Clean Coal Clean Coal Clean Coal Technology echnologyechnology echnologyechnology

Demonstration Pr Demonstration Pr Demonstration Program

Program Update 2000 ogram Update 2000 ogram Update 2000

As of September 2000 As of September 2000

U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

April 2001 April 2001April 2001 April 2001April 2001
U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

Clean Coal Clean Coal Clean Coal Technology echnologyechnology echnologyechnology

Demonstration Pr Demonstration Pr Demonstration ProgramProgram Update 2000 ogram Update 2000 ogram Update 2000

As of September 2000 As of September 2000

April 2001 April 2001April 2001 April 2001April 2001
This report has been reproduced directly from the best available copy.

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

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Victor K. DerProduct Line DirectorPower SystemsU.S. Department of EnergyMail Stop FE-22 GTN19901 Germantown RoadGermantown, MD 20874-1290(301) 903-2700

DPFUM1G(

Comments, corrections, or contributive information may be directed to: Comments, corrections, or contributive information may be directed to:

Program Update and Program Fact Sheetsc/o Gene H. KightSr. Financial & Procurement DirectorU.S. Department of EnergyMail Stop FE-20 GTN19901 Germantown RoadGermantown, MD 20874-1290(301) 903-2624(301) 903-9301 (fax)gene.kight@hq.doe.gov

David J. BeecyProduct Line DirectorEnvironmental SystemsU.S. Department of EnergyMail Stop FE-23 GTN19901 Germantown RoadGermantown, MD 20874-1290(301) 903-2787
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Executive Summary 012345Section 1: Role of the CCT Program 012345Section 2: Program Implementation 012345Section 3: Funding and Costs 012345Section 4: CCT Program Accomplishments 012345Section 5: CCT Projects 012345Appendix A: Historical Perspective and Legislative History 012345Appendix B: Program History 012345Appendix C: Environmental Aspects 012345Appendix D: CCT Project Contacts 012345Appendix E: Acronyms, Abbreviations, and Symbols 012345What do you find is the best and most effective part of the Program Update?

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Contents ContentsContents ContentsContents

Executive Summary: The CCTProgram Update 2000

Introduction ES-1Role of the CCT Program ES-2Program Implementation ES-4Funding and Costs ES-5CCT Program Accomplishments ES-6CCT Projects ES-20Benefits Legacy ES-24Introduction 1-1CCT Program Evolution 1-2Environmental Impetus 1-3

SO2 Regulation 1-3NO

x Regulation 1-4

Hazardous Air Pollutants 1-6Global Climate Change 1-7Regional Haze 1-7Solid Waste 1-7Toxics Release Inventory 1-8

Market Considerations 1-8Ensuring Sustainable Economic Growth 1-9Looking to the Future 1-10

Power Plant Improvement Initiative 1-10Vision 21 1-11

Introduction 2-1Implementation Principles 2-1Implementation Process 2-2Commitment to Commercial Realization 2-4Solicitation Results 2-5

Section 1: Role of the CCT ProgramSection 2: Program Implementation
ii Program Update 2000

Future Implementation Direction 2-12Introduction 3-1Program Funding 3-1

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

Cost-Sharing 3-4Recovery of Government Outlays (Recoupment) 3-10Introduction 4-1Marketplace Commitment 4-1

Factors Impacting Domestic Commercialization 4-2Environmental Control Devices 4-2Advanced Electric Power Generation 4-5Coal Processing for Clean Fuels 4-9Industrial Applications 4-12Awards 4-12

Market Communications—Outreach 4-14

Information Sources 4-14Publications Issued in FY2000 4-15Information Access 4-16Information Dissemination and Feedback 4-16Conferences and Workshops Held in FY2000 4-16Trade Mission Activities in FY2000 4-18

Introduction 5-1Technology Overview 5-2

Environmental Control Devices 5-2Advanced Electric Power Generation Technology 5-5

Section 3: Funding and CostsSection 4: CCT Program Accomplishments

Section 5: CCT Projects
Coal Processing for Clean Fuels Technology 5-9Industrial Applications Technology 5-11

Project Fact Sheets 5-13

Environmental Control Devices 5-21

SO2 Control Technologies 5-21NO

x Control Technologies 5-43

Combined SO2/NOx Control Technologies 5-73

Advanced Electric Power Generation 5-99

Fluidized-Bed Combustion 5-99Integrated Gasification Combined-Cycle 5-115Advanced Combustion/Heat Engines 5-127

Coal Processing for Clean Fuels 5-135Industrial Applications 5-149

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

Categorical Exclusions C-2Memoranda-to-File C-2Environmental Assessments C-2Environmental Impact Statements C-5NEPA Actions in Progress C-5

Environmental Monitoring C-6Air Toxics C-6

Section 5: CCT Projects (continued)

Appendix A: Historical Perspective andLegislative History

Appendix B: Program History

Appendix C: Environmental Aspects
iv Program Update 2000

Project Contacts D-1Environmental Control Devices D-1Advanced Electric Power Generation D-4Coal Processing for Clean Fuels D-6Industrial Applications D-7Acronyms, Abbreviations, and Symbols E-1State Abbreviations E-4Other E-4Index Index-1

Appendix E: Acronyms, Abbreviations,and SymbolsIndex of CCT Projects and ParticipantsAppendix D: CCT Project Contacts
Exhibits ExhibitsExhibits ExhibitsExhibits

Completed Projects by Application Category ES-6Summary of Results of Completed Environmental Control Technology Projects ECommercial Successes—Environmental Control Technologies ES-11Summary of Results of Completed Advanced Electric Power Generation Projects Commercial Successes—Advanced Electric Power Generation Technologies ESSummary of Results of Completed Coal Processing for Clean Fuels Projects ES-Commercial Successes—Coal Processing for Clean Fuels Technologies ES-18Summary of Results of Completed Industrial Application Projects ES-19Commercial Successes—Industrial Application Technologies ES-19Project Fact Sheets by Application Category ES-21Award-Winning CCT Projects ES-23Benefits Legacy from CCT Program and Associated RD&D ES-24Phase I SO2 Compliance Methods 1-3CAAA NO

x

 Emission Limits 1-4

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

Section 2: Program ImplementationExecutive Summary: The CCT ProgramUpdate 2000Section 1: Role of the CCT Program

Section 3: Funding and Costs
vi Program Update 2000

CCT Financial Projections as of September 30, 2000 3-4Financial Status of the CCT Program as of September 30, 2000 3-5CCT Project Schedules by Application Category 3-6CCT Project Funding by Application Category 3-8Commercial Successes—SO2 Control Technology 4-4Commercial Successes—NO

x Control Technology 4-6

Commercial Successes—Combined SO2/NOx Control Technology 4-7Commercial Successes—Advanced Electric Power Generation 4-10Commercial Successes—Coal Processing for Clean Fuels 4-11Commercial Successes—Industrial Applications 4-12Award-Winning CCT Projects 4-13How to Obtain CCT Program Information 4-14CCT Program SO2 Control Technology Characteristics 5-3Group 1 and 2 Boiler Statistics and Phase II NOx Emission Limits 5-4CCT Program NOx Control Technology Characteristics 5-6CCT Program Combined SO2/NOx Control Technology Characteristics 5-7CCT Program Advanced Electric Power Generation Technology Characteristics 5CCT Program Coal Processing for Clean Fuels Technology Characteristics 5-12CCT Program Industrial Applications Technology Characteristics 5-14Project Fact Sheets by Application Category 5-15Project Fact Sheets by Participant 5-17Key to Milestone Charts in Fact Sheets 5-19Variables and Levels Used in GSA Factorial Testing 5-24GSA Factorial Testing Results 5-24Pure Air SO2 Removal Performance 5-36Estimated Costs for an AFGD System 5-37Flue Gas Desulfurization Economics 5-37Operation of CT-121 Scrubber 5-40

Section 5: CCT ProjectsSection 4: CCT Program AccomplishmentsSection 3: Funding and Costs (continued)
Section 5: CCT Projects (continued) SO2 Removal Efficiency 5-40

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

x

 vs. LOI Tests—All Sensitivities 5-46

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

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

Reactor Baseline Conditions 5-66Catalysts Tested 5-66Average SO2 Oxidation Rate 5-66SCR Design Criteria 5-67SCR Economics by Unit Size 5-67SCR Economics by NOx Removal 5-67LNCFSTM Configurations 5-70Concentric Firing Concept 5-70Unit Performance Impacts Based on Long-Term Testing 5-71Average Annual NOx Emissions and Percent Reduction 5-71LIMB SO2 Removal Efficiencies 5-80LIMB Capital Cost Comparison 5-81LIMB Annual Levelized Cost Comparison 5-81Effect of Limestone Grind 5-92Pressure Drop vs. Countercurrent Headers 5-92Effect of Bed Temperature on Ca/S Requirement 5-112Calcium Requirements and Sulfur Retentions for Various Fuels 5-113Wabash Thermal Performance Summary 5-125Wabash Fuel Analysis 5-125
viii Program Update 2000

Wabash Product Syngas Analysis 5-125Healy Performance Goals and Combustion System Characterization 5-132Healy SDA Performance Test Results and Performance Guarantees 5-133ENCOAL Production 5-146Summary of Emissions and Removal Efficiencies 5-164CCT Program Legislative History A-4NEPA Reviews Completed as of September 30, 2000 C-1Memoranda-to-File Completed C-3Environmental Assessments Completed as of September 30, 2000 C-4Environmental Impact Statements Completed as of September 30, 2000 C-5NEPA Reviews in Progress as of September 30, 2000 C-5Status of Environmental Monitoring Plans for CCT Projects as of September 30, 2Status of CCT Projects Monitoring Hazardous Air Pollutants as of September 30, 2

Appendix A: Historical Perspective andLegislative HistoryAppendix C: Environmental AspectsSection 5: CCT Projects (continued)
Environmental Control Devices

Project Fact Sheets by oject Fact Sheets by oject Fact Sheets by Application Categ

Application CategApplication Categ

SO2 Control Technologies

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

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

x Control Technologies

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

x Cell Burner Retrofit (The Babcock & Wi

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler

(Energy and Environmental Research Corporation) 5-56

Micronized Coal Reburning Demonstration for NOx Control (New York State ElDemonstration of Selective Catalytic Reduction Technology for the Control of N

Coal-Fired Boilers (Southern Company Services, Inc.) 5-64

180-MWe Demonstration of Advanced Tangentially Fired Combustion TechniquEmissions from Coal-Fired Boilers (Southern Company Services, Inc.) 5-68

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental System

LIMB Demonstration Project Extension and Coolside Demonstration (The BabcSO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstration Project (The Babcock & 

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection(Energy and Environmental Research Corporation) 5-86Milliken Clean Coal Technology Demonstration Project (New York State ElectrIntegrated Dry NOx/SO2 Emissions Control System (Public Service Company of 
x Program Update 2000

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland ElecMcIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, LakelJEA Large-Scale CFB Combustion Demonstration Project (JEA) 5-104Tidd PFBC Demonstration Project (The Ohio Power Company) 5-106Nucla CFB Demonstration Project (Tri-State Generation and Transmission Assoc

Integrated Gasification Combined-Cycle

Kentucky Pioneer IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) Piñon Pine IGCC Power Project (Sierra Pacific Power Company) 5-118Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Wabash River Coal Gasification Repowering Project (Wabash River Coal GasificVenture) 5-122

Advanced Combustion/Heat Engines

Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) 5-128Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) PrPhase Conversion Company, L.P.) 5-136Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) 5-13Development of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc., ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) 5-144Clean Power from Integrated Coal/Ore Reduction (CPICORTM)(CPICORTM Management Company, LLC) 5-150Pulse Combustor Design Qualification Test (ThermoChem, Inc.) 5-152Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (CCement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) 5-162

Advanced Electric Power GenerationCoal Processing for Clean FuelsIndustrial Applications
ABB Combustion Engineering, Inc., and CQ Inc. (Development of the Coal Quality ExpertTM) 5-140ABB Environmental Systems (SNOXTM Flue Gas Cleaning Demonstration Project) 5-74Air Products Liquid Phase Conversion Company, L.P. (Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) PAirPol, Inc. (10-MWe Demonstration of Gas Suspension Absorption) 5-22Alaska Industrial Development and Export Authority (Healy Clean Coal Project) 5-130Arthur D. Little, Inc. (Clean Coal Diesel Demonstration Project) 5-128Babcock & Wilcox Company, The (Demonstration of Coal Reburning for Cyclone Boiler NOx Control) 5-48Babcock & Wilcox Company, The (Full-Scale Demonstration of Low-NOx Cell Burner Retrofit) 5-52Babcock & Wilcox Company, The (LIMB Demonstration Project Extension and Coolside Demonstration) 5-78Babcock & Wilcox Company, The (SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project) 5-82Bechtel Corporation (Confined Zone Dispersion Flue Gas Desulfurization Demonstration) 5-26Bethlehem Steel Corporation (Blast Furnace Granular-Coal Injection System Demonstration Project) 5-154Coal Tech Corporation (Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control) 5-158CPICORTM Management Company, LLC (Clean Power from Integrated Coal/Ore Reduction (CPICORTM) 5-150CQ Inc. (see ABB Combustion Engineering and CQ Inc.)ENCOAL Corporation (ENCOAL® Mild Coal Gasification Project) 5-144Energy and Environmental Research Corporation (Enhancing the Use of Coals by Gas Reburning and Sorbent Injection) 5-86Energy and Environmental Research Corporation (Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler) 5-56JEA (JEA Large-Scale CFB Combustion Demonstration Project) 5-104Kentucky Pioneer Energy, LLC (Kentucky Pioneer IGCC Demonstration Project) 5-116Lakeland, City of, Lakeland Electric (McIntosh Unit 4A PCFB Demonstration Project) 5-100Lakeland, City of, Lakeland Electric (McIntosh Unit 4B Topped PCFB Demonstration Project) 5-102LIFAC-North America (LIFAC Sorbent Injection Desulfurization Demonstration Project) 5-30New York State Electric & Gas Corporation (Micronized Coal Reburning Demonstration for NOx Control) 5-60New York State Electric & Gas Corporation (Milliken Clean Coal Technology Demonstration Project) 5-90Ohio Power Company, The (Tidd PFBC Demonstration Project) 5-106Passamaquoddy Tribe (Cement Kiln Flue Gas Recovery Scrubber) 5-162Public Service Company of Colorado (Integrated Dry NOx /SO2 Emissions Control System) 5-94Pure Air on the Lake, L.P. (Advanced Flue Gas Desulfurization Demonstration Project) 5-34Sierra Pacific Power Company (Piñon Pine IGCC Power Project) 5-118Southern Company Services, Inc. (Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler) 5-44

Project Fact Sheets by Par oject Fact Sheets by Par oject Fact Sheets by Participant ticipantticipant ticipantticipant
xii Program Update 2000

Southern Company Services, Inc. (Demonstration of Innovative Applications of Technology for the CT-121 FGD Process) 5-38Southern Company Services, Inc. (Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from Hig

Boilers) 5-64

Southern Company Services, Inc. (180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction oCoal-Fired Boilers) 5-68Tampa Electric Company (Tampa Electric Integrated Gasification Combined-Cycle Project) 5-120ThermoChem, Inc. (Pulse Combustor Design Qualification Test) 5-152Tri-State Generation and Transmission Association, Inc. (Nucla CFB Demonstration Project) 5-110Wabash River Coal Gasification Repowering Project Joint Venture (Wabash River Coal Gasification Repowering Project) 5-122Western SynCoal LLC (Advanced Coal Conversion Process Demonstration) 5-138
Executive Summar Executive Summar Executive Summary: CCT Program Upd

ogram Updogram Upd

Introduction oductionoduction oductionoduction

CCT Program. ogram. ogram. ogram. ogram. The Clean Coal Technology Demonstration Program (CCT Program), a model of government and industry cooperation, advances the Department of Energy’s (DOE) mission to foster a secure and

reliable energy system that is environmentally andeconomically sustainable. With 26 of the 38 activeprojects having completed operations, the CCTProgram has yielded clean coal technologies (CCTs)that are capable of meeting existing and emergingenvironmental regulations and competing in a deregulated electric power marketplace.The CCT Program is providing a portfolio of technologies that will assure that the U.S. recoverable coalreserves of 274 billion tons can continue to supply thenation’s energy needs economically and in an environmentally sound manner. At the dawn of the 21st

century, many of the clean coal technologies haverealized commercial application. Industry now standsready to respond to the energy and environmentaldemands of the new century, both domestically andinternationally. For existing power plants, there arecost-effective environmental control devices to controlsulfur dioxide (SO2), nitrogen oxides (NOx), andparticulate matter (PM). Also ready are a new generation of technologies that can produce electricity andother commodities, such as steam and synthetic gas,and provide the efficiencies and environmental performance responsive to global climate change. The CCTProgram took a pollution prevention approach as well,demonstrating technologies that produce clean coalbased solid and liquid fuels by removing pollutants or Tampa Electric Integrated 

Project (Tampa Electric Cpresented by Power mag

Tidd PFBC Demonstratiopany)—1991 Powerplant magazine.

their precursors before being burned. Lastly, newtechnologies were introduced into the major coal-usingindustries to enhance environmental performance.Thanks in part to the CCT Program, coal—abundant,secure, and economical—can continue in its role as akey component in the U.S. and world energy markets.Fiscal Year 2000 Major Accomplishments. Accomplishments. Early in

fiscal year 2000, the Wabash River Coal GasificationRepowering Project successfully completed demonstration operations. The final report was issued and theproject was closed out by the end of the year. Beyondthe integration of an advanced integrated gasificationcombined-cycle system with a 1950s vintage pulverized coal-fired plant, the project incorporated otherfeatures that resulted in a 40 percent efficient unit.These include: (1) hot/dry particulate removal toenable gas cleanup without heat loss, (2) integration ofthe gasifier and high-temperature heat recovery steamgenerator to ensure optimum steam conditions for thesteam turbine, (3) use of a carbonyl sulfide hydrolysisprocess to enable high-percentage sulfur removal, (4)recycle of slag fines for additional carbon recovery, (5)use of 95 percent pure oxygen to lower power requirements for the oxygen plant, and (6) fuel gas moisturization to reduce steam injection requirements for NOx

control.The Healy Clean Coal Project successfully completeddemonstration operations early in fiscal year 2000. Theproject was the first utility-scale demonstration of theTRW advanced entrained (slagging) combustor. Theproject eclipsed extremely strict environmentaloperating permit emission limits, which were requiredbecause of the project’s proximity to the environmentally sensitive Denali National Park and Preserve, withtypical emissions of 30 percent, 56 percent, and 77
ES-2 Program Update 2000

Demonstration of Innovative Applications of Technology forthe CT-121 FGD Process Project (Southern CompanyServices, Inc.)—1994 Powerplant Award presented by Powermagazine.tion Combined-Cycle Project and the Blast FurnaceGranular Coal Injection System Demonstration Project.Also, DOE continued coverage of the program bypublishing the Clean Coal Technology Demonstration

Program: Program Update 1999, and the mid-year

update of project fact sheets, Clean Coal Technology

Demonstration Program: Project Fact Sheets 2000.

In fiscal year 2000, the cooperative agreements for twodemonstration projects expired—NOXSOCorporation’s Commercial Demonstration of theNOXSO SO2/NOx Removal Flue Gas Cleanup Systemand Custom Coals International’s Self-ScrubbingCoal

TM: An Integrated Approach—and are not discussed

herein.These accomplishments and more are described infurther detail in this Clean Coal Technology Demonstration Program: Program Update 2000. In sum, theCCT Program is continuing to yield advances in coaltechnologies and thus ensures that the nation’s mostabundant fossil energy resource will serve the energyneeds of the United States while satisfying nationalenvironmental objectives.

Role of the C

CCT Program Evolutiopercent of the proven foUnited States and supplireliable electricity vital tglobal competitiveness. nation’s electricity was pprojections by the U.S. E(EIA) predict that coal welectric power productiothe 21st century. Howev

coal resources in an envimanner.The CCT Program was ecommercial feasibility odemand for a new genertechnologies characterizeconomic, and environmsolicitation (CCT-I) for broad range of projects bproduct markets—enviroadvanced electric power for clean fuels, and induThe second solicitation (piece for satisfying the rthe Joint Report of the S(1986). The goal was to could achieve significanprecursors of acid rain, nthird solicitation (CCT-III and added technologiefrom run-of-mine coal.The fourth and fifth solirespectively) recognized mental issues, such as gl

percent below permit emission limits for NOx (0.350 lb/106 Btu), SO2 (0.086 lb/106 Btu), and PM (0.02 lb/106Btu), respectively. The project is now in the reportingphase.Final reports were issued and the following projectsclosed out:

• Micronized Coal Reburning Demonstration for NOx

Control,

• Milliken Clean Coal Technology Demonstration

Project,

• Integrated Dry NOx/SO2 Emissions Control System,

and

• Blast Furnace Granular-Coal Injection System

Demonstration Project.

The cooperative agreement was novated and a new siteapproved for the Kentucky Pioneer Energy IGCCDemonstration Project. The National EnvironmentalPolicy Act (NEPA) process, which includes preparingan Environmental Impact Statement (EIS), was startedfor the project.Throughout the year, the CCT Program staff participated in over a dozen domestic and international eventsinvolving users and vendors of clean coal technologies,regulators, financiers, environmental groups, and otherpublic and private institutions. Four issues of theClean Coal Today newsletter were published in thesame period, along with the fifth annual edition of theClean Coal Today Index, which cross-references all

articles published in the newsletter. A 12-page Project

Performance Summary document was issued for the

ENCOAL® Mild Coal Gasification Project. An

updated The Investment Pays Off document, capturing

the latest contributions of the CCT Program to advancing coal technologies, was published. Clean Coal

Technology Topical Reports were issued during the

fiscal year for the Tampa Electric Integrated Gasifica-
Advanced Flue Gas Desu(Pure Air on the Lake, L.Ppresented by Power mag

capping SO2 emissions, and thus focused on technologies that were capable of addressing these issues.CCT-IV called for energy efficient, economicallycompetitive technologies capable of retrofitting,repowering, or replacing existing facilities, while at thesame time significantly reducing SO2 and NOx emissions. CCT-V focused on technologies applicable tonew or existing facilities that could significantlyimprove efficiency and 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

SO2 credits are being used to meet short-term goals,

EIA predicts 11 GWe of capacity will be retrofittedwith scrubbers to meet Phase II goals. Furthermore,these SO2 reduction technologies may be important in

meeting new requirements for PM2.5 (particulate matter

2.5 microns and smaller in diameter) because somesulfur species are in this size range.In addition to SO2 reductions, Title IV also called forreductions in NOx emissions. Phase I of the NOxprovisions of Title IV requires reductions from the socalled Group 1 boilers—tangentially fired and drybottom 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 NOx

emission limitations for Group 2 boilers and reducedthe emission limits for Group 1 boilers. Group 2boilers include cell-burner, cyclone, wet-bottom wallfired, and vertically fired boilers. The CCT Programhas demonstrated NOx emission control techniques thatare applicable 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.Although the deadline has been stayed pending appeal,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 ozonenonattainment in the Northeast. The SIP Call requiresthe 23 affected jurisdictions to revise their stateimplementation plans (SIPs) to reduce NOx emissions85 percent below 1990 rates or achieve a 0.15 lb/106Btu emission 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 generation 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 environmental controls database has been developed thatprovides a foundation for developing technologies tomeet the increasingly stringent standards for existingunits.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 understanding of potential HAPs from power plant emissions bymonitoring HAPs from CCT Program project sites.

The results of these and mitigated concerns abofired power plants and emissions. In Decembdevelop regulations for next three years.The CCT Program is aglobal climate change. as IGCC) being demonoffer utilities an option (GHG) by as much as 2systems through enhantion of atmospheric fluand pressurized fluidizalso serve to reduce GH

Market Consideratio

market moves from a rmarket, the CCT Progrchanges. Whether the the federal government legislation or by state gis demonstrating the firgies that will be needed 
ES-4 Program Update 2000

generation market. These new technologies will be farmore efficient than existing plants and environmentallybenign.

Ensuring Sustainable Economic Growth. It is in the

nation’s interest to maintain a diverse energy mix tosustain domestic economic growth. The CCT Programis contributing to this interest by developing anddeploying a technology portfolio that enhances theefficient use of the United States’ abundant coalresource while simultaneously achieving importantenvironmental goals. The advancements in coal usetechnology resulting from the CCT Program willreduce dependence on foreign energy resources andcreate an international market for these new technologies. The worldwide market for power generationtechnologies could be as high as $80 billion between1995 and 2020.Coal 

Technology for the Futur the Futur the Future. The investment in

the CCT Program is forming a solid foundation uponwhich to build a responsible future for fossil energywhile addressing growing global and regional environmental concerns and providing low-cost energy. Twoprograms are of particular relevance to advancing theclean coal technologies demonstrated in the CCTProgram. First is the Power Plant ImprovementInitiative and second is Vision 21.For the near term, the Office of Coal and PowerSystems (OCPS) has embarked upon the Power PlantImprovement Initiative. The rapid growth in powerdemand, especially peak demand, coupled with theongoing restructuring of the electric power industry,has resulted in a real and growing concern over thereliability of the nation’s electricity grid. This concernprompted Congress to add $95 million to the Office ofFossil Energy budget for fiscal year 2001. The PowerPlant Improvement Initiative approved by Congresswill have a near-term focus on improving the efficiencyand environmental performance of coal-fired power

generation. New technologies will be demonstrated thatcan boost the efficiency of a power plant—increasingthe amount of electricity it can generate, reducing airemissions, or perhaps a combination of both. Theinitial program will apply to existing and new coalbased, central power plants. Later, the program couldinclude a wider span of more flexible generationtechnologies such as fuel cells and turbines that canoperate on natural gas as well as coal.For the long-term, OC&PS will build upon the solidfoundation established by the CCT Program towardmeeting Vision 21 goals. Vision 21 is a long-termstrategic concept that integrates OC&PS program goalsto develop the full potential of the nation’s abundantfossil fuel resources while addressing regional andglobal environmental concerns. Vision 21 plants wouldcomprise a portfolio of fuel-flexible systems andmodules capable of producing a varied slate of highvalue commodities, such as clean fuels, chemicals, andelectricity, tailored to meet market demands in the2010-2015 time frame. The OC&PS program areas,which include Central Power Systems, DistributedGeneration, Fuels, CO2 Sequestration, and AdvancedResearch, were developed to align with and directlysupport the goals and objectives of Vision 21 and theComprehensive National Energy Strategy. 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 Im

ogram Im

Implementation Princi

principles that have been the CCT Program. Thes• Strong and stable fin

of the project, includigovernment’s share o

• Multiple solicitations 

years, enabling the Crange of national neetechnologies;

• Demonstrations cond

actual user environmeof the technology’s co

• A technical agenda e

government, enhancin

• Clearly defined roles 

reflecting the degree 

• A requirement for at 

throughout all project participant’s commitm

• An allowance for cos

and cost-sharing, recoand providing an impthe program;

• Industry retention of 

rights, enhancing com

• A requirement for ind

cialize the technologygoals; and
• A requirement for repayment up to the

government’s cost-share upon successful commercialization of the technology being demonstrated.

Implementation Process. Public and private sector

involvement is integral to the CCT Program processand has been crucial to the program’s success. Environmental concerns are publicly addressed through theprocess instituted under the National EnvironmentalPolicy Act (NEPA). Through programmatic environmental assessments (PEAs) and environmental impactstatements (PEISs), project specific environmentalassessments (EAs) and environmental impact statements (EISs), and other NEPA documents, the public isable to comment and have its comments addressedbefore the projects proceed to implementation. Inaddition, environmental monitoring programs arerequired for all projects to address non-regulatedpollutant emissions.As to the solicitation process, Congress set the goalsfor each solicitation. The Department of Energytranslated the congressional guidance into performance-based criteria and developed approaches toaddress “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 disapprove continuance of the project. Also, any changes tocost or other major project changes require DOEapproval. In addition to formal project reportingrequirements, an outreach program was instituted tomake project information available to customers and

stakeholders. This Program Update 2000 is only oneof the many public reports made available through theoutreach program.

Commitment to Commercial Realization. The CCT

Program has focused on achieving commercialrealization since the program’s inception. All fivesolicitations required the potential participants toaddress the commercial plans and approaches to beused by the participants to achieve full commercialization of the proposed technology. The cooperativeagreements contain balanced provisions that provideprotection for intellectual property but require theparticipants to make the technology available underlicense on a nondiscriminatory basis.

Solicitation Results. Each solicitation was issued as a

Program 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 participant. The result was a broad spectrum of technologiesinvolving customers and stakeholders from all marketsegments. In sum, 211 proposals were submitted and60 of those were selected. As of September 2000, 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. InFY2001, four projects are scheduled to completeoperations.

The body of knowledgProgram is being used regulatory complianceenergy and environmennext generation of techincreasing demands on competitive costs.

Funding and Funding and 

Program Funding. Cfederal budget of $1.8 For the 38 completed apants have contributed combined commitment law, DOE’s contributiothe total cost of any prostepped forward and copercent of the project fCongress has provided five solicitations througadjustments. AdditionProgram are the Small Program and the Small Program. Funding is aand management of the priated funds is controlvariety of financial magovernment cost-share agreement is considerehowever, DOE obligatincrements by budget pthe government’s finanDOE fully participates each major phase of pr
ES-6 Program Update 2000

Cost Sharing. As stated above, DOE’s contribution

cannot 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 likely to happenfor any demonstration project) up to 25 percent of theoriginal project cost. The participant’s contributionsmust occur as expenses are incurred and cannot bedelayed based on forecasted revenues, proceeds, orroyalties. Also, prior investments in facilities byparticipants cannot count toward the participant’s share.

Recovery of Government Outlays (Recoupment) Recovery of Government Outlays (Recoupment).

The policy objective of DOE is to recover an amount ofthe federal government’s financial contribution to eachproject when a technology is successfully commercialized. A recoupment agreement accompanies eachdemonstration agreement and stipulates the repaymentprovisions.

CCT Program

Accomplishments Accomplishments

Marketplace Commitment Marketplace Commitment. The success of the CCT

Program ultimately will be measured by the contribution the technologies make to the resolution of energy,economic, and environmental issues. These contributions can only be achieved if the public and privatesectors understand that clean coal technologies canincrease the efficiency of energy use and enhanceenvironmental performance at costs that are competitive with alternative energy options. The demonstrations, in conjunction with an aggressive outreach effort,are designed to impart that understanding. Also, theCCT Program is organized from a market perspectivewith projects placed in four major product lines—

environmental control devices, advanced electricpower generation, coal processing for clean fuels, andindustrial applications. A summary of the number ofprojects having completed operations by category isshown in Exhibit ES-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 limeand 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.For NOx control technologies, two basic approacheswere used: (1) combustion modification techniquesincluding low-NOx burners, overfire air, advancedcontrols, and reburningsystems; and (2) post-combustion techniques using selectivecatalytic reduction (SCR) andselective non-catalytic reduction (SNCR) systems. TheseNOx control techniques wereapplied in a variety of combinations on a diverse group ofboilers, which are representative of 99 percent of the preNSPS boilers, i.e., those boilersbuilt before instituting NSPSunder the Clean Air Act of1970. The result of the NOxcontrol technology demonstrations is a portfolio of technologies that can be applied to thefull range of boiler types andused to address today’s pressingenvironmental concerns, e.g.,

ozone. Six of the seven demonstrations have suctions. For the seventh prwere issued on key facetwas extended for additioAll six of the combined demonstrations have suctions. The demonstratiocomplementary and syneachieve cost-effective SOreductions.A summary of the resultextended environmental found in exhibit ES-2. Tthe environmental controExhibit ES-3.

Exhibit ES-1

Completed Projects by App

Application Category 

Environmental Control DevicesSO2 Control Technology 

NOx Control Technology 

Combined SO2/NOx Control Technology 

Advanced Electric Power GenerationFluidized-Bed Combustion Integrated Gasification Combined-Cycle 

Advanced Combustion/Heat Engines Coal Processing for Clean Fuels Industrial Applications 

 Total 
Exhibit ES-2

Summary of Results of Completed Environmental Control Technology P

Project and Participant Key Results Capital Cost

SO2 Control Technology

10-MWe Demonstration of Gas Suspension Absorption Gas suspension absorption (GSA)/electrostatic precipita- $149/kW for GSA (2.6(AirPol, Inc.) tor (ESP)—SO2 removal efficiency of 90% at Ca/S molar conventional wet limes

ratio of 1.4, 18 oF approach to saturation, and 0.12%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 50

Demonstration (Bechtel Corporation)LIFAC Sorbent Injection Desulfurization Demonstration SO2 removal efficiency of 70% at 2.0 Ca/S molar ratio $66/kW for two reactoProject (LIFAC–North America) (2.0–2.8% sulfur bituminous coal) reactor (150 MWe); $9

(1994$)

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

coalMaximum SO2 removal efficiency of 98%Over 3-year demonstration, 237,000 tons of SO2

removed while producing 210,000 tons of gypsumGypsum 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 S

for the CT-121 FGD Process (Southern Company concentrations of 1,000–3,500 ppm using 3% sulfur coal $131/kW or $171/ton SServices, Inc.) $104/kW or $136/ton S

Particulate removal efficiency of 97.7–99.3% (Costs based on limestoat inlet mass loadings of 0.303–1.392 lb/106 Btu

Agricultural-grade gypsum as a by-productFiberglass-reinforced-plastic construction—chemicallyand structurally durable; eliminated the need for a flue gasprescrubber and reheat
ES-8 Program Update 2000

Exhibit ES-2 (continued) Exhibit ES-2 (continued)

Summary of Results of Completed Environmental Control Technology Pr

Project and Participant Key Results Capital Cost

NO

x Control Technology

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

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

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

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

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

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

Demonstration of Coal Reburning for Cyclone Boiler NOx NOx reductions of 52% using bituminous coal and 55% $66/kW at 110 MWe; $4Control (The Babcock & Wilcox Company) using subbituminous coal at full load (110 MWe); 36%

and 53%, respectively, at 60 MWe

Full-Scale Demonstration of Low-NO

x

 Cell Burner NO

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

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

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

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

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

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

x

 reduction

Using a 17% reburn fuel heat input on the Kodak Park cycloneboiler resulted in a NO

x

 emission rate of 0.60 lb/106 Btu,

which represents a 59% NOx reduction

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

Technology for the Control of NOx Emissions from High- 5 ppm 2.79 mills/kWh or $2,03

Sulfur, Coal-Fired Boilers (Southern Company (1996$)Services, Inc.)180-MWe Demonstration of Advanced Tangentially NOx reductions of 37% for LNCFSTM I and II, and 45% LNCFS I—$5–15/kW (1

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

Emissions from Coal-Fired Boilers (Southern Company air and close-coupled overfire airServices, Inc.)
Exhibit ES-2 (continued) Exhibit ES-2 (continued)

Summary of Results of Completed Environmental Control Technology P

Project and Participant Key Results Capital Cost

Combined SO2/NOx Control Technology

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

(ABB Environmental Systems) tions of 500–700 ppm

SO2 removal efficiency over 95% at inlet concentrations

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

LIMB Demonstration Project Extension and Coolside SO2 removal efficiency (3.8% sulfur coal, Ca/S molar ratio LIMB—$31–102/kW Demonstration (McDermott Technology, Inc.) of 2.0): Coolside—$69–160/k

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

 – Coolside—70% for hydrated limeNO

x

 reduction of 40–50%

SO

x

-NO

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

Project (The Babcock & Wilcox Company) coal, depending on sorbent and conditions NOx level of 1.2 lb/10

NO

x

 reduction of 90% with 0.9 NH3/NOx ratio

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

Sorbent Injection (Energy and Environmental Research input; SO2 removal efficiency of 53% at 1.75 Ca/S molar (1996$)

Corporation) ratio $50/kW for sorbent in

Lakeside—Average NOx reduction of 66% and SO2 reductions

of 58% during extended continuous combined (GR-SI) runsat 29 MWe, about 22% gas heat input, and 1.8 Ca/S molarratio

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

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

acid. The maximum SO2 removal without formic acid was $217/kW at 300 MWe 95% for other related costs

$4,620,000/yr for O&

Testing of the LNCFSTM III indicated NOx emissions of

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

original burners), a 36% reduction
ES-10 Program Update 2000

Project and Participant Key Results Capital Cost

Combined SO2/NOx Control Technology (continued)

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

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

NO

x

 reduction of 63% with low-NO

x

 burners and minimum

overfire air; steady state conditionsNO

x reduction decreased by 10–25% under load following

SNCR obtained NO

x reduction of 30–50%, thereby

increasing total NOx control system reduction to more than

80%SO2 removal efficiency of 70% with sodium bicarbonate atnormalized stoichiometric ratio of 1.0

Exhibit ES-2 (continued) Exhibit ES-2 (continued)

Summary of Results of Completed Environmental Control Technology Pr
Project Commercial Use10-MWe Demonstration of Gas Suspension Absorption Sold domestically and internationally. GSA market entry was significan

(AirPol, Inc.) 50-MWe unit, worth $12.5 million, to the city of Hamilton, Ohio, subsidi

Office. A sale worth $1.3 million has been made to the U.S. Army for hasystem has been sold to a Swedish iron ore sinter plant. Two GSA systemsold to Taiwan Sugar Corporation for their oil-fired cogeneration plant. Ftechnical assistance and proprietary equipment valued at $1.0 million. Ai$1.5 million to a petroleum coke calciner in India. Negotiations are under incinerator in Holland.

Confined Zone Dispersion Flue Gas Desulfurization Demonstration No sales r No sales rNo sales reported. CZD/FGD can be used to retrofit existing plants or fo(Bechtel Corp.) about one-fourth the cost of a commercial wet scrubber.LIFAC Sorbent Injection Desulfurization Demonstration Project Sold domestically and internationally. There are 10 LIFAC units in ope(LIFAC–North America) Japan, Russia, and the United States, including 5 projects started before th

system at Richmond Power & Light is the first to be applied to a power pcoal. The LIFAC system has been retained for commercial use by RichmValley Station, Unit No. 2.

Advanced Flue Gas Desulfurization Demonstration Project No sales r No sales rNo sales reported. The AFGD continues in commercial service at North(Pure Air on the Lake, L.P.) Company’s Bailly Generating Station. Gypsum produced by the PowerC

commercially.

Demonstration of Innovative Applications of Technology for the Sold internationally. Plant Yates continues to operate with the CT-121 s

CT-121 FGD Process (Southern Company Services, Inc.) site’s CAAA compliance strategy. Since the CCT Program demonstration

of CT 121 FGD capacity are operating at 17 plants in 8 countries. Anothor construction.

Micronized Coal Reburning Demonstration for NOx Control No sales r No sales rNo sales reported. Technology retained for commercial use at Kodak Po

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

(The Babcock & Wilcox Company) Nelson Dewy StationFull-Scale Demonstration of Low-NO

x

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

(The Babcock & Wilcox Company) commercial contracts have been awarded for 172 burners, valued at $27 m

has already been installed on more than 4,900 MWe of capacity.

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Sold domestically and internationally. Public Service Company of Colo

(Energy and Environmental Research Corp.) to retain the low-NOx burners and the gas-reburning system for immediate 

required to remove the flue gas recirculation system. Energy and Environhas been awarded two contracts to provide gas reburning systems for cyclAllen Unit 1 (a 330-MWe unit) as well as Baltimore Gas & Electric’s C. P200-MWe units). The technology is also installed at Ladyzkin State Powe

Exhibit ES-3

Commercial Successes—Environmental Control Technologies
ES-12 Program Update 2000

Project Commercial UseDemonstration of Selective Catalytic Reduction Technology Sold domestically and internationally. Sold domestically and internationally. Since the project was initiated, rev

for the Control of NO

x Emissions from High-Sulfur, Coal-Fired Boilers $2.7 billion through 2000, with projected revenues for 2001 and 2002 expe

(Southern Company Services, Inc.) $1.3 billion, respectively.180-MWe Demonstration of Advanced Tangentially Fired Combustion Sold domestically and internationally. Sold domestically and internationally. LNCFSTM has been retained at the 

Techniques for the Reduction of NOx Emissions from Coal-Fired Boilers ABB Combustion Engineering has sold about 56 GWe of LNCFSTM burne

(Southern Company Services, Inc.) 23 GWe are equipped with overfire air and 33 GWe are without overfire ai

$1 billion.

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Sold domestically and internationally. Sold domestically and internationally. The host has retained the technolo(Southern Company Services, Inc.) Foster Wheeler has equipped 86 boilers (51 domestic and 35 international) 

technology—a total of over 1,800 burners representing over 30,000 MWe oTwenty-six commercial installations of GNOCIS, the associated AI control planned. This represents over 12,000 MWe of capacity. In a strict sense, tcompleted; it has been extended to apply GNOCIS to other pieces of plant its commercial potential.

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

Commercial SNOXTM plants are also operating in Denmark and Sicily. In has operated since August 1991. The boiler at this plant burns coals from vworld, including the United States; the coals contain 0.5–3.0% sulfur. The since March 1991, has a capacity of about 30 MWe and fires petroleum cok

LIMB Demonstration Project Extension and Coolside Demonstration Sold domestically and internationally. Sold domestically and internationally. LIMB has been sold to an indepe(The Babcock & Wilcox Company) Babcock & Wilcox has sales of 2,585 burners for 35,310 MWe of capacity 

burners. The low-NO

x

 burners have an estimated value of $320 million.

SO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstration Project No sales reported. No sales reported. Commercialization of the technology is expected to de

(The Babcock & Wilcox Company) scale application equivalent to 50–100 MWe. The focus of marketing effo

specific needs of potential industrial, utility, and independent power producplant construction. SNRBTM is a flexible technology that can be tailored to 

particulate, or combined emissions to meet current performance requiremento address future needs.

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

Burner on a Wall-Fired Boiler project for a complete understanding of commtechnology.)

Exhibit ES-3 (continued) Exhibit ES-3 (continued)

Commercial Successes—Environmental Control Technologies
Project Commercial UseMilliken Clean Coal Technology Demonstration Project Sold domestically. Sold domestically. Eight modules of DHR Technologies’ Plant Emission(New York State Electric & Gas Corp.) estimated value of $210,000, have been sold. A U.S. company, SHN, has 

S-H-U scrubber. SHN is pursuing an advanced flue gas desulfurization bCombustion Engineering has modified 116 units representing over 25,000 derivative TFS 2000TM.

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

(Public Service Company of Colorado) service at its Arapahoe Station. The Babcock & Wilcox DRB-XCL® burn

realized sales of 2,428 burners, representing 31,467 MWe. The burners a

Exhibit ES-3 (continued) Exhibit ES-3 (continued)

Commercial Successes—Environmental Control Technologies
ES-14 Program Update 2000

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 repowering existing plants and for new plants.For fluidized-bed combustion, two approaches wereused: atmospheric fluidized-bed combustion andpressurized fluidized-bed combustion. The two AFBCprojects use a circulating-bed, as opposed to 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 completed PFBC project used a bubbling-bed operating at16 atmospheres to generate steam and drive a gasturbine in a combined-cycle mode. Two interrelatedPFBC projects, which are now on hold pending furtheranalysis for generation needs by the participant, willuse a circulating-bed operating at 13 atmospheres, in acombined-cycle mode.

During fiscal year 2000, one integrated gasificationcombined-cycle (IGCC) project successfully completedoperations, two IGCC projects were in operation, and afourth IGCC project was in the design stage. TheIGCC projects represent a diversity of gasifier types,cleanup systems, and applications.Two projects are demonstrating advanced combustion/heat engine technology. One uses an entrained(slagging) combustor, and the other uses a heavy dutydiesel fired on a coal-water fuel. One project completed operations in fiscal year 2000 and the otherproject 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 projects areusing chemical and physical processes to transform rawcoal into high-energy-density environmentally compliant fuels. Another project is converting coal to

methanol from coal-derived synthesis gas. A fourthproject in this product line is a software program usedto assess the environmental and operational performance of and determine the least-cost option foravailable coals. Two 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; three are completed and two are ongoing.

A summary of the resultprojects can be found in successes of these projec

Market Communicatio

been a hallmark of the Ction. Commercialization 

Full-Scale Demonstration o

Project (The Babcock & Wi

Award presented by R&D mWabash River Coal GasificRiver Coal Gasification Rep1996 Powerplant Award pre

The PC-based software tool CQETM can be used to determinethe complete costs of various fuel options by integrating theeffects of fuel purchase decisions on power plant performance, emissions, and power generation costs.
Exhibit ES-4

Summary of Results of Completed Advanced Electric Power Generation 

Project and Participant Key Results Capital Cost

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

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

NO

x

 emissions of 0.15–0.33 lb/106 Btu

Particulate emissions of 0.02 lb/106 Btu

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

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

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

NO

x

 emissions of 0.18 lb/106 Btu

Particulate emissions of 0.0072–0.0125 lb/106 Btu

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

Healy Clean Coal Project (Arthur D. Little, Inc.) SO2 reduction in excess of 90% (Usibelli subbituminous Economic data are not 

50% run-of-mine and 50% waste coal) at 1.4–1.8 Ca/Smolar ratioNO

x

 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
ES-16 Program Update 2000

Exhibit ES-5

Commercial Successes—Advanced Electric Power Generation Technolo

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

acquire domestic licensing rights. Commercial ventures abroad include the – Vartan Sweden is operating two P200 units to produce 135 MWe and 22– Escatron in Spain is operating one P200 unit producing 80 MWe– Wakamatsu in Japan is operating one P200 unit to produce 71 MWe– Cottbus in Germany is operating one P200 unit to produce 71 MWe and – Karita in Japan operates one P800 unit to produce 360 MWe– Other projects under construction are in China, South Korea, U.K., and 

Nucla CFB Demonstration Project (Tri-State Generation and Sold domestically and internationally. Sold domestically and internationally. Since the demonstration, Foster WTransmission Association, Inc.) the technology supplier for the demonstration effort, has achieved sales of 

another $2.7 billion in sales projected for 2001 through 2003. Twenty-one 2000 were domestic, while the remaining sales through 2000 were foreign.

Tampa Electric Integrated Gasification Combined-Cycle Sold domestically and internationally. Sold domestically and internationally. First greenfield IGCC unit in com

Project (Tampa Electric Company) and ASEA Brown Boveri signed an agreement forming an alliance to mark

There are currently 10 projects using a Texaco gasifier that are either plann

Wabash River Coal Gasification Repowering Project (Wabash No sales reported. No sales reported. First repowered IGCC unit in commercial service and w

River Coal Gasification Repowering Project Joint Venture) IGCC in commercial service. Preferentially dispatched over other coal-fire

because of high efficiency.

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

Export Authority)
Exhibit ES-6

Summary of Results of Completed Coal Processing for Clean Fuels Pr

Project and Participant Key Results Capital Cost

Development of the Coal Quality ExpertTM CQETM features: CQETM package sells 

(ABB Combustion Engineering, Inc. and CQ Inc.) - Fuel evaluator—performs system-, plant-, and/or unit- $100,000

 level fuel quality, economic, and technical assessments- Plant engineer—provides in-depth performance evalua- tions with a more focused scope than provided in the fuel evaluator- Environmental planner—provides access to evaluation and presentation capabilities of the Acid Rain Advisor- Coal cleaning expert—establishes the feasibility of cleaning a coal, determines cleaning processes, and predicts associated costs

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

Corporation) been used economically in commercial boilers and ton/day would cost $4

furnaces and have reduced SO2 and NOx emissions with annual operating 

significantly at utility and industrial facilities currently million per yearburning high-sulfur bituminous coal or fuel oilsAlmost five years of operating data have been collectedfor use as a basis for the evaluation and design of acommercial plantAbout 260,000 tons of coal had been processed into120,000 tons of PDF® and 5,101,000 gallons of CDL®
ES-18 Program Update 2000

Exhibit ES-7

Commercial Successes—Coal Processing for Clean Fuels Technolog

Project Commercial UseDevelopment of the Coal Quality ExpertTM (ABB Combustion Sold domestically and internationally. Sold domestically and internationally. The Electric Power Research Instit

Engineering, Inc. and CQ Inc.) and distributes it to EPRI members for their use. CQ Inc. and Black and V

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

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

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

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

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

Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) No sales reported. No sales reported. Total sales of SynCoal® product exceed 1.5 million ton

in place to purchase the product. One domestic and five international projeWestern SynCoal LLC has a joint marketing agreement with Ube Industries non-exclusive marketing rights outside of the United States. Ube is pursuinWestern SynCoal is also discussing a potential marketing and development engineering firm.

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

(LPMEOHTM) Process (Air Products Liquid Phase Conversion CompanyCompany , L.P.)
Exhibit ES-8

Summary of Results of Completed Industrial Application Projects

Project and Participant Key Results Capital Cost

Advanced Cyclone Combustor with Internal Sulfur, SO2 reduction of 58% with limestone injection in the Not available

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

NO

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

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

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

quoddy Tribe) coal); 98% maximum reduction

NO

x reduction of 18.8% avg

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

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

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

Exhibit ES-9

Commercial Successes—Industrial Commercial Successes—Industrial Application Technologies

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

Corporation) commercial introduction.Cement Kiln Flue Gas Recovery Scrubber No sales reported. No sales reported. The scrubber became a permanent part of the cement plant at the en

(Passamaquoddy Tribe) feasibility study has been completed for a Taiwanese cement plant.Blast Furnace Granular-Coal Injection System Domestic sale. Domestic sale. British Steel’s Blast Furnace Granular Coal Injection System was sold 

Demonstration Project (Bethlehem Steel by United States Steel Corporation.Corporation)
ES-20 Program Update 2000

acceptance by a wide range of interests—customers,manufacturers, suppliers, financiers, government, andpublic interest groups. The CCT Program has aggressively sought to disseminate key information to this fullrange of customers and stakeholders and to obtainfeedback on changing needs. This dissemination ofinformation takes the form of printed media, exhibits,and electronic media. Printed media consist of newsletters, proceedings, technical papers, fact sheets,program updates, and bibliographies. The CCTProgram currently uses four traveling exhibits ofvarying sizes and complexity that can be updated andtailored to specific forums. A fifth exhibit is beingdeveloped to replace an older exhibit that will beretired. Electronic media are available through theWorld Wide Web.Feedback is another important part of the outreacheffort. From public meetings during the PON processto open houses at demonstration sites, the CCTProgram stays in contact with customers and stakeholders. Executive seminars, stakeholder meetings, conferences, workshops, and trade missions are used by theCCT Program to disseminate information and obtainfeedback.Several domestic and international conferences andworkshops were attended or sponsored in fiscal year2000. The forums for conferences varied from Slovakiato Japan. Trade missions during fiscal year 2000included South Africa and India. The Department ofEnergy also provided support for the Foreign ServiceTraining Course. All of these events were used toendorse and promote the technologies demonstrated inthe CCT Program.

CCT Projects

Technology 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 ol Devicesol Devices. The environmentalcontrol technologies provide a suite of cost-effectivecontrol options for the full range of boiler types. The17 environmental control device projects are valued at$620 million. These include seven NOx emissioncontrol systems installed in more than 1,750 MWe ofutility generating capacity, five SO2 emission controlsystems installed on approximately 770 MWe, and sixcombined SO2/NOx emission control systems installedor planned for installation on more than 665 MWe ofcapacity.

Advanced Electric Power Generation. To respond to

load growth, as well as growing environmentalconcerns, the CCT Program provides a range ofadvanced electric power generation options for bothrepowering 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 21stcentury.Coal Pr Coal Processing for Clean Fuels. Also addressed areapproaches to converting run-of-mine coals to highenergy-density, low-sulfur products. These products

have application domestCAAA. Internationally, cesses have excellent maalmost $432 million, the processing for clean fuelfied portfolio of technolo

Industrial Processes ocesses. P

well to address pollution use in the industrial sectinclude dependence of ththe pollutant emissions ireliance of the cement inand often high-sulfur, coindustrial boiler operatofuels to reduce operating applications projects hav$1.3 billion. The projectcoal for 40 percent of coof a direct iron-making pelectricity; reduction of csolid waste generation; dscale slagging combustocombustor system.Project Fact Sheets. Th

Update 2000 is the proje

fact sheets are provided: for ongoing projects and summary for projects thaoperational testing. The the major results from thsources for obtaining furdescriptions, costs, and sprojects. A list of the prsolicitation, and status is list of the award-winning shown in Exhibit ES-11.
Exhibit ES-10

Project Fact Sheets by Application Category

Project Project Participant Solicitatio

Environmental Control Devices

SO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/comConfined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/comLIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC-North America CCT-III/comAdvanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/comDemonstration of Innovative Applications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/com

NO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/exteDemonstration of Coal Reburning for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/com

Full-Scale Demonstration of Low-NO

x

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

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

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

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

for the Control of NO

x Emissions from High-Sulfur, Coal-Fired Boilers

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

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/comLIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/comSO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/com

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/com

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/coIntegrated Dry NOx/SO2 Emissions Control System Public Service Company of Colorado CCT-III/com

Advanced Electric Power Generation

Fluidized-Bed Combustion

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

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

JEA Large-Scale CFB Combustion Demonstration Project JEA CCT-I/desig

Shaded area indicates projects having completed operations.
ES-22 Program Update 2000

Shaded area indicates projects having completed operations.

Exhibit ES-10 (continued) Exhibit ES-10 (continued)

Project Fact Sheets by Application Category

Project Project Participant Solicitation

Tidd PFBC Demonstration Project The Ohio Power Company CCT-I/complNucla CFB Demonstration Project Tri-State Generation and Transmission

Association, Inc. CCT-I/compl

Integrated Gasification Combined-Cycle

Kentucky Pioneer Energy IGCC Demonstration Project Kentucky Pioneer Energy, LLC CCT-V/desigPiñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/operTampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/operWabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering CCT-IV/comp

Project Joint Venture

Advanced Combustion/Heat Engines

Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/constHealy Clean Coal Project Alaska Industrial Development and CCT-III/comp

Export Authority

Coal Processing for Clean Fuels

Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process Air Products Liquid Phase CCT-III/oper

Conversion Company, L.P.

Advanced Coal Conversion Process Demonstration Western SynCoal LLC CCT-I/operatDevelopment of the Coal Quality ExpertTM ABB Combustion Engineering, Inc. CCT-I/compl

and CQ Inc.

ENCOAL® Mild Coal Gasification Project ENCOAL Corporation CCT-III/comp

Industrial Applications

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) CPICORTM Management Company LLC CCT-V/desig

Pulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/consBlast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/compAdvanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/complCement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/comp
Full-Scale Demonstration of Low-NO

x

 Cell Burner

Retrofit (The Babcock & Wilcox Company)Evaluation of Gas Reburning and Low-NOx Burners

on a Wall-Fired Boiler; Enhancing the Use of Coals byGas Reburning and Sorbent Injection (Energy andEnvironmental Research Corporation)Advanced Flue Gas Desulfurization DemonstrationProject (Pure Air on the Lake, L.P.)Demonstration of Innovative Applications of Technology for the CT-121 FGD Process(Southern Company Services, Inc.)Tidd PFBC Demonstration Project (The Ohio PowerCompany)Tampa Electric Integrated Gasification CombinedCycle Project (Tampa Electric Company)Wabash River Coal Gasification Repowering Project(Wabash River Coal Gasification Repowering ProjectJoint Venture)Development of the Coal Quality ExpertTM (ABBCombustion Engineering, Inc. and CQ Inc.)

Exhibit ES-11

Award-Winning CCT Projects

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

burner.1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management AssociaEnergy, Gas Research Institute, and U.S. Environmental Protection Agency for the developgas-reburning technology.1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service 

Station.1992 Outstanding Engineering Achievement Award presented by the National Society of P1995 Design Award presented by the Society of Plastics Industries in recognition of the m1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. CDepartment of Energy.1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and W1993 Environmental Award presented by the Georgia Chamber of Commerce.1992 National Energy Resource Organization award for demonstration of energy-efficient 1991 Powerplant Award presented by Power magazine to American Electric Power Comp

was The Babcock & Wilcox Company.1997 Powerplant Award presented by Power magazine to Tampa Electric’s Polk Power Sta

1996 Association of Builders and Contractors Award presented to Tampa Electric for qual1993 Ecological Society of America Corporate Award presented to Tampa Electric for its i1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of process.1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innov1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc.

1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 199neers Council competition.In 1996 recognized by then Secretary of Energy Hazel O’Leary and EPRI President RichaDOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Pr

Project and Participant Award
ES-24 Program Update 2000

Benefits Legacy Benefits Legacy

The CCT Program, in conjunction with other government-sponsored coal research, development, anddemonstration (RD&D) projects and partnerships, hasresulted in a broad range of environmental andeconomic benefits. DOE efforts to advance coaltechnologies prior to the CCT Program, through theCCT Program, and via ongoing RD&D programs havebeen highly complementary and successful. Closeworking relationships between government andindustry have accelerated market entry of the advancedtechnologies emerging from these collaborative efforts,as well as the realization of the related benefits.Exhibit ES-12 summarizes some of the benefits derivedfrom the CCT Program, associated RD&D partnerships, and the resultant technologies.

