Clean Coal Technology Demonstration Program: …/67531/metadc741708/...technologies that produce...

DOE/FE-0444

Clean Coal TechnologyDemonstration Program:Program Update 2001

Includes Power Plant Improvement Initiative Projects

As of September 2001

U.S. Department of EnergyAssistant Secretary for Fossil Energy

Washington, DC 20585July 2002

U.S. Department of EnergyAssistant Secretary for Fossil Energy

Washington, DC 20585

Clean Coal TechnologyDemonstration Program:Program Update 2001

Includes Power Plant Improvement Initiative Projects

As of September 2001

July 2002

DOE/FE-0444

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

Available to DOE and DOE contractors from the Office of Scientific and Technical Information,P.O. Box 62, Oak Ridge, Tennessee 37831; prices available from (615) 576-8401. http://www.osti.gov

Available to the public from the National Technical Information Service, U.S. Department of Commerce,5285 Port Royal Rd., Springfield, Virginia 22161. http://www.ntis.gov

For further information about this publication or related U.S. DOE programs please contact:

Victor K. DerProduct Line DirectorPower SystemsU.S. Department of EnergyFE-22/Germantown Building1000 Independence Ave. S.W.Washington DC 20585-1290(301) 903-2700

Dr. C. Lowell MillerProduct Line DirectorFuels & Industrial SystemsU.S. Department of EnergyFE-24/Germantown Building1000 Independence Ave. S.W.Washington DC 20585-1290(301) 903-9453

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)[email protected]

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

PrefaceThe Clean Coal Technology DemonstrationProgram: Program Update 2001 (ProgramUpdate 2001) not only presents the Clean CoalTechnology Demonstration Program (CCTProgram) and associated progress and accom-plishments, 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 Depart-ment 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 envi-ronmental regulations and competing in a chang-ing 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 commodi-ties, 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 coal-using 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 commercial-scale demonstration of technologies to assure thereliability of the nation’s energy supply fromexisting and new electric coal-based generatingfacilities. The single solicitation required partici-pants 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

In an effort to continue providing the most useful and effective information to the users of the Program Update, the U.S. Department of Energy(DOE) is including the following evaluation form. Please take a few minutes to complete the evaluation and mail your comments to DOE. The resultswill be used to improve the next edition of this document.

On a scale of 1 to 5, with 1 meaning not effective and 5 meaning very effective, please rate each of the chapters by circling the appropriate number. Aspace has been provided to make comments. If you do not use a particular chapter and cannot comment on its effectiveness, please circle zero.

Not Not VeryUsed Effective Effective Comments?

Executive Summary 0 1 2 3 4 5

Section 1. Role of the CCT Program 0 1 2 3 4 5

Section 2. CCT Program Implementation 0 1 2 3 4 5

Section 3. CCT Program Funding and Costs 0 1 2 3 4 5

Section 4. CCT Program Accomplishments 0 1 2 3 4 5

Section 5. CCT Program Projects 0 1 2 3 4 5

Section 6. PPII Initiative 0 1 2 3 4 5

Appendix A. Historical Perspective and Legislative History 0 1 2 3 4 5

Appendix B. CCT Program History 0 1 2 3 4 5

Appendix C. CCT Program Environmental Aspects 0 1 2 3 4 5

Appendix D. Project Contacts 0 1 2 3 4 5

Appendix E. Acronyms, Abbreviations, and Symbols 0 1 2 3 4 5

What do you find is the best and most effective part of the Program Update?

What do you find is the least effective part of the Program Update?

Do you have any other suggestions on how to improve the Program Update?

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Program Update 2001 i

ContentsExecutive Summary Introduction ES-1

Role of the CCT Program ES-2

Program Implementation ES-4

Funding and Costs ES-5

CCT Program Accomplishments ES-6

CCT Projects ES-17

PPII Projects ES-21

Introduction 1-1

CCT Program Evolution 1-2

Environmental Impetus 1-3

SO2 Regulation 1-3

NOx Regulation 1-4

Hazardous Air Pollutants 1-6

Global Climate Change 1-7

Regional Haze 1-7

Solid Waste 1-7

Toxics Release Inventory 1-7

Market Considerations 1-7

Ensuring Sustainable Economic Growth 1-8

Looking to the Future 1-10

Power Plant Improvement Initiative 1-10

Clean Coal Power Initiative 1-10

Vision 21 1-10

Introduction 2-1

Implementation Principles 2-1

Implementation Process 2-2

Commitment to Commercial Realization 2-4

Section 1. Role of the CCT Program

Section 2. CCT Program Implementation

ii Program Update 2001

Solicitation Results 2-5

Future Implementation Direction 2-12

Introduction 3-1

Program Funding 3-1

General Provisions 3-1

Availability of Funding 3-2

Use of Appropriated Funds 3-2

Project Funding, Costs, and Schedules 3-4

Cost-Sharing 3-4

Recovery of Government Outlays (Recoupment) 3-10

Introduction 4-1

Fossil Energy R&D Benefits 4-1

Marketplace Commitment 4-3

Factors Impacting Domestic Commercialization 4-4

Environmental Control Devices 4-4

Advanced Electric Power Generation 4-8

Coal Processing for Clean Fuels 4-11

Industrial Applications 4-11

Awards 4-14

Market Communications—Outreach 4-14

Information Sources 4-14

Publications Issued in FY2001 4-16

Information Access 4-17

Information Dissemination and Feedback 4-17

Conferences and Workshops Held in FY2001 4-18

Trade Mission Activities in FY2001 4-20

Introduction 5-1

Technology Overview 5-2

Section 3. CCT Program Funding and Costs

Section 4. CCT Program Accomplishments

Section 5. CCT Program Projects


(continued)

Program Update 2001 iii


Advanced Electric Power Generation Technology 5-5

Coal Processing for Clean Fuels Technology 5-9

Industrial Applications Technology 5-11

Project Fact Sheets 5-11


SO2 Control Technologies 5-21

NOx Control Technologies 5-43

Combined SO2/NOx Control Technologies 5-73

Advanced Electric Power Generation 5-99

Fluidized-Bed Combustion 5-99

Integrated Gasification Combined-Cycle 5-115

Advanced Combustion/Heat Engines 5-131

Coal Processing for Clean Fuels 5-139

Industrial Applications 5-155

Role of the PPII Program 6-1

Program Implementation 6-1

Introduction 6-1

PPII Solicitation 6-1

Intellectual Property Rights 6-3

Environmental Provisions 6-3

PPII Funding and Costs 6-3

PPII Accomplishments 6-3

PPII Projects 6-3

PPII Fact Sheets 6-7

CCT Historical Perspective A-1

CCT Legislative History A-2

PPII Historical Perspective A-3

PPII 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-1

Selection and Negotiation History B-1

Introduction C-1

The Role of NEPA in the CCT Program C-2

Compliance with NEPA C-2

Categorical Exclusions C-2

Memoranda-to-File C-2

Environmental Assessments C-2

Environmental Impact Statements C-5

NEPA Actions in Progress C-5

Environmental Monitoring C-6

Air Toxics C-6

Project Contacts D-1

CCT Program Environmental Control Devices D-1

CCT Program Advanced Electric Power Generation D-4

CCT Program Coal Processing for Clean Fuels D-6

CCT Program Industrial Applications D-7

PPII Projects D-8

Acronyms, Abbreviations, and Symbols E-1

State Abbreviations E-4

Other E-4

Index Index-1

Appendix E. Acronyms, Abbreviations,and Symbols

Index of Projects and Participants

Appendix C. CCT Program EnvironmentalAspects

Appendix D. Project Contacts

Appendix B. CCT Program History

Program Update 2001 v

ExhibitsCompleted Projects by Application Category ES-6

Summary of Results of Completed Environmental Control Technology Projects ES-8

Commercial Successes—Environmental Control Technologies ES-12

Summary of Results of Completed Advanced Electric Power Generation Projects ES-14

Commercial Successes—Advanced Electric Power Generation Technologies ES-16

Summary of Results of Completed Coal Processing for Clean Fuels Projects ES-18

Commercial Successes—Coal Processing for Clean Fuels Technologies ES-19

Summary of Results of Completed Industrial Application Projects ES-20

Commercial Successes—Industrial Application Technologies ES-20

Project Fact Sheets by Application Category ES-21

Award-Winning CCT Projects ES-23

PPII Technology Characteristics ES-24

Phase I SO2 Compliance Methods 1-3

CAAA NOx Emission Limits 1-4

Comparison of Energy Projections for Electric Generators 1-9

Vision 21 Objectives 1-11

CCT Program Selection Process Summary 2-5

Clean Coal Technology Demonstration Projects by Solicitation 2-6

Geographic Locations of CCT Projects—Environmental Control Devices 2-8

Geographic Locations of CCT Projects—Advanced Electric Power Generation 2-9

Geographic Locations of CCT Projects—Coal Processing for Clean Fuels 2-10

Geographic Locations of CCT Projects—Industrial Applications 2-11

CCT Project Costs and Cost-Sharing 3-1

Relationship between Appropriations and Subprogram Budgets for the CCT Program 3-2

Annual CCT Program Funding by Appropriations and Subprogram Budgets 3-3


Executive Summary



vi Program Update 2001

CCT Financial Projections as of September 30, 2001 3-4

Financial Status of the CCT Program as of September 30, 2001 3-5

CCT Project Schedules by Application Category 3-6

CCT Project Funding by Application Category 3-8

National Research Council Conclusions on Fossil Energy Research 4-2

Commercial Successes—SO2 Control Technology 4-6

Commercial Successes—NOx Control Technology 4-7

Commercial Successes—Combined SO2/NOx Control Technology 4-9

Commercial Successes—Advanced Electric Power Generation 4-12

Commercial Successes—Coal Processing for Clean Fuels 4-13

Commercial Successes—Industrial Applications 4-14

Award-Winning CCT Program Projects 4-15

How to Obtain CCT Program Information 4-16

CCT 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 5-6

CCT Program Combined SO2/NOx Control Technology Characteristics 5-7

CCT Program Advanced Electric Power Generation Technology Characteristics 5-10

CCT Program Coal Processing for Clean Fuels Technology Characteristics 5-12

CCT Program Industrial Applications Technology Characteristics 5-13

Project Fact Sheets by Application Category 5-15

Project Fact Sheets by Participant 5-17

Key to Milestone Charts in Fact Sheets 5-19

Variables and Levels Used in GSA Factorial Testing 5-24

GSA Factorial Testing Results 5-24

Pure Air SO2 Removal Performance 5-36

Estimated Costs for an AFGD System 5-37

Flue Gas Desulfurization Economics 5-37




(continued)

Program Update 2001 vii

Section 5. CCT Program Projects (continued) Operation of CT-121 Scrubber 5-40

SO2 Removal Efficiency 5-40

CT-121 Particulate Capture Performance 5-41

CT-121 Air Toxics Removal 5-41

LOI Performance Test Results 5-46

NOx vs. LOI Tests—All Sensitivities 5-46

Typical Trade-Offs in Boiler Optimization 5-46

Major Elements of GNOCIS 5-47

Coal Reburning Test Results 5-50

Coal Reburning Economics 5-51

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

Reactor Baseline Conditions 5-66

Catalysts Tested 5-66

Average SO2 Oxidation Rate 5-66

SCR Design Criteria 5-67

SCR Economics by Unit Size 5-67

SCR Economics by NOx Removal 5-67

LNCFS™ Configurations 5-70

Concentric Firing Concept 5-70

Unit Performance Impacts Based on Long-Term Testing 5-71

Average Annual NOx Emissions and Percent Reduction 5-71

LIMB SO2 Removal Efficiencies 5-80

LIMB Capital Cost Comparison 5-81

LIMB Annual Levelized Cost Comparison 5-81

Effect of Limestone Grind 5-92

Pressure Drop vs. Countercurrent Headers 5-92

Effect of Bed Temperature on Ca/S Requirement 5-112

Calcium Requirements and Sulfur Retentions for Various Fuels 5-113

Wabash Thermal Performance Summary 5-129

viii Program Update 2001

Wabash River Coal Gasification Repowering Project Production Statistics 5-129

Healy Performance Goals and Demonstration Test Program Results 5-136

Healy SDA Performance Test Results and Performance Guarantees 5-137

ENCOAL Production 5-148

ACCP Annual Production Rates 5-152

ACCP Stack Emissions Survey 5-153

Summary of Emissions and Removal Efficiencies 5-168

Tube Pulse Heater Test — Partial Summary 5-172

Geographic Locations of PPII Projects 6-2

PPII Technology Characteristics 6-4

PPII Project Fact Sheets by Project Name 6-5

PPII Project Fact Sheets by Participant 6-6

Key to Milestone Charts in Fact Sheets 6-6

CCT Program Legislative History A-4

PPII Legislative History A-10

NEPA Reviews Completed as of September 30, 2001 C-1

Memoranda-to-File Completed C-3

Environmental Assessments Completed as of September 30, 2001 C-4

Environmental Impact Statements Completed as of September 30, 2001 C-5

NEPA Reviews in Progress as of September 30, 2001 C-5

Status of Environmental Monitoring Plans for CCT Projects as of September 30, 2001 C-7

Status of CCT Projects Monitoring Hazardous Air Pollutants as of September 30, 2001 C-9

Appendix A. Historical Perspective and

Legislative History

Section 5. CCT Program Projects (continued)


Appendix C. CCT Program Environmental

Aspects

Program Update 2001 ix

CCT Program Environmental Control Devices

Project Fact Sheets by Application CategorySO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) 5-22

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) 5-26

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC-North America) 5-30

Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) 5-34

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process(Southern Company Services, Inc.) 5-38

NOx Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler(Southern Company Services, Inc.) 5-44

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

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

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler(Energy and Environmental Research Corporation) 5-56

Micronized Coal Reburning Demonstration for NOx Control (New York State Electric & Gas Corporation) 5-60

Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High-Sulfur,Coal-Fired Boilers (Southern Company Services, Inc.) 5-64

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of NOxEmissions from Coal-Fired Boilers (Southern Company Services, Inc.) 5-68

Combined SO2/NOx Control Technologies

SNOX� Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) 5-74

LIMB Demonstration Project Extension and Coolside Demonstration (The Babcock & Wilcox Company) 5-78

SOx-NOx-Rox Box� Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) 5-82

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection(Energy and Environmental Research Corporation) 5-86

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) 5-90

Integrated Dry NOx/SO2 Emissions Control System (Public Service Company of Colorado) 5-94

x Program Update 2001

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland Electric) 5-100

McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, Lakeland Electric) 5-102

JEA Large-Scale CFB Combustion Demonstration Project (JEA) 5-104

Tidd PFBC Demonstration Project (The Ohio Power Company) 5-106

Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) 5-110

Integrated Gasification Combined-Cycle

Kentucky Pioneer IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) 5-116

Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) 5-118

Piñon Pine IGCC Power Project (Sierra Pacific Power Company) 5-122

Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project JointVenture) 5-126

Advanced Combustion/Heat Engines

Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) 5-132

Healy Clean Coal Project (Alaska Industrial Development and Export Authority) 5-134

Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process (Air Products LiquidPhase Conversion Company, L.P.) 5-140

Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc., and CQ Inc.) 5-142

ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) 5-146

Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) 5-150

Clean Power from Integrated Coal/Ore Reduction (CPICOR™)(CPICOR™ Management Company, LLC) 5-156

Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) 5-158

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) 5-162

Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) 5-166

Pulse Combustor Design Qualification Test (ThermoChem, Inc.) 5-170

Achieving New Source Performance Standards Emission Standards Through Integration of Low-NOx Burnerswith an Optimization Plan for Boiler Combustion (Sunflower Electric Power Corp.) 6-16

Big Bend Power Station Neural Network-Sootblower Optimization (Tampa Electric Company) 6-20

CCT Program Advanced Electric Power

Generation

CCT Program Coal Processing for Clean

Fuels

CCT Program Industrial Applications

Power Plant Improvement Initiative

Program Update 2001 xi


(continued)

Combustion Initiative for Innovative Cost-Effective NOx Reduction (Alliant Energy Corporate Services, Inc.) 6-8

Commercial Demonstration of the Manufactured Aggregate Processing Technology UtilizingSpray Dryer Ash (Universal Aggregates, LLC) 6-22

Demonstration of a Full-Scale Retrofit of the Advanced Hybrid Particulate Collector Technology(Otter Tail Power Company) 6-14

Development of Hybrid FLGR/SNCR/SCR Advanced NOx Control for Orion Avon Lake Unit 9(Arthur D. Little, Inc.) 6-10

Greenidge Multi-Pollutant Control Project (CONSOL Energy, Inc.) 6-12

Polk 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 Expert�) 5-142

ABB Environmental Systems (SNOX� Flue Gas Cleaning Demonstration Project) 5-74

Air Products Liquid Phase Conversion Company, L.P. (Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOH�) Process) 5-140

AirPol, Inc. (10-MWe Demonstration of Gas Suspension Absorption) 5-22

Alaska Industrial Development and Export Authority (Healy Clean Coal Project) 5-134

Alliant Energy Corporate Services, Inc. (Combustion Initiative for Innovative Cost-Effective NOx Reduction) 6-8

Arthur D. Little, Inc. (Clean Coal Diesel Demonstration Project) 5-132

Arthur 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) 5-78

Babcock & Wilcox Company, The (SOx-NOx-Rox Box� Flue Gas Cleanup Demonstration Project) 5-82

Bechtel Corporation (Confined Zone Dispersion Flue Gas Desulfurization Demonstration) 5-26

Bethlehem Steel Corporation (Blast Furnace Granular-Coal Injection System Demonstration Project) 5-158

Coal Tech Corporation (Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control) 5-162

CONSOL Energy, Inc. (Greenidge Multi-Pollutant Control Project) 6-12

CPICOR� Management Company, LLC (Clean Power from Integrated Coal/Ore Reduction (CPICOR�) 5-156

CQ Inc. (see ABB Combustion Engineering and CQ Inc.)

ENCOAL Corporation (ENCOAL® Mild Coal Gasification Project) 5-142

Energy and Environmental Research Corporation (Enhancing the Use of Coals by Gas Reburning and Sorbent Injection) 5-86

Energy 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) 5-104

Kentucky Pioneer Energy, LLC (Kentucky Pioneer IGCC Demonstration Project) 5-116

Lakeland, City of, Lakeland Electric (McIntosh Unit 4A PCFB Demonstration Project) 5-100

Lakeland, City of, Lakeland Electric (McIntosh Unit 4B Topped PCFB Demonstration Project) 5-102

LIFAC-North America (LIFAC Sorbent Injection Desulfurization Demonstration Project) 5-30

New York State Electric & Gas Corporation (Micronized Coal Reburning Demonstration for NOx Control) 5-60

Project Fact Sheets by Participant

Program Update 2001 xiii

New York State Electric & Gas Corporation (Milliken Clean Coal Technology Demonstration Project) 5-90

Ohio Power Company, The (Tidd PFBC Demonstration Project) 5-106

Otter Tail Power Company (Demonstration of a Full-Scale Retrofit of the Advanced Hybrid Particulate Collector Technology) 6-14

Passamaquoddy Tribe (Cement Kiln Flue Gas Recovery Scrubber) 5-166

Public 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) 5-34

Sierra Pacific Power Company (Piñon Pine IGCC Power Project) 5-122

Southern Company Services, Inc. (Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler) 5-44

Southern Company Services, Inc. (Demonstration of Innovative Applications of Technology for the CT-121 FGD Process) 5-38

Southern Company Services, Inc. (Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High-Sulfur, Coal-FiredBoilers) 5-64

Southern Company Services, Inc. (180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of NOx Emissions from Coal-Fired Boilers) 5-68

Sunflower Electric Power Corp. (Achieving New Source Performance Standards Emission Standards Through Integration of Low-NOx Burners with an OptimizationPlan for Boiler Combustion) 6-16

Tampa Electric Company (Polk Power Station Plant Improvement Project) 6-18

Tampa Electric Company (Big Bend Power Station Neural Network-Sootblower Optimization) 6-20

Tampa Electric Company (Tampa Electric Integrated Gasification Combined-Cycle Project) 5-118

ThermoChem, Inc. (Pulse Combustor Design Qualification Test) 5-170

Tri-State Generation and Transmission Association, Inc. (Nucla CFB Demonstration Project) 5-110

Universal Aggregates, LLC (Commercial Demonstration of the Manufactured Aggregate Processing Technology Utilizing Spray Dryer Ash) 6-22

Wabash River Coal Gasification Repowering Project Joint Venture (Wabash River Coal Gasification Repowering Project) 5-126

Western SynCoal LLC (Advanced Coal Conversion Process Demonstration) 5-150

xiv Program Update 2001

Program Update 2001 ES-1

IntroductionThe Clean Coal Technology Demonstration Program:Program Update 2001 (Program Update 2001) notonly presents the Clean Coal Technology Demonstra-tion 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 thenation�s energy supply.

CCT Program. The CCT Program, a model ofgovernment and industry cooperation, advances theDepartment of Energy�s (DOE) mission to foster asecure and reliable energy system that is environmen-tally 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 deregu-lated electric power marketplace.

The CCT Program is providing a portfolio of technolo-gies that will assure that the U.S. recoverable coalreserves of 274 billion tons can continue to supply thenation�s energy needs economically and in an environ-mentally 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 Summarysuch 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, demon-strating technologies that produce clean coal-basedsolid and liquid fuels by removing pollutants or theirprecursors before being burned. Lastly, new technolo-gies were introduced into the major coal-using indus-tries to enhance environmental performance. Thanks inpart to the CCT Program, coal�abundant, secure, andeconomical�can continue in its role as a key compo-nent in the U.S. and world energy markets.

CCT Program Major Accomplishments. In fiscalyear 2001, the Tampa Electric Integrated GasificationCombined-Cycle Project, the Piñon Pine IGCC PowerProject, the Advanced Coal Conversion ProcessDemonstration, and the Pulse Combustor DesignQualification Test completed demonstration operations.

The Tampa Electric Integrated Gasification Combined-Cycle Project successfully demonstrated an advancedintegrated gasification combined-cycle (IGCC) systemusing Texaco�s 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 Piñon Pine IGCC Power Project, using KRW�s air-blown, pressurized fluidized-bed gasification system,provided valuable �lessons learned� data that willassist the next generation of plants to improve reliabil-ity, 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 Project (The Ohio PowerCompany)�1991 Powerplant Award presented by Powermagazine.

Tampa Electric Integrated Gasification Combined-CycleProject (Tampa Electric Company)�1997 Powerplant Awardpresented by Power magazine.

ES-2 Program Update 2001

The Advanced Coal Conversion Process Demonstra-tion successfully produced SynCoal®—a coal producthaving 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 Enhanced™ 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 partici-pated 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 ControlTechniques for a Wall-Fired Boiler and the Evaluationof Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler. Clean Coal Technology Topical Reportswere issued during the fiscal year for the Environmen-tal 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 Demon-stration 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 ofEnergy developed a PPII solicitation, incorporatinggeneral provisions of the CCT Program (per congres-

sional direction) with some modifications to take intoaccount lessons learned from the CCT Program. Theprogram solicitation was issued on February 6, 2001and 24 proposals were received on April 19, 2001. OnSeptember 28, 2001, a total of eight projects valued atover $110 million were selected for negotiations.

Role of the CCT ProgramCCT Program Evolution. Coal accounts for over 94percent of the proven fossil energy reserves in theUnited States and supplies the bulk of the low-cost,reliable electricity vital to the nation’s economy andglobal competitiveness. In 2000, over half of thenation’s electricity was produced with coal, andprojections by the U.S. Energy Information Agency(EIA) predict that coal will continue to dominateelectric power production well into the first quarter of`the 21st century. However, there is a need to use U.S.coal resources in an environmentally responsiblemanner.

The CCT Program was established to demonstrate thecommercial feasibility of CCTs to respond to a growingdemand for a new generation of advanced coal-basedtechnologies characterized by enhanced operational,economic, and environmental performance. The firstsolicitation (CCT-I) for clean coal projects resulted in abroad range of projects being selected in four majorproduct markets—environmental control devices,advanced electric power generation, coal processingfor clean fuels, and industrial applications.

The second solicitation (CCT-II) became the center-piece for satisfying the recommendations contained inthe Joint Report of the Special Envoys on Acid Rain(1986). The goal was to demonstrate technologies thatcould achieve significant reductions in the emissions ofprecursors of acid rain, namely SO2 and NOx. The third

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 environ-mental issues, such as global climate change andcapping SO2 emissions, and thus focused on technolo-gies that were capable of addressing these issues. CCT-IV called for energy efficient, economically competi-tive 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 so-

called Group 1 boilers—tangentially fired and dry-bottom wall-fired boilers. The U.S. EnvironmentalProtection Agency (EPA) used data developed duringthe CCT Program in establishing the NOx emissionstandards. Under Phase II, EPA established NOxemission limitations for Group 2 boilers and furtherlimited emissions for Group 1 boilers. Group 2 boilersinclude cell-burner, cyclone, wet-bottom wall-fired,and vertically fired boilers. The CCT Program hasdemonstrated NOx emission control techniques that areapplicable to all of these boiler types. Furthermore,these technologies are not only applicable to Phase Iand II NOx emission reductions, but can be used inozone nonattainment areas to make deeper cuts in NOxemissions, which are a precursor to ozone.

The EPA has issued a “SIP Call” to 22 states and theDistrict of Columbia to take action to reduce regionaltransport of pollutants that contribute to ozone nonat-tainment in the Northeast. The SIP Call requires the 23affected jurisdictions to revise their state implementa-tion plans (SIPs) to reduce NOx emissions to 85percent below 1990 rates or achieve a 0.15 lb/106 Btuemission rate by May 2003. In addition, EPA hastightened the New Source Performance Standard(NSPS) for electric and industrial boilers built ormodified after July 9, 1997. The CCT Program hasdemonstrated several advanced electric power genera-tion technologies that can be used to meet the newrequirements or exceed the requirements to produceNOx credits that could be sold to unit operators unableto meet the requirements. Furthermore, an environmen-tal controls database has been developed that providesa foundation for developing technologies to meet theincreasingly stringent standards for existing units.

Air toxics is another important area of environmentalconcern addressed by the CCT Program. Under Title Iof the CAAA, EPA is responsible for determining thehazards to public health posed by 189 identifiedhazardous air pollutants (HAPs). The CCT Programmade a significant contribution to a better understand-ing of potential HAPs from power plant emissions by

monitoring HAPs from CCT Program project sites. Theresults of these and other studies have significantlymitigated concerns about HAP emissions from coal-fired power plants and focused attention on mercuryemissions. In December 2000, EPA decided to developregulations for mercury emissions over the ensuingthree year period.

The CCT Program is also cognizant of concerns aboutglobal climate change. Clean coal technologies (suchas IGCC) being demonstrated in the CCT Programoffer utilities an option to reduce greenhouse gases(GHG) by as much as 25 percent with first-generationsystems through enhanced efficiency. Commercializa-tion of atmospheric fluidized-bed combustion (AFBC)and pressurized fluidized-bed combustion (PFBC) willalso serve to reduce GHGs.

Market Considerations. As the electric generationmarket moves from a regulated industry to a freemarket, the CCT Program has kept pace with thechanges. Whether the changes are brought about by thefederal government through existing or new legislationor by state governments, the CCT Program is demon-strating the first generation of many technologies thatwill be needed in a competitive power generation

Advanced Flue Gas Desulfurization Demonstration Project(Pure Air on the Lake, L.P.)—1993 Powerplant Awardpresented by Power magazine.


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 technolo-gies.

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 pro-grams 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 Improve-ment 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 Con-gress to add $95 million to the Office of Fossil Energybudget for fiscal year 2001. The Power Plant Improve-ment Initiative approved by Congress will have a near-term focus on improving the efficiency and environmen-tal 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 govern-ment/industry partnership designed to implement thePresident’s National Energy Policy (NEP) recommen-dation 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 deploy-ment 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 high-value 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 ImplementationImplementation Principles. There are 10 guidingprinciples that have been instrumental in the success ofthe CCT Program. These principles are:

• Strong and stable financial commitment for the lifeof a project, including full funding of thegovernment’s share of the costs;

• Multiple solicitations spread over a number ofyears, enabling the CCT Program to address a broadrange of national needs with a portfolio of evolvingtechnologies;

• Demonstrations conducted at commercial scale inactual user environments, allowing clear assessmentof a technology’s commercial potential;

• A technical agenda established by industry, not thegovernment, enhancing commercialization potential;

• Clearly defined roles of government and industry,reflecting the degree of cost-sharing required;

• A requirement for at least 50 percent cost-sharingthroughout all project phases, enhancing partici-pants’ commitment;

• An allowance for cost growth, but with a ceilingand cost-sharing, recognizing demonstration riskand providing an important check-and-balancesystem to the program;

• Industry retention of real and intellectual propertyrights, enhancing commercialization potential;

• A requirement for industry to commit to commer-cialize the technology, reflecting commercializationgoals; and

• A requirement for repayment up to thegovernment’s cost-share upon successful commer-cialization of the technology being demonstrated.


Implementation Process. Public and private sectorinvolvement is integral to the CCT Program processand has been crucial to the program�s success. Environ-mental concerns are publicly addressed through theprocess instituted under the National EnvironmentalPolicy Act (NEPA). Through programmatic environ-mental assessments (PEAs) and environmental impactstatements (PEISs), project-specific environmentalassessments (EAs) and environmental impact state-ments (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 perfor-mance-based criteria and developed approaches toaddress �lessons learned� 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 disap-prove 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 oneof the many public reports made available through theoutreach program.

Commitment to Commercial Realization. The CCTProgram has focused on achieving commercialrealization since the program�s inception. All fivesolicitations required the potential participants to

address the commercial plans and approaches to beused by the participants to achieve full commercializa-tion 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)�a 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 partici-pant. 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 newinitiatives�Power Plant Improvement Initiative andClean Coal Power Initiative�will incorporate many ofthe implementation principles of the CCT Program.

These implementation principles will also reflectlessons learned from the CCT Program to furtherenhance the return on taxpayer investment.

Funding and CostsProgram Funding. Congress has appropriated afederal budget of $1.8 billion for the CCT Program.The participants in the 38 completed and activeprojects will have contributed almost $3.5 billiondollars for a combined commitment of more than $5.2billion. By law, DOE�s contribution cannot exceed 50percent of the total cost of any project. However,industry has stepped forward and cost-shared anunprecedented 66 percent of the project funding.

Congress has provided CCT Program funding for allfive solicitations through appropriation acts andadjustments. Additional activities funded by the CCTProgram are the Small Business Innovation ResearchProgram and the Small Business Technology TransferProgram. Funding is also provided for administrationand management of the CCT Program. Use of appro-priated funds is controlled and monitored using avariety of financial management techniques. The fullgovernment cost-share specified in the cooperativeagreement is considered committed to each project;however, DOE obligates funds for the project inincrements by budget period. This procedure reducesthe government�s financial exposure and assures thatDOE fully participates in the decision to proceed witheach major phase of project implementation.

Cost Sharing. As stated above, DOE�s contributioncannot exceed 50 percent of the total cost of anyproject. Participant cost-sharing is required for allphases of the project. The federal government mayshare in project cost growth (which is a potential forany demonstration project) up to 25 percent of the


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 invest-ments 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 com-mercialized. 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 technolo-gies 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 Commit-ment. The success of theCCT Program ultimatelywill be measured by thecontribution the tech-nologies make to theresolution of energy,economic, and environ-mental issues. Thesecontributions can only beachieved if the publicand private sectorsunderstand that cleancoal technologies canincrease the efficiency ofenergy use and enhanceenvironmental perfor-mance at costs that arecompetitive withalternative energyoptions. The demonstra-tions, in conjunction withan aggressive outreacheffort, are designed to

impart that understanding. Also, the CCT Program isorganized from a market perspective with projectsplaced in four major product lines—environmentalcontrol devices, advanced electric power generation,coal processing for clean fuels, and industrial applica-tions. A summary of the number of projects havingcompleted operations by category is shown in ExhibitES-1.

The first major product line, environmental controldevices, is subdivided into three groups—SO2 controltechnologies, NOx control technologies, and combinedSO2/NOx control technologies. Both wet and dry lime-and limestone-based systems were demonstrated toachieve a range of SO2 capture efficiencies from 50 to99 percent. All five of the SO2 control technologydemonstrations have successfully completed operations.

Exhibit ES-1Completed Projects by Application Category

Number of Projects

Application Category Completed Total

Operations

as of Sept. 30, 2001

Environmental Control Devices

SO2 Control Technology 5 5

NOx Control Technology 6 7

Combined SO2/NOx Control Technology 6 6

Advanced Electric Power Generation

Fluidized-Bed Combustion 2 5

Integrated Gasification Combined-Cycle 3 4

Advanced Combustion/Heat Engines 1 2

Coal Processing for Clean Fuels 3 4

Industrial Applications 4 5

Total 30 38


The PC-based software tool CQE™ 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 Gasification Repowering Project (WabashRiver Coal Gasification Repowering Project Joint Venture)—1996 Powerplant Award presented by Power magazine.

Full-Scale Demonstration of Low-NOx Cell Burner RetrofitProject (The Babcock & Wilcox Company)—1994 R&D 100Award presented by R&D magazine.

For NOx control technologies, two basic approacheswere used: (1) combustion modification techniquesincluding low-NOx burners, overfire air, advancedcontrols, and reburning systems; and (2) post-combus-tion 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 coal-fired 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 technologydemonstrations have successfully completed opera-tions. 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 complemen-

tary and synergistic control methods to achieve cost-effective SO2 and NOx emission reductions.

A summary of the results of the completed andextended environmental control device projects can befound in exhibit ES-2. The commercial successes of theenvironmental control devices can be seen in ExhibitES-3.

The second major product line, advanced electricpower generation, is subdivided into three groups—(1)fluidized-bed combustion, (2) integrated gasificationcombined-cycle, and (3) advanced combustion/heatengines. These technologies can be used for repower-ing existing plants and for new plants.

For fluidized-bed combustion, two approaches wereused: atmospheric fluidized-bed combustion (AFBC)and pressurized fluidized-bed combustion (PFBC). Thetwo AFBC projects use a circulating-bed, as opposedto a bubbling-bed, operating at atmospheric pressure togenerate steam for electricity production. One projectis complete and the other project is ongoing. There arethree PFBC projects in the CCT Program. The com-pleted 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 com-pleted 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 (slag-ging) combustor, and the other uses a heavy duty dieselengine fired on a coal-water fuel. One project com-pleted operations and the other project is ongoing.

A summary of the results of the completed advancedelectric power generation projects can be found inExhibit ES-4. The commercial successes of theseprojects can be seen in Exhibit ES-5.

For the third major product line, coal processing forclean fuels, there are four projects. Two completedprojects used chemical and physical processes to


Exhibit ES-2Summary of Results of Completed Environmental Control Technology Projects

Project and Participant Key Results Capital Cost

SO2 Control Technology10-MWe Demonstration of Gas Suspension Absorption Gas suspension absorption (GSA)/electrostatic precipita- $149/kW for GSA (2.6% sulfur coal) vs. $216/kW for(AirPol, Inc.) tor (ESP)�SO2 removal efficiency of 90% at Ca/S molar conventional wet limestone forced oxidation scrubber

ratio of 1.4, 18 ºF approach to saturation, and 0.12% (1990$)chloride (3.0% sulfur bituminous coal)

GSA/pulse jet baghouse�SO2 removal efficiency 3�5%greater than GSA/ESP (3.0% sulfur bituminous coal)

Confined Zone Dispersion Flue Gas Desulfurization SO2 reduction of 50% (1.2�2.5% sulfur bituminous coal) Less than $30/kW at 500 MWe (4% sulfur coal) (1994$)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 (300 MWe); $76/kW for oneProject (LIFAC�North America) (2.0�2.8% sulfur bituminous coal) reactor (150 MWe); $99/kW for one reactor (65 MWe)

(1994$)

Advanced Flue Gas Desulfurization Demonstration Project SO2 removal efficiency of 95% or more at availabilities of $210/kW at 100 MWe; $121/kW at 300 MWe;(Pure Air on the Lake, L.P.) 99.5% when operating on 2.0�4.5% sulfur bituminous $94/kW at 500 MWe (3.0% sulfur coal) (1995$)

coal

Maximum SO2 removal efficiency of 98%

Over 3-year demonstration, 237,000 tons of SO2removed while producing 210,000 tons of gypsum

Gypsum purity��97.2%

Power consumption�5,275 kW (61% of expected)

Water consumption�1,560 gal/min (52% of expected)

Demonstration of Innovative Applications of Technology SO2 removal efficiency of over 95% at SO2 inlet $313/kW or $408/ton SO2 for 100 MWefor the CT-121 FGD Process (Southern Company concentrations of 1,000�3,500 ppm using 3% sulfur coal $131/kW or $171/ton SO2 for 300 MWeServices, Inc.) Particulate removal efficiency of 97.7�99.3% $104/kW or $136/ton SO2 for 500 MWe

at inlet mass loadings of 0.303�1.392 lb/106 Btu (Costs based on limestone at $20/ton delivered)

Agricultural-grade gypsum as a by-product

Fiberglass-reinforced-plastic construction�chemicallyand structurally durable; eliminated the need for a flue gasprescrubber and reheat


Exhibit ES-2 (continued)Summary of Results of Completed Environmental Control Technology Projects


NOx 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-MWe wall-fired unit is $18.80/kWa Wall-Fired Boiler (Southern Company Services, Inc.) full load, representing a 48% reduction from baseline for LNB/AOFA, $8.80/kW for AOFA alone, $10.00/kW

conditions (1.24 lb/106 Btu) for LNB alone, and $0.50/kW for GNOCIS

Using AOFA only, NOx reductions of 24% below Estimated cost of NOx removal is $79/ton in a base loadbaseline conditions were achieved under normal long-term dispatch modeoperation, depending upon load

Using LNB/AOFA, full load NOx emissions wereapproximately 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; $43/kW at 605 MWe (1990$)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-NOx Cell Burner NOx reductions of 58% using bituminous coal at full load $9/kW at 600 MWe (1994$)Retrofit (The Babcock & Wilcox Company) (605 MWe); 48% at 350 MWe

Evaluation of Gas Reburning and Low-NOx Burners on a LNB alone (second generation)—37% NOx reduction; GR-LNB $26/kW at 300MWe; GR alone $12/kW, plusWall-Fired Boiler (Energy and Environmental Research GR-LNB (second generation)—64% NOx reduction gas pipeline cost (1996$)Corporation) (13% gas heat input)

Micronized Coal Reburning Demonstration for NOx Using a 14% reburn fuel heat input on the Milliken Station $14/kW at 300 MWe (1999$)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%NOx 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% NOx reduction—2.79 mills/kWhTechnology for the Control of NOx Emissions from High- 5 ppm or $2,036/ton of NOx removed (1996$)Sulfur, Coal-Fired Boilers (Southern CompanyServices, Inc.)

180-MWe Demonstration of Advanced Tangentially NOx reductions of 37% for LNCFS™ I and II, and 45% LNCFS I—$5–15/kW (1993$)Fired Combustion Techniques for Reduction of NOx for LNCFS™ III, which includes both separated overfire LNCFS II/III—$15–25/kW (1993$)Emissions from Coal-Fired Boilers (Southern Company air and close-coupled overfire airServices, Inc.)




Combined SO2/NO

x Control Technology

SNOX™ Flue Gas Cleaning Demonstration Project NOx reduction of over 94% at inlet concentra- $305/kW at 500 MWe (3.2% sulfur coal) (1995$)(ABB Environmental Systems) tions of 500–700 ppm

SO2 removal efficiency over 95% at inlet concentrationsof 2,000 ppm

Produced 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—$31–102/kW (100–500 MWe) (1992$)Demonstration (McDermott Technology, Inc.) of 2.0): Coolside—$69–160/kW (100–500 MWe) (1992$)

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

NOx reduction of 40–50%

SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstration SO2 reductions of 80–90% using 3–4% sulfur bituminous $233/kW at 250 MWe (3.5% sulfur coal and inletProject (The Babcock & Wilcox Company) coal, depending on sorbent and conditions NOx level of 1.2 lb/106 Btu) (1994$)

NOx 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 $15/kW for gas reburning, plus gas pipeline cost (1996$)Sorbent Injection (Energy and Environmental Research heat input; SO2 removal efficiency of 53% at 1.75 Ca/SCorporation) molar ratio

Lakeside—Average NOx reduction of 66% and SO2 $50/kW for sorbent injectionreductions 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% $300/kW at 300 MWe (1998$) for total capital(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 total plant costs and $83/kWwas 95% for other related costs

Testing of the LNCFS™ III indicated NOx emissions of $4,620,000/yr for O&M costs0.39 lb/106 Btu (compared to 0.64 lb/106 Btu for theoriginal burners), a 36% reduction




Combined SO2/NO

x 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 for total capital requirements(Public Service Company of Colorado) maximum overfire air (50–110 MWe) $281/kW at 50 MWe for total capital requirements

NOx reduction of 63% with low-NOx burners andminimum overfire air; steady state conditions

NOx reduction decreased by 10–25% under loadfollowing

SNCR obtained NOx reduction of 30–50%,thereby increasing total NOx control system reductionto more than 80%

SO2 removal efficiency of 70% with sodium bicarbonateat normalized stoichiometric ratio of 1.0


Exhibit ES-3Commercial Successes—Environmental Control Technologies

10-MWe Demonstration of Gas Suspension Absorption Sold domestically and internationally. GSA market entry was significantly enhanced with the sale of a 50-MWe(AirPol, Inc.) unit, worth $12.5 million, to the city of Hamilton, Ohio, subsidized by the Ohio Coal Development Office. A sale

worth $1.3 million has been made to the U.S. Army for hazardous waste disposal. A GSA system has been sold to aSwedish iron ore sinter plant. Two GSA systems valued at $1.8 million have been sold to Taiwan Sugar Corporationfor their oil-fired cogeneration plant. AirPol sold a GSA system valued at $1.5 million to a petroleum coke calciner inIndia. Startup has begun in Wasatch, Utah for a GSA-based municipal waste incinerator coproducing electricity andsteam. A new contract is expected for a waste incinerator in Holland using the GSA system.

Confined Zone Dispersion Flue Gas Desulfurization No sales reported. CZD/FGD can be used to retrofit existing plants or for new installations at a cost of about one-Demonstration (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 & Light is the first to be applied to a(LIFAC–North America) power plant using high-sulfur (2.0-2.9%) coal. The LIFAC system has been retained for commercial use by Richmond

Power & Light at Whitewater Valley Station, Unit No. 2. There are 10 LIFAC units in operation in Canada, China,Finland, Japan, Russia, and the United States, including 5 projects started before the CCT Program. For three sales inChina, 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 Public Service Company’s Bailly(Pure Air on the Lake, L.P.) Generating Station. Gypsum produced by the PowerChip® process is being sold commercially. The estimated value

for 17 years of continued scrubber operations roughly equals the value of the project. FLS miljo, a Copenhagen-basedlicensee, is currently working on a potential $60 million project in Kentucky using the next generation of thistechnology.

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

worldwide. There are 17 CT-121 plants operating in Japan, Australia, Canada, the Czech Republic, Korea, Denmark,Malaysia, and Kuwait. The value of these 17 plants is estimated at $2.03 billion. For the projects in the planning stage,the 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 Plant.(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 Light Company’s NelsonControl (The Babcock & Wilcox Company) Dewey Station.

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit Sold domestically. Dayton Power & Light has retained the LNCB® for use in commercial service. Seven(The Babcock & Wilcox Company) commercial contracts have been awarded for 196 burners or 5,475 MWe of capacity, valued at $30 million.

Evaluation of Gas Reburning and Low-NOx Burners on a Sold domestically and internationally. Public Service Company of Colorado, the host utility, decided to retain theWall-Fired Boiler (Energy and Environmental Research Corp.) low-NOx burners and the gas-reburning system for immediate use; however, a restoration was required to remove the

flue gas recirculation system. Since the CCT Program, the participant has installed or is in the process of installing thegas reburning or the gas reburning-low-NOx burner technology on 14 boilers representing 4,814 MWe of capacity.Most of the sites are domestic, but one site is the Ladyzkin Power Station in Ladyzkin, Ukraine.

Project Commercial Use


Exhibit ES-3 (continued)Commercial Successes—Environmental Control Technologies


Demonstration of Selective Catalytic Reduction Technology Sold domestically and internationally. Since the project was initiated, revenues from SCR sales achieved $4.9for the Control of NOx 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. LNCFS™ has been retained at the host site for commercial use. AlstromCombustion Techniques for the Reduction of NOx Emissions Power has sold about 63 GWe of LNCFS™ burners. Of this amount, about 49 GWe are equipped with overfire airfrom 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 commercial use. Foster WheelerFired Boiler (Southern Company Services, Inc.) has equipped 101 boilers with low-NOx burner technology—a total of over 1,447 burners representing 26,105 MWe

of capacity valued at $83 million. Foreign sales make up 35 percent of the commercial market. Twenty-six commercialinstallations of GNOCIS, the associated artificial intelligence control system, are underway or planned. Thisrepresents over 12,000 MWe of capacity. In a strict sense, this project has not been completed; it has been extended toapply GNOCIS to other pieces of plant equipment, which may increase its commercial potential.

SNOX™ Flue Gas Cleaning Demonstration Project (ABB International use. The host utility, Ohio Edison, is retaining the SNOX™ technology as a permanent part of theEnvironmental Systems) pollution control system at Niles Station to help meet its overall SO2 and NOx reduction goals. Commercial SNOX™

plants are also operating in Denmark and Sicily. In Denmark, a 305-MWe plant has operated since August 1991. Theboiler at this plant burns coals from various suppliers around the world, including the United States; the coals contain0.5–3.0% sulfur. The plant in Sicily, in operation since March 1991, has a capacity of about 30 MWe and firespetroleum coke.

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

value of $388 million.

SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstration Project No sales reported. Commercialization of the technology is expected to develop with an initial larger scale(The Babcock & Wilcox Company) application equivalent to 50–100 MWe. The focus of marketing efforts is being tailored to match the specific needs

of potential industrial, utility, and independent power producers for both retrofit and new plant construction.SNRB™ is a flexible technology that can be tailored to maximize control of SO2, NOx, particulate, or combinedemissions to meet current performance requirements while providing flexibility to address future needs.

Enhancing the Use of Coals by Gas Reburning and Sorbent No sales reported. Illinois Power has retained the gas-reburning system and City Water, Light & Power has retainedInjection (Energy and Environmental Research Corp.) the full technology for commercial use. (See Evaluation of Gas Reburning and Low-NOx Burner on a Wall-Fired

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 Optimization Advisor, with an estimated(New York State Electric & Gas Corp.) value of $280,000, have been sold. A U.S. company, SHN, has been established to market the S-H-U scrubber. SHN

is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABB Combustion Engineering hasmodified 116 units representing over 25,000 MWe with LNCFS™ or its derivative TFS 2000™.

Integrated Dry NOx/SO2 Emissions Control System Sold domestically. The technology was retained by Public Service Company of Colorado for commercial service(Public Service Company of Colorado) at its Arapahoe Station. Babcock & Wilcox has sales of 2,805 DRB-XCL® burners for 38,284 MWe of capacity. The

low-NOx burners have an estimated value of $388 million.


Exhibit ES-4Summary of Results of Completed Advanced Electric Power Generation Projects

Tidd PFBC Demonstration Project (The Ohio Power SO2 reduction of 90–95% (Ohio bituminous coal, 2–4% $1,263/kW at 360 MWe (1997$)Company) sulfur) at 1.1–1.5 Ca/S molar ratio

NOx emissions of 0.15–0.33 lb/106 Btu

Particulate emissions of 0.02 lb/106 Btu

Heat rate—10,280 Btu/kWh

Combustion efficiency—99.6%

Commercially viable design

Gas turbine operable in PFBC environment

Nucla CFB Demonstration Project (Tri-State Generation SO2 reduction of 70–95% (up to 1.8% sulfur coal), Approximately $1,123/net kW (repowering cost) (1990$)and Transmission Association, Inc.) depending on Ca/S molar ratio

NOx emissions of 0.18 lb/106 Btu

Particulate emissions of 0.0072–0.0125 lb/106 Btu


Combustion 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) NOx emissions of 0.27 lb/106 Btu


Carbon burnout—95+%


Piñon Pine IGCC Power Project Design SO2 reduction of 95%(Sierra Pacific Power Company)

Design NOx emissions of 70% less than conventionalcoal plant

Steady-state operation was not reached


Economic performance could not be evaluated becauseplant did not achieve steady-state operation


Exhibit ES-4 (continued)Summary of Results of Completed Advanced Electric Power Generation Projects

Wabash River Coal Gasification Repowering Project SO2 reductions of 99% $1,318/kW (2000$) for a greenfield coal-fueled plant(Wabash River Coal Gasification Project Joint Venture) NOx emissions of 0.15 lb/106 Btu $1,260/kW (2000$) for a greenfield petroleum

coke-fueled plantParticulate emissions below detectable limits

Heat rate�8,910 Btu/kWh


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

50% run-of-mine and 50% waste coal) at 1.4�1.8 Ca/S $1,502/kW for a 300-MWe unitmolar ratio

NOx emissions of 0.208�0.278 lb/106 Btu

Particulate emissions of 0.0047 lb/106 Btu

Greater than 99% carbon burnout at 100% maximumcontinuous rating



Exhibit ES-5Commercial Successes—Advanced Electric Power Generation Technologies


Tidd PFBC Demonstration Project (The Ohio Power Company) Sold internationally. Success of the project has led Babcock & Wilcox to invest in the technology andacquire domestic licensing rights. Commercial coal-fired ventures abroad include the following:

– Vartan Sweden is operating two P200 units to produce 135 MWe and 224 MWth*;

– 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 40 MWth;

– 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 Wheeler Energy Corporation,Transmission Association, Inc.) the technology supplier for the demonstration effort, has achieved sales of $9 billion through 2001. Almost

25 percent of the sales through 2001 were domestic, while the remaining sales were foreign. For a similartime frame, Alstom Power, also a supplier of CFB technology, has had sales of $4.1 billion (representing3.47 GWe) through 2001.

Tampa Electric Integrated Gasification Combined-Cycle Sold domestically and internationally. First greenfield IGCC unit in commercial service. Texaco, Inc.,Project (Tampa Electric Company) and ASEA Brown Boveri signed an agreement forming an alliance to market IGCC technology in Europe.

Since 1996, when the Tampa IGCC began operations, Texaco has placed into operation 9 gasifiersdomestically, including Tampa, (1 using coal, 1 using petroleum, 3 using petroleum coke, and 4 using naturalgas) and 16 gasifiers internationally (3 using coal, 11 using petroleum, and 2 using natural gas).

Wabash River Coal Gasification Repowering Project (Wabash No sales reported. First repowered IGCC unit in commercial service and world’s largest single trainRiver Coal Gasification Repowering Project Joint Venture) IGCC in commercial service. Preferentially dispatched over other coal-fired units in PSI Energy’s system

because of high efficiency. The port of Port Arthur, Texas has announced plans for a $1.75 billion project touse 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 environ-mentally 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 Communications�Outreach. Outreach hasbeen a hallmark of the CCT Program since its incep-tion. Commercialization of new technologies requiresacceptance by a wide range of interests�customers,manufacturers, suppliers, financiers, government, andpublic interest groups. The CCT Program has aggres-sively 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 newslet-ters, 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 demon-stration 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 technolo-gies 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 nation�s 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 power generation. These advancedoptions offer greater than 20 percent reductions ingreenhouse gas emissions; SO2, NOx, and particulateemissions far below NSPS; and salable solid and liquidby-products in lieu of solid wastes. Over 1,800 MWeof capacity are represented by 11 projects valued atmore than $2.8 billion. These projects will not onlyprovide environmentally sound electric generation now,but also will provide the demonstrated technology basenecessary to meet new capacity requirements in the 21st

century.

Coal Processing for Clean Fuels. Also addressed areapproaches to converting run-of-mine coals to high-energy-density, low-sulfur products. These productshave application domestically for compliance with theCAAA. Internationally, both the products and pro-cesses have excellent market potential. Valued atalmost $432 million, the four projects in the coalprocessing for clean fuels category represent a diversi-fied portfolio of technologies.

Industrial Processes. Projects were undertaken as wellto address pollution problems associated with coal usein the industrial sector. The problems addressedinclude dependence of the steel industry on coke andthe pollutant emissions inherent in coke making;reliance of the cement industry on low-cost indigenous,and often high-sulfur, coal fuels; and the need for manyindustrial boiler operators to consider switching to coalfuels to reduce operating costs. The five industrialapplications projects have a combined value of nearly$1.3 billion. The projects encompass substitution ofcoal for 40 percent of coke in iron making; integrationof a direct iron-making process with the production ofelectricity; reduction of cement kiln emissions andsolid waste generation; demonstration of an industrial-scale slagging combustor; and demonstration of a pulsecombustor system.

Project Fact Sheets. The core of this Program Update2001 is the project fact sheets. Two types of fact sheetsare provided: (1) a brief two-page overview for



Development of the Coal Quality Expert™ CQE™ features: CQE™ package sells for between $75,000 and(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 evaluationswith a more focused scope than provided in the fuel evaluator

- Environmental planner—provides access to evaluation andpresentation capabilities of the Acid Rain Advisor

- Coal cleaning expert—establishes the feasibility of cleaning acoal, determines cleaning processes, and predicts associatedcosts

ENCOAL® Mild Gasification Project (ENCOAL The liquid (CDL®) and solid (PDF®) product fuels have been A commercial plant designed to process 15,000Corporation) used economically in commercial boilers and furnaces and have metric-ton/day would cost $475 million (2001$) to

reduced SO2 and NOx emissions significantly at utility and construct with annual operating and maintenanceindustrial facilities currently burning high-sulfur bituminous costs of $52 million per yearcoal or fuel oils.

Almost five years of operating data have been collected for useas a basis for the evaluation and design of a commercial plant

About 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 not available(Western Syncoal LLC) product

Nine years of operating data have been collected for use as thebasis for the evaluation and design of a commercial plant

Over 2.8 million tons of raw coal was processed to producealmost 1.9 million tons of SynCoal® products

Exhibit ES-6Summary of Results of Completed Coal Processing for Clean Fuels Projects


Exhibit ES-7Commercial Successes—Coal Processing for Clean Fuels Technologies


Development of the Coal Quality Expert™ (ABB Combustion Sold domestically and internationally. The Electric Power Research Institute (EPRI) owns the softwareEngineering, Inc. and CQ Inc.) and distributes it to EPRI members for their use. CQ Inc. and Black and Veatch have signed

commercialization agreements that give both companies nonexclusive worldwide rights to sell user licensesand offer consulting services that include use of CQE®. More than 22 U.S. utilities, two United Kingdomutilities, and one French utility have received CQE® through EPRI membership. Two modules of the AcidRain Advisor valued at $6,000 have been sold. EPRI estimated that the Acid Rain Advisor saved one U.S.utility about $26 million, more than the total cost of the demonstration project. There have been two sales ofthe Windows version of the software (Vista) at an estimated value of $180,000.

ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Domestic and international sales pending. In order to determine the viability of potential LFC® plants,five detailed commercial feasibility studies—two Indonesian, one Russian, and two U.S. projects—havebeen completed. Permitting of a 15,000 metric-ton/day commercial plant in Wyoming is proceeding.

Advanced Coal Conversion Process Demonstration (Western No sales reported. Total sales of SynCoal® product exceed 1.9 million tons. Six long-term agreements wereSynCoal LLC) in place to purchase the product. One domestic and five international projects have been investigated.

Western SynCoal LLC has a joint marketing agreement with Ube Industries of Japan providing Ube non-exclusive marketing rights outside of the United States. Ube is pursuing several projects in Asia.

Commercial-Scale Demonstration of the Liquid Phase Methanol No sales reported. Nominal 80,000 gallon/day methanol production being used by Eastman Chemical(LPMEOH™) Process (Air Products Liquid Phase Conversion CompanyCompany, L.P.)


Exhibit ES-8Summary of Results of Completed Industrial Application Projects


Advanced Cyclone Combustor with Internal Sulfur, SO2 reduction of 58% with limestone injection in the $100–200/kWNitrogen, and Ash Control (Coal Tech Corporation) combustor at 2.0 Ca/S molar ratio

NOx 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 $10 million for 450,000 ton/yr wet-process plant (1990$)quoddy Tribe) coal); 98% maximum reduction

NOx 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 blast furnace producing 7,200 netProject (Bethlehem Steel Corporation) of coke for every pound of coal tons of hot metal per day

No increase in sulfur emissions

Sulfur 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-9Commercial Successes—Industrial Application Projects


Advanced Cyclone Combustor with Internal Sulfur, No sales reported. While the combustor was not yet fully ready for sale with commercial guarantees, it was believedNitrogen, and Ash Control (Coal Tech Corporation) to have commercial potential. Subsequent work was undertaken, which has brought the technology close to

commercial introduction.

Cement Kiln Flue Gas Recovery Scrubber No sales reported. The scrubber became a permanent part of the cement plant at the end of the demonstration. A(Passamaquoddy Tribe) feasibility study has been completed for a Taiwanese cement plant.

Blast Furnace Granular-Coal Injection System 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 Improve-ment Initiative was established in fiscal year 2001 byCongress and provided �for 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 generat-ing facilities for which the Department of Energy uponreview may provide financial assistance awards . . .� 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 demonstra-tion and last for 20 years. In accordance with congres-sional 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 technolo-gies enabling coal-fired power plants to meet increas-ingly stringent environmental regulations at the lowestpossible cost. Many coal plants could continueoperations under stricter environmental guidelines ifmore effective and lower cost emission controls can bedeveloped. Other projects will improve the perfor-mance and reliability of power plants. A list of theselected PPII projects is presented in Exhibit ES-12.


Exhibit ES-10CCT Program Project Fact Sheets by Application Category

Project Participant Solicitation/Status Page


SO2 Control Technologies10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/completed 3/94 5-22

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93 5-26

LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCT-III/completed 6/94 5-30

Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95 5-34

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/completed 12/94 5-38

NOx Control TechnologiesDemonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/extended 5-44

Demonstration of Coal Reburning for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/completed 12/92 5-48

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 4/93 5-52

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 1/95 5-56

Micronized Coal Reburning Demonstration for NOx Control New York State Electric & Gas Corporation CCT-IV/completed 4/99 5-60

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95 5-64

for the Control of NOx Emissions from High-Sulfur, Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion Southern Company Services, Inc. CCT-II/completed 12/92 5-68

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

Combined SO2/NOx Control TechnologiesSNOX™ Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/completed 12/94 5-74

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/completed 8/91 5-78

SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5/93 5-82

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 10/94 5-86

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/completed 6/98 5-90

Integrated Dry NOx/SO2 Emissions Control System Public Service Company of Colorado CCT-III/completed 12/96 5-94



McIntosh Unit 4A PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-III/design 5-100

McIntosh Unit 4B Topped PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-V/design 5-102

JEA Large-Scale CFB Combustion Demonstration Project JEA CCT-I/construction 5-104


Exhibit ES-10 (continued)CCT Program Project Fact Sheets by Application Category


Tidd PFBC Demonstration Project The Ohio Power Company CCT-I/completed 3/95 5-106

Nucla CFB Demonstration Project Tri-State Generation and Transmission CCT-I/completed 1/91 5-110Association, Inc.


Kentucky Pioneer Energy IGCC Demonstration Project Kentucky Pioneer Energy, LLC CCT-V/design 5-116

Tampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/completed 10/01 5-118

Piñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/completed 1/01 5-122

Wabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering CCT-IV/completed 12/99 5-126Project Joint Venture


Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/construction 5-132

Healy Clean Coal Project Alaska Industrial Development and CCT-III/completed 12/99 5-134Export Authority

Coal Processing for Clean Fuels

Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process Air Products Liquid Phase CCT-III/operational 5-140Conversion Company, L.P.

Development of the Coal Quality Expert™ ABB Combustion Engineering, Inc. CCT-I/completed 12/95 5-142and CQ Inc.

ENCOAL® Mild Coal Gasification Project ENCOAL Corporation CCT-III/completed 7/97 5-146

Advanced Coal Conversion Process Demonstration Western SynCoal LLC CCT-I/completed 1/01 5-150

Industrial Applications

Clean Power from Integrated Coal/Ore Reduction (CPICOR™) CPICOR™ Management Company LLC CCT-V/design 5-156

Blast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/completed 11/98 5-158

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/completed 5/90 5-162

Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/completed 9/93 5-166

Pulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/completed 9/01 5-170


Exhibit ES-11Award-Winning CCT Program Projects

Project and Participant Award

Full-Scale Demonstration of Low-NOx Cell Burner 1994 R&D 100 Award presented by R&D magazine to the U.S. Department of Energy for development of the low-NOx cellRetrofit (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 to the U.S. Department ofon a Wall-Fired Boiler; Enhancing the Use of Coals Energy, Gas Research Institute, and U.S. Environmental Protection Agency for the development and commercialization ofby 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 Company’s Bailly GeneratingProject (Pure Air on the Lake, L.P.) Station.

1992 Outstanding Engineering Achievement Award presented by the National Society of Professional Engineers.

Demonstration of Innovative Applications of 1995 Design Award presented by the Society of Plastics Industries in recognition of the mist eliminator.Technology for the CT-121 FGD Process (Southern 1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. Co-recipient was the U.S.Company Services, Inc.) Department of Energy.

1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and Waste Management Association.

1993 Environmental Award presented by the Georgia Chamber of Commerce.

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

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 construction.

1993 Ecological Society of America Corporate Award presented to Tampa Electric for its innovative siting process.

1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of Florida for the innovative sitingprocess.

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

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 American Consulting EngineersJoint Venture) Council competition.

Development of the Coal Quality Expert™ (ABB 1996 Recognized by then Secretary of Energy Hazel O’Leary and EPRI President Richard Balzhiser as the best of nineCombustion Engineering, Inc. and CQ Inc.) DOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Program.


Exhibit ES-12PPII Technology Characteristics

Project Participant Process Page

Combustion Initiative for Innovative Cost-Effective NOx Alliant Energy Corporation Combustion Initiative method and re-engineering/modeling to 6-8Reduction 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-Catalytic 6-10Control for Orion Avon Lake Unit 9 Reduction, Selective Non-Catalytic Reduction, and Selective

Catalytic Reduction

Greenidge Multi-Pollutant Control Project CONSOL Energy, Inc. Single-bed Selective Catalytic Reduction in combination with 6-12low-NOx combustion technology to control NOx and a circulatingdry 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 6-14Hybrid Particulate Collector Technology

Achieving New Source Performance Standards Emission Sunflower Electric Power Ultra-low NOx burners with other combustion-stage controls 6-16Standards Through Integration of Low-NOx Burners with Corporationan Optimization Plan for Boiler Combustion

Polk Power Station Plant Improvement Project Tampa Electric Company Refractory lining wear monitor (project withdrawn) 6-18

Big Bend Power Station Neural Network-Sootblower Tampa Electric Company Neural-network soot-blowing system in conjunction with 6-20Optimization advanced controls and instruments

Commercial Demonstration of the Manufactured Universal Aggregates, LLC Aggregate manufacturing plant using by-products from a spray 6-22Aggregate Processing Technology Utilizing Spray Dryer dryer desulfurization unitAsh


Program Update 2001 1-1

1. Role of the CCT Program

IntroductionOver the past quarter century, both nationally and inter-nationally 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 restructur-ing, 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 Pro-gram is unprecedented. More than $5.2 billion is beingexpended, with industry and state governments invest-ing 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 them-selves in the marketplace. New technologies to reducethe emissions of acid rain precursors, namely sulfurdioxide (SO2) and NOx, are now in the marketplace andare 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 re-source—coal. Coal, which accounts for over 94 percentof the proven fossil energy reserves in the UnitedStates, supplies the bulk of the low-cost, reliable elec-tricity vital to the nation’s economy and global com-petitiveness. 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 pro-duce over 1,964 billion kilowatt-hours (net) or 52 per-cent of the nation’s electricity in 2000. The EIA projec-tions 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 electric-ity generation estimates are five percent higher than theprevious year’s estimates by EIA due to projected in-creased 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 estab-lished in current and emerging laws and regulations,and (2) operational and economic performance require-

ments consistent with competition in the era of utilityrestructuring. The CCT Program is responding to theserequirements by producing a portfolio of advancedcoal-based technologies that will enable coal to retainits prominent role in the nation’s power generationfuture. Furthermore, advanced technologies emergingfrom the CCT Program will also enhance coal’s com-petitive position in the industrial sector. For example,technology advances in steel making, involving directuse of coal, will reduce the cost of production whilegreatly improving environmental performance. Also,coal could increase its market share in the industrialsector through cogeneration (steam and electricity) andcoproduction of products (clean fuels and chemicals).

While the CCT Program responds to domestic needsfor competitive and clean coal-based technology, it alsopositions U.S. industry to compete in a burgeoningpower market abroad. Electricity continues to be themost rapidly growing form of energy consumption inthe world. Projections from EIA’s International EnergyOutlook 2001 (March 2001) (IEO2001) show electric-ity demand rising from 12.8 trillion kilowatt-hoursin 1999 to 22.2 trillion kilowatt-hours in 2020. Thestrongest growth is projected for the coal-dependentdeveloping countries of Asia. This growth not onlyrepresents a tremendous market opportunity, but anopportunity to make a reduction in global carbon emis-sions through the application of highly efficient cleancoal technologies.

1-2 Program Update 2001

CCT Program EvolutionThe environmentally sound and competitive perfor-mance of modern coal technologies has evolvedthrough many years of industry and government re-search, development, and demonstration (RD&D). Theprograms were pursued to assure that the U.S. recover-able 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 govern-ment-sponsored technology demonstrations focused onsynthetic fuels production technology. Under the En-ergy Security Act of 1980, the Synthetic Fuels Corpo-ration (SFC) was established for the purpose of reduc-ing 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 facili-ties. 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 dis-solved as oil prices declined, world oil supplies stabi-lized, 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 mar-ket 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 Ap-propriation 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. Trea-sury 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 sup-ply of energy, maintained at a reasonable cost, and con-sistent with environmental, health, and safety objectives.Energy stability, security, and strength were the founda-tions 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 thecoal resource base are well understood.

• The technology and skilled labor base to safely andeconomically extract, transport, and use coal areavailable.

• A multi-billion dollar infrastructure is in place togather, transport, and deliver this valuable energycommodity to serve the domestic and internationalmarketplace.

• Coal is used to produce over half of the nation’selectric power and is vital to industrial processes,such as steel and cement production, as well as in-dustrial power.

• This abundant fossil energy resource is securewithin the nation’s borders and relatively invulner-able 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 devel-oped economies, which provides export opportuni-ties for U.S.-developed, coal-based technologies.

Congress recognized that the continued viability ofcoal as a source of energy was dependent on the dem-onstration and commercial application of a new genera-tion of advanced coal-based technologies characterizedby enhanced operational, economic, and environmentalperformance. The CCT Program was established todemonstrate the commercial feasibility of clean coaltechnology applications in response to that need. In1986, DOE issued the first solicitation (CCT-I) forclean coal technology projects. The CCT-I solicitationresulted in a broad range of projects being selected infour major product markets—environmental controldevices, advanced electric power generation, coal pro-cessing for clean fuels, and industrial applications.

In 1987, the CCT Program became the centerpiece forsatisfying the recommendations contained in the JointReport of the Special Envoys on Acid Rain (1986). APresidential initiative launched a five-year, $5-billionU.S. government/industry effort to curb precursors toacid rain formation—SO2 and NOx. Thus, the secondsolicitation (CCT-II), issued in February 1988, pro-vided for the demonstration of technologies that werecapable of achieving significant emission reductions inSO2, NOx, or both, from existing power plants. Thesetechnologies were to be more cost-effective thancurrent technologies and capable of commercial de-ployment in the 1990s. In May 1989, DOE issued athird solicitation (CCT-III) with essentially the sameobjective as the second, but additionally encouragedtechnologies that would produce clean fuels from run-of-mine coal.

The next two solicitations recognized emerging energyand environmental issues, such as global climatechange and capping of SO2 emissions, and thusfocused on seeking highly efficient, economically com-petitive, and low-emission technologies. Specifically,the fourth solicitation (CCT-IV), released in January1991, had as its objective the demonstration of energy-efficient, economically competitive technologies ca-pable of retrofitting, repowering, or replacing existingfacilities while achieving significant reductions in SO2


and NOx emissions. In July 1992, DOE issued the fifthand final solicitation (CCT-V) to provide for demon-stration projects that significantly advanced the effi-ciency and environmental performance of technologiesapplicable to new or existing facilities. As a result ofthese five solicitations, a total of 60 government/indus-try cost-shared projects were selected, of which 38,valued at more than $5.2 billion, have either been suc-cessfully completed or remain active in the CCT Pro-gram.

The success of the government/industry CCT Programis directly attributable to the CCT Program�s respon-siveness 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 Impetus

SO2 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 emis-sions levels by using marketable allowances. The utili-ties can adopt a control strategy that is most cost-effec-tive for their given systems and plants rather than hav-ing to apply a �command-and-control� approachwherein the emission-reduction method is specified.

The emission-reduction requirements for SO2 wereinstituted 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 �affectedunits�) 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 sat-isfy 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 de-cline. 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 exist-ing 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 levelsare generally0.3 lb/106 Btu for low-sulfur coals and0.6 lb/106 Btu forhigh-sulfur coals.Moreover, the CAAAcalls for SO2 emissions

to be limited to 9.48 million tons per year between2000 and 2009 and 8.95 million tons per year thereaf-ter. EIA predicts that 11 GWe of capacity will be retro-fitted with scrubbers to meet the Phase II goals.

Several projects within the CCT Program, listed below,were designated affected units and were required toachieve compliance with Phase I requirements:

� Northern Indiana Public Service Company�s BaillyGenerating Station, 528-MWe Units Nos. 7 and 8(Pure Air advanced flue gas desulfurization scrub-ber);

� Georgia Power Company�s Plant Yates, 100-MWeUnit No. 1 (Chiyoda Thoroughbred-121 advancedflue gas desulfurization scrubber);

� New York State Electric & Gas Corporation�sMilliken Station, 300-MWe Unit Nos. 1 and 2(S-H-U formic-acid-enhanced wet limestone scrub-ber); and

Exhibit 1-1Phase I SO2 Compliance Methods

% SO2

Method No. of % of Reduction from % of TotalUnits Units 1985 Baseline SO2 Reduction

Fuel switching/blending 136 52 60 59

Additional SO2 allowances 83 32 16 9a

Scrubbers 27 10 83 28

Retirements 7 3 100 2

Otherb 8 3 86 2

Total 261 100 345 100a Includes reduced coal consumption of 2.5 million tons and 16% reduction in sulfur content.b Includes 1 repowered unit, 2 switched to natural gas, and 5 switched to No. 6 fuel oil.

Source: The Effects of Title IV of the Clean Air Act Amendments of 1990 on ElectricUtilities: An Update, Energy Information Administration, March 1997.


• PSI Energy’s Wabash River Station, 262-MWe UnitNo. 1 (repowered with Destec integrated gasifica-tion combined-cycle unit).

