, and production coCQETM. CQETM can be ussuch impacts, or it may be default data to perform mstudies.

Coal Quality Expert, CQE, CQIS, and CQIM are trademarks of theElectric Power Research Institute.Pentium is a registered trademark of Intel.OS/2 Warp is a registered trademark of IBM.Windows is a registered trademark of Microsoft Corporation.
 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 

Calendar Year

Coal Processing for Clean Fuels Results SummaryEnvironmental• CQETM includes models to evaluate emission and

regulatory issues.

Operational• CQETM can be used on a stand-alone computer or as a

network application for utilities, coal producers, andequipment manufacturers to perform detailed coalimpact analyses.

• Four features included in the CQETM program are:

– Fuel Evaluator,– Plant Engineer,– Environmental Planner, and– Coal-Cleaning Expert.

• CQETM can be used to evaluate:

– Coal quality,– Transportation system options,– Performance issues, and– Alternative emissions control strategies.

• CQETM operates on an OS/2 Warp® (Version 3 or

later) operating system with preferred hardwarerequirements of a Pentium®-equipped personal computer, 1 gigabyte hard disk space, 32 megabytesRAM, 1024x768 SVGA, and CD-ROM.

Economic• CQETM includes economic models to determine production cost components for coal-cleaning processes,

power production equipment, and emissions controlsystems.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

DOE selectedproject (CCT-I)12/9/88

12/88

Cooperative agreement awarded 6/14/90

NEPA process completed

(MTF) 4/27/90

Environmental monitoringplan completed 7/31/90

Operation initiated 8/90

Preaward

Development

6/90

Field testing completed 4/93

8/90

CQE R

CQE CD-ROM is
5-144 Program Update 2001 

Project SummaryBackgroundCQETM began with EPRI’s CQIMTM, developed for EPRIby Black & Veatch and introduced in 1989. CQIMTM wasendowed with a variety of capabilities, including evaluating Clean Air Act compliance strategies, evaluating bidson coal contracts, conducting test-burn planning andanalysis, and providing technical and economic analysesof plant operating strategies. CQETM, which combinesCQIMTM with other existing software and databases, extends the art of model-based fuel evaluation establishedby CQIMTM in three dimensions: (1) new flexibility andapplication, (2) advanced technical models and performance correlations, and (3) advanced user interface andnetwork awareness.Algorithm DevelopmentData derived from bench-, pilot-, and full-scale testingwere used to develop the CQETM algorithms. Bench-scaletesting was performed at ABB Combustion Engineering’sfacilities in Windsor, Connecticut and the University ofNorth Dakota’s Energy and Environmental Research Center in Grand Forks, North Dakota. Pilot-scale testing wasperformed at ABB Combustion Engineering’s facilities inWindsor, Connecticut and Alliance, Ohio. The five fieldtest 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.

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 operatingperformance of the boiler. The alternate coal, a blended or

cleaned coal of improved quality, was burned in the boilerfor the remaining test period.The baseline and alternate coals for each test site alsowere burned in bench- and pilot-scale facilities undersimilar conditions. The alternate coal was cleaned atCQ Inc. to determine what quality levels of clean coal canbe produced economically and then transported to thebench- and pilot-scale facilities for testing. All data frombench-, pilot-, and full-scale facilities were evaluated andcorrelated to formulate algorithms used to develop themodel.CQETM CapabilityThe OS/2®-based program evaluates coal quality, transportation system options, performance issues, and

alternative emissions control strategies for utility powerplants. CQETM is composed of technical tools to evaluateperformance issues, environmental models to evaluateemissions and regulatory issues, and economic models todetermine production cost components. These includeconsumables (e.g., fuel, scrubber additives), waste disposal, operation and maintenance, replacement energy

costs, and operation and maintenance costs for coalcleaning processes, power production equipment, andemissions control systems. CQETM has four main features:• Fuel Evaluator—Performs system-, plant-, or unitlevel fuel quality, economic, and technical assessments.• Plant Engineer—Provides in-depth performance evaluations 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, andpredicts associated costs.

Software DescriptionThe CQETM includes more than 100 algorithms based onthe data generated in the six full-scale field tests. TheCQETM design philosophy underscores the importance offlexibility by modeling all important power plant equipment and systems and the

situations. This level of socations to be added by asinteract. Updated informashared among all affected work-aware, enabling useshare data and results. Thcoupled with an object daallows different views of efficiency is enhanced whCQETM also can be expanthe system. Object-orienteobjects to be added and ohanced easily. For exampmade with respect to pred

slagging and fouling), the object that provides these augmented. Other objects 

ash collection and disposado not need to be altered; lying system is maintaineSystem Requirements CQETM uses the OS/2® op

operate in stand-alone monetwork. Technical suppoVeatch for licensed users. Commercial ApplicatiThe CQETM system is appgeneration plants and largthat burn pulverized coal. suppliers, environmental regulatory institutions, antional markets for CQETM Inc. and Black & Veatch. EPRI owns the software amembers for their use. CQform of three types of licemercializer. CQ Inc. and Bsigned commercialization companies non-exclusive licenses and to offer consuse of CQETM software. T
Coal Processing for Clean Fuels 

licensed to use copies of CQETM’s stand-alone Acid RainAdvisor. Over 30 U.S. utilities and one U.K. utility haveCQETM through their EPRI membership. Over 100 utilities and coal companies are now using CQETM. Proposalsare pending with several non-EPRI-member U.S. andforeign utilities to license the software.CQETM was recognized by the Secretary of Energy andthe President of EPRI in 1996 as the best of nine DOE/EPRI cost-shared utility research and developmentprojects under the “Sustainable Electric Partnership”program.The CQETM program has been incorporated in the Vistaprogram package, which is the latest version of the software. Vista operates in the Windows® environment. The

Vista Fuels Web server has a Home Page on the WorldWide Web (http://www.fuels.bv.com) to promote the software, facilitate communications between developers andusers, and eventually allow software updates to be distributed over the Internet. The Home Page also helps attractthe interest of international utilities and consulting firms.ContactsClark D. Harrison, President, (724) 479-3503

CQ Inc.160 Quality Center Rd.Homer City, PA 15748(724) 479-4181 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Joseph B. Renk, NETL, (412) 386-6406ReferencesFinal Report: Development of a Coal Quality Expert. CQInc. June 20, 1998.“Recent Experience with the CQETM.” Harrison, Clark D.et al. Fifth Annual Clean Coal Technology Conference:Technical Papers. January 1997.CQETM Users Manual, CQETM Home Page athttp://www.fuels.bv.com/unused/cqe/cqe.htm.Comprehensive Report to Congress on the Clean CoalTechnology Program: Development of the Coal QualityExpert. ABB Combustion Engineering, Inc., and CQ Inc.Report No. DOE/FE-0174P. U.S. Department of Energy.May 1990. (Available from NTIS as DE90010381.)

New England Power

Five utilities acted as hosts for field tests of CQETM.
5-146 Program Update 2001 

ENCOAL® Mild Coal

Gasification Project

Project completedParticipantENCOAL Corporation (a wholly owned subsidiary ofBluegrass Coal Development Company)Additional Team MembersBluegrass Coal Development Company (a wholly owned

subsidiary of AEI Resources, Inc.)—cofunder

SGI International—technology developer, owner, licensorTriton Coal Company (a wholly owned subsidiary of

Vulcan Coal Company)— host

LocationNear Gillette, Campbell County, WY (Triton CoalCompany’s Buckskin Mine site)TechnologySGI International’s Liquids-From-Coal (LFC®) process

CoalLow-sulfur Powder River Basin (PRB) subbituminouscoal, 0.45% sulfurPlant Capacity/Production1,000 tons/day of subbituminous coal feedProject FundingTotal project cost $90,664,000 100%DOE 45,332,000 50Participant 45,332,000 50Project ObjectiveTo demonstrate the integrated operation of a number ofnovel processing steps to produce two higher-heatingvalue fuel forms from mild gasification of low-sulfursubbituminous coal, and to provide sufficient products forpotential end users to conduct burn tests.Coal Processing for Clean FuelsMild Gasification

Technology/Project DescriptionCoal is fed into a rotary grate dryer where it is heated toreduce moisture. The temperature is controlled so that nosignificant amounts of methane, CO2, or CO are released.

The solids are then fed to the pyrolyzer where the temperature is about 1,000 °F, and all remaining water isremoved. A chemical reaction releases the volatile gaseous material. Solids exiting the pyrolyzer are quenchedto stop the pyrolysis reactions.In the original process, the quench table solids were further cooled in a rotary cooler and transferred to a surgebin. 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 “oxidative

deactivation,” a reaction othe particles, reducing the tion.Following the VFB, the sspheric temperature in an water is added to rehydra

suppressant is added as th

The hot gas produced in tcyclone for removal of thin a quench column to stotions and to condense the 
 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 

Calendar Year

Coal Processing for Clean Fuels Results SummaryEnvironmental• The PDF® contains 0.36% sulfur with a heat content of

11,100 Btu/lb (compared with 0.45% sulfur and 8,300Btu/lb for the feed coal).

• The CDL® contains 0.6% sulfur and 140,000 Btu/gal

(compared with 0.8% sulfur and 150,000 Btu/gal forNo. 6 fuel oil).

• In utility applications, PDF® enabled reduction in SO2

emissions, reduction in NOx emissions (through flame

stabilization), and maintenance of boiler rated capacitywith 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).

• The LFC® process consistently produced 250 tons/day

of PDF® and 250 barrels/day of CDL® from500 tons/day of run-of-mine PRB coal.

• Integrated operation of the LFC® process components

over five years has provided a comprehensive databasefor 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 insix states. Shipments included 100% PDF® and blendsfrom 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 stableflame.

• The low-volatile PDF® also showed promise as a reductant 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 lowsulfur 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 d

tons per day would c(2001$) to construct, tenance costs of $52 

Design and Construction Operation and Reporting

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Cooperative agreement awarded 9/17/90

DOEselectedproject(CCT-III)12/19/89

NEPA process completed (EA) 8/1/90

Ground breaking/construction started 10/26/90

Operation initiated 7/92

Construction completed 6/92

Preoperational tests initiated 4/92

Design completed 7/91

Environmental monitoring plan completed 5/29/92

12/89 9/90 7/92

Preaward

Operation 
5-148 Program Update 2001 

Project SummaryOperational PerformanceThe LFC® facility operated for more than 15,000 hours

over a five-year period. Steady-state operation was maintained for much of the demonstration with availabilitiesof 90% for extended periods. The length of operation andvolume of production proved the soundness and durability of the process.Exhibit 5-49 summarizes ENCOAL’s production history.By the end of the demonstration, over 83,500 tons ofPDF® 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®. Over 5

million gallons of CDL® were produced and shipped to

eight customers in seven states.As with most demonstrations, however, success requiredovercoming many challenges. The most difficult challenge was achieving 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 persistentPDF® 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 wasneeded for product deactivation. A search for a suitabledesign led to adoption of a VFB. A 500-ton/day VFB wasinstalled between the quench table and rotary cooler.(Plans were made for installation of a second 500 ton/dayVFB but were never implemented.)Although the VFB enhanced deactivation, the PDF stillrequired “finishing” to achieve stabilization. Extensivestudy revealed that more oxygen was needed for deactivation. Two courses of action were pursued: (1) development of interim measures to finish deactivation externalto the plant, enabling immediate PDF® shipment for test

burns; and (2) development of an in-plant process forfinishing, eliminating product quality and labor penaltiesfor external finishing.“Pile layering” was the primary external PDF® finishing

measure adopted. However, PDF® quality becomes somewhat impaired due to changes in size, moisture, and ash

content.

Pursuit of a finishing process step resulted in establishment of a stabilization task force composed of privatesector and government engineers and scientists. Theoutcome was construction and testing of a Pilot Air Stabilization System (PASS) to complete the oxidative deactivation of PDF®. The PASS controls temperature and

humidity during forced oxidation. The data obtained wereused to develop specifications and design requirementsfor a full-scale, in-plant PDF® finishing unit based upon a

commercial (Aeroglide) tower dryer design.The first shipment of ENCOAL’s liquid CDL® product

experienced unloading problems. The use of heat tracingand tank heating coils solved the unloading problems forsubsequent 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 oF, and the flash pointaveraged 230 oF, both within the design range. Watercontent was down to 1–2%, and solids content was 2–4%.Improvements resulted from more consistent operationand lower pyrolysis temperatures and higher pyrolysisflow rates enabled by a new pyrolyzer water seal.

Environmental PerforPDF® offers the advantag

Basin coal without a heatLFC® process removes orthe PDF® product lower i

Btu basis. Because the RO

levels remain reasonable the ash level is essentially ROM coal goes into one-

Dust emissions were not a 

suppressant (MK) was sp

surface as it leaves the sto

narrower particle size disa larger fines content but dust range than ROM coaENCOAL’s test burn shipwhen Japan’s Electric Pow(EPDC) evaluated six me

EPDC, which must approelectric power generation 

able for use in Japanese uIn October 1996, instrumconducted at the Indiana-

Pre-VFB Post-VFB

1992 1993 1994 1995 1996 

Raw Coal Feed (tons) 5,200 12,400 67,500 65,800 68,000 PDF® Produced (tons) 2,200 4,900 31,700 28,600 33,300 

PDF® Sold (tons) 0 0 23,700 19,100 32,700 CDL® Produced (bbl) 2,600 6,600 28,000 31,700 32,500 Hours on Line 314 980 4,300 3,400 3,600 Average Length ofRuns (Days) 2 8 26 38 44 

Exhibit 5-49

ENCOAL Production

1Through June 1997.
Coal Processing for Clean Fuels 

operative’s (IKEC) Clifty Creek Station, Unit No. 3. Important findings included the following:• Full generating capacity using PDF® was possible with

one mill out of service, which was not possible usingthe baseline fuel. Operation using PDF® afforded time

to perform mill maintenance and calibration withoutlosing capacity or revenues, increasing capacity factorand availability, and decreasing operation and maintenance costs.

• NOx emissions were reduced by 20% due to high PDF®

reactivity, resulting in almost immediate ignition uponleaving the burner coal nozzle. Furthermore, PDF®sustained effective combustion (maintaining low losson ignition) with very low excess oxygen, which isconducive to low NOx emissions.

• PDF® use precipitated increased ash deposits in the

convective pass that were wetter than those resultingfrom baseline coal use, requiring increased sootblowing to control build-up.

The CDL® liquid product is a low-sulfur, highly aromatic,

heavy liquid hydrocarbon. CDL® fuel characteristics are

similar to those of a low-sulfur No. 6 fuel oil, except thatthe sulfur content is significantly lower. 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 incompatibility of thearomatic CDL® with many straight-chain hydrocarbon

distillates.ENCOAL determined that a centrifuge was needed toreduce solids retention and improve marketability ofCDL® (tests validated a 90% removal capability); and an

optimum slate of upgraded products was identified. Theupgraded products were: (1) crude cresylic acid, (2) pitch,(3) refinery feedstock (low-oxygen middle distillate), and(4) oxygenated middle distillate (industrial fuel).EconomicThe “base case” for economics of a commercial plant isthe 15,000-metric-ton/day, three-unit North RochelleLFC® 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 isassumed that the cogeneration unit is owned and operatedby an independent third party. The capital cost for a fullscale, 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 isthe largest single operating cost item. The total estimatedoperating cost is $9.00/ton of feed coal including the costof feed coal, chemical supplies, maintenance, and labor.Commercial ApplicationsIn a commercial application, CDL® would be upgraded to

cresylic acid, pitch, refinery feedstock, and oxygenatedmiddle distillate. Oxygenated middle distillate, the lowestvalue by-product, would be used in lieu of natural gas asa make-up fuel for the process (30% of the process heatinput). PDF® would be marketed not only as a boiler fuel

but as a supplement to or substitute for coke in the steelindustry. PDF® characteristics make it attractive to the

metallurgical market as a coke supplement in pulverizedcoal-injection and granular-coal-injection methods, and asa 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 Indonesian, oneRussian, and two U.S. projects. A U.S. project has received an Industrial Siting Permit and an Air QualityConstruction Permit, but the project is on hold due to lackof funding.ContactsJim Mahler, (858) 551-1090

SGI International1200 Prospect, Suite 325La Jolla, CA 92037jmahler@sgiinternational.com(858) 551-0247 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Douglas M. Jewell, NETL, (304) 285-4720

ReferencesENCOAL® Mild Gasific

Feasibility Study. U.S. D1997. Report No. DOE/as DE98002005.)Final Design ModificatiEnergy. September 19975797. (Available from NENCOAL® Mild GasificFinal Report. Report NoDepartment of Energy. SNTIS as DE98002007.)“Results of the PDF® Te

Topical Report. JohnsonOctober 1996.ENCOAL® Mild Coal G

Public Design and ConsDOE/MC/27339-4065. 1994. (Available from N
5-150 Program Update 2001 

Coal Processing for Clean FuelsCoal Preparation TechnologiesAdvanced Coal ConversionProcess DemonstrationProject completedParticipantWestern SynCoal LLC (formerly Rosebud SynCoalPartnership; a subsidiary of Montana Power Company’sEnergy Supply Division)Additional Team MembersNoneLocationColstrip, Rosebud County, MT (adjacent to WesternEnergy Company’s Rosebud Mine)TechnologyWestern SynCoal LLC’s Advanced Coal ConversionProcess for upgrading low-rank subbituminous and lignitecoalsPlant Capacity/Production45 tons/hr of SynCoal® product

CoalPowder River Basin subbituminous (Rosebud Mine),0.5–1.5% sulfur, plus tests of other subbituminous coalsand lignitesProject FundingTotal project cost $105,700,000 100%DOE 43,125,000 41Participant 62,575,000 59Project ObjectiveTo demonstrate Western SynCoal LLC’s Advanced CoalConversion Process (ACCP) to produce SynCoal®, a

stable coal product having a moisture content as low as1%, sulfur content as low as 0.3%, and heating value upto 12,000 Btu/lb.

Technology/Project DescriptionThe process demonstrated is an advanced thermal coalconversion process coupled with physical cleaning techniques to upgrade high-moisture, low-rank coals to produce a high-quality, low-sulfur fuel. The raw coal isscreened and fed to a vibratory fluidized-bed reactorwhere surface moisture is removed by heating with hotcombustion gas. Coal exits this reactor at a temperatureslightly higher than that required to evaporate water andflows to a second vibratory reactor where the coal isheated to nearly 600 °F. This temperature is sufficient toremove chemically bound water, carboxyl groups, andvolatile sulfur compounds. In addition, a small amount oftar is released, partially sealing the dried product. Particleshrinkage causes fracturing, destroys moisture reactionsites, and liberates the ash-forming mineral matter.

SynCoal is a registered trademark of the Rosebud SynCoal Partnership.

The coal is then cooled to with an inert gas in a vibrcooled coal is sized and fair pressure and vibration ing much of the pyrite, frothe sulfur content of the pfractions are sent to a profractions go to fluidized-bremoval.The fines handling system are produced throughout tgathered by screw conveyconveyors to a bulk cooliblended with the coarse ppacity bin until loaded intsales, or returned to the m
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Calendar Year

Coal Processing for Clean Fuels Results SummaryOperational• During the life of the ACCP project, over 2.8 million

tons of raw coal was processed to produce almost1.9 million tons of SynCoal® products, which include

regular, fines, blends, DSE treated, and special characteristic SynCoal® shipped to various customers.

• The product produced was exceptionally close to the

design basis product from a chemical standpoint, butdid not allow for conventional bulk handling from aphysical standpoint due to instability (spontaneousheating) and dustiness.

Environmental• The measured emissions of PM from the process stack

were 0.0259 gr/dscf (2.563 lb/hr) with a limit of0.031 gr/dscf.

• The measured emissions of NO

x

 were 4.50 lbs/hr

(54.5 ppm) compared with a vendor estimated limit of7.95 lb/hr for controlled emissions and 11.55 lb/hr foruncontrolled emissions.

• The measured emissions of CO were 9.61 lbs/hr

(191.5 ppm) compared with a vendor estimated limitof 6.46 lb/hr for controlled emissions and 27.19 lb/hrfor uncontrolled emissions.

• The measured emissions of SO2 were 0.227 lbs/hr

(2.0 ppm) compared with a vendor estimated limit of7.95 lb/hr for controlled emissions and 20.27 lb/hr foruncontrolled emissions.

• The measured emissions of total hydrocarbons were

2.93 lb/hr (37.1 parts per million).

• The measured emissions of hydrogen sulfide were

0.007 lb/hr (0.12 parts per million).

Economic• Economic data are not available.

Preaward Design and Construction Operation and Reporting

1988 1989 1990 1991 1992 1993 1994 1999 2000

12/88 9/90 6/92

Design completed 8/91

DOE selected project(CCT-I) 12/9/88

Cooperative agreement

awarded 9/21/90

Ground breaking/construction started 3/28/91NEPA process completed (EA) 3/27/91

Preoperational tests initiated 12/91

Construction completed 2/92

Environmental monitoring plan completed 4/7/92

Test operation initiated 6/92

**

Operation comp
5-152 Program Update 2001 

Project SummaryThis project demonstrated an advanced, thermal, coalupgrading process, coupled with physical cleaning techniques, that was designed to upgrade high-moisture, lowrank coals to a high-quality, low-sulfur fuel, registered asthe SynCoalÆ process. The coal was processed through

three stages (two heating stages followed by an inert cooling stage) of vibrating fluidized-bed reactors that removechemically bound water, carboxyl groups, and volatilesulfur compounds. After thermal upgrading, the coal isprocessed in vibrating pneumatic stratifiers to separate thepyrite-rich coal refuse from the SynCoalÆ product.

The 45-ton-per-hour unit is located adjacent to a unit trainload-out facility at Western Energy Company's Rosebudcoal mine near Colstrip, Montana. The demonstrationplant was sized at about one-tenth the projected throughput of a projected commercial facility.Operational PerformanceDuring the life of the ACCP project, over 2.9 million tonsof raw coal was processed to produce almost 2.0 milliontons of SynCoalÆ products, which include regular, fines,

blends, dust stabilization enhancement (DSE) treated, andspecial characteristic SynCoalÆ shipped to various customers. See Exhibit 5-50 for annual statistics from the

Exhibit 5-50

ACCP Annual Production Rates

ACCP plant. The plant posted a perfect worker safetyrecord with no lost time accidents during the entire nineyears of operation. When operation ended in 2001, theACCP had been supplying six commercial customers withSynCoalÆ.

The product produced has been exceptionally close to thedesign basis product from a chemical standpoint, but wasnot acceptable for conventional bulk handling and storagedue to instability (spontaneous heating) and dustiness.Due to the instability, SynCoalÆ had to be stored with an

inert gas or in tightly sealed vessels to prevent air filtration. A CO2 inert storage system was developed and installed for silo storage of SynCoalÆ. A significant amount

of work has gone into addressing the instability issue. Inconjunction with ENCOAL LLC and Amax Coal Company, Western SynCoal researched the effects of differentenvironments and treatments on low-rank coal composition. Specific objectives were to study the exposivity andflammability limits of dust from the conversion processand to identify the causes of spontaneous heating of upgraded coal products. At the time activities were suspended, the development efforts were focused on the useof the Aeroglide Tower Reactor design.The Aeroglide reactor represents a novel method of allowing process gases to contact the solids in a mechanically gentle environment. 

flow, assisted only by gratem of baffles that gently tion of the solids from the controlled using a mass flbaffles are configured perrow. Process gases are inttally configured baffles anuniformly. Process gases exit the process bed of soconfigured to rehydrate p

heat of reaction, and partieffort to promote product was intended to modify thSynCoalÆ product allowin

techniques to be employepromising, but not concluWith regard to the operatiSynCoalÆ product, three dat the ACCP facilityóNolignite, and Amax subbitu190 tons of the SynCoalÆ 

North Dakota lignite was clone-fired Milton R. YouTesting showed dramatic 

1992 1993 1994 1995 1996 1997 1998 1999 2000 

Raw Coal 28,686 157,421 371,447 479,621 369,652 395,450 163,272 419,296 441,379 

Processed (tons)Availability (%) 18 50 65 78 65 66 28 70 73 Forced Outage 68 24 26 13 21 26 8 15 14 Rate (%)Avg. Feed Rate 21.1 35.8 64.8 70.1 64.3 68.0 66.0 68.4 69.(ton/hr)SynCoalÆ Shipped 5,566 57,927 208,428 315,688 238,766 250,070 97,575 288,650 291,604 

 (tons)

Note: 163,106 tons of fines sold in July 1997.
Coal Processing for Clean Fuels 

Exhibit 5-51

ACCP Stack Emissions

Survey Results

Limit Measured

Particulate Matter 0.031 gr/dscf 0.0259 gr/dscf

2.563 lb/hr

Nitrogen Oxides 7.95 lb/hra 4.50 lb/hr

11.55 lb/hrb 54.5 ppm

Carbon Monoxide 6.46 lb/hra 9.61 lb/hr

27.19 lb/hrb 191.5 ppm

Sulfur Dioxide 7.95 lb/hra 0.227 lb/hr

20.27 lb/hrb 2.0 ppm

Total Hydrocarbons as NA 2.93 lb/hrPropane (Less Methane 37.1 ppmand Ethane)Hydrogen Sulfide NA 0.007 lb/hr

0.12 ppm

a Estimated controlled emissions based on vendor information.b Estimated uncontrolled emissions based on vendor information.

bustion, improved slag tapping, and a 13% reduction inboiler air flow requirements. In addition, boiler efficiencyincreased from 82% to over 86%, and the total gross heatrate improved by 123 Btu/kWh.At the Colstrip plant with two coal-fired power plants,baseline testing at the start of the demonstration indicatedthat the 330-MWe Unit No. 2 was typically producing 2.9MWe (net) less than Unit No. 1, a sister unit of comparable capacity. In late Spring 1999, Unit No. 1 was overhauled, resulting in an increase in its average output of 7MWe (net). With this increase in output, the overhauledUnit No. 1 would have produced 5.4 MWe more thanUnit No. 2. However, for the days that SynCoalÆ was

used, Unit No. 2 out-produced the overhauled Unit No. 1by an average of 7.3 MWeó285.7 MWe versus 278.4MWe (net)ówith 15.0% of the total heat input comingfrom SynCoal. Furthermore, SynCoalÆ can be credited for

actual 1999 SO2 emissions reductions for Unit No. 2 of

approximately 430 tons, or an 8% reduction, and NOx

emissions reductions of approximately 826 tons, or a 19%reduction, when compared with Unit No. 1 emissions.Environmental PerformanceWestern SynCoal originally assumed that SO2 emissions

would have to be controlled by injecting chemical sorbentsinto the ductwork. Preliminary data indicated that the addition of chemical injection sorbent was not necessary tocontrol SO2 emissions under the operating conditions.

The coal-cleaning area's fugitive dust was controlled byplacing hoods over the fugitive dust sources conveyingthe dust-laden air to fabric filters. The bag filters effectively removed coal dust from the air before discharge.The Montana Department of Health and EnvironmentalSciences completed stack tests on the east and west baghouse outlet ducts and the first-stage drying gas baghousestack in 1993.A stack emissions survey was conducted in May 1994.The survey determined the emissions of particulates, sulfur dioxide, oxides of nitrogen, carbon monoxide, totalhydrocarbons, and hydrogen sulfide from the processstack. The results are shown in Exhibit 5-51.Economic PerformanceEconomic data are not available.

Commercial ApplicationsACCP has the potential to enhance the use of low-rankwestern subbituminous and lignite coals. The SynCoalÆ is

a viable compliance option for meeting SO2 emission

reduction requirements. SynCoalÆ is an ideal supplemental fuel for plants seeking to burn western low-rank coals

because the ACCP allows a wider range of low-sulfur rawcoals without derating the units.The project was able to prove the value of SynCoalÆ

through the seven commercial customers serviced duringthe last few years of operation. The customers representedutility, industrial, and metallurgical applications.The ACCP has the potential to convert inexpensive, lowsulfur low-rank coals into valuable carbon-based reducingagents for many metallurgical applications. Furthermore,SynCoalÆ enhances cement and lime production and provides a value-added bentonite product.

ContactsRay W. Sheldon, Genera

(406) 252-2277Western SynCoal LLP.O. Box 7137Billings, MT 59103-(406) 252-2090 (fax)

Douglas Archer, DOE/HJoseph B. Renk III, NETReferencesTechnical Progress RepSynCoal LLC. April 2001999, February 1999, A1995, December 1993, a
5-154 Program Update 2001 
Industrial Applications 

Industrial Applications
Industrial Applications

5-156 Program Update 2001 

Clean Power from IntegratedCoal/Ore Reduction(CPICORô)ParticipantCPICORô Management Company LLC (a limited liability company composed of subsidiaries of the GenevaSteel Company)Additional Team MembersGeneva Steel Holdings corporationócofunder,

constructor, host, and operator of unit

LocationVineyard, Utah County, UT (Geneva Steel Co.ís mill)TechnologyHIsmeltÆ direct iron-making process

Plant Capacity/Production3,300 ton/day liquid iron production 160 MW ofelectricityCoalBituminous, 0.5% sulfurProject FundingTotal project cost $1,065,805,000 100%DOE 149,469,242 14Participant 916,335,758 86

Project ObjectiveTo demonstrate the integration of direct iron making withthe coproduction of electricity using various U.S. coals inan efficient and environmentally responsible manner.Technology/Project DescriptionThe HIsmeltÆ process is based on producing hot metal

and slag from iron ore fines and non-coking coals. Theheart of the process is producing sufficient heat and maintaining high heat transfer efficiency in the post-combus- tion zone above the reaction zone to reduce and smelt iron oxides. The HIsmeltÆ 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 dis- solved rapidly. The carbon reacts with O2 (from the iron ore) to form CO and metallic iron. Injection gases and evolved CO entrain and propel droplets of slag and mol- ten iron upward into the post-combustion zone. The iron reduction reaction in the molten bath is endot- hermic; therefore, additional heat is needed to sustain the process and maintain hot metal temperature. This heat is generated by post-combusting the CO and hydrogen from the bath with an O2-enriched hot air blast from the central

top lance. The heat is absorbed by the slag and molten

iron droplets, which are rDroplets in contact with tzone absorb heat, but are ascending reducing gasesbon, prevent unacceptable molten iron collects in the tinuously tapped from the which maintains a constanSlag, which is periodicallblast furnace-type tap holinternal cooling system anReacted gases, mainly N2

vessel. After scrubbing thgases will be combusted tand can be used to pre-hecoming iron ore.