Exhibit ES-12

Benefits Legacy from CCT Program and Asso

NO

x

 Control T Control T Control Technologies

• 75% of existing U.S. coal-fired units have been or currently are being retrofi

• $1.3 billion in commercial foreign and domestic sales of low-NOx burners ha

• A 50% reduction in SCR costs has resulted since 1980.• An estimated 30% of U.S. coal-fired generating capacity will incorporate SC• Over 60 million tons of NO

x emissions have been avoided since 1970 based 

SO2 Control T Control T Control Technologies

• A 30% reduction in FGD costs has resulted since the early 1990s.• An estimated 30% of U.S. coal-fired generating capacity will incorporate FG• 127 million tons of SO2 emissions have been avoided since 1970 as a result o

Fluidized-Bed Combustion Technologies

• Well over 100 domestic and more than 400 overseas industrial and utility FB• Since the CCT demonstrations, at least 29 units greater than 100 MWe have 

over 6,000 MWe of capacity valued at over $6 billion.

• FBCs offer inherently low NOx emissions, high combustion and SO2 capture 

flexibility—e.g., six FBCs in Pennsylvania are using coal waste as fuel, elimproblem, saving $1 billion in fuel costs, and avoiding 1.8 million tons of NO

Integrated Gasification Combined Cycle Technologies

• Over 5,600 MWe of IGCC, designed for a multiplicity of fuels, is in operatio

of which is coal-fired and in operation.

• 16,500 MWe of IGCC is expected to be operating in the United States by 20• The more than 1,100 MWe of CCT demonstration unit capacity will avoid an 

SO2 and 312,000 tons of NOx over the life of the units.

Life-Cycle Cost Savings to Industry and the Public for Near-Term De

erm De

• Lower capital and operating costs for advanced power plants and NOx and S

systems equate to $23 billion.

• Lower compliance costs for air toxics and solid waste, through technology d

$70 billion.

• Market value of SO2 and NOx reduction is estimated at $10 billion.

• Improved waste characterization and advances in waste recovery are estimat

cost benefit.
1. Role of the CCT 1. Role of the CCT Program

Introduction Introduction

Over the past quarter century, both nationally andinternationally the energy picture has been one ofdynamic change. These include the oil embargoes ofthe 1970s and the environmental debates of the 1980s.The 1990s brought about more changes in response torequired emission reductions for acid rain precursors,initiation of more stringent NOx standards for ozone

nonattainment areas, tighter standards on fineparticulates, the beginning of electric utility restructuring, and concern about global warming.Upon entering the 21st century, the immediate challenge is to meet escalating domestic demands for

electric power and to assuage associated electricitydelivery reliability concerns. This challenge comes at atime when natural gas prices are extremely volatile andenvironmental regulations are increasingly stringent.The Clean Coal Technology Demonstration Program(CCT Program), begun in fiscal year 1985, has largelyresponded to the dynamic changes experiencedthrough the 1990s. Adjustments were enabled byspacing a series of five competitive solicitations from1986 to 1992. 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 their expertise andcarry out appropriate roles. The magnitude of theprojects and extent of industry participation in theCCT Program is unprecedented. More than $5.2

billion is being expended, with industry and stategovernments investing two dollars for every federalgovernment dollar invested. With 66 percent of theprojects having completed operations by the end offiscal year 2000, the technological successes havemanifested themselves in the marketplace. Newtechnologies to reduce the emissions of acid rainprecursors, namely sulfur dioxide (SO2) and nitrogen

oxides (NOx), are now in the marketplace and are

being used by electric power producers and heavyindustry. Advanced electric power generationsystems that generate electricity with greaterefficiency and fewer environmental consequencesare now operating with the nation’s most plentifulfossil energy resource—coal. Coal, which accountsfor over 94 percent of the proven fossil energyreserves in the United States, supplies the bulk of thelow-cost, reliable electricity vital to the nation’seconomy and global competitiveness. According tothe U.S. Department of Energy’s (DOE) EnergyInformation Administration (EIA) Annual Energy

Review 1999 (July 2000) (AER1999), 944 million tons

of coal were used to produce over 1,890 billionkilowatt-hours or 51 percent of the nation’s electricityin 1999. EIA projections count on coal continuing todominate electric power production, at least through2020 (the end of the forecast period). In the Annual

Energy Outlook 2001 (December 2000) (AEO2001),

EIA estimates 1,186 million tons of coal will generatean estimated 2,350 billion kilowatt-hours or 44 percent of all electricity generated in 2020.The ability of coal and coal technologies to respondto the nation’s need for low-cost, reliable electricityhinges on the ability to meet two central requirements: (1) environmental performance requirements

established in current ations, and (2) operationrequirements consistenutility restructuring. Ththese requirements by pvanced coal-based techretain its prominent roltion future. Furthermoemerging from the CCT coal’s competitive posiexample, technology ading direct use of coal, wwhile greatly improving Also, coal could increaindustrial sector througelectricity) and coproduand chemicals).While the CCT Program competitive and clean cpositions U.S. industry power market abroad. Emost rapidly growing foworld. Projections from 

Outlook 2000 (March 2

demand rising from 12 trtrillion kilowatt-hours in projected for the coal-dAsia. This growth not market opportunity, but reduction in global carbapplication of highly eff
1-2 Program Update 2000

CCT Program Evolution CCT Program Evolution

The environmentally sound and competitive performance of modern coal technologies has evolvedthrough many years of industry and governmentresearch, development, and demonstration (RD&D).The programs were pursued to assure that the U.S.recoverable coal reserves of 274 billion tons, whichrepresent a secure, low-cost energy source, couldcontinue to supply the nation’s energy needs economically and in an environmentally acceptablemanner.During the 1970s and early 1980s, many of thegovernment-sponsored technology demonstrationsfocused on synthetic fuels production technology.Under the Energy Security Act of 1980, the SyntheticFuels Corporation (SFC) was established for thepurpose of reducing the U.S. vulnerability to disruptions of crude oil imports.The SFC’s purpose was accomplished by encouragingthe private sector to build and operate synthetic fuelproduction facilities that would use abundant domestic energy resources, primarily coal and oil shale. Thestrategy was for the SFC to be primarily a financier ofpioneer commercial and near-commercial scalefacilities. The goal of the SFC was to achieve production capacities of 500,000 barrels per day of syntheticfuels by 1987 and 2 million barrels per day by 1992, atan estimated cost of $8.8 billion.By 1985, the market drivers for synthetic fuelsdissolved as oil prices declined, world oil suppliesstabilized, and a short-term supply buffer was provided by the Strategic Petroleum Reserve. In 1986,Congress responded to the decline of private-sectorinterest in the production of synthetic fuels in light ofthese market conditions. Public Law 99-190, Department of the Interior and Related Agencies Appropria- tions Act for Fiscal Year 1986, abolished the SFC and transferred project management to the Treasury Department. The CCT Program was initiated in October 1984. Public Law 98-473, Joint Resolution Making Continuing Appropriation for Fiscal Year 1985 and Other Pur- poses, provided $750 million from the Energy Security Reserve to be deposited in a separate account in the U.S. Treasury entitled The Clean Coal Technology Reserve. The nation moved from an energy policy based on synthetic fuels production to a more balanced policy. This policy established that the nation should have an adequate supply of energy, maintained at a reasonable cost, and consistent with environmental, health, and safety objectives. Energy stability, security, and strength were the foundations for this policy. Coal was recognized as an essential element in this energy policy for the foreseeable future because of the following: • The location, magnitude, and characteristics of the coal resource base are well understood. • The technology and skilled labor base to safely and economically extract, transport, and use coal are available. • A multi-billion dollar infrastructure is in place to gather, transport, and deliver this valuable energy commodity to serve the domestic and international marketplace. • Coal is used to produce over half of the nation’s electric power and is vital to industrial processes, such as steel and cement production, as well as industrial power. • This abundant fossil energy resource is secure within the nation’s borders and relatively invulner- able to disruptions because the coal industry’s production is dispers

network is vast, and great. • Coal is the fuel of nedeveloped economieopportunities for U.Stechnologies. Congress recognized th

coal as a source of enerdemonstration and comgeneration of advanced characterized by enhanenvironmental performaestablished to demonstrof clean coal technologthat need. In 1986, DOE (CCT-I) for clean coal tsolicitation resulted in a selected in four major ptal control devices, advtion, coal processing foapplications. In 1987, the CCT Prograsatisfying the recomme

Report of the Special E

Presidential initiative laU.S. government/indusacid rain formation—SO

solicitation (CCT-II), isvided for the demonstracapable of achieving sigin SO2, NOx, or both, fro

These technologies werthan current technologideployment in the 1990third solicitation (CCT-objective as the second
Exhibit 1-1

Phase I SO2 Compliance 

% S

Method No. of % of Re

Units Units 19

Fuel switching/blending 136 52 60 Additional SO2 allowances 83 32 16 

Scrubbers 27 10 83 Retirements 7 3 100 

Otherb 8 3 86 

Total 261 100 345 

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

Effects of Title IV of the Clean Air Act Amendments of 1990 on 

Information Administration, March 1997.

technologies that would produce clean fuels from runof-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, economicallycompetitive, and low-emission technologies. Specifically, the fourth solicitation (CCT-IV), released inJanuary 1991, had as its objective the demonstrationof energy-efficient, economically competitive technologies capable of retrofitting, repowering, orreplacing existing facilities while achieving significantreductions in SO2 and NOx emissions. In July 1992,DOE issued the fifth and final solicitation (CCT-V) toprovide for demonstration projects that significantlyadvanced the efficiency and environmental performance of technologies applicable to new or existingfacilities. As a result of these five solicitations, a totalof 60 government/industry cost-shared projects wereselected, of which 38, valued at more than $5.2 billion,have either been successfully completed or remainactive in the CCT Program.The success of the government/industry CCTProgram is directly attributable to the CCT Program’sresponsiveness to public and private sector needs toreduce environmental emissions and maximizeeconomic and efficient energy production. The CCTProgram is strengthening the economy, enhancingenergy security, and reducing the vulnerability of theeconomy to global energy market shocks.

Environmental Impetus Environmental Impetus

SO2 Regulation

Acid Rain Mitigation. Acid Rain Mitigation. During the late 1980s, work

began on drafting what was to become the Clean AirAct Amendments of 1990 (CAAA). On November 15,1990, Congress enacted the CAAA as Public Law 101-549. 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 overallemissions levels by using marketable allowances. Theutilities can adopt a control strategy that is most costeffective for their given systems and plants ratherthan having to apply a “command-and-control”approach wherein the emission-reduction method isspecified.The emissionreduction requirements for SO2 wereinstituted in twophases. Phase Iprovided for theinitial increment ofSO2 reduction,beginning onJanuary 1, 1995.Phase II began onJanuary 1, 2000.Title IV identified261 generatingunits (designatedas “affected units”)that were required

to comply with Phase units with fairly high esummarizes the compaffected units listed in requirements. An addPhase I based on U.S. Agency (EPA) rules thsubstitution or compecompliance strategiesconsidered Phase I uning 2,500 boilers at 1,0As a result of Phase I, utilities declined from to 12.5 million tons pedecline. As shown in Esulfur coal was the opthe owners of Phase I
1-4 Program Update 2000

In Phase II, all existing boilers must meet SO2 emission

levels of 1.2 lb/106 Btu and a sliding-scale percent

reduction of 70 to 90 percent, depending upon theinput sulfur content. The resultant SO2 emission

levels are generally 0.3 lb/106 Btu for low-sulfur coals

and 0.6 lb/106 Btu for high-sulfur coals. Moreover, the

CAAA calls for SO2 emissions to be limited to 9.48

million tons per year between 2000 and 2009 and 8.95million tons per year thereafter. EIA predicts that 11GWe of capacity will be retrofitted with scrubbers tomeet 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 Bailly

Generating Station, 528-MWe Units Nos. 7 and 8(Pure Air advanced flue gas desulfurizationscrubber);

• Georgia Power Company’s Plant Yates,

100-MWe Unit No. 1 (Chiyoda Thoroughbred-121advanced flue gas desulfurization scrubber);

• New York State Electric & Gas Corporation’s

Milliken Station, 300-MWe Unit Nos. 1 and 2 (S-HU formic-acid-enhanced wet limestone scrubber);and

• PSI Energy’s Wabash River Station,

262-MWe Unit No. 1 (repowered with Destecintegrated gasification combined-cycle unit).

The three Phase I scrubber projects served to redefinethe state-of-the-art in wet limestone scrubber technology and the other was the first to introduce integratedgasification combined-cycle as a repowering technology. The advanced scrubbers essentially halved thecost of conventional scrubbers of the time. Therepowering project represented an option providedunder the CAAA that allows a four-year extension (to

December 31, 2003) for compliance with Phase IIrequirements when advanced electric power generation technology is applied. Together with the otherprojects, the CCT Program has afforded a portfolio ofSO2 compliance options for the diverse fleet of

existing coal-fired electric generating units and themeans to meet future energy and environmentaldemands. These include advanced scrubbers, lowcapital-cost sorbent injection systems, clean highenergy-density fuels from both eastern and westerncoals, and a range of advanced electric power generation systems.

NOx Regulation

Acid Rain Mitigation. Acid Rain Mitigation. In Title IV of the CAAA,

Congress also requiredthe EPA to establishannual allowableemissions limitationsfor NOx in two phases.Phase I required NOxreductions fromtangentially fired anddry-bottom wall-firedboilers. These boilersare referred to as Group1 boilers. In March1994, EPA promulgateda rule establishing NOxemission limitations of0.45 lb/106 Btu fortangentially fired unitsand 0.50 lb/106 Btu for

wall-fired units.Ultimately, a compliance date of January 1,1996, was established.

On December 19, 1996, Phase II. The rule estab

for additional coal-fired the NOx emissions limit

types of Group 1 and 2 NOx emission limits are In response to the need 

reductions that were rea1, EPA was able to use Southern Company Ser

control technologies on fired boilers. Furthermo

oped under the CCT Protypes (wall-fired, tangenburner, and vertically fi

Exhibit 1-2

CAAA NO CAAA NOx Emission 

Group 1 Group 1 Group 2 Group 2 Phase I NO

Boiler Type Boiler Type Emission 

(lb/106Btu) 

Tangentially firedboilers 0.45 Dry-bottom wallfired boilersb 0.50 

Cell-burnerboilers Cyclone boiler >155 MWe Wet-bottom wallfired boilers>65 MWe Vertically fired boilers 

aEmission limits are lb/106Btu of heat input on an annual averabOther than units applying cell-burner technology.
percent of the pre-New Source Performance Standard(NSPS) boiler types. Low-NOx burners were developed for all boiler types amenable to burner modification. As a result, nearly half of the pre-NSPS boilersare equipped with low-NOx burners (LNB). The CCTProgram also demonstrated a range of NOx control

techniques to address boilers where burner modification is not practical and to provide methods toenhance NO

x control beyond low-NOx burner capability. These options included coal and gas reburning,

selective noncatalytic reduction (SNCR), and selectivecatalytic reduction (SCR). This portfolio of NOx

controls not only will assure that Phase I and IIemission reductions are achievable, but will providethe technology base necessary to achieve evengreater NOx reductions required to meet new National

Ambient Air Quality Standards (NAAQS) for ozoneand fine particulate matter under Title I of the CAAA.

Soot and Smog. In July 1997, under Title I of the

CAAA, EPA issued final rules revising the primaryand secondary NAAQS for particulate matter (PM)

and ozone (O3) (commonly referred to as “soot andsmog” regulations).The soot provisions addressed ambient air concentrations of particulate matter in the respirable range of 2.5micrometers (microns) in diameter or less (PM2.5).Previous fine particulate standards dealt with airbornematerial in the inhalable range of 10 microns indiameter or less (PM10). The PM2.5 standard affectsprimary sources such as fly ash, carbon soot, and acidmists (aerosols) and secondary sources such asammonium sulfates and nitrates from precursor SO2and NOx gases. Monitoring to ascertain PM2.5attainment is ongoing, with designations of nonattainment expected by 2003–2004. State Implementation Plans (SIPs) for compliance are expected by 2007–2008, with compliance 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 according to specified amounts (budgets) by May 2003. Theexpected emission limits for power plants is 0.15 lb/106Btu, which generally requires relatively expensiveselective catalytic reduction (SCR) technology. Underthe general provisions of the ozone NAAQS provisions, SIPs are expected by 2003, with complianceranging from 2003–2018 depending on the air qualityin a particular 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 23jurisdictions affected by the SIP Call. Under the plan,the affected jurisdictions would establish a cap onNOx emissions and then give power plants and

industries the flexibilimost cost-effective mindustries that cut NOcould sell credits to faemissions as quickly o

trading program, simil

program, allows sourcstrategies, such as fuecontrol devices, like tCCT Program; or buyover-complied.

Low-NOx burner technol

Engineering’s LNCFSTM left), Foster Wheeler’s l(top right), Babcock & W

(center), and Babcock & 

boilers (bottom).

NOx emissions at Georgia Power’s Plant Hammond were

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

burners, shown here, and advanced overfire air.
1-6 Program Update 2000

New Source Performance Standards. On the national

level, the EPA has tightened its NOx emission

standards for new electric utility boilers and haschanged its rules so that all generation fuels aretreated the same. Under the revised New SourcePerformance Standard (NSPS), electric utility andindustrial steam generating units built or modifiedafter July 9, 1997, must meet an emission limit of 1.6 lb/MWh regardless of fuel type. However, under EPA’sso-called “WEPCO Rule” existing units may besubject to NSPS as a result of certain modifications.By basing the standard on electricity output, there isan economic incentive to use more efficient systems.

Hazardous Air Pollutants Hazardous Air Pollutants

Hazardous Air Pollutant Monitoring. Hazardous Air Pollutant Monitoring. Under Title III

of 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.To address this issue, DOE implemented a programwith industry to monitor HAPs emissions at CCT

Program project sites. Objectives of the HAPsmonitoring are to (1) improve the quality of HAPs databeing gathered, and (2) monitor a broader range ofplant configurations and emissions control equipment.As a result of this program, 20 CCT projects aremonitoring HAPs, with 13 having completed monitoring by September 2000 (see Appendix C, Exhibit C-7).In a parallel effort begun in January 1993, EPA, with theparticipation 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 eightutilities representing nine process configurations,several of which were sites for CCT projects. Theseutilities represented different coal types, processconfigurations, furnace types, and pollution controlmethods. The report, A Comprehensive Assessment of

Toxic Emissions from Coal-Fired Power Plants:

Phase I Results from the U.S. Department of Energy

Study, was released in September 1996 and provided

the raw data from the emissions testing. The secondphase of the DOE/EPRI effort involves sampling atother sites, including the CCT Program’s WabashRiver, Tampa Electric, and Sierra Pacific integratedgasification combined-cycle (IGCC) projects.In another DOE study, HAPs data were collected from16 power plants and reported in Summary of Air Toxics

Emissions Testing at Sixteen Utility Plants. The

report, issued in July 1996, provides an assessment ofHAPs measured in the coal, across the major pollutioncontrol devices, and emitted from the stack. Theresults of the HAPs program have significantlymitigated concerns about a broad range of HAPsemissions from coal-fired power generation, andfocused attention on mercury.

Mercur

y. Following up 

report to Congress, Stu

Emissions from Electri

Units—Interim Final R

February 1998). The M

Congress, issued Decem

industrial sources were tons of mercury into the The EPA estimates that originate from combustEight SCR catalysts with were evaluated side-by-siusing high-sulfur coal. NO

achieved.

This picture illustrates how minute PM2.5 particles are when

compared to a human hair.

PM2.5 Particle

Human Hair Magnified 1,000x
fossil fuel facilities, 10 percent from manufacturingfacilities, 2 percent from area sources, and 1 percentfrom other sources. The EPA also identified fourspecific 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.In December 2000, EPA decided to develop regulations for mercury emissions. The schedule calls forEPA to issue proposed regulations for comment by2003 and issue final regulations by 2004.

Global Climate Change

The CCT Program had its roots in the reduction ofacid rain precursors and was responsive to therecommendations contained in the Joint Report of the

Special Envoys on Acid Rain, as discussed earlier.

Moreover, as concerns over global climate changeemerged, the CCT Program began to emphasizedemonstration of advanced electric power generationtechnology capable of achieving significantly higherefficiency than conventional systems, thus reducingcarbon emissions.For example, pressurized fluidized-bed combustion(PFBC) technology has efficiencies up to 25 percenthigher than conventional coal-fired systems, whichresults in a like reduction in carbon emissions. Also,the PFBC technology reduces pollutant emissions farbelow NSPS, without expensive add-on emissioncontrols. As a result of the CCT Program’s Tidd PFBCDemonstration Project and associated developmentwork, this technology is achieving market penetration,including several commercial sales of this newgeneration of advanced power system in Japan andGermany. The work at Tidd is also providing the basisfor the second-generation PFBC demonstrations to be

conducted in Lakeland, Florida with funding from theCCT Program.Another very efficient advanced power system isintegrated gasification combined-cycle (IGCC). Thereare four IGCC demonstration projects in the CCTProgram, representing a diversity of gasifier types andcleanup systems. These projects are pioneering thisenvironmentally friendly technology, which inaddition to lower carbon emissions, boasts very lowSO2 and NOx emissions. The IGCC technology offersflexibility in that new plants can be constructed inmodules as demand dictates. Current worldwidemarket penetration of this technology is approximately5 gigawatts (GW), and demand is growing.

Regional Haze

In 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 groupsbelieve coal-fired power plants are asource of regional haze in the nationalparks and wilderness areas.During the period 2003-2008, states arerequired to establish goals for improvingvisibility in each of these 156 areas andadopt emission-reduction strategies forthe period extending to 2018. States haveflexibility to set these goals based uponcertain factors, but as part of the process,they must consider the rate of progressneeded to reach natural visibility conditions in 60 years. Coal-fired power plantsare likely targets for new controls toreduce regional haze.

Solid 

Waste

The CCT Program alswaste. For example, sstate-of-the-art in wet Included in this signifwas production of comthe scrubber sludge ascrubbers of the early been projected to requdisposal by 2015. Adprecluded that need. the CCT Program also by producing salable (e.g., sulfur, sulfuric acmentally benign materused as construction mroadbed stabilization, agricultural supplemesubsidence and acid mdisposed of in landfill

Hazardous air pollutants were measureCompany’s Demonstration of Coal Rebuat Nelson Dewey Station.
1-8 Program Update 2000

Toxics Release Inventory

Section 313 of the Emergency Planning and Community Right-To-Know Act (EPCRA) and Section 6607 ofthe Pollution Prevention Act (PPA) mandate establishment of a publicly accessible database containinginformation on the release of toxic chemicals byfacilities that manufacture, process, or otherwise usethem. This database is known as the Toxics ReleaseInventory (TRI). Starting in 2000, electric utilities arerequired to report on releases of toxic chemicals intothe air, water, and land. EPA compiles this data in anonline TRI that gives the public access to detailedinformation about releases of toxic chemicals in theircommunities. It is expected that electric utilities willexceed chemical manufacturers as the largest emittersof toxic chemicals into the environment. Although theemission rates are low for electric utilities, the volumeof emissions will likely bring pressure for furtherreductions.

Market Considerations Market Considerations

When the CCT Program started in 1985, the electricutility industry was highly regulated. The majoruncertainty was the breadth and depth of environmental regulatory requirements that would be imposed onthe industry. Even this uncertainty was mitigated bythe fact that the environmental control costs could bepassed through to the consumer if approved by thestate regulatory commission. As long as the utilitymade prudent investments in plant and equipment,their economic future was fairly stable and predictable.Most industry observers assumed that coal andnuclear energy would carry the burden of baseload

generation, oil would be phased out, and natural gaswould be used for meeting peak load requirements.By mid-1997, the picture was entirely different—theutility industry was in the midst of a major restructuring to accommodate a competitive marketplace. Underutility restructuring, power generators must assumethe risk for new capacity additions. The relatively lowcapital cost and short lead times for natural gas-basedsystems makes them the preferred option for theforeseeable future. As a result, projections now callfor natural gas to be the fuel of choice for newcapacity additions through 2020. During the sameperiod, nuclear-based capacity will decline and coalbased capacity will increase moderately.Consumers became a major factor in pushing forcompetition and regulatory reform even thoughregulators provide the oversight necessary to assure

that consumers were papressures for access to successful in bringing awell as wholesale poweretail markets is occurriFederal Energy Regulatoprohibited from orderinEnergy Policy Act of 19have responsibility for rcompany operating withelectric wholesale generwholesale to such a utilcompany that was an asselling power to a regulfiscal year 2000, twentyColumbia had enacted lin the retail electricity mIn one other state, a comwas issued. Eighteen sing deregulation optionsignificant deregulation lation, end users are nofrom their local utility cpurchase power from gein other states and regiocompetitive market envaccording to market coaccording to generation Advancement in the tection is another factor threstructuring. Nonutiliadvantage of these advgas turbines, to generatbe achieved using convnuclear generators. Thmore efficient, less envbe installed in a very shmodules closely matchi

Aero-derivative gas turbines, like the one shown duringinstallation at the Tampa IGCC plant, will account for mostnew generation capacity.
Exhibit 1-3

Comparison of Energy Projections for Electric Generators

Electricity Sales Coal Consumption Gas Consumptiona Oil Con

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

NEPP AEO % dif NEPP AEO % dif NEPP AEO % dif NEPP 

1985 2001 1985 2001 1985 2001 1985 

1995 3,018 3,026b 0.3 924 958b 3.7 3.0 3.37b 12 73 

2010 4,176 4,147 -0.7 1,355 1,122 -17.2 1.7 6.94 308 146 NEPP 1985: National Energy Policy Plan Projections to 2010, U.S. Department of Energy, December 1985.

AEO 2001: Annual Energy Outlook 2001 with Projections to 2020, Energy Information Agency, December 2000.

% dif = percent difference between the two projections.

aConsumptions by electric generators excluding cogenerators.bActuals from Annual Energy Outlook 1998, December 1997.

These factors have had a pronounced effect on theutility market for coal and clean coal technology. Acomparison of 1985 and 1999 energy projections forcoal, natural gas, and oil, which is shown in Exhibit 1-3, illustrates the magnitude of the change thatrestructuring is playing, as well as environmentalregulation discussed previously. According to EIA’sAEO2001, coal is projected to maintain its lead in theproduction of electricity in 2010 at 50 percent;however, that is down from 60 percent when the CCTProgram started. The differential has been, for themost part, made up by the growth in natural gas powergeneration. Nuclear power’s contribution to thenation’s electric power generation in 2010 is expectedto drop by almost 30 percent between the 1985 and2000 projections.Industry restructuring and competition will impactcoal and coal technologies for the foreseeable future.Utilities are expected to improve their operatingefficiencies by using existing plants at higher capacity

factors. Contributing to increased capacity factors is aprojected drop in generating capacity not only fromnuclear plant retirements but capacity losses wherestranded costs are not recovered. The EIA hasprojected that the capacity factor for coal-fired powerplants will increase from 68 percent in 1998 to 83percent in 2020. EIA further predicts that nearly 22GW of new coal-fired capacity is expected to come online between 1999 and 2020, accounting for almost 6percent of capacity expansion. During this time, newhighly efficient low-emissions power systems willenter the power production markets. New concepts toreduce delivered electricity prices will likely beemployed. Examples include minemouth plants thatreduce or eliminate the coal transportation costcomponent in power production. Also, cogenerationand coproduction systems will be available, whichallow the consumer’s cost of electricity to be offset bythe profitability of coproducts.

Ensuring SuEnsuring SuEconomic GEconomic G

It is in the national inteenergy mix to sustain is a key component of because of its affordabdance within the natioProgram’s strategy leadeployment of a technthe efficient use of thithat national and globachieved. The domesenough to supply U.Sat current rates of proThe United States is iimported oil as low prdomestic oil productio
1-10 Program Update 2000

broken in 1995 by an oil production capacity increaseof 0.4 million barrels per day. In 1998, net petroleumimports were 9.8 million barrels per day, or 51 percentof domestic consumption. The AEO2001 reference

case for 2020 calls for net imports of 12.14 millionbarrels per day, which is over 70 percent of the totalcrude supply. Also, natural gas imports are expectedto grow from 14.0 percent of total gas consumption in1998 to 16.7 percent in 2020. These imports areprimarily from Canada, which does not represent asupply stability problem, but does represent a drainon balance of payments.United States coal consumption is equivalent toapproximately 3.6 billion barrels of oil per day, whichwould equate to $44 billionper year. The CCTProgram will provide thetechnologies that willenable coal to continue asa major component in thenation’s economy whileachieving the environmental quality that societydemands. The domesticand export value of 1998coal production approaches $60 billion in theU.S. economy. Coalrelated jobs are dispersedthrough the mining,transportation, manufacturing, utility, and supporting industries.A U.S. coal conversionindustry could directlyreduce the nation’sdependency on importedoil. The economic impact

of adding to domestic oil production or reducing thecost of imported oil is very significant. The CCTProgram is responding to this opportunity throughdevelopment and demonstration of mild gasificationand liquid-phase methanol production technologies.According to EIA’s AER1999, the U.S. exported 78million tons of coal in 1998. Coal exports to foreigndestinations contributed $2.91 billion to the U.S.balance of trade in 1998. Worldwide demand forenergy is expected to reach 608 quadrillion Btu by2020, approximately 1.6 times the current level.According to the EIA, worldwide coal use in 1997accounted for about 24 percent of total energyconsumption and 36 percent of the energy consumed

worldwide for electricitshares are not projected through 2020.According to the latest wide market for power be as high as $80 billion of the investment will bThis market provides opogy suppliers, developeother U.S. firms to capithrough experiences in taggressive action is neerecognizing the enormoeconomies can enjoy if greater share of this maBeyond the CCT Progracreating a favorable expcoal technology. These the visibility of U.S. firmestablishing an informaliaison with U.S. represstrengthening interagenprograms pertinent to thcurrent programs and pfinancing of coal-relate

Looking to tLooking to t

Power Plant Impro

The rapid growth in powdemand, coupled with tthe electric power indugrowing concern over telectricity grid. This co

Vision 21 modules can be combined in a variety of configurations. One example, shownabove, incorporates modules to produce a variety of energy products.
Exhibit 1-4

Vision 21 Objectives

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

elements, and organic compounds; 40-50% reduction in CO2 emissions by

efficiency improvement; 100% reduction with sequestration.

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

plants must be cost-competitive with market clearing prices.

Timing Major spinoffs such as improved gasifiers, advanced combustors, hightemperature filters and heat exchangers, and gas separation membranes begin by

2004; designs for most Vision 21 subsystems and modules available by 2012;Vision 21 commercial plant designs available by 2015.

aThe efficiency goal for a plant co-feeding coal and natural gas will be calculated on a pro-rata basis. Likewise, the efficiency goal for a plant

producing both electricity and fuels will be calculated on a pro-rata basis

add $95 million to the Office of Fossil Energy budgetfor fiscal year 2001.Coal power plants are a significant part of the nation’sgenerating capacity, currently accounting for morethan 51 percent of the country’s electricity production.The Power Plant Improvement Initiative, approved byCongress in the Department of the Interior andRelated Agencies Appropriations Act for FY 2001, willhave a near-term focus on improving the efficiencyand environmental performance of coal-fired powergeneration. New technologies will be demonstratedthat can boost the efficiency of a power plant,increasing the amount of electricity it can generate;reduce air emissions; or perhaps a combination ofboth.The initial program will apply to existing and new coalbased, central power plants. Later, the program could

include a wider span of more flexible generationtechnologies such as fuel cells and turbines that canoperate on natural gas as well as coal.The initiative will be a cost-shared, public-privatepartnership that will retain the guidelines of the CCTProgram. For example, projects will be chosen competitively and must be supported by at least 50 percentfunding from the private sector. Repayment provisionswill be incorporated to return proceeds to the government from both domestic and international technologysales. The government’s share of funding will bedirected at the higher risk aspects of a demonstrationproject.There will also be additional guidelines that limit themaximum amount the government will fund in anyparticular project. Current plans are for the government to cost-share multiple projects from the initial

solicitation. The deparfeasibility of additioncongressional appropCongressional guidelispecify that technologenable power plants to reduces environmentaefficiency in operationother emissions, remaresponds quickly to chtechnologies could applants including co-prplants that produce hefuels, and new technoof coal fines into the fThe Department of Ensolicitation December first projects are expecber 30, 2001.

Vision 21 ision 21ision 21

The CCT Program is pto build a future generpower systems capablenvironmental demanhardware and attendafor power, environmetogether can meet the Fossil Energy’s Coal & These “Vision 21” goa1-4. The expected resmodules capable of usbiomass; and forestry, refinery wastes) to provalue commodities (elchemicals) at greater tnear-zero emissions.
1-12 Program Update 2000

First-generation systems emerging from the CCTProgram provide: (1) the knowledge base from whichto launch 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, artificially intelligent controls and sensors, and CO2 and hydrogenseparation technologies. A strategy of the Vision 21effort is to develop and spin off such key componentsto mitigate the risk and cost of integrating the technologies into power, environmental, and fuel systemmodules.
2. Program Implementation ogram Implementation

Introduction oductionoduction oductionoductionThe CCT Program founding principles and implementing process resulted in one of the most successful costshared government/industry partnerships forged torespond to critical national needs. Through fivenationwide competitions, a total of 60 government/industry cost-shared projects were selected, of which38, valued at more than $5.2 billion either have beencompleted or remain active at the end of fiscal year2000. For the 38 projects, the industry cost-share is anunprecedented 66 percent. Sixty-eight percent (26) ofthe projects have successfully completed operations.The balance are moving forward, with operationaltesting under way for five projects.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 thedegree to which the operational, environmental, andeconomic performance of a technology can be projected for commercial applications. Decision makersmust have a sufficient database to project performanceand assess risk for commercial introduction and

deployment of new technologies. This need forinformation was a driving force in establishing theprinciples that created the foundation for the implementation process. The government role is nontraditional, moving away from a command-and-controlapproach to a performance-based approach, where thegovernment sets performance objectives and industryresponds with its ideas and is allowed broad latitude intechnical management of the projects. This approachencourages technology innovation and cost-sharing.Industry and the public play major roles in the process,reflecting their respective roles in moving technologiesinto the marketplace.

Implementation Principles Implementation Principles

The principles underlying the CCT Program weredeveloped after much study of previous governmentdemonstration programs, assessing both positive andnegative results. The principles represent a compositeof incentives and checks and balances that allows allparticipants to best apply their expertise and resources.These guiding principles are outlined below.• A strong and stable financial commitment exists

for the life of the projects. ojects. ojects. Full funding for thegovernment’s share of selected projects wasappropriated by Congress at the start of the program. This up-front commitment has been vital togetting industry’s response in terms of quantity andquality of proposals received and the achievementof 66 percent cost-sharing.

• Multiple solicitatio

years enabled the range of national nrange of national nevolving technologevolving technolog

solicitations enablethe program to meeprovided DOE time process based on letions; and provided develop better projepropose evolving te

• Demonstrations ar

scale in actual use

technology is constfull system integratcommercial configucommercial facility commercial facilityperformance potentcommercial environ

• The technical agen

and not the governand not the govern

lished by Congress DOE set definitive performance-based proposals would be flexibility to use thedefine the technoloresponse to the objeDepartment of Enermet the evaluation c
2-2 Program Update 2000

• Roles of the government and industry are clearly e clearlye clearly

defined and reflect the degree of cost-sharing

required. The government plays a significant role

up 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 governmentoversees the project through aggressive monitoringand engages in implementation only at decisionpoints. Continued government support is assured aslong as project milestones and the terms andconditions of the original cooperative agreementcontinue to be met.

• At least 50 percent cost-sharing by industry is

required throughout all project phases. oject phases.

Industry’s cost-share was required to be tangibleand directly 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 project objectives was strengthened.

• Allowance for cost gr cost gr cost growth pr owth provides an important check-and-balance feature to the pr e to the pre to the program.

Statutory provisions allow for additional financialassistance beyond the original agreement in anamount up to 25 percent of DOE’s original contribution. Such financial assistance, if provided, mustbe cost-shared by the industrial participant at no lessthan the cost-share ratio of the original cooperativeagreement. This statutory provision recognizes therisk involved in first-of-a-kind demonstrations byallowing for cost growth. At the same time, itrecognizes the need for the industrial participant’s

commitment to share cost growth and limits thegovernment’s exposure.

• Industr Industry retains r etains retains real and intellectual property

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

• Industry must make a commitment to commer- Industry must make a commitment to commercialize the technology. Consistent with program

goals, the industrial participant is required to makethe technology available on a nondiscriminatorybasis, under reasonable terms and conditions, to allU.S. companies that seek to use the technology.While the technology owner is not forced to divulgeknow-how to a competitor, the technology must bemade available to potential domestic users onreasonable commercial terms.

• Upon successful commercialization of the

technology technologytechnology, repayment up to the government’ epayment up to the government’scost-shar cost-sharcost-share is required. The repayment obligation

occurs 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 and government roles are appropriate and that the governmentserves as a risk-sharing partner without impedingindustry from using its expertise and getting thetechnology into the marketplace.

ImplementatImplementat

Significant public and printegral to the process lestration and critical to prengaging in a solicitationinstituted under the Nati(NEPA) to review the enprogrammatic environm(PEIA), followed by a primpact statement (PEIS)initiating solicitations. Pof comments were requithe program.As to the solicitation profor each solicitation in threport language (see Appand Appendix B for progThe Department of Energuidance and direction inand developed approachfrom previous solicitatiosolicitation, however, an solicitation and attendanpresented in a series of robtain feedback. The pualong the lines of workshand obtain comments frointerests. Comments frowere used in preparing a turn was issued for publireceived were formally rissuance.To aid proposers, preprofor the purpose of clarifytion. Further, every attem
tion to impart a clear understanding of what was beingsought, how it would be evaluated, and what contractual terms and conditions would apply. A section ofthe solicitation was devoted to helping potentialproposers determine technology eligibility, andnumerical quantification of the evaluation criteria wasprovided. The solicitation also contained a modelcooperative agreement with the key relevant contractual 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 Environmental Policy Act requires that a rigorous environmentalassessment 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, with emphasis on potential environmental, health, safety, andsocioeconomic 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 data

collection 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 on satisfyingusers and the public as to acceptable environmentalperformance. Appendix C reviews the proactiveenvironmental stance taken by the program, further

delineates the NEPA prkey actions.Projects are managed bgovernment. Howeverby requiring defined peas budget periods, throperiods are keyed to mamount of funds is alloalong with performancreceiving funds for the criteria are contained in (PEPs). Progress reporperiods serve to keep thdecision points, progreevaluated, as is the PEP Financial data is also epants’ capability to conFailure to perform as egovernment involvemeprocess. Proposal of mtates not only in-depth 

legal and procurement regarding continuance any increase in fundingrequire the approval of Fossil Energy.Beyond the formal prosolicitations, parallel estakeholders of ongointo engage them in discensuring that the progrneeds. A continuing dinvolvement in the proutilities, technology sukey industry-based res

Electric Power ResearInstitute). This was acseminars designed to e

The NEPA process assured environmental acceptability ofthe Healy Clean Coal Project on the border of Denali NationalPark in Alaska.
2-4 Program Update 2000

the utility, independent power producer, regulatory,insurance underwriter, and financial sectors. Theapproach was to identify those sectors where inputswere missing and then structure seminars to provideinformation on the program and obtain the executives’perspectives and suggestions for enhancing programperformance. Furthermore, a periodic CCT Conference was instituted to serve as a forum for reportingproject progress and results and discussing issuesaffecting the outcome of the CCT Program. And, anoutreach program was put in place to ensure thatneeded information was prepared and disseminated inthe most efficient manner, leveraging a variety ofdomestic and international conferences, symposia, andworkshops. These activities are discussed in furtherdetail in Section 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 business arrangements of multimillion dollar CCT projects is a significant asset that has contributed greatly to the CCTProgram’s success—an asset of value to other programs seeking to forge government/industry partnerships. To document lessons learned, Clean Coal

Technology Program Lessons Learned was published

in July 1994. This report documents the knowledgeacquired over the course of the CCT Program throughthe completion of five solicitations. The report wasbased on the belief that it is of mutual advantage to theprivate and public sectors to identify those factorsthought to contribute to the program’s success and topoint out pitfalls encountered and corrective actionstaken.

Commitment to Commer Commitment to Commercial

Realization RealizationRealization RealizationRealization

The CCT Program has been committed to commercialrealization since its inception. The significant environmental, operational, and economic benefits of thetechnologies being demonstrated in the program willbe realized when the technologies achieve widespreadcommercial success. The importance attached tocommercial realization of clean coal technologies ishighlighted in Senate Report 99-82, which contains thefollowing recommendation for project evaluationcriteria: “[t]he project must demonstrate commercialfeasibility of the technology or process and be ofcommercial scale or of such size as to permit rapidcommercial scale-up.”The commitment to commercial realization recognizesthe complementary but distinctive roles of the technology owner and the government. It is the technologyowner’s role to retain and use the information andexperience gained during the demonstration and topromote the use of the technology in the domestic andinternational marketplaces. The detailed operational,economic, and environmental data and the experiencegained during the demonstration are vital to efforts tocommercialize the technology. The government’s roleis to capture, assess, and transfer operational, economic, and environmental information to a broadspectrum of the private sector and internationalcommunity. The information must be sufficient toallow potential commercial users to confidently screenthe technologies and to identify those meeting operational requirements. 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 solicitatfor the project proposals commercialization plans the participants. The prothe following topics:• The critical factors re

deployment, such as fing, manufacturing, a

• A timetable identifyin

goals and schedule fo

Pressurized fluidized-bed cat Ohio Power Company’s Tcommercialization.
• Additional requirements for demonstration of the

technology at other operational scales, as well assignificant planned parallel efforts to the demonstration project, that may affect the commercializationapproach or schedule; and

• The priority placed by senior management on

accomplishing 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:• The commercialization clause requires the technology owner to meet U.S. market demands for the

technology on a nondiscriminatory basis (this clause“flows down” from the project participant to theproject team members and contractors);

• The clauses concerning rights to technical data deal

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

• The patent clause affords protection for new

inventions developed in the project.

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

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

• Provide potential domestic and foreign users of the

technologies with the information needed fordecision making;

• Inform financial institutions and insurance underwriters about the advancements in technology and

associated risk mitigation to increase confidence;and

• Provide customers and stakeholders opportunities

for feedback on program direction and informationrequirements.

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

Solicitation Results Solicitation Results

Each solicitation was issued as a Program OpportunityNotice (PON)—a solicitation mechanism for cooperative agreements where the program goals and objectives are defined but thetechnology is not. Proposals for demonstrationprojects consistent with theobjectives of the PON weresubmitted to DOE byspecific deadlines. DOEevaluated, selected, andnegotiated projects strictlywithin the bounds of thePON provisions. Awardwas made only afterCongress was allowed 30in-session days to considerthe projects as outlined in a

Exhibit 2-1

CCT Program Selection Pr

Proposals ProposalsProposals 

Solicitation PON Issued Submitted SubmittedSubmitted 

CCT-I February 17, 1986 51 CCT-II February 22, 1988 55 CCT-III May 1, 1989 48 CCT-IV January 17, 1991 33 CCT-V July 6, 1992 24 

211 

Comprehensive Report solicitation.Exhibit 2-1 summarizeExhibit 2-2 identifies thProgram and the solicitwere selected. Appendprocurement history anselection, negotiation, termination. Project sithrough 2-6, which indprojects by application The resultant projects hsupport. Team membethan 50 utilities; more tand more than 20 enginconsulting firms. OtheElectric Power ResearcInstitute, numerous staauthorities, industrial mAmerican tribe.
2-6 Program Update 2000

Project and Participant Locatio

Locatio

Locatio

CCT-IDevelopment of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc. and CQ Inc.) Homer CLIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) Lorain, O

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) WilliamsEnhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Hennepi

Tidd PFBC Demonstration Project (The Ohio Power Company) BrilliantAdvanced Coal Conversion Process Demonstration (Western SynCoal LLC) Colstrip, Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) Nucla, CJEA Large Scale CFB Combustion Demonstration Project (JEA) Jacksonv

CCT-IISNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) Niles, O

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

SO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Dilles B

Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) ThomastAdvanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) ChestertDemonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Coosa, GDemonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) NewnanDemonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High-Sulfur, Coal-Fired Boilers Pensacol

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

Boilers (Southern Company Services, Inc.)

CCT-III CCT-III CCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Kingspo

Company, L.P.)10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) West PadHealy Clean Coal Project (Alaska Industrial Development and Export Authority) Healy, AFull-Scale Demonstration of Low-NO

x Cell Burner Retrofit (The Babcock & Wilcox Company) Aberdee

Exhibit 2-2

Clean Coal Technology Demonstration Projects by Solicitation
CCT-III (continued)

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) SewardBlast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) Burns 

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland Electric) LakelaENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Gillette

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

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

Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Mulber

CCT-IVMicronized Coal Reburning Demonstration for NOx Control (New York State Electric & Gas Corporation) Lansin

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) LansinPiñon Pine IGCC Power Project (Sierra Pacific Power Company) Reno, N

Pulse Combustor Design Qualification Test (ThermoChem, Inc.) BaltimWabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) West T

CCT-VClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) Fairban

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management Company LLC) VineyaKentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) Trapp, McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, Lakeland Electric) Lakela

Project and Participant Locat

Locat

Locat

Exhibit 2-2 (continued) Exhibit 2-2 (continued)

Clean Coal Technology Demonstration Projects by Solicitation
2-8 Program Update 2000

S

Public Service Company

of ColoradoDenver, CO

Energy and Environmental

Research Corporation

Denver, CO

Energy and Environmental

Research Corporation

Hennepin and Springfield, IL

Exhibit 2-3

Geographic Locations of CCT Projects—Environmental Control Devic

AirPol, Inc.

West Paducah, KY

The Babcock & Wilcox

Company

Cassville, WI

Pure Air

on the Lake, L.P.

Chesterton, IN

New York State Electric & Ga

Lansing and Rocheste

The Babcock & Wilcox

Company

Lorain, OH

T

T

S

SS
Alaska Industrial

Development and

Export Authority

Healy, AK

Kentuck

Wabash River Coal Gasification

Repowering Project Joint Venture

West Terre Haute, IN

The Ohio Power Company

Brilliant, OH

Exhibit 2-4

Geographic Locations of CCT Projects—Advanced Electric Power Gene

Sierra Pacific

Power Company

Reno, NV

Tampa Electric Company

Mulberry, FL

Tri-State Generation

and Transmission

Association, Inc.

Nucla, CO

City of 

Lakel

(2 pr

Arthur D. Little, Inc.

Fairbanks, AK

JEA

Jacksonville
2-10 Program Update 2000

Rosebud SynCoal

Partnership

Colstrip, MT

ENCOAL Corporation

Gillette, WY

Engine

Exhibit 2-5

Geographic Locations of CCT Projects—Coal Processing for Clean Fu
CPICORTM Management

Company, L.L.C.

Vineyard, UT

Bethlehem Steel Corporation

Burns Harbor, IN

Exhibit 2-6

Geographic Locations of CCT Projects—Industrial Applications

P

C

Therm

Bal
2-12 Program Update 2000

The contributions of the selected projects to domesticand international energy and environmental needs aresignificant. These contributions include:• Completing demonstration and proving commercial

viability of a suite of cost-effective SO2 and NOxcontrol options capable of achieving moderate (50percent) to deep (70–95 percent) emission reductionfor the full range of coal-fired boiler types;

• Providing the database and operating experience

requisite to making atmospheric fluidized-bedcombustion a commercial technology at utility scale;

• Completing demonstration of a number of coal

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

• Laying the foundation for the next generation of

technologies to meet the energy and environmentaldemands of the 21st century—three IGCC plants are

in 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 pollutant

emission reduction enhancements in steel making,advanced combustion for combined SO2/NOx/PMcontrol for industrial and small utility boilers, andinnovative SO2 control for waste elimination in

cement production.

Future Implementation e ImplementationDirection

The 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 2001, the following projects are forecasted to complete operations:• Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler,• Piñon Pine IGCC Power Project,• Advanced Coal Conversion Process Demonstration,

and

• Pulse Combustor Design Qualification Test.

The body of knowledge Program demonstrationdecision making relative forging plans for meetinmental demands, and detechnology responsive tenvironmental performaexpanded portfolio of into make it easier for stakthrough the already enofrom the demonstrationsEfforts will continue towin responding to customToward that end, as neesought to obtain feedbacrestructuring, continued burgeoning foreign marthat CCT Program efforfollow-on efforts under opment, and Demonstra

Comprehensive Report to Congress was issued after each

solicitation for each selected project.
3. Funding and Costs 3. Funding and Costs 3. Funding and Costs

Introduction oductionoduction oductionoductionCongress 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 30,2000, the program consisted of 38 active or completedprojects. These 38 projects have resulted in acombined commitment by the federal government andthe private sector of $5.2 billion. DOE’s cost-sharefor these projects exceeds $1.7 billion, or approximately 34 percent of the total. The project participants (i.e., the non-federal-government participants)

are providing the remaining $3.4 billion, or 66 percentof the total. Exhibit 3-1 summarizes the total costs ofCCT projects as well as cost-sharing by DOE andproject participants. The data used to prepare Chapter3 is based on the 38 projects that were active in theCCT Program as of September 30, 2000.

Program Funding ogram Funding

General Provisions General Provisions

In the CCT Program, the federal government’scontribution cannot exceed 50 percent of the total costof any individual project. The federal government’sfunding commitments and other terms of federalassistance are represented in a cooperative agreement

Exhibit 3-1

CCT Project Costs and Cost-Sha

(Dollars in Thousands) (Dollars in Thousands)

Total Cost-Share Dollars 

Project Costs

% DOEb Participan

Subprogram

CCT-I 844,363 16 239,640 604,723 CCT-II 318,577 6 139,229 179,348 CCT-III 1,325,329 26 576,918 748,411 

CCT-IV 950,429 18 439,063 511,366 CCT-V 1,765,009 34 360,982 1,404,027  Totala 5,203,707 100 1,755,832 3,447,875 

Application Category

Advanced Electric Power 2,864,284 55 1,118,865 1,745,419 GenerationEnvironmental Control Devices 620,110 12 252,866 367,244 Coal Processing for Clean Fuels 431,810 8 192,029 239,781 Industrial Applications 1,287,503 25 192,072 1,095,431  Totala 5,203,707 100 1,755,832 3,447,875 

aTotals may not add due to rounding.bDOE share does not include $99,581,000 obligated for withdrawn projects and audit expenses.
3-2 Program Update 2000

Innovation Developmerole for small, innovatiand development (R&Dimplements the Small BAct of 1992 that establfunding for small busincooperative R&D efforThe CCT program diremanagement and adminand includes federal emtravel, site support servnational laboratories an

Availability of Fun

Although all funds neceCCT Program were appFY1990, the legislation be made available (i.e., 

time-phased basis. Exhment of funding to DOprogram’s yearly fundiand by subprogram. Fusubprogram budgets to needs.

Use of Appropriate

Use of Appropriate

There are five key finangovernment to track the funds: (1) budget authoobligations, (4) costs, adefinition of each of th• Budget Authority AuthorityAuthority. 

created by legislatio

that permits the fedefunds.

Through these activities, the federal governmentensures the efficient use of public funds in theachievement of individual project and overall programobjectives.Congress has provided program funding throughappropriation acts and adjustments. (See Appendix Afor legislative history and excerpts from the relevantfunding legislation.)Exhibit 3-2 presents the allocation of appropriatedCCT Program funds (after adjustment) and the amountavailable for each CCT solicitation. Additionalactivities funded by CCT Program appropriations arethe Small Business Innovation Research (SBIR)Program, the Small Business Technology Transfer(STTR) Program, and CCT Program direction. TheSBIR Program implements the Small Business

negotiated for each project in the program. Terms ofthe cooperative agreement also include a plan for thefederal government to recoup up to the full amount ofthe federal government’s contribution. This approachenables taxpayers to benefit from commerciallysuccessful projects. This is in addition to the benefitsderived from the demonstration and commercialdeployment of technologies that improve environmental quality and promote the efficient use of the nation’scoal resources.The project participant has primary responsibility forthe project. The federal government monitors projectactivities, provides technical advice, and assessesprogress by periodically reviewing project performance with the participant. The federal governmentalso participates in decision making at major projectjunctures negotiated into the cooperative agreement.

Exhibit 3-2

Relationship Between Appropriations and Subprogram Budgets

for the CCT Program

(Dollars in Thousands) (Dollars in Thousands)

SBIR Program Program

Appropriation Adjusted AdjustedAdjusted & STTR Direction DirectionDirection Projects ProjectsProjects

Enacted Enacted Subprogram Appropriations Budgets Budgetsa Budget Budget

P.L. 99-190 CCT-I 380,600 4,902 115,767 259,931

P.L. 100-202 CCT-II 473,959 6,781 32,512 434,666P.L. 100-446 CCT-III 574,998 6,906 22,548 545,544

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 2,211,557 31,081 220,827 1,959,649

aSmall Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs.bP.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, and 106-291.
Exhibit 3-3

Annual CCT Program Funding by Appropriations and Subprogram Bu

(Dollars in Thousands) (Dollars in Thousands)

Fiscal Year 1986–91 1986–91 1992e 1994e 1995 1996 1997 1998 1999 2000 Adjusted Appropriationsa

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

P.L. 100-202 574,997 (101,000) (40,000) 9,962 P.L. 100-446 574,998 (156,000) 1

P.L. 101-121b 35,000 315,000 100,000 18,000 50,000 (91,000) (16

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

 Total 1,582,595 415,000 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 

Subprogram Budgets

CCT-I Projects 387,231 (18,000) (18,000) (33,000) (15,000) (14,900) (14,400) (1

CCT-II Projects 535,704 (101,000) (40,000) 9,962 

CCT-III Projects 545,544 (156,000) 1

CCT-IV Projects 9,875 311,063 98,450 17,622 48,925 (91,000) (16CCT-V Projects 74,062 123,063 18,719 97,850 105,879  Projects Subtotal 1,478,354 385,125 221,513 18,341 128,775 (18,121) (116,000) (54,900) (160,438) (Program Direction 85,527 25,000 18,000 18,000 16,000 15,000 14,900 14,400 

 Fossil Energy Subtotal 1,563,881 410,125 221,513 36,341 146,775 (2,121) (101,000) (40,000) (146,038) SBIR & STTRc 18,714 4,875 3,487 779 3,225 

 Totald 1,582,595 415,000 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 

aShown are appropriations less amounts sequestered under the Gramm-Rudman-Hollings Deficit Reduction Act.bShown 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, 10cSmall Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs.dTotals may not appear to add due to rounding.eNo changes were made to funding amounts in 1993.
3-4 Program Update 2000

to proceed with each major phase of project implementation.The overall financial profile for the CCT Program ispresented in Exhibit 3-4. The graph shows actualperformance for FY1986 through FY1999 and DOEestimates for FY2000 through program completion.Excluded from the graph are SBIR and STTR funds,as these are used and tracked separately from the CCTProgram. The financial projections presented inExhibit 3-4 are based on individual project schedulesand budget periods as defined in the cooperativeagreements and modifications. The negative BudgetAuthority values shown in Exhibit 3-4 result fromrescission of $101 million in FY1998, the deferral of$40 million in FY1999, and the deferral of $146million in FY2000.The financial status of the program throughSeptember 30, 2000, is presented by subprogram inExhibit 3-5. SBIR andSTTR funds are included inthis exhibit to account forall funding. Exhibit 3-5also indicates the apportionment sequence asmodified by Public Law106-291. These valuesrepresent the amount ofbudget authority availablefor the CCT Program.

Project Funding, Project Funding,

Costs, and Schedules Costs, and Schedules

Information for individualCCT projects, includingfunding and the status ofkey milestones, is providedin Section 5. An overview

• Commitments. Commitments. Within the context of the CCT

Program, 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.

• Obligations. Obligations. The cooperative agreement for each

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

• Costs. A request for payment submitted by the

project participant to the federal government forreimbursement of tasks performed under the termsof the cooperative agreement is considered a cost.Costs are equivalent to a bill for payment orinvoice.

• Expenditur ExpenditurExpenditures. Expenditures represent payment

amounts to the project participant from checksdrawn upon the U.S. Treasury.

The full government cost-share specified in thecooperative agreement is considered committed toeach project. However, DOE obligates funds for theproject in increments. Most projects are subdividedinto several time and funding intervals, or budgetperiods. The number of budget periods is determinedduring negotiations and is incorporated into thecooperative agreement. DOE obligates sufficientfunds at the beginning of each budget period to coverthe government’s cost-share for that period. Thisprocedure limits the government’s financial exposureand assures that DOE fully participates in the decision

Exhibit 3-4

CCT Financial Proje

as of September 30

a Includes changes resulting from P.L. 106-291.

of project schedules and Exhibits 3-6 and 3-7.