The three Phase I scrubber projects served to redefinethe state-of-the-art in wet limestone scrubber technol-ogy and Wabash was the first to introduce integratedgasification combined-cycle as a repowering technol-ogy. The advanced scrubbers essentially halved thecost of conventional scrubbers of the time. The repow-ering 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 compli-ance options for the diverse fleet of existing coal-firedelectric 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.

NOx RegulationAcid Rain Mitigation. In Title IV of the CAAA, Con-gress also required the EPA to establish annual allow-able emissions limitations for NOx in two phases. PhaseI required NOx reductions from tangentially fired anddry-bottom wall-fired boilers. These boilers are re-ferred to as Group 1 boilers. In March 1994, EPA pro-mulgated a rule establishing NOx emission limitationsof 0.45 lb/106 Btu for tangentially fired units and 0.50lb/106 Btu for wall-fired units. Ultimately, a compli-ance date of January 1, 1996, was established.

On December 19, 1996, EPA issued a rule to imple-ment Phase II. The rule established NOx emission limi-tations for additional coal-fired boilers (Group 2) andreduced the NOx emissions limitations on Group 1 boil-

ers. The types of Group 1 and 2 boilers and the Phase Iand 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 CCTProgram during the Southern Company Services’evaluation of NOx control technologies on wall-firedand tangentially fired boilers. Furthermore, NOx con-trols were developed under the CCT Program for allfive major boiler types (wall-fired, tangentially fired,cyclone-fired, cell-burner, and vertically fired), whichconstitute over 97 percent of existing U.S. coal-firedutility boiler types. Low-NOx burners were developedfor 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 arebeing retrofitted. TheCCT Program alsodemonstrated a rangeof NOx control tech-niques to addressboilers where burnermodification is notpractical and to pro-vide methods to en-hance NOx controlbeyond low-NOxburner capability.These options in-cluded coal and gasreburning, selectivenoncatalytic reduc-tion (SNCR), andselective catalyticreduction (SCR).This portfolio of NOxcontrols not onlyassured that Phase Iand II emission re-ductions were

achieved, but provided the technology base necessaryto develop technology capable of even greater NOxreductions required to meet new National Ambient AirQuality Standards (NAAQS) for ozone and fine par-ticulate matter under Title I of the CAAA.

Soot and Smog. In July 1997, under Title I of theCAAA, EPA issued final rules revising the primary andsecondary NAAQS for particulate matter (PM) andozone (O3) (commonly referred to as “soot and smog”regulations).

The soot provisions addressed ambient air concentra-tions of particulate matter in the respirable range of 2.5millionths of a meter (microns) in diameter or less(PM2.5). Previous fine particulate standards dealt withairborne material in the inhalable range of 10 microns

Exhibit 1-2CAAA NOx Emission Limits

Group 1 Group 2 Phase I NOx

Phase II NOx

Boiler Type Boiler Type Emission Limitsa Emission Limitsa

(lb/106Btu) (lb/106 Btu)

Tangentially firedboilers 0.45 0.40

Dry-bottom wall-fired boilersb 0.50 0.46

Cell-burnerboilers 0.68

Cyclone boiler >155 MWe 0.86

Wet-bottom wall-fired boilers>65 MWe 0.84

Vertically fired boilers 0.80aEmission limits are lb/106Btu of heat input on an annual average basis.bOther 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 ammo-nium sulfates and nitrates from precursor SO2 and NOxgases. Monitoring to ascertain PM2.5 attainment is on-going, with designations of non-attainment expected by2003–2004. State Implementation Plans (SIPs) forcompliance are expected by 2007–2008, with compli-ance by 2013–2014.

The ozone standards in turn impact NOx emissionsbecause NOx is a precursor to ozone formation. As aninterim 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 NOx emissions accord-ing to specified amounts (budgets) by May 2003. Theexpected emission limits for power plants is 0.15 lb/106

Btu, which generally requires relatively expensive se-lective 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 par-ticular area.

The EPA is also formulating a plan for utilities andindustries to trade allowances for NOx emissions. The“cap and trade” program would apply to the 23 juris-dictions 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-effec-tive manner. Power plants and industries that cut NOxemissions below the caps could sell credits to facilitiesthat could not cut emissions as quickly or cost-effec-tively. The NOx trading program, similar to the existingSO2 trading program, allows sources to pursue variouscompliance strategies, such as fuel switching; installingpollution control devices, like the devices demon-strated 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” exist-ing 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 effi-cient 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

NOx emissions at Georgia Power’s Plant Hammond werereduced by 63 percent with Foster Wheeler’s low-NOxburners, shown here, and advanced overfire air.

Low-NOx burner technologies: ABB Combustion Engineering’sLNCFS™ for tangentially fired boilers (top left), FosterWheeler’s low-NOx burner for wall-fired boilers (top right),Babcock & Wilcox’s LNCB® for cell-burner boilers (bottomright), and Babcock & Wilcox’s DRB-XCL® for down-firedboilers (bottom left).

industry to monitor HAPs emissions at CCT Programproject sites. Objectives of the HAPs monitoring are to(1) improve the quality of HAPs data being gathered,and (2) monitor a broader range of plant configurationsand emissions control equipment. As a result of thisprogram, 20 CCT projects are monitoring or havemonitored HAPs, with 15 having completed monitoringby September 2001 (see Appendix C, Exhibit C-7).

In a parallel effort begun in January 1993, EPA, withthe participation of DOE under the Coal Research andDevelopment Program, the Electric Power ResearchInstitute (EPRI), and the Utility Air Regulatory Group(UARG), began an emissions data collection programusing state-of-the-art sampling and analysis techniques.


Emissions data were collected from eight utilities rep-resenting nine process configurations, several of whichwere CCT Program projects. These utilities repre-sented different coal types, process configurations,furnace types, and pollution control methods. The re-port, 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 re-port to Congress, Study of Hazardous Air PollutantEmissions from Electric Utility Steam GeneratingUnits—Interim Final Report (final report was issuedFebruary 1998), the Mercury Study Report toCongress, 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 spe-cific 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 regula-tions 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 recommenda-tions contained in the Joint Report of the Special En-voys on Acid Rain, as discussed earlier. Moreover, asconcerns over global climate change emerged, the CCTProgram began to emphasize demonstration of ad-vanced electric power generation technology capableof achieving significantly higher efficiency than con-ventional 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, represent-ing a diversity of gasifier types and cleanup systems.

These projects are pioneering this environmentallyfriendly technology, which in addition to lower carbonemissions, boasts very low SO2 and NOx emissions. TheIGCC technology offers flexibility in that new plantscan be constructed in modules as demand dictates.Current worldwide market penetration of this technol-ogy is approximately 5 gigawatts (GW), and demand isgrowing.

Eight SCR catalysts with various shapes and compositionswere evaluated side by side at Gulf Power’s Plant Crist usinghigh-sulfur coal. NOx reductions of 80 percent were achieved.

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 na-tional 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 produc-tion of commercial-grade gypsum in lieu of the scrub-ber 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 by-products instead of wastes (e.g., sulfur, sulfuric acid, orfertilizer) or dry, environmentally benign materials.These dry materials can be used as construction materi-als (e.g., for use in soil and roadbed stabilization, or asa 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 Commu-nity Right-To-Know Act (EPCRA) and Section 6607 ofthe Pollution Prevention Act (PPA) mandate establish-ment of a publicly accessible database containing infor-mation 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 infor-mation about releases of toxic chemicals in their com-munities. 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 emis-sions 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 regu-latory requirements that would be im-posed on the industry. Even this uncer-tainty was mitigated by the fact that theenvironmental control costs could bepassed through to the consumer if ap-proved by the state regulatory commis-sion. As long as the utility made prudentinvestments in plant and equipment, itseconomic future was fairly stable andpredictable. Most industry observers

assumed that coal and nuclear energy would carry theburden of baseload generation, oil would be phasedout, and natural gas would be used for meeting peakload requirements.

By mid-1997, the picture was entirely different—theutility industry was in the midst of a major restructuringto accommodate a competitive marketplace. Underutility restructuring, power generators must assume therisk for new capacity additions. The relatively lowcapital cost and short lead times for natural gas-basedsystems make them the preferred option for the fore-seeable future. As a result, projections now call fornatural gas to be the fuel of choice for new capacityadditions through 2020. During the same period,nuclear-based capacity is projected to decline and coal-based capacity is projected to increase moderately.

Consumers also became a major factor in pushing forcompetition and regulatory reform even though regula-tors provide the oversight necessary to assure that con-sumers were paying a fair price. Under retail deregula-

Hazardous air pollutants were measured at the Babcock & WilcoxCompany’s Demonstration of Coal Reburning for Cyclone Boiler NOx Controlat Nelson Dewey Station.


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 mar-ket conditions, not necessarily according to generationcosts.

Advancement in the technology of electricity produc-tion is another factor that has had an impact on restruc-turing. 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 environ-mentally 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 util-ity market for coal and clean coal technology. A com-parison 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 restructur-ing is playing, as well as environmental regulation dis-cussed previously. According to EIA’s AEO2002, coalis 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. Utili-

ties are expected toimprove their operat-ing efficiencies byusing existing plantsat higher capacityfactors. Contributingto increased capacityfactors is a projecteddrop in generatingcapacity not onlyfrom nuclear plantretirements but ca-pacity losses fromfossil-fueled plantretirements. EIApredicts that nearly31 GW of new coal-fired capacity is ex-pected to come online between 2000and 2020, account-ing for 9 percent ofcapacity expansion.

During this time, new highly efficient low-emissionspower systems will enter the power production mar-kets. New concepts to reduce delivered electricityprices will likely be employed. Examples includeminemouth plants that reduce or eliminate the coaltransportation cost component in power production.Also, cogeneration and coproduction systems will beavailable, which allow the consumer’s cost of electric-ity potentially to be reduced by the profitability of co-products.

Ensuring SustainableEconomic GrowthIt is in the national interest to maintain a multi-fuelenergy mix to sustain national economic growth. Coalis a key component of national energy security becauseof its affordability, availability, and abundance withinthe nation’s borders. The CCT Program’s strategy leadsto the development and deployment of a technologyportfolio that enhances the efficient use of this coalresource while assuring that national and global envi-ronmental goals are achieved. The domestic coal re-sources are large enough to supply U.S. needs for morethan 250 years at current rates of production.

The United States is increasingly dependent on im-ported oil as lower average prices and increased pricevolatility have resulted in decreased domestic oil pro-duction for 13 years. That trend was broken in 1995 byan oil production capacity increase of 0.4 million bar-rels per day. In 2000, net petroleum imports were 10.4million barrels per day, or 53 percent of domestic con-sumption. The AEO2002 reference case for 2020 callsfor net imports of 16.6 million barrels per day, which isover 62 percent of the total supply. Also, natural gas

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 rep-resent 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 bil-lion/year using 2000 average oil prices. The CCT Pro-gram 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 reduc-ing 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 coalare as follows:

• World coal consumption is projected to increase by1.7 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 toincrease by 1.7 billion tons from 1.7 billion tons in1999 to 3.4 billion tons in 2020. China and Indiatogether are projected to account for 29 percent of thetotal increase in energy consumption worldwide be-tween 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 parts of the world, only a slightdrop in coal’s total energy consumption is projectedby 2020 as other fuels outpace coal. The share ofcoal in world total primary energy consumption isexpected to decline from 22 percent in 1999 to 19percent in 2020. Coal’s share of energy consumedworldwide for electricity generation is also pro-jected to decline, from 34 percent in 1999 to 31percent in 2020.

• World coal trade is projected to increase from 548million tons in 1999 to 729 million tons in 2020,accounting for between 11 and 12 percent of totalworld coal consumption over the period. Steam coal(including coal for pulverized coal injection at blastfurnaces) accounts for most of the projected in-crease in world trade. However, the United States’share of this market is forecasted to decline due tocompetition from Australia and other exportingcountries.

According to the latest DOE projections, the world-wide market for power generation technologies couldbe as high as $80 billion between 1995 and 2020. Most

Exhibit 1-3Comparison of Energy Projections for Electric Generators

Electricity Sales Coal Consumption Gas Consumption Oil Consumption

(109 kWh/yr) (106 tons/yr) (1012 ft3/yr) (106 barrels/yr)

NEPP AEO % ∆∆∆∆∆ NEPP AEO % ∆∆∆∆∆ NEPP AEO % ∆∆∆∆∆ NEPP AEO % ∆∆∆∆∆1985 2002 1985 2002 1985 2002 1985 2002

1995 3,018 3,026b 0.27 924 958b 3.7 3.0 3.37b 12 73 110b 51

2010 4,176 4,170c -0.14 1,355 1,141 -15.8 1.7 8.91 424 146 33 -77

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.


Power

Fuels

HydrogenSeparation

Electricity

Fuel Chemicals

CO2 Sequestration

Gas StreamCleanup

Gasification

OxygenMembrane

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 estab-lishing an information clearinghouse and closer liaisonwith U.S. representatives in other countries, (2)strengthening interagency coordination of federal pro-grams pertinent to theseexports, and (3) improvingcurrent programs and poli-cies for facilitating the fi-nancing of coal-relatedprojects abroad.

Looking to the Future

Power 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 grow-ing concern over the reliability of the nation’s electric-ity 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 InitiativeThe Clean Coal Power Initiative (CCPI) is a govern-ment/industry partnership to implement the President'sNational Energy Policy (NEP) recommendation to in-crease investment in clean coal technology. This recom-mendation, one of several dealing with electricity, ad-dresses the national challenge of ensuring the reliabilityof our electric supply while simultaneously protectingour environment. The CCPI is a cost-shared partnershipbetween the government and industry that implementsthe NEP recommendation to “fund research in cleancoal technology.” The goal is to accelerate commercialdeployment of advanced technologies to ensure theUnited States has clean, reliable, and affordable electric-ity. This ten-year initiative will be tentatively funded at atotal federal cost share estimated at $2 billion with amatching cost share of at least 50 percent. The Depart-ment of Energy is in the initial planning and implementa-tion phases of the CCPI program.

Vision 21The CCT Program is providing the foundation neededto build a future generation of fossil energy-basedpower systems capable of meeting the energy and envi-ronmental demands of the 21st century. The hardwareand attendant databases serve as platforms for power,environmental, and fuels systems that together canmeet the long-term goals of the Office of FossilEnergy’s Coal & Power Systems Program. These“Vision 21” goals are delineated in Exhibit 1-4. Theexpected result is a suite of technology modules ca-pable of using a broad range of fuels (coal; biomass;and forestry, agricultural, municipal, and refinerywastes) to produce a varied slate of high-value com-modities (electricity, steam, clean fuels, and chemicals)at greater than 60 percent efficiency and near-zeroemissions.

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 Pro-gram 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 intelli-gence-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 1-4Vision 21 Objectives

Efficiency—Electricity Coal-based systems 60% (HHV); natural gas-based systems 75% (LHV) withGeneration no credit for cogenerated steam.a

Efficiency—Combined Overall thermal efficiency above 85% (HHV); also meetsHeat & Power efficiency goals for electricity.a

Efficiency—Fuels Plant Only Fuel utilization efficiency of 75% (LHV) when producing coal derived fuels.a

Environmental Near-zero emissions of sulfur, nitrogen oxides, particulate matter, trace elements, andorganic 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 productscost-competitive with market clearing prices.

Timing Major spinoffs such as improved gasifiers, advanced combustors, high-temperaturefilters 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 efficiencygoal for a plant producing both electricity and fuels will be calculated on a pro-rata basis



2. CCT Program Implementation

IntroductionThe 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 performance-based 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 existsfor 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 ofyears enabled the program to address a broadrange of national needs with a portfolio of

evolving technologies. Allowing time betweensolicitations enabled Congress to adjust the goals ofthe program to meet changing national needs;provided DOE time to revise the implementationprocess based on lessons learned in priorsolicitations; and provided industry the opportunityto develop better projects and more confidentlypropose evolving technologies.

• Demonstrations are conducted at commercialscale in actual user environments. Typically, atechnology is constructed at commercial scale withfull system integration, reflective of its intendedcommercial configuration, and operated as acommercial facility or installed on an existingcommercial facility. This enables the technology’sperformance potential to be judged in the intendedcommercial environment.

• The technical agenda is determined by industryand not the government. Based on goalsestablished by Congress and policy guidancereceived, DOE set definitive performance objectivesand performance-based evaluation criteria againstwhich proposals would be judged. Industry wasgiven the flexibility to use its expertise andinnovation to define the technology and proposedproject in response to the objectives and criteria.The Department of Energy selected the projects thatbest met the evaluation criteria.

• Roles of the government and industry are clearlydefined and reflect the degree of cost-sharingrequired. The government plays a significant roleup front in structuring the cooperative agreements toprotect public interests. This includes negotiatingdefinitive performance milestones and decisionpoints throughout the project. Once the projectbegins, the industrial participant is responsible fortechnical management, while the government


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 isrequired 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 importantcheck-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 propertyrights. 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 tocommercialize 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 thetechnology, 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 Energy translated the congressionalguidance and direction into performance-based criteria,and developed approaches to address lessons learnedfrom previous solicitations. Before proceeding with asolicitation, however, an outline of the impendingsolicitation and attendant issues and options waspresented in a series of regional public meetings toobtain feedback. The public meetings were structuredalong the lines of workshops to facilitate discussionand obtain comments from the broadest range ofinterests. Comments from the public meetings thenwere used in preparing a draft solicitation, which inturn was issued for public comment. Commentsreceived were formally resolved prior to solicitationissuance.

To aid proposers, preproposal conferences were heldfor the purpose of clarifying any aspects of thesolicitation. Further, every attempt was made in thesolicitation to impart a clear understanding of what wasbeing sought, how it would be evaluated, and whatcontractual terms and conditions would apply. Asection of the solicitation was devoted to helpingpotential proposers determine technology eligibility,and numerical quantification of the evaluation criteriawas provided. The solicitation also contained a modelcooperative agreement with the key relevantcontractual terms and conditions.

Project selection and negotiation leading to award wereconducted under stringent rules carrying criminalpenalties for noncompliance. Proposals were evaluatedand projects negotiated strictly against and within thecriteria and terms and conditions established in thesolicitation. In the spirit of NEPA, information requiredand evaluated included project-specific environmental,health, safety, and socioeconomic aspects of projectimplementation.

Upon project award, another public process wasengaged to ensure that all site-specific environmentalconcerns were addressed. The National Environmen-tal Policy Act requires that a rigorous environmental


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 cost-sharing. 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 process associated with thesolicitations, parallel efforts were conducted to informstakeholders of ongoing events, results, and issues andto engage them in discussion on matters pertinent toensuring that the program remained responsive toneeds. A continuing dialog was facilitated by directinvolvement in the projects of a large number ofutilities, technology suppliers, and states, as well as keyindustry-based research organizations (e.g., the ElectricPower Research Institute and Gas Research Institute).This was accompanied by executive seminars designedto enhance communications with the utility,independent power producer, regulatory, insuranceunderwriter, and financial sectors. The approach wasto identify those sectors where inputs were missing andthen structure seminars to provide information on theprogram and obtain the executives’ perspectives andsuggestions for enhancing program performance.Furthermore, a periodic CCT Conference was institutedto serve as a forum for reporting project progress andresults and discussing issues affecting the outcome ofthe CCT Program. And, an outreach program was putin place to ensure that needed information wasprepared and disseminated in the most efficientmanner, leveraging a variety of domestic andinternational conferences, symposia, and workshops.These activities are discussed in further detail inSection 4.

During implementation of the CCT Program, manyprecedent-setting actions were taken and manyinnovations were used by both the public and privatesectors to overcome procedural problems, create newmanagement systems and controls, and move towardaccomplishment of shared objectives. The experiencedeveloped in dealing with complex businessarrangements of multimillion dollar CCT projects is asignificant asset that has contributed greatly to the CCTProgram’s success—an asset of value to otherprograms seeking to forge government/industrypartnerships. To document lessons learned, CleanCoal Technology Program Lessons Learned was

The NEPA process assured environmental acceptability of theHealy Clean Coal Project on the border of Denali NationalPark in Alaska.


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

• A timetable identifying major commercializationgoals and schedule for completion;

• Additional requirements for demonstration of thetechnology 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 senior management onaccomplishing the commercialization effort and howthe project fits into the various corporations’business, marketing, or energy utilization strategies.

The cooperative agreement contains three mechanismsto ensure that the demonstrated technology can bereplicated by responsible firms while protecting theproprietary commercial position of the technologyowner. These three mechanisms are:

Pressurized fluidized-bed combustion, like that demonstratedat Ohio Power Company’s Tidd Plant, is starting to see globalcommercialization.


� The commercialization clause requires thetechnology owner to meet U.S. market demands forthe technology on a nondiscriminatory basis (thisclause �flows down� from the project participant tothe project team members and contractors);

� The clauses concerning rights to technical data dealwith the treatment of data developed jointly in theproject as well as data brought into the project; and

� The patent clause affords protection for newinventions 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:

� Make the public and local, state, and federalgovernment policy makers aware of the CCTs andtheir operational, economic, and environmentalbenefits;

� Provide potential domestic and foreign users of thetechnologies with the information needed fordecision making;

� Inform financial institutions and insuranceunderwriters about the advancements in technologyand associated risk mitigation to increaseconfidence; and

� Provide customers and stakeholders opportunitiesfor 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)�a 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 broad-based support.Team members forthe projects includemore than 50

utilities; more than 45 technology suppliers; and morethan 20 engineering, construction, or consulting firms.Other team members include the Electric PowerResearch Institute, the Gas Research Institute,numerous state and local agencies and authorities,industrial manufacturers, and one Native Americantribe.

The contributions of the selected projects to domesticand international energy and environmental needs aresignificant. These contributions include:

� Completing demonstration and proving commercialviability of a suite of cost-effective SO2 and NOxcontrol options capable of achieving moderate (50percent) to deep (70�95 percent) emissionreductions for the full range of coal-fired boilertypes;

� Providing the database and operating experiencerequisite to making atmospheric fluidized-bedcombustion a commercial technology at utility scale;

Exhibit 2-1CCT Program Selection Process Summary

Projects inProposals Projects CCT Program as

Solicitation PON Issued Submitted Selected of Sept. 30, 2001

CCT-I February 17, 1986 51 17 8

CCT-II February 22, 1988 55 16 9

CCT-III May 1, 1989 48 13 12

CCT-IV January 17, 1991 33 9 5

CCT-V July 6, 1992 24 5 4

Total 211 60 38


Exhibit 2-2Clean Coal Technology Demonstration Projects by Solicitation

Project and Participant Location

CCT-IDevelopment of the Coal Quality Expert� (ABB Combustion Engineering, Inc. and CQ Inc.) Homer City, PA

LIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) Lorain, OH

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) Williamsport, PA

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Hennepin and Springfield, IL

Tidd PFBC Demonstration Project (The Ohio Power Company) Brilliant, OH

Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) Colstrip, MT

Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) Nucla, CO

JEA Large Scale CFB Combustion Demonstration Project (JEA) Jacksonville, FL

CCT-IISNOX� Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) Niles, OH

Demonstration of Coal Reburning for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) Cassville, WI

SOx-NOx-Rox Box� Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Dilles Bottom, OH

Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) Thomaston, ME

Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Chesterton, IN

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Coosa, GA

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Newnan, GA

Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High-Sulfur, Coal-Fired Boilers Pensacola, FL(Southern Company Services, Inc.)

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

CCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH�) Process (Air Products Liquid Phase Conversion Kingsport, TNCompany, L.P.)

10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) West Paducah, KY

Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Healy, AK

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


Exhibit 2-2 (continued)Clean Coal Technology Demonstration Projects by Solicitation

Project and Participant Location

CCT-III (continued)

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) Seward, PA

Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) Burns Harbor, IN

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland Electric) Lakeland, FL

ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Gillette, WY

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

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) Richmond, IN

Integrated Dry NOx/SO2 Emissions Control System (Public Service Company of Colorado) Denver, CO

Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Mulberry, FL

CCT-IV

Micronized Coal Reburning Demonstration for NOx Control (New York State Electric & Gas Corporation) Lansing and Rochester, NY

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) Lansing, NY

Piñon Pine IGCC Power Project (Sierra Pacific Power Company) Reno, NV

Pulse Combustor Design Qualification Test (ThermoChem, Inc.) Baltimore, MD

Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) West Terre Haute, IN

CCT-V

Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) Fairbanks, AK

Clean Power from Integrated Coal/Ore Reduction (CPICOR™) (CPICOR™ Management Company LLC) Vineyard, UT

Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) Trapp, KY

McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, Lakeland Electric) Lakeland, FL


Exhibit 2-3Geographic Locations of CCT Projects—Environmental Control Devices


Exhibit 2-4Geographic Locations of CCT Projects—Advanced Electric Power Generation


Exhibit 2-5Geographic Locations of CCT Projects—Coal Processing for Clean Fuels


Exhibit 2-6Geographic Locations of CCT Projects—Industrial Applications


� Completing demonstration of a number of coalprocesses to produce high-energy-density, low-sulfur solid fuels and clean liquids from a range ofcoal types;

� Laying the foundation for the next generation oftechnologies to meet the energy and environmentaldemands of the 21st century�three 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

� Demonstrating significant efficiency and pollutantemission reduction enhancements in steel making,advanced combustion for combined SO2/NOx/PMcontrol for industrial and small utility boilers, andinnovative SO2 control for waste elimination incement 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:

� JEA Large-scale CFB Combustion DemonstrationProject, and

� Clean Coal Diesel Demonstration Project.For the same period, the following projects arescheduled to commence construction:

� Kentucky Pioneer Energy IGCC DemonstrationProject, and

� Clean Power from Integrated Coal/Ore Reduction(CPICOR�).

In fiscal year 2002, the following project is forecastedto complete operations:

� Demonstration of Advanced CombustionTechniques 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 amountof data resulting from the demonstrations.A Comprehensive Report to Congress was issued after each

solicitation for each selected project.

Efforts will continue toward refining the effectivenessof the program in responding to customer andstakeholder needs. Toward that end, as needs change,forums will be sought to obtain feedback particularly inview of utility restructuring, continued environmentalconcerns, and a burgeoning foreign market. Objectivesare to ensure that CCT Program efforts are fullyleveraged and that follow-on efforts under the OC&PSResearch, Development, and Demonstration Programare appropriate.

Two new initiatives arising out of the President�sNational Energy Policy�Power Plant ImprovementInitiative and Clean Coal Power Initiative�will usemany of the same implementation principles as theCCT Program. These initiatives will also build uponlessons learned in the CCT Program.


3. CCT Program Funding and Costs

IntroductionCongress 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 com-bined 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 partici-pants. The data used to prepare Chapter 3 are based onthe 38 projects that were active in the CCT Program asof September 30, 2001.

Program Funding

General ProvisionsIn the CCT Program, the federal government’s contri-bution cannot exceed 50 percent of the total cost ofany individual project. The federal government’sfunding commitments and other terms of federal assis-tance are represented in a cooperative agreement nego-tiated for each project in the program. Each project

Exhibit 3-1CCT Project Costs and Cost-Sharing

(Dollars in Thousands)

Total Cost-Share Dollars Cost-Share Percent

Project Costs % DOEb Participants DOE Participants

Subprogram

CCT-I 844,363 16 239,640 604,723 28 72

CCT-II 318,577 6 139,229 179,348 44 56

CCT-III 1,325,329 26 576,918 748,411 44 56

CCT-IV 950,429 18 439,063 511,366 46 54

CCT-V 1,765,009 34 360,982 1,404,027 20 80

Totala 5,203,707 100 1,755,832 3,447,875 34 66

Application Category

Advanced Electric Power 2,864,284 55 1,118,865 1,745,419 39 61Generation

Environmental Control Devices 620,110 12 252,866 367,244 41 59

Coal Processing for Clean Fuels 431,810 8 192,029 239,781 44 56

Industrial Applications 1,287,503 25 192,072 1,095,431 15 85

Totala 5,203,707 100 1,755,832 3,447,875 34 66

a Totals may not add due to rounding.b DOE share does not include $99,840,000 obligated for withdrawn projects and audit expenses.


also has an agreement for the federal government torecoup up to the full amount of the federalgovernment�s 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 nation�s coal resources.

The project participant has primary responsibility forthe project. The federal government monitors projectactivities, provides technical advice, and assessesprogress by periodically reviewing project perfor-mance 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 ap-propriation acts and adjustments. (See Appendix A forlegislative history and excerpts from the relevant fund-ing legislation.)

Exhibit 3-2 presents the allocation of appropriatedCCT Program funds (after adjustment) and the amountavailable for each CCT solicitation. Additional activi-ties funded by CCT Program appropriations are theSmall Business Innovation Research (SBIR) Program,the Small Business Technology Transfer (STTR) Pro-gram, and CCT Program direction. The SBIR Programimplements the Small Business Innovation Develop-ment Act of 1982 and provides a role for small, inno-vative firms in selected research and development(R&D) areas. The STTR Program implements the

Small Business Technology Transfer Act of 1992that establishes a pilot program and funding forsmall business concerns performing cooperative R&Defforts.

The CCT Program direction budget provides for themanagement and administrative costs of the programand includes federal employees� salaries, benefits, andtravel, site support services, and services provided bynational laboratories and private firms.

Availability of FundingAlthough all funds necessary to implement the entireCCT Program were appropriated by Congress prior toFY1990, the legislation also directed that these fundsbe made available (i.e., apportioned) to DOE on atime-phased basis. Exhibit 3-3 depicts this apportion-ment of funding to DOE. Exhibit 3-3 also shows theprogram�s yearly funding profile by appropriations actand by subprogram. Funds can be transferred amongsubprogram budgets to meet project and programneeds.

Use of Appropriated FundsThere are five key financial terms used by the govern-ment to track the status and use of appropriated funds:(1) budget authority, (2) commitments, (3) obligations,(4) costs, and (5) expenditures. The definition of eachof these terms is given below.

� Budget Authority. This is the legal authorizationcreated by legislation (i.e., an appropriations act)that permits the federal government to obligatefunds.

� Commitments. Within the context of the CCT Pro-gram, a commitment is established when DOEselects a project for negotiation. The commitmentamount is equal to DOE�s share of the project costscontained in the cooperative agreement.

Exhibit 3-2Relationship Between Appropriations and Subprogram Budgets

for the CCT Program(Dollars in Thousands)

SBIR ProgramAppropriation Adjusted & STTR Direction ProjectsEnacted 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 32,512 434,646

P.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 1,911,929a 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 3-3Annual CCT Program Funding by Appropriations and Subprogram Budgets


Fiscal Year 1986–93 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 Totald

Adjusted Appropriationsa

P.L. 99-190 397,600 (17,000) 380,600

P.L. 100-202 574,997 (101,000) (40,000) 9,962 14,980 15,000 473,939

P.L. 100-446 574,998 (156,000) 156,000 (33,700) 541,298

P.L. 101-121b 350,000 100,000 18,000 50,000 (91,000) (162,000) 27,000 40,000 332,000

P.L. 101-121b 100,000 125,000 19,121 100,000 105,879 450,000

Total 1,997,595 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 8,980 8,300 40,000 2,177,837

Subprogram BudgetsCCT-I Projects 387,231 (18,000) (18,000) (33,000) (15,000) (14,900) (14,400) (14,000) (14,000) 245,931

CCT-II Projects 535,704 (101,000) (40,000) 9,962 14,980 15,000 434,646

CCT-III Projects 545,544 (156,000) 156,000 (33,700) 511,844

CCT-IV Projects 320,938 98,450 17,622 48,925 (91,000) (162,000) 27,000 40,000 299,935

CCT-V Projects 74,062 123,063 18,719 97,850 105,879 419,573

Projects Subtotal 1,863,479 221,513 18,341 128,775 (18,121) (116,000) (54,900) (160,438) (5,020) (5,700) 40,000 1,911,929

Program Direction 110,527 18,000 18,000 16,000 15,000 14,900 14,400 14,000 14,000 234,827

Fossil Energy Subtotal 1,974,006 221,513 36,341 146,775 (2,121) (101,000) (40,000) (146,038) 8,980 8,300 40,000 2,146,756

SBIR & STTRc 23,589 3,487 779 3,225 31,081

Totald 1,997,595 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 8,980 8,300 40,000 2,177,837

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, 105-277, 106-113, 106-291, and 107-63.c Small Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs.d Totals may not appear to add due to rounding.


• Obligations. The cooperative agreement for eachproject 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 coop-erative agreement.

• Costs. A request for payment submitted by theproject 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 in-voice.

• Expenditures. Expenditures represent paymentamounts to the project participant from checksdrawn upon the U.S. Treasury.

The full government cost-share specified in the coop-erative agreement is considered committed to eachproject. However, DOE obligates funds for the projectin increments. Most projects are subdivided into sev-eral time and funding intervals, or budget periods. Thenumber of budget periods is determined during nego-tiations and is incorporated into the cooperative agree-ment. DOE obligates sufficient funds at the beginningof each budget period to cover the government’s cost-share 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 Ex-hibit 3-4 are based on individual project schedules andbudget periods as defined in the cooperative agree-ments and modifications. The negative Budget

Authority values shown in Exhibit 3-4 result from re-scission 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 fund-ing is presented in Exhibits 3-6 and 3-7.

Cost-SharingA characteristic feature of the CCT Program is thecooperative funding agreement between the participantand the federal government referred to as cost-sharing.This cost-sharing approach, as implemented in theCCT Program, was introduced in Public Law 99-190,An Act Making Appropriations for the Department ofthe Interior and Related Agencies for the Fiscal YearEnding September 30, 1986, and for Other Purposes.General concepts and requirements of the cost-sharingprinciple as applied to the CCT Program include thefollowing elements:

• The federal government may not finance more than50 percent of the total costs of a project;

Exhibit 3-4CCT Financial Projectionsa

as of September 30, 2001

aIncludes changes resulting from P.L. 107-63.


Exhibit 3-5Financial Status of the CCT Program as of September 30, 2001c


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 511,844 511,844 592,307 592,307 490,430

CCT-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 1,411,199

SBIR & 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 Sequence

FY Annual Cumulative

1986 99,400 99,400

1987 149,100 248,500

1988 199,100 447,600

1989 190,000 637,600

1990 554,000 1,191,600

1991 390,995 1,582,595

1992 415,000 1,997,595

1993 0 1,997,595

1994 225,000 2,222,595

1995 37,121 2,259,716

1996 150,000 2,409,716

1997 (2,121) 2,407,595

1998 (101,000) 2,306,595

1999 (40,000) 2,266,595

2000 (146,038) 2,120,557

2001 8,980 2,129,537

2002 8,300 2,137,837

2003 40,000 2,177,837


Exhibit 3-6CCT Project Schedules by Application Category

Calendar Year


Exhibit 3-6 (continued)CCT Project Schedules by Application Category

Calendar Year


Exhibit 3-7CCT Project Funding by Application Category

Project DOE % Participant % Total


SO2 Control Technologies10-MWe Demonstration of Gas Suspension Absorption 2,315,259 30.0 5,401,930 70.0 7,717,189

Confined Zone Dispersion Flue Gas Desulfurization Demonstration 5,205,800 50.0 5,205,800 50.0 10,411,600

LIFAC Sorbent Injection Desulfurization Demonstration Project 10,636,864 49.7 10,756,908 50.3 21,393,772

Advanced Flue Gas Desulfurization Demonstration Project 63,913,200 42.1 87,794,698 57.9 151,707,898

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process 21,085,211 49.0 21,989,785 51.0 43,074,996

Subtotal SO2 Control Technology 103,156,334 44.0 131,149,121 56.0 234,305,455

NOx Control TechnologiesDemonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 6,553,526 41.3 9,300,374 58.7 15,853,900

Demonstration of Coal Reburning for Cyclone Boiler NOx Control 6,340,787 46.5 7,305,822 53.5 13,646,609

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit 5,442,800 48.5 5,790,592 51.5 11,233,392

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler 8,895,790 50.0 8,911,468 50.0 17,807,258

Micronized Coal Reburning Demonstration for NOx Control 2,701,011 29.7 6,395,475 70.3 9,096,486

Demonstration of Selective Catalytic Reduction Technology 9,406,673 40.5 13,823,056 59.5 23,229,729for the Control of NOx Emissions from High-Sulfur, Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion 4,149,383 48.5 4,404,282 51.5 8,553,665Techniques for the Reduction of NOx Emissions from Coal-Fired Boilers

Subtotal NOx Control Technology 43,489,970 43.7 55,931,069 56.3 99,421,039

Combined SO2/NOx Control TechnologiesSNOX™ Flue Gas Cleaning Demonstration Project 15,719,200 50.0 15,719,208 50.0 31,438,408

LIMB Demonstration Project Extension and Coolside Demonstration 7,591,655 39.3 11,719,378 60.7 19,311,033

SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstration Project 6,078,402 45.8 7,193,219 54.2 13,271,621

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection 18,747,816 49.9 18,841,139 50.1 37,588,955

Milliken Clean Coal Technology Demonstration Project 45,000,000 28.4 113,607,807 71.6 158,607,807

Integrated Dry NOx/SO2 Emissions Control System 13,082,653 50.0 13,082,653 50.0 26,165,306

Subtotal Combined SO2/NOx Control Technologies 106,219,726 37.1 180,163,404 62.9 286,383,130

Total Environmental Controls 252,866,030 40.8 367,243,594 59.2 620,109,624


Exhibit 3-7 (continued)CCT Project Funding by Application Category

Project DOE % Participant % Total


Fluidized-Bed CombustionMcIntosh Unit 4A PCFB Demonstration Project 93,252,864 50.0 93,335,136 50.0 186,588,000McIntosh Unit 4B Topped PCFB Demonstration Project 109,608,507 49.9 110,027,039 50.1 219,635,546JEA Large-Scale CFB Combustion Demonstration Project 74,733,833 24.2 234,362,679 75.8 309,096,512Tidd PFBC Demonstration Project 66,956,993 35.3 122,929,346 64.7 189,886,339Nucla CFB Demonstration Project 17,130,411 10.7 142,919,538 89.3 160,049,949Subtotal Fluidized-Bed Combustion 361,682,608 34.0 703,573,738 66.0 1,065,256,346Integrated Gasification Combined-CycleKentucky Pioneer Energy IGCC Demonstration Project 78,086,357 18.1 353,846,225 81.9 431,932,582Piñon Pine IGCC Power Project 167,956,500 50.0 167,956,500 50.0 335,913,000Tampa Electric Integrated Gasification Combined-Cycle Project 150,894,223 49.8 152,394,223 50.2 303,288,446Wabash River Coal Gasification Repowering Project 219,100,000 50.0 219,100,000 50.0 438,200,000Subtotal Integrated Gasification Combined-Cycle 616,037,080 40.8 893,296,948 59.2 1,509,334,028Advanced Combustion/Heat EnginesClean Coal Diesel Demonstration Project 23,818,000 50.0 23,818,000 50.0 47,636,000Healy Clean Coal Project 117,327,000 48.5 124,731,000 51.5 242,058,000Subtotal Advanced Combustion/Heat Engines 141,145,000 48.7 148,549,000 51.3 289,694,000Total Advanced Electric Power Generation 1,118,864,688 39.1 1,745,419,686 60.9 2,864,284,374Coal Processing for Clean Fuels

Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process 92,708,370 43.4 120,991,630 56.6 213,700,000Advanced Coal Conversion Process Demonstration 43,125,000 40.8 62,575,000 59.2 105,700,000Development of the Coal Quality Expert™ 10,863,911 50.0 10,882,093 50.0 21,746,004ENCOAL® Mild Coal Gasification Project 45,332,000 50.0 45,332,000 50.0 90,664,000Total Coal Processing for Clean Fuels 192,029,281 44.5 239,780,723 55.5 431,810,004Industrial Applications

Clean Power from Integrated Coal/Ore Reduction (CPICOR™) 149,469,242 14.0 916,335,758 86.0 1,065,805,000Pulse Combustor Design Qualification Test 4,306,027 50.0 4,306,027 50.0 8,612,054Blast Furnace Granular-Coal Injection System Demonstration Project 31,824,118 16.4 162,477,672 83.6 194,301,790Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 490,122 49.8 494,272 50.2 984,394Cement Kiln Flue Gas Recovery Scrubber 5,982,592 33.6 11,817,408 66.4 17,800,000Total Industrial Applications 192,072,101 14.9 1,095,431,137 85.1 1,287,503,238Grand Total 1,755,832,100 33.7 3,447,875,140 66.3 5,203,707,240


• Cost-sharing by the project participants is requiredthroughout the project (design, construction, andoperation);

• The federal government may share in project costgrowth (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 mustoccur as project expenses are incurred and cannotbe offset or delayed based on prospective projectrevenues, proceeds, or royalties; and

• Investment in existing facilities, equipment, or pre-viously expended R&D funds are not allowed forthe 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 out-lining 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 rev-enues 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-by-project 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 market-place. 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 Asso-ciation, Inc.); Full-Scale Demonstration of Low-NOxCell Burner Retrofit (The Babcock & Wilcox Com-pany); Development of the Coal Quality Expert™(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 set forth in General AccountingOffice (GAO) Report RCED-92-17, GAO ReportRCED-96-141, and Inspector General Audit ReportIG-0391 relative to recoupment; and (3) provided inputinto DOE deliberations on recoupment policy.


4. CCT Program Accomplishments

IntroductionDuring fiscal year 2001, by the following demonstra-tions completing operations:

• Piñon Pine IGCC Power Project,• Advanced Coal Conversion Process Demonstration,• Tampa Electric Integrated Gasification Combined-

Cycle 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 util-ity restructuring have on the demand for clean coaltechnologies. Internationally, activities include partici-pating 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 interna-tional 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 pub-lished in the same period, along with the sixth annualedition of the Clean Coal Today Index, which cross-references all articles published in the newsletter. Two12-page Project Performance Summary documentswere issued for the Demonstration of Advanced Com-bustion 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 Ben-efits 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 commer-cialization 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 produced during fiscal year 2001.


in the late 1970s and early 1980s provided a solid foun-dation for demonstrations in the CCT Program as evi-denced 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 �played a major role� in AFBC,

PFBC, and IGCC RD&D, all of which have receivedfunding from the CCT Program. The NRC also creditsDOE with benefits associated with NOx control R&Dbecause the research has resulted in technologies thatallow power plant operators the opportunity to morecost-effectively control NOx emission beyond existing

environmental requirements. Many of these accomplish-ments are directly related to the CCT Program.

In the area of NOx control technology, low-NOx burnerswere developed for all boiler types compatible withreconfiguring the burners, enabling these boilers to cost-effectively comply with 1996 and 2000 emission stan-

Exhibit 4-1National Research Council Conclusions on Fossil Energy Researcha

Technology Role Comments

Atmospheric Fluidized-Bed Majorb In the development and demonstration of industrial-scale systems using low-valued, low-cost fuels (culm, petroleum coke, andCombustion 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 demonstrations (DOE providedCombustion 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 production and environmentalCombined-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 technologies developed by industry.

Indirect Liquefaction Significant In basic, pilot-scale, and bench-scale research and development that improved the technologies developed by industry and keepDOE current.

Coal Preparation Significant In improving the removal efficiencies of ash, sulfur, and other impurities through fine grinding of coal and advanced separationtechniques.

Flue Gas Desulfurization Significant In the development and, more importantly, the demonstration of second-generation systems that offer improved process technology,removal efficiency improvements, and the ability to control emissions from a wider variety of boilers using a wider variety of coalsthan conventional systems.

NOx Control Systems Significant In the development and, more importantly, the demonstration of second-generation systems that offer reliable process technology,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 advanced technologies for wastes, andresearching 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 determining their fate) and inToxic Substances in the Atmosphere conducting research on technologies that could remove the toxic elements from the coal feed and flue gas.

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 Pro-gram developed reburning technology for NOx controlfor 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 incor-porate SCR technology by 2004. The SCR sales through2000 reached $2.7 billion.

Advanced wet flue gas desulfurization projects demon-strated in the CCT Program redefined the state-of-the-art 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 technolo-gies were demonstrated that provided SO2 removal upto 90 percent for older, smaller, space constrainedplants. Technology sales for SO2 control technologiesprimarily have been overseas, but an estimated 30 per-cent 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 is-sues 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 mea-sure 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 operat-ing 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 feed-stock. 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 demonstra-tion, another major steel producer replicated the tech-nology at a high-volume production facility.

The specific technology successes described later inthis chapter underscore the effectiveness of the govern-ment/industry partnerships forged and the importanceof a market-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 ofinstitutional successes associated with the CCT Pro-gram. For example, the General Accounting Office hasdescribed the CCT Program as one of the most suc-cessful government/industry partnerships. Congresshas recognized the success of the CCT Program andhas adapted the program's general principles to thePower Plant Improvement Initiative and the Clean CoalPower Initiative. The Department of Energy hasadapted the same principles to other programs.

The Tampa IGCC plant at night.


Marketplace CommitmentCommensurate with CCT Program commercializationgoals, the majority of the projects involve demonstra-tions at commercial scale, providing the opportunityfor the participants to continue operation of the demon-strated 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:

� Create jobs,� Improve the environment,� Reduce the cost of compliance with environmental

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

services and equipment.Reflecting the marketplace commitment, the CCTprojects are organized within four major product lines�environmental 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 technol-ogy 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 controltechnologies. Also, the utilities are awaiting the outcomeof PM2.5 and other regulatory actions that may signifi-cantly impact SO2 compliance requirements. Similarly,there has been no domestic market for advanced tech-nologies 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 emis-sion requirements for NOx. Until recently, the more ag-gressive, 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. Begin-ning as early as 2003, new NAAQS for PM2.5 and ozone,

and the associated EPA �SIP Call� will require applica-tion of the deeper SO2, NOx, and particulate controlmeasures, like those emerging from the CCT Program.The EIA estimates that 23 gigawatts of scrubber capac-ity will be in place by 2020.

The domestic market has not been conducive to theintroduction of advanced coal-based power generationtechnologies. Uncertainty in the domestic power mar-kets due to utility restructuring and increasingly strin-gent emission standards have combined with relativelylow natural gas prices to discourage investments in coalplants. Successfully demonstrated technologies likeIGCC and PFBC have realized commercial sales butonly overseas.

The market is changing. Increasing demand for electricpower generation, rising natural gas prices, and theincreasing importance being placed on fuel diversityare placing a premium on retaining existing coal-firedelectric capacity and making coal-based power genera-tion a solid option for capacity additions. For theexisting plants, investments will likely be made in thecontrol measures needed to meet emissions compliancerequirements.

For capacity additions, only advanced coal-based powergeneration systems, such as IGCC, PFBC, and derivativetechnologies, can meet projected emission standards andaddress concerns over global climate change.

Environmental Control DevicesAll but 1 of the 19 environmental control deviceprojects have now completed operations. The com-pleted demonstrations proved commercial viability ofa suite of cost-effective SO2 and NOx control optionsfor the full range of coal-fired boiler types. Risk wassignificantly mitigated in successfully applying thetechnologies commercially, because of the extensivedatabases and attendant predictive models developedthrough the demonstrations. Also, projects wereleveraged to provide input in formulating NOx controlrequirements under the CAAA and to evaluate the im-

SO2 control technologies: AirPol (left), CT-121 (center), and LIFAC (right).


pact of emerging issues, such as air toxics, on the exist-ing 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 suppli-ers have realized commercial sales.

SO2 Control Technologies. All five SO2 control tech-nology demonstrations have completed operations,evaluating three basic approaches to address thediverse coal-fired boiler population: (1) sorbent injec-tion, (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 efficienciesin the range of 50 to 70 percent. These systems holdparticular promise for the older, smaller units, par-ticularly those with space constraints.

• A moderate-capital-cost gas-suspension-absorptionsystem, 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 limi-tations.

• 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, dem-onstrated SO2 capture efficiencies in the range of 90to 95 percent. These systems are primarily appli-cable 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 vol-umes 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 require-ments. The AFGD testing also established that wall-board-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., pre-quenching for chloride removal and flue gas reheat).

The AFGD demonstration by Southern Company Ser-vices using Chiyoda CT-121 showed that the systemcould significantly enhance particulate control. PureAir on the Lake, L.P., introduced an innovative busi-ness 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 con-trol 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 formulat-ing NOx provisions under the CAAA. ABB Combus-tion Engineering’s LNCFS™ proved effective for

tangentially fired boilers and realized commercialacceptance, as did Foster Wheeler’s Controlled Flow/Split Flame and Babcock & Wilcox’s DRB-XCL® low-NOx burners for wall-fired boilers. The Babcock &Wilcox Company’s low-NOx cell burner, LNCB®,provided an effective low-cost plug-in NOx controlsystem for cell-burner boilers, which are known fortheir inherently high NOx emissions.

Integration of neural-network systems into digitalboiler controls, such as the Generic NOx Control Intel-ligent System (GNOCIS) installed at Plant Hammond,demonstrated effective optimization of parameters forNOx control and boiler performance under load-fol-lowing operations.

The Babcock & Wilcox Company’s coal reburningtechnology proved not only to be an effective way tocontrol NOx on cyclone boilers, but a means to avoidderating cyclone boilers when switching to low-sulfur,low-rank western coals. Energy and EnvironmentalResearch Corporation’s use of gas reburning, appli-cable to all boiler types, introduced an alternative toSCR for high NOx emission reduction, particularlywhen used with low-NOx burners.

In another project, comparative analyses were conductedon a range of SCR catalysts using high-sulfur U.S. coals,providing needed insight into the environmental andeconomic performance potential of SCR. Other SCRsystems and selective non-catalytic reduction (SNCR)systems were demonstrated in conjunction with com-bined SO2/NOx control technologies.

Commercialization successes to date for the NOx con-trol technologies are summarized in Exhibit 4-3.

Combined SO2/NOx Control Technologies. All sevenof the combined SO2/NOx control technology demon-strations have successfully completed operations.The demonstrations evaluated a multiplicity of comple-mentary and synergistic control methods to achieve cost-effective SO2 and NOx emissions reductions.


Exhibit 4-2Commercial Successes—SO2 Control Technology


10-MWe Demonstration of Gas Suspension Absorption Sold domestically and internationally. GSA market entry was significantly enhanced with the sale of a 50-MWe(AirPol, Inc.) unit, worth $12.5 million, to the city of Hamilton, Ohio, subsidized by the Ohio Coal Development Office. A sale

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

Confined Zone Dispersion Flue Gas Desulfurization No sales reported. CZD/FGD can be used to retrofit existing plants or for new installations at a cost of aboutDemonstration (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 plant using high-sulfur (2.0-2.9%)

coal. The LIFAC system has been retained for commercial use by Richmond Power & Light at Whitewater ValleyStation, Unit No. 2. There are 10 full-scale LIFAC units in operation in Canada, China, Finland, Russia, Japan, and theUnited States, including 5 projects started before the CCT Program. For three sales in China, 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 Public Service Company’s(Pure Air on the Lake, L.P.) Bailly Generating Station. Gypsum produced by the PowerChip® process is being sold commercially. The estimated

value for 17 years of continued scrubber operations roughly equals the value of the project. FLS miljo, a Copenhagen-based licensee, is currently working on a potential $60 million project in Kentucky using the next generation of thistechnology.

Demonstration of Innovative Applications of Sold internationally. Plant Yates continues to operate with the CT-121 scrubber as an integral part of the site’sTechnology for the CT-121 FGD Process CAAA compliance strategy. There are now 22 CT-121 plants in the planning, construction, or operational phase(Southern Company Services, Inc.) worldwide. There are 17 CT-121 plants operating in Japan, Australia, Canada, the Czech Republic, Korea, Denmark,

Malaysia, and Kuwait. The value of these 17 plants is estimated at $2.03 billion. For the projects in the planning stage,the value is estimated at $880 million.


Exhibit 4-3Commercial Successes—NOx Control Technology


Micronized Coal Reburning Demonstration for NOx Control No sales reported. Technology retained for commercial use at Kodak Park Power Plant.(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 and Light Company’s Nelson(The Babcock & Wilcox Company) Dewey Station.

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit Sold domestically. Dayton Power & Light has retained the LNCB® for use in commercial service. Seven(The Babcock & Wilcox Company) commercial contracts have been awarded for 196 burners or 5,475 MWe of capacity, valued at $30 million.

Evaluation of Gas Reburning and Low-NOx Burners on a Sold domestically and internationally. Public Service Company of Colorado, the host utility, decided toWall-Fired Boiler (Energy and Environmental Research retain the low-NOx burners and the gas-reburning system for immediate use; however, a restoration was required

to Corporation) remove the flue gas recirculation system. Since the CCT Program, the participant has installed oris in the process of installing the gas reburning or the gas reburning-low-NOx burner technology on 14 boilersrepresenting 4,814 MWe of capacity. Most of the sites are domestic, but one site is the Ladyzkin Power Station inLadyzkin, Ukraine.

Demonstration of Selective Catalytic Reduction Technology Sold domestically and internationally. Since the project was initiated, revenues from SCR sales achievedfor the Control of NOx 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. LNCFS™ has been retained at the host site for commercial use. AlstomCombustion Techniques for the Reduction of NOx Emissions from Power has sold about 63 GWe of LNCFS™ burners. Of this amount, about 49 GWe are equipped with overfire airCoal-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 commercial use. Fosterfor a Wall-Fired Boiler (Southern Company Services, Inc.) Wheeler has equipped 101 boilers with low-NOx burner technology—a total of over 1,447 burners representing

over 26,105 MWe capacity valued at $83 million. Foreign sales make up 35 percent of the commercial market.Twenty-six commercial installations of GNOCIS, the associated AI control system, are underway or planned. Thisrepresents over 12,000 MWe of capacity. In a strict sense, this project has not been completed; it has been extendedto apply GNOCIS to other pieces of plant equipment, which may increase its commercial potential.


A catalytic process developed by Haldor Topsoe a/s,SNOX�, consistently achieved 95 and 94 percent SO2and NOx reductions, respectively. The process alsodemonstrated excellent particulate control, while pro-ducing 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 burnerswith SNCR resulted in NOx emission reductions ofgreater than 80 percent. The SNCR process interactedsynergistically with sorbent injection to reduce ammo-nia slip and lower NOx emissions. Sodium-based sor-bent 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 scrub-bing 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 Com-bustion Engineering, Inc.�s LNCFS� burners. DHRTechnologies supplied a plant optimization controlsystem known as the Plant Emission Optimization Ad-visor or PEOA�, which has been sold to a number ofusers in the power industry.

The Babcock & Wilcox Company�s SOx-NOx-RoxBox�, an integration of a newly developed high-tem-perature 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 per-cent 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-XCL® advanced low-NOx burners reduced NOx emissions by 45 percent.

Energy and Environmental Research Corporation�sdemonstration of gas reburning and sorbent injectionshowed that: (1) NOx reductions greater than 60 per-cent could be achieved with only 13 percent natural gasheat input, and (2) SO2 removal of over 55 percentcould be achieved by using special sorbents.

Commercialization successes to date for the combinedSO2 and NOx control technologies are summarized inExhibit 4-4.

Advanced Electric Power GenerationPollution control was the priority early in the CCTProgram. This program emphasis included technolo-gies 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 repre-sents a major undertaking. This recognition led to earlyawards of three key repowering projects�two 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-emis-sion power generation technologies for both repower-

ing and new power generation. This emphasis wasdeemed essential to enable coal to fulfill its projectedcontribution to the nation�s energy mix well into the21st century. Environmental issues included a growingconcern over greenhouse gas emissions, capping ofSO2 emissions, increasing attention to NOx in ozonenonattainment areas, and recognizing fine particulateemissions (respirable particulates) as a significanthealth threat. These issues prompted follow-on projectsin PFBC, initiation of projects in IGCC, and projects inadvanced combustion and heat engines.

Fluidized-Bed Combustion. The Tri-State Generationand Transmission Association, Inc.�s Nucla Stationrepowering project provided the database and operat-ing experience requisite to making ACFB a commer-cial technology option at utility scale. At 110 MWe,the Nucla ACFB unit was more than 40 percent largerthan any other ACFB at that time. Up to 95 percentSO2 removal was achieved during the 15,700 hours ofdemonstration, and NOx emissions averaged a verylow 0.18 lb/106 Btu. The thrust of this effort was tofully evaluate the environmental, operational, and eco-nomic performance of ACFB. As a result, the mostcomprehensive database on ACFB technology avail-able at the time was developed. Based on this knowl-edge, commercial units were offered and built.

While the Nucla project established commercial accep-tance of ACFB at moderate utility capacities, a secondCCT demonstration project, located in Jacksonville,Florida, is carrying on where Nucla left off. JEA (for-merly Jacksonville Electric Authority) is building a300-MWe plant, which will have the distinction ofbeing the largest ACFB in the world, as well as one ofthe cleanest.

Today, every major U.S. boiler manufacturer offers anACFB in its product line. There are now more than 120fluidized-bed combustion boilers of varying capacitiesoperating in the United States, and the technology hasmade significant market penetration abroad.

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


Exhibit 4-4Commercial Successes—Combined SO2/NOx Control Technology


SNOX™ Flue Gas Cleaning Demonstration Project (ABB International use. The host utility, Ohio Edison, is retaining the SNOX™ technology as a permanent part of theEnvironmental Systems) pollution control system at Niles Station to help meet its overall SO2 and NOx reduction goals. Commercial SNOX™

plants are also operating in Denmark and Sicily. In Denmark, a 305-MWe plant has operated since August 1991.The boiler at this plant burns coals from various suppliers around the world, including the United States; the coalscontain 0.5-3.0% sulfur. The plant in Sicily, in operation since March 1991, has a capacity of about 30 MWe andfires petroleum coke.

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

value of $388 million.

SOx-NOx-Rox Box™ Flue Gas Cleanup No sales reported. Commercialization of the technology is expected to develop with an initial larger scale applicationDemonstration Project (The Babcock & Wilcox Company) equivalent to 50-100 MWe. The focus of marketing efforts is being tailored to match the specific needs of potential

industrial, utility, and independent power producers for both retrofit and new plant construction. SNRB™ is a flexibletechnology that can be tailored to maximize control of SO2, NOx, particulate, or combined emissions to meet currentperformance 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 Water, Light & Power has retainedSorbent Injection (Energy and Environmental Research the full technology for commercial use. (See Evaluation of Gas Reburning and Low-NOx Burner on a Wall-FiredCorporation) 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 Optimization Advisor, with an estimated(New York State Electric & Gas Corporation) value of $280,000, have been sold. A U.S. company, SHN, has been established to market the S-H-U scrubber. SHN

is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABB Combustion Engineering hasmodified 116 units representing over 25,000 MWe with LNCFS™ or its derivative TFS 2000™.

Integrated Dry NOx/SO2 Emissions Control System Sold domestically. The technology was retained by Public Service Company of Colorado for commercial service at its(Public Service Company of Colorado) Arapahoe Station. Babcock & Wilcox has sales of 2,805 DRB-XCL® burners for 38,284 MWe of capacity. The low-

NOx burners have an estimated value of $388 million.


Through the Ohio Power Company’s repowering of theTidd Plant (70 MWe), the potential of pressurized fluid-ized-bed combustion (PFBC) as a high-efficiency, low-emission technology was established, and the foundationwas laid for commercialization. This was the first utility-scale PFBC system in the United States. Efforts werefocused on fully evaluating the performance potential.Over 11,400 hours of operation, the technology success-fully demonstrated SO2 removal efficiencies up to 95percent with very high sorbent utilization (calcium-to-sulfur molar ratio of 1.5), and NOx emissions in therange 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 ex-changer. 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 King-dom, Italy, Japan, and Israel.

Plans are for two ongoing interrelated projects, McIn-tosh 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 second-generation 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 gas-ifier types, cleanup systems, and applications. PSIEnergy’s 262-MWe Wabash River Coal GasificationRepowering Project began operation in November1995, completed demonstration operations in Decem-ber 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 opera-tions in September 2001, and now operates in commer-cial 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 Sta-tion began operations in January 1998, and completeddemonstration operations in January 2001. The com-bined-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 an-other 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 gasifi-cation fuel cell (IGFC) system. IGFC has the potentialto achieve efficiencies up to 52 percent.

Commercial configurations resulting from the currentIGCC and PFBC demonstrations will typically haveefficiencies at least 20 percent greater than conventionalcoal-fired systems (with like CO2 emissionreductions), remove 95 to 99 percent of the SO2,reduce NOx emissions to levels well within NSPS, re-duce particulate emissions by one-third to one-tenth thatcurrently allowed under the CAAA, and produce salableby-products from solid residues as opposed to waste.

Advanced Combustion/Heat Engines. Two projectsare demonstrating advanced combustion/heat enginetechnology. The Healy Clean Coal Project demonstratedTRW’s entrained (slagging) combustor combined withBabcock & Wilcox’s spray-dryer absorber using sorbentrecycle. Operations were completed in December 2000.

Three IGCC plants have completed operations: TampaElectric (top), Piñon Pine (middle), and Wabash River(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 forparticulates. Permit levels are 0.35 lb/106 Btu for NOx,0.086 lb/106 Btu for SO2, and 0.03 lb/106 Btu for par-ticulates because of the plant’s proximity to a nationalpark.

The Clean Coal Diesel Demonstration Project is evaluat-ing 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, envi-ronmentally 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 in-ternationally.

The ENCOAL and Western SynCoal LLC projects arebreaking down the barrier to using the nation’s vastlow-sulfur but low-energy-density western coal re-sources. 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 feasi-bility 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 low-rank coals. The advanced coal conversion process(ACCP) upgrades low-rank coal to produce a low-sulfur(as low as 0.3 percent sulfur) SynCoal® product having 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 topurchase the product.

Air Products Liquid Phase Conversion Company, L.P.,is demonstrating the LPMEOH™ process to producemethanol from coal-derived synthesis gas. TheLPMEOH™ process has been developed to enhanceintegrated gasification combined-cycle power genera-tion facilities by co-producing a clean-burning storableliquid fuel from coal-derived synthesis gas. Theproduction of dimethyl ether (DME) as a mixed co-product 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 ad-ditive. Since startup, the LPMEOH™ demonstrationunit has produced over 80 million gallons of methanol,all of which was accepted by Eastman Chemical Com-pany 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 per-cent/day.

ABB Combustion Engineering, Inc. and CQ Inc.developed the PC-based software, Coal QualityExpert™ (CQE™), to assist utilities in assessing theenvironmental and operational performance of theirsystems for the available range of coal fuels to deter-mine the least-cost option. The CQE™ software hasbeen distributed to over 25 utility members of EPRIand is being marketed commercially worldwide. TwoU.S. utilities also have been licensed to use copies ofthe CQE™ stand-alone Acid Rain Advisor.

Commercialization successes for the coal processingtechnologies to date are summarized in Exhibit 4-6.

Industrial ApplicationsThe CCT Program is addressing the environmentalissues and barriers associated with coal use in indus-trial applications. Three of five projects have com-pleted operations in this area.

Historically, production of steel has been dependentupon coke. Coke making, however, is an inherentlylarge producer of hazardous air pollutants. Also,cement production often relies on coal fuel becauseproduction costs are largely driven by fuel costs.Because of its stable low price, coal is an attractivesubstitute for oil and gas in industrial boilers, but con-cerns over increased SO2 and NOx emissions and boilertube fouling have impeded coal use.

Under a project with Bethlehem Steel Corporation,British Steel’s blast furnace granular-coal injection(BFGCI) technology demonstrated that 0.96 pounds ofcoke can be replaced for every pound of coal injecteddirectly into a blast furnace where emissions from coalcombustion are effectively controlled in the process.

CPICOR™ Management Company LLC is in the de-sign stage for demonstrating direct iron ore reductionand smelting of iron oxides using coal in lieu of coke.This would reduce the need for coke, which results inlarge amounts of pollutants during its production.


Exhibit 4-5Commercial Successes�Advanced Electric Power Generation


Tidd PFBC Demonstration Project Sold internationally. The project�s success has led Babcock & Wilcox to invest in the technology(The Ohio Power Company) and acquire domestic licensing rights.

Commercial coal-fired ventures abroad include the following:

� Vartan in Sweden is operating two P200 units to produce 135 MWe and 224 MWt*;

� Escatron in Spain is operating one P200 unit producing 80 MWe*;

� Wakamatsu in Japan has retired one P200 unit that produced 71 MWe;

� Cottbus in Germany is operating one P200 unit to produce 71 MWe and 40 MWt;

� Karita in Japan operates one P800 unit to produce 360 MWe;

� Chuoku in Japan to produce 250 MWe; and

� 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 Energy Corporation, the technologyand Transmission Association, Inc.) supplier for the demonstration effort, has achieved sales of $9 billion through 2001. Almost 25 percent of the sales

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

Tampa Electric Integrated Gasification Combined-Cycle Sold domestically and internationally. First greenfield IGCC unit in commercial service. Texaco, Inc., and ASEAProject (Tampa Electric Company) Brown Boveri signed an agreement forming an alliance to market IGCC technology in Europe. Since 1996, when the

Tampa IGCC began operations, Texaco has placed into operation 9 gasifiers domestically, including Tampa, (1 usingcoal, 1 using petroleum, 3 using petroleum coke, and 4 using natural gas) and 16 gasifiers internationally (3 using coal,11 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 world�s largest single-train IGCC(Wabash River Coal Gasification Repowering Project in commercial service. The unit is preferentially dispatched over other coal-fired units in PSI Energy�sJoint Venture) system because of the unit�s high efficiency. The Port of Port Arthur, Texas has announced plans for a $1.75 billion

project to use the E-Gas technology.

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

* Parallel project with Tidd.


Exhibit 4-6Commercial Successes—Coal Processing for Clean Fuels


Development of the Coal Quality Expert™ (ABB Combustion Sold domestically and internationally. The Electric Power Research Institute (EPRI) owns the Engineering, Inc.Engineering and CQ, Inc.) software and distributes it to EPRI members for their use. CQ Inc. and Black and Veatch have signed

commercialization agreements that give both companies nonexclusive worldwide rights to sell user licenses and offerconsulting services that include use of CQE®. More than 22 U.S. utilities, two United Kingdom utilities, and oneutility in France have received CQE® through EPRI membership. Two modules of the Acid Rain Advisor valued at$6,000 have been sold. EPRI estimated that the Acid Rain Advisor has saved one U.S. utility about $26 million—more than the total cost of the demonstration project. There have also been two sales of the Windows version of thesoftware (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 potential mild coal gasificationCorporation) plants, five detailed commercial feasibility studies—two Indonesian, one Russian, and two U.S. projects—have been

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

Commercial-Scale Demonstration of the Liquid Phase No sales reported. Nominal 80,000 gallon/day methanol production being used by Eastman Chemical Company.Methanol (LPMEOH™) 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 long-term agreements were in(Western SynCoal LLC) place to purchase the product. One domestic and five international projects have been investigated. Western

SynCoal LLC has a joint marketing agreement with Ube Industries of Japan providing Ube non-exclusive marketingrights outside of the United States. Ube is pursuing several projects in Asia.


Exhibit 4-7Commercial Successes—Industrial Applications


Cement Kiln Flue Gas Recovery Scrubber No sales reported. The scrubber became a permanent part of the cement plant at the end of the demonstration. A feasibility(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, it is believed to haveNitrogen, and Ash Control (Coal Tech Corporation) commercial potential. Follow-on work to the CCT Program demonstration was undertaken, which has brought the technology

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 con-vert the kiln dust to feedstock with no waste generated.

Coal Tech Corporation moved closer to commercializ-ing a combustor for industrial boilers that slags theash in the combustor to prevent boiler tube fouling,controls NOx (70 to 80 percent reduction) throughstaged combustion, and controls SO2 (90 percent) withsorbent injection.

ThermoChem, Inc. has recently completed demonstra-tion of its multiple resonance tube pulse combustor.

Commercialization successes for the industrial appli-cations technologies to date are summarized inExhibit 4-7.

AwardsThe projects in the CCT Program have won numerousawards from news, professional, and non-profit organi-zations. 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 recog-nized 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 insti-tutions 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 con-tinuing basis, feedback on program direction and infor-mation 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, opera-tional, and economic performance characteristics ofclean coal technologies and to redesign information

packages as customers and stakeholders, and their re-spective needs, change with the market. Specific objec-tives of the outreach program include the following:

• Achieving public and government awareness ofadvanced coal-using technologies as viable energyoptions;

• Providing potential technology users, both foreignand domestic, with information that is timely andrelevant to their decision making process;

• Providing policy makers, legislators, and regulatorswith information about the advantages of clean coaltechnologies;

• Informing financial institutions and insurance under-writers that clean coal technologies are viable op-tions; and

• Providing forums and opportunities for feedback onprogram direction and information requirements.

Information SourcesA variety of publications and information access mediaexist and are being improved upon as program andmarketplace events unfold. Information is currentlydistributed to over 4,000 customers and stakeholders.


Exhibit 4-8Award-Winning CCT Program Projects

Project and Participant Award

Full-Scale Demonstration of Low-NOx Cell Burner 1994 R&D 100 Award presented by R&D magazine to the U.S. Department of Energy for development of the low-NOx cellRetrofit (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 Association to the U.S. Department ofa Wall-Fired Boiler; Enhancing the Use of Coals by Gas Energy, Gas Research Institute, and U.S. Environmental Protection Agency for the development and commercialization ofReburning 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 Company�s Bailly GeneratingProject (Pure Air on the Lake, L.P.) Station.

1992 Outstanding Engineering Achievement Award presented by the National Society of Professional Engineers.

Demonstration of Innovative Applications of Technology 1995 Design Award presented by the Society of Plastics Industries in recognition of the mist eliminator.for the CT-121 FGD Process(Southern Company Services, Inc.) 1994 Powerplant Award presented by Power magazine to Georgia Power�s Plant Yates. Co-recipient was the U.S.

Department of Energy.

1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and Waste Management Association.

1993 Environmental Award presented by the Georgia Chamber of Commerce.

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

1991 Powerplant Award presented by Power magazine to American Electric Power Company�s Tidd project. Co-recipientwas The Babcock & Wilcox Company.

Tampa Electric Integrated Gasification Combined-Cycle 1997 Powerplant Award presented by Power magazine to Tampa Electric�s Polk Power Station.Project (Tampa Electric Company)

1996 Association of Builders and Contractors Award presented to Tampa Electric for quality of construction.

1993 Ecological Society of America Corporate Award presented to Tampa Electric for its innovative siting process.

1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of Florida for the innovative sitingprocess.

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

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 1996 American Consulting Engineers

Council competition.

Development of the Coal Quality Expert� (ABB In 1996 recognized by then Secretary of Energy Hazel O�Leary and EPRI President Richard Balzhiser as the best of nineCombustion Engineering, Inc. and CQ Inc.) DOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Program.


The following provides a brief synopsis of the publica-tions and information transfer mechanisms currently inplace.

Clean Coal Technology Demonstration Program: Pro-gram 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 quar-terly look at the CCT Program and related issues, high-lighting 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 eco-

nomic performance. Thirteen have been published sofar, with another one expected in early fiscal year 2002.

Topical Report documents capture projects at criticaljunctures and highlight particular technological advan-tages, project plans, and expected outcomes. Nineteenhave been published so far.

The National Technical Information Service (NTIS)serves as the federal government’s central source forthe sale of scientific, technical, engineering, and relatedbusiness information produced by or for the U.S. gov-ernment. The NTIS has many of the CCT Programtechnical reports.