HIsmelt is a registered trademark of HIsmelt Corporation Pty Limited.CPICOR is a trademark of the CPICORô Management Company, LLC
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Calendar Year

Industrial Applications 

Project Status/AccomplishmentsThe cooperative agreement was awarded on October 11,1996. CPICORô analyzed the global assortment of newdirect iron-making technologies to determine which technology would be most adaptable to western U.S. coalsand raw materials. Originally, the COREXÆ process appeared suitable for using Genevaís local raw materials;

however, lack of COREXÆ plant data on 100% raw coals

and ores prevented its application in this demonstration.Thus, CPICORô chose to examine alternatives. Theprocesses evaluated included: AISI direct iron-making,DIOS, Romelt, Tecnored, Cyclonic Smelter, andHIsmeltÆ. The HIsmeltÆ process appears to offer good

economic and operational potential, as well as the prospect of rapid commercialization. CPICORô has completed testing of two U.S. coals at the HIsmeltÆ pilot plant

near Perth, Australia.Project definition, preliminary design, and environmentalpermitting are ongoing. On July 28, 1999, DOE issued aNotice of Intent to prepare an Environmental ImpactStatement for the project. A NEPA public scoping meetingwas held in Provo, Utah on July 15, 1999. CPICORôwants to have all permits in place before the end of 2001.

On February 1, 1999, Geneva Steel Company (CPICORôManagement Companyís parent corporation) filed a voluntary petition for bankruptcy under Chapter 11 of the UnitedStates Bankruptcy Code in the U.S. Bankruptcy Court forthe District of Utah. Geneva Steel emerged from Chapter11 bankruptcy in early 2001 with a restructured balancesheet that enables full participation in this demonstrationproject.On January 25, 2002, Geneva Steel LLC filed a voluntarypetition under Chapter 11 of the United States Bankruptcy Code. The filing in the United States BankruptcyCourt for Utah, Central Division, was required by thecompany's secured lenders as a condition to providingcontinued access to cash proceeds from the sale of inventory and the collection of accounts receivable. Withoutsuch access, Geneva Steel would not have sufficient liquidity to continue its activities and protect its facilities.CPICORô has issued several major contracts for theengineering design of the project. HIsmelt Plc. will perform all preliminary engineering required for Phase I ofthe project. Lurgi Metallurgy will assist in the design ofthe direct iron making process, with Rio Tinto (the parent

company of HIsmelt PlcLurgi will also provide egeneration process, inclexpander for power genCommercial ApplicaThe HIsmeltÆ technolog

ing blast furnace and cotional potential to produOf the existing 79 coke of age or older and are dbuilds. There are about which have been operatsome originally installed 

represents a viable optioiron-making technologyThe HIsmeltÆ process is 

pilot plants have been bone in Kwinana, AustraAustralia, the process hatrol parameters have beeputer models have been proven.

1992 1997 2001 1993 1996 2002 2003 2004 2005 

DOE selected project(CCT-V) 5/4/93

5/93

Preaward

Cooperative agreement awarded 10/11/96

NEPA process completed 7/02*

Construction started 7/02*

Design and Construction

Operation initiated 9Construction comple

Operatio

**

Environmental monitoring

plan completed 1/04*

9/04

**

10/96 
Industrial Applications

5-158 Program Update 2001 

Blast Furnace Granular-CoalInjection SystemDemonstration ProjectProject completedParticipantBethlehem Steel CorporationAdditional Team MembersBritish Steel Consultants Overseas Services, Inc.

(marketing arm of British Steel Corporation)—technology owner

Clyde Pneumatic (formerly named Simon-Macawber,

Ltd.)—equipment supplier

Fluor Daniel, Inc.—architect and engineerATSI, Inc.—injection equipment engineer (North

America technology licensee)

LocationBurns Harbor, Porter County, IN (Bethlehem Steel’sBurns Harbor Plant, Blast Furnace Units C and D)TechnologyBritish Steel and Clyde Pneumatic blast furnace granularcoal injection (BFGCI) processPlant Capacity/Production7,000 net tons of hot metal (NTHM)/day requiring 2,800tons/day of coal (each blast furnace)CoalVirginia Pocahontas/Buchanan; 0.76% S, 86.39% COxbow; 0.76% S, 73.2% CProject FundingTotal project cost $194,301,790 100%DOE 31,824,118 16Participant 162,477,672 84

Project ObjectiveTo demonstrate that granular coal could effectively displace coke and maintain established blast furnace production rates and quality specifications; to determine theeffect of coal chemistry, such as ash content (quantity andsulfur levels) and volatile levels, on blast furnace performance; and to evaluate the economics of granular coalinjection relative to natural gas injection.Technology/Project DescriptionThe BFGCI process uses granular coal, which requiressignificantly less grinding energy than pulverized coal toproduce. The coal, along with heated air, is blown into thelower part of the blast furnace through passages calledtuyeres, which create swept zones in the furnace calledraceways. This preheated blast air provides partial oxidation of the coke introduced along with the iron ore andlimestone at the top of the furnace. The coke serves as the

primary fuel and reducing bon reacts with the air anheat, iron, and carbon mofluxing agent, creating a sents such as sulfur and silThe low-Btu gas leaving sulfur and is used to prehon-site power.Bethlehem Steel introducreduce the amount of cokwhich also replaced the nthe tuyeres for supplemenemissions result from coksive, expensive control syted Units C and D at its Bat 7,000 NTHM/day. The effect of coal size and cheperformance and econom

TO STEEL MAKING
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Calendar Year

Industrial Applications 

Results SummaryEnvironmental• BFGCI technology, using low-volatile, low-ash coal,

displaced up to 0.96 pounds of coke for every poundof coal, which avoids the air toxics emissions associated with comparable coke production. By adjustingblast furnace slag, no additional sulfur emissions resulted from the coal injection, and sulfur levels in theproduct remained within the specified range.

Operational• Granular coal performed as well as pulverized coal on

the large blast furnaces and proved easier to handlethan pulverized coal, which tended to plug when usinglow-volatile coals. Direct comparative testing on aspecific coal showed that 60% less energy is consumed in granulating coal than in pulverizing coal.

• Coal injection decreased furnace permeability, which

can adversely affect hot blast flow rate and furnaceproductivity, but increasing oxygen enrichment andmoisture content returned permeability and productivity to acceptable levels. Low-volatile coal replaced significantly more coke than lower carbon content, high-volatile coal, which was a major objective and also a measure of the quality of the overall operation. Using low-volatile Virginia Pocahontas coal, the coke rate was reduced from approximately 740 lb/NTHM to 661 lb/NTHM. • There is a coke rate disadvantage of 3 lb/NTHM for each one percent increase in ash content at an injection rate of 260 lb/NTHM. Higher ash coal had no adverse effect on furnace permeability, productivity, or product quality, but the slag volume increased. Economic • The capital cost for one complete injection system at Burns Harbor was $15,073,106 (1990$) 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. At a total cost of $60/ton and a natu- ral gas cost of $2.80/106 Btu, the iron cost savings would be about $6.5

the Burns Harbor proiron per year, the ann

1989 1990 1991 1993 1994 1995 1996 1997 1998 

Preaward

DOE selectedproject (CCT-III)12/19/89

12/89 11/90

Cooperative agreement awarded 11/26/90

Design and Construction Operation and Reporting

final 

Operation completed 1

**

NEPA process completed (EA) 6/8/93

Construction started 9/93

Design completed 12/93

Environmental monitoring plan completed 12/23/94

Construction completed 1/95

Preoperational tests initiated 2/95

Operation initiated 11/95

11/95
5-160 Program Update 2001 

Project SummaryBethlehem Steel retrofitted two high-capacity blast furnaces with BFGCI technology, Units C and D, at theirBurns Harbor facility in a successful attempt to reducecoke use and become a self-sufficient supplier. The questions posed in applying the technology went to the effectof coal grind (size) and coal chemistry on coke displacement and furnace performance. A coal pulverizer in lieuof a less energy- and capital-intensive hammer mill, wasused to provide a range of coal grinds from granular (30%passing 200 mesh) to pulverized (80% passing 200mesh). Each 7,000-NTHM/day furnace required approximately 2,800 tons/day of coal. Each BFGCI unit includeda raw coal reclaim area and two 240-ton enclosed storagebins, a 500-Hp Williams variable speed coal-grinding milland integrated dryer, two 180-ton product coal silos designed to exclude oxygen, two distribution bins each with14 conical pant leg distributors, 28 injectors with lockhoppers and metered screw feeders, and a high-pressureair system transporting the coal 600 feet to injectionlances mounted on 28 separate tuyeres.Operational PerformanceInitial steady-state testing involved operation on granulated(15% passing 200 mesh) Virginia Pocahontas low-ash,low-volatile, high-carbon coal in the Unit C furnace. Thiscoal was selected as the baseline coal after a series of trialson different coal types. An average coal injection rate of264 lb/NTHM was achieved over the baseline October1996 performance period. The furnace coke rate during theperiod was 661 lb/NTHM, down from 740 lb/NTHM whenoperating on natural gas.Increasing slag volume in the furnace controlled the additional sulfur and silicon loading from the coal injection tospecified levels in the hot metal product. The slag alsocaptured sufficient sulfur to prevent any additional sulfur inthe furnace gas output. An adverse downturn in furnacepermeability resulting from coal injection was moderatelyincreased and compensated for by increasing the oxygenenrichment from 24.4–27.3% and increasing steam inputfrom 3.7 grains/scf to 19.8 grains/scf. The permeabilityadjustments enabled furnace productivity to be maintained.

To determine the coal/coke replacement ratio, all factorsimpacting on coke rate other than coal injection had to beremoved from the equation. After doing so, the adjustedfurnace coke rate shows that one pound of VirginiaPocahontas baseline coal displaces 0.96 pounds of coke.The next test addressed the impact of ash volume on cokedisplacement and furnace performance. To do so, only thepercentage of ash was increased, not the coal or ash chemistry. This was done by eliminating a coal cleaning step onthe Pocahontas Seam coal (obtained from the BuchananMine), which increased the ash content from 5.3–7.7%.Tests showed that there is a coke rate disadvantage of3 lb/NTHM for each one percentage point increase in coalash content at an injection rate of 260 lb/NTHM; and thehigher ash coal had no adverse impact on furnace permeability, productivity, or product quality.Comparative testing followed to evaluate the effect ofcoal grind size (granular versus pulverized) on cokedisplacement and furnace performance as well as theeffects of coal chemistry. Furnace D was used becauseof some temporary operating difficulties on Furnace C.A high-volatile, low-carbon Oxbow western coal wasused in lieu of the baseline coal because of pluggingproblems experienced when pulverizing the baselinelow-volatile coal and because there was the need toevaluate the impact of high-volatile coal on furnaceperformance. The Oxbow coal averaged 73.2% carbonand 11.2% ash versus 86.3% carbon and 5.3% ash forthe baseline coal. The granular Oxbow coal grind was15% passing 200 mesh and the pulverized Oxbow coalgrind was 74% passing 200 mesh. Granular coal production required 60% less energy (19.6 kWh/ton) thanpulverized coal production (31.4 kWh/ton). The grinding mill production rate for pulverizing the coal limitedthe coal injection rate to 183 lb/NTHM. After adjustingfor the lower coal injection rate and other factors, it wasdetermined that the coke rate when using the Oxbowcoal was 46 lb/NTHM higher than when using the lowvolatile baseline coal during tests—a substantial disadvantage. The blast furnace performance was unaffectedby whether the coal was pulverized or granular at thecoal injection rate of 183 lb/NTHM.

Environmental PerforData collected over each injected coal in the blast fcrease in the sulfur conten0.76% sulfur. Evidence suvolume and chemistry cosulfur coals. However, the application of the BFGCI coke usage. Coke productbe avoided if at all possibBFGCI technology, Bethlproduction with the limitesite.Economic SummaryCapital cost for one compHarbor was approximately not include infrastructure million at Burns Harbor. Tincludes labor and repair cvariable operating cost, whnatural gas, and nitrogen, were $50–60/ton. This bro$59.81–69.81/ton of coal. natural gas cost of $2.80/1

be about $6.50/ton of iron which produces 5.2 millionual savings would be aboperiod 3.44 years, using a Commercial ApplicatiThere are 35 operating blSeventeen of them are alrinjection. An extensive mBethlehem Steel showed have the potential to utiliz1994, U.S. Steel Group coPneumatic for the installaFairfield Works in Alabamwhich began operating in except that no added coal meet the granular coal sizWorks Blast Furnace #8 pBFGCI installation cost a
Industrial Applications 

with an additional $5.5 million required to build a coalload-out facility.ContactsRobert Bouman, Manager, (610) 694-6792

Bethlehem Steel CorporationBuilding C, Room 211Homer Research LaboratoryMountain Top CampusBethlehem, PA 18016(610) 694-2981 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Leo E. Makovsky, NETL, (412) 386-5814ReferencesBlast Furnace Granular Coal Injection System, FinalReport Volume 2—Project Performance and Economics.Bethlehem Steel Corporation. October 1999“Blast Furnace Granular-Coal Injection System Demonstration Project.” Hill, D.G. et al. Sixth Clean Coal Conference Proceedings: Volume II—Technical Papers.April–May, 1998.
Industrial Applications

5-162 Program Update 2001 

Advanced CycloneCombustor with InternalSulfur, Nitrogen, and AshControlProject completedParticipantCoal Tech CorporationAdditional Team MembersCommonwealth of Pennsylvania, Energy Development

Authority—cofunder

Pennsylvania Power and Light Company—supplier of

test coals

Tampella Power Corporation—hostLocationWilliamsport, Lycoming County, PA (Tampella PowerCorporation’s boiler manufacturing plant)TechnologyCoal Tech’s advanced, air-cooled, slagging combustorPlant Capacity/Production23 x 106 Btu/hr of steam

CoalPennsylvania bituminous, 1.0–3.3% sulfurProject FundingTotal project cost $984,394 100%DOE 490,149 50Participant 494,245 50

Project ObjectiveTo demonstrate that an advanced cyclone combustor canbe retrofitted to an industrial boiler and that it can simultaneously remove up to 90% of the SO2 and 90–95% of

the ash within the combustor and reduce NO

x to 100 ppm.

Technology/Project DescriptionCoal Tech’s horizontal cyclone combustor is lined with anair-cooled ceramic. Pulverized coal, air, and sorbent areinjected tangentially toward the wall through tubes in theannular region of the combustor to cause cyclonic action.In this manner, coal-particle combustion takes place in aswirling flame in a region favorable to particle retentionin the combustor. Secondary air is used to adjust the overall combustor stoichiometry. Tertiary air is injected at thecombustor/boiler interface. The ceramic liner is cooled bythe secondary air and maintained at a temperature highenough to keep the slag in a liquid, free-flowing state.The secondary air is preheated by the combustor walls toattain efficient combustion of the coal particles in thefuel-rich combustor. Fine coal pulverization allows combustion of most of the coal particles near the cyclonewall. The combustor was designed so that a high percentage of the ash and sorben

tained as slag. For NOx co

fuel rich, with final combfurnace to which the com

captured by injection of lThe cyclonic action insidash and sorbent to the waliquid slag. Under optimacontains a significant fracDownstream sorbent injecadditional sulfur removal In Coal Tech’s demonstratcyclone coal combustor w

oil-fired package boiler loCorporation boiler factory 
 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 

Calendar Year

Industrial Applications 

Results SummaryEnvironmental• SO2 removal efficiencies of over 80% were achieved

with sorbent injection in the furnace at various calcium-to-sulfur (Ca/S) molar ratios.

• SO2 removal efficiencies up to 58% were achieved

with sorbent injection in the combustor at a Ca/S molar ratio of 2.0.

• A maximum of one-third of the coal’s sulfur was retained 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

x emissions were reduced to 184 ppm by the combustor and furnace, and to 160 ppm with the addition

of a wet particulate scrubber.

• Combustor slag was essentially inert.• Ash/sorbent retention in the combustor as slag averaged 72% and ranged from 55–90%. Under more fuellean 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 demonstrated. Protection of combustor refractory with slag

was shown to be possible.

• A computer-controlled system for automatic combustor

operation was developed and demonstrated.

Economic• Because the technology failed to meet commercialization criteria, economics were not developed during the

demonstration. However, subsequent efforts indicatethat the incremental capital cost for installing the coalcombustor in lieu of oil or gas systems is $100–200/kW.

1986 1989 1990 1987 1988 1991 1992 1993 1994 

Preaward

Operation and Reporting

7/86 3/87 11/87

Design and

Construction

DOE selected project (CCT-I) 7/24/86

Design completed 7/87Ground breaking/construction started 7/87

Cooperative agreement awarded 3/20/87NEPA process completed (MTF) 3/26/87

Environmental monitoring plan completed 9/22/87

Construction completed 11/87Operation initiated 11/87

Operation

completed 5/90

9/91

Project completed/final report issued 9/91
5-164 Program Update 2001 

Project SummaryThe novel features of Coal Techís patentedceramic-lined, slagging cyclone combustorincluded its air-cooled walls and environmental control of NOx, SO2, and solid waste

emissions. Air cooling took place in a verycompact combustor, which could be retrofitted to a wide range of industrial and utilityboiler designs without disturbing the boileríswater-steam circuit. In this technology, NOx

reduction was achieved by staged combustion, and SO2 was captured by injection of

limestone into the combustor and/or boiler.Critical to combustor performance was removal of ash as slag, which would otherwiseerode boiler tubes. This was particularlyimportant in oil furnace retrofits where tubespacing is tight (made possible by the lowash content of oil-based fuels).The test effort consisted of 800 hours of operation, including five individual tests, each of four days duration. Anadditional 100 hours of testing was performed as part of aseparate ash vitrification test. Test results obtained duringoperation of the combustor indicated that Coal Tech attained most of the objectives contained in the cooperativeagreement. About eight different Pennsylvania bituminouscoals with sulfur contents ranging from 1.0ñ3.3% andvolatile matter contents ranging from 19ñ37% were tested.Environmental PerformanceA maximum of over 80% SO2 reduction measured at the

boiler outlet stack was achieved using sorbent injection inthe furnace at various Ca/S molar ratios. A maximum SO2

reduction of 58% was measured at the stack with limestone injection into the combustor at a Ca/S molar ratio of2. A maximum of one-third of the coalís sulfur was retained in the dry ash removed from the combustor andfurnace hearths, and as much as 11% of the coalís sulfurwas retained in the slag rejected through the slag tap.Additional sulfur retention in the slag is possible by increasing the slag flow rate and further improving fuel-richcombustion and sorbent-gas mixing.With fuel-rich operation of the combustor, a three-fourthsreduction in measured boiler outlet stack NOx was obtained, corresponding to 184 ppm. An additional reduc- tion was obtained by the action of the wet particulate scrubber, resulting in atmospheric NOx emissions as low as 160 ppm. All the slag removed from the combustor produced trace metal leachates well below EPAís Drinking Water Stan- dard. Total ash/sorbent retention as slag in the combustor, under efficient combustion operating conditions, averaged 72% and ranged from 55ñ90%. Under more fuel-lean con- ditions, the slag retention averaged 80%. After the CCT project, tests on fly ash 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 emission 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 106 Btu/hr from a peak of 19 x 106 Btu/hr (or a 3-to-1 turndown) was achieved. The maximum heat input during the tests was around 20 x 106 Btu/hr, even though the combustor was designed for 30 x 106 Btu/hr and the

boiler was thermally rated 

situation resulted from fafor the boiler. In fact, due cooling, even 20 x 106 Bt

of the testing was conducDifferent sections of the cals requirements. Suitable identified. Also, the test eprocedures were closely cAs an example, by implemas changing the combustosible to replenish the comwith slag produced during adding ceramic to the comThe combustorís total opeCCT project was about 90mately 100 hours of opercation test projects. Of thwith coal; about 125 tons Developing proper combualso a project objective. Nating an air-cooled combuoperating database was inctrolled system for automatCommercial ApplicatiThe goal of this project wof the air-cooled combustthe combustor was not yemercial guarantees, it was potential. Subsequent wobrought the technology clContactsBert Zauderer, President, 

Coal Tech CorporationP.O. Box 154Merion Station, PA 19coaltechbz@compuser(610) 677-0576 (fax)

William E. Fernald, DOEJames U. Watts, NETL, (4

The slagging combustor, associated piping, and control panel for CoalTechís advanced ceramic-lined slagging combustor are shown.
Industrial Applications 

ReferencesThe Coal Tech Advanced Cyclone Combustor Demonstration Project—A DOE Assessment. Report No. DOE/PC/79799-T1. 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 forthe Conversion of a 23-MMBtu/Hour Oil Fired Boiler toPulverized Coal; Vol. 1: Final Technical Report; Vol. 2:Appendixes I–V; Vol. 3: Appendix VI. Coal Tech Corporation. August 1991. (Available from NTIS as DE92002587and DE92002588.)Comprehensive Report to Congress on the Clean CoalTechnology Program: Advanced Cyclone Combustor withInternal Sulfur, Nitrogen, and Ash Control. Coal TechCorporation. Report No. DOE/FE-0077. U.S. Departmentof Energy. February 1987. (Available from NTIS asDE87005804.)

Coal Tech’s slagging combustor demonstrated the capability to of the non-fuel components injected into the combustor. The slaessentially an inert, glassy by-product with value in the construcin the manufacture of abrasives.
Industrial Applications

5-166 Program Update 2001 

Cement Kiln Flue GasRecovery ScrubberProject completed.ParticipantPassamaquoddy TribeAdditional Team MembersDragon Products Company—project manager and hostHPD, Incorporated—designer and fabricator of tanks and

heat exchanger

Cianbro Corporation—constructorLocationThomaston, Knox County, ME (Dragon ProductsCompany’s coal-fired cement kiln)TechnologyPassamaquoddy Technology Recovery ScrubberTMPlant Capacity/Production1,450 ton/day of cement; 250,000 scfm of kiln gas; andup to 274 ton/day of coalCoalPennsylvania bituminous, 2.5–3.0% sulfurProject FundingTotal project cost $17,800,000 100%DOE 5,982,592 34Participant 11,817,408 66Project ObjectiveTo retrofit and demonstrate a full-scale industrial scrubberand waste recovery system for a coal-burning wet processcement kiln using waste dust as the reagent to accomplish90–95% SO2 reduction using high-sulfur eastern coals;

and to produce commercial, potassium-based fertilizerby-products.

Technology/Project DescriptionThe Passamaquoddy Technology Recovery ScrubberTMuses cement kiln dust (CKD), an alkaline-rich (potassium)waste, to react with the acidic flue gas. This CKD, representing about 10% of the cement feedstock otherwise lostas waste, is formed into a water-based slurry and mixedwith the flue gas as the slurry passes over a perforatedtray that enables the flue gas to percolate through theslurry. The SO2 in the flue gas reacts with the potassium

to form potassium sulfate, which stays in solution andremains in the liquid as the slurry undergoes separationinto liquid and solid fractions. The solid fraction, in thickened slurry form and freed of the potassium and otheralkali constituents, is returned to the kiln as feedstock (itis the alkali content that makes the CKD unusable asfeedstock). No dewatering is necessary for the wet process used at the Dragon Products Company cement plant.

The liquid fraction is passwaste heat in the flue gas cover dissolved alkali methe incoming flue gas temevaporation, enables the ustruction material, and proter through condensation The Passamaquoddy Techwas constructed at the DraThomaston, Maine, a plan450,000 ton/yr of cement. the Passamaquoddy Indian to solve landfill problems, dispose of CKD from the 
 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 

Calendar Year

Industrial Applications 

Results SummaryEnvironmental• The SO2 removal efficiency averaged 94.6% during

the last several months of operation and 89.2% for theentire operating period.

• The NO

x 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, whichresulted in reducing the raw feedstock requirement by10% 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 achievedwith dust loadings of approximately 0.04 gr/scf.

• Pilot testing conducted at U.S. Environmental Protection Agency laboratories under Passamaquoddy Technology, L.P. sponsorship showed 98% HCl removal.• On three different runs, VOC (as represented by alphapinene) removal efficiencies of 72.3, 83.1, and 74.5%

were achieved.

• A reduction of approximately 2% in CO2 emissions

was realized through recycling of the CKD.

Operational• During the last operating interval, April to September

1993, recovery scrubber availability (discounting hostsite downtime) steadily increased from 65% in April1993 to 99.5% in July 1993.

Economic• Capital costs are approximately $10,090,000 (1990$)

for a recovery scrubber to control emissions from a450,000-ton/yr wet process plant, with a simple payback estimated in 3.1 years.

• Operation and maintenance costs, estimated at

$500,000/yr, plus capital and interest costs, are generally offset by avoided costs associated with fuel, feedstock, and waste disposal and with revenues from thesale of fertilizer.

1988 1991 1992 1989 1990 1993 1994 1995 1996 

Preaward Design and Construction

9/88 8/91

Operation and Reporting

DOEselectedproject(CCT-II)9/28/88

12/89

Design completed 4/90

Environmental monitoring plancompleted 3/26/90

Operation initiated 8/91

Construction completed 5/91Preoperational tests initiated 5/91

NEPA process completed (EA) 2/16/90

Cooperative agreement awarded 12/20/89

2/94

Project completed/final report issued 2/94

Construction started 6/89

Operation

completed 9/93
5-168 Program Update 2001 

Project SummaryThe Passamaquoddy Technology Recovery Scrubberô isa unique process that achieves efficient acid gas and particulate control through effective contact between flue gasand a potassium-rich slurry composed of waste kiln dust.Flue gas passes through the slurry as it moves over aspecial sieve tray. This results in high SO2 and particulate

capture, some NOx reduction, and sufficient uptake of the

potassium (an unwanted constituent in cement) to allowthe slurry to be recycled as feedstock. Waste cement kilndust, exhaust gases (including waste heat), and wastewater are the only inputs to the process. Renovated cementkiln dust, potassium-based fertilizer, scrubbed exhaustgas, and distilled water are the only proven outputs. Thereis no waste.The scrubber was evaluated over three basic operatingintervals dictated by winter shutdowns for maintenanceand inventory and 14 separate operating periods (withinthese basic intervals) largely determined by unforeseenhost-plant maintenance and repairs and a depressed cement market. Over the period August 1991 to September1993, more than 5,300 hours were logged, 1,400 hours inthe first operating interval, 1,300 hours in the secondinterval, and 2,600 hours in the third interval. Sulfur loadings varied significantly over the operating periods due tovariations in feedstock and operating conditions.Operational PerformanceSeveral design problems were discovered and correctedduring startup. No further problems were experienced inthese areas during actual operation.Two problems persisted into the demonstration period.The mesh-type mist eliminator, which was installed toprevent slurry entrainment in the flue gas, experiencedplugging. Attempts to design a more efficient water sprayfor cleaning failed. However, replacement with a chevron-type mist eliminator prior to the third operating interval was effective. Potassium sulfate pelletization provedto be a more difficult problem. The cause was eventuallyisolated and found to be excessive water entrainment dueto carry-over of gypsum and syngenite. Hydroclones wereinstalled in the crystallizer circuit to separate the very finegypsum and syngenite crystals from the much coarser

potassium sulfate crystals. Although the correction wasmade, it was not completed in time to realize pellet production during the demonstration period. After all modifications were completed, the recovery scrubber enteredinto the third and final operating intervalóApril to September 1993. During this interval, recovery scrubberavailability (discounting host site downtime) steadilyincreased from 65% in April to 99.5% in July.Environmental PerformanceAn average 250 ton/day of CKD waste generated by theDragon Products plant was used as the sole reagent in therecovery scrubber to treat approximately 250,000 scfm offlue gas. All the CKD, or approximately 10 ton/hr, wasrenovated and returned to the plant as feedstock andmixed with about 90 ton/hr of fresh feed to make up the

required 100 ton/hr. The ato potassium-based fertiliExhibit 5-52 lists the numriod, SO2 and NOx inlet a

hour, and removal efficienoperating period.Average removal efficienperiod were 89.2% for SO

No definitive explanation 

was available at the conclAside from the operating sessment was made of inl

efficiency. For SO2 inlet l

less, recovery scrubber re82.0%. For SO2 inlet load

Exhibit 5-52

Summary of Emissions and Removal Eff

Operating Operating Inlet (lb/hr) Outlet (lb/hr) Period Time (hr) SO2 NOx SO2 NOx 1 211 73 320 10 279 2 476 71 284 11 260 

3 464 87 292 13 251 4 259 131 252 16 165 

5 304 245 293 28 243 6 379 222 265 28 208 

7 328 281 345 28 244 8 301 124 278 10 188 

9 314 47 240 7 194 10 402 41 244 6 218 

11 460 36 315 6 267 

12 549 57 333 2 291 13 464 86 288 4 223 

14 405 124 274 9 199 Total operating time 5,316Weighted Average 109 289 12 234 
Industrial Applications 

removal efficiency increased to 94.1% and up to 98.5%for loads greater than 200 lb/hr.In compliance testing for Maine’s Department of Environmental Quality, the recovery scrubber was subjected todust loadings of approximately 0.04 gr/scf and demonstrated particulate emission rates of 0.005–0.007 gr/scf—less than one-tenth the current allowable limit.Economic PerformanceThe estimated “as-built” capital cost to reconstruct theDragon Products prototype, absent the modifications, is$10,090,000 in 1990 dollars.Annual operating and maintenance costs are estimated 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 nocosts for reagents or disposal, and no dedicated staffing ormaintenance equipment is required.The simple payback on the investment is projected in aslittle as 3.1 years considering various revenues and

The Passamaquoddy Technology Recovery ScrubberTM wassuccessfully demonstrated at Dragon Products Company’scement plant in Thomaston, Maine.

avoided costs that may be realized by installing a recoveryscrubber similar in size to the one used at Dragon Products. In making this projection, $6,000,000 was added tothe “as-built” capital costs to allow for contingency, design/permitting, construction interest, and licensing fees.Commercial ApplicationsOf the approximately 2,000 Portland cement kilns in theworld, about 250 are in the United States and Canada.These 250 kilns emit an estimated 230,000 ton/yr of SO2(only three plants have SO2 controls, one of which is the

Passamaquoddy Technology Recovery ScrubberTM). Theapplicable market for SO2 control is estimated at 75% of

the 250 installations. If full penetration of this estimatedmarket were realized, approximately 150,000 ton/yr ofSO2 reduction could be achieved.