Cost-SharinCost-Sharin

A characteristic feature cooperative funding agrpant and the federal govsharing. This cost-sharin the CCT Program, w99-190, An Act Making Department of the Interthe Fiscal Year Ending Other Purposes. Gener

-200,000-100,000

0

100,000200,000300,000400,000500,000600,000

86 87 88 89 90 91 92 93 94 95 96 97 98 

Fiscal Year

Dollars x 1,000

Budget Authority Costs 
 Appropriations Allocated to Apportioned Committed Obligated Obligated Obligated Cost

Subprogram Subprogramb to Date to Date to Date to Date to Date to Date to Date to Date to Date to Date

1986 91987 14

1988 19

1989 19

1990 551991 391992 411993 1994 221995 31996 151997 (1998 (101999 (42000 (142001 2002 8

CCT-I 259,931 259,931 257,126 257,126 193,291CCT-II 434,666 419,666 165,370 165,370 164,944CCT-III 545,544 545,544 592,307 592,307 479,495CCT-IV 299,935 232,935 477,428 477,428 472,337CCT-V 419,573 419,573 363,182 148,331 19,521 Projects Subtotal 1,959,649 1,877,649 1,855,413 1,640,562 1,329,588SBIR & STTRa 31,081 31,081 31,081 31,081 31,081

Program Direction 220,827 220,827 220,827 205,837 203,281 Total 2,211,557 2,129,557 2,107,321 1,877,480 1,563,950

Apportionment Se

FY A

aSmall Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) ProgramsbTotals may not appear to add due to roundingcIncludes changes from P.L. 106-291

Exhibit 3-5

Financial Status of the CCT Program as of September 30, 2000c

(Dollars in Thousands) (Dollars in Thousands)
3-6 Program Update 2000

Exhibit 3-6

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

CCT Project Schedules by Application Category
3-8 Program Update 2000

Exhibit 3-7

CCT Project Funding by Application Category

Project Project DOE % Participant 

Environmental Control Devices

SO2 Control Technologies10-MWe Demonstration of Gas Suspension Absorption 2,315,259 30.0 5,401,930 Confined Zone Dispersion Flue Gas Desulfurization Demonstration 5,205,800 50.0 5,205,800 LIFAC Sorbent Injection Desulfurization Demonstration Project 10,636,864 49.7 10,756,908 Advanced Flue Gas Desulfurization Demonstration Project 63,913,200 42.1 87,794,698 Demonstration of Innovative Applications of Technology for the CT-121 FGD Process 21,085,211 49.0 21,989,785 

Subtotal SO2 Control Technology 103,156,334 44.0 131,149,121 

NO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 6,553,526 41.3 9,300,374 Demonstration of Coal Reburning for Cyclone Boiler NOx Control 6,340,787 46.5 7,305,822 

Full-Scale Demonstration of Low-NO

x

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

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

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

Demonstration of Selective Catalytic Reduction Technology 9,406,673 40.5 13,823,056 

for the Control of NO

x Emissions from High-Sulfur, Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion 4,149,383 48.5 4,404,282 

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

Subtotal NO

x Control Technology 43,489,970 43,489,97043,489,970 43.7 55,931,069 55,931,06955,931,069 

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project 15,719,200 50.0 15,719,208 LIMB Demonstration Project Extension and Coolside Demonstration 7,591,655 39.3 11,719,378 SO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstration Project 6,078,402 45.8 7,193,219 

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection 18,747,816 49.9 18,841,139 Milliken Clean Coal Technology Demonstration Project 45,000,000 28.4 113,607,807 Integrated Dry NOx/SO2 Emissions Control System 13,082,653 50.0 13,082,653 

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

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

CCT Project Funding by Application Category

Project Project DOE % Participant 

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project 93,252,864 50.0 93,335,136 McIntosh Unit 4B Topped PCFB Demonstration Project 109,608,507 49.9 110,027,039 JEA Large-Scale CFB Combustion Demonstration Project 74,733,833 24.2 234,362,679 Tidd PFBC Demonstration Project 66,956,993 35.3 122,929,346 Nucla CFB Demonstration Project 17,130,411 10.7 142,919,538 

Subtotal Fluidized-Bed Combustion 361,682,608 34.0 703,573,738 

Integrated Gasification Combined-Cycle

Kentucky Pioneer Energy IGCC Demonstration Project 78,086,357 18.1 353,846,225 Piñon Pine IGCC Power Project 167,956,500 50.0 167,956,500 Tampa Electric Integrated Gasification Combined-Cycle Project 150,894,223 49.8 152,394,223 Wabash River Coal Gasification Repowering Project 219,100,000 50.0 219,100,000 

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

Advanced Combustion/Heat Engines

Clean Coal Diesel Demonstration Project 23,818,000 50.0 23,818,000 Healy Clean Coal Project 117,327,000 48.5 124,731,000 

Subtotal Advanced Combustion/Heat Engines 141,145,000 48.7 148,549,000 

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

Coal Processing for Clean Fuels

Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process 92,708,370 43.4 120,991,630 Advanced Coal Conversion Process Demonstration 43,125,000 40.8 62,575,000 Development of the Coal Quality ExpertTM 10,863,911 50.0 10,882,093 ENCOAL® Mild Coal Gasification Project 45,332,000 50.0 45,332,000 

Total Coal Processing for Clean Fuels 192,029,281 44.5 239,780,723 

Industrial Applications

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) 149,469,242 14.0 916,335,758 

Pulse Combustor Design Qualification Test 4,306,027 50.0 4,306,027 Blast Furnace Granular-Coal Injection System Demonstration Project 31,824,118 16.4 162,477,672 Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 490,122 49.8 494,272 

Cement Kiln Flue Gas Recovery Scrubber 5,982,592 33.6 11,817,408 

Total Industrial Applications 192,072,101 14.9 1,095,431,137 

Grand Total Grand Total 1,755,832,100 33.7 3,447,875,140 
3-10 Program Update 2000

of the cost-sharing principle as applied to the CCTProgram include the following elements:• The federal government may not finance more than

50 percent of the total costs of a project;

• Cost-sharing by the project participants is required

throughout the project (design, construction, andoperation);

• The federal government may share in project cost

growth (within the scope of work defined in theoriginal cooperative agreement) up to25 percent of the originally negotiated governmentshare of the project;

• The participant’s cost-sharing contribution must

occur as project expenses are incurred and cannotbe offset or delayed based on prospective projectrevenues, proceeds, or royalties; and

• Investment in existing facilities, equipment, or

previously expended R&D funds are not allowedfor the purpose of cost-sharing.

As previously discussed, Exhibit 3-1 summarizes thecost-sharing status by subprogram and by applicationcategory for the 38 active or completed projects. Inthe advanced electric power generation category,which accounts for 55 percent of total project costs,participants are contributing 61 percent of the funds.Cost-sharing by participants for environmental controldevices, coal processing for clean fuels, and industrialapplications categories is 59 percent, 56 percent, and85 percent, respectively. For the overall program,participants are contributing 66 percent of the totalfunding, or nearly $1.7 billion more than the federalgovernment.

Recovery of Government Recovery of GovernmentOutlays (Recoupment) Outlays (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 planoutlining a proposed schedule for recovering thegovernment’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 torevenues realized from the future commercializationof the demonstrated technology. The government’sshare would be 2 percent of gross equipment sales and3 percent of the royalties realized on the technologysubsequent to the demonstration.The CCT-III repayment formula was adjusted to 0.5percent of equipment sales and 5 percent of royalties.Limited grace periods were allowed on a project-byproject basis. A waiver on repayment may be soughtfrom the Secretary of Energy if the project participantdetermines that a competitive disadvantage wouldresult in either the domestic or international marketplace. The recoupment provisions for CCT-IV andCCT-V were identical to those inCCT-III.As of September 30, 2000, six projects have maderepayments to the federal government: Nucla CFBDemonstration Project (Tri-State Generation andTransmission Association, Inc.); Full-Scale Demonstration of Low-NOx Cell Burner Retrofit (The

Babcock & Wilcox ComCoal Quality ExpertTM ing, Inc. and CQ Inc.); Suspension Absorption Flue Gas DesulfurizatioAir on the Lake, L.P.); Gasification RepowerinIn September 1997, the report entitled Recoupm

Coal Technology Demo

report: (1) reviewed the ment during the implem(2) addressed recommeGeneral Accounting Of17, GAO Report RCEDGeneral Audit Report Iand (3) provided input recoupment policy.
4. CCT Program Accomplishments Accomplishments Accomplishments

Introduction oductionoduction oductionoduction

The CCT Program’s continued success is exemplifiedby the following demonstrations completing operationin fiscal year 2000:• Wabash River Coal Gasification Repowering

Project, and

• Healy Clean Coal Project.These completed projects, along with the other 36active 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 electricutility restructuring have on the demand for clean coaltechnologies. Internationally, activities includeparticipating in international conferences and workshops, furnishing information on clean coal technologies, and providing technical support to trade agencies, trade missions, and financial organizations. Throughout the 2000 fiscal year, the CCT Program staff participated in over a dozen domestic and international events involving users and vendors of clean coal technologies, regulators, financiers, environmental groups, and other public and private institutions. Four issues of the Clean Coal Today newsletter were published in the same period, along with the fifth annual edition of the Clean Coal Today Index, which cross-references all articles published in the newsletter. A 12-page Project Performance Summary document was issued for the ENCOAL® Mild Coal Gasification Project. An updated The Investment Pays Off document, capturing the latest contributions of the CCT program to advancing coal technologies, was published. Also, two Clean Coal Technology Topical Reports were issued during the fiscal year for the Tampa Electric Integrated Gasifica- tion Combined-Cycle Project and the Blast Furnace Granular Coal Injection System Demonstration Project. The Department of Energy also continued coverage of the program by publishing the Clean Coal Technology Demonstration Program: Update 1999, and the mid-year update of project fact sheets, Clean Coal Technology Demonstration Program: Project Fact Sheets 2000. Marketplace Commitment Marketplace Commitment Reflecting CCT Program commercialization goals, the majority of the projects involve demonstrations at Some new publications p
4-2 Program Update 2000

commercial scale, providing the opportunity for theparticipants to continue operation of the demonstratedtechnologies as part of their strategy to comply with theCAAA.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 thesetechnologies and then highlights, by market sector,

some of the program and project accomplishments todate along with commercialization successes.

Factors Impacting Domestic Commercial- Factors Impacting Domestic Commercialization ization

The domestic market for advanced SO2 controltechnology is not yet fully developed. Domesticutilities are investing in SO2 control technology by fuelswitching, and procuring and banking SO2 allowances,rather than making capital investments on SO2 control

technologies. Also, the utilities are awaiting theoutcome of PM2.5 and other regulatory actions that maysignificantly impact SO2 compliance requirements.

Similarly, there has been no domestic market foradvanced technologies that combine high captureefficiency 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 Amendmentemission requirements for NOx. The more advancedcoal and gas reburning, and SCR technologies havebeen applied only sparingly, but will likely come intoplay as utilities are forced to comply with new, morestringent requirements. Beginning as early as 2003,

new NAAQS for PM2.5 a

EPA “SIP Call” will requ

particulate controls like Program. The EIA estimscrubber capacity will be The domestic market haintroduction of advanced technologies. Uncertaintmarkets due to utility resstringent emission standlow natural gas prices to plants. Successfully demIGCC and PFBC have reonly overseas.The market is changing. electric power generatioare placing a premium oelectric capacity and mageneration a solid option existing plants, investmecontrol measures needed requirements.For capacity additions, opower generation systemmeet projected emission concerns over global clim

Environmental Con

Environmental Con

All but 1 of the 19 envirprojects have now comppleted demonstrations prsuite of cost-effective SOthe full range of coal-firesignificantly mitigated in technologies commerciadatabases and attendant through the demonstratio

SO2 control technologies: AirPol (left), CT-121 (center), and LIFAC (right).
leveraged to provide input in formulating NOx control

requirements under the CAAA and to evaluate theimpact of emerging issues, such as air toxics, on theexisting boiler population and control options. Extensive air toxics testing was performed in conjunctionwith 10 of the environmental control projects. To agreat extent, the technologies were retained forcommercial service at the demonstration sites andmany technology suppliers have realized commercialsales.SO2 Control 

Technologies. echnologies. All five SO2 control

technology demonstrations have completed operations,evaluating three basic approaches to address thediverse coal-fired boiler population: (1) sorbentinjection, (2) gas-suspension absorption, and (3)advanced flue 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,particularly those with space constraints.

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

system, sponsored by AirPol, Inc., demonstratedSO2 capture efficiencies in the range of 60 to 90

percent. The system has particular applicability tothe small- to mid-range units with some spacelimitations.

• Two advanced flue gas desulfurization (AFGD)

systems, sponsored by Pure Air on the Lake, L.P.and Southern Company Services, having somewhathigher capital costs than the other approaches,demonstrated SO2 capture efficiencies in the rangeof 90 to 95 percent. These systems are primarilyapplicable 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 largevolumes of flue gas and provide the required availability and reliability. This single module design, withoutthe usual spares, combined with integration of functions within the absorber module and use of highthroughput designs, nearly halved capital cost andspace requirements. The AFGD testing also established that wallboard-grade gypsum could be producedin lieu of solid waste; wastewater discharge could beeliminated; and, by mitigating corrosion, fiberglassreinforced-plastic fabrication could eliminate processsteps (e.g., prequenching for chloride removal and fluegas reheat).The AFGD demonstration by Southern CompanyServices using Chiyoda CT-121 showed that the systemcould significantly enhance particulate control. PureAir on the Lake, L.P., introduced an innovativebusiness concept whereby the company builds, owns,and operates scrubbers as a contracted service to autility. The arrangement relieves utilities of the burdenof ownership and operation.Commercialization successes to date for the SO2

control technologies are summarized in Exhibit 4-1.NOx Control 

Technology echnologyechnology. Six of the seven NOx

control 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 the

various approaches were:• Low-NOx burners and OFA: 45 to 68 percent

• Reburning systems: 50 to 67 percent

• SNCR systems: 30 • SCR systems: 80 to • Advanced controlsThe database developeServices’ evaluation of 

tangentially fired boileHammond, respectiveling NOx provisions un

tion Engineering’s LNtangentially fired boileacceptance, as did FosSplit Flame and Babcolow-NOx burners for w& Wilcox Company’s provided an effective l

system for cell-burner their inherently high N

Integration of neural-nboiler controls, such as Intelligent System (GNHammond, demonstratparameters for NOx co

under load-following oThe Babcock & Wilcotechnology proved not control NOx on cyclon

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

when used with low-N

In another project, comducted on a range of SCU.S. coals, providing nmental and economic pOther SCR systems an
4-4 Program Update 2000

Exhibit 4-1

Commercial Successes—SO2 Control T Control T Control Technology echnologyechnology

Project Project Commercial Use

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

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

worth $1.3 million has been made to the U.S. Army for hazardous waste disposal. A a Swedish iron ore sinter plant. Two GSA systems valued at $1.8 million have been ration for their oil-fired cogeneration plant. Furthermore, Taiwan contracted for tecetary equipment valued at $1.0 million. Airpol sold a GSA system valued at $1.5 mcalciner in India. Negotiations are under way for a GSA system for a waste inciner

Confined Zone Dispersion Flue Gas Desulfurization No sales reported. No sales reported. CZD/FGD can be used to retrofit existing plants or for new ins

Demonstration (Bechtel Corporation) one-tenth that of a commercial wet scrubber.LIFAC Sorbent Injection Desulfurization Sold domestically and internationally. Sold domestically and internationally. There are 10 full-scale LIFAC units in opeDemonstration Project (LIFAC–North America) Finland, Russia, Japan, and the United States, including 5 projects started before th

system at Richmond Power & Light is the first to be applied to a power plant using The LIFAC system has been retained for commercial use by Richmond Power & LiStation, Unit No. 2.

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

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

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

Technology for the CT-121 FGD Process CAAA compliance strategy. Since the CCT Program demonstration, over 8,200 M(Southern Company Services, Inc.) capacity are operating at 17 plants in 8 countries. Another 5 projects are either in d
gies that could effectivwith the need to both cgrowing power demanoption because existing significant value and winfrastructure is in placrepresents a major undto award early on of thtwo ACFB projects anAs the CCT Program uand environmental issuemphasis toward seekipower generation technand new power generaessential to enable coation to the nation’s enecentury. Environmentaconcern over greenhouSO2 emissions, increasnonattainment areas, aemissions (respirable phealth threat. These isprojects in PFBC, initiprojects in advanced c

Fluidized-Bed CombuFluidized-Bed Combu

tion and Transmission Station repowering prooperating experience rcommercial technologMWe, the Nucla ACFB larger than any other Apercent SO2 removal whours of demonstration

very low 0.18 lb/106 B

to fully evaluate the eneconomic performance comprehensive databaable to date was develocommercial units were 

tion (SNCR) systems were demonstrated in conjunctionwith combined SO2/NOx control technologies.

Commercialization successes to date for the NOx

control technologies are summarized in Exhibit 4-2.

Combined SO2/NOx Control 

Technologies. echnologies. All seven

of the combined SO2/NOx control technology demonstrations have successfully completed operations. Thedemonstrations evaluated a multiplicity of complementary and synergistic control methods to achieve costeffective SO2 and NOx emissions reductions.A catalytic process developed by Haldor Topsoe a/s,SNOXTM, consistently achieved 95 and 94 percent SO2and NOx reductions, respectively. The process also

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

with SNCR resulted in NOx emission reductions ofgreater than 80 percent. The SNCR process interactedsynergistically with sorbent injection to reduceammonia slip and lower NOx emissions. Sodium-basedsorbent injection achieved 70 percent SO2 removal at

high sorbent utilization rates.New York State Electric & Gas Corporation (NYSEG)evaluated an advanced flue gas desulfurization system,the S-H-U scrubber process. The S-H-U process, anadvanced formic acid-enhanced wet limestone scrubbing process, demonstrated a 98 percent SO2 capture

efficiency. In conjunction with the S-H-U- process,NYSEG also evaluated micronized coal as a reburnfuel using close-coupled reburning techniques and deepstaged combustion incorporated into ABB CombustionEngineering, Inc.’s LNCFSTM burners. DHR Technologies supplied a plant optimization control systemknown as the Plant Emission Optimization Advisor orPEOATM, which has been sold to a number of users inthe power industry.

The Babcock & Wilcox Company’s SOx-NOx-Rox

BoxTM, an integration of a newly developed hightemperature fabric-filter bag (for baghouse installations) with SCR and sorbent injection, proved to be aneasily installed, highly efficient control system for SO2

,

NOx, and particulates. Typical performance was 80

percent SO2 removal, 90 percent NOx removal, and

99.9 percent particulate removal.Limestone injection multistage burner (LIMB) andcoolside demonstrations proved that sorbent injectionmethods could achieve up to 70 percent SO2 reduction.The Babcock & Wilcox DRB-XCL® advanced lowNOx 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

percent could be achieved with only 13 percent naturalgas heat input, and (2) SO2 removal of over 55 percent

could be achieved by using special sorbents.Commercialization successes to date for the combinedSO2 and NOx control technologies are summarized inExhibit 4-3.

Advanced Electric Power Generation

Pollution control was the priority early in the CCTProgram. This program emphasis included technoloMilliken Station served as the host for two CCT Program projects demonstrating advanced environmental controls.
4-6 Program Update 2000

Exhibit 4-2

Commercial Successes—NO

x

 Control T Control T Control Technology echnologyechnology

Project Project Commercial Use

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

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

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

x

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

(The Babcock & Wilcox Company) commercial contracts have been awarded for 172 burners, valued at $27 million. T

already been installed on more than 4,900 MWe of capacity.

Evaluation of Gas Reburning and Low-NOx Burners on a Sold domestically and internationally. Sold domestically and internationally. Public Service Company of Colorado, the 

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

Corporation) remove the flue gas recirculation system. Energy and Environmental Research Cor

contracts to provide gas reburning systems for cyclone coal-fired boilers: TVA’s Alwell as Baltimore Gas & Electric’s C. P. Crane Unit Nos. 1 and 2 (similar 200-MWinstalled at Ladyzkin State Power Station in Ladyzkin, Ukraine.

Demonstration of Selective Catalytic Reduction Technology Sold domestically and internationally. Sold domestically and internationally. Since the project was initiated, revenues f

for the Control of NO

x Emissions from High-Sulfur, through 2000, with projected revenues for 2001 and 2002 expected to be $1.4 billio

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

Combustion Techniques for the Reduction of NOx Emissions from Combustion Engineering has sold about 56 GWe of LNCFSTM burners. Of this am

Coal-Fired Boilers (Southern Company Services, Inc.) equipped with overfire air and 33 GWe are without overfire air. Total sales are estiDemonstration of Advanced Combustion Techniques Sold domestically and internationally. Sold domestically and internationally. The host has retained the technologies for 

for a Wall-Fired Boiler (Southern Company Services, Inc.) Wheeler has equipped 86 boilers (51 domestic and 35 international) with low-NOx b

over 1,800 burners representing over 30,000 MWe capacity valued at $55 million. Tinstallations of GNOCIS, the associated AI control system, are underway or planne12,000 MWe of capacity. In a strict sense, this project has not been completed; it hGNOCIS to other pieces of plant equipment, which may increase its commercial po
Exhibit 4-3

Commercial Successes—Combined SO2/NOx Control T Control T Control Technology echnologyechnology

Project Project Commercial Use

SNOXTM Flue Gas Cleaning Demonstration Project (ABB International use. International use. The host utility, Ohio Edison, is retaining the SNOXTM technolog

Environmental Systems) pollution control system at Niles Station to help meet its overall SO2 and NOx reducti

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

LIMB Demonstration Project Extension and Coolside Sold domestically and internationally. Sold domestically and internationally. LIMB has been sold to an independent powDemonstration (The Babcock & Wilcox Company) Wilcox has sales of 2,585 burners for 35,310 MWe of capacity for the DRB-XCL® lo

burners have an estimated value of $240 million.

SO

x

-NO

x-Rox BoxTM Flue Gas Cleanup No sales reported. No sales reported. Commercialization of the technology is expected to develop with 

Demonstration Project (The Babcock & Wilcox Company) equivalent to 50-100 MWe. The focus of marketing efforts is being tailored to match 

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

performance requirements while providing flexibility to address future needs.

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

Corporation) Boiler project for a complete understanding of commercial success of the technologyMilliken Clean Coal Technology Demonstration Project Sold domestically. Sold domestically. Eight modules of DHR Technologies’ Plant Emissions Optimiza

(New York State Electric & Gas Corporation) value of $210,000, have been sold. A U.S. company, SHN, has been established to m

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

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

(Public Service Company of Colorado) Arapahoe Station. The Babcock & Wilcox DRB-XCL® burner that was demonstrated 

burners, representing 31,467 MWe. The burners are valued at $320 million.
4-8 Program Update 2000

While the Nucla project established commercialacceptance of ACFB at moderate utility capacities, asecond CCT demonstration project, located in Jacksonville, Florida, is carrying on where Nucla left off. JEA(formerly Jacksonville Electric Authority) will build 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.Through the Ohio Power Company’s repowering of theTidd Plant (70 MWe), the potential of PFBC as a highefficiency, low-emission technology was established,and the foundation was laid for commercialization.This was the first utility-scale PFBC system in theUnited States. Efforts were focused on fully evaluatingthe performance potential. Over 11,400 hours ofoperation, the technology successfully demonstratedSO2 removal efficiencies up to 95 percent with veryhigh sorbent utilization (calcium-to-sulfur molar ratioof 1.5), and NOx emissions in the range of 0.15 to 0.33

lb/106 Btu.

The Tidd Plant PFBC was one of the first generation70-MWe P200 units installed in the early 1990s.Others were built and operated in Sweden, Spain, andJapan. ABB Stal, the technology supplier, uses a“bubbling” fluidized-bed design, which is characterized by low fluidization velocities and use of an in-bedheat exchanger. The first 360-MWe P800 PFBC isbeing built in Japan and started operations in 1999.And, a “second generation” P200 PFBC with freeboard-firing is operating in Cottbus, Germany. Anumber of other ABB Carbon PFBC projects are underconsideration in China, South Korea, the UnitedKingdom, Italy, and Israel.

Two ongoing interrelated projects, McIntosh 4A andMcIntosh 4B, will demonstrate PCFB at utility scale.PCFB uses a higher fluidization velocity than bubbling-bed systems, which entrains the bed material.Bed material is separated from the flue gas by cyclonesand recirculated to the combustor. The economizer,which captures heat from the flue gas, is downstreamof the cyclones. McIntosh 4A will evaluate a 137-MWe first generation PCFB configuration using FosterWheeler technology. McIntosh 4B will demonstrate asecond-generation system by integrating a small coalgasifier (pyrolyzer) to fuel the gas turbine “toppingcycle,” thereby adding 103 MWe capacity. Thesecond-generation PCFB has the potential to significantly improve the efficiency of pressurized fluidizedbed systems by increasing power generation from thegas turbine, which is more efficient than the steambottom cycle.

Integrated Gasification Combined-Cycle. Integrated Gasification Combined-Cycle. Three of

four IGCC projects are in operation or have completedoperations under the CCT Program. They represent adiversity of gasifier types, cleanup systems, andapplications. PSI Energy’s 262-MWe Wabash RiverCoal Gasification Repowering Project began operationin November 1995, ceased demonstration operations inDecember 1999, and now operates in commercialservice. The unit, which is the world’s largest singletrain IGCC, has operated on coal for over 12,400 hoursand processed more than one million tons of coal. Theunit 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 and continues to accumulate runtime. The gasifier has accumulated over 15,000 hoursof operation and produced over 3,500,000 MWh ofelectricity on syngas. Tests have included evaluationof various coal types on system performance.

The Sierra Pacific Poweto make progress on its Piñon Pine IGCC Power Station began operation 1996. The GE Frame 6Fworld, performed well. shakedown, and design mThe system has achieved for short periods, but cowith sustained operationThe Kentucky Pioneer EProject, which is in the danother gasifier design acell operated on syngas provide valuable data fo

IGCC plants operating or hElectric (top), Piñon Pine (m
Coal Processing for Clean Fuels Coal Processing for Clean Fuels

Two of five projects in the coal processing for cleanfuels category completed operations and submittedfinal reports. Projects in this category include physicaland chemical processes that can be used to transformthe abundant U.S. coal reserves into economic,environmentally compliant solid and liquid fuels andfeedstocks. The solid products from coal processingare largely designed to be readily transportable; high inenergy density; and low in sulfur, ash, and moisture.The liquid products are designed to be suitable astransportation and stationary power generation fuels, oras chemical feedstocks. Both solid and liquid products,and the processes that produce them, have substantialmarket potential both domestically and internationally.The ENCOAL and Western SynCoal LLC projects arebreaking down the barrier to using the nation’s vastlow-sulfur but low-energy-density western coalresources. The resultant fuels have particular application domestically for CAAA compliance and internationally for Pacific Rim energy markets.ENCOAL’s solid fuel product has an energy density 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 commercialfeasibility studies have been completed—two forIndonesia, one for Russia, and two for U.S. projects.Permitting of a 15,000 metric ton/day commercialplant in Wyoming is nearly complete.The Western SynCoal LLC project is demonstratinganother route to producing high-quality fuel from lowrank coals. The advanced coal conversion process(ACCP) upgrades low-rank coal to produce a lowgasification fuel cell (IGFC) system. IGFC has the potential to achieve efficiencies greater than 60 percent. Commercial configurations resulting from the current IGCC and PFBC demonstrations will typically have efficiencies at least 20 percent greater than conven- tional coal-fired systems (with like CO2 emission reductions), remove 95 to 99 percent of the SO2

,

reduce NOx emissions to levels well within NSPS,

reduce particulate emissions by one-third to one-tenththat currently allowed under the CAAA, and producesalable by-products from solid residues as opposed towaste.

Advanced Combustion/Heat Engines. Advanced Combustion/Heat Engines. Two projects

are demonstrating advanced combustion/heat enginetechnology. The Healy Clean Coal Project is demonstrating TRW’s entrained (slagging) combustorcombined with Babcock & Wilcox’s spray-dryerabsorber using sorbent recycle. Operations werecompleted in December 2000. Results from environmental compliance testing showed very low emissions—0.26 lb/106 Btu for NOx, 0.01 lb/106 Btu for

SO2, and 0.0047 lb/106 Btu for particulates. Permit

levels are 0.35 lb/106 Btu for NOx, 0.086 lb/106 Btu for

SO2, and 0.03 lb/106 Btu for particulates because of the

plant’s proximity to a national park. NSPS allows1.2 lb/106 Btu for SO2

.

The Clean Coal Diesel Demonstration Project isevaluating a heavy duty diesel engine operating on alow-rank coal-water fuel. The demonstration plant isexpected to achieve 41 percent efficiency and futurecommercial designs are expected to reach 48 percentefficiency. As of September 2000, the unit hadoperated on diesel, with plans for operating on coal in2002.Commercialization successes for the advanced electricpower generation systems to date are summarized inExhibit 4-4.

sulfur (as low as 0.3 pe

having a heating value Western SynCoal LLC to supply fuel to MontaUnit No. 2. Five other Air Products Liquid Phis demonstrating the Lmethanol from coal-deLPMEOHTM process hintegrated gasification tion facilities by coproliquid fuel from coal-dproduction of dimethyl coproduct with methanMethanol and DME m

NOx alternative liquid sis of chemicals, or as a Since startup, the LPMproduced over 60 milliwhich was accepted by for use in downstream restart of the unit with availability of the unit and catalyst activity depercent/day.ABB Combustion Engdeveloped PC-based soutilities in assessing the performance of their sycoal fuels to determine CQETM software has bmembers of EPRI and worldwide. Two U.S. uto use copies of the CQAdvisor.Commercialization suctechnologies to date ar
4-10 Program Update 2000

Exhibit 4-4

Commercial Successes—Advanced Electric Power Generation

Project Project Commercial Use

Tidd PFBC Demonstration Project Sold internationally. Sold internationally. The project’s success has led Babcock & Wilcox to inv(The Ohio Power Company) and acquire domestic licensing rights.

Commercial ventures abroad include the following:– Vartan in Sweden is operating two P200 units to produce 135 MWe and 22– Escatron in Spain is operating one P200 unit producing 80 MWe;– Wakamatsu in Japan is operating one P200 unit to produce 71 MWe;– Cottbus in Germany is operating one P200 unit to produce 71 MWe and 40 – Karita in Japan operates one P800 unit to produce 360 MWe; and– Other projects under construction are in China, South Korea, U.K., and Isr

Nucla CFB Demonstration Project (Tri-State Generation Sold domestically and internationally. Sold domestically and internationally. Since the demonstration, Foster Wheand Transmission Association, Inc.) Corporation, the technology supplier for the demonstration effort, has achieve

through 2000, with another $2.7 billion in sales projected for 2001 through 20percent of the sales through 2000 were domestic, while the remaining sales thrforeign.

Tampa Electric Integrated Gasification Combined-Cycle Sold domestically and internationally. Sold domestically and internationally. First greenfield IGCC unit in comme

 Project (Tampa Electric Company) Texaco, Inc., and ASEA Brown Boveri signed an agreement forming an allian

technology in Europe. There are currently 10 IGCC projects using a Texaco geither planned or under construction.

Wabash River Coal Gasification Repowering Project No sales reported. No sales reported. First repowered IGCC unit in commercial service and is th(Wabash River Coal Gasification Repowering Project single-train IGCC in commercial service. The unit is preferentially dispatched 

Joint Venture) units in PSI Energy’s system because of the unit’s high efficiency.Piñon Pine IGCC Power Project (Sierra Pacific Power No sales reported. No sales reported. Unit in initial operation preparatory to commercial serviceCompany)Healy Clean Coal Project (Alaska Industrial Development No sales reported. No sales reported. TRW offering licensing of combustor worldwide (China aand Export Authority) Commercial operation tests are ongoing.
Exhibit 4-5

Commercial Successes—Coal Processing for Clean Fuels

Project Project Commercial Use

Development of the Coal Quality ExpertTM (ABB Combustion Sold domestically and internationally. Sold domestically and internationally. The Electric Power Research Institute 

Engineering, Inc. and CQ, Inc.) software and distributes it to EPRI members for their use. CQ Inc. and Black 

signed commercialization agreements that give both companies nonexclusive wsell user licenses and offer consulting services that include use of CQE®. Mor

two United Kingdom utilities, and one utility in France have received CQE® th

membership. Two modules of the Acid Rain Advisor valued at $6,000 have bestimated that the Acid Rain Advisor has saved one U.S. utility about $26 miltotal cost of the demonstration project. There have also been two sales of the software at an estimated value of $180,000.

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

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

projects—have been completed. Permitting of a 15,000 metric-ton/day commWyoming is nearly complete.

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

Methanol (LPMEOHTM) Process (Air Products Liquid Chemical Company.Phase Conversion Company, L.P.)Advanced Coal Conversion Process Demonstration No sales reported. No sales reported. Total sales of SynCoal® product exceed 1.5 million tons. 

(Western SynCoal LLC) agreements are in place to purchase the product. One domestic and five intern

been investigated. Western SynCoal LLC has a joint marketing agreement wiJapan providing Ube non-exclusive marketing rights outside of the United Staseveral projects in Asia. Western SynCoal is also discussing a potential markeagreement with a U.S. engineering firm.
4-12 Program Update 2000

Industrial Applications Industrial Applications

The CCT Program is addressing the environmentalissues and barriers associated with coal use in industrial applications. Three of five projects have completed 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 low stable price, coal is an attractivesubstitute for oil and gas in industrial boilers, butconcerns over increased SO2 and NOx emissions and

boiler tube fouling have impeded coal use.Under a project with Bethlehem Steel Corporation,British Steel’s blast furnace granular-coal injection(BFGCI) technology demonstrated that 40 percent ofthe coke can be replaced with coal injected directlyinto a blast furnace where emissions from coal combustion are effectively controlled in the process.CPICORTM Management Company LLC is in thedesign stage of demonstrating direct iron ore reduction

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

x (70 to 80 percent reduction) through

staged combustion, and controls SO2 (90 percent) with

sorbent injection.ThermoChem, Inc. has completed restructuring of itsproject and is in the construction phase of the demonstration of a multiple resonance tube pulse combustor.Commercialization successes for the industrial applications technologies to date are summarized in Exhibit 4-6.

The Burns Harbor plant wastration.

Exhibit 4-6

Commercial Successes—Industrial Applications

Project Project Commercial Use

Cement Kiln Flue Gas Recovery Scrubber No sales reported. No sales reported. The scrubber became a permanent part of the cement plant at the end of the d(Passamaquoddy Tribe) study has been completed for a Taiwanese cement plant.Blast Furnace Granular-Coal Injection System Domestic sale. Domestic sale. British Steel’s Blast Furnace Granular-Coal Injection System was sold and install

Demonstration Project (Bethlehem Steel United States Steel Corporation.Corporation)Advanced Cyclone Combustor with Internal Sulfur, No sales reported. No sales reported. While the combustor is not yet fully ready for sale with commercial guaranteeNitrogen, and Ash Control (Coal Tech Corporation) commercial potential. Follow-on work to the CCT Program demonstration was undertaken, which 

close to commercial introduction.

Awards

The projects in the CCT awards from news, profeorganizations. A listing Exhibit 4-7.
Full-Scale Demonstration of Low-NO

x

 Cell Burner

Retrofit (The Babcock & Wilcox Company)Evaluation of Gas Reburning and Low-NOx Burners

on a Wall-Fired Boiler; Enhancing the Use of Coals byGas Reburning and Sorbent Injection (Energy andEnvironmental Research Corporation)Advanced Flue Gas Desulfurization DemonstrationProject (Pure Air on the Lake, L.P.)Demonstration of Innovative Applications of Technology for the CT-121 FGD Process(Southern Company Services, Inc.)Tidd PFBC Demonstration Project (The Ohio PowerCompany)Tampa Electric Integrated Gasification CombinedCycle Project (Tampa Electric Company)Wabash River Coal Gasification Repowering Project(Wabash River Coal Gasification Repowering ProjectJoint Venture)Development of the Coal Quality ExpertTM (ABBCombustion Engineering, Inc. and CQ Inc.)

Exhibit 4-7

Award-Winning CCT Projects

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

burner.1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management AssociaEnergy, Gas Research Institute, and U.S. Environmental Protection Agency for the developgas-reburning technology.1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service 

Station.1992 Outstanding Engineering Achievement Award presented by the National Society of P1995 Design Award presented by the Society of Plastics Industries in recognition of the m1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. C

Department of Energy.1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and W1993 Environmental Award presented by the Georgia Chamber of Commerce.1992 National Energy Resource Organization award for demonstration of energy-efficient 1991 Powerplant Award presented by Power magazine to American Electric Power Comp

was The Babcock & Wilcox Company.1997 Powerplant Award presented by Power magazine to Tampa Electric’s Polk Power St

1996 Association of Builders and Contractors Award presented to Tampa Electric for qual1993 Ecological Society of America Corporate Award presented to Tampa Electric for its i1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of process.1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innov1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc.

1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 199neers Council competition.In 1996 recognized by then Secretary of Energy Hazel O’Leary and EPRI President RichaDOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Pr

Project and Participant Award
4-14 Program Update 2000

Market Communications—

OutreachOutreach has been a hallmark of the CCT Programsince its inception. The Department of Energy recognized early on that commercialization of technologyrequires acceptance by a range of interests including:technology users; equipment manufacturers; suppliersand users of raw materials and products; financialinstitutions and insurance underwriters; governmentpolicy makers, legislators, and regulators; and publicinterest groups. Requisite to acceptance is an outreachprogram to provide these customers and stakeholderswith both program and project information and to seek,on a continuing basis, feedback on program directionand information requirements. An ongoing outreachprogram has aggressively sought to disseminate keyinformation to the full range of customers and stakeholders and to obtain feedback on changing needs. Theeffort has recognized the need to highlight environmental, operational, and economic performance characteristics of clean coal technologies and to redesigninformation packages as customers and stakeholders,and their respective needs, change with the market.Specific objectives of the outreach program include thefollowing:

• Achieving public and government awareness of

advanced coal-using technologies as viable energyoptions;

• Providing potential technology users, both foreign

and domestic, with information that is timely andrelevant to their decision making process;

• Providing policy makers, legislators, and regulators

with information about the advantages of clean coaltechnologies;

• Convincing financial institutions and insurance

underwriters that clean coal technologies are viableoptions; and

• Providing forums and opportunities for feedback on

program direction and information requirements.

Information Sources Information Sources

A portfolio of publications and information accessmedia exist and are being improved upon as programand marketplace events unfold. Information is currently distributed to over 4,000 customers and stakeholders. The following provides a brief synopsis of thepublications and information transfer mechanismscurrently in place.Clean Coal Technology Demonstration Program:

Program Update provides an annual summary of

program and project progress, accomplishments, andfinancial status along with a historical backdrop andprogram role relative to current policy.

The CCT Compendium is a CCT Program.

Exhibit 4-8

How to Obtain CCT Program Inform

Media Description and ActionClean Coal Today Subscription to quarterly newsletter—

Department of Energy, FE-24, Washin

Fossil Energy Home Page Primary gateway to extensive informa

Program and to relevant Web links—Ohttp://www.fe.doe.gov and use menu 

CCT Compendium On the Internet, access http://www.lanCCT Program Update and other publications Send name and address to U.S. Depar

Washington, DC 20585.

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

Springfield, VA 22161.

Clean Coal Technology 

Project Fact Sheets prov

each project.Clean Coal Technology serves as an update on isfeedback on program in
periodic snapshot of how each of the active projects isprogressing with some degree of technical depth.Clean Coal Today newsletter offers its readers a

quarterly look at the CCT Program and related issues,highlighting key events, updating project status, andlisting the latest publications and upcoming events.

Project Performance Summary documents provide a

12-page synopsis of a completed project, highlightingits operational, environmental, and economic performance. Eleven have been published so far, withanother one expected in early fiscal year 2001.

Clean Coal Technology Topical Reports capture

projects at critical junctures and highlight particulartechnological advantages, project plans, and expectedoutcomes. Fifteen have been published so far, withanother two expected in early fiscal year 2001.

National Technical Information Service (NTIS) serves

as the federal government’s central source for the saleof scientific, technical, engineering, and relatedbusiness information produced by or for the U.S.government. The NTIS has most of CCT Programtechnical reports.

CCT Program Bibliography of Publications, Papers,

and Presentations periodically updates the key

materials available on the technologies demonstratedunder the CCT Program.

The Investment Pays Off periodically takes a marketbased view of the success of the CCT Program by

virtue of commercial sales and relevance of ongoingactivities to projected market need.

CCT Program—Lessons Learned documents the

lessons learned in soliciting, selecting, and awardingprojects and implementing the program.

CCT Compendium provides an electronic database

incorporating the CCT Program publications that can

be accessed on the Internet (http://www.lanl.gov/projects/cctc/).Exhibits provide a means through graphics, 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 arecurrently four exhibits of varying sizes and complexitythat are updated and modified, as necessary, to conveythe appropriate message for specific forums. A fifthexhibit is in development to replace an older exhibitthat will be retired.Fossil Energy Home Page provides the primary

Internet gateway to extensive information on DOE’sFossil Energy Program and to relevant World WideWeb links (http://www.fe.doe.gov).Exhibit 4-8 summarizes how the above publicationscan be obtained and information sources can beaccessed.

Publications Issue

The following publicat2000 by the CCT Progbe expected in fiscal ye

• Clean Coal Techno

Program Update 19

• Clean Coal Techno

Project Fact Sheets 

• Clean Coal Today: 

Summer 2000, Fall 

• Clean Coal Today I

• Project Performanc

Coal Gasification P

• Clean Coal Techno

• Topical Report—Bl

Injection System De

A new exhibit is in development for the Outreach Program. Shown is the conceptual design 
4-16 Program Update 2000

• Topical Report—Tampa Electric Integrated

Gasification Combined-Cycle Project: An Update

Information Access Information Access

The Department of Energy continues to expand itswebsite to provide information on federal fossil energyprograms and serve as a gateway to other relatedinformation throughout the United States and theworld. Once into the DOE website, users can obtaingeneral information and follow links to increasinglydetailed information, ultimately accessing specific dataon individual projects and facilities. Hyperlinks allowusers to move seamlessly between headquarters andfield sites. Users can also access technical abstractsand reports maintained by DOE’s Office of Scientificand Technical Information (OSTI) at Oak Ridge,Tennessee. The gateways link to more than a hundredenergy-related websites operated by private companies,trade associations, and other agencies worldwide.Furthermore, the Fossil Energy International Activitiessite on the World Wide Web has been expanded withthe addition of new country pages in the WesternHemisphere region (Mexico, Ecuador and Canada).Many of the existing country pages have also beenupgraded, with new hyperlinks to business- or energyrelated information sources. An innovation at theFossil Energy International Activities website 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 FossilEnergy and the National Energy Technology Laboratory (NETL), is dedicated to making the maximum useof information derived from the CCT Program. Thecompendium 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 Demonstration Program: Program Update and Topical Reports

published periodically on individual CCT projects.The CCT Compendium is accessible via the Internetat http://www.lanl.gov/projects/cctc/.

Information Dissemination and Feedback

A number of mechanisms are used to disseminateprogram information to customers and stakeholdersand obtain feedback from them on specific issues,program direction, and information requirements. Thefollowing provides 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 anddedication 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 on the future direction of the power

industry. Over 50 meetiwith influential leaders ipower, regulatory, and fiStakeholder Meetings brorganizations for the purgrams, where appropriatissues and implementatiissues and outreach needtions include the Electric (EPRI), Gas Research InResearch Council, CenteDevelopment (CEED), COwners (CIBO), Clean CNational Mining AssociaConferences and Workshaudiences to review and document discussions anrecommendations, as apa subset of these and diffinternational in characteing the export of U.S. teoutreach program has pacal conferences, workshsince 1991.

Conferences and Conferences and 

W

FY2000

Indonesia. Indonesia.Indonesia. Indonesia.Indonesia. The Nationatory, along with Indonessponsored the highly sucence in Jakarta, IndonesThe conference, designeknowledge of clean coal coal mining and power gattendees from a variety the meeting was the formSociety to facilitate tech
standing of Indonesian coal properties and clean coaltechnologies’ performance characteristics. Indonesiamines approximately 60 million tons of coal per year,of which 40 million tons are high quality and targetedfor export. The remaining 20 million tons of lowerquality coal are used in domestic power plants. Thesepower plants are slated to reduce SO2 emissions by upto 50 percent, and clean coal technologies are seen as away to achieve that end. During the opening ceremonies for the conference, NETL and LaboratoriumSumderdaya Energi (LSDE) signed a Joint Statement todiscuss potential cooperation on clean coal and otheradvanced power technologies. As a first sign ofcooperation, LSDE requested that NETL co-sponsorthe second CoalTech Conference during October 23-24, 2000 in Jakarta.Slovakia. Slovakia. Slovakia. Slovakia. Slovakia. Under a cooperative research agreementbetween NETL and the Slovak Academy of Sciences,NETL researchers have recently completed a study ofthe application of triboelectrostatic separation toSlovakian brown coal. The brown coal, a significantresource for power production in Slovakia, containselevated levels of ash, sulphur, and arsenic. The studyconcluded that using triboelectrostatic separationreduced ash levels in the coal significantly. The resultswere presented at the 10th International Conference onCoal Science on September 13, 1999, in Taiyuan,China, as well as at the 16th Pittsburgh Coal Conference on October 14, 1999, in Pittsburgh, Pennsylvania.Japan. At the request of the Japanese Institute ofApplied Energy and the New Energy DevelopmentOrganization (NEDO), the Office of Fossil Energyhosted a one-day workshop held in Washington, D.C.,in January 2000 on municipal solid waste (MSW)treatment options designed to address Japan’s landfillshortage and, secondarily, to produce power. Japan’splans are aimed at developing high-temperatureprocesses to transform MSW into vitrified ash and

additional power-generation capacity. Particularinterest was expressed in the high-temperature gasification systems under FE’s Coal & Power Systemsprograms.Japan generated 51 million tons of waste in 1996, andthe average annual increase since 1992 has been225,000 tons, making development of effectiverecycling and disposal methods imperative and makingMSW a major power generation fuel option. Currently, Japan has 1,800 small, low-efficiency incineration facilities, only nine percent of which generate atotal of 890 MWe.Japan’s goal is to convert or establish new MSWprocess facilities to generate 5,000 MWe of power by2010, representing an increase of almost 800 facilitiesthat coproduce power. Currently, Japan relies on apyrolysis furnace to produce pyrolytic gas from MSW,which in turn fuels a melting furnace to transform theremaining waste from the pyrolysis unit into “moltenslag.” Heat from the combustion melting furnace raisessteam to drive a steam turbine for power generation atan efficiency of about 30 percent. On the other hand,high-temperature gasification systems under development in the United States use the synthetic gas produced in the gasifier to generate power in a combinedcycle, which results in efficiencies of over 40 percentand a vitrified slag usable in construction applications.The workshop agenda included a presentation to Japanon high-efficiency waste power generation, anddiscussions of representative R&D, Clean CoalTechnology projects, and Vision 21 research programgoals as all three address Japan’s current need.Various gasification projects were discussed, alongwith FE’s gasification database, and power/fuelscoproduction. Japanese attendees were particularlyinterested in Global Energy’s presentation on the latestCCT Program project, the Kentucky Pioneer IGCC

facility, which will gasfines and MSW to prodturbines in combined-cfuel cell. One product stration plant to make smunicipal sewage sludpulverized coal power Carb” process), is alreaJapan using MSW.In all, U.S. workshop pcase to their Japanese ccost-effective option foelimination, while simuorganic emissions into do not require landfillinIndia. An Office of Foseveral contractors playtional conference entitlEfficiency and EnvironFebruary in New Delhiorganized by the Natio(India) and the USAID Electric Power ResearcValley Authority (TVAsome 350 attendees, ingovernment of India, aApproximately 25 Ampresenters shared expecounterparts. As part oCooperative Agreemenees with a two-volume Heat Rate ImprovemenIndia,” prepared under Prevention Project with report culminates an inindustry, and focuses oopportunities for impro
4-18 Program Update 2000

efficiencies of currently operating coal-fired plants.Both DOE and USAID share the long-range hope thatmany of the recommendations will be incorporated bythe Indian power industry.As part of this conference, FE also helped to organize aworkshop entitled “Identification of Barriers andUtilization Options: Large Volume Applications of FlyAsh in India.” Some 90 attendees from the Indianpower industry discussed areas such as policies andstandards, geomaterials and agricultural applications,and construction applications/technologies. The Officeof Fossil Energy supported these sessions withconsultants and speakers from the U.S. coal and powerresearch community.APEC. Asia Pacific Economic Cooperation’s (APEC)Sixth Coal Flow Seminar was held in the Spring of2000 in Kyongju, Korea. The Asia Pacific EconomicCooperation was formed in 1989 to address issues ofregional interdependence, and its members include 18countries bordering the Pacific Ocean. The seminar,where policymakers discuss the flow of coal importsand exports among APEC nations, is funded by DOE,along with Japan’s Ministry of International Trade andIndustry, and Korea’s Ministry of Commerce, Industry,and Energy. The Office of Fossil Energy is the mainU.S. government presence at the seminar and everyyear has provided technical speakers.There were 120 participants from nine APEC economies at this year’s conference, the theme of which was“Coal in the New Millennium.” With economiesrebounding from the Asian economic crisis, APEC islooking for new coal demand projections. Seminarparticipants believe that a shared view of future coalsupply and demand, as well as pricing and environmental concerns, can contribute to greater market stabilityin the region.

Speakers addressed broad challenges affecting coal inAPEC nations, such as excess capacity as a result oflower growth rates during the recent economic crisis,environmental concerns, and insufficient infrastructure.However, on the positive side, the economic crisisresulted in liberalization/privatization reforms so thatthe energy sector is expected to become more competitive.The Chairman of APEC’s Experts Group on CleanFossil Energy gave one of the opening addresses andnoted that APEC is the fastest growing region in theworld in energy terms. Clean coal technologies canhelp achieve sustainable development in the region,and support the strategic importance of the region’sindigenous coal in the context of a vulnerable oilmarket.Another keynote address focused on the overridingissue of greenhouse gas constraints and the competitiveposition of coal in Asia. The speaker noted that localand regional environmental restrictions for SO2 andparticulates, as well as increased competitiveness ofnatural gas, pose a greater threat to coal expansion thandoes the Kyoto Protocol. According to the speaker,most economies are following a gradual approach tocarbon emission reductions, which should allow timefor introduction of clean coal technologies. Underlikely scenarios, some experts expect coal consumptionto double within the next 25 years.A number of seminar speakers provided the individualcountry perspective. Among them were representativesfrom FE, who noted that the U.S. coal industry hassuccessfully responded to major challenges since the1960s. They explained that the new slate of near zeropolluting clean coal technologies to be developedunder the Vision 21 program can provide new marketsfor coal in the 21st century. Representatives fromKorea noted the country’s desire to diversify import

sources and develop ovement assistance may be rment. Chinese representexports, with governmenrepresentative from the Raddressed problems of inAustralian representativeimprovements. A JapanJapan expects to continurates.

Trade Mission rade Mission Activ

South Africa. Africa. Africa. Africa. Africa. South Afis considering repowerinmothballed 1,000-MWe circulating fluidized-bed ogy. The plan is to burn residue from coal washinSouth Africa, the project clean coal technology inKomati project represential U.S. goods and serviThe Office of Fossil EneESKOM began in 1998, facilitated meetings with technology vendors, arrasite visits, and encouragrelated conferences. ESU.S. power plants, incluJacksonville, Florida, whCombustion DemonstratESKOM has also visited CFB technology in the UBabcock & Wilcox, and In recent years, South Atons of coal annually, ansecond largest exporter w
in 1999. Discard coal is the country’s largest volumeindustrial waste, with 55 million tons of fresh discardsgenerated annually, 20 percent of the total minedproduct. By 2002, it is estimated that the inventories ofaccumulated discard coal in South Africa will reach 1billion tons.Long-term planning for ESKOM calls for adding1,000–2,000 MWe of new generation capacity annuallystarting in 2007. Clean coal technologies like CFBwould allow that power demand to be met with stateof-the-art technology. In addition, CFB plants coulduse the vast quantities of discard coal that otherwisewould have to be landfilled.A preliminary investigation has indicated that sufficientdiscard coal inventories exist within a 10-km radius ofthe Komati power station, in terms of both accumulatedproduct and future streams, to support 400–500 MWeof capacity for 30 years. The Komati demonstrationwould prove CFB in South Africa and could lead torepowering of additional mothballed conventionalpulverized-coal units. If all 3,800 MWe of ESKOM’smothballed units are repowered, the U.S. exportpotential could be as high as $800 million. Largedeposits of discard coal could also make CFB greenfield units more attractive.In August 1999, as a commitment under the U.S.-SouthAfrica Binational Commission, the U.S. Trade Development Agency approved $500,000 for a repoweringfeasibility study of ESKOM. With results of thefeasibility study in hand, ESKOM will assess jointventure possibilities with technology vendors and localinvestors. To meet the projected demand for newpower, ESKOM will likely need to commit to theKomati demonstration project within the next year.India. In March 2000, President Clinton spent a weekin India and Pakistan addressing environmental,economic, health, and other issues of joint concern.

During his stay in India, the President announcedseveral initiatives to protect the environment, developclean energy sources, and combat climate change, someof which could have potential for clean coal technologyapplications.One initiative was a Joint Statement on Energy and theEnvironment, signed by the U.S. Secretary of State andIndia’s Minister of External Affairs. Of particularrelevance to the Office of Fossil Energy is a provisionfor improvements in power plant efficiency, an area onwhich the efforts of FE in India have long been focused.The goals are a 15 percent improvement in generatingefficiency by 2008, along with a 10 percent increase inuse of biomass and other renewables by 2012. Sincemost of India’s power is supplied by low-grade coalburned in aging and inefficient facilities, it is likely thatmuch of the improvement will have to come frommodification of existing coal-fired plants or installationof new ones. The agreement notes that India is makingfossil fuel energy use cleaner and more efficient, andintends to further improve energy efficiency in theelectric power sector by focusing on renovation andmodernization to include repowering of older plants toimprove plant load factors, upgrading, and strengtheningtransmission and distribution systems as well as toreduce transmission and distribution losses. Theagreement expands upon an earlier Joint Statement ofOctober 1999. A Joint Consultative Group on CleanEnergy and Environment will be created to promotecollaborative projects and cooperation.While in India, the President announced a $45 millionenergy efficiency/clean energy package that includes asecond, five-year phase of the Greenhouse GasPollution Prevention Project headed by the U.S.Agency for International Development (USAID) withtechnical support from FE, the result of a ParticipatingAgency Service Agreement with USAID-India. Currentactivities are directed toward reducing the amount of

greenhouse gas emissioelectricity generated.Over the past five yearby FE have provided tepower stations and trai1994, FE also helped thCorporation (NTPC), tworld, to establish the Efficiency and EnvironNoida, near New Delhident, power industry-fuexperts who manage vapower industry, includiment, R&D, and traininresource for technical ksupport of improved poincreasing operating efenvironmental protectiIn the second phase, teSupplement, FE will assustain greenhouse gas will also introduce morgreenhouse gas technoimprove the utilization Three months after the regional CenPEEP was Lucknow in the state ofrom FE and USAID. Tand another planned foexpedite training throuDepartment of Energy instrumental in demonsand environmental impand State Electricity B“Heat Rate ImprovemePlants.” During 2001, Ftraining in power plant 
4-20 Program Update 2000

operating and maintenance practices, as well asenvironmental monitoring. Efficiency improvements inIndian plants will help meet the 15 percent improvement goal established in March 2000 by the U.S. andIndian governments.On September 13, 2000, DOE, USAID, India’sMinistry of Power, and the NTPC signed a Protocol ofIntent to conduct a detailed technical and economicfeasibility study for setting up a commercial-scaleintegrated gasification combined-cycle demonstrationplant in India. The study will seek to establish the mostsuitable IGCC technology for India’s coal and environmental conditions, explore possible financing structures competitive in India, and develop an implementation plan for IGCC technology demonstration in India.The agreement was signed for by the DOE DeputySecretary, the USAID Deputy Administrator, India’sSecretary of Power, and the NTPC Director. Thisfollows the signing of a Joint Statement on Cooperationin Energy and Environment in New Delhi on March 22,2000, which articulated both countries’ desire toincrease their energy and environment cooperation.Both USAID and NETL are discussing possible IGCCactivities to be conducted under the ongoing Greenhouse Gas Pollution Prevention Project.Foreign Service Of eign Service Officer Training Course. raining Course. In

cooperation with the U.S. Department of State’sForeign Service Institute and Bureau of Economic andBusiness Affairs, the Department of Energy hosted thefirst week-long Coal and Power Sector Training Coursein the Pittsburgh, Pennsylvania, area during July 24-28,2000. The 22 participants were given several extensivesite tours to learn about various technologies. Theyalso attended lectures and discussions on timely issuesin the international energy arena, such as electricityderegulation, climate change, and emergence of newtechnologies for clean coal, distributed generation,

greenhouse gas reduction and other pollution controls,and ultra-clean fuels.The Foreign Service Institute was established in 1947to furnish Foreign Service Officers (FSOs) withtraining throughout their careers. The FSOs explainU.S. policies and interests to foreign nationals and theirgovernments, and also have a function in promotingexports and negotiating international agreements.Increasingly, FSOs are involved in energy matters. TheForeign Service promotes free-market economies andworks with international institutions toward progress inmeeting global concerns regarding the environment andother international interests. The Foreign Service alsoacts as an advocate for U.S. business interests and toprotect intellectual property rights. According to theState Department, efforts by FSOs resulted in U.S.exports totaling $934 billion in 1998, or 12 percent ofthe U.S. gross domestic product.The training course provided participants an overviewof the fundamentals of the coal and power sectorsworldwide, and provided a forum for discussion amongenergy specialists from the U.S. government andprivate industry. Emphasis was placed on technological changes in the coal and power industry specificallyrelated to developing countries. During the week oftraining, participants made a number of field trips tosites including Ebensburg Power Company’s 50-MWewaste coal-fired cogeneration plant; Edison MissionEnergy’s 2,012-MWe pulverized coal-fired Homer CityPlant and on-site coal preparation plant; First Energy/Penn Power’s 2,742-MWe Bruce Mansfield PowerPlant with its large wet SO2 scrubber, and NationalGypsum Company’s adjacent wallboard manufacturingplant; Allegheny Energy’s 88-MWe gas turbineSpringdale plant; and the Siemens Westinghouse SolidOxide Fuel Cell pilot manufacturing facility.