CCT Program Bibliography of Publications, Papers,and Presentations periodically updates the key materi-als available on the technologies demonstrated underthe CCT Program.

The Investment Pays Off periodically takes a market-based view of the success of the CCT Program byvirtue of commercial sales and relevance of ongoingactivities to projected market need.

CCT Program—Lessons Learned documents thelessons learned in soliciting, selecting, and awardingprojects and implementing the program.

CCT Compendium is an electronic database incorpo-rating the CCT Program publications that can be ac-cessed on the Internet (http://www.lanl.gov/projects/cctc/).

Exhibits provide a means through graphics, photos,broadcast videos, and interactive videos to conveyprogram messages at a variety of forums, and serve asfocal points for distribution of literature and discussionof the program and information needs. There are cur-rently four exhibits of varying sizes and complexitythat are updated and modified, as necessary, to conveythe appropriate message for specific forums.

The Home Page of DOE’s Office of Fossil Energy pro-vides the primary Internet gateway to extensive informa-tion on DOE’s Fossil Energy Program and to relevantWorld Wide Web links (http://www.fe.doe.gov).

Exhibit 4-9 summarizes how the above publicationscan be obtained and information sources can beaccessed.

The CCT Compendium is a new source of information on theCCT Program.

Exhibit 4-9How to Obtain CCT Program Information

Media Description and Action

Clean 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 EnergyProgram 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 publica-tions can be expected in fiscal year 2002.

• Clean Coal Technology Demonstration Program:Program Update 2000

• Clean Coal Today: Winter 2000, Spring 2001, Sum-mer 2001, Fall 2001

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

Advanced Combustion NOx Control Techniques fora Wall-Fired Boiler Project

• Project Performance Summary—Evaluation of GasReburning and Low-NOx Burners on a Wall-FiredBoiler

• Topical Report—Environmental Benefits of CleanCoal Technologies

• Topical Report—The Wabash River Coal Gasifica-tion Repowering Project—An Update

• Topical Report—Coproduction of Power Fuels andChemicals

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 infor-mation 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 indi-vidual 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, Tennes-see. The gateway links to more than a hundred energy-related 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 energy-related 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 established a new informationresource on the Internet. The Clean Coal TechnologyCompendium, sponsored by the Office of Fossil Energyand the National Energy Technology Laboratory(NETL), is dedicated to making the maximum use ofinformation derived from the CCT Program. The com-pendium is designed to emphasize ease of use, andcontains a broad collection of different types of dataand information, making it applicable to the needs ofboth managers and engineers. For example, one canaccess the latest Clean Coal Technology Demonstra-tion Program: Program Update and Topical Reportspublished periodically on individual CCT projects. TheCCT Compendium is accessible via the Internet athttp://www.lanl.gov/projects/cctc/.

The new Coal & Power Systems exhibit at the Clean Coal and Power Conference in Washington, D.C.


Representatives from DOE and the U.K. Department of Tradeand Industry convened in Knoxville, Tennessee to planbilateral cooperative agreements.

Information Dissemination and FeedbackA number of mechanisms are used to disseminate pro-gram 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 dedi-cation 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 pro-grams, 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 Re-search Council, Center for Energy & Economic Devel-opment (CEED), Council of Industrial Boiler Owners(CIBO), Clean Coal Technology Coalition, and Na-tional Mining Association (NMA).

Conferences and Workshops bring together targetedaudiences to review and discuss topics of interest,document discussions and findings, and provide rec-ommendations, as appropriate. Trade Missions are a

subset of these and differ only in that the thrust is inter-national in character with the purpose of promoting theexport of U.S. technology and services. The outreachprogram has participated in over 230 technical confer-ences, 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 Coordi-nating Committee. The committee was established topromote U.S.-China cooperation on fossil fuels. At theforum’s conclusion, five project task agreements relat-ing 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, environ-mental 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 Con-trol 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 conferences stressed the mutualbenefit that can be realized through R&D cooperationbetween the United States and China, the world’s twolargest energy consumers and emitters of greenhousegases.

India. As part of the Efficient Power Generation com-ponent of the Greenhouse Gas Prevention Project(GEP) between the U.S. Agency for International De-velopment (USAID) and the government of India,NETL sponsored two training workshops in New Delhiaimed at special areas of power plant improvement.Some 35 power plant managers attended each of theworkshops. “Availability and Reliability ImprovementThrough Predictive Diagnostic Maintenance,” held onJanuary 26–February 10, 2001, focused on acousticpredictive diagnostics maintenance.

The second workshop, “Fireside Performance Optimi-zation/Emissions Control and Monitoring on AirPreheaters,” held on February 18-28, 2001, wasgeared toward methodologies for fire-side optimiza-tion, environmental improvements, and perfecting pre-heater performance. In another activity in May 2001,NETL arranged training in cooling tower thermal per-formance improvement. Twenty engineers from India’sNational Thermal Power Corporation (NTPC) weretrained in cooling tower evaluation.


United Kingdom. In May 2001, FE held a workshopin Knoxville, Tennessee called the “Introductory Meet-ing on Potential US-UK Interactions in Fossil Energy”as the first step toward developing the first Implement-ing Arrangement under a memorandum of understand-ing (MOU) signed in November 2000 by DOE and theUnited Kingdom Department of Trade and Industry forcooperative work in energy R&D. The two-day meet-ing 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 andchemicals, 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, non-destructive 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 re-searching complementary subject areas. The workshopalso illuminated business opportunities and providedperspective on both internal and export energy markets.

United States. The First National Conference on Car-bon 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 model-ing. 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 Net-work for CO2 Capture was held October 11–12, 2000,in Gaithersburg, Maryland. Forty-two researchers from10 countries attended, representing industry, govern-ment, and academia. The workshop was organized bythe International Energy Agency Greenhouse Gas Re-

search and DevelopmentProgramme, DOE, andABB Lummus Global ofSwitzerland to identifyareas for collaboration.The focus was on CO2capture techniques thatemploy regenerablechemical scrubbing atatmospheric pressure,considered the most ma-ture capture technology.

The Acting AssistantSecretary for Fossil En-ergy described carbonsequestration as the thirdleg of DOE’s climatechange strategy, joiningenergy efficiency and the use of low- or no-carbon fuels.Capture of CO2 accounts for 75–80 percent of the costof CO2 sequestration. Transportation costs are highlydependent on the relative locations of the capture facilityand the storage site. The largest industrial application forCO2 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 methodsthrough fundamental research, process development,and systems integration, and (4) initiation of a feasibil-ity study to define the characteristics of a futuredemonstration plant for investigating advanced CO2capture concepts. The proposed new demonstrationplant would make it possible to evaluate all CO2 scrub-bing technologies in an integrated manner at one testsite. The workshop also included a visit to the WarriorRun Power Plant near Cumberland, Maryland, whichuses state-of-the art gas cleaning technology.

The U.S. Naval Research Laboratory and DOE werethe primary sponsors of a seven-day oceanographiccruise conducted at the end of October 2000 by thescientific research team of the International CO2 Se-questration Field Experiment. The 20 scientists andengineers from the United States, Japan, Norway, andCanada undertook a preliminary sampling of the bot-tom sediments at a depth of 800 meters, and performeda detailed mapping of the seafloor. Students and teach-ers from three local high schools and a group of under-graduate students from the University of Hawaii at Hiloalso made an educational visit during the cruise.

A workshop on sensors and controls sponsored byNETL and held April 17–18, 2001, in Washington,D.C., was attended by 46 experts from 29 organiza-tions, including private industry, research laboratories,academia, and government agencies. Under the Vision21 Program, ultra-high efficiency and environmentalperformance would require new power plants to oper-ate at optimal conditions, while undergoing changes indemand and feedstock, resulting in challenging tasksfor sensor and control systems. Existing plant perfor-mance can be improved also by updating sensor andcontrol systems. The workshop held parallel discus-sions on advanced combustion/gasification, turbines,fuel cells, and environmental controls, to identify andprioritize the near-term and long-term sensors and con-trols needs.

A discussion of emerging technologies followed. Theresults indicated sensors need to be developed or im-proved for on-line or in-situ applications where condi-tions are extremely harsh. Sensor development needs tofocus on robustness and accuracy, while balancinglongevity with cost. Self-diagnostic and drift quantifi-cation capabilities of individual sensors will be anessential feature of new “smart” sensors. Balancing thefuel/air ratio was identified as a high priority to im-prove power generation efficiency as well as reduceemissions. The challenge is to transform sensor datainto meaningful information that can be interpreted bythe control system. Much work is also still needed in

NETL Director addressing theplenary session of the FirstNational Conference onCarbon Sequestration.


the area of accurate measurement of on-line solid fuelflow. Feedstock characterization was also identified asa long-term need. Combustion zone measurement tech-niques remain a high priority. The primary need thereis to develop materials and techniques capable of accu-rately detecting gas path and surface temperatures inhigh-pressure corrosive environments. Such capabili-ties are also needed for emissions controls. Some meth-ods 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 compo-nents, an umbrella approach was deemed necessary. Atthe individual modular system level, the need was dis-cussed to develop smart feedback or feedforward con-trols 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 repre-sentatives 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 re-maining time focused on other LAC regions. The con-ference 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 per-spectives 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 pro-viding sustainable and affordable energy to the world’spopulation living without such energy today and is vitalto the goal of reducing energy poverty without deleteri-ous 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 genera-tion capacity.

Trade Mission Activities in FY2001The U.S. Environmental Protection Agency has re-quested assistance from NETL in implementing a Tech-nology 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 devel-opment goals, while mitigating greenhouse gas emis-sions. Three fossil energy-related projects are planned:Clean Coal Technology, Improving Efficiency of Coal-Fired 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 com-bined-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 demonstra-tion 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 items include a U.S. study tour onadvanced boiler products and concepts, and possibleestablishment of a Chinese Industrial Boiler OwnersAssociation, as well as convening an International Con-ference on Technical Improvements to Chinese Indus-trial Boilers to Reduce Greenhouse Gas Emissions.


IntroductionCCT Program projects provide a portfolio of technolo-gies that will enable coal to continue to provide low-cost, secure energy vital to the nation’s economy whilesatisfying energy and environmental goals well into the21st century. This is being carried out by addressingfour basic market sectors: (1) environmental controldevices for existing and new power plants, (2) ad-vanced electric power generation for repowering exist-ing facilities and providing new generating capacity,(3) coal processing for clean fuels to convert thenation’s vast coal resources to clean fuels, and (4) in-dustrial 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-ef-fective 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 systemsinstalled on approximately 770 MWe, and seven com-bined SO2/NOx emission control systems installed orplanned on more than 665 MWe of capacity.

To respond to load growth as well as growing environ-mental concerns, the program provides a range ofadvanced electric power generation options for bothrepowering and new power generation. These ad-vanced options offer greater than 20 percent reductionsin greenhouse gas emissions; SO2, NOx, and particulateemissions far below New Source Performance Stan-

5. CCT Program Projectsdards (NSPS); and salable solid and liquid by-productsin lieu of solid wastes. Over 1,800 MWe of capacityare represented by 11 projects valued at more than$2.8 billion. These projects include five fluidized-bedcombustion (FBC) systems, four integrated gasifica-tion combined-cycle (IGCC) systems, and two ad-vanced combustion/heat engine systems. Theseprojects will provide the demonstrated technology basenecessary to meet new capacity requirements in the21st 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 forcompliance with the Clean Air Act Amendments of1990 (CAAA). Internationally, both the products andprocesses have excellent market potential. Valued atmore than $519 million, the five projects in the coalprocessing for clean fuels category represent a diversi-fied portfolio of technologies. Three projects involvethe production of high-energy-density solid fuels, oneof which also produces a liquid product equivalent toNo. 6 fuel oil. A fourth project is demonstrating a newmethanol production process. A fifth effort comple-ments the process demonstrations by providing anexpert computer software system that enables a utilityto 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 pollutionproblems associated with coal use in the industrialsector. These included dependence of the steel industryon coke and the inherent pollutant emissions in cokemaking; reliance of the cement industry on low-costindigenous, and often high-sulfur, coal fuels; and theneed for many industrial boiler operators to considerswitching to coal fuels to reduce operating costs. The

five industrial applications projects have a combinedvalue of nearly $1.3 billion. Projects encompass substi-tution of coal for 40 percent of coke in iron making,integration of a direct iron making process with theproduction of electricity, reduction of cement kilnemissions and solid waste generation, and demonstra-tions of an industrial-scale slagging combustor and apulse combustor system.

The remainder of this section contains a discussion ofthe technologies being demonstrated and fact sheetsfor each project.

The CCT projects are spread across the nation in 18 states,indicated in white.


Technology Overview

Environmental 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 gasformed during coal combustion, which oxidizes theinorganic pyritic sulfur (Fe2S) and organically boundsulfur in the coal. Identified as a precursor to the for-mation of acid rain, SO2 was targeted in Title IV of theCAAA. Phase I of Title IV, effective in 1995, affected261 coal-fired units nationwide. The required SO2 re-duction 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 fa-cilities. The CAAA provides utilities flexibility in con-trol strategies through SO2 allowance trading. Thispermits a range of control options to be applied by autility, as well as allowance purchasing. Recognizingthis, the CCT Program has sought to provide a portfo-lio of SO2 control technologies.

Sulfur dioxide control devices embody those technolo-gies 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 prima-rily by different conditions that exist within the pre-NSPS 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 boil-ers with limited space for adding equipment. For these,sorbent injection techniques hold promise. Sorbent isinjected into the boiler or the ductwork, and humidifi-cation is incorporated in some fashion to properlycondition the flue gas for efficient SO2 capture. Equip-ment 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 lime-stone must be conditioned (calcined), and even then, itis less effective in SO2 capture (under simple sorbentinjection conditions) than hydrated lime. Where lime-stone 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 effi-ciencies 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 equip-ment 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 sor-bent 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 lati-tude 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 cost-effective. These systems apply larger and somewhatmore complex reactors that drive up the capital cost.

However, the sorbent is the lower cost limestone,which reduces operating costs. In addition, new tech-nologies reduce capital costs, improve reliability, andincrease overall plant efficiency. The AFGD achievedSO2 removal efficiencies of greater than 90 percent at aCa/S molar ratio of about 1.0, making operating costssignificantly lower than those of the other two ap-proaches. Furthermore, although the initial AFGDsolid by-product is in slurry form, it is dewatered toproduce gypsum—a salable product.

The CCT Program successfully demonstrated two sor-bent injection systems, one spray dryer system, andtwo AFGD systems. All have completed testing. Ex-hibit 5-1 briefly summarizes the characteristics andperformance of the SO2 control technologies that aredescribed in the project fact sheets in this section.

NOx Control Technology. Nitrogen oxides are formedfrom oxidation of nitrogen contained within the coal(fuel-bound NOx) and oxidation of the nitrogen in theair at high temperatures of combustion (thermal NOx).To control fuel-bound NOx formation, it is important tolimit oxygen at the early stages of combustion. Tocontrol thermal NOx, it is important to limit peaktemperatures.

Pure Air on the Lake L.P. demonstrated an FGD process thatremoved 95 percent or more of SO2 emissions at the BaillyGenerating Station in Indiana.


The 10-MWe AirPol gas suspension absorption demonstrationunit. LIFAC reactor being installed in Richmond, Indiana. The CT-121’s Jet Bubbling Reactor®

Exhibit 5-1CCT Program SO2 Control Technology Characteristics

Coal Sulfur SO2

Project Process Content Reduction Page

10-MWe Demonstration of Gas Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7–3.5% 60–90% 5-22Absorption particulate recycle (lime sorbent)

Confined Zone Dispersion Flue Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.5–2.5% 50% 5-26Desulfurization Demonstration

LIFAC Sorbent Injection Desulfurization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% 70% 5-30Demonstration Project humidification vessel and sorbent recycle

Advanced Flue Gas Desulfurization AFGD—cocurrent flow, integrated quench absorber tower, and reaction 2.25–4.7% 94% 5-34Demonstration Project tank with combined agitation/oxidation (gypsum by-product)

Demonstration of Innovative Applications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2–3% 90+% 5-38of Technology for the CT-121 FGD Process Reactor®) for combined SO2 and particulate capture (gypsum by-product)


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 emis-sions 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 ImplementationPlan (SIP) call for 22 states and the District of Colum-bia to cut NOx emissions to 85 percent below 1990rates or achieve a 0.15 lb/106 Btu emission rate byMay 2003. The fate of the SIP call is uncertain as liti-gation 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. Postcombus-tion 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, veloci-ties, 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 com-bustion 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 defi-ciency mitigates fuel-bound NOx formation. TheAOFA, injected at high velocity, creates turbulentmixing to complete the combustionin a gradual fashion at lower tem-peratures 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 in-jection ports above the primary com-bustion 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 oxy-gen, resulting in elemental nitrogen.Combustion is completed in a burn-out zone where air is injected by an

AOFA system. Reburning has application to all boilertypes, including cyclone boilers, and can achieve NOxemission reductions of 50–67 percent.

The SCR and SNCR technologies can be used alone orin combination with combustion modification. Theseprocesses use ammonia or urea in a reducing reactionwith NOx to form elemental nitrogen and water. TheSNCR system can only be used at high temperatures(1,600–2,200 ºF) where a catalyst is not needed. TheSCR system is typically applied at temperatures of600–800 ºF. Generally, SNCR and SCR systems alonecan achieve NOx emission reductions of 30–50 percentand 80–90+ percent, respectively.

Advanced control systems using artificial intelligenceare also becoming an integral part of NOx control sys-tems. These systems can handle the numerous param-

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

Exhibit 5-2Group 1 and 2 Boiler Statistics

and Phase II NOx Emission Limits Number Phase II

of NOx Emission Limits

Boiler Types Boilers (lb/106 Btu)

Group 1

Tangentially fired 299 0.40

Dry-bottom, wall-fired 308 0.46

Group 2

Cell burner 36 0.68

Cyclone >155 MWe 55 0.86

Wet-bottom, wall-fired >65 MWe 26 0.84

Vertically fired 28 0.80

Source: U.S. Environmental Protection Agency, Nitrogen Oxides EmissionReduction Program, Final Rule for Phase II, Group 1 and Group 2 Boilers(http://www.epa.gov/docs/acidrain/noxfs3.html).


eters and optimize performance to reduce NOx whileenhancing boiler performance.

Under the CCT Program, seven NOx control technolo-gies 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 summa-rizes the characteristics and performance of the tech-nologies that are described in more detail in the projectfact sheets.

Combined SO2/NOx Control Technology. CombinedSO2/NOx control systems encompass those technolo-gies that combine previously described control meth-ods 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 wet-scrubber design, sorbent additive, and artificial intelli-gence controls. The balance of the six projects usesynergistic methods not previously described.

SOx-NOx-Rox Box™ incorporates an SCR catalyst ina high-temperature filter bag for NOx control and ap-plies sorbent injection for SO2 control. The high-tem-perature filter bag, operated in a standard pulsed-jetbaghouse, protects the SCR catalyst, allows operationat optimal NOx control temperatures, forms a sorbentcake on the surface to enhance SO2 capture, and pro-vides high-efficiency particulate capture.

SNOX™ uses SCR followed by catalytic oxidation ofSO2 to SO3 with condensation of the SO3 in the pres-ence 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 sec-ond catalyst is broken down into water vapor, nitrogen,and a small amount of NOx). Furthermore, most par-ticulates passing through the upstream baghouse arecaptured in the sulfuric acid condensing unit. The sys-tem 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 gen-eration of electricity. The advanced electric powergeneration projects selected under the CCT Programare responsive to capacity expansion needs requisite tomeeting long-term demand, offsetting nuclear retire-ments, and meeting stringent CAAA emission limitseffective in 2000. These technologies are characterizedby high thermal efficiency, very low pollutant emis-sions, reduced CO2 emissions, few solid waste prob-lems, and enhanced economics. Advanced electricpower generation technologies may be deployed in

modules, allowing phased construction to better matchdemand growth, and to meet the smaller capacityrequirements of municipal, rural, and nonutilitygenerators.

There are five generic advanced electric power genera-tion technologies demonstrated in the CCT Program.The characteristics of these five technologies are out-lined here, and the specific projects and technologiesare presented in more detail in the fact sheets.

Fluidized-Bed Combustion. Fluidized-bed combus-tion (FBC) reduces emissions of SO2 and NOx by con-trolling combustion parameters and by injecting asorbent (such as crushed limestone) into the combus-tion chamber along with the coal. Pulverized coalmixed with the limestone is fluidized on jets of air inthe combustion chamber. Sulfur released from the coalas SO2 is captured by the sorbent in the bed to form asolid calcium compound that is removed with the ash.The resultant waste is a dry, benign solid that can bedisposed of easily or used in agricultural and construc-tion applications. More than 90 percent of the SO2 canbe captured in this manner.

At combustion temperatures of 1,400–1,600 ºF, thefluidized mixing of the fuel and sorbent enhances bothcombustion and sulfur capture. The operating tempera-ture range is about half that of a conventional pulver-ized-coal boiler and below the temperature thatthermal NOx is formed. In fact, FBC NOx emissionsare about 70–80 percent lower than those for conven-tional pulverized-coal boilers. Thus, fluidized-bedcombustors substantially reduce both SO2 and NOxemissions. Also, FBC has the capability of using high-ash coal, whereas conventional pulverized-coal unitsmust limit ash content in the coal to relatively lowlevels.

Two parallel paths were pursued in FBC develop-ment—bubbling and circulating beds. Bubbling fluid-ized-beds use a dense fluid bed and low fluidizationvelocity to effect good heat transfer and mitigateerosion of an in-bed heat exchanger. Circulating fluid-

Kodak Park was one of two sites demonstrating micronizedcoal reburning.


Foster Wheeler’s LNBs used at Cherokee Station for the GR-LNB demonstration.

Air and coal feed for coal reburning in a cyclone boiler at theNelson Dewey Station.

The SCR demonstration facility at Southern Company’s PlantCrist.

Exhibit 5-3CCT Program NOx Control Technology Characteristics

Boiler Size/ NOx

Project Process Type Reduction Page

Demonstration of Advanced Combustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500-MWe/wall 68% 5-44for a Wall-Fired Boiler and artificial intelligence controls

Demonstration of Coal Reburning for Cyclone Coal reburning—30% heat input 100-MWe/cyclone 52–62% 5-48Boiler NOx Control

Full-Scale Demonstration of Low-NOx Cell Burner LNB—separation of coal and air ports on plug-in unit 605-MWe/cell burner 48–58% 5-52Retrofit

Evaluation of Gas Reburning and Low-NOx Burners LNB/gas reburning/AOFA—13–18% gas heat input 172-MWe/wall 37–65% 5-56on a Wall-Fired Boiler

Micronized Coal Reburning Demonstration Coal reburning—14% heat input (tangentially fired) and 148-MWe/tangential 28% 5-60for NOx Control 17% heat input (cyclone) 50-MWe/cyclone 59%

Demonstration of Selective Catalytic Reduction SCR—eight catalysts with different shapes and 8.7-MWe/various 80% 5-64Technology for the Control of NOx Emissions chemical compositionsfrom High-Sulfur, Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially LNB/AOFA—advanced LNB with close-coupled 180-MWe/tangential 37–45% 5-68Fired Combustion Techniques for the Reduction of NOx and separated overfire airEmissions from Coal-Fired Boilers


LIMB furnace sorbent injection lines The SOx-NOx-Rox Box� and SCR catalyst holder. The sorbent injection system for the GR-SI technology.

Exhibit 5-4CCT Program Combined SO2/NOx Control Technology Characteristics

Boiler Size/ NOx

Project Process Type Reduction Page

SNOX� Flue Gas Cleaning Demonstration SCR/oxidation catalyst/sulfuric acid condenser�synergistic 3.4% 95%/94% 5-74Project catalyst effect and no solid waste

LIMB Demonstration Project Extension and LNB/sorbent injection�furnace and duct injection, calcium-based 1.6�3.8% 60�70%/40�50% 5-78Coolside Demonstration sorbents

SOx-NOx-Rox Box� Flue Gas Cleanup SCR/high-temperature baghouse/sorbent injection�SCR in high- 3.4% 80�90%/90% 5-82Demonstration Project temperature filter bag and calcium-based sorbent injection

Enhancing the Use of Coals by Gas Reburning Gas reburning/sorbent injection (GR-SI)�calcium-based sorbents 3.0% 50�60%/67% 5-86and Sorbent Injection used in duct injection

Milliken Clean Coal Technology Demonstration LNB/SNCR/wet scrubber�sorbent additive and space-saving, 1.5�4.0% 98%/53�58% 5-90Project durable scrubber design

Integrated Dry NOx/SO2 Emissions LNB/SNCR/sorbent injection�calcium- and sodium-based 0.4% 70%/62�80% 5-94Control System sorbents used in duct injection


ized-beds use a relatively high fluidization velocity thatentrains the bed material, in conjunction with hot cy-clones, 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 in-

herent 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, twohave successfully completed demonstration (one PFBCand one AFBC), one is in construction, and the othertwo are in the project definition and design phase as ofthe end of fiscal year 2001. By the time this report ispublished, the project under construction will be inoperation.

Integrated Gasification Combined-Cycle. The IGCCprocess has four basic steps: (1) fuel gas is generatedfrom coal reacting with high-temperature steam and anoxidant (oxygen or air) in a reducing atmosphere;(2) the fuel gas is either passed directly to a hot-gascleanup system to remove particulates, sulfur, andnitrogen compounds, or the gas is first cooled to pro-duce steam and then cleaned conventionally; (3) theclean 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 sorbent injected into the gasifier.Others use existing proven commercial hydrogen sul-fide removal processes, which remove more than 99percent of the sulfur, but require the fuel to be cooled,which is an efficiency penalty. Therefore, hot-gascleanup systems are now being considered. In thesehot cleanup systems, the hot coal gas is passed througha bed of metal oxide particles, such as zinc oxides.Zinc oxide can absorb sulfur contaminants at tempera-tures in excess of 1,000 ºF, and the compound can beregenerated and reused with little loss of effectiveness.Produced during the regeneration stage are salablesulfur, sulfuric acid, or sulfur-containing compoundsthat may be used to produce useful by-products. Thetechnique is capable of removing more than 99.9 per-cent of the sulfur in the gas stream. With hot-gascleanup, IGCC systems have the potential for efficien-cies of over 50 percent.

High levels of nitrogen removal are also possible.Some of the coal’s nitrogen is converted to ammonia,which can be almost totally removed by commerciallyavailable chemical processes. Nitrogen oxides formedin the gas turbine can be held to well within allowablelevels by staged combustion in the gas turbine or byadding moisture to control flame temperature.

Integrated Gasification Fuel Cell. A typical fuel cellsystem using coal as fuel includes a coal gasifier with agas cleanup system, a fuel cell to use the coal gas togenerate electricity (direct current) and heat, an in-verter to convert direct current to alternating current,and a heat recovery system. The heat recovery systemwould be used to produce additional electric power ina bottoming steam cycle.

Energy conversion in fuel cells is more efficient thantraditional energy conversion devices (up to 60 per-cent, depending on fuel and type of fuel cell). Fuelcells directly transform the chemical energy of a fueland an oxidant (air or oxygen) into electrical energyinstead of going through intermediate steps—burner,boiler, turbines, and generators. Each fuel cell includes

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 op-erations, 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 carbon-ate 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 pro-duce steam for a steam-turbine electric generatingsystem (combined cycle). Environmental control sys-tems for SO2, NOx, and particulate removal treat thecooled exhaust before release to the atmosphere. Thediesel system is expected to achieve a 41�48 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 tech-nologies 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 combus-tor. 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 70�80 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 tech-nologies presented in the project fact sheets.

Coal Processing for Clean Fuels TechnologyThe coal processing category includes a range of tech-nologies 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 LLC�s 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 prop-erties of the coal is required, however, to provide sta-bility (prevent spontaneous combustion) in transportand handling. In the process, coal with 5,500�9,000 Btu/lb, 25�40 percent moisture content, and 0.5�1.5 percent sulfur is converted to a 12,000 Btu/lb prod-uct with 1.0 percent moisture and as low as 0.3 percentsulfur. The SynCoal® product is used at utility and in-dustrial 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-en-ergy-density, low-sulfur solid product and a clean liquidfuel comparable to No. 6 fuel oil. Mild gasification is a

pyrolysis process (heating in the absence of oxygen)performed at moderate temperatures and pressures. Itproduces condensable volatile hydrocarbons in additionto solids and gas. The condensable fraction is drawn offas a liquid product. Most of the gas is used to provideon-site energy requirements. The process solid is signifi-cantly beneficiated to produce an 11,000 Btu/lb low-sulfur solid fuel. The demonstration plant processed 500tons per day of subbituminous coal, and produced 250tons per day of solid Process-Derived Fuel (PDF®) and250 barrels per day of Coal-Derived Liquids (CDL®).Both the solid and liquid fuels have undergone testburns at utility and industrial sites. The project was suc-cessfully completed.

The liquid phase methanol (LPMEOH�) processbeing demonstrated is an 80,000 gallon/day indirectliquefaction process using synthesis gas from a coalgasifier. The unique aspect of the process is the use ofan inert liquid to suspend the conversion catalyst. Thisremoves the heat of reaction and eliminates the needfor an intermediate water-gas shift conversion. Alsoaddressed in the project are the load-following capabil-ity of the process by simulating application in an IGCCsystem and the fuel characteristics of the unrefinedproduct.

ABB Combustion Engineering, Inc., and CQ Inc., havedeveloped a personal computer software package,CQE®, that will serve as a predictive tool to assist utili-ties in selecting optimal quality coal for a specificboiler based on operational, economic, and environ-mental considerations. Algorithms were developed andverified through comparative testing at bench, pilot,and utility scale. Six large-scale field tests were con-ducted at five separate utilities. The software has beenreleased for commercial use. More than 35 U.S. utili-ties and one U.K. utility have received CQE® throughElectric Power Research Institute (EPRI) membership.It is estimated that CQE® saves U.S. utilities about $26million annually.


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

Exhibit 5-5CCT Program Advanced Electric Power Generation Technology Characteristics

Project Process Size Page


McIntosh Unit 4A PCFB Demonstration Project Pressurized circulating fluidized-bed combustion 137 MWe (net) 5-100

McIntosh Unit 4B Topped PCFB Demonstration Project McIntosh 4A with pyrolyzer and topping combustor 240 MWe (net) 5-102

JEA Large-Scale CFB Combustion Demonstration Project Atmospheric circulating fluidized-bed combustion 297.5 MWe (gross); 265 MWe (net) 5-104

Tidd PFBC Demonstration Project Pressurized bubbling fluidized-bed combustion 70 MWe 5-106

Nucla CFB Demonstration Project Atmospheric circulating fluidized-bed combustion 100 MWe 5-110

Integrated Gasification Combined Cycle

Kentucky Pioneer Energy IGCC Demonstration Project Oxygen-blown, slagging fixed-bed gasifier with cold gas cleanup 580 MWe (gross); 540 MWe (net)a 5-116

Tampa Electric Integrated Gasification Oxygen-blown, entrained-flow gasifier with hot and cold gas cleanup 313 MWe (gross); 250 MWe (net) 5-118

Piñon Pine IGCC Power Project Air-blown, fluidized-bed gasifier with hot gas cleanup 107 MWe (gross); 99 MWe (net) 5-122

Combined-Cycle Project

Wabash River Coal Gasification Repowering Project Oxygen-blown, two-stage entrained-flow gasifier with cold gas cleanup 296 MWe (gross); 262 MWe (net) 5-126


Clean Coal Diesel Demonstration Project Coal-fueled diesel engine 6.4 MWe (net) 5-132

Healy Clean Coal Project Advanced slagging combustor, spray dryer with sorbent recycle 50 MWe (nominal) 5-134a 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 associ-ated with coal use in industrial processes. These tech-nologies 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 ap-proaches to mitigate or eliminate this problem are be-ing 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 emis-sions 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 andto address growing solid waste management problems,industry sponsored the demonstration of an innovativeSO2 scrubber. The successfully demonstrated Passama-quoddy Technology Recovery Scrubber™ uses cementkiln 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 substi-tute 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. Oil-and gas-fired units are not high SO2 or NOx emitters;use relatively tight tube spacing in the absence of po-tential ash fouling; and the flow of oil or gas cools thecombustor, precluding the need for water cooling. Forthese reasons, the CCT Program demonstrated an ad-vanced air-cooled, slagging combustor that couldavoid these potential problems. The cyclone combustorstages introduction of air to control NOx, injects sor-bent 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 gasifi-cation and waste-to-energy applications.

The cement kiln, slagging combustor, blast furnacegranular-coal injection, and pulse combustor projectsare completed. The ThermoChem Pulse Combustorproject completed operations in fiscal year 2001, butthe final report has not been issued. The CPICOR™project is in the design and construction phase as of theend of fiscal year 2001.

Exhibit 5-7 summarizes process characteristics and sizefor the industrial applications technologies presented inmore detail in the project fact sheets.

Project Fact SheetsThe remainder of this document contains fact sheets forall 38 projects. Two types of fact sheets are provided: (1)a brief, two-page overview for ongoing projects and (2)an expanded four-page summary for projects that havesuccessfully completed operational testing. The ex-panded fact sheets for completed projects contain a sum-mary of the major results from the demonstration as wellas sources for obtaining further information, specifically,contact persons and key references. Information pro-vided in the fact sheets includes the project participantsand team members, project objectives, significantproject features, process description, major milestones,progress (if ongoing) or summary of results (if com-pleted), and commercial applications. To prevent therelease of project-specific information of a proprietarynature, process flow diagrams contained in the factsheets are highly simplified and presented only as illus-trations of the concepts involved in the demonstrations.The portion of the process or facility central to the dem-onstration is demarcated by the shaded area.

Shown is the Coltec coal-fired diesel being installed at theUniversity of Alaska in Fairbanks.


Western SynCoal Partnership�s advanced coal conversionprocess plant in Colstrip, Montana, has produced over 1.5million tons of SynCoal® 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 ofPDF® and 121,000 barrels of CDL®.

The LPMEOH� process produces over 80,000 gal/day ofmethanol, all of which is used by the Eastman ChemicalCompany in Kingsport, Tennessee.

Exhibit 5-6CCT Program Coal Processing for Clean Fuels Technology Characteristics


Commercial-Scale Demonstration of the Liquid Phase Methanol Liquid phase process for methanol production from 80,000 gal/day 5-140(LPMEOH�) Process coal-derived syngas

Development of the Coal Quality Expert� Coal Quality Expert� computer software Tested at 250�880 MWe 5-142

ENCOAL® Mild Coal Gasification Project Liquids-from-coal (LFC®) mild gasification to 1,000 tons/day* 5-146produce solid and liquid fuels

Advanced Coal Conversion Process Demonstration Advanced coal conversion process for upgrading 45 tons/hr 5-150low-rank coals

*Operated at 500 tons/day


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 Gas Recovery Scrubber project’scrystallizer and condenser (right) and flue gas condenser(left).

Exhibit 5-7CCT Program Industrial Applications Technology Characteristics


Clean Power from Integrated Coal/Ore Direct reduction iron-making process to eliminate coke; 3,300 tons/day of hot metal 5-156Reduction (CPICOR™) combined-cycle electric power generation 170 MWe

Blast Furnace Granular-Coal Injection System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of hot 5-158Demonstration Project metal/furnace

Advanced Cyclone Combustor with Internal Advanced slagging combustor with staged combustion and sorbent 23x106 Btu/hr 5-162Sulfur, Nitrogen, and Ash Control injection

Cement Kiln Flue Gas Recovery Scrubber Cement kiln dust used to capture SO2; dust converted to feedstock; 1,450 tons/day of cement 5-166and fertilizer and distilled water produced

Pulse Combustor Design Qualification Test Advanced combustion using Manufacturing and Technology 30x106 Btu/hr 5-170Conversion International’s (MTCI) pulse combustor/gasifier


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 com-pleted operations. A shaded area distinguishes projectshaving completed operations from ongoing projects.Within these breakdowns, projects are listed alphabeti-cally 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 num-ber for each fact sheet. Exhibit 5-9 lists the projectsalphabetically by participant and provides project loca-tion and page numbers. A key to interpreting the mile-stone charts is provided in Exhibit 5-10.

An appendix containing contact information for all ofthe projects is provided as Appendix D. A list of acro-nyms used in this document is provided as Appendix E.


Exhibit 5-8Project Fact Sheets by Application Category



SO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/completed 3/94 5-22

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93 5-26

LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCT-III/completed 6/94 5-30

Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95 5-34

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/completed 12/94 5-38


Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/extended 5-44

Demonstration of Coal Reburning for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/completed 12/92 5-48

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 4/93 5-52

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 1/95 5-56

Micronized Coal Reburning Demonstration for NOx Control New York State Electric & Gas Corporation CCT-IV/completed 4/99 5-60

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95 5-64for the Control of NOx Emissions from High-Sulfur, Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion Southern Company Services, Inc. CCT-II/completed 12/92 5-68Techniques for the Reduction of NOx Emissions from Coal-Fired Boilers

Combined SO2/NOx Control Technologies

SNOX™ Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/completed 12/94 5-74

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/completed 8/91 5-78

SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5/93 5-82

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 10/94 5-86

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/completed 6/98 5-90

Integrated Dry NOx/SO2 Emissions Control System Public Service Company of Colorado CCT-III/completed 12/96 5-94



McIntosh Unit 4A PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-III/design 5-100

McIntosh Unit 4B Topped PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-V/design 5-102

JEA Large-Scale CFB Combustion Demonstration Project JEA CCT-I/construction 5-104Shaded area indicates projects having completed operations.


Exhibit 5-8 (continued)Project Fact Sheets by Application Category


Tidd PFBC Demonstration Project The Ohio Power Company CCT-I/completed 3/95 5-106

Nucla CFB Demonstration Project Tri-State Generation and Transmission CCT-I/completed 1/91 5-110Association, Inc.


Kentucky Pioneer Energy IGCC Demonstration Project Kentucky Pioneer Energy, LLC CCT-V/design 5-116

Tampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/completed 10/01 5-118

Piñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/completed 1/01 5-122

Wabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering CCT-IV/completed 12/99 5-126Project Joint Venture


Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/construction 5-132

Healy Clean Coal Project Alaska Industrial Development and CCT-III/completed 12/99 5-134Export Authority


Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process Air Products Liquid Phase CCT-III/operational 5-140Conversion Company, L.P.

Development of the Coal Quality Expert™ ABB Combustion Engineering, Inc. CCT-I/completed 12/95 5-142and CQ Inc.

ENCOAL® Mild Coal Gasification Project ENCOAL Corporation CCT-III/completed 7/97 5-146

Advanced Coal Conversion Process Demonstration Western SynCoal LLC CCT-I/completed 1/01 5-150


Clean Power from Integrated Coal/Ore Reduction (CPICOR™) CPICOR™ Management Company LLC CCT-V/design 5-156

Blast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/completed 11/98 5-158

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/completed 5/90 5-162

Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/completed 9/93 5-166

Pulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/completed 9/01 5-170

Shaded area indicates projects having completed operations.


Exhibit 5-9Project Fact Sheets by Participant

Participant Project Location Page

ABB Combustion Engineering, Inc. and CQ Inc. Development of the Coal Quality Expert™ Homer City, PA 5-142

ABB Environmental Systems SNOX™ Flue Gas Cleaning Demonstration Project Niles, OH 5-74

Air Products Liquid Phase Conversion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOH™) Kingsport, TN 5-140Process

AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption West Paducah, KY 5-22

Alaska Industrial Development and Export Authority Healy Clean Coal Project Healy, AK 5-134

Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project Fairbanks, AK 5-132

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

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

Babcock & Wilcox Company, The LIMB Demonstration Project Extension and Coolside Demonstration Loraine, OH 5-78

Babcock & Wilcox Company, The SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstration Project Dilles Bottom, OH 5-82

Bechtel Corporation Confined Zone Dispersion Flue Gas Desulfurization Demonstration Seward, PA 5-26

Bethlehem Steel Corporation Blast Furnace Granular-Coal Injection System Demonstration Project Burns Harbor, IN 5-158

Coal Tech Corporation Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Williamsport, PA 5-162

CPICOR™ Management Company LLC Clean Power from Integrated Coal/Ore Reduction (CPICOR™) Vineyard, UT 5-156

CQ Inc. (see ABB Combustion Engineering and CQ Inc.)

ENCOAL Corporation ENCOAL® Mild Coal Gasification Project Gillette, WY 5-142

Energy and Environmental Research Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Hennepin, IL 5-86Springfield, IL

Energy and Environmental Research Corporation Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Denver, CO 5-56

JEA JEA Large-Scale CFB Combustion Demonstration Project Jacksonville, FL 5-104

Kentucky Pioneer Energy, LLC Kentucky Pioneer Energy IGCC Demonstration Project Trapp, KY 5-116

Lakeland, City of, Lakeland Electric McIntosh Unit 4A PCFB Demonstration Project Lakeland, FL 5-100

Lakeland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project Lakeland, FL 5-102

LIFAC–North America LIFAC Sorbent Injection Desulfurization Demonstration Project Richmond, IN 5-30

New York State Electric & Gas Corporation Micronized Coal Reburning Demonstration for NOx Control Lansing, NY 5-60


Exhibit 5-9 (continued)Project Fact Sheets by Participant

Participant Project Location Page

New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project Lansing, NY 5-90

Ohio Power Company, The Tidd PFBC Demonstration Project Brilliant, OH 5-106

Passamaquoddy Tribe Cement Kiln Flue Gas Recovery Scrubber Thomaston, ME 5-166

Public Service Company of Colorado Integrated Dry NOx/SO2 Emissions Control System Denver, CO 5-94

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Chesterton, IN 5-34

Sierra Pacific Power Company Piñon Pine IGCC Power Project Reno, NV 5-122

Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coosa, GA 5-44

Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newnan, GA 5-38Process

Southern Company Services, Inc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensacola, FL 5-64NOx Emissions from High-Sulfur, Coal-Fired Boilers

Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Combustion Lynn Haven, FL 5-68Techniques for the Reduction of NOx Emissions from Coal-Fired Boilers

Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project Mulberry, FL 5-118

ThermoChem, Inc. Pulse Combustor Design Qualification Test Baltimore, MD 5-170

Tri-State Generation and Transmission Association, Inc. Nucla CFB Demonstration Project Nucla, CO 5-110

Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project West Terre Haute, IN 5-126Project Joint Venture

Western SynCoal LLC Advanced Coal Conversion Process Demonstration Colstrip, MT 5-150


Exhibit 5-10Key to Milestone Charts in Fact Sheets

Each fact sheet contains a bar chart that highlights major milestones—past and planned. The bar chart shows a project’s duration and indicates the time period for three general categoriesof project activities—preaward, design and construction, and operation and reporting. The key provided below explains what is included in each of these categories.

Preaward

Includes preaward briefings, negotiations, and other activities conducted during the period between DOE’s selection of the project and award of the cooperative agreement.

Design and Construction

Includes the NEPA process, permitting, design, procurement, construction, preoperational testing, and other activities conducted prior to the beginning of operation of thedemonstration.

MTF Memo-to-file

CX Categorical exclusion

EA Environmental assessment

EIS Environmental impact statement

Operation and Reporting

Begins with startup and includes operational testing, data collection, analysis, evaluation, reporting, and other activities to complete the demonstration project.


Environmental Control Devices Program Update 2001 5-21

Environmental Control DevicesSO2 Control Technologies

5-22 Program Update 2001 Environmental Control Devices

Environmental Control DevicesSO2 Control Technology

10-MWe Demonstration ofGas Suspension AbsorptionProject completedParticipantAirPol, Inc.

Additional Team MembersFLS miljo, Inc. (FLS)—technology ownerTennessee Valley Authority—cofunder and site owner

LocationWest Paducah, McCracken County, KY

TechnologyFLS’ Gas Suspension Absorption (GSA) system for fluegas desulfurization (FGD)

Plant Capacity/Production10-MWe equivalent slipstream of flue gas from a175-MWe wall-fired boiler

CoalWestern Kentucky bituminous: Peabody Martwick, 3.05%sulfur; Emerald Energy, 2.61% sulfur; Andalax, 3.06%sulfur; and Warrior Basin, 3.5% sulfur (used intermit-tently)

Project FundingTotal project cost $7,717,189 100%DOE 2,315,259 30Participant 5,401,930 70Project ObjectiveTo demonstrate the applicability of Gas Suspension Ab-sorption as an economic option for achieving Phase IICAAA SO2 compliance in pulverized coal-fired boilersusing high-sulfur coal.

Technology/Project DescriptionThe GSA system consists of a vertical reactor in whichflue gas comes into contact with suspended solids con-sisting 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, pre-pared 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 structured to (1) optimize design ofthe GSA reactor for reduction of SO2 emissions fromboilers using high-sulfur coal, and (2) evaluate the envi-ronmental control capability, economic potential, andmechanical performance of GSA. A statistically designedparametric (factorial) test plan was developed involvingsix variables. Beyond evaluation of the basic GSA unit tocontrol SO2, air toxics control tests were conducted, andthe effectiveness of GSA/ESP and GSA/PJBH combina-tions to control both SO2 and particulates was tested.Factorial tests were followed by continuous runs to verifyconsistency of performance over time.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Capital Cost Levelized Cost(1990 $/kW) (mills/kWh)

GSA—3 units at 149 10.3550% capacityWLFO 216 13.04

Results SummaryEnvironmental• Ca/S molar ratio had the greatest effect on SO2 re-

moval, 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 1.4with 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 1.4with 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 hydro-gen 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 con-

ventional spray dryer, but at one-quarter to one-thirdthe size.

• GSA generated lower particulate loading than a con-ventional spray dryer, enabling compliance with alower ESP efficiency.

• Special steels were not required in construction, andonly a single spray nozzle is needed.

• High availability and reliability similar to other com-mercial applications were demonstrated, reflectingsimple design.

Economic• Capital and levelized (15-year constant 1990$) costs

for GSA installed in a 300-MWe plant using 2.6%sulfur coal are compared below to costs for a wet lime-stone scrubber with forced oxidation (WLFO scrub-ber). EPRI’s TAG™ cost method was used. Based onEPRI cost studies of FGD processes, the capital cost(1990$) for a conventional spray dryer was $172/kW.

19981997199619951994199319921991199019891988


Ground breaking/construction started 5/92

Preaward10/9212/89 10/90


DOE selected project(CCT-III) 12/19/89

Environmental monitoring plan completed10/2/92Operation 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 report issued 6/95Operation completed 3/94


Exhibit 5-11Variables and Levels Used in GSA

Factorial TestingVariable Level

Approach-to-saturation temperature (°F) 8*, 18, and 28Ca/S (moles Ca(OH)2/mole inlet SO2) 1.00 and 1.30Fly ash loading (gr/ft3, actual) 0.50 and 2.0Coal 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 5-12GSA Factorial Testing Results

Project SummaryThe GSA has a capability of suspending a high concentra-tion of solids, effectively drying the solids, and recirculat-ing the solids at a high rate with precise control. Thisresults in SO2 control comparable to that of wet scrubbersand high lime utilization. The high concentration of solidsprovides the sorbent/SO2 contact area. The drying enableslow approach-to-saturation temperature and chloride us-age. 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 gen-erated. The GSA is distinguished from the average spraydryer by its modest size, simple means of introducingreagent to the reactor, direct means of recirculating un-used lime, and low reagent consumption. Also, injectedslurry coats recycled solids, not the walls, avoiding corro-sion 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 tempera-ture was the next most important factor, followed closelyby 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-satura-tion 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 con-figuration was made with bituminous coals averaging2.7% sulfur, 0.12% chloride levels, and 18 ºF approach-to-saturation temperature. A subsequent 14-day continu-ous 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 morethan 90%, very close to the set point of 91%, at an aver-age Ca/S molar ratio of 1.40–1.45 moles Ca(OH)2/moleinlet SO2. The system was able to adjust rapidly to thesurge in inlet SO2 caused by switching to 3.5% sulfurWarrior Basin coal for a week. Lime utilization averaged

66.1%. The particulate removal efficiency averaged99.9+% and emission rates were maintained below 0.015lb/106 Btu. The 14-day run on the GSA/PJBH systemshowed that the SO2 removal efficiency averaged morethan 96% at an average Ca/S molar ratio of 1.34–1.43moles Ca(OH)2/mole inlet SO2. Lime utilization averaged70.5%. The particulate removal efficiency averaged99.99+% and emission rates ranged from 0.001–0.003 lb/106 Btu.

All air toxics tests were conducted with 2.7% sulfur, low-chloride coal with a 12 ºF approach-to-saturation tem-perature and a high fly ash loading of 2.0 gr/ft3 (actual).The GSA/ESP arrangement indicated average removalefficiencies of greater than 99% for arsenic, barium, chro-mium, lead, and vanadium; somewhat less for manga-nese; and less than 99% for antimony, cadmium, mercury,and selenium. The GSA/PJBH configuration showed99+% removal efficiencies for arsenic, barium, chro-mium, lead, manganese, selenium, and vanadium; withcadmium removal much lower and mercury removallower than that of the GSA/ESP system. The removal ofHCl and HF was dependent upon the utilization of limeslurry and was relatively independent of particulate con-trol configuration. Removal efficiencies were greater than98% for HCl and 96% for HF.

Operational PerformanceBecause the GSA system has suspended recycle solids toprovide a contact area for SO2 capture, multiple high-pressure atomizer nozzles or high-speed rotary nozzlesare not required to achieve uniform, fine droplet size.Also, recycle of solids is direct and avoids recycling ma-terial in the feed slurry, which would necessitate expen-sive abrasion-resistant materials in the atomizer(s).

The high heat and mass transfer characteristics of theGSA enable the GSA system to be significantly smallerthan a conventional spray dryer for the same capacity—one-quarter to one-third the size. This makes retrofit fea-sible for space-confined plants and reduces installationcost. The GSA system slurry is sprayed on the recycledsolids, not the reactor walls, avoiding direct wall contactand the need for corrosion-resistant alloy steels. Further-more, the high concentration of rapidly moving solidsscours the reactor walls and mitigates scaling. The GSA


system generates a significantly lower dust loading than aconventional spray dryer, 2–5 gr/ft3 for GSA versus6–10 gr/ft3 for a spray dryer, thereby easing the burden onparticulate controls. The GSA system produces a solidby-product containing very low moisture. This materialcontains both fly ash and unreacted lime. With the addi-tion 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 effi-ciency was 90% at a lime feed rate equivalent to 1.30moles of Ca per mole of inlet SO2. Lime was assumed tobe 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 con-stant 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 utiliza-tion than a spray dryer, the GSA will have a lower operat-ing cost.

Commercial ApplicationsThe low capital cost, moderate operating cost, and highSO2 capture efficiency make the GSA system particularlyattractive as a CAAA compliance option for boilers in the50- to 250-MWe range. Other major advantages includethe modest space requirements comparable to duct injec-tion 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 Develop-ment 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 com-bined value of $20 million. Furthermore, Taiwan con-tracted for technical assistance and proprietary equipmentvalued at $1.0 million.

ContactsNiels H. Kastrup, (281) 539-3400

FLS miljo, Inc.100 Glennborough Drive, 5th FloorHouston, TX 77067(281) 539-3411 (fax)

James U. Watts, NETL, (412) 386-5991

References10-MWe Demonstration of Gas Suspension AbsorptionFinal Project Performance and Economics Report. Re-port No. DOE/PC/90542-T9. AirPol, Inc. June 1995.(Available from NTIS as DE95016681.)

10-MW Demonstration of Gas Suspension AbsorptionFinal Public Design Report. Report No. DOE/PC/90542-T10. AirPol, Inc. June 1995. (Available from NTIS asDE960003270.)

SO2 Removal Using Gas Suspension Absorption Technol-ogy. Topical Report No. 4. U.S. Department of Energyand AirPol, Inc. April 1995.10-MWe Demonstration of the Gas Suspension Absorp-tion Process at TVA’s Center for Emissions Research:Final Report. Report No. DOE/PC/90542-T10. TennesseeValley Authority. March 1995. (Available from NTIS asDE96000327.)

AirPol, Inc. successfully demonstrated the GSA system atTVA’s Center for Emissions Research, located at TVA’sShawnee Plant.



Confined Zone DispersionFlue Gas DesulfurizationDemonstrationProject completedParticipantBechtel Corporation

Additional Team MembersPennsylvania Electric Company—cofunder and hostPennsylvania Energy Development Authority—cofunderNew York State Electric & Gas Corporation—cofunderRockwell Lime Company—cofunder

LocationSeward, Indiana County, PA (Pennsylvania ElectricCompany’s Seward Station, Unit No. 5)

TechnologyBechtel Corporation’s in-duct, confined zone dispersionflue gas desulfurization (CZD/FGD) process

Plant Capacity/Production73.5 MWe equivalent

CoalPennsylvania bituminous, 1.2–2.5% sulfur

Project FundingTotal project cost* $10,411,600 100%DOE 5,205,800 50Participant 5,205,800 50Project ObjectiveTo demonstrate SO2 removal capabilities of in-ductCZD/FGD technology; specifically, to define the opti-mum 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 be-tween the boiler air heater and the electrostatic precipita-tor (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 pre-cludes 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 injection of different types of sor-bents (dolomitic and calcitic limes) with several atomizerdesigns using low- and high-sulfur coals to evaluate theeffects on SO2 removal and ESP performance. The dem-onstration was conducted at Pennsylvania ElectricCompany’s Seward Station in Seward, Pennsylvania.One-half of the flue gas capacity of the 147-MWe UnitNo. 5 was routed through a modified, extended straightsection of duct between the first- and second-stage ESPs.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


19981997199619951994199319921991199019891988



Preaward10/9212/89 10/90



Environmental monitoring plan completed10/2/92Operation initiated 10/92





6/94

Project completed/final report issued 6/94Operation 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 param-eter on SO2 capture. Flue gas temperature was thelimiting factor on injection rate. For SO2 capture effi-ciency of 50% or more, a flue gas temperature of300 ºF or more was needed.

• Slurry concentration for a given sorbent did not in-crease SO2 removal efficiency beyond a certain thresh-old 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 pressure-hydrated dolomitic-lime concentration of about 9%.

• For operating conditions at Seward Station, data indi-cated that for 40–50% SO2 removal, a 6–8% lime or

dolomitic lime slurry concentration, and a stoichiomet-ric 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 wasrequired 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 detrimentallyaffected 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 ofsolids within the ductwork during upsets.

Economic• Capital cost of a 500-MWe system operating on 4%

sulfur coal and achieving 50% SO2 reduction wasestimated at less than $30/kW and operating cost at$300/ton of SO2 removed (1994$).


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 be-tween the wet zone and the duct walls. Thelime slurry reacts with part of the SO2 in thegas and the reaction products dry to formsolid particles. An ESP, downstream from thepoint of injection, captures the reaction prod-ucts 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 pres-sure-hydrated dolomitic lime reduced resi-dence 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 opera-tional testing. During the continuous operational testperiod, the system was operated under fully automaticcontrol by the host utility boiler operators. The new atom-izing nozzles were thoroughly tested both outside andinside the duct prior to system testing.

The SO2 removal parametric test program, which began inOctober 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 butrequire different feed concentrations of lime slurry for the

same percentage of SO2 removed. The most efficientremovals and easiest operation were achieved using pres-sure-hydrated dolomitic lime.

Environmental PerformanceSorbent injection rate proved to be the most influentialfactor on SO2 capture. The rate of injection possible waslimited by the flue gas temperature. This impacted a por-tion 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% wereachieved. 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 givensorbent did not increase SO2 removal efficiency beyond acertain threshold concentration. For example, with pres-sure-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 tem-perature 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 PerformanceThe percentage of lime utilization in the CZD/FGD sig-nificantly affected the total cost of SO2 removal. Ananalysis of the continuous operational data indicated thatthe percentage of lime utilization was directly dependenton two key factors: (1) percentage of SO2 removed, and(2) lime slurry feed concentration.

For operating conditions at Seward Station, data indicatedthat for 40–50% SO2 removal, a 6–8% lime or dolomiticlime slurry concentration, and a stoichiometric ratio of2–2.5 resulted in a 40–50% lime utilization rate. That is,2–2.5 moles of CaO or CaO•MgO were required for everymole of SO2 removed; or assuming 92% lime purity,1.9–2.4 tons of lime were required for every ton of SO2removed. In summary, the demonstration showed thefollowing results:

• A 50% SO2 removal efficiency with CZD/FGD waspossible.

• Drying and SO2 absorption required a residence timeof 2 seconds, which required a long and straight hori-zontal gas duct of about 100 feet.

• The fully automated system integrated with the powerplant operation demonstrated that the CZD/FGD pro-cess responded well to automated control operation.However, modifications to the CZD/FGD were re-quired to assure consistent SO2 removal and avoiddeposition of solids within the gas duct during upsets.

• Availability of the system was very good.• At Seward Station, stack opacity was not detrimentally

affected by the CZD/FGD system.

Economic PerformanceEstimates show that the CZD/FGD process can achievecosts of $300/ton of SO2 removed (1994$) when operat-ing a 500-MWe unit burning 4% sulfur coal. Based on a500-MWe plant retrofitted with CZD/FGD for 50% SO2removal, the total capital cost is estimated to be less than$30/kW (1994$).

Commercial ApplicationsAfter the conclusion of the DOE-funded CZD/FGDdemonstration project at Seward Station, the CZD/FGDsystem was modified to improve SO2 removal during


CZD/FGD lime slurry injector control system.

continuous operation while following daily load cycles.Bechtel and the host utility, Pennsylvania Electric Com-pany, continued the CZD/FGD demonstration for an addi-tional year. Results showed that CZD/FGD operation atSO2 removal rates lower than 50% could be sustainedover long periods without significant process problems.

CZD/FGD can be used for retrofitting existing plants andinstallation in new utility boiler flue gas facilities to re-move 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) 386-5991

ReferencesConfined Zone Dispersion Project: FinalTechnical Report. Bechtel Corporation. June1994.

Confined Zone Dispersion Project: PublicDesign Report. Bechtel Corporation. Octo-ber 1993.

Comprehensive Report to Congress on theClean Coal Technology Program: Confined

Zone Dispersion Flue Gas Desulfurization Demonstra-tion. Bechtel Corporation. Report No. DOE/FE-0203P.U.S. Department of Energy. September 1990. (Availablefrom NTIS as DE91002564.)



LIFAC 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

managerTampella Power Corporation—cofunderTampella, Ltd.—technology ownerRichmond Power and Light—cofunder and host utilityElectric Power Research Institute—cofunderBlack Beauty Coal Company—cofunderState of Indiana—cofunder

LocationRichmond, 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 reactor

Plant Capacity/Production60 MWe

CoalBituminous, 2.0–2.8% sulfur

Project 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 ab-sorbs some of the SO2 in the boiler flue gas. The lime-stone is calcined into calcium oxide and is available forcapture of additional SO2 downstream in the activation, orhumidification, 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 flue gas along with the fly ash inthe electrostatic precipitator (ESP). The sorbent materialfrom the reactor and electrostatic precipitator are recircu-lated back through the reactor for increased efficiency.The waste is dry, making it easier to handle than the wetscrubber sludge produced by conventional wet limestonescrubber systems.

The technology enables power plants with space limita-tions to use high-sulfur midwestern coals, by providing aninjection process that removes 75–85% of the SO2 fromflue gas and produces a dry solid waste product suitablefor disposal in a landfill.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


199619951994199319921991199019891988

Preaward Operation and ReportingDesign and Construction

Preoperational tests initiated 7/92Environmental monitoring plancompleted 6/12/92Construction completed 6/92

11/90 9/9212/89

DOE selected project (CCT-III) 12/19/89



Ground breaking/construction started 5/29/91

Original design completed 7/91

Operation initiated 9/92

Operation completed 6/94

19981997

4/98

Project completed/finalreport issued 4/98

Results SummaryEnvironmental• SO2 removal efficiency was 70% at a calcium-to-sulfur

(Ca/S) molar ratio of 2.0, approach-to-saturation tem-perature 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 onsulfur 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 demonstrationsystem configuration. Increasing the recycle rate andsustaining a 5 ºF approach-to-saturation temperaturewere projected to increase SO2 removal efficiency to85% at a Ca/S molar ratio of 2.0 and limestone fine-ness of 80% minus 325 mesh.

• ESP efficiency and operating levels were essentiallyunaffected by LIFAC during steady-state operation.

• Fly and bottom ash were dry and readily disposed ofat a local landfill. The quantity of additional solidwaste can be determined by assuming that approxi-mately 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 designmake the LIFAC system easy to operate in startup,shutdown, or normal duty cycles.

• The amount of bottom ash increased slightly, but therewas 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$)—$65/ton of SO2 removed,assuming 75% SO2 capture, Ca/S molar ratio of 2.0,limestone composed of 95% CaCO3, and costing$15/ton.


The LIFAC system successfully demonstrated at WhitewaterValley Station Unit No. 2 is being retained by Richmond Power& Light for commercial use with high-sulfur coal. There are 10full-scale LIFAC units in Canada, China, Finland, Russia, andthe United States.

Project SummaryThe LIFAC technology was designed to enhance the ef-fectiveness of dry sorbent injection systems for SO2 con-trol and to maintain the desirable aspects of low capitalcost 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 hostboiler and associated subsystems prior to LIFACoperations.

• Parametric tests were designed to evaluate the manypossible combinations of LIFAC process parametersand their effect on SO2 removal.

• Optimization tests were performed after the parametrictests to evaluate the reliability and operability of theLIFAC process over short, continuous operating peri-ods.

• Long-term tests were designed to demonstrate LIFAC’sperformance under commercial operating conditions.

• Post-LIFAC tests involved repeating the baseline testto 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 effi-ciency were evaluated. The four major parameters havingthe greatest influence on sulfur removal efficiency werelimestone fineness, Ca/S molar ratio, reactor bottom tem-perature (approach-to-saturation), and ESP ash recyclingrate. Total SO2 capture was about 15% better when inject-ing fine limestone (80% minus 325 mesh) than it waswith coarse limestone (80% minus 200 mesh).

While injecting the fine limestone, the sootblowing fre-quency had to be increased from 6-hour to 4.5-hourcycles. The coarse-quality limestone did not affect soot-

blowing but was found to be more abrasive on the feedand transport hoses.

Parametric tests indicated that a 70% SO2 reduction wasachievable with a Ca/S molar ratio of 2.0. ESP ash con-taining unspent sorbent and fly ash was recycled from theESP hoppers back into the reactor inlet duct work. Ashrecycling was found to be essential for efficient SO2 cap-ture. However, the large quantity of ash removed from theLIFAC reactor bottom and the small size of the ESP hop-pers limited the ESP ash recycling rate. As a result, theamount of material recycled from the ESP was approxi-mately 70% less than had been anticipated, but even thislow recycling rate was found to affect SO2 capture. Dur-ing a brief test, it was found that increasing the recyclerate by 50% resulted in a 5% increase in SO2 removalefficiency. It was estimated that if the reactor bottom ashis recycled along with ESP ash, while sustaining a reactortemperature of 5 ºF above saturation temperature, an SO2reduction of 85% could be maintained.

Operational PerformanceOptimization testing began in March 1994 and was fol-lowed by long-term testing in June 1994. The boiler wasoperated at an average load of 60 MWe during long-termtesting, although it fluctuated according to power de-mand. The LIFAC process automatically adjusted toboiler 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 toavoid ash buildup on the steam reheaters. Atomized waterdroplet size was smaller than optimum for the same rea-son. Other key process parameters held constant duringthe long-term tests included the degree of humidification,grind size of the high-calcium-content limestone, andrecycle of spent sorbent from the ESP.

Long-term testing showed that SO2 reductions of 70% ormore can be maintained under normal boiler operatingconditions. Stack opacity was low (about 10%) and ESPefficiency was high (99.2%). The amount of boiler bot-tom ash increased slightly during testing, but there was nonegative impact on the power plant’s bottom and fly ashremoval system. The solid waste generated was a mixtureof fly ash and calcium compounds, and was readily dis-posed of at a local landfill.

The LIFAC system proved to be highly practical becauseit has few moving parts and is simple to operate. Theprocess can be easily shut down and restarted. The pro-cess is automated by a programmable logic system thatregulates process control loops, interlocking, startup,shutdown, and data collection. The entire LIFAC processwas easily managed via two personal computers locatedin the host utility’s control room.


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 undernormal 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 lime-stone to remove 1.0 ton of SO2, assuming 75% SO2 cap-ture, a Ca/S molar ratio of 2.0, and limestone containing95% CaCO3. Assuming limestone costs of $15/ton,LIFAC’s operating cost would be $65/ton of SO2removed.

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 Rich-mond 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)


ReferencesLIFAC 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. Re-port No. DOE/FE-0215P-21. Spring 1996.

“Commercialization of the LIFAC Sorbent Injection Pro-cess in North America.” Third Annual Clean Coal Tech-nology Conference: Technical Papers. Viiala, J., et al.September 1994.

Comprehensive Report to Congress on the Clean CoalTechnology Program: LIFAC Sorbent Injection Desulfur-ization Demonstration Project. LIFAC-North America.Report No. DOE/FE-0207P. U.S. Department of Energy,October 1990. (Available from NTIS as DE91001077.)



Advanced 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

hostMitsubishi Heavy Industries, Ltd.—process designerStearns-Roger Division of United Engineers and

Constructors—facility designerAir 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


CoalBituminous, 2.0–4.5% sulfur

Project 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 approxi-mately one-half the cost of conventional scrubbingtechnology, significantly reduce space requirements, andcreate no new waste streams.

Technology/Project DescriptionPure Air built a single SO2 absorber for a 528-MWepower plant. Although the largest capacity absorber mod-ule of its time in the United States, space requirementswere modest because no spare or backup absorber mod-ules were required. The absorber performed three func-tions 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 rela-tively high velocity compared to that in conventional

scrubbers. These features all combined to yield a state-of-the-art SO2 absorber that was more compact and less ex-pensive than contemporary conventional scrubbers.

Other technical features included the injection of pulver-ized limestone directly into the absorber, a device calledan air rotary sparger located within the base of the ab-sorber, and a novel wastewater evaporation system. Theair rotary sparger combined the functions of agitation andair distribution into one piece of equipment to facilitatethe oxidation of calcium sulfite to gypsum.

Pure Air also demonstrated a unique gypsum agglomera-tion process, PowerChip®, to significantly enhance han-dling characteristics of AFGD-derived gypsum.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

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1 2


19981997199619951994199319921991199019891988

Design and Construction Operation and ReportingPreaward9/88

Project completed/final report issued 6/96Design completed 9/92Construction 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


Preoperational tests initiated 3/92

Operation initiated 6/92Operation completed 6/95

Results SummaryEnvironmental• The AFGD design enabled a single 600-MWe absorber

module without spares to remove 95% or more SO2 atavailabilities of 99.5% when operating with high-sulfur coals.

• Wallboard-grade gypsum was produced in lieu of solidwaste, and all gypsum produced was sold commer-cially.

• The wastewater evaporation system (WES) mitigatedexpected increases in wastewater generation associatedwith gypsum production and showed the potential forachieving zero wastewater discharge (only a partial-capacity WES was installed).

• PowerChip® increased the market potential for AFGD-derived gypsum by cost-effectively converting it to aproduct with the handling characteristics of naturalrock gypsum.

• Air toxics testing established that all acid gases wereeffectively captured and neutralized by the AFGD.

Trace elements largely became constituents of thesolids streams (bottom ash, fly ash, and gypsum prod-uct). Some boron, selenium, and mercury passed to thestack gas in a vapor state.

Operational• AFGD use of co-current, high-velocity flow; integra-

tion of functions; and a unique air rotary spargerproved to be highly efficient, reliable (to the exclusionof requiring a spare module), and compact. The com-pactness, combined with no need for a spare module,significantly reduced space requirements.

• The own-and-operate contractual arrangement—PureAir 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.


Exhibit 5-13 Pure Air SO2 Removal Performance

(100% Boiler Load)

Project SummaryThe project proved that single absorber mod-ules of advanced design could process largevolumes of flue gas and provide the requiredavailability and reliability without the usualspare absorber modules. The major perfor-mance 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 cap-ture efficiencies of 95% or more, and over210,000 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 wall-board production plant.

Environmental PerformanceTesting over the three-year period clearly established thatAFGD operating within its design parameters (withoutadditives) could consistently achieve 95% SO2 reductionor 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 gyp-sum). 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 de-sign L/G range was 50–128 gal/1,000 ft3. The lower endof 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 afunction of load, sulfur content, stoichiometric ratio, andL/G. Loads tested were 33%, 67%, and 100%. High re-moval efficiencies, well above 95%, were possible atloads of 33% and 67% with low to moderate stoichio-metric 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 em-ploying 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 in-creases due to lower sulfate availability. The primaryimportance of producing a commercial-grade gypsum isavoidance of the environmental and economic conse-quences of disposal. Marketability of the gypsum is de-pendent upon whether users are in range of economictransport and whether they can handle the gypsum by-product. For these reasons, PowerChip® technology wasdemonstrated as part of the project. This technology usesa compression mill to convert the highly cohesive AFGDgypsum cake into a flaked product with handling charac-

teristics equivalent to natural rock gypsum.The process avoids use of binders, pre-dry-ing, or pre-calcining normally associated withbriquetting, and is 30–55% cheaper at $2.50–$4.10/ton.

Air toxics testing established that all acidgases are effectively captured and neutralizedby the AFGD. Trace elements largely becomeconstituents of the solids streams (bottomash, fly ash, gypsum product). Some boron,selenium, and mercury pass to the stack gasin a vapor state.

Operational PerformanceAvailability over the 3-year operating periodaveraged 99.5% while maintaining an aver-age SO2 removal efficiency of 94%. This wasattributable to the simple, effective designand an effective operating/maintenance phi-losophy. Modifications contributed to the

high availability. An example was the implementation ofnew alloy technology, C-276 alloy over carbon steel cladmaterial, to replace alloy wallpaper construction withinthe absorber tower wet/dry interface. The use of co-cur-rent rather than conventional counter-current flow re-sulted in lower pressure drops across the absorber andafforded the flexibility to increase gas flow without anabrupt drop in removal efficiency. The AFGD SO2 cap-ture efficiency with limestone was comparable to that inwet scrubbers using lime, which is far more expensive.The 24-hour power consumption was 5,275 kW, or 61%of expected consumption; and water consumption was1,560 gal/min, or 52% of expected consumption.

Economic PerformanceExhibit 5-14 summarizes capital and levelized 1995 cur-rent dollar cost estimates for nine cases with varying plantcapacity and coal sulfur content. A capacity factor of 65%and a sulfur removal efficiency of 90% were assumed.The calculation of levelized cost followed guidelinesestablished in EPRI’s Technical Assessment Guide™.