The scrubber became a permanent part of the cementplant at the end of the demonstration. A feasibility studyhas been completed for a Taiwanese cement plant.ContactsThomas N. Tureen, Project Manager, (207) 773-7166

Passamaquoddy Technology, L.P.1 Monument Way, Suite 200Portland, ME 04101(207) 773-7166(207) 773-8832 (fax)

William E. Fernald, DOE/HQ, (301) 903-9448John C. McDowell, NETL, (412) 386-6175ReferencesPassamaquoddy Technology Recovery ScrubberTM: FinalReport. Volumes 1 and 2 (Appendices A–M. Passamaquoddy Tribe. February 1994. (Vol. 1 available fromNTIS as DE94011175, Vol. 2 as DE94011176.)Passamaquoddy Technology Recovery ScrubberTM: Public Design Report. Report No. DOE/PC/89657-T2. Passamaquoddy Tribe. October 1993. (Available from NTIS asDE94008316.)Passamaquoddy Technology Recovery ScrubberTM:Topical Report. Report No. DOE/PC/89657-T1. Passamaquoddy Tribe. March 1992. (Available from NTIS asDE92019868.)

Comprehensive Report Technology Program: CScrubber. Passamaquod0152. U.S. Department (Available from NTIS a
Industrial Applications

5-170 Program Update 2001 

Pulse Combustor DesignQualification TestProject completedParticipantThermoChem, Inc.Additional Team MemberManufacturing and Technology Conversion International,Inc. (MTCI)—technology supplierLocationBaltimore, MD (MTCI Test Facility)TechnologyMTCI’s Pulsed EnhancedTM Steam Reforming processusing a multiple resonance-tube pulse combustor.Plant Capacity/Production30 million Btu/hr (steam reformer)CoalBlack Thunder (Powder River Basin) subbituminousProject FundingTotal project cost $8,612,054 100%DOE 4,306,027 50Participants 4,306,027 50Project ObjectiveTo demonstrate the operational/commercial viability of asingle 253-resonance-tube pulse combustor unit andevaluate characteristics of coal-derived fuel gas generatedby an existing Process Data Unit.Technology/Project DescriptionMTCI’s Pulsed EnhancedTM Steam Reforming processincorporates an indirect heating process for thermochemical steam gasification of coal to produce hydrogen-rich,clean, medium-Btu content fuel gas without the need foran oxygen plant. Indirect heat transfer is provided byimmersing a multiple resonance-tube pulse combustor in

a fluidized-bed steam gasification reactor. Pulse combustion increases the heat transfer rate by a factor of 3 to 5,thus greatly reducing the heat transfer area required in thegasifier.The pulse combustor represents the core of the PulsedEnhancedTM Steam Reforming process because it provides a highly efficient and cost-effective heat source.Demonstration of the combustor at the 253-resonancetube commercial scale is critical to market entry. The253-resonance-tube unit represents a 3.5:1 scale-up fromprevious tests. Testing verified scale-up criteria and appropriateness of controls and instrumentation. Also, anexisting process data unit was used to gasify coal feedstock to provide fuel gas data, including energy content,species concentration, and yield. Char from the processdata unit was evaluated as well.

The facility has a product two stages of cyclones, a tank, and a gas quench cochanger was used to rejecexcess steam (unreacted fthe venturi scrubber and gtesting was performed at more, Maryland.
 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 

Calendar Year

Industrial Applications 

Results SummaryEnvironmental• Initial testing showed NOx emissions were 79–97

ppmv corrected to 3% oxygen.

• Using recirculated flue gas in the combustor in a

second series of tests reduced NO

x

 emissions to

19–23 ppmv corrected to 3% oxygen.

Operational• Testing was conducted using bed temperatures of

1,000 °F, 1,100 °F, and 1,200 °F.

Economic• Economic data are not available.

1991 1992 1993 1994 1998 1999 2000 

Preaward

1995 1997

9/91 10/92

DOE selectedproject (CCT-IV)9/12/91

Cooperative agreementawarded 10/27/92

Project relocationrequested 10/26/94

Design and Construction

Revised cooperative agreement

awarded 9/29/98

Construction completed;

operation initiated 10/00

Operation co

10/0

Final rep

Design complete 2/15/99

Restructuring complete

3/21/98

Environmental monito

plan complete 12

Opera

NEPA process completed 11/98

**

PDU gasification 
5-172 Program Update 2001 

Project SummaryOn September 10, 1998, DOE approved revision ofThermoChem, Inc.’s Cooperative Agreement for a scaleddown project. The original project, awarded in October1992, was a commercial demonstration facility that wouldemploy 10 identical 253-resonance-tube pulse combustorunits. After fabrication of the first combustor unit, theproject went through restructuring. The revised projectwill demonstrate a single 253-resonance-tube pulse combustor. NEPA requirements were satisfied on November30, 1998, with a Categorical Exclusion. ThermoCheminitiated shakedown and commissioning tests on the 253-tube combustor in October 2000 and carried out emissions testing from December 2000 through May 2001.Environmental PerformanceThe thrust of the testing was to control NOx emissions to

acceptable levels. Initial tests at a firing rate of approximately 20 x 106 Btu/hr yielded NOx emissions ranging

from 79–97 ppmv corrected to 3% oxygen. Using recirculated flue gas (RFG) in the combustor in a second series of tests reduced NOx emissions to 19–23 ppmv corrected to 3% oxygen. Carbon monoxide emission levels aver- aged over 300 ppmv, but do not represent a problem because the combustor flue gas is reburned with product gas to produce steam. Tests indicated that the use of flue gas recycle limits NOx levels to acceptable values, as shown in Exhibit 5-53. Testing was conducted using natural gas as a proxy for coal-derived synthetic gas. At high firing rates, the use of flue gas recycle reduces the NOx levels, corrected to 3% oxygen, to about one-fourth those obtained when flue gas recycle was not utilized. At low firing rates, the reduction is to about one-third the non-FGR values. The CO levels and total hydrocarbons do not represent a problem be- cause the flue gas leaving the pulse combustors is reburned with a portion of the product gas to generate steam for the process. Since NOx once formed is very difficult to reduce, the focus was on generating accept- able levels of NO

x throughout the test program.

Operational PerformaSix series of tests were cotube pulse combustor. Th• Series 1: long shield tu

recycle bed temperaturfiring rate up to 14 x 1

• Series 2: long shield tu

and without flue gas re1,100 °F, natural gas f

• Series 3: long shield tu

and without flue gas re1,200 °F, natural gas f

• Series 4: short shield tu

without flue gas recyclnatural gas firing rate u

• Series 5: short shield t

recycle bed temperaturup to 16 x 106 Btu/hr.

Exhibit 5-53

253-Tube Pulse Heater Test—Partial Summary

Test Test Test Test Test Test 

Without Without Without Without With With 

FGR FGR FGR FGR FGR FGR 

Firing Rate (106 Btu/hr) 20.6 20.1 17.5 17.5 20.8 21 

Combustion Chamber Temp °F 2,500 2,520 2,500 2,540 2,400 2,490 

Decoupler Temp °F 1,200 1,238 1,240 1,265 1,201 1,245 Emissions as Measured:

NO

x, ppmv 58 51 59 57 22 18 

CO, ppmv 521 282 77 184 291 290 

Total HC, ppmv 61 24 6 7 IE 7 O2 (%) 10.2 9.3 5 8.6 4.2 4 

Emissions Corrected to 3% O2:

NO

x, ppmv 97 79 82 83 23 19 

CO, ppmv 868 434 107 268 312 307 

Total HC, ppmv 101 37 9 11 8 
Industrial Applications 

• Series 6: short shield tube, water bath, without flue gas

recycle bed temperature 212 °F, syn gas firing rate upto 11 x 106 Btu/hr.

Three tests were conducted on the PDU to evaluate charproduction. The three tests examined the impact of operating temperature. Bed temperatures included 1,000 °F,1,100 °F, and 1,200 °F.Economic PerformanceEconomic data are not available.Commercial ApplicationsPulsedEnhancedTM Steam Reforming has application inmany different processes. Coal, with world production onthe order of four billion tons per year, constitutes thelargest potential feedstock for steam reforming. Otherpotential feedstocks include spent liquor from pulp andpaper mills, refuse-derived fuel, municipal solid waste,sewage sludge, biomass, and other wastes.

Application of the technology to the production of charfor use in direct reduction of iron has the potential foraccomplishing significant reductions in pollutant emissions by reducing production of conventional metallurgical coke and facilitating the use of a new efficient ironmaking process.Although the project will demonstrate mild gasificationof coal only, the technology has application to:• Combined-cycle power generation;• Fuel cell power generation;• Cofiring or reburning to reduce NOx emissions;

• Production of gas or liquid fuel, and char for the steel

industry for use in direct reduction of iron ore;

• Production of compliance fuels;• Coal drying;• Black liquor processing and chemical recovery; and• Hazardous, low-level radioactive, and low-level mixed

waste volume reduction and destruction.

Project ContactsLee Rockvam, Project Manager(410) 354-9890(410) 354-9894 (fax)lrockvam@tchem.netThermoChem, Inc.6001 Chemical RoadBaltimore, MD 21226William E. Fernald, DOE/HQ,(301) 903-9448william.fernald@hq.doe.govLeo E. Makovsky, NETL,(412) 386-5814leo.makovsky@netl.doe.govReferencesInternal NETL data.

ThermoChem’s 253 tube 

ThermoChem’s test facility.
5-174 Program Update 2001 
Power Plant Improvement Initiative 

Role of the PPII ProgramThe Power Plant Improvement Initiative (PPII) wasestablished in fiscal year 2001 by Congress in PublicLaw 106-291, Department of the Interior and RelatedAgencies Appropriations Act for Fiscal Year 2001. Theact provided ìfor a general request for proposals forthe commercial scale demonstration of technologies toassure the reliability of the [n]ationís energy supplyfrom existing and new electric generating facilities forwhich the Department of Energy [(DOE)] upon reviewmay provide financial assistance awards . . . .î In theact, Congress transferred $95,000,000 for this purposefrom previously appropriated CCT Program funding.The roots of PPII lie in the blackouts and brownouts of1999 and 2000 and increasing concerns over the adequacy of the nationís power supplies as a whole.Several parts of the United States, including the WestCoast and parts of the Northeast, had experienced rolling blackouts and brownouts in the previous two yearscaused in large part by sharp rises in demand for electricity and lagging construction of new power plants.Program ImplementationIntroductionThe Department of Energy developed a PPII solicitation, incorporating general provisions of the CCTProgram (per congressional direction) with some modifications to take into account lessons learned from the

CCT Program. The program solicitation was issued onFebruary 6, 2001 and 24 proposals were received onApril 19, 2001. On September 28, 2001, a total of eightprojects valued at over $110 million were selected fornegotiations. Subsequently, one project was withdrawn.Exhibit 6-1 shows the locations of the selectedprojects. Contract awards are expected by March 2002.PPII SolicitationThe solicitation provided that participants must offersignificant improvements in power plant performanceleading to enhanced electric reliability. These improvements could be in the form of increasing theefficiency of electricity production, reducing environmental impacts, or increasing cost-competitiveness.The projects also had to be applicable to a large portion of existing plants and of commercial scale in orderto be deployed over the early part of the decade.Specific areas of interest expressed by DOE were:ï Advanced combustion or gasification systems and

components;

ï Advanced NOx control technology;ï CO2 capture, and utilization or sequestration;ï Combustion or gasification system improvements;ï Co-production;ï Fine particulate control;ï Hydrogen chloride control;ï Mercury control technology;ï Process control systems;ï Repowering;ï Steam cycle improvements; andï Wet and dry scrubbers for SO2 control.

The proposals were evof the proposed technoviability and market poogy (30 percent), and mbilities of the project tethe technical merit, DOfunding and financial pstraints; environmentaland program policy facOther implementing prproperty lies with the pLike the CCT Programprovide at least a 50 peprovide up to 25 percencost-shared by the partnal cooperative agreemrequired that 75 percencluding subcontract labStates.Potential participants wness plan with their procific to the proposed prdecision to commit funto address competition external. Finally, the plexpenditures of public would be a wise investresult in commercializaa public purpose and it cialized absent federal Potential participants almental Information VolEnergy uses the EIV to review of environmentaposed project prior to sdetailed site-specific reEnvironmental Policy A

6. Power Plant Improvement Initiative
6-2 Program Update 2001 Po

Exhibit 6-1

Geographic Locations of PPII Projects
Power Plant Improvement Initiative 

Intellectual Property RightsWith regard to intellectual property rights, there werethree main issues that must be addressed by the participants: commercialization of technology, data rights,and patent rights. For commercialization of technology,there must be a precise definition of the technologyenvelope and third-party licensing arrangements mustbe addressed. For data rights, the participant can protect proprietary technology and data; however, suchdata must be made available to DOE without limitations. Patent rights for inventions conceived or firstactually reduced to practice under DOE contract aredefined by statute and regulation and vary dependingon the status of the participant, e.g., large businessfirm, small business firm, or non-profit organization.Environmental ProvisionsThe PPII projects are considered CCT Programprojects for the purposes of regulatory review. Thusany provisions in the Clean Air Act that apply to CCTProgram projects, will apply to PPII projects. For example, section 414 of the Clean Air Act (42 U.S.C. §7651n) exempts temporary (less than 5 years of operation) clean coal technology projects from New SourcePerformance Standards and New Source Review forboth attainment and non-attainment areas. However,the facility must comply with the state’s State Implementation Plan and not cause National Ambient AirQuality Standards exceedences. Related provisionsexist for permanent repowering projects.PPII Funding and CostsThe PPII was established by the Department of theInterior and Related Agencies Appropriations for Fiscal Year 2001 (Public Law 106-291) through the transfer of $95,000,000 in previously appropriated funding

for the CCT Program. DOE commitments will be approximately $50 million with final values determinedduring negotiations.Repayment obligations start after the completion of thedemonstration and last for 20 years. The base repayment is one-half of one percent of gross equipmentsales and leases plus five percent of royalty and licensing fees. Repayment also covers foreign, as well asdomestic, sales and licenses. A grace period of up tofive years or 10 percent of sales and licenses may benegotiated.DOE also allowed for alternative approaches to repayment, but those approaches must generate equal orgreater repayment than the standard provisions. Forexample, a participant could pay a percentage of netrevenues from continued operation of the project aftercompletion of the demonstration period. In accordancewith congressional direction, repayments will be retained by DOE for future projects.PPII AccomplishmentsEight PPII projects were selected from 24 proposalssubmitted to DOE in April 2001. One project waseventually withdrawn in March 2002. Although exactdollar amounts will be determined during upcomingnegotiations, DOE expects to provide approximately$51 million for the eight projects. Private sector sponsors are expected to contribute nearly $61 million,exceeding the 50 percent private sector cost-sharingmandated by Congress. Projects will take from one tofive years to complete. The selected PPII projects arelisted in Exhibit 6-2.

PPII ProjecMost PPII projects foccoal-fired power plants environmental regulatiWith many coal plants cause of environmentalower cost emission coning while improving twater. Other projects wreliability of power plaAlliant Energy CorporaWisconsin, proposes to modeling to improve thsystems and “push the gies that reduce nitroge

contribute to smog, harEnergy Department’s $of the three demonstratat the Edgewood GeneWisconsin. The plant ucoal furnace especially emissions. Alliant Enering share for the 15-moArthur D. Little Inc., owill outfit a boiler at thLake Power Plant near pollution control system hybrid system will low

integrating three establ

gies: natural gas reburnduction, and selective cof the 38-month projecLittle will provide $15CONSOL Energy Inc., plans to demonstrate a to reduce NOx, sulfur d

gases, and fine particle
6-4 Program Update 2001 Po

less money than it costs to control NOx and SO2 separately. Among the innovations CONSOL plans to install at the AES Greenidge Power Plant near Dresden,

New York, is a catalytic NOx-reduction technology that

works inside the plant’s ductwork, a low-NOx combustion technology that burns coal mixed with biomass,

and a flue gas scrubber that is less complex and nearlyhalf the cost of conventional systems. Thegovernment’s share of the 54-month project will be$14.5 million; $18.3 million will be provided byCONSOL and its project partners.

Otter Tail Power Company, of Fergus Falls, Minnesota,will install a technology designed to capture up to99.9999 percent of the fly ash particles emitted from acoal boiler. To achieve the high capture rate, the company will integrate a fabric filter system (or “baghouse”) with an electrostatic precipitator (which useselectrically charged plates to attract ash particles) in asingle unit. The 36-month demonstration will takeplace at the company’s Big Stone Power Plant in SouthDakota. The Department of Energy’s $6.5 million costshare will be matched by $6.9 million in private sectorfunding.

Exhibit 6-2

PPII Technology Characteristics

Project Participant Process Combustion Initiative for Innovative Cost-Effective NO

x Alliant Energy Corporate Combustion Initiative method and re-engineering/mode

Reduction Services, Inc. optimize system performance to reduce NOx emissions

Development of Hybrid FLGR/SNCR/SCR Advanced NOx Arthur D. Little, Inc. A hybrid of Fuel-Lean Gas Reburn/Selective Non-Cata

Control for Orion Avon Lake Unit 9 Reduction, Selective Non-Catalytic Reduction, and Sel

Catalytic Reduction

Greenidge Multi-Pollutant Control Project CONSOL Energy, Inc. Single-bed Selective Catalytic Reduction in combinatio

low-NO

x combustion technology to control NOx and a 

dry scrubber to control SO2, mercury, and acid gases

Demonstration of a Full-Scale Retrofit of the Advanced Otter Tail Power Company Advanced Hybrid Particulate Collector 

Hybrid Particulate Collector TechnologyAchieving New Source Performance Standards Emission Sunflower Electric Power Ultra-low NOx burners with other combustion-stage co

Standards Through Integration of Low-NOx Burners with Corporationan Optimization Plan for Boiler CombustionPolk Power Station Plant Improvement Project Tampa Electric Company Refractory lining wear monitor Big Bend Power Station Neural Network-Sootblower Tampa Electric Company Neural-network soot-blowing system in conjunction wiOptimization advanced controls and instrumentsCommercial Demonstration of the Manufactured Universal Aggregates, LLC Aggregate manufacturing plant using by-products from Aggregate Processing Technology Utilizing Spray Dryer dryer desulfurization unitAsh

Sunflower Electric Powesas, will install ultra-lowbustion controls to democoncept that has never bing western subbituminoWyoming’s Powder Rivewill be demonstrated in company’s power station Department of Energy wflower Electric Power prTampa Electric Companyselected for two projectsin Apollo Beach, Florida
Power Plant Improvement Initiative 

ral network system to determine when and how best todislodge soot that can build up inside a boiler and degrade performance. While sootblowers arecommon in utility boilers, most are manually activatedunder preset rules or the operator’s judgment. Computercontrolled sootblowing technology will provide optimum cleaning of internal boiler surfaces that will lead toimproved power plant performance. The 36-monthproject will receive just under $1 million from DOE withTampa Electric providing almost $1.5 million.In a second project, Tampa Electric was to demonstratea laser system that measures the wear pattern of thebrick liner inside a coal gasifier. However, just prior topublication of this report, the participant withdrew theproject. Coal gasification is likely to be one of the newtechnologies installed in future power plants largelybecause it offers superior environmental performanceand efficiency improvements over today’s coal-burningboilers. In the Energy Department’s original CleanCoal Technology Program in the 1980s and 1990s,

Exhibit 6-3

PPII Project Fact Sheets by Project Name

Project Participant Achieving New Source Performance Standards Emission Standards Through Integration of Low-NOx Sunflower Electric Power Corporation 

Burners with an Optimization Plan for Boiler CombustionBig Bend Power Station Neural Network-Sootblower Optimization Tampa Electric Company 

Combustion Initiative for Innovative Cost-Effective NO

x

 Reduction Alliant Energy Corporate Services, Inc. 

Commercial Demonstration of the Manufactured Aggregate Processing Technology Utilizing Spray Universal Aggregates, LLC 

Dryer AshDemonstration of a Full-Scale Retrofit of the Advanced Hybrid Particulate Collector Technology Otter Tail Power Company 

Development of Hybrid FLGR/SNCR/SCR Advanced NOx Control for Orion Avon Lake Unit 9 Arthur D. Little, Inc. 

Greenidge Multi-Pollutant Control Project CONSOL Energy, Inc. Polk Power Station Plant Improvement Project Tampa Electric Company 

Tampa Electric built one of the nation’s pioneering coalgasification power plants in Polk County, Florida. TheDepartment of Energy was to fund $640,000 of the 18-month project’s $1.7 million total cost.Universal Aggregates LLC, of South Park, Pennsylvania, will demonstrate a system that converts the sludgefrom power plant scrubbers into light weight masonryblocks or concrete. Today more than 80% of thissludge is disposed of in landfills, and the practice isbecoming an increasingly contentious public issue.This 43-month project in Birchwood, Virginia, couldoffer an alternative by turning a pollutant into a commercially valuable product. The Department of Energywill fund $7.2 million while the company will provide$10.8 million.A list of the projects by project name is shown inExhibit 6-3 and a list by participant is shown inExhibit 6-4.
6-6 Program Update 2001 Po

Exhibit 6-4

PPII Project Fact Sheets by Participant

Participant Project Alliant Energy Corporate Services, Inc. Combustion Initiative for Innovative Cost-Effective NOx Reduction 

Arthur D. Little, Inc. Development of Hybrid FLGR/SNCR/SCR Advanced NOx Control for Orion Avon Lake Unit 9 

CONSOL Energy, Inc. Greenidge Multi-Pollutant Control Project Otter Tail Power Company Demonstration of a Full-Scale Retrofit of the Advanced Hybrid Particulate Collector Technology 

Sunflower Electric Power Corporation Achieving New Source Performance Standards Emission Standards Through Integration of 

Low-NO

x Burners with an Optimization Plan for Boiler Combustion

Tampa Electric Company Polk Power Station Plant Improvement Project 

Tampa Electric Company Big Bend Power Station Neural Network-Sootblower Optimization Universal Aggregates, LLC Commercial Demonstration of the Manufactured Aggregate Processing Technology Utilizing 

Spray Dryer Ash
Power Plant Improvement Initiative 

Power Plant Improvement Init
6-8 Program Update 2001 Po

Power Plant Improvement InitiativeCombustion Initiative forInnovative Cost-Effective NO

x

ReductionParticipantAlliant Energy Corporate Services, Inc.Additional Team MembersWisconsin Power & Light Co.—hostReaction Engineering International—modelingElectric Power Research Institute—technology supplierLocationsSheboygan, Sheboygan County, WI (Wisconsin Power& Light’s Edgewater Generating Station, Unit No. 4)TechnologyCombustion Initiative modifications for cyclone coalfired boiler technology using a Computational Fluid Dynamic (CFD) System Model to reduce NOx emissions,

which include a redesign of the cyclone re-entry throats,an upgrade of the gravimetric feeder controls, and chemical reagent injection.Plant Capacity/Production340 MWCoalPowder River Basin Coal (85%) and Kicker Coal (15%)Project FundingTotal Project Cost $7,397,718DOE 3,698,859Participant 3,698,859Project ObjectiveTo achieve the same, stringent nitrogen-oxide-emissionsreductions as selective catalytic reduction (SCR) at afraction of the capital cost and with drastically loweroperation and maintenance costs. Participant uses a computational modeling approach, its Combustion Initiative,to optimize overall power plant NOx performance. The

Combustion Initiative will attempt to hold NOx emissions

to 0.15 lb/106 Btu from a 340-MW cyclone boiler. Cyclone boilers are especially prone to high NOx emissions;

this demonstration could help establish a target baselinefor combustion-stage NOx reductions on cyclone boilers.

Technology/Project DescriptionThe Combustion Initiative is a method that starts withdeveloping a deep understanding of the combustion andrelated processes in each piece of equipment and in thepower plant as a whole. The second step is to push theenvelope for existing NOx control technologies throughre-engineering and modeling. The use of computationalmodeling as a tool is key to optimizing the system performance and maximizing the use of emission reductiontechnologies. The Combustion Initiative method results inthe potential to reduce NOx emissions to 0.15 lb/106 Btu

or below, without the use of SCR technology.
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Calendar Year

Power Plant Improvement Initiative 

2001 2002 2005 2003 2004 2006 2007 2008 2009 

Project Status/AccomplishmentsThe project was selected for award on September 26,2001. The Department of Energy selected this project fora partial award for demonstration on a cyclone boileronly. Contract negotiations are under way as of the end offiscal year 2001.Alliant Energy proposes, through its Wisconsin Power &Light Company subsidiary, to demonstrate the reductionof NO

x emissions using the Combustion Initiative method

on three of the main coal-fired boiler types in the UnitedStates: tangentially fired, cyclone-fired, and wall-firedunits. The three units include Edgewater Generating Station Unit No. 4 (cyclone) and Unit No. 5 (wall-fired) inSheboygan, Wisconsin, and Columbia Generating StationUnit No. 2 (tangentially fired) in Portage, Wisconsin.Better thermal efficiency will mean that less fuel will beneeded to produce energy, which saves money and reduces stress on equipment. Improved reliability will helpkeep customers lights on, even as demand grows throughout the region. Finally, when costs are minimized,shareowners experience increased earnings. Throughapplied science and technology, the Combustion Initiative

is helping Alliant Energy find cost-effective solutions tochallenges the power industry faces today and tomorrow.The ability to reach these low NOx emission levels has

been demonstrated in the pilot-scale work that AlliantEnergy has conducted at its M.L. Kapp Station in Iowa.This facility lowered its NOx emissions from 0.35 lb/106

Btu to 0.15 lb/106 Btu using the Combustion Initiative

Method.Commercial ApplicationsAlliant Energy’s Combustion Initiative is a science-andtechnology—driven approach to lowering emissions andimproving the performance of coal-fired power plants.Through research and development, the company is finding innovative ways to reduce emissions, increase thermalefficiency, and improve plant reliability. This technologyhas potential application to all 89 cyclone-fired boilers,having an installed capacity of 27,600 MWe. If successfully demonstrated, the relatively low capital cost of theCFD-based technology and the high potential NOx reduction should result in significant market penetration.

Project selected 9/26/01

Project complete/final report issued 12/03*

Cooperative agreementawarded 3/02*

3/02 12/03

The Wisconsin Departm(WDNR) has designated Control Region.” The Ethis region. The WDNR NOx emissions from utithrough September “ozotions, the Edgewater site 

sions to 0.33 lb/106 Btu 

gressively reduce emiss
6-10 Program Update 2001 Po

Power Plant Improvement InitiativeDevelopment of Hybrid FLGR/SNCR/SCR Advanced NO

x

Control for Orion Avon LakeUnit 9ParticipantArthur D. Little, Inc.Additional Team MembersFuel Tech—equipment supplierRelient Energy—hostLocationAvon Lake, Lorain County, OH (Orion Power’s AvonLake Station, Unit No. 9)TechnologyA hybrid of Fuel-Lean Gas Reburn/Selective Non-Catalytic Reduction, Selective Non-Catalytic Reduction, andSelective Catalytic ReductionPlant Capacity/Production623 MWCoalEastern Bituminous CoalProject FundingTotal Project Cost $30,513,711DOE 14,957,658Participant 15,556,053Project ObjectiveTo develop and demonstrate a hybrid system composedof lower-cost components from three established NOxreduction systems that can function as stand-alone units

or as an integrated, optimized, single-control system.Using Fuel-Lean Gas Reburn/Selective Non-CatalyticReduction (FLGR/SNCR), Selective Non-Catalytic Reduction (SNCR), and Selective Catalytic Reduction(SCR) systems, the hybrid seeks to lower NOx emissions

to 0.15 lb/106 Btu at lower costs than conventional SCR,

a comparatively expensive, effective way to curb NOx.

Technology/Project DescriptionThe three components in the hybrid system are FLGR/SNCR, SNCR, and compact SCR. The three componentshave been developed individually, but have not been developed and optimized as a hybrid control. The objectivesof this project are to demonstrate the hybrid as a lowercost alternative to SCR to achieve 0.15 lb/106 Btu emission levels, and to operate the hybrid system to improve

performance and reduce compliance costs to enhanceoperation in system-wide dispatch in the deregulatedmarket.
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Calendar Year

Power Plant Improvement Initiative 

2001 2002 2005 2003 2004 2006 2007 2008 2009 

Project Status/AccomplishmentsThe project was selected for award on September 26,2001. Contract negotiations are under way as of the endof fiscal year 2001. Long-term performance and emissionmonitoring will be done during the 2004 ozone season.The schedule will be finalized when contract negotiationsare complete.Commercial ApplicationsCoal-fired power boiler operators are facing a dual challenge to remain competitive while adapting to deregulationand to impending stringent NOx controls. The NOx control

technologies available to coal-fired operators are not optimized for this new set of challenges. Under deregulation,the optimum control techniques need to havea low capital cost base, and cost basis, and cost-effectivereduction over a wide operational range so that the performance of each unit in the system can be optimized to allowmaximum revenue dispatch. The increased flexibility isneeded to allow each boiler and the integratedsystem to respond competitively to market conditions.Current reliance on selective catalytic reduction, with theassociated high capital cost, will not typically give a utility

Project selected 9/26/01

Project complete/final report issued 9/04*

Cooperative agreementsigned 3/02*

3/02 9/04

sufficient dispatch flexibility to maximize competitiveness.Projections indicate that 30% of coal-fired boilers aregoing to be retrofitted with SCR. For the balance of units,power generators are looking for lower cost, more flexible means to design their units for competitive dispatchdictated by regional cost and environmental criteria.
6-12 Program Update 2001 Po

Power Plant Improvement InitiativeGreenidge Multi-PollutantControl ProjectParticipantCONSOL Energy, Inc.Additional Team MembersAES Greenidge, LLC—hostEnvironmental Elements Corporation (EEC)—technology

supplier

Foster Wheeler Energy Corporation (FWEC)—technology

supplier

AEP Pro Serv—construction coordinatorLocationTorrey, Yates County, NY (AES’ Greenidge Unit No. 4)TechnologySingle-bed Selective Catalytic Reduction in combinationwith low-NO

x combustion technology to control NOx and

a circulating dry scrubber with carbon injection to controlSO2, mercury, and acid gases

Plant Capacity/Production104 MWCoalBituminous coal (<2% sulfur) co-fired with up to 10%biomassProject FundingTotal Project Cost $32,800,000DOE 14,500,000Participant 18,300,000Project ObjectiveTo demonstrate a multi-pollutant-control system that cancost effectively reduce NOx, SO2, acidic gas, and mercury

from smaller coal plants. This project would be the first todemonstrate (1) NOx reductions to 0.122 lb/106 Btu using

single bed, in-duct Selective Catalytic Reduction (SCR)combined with a low-NO

x combustion technology on a

unit burning coal and biomass, (2) 95% SO2 removal

using a Circulating Dry Scrubber (CDS) from Environmental Elements Corp. on a coal-fired boiler, (3) 90%mercury reduction in the CDS, and (4) more than 95%acid gas (sulfur trioxide (SO3), hydrochloric (HCl), andhydrofluoric (HF) acids) removal in the CDS. The systemis projected to offer 60% NOx removal for one-third of

the capital cost and one-fourth of the operation and maintenance cost of conventional SCR or SNCR technology.Technology/Project DescriptionThe single-bed, in-duct SCR, in combination withlow-NO

x combustion technology, can achieve 60% NOx

reduction for about one-third the capital cost and onefourth the operating and maintenance cost of a full SCRor Selective Non-Catalytic Reduction (SNCR) system ona 104-MW unit. The capital cost of the CDS system is

projected to be less than hgas desulfurization (FGDnance costs are less for thinjection into the CDS untimes less carbon than dirduct for a given level of mcarbon has a greater averathan in the flue gas duct. results in substantial mercCDS system will reduce a

more than 95%, with the plume visibility and seconAcid gases must be reporRelease Inventory (TRI). evaluation of the impact othe heat input) on the perfsystems.
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Calendar Year

Power Plant Improvement Initiative 

2001 2002 2005 2003 2004 2006 2007 2008 2009 

Project Status/AccomplishmentsThe project was selected for award on September 26,2001. Contract negotiations are under way as of the endof fiscal year 2001. The schedule will be finalized whencontract negotiations are complete.The goal of the proposed project is to demonstrate substantial improvements in mercury, SO3 and fine particulate control, and substantial reductions in the cost for NOxand SO2 control, compared to conventional technologies

when applied to the large number of smaller coal-firedgenerating units in the U.S. This project will produceoperating and maintenance cost data, reliability and availability data, and process performance data so that generators will accept the risk of installing multi-pollutant control on smaller coal-fired units. Ultimately, the successfuldemonstration of these technologies will help to ensurethe future availability of low-cost electricity from a significant fraction of the U.S. coal-fired generating fleet.Commercial ApplicationsGreenidge Unit No. 4 is representative of 492 coal-firedelectricity generating units in the United States with capacities of 50–300 MWe. These smaller units, almost one- quarter of the U.S. coal-fired generating capacity, are increasingly vulnerable to fuel switching or retirement as a result of more stringent state and federal environmental regulations. The proposed project will demonstrate the commercial readiness of an emissions control system that is particularly suited, because of its low capital and main- tenance costs, to meet the requirements of this large group of smaller existing electricity generating units.