Implementation of the Fnumerous private compasuccessful government-iCoal and Power Sector tsupported Oil and Gas Inton, Texas, the following Institute intends to offer in the future.
5. CCT 5. CCT 5. CCT Projects

The CCT projects are sprindicated in white.

Introduction oductionoduction oductionoductionCCT Program demonstrations provide a portfolio oftechnologies that will enable coal to continue toprovide low-cost, secure energy vital to the nation’seconomy while satisfying energy and environmentalgoals well into the 21st century. This is being carried

out by addressing four basic market sectors: (1)environmental control devices for existing and newpower plants, (2) advanced electric power generationfor repowering existing facilities and providing newgenerating capacity, (3) coal processing for clean fuelsto convert the nation’s vast coal resources to cleanfuels, and (4) industrial applications dependent uponcoal 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 costeffective control options for the full range of boilertypes. The 19 environmental control device projectsare valued at more than $702 million. These includeseven NO

x emission control systems installed in more

than 1,750 MWe of utility generating capacity, five SO2emission control systems installed on approximately770 MWe, and seven combined SO2/NOx emission

control systems installed or planned on more than 665MWe of capacity.To respond to load growth as well as growing environmental concerns, the program provides a range ofadvanced electric power generation options for bothrepowering and new power generation. These advanced options offer greater than 20 percent reductions in greenhouse gas emissions; SO2, NOx, and particulate emissions far below New Source Performance Stan- dards (NSPS); and salable solid and liquid by-products in lieu of solid wastes. Over 1,800 MWe of capacity are represented by 11 projects valued at more than $2.8 billion. These projects include five fluidized-bed combustion (FBC) systems, four integrated gasification combined-cycle (IGCC) systems, and two advanced combustion/heat engine systems. These projects will provide the demonstrated technology base necessary to meet new capacity requirements in the 21st century. Also addressed are approaches to converting raw run- of-mine coals to high-energy-density, low-sulfur products. These products have application domesti- cally for compliance with the Clean Air Act Amend- ments of 1990 (CAAA). Internationally, both the products and processes have excellent market potential. Valued at more than $519 million, the five projects in the coal processing for clean fuels category represent a diversified portfolio of technologies. Three projects involve the production of high-energy-density solid fuels, one of which also produces a liquid product equivalent to No. 6 fuel oil. A fourth project is demonstrating a new methanol production process. A fifth effort complements the process demonstrations by providing an expert computer software system that enables a utility to assess the environmental, opera- tional, and cost impact of utilizing coals not previously burned at a facility, including upgraded coals and coal blends. Projects also were undertaken to address pollution problems associated with coal use in the industrial sector. These included dependence of the steel industry on coke and th

in coke making; relianclow-cost indigenous, aand the need for many consider switching to ccosts. The five industrcombined value of neaencompass substitution in iron making, integraprocess with the producement kiln emissions demonstrations of an intor and a pulse combusThe remainder of this sthe technologies being each project.
5-2 Program Update 2000

Unique CT-121 SO2 scrubbnumber of functions and el

Technology Overview

Environmental Control Devices Environmental Control Devices

Environmental 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 echnologyechnology. Sulfur dioxide is an acid

gas formed during coal combustion, which oxidizes theinorganic pyritic sulfur (Fe2S) and organically bound

sulfur in the coal. Identified as a precursor to theformation of acid rain, SO2 was targeted in Title IV of

the CAAA. Phase I of Title IV, effective in 1995,affected 261 coal-fired units nationwide. The requiredSO2 reduction was moderate and largely met byswitching to low-sulfur fuels. This year, Phase II ofTitle IV became effective, impacting all fossil fuelfired units, but most of all, the approximately 700 preNSPS coal-fired facilities. The CAAA providesutilities flexibility in control strategies through SO2

allowance trading. This permits a range of controloptions to be applied by a utility, as well as allowancepurchasing. Recognizing this, the CCT Program hassought to provide a portfolio of SO2 control technologies.

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

driven primarily by different conditions that existwithin the pre-NSPS boiler population impacted by the

CAAA. There is a tremendous range in critical factors,such as size, type, age, and space availability for theseboilers.On one end of the spectrum are the smaller, olderboilers with limited space for adding equipment. Forthese, sorbent injection techniques hold promise.Sorbent is injected into the boiler or the ductwork, andhumidification is incorporated in some fashion toproperly condition the flue gas for efficient SO2

capture. Equipment size and complexity are held to aminimum to keep capital costs and space requirementslow. Both limestone and lime sorbents are used.Limestone costs are about one-third that of hydratedlime; but limestone must be conditioned (calcined), andeven then, it is less effective in SO2 capture (under

simple sorbent injection conditions) than hydratedlime. Where limestone is used, it is injected into theboiler to produce calcium oxide, which reacts with SO2

to form solid compounds of calcium sulfite andcalcium sulfate. Both limestone and lime injectionrequire the presence of water (humidification) and acalcium-to-sulfur (Ca/S) molar ratio of about 2.0 forsulfur capture efficiencies of 50–70 percent.In the mid-range of the spectrum are 100- to 300-MWeboilers less than 30 years old and somewhat spaceconstrained. For many of these, an increase in equipment cost is justified by enhanced performance. Theapproach involves introduction of a reactor vessel inthe flue gas stream to create conditions to enhance SO2capture beyond that achievable with the simplersorbent injection systems. Lime is used, as opposed tolimestone, and sulfur capture efficiencies up to 90percent can be achieved at Ca/S molar ratios of 1.3–2.0. This category of control device is called a spraydryer because the solid by-product from the reaction isdry.

At the other end of the sMWe and larger) existinspace availability, and nadvanced flue gas desulfscrubbers, with higher ccapture efficiency than oeffective. These systemmore complex reactors tHowever, the sorbent is which reduces operating technologies reduce capand increase overall planachieved SO2 removal e

percent at a Ca/S molar operating costs significaother two approaches. Finitial AFGD solid by-prdewatered to produce gyThe CCT Program succesorbent injection systemtwo AFGD systems. All Exhibit 5-1 briefly summperformance of the SO2 

described in the project 
Exhibit 5-1

CCT Program SO2 Control T Control T Control Technology Characteristics

Coal Sulfur SO

Project Project Process Process Content Content Red

Re

Red

10-MWe Demonstration of Gas Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7–3.5% 60–Absorption particulate recycle (lime sorbent)Confined Zone Dispersion Flue Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.5–2.5% 50% Desulfurization DemonstrationLIFAC Sorbent Injection Desulfurization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% 70% Demonstration Project humidification vessel and sorbent recycleAdvanced Flue Gas Desulfurization AFGD—cocurrent flow, integrated quench absorber tower, and reaction 2.25–4.7% 94% Demonstration Project tank with combined agitation/oxidation (gypsum by-product)Demonstration of Innovative Applications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2–3% 90+of Technology for the CT-121 FGD Process Reactor®) for combined SO2 and particulate capture (gypsum by-product)

The 10-MWe AirPol gas suspension absorptiondemonstration unit.

Pure Air absorber module 

LIFAC reactor being installed in Richmond, Indiana. Desulfurization Demonstr
5-4 Program Update 2000

The Confined Zone Dispersion FGD technology achieved50% SO2 removal efficiency. The extended ductwork,where the lime slurry was injected, is shown on the left.

NOx Control 

Technology echnologyechnology. Nitrogen oxides are formed

from oxidation of nitrogen contained within the coal(fuel-bound NOx) and oxidation of the nitrogen in the

air 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 peak

temperatures.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 reduceemissions to 0.50 and 0.45 lb/106 Btu, respectively. In

2000, 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 nonattainment prompted the U.S. Environmental ProtectionAgency (EPA) to issue a NOx transport State Implementation Plan (SIP) call for 22 states and the District

of Columbia to cut NOx emissions to 85 percent below

1990 rates or achieve a 0.15 lb/106 Btu emission rateby May 2003. The fate of the SIP call is uncertain aslitigation 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 NOx

emissions can be accomplished either by modifying thecombustion process or by acting upon the products ofcombustion (or combinations thereof). Combustionmodification technologies include low-NOx burners

(LNBs), advanced overfire air (AOFA), and reburningprocesses using either natural gas or coal.Postcombustion processes for treating flue gas includeselective catalytic reduction (SCR) and selectivenoncatalytic reduction (SNCR). Advanced controlscan also help in NOx reductions.The LNBs regulate the initial fuel-air mixture, velocities, and turbulence to create a fuel-rich flame core,and control the rate at which additional air required tocomplete combustion is mixed. Thisstaging of combustion avoids a highlyoxidized environment and hot spotsconducive to formation of fuel-boundNOx and thermal NOx. Alone, LNBstypically can achieve 40–50 percentNOx reduction.The AOFA technology involvesinjection of air above the primarycombustion zone to allow the primarycombustion to occur without theamount of oxygen needed forcomplete combustion. This oxygendeficiency mitigates fuel-bound NOx

formation. The AOFA, injected athigh velocity, creates turbulent mixingto complete the combustion in agradual fashion at lower temperaturesto mitigate thermal NOx formation.

Usually, AOFA is used in combination with LNBs; but alone, AOFA can

achieve 10–25 percent N

LNB/AOFA systems gen

emission reductions of 3upon boiler type.In reburning, a percentagis diverted to injection pcombustion zone. Eitheas the reburning fuel to pheat input to the boiler. to create a fuel-rich zone reducing rather than oxientering this zone is stripelemental nitrogen. Comburnout zone where air iReburning has applicatio

Exhibit 5

Group 1 and 2 Boi

and Phase II NOx Em

 Num of 

Boiler T Boiler TBoiler Types Boile

 Boile

 Boile

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

Source: U.S. Environmental Protection AgencyReduction Program, Final Rule for Phase II, Gr(http://www.epa.gov/docs/acidrain/noxfs3.html
cyclone boilers, and can achieve NOx emissionreductions 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. The

SNCR 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 temperaturesbetween 600–800 oF. Generally, SNCR and SCRsystems alone can achieve NOx emission reductions of

30–50 percent and 80–90+ percent, respectively.Advanced control systems using artificial intelligenceare also becoming an integral part of NOx controlsystems. These systems can handle the numerousparameters and optimize performance to reduce NOxwhile enhancing boiler performance.Under the CCT Program, seven NOx control technologies were assessed encompassing LNBs, AOFA,reburning, SNCR, SCR, and combinations thereof. Sixof the seven projects have completed operations. One

project has been extended. Exhibit 5-3 briefly summarizes the characteristics and performance of thetechnologies that are described in more detail in theproject fact sheets.

Combined SO2/NOx Control 

Technology echnologyechnology. Combined

SO2/NOx control systems encompass those technologies that combine previously described controlmethods and those that apply other synergistic techniques. Three of the projects combine either LNBs orgas reburning with sorbent injection. In one of these,SNCR is used with LNBs to enhance performance.Another project combines a number of techniques toimprove overall system performance, such as LNBswith SNCR, unique space-saving and durable wetscrubber design, sorbent additive, and artificialintelligence controls. The balance of the six projectsuse synergistic methods not previously described.SOx-NOx-Rox BoxTM incorporates an SCR catalyst in ahigh-temperature filter bag for NOx control and appliessorbent injection for SO2 control. The high-temperature filter bag, operated in a standard pulsed-jetbaghouse, protects the SCR catalyst, allows operationat optimal NOx control temperatures, forms a sorbentcake on the surface to enhance SO2 capture, andprovides high-efficiency particulate capture.SNOXTM uses SCR followed by catalytic oxidation ofSO2 to SO3 with condensation of the SO3 in thepresence of water to produce sulfuric acid. Followingthe SCR with the catalytic oxidation allows the SCR tooperate at optimal ammonia concentration withoutworry of ammonia slip (ammonia passing to the secondcatalyst is broken down into water vapor, nitrogen, anda small amount of NOx). Furthermore, most particulates passing through the upstream baghouse are

captured in the sulfuric acid condensing unit. Thesystem produces no solid waste.

All six of the combined projects have completebriefly summarizes the of the technologies thasheets.

Advanced Electric 

Technology echnologyechnology

Advanced electric powenable the efficient and generation of electricitgeneration projects selare responsive to capacmeeting long-term demments, and meeting strieffective in 2000. Theized by high thermal efemissions, reduced CO

problems, and enhancepower generation technmodules, allowing phademand growth, and to requirements of municgenerators.There are five generic generation technologieProgram. The characteare outlined here, and ttechnologies are presensheets.

Fluidized-Bed Combu

tion (FBC) reduces em

controlling combustion sorbent (such as crushetion chamber along witmixed with the limestothe combustion chamb

Kodak Park was one of two sites demonstrating micronizedcoal reburning.
5-6 Program Update 2000

Exhibit 5-3

CCT Program NOx Control T Control T Control Technology Characteristics

Boiler Size/ Boiler Size/ 

Project Project Process Process Type 

Demonstration of Advanced Combustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500-MWe/wall for a Wall-Fired Boiler and artificial intelligence controlsDemonstration of Coal Reburning for Cyclone Coal reburning—30% heat input 100-MWe/cyclone Boiler NO

x

 Control

Full-Scale Demonstration of Low-NO

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

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

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

for NO

x

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

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

Technology for the Control of NOx Emissions chemical compositions

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

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

Emissions from Coal-Fired Boilers

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

New air fan in the foreground and new pulverizer in thebackground for the micronized coal reburning project.

The SCR demonstration faCrist.
Exhibit 5-4

CCT Program Combined SO2/NOx Control T Control T Control Technology Characteristi

Coal Sulfur SO2/

Project Project Process Process Content Content Redu

Redu

Redu

SNOXTM Flue Gas Cleaning Demonstration SCR/oxidation catalyst/sulfuric acid condenser—synergistic 3.4% 95%/Project catalyst effect and no solid wasteLIMB Demonstration Project Extension and LNB/sorbent injection—furnace and duct injection, calcium-based 1.6–3.8% 60–7Coolside Demonstration sorbentsSO

x

-NO

x-Rox BoxTM Flue Gas Cleanup SCR/high-temperature baghouse/sorbent injection—SCR in high- 3.4% 80–9

Demonstration Project temperature filter bag and calcium-based sorbent injectionEnhancing the Use of Coals by Gas Reburning Gas reburning/sorbent injection (GR-SI)—calcium-based sorbents 3.0% 50–6and Sorbent Injection used in duct injectionMilliken Clean Coal Technology Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5–4.0% 98%/Project durable scrubber designIntegrated Dry NOx/SO2 Emissions LNB/SNCR/sorbent injection—calcium- and sodium-based 0.4% 70%/

Control System sorbents used in duct injection

Coolside process sorbent distribution bottle and feed lines ontop of bypass duct.

Humidification panels and controls on the side of duct workwhere water is injected into the flue gas for GR-SI.

The SO

x

-NO

x-Rox BoxTM 

and tie-in.
5-8 Program Update 2000

The 110-MWe Nucla ACFB demonstration enabledPyropower Corporation (now owned by Foster Wheeler) tosave almost three years in establishing a commercial line ofACFB units.as SO2 is captured by the sorbent in the bed to form a

solid calcium compound that is removed with the ash.The resultant waste is a dry, benign solid that can bedisposed of easily or used in agricultural and construction applications. More than 90 percent of the SO2 can

be 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 temperature range is about half that of a conventional pulverized-coal boiler and below the temperature that thermalNOx is formed. In fact, FBC NOx emissions are about

70–80 percent lower than those for conventionalpulverized-coal boilers. Thus, fluidized-bed combustors substantially reduce both SO2 and NOx emissions.

Also, FBC has the capability of using high-ash coal,

whereas conventional pulverized-coal units must limitash content in the coal to relatively low levels.Two parallel paths were pursued in FBC development—bubbling and circulating beds. Bubblingfluidized-beds use a dense fluid bed and low fluidization velocity to effect good heat transfer and mitigateerosion of an in-bed heat exchanger. Circulatingfluidized-beds use a relatively high fluidizationvelocity that entrains the bed material, in conjunctionwith hot cyclones, to separate and recirculate the bedmaterial from the flue gas before it passes to a heatexchanger. Hybrid systems have evolved from thesetwo basic approaches.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 andwaste are reduced relative to AFBC, as well as boilersize per unit of power output.Second-generation PFBC integrates the combustor witha pyrolyzer (coal gasifier) to fuel a gas turbine (toppingcycle), and the waste heat is used to generate steam fora steam turbine (bottoming cycle). The inherentefficiency of the gas turbine and waste heat recovery inthis combined-cycle mode significantly increasesoverall efficiency. Such advanced PFBC systems havethe potential for efficiencies over 50 percent.Of the five fluidized-bed combustion projects, twohave successfully completed demonstration (one PFBCand one AFBC), and the other three are in the projectdefinition and design phase as of the end of fiscal year2000.

Integrated Gasification Combined-Cycle. The

IGCC process has four basic steps: (1) fuel gas is

generated from coal reacsteam and an oxidant (oxatmosphere; (2) the fuel a hot-gas cleanup system and nitrogen compoundsproduce steam and then clean fuel gas is combusto produce electricity; anhot exhaust from the gas recovery steam generatoproduce additional electgenerator.Integrated gasification camong the cleanest and mclean coal technologies. and particulates are remin the gas turbine, that isadded. For this reason, tof gas to be treated than The chemical compositigas stream must be cleanto achieve low emissioncomponents, such as the erosion and corrosion.In a coal gasifier, the sulthe form of hydrogen suIn some IGCC systems, gas is captured by a sorbOthers use existing provsulfide removal processepercent of the sulfur, but which is an efficiency pecleanup systems are now hot cleanup systems, the a bed of metal oxide parZinc oxide can absorb sutures in excess of 1,000 
regenerated and reused 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 99.9percent of the sulfur in the gas stream. With hot-gascleanup, IGCC systems have the potential for efficiencies of over 50 percent.High levels of nitrogen removal are also possible.Some of the coal’s nitrogen is converted to ammonia,which can be almost totally removed by 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 Integrated Gasification Fuel Cell. A typical fuel cell

system 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, aninverter to convert direct current to alternating current,and a heat recovery system. The heat recovery systemwould be used to produce additional electric power in abottoming steam cycle.Energy conversion in fuel cells is more efficient thantraditional energy conversion devices (up to 60percent, 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 includesan 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, one has completed operations, two are in operation, and one is in the projectdefinition and design phase as of the end of fiscal year

2000. The project in the design phase plans toincorporate a molten carbonate fuel cell (MCFC).Coal-Fir Coal-FirCoal-Fired Diesel ed Dieseled Diesel ed Dieseled 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 toproduce steam for a steam-turbine electric generatingsystem (combined cycle). Environmental controlsystems 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.

Slagging Combustor. Many new coal-burning

technologies are designed to remove the coal ash asmolten slag from the combustor rather than the furnace.Most of these slagging combustors are based on acyclone concept. In a cyclone combustor, coal isburned in a separate chamber outside the furnacecavity. The hot combustion gases then pass into theboiler where the actual 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 impurities meltand form slag, hence the name slagging combustor. Avortex of air (the cyclone) forces the slag to the outerwalls of the combustor where it can be removed aswaste.Results show that by positioning air injection ports sothat coal is combusted in stages, NOx emissions can be

reduced by 70–80 percent. Injecting limestone into thecombustion chamber has the potential to reduce sulfuremissions by 90 percent in combination with a spray

dryer absorber. Advanreplace oil-fired units iapplications or be used cyclone boilers.Exhibit 5-5 summarizesize of the advanced elnologies presented in t

Coal Processing fo

The coal processing catechnologies designed low-sulfur solid and clsystems to assist users quality on boiler perforWestern SynCoal LLCprocess applies mostly low-Btu, low-sulfur suremove moisture and sobjective is to enhance already low-sulfur coaproperties of the coal istability (prevent spontand handling. In the pBtu/lb, 25–40 percent mpercent sulfur is convewith 1.0 percent moistusulfur. The SynCoal® pindustrial facilities. Prthrough 2001.The ENCOAL project, testing in July 1997, uslow-Btu, low-sulfur suenergy-density, low-suliquid fuel comparable tion is a pyrolysis procoxygen) performed at m
5-10 Program Update 2000

Exhibit 5-5

CCT Program CCT Program Advanced Electric Power Generation Technology Characte

Project Project Process Process Size 

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project Pressurized circulating fluidized-bed combustion 137 MWe (net) McIntosh Unit 4B Topped PCFB Demonstration Project McIntosh 4A with pyrolyzer and topping combustor 240 MWe (net) JEA Large-Scale CFB Combustion Demonstration Project Atmospheric circulating fluidized-bed combustion 297.5 MWe (gross)

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

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

Integrated Gasification Combined Cycle

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

Piñon Pine IGCC Power Project Air-blown, fluidized-bed gasifier with hot gas cleanup 107 MWe (gross); 9

Tampa Electric Integrated Gasification Oxygen-blown, entrained-flow gasifier with hot and cold gas cleanup 313 MWe (gross); 2Combined-Cycle ProjectWabash River Coal Gasification Repowering Project Oxygen-blown, two-stage entrained-flow gasifier with cold gas cleanup 296 MWe (gross); 2

Advanced Combustion/Heat Engines

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

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

a Plus a 2.0 MWe molton carbonate fuel cell.

The coal slurry and sorbent injectors for the Tidd PFBCdemonstration. The Wabash IGCC gas cleanup system. The TRW slagging combus
pressures. It produces condensable volatile hydrocarbons in addition to solids and gas. The condensablefraction is drawn off as a liquid product. Most of thegas is used to provide on-site energy requirements.The process solid is significantly beneficiated toproduce an 11,000 Btu/lb low-sulfur solid fuel. Thedemonstration plant processed 500 tons per day ofsubbituminous coal, and produced 250 tons per day ofsolid Process-Derived Fuel (PDF®) and 250 barrels perday of Coal-Derived Liquids (CDL®). Both the solidand liquid fuels have undergone test burns at utility andindustrial sites. The project was successfully completed.The liquid phase methanol (LPMEOHTM) 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 capability of the process by simulating application in an IGCC system and the fuel characteristics of the unrefined product. ABB Combustion Engineering, Inc., and CQ Inc., have developed a personal computer software package, CQE®, that will serve as a predictive tool to assist utilities in selecting optimal quality coal for a specific boiler based on operational, economic, and environ- mental considerations. Algorithms were developed and verified through comparative testing at bench, pilot, and utility scale. Six large-scale field tests were conducted at five separate utilities. The software has been released for commercial use. More than 35 U.S. utilities and one U.K. utility have received CQE® through Electric Power Research Institute (EPRI) membership. It is estimated that CQE® saves U.S. utilities about $26 million annually. Exhibit 5-6 summarizes the process characteristics and size of the coal processing for clean fuels technologies presented in the project fact sheets.

Industrial Industrial Industrial Industrial Industrial Applications Technology echnologyechnology

Technologies applicable to the industrial sector addresssignificant environmental issues and barriers associatedwith coal use in industrial processes. These technologies are directed at both continuing coal use andintroducing coal use in various industrial sectors.One of the critical environmental concerns has to dowith pollutant emissions resulting from producing cokefrom coal for use in steel making. Two approaches tomitigate or eliminate this problem are being demonstrated. In one, about 40 percent of the coke isdisplaced through direct injection of granular coal intoa blast furnace system. The coal is essentially burnedin the blast furnace where the pollutant emissions arereadily controlled (as opposed to first coking the coal).

The other approach elimaking by using a direprocess, raw coal is intproduce reducing gas afurnace; no coke is reqcleaned and used to fuegeneration.Coal is often the fuel obecause production cocost. Faced with the n

to address growing solindustry sponsored the SO2 scrubber. The suc

Passamaquoddy Technuses cement kiln dust, control SO2 emissions, 

acid gases to fertilizer, cement kiln feedstock, new wastes are generatis converted to feedstoapplication for controllproduction and waste-tIn many industrial boillow, stable price of coatute for oil and gas feedconversion of oil- and addition of SO2 and NO

need for a coolant wateand gas-fired units are 

use relatively tight tube potential ash fouling; athe combustor, precludFor these reasons, the Cadvanced air-cooled, savoid these potential ptor stages introduction 

sorbent to control SO2, 

Shown is the Coltec coal-fired diesel being installed at the University of Alaska in Fairbanks.
5-12 Program Update 2000

The LPMEOHTM process pmethanol, all of which is usCompany in Kingsport, Ten

Western SynCoal Partnership’s advanced coal conversionprocess plant in Colstrip, Montana, has produced over 1.5million tons of SynCoal® products.

Exhibit 5-6

CCT Program Coal Processing for Clean Fuels Technology Characteris

Project Project Process Process Size 

Commercial-Scale Demonstration of the Liquid Phase Methanol Liquid phase process for methanol production from 80,000 gal/day (LPMEOHTM) Process coal-derived syngasAdvanced Coal Conversion Process Demonstration Advanced coal conversion process for upgrading 45 tons/hr 

low-rank coals

Development of the Coal Quality ExpertTM Coal Quality ExpertTM computer software Tested at 250–880 ENCOAL® Mild Coal Gasification Project Liquids-from-coal (LFC®) mild gasification to 1,000 tons/day* 

produce solid and liquid fuels

*Operated at 500 ton

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®.
to prevent tube fouling, and uses air cooling to eliminate the need for water circuitry.The pulse combustor to be demonstrated byThermoChem has a wide range of applications. Thetechnology can be used in many coal processes,including coal gasification and waste-to-energyapplications.The cement kiln, slagging combustor, and blast furnacegranular-coal injection projects are completed. TheCPICORTM and the ThermoChem projects are in thedesign phase and the construction phase, respectively,as of the end of fiscal year 2000.Exhibit 5-7 summarizes process characteristics andsize for the industrial applications technologiespresented in more detail in the project fact sheets.Project Fact Sheets oject 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 thathave successfully completed operational testing. Theexpanded fact sheets for completed projects contain asummary of the major results from the demonstrationas well as sources for obtaining further information,specifically, contact persons and key references.Information provided in the fact sheets includes theproject participants and team members, projectobjectives, significant project features, processdescription, major milestones, progress (if ongoing) orsummary of results (if completed), and commercialapplications. To prevent the release of project-specificinformation of a proprietary nature, process flow

diagrams contained in the fact sheets are highlysimplified and presented only as illustrations of theconcepts involved in the demonstrations. The portionof the process or facility central to the demonstration isdemarcated by the shaded area.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 havingcompleted operations. A shaded area distinguishesprojects having completed operations from ongoingprojects. Within these breakdowns, projects are listedalphabetically by participant. In addition, Exhibit 5-8indicates the solicitation under which the project wasselected; its status as of June 30, 2000; and the pagenumber for each fact sheet. Exhibit 5-9 lists theprojects alphabetically by participant and providesproject location and page numbers. A key to interpreting the milestone charts is provided in Exhibit 5-10.An appendix containing contact information for all ofthe projects is provided as Appendix D. A list ofacronyms used in this document is provided asAppendix E.
5-14 Program Update 2000

The Cement Kiln Flue Gas crystallizer and condenser condenser in background.

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

Exhibit 5-7

CCT Program Industrial CCT Program Industrial Applications Technology Characteristics

Project Project Process Process Size 

Clean Power from Integrated Coal/Ore Direct reduction iron-making process to eliminate coke; 3,300 tons/day of hot mReduction (CPICORTM) combined-cycle electric power generation 170 MWePulse Combustor Design Qualification Test Advanced combustion using Manufacturing and Technology 30x106 Btu/hr 

Conversion International’s pulse combustor/gasifier

Blast Furnace Granular-Coal Injection System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of hoDemonstration Project metal/furnaceAdvanced Cyclone Combustor with Internal Advanced slagging combustor with staged combustion and sorbent 23 x 106 Btu/hr 

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

and fertilizer and distilled water produced

Front view of Coal Tech’s advanced cyclone combustor
Shaded area indicates projects having completed operations.

Exhibit 5-8

Project Fact Sheets by Application Category

Project Project Participant Solicitatio

Environmental Control Devices

SO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/comConfined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/comLIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCT-III/comAdvanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/comDemonstration of Innovative Applications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/com

NO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/exteDemonstration of Coal Reburning for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/com

Full-Scale Demonstration of Low-NO

x

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

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

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

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

for the Control of NO

x Emissions from High-Sulfur, Coal-Fired Boilers

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

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/comLIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/comSO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/com

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/com

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/coIntegrated Dry NOx/SO2 Emissions Control System Public Service Company of Colorado CCT-III/com

Advanced Electric Power Generation

Fluidized-Bed Combustion

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

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

JEA Large-Scale CFB Combustion Demonstration Project JEA CCT-I/desig
5-16 Program Update 2000

Shaded area indicates projects having completed operations.

Exhibit 5-8 (continued) Exhibit 5-8 (continued)

Project Fact Sheets by Application Category

Project Project Participant Solicitation

Tidd PFBC Demonstration Project The Ohio Power Company CCT-I/complNucla CFB Demonstration Project Tri-State Generation and Transmission CCT-I/compl

Association, Inc.

Integrated Gasification Combined-Cycle

Kentucky Pioneer Energy IGCC Demonstration Project Kentucky Pioneer Energy, LLC CCT-V/desigPiñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/operTampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/operWabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering CCT-IV/comp

Project Joint Venture

Advanced Combustion/Heat Engines

Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/constHealy Clean Coal Project Alaska Industrial Development and CCT-III/comp

Export Authority

Coal Processing for Clean Fuels

Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process Air Products Liquid Phase CCT-III/oper

Conversion Company, L.P.

Advanced Coal Conversion Process Demonstration Western SynCoal LLC CCT-I/operatDevelopment of the Coal Quality ExpertTM ABB Combustion Engineering, Inc. CCT-I/compl

and CQ Inc.

ENCOAL® Mild Coal Gasification Project ENCOAL Corporation CCT-III/comp

Industrial Applications

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) CPICORTM Management Company LLC CCT-V/desig

Pulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/cons

Blast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/compAdvanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/complCement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/comp
Exhibit 5-9

Project Fact Sheets by Participant Project Fact Sheets by Participant

Participant Project Project L

L

L

ABB Combustion Engineering, Inc. and CQ Inc. Development of the Coal Quality ExpertTM HABB Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project NAir Products Liquid Phase Conversion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) K

Process

AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption WAlaska Industrial Development and Export Authority Healy Clean Coal Project HArthur D. Little, Inc. Clean Coal Diesel Demonstration Project FaBabcock & Wilcox Company, The Demonstration of Coal Reburning for Cyclone Boiler NOx Control C

Babcock & Wilcox Company, The Full-Scale Demonstration of Low-NOx Cell Burner Retrofit A

Babcock & Wilcox Company, The LIMB Demonstration Project Extension and Coolside Demonstration Lo

Babcock & Wilcox Company, The SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project D

Bechtel Corporation Confined Zone Dispersion Flue Gas Desulfurization Demonstration Se

Bethlehem Steel Corporation Blast Furnace Granular-Coal Injection System Demonstration Project BCoal Tech Corporation Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control WCPICORTM Management Company LLC Clean Power from Integrated Coal/Ore Reduction (CPICORTM) V

CQ Inc. (see ABB Combustion Engineering and CQ Inc.)ENCOAL Corporation ENCOAL® Mild Coal Gasification Project G

Energy and Environmental Research Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection H

Sp

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

JEA JEA Large-Scale CFB Combustion Demonstration Project Ja

Kentucky Pioneer Energy, LLC Kentucky Pioneer Energy IGCC Demonstration Project Tr

Lakeland, City of, Lakeland Electric McIntosh Unit 4A PCFB Demonstration Project L

Lakeland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project L

LIFAC–North America LIFAC Sorbent Injection Desulfurization Demonstration Project R

New York State Electric & Gas Corporation Micronized Coal Reburning Demonstration for NOx Control La
5-18 Program Update 2000

Exhibit 5-9 (continued) Exhibit 5-9 (continued)

Project Fact Sheets by Participant Project Fact Sheets by Participant

Participant Project Project Lo

Lo

Lo

New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project LaOhio Power Company, The Tidd PFBC Demonstration Project BrPassamaquoddy Tribe Cement Kiln Flue Gas Recovery Scrubber ThPublic Service Company of Colorado Integrated Dry NOx /SO2 Emissions Control System De

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Ch

Sierra Pacific Power Company Piñon Pine IGCC Power Project Re

Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Co

Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Ne

Process

Southern Company Services, Inc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pe

NO

x Emissions from High-Sulfur, Coal-Fired Boilers

Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Combustion Ly

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

Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project Mu

ThermoChem, Inc. Pulse Combustor Design Qualification Test Ba

Tri-State Generation and Transmission Association, Inc. Nucla CFB Demonstration Project Nu

Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project We

Project Joint VentureWestern SynCoal LLC Advanced Coal Conversion Process Demonstration Co
Each fact sheet contains a bar chart that highlights major milestones—past and planned. The bar chart shows a project’s duration aperiod for three general categories of project activities—preaward, design and construction, and operation and reporting. The key what is included in each of these categories.

Preaward PreawardPreawardIncludes preaward briefings, negotiations, and other activities conducted during the period between DOE’s selectioof the project and award of the cooperative agreement.

Design and Construction

Includes the NEPA process, permitting, design, procurement, construction, preoperational testing, and other activitconducted prior to the beginning of operation of the demonstration.MTF Memo-to-fileCX Categorical exclusionEA Environmental assessmentEIS Environmental impact statement

Operation and Reporting

Begins with startup and includes operational testing, data collection, analysis, evaluation, reporting, and other activties to complete the demonstration project.

Exhibit 5-10

Key to Milestone Charts in Fact Sheets
5-20 Program Update 2000
Environmental Control Devices 

Environmental Control Devic

SO2 Control Technologies
5-22 Program Update 2000 

Environmental Control Devices

SO2 Control Technology

10-MWe Demonstration of e Demonstration of

Gas Suspension Absorption

Project completed. Project completed.Participant

AirPol, Inc.

Additional Team Members

FLS miljo, Inc. (FLS)—technology ownerTennessee Valley Authority—cofunder and site ownerLocation LocationLocationWest Paducah, McCracken County, KYTechnologyFLS’ Gas Suspension Absorption (GSA) system for fluegas desulfurization (FGD)

Plant Capacity/Production

10-MWe equivalent slipstream of flue gas from a175-MWe wall-fired boilerCoalWestern Kentucky bituminous: Peabody Martwick,3.05% sulfur; Emerald Energy, 2.61% sulfur; Andalax,3.06% sulfur; and Warrior Basin, 3.5% sulfur (usedintermittently)

Project Funding

Total project cost $7,717,189 100%DOE 2,315,259 30Participant 5,401,930 70

Project Objective

To demonstrate the applicability of Gas SuspensionAbsorption as an economic option for achieving Phase IICAAA SO2 compliance on pulverized coal-fired boilers

using high-sulfur coal.

Technology/Project DescriptionThe GSA system consists of a vertical reactor in whichflue gas comes into contact with suspended solids consisting of lime, reaction products, and fly ash. About99% of the solids are recycled to the reactor via a cyclone while the exit gas stream passes through an electrostatic precipitator (ESP) or pulse jet baghouse (PJBH)before being released to the atmosphere. The limeslurry, prepared from hydrated lime, is injected through aspray nozzle at the bottom of the reactor. The volumeof lime slurry is regulated with a variable-speed pumpcontrolled by the measurement of the acid content in theinlet and outlet gas streams. The dilution water addedto the lime slurry is controlled by on-line measurementsof the flue gas exit temperature.

A test program was structhe GSA reactor for redu

boilers using high-sulfur ronmental control capabimechanical performance signed parametric (factorinvolving six variables. BGSA unit to control SO2, 

conducted, and the effectPJBH combinations to co

were tested. Factorial tesruns to verify consistency 
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• Ca/S molar ratio had the greatest effect on SO2

removal, with approach-to-saturation temperaturenext, followed closely by chloride content.

• GSA/ESP achieved

– 90% sulfur capture at a Ca/S molar ratio of 1.3

with 8 oF approach-to-saturation and 0.04% chloride,

– 90% sulfur capture at a Ca/S molar ratio of 1.4

with 18 oF approach-to-saturation and 0.12% chloride, and

– 99.9+% average particulate removal efficiency.

• GSA/PJBH achieved

– 96% sulfur capture at a Ca/S molar ratio of 1.4

with 18 oF approach-to-saturation and 0.12% chloride,

– 3–5% increase in SO2 reduction relative to

GSA/ESP, and

– 99.99+% average particulate removal efficiency.

• GSA/ESP and GSA/PJBH removed 98% of the

hydrogen chloride (HCl), 96% of the hydrogenfluoride (HF), and 99% or more of most trace metals,except cadmium, antimony, mercury, and selenium.(GSA/PJBH removed 99+% of the selenium.)

• The solid by-product was usable as low-grade cement.

Operational Operational

• GSA/ESP lime utilization averaged 66.1% and

GSA/PJBH averaged 70.5%.

• The reactor achieved the same performance as a

conventional spray dryer, but at one-quarter to onethird the size.

• GSA generated lower particulate loading than a

conventional spray dryer, enabling compliance with alower ESP efficiency.

• Special steels were not required in construction, and

only a single spray nozzle is needed.

• High availability and reliability similar to other

commercial applications were demonstrated, reflecting simple design.

Economic EconomicEconomic• Capital and levelized 

for GSA installed in sulfur coal are complimestone scrubber wscrubber). EPRI’s TBased on EPRI cost capital cost (1990$) was $172/kW.

Ca(19

GSA—3 units at 50% capacityWLFO 

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

Ground breaking/construction started 5/92

Preaward PreawardPreaward

12/89 10/90 10/92

Design and Construction

DOE selected project

(CCT-III) 12/19/89 Environmental monitoring plan completed

10/2/92Operation initiated 10/92

Design completed 12/91

Cooperative agreement awarded 10/11/90

NEPA process completed (MTF) 9/21/90

Preoperational tests initiated 9/92Construction completed 9/92

6/95

Project completed/final rep

Operation completed 3/94
5-24 Program Update 2000 

Project Summary

The GSA has a capability of suspending a high concentration of solids, effectively drying the solids, and recirculating the solids at a high rate with precise control.This results in SO2 control comparable to that of wet

scrubbers and high lime utilization. The high concentration of solids provides the sorbent/SO2 contact area.

The drying enables low approach-to-saturation temperature and chloride usage. The rapid, precise, integral recycle system sustains the high solids concentration. The high lime utilization mitigates the largestoperating cost (lime) and further reduces costs byreducing the amount of by-product generated. TheGSA is distinguished from the average spray dryer byits modest size, simple means of introducing reagent tothe reactor, direct means of recirculating unused lime,and low reagent consumption. Also, injected slurrycoats recycled solids, not the walls, avoiding corrosionand enabling use of carbon steel in fabrication.

Environmental Performance

Exhibit 5-11 lists the six variables used in the factorialtests and the levels at which they were applied. Inletflue gas temperature was held constant at 320 oF. Factorial testing showed that lime stoichiometry had thegreatest effect on SO2 removal. Approach-to-saturation temperature was the next most important factor,

followed closely by chloride levels. Although anapproach-to-saturation temperature of 8 oF wasachieved without plugging the system, the test wasconducted at a very low chloride level (0.04%). Because water evaporation rates decrease as chloridelevels increase, an 18 oF approach-to-saturation temperature was chosen for the higher 0.12% coal chloride level. Exhibit 5-12 summarizes key results fromfactorial testing.A 28-day continuous run to evaluate the GSA/ESPconfiguration was made with bituminous coals averaging 2.7% sulfur, 0.12% chloride levels, and 18 oFapproach-to-saturation temperature. A subsequent 14-day continuous run to evaluate the GSA/PJBH configuration was performed under the same conditions as those of the 28-day run, except for adjustments in fly ash injection rate from 1.5–1.0 gr/ft3 (actual). The 28-day run on the GSA/ESP system showed that the overall SO2 removal efficiency averaged slightly more than 90%, very close to t

age Ca/S molar ratio of 1

inlet SO2. The system w

surge in inlet SO2 caused 

Warrior Basin coal for a waged 66.1%. The particuaged 99.9+% and emissio0.015 lb/106 Btu. The 14

system showed that the S

more than 96% at an ave1.43 moles Ca(OH)2/mol

averaged 70.5%. The paaveraged 99.99+% and e0.001–0.003 lb/106 Btu. All air toxics tests were c

low-chloride coal with a temperature and a high fl

tual). The GSA/ESP arraremoval efficiencies of gbarium, chromium, lead, for manganese; and less tmium, mercury, and selenration showed 99+% rembarium, chromium, lead, vanadium; with cadmium cury removal lower than The removal of HCl and utilization of lime slurry of particulate control concies were greater than 98

Operational Performa

Because the GSA system provide a contact area for 

pressure atomizer nozzleare not required to achievAlso, recycle of solids is material in the feed slurryexpensive abrasion-resist

Exhibit 5-12 GSA Factorial Testing Results Exhibit 5-11

Variables and Levels Used in

GSA Factorial Testing

Variable ariable Level

Approach-to-saturation temperature (°F) 8*, 18, and 28

Ca/S (moles Ca(OH)2/mole inlet SO2) 1.00 and 1.30

Fly ash loading (gr/ft3, actual) 0.50 and 2.0

Coal chloride level (%) 0.04 and 0.12Flue gas flow rate (103 scfm) 14 and 20

Recycle screw speed (rpm) 30 and 45

*8 °F was only run at the low coal chloride level.
Environmental Control Devices 

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 retrofitfeasible for space-confined plants and reduces installation cost. The GSA system slurry is sprayed on therecycled solids, not the reactor walls, avoiding directwall contact and the need for corrosion-resistant alloysteels. Furthermore, the high concentration of rapidlymoving solids scours the reactor walls and mitigatesscaling. The GSA system generates a significantly lowerdust loading than a conventional spray dryer, 2–5 gr/ft3for GSA versus 6–10 gr/ft3 for a spray dryer, thereby

easing the burden on particulate controls. The GSAsystem produces a solid by-product containing very lowmoisture. This material contains both fly ash and unreacted lime. With the addition of water, the by-productundergoes a pozzuolanic reaction, essentially providingthe characteristics of a low-grade cement.

Economic Performance

Using EPRI costing methods, which have been appliedto 30 to 35 other FGD processes, economics were estimated for a moderately difficult retrofit of a 300-MWeboiler burning 2.6% sulfur coal. The design SO2 removal efficiency was 90% at a lime feed rate equivalent

to 1.30 moles of Ca per mole of inlet SO2. Lime was

assumed to be 2.8 times the cost of limestone. It wasestimated that (1) the capital cost was $149/kW (1990$)with three units at 50% capacity, and (2) the levelizedcost (15-year constant 1990$) was 10.35 mills/kWh withthree 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 MWeand 2.6% sulfur coal was $172/kW (1990$). Also, because the GSA requires less power and has better limeutilization than a spray dryer, the GSA will have a loweroperating cost.

GSA market entry was sale of a 50-MWe unit wHamilton, Ohio, subsidment Office. A sale woto the U.S. Army for haGSA system has been splant. Sales to Taiwancombined value of $20 contracted for technical ment valued at $1.0 milContacts ContactsContactsNiels H. Kastrup, (281) 

FLS miljo, Inc.100 Glennborough DHouston, TX 77067(281) 539-3411 (fax)

Lawrence Saroff, DOE/James U. Watts, NETL

References

• 10-MWe Demonstra

tion Final Project P

Report. Report No. 

Inc. June 1995. (ADE95016681.)

• 10-MW Demonstrat

Final Public Design 

90542-T10. AirPolfrom NTIS as DE96

• SO2 Removal Using 

Technology. Topica

ment of Energy and 

• 10-MWe Demonstra

Absorption Process 

Research: Final Rep

90542-T10. Tennes1995. (Available fr

AirPol, Inc. successfully demonstrated the GSA system atTVA’s Center for Emissions Research, located at TVA’sShawnee Plant.

Commercial Applications

The low capital cost, moderate operating cost, and highSO2 capture efficiency make the GSA system particularly

attractive as a CAAA compliance option for boilers inthe 50- to 250-MWe range. Other major advantagesinclude the modest space requirements comparable toduct injection systems; high availability/reliability owingto design simplicity; and low dust loading, minimizingparticulate upgrade costs.
5-26 Program Update 2000 

Environmental Control Devices

SO2 Control Technology

Confined Zone DispersionFlue Gas DesulfurizationDemonstration

Project completed. Project completed.Participant

Bechtel Corporation

Additional Team Members

Pennsylvania Electric Company—cofunder and host

Pennsylvania Energy Development Authority—cofunderNew York State Electric & Gas Corporation—cofunder

Rockwell Lime Company—cofunderLocation LocationLocationSeward, 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/Production

73.5 MWe equivalentCoalPennsylvania bituminous, 1.2–2.5% sulfur

Project Funding

Total project cost* $10,411,600 100%DOE 5,205,800 50Participant 5,205,800 50

Project Objective

To demonstrate SO2 removal capabilities of in-duct

CZD/FGD technology; specifically, to define the optimum process operating parameters and to determineCZD/FGD’s operability, reliability, and cost-effectiveness

during long-term testing and its impact on downstreamoperations and emissions.Technology/Project DescriptionIn Bechtel’s CZD/FGD process, a finely atomized slurryof reactive lime is sprayed into the flue gas stream between the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the center ofthe duct by spray nozzles designed to produce a cone offine spray. As the spray moves downstream and expands,the gas within the cone cools and the SO2 is quickly absorbed on the liquid droplets. The droplets mix with the

hot flue gas, and the water evaporates rapidly. Fast drying precludes wet particle buildup in the duct and aids theflue gas in carrying the dry reaction products and theunreacted lime to the ESP.

 This project included injbents (dolomitic and calcdesigns using low- and hieffects on SO2 removal an

onstration was conducted Company’s Seward Statiothe flue gas capacity of throuted through a modifiedduct between the first- an

*Additional project overrun costs were funded 100% by the participantfor a final total project cost of $12,173,000.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• Pressure-hydrated dolomitic lime proved to be a more

effective sorbent than either dry hydrated calcitic limeor freshly slaked calcitic lime.

• Sorbent injection rate was the most influential parameter on SO2 capture. Flue gas temperature was the

limiting factor on injection rate. For SO2 capture

efficiency of 50% or more, a flue gas temperature of300 oF or more was needed.

• Slurry concentration for a given sorbent did not increase SO2 removal efficiency beyond a certain threshold concentration.

• Testing indicated that SO2 removal efficiencies of 50%

or more were achievable with flue gas temperatures of300–310 oF (full load), sorbent injection rate of 52–57gal/min, residence time of 2 seconds, and a pressurehydrated dolomitic-lime concentration of about 9%.

• For operating conditions at Seward Station, data indicated that for 40–50% SO2 removal, a 6–8% lime or

dolomitic lime slurry concentration, and a stoichiometric ratio of 2–2.5 resulted in a 40–50% lime utilizationrate. That is, 2–2.5 moles of CaO or CaO•MgO wererequired for every mole of SO2 removed.

• Assuming 92% lime purity, 1.9–2.4 tons of lime was

required for every ton of SO2 removed.

Operational Operational

• About 100 ft of straight duct was required to assure

the 2-second residence time needed for effectiveCZD/FGD operation.

• At Seward Station, stack opacity was not detrimentally

affected by CZD/FGD.

• Availability of CZD/FGD was very good.• Some CZD/FGD modification will be necessary to

assure consistent SO2 removal and avoid deposition of

solids within the ductwork during upsets.

Economic EconomicEconomic• Capital cost of a 500

sulfur coal and achie

estimated at less than $300/ton of SO2 rem

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward PreawardPreaward Operation and Reporting

12/89 10/90

DOE selected project

(CCT-III) 12/19/89

Design start 6/90

NEPA process completed (MTF) 9/90

Cooperative agreement awarded 10/90

Design completed 10/90

Ground breaking/construction started 3/91

Construction completed 6/91Environmental monitoring plan 6/12/91

Preoperational tests initiated 7/91Operation initiated 7/91

Design and Construction

Operation completed 6/93

7/91

Project completed/final report issued 6/94

6/94
5-28 Program Update 2000 

Project Summary

The principle of the CZD/FGD is to form a wetzone of slurry droplets in the middle of a ductconfined in an envelope of hot gas between thewet zone and the duct walls. The lime slurryreacts with part of the SO2 in the gas and thereaction products dry to form solid particles.An ESP, downstream from the point of injection, captures the reaction products along withthe fly ash entrained in the flue gas.CZD/FGD did not require a special reactor,simply a modification to the ductwork. Use ofthe commercially available Type S pressurehydrated dolomitic lime reduced residence timerequirements for CZD/FGD and enhancedsorbent utilization. The increased humidity ofCZD/FGD processed flue gas enhanced ESPperformance, eliminating the need for upgradesto handle the increased particulate load.Bechtel began its 18-month, two-part test program for theCZD process in July 1991, with the first 12 months of thetest program consisting primarily of parametric testingand the last 6 months consisting of continuous operational testing. During the continuous operational testperiod, the system was operated under fully automaticcontrol by the host utility boiler operators. The newatomizing nozzles were thoroughly tested both outsideand inside the duct prior to system testing.The SO2 removal parametric test program, which began in

October 1991, was completed in August 1992. Specificobjectives were as follows:• Achieve projected SO2 removal of 50%;

• Realize SO2 removal costs of less than $300/ton; and

• Eliminate negative effects on normal boiler operations

without increasing particulate emissions and opacity.

The parametric tests included duct injection of atomizedlime slurry made of dry hydrated calcitic lime, freshlyslaked calcitic lime, and pressure-hydrated dolomitic

lime. All three reagents remove SO2 from the flue gas but

require different feed concentrations of lime slurry for thesame percentage of SO2 removed. The most efficient

removals and easiest operation were achieved using pressure-hydrated dolomitic lime.

Environmental Performance

Sorbent injection rate proved to be the most influentialfactor on SO2 capture. The rate of injection possible was

limited by the flue gas temperature. This impacted aportion of the demonstration when air leakage caused fluegas temperature to drop from 300–310 oF to 260–280 oF.At 300–310 oF, injection rates of 52–57 gal/min werepossible and SO2 reductions greater than 50% were

achieved. At 260–280 oF, injection rates had to bedropped to 30–40 gal/min, resulting in a 15–30% drop inSO2 removal efficiency. Slurry concentration for a given

sorbent did not increase SO2 removal efficiency beyond a

certain threshold concentration. For example, with pressure-hydrated dolomitic lime, slurry concentrations above9% did not increase SO2 capture efficiency.

Parametric tests indicated that SO2 removals above 50%are possible under the following conditions: flue gas

temperature of 300–310 oresidence time in the duct injection rate of 52–57 ga

Operational Performa

The percentage of lime utnificantly affected the tot

analysis of the continuouthe percentage of lime ution two key factors: (1) p

(2) lime slurry feed conceFor operating conditions that for 40–50% SO2 rem

lime slurry concentration2.5 resulted in a 40–50% 2.5 moles of CaO or CaOmole of SO2 removed; or 

2.4 tons of lime were requ

moved. In summary, the lowing results:• A 50% SO2 removal e

possible.

• Drying and SO2 absorp

of 2 seconds, which rezontal gas duct of abo

• The fully automated sy

plant operation demoncess responded well to However, modificationquired to assure consis

deposition of solids w

• Availability of the syst• At Seward Station, sta

affected by the CZD/F

Bechtel’s demonstration showed that 50% SO2 removal efficiency was

possible using CZD/FGD technology. The extended duct into which limeslurry was injected is in the foreground.
Environmental Control Devices 

Economic Performance

Estimates show that the CZD/FGD process can achievecosts of $300/ton of SO2 removed (1994$) when operating a 500-MWe unit burning 4% sulfur coal. Based on a

500-MWe plant retrofitted with CZD/FGD for 50% SO2

removal, the total capital cost is estimated to be less than$30/kW (1994$).

Commercial Applications

After the conclusion of the DOE-funded CZD/FGD demonstration project at Seward Station, the CZD/FGD system was modified to improve SO2 removal during continuous operation while following daily load cycles.

Bechtel and the host utility, Pennsylvania Electric Company, continued the CZD/FGD demonstration for anadditional year. Results showed that CZD/FGD operationat SO2 removal rates lower than 50% could be sustained

over long periods without significant process problems.CZD/FGD can be used for retrofitting existing plants andinstallation in new utility boiler flue gas facilities to remove SO2 from a wide variety of sulfur-containing coals.

A CZD/FGD system can be added to a utility boiler witha capital investment of about $25–50/kW of installed

capacity, or approximately one-fourth thecost of building a conventional wet scrubber. In addition to low capital cost, otheradvantages include small space requirements, ease of retrofit, low energy requirements, fully automated operation,and production of only nontoxic, disposable waste. The CZD/FGD technology isparticularly well suited for retrofittingexisting boilers, independent of type, age,or size. The CZD/FGD installation doesnot require major power station alterations and can be easily and economicallyintegrated into existing power plants.

Contacts ContactsContactsJoseph T. Newman, Project Manager, (415) 768-1189

Bechtel CorporationP.O. Box 193965San Francisco, CA 94119-3965(415) 768-2095 (fax)

Lawrence Saroff, DOE/HQ,

(301) 903-9483

James U. Watts, NETL, (412) 386-5991

References

• Confined Zone Dispersion Project: Final Technical

Report. Bechtel Corporation. June 1994.

• Confined Zone Dispersion Project: Public Design

Report. Bechtel Corporation. October 1993.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Confined Zone Dispersion Flue

Gas Desulfurization Demonstration. Bechtel Corporation. Report No. DOE/FE-0203P. U.S. Department

of Energy. September 1990. (Available from NTIS asDE91002564.)

This photo shows the CZD/FGD lime slurry injector control system.
5-30 Program Update 2000 

Environmental Control Devices

SO2 Control Technology

LIFAC Sorbent Injection

DesulfurizationDemonstration Project Demonstration Project

Project completed. Project completed.Participant

LIFAC–North America (a joint venture partnershipbetween Tampella Power Corporation and ICF KaiserEngineers, Inc.)

Additional Team Members

ICF Kaiser Engineers, Inc.—cofunder and project

manager

Tampella Power Corporation—cofunderTampella, Ltd.—technology owner

Richmond Power and Light—cofunder and host utilityElectric Power Research Institute—cofunderBlack Beauty Coal Company—cofunder

State of Indiana—cofunderLocation LocationLocationRichmond, Wayne County, IN (Richmond Power &Light’s Whitewater Valley Station, Unit No. 2)TechnologyLIFAC’s sorbent injection process with sulfur capture ina unique, patented vertical activation reactor

Plant Capacity/Production

60 MWeCoalBituminous, 2.0–2.8% sulfur

Project Funding

Total project cost $21,393,772 100%DOE 10,636,864 50Participants 10,756,908 50

Project Objective

To 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 SO2

from 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 itabsorbs some of the SO2 in the boiler flue gas. The limestone is calcined into calcium oxide and is available for

capture of additional SO2 downstream in the activation, or

humidification, reactor. In the vertical chamber, watersprays initiate a series of chemical reactions leading toSO2 capture. After leaving the chamber, the sorbent is

easily separated from the in the electrostatic preciprial from the reactor and erecirculated back through ciency. The waste is dry, the wet scrubber sludge plimestone scrubber systemThe technology enables ptions to use high-sulfur man injection process that r

from flue gas and producsuitable for disposal in a 
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• SO2 removal efficiency was 70% at a calcium-to-sulfur

(Ca/S) molar ratio of 2.0, approach-to-saturation temperature of 7–12 oF, and limestone fineness of 80%minus 325 mesh.

• SO2 removal efficiency was reduced an additional

15% by increasing limestone fineness to 80% minus200 mesh and maintaining a Ca/S molar ratio of 2.0and 7–12 oF approach-to-saturation temperature.

• The four parameters having the greatest influence on

sulfur removal efficiency were limestone fineness,Ca/S molar ratio, approach-to-saturation temperature,and ESP ash recycle rate.

• ESP ash recycle rate was limited in the demonstration

system configuration. Increasing the recycle rate andsustaining a 5 oF approach-to-saturation temperaturewere projected to increase SO2 removal efficiency to

85% at a Ca/S molar ratio of 2.0 and limestone fineness of 80% minus 325 mesh.

• ESP efficiency and operating levels were essentially

unaffected by LIFAC during steady-state operation.

• Fly and bottom ash were dry and readily disposed of

at a local landfill. The quantity of additional solidwaste can be determined by assuming that approximately 4.3 tons of limestone is required to remove1.0 ton of SO2.

Operational Operational

• When operating with fine limestone (80% minus

325 mesh), the sootblowing cycle had to be reducedfrom 6.0–4.5 hours.

• Automated programmable logic and simple design

make the LIFAC system easy to operate in startup,shutdown, or normal duty cycles.

• The amount of bottom ash increased slightly, but

there was no negative impact on the ash-handlingsystem.

Economic EconomicEconomic• Capital cost (1994$)—

(300 MWe); $76/kW (150 MWe); $99/kW (65 MWe).

• Operating cost (1994

assuming 75% SO2 c

limestone composed 

ton.