The incremental benefits of the own-and-operate arrange-ment, by-product utilization, and emission allowanceswere also evaluated. Exhibit 5-15 depicts the relative


Exhibit 5-14Estimated Costs for an AFGD System

(1995 Current Dollars)Cases: 1 2 3 4 5 6 7 8 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

Exhibit 5-15Flue Gas Desulfurization

Economics

500-MWe plant, 30-yr levelized costs, allowance value of$300/ton

Incremental cases:

A�Conventional FGD (EPRI model)

B�AFGD, own-and-operate arrangement

C�Adds gypsum sales

D�Adds emission allowance credits at $300/ton, for 90% SO2removal

E�Increases SO2 removal to 95%

costs of a hypothetical 500-MWe generating unit in theMidwest burning 4.3% sulfur coal with a base case con-ventional 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 AFGDtechnology has markedly reduced cost and demonstratedthe ability to compete with fuel switching under certaincircumstances even with a first-generation system. Ad-vances in technology, e.g., in materials and components,should lower costs for AFGD. The own-and-operate busi-ness approach has done much to mitigate risk on the partof prospective users. High SO2 capture efficiency offersthe AFGD user the possibility of generating allowances orapplying credits to other units within the utility. WES andPowerChip® mitigate or eliminate otherwise serious envi-ronmental concerns. AFGD effectively deals with hazard-ous air pollutants.

The project received Power magazine�s 1993 PowerplantAward and the National Society of Professional Engi-neers� 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)


ReferencesSummary of Air Toxics Emissions Testing at Sixteen Util-ity Power Plants. Prepared by Burns and Roe ServicesCorporation for U.S. Department of Energy, PittsburghEnergy Technology Center. July 1996.

Advanced Flue Gas Desulfurization (AFGD) Demonstra-tion Project. Final Technical Report, Vol. II: Project Per-formance and Economics. Pure Air on the Lake, L.P.April 1996. (Available from NTIS as DE96050313.)

Advanced Flue Gas Desulfurization Project: Public De-sign Report. Pure Air on the Lake, L.P. March 1990.

$/Ton SO2 $/106 Btu



Demonstration 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

consultantErshigs, Inc.—fiberglass fabricatorComposite Construction and Equipment—fiberglass

sustainment consultantAcentech—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) pro-cess using the Jet Bubbling Reactor®


CoalIllinois No. 5 & No. 6 blend, 2.4% sulfurCompliance coal, 1.2% sulfur

Project FundingTotal project cost $43,074,996 100%DOE 21,085,211 49Participant 21,989,785 51Project ObjectiveTo demonstrate 90% SO2 control at high reliability withand 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 reliabil-ity; and to evaluate use of gypsum to reduce waste man-agement costs.

Technology/Project DescriptionThe project demonstrated the CT-121 AFGD process,which uses a unique absorber design known as the Jet

Bubbling Reactor® (JBR). The process combines lime-stone AFGD reaction, forced oxidation, and gypsumcrystallization in one process vessel. The process is me-chanically and chemically simpler than conventionalAFGD processes and can be expected to exhibit lowercost characteristics.

The flue gas enters underneath the scrubbing solution inthe JBR. The SO2 in the flue gas is absorbed and formscalcium sulfite (CaSO3). Air is bubbled into the bottom ofthe solution to oxidize the calcium sulfite to form gyp-sum. The slurry is dewatered in a gypsum stack, whichinvolves filling a diked area with gypsum slurry. Gypsumsolids settle in the diked area by gravity, and clear waterflows to a retention pond. The clear water from the pondis returned to the process.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental• Over 90% SO2 removal efficiency was achieved at SO2

inlet concentrations of 1,000–3,500 ppm with lime-stone utilization over 97%.

• JBR achieved particulate removal efficiencies of 97.7–99.3% for inlet mass loadings of 0.303–1.392 lb/106

Btu over a load range of 50–100 MWe.• Capture efficiency was a function of particle size:

– >10 microns—99% capture– 1–10 microns—90% capture– 0.5–1 micron—negligible capture– <0.5 micron—90% capture

• Hazardous air pollutant (HAP) testing showed greaterthan 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 wall-board/cement-grade gypsum.

Operational• FRP-fabricated equipment proved durable both struc-

turally and chemically, eliminating the need for a fluegas prescrubber and reheat.

• FRP construction combined with simplicity of designresulted in 97% availability at low ash loadings and95% at high ash loadings, eliminating the need for aspare reactor module.

• Simultaneous SO2 and particulate control wereachieved 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 vari-

able operating costs were $34–64/ton of SO2 removed,depending on specific test conditions.

• Generic plant costs were not estimated; however,elimination of the need for flue gas prescrubbing,reheat, and a spare module should result in capitalrequirements far below those of contemporary conven-tional flue gas desulfurization (FGD) systems.

20001999199619951994199319921991199019891988

4/90Design and Construction Operation and ReportingPreaward

9/88 10/92



NEPA process completed (EA)8/10/90Ground breaking/constructionstarted 8/23/90

Environmental monitoringplan completed 12/18/90



Operation initiated 10/92Construction completed 10/92

10/99



**

** Years omitted


Project SummaryThe CT-121 AFGD process differs from the more com-mon 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. Pump-ing of reacted slurry to a gypsum transfer tank is intermit-tent. 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 amarginally performing particulate collection device. TheSO2 removal efficiency was measured under five differentinlet 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 lime-stone 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 pre-scrubber to remove chlorides was eliminated. Similarly,the FRP-constructed chimney proved resistant to the cor-rosive 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 agglom-eration on the sparger tube walls during high ash loadingwhen the ESP was deenergized. The high reliability dem-onstrated 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 concen-tration increased, removal efficiencydecreased, but adjustments in JBRfluid level could maintain the effi-ciency above 90% and, at lower SO2concentration levels, above 98%.Limestone utilization remainedabove 97% throughout the demon-stration. 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 per-centage of the outlet particulatematter is sulfate, likely a result ofacid mist and gypsum carryover.

This reduces the estimate of ash mass loading at the outletto approximately 70% of the measured outlet particulates.

For particulate sizes greater than 10 microns, captureefficiency was consistently greater than 99%. In the 1–10micron range, capture efficiency was over 90%. Between0.5 and 1 micron, the particulate removal dropped attimes to negligible values, possibly due to acid mistcarryover entraining particulates in this size range. Below0.5 micron, the capture efficiency increased to over 90%.Calculated air toxics removals across the CT-121 JBR,based on the measurements taken during the demonstra-tion, are shown in Exhibit 5-19.As to solids handling, the gypsum stacking methodproved effective in the long term. Although chloride con-tent was initially high in the stack due to the closed loopnature of the process (with concentrations often exceed-ing 35,000 ppm), a year later the chloride concentration inthe gypsum dropped to less than 50 ppm, suitable forwallboard and cement applications. The reduction inchloride content was attributed to rainwater washing thestack.

Exhibit 5-16Operation of CT-121 Scrubber

Low Ash Elevated Ash Cumulative

Phase Phase for Project

Total test period (hr) 11,750 7,250 19,000Scrubber available (hr) 11,430 6,310 18,340Scrubber operating (hr) 8,600 5,210 13,810Scrubber called upon (hr) 8,800 5,490 14,290

Reliabilitya 0.98 0.95 0.96Availabilityb 0.97 0.95 0.97Utilizationc 0.73 0.72 0.75a 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

Exhibit 5-17SO2 Removal Efficiency


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 spe-cific test conditions.

FRP construction eliminates the need for prescrubbingand reheating flue gas. High system availability elimi-nates 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 South-ern 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 generat-ing capacity by the year 2010. A 90% reduction in SO2emissions 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 compli-ance 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 Out-standing 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 5-19CT-121 Air Toxics Removal

(JBR Components Only)

ContactsDavid P. Burford, Project Manager, (205) 257-6329

Southern CompanyP.O. Box 2641 / bin no. 13N-8060Birmingham, AL 35242(205) 257-7161 (fax)

James U. Watts, DOE/NETL, (412) 386-5991

ReferencesSouthern Company Services, Inc. Demonstration of Inno-vative Applications of Technology for Cost Reductions tothe CT-121 FGD Process. Final Report. Volumes 1-6.January 1997.

Comprehensive Report to Congress on the Clean CoalTechnology Program: Demonstration of Innovative Appli-cations of Technology for the CT-121 FGD Process.Southern Company Services, Inc. Report No. DOE/FE-0158. U.S. Department of Energy. February 1990. (Avail-able from NTIS as DE9008110.)

Exhibit 5-18CT-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 Yatespermit limit is 0.24 lb/106 Btu as an existing unit.



Environmental Control DevicesNOx Control Technologies

5-44 Program Update 2001 Environmental Control Devicesi

Environmental Control DevicesNOx 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 supplierGeorgia Power Company—hostPowerGen—cofunderU.K. Department of Trade and Industry—cofunderEnTEC—technology supplierRadian—technology supplierTennessee Technological University—technology supplierSouthern Company—cofunder

LocationCoosa, Floyd County, GA (Georgia Power Company’sPlant Hammond, Unit No. 4)

TechnologyFoster Wheeler’s low-NOx burner (LNB) with advancedoverfire air (AOFA) and EPRI’s Generic NOx ControlIntelligent System (GNOCIS) computer software.


CoalEastern bituminous coals, 1.7% sulfur


Project ObjectiveTo achieve 50% NOx reduction with the LNB/AOFAsystem; to determine the contributions of AOFA and LNBto NOx 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 perfor-mance, 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 (sub-stoichiometric), without increasing combustible losses;and (2) introducing “boundary air” at the boiler walls toprevent corrosion caused by the reducing atmosphere.

In the Foster Wheeler Controlled Flow/Split Flame(CFSF) LNB, fuel and air mixing is staged by regulatingthe primary air/fuel mixture, velocities, and turbulence tocreate a fuel-rich core with sufficient air to sustain com-bustion at a severely sub-stoichiometric air/fuel ratio. Theburner also controls the rate at which additional air, nec-essary to complete combustion, is mixed with the flamesolids and gases so as to maintain a deficiency of oxygenuntil the remaining combustibles fall below the peakNOx-producing temperature (around 2,800 °F). The finalexcess air then can be allowed to mix with the unburnedproducts so that combustion is completed at a relativelylow temperature. The CFSF LNB splits the coal/airmixture into four streams, which minimizes coal and airmixing and combustion staging.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental• Using LNB alone, long-term NOx emissions were 0.65

lb/106 Btu, representing a 48% reduction from baselineconditions (1.24 lb/106 Btu).

• Using AOFA only, long-term NOx emissions were 0.94lb/106 Btu, representing a 24% reduction from baselineconditions.

• Using LNB/AOFA, long-term NOx emissions were0.40 lb/106 Btu, representing a 68% reduction frombaseline conditions.

• Chemical emissions testing showed no evidence oforganic compound emissions resulting from the com-bustion modifications installed for NOx control. Traceelement control, except for mercury and selenium,proved to be a function of electrostatic precipitator(ESP) performance.

Operational• AOFA accounted for an incremental NOx reduction

beyond the use of LNB of approximately 17%, withadditional reductions resulting from other operationalchanges.

• GNOCIS achieved a boiler efficiency gain of 0.5 per-centage points, a reduction in fly ash loss-on-ignition(LOI) levels of 1–3 percentage points, and a reductionin NOx emissions of 10–15% at full load.

• Fly ash LOI increased from a baseline of 7% (cor-rected to representative excess oxygen conditions) to10% 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 NOx removal is $79/ton using LNB/AOFA in a baseload dispatch scenario experienced atPlant Hammond.

Preaward

20021999199819961994199319921991199019891988

9/88 6/9012/89Design and Construction

DOEselectedproject(CCT-II)9/28/88

Design completed, 3/90Construction started, AOFA 4/90

Construction completed, AOFA 5/90Operation initiated, AOFA 6/90


Construction started, LNB;Operation completed, AOFA 3/91

Construction completed, LNB;Operation initiated, LNB 4/91

NEPA processcompleted (MTF)

5/22/89

Operation completed,LNB 1/92

Operation initiated, LNB/AOFA 5/93


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

Final report(Phase 4)issued 9/98

Project completed/final report issued 6/02*

6/02

**

Cooperative agreementre-signed 9/15/99

**

*Projected date**Years OmittedCooperative agreement awarded, 12/20/89

1 2


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 require-ments and fly ash loading to the electrostatic precipitator(ESP), adversely affected the unit’s stack particulate emis-sions. The LNB/AOFA testing was conducted from Janu-ary 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. In-creased LOI was a concern not only because of the asso-ciated efficiency loss, but also due to a potential loss of

Exhibit 5-20LOI Performance Test Results

Exhibit 5-21NOx vs. LOI Tests—All Sensitivities

Exhibit 5-22Typical Trade-Offs in Boiler Optimization

fly ash sales. The increased carbon in the flyash renders the material unsuitable for use inmaking concrete.

During October 1992, SCS conducted para-metric testing to determine the relationshipbetween NOx and LOI emissions. The param-eters tested were: excess oxygen, mill coalflow bias, burner sliding tip position, burnerouter register position, and burner inner regis-ter position. Nitrogen oxide emissions andLOI levels varied from 0.44–0.57 lb/106 Btuand 3–10%, respectively. As expected, excessoxygen levels had considerable effect on bothNOx and LOI. The results showed that there issome flexibility in selecting the optimumoperating point and making trade-offs be-tween NOx emissions and fly ash LOI; how-ever, much of the variation was the result ofchanges 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 NOxemissions are at the expense of increased fly ash LOI. Incontrast, the slope of the outer register adjustment sug-gests that improvement in both NOx emissions and LOIcan be achieved by adjustment of this damper. However,

due to the relatively small impact of the outerregister adjustment on both NOx and LOI, it islikely the positive NOx/LOI slope is an artifact ofprocess noise.

A subsidiary goal of theproject was to evaluate ad-vanced instrumentation andcontrols (I&C) as applied tocombustion control. The needfor more sophisticated I&Cequipment is illustrated inExhibit 5-22. There are trade-offs in boiler operation, e.g.,as excess air increases, NOxincreases, LOI decreases, andboiler losses increase. Thegoal is to find and maintain

an optimal operating condition. The I&C systems testedincluded GNOCIS and carbon-in-ash analyzers.

The GNOCIS software applies an optimizing procedureto identify the best set points for the plant, which areimplemented automatically without operator intervention(closed-loop), or conveyed to the plant operators forimplementation (open-loop). The major elements ofGNOCIS are shown in Exhibit 5-23. The GNOCIS sys-tem provided advice that reduced NOx emissions by10–15% at full load, while improving the heat rate orreducing fly ash LOI by 1–3 percentage points.


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 base-line levels, a substantial portion of the incremental changein NOx emissions between the LNB and the LNB/AOFAconfigurations 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. Basedon this data set, the full-load, long-term NOx emissionswere 0.40 lb/106 Btu, which was consistent with earliershort-term test data. Earlier long-term testing had resultedin NOx emissions of 0.94 lb/106 Btu for AOFA only and0.65 lb/106 Btu for LNB only.

Chemical emissions testing showed no evidence of or-ganic compound emissions resulting from the combustionmodifications installed for NOx control. Trace elementcontrol, 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 chlo-rine (as hydrochloric acid) and fluorine (as hydrofluoricacid) were captured.

Exhibit 5-23Major Elements of GNOCIS

Economic PerformanceEstimated capital costs for a commercial 500-MWe wall-fired installation are: AOFA—$8.8/kW, LNB—$10.0/kW, LNB/AOFA—$18.8/kW, and GNOCIS—$0.5/kW.Annual O&M costs and NOx reductions depend on theassumed 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 de-creased by 1.3 percent, and the NOx reduction is 68 per-cent of baseline, or 11,615 tons/year at full load. Thecapital cost is $8,300,000 and the calculated cost of NOxremoved 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 themaximum NOx removal case, the efficiency is improvedby 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 gaindue 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/opti-mization. To date, the designs and testing of the optimiza-tion 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 appli-cable to all fossil fuel-fired boilers, including units firedwith natural gas and units cofiring coal and natural gas.

The host has retained the technologies for commercialuse. Foster Wheeler has equipped 86 boilers with low-NOx burner technology (51 domestic and 35 interna-tional)—1,800 burners for over 30,000 MWe capacity.

ContactsJohn N. Sorge, Research Engineer, (205) 257-7426

Southern Company Services, Inc.Mail stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195(205) 257-5367 (fax)[email protected]

James R. Longanbach, NETL, (304) 285-4659

References500-MW Demonstration of Advanced Wall-Fired Com-bustion Techniques for the Reduction of Nitrogen Oxide(NOx) Emissions from Coal-Fired Boilers. Phase 4—Digital Control System and Optimization. Southern Com-pany Services, Inc. September 1998.

500-MW Demonstration of Advanced Wall-Fired Com-bustion Techniques for the Reduction of Nitrogen Oxide(NOx) Emissions from Coal-Fired Boilers. Phases 1-3B,Final Report. Southern Company Services, Inc. January1998.



Demonstration of CoalReburning for Cyclone BoilerNOx ControlProject completedParticipantThe Babcock & Wilcox Company

Additional Team MembersWisconsin Power and Light Company—cofunder and

hostSargent and Lundy—engineer for coal handlingElectric Power Research Institute—cofunderState of Illinois, Department of Energy and Natural

Resources—cofunderUtility 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 Sys-tem (Coal Reburning)


CoalIllinois Basin bituminous (Lamar), 1.15% sulfur, 1.24%nitrogen

Powder River Basin (PRB) subbituminous, 0.27% sulfur,0.55% nitrogen


Project ObjectiveTo demonstrate the technical and economic feasibility ofCoal Reburning to achieve greater than 50% reduction inNOx emissions with no serious impact on cyclone com-bustor operation, boiler performance, or other emissionstreams.

Technology/Project DescriptionBabcock & Wilcox Coal Reburning reduces NOx in thefurnace through the use of multiple combustion zones.The main combustion zone uses 70–80% of the total heat-equivalent fuel input to the boiler, and slightly less 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 NOx formed in the cyclone burners reacts

with the resultant reducing flue gas and is converted intonitrogen in this zone. Completion of the combustion pro-cess occurs in the third zone, called the burnout zone,where the balance of the combustion air is introduced.

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Calendar Year

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Results SummaryEnvironmental• Coal Reburning achieved greater than 50% NOx reduc-

tion at full load with Lamar bituminous and PRB sub-bituminous coals.

• Reburning-zone stoichiometry had the greatest effecton NOx control.

• Gas recirculation was vital to maintaining reburning-zone stoichiometry while providing necessary burnercooling, 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% atfull load and 33–35% at half to moderate loads.

Operational• No major boiler performance problems were experi-

enced with Coal Reburning operations.• Boiler turndown capability was 66%, exceeding the

50% goal.

• ESP efficiency improved slightly during Lamar coaltesting and did not change with PRB coal.

• Coal fineness levels above the nominal 90% through200 mesh were maintained, reducing unburned carbonlosses (UBCL).

• UBCL was the only major contributor to boiler effi-ciency loss, which was 0.1, 0.25, and 1.5 percentagepoints 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 Lamarcoal.

• Expanded volumetric fuel delivery with reburningburners enabled switching to PRB low-rank coal with-out boiler derating.

Economic• Capital costs for 110- and 605-MWe plants were

$66/kW and $43/kW, respectively (1990$).

• Levelized 10- and 30-year busbar power costs for a110-MWe plant were 2.4 and 2.3 mills/kWh, respec-tively (constant 1990$).

• Levelized 10- and 30-year busbar power costs for a605-MWe plant were 1.6 and 1.5 mills/kWh, respec-tively (constant 1990$).

Operationinitiated 12/91

19981997199619951994199319921991199019891988

Design and Construction9/88

Preaward


4/90 12/91Operation and Reporting

3/94

Project completed/final report issued 3/94Operationcompleted 12/92

Environmental monitoring plan completed 11/18/91Construction completed 11/91Preoperational tests initiated 11/91

NEPA process completed (EA) 2/12/91



Cooperative agreementawarded 4/2/90


Wisconsin Power and Light Company�s Nelson Dewey Stationhosted the successful demonstration of Coal Reburning.

Boiler Load110 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 0.30/53

Boiler efficiency losses due 0.0 0.2 0.3to unburned carbon (%)

Exhibit 5-24Coal Reburning Test Results

Project SummaryAlthough cyclone boilers represent only 8.5% of the pre-NSPS coal-fired generating capacity, they contribute 12%of the NOx formed by pre-NSPS coal-fired units. This isdue to the cyclone combustor�s inherent turbulent, high-temperature combustion process. However, at the time ofthis demonstration, there was no cost-effective combus-tion modification available for cyclone boiler NOx con-trol.

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 con-trol options, such as SCR, which have relatively highcapital 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. Subbi-tuminous PRB coal tests were performed to evaluate theeffect of coal switching on reburning operation. Wiscon-sin Power and Light�s strategy to meet Wisconsin�s 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 perfor-mance modes. Exhibit 5-24 shows changes in NOx emis-sions and boiler efficiency using the reburning system forvarious 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 emissionslevels. 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 Reburn-ing were comparable to baseline operation. No majoreffect of reburning on trace-metals partitioning was dis-cernible. None of the 16 targeted polynuclear aromaticsemi-volatile organics (controlled under Title III of

CAAA) were present in detectable con-centrations, at a detection limit of 1.2parts per billion.

Operational PerformanceFor Lamar coal, the full-, medium-, andlow-load efficiency losses due to un-burned carbon were higher than thebaseline by 0.1, 0.25, and 1.5 percent-age points, respectively. Full-, medium-,and low-load efficiency losses withPRB coal were 0.0, 0.2, and 0.3 per-centage points, respectively. Coal Re-burning burner flame stability improvedwith PRB coal.

During Coal Reburning operation withLamar coal, the operators continuallymonitored boiler internals for increasedash deposition and the on-line perfor-

mance monitoring system for heat transfer changes. At notime throughout the system optimization or long-termoperation period were any slagging or fouling problemsobserved. In fact, during scheduled outages, internalboiler inspections revealed that boiler cleanliness hadactually improved. Extensive ultrasonic thickness mea-surements were taken of the furnace wall tubes. No ob-servable decrease in wall tube thickness was measured.

Another significant finding was that Coal Reburningminimizes and possibly eliminates a 0�25% deratingnormally associated with switching to subbituminous coalin a cyclone unit. This derating results from using a lowerBtu fuel in a cyclone combustor, which has a limited coalfeed capacity. Coal Reburning transferred about 30% ofthe coal feed out of the cyclone to the reburning burners,bringing the cyclone feed rate down to a manageable levelwhile maintaining full-load heat input to the unit.

Economic PerformanceAn economic analysis of total capital and levelized rev-enue requirements was conducted using the �ElectricPower Research Institute Economic Premises� for retrofitof 110- and 605-MWe plants. In addition, annualizedcosts per ton of NOx removed were developed for 110-and 605-MWe plants over both 10 and 30 years. The re-sults of these analyses are shown in Exhibit 5-25. Thesevalues assumed typical retrofit conditions and did not


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.

Exhibit 5-25Coal Reburning Economics

(1990 Constant Dollars)Plant Size

Costs 110 MWe 605 MWe

Total capital cost ($/kW) 66 43Levelized busbar powercost (mills/kWh)

10-year life 2.4 1.630-year life 2.3 1.5

Annualized cost ($/ton of NOx removed)

10-year life 1,075 40830-year life 692 263

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 sig-nificantly impact these retrofit costs included the state ofthe existing control system, availability of flue gas recir-culation, 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 100�1,150 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 [email protected](330) 821-7801 (fax)

John C. McDowell, NETL, (412) 386-6175

ReferencesDemonstration of Coal Reburning for Cyclone BoilerNOx 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 NOx 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 NOx Control. Report No. DOE/FE-0157. U.S. De-partment of Energy. February 1990. (Available from NTISas DE90008111.)



Full-Scale Demonstration ofLow-NOx Cell Burner RetrofitProject completedParticipantThe Babcock & Wilcox Company

Additional Team MembersThe Dayton Power and Light Company—cofunder and

hostElectric Power Research Institute—cofunderOhio Coal Development Office—cofunderTennessee Valley Authority—cofunderNew England Power Company—cofunderDuke Power Company—cofunderAllegheny Power System—cofunderCenterior Energy Corporation—cofunder

LocationAberdeen, 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


CoalBituminous, medium sulfur


Project ObjectiveTo demonstrate, through the first commercial-scale fullburner retrofit, the cost-effective reduction of NOx froma large, baseload coal-fired utility boiler with LNCB®

technology and to achieve at least a 50% NOx reductionwithout degradation of boiler performance at less costthan that of conventional low-NOx burners.

Technology/Project DescriptionThe LNCB® technology replaces the upper coal nozzle ofthe 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 toreduce NOx emissions. Combustion is staged by provid-ing only about 58% of the air theoretically required forcomplete combustion through the lower burner and the

balance of the air through the secondary air port (NOxport).

The demonstration was conducted on a Babcock &Wilcox-designed, supercritical once-through boilerequipped with an electrostatic precipitator (ESP). Thisunit, which is typical of cell-burner boilers, contained 24two-nozzle cell burners arranged in an opposed-firingconfiguration. Twelve burners (arranged in two rows ofsix burners each) were mounted on each of two opposingwalls of the boiler. All 24 standard cell burners were re-moved and 24 new LNCBs® were installed. AlternateLNCBs® on the bottom rows were inverted, with the airport then being on the bottom to ensure complete com-bustion in the lower furnace.

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Results SummaryEnvironmental• Short-term optimization testing (all mills in service)

showed NOx 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 8months).

• 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 28–55ppm at full load with LNCB® in service.

• Fly ash increased, but ESP performance remainedvirtually unchanged.

Operational• Unit efficiency remained essentially unchanged.• Unburned carbon losses (UBCL) increased by approxi-

mately 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 equivalentto 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 NOx emission rate and 65%capacity factor, was $9/kW (1994$).

• Levelized cost (15-year) for the same 600-MWe plantwas estimated at 0.284 mills/kWh and $96.48/ton ofNOx removed (constant 1994$).

19981997199619951994199319921991199019891988


10/90Operation and Reporting

Design andConstructionPreaward

12/91



Project completed/final report issued 12/95

12/95


12/89

Construction completed 11/91Preoperational tests initiated 11/91



Environmental monitoring plancompleted 8/9/91



Project SummaryUtility boilers equipped with cell burners currently repre-sent 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 effi-ciency is good, but the rapid heat release produces rela-tively large quantities of NOx.

To reduce NOx emissions, the LNCB® has been designedto 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 alower cost alternative to address NOx reduction require-ments for cell burners.

Environmental PerformanceThe initial LNCB® configuration resulted in excessive COand H2S emissions. Through modeling, a revised configu-ration was developed (inverting alternate burners on thelower rows), which addressed the problem without com-promising boiler performance. The modification served tovalidate model capabilities.

Following parametric testing to establish optimal operat-ing modes, a series of optimization tests were conductedon the LNCB® to assess environmental and operationalperformance. 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 fullload with all mills in service ranged from 53.0–55.5%.With one mill out of service at full load, the average NOxreduction ranged from 53.3–54.5%. Average NOx reduc-tion at intermediate load (about 460 MWe) ranged from52.5–54.7%. At low loads (about 350 MWe), averageNOx reduction ranged from 46.9–47.9%. NOx emissionswere 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 werecorrected 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 dueto SO3 injection, and therefore ESP removal efficiencyremained 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 were99.43%, 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 opti-mizing LNCB® operation, levels were largely at the lowerdetection limit. There were some higher local readings,

but corrosion panel tests established that corrosion rateswith LNCB® were roughly equivalent to pre-retrofit rates.

Ash sample analyses indicated that ash deposition wouldnot be a problem. The LNCB® ash differed little frombaseline ash. Furthermore, the small variations observedin furnace exit gas temperature between baseline andLNCB® indicated little change in furnace slagging.Startup and turndown of the unit were unaffected by con-version to LNCB®.

Economic PerformanceThe economic analyses were performed for a 600-MWenominal unit size and typical location in the MidwestUnited States. A medium-sulfur, medium-volatile bitumi-nous coal was chosen as the typical fuel. For a baselineNOx emission level of 1.2 lb/106 Btu, 65% capacity fac-tor, and a 50% reduction target, the estimated capital costwas $9/kW (1994$). The 15-year levelized cost of elec-


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 ofNOx removed in constant 1994 dollars.

Commercial ApplicationsThe low cost and short outage time for retrofit make theLNCB® design the most cost-effective NOx control tech-nology available today for cell-burner boilers. TheLNCB® system can be installed at about half the cost andtime of other commercial low-NOx burners.

Dayton Power & Light has retained the LNCB® for use incommercial service. Seven commercial contracts havebeen awarded for 172 burners, valued at $24 million.LNCBs® have already been installed on more than 4,900MWe of capacity.

The demonstration project received R&D magazine’s1994 R&D Award.


McDermott Technology, Inc.1562 Beeson StreetAlliance, OH [email protected](330) 821-7801 (fax)


ReferencesFinal Report: Full-Scale Demonstration of Low-NOxCell™ Burner Retrofit. Report No. DOE/PC/90545-T2.The Babcock & Wilcox Company, Research and Develop-ment Division. December 1995. (Available from NTIS asDE96003766.)

Full-Scale Demonstration of Low-NOx Cell Burner Retro-fit: 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 Low-NOx Cell Burner Retrofit. The Babcock & Wilcox Com-pany. Report No. DOE/FE-0197P. U.S. Department ofEnergy. July 1990. (Available from NTIS asDE90018026.)



Evaluation of Gas Reburningand Low-NOx Burners on aWall-Fired BoilerProject completedParticipantEnergy and Environmental Research Corporation

Additional Team MembersPublic Service Company of Colorado—cofunder and hostGas Research Institute—cofunderColorado Interstate Gas Company—cofunderElectric Power Research Institute—cofunderFoster Wheeler Energy Corp.—technology supplier

LocationDenver, 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% ash

Project 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 anexisting wall-fired utility boiler, firing low-sulfur coalusing both gas reburning and low-NOx burners (GR-LNB); and to assess the impact of GR-LNB on boilerperformance.

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 combus-tion by limiting available oxygen creates a fuel-rich zone.NOx moving upward from coal combustion in the lowerfurnace is stripped of oxygen as the reburn fuel is par-tially 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-NOxburners 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 burnerswas intended to lower NOx emissions by up to 70%. Gasreburning was demonstrated with and without the use ofrecirculated flue gas.

A series of parametric tests was performed on the gasreburning system, varying operational control parametersand assessing the effect on boiler emissions, complete-ness of combustion (carbon-in-ash or loss-on-ignition),thermal efficiency, and heat rate. A one-year long-termtesting program was performed in order to judge the con-sistency of system outputs, assess the impact of long-termoperation on the boiler equipment, gain experience inoperating GR-LNB in a normal load-following environ-ment, and develop a database for use in subsequent GR-LNB applications. Both first- and second-generation gasreburning tests were performed.

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Results SummaryEnvironmental• LNB alone reduced NOx emissions from a pre-con-

struction 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 recir-culation in combination with LNB, reduced NOx emis-sions to an average 0.25 lb/106 Btu (at 3.25% O2), a66% NOx reduction at an 18% gas heat input rate.

• Second-generation GR, without flue gas recirculationand in combination with LNB, reduced NOx emissionsto an average 0.26 lb/106 Btu, a 64% NOx reductionwith only 12.5% gas heat input.

• Both first- and second-generation GR with LNB werecapable of reducing NOx emissions by up to 70% forshort periods of time; the average was approximately65%.

• After modifying the overfire air system to enhancepenetration and turbulence (as part of second-genera-tion GR), CO emissions were controlled to acceptablelevels at low gas heat input rates.

• SO2 emissions and particulate loadings were reducedby the percentage heat input supplied by GR.

Operational• Boiler efficiency decreased #1.0%.• There was no measurable boiler tube wear and only a

small amount of slagging.• Carbon-in-ash and CO levels were acceptable for first-

and second-generation GR with LNB, but not withLNB 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 differ-ential and the value of SO2 emission allowances be-cause GR reduces SO2 emissions when displacingcoal.

19991998199619951994199319921991199019891988

Preaward Operation and Reporting12/89

Design and Construction10/90 11/92

DOE selected project (CCT-III) 12/19/89Environmental monitoring plan completed 7/26/90





Construction completed;Operation initiated 11/92

Long-term operationsstarted 4/93


Restorationcompleted 11/95

10/98


**

**Years omitted


Project SummaryThe demonstration established that GR-LNB offers acost-effective option for deep NOx reductions on wall-fired boilers. GR-LNB NOx control performance ap-proached that of selective catalytic reduction (SCR), butat significantly lower cost. The importance of cost-effec-tive technology for deep NOx reductions is that it meetsthe need for NOx reduction in ozone nonattainment areasbeyond what is currently projected in Title IV of theCAAA. Title I of the CAAA deals with ozone nonattain-ment and is currently the driving force for deep NOx re-duction in many regions of the country.

The GR-LNB was installed and evaluated on a 172-MWe(gross) wall-fired boiler—a Babcock & Wilcox balanced-draft pulverized coal-fired unit. The GR system, includingan overfire air system, was designed and installed by

A worker inspects the support ring for the Foster Wheeler low-NOx burner installed in the boiler wall.

GR Generation

First Second

Baseline (lb/106 Btu) 0.73 0.73Avg NOx reduction (%)

LNB 37 44GR-LNB 66 64

Avg gas heat input (%) 18 12.5

Exhibit 5-26NOx Data from Cherokee

Station, Unit No. 3

Energy and Environmental Research Corporation. TheLNBs were designed and installed by Foster WheelerEnergy Corp.

Parametric testing began in October 1992 and was com-pleted 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 withincreasing gas heat input. At gas heat inputs greater than10%, NOx emissions were reduced marginally as gas heatinput increased. Natural gas also reduced SO2 emissionsin proportion to the gas heat input. At the Cherokee Sta-tion, low-sulfur (0.40%) coal is used, and typical SO2emissions are 0.65 lb/106 Btu. With a gas heat input of20%, SO2 emissions decreased by 20% to 0.52 lb/106 Btu.The CO2 emissions were also reduced as a result of usingnatural gas because it has a lower carbon-to-hydrogenratio than coal. At a gas heat input of 20%, the CO2 emis-sions were reduced by 8%.

Long-term testing was initiated in April 1993 and com-pleted 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 in-cremental 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 designedto provide momentum to the natural gas, was re-moved. (This change significantly reduced capitalcosts.)

• Natural gas injection was optimized at 10% gas heatinput compared to the initial design value of 18%.

Removal of the flue gas recirculation system requiredinstallation of high-velocity injectors, which madegreater use of available natural gas pressure. (Thismodification reduced natural gas usage and thus oper-ating costs.)

• Overfire air ports were modified to provide higher jetmomentum, particularly at low total flows.

Over 4,000 hours of operation were achieved, with theresults shown in Exhibit 5-26. Although the 37% NOxreduction performance of LNB was less than the expected45%, the overall objectives of the demonstration weremet. Boiler efficiency decreased by only 1% during gasreburning due to increased moisture in the fuel resultingfrom natural gas use. Further, there was no measurabletube wear, and only small amounts of slagging occurredduring the GR-LNB demonstration. However, with LNBalone, carbon-in-ash and CO could not be maintained atacceptable levels.

Economic PerformanceGR-LNB is a retrofit technology in which the economicbenefits are dependent on the following site-specific fac-tors:• Gas availability at the site,• Gas/coal cost differential,• Boiler efficiency,


• 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 heatinput 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 equip-ment 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 differen-tial cost of natural gas and coal and reduced by the valueof the SO2 emission credits received due to absence ofsulfur in the gas. A fuel differential of $1.00/106 Btu wasused 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 boosterand 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 netoperating cost is $2.14 million per year and the NOx re-moval 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-reburn-ing system for immediate use; however, a restoration wasrequired 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 Sta-tion 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 [email protected](949) 859-3194 (fax)

Jerry L. Hebb, NETL, (412) 386-6079

ReferencesEvaluation of Gas Reburning and Low-NOx Burners on aWall-Fired Boiler: Performance and Economics Report,Gas Reburning—Low-NOx Burner System, CherokeeStation Unit No. 3, Public Service Company of Colorado.Final Report. July 1998.Guideline Manual: Gas Reburning—Low-NOx BurnerSystem, Cherokee Station Unit No. 3. Public ServiceCompany of Colorado. Final Report. July 1998.

Evaluation of Gas Reburning and Low-NOx Burners on aWall-Fired Boiler (Long-Term Testing, April 1993–Janu-ary 1995). Report No. DOE/PC/90547-T20. Energy andEnvironmental Research Corporation. June 1995. (Avail-able 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. En-ergy and Environmental Research Corporation. June1995. (Available from NTIS as DE95017754.)



Micronized Coal ReburningDemonstration for NOxControlProject completedParticipantNew York State Electric & Gas Corporation

Additional Team MembersEastman Kodak Company—host and cofunderCONSOL (formerly Consolidation Coal Company)—coal

sample testerD.B. Riley—technology supplierFuller Company—technology supplierEnergy and Environmental Research Corporation EER)—

reburn system designerNew York State Energy Research and Development

Authority—cofunderEmpire 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’sMicroMill™ (at Eastman Kodak) technologies for pro-ducing micronized coal

Plant 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 30Participant 6,395,475 70Project ObjectiveTo achieve at least 50% NOx reduction with micronizedcoal reburning technology on a cyclone boiler, to achieve25–35% NOx reduction with micronized coal reburningtechnology in conjunction with low-NOx burners on atangentially fired boiler, and to determine the effects ofcoal micronization on electrostatic precipitator (ESP)performance.

Technology/Project DescriptionThe reburn coal, which can constitute up to 30% of thetotal fuel, is micronized (pulverized to achieve 80% be-low 325 mesh) and injected into a pulverized coal-firedfurnace above the primary combustion zone. At the Mil-liken tangentially fired boiler site, NOx control isachieved by: (1) close-coupled overfire air (CCOFA)reburning in which the top coal injector of the LNCFSIII™ burner is used for injecting the micronized coal, andthe separated overfire air system completes combustion;and (2) the remaining burners and air ports are adjustedfor deep-stage combustion by re-aiming them to create afuel-rich inner zone and fuel-lean outer zone providingcombustion air. At the Kodak Park cyclone boiler site, theFuller MicroMill™ is used to produce the micronizedcoal, reburn fuel is introduced above the cyclone combus-tor, and overfire air is employed to complete the combus-tion.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental• Using a 14.4% reburn fuel heat input on the Milliken

Station tangentially fired boiler at full load resulted ina NOx emission rate of 0.25 lb/106 Btu, which repre-sents a 29% NOx reduction from the 0.35 lb/106 Btuachieved with the LNCFS III™ burner alone (base-line).

• Using a 17.3% reburn fuel heat input (reburn stoichi-ometry of 0.89) on the Kodak Park cyclone boilerresulted in a NOx 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 at18.4% reburn or stoichiometry of 0.87) would be re-quired for long-term compliance with 0.60 lb/106 BtuNOx emission limits.

Operational• Reburning was successfully applied at Milliken Station

using the top coal feed of the LNCFS III™ 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 loss-

on-ignition (LOI), was maintained under 5%;– Increasing the economizer O2 generated the classi-

cal response of higher NOx emissions and lowerLOI—the sensitivity was estimated at 0.1 lb/106

Btu per 1% change in O2 and was relatively inde-pendent of coal fineness;

– Increasing coal fineness reduced both NOx emis-sions and LOI—the effect on NOx was significantonly 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 re-burning, but significantly impacted LOI.

• Testing on the cyclone boiler at Kodak Park showed:– The reburn stoichiometry had a significant effect

on NOx emissions and a significant effect onLOI—lower reburn stoichiometries reduced NOxemissions and increased LOI to 40–45% comparedwith a LOI baseline of 10–15%.

– Short-term testing indicated that LOI could bemaintained at levels similar to baseline levels with-out significantly affecting NOx emissions by main-taining a baseline cyclone heat input.

Economic• The estimated capital cost for retrofitting a generic

300-MWe tangentially fired boiler with micronizedcoal reburning is $4.3 million, or approximately$14/kW (1999$). The corresponding O&M costs areestimated at $0.30 million per year (1999$). The re-sulting total 15-year levelized cost is $1,329/ton ofNOx removed (current 1999$) or $1,023 (constant1999$).

• The estimated capital cost for retrofitting a generic300-MWe cyclone boiler with micronized coal reburn-ing is $16.9 million, or approximately $56/kW(1999$). The corresponding O&M costs are estimatedat $0.80 million per year (1999$). The total 15-yearlevelized cost is $741/ton of NOx removed (current1999$) or $571 (constant 1999$).

3/97Preaward

20012000199919981997199619951994199319921991

9/91 7/92

DOE selectedproject (CCT-IV)9/12/91

Design and Construction Operation and Reporting12/99

Operation completed (Rochester) 10/98

Ground breaking/construction started (Lansing) 3/15/96Design completed (Rochester) 9/96

Ground breaking/construction started (Rochester) 9/8/96

NEPA process completed(CX) 8/13/92


Preoperational tests initiated (Rochester) 1/97Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

Operation initiated (Rochester) 4/97

Environmental monitoring plan completed (Lansing) 8/97Environmental monitoring plan completed (Rochester) 8/97

Construction completed (Lansing) 1/97

Operation initiated (Lansing) 3/97

Project relocated to Lansing and Rochester 12/95

Operation completed (Lansing) 4/99

Project completed 12/99Final report issued 10/99


Project SummaryNYSEG demonstrated the micronized coal reburningtechnology in both tangentially fired and cyclone boilers.The tangentially fired boiler was NYSEG’s Milliken Sta-tion 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 increasingthe unburned carbon in the ash, i.e., loss-on-ignition. Theprimary objective of this two-site project was to demon-strate improvements in coal reburning for NOx emissioncontrol 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 in-creases surface area ninefold.

With this increased surface area and coal fineness (mi-cronized coal has the combustion characteristics of atom-ized oil), carbon combustion occurs in milliseconds andvolatiles are released at an even rate.

Operating PerformanceAt the Milliken Station, the existing ABB Low-NOx Con-centric Firing System™ (LNCFS-III), which includesboth 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 appli-cation, the top-level coal injection nozzles fed micronizedcoal to the upper part of the furnace for this demonstra-tion. The coal injection nozzles at the three lower eleva-tions 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 singleoperating variable had a dominant effect on reburningperformance. A combination of operating settings deter-mined from short-term testing were selected for long-termoperation to achieve the lowest NOx emissions and reli-able operation. Operating settings for long-term operationwere 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. Noadditional 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 compo-nents were designed with a high degree of flexibility toallow for field optimization to accommodate the complexfurnace flow patterns in the cyclone boiler. Two FullerMicroMills™ 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 electro-static 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 emissionsfrom 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 III™ low-NOx burner alone. Boiler efficiency was maintained at88.4–88.8%. Furthermore, concentrating the overfire air

through fewer and higher ports and using finer grindreburn coal maintained LOI below 5%. Based on long-term testing consisting of 23 days of continuous measure-ments, the achievable annual NOx emissions using 15.1%coal reburn heat input were estimated at 0.245 ± 0.011 lb/106 Btu (95% confidence), and the estimated average flyash LOI was 4.4 ± 0.4%. Based on replicated perfor-mance tests and a 95% confidence level, variations inNOx emissions less than 0.006 lb/106 Btu and in fly ashLOI less than 1.5 percentage points were assumed to beof no statistical significance. There were large uncertain-ties with respect to the effects on LOI, possibly becauseLOI generally varied within a relatively narrow range(between 3% and 5%) in response to changing operatingvariables.

With regard to reburn coal fineness and reburn coalquantity, using a finer grind reburn coal (top mill) reducedboth NOx emissions and LOI. The effect on NOx wassignificant (relative to the uncertainty level of 0.006 lb/106 Btu) only for relatively large variations in the top millclassifier speed (and hence coal fineness). Using a finergrind coal (all mills) reduced both NOx emissions andLOI. Decreasing the reburn coal fraction from 25% to14% decreased NOx emissions from 0.25 to 0.23 lb/106

Btu and had a minor effect on LOI (generally less than1.5 percentage points). The decrease in NOx from de-creasing the coal reburn fraction was attributed to lowerexcess air levels in the primary combustion zone as morecoal was diverted to the lower burners.

Reducing the boiler load reduced NOx emissions, and theeffect was greater when the second mill was taken out ofservice. Thus, reducing the boiler load by taking the sec-ond mill out of service is a recommended option. Takingthe second mill out of service while maintaining the sameboiler load reduced NOx emissions at both high (140MW) and low (110 MW) boiler loads, possibly due tolonger residence times in the primary combustion zone.

Changes in air flow resulted in measurable changes inboth NOx reduction and LOI. An increase in the reburncoal transport air (top burner primary air), correspondingto a 20% increase in the air-to-fuel ratio from 2.05 to2.45, increased NOx emissions from 0.28–0.31 lb/106 Btu.This increase in NOx was attributed to less reducing


reburn zones with the additional introduction of an oxi-dant with the reburn fuel. Increasing the top level auxil-iary airflow increased both NOx emissions and LOI. Thisincrease in NOx was attributed to less reducing reburnzones as more oxidant was introduced through the auxil-iary 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 emis-sions and lower or stable LOI. The economizer O2 sensi-tivity was estimated at 0.1 lb NOx/106 Btu per 1% changein O2 and was relatively independent of the reburn coalfineness.

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 III™ and reburnconfigurations. 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 attrib-uted to longer residence times in the furnace prior to over-fire air introduction. Overall, the effect was difficult toquantify due to the limited number of tests.

At Kodak Park, the application of micronized coal re-burning reduced NOx emissions and increased LOI, asexpected. Micronized coal reburning with 17.3% reburnfuel at a reburn stoichometry of 0.89, reduced NOx emis-sions to 0.59 lb/106 Btu from a baseline of 1.36 lb/106 Btu, a 59% reduction, and reduced the boiler effi-ciency from 87.8% to 87.3%. At greater reburn rates,further NOx reduction was achieved to a degree compa-rable with gas reburning systems. At full load, LOI was40–45%, compared with a baseline level of 10–12%.

Based on long-term testing, the achievable annual NOxemissions (at 15.6% reburn or stoichiometry of 0.90)were 0.69 ± 0.03 lb/106 Btu (95% confidence), corre-sponding 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 NOxemissions and a significant effect on the LOI. Lowerreburn stoichiometries reduced NOx emissions and in-creased the LOI, typically dropping below 0.6 lb/106 Btuat 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 NOxformation and less efficient char burnout. The LOI in-crease was also partially due to the staged combustionresulting in shorter residence times under oxidizing con-ditions. At constant heat input levels, the LOI was notsignificantly different with or without reburning, suggest-ing that in reburn applications, the LOI could be main-tained 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 capi-tal 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 lev-elized 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 acurrent 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 furnacemodifications for existing units.

The availability of a coal-reburning fuel, as an additionalfuel to the furnace, enables switching to lower heating-value coals without boiler derating. Commercial units canachieve a turndown of 8:1 on nights and weekends with-out consuming expensive auxiliary fuel.

ContactsJim Harvilla, (607) 762-8630

New York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY [email protected](607) 762-8457 (fax)


ReferencesMicronized Coal Reburning Demonstration for NOxControl. Final Report. New York State Electric & GasCorporation and CONSOL, Inc. October 1999.

Reburning Technologies for the Control of Nitrogen Ox-ides from Coal-Fired Boilers. U.S. Department of Energy,Babcock & Wilcox, EER Corp., and NYSEG. TopicalReport No. 14. May 1999.Savichky et al. “Micronized Coal Reburning Demonstra-tion of NOx Control.” Sixth Clean Coal TechnologyConference: Technical Papers. April–May 1998.



Demonstration of SelectiveCatalytic ReductionTechnology for the Control ofNOx Emissions from High-Sulfur, Coal-Fired BoilersProject completedParticipantSouthern Company Services, Inc.

Additional Team MembersElectric Power Research Institute—cofunderOntario Hydro—cofunderGulf Power Company—host

LocationPensacola, 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% sulfur

Project 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 high-sulfur 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 NOx and ammonia react to form nitrogen and watervapor.

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 calcu-lated 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 demon-stration.

The project demonstrated, at high- and low-dust loadingsof flue gas, the applicability of SCR technology to pro-vide a cost-effective means of reducing NOx emissionsfrom power plants burning high-sulfur U.S. coal.

The demonstration plant, which was located at GulfPower Company’s Plant Crist near Pensacola, Florida,used flue gas from the burning of 2.7% sulfur coal.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental• NOx reductions of over 80% were achieved at an am-

monia slip well under the 5 ppm deemed acceptablefor commercial operation.

• Flow rates could be increased to 150% of design with-out exceeding the ammonia slip design level of 5 ppmat 80% NOx 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 deactiva-tion, went from less than 1 ppm to approximately 3ppm 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 waswithin or below the design limits necessary to protectdownstream equipment.

Operational• Fouling of catalysts was controlled by adequate soot-

blowing 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 resultsof 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 NOx 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.

19981997199619951994199319921991199019891988

Preaward9/88



NEPA processcompleted(MTF) 8/16/89



7/93

Preoperational tests initiated 3/93Environmental monitoring plan completed 3/11/93

Construction completed 2/93Design completed 12/92

11/96





Project SummaryThe demonstration tests were designed to address severaluncertainties, including potential catalyst deactivation dueto poisoning by trace metals species in U.S. coals, perfor-mance of the technology and its effects on the balance-of-plant equipment in the presence of high amounts of SO2and SO3, and performance of the SCR catalyst undertypical U.S. high-sulfur coal-fired utility operating condi-tions. Catalyst suppliers were required to design thecatalyst baskets to match predetermined reactor dimen-sions, 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 be-cause 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 conse-quently NOx reduction generally produced the most sig-nificant changes in ammonia slip. The ammonia slip at60% NOx reduction was at or near the detection limit of1 ppm. As NOx reduction was increased above 80%, am-

Parameter 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 rateLarge reactor (scfm) 3,000 5,000 7,500Small reactor (scfm) 240 400 600

Exhibit 5-27Reactor Baseline Conditions

Exhibit 5-28Catalysts Tested

Catalyst Reactor Size* CatalystConfiguration

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

Exhibit 5-29Average SO2 Oxidation Rate

(Baseline)

monia slip also increased and remained at reasonablelevels up to NOx reductions of 90%. Over 90%, the am-monia slip levels increased dramatically.

The flow rate and temperature effects on NOx reductionwere 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 tempera-ture. With respect to temperature, most catalysts exhibitedfairly significant improvements in overall performance astemperatures increased from 620 °F to 700 °F, but rela-tively little improvement as temperature increased from700 °F to 750 °F. The conclusion was that the benefits ofhigh-temperature operation probably do not outweigh the heatrate penalties involved in operating SCR at the highertemperatures.

Catalyst deactivation was observed by an increase in am-monia slip over time, assuming the NOx reduction effi-ciency was held constant. Over the 12,000 hours of thedemonstration 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), which can be detrimental to down-stream equipment. In general, NOx reduction can be in-creased as the tolerance for SO3 is also increased. Theupper bound for SO2 oxidation for the demonstrationcatalyst was set at 0.75% at baseline conditions. The aver-age SO2 oxidation rate for each of the catalysts is shownin Exhibit 5-29. These data reflect baseline conditionsover the life of the demonstration. All of the catalystswere within design limits, with most exhibiting oxidationrates below the design limit.

Other factors affecting SO2 oxidations were flow rate andtemperature. Most of the catalysts exhibited fairly con-stant SO2 oxidation with respect to flow rate (i.e., spacevelocity). In theory, SO2 oxidation should be inverselyproportional to flow rate. Theoretically, the relationshipbetween SO2 oxidation and temperature should be expo-nential as temperature increases; however, measurementsshowed the relationship to be linear with little differencein SO2 oxidation between 620 ºF and 700 ºF. On the otherhand, between 700 °F and 750 °F, the SO2 oxidation in-creased more significantly.

Other findings from the demonstration deal with pressuredrop, fouling, erosion, air preheater performance, ammo-nia volatilization, and TCLP analysis. Overall reactor


Exhibit 5-32SCR Economics by NOx Removal

40% 60% 80%

Capital cost ($/kW) 52 54 57Operating costs ($/yr) 926,000 1,045,000 1,181,000

Constant 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 5-30SCR Design Criteria

Parameter Specification

Type 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 BtuDesign 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 2,667,000

Constant 1996$ levelized costMills/kWh 2.89 2.57 2.22$/ton NOx removed 2,811 2,500 2,165

Note: 30 year life; 60% NOx removal

Exhibit 5-31SCR 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. Dur-ing 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 honey-comb 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 exacer-bated 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 leach-ability 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 high-sulfur Illinois No. 6 coal. Other key base case designcriteria are shown in Exhibit 5-30.

The economic analysis of capital, operating and mainte-nance (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-MWeunit are shown in Exhibit 5-32. For retrofit applications,the estimated capital costs were $59–112/kW, depending

on the size of the installation and the difficulty andscope of the retrofit. The levelized costs for the retrofitapplications were $1,850–5,100/ton (1996$).

Commercial ApplicationsAs a result of this demonstration, SCR technology hasbeen shown to be applicable to existing and new utilitygenerating capacity for removal of NOx from the fluegas of virtually any size boiler. There are over1,000 coal-fired utility boilers in active commercialservice in the United States; these boilers representa total generating capacity of approximately300,000 MWe.

ContactsLarry Monroe, (205) 257-7772

Southern Company Services, Inc.Mail Stop 14N-8195P.O. Box 2641Birmingham, AL [email protected](205) 257-5367 (fax)


ReferencesMaxwell, J. D., et al. “Demonstration of SCR Technol-ogy for the Control of NOx Emissions from High-SulfurCoal-Fired Utility Boilers.” Fifth Annual Clean CoalTechnology Conference: Technical Papers, January1997.

Demonstration of SCR Technology for the Control ofNOx Emissions from High-Sulfur, Coal-Fired UtilityBoilers: Final Report. Vol. 1. Southern Company Ser-vices, Inc. October 1996. (Available from NTIS, Vol. 1as DE97050873, Vol. 2: Appendixes A–N asDE97050874, and Vol. 3: Appendixes O–T asDE97050875.)



180-MWe Demonstration ofAdvanced Tangentially FiredCombustion Techniques forthe Reduction of NOxEmissions 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 ConcentricFiring System (LNCFS™) with advanced overfire air(AOFA), clustered coal nozzles, and offset air


CoalEastern bituminous, high reactivity


Project ObjectiveTo demonstrate in a stepwise fashion the short- and long-term NOx reduction capabilities of LNCFS™ levels I, II,and III on a single reference boiler.

Technology/Project DescriptionTechnologies demonstrated included LNCFS™ levels I,II, and III. Each level of the LNCFS™ used differentcombinations of overfire air and clustered coal nozzlepositioning to achieve NOx reductions. With theLNCFS™, primary air and coal are surrounded by oxy-gen-rich secondary air that blankets the outer regions ofthe combustion zone. LNCFS™ 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 LNCFS™ II system. This was an advanced overfire

air system that incorporates back pressuring and flowmeasurement capabilities. CCOFA and SOFA were bothused in the LNCFS™ III tangential-firing approach.

Carefully controlled short-term tests were conducted fol-lowed by long-term testing under normal load dispatchconditions. Long-term tests, which typically lasted 2–3months for each phase, best represent the true emissionscharacteristics of each technology. Results presented arebased on long-term test data.

LNCFS is a trademark of ABB Combustion Engineering, Inc.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental• At full load, the NOx emissions using LNCFS™ I, II,

and III were 0.39, 0.39, and 0.34 lb/106 Btu, respec-tively, which represent reductions of 37, 37, and 45%from the baseline emissions.

• Emissions with LNCFS™ were not sensitive to poweroutputs between 100 MWe and 200 MWe, but emis-sions increased significantly below 100 MWe, reach-ing baseline emission levels at 70 MWe.

• Because of reduced effectiveness at low loads,LNCFS™ proved marginal as a compliance option forpeaking load conditions.

• Average CO emissions increased at full load.• Air toxics testing found LNCFS™ to have no clear-cut

effect on the emissions of trace metals or acid gases.Volatile organic compounds (VOCs) appeared to bereduced and semi-volatile compounds increased.

Operational• Loss-on-ignition (LOI) was not sensitive to the

LNCFS™ retrofits, but very sensitive to coal fineness.• Furnace slagging was reduced, but backpass fouling

was increased for LNCFS™ II and III.• Boiler efficiency and unit heat rate were impacted

minimally.• Unit operation was not significantly affected, but oper-

ating flexibility of the unit was reduced at low loadswith LNCFS™ II and III.

Economic• The capital cost estimate for LNCFS™ I was

$5–15/kW, and for LNCFS™ II and III, $15–25/kW(1993$).

• The cost-effectiveness for LNCFS™ I was $103/ton ofNOx removed; LNCFS™ II, $444/ton; and LNCFS™III, $400/ton (1993$).

19981997199619951994199319921991199019891988

Operation and ReportingPreaward9/88 9/90



6/94




Constructioncompleted 5/91Operation initiated 5/91


NEPA processcompleted (MTF)7/21/89

DOE selectedproject(CCT-II)9/28/88


5/91


Project SummaryLNCFS™ technology was designed for tangentially firedboilers, which represent a large percentage of the pre-NSPS coal-fired generating capacity. The technologyreduces NOx by staging combustion vertically in theboiler with separate coal and air injectors, and horizon-tally by creating fuel-rich and lean zones with offset airnozzles. The objective was to determine NOx emissionreductions and impact on boiler performance under nor-mal 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 emissionsand key operating parameters.

At the time of the demonstration, specific NOx emissionregulations 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 LNCFS™ configurationsused to achieve staged combustion. In addition to overfireair, the LNCFS™ incorporates other NOx-reducing tech-niques into the combustion process as shown in Exhibit5-34. 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 fuel-lean zone containing combustion air. The size of thisouter annulus of combustion air can be varied using ad-justable offset air nozzles.

Operational PerformanceExhibit 5-35 summarizes the impacts of LNCFS™ onunit performance.

Environmental PerformanceAt full load, LNCFS™ I, II, and III reduced NOx emis-sions by 37, 37, and 45%, respectively. Exhibit 5-36presents the NOx emission estimates obtained from theassessment of the average annual NOx emissions for threedispatch scenarios.

Air toxics testing found LNCFS™ to have no clear-cuteffect on the emission of trace metals or acid gases. The

Exhibit 5-33LNCFS™ Configurations

Exhibit 5-34Concentric Firing Concept

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 com-pounds increased. The increase in semi-volatile com-pounds was deemed to be consistent with increases in theamount of unburned carbon in the ash.

Economic PerformanceLNCFS™ II was the only complete retrofit (LNCFS™ Iand III were modifications of LNCFS™ II), and thereforecapital cost estimates were based on the Lansing SmithUnit No. 2 retrofit as well as other tangentially firedLNCFS™ retrofits. The capital cost ranges in 1993 dol-lars follow:

• LNCFS™ I—$5–15/kW• LNCFS™ II—$15–25/kW• LNCFS™ III—$15–25/kW

Site-specific considerations have a significant effect oncapital costs; however, the above ranges reflect actualexperience and are planning estimates. The actual capitalcost for LNCFS™ II at Lansing Smith Unit No. 2 was $3million, or $17/kW, which falls within the projectedrange.

The cost-effectiveness of the LNCFS™ technologies isbased on the capital and operating and maintenance costsand the NOx removal efficiency of the technologies. Thecost-effectiveness of the LNCFS™ technologies follows(based on a levelization factor of 0.144 in 1993 constantdollars):

• LNCFS™ I—$103/ton of NOx removed• LNCFS™ II—$444/ton of NOx removed• LNCFS™ III—$400/ton of NOx removed

Commercial ApplicationsThe LNCFS™ technology has potential commercial ap-plication to all the 423 U.S. pulverized coal, tangentiallyfired utility units. These units range from 25 MWe to 950


Exhibit 5-35Unit Performance Impacts Based on Long-Term Testing

Baseline LNCFS™ I LNCFS™ II LNCFS™ III

Avg CO at full load (ppm) 10 12 22 33

Avg excess O2 at full load (%) 3.7 3.2 4.5 4.3

LOI at full load (%) 4.8 4.6 4.2 5.9O2 (%) 4.0 3.9 5.3 4.7

Steam outlet conditions Satisfactory at full Full load: 5–10 ºF Same as baseline 160–200 MWe:load; low temper- lower than baseline satisfactoryatures 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 fouling

Operating flexibility Normal Same as baseline More care required More difficult toat low loads operate than other

systems

Boiler efficiency (%) 90 90.2 89.7 89.85Efficiency change (points) N/A +0.2 -0.3 -0.15

Turbine heat rate (Btu/kWh) 9,000 9,011 9,000 9,000

Unit net heat rate (Btu/kWh) 9,995 9,986 10,031 10,013Change (%) N/A -0.1 +0.36 +0.18

Exhibit 5-36Average Annual NOx Emissions and Percent Reduction

Boiler Duty Cycle Units Baseline LNCFS™ I LNCFS™ II LNCFS™ 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 wide range of coals, from low-volatile bituminous through lignite.

The LNCFS™ has been retained at the host site for com-mercial use. ABB Combustion Engineering has modified116 tangentially fired boilers with LNCFS™ and deriva-tive TFS 2000™ burners, representing over 25,000 MWe.

ContactsLarry Monroe, (205) 257-7772

Southern Company Services, Inc.Mail Stop 14N-8195P.O. Box 2641Birmingham, AL [email protected](205) 257-5367 (fax)


References180-MWe Demonstration of Advanced Tangentially FiredCombustion Techniques for the Reduction of NitrogenOxide (NOx) Emissions from Coal-Fired Boilers: FinalReport and Key Project Findings. Report No. DOE/PC/89653-T14. Southern Company Services, Inc. February1994. (Available from NTIS as DE94011174.)180-MWe Demonstration of Advanced Tangentially FiredCombustion Techniques for the Reduction of NitrogenOxide (NOx) Emissions from Coal-Fired Boilers—PlantLansing Smith—Phase III and Final EnvironmentalMonitoring Program Report. Southern Company Ser-vices, Inc. December 1993.



Environmental Control DevicesCombined SO2/NOx Control Technologies


Environmental Control DevicesCombined SO2 / NOx Control Technology

SNOX™ Flue Gas CleaningDemonstration ProjectProject completedParticipantABB Environmental Systems

Additional Team MembersOhio Coal Development Office—cofunderOhio Edison Company—cofunder and hostHaldor Topsoe a/s—patent owner for process technology,

catalysts, and WSA CondenserSnamprogetti, U.S.A.—cofunder and process designer

LocationNiles, Trumbull County, OH (Ohio Edison’s Niles Sta-tion, Unit No. 2)

TechnologyHaldor Topsoe’s SNOX™ catalytic advanced flue gascleanup system

Plant Capacity/Production35-MWe equivalent slipstream from a 108-MWe boiler

CoalOhio bituminous, 3.4% sulfur

Project FundingTotal project cost $31,438,408 100%DOE 15,719,200 50Participant 15,719,208 50Project ObjectiveTo demonstrate SNOX™ technology at an electric powerplant using U.S. high-sulfur coals in which it will cata-lytically remove 95% of SO2 and more than 90% of NOxfrom flue gas and produce a salable by-product of con-centrated sulfuric acid.

Technology/Project DescriptionIn the SNOX™ process, the stack gas leaving the boiler iscleaned of fly ash in a high-efficiency fabric filter bag-house to minimize the cleaning frequency of the sulfuricacid catalyst in the downstream SO2 converter. The ash-free gas is reheated, and NOx is reacted with small quanti-ties of ammonia in the first of two catalytic reactorswhere the NOx is converted to harmless nitrogen andwater vapor. The SO2 is oxidized to SO3 in a second cata-lytic converter. The gas then passes through a novelglass-tube condenser that allows SO3 to hydrolyze toconcentrated sulfuric acid.

Because the SO2 catalyst follows the NOx catalyst, anyunreacted ammonia (slip) is oxidized in the SO2 catalystlargely to nitrogen and water vapor. Downstream foulingby ammonia compounds is eliminated, permitting opera-

tion at higher than normal stoichiometries. These higherstoichiometries allow smaller catalyst volumes and highreduction efficiencies.

The technology was designed to remove 95% of the SO2and more than 90% of the NOx from flue gas, and pro-duce a salable sulfuric acid by-product using U.S. coals.This was accomplished without using sorbents and with-out creating waste streams.

The demonstration was conducted at Ohio Edison’s NilesStation in Niles, Ohio. The demonstration unit treated a35-MWe equivalent slipstream of flue gas from the 108-MWe Unit No. 2 boiler, which burned a 3.4% sulfur Ohiocoal. The process steps were virtually the same as for afull-scale commercial plant, and commercial-scale com-ponents were installed and operated.

SNOX is a trademark of Haldor Topsoe a/s.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental• SO2 removal efficiency was normally in excess of 95%

for inlet concentrations, averaging about 2,000 ppm.• NOx reduction averaged 94% for inlet concentrations

ranging from 500–700 ppm.• Particulate removal efficiency for the high-efficiency

fabric filter baghouse with SNOX™ system wasgreater than 99%.

• Sulfuric acid purity exceeded federal specifications forClass I acid.

• Air toxics testing showed high capture efficiency ofmost trace elements in the baghouse. A significantportion of the boron and almost all of the mercuryescaped to the stack; but selenium and cadmium, nor-mally a problem, were effectively captured in the aciddrain, as were organic compounds.

• Absence of an alkali reagent contributed to eliminationof secondary pollution streams and increases in CO2emissions.

• Presence of the SO2 catalyst virtually eliminated COand hydrocarbon emissions.

Operational• Having the SO2 catalyst downstream of the NOx cata-

lyst eliminated ammonia slip and allowed the SCR tofunction more efficiently.

• Heat developed in the SNOX™ process was used toenhancet 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 andNOx removed on a constant 1995 dollar basis.

19981997199619951994199319921991199019891988

Operation and Reporting9/88

Preaward Design and Construction


12/89 3/92




Dedication ceremony held 10/17/91Environmental monitoring plan completed 10/31/91


Construction started 1/91

DOE selectedproject (CCT-II)9/28/88

7/96




Project SummaryNo reagent was required for the SO2 removal step becausethe SNOX™ process utilized an oxidation catalyst toconvert SO2 to SO3 and ultimately to sulfuric acid. As aresult, the process produced no other waste streams.

In order to demonstrate and evaluate the performance ofthe SNOX™ process, general operating data were col-lected and parametric tests conducted to characterize theprocess and equipment. The system operated for approxi-mately 8,000 hours and produced more than 5,600 tons ofcommercial-grade sulfuric acid. Many of the tests for theSNOX™ 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 catalystand the sulfuric acid condenser (WSA Condenser). TheNiles SNOX™ 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. Atoperating temperature, the SO2 catalyst retained about90% of the dust that entered the catalyst vessel because ofits sticky surface. Dust that passed through was subse-quently 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 processresulted from two features—the lack of a carbonate-basedalkali reagent that releases CO2, and the fact that the pro-cess recovered additional heat from the flue gas to offsetits 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 SNOX™ process, and consequently no increaseoccurs in CO2 generation.

With respect to CO and hydrocarbons, the SO2 catalystacted to virtually eliminate these compounds as well.This aspect also positively affected the interaction of theNOx and SO2 catalysts. Because the SO2 catalyst fol-lowed the NOx catalyst, any unreacted ammonia (slip)was oxidized in the SO2 catalyst to nitrogen, water vapor,

The bottom portion of the SO2 converter reactor, with thecatalyst dust collector hopper mounted on steel rails (center).

and a small amount of NOx. As a result, downstreamfouling by ammonia compounds was eliminated, and theSCR was operated at slightly higher than typical ammo-nia stoichiometries. These higher stoichiometries allowedsmaller SCR catalyst volumes and permitted the attain-ment of very high reduction efficiencies. Normal operat-ing stoichiometries for the SCR system were in the rangeof 1.02–1.05, and system reduction efficiencies averaged94% with inlet NOx levels of approximately 500–700ppm.

Sulfur dioxide removal in the SNOX™ process was con-trolled 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 tempera-ture had to be high enough to activate the SO2 oxidationreaction. During the test program, SO2 removal efficiencywas 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 SNOX™ demonstration, arrangements were madewith a sulfuric acid supplier to purchase and distribute theacid from the plant. The acid has been sold to the agricul-ture 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 SNOX™ plantmeasured the following substances:

• Five major and 16 trace elements including mercury,chromium, cadmium, lead, selenium, arsenic, beryl-lium, and nickel;

• Acids and corresponding anions (hydrogen chloride,hydrogen fluoride, chloride, fluoride, phosphate,sulfate);

• Ammonia and cyanide;• Elemental carbon;• Radionuclides;

• Volatile organic compounds;• Semi-volatile compounds including polynuclear aro-

matic hydrocarbons; and• Aldehydes.Most trace elements were captured in the baghouse alongwith the particulates. A significant portion of the boronand almost all of the mercury escaped to the stack; butselenium and cadmium, normally a problem, were effec-tively captured in the acid drain, as were organic com-pounds.


The SNOX� demonstration at Ohio Edison�s Niles Station Unit No. 2 achieved SO2removal efficiencies exceeding 95% and NOx reduction effectiveness averaging94%. Ohio Edison is retaining the SNOX� technology as part of its environmentalcontrol system.

Operational PerformanceHeat recovery was accomplished by the SNOX� process.In a commercial configuration, it can be utilized in thethermal cycle of the boiler. The process generated recov-erable heat in several ways. All of the reactions that tookplace with respect to NOx and SO2 removal were exother-mic and increased the temperature of the flue gas. Thisheat, plus fuel-fired support heat added in the high-tem-perature SCR/SO2 catalyst loop, was recovered in theWSA Condenser cooling air discharge for use in the fur-nace 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 SNOX� process showeda capital cost of approximately $305/kW for a 500-MWeunit firing 3.2% sulfur coal. The 15-year levelized incre-mental cost was 6.1 mills/kWh on a constant dollar basis(1995$). The equivalent costs of pollutant removed were$219/ton of SO2, and $198/ton of SO2and NOx.

Commercial ApplicationsThe SNOX� technology is applicableto all electric power plants and indus-trial/institutional boilers firing coal,oil, or gas. The high removal effi-ciency for NOx and SO2 makes theprocess attractive in many applica-tions. Elimination of additional solidwaste (except ash) enhances its mar-ketability in urban and other areaswhere solid waste disposal is a signifi-cant problem.

The host utility, Ohio Edison, is retain-ing the SNOX� technology as a per-manent part of the pollution controlsystem at Niles Station to help OhioEdison meet its overall SO2/NOx re-duction goals.

Commercial SNOX� plants also are operating in Den-mark and Sicily. In Denmark, a 305-MWe plant has oper-ated since August 1991. The boiler at this plant burnscoals from various suppliers around the world, includingthe United States; the coals contain 0.5�3.0% 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)


ReferencesFinal Report Volume II: Project Performance and Eco-nomics. 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 Emissions from a Coal-Fired PowerPlant Utilizing the SNOX� Innovative Clean Coal Tech-nology Demonstration. Volume 1, Sampling/Results/Special Topics: Final Report. Report No. DOE/PC/93251-T3-Vol. 1. Battelle Columbus Operations. July1994. (Available from NTIS as DE94018832.)

A Study of Toxic Emissions from a Coal-Fired PowerPlant Utilizing the SNOX� Innovative Clean Coal Tech-nology Demonstration. Volume 2, Appendices: FinalReport. Report No. DOE/PC/93251-T3-Vol. 2. BattelleColumbus Operations. July 1994. (Available from NTISas DE94018833.)