Project selected 9/26/01

Cooperative agreementawarded 4/02*

4/02

Project complete/final report issued 9/06*

9/06
6-14 Program Update 2001 Po

Power Plant Improvement InitiativeDemonstration of a Full-ScaleRetrofit of the AdvancedHybrid Particulate CollectorTechnologyParticipantOtter Tail Power CompanyAdditional Team MembersMontana-Dakota Utilities—co-hostNorthWestern Public Service—co-hostW.L. Gore & Associates, Inc.—licensee and filter bag

provider

Energy and Environmental Research Center (University

of North Dakota)—concept developer

LocationBig Stone City, Grant County, SD (Montana-Dakota Utilities and NorthWestern Public Service’s Big Stone PowerPlant)TechnologyAdvanced Hybrid Particulate CollectorPlant Capacity/Production450 MWCoalLow-sulfur coalProject FundingTotal Project Cost $13,397,445DOE 6,491,000Participant 6,906,445Project ObjectiveTo demonstrate, in a full-scale application, a hybrid technology that raises the particulate matter capture of coalplants up to 99.99% by integrating fabric filtration andelectrostatic precipitation (ESP) in a single unit. The Advanced Hybrid Particulate Collector (AHPC) overcomes the problem of excessive fine particle emissions that es- cape collection in ESPs and the reentrainment of dust in baghouses. The overall goal of the project is to demon- strate the AHPC concept in a full-scale application. Spe- cific objectives are to demonstrate ultra-low fine particu- late emissions, low pressure drop, overall reliability of the technology and, eventually, long-term bag life. Technology/Project Description The AHPC combines the best features of ESPs and bag- houses in an entirely novel manner. The AHPC concept combines fabric filtration and electrostatic precipitation in the same housing, providing major synergism between the two methods, both in the particulate collection step and in transfer of dust to the hopper. The AHPC provides ultra- high collection efficiency, overcoming the problem of excessive fine-particle em

and solves the problem of of dust in conventional ba
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Calendar Year

Power Plant Improvement Initiative 

2001 2002 2005 2003 2004 2006 2007 2008 2009 

Project Status/AccomplishmentsThe project was selected for award on September 26,2001. Contract negotiations are under way as of the endof fiscal year 2001.A slipstream AHPC (9,000 scfm) has been operating atthe Big Stone Power Plant for the past one and one-halfyears. The AHPC demonstrated ultra-high particulatecollection efficiency for submicron particles and totalparticulate mass. Collection efficiency was proven toexceed 99.99% by one to two orders of magnitude overthe entire range of particles from 0.01 to 50 μm. The fluegas exiting the AHPC was as clean as pristine ambient airwith a fine particulate matter level of 5 μg/m3. This level

of control would be well below any current particulateemission standards. These results were achieved whileoperating at significantly higher air-to-cloth ratios(12 ft/min compared to 4 ft/min) than what is used forstandard pulse-jet baghouses. In fact, preliminary economic analysis of the AHPC compared with conventionalESPs and baghouses indicates that the AHPC is economically competitive with either of these technologies formeeting current standards. For meeting a possible stricter

fine-particle standard or 99.99% control of total particulates, the AHPC is the economic choice over either ESPsor baghouses by a wide margin.Commercial ApplicationsWith new requirements to control respirable particulatematter (less than 2.5 microns in diameter; PM2.5), the

AHPC is a superior technology not only for new installations but as a retrofit technology as well. The AHPC combines a high particulate collection efficiency, with a smallfootprint and potential economic advantages. Given theage and performance level of many existing ESPs, there isa great and immediate need for this type of retrofit technology. This technology has potential application to all ofthe more than 1,000 coal-fired units. However, space andother site-specific constraints come in to play to preclude100% applicability.

Project selected 9/26/01

Project complete/final report issued 3/05*

Cooperative agreementawarded 3/02*

3/02 3/05
6-16 Program Update 2001 Po

Power Plant Improvement InitiativeAchieving New SourcePerformance StandardsEmission Standards ThroughIntegration of Low-NOxBurners with an OptimizationPlan for Boiler CombustionParticipantSunflower Electric Power Corp.Additional Team MembersElectric Power Research Institute—cofunderFoster Wheeler Energy Corporation—technology supplierLocationGarden City, Finney County, KSTechnologyUltra-low NO

x burners with other combustion-stage

controlsPlant Capacity/Production360 MWCoalSubbituminous coalsProject FundingTotal Project Cost $5,831,100DOE 2,786,900Participant 3,044,200Project ObjectiveTo demonstrate ultra-low-NO

x

 burners with other combustion-stage controls with the goal to reduce NOx emissions to 0.13-0.14 lb/106 Btu, demonstrating a concept

that has never been illustrated in plants using subbituminous coals, including those from the Powder River Basin.Expected to help define the extent to which combustionmodifications can reduce NO

x from pulverized coal boilers, the project will be tried out on a 360-MW wall-fired unit. Technology/Project Description Low-NOx Burners (LNB) have been in development since the late 1970s and are in general use on many steam-electric generating units. Increasing demands for overall reductions in NOx emissions have continued to put pressure on manufacturers to improve burner design. Recent developments have introduced what are generally referenced as ultra-LNB. When used with separated over- fire air (SOFA) they have been found capable of reducing emission rates to very near the current New Source Performance Standards (NSPS) level of about 0.16 lb/106 Btu. To further reduce NOx emissions, the participant will employ five elements: (1) ultra-low NOx burners, (2) separated over-fire air

transducers, (4) air balanccontrols.
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Calendar Year

Power Plant Improvement Initiative 

2001 2002 2005 2003 2004 2006 2007 2008 2009 

Project Status/AccomplishmentsThe project was selected for award on September 26,2001. Contract negotiations are under way as of the endof fiscal year 2001.Naturally, vendors are reluctant to guarantee emissions ator below the NSPS level. A practical demonstration of thebest designed and controlled equipment will reduce theuncertainties and thus assure the availability of technology that has much lower installed cost than the SelectiveCatalytic Reduction (SCR) units that are now in favor. Aportion of the technology proposed has been installed onone 600-MW wall-fired unit and it has achieved theNSPS level of NO

x emissions, at least on a short-term

basis.The full application of the five elements proposed hereinhave never been demonstrated in plants firing subbituminous coals, especially those from Wyomingís PowderRiver Basin (PRB). Likewise, there are no other wallfired units on which owners have sought to fully explorethe technology proposed to its fullest potential. Theinclusion of the very latest in distributed control systems,

proposed for this unit in 2003, make this location idealfor integration with the proposed elements. The unit onwhich this technology will be applied has among the verybest availabilities and performance histories for boilers ofits type. It was placed in commercial operation in 1983and is equipped with the latest SO2 scrubber and fabric

filter for particulate matter. When completed, this will beamong the cleanest non-SCR-equipped coal-fired units inthe United States.Commercial ApplicationsThere are as many as 30 units for which this technologycan be deployed that will be able to meet the currentNSPS level, if long-term practical demonstration can bemade. A further 60 units will be able to establish significant reductions, to levels of about 0.22 lbs/106 Btu. This

choice of equipment, if enabled in a timely fashion, willallow a reduction in the number of SCRs being installed,thereby reducing the overall consumer cost; will reducethe outage duration necessary for completion, therebyimproving the electric system reliability; and will conserve the critical pool of skilled labor needed to accomplish this work.

Project selected 9/26/01

Cooperative agreement awarded 4/02* Project complete/final report issued 9/05*

4/02 9/05
6-18 Program Update 2001 Po

Power Plant Improvement InitiativePolk Power Station PlantImprovement ProjectProject WithdrawnParticipantTampa Electric CompanyAdditional Team MembersProcess Matrix, LLC—technology supplierAlbany Research Center—cofunderLocationMulberry, Polk County, FL (Tampa Electric’s Polk PowerStation)TechnologyRefractory lining wear monitorPlant Capacity/Production250 MW (net)CoalUnknownProject FundingTotal Project Cost $1,676,410DOE 637,036Participant 1,039,374Project ObjectiveTo reduce costs and uncertainty related to refractory wearand replacement for Integrated Gasification CombinedCycles (IGCCs), which are highly efficient, clean, coalbased, power-generation systems.Technology/Project DescriptionTampa Electric Company will demonstrate a monitor thatmeasures the wear pattern of refractory liners at hightemperatures, thereby increasing unit reliability and availability.
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Calendar Year

Power Plant Improvement Initiative 

2001 2002 2005 2003 2004 2006 2007 2008 2009 

Project Status/AccomplishmentsThe project was selected for award on September 26,2001. Contract negotiations are under way as of the endof fiscal year 2001. The Energy Department has selectedthis project for a partial award. Just prior to publicationof this report, the project was withdrawn by the participant because of recent fuel changes.Phase I would have included the complete process designand preliminary engineering. Phase II would have consisted of the detailed engineering and long lead-timeequipment. Phase III would have covered construction,start-up, operation/demonstration and reporting of theresults and conclusions.The demonstrations proposed herein for the Polk PowerStation would have provided significant improvementsto overall plant performance, plant reliability and plantoperating costs thereby assuring the gasification technologies remain competitive for future power generationapplications.

Project selected 9/26/01

Commercial ApplicationsCoal is our nation’s most abundant fuel resource. It isused primarily in power plants. However, coal contains upto 60% more carbon per unit of useful energy than liquidfuels or natural gas, so coal-fired power plants are normally large sources for CO2 generation and by-products.

A new type of coal-fired power plant called IntegratedGasification Combined-Cycle (IGCC) has been developed, demonstrated, and commercialized in the UnitedStates and abroad. In IGCC plants, the coal is firstconverted into a high-pressure gas before combustion.Conventional pollutants and their precursors such as sulfur, nitrogen compounds and particulates are much easierto remove from this high-pressure, low-volume gasstream in IGCC plants than from the low-pressure, highvolume combustion products in power plant stacks.The IGCC demonstration plants funded in part by theUnited States Department of Energy under the Clean CoalTechnology Program have already shown their environmental superiority in this regard. At this time, Polk PowerStation is generating 250 MW (net) of power, is operating

at over 80% availability Company’s premier basof IGCC plants, a high-pwhich contains most of best chance to minimize 

capture and recovery. Thoffers an opportunity to all coal streams from thgasification process, the pattern of the brick liner increase unit reliability tended life.This technology will be gasifiers. There may be technologies that use ref

Project withdrawn
6-20 Program Update 2001 Po

Power Plant Improvement InitiativeBig Bend Power StationNeural Network-SootblowerOptimizationParticipantTampa Electric CompanyAdditional Team MembersPegasus Technology, Inc.—technology supplierLocationApollo Beach, Hillsborough County, FL (TampaElectric’s Big Bend Power Station)TechnologyNeural-network soot-blowing system in conjunction withadvanced controls and instrumentsPlant Capacity/Production445 MWCoalUnknownProject FundingTotal Project Cost $2,381,614DOE 905,013Participant 1,476,601Project ObjectiveTo control boiler fouling on a 445-MWe unit by using aneural-network soot-blowing system in conjunction withadvanced controls and instruments. Ash and slag deposition compromise plant efficiency by impeding the transferof heat to the working fluid. This leads to higher fuelconsumption and higher air emissions, especially NOx.

This project is expected to reduce NOx by 30%, improve

heat rate by 2% and reduce particulate matter emissionsby 5%.

Technology/Project DescriptionThe intent of this project is to apply a neural networkintelligent sootblowing system in conjunction withstate-of-the-art controls and instruments to optimize theoperation of a utility boiler and systematically controlboiler fouling. This optimization process is targeted toreduce total NO

x generation by 30% or more, improve

heat rate by 2%, and reduce PM emissions by 5%. Ascompared to competing technologies, this could be anextremely cost-effective technology, which has the abilityto be readily and easily adapted to virtually any pulverized coal boiler.
 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 

Calendar Year

Power Plant Improvement Initiative 

2001 2002 2005 2003 2004 2006 2007 2008 2009 

Project Status/AccomplishmentsThe project was selected for award on September 26,2001. Contract negotiations are under way as of the endof fiscal year 2001. The schedule will be finalized whencontract negotiations are complete.Commercial ApplicationsOne problem that exists with the combustion of coal, isthe formation and deposition of ash and slag within theboilers which adversely affects the rate at which heat istransferred to the working fluid, which in the case ofelectric generators is water/steam. The fouling of theboiler leads to poor efficiencies due to the fact that heatwhich could normally be transferred to the working fluidremains in the flue gas stream and exits to the environment without beneficial use. This loss in efficiency translates to higher consumption of fuel for equivalent levelsof electric generation, hence more gaseous emissions arealso produced. Another less obvious problem exists withfouling of various sections of the boiler relating to theintensity of peak temperatures within and around thecombustion zone. Total NO

x generation is primarily a

function of both fuel- and thermal-NO

x production. FuelNOx, which generally comprises 20–40% of the total NOx generated, is predominately influenced by the levels of oxygen present, while thermal-NOx, which comprises the balance, is a function of temperature. As the fouling of the boiler increases and the rate of heat transfer de- creases, peak temperatures increase as does the thermal NOx production. Due to the composition of coal, particulate matter is also a by-product of coal combustion. Modern day utility boil- ers are usually fitted with electrostatic precipitators to aid in the collection of particulate matter (PM). Although extremely efficient, these devices are sensitive to rapid changes in inlet mass concentration as well as total mass loading. Traditionally, utility boilers are equipped with devices known as sootblowers, that use, steam, water, or air to dislodge particulates and clean the surfaces within the boiler and are operated based upon established rules or the operators judgment. Without extreme care and due diligence, excessive soot can overload an ESP resulting in high levels of PM being released. This technology has potential application to all of the more than 1,000 coal- fired units.

Project selected 9/26/01

Cooperative agreement awarded 4/02*

Project complete/final report issued 2/04*

4/02 2/04
6-22 Program Update 2001 Po

Power Plant Improvement InitiativeCommercial Demonstration ofthe Manufactured AggregateProcessing TechnologyUtilizing Spray Dryer AshParticipantUniversal Aggregates, LLC (a joint venture betweenCONSOL Energy, Inc. and SynAggs, Inc.)Additional Team MembersCONSOL Energy, Inc.—development and engineeringP.J. Dick, Inc.—project management and constructionSynAggs, LLC—marketing and utilizationLocationKing George County, VA (Birchwood Power Facility)TechnologyAggregate manufacturing plant using by-products fromspray dryer fluegas desulfurization (FGD) scrubbersPlant Capacity/Production150,000 tons/year of lightweight aggregateCoalBituminous, 0.9% sulfurProject FundingTotal Project Cost $17,060,900DOE 7,224,000Participant 9,836,900Project ObjectiveUniversal Aggregates LLC will design, build, andoperate an aggregate manufacturing plant that converts115,000 tons/year of spray dryer by-products into150,000 tons/year of lightweight masonry blocks orlightweight concrete.

Technology/Project DescriptionUniversal Aggregates, LLC will design, construct, andoperate a lightweight aggregate manufacturing plant atthe Birchwood Power Facility.Flue gas desulfurization systems, used to lower sulfuremissions from coal plants, often produce a type ofsludge that is landfilled; only 18% of FGD residue isrecycled. Much of that 18% pertains to recycling byproducts from wet FGD systems or scrubbers. UniversalAggregates’ process can be used to recycle the by-products from wet or dry scrubbers. This would reduce plantdisposal costs while reducing the environmental drawbacks of landfilling.The Birchwood facility will transform 115,000 tons/yearof spray dryer by-products that are currently being disposed of in an off-site landfill into 150,000 tons/year of a

useful product, lightweighmanufacture lightweight mconcrete.
 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 

Calendar Year

Power Plant Improvement Initiative 

2001 2002 2005 2003 2004 2006 2007 2008 2009 

Project selected 9/26/01

Project Status/AccomplishmentsThe project was selected for award on September 26,2001. The Department of Energy is scheduled to beginformal discussions with Universal Aggregates on December 10, 2001.Commercial ApplicationsThere are currently twenty-one spray dryer facilities operating in the United States that produce an adequate amountof spray dryer by-product to economically justify the installation of a lightweight aggregate manufacturing facility.Industry sources believe that as additional scrubbing isrequired, dry FGD technologies will be the technology ofchoice. Letters from potential lightweight aggregate customers indicate that there is a market for the product oncethe commercialization barriers are eliminated by this demonstration project.

Cooperative agreement awarded/start design and construction period 3/02*

Project complete/final report issued 9/04*

Start contractnegotiations 12/01*

3/02 9/04

NEPA complete (EA) 9/02*

Begin aggregate production 9/03*
6-24 Program Update 2001 Po
Appendix A. Historical Perspective andLegislative HistoryCCT Historical PerspectiveThere were a number of key events that prompted creation of the CCT Program and impacted its focus overthe course of the five solicitations. The roots of theCCT Program can be traced to the acid rain debates ofthe early 1980s, culminating in U.S. and Canadianenvoys recommending a five-year, $5 billion U.S. effortto curb precursors to acid rain formation—SO2 andNOx. This recommendation was adopted and became apresidential initiative in March 1987.As a part of the response to the recommendations ofthe Special Envoys on Acid Rain in April 1987, thePresident directed the Secretary of Energy to establisha panel to advise the President on innovative clean coaltechnology activities. This panel was the InnovativeControl Technology Advisory Panel. As a part of thepanel’s activities, the state and federal incentive subcommittee prepared a report, Report to the Secretary ofEnergy Concerning Commercialization Incentives, that

addressed actions that states could take to provide incentives for demonstrating and deploying clean coaltechnologies. The panel determined that demonstrationand deployment should be managed through both stateand federal initiatives.In the same time frame, the Vice President’s TaskForce on Regulatory Relief (later referred to as thePresidential Task Force on Regulatory Relief) wasestablished. Among other things, the task force wasasked to examine incentives and disincentives to the

commercial realization of new clean coal technologies.The task force also examined cost-effective emissionsreduction measures that might be inhibited by variousfederal, state, and local regulations. The task forcerecommended that preference be given to projects located in states that offer certain regulatory incentives toencourage such technologies. This recommendationwas accepted and became part of the project selectionconsiderations beginning with CCT-II.Initial CCT Program emphasis was on controlling SO2

and NOx emissions from existing coal-based powergenerators. Approaches demonstrated through the program were coal processing to produce clean fuels,combustion modification to control emissions,postcombustion cleanup of flue gas, and repoweringwith advanced power generation systems. These earlyefforts (projects resulting from the first three solicitations) produced a suite of cost-effective complianceoptions available today to address acid rain concerns.As the CCT Program evolved, work began on draftingwhat was to become the Clean Air Act Amendments of1990. Through a dialog with EPA and Congress, theprogram was able to remain responsive to shifts inenvironmental emphasis. Also, projects in place enabled CAAA architects to have access to real-time dataon emission control capabilities while structuring proposed acid rain regulations under Title IV of theCAAA.Aside from acid rain, there was an emerging issue inthe area of hazardous air pollutants (HAPs), also referred to as air toxics. Title III of the CAAA listed 189

airborne compounds suelements and volatile aassess the impacts on cCCT Program projects through an integrated eand the Utility Air Regeffort, concerns about power generation have enabling focus on but a because NOx is a precupresence of NOx in ozolow levels, became an the CCT Program to indeep NOx reduction in sought.In the course of the last Program, a number of esiderations combined tseeking high-efficiencyeration technology. EnUnited States showed ton coal-based power gegrowth required into th

ever, capped SO2 emis

NOx continued to recei

ozone nonattainment. Fsions were coming undcorrelations with lung toxic compounds to adto these concerns was twarming, and more spe

from burning fossil fue
A-2 Program Update 2001

because of the high carbon-to-hydrogen ratio relative tonatural gas, resulting in somewhat higher CO2 emissions per unit of energy produced. However, coal is thefuel of choice (if not necessity) for many developingcountries where projected growth in electric powergeneration is the greatest. The path chosen to respondto these considerations was to pursue advanced powergeneration systems that could provide major enhancements in efficiency and control SO2, NOx, and particulates without introducing external parasitic control

devices. (Increased efficiency translates to less coalconsumption per unit of energy produced.) As a result,a number of advanced power generation projects wereundertaken, representing pioneer efforts recognizedthroughout the world.

CCT Legislative HistoryThe legislation authorizing the CCT Program is foundin Public Law 98-473, Joint Resolution Making Continuing Appropriations for Fiscal Year 1985 and forOther Purposes. Title I set aside $750 million of thecongressionally rescinded $5.375 billion of the Synthetic Fuels Corporation into a special U.S. Treasuryaccount entitled the “Clean Coal Technology Reserve.”This account was dedicated to “conducting cost-sharedclean coal technology projects for the construction andoperation of facilities to demonstrate the feasibility offuture commercial applications of such technology.”Title III of this act directed the Secretary of Energy tosolicit statements of interest in and proposals for cleancoal projects. In keeping with this mandate, DOE issued a program announcement, which resulted in thereceipt of 176 proposals representing both domesticand international projects with a total estimated cost inexcess of $8 billion.

After this significant initial expression of interest inclean coal demonstration projects, Public Law 99-190,enacted December 1985, appropriated $400 million toconduct cost-shared demonstration projects. Of thetotal appropriated funds, approximately $387 millionwas made available for cost-shared projects to be selected through a competitive solicitation, or ProgramOpportunity Notice (PON), referred to as CCT-I. (Theremaining funds were required for program directionand the legislatively mandated Small Business Innovation Research Program [SBIR] and Small BusinessTechnology Transfer Program [STTR].)In a manner similar to the initiation of CCT-I, Congress again directed DOE to solicit information fromthe private sector in the Department of the Interior andRelated Agencies Appropriations Act for FY1987(Public Law 99-591, enacted October 30, 1986). Theinformation received was to be used to establish thelevel of potential industrial interest in another solicitation, this time involving clean coal technologiescapable of retrofitting, repowering, or modernizingexisting facilities. Projects were to be cost-shared, withindustry sharing at least 50 percent of the cost. As aresult of the solicitation, a total of 39 expressions ofinterest were received by DOE in January 1987.On March 18, 1987, the President announced the endorsement of the recommendations of the SpecialEnvoys on Acid Rain, including a $2.5 billion government share of funding for industry/government demonstrations of innovative control technology over a fiveyear period. The Secretary of Energy stated that thedepartment would ask Congress for an additional $350million in FY1988 and an advanced appropriation of$500 million in FY1989. 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, enamended by Public Law of $575 million to condulion was for projects, widirection and the SBIR aThe Department of the IAppropriations Act for Fenacted September 27, 1for necessary expenses anology demonstrations ithe total funding, about $able for cost-sharing proprogram direction and thThe act continued the redemonstrate technologierepowering existing facirized the use of Tennesseprogram funds as a sourexcept if provided by anaddition, funds borroweAdministration now Rurcooperatives from the Feeligible as cost-sharing iexcept if provided by anIn the Department of the Appropriations Act of 1enacted October 23, 198million for the CCT-IV to the act, “shall demonsreplacing, retrofitting, or and shall be subject to alhead in Public Laws 99-amended by this Act.” Aavailable for federal cofCCT-IV, with the remainthe SBIR and STTR Pro
In Public Law 101-121, enacted October 23, 1989,Congress also provided $600 million for the CCT-Vsolicitation. CCT-V, according to the act, “shall besubject to all provisos contained under this head inPublic Laws 99-190, 100-202 and 100-446 as amendedby this Act.” Approximately $568 million was madeavailable for federal cofunding of projects to be selected in this solicitation, with the remainder again forprogram 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 selectingprojects. In Public Law 101-512, Congress directedDOE to issue the PON for CCT-IV not later than February 1, 1991, with selections to be made within 8months. In Public Law 102-154, Congress directedDOE to issue CCT-V PON not later than July 6, 1992,with selections to be made within 10 months. This lateract also directed that CCT-V proposals should advancesignificantly the efficiency and environmental performance of coal-using technologies and be applicable toeither new or existing facilities.Public Laws 101-164, 101-302, 101-512, 103-138, and103-332 adjusted the rate at which funds were to bemade available to the program.CCT Program funds have been further adjustedthrough sequestering requirements of the GrammRudman-Hollings Deficit Reduction Act as well asrescissions. 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 appropriationsas 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 weredeferred by Public Law 105-277. Funds will be restored over a three year period beginning October 1,1999. Again in 1999, Congress deferred programfunds. In Public Law 106-113, Congress deferred$156,000,000 until October 1, 2000. And in PublicLaw 107-63, Congress deferred $40,000,000 until October 1, 2002.Exhibit A-1 lists all the key legislation relating to theCCT Program and provides a summary of provisionsrelating to program funding as well as program implementation. At the end of this appendix are fundingprovisions excerpted from appropriations and otherrelevant funding-related acts.

PPII HistorThe roots of this progrbrownouts of 1999 and provement Initiative is direction provided in thtions to DOE’s fossil eing was added for the pconcerns over the adeqplies. Several parts of tWest Coast and parts orolling blackouts and byears caused in large pelectricity and lagging plants.Eligible projects includefficiencies of currentlerating more megawattfuel—or that lower emin operation in compliadards. The program waimprove the economics coal-fired power plantsPrivate sector proposerernment funding. Propture enough to be commyears, and the cost-shalarge enough to show tcommercial use.
A-4 Program Update 2001

Exhibit A-1

CCT Program Legislative History

Public DateLaw Enacted CCT Round Program Funding Implementation Provisio98-473 10/12/84 Initiation of CCT Rescinded $750 million of $5.375 billion from the Energy Title III required publication 

Program; informational Security Reserve (Synthetic Fuels Corporation) to be of interest in and proposals fsolicitation deposited in a U.S. Treasury Department account entitled emerging CCTs. A report to 

“Clean Coal Technology Reserve” for conducting cost-shared later than 4/15/85.CCT projects for the construction and operation of facilitiesto demonstrate the feasibility for future commercial applicationof such technology, without fiscal year limitation, subject tosubsequent annual appropriation.

99-88 8/15/85 CCT-I Deferred $1.6 million for obligation until 10/1/85. Conference Report (H. Rep. 

project guidelines contained certain modifications.

99-190 12/19/85 CCT-I Conference Report (H. Rep. 99-450) agreed to a $400-million Required a PON (CCT-I) to 

CCT Program as described under the U.S. Treasury Department selected no later than 8/1/86. Energy Security Reserve, with the request for proposals to be provisions were detailed.for the full $400 million.

99-591 10/30/86 Second informational (Contained no funding provisions for CCT Program.) Title II required publication o

solicitation of interest in, and informatio

employing emerging CCTs crepowering, or modernizing Congress was required no lat

100-202 12/22/87 CCT-II Appropriated $50 million for FY beginning 10/1/87 until Required a request for propo

expended and $525 million for FY beginning 10/1/88 until no later than 60 days followiexpended. CCTs capable of retrofitting 

facilities. Extended project sdays after receipt of proposapreaward costs for preparatiomental data upon signing of Conference Report (H. Rep. cost-sharing funds be made aas utility applications. No funnew, stand-alone applicationSenate Report 100-165 outlinrepay government contributi
Exhibit A-1 (continued)

CCT Program Legislative History

Public DateLaw Enacted CCT Round Program Funding Implementation Provisio

100-446 9/27/88 CCT-III Made available $575 million on 10/1/89 until expended. Request for proposals (CCT-

Pub. L. 100-202 was amended by striking $525 million and for emerging CCTs capable oinserting $190 million for FY beginning 10/1/88 until expended, ing facilities. Proposals were $135 million for fiscal year beginning 10/1/89 until expended, of the PON; projects were to and $200 million for FY beginning 10/1/90 until expended, days after receipt of proposalprovided that outlays for FY89 resulting from use of fundsappropriated under Pub. L. 100-202, as amended, did not Funds borrowed by REA eleexceed $15.5 million. Federal Financing Bank were 

Funds derived by the Tennespower program were deemed if provided by annual approp

101-45 6/30/89 CCT-III Funds appropriated for FY1989 were made available for a Project selections for the thir

third solicitation. later than 1/1/90.