1988 1989 1990 1991 1992 1993 1994 1995 1996

Preaward PreawardPreaward Design and Construction Operation and Reporting

Preoperational tests initiated 7/92

Environmental monitoring plancompleted 6/12/92Construction completed 6/92

12/89 11/90 9/92

DOE selected project (CCT-III) 12/19/89

NEPA process completed (MTF) 10/2/90

Cooperative agreement awarded 11/20/90

Ground breaking/construction started 5/29/91

Original design completed 7/91

Operation initiated 9/92

Operation completed 6/94
5-32 Program Update 2000 

Project Summary

The LIFAC technology was designed to enhance theeffectiveness of dry sorbent injection systems for SO2control and to maintain the desirable aspects of low capital cost and compactness for ease of retrofit. Furthermore, limestone was used as the sorbent (about 1/3 of thecost of lime) and a sorbent recycle system was incorporated to reduce operating costs.The process evaluation test plan was composed of fivedistinct phases, each having its own objectives. Thesetests were:• Baseline tests characterized the operation of the host

boiler and associated subsystems prior to LIFAC operations.

• Parametric tests were designed to evaluate the many

possible combinations of LIFAC process parametersand their effect on SO2 removal.

• Optimization tests were performed after the parametric

tests to evaluate the reliability and operability of theLIFAC process over short, continuous operating periods.

• Long-term tests were designed to demonstrate

LIFAC’s performance under commercial operatingconditions.

• Post-LIFAC tests involved repeating the baseline test

to identify any changes caused by the LIFAC system.

The coals used during the demonstration varied in sulfurcontent from 1.4–2.8%. However, most of the testingwas conducted with the higher (2.0–2.8%) sulfur coals.

Environmental Performance

During the parametric testing phase, the numerous LIFACprocess values and their effects on sulfur removal efficiency were evaluated. The four major parameters havingthe greatest influence on sulfur removal efficiency werelimestone fineness, Ca/S molar ratio, reactor bottomtemperature (approach-to-saturation), and ESP ash recycling rate. Total SO2 capture was about 15% better when

injecting fine limestone (80% minus 325 mesh) than itwas with coarse limestone (80% minus 200 mesh).While injecting the fine limestone, the sootblowing frequency had to be increased from 6-hour to 4.5-hourcycles. The coarse-quality limestone did not affect sootblowing but was found to be more abrasive on the feedand transport hoses.Parametric tests indicated that a 70% SO2 reduction was

achievable with a Ca/S molar ratio of 2.0. ESP ash containing 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

capture. However, the large quantity of ash removedfrom the LIFAC reactor bottom and the small size of theESP hoppers limited the ESP ash recycling rate. As aresult, the amount of material recycled from the ESP wasapproximately 70% less than had been anticipated, buteven this low recycling rate was found to affect SO2capture. During a brief test, it was found that increasingthe recycle rate by 50% resulted in a 5% increase in SO2removal efficiency. It was estimated that if the reactorbottom ash is recycled along with ESP ash, while sustaining a reactor temperature of 5 oF above saturation temperature, an SO2 reduction of 85% could be maintained.

Operational Performance

Optimization testing began in March 1994 and was followed 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 demand. The LIFAC process automatically adjusted toboiler load changes. A Ca/S molar ratio of 2.0 was selected to attain SO2 reductions above 70%. Reactor bottom temperature was about 5 oF higher than optimum to

avoid ash buildup on the steam reheaters. Atomizedwater droplet size was smaller than optimum for the samereason. Other key process parameters held constant during the long-term tests included the degree of humidification, grind size of the high-calcium-content limestone,and recycle of spent sorbent from the ESP.

Long-term testing showed 

more can be maintained uconditions. Stack opacity efficiency was high (99.2tom ash increased slightly negative impact on the poremoval system. The soliof fly ash and calcium coposed of at a local landfil

The LIFAC system successValley Station Unit No. 2 is Power & Light for commercThere are 10 full-scale LIFAFinland, Russia, and the U
Environmental Control Devices 

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 process 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 under

normal boiler operation.

Economic Performance

The economic evaluation indicated that the capital cost ofa LIFAC installation is lower than for either a spray dryeror wet scrubber. Capital costs for LIFAC technologyvary, 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 oflimestone to remove 1.0 ton of SO2, assuming 75% SO2

capture, a Ca/S molar ratio of 2.0, and limestone containing 95% CaCO3. Assuming limestone costs of $15/ton,

LIFAC’s operating cost would be $65/ton of SO2 removed.

Commercial Applications

There are 10 full-scale LIFAC units in operation inCanada, China, Finland, Russia, and the United States.The LIFAC system at Richmond Power & Light is thefirst to be applied to a power plant using high-sulfur (2.0–2.9%) coal. The LIFAC system is being retained by Richmond Power & Light at Whitewater Valley Station, UnitNo. 2. The other LIFAC installations on power plants areusing bituminous and lignite coals having lower sulfurcontents (0.6–1.5%).Contacts ContactsContactsJohn Scott, (703) 218-2744

Kaiser Engineers, Inc.9300 Lee HighwayFairfax, Virginia 22031(703) 934-3029 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

References

• LIFAC Sorbent Injec

tion Project. Final R

mance and Economi

ruary 1998. (Availab

• “LIFAC Nearing Ma

Report No. DOE/FE

• Viiala, J., et al. “Com

Sorbent Injection Pro

Annual Clean Coal T

cal Papers. Septemb

• Comprehensive Repo

Technology Program

Desulfurization DemAmerica. Report Noment of Energy, Octoas DE91001077.)
5-34 Program Update 2000 

Environmental Control Devices

SO2 Control Technology

Advanced Flue GasDesulfurizationDemonstration Project Demonstration Project

Project completed. Project completed.Participant

Pure 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 Members

Northern Indiana Public Service Company—cofunder and

host

Mitsubishi Heavy Industries, Ltd.—process designerStearns-Roger Division of United Engineers and Constructors—facility designerAir Products and Chemicals, Inc.—constructor and

operator

Location LocationLocationChesterton, Porter County, IN (Northern Indiana PublicService Company’s Bailly Generating Station, Unit Nos.7 and 8)TechnologyPure Air’s advanced flue gas desulfurization (AFGD)process and PowerChip® agglomeration process

Plant Capacity/Production

528 MWeCoalBituminous, 2.0–4.5% sulfur

Project Funding

Total project cost $151,707,898 100%DOE 63,913,200 42

Participant 87,794,698 58

Project Objective

To reduce SO2 emissions by 95% or more at approximately one-half the cost of conventional scrubbing technology, significantly reduce space requirements, and

create no new waste streams.Technology/Project DescriptionPure Air built a single SO2 absorber for a 528-MWe

power plant. Although the largest capacity absorbermodule of its time in the United States, space requirements were modest because no spare or backup absorbermodules were required. The absorber performed threefunctions in a single vessel: prequenching, absorbing, andoxidation of sludge to gypsum. Additionally, the absorber was of a co-current design, in which the flue gasand scrubbing slurry move in the same direction and at arelatively high velocity compared to that in conventional

scrubbers. These features of-the-art SO2 absorber th

expensive than contempoOther technical features iized limestone directly inan air rotary sparger locatsorber, and a novel wasteair rotary sparger combinair distribution into one pthe oxidation of calcium Pure Air also demonstrateagglomeration process, Penhance handling charactsum.

PowerChip is a registered trademark of Pure Air on the Lake, L.P.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• The AFGD design enabled a single 600-MWe absorber

module without spares to remove 95% or more SO2 at

availabilities of 99.5% when operating with highsulfur coals.

• Wallboard-grade gypsum was produced in lieu of

solid waste, and all gypsum produced was soldcommercially.

• The wastewater evaporation system (WES) mitigated

expected increases in wastewater generation associated with gypsum production and showed the potentialfor achieving zero wastewater discharge (only a partial- capacity WES was installed).

• PowerChip® increased the market potential for AFGDderived gypsum by cost-effectively converting it to a

product with the handling characteristics of naturalrock gypsum.

• Air toxics testing established that all acid gases were

effectively captured and neutralized by the AFGD.Trace elements largely became constituents of thesolids streams (bottom ash, fly ash, and gypsum product). Some boron, selenium, and mercury passed tothe stack gas in a vapor state.

Operational Operational

• AFGD use of co-current, high-velocity flow; integration of functions; and a unique air rotary sparger

proved to be highly efficient, reliable (to the exclusionof requiring a spare module), and compact. The compactness, combined with no need for a spare module,significantly reduced space requirements.

• The own-and-operate contractual arrangement—Pure

Air took on the turnkey, financing, operating, andmaintenance risks through performance guarantees—was successful.

Economic EconomicEconomic• Capital costs and spa

about half those of c

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward PreawardPreaward Design and Construction Operation and Reporting

9/88

Design completed 9/92 ProjecConstruction completed 9/92

12/89 6/92

Environmental monitoring plan completed 1/31/91

6/96

DOE selected project(CCT-II) 9/28/88

NEPA process completed (EA) 4/16/90Ground breaking/construction started 4/20/90

Cooperative agreement awarded 12/20/89

Preoperational tests initiated 3/92

Operation initiated 6/92 Operation completed 6/95
5-36 Program Update 2000 

Project Summary

The project proved that single absorber modulesof advanced design could process large volumesof flue gas and provide the required availabilityand reliability without the usual spare absorbermodules. The major performance objectives weremet.Over the three-year demonstration, the AFGDunit accumulated 26,280 hours of operation withan availability of 99.5%. Approximately 237,000tons of SO2 were removed, with capture efficiencies of 95% or more, and over 210,000 tons of

salable gypsum were produced. The AFGD continues in commercial service, which includes saleof all by-product gypsum to U.S. Gypsum’s EastChicago, Indiana wallboard production plant.

Environmental Performance

Testing over the three-year period clearly established thatAFGD operating within its design parameters (withoutadditives) could consistently achieve 95% SO2 reduction

or more with 2.0–4.5% sulfur coals. The design range forthe calcium-to-sulfur stoichiometric ratio was 1.01–1.07,with the upper value set by gypsum purity requirements(i.e., amount of unreacted reagent allowed in the gypsum). Another key control parameter was the ratio L/G,

which is the amount of reagent slurry injected into theabsorber grid (L) to the volume of flue gas (G). Thedesign L/G range was 50–128 gal/1,000 ft3. The lower

end of the L/G ratio was determined by solids settlingrates in the slurry and the requirement for full wetting ofthe grid packing. The high end of the L/G ratio was determined by where performance leveled out.Five coals with differing sulfur contents were selected forparametric testing to examine SO2 removal efficiency as a

function of load, sulfur content, stoichiometric ratio, andL/G. Loads tested were 33%, 67%, and 100%. Highremoval efficiencies, well above 95%, were possible atloads of 33% and 67% with low to moderate stoichiometric ratio and L/G settings, even for 4.5% sulfur coal.

Exhibit 5-13 summarizes the results of parametric testingat full load.In the AFGD process, chlorides that would have beenreleased to the air are captured, but potentially become awastewater problem. This was mitigated by the additionof the WES, which takes a portion of the wastewaterstream with high chloride and sulfate levels and injects itinto the ductwork upstream of the ESP. The hot flue gasevaporates the water and the dissolved solids are capturedin the ESP. Problems were experienced early on, with theWES nozzles failing to provide adequate atomization,and plugging as well. This was resolved by replacing theoriginal single-fluid nozzles with dual-fluid systemsemploying air as the second fluid.Commercial-grade gypsum quality (95.6–99.7%) wasmaintained throughout testing, even at the lower sulfurconcentrations where the ratio of fly ash to gypsum increases due to lower sulfate availability. The primaryimportance of producing a commercial-grade gypsum isavoidance of the environmental and economic consequences of disposal. Marketability of the gypsum is

dependent uof economihandle the greasons, Po

onstrated as nology uses the highly cinto a flaketeristics equThe procesdrying, or pwith brique$2.50–$4.1Air toxics tgases are efized by the become con(bottom ash

Some boron, selenium, anin a vapor state.

Operational Performa

Availability over the 3-ye99.5% while maintaining ciency of 94%. This was tive design and an effectilosophy. Modifications city. An example was the technology, C-276 alloy oto replace alloy wallpaper sorber tower wet/dry interather than conventional clower pressure drops acroflexibility to increase gas removal efficiency. The A

with limestone was compusing lime, which is far mpower consumption was 5consumption; and water cor 52% of expected consu

Exhibit 5-13

 Pure Air SO2 Removal Performance

(100% Boiler Load) (100% Boiler Load)
Environmental Control Devices 

Economic Performance

Exhibit 5-14 summarizes capital and levelized 1995current dollar cost estimates for nine cases with varyingplant capacity and coal sulfur content. A capacity factorof 65% and a sulfur removal efficiency of 90% wereassumed. The calculation of levelized cost followedguidelines established in EPRI’s Technical AssessmentGuideTM.The incremental benefits of the own-and-operate arrangement, by-product utilization, and emission allowanceswere also evaluated. Exhibit 5-15 depicts the relativecosts of a hypothetical 500-MWe generating unit in theMidwest burning 4.3% sulfur coal with a base case conventional FGD system and four incremental cases. Thehorizontal lines in Exhibit 5-15 show the range of costsfor a fuel-switching option. The lower bar is the cost offuel delivered to the hypothetical midwest unit, and theupper bar allows for some plant modifications to accommodate the compliance fuel.

Commercial Applications

The AFGD technology is positioned well to compete inthe pollution control arena of 2000 and beyond. The

Ex

Flue Gas 

Ec

500-MWe plant, 30-yr lev$300/tonIncremental cases:A—Conventional FGD (EB—AFGD, own-and-operC—Adds gypsum salesD—Adds emission allowa

removal

E—Increases SO2 removal 

Exhibit 5-14

Estimated Costs for an AFGD System

(1995 Current Dollars) (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

$/Ton SO2 

AFGD technologyhas markedly reduced cost anddemonstrated theability to competewith fuel switchingunder certain circumstances evenwith a first-generation system. Advances in technology, e.g., in materials and components, should lower

costs for AFGD.The own-andoperate businessapproach has done

much to mitigate risk on the part of prospective users.High SO2 capture efficiency offers the AFGD user the

possibility of generating allowances or applying credits toother units within the utility. WES and PowerChip® mitigate or eliminate otherwise serious environmental concerns. AFGD effectively deals with hazardous air pollutants.

The project received Power magazine’s 1993 Powerplant

Award and the National Society of Professional Engineers’ 1992 Outstanding Engineering AchievementAward.Contacts ContactsContactsTim 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) 481-7166 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

References

• Advanced Flue Gas D

stration Project. Fin

Project Performance 

Lake, L.P. April 1996DE96050313.)

• Advanced Flue Gas D

Design Report. Pure 

1990.

• Summary of Air Toxi

Utility Power Plants

Services Corporation Pittsburgh Energy Te
5-38 Program Update 2000 

Environmental Control Devices

SO2 Control Technology

Demonstration of InnovativeApplications of Technologyfor the CT-121 FGD Process

Project completed. Project completed.Participant

Southern Company Services, Inc.

Additional Team Members

Georgia Power Company—hostElectric Power Research Institute—cofunderRadian Corporation—environmental and analytical

consultant

Ershigs, Inc.—fiberglass fabricatorComposite Construction and Equipment—fiberglass

sustainment consultant

Acentech—flow modeling consultantArdaman—gypsum stacking consultantUniversity of Georgia Research Foundation—

by-product utilization studies consultant

Location LocationLocationNewnan, Coweta County, GA (Georgia PowerCompany’s Plant Yates, Unit No. 1)TechnologyChiyoda Corporation’s Chiyoda Thoroughbred-121(CT-121) advanced flue gas desulfurization (AFGD)process using the Jet Bubbling Reactor®

Plant Capacity/Production

100 MWeCoalIllinois No. 5 & No. 6 blend, 2.4% sulfurCompliance coal, 1.2% sulfur

Project Funding

Total project cost $43,074,996 100%DOE 21,085,211 49Participant 21,989,785 51

Project Objective

To demonstrate 90% SO2 control at high reliability with

and without simultaneous particulate control requisite toeliminating spare absorber modules; to evaluate use offiberglass-reinforced plastic (FRP) vessels to eliminateflue gas prescrubbing and reheat, and to enhance reliability; and to evaluate use of gypsum to reduce waste management costs.Technology/Project DescriptionThe project demonstrated the CT-121 AFGD process,which uses a unique absorber design known as the Jet

Bubbling Reactor® (JBR)

stone AFGD reaction, forcrystallization in one procchanically and chemically AFGD processes and can cost characteristics.The flue gas enters underthe JBR. The SO2 in the 

calcium sulfite (CaSO3). 

of the solution to oxidize gypsum. The slurry is dewhich involves filling a dGypsum solids settle in thclear water flows to a retefrom the pond is returned 

Jet Bubbling Reactor is a registered trademark of the Chiyoda Corp.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• Over 90% SO2 removal efficiency was achieved at SO2

inlet concentrations of 1,000–3,500 ppm with limestone utilization over 97%.

• JBR achieved particulate removal efficiencies of

97.7–99.3% for inlet mass loadings of 0.303–1.392 lb/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 greater

than 95% capture of hydrogen chloride (HCl) andhydrogen fluoride (HF) gases, 80–98% capture ofmost trace metals, less than 50% capture of mercuryand cadmium, and less than 70% capture of selenium.

• Gypsum stacking proved effective for producing

wallboard/cement-grade gypsum.

Operational Operational

• FRP-fabricated equipment proved durable both

structurally and chemically, eliminating the need for aflue gas prescrubber and reheat.

• FRP construction combined with simplicity of design

resulted in 97% availability at low ash loadings and95% at high ash loadings, eliminating the need for aspare reactor module.

• Simultaneous SO2 and particulate control were

achieved at fly ash loadings similar to those of anelectrostatic precipitator (ESP) that has marginalperformance.

Economic EconomicEconomic• Capital costs for project equipment, process, and

startup were $29 million, or $293/kW at Plant Yates.

• Fixed O&M costs were $357,000/yr (1994$), and

variable operating costs were $34–64/ton of SO2

removed, depending on specific test conditions.

• Generic plant costs w

elimination of the nereheat, and a spare mrequirements far belconventional flue ga

1988 1989 1990 1991 1992 1993 1994 1995 1996 

4/90

Preaward PreawardPreaward Design and Construction Operation and Reporting

9/88 10/92

DOE selected project(CCT-II) 9/28/88

Cooperative agreement awarded 4/2/90

NEPA process completed(EA) 8/10/90Ground breaking/constructionstarted 8/23/90

Environmental monitoringplan completed 12/18/90

Preoperational tests initiated 5/92

Design completed 9/92

Operation initiated 10/92Construction completed 10/92

Operation completed 12/94

Pr
5-40 Program Update 2000 

Project Summary

The CT-121 AFGD process differs from the more common spray tower type of flue gas desulfurization systemsin that a single process vessel is used in place of the usualspray tower/reaction tank/thickener arrangement. Pumping of reacted slurry to a gypsum transfer tank is intermittent. This allows crystal growth to proceed essentiallyuninterrupted, resulting in large, easily dewatered gypsumcrystals (conventional systems employ large centrifugalpumps to move reacted slurry causing crystal attrition andsecondary nucleation).The demonstration spanned 27 months, including startupand shakedown, during which approximately 19,000hours were logged. Exhibit 5-16 summarizes operatingstatistics. Elevated particulate loading included a shorttest with the electrostatic precipitator (ESP) completelydeenergized, but the long-term testing was conductedwith the ESP partially deenergized to simulate a morerealistic scenario, i.e., a CT-121 retrofit to a boiler with a

marginally performing particulate collection device. TheSO2 removal efficiency was measured under five different

inlet concentrations with coals averaging 2.4% sulfur andranging from 1.2– 4.3% sulfur (as burned).

Operating Performance

Use of FRP construction proved very successful. Becausetheir large size precluded shipment, the JBR and limestone slurry storage tanks were constructed on site. Except for some erosion experienced at the JBR inlet transition duct, the FRP-fabricated equipment proved to bedurable both structurally and chemically. Because of thehigh corrosion resistance, the need for a flue gasprescrubber to remove chlorides was eliminated. Similarly, the FRP-constructed chimney proved resistant to thecorrosive condensates in wet flue gas, eliminating theneed for flue gas reheat.Availability of the CT-121 scrubber during the low ashtest phase was 97%. Availability dropped to 95% underthe elevated ash loading conditions due largely to spargertube plugging problems, precipitated by fly ash agglomeration on the sparger tube walls during high ash loadingwhen the ESP was deenergized. The high reliability

demonstrated verified that a spareJBR is not required in a commercialdesign offering.

Environmental Performance

Exhibit 5-17 shows SO2 removal

efficiency as a function of pressuredrop across the JBR for five different inlet concentrations. The greaterthe pressure drop, the greater thedepth of slurry traversed by the fluegas. As the SO2 concentration increased, removal efficiency decreased, but adjustments in JBR

fluid level could maintain the efficiency above 90% and, at lower SO2

concentration levels, above 98%.Limestone utilization remainedabove 97% throughout the demonstration. Long-term particulate

capture performance was deenergized ESP (approxsummarized in Exhibit 5-Analysis indicated that a particulate matter is sulfaand gypsum carryover. Tmass loading at the outlet measured outlet particulaFor particulate sizes greatefficiency was consistentlmicron range, capture eff0.5 and 1 micron, the parttimes to negligible valuescarryover entraining parti0.5 micron, the capture efCalculated air toxics remobased on the measuremention, are shown in Exhibi

Low Ash Low Ash Elevated Ash CumulativePhase 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 14,290Reliabilitya 0.98 0.95 0.96

Availabilityb 0.97 0.95 0.97Utilizationc 0.73 0.72 0.75

a Reliability = hours scrubber operated divided by the hours called upon to operate

b 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 5-16

Operation of CT-121 Scrubber Operation of CT-121 Scrubber

Exh

SO2 Remo
Environmental Control Devices 

As to solids handling, the gypsum stacking methodproved effective in the long term. Although chloridecontent was initially high in the stack due to the closedloop nature of the process (with concentrations oftenexceeding 35,000 ppm), a year later the chloride concentration in the gypsum dropped to less than 50 ppm, suitable for wallboard and cement applications. The reduction in chloride content was attributed to rainwater washing the stack.

Economic Performance

The capital cost of the Plant Yates CT-121 project was$29,335,979, or $293/kW, which includes equipment,process, and start-up costs. The annual fixed O&M costwas $354,000/yr. (1994$). Variable operating cost was$34–64/ton of SO2 removed (1994$), depending on specific test conditions.

FRP construction eliminates the need for prescrubbingand reheating flue gas. High system availability eliminates the need for a spare absorber module. Particulateremoval capability eliminates the need for expensive(capital-intensive) ESP upgrades to meet increasinglystrict environmental regulations.

Exhibit 5-18

CT-121 Particulate Capture Performance

(ESP Marginally Operating) (ESP Marginally Operating)

JBR Pressure Boiler Inlet Mass Inlet MassInlet Mass Outlet Mass Removal Removal Removal

Change (inches of Load Loading Loading Loading* Loading*Loading* Efficiency EfficiencyEfficiency

water column) (MWe) (lb/106 Btu) (lb/106 Btu) (%)

18 100 1.288 0.02 97.710 100 1.392 0.010 99.318 50 0.325 0.005 98.510 50 0.303 0.006 98.0

*Federal NSPS is 0.03 lb/106 Btu for units constructed after September 18, 1978. Plant Yates

permit limit is 0.24 lb/106 Btu as an existing unit.

Ex

CT-121 Air 

(JBR Co(JBR Co

Commercial Applications

Involvement of SouthernCompany (which ownsSouthern Company Services,Inc.), with more than 20,000MWe of coal-fired generating capacity, is expected toenhance confidence in theCT-121 process among otherlarge high-sulfur coal boilerusers. This process will beapplicable to 370,000 MWeof new and existing generating capacity by the year2010. A 90% reduction inSO2 emissions from only the

retrofit portion of this capacity represents more than10,500,000 tons/yr of potential SO2 control.

Plant Yates continues to operate with the CT-121 scrubber as an integral part of the site’s CAAA compliancestrategy. Since the CCT Program demonstration, over8,200 MWe equivalent of CT-121 AFGD capacity hasbeen sold to 16 customers in seven countries.The project received Power magazine’s 1994 Powerplant

Award. Other awards include the Georgia Chapter of theAir and Waste Management Association’s 1994 Outstanding Achievement Award, the Georgia Chamber ofCommerce’s 1993 Air Quality Citizen of the Year Award,and the Composites Institute (Society of Plastics Industries) 1996 Design Award of Excellence.Contacts ContactsContactsDavid P. Burford, Project Manager, (205) 992-6329

Southern Company42 Inverness Parkway, Suite 340Birmingham, AL 35242(205) 992-7535 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, DOE/NETL, (412) 386-5991

References

• Southern Company S

Innovative Applicatio

tions to the CT-121 F

Volumes 1-6. Januar

• Comprehensive Repo

Technology Program

Applications of Tech

cess. Southern Com

DOE/FE-0158. U.S. 1990. (Available fro
5-42 Program Update 2000 
Environmental Control Devices 

Environmental Control Devic

NO

x Control Technologies
5-44 Program Update 2000 

Environmental Control Devices

NO

x Control Technology

Demonstration of AdvancedCombustion Techniques for a

Wall-Fired Boiler all-Fired Boiler

Project extended. Project extended.Participant

Southern Company Services, Inc. (SCS)

Additional Team Members

Electric Power Research Institute (EPRI)—cofunderFoster Wheeler Energy Corporation (Foster Wheeler)—

technology supplier

Georgia Power Company—hostPowerGen—cofunderU.K. Department of Trade and Industry—cofunderEnTEC—technology supplierRadian—technology supplierTennessee Technological University—technology supplierSouthern Company—cofunderLocation LocationLocationCoosa, Floyd County, GA (Georgia Power Company’sPlant Hammond, Unit No. 4)TechnologyFoster Wheeler’s low-NO

x burner (LNB) with advanced

overfire air (AOFA) and EPRI’s Generic NOx Control

Intelligent System (GNOCIS) computer software.

Plant Capacity/Production

500 MWeCoalEastern bituminous coals, 1.7% sulfur

Project Funding

Total project cost $15,853,900 100%DOE 6,553,526 41Participant 9,300,374 59

Project Objective

To achieve 50% NO

x

 reduction with the LNB/AOFA

system; to determine the contributions of AOFA and LNBto NO

x reduction and the parameters for optimal LNB/

AOFA performance; and to assess the long-term effects ofLNB, AOFA, combined LNB/AOFA, and the GNOCISadvanced digital controls on NOx reduction, boiler performance, and peripheral equipment performance. The

project 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 ratio theoretically required to complete combustion (sub-stoichiometric), without increasing combustible losses; and (2) introducing “boundary air” at the boiler walls to prevent corrosion caused by the reducing atmosphere.

In the Foster Wheeler Co(CFSF) LNB, fuel and air the primary air/fuel mixtucreate a fuel-rich core witbustion at a severely sub-The burner also controls tnecessary to complete comflame solids and gases so oxygen until the remaininpeak NOx-producing temp

final excess air then can bburned products so that crelatively low temperaturcoal/air mixture into four and air mixing and combu
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• Using LNB alone, long-term NOx emissions were

0.65 lb/106 Btu, representing a 48% reduction from

baseline conditions (1.24 lb/106 Btu).

• Using AOFA only, long-term NOx emissions were

0.94 lb/106 Btu, representing a 24% reduction from

baseline conditions.

• Using LNB/AOFA, long-term NOx emissions were

0.40 lb/106 Btu, representing a 68% reduction from

baseline conditions.

• Chemical emissions testing showed no evidence of

organic compound emissions resulting from the combustion modifications installed for NO

x

 control. Trace

element control, except for mercury and selenium,proved to be a function of electrostatic precipitator(ESP) performance.

Operational Operational

• AOFA accounted for an incremental NO

x

 reduction

beyond the use of LNB of approximately 17%, withadditional reductions resulting from other operationalchanges.

• GNOCIS achieved a boiler efficiency gain of 0.5

percentage points, a reduction in fly ash loss-on-ignition (LOI) levels of 1–3 percentage points, and a reduction in NO

x

 emissions of 10–15% at full load.

• Fly ash LOI increased from a baseline of 7% (corrected to representative excess oxygen conditions) to

10% with AOFA and 8% with LNB and LNB/AOFA,despite significant improvements in coal fineness.

Economic EconomicEconomic• Capital cost for a 500-MWe wall-fired unit is $8.8/kW

for AOFA alone, $10.0/kW for LNB alone, $18.8/kWfor LNB/AOFA, and $0.5/kW for GNOCIS.

• Estimated cost of NO

LNB/AOFA in a basenced at Plant Hamm

Preaward PreawardPreaward

1988 1989 1990 1991 1992 1993 1994 1996 1998 

9/88 12/89 6/90

Design and Construction

DOEselectedproject(CCT-II)9/28/88

Cooperative agreement awarded 12/20/89

Design completed 3/90

Construction started, AOFA 4/90

Construction completed, AOFA 5/90

Operation initiated, AOFA 6/90

Environmental monitoring plan completed 9/14/90

Construction started, LNB;Operation completed, AOFA 3/91

Construction completed, LNB;Operation initiated, LNB 4/91

NEPA process

completed (MTF)

5/22/89

Operation completed,LNB 1/92

Operation initiated, LNB/AOFA 5/93

Operation and Reporting

Operation completed, LNB/AOFA 8/93

Operation initiated,LNB/AOFA with digital controlsystem 6/94

Final report

(Phase 1-3B)

issued 1/98

**

GNOCIS testinginitiated 2/96

Fin(Phiss

Coope

re

**
5-46 Program Update 2000 

Project Summary

SCS conducted baseline characterization of the unit in an“as-found” condition from August 1989 to April 1990.The AOFA system was tested from August 1990 to March1991. Following installation of the LNBs in the secondquarter of 1991, the LNBs were tested from July 1991 toJanuary 1992, excluding a three-month delay when theplant ran at reduced capacity. Post-LNB increases in flyash LOI, along with increases in combustion air requirements and fly ash loading to the electrostatic precipitator(ESP), adversely affected the unit’s stack particulateemissions. The LNB/AOFA testing was conducted fromJanuary 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 Performance

LOI increased for the AOFA, LNB, and LNB/AOFA

phases, as shown in Exhibit 5-20, despite improved millperformance due to the replacement of the mills. Increased LOI was a concern not only because of the associated efficiency loss, but also due to a poten- tial loss of fly ash sales. The increased carbon in the fly ash renders the material unsuitable for use in making concrete. During October 1992, SCS conducted para- metric testing to determine the relationship between NOx and LOI emissions. The param- eters tested were: excess oxygen, mill coal flow bias, burner sliding tip position, burner outer register position, and burner inner regis- ter position. Nitrogen oxide emissions and LOI levels varied from 0.44–0.57 lb/106 Btu and 3–10%, respectively. As expected, excess oxygen levels had considerable effect on both NOx and LOI. The results showed that there is some flexibility in selecting the optimum operating point and making trade-offs be- tween NOx emissions and fly ash LOI; however, much of the variation was the result of changes in excess oxygen. This can be more clearly seen in Exhibit 5-21 in which all sensitivities are plotted. This exhibit shows that, for excess oxygen, mill bias, inner register, and sliding tip, any adjustments to reduce NOx emissions are at the ex- pense of increased fly ash LOI. In contrast, the slope of

the outer register adjustment suggests that improvement in both NOx emissions and LOI can be

achieved by adjustment of this damper. However,due to the relatively small impact of the outerregister adjustment on bothNOx and LOI, it is likely the

positive NOx/LOI slope is an

artifact of process noise.A subsidiary goal of theproject was to evaluate advanced instrumentation andcontrols (I&C) as applied tocombustion control. The needfor more sophisticated I&Cequipment is illustrated inExhibit 5-22. There are tradeoffs in boiler operation, e

increases, LOI decreases, goal is to find and maintation. The I&C systems tecarbon-in-ash analyzers. The GNOCIS software apto identify the best set poimplemented automatical(closed-loop), or conveyeimplementation (open-loo

Exhibit 5-20 LOI Performance Test Results

Exhibit 

NO

x vs. LOI T vs. LOI T vs. LOI Tests—

Exhibit 5-2

Typical T ypical Typical Trade-Offs in Bo
Environmental Control Devices 

GNOCIS are shown in Exhibit 5-23. The GNOCIS system provided advice that reduced NOx emissions by 10–

15% at full load, while improving the heat rate or reducing fly ash LOI by 1–3 percentage points.

Environmental Performance

Long-term testing showed that the AOFA, LNBs, andLNB/AOFA provide full-load NOx reductions of 24, 48,

and 68%, respectively. Although the long-term LNB/AOFA NOx level represents a 68% reduction from baseline levels, a substantial portion of the incremental

change in NOx emissions between the LNB and the LNB/

AOFA configurations is the result of operational changesand is not the result of adding AOFA.During the LNB/AOFA test phase a total of 63 days ofvalid long-term NOx emissions data was collected. Based

on this data set, the full-load, long-term NOx emissions

were 0.40 lb/106 Btu, which was consistent with earlier

short-term test data. Earlier long-term testing had resulted in NOx emissions of 0.94 lb/106 Btu for AOFA

only and 0.65 lb/106 Btu for LNB only.

Chemical emissions testing showed no evidence of organic compound emissions resulting from the combustionmodifications installed for NOx control. Trace element

control, except for mercury and selenium, proved to be afunction of electrostatic precipitator (ESP) performance.Only a small portion of the mercury and selenium, whichadopt a vapor phase, and none of the vapor-phase chlorine (as hydrochloric acid) and fluorine (as hydrofluoricacid) were captured.

Economic Performance

Estimated capital costs for a commercial 500-MWe wallfired installation are: AOFA—$8.8/kW, LNB—$10.0/kW, LNB/AOFA—$18.8/kW, and GNOCIS—$0.5/kW.Annual O&M costs and NOx reductions depend on the

assumed load profile. Based on the actual load profileobserved in the testing, the estimated annual O&M costincrease for LNB/AOFA is $333,351. Efficiency is decreased by 1.3 percent, and the NOx reduction is 68 percent of baseline, or 11,615 tons/year at full load. The

capital cost is $8,300,000 and the calculated cost of NOx

removed is $79/ton for the Hammond baseload dispatchscenario.The addition of GNOCIS to the LNB/AOFA, using theactual load profile observed in the testing, results in arange of costs depending on whether the unit is operatedto maximize NOx removal efficiency, or LOI. For the

maximum NOx removal case, the efficiency is improved

by 0.6 percent, the annual O&M cost is decreased by$228,058, the incremental NOx reduction is 11 percent

(696 tons/year), and the capital cost is $250,000. Thecalculated cost per ton of NOx removed is -$299 (net gain

due to increased efficiency).

Project Extension

On 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, which includes a real-time heat rate monitor,for power plant processes and for the unit as a whole. Themajor tasks include unit optimization, boiler optimization, automated sootblowing, and precipitator modeling/

optimization. To date, tis complete, and the desages are in progress.

Commercial Applica

The technology is appliNSPS dry-bottom wall-which burn a variety of is applicable to all fossifired with natural gas angas.The host has retained thuse. Foster Wheeler haNOx burner technology 

tional)—1,800 burners fContacts ContactsContactsJohn N. Sorge, (205) 25

Research EngineerSouthern Company SP.O. Box 2641Birmingham, AL 352jnsorge@southernco

Lawrence Saroff, DOE/James R. Longanbach, N

References

• 500-MW Demonstra

Combustion Techniq

Oxide (NOx) Emissio

Phase 4—Digital Co

Southern Company S

• 500-MW Demonstra

Combustion Techniq

Oxide (NOx) Emissio

Phases 1-3B, Final R

vices, Inc. January 1

Exhibit 5-23

Major Elements of GNOCIS
5-48 Program Update 2000 

Environmental Control Devices

NO

x Control Technology

Demonstration of Coal Demonstration of CoalReburning for Cyclone Boiler Reburning for Cyclone Boiler

NO

x

 Control Control Control Control Control

Project completed. Project completed.Participant

The Babcock & Wilcox Company

Additional Team Members

Wisconsin Power and Light Company—cofunder and

host

Sargent and Lundy—engineer for coal handlingElectric Power Research Institute—cofunderState of Illinois, Department of Energy and Natural

Resources—cofunder

Utility companies (14 cyclone boiler operators)—

cofunders

Location LocationLocationCassville, Grant County, WI (Wisconsin Power and LightCompany’s Nelson Dewey Station, Unit No. 2)Technology

The Babcock & Wilcox Company’s Coal Reburning

System (Coal Reburning)

Plant Capacity/Production

100 MWeCoalIllinois Basin bituminous (Lamar), 1.15% sulfur,

1.24% nitrogen

Powder River Basin (PRB) subbituminous, 0.27% sulfur,

0.55% nitrogen

Project Funding

Total project cost $13,646,609 100%

DOE 6,340,788 46

Participant 7,305,821 54

Project Objective

To demonstrate the technical and economic feasibility ofCoal Reburning to achieve greater than 50% reduction inNO

x emissions with no serious impact on cyclone combustor operation, boiler performance, or other emission

streams.Technology/Project DescriptionBabcock & Wilcox Coal Reburning reduces NOx in the

furnace through the use of multiple combustion zones.The main combustion zone uses 70–80% of the total heatequivalent fuel input to the boiler, and slightly less thannormal combustion air input. The balance of the coal(20–30%), along with significantly less than the theoretically determined requirement of air, is fed to the reburning zone above the cyclones to create an oxygen-deficientcondition. The NO

x formed in the cyclone burners reacts

with the resultant reducinnitrogen in this zone. Coprocess occurs in the thirwhere the balance of the 
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• Coal Reburning achieved greater than 50% NOx reduction at full load with Lamar bituminous and PRB

subbituminous coals.

• Reburning-zone stoichiometry had the greatest effect

on NO

x

 control.

• Gas recirculation was vital to maintaining reburningzone stoichiometry while providing necessary burner

cooling, flame penetration, and mixing.

• Opacity levels and electrostatic precipitator (ESP)

performance were not affected by Coal Reburningwith either coal tested.

• Optimal Coal Reburning heat input was 29–30% at

full load and 33–35% at half to moderate loads.

Operational Operational

• No major boiler performance problems were experienced with Coal Reburning operations.• Boiler turndown capability was 66%, exceeding the

50% goal.

• ESP efficiency improved slightly during Lamar coal

testing and did not change with PRB coal.

• Coal fineness levels above the nominal 90% through

200 mesh were maintained, reducing unburned carbonlosses (UBCL).

• UBCL was the only major contributor to boiler efficiency loss, which was 0.1, 0.25, and 1.5 percentage

points at loads of 110, 82, and 60 MWe, respectively,when using Lamar coal. With PRB coal, the efficiency loss ranged from zero at full load to 0.3 percentage points at 60-MWe.

• Superior flame stability was realized with PRB coal,

contributing to better NOx control than with Lamar

coal.

• Expanded volumetric 

burners enabled switout boiler derating.

Economic EconomicEconomic• Capital costs for 110

$66/kW and $43/kW

• Levelized 10- and 30

110-MWe plant were tively (constant 1990

• Levelized 10- and 30

605-MWe plant were tively (constant 1990

Operationinitiated 12/91

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Design and Construction

9/88

Preaward PreawardPreaward

DOE selected project(CCT-II) 9/28/88

4/90 12/91

Operation and Reporting

3/94

Project completed/final report issued 3/94

Operationcompleted 12/92

Environmental monitoring plan completed 11/18/91Construction completed 11/91Preoperational tests initiated 11/91

NEPA process completed (EA) 2/12/91

Design completed 6/91

Ground breaking/construction started 11/90

Cooperative agreement

awarded 4/2/90
5-50 Program Update 2000 

Project Summary

Although cyclone boilers represent only 8.5% of the preNSPS coal-fired generating capacity, they contribute 12%of the NOx formed by pre-NSPS coal-fired units. This is

due to the cyclone combustor’s inherent turbulent, hightemperature combustion process. However, at the time ofthis demonstration, there was no cost-effective combustion modification available for cyclone boiler NOx control.

Babcock & Wilcox Coal Reburning offers an economicand operationally sound response to the environmentalrequirements. This technology avoids cyclone combustormodification and associated performance complications,and provides an alternative to postcombustion NOx control options, such as SCR, which have relatively high

capital and/or operating costs.The majority of the testing was performed firing IllinoisBasin bituminous coal (Lamar), because it is typical ofthe coal used by many utilities operating cyclones. Subbituminous PRB coal tests were performed to evaluate theeffect of coal switching on reburning operation. Wisconsin Power and Light’s strategy to meet Wisconsin’s sulfur

emission limitations as of January 1, 1993, was to firelow-sulfur coal.

Environmental Performance

Three sequential tests of Coal Reburning used Lamarcoal. Parametric optimization testing set up the automaticcontrols. Performance testing evaluated the unit in fullautomatic control at set load points. Long-term testingassessed performance in a load-following mode. PRBcoal was used for parametric optimization and performance modes. Exhibit 5-24 shows changes in NOx emissions and boiler efficiency using the reburning system for

various load conditions and coal types.Coal Reburning tests on both the Lamar and PRB coalsindicated that variation of reburning-zone stoichiometrywas the most critical factor in changing NOx emissions

levels. The reburning-zone stoichiometry can be variedby alternating the air flow quantities (oxygen availability)to the reburning burners, the percent reburning heat input,the gas recirculation flow rate, or the cyclone stoichiometry.Hazardous air pollutant (HAP) testing was performedusing Lamar test coal. HAP emissions were generally

well within expected levels, and emissions with Coal Reburning were comparable to baseline operation. No major effect of reburning on trace-metalspartitioning was discernible. None ofthe 16 targeted polynuclear aromaticsemi-volatile organics (controlled underTitle III of CAAA) were present indetectable concentrations, at a detectionlimit of 1.2 parts per billion.

Operational Performance

For Lamar coal, the full-, medium-, andlow-load efficiency losses due to unburned carbon were higher than thebaseline by 0.1, 0.25, and 1.5 percentage points, respectively. Full-, medium-, and low-load efficiency losseswith PRB coal were 0.0, 0.2, and 0.3

percentage points, respecflame stability improved During Coal Reburning ooperators continually moncreased ash deposition antoring system for heat tranthroughout the system option period were any slagserved. In fact, during scinspections revealed that improved. Extensive ultrwere taken of the furnace decrease in wall tube thicAnother significant findinminimizes and possibly enormally associated with in a cyclone unit. This delower Btu fuel in a cyclonited coal feed capacity. C30% of the coal feed out burners, bringing the cyclable level while maintainunit.

Boiler Load

110 MWe 82 MWe 60 MWe

Lamar coal ar coal ar 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 coal Powder River Basin coal

NOx (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 5-24

Coal Reburning Test Results

Wisconsin Power and Light hosted the successful demo
Environmental Control Devices 

Economic Performance

An economic analysis of total capital and levelized revenue 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. Theresults of these analyses are shown in Exhibit 5-25.These values assumed typical retrofit conditions and didnot take into account any fuel savings from use of lowrank coal. The pulverizers and associated coal handlingwere taken into account. Site-specific parameters that can

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.

significantly impact these retrofit costs included the stateof the existing control system, availability of flue gasrecirculation, space for coal pulverizers, space for reburning burners and overfire air ports within the boiler, scopeof coal-handling modification, sootblowing capacity, ESPcapacity, steam temperature control capacity, and boilercirculation considerations.

Commercial Applications

Coal 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.Contacts ContactsContactsDot K. Johnson, (330) 829-7395

McDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601(330) 821-7801 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483John C. McDowell, NETL, (412) 386-6175

References

• Demonstration of Coal Reburning for Cyclone Boiler

NO

x

 Control: Final Project Report. Report No. DOE/

PC/89659-T16. The Babcock & Wilcox Company.February 1994. (Available from NTIS asDE94013052, Appendix 1 as DE94013053, Appendix2 as DE94013054.)

• Public Design Report: Coal Reburning for Cyclone

Boiler NO

x

 Control. The Babcock & Wilcox Company. August 1991. (Available from NTIS as

DE92012554.)

Ex

Coal Rebu

(1990 C(1990 C

Costs Total capital cost ($/kWLevelized busbar powercost (mills/kWh)

10-year life 30-year life 

Annualized cost ($/ton of NOx removed

10-year life 30-year life 

• Comprehensive Repo

Program: Demonstr

Cyclone Boiler NOx 

0157. U.S. Departm(Available from NTI
5-52 Program Update 2000 

Environmental Control Devices

NO

x Control Technology

Full-Scale Demonstration of Full-Scale Demonstration of

Low-NO

x

 Cell Burner Retrofit Cell Burner Retrofit

Project completed. Project completed.Participant

The Babcock & Wilcox Company

Additional Team Members

The Dayton Power and Light Company—cofunder and

host

Electric Power Research Institute—cofunderOhio Coal Development Office—cofunderTennessee Valley Authority—cofunderNew England Power Company—cofunderDuke Power Company—cofunderAllegheny Power System—cofunderCenterior Energy Corporation—cofunderLocation LocationLocationAberdeen, Adams County, OH (Dayton Power and LightCompany’s J.M. Stuart Plant, Unit No. 4)TechnologyThe Babcock & Wilcox Company’s low-NOx cell-burner

(LNCB®) system

Plant Capacity/Production

605 MWeCoalBituminous, medium sulfur

Project Funding

Total project cost $11,233,392 100%

DOE 5,442,800 48

Participant 5,790,592 52

Project Objective

To demonstrate, through the first commercial-scale fullburner retrofit, the cost-effective reduction of NOx from a

large, baseload coal-fired utility boiler with LNCB® technology and to achieve at least a 50% NOx reduction without degradation of boiler performance at less cost than

that of conventional low-NO

x

 burners.

Technology/Project DescriptionThe LNCB® technology replaces the upper coal nozzle of

the standard two-nozzle cell burner with a secondary airport. The lower burner coal nozzle is enlarged to thesame fuel input capacity as the two standard coal nozzles.The LNCB® operates on the principle of staged combustion to reduce NO

x emissions. Combustion is staged by

providing only about 58% of the air theoretically requiredfor complete combustion through the lower burner and

the balance of the air thro

port).The demonstration was cWilcox-designed, supercrequipped with an electrosunit, which is typical of ctwo-nozzle cell burners aconfiguration. Twelve busix burners each) were mwalls of the boiler. All 24 removed and 24 new LNC

LNCBs® on the bottom ro

port then being on the botbustion in the lower furna

LNCB is a registered trademark of The Babcock & Wilcox Company.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• Short-term optimization testing (all mills in service)

showed NO

x reductions in the range of 53.0–55.5%,

52.5–54.7%, and 46.9–47.9% at loads of 605 MWe,460 MWe, and 350 MWe, respectively.

• Long-term testing at full load (all mills in service)

showed an average NOx reduction of 58% (over

8 months).

• Long-term testing at full load (one mill out of service)

showed an average NOx reduction of 60% (over8 months).

• Carbon monoxide (CO) emissions averaged 28–55

ppm at full load with LNCB® in service.

• Fly ash increased, but ESP performance remained

virtually unchanged.

Operational Operational

• Unit efficiency remained essentially unchanged.• Unburned carbon losses (UBCL) increased by approximately 28% for all tests, but boiler efficiency loss

was offset by a decrease in dry gas loss due to a lowerboiler economizer outlet gas temperature.

• Boiler corrosion with LNCB® was roughly equivalent

to boiler corrosion rates prior to retrofit.

Economic EconomicEconomic• 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 plant

was estimated at 0.284 mills/kWh and $96.48/ton ofNO

x removed (constant 1994$).

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operationinitiated 12/91

10/90

Operation and Reporting

Design and

Preaward PreawardPreaward Construction

12/91

NEPA process completed (MTF) 8/10/90

DOE selected project

(CCT-III) 12/19/89

Project complet

12/95

Operation completed 4/93

12/89

Construction completed 11/91Preoperational tests initiated 11/91

Cooperative agreement

awarded 10/11/90

Design completed 10/90

Environmental monitoring plancompleted 8/9/91

Ground breaking/construction started 9/91
5-54 Program Update 2000 

Project Summary

Utility boilers equipped with cell burners currently represent 7.4% or approximately 24,000 MWe of pre-NSPScoal-fired generating capacity. Cell burners are designedfor rapid mixing of fuel and air. The tight burner spacingand rapid mixing minimize flame size while maximizingthe heat release rate and unit efficiency. Combustionefficiency is good, but the rapid heat release producesrelatively large quantities of NOx

.

To reduce NOx emissions, the LNCB® has been designed

to stage mixing of fuel and combustion air. A key designcriterion was accomplishing delayed fuel-air mixing withno modifications to boiler walls. The plug-in LNCB®

design reduces material costs and outage time required tocomplete the retrofit, compared to installing conventional,internally staged low-NOx burners, thereby providing a

lower cost alternative to address NOx reduction requirements for cell burners.

Environmental Performance

The initial LNCB® configuration resulted in excessive CO

and H2S emissions. Through modeling, a revised configuration was developed (inverting alternate burners on

the lower rows), which addressed the problem withoutcompromising boiler performance. The modificationserved to validate model capabilities.Following parametric testing to establish optimal operating modes, a series of optimization tests were conductedon the LNCB® to assess environmental and operational

performance. Two sets of measurements were taken, oneby Babcock & Wilcox and the other by an independentcompany, to validate data accuracy. Consequently, thedata provided is a range reflecting the two measurements.The average NOx emissions reduction achieved at full

load with all mills in service ranged from 53.0–55.5%.With one mill out of service at full load, the average NOx

reduction ranged from 53.3–54.5%. Average NOx reduction at intermediate load (about 460 MWe) ranged from

52.5–54.7%. At low loads (about 350 MWe), averageNOx reduction ranged from 46.9–47.9%. NOx emissions

were monitored over the long term at full load for allmills in service and one mill out of service. Each testspanned an 8-month period. The NOx emission reductions realized were 58% for all mills in service and about

60% for one mill out of service.Complications arose in assessing CO emissions relativeto baseline because baseline calibration was not sufficiently refined. However, accurate measurements weremade with LNCB® in service. Carbon monoxide emissions were corrected for 3.0% O2 and measured at full,

intermediate, and low loads. The range of CO emissionsat full load with all mills in service was 28–55 ppm, and20–38 ppm with one mill out of service. At intermediateloads (about 460 MWe), CO emissions were 28–45 ppm,and at low loads (about 350 MWe), 5–27 ppm.Particulate emissions were minimally impacted. TheLNCB® had little effect on fly ash resistivity, largely due

to SO3 injection, and therefore ESP removal efficiency

remained very high. Baseline ESP collection efficienciesfor full load with all mills in service, full load with onemill in service, and intermediate load with one mill out ofservice were 99.50%, 99.49%, and 99.81%, respectively.For the same conditions, in the same sequence withLNCB® in operation, ESP collection efficiencies were

99.43%, 99.12%, and 99.35%, respectively.

Operational Performance

Furnace 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 for 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 outlet

temperature), offsetting UAlso, increased coal finenBecause sulfidation is the in substoichiometric comcoal, H2S levels were mon

mizing LNCB® operation

detection limit. There webut corrosion panel tests ewith LNCB® were roughl

Ash sample analyses indinot be a problem. The LN

baseline ash. Furthermorin furnace exit gas temperLNCB® indicated little ch

Startup and turndown of tconversion to LNCB®.

Single LNCB® retrofit.
Environmental Control Devices 

Economic Performance

The economic analyses were performed for a 600-MWenominal unit size and typical location in the midwestUnited States. A medium-sulfur, medium-volatile bituminous coal was chosen as the typical fuel. For a baselineNO

x

 emission level of 1.2 lb/106 Btu, 65% capacity factor, and a 50% reduction target, the estimated capital cost

was $9/kW (1994$). The 15-year levelized cost of electricity was estimated at 0.284 mills/kWh, or $96.48/ton ofNO

x

 removed in constant 1994 dollars.

Commercial Applications

The low cost and short outage time for retrofit make the LNCB® design the most costeffective NO

x control technology available

today for cell-burner boilers. The LNCB®

system can be installed at about half the costand time of other commercial low-NO

x

burners.Dayton Power & Light has retained theLNCB® for use in commercial service.

Seven commercial contracts have beenawarded for 172 burners, valued at $24million. LNCBs® have already been installed on more than 4,900 MWe of capacity.

The demonstration project received R&D

magazine’s 1994 R&D Award.Contacts ContactsContactsDot K. Johnson, (330) 829-7395

McDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601(330) 821-7801 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

References

• Final Report: Full-Scale Demonstration of Low-NOx

CellTM Burner Retrofit. Report No. DOE/PC/90545-

T2. The Babcock & Wilcox Company Research andDevelopment Division. December 1995. (Availablefrom NTIS as DE96003766.)

• Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit: Public Design Report. Report No. DOE/PC/

90545-T4. The Babcock & Wilcox Company EnergyServices Division. August 1991. (Available fromNTIS as DE92009768.)

The LNCB® viewed from within the boiler.

• Comprehensive Repo

Technology Program

Low-NO

x Cell Burne

Wilcox Company. RDepartment of EnergNTIS as DE9001802

The connections to the LNCB® viewed f
5-56 Program Update 2000 

Environmental Control Devices

NO

x Control Technology

Evaluation of Gas Reburningand Low-NOx Burners on a

Wall-Fired Boiler all-Fired Boiler

Project completed. Project completed.Participant

Energy and Environmental Research Corporation

Additional Team Members

Public Service Company of Colorado—cofunder and hostGas Research Institute—cofunderColorado Interstate Gas Company—cofunderElectric Power Research Institute—cofunderFoster Wheeler Energy Corp.—technology supplierLocation LocationLocationDenver, Adams County, CO (Public Service Company of

Colorado’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/Production

172 MWe (gross), 158 MWe (net)CoalColorado bituminous, 0.40% sulfur, 10% ash

Project Funding

Total project cost $17,807,258 100%DOE 8,895,790 50

Participant 8,911,468 50

Project Objective

To attain up to a 70% decrease in NOx emissions from an

existing wall-fired utility boiler, firing low-sulfur coalusing both gas reburning and low-NOx burners (GRLNB); and to assess the impact of GR-LNB on boilerperformance.

Technology/Project Description

Gas reburning involves injecting natural gas (up to 25%of total heat input) above the main coal combustion zonein a boiler. This upper-level injection and partial combustion by limiting available oxygen creates a fuel-rich zone.NO

x moving upward from coal combustion in the lower

furnace is stripped of oxygen as the reburn fuel is partially combusted in the reburn zone and converted tomolecular nitrogen. Overfire air ports above the reburnzone provide for complete combustion in a relativelycooler region of the boiler. Reburning allows the lowNO

x burners to operate at excess air levels far below that

needed for complete combustion, thus enhancing theireffectiveness. The synergistic effect of adding areburning stage to wall-fired boilers equipped with lowNO

x

 burners was intended to lower NO

x emissions by up

to 70%. Gas reburning wout the use of recirculated A series of parametric tesreburning system, varying and assessing the effect oness of combustion (carbthermal efficiency, and hetesting program was perfoconsistency of system outterm operation on the boiin operating GR-LNB in ronment, and develop a dGR-LNB applications. Bgas reburning tests were p
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• LNB alone reduced NO

x

 emissions from a

pre-construction baseline of 0.73 lb/106 Btu to0.46 lb/106 Btu (at 3.5% O2), a 37% NOx reduction.

• First-generation GR, which incorporated flue gas

recirculation in combination with LNB, reduced NOx

emissions to an average 0.25 lb/106 Btu (at 3.25% O2),

a 66% NO

x reduction at an 18% gas heat input rate.

• Second-generation GR, without flue gas recirculation

and in combination with LNB, reduced NOx emissions

to an average 0.26 lb/106 Btu, a 64% NOx reduction

with only 12.5% gas heat input.

• Both first- and second-generation GR with LNB were

capable of reducing NOx emissions by up to 70%

for short periods of time; the average was approximately 65%.

• After modifying the overfire air system to enhance

penetration and turbulence (as part of second-generation GR), CO emissions were controlled to acceptablelevels at low gas heat input rates.

• SO2 emissions and particulate loadings were reduced

by the percentage heat input supplied by GR.

Operational Operational

• Boiler efficiency decreased < 1.0%.

• There was no measurable boiler tube wear and only a

small amount of slagging.

• Carbon-in-ash and CO levels were acceptable for firstand second-generation GR with LNB, but not with

LNB alone.

Economic EconomicEconomic• Capital cost for a GR

plant is $26.01/kW (if not already existin$13.87/kW for LNB 

• Operating costs were 

ferential and the valu

because GR reduces 

coal.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward PreawardPreaward Operation and Reporting

12/89

Design and Construction

10/90 11/92

DOE selected project (CCT-III) 12/19/89

Environmental monitoring plan completed 7/26/90

NEPA process completed (MTF) 9/6/90

Cooperative agreement awarded 10/13/90

Ground breaking/construction started 6/91

Design completed 8/91

Construction completed;Operation initiated 11/92

Long-term operationsstarted 4/93

Operation completed 1/95

Restorationcompleted 11/95

Pro
5-58 Program Update 2000 

Project Summary

The demonstration established that GR-LNB offers acost-effective option for deep NOx reductions on wallfired boilers. GR-LNB NOx control performance approached that of selective catalytic reduction (SCR), but

at significantly lower cost. The importance of costeffective technology for deep NOx reductions is that it

meets the need for NOx reduction in ozone nonattainment

areas beyond what is currently projected in Title IV of theCAAA. Title I of the CAAA deals with ozonenonattainment and is currently the driving force for deepNOx reduction in many regions of the country.