LIMB Demonstration ProjectExtension and CoolsideDemonstrationProject completedParticipantThe Babcock & Wilcox Company

Additional Team MembersOhio Coal Development Office�cofunderConsolidation Coal Company�cofunder and technology

supplierOhio Edison Company�host

LocationLorain, Lorain County, OH (Ohio Edison�s EdgewaterStation, Unit No. 4)

TechnologyThe Babcock & Wilcox Company�s (B&W) limestoneinjection multistage burner (LIMB) system; Babcock &Wilcox DRB-XCL® low-NOx burners; ConsolidationCoal Company�s Coolside duct injection of lime sorbents


CoalOhio bituminous, 1.6, 3.0, and 3.8% sulfur

Project 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 SO2reductions, and to demonstrate that the Coolside processcan achieve SO2 removal of up to 70%.

Technology/Project DescriptionThe LIMB process reduces SO2 by injecting dry sorbentinto 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 en-hance SO2 removal. Combinations of three bituminouscoals (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 perfor-mance and SO2 absorption. SO2 absorption is improved

by dissolving sodium hydroxide (NaOH) or sodium car-bonate (Na2CO3) in the humidification water. The spentsorbent is collected with the fly ash, as in the LIMBprocess. Bituminous coal with 3.0% sulfur was used intesting.

Babcock & Wilcox DRB-XCL® low-NOx burners, whichcontrol NOx through staged combustion, were used indemonstrating both LIMB and Coolside technologies.

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1 2


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% usinglimestone ground to 100% minus 325 mesh, and in-creased an additional 5–7% when ground to 100% lessthan 10 microns.

• LIMB SO2 removal efficiencies were enhanced byabout 10% when humidification down to 20 ºF ap-proach-to-saturation temperature was used.

• LIMB, which incorporated Babcock & WilcoxDRB-XCL® low-NOx burners, achieved 40–50% NOxreduction.

• Coolside SO2 removal efficiency was 70% at a Ca/Smolar 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 toimprove 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 con-ditions were $392–791/ton of SO2 removed.

• Coolside capital costs were $69–160/kW (1992$) forplants ranging from 100–500 MWe and coals with1.5–3.5% sulfur, with a target SO2 reduction of 70%.

Annualized levelized costs (15-year) for this range ofconditions were $482–943/ton of SO2 removed.

19961995199419931992199119901989198819871986

Design and ConstructionPreaward11/92


LIMB operational tests completed 8/91

NEPA process completed (MTF)

6/2/87Cooperative

agreementawarded 6/25/87

Coolside operational tests initiated 7/89

Construction completed 9/89Ground breaking/constructionstarted 8/87


Operation and Reporting6/87

LIMB operational testsinitiated 4/90

Coolside operational testscompleted 2/90

DOE selectedproject (CCT-I)7/24/86

7/897/86


Project SummaryThe initial expectation with LIMB technology was thatlimestone calcined by injection into the furnace wouldachieve adequate SO2 capture. Use of limestone in lieu ofthe significantly more expensive lime would keep operat-ing 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 en-hanced performance. Although LIMB performance wasenhanced by applying humidification to the point of ap-proaching 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.

Exhibit 5-37LIMB SO2 Removal Efficiencies

(Percent)Nominal Coal Sulfur Content

Sorbent 3.8% 3.0% 1.6%

Ligno lime 61 63 53Commercial calcitic lime 58 55 51Dolomitic lime 52 48 45Limestone NT 25 22(80% <44 microns)

NT = Not testedTest conditions: injection at 181 ft, Ca/S molar ratio of 2.0,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 ofsorbents 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 par-ticles 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 con-firmed that injection at this level, just above the nose ofthe boiler, yielded the highest SO2 removal. Injection wasalso 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 burnersresulted in an overall average NOx emissions level of0.43 lb/106 Btu, which is about a 45% reduction.

Operational Performance (LIMB)Long-term test data showed that the LIMB system wasavailable about 95% of the time it was called upon tooperate. Even with minimal humidification, ESP perfor-mance was adequately enhanced to keep opacity levelswell below the permitted limit. Opacity was generally inthe 2–5% range (limit was 20%).

Environmental Performance (Coolside)The Coolside process was tested while burning compli-ance (1.2–1.6% sulfur) and noncompliance (2.8–3.2%sulfur) coals. Objectives of the full-scale test programwere to verify short-term process operability and to de-velop a design performance database to establish processeconomics for Coolside. Key process variables—Ca/Smolar ratio, Na/Ca molar ratio, and approach-to-satura-tion temperatures—were evaluated in short-term (6–8hours) parametric tests and longer term (1–11 days) pro-cess operability tests.

The test program demonstrated that the Coolside processroutinely achieved 70% SO2 removal at design conditionsof 2.0 Ca/S molar ratio, 0.2 Na/Ca molar ratio, and 20 ºFapproach-to-saturation temperature using commerciallyavailable hydrated lime. Coolside SO2 removal depended


Exhibit 5-38LIMB Capital Cost Comparison

(1992 $/kW)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe1.5 93 150 413 66 116 3122.5 95 154 421 71 122 3163.5 102 160 425 73 127 324

250 MWe 500 MWe1.5 46 96 228 31 69 1632.5 50 101 235 36 76 1693.5 54 105 240 40 81 174

Exhibit 5-39LIMB Annual Levelized Cost Comparison

(1992 $/Ton of SO2 Removed)Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe1.5 791 943 1418 653 797 10982.5 595 706 895 520 624 6923.5 525 629 665 461 570 527

250 MWe 500 MWe1.5 549 704 831 480 589 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-to-adiabatic-saturation, and the physical properties of thehydrated lime. Sorbent recycle showed significant poten-tial 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-adia-

batic-saturation. The observedSO2 removal with simultaneousrecycle and fresh sorbent feed was40% at 0.8 fresh Ca/S molar ratio,0.2 fresh Na/Ca molar ratio, 0.5available recycle, and 18 ºF ap-proach-to-adiabatic-saturation.

Operational Performance(Coolside)Floor deposits experienced in theductwork with the horizontalhumidification led designers toconsider a vertical unit in a com-mercial configuration. Short-termtesting did not permit evaluationof Coolside system availability.

Economic Performance(LIMB & Coolside)Economic comparisons weremade between LIMB, Coolside,and a wet scrubber with limestoneinjection and forced oxidation(LSFO). Assumptions onperformance were SO2 removalefficiencies of 60, 70, and 95%for LIMB, Coolside, and LSFO,respectively. The EPRI TAG™methods were used for the eco-nomics, which are summarized inExhibits 5-38 and 5-39.

Commercial ApplicationBoth LIMB and Coolside tech-nologies are applicable to mostutility and industrial coal-firedunits, and provide alternatives toconventional wet flue gas desulfu-

rization processes. LIMB and Coolside can be retrofittedwith modest capital investment and downtime, and theirspace requirements are substantially less than for conven-tional flue gas desulfurization processes.

LIMB has been sold to an independent power plant inCanada. Babcock & Wilcox has signed 124 contracts for

DLB-XCL® low-NOx burners, representing 2,428 burnersfor 31,467 MWe of capacity.

ContactsPaul Nolan, (330) 860-1074

The Babcock & Wilcox Company20 South Van Buren AvenueP.O. Box 351Barberton, OH [email protected](330) 860-2045 (fax)

John C. McDowell, NETL, (412) 386-6175

ReferencesT.R. Goots, M.J. DePero, and P.S. Nolan. LIMB Demon-stration Project Extension and Coolside Demonstration:Final Report. Report No. DOE/PC/79798-T27. TheBabcock & Wilcox Company. November 1992. (Avail-able from NTIS as DE93005979.)

D.C. McCoy et al. The Edgewater Coolside ProcessDemonstration: A Topical Report. Report No. DOE/PC/79798-T26. CONSOL, Inc. February 1992. (Availablefrom NTIS as DE93001722.)Coolside and LIMB: Sorbent Injection DemonstrationsNearing Completion. Topical Report No. 2. U.S. Depart-ment of Energy and The Babcock & Wilcox Company.September 1990.



SOx-NOx-Rox Box� Flue GasCleanup DemonstrationProjectProject completedParticipantThe Babcock & Wilcox Company

Additional Team MembersOhio Edison Company�cofunder and hostOhio Coal Development Office�cofunderElectric Power Research Institute�cofunderNorton Company�cofunder and SCR catalyst supplier3M Company�cofunder and filter bag supplierOwens Corning Fiberglas Corporation�cofunder and

filter bag supplier

LocationDilles Bottom, Belmont County, OH (Ohio EdisonCompany�s R.E. Burger Plant, Unit No. 5)

TechnologyThe Babcock & Wilcox Company�s SOx-NOx-RoxBox� (SNRB�) process

Plant Capacity/Production5-MWe equivalent slipstream from a 156-MWe boiler

CoalBituminous coal blend, 3.7% sulfur average


Project ObjectiveTo achieve greater than 70% SO2 removal and 90% orhigher reduction in NOx emissions while maintainingparticulate emissions below 0.03 lb/106 Btu.

Technology/Project DescriptionThe SNRB� process combines the removal of SO2, NOx,and particulates in one unit�a high-temperature bag-house. SO2 removal is accomplished using either cal-cium- or sodium-based sorbent injected into the flue gas.The NOx removal is accomplished by injecting ammonia(NH3) to selectively reduce NOx in the presence of a se-lective catalytic reduction (SCR) catalyst. Particulateremoval is accomplished by high-temperature fiber bagfilters.

The 5-MWe SNRB� demonstration unit is large enoughto demonstrate commercial-scale components while mini-

mizing the demonstration cost. Operation at this scalealso permitted cost-effective control of the flue gas tem-perature, which allowed for evaluation of performanceover a wide range of sorbent injection and baghouse oper-ating temperatures. Thus, several different arrangementsfor potential commercial installations could be simulated.

SOx-NOx-Rox Box and SNRB are trademarks of The Babcock &Wilcox Company.

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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 withsugar-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 withsodium bicarbonate at a sodium-to-sulfur (Na2/S) mo-lar 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 upstreamof the baghouse at 825–900 ºF resulted in higher over-all SO2 removal than injection further upstream attemperatures up to 1,200 ºF.

• The NOx reduction of 90% was achieved with an NH3/NOx molar ratio of 0.9 and temperature of 800–850 ºF.

• Air toxics removal efficiency was comparable to thatof an electrostatic precipitator (ESP), except that hy-drogen fluoride (HF) was reduced by 84% and hydro-gen 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 demonstra-tion.

• No excessive wear or failures occurred with the filterbags 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, baselineNOx 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 dollarswas $553/ton of SO2 and NOx removed.

19981997199619951994199319921991199019891988

9/88Preaward

12/89


DOE selectedproject (CCT-II)9/28/88




5/92Design and Construction Operation and Reporting


Construction completed 12/91Environmental monitoring plan completed 12/31/91


Operation completed 5/93Project completed/final report issued 9/95

9/95


The sorbent injection into the duct upstream of SOx-NOx-RoxBox� system.

Project SummarySNRB� incorporates two successful technology develop-ment efforts that offer distinct advantages over other con-trol technologies. High-temperature filter bags and circu-lar monolith catalyst developments enabled multipleemission controls in a single component with a low plan-area space requirement. As a postcombustion controlsystem, it is simple to operate. The high-temperature bagprovides a clean, high-temperature environment compat-ible with effective SCR operation, and a surface for en-hanced SO2/sorbent contact (creates a sorbent cake on thesurface).

Environmental PerformanceFour different sorbents were tested for SO2 capture. Cal-cium-based sorbents included commercial grade hydratedlime, 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 filtercake 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%. Ata Ca/S molar ratio of 2.0, sugar-hydrated lime and ligno-sulfonate-hydrated lime increased performance by ap-proximately 8%, for overall removal of approximately90%. SO2 removal of 85�90% was obtained with calciumutilization in the range of 40�45%. Injection of the cal-cium-based sorbents directly upstream of the baghouse at825�900 ºF resulted in higher overall SO2 removal thaninjection further upstream at temperatures up to 1,200 ºF.

The SO2 removal using sodium bicarbonate was 80% atan Na2/S molar ratio of 1.0 and 98% at an Na2/S molarratio of 2.0, at a significantly reduced baghouse tempera-ture of 450�460 ºF. The SO2 emissions while burning a3�4% sulfur coal were reduced to less than 1.2 lb/106 Btuwith a Ca/S molar ratio as low as 1.5 and Na2/S molarratio less than 1.0.

To capture NOx, ammonia was injected between the sor-bent injection point and the baghouse. The ammonia andNOx reacted to form nitrogen and water in the presence of

Norton Company�s 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 achievedwith ammonia slip limited to less than 5 ppm. This per-formance reduced NOx emissions to less than 0.10 lb/106 Btu. NOx reduction was insensitive to temperaturesover the catalyst design temperature range of 700�900 ºF.Catalyst space velocity (volumetric gas flow/catalyst vol-

ume) had a minimal effect on NOx removal over the rangeevaluated.

Turndown capability for tailoring the degree of NOx re-duction by varying the rate of ammonia injection wasdemonstrated for a range of 50�95% NOx reduction. Noappreciable physical degradation or change in the catalystactivity was observed over the duration of the test pro-gram. The degree of oxidation of SO2 to SO3 over thezeolite catalyst appeared to be less than 0.5%. (SO2oxidation is a concern for SCR catalysts containingvanadium.) Leach potential analysis of the catalyst aftercompletion of the field test showed that the catalystremained nonhazardous for disposal.

Particulate emissions were consistently below NSPS stan-dards of 0.03 lb/106 Btu, with an average of 0.018 lb/106 Btu, which corresponds to a collective efficiency of99.89%. Hydrated lime injection increased the baghouseinlet particulate loading from 5.6 to 16.5 lb/106 Btu.Emissions testing with and without the SCR catalyst in-stalled revealed no apparent differences in collectionefficiency. On-line cleaning with a pulse air pressure of30�40 lb/in2 was sufficient for cleaning the bag/catalystassemblies. Typically, one of five baghouse modules inservice was cleaned every 30�150 minutes.

A comprehensive air toxics emissions monitoring test wasperformed at the end of the SNRB� demonstration testprogram. The targeted emissions monitored includedtrace metals, volatile organic compounds, semi-volatileorganic compounds, aldehydes, halides, and radionu-clides. These species were a subset of the 189 hazardoussubstances identified in the CAAA. Measurements ofmercury speciation, dioxins, and furans were uniquefeatures of this test program. The emissions controlefficiencies achieved for various air toxics by theSNRB� system were generally comparable to those ofthe conventional ESP at the power plant. However, theSNRB� system did reduce HCl by an average of 95%and HF emissions by an average of 84%, whereas theESP had no effect on these constituents.

Operation of the SNRB� demonstration resulted in theproduction of approximately 830 tons of fly ash and by-product solids. An evaluation of potential uses for the


Workers lower one of the catalyst holder tubes into amounting plate in the penthouse of the high-temperaturebaghouse.

by-product showed that the material might be used foragricultural liming (if pelletized). Also, the solids poten-tially 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 andNOx emissions of 1.2 lb/106 Btu, 65% capacity factor, and85% SO2 and 90% NOx removal, the projected capitalcost of a SNRB™ system is approximately $253/kW(1994$), including various technology and project contin-gency 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 asystem designed for 85–90% SO2 removal. Fixed operat-ing costs primarily consist of system operating labor andprojected labor and material for the hot baghouse and ash-handling systems. Levelized costs over 15 years in con-stant 1994 dollars are estimated at $553/ton of SO2 andNOx removed.

Commercial ApplicationsCommercialization of the technology is expected to de-velop 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. SNRB™ is a flexible technologythat can be tailored to maximize control of SO2, NOx, orcombined emissions to meet current performance require-ments while providing flexibility to address future needs.


McDermott Technology1562 Beeson StreetAlliance, OH [email protected](330) 829-7801 (fax)


ReferencesSOx-NOx-Rox Box™ Flue Gas Cleanup DemonstrationFinal Report. Report No. DOE/PC/89656-T1. The Bab-cock & Wilcox Company. September 1995. (Availablefrom NTIS as DE96003839.)

5-MWe SNRB™ Demonstration Facility: Detailed DesignReport. The Babcock & Wilcox Company. November1992.

Comprehensive Report to Congress on the Clean CoalTechnology Program: SOx-NOx-Rox Box™ Flue GasCleanup Demonstration Project. The Babcock & WilcoxCompany. Report No. DOE/FE-0145. U.S. Departmentof Energy. November 1989. (Available from NTIS asDE90004458.)



Enhancing the Use of Coalsby Gas Reburning andSorbent InjectionProject completedParticipantEnergy and Environmental Research Corporation

Additional Team MembersGas Research Institute—cofunderState of Illinois, Department of Commerce & Community

Affairs—cofunderIllinois Power Company—hostCity Water, Light and Power—host

LocationsHennepin, 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) process

Plant Capacity/ProductionHennepin: tangentially fired 80 MWe (gross), 71 MWe(net)

Lakeside: cyclone-fired 40 MWe (gross), 33 MWe (net)

CoalIllinois bituminous, 3.0% sulfur


PromiSORB is a trademark of Energy and Environmental ResearchCorporation.

Project ObjectiveTo demonstrate 60% NOx reduction with gas reburningand at least 50% SO2 removal with sorbent injection ontwo 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 combus-tion zone and is injected above the main burners to form areducing (reburning) zone in which NOx is converted tonitrogen. 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 base-line sorbent.

This project demonstrated the GR-SI process on twoseparate boilers representing two different firing configu-rations—a tangentially fired, 80-MWe (gross) boiler atIllinois Power Company’s Hennepin Plant in Hennepin,Illinois, and a cyclone-fired, 40-MWe (gross) boiler atCity Water, Light and Power’s Lakeside Station inSpringfield, Illinois. Illinois bituminous coal containing3% sulfur was the test coal for both Hennepin andLakeside.

A comprehensive test program was conducted at each ofthe two sites, operating the equipment over a wide rangeof boiler conditions. Over 1,500 hours of operation wereachieved, enabling a substantial amount of data to beobtained. Intensive measurements were taken to quantifythe reductions in NOx and SO2 emissions, the impact onboiler equipment and operability, and all factors influenc-ing costs.

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Calendar Year

1 2


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 firedboiler averaged 53% with hydrated lime at a calcium-to-sulfur (Ca/S) molar ratio of 1.75 (corresponding toa sorbent utilization of 24%).

• On the cyclone-fired boiler, GR-SI NOx reductions ofup to 74% were achieved, and an average 66% reduc-tion was realized at an average gas heat input of 22%.

• GR-SI SO2 removal efficiency on the cyclone-firedboiler averaged 58% with hydrated lime at a Ca/Smolar ratio of 1.8 (corresponding to a sorbent utiliza-tion of 24%).

• Particulate emissions were not a problem on either unitundergoing demonstration, but humidification had tobe introduced at Hennepin to enhance ESP perfor-mance.

• Three advanced sorbents tested achieved higher SO2capture efficiencies than the baseline Linwood hy-drated lime. PromiSORB™ A achieved 53% SO2capture efficiency and 31% utilization without GR at aCa/S molar ratio of 1.75. Under the same conditions,PromiSORB™ B achieved 66% SO2 reduction and38% 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 met-allurgy, 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/coalcost differential and the value of SO2 emission allow-ances (because GR replaces some coal with gas, it alsoreduces SO2 emissions).

• Capital cost for sorbent injection (SI) was approxi-mately $50/kW.

• Operating costs for SI were dominated by the cost ofsorbent and sorbent/ash disposal costs. SI was esti-mated to be competitive at $300/ton of SO2 removed.

Preaward Design and Construction

1998199519941993199219901989198819871986 1991

7/86 1/91


7/87

Operation initiated,Lakeside 5/93

Operation completed,Hennepin 1/93

Construction completed, Hennepin 8/91Operation initiated, Hennepin 1/91

Construction started, Lakeside 6/90

Environmental monitoring plan completed,Lakeside 11/15/89

Environmental monitoring plancompleted, Hennepin 10/15/89

NEPA process completed, Lakeside (EA) 6/25/89

Design completed, both sites 5/89Construction started, Hennepin 5/89

NEPAprocesscompleted,Hennepin(MTF) 5/9/88

Cooperativeagreementawarded7/14/87

Construction completed, Lakeside 5/92

Restoration completed,Hennepin 12/93

9/98


Operation completed,Lakeside 10/94


Restoration completed,Lakeside 12/95

**

** years omitted

3 4


The flexible lime-sorbent distribution lines lead from thesorbent splitter to the top of the cyclone-fired boiler atLakeside Station.

Project SummaryThe GR-SI project demonstrated the success of gas re-burning and sorbent injection technologies in reducingNOx and SO2 emissions. The process design conductedearly in the project combined with the vast amount ofdata collected during the testing created a database en-abling effective design for any site-specific utility or in-dustrial application.

Environmental Performance (Hennepin)Following optimization testing throughout 1991, the GR-SI 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 demon-stration period, the average gross power output was 62MWe.

For long-term demonstration testing, the average NOxreduction 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. Thiswas 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 emis-sions reduction of nearly 8% from the coal-fired baselinelevel. With flue gas humidification, electrostatic precipi-tator (ESP) collection efficiencies greater than 99.8% andparticulate emissions less than 0.025 lb/106 Btu weremeasured, even with an increase in inlet particulate load-ing resulting from sorbent injection. These levels com-pared favorably to baseline emissions of 0.035 lb/106 Btuand a collection efficiency greater than 99.5%.

Following completion of the long-term tests, three spe-cially prepared sorbents were tested. Two weremanufactured by the participant and contained proprietaryadditives to increase their reactivity toward SO2, and werereferred to as PromiSORB™ A and B. The Illinois

Geological Survey developed the other sorbent—high-surface-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/Smolar ratio, was 53% for PromiSORB™ A, 66% forPromiSORB™ B, 60% for high-surface-area hydratedlime, and 42% for Linwood lime. At a 2.6 Ca/S molarratio, the PromiSORB™ B yielded 81% SO2 removalefficiency.

Environmental Performance (Lakeside)Parametric tests were conducted in three series: GR para-metric 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 inputof 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 operabil-ity. Results showed that SO2 reduction levels varied withload because of the effect of temperature on the sulfationreaction. At a Ca/S molar ratio of 2.0, 44% SO2 reductionwas achieved at full load (33 MWe); 38% SO2 reductionwas achieved at mid load (25 MWe); and 32% SO2 reduc-tion was achieved at low load (20 MWe).

In the GR-SI optimization tests, the two technologieswere integrated. Modifications were made to the reburn-ing fuel injection nozzles based on the results of the ini-tial GR parametric tests and flow modeling studies. Thetotal cross-sectional area of the reburning jets was de-creased by 32% to increase the reburning jet’s penetrationcharacteristics. The decrease in nozzle diameter increasedNOx reduction by an additional 3–5% compared with theinitial parametric tests. With GR-SI, total SO2 reductionsresulted 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-SI was 66% and the average SO2reduction was 58%.

Operational Performance (Hennepin/Lakeside)Sorbent injection increased the frequency of sootbloweroperation but did not adversely affect boiler efficiency orequipment performance. Gas reburning decreased boilerefficiency by approximately 1.0% because of the increasein moisture formed with combustion of natural gas. Ex-amination of the boiler before and after testing showed nomeasurable change in tube wear or metallurgy. Essentially,the scheduled life of the boiler was not compromised.


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, andvalue of SO2 allowances. It was estimated that for mostinstallations, a 15% gas heat input will achieve 60% NOxreduction. The capital cost for such a GR installation wasestimated at $15/kW for 100-MWe and larger plants plusthe cost of the gas pipeline (if required) (1996$). Operat-

ing costs were almost entirely related to the differentialcost of the gas over the coal as reduced by the value ofSO2 emission allowances.

The capital cost estimate for SI was $50/kW. Operatingcosts for SI were dominated by the cost of the sorbent andsorbent/ash disposal costs. SI was projected to be costcompetitive at $300/ton of SO2 removed.

Commercial ApplicationsThe GR-SI process is a unique combination of two sepa-rate technologies. The commercial applications for thesetechnologies, both separately and combined, extend toboth utility companies and industry in the United Statesand abroad. In the United States alone, these two tech-nologies can be applied to more than 900 pre-NSPS util-ity boilers. The technologies also can be applied to newutility boilers. With NOx and SO2 removal exceeding60% 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 technol-ogy 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

Corporation18 MasonIrvine, CA [email protected](949) 859-3194 (fax)


ReferencesEnhancing the Use of Coals by Gas Reburning and Sor-bent 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, Spring-field, Illinois. Final Report. Energy and Environmental

Research Corporation. March 1996. Report No. DOE/PC/79796-T48-Vol.4. (Available from NTIS asDE96011869.)

Enhancing the Use of Coals by Gas Reburning–SorbentInjection; Long Term Testing Period, September 1, 1991–January 15, 1993. Report No. DOE/PC/79796-T40.Energy and Environmental Research Corporation. Febru-ary 1995. (Available from NTIS as DE95011481.)

Enhancing the Use of Coals by Gas Reburning and Sor-bent Injection; Volume 2: Gas Reburning–Sorbent Injec-tion at Hennepin Unit 1, Illinois Power Company. ReportNo. DOE/PC/79796-T38-Vol. 2. Energy and Environ-mental Research Corporation. October 1994. (Availablefrom NTIS as DE95009448.)

Enhancing the Use of Coals by Gas Reburning and Sor-bent Injection; Volume 3: Gas Reburning–Sorbent Injec-tion at Edwards Unit 1, Central Illinois Light Company.Report No. DOE/PC/79796-T38-Vol. 3. Energy and En-vironmental Research Corporation. October 1994.(Available from NTIS as DE95009447.)



Milliken Clean CoalTechnology DemonstrationProjectProject completedParticipantNew York State Electric & Gas Corporation (NYSEG)

Additional Team MembersNew York State Energy Research and Development

Authority�cofunderEmpire State Electric Energy Research Corporation�

cofunderConsolidation Coal Company�technical consultantSaarberg-Hölter Umwelttechnik, GmbH (S-H-U)�

technology supplierThe Stebbins Engineering and Manufacturing

Company�technology supplierABB Air Preheater, Inc.�technology supplier

LocationLansing, Tompkins County, NY (New York State Electric& Gas Corporation�s Milliken Station, Unit Nos. 1 and 2)

TechnologyFlue gas cleanup using S-H-U formic-acid-enhanced, wetlimestone scrubber technology; ABB CombustionEngineering�s Low-NOx Concentric Firing System(LNCFS�) Level III; Stebbins� tile-lined split-moduleabsorber; ABB Air Preheater�s heat-pipe air preheater;and NYSEG�s PEOA Control System.


CoalPittsburgh, 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 by-products 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 con-

trolled by LNCFS III� low-NOx burners and by micron-ized coal reburning. A heat-pipe air preheater is inte-grated to increase boiler efficiency by reducing both airleakage and the air preheater�s flue gas exit temperature.To enhance boiler efficiency and emissions reductions, aPlant Emission Optimization Advisor (PEOA) providesstate-of-the-art artificial-intelligence-based control of keyboiler and plant operating parameters.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental� The maximum SO2 removal demonstrated was 98%

with all seven recycle pumps operating and usingformic acid. The maximum SO2 removal withoutformic acid was 95%.

� The difference in SO2 removal between the two lime-stone grind sizes tested (90%�325 mesh and 90%�170mesh) while using low-sulfur coal was an average of2.6 percentage points.

� The SO2 removal efficiency was greater than the de-sign efficiency during the high-velocity test of theconcurrent scrubber section up to a liquid-to-gas ratio(L/G) of 110 gallons per 1,000 actual cubic feet (kacf)of gas.

� At full load, LNCFS� III lowered NOx emissions to0.39 lb/106 Btu (compared to 0.64 lb/106 Btu for theoriginal burners)�a 39% reduction.

� During diagnostic tests, LOI was above 4% at fullboiler 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 NOxemissions.

Operational� 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.

� Performance of a modified ESP with wider plate spac-ing and reduced plate area exceeded that of the origi-nal ESPs at lower power consumption.

� Boiler efficiency was 88.3�88.5% for LNCFS� III,compared to a baseline of 89.3�89.6%.

� Air infiltration was low for both heat pipes. Someunaccounted for air leakage occurred at full load,ranging between 2.0�2.4%.

� The flue gas side pressure loss for both heat pipes wasless than the design maximum of 3.65 inches w.c. Theprimary side pressure drops for both heat pipes wereless than the design maximum of 3.6 inches w.c. Thesecondary air side pressure drops for both heat pipeswere less than the design maximum of 5.35 inches w.c.

Economic� The capital cost (1998$) of the FGD system is esti-

mated at $300 /kW for a 300-MWe unit with a 65%capacity factor, 3.2% sulfur coal, and 95% sulfurremoval.

� The annual operating cost is estimated at $4.62 million(1998$); and the 15-year levelized cost is estimated at$412/ton of SO2 removed (constant 1998$).

20012000199919981997199619951994199319921991

Operation and ReportingPreaward9/91 10/92



Design completed 4/93Ground breaking/construction started 4/93

NEPA process completed(EA) 8/18/93

10/99


Operation initiated on Unit 2 1/95

6/95Design and Construction

Environmentalmonitoring

plan completed12/1/94 Construction completed 6/95

Fully integrated operation of Units 1 and 2 initiated 6/95

Project completed/final report issued10/99


Exhibit 5-40Effect of Limestone Grind

Exhibit 5-41Pressure Drop vs.

Countercurrent Headers

High Gas Velocity

Design Gas Velocity

Number of Countercurrent Headers

Scr

ub

ber

Pre

ssu

re D

rop

, in

ches

w.c

.

Project SummaryThe test plan was developed to cover all of the newtechnologies used in the project. In addition to the tech-nologies tested, the project demonstrated that existingtechnologies can be used in conjunction with new pro-cesses 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, perfor-mance, long-term, and validation. (See Micronized CoalReburning Demonstration for NOx Control for anotherCCT Program project at this unit.)

Environmental PerformanceThe S-H-U FGD system was tested over a 36-month pe-riod. 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 con-

tent, and flue gas velocity. The maximum SO2 removaldemonstrated was 98% with all seven recycle pumpsoperating and using formic acid, and the maximum SO2removal without formic acid was 95%. The difference inSO2 removal between the two limestone grind sizes tested(90%�325 mesh and 90%�170 mesh), while using low-sulfur coal, was an average of 2.6 percentage points, asshown in Exhibit 5-40. The SO2 removal efficiency wasgreater than the design efficiency during the high-velocitytest of the cocurrent scrubber section up to a liquid-to-gasratio of 110 gal/kacf. The cocurrent pumps had no mea-surable effect on pressure drop, whereas the countercur-rent pumps significantly increased the scrubber pressuredrop. As seen in Exhibit 5-41, the average effect of eachcountercurrent header was to increase pressure drop by0.45 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 theESP modification was 0.22%and decreased to 0.12% afterthe modifications.

At full boiler load (145�150 MWe) and 3.0�3.5%economizer O2, the LNCFS�III lowered NOx emissionsfrom a baseline of 0.64 lb/106

Btu to 0.39 lb/106 Btu (39%reduction). At 80- to 90-MWe boiler load and 4.3�5.0% economizer O2, theLNCFS� III lowered NOxemissions from a baseline of0.58 lb/106 Btu to 0.41 lb/106

Btu (29% reduction). WithLNCFS� III, LOI was main-tained below 4% and COemissions did not increase.

Operational PerformanceThe S-H-U FGD system performance goal of 98% SO2removal efficiency was achieved. Similarly, the objectiveof producing a marketable gypsum by-product from theFGD system was achieved. The test results indicate thatthe gypsum produced can be maintained at a purity levelexceeding 95% with a chloride level less than 100 ppm.However, the goal of producing a marketable calciumchloride solution from the FGD blowdown stream wasnot achieved. The FGD availability for the test periodwas 99.9%.

The modified ESP has performed better than the originalESP at a lower power use. The total voltage current prod-uct (V�I) for ESPs is directly proportional to the totalpower requirement. The modified ESP required only75% of the V�I demand of the original ESPs. The modi-


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 capi-tal costs.

Boiler efficiency was 88.3–88.5% for LNCFS™ III, com-pared 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 accom-panied 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 leak-age 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 market-able byproducts, offer significant incentives to generatingstations with limited space. Six modules of DHRTechnologies’ PEOA™ 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 [email protected](607) 762-8457 (fax)


ReferencesMilliken Clean Coal Technology Demonstration Project:Project Performance and Economics Report, Final Re-port Volumes I & II. New York State Electric & Gas Cor-poration. October 1999.

Comprehensive Report to Congress on the Clean CoalTechnology Program: Milliken Coal Technology Demon-stration Project. New York State Electric & Gas Corpo-ration. 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 WillIt Take? Volume II—Technical Papers. CONF-980410—VOL II. April 28–May 1, 1998.



Integrated Dry NOx/SO2Emissions Control SystemProject completedParticipantPublic Service Company of Colorado

Additional 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 testerNOELL, Inc.—urea injection system provider

LocationDenver, 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)injection


CoalColorado bituminous, 0.4% sulfurWyoming subbituminous (short test), 0.35% sulfur


DRB-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 down-fired low-NOx burner with in-furnace urea injection foradditional NOx removal and dry sorbent in-duct injectionwith humidification for SO2 removal.

Technology/Project DescriptionAll of the testing used Babcock & Wilcox’s low-NOxDRB-XCL® down-fired burners with overfire air. Theseburners control NOx by injecting the coal and the com-bustion air in an oxygen-deficient environment. Addi-tional air is introduced via overfire air ports to completethe combustion process and further enhance NOx re-moval. A urea-based selective noncatalytic reduction(SNCR) system was tested to determine how much addi-tional NOx can be removed from the combustion gas.

Two types of dry sorbents were injected into the ductworkdownstream of the boiler to reduce SO2 emissions. Eithercalcium-based sorbent was injected upstream of theeconomizer, or sodium-based sorbent downstream of theair heater. Humidification downstream of the dry sorbentinjection was incorporated to aid SO2 capture and lowerflue gas temperature and gas flow before entering thefabric filter dust collector.

The systems were installed on Public Service Company ofColorado’s Arapahoe Station Unit No. 4, a 100-MWedown-fired, pulverized-coal boiler with roof-mountedburners.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental• DRB-XCL® burners with minimum overfire air re-

duced NOx emissions by more than 63% under steadystate conditions.

• With maximum overfire air (24% of total combustionair), a NOx reduction of 62–69% was achieved acrossthe 50- to 110-MWe load range.

• The SNCR system, using both stationary and retract-able injection lances in the furnace, provided NOxremoval of 30–50% at an ammonia (NH3) slip of10 ppm, thus increasing performance of the total NOxcontrol system to greater than 80% NOx reduction.

• SO2 removal with dry calcium hydroxide injection intothe 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 heaterdemonstrated a long-term SO2 removal of approxi-

mately 70% at a normalized stoichiometric ratio(NSR) of 1.0.

• Sodium sesquicarbonate injection ahead of the fabricfilter achieved 70% SO2 removal at an NSR of 2.0.

• NO2 emissions were generally higher when using so-dium bicarbonate than when using sodiumsesquicarbonate.

• 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 filtersuccessfully removed nearly all trace metal emissionsand 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 operatortraining may be necessary to improve NOx controlunder load-following conditions.

• Temperature differential between the top and bottomsurfaces of the Advanced Retractable Injection Lances

(ARIL) initially caused the lances to bend downward12–18 inches. Alternative designs corrected theproblem.

Economic• When used on units burning low-sulfur coal, the tech-

nology offers SO2 and NOx removals comparable to awet scrubber and SCR, but at a lower cost.

• Total capital costs for the technology ranges from$125/kW to $281/kW for 300-MWe to 50-MWeplants, respectively. Levelized costs range from12.43–7.03 mills/kWh or 1746–987 $/ton of SO2 andNOx removed for 300-MWe to 50-MWe plants, respec-tively.

20001999199619951994199319921991199019891988

Preaward Operation8/92Design and

Construction3/9112/89


Design initiated 6/90


Ground breaking/construction started 5/21/91Design completed 3/92


Construction completed 8/92Operation initiated 8/92


9/99



Project completed/final report issued9/99

**

** years omitted


Project SummaryThe Integrated Dry NOx/SO2 Emissions Control Systemcombines five major control technologies to form an inte-grated system to control both NOx and SO2. The low-NOxcombustion system consists of 12 Babcock & WilcoxDRB-XCL® low-NOx burners installed on the boiler roof.The low-NOx combustion system also incorporates threeBabcock & Wilcox dual-zone NOx ports added to eachside of the furnace approximately 20 feet below the boilerroof. These ports inject up to 24% of the total combus-tion air through the furnace sidewalls.

Additional NOx control was achieved using the urea-based SNCR system. The SNCR when used with thelow-NOx combustion system, allowed the goal of 70%NOx reduction to be reached. Further, the SNCR systemwas an important part of the integrated system, interactingsynergistically with the dry sorbent injection (DSI) sys-tem to reduce NO2 formation and ammonia slip.

Initially, the SNCR was designed and installed to incor-porate two levels of injectors with 10 injectors at eachlevel. Levels were determined by temperature profilesthat existed with the original combustion system. How-ever, the retrofit low-NOx combustion system resulted in adecrease in furnace exit gas temperature of approximately200 ºF, thus moving one injector level out of the tempera-ture regime needed for effective SNCR operation. Withonly one operational injector level, load-following perfor-mance was compromised.

In order to achieve the desirable NOx reduction at lowloads, 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 in-jectors 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 ap-proximately 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 sig-nificant maldistributions of flue gas velocity, temperature,or baseline NOx concentration. One of the key features ofthe ARIL system was its ability to rotate, thus providing ahigh degree of flexibility in optimizing SNCR perfor-mance.The SO2 control system was a direct sorbent injectionsystem 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 approxi-mately 600 ºF, or (3) the boiler economizer region wherethe flue gas temperature was approximately 1,000 ºF. Toimprove SO2 removal with calcium hydroxide, a humidi-fication system capable of achieving 20 ºF approach-to-saturation was installed approximately 100 feet ahead ofthe 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 overfireair reduced NOx emissions by over 63% under steady

state conditions and with carefully supervised operations.Under load-following conditions, NOx emissions wereabout 10–25% higher. At maximum overfire air (24% oftotal combustion air), the low-NOx combustion systemreduced NOx emissions by 62–69% across the load range(60- to 110-MWe). The results verified that the low-NOxburners were responsible for most of the NOx reduction.

The original design of two rows of SNCR injector nozzlesproved relatively ineffective because one row of injectorswas in a region where the flue gas temperature was toolow for effective operation. At full load, the originaldesign achieved a NOx reduction of 45%. However, theperformance decreased significantly as load decreased; at60-MWe, NOx removal was limited to about 11% with anammonia slip of 10 ppm. The addition of retractablelances improved low-load performance of the urea-basedSNCR injection system. The ability to follow the tem-perature window by rotating the ARIL lances proved tobe an important feature in optimizing performance. As aresult, the SNCR system achieved NOx removals in therange of 30–50% (at a NH3 slip limited to 10 ppm at thefabric filter inlet), increasing total NOx reduction togreater than 80%, significantly exceeding the goal of70%.

Testing of calcium hydroxide injection at the economizerwithout humidification resulted in SO2 removal in therange of 5–8% at a Ca/S molar ratio of 2.0. Higher SO2removal was achieved with duct injection of calciumhydroxide and humidification, with SO2 removals ap-proaching 40% at a Ca/S molar ratio of 2.0 and within20–30 ºF approach-to-saturation. Sodium-based reagentswere found to be much more effective than calcium-basedsorbents and achieved significantly higher SO2 removalsduring dry injection. Sodium bicarbonate injectionbefore the air heater demonstrated short-time SO2 remov-als of 80%. Long-term reductions of 70% were achievedwith an NSR of 1.0. Sodium sesquicarbonate achieved70% removal at an NSR of 2.0 when injected ahead of thefabric filter. A disadvantage of the sodium-based processwas that it converted some existing NO to NO2. Eventhough 5–10% of the NOx was reduced during the conver-sion process, the net NO2 exiting at the stack was in-creased. While NO is colorless, small quantities ofbrown/orange NO2 caused a visible plume.


A major objective was the demonstration of the integratedperformance of the NOx emissions control systems andthe SO2 removal technologies. The results showed that asynergistic benefit occurred during the simultaneous op-eration of the SNCR and the sodium DSI system in thatthe NH3 slip from the SNCR process suppressed the NO2emissions associated with NO-to-NO2 oxidation by drysodium 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. How-ever, 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 con-ditions, the fabric filter pressure-drop significantly in-creased. 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 wasgood; 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 inser-tion 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 evapo-rative cooling, even though its NOx reduction and NH3slip performance dropped relative to the ARIL lance.

When the SNCR and dry sodium systems were operatedconcurrently, an NH3 odor problem was encounteredaround the ash silo. Reducing the NH3 slip set points tothe 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 han-dling. 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. Totalestimated 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 NOxremoved) 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. Theintegrated 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 Con-trol System or the individual technologies are applicableto 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 Engineer, (720) 497-2129

Xcel Energy4653 Table Mountain Dr.Golden, CO 80402


ReferencesPublic Service Company of Colorado. Integrated DryNOx /SO2 Emissions Control System. Final Report, Vol-ume 1: Public Design. November 1997.

Public Service Company of Colorado. Integrated DryNOx /SO2 Emissions Control System. Final Report, Vol-ume 2: Project Performance and Economics.September 1999.


Advanced Electric Power Generation Program Update 2001 5-99

Advanced Electric Power GenerationFluidized-Bed Combustion

5-100 Program Update 2001 Advanced Electric Power Generation

McIntosh Unit 4A PCFBDemonstration ProjectParticipantCity of Lakeland, Lakeland Electric

Additional Team MembersFoster Wheeler Corporation—supplier of pressurized

circulating fluidized-bed (PCFB) combustor and heatexchanger; engineer

Siemens Westinghouse Power Corporation—supplier ofhot 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 Si-emens Westinghouse’s hot gas particulate filter system(HGPFS) and power generation technologies

Plant Capacity/Production137 MWe (net)

CoalEastern Kentucky and high-ash, high-sulfur bituminouscoals

Project 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.


Technology/Project DescriptionIn the first of the two Lakeland Electric projects, McIn-tosh 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 combus-tion 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 blade-cooling 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 reheat steam turbine. Approxi-mately 5–10% of the power is derived from the gas tur-bine, with the steam turbine contributing the balance. Theproject also includes an atmospheric fluidized-bed unitthat can be fired on coal or char from the carbonizer andwill replace the PCFB unit during times of PCFB unavail-ability, allowing various modes of operation.

The projected net heat rate for the system is approxi-mately 9,480 Btu/kWh (HHV), which equates to anefficiency greater than 36%. Environmental attributesinclude in-situ sulfur removal of 95%, NOx emissions lessthan 0.3 lb/106 Btu, and particulate matter discharge lessthan 0.03 lb/106 Btu. Solid waste will increase slightly ascompared to conventional systems, but the dry material isreadily disposable or potentially usable.

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Project Status/AccomplishmentsThe project resulted from a restructuring of the DMEC-1PCFB Demonstration Project awarded under CCT-III. OnDecember 19, 1997, a Cooperative Agreement modifica-tion 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 Elec-tric & 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 alu-mina/mullite candle filters proved effective under condi-tions 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-rugge-dized gas turbine in a pressurized fluidized-bedapplication.

The combined-cycle PCFB system permits the combus-tion 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 gener-ating 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 appli-cations is the compactness of the equipment due to pres-surized operation, which reduces space requirements perunit of energy generated.

200320022001200019991998199119901989 1996 1997

12/89



Design and Construction8/91

Site change approved(Lakeland) 10/29/96

Preaward

Cooperative agreementsigned 12/19/97

NEPA process started 3/99

Project on Hold

**Years omitted

**



McIntosh Unit 4B ToppedPCFB Demonstration ProjectParticipantCity of Lakeland, Lakeland Electric

Additional Team MembersFoster Wheeler Corporation—supplier of carbonizer;

engineerSiemens Westinghouse Power Corporation—supplier of

topping combustor and high-temperature filterLocationLakeland, 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) top-ping combustor

Plant Capacity/Production103-MWe (net) addition to the 137-MWe (net) McIntosh4A project

CoalEastern Kentucky and high-ash, high-sulfur bituminouscoals

Project FundingTotal project cost $219,635,546 100%DOE 109,608,507 50Participant 110,027,039 50Project ObjectiveTo demonstrate topped PCFB technology in a fully com-mercial 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 generator, and exhausted to the stack. Thenet impact of the addition of the topping cycle is an in-crease in both power output and efficiency. The coal andlimestone used in McIntosh 4B are the same as those usedin McIntosh 4A.

The 240-MWe (net) plant is expected to have a heat rateof 8,406 Btu/kWh (40.6% efficiency, HHV). The designSO2 capture efficiency rate is 95%. Particulate and NOxemissions are expected to be 0.02 lb/106 Btu and 0.17 lb/106 Btu, respectively. In the final configuration, the gasturbine will produce 58 MWe and the steam turbine willproduce 207 MWe, while plant auxiliaries will consumeabout 25 MWe.

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Project Status/AccomplishmentsThe project resulted from a restructuring of the Four Riv-ers Energy Modernization Project awarded under the fifthsolicitation. The Four Rivers project was to demonstratethe integration of a carbonizer (gasifier) and topping com-bustor (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 modifi-cation 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 De-partment of Electric & Water Utilities), which includedthis project. However, the project is on hold while techni-cal 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 coal-fired plant with flue gas desulfurization, (2) meet emis-sion limits allowed by the New Source Performance Stan-dard (NSPS), (3) operate economically on a wide range ofcoals, and (4) be amenable to shop fabrication. The ben-efits 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,NOx emissions that will meet or exceed NSPS, and par-

ticulate matter discharge of approximately 0.03 lb/106

Btu. Although the system will generate a slight increasein solid waste compared to conventional systems, thematerial is a dry, readily disposable, and potentially us-able material.

19951994 2003200220012000199919981993 1996 1997

5/93

DOE selected project(CCT-V) 5/4/93

Cooperative agreement awarded7/28/94; effective 8/1/94


Site change approved(Lakeland) 10/29/96

Project on Hold8/94

Preaward

Cooperative agreementsigned 1/29/98

NEPA processstarted 3/99



JEA Large-Scale CFBCombustion DemonstrationProjectParticipantJEA (formerly Jacksonville Electric Authority)

Additional Team MembersFoster Wheeler Energy Corporation—technology supplier

LocationJacksonville, Duval County, FL (JEA’s Northside Station,Unit No. 2)

TechnologyFoster Wheeler’s atmospheric circulating fluidized-bed(ACFB) combustor

Plant 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 eco-nomic, environmental, and technical performance; toprovide potential users with the data necessary for evalu-ating a large-scale ACFB as a commercial alternative; toaccomplish greater than 90% SO2 removal; and to reduceNOx emissions by 60% when compared with conventionaltechnology.

Technology/Project DescriptionA circulating fluidized-bed combustor, operating at atmo-spheric 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. How-ever, additional SO2 capture is achieved through the useof a polishing scrubber to be installed ahead of the par-ticulate 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 approximately 2 x 106 lb/hr of mainsteam at about 2,500 psig and 1,005 ºF, and 1.73 x 106

lb/hr of reheat steam at 600 psig and 1,005 ºF. The steamwill be used in an existing 297.5-MWe (nameplate) steamturbine.

The heat rate for the retrofit plant is expected to be ap-proximately 9,950 Btu/kWh (34% efficiency; HHV).Expected environmental performance is 0.15 lb/106 Btufor SO2 (98% reduction), 0.09 lb/106 Btu for NOx, and0.011 lb/106 Btu for total particulates (0.011 lb/106 Btufor PM10).

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Project Status/AccomplishmentsThe project was successfully resited to Jacksonville,Florida after York County Energy Partners and Metropoli-tan 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 Deci-sion 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 (INTREX™) in the furnace, steam-cooledcyclones, a parallel pass reheat control, an SO2 polishingscrubber, 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 appli-cations 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 re-powering 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 configuration, ACFB technology offersseveral potential benefits when compared with conven-tional pulverized coal-fired systems: lower capital costs;reduced SO2 and NOx emissions at lower costs; highercombustion efficiency; a high degree of fuel flexibility(including use of renewable fuels); and dry, granular solidby-product material that is easily disposed of or poten-tially salable.

Environmental monitoring plancompleted; preoperational testsstarted 7/01

1995199219901989 200220012000199919971993

Preaward6/89

Operationand

Reporting11/90


2004** **


Project restructured 6/92

Project sited(York) 6/93

Project restructured and resited(Jacksonville) 8/26/97

** **

4/02 4/04Design and Construction

NEPA process completed(EIS York site) 8/11/95

Cooperative agreement modified 9/29/97

Operation initiated4/02*

Operation completed 4/04*Project completed/final report issued 4/04*

Pre-constructionstarted

8/99Construction completed12/01*

NEPA process completed (EIS Jacksonville site);design completed;

construction started 12/00

**

*Projected date**Years omitted



Tidd PFBC DemonstrationProjectProject completedParticipantThe Ohio Power Company

Additional Team MembersAmerican Electric Power Service Corporation—designer,

constructor, and managerThe 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 fluidized-bed combustion (PFBC) system (under license from ABBCarbon)

Plant Capacity/Production70 MWe (net)

CoalOhio bituminous, 2–4% sulfur

Project 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 repower-ing 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 associ-ated hardware were encapsulated in a pressure vessel 45feet in diameter and 70 feet high. The facility was de-signed 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 combus-tion 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 tem-perature of about 1,600 ºF limits NOx formation.

The hot combustion gases exit the bed vessel with en-trained ash particles, 98% of which are removed when thegases pass through cyclones. The cleaned gases are then

expanded through a 15-MWe gas turbine. Heat from thegases exiting the turbine, combined with heat from a tubebundle in the fluid bed, generates steam to drive an exist-ing 55-MWe steam turbine.

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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 fullload 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 fullload with a Ca/S molar ratio of 1.5 and temperature of1,580 ºF.

• NOx 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 siliconcarbide 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 environ-ment.

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-MWePFBC Karita Plant projected a capital cost of$1,263/kW (1997$).

19961993199219911990198919881986 1987 1994 1995


Cooperative agreement awarded 3/20/87NEPA process completed (MTF) 3/5/87


Ground breaking ceremony 4/6/88

Construction started 12/9/87


Design completed 12/90Construction completed 12/90Preoperational tests started 12/90

3/91

DOE selected project (CCT-I) 7/24/86

7/86Preaward

12/95

Projectcompleted/final reportissued 12/95



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 combus-tion efficiency, allows very low temperatures that mitigatethermal NOx generation, promotes flue gas/sorbent reac-tions that increase sorbent utilization, and produces fluegas 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 estab-lished because it was the maximum allowable temperatureat the gas turbine inlet and was well below temperaturesfor coal ash fusion, thermal NOx formation, and alkalivaporization.

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 distribu-tion.

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 one-seventh 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, includ-ing 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 achievablewith a Ca/S molar ratio of 1.14 and that 95% SO2 capturewas possible with a Ca/S molar ratio of 1.5, provided the

size gradation of the sorbent being utilized was opti-mized. 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 fluidized-bed materials, a fusing of the materials rather than effec-tive 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 posi-tive impact on process performance without the expectedexcessive elutriation of sorbent. The finer material in-creased the fluidization activity as evidenced by a 10%improvement in heat transfer rate and an approximately30% increase in sorbent utilization. In addition, the pro-cess 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, butwere 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 controlenhancements, 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 expe-rienced no widespread erosion that would require signifi-cant 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 prob-lems and was the leading cause of unit unavailabilityduring the first 3 years of operation. However, design

changes instituted over the course of the demonstrationproved effective in addressing the problem. The Tidddemonstration showed that a gas turbine could operate ina PFBC flue gas environment.

Efficiency of the PFBC combustion process was calcu-lated during testing from the amount of unburned carbonin cyclone and bed ash, together with measurements ofthe amount of carbon monoxide in the flue gas. Combus-tion efficiencies averaged 99.5% at moderate to full bedheights, surpassing the design efficiency of 99.0%.Using data for typical full-load operation, a heat rate of10,280 Btu/kWh (HHV basis) was calculated. This corre-sponds to a cycle thermodynamic efficiency of 33.2% at apoint where the cycle produced 70-MWe of gross electri-cal power while burning Pittsburgh No. 8 coal. Becausethe Tidd plant was a repowering application at a compara-tively small scale, the measured efficiency does not repre-sent what would be expected for a larger utility-scaleplant using Tidd technology. Studies conducted under thePFBC Utility Demonstration Project showed that efficien-

The PFBC demonstration at the repowered 70-MWe unit atOhio Power’s Tidd Plant led to significant refinements andunderstanding of the technology.


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 re-finements 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 particu-late 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 capi-tal 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 signifi-cantly 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. Ca-pable of being constructed modularly, PFBC generatingplants permit utilities to add increments of capacity eco-nomically to match load growth. Plant life can be ex-tended 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 Is-rael.

The Tidd project received Power magazine’s 1991Powerplant Award. In 1992, the project received theNational Energy Resource Organization award for dem-onstrating energy efficient technology.

ContactsMichael J. Mudd, (614) 223-1585

American Electric Power1 Riverside PlazaColumbus, OH [email protected](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, In-cluding Fourth Year of Operation. The Ohio PowerCompany. August 1995. (Available from DOE Library/

Morgantown, 1-800-432-8330, ext. 4184 asDE96000623.)

• Tidd PFBC Demonstration Project Final Report,March 1, 1994–March 30, 1995. Report No. DOE/MC/24132-T8. The Ohio Power Company. August1995. (Available from NTIS as DE96004973.)

• Tidd PFBC Demonstration Project—First Three Yearsof Operation. Report No. DOE/MC/24132-5037-Vol.1 and 2. The Ohio Power Company. April 1995.(Available from NTIS as DE96000559 for Vol. 1 andDE96003781 for Vol. 2.)

Coal and sorbent conveyors can be seen just after enteringthe Tidd plant.



Nucla CFB DemonstrationProjectProject completedParticipantTri-State Generation and Transmission Association, Inc.

Additional Team MembersFoster Wheeler Energy Corporation*—technology

supplierTechnical Advisory Group (potential users)—cofunderElectric Power Research Institute—technical consultantLocationNucla, Montrose County, CO (Nucla Station)

TechnologyFoster Wheeler’s atmospheric circulating fluidized-bed(ACFB) combustion system


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 atmo-spheric pressure. In the combustion chamber, a stream ofair fluidizes and entrains a bed of coal, coal ash, and sor-bent (e.g., limestone). Relatively low combustion tem-peratures limit NOx formation. Calcium in the sorbentcombines with SO2 gas to form calcium sulfite and sulfatesolids, 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 tem-perature control. Continuous circulation of coal and sor-bent 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 econo-mizer. Flue gas passes through a baghouse where

particulate matter is removed. Steam generated in theACFB is used to produce electric power.

Three small, coal-fired, stoker-type boilers at NuclaStation were replaced with a new 925,000 lb/hr ACFBsteam generator capable of driving a new 74-MWe (gross)turbine generator. Extraction steam from this turbine gen-erator powers three existing turbine generators (12.5MWe gross each).

* Pyropower corporation, the original technology developer andsupplier, was acquired by Foster Wheeler Energy Corporation.

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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 cal-cium-to-sulfur (Ca/S) molar ratios of 1.5 and 4.0, re-spectively.

• During all tests, NOx emissions averaged0.18 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 of99.9%.

• Solid waste was essentially benign and showed poten-tial as an agricultural soil amendment, soil/roadbedstabilizer, or landfill cap.

Operational• Boiler efficiency ranged from 85.6–88.6% and com-

bustion efficiency ranged from 96.9–98.9%.

• A 3:1 boiler turndown capability was demonstrated.• Heat rate at full load was 11,600 Btu/kWh and was

12,400 Btu/kWh at half load.

Economic• Capital cost for the Nucla retrofit was $1,123/kW and

normalized power production cost was 64 mills/kWh.

1991198919881987 199619951994199319921990

Preaward Operation and Reporting

1997

10/87 10/88




Operationcompleted 1/91

Operation test program initiated 8/88


4/92



Project SummaryFluidized-bed combustion evolved from efforts to find acombustion process conducive to controlling pollutantemissions without external controls. Fluidized-bed com-bustion enables efficient combustion at temperatures of1,400–1,700 ºF, well below the thermal NOx formationtemperature (2,500 ºF), and enables high SO2-captureefficiency through effective sorbent/flue gas contact.ACFB differs from the more traditional fluid-bed com-bustion. 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 pro-tect a downstream heat exchanger.

Interest and participation of DOE, EPRI, and the Techni-cal Advisory Group (potential users) resulted in the evalu-ation of ACFB potential for broad utility applicationthrough a comprehensive test program. Over a two-and-a-half-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 capac-ity factor of 40%. However, toward the end of the demon-stration, most of the technical problems had been over-come. During the last three months of the demonstration,average availability was 97% and the capacity factor 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 tem-peratures, bed temperature was the only parameter thathad a measurable impact on emissions and efficiency.

Combustion efficiency, a measure of the quantity of car-bon 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 de-creased 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 PerformanceAs indicated above, bed temperature had the greatestimpact on ACFB performance, including pollutant emis-sions. Exhibit 5-42 shows the effect of bed temperatureson the Ca/S molar ratio requirement for 70% sulfur reten-tion. The Ca/S molar ratios were calculated based on thecalcium content of the sorbent only, and do not accountfor the calcium content of the coal. While a Ca/S molarratio of about 1.5 was sufficient to achieve 70% sulfurretention in the 1,500–1,620 °F range, the Ca/S molarratio requirement jumped to 5.0 or more at 1,700 °F orgreater.

Exhibit 5-43 shows the effect of Ca/S molar ratio on sul-fur retention at average bed temperatures below 1,620 ºF.Salt Creek and Peabody coals contain 0.5% and 0.7%sulfur, respectively. To achieve 70% SO2 reduction, or the0.4 lb/106 Btu emission rate required by the licensingagreement, a Ca/S molar ratio of approximately 1.5 isrequired. To achieve an SO2 reduction of 95%, a Ca/Smolar ratio of approximately 4.0 is necessary. Dorchester

Exhibit 5-42 Effect of Bed Temperature

on Ca/S Requirement

Plant layout with coal and limestone feed locations.


coal, averaging 1.5% sulfur content, required a somewhatlower Ca/S molar ratio for a given reduction.

The NOx emissions measured throughout the demonstra-tion were less than 0.34 lb/106 Btu, which is well belowthe regulated value of 0.5 lb/106 Btu. The average level ofNOx emissions for all tests was 0.18 lb/106 Btu. The NOxemissions indicate a relatively strong correlation withtemperature, increasing from 40 ppmv (0.06 lb/106 Btu) at1,425 ºF to 240 ppmv (0.34 lb/106 Btu) at 1,700 °F. Lime-stone feed rate was also identified as a variable affectingNOx emissions, i.e., somewhat higher NOx emissionsresulted from increasing calcium-to-nitrogen (Ca/N) mo-lar ratios. The mechanism was believed to be oxidation ofvolatile nitrogen in the form of ammonia (NH3) catalyzedby calcium oxide. The CO emissions decreased as tem-perature 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 par-ticulates. With the addition of baghouses, removal effi-ciencies 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, wellbelow 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 opera-tions between September 1988 and January1991 was approximately $54.7 million, result-ing in a normalized cost of power productionof 64 mills/kWh. The average monthly operat-ing 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 in-clude fuel expenses (26.2%), non-fuel ex-penses (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 thetechnology�s ability to burn a wide variety of coalscleanly and efficiently. The comprehensive database re-sulting from the Nucla project enabled the resultant tech-nology to be replicated in numerous commercial plantsthroughout the world. Nucla continues in commercialservice.

The ACFB technology is being currently used in Pennsyl-vania, 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 signifi-cant 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) 452-6111

Tri-State Generation and TransmissionAssociation, Inc.

P.O. Box 33695Denver, CO 80233(303) 254-6066 (fax)

George Lynch, DOE/HQ, (301) 903-9434Thomas Sarkus, NETL, (412) 386-5981ReferencesDemonstration Program Performance Test: SummaryReports. Report No. DOE/MC/25137-3104. Colorado-Ute Electric Association, Inc. March 1992. (Availablefrom NTIS as DE92001299.)

Economic Evaluation Report: Topical Report. Report No.DOE/MC/25137-3127. Colorado-Ute Electric Associa-tion, Inc., March 1992. (Available from NTIS asDE93000212.)

Colorado-Ute Nucla Station Circulating Fluidized-Bed(CFB) Demonstration�Volume 2: Test Program Results.EPRI Report No. GS-7483. October 1991.

Nucla CFB Demonstration Project: Detailed Public De-sign Report. Report No. DOE/MC/25137-2999. Colo-rado-Ute Electric Association, Inc., December 1990.(Available from NTIS as DE91002081.)

Exhibit 5-43Calcium Requirements and

Sulfur Retentions for Various Fuels



Advanced Electric Power GenerationIntegrated Gasification Combined-Cycle


Kentucky Pioneer EnergyIGCC Demonstration ProjectParticipantKentucky Pioneer Energy, LLC

Additional Team MembersFuel Cell Energy, Inc. (formerly Energy ResearchCorporation)—molten carbonate fuel cell designer andsupplier, and cofunder

LocationTrapp, 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 mol-ten carbonate fuel cell (MCFC)

Plant Capacity/Production580 MWe (gross); 540 MWe (net) IGCC; 2.0 MWeMCFC

CoalHigh-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.


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 re-claimed and sold as a by-product. Tars, oils, and dust arerecycled to the gasifier. Instead of ash, the inorganic com-ponents 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 of a molten carbonate electrolytesandwiched between porous anode and cathode plates.Fuel (desulfurized, heated medium-Btu fuel gas) andsteam are fed continuously into the anode; CO2-enrichedair is fed into the cathode. Chemical reactions producedirect electric current, which is converted to alternatingcurrent with an inverter.

Operation will commence on 100% coal with slowlyincreasing levels of RDF throughout the demonstration.This method will allow the development of a database ofplant performance at various levels of RDF feed.

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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 busi-ness 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), ex-pressed 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 no-vated 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 pre-pared. As of September 30, 2001, the EIS is in the pro-

cess of final approval at DOE. (As of the time of publica-tion of this report, the EIS has been approved.) The Stateof Kentucky air quality permit was issued June 7, 2001.The permit authorizes construction and operation of thefacility, including the use of RDF as a feedstock. Thecomment period for the municipal solid waste permit isstill open. The comment period for the construction per-mit is also still open.

Commercial ApplicationsThe IGCC system being demonstrated in this project issuitable for both repowering applications and new powerplants. The technology is expected to be adaptable to awide variety of potential market applications because ofseveral factors. First, the BG/L gasification technologyhas successfully used a wide variety of U.S. coals. Also,the highly modular approach to system design makes theBG/L-based IGCC and MCFC competitive in a widerange of plant sizes. In addition, the high efficiency andexcellent environmental performance of the system arecompetitive with or superior to other fossil-fuel-firedpower generation technologies.

The heat rate of the IGCC demonstration facility is pro-jected to be 8,560 Btu/kWh (40% efficiency) and thecommercial embodiment of the system has a projectedheat rate of 8,035 Btu/kWh (42.5% efficiency). The com-mercial version of the molten carbonate fuel cell fueledby a BGL gasifier is anticipated to have a heat rate of7,379 Btu/kWh (46.2% efficiency). Theseefficiencies represent a greater than 20% reduction inemissions of CO2 when compared with a conventionalpulverized coal plant equipped with a scrubber. The SO2emissions from the IGCC system are expected to be lessthan 0.1 lb/106 Btu (99% reduction); and NOx emissionsless than 0.15 lb/106 Btu (90% reduction).

Also, the slagging characteristic of the gasifier produces anonleaching, glass-like slag that can be marketed as ausable by-product.

200720062005200320022000199419931992 1998 1999

Preaward5/93



Design and Construction12/94 12/05 Operation and

Reporting

Operation initiated 12/05*

Final report issued/project completed 12/06

**

Novation of cooperativeagreement; New siteapproved 11/99New site approved 5/98

12/06

NEPA process completed 5/02*

Site withdrawn4/99

EIS processinitiated 5/00


** **

Construction started 9/02*


Tampa Electric IntegratedGasification Combined-CycleProjectProject CompletedParticipantTampa Electric Company

Additional Team MembersTexaco Development Corporation—gasification

technology supplierGeneral Electric Corporation—combined-cycle

technology supplierAir Products and Chemicals, Inc.—air separation unit

supplierMonsanto Enviro-Chem Systems, Inc.—sulfuric acid

plant supplierTECO Power Services Corporation—project manager and

marketerBechtel 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 en-trained-flow gasifier technology


CoalIllinois #6, Pittsburgh #8, Kentucky #11, and Kentucky#9; 2.5-3.5% sulfur



Project ObjectiveTo demonstrate IGCC technology in a greenfield commer-cial 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 augmenta-tion and NOx control.

Technology/Project DescriptionCoal/water slurry and oxygen are reacted at high tempera-ture 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-tem-perature 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 reactor converts one of the sulfurspecies in the gas to a form that is more easily removed.The syngas is then further cooled before entering a con-ventional amine sulfur removal system. The amine systemkeeps SO2 emissions below 0.15 lb/106 Btu (97% cap-ture). The cleaned gases are then reheated and routed to acombined-cycle system for power generation.

A GE MS 7001FA gas turbine generates 192 MWe.Thermal NOx is controlled to below 0.27 lb/106 Btu byinjecting nitrogen. A steam turbine uses steam producedby cooling the syngas and superheated with the gas tur-bine exhaust gases in the HRSG to produce an additional124 MWe. The plant heat rate is 9,350 Btu/kWh (HHV).

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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 be-

low 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 syn-gas.

• Power production met the target goal of 250 MWe at ahigh stream factor and plant availability.

• Carbon burnout exceeds 95%.• During the fourth and fifth year of operation, the gas-

ifier capacity factor was 75% and 66%, respectively.For these same years, the gasifier availability was88.7% and 84.2%, respectively.

20022001199819971996199519941991199019891988

Preaward Design and Construction12/89 3/91

**

DOE selected project (CCT-III) 12/19/89Cooperative agreement awarded 3/11/91



9/96

Design completed 8/94NEPA process completed (EIS) 8/17/94Construction started 8/94

Project completed/final report issued

4/02*

4/02Operation and Reporting

Environmental monitoring plan completed 5/96


**

• For the fourth and fifth year of operation, the air sepa-ration 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.

Demonstration operationscompleted 9/30/01


Project SummaryThe Tampa Electric IGCC project conducted at PolkPower Station has successfully demonstrated the commer-cial 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 limitsset for the Polk plant site. Along with other IGCC dem-onstrations 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 in-cluded environmentalists, educators, economists, andcommunity leaders. Economic factors were also consid-ered. 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 en-hance 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 hy-drolysis unit was installed in 1999 to reduce SO2 emis-sions, enabling the station to meet recent, more stringentrestrictions. Injecting nitrogen into the gas

turbine is used to control NOx emissions. The use of ni-trogen that would otherwise be vented represents a novelapproach in oxygen-blown gasification technology.

A brine concentration unit processes �grey� water dis-charged from the gas cleanup systems, recovering areusable water stream for slurry preparation and a land-fillable 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 5-44Tampa Electric IGCC

Allowable Stack EmissionsPollutant Allowed Emissions

lb/hr lb/106 Btu

SO2 357 0.21NOx 223 0.27CO 98

VOC 3PM/PM10 17

84.2%, respectively. For the fourth and fifth year ofoperation, the air separation unit (ASU) had an availabil-ity of 93.9% and 90.5%, respectively, and the powerblock had an availability of 86.6% and 93.9%, respec-tively. The lower availability of the gasifier in the fifthyear of operation reflects the longer planned outage inthat year to replace the refractory liner. Also, there was a28-day forced outage to weld repair the main compressorin the ASU.

Several modifications to the original design and proce-dures were required to achieve the high availability thathas been demonstrated. Soon after initial startup, ashplugging caused failure of some exchangers in the high-temperature heat recovery system. This led to seriousdamage to the combustion turbine. The exchangers wereremoved in 1997, and compensating adjustments weremade in the rest of the heat recovery system. Additionalparticulate removal was provided to protect the turbine.

Pluggage in another bank of exchangers in the high-tem-perature heat recovery system was arrested by a designmodification in 1999. In late 1997, hot restart procedureswere implemented. These eliminated the need to changeburners and reheat the gasifier every time it shut down,reducing gasifier restart time by over 18 hours.

Initially, there were problems with the gasifier, which is50% larger than any previous Texaco gasifier. Carbonconversion in this larger gasifier was lower than expected,and refractory life has been identified as a significantissue. Liner replacement is expensive and requires consid-erable downtime. To achieve the target life of two years,the gasifier is being operated at a lower temperature thandesign, which in turn results in a further decrease in car-bon conversion efficiency. This caused load restrictionsdue to capacity limitations in the fines handling system. Aslag crusher and a duplicate fines handling system in-stalled in 1998 solved this problem.

Thermocouple replacement in the gasifier also presents aproblem. Replacement is relatively expensive. Thermo-couple failure by shearing is attributed to expansion ofdissimilar materials. In early 1998, revised operating pro-cedures were developed to handle high shell temperaturesin the dome of the radiant syngas cooler. This problemhad caused two extended outages.

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 com-bustion 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 steamor 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


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 cor-rective actions taken to solve operating and maintenanceproblems in this project have resulted in patent applica-tions.

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-tem-perature exchangers, lower than excepted carbon conver-sion, 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 uncon-verted 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 effi-ciency to 38% (9,000 Btu/kWh), consistent with the origi-nal design value.

The IGCC's oxygen plant requires 11.5 x 106 scfm of airto 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 val-ues. 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 after-cooler 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 defi-ciency.

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) aggres-siveness 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 signifi-cantly 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 $900�1,250/kW (1999$) depend-ing on the degree to which existing equipment and infra-structure can be utilized. Heat rate ultimately is expectedto be in the range of 7,000�7,500 Btu/kWh (46�49%;HHV).

Commercial ApplicationsThe project was presented the 1997 Powerplant Award byPower magazine. In 1996 the project received the Asso-ciation of Builders and Contractors award for construc-tion quality. Several awards were presented for using aninnovative siting process: 1993 Ecological Society ofAmerica Corporate Award, 1993 Timer Powers ConflictResolution Award from the State of Florida, and the 1991Florida Audubon Society Corporate Award.

As a result of the Polk Power Station demonstration,Texaco-based IGCC can be considered commercially andenvironmentally suitable for electric power generationutilizing a wide variety of feedstocks. Sulfur capture forthe project is greater than 98%, while NOx emissionsreductions are 90% those of a conventional pulverizedcoal-fired power plant. The integration and control ap-proaches utilized at Polk can also be applied in IGCCprojects using different gasification technologies.

TECO Energy is not only actively working with Texaco tocommercialize the technology in the United States, buthas been contacted by European power producers to dis-cuss possible technical assistance on using the gasifiertechnology.