101-121 10/23/89 CCT-IV and CCT-V Made available $600 million on 10/1/90 until expended and Two solicitations (CCT-IV a

for $600 million on 10/1/91 until expended. Pub. L. 100-446 each appropriation, to demonwas amended by striking $575 million and inserting $450 million replacing, retrofitting, or rep

to be made available on 10/1/89 until expended and $125 million to all provisos contained in Pto be made available on 10/1/90. Unobligated balances excess to 100-446 as amended. The POthe needs of the procurement for which they originally were ing available on 10/1/90 was made available may be applied to other procurements for which selections made by 2/1/91. Trequests for proposals had not yet been issued, except that no becoming available on 10/1/9supplemental, backup, or contingent selection of projects could 9/1/91, with selections made be made over and above the projects originally selected.

101-164 11/21/89 CCT-IV and CCT-V Appropriation for FY1990 was amended by striking $450 million Solicitations could not be co

and inserting $419 million and by striking $125 million and funds. Repayment provisions inserting $156 million. be the same as for CCT-III.

101-302 5/25/90 CCT-IV and CCT-V Obligation of funds previously appropriated for CCT-IV and

CCT-V was deferred until 9/1/91.
A-6 Program Update 2001

Exhibit A-1 (continued)

CCT Program Legislative History

Public DateLaw Enacted CCT Round Program Funding Implementation Provision101-512 11/5/90 CCT-IV and CCT-V Pub. L. 101-121 was amended by striking $600 million made The CCT-IV solicitation was 

available on 10/1/90 until expended and $600 million made 2/1/91. The CCT-V PON was available on 10/1/91 until expended and inserting $600 million 3/1/92. Project selections wermade available as follows: $35 million on 9/1/91, $315 million months of PON’s issuance. Reon 10/1/91, and $250 million on 10/1/92, all sums remaining the same as for CCT-III. Provuntil expended, for use in conjunction with a separate general protections for trade secrets anrequest for proposals, and $600 million made available as Conference Report (H. Rep. 1follows: $150 million on 10/1/91, $225 million on 10/1/92, and to program policy factors.$225 million on 10/1/93, all sums remaining until expended, foruse 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 

10/1/91 and $225 million on 10/1/92 and inserting $100 million selection to be made within 10 on 10/1/91 and $275 million on 10/1/92. months). The PON was to be 

nificantly the efficiency and ecoal-using technologies and bexisting facilities. Conference stated expectations that the CCconducted under the same genprincipally modified only to (eligible technologies or appliccriteria to consider allowable strengthen criteria for nonutilicommercial performance critetechnologies with regard to asciency and environmental perfstrengthen cost and finance crdevelopment activities.Funding was allowed for projeties for process performance dverification, materials selectiodesigns on a cost-shared basis the government share of proje
Exhibit A-1 (continued)

CCT Program Legislative History

Public DateLaw Enacted CCT Round Program Funding Implementation Provis102-154 Development activities elig(continued) limited modifications to ex

testing but not construction 

102-381 10/5/92 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 10/1/93and inserting $250 million on 10/1/93 and $250 million on 10/1/94.

102-486 10/24/92 (Contained no funding provisions for CCT Program.) Section 1301—Coal RD&D 

Programs (Title XIII; Subtiprograms for RD&D and cbased technologies. Secretasubmit to Congress (1) a rethings, recommendations recost-sharing demonstrationCoal Program (Pub. L. 98-ded in order to ensure the tcoal-based technologies andevelopment of advanced cRD&D and commercial ap

103-138 11/11/93 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 millionon 10/1/95.

103-332 9/30/94 Pub. L. 101-512 was amended by striking $100 million on 10/1/94 An amount not to exceed $

and $50 million on 10/1/95 and inserting $18 million on 10/1/94, may be used for administra$100 million on 10/1/95, and $32 million on 10/1/96; and by striking Program.$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 $255.879million on 10/1/96.
A-8 Program Update 2001

Exhibit A-1 (continued)

CCT Program Legislative History

Public DateLaw Enacted CCT Round Program Funding Implementation Provision104-6 4/10/95 Of funds available for obligation in FY1996, $50 million was rescinded. Of the funds to be made available for obligation in FY1997,

$150 million was rescinded.

104-134a 4/26/96 Conference Report (H. Rep. 10

1977) allowed for the use of up Program funds for program ad

104-208b 9/30/96 Conference Report (H. Rep. 104-863 to accompany H.R. 3610) House and Senate committees 

noted rescission of $123 million for FY1997 or prior years. $16 million in available funds 

Program in FY1997 (H. Rep. 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 FY1997 or priors, $101

million was rescinded.

105-277 10/21/98 Of funds made available for obligation in prior years, $40 million Conference Report allowed $1

was deferred. funds for program administrati

106-113 11/29/99 Of funds made available for obligation in prior years, $156 million Conference Report did not obj

was deferred. $38,000 was rescinded as a result of the general million in CCT Program funds reduction.

106-291 10/11/00 Of funds made available for obligation in prior years, $67 million Conference Report (H. Rep. 10

was deferred. Another $95 million was transferred to the Power use of up to $14.4 million in CPlant Improvement Initiative. administration.

107-63 11/5/01 Of the funds made available for obligation in prior years,

$40,000,000 was deferred.

a H.R. 3019, which became Pub. L. 104-134, replaced H.R. 1977.b H.R. 3610, which became Pub. L. 104-208, replaced H.R. 3662.
Public Law 99-190Public 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, pursuantto the Federal Nonnuclear Energy Research and Development Act of 1974 (42 U.S.C. 5901, et seq.), issue a

general request for proposals for clean coal technologyprojects for which the Secretary of Energy upon reviewmay provide financial assistance awards. Proposals forclean coal technology projects under this section shallbe submitted to the Department of Energy within 60days 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 theSecretary may vest fee title or other property interestsacquired under cost-shared clean coal technologyagreements in any entity, including the United States:Provided further, That the Secretary shall not financemore than 50 per centum of the total costs of a projectas estimated by the Secretary as of the date of award offinancial assistance: Provided further, That cost-sharing by project sponsors is required in each of the design, construction, and operating phases proposed to beincluded in a project: Provided further, That financialassistance for costs in excess of those estimated as ofthe date of award of original financial assistance maynot be provided in excess of the proportion of costsborne by the Government in the original agreement andonly up to 25 per centum of the original financial assistance: Provided further, That revenues or royaltiesfrom prospective operation of projects beyond the timeconsidered in the award of financial assistance, or proceeds from prospective 

or revenues or royaltiein future projects or plapurposes of this appropother appropriated Fedfor the purposes of this That existing facilitiespreviously expended reare not cost-sharing for tion, except as amortiznormal business practiConference Repor450, 99th Cong., 1

CLEAN C

The managers have agCoal Technology progrpartment of the Treasulanguage is included wof projects no later thaperiod, a general requewithin 60 days and proDepartment within 60 request for proposals. Ling the Secretary of Enacquired under agreemUnited States, and deliments. Funds for these available to the Clean CEnergy Security prograIt is the intent of the mform of facilities and ethe extent that they woexpensed in normal bupractice shall be determnecessarily the practice 

PPII Legislative History The legislation authorizing the Power Plant Improve- ment Program (PPII) is found in Public Law 106-291, Department of the Interior and Related Agencies Ap- propriations Act, 2001. Under the act, $95,000,000 was transfered from funds appropriated in prior years under the CCT Program and made available for a gen- eral request for proposals for the commercial scale demonstration of technologies to assure the reliability of the Nation’s energy supply from existing and new electric generating facilities. The funds provided were to be spent only in accordance with the provisions gov- erning the use of funds contained under the CCT Pro- gram under which they were originally appropriated. Provisions for recoupment are identical to Round III of the CCT Program except that repayments from sale or licensing of technologies shall be from both domestic and foreign transactions and the repayments are re- tained for future projects. Congress provided that any project approved under PPII shall be considered a Clean Coal Technology Demonstration Project, for the purposes of Chapters 51, 52, and 60 of title 40 of the Code of Federal Regulations. In Public Law 107-63, Congress provided for funds excess to the needs of the PPII procurement shall be made available for the Clean Coal Power Initiative. Exhibit A-2 lists all the key legislation relating to PPII and provides a summary of provisions relating to pro- gram funding as well as program implementation. Fol- lowing this section are funding provisions excerpted from appropriations and other relevant funding-related acts.
A-10 Program Update 2001

Exhibit A-2

PPII Legislative History

Public DateLaw Enacted Program Funding Implementation Provision106-291 10/11/00 Made available $95,000,000 derived by transfer from funds

appropriated in prior years From the CCT Program for ageneral request for proposals for the commercial scaledemonstration of technologies to assure the reliability of theNation’s energy supply from existing and new electricgenerating facilities for which the Department of Energy uponreview may provide financial assistance awards.

107-63 11/5/01 Provided that funds excess to the needs of the Power Plant

Improvement Initiative procurement provided for in PublicLaw 106-291 shall be made available for the Clean Coal PowerInitiative provided for in Public Law 107-63.
erty which has been fully depreciated would not receive any cost-sharing value except to the extent that ithas been in continuous use by the proposer during thecalendar year immediately preceding the enactment ofthis Act. For this property, a fair use value for the lifeof the project may be assigned. Property offered as acost-share by the proposer that is currently being depreciated would be limited in its cost-share value tothe depreciation claimed during the life of the demonstration project. Furthermore, in determining normalbusiness practice, the Secretary should not acceptvaluation for property sold, transferred, exchanged, orotherwise manipulated to acquire a new basis for depreciation purposes or to establish a rental value incircumstances which would amount to a transaction forthe 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 consideredin determining the percentage of Federal cost-sharing.This is consistent with current and historical practicesin Department of Energy procurements.It is the intent of the managers that there be full andopen competition and that the solicitation be open toall markets utilizing the entire coal resource base.However, projects should be limited to the use ofUnited States mined coal as the feedstock and demonstration sites should be located within the UnitedStates.The managers agree that no more than $1,500,000 shallbe available in FY1986 and $2,000,000 each yearthereafter for contracting, travel and ancillary costs ofthe program, and that manpower costs are to be fundedunder the fossil energy research and developmentprogram.The managers direct the Department, after projects areselected, to provide a comprehensive report to the Congress on proposals received.

The managers also expect the request for proposals tobe or the full $400,000,000 program, and not only forthe first $100,000,000 available in fiscal year 1986.

Public Law 100-202Public Law 100-202, 101 Stat. 1329-1 (1987)

CLEAN COAL TECHNOLOGY

For necessary expenses of, and associated with, CleanCoal Technology demonstrations pursuant to 42 U.S.C.5901 et seq., $50,000,000 are appropriated for thefiscal year beginning October 1, 1987, and shall remainavailable 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 thisAct, the Secretary of Energy shall, pursuant to the Federal Nonnuclear Energy Research and DevelopmentAct of 1974 (42 U.S.C. 5901 et seq.), issue a generalrequest for proposals for emerging clean coal technologies which are capable of retrofitting or repoweringexisting facilities, for which the Secretary of Energyupon review may provide financial assistance awards.Proposals under this section shall be submitted to theDepartment of Energy no later than ninety days afterissuance of the general request for proposals requiredherein, and the Secretary of Energy shall make anyproject selections no later than one hundred and sixtydays after receipt of proposal: Provided, That projectsselected are subject to all provisos contained under thishead in Public Law 99-190: Provided further, That preaward costs incurred by project sponsors after selection

House 

Fiscal year:1988 $50,000,001989 200,000,001990 100,000,00Total 350,000,00

and before signing an aextent that they are relamaterial requested by tidentified as required fpreparation and submisquested by the Departmtional Environmental Pprojects: Provided furtbe reimbursed only upoment and only in the sathe total project: Proviprojects selected by the to authority granted untechnology” in the Deplated Agencies Appropin Public Law 99-190, Speaker of the House odent of the Senate priothe 100th Congress shacriteria in the third prounder the heading “Adment of Energy” in the Related Agencies Apptained in Public Law 9calendar days from recof the House of Represthe Senate.
A-12 Program Update 2001

Conference Report (H.R. Conf. Rep. No.498, 100th Cong., 1st Sess. [1987])

CLEAN COAL TECHNOLOGY

Appropriates $575,000,000 for clean coal technologyinstead 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:Bill language, proposed by the House, which wouldhave prohibited using grants has been deleted. Themanagers agree that project funding is expected to bebased on cooperative agreements, but that grants mightbe applicable to support work also funded from thisaccount.The managers agree to deleted Senate language providing personnel floors for Clean Coal Technology. Themanagers further agree that the budget estimates forpersonnel and contract support are to be followed. Theagreement included 58 new positions above currentemployment floors for the fossil energy organizationand 30 positions within the floors. Out of clean coaltechnology funds, up to $3,980,000 is for fiscal year1988 personnel-related costs and up to $16,520,000 isfor all contract costs needed to make project selectionsand complete negotiations for both clean coal procurements. Contract costs necessary to monitor approvedprojects should be requested in the fiscal year 1989budget. Increases above to those amount are subject toreprogramming procedures. No funds other than personnel related costs for the 30 positions included in theprogram direction are to be provided from the fossilenergy research and development account.The length of time for selection of projects by the Secretary of Energy has been extended from 120 days to160 days based on experience from the original cleancoal procurement. Once projects have been selected the

Secretary should establish project milestones andguidelines for project negotiations in order to expeditethe negotiation process to the extent feasible.The managers agree that the funds provided are available for non-utility applications as well as for utilityapplications.The managers agree that no funds are provided for thedemonstration of clean coal technologies which areintended solely for new, stand alone, applications. TheSenate had proposed up to 25% of the funds be available for this purpose.Bill language has been included which provides thatreports on projects selected in the first round of cleancoal procurements that are received before the end ofthe first session of the 100th Congress will satisfy reporting requirements 30 calendar days after receipt byCongress. This provision applies to a maximum of twoproject reports.

Public Law 100-446Public Law 100-446, 102 Stat. 1774 (1988)

CLEAN COAL TECHNOLOGY

For necessary expenses of, and associated with, CleanCoal Technology demonstrations pursuant to 42 U.S.C.5901 et seq., $575,000,000 shall be made available onOctober 1, 1989, and shall remain available until expended: Provided, That projects selected pursuant to ageneral request for proposals issued pursuant to thisappropriation shall demonstrate technologies capableof retrofitting or repowering existing facilities and shallbe subject to all provisions contained under this head

in Public Laws 99-190 athis Act.The first paragraph unde202 is amended by strikiappropriated for the fisc1988” and inserting “$1for the fiscal year beginnremain available until exappropriated for the fisc1989, and shall remain a$200,000,000 are appropginning October 1, 1990

fiscal year 1989 resultinpriated under this head iamended by this Act, maProvided further, That thto section 202(b)(1) of P909).For the purposes of the sPublic Laws 99-190, funValley Authority from itnot to be precluded from cost-sharing requiremenfunds are provided by anvided, That unexpended able in the “Energy SecuTreasury for the Clean Cthe Department of the InAppropriations Acts, 19101(d) of Public Law 99account: Provided furthesixth proviso in Public Lfunds provided under seshall be considered non-reports on projects selecpursuant to authority gracoal technology” in the DRelated Agencies Appro
tained in Public Law 99-190, which are received by theSpeaker 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 havemet the criteria in the third proviso of the fourth paragraph under the heading “Administrative provisions,Department Energy” in the Department of the Interiorand Related Agencies Appropriations Act, 1986, ascontained in Public Law 99-190, upon expiration of 30calendar days from receipt of the report by the Speakerof the House of Representatives and the President ofthe Senate.Conference Report (H.R. Conf. Rep. No.862, 100th Cong., 2nd Sess. [1988])

CLEAN COAL TECHNOLOGY

Amendment No. 131: Reported in technical disagreement. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate with an amendment as follows:In lieu of the matter proposed by said amendment insert the following: For necessary expenses of, andassociated with, Clean Coal Technology demonstrations pursuant to 42 U.S.C. 5901 et seq., $575,000,000shall be made available on October 1, 1989, and shallremain available until expended: Provided, Thatprojects selected pursuant to a general request forproposals issued pursuant to this appropriation shalldemonstrate technologies capable of retrofitting orrepowering existing facilities and shall be subject toall provisos contained under this head in Public Laws99-190 and 100-202 as amended by this Act.The managers on the part of the Senate will move toconcur 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 andrepowering technologies and is subject to the costsharing provisions of the previous two procurements.The managers agree that a request for proposals shouldbe issued by May 1, 1989, with proposals due no laterthan 120 days after issuance of the request for proposals, and that the Secretary of Energy should makeproject selections no later than 120 days after receipt ofproposals.Amendment No. 132: Reported in technical disagreement. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate 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 fiscalyear beginning October 1, 1988” and inserting“$190,000,000 are appropriated for the fiscal yearbeginning October 1, 1988, and shall remain availableuntil expended, $135,000,000 are appropriated for thefiscal year beginning October 1, 1989, and shall remain available until expended, and $200,000,000 areappropriated for the fiscal year beginning October 1,1990”: Provided, That outlays in fiscal year 1989resulting from the use of funds appropriated under thishead in Public Law 100-202, as amended by this Act,may not exceed $15,500,000: Provided further, Thatthese 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 toconcur 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 Pub$190,000,000 available able in 1990, and $200also provides an outlay House had proposed $$225,000,000 in fiscal fiscal year 1989, $225,$200,000,000 in fiscal the House language.Both of these changes allocation constraints, on the execution of the Congress’ overall suppdenced by additional athird procurement of teThe managers agree thpenses may be incurred $9,820,000, but cautiopenditures is necessary provided will be sufficAmendment No. 133: Mproposed by the SenateAmendment No. 134: Rment. The managers on a motion to recede and Senate which clarifies Electric Cooperatives fare eligible as cost-shaprogram.Amendment No. 135: Rment. The managers on a motion to recede and Senate which specifies 30 calendar days after reports, provided the reend of the 100th Congr
A-14 Program Update 2001

Public Law 101-45Public Law 101-45, 103 Stat. 97 (1989)

CLEAN COAL TECHNOLOGY

Notwithstanding any other provision of law, fundsoriginally appropriated under this head in the Department of the Interior and Related Agencies Appropriations Act, 1989, shall be available for a third solicitation of clean coal technology demonstration projects,which projects are to be selected by the Department notlater than January 1, 1990.Public Law 101-121Public Law 101-121, 103 Stat. 701 (1989)

CLEAN COAL TECHNOLOGY

For necessary expenses of, and associated with, CleanCoal Technology demonstrations pursuant to 42 U.S.C.5901 et seq., $600,000,000 shall be made available onOctober 1, 1990, and shall remain available untilexpended, and $600,000,000 shall be made availableon October 1, 1991, and shall remain available untilexpended: Provided, That projects selected pursuant to

a separate general request for proposals issued pursuant to each of these appropriations shall demonstratetechnologies capable of replacing, retrofitting or repowering existing facilities and shall be subject to allprovisos 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 proposalsusing funds becoming available on October 1, 1990,under this paragraph shall be issued no later than June1, 1990, and projects resulting from such a solicitationmust 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 asolicitation must be selected no later than May 1, 1992.The first paragraph under this head in Public Law100-446 is amended by striking “$575,000,000 shall bemade 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 pursuantto section 202(b)(1) of Public Law 100-119 (2 U.S.C.909).With regard to funds made available under this head inthis and previous appropriations Acts, unobligatedbalances excess to the needs of the procurement forwhich 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 notbeen made as of the date of enactment of this Act nosupplemental, backup, or contingent selection ofprojects shall be made over and above projects originally selected for negotiation and utilization of available funds: Provided further, That reports on projectsselected by the Secretary of Energy pursuant to authority granted under this heading which are received bythe Speaker of the House of Representatives and thePresident of the Senate less than 30 legislative daysprior 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 four“Administrative provisiothe Department of the InAppropriations Act, 19899-190, upon expiration ceipt of the report by the resentatives and the Presend of the session, which

Conference Report 264, 101st Cong., 1s

CLEAN CO

Amendment No. 112: Rement. The managers on a motion to recede and cSenate which adds the wtion of clean coal technothe inclusion of “replaciintended to cover the coing facility if because of tions, repowering or retrdesirable option.Amendment No. 113: Afiscal year 1990 for clea$500,000,000 as propos$325,000,000 as propospriation along with $125year 1991 in Amendmenround of clean coal techagree that additional maat the Department’s Eneorder to manage adequatfrom the accumulation oprojects and the inclusioin this bill. Although a lethe managers agree that 
be required in addition to the approximately thirtyFTE’s now included in the fossil energy research anddevelopment appropriation. The managers agree further that funds from the fossil energy research and development appropriation should not be used to pay thecost of more than the equivalent FTE’s paid under thataccount in fiscal year 1989.Amendment No. 114: Reported in technical disagreement. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate with an amendment as follows:In lieu of the matter stricken and inserted by saidamendment, insert: and shall remain available untilexpended, and $125,0000,000The managers on the part of the Senate will move toconcur 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 cleancoal technology procurement instead of $75,000,000 asproposed by the House and $100,000,000 as proposedby the Senate.Amendment No 115: Deletes Senate proposed appropriation of $150,000,000 for fiscal year 1992 for cleancoal technology. The House proposed no suchappropriation.Amendment No. 116: Restores House languagestricken by the Senate which prohibits the use ofsupplemental, backup, or contingent project selectionsin clean coal technology procurements.Amendment No. 117: Restores the word “further”stricken by the Senate.

Public Law 101-164Public Law 101-164, 103 Stat. 1109 (1989)

CLEAN COAL TECHNOLOGY

The second paragraph under this head contained in theAct making appropriations for the Department of theInterior and Related Agencies for the fiscal year endingSeptember 30, 1990, is amended by striking“$450,000,000” and inserting “$419,000,000” and bystriking “$125,000,000” and inserting “$156,000,000”.Conference Report (H.R. Conf. Rep. No.315, 101st Cong.) 1st Sess. [1989])The managers have agreed to reduce the funds appropriated by the Energy and Water Development Appropriations Act for Fiscal Year 1990 (Public Law101-101) for the “Nuclear Waste Disposal Fund” by$46,000,000. This reduction will make funds availablefor the drug prevention effort.The managers have agreed to reductions to the Interiorand Related Agencies Appropriations Act for FiscalYear 1990 (Public Law 101-121) in order to accommodate additional drug related appropriations.The reductions are in three areas. The new budget authority for Clean Coal Technology of $450,000,000 forfiscal year 1990 is reduced by $31,000,000 with thissame amount added to the advance appropriation forfiscal year 1991. With this change the new amount forfiscal year 1990 is $419,000,000 while fiscal year 1991increases to $156,000,000. The second area of changeis the imposition of an outlay ceiling on Strategic Petroleum Reserve oil acquisition. Outlays will be reduced from an estimate

$147,125,000 and will proximately 50,000 ba46,000 or 47,000 barrerelates to the Pennsylvporation. The borrowin$5,000,000 to $100,00The conference agreeming the amount of funds the Health Care FinanciManagement account b$1,917,172,000 to $18,along with the outlays rLabor, Health and Humpropriations bill, will be subcommittee’s share ofunding. The conferees fund transfers be associcatastrophic health insube diminished. Public Law 

Public Law 101-30

CLEAN C

Funds previously approclean coal technology than June 1, 1990, and 1991, respectively, shaber 1, 1991: Provided, tations shall not be conobligate these funds: Psection 202(b) of the B
A-16 Program Update 2001

Deficit Control Reaffirmation Act of 1987, this actionis a necessary (but secondary) result of a significantpolicy change: Provided further, That for the clean coalsolicitations identified herein, provisions included forthe repayment of government contributions to individual projects shall be identical to those included inthe Program Opportunity Notice (PON) for Clean CoalTechnology III (CCT-III) Demonstration Projects (solicitation number DE-PSO1-89 FE 61825), issued bythe 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 offera motion to recede and concur in the amendment of thesenate with an amendment as follows:In lieu of the matter proposed by said amendmentinsert:

DEPARTMENT OF ENERGY

CLEAN COAL TECHNOLOGY

Funds previously appropriated under this head forclean coal technology solicitations to be issued nolater than June 1, 1990, and no later than September1, 1991, respectively, shall not be obligated until September 1, 1991: Provided, That the aforementionedsolicitations shall not be conducted prior to the abilityto obligate these funds: Provided further, That pursuant to section 202 (b) of the Balanced Budget andEmergency Deficit Control reaffirmation /Act of 1987this action is a necessary (but secondary) result of asignificant policy change: Provided further, That forthe 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-III) Dem- onstration 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 amend- ment 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 Supple- mental. 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. The managers have added language to ensure that pro- visions dealing with the repayment of government pro- vided 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 pro- curements and negotiations, and input from industrial participants, Congress, and the managers of the pro- gram. 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 substan- tially. Such proposals, w

recovery of governmentof up to 20 years, might trial participation in the 50 percent cost-shared bprogram is to accelerate of coal in a more efficienstringent new air quality investment returns to the nascent markets. Public Law 1Public Law 101-512

CLEAN CO

The first paragraph unde101-121 is amended by made available on Octobavailable until expendedmade available on Octobavailable until expendedshall be made available September 1, 1991, $31and $250,000,000 on Ocremain available until exwith a separate general r$600,000,000 shall be m$150,000,000 on OctobeOctober 1, 1992, and $21993, all such sums to refor use in conjunction wfor proposals”: Providedpursuant to section 202(
(2 U.S.C. 909): Provided further, That a fourth generalrequest for proposals shall be issued not later than February 1, 1991, and a fifth general request for proposalsshall be issued not later than March 1, 1992: Providedfurther, That project proposals resulting from suchsolicitations shall be selected not later than eightmonths after the date of the general request for proposals: Provided further, That for clean coal solicitationsrequired herein, provisions included for the repaymentof government contributions to individual projects shallbe identical to those included in the Program Opportunity Notice (PON) for Clean Coal Technology III(CCT-III) Demonstration Projects (solicitation numberDE-PS01-89 FE 61825), issued by the Department ofEnergy on May 1, 1989: Provided further, That fundsprovided under this head in this or any other appropriations Act shall be expended only in accordance withthe 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 inthis and previous appropriations Acts, unobligatedbalances excess to the needs of the procurement forwhich they originally were made available may be applied to other procurements for use on projects forwhich cooperative agreements are in place, within thelimitations and proportions of Government financingincreases 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 acooperative agreement may provide appropriate protections, including exemptions from subchapter II ofchapter 5 of title 5, United States Code, against thedissemination of information that results from demonstration activities conducted under the Clean CoalTechnology Program and that would be a trade secretor commercial or financial information that is privileged or confidential if the information had been ob- tained from and first produced by a non-Federal party participating in a Clean Coal Technology project: Pro- vided further, That, in addition to the full-time perma- nent 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 Assis- tant 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 se- lected 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 Presi- dent 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 “Ad- ministrative provisions, Department of Energy” in the Department of the Interior and Related Agencies Ap- propriations 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 Represen- tatives 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 cleancoal technology on September 1, 1991 as proposed bythe House instead of $100,000,000 as proposed by theSenate. This amendment and Amendment No. 143 shiftthe availability of $65,000,000 from fiscal year 1991 tofiscal year 1992.

Amendment No. 143: Pcoal technology on OcHouse instead of $250Senate. This amendmethe availability of $65,fiscal year 1992.Amendment No. 144: Ptions for clean coal tecate. The date for CCT-1991 from January 1, 1changed from the SenaThe managers have agrfor the next solicitation publish a draft solicitatparties. It is expected tevaluation criteria and perative that potential pcomment on the contenThe managers urge the benefits to remote, impgram policy factor in eDepartment should alsprovide multiple fuel rwhich are more than seone fuel form for total Amendment No. 145: Rwithin eight months of quired by Amendment Senate. The House had Amendment No. 146: Rment contributions to pidentical to the most reproposed by the Senatesion.Amendment No. 147: Pcoal technology may b
A-18 Program Update 2001

tions contained in appropriations Acts. The Senatelanguage had prohibited geographic restrictions on theexpenditure of funds. The House had no such provision. The managers direct that no preferential consideration be given to any project referenced explicitly orimplicitly in other legislation.The managers agree to delete bill language dealingwith geographic restrictions based on such restrictionsbeing 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 managersagree 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 30full-time equivalent positions from fossil energy research and development may be used in the clean coalprogram in fiscal year 1991.Public Law 102-154Public Law 102-154, 105 Stat. 990 (1991)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law101-512 is amended by striking the phrase“$150,000,000 on October 1, 1991, $225,000,000 onOctober 1, 1992” and inserting “$100,000,000 onOctober 1, 1991, $275,000,000 on October 1, 1992”.Notwithstanding the issuance date for the fifth generalrequest for proposals under this head in Public Law101-512, such request for proposals shall be issued not

later than July 6, 1992, and notwithstanding the provisounder this head in Public Law 101-512 regarding thetime interval for selection of proposals resulting fromsuch solicitation, project proposals resulting from thefifth general request for proposals shall be selected notlater than ten months after the issuance date of the fifthgeneral request for proposals: Provided, That hereafterthe fifth general request for proposals shall be subjectto all provisos contained under this head in previousappropriations Acts unless amended by this Act.Notwithstanding the provisos under this head in previous appropriations Acts, projects selected pursuant tothe fifth general request for proposals shall advancesignificantly the efficiency and environmental performance of coal-using technologies and be applicable toeither new or existing facilities: Provided, That budgetperiods may be used in lieu of design, construction,and operating phases for cost-sharing calculations:Provided further, That the Secretary shall not financemore than 50 per centum of the total costs of anybudget period: Provided further, That project specificdevelopment activities for process performance definition, component design verification, materials selection, and evaluation of alternative designs may befunded on a cost-shared basis up to a limit of 10 percentum of the Government’s share of project cost:Provided further, That development activities eligiblefor cost-sharing may include limited modifications toexisting facilities for project related testing but do notinclude construction of new facilities.With regard to funds made available under this head inthis and previous appropriations Acts, unobligatedbalances excess to the needs of the procurement forwhich they originally were made available may be applied to other procurements for use on projects forwhich cooperative agreements are in place, within thelimitations and proportions of Government financing

increases currently allowhereafter, the Departmento five years after complof a cooperative agreemprotections, including exof chapter 5 of title 5, Udissemination of informstration activities conducTechnology Program anor commercial or financleged or confidential if ttained from and first proparticipating in a Clean vided further, That hereapermanent Federal emplof Public Law 97-257, afull-time Federal employAssistant Secretary for Fthe programs under this under this head in this anand of which not less thanot less than 30 shall be That hereafter reports on retary of Energy pursuanthis heading which are rHouse of Representativeate less than 30 legislativsession of Congress shalcriteria in the third proviunder the heading “Admment of Energy” in the DRelated Agencies Approtained in Public Law 99-calendar days from receof the House of Represe
the Senate or at the end of the session, whichever occurs later.Conference Report (H.R. Conf. Rep. No.256, 102nd Cong., 1st Sess. [1991])

CLEAN COAL TECHNOLOGY

Amendment No. 165: Reported in technical disagreement. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate with an amendment as follows:In lieu of the matter stricken and inserted by saidamendment insert:Notwithstanding the issuance date for the fifth generalrequest for proposals under this head in Public Law101-512, such request for proposals shall be issued notlater than July 6, 1992, and notwithstanding the proviso under this head in Public Law 101-512 regardingthe time interval for selection of proposals resultingfrom such solicitation, project proposals resulting fromthe fifth general request for proposals shall be selectednot later than ten months after the issuance date of thefifth general request for proposals: Provided, Thathereafter the fifth general request for proposalsThe managers on the part of the Senate will move toconcur in the amendment of the House to the amendment of the Senate.The amendment changes the issuance date for the fifthgeneral request for proposals to July 6, 1992 instead ofMarch 1, 1992 as proposed by the House and August 10,1992 as proposed by the Senate and the allowable lengthof time from issuance of the request for proposals toselection of projects to ten months. The amendment alsodeletes Senate proposed bill language pertaining to asixth general request for proposals as discussed below.