The GR-LNB was installed and evaluated on a 172-MWe(gross) wall-fired boiler—a Babcock & Wilcox balanceddraft pulverized coal-fired unit. The GR system, including an overfire air system, was designed and installed by Energy and Environmental Research Corporation. The LNBs were designed and installed by Foster Wheeler Energy Corp. Parametric testing began in October 1992 and was com- pleted in April 1993. The parametric tests examined the effect of process variables (such as zone stoichiometric ratio, percent gas heat input, percent overfire air, and load) on NOx reduction, SO2 reduction, CO emissions, carbon-in-ash, and heat rates. The baseline performance of the LNB was also established. Environmental Performance At a constant load (150 MWe) and a constant oxygen level at the boiler exit, NOx emissions were reduced with increasing gas heat input. At gas heat inputs greater than

10%, NOx emissions were reduced marginally as gas heat

input increased. Natural gas also reduced SO2 emissions

in proportion to the gas heat input. At the CherokeeStation, low-sulfur (0.40%) coal is used, and typical SO2

emissions are 0.65 lb/106 Btu. With a gas heat input of

20%, SO2 emissions decreased by 20% to 0.52 lb/106 Btu.

The CO2 emissions were also reduced as a result of using

natural gas because it has a lower carbon-to-hydrogenratio than coal. At a gas heat input of 20%, the CO2

emissions were reduced by 8%.Long-term testing was initiated in April 1993 and completed in January 1995. The objectives of the test were toobtain operating data over an extended period when theunit was in routine commercial service, determine theeffect of GR-LNB operation on the unit, and obtain incremental maintenance and operating costs with GR. Duringlong-term testing, it was determined that flue gas recirculation had minimal effect on NOx emissions.

 A second series of tests was added to the demonstrationto evaluate a modified or second-generation system.Modifications included the following:• The flue gas recirculation system, originally designed

to provide momentum to the natural gas, was removed.(This change significantly reduced capital costs.)

• Natural gas injection w

input compared to the Removal of the flue gainstallation of high-vegreater use of availablmodification reduced nating costs.)

• Overfire air ports were 

momentum, particular

Over 4,000 hours of operresults shown in Exhibit 5

reduction performance of 45%, the overall objectivmet. Boiler efficiency dereburning due to increasefrom natural gas use. Furttube wear, and only small during the GR-LNB demoalone, carbon-in-ash and acceptable levels.

Economic Performan

GR-LNB is a retrofit techbenefits are dependent on factors:

A worker inspects the support ring for the Foster Wheeler lowNOx burner installed in the boiler wall.

Baseline (lb/106 Btu) 

Avg NOx reduction (%)

LNB GR-LNB 

Avg gas heat input (%) 

Exh

NOx Data f

Station
Environmental Control Devices 

• 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 heat

input of 12.5%. The capital cost estimate for a 300-MWewall-fired installation is $26.01/kW (1996$), plus gaspipeline costs, if required. This cost includes both equipment and installation costs and a 15% contingency. TheGR and LNB system capital costs can be easily separatedfrom one another because they are independent systems.The capital cost for the GR system only is estimated at$12.14/kW. The LNB system capital cost is $13.87/kW.Operating costs are almost entirely related to the differential cost of natural gas and coal and reduced by the valueof the SO2 emission credits received due to absence of

sulfur in the gas. A fuel differential of $1.00/106 Btu was

used because gas costs more than coal on a heating valuebasis. Boiler efficiency was estimated to decline by0.80%; the cost of this decline was calculated using acomposite fuel cost of $1.67/106 Btu. Overfire air

booster and cooling fan auxiliary loads will be partiallyoffset by lower loads on the pulverizers. No additionaloperating labor is required, but there is an increase inmaintenance costs. Allowances also were made for overhead, taxes, and insurance. Based on these assumptionsand assuming an SO2 credit allowance of $95/ton (Feb.

1996$), the net operating cost is $2.14 million per yearand the NOx removal cost is $786/ton (constant 1996$).

Commercial Applications

The 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 catalytic

reduction. 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 gasreburning system for immediate use; however, a restoration was required to remove the flue gas recirculation

system.Energy and Environmental Research Corporation hasbeen awarded two contracts to provide gas-reburningsystems for five cyclone coal-fired boilers: TVA’s AllenUnit No. 1, with options for Unit Nos. 2 and 3 (identical330-MWe units); and Baltimore Gas & Electric’s C.P.Crane, Unit No. 2, with an option for Unit No. 1 (similar200-MWe units). Use of the technology also extends tooverseas markets. One of the first installations of thetechnology took place at the Ladyzkin State Power Station in Ladyzkin, Ukraine.This demonstration project was one of two that receivedthe Air and Waste Management Association’s 1997J. Deanne Sensenbaugh Award.Contacts ContactsContactsBlair A. Folsom, Sr. V.P., (949) 859-8851, ext. 140

General Electric Energy and Environmental ResearchCorporation18 MasonIrvine CA 92618(949) 859-3194 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483Jerry L. Hebb, NETL, (412) 386-6079

References

• Evaluation of Gas Reburning and Low-NOx Burners

on a Wall-Fired Boiler: Performance and Economics

Report, Gas Reburning—Low-NOx Burner System,

Cherokee Station Unit No. 3, Public Service Company

of Colorado. Final Report. July 1998.

• Guideline Manual: 

System, Cherokee Sta

Company of Colorad

• Evaluation of Gas R

on a Wall-Fired Boil

1993–January 1995)

T20. Energy and Ention. June 1995. (AvDE95017755.)

• Evaluation of Gas R

on a Wall-Fired Boil

ber 1992–April 1993

T19. Energy and Ention. June 1995. (AvDE95017754.)
5-60 Program Update 2000 

MicroMill is a trademark of the Fuller Company.LNCFS is a trademark of ABB Combustion Engineering, Inc.

Environmental Control Devices

NO

x Control Technology

Micronized Coal ReburningDemonstration for NO

x Control Control Control

Project completed. Project completed.Participant

New York State Electric & Gas Corporation

Additional Team Members

Eastman Kodak Company—host and cofunderCONSOL (formerly Consolidation Coal Company)—coal

sample tester

D.B. Riley—technology supplierFuller Company—technology supplierEnergy and Environmental Research Corporation

(EER)—reburn system designer

New York State Energy Research and Development

Authority—cofunder

Empire State Electric Energy Research Corporation—

cofunder

Locations LocationsLocationsLansing, Tompkins County, NY (New York State Electric

& Gas Corporation’s Milliken Station, Unit No. 1)

Rochester, Monroe County, NY (Eastman Kodak

Company’s Kodak Park Power Plant, Unit No. 15)

TechnologyD.B. Riley’s MPS mill (at Milliken Station) and Fuller’sMicroMillTM (at Eastman Kodak) technologies for producing micronized coal

Plant Capacity/Production

Milliken 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 Funding

Total project cost $9,096,486 100%DOE 2,701,011 30Participant 6,395,475 70

Project Objective

To achieve at least 50% NO

x

 reduction with micronized

coal reburning technology on a cyclone boiler, to achieve25—35% NO

x reduction with micronized coal reburning

technology in conjunction with low-NOx burners on a

tangentially fired boiler, and to determine the effects ofcoal micronization on electrostatic precipitator (EPS)performance.

Technology/Project DThe reburn coal, which catotal fuel, is micronized (low 325 mesh) and injectfurnace above the primary Milliken tangentially fire

achieved by: (1) close-coreburning in which the toIIITM burner is used for inthe separated overfire air and (2) the remaining burfor deep-stage combustiofuel-rich inner zone and fcombustion air. At the Kthe Fuller MicroMillTM is coal, reburn fuel is introdtor, and overfire air is emtion.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

3/97

Preaward PreawardPreaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

9/91 7/92

DOE selectedproject (CCT-IV)9/12/91

Design and Construction Operation and Reporting

Operation 

Operation complete

Ground breaking/construction started (Lansing) 3/15/96

Design completed (Rochester) 9/96

Ground breaking/construction started (Rochester) 9/8/96

NEPA process completed(CX) 8/13/92

Cooperative agreement awarded 7/28/92

Preoperational tests initiated (Rochester) 1/97

Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

Operation initiated (Rochester) 4/97

Environmental monitoring plan completed Environmental monitoring plan completed 

Construction completed (Lansing) 1/97

Operation initiated (Lansing) 3/97

Project relocated to Lansing and Rochester 12/95

Fin

Results Summary

Environmental Environmental

• Using a 14.4% reburn fuel heat input on the Milliken

Station tangentially fired boiler at full load resulted in aNO

x

 emission rate of 0.25 lb/106 Btu, which represents

a 29% NO

x

 reduction from the 0.35 lb/106 Btu achieved

with the LNCFS IIITM burner alone (baseline).

• Using a 17.3% reburn fuel heat input (reburn stoichiometry of 0.89) on the Kodak Park cyclone boiler

resulted in a NO

x

 emission rate of 0.59 lb/106 Btu,

which represents a 59% NOx reduction from 1.36 lb/

106 Btu (baseline). Higher reburn rates (estimated at

18.4% reburn or stoichiometry of 0.87) would be required for long-term compliance with 0.60 lb/106 Btu

NO

x

 emission limits.

Operational Operational

• Reburning was successfully applied at Milliken Station

using the top coal feed of the LNCFS IIITM burner forthe reburn fuel and reducing the top burner level airflows. This eliminated the need for a separate reburnsystem. Testing on the tangentially fired boiler at Milliken Station showed:

– Unburned carbon-in-ash, also referred to as loss-onignition (LOI), was maintained under 5%;– Increasing the economizer O2 generated the classical

response of higher NOx emissions and lower LOI—

the sensitivity was estimated at 0.1 lb/106 Btu per 1%

change in O2 and was relatively independent of coal

fineness;

– Increasing coal fineness reduced both NOx emissions

and LOI—the effect on NO

x was significant only for

large variations in coal fineness; and

– Pulverizing the reburn coal to the micronized level

(greater than 80% passing 325 mesh) was not a requirement for the successful application ofreburning, but significantly impacted LOI.

• Testing on the cyclone boiler at Kodak Park showed:

– The reburn stoichiometry had a significant effect on

NO

x emissions and a significant effect on LOI—

lower reburn stoichiometries reduced NO

x

 emissions

and increased LOI to 40–45% compared with a LOIbaseline of 10–15%.

– Short-term testing indicated that LOI could be maintained at levels similar to baseline levels without

significantly affecti

a baseline cyclone 

Economic EconomicEconomic• The estimated capital 

300-MWe tangentiallcoal reburning is $4.3 kW (1999$). The cormated at $0.30 milliototal 15-year levelize

moved (current 1999$

• The estimated capital 

300-MWe cyclone boreburning is $16.9 mi(1999$). The correspat $0.80 million per ylevelized cost is $741

1999$) or $571 (cons
5-62 Program Update 2000 

Project Summary

NYSEG demonstrated the micronized coal reburning technology in both tangentially fired and cyclone boilers. Thetangentially fired boiler was NYSEG’s Milliken Station148-MWe tangentially fired Unit No. 1 (also the host foranother CCT Program demonstration). The cyclone boilerwas Eastman Kodak Company’s Kodak Park Power Plant60-MWe cyclone Unit No. 15.The challenge with this coal reburning demonstration wasto achieve adequate combustion of the reburn coal in theoxygen-deficient, short-residence-time reburn zone toreduce NOx emissions without detrimentally increasing

the unburned carbon in the ash, i.e., loss-on-ignition. The

primary objective of this two-site project was to demonstrate improvements in coal reburning for NOx emission

control by reducing the particle size of the reburn coal. Inthis demonstration, the coal was finely ground to 80% ormore passing 325 mesh and injected into the boilersabove the primary combustion zone. The resulting typicalparticle size is 20 microns compared to 60 microns fornormal pulverized coal particles. This smaller size increases surface area ninefold.With this increased surface area and coal fineness (micronized coal has the combustion characteristics of atomized oil), carbon combustion occurs in milliseconds andvolatiles are released at an even rate.

Operating Performance

At the Milliken Station, the existing ABB Low-NOx

Concentric Firing SystemTM (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 fourlevels of burners. To simulate and test the coal reburningapplication, the top-level coal injection nozzles fed micronized coal to the upper part of the furnace for thisdemonstration. The coal injection nozzles at the threelower elevations were biased to carry approximately 80%of the fuel required for full load. The speed of the dynamic classifier serving the mill feeding the top burners

was increased to produce the micronized coal (greaterthan 80% passing 325 mesh).During the evaluation, several conclusions were reachedon how operating variables affected performance. Whilemaintaining a constant economizer O2 level, no single

operating variable had a dominant effect on reburningperformance. A combination of operating settings determined from short-term testing were selected for long-termoperation to achieve the lowest NOx emissions and reliable operation. Operating settings for long-term operation were 14–16% reburn coal, 105 rpm top mill classifier

speed (corresponds to 70–72% passing 325 mesh), –5degrees main burner tilt and 2.8% economizer O2. No

additional improvement in LOI was observed at top millclassifier speeds above 105 rpm.At Kodak Park, EER designed the micronized coal reburnsystem using a combination of analytical and empiricaltechniques. The reburn fuel and OFA injection components were designed with a high degree of flexibility toallow for field optimization to accommodate the complexfurnace flow patterns in the cyclone boiler. Two FullerMicroMillsTM were installed in parallel on Kodak ParkUnit No. 15 to provide the capacity necessary for highreburn rates, with the second mill serving as a spare atlower reburn rates. The mills produced the micronizedcoal reburn fuel at greater than 90% passing 325 mesh.Eight injectors, six on the rear wall and one on each ofthe side walls, introduced the micronized coal into thereburn zone. The optimization variables included thenumber of injectors, swirl, and velocity. Four ports on thefront wall provided OFA using EER’s second-generation,dual-concentric overfire air design, which has variableinjection velocity and swirl. To maximize NOx reduction,

the reburn fuel was injected with flue gas rather than air.The flue gas was extracted downstream of the electrostatic precipitator and was boosted by a single fan. A newboiler control system was also installed on Unit No. 15.

Environmental Performance

At the Milliken Station, micronized coal reburning with14.4% reburn fuel at full load reduced NOx emissions

from the 0.35 lb/106 Btu baseline level to 0.25 lb/106 Btu,

a 29% reduction. This rethe 39% reduction achiev

NOx burner alone. Boiler 

88.4–88.8%. Furthermorthrough fewer and higher reburn coal maintained Lterm testing consisting of ments, the achievable ann

coal reburn heat input we106 Btu (95% confidence)

ash LOI was 4.4 ± 0.4%. mance tests and a 95% coNOx emissions less than 0

LOI less than 1.5 percentof no statistical significanties with respect to the effLOI generally varied with(between 3% and 5%) in variables.With regard to reburn coatity, using a finer grind reboth NOx emissions and L

significant (relative to the 106 Btu) only for relativel

classifier speed (and hencgrind coal (all mills) redu

LOI. Decreasing the rebu14% decreased NOx emis

Btu and had a minor effec1.5 percentage points). Th

creasing the coal reburn fexcess air levels in the prcoal was diverted to the lReducing the boiler load 

effect was greater when thservice. Thus, reducing thsecond mill out of service Taking the second mill outhe same boiler load redu

(140 MW) and low (110 Mto longer residence times 
Environmental Control Devices 

Changes in air flow resulted in measurable changes inboth NOx reduction and LOI. An increase in the reburn

coal 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 oxidant with the reburn fuel. Increasing the top level auxiliary airflow increased both NOx emissions and LOI. This

increase in NOx was attributed to less reducing reburn

zones as more oxidant was introduced through the auxiliary air nozzle situated directly below the reburn coalnozzle. The increase in LOI from increasing the top levelauxiliary airflow was attributed to lower excess air levelsin the primary combustion zone as more air was divertedaway from the lower burners. Increasing the economizerO2 generated the classical response of higher NOx emissions and lower or stable LOI. The economizer O2 sensitivity was estimated at 0.1 lb NOx/106 Btu per 1% change

in O2 and was relatively independent of the reburn coal

fineness.The SOFA and main burner tilts had minimal effects onperformance. Variations in the SOFA tilt between 0 and15 degrees (above horizontal) had minor effects on bothNOx emissions and LOI in both LNCFS IIITM and reburn

configurations. Operating the main burner tilt slightlybelow the horizontal (about -5 degrees) improved thereburning performance (lower LOI without increasingNOx), relative to the horizontal setting, which was attributed to longer residence times in the furnace prior tooverfire air introduction. Overall, the effect was difficultto quantify due to the limited number of tests.At Kodak Park, the application of micronized coal reburning reduced NOx emissions and increased LOI, as

expected. Micronized coal reburning with 17.3% reburnfuel at a reburn stoichometry of 0.89, reduced NOx emissions to 0.59 lb/106 Btu from a baseline of 1.36 lb/106

Btu, a 59% reduction, and reduced the boiler efficiencyfrom 87.8% to 87.3%. At greater reburn rates, furtherNOx reduction was achieved to a degree comparable with

gas reburning systems. At full load, LOI was 40–45%,compared with a baseline level of 10–12%.Based on long-term testing, the achievable annual NOx

emissions (at 15.6% reburn or stoichiometry of 0.90)were 0.69 ± 0.03 lb/106 Btu (95% confidence), corresponding to an LOI of 38% ± 2%. Higher reburn feeds

(estimated at 18.4% reburn or stoichiometry of 0.87)would be required for long-term compliance with the 0.6lb/106 Btu NOx emissions limit.

The reburn stoichiometry had a significant effect on NOx

emissions and a significant effect on the LOI. Lowerreburn stoichiometries reduced NOx emissions and increased the LOI, typically dropping below 0.6 lb/106 Btu

at reburn stoichiometries below 0.9 and corresponding to40–45% LOI. The increase in the LOI relative to baselinewas partially due to a lower cyclone heat input, whichresulted in lower temperatures in the primary combustionzone. The lower temperatures produced less thermal NOx

formation and less efficient char burnout. The LOI increase was also partially due to the staged combustionresulting in shorter residence times under oxidizing conditions. At constant heat input levels, the LOI was notsignificantly different with or without reburning, suggesting that in reburn applications, the LOI could be maintained at levels similar to baseline by maintaining a highcyclone heat input. The contribution of reburning alone(assuming no change in the cyclone heat input) to theincrease in the LOI was estimated at 0–12% (absolute).

Economic Performance

Estimates were prepared for retrofitting micronized coalreburning on generic 300-MWe tangentially fired andcyclone boilers. For the tangentially fired boiler, thecapital costs were estimated at $4.3 million, or approximately $14/kW (1999$). The O&M costs were estimatedat $0.30 million per year (1999$). Costs were levelizedboth on a current dollar and constant dollar basis. The15-year levelized cost for the 300-MWe unit is $1,329/tonof NOx removed on a current dollar basis, and $1,023/ton

of NOx removed on a constant dollar basis (1999$).

For the cyclone boiler, tmillion, or approximatemated O&M costs are $The total 15-year leveliz

moved on a current dolldollar basis (1999$).

Commercial Applica

Micronized coal reburniexisting and greenfield tangentially fired pulverreduces NOx emissions 

modifications for existinThe availability of a coafuel to the furnace, enabvalue coals without boilcan achieve a turndown without consuming expeContacts ContactsContactsJim Harvilla, (607) 762

New York State ElecCorporate Drive—KP.O. Box 5224Binghamton, NY 13(607) 762-8457 (fax

Lawrence Saroff, DOE/James U. Watts, NETL, 

References

• Micronized Coal Reb

Control. Final Repor

Corporation and CON

• Reburning Technolog

Oxides from Coal-Fir

Energy, Babcock & WTopical Report No. 14

• Savichky et al. “Mic

stration of NOx Contr

Conference: Technica
5-64 Program Update 2000 

Environmental Control Devices

NO

x Control Technology

Demonstration of SelectiveCatalytic Reduction Technol- echnol- echnology for the Control of NOxEmissions from High- Emissions from High-Sulfur,

Coal-Fired Boilers

Project completed. Project completed.Participant

Southern Company Services, Inc.

Additional Team Members

Electric Power Research Institute—cofunderOntario Hydro—cofunderGulf Power Company—hostLocation LocationLocationPensacola, Escambia County, FL (Gulf PowerCompany’s Plant Crist, Unit No. 4)TechnologySelective catalytic reduction (SCR)

Plant Capacity/Production

8.7-MWe equivalent (three 2.5-MWe and six 0.2-MWeequivalent SCR reactor plants)CoalIllinois bituminous, 2.7% sulfur

Project Funding

Total project cost $23,229,729 100%DOE 9,406,673 40Participant 13,823,056 60

Project Objective

To evaluate the performance of commercially availableSCR catalysts when applied to operating conditions foundin U.S. pulverized coal-fired utility boilers using highsulfur U.S. coal under various operating conditions, whileachieving as much as 80% NOx removal.

Technology/Project DescriptionThe SCR technology consists of injecting ammonia intoboiler flue gas and passing it through a catalyst bed wherethe NO

x and ammonia react to form nitrogen and water

vapor.In this demonstration project, the SCR facility consistedof three 2.5-MWe equivalent SCR reactors, supplied byseparate 5,000-scfm flue gas slipstreams, and six0.20-MWe equivalent SCR reactors. These reactors werecalculated to be large enough to produce design data thatwill allow the SCR process to be scaled up to commercialsize. Catalyst suppliers (two U.S., two European, andtwo Japanese) provided eight catalysts with variousshapes and chemical compositions for evaluation of process chemistry and economics of operation during thedemonstration.

The project demonstratedof flue gas, the applicabilvide a cost-effective mean

from power plants burninThe demonstration plant, Power Company’s Plant Cused flue gas from the bu
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• NO

x

 reductions of over 80% were achieved at an

ammonia slip well under the 5 ppm deemed acceptablefor commercial operation.

• Flow rates could be increased to 150% of design without exceeding the ammonia slip design level of 5 ppm

at 80% NO

x

 reduction.

• While catalyst performance increased above 700 oF,

the benefit did not outweigh the heat rate penalties.

• Increases in ammonia slip, a sign of catalyst deactivation, went from less than 1 ppm to approximately

3 ppm over the nearly 12,000 hours of operation, thusdemonstrating deactivation in coal-fired units was inline with worldwide experience.

• Long-term testing showed that SO2 oxidation was

within or below the design limits necessary to protectdownstream equipment.

Operational Operational

• Fouling of catalysts was controlled by adequate

sootblowing procedures.

• Long-term testing showed that catalyst erosion was

not a problem.

• Air preheater performance was degraded because of

ammonia slip and subsequent by-product formation;however, solutions were identified.

• The SCR process did not significantly affect the results of Toxicity Characteristic Leaching Procedure

(TCLP) analysis of the fly ash.

Economic EconomicEconomic• Levelized costs on a 

at a 0.35 lb/106 Btu N

and 2.79 mills/kWh 80 percent removal eequates to 3,502; 2,51996$), respectively.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward PreawardPreaward

9/88

Design and Construction Operation and Reporting

6/90

DOE selected project(CCT-II) 9/28/88

NEPA processcompleted(MTF) 8/16/89

Cooperative agreementawarded 6/14/90

Ground breaking/construction started 3/92

7/93

Preoperational tests initiated 3/93Environmental monitoring plan completed 3/11/93

Construction completed 2/93

Design completed 12/92

Operation initiated 7/93

Operation completed 7/
5-66 Program Update 2000 

Project Summary

The demonstration tests were designed to address severaluncertainties, including potential catalyst deactivation dueto poisoning by trace metals species in U.S. coals, performance of the technology and its effects on the balance-ofplant equipment in the presence of high amounts of SO2and SO3, and performance of the SCR catalyst under

typical U.S. high-sulfur coal-fired utility operating conditions. Catalyst suppliers were required to design thecatalyst baskets to match predetermined reactor dimensions, provide a maximum of four catalyst layers, andmeet the conditions shown in Exhibit 5-27.The catalysts tested are listed in Exhibit 5-28. Catalystsuppliers were given great latitude in providing theamount of catalyst for this demonstration.

Environmental Results

Ammonia slip, the controlling factor in the long-termoperation of commercial SCR, was usually <5 ppm because of plant and operational considerations. Ammonia

slip was dependent on catalyst exposure time, flow rate,temperature, NH3/NOx distribution, and NH3/NOx ratio

(NOx reduction). Changes in NH3/NOx ratio and consequently NOx reduction generally produced the most significant changes in ammonia slip. The ammonia slip at

60% NO

x 

reduction was at or near the detection limit of

1 ppm. As NOx reduction was increased above 80%,

ammonia slip also increased and remained at reasonablelevels up to NOx reductions of 90%. Over 90%, the

ammonia slip levels increased dramatically.The flow rate and temperature effects on NOx reduction

were also measured. In general, flows could be increasedto 150% of design without the ammonia slip exceeding 5ppm, at 80% NOx reduction and at the design temperature. With respect to temperature, most catalysts exhibited fairly significant improvements in overall performance as temperatures increased from 620 °F to 700 °F,

but relatively little improvement as temperature increasedfrom 700 °F to 750 °F. The conclusion was that the benefits of high-temperature operation probably do not outweigh the heat rate penalties involved in operating SCRat the higher temperatures.Catalyst deactivation was observed by an increase in ammonia slip over time, assuming the NOx reduction efficiency was held constant. Over the 12,000 hours of the

demonstration tests, the ammonia slip did increase fromless than 1 ppm to approximately 3 ppm. These resultsdemonstrated the maturity of catalyst design and that deactivation was in line with prior worldwide experience.

Experience has shown tharesult in NOx reduction o

tion (i.e., SO3 formation), 

downstream equipment. 

increased as the tolerance 

upper bound for SO2 oxid

catalyst was set at 0.75% average SO2 oxidation rat

shown in Exhibit 5-29. Ttions over the life of the dlysts were within design loxidation rates below the Other factors affecting SO

temperature. Most of the stant SO2 oxidation with r

velocity). In theory, SO2 

proportional to flow rate. between SO2 oxidation an

nential as temperature incshowed the relationship tin SO2 oxidation between 

hand, between 700 °F and 

increased more significan

Exhibit 5-28

Catalysts Tested

Catalyst CatalystCatalyst Reactor Size* Catalyst CatalystCatalyst

Configuration

Nippon/Shokubai Large HoneycombSiemens AG Large Plate

W.R. Grace/Noxeram Large HoneycombW.R. Grace/Synox Small HoneycombHaldor Topsoe Small PlateHitachi/Zosen Small PlateCormetech/High dust Small HoneycombCormetech/Low dust Small Honeycomb

* Large = 2.5 MWe; 5,000 scfm Small = 0.2 MWe; 400 scfm

Exh

Average SO verage SOverage SO

(Ba

(Ba

(Ba

(Ba

(Ba

Parameter Minimum Minimum Baseline BaselineBaseline Maximum Maximum

Temperature (oF) 620 700 750

NH3/NOx molar ratio 0.6 0.8 1.0Space velocity(1% design flow) 60 100 150Flow rateLarge reactor (scfm) 3,000 5,000 7,500Small reactor (scfm) 240 400 600

Exhibit 5-27

Reactor Baseline Conditions
Environmental Control Devices 

Other findings from the demonstration deal with pressuredrop, fouling, erosion, air preheater performance, ammonia volatilization, and TCLP analysis. Overall reactorpressure drop was a function of the catalyst geometry andvolume, but tests were inconclusive in determining whichparameter was controlling. The fouling characteristics ofthe catalyst were important to long-term operation. During the demonstration, measurements showed a relativelylevel pressure drop over time, indicating that sootblowingprocedures were effective. The plate-type configurationhad somewhat less fouling potential than did the honeycomb configuration, but both were acceptable. Catalysterosion was not considered to be a significant problembecause most of the erosion was attributed to aggressivesootblowing. With regard to air preheater performance,the demonstration showed that the SCR process exacerbated performance degradation of the air preheatersmainly due to ammonia slip and subsequent by-productformation. Regenerator-type air heaters outperformedrecuperators in SCR applications in terms of both thermalperformance and fouling. The ammonia volatilized fromthe SCR fly ash when a significant amount of water wasabsorbed by the ash. This was caused by formation of amoist layer on the ash with a pH high enough to convertammonia compounds in the ash to gas-phase ammonia.TCLP analyses were performed on fly ash samples. TheSCR process did not significantly affect the toxics leachability of the fly ash.

Economic Results

An economic evaluation was performed for full-scaleapplications of SCR technology to a new 250-MWe pulverized coal-fired plant located in a rural area with minimal space limitations. The fuel considered was highsulfur Illinois No. 6 coal. Other key base case designcriteria are shown in Exhibit 5-30.The economic analysis of capital, operating and maintenance (O&M), and levelized cost for various unit sizesfor an SCR system are shown in Exhibit 5-31. Results ofthe economic analysis of capital, O&M, and levelizedcost for various NOx removal efficiencies for a 250-MWe

unit are shown in Exhibit 5-32. For retrofit applications,

the estimated capital costs were $59–112/kW, dependingon the size of the installation and the difficulty and scopeof the retrofit. The levelized costs for the retrofit applications were $1,850–5,100/ton (1996$).

Commercial Applications

As a result of this demonstration, SCR technology hasbeen shown to be applicable to existing and new utilitygenerating capacity for removal of NOx from the flue gas

of virtually any size boiler. There are over 1,000 coalfired utility boilers in active commercial service in theUnited States; these boilers represent a total generatingcapacity of approximately 300,000 MWe.Contacts ContactsContactsLarry Monroe, (205) 257-7772

Southern Company Services, Inc.Mail Stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195(205) 257-5367 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

Exhibit 5-30

SCR Design Criteria

Parameter ParameterParameter SpecificationType of SCR Hot sideNumber of reactors OneReactor configuration 3 catalyst support layersInitial catalyst load 2 of 3 layers loadedRange of operation 35–100% boiler loadNOx inlet concentration 0.35 lb/106 Btu

Design NOx reduction 60%

Design ammonia slip 5 ppmCatalyst life 16,000 hrAmmonia cost $250/tonSCR cost $400/ft3

Capital cost ($/kW) Operating cost ($/yr) Constant 1996$ leveliMills/kWh $/ton NOx removed Note: 30 year life; 60% N

Ex

SCR Econo

Ex

SCR Econom

Capital cost ($/kW) Operating costs ($/yr) Constant 1996$ levelizmills/kWh $/ton NOx removed Note: 250MWe; 0.35 lb/1

References

• Maxwell, J. D., et al

nology for the Contr

Sulfur Coal-Fired Ut

Coal Technology Co

January 1997.

• Demonstration of SC

NOx Emissions from 

Boilers: Final Repor

Services, Inc. OctobVol. 1 as DE9705087DE97050874, and VDE97050875.)
5-68 Program Update 2000 

Environmental Control Devices

NO

x Control Technology

180-MWe Demonstration of e Demonstration of

Advanced Tangentially Fired

Combustion Techniques for echniques for

the Reduction of NO

x

Emissions from Coal-Fired Boilers

Project completed. Project completed.Participant

Southern Company Services, Inc.

Additional Team Members

Gulf Power Company—cofunder and hostElectric Power Research Institute—cofunderABB Combustion Engineering, Inc.—cofunder and

technology supplier

Location LocationLocationLynn Haven, Bay County, FL (Gulf Power Company’s

Plant Lansing Smith, Unit No. 2)

TechnologyABB Combustion Engineering’s Low-NOx Concentric

Firing System (LNCFSTM) with advanced overfire air(AOFA), clustered coal nozzles, and offset air

Plant Capacity/Production

180 MWeCoalEastern bituminous, high reactivity

Project Funding

Total project cost $8,553,665 100%DOE 4,149,382 49Participant 4,404,283 51

Project Objective

To demonstrate in a stepwise fashion the short- and longterm NO

x reduction capabilities of LNCFSTM levels I, II,

and III on a single reference boiler.Technology/Project DescriptionTechnologies demonstrated included LNCFSTM levels I,II, and III. Each level of the LNCFSTM used differentcombinations of overfire air and clustered coal nozzlepositioning to achieve NOx reductions. With the

LNCFSTM, primary air and coal are surrounded by oxygen-rich secondary air that blankets the outer regions ofthe combustion zone. LNCFSTM I used a close-coupledoverfire air (CCOFA) system integrated directly into thewindbox of the boiler. A separated overfire air (SOFA)system located above the combustion zone was featuredin the LNCFSTM II system. This was an advanced

overfire air system that inflow measurement capabiboth used in the LNCFSTM Carefully controlled shortfollowed by long-term tesconditions. Long-term temonths for each phase, becharacteristics of each tecbased on long-term test d

LNCFS is a trademark of ABB Combustion Engineering, Inc.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• At full load, the NOx emissions using LNCFSTM I, II,

and III were 0.39, 0.39, and 0.34 lb/106 Btu, respectively, which represent reductions of 37, 37, and 45%

from the baseline emissions.

• Emissions with LNCFSTM were not sensitive to power

outputs between 100 MWe and 200 MWe, but emissions increased significantly below 100 MWe, reaching baseline emission levels at 70 MWe.

• Because of reduced effectiveness at low loads,

LNCFSTM proved marginal as a compliance option forpeaking load conditions.

• Average CO emissions increased at full load.• Air toxics testing found LNCFSTM to have no clear-cut

effect on the emissions of trace metals or acid gases.Volatile organic compounds (VOCs) appeared to bereduced and semi-volatile compounds increased.

Operational Operational

• Loss-on-ignition (LOI) was not sensitive to the

LNCFSTM retrofits, but very sensitive to coal fineness.

• Furnace slagging was reduced, but backpass fouling

was increased for LNCFSTM II and III.

• Boiler efficiency and unit heat rate were impacted

minimally.

• Unit operation was not significantly affected, but

operating flexibility of the unit was reduced at lowloads with LNCFSTM II and III.

Economic EconomicEconomic• The capital cost estimate for LNCFSTM I was

$5–15/kW, and for LNCFSTM II and III, $15–25/kW(1993$).

• The cost-effectiveness for LNCFSTM I was $103/ton of

NO

x removed; LNCFSTM II, $444/ton; and LNCFSTM

III, $400/ton (1993$).

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward PreawardPreaward Operation and Reporting

9/88 9/90

Design and Construction

Project completed/final report issued 6/94

6/94

Environmental monitoringplan completed 12/27/90

Ground breaking/construction started 11/90

Design completed 4/91

Constructioncompleted 5/91Operation initiated 5/91 Operation completed 12/92

NEPA processcompleted (MTF)7/21/89

DOE selectedproject(CCT-II)9/28/88

Cooperative agreement awarded 9/20/90

5/91
5-70 Program Update 2000 

Project Summary

LNCFSTM technology was designed for tangentially firedboilers, which represent a large percentage of the preNSPS coal-fired generating capacity. The technologyreduces NOx by staging combustion vertically in the

boiler with separate coal and air injectors, and horizontally by creating fuel-rich and lean zones with offset airnozzles. The objective was to determine NOx emission

reductions and impact on boiler performance under normal dispatch and operating conditions over the long-term.By using the same boiler, the demonstration provideddirect comparative performance analysis of the threeconfigurations. Short-term parametric testing enabledextrapolation of results to other tangentially fired units byevaluating the relationship between NOx emissions and

key operating parameters.At the time of the demonstration, specific NOx emission

regulations were being formulated under the CAAA. Thedata developed over the course of this project providedneeded real-time input to regulation development.Exhibit 5-33 shows the various LNCFSTM configurationsused to achieve staged combustion. In addition tooverfire air, the LNCFSTM incorporates other NOx-reducing techniques into the combustion process as shown in

Exhibit 5-34. Using offset air, two concentric circularcombustion regions are formed. The majority of the coalis contained in the fuel-rich zone. This region is surrounded by a fuel-lean zone containing combustion air.The size of this outer annulus of combustion air can bevaried using adjustable offset air nozzles.

Operational Performance

Exhibit 5-35 summarizes the impacts of LNCFSTM onunit performance.

Environmental Performance

At full load, LNCFSTM I, II, and III reduced NOx emissions by 37, 37, and 45%, respectively. Exhibit 5-36

presents the NOx emission estimates obtained from the

assessment of the average annual NOx emissions for three

dispatch scenarios.

Air toxics testing found LNCFSTM to have no clear-cuteffect on the emission of trace metals or acid gases. Thedata provided marginal evidence for a decreased emissionof chromium. The effect on aldehydes/ketones could notbe assessed because baseline data were compromised.VOCs appeared to be reduced and semi-volatile compounds increased. The increase in semi-volatile compounds was deemed to be consistent with increases in theamount of unburned carbon in the ash.

Economic Performance

LNCFSTM II was the only complete retrofit (LNCFSTM Iand III were modifications of LNCFSTM II), and thereforecapital cost estimates were based on the Lansing SmithUnit No. 2 retrofit as well as other tangentially firedLNCFSTM retrofits. The capital cost ranges in 1993 dollars follow:

• LNCFSTM I—$5–15/k• LNCFSTM II—$15–25

• LNCFSTM III—$15–2Site-specific consideratiocapital costs; however, thexperience and are plannicost for LNCFSTM II at Lmillion, or $17/kW, whicrange.The cost-effectiveness of based on the capital and oand the NOx removal effi

cost-effectiveness of the L(based on a levelization fdollars):

Exhibit 5-33

LNCFSTM Configurations

Exh

Concentric Concentric 
Environmental Control Devices 

• LNCFSTM I—$103/ton of NOx removed

• LNCFSTM II—$444/ton of NOx removed

• LNCFSTM III—$400/ton of NOx removed

Commercial Applications

The LNCFSTM technology has potential commercialapplication to all the 423 U.S. pulverized coal, tangentially fired utility units. These units range from 25 MWeto 950 MWe in size and fire a wide range of coals, fromlow-volatile bituminous through lignite.The LNCFSTM has been retained at the host site for commercial use. ABB Combustion Engineering has modified116 tangentially fired boilers with LNCFSTM and derivative TFS 2000TM burners, representing over 25,000 MWe.Contacts ContactsContactsLarry Monroe, (205) 257-7772

Southern Company Services, Inc.Mail Stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195(205) 257-5367 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

References

• 180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the

Reduction of Nitrogen Oxide (NOx) Emissions from

Coal-Fired Boilers: Final Report and Key Project

Findings. Report No. DOE/PC/89653-T14. Southern

Company Services, Inc. February 1994. (Availablefrom NTIS as DE94011174.)

• 180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx) Emissions from Coal-Fired

Boilers—Plant Lansing Smith—Phase III and Final

Environmental Monitoring Program Report. Southern

Company Services, Inc. December 1993.

Exhibit 5-35

Unit Performance Impacts Based on Long

Baseline BaselineBaseline LNCFSTM I LNCFSTM ILNCFSTM I LNCFSTM ILNCFSTM I LNCFSTM I

LNCFSTM I

Avg CO at full load (ppm) 10 12 22 Avg excess O2 at full load (%) 3.7 3.2 4.5 

LOI at full load (%) 4.8 4.6 4.2 

O2 (%) 4.0 3.9 5.3 

Steam outlet conditions Satisfactory at full Full load: 5–10 oF Same as bas

load; low temper- lower than baseline atures at low loads Low loads: 10–30 oF

lower than baseline 

Furnace slagging and Medium Medium Reduced sla

backpass fouling but increased Operating flexibility Normal Same as baseline More care re

at low loads 

Boiler efficiency (%) 90 90.2 89.7 

Efficiency change (points) N/A +0.2 -0.3 Turbine heat rate (Btu/kWh) 9,000 9,011 9,000 Unit net heat rate (Btu/kWh) 9,995 9,986 10,031 Change (%) N/A -0.1 +0.36 

Exhibit 5-36

Average Annual NOx Emissions and Perce

Boiler Duty Cycle Units Baseline BaselineBaseline LNCFSTM I LNCFSTM ILNCFSTM I LNCFSTM ILNCFSTM I 

Baseload Avg NOx emissions (lb/106 Btu) 0.62 0.41 

(161.8 MWe avg) Avg reduction (%) 38.7 

Intermediate load Avg NOx emissions (lb/106 Btu) 0.62 0.40 

(146.6 MWe avg) Avg reduction (%) 39.2 

Peaking load Avg NOx emissions (lb/106 Btu) 0.59 0.45 

(101.8 MWe avg) Avg reduction (%) 36.1 
5-72 Program Update 2000 
Environmental Control Devices 

Environmental Control Devic

Combined SO2/NOx Control Techn
5-74 Program Update 2000 

Environmental Control Devices

Combined SO2 /NOx Control Technology

SNOXTM Flue Gas CleaningDemonstration Project Demonstration Project

Project completed. Project completed.Participant

ABB Environmental Systems

Additional Team Members

Ohio 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 designerLocation LocationLocationNiles, Trumbull County, OH (Ohio Edison’s Niles Station, Unit No. 2)TechnologyHaldor Topsoe’s SNOXTM catalytic advanced flue gascleanup system

Plant Capacity/Production

35-MWe equivalent slipstream from a 108-MWe boilerCoalOhio bituminous, 3.4% sulfur

Project Funding

Total project cost $31,438,408 100%

DOE 15,719,200 50

Participant 15,719,208 50

Project Objective

To demonstrate SNOXTM technology at an electric powerplant using U.S. high-sulfur coals in which it will catalytically remove 95% of SO2 and more than 90% of NOx

from flue gas and produce a salable by-product of concentrated sulfuric acid.

Technology/Project DescriptionIn the SNOXTM process, the stack gas leaving the boiler iscleaned of fly ash in a high-efficiency fabric filter baghouse to minimize the cleaning frequency of the sulfuricacid catalyst in the downstream SO2 converter. The ashfree gas is reheated, and NOx is reacted with small quantities of ammonia in the first of two catalytic reactors

where the NO

x is converted to harmless nitrogen and

water vapor. The SO2 is oxidized to SO3 in a second

catalytic converter. The gas then passes through a novelglass-tube condenser that allows SO3 to hydrolyze to

concentrated sulfuric acid.Because the SO2 catalyst follows the NOx catalyst, any

unreacted ammonia (slip) is oxidized in the SO2 catalyst

largely to nitrogen and water vapor. Downstream foulingby ammonia compounds is eliminated, permitting operation at higher than norma

stoichiometries allow smareduction efficiencies. The technology was desig

and more than 90% of the 

duce a salable sulfuric acThis was accomplished wout creating waste streamThe demonstration was cStation in Niles, Ohio. T35-MWe equivalent slipstMWe Unit No. 2 boiler, wcoal. The process steps wfull-scale commercial plaponents were installed an

SNOX is a trademark of Haldor Topsoe a/s.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• SO2 removal efficiency was normally in excess of 95%

for inlet concentrations, averaging about 2,000 ppm.

• NO

x reduction averaged 94% for inlet concentrations

ranging from 500–700 ppm.

• Particulate removal efficiency for the high-efficiency

fabric filter baghouse with SNOXTM system wasgreater than 99%.

• Sulfuric acid purity exceeded federal specifications for

Class I acid.

• Air toxics testing showed high capture efficiency of

most trace elements in the baghouse. A significantportion of the boron and almost all of the mercuryescaped to the stack; but selenium and cadmium,normally a problem, were effectively captured in theacid drain, as were organic compounds.

• Absence of an alkali reagent contributed to elimination of secondary pollution streams and increases in

CO2 emissions.

• Presence of the SO2 catalyst virtually eliminated CO

and hydrocarbon emissions.

Operational Operational

• Having the SO2 catalyst downstream of the NOx catalyst eliminated ammonia slip and allowed the SCR to

function more efficiently.

• Heat developed in the SNOXTM process was used to

enhance thermal efficiency.

Economic EconomicEconomic• Capital cost was estimated at $305/kW for a

500-MWe unit firing 3.2% sulfur coal. The 15-yearlevelized incremental cost was estimated at 6.1 mills/kWh, $219/ton of SO2 removed, and $198/ton of SO2and NO

x

 removed on a constant 1995 dollar basis.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

9/88

Preaward PreawardPreaward Design and Construction

Operation initiated 3/92

12/89 3/92

Cooperative agreement

awarded 12/20/89

NEPA process completed (MTF) 1/31/90

Construction completed 12/91Preoperational tests initiated 12/91

Dedication ceremony held 10/17/91Environmental monitoring plan completed 10/31/91

Design completed 8/91

Construction started 1/91

DOE selectedproject (CCT-II)9/28/88

7/96

Operation completed 12/94

Projefinal 
5-76 Program Update 2000 

Project Summary

No reagent was required for the SO2 removal step because

the SNOXTM process utilized an oxidation catalyst toconvert SO2 to SO3 and ultimately to sulfuric acid. As a

result, the process produced no other waste streams.In order to demonstrate and evaluate the performance ofthe SNOXTM process, general operating data were collected and parametric tests conducted to characterize theprocess and equipment. The system operated for approximately 8,000 hours and produced more than5,600 tons of commercial-grade sulfuric acid. Many ofthe tests for the SNOXTM system were conducted at threeloads—75, 100, and 110% of design capacity.

Environmental Performance

Particulate emissions from the process were very low (<1 mg/Nm3) due to the characteristics of the SO2 catalyst and the sulfuric acid condenser (WSA Condenser).

The Niles SNOXTM plant was fitted with a baghouse(rather than an ESP) on its inlet. This was not necessaryfor low particulate emissions, but rather was needed tomaintain an acceptable cleaning frequency for the SO2

catalyst. At operating temperature, the SO2 catalyst retained about 90% of the dust that entered the catalyst

vessel because of its sticky surface. Dust that passedthrough was subsequently removed in the WSA Condenser, which acted as a condensing particulate removaldevice (utilizing the dust particulates as nuclei).Minimal or no increase in CO2 emissions by the process

resulted from two features—the lack of a carbonate-basedalkali reagent that releases CO2, and the fact that the

process recovered additional heat from the flue gas tooffset its parasitic energy requirements. Under mostdesign conditions this heat recovery results in the net heatrate of the boiler remaining the same or increasing afteraddition of the SNOXTM process, and consequently noincrease occurs in CO2 generation.

With respect to CO and hydrocarbons, the SO2 catalyst

acted to virtually eliminate these compounds as well.This aspect also positively affected the interaction of the

NOx and SO2 catalysts. Because the SO2 catalyst followed the NOx catalyst, any unreacted ammonia (slip)

was oxidized in the SO2 catalyst to nitrogen, water vapor,

and a small amount of NOx. As a result, downstream

fouling by ammonia compounds was eliminated, and theSCR was operated at slightly higher than typical ammoniastoichiometries. These higher stoichiometries allowedsmaller SCR catalyst volumes and permitted the attainment of very high reduction efficiencies. Normal operating stoichiometries for the SCR system were in the rangeof 1.02–1.05, and system reduction efficiencies averaged94% with inlet NOx levels of approximately 500–700

ppm.Sulfur dioxide removal in the SNOXTM process wascontrolled by the efficiency of the SO2-to-SO3 oxidation,

which occurred as the flue gas passed through the oxidation catalyst beds. The efficiency was controlled by twofactors—space velocity and bed temperature. Spacevelocity governed the amount of catalyst necessary atdesign flue gas flow conditions, and gas and bed temperature had to be high enough to activate the SO2 oxidation

reaction. During the test program, SO2 removal efficiency was normally in excess of 95% for inlet concentrations averaging about 2,000 ppm.

Sulfuric acid concentration and composition have met orexceeded the requirements of the federal specificationsfor Class I acid. During the design and construction ofthe SNOXTM demonstration, arrangements were madewith a sulfuric acid supplier to purchase and distribute theacid from the plant. The acid has been sold to the agriculture industry for production of diammonium phosphate fertilizer and to the steel industry for pickling.Ohio Edison also has used a significant amount in boilerwater demineralizer systems throughout its plants.Air toxics testing conducted at the Niles SNOXTM plantmeasured the following substances:• Five major and 16 trace elements including mercury,

chromium, cadmium, lead, selenium, arsenic, beryllium, and nickel;

• Acids and correspondi

hydrogen fluoride, chlsulfate);

• Ammonia and cyanide• Elemental carbon;• Radionuclides;• Volatile organic comp• Semi-volatile compou

matic hydrocarbons; a

• Aldehydes.

The bottom portion of the Scatalyst dust collector hopp
Environmental Control Devices 

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 effectively captured in the acid drain, as were organic compounds.

Operational Performance

Heat recovery was accomplished by the SNOXTM process.In a commercial configuration, it can be utilized in thethermal cycle of the boiler. The process generated recoverable heat in several ways. All of the reactions that tookplace with respect to NOx and SO2 removal were exothermic and increased the temperature of the flue gas. This

heat, plus fuel-fired support heat added in the high-temperature SCR/SO2 catalyst loop, was recovered in the

WSA Condenser cooling air discharge for use in thefurnace 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 Performance

The economic evaluation of theSNOXTM process showed a capital costof approximately $305/kW for a 500-MWe unit firing 3.2% sulfur coal. The15-year levelized incremental cost was6.1 mills/kWh on a constant dollarbasis (1995$). The equivalent costs ofpollutant removed were $219/ton ofSO2, and $198/ton of SO2 and NOx

.

Commercial Applications

The SNOXTM technology is applicableto all electric power plants and industrial/institutional boilers firing coal, oil,or gas. The high removal efficiency forNO

x 

and SO2 makes the process attractive in many applications. Elimination The SNOXTM demonstration at Ohio Edison’s Niles Station Unit No. 2 achieved SO2 removal efficiencies exceeding 95% and NOx reduction effectiveness averaging 94%. Ohio Edison is retaining the SNOXTM technology as part of its environmental

control system.

of additional solid waste (except ash) enhances its marketability in urban and other areas where solid wastedisposal is a significant problem.The host utility, Ohio Edison, is retaining the SNOXTMtechnology as a permanent part of the pollution controlsystem at Niles Station to help Ohio Edison meet itsoverall SO2/NOx reduction goals.

Commercial SNOXTM plants also are operating in Denmark and Sicily. In Denmark, a 305-MWe plant hasoperated since August 1991. The boiler at this plantburns coals from various suppliers around the world,including the United States; the coals contain 0.5–3.0%sulfur. The plant in Sicily, operating since March 1991,has a capacity of about 30 MWe and fires petroleum coke.

Contacts ContactsContactsPaul Yosick, Project Ma

Alstom Power, Inc.1409 Center Port BoKnoxville, TN 37932(865) 694-5213 (fax)

Lawrence Saroff, DOE/James U. Watts, NETL, 

References

• Final Report Volume 

Economics. July 199

90PC89C55.

• Final Report Volume 

DOE/PC/89655-T21DE96050312.)

• A Study of Toxic Emi

Plant Utilizing the SN

Technology Demonst

Results/Special Topic

DOE/PC/93251-T3-Vtions. July 1994. (ADE94018832.)

• A Study of Toxic Emi

Plant Utilizing the SN

Technology Demonst

Final Report. Repor

Battelle Columbus Ofrom NTIS as DE940
5-78 Program Update 2000 

Environmental Control Devices

Combined SO2 /NOx Control Technology

LIMB Demonstration Project LIMB Demonstration ProjectExtension and CoolsideDemonstration

Project completed. Project completed.Participant

The Babcock & Wilcox Company

Additional Team Members

Ohio Coal Development Office—cofunderConsolidation Coal Company—cofunder and technology

supplier

Ohio Edison Company—hostLocation LocationLocationLorain, 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-NO

x burners; Consolidation

Coal Company’s Coolside duct injection of lime sorbents

Plant Capacity/Production

105 MWeCoalOhio bituminous, 1.6, 3.0, and 3.8% sulfur

Project Funding

Total project cost $19,311,033 100%DOE 7,591,655 39Participant 11,719,378 61

Project Objective

To demonstrate, with a variety of coals and sorbents, thatthe LIMB process can achieve up to 50% NOx and SO2

reductions, and to demonstrate that the Coolside processcan achieve SO2 removal of up to 70%.

Technology/Project DescriptionThe LIMB process reduces SO2 by injecting dry sorbent

into the boiler at a point above the burners. The sorbentthen travels through the boiler and is removed along withfly ash in an electrostatic precipitator (ESP) or baghouse.Humidification of the flue gas before it enters an ESP isnecessary to maintain normal ESP operation and to enhance SO2 removal. Combinations of three bituminous

coals (1.6, 3.0, and 3.8% sulfur) and four sorbents weretested. Other variables examined were stoichiometry,

humidifier outlet temperalevel in the boiler.In the Coolside process, dflue gas downstream of thgas humidification. Hummance and SO2 absorptio

by dissolving sodium hydbonate (Na2CO3) in the hu

sorbent is collected with tcess. Bituminous coal witesting.Babcock & Wilcox DRB-

control NO

x through stag

demonstrating both LIMB 

DRB-XCL is a registered trademark of the Babcock & Wilcox Company.TAG is a trademark of the Electric Power Research Institute.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Results Summary

Environmental Environmental

• LIMB SO2 removal efficiencies at a calcium-to-sulfur

(Ca/S) molar ratio of 2.0, and minimal humidificationacross the range of coal sulfur contents were 53–61%for ligno lime, 51–58% for calcitic lime, 45–52% fordolomitic lime, and 22–25% for limestone ground to80% less than 44 microns (325 mesh).

• LIMB SO2 removal efficiency increased to 32% using

limestone ground to 100% minus 325 mesh, and increased an additional 5–7% when ground to 100% lessthan 10 microns.

• LIMB SO2 removal efficiencies were enhanced by

about 10% when humidification down to 20 oF approach-to-saturation temperature was used.

• LIMB, which incorporated Babcock & Wilcox

DRB-XCL® low-NO

x burners, achieved 40–50% NOx

reduction.

• Coolside SO2 removal efficiency was 70% at a Ca/S

molar ratio of 2.0, a sodium-to-calcium (Na/Ca) ratioof 0.2, and 20 oF approach-to-saturation temperatureusing commercial hydrated lime and 2.8–3.0% sulfurcoal.

• Sorbent recycle tests demonstrated the potential to

improve sorbent utilization.

Operational 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 EconomicEconomic• 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 cosconditions were $392

• Coolside capital cost

plants ranging from 1.5–3.5% sulfur, wit

Annualized levelized conditions were $482

1986 1987 1988 1989 1990 1991 1992 1993 1994 

Preaward PreawardPreaward Design and Construction

11/92

Project completed/final report issued 

LIMB operational tests completed 8/91

NEPA process

 completed (MTF)

6/2/87

Cooperative

agreement

awarded 6/25/87

Coolside operational tests initiated 7/89

Construction completed 9/89

Ground breaking/constructionstarted 8/87

Environmental monitoring plan

completed 10/19/88

Operation and Reporting

6/87

LIMB operational testsinitiated 4/90

Coolside operational testscompleted 2/90

DOE selectedproject (CCT-I)7/24/86

7/86 7/89
5-80 Program Update 2000 

Project Summary

The initial expectation with LIMB technology was thatlimestone calcined by injection into the furnace wouldachieve adequate SO2 capture. Use of limestone in lieu of

the significantly more expensive lime would keep operating costs relatively low. However, the demonstrationshowed that, even with fine grinding of the limestone anddeep humidification, performance with limestone wasmarginal. As a result, a variety of hydrated limes wereevaluated in the LIMB configuration, demonstratingenhanced performance. Although LIMB performancewas enhanced by applying humidification to the point ofapproaching adiabatic saturation temperatures, performance did 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 dissolving

sodium hydroxide (NaOH) or sodium carbonate(Na2CO3) in the humidification water.

Environmental Performance (LIMB)

LIMB tests were conducted over a range of Ca/Smolar ratios and humidification conditions whileburning Ohio coals with nominal sulfur contents of1.6, 3.0, and 3.8% by weight. Each of four differentsorbents was injected while burning each of the threedifferent coals. Other variables examined werestoichiometry, humidifier outlet temperature, andinjection elevation level in the boiler. Exhibit 5-37summarizes SO2 removal efficiencies for the range of

sorbents and coals tested.While injecting commercial limestone with 80% ofthe particles less than 44 microns in size, removalefficiencies of about 22% were obtained at a stoichiometry of 2.0 while burning 1.6% sulfur coal. However, removal efficiencies of about 32% were achieved ata stoichiometry of 2.0 when using a limestone with asmaller particle size (i.e., all particles were less than 44

microns). A third limestone with essentially all particlesless than 10 microns was used to determine the removalefficiency limit. The removal efficiency for this very finelimestone was approximately 5–7% higher than thatobtained under similar conditions for limestone withparticles all sized less than 44 microns.During the design phase, it was expected that injection atthe 181-foot plant elevation level inside the boiler wouldpermit the introduction of the limestone at close to theoptimum furnace temperature of 2,300 oF. Testing confirmed that injection at this level, just above the nose ofthe boiler, yielded the highest SO2 removal. Injection was

also performed at the 187-foot level and similar removalswere observed. Removal efficiencies while injecting atthese levels were about 5% higher than while injectingsorbent at the 191-foot level.Removal efficiencies were enhanced by approximately10% over the range of stoichiometries tested when usinghumidification down to a 20 oF approach-to-saturation

temperature. The continu

resulted in an overall aver

lb/106 Btu, which is abou

Operational Performa

Long-term test data showavailable about 95% of thoperate. Even with minimmance was adequately enwell below the permitted the 2–5% range (limit wa

Environmental Perfor

The Coolside process waance (1.2–1.6% sulfur) ansulfur) coals. Objectives were to verify short-term velop a design performaneconomics for Coolside. molar ratio, Na/Ca molar tion temperatures—were hours) parametric tests ancess operability tests.