ContactsMark Hornick, (813) 228-1111, ext. 39988

General Manager, Polk Power StationTECO EnergyP.O. Box 111Tampa, FL 33601-0111(863) 428-5927 (fax)

George Lynch, DOE/HQ, (301) [email protected]

James U. Watts, NETL, (412) [email protected]

ReferencesTampa Electric Integrated Gasification Combined-CycleProject�An Update. U.S. Department of Energy. July2000.

�Polk Power Station�5th Commercial Year of Opera-tion.� McDeniel, John E. and Mark Hornick. Presented atthe 2001 Gasification Technologies Conference. October8�10, 2001

Inside the Texaco gasifier.



Piñon Pine IGCC PowerProjectProject completedParticipantSierra Pacific Power Company

Additional Team MembersFoster Wheeler USA Corporation—architect, engineer,

and constructorThe 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 gasifica-tion system


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 deter-mine 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 cal-cium sulfide which, after oxidation, exits as calcium sul-fate 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 sys-tem. During cleanup, virtually all of the remaining par-ticulates 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 enters the GE MS6001FA (Frame6FA) combustion turbine, which is coupled to a 61-MWe(gross) generator. Exhaust gas from the combustion tur-bine is used to produce steam in a heat recovery steamgenerator (HRSG). Superheated high-pressure steamdrives a condensing steam turbine-generator designed toproduce about 46 MWe (gross).

The IGCC plant is designed to remove more than 95% ofthe sulfur in the coal and emits 70% less NOx and 20%less CO2 than a comparable conventional coal-fired plant.The superior environmental performance is founded inthe inherent efficiency of the pressurized fluidized-bedgasifier and incorporation of hot gas cleanup.

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Calendar Year

1 2


Results SummaryOperational• The project succeeded in identifying and working

through a number of problems, made possible onlythrough full-scale system demonstrations, and posi-tioned the technology for commercialization.

• Operational testing proved the ability of the KRWgasifier to produce coal-derived synthesis gas of de-sign quality—two runs achieved 145 Btu/standardcubic foot.

• The power island demonstrated a 94% availability in abase load operating mode after working through aquality control problem in the HRSG, replacing anundersized turbine/generator coupling, and uncover-ing a shortcoming in the 2nd stage bucket shroud de-sign in the hot gas path of the first-of-a-kind GEMS6001FA gas turbine.

• New start-up procedures for the IGCC system weredeveloped 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 particulatefiltration vessel was modified, which included increas-ing the size of the Filter Fines Depressurization Binfilters, using nuclear and vibration-based level detec-tors 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 particulatefilter 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 facili-tate ash and limestone (LASH) removal and cooling.

• The hot gas desulfurizer and regenerator system, usinga 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

20012000199919981997199619951994199319921991

Design and Construction Operation and Reporting9/91 8/92 1/01



Project completed/final report issued/Operation completed 1/01


NEPA process completed (EIS) 11/8/94




1/98


Economic• Steady-state operation was not reached in the course

of testing, so economic performance could not beevaluated.


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 pro-vided valuable information to guide developers in com-pleting a course of action toward design of a commercialIGCC configuration embodying the basic system tech-nologies. 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 com-pleted 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-a-kind unit designed to operate at a 2,350 °F firing tempera-ture 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 incorpora-tion of modifications to improve system performance.The longest syngas production run was 25 hours and thecumulative hours totaled 127.5. Although brief, the op-eration 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 start-up (once the bed is ignited), which induced spalling of thegasifier refractory and threatened the integrity of the ce-

ramic candle filters in the hot gas particulate filtrationsystem. Moreover, start-up used hot air, an oxidant, whichhas the potential to cause fires in a system normally oper-ated in a reducing environment—residual fuel on or incomponents can catch fire if ignition temperatures arereached. A fire occurred during the last start-up andcaused 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 addressboth rapid heat up and oxidation problems. Once up totemperature and operating, the gasifier proved easy tocontrol.

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 atthe base of the HGPF, a Filter Fines Collection Bin (Col-lection Bin) to receive the HGPF fines, a Filter FinesDepressurization Bin (Depressurization Bin) to bring thesystem down to atmospheric pressure, and a Filter FinesFeed Bin (Feed Bin) to serve as a surge bin for the FinesCombustor. Testing led to development of several modifi-cations to resolve the fines removalproblems. Depressurization Bin filters,through which vented gas passes toprevent emissions, were increased by anorder of magnitude. Capacitance-typebin level detectors, including those inthe HGPF, were replaced with nuclearlevel detection devices and vibration-based level detection, which subse-quently functioned well. The HGPFvessel was further modified by incorpo-rating a thermocouple array. Incorpora-tion of Skimmer valves, providing aburst of high-pressure gas against thebin wall, in lieu of Evaser fluidizingnozzles, resolved the problem of finesbridging in the cone sections of theCollection and Depressurization Bins.

Also, testing suggested modifying thehot gas particulate filter to improvedurability and enhance protection forthe gas turbine in the event of candleelement failures. The ceramic candles

are subject to failure from back-up of material in the finesremoval system and thermal shock and fatigue failures.And, the safeguard devices (SGD), installed with eachcandle filter to plug upon candle failure, did not performeffectively. Moreover, candle breakage requires systemshutdown because the broken pieces plug the fines re-moval system. Testing led to design of an alternativecandle filter system that enhances durability and to SGDdesigns that show promise for major improvements.

Repeated start-ups, accelerated temperature ramps duringstart-up in early testing, and a two-layer refractory designresulted in spalling of the old refractory, which in turnplugged the LASH removal annulus. Moreover, the inter-nal volume of the annulus proved to be too small to allowsufficient cooling of the LASH. Resolution included re-placing the original two-layer refractory with new, single-layer refractory and fire brick in selected locations andincreasing the annulus volume. The single castable layerof refractory, using a revised anchoring pattern, was in-stalled from the grid area of the annulus up to 18 feet into

HRSG in foreground and gasifier island in background.


the fluidized-bed region to provide the needed resistanceto fatigue failure.Failure of the fines removal system to provide a continu-ous 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 steady-state 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 commercial-ization 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 gen-eration assets until July 2003. This reflects recognitionthat despite the difficulties encountered, the IGCC systemshows promise. The demonstration resulted in the engi-neering 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 pulver-ized coal plant with a scrubber and a comparable reduc-tion in CO2 emissions. The compactness of an IGCC sys-tem reduces space requirements per unit of energy gener-ated relative to other coal-based power generation sys-tems. The advantages provided by phased modular con-struction reduce the financial risk associated with newcapacity 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 high-swelling coals, as well as biowaste or refuse-derivedwaste, with minimal environmental impact. There are nosignificant process waste streams that require remedi-

Conveyor leading to coal storage facility.

ation. The only solid waste from the plant is a mixture ofash and calcium sulfate, a nonhazardous waste.

ContactsJeffrey W. Hill, (775) 834-5650

Sierra Pacific Power CompanyP.O. Box 10100Reno, NV 89520-0024

George Lynch, DOE/HQ, (301) 930-9434Donald W. Geiling, NETL, (304) 285-4784ReferencesSierra Pacific Resources: Final Technical Report to theDepartment of Energy. Final Report. Sierra Pacific PowerCompany. January 1, 2001.


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-GasTechnology™


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, pres-surized, oxygen-blown, entrained-flow IGCC system,including advancements in the technology relevant to theuse of high-sulfur bituminous coal; and to assess long-term reliability, availability, and maintainability of thesystem at a fully commercial scale.


Technology/Project DescriptionThe Destec, now E-Gas Technology™, process featuresan oxygen-blown, continuous-slagging, two-stage, en-trained flow gasifier. Coal is slurried, combined with 95%pure oxygen, and injected into the first stage of the gas-ifier, which operates at 2,600 °F/400 psig. In the firststage, the coal slurry undergoes a partial oxidation reac-tion 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 satu-

rated steam. After cooling in the syngas cooler, particu-lates are removed in a hot/dry filter and recycled to thegasifier. The syngas is further cooled in a series of heatexchangers. The syngas is water-scrubbed to removechlorides and passed through a catalyst that hydrolyzescarbonyl sulfide into hydrogen sulfide. Hydrogen sulfideis removed in the acid gas removal system using MDEA-based absorber/stripper columns. A Claus unit is used toproduce elemental sulfur as a salable by-product. The“sweet” gas is then moisturized, preheated, and piped tothe power block. The power block consists of a single192-MWe General Electric MS 7001FA (Frame 7 FA) gasturbine, a Foster Wheeler single-drum heat recoverysteam generator with reheat, and a 1952-vintage Westing-house reheat steam turbine.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


Results SummaryEnvironmental• The SO2 capture efficiency was greater than 99%,

keeping SO2 emissions consistently below0.1 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 NOx emissions were 0.15 lb/106 Btu, which meetsthe 2003 target emission limits for ozone non-attain-ment 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 mate-rials; 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 second-

stage gasifier and changing the flow path geometryto eliminate ash deposition on the second-stagegasifier walls and downstream piping;

– Changing to improved metallic candle filters toprevent particulate breakthrough in the hot gasfilter; and

– Installing a wet chloride scrubber and a COS cata-lyst less prone to poisoning to eliminate chlorideand metals poisoning of the COS catalyst.

• The second year identified cracking in the gas turbinecombustion liners and tube leaks in the heat recoverysteam generator (HRSG). Resolution involved replace-ment of the gas turbine fuel nozzles and liners andmodifications to the HRSG to allow for more tubeexpansion.

• The third year was essentially trouble free and theIGCC unit underwent fuel flexibility tests, whichshowed that the unit operated trouble free, withoutmodification, on a second coal feedstock, a blend oftwo different Illinois #6 coals, and petroleum coke.

• Overall thermal performance actually improved duringpetroleum coke operation, increasing plant efficiencyfrom 39.7% to 40.2%.

• In the fourth year, the gas turbine incurred damage torows 14 through 17 of the compressor causing a 3-month outage. But over the four years of operation,availability of the gasification plant steadily improvedreaching 79.1% in 1999.

Economic• The overall cost of the IGCC plant was $417 million,

which equates to about $1,590/kW in 1994 dollars.For an equivalent greenfield project the cost was esti-mated at $1,700/kW. Capital cost estimates for a new285 MWe (net) greenfield IGCC plant incorporatinglessons learned, technology improvements, and a heatrate of 8,526 Btu/kWh are $1,318/kW (2000$) for acoal-fueled unit and $1,260 (2000$) for a petroleumcoke-fueled unit.

Preaward

20012000199919981997199619951994199319921991



Design and Construction9/91 7/92




Environmental monitoring plan completed 7/9/93Groundbreaking ceremony 7/7/93


11/95 9/00

Demonstration operationscompleted 12/99


Project completed/final reportissued 9/00


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, PSI�s 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 sys-tem, 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 No-vember 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 sev-eral of the months, syngas production exceeded one tril-lion 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 poison-ing of the COS catalyst. Modifications to the second-stage refractory to avoid tenacious bonds with the ash andto the hot gas path flow geometry corrected the ash depo-sition problem. Replacement of the ceramic candle filterswith metallic candles proved to be largely successful. A

follow-on metallic candle filter development effort en-sued using a hot gas slipstream, which resulted in im-proved candle filter metallurgy, blinding rates, and clean-ing 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 prob-lems 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 40�50 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 dif-ferent 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 demon-stration period.

Environmental PerformanceThe IGCC unit operates with an SO2 capture efficiencygreater than 99%. As a result, SO2 emissions are consis-tently below 0.1 lb/106 Btu of coal input, reaching as lowas 0.03 lb/106 Btu. Moreover, the process transforms sul-fur-based pollutants into 99.99% pure sulfur, a highlyvalued by-product, rather than a solid waste.

Moisturizing the syngas in combination with steam injec-tion reduced NOx emissions to the 0.15 lb/106 Btu re-quirement established by EPA for existing plants in ozonenon-attainment areas. Because of the extreme particulatefiltration necessary for combustion of the syngas in a gasturbine, particulate emissions were negligible, averaging0.012 lb/106 Btu. Also, carbon monoxide emissions werequite low, averaging 0.05 lb/106 Btu.

The ash component of the coal results in a low-carbonvitreous slag, impervious to leaching and valued as anaggregate in construction or as grit for abrasives and roof-ing materials. Also, the trace metal constituents in thepetcoke were effectively captured in the slag produced.

Economic PerformanceThe overall cost of the IGCC demonstration plant was$417 million, which equates to about $1,590/kW in 1994dollars. For an equivalent greenfield project, allowing foradditional new equipment required, the installed cost wasestimated at $1,700/kW. Costs include engineering, per-mitting, equipment procurement, project and constructionmanagement, construction, start-up, and hiring and train-ing personnel.

In the final report, the participant estimates capital costfor a new 262-MWe greenfield IGCC plant incorporatinglessons learned, technology improvements, and a heat rateof 8,250 Btu/kWh are $1,275/kW (2000$) for a coal-fueled unit and $1,150 (2000$) for a petroleum coke-fueled unit. In designing for petcoke, some equipment canbe reduced in size and some eliminated.

More recent data developed by DOE shows that a 285-MWe (net) coal-fired greenfield IGCC plant with a heatrate of 8,526 Btu/KWh would cost $1,318/KW (2000$).A 291-MWe (net) petroleum coke-fired IGCC unit with a8,400 Btu/KWh heat rate would cost $1,260/KW.


Design ActualCoal Coal Petcoke

Nominal Throughput, tons/day 2,550 2,450 2,000Syngas Capacity, 106 Btu/hr 1,780 1,690 1,690Combustion Turbine, MW 192 192 192Steam Turbine, MW 105 96 96Auxiliary Power, MW 35 36 36Net Generation, MW 262 261 261Plant Efficiency, % (HHV) 37.8 39.7 40.2Sulfur Removal Efficiency, % >98 >99 >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 andmaintenance (O&M) costs for the syngas facility (exclud-ing 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, oper-ating 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, Glo-bal Energy, Inc. purchased Dynegy's gasification assetsand technology. Global Energy is marketing the technol-ogy under the name “E-Gas Technology™.” The projectis continuing to operate in commercial service as WabashRiver Energy, Ltd., a subsidiary of Global Energy.

The immediate future for E-Gas Technology™ appears tolie with both foreign and domestic applications wherelow-cost feedstocks such as petroleum coke can be usedand co-production options are afforded—bundled produc-tion 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 part-nership with Sabine Power I, Limited to build the world'slargest petroleum coke-fueled IGCC facility using E-GasTechnology™. The Port estimates the cost of the facilityat $1.75 billion; construction jobs at 1,250; and perma-nent 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 impor-tance placed on displacement of petroleum in chemicalsand fuels production.

Exhibit 5-45Wabash Thermal Performance Summary

Exhibit 5-46Wabash River Coal Gasification Repowering Project

Production StatisticsCoal On Spec. Steam Power Sulfur

On Coal Processed Gas Produced Produced ProducedTime Period (Hr) (tons) (106 Btu) (106 lb) (MWh) (tons)

Start-up 1995 505 41,000a 230,784 171,613 71,000a 5591996 1,902 184,382 2,769,685 820,624 449,919 3,2991997 3,885 392,822 6,232,545 1,720,229 1,086,877 8,5211998 5,279 561,495 8,844,902 2,190,393 1,513,629 12,4521999b 3,496 369,862 5,813,151 1,480,908 1,003,853 8,557

Overall 15,067 1,549,561 23,891,067 6,383,767 4,125,278 33,388aEstimates.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 [email protected](713) 374-7279 (fax)

George Lynch, DOE/HQ, (301) 903-9434Leo E. Makovsky, NETL, (412) 386-5814

ReferencesWabash River Coal Gasification Repowering Project:Final Technical Report. Wabash River Coal GasificationProject Joint Venture. August 2000.

Wabash River Coal Gasification Repowering Project:Project Performance Summary. U.S. Department of En-ergy. January 2002.



Advanced Electric Power GenerationAdvanced Combustion/Heat Engines



Clean Coal DieselDemonstration ProjectParticipantArthur D. Little, Inc. (ADL)

Additional Team MembersUniversity of Alaska at Fairbanks—host and cofunderFairbanks Morse Engine, Goodrich Corp.—diesel engine

technology vendorUsibelli Coal Mine, Inc.—coal supplierLocationFairbanks, AK (University of Alaska facility)

TechnologyFairbanks Morse coal-fueled diesel engine

Plant Capacity/Production6.4 MWe (net)

CoalUsibelli Alaskan subbituminous

Project 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-cylin-der, heavy-duty engine (6.4 MWe) modified to operate onAlaskan subbituminous coal. The clean coal diesel tech-nology, 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 Stan-dards). In addition, the demonstration plant is expected toachieve 41% efficiency, and future plant designs are ex-pected to reach 48% efficiency. This will result in a 25%

reduction in CO2 emissions compared with conventionalcoal-fired plants. The engine will use selective catalyticreduction (SCR) for NOx control.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


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 genera-tor. 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 emis-sions, which was within contract specifications. SinceAugust 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 hard-ened engine parts for the Fairbanks Morse two-cylindertest engine, coal fuel preparation and testing, and comple-tion 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 manu-facture the LRCWF. Usibelli Coal Mine, Inc. will supplythe coal. Samples of three different blends of LRCWF

200520042002200119991998199419931992 1996 1997

Preaward5/93 7/94




NEPA processcompleted (EA)6/2/97


Environmental monitoringplan completed 2/99

Coal Diesel Operation initiated 10/02*

10/02 10/04

OperationcompletedProject completed/final report issued10/04*

Operationand

Reporting

Projectrestructured 8/96


Fairbanks Morse two-cylinderengine 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 reliabil-ity 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 devel-oping 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 similarly sized coal- and fueloil-fired installations. Environmental emissions fromcommercial diesel systems should be reduced to levelsbetween 50% and 70% below NSPS. The estimated in-stallation cost of a mature commercial unit is approxi-mately $1,300/kW.


Healy Clean Coal ProjectProject completedParticipantAlaska Industrial Development and Export Authority

Additional Team MembersGolden Valley Electric Association, Inc.—host and

operatorStone and Webster Engineering Corp.—engineerTRW, Inc., Space & Technology Division—combustor

technology supplierThe Babcock & Wilcox Company (B&W)—spray dryer

absorber technology supplierUsibelli Coal Mine, Inc.—coal supplierSteigers Corporation—environmental and permitting

supportLocationHealy, Denali Borough, AK (adjacent to Healy Unit No. 1)

TechnologyTRW’s Clean Coal Combustion System; Babcock &Wilcox’s spray dryer absorber (SDA) with sorbent recycle

Plant Capacity/Production50 MWe (nominal)

CoalUsibelli subbituminous 50% run-of-mine (ROM) coal and50% waste coal

Project 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.


Technology/Project DescriptionEmissions are controlled using TRW’s clean coal com-bustion system, an advanced entrained/slagging combus-tors through staged fuel and air injection for NOx controland limestone injection for SO2 control. Additional SO2 isremoved using B&W’s activated recycle SDA.

A coal-fired precombustor increases the air inlet tempera-ture for optimum slagging performance. The slaggingcombustors are bottom mounted, injecting the combus-tion products into the boiler. The main slagging combus-tor 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 pre-combustor gases and additional air flow, and burned un-der substoichiometric conditions for NOx control. The ash

forms molten slag, which flows along the water-cooledwalls and is driven by aerodynamic and gravitationalforces through a slot into the slag recovery section. About70–80% of the ash is removed as molten slag. The hot gasis then ducted to the furnace where, to ensure completecombustion, additional air is supplied from a tertiary airwindbox to NOx ports and to final overfire air ports. Pul-verized limestone (CaCO3) for SO2 control is fed into thecombustors where it is flash calcined (converting CaCO3to lime (CaO). The mixture of this CaO and ash that wasnot removed in the combustor, called flash-calcined mate-rial, is removed in the fabric filter system. Most of theflash-calcined material is used to form a 45% solidsslurry, which is injected into the spray dryer. The SO2 inthe flue gas reacts with the slurry droplets as water issimultaneously evaporated. The SO2 is further removedfrom the flue gas by reacting with the dry flash-calcined-material on the baghouse filter bags.

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Results SummaryEnvironmental• NOx emissions ranged from 0.208–0.278 lb/106 Btu,

with typical emissions of 0.245 lb/106 Btu on a 30-dayrolling 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, whichare below the permit limit of 0.10 lb/106 Btu (3-houraverage).

• High SO2 removal efficiencies in excess of 90% wereachieved with low-sulfur coal and Ca/S molar ratios of1.4–1.8.

• Particulate matter (PM) emissions were 0.0047lb/106 Btu, which is well below the permit limit of0.02 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, PMemissions, 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 slagrecovery 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, theplant availability was 97% at a capacity factor of 95%.

• The SDA pressure drops and power consumption werewell below guarantee levels of the technology supplier.

• The system required less limestone and produced lesssolid waste by-product than anticipated.

Economic• The capital costs of a 50-MWe and 300-MWe plant

using this system are $90.6 million ($1,812/kW) and$450.7 million ($1,502/kW) (1993$), respectively.

• The variable operating costs for the 300-MWe systemis $7.2 million/yr (1993$) for the fixed cost and $28.4million/yr (1993$) for the variable costs (based on 90percent capacity factor).

• The levelized cost of power is 36.5 mills/KWh (con-stant 1993$) for the 300-MWe plant (based on 90percent capacity factor).

• The levelized cost per ton of SO2/NOx removed is$6,499/ton (constant 1993$) for the 300-MWe plant(based on 90 percent capacity factor).

20012000199919981997199519941993199119901989

Design and ConstructionPreaward

Designstarted 7/90

4/91

Cooperativeagreementawarded 4/11/91


Operation and Reporting1/9812/89

**

DOE cost-shared operationcompleted 12/99


Preoperational testsinitiated 8/97

NEPA process completed (EIS) 3/10/94

Design completed 10/93 Ground breaking/construction

started 5/30/95 Environmental monitoringplan completed 4/11/97

Constructioncompleted 11/97 Project completed/final

report issued 4/01

**

4/01

**Years omitted


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 mini-mize NOx emissions, achieve high carbon burnout, andremove 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 convert-ing limestone to flash-calcined lime. Second, the flashcalcined-lime absorbs SO2 within the boiler. Third, themajority 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 pur-chase or manufacture lime for the back end scrubbingsystem.

During a cumulative six-month combustion system char-acterization test, a series of tests were performed to estab-lish baseline performance of the combustion system whileburning ROM and ROM/waste coal blends, to map com-bustor 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 demonstra-tion test period, the NOx, SO2, PM, opacity, and CO emis-sion goals were met with the exception of short-term SO2

and opacity exceedences during startup and repairs. Theemissions, as well as permit and NSPS requirements, arepresented in Exhibit 5-47.

Performance testing of the SDA system conducted in June1999 showed that the technology performed well. Mea-surements of the SDA inlet, SDA outlet, stack, limestonefeed, coal feed, air preheater hopper ash, surge bin ash,electrical power consumption, and stack opacity, as wellas normal plant data from the plant distributed controlsystem, showed that the technology exceeds the guaran-tees. The results of the tests and the performance guaran-tees are shown in Exhibit 5-48. It should be noted thatenvironmental performance was not fully optimized.

Exhibit 5-47 Healy Performance Goals and Demonstration Test Program Results

(January 1998–December 1999)Parameter NSPS Permit Goal Actual Range Actual Typical

NOx 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 lb/106 Btu1,010 tons/yr (full load) (30-day rolling avg) (30-day rolling avg) (30-day rolling avg)

SO2 70% removal when emissions 0.086 lb/106 Btu (annual avg) 70% removal (minimum) ~90% removal 0.038 lb/106 Btu<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-minute avg

65.8 lb/hr max (3-hour avg) avg) (30-minute avg corrected to 3% O2)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 0.0047 lb/106 Btub

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% Opacitya

27% Opacity (one 6-minute minute avg) (30-minute avg) (30-minute avg)period per hour)

CO Dependent on ambient CO 0.20 lb/106 Btu (hourly avg) 206 ppm (corrected 20–50 ppm 25.9 ppmlevels in the local region 202 ppm (corrected to 3% O2) to 3.0% O2) (30-minute avg (30-minute avg

132 lb/hr, 577 tons/yr (full load) 200 ppm (corrected corrected to 3% O2) corrected to 3% O2)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.


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 per-formed very well with ROM coal, but exhibited morevariable performance, in terms of slagging behavior, dur-ing the initial tests with ROM/waste coal blends.

Localized slag freezing was observed in the precombustorduring early testing. A combination of hardware configu-ration 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 com-pletely transferring the precombustor mill air to the boilerNOx ports following boiler warmup. These changes elimi-nated the mixing of excess air downstream of the precom-bustor chamber to minimize local slag freezing and in-creased the precombustor operating temperature to pro-vide additional temperature margin. The mill air changehad 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 5-48Healy SDA Performance Test Results and Performance GuaranteesOperating Parameter Guarantee Range of Parameter Values

SO2 79.6 lb/hr (max) <2.15

PM 0.015 lb/106 Btu 0.0014-0.0052

Opacity 20% Opacity 1.0-2.0(3-minute avg) 27% Opacity for 3 minutes per hour

System Pressure Drop 13 inches W.G. 9.6-10.0

System 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 burn-out 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 perfor-mance 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 con-sumption was approximately 38–41% less than the guar-anteed level. Based on these results, Stone & Websterconcluded that the SDA system met all performance guar-antees.

Economic PerformanceCapital and operating cost estimates were prepared by anindependent consultant to the participant for new plantsin the “lower 48” that incorporate the technology demon-strated 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 esti-mated at $28.4 million per year based on a 90 percent

capacity factor (1993$). The levelized cost of powerwould then be 36.5 mills/kWh (constant 1993$). Thelevelized cost per ton of SO2 and NOx removed is$6,499/ton (constant 1993$) for the 300-MWe plant.

Commercial ApplicationsThis technology is appropriate for any size utility or in-dustrial boiler in new or retrofit uses. It can be used incoal-fired boilers as well as in oil- and gas-fired boilersbecause of its high ash-removal capability. However,cyclone boilers may be the most amenable type to retrofitwith the entrained/slagging combustor because of thelimited supply of high-Btu, low-sulfur, low-ash-fusion-temperature coal that cyclone boilers require. The com-mercial availability of cost-effective and reliable systemsfor SO2, NOx, and particulate control is important to po-tential users planning new capacity, repowering, or retro-fits to existing capacity in order to comply with CAAArequirements.

ContactsArthur E. Copoulos, Project Manager, (907) 269-3029

Alaska Industrial Development and Export Authority813 West Northern Lights BlvdAnchorage, AK 99503(907) 269-3044 (fax)

George Lynch, DOE/HQ, (301) 903-9434Robert M. Kornosky, NETL, (412) 386-4521ReferencesHealy Clean Coal Project—Project Performance andEconomics Report Final Report: Volume 2. AIDEA.April 2001.

Spray Dryer Absorber System Performance Test Report:June 7-11, 1999. Stone & Webster Engineering Corpora-tion. February 2000.


Coal Processing for Clean Fuels Program Update 2001 5-139


5-140 Program Update 2001 Coal Processing for Clean Fuels

Commercial-ScaleDemonstration of the LiquidPhase Methanol (LPMEOH™)ProcessParticipantAir Products Liquid Phase Conversion Company, L.P.(a limited partnership between Air Products and Chemi-cals, Inc., the general partner, and Eastman ChemicalCompany)

Additional Team MembersAir Products and Chemicals, Inc.—technology supplier

and cofunderEastman Chemical Company—host, operator, synthesis

gas and services providerARCADIS Geraghty & Miller—fuel methanol tester and

cofunderElectric Power Research Institute—utility advisor

LocationKingsport, Sullivan County, TN (Eastman ChemicalCompany’s Chemicals-from-Coal Complex)

TechnologyAir Products and Chemicals, Inc.’s liquid phase methanolprocess

Plant Capacity/Production80,000 gallons/day of methanol (nominal)

CoalEastern high-sulfur bituminous, 3–5% sulfur


Project ObjectiveTo demonstrate on a commercial scale the production ofmethanol from coal-derived synthesis gas using theLPMEOH™ process; to determine the suitability ofmethanol produced during this demonstration for use as achemical feedstock or as a low-SOx emitting, low-NOxemitting alternative fuel in stationary and transportationapplications; and to demonstrate, if practical, the produc-tion of dimethyl ether (DME) as a mixed coproduct withmethanol.

Technology/Project DescriptionThis project is demonstrating, at commercial scale, theLPMEOH™ process to produce methanol from coal-derived synthesis gas. The combined reactor and heatremoval system is different from other commercial metha-nol processes. The liquid phase not only suspends the

catalyst but functions as an efficient means to remove theheat of reaction away from the catalyst surface. This fea-ture permits the direct use of synthesis gas streams as feedto the reactor without the need for water-gas shift conver-sion. Synthesis gas feed to the LPMEOH™ reactor isproduced by the gasification of eastern high-sulfur bitu-minous coal (Mason seam) containing 3% sulfur (5%maximum) and 10% ash.

Methanol fuel testing is being conducted in off-site sta-tionary and mobile applications, such as fuel cells, buses,and distributed electric power generation. Stabilizedmethanol from the project was made available to severaltest locations to study the feasibility of using the productas a feedstock in transportation and power generationapplications.

Coal Processing for Clean FuelsIndirect Liquefaction

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Project Status/AccomplishmentsThe first production of methanol from the 80,000 gal/dayunit occurred on April 2, 1997, with the first stable opera-tion at nameplate capacity occurring on April 6, 1997. Astable test period at over 92,000 gal/day revealed no sys-tem limitations.

The LPMEOH� process demonstration unit continues toexceed expectations. Tests have given increased confi-dence in the use of the LPMEOH� process for IGCCapplications. This confidence level will increase withadditional testing of the LPMEOH� 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 ex-pected to significantly reduce other catalyst poisons suchas arsenic. This new adsorbent is a commercially avail-able copper oxide impregnated activated carbon. Thecatalyst guard bed was placed in service in August 2001after the implementation of some plant equipment modifi-cations to allow for the adsorbent material change. Theinitial performance of the catalyst guard bed was verypromising with the new adsorbent. Performance evalua-tion of the new adsorbent material will continue on anongoing basis.

Plant modifications to support in situ catalyst activationin the LPMEOH� reactor have been completed. Previ-ously, catalyst was activated in small batches in a separatevessel and transferred into the LPMEOH� reactor. In situactivation of the methanol catalyst is of commercial sig-nificance as it has the potential to simplify equipment andto reduce capital requirements. The first large-scale, in-situ activation of methanol synthesis catalyst was success-fully 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

LPMEOH� reactor. The catalyst was then reduced oractivated in-situ using dilute synthesis gas over a 26-hourperiod. Following the in situ activation, the LPMEOH�process demonstration unit was successfully restarted andhas begun operation in a new temperature programmingmode.

Commercial ApplicationsThe LPMEOH� process has been developed to enhanceIGCC power generation by producing a clean-burning,storable-liquid fuel (methanol) from clean coal-derivedgas. Methanol also has a broad range of commercial ap-plications; it can be substituted for conventional fuels instationary and mobile combustion applications and is anexcellent fuel for utility peaking units. Methanol containsno sulfur and has exceptionally low NOx characteristicswhen burned.

DME has several commercial uses. In a storable blendwith methanol, the mixture can be used as peaking fuel inIGCC electric power generating facilities. Blends ofmethanol and DME also can be used as a chemical feed-stock for the synthesis of chemicals or new oxygenatefuel additives. Pure DME is an environmentally friendlyaerosol for personal products.


20032002199819971996199319921991 1995 20041989

3/03





4/97



Project completed/finalreport issued 3/03*

3 4

Project transferred to Air ProductsLiquid Phase Conversion

Company, L.P. 3/95

Project resited toKingsport, TN

10/93

Operationcompleted6/02*

**

* Projected date**Years omitted

**

PreawardDesign and Construction

12/89 10/92

DOE selectedproject (CCT-III)12/19/89


**


Development of the CoalQuality Expert™Project completedParticipantsABB Combustion Engineering, Inc. and CQ Inc.

Additional Team MembersBlack & Veatch—cofunder and software developerElectric Power Research Institute—cofunderThe Babcock & Wilcox Company—cofunder and pilot-

scale testerElectric Power Technologies, Inc.—field testerUniversity of North Dakota, Energy and Environmental

Research Center—bench-scale testerUtility 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 sites

TechnologyCQ Inc.’s EPRI Coal Quality Expert™ (CQE™) com-puter software

Plant Capacity/ProductionFull-scale testing took place at utility sites ranging in sizefrom 250–880 MWe.

CoalWide variety of coals and blends

Coal 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 (CQIS™) database andCoal Quality Impact Model (CQIM™) to allow assess-ment of the effects of coal-cleaning on specific boilercosts and performance; and (2) develop and validateCQE™, a model that allows accurate and detailed predic-tion of coal quality impacts on total power plant operatingcost and performance.

Technology/Project DescriptionThe CQE™ is a software tool that brings a new level ofsophistication to fueling decisions by integrating thesystem-wide impact of fuel purchase decisions on coal-fired power plant performance, emissions, and powergeneration costs. The impacts of coal quality; capitalimprovements; operational changes; and environmentalcompliance alternatives on power plant emissions, perfor-mance, and production costs can be evaluated usingCQE™. CQE™ can be used to systematically evaluate allsuch impacts, or it may be used in modules with somedefault data to perform more strategic or comparativestudies.

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.

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Results SummaryEnvironmental• CQE™ includes models to evaluate emission and

regulatory issues.

Operational• CQE™ 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 CQE™ program are:– Fuel Evaluator,– Plant Engineer,– Environmental Planner, and– Coal-Cleaning Expert.

• CQE™ can be used to evaluate:– Coal quality,– Transportation system options,– Performance issues, and– Alternative emissions control strategies.

• CQE™ operates on an OS/2 Warp® (Version 3 orlater) operating system with preferred hardwarerequirements of a Pentium®-equipped personal com-puter, 1 gigabyte hard disk space, 32 megabytesRAM, 1024x768 SVGA, and CD-ROM.

Economic• CQE™ includes economic models to determine pro-

duction cost components for coal-cleaning processes,power production equipment, and emissions controlsystems.

19981997199619951994199319921991199019891988



12/88


NEPA process completed(MTF) 4/27/90



Preaward

Development6/90

Field testing completed 4/93

8/90

CQE Release 1.1 Beta issued 6/96CQE CD-ROM issued 12/95


6/98

CQE Release 1.2issued 12/97


Project SummaryBackgroundCQE™ began with EPRI’s CQIM™, developed for EPRIby Black & Veatch and introduced in 1989. CQIM™ wasendowed with a variety of capabilities, including evaluat-ing Clean Air Act compliance strategies, evaluating bidson coal contracts, conducting test-burn planning andanalysis, and providing technical and economic analysesof plant operating strategies. CQE™, which combinesCQIM™ with other existing software and databases, ex-tends the art of model-based fuel evaluation establishedby CQIM™ in three dimensions: (1) new flexibility andapplication, (2) advanced technical models and perfor-mance correlations, and (3) advanced user interface andnetwork awareness.

Algorithm DevelopmentData derived from bench-, pilot-, and full-scale testingwere used to develop the CQE™ algorithms. Bench-scaletesting was performed at ABB Combustion Engineering’sfacilities in Windsor, Connecticut and the University ofNorth Dakota’s Energy and Environmental Research Cen-ter 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 base-line 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.

CQE™ CapabilityThe OS/2®-based program evaluates coal quality, trans-portation system options, performance issues, andalternative emissions control strategies for utility powerplants. CQE™ 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 dis-posal, operation and maintenance, replacement energycosts, and operation and maintenance costs for coal-cleaning processes, power production equipment, andemissions control systems. CQE™ has four main fea-tures:

• Fuel Evaluator—Performs system-, plant-, or unit-level fuel quality, economic, and technical assess-ments.

• Plant Engineer—Provides in-depth performance evalu-ations with a more focused scope than provided in theFuel Evaluator.

• Environmental Planner—Provides access to evaluationand presentation capabilities of the Acid Rain Advisor.

• Coal-Cleaning Expert—Establishes the feasibility ofcleaning a coal, determines cleaning processes, andpredicts associated costs.

Software DescriptionThe CQE™ includes more than 100 algorithms based onthe data generated in the six full-scale field tests. TheCQE™ design philosophy underscores the importance offlexibility by modeling all important power plant equip-

ment and systems and their performance in real-worldsituations. This level of sophistication allows new appli-cations to be added by assembling a model of how objectsinteract. Updated information records can be readilyshared among all affected users because CQE™ is net-work-aware, enabling users throughout an organization toshare data and results. The CQE™ object-oriented design,coupled with an object database management system,allows different views of the same data. As a result, staffefficiency is enhanced when decisions are made.

CQE™ also can be expanded without major revisions tothe system. Object-oriented programming allows newobjects to be added and old objects to be deleted or en-hanced easily. For example, if modeling advancements aremade with respect to predicting boiler ash deposition (i.e.,slagging and fouling), the internal calculations of theobject that provides these predictions can be replaced oraugmented. Other objects affected by ash deposition (e.g.,ash collection and disposal systems, sootblower systems)do not need to be altered; thus, the integrity of the under-lying system is maintained.

System RequirementsCQE™ uses the OS/2® operating system. CQE™ canoperate in stand-alone mode on a single computer or on anetwork. Technical support is available from Black &Veatch for licensed users.

Commercial ApplicationsThe CQE™ system is applicable to all electric powergeneration plants and large industrial/institutional boilersthat burn pulverized coal. Potential users include fuelsuppliers, environmental organizations, government andregulatory institutions, and engineering firms. Interna-tional markets for CQE™ are being explored by both CQInc. and Black & Veatch.

EPRI owns the software and distributes CQE™ to EPRImembers for their use. CQE™ is available to others in theform of three types of licenses: user, consultant, and com-mercializer. CQ Inc. and Black & Veatch have eachsigned commercialization agreements, which give bothcompanies non-exclusive worldwide rights to sell user’slicenses and to offer consulting services that include theuse of CQE™ software. Two U.S. utilities have been


licensed to use copies of CQE™’s stand-alone Acid RainAdvisor. Over 30 U.S. utilities and one U.K. utility haveCQE™ through their EPRI membership. Over 100 utili-ties and coal companies are now using CQE™. Proposalsare pending with several non-EPRI-member U.S. andforeign utilities to license the software.

CQE™ 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 CQE™ program has been incorporated in the Vistaprogram package, which is the latest version of the soft-ware. Vista operates in the Windows® environment. TheVista Fuels Web server has a Home Page on the WorldWide Web (http://www.fuels.bv.com) to promote the soft-ware, facilitate communications between developers andusers, and eventually allow software updates to be distrib-uted 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) 386-6406

ReferencesFinal Report: Development of a Coal Quality Expert. CQInc. June 20, 1998.

“Recent Experience with the CQE™.” Harrison, Clark D.et al. Fifth Annual Clean Coal Technology Conference:Technical Papers. January 1997.

CQE™ Users Manual, CQE™ 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 CQE™.


ENCOAL® Mild CoalGasification ProjectProject completedParticipantENCOAL Corporation (a wholly owned subsidiary ofBluegrass Coal Development Company)

Additional Team MembersBluegrass Coal Development Company (a wholly owned

subsidiary of AEI Resources, Inc.)—cofunderSGI 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% sulfur

Plant Capacity/Production1,000 tons/day of subbituminous coal feed

Project 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 tem-perature is about 1,000 °F, and all remaining water isremoved. A chemical reaction releases the volatile gas-eous material. Solids exiting the pyrolyzer are quenchedto stop the pyrolysis reactions.

In the original process, the quench table solids were fur-ther 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 par-tially cooled, pyrolyzed solids contact a gas stream con-taining a controlled amount of oxygen. Termed “oxidative

deactivation,” a reaction occurs at active surface sites onthe particles, reducing the tendency for spontaneous igni-tion.

Following the VFB, the solids are cooled to near atmo-spheric temperature in an indirect rotary cooler wherewater is added to rehydrate the PDF®. A patented dustsuppressant is added as the PDF® leaves the surge bin.The hot gas produced in the pyrolyzer is sent through acyclone for removal of the particulates, and then cooledin a quench column to stop any additional pyrolysis reac-tions and to condense the Coal-Derived Liquid (CDL®).

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


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 SO2emissions, reduction in NOx emissions (through flamestabilization), and maintenance of boiler rated capacitywith fewer mills in service.

• LFC® products contained no toxins in concentrationsanywhere close to federal limits.

Operational• Steady-state operation exceeding 90% availability was

achieved for extended periods for the entire plant (nu-merous runs exceeded 120 days duration).

• The LFC® process consistently produced 250 tons/dayof PDF® and 250 barrels/day of CDL® from500 tons/day of run-of-mine PRB coal.

• Integrated operation of the LFC® process componentsover five years has provided a comprehensive databasefor evaluation and design of a commercial unit.

• Over 83,500 tons of PDF® were shipped via 17 unittrains and one truck shipment to seven customers insix states. Shipments included 100% PDF® and blendsfrom 14–94% PDF®.

• PDF®, alone and in blends, demonstrated excellentcombustion characteristics in utility applications, pro-viding heating values comparable to bituminous coal,more reactivity than bituminous coal, and a stableflame.

• The low-volatile PDF® also showed promise as a re-ductant in direct iron reducing testing and also as ablast furnace injectant in place of coke.

• Nearly 5 million gallons of CDL® were produced andshipped to eight customers in seven states.

• CDL® demonstrated fuel properties similar to a low-sulfur No. 6 fuel oil but with the added benefit oflower sulfur content. High aromatic hydrocarbon con-tent, however, may make CDL® more valuable as achemical feedstock.

Economic• A commercial plant designed to process 15,000 metric

tons per day would cost an estimated $475 million(2001$) to construct, with annual operating and main-tenance costs of $52 million per year.

Operation and ReportingDesign and Construction

19981997199619951994199319921991199019891988


DOEselectedproject(CCT-III)12/19/89




Preoperational tests initiated 4/92Design completed 7/91


12/89 9/90 7/92Preaward



12/97


Project SummaryOperational PerformanceThe LFC® facility operated for more than 15,000 hoursover a five-year period. Steady-state operation was main-tained for much of the demonstration with availabilitiesof 90% for extended periods. The length of operation andvolume of production proved the soundness and durabil-ity 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 ship-ment to seven customers in six states. Shipments included100% PDF® and blends from 14–94% PDF®. Over 5million gallons of CDL® were produced and shipped toeight customers in seven states.

As with most demonstrations, however, success requiredovercoming many challenges. The most difficult chal-lenge was achieving stability of the PDF® product, whichhad 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 originalplant design. The rotary cooler failed to provide the deac-tivation 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 deactiva-tion. Two courses of action were pursued: (1) develop-ment of interim measures to finish deactivation externalto the plant, enabling immediate PDF® shipment for testburns; and (2) development of an in-plant process forfinishing, eliminating product quality and labor penaltiesfor external finishing.

“Pile layering” was the primary external PDF® finishingmeasure adopted. However, PDF® quality becomes some-what impaired due to changes in size, moisture, and ashcontent.

Pursuit of a finishing process step resulted in establish-ment of a stabilization task force composed of privatesector and government engineers and scientists. Theoutcome was construction and testing of a Pilot Air Stabi-lization System (PASS) to complete the oxidative deacti-vation of PDF®. The PASS controls temperature andhumidity during forced oxidation. The data obtained wereused to develop specifications and design requirementsfor a full-scale, in-plant PDF® finishing unit based upon acommercial (Aeroglide) tower dryer design.

The first shipment of ENCOAL’s liquid CDL® productexperienced unloading problems. The use of heat tracingand tank heating coils solved the unloading problems forsubsequent customers. The CDL® also contained moresolids and water than had been hoped for, but was consid-ered usable as a lower grade oil.

Following VFB installation, CDL® quality improved. Thepour 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 PerformancePDF® offers the advantages of low-sulfur Powder RiverBasin coal without a heating value penalty. In fact, theLFC® process removes organically bound sulfur, makingthe PDF® product lower in sulfur than the parent coal on aBtu basis. Because the ROM coal is low in ash, PDF® ashlevels remain reasonable after processing, even thoughthe ash level is essentially doubled (ash from one ton ofROM coal goes into one-half ton of PDF®).

Dust emissions were not a problem with PDF®. A dustsuppressant (MK) was sprayed on the PDF® to coat thesurface as it leaves the storage bin. Also, PDF® has anarrower particle size distribution than ROM coal, havinga larger fines content but fewer particles in the fugitivedust range than ROM coal.

ENCOAL’s test burn shipments became internationalwhen Japan’s Electric Power Development Company(EPDC) evaluated six metric tons of PDF® in 1994. TheEPDC, which must approve all fuels being considered forelectric power generation in Japan, found PDF® accept-able for use in Japanese utility boilers.

In October 1996, instrumented combustion testing wasconducted at the Indiana-Kentucky Electric Co-

Pre-VFB Post-VFB1992 1993 1994 1995 1996 19971 Total

Raw Coal Feed (tons) 5,200 12,400 67,500 65,800 68,000 39,340 258,300PDF® Produced (tons) 2,200 4,900 31,700 28,600 33,300 19,300 120,500PDF® Sold (tons) 0 0 23,700 19,100 32,700 7,400 82,900CDL® Produced (bbl) 2,600 6,600 28,000 31,700 32,500 20,300 121,700Hours on Line 314 980 4,300 3,400 3,600 2,603 15,197Average Length ofRuns (Days) 2 8 26 38 44 75 N/A

Exhibit 5-49ENCOAL Production

1Through June 1997.


operative’s (IKEC) Clifty Creek Station, Unit No. 3. Im-portant findings included the following:

• Full generating capacity using PDF® was possible withone mill out of service, which was not possible usingthe baseline fuel. Operation using PDF® afforded timeto perform mill maintenance and calibration withoutlosing capacity or revenues, increasing capacity factorand availability, and decreasing operation and mainte-nance 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 theconvective pass that were wetter than those resultingfrom baseline coal use, requiring increased sootblow-ing to control build-up.

The CDL® liquid product is a low-sulfur, highly aromatic,heavy liquid hydrocarbon. CDL® fuel characteristics aresimilar to those of a low-sulfur No. 6 fuel oil, except thatthe sulfur content is significantly lower. CDL®’s marketpotential as a straight industrial residual fuel, however,appears limited. The market for CDL® as a fuel nevermaterialized, and CDL® has limited application as a blendfor high-sulfur residual fuels due to incompatibility of thearomatic CDL® with many straight-chain hydrocarbondistillates.ENCOAL determined that a centrifuge was needed toreduce solids retention and improve marketability ofCDL® (tests validated a 90% removal capability); and anoptimum 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 byENCOAL, 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 full-scale, three-module LFC® plant is $475 million.

Economic benefits from an LFC® commercial plant arederived from the margin in value between a raw, unproc-essed 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 tocresylic 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 fuelbut as a supplement to or substitute for coke in the steelindustry. PDF® characteristics make it attractive to themetallurgical market as a coke supplement in pulverized-coal-injection and granular-coal-injection methods, and asa reductant in direct reduced iron processes.

Partners in the ENCOAL® project completed five detailedcommercial feasibility studies over the course of the dem-onstration and shortly thereafter—two Indonesian, oneRussian, and two U.S. projects. A U.S. project has re-ceived 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 [email protected](858) 551-0247 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Douglas M. Jewell, NETL, (304) 285-4720

ReferencesENCOAL® Mild Gasification Plant Commercial PlantFeasibility Study. U.S. Department of Energy. September1997. Report No. DOE/MC/27339. (Available from NTISas DE98002005.)

Final Design Modifications Report. U.S. Department ofEnergy. September 1997. Report No. DOE/MC/27339-5797. (Available from NTIS as DE98002006.)

ENCOAL® Mild Gasification Project: ENCOAL ProjectFinal Report. Report No. DOE/MC/27339-5798. U.S.Department of Energy. September 1997. (Available fromNTIS as DE98002007.)

“Results of the PDF® Test Burn at Clifty Creek Station.”Topical Report. Johnson, S.A., and Knottnerus, B.A.October 1996.

ENCOAL® Mild Coal Gasification Demonstration ProjectPublic Design and Construction Report. Report No.DOE/MC/27339-4065. ENCOAL Corporation. December1994. (Available from NTIS as DE95009711.)


Coal Processing for Clean FuelsCoal Preparation Technologies

Advanced Coal ConversionProcess DemonstrationProject completedParticipantWestern SynCoal LLC (formerly Rosebud SynCoalPartnership; a subsidiary of Montana Power Company’sEnergy Supply Division)

Additional Team MembersNone

LocationColstrip, Rosebud County, MT (adjacent to WesternEnergy Company’s Rosebud Mine)

TechnologyWestern SynCoal LLC’s Advanced Coal ConversionProcess for upgrading low-rank subbituminous and lignitecoals

Plant Capacity/Production45 tons/hr of SynCoal® product

CoalPowder River Basin subbituminous (Rosebud Mine),0.5–1.5% sulfur, plus tests of other subbituminous coalsand lignites

Project 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®, astable 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 tech-niques to upgrade high-moisture, low-rank coals to pro-duce 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 less than 150 °F by contactwith an inert gas in a vibrating fluidized-bed cooler. Thecooled coal is sized and fed to deep-bed stratifiers whereair pressure and vibration separate mineral matter, includ-ing much of the pyrite, from the coal, thereby reducingthe sulfur content of the product. The low specific gravityfractions are sent to a product conveyor while heavierfractions go to fluidized-bed separators for additional ashremoval.

The fines handling system consolidates the coal fines thatare produced throughout the ACCP facility. The fines aregathered by screw conveyors and transported by dragconveyors to a bulk cooling system. The cooled fines areblended with the coarse product, stored in a 250-ton ca-pacity bin until loaded into pneumatic trucks for off-sitesales, or returned to the mine pit.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


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 includeregular, fines, blends, DSE treated, and special charac-teristic SynCoal® shipped to various customers.

• The product produced was exceptionally close to thedesign 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 NOx 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 were2.93 lb/hr (37.1 parts per million).

• The measured emissions of hydrogen sulfide were0.007 lb/hr (0.12 parts per million).

Economic• Economic data are not available.

Preaward Design and Construction Operation and Reporting

200019991994199319921991199019891988

12/88 9/90 6/92


DOE selected project(CCT-I) 12/9/88


Ground breaking/construction started 3/28/91NEPA process completed (EA) 3/27/91


Construction completed 2/92


Test operation initiated 6/92

**

Project completed/final report issued 6/02*


20022001

6/02

* Projected date**Years omitted


Project SummaryThis project demonstrated an advanced, thermal, coalupgrading process, coupled with physical cleaning tech-niques, that was designed to upgrade high-moisture, low-rank coals to a high-quality, low-sulfur fuel, registered asthe SynCoal® process. The coal was processed throughthree stages (two heating stages followed by an inert cool-ing 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 SynCoal® 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 through-put 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 SynCoal® products, which include regular, fines,blends, dust stabilization enhancement (DSE) treated, andspecial characteristic SynCoal® shipped to various cus-tomers. See Exhibit 5-50 for annual statistics from the

Exhibit 5-50ACCP 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 withSynCoal®.

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, SynCoal® had to be stored with aninert gas or in tightly sealed vessels to prevent air filtra-tion. A CO2 inert storage system was developed and in-stalled for silo storage of SynCoal®. A significant amountof work has gone into addressing the instability issue. Inconjunction with ENCOAL LLC and Amax Coal Com-pany, Western SynCoal researched the effects of differentenvironments and treatments on low-rank coal composi-tion. Specific objectives were to study the exposivity andflammability limits of dust from the conversion processand to identify the causes of spontaneous heating of up-graded coal products. At the time activities were sus-pended, the development efforts were focused on the useof the Aeroglide Tower Reactor design.

The Aeroglide reactor represents a novel method of al-lowing process gases to contact the solids in a mechani-

cally gentle environment. Solids are fed to the unit andflow, assisted only by gravity, downward through a sys-tem of baffles that gently mix the solids during the migra-tion of the solids from the inlet to the outlet. The flow iscontrolled using a mass flow discharge valve. Rows ofbaffles are configured perpendicular to each successiverow. Process gases are introduced using alternate horizon-tally configured baffles and distributed into the solidsuniformly. Process gases migrate to adjacent baffles andexit the process bed of solids. The Aeroglide reactor wasconfigured to rehydrate processed SynCoal®, remove theheat of reaction, and partially oxidize the product in aneffort to promote product stability. This process schemewas intended to modify the characteristics of the finalSynCoal® product allowing traditional transportationtechniques to be employed. Results of the testing werepromising, but not conclusive.

With regard to the operational performance of theSynCoal® product, three different feedstocks were testedat the ACCP facility�North Dakota lignite, Knife Riverlignite, and Amax subbituminous coal. Approximately190 tons of the SynCoal® product produced with theNorth Dakota lignite was burned at the 250-MWe cy-clone-fired Milton R. Young Power Plant Unit No. 1.Testing showed dramatic improvement in cyclone com-

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 Total

Raw Coal 28,686 157,421 371,447 479,621 369,652 395,450 163,272 419,296 441,379 112,931 2,939,235Processed (tons)

Availability (%) 18 50 65 78 65 66 28 70 73 54 58

Forced Outage 68 24 26 13 21 26 8 15 14 36 23Rate (%)

Avg. Feed Rate 21.1 35.8 64.8 70.1 64.3 68.0 66.0 68.4 69.0 73.0 63.3(ton/hr)

SynCoal® Shipped 5,566 57,927 208,428 315,688 238,766 250,070 97,575 288,650 291,604 76,649 1,811,124 (tons)

Note: 163,106 tons of fines sold in July 1997.


Exhibit 5-51ACCP Stack Emissions

Survey ResultsLimit Measured

Particulate Matter 0.031 gr/dscf 0.0259 gr/dscf2.563 lb/hr

Nitrogen Oxides 7.95 lb/hra 4.50 lb/hr11.55 lb/hrb 54.5 ppm

Carbon Monoxide 6.46 lb/hra 9.61 lb/hr27.19 lb/hrb 191.5 ppm

Sulfur Dioxide 7.95 lb/hra 0.227 lb/hr20.27 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 ppma 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 compa-rable capacity. In late Spring 1999, Unit No. 1 was over-hauled, 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 SynCoal® wasused, Unit No. 2 out-produced the overhauled Unit No. 1by an average of 7.3 MWe�285.7 MWe versus 278.4MWe (net)�with 15.0% of the total heat input comingfrom SynCoal. Furthermore, SynCoal® can be credited foractual 1999 SO2 emissions reductions for Unit No. 2 ofapproximately 430 tons, or an 8% reduction, and NOxemissions reductions of approximately 826 tons, or a 19%reduction, when compared with Unit No. 1 emissions.

Environmental PerformanceWestern SynCoal originally assumed that SO2 emissionswould have to be controlled by injecting chemical sorbentsinto the ductwork. Preliminary data indicated that the addi-tion 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 effec-tively removed coal dust from the air before discharge.The Montana Department of Health and EnvironmentalSciences completed stack tests on the east and west bag-house 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, sul-fur 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 SynCoal® isa viable compliance option for meeting SO2 emissionreduction requirements. SynCoal® is an ideal supplemen-tal fuel for plants seeking to burn western low-rank coalsbecause the ACCP allows a wider range of low-sulfur rawcoals without derating the units.

The project was able to prove the value of SynCoal®

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, low-sulfur low-rank coals into valuable carbon-based reducingagents for many metallurgical applications. Furthermore,SynCoal® enhances cement and lime production and pro-vides a value-added bentonite product.

ContactsRay W. Sheldon, General Manager

(406) 252-2277Western SynCoal LLCP.O. Box 7137Billings, MT 59103-7137(406) 252-2090 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Joseph B. Renk III, NETL, (412) 386-6406

ReferencesTechnical Progress Reports (1991�2000). WesternSynCoal LLC. April 2001, January 2001, November1999, February 1999, August 1998, May 1997, February1995, December 1993, and February 1992.


Industrial Applications Program Update 2001 5-155



5-156 Program Update 2001 Industrial Applications

Clean Power from IntegratedCoal/Ore Reduction(CPICOR�)ParticipantCPICOR� Management Company LLC (a limited liabil-ity company composed of subsidiaries of the GenevaSteel Company)

Additional Team MembersGeneva Steel Holdings corporation�cofunder,

constructor, host, and operator of unit

LocationVineyard, Utah County, UT (Geneva Steel Co.�s mill)

TechnologyHIsmelt® direct iron-making process

Plant Capacity/Production3,300 ton/day liquid iron production 160 MW ofelectricity

CoalBituminous, 0.5% sulfur

Project 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 HIsmelt® process is based on producing hot metaland slag from iron ore fines and non-coking coals. Theheart of the process is producing sufficient heat and main-

taining high heat transfer efficiency in the post-combus-tion zone above the reaction zone to reduce and smeltiron oxides. The HIsmelt® process uses a vertical smeltreduction 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 ironore) to form CO and metallic iron. Injection gases andevolved 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 theprocess and maintain hot metal temperature. This heat isgenerated by post-combusting the CO and hydrogen fromthe bath with an O2-enriched hot air blast from the centraltop lance. The heat is absorbed by the slag and molten

iron droplets, which are returned to the bath by gravity.Droplets in contact with the gas in the post-combustionzone absorb heat, but are shrouded during the descent byascending reducing gases, which, together with bath car-bon, prevent unacceptable levels of FeO in the slag. Themolten iron collects in the bottom of the bath and is con-tinuously tapped from the reactor through a fore-hearth,which maintains a constant level of iron in the reactor.Slag, which is periodically tapped through a conventionalblast furnace-type tap hole, is used to coat and control theinternal cooling system and reduce the heat loss.

Reacted gases, mainly N2, CO2, CO, H2, and H2O, exit thevessel. After scrubbing the reacted gases, the cleanedgases will be combusted to produce 160 MWe of powerand can be used to pre-heat and partially reduce the in-coming iron ore.

HIsmelt is a registered trademark of HIsmelt Corporation Pty Limited.CPICOR is a trademark of the CPICOR� Management Company, LLC

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Project Status/AccomplishmentsThe cooperative agreement was awarded on October 11,1996. CPICOR� analyzed the global assortment of newdirect iron-making technologies to determine which tech-nology would be most adaptable to western U.S. coalsand raw materials. Originally, the COREX® process ap-peared suitable for using Geneva�s local raw materials;however, lack of COREX® plant data on 100% raw coalsand ores prevented its application in this demonstration.Thus, CPICOR� chose to examine alternatives. Theprocesses evaluated included: AISI direct iron-making,DIOS, Romelt, Tecnored, Cyclonic Smelter, andHIsmelt®. The HIsmelt® process appears to offer goodeconomic and operational potential, as well as the pros-pect of rapid commercialization. CPICOR� has com-pleted testing of two U.S. coals at the HIsmelt® pilot plantnear 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. CPICOR�wants to have all permits in place before the end of 2001.

On February 1, 1999, Geneva Steel Company (CPICOR�Management Company�s parent corporation) filed a volun-tary 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 Bank-ruptcy 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 inven-tory and the collection of accounts receivable. Withoutsuch access, Geneva Steel would not have sufficient li-quidity to continue its activities and protect its facilities.

CPICOR� has issued several major contracts for theengineering design of the project. HIsmelt Plc. will per-form 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 Plc.) providing funding support.Lurgi will also provide engineering services for the co-generation process, including investigation of a turboexpander for power generation.

Commercial ApplicationsThe HIsmelt® technology is a direct replacement for exist-ing blast furnace and coke-making facilities with addi-tional potential to produce steam for power production.Of the existing 79 coke oven batteries, half are 30 yearsof age or older and are due for replacement or major re-builds. There are about 60 U.S. blast furnaces, all ofwhich have been operating for more than 10 years, withsome originally installed up to 90 years ago. HIsmelt®

represents a viable option as a substitute for conventionaliron-making technology.

The HIsmelt® process is ready for demonstration. Twopilot plants have been built, one in Germany in 1984 andone in Kwinana, Australia in 1991. Through test work inAustralia, the process has been proven�operational con-trol parameters have been identified and complete com-puter models have been successfully developed andproven.

200720062005200420032002199619931992 1997 2001


5/93Preaward


NEPA process completed 7/02*Construction started 7/02*


Operation initiated 9/04*Construction completed 9/04*


Projectcompleted/final

report issued 2/07*Operation

completed 2/07*

**

Environmental monitoringplan completed 1/04*

9/04

**

10/96 2/07

*Projected date** Years omitted



Blast Furnace Granular-CoalInjection SystemDemonstration ProjectProject completedParticipantBethlehem Steel Corporation

Additional 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 granular-coal injection (BFGCI) process

Plant 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% C


Project ObjectiveTo demonstrate that granular coal could effectively dis-place coke and maintain established blast furnace produc-tion rates and quality specifications; to determine theeffect of coal chemistry, such as ash content (quantity andsulfur levels) and volatile levels, on blast furnace perfor-mance; 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 oxida-tion 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 agent for the process. The car-bon reacts with the air and the iron oxide ore to produceheat, iron, and carbon monoxide. The limestone acts as afluxing agent, creating a slag to capture mineral constitu-ents such as sulfur and silicon not wanted in the product.The low-Btu gas leaving the furnace is essentially free ofsulfur and is used to preheat blast air and fire a boiler foron-site power.

Bethlehem Steel introduced coal injection primarily toreduce the amount of coke needed in the blast furnace,which also replaced the natural gas normally injected inthe tuyeres for supplemental fuel. High levels of air toxicsemissions result from coke production requiring exten-sive, expensive control systems. Bethlehem Steel retrofit-ted Units C and D at its Burns Harbor facility, both ratedat 7,000 NTHM/day. The project sought to determine theeffect of coal size and chemical composition on processperformance and economics.

TO STEEL MAKING

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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 associ-ated with comparable coke production. By adjustingblast furnace slag, no additional sulfur emissions re-sulted 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 con-sumed in granulating coal than in pulverizing coal.

• Coal injection decreased furnace permeability, whichcan adversely affect hot blast flow rate and furnaceproductivity, but increasing oxygen enrichment andmoisture content returned permeability and productiv-

ity to acceptable levels. Low-volatile coal replacedsignificantly more coke than lower carbon content,high-volatile coal, which was a major objective andalso a measure of the quality of the overall operation.Using low-volatile Virginia Pocahontas coal, the cokerate was reduced from approximately 740 lb/NTHM to661 lb/NTHM.

• There is a coke rate disadvantage of 3 lb/NTHM foreach one percent increase in ash content at an injectionrate of 260 lb/NTHM. Higher ash coal had no adverseeffect on furnace permeability, productivity, or productquality, but the slag volume increased.

Economic• The capital cost for one complete injection system at

Burns Harbor was $15,073,106 (1990$) for the 7,200NTHM/day blast furnace. The total fixed costs (laborand repair costs) at Burns Harbor were $6.25/ton ofcoal. The total variable costs (water, electricity, naturalgas, and nitrogen) were $3.56/ton of coal. Coal costswere $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 $6.50/ton of iron produced. Based onthe Burns Harbor production of 5.2 million tons ofiron per year, the annual savings is about $34 million.

20001999199819971996199519941993199119901989

Preaward

DOE selectedproject (CCT-III)12/19/89

12/89 11/90





**


Construction started 9/93Design completed 12/93

Environmental monitoring plan completed 12/23/94Construction completed 1/95

Preoperational tests initiated 2/95Operation initiated 11/95

11/95

**Years omitted


Project SummaryBethlehem Steel retrofitted two high-capacity blast fur-naces 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 ques-tions posed in applying the technology went to the effectof coal grind (size) and coal chemistry on coke displace-ment 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 approxi-mately 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 de-signed 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 addi-tional 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 chem-istry. 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 perme-ability, 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 produc-tion required 60% less energy (19.6 kWh/ton) thanpulverized coal production (31.4 kWh/ton). The grind-ing 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 low-volatile baseline coal during tests—a substantial disad-vantage. The blast furnace performance was unaffectedby whether the coal was pulverized or granular at thecoal injection rate of 183 lb/NTHM.

Environmental PerformanceData collected over each test period show that the use ofinjected coal in the blast furnace does not cause an in-crease in the sulfur content of the gas for coals averaging0.76% sulfur. Evidence suggests that adjustments to slagvolume and chemistry could effectively handle highersulfur coals. However, the greatest benefit derived fromapplication of the BFGCI technology is the reduction incoke usage. Coke production is air toxics intensive and tobe avoided if at all possible. With the application of theBFGCI technology, Bethlehem Steel can maintain steelproduction with the limited coke production currently onsite.

Economic SummaryCapital cost for one complete injection system at BurnsHarbor was approximately $15 million (1990$). This doesnot include infrastructure improvements, which cost $87million at Burns Harbor. The fixed operating cost, whichincludes labor and repair costs, was $6.25/ton of coal. Thevariable operating cost, which includes water, electricity,natural gas, and nitrogen, was $3.56/ton of coal. Coal costswere $50–60/ton. This brought the total operating costs to$59.81–69.81/ton of coal. Using $60/ton of coal and anatural gas cost of $2.80/106 Btu, the cost savings wouldbe about $6.50/ton of iron produced. At Burns Harbor,which produces 5.2 million tons of iron per year, the an-nual savings would be about $34 million and the paybackperiod 3.44 years, using a simple rate of return calculation.

Commercial ApplicationsThere are 35 operating blast furnaces in the United States.Seventeen of them are already using some type of coalinjection. An extensive market analysis conducted byBethlehem Steel showed that 18 of the 35 blast furnaceshave the potential to utilize a BFGCI system. In August1994, U.S. Steel Group contracted with ATSI and ClydePneumatic for the installation of a BFGCI unit at theirFairfield Works in Alabama, Blast Furnace #8. The unit,which began operating in 1995, is similar to Bethlehem’sexcept that no added coal grinding facility was needed tomeet the granular coal sizing requirements. FairfieldWorks Blast Furnace #8 produces 6,300 NTHM/day. TheBFGCI installation cost at Fairfield was $20.2 million,


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) 386-5814

ReferencesBlast Furnace Granular Coal Injection System, FinalReport Volume 2—Project Performance and Economics.Bethlehem Steel Corporation. October 1999

“Blast Furnace Granular-Coal Injection System Demon-stration Project.” Hill, D.G. et al. Sixth Clean Coal Con-ference Proceedings: Volume II—Technical Papers.April–May, 1998.



Advanced CycloneCombustor with InternalSulfur, Nitrogen, and AshControlProject completedParticipantCoal Tech Corporation

Additional Team MembersCommonwealth of Pennsylvania, Energy Development

Authority—cofunderPennsylvania Power and Light Company—supplier of

test coalsTampella Power Corporation—host

LocationWilliamsport, Lycoming County, PA (Tampella PowerCorporation’s boiler manufacturing plant)

TechnologyCoal Tech’s advanced, air-cooled, slagging combustor

Plant Capacity/Production23 x 106 Btu/hr of steam


Project 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 simul-taneously remove up to 90% of the SO2 and 90–95% ofthe ash within the combustor and reduce NOx 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 over-all 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 com-bustion of most of the coal particles near the cyclonewall. The combustor was designed so that a high percent-

age of the ash and sorbent fed to the combustor is re-tained as slag. For NOx control, the combustor is operatedfuel rich, with final combustion taking place in the boilerfurnace to which the combustor is attached. The SO2 iscaptured by injection of limestone into the combustor.The cyclonic action inside the combustor forces the coalash and sorbent to the walls where it can be collected asliquid slag. Under optimal operating conditions, the slagcontains a significant fraction of vitrified coal sulfur.Downstream sorbent injection into the boiler providesadditional sulfur removal capacity.

In Coal Tech’s demonstration, an advanced, air-cooledcyclone coal combustor was retrofitted to a 23 x 106 Btu/hr,oil-fired package boiler located at the Tampella PowerCorporation boiler factory in Williamsport, Pennsylvania.

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Results SummaryEnvironmental• SO2 removal efficiencies of over 80% were achieved

with sorbent injection in the furnace at various cal-cium-to-sulfur (Ca/S) molar ratios.

• SO2 removal efficiencies up to 58% were achievedwith sorbent injection in the combustor at a Ca/S mo-lar ratio of 2.0.

• A maximum of one-third of the coal’s sulfur was re-tained in the dry ash removed from the combustor (asslag) and furnace hearth.

• At most, 11% of the coal’s sulfur was retained in theslag rejected through the combustor’s slag tap.

• NOx emissions were reduced to 184 ppm by the com-bustor and furnace, and to 160 ppm with the additionof a wet particulate scrubber.

• Combustor slag was essentially inert.• Ash/sorbent retention in the combustor as slag aver-

aged 72% and ranged from 55–90%. Under more fuel-lean conditions, retention averaged 80%.

• Meeting local particulate emissions standards requiredthe addition of a wet venturi scrubber.

Operational• Combustion efficiencies of over 99% were achieved.• A 3-to-1 combustor turndown capability was demon-

strated. Protection of combustor refractory with slagwas shown to be possible.

• A computer-controlled system for automatic combustoroperation was developed and demonstrated.

Economic• Because the technology failed to meet commercializa-

tion criteria, economics were not developed during thedemonstration. However, subsequent efforts indicatethat the incremental capital cost for installing the coalcombustor in lieu of oil or gas systems is $100–200/kW.

199619951994199319921991198819871986 1989 1990

Preaward

Operation and Reporting7/86 11/873/87

Design andConstruction

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




9/91



Project SummaryThe novel features of Coal Tech�s patentedceramic-lined, slagging cyclone combustorincluded its air-cooled walls and environ-mental control of NOx, SO2, and solid wasteemissions. Air cooling took place in a verycompact combustor, which could be retrofit-ted to a wide range of industrial and utilityboiler designs without disturbing the boiler�swater-steam circuit. In this technology, NOxreduction was achieved by staged combus-tion, and SO2 was captured by injection oflimestone into the combustor and/or boiler.Critical to combustor performance was re-moval of ash as slag, which would otherwiseerode boiler tubes. This was particularlyimportant in oil furnace retrofits where tubespacing is tight (made possible by the low-ash content of oil-based fuels).

The test effort consisted of 800 hours of operation, includ-ing 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 at-tained most of the objectives contained in the cooperativeagreement. About eight different Pennsylvania bituminouscoals with sulfur contents ranging from 1.0�3.3% andvolatile matter contents ranging from 19�37% were tested.

Environmental PerformanceA maximum of over 80% SO2 reduction measured at theboiler outlet stack was achieved using sorbent injection inthe furnace at various Ca/S molar ratios. A maximum SO2reduction of 58% was measured at the stack with lime-stone injection into the combustor at a Ca/S molar ratio of2. A maximum of one-third of the coal�s sulfur was re-tained in the dry ash removed from the combustor andfurnace hearths, and as much as 11% of the coal�s sulfurwas retained in the slag rejected through the slag tap.Additional sulfur retention in the slag is possible by in-creasing 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 ob-

tained, corresponding to 184 ppm. An additional reduc-tion was obtained by the action of the wet particulatescrubber, resulting in atmospheric NOx emissions as lowas 160 ppm.