The managers agree that the additional two months inthe procurement process for the fifth round of proposals should include an additional month to allow for thepreparation of proposals by the private sector, and upto an additional month for Department of Energy review and evaluation of proposals when compared tothe process for the fourth round.The managers have agreed to delete bill languageregarding a sixth round of proposals, but agree thatfunding will be provided for a sixth round based onunobligated and unneeded amounts that may becomeavailable from the first five rounds. The report from theSecretary on available funds, which was originally inthe Senate amendment, is still a requirement and suchreport should be submitted to the House and SenateCommittees 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 fiscalyear 1995 appropriation.The managers expect that the fifth solicitation will beconducted under the same general types of criteria asthe fourth solicitation principally modified only (1) toinclude the wider range of eligible technologies orapplications; (2) to adjust technical criteria to considerallowable development activities, to strengthen criteriafor non-utility demonstrations, and to adjust commercial performance criteria for additional facilities andtechnologies with regard to aspects of general energyefficiency and environmental performance; and (3) toclarify and strengthen cost and finance criteria particularly with regard to development activities.Amendment No. 166: Restores House language deletedby the Senate which refers to a fifth general request forproposals. The Senate proposed language dealing withboth a fifth and a sixth round.

Amendment No. 167: Rment. The managers on a motion to recede and Senate which directs threobligate up to $44,00Clean Coal Technology highest in its specific teSource Evaluation Boaing project in that categthe Secretary, and if suand are sufficient to fument would earmark suable, to a specific projeof Energy selection proClean Coal TechnologyAmendment No. 168: Tdeletes House proposeproposed by the SenateAmendment No. 169: Dguage which made unoprocurements for whicbeen issued.Amendment No. 170: Rment. The managers on a motion to recede and Senate which adds “nolanguage for PETC as House had no such lanAmendment No. 171: Rment. The managers on a motion to recede and Senate which adds “nolanguage for METC as House had no such lan
A-20 Program Update 2001

Public Law 102-381Public Law 102-381, 106 Stat. 1374 (1992)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law101-512, as amended, is further amended by strikingthe 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 thephrase “$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”.Public Law 103-138Public Law 103-138, 107 Stat. 1379 (1993)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law101-512, as amended, is further amended by strikingthe phrase “$150,000,000 on October 1, 1993, and$100,000,000 on October 1, 1994” and inserting“$100,000,000 on October 1, 1993, $100,000,000 onOctober 1, 1994, and $50,000,000 on October 1,1995” and by striking the phrase “$250,000,000 onOctober 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 103-332Public Law 103-332, 108 Stat. 2499 (1994)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law101-512, as amended, is further amended by strikingthe 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 onOctober 1, 1995, and $32,000,000 on October 1,1996”; and by striking the phrase “$275,000,000 onOctober 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, Thatnot to exceed $18,000,000 available in fiscal year1995 may be used for administrative oversight of theClean Coal Technology program.Public Law 104-6Public Law 104-6, 109 Stat. 73 (1995)

CLEAN COAL TECHNOLOGY

(RESCISSION)

Of the funds made available under this heading forobligation in fiscal year 1996, $50,000,000 are rescinded and of the funds made available under thisheading for obligation in fiscal year 1997,$150,000,000 are rescinded: Provided, That funds

made available in previoavailable for any ongoinseparate request for propwas selected.Public Law 1Conference Report 402, 104th Cong., 1The managers do not ob$18,000,000 in clean cofor administration of the Public Law 1Public Law 104-208

CLEAN CO

(RE

Of the funds made availobligation in fiscal year $123,000,000 are rescinmade available in previoavailable for any ongoinseparate request for propwas 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 forobligation in fiscal year 1997 or prior years,$123,000,000 are rescinded: Provided, That funds

made available in previous appropriations Acts shall beavailable for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.

Senate Report (S. Rep. No. 319, 104thCong., 2nd Sess. [1996])The Committee does not object to the use of up to$16,000,000 in available funds for administration ofthe clean coal program in fiscal year 1997.House Report (H.R. Rep. No. 625, 104thCong., 2nd Sess. [1996])The Committee does not object to the use of up to$16,000,000 in available funds for administration ofthe clean coal program in fiscal year 1997.

Public Law 105-18Public Law 105-18, 111 Stat. 158 (1997)

CLEAN COAL TECHNOLOGY

(RESCISSION)

Of the funds made available under this heading forobligation in fiscal year 1997 or prior years,$17,000,000 are rescinded: Provided, That funds madeavailable in previous appropriations Acts shall beavailable for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.Public Law 105-83Public Law 105-83, 111 Stat. 37 (1997)Of the funds made available under this heading forobligation in fiscal year 1997 or prior years,$101,000,000 are rescinded: Provided, That fundsmade available in previous appropriations Acts shall beavailable for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.

Public Law Public Law 105-27

CLEAN C

(D

Of the funds made avaobligation in prior yearshall not be available u$15,000,000 shall not b2000; and $15,000,000 October 1, 2001: Proviin previous appropriatiany ongoing project refor proposal under whiConference Repor825, 105th Cong. 2

CLEAN C

The conference agreem$40,000,000 in previouclean coal technology pSenate. The House did The Committees agree for administration of thprogram.
A-22 Program Update 2001

Public Law 106-113Public Law 106-113, 113 Stat. 1501 (1999)

CLEAN COAL TECHNOLOGY

(DEFERRAL)

Of the funds made available under this heading forobligation in prior years, $156,000,000 shall not beavailable until October 1, 2000: Provided, That funds

made available in previous appropriations Acts shall beavailable for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.

Conference Report (H.R. Rep. No. 406,106th Cong., 1st Sess. [1999])

CLEAN COAL TECHNOLOGY

(DEFERRAL)

The conference agreement provides for the deferral of$156,000,000 in previously appropriated funds for theclean coal technology program as proposed by theSenate 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.

Public Law 106-291Public Law 106-291, 114 Stat. 922 (2000)

CLEAN COAL TECHNOLOGY

(DEFERRAL)

Of the funds made available under this heading forobligation in prior years, $67,000,000 shall not beavailable until October 1, 2001: Provided, That fundsmade available in previous appropriations Acts shall beavailable for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.

FOSSIL ENERGY RESEARCH AND DEVELOPMENT

(INCLUDING TRANSFERS OF FUNDS)

For necessary expenses in carrying out fossil energyresearch and development activities, under the authority of the Department of Energy Organization Act(Public Law 95-91), including the acquisition of interest, including defeasible and equitable interests in anyreal property or any facility or for plant or facility acquisition or expansion, and for conducting inquiries,technological investigations and research concerningthe extraction, processing, use, and disposal of mineralsubstances without objectionable social and environmental costs (30 U.S.C. 3, 1602, and 1603), performedunder the minerals and materials science programs atthe Albany Research Center in Oregon $ 540,653,000,to remain available until expended, of which $12,000,000 for oil technology research shall be derivedby transfer from funds appropriated in prior years under the heading “Strategic Petroleum Reserve, SPRPetroleum Account” and of which $ 95,000,000 shallbe derived by transfer from funds appropriated in prioryears under the heading “Clean Coal Technology”,

such funds to be availabproposals for the commetechnologies to assure thenergy supply from exising facilities for which threview may provide finavided, That the request flater than one hundred aactment of this Act, proplater than ninety days aftfor proposals, and the Dmake project selections sixty days after the receither, That no funds are tproposals prior to Septemther, That funds provideaccordance with the provfunds contained under thwere originally appropriprovisions for repaymento individual projects shcluded in the Program ONumber DE-PS01-89FEment of Energy on May ments from sale or licenfrom both domestic and further, That such repaymaccount to be retained fofurther, That any project shall be considered a Clstration Project, for the pand 60 of title 40 of the Provided further, That navailable shall be used fexplosives in the recovefurther, That up to 4 percavailable to the Nationatory may be used to suppactivities not included in 
Public Law 107-63Public Law 107-63, 115 Stat. 414 (2001)

CLEAN COAL TECHNOLOGY

(DEFERRAL)

Of the funds made available under this heading forobligation in prior years, $40,000,000 shall not beavailable until October 1, 2002: Provided, That fundsmade available in previous appropriations Acts shall beavailable for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.

FOSSIL ENERGY RESEARCH AND DEVELOPMENT

(INCLUDING TRANSFER OF FUNDS)

For necessary expenses in carrying out fossil energyresearch and development activities, under the authority of the Department of Energy Organization Act(Public Law 95-91), including the acquisition of interest, including defeasible and equitable interests in anyreal property or any facility or for plant or facility acquisition or expansion, and for conducting inquiries,technological investigations and research concerningthe extraction, processing, use, and disposal of mineralsubstances without objectionable social and environmental costs (30 U.S.C. 3, 1602, and 1603),$616,490,000, to remain available until expended, ofwhich $11,000,000 is to begin a 7-year project for construction, renovation, furnishing, and demolition orremoval of buildings at National Energy TechnologyLaboratory facilities in Morgantown, West Virginia andPittsburgh, Pennsylvania; and for acquisition of lands,and interests therein, in proximity to the National Energy Technology Laboratory, and of which$33,700,000 shall be derived by transfer from funds

appropriated in prior years under the heading ‘CleanCoal Technology’, and of which $150,000,000 andsuch sums as may be appropriated in fiscal year 2003are to be made available, after coordination with theprivate sector, for a request for proposals for a CleanCoal Power Initiative providing for competitivelyawarded demonstrations of commercial scale technologies to reduce the barriers to continued and expandedcoal use: Provided, That the request for proposals shallbe issued no later than 120 days following enactmentof this Act, proposals shall be submitted no later than150 days after the issuance of the request for proposals,and the Department of Energy shall make project selections no later than 160 days after the receipt of proposals: Provided further, That no project may be selectedfor which sufficient funding is not available to providefor the total project: Provided further, That funds shallbe expended in accordance with the provisions governing the use of funds contained under the heading‘Clean Coal Technology’ in prior appropriations:Provided further, That the Department may includeprovisions for repayment of Government contributionsto individual projects in an amount up to the Government contribution to the project on terms and conditions that are acceptable to the Department includingrepayments from sale and licensing of technologiesfrom both domestic and foreign transactions: Providedfurther, That such repayments shall be retained by theDepartment for future coal-related research, development and demonstration projects: Provided further,That any technology selected under this program shallbe considered a Clean Coal Technology, and anyproject selected under this program shall be considereda Clean Coal Technology Project, for the purposes of42 U.S.C. Sec. 7651n, and Chapters 51, 52, and 60 oftitle 40 of the Code of Federal Regulations: Providedfurther, That funds excess to the needs of the PowerPlant Improvement Initiative procurement provided for

under this heading in Pmade available for the provided for under this further, That no part of shall be used for the fiein the recovery of oil aup to 4 percent of progthe National Energy Teused to support Departincluded in this accoun
A-24 Program Update 2001
 Program Update 2001 B-1

x B. CCT Program History

olicitation

citation, issued Febru

shared projects to

ean coal technologies

he Program Opportunity

osals. Nine projects

were placed on a list of

ations on the original 9

lternate projects were

ment projects. Projects

ternates on three

ary 22, 1988, solicited

oal technology projects

at were capable of being

more cost-effective than

le of achieving signifi

NOx emissions from

 particularly those that

pollution. The CCT-II

mplementing the

nd Canadian Special

OE received 55 propos

ering the goals and

nates were selected).

ON, issued May 1,

 clean coal technology

projects to demonstrate innovative, energy-efficienttechnologies capable of being commercialized in the1990s. These technologies were to be capable of (1)achieving significant reductions in emissions of SO2and/or NOx from existing facilities to minimizeenvironmental impacts, such as transboundary andinterstate air pollution; and/or (2) providing for futureenergy needs in an environmentally acceptable manner.DOE received 48 proposals and selected 13 projects asbest furthering the goals and objectives of the PON.The CCT-IV PON, issued January 17, 1991, solicitedproposals to conduct cost-shared clean coal technologyprojects to demonstrate innovative, energy-efficient,economically competitive technologies. These technologies were to be capable of (1) retrofitting, repowering, or replacing existing facilities while achievingsignificant reductions in the emissions of SO2, NOx, or

both, and/or (2) providing for future energy needs in anenvironmentally acceptable manner. A total of 33proposals were submitted in response to the PON. Nineprojects were selected.The objective of the CCT-V PON, issued July 6, 1992,was to solicit proposals to conduct cost-shareddemonstration projects that significantly advance theefficiency and environmental performance of coalusing technologies and are applicable to either new orexisting facilities. In response to the solicitation, DOEreceived proposals for 24 projects and selected 5projects.

CCT Program Selection andNegotiation HistoryThe following is a history of the selection and negotiations for the CCT Program Projects. Data are providedthrough September 2000.July 1986Nine projects were selected under CCT-I (14 alternateprojects selected to replace any selected projects ifnegotiations were unsuccessful).March 1987DOE signed cooperative agreements with two CCT-Iparticipants, Coal Tech Corporation (AdvancedCyclone Combustor with Internal Sulfur, Nitrogen, andAsh Control) and The Ohio Power Company (TiddPFBC Demonstration Project).June 1987DOE signed a cooperative agreement with CCT-Iparticipant, The Babcock & Wilcox Company (nowMcDermott Technology, Inc.) LIMB DemonstrationProject Extension and Coolside Demonstration.July 1987DOE signed a cooperative agreement with CCT-Iparticipant, Energy and Environmental ResearchCorporation (Enhancing the Use of Coals by GasReburning and Sorbent Injection).
B-2 Program Update 2001

September 1987General Electric Company withdrew its proposal(Integrated Coal Gasification Steam Injection GasTurbine Demonstration Plants with Hot Gas Cleanup).October 1987Weirton Steel Corporation withdrew its proposal,Direct Iron Ore Reduction to Replace Coke Oven/BlastFurnace for Steelmaking, from furtherconsideration.Four more CCT-I projects were selected: Colorado-UteElectric Association, Inc. (Nucla CFB DemonstrationProject); TRW, Inc. (Advanced Slagging Coal Combustor Utility Demonstration Project); MinnesotaDepartment of Natural Resources (COREX IronmakingDemonstration Project); and Foster Wheeler PowerSystems, Inc. (Clean Energy IGCC DemonstrationProject).December 1987DOE signed cooperative agreements with two moreCCT-I participants, Ohio Ontario Clean Fuels, Inc.,(Prototype Commercial Coal/Oil CoprocessingProject) and Energy International, Inc. (UndergroundCoal Gasification Demonstration Project).January 1988DOE signed a cooperative agreement with The M.W.Kellogg Company and Bechtel Development Companyfor a CCT-I project, The Appalachian IGCC Demonstration Project.September 1988Sixteen projects were selected under CCT-II.November 1988DOE signed a cooperative agreement with CCT-Iparticipant, TRW, Inc. (Advanced Slagging CoalCombustor Utility Demonstration Project).

December 1988Negotiations were terminated with Minnesota Department of Natural Resources (COREX IronmakingDemonstration Project) under CCT-I.DOE selected three more CCT-I projects: ABBCombustion Engineering, Inc. and CQ Inc. (Development of the Coal Quality ExpertTM); Western EnergyCompany (formerly Rosebud SynCoal Partnership,now Western SynCoal LLC; Advanced Coal Conversion Process Demonstration); and United Coal Company(Coal Waste Recovery Advanced TechnologyDemonstration).June 1989The City of Tallahassee CCT-I project, ACFB Repowering, was selected from the alternate list.The M.W. Kellogg Company and Bechtel Development Company withdrew their CCT-I project, CleanEnergy IGCC Demonstration Project.September 1989United Coal Company withdrew its CCT-I project,Coal Waste Recovery Advanced TechnologyDemonstration.November 1989DOE signed a cooperative agreement with CCT-IIparticipant, Bethlehem Steel Corporation (InnovativeCoke Oven Gas Cleaning System for RetrofitApplications).Combustion Engineering, Inc., (CCT-II) withdrew itsPostcombustion Sorbent Injection DemonstrationProject.December 1989Thirteen projects were selected under CCT-III.

DOE signed cooperative participants: ABB Comb(SNOXTM Flue Gas CleaThe Babcock & Wilcox 

BoxTM Flue Gas Cleanup Passamaquoddy Tribe (Cery Scrubber); Pure Air Flue Gas Desulfurization Southern Company ServAdvanced Combustion TBoiler).Energy International, IncUnderground Coal Gasif

February 1990Foster Wheeler Power SCCT-I proposal, Clean EProject.April 1990DOE signed cooperative participants: The AppalaUtility Demonstration PWilcox Company (Demofor Cyclone Boiler NOx Company Services, Inc. Applications of TechnolProcess).June 1990DOE signed cooperative participants of one CCTEngineering, Inc. and CQ Coal Quality ExpertTM), pants: Southern Compantion of Selective Catalytthe Control of NOx EmisFired Boilers) and Trans
Corporation (LNS Burner for Cyclone-Fired BoilersDemonstration Project).September 1990DOE signed cooperative agreements with one CCT-Iparticipant, Western Energy Company (formerlyRosebud SynCoal Partnership, now Western SynCoalLLC); Advanced Coal Conversion Process Demonstration); one CCT-II participant, Southern CompanyServices, Inc. (180-MWe Demonstration of AdvancedTangentially Fired Combustion Techniques for theReduction of NOx Emissions from Coal-Fired Boilers);and one CCT-III participant, ENCOAL Corporation(ENCOALÆ Mild Coal Gasification Project).

Negotiations were terminated with CCT-II participant,Southwestern Public Service Company (Nichols CFBRepowering Project).

October 1990DOE signed cooperative agreements with four CCT-IIIparticipants: AirPol, Inc. (10-MWe Demonstration ofGas Suspension Absorption); The Babcock & WilcoxCompany (Full-Scale Demonstration of Low-NOx CellBurner Retrofit); Bechtel Corporation (Confined ZoneDispersion Flue Gas Desulfurization Demonstration);and Energy and Environmental Research Corporation(Evaluation of Gas Reburning and Low-NOx Burnerson a Wall-Fired Boiler).November 1990DOE signed cooperative agreements with one CCT-Iparticipant, The City of Tallahassee (Arvah B. HopkinsCirculating Fluidized-Bed Repowering Project; nowJEA and the JEA Large-Scale CFB CombustionDemonstration Project); one CCT-II participant, ABBCombustion Engineering, Inc. (Combustion Engineering IGCC Repowering Project); and two CCT-IIIparticipants, Bethlehem Steel Corporation (Blast

Furnace Granular-Coal Injection System Demonstration Project) and LIFACñNorth America (LIFACSorbent Injection Desulfurization DemonstrationProject).

December 1990Negotiations terminated with CCT-II participant,Otisca Industries, Ltd. (Otisca Fuel DemonstrationProject) and CPICORô.March 1991DOE signed cooperative agreements with three CCTIII participants: MK-Ferguson Company (now NOXSOCorporation (Commercial Demonstration of theNOXSO SO2/NOx Removal Flue Gas Cleanup System); Public Service Company of Colorado (Integrated

Dry NOx/SO2 Emissions Control System); and TampaElectric Company (formerly Clean Power Cogeneration Limited Partnership; now Tampa Electric Integrated Gasification Combined-Cycle Project).TRW, Inc., withdrew its CCT-I project (AdvancedSlagging Coal Combustion Utility DemonstrationProject).

April 1991DOE signed a cooperative agreement with CCT-IIIparticipant, Alaska Industrial Development and ExportAuthority (Healy Clean Coal Project).June 1991DOE withdrew its sponsorship of the Ohio OntarioClean Fuels, Inc., CCT-I project, Prototype Commercial Coal/Oil Coprocessing Plant.August 1991DOE signed a cooperative agreement with CCT-IIIparticipant, DMEC-1 Limited Partnership (formerly

Dairyland Power CoopProject).TransAlta Resources Inits CCT-II project, LNBoilers Demonstration 

September 1991Nine projects were seleCoal Tech CorporationCyclone Combustor wiAsh Control, final repocompleted.April 1992Tri-State Generation anInc.ís (formerly ColoraInc.) CCT-I project, NuProject, final reports isJune 1992The City of Tallahassetured and transferred to L.P. (York County EneProject).July 1992DOE signed cooperativparticipants: Tennessee York State Electric & GCoal Reburning Demo

175-MWe Wall-Fired UCoal Gasification Repo(Wabash River Coal G
B-4 Program Update 2001

August 1992DOE signed a cooperative agreement with CCT-IVparticipant, Sierra Pacific Power Company (PiÒon PineIGCC Power Project).Cordero Mining Company withdrew from negotiationsfor its CCT-IV project, Cordero Coal-UpgradingDemonstration Project.At the participantís request, Union Carbide Chemicalsand Plastics Company, Inc. (CCT-IV) was granted anextension of one year to the DOE deadline for completing negotiations of its Demonstration of the UnionCarbide CANSOLVô System at the Alcoa GeneratingCorporation Warrick Power Plant.October 1992DOE signed cooperative agreements with one CCT-IIIparticipant, Air Products and Chemicals, Inc. (Commercial-Scale Demonstration of the Liquid PhaseMethanol [LPMEOHô] Process) and with four CCTIV participants: Custom Coals International (SelfScrubbing Coalô: An Integrated Approach to CleanAir); New York State Electric & Gas Corporation(Milliken Clean Coal Technology DemonstrationProject); TAMCO Power Partners (Toms Creek IGCCDemonstration Project); and ThermoChem, Inc. (PulseCombustor Design Qualification Test).November 1992The Babcock & Wilcox Companyís (now McDermottTechnology, Inc.) CCT-I project, LIMB DemonstrationProject Extension and Coolside Demonstration, finalreports issued and project completed.May 1993Five projects were selected under CCT-V: Four RiversEnergy Partners, L.P. (Four Rivers Energy Modernization Project (formerly Calvert City Advanced Energy

Project, now McIntosh Unit 4B Topped PCFB Demonstration Project); Duke Energy Corporation (CamdenClean Energy Demonstration Project); CenteriorEnergy Corporation, on behalf of CPICORô Management Company LLC (Clean Power from IntegratedCoal/Ore Reduction [CPICORô]); Arthur D. Little,Inc. (Clean Coal Combined-Cycle Project; formerlyDemonstration of Coal Diesel Technology at EastonUtilities; now Clean Coal Diesel DemonstrationProject); and Pennsylvania Electric Company (WarrenStation Externally Fired Combined-Cycle Demonstration Project).

July 1993Union Carbide Chemicals and Plastics Company, Inc.,withdrew its CCT-IV proposal, Demonstration of theUnion Carbide CANSOLVô System at the AlcoaGenerating Corporation Warrick Power Plant.February 1994The Passamaquoddy Tribeís CCT-III project, CementKiln Flue Gas Recovery Scrubber, final reports issuedand project completed.March 1994The Babcock & Wilcox Companyís CCT-II project,Demonstration of Coal Reburning for Cyclone BoilerNOx Control, final reports issued and project

completed.

June 1994DOE signed a cooperative agreement with CCT-Vparticipant, Arthur D. Little, Inc. (Coal Diesel Combined-Cycle Project).Southern Company Servicesí CCT-III project, 180-MWe Demonstration of Advanced Tangentially FiredCombustion Techniques for the Reduction of NOx

Emissions from Coal-Fiand project completed.Bechtel Corporationís CDispersion Flue Gas Desfinal reports issued and pAugust 1994DOE signed cooperative participants, Four Rivers Rivers Energy Moderniznia Electric Company (WCombined-Cycle DemonThe CCT-III project, Cothe NOXSO SO2/NOx R

System, was relocated anCorporation.

September 1994The Air Products and ChCommercial-Scale DemMethanol (LPMEOHô) Air Products Liquid PhaDecember 1994DOE signed a cooperativparticipant, Clean Energ(formerly Duke Energy CIGCC Demonstration PrIGCC Demonstration PrMarch 1995TAMCO Power PartnerIGCC Demonstration Prextension and the projec
April 1995Bethlehem Steel Corporationís CCT-II project,Innovative Coke Oven Gas Cleaning System forRetrofit Applications, was terminated by mutualagreement with DOE because coke production wassuspended at the demonstration facility.June 1995AirPol, Inc.ís CCT-II project, 10-MWe Demonstrationof Gas Suspension Absorption, final reports issued andproject completed.September 1995The Babcock & Wilcox Companyís CCT-II project,SOx-NOx-Rox Boxô Flue Gas Cleanup DemonstrationProject, final reports issued and project completed.December 1995The Tennessee Valley Authority and New York StateElectric & Gas Corporation finalized an agreement toallow the project, Micronized Coal Reburning Demonstration for NOx Control, to be conducted at bothMilliken Station in Lansing, NY and Eastman KodakCompany in Rochester, NY.The Babcock & Wilcox Companyís CCT-II project,Full-Scale Demonstration of Low-NOx Cell BurnerRetrofit, final reports issued and project completed.The Ohio Power Companyís CCT-I project, TiddPFBC Demonstration Project, final reports issued andproject completed.May 1996The ABB Combustion Engineering, Inc. CCT-IIproject, Combustion Engineering IGCC RepoweringProject, was concluded.

June 1996Pure Air on the Lakeís CCT-II project, Advanced FlueGas Desulfurization Project, final reports issued andproject completed.August 1996The Arthur D. Little, Inc., CCT-V project was restructured and retitled as the Clean Coal Diesel Demonstration Project.September 1996The Appalachia Power Company CCT-II project,PFBC Utility Demonstration Project, was concluded.October 1996DOE signed a cooperative agreement with CCT-Vparticipant, CPICORô Management Company LLC(Clean Power from Integrated Coal/Ore Reduction[CPICORô]).November 1996Southern Company Servicesí CCT-II project, Demonstration of Selective Catalytic Reduction Technologyfor the Control of NOx Emissions from High-Sulfur,

Coal-Fired Boilers, final reports issued and projectcompleted.

December 1996ABB Environmental Systemsí CCT-II project,SNOXô Flue Gas Cleaning Demonstration Project,final reports issued and project completed.May 1997The Pennsylvania Electric Company CCT-V project,Warren Station Externally Fired Combined-CycleDemonstration Project, was concluded.

September 1997DOE modified the coo(formerly Jacksonville project, JEA Large-Sca(formerly The City of TYork County Energy PDecember 1997ENCOAL CorporationMild Coal Gasification project completed.DOE signed a new coorestructured City of LaMcIntosh Unit 4A PCF(formerly the DMEC-1 January 1998DOE signed a new coorestructured City of LaMcIntosh Unit 4B TopProject (formerly the Fproject).April 1998LIFACñNorth AmericaSorbent Injection DesuProject, final reports isJune 1998Southern Company Serstration of Innovative Athe CT-121 FGD Proceproject completed.The ABB Combustion CCT-I project, DeveloExpertô, final reports 
B-6 Program Update 2001

September 1998Energy and Environmental Research CorporationísCCT-I project, Enhancing the Use of Coals by GasReburning and Sorbent Injection, final reports issuedand project completed.DOE signed a revised cooperative agreement for therestructured ThermoChem Inc.ís CCT-IV project,Pulse Combustor Design Qualification test.October 1998Energy and Environmental Research CorporationísCCT-III project, Evaluation of Gas Reburning andLow-NO

x Burners on a Wall-Fired Boiler, final reports

issued and project completed.

September 1999Energy and Environmental Research Corp.ís CCT-Iproject, Enhancing the Use of Coals by Gas Reburningand Sorbent Injection, final report issued and projectcompleted.DOE signed a revised cooperative agreement forSouthern Company Services, Inc.ís CCT-II project,Demonstration of Advanced Combustion Techniquesfor a Wall-Fired Boiler, extending the project.October 1999Southern Company Services, Inc.ís CCT-II project,Demonstration of Innovative Applications of Technology for the CT-121 FGD Process, final report issuedand project completed.New York State Electric & Gas Corporationís CCT-IVproject, Milliken Clean Coal Technology Demonstration Project, final report issued and project completed.Bethlehem Steel Corporationís CCT-III project, BlastFurnace Granular-Coal Injection System Demonstration Project, final report issued and project completed.

December 1999New York State Electric & Gas Corporationís CCT-IVproject, Micronized Coal Reburning Demonstration forNO

x Control, final report issued and project completed.

NOXSO Corporationís project, Commercial Demonstration of the NOXSO SO2/NOx Removal Flue GasCleanup System, was terminated.

January 2000Custom Coal Internationalís CCT-IV project, SelfScrubbing Coalô : An Integrated Approach to CleanAir, was terminated.February 2000Public Service Company of Coloradoís CCT-IIIproject, Integrated Dry NOx/SO2 Emissions Control

System, final report issued and project completed.