Water mist, sprayed into the flue gas, enhanced sulfurcapture by the sorbent by approximately 10% in the LIMBprocess when 20 °F approach-to-saturation was used.

Exhib

LIMB SO LIMB SO2 Rem

(Per

(Per

(Per

(Per

(Per

No

Sorbent Sorbent Ligno lime Commercial calcitic lime Dolomitic lime Limestone (80% <44 microns)

NT = Not testedTest conditions: injection at 181 minimal humidification.
Environmental Control Devices 

Exhibit 5-38

LIMB Capital Cost Comparison

(1992 $/kW) (1992 $/kW)

Coal (%S) Coal (%S)Coal (%S) LIMB Coolside CoolsideCoolside LSFO LIMB Coolside CoolsideCoolside LSFO

100 MWe 150 MWe

1.5 93 150 413 66 116 3122.5 95 154 421 71 122 3163.5 102 160 425 73 127 324

250 MWe 500 MWe

1.5 46 96 228 31 69 1632.5 50 101 235 36 76 1693.5 54 105 240 40 81 174

Exhibit 5-39

LIMB Annual Levelized Cost Comparison

(1992 $/T (1992 $/T(1992 $/Ton of SO on of SOon of SO2 Removed) Removed)

Coal (%S) Coal (%S)Coal (%S) LIMB Coolside CoolsideCoolside LSFO LIMB Coolside CoolsideCoolside LSFO

100 MWe 150 MWe

1.5 791 943 1418 653 797 10982.5 595 706 895 520 624 6923.5 525 629 665 461 570 527

250 MWe 500 MWe

1.5 549 704 831 480 589 6232.5 456 567 539 416 502 4113.5 419 526 413 392 482 321

The test program demonstrated that the Coolside processroutinely achieved 70% SO2 removal at design conditions

of 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

on Ca/S molar ratio, Na/Ca molar ratio, approach-toadiabatic-saturation, and the physical properties of the hydrated lime. Sorbent recycle showed significant potential to improve sorbent utilization. The observed SO2 removal with recycled sorbent alone was 22% at 0.5 available Ca/S molar ratio and 18 oF ap- proach-to-adiabatic-saturation. The observed SO2 removal with simultaneous recycle and fresh sorbent feed was 40% at 0.8 fresh Ca/S molar ratio, 0.2 fresh Na/Ca molar ratio, 0.5 available recycle, and 18 oF approach-to-adiabatic- saturation. Operational Performance (Coolside) (Coolside)(Coolside) Floor deposits experienced in the ductwork with the horizontal humidification led designers to consider a vertical unit in a com- mercial configuration. Short-term testing did not permit evaluation of Coolside system availability. Economic Performance (LIMB & Coolside) Economic comparisons were made between LIMB, Coolside, and a wet scrubber with limestone injection and forced oxidation (LSFO). Assumptions on perfor- mance were SO2 removal efficien- cies of 60, 70, and 95% for LIMB, Coolside, and LSFO, respectively. The EPRI TAGTM methods were used for the economics, which are summarized in Exhibits 5-38 and 5-39. Commercial Applica

Both LIMB and Coolsidmost utility and industrialternatives to conventioprocesses. LIMB and Cmodest capital investmerequirements are substaflue gas desulfurization LIMB has been sold to Canada. Babcock & WDLB-XCL® low-NOx bu

for 31,467 MWe of capaContacts ContactsContacts Paul Nolan, (330) 860-1

The Babcock & Wilc20 South Van Buren P.O. Box 351 Barberton, OH 4420(330) 860-2045 (fax) Lawrence Saroff, DOE/

John C. McDowell, NE

References

• T.R. Goots, M.J. DeP

onstration Project Ex

stration: Final Repo

T27. The Babcock & 1992. (Available fro

• D.C. McCoy et al. T

Demonstration: A To

PC/79798-T26. CON(Available from NTI

• Coolside and LIMB: 

tions Nearing Comp

U.S. Department of Ecox Company. Septe
5-82 Program Update 2000 

Environmental Control Devices

Combined SO2 /NOx Control Technology

SO

x

-NO

x

-Rox BoxTM Flue Gas

Cleanup Demonstration

Project Project Project

Project completed. Project completed.Participant

The Babcock & Wilcox Company

Additional Team Members

Ohio 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

Location LocationLocation

Dilles Bottom, Belmont County, OH (Ohio Edison

Company’s R.E. Burger Plant, Unit No. 5)TechnologyThe Babcock & Wilcox Company’s SOx-NOx-Rox BoxTM

(SNRBTM) process

Plant Capacity/Production

5-MWe equivalent slipstream from a 156-MWe boilerCoalBituminous coal blend, 3.7% sulfur average

Project Funding

Total project cost $13,271,620 100%DOE 6,078,402 46Participant 7,193,218 54

Project Objective

To achieve greater than 70% SO2 removal and 90% or

higher reduction in NOx emissions while maintaining

particulate emissions below 0.03 lb/106 Btu.

Technology/Project Description

The SNRBTM process combines the removal of SO2, NOx,

and particulates in one unit—a high-temperature baghouse. SO2 removal is accomplished using either calcium- or sodium-based sorbent injected into the flue gas.

The NO

x removal is accomplished by injecting ammonia

(NH3) to selectively reduce NOx in the presence of a

selective catalytic reduction (SCR) catalyst. Particulateremoval is accomplished by high-temperature fiberbag filters.

The 5-MWe SNRBTM demto demonstrate commercimizing the demonstration also permitted cost-effectperature, which allowed fover a wide range of sorboperating temperatures. Tments for potential commsimulated.

SO

x

-NO

x

-Rox Box and SNRB are trademarks of The Babcock & Wilcox

Company.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

1988 1989 1990 1991 1992 1993 1994 1995 1996 

9/88

Preaward PreawardPreaward

12/89

Design completed 8/91

DOE selectedproject (CCT-II)9/28/88

Cooperative agreementawarded 12/20/89

NEPA process completed (MTF) 9/22/89

Ground breaking/construction started 5/9/91

5/92

Design and Construction Operation and Reporting

Preoperational tests initiated 11/91

Construction completed 12/91Environmental monitoring plan completed 12/31/91

Operationinitiated 5/92 Operation completed 5/93 Project completed/fina

9/95

Results Summary

Environmental Environmental

• The SO2 removal efficiency of 80% was achieved with

commercial-grade lime at a calcium-to-sulfur (Ca/S)molar ratio of 2.0 and temperature of 800–850 oF.

• The SO2 removal efficiency of 90% was achieved with

sugar-hydrated lime and lignosulfonate-hydrated limeat a Ca/S molar ratio of 2.0 and temperature of800–850 oF.

• The SO2 removal efficiency of 80% was achieved with

sodium bicarbonate at a sodium-to-sulfur (Na2/S)

molar ratio of 1.0 and temperature of 425 oF.

• The SO2 emissions were reduced to less than 1.2 lb/

106 Btu with 3–4% sulfur coal, with a Ca/S molar ratio

as low as 1.5 and Na2/S molar ratio of 1.0.

• Injection of calcium-based sorbents directly upstream

of the baghouse at 825–900 oF resulted in higher overall SO2 removal than injection further upstream at

temperatures up to 1,200 oF.

• The NO

x

 reduction of 90% was achieved with an NH3/

NO

x molar ratio of 0.9 and temperature of 800–850 oF.

• Air toxics removal efficiency was comparable to that

of an electrostatic precipitator (ESP), except that hydrogen fluoride (HF) was reduced by 84% and hydrogen chloride (HCl) by 95%.

Operational Operational

• Calcium utilization was 40–45% for SO2 removals of

85–90%.

• Norton Company’s NC-300 zeolite SCR catalyst

showed no appreciable physical degradation or changein catalyst activity over the course of the demonstration.

• No excessive wear or failures occurred with the filter

bags tested: 3M’s Nextel ceramic fiber filter bag andOwens Corning Fiberglas’ S-Glass filter bag.

Economic EconomicEconomic• Capital cost in 1994 

was $253/kW, assumNO

x

 emissions of 1.2 

and 85% SO2 and 90

• Levelized cost over 

was $553/ton of SO2 
5-84 Program Update 2000 

The demonstration baghouse is installed on the back side ofthe power plant. Workers stand by the catalyst holder tubeprior to lifting it into the penthouse.

Project Summary

SNRBTM incorporates two successful technology development efforts that offer distinct advantages over othercontrol technologies. High-temperature filter bags andcircular monolith catalyst developments enabled multipleemission controls in a single component with a low planarea space requirement. As a postcombustion controlsystem, it is simple to operate. The high-temperature bagprovides a clean, high-temperature environment compatible with effective SCR operation, and a surface for enhanced SO2/sorbent contact (creates a sorbent cake on the

surface).

Environmental Performance

Four different sorbents were tested for SO2 capture. Calcium-based sorbents included commercial grade hydrated

lime, sugar-hydrated lime, and lignosulfonate-hydratedlime. In addition, sodium bicarbonate was tested. Theoptimal location for injecting the sorbent into the flue gaswas immediately upstream of the baghouse. Essentially,the SO2 was captured by the sorbent in the form of a filter

cake on the filter bags (along with fly ash).With the baghouse operating above 830 oF, injection ofcommercial-grade hydrated lime at Ca/S molar ratios of1.8 and above resulted in SO2 removals of over 80%. At

a Ca/S molar ratio of 2.0, sugar-hydrated lime and lignosulfonate-hydrated lime increased performance by approximately 8%, for overall removal of approximately90%. SO2 removal of 85–90% was obtained with calcium utilization in the range of 40–45%. Injection of the

calcium-based sorbents directly upstream of the baghouseat 825–900 oF resulted in higher overall SO2 removal than

injection further upstream at temperatures up to 1,200 oF.The SO2 removal using sodium bicarbonate was 80% at

an Na2/S molar ratio of 1.0 and 98% at an Na2/S molar

ratio of 2.0, at a significantly reduced baghouse temperature of 450–460 oF. SO2 emissions while burning a 3–4%

sulfur coal were reduced to less than 1.2 lb/106 Btu with a

Ca/S molar ratio as low as 1.5 and Na2/S molar ratio less

than 1.0.

To capture NOx, ammonia was injected between the sorbent injection point and the baghouse. The ammonia and

NOx reacted to form nitrogen and water in the presence of

Norton 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 achieved

with ammonia slip limited to less than 5 ppm. This performance reduced NOx em

Btu. NOx reduction was i

the catalyst design tempeCatalyst space velocity (vvolume) had a minimal ef

range evaluated. Turndown capability for t

reduction by varying the rdemonstrated for a range 

appreciable physical degractivity was observed ovegram. The degree of oxid

zeolite catalyst appeared 

dation is a concern for SCdium.) Leach potential ancompletion of the field temained nonhazardous for Particulate emissions werstandards of 0.03 lb/106 B

106 Btu, which correspon

99.89%. Hydrated lime iinlet particulate loading f

Emissions testing with aninstalled revealed no appaefficiency. On-line clean30–40 lb/in2 was sufficien

assemblies. Typically, onservice was cleaned every A comprehensive air toxiperformed at the end of thprogram. The targeted etrace metals, volatile orgaorganic compounds, aldehclides. These species wersubstances identified in thmercury speciation, dioxifeatures of this test prograefficiencies achieved for SNRBTM system were genthe conventional ESP at t
Environmental Control Devices 

Workers lower one of the mounting plate in the penbaghouse.

SNRBTM 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 SNRBTM demonstration resulted in theproduction of approximately 830 tons of fly ash and byproduct solids. An evaluation of potential uses for theby-product showed that the material might be used foragricultural liming (if pelletized). Also, the solids potentially could be used as a partial cement replacement tolower the cost of concrete.

Operational Performance

A 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 failures occurred in over 2,000 hours of elevated temperature operation.

Economic Performance

For a 150-MWe boiler fired with 3.5% sulfur coal andNO

x

 emissions of 1.2 lb/106 Btu, 65% capacity factor, and

85% SO2 and 90% NOx removal, the projected capital

cost of a SNRBTM system is approximately $253/kW(1994$), including various technology and project contingency factors. A combination of fabric filter, SCR, andwet scrubber for achieving comparable emissions controlhas been estimated at $360–400/kW. Variable operatingcosts are dominated by the cost of the SO2 sorbent for a

system designed for 85–90% SO2 removal. Fixed operating costs primarily consist of system operating labor and

projected labor and material for the hot baghouse andash-handling systems. Levelized costs over 15 years inconstant 1994 dollars are estimated at $553/ton of SO2

and NO

x

 removed.

Commercial Applications

Commercialization of the technology is expected to develop with an initial application equivalent to 50–100MWe. The focus of marketing efforts is being tailored tomatch the specific needs of potential industrial, utility,and independent power producers for both retrofit andnew plant construction. SNRBTM is a flexible technologythat can be tailored to maximize control of SO2, NOx, or

combined emissions to meet current performance requirements while providing flexibility to address future needs.Contacts ContactsContactsDot K. Johnson, (330) 829-7395

McDermott Technology1562 Beeson StreetAlliance, OH 44601(330) 829-7801 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

References

• SO

x

-NO

x

-Rox BoxTM Flue Gas Cleanup Demonstration

Final Report. Report No. DOE/PC/89656-T1. The

Babcock & Wilcox Company. September 1995.(Available from NTIS as DE96003839.)

• 5-MWe SNRBTM Demonstration Facility: Detailed

Design Report. The Babcock & Wilcox Company.

November 1992.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: SOx-NOx-Rox BoxTM Flue Gas

Cleanup Demonstration Project. The Babcock &

Wilcox Company. Report No. DOE/FE-0145. U.S.Department of Energy. November 1989. (Availablefrom NTIS as DE90004458.)
5-86 Program Update 2000 

Environmental Control Devices

Combined SO2 /NOx Control Technology

Enhancing the Use of Coalsby Gas Reburning and Sor- by Gas Reburning and Sorbent Injection

Project completed. Project completed.Participant

Energy and Environmental Research Corporation

Additional Team Members

Gas Research Institute—cofunderState of Illinois, Department of Commerce & Community

Affairs—cofunder

Illinois Power Company—hostCity Water, Light and Power—hostLocations LocationsLocationsHennepin, Putnam County, IL (Illinois Power Company’s

Hennepin Plant, Unit No. 1)

Springfield, Sangamon County, IL (City Water, Light and

Power’s Lakeside Station, Unit No. 7)

TechnologyEnergy and Environmental Research Corporation’s gasreburning and sorbent injection (GR-SI) process

Plant Capacity/Production

Hennepin: tangentially fired 80 MWe (gross), 71 MWe

(net)

Lakeside: cyclone-fired 40 MWe (gross), 33 MWe (net)CoalIllinois bituminous, 3.0% sulfur

Project Funding

Total project cost $37,588,955 100%DOE 18,747,816 50Participant 18,841,139 50

Project Objective

To demonstrate 60% NO

x reduction with gas reburning

and at least 50% SO2 removal with sorbent injection on

two different boiler configurations—tangentially firedand cyclone-fired—while burning high-sulfur midwesterncoal.Technology/Project DescriptionIn this process, 80–85% of the fuel as coal is supplied tothe main combustion zone. The remaining 15–20% ofthe fuel, provided as natural gas, bypasses the main combustion zone and is injected above the main burners toform a reducing (reburning) zone in which NOx is converted to nitrogen. A calcium compound (sorbent) is

injected in the form of dry, fine particulates above thereburning zone in the boiler. Hydrated lime (Ca(OH)2)

serves as the baseline sorbent.

This project demonstrated separate boilers representrations—a tangentially firIllinois Power Company’Illinois, and a cyclone-firCity Water, Light and PowSpringfield, Illinois. Illin3% sulfur was the test coside.A comprehensive test prothe two sites, operating thof boiler conditions. Oveachieved, enabling a subsobtained. Intensive measthe reductions in NO

x

 and 

boiler equipment and opeing costs. PromiSORB is a trademark of Energy and Environmental Research Corporation.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

Preaward PreawardPreaward Design and Construction

1986 1987 1988 1989 1990 1991 1992 1993 1994 

7/86 1/91

DOE selectedproject (CCT-I)7/24/86

7/87

Operation initiated,Lakeside 5/93

Operation completed,Hennepin 1/93

Construction completed, Hennepin 8/91

Operation initiated, Hennepin 1/91

Construction started, Lakeside 6/90

Environmental monitoring plan completed,Lakeside 11/15/89

Environmental monitoring plan

completed, Hennepin 10/15/89

NEPA process completed, Lakeside (EA) 6/25/89

Design completed, both sites 5/89

Construction started, Hennepin 5/89

NEPAprocesscompleted,Hennepin(MTF) 5/9/88

Cooperativeagreementawarded7/14/87

Construction completed, Lakeside 5/92

RestoHenn

OL

Operation and Reporting

Results Summary

Environmental Environmental

• On the tangentially fired boiler, GR-SI NOx reductions

of up to 75% were achieved, and an average 67%reduction was realized at an average gas heat input of18%.

• GR-SI SO2 removal efficiency on the tangentially fired

boiler averaged 53% with hydrated lime at a calciumto-sulfur (Ca/S) molar ratio of 1.75 (corresponding toa sorbent utilization of 24%).

• On the cyclone-fired boiler, GR-SI NOx reductions of

up to 74% were achieved, and an average 66% reduction was realized at an average gas heat input of 22%.

• GR-SI SO2 removal efficiency on the cyclone-fired

boiler averaged 58% with hydrated lime at a Ca/Smolar ratio of 1.8 (corresponding to a sorbent utilization of 24%).

• Particulate emissions were not a problem on either

unit undergoing demonstration, but humidification hadto be introduced at Hennepin to enhance ESP performance.

• Three advanced sorbents tested achieved higher SO2

capture efficiencies than the baseline Linwood hydrated lime. PromiSORBTM A achieved 53% SO2capture efficiency and 31% utilization without GR at aCa/S molar ratio of 1.75. Under the same conditions,PromiSORBTM B achieved 66% SO2 reduction and

38% utilization, and high-surface-area hydrated limeachieved 60% SO2 reduction and 34% utilization.

Operational Operational

• Boiler efficiency decreased by approximately 1% as a

result of increased moisture formed in combustionfrom natural gas use.

• There was no change 

metallurgy, or projec

Economic EconomicEconomic• Capital cost for gas r

$15/kW plus the gas (1996$).

• Operating costs for G

cost differential and 

ances (because GR rreduces SO2 emissio

• Capital cost for sorb

mately $50/kW.
5-88 Program Update 2000 

The flexible lime-sorbent disorbent splitter to the top oLakeside Station.

• Operating costs for SI were dominated by the cost of

sorbent and sorbent/ash disposal costs. SI was estimated to be competitive at $300/ton of SO2 removed.

Project Summary

The GR-SI project demonstrated the success of gas reburning and sorbent injection technologies in reducingNOx and SO2 emissions. The process design conducted

early in the project combined with the vast amount ofdata collected during the testing created a database enabling effective design for any site-specific utility orindustrial application.

Environmental Performance (Hennepin)

Following optimization testing throughout 1991, the GRSI long-term demonstration tests spanned 1992. The unitwas operated at constant loads and with the system underdispatch load following. With the system under dispatch,the load fluctuated over a wide range from 40-MWe to amaximum load of 75 MWe. Over the long-term demonstration period, the average gross power output was 62MWe.For long-term demonstration testing, the average NOx

reduction was approximately 67%. The average SO2removal efficiency was over 53% at a Ca/S molar ratio of1.75. (Linwood hydrated lime was used throughout thesetests except for a few days when Marblehead lime wasused.) CO emissions were below 50 ppm in most casesbut were higher during operation at low load.A significant reduction in CO2 was also realized. This

was due to partial replacement of coal with natural gashaving a lower carbon-to-hydrogen ratio. This cofiringwith 18% natural gas resulted in a theoretical CO2 emissions reduction of nearly 8% from the coal-fired baseline

level. With flue gas humidification, electrostatic precipitator (ESP) collection efficiencies greater than 99.8% andparticulate emissions less than 0.025 lb/106 Btu were

measured, even with an increase in inlet particulate loading resulting from sorbent injection. These levels compared favorably to baseline emissions of 0.035 lb/106 Btu

and a collection efficiency greater than 99.5%.

Following completion of the long-term tests, three specially prepared sorbents were tested. Two were manufactured by the participant and contained proprietary additives to increase their reactivity toward SO2, and were

referred to as PromiSORBTM 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/S

molar ratio, was 53% for PromiSORBTMA, 66% for

PromiSORBTM B, 60% for high-surface-area hydratedlime, and 42% for Linwood lime. At a 2.6 Ca/S molarratio, the PromiSORBTM B yielded 81% SO2 removal

efficiency.

Environmental Performance (Lakeside)

Parametric tests were conducted in three series: GRparametric tests, SI parametric tests, and GR-SI optimization tests. A total of 100 GR parametric tests were conducted at boiler loads of 33, 25, and 20 MWe. Gas heatinput varied from 5–26%. The GR parametric testsachieved a NOx reduction of approximately 60% at a gas

heat input of 22–23%. Additional flow modeling andcomputer modeling studies indicated that smaller reburning fuel jet nozzles could increase reburning fuel mixingand thus improve the NOx reduction performance.

A total of 25 SI parametric tests were conducted to isolatethe effects of sorbent on boiler performance and operability. Results showed that SO2 reduction levels varied with

load because of the effect of temperature on the sulfationreaction. At a Ca/S molar ratio of 2.0, 44% SO2 reduction was achieved at full load (33 MWe); 38% SO2 reduction was achieved at mid load (25 MWe); and 32% SO2

reduction was achieved at low load (20 MWe).In the GR-SI optimization tests, the two technologieswere integrated. Modifications were made to the reburning fuel injection nozzles based on the results of theinitial GR parametric tests and flow modeling studies.The total cross-sectional area of the reburning jets was

decreased by 32% to incrtion characteristics. The increased NOx reduction b

with the initial parametric 

reductions resulted from pnatural gas and sorbent in22% and Ca/S molar ratio 

during the long-term testiaverage SO2 reduction wa

Operational Performa

Sorbent injection increaseoperation but did not adve
Environmental Control Devices 

The natural gas injector was installed on the corner ofHennepin Station’s tangentially fired boiler.equipment performance. Gas reburning decreased boilerefficiency by approximately 1.0% because of the increasein moisture formed with combustion of natural gas. Examination 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 ESPs adequately accommodated the changes in ashloading and resistivity with the presence of sorbent in theash. No adverse conditions were found to exist. But asmentioned, humidification was added at Hennepin toachieve acceptable ESP performance with GR-SI.

Economic Performance (Hennepin/Lakeside)

Capital and operating costs depend largely onsite-specific factors, such as gas availability at the site,coal/gas cost differential, SO2 removal requirements, and

value of SO2 allowances. It was estimated that for most

installation, a 15% gas heat input will achieve 60% NOx

reduction. The capital cost for such a GR installation wasestimated at $15/kW for 100-MWe and larger plants plusthe cost of the gas pipeline (if required) (1996$). Operating costs were almost entirely related to the 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 Applications

The GR-SI process is a unique combination of two separate 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 technologies can be applied to more than 900 pre-NSPS utility boilers. The technologies also can be applied to newutility boilers. With NOx and SO2 removal exceeding

60% and 50%, respectively, these technologies have thepotential to extend the life of a boiler or power plant andalso provide a way to use higher sulfur coals.Illinois Power has retained the gas-reburning system andCity Water, Light & Power has retained the full technology for commercial use. The project was one of tworeceiving the Air and Waste Management Association’s1997 J. Deanne Sensenbaugh Award.

Contacts ContactsContactsBlair A. Folsom, Senior 

General Electric EneCorporation18 MasonIrvine, CA 92618(949) 859-3194 (fax)

Lawrence Saroff, DOE/Jerry L. Hebb, NETL, (4

References

• Enhancing the Use o

Sorbent Injection; Vo

February 1997.

• Enhancing the Use o

bent Injection: Volum

Injection at Lakeside 

Power, Springfield, I

Environmental ReseReport No. DOE/PCfrom NTIS as DE960

• Enhancing the Use o

bent Injection; Long 

1, 1991–January 15, 

79796-T40. Energy Corporation. FebruaDE95011481.)

• Enhancing the Use o

Sorbent Injection; Vo

Injection at Hennepi

Report No. DOE/PCEnvironmental Rese(Available from NTI

• Enhancing the Use o

Sorbent Injection; Vo

Injection at Edwards 

Company. Report N

Energy and EnvironmOctober 1994. (AvaiDE95009447.)
5-90 Program Update 2000 

Environmental Control Devices

Combined SO2 /NOx Control Technology

Milliken Clean Coal Milliken Clean Coal

Technology Demonstration

Project Project Project

Project completed. Project completed.Participant

New York State Electric & Gas Corporation (NYSEG)

Additional Team Members

New York State Energy Research and Development

Authority—cofunder

Empire State Electric Energy Research Corporation—

cofunder

Consolidation Coal Company—technical consultantSaarberg-Hölter-Umwelttechnik, GmbH (S-H-U)—technology supplierThe Stebbins Engineering and Manufacturing Company—technology supplierABB Air Preheater, Inc.—technology supplierLocation LocationLocationLansing, 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

(LNCFSTM) Level III; Stebbins’ tile-lined split-moduleabsorber; ABB Air Preheater’s heat-pipe air preheater;and NYSEG’s PEOA Control System.

Plant Capacity/Production

300 MWe

CoalPittsburgh, Freeport, and Kittanning Coals; 1.5, 2.9 and4.0% sulfur, respectively.

Project Funding

Total project cost $158,607,807 100%

DOE 45,000,000 28

Participant 113,607,807 72

Project Objective

To demonstrate high sulfur capture efficiency and NOx

and particulate control at minimum power requirements,zero waste water discharge, and the production of byproducts in lieu of wastes.

Technology/Project DThe formic acid enhanced remove up to 98% SO2 at The Stebbins tile-lined, spabsorber vessel provides resistance. Placement belprovides operational flexi

trolled by LNCFS IIITMlo

ized coal reburning. A hegrated to increase boiler eleakage and the air preheaTo enhance boiler efficienPlant Emission Optimizatstate-of-the-art artificial-iboiler and plant operating 

LNCFS is a trademark of ABB Combustion Engineering, Inc. PEOA is atrademark of DHR Technologies, Inc.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Preaward PreawardPreaward Operation and Reporting

9/91 10/92

DOE selectedproject (CCT-IV)9/12/91

Cooperative agreement awarded 10/20/92

Design completed 4/93Ground breaking/construction started 4/93

NEPA process completed(EA) 8/18/93

10/

Operation completed 6/98

Operation initiated on Unit 2 1/95

6/95

Design and Construction

Environmental

monitoring

plan completed

12/1/94 Construction completed 6/95

Fully integrated operation of Units 1 and 2 initiated 6/95

Results Summary

Environmental Environmental

• The maximum SO2 removal demonstrated was 98%

with all seven recycle pumps operating and usingformic acid. The maximum SO2 removal without

formic acid was 95%.

• The difference in SO2 removal between the two limestone grind sizes tested (90%–325 mesh and 90%–170

mesh) while using low-sulfur coal was an average of2.6 percentage points.

• The SO2 removal efficiency was greater than the design efficiency during the high-velocity test of the

concurrent scrubber section up to a liquid-to-gas ratio(L/G) of 110 gallons per 1,000 actual cubic feet of gas.

• At full load, LNCFSTM III lowered NOx emissions to

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

original burners)—a 39% reduction.

• During diagnostic tests, LOI was above 4% at full

boiler load. During the validation tests (when overfire

air limitations were relaxed), the LOI dropped by 0.7to 1.7 percentage points, with a minor effect on NOx

emissions.

Operational 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(WC) in the design flow tests and 0.64 inches WC inthe high-velocity tests.

• Performance of a modified ESP with wider plate spacing and reduced plate area exceeded that of the original ESPs at lower power consumption.• Boiler efficiency was 88.3–88.5% for LNCFSTM III,

compared to a baseline of 89.3–89.6%.

• Air infiltration was low for both heat pipes. Some

unaccounted for air leakage occurred at full load,ranging between 2.0–2.4%.

• The flue gas side pre

less than the design mThe primary side prewere less than the deThe secondary air sidpipes were less than inches WC.

Economic EconomicEconomic• The capital cost (199

mated at $300 /kW fcapacity factor, 3.2% removal.

• The annual operating 

(1998$); and the 15-$412/ton of SO2 rem
5-92 Program Update 2000 

Exhibit 5-40

Effect of Limestone Grind

Exh

PressuPressu

Countercu

Project Summary

The test plan was developed to cover all of the new technologies used in the project. In addition to the technologies tested, the project demonstrated that existing technologies can be used in conjunction with new processesto produce salable by-products. Supplemental monitoringhas provided operation and performance data illustratingthe success of these processes under a variety of operatingconditions. Generally, each test program was divided intofour independent subtests: diagnostic, performance, longterm, and validation. (See Micronized Coal ReburningDemonstration for NOx Control for another CCT Program

project at this unit.)

Environmental Performance

The S-H-U FGD system was tested over a 36-monthperiod. Typical evaluations included SO2 removal efficiency, power consumption, process economics, load

following capability, reagent utilization, by-product quality, and additive effects. Parametric testing included formic acid concentration, L/G ratio, mass transfer, coal sulfur content, and flue gas velocity. The maximum SO2 removal demonstrated was 98% with all seven recycle pumps operating and using formic acid, and the maxi- mum SO2 removal without formic acid was 95%. The difference in SO2 removal between the two limestone grind sizes tested (90%–325 mesh and 90%–170 mesh), while using low-sulfur coal was an average of 2.6 per- centage points, as shown in Exhibit 5-40. The SO2 re- moval efficiency was greater than the design efficiency during the high-velocity test of the cocurrent scrubber section up to a liquid-to-gas ratio of 110. The cocurrent pumps had no measurable effect on pressure drop, whereas the countercurrent pumps significantly increased the scrubber pressure drop. As seen in Exhibit 5-41, the average effect of each countercurrent header was to in- crease pressure drop by 0.45 inches water column (W.C.) in the design flow tests, and 0.64 inches W.C. in the high

velocity tests.Performance of a modifiedESP with wider plate spacing, reduced plate area, andreduced power consumption exceeded that of theoriginal ESP. The averageparticulate matter penetration before the ESP modification was 0.22% and decreased to 0.12% after themodifications.At full boiler load (145–150MWe) and 3.0–3.5% economizer O2, the LNCFSTM III

lowered NOx emissions

from a baseline of 0.64 lb/106 Btu to 0.39 lb/106 Btu

(39% reduction). At 80- to90-MWe boiler load and4.3–5.0% economizer O2

,

the LNCFSTM III lowered

NOx emissions from a ba

lb/106 Btu (29% reduction

maintained below 4% and 

Operational Performa

The S-H-U FGD system p

removal efficiency was acof producing a marketablFGD system was achievethe gypsum produced can exceeding 95% with a chHowever, the goal of prodchloride solution from the not achieved. FGD availa99.9%.
Environmental Control Devices 

The modified ESP has performed better than the originalESP at a lower power use. The total voltage currentproduct (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 modified ESP has a smaller plant footprint with fewer internalsand a smaller SCA. Total internal plate area is less thanone-half that of the original ESPs, tending to lower capital costs.Boiler efficiency was 88.3–88.5% for LNCFSTM III,compared to a baseline of 89.3–89.6%. The lower efficiency was attributed to higher post-retrofit flue gas excess O2 requirement and higher stack temperatures which

accompanied the air heater retrofit.The heat pipe was tested in accordance with ASMEPower Test Code for Air Heaters 4.3. Air infiltration waslow for both heat pipes. Unaccounted for air leakageoccurred at full load, ranging between 2.0–2.4%. Thetests showed that the flue gas side pressure loss for bothheat pipes was less than the design maximum of 3.65inches WC. The primary side pressure drops for bothheat pipes were less than the design maximum of 3.6inches WC. The secondary air side pressure drops forboth heat pipes were less than the design maximum of5.35 inches WC.

Economic Performance

The 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 Applications

The S-H-U process, Stebbins absorber module, and heatpipe air preheater are applicable to virtually all powerplants. The space-saving design features of the technologies, combined with the production of marketable byproducts, offer significant incentives to generating stations with limited space. Six modules of DHR Technologies’ PEOATM system have been sold, with an estimated value of $210,000. Contacts ContactsContacts Jim Harvilla, Project Manager, (607) 762-8630 New York State Electric & Gas Corporation Corporate Drive—Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References • Milliken Clean Coal Technology Demonstration Project: Project Performance and Economics Report, Final Report Volumes I & II. New York State Electric & Gas Corporation. October 1999. • Comprehensive Report to Congress on the Clean Coal Technology Program: Milliken Coal Technology Demonstration Project. New York State Electric & Gas Corporation. Report No. DOE/FE-0265P. U.S. Department of Energy. September 1992. (Available from NTIS as DE93001756.) • Harvilla, James et al. “Milliken Clean Coal Technol- ogy Demonstration Project.” Sixth Clean Coal Tech- nology Conference: Clean Coal for the 21st Century— What Will It Take? Volume II - Technical Papers. CONF-980410—VOL II. April 28–May 1, 1998.
5-94 Program Update 2000 

Environmental Control Devices

Combined SO2 /NOx Control Technology

Integrated Dry NOx/SO2Emissions Control System

Project completed. Project completed.Participant

Public Service Company of Colorado

Additional Team Members

Electric Power Research Institute—cofunderStone and Webster Engineering Corp.—engineerThe Babcock & Wilcox Company—burner developerFossil Energy Research Corporation—operational testerWestern Research Institute—fly ash evaluatorColorado School of Mines—bench-scale engineering

researcher and tester

NOELL, Inc.—urea injection system providerLocation LocationLocationDenver, Denver County, CO (Public Service Company ofColorado’s Arapahoe Station, Unit No. 4)TechnologyThe Babcock & Wilcox Company’s DRB-XCL® lowNO

x burners, in-duct sorbent injection, and furnace

(urea) injection

Plant Capacity/Production

100 MWeCoalColorado bituminous, 0.4% sulfurWyoming subbituminous (short test), 0.35% sulfur

Project Funding

Total project cost $26,165,306 100%DOE 13,082,653 50

Participant 13,082,653 50

Project Objective

To demonstrate the integration of five technologies toachieve up to 70% reduction in NOx and SO2 emissions;

more specifically, to assess the integration of a downfired low-NO

x burner with in-furnace urea injection for

additional NO

x removal and dry sorbent in-duct injection

with humidification for SO2 removal.

Technology/Project DescriptionAll of the testing used Babcock & Wilcox’s low-NOx

DRB-XCL® down-fired burners with overfire air. These

burners control NO

x by injecting the coal and the combustion air in an oxygen-deficient environment. Additional air is introduced via overfire air ports to complete

the combustion process and further enhance NOx removal. A urea-based selective noncatalytic reduction

(SNCR) system was testetional NO

x can be remove

Two types of dry sorbents downstream of the boiler 

calcium-based sorbent waeconomizer, or sodium-baair heater. Humidification injection was incorporate

flue gas temperature and fabric filter dust collectorThe systems were installeColorado’s Arapahoe Statdown-fired, pulverized-coburners.

DRB-XCL is a registered trademark of The Babcock & WilcoxCompany.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Environmental Control Devices 

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward PreawardPreaward Operation OperationOperation

Design and 8/92

Construction

12/89 3/91

NEPA process completed (MTF) 9/27/90

Design initiated 6/90

DOE selected project

(CCT-III) 12/19/89

Ground breaking/construction started 5/21/91

Design completed 3/92

Preoperational tests initiated 6/92

Construction completed 8/92Operation initiated 8/92

Environmental monitoring plancompleted 8/5/93

Cooperative agreement awarded 3/11/91

Results Summary

Environmental Environmental

• DRB-XCL® burners with minimum overfire air reduced NO

x emissions by more than 63% under steady

state conditions.

• With maximum overfire air (24% of total combustion

air), a NOx reduction of 62–69% was achieved across

the 50- to 110-MWe load range.

• The SNCR system, using both stationary and retractable injection lances in the furnace, provided NOx

removal of 30–50% at an ammonia (NH3) slip of

10 ppm, thus increasing performance of the total NOx

control system to greater than 80% NOx reduction.

• SO2 removal with dry calcium hydroxide injection into

the boiler economizer at approximately 1,000 oF wasless than 10%; and with injection into the fabric filterduct, SO2 removal was less than 40% at a calcium/

sulfur (Ca/S) molar ratio of 2.0.

• Sodium bicarbonate injection before the air heater

demonstrated a long-term SO2 removal of approximately 70% at a normalized stoichiometric ratio

(NSR) of 1.0.

• Sodium sesquicarbonate injection ahead of the fabric

filter achieved 70% SO2 removal at an NSR of 2.0.

• NO2 emissions were generally higher when using

sodium bicarbonate than when using sodiumsesquicarbonate.

• Integrated SNCR and dry sodium-based sorbent injection tests showed reduced NH3 and NO2 emissions.

• During four series of air toxics tests, the fabric filter

successfully removed nearly all trace metal emissionsand 80% of the mercury.

Operational Operational

• Arapahoe Unit No. 4 operated more than 34,000 hours

with the combustion modifications in place. Availability factor was over 91%.

• Control system modi

training may be nece

under load-following 

• Temperature differen

surfaces of the Adva(ARIL) initially caus12–18 inches. Alternproblem.

Economic EconomicEconomic• When used on units 

nology offers SO2 an

wet scrubber and SC

• Total capital costs fo

$125/kW to $281/kW plants, respectively. 12.43–7.03 mills/kW

NO

x removed for 30

tively.
5-96 Program Update 2000 

Public Service Company of Colorado demonstrated low-NOxburners, in-duct sorbent injection, and SNCR at ArapahoeStation near Denver, Colorado.

Project Summary

The Integrated Dry NOx/SO2 Emissions Control System

combines five major control technologies to form anintegrated system to control both NOx and SO2. The lowNOx combustion system consists of 12 Babcock & Wilcox DRB-XCL® low-NOx burners installed on the boiler

roof. The low-NO

x combustion system also incorporates

three Babcock & Wilcox dual-zone NO

x ports added to

each side of the furnace approximately 20 feet below theboiler roof. These ports inject up to 24% of the totalcombustion air through the furnace sidewalls.Additional NOx control was achieved using the ureabased SNCR system. The SNCR when used with the

low-NOx combustion system, allowed the goal of 70%

NOx reduction to be reached. Further, the SNCR system

was an important part of the integrated system, interactingsynergistically with the dry sorbent injection (DSI) systemto reduce NO2 formation and ammonia slip.

Initially, the SNCR was designed and installed to incorporate two levels of injectors with 10 injectors at each level.Levels were determined by temperature profiles thatexisted with the original combustion system. However,the retrofit low-NOx combustion system resulted in a

decrease in furnace exit gas temperature of approximately200 oF, thus moving one injector level out of the temperature regime needed for effective SNCR operation. Withonly one operational injector level, load-following performance was compromised.In order to achieve the desirable NOx reduction at low

loads, two alternatives were explored. The first approachwas to substitute ammonia for urea. It was shown thatammonia was more effective than urea at low loads. Anon-line urea-to-ammonia conversion system was installedand resulted in improved low-load performance, but theimprovement was not as large as desired for the lowestload (60 MWe). The second approach was to installinjectors in the higher temperature regions of the furnace.This was achieved by installing two NOELL ARIL lancesinto the furnace through two unused sootblower ports.Each lance was nominally 4 inches in diameter and approximately 20 feet in length with a single row of nine injection nozzles. Each injection nozzle consisted of a fixed air orifice and a replaceable liquid orifice. The ability to change orifices allowed for not only removal and cleaning but also adjustment of the injection pattern along 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 of the ARIL system was its ability to rotate, thus providing a high degree of flexibility in optimizing SNCR perfor- mance. The SO2 control system was a direct sorbent injection system that could inject either calcium- or sodium-based reagents into the flue gas upstream of the fabric filter. Sorbent was injected into three locations: (1) air heater exit where the temperature was approximately 260 oF, (2) air heater entrance where the temperature was ap- proximately 600 oF, or (3) the boiler economizer region where the flue gas temperature was approximately 1,000 oF. To improve SO2 removal with calcium hydrox- ide, a humidification system capable of achieving 20 oF approach-to-saturation was installed approximately 100 feet ahead of the fabric filter. The system designed by

Babcock & Wilcox incluinject up to 80 gal/min in

Environmental Perfor

The combined DRB-XCL

air reduced NOx emission

state conditions and with Under load-following con

about 10–25% higher. Atotal combustion air), the 

reduced NOx emissions b

(60- to 110-MWe). The 

burners were responsible 

The original design of twnozzles proved relatively injectors was in a region was too low for effective 

original design achieved 

ever, the performance decdecreased; at 60-MWe, N

11% with an ammonia sliretractable lances improvurea-based SNCR injectiothe temperature window bproved to be an importanmance. As a result, the S

removals in the range of 3

10 ppm at the fabric filter 

reduction to greater than goal of 70%.Testing of calcium hydroxwithout humidification re

range of 5–8% at a Ca/S m

removal was achieved wihydroxide and humidifica

proaching 40% at a Ca/S 20–30 oF approach-to-satwere found to be much msorbents and achieved sig

during dry injection. Sod
Environmental Control Devices 

fore the air heater demonstrated short-time SO2 removals

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 ofthe fabric filter. A disadvantage of the sodium-basedprocess was that it converted some existing NO to NO2

.

Even though 5–10% of the NOx was reduced during the

conversion process, the net NO2 exiting at the stack was

increased. 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 and

the SO2 removal technologies. The results showed that a

synergistic benefit occurred during the simultaneousoperation of the SNCR and the sodium DSI system in thatthe NH3 slip from the SNCR process suppressed the NO2

emissions associated with NO-to-NO2 oxidation by dry

sodium injection.

Operating Performance

The Arapahoe Unit No. 4 operated more than 34,000hours with the combustion modifications in place. Theavailability factor during the period was over 91%. Theoperational test objectives were met or exceeded. However, there were operational lessons learned during thedemonstration that will be useful in future deployment ofthe technologies.During the operation of the duct injection of calciumhydroxide and humidification under load-following conditions, the fabric filter pressure-drop significantly increased. This was caused by the buildup of a hard ashcake on the fabric filter bags that could not be cleanedunder normal reverse-air cleaning. The heavy ash cakewas caused by the humidification system, but it was notdetermined whether the problem was due to operation at30 oF approach-to-saturation temperature or an excursioncaused by a rapid decrease in load.The performance of the ARIL lances in NOx removal was

good; however, the location created some operationalproblems. A large differential heating pattern betweenthe top and bottom of the lance caused a significant

amount of thermal expansion along the upper surface ofthe lance. This caused the lance to bend downward approximately 12–18 inches after 30 minutes of exposure.Eventually the lances become permanently bent, thusmaking insertion and retraction difficult. The problemwas partially resolved by adding cooling slots at the endof the lance. An alternative lance design provided byDiamond Power Specialty Company (a division of Babcock & Wilcox) was tested and found to have less bending due to evaporative cooling, even though its NOx

reduction and NH3 slip performance dropped relative to

the ARIL lance.When the SNCR and dry sodium systems were operatedconcurrently, an NH3 odor problem was encountered

around the ash silo. Reducing the NH3 slip set points to

the range of 4–5 ppm reduced the ammonia concentrationin the fly ash to the 100–200 ppm range, but the odorpersisted. It was found that the problem was related tothe rapid change in pH due to the presence of sodium inthe ash. The rapid development of the high pH level andthe attendant release of the ammonia vapor appear to berelated to the wetting of the fly ash necessary to minimizefugitive dust emissions during transportation and handling. Handling ash in dry transport trucks solved thisproblem.

Economic Performance

The technology is an economical method of obtainingSO2 and NOx reduction on low-sulfur coal units. Total

estimated capital costs range from 125–281 $/kW forcapacities ranging from 300–50 MWe. Comparably, wetscrubber and SCR capital costs range from 270–474 $/kW for the same unit size range. On a levelizedcost basis, the demonstrated system costs vary from12.43–7.03 mills/kWh (1,746–987 $/ton of SO2 and NOx

removed) compared to wet scrubber and SCR levelizedcosts of 23.34–12.67 mills/kWh (4,974–2,701 $/ton ofSO2 and NOx removed) based on 0.4% sulfur coal. The

integrated system is most efficient on smaller low-sulfurcoal units. As size and sulfur content increase, the costadvantages decrease.

Commercial Applica

Either the entire Integra

trol System or the indivto most utility and induslower capital-cost alterngas desulfurization procwith modest capital invespace requirements are applied to any unit size older, small- to mid-size Contacts ContactsContactsTerry Hunt, Project Man

Utility Engineering550 15th Street, Suite 

Denver, CO 80202-4

Lawrence Saroff, DOE/Jerry L. Hebb, NETL, (4

References

• Public Service Comp

NOx/SO2 Emissions C

Volume 1: Public De

• Public Service Comp

NOx/SO2 Emissions C

Volume 2: Project Pe

September 1999.
5-98 Program Update 2000 
Advanced Electric Power Generation 

Advanced Electric Power Gener

Advanced Electric Power GenerAdvanced Electric Power Gener

Fluidized-Bed Combustion Fluidized-Bed Combustion Fluidized-Bed Combustion
5-100 Program Update 2000 Adva

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFBDemonstration Project Demonstration Project

Participant

City of Lakeland, Lakeland Electric

Additional Team Members

Foster Wheeler Corporation—supplier of pressurized

circulating fluidized-bed (PCFB) combustor and heatexchanger; engineer

Siemens Westinghouse Power Corporation—supplier of

hot gas filter, gas turbine, and steam turbine

Location LocationLocationLakeland, Polk County, FL (Lakeland Electric’s McIntosh Power Station, Unit No. 4)Technology

Foster Wheeler’s PCFB technology integrated with

Siemens Westinghouse’s hot gas particulate filter system(HGPFS) and power generation technologies

Plant Capacity/Production

137 MWe (net)

CoalEastern Kentucky and high-ash, high-sulfur bituminouscoals

Project Funding

Total project cost $186,588,000 100%DOE 93,252,864 50Participant 93,335,136 50

Project Objective

To 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, McIntosh Unit No. 4A will be constructed with a PCFB combustor adjacent to the existing Unit No. 3 (see also McIntosh Unit 4B Topped PCFB Demonstration Project).Coal and limestone are mixed and fed into the combustion chamber. Combustion takes place at a temperature ofapproximately 1,560–1,600 °F and a pressure of about200 psig. The resulting flue gas and fly ash leaving thecombustor pass through a cyclone and ceramic candletype HGPFS where the particulates are removed. The hotgas leaving the HGPFS is expanded through a SiemensV64.3 gas turbine. The gas inlet temperature of less than1,650 °F allows for a simplified turbine shaft and bladecooling system. The hot gas leaving the gas turbinepasses through a heat recovery steam generator (HRSG).

Heat recovered from both used to generate steam to Approximately 5–10% of gas turbine, with the steam the balance. The project fluidized-bed unit that can the carbonizer and will retimes of PCFB unavailaboperation.The projected net heat ratmately 9,480 Btu/kWh (Hciency greater than 36%. clude in-situ sulfur remov

than 0.3 lb/106 Btu, and p

than 0.03 lb/106 Btu. Sol

compared to conventionareadily disposable or pote
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Advanced Electric Power Generation 

1989 1992 1993 1990 1991 1994 1995 1996 1997 

12/89

DOE selected project(CCT-III) 12/19/89

Cooperative Agreementawarded 8/1/91

Design and Construction

8/91

Site change approved

(Lakeland) 10/29/96

Preaward PreawardPreaward

Cooperative Agreem

signed 12/19

NEPA process sta

Project Status/Accomplishments

The project resulted from a restructuring of the DMEC-1PCFB Demonstration Project awarded under CCT-III.On December 19, 1997, a Cooperative Agreement modification was signed implementing the project restructuring from DMEC-1 to the City of Lakeland. The LakelandCity Council gave approval in April 1998 for the 10-yearplan of Lakeland Electric (formerly Department of Electric & Water Utilities), which included this project. However, the project is on hold while technical and economicissues are resolved.Efforts have been focused on testing the HGPFS, which iscritical to system performance. Silicon carbide and alumina/mullite candle filters proved effective under conditions simulating those of the demonstration unit. At both1,550 oF and 1,400 oF, the candle filters performed forover 1,000 hours at design levels without evidence of ashbridging or structural failure. Three new oxide-basedcandle filters showed promise as well and will undergofurther testing because of the potential for reduced costand operation at higher temperatures.

Commercial Applications

The project serves to demonstrate the PCFB technologyfor widespread commercial deployment and will includethe first commercial application of hot gas particulatecleanup and will be one of the first to use a non-ruggedized gas turbine in a pressurized fluidized-bed application.The combined-cycle PCFB system permits the combustion of a wide range of coals, including high-sulfur coals,and would compete with the pressurized bubbling-bedfluidized-bed system. The PCFB technology can be usedto repower or replace conventional power plants. Because of modular construction capability, PCFB generating plants permit utilities to add economical incrementsof capacity to match load growth or to repower plantsusing existing coal- and waste-handling equipment andsteam turbines. Another advantage for repowering applications is the compactness of the equipment due to pressurized operation, which reduces space requirements perunit of energy generated.
5-102 Program Update 2000 Adva

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4B ToppedPCFB Demonstration Project PCFB Demonstration Project

Participant

City of Lakeland, Lakeland Electric

Additional Team Members

Foster Wheeler Corporation—supplier of carbonizer;

engineer

Siemens Westinghouse Power Corporation—supplier of

topping combustor and high-temperature filter

Location LocationLocation

Lakeland, Polk County, FL (Lakeland Electric’s McIntosh Power Station, Unit No. 4)

TechnologyFully integrated second-generation PCFB technologywith the addition of a carbonizer island that includesSiemens Westinghouse’s multi-annular swirl burner(MASB) topping combustor

Plant Capacity/Production

103-MWe (net) addition to the 137-MWe (net) McIntosh4A projectCoalEastern Kentucky and high-ash, high-sulfur bituminouscoals

Project Funding

Total project cost $219,635,546 100%DOE 109,608,507 50Participant 110,027,039 50

Project Objective

To demonstrate topped PCFB technology in a fully commercial power generation setting, thereby advancing thetechnology for future plants that will operate at higher gasturbine inlet temperatures and will be expected to achievecycle efficiencies in excess of 45%.

Technology/Project DescriptionThe project involves the addition of a carbonizer island tothe PCFB demonstrated in the McIntosh 4A project.Dried coal and limestone are fed via a lock hopper systemto the carbonizer with part of the gas turbine dischargeair. The coal is partially gasified at about 1,750–1,800 oFto produce syngas and char solids streams. The limestoneis used to absorb sulfur compounds generated during themild gasification process. After cooling the syngas toabout 1,200 oF, the char and limestone entrained with thesyngas are removed by a hot gas particulate filter system(HGPFS). The char and limestone are then transferred tothe PCFB combustor for complete carbon combustionand limestone utilization. The hot, cleaned, filtered syngas is then fired in the MASB topping combustor to raisethe turbine inlet temperature to approximately 2,350 °F.

The gas is expanded throurecovery steam generatornet impact of the addition crease in both power outplimestone used in McIntoin McIntosh 4A.The 240-MWe (net) plant of 8,406 Btu/kWh (40.6% SO2 capture efficiency rat

emissions are expected to 

106 Btu, respectively. In 

turbine will produce 58 Mproduce 207 MWe, while about 25 MWe.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Advanced Electric Power Generation 

1993 1996 1997 1994 1995 1998 1999 2000 2001 

5/93

DOE selected project(CCT-V) 5/4/93

Cooperative agreement awarded7/28/94; effective 8/1/94

Design and Construction

Site change approved(Lakeland) 10/29/96

Projec

8/94

Preaward PreawardPreaward

Cooperative Agreementsigned 1/29/98

NEPA processstarted 3/99

Project Status/Accomplishments

The project resulted from a restructuring of the FourRivers Energy Modernization Project awarded under thefifth solicitation. The Four Rivers project was to demonstrate the integration of a carbonizer (gasifier) and topping combustor (topping cycle) with the PCFB technology. By using a phased approach, Lakeland Electric willbe able to demonstrate both PCFB (McIntosh 4A) andtopped PCFB (McIntosh 4B) technologies at one plantsite.On January 29, 1998, a Cooperative Agreement modification was signed implementing the project restructuringfrom Four Rivers Energy Partners to the City of Lakeland.The Lakeland City Council gave approval in April 1998for the 10-year plan of Lakeland Electric (formerly Department of Electric & Water Utilities), which includedthis project. However, the project is on hold while technical and economic issues are resolved.Recent efforts focused on testing the HGPFS, which iscritical to system performance. Silicon carbide and alumina/mullite candle filters proved effective under conditions simulating those of the demonstration unit. At both 1,550 oF and 1,400 oF, the candle filters performed for over 1,000 hours at design levels without evidence of ash bridging or structural failure. Three new oxide-based candle filters showed promise as well. These will un- dergo further testing because of the potential for reduced cost and operation at higher temperatures. Commercial Applications The commercial version of the topped PCFB technology will have a greenfield net plant efficiency of 45% (which equates to a heat rate approaching 7,500 Btu/kWh, HHV). In addition to higher plant efficiencies, the plant will (1) have a cost of electricity that is projected to be 20% lower than that of a conventional pulverized coal- fired plant with flue gas desulfurization, (2) meet emis- sion limits allowed by the New Source Performance Standard (NSPS), (3) operate economically on a wide range of coals, and (4) be amenable to shop fabrication. The benefits of improved efficiency include reduced cost for fuels and a reduction in CO2 emissions. The commercial version 

has other environmental 

sulfur retention that can NOx emissions that will 

ticulate matter discharge 

Btu. Although the systein solid waste compared material is a dry, readily able material.
5-104 Program Update 2000 Adva

Advanced Electric Power Generation

Fluidized-Bed Combustion

JEA Large-Scale CFB Com- JEA Large-Scale CFB Combustion Demonstration

Project Project Project

Participant

JEA (formerly Jacksonville Electric Authority)

Additional Team Member

Foster Wheeler Energy Corporation—technology supplierLocation LocationLocationJacksonville, Duval County, FL (JEA’s Northside Station, Unit No. 2)TechnologyFoster Wheeler’s atmospheric circulating fluidized-bed(ACFB) combustor

Plant Capacity/Production

297.5 MWe (gross), 265 MWe (net)CoalEastern bituminous, 0.3.39% sulfur (design)

Project Funding

Total project cost $309,096,512 100%DOE 74,733,833 24Participant 234,362,679 76

Project Objective

To demonstrate ACFB at 297.5 MWe gross (265 MWenet) representing a scaleup from previously constructedfacilities; to verify expectations of the technology’s economic, environmental, and technical performance; toprovide potential users with the data necessary for evaluating a large-scale ACFB as a commercial alternative; toaccomplish greater than 90% SO2 removal; and to reduce

NO

x emissions by 60% when compared with conventional technology.

Technology/Project DescriptionA circulating fluidized-bed combustor, operating at atmospheric pressure, will be retrofitted into Unit No. 2 of theNorthside 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 reducedin size, the coal, along with some of the sorbent, is carried out of the combustor, collected in a cyclone separator, and recycled to the lower portion of the combustor.Primary sulfur capture is achieved by the sorbent in thebed. However, additional SO2 capture is achieved

through the use of a polishing scrubber to be installedahead of the particulate control equipment.

Steam is generated in tubwalls and superheated in of the particulate separatoThe system will produce 

main steam at about 2,50106 lb/hr of reheat steam a

steam will be used in an esteam turbine.The heat rate for the retroproximately 9,950 Btu/kWExpected environmental p

for SO2 (98% reduction), 

0.011 lb/106 Btu for total 

for PM10).

INTREX is a trademark of Foster Wheeler Energy Corp.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Advanced Electric Power Generation 

EnvircompPreo

1989 1990 1992 1993 1995 1997 1999 2000 2001 

Preaward PreawardPreaward

6/89

11/90

DOE selectedproject (CCT-I)6/23/89

** **

Cooperative agreementawarded 11/30/90

Project restructured 6/92

Project sited

(York) 6/93

Project restructured and resited

(Jacksonville) 8/26/97

** **

Design and Construction

NEPA process completed

(EIS York site) 8/11/95

Cooperative agreement modified 9/29/97

Project co

Pre-construction

started

8/99

NEPA process completed (EIS Jacksonville site);

Design completed;

construction started 12/00*

Project Status/Accomplishments

The project was successfully resited to Jacksonville,Florida after York County Energy Partners and Metropolitan Edison Company terminated activities on the ACFBproject in September 1996. On August 26, 1997, DOEapproved the transfer of the ACFB Clean Coal Projectfrom York, Pennsylvania to Jacksonville, Florida. OnSeptember 29, 1997, DOE signed a modified cooperativeagreement with JEA to cost-share refurbishment of thefirst (Unit No. 2) of two units at Northside GeneratingStation.The Environmental Impact Statement (EIS) process wasinitiated on December 3, 1997 with the Public ScopingMeeting. Following the NEPA process of public comment and review, the final draft EIS was prepared andapproved by DOE. After incorporating comments andobtaining formal approval, the EIS was issued on June30, 2000. Public comments were addressed and theRecord of Decision was issued December 7, 2000.