All the slag removed from the combustor produced tracemetal leachates well below EPA�s Drinking Water Stan-dard. Total ash/sorbent retention as slag in the combustor,under efficient combustion operating conditions, averaged72% and ranged from 55�90%. Under more fuel-lean con-ditions, the slag retention averaged 80%. After the CCTproject, tests on fly ash vitrification in the combustor,modifications to the solids injection system, and increasesin the slag flow rate produced substantial increases in theslag retention rate. To meet local stack particulate emissionstandards, a wet venturi particulate scrubber was installedat the boiler outlet.

Operational PerformanceCombustion efficiencies exceeded 99% after proper oper-ating procedures were achieved. Combustor turndown to6 x 106 Btu/hr from a peak of 19 x 106 Btu/hr (or a 3-to-1turndown) was achieved. The maximum heat input duringthe tests was around 20 x 106 Btu/hr, even though thecombustor was designed for 30 x 106 Btu/hr and the

boiler was thermally rated at around 25 x 106 Btu/hr. Thissituation resulted from facility limits on water availabilityfor the boiler. In fact, due to the lack of sufficient watercooling, even 20 x 106 Btu/hr was borderline, so that mostof the testing was conducted at lower rates.

Different sections of the combustor had different materi-als requirements. Suitable materials for each section wereidentified. Also, the test effort showed that operationalprocedures were closely coupled with materials durability.As an example, by implementing certain procedures, suchas changing the combustor wall temperature, it was pos-sible to replenish the combustor refractory wall thicknesswith slag produced during combustion rather than byadding ceramic to the combustor walls.

The combustor�s total operating time during the life of theCCT project was about 900 hours. This included approxi-mately 100 hours of operation in two other fly ash vitrifi-cation test projects. Of the total time, about one-third waswith coal; about 125 tons of coal were consumed.

Developing proper combustor operating procedures wasalso a project objective. Not only were procedures for oper-ating an air-cooled combustor developed, but the entireoperating database was incorporated into a computer-con-trolled system for automatic combustor operation.

Commercial ApplicationsThe goal of this project was to validate the performanceof the air-cooled combustor at a commercial scale. Whilethe combustor was not yet fully ready for sale with com-mercial guarantees, it was believed to have commercialpotential. Subsequent work was undertaken, which hasbrought the technology close to commercial introduction.

ContactsBert Zauderer, President, (610) 667-0442

Coal Tech CorporationP.O. Box 154Merion Station, PA [email protected](610) 677-0576 (fax)

William E. Fernald, DOE/HQ, (301) 903-9448James U. Watts, NETL, (412) 386-5991

The slagging combustor, associated piping, and control panel for CoalTech�s advanced ceramic-lined slagging combustor are shown.


ReferencesThe Coal Tech Advanced Cyclone Combustor Demonstra-tion Project—A DOE Assessment. Report No. DOE/PC/79799-T1. U.S. Department of Energy. May 1993. (Avail-able from NTIS as DE93017043.)

The Demonstration of an Advanced Cyclone Coal Com-bustor, 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 Corpora-tion. 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 retain, as slag, a high percentageof the non-fuel components injected into the combustor. The slag, shown on the conveyor, isessentially an inert, glassy by-product with value in the construction industry as an aggregate andin the manufacture of abrasives.



Cement Kiln Flue GasRecovery ScrubberProject completed.ParticipantPassamaquoddy Tribe

Additional Team MembersDragon Products Company—project manager and hostHPD, Incorporated—designer and fabricator of tanks and

heat exchangerCianbro Corporation—constructor

LocationThomaston, Knox County, ME (Dragon ProductsCompany’s coal-fired cement kiln)

TechnologyPassamaquoddy Technology Recovery Scrubber™

Plant Capacity/Production1,450 ton/day of cement; 250,000 scfm of kiln gas; andup to 274 ton/day of coal



Project 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 Scrubber™uses cement kiln dust (CKD), an alkaline-rich (potassium)waste, to react with the acidic flue gas. This CKD, repre-senting 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 potassiumto form potassium sulfate, which stays in solution andremains in the liquid as the slurry undergoes separationinto liquid and solid fractions. The solid fraction, in thick-ened 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 pro-cess used at the Dragon Products Company cement plant.

The liquid fraction is passed to a crystallizer that useswaste heat in the flue gas to evaporate the water and re-cover dissolved alkali metal salts. A recuperator lowersthe incoming flue gas temperature to prevent slurryevaporation, enables the use of low-cost fiberglass con-struction material, and provides much of the process wa-ter through condensation of exhaust gas moisture.

The Passamaquoddy Technology Recovery Scrubber™was constructed at the Dragon Products plant inThomaston, Maine, a plant that can process approximately450,000 ton/yr of cement. The process was developed bythe Passamaquoddy Indian Tribe while it was seeking waysto solve landfill problems, which resulted from the need todispose of CKD from the cement-making process.

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Calendar Year

1 2


Results SummaryEnvironmental• The SO2 removal efficiency averaged 94.6% during

the last several months of operation and 89.2% for theentire operating period.

• The NOx 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 theplant 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, aboutone-tenth that allowed for cement kilns, were achievedwith dust loadings of approximately 0.04 gr/scf.

• Pilot testing conducted at U.S. Environmental Protec-tion Agency laboratories under Passamaquoddy Tech-nology, L.P. sponsorship showed 98% HCl removal.

• On three different runs, VOC (as represented by alpha-pinene) removal efficiencies of 72.3, 83.1, and 74.5%were achieved.

• A reduction of approximately 2% in CO2 emissionswas 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 pay-back estimated in 3.1 years.

• Operation and maintenance costs, estimated at$500,000/yr, plus capital and interest costs, are gener-ally offset by avoided costs associated with fuel, feed-stock, and waste disposal and with revenues from thesale of fertilizer.

199819971996199519941993199019891988 1991 1992

Preaward Design and Construction9/88 8/91


DOEselectedproject(CCT-II)9/28/88

12/89



Operation initiated 8/91Construction completed 5/91Preoperational tests initiated 5/91



2/94





Project SummaryThe Passamaquoddy Technology Recovery Scrubber� isa unique process that achieves efficient acid gas and par-ticulate 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 particulatecapture, some NOx reduction, and sufficient uptake of thepotassium (an unwanted constituent in cement) to allowthe slurry to be recycled as feedstock. Waste cement kilndust, exhaust gases (including waste heat), and wastewa-ter 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 ce-ment 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 load-ings 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 chev-ron-type mist eliminator prior to the third operating inter-val 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 pro-duction during the demonstration period. After all modifi-cations were completed, the recovery scrubber enteredinto the third and final operating interval�April to Sep-tember 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 alkali in the CKD was convertedto potassium-based fertilizer, eliminating all solid waste.Exhibit 5-52 lists the number of hours per operating pe-riod, SO2 and NOx inlet and outlet readings in pounds perhour, and removal efficiency as a percentage for eachoperating period.

Average removal efficiencies during the demonstrationperiod were 89.2% for SO2 and 18.8% for NOx emissions.No definitive explanation for the NOx control mechanicswas available at the conclusion of the demonstration.

Aside from the operating period emissions data, an as-sessment was made of inlet SO2 load impact on removalefficiency. For SO2 inlet loads in the range of 100 lb/hr orless, recovery scrubber removal efficiency averaged82.0%. For SO2 inlet loads in the range of 100�200 lb/hr,

Exhibit 5-52Summary of Emissions and Removal Efficiencies

Operating Operating Inlet (lb/hr) Outlet (lb/hr) Removal Efficiency (%)Period Time (hr) SO2 NOx SO2 NOx SO2 NOx

1 211 73 320 10 279 87.0 12.82 476 71 284 11 260 84.6 08.63 464 87 292 13 251 85.4 14.04 259 131 252 16 165 87.6 34.55 304 245 293 28 243 88.7 17.16 379 222 265 28 208 87.4 21.37 328 281 345 28 244 90.1 29.38 301 124 278 10 188 91.8 32.49 314 47 240 7 194 85.7 19.010 402 41 244 6 218 86.1 10.511 460 36 315 6 267 83.4 15.012 549 57 333 2 291 95.9 12.413 464 86 288 4 223 95.0 22.614 405 124 274 9 199 92.4 27.4

Total operating time 5,316

Weighted Average 109 289 12 234 89.2 18.8


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 Environ-mental Quality, the recovery scrubber was subjected todust loadings of approximately 0.04 gr/scf and demon-strated 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 esti-mated 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 Scrubber™ 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 Prod-ucts. In making this projection, $6,000,000 was added tothe “as-built” capital costs to allow for contingency, de-sign/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 thePassamaquoddy Technology Recovery Scrubber™). Theapplicable market for SO2 control is estimated at 75% ofthe 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) 386-6175

ReferencesPassamaquoddy Technology Recovery Scrubber™: FinalReport. Volumes 1 and 2 (Appendices A–M. Passama-quoddy Tribe. February 1994. (Vol. 1 available fromNTIS as DE94011175, Vol. 2 as DE94011176.)

Passamaquoddy Technology Recovery Scrubber™: Pub-lic Design Report. Report No. DOE/PC/89657-T2. Passa-maquoddy Tribe. October 1993. (Available from NTIS asDE94008316.)Passamaquoddy Technology Recovery Scrubber™:Topical Report. Report No. DOE/PC/89657-T1. Passama-quoddy Tribe. March 1992. (Available from NTIS asDE92019868.)

Comprehensive Report to Congress on the Clean CoalTechnology Program: Cement Kiln Flue Gas RecoveryScrubber. Passamaquoddy Tribe. Report No. DOE/FE-0152. U.S. Department of Energy. November 1989.(Available from NTIS as DE90004462.)



Pulse Combustor DesignQualification TestProject completedParticipantThermoChem, Inc.

Additional Team MemberManufacturing and Technology Conversion International,Inc. (MTCI)—technology supplier

LocationBaltimore, MD (MTCI Test Facility)

TechnologyMTCI’s Pulsed Enhanced™ Steam Reforming processusing a multiple resonance-tube pulse combustor.

Plant Capacity/Production30 million Btu/hr (steam reformer)

CoalBlack Thunder (Powder River Basin) subbituminous

Project FundingTotal project cost $8,612,054 100%DOE 4,306,027 50Participants 4,306,027 50

Project 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 Enhanced™ Steam Reforming processincorporates an indirect heating process for thermochemi-cal 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 combus-tion 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 PulsedEnhanced™ Steam Reforming process because it pro-vides a highly efficient and cost-effective heat source.Demonstration of the combustor at the 253-resonance-tube 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 ap-propriateness of controls and instrumentation. Also, anexisting process data unit was used to gasify coal feed-stock 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 gas cleanup train that includestwo stages of cyclones, a venturi scrubber with a scrubbertank, and a gas quench column. An air-cooled heat ex-changer was used to reject heat from the condensation ofexcess steam (unreacted fluidization steam) quenched inthe venturi scrubber and gas quench column. All projecttesting was performed at the MTCI test facility in Balti-more, Maryland.

1 2 3 41 2 3 41 2 3 41 2 3 41 2 3 4 1 2 3 41 2 3 4 3 4 1 2 3 4 1 2 3 4

Calendar Year

1 2


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 NOx emissions to19–23 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.

200220012000199919981994199319921991

Preaward

1995 1997

9/91 10/92



Project relocationrequested 10/26/94


*Projected Date**Years Omitted

Revised cooperative agreementawarded 9/29/98

Construction completed;operation initiated 10/00

Operation complete 5/01

10/00 3/02

Final report/project complete 3/31/02*

Design complete 2/15/99

Restructuring complete3/21/98

Environmental monitoringplan complete 12/00


NEPA process completed 11/98

**

PDU gasification data 4/01


Project SummaryOn September 10, 1998, DOE approved revision ofThermoChem, Inc.’s Cooperative Agreement for a scaled-down 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 com-bustor. 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 emis-sions testing from December 2000 through May 2001.

Environmental PerformanceThe thrust of the testing was to control NOx emissions toacceptable levels. Initial tests at a firing rate of approxi-mately 20 x 106 Btu/hr yielded NOx emissions rangingfrom 79–97 ppmv corrected to 3% oxygen. Using recircu-

lated flue gas (RFG) in the combustor in a second seriesof tests reduced NOx emissions to 19–23 ppmv correctedto 3% oxygen. Carbon monoxide emission levels aver-aged over 300 ppmv, but do not represent a problembecause the combustor flue gas is reburned with productgas to produce steam.

Tests indicated that the use of flue gas recycle limits NOxlevels to acceptable values, as shown in Exhibit 5-53.Testing was conducted using natural gas as a proxy forcoal-derived synthetic gas. At high firing rates, the use offlue gas recycle reduces the NOx levels, corrected to 3%oxygen, to about one-fourth those obtained when flue gasrecycle was not utilized. At low firing rates, the reductionis to about one-third the non-FGR values. The CO levelsand total hydrocarbons do not represent a problem be-cause the flue gas leaving the pulse combustors isreburned with a portion of the product gas to generatesteam for the process. Since NOx once formed is verydifficult to reduce, the focus was on generating accept-able levels of NOx throughout the test program.

Operational PerformanceSix series of tests were completed while firing the 253-tube pulse combustor. These are:

• Series 1: long shield tube, air fluidized bed, no flue gasrecycle bed temperature up to 1,100 °F, natural gasfiring rate up to 14 x 106 Btu/hr.

• Series 2: long shield tube, air fluidized bed, withand without flue gas recycle bed temperature up to1,100 °F, natural gas firing rate up to 22 x 106 Btu/hr.

• Series 3: long shield tube, air fluidized bed, withand without flue gas recycle bed temperature up to1,200 °F, natural gas firing rate up to 22 x 106 Btu/hr.

• Series 4: short shield tube, air fluidized bed, with andwithout flue gas recycle bed temperature up to 1,350 °F,natural gas firing rate up to 23 x 106 Btu/hr.

• Series 5: short shield tube, water bath, without flue gasrecycle bed temperature 212 °F, natural gas firing rateup to 16 x 106 Btu/hr.

Exhibit 5-53253-Tube Pulse Heater Test—Partial Summary

Test Test Test Test Test Test Test TestWithout Without Without Without With With With With

FGR FGR FGR FGR FGR FGR FGR FGR

Firing Rate (106 Btu/hr) 20.6 20.1 17.5 17.5 20.8 21 19.2 17.7Combustion Chamber Temp °F 2,500 2,520 2,500 2,540 2,400 2,490 2,500 2,350Decoupler Temp °F 1,200 1,238 1,240 1,265 1,201 1,245 1,225 1,255Emissions as Measured:NOx, ppmv 58 51 59 57 22 18 26 25CO, ppmv 521 282 77 184 291 290 276 220Total HC, ppmv 61 24 6 7 IE 7 8 20O2 (%) 10.2 9.3 5 8.6 4.2 4 4.2 7.1Emissions Corrected to 3% O2:NOx, ppmv 97 79 82 83 23 19 28 32CO, ppmv 868 434 107 268 312 307 295 285Total HC, ppmv 101 37 9 11 8 9 26


• Series 6: short shield tube, water bath, without flue gasrecycle 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 oper-ating temperature. Bed temperatures included 1,000 °F,1,100 °F, and 1,200 °F.

Economic PerformanceEconomic data are not available.

Commercial ApplicationsPulsedEnhanced™ 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 emis-sions by reducing production of conventional metallurgi-cal 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)[email protected], Inc.6001 Chemical RoadBaltimore, MD 21226William E. Fernald, DOE/HQ,(301) [email protected] E. Makovsky, NETL,(412) [email protected]

ReferencesInternal NETL data.

ThermoChem’s 253 tube pulse combustor.

ThermoChem’s test facility.


Power Plant Improvement Initiative Program Update 2001 6-1

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 �for a general request for proposals forthe commercial scale demonstration of technologies toassure the reliability of the [n]ation�s energy supplyfrom existing and new electric generating facilities forwhich the Department of Energy [(DOE)] upon reviewmay provide financial assistance awards . . . .� 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 ad-equacy of the nation�s power supplies as a whole.Several parts of the United States, including the WestCoast and parts of the Northeast, had experienced roll-ing blackouts and brownouts in the previous two yearscaused in large part by sharp rises in demand for elec-tricity and lagging construction of new power plants.

Program Implementation

IntroductionThe Department of Energy developed a PPII solicita-tion, incorporating general provisions of the CCTProgram (per congressional direction) with some modi-fications 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 im-provements could be in the form of increasing theefficiency of electricity production, reducing environ-mental impacts, or increasing cost-competitiveness.The projects also had to be applicable to a large por-tion 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:

� Advanced combustion or gasification systems andcomponents;

� Advanced NOx control technology;� CO2 capture, and utilization or sequestration;� Combustion or gasification system improvements;� Co-production;� Fine particulate control;� Hydrogen chloride control;� Mercury control technology;� Process control systems;� Repowering;� Steam cycle improvements; and� Wet and dry scrubbers for SO2 control.

The proposals were evaluated on the technical meritsof the proposed technology (40 percent), commercialviability and market potential of the proposed technol-ogy (30 percent), and management approach and capa-bilities of the project team (30 percent). Along withthe technical merit, DOE considered the participant�sfunding and financial proposal; DOE budget con-straints; environmental, health, and safety implications;and program policy factors.

Other implementing provisions provided that title toproperty lies with the participant, i.e., project sponsor.Like the CCT Program, participants are required toprovide at least a 50 percent cost-share and DOE couldprovide up to 25 percent funding for cost growth, ifcost-shared by the participant at no less than the origi-nal cooperative agreement. The solicitation furtherrequired that 75 percent of the direct labor costs, in-cluding subcontract labor, come from the UnitedStates.

Potential participants were required to submit a busi-ness plan with their proposal. This plan had to be spe-cific to the proposed project and show a managementdecision to commit funds for the project. The plan hadto address competition for funds, both internal andexternal. Finally, the plan had to convince DOE thatexpenditures of public monies on the proposed projectwould be a wise investment, i.e., that the effort wouldresult in commercialization of a technology that serveda public purpose and it would not have been commer-cialized absent federal dollars.

Potential participants also needed to submit an Environ-mental Information Volume (EIV). The Department ofEnergy uses the EIV to (1) perform a project-specificreview of environmental issues pertinent to each pro-posed project prior to selection, and (2) perform a moredetailed site-specific review required under the NationalEnvironmental Policy Act (NEPA) after selection.

6. Power Plant Improvement Initiative

6-2 Program Update 2001 Power Plant Improvement Initiative

Exhibit 6-1Geographic Locations of PPII Projects


Intellectual Property RightsWith regard to intellectual property rights, there werethree main issues that must be addressed by the partici-pants: 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 pro-tect proprietary technology and data; however, suchdata must be made available to DOE without limita-tions. 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 ex-ample, section 414 of the Clean Air Act (42 U.S.C. §7651n) exempts temporary (less than 5 years of opera-tion) 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 Imple-mentation 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 Fis-cal Year 2001 (Public Law 106-291) through the trans-fer of $95,000,000 in previously appropriated funding

for the CCT Program. DOE commitments will be ap-proximately $50 million with final values determinedduring negotiations.

Repayment obligations start after the completion of thedemonstration and last for 20 years. The base repay-ment is one-half of one percent of gross equipmentsales and leases plus five percent of royalty and licens-ing 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 repay-ment, 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 re-tained 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 spon-sors 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 ProjectsMost PPII projects focus on technologies enablingcoal-fired power plants to meet increasingly stringentenvironmental regulations at the lowest possible cost.With many coal plants threatened with shutdowns be-cause of environmental concerns, more effective andlower cost emission controls can keep generators run-ning while improving the quality of the nation’s air andwater. Other projects will improve the performance andreliability of power plants.

Alliant Energy Corporate Services, Inc., of Madison,Wisconsin, proposes to use advanced computationalmodeling to improve the performance of coal-burningsystems and “push the envelope” for existing technolo-gies that reduce nitrogen oxides (NOx), pollutants thatcontribute to smog, harmful ozone, and acid rain. TheEnergy Department’s $3.7 million will provide for oneof the three demonstrations proposed by the company,at the Edgewood Generating Station in Sheboygan,Wisconsin. The plant uses a “cyclone boiler,” a type ofcoal furnace especially prone to high nitrogen oxideemissions. Alliant Energy will match the federal fund-ing share for the 15-month project.

Arthur D. Little Inc., of Cambridge, Massachusetts,will outfit a boiler at the Orion Power Company’s AvonLake Power Plant near Cleveland, Ohio, with a hybridpollution control system to reduce nitrogen oxides. Thehybrid system will lower the cost of reducing NOx byintegrating three established NOx-reduction technolo-gies: natural gas reburning, selective non-catalytic re-duction, and selective catalytic reduction. DOE’s shareof the 38-month project is nearly $15 million; A.D.Little will provide $15.6 million.

CONSOL Energy Inc., of South Park, Pennsylvania,plans to demonstrate a multi-pollutant control systemto reduce NOx, sulfur dioxide (SO2), mercury, acidicgases, and fine particles from smaller coal plants for


less money than it costs to control NOx and SO2 sepa-rately. Among the innovations CONSOL plans to in-stall at the AES Greenidge Power Plant near Dresden,New York, is a catalytic NOx-reduction technology thatworks inside the plant’s ductwork, a low-NOx combus-tion 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 com-pany will integrate a fabric filter system (or “bag-house”) 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 cost-share will be matched by $6.9 million in private sectorfunding.

Exhibit 6-2PPII Technology Characteristics

Project Participant Process Page

Combustion Initiative for Innovative Cost-Effective NOx Alliant Energy Corporate Combustion Initiative method and re-engineering/modeling to 6-8Reduction 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-Catalytic 6-10Control for Orion Avon Lake Unit 9 Reduction, Selective Non-Catalytic Reduction, and Selective

Catalytic Reduction

Greenidge Multi-Pollutant Control Project CONSOL Energy, Inc. Single-bed Selective Catalytic Reduction in combination with 6-12low-NOx combustion technology to control NOx and a circulatingdry 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 6-14Hybrid Particulate Collector Technology

Achieving New Source Performance Standards Emission Sunflower Electric Power Ultra-low NOx burners with other combustion-stage controls 6-16Standards Through Integration of Low-NOx Burners with Corporationan Optimization Plan for Boiler Combustion

Polk Power Station Plant Improvement Project Tampa Electric Company Refractory lining wear monitor 6-18

Big Bend Power Station Neural Network-Sootblower Tampa Electric Company Neural-network soot-blowing system in conjunction with 6-20Optimization advanced controls and instruments

Commercial Demonstration of the Manufactured Universal Aggregates, LLC Aggregate manufacturing plant using by-products from a spray 6-22Aggregate Processing Technology Utilizing Spray Dryer dryer desulfurization unitAsh

Sunflower Electric Power Corporation, of Hays, Kan-sas, will install ultra-low-NOx burners with other com-bustion controls to demonstrate a pollution controlconcept that has never been tried in power plants burn-ing western subbituminous coals such as those fromWyoming’s Powder River Basin. The pollution controlswill be demonstrated in a 48-month project at thecompany’s power station in Garden City, Kansas. TheDepartment of Energy will fund $2.8 million with Sun-flower Electric Power providing $3.0 million.

Tampa Electric Company, of Tampa, Florida, has beenselected for two projects. At its Big Bend Power Stationin Apollo Beach, Florida, the company will apply a neu-


ral network system to determine when and how best todislodge soot that can build up inside a boiler and de-grade performance. While sootblowers arecommon in utility boilers, most are manually activatedunder preset rules or the operator’s judgment. Computer-controlled sootblowing technology will provide opti-mum 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 6-3PPII Project Fact Sheets by Project Name

Project Participant Page

Achieving New Source Performance Standards Emission Standards Through Integration of Low-NOx Sunflower Electric Power Corporation 6-16Burners with an Optimization Plan for Boiler Combustion

Big Bend Power Station Neural Network-Sootblower Optimization Tampa Electric Company 6-20

Combustion Initiative for Innovative Cost-Effective NOx Reduction Alliant Energy Corporate Services, Inc. 6-8

Commercial Demonstration of the Manufactured Aggregate Processing Technology Utilizing Spray Universal Aggregates, LLC 6-22Dryer Ash

Demonstration of a Full-Scale Retrofit of the Advanced Hybrid Particulate Collector Technology Otter Tail Power Company 6-14

Development of Hybrid FLGR/SNCR/SCR Advanced NOx Control for Orion Avon Lake Unit 9 Arthur D. Little, Inc. 6-10

Greenidge Multi-Pollutant Control Project CONSOL Energy, Inc. 6-12

Polk Power Station Plant Improvement Project Tampa Electric Company 6-18

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, Pennsylva-nia, 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 com-mercially 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.


Exhibit 6-4PPII Project Fact Sheets by Participant

Participant Project Page

Alliant Energy Corporate Services, Inc. Combustion Initiative for Innovative Cost-Effective NOx Reduction 6-8

Arthur D. Little, Inc. Development of Hybrid FLGR/SNCR/SCR Advanced NOx Control for Orion Avon Lake Unit 9 6-10

CONSOL Energy, Inc. Greenidge Multi-Pollutant Control Project 6-12

Otter Tail Power Company Demonstration of a Full-Scale Retrofit of the Advanced Hybrid Particulate Collector Technology 6-14

Sunflower Electric Power Corporation Achieving New Source Performance Standards Emission Standards Through Integration of 6-16Low-NOx Burners with an Optimization Plan for Boiler Combustion

Tampa Electric Company Polk Power Station Plant Improvement Project 6-18

Tampa Electric Company Big Bend Power Station Neural Network-Sootblower Optimization 6-20

Universal Aggregates, LLC Commercial Demonstration of the Manufactured Aggregate Processing Technology Utilizing 6-22Spray Dryer Ash





Combustion Initiative forInnovative Cost-Effective NOxReductionParticipantAlliant Energy Corporate Services, Inc.

Additional Team MembersWisconsin Power & Light Co.—host

Reaction Engineering International—modeling

Electric Power Research Institute—technology supplier

LocationsSheboygan, Sheboygan County, WI (Wisconsin Power& Light’s Edgewater Generating Station, Unit No. 4)

TechnologyCombustion Initiative modifications for cyclone coal-fired boiler technology using a Computational Fluid Dy-namic (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 chemi-cal reagent injection.

Plant Capacity/Production340 MW

CoalPowder 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 com-putational modeling approach, its Combustion Initiative,to optimize overall power plant NOx performance. The

Combustion Initiative will attempt to hold NOx emissionsto 0.15 lb/106 Btu from a 340-MW cyclone boiler. Cy-clone 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 perfor-mance and maximizing the use of emission reductiontechnologies. The Combustion Initiative method results inthe potential to reduce NOx emissions to 0.15 lb/106 Btuor below, without the use of SCR technology.

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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 NOx emissions using the Combustion Initiative methodon three of the main coal-fired boiler types in the UnitedStates: tangentially fired, cyclone-fired, and wall-firedunits. The three units include Edgewater Generating Sta-tion 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 re-duces stress on equipment. Improved reliability will helpkeep customers lights on, even as demand grows through-out 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 hasbeen 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 InitiativeMethod.

Commercial ApplicationsAlliant Energy’s Combustion Initiative is a science-and-technology—driven approach to lowering emissions andimproving the performance of coal-fired power plants.Through research and development, the company is find-ing 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 success-fully demonstrated, the relatively low capital cost of theCFD-based technology and the high potential NOx reduc-tion 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 Department of Natural Resources(WDNR) has designated Sheboygan as a “Primary OzoneControl Region.” The Edgewater site is located withinthis region. The WDNR regulations call for reduction ofNOx emissions from utility boilers during the Maythrough September “ozone season.” Under these regula-tions, the Edgewater site is required to reduce NOx emis-sions to 0.33 lb/106 Btu by 2003 and to continue to pro-gressively reduce emissions to 0.28 lb/106 by 2008.

* Projected date



Development of Hybrid FLGR/SNCR/SCR Advanced NOxControl for Orion Avon LakeUnit 9ParticipantArthur D. Little, Inc.

Additional Team MembersFuel Tech—equipment supplierRelient Energy—host

LocationAvon Lake, Lorain County, OH (Orion Power’s AvonLake Station, Unit No. 9)

TechnologyA hybrid of Fuel-Lean Gas Reburn/Selective Non-Cata-lytic Reduction, Selective Non-Catalytic Reduction, andSelective Catalytic Reduction


CoalEastern Bituminous Coal

Project 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 NOx-reduction systems that can function as stand-alone unitsor as an integrated, optimized, single-control system.Using Fuel-Lean Gas Reburn/Selective Non-CatalyticReduction (FLGR/SNCR), Selective Non-Catalytic Re-duction (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 de-veloped 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 emis-sion levels, and to operate the hybrid system to improveperformance and reduce compliance costs to enhanceoperation in system-wide dispatch in the deregulatedmarket.

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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 chal-lenge to remain competitive while adapting to deregulationand to impending stringent NOx controls. The NOx controltechnologies available to coal-fired operators are not opti-mized 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 perfor-mance 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



Cooperative agreementsigned 3/02*

3/02 9/04

* Projected date

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 flex-ible means to design their units for competitive dispatchdictated by regional cost and environmental criteria.



Greenidge Multi-PollutantControl ProjectParticipantCONSOL Energy, Inc.

Additional Team MembersAES Greenidge, LLC—hostEnvironmental Elements Corporation (EEC)—technology

supplierFoster Wheeler Energy Corporation (FWEC)—technology

supplierAEP Pro Serv—construction coordinator

LocationTorrey, Yates County, NY (AES’ Greenidge Unit No. 4)

TechnologySingle-bed Selective Catalytic Reduction in combinationwith low-NOx combustion technology to control NOx anda circulating dry scrubber with carbon injection to controlSO2, mercury, and acid gases


CoalBituminous coal (<2% sulfur) co-fired with up to 10%biomass

Project 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 mercuryfrom smaller coal plants. This project would be the first todemonstrate (1) NOx reductions to 0.122 lb/106 Btu usingsingle bed, in-duct Selective Catalytic Reduction (SCR)combined with a low-NOx combustion technology on a

unit burning coal and biomass, (2) 95% SO2 removalusing a Circulating Dry Scrubber (CDS) from Environ-mental 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 ofthe capital cost and one-fourth of the operation and main-tenance cost of conventional SCR or SNCR technology.

Technology/Project DescriptionThe single-bed, in-duct SCR, in combination withlow-NOx combustion technology, can achieve 60% NOxreduction for about one-third the capital cost and one-fourth 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 half that of a conventional fluegas desulfurization (FGD) system. Operating and mainte-nance costs are less for the CDS system. Activated carboninjection into the CDS unit is projected to use 5 to 10times less carbon than direct injection into the flue gasduct for a given level of mercury control, because thecarbon has a greater average contact time in the CDS bedthan in the flue gas duct. Reducing the carbon feed rateresults in substantial mercury control cost savings. TheCDS system will reduce acid gases (SO3, HCl, HF) bymore than 95%, with the additional benefits of reducingplume visibility and secondary particulate formation.Acid gases must be reported to EPA as part of the ToxicRelease Inventory (TRI). The project will also include anevaluation of the impact of biomass co-firing (5–10% ofthe heat input) on the performance of the SCR and CDSsystems.

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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 sub-stantial improvements in mercury, SO3 and fine particu-late control, and substantial reductions in the cost for NOxand SO2 control, compared to conventional technologieswhen applied to the large number of smaller coal-firedgenerating units in the U.S. This project will produceoperating and maintenance cost data, reliability and avail-ability data, and process performance data so that genera-tors will accept the risk of installing multi-pollutant con-trol on smaller coal-fired units. Ultimately, the successfuldemonstration of these technologies will help to ensurethe future availability of low-cost electricity from a sig-nificant 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 ca-

pacities of 50–300 MWe. These smaller units, almost one-quarter of the U.S. coal-fired generating capacity, areincreasingly vulnerable to fuel switching or retirement asa result of more stringent state and federal environmentalregulations. The proposed project will demonstrate thecommercial readiness of an emissions control system thatis particularly suited, because of its low capital and main-tenance costs, to meet the requirements of this large groupof smaller existing electricity generating units.



4/02


9/06

* Projected date



Demonstration of a Full-ScaleRetrofit of the AdvancedHybrid Particulate CollectorTechnologyParticipantOtter Tail Power Company

Additional Team MembersMontana-Dakota Utilities—co-hostNorthWestern Public Service—co-hostW.L. Gore & Associates, Inc.—licensee and filter bag

providerEnergy and Environmental Research Center (University

of North Dakota)—concept developer

LocationBig Stone City, Grant County, SD (Montana-Dakota Utili-ties and NorthWestern Public Service’s Big Stone PowerPlant)

TechnologyAdvanced Hybrid Particulate Collector


CoalLow-sulfur coal

Project FundingTotal Project Cost $13,397,445DOE 6,491,000Participant 6,906,445Project ObjectiveTo demonstrate, in a full-scale application, a hybrid tech-nology that raises the particulate matter capture of coalplants up to 99.99% by integrating fabric filtration andelectrostatic precipitation (ESP) in a single unit. The Ad-

vanced Hybrid Particulate Collector (AHPC) overcomesthe problem of excessive fine particle emissions that es-cape collection in ESPs and the reentrainment of dust inbaghouses. 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 thetechnology and, eventually, long-term bag life.

Technology/Project DescriptionThe AHPC combines the best features of ESPs and bag-houses in an entirely novel manner. The AHPC conceptcombines fabric filtration and electrostatic precipitation inthe same housing, providing major synergism between thetwo methods, both in the particulate collection step and intransfer of dust to the hopper. The AHPC provides ultra-high collection efficiency, overcoming the problem of

excessive fine-particle emissions with conventional ESPs,and solves the problem of reentrainment and re-collectionof dust in conventional baghouses.

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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 levelof 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 eco-nomic analysis of the AHPC compared with conventionalESPs and baghouses indicates that the AHPC is economi-cally competitive with either of these technologies formeeting current standards. For meeting a possible stricter

fine-particle standard or 99.99% control of total particu-lates, 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), theAHPC is a superior technology not only for new installa-tions but as a retrofit technology as well. The AHPC com-bines 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 tech-nology. 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.




3/02 3/05

* Projected date



Achieving 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 supplier

LocationGarden City, Finney County, KS

TechnologyUltra-low NOx burners with other combustion-stagecontrols


CoalSubbituminous coals

Project FundingTotal Project Cost $5,831,100DOE 2,786,900Participant 3,044,200Project ObjectiveTo demonstrate ultra-low-NOx burners with other com-bustion-stage controls with the goal to reduce NOx emis-sions to 0.13-0.14 lb/106 Btu, demonstrating a conceptthat has never been illustrated in plants using subbitumi-nous coals, including those from the Powder River Basin.Expected to help define the extent to which combustionmodifications can reduce NOx from pulverized coal boil-

ers, the project will be tried out on a 360-MW wall-firedunit.

Technology/Project DescriptionLow-NOx Burners (LNB) have been in developmentsince the late 1970s and are in general use on manysteam-electric generating units. Increasing demands foroverall reductions in NOx emissions have continued toput pressure on manufacturers to improve burner design.Recent developments have introduced what are generallyreferenced as ultra-LNB. When used with separated over-fire air (SOFA) they have been found capable of reducingemission rates to very near the current New SourcePerformance Standards (NSPS) level of about0.16 lb/106 Btu.

To further reduce NOx emissions, the participant willemploy five elements: (1) ultra-low NOx burners,

(2) separated over-fire air, (3) fuel flow measurementtransducers, (4) air balancing, and (5) neural networkcontrols.

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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 technol-ogy 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 NOx emissions, at least on a short-termbasis.The full application of the five elements proposed hereinhave never been demonstrated in plants firing subbitumi-nous coals, especially those from Wyoming�s PowderRiver Basin (PRB). Likewise, there are no other wall-fired 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 fabricfilter 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 signifi-cant reductions, to levels of about 0.22 lbs/106 Btu. Thischoice 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 con-serve the critical pool of skilled labor needed to accom-plish this work.


Cooperative agreement awarded 4/02*Project complete/final report issued 9/05*

4/02 9/05

* Projected date



Polk Power Station PlantImprovement ProjectProject WithdrawnParticipantTampa Electric Company

Additional Team MembersProcess Matrix, LLC—technology supplierAlbany Research Center—cofunder

LocationMulberry, Polk County, FL (Tampa Electric’s Polk PowerStation)

TechnologyRefractory lining wear monitor

Plant Capacity/Production250 MW (net)

CoalUnknown

Project FundingTotal Project Cost $1,676,410DOE 637,036Participant 1,039,374Project ObjectiveTo reduce costs and uncertainty related to refractory wearand replacement for Integrated Gasification Combined-Cycles (IGCCs), which are highly efficient, clean, coal-based, 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 avail-ability.

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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 partici-pant because of recent fuel changes.

Phase I would have included the complete process designand preliminary engineering. Phase II would have con-sisted 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 technolo-gies remain competitive for future power generationapplications.


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 nor-mally large sources for CO2 generation and by-products.

A new type of coal-fired power plant called IntegratedGasification Combined-Cycle (IGCC) has been devel-oped, 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 sul-fur, nitrogen compounds and particulates are much easierto remove from this high-pressure, low-volume gasstream in IGCC plants than from the low-pressure, high-volume 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 environ-mental superiority in this regard. At this time, Polk PowerStation is generating 250 MW (net) of power, is operating

at over 80% availability and is one of Tampa ElectricCompany’s premier baseload plants. This same attributeof IGCC plants, a high-pressure, low-volume gas stream,which contains most of the fuels carbon, also offers thebest chance to minimize the cost and demonstrate CO2capture and recovery. The Polk Power Station project alsooffers an opportunity to demonstrate the full recycling ofall coal streams from the gasification process. Within thegasification process, the ability to measure the wearpattern of the brick liner will also be demonstrated toincrease unit reliability and availability including ex-tended life.

This technology will be applicable to all entrained flowgasifiers. There may be crossover applications to othertechnologies that use refractory lining.

Project withdrawn



Big Bend Power StationNeural Network-SootblowerOptimizationParticipantTampa Electric Company

Additional Team MembersPegasus Technology, Inc.—technology supplier

LocationApollo Beach, Hillsborough County, FL (TampaElectric’s Big Bend Power Station)

TechnologyNeural-network soot-blowing system in conjunction withadvanced controls and instruments


CoalUnknown

Project 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 deposi-tion 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%, improveheat 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 NOx generation by 30% or more, improveheat 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 pulver-ized coal boiler.

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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 environ-ment without beneficial use. This loss in efficiency trans-lates 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 NOx generation is primarily afunction of both fuel- and thermal-NOx production. Fuel-

NOx, which generally comprises 20–40% of the total NOxgenerated, is predominately influenced by the levels ofoxygen present, while thermal-NOx, which comprises thebalance, is a function of temperature. As the foulingof the boiler increases and the rate of heat transfer de-creases, peak temperatures increase as does the thermalNOx production.

Due to the composition of coal, particulate matter is alsoa by-product of coal combustion. Modern day utility boil-ers are usually fitted with electrostatic precipitators to aidin the collection of particulate matter (PM). Althoughextremely efficient, these devices are sensitive to rapidchanges in inlet mass concentration as well as total massloading. Traditionally, utility boilers are equipped withdevices known as sootblowers, that use, steam, water, orair to dislodge particulates and clean the surfaces withinthe boiler and are operated based upon established rulesor the operators judgment. Without extreme care and duediligence, excessive soot can overload an ESP resulting inhigh levels of PM being released. This technology haspotential application to all of the more than 1,000 coal-fired units.


Cooperative agreement awarded 4/02*


4/02 2/04

* Projected date



Commercial 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 utilization

LocationKing George County, VA (Birchwood Power Facility)

TechnologyAggregate manufacturing plant using by-products fromspray dryer fluegas desulfurization (FGD) scrubbers

Plant Capacity/Production150,000 tons/year of lightweight aggregate

CoalBituminous, 0.9% sulfur

Project 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 by-products from wet FGD systems or scrubbers. UniversalAggregates’ process can be used to recycle the by-prod-ucts from wet or dry scrubbers. This would reduce plantdisposal costs while reducing the environmental draw-backs of landfilling.

The Birchwood facility will transform 115,000 tons/yearof spray dryer by-products that are currently being dis-posed of in an off-site landfill into 150,000 tons/year of a

useful product, lightweight aggregates that can be used tomanufacture lightweight masonry blocks or lightweightconcrete.

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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 Decem-ber 10, 2001.

Commercial ApplicationsThere are currently twenty-one spray dryer facilities operat-ing in the United States that produce an adequate amountof spray dryer by-product to economically justify the instal-lation 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 cus-tomers indicate that there is a market for the product oncethe commercialization barriers are eliminated by this dem-onstration project.

Cooperative agreement awarded/start design and construction period 3/02*


Start contractnegotiations 12/01*

9/043/02

NEPA complete (EA) 9/02*

Begin aggregate production 9/03*

* Projected date


Program Update 2001 A-1

Appendix A. Historical Perspective andLegislative History

CCT Historical PerspectiveThere were a number of key events that prompted cre-ation 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 sub-committee prepared a report, Report to the Secretary ofEnergy Concerning Commercialization Incentives, thataddressed actions that states could take to provide in-centives 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 lo-cated 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 pro-gram 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 solicita-tions) 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 en-abled CAAA architects to have access to real-time dataon emission control capabilities while structuring pro-posed 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 re-ferred to as air toxics. Title III of the CAAA listed 189

airborne compounds subject to control, including traceelements and volatile and semi-volatile compounds. Toassess the impacts on coal-based power generation,CCT Program projects were leveraged to obtain datathrough an integrated effort among DOE, EPA, EPRI,and the Utility Air Regulatory Group. Through thiseffort, concerns about HAPs relative to coal-basedpower generation have been significantly mitigated,enabling focus on but a few flue gas constituents. Also,because NOx is a precursor to ozone formation, thepresence of NOx in ozone nonattainment areas, even atlow levels, became an issue. This precipitated action inthe CCT Program to include technologies capable ofdeep NOx reduction in the portfolio of technologiessought.

In the course of the last two solicitations of the CCTProgram, a number of energy and environmental con-siderations combined to change the emphasis towardseeking high-efficiency, very-low-emission power gen-eration technology. Energy demand projections in theUnited States showed the need for continued relianceon coal-based power generation, with significantgrowth required into the 21st century. The CAAA, how-ever, capped SO2 emissions at year 2000 levels, andNOx continued to receive increased attention relative toozone nonattainment. Furthermore, particulate emis-sions were coming under increased scrutiny because ofcorrelations with lung disorders and the tendency fortoxic compounds to adhere to particulate matter. Addedto these concerns was the growing concern over globalwarming, and more specifically, the CO2 producedfrom burning fossil fuels. Coal became a primary target

A-2 Program Update 2001

because of the high carbon-to-hydrogen ratio relative tonatural gas, resulting in somewhat higher CO2 emis-sions 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 enhance-ments in efficiency and control SO2, NOx, and particu-lates without introducing external parasitic controldevices. (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 Con-tinuing Appropriations for Fiscal Year 1985 and forOther Purposes. Title I set aside $750 million of thecongressionally rescinded $5.375 billion of the Syn-thetic 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 is-sued 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 se-lected 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 Innova-tion Research Program [SBIR] and Small BusinessTechnology Transfer Program [STTR].)

In a manner similar to the initiation of CCT-I, Con-gress 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 solicita-tion, 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 en-dorsement of the recommendations of the SpecialEnvoys on Acid Rain, including a $2.5 billion govern-ment share of funding for industry/government demon-strations 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 Presi-dent on April 4, 1987.

Public Law 100-202, enacted December 22, 1987, asamended by Public Law 100-446, appropriated a totalof $575 million to conduct CCT-II. About $536 mil-lion was for projects, with the remainder for programdirection and the SBIR and STTR Programs.

The Department of the Interior and Related AgenciesAppropriations Act for FY1989 (Public Law 100-446,enacted September 27, 1988) provided $575 millionfor necessary expenses associated with clean coal tech-nology demonstrations in the CCT-III solicitation. Ofthe total funding, about $546 million was made avail-able for cost-sharing projects, with the remainder forprogram direction and the SBIR and STTR Programs.The act continued the requirement that proposals mustdemonstrate technologies capable of retrofitting orrepowering existing facilities. The statute also autho-rized the use of Tennessee Valley Authority powerprogram funds as a source of nonfederal cost-sharing,except if provided by annual appropriations acts. Inaddition, funds borrowed by Rural ElectrificationAdministration now Rural Utilities Service) electriccooperatives from the Federal Financing Bank becameeligible as cost-sharing in the CCT-III solicitation,except if provided by annual appropriations.

In the Department of the Interior and Related AgenciesAppropriations Act of 1990 (Public Law 101-121,enacted October 23, 1989), Congress provided $600million for the CCT-IV solicitation. CCT-IV, accordingto the act, “shall demonstrate technologies capable ofreplacing, retrofitting, or repowering existing facilitiesand shall be subject to all provisos contained under thishead in Public Laws 99-190, 100-202 and 100-446 asamended by this Act.” About $563 million was madeavailable for federal cofunding of projects selected inCCT-IV, with the remainder for program direction andthe SBIR and STTR Programs.


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 se-lected 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 issu-ing 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 Feb-ruary 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 perfor-mance 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 Gramm-Rudman-Hollings Deficit Reduction Act as well asrescissions. Sequestering reduced CCT Program appro-priations as follows:

• $2.4 million was sequestered from the $400 millionappropriated by Public Law 99-190.

• $2,600 was sequestered from the $575 million ap-propriated by Public Law 100-202, as amended byPublic Law 100-446.

• $2,028 was sequestered from the $575 million ap-propriated by Public Law 100-446, as amended byPublic Law 101-164.

• $455 was sequestered from the $1.2 billion appro-priated by Public Law 101-121, as amended byPublic 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.




• $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 re-stored 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 Oc-tober 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 imple-mentation. At the end of this appendix are fundingprovisions excerpted from appropriations and otherrelevant funding-related acts.

PPII Historical PerspectiveThe roots of this program lie in the blackouts andbrownouts of 1999 and 2000. The Power Plant Im-provement Initiative is an outgrowth of congressionaldirection provided in the fiscal year 2001 appropria-tions to DOE’s fossil energy research program. Fund-ing was added for the program following increasingconcerns over the adequacy of the nation’s power sup-plies. Several parts of the United States, including theWest Coast and parts of the Northeast, had experiencedrolling blackouts and brownouts in the previous twoyears caused in large part by sharp rises in demand forelectricity and lagging construction of new powerplants.

Eligible projects include technologies that boost theefficiencies of currently-operating power plants—gen-erating more megawatts from the same amount offuel—or that lower emissions and allow plants to stayin operation in compliance with environmental stan-dards. The program was also open to technologies thatimprove the economics and overall performance ofcoal-fired power plants.

Private sector proposers must at least match the gov-ernment funding. Proposed technologies must be ma-ture enough to be commercialized within the next fewyears, and the cost-shared demonstrations must belarge enough to show that the technology is viable forcommercial use.


Exhibit A-1

CCT Program Legislative History

Public Date

Law Enacted CCT Round Program Funding Implementation Provisions

98-473 10/12/84 Initiation of CCT Rescinded $750 million of $5.375 billion from the Energy Title III required publication of a notice soliciting statementsProgram; informational Security Reserve (Synthetic Fuels Corporation) to be of interest in and proposals for projects employingsolicitation deposited in a U.S. Treasury Department account entitled emerging CCTs. A report to Congress was required no

“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. 99-236) concurred with CCTproject guidelines contained in Senate Report 99-82, withcertain 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 be issued and projects to beCCT Program as described under the U.S. Treasury Department selected no later than 8/1/86. Project cost-sharingEnergy 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 of a notice soliciting statementssolicitation of interest in, and informational proposals for projects

employing emerging CCTs capable of retrofitting,repowering, or modernizing existing facilities. A report toCongress was required no later than 3/6/87.

100-202 12/22/87 CCT-II Appropriated $50 million for FY beginning 10/1/87 until Required a request for proposals (CCT-II) to be issuedexpended and $525 million for FY beginning 10/1/88 until no later than 60 days following enactment, for emergingexpended. CCTs capable of retrofitting or repowering existing

facilities. Extended project selection from 120 days to 160days after receipt of proposals. Provided for cost-sharing ofpreaward costs for preparation and submission of environ-mental data upon signing of the cooperative agreement.Conference Report (H. Rep. 100-498) provided that projectcost-sharing funds be made available to nonutility as wellas utility applications. No funds were made available fornew, stand-alone applications. H. Rep. Report 100-171 andSenate Report 100-165 outlined provisions for participant torepay government contributions.


Exhibit A-1 (continued)


Public Date


100-446 9/27/88 CCT-III Made available $575 million on 10/1/89 until expended. Request for proposals (CCT-III) to be issued by 5/1/89 forPub. L. 100-202 was amended by striking $525 million and for emerging CCTs capable of retrofitting or repowering existinserting $190 million for FY beginning 10/1/88 until expended, ing facilities. Proposals were to be due 120 days after issuance$135 million for fiscal year beginning 10/1/89 until expended, of the PON; projects were to be selected no later than 120and $200 million for FY beginning 10/1/90 until expended, days after receipt of proposals.provided that outlays for FY89 resulting from use of fundsappropriated under Pub. L. 100-202, as amended, did not Funds borrowed by REA electric cooperatives from theexceed $15.5 million. Federal Financing Bank were made eligible as cost-sharing.

Funds derived by the Tennessee Valley Authority from itspower program were deemed allowable as cost-sharing exceptif provided by annual appropriations acts.

101-45 6/30/89 CCT-III Funds appropriated for FY1989 were made available for a Project selections for the third solicitation were to be made notthird 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 and CCT-V) to be issued, onefor $600 million on 10/1/91 until expended. Pub. L. 100-446 each appropriation, to demonstrate technologies capable ofwas amended by striking $575 million and inserting $450 million replacing, retrofitting, or repowering existing facilities, subjectto be made available on 10/1/89 until expended and $125 million to all provisos contained in Pub. L. 99-190, 100-202, andto be made available on 10/1/90. Unobligated balances excess to 100-446 as amended. The PON (CCT-IV) using funds becom-the needs of the procurement for which they originally were ing available on 10/1/90 was to be issued by 6/1/90, withmade available may be applied to other procurements for which selections made by 2/1/91. The PON (CCT-V) using fundsrequests for proposals had not yet been issued, except that no becoming available on 10/1/91 was to be issued no later thansupplemental, backup, or contingent selection of projects could 9/1/91, with selections made by 5/1/92.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 conducted prior to ability to obligateand inserting $419 million and by striking $125 million and funds. Repayment provisions for CCT-IV and CCT-V were toinserting $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 andCCT-V was deferred until 9/1/91.




Public Date


101-512 11/5/90 CCT-IV and CCT-V Pub. L. 101-121 was amended by striking $600 million made The CCT-IV solicitation was to be issued not later thanavailable on 10/1/90 until expended and $600 million made 2/1/91. The CCT-V PON was to be issued not later thanavailable on 10/1/91 until expended and inserting $600 million 3/1/92. Project selections were to be made within eightmade available as follows: $35 million on 9/1/91, $315 million months of PON’s issuance. Repayment provisions were to beon 10/1/91, and $250 million on 10/1/92, all sums remaining the same as for CCT-III. Provisions were included to provideuntil expended, for use in conjunction with a separate general protections for trade secrets and proprietary information.request for proposals, and $600 million made available as Conference Report (H. Rep. 101-971) recommends changesfollows: $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 to not later than 7/6/92, with10/1/91 and $225 million on 10/1/92 and inserting $100 million selection to be made within 10 months (extended by twoon 10/1/91 and $275 million on 10/1/92. months). The PON was to be for projects that advance sig-

nificantly the efficiency and environmental performance ofcoal-using technologies and be applicable to either new orexisting facilities. Conference Report (H. Rep. 102-256)stated expectations that the CCT-V solicitation would beconducted under the same general types of criteria as CCT-IV,principally modified only to (1) include the wider range ofeligible technologies or applications; (2) adjust technicalcriteria to consider allowable development activities,strengthen criteria for nonutility demonstrations, and adjustcommercial performance criteria for additional facilities andtechnologies with regard to aspects of general energy effi-ciency and environmental performance; and (3) clarify andstrengthen cost and finance criteria, particularly with regard todevelopment activities.

Funding was allowed for project-specific development activi-ties for process performance definition, component designverification, materials selection, and evaluation of alternativedesigns on a cost-shared basis up to a limit of 10 percent ofthe government share of project cost.




Public Date


102-154 Development activities eligible for cost-sharing included(continued) limited modifications to existing facilities for project-related

testing but not construction of new facilities.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 and Commercial ApplicationsPrograms (Title XIII; Subtitle A) authorized DOE to conductprograms for RD&D and commercial applications of coal-based technologies. Secretary of Energy was directed tosubmit to Congress (1) a report that included, among otherthings, recommendations regarding the manner in which thecost-sharing demonstrations conducted pursuant to the CleanCoal Program (Pub. L. 98-473) might be modified and exten-ded in order to ensure the timely demonstration of advancedcoal-based technologies and (2) periodic status reports on thedevelopment of advanced coal-based technologies andRD&D and commercial application attributes.

103-138 11/11/93 Pub. L. 101-512 was amended by striking $150 million on 10/1/93and $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 $18 million available in FY1995and $50 million on 10/1/95 and inserting $18 million on 10/1/94, may be used for administrative oversight of the CCT$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.




Public Date


104-6 4/10/95 Of funds available for obligation in FY1996, $50 million was res-cinded. Of the funds to be made available for obligation in FY1997,$150 million was rescinded.

104-134a 4/26/96 Conference Report (H. Rep. 104-402 to accompany H.R.1977) allowed for the use of up to $18 million in CCTProgram funds for program administration.

104-208b 9/30/96 Conference Report (H. Rep. 104-863 to accompany H.R. 3610) House and Senate committees did not object to use of up tonoted rescission of $123 million for FY1997 or prior years. $16 million in available funds for administration of the CCT

Program in FY1997 (H. Rep. 104-625 and Senate 104-319 toaccompany 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, $101million was rescinded.

105-277 10/21/98 Of funds made available for obligation in prior years, $40 million Conference Report allowed $14.9 million in CCT Programwas deferred. funds for program administration.

106-113 11/29/99 Of funds made available for obligation in prior years, $156 million Conference Report did not object to the use of up to $14.4was deferred. $38,000 was rescinded as a result of the general million in CCT Program funds for program administration.reduction.

106-291 10/11/00 Of funds made available for obligation in prior years, $67 million Conference Report (H. Rep. 106–406) did not object to thewas deferred. Another $95 million was transferred to the Power use of up to $14.4 million in CCT Program funds for programPlant 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 99-190

Public Law 99-190, 99 Stat. 1251 (1985)

CLEAN COAL TECHNOLOGY

Within 60 days following enactment of this Act[Dec. 19, 1985] the Secretary of Energy shall, pursuantto the Federal Nonnuclear Energy Research and Devel-opment Act of 1974 (42 U.S.C. 5901, et seq.), issue ageneral 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 selec-tions 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-shar-ing by project sponsors is required in each of the de-sign, 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 assis-tance: Provided further, That revenues or royaltiesfrom prospective operation of projects beyond the timeconsidered in the award of financial assistance, or pro-

ceeds from prospective sale of the assets of the project,or revenues or royalties from replication of technologyin future projects or plants are not cost-sharing for thepurposes of this appropriation: Provided further, Thatother appropriated Federal funds are not cost-sharingfor the purposes of this appropriation: Provided further,That existing facilities, equipment, and supplies, orpreviously expended research or development fundsare not cost-sharing for the purposes of this appropria-tion, except as amortized, depreciated, or expensed innormal business practice.

Conference Report (H.R. Conf. Rep. No.450, 99th Cong., 1st Sess. [1985])


The managers have agreed to a $400,000,000 CleanCoal Technology program as described under the De-partment of the Treasury, Energy Security Reserve. Billlanguage is included which provides for the selectionof projects no later than August 1, 1986. Within thatperiod, a general request for proposals must be issuedwithin 60 days and proposals must be submitted to theDepartment within 60 days after issuance of the generalrequest for proposals. Language is also included allow-ing the Secretary of Energy to vest title in interestsacquired under agreements in any entity, including theUnited States, and delineating cost-sharing require-ments. Funds for these activities and projects are madeavailable to the Clean Coal Technology program in theEnergy Security program.

It is the intent of the managers that contributions in theform of facilities and equipment be considered only tothe extent that they would be amortized, depreciated orexpensed in normal business practice. Normal businesspractice shall be determined by the Secretary and is notnecessarily the practice of any single proposer. Prop-

PPII Legislative HistoryThe 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, $95,000,000was transfered from funds appropriated in prior yearsunder the CCT Program and made available for a gen-eral request for proposals for the commercial scaledemonstration of technologies to assure the reliabilityof the Nation’s energy supply from existing and newelectric generating facilities. The funds provided wereto 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 ofthe CCT Program except that repayments from sale orlicensing of technologies shall be from both domesticand foreign transactions and the repayments are re-tained for future projects. Congress provided that anyproject approved under PPII shall be considered aClean Coal Technology Demonstration Project, for thepurposes of Chapters 51, 52, and 60 of title 40 of theCode of Federal Regulations.

In Public Law 107-63, Congress provided for fundsexcess to the needs of the PPII procurement shall bemade available for the Clean Coal Power Initiative.

Exhibit A-2 lists all the key legislation relating to PPIIand provides a summary of provisions relating to pro-gram funding as well as program implementation. Fol-lowing this section are funding provisions excerptedfrom appropriations and other relevant funding-relatedacts.


Exhibit A-2

PPII Legislative History

Public Date

Law Enacted Program Funding Implementation Provisions

106-291 10/11/00 Made available $95,000,000 derived by transfer from fundsappropriated 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 PlantImprovement 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 re-ceive 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 de-preciated would be limited in its cost-share value tothe depreciation claimed during the life of the demon-stration project. Furthermore, in determining normalbusiness practice, the Secretary should not acceptvaluation for property sold, transferred, exchanged, orotherwise manipulated to acquire a new basis for de-preciation 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 avail-able 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 demon-stration 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 Con-gress 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 100-202

Public Law 100-202, 101 Stat. 1329-1 (1987)


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 appro-priated 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 Fed-eral Nonnuclear Energy Research and DevelopmentAct of 1974 (42 U.S.C. 5901 et seq.), issue a generalrequest for proposals for emerging clean coal technolo-gies 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 pre-award costs incurred by project sponsors after selection

House Senate Conference

Fiscal year:

1988 $50,000,000 $350,000,000 $50,000,000

1989 200,000,000 500,000,000 525,000,0001990 100,000,000 ___________ __________

Total 350,000,000 850,000,000 575,000,000

and before signing an agreement are allowable to theextent that they are related to (1) the preparation ofmaterial requested by the Department of Energy andidentified as required for the negotiation; or (2) thepreparation and submission of environmental data re-quested by the Department of Energy to complete Na-tional Environmental Policy Act requirements for theprojects: Provided further, That pre-award costs are tobe reimbursed only upon signing of the project agree-ment and only in the same ratio as the cost-sharing forthe total project: Provided further, That reports onprojects selected by the Secretary of Energy pursuantto authority granted under the heading “Clean coaltechnology” in the Department of the Interior and Re-lated Agencies Appropriations Act, 1986, as containedin Public Law 99-190, which are received by theSpeaker of the House of Representatives and the Presi-dent of the Senate prior to the end of the first session ofthe 100th Congress shall be deemed to have met thecriteria in the third proviso of the fourth paragraphunder the heading “Administrative provision, Depart-ment of Energy” in the Department of the Interior andRelated Agencies Appropriations Act, 1986, as con-tained 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.




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 compari-son 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 provid-ing 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 procure-ments. 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 per-sonnel 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 Sec-retary 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 avail-able 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 avail-able 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 re-porting requirements 30 calendar days after receipt byCongress. This provision applies to a maximum of twoproject reports.

Public Law 100-446

Public Law 100-446, 102 Stat. 1774 (1988)


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 ex-pended: 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 and 100-202 as amended bythis Act.

The first paragraph under this head in Public Law 100-202 is amended by striking “and $525,000,000 areappropriated for the fiscal year beginning October 1,1988” and inserting “$190,000,000 are appropriatedfor the fiscal year beginning October 1, 1988, and shallremain available until expended, $135,000,000 areappropriated for the fiscal year beginning October 1,1989, and shall remain available until expended, and$200,000,000 are appropriated for the fiscal year be-ginning October 1, 1990”: Provided, That outlays infiscal year 1989 resulting from the use of funds appro-priated under this head in Public Law 100-202, asamended by this Act, may not exceed $15,500,000:Provided further, That these actions are taken pursuantto section 202(b)(1) of Public law 100-119 (2 U.S.C.909).

For the purposes of the sixth proviso under this head inPublic Laws 99-190, funds derived by the TennesseeValley Authority from its power program are hereafternot to be precluded from qualifying as all or part of anycost-sharing requirement, except to the extent that suchfunds are provided by annual appropriations Acts: Pro-vided, That unexpended balances of funds made avail-able in the “Energy Security Reserve” account in theTreasury for the Clean Coal Technology Program bythe Department of the Interior and Related AgenciesAppropriations Acts, 1986, as contained in section101(d) of Public Law 99-190, shall be merged with thisaccount: Provided further, That for the purposes of thesixth proviso in Public Law 99-190 under this heading,funds provided under section 306 of Public Law 93-32shall be considered non-Federal: Provided further, Thatreports on projects selected by the Secretary of Energypursuant to authority granted under the heading “Cleancoal technology” in the Department of the Interior andRelated Agencies Appropriations Act, 1986, as con-


tained in Public Law 99-190, which are received by theSpeaker of the House of Representatives and the Presi-dent of the Senate prior to the end of the second ses-sion of the 100th Congress shall be deemed to havemet the criteria in the third proviso of the fourth para-graph 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])


Amendment No. 131: Reported in technical disagree-ment. 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 in-sert the following: For necessary expenses of, andassociated with, Clean Coal Technology demonstra-tions 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 amend-ment 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 cost-sharing 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 propos-als, and that the Secretary of Energy should makeproject selections no later than 120 days after receipt ofproposals.


Restore the matter stricken by said amendment,amended to read as follows: The first paragraph underthis head in Public Law 100-202 is amended by strik-ing “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 re-main 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 amend-ment of the Senate. The amendment changes the avail-ability of $525,000,000 originally made available for

fiscal year 1989 in Public Law 100-202 by making$190,000,000 available in 1989, $135,000,000 avail-able in 1990, and $200,000,000 available in 1991 andalso provides an outlay ceiling in fiscal year 1989. TheHouse had proposed $100,000,000 in fiscal year 1989,$225,000,000 in fiscal year 1990, and $200,000,000 infiscal year 1989, $225,000,000 in fiscal year 1990, and$200,000,000 in fiscal year 1991, and the Senate struckthe House language.

Both of these changes are necessary because of budgetallocation constraints, but neither action has an effecton the execution of the Clean Coal program, or on theCongress’ overall support for the program, as is evi-denced by additional appropriations provided for athird procurement of technologies.

The managers agree that administrative contract ex-penses may be incurred up to the budget level of$9,820,000, but caution that close control of such ex-penditures is necessary to assure that the outlay ceilingprovided will be sufficient to cover project costs.

Amendment No. 133: Modifies public law citation asproposed by the Senate.

Amendment No. 134: Reported in technical disagree-ment. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate which clarifies that funds borrowed by REAElectric Cooperatives from the Federal Financing Bankare eligible as cost-sharing in the clean coal technologyprogram.

Amendment No. 135: Reported in technical disagree-ment. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate which specifies clean coal projects may proceed30 calendar days after receipt by Congress of requiredreports, provided the reports are received prior to theend of the 100th Congress.


Public Law 101-45

Public Law 101-45, 103 Stat. 97 (1989)


Notwithstanding any other provision of law, fundsoriginally appropriated under this head in the Depart-ment of the Interior and Related Agencies Appropria-tions Act, 1989, shall be available for a third solicita-tion of clean coal technology demonstration projects,which projects are to be selected by the Department notlater than January 1, 1990.

Public Law 101-121

Public Law 101-121, 103 Stat. 701 (1989)


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 toa separate general request for proposals issued pursu-ant to each of these appropriations shall demonstratetechnologies capable of replacing, retrofitting or re-powering 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: Pro-vided further, That the general request for proposalsusing funds becoming available on October 1, 1991,under this paragraph shall be issued no later than Sep-tember 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 ap-plied to other procurements for which requests for pro-posals have not yet been issued: Provided, That for allprocurements 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 origi-nally selected for negotiation and utilization of avail-able funds: Provided further, That reports on projectsselected by the Secretary of Energy pursuant to author-ity 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 Con-gress shall be deemed to have met the criteria in the

third proviso of the fourth paragraph under the heading“Administrative provisions, Department of Energy” inthe Department of the Interior and Related AgenciesAppropriations Act, 1986, as contained in Public Law99-190, upon expiration of 30 calendar days from re-ceipt of the report by the Speaker of the House of Rep-resentatives and the President of the Senate or at theend of the session, whichever occurs later.

Conference Report (H.R. Conf. Rep. No.264, 101st Cong., 1st Sess. [1989])


Amendment No. 112: Reported in technical disagree-ment. The managers on the part of the House will offera motion to recede and concur in the amendment of heSenate which adds the word “replacing” to the defini-tion of clean coal technology. The managers agree thatthe inclusion of “replacing” for clean coal IV and V isintended to cover the complete replacement of an exist-ing facility if because of design or site specific limita-tions, repowering or retrofitting of the plant is not adesirable option.

Amendment No. 113: Appropriates $450,000,000 forfiscal year 1990 for clean coal technology instead of$500,000,000 as proposed by the House and$325,000,000 as proposed by he Senate. This appro-priation along with $125,000,000 provided for fiscalyear 1991 in Amendment 114 fully funds the thirdround of clean coal technology projects. The managersagree that additional manpower is required, particularlyat the Department’s Energy Technology Centers, inorder to manage adequately the increased workloadfrom the accumulation of active clean coal technologyprojects and the inclusion of additional procurementsin this bill. Although a legislative floor is not included,the managers agree that at least eighty personnel will


be required in addition to the approximately thirtyFTE’s now included in the fossil energy research anddevelopment appropriation. The managers agree fur-ther that funds from the fossil energy research and de-velopment appropriation should not be used to pay thecost of more than the equivalent FTE’s paid under thataccount in fiscal year 1989.


In lieu of the matter stricken and inserted by saidamendment, insert: and shall remain available untilexpended, and $125,0000,000

The managers on the part of the Senate will move toconcur in the amendment of the House to the amend-ment 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 appro-priation 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 101-164

Public Law 101-164, 103 Stat. 1109 (1989)


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 appro-priated by the Energy and Water Development Appro-priations 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 accommo-date additional drug related appropriations.

The reductions are in three areas. The new budget au-thority 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 Pe-troleum Reserve oil acquisition. Outlays will be re-

duced from an estimated $169,945,000 to$147,125,000 and will decrease the fill rate from ap-proximately 50,000 barrels per day to approximately46,000 or 47,000 barrels per day. The third reductionrelates to the Pennsylvania Avenue Development Cor-poration. The borrowing authority is reduced from$5,000,000 to $100,000.

The conference agreement includes bill language reduc-ing the amount of funds transferred from trust funds tothe Health Care Financing Administration ProgramManagement account by $32,000,000 from$1,917,172,000 to $18,851,712,000. This reduction,along with the outlays reserved from the regular 1990Labor, Health and Human Services, and Education ap-propriations bill, will be sufficient to support thesubcommittee’s share of the cost of anti-drug abusefunding. The conferees intend that the reduction in trustfund transfers be associated with activities to implementcatastrophic health insurance, where funding needs maybe diminished.

Public Law 101-302

Public Law 101-302, 104 Stat. 213 (1990)


Funds previously appropriated under this head forclean coal technology solicitations to be issued no laterthan June 1, 1990, and no later than September 1,1991, respectively, shall not be obligated until Septem-ber 1, 1991: Provided, That the aforementioned solici-tations shall not be conducted prior to the ability toobligate these funds: Provided further, That pursuant tosection 202(b) of the Balanced Budget and Emergency


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 indi-vidual projects shall be identical to those included inthe Program Opportunity Notice (PON) for Clean CoalTechnology III (CCT-III) Demonstration Projects (so-licitation 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])


Amendment No. 89: Reported in technical disagree-ment. 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 ENERGYCLEAN 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 Sep-tember 1, 1991: Provided, That the aforementionedsolicitations shall not be conducted prior to the abilityto obligate these funds: Provided further, That pursu-ant 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, provi-sions included for the repayment of government contri-

butions to individual projects shall be identical tothose included in the Program Opportunity Notice(PON) for Clean Coal Technology III (CCT-III) Dem-onstration Projects (solicitation number DE-PS01-89FE 61825), issued by the Department of Energy onMay 1, 1989.

The managers on the part of the Senate will move toconcur in the amendment of the House to the amend-ment of the Senate.

The amendment delays the fourth and fifth clean coaltechnology solicitations as proposed by the Senate andspecifies that, when issued, these solicitations must userepayment provisions used successfully in the thirdsolicitation. This provision was included in the Houseintroduced bill (H.R. 4828) and modifies a Senateamendment to the original Dire Emergency Supple-mental.

The managers agree that changes to the clean air bill,proposed by a House authorizing committee, thatwould modify the Clean Coal Technology programmust be resolved before a reasonable solicitationcan be issued. The proposed delay will allow suchresolution.

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 ofprocurements. These provisions were developed over afour year period based on experience of previous pro-curements and negotiations, and input from industrialparticipants, Congress, and the managers of the pro-gram. They appear to be working well.

Based on the long-term experience, and the clear factthat implementation of this type of technology willbecome even more important with passage of clean airlegislation, the managers reject proposals put forth bythe Department of Energy to increase rates substan-

tially. Such proposals, while they might increase therecovery of government-provided funds over periodsof up to 20 years, might also act as a deterrent to indus-trial participation in the program, which is already over50 percent cost-shared by industry. The purpose of theprogram is to accelerate the introduction of clean usesof coal in a more efficient manner in compliance withstringent new air quality standards, not the provision ofinvestment returns to the Government at the expense ofnascent markets.