September 2000Wabash River Coal Gasification Repowering ProjectJoint Ventureís CCT-IV project, Wabash River CoalGasification Repowering Project, final report issuedand project completed.January 2001Sierra Pacific Power Companyís project, Pinon PineIGCC Power Project, final report issued and projectcompleted.June 2001Western SynCoal LLCís project, Advanced CoalConversion Process Demonstration, final report issuedand project completed.
 Program Update 2001 C-1

will ensure operational compliance and that significanttechnical and environmental data are collected anddisseminated. 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.

x C. CCT Program Environmental Aspects

and EISs for 5 projects (actions exceed 35 because ofproject terminations, withdrawals, and restructuring).For each project cofunded by DOE under the CCTProgram, the industrial participant is required todevelop an environmental monitoring plan (EMP) that

y (DOE) employs a

t the CCT Program and

cedural requirements

Policy Act (NEPA), and

liance promulgated by

Quality (CEQ) (40 CFR

 (10 CFR Part 1021).

ration of a program

tement (PEIS) in 1989;

 project-specific

 preparation of

PA documentation.

nts have been used in

emoranda-to-file (MTF;

0, 1990), environmen

onmental impact

ment of Energy’s NEPA

egorical exclusions

ons.

 made through Septem

A reviews of projects in

ber 30, 2001, NEPA

 of the 38 CCT projects

NEPA reviews were

ancing the Use of Coals

Injection—an MTF

n site and an EA for the

ugh September 30,

e satisfied with a CX for

, EAs for 18 projects

Exhibit C-1

NEPA Reviews Completed as of September 30, 2001

02468

101214

1987 1988a 1989 a,c 1990 1991b 1992c 1993 1994 1995c 1996 1997 1998 1999 2000 2001

Fiscal Year

Number of Projects

a Includes an MTF (1988) and an

 EA (1989) required for one project

b Includes an EA for a project 

 that was withdrawn

c Includes an EA for a project 

 that was terminated

Environmental assessmentsMemoranda-to-file Categorical exclusions

Environmental impact statements
C-2 Program Update 2001

tion is used, along with gathered by DOE, as thdocuments that are prepproject. These NEPA dconsidered, and publishCEQ and DOE regulatiCategorical Exclus“Subpart D—Typical CNEPA regulations provas a class of actions thaindividually or cumulaton the human environmCoal Reburning Demon

Pulse Combustor Desigdetermined to be covereAugust 1992 and Nove

Memoranda-to-FilThe MTF was establishguidelines were first issintended for circumstanof the proposed action wthe action had not been exclusion from NEPA dMTF was terminated as Exhibit C-2 lists the 17 was prepared.Environmental AssAn EA has the followin1. To provide sufficien

determining whethpreparation of an Ecant impact (FONS

The Role of NEPA in theCCT ProgramNEPA 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 encapsulated in the following provision (Section 102):

[A]ll agencies of the Federal Government shall—. . .(C) include in every recommendation or report on proposals for legislation and other major Federal actions significantly affecting the quality of the human environment, adetailed 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 oflong-term productivity, and

v. any irreversible and irretrievable commitments of

resources which would be involved in the proposedaction should it be implemented. . . .

(E) study, develop, and describe appropriate alternatives torecommended courses of action in any proposal whichinvolves unresolved conflicts concerning alternative uses ofavailable resources[.]Through NEPA, Congress created the CEQ, which haspromulgated regulations that ensure compliance withthe Act.

Compliance with NEPAIn November 1989, a PEIS was completed for theCCT Program. This PEIS addressed issues such aspotential global climatic modification and theecological and socioeconomic impacts of the CCTProgram. The PEIS evaluated the following twoalternatives:• “No action,” which assumed that conventional

coal-fired technologies with conventional flue gasdesulfurization controls would continue to beused, and

• “Proposed action,” which assumed that successfully demonstrated clean coal technologies would

undergo widespread commercialization by theyear 2010.

In preselection project-specific environmentalreviews, DOE evaluates the environmental aspects ofeach proposed demonstration project. Reviews areprovided to the Source Selection Official for consideration in the project selection process. The sitespecific environmental, health, safety, and socioeconomic issues associated with each proposed projectare examined during the NEPA review. As part of thecomprehensive evaluation prior to selecting projects,the strengths and weaknesses of each proposal arecompared with the environmental evaluation criteria.To the maximum extent possible, the environmentalimpacts of each proposed project and practicalmitigating measures are considered. Also, a list ofnecessary permits is prepared, to the extent known;these are permits that would need to be obtained inimplementing the proposed project.Upon selection, project participants are required toprepare and submit additional environmental information. This detailed site- and project-specific informa-
2. To aid an agency’s 

no EIS is necessaplinary review of potential impactsand mitigation me

3. To facilitate prepa

necessary.

An EA’s contents are basis and depend on thappropriate, a DOE Eor wetlands assessmenmay include analyses determinations.If an agency determinnot necessary to prepaCouncil on Environmdescribe the FONSI apresents the reasons wsignificant effect on thwhich an EIS thereforFONSI includes the Eany other related enviand DOE regulations the public that a FONprovides copies of the request.Exhibit C-3 lists the 1been prepared. The eproject that was subseprogram—TransAlta RCorporation’s Low-N

Utility Cyclone Boilerterminated—ABB Cobustion Engineering IBethlehem Steel CorpGas Cleaning System Pennsylvania ElectricFired Combined-Cycl

Project and Participant CompletedCCT-IDevelopment of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc. and CQ Inc.) 4/27/90LIMB Demonstration Project Extension and Coolside Demonstration 6/2/87(McDermott Technology, Inc.)Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 3/26/87

(Coal Tech Corporation)Nucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State 4/18/88Generation and Transmission Association, Inc.)Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Hennepin site) 5/9/88(Energy and Environmental Research Corporation)

Tidd PFBC Demonstration Project (The Ohio Power Company) 3/5/87CCT-IISNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) 1/31/90

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project 9/22/89(The Babcock & Wilcox Company)Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 5/22/89(Southern Company Services, Inc.)Demonstration of Selective Catalytic Reduction Technology for the Control of NOx 8/16/89

Emissions from High-Sulfur, Coal-Fired Boilers (Southern Company Services, Inc.)180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the 7/21/89

Reduction of NOx Emissions from Coal-Fired Boilers (Southern Company Services, Inc.)

CCT-III10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) 9/21/90

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit (The Babcock & Wilcox Company) 8/10/90

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) 9/25/90

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler (Energy and 9/6/90

Environmental Research Corporation)LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) 10/2/90

Integrated Dry NOx/SO2 Emissions Control System (Public Service Company of Colorado) 9/27/90

Exhibit C-2

Memoranda-to-File Completed
C-4 Program Update 2001

Project and Participant CCT-IEnhancing the Use of Coals by Gas Reburning and Sorbent Injection (Lakeside site) (Energy and Environmental Research Corporation) Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) CCT-IICombustion Engineering IGCC Repowering Project (ABB Combustion Engineering, Inc.) (project terminated) Demonstration of Coal Reburning for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) 

Innovative Coke Oven Gas Cleaning System for Retrofit Applications (Bethlehem Steel Corporation) (project terminated) Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) 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.) 

Low-NO

x

/SO2 Burner Retrofit for Utility Cyclone Boilers (TransAlta Resources Investment Corporation) (project withdrawn) 

CCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHô) Process (Air Products Liquid Phase Conversion Company, L.P.) Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) ENCOALÆ Mild Coal Gasification Project (ENCOALCorporation) 

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) 

CCT-IVSelf-Scrubbing Coalô: An Integrated Approach to Clean Air (Custom Coals International) 

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) 

Warren Station Externally Fired Combined-Cycle Demonstration Project (Pennsylvania Electric Company) (Warren Station site) (project terminated) 

Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) 

CCT-VClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) 

Exhibit C-3

Environmental Assessments Completed as of September 30, 2001
Project and Participant CCT-IYork County Energy Partners Cogeneration Project (York County, PA site) (York County Energy Partners, L.P.) (project relocated)JEA Large-Scale CFB Combustion Demonstration Project CCT-IIIHealy Clean Coal Project (Alaska Industrial Development and Export Authority) Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company)CCT-IVPiñon Pine IGCC Power Project (Sierra Pacific Power Company) Note: Completion is the date DOE issued a record of decision.

Environmental Impact StatementsThe primary purpose of an EIS is to serve as anaction-forcing device to ensure that the policies andgoals defined in NEPA are infused into the programsand actions of the federal government. An EIScontains a full and fair discussion of all significantenvironmental impacts. The EIS should informdecision makers and the public of reasonable alternatives that would avoid or minimize adverse impacts orenhance the quality of the human environment.The CEQ regulations state that an EIS is to be morethan a disclosure document; it is to be used by federalofficials in conjunction with other relevant material toplan actions and make decisions. Analysis of alternatives is to encompass those alternatives to be considered by the ultimate decision maker, including acomplete description of the proposed action. In short,the EIS is a means of assessing the environmentalimpacts of a proposed DOE action (rather thanjustifying decisions already made), prior to making adecision to proceed with the proposed action. Consequently, before a record of decision (ROD) is issued,DOE may not take any action that would have anadverse environmental effect or limit the choice ofreasonable alternatives. As seen in Exhibit C-4, theEISs for three projects were completed in 1994. In1995, DOE issued a ROD on the EIS prepared for theYork County Energy Partners project located in YorkCounty, Pennsylvania. This project has been restructured, and a new NEPA compliance document for theJEA project site was completed in fiscal year 2000,and the ROD issued in fiscal year 2001.NEPA Actions in ProgressExhibit C-5 lists the status of projects for which theNEPA process has not yet been completed.

Exhibit C-4

Environmental Impact Statements Comp

September 30, 2001

Project and Participant CCT-IIIMcIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland Elec

CCT-VMcIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, Lakeland Electric)Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM ManagemCompany LLC)Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LL

Exhibit C-5

NEPA Reviews in Progress as of Septem
C-6 Program Update 2001

With respect to emisProposers should coelements and compothe PON, “Specific tored”]. Proposers sinformation known emissions of these ttechnology. Some oproposed technology likely unregulated in present. The signifithe additional controtechnology for the cbe explained. An exbe one or more particontrolled by a techpower generation.

The CCT-V PON also stoxics be presented in threquired by DOE. Exhprovide for HAPs monihave completed the HAThe objective of the HAimprove the quality of Hto monitor a broader ranemissions control equipThe CCT Program is cosuch as the Electric Powand the Ohio Coal Devefocused on HAPs moniunder the DOE Coal R&summarizing the sourcefrom coal-fired power pA report released in JulEmissions Testing at Sixassessment of HAPs memajor pollution control from the stack. A secoAssessment of Toxics EPower Plants: Phase I ment of Energy Study, w

Environmental MonitoringCCT project participants are required to develop andimplement an EMP that addresses both complianceand supplemental monitoring. Exhibit C-6 lists thestatus of EMPs for all 38 projects in the CCT Program.The EMP is intended to ensure collection and dissemination of the significant technology-, project-, and sitespecific environmental data necessary for evaluation ofimpacts upon health, safety, and the environment.Further, the data are used to characterize and quantifythe environmental performance of the technology inorder to evaluate its commercialization and deployment potential. In addition to regulatory compliancedata, further monitoring is required to fulfill thefollowing:• 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 amitigation action plan pursuant to the provisionsof an EA or EIS, and

• Provide the essential data on the environmental

performance of the technology needed to evaluatethe potential impact of future commercialization,including the ability of the technology to meetrequirements of the Clean Air Act and the 1990amendments.

The objective of the CCT Program’s environmentalmonitoring efforts is to ensure that, when commerciallyavailable, clean coal technologies will be capable ofresponding fully to air toxics regulations that emerge

from the CAAA, and to the maximum extent possible,are in the vanguard of cost-effective solutions toconcerns about public health and safety related to coaluse.Air ToxicsTitle III of the CAAA lists known hazardous airpollutants (HAPs) and, among other things, calls forthe EPA to establish categories of sources that emitthese pollutants. Exploratory analyses suggest thatHAPs may be released by conventional coal-firedpower plants and, presumably, by plants using cleancoal technologies. It is expected that emissionsstandards will be proposed for the electric-powerproduction-source categories. However, there aremany uncertainties as to which HAPs will be regulated, their prevalence in various types and sources ofcoal, and their nature and fate as functions of combustion characteristics and the particular clean coaltechnology used.The CCT Program recognizes the importance ofmonitoring HAPs in achieving widespread commercialization in the late 1990s and beyond. For allprojects with existing cooperative agreements, DOEsought to include HAPs monitoring. A total of 20projects contain provisions for monitoring HAPs.The CCT-V Program Opportunity Notice (PON)acknowledged the importance of HAPs throughout thesolicitation, including them as an aspect of proposalevaluation. The PON addressed the control of airtoxics as an environmental performance criterion.Also, in the instructions on proposal preparation, thePON directed proposers as follows:
Project and Participant StatCCT-IDevelopment of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc. and CQ Inc.) ComLIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) ComAdvanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) ComNucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State Generation and Transmission Association, Inc.) ComEnhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Com

Com

Tidd PFBC Demonstration Project (The Ohio Power Company) ComAdvanced Coal Conversion Process Demonstration (Western SynCoal LLC) ComJEA Large-Scale CFB Combustion Demonstration Project (JEA) Proje

CCT-IISNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) ComDemonstration of Coal Reburning for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) Com

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) ComCement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) ComAdvanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) ComDemonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) ComDemonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Com

Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High-Sulfur-Coal-Fired Com

Boilers (Southern Company Services, Inc.)180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of NOx Emissions from Com

Coal-Fired Boilers (Southern Company Services, Inc.)

Exhibit C-6

Status of Environmental Monitoring Plans for CCT Projects as of Septembe
C-8 Program Update 2001

Project and Participant StaCCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Company, L.P.) Com10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) ComHealy Clean Coal Project (Alaska Industrial Development and Export Authority) ComFull-Scale Demonstration of Low-NO

x Cell Burner Retrofit (The Babcock & Wilcox Company) Com

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) ComBlast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) ComMcIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) On 

ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Com

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) Com

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) ComIntegrated Dry NOx/SO2 Emissions Control System (Public Service Company of Colorado) Com

Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Com

CCT-IVMicronized Coal Reburning Demonstration for NOx Control (New York State Electric & Gas Corporation) Com

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) ComPiñon Pine IGCC Power Project (Sierra Pacific Power Company) ComWabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Com

Pulse Combustor Design Qualification Test (ThermoChem, Inc.) Com

CCT-VClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) ComClean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management Company LLC) ProjKentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) To McIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) On 

Exhibit C-6 (continued)

Status of Environmental Monitoring Plans for CCT Projects as of Septembe
Coal Processing forClean Fuels

Application Category Participant Project 

Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project Kentucky Pioneer Energy, LLC Kentucky Pioneer Energy IGCC Demonstration Project 

Lakeland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project 

The Ohio Power Company Tidd PFBC Demonstration Project Sierra Pacific Power Company Piñon Pine IGCC Power Project 

Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Projec

Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project 

Project Joint VentureJEA JEA Large-Scale CFB Combustion Demonstration Project 

ABB Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption 

The Babcock & Wilcox Company Demonstration of Coal Reburning for Cyclone Boiler NOx Cont

The Babcock & Wilcox Company SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Projec

New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project Public Service Company of Colorado Integrated Dry NOx/SO2 Emissions Control System 

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a WalSouthern Company Services, Inc. Demonstration of Innovative Applications of Technology for th

CT-121 FGD Process

Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Com

Techniques for the Reduction of NOx Emissions from Coal-Fire

ENCOAL Corporation ENCOAL® Mild Coal Gasification Project CPICORTM Management Company LLC Clean Power from Integrated Coal/Ore Reduction (CPICORTM) 

Exhibit C-7

Status of CCT Projects Monitoring Hazardous Air Pollutants as of Septemb

Advanced ElectricPower GenerationIndustrialApplicationsEnvironmentalControl Devices
C-10 Program Update 2001

and provided the raw data from the emissions testing.Emissions data were collected from 16 power plants,representing nine process configurations, operated byeight different utilities; several power plants were sitesfor 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 currently inprogress is sampling at other sites, including the CCTProgram’s Wabash River IGCC project. Further, theresults from the first phase will be used to determinewhat configuration and coal types require furtherassessment.In October 1996, EPA submitted to Congress aninterim version of its technical assessment of toxic airpollutant emissions from power plants, Study ofHazardous Air Pollutant Emissions from ElectricUtility Steam Generating Units, Interim Final Report.EPA plans to continue evaluating the potentialexposures and potential public health concerns frommercury emissions from utilities. In addition, theagency will evaluate information on various potentialcontrol technologies for mercury. If EPA decides thatHAPs pose a risk, then the agency must propose airtoxic emissions controls by November 15, 1998, andmake them final two years later.Following up on the October 1996 report to Congress,a report was released by EPA focusing on Mercuryemissions. The December 1997 report, MercuryStudy Report to Congress, estimates that U.S. industrial sources were responsible for releasing 158 tonsof Mercury into the atmosphere in 1994 and 1995.The EPA estimates that 87 percent of those emissionsoriginate from combustion sources such as waste andfossil fuel facilities, 10 percent from manufacturingfacilities, 2 percent from area sources, and 1 percentfrom other sources. The EPA also identified four

specific categories that account for about 80 percentof the total anthropogenic sources: coal-fired powerplants, 33 percent; municipal waste incinerators, 18percent; commercial and industrial boilers, 18 percent;and medical waste incinerators, 10 percent. The nextstep for EPA is to assess the need for enhancedresearch on health effects and on new pollutioncontrol technologies, community “right-to-know”approaches, and regulatory actions.Most recently, the National Academy of Sciencesreleased a report in June 2000 reinforcing the importance, especially for women in their child-bearingyears, of heeding consumption advisories on noncommercial fish to avoid methylmercury. As a result ofthe study, EPA has announced it will regulate mercuryemissions from power plants. The EnvironmentalProtection Agency will propose regulations byDecember 2003.The results of the HAPs program have significantlymitigated concerns about HAPs emission from coalfired generation and focused attention on but a fewflue gas constituents. The results have the potentialto make the forthcoming EPA regulations less strict,which could avoid unnecessary control costs and thussave consumers money on electricity bills.
 Project Fact Sheets 2001 D-1

x D. Project Contacts

s

btaining further infor

gram and PPII demon

 name, title, phone

ddress, and e-mail

oject participant contact

re the project partici

company, a partner

ng address listed is that

on, the names, phone

for contact persons at

ional Energy Technol

ovided.

CCT ProgramEnvironmental ControlDevicesSO2 Control Technologies10-MWe Demonstration of Gas SuspensionAbsorptionParticipant:AirPol, Inc.Contacts:Niels H. Kastrup

(281) 539-3400(281) 539-3411 (fax)nhk@flsmiljo.comFLS miljo, Inc.100 Glenborough Drive, 5th FloorHouston, TX 77067

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Confined Zone Dispersion Flue GasDesulfurization DemonstrationParticipant:Bechtel CorporationContacts:Joseph T. Newman, Project Manager

(415) 768-1189(415) 768-3535 (fax)Bechtel CorporationP.O. Box 193965San Francisco, CA 94119-3965

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

LIFAC Sorbent Injection DesulfurizationDemonstration ProjectParticipant:LIFAC-North AmericaContacts:Darryl Brogan

(412) 497-2144(412) 497-2212 (fax)Kaiser Engineers, Inc.Gateway View Plaza1600 West Carson StreetPittsburgh, PA 15219-1031

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov
D-2 Project Fact Sheets 2001

Advanced Flue Gas Desulfurization DemonstrationProjectParticipant:Pure Air on the Lake, L.P.Contacts:Tim Roth

(610) 481-6257(610) 706-7018 (fax)rothtj@apci.comPure Air on the Lake, L.P.c/o Air Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Demonstration of Innovative Applications ofTechnology for the CT-121 FGD ProcessParticipant:Southern Company Services, Inc.Contacts:David P. Burford, Project Manager

(205) 257-6329(205) 257-7161 (fax)dpburfor@southernco.comSouthern CompanyP.O. Box 2641 / bin no. 13N-8060Birmingham, AL 35291

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

NO

x Control Technologies

Demonstration of Coal Reburning for CycloneBoiler NO

x

 Control

Participant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)dot.k.johnson@mcdermott.comMcDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601

John C. McDowell, NETL, (412) 386-6175

mcdowell@netl.doe.gov

Full-Scale Demonstration of Low-NO

x

 CellBurner

RetrofitParticipant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)dot.k.johnson@mcdermott.comMcDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Evaluation of Gas RebBurners on a Wall-FirParticipant:Energy and EnvironmeContacts:Blair A. Folsom, Senio

(949) 859-8851, ex(949) 859-3194 (fablair.folsom@ps.geGE Energy and EnCorporation18 MasonIrvine, CA 92618

Jerry L. Hebb, NETL, (

hebb@netl.doe.gov

Micronized Coal RebuNO

x

 Control

Participant:New York State ElectriContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fajharvilla@nyseg.coNew York State ElCorporate Drive—P.O. Box 5224Binghamton, NY 1

James U. Watts, NETL

james.watts@netl.d
Demonstration of Selective Catalytic ReductionTechnology for the Control of NOx Emissions from

High-Sulfur, Coal-Fired BoilersParticipant:Southern Company Services, Inc.Contacts:Larry Monroe

(205) 257-7772(205) 257-5367 (fax)lsmonroe@southernco.comSouthern Company Services, Inc.Mail Stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Demonstration of Advanced CombustionTechniques for a Wall-Fired BoilerParticipant:Southern Company Services, Inc.Contacts:John N. Sorge, Research Engineer

(205) 257-7426(205) 257-5367 (fax)jnsorge@southernco.comSouthern Company Services, Inc.Mail Stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195

James R. Longanbach, NETL, (304) 285-4659

jlonga@netl.doe.gov

180-MWe Demonstration of AdvancedTangentially Fired Combustion Techniques for theReduction of NOx Emissions from Coal-Fired

BoilersParticipant:Southern Company Services, Inc.Contacts:Larry Monroe

(205) 257-7772(205) 257-5367 (fax)lsmonroe@southernco.comSouthern Company Services, Inc.Mail Stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Combined SO2 /NOx Control TechnologiesSNOXTM Flue Gas Cleaning DemonstrationProjectParticipant:ABB Environmental SystemsContacts:Paul Yosick, Project Manager

(865) 694-5300 (fax)(865) 694-5213 (fax)Alstom Power, Inc.1409 Center Point BoulevardKnoxville, TN 37932

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

LIMB DemonstratioCoolside DemonstraParticipant:The Babcock & WilcoContacts:Paul Nolan

(330) 860-1074(330) 860-2045 (psnolan@babcocThe Babcock & W20 South Van BuP.O. Box 351Barberton, OH 44

John C. McDowell, N

mcdowell@netl.d

SOx-NOx-Rox BoxTM Demonstration ProjeParticipant:The Babcock & WilcoContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (dot.k.johnson@mMcDermott Tech1562 Beeson StreAlliance, OH 446

James U. Watts, NET

james.watts@netl
D-4 Project Fact Sheets 2001

Enhancing the Use of Coals by Gas Reburning andSorbent InjectionParticipant:Energy and Environmental Research CorporationContacts:Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140(949) 859-3194 (fax)blair.folsom@ps.ge.comGeneral Electric Energy and EnvironmentalResearch Corporation18 MasonIrvine, CA 92618

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

Milliken Clean Coal Technology DemonstrationProjectParticipant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)jharvilla@nyseg.comNew York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Integrated Dry NOx/SO2 Emissions Control System

Participant:Public Service Company of ColoradoContacts:Terry Hunt, Production Engineer

(720) 497-2129(720) 497-2122 (fax)terry.hunt@xcelenergy.comXcel Energy4653 Table Mountain DriveGolden, CO 80403

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

CCT PrograElectric PowFluidized-Bed ComMcIntosh Unit 4A PCParticipant:City of Lakeland, LakeContacts:Alfred M. Dodd, Projec

(863) 834-6461(863) 834-6488 (faal.dodd@lakelandgLakeland Electric501 E. Lemon StreLakeland, FL 3380

George Lynch, DOE/H

george.lynch@hq.d

Donald L. Bonk, NETL

dbonk@netl.doe.go
McIntosh Unit 4B Topped PCFB DemonstrationProjectParticipant:City of Lakeland, Lakeland ElectricContacts:Alfred M. Dodd, Project Director

(863) 834-6461(863) 834-6488 (fax)al.dodd@lakelandgov.netLakeland Electric501 E. Lemon StreetLakeland, 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 DemonstrationProjectParticipant:JEAContacts:Joey Duncan

(904) 714-4831(904) 714-4895 (fax)JEA4377 Heckscher Drive, NSRPCOJacksonville, FL 32226

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 ProjectParticipant:American Electric Power Service CorporationContacts:Michael J. Mudd

(614) 223-1585(614) 223-1292 (fax)mjmudd@aep.comAmerican Electric Power1 Riverside PlazaColumbus, OH 43215

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, NETL, (304) 285-4784

donald.geiling@netl.doe.gov

Nucla CFB Demonstration ProjectParticipant:Tri-State Generation and TransmissionAssociation, Inc.Contacts:Joe Egloff

(303) 452-6111(303) 254-6066 (fax)Tri-State Generation and Transmission Association, Inc.P.O. Box 33695Denver, 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 GasificKentucky Pioneer IGParticipant:Kentucky Pioneer EneContacts:H. H. Graves, Preside

(513) 621-0077(513) 621-5947 (hhgraves@globalKentucky Pionee312 Walnut StreeCincinnati, OH 4

George Lynch, DOE/H

george.lynch@hq

James U. Watts, NET

james.watts@netl

Piñon Pine IGCC PoParticipant:Sierra Pacific Power CContacts:Jeffrey W. Hill, Direc

(775) 834-5890(775) 834-4569 (jhill@sppc.comSierra Pacific PowP.O. Box 10100Reno, NV 89520

George Lynch, DOE/H

george.lynch@hq

Donald W. Geiling, N

donald.geiling@n

Web Site:www.sierrapacific.com
D-6 Project Fact Sheets 2001

Tampa Electric Integrated Gasification CombinedCycle ProjectParticipant:Tampa Electric CompanyContacts:Mark Hornick, General Manager, Polk Power Station

(813) 228-1111, ext. 39988(863) 428-5927 (fax)TECO EnergyP.O. Box 111Tampa, 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:www.teco.net/teco/TEKPlkPwrStn.htmlWabash River Coal Gasification RepoweringProjectParticipant:Wabash River Coal Gasification Repowering ProjectJoint VentureContacts:Phil Amick, VP for Commercial Development

(713) 374-7252(713) 374-7278 (fax)pramick@globalenergyinc.comGlobal Energy, Inc.1000 Louisiana St., Suite 3800Houston, 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

Advanced Combustion/Heat EnginesHealy Clean Coal ProjectParticipant:Alaska Industrial Development and Export AuthorityContacts:Arthur E. Copoulos, Project Manager II

(907) 269-3029(907) 269-3044 (fax)acopoulos@aidea.orgAlaska Industrial Development and Export Authority801 West Northern Lights BoulevardAnchorage, AK 99503

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 ProjectParticipant:Arthur D. Little, Inc.Contacts:Robert P. Wilson, Vice President

(617) 498-5806(617) 498-7017 (fax)Arthur D. Little, Inc.Building 15, Room 25925 Acorn ParkCambridge, 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

CCT PrograProcessing fIndirect LiquefactiCommercial-Scale DePhase Methanol (LPMParticipant:Air Products Liquid PhContacts:Edward C. Heydorn, Pr

(610) 481-7099(610) 481-2247 (faheydorec@apci.coAir Products and C7201 Hamilton BoAllentown, PA 181

Edward Schmetz, DOE

edward.schmetz@h

Robert M. Kornosky, N

robert.kornosky@n
Coal Preparation TechnologiesDevelopment of the Coal Quality ExpertTMParticipants:ABB Combustion Engineering, Inc. and CQ Inc.Contacts:Clark D. Harrison, President

(724) 479-3503(724) 479-4181 (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

Mild GasificationENCOAL® Mild Coal Gasification ProjectParticipant:ENCOAL CorporationContacts:Jim Mahler

(858) 551-1090(858) 551-0247 (fax)jmahler@sgiinternational.comSGI International1200 Prospect, Suite 325La Jolla, CA 92037

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Douglas M. Jewell, NETL, (304) 285-4720

doug.jewell@netl.doe.gov

Advanced Coal Conversion Process DemonstrationParticipant:Western SynCoal LLCContacts:Ray W. Sheldon, P.E., General Manager

(406) 252-2277, ext. 502(406) 252-2090 (fax)Westmoreland Mining LLCP.O. Box 7137Billings, MT 59103-7137

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

CCT ProgrApplicationBlast Furnace GranuDemonstration ProjeParticipant:Bethlehem Steel CorpContacts:Robert W. Bouman, M

(610) 694-6792(610) 694-2981 (Bethlehem Steel Building C, Room Homer Research Mountain Top CaBethlehem, PA 1

Douglas Archer, DOE

douglas.archer@h

Leo E. Makovsky, NE

makovsky@netl.d
D-8 Project Fact Sheets 2001

Clean Power from Integrated Coal/Ore Reduction(CPICORTM)Participant:CPICORTM Management Company, LLCContacts:Les Jones

(801) 227-9273(801) 227-9198 (fax)ljones@geneva.comCPICORTM Management Company, LLCP.O. Box 2500Provo, 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

Advanced Cyclone Combustor with InternalSulfur, Nitrogen, and Ash ControlParticipant:Coal Tech CorporationContacts:Bert Zauderer, President

(610) 667-0442(610) 667-0576 (fax)coaltechbz@compuserve.comCoal Tech CorporationP.O. Box 154Merion 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 ScrubberParticipant:Passamaquoddy TribeContacts:Thomas N. Tureen, Project Manager

(207) 773-7166(207) 773-8832 (fax)tntureen@gwi.netPassamaquoddy Technology, L.P.1 Monument Way, Suite 200Portland, ME 04101

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

John C. McDowell, NETL, (412) 386-6175

mcdowell@netl.doe.gov

Pulse Combustor Design Qualification TestParticipant:ThermoChem, Inc.Contacts:Lee Rockvam, Project Manager

(410) 354-9890, ext. 43(410) 354-9894 (fax)lrockvam@tchem.netThermoChem, Inc.6001 Chemical RoadBaltimore, MD 21226

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Leo E. Makovsky, NETL, (412) 386-5814

leo.makovsky@netl.doe.gov

PPII ProjectCombustion Initiative Effective NO

x

 Reducti

Participant:Alliant Energy CorporaContacts:Gary Walling

(608) 250-6802(608) 250-6832 (faAlliant Energy Cor222 West WashingMadison, WI 5370

Soung-Sik S. Kim, NET

Soung-sik.kim@ne

Development of HybriNO

x

 Control for Orion 

Participant:Arthur D. Little, Inc.Contacts:Howard B. Mason

(408) 517-1570(408) 517-1551 (famason.howard@adArthur D. Little, In20 Acorn ParkCambridge, MA 0

James R. Longanbach, 

james.longanbach@
Greenidge Multi-Pollutant Control ProjectParticipant:CONSOL, Inc.Contacts:Bob Statnick, Project Manager

(412) 854-6758(412) 854-6613bobstatnick@consolenergy.comCONSOL Energy, Inc.4000 Brownsville RoadSouth Park, PA 15129-9566

Ronald L. Heavner, NETL (412) 386-5178

ronald.heavner@netl.doe.gov

Achieving NSPS Emission Standards ThroughIntegration of Low-NOx Burners with anOptimization Plan for Boiler CombustionParticipant:Sunflower Electric Power CorporationContacts:Wayne F. Penrod

(785) 628-2845(785) 623-3395 (fax)Sunflower Electric Power Corporation301 West 13th StreetHays, KS 67601

Leo E. Makovsky, NETL, (412) 386-5814

leo.makovsky@netl.doe.gov

Demonstration of a Full-Scale Retrofit of theAdvanced Hybrid Particulate CollectorParticipant:Otter Tail Power CompanyContacts:Bill Swanson

(605) 862-6300(605) 862-8539 (fax)wswanson@otpco.comOtter Tail Power Company48450 144th StreetBig Stone City, SD 57216

John M. Rockey, NETL, (304) 285-4711

john.rocky@netl.doe.gov

Polk Power Station ImprovementsParticipant:Tampa Electric CompanyContacts:Ronald L. Boehm, Manager

(813) 641-5214(813) 641-5281 (fax)rlboehm@tecoenergy.comTECO EnergyP.O. Box 111Tampa, FL 33601

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Big Bend Power StatSootblower OptimizaParticipant:Tampa Electric CompContacts:Ronald L. Boehm, M

(813) 641-5214(813) 641-5281 rlboehm@tecoenTECO EnergyP.O. Box 111Tampa, FL 336

James U. Watts, NET

james.watts@netl

Commercial DemonsAggregate ProcessinDryer AshParticipant:Universal AggregatesContacts:Roy O. Scandrol

(412) 854-6643(412) 854-6521 (royscandrol@uniUniversal AggregSuite 3004000 Brownsville P.O. Box 300South Park, PA 1

Donald W. Geiling, N

donald.geiling@n

Web Site:

www.universalag
D-10 Project Fact Sheets 2001
Appendix E. Acronyms, Abbreviations, aSymbols¢ cent°C degrees Celsius°F degrees Fahrenheit$ dollars (U.S.)