Public Law 101-512

Public Law 101-512, 104 Stat. 1915 (1990)


The first paragraph under this head in Public Law101-121 is amended by striking “$600,000,000 shall bemade available on October 1, 1990, and shall remainavailable until expended, and $600,000,000 shall bemade available on October 1, 1991, and shall remainavailable until expended” and inserting “$600,000,000shall be made available as follows: $35,000,000 onSeptember 1, 1991, $315,000,000 on October 1, 1991,and $250,000,000 on October 1, 1992, all such sums toremain available until expended for use in conjunctionwith a separate general request for proposals, and$600,000,000 shall be made available as follows:$150,000,000 on October 1, 1991, $225,000,000 onOctober 1, 1992, and $225,000,000 on October 1,1993, all such sums to remain available until expendedfor use in conjunction with a separate general requestfor proposals”: Provided, That these actions are takenpursuant to section 202(b)(1) of Public Law 100-119


(2 U.S.C. 909): Provided further, That a fourth generalrequest for proposals shall be issued not later than Feb-ruary 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 propos-als: 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 Opportu-nity 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 appropria-tions Act shall be expended only in accordance withthe provisions governing the use of such funds con-tained under this head in this or any other appropria-tions 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 ap-plied 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 theDepartment of Energy, for a period of up to five (5)years after completion of the operations phase of acooperative agreement may provide appropriate pro-tections, including exemptions from subchapter II ofchapter 5 of title 5, United States Code, against thedissemination of information that results from demon-stration activities conducted under the Clean CoalTechnology Program and that would be a trade secretor commercial or financial information that is privi-

leged or confidential if the information had been ob-tained from and first produced by a non-Federal partyparticipating in a Clean Coal Technology project: Pro-vided further, That, in addition to the full-time perma-nent Federal employees specified in section 303 ofPublic 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 theprograms under this head using funds available underthis head in this and any other appropriations Act andof which 35 shall be for PETC and 30 shall be forMETC: Provided further, That reports on projects se-lected by the Secretary of Energy pursuant to authoritygranted under this heading which are received by theSpeaker of the House of Representatives and the Presi-dent of the Senate less than 30 legislative days prior tothe end of the second session of the 101st Congressshall be deemed to have met the criteria in the thirdproviso of the fourth paragraph under the heading “Ad-ministrative provisions, Department of Energy” in theDepartment of the Interior and Related Agencies Ap-propriations Act, 1986, as contained in Public Law 99-190, upon expiration of 30 calendar days from receiptof the report by the Speaker of the House of Represen-tatives and the President of the Senate or at the end ofthe session, whichever occurs later.

Conference Report (H.R. Conf. Rep. No.971, 101st Cong., 2nd Sess. [1990])


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: Provides $315,000,000 for cleancoal technology on October 1, 1991 as proposed by theHouse instead of $250,000,000 as proposed by theSenate. This amendment and Amendment No. 142 shiftthe availability of $65,000,000 from fiscal year 1991 tofiscal year 1992.

Amendment No. 144: Provides dates for two solicita-tions for clean coal technology as proposed by the Sen-ate. The date for CCT-IV is amended to February 1,1991 from January 1, 1991. The date for CCT-V is notchanged from the Senate date of March 1, 1992.

The managers have agreed to a February 1, 1991 datefor the next solicitation to enable the Department topublish a draft solicitation for comment by interestedparties. It is expected that there will be changes toevaluation criteria and other factors that make it im-perative that potential proposers have an opportunity tocomment on the content of the solicitation.

The managers urge the Department to include potentialbenefits to remote, import-dependent sites as a pro-gram policy factor in evaluating proposals. TheDepartment should also consider projects which canprovide multiple fuel resource options for regionswhich are more than seventy-five percent dependent onone fuel form for total energy requirements.

Amendment No. 145: Requires selection of projectswithin eight months of the requests for proposals re-quired by Amendment No. 144 as proposed by theSenate. The House had no such provision.

Amendment No. 146: Requires repayment of govern-ment contributions to projects under conditionsidentical to the most recent clean coal solicitation asproposed by the Senate. The House had no such provi-sion.

Amendment No. 147: Provides that funds for cleancoal technology may be expended only under condi-


tions contained in appropriations Acts. The Senatelanguage had prohibited geographic restrictions on theexpenditure of funds. The House had no such provi-sion. The managers direct that no preferential consider-ation 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 fos-sil energy technology centers as proposed by the Sen-ate. The House had no such provision. The managersagree that the earmarks for PETC and METC are mini-mum levels and may be increased as necessary.

The managers agree that no more than the current 30full-time equivalent positions from fossil energy re-search and development may be used in the clean coalprogram in fiscal year 1991.

Public Law 102-154

Public Law 102-154, 105 Stat. 990 (1991)


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 previ-ous appropriations Acts, projects selected pursuant tothe fifth general request for proposals shall advancesignificantly the efficiency and environmental perfor-mance 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 defini-tion, component design verification, materials selec-tion, 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 ap-plied to other procurements for use on projects forwhich cooperative agreements are in place, within thelimitations and proportions of Government financing

increases currently allowed by law: Provided, Thathereafter, the Department of Energy, for a period of upto five years after completion of the operations phaseof a cooperative agreement may provide appropriateprotections, including exemptions from subchapter IIof chapter 5 of title 5, United States Code, against thedissemination of information that results from demon-stration activities conducted under the Clean CoalTechnology Program and that would be a trade secretor commercial or financial information that is privi-leged or confidential if the information had been ob-tained from and first produced by a non-Federal partyparticipating in a Clean Coal Technology project: Pro-vided further, That hereafter, in addition to the full-timepermanent Federal employees specified in section 303of Public Law 97-257, as amended, no less than 90full-time Federal employees shall be assigned to theAssistant Secretary for Fossil Energy for carrying outthe programs under this head using funds availableunder this head in this and any other appropriations Actand of which not less than 35 shall be for PETC andnot less than 30 shall be for METC: Provided further,That hereafter reports on projects selected by the Sec-retary of Energy pursuant to authority granted underthis heading which are received by the Speaker of theHouse of Representatives and the President of the Sen-ate less than 30 legislative days prior to the end of eachsession of Congress shall be deemed to have met thecriteria in the third proviso of the fourth paragraphunder the heading “Administrative provisions, Depart-ment of Energy” in the Department of the Interior andRelated Agencies Appropriations Act, 1986, as con-tained 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 of


the Senate or at the end of the session, whichever oc-curs later.

Conference Report (H.R. Conf. Rep. No.256, 102nd Cong., 1st Sess. [1991])



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 pro-viso 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 proposals

The managers on the part of the Senate will move toconcur in the amendment of the House to the amend-ment 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 propos-als should include an additional month to allow for thepreparation of proposals by the private sector, and upto an additional month for Department of Energy re-view 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 con-ditions 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 commer-cial 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 particu-larly 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: Reported in technical disagree-ment. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate which directs the Secretary of Energy toreobligate up to $44,000,000 from the fourth round ofClean Coal Technology proposals to a proposal rankedhighest in its specific technology category by theSource Evaluation Board if other than the highest rank-ing project in that category was selected originally bythe Secretary, and if such funds become unobligatedand are sufficient to fund such projects. This amend-ment would earmark such funds, if they become avail-able, to a specific project not chosen in the Departmentof Energy selection process for the fourth round ofClean Coal Technology.

Amendment No. 168: Technical amendment whichdeletes House proposed punctuation and numbering asproposed by the Senate.

Amendment No. 169: Deletes House proposed lan-guage which made unobligated funds available forprocurements for which requests for proposals have notbeen issued.

Amendment No. 170: Reported in technical disagree-ment. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate which adds “not less than” to employment floorlanguage for PETC as proposed by the Senate. TheHouse had no such language.

Amendment No. 171: Reported in technical disagree-ment. The managers on the part of the House will offera motion to recede and concur in the amendment of theSenate which adds “not less than” to employment floorlanguage for METC as proposed by the Senate. TheHouse had no such language.


Public Law 102-381

Public Law 102-381, 106 Stat. 1374 (1992)


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 103-138

Public Law 103-138, 107 Stat. 1379 (1993)


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 103-332

Public Law 103-332, 108 Stat. 2499 (1994)


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 104-6

Public 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 re-scinded 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 previous appropriations Acts shall beavailable for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.

Public Law 104-134


The managers do not object to the use of up to$18,000,000 in clean coal technology program fundsfor administration of the clean coal program.

Public Law 104-208

Public Law 104-208, 110 Stat. 3009 (1999)


Of the funds made available under this heading forobligation in fiscal year 1997 or prior years,$123,000,000 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.


Conference Report (H.R. Conf. Rep. No.863, 104th Cong., 2nd Sess., [1996])



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 105-18

Public Law 105-18, 111 Stat. 158 (1997)


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 105-83

Public Law 105-83, 111 Stat. 37 (1997)


Public Law 105-277

Public Law 105-277, 112 Stat. 2681 (1998)

CLEAN COAL TECHNOLOGY(DEFERRAL)

Of the funds made available under this heading forobligation in prior years, $10,000,000 of such fundsshall not be available until October 1, 1999;$15,000,000 shall not be available until October 1,2000; and $15,000,000 shall not be available untilOctober 1, 2001: Provided, That funds made availablein previous appropriations Acts shall be available forany ongoing project regardless of the separate requestfor proposal under which the project was selected.

Conference Report (H.R. Conf. Rep. No.825, 105th Cong. 2nd Sess. [1998])


The conference agreement provides for the deferral of$40,000,000 in previously appropriated funds for theclean coal technology program as proposed by theSenate. The House did not propose to defer funding.The Committees agree that $14,900,000 may be usedfor administration of the clean coal technologyprogram.


Public Law 106-113

Public Law 106-113, 113 Stat. 1501 (1999)


Of the funds made available under this heading forobligation in prior years, $156,000,000 shall not beavailable until October 1, 2000: 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.

Conference Report (H.R. Rep. No. 406,106th Cong., 1st Sess. [1999])


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 pro-posed by the House. The managers agree that up to$14,400,00 may be used for program direction.

Public Law 106-291

Public Law 106-291, 114 Stat. 922 (2000)



FOSSIL ENERGY RESEARCH AND DEVELOPMENT(INCLUDING TRANSFERS OF FUNDS)

For necessary expenses in carrying out fossil energyresearch and development activities, under the author-ity of the Department of Energy Organization Act(Public Law 95-91), including the acquisition of inter-est, including defeasible and equitable interests in anyreal property or any facility or for plant or facility ac-quisition or expansion, and for conducting inquiries,technological investigations and research concerningthe extraction, processing, use, and disposal of mineralsubstances without objectionable social and environ-mental 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 un-der 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 available for a general request forproposals for the commercial scale demonstration oftechnologies to assure the reliability of the Nation’senergy supply from existing and new electric generat-ing facilities for which the Department of Energy uponreview may provide financial assistance awards: Pro-vided, That the request for proposals shall be issued nolater than one hundred and twenty days following en-actment of this Act, proposals shall be submitted nolater than ninety days after the issuance of the requestfor proposals, and the Department of Energy shallmake project selections no later than one hundred andsixty days after the receipt of proposals: Provided fur-ther, That no funds are to be obligated for selectedproposals prior to September 30, 2001: Provided fur-ther, That funds provided shall be expended only inaccordance with the provisions governing the use offunds contained under the heading under which theywere originally appropriated: Provided further, Thatprovisions for repayment of government contributionsto individual projects shall be identical to those in-cluded in the Program Opportunity Notice (SolicitationNumber DE-PS01-89FE61825), issued by the Depart-ment of Energy on May 1, 1989, except that repay-ments from sale or licensing of technologies shall befrom both domestic and foreign transactions: Providedfurther, That such repayments shall be deposited in thisaccount to be retained for future projects: Providedfurther, That any project approved under this programshall be considered a Clean Coal Technology Demon-stration Project, for the purposes of Chapters 51, 52,and 60 of title 40 of the Code of Federal Regulations:Provided further, That no part of the sum herein madeavailable shall be used for the field testing of nuclearexplosives in the recovery of oil and gas: Providedfurther, That up to 4 percent of program direction fundsavailable to the National Energy Technology Labora-tory may be used to support Department of Energyactivities not included in this account.


Public Law 107-63

Public Law 107-63, 115 Stat. 414 (2001)



FOSSIL ENERGY RESEARCH AND DEVELOPMENT(INCLUDING TRANSFER OF FUNDS)

For necessary expenses in carrying out fossil energyresearch and development activities, under the author-ity of the Department of Energy Organization Act(Public Law 95-91), including the acquisition of inter-est, including defeasible and equitable interests in anyreal property or any facility or for plant or facility ac-quisition or expansion, and for conducting inquiries,technological investigations and research concerningthe extraction, processing, use, and disposal of mineralsubstances without objectionable social and environ-mental 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 con-struction, 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 En-ergy 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 competitively-awarded demonstrations of commercial scale technolo-gies 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 selec-tions no later than 160 days after the receipt of propos-als: 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 govern-ing 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 Govern-ment contribution to the project on terms and condi-tions 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, develop-ment 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 Public Law 106-291 shall bemade available for the Clean Coal Power Initiativeprovided for under this heading in this Act: Providedfurther, That no part of the sum herein made availableshall be used for the field testing of nuclear explosivesin the recovery of oil and gas: Provided further, Thatup to 4 percent of program direction funds available tothe National Energy Technology Laboratory may beused to support Department of Energy activities notincluded in this account.


Program Update 2001 B-1


CCT Program SolicitationHistoryThe objective of the CCT-I solicitation, issued Febru-ary 17, 1986, was to seek cost-shared projects todemonstrate the feasibility of clean coal technologiesfor commercial applications. The Program OpportunityNotice (PON) elicited 51 proposals. Nine projectswere selected and 14 projects were placed on a list ofalternatives in the event negotiations on the original 9projects were unsuccessful; 8 alternate projects wereeventually selected as replacement projects. Projectswere selected from the list of alternates on threeseparate occasions.

The CCT-II PON, issued February 22, 1988, solicitedcost-shared, innovative clean coal technology projectsto demonstrate technologies that were capable of beingcommercialized in the 1990s, more cost-effective thancurrent technologies, and capable of achieving signifi-cant reductions in SO2 and/or NOx emissions fromexisting coal-burning facilities, particularly those thatcontribute to transboundary air pollution. The CCT-IIPON was the first solicitation implementing therecommendations of the U.S. and Canadian SpecialEnvoys’ report on acid rain. DOE received 55 propos-als and selected 16 as best furthering the goals andobjectives of the PON (no alternates were selected).

The objective of the CCT-III PON, issued May 1,1989, was to solicit cost-shared clean coal technology

projects to demonstrate innovative, energy-efficienttechnologies capable of being commercialized in the1990s. These technologies were to be capable of (1)achieving significant reductions in emissions of SO2

and/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 tech-nologies were to be capable of (1) retrofitting, repow-ering, or replacing existing facilities while achievingsignificant reductions in the emissions of SO2, NOx, orboth, 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 coal-using 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 negotia-tions 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 Com-bustor 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 Demon-stration 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 Depart-ment of Natural Resources (COREX IronmakingDemonstration Project) under CCT-I.

DOE selected three more CCT-I projects: ABBCombustion Engineering, Inc. and CQ Inc. (Develop-ment of the Coal Quality Expert™); Western EnergyCompany (formerly Rosebud SynCoal Partnership,now Western SynCoal LLC; Advanced Coal Conver-sion Process Demonstration); and United Coal Com-pany(Coal Waste Recovery Advanced TechnologyDemonstration).

June 1989The City of Tallahassee CCT-I project, ACFB Repow-ering, was selected from the alternate list.

The M.W. Kellogg Company and Bechtel Develop-ment Company withdrew their CCT-I project, 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 agreements with five CCT-IIparticipants: ABB Combustion Engineering, Inc.(SNOX™ Flue Gas Cleaning Demonstration Project);The Babcock & Wilcox Company (SOx-NOx-RoxBox™ Flue Gas Cleanup Demonstration Project);Passamaquoddy Tribe (Cement Kiln Flue Gas Recov-ery Scrubber); Pure Air on the Lake, L.P. (AdvancedFlue Gas Desulfurization Demonstration Project); andSouthern Company Services, Inc. (Demonstration ofAdvanced Combustion Techniques for a Wall-FiredBoiler).

Energy International, Inc., withdrew its CCT-I project,Underground Coal Gasification Demonstration Project.

February 1990Foster Wheeler Power Systems, Inc., withdrew itsCCT-I proposal, Clean Energy IGCC DemonstrationProject.

April 1990DOE signed cooperative agreements with three CCT-IIparticipants: The Appalachian Power Company (PFBCUtility Demonstration Project); The Babcock &Wilcox Company (Demonstration of Coal Reburningfor Cyclone Boiler NOx Control); and SouthernCompany Services, Inc. (Demonstration of InnovativeApplications of Technology for the CT-121 FGDProcess).

June 1990DOE signed cooperative agreements with the co-participants of one CCT-I project, ABB CombustionEngineering, Inc. and CQ Inc. (Development of theCoal Quality Expert™), and with two CCT-II partici-pants: Southern Company Services, Inc. (Demonstra-tion of Selective Catalytic Reduction Technology forthe Control of NOx Emissions from High-Sulfur, Coal-Fired Boilers) and TransAlta Resources Investment


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 Demonstra-tion); 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(ENCOAL® 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 Engineer-ing IGCC Repowering Project); and two CCT-IIIparticipants, Bethlehem Steel Corporation (Blast

Furnace Granular-Coal Injection System Demonstra-tion Project) and LIFAC�North America (LIFACSorbent Injection Desulfurization DemonstrationProject).

December 1990Negotiations terminated with CCT-II participant,Otisca Industries, Ltd. (Otisca Fuel DemonstrationProject) and CPICOR�.

March 1991DOE signed cooperative agreements with three CCT-III participants: MK-Ferguson Company (now NOXSOCorporation (Commercial Demonstration of theNOXSO SO2/NOx Removal Flue Gas Cleanup Sys-tem); Public Service Company of Colorado (IntegratedDry NOx/SO2 Emissions Control System); and TampaElectric Company (formerly Clean Power Cogenera-tion Limited Partnership; now Tampa Electric Inte-grated 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 Commer-cial Coal/Oil Coprocessing Plant.

August 1991DOE signed a cooperative agreement with CCT-IIIparticipant, DMEC-1 Limited Partnership (formerly

Dairyland Power Cooperative; PCFB DemonstrationProject).

TransAlta Resources Investment Corporation withdrewits CCT-II project, LNS Burner for Cyclone-FiredBoilers Demonstration Project.

September 1991Nine projects were selected under CCT-IV.

Coal Tech Corporation�s CCT-I project, AdvancedCyclone Combustor with Internal Sulfur, Nitrogen, andAsh Control, final reports issued and projectcompleted.

April 1992Tri-State Generation and Transmission Association,Inc.�s (formerly Colorado-Ute Electric Association,Inc.) CCT-I project, Nucla CFB DemonstrationProject, final reports issued and project completed.

June 1992The City of Tallahassee project (CCT-I) was restruc-tured and transferred to York County Energy Partners,L.P. (York County Energy Partners CogenerationProject).

July 1992DOE signed cooperative agreements with two CCT-IVparticipants: Tennessee Valley Authority (now NewYork State Electric & Gas Corporation; MicronizedCoal Reburning Demonstration for NOx Control on a175-MWe Wall-Fired Unit), and the Wabash RiverCoal Gasification Repowering Project Joint Venture(Wabash River Coal Gasification Repowering Project).


August 1992DOE signed a cooperative agreement with CCT-IVparticipant, Sierra Pacific Power Company (Piñon PineIGCC Power Project).

Cordero Mining Company withdrew from negotiationsfor its CCT-IV project, Cordero Coal-UpgradingDemonstration Project.

At the participant�s request, Union Carbide Chemicalsand Plastics Company, Inc. (CCT-IV) was granted anextension of one year to the DOE deadline for complet-ing negotiations of its Demonstration of the UnionCarbide CANSOLV� System at the Alcoa GeneratingCorporation Warrick Power Plant.

October 1992DOE signed cooperative agreements with one CCT-IIIparticipant, Air Products and Chemicals, Inc. (Com-mercial-Scale Demonstration of the Liquid PhaseMethanol [LPMEOH�] Process) and with four CCT-IV participants: Custom Coals International (Self-Scrubbing Coal�: 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 Company�s (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 Moderniza-tion Project (formerly Calvert City Advanced Energy

Project, now McIntosh Unit 4B Topped PCFB Demon-stration Project); Duke Energy Corporation (CamdenClean Energy Demonstration Project); CenteriorEnergy Corporation, on behalf of CPICOR� Manage-ment Company LLC (Clean Power from IntegratedCoal/Ore Reduction [CPICOR�]); 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 Demonstra-tion Project).

July 1993Union Carbide Chemicals and Plastics Company, Inc.,withdrew its CCT-IV proposal, Demonstration of theUnion Carbide CANSOLV� System at the AlcoaGenerating Corporation Warrick Power Plant.

February 1994The Passamaquoddy Tribe�s CCT-III project, CementKiln Flue Gas Recovery Scrubber, final reports issuedand project completed.

March 1994The Babcock & Wilcox Company�s CCT-II project,Demonstration of Coal Reburning for Cyclone BoilerNOx Control, final reports issued and projectcompleted.

June 1994DOE signed a cooperative agreement with CCT-Vparticipant, Arthur D. Little, Inc. (Coal Diesel Com-bined-Cycle Project).

Southern Company Services� CCT-III project, 180-MWe Demonstration of Advanced Tangentially FiredCombustion Techniques for the Reduction of NOx

Emissions from Coal-Fired Boilers, final reports issuedand project completed.

Bechtel Corporation�s CCT-III project, Confined ZoneDispersion Flue Gas Desulfurization Demonstration,final reports issued and project completed.

August 1994DOE signed cooperative agreements with two CCT-Vparticipants, Four Rivers Energy Partners, L.P. (FourRivers Energy Modernization Project); and Pennsylva-nia Electric Company (Warren Station Externally-FiredCombined-Cycle Demonstration Project).

The CCT-III project, Commercial Demonstration ofthe NOXSO SO2/NOx Removal Flue Gas CleanupSystem, was relocated and transferred to NOXSOCorporation.

September 1994The Air Products and Chemicals CCT-III project,Commercial-Scale Demonstration of the Liquid PhaseMethanol (LPMEOH�) Process, was transferred toAir Products Liquid Phase Conversion Company, L.P.

December 1994DOE signed a cooperative agreement with CCT-Vparticipant, Clean Energy Partners Limited Partnership(formerly Duke Energy Corporation; Clean EnergyIGCC Demonstration Project; now Kentucky PioneerIGCC Demonstration Project).

March 1995TAMCO Power Partner�s CCT-IV project, Toms CreekIGCC Demonstration Project, was not granted a furtherextension and the project was concluded.


April 1995Bethlehem Steel Corporation�s 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.�s CCT-II project, 10-MWe Demonstrationof Gas Suspension Absorption, final reports issued andproject completed.

September 1995The Babcock & Wilcox Company�s CCT-II project,SOx-NOx-Rox Box� 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 Demon-stration for NOx Control, to be conducted at bothMilliken Station in Lansing, NY and Eastman KodakCompany in Rochester, NY.

The Babcock & Wilcox Company�s CCT-II project,Full-Scale Demonstration of Low-NOx Cell BurnerRetrofit, final reports issued and project completed.

The Ohio Power Company�s 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 Lake�s CCT-II project, Advanced FlueGas Desulfurization Project, final reports issued andproject completed.

August 1996The Arthur D. Little, Inc., CCT-V project was restruc-tured and retitled as the Clean Coal Diesel Demonstra-tion Project.

September 1996The Appalachia Power Company CCT-II project,PFBC Utility Demonstration Project, was concluded.

October 1996DOE signed a cooperative agreement with CCT-Vparticipant, CPICOR� Management Company LLC(Clean Power from Integrated Coal/Ore Reduction[CPICOR�]).

November 1996Southern Company Services� CCT-II project, Demon-stration of Selective Catalytic Reduction Technologyfor the Control of NOx Emissions from High-Sulfur,Coal-Fired Boilers, final reports issued and projectcompleted.

December 1996ABB Environmental Systems� CCT-II project,SNOX� 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 cooperative agreement for JEA�s(formerly Jacksonville Electric Authority) CCT-Iproject, JEA Large-Scale CFB Combustion Project(formerly The City of Tallahassee project, then theYork County Energy Partners project).

December 1997ENCOAL Corporation�s CCT-III project, ENCOAL®

Mild Coal Gasification Project, final reports issued andproject completed.

DOE signed a new cooperative agreement for therestructured City of Lakeland�s CCT-III project,McIntosh Unit 4A PCFB Demonstration Project(formerly the DMEC-1 Limited Partnership project).

January 1998DOE signed a new cooperative agreement for therestructured City of Lakeland�s CCT-III project,McIntosh Unit 4B Topped PCFB DemonstrationProject (formerly the Four Rivers Energy Partners, L.P.project).

April 1998LIFAC�North America�s CCT-III project, LIFACSorbent Injection Desulfurization DemonstrationProject, final reports issued and project completed.

June 1998Southern Company Services� CCT-II project, Demon-stration of Innovative Applications of Technology forthe CT-121 FGD Process, final reports issued andproject completed.

The ABB Combustion Engineering, Inc. and CQ Inc.�sCCT-I project, Development of the Coal QualityExpert�, final reports issued and project completed.


September 1998Energy and Environmental Research Corporation�sCCT-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.�s CCT-IV project,Pulse Combustor Design Qualification test.

October 1998Energy and Environmental Research Corporation�sCCT-III project, Evaluation of Gas Reburning andLow-NOx Burners on a Wall-Fired Boiler, final reportsissued and project completed.

September 1999Energy and Environmental Research Corp.�s 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.�s CCT-II project,Demonstration of Advanced Combustion Techniquesfor a Wall-Fired Boiler, extending the project.

October 1999Southern Company Services, Inc.�s CCT-II project,Demonstration of Innovative Applications of Technol-ogy for the CT-121 FGD Process, final report issuedand project completed.

New York State Electric & Gas Corporation�s CCT-IVproject, Milliken Clean Coal Technology Demonstra-tion Project, final report issued and project completed.

Bethlehem Steel Corporation�s CCT-III project, BlastFurnace Granular-Coal Injection System Demonstra-tion Project, final report issued and project completed.

December 1999New York State Electric & Gas Corporation�s CCT-IVproject, Micronized Coal Reburning Demonstration forNOx Control, final report issued and project completed.

NOXSO Corporation�s project, Commercial Demon-stration of the NOXSO SO2/NOx Removal Flue GasCleanup System, was terminated.

January 2000Custom Coal International�s CCT-IV project, Self-Scrubbing Coal� : An Integrated Approach to CleanAir, was terminated.

February 2000Public Service Company of Colorado�s CCT-IIIproject, Integrated Dry NOx/SO2 Emissions ControlSystem, final report issued and project completed.

September 2000Wabash River Coal Gasification Repowering ProjectJoint Venture�s CCT-IV project, Wabash River CoalGasification Repowering Project, final report issuedand project completed.

January 2001Sierra Pacific Power Company�s project, Pinon PineIGCC Power Project, final report issued and projectcompleted.

June 2001Western SynCoal LLC�s 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 compli-ance data to meet federal, state, and local require-ments and performance data to aid in future commer-cialization of the technology.

Appendix C. CCT Program Environmental Aspectsand 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

IntroductionThe U.S. Department of Energy (DOE) employs athree-step process to ensure that the CCT Program andits projects comply with the procedural requirementsof the National Environmental Policy Act (NEPA), andthe regulations for NEPA compliance promulgated bythe Council on Environmental Quality (CEQ) (40 CFRParts 1500–1508) and by DOE (10 CFR Part 1021).This process includes (1) preparation of a program-matic environmental impact statement (PEIS) in 1989;(2) preparation of preselection, project-specificenvironmental reviews; and (3) preparation ofpostselection, site-specific NEPA documentation.Several types of NEPA documents have been used inthe CCT Program, including memoranda-to-file (MTF;discontinued as of September 30, 1990), environmen-tal assessments (EA), and environmental impactstatements (EIS). The Department of Energy’s NEPAregulations also provide for categorical exclusions(CX) for certain classes of actions.

Exhibit C-1 shows the progress made through Septem-ber 30, 2001, to complete NEPA reviews of projects inthe CCT Program. By September 30, 2001, NEPAreviews were completed for 35 of the 38 CCT projectsremaining in the program (two NEPA reviews werecompleted for one project, Enhancing the Use of Coalsby Gas Reburning and Sorbent Injection—an MTFwas completed for the Hennepin site and an EA for theLakeside site). From 1987 through September 30,2001, NEPA requirements were satisfied with a CX for1 project, MTFs for 17 projects, EAs for 18 projects

Exhibit C-1NEPA Reviews Completed as of September 30, 2001

0

2

4

6

8

10

12

14

1987 1988a 1989 a,c 1990 1991b 1992c 1993 1994 1995c 1996 1997 1998 1999 2000 2001

Fiscal Year

Nu

mb

er o

f P

roje

cts

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 assessments

Memoranda-to-file Categorical exclusions

Environmental impact statements

C-2 Program Update 2001

tion is used, along with independent informationgathered by DOE, as the basis for site-specific NEPAdocuments that are prepared by DOE for each selectedproject. These NEPA documents are prepared,considered, and published in full conformance withCEQ and DOE regulations for NEPA compliance.

Categorical Exclusions

“Subpart D—Typical Classes of Actions” of the DOENEPA regulations provides for categorical exclusionsas a class of actions that DOE has determined do notindividually or cumulatively have a significant effecton the human environment. Two projects, MicronizedCoal Reburning Demonstration for NOx Control andPulse Combustor Design Qualification Test, weredetermined to be covered by a categorical exclusion inAugust 1992 and November 1998, respectively.

Memoranda-to-File

The MTF was established when DOE’s NEPAguidelines were first issued in 1980. The MTF wasintended for circumstances when the expected impactsof the proposed action were clearly insignificant, yetthe action had not been specified as a categoricalexclusion from NEPA documentation. The use of theMTF was terminated as of September 30, 1990.Exhibit C-2 lists the 17 projects for which an MTFwas prepared.

Environmental Assessments

An EA has the following three functions:

1. To provide sufficient evidence and analysis fordetermining whether a proposed action requirespreparation of an EIS or a finding of no signifi-cant impact (FONSI);

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. Theapplicability of NEPA to the CCT Program is encapsu-lated in the following provision (Section 102):[A]ll agencies of the Federal Government shall—. . .

(C) include in every recommendation or report on propos-als for legislation and other major Federal actions signifi-cantly affecting the quality of the human environment, 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 ofresources 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 conventionalcoal-fired technologies with conventional flue gasdesulfurization controls would continue to beused, and

• “Proposed action,” which assumed that success-fully demonstrated clean coal technologies wouldundergo 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 consider-ation in the project selection process. The site-specific environmental, health, safety, and socioeco-nomic 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 informa-tion. This detailed site- and project-specific informa-


2. To aid an agency’s compliance with NEPA whenno EIS is necessary, i.e., to provide an interdisci-plinary review of proposed actions, assesspotential impacts, and identify better alternativesand mitigation measures; and

3. To facilitate preparation of an EIS when one isnecessary.

An EA’s contents are determined on a case-by-casebasis and depend on the nature of the action. Ifappropriate, a DOE EA also includes any floodplainor wetlands assessment that has been prepared, andmay include analyses needed for other environmentaldeterminations.

If an agency determines on the basis of an EA that it isnot necessary to prepare an EIS, a FONSI is issued.Council on Environmental Quality regulationsdescribe the FONSI as a document that brieflypresents the reasons why an action will not have asignificant effect on the human environment and forwhich an EIS therefore will not be prepared. TheFONSI includes the EA, or a summary of it, and notesany other related environmental documents. The CEQand DOE regulations also provide for notification ofthe public that a FONSI has been issued. Also, DOEprovides copies of the EA and FONSI to the public onrequest.

Exhibit C-3 lists the 18 projects for which an EA hasbeen prepared. The exhibit includes EAs for oneproject that was subsequently withdrawn from theprogram—TransAlta Resources InvestmentCorporation’s Low-NOx/SO2 Burner Retrofit forUtility Cyclone Boilers project—and three that wereterminated—ABB Combustion Engineering’s Com-bustion Engineering IGCC Repowering Project,Bethlehem Steel Corporation’s Innovative Coke OvenGas Cleaning System for Retrofit Applications, andPennsylvania Electric’s Warren Station Externally-Fired Combined-Cycle Demonstration Project.

Project and Participant Completed

CCT-IDevelopment of the Coal Quality Expert™ (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) 3/5/87

CCT-IISNOX™ Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) 1/31/90SOx-NOx-Rox Box™ 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 8/16/89Emissions from High-Sulfur, Coal-Fired Boilers (Southern Company Services, Inc.)180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the 7/21/89Reduction of NOx Emissions from Coal-Fired Boilers (Southern Company Services, Inc.)

CCT-III10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) 9/21/90Full-Scale Demonstration of Low-NOx Cell Burner Retrofit (The Babcock & Wilcox Company) 8/10/90Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) 9/25/90Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler (Energy and 9/6/90Environmental Research Corporation)LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) 10/2/90Integrated Dry NOx/SO2 Emissions Control System (Public Service Company of Colorado) 9/27/90

Exhibit C-2Memoranda-to-File Completed



CCT-IEnhancing the Use of Coals by Gas Reburning and Sorbent Injection (Lakeside site) (Energy and Environmental Research Corporation) 6/25/89Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) 3/27/91

CCT-IICombustion Engineering IGCC Repowering Project (ABB Combustion Engineering, Inc.) (project terminated) 3/27/92Demonstration of Coal Reburning for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) 2/12/91

Innovative Coke Oven Gas Cleaning System for Retrofit Applications (Bethlehem Steel Corporation) (project terminated) 12/22/89Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) 2/16/90Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) 4/16/90

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) 8/10/90Low-NOx/SO2 Burner Retrofit for Utility Cyclone Boilers (TransAlta Resources Investment Corporation) (project withdrawn) 3/21/91

CCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH�) Process (Air Products Liquid Phase Conversion Company, L.P.) 6/30/95

Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) 6/8/93ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) 8/1/90Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) 6/26/95

CCT-IVSelf-Scrubbing Coal�: An Integrated Approach to Clean Air (Custom Coals International) 2/14/94Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) 8/18/93Warren Station Externally Fired Combined-Cycle Demonstration Project (Pennsylvania Electric Company) (Warren Station site) (project terminated) 5/18/95

Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) 5/28/93

CCT-VClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) 6/2/97

Exhibit C-3Environmental Assessments Completed as of September 30, 2001



CCT-IYork County Energy Partners Cogeneration Project (York County, PA site) 8/11/95(York County Energy Partners, L.P.) (project relocated)

JEA Large-Scale CFB Combustion Demonstration Project 12/7/00

CCT-IIIHealy Clean Coal Project (Alaska Industrial Development and Export Authority) 3/10/94

Tampa Electric Integrated Gasification Combined-Cycle Project 8/17/94(Tampa Electric Company)

CCT-IVPiñon Pine IGCC Power Project (Sierra Pacific Power Company) 11/8/94

Note: Completion is the date DOE issued a record of decision.

Environmental Impact Statements

The 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 alterna-tives 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 alterna-tives is to encompass those alternatives to be consid-ered 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. Conse-quently, 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 restruc-tured, 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 Progress

Exhibit C-5 lists the status of projects for which theNEPA process has not yet been completed.

Exhibit C-4Environmental Impact Statements Completed as of

September 30, 2001

Project and Participant Status

CCT-III

McIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) On hold

CCT-VMcIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, On holdLakeland Electric)Clean Power from Integrated Coal/Ore Reduction (CPICOR™) (CPICOR™ Management EIS planned (7/02)Company LLC)Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) EIS planned (5/02)

Exhibit C-5NEPA Reviews in Progress as of September 30, 2001


With respect to emission of air toxics,Proposers should consider . . . the particularelements and compounds [listed in Table 5-1 ofthe PON, “Specific Air Toxics to be Moni-tored”]. Proposers should present anyinformation known concerning the reduction ofemissions of these toxics by [the proposed]technology. Some of the toxics for which theproposed technology may offer control arelikely unregulated in the target market atpresent. The significance and importance ofthe additional control afforded by the proposedtechnology for the continued use of coal shouldbe explained. An example of this kind wouldbe one or more particular air toxic compoundscontrolled by a technology meant for use inpower generation.

The CCT-V PON also stipulates that information on airtoxics be presented in the environmental informationrequired by DOE. Exhibit C-7 lists the 20 projects thatprovide for HAPs monitoring. Eleven of these projectshave completed the HAPs monitoring requirements.The objective of the HAPs monitoring program is toimprove the quality of HAPs data being gathered andto monitor a broader range of plant configurations andemissions control equipment.

The CCT Program is coordinating with organizationssuch as the Electric Power Research Institute (EPRI)and the Ohio Coal Development Office in activitiesfocused on HAPs monitoring and analysis. Further,under the DOE Coal R&D Program, two reportssummarizing the source, distribution, and fate of HAPsfrom coal-fired power plants were published in 1996.A report released in July 1996, Summary of Air ToxicsEmissions Testing at Sixteen Utility Plants, providedassessment of HAPs measured in the coal, across themajor pollution control devices, and the HAPs emittedfrom the stack. A second report, A ComprehensiveAssessment of Toxics Emissions from Coal-FiredPower Plants: Phase I Results from the U.S. Depart-ment of Energy Study, was released in September 1996

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 dissemi-nation of the significant technology-, project-, and site-specific 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 deploy-ment potential. In addition to regulatory compliancedata, further monitoring is required to fulfill thefollowing:

• Ensure that emissions, ambient levels of pollut-ants, and environmental impacts do not exceedexpectations 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 environmentalperformance 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-power-production-source categories. However, there aremany uncertainties as to which HAPs will be regu-lated, their prevalence in various types and sources ofcoal, and their nature and fate as functions of combus-tion characteristics and the particular clean coaltechnology used.

The CCT Program recognizes the importance ofmonitoring HAPs in achieving widespread commer-cialization 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:



CCT-IDevelopment of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ Inc.) Completed 7/31/90LIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) Completed 10/19/88

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) Completed 9/22/87Nucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State Generation and Transmission Association, Inc.) Completed 2/27/88Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Completed 10/15/89 (Hennepin)

Completed 11/15/89 (Lakeside)

Tidd PFBC Demonstration Project (The Ohio Power Company) Completed 5/25/88Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) Completed 4/7/92JEA Large-Scale CFB Combustion Demonstration Project (JEA) Projected 7/01

CCT-IISNOX™ Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) Completed 10/31/91Demonstration of Coal Reburning for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) Completed 11/18/91

SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Completed 12/31/91Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) Completed 3/26/90Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Completed 1/31/91

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Completed 9/14/90Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Completed 12/18/90Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High-Sulfur-Coal-Fired Completed 3/11/93Boilers (Southern Company Services, Inc.)

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of NOx Emissions from Completed 12/27/90Coal-Fired Boilers (Southern Company Services, Inc.)

Exhibit C-6Status of Environmental Monitoring Plans for CCT Projects as of September 30, 2001



CCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process (Air Products Liquid Phase Conversion Company, L.P.) Completed 8/29/9610-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) Completed 10/2/92Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Completed 4/11/97Full-Scale Demonstration of Low-NOx Cell Burner Retrofit (The Babcock & Wilcox Company) Completed 8/9/91Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) Completed 6/12/91Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) Completed 12/23/94McIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) On holdENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Completed 5/29/92Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) Completed 7/26/90LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) Completed 6/12/92Integrated Dry NOx/SO2 Emissions Control System (Public Service Company of Colorado) Completed 8/5/93Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Completed 5/96

CCT-IVMicronized Coal Reburning Demonstration for NOx Control (New York State Electric & Gas Corporation) Completed 8/97Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) Completed 12/1/94Piñon Pine IGCC Power Project (Sierra Pacific Power Company) Completed 10/31/96Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Completed 7/9/93Pulse Combustor Design Qualification Test (ThermoChem, Inc.) Completed 12/00

CCT-VClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) Completed 2/99Clean Power from Integrated Coal/Ore Reduction (CPICOR™) (CPICOR™ Management Company LLC) Projected 9/03Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) To be determinedMcIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) On hold

Exhibit C-6 (continued)Status of Environmental Monitoring Plans for CCT Projects as of September 30, 2001


Coal Processing forClean Fuels

Application Category Participant Project Status

Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project PlannedKentucky Pioneer Energy, LLC Kentucky Pioneer Energy IGCC Demonstration Project PlannedLakeland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project On holdThe Ohio Power Company Tidd PFBC Demonstration Project CompletedSierra Pacific Power Company Piñon Pine IGCC Power Project CompletedTampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project CompletedWabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project CompletedProject Joint VentureJEA JEA Large-Scale CFB Combustion Demonstration Project Planned

ABB Environmental Systems SNOX™ Flue Gas Cleaning Demonstration Project CompletedAirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption CompletedThe Babcock & Wilcox Company Demonstration of Coal Reburning for Cyclone Boiler NOx Control CompletedThe Babcock & Wilcox Company SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstration Project CompletedNew York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project CompletedPublic Service Company of Colorado Integrated Dry NOx/SO2 Emissions Control System CompletedPure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project CompletedSouthern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler CompletedSouthern Company Services, Inc. Demonstration of Innovative Applications of Technology for the Completed

CT-121 FGD ProcessSouthern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Combustion Completed

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

ENCOAL Corporation ENCOAL® Mild Coal Gasification Project Completed

CPICOR™ Management Company LLC Clean Power from Integrated Coal/Ore Reduction (CPICOR™) Planned

Exhibit C-7Status of CCT Projects Monitoring Hazardous Air Pollutants as of September 30, 2001

Advanced ElectricPower Generation

IndustrialApplications

EnvironmentalControl Devices


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 repre-sented a range of different coal types, process configu-rations, 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. indus-trial 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 impor-tance, especially for women in their child-bearingyears, of heeding consumption advisories on noncom-mercial 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 coal-fired 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


Project ContactsListed below are contacts for obtaining further infor-mation about specific CCT Program and PPII demon-stration projects. Listed are the name, title, phonenumber, fax number, mailing address, and e-mailaddress, if available, for the project participant contactperson. In those instances where the project partici-pant consists of more than one company, a partner-ship, or joint venture, the mailing address listed is thatof the contact person. In addition, the names, phonenumbers, and e-mail addresses for contact persons atDOE Headquarters and the National Energy Technol-ogy Laboratory (NETL) are provided.

CCT ProgramEnvironmental ControlDevices

SO2 Control Technologies

10-MWe Demonstration of Gas SuspensionAbsorption

Participant:AirPol, Inc.Contacts:Niels H. Kastrup

(281) 539-3400(281) 539-3411 (fax)[email protected] miljo, Inc.100 Glenborough Drive, 5th FloorHouston, TX 77067


Confined Zone Dispersion Flue GasDesulfurization Demonstration

Participant:Bechtel CorporationContacts:Joseph T. Newman, Project Manager

(415) 768-1189(415) 768-3535 (fax)Bechtel CorporationP.O. Box 193965San Francisco, CA 94119-3965


LIFAC Sorbent Injection DesulfurizationDemonstration Project

Participant:LIFAC-North AmericaContacts:Darryl Brogan

(412) 497-2144(412) 497-2212 (fax)Kaiser Engineers, Inc.Gateway View Plaza1600 West Carson StreetPittsburgh, PA 15219-1031


D-2 Project Fact Sheets 2001

Advanced Flue Gas Desulfurization DemonstrationProject

Participant:Pure Air on the Lake, L.P.Contacts:Tim Roth

(610) 481-6257(610) 706-7018 (fax)[email protected] Air on the Lake, L.P.c/o Air Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501


Demonstration of Innovative Applications ofTechnology for the CT-121 FGD Process

Participant:Southern Company Services, Inc.Contacts:David P. Burford, Project Manager

(205) 257-6329(205) 257-7161 (fax)[email protected] CompanyP.O. Box 2641 / bin no. 13N-8060Birmingham, AL 35291



Demonstration of Coal Reburning for CycloneBoiler NOx Control

Participant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)[email protected] Technology, Inc.1562 Beeson StreetAlliance, OH 44601

John C. McDowell, NETL, (412) [email protected]

Full-Scale Demonstration of Low-NOx Cell BurnerRetrofit




Evaluation of Gas Reburning and Low-NOxBurners on a Wall-Fired Boiler

Participant:Energy and Environmental Research CorporationContacts:Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140(949) 859-3194 (fax)[email protected] Energy and Environmental ResearchCorporation18 MasonIrvine, CA 92618

Jerry L. Hebb, NETL, (412) [email protected]

Micronized Coal Reburning Demonstration forNOx Control

Participant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)[email protected] York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224



Demonstration of Selective Catalytic ReductionTechnology for the Control of NOx Emissions fromHigh-Sulfur, Coal-Fired Boilers

Participant:Southern Company Services, Inc.Contacts:Larry Monroe

(205) 257-7772(205) 257-5367 (fax)[email protected] Company Services, Inc.Mail Stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195


Demonstration of Advanced CombustionTechniques for a Wall-Fired Boiler

Participant:Southern Company Services, Inc.Contacts:John N. Sorge, Research Engineer


James R. Longanbach, NETL, (304) [email protected]

180-MWe Demonstration of AdvancedTangentially Fired Combustion Techniques for theReduction of NOx Emissions from Coal-FiredBoilers

Participant:Southern Company Services, Inc.Contacts:Larry Monroe



Combined SO2 /NOx Control Technologies

SNOX™ Flue Gas Cleaning DemonstrationProject

Participant:ABB Environmental SystemsContacts:Paul Yosick, Project Manager

(865) 694-5300 (fax)(865) 694-5213 (fax)Alstom Power, Inc.1409 Center Point BoulevardKnoxville, TN 37932


LIMB Demonstration Project Extension andCoolside Demonstration

Participant:The Babcock & Wilcox CompanyContacts:Paul Nolan

(330) 860-1074(330) 860-2045 (fax)[email protected] Babcock & Wilcox Company20 South Van Buren AvenueP.O. Box 351Barberton, OH 44203-0351


SOx-NOx-Rox Box™ Flue Gas CleanupDemonstration Project





Enhancing the Use of Coals by Gas Reburning andSorbent Injection

Participant:Energy and Environmental Research CorporationContacts:Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140(949) 859-3194 (fax)[email protected] Electric Energy and EnvironmentalResearch Corporation18 MasonIrvine, CA 92618


Milliken Clean Coal Technology DemonstrationProject

Participant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)[email protected] York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224


Integrated Dry NOx/SO2 Emissions Control System

Participant:Public Service Company of ColoradoContacts:Terry Hunt, Production Engineer

(720) 497-2129(720) 497-2122 (fax)[email protected] Energy4653 Table Mountain DriveGolden, CO 80403


CCT Program AdvancedElectric Power Generation


McIntosh Unit 4A PCFB Demonstration Project

Participant:City of Lakeland, Lakeland ElectricContacts:Alfred M. Dodd, Project Director

(863) 834-6461(863) 834-6488 (fax)[email protected] Electric501 E. Lemon StreetLakeland, FL 33801-5079


Donald L. Bonk, NETL, (304) [email protected]


McIntosh Unit 4B Topped PCFB DemonstrationProject

Participant:City of Lakeland, Lakeland ElectricContacts:Alfred M. Dodd, Project Director

(863) 834-6461(863) 834-6488 (fax)[email protected] Electric501 E. Lemon StreetLakeland, FL 33801-5079


Donald L. Bonk, NETL, (304) [email protected]

JEA Large-Scale CFB Combustion DemonstrationProject

Participant:JEAContacts:Joey Duncan

(904) 714-4831(904) 714-4895 (fax)JEA4377 Heckscher Drive, NSRPCOJacksonville, FL 32226



Tidd PFBC Demonstration Project

Participant:American Electric Power Service CorporationContacts:Michael J. Mudd

(614) 223-1585(614) 223-1292 (fax)[email protected] Electric Power1 Riverside PlazaColumbus, OH 43215


Donald W. Geiling, NETL, (304) [email protected]

Nucla CFB Demonstration Project

Participant: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


Thomas Sarkus, NETL (412) [email protected]


Kentucky Pioneer IGCC Demonstration Project

Participant:Kentucky Pioneer Energy, LLCContacts:H. H. Graves, President

(513) 621-0077(513) 621-5947 (fax)[email protected] Pioneer Energy, LLC312 Walnut Street, Suite 2000Cincinnati, OH 45202



Piñon Pine IGCC Power Project

Participant:Sierra Pacific Power CompanyContacts:Jeffrey W. Hill, Director, Power Generation

(775) 834-5890(775) 834-4569 (fax)[email protected] Pacific Power CompanyP.O. Box 10100Reno, NV 89520-0024



Web Site:www.sierrapacific.com/utilserv/electric/pinon/


Tampa Electric Integrated Gasification Combined-Cycle Project

Participant: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



Web Site:www.teco.net/teco/TEKPlkPwrStn.html

Wabash River Coal Gasification RepoweringProject

Participant:Wabash River Coal Gasification Repowering ProjectJoint VentureContacts:Phil Amick, VP for Commercial Development

(713) 374-7252(713) 374-7278 (fax)[email protected] Energy, Inc.1000 Louisiana St., Suite 3800Houston, TX 77002


Leo E. Makovsky, NETL, (412) [email protected]


Healy Clean Coal Project

Participant:Alaska Industrial Development and Export AuthorityContacts:Arthur E. Copoulos, Project Manager II

(907) 269-3029(907) 269-3044 (fax)[email protected] Industrial Development and Export Authority801 West Northern Lights BoulevardAnchorage, AK 99503


Robert M. Kornosky, NETL, (412) [email protected]

Clean Coal Diesel Demonstration Project

Participant: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



CCT Program CoalProcessing for Clean Fuels

Indirect Liquefaction

Commercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOH™) Process

Participant:Air Products Liquid Phase Conversion Company, L.P.Contacts:Edward C. Heydorn, Project Manager

(610) 481-7099(610) 481-2247 (fax)[email protected] Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501

Edward Schmetz, DOE/HQ, (301) [email protected]

Robert M. Kornosky, NETL, (412) [email protected]


Coal Preparation Technologies

Development of the Coal Quality Expert™

Participants: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) [email protected]

Joseph B. Renk III, NETL, (412) [email protected]

Mild Gasification

ENCOAL® Mild Coal Gasification Project

Participant:ENCOAL CorporationContacts:Jim Mahler

(858) 551-1090(858) 551-0247 (fax)[email protected] International1200 Prospect, Suite 325La Jolla, CA 92037


Douglas M. Jewell, NETL, (304) [email protected]

Advanced Coal Conversion Process Demonstration

Participant: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


Joseph B. Renk III, NETL, (412) [email protected]

CCT Program IndustrialApplicationsBlast Furnace Granular-Coal Injection SystemDemonstration Project

Participant:Bethlehem Steel CorporationContacts:Robert W. Bouman, Manager

(610) 694-6792(610) 694-2981 (fax)Bethlehem Steel CorporationBuilding C, Room 211Homer Research LaboratoryMountain Top CampusBethlehem, PA 18016




Clean Power from Integrated Coal/Ore Reduction(CPICOR™)

Participant:CPICOR™ Management Company, LLCContacts:Les Jones

(801) 227-9273(801) 227-9198 (fax)[email protected]™ Management Company, LLCP.O. Box 2500Provo, UT 84603

William E. Fernald, DOE/HQ, (301) [email protected]

Douglas M. Jewell, NETL, (304) [email protected]

Advanced Cyclone Combustor with InternalSulfur, Nitrogen, and Ash Control

Participant:Coal Tech CorporationContacts:Bert Zauderer, President

(610) 667-0442(610) 667-0576 (fax)[email protected] Tech CorporationP.O. Box 154Merion Station, PA 19066



Cement Kiln Flue Gas Recovery Scrubber

Participant:Passamaquoddy TribeContacts:Thomas N. Tureen, Project Manager

(207) 773-7166(207) 773-8832 (fax)[email protected] Technology, L.P.1 Monument Way, Suite 200Portland, ME 04101



Pulse Combustor Design Qualification Test

Participant:ThermoChem, Inc.Contacts:Lee Rockvam, Project Manager

(410) 354-9890, ext. 43(410) 354-9894 (fax)[email protected], Inc.6001 Chemical RoadBaltimore, MD 21226



PPII ProjectsCombustion Initiative for Innovative Cost-Effective NOx Reduction

Participant:Alliant Energy Corporate Services, Inc.Contacts:Gary Walling

(608) 250-6802(608) 250-6832 (fax)Alliant Energy Corporate Services, Inc.222 West Washington AvenueMadison, WI 53701

Soung-Sik S. Kim, NETL, (412) [email protected]

Development of Hybrid FLGR/SNCR AdvancedNOx Control for Orion Avon Lake 9

Participant:Arthur D. Little, Inc.Contacts:Howard B. Mason

(408) 517-1570(408) 517-1551 (fax)[email protected] D. Little, Inc.20 Acorn ParkCambridge, MA 02140

James R. Longanbach, NETL, (304) [email protected]


Greenidge Multi-Pollutant Control Project

Participant:CONSOL, Inc.Contacts:Bob Statnick, Project Manager

(412) 854-6758(412) [email protected] Energy, Inc.4000 Brownsville RoadSouth Park, PA 15129-9566

Ronald L. Heavner, NETL (412) [email protected]

Achieving NSPS Emission Standards ThroughIntegration of Low-NOx Burners with anOptimization Plan for Boiler Combustion

Participant:Sunflower Electric Power CorporationContacts:Wayne F. Penrod

(785) 628-2845(785) 623-3395 (fax)Sunflower Electric Power Corporation301 West 13th StreetHays, KS 67601


Demonstration of a Full-Scale Retrofit of theAdvanced Hybrid Particulate Collector

Participant:Otter Tail Power CompanyContacts:Bill Swanson

(605) 862-6300(605) 862-8539 (fax)[email protected] Tail Power Company48450 144th StreetBig Stone City, SD 57216

John M. Rockey, NETL, (304) [email protected]

Polk Power Station Improvements

Participant:Tampa Electric CompanyContacts:Ronald L. Boehm, Manager

(813) 641-5214(813) 641-5281 (fax)[email protected] EnergyP.O. Box 111Tampa, FL 33601


Big Bend Power Station Neural Network-Sootblower Optimization

Participant:Tampa Electric CompanyContacts:Ronald L. Boehm, Manager

(813) 641-5214(813) 641-5281 (fax)[email protected] EnergyP.O. Box 111Tampa, FL 33601


Commercial Demonstration of the ManufacturedAggregate Processing Technology Utilizing SprayDryer Ash

Participant:Universal Aggregates, LLCContacts:Roy O. Scandrol

(412) 854-6643(412) 854-6521 (fax)[email protected] Aggregates, LLCSuite 3004000 Brownsville RoadP.O. Box 300South Park, PA 15129


Web Site:www.universalaggregates.com


Program Update 2001 E-1

Appendix E. Acronyms, Abbreviations, andSymbols¢ cent°C degrees Celsius°F degrees Fahrenheit$ dollars (U.S.)$/kw dollars per kilowatt$/ton dollars per ton% percent® registered trademark� 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

combustionAFGD advanced flue gas desulfurizationAIDEA Alaska Industrial Development and

Export AuthorityAOFA advanced overfire airAPEC Asia Pacific Economic CooperationAPF advanced particulate filterARIL Advanced Retractable Injection

LancesASME American Society of Mechanical

EngineersAss�n. 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 kilowatt-

hourB&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)2�MgO dolomitic hydrated limeCa/N calcium-to-nitrogenCAPI Clean Air Power InitiativeCa/S calcium-to-sulfurCaSO3 calcium sulfiteCaSO4 calcium sulfateCCOFA close-coupled overfire airCCT clean coal technologyCCTDP Clean Coal Technology

Demonstration ProgramCCT 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 Compact disk-read only memoryCDL® Coal-Derived Liquid®

CenPEEP Center for Power Efficiency andEnvironmental Protection

CEQ Council on Environmental QualityCFB circulating fluidized-bedCFD Computational Fluid DynamicC/H carbon-to-hydrogenCKD cement kiln dustCO carbon monoxideCO2 carbon dioxideCOP Conference of PartiesCT-121 Chiyoda Thoroughbred-121CQE� Coal Quality Expert�CQIM� Coal Quality Impact Model�CX categorical exclusionCZD confined zone dispersionDER discrete emissions reductionDME dimethyl etherDOE U.S. Department of EnergyDOE/HQ U.S. Department of Energy

HeadquartersDSE dust stabilization enhancementDSI dry sorbent injectionEA environmental assessmentEER Energy and Environmental Research

CorporationEERC Energy and Environmental Research

Center, University of North DakotaEFCC externally fired combined-cycle

E-2 Program Update 2001

EIA Energy Information AdministrationEIS environmental impact statementEIV Environmental Information VolumeEMP environmental monitoring planEPA U.S. Environmental Protection

AgencyEPAct Energy Policy Act of 1992EPDC Japan’s Electric Power Development

CompanyEPRI Electric Power Research InstituteESP electrostatic precipitatorEWG exempt wholesale generatorext. extensionFBC fluidized-bed combustionFCCC Framework Convention on Climate

ChangeFE Office of Fossil EnergyFeO iron oxideFe2S pyritic sulfurFERC Federal Energy Regulatory

CommissionFETC 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 feetFY fiscal yeargal. gallon(s)gal/ft3 gallons per cubic footGB gigabyte(s)GE General ElectricGHG greenhouse gasesGNOCIS Generic NOx Control Intelligent

Systemgpm 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 hydrogenH2S hydrogen sulfideH2SO4 sulfuric acidHAP 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 combined-

cycleIGFC 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 limestone injection multistageburner

LNB low-NOx burnerLNCB® low-NOx cell burnerLNCFS Low-NOx Concentric-Firing SystemLOI loss-on-ignitionLPMEOH™ Liquid phase methanolLRCWF low-rank coal-water-fuelLSDE Laboratorium Sumderdaya EnergiLSFO limestone forced oxidationMASB multi-annular swirl burnerMB megabyte(s)MCFC molten carbonate fuel cellMCR Maximum Continuous RatingMDEA methyldiethanolamineMgCO3 magnesium carbonateMgO magnesium oxideMHz megahertzmills/kWh mills per kilowatt hourmin. minute(s)mo. month(s)MSW municipal solid wasteMTCI Manufacturing and Technology

Conversion InternationalMTF memorandum (memoranda)-to-fileMW megawatt(s)MWe megawatt(s)-electricMWt megawatt(s)-thermalN elemental nitrogenN2 molecular nitrogenn.d. not datedN/A not applicableNa/Ca sodium-to-calciumNa2/S sodium-to-sulfurNaOH sodium hydroxideNa2CO3 sodium carbonate

Program Update 2001 E-3

NAAQS National Ambient Air QualityStandards

NEDO New Energy DevelopmentOrganization

NEPA National Environmental Policy ActNETL National Energy Technology

Laboratory (formerly FETC)NH3 ammoniaNm3 Normal cubic meterNO2 nitrogen dioxideNOPR Notice of Proposed RulemakingNOx nitrogen oxidesNSPS New Source Performance StandardsNSR normalized stoichiometric ratioNTHM net tons of hot metalNTIS National Technical Information

ServiceNTPC National Thermal Power CorporationNYSEG New York State Electric & Gas

CorporationO 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 TechnologyPCFB pressurized circulating fluidized-bedPDF® Process-Derived Fuel®

PEIA programmatic environmental impactassessment

PEIS programmatic environmental impactstatement

PEOATM Plant Emission OptimizationAdvisorTM

PENELEC Pennsylvania Electric CompanyPEP progress evaluation planPFBC pressurized fluidized-bed

combustionPJBH pulse jet baghousePM particulate matterPM10 particulate matter less than 10

microns in diameterPM2.5 particulate matter less than 2.5

microns in diameterPON program opportunity noticePRB Powder River Basinppm parts per million (mass)ppmv parts per million by volumePSCC Public Service Company of ColoradoPSD Prevention of Significant

Deteriorationpsi pound(s) per square inchpsia pound(s) per square inch absolutepsig pound(s) per square inch gaugePUHCA Public Utility Holding Company Act

of 1935PURPA Public Utility Regulatory Policies

Act of 1978QF qualifying facilityRAM random access memoryR&D research and developmentRD&D research, development, and

demonstrationRDF refuse derived fuelREA Rural Electrification AdministrationRP&L Richmond Power & LightROD Record of Decision

ROM run-of-minerpm revolutions per minuteRUS Rural Utility ServiceS sulfurSBIR Small Business Innovation Researchscf standard cubic feetscfm standard cubic feet per minuteSCR selective catalytic reductionSCS Southern Company Services, Inc.SDA spray dryer absorberSFC Synthetic Fuels CorporationS-H-U Saarberg-Hölter-UmwelttechnikSI sorbent injectionSIP state implementation planSM service markSNCR selective noncatalytic reductionSNRB™ SOx-NOx-Rox Box™SO2 sulfur dioxideSO3 sulfur trioxidestd ft3 standard cubic feetSOFA separated overfire airSTTR Small Business Technology Transfer

ProgramSVGA super video graphics adapterTAG™ Technical Assessment Guide™TCLP toxicity characteristics leaching

procedureTVA Tennessee Valley AuthorityUAF University of Alaska, FairbanksUARG Utility Air Regulatory GroupUBCL unburned carbon lossesU.K. United KingdomUNESCO United Nations Educational,

Scientific and Cultural OrganizationURL Uniform Resource Locator

E-4 Program Update 2001

U.S. United StatesUSAID U.S. Agency for International

DevelopmentV·I voltage current productVFB vibrating fluidized bedVOC volatile organic compoundw.c. water columnWDNR Wisconsin Department of Natural

ResourcesWES 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 LouisianaMA 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 VirginiaWY Wyoming

OtherSome companies have adopted an acronym as theircorporate names. The following corporate namesreflect the former name of the company.

BG/L British Gas LurgiJEA Jacksonville Electric AuthorityKRW Kellogg Rust Westinghouse

Program Update 2001 Index-1

Index of CCT Projects and ParticipantsSymbols

10-MWe Demonstration of Gas SuspensionAbsorption 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 TangentiallyFired Combustion Techniques for the Reductionof NOx Emissions from Coal-Fired BiolersES-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

A

ABB 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 Low-NOx Burners with an Optimization Plan for BoilerCombustion ES-25, 6-4, 6-5, 6-6, 6-16, D-9

Advanced Coal Conversion ProcessDemonstration 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 DemonstrationProject 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 UtilityDemonstration 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 ExportAuthority 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-BedRepowering Project B-3

B

Babcock & 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 ES-8, ES-12, ES-22, 2-7,4-5, 4-6, 5-15, 5-17, 5-26, 5-29, 5-122, B-3,B-4, C-3, C-8, D-1

Bechtel Development Company B-2Bethlehem Steel Corporation ES-20, ES-23, 2-7,

4-12, 4-14, 5-16, 5-17, 5-158, B-2, B-3,B-4, B-6, C-3, C-4, C-8, D-7

Big Bend Power Station Neural Network-SootblowerOptimization ES-25, 6-4, 6-5, 6-6, 6-20, D-9

Blast Furnace Granular-Coal Injection SystemDemonstration Project ES-20, ES-23, 2-7,3-9, 4-14, 5-13, 5-16, 5-17, 5-158, B-3, B-6,C-4, C-8, D-7

C

Calvert City Advanced Energy Project B-4Camden Clean Energy Demonstration Project B-4Cement Kiln Flue Gas Recovery Scrubber

ES-20, ES-23, 3-9, 4-14, 5-13, 5-16, 5-18,5-166, B-2, B-4, C-4, C-7, D-8

Centerior Energy Corporation 5-52Clean Coal Combined-Cycle Project B-4Clean Coal Diesel Demonstration Project ES-23,

2-7, 2-12, 3-9, 4-12, 5-10, 5-16, 5-17,5-132, B-4, B-5, C-4, C-8, C-9, D-6

Clean Energy IGCC Demonstration Project B-2, B-4Clean Energy Partners Limited Partnership

5-117, B-4Clean Power Cogeneration Limited Partnership B-3Clean Power from Integrated Coal/Ore Reduction

(CPICOR�) ES-23, 2-7, 2-12, 3-9, 5-13,5-16, 5-17, 5-156, B-4, B-5, C-5, C-8, C-9,D-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 TechnologyDemonstration B-2

Colorado-Ute Electric Association, Inc. 5-113,B-2, B-3, C-3, C-7

Combustion Engineering IGCC RepoweringProject 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-8Commercial 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/NOxRemoval Flue Gas Cleanup System B-3,B-4, B-6, C-4

Commercial-Scale Demonsatration of the Liquid PhaseMethanol (LPMEOH™) 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 GasDesulfurization 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-2CPICOR™ 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-4

D

Dairyland 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 Techniquesfor 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 EastonUtilities B-4

Demonstration of Coal Reburning for Cyclone BoilerNOx 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 ofTechnology 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 ReductionTechnology 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 CANSOLV™System at the Alcoa Generating corporationWarrick Power Plant B-4

Development of Hybrid FLGR/SNCR/SCR AdvancedNOx Control for Orion Avon Lake Unit 9ES-25, 6-4, 6-5, 6-6, 6-10, D-8

Development of the Coal Quality Expert™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 Reduction to Replace Coke Oven/Blast Furnace for Steelmaking B-2

DMEC-1 Limited Partnership B-3, B-5Duke Energy Corporation B-4

E

Eastman Kodak Company 5-60, 5-62, B-5ENCOAL Corporation ES-18, ES-19, ES-23, 2-7,

4-12, 4-13, 5-16, 5-17, 5-146, B-3, B-5,C-4, C-8, C-9, D-7

ENCOAL® Mild Coal Gasification ProjectES-18, ES-19, ES-23, 2-7, 3-9, 4-13, 5-12,5-16, 5-17, 5-146, B-3, B-5, C-4, C-8, C-9,D-7

Energy and Environmental ResearchCorporation ES-9, ES-10, ES-12, ES-13,ES-22, ES-24, 2-6, 2-7, 4-5, 4-7, 4-8, 4-9,4-15, 5-15, 5-17, 5-56, 5-58, 5-59, 5-60,5-86, B-1, B-3, B-5, B-6, C-3, C-4, C-7,C-8, D-2, D-4, E-1

Energy International, Inc. B-2Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection ES-10, ES-13, ES-22,ES-24, 2-6, 3-8, 4-9, 4-15, 5-7, 5-15, 5-17,5-86, B-1, B-5, B-6, C-1, C-3, C-4, C-7, D-4

Evaluation of Gas Reburning and Low-NOx Burnerson a Wall-Fired Boiler ES-2, ES-9, ES-12,ES-13, ES-22, ES-24, 2-7, 3-8, 4-1, 4-7, 4-9,4-15, 4-17, 5-6, 5-15, 5-17, 5-56, B-3, B-6,C-3, C-8, D-2

F

Foster Wheeler Power Systems, Inc. 4-5, 4-7,4-10, 4-11, 5-44, 5-56, 5-58, B-2

Four Rivers Energy Modernization Project5-103, B-4

Four Rivers Energy Partners, L.P. 5-103, B-4, B-5

Program Update 2001 Index-3

Full-Scale Demonstration of Low-NOx Cell BurnerRetrofit 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

G

General Electric Company B-2Greenidge Multi-Pollutant Control Project ES-25,

6-4, 6-5, 6-6, 6-12, D-9

H

Healy 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

I

Innovative Coke Oven Gas Cleaning System forRetrofit B-2, B-4, C-3, C-4

Integrated Coal Gasification Steam Injection GasTurbine Demonstration Plants with Hot GasCleanup B-2

Integrated Dry NOx/SO2 Emissions ControlSystem 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

J

JEA 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 DemonstrationProject 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

K

Kentucky Pioneer Energy IGCC DemonstrationProject 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

L

Lakeland, 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 DesulfurizationDemonstration 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 CoolsideDemonstration 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 DemonstrationProject B-3

M

M.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 DemonstrationProject 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 NOxControl 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 DemonstrationProject 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 Department of Natural Resource B-2MK-Ferguson Company B-3

N

New York State Electric & Gas CorporationES-9, ES-10, ES-12, ES-13, ES-22, 1-3, 2-7,4-7, 4-8, 4-9, 5-15, 5-17, 5-18, 5-26, 5-60,5-63, 5-90, 5-93, B-3, B-4, B-5, B-6, C-4,C-8, C-9, D-2, D-4, E-3

Nichols CFB Repowering Project B-3NOXSO Corporation B-3, B-4, B-6, C-4Nucla CFB Demonstration Project ES-14,

ES-16, ES-23, 2-6, 4-11, 5-10, 5-16, 5-18,5-110, B-2, B-3, C-3, C-7, D-5

O

Ohio Ontario Clean Fuels, Inc. B-2, B-3Ohio Power Company, The ES-14, ES-16,

ES-23, ES-24, 2-4, 2-6, 4-10, 4-11, 4-15,5-16, 5-18, 5-106, B-1, B-5, C-3, C-7, C-9

Otisca Fuel Demonstration Project B-3Otisca Industries, Ltd. B-3Otter Tail Power Company ES-25, 6-4, 6-5, 6-6,

6-14, D-9

P

Passamaquoddy Tribe ES-20, ES-23, 2-6, 4-14,5-16, 5-18, 5-166, B-2, B-4, C-4, C-7, D-8

Pennsylvania Electric Company 5-26, 5-29, B-4,B-5, C-3, C-4, E-3

PFBC Utility Demonstration Project B-2, B-5Piñon Pine IGCC Power Project ES-1, ES-2,

ES-14, ES-23, 2-7, 3-9, 4-1, 4-10, 4-11,5-10, 5-16, 5-18, 5-122, B-4, B-6, C-5, C-8,C-9, D-5

Index-4 Program Update 2001

Polk Power Station Plant Improvement ProjectES-25, 6-4, 6-5, 6-6, 6-18, D-9

Postcombustion Sorbent Injection DemonstrationProject B-2

Prototype Commercial Coal/Oil CoprocessingProject 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 TestES-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

S

Self-Scrubbing Coal™: An Integrated Approach toClean 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

SNOX™ Flue Gas Cleaning DemonstrationProject 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 Box™ Flue Gas DemonstrationProject 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

T

Tallahassee, 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 Combined-Cycle 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-4Tri-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

U

Underground Coal Gasification DemonstrationProject B-2

Union Carbide Chemicals and Plastics CompanyInc. B-4

United Coal Company B-2Universal Aggregates, LLC ES-25, 6-4, 6-5,

6-6, 6-22, D-9

W

Wabash River Coal Gasification Repowering JointVenture ES-15, ES-16, ES-23, ES-24, 2-7,4-11, 4-15, 5-16, 5-18, 5-126, B-3, B-6,C-4, C-8, C-9, D-6

Wabash River Coal Gasification RepoweringProject ES-2, ES-15, ES-16, ES-23, ES-24,1-6, 2-7, 3-9, 3-10, 4-1, 4-10, 4-11, 4-15,4-17, 5-10, 5-16, 5-18, 5-126, 5-128, 5-129,B-3, B-6, C-4, C-8, C-9, C-10, D-6

Warren Station Externally Fired Combined-CycleDemonstration B-4, B-5, C-3, C-4

Weirton Steel Corporation B-2Western Energy Company 5-150, 5-152, B-2, B-3Western SynCoal LLC ES-18, ES-19, ES-23,

2-6, 4-12, 4-13, 5-9, 5-16, 5-18, 5-150, B-2,B-3, B-6, C-4, C-7, D-7

Y

York County Energy Partners CogenerationProject B-3, C-5

York County Energy Partners, L.P. 5-105, B-3,B-5, C-5

Contents

Executive Summary






SO2 Control Technologies Fact Sheets

NOx Control Technologies Fact Sheets

Combined SO2/NOx Control Technologies Fact Sheets

Fluidized-Bed Combustion Fact Sheets

Integrated Gasification Combined-Cycle Fact Sheets

Advanced Combustion/Heat Engines Fact Sheets

Coal Processing for Clean Fuels Fact Sheets

Industrial Applications Fact Sheets


Appendix A. Historical Perspective and Legislative History


Appendix C. CCT Program Environmental Aspects


Appendix E. Acronyms, Abbreviations, and Symbols

Index of CCT Projects and Participants

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