$/kw dollars per kilowatt$/ton dollars per ton% percentÆ registered trademarkô trademarkABB CE ABB Combustion Engineering, Inc.ABB ES ABB Environmental SystemsACFB atmospheric circulating fluidized-bedADL Arthur D. Little, Inc.AEO2001 Annual Energy Outlook 2001AER2000 Annual Energy Review 2000AFBC atmospheric fluidized-bed

combustion

AFGD advanced flue gas desulfurizationAIDEA Alaska Industrial Development and

Export Authority

AOFA advanced overfire airAPEC Asia Pacific Economic CooperationAPF advanced particulate filterARIL Advanced Retractable Injection

Lances

ASME American Society of Mechanical

Engineers

Assín. AssociationATCF after tax cash flowsatm atmosphere(s)

avg. averageBFGCI blast furnace granular-coal injectionBG British GasBtu British thermal unit(s)Btu/kWh British thermal units per kilowatthourB&W The Babcock & Wilcox CompanyCAAA Clean Air Act Amendments of 1990CaCO3 calcium carbonate (calcitic

limestone)

CaO calcium oxide (lime)Ca(OH)2 calcium hydroxide (calcitic hydrated

lime)

Ca(OH)2ïMgO dolomitic hydrated lime

Ca/N calcium-to-nitrogenCAPI Clean Air Power InitiativeCa/S calcium-to-sulfurCaSO3 calcium sulfite

CaSO4 calcium sulfateCCOFA close-coupled overfire airCCT clean coal technologyCCTDP Clean Coal Technology

Demonstration Program

CCT I First CCT Program solicitationCCT II Second CCT Program solicitationCCT III Third CCT Program solicitationCCT IV Fourth CCT Program solicitationCCT V Fifth CCT Program solicitationCCT Program Clean Coal Technology

Demonstration Program

CD-ROM ComCDLÆ Coal

CenPEEP Cent

Envi

CEQ CounCFB circuCFD ComC/H carboCKD cemeCO carboCO2 carboCOP ConfCT-121 ChiyCQEô Coal CQIMô Coal CX categCZD confDER discrDME dimeDOE U.S. DOE/HQ U.S. 

Head

DSE dust DSI dry sEA envirEER Ener

Corp

EERC Ener

Cent

EFCC exter
E-2 Program Update 2001

EIA Energy Information AdministrationEIS environmental impact statementEIV Environmental Information VolumeEMP environmental monitoring planEPA U.S. Environmental Protection

Agency

EPAct Energy Policy Act of 1992EPDC Japan’s Electric Power Development

Company

EPRI Electric Power Research InstituteESP electrostatic precipitatorEWG exempt wholesale generatorext. extensionFBC fluidized-bed combustionFCCC Framework Convention on Climate

Change

FE Office of Fossil EnergyFeO iron oxideFe2S pyritic sulfur

FERC Federal Energy Regulatory

Commission

FETC Federal Energy Technology Center

(now NETL)

FGD flue gas desulfurizationFONSI finding of no significant impactFRP fiberglass-reinforced plasticft, ft2, ft3 foot (feet), square feet, cubic feet

FY fiscal yeargal. gallon(s)gal/ft3 gallons per cubic footGB gigabyte(s)GE General ElectricGHG greenhouse gasesGNOCIS Generic NO

x Control Intelligent

System

gpm gallons per minute

gr grainsGR gas reburningGR-LNB gas reburning and low-NOx burnerGR-SI gas reburning and sorbent injectionGSA gas suspension absorptionGVEA Golden Valley Electric AssociationGW gigawatt(s)GWe gigawatt(s)-electricH elemental hydrogenH2 molecular hydrogen

H2S hydrogen sulfide

H2SO4 sulfuric acid

HAP hazardous air pollutantHCl hydrogen chlorideHF hydrogen fluorideHGPFS hot gas particulate filter systemHHV higher heating valuehr. hour(s)HRSG heat recovery steam generatorID Induced DraftIEA International Energy AgencyIEO2001 International Energy Outlook 2001IGCC integrated gasification combinedcycleIGFC integrated gasification fuel cellin, in2, in3 inch(es), square inch(es), cubic

inch(es)

JBR Jet Bubbling Reactor®KCl potassium chlorideK2SO4 potassium sulfatekW kilowatt(s)kWh kilowatt-hour(s)LAC Latin America and the Carribbeanlb. pound(s)L/G liquid-to-gas ratioLHV lower heating value

LIMB limest

burner

LNB low-N

LNCB® low-NLNCFS Low-NLOI loss-oLPMEOHTM Liquid LRCWF low-raLSDE LaborLSFO limestMASB multi-MB megabMCFC molten MCR MaximMDEA methyMgCO3 magneMgO magneMHz megahmills/kWh mills pmin. minutemo. monthMSW municMTCI Manuf

Conve

MTF memoMW megawMWe megawMWt megawN elemeN2 molecn.d. not daN/A not apNa/Ca sodiumNa2/S sodiumNaOH sodium Na2CO3 sodium 
NAAQS National Ambient Air Quality

Standards

NEDO New Energy Development

Organization

NEPA National Environmental Policy ActNETL National Energy Technology

Laboratory (formerly FETC)

NH3 ammoniaNm3 Normal cubic meterNO2 nitrogen dioxideNOPR Notice of Proposed RulemakingNO

x nitrogen oxides

NSPS New Source Performance StandardsNSR normalized stoichiometric ratioNTHM net tons of hot metalNTIS National Technical Information

Service

NTPC National Thermal Power CorporationNYSEG New York State Electric & Gas

Corporation

O elemental oxygenO2 molecular oxygenO&M operation and maintenanceOC&PS Office of Coal & Power SystemsOTAG Ozone Transport Assessment GroupOTC Ozone Transport CommissionPASS Pilot Air Stabilization SystemPC personal computerPCAST Presidential Committee of Advisors

on Science and Technology

PCFB pressurized circulating fluidized-bedPDF® Process-Derived Fuel®PEIA programmatic environmental impact

assessment

PEIS programmatic environmental impact

statement

PEOATM Plant Emission Optimization

AdvisorTM

PENELEC Pennsylvania Electric CompanyPEP progress evaluation planPFBC pressurized fluidized-bed

combustion

PJBH pulse jet baghousePM particulate matterPM10 particulate matter less than 10

microns in diameter

PM2.5 particulate matter less than 2.5

microns in diameter

PON program opportunity noticePRB Powder River Basinppm parts per million (mass)ppmv parts per million by volumePSCC Public Service Company of ColoradoPSD Prevention of Significant

Deterioration

psi pound(s) per square inchpsia pound(s) per square inch absolutepsig pound(s) per square inch gaugePUHCA Public Utility Holding Company Act

of 1935

PURPA Public Utility Regulatory Policies

Act of 1978

QF qualifying facilityRAM random access memoryR&D research and developmentRD&D research, development, and

demonstration

RDF refuse derived fuelREA Rural Electrification AdministrationRP&L Richmond Power & LightROD Record of Decision

ROM run-orpm revoRUS RuraS sulfuSBIR Smascf standscfm standSCR selecSCS SoutSDA spray SFC SyntS-H-U SaarSI sorbeSIP state SM serviSNCR selecSNRBTM SO

x

-

SO2 sulfuSO3 sulfustd ft3 standSOFA sepaSTTR Sma

Prog

SVGA supeTAGTM TechTCLP toxic

proc

TVA TennUAF UnivUARG UtiliUBCL unbuU.K. UnitUNESCO Unit

Scien

URL Unif
E-4 Program Update 2001

U.S. United StatesUSAID U.S. Agency for International

Development

V·I voltage current productVFB vibrating fluidized bedVOC volatile organic compoundw.c. water column

WDNR Wisconsin Department of Natural

Resources

WES wastewater evaporation systemW.G. water gageWLFO wet limestone, forced oxidationwt. weightyr. year(s)

State AbbreviationsAK AlaskaAL AlabamaAR ArkansasAZ ArizonaCA CaliforniaCO ColoradoCT ConnecticutDC District of ColumbiaDE DelawareFL FloridaGA GeorgiaHI HawaiiIA IowaID IdahoIL IllinoisIN Indiana

KS KansasKY KentuckyLA Louisiana

MA MassachusettsMD MarylandME MaineMI MichiganMN MinnesotaMO MissouriMS MississippiMT MontanaNC North CarolinaND North DakotaNE NebraskaNH New HampshireNJ New JerseyNM New MexicoNV NevadaNY New YorkOH OhioOK OklahomaOR OregonPA PennsylvaniaPR Puerto RicoRI Rhode IslandSC South CarolinaSD South DakotaTN TennesseeTX TexasUT UtahVA VirginiaVI Virgin IslandsVT VermontWA WashingtonWI Wisconsin

WV West VWY WyomOtherSome companies have acorporate names. The foreflect the former name BG/L British JEA JacksoKRW Kellog
Index of CCT Projects and ParticipantsSymbols10-MWe Demonstration of Gas Suspension

Absorption ES-8, ES-12, ES-22, 2-6, 3-8,3-10, 4-6, 5-3, 5-15, 5-17, 5-22, B-3, B-5,C-3, C-8, C-9, D-1

180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reductionof NOx Emissions from Coal-Fired Biolers

ES-9, ES-13, ES-22, 2-6, 3-8, 4-7, 5-6, 5-15,5-18, 5-68, B-3, B-4, C-3, C-7, C-9, D-3

AABB Combustion Engineering, Inc. ES-13,

ES-18, ES-23, ES-24, 2-6, 3-10, 4-5, 4-8,4-9, 4-12, 4-13, 4-15, 5-9, 5-16, 5-17, 5-68,5-142, B-2, B-3, B-5, C-3, C-4, C-7, D-7, E-1

ABB Environmental Systems ES-10, ES-13,

ES-22, 2-6, 4-9, 5-15, 5-17, 5-74, B-5, C-3,C-7, C-9, D-3, E-1

ACFB Repowering B-2Achieving New Source Performance Standards

Emission Standards Through Integration of LowNOx Burners with an Optimization Plan for Boiler

Combustion ES-25, 6-4, 6-5, 6-6, 6-16, D-9

Advanced Coal Conversion Process

Demonstration ES-1, ES-2, ES-18, ES-19,ES-23, 2-6, 3-9, 4-1, 4-13, 5-12, 5-16, 5-18,5-150, B-2, B-3, B-6, C-4, C-7, D-7

Advanced Cyclone Combustor with Internal Sulfur,

Nitrogen, and Ash Control ES-20, ES-23,2-6, 3-9, 4-14, 5-13, 5-16, 5-17, 5-162, B-1,B-3, C-3, C-7, D-8

Advanced Flue Gas Desulfurization Demonstration

Project ES-8, ES-12, ES-22, ES-24, 2-6,3-8, 3-10, 4-6, 4-15, 5-3, 5-15, 5-18, 5-34,B-2, B-5, C-4, C-7, C-9, D-2

Advanced Slagging Coal Combustor Utility

Demonstration Project B-2, B-3

Air Products and Chemicals, Inc. 5-34, 5-118,

5-140, B-4

Air Products Liquid Phase Conversion Company,

L.P. ES-19, ES-23, 2-6, 4-12, 4-13, 5-16,5-17, 5-140, B-4, C-4, C-8, D-6

AirPol, Inc. ES-8, ES-12, ES-22, 2-6, 3-10, 4-5,

4-6, 5-15, 5-17, 5-22, 5-25, B-3, B-5, C-3,C-8, C-9, D-1

Alaska Industrial Development and Export

Authority ES-16, ES-23, 2-6, 4-11, 5-16,5-17, 5-134, B-3, C-5, C-8, D-6, E-1

Alliant Energy Corporation ES-25, 6-3, 6-4, 6-5,

6-6, 6-8, D-8

American Electric Power Service Corporation D-5Appalachian IGCC Demonstration Project B-2Appalachian Power Company B-2Arthur D. Little, Inc. ES-15, ES-23, ES-25, 2-7,

5-16, 5-17, 5-132, 6-3, 6-4, 6-5, 6-6, 6-10,B-4, B-5, C-4, C-8, C-9, D-6, D-8, E-1

Arvah B. Hopkins Circulating Fluidized-Bed

Repowering Project B-3

BBabcock & Wilcox Company, The ES-9, ES-10,

ES-12, ES-13, ES-16, ES-22, ES-24, 2-6,3-10, 4-11, 5-15, 5-17, 5-48, 5-52, 5-78,5-81, 5-82, 5-94, 5-106, 5-134, 5-142, B-1,B-2, B-3, B-4, B-5, C-3, C-4, C-7, C-8,C-9, D-2, D-3, E-1

Bechtel Corporation 

4-5, 4-6, 5-15, 5B-4, C-3, C-8, D

Bechtel Development Bethlehem Steel Corpo

4-12, 4-14, 5-16B-4, B-6, C-3, C

Big Bend Power Statio

Optimization E

Blast Furnace Granula

Demonstration Pr3-9, 4-14, 5-13, C-4, C-8, D-7

CCalvert City AdvanceCamden Clean Energy Cement Kiln Flue Gas 

ES-20, ES-23, 35-166, B-2, B-4, 

Centerior Energy CorpClean Coal CombinedClean Coal Diesel Dem

2-7, 2-12, 3-9, 45-132, B-4, B-5, 

Clean Energy IGCC DClean Energy Partners 

5-117, B-4

Clean Power CogenerClean Power from Inte

(CPICORô) ES5-16, 5-17, 5-156D-8
Index-2 Program Update 2001

Coal Tech Corporation ES-20, ES-23, 2-6, 4-14,

5-16, 5-17, 5-162, B-1, B-3, C-3, C-7, D-8

Coal Waste Recovery Advanced Technology

Demonstration B-2

Colorado-Ute Electric Association, Inc. 5-113,

B-2, B-3, C-3, C-7

Combustion Engineering IGCC Repowering

Project B-3, B-5, C-4

Combustion Engineering, Inc B-2Combustion Initiative for Innovative Cost-Effective

NOx Reduction ES-25, 6-4, 6-5, 6-6, 6-8, D-8

Commercial Demonstration of the Manufactured

Aggregate Processing Technology UtilizingSpray Dryer Ash ES-25, 6-4, 6-5, 6-6,6-22, D-9

Commercial Demonstration of the NOXSO SO2/NOx

Removal Flue Gas Cleanup System B-3,B-4, B-6, C-4

Commercial-Scale Demonsatration of the Liquid Phase

Methanol (LPMEOHTM) ES-19, ES-23, 2-6,3-9, 4-13, 5-12, 5-16, 5-17, 5-140, B-4, C-4,C-8, D-6

Confined Zone Dispersion Flue Gas

Desulfurization ES-8, ES-12, ES-22, 2-7,3-8, 4-6, 5-3, 5-15, 5-17, 5-26, B-3, B-4,C-3, C-8, D-1

CONSOL Energy, Inc. ES-25, 6-3, 6-4, 6-5, 6-6,

6-12, 6-22, D-9

Cordero Coal-Upgrading Demonstration Project B-4Cordero Mining Company B-4COREX Ironmaking Demonstration Project B-2CPICORTM Management Company LLC ES-23,

2-7, 4-12, 5-16, 5-17, 5-156, B-4, B-5, C-5,C-8, C-9, D-8

CQ Inc. ES-18, ES-19, ES-23, ES-24, 2-6, 3-10,

4-12, 4-13, 4-15, 5-9, 5-16, 5-17, 5-142,5-144, B-2, B-5, C-3, C-7

Custom Coals International C-4DDairyland Power Cooperative B-3Demonstration of a Full-Scale Retrofit of the

Advanced Hybrid Particulate CollectorTechnology ES-25, 6-4, 6-5, 6-6, 6-14, D-9

Demonstration of Advanced Combustion Techniques

for a Wall-Fired Boiler ES-2, ES-9, ES-13,ES-22, 2-6, 2-12, 3-8, 4-7, 5-6, 5-15, 5-18,5-44, B-2, B-6, C-3, C-7, C-9, D-3

Demonstration of Coal Diesel Technology at Easton

Utilities B-4

Demonstration of Coal Reburning for Cyclone Boiler

NOx Control ES-9, ES-12, ES-22, 1-7, 2-6,3-8, 4-7, 5-6, 5-15, 5-17, 5-48, B-2, B-4,C-4, C-7, C-9, D-2

Demonstration of Innovative Applications of

Technology for the CT-121 FGD ES-8,ES-12, ES-22, ES-24, 2-6, 3-8, 4-6, 4-15,5-3, 5-15, 5-18, 5-38, B-2, B-5, B-6, C-4,C-7, C-9, D-2

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx Emissionsfrom High-Sulfur, Coal-Fired Boilers ES-9,ES-13, ES-22, 3-8, 4-7, 5-6, 5-15, 5-18,5-64, B-2, B-5, C-3, C-7, D-3

Demonstration of the Union Carbide CANSOLVTM

System at the Alcoa Generating corporationWarrick Power Plant B-4

Development of Hybrid FLGR/SNCR/SCR Advanced

NOx Control for Orion Avon Lake Unit 9

ES-25, 6-4, 6-5, 6-6, 6-10, D-8

Development of the Coal Quality ExpertTM

ES-18, ES-19, ES-23, ES-24, 2-6, 3-9, 3-10,4-13, 4-15, 5-12, 5-16, 5-17, 5-142, B-2,B-5, C-3, C-7, D-7

Direct Iron Ore Reducti

Blast Furnace for S

DMEC-1 Limited PartneDuke Energy Corporati

EEastman Kodak CompanENCOAL Corporation 

4-12, 4-13, 5-16, C-4, C-8, C-9, D-

ENCOAL® Mild Coal G

ES-18, ES-19, ES5-16, 5-17, 5-146, D-7

Energy and Environme

Corporation ES-9ES-22, ES-24, 2-64-15, 5-15, 5-17, 5-86, B-1, B-3, BC-8, D-2, D-4, E-

Energy International, InEnhancing the Use of C

Sorbent Injection ES-24, 2-6, 3-8, 45-86, B-1, B-5, B

Evaluation of Gas Rebu

on a Wall-Fired BoES-13, ES-22, ES4-15, 4-17, 5-6, 5C-3, C-8, D-2

FFoster Wheeler Power S

4-10, 4-11, 5-44, 

Four Rivers Energy Mo

5-103, B-4

Four Rivers Energy Part
Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit ES-9, ES-12, ES-22, ES-24, 2-6,3-8, 3-10, 4-7, 4-15, 5-6, 5-15, 5-17, 5-52,B-3, B-5, C-3, C-8, D-2

GGeneral Electric Company B-2Greenidge Multi-Pollutant Control Project ES-25,

6-4, 6-5, 6-6, 6-12, D-9

HHealy Clean Coal Project ES-2, ES-15, ES-16,

ES-23, 2-3, 2-6, 3-9, 4-10, 4-11, 5-10, 5-16,5-17, 5-134, 5-136, B-3, C-5, C-8, D-6

IInnovative Coke Oven Gas Cleaning System for

Retrofit B-2, B-4, C-3, C-4

Integrated Coal Gasification Steam Injection Gas

Turbine Demonstration Plants with Hot GasCleanup B-2

Integrated Dry NOx/SO2 Emissions Control

System ES-11, ES-13, ES-22, 2-7, 3-8, 4-9,5-7, 5-15, 5-18, 5-94, 5-96, 5-97, B-3, B-6,C-3, C-8, C-9, D-4

JJEA ES-22, 2-6, 4-8, 5-15, 5-17, 5-104, 5-105,

B-3, B-5, C-5, C-7, C-9, D-5, E-4

JEA Large-Scale CFB Combustion Demonstration

Project ES-22, 2-6, 2-12, 3-9, 5-10, 5-15,5-17, 5-104, B-3, B-5, C-5, C-7, C-9, D-5

KKentucky Pioneer Energy IGCC Demonstration

Project ES-23, 2-7, 2-12, 3-9, 4-10, 5-10,5-16, 5-17, 5-116, B-4, C-5, C-8, C-9, D-5

Kentucky Pioneer Energy, LLC ES-23, 2-7, 5-16,

5-17, 5-116, 5-117, C-5, C-8, C-9, D-5

LLakeland, City of, Lakeland Electric ES-22, 2-7,

5-15, 5-17, 5-100, 5-102, B-5, C-5, C-8,C-9, D-4, D-5

LIFAC Sorbent Injection Desulfurization

Demonstration Project ES-8, ES-12, ES-22,2-7, 3-8, 4-6, 5-3, 5-15, 5-17, 5-30, B-3,B-5, C-3, C-8, D-1

LIFAC–North America ES-8, ES-12, ES-22, 2-7,

4-5, 4-6, 5-15, 5-17, 5-30, B-3, B-5, C-3,C-8, D-1

LIMB Demonstration Project Extension and Coolside

Demonstration ES-10, ES-13, ES-22, 2-6,3-8, 4-9, 5-7, 5-15, 5-17, 5-78, B-1, B-4,C-3, C-7, D-3

LNS Burner for Cyclone-Fired Boilers Demonstration

Project B-3

MM.W. Kellogg Company, The 5-122, B-2McIntosh Unit 4A PCFB Demonstration Project

ES-22, 2-7, 3-9, 4-10, 5-10, 5-15, 5-17,5-100, B-5, C-5, C-8, D-4

McIntosh Unit 4B Topped PCFB Demonstration

Project ES-22, 2-7, 3-9, 4-10, 5-10, 5-15,5-17, 5-100, 5-102, B-4, B-5, C-5, C-8,C-9, D-5

Micronized Coal Reburning Demonstration for NOx

Control ES-9, ES-12, ES-22, 2-7, 3-8, 4-7,5-6, 5-15, 5-17, 5-60, 5-92, B-3, B-5, B-6,C-2, C-8, D-2

Milliken Clean Coal Technology Demonstration

Project ES-10, ES-13, ES-22, 2-7, 3-8, 4-9,5-7, 5-15, 5-18, 5-90, B-4, B-6, C-4, C-8,C-9, D-4

Minnesota DepartmenMK-Ferguson Compa

NNew York State Electr

ES-9, ES-10, ES4-7, 4-8, 4-9, 5-5-63, 5-90, 5-93C-8, C-9, D-2, D

Nichols CFB RepowerNOXSO Corporation Nucla CFB Demonstra

ES-16, ES-23, 25-110, B-2, B-3, 

OOhio Ontario Clean FuOhio Power Company

ES-23, ES-24, 25-16, 5-18, 5-106

Otisca Fuel DemonstrOtisca Industries, LtdOtter Tail Power Comp

6-14, D-9

PPassamaquoddy Tribe 

5-16, 5-18, 5-166

Pennsylvania Electric 

B-5, C-3, C-4, E

PFBC Utility DemonsPiñon Pine IGCC Pow

ES-14, ES-23, 25-10, 5-16, 5-18C-9, D-5
Index-4 Program Update 2001

Polk Power Station Plant Improvement Project

ES-25, 6-4, 6-5, 6-6, 6-18, D-9

Postcombustion Sorbent Injection Demonstration

Project B-2

Prototype Commercial Coal/Oil Coprocessing

Project B-2, B-3

Public Service Company of Colorado ES-11,

ES-12, ES-13, ES-22, 2-7, 4-7, 4-8, 4-9,5-15, 5-18, 5-56, 5-59, 5-94, B-3, B-6, C-3,C-8, C-9, D-4, E-3

Pulse Combustor Design Qualification Test

ES-1, ES-2, ES-20, ES-23, 2-7, 3-9, 4-1,5-13, 5-16, 5-18, 5-170, B-4, B-5, C-2, C-8,D-8

Pure Air on the Lake, L.P. ES-8, ES-12, ES-22,

ES-24, 1-3, 2-6, 3-10, 4-5, 4-6, 4-15, 5-2,5-4, 5-15, 5-18, 5-34, 5-37, B-2, B-5, C-4,C-7, C-9, D-2

SSelf-Scrubbing CoalTM: An Integrated Approach to

Clean Air 1-6, B-4, B-6, C-4

Sierra Pacific Power Company ES-14, ES-23,

2-7, 4-10, 4-11, 5-16, 5-18, 5-122, B-4, B-6,C-5, C-8, C-9, D-5

SNOXTM Flue Gas Cleaning Demonstration

Project ES-10, ES-13, ES-22, 2-6, 3-8, 4-9,5-7, 5-15, 5-17, 5-74, B-2, B-5, C-3, C-7,C-9, D-3

Southern Company Services, Inc. ES-8, ES-9,

ES-12, ES-13, ES-22, ES-24, 1-4, 2-6, 4-5,4-6, 4-7, 4-15, 5-15, 5-18, 5-38, 5-44, 5-64,5-68, B-2, B-3, B-4, B-5, B-6, C-3, C-4,C-7, C-9, D-2, D-3, E-3

Southwestern Public Service Company B-3

SOx-NOx-Rox BoxTM Flue Gas Demonstration

Project ES-10, ES-13, ES-22, 2-6, 3-8, 4-8,4-9, 5-7, 5-15, 5-17, 5-82, B-2, B-5, C-3,C-7, C-9, D-3

Sunflower Electric Power Corporation ES-25,

6-4, 6-5, 6-6, 6-16, D-9

TTallahassee, City of B-2, B-3, B-5TAMCO Power Partners B-4Tampa Electric Company ES-14, ES-16, ES-23,

ES-24, ES-25, 1-6, 2-7, 4-11, 4-15, 5-16,5-18, 5-118, 6-4, 6-5, 6-6, 6-18, 6-19, 6-20,B-3, C-5, C-8, C-9, D-6, D-9

Tampa Electric Integrated Gasification CombinedCycle Project ES-1, ES-14, ES-16, ES-23,

ES-24, 2-7, 3-9, 4-1, 4-10, 4-11, 4-15, 5-10,5-16, 5-18, 5-118, 5-120, 5-121, B-3, C-5,C-8, C-9, D-6

Tennessee Valley Authority 5-22, 5-52, A-2,

A-5, A-12, B-3, B-5, E-3

ThermoChem, Inc. ES-20, ES-23, 2-7, 4-14,

5-16, 5-18, 5-170, 5-172, B-4, B-5, C-8, D-8

Tidd PFBC Demonstration Project ES-14,

ES-16, ES-23, ES-24, 2-6, 3-9, 4-11, 4-15,5-10, 5-16, 5-18, 5-106, B-1, B-5, C-3, C-7,C-9, D-5

Toms Creek IGCC Demonstration Project B-4TransAlta Resources Investment Corporation

B-2, B-3, C-3, C-4

Tri-State Generation and Transmission

Association ES-14, ES-16, ES-23, 2-6,3-10, 4-8, 4-11, 5-16, 5-18, 5-110, B-3, C-3,C-7, D-5

TRW, Inc. ES-16, 5-134, B-2, B-3

UUnderground Coal Gas

Project B-2

Union Carbide Chemic

Inc. B-4

United Coal Company Universal Aggregates, L

6-6, 6-22, D-9

WWabash River Coal Gas

Venture ES-15, E4-11, 4-15, 5-16, C-4, C-8, C-9, D-

Wabash River Coal Gas

Project ES-2, ES1-6, 2-7, 3-9, 3-104-17, 5-10, 5-16, B-3, B-6, C-4, C-

Warren Station External

Demonstration B

Weirton Steel CorporatiWestern Energy CompaWestern SynCoal LLC 

2-6, 4-12, 4-13, 5B-3, B-6, C-4, C-

YYork County Energy Pa

Project B-3, C-5

York County Energy Pa

B-5, C-5
Contents

Executive SummarySection 1. Role of the CCT ProgramSection 2. CCT Program ImplementationSection 3. CCT Program Funding and CostsSection 4. CCT Program AccomplishmentsSection 5. CCT Program Projects

SO2 Control Technologies Fact Sheets

NO

x Control Technologies Fact Sheets

Combined SO2/NOx Control Technologies Fact Sheets

Fluidized-Bed Combustion Fact SheetsIntegrated Gasification Combined-Cycle Fact SheetsAdvanced Combustion/Heat Engines Fact SheetsCoal Processing for Clean Fuels Fact SheetsIndustrial Applications Fact Sheets

Section 6. Power Plant Improvement InitiativeAppendix A. Historical Perspective and Legislative HistoryAppendix B. CCT Program HistoryAppendix C. CCT Program Environmental AspectsAppendix D. Project ContactsAppendix E. Acronyms, Abbreviations, and SymbolsIndex of CCT Projects and Participants