The project, currently in construction, moves atmosphericfluidized-bed combustion technology to the larger sizesof utility boilers typically considered in capacity additionsand replacements. The nominal 300-MWe demonstrationunit in the JEA project will be more than double the sizeof the Nucla unit (110-MWe). Features include an integrated recycle heat exchanger (INTREXTM) in the furnace, steam-cooled cyclones, a parallel pass reheat control, an SO2 polishing scrubber, and a fabric filter for

particulate control.

Commercial Applications

ACFB technology has good potential for application inboth the industrial and utility sectors, whether for use inrepowering existing plants or in new facilities. ACFB isattractive for both baseload and dispatchable power applications because it can be efficiently turned down to 25%of full load. Coal of any sulfur or ash content can beused, and any type or size unit can be repowered. Inrepowering applications, an existing plant area is used,and coal- and waste-handling equipment, as well as steam

turbine equipment are reof the plant.In its commercial configseveral potential benefittional pulverized coal-fireduced SO2 and NOx em

combustion efficiency; (including use of renewby-product material that salable.
5-106 Program Update 2000 Adva

Advanced Electric Power Generation

Fluidized-Bed Combustion

Tidd PFBC DemonstrationProject Project Project

Project completed. Project completed.Participant

The Ohio Power Company

Additional Team Members

American Electric Power Service Corporation—

designer, constructor, and manager

The Babcock & Wilcox Company—technology supplierOhio Coal Development Office—cofunderLocation LocationLocationBrilliant, Jefferson County, Ohio (Ohio PowerCompany’s Tidd Plant, Unit No. 1)TechnologyThe Babcock & Wilcox Company’s pressurized fluidized-bed combustion (PFBC) system (under license fromABB Carbon)

Plant Capacity/Production

70 MWe (net)CoalOhio bituminous, 2–4% sulfur

Project Funding

Total project cost $189,886,339 100%

DOE 66,956,993 35Participant 122,929,346 65

Project Objective

To verify expectations of PFBC economic, environmental, and technical performance in a combined-cyclerepowering application at utility scale; and to accomplishgreater than 90% SO2 removal and NOx emission level of

0.2 lb/106 Btu at full load.

Technology/Project DescriptionTidd was the first large-scale operational demonstrationof PFBC in the United States. The project represented a13:1 scaleup from the pilot facility.The boiler, cyclones, bed reinjection vessels, and associated hardware were encapsulated in a pressure vessel 45feet in diameter and 70 feet high. The facility was designed so that one-seventh of the hot gases producedcould be routed to an advanced particulate filter (APF).The Tidd facility used a bubbling fluidized-bed combustion process operating at 12 atm (175 psi). Pressurizedcombustion air is supplied by the turbine compressor tofluidize the bed material, which consists of a coal-waterfuel paste, coal ash, and a dolomite or limestone sorbent.Dolomite or limestone in the bed reacts with sulfur toform calcium sulfate, a dry, granular bed-ash material,

which is easily disposed oA low bed temperature of 

formation.The hot combustion gasetrained ash particles, 98% gases pass through cyclonexpanded through a 15-Mgases exiting the turbine, bundle in the fluid bed, ging 55-MWe steam turbin
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Advanced Electric Power Generation 

1986 1987 1988 1989 1990 1991 1992 1993 1994 

Design and Construction Operation and Reporting

3/87

Cooperative agreement awarded 3/20/87NEPA process completed (MTF) 3/5/87

Environmental monitoringplan completed 5/25/88

Ground breaking ceremony 4/6/88

Construction started 12/9/87

Operation initiated 3/91

Design completed 12/90Construction completed 12/90Preoperational tests started 12/90

3/91

DOE selected project (CCT-I) 7/24/86

7/86

Preaward PreawardPreaward

Results Summary

Environmental Environmental

• Sorbent size had the greatest effect on SO2 removal

efficiency as well as stabilization and heat transfercharacteristics of the fluidized-bed.

• SO2 removal efficiency of 90% was achieved at full

load with a calcium-to-sulfur (Ca/S) molar ratio of1.14 and temperature of 1,580 oF.

• SO2 removal efficiency of 95% was achieved at full

load with a Ca/S molar ratio of 1.5 and temperature of1,580 oF.

• NO

x

 emissions were 0.15–0.33 lb/106 Btu.

• CO emissions were less than 0.01 lb/106 Btu.

• Particulate emissions were less than 0.02 lb/106 Btu.

Operational Operational

• Combustion efficiency ranged from an average 99.3%

at low bed levels to an average 99.5% at moderate tofull bed levels.

• Heat rate was 10,280 Btu/kWh (HHV, gross output)

(33.2% efficiency) because the unit was small and noattempt was made to optimize heat recovery.

• An advanced particulate filter (APF), using a silicon

carbide candle filter array, achieved 99.99% filtrationefficiency on a mass basis.

• PFBC boiler demonstrated commercial readiness.• ASEA Stal GT-35P gas turbine proved capable of

operating commercially in a PFBC flue gasenvironment.

Economic EconomicEconomic• The Tidd plant was a 

and as such, detailed part of this project.

• A recent cost estimat

PFBC Karita Plant p$1,263/kW (1997$).
5-108 Program Update 2000 Adva

The PFBC demonstration aOhio Power’s Tidd Plant leunderstanding of the techn

Project Summary

The Tidd PFBC technology is a bubbling fluidized-bedcombustion process operating at 12 atmospheres(175 psi). Fluidized-bed combustion is inherently efficient because the pressurized environment enhancescombustion efficiency, allows very low temperatures thatmitigate thermal NOx generation, promotes flue gas/

sorbent reactions that increase sorbent utilization, andproduces flue gas energy that is used to drive a gas turbine. The latter contributed significantly to system efficiency because of the high efficiency of gas turbines andthe availability of gas turbine exhaust heat that can beapplied to the steam cycle. A bed design temperature of1,580 oF was established because it was the maximumallowable temperature at the gas turbine inlet and waswell below temperatures for coal ash fusion, thermal NOx

formation, and alkali vaporization.Coal crushed to one-quarter inch or less was injected intothe combustor as a coal/water paste containing 25% waterby weight. Crushed sorbent, either dolomite or limestone, was injected into the fluidized bed via two pneumatic feed lines, supplied from two lock hoppers. Thesorbent feed system initially used two injector nozzles butwas modified to add two more nozzles to enhance distribution.In 1992, a 10-MWe equivalent APF was installed andcommissioned as part of a research and developmentprogram and not part of the CCT Program demonstration.This system used ceramic candle filters to clean oneseventh of the exhaust gases from the PFBC system. Thehot gas cleanup system unit replaced one of the sevensecondary cyclones.The Tidd PFBC demonstration plant accumulated 11,444hours of coal-fired operations during its 54 months ofoperation. The unit completed 95 parametric tests, including continuous coal-fired runs of 28, 29, 30, 31, and45 days. Ohio bituminous coals having sulfur contents of2–4% were used in the demonstration.

Environmental Performance

Testing showed that 90% SO2 capture was achievable

with a Ca/S molar ratio of 1.14 and that 95% SO2 capture

was possible with a Ca/S molar ratio of 1.5, provided thesize gradation of the sorbent being utilized was optimized. This sulfur retention was achieved at a bed temperature of 1,580 oF and full bed height. Limestone induced deterioration of the fluidized-bed, and as a result,testing focused on dolomite. The testing showed thatsulfur capture as well as sintering was sensitive to thefineness of the dolomite sorbent (Plum Run Greenfielddolomite was the design sorbent). Sintering of fluidizedbed materials, a fusing of the materials rather than effective reaction, had become a serious problem that requiredoperation at bed temperatures below the optimum foreffective boiler operation. Tests were conducted withsorbent size reduced from minus 6 mesh to a minus 12mesh. The result with the finer material was a majorpositive impact on process performance without the expected excessive elutriation of sorbent. The finer materialincreased the fluidization activity as evidenced by a 10%improvement in heat transfer rate and an approximately30% increase in sorbent utilization. In addition, the process was much more stable as indicated by reductions intemperature variations in both the bed and the evaporatortubes. Furthermore, sintering was effectively eliminated.NO

x emissions ranged from 0.15–0.33 lb/106 Btu, but

were typically 0.2 lb/106 Btu during the demonstration.

These emissions were inherent in the process, which wasoperating at approximately 1,580 oF. No NOx control

enhancements, such as ammonia injection, were required.Emissions of carbon monoxide and particulates were lessthan 0.01 and 0.02 lb/106 Btu, respectively.

Operational Performance

Except for localized erosion of the in-bed tube bundleand the more general erosion of the water walls, the Tiddboiler performed extremely well and was considered acommercially viable design. The in-bed tube bundleexperienced no widespread erosion that would requiresignificant maintenance. While the tube bundle experienced little wear, a signif

of the four water walls wno problem, however, beccritical to heat transfer anrefractory. The prototype gas turbine lems and was the leading during the first 3 years of changes instituted over thproved effective in addredemonstration showed tha PFBC flue gas environmEfficiency of the PFBC clated during testing from in cyclone and bed ash, tothe amount of carbon motion efficiencies averaged heights, surpassing the de99.0%.
Advanced Electric Power Generation 

Coal and sorbent conveyors can be seen just after enteringthe Tidd plant.

Using data for typical full-load operation, a heat rate of10,280 Btu/kWh (HHV basis) was calculated. This corresponds to a cycle thermodynamic efficiency of 33.2% at apoint where the cycle produced 70-MWe of gross electrical power while burning Pittsburgh No. 8 coal. Becausethe Tidd plant was a repowering application at a comparatively small scale, the measured efficiency does not represent what would be expected for a larger utility-scaleplant using Tidd technology. Studies conducted under thePFBC Utility Demonstration Project showed that efficiencies of over 40% are likely for a larger, utility-scale PFBCplant.In summary, the Tidd project showed that the PFBC system could be applied to electric power generation. Further, the demonstration project led to significant refinements and understanding of the technology in the areas ofturbine design, sorbent utilization, sintering, post-bedcombustion, 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 theparticulate matter; and filtration efficiency (mass basis)was 99.99%.

Economic Performance

The Tidd plant was a relatively small-scale demonstrationfacility, so detailed economics were not prepared as partof this project. However, a recent cost estimate performed on Japan’s 360-MWe PFBC Karita Plant projected a capital cost of $1,263/kW (1997$).

Commercial Applications

Combined-cycle PFBC permits use of a wide range ofcoals, including high-sulfur coals. The compactness ofbubbling-bed PFBC equipment allows utilities to significantly increase capacity at existing sites. Compactnessdue to pressurized operation reduces space requirements

per unit of energy generated. PFBC technology appearsto be best suited for applications of 50 MWe or larger.Capable of being constructed modularly, PFBC generating plants permit utilities to add increments of capacityeconomically to match load growth. Plant life can beextended by repowering with PFBC using the existingplant area, coal- and waste-handling equipment, andsteam turbine 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 considerationin China, South Korea, the United Kingdom, Italy, andIsrael.The Tidd project received Power magazine’s 1991

Powerplant Award. In 1992, the project received theNational Energy Resource Organization award for demonstrating energy efficient technology.

Contacts ContactsContactsMichael J. Mudd, (614) 

American Electric Po1 Riverside PlazaColumbus, OH 4321(614) 223-2027 (fax)

George Lynch, DOE/HQDonald W. Geiling, NET

References

• Tidd PFBC Hot Gas 

Report No. DOE/MCCompany. October 1DE96000650.)

• Tidd PFBC Demonst

Including Fourth Yea

Company. August 1brary/Morgantown, 1DE96000623.)

• Tidd PFBC Demonst

March 1, 1994–Marc

MC/24132-T8. The 1995. (Available fro

• Tidd PFBC Demonst

of Operation. Repor

1 and 2. The Ohio P(Available from NTIDE96003781 for Vol
5-110 Program Update 2000 Adva

Advanced Electric Power Generation

Fluidized-Bed Combustion

Nucla CFB Demonstration

Project Project Project

Project completed. Project completed.Participant

Tri-State Generation and Transmission Association, Inc.

Additional Team Members

Foster Wheeler Energy Corporation*—technology

supplier

Technical Advisory Group (potential users)—cofunderElectric Power Research Institute—technical consultantLocation LocationLocationNucla, Montrose County, CO (Nucla Station)TechnologyFoster Wheeler’s atmospheric circulating fluidized-bed(ACFB) combustion system

Plant Capacity/Production

110 MWe (gross), 100 MWe (net)CoalWestern bituminous—

Salt Creek, 0.5% sulfur, 17% ashPeabody, 0.7% sulfur, 18% ashDorchester, 1.5% sulfur, 23% ash

Project Funding

Total project cost $160,049,949 100%

DOE 17,130,411 11Participant 142,919,538 89

Project Objective

To demonstrate the feasibility of ACFB technology atutility scale and to evaluate the economic, environmental,and operational performance at that scale.

Technology/Project DescriptionNucla’s circulating fluidized-bed system operates at atmospheric pressure. In the combustion chamber, a streamof air fluidizes and entrains a bed of coal, coal ash, andsorbent (e.g., limestone). Relatively low combustion

temperatures limit NOx formation. Calcium in the sorbent combines with SO2 gas to form calcium sulfite and

sulfate solids, and solids exit the combustion chamberand flow into a hot cyclone. The cyclone separates thesolids from the gases, and the solids are recycled forcombustor temperature control. Continuous circulation ofcoal and sorbent improves mixing and extends the contacttime of solids and gases, thus promoting high utilizationof the coal and high sulfur-capture efficiency. Heat in theflue gas exiting the hot cyclone is recovered in the economizer. Flue gas passes through a baghouse where particulate matter is removed. S

used to produce electric pThree small, coal-fired, sttion were replaced with a generator capable of drivibine generator. Extractioerator powers three existiMWe [gross] each).

*Pyropower Corporation, the original technology developer and supplier,was acquired by Foster Wheeler Energy Corp.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Advanced Electric Power Generation 

1987 1988 1989 1990 1991 1992 1993 1994 1995 

Preaward PreawardPreaward Operation and Reporting

10/87 10/88

DOE selectedproject (CCT-I)10/7/87

Environmental monitoringplan completed 2/27/88

NEPA process completed (MTF) 4/18/88

Operationcompleted 1/91

Operation test program initiated 8/88

Cooperative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92

Results Summary

Environmental Environmental

• Bed temperature had the greatest effect on pollutant

emissions and boiler efficiency.

• At bed temperatures below 1,620 oF, sulfur capture

efficiencies of 70% and 95% were achieved at calcium- to-sulfur (Ca/S) molar ratios of 1.5 and 4.0,respectively.

• During all tests, NOx emissions averaged 0.18 lb/106

Btu and did not exceed 0.34 lb/106 Btu.

• CO emissions ranged from 70–140 ppmv.• Particulate emissions ranged from 0.0072–0.0125

lb/106 Btu, corresponding to a removal efficiency

of 99.9%.

• Solid waste was essentially benign and showed potential as an agricultural soil amendment, soil/roadbed

stabilizer, or landfill cap.

Operational Operational

• Boiler efficiency ranged from 85.6–88.6% and combustion efficiency ranged from 96.9–98.9%.• A 3:1 boiler turndown capability was demonstrated.• Heat rate at full load was 11,600 Btu/kWh and was

12,400 Btu/kWh at half load.

Economic EconomicEconomic• Capital cost for the Nucla retrofit was $1,123/kW and

normalized power production cost was 64 mills/kWh.
5-112 Program Update 2000 Adva

Exh

 Effect of B

on Ca/S on Ca/S 

Plant layout with coal and limestone feed locations. Project Summary

Fluidized-bed combustion evolved from efforts to find acombustion process conducive to controlling pollutantemissions without external controls. Fluidized-bed combustion enables efficient combustion at temperatures of1,400–1,700 oF, well below the thermal NOx formationtemperature (2,500 oF), and enables high SO2-capture

efficiency through effective sorbent/flue gas contact.ACFB differs from the more traditional fluid-bed combustion. Rather than submerging a heat exchanger in thefluid bed, which dictates a low fluidization velocity,ACFB uses a relatively high fluidization velocity, whichentrains the bed material. Hot cyclones capture and return the solids emerging from the turbulent bed to controltemperature, extend the gas/solid contact time, and protect a downstream heat exchanger.Interest and participation of DOE, EPRI, and the Technical Advisory Group (potential users) resulted in the evaluation of ACFB potential for broad utility applicationthrough a comprehensive test program. Over a two-anda-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 Performance

Between July 1988 and January 1991, the plant operatedwith an average availability of 58% and an average capacity factor of 40%. However, toward the end of the demonstration, most of the technical problems had been overcome. During the last three months of the demonstration,average availability was 97% and the capacity factor was66.5%.Over the range of operating temperature at which testingwas performed, bed temperature was found to be the mostinfluential operating parameter. With the exception ofcoal-fired configuration and excess air at elevated temperatures, bed temperature was the only parameter thathad a measurable impact on emissions and efficiency.

Combustion efficiency, a measure of the quantity of carbon that is fully oxidized to CO2, ranged from

96.9–98.9%. Of the four exit sources of incompletelyburned carbon, the largest was carbon contained in the flyash (93%). The next largest (5%) was carbon containedin the bottom ash stream, and the remaining feed-carbonloss (2%) was incompletely oxidized CO in the flue gas.The fourth possible source, hydrocarbons in the flue gas,was measured and found to be negligible.Boiler efficiencies for 68 performance tests varied from85.6–88.6%. The contributions to boiler heat loss wereidentified as unburned carbon, sensible heat in dry fluegas, fuel and sorbent moisture, latent heat in burninghydrogen, sorbent calcination, radiation and convection,and bottom-ash cooling water. Net plant heat rate decreased with increasing boiler load, from 12,400 Btu/kWh at 50% of full load to 11,600 Btu/kWh at full load.The lowest value achieved during a full-load steady-state

test was 10,980 Btu/kWhthe absence of reheat, the 12.5-MWe turbines in the of unit restarts, and part-l

Environmental Perfor

As indicated above, bed timpact on ACFB performsions. Exhibit 5-42 showon the Ca/S molar ratio retion. The Ca/S molar raticalcium content of the sofor the calcium content of ratio of about 1.5 was sufretention in the 1,500–1,6ratio requirement jumped greater.Exhibit 5-43 shows the efsulfur retention at average 1,620 oF. Salt Creek and 
Advanced Electric Power Generation 

Exhibit 5-43

Calcium Requirements and

Sulfur Retentions for Various Fuels

0.7% sulfur, respectively. To achieve 70% SO2 reduction,

or the 0.4 lb/106 Btu emission rate required by the licensing agreement, a Ca/S molar ratio of approximately 1.5 is

required. To achieve an SO2 reduction of 95%, a Ca/S

molar ratio of approximately 4.0 is necessary. Dorchestercoal, averaging 1.5% sulfur content, required a somewhatlower Ca/S molar ratio for a given reduction.NOx emissions measured throughout the demonstration

were less than 0.34 lb/106 Btu, which is well below the

regulated value of 0.5 lb/106 Btu. The average level of

NOx emissions for all tests was 0.18 lb/106 Btu. NOx

emissions indicate a relatively strong correlation withtemperature, increasing from 40 ppmv (0.06 lb/106 Btu) at

1,425 oF to 240 ppmv (0.34 lb/106 Btu) at 1,700 °F.

Limestone feed rate was also identified as a variableaffecting NOx emissions, i.e., somewhat higher NOx

emissions resulted from increasing calcium-to-nitrogen(Ca/N) molar ratios. The mechanism was believed to beoxidation of volatile nitrogen in the form of ammonia(NH3) catalyzed by calcium oxide. CO emissions decreased as temperature increased, from 140 ppmv at

1,425 oF to 70 ppmv at 1,700 oF.

At full load, the hot cyclones removed 99.8%of the particulates. With the addition ofbaghouses, removal efficiencies achieved onPeabody and Salt Creek coals were 99.905%and 99.959%, respectively. This equated toemission levels of 0.0125 lb/106 Btu for

Peabody coal and 0.0072 lb/106 Btu for Salt

Creek coal, well below the required 0.03 lb/106 Btu.

Economic Performance

The 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).The total power cost associated with plantoperations between September 1988 andJanuary 1991 was approximately $54.7 million, resulting in a normalized cost of powerproduction of 64 mills/kWh. The average

monthly operating cost over this period was about$1,888,000. Fixed costs represent about 62% of the totaland include interest (47%), taxes (4.8%), depreciation(6.9%), and insurance (2.7%). Variable costs representmore than 38% of the power production costs and includefuel expenses (26.2%), non-fuel expenses (6.8%), andmaintenance expenses (5.5%).

Commercial Applications

The 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 databaseresulting from the Nucla project enabled the resultanttechnology to be replicated in numerous commercialplants throughout the world. Nucla continues in commercial service.Today, every major boiler manufacturer offers an ACFBsystem in its product line. There are now more than 170fluidized-bed combustion boilers of varying capacityoperating in the U.S. and the technology has made significant market penetrat

and ease of operation mpower generation option in developing countriesContacts ContactsContacts Stuart Bush, (303) 452-

Tri-State Generation P.O. Box 33695 Denver, CO 80233 (303) 254-6066 (fax) George Lynch, DOE/HQ

Thomas Sarkus, NETL, 

References

• Colorado-Ute Nucla 

Bed (CFB) Demonst

Results. EPRI Repor

• Demonstration Prog

Reports. Report No. 

Ute Electric Associafrom NTIS as DE920

• Economic Evaluation 

No. DOE/MC/25137Association, Inc., Mas DE93000212.)

• Nucla CFB Demonst

Design Report. Rep

Colorado-Ute Electri1990. (Available from 
5-114 Program Update 2000 Adva
Advanced Electric Power Generation 

Advanced Electric Power Gener

Advanced Electric Power GenerAdvanced Electric Power Gener

Integrated Gasification Combined

Integrated Gasification CombinedIntegrated Gasification Combined
5-116 Program Update 2000 Adva

Advanced Electric Power Generation

Integrated Gasification Combined-Cycle

Kentucky Pioneer EnergyIGCC Demonstration Project IGCC Demonstration Project

Participant

Kentucky Pioneer Energy, LLC

Additional Team Members

Fuel Cell Energy, Inc. (formerly Energy Research Corporation)—molten carbonate fuel cell designer and supplier, and cofunderLocation LocationLocationTrapp, 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’smolten carbonate fuel cell (MCFC)

Plant Capacity/Production

580 (gross); 540 MWe (net) IGCC; 2.0 MWe MCFCCoalHigh-sulfur Kentucky bituminous coal and pelletizedrefuse-derived fuel (RDF)

Project Funding

Total project cost $431,932,714 100%DOE 78,086,357 18Participant 353,846,225 82

Project Objective

To demonstrate and assess the reliability, availability, andmaintainability of a utility-scale IGCC system using ahigh-sulfur bituminous coal and municipal solid wasteblend in an oxygen-blown, fixed-bed, slagging gasifierand the operability of a molten carbonate fuel cell fueledby 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 andother sulfur compounds are removed. Elemental sulfur isreclaimed and sold as a by-product. Tars, oils, and dustare recycled to the gasifier. The resulting clean, mediumBtu fuel gas fires two gas turbines. A small portion ofthe clean fuel gas is used for the 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-enriched

air is fed into the cathodedirect electric current, whcurrent with an inverter.Operation will commence increasing levels of RDF This method will allow thplant performance at vari
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Calendar Year

Advanced Electric Power Generation 

1992 1998 1999 1993 1994 2000 2001 2002 2003 

Preaward PreawardPreaward

5/93

DOE selected project

(CCT-V) 5/4/93

Cooperative Agreement

awarded 12/2/94

Design and Construction

12/94 1

Operation initiated 1

p

**

Novation of cooperativeagreement; New siteapproved 11/99 New site approved 5/98

NEPA process completed;construction started 3/02*

Site withdrawn

4/99

EIS processinitiated 5/00

Project Status/Accomplishments

On 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 specificbusiness and teaming milestones. The new project site tobe provided by Ameren was at its Venice Station Plant inVenice, Illinois. On April 30, 1999, Ameren ServicesCompany withdrew from the project for economic andbusiness reasons.In May 1999, Global Energy USA Limited (Global), soleowner of Kentucky Pioneer Energy, LLC (KPE), expressed interest in acquiring the project and providing ahost site at East Kentucky Power Cooperative’s SmithSite in Clark County, Kentucky. Subsequently, Globalnegotiated all the necessary documents with DOE andClean Energy Partners, L.P. (CEP) to acquire the project.In November 1999, the cooperative agreement was novated and the new site was approved.The NEPA process was initiated with the public scopingmeeting on May 4, 2000.

Commercial Applications

The 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 projected 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). Thecommercial version of the molten carbonate fuel cellfueled by a BGL gasifier is anticipated to have a heat rateof 7,379 Btu/kWh (46.2% efficiency). These efficienciesrepresent a greater than 20% reduction in emissions of

CO2 when compared wi

plant equipped with a scIGCC system are expec

(99% reduction); and N

Btu (90% reduction).Also, the slagging charanonleaching, glass-like usable by-product.
5-118 Program Update 2000 Adva

Advanced Electric Power Generation

Integrated Gasification Combined-Cycle

Piñon Pine IGCC Power Piñon Pine IGCC Power

Project Project Project

Participant

Sierra Pacific Power Company

Additional Team Members

Foster Wheeler USA Corporation—architect, engineer,

and constructor

The M.W. Kellogg Company—technology supplierBechtel Corporation—start-up engineerLocation LocationLocationReno, Storey County, NV (Sierra Pacific PowerCompany’s Tracy Station)TechnologyIntegrated gasification combined-cycle (IGCC) using theKRW air-blown pressurized fluidized-bed coal gasification system

Plant Capacity/Production

107 MWe (gross), 99 MWe (net)CoalSouthern Utah bituminous, 0.5–0.9% sulfur (designcoal); Eastern bituminous, 2–3% sulfur (planned test)

Project Funding

Total project cost $335,913,000 100%

DOE 167,956,500 50Participant 167,956,500 50

Project Objective

To demonstrate air-blown pressurized fluidized-bedIGCC technology incorporating hot gas cleanup (HGCU);to evaluate a low-Btu gas combustion turbine; and toassess long-term reliability, availability, maintainability,and environmental performance at a scale sufficient todetermine commercial potential.

Technology/Project DescriptionDried and crushed coal and limestone are introduced intoa KRW air-blown pressurized fluidized-bed gasifier.Crushed limestone is used to capture a portion of thesulfur. The sulfur reacts with the limestone to form calcium sulfide which, after oxidation, exits as calciumsulfate along with the coal ash in the form of agglomerated particles suitable for landfill.Low-Btu coal gas leaving the gasifier passes throughcyclones, which return most of the entrained particulatematter to the gasifier. The gas, which leaves the gasifierat about 1,700 oF, is cooled to about 1,100 oF beforeentering the hot gas cleanup system. During cleanup,virtually all of the remaining particulates are removed byceramic candle filters, and final traces of sulfur are removed by reaction with a 

port reactor. The cleaned gas then ente6FA) combustion turbine(gross) generator. Exhauturbine is used to produce generator (HRSG). Supedrives a condensing steam produce about 46 MWe (gThe IGCC plant will remcoal. Due to the relativelthe gasifier and the injecttion fuel stream, the NOx 

70% less than a conventiowill produce 20% less CO
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Calendar Year

Advanced Electric Power Generation 

Preaward PreawardPreaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Design and Construction Operation and Repo

9/91 8/92 

DOE selectedproject (CCT-IV)9/12/91

Cooperative agreement awarded 8/1/92

Project co

O

Ground breaking/construction started 2/95

NEPA process completed (EIS) 11/8/94

Design completed 8/95

Environmental monitoring plancompleted 10/31/96

Preoperational tests initiated 11/96

1/98

Operation initiated 1/98

Construction completed 2/97

Project Status/Accomplishments

The system has initiated demonstration operations butcontinues to experience operational difficulties. Thestation began operation on natural gas in November 1996.Preoperational testing and shakedown of the coal gasification combined-cycle system continued through 1997with syngas produced in January 1998. The plant wasdedicated in April 1998.The project continues to suffer from a number of designissues, many of which have been solved, but others remain. Problems have been attributed to the high degreeof new technology, high scale-up factors on auxiliarycomponents, and some design and engineering deficiencies. Nevertheless, Sierra Pacific is confident that nofatal flaws exist that will preclude successful demonstration and subsequent commercialization of the KRW gasification technology.In the first quarter of 2000, Sierra Pacific began to makeadditional repairs and improvements so that sustainedoperation of the gasifier can be achieved. Improvements

include increasing the diameter to the annulus section ofthe gasifier to address the problem of high temperaturesof the limestone and ash leaving the gasifier. Also, therefractory in the gasifier grid area and 18 feet into thefluid bed region will be replaced with a single castablelayer in a revised anchoring pattern, to provide improvedresistance to low cycle fatigue of the refractory lining.The project suffered a setback in August 2000 when charfines from the desulfurizer caught fire in the filter vesselduring a start-up attempt, breaking candles, and meltingfilter holders. It will take six to eight months to makerepairs, which have been delayed until the sale of theplant is complete. The final terms and conditions of thesale will not be known until mid-year 2001.

Commercial Applications

The 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 in

thermal efficiency compized coal plant with a sction in CO2 emissions. 

system reduces space regenerated relative to othsystems. The advantageconstruction reduce the capacity additions. Furtdemonstrating HGCU, wIGCC technology, but acombustion.With the exception of thPioneer Energy IGCC DIGCC technology is capcoals, including high-suhigh-swelling coals, as wwaste, with minimal envsignificant process wasttion. The only solid waash and calcium sulfate
5-120 Program Update 2000 Adva

Advanced Electric Power Generation

Integrated Gasification Combined-Cycle

Tampa Electric Integrated

Gasification Combined-Cycle

Project Project Project

Participant

Tampa Electric Company

Additional Team Members

Texaco Development Corporation—gasification

technology supplier

General Electric Corporation—combined-cycle

technology supplier

Air Products and Chemicals, Inc.—air separation unit

supplier

Monsanto Enviro-Chem Systems, Inc.—sulfuric acid

plant supplier

TECO Power Services Corporation—project manager and

marketer

Bechtel Power Corporation—architect and engineerLocation LocationLocationMulberry, Polk County, FL (Tampa Electric Company’sPolk Power Station, Unit No. 1)TechnologyAdvanced integrated gasification combined-cycle(IGCC) system using Texaco’s pressurized, oxygenblown entrained-flow gasifier technology

Plant Capacity/Production

316 MWe (gross), 250 MWe (net)CoalIllinois #6, Pittsburgh #8, Kentucky #11, and Kentucky#9; 2.5-3.5% sulfur

Project Funding

Total project cost $303,288,446 100%DOE 150,894,223 49Participant 152,394,223 51

Project Objective

To demonstrate IGCC technology in a greenfield commercial electric utility application at the 250-MWe sizeusing an entrained-flow, oxygen-blown, gasifier with fullheat recovery, conventional cold-gas cleanup, and anadvanced gas turbine with nitrogen injection for poweraugmentation and NOx control.

Technology/Project Description

Coal/water slurry and oxygen are reacted at high temperature and pressure to produce a medium-Btu syngas in aTexaco gasifier. Molten ash flows out of the bottom ofthe gasifier into a water-filled sump where it forms a solidslag. The syngas moves from the gasifier to a high temperature heat-recovery unit, which cools the syngas whilegenerating high pressure steam. The cooled gases flow toa water wash for particulate removal. Next, a COS hydrolysis reactor converts 

gas to a form that is more then further cooled before sulfur removal system. T

emissions below 0.15 lb/

cleaned gases are then rehbined-cycle system for po7001FA gas turbine gener

controlled to below 0.27 

A steam turbine uses steasyngas and superheated wgases in the HRSG to proThe plant heat rate is 9,35
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Calendar Year

Advanced Electric Power Generation 

1988 1989 1990 1991 1994 1995 1996 1997 1998 

Preaward PreawardPreaward Design and Construction

12/89 3/91

**

DOE selected project (CCT-III) 12/19/89

Cooperative agreement awarded 3/11/91

Preoperational tests initiated 6/96

Construction completed 8/96

Operation initiated 9/96

9/96

Design completed 8/94NEPA process completed (EIS) 8/17/94Construction started 8/94

Proje

Operation and 

Environmental monitoring plan completed 5/96

Project Status/Accomplishments

Since Polk Power Station’s first gasifier run in July 1996,the gasifier has operated over 21,000 hours. The stationgenerated more than 6 million MWh of electricity fromsyngas it produced through March 2000. During one sixmonth period, the gasifier had an 83.5% on-stream factorand the combined-cycle availability was 94%.Several modifications to the original design and procedures were required to achieve the recent high availability, including: (1) removing or modifying some of theheat exchangers in the high-temperature heat recoverysystem and making compensating adjustments in thebalance of the system to resolve ash plugging problems,(2) additional solid particle erosion protection for thecombustion turbine to protect the machine from ash, (3)implementing hot restart procedures to reduce gasifierrestart time by 18 hours, (4) adding a duplicate fineshandling system to deal with increased fines loadingresulting from lower than expected carbon conversion, (5)revising operating procedures to deal with high shelltemperatures in the dome of the radiant syngas cooler,

and (6) making various piping changes to correct forerosion and corrosion in the process and coal/water slurrysystems. A COS hydrolysis unit was installed in 1999 tofurther reduce SO2 emissions, enabling the station to meet

recent, more stringent emissions restrictions.In March and April 2000, Tampa Electric tested severalcoal/petroleum coke blends. Preliminary test results from60/40 and 40/60 blends of Pittsburgh #8 and petroleumcoke (petcoke) looked promising. Both tests were successful and provide data that show continued operationon a blend of coal/petcoke is possible. One further test isplanned using a 20/80 blend.

Commercial Applications

The project was presented the 1997 Powerplant Award by

Power magazine. In 1996 the project received the Association of Builders and Contractors award for construction quality. Several awards were presented for using an

innovative siting process: 1993 Ecological Society ofAmerica Corporate Award, 1993 Timer Powers Conflict

Resolution Award from Florida Audubon SocietAs a result of the Polk PTexaco-based IGCC can environmentally suitablutilizing a wide variety the project is greater tha

reductions are 90% thoscoal-fired power plant. Tproaches utilized at Polk projects using different TECO Energy is not onlcommercialize the technhas been contacted by Ediscuss possible technictechnology.
5-122 Program Update 2000 Adva

Advanced Electric Power Generation

Integrated Gasification Combined-Cycle

Wabash River Coal Gasifica- abash River Coal Gasification Repowering Project tion Repowering Project

Project completed. Project completed.Participant

Wabash River Coal Gasification Repowering ProjectJoint Venture (a joint venture of Dynegy and PSI Energy,Inc.)

Additional Team Members

PSI Energy, Inc.—hostDynegy (formerly Destec Energy, Inc., a subsidiary of

Natural Gas Clearinghouse)—engineer and gas plantoperator

Location LocationLocationWest Terre Haute, Vigo County, IN (PSI Energy’sWabash River Generating Station, Unit No. 1)TechnologyIntegrated gasification combined-cycle (IGCC) usingGlobal Energy’s two-stage pressurized, oxygenblown, entrained-flow gasification system—E-GasTechnologyTM

Plant Capacity/Production

296 MWe (gross), 262 MWe (net)CoalIllinois Basin bituminous

Project Funding

Total project cost $438,200,000 100%DOE 219,100,000 50Participant 219,100,000 50

Project Objective

To demonstrate utility repowering with a two-stage pressurized, oxygen-blown, entrained-flow IGCC system,including advancements in the technology relevant to the

use of high-sulfur bituminous coal; and to assess longterm reliability, availability, and maintainability of thesystem at a fully commercial scale.Technology/Project DescriptionThe Destec process features an oxygen-blown, continuous-slagging, two-stage, entrained flow gasifier. Coal isslurried, combined with 95% pure oxygen, and injectedinto the first stage of the gasifier, which operates at2,600 °F/400 psig. In the first stage, the coal slurry undergoes a partial oxidation reaction at temperatures highenough to bring the coal’s ash above its melting point.The fluid ash falls through a tap hole at the bottom of thefirst stage into a water quench, forming an inert vitreousslag. The syngas flows to the second stage, where additional coal slurry is injected. This coal is pyrolyzed in anendothermic reaction with the hot syngas to enhancesyngas heating value and improve efficiency.

The syngas then flows to fire tube steam generator, rated steam. After coolinlates are removed in a hotgasifier. The syngas is fuexchangers. The syngas ichlorides and passed throcarbonyl sulfide into hydris removed in the acid gas based absorber/stripper coproduce elemental sulfur “sweet” gas is then moistthe power block. The pow192-MWe GE MS 7001FA Foster Wheeler single-drutor with reheat, and a 195steam turbine.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Advanced Electric Power Generation 

Preaward PreawardPreaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Operation and Reporting

DOE selectedproject (CCT-IV)9/12/91

Design and Construction

9/91 7/92

NEPA process completed (EA) 5/28/93

Design completed 5/94

Cooperative agreement awarded 7/28/92

Environmental monitoring plan completed 7/9/93Groundbreaking ceremony 7/7/93

Preoperational tests initiated 8/95

11/95 

Demonstration operati

completed 12

Construction completed 11/95Operation initiated 11/95

Results Summary

Environmental Environmental

• The SO2 capture efficiency was greater than 99%,

keeping SO2 emissions consistently below 0.1 lb/106

Btu and reaching as low as 0.03 lb/106 Btu; and SO2was transformed into 99.99% pure sulfur, a highlyvalued by-product.

• The NO

x emissions were controlled by steam injection

down to 0.15 lb/106 Btu.

• Coal ash was converted to a low-carbon vitreous slag,

impervious to leaching and valued as an aggregate inconstruction or as grit for abrasives and roofing materials; and trace metals from petroleum coke were alsoencased in an inert vitreous slag.

Operational Performance

• The first year problems encountered included:

– Ash deposition at the fire tube boiler inlet, which

was corrected by a change to the flow pathgeometry;

– Particulate breakthrough in the hot gas filter, which

was largely solved by changing to improved metallic candle filters.

– Chloride and metals poisoning of the COS catalyst,

which was eliminated by installation of a wet chloride scrubber and a COS catalyst less prone topoisoning.

• The second year identified cracking in the gas turbine

combustion liners and tube leaks in the heat recoverysteam generator (HRSG). Resolution involved replacement of the gas turbine fuel nozzles and liners andmodifications to the HRSG to allow for more tubeexpansion.

• The third year was essentially trouble free and the

IGCC 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 during

petroleum coke operation.

• In the fourth year, th

rows 14 through 17 omonth outage. But oavailability of the gareaching 79.1% in 19

Economic Performa

• Overall cost of the g

facilities was $417 menvironmental studiestruction, pre-operati

• Preliminary estimate

are $1,200/kW. Cosfor a greenfield plant ogy.
5-124 Program Update 2000 Adva

Project Summary

The 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 system, a number of other advanced features contributed tothe high energy efficiency. These included: (1) hot/dryparticulate removal to enable gas cleanup without heatloss, (2) integration of the gasifier high-temperature heatrecovery steam generator with the gas turbine-connectedHRSG to ensure optimum steam conditions for the steamturbine, (3) use of a carbonyl sulfide (COS) hydrolysisprocess to enable high-percentage sulfur removal, (4)recycle of slag fines for additional carbon recovery, (5)use of 95% pure oxygen to lower power requirements forthe oxygen plant, and (6) fuel gas moisturization to reduce steam injection requirements for NOx control.

Over the four-year demonstration period starting in November 1995, the facility operated approximately 15,000hours and processed approximately 1.5 million tons ofcoal to produce about 23 x 1012 Btu of syngas. For several

of the months, syngas production exceeded one trillionBtu. By the beginning of the final year of operation underthe demonstration, the 262-MWe IGCC unit had capturedover 100 million pounds equivalent of SO2

.

Operational Performance

The first year of operation was plagued by problemsprimarily with: (1) ash deposition at the inlet to the firetube boiler, (2) particulate breakthrough in the hot gasfilter system, and (3) chloride and metals poisoning of theCOS catalyst. A modification to the hot gas path flowgeometry corrected the ash deposition problem. Replacement of the ceramic candle filters with metallic candles

proved to be largely successful. A follow-on metalliccandle filter development effort ensued using a hot gasslipstream, which resulted in improved candle filter metallurgy, blinding rates, and cleaning techniques. Thecombined effort all but eliminated downtime associatedwith the filter system by the close of 1998. Installation ofa wet chloride scrubber eliminated the chloride problemby September 1996 and use of an alternate COS catalystless prone to trace metal poisoning provided the final curefor the COS system by October 1997.The second year of operation identified cracking problems with the gas turbine combustion liners and tubeleaks in the HRSG. Replacement of the fuel nozzles andliners solved the cracking problem. Resolution of theHRSG problem required modification to the tube supportand HRSG roof/penthouse floor to allow for more expansion.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 twodifferent 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 produced350,000 x 106 Btu of syngas. There was a negligible

amount of tar production and no problems were encountered in removing the dry char particulate despite a higherdust loading. Exhibit 5-44 provides a summary of thethermal performance of the unit on both coal and petcoke.Exhibit 5-45 compares the coal and petcoke fuel characteristics and Exhibit 5-46 compares the syngas products.The fourth year of operation was marred by a 3-monthoutage due to damage incurred to rows 14 through 17 of

the gas turbine air compreyears of operation, availasteadily improved, reachi

Environmental Perfor

The IGCC unit operates w

greater than 99%. As a re

tently below 0.1 lb/106 Bt

as 0.03 lb/106 Btu. Moreo

SO2 pollutant into 99.99% 

by-product, rather than a Steam injection controls N

106 Btu. This is the emiss

EPA SIP call related to ozparticulate emissions are The ash component of the vitreous slag, impervious aggregate in construction roofing materials. Also, thpetcoke were effectively 

Economic Performan

The economic performanforthcoming in the Final Tpreparation. Some prelimwas drawn from technicacourse of the demonstratiThe overall combined cosgeneration facilities was $cost includes engineering equipment procurement, management (including oEscalation during the projthe costs of construction and power, up to the date December 1995. Soft cosfees and interest during cProject participants projedual-train repowered faci$1,000/kW, with advance
Advanced Electric Power Generation 

Design 

Coal Coal 

Nominal Throughput, tons/day 2,550 2,450 

Syngas Capacity, 106 Btu/hr 1,780 1,690 

Combustion Turbine, MW 192 192 

Steam Turbine, MW 105 96 

Auxiliary Power, MW 35 36 Net Generation, MW 262 261 

Plant Efficiency, % (HHV) 37.8 39.7 

Sulfur Removal Efficiency, % >98 >99 

Exhibit 5-44

Wabash Thermal Performance Sum

Exhibit 5-45

Wabash Fuel abash Fuel Analysis AnalysisAnalysis

Typical Coal 

Moisture, % by wt. 15.2 

Ash, % by wt. 12.0 

Volatile, % by wt. 32.8 

Fixed Carbon, % by wt. 39.9 

Sulfur, % by wt. 1.9 

Heating Value, as Rec’d, Btu/lb 10,536 

Exhibit 5-46

Wabash Product Syngas abash Product Syngas Analys

Analys

Analys

Typical Coal 

Nitrogen, % by vol. 1.9 

Argon, % by vol. 0.6 

Carbon Dioxide, % by vol. 15.8 

Carbon Monoxide, % by vol. 45.3 

Hydrogen, % by vol. 34.4 

Methane, % by vol. 1.9 

Total Sulfur, ppmv 68 

Higher Heating Value, Btu/scf 277 

Commercial Applications

At the end of the demonstration in December 1999, Global Energy, Inc. purchased Dynegy’s gasification assetsand technology. Global Energy plans to market the technology under the name “E-Gas TechnologyTM.” Theproject is continuing to operate as Wabash River Energy,Ltd., a subsidiary of Global Energy.The immediate future for E-Gas TechnologyTM appears tolie with both foreign and domestic applications wherelow-cost feedstocks such as petcoke can be used and coproduction options are afforded such as bundled production of steam, fuels/chemicals, and electricity. Integrationor association with refinery operations are examples.In the longer term, the technology has application to therepowering of the 95,000 MWe of existing U.S. coal-firedboilers over 30 years old, and new foreign and domesticcoal-fired capacity additions. Over time, the economicsand performance of the technology will continue to improve, coal and gas price differentials will increase, anddisplacement of petroleum in chemicals and fuels production will increase in importance.Contacts ContactsContactsPhil Amick, (713) 374-7252

Global Energy, Inc.1000 Louisiana St., Suite 3800Houston, TX 77002(713) 374-7279 (fax)

George Lynch, DOE/HQ, (301) 903-9434Leo E. Makovsky, NETL, (412) 386-5814

References

• Steven L. Douglas. “Wabash River in Its Fourth Year

of Commercial Operation.” 7th Clean Coal Technology Conference: Volume II Technical Papers. June

1999.
5-126 Program Update 2000 Adva
Advanced Electric Power Generation 

Advanced Electric Power Gener

Advanced Electric Power GenerAdvanced Electric Power Gener

Advanced Combustion/Heat En

Advanced Combustion/Heat EnAdvanced Combustion/Heat En
5-128 Program Update 2000 Adva

Advanced Electric Power Generation

Advanced Combustion/Heat Engines

Clean Coal Diesel Clean Coal DieselDemonstration Project Demonstration Project

Participant

Arthur D. Little, Inc. (ADL)

Additional Team Members

University of Alaska at Fairbanks—host and cofunderColtec Industries Inc.—diesel engine technology vendorUsibelli Coal Mine, Inc.—coal supplierCQ Inc.Fairbanks MorseAMBAC, Inc.Location LocationLocationFairbanks, AK (University of Alaska facility)TechnologyColtec’s coal-fueled diesel engine

Plant Capacity/Production

6.4 MWe (net)CoalUsibelli Alaskan subbituminous

Project Funding

Total project cost $47,636,000 100%DOE 23,818,000 50Participant 23,818,000 50

Project Objective

To prove the design, operability, and durability of the coaldiesel engine during 4,000 hours of operation and test thecoal slurry in the diesel.

Technology/Project DescriptionThe project is based on the demonstration of an 18-cylinder, heavy-duty engine (6.4 MWe) modified to operate onAlaskan subbituminous coal. The clean coal diesel technology, which uses a low-rank coal-water-fuel (LRCWF),is expected to have very low NOx and SO2 emission levels

(50–70% below current New Source Performance Standards). In addition, the demonstration plant is expectedto achieve 41% efficiency, and future plant designs areexpected to reach 48% efficiency. This will result in a25% reduction in CO2 emissions compared with conventional coal-fired plants. The engine will use selective

catalytic reduction (SCR) for NOx control.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Advanced Electric Power Generation 

1992 1996 1997 1993 1994 1998 1999 2000 2001 

Preaward PreawardPreaward

5/93 7/94

DOE selected project(CCT-V) 5/4/93

Cooperative agreementawarded 7/12/94

Design and Construction

NEPA processcompleted (EA)6/2/97

Construction started 6/98

Environmental monitoring

plan completed 2/99

Coal Diesel Operation initiated 10/01*

10/0

Project

restructured 8/96

Design completed 1/99

Coaltec two-cylinder engine

test on LRCWF 2/01*

** 

Project Status/Accomplishments

Overall project system design was completed in early1999. The 18-cylinder diesel engine arrived on site atUAF in January 1999 and was mounted in the enginehouse in late February. In October 1999, the engine, afterbeing connected to the generator, was operated on dieselfuel to ensure it would function coupled with the generator. In May 2000, total system startup was attempted ondiesel fuel. Minor problems with system integration andtie-in with the existing electrical bus system were encountered. The SCR system for the diesel was tested in August 2000 and achieved 90% reduction in NOx emissions,

which was within contract specifications. Since August15, 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. Design of the hardenedengine parts, coal fuel preparation and testing, andcompletion of the baghouse and SNCR system are inprogress.

With the change of site from Easton, Maryland to UAF,Alaskan subbituminous coal will now be used to manufacture the LRCWF. Usibelli Coal Mine, Inc. will supplythe coal. Samples of the coal have been sent to CQ Inc.for analysis and washability tests. ADL and EERC willalso perform various analyses of the coal. Upon completion of the tests, a design formula will be devised to produce the LRCWF. The LRCWF will first be tested in aColtec two-cylinder test engine. These tests are scheduled for the Fall 2000. The tests on the test engine willprovide information and data on how to optimize theoperational settings, verify the coal fuel performance, andfinalize the requirements for hardened coatings for critical components.

Commercial Applications

The U.S. diesel market is projected to exceed60,000 MWe (over 7,000 engines) through 2020. Theworldwide market is 70 times the U.S. market. The technology is particularly applicable to distributed powergeneration in the 5- to 20-MWe range, using indigenouscoal in developing countries.

The net effective heat raexpected to be 6,830 Btvery competitive with sifired installations. Envimercial diesel systems stween 50% and 70% belation cost of a mature c$1,300/kW.
5-130 Program Update 2000 Adva

Advanced Electric Power Generation

Advanced Combustion/Heat Engines

Healy Clean Coal Project Healy Clean Coal Project

Project completed. Project completed.Participant

Alaska Industrial Development and Export Authority

Additional Team Members

Golden Valley Electric Association, Inc.—host and operatorStone and Webster Engineering Corp.—engineerTRW, Inc., Space & Technology Division—combustor

technology supplier

The Babcock & Wilcox Company (B&W)—spray dryer

absorber technology supplier

Usibelli Coal Mine, Inc.—coal supplierSteigers Corporation—environmental and permitting

support

Location LocationLocationHealy, 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/Production

50 MWe (nominal)CoalUsibelli subbituminous 50% run-of-mine (ROM) and50% waste coal

Project Funding

Total project cost $242,058,000 100%DOE 117,327,000 48Participant 124,731,000 52

Project Objective

To 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 combustion system, an advanced entrained/slagging combustors through staged fuel and air injection for NOx control

and limestone injection for SO2 control. Additional SO2

is removed using B&W’s activated recycle SDA.A coal-fired precombustor increases the air inlet temperature for optimum slagging performance. The slaggingcombustors are bottom mounted, injecting the combustion products into the boiler. The main slagging combustor consists of a water-cooled cylinder that slopes towarda slag opening. The precombustor burns 25–40% of thetotal coal input. The remaining coal is injected axiallyinto the combustor, rapidly entrained by the swirlingprecombustor gases and additional air flow, and burnedunder substoichiometric conditions for NO

x

 control. The

ash forms molten slag, which flows along the watercooled walls and is driven 

tional forces through a sloAbout 70–80% of the ash hot gas is then ducted to tcomplete combustion, adtertiary air windbox to NO

ports. Pulverized limesto

fed into the combustors wverting CaCO3 to lime (C

and ash that was not remoflash-calcined material, is system. Most of the flashform a 45% solids slurry, dryer. The SO2 in the flue 

lets as water is simultaneo

further removed from the flash-calcined-material on 
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Advanced Electric Power Generation 

1990 1991 1993 1994 1995 1997 1998 1999 2000 

Preaward PreawardPreaward Design and Construction

Designstarted 7/90

4/91

Cooperativeagreementawarded 4/11/91

DOE selected project(CCT-III) 12/19/89

Operation and Reporting

12/89 1/98

**

DOE cost-sharecompleted 12/9

Operation initiated 1/98

Preoperational testsinitiated 8/97

NEPA process completed (EIS) 3/10/94

Design completed 10/93

Ground breaking/

construction

started 5/30/95 Environmental monitoring

plan completed 4/11/97

Constructioncompleted 11/97

**

Results Summary

Environmental Environmental

• NO

x emissions ranged from 0.208–0.278 lb/106 Btu,

with typical emissions of 0.245 lb/106 Btu on a 30-day

rolling average, which is well below the permit limitof 0.350 lb/106 Btu on a rolling day average.

• SO2 emissions were consistently less than 0.09 lb/106

Btu, with typical emissions of 0.038 lb/106 Btu, which

are below the permit limit of 0.10 lb/106 Btu (3-hour

average).

• High SO2 removal efficiencies in excess of 90% were

achieved with low-sulfur coal and Ca/S molar ratios of1.4–1.8.

• Particulate matter (PM) emissions were 0.0047 lb/106

Btu, which is well below the permit limit of 0.02 lb/106 Btu.

• CO emissions were less than 130 ppm at 3.0% O2,

with typical emissions of 30–40 ppm at 3.0% O2,

which is well below the permit limit of 202 ppm at3.0% O2.

• Tests showed that the SDA system SO2 emissions, PM

emissions, and opacity were well within guarantees.

Operational Operational

• Carbon burnout contract goals were achieved—greater

than 99% carbon burnout at 100% maximum continuous rating (MCR) for the ROM, 50/50 blend of ROM/waste coal, and 55/45 blend. The carbon burnout wastypically 99.7%.

• The contract goal for slag recovery greater than 70% at

100% MCR for all coals was also achieved. Slagrecovery ranged from 78–87%, with a typical recoveryof 83%.

• During a 90-day test in the second half of 1999, the

plant availability was 97% at a capacity factor of 95%.

• The SDA pressure drops and power consumption were

well below guarantee levels.

Economic EconomicEconomic• Economic data are not yet available.
5-132 Program Update 2000 Adva

 Exhibit 5-47

 Healy Performance Goals and Combustion System Characterizatio

Testing Results (June–December 1998) esting Results (June–December 1998)

Parameter ParameterParameter NSPS Permit Goal Actual Range Actu

Actu

NO

x

0.5 lb/106 Btu (before 7/97) 0.350 lb/106 Btu (30-day rolling avg) <0.35 lb/106 Btu 0.208–0.278 lb/106 Btu 0.245 

0.15 lb/106 Btu (modified after 7/97) (30-day rolling avg) (30-da

0.5 lb/106 Btu (new plant after 7/97)

SO2 90% removal and less than 0.086 lb/106 Btu (annual avg) 70% removal (min) <0.09 lb/106 Btu 0.038 

1.2 lb/106 Btu 79.6 lb/hr max (<35 ppm @ 3% O2) 25 lb/

70% removal when emissions 0.10 lb/106 Btu (3-hour avg)

< 0.60 lb/106 Btu 65.8 lb/hr max (3-hour avg)

PM 0.03 lb/106 Btu 0.02 lb/106 Btu (hourly avg) 0.015 lb/106 Btu NA 0.004Opacity 20% Opacity (6-minute avg) 20% Opacity (3-minute avg) 20% Opacity (3- <10% Opacity 2.3% 

27% Opacity (one 6-minute minute avg) (30-min avg.)period per hour)

CO Dependent on ambient CO 0.20 lb/106 Btu (hourly avg) <200 ppm (dry basis) <130 ppm @ 30–40 

levels in the local region (202 ppm CO @ 3.0% O2) at 3.5% O2 (dry basis) 3.0% O2 0.036 

(<206 ppm CO @3.0% O2)

a After correction of problems with premature filter bag failures in the baghouse.

Project Summary

The 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 Performance

The entrained/slagging combustor is designed to minimize NO

x emissions, achieve high carbon burnout, and

remove the majority of fly ash from the flue gas prior tothe boiler. The slagging combustor is also the first step ofa three-step process for controlling SO2 by first converting limestone to flash-calcined lime. Second, the flash

calcined-lime absorbs SO2 within the boiler. Third, the

majority of the SO2 is removed with B&W’s SDA system,

which uses the flash-calcined lime and fly ash captured inthe baghouse. Because most of the coal ash is removedby the slagging combustors, the recycled material is richenough in calcium content that the SDA can be operatedsolely on the recycled solids, eliminating the need topurchase or manufacture lime for the back end scrubbingsystem.During a cumulative six-month combustion system characterization test, a series of tests were performed to establish baseline performance of the combustion system whileburning ROM and ROM/waste coal blends, to map combustor performance characteristics over a broad range ofoperating conditions and hardware configurations, and todetermine the best configuration and operating conditions

for long-term operation. the NO

x, SO2, PM, opacit

met with the exception of 

exceedences during startuas well as permit and NSPin Exhibit 5-47.Performance testing of thJune 1999 showed that thMeasurements of the SDA stone feed, coal feed, air pash, electrical power conswell as normal plant data trol system, showed that t
Advanced Electric Power Generation 

Exhibit 5-48

Healy SDA Performance Test Results and Performance Guarantees

Operating Parameter Guarantee GuaranteeGuarantee Range of Parameter Values

SO2 79.6 lb/hr (max) <2.15PM 0.015 lb/106 Btu 0.0014-0.0052Opacity 20% Opacity 1.0-2.0

(3-minute avg) 27% Opacity for 3 minutes per hour

System Pressure Drop 13 inches WG 9.6-10.0System Power Consumption 550.5 kW 324-340

antees. The results of the tests and the performance guarantees are shown in Exhibit 5-48.

Operational Performance

The slagging stage of the combustor performed extremelywell and continuously demonstrated the capability to burnboth ROM and ROM/waste coal blends over a broadrange of operating conditions. The precombustor performed very well with ROM coal, but exhibited morevariable performance, in terms of slagging behavior,during the initial tests with ROM/waste coal blends.Localized slag freezing was observed in the precombustorduring early testing. A combination of hardware configuration and operational configuration changes were madethat successfully minimized slag freezing. These changesincluded relocating the secondary air from the precombustor mix annulus to the head end of the slagging stageand completely transferring the precombustor mill air tothe boiler NOx ports following boiler warmup. These

changes eliminated the mixing of excess air downstreamof the precombustor chamber to minimize local slagfreezing and increased the precombustor operating temperature to provide additional temperature margin. Themill air change had the added benefit of simplifyingcombustor operation by eliminating the need to monitor

and control coal-laden mill air flow to the precombustormill air ports during steady-state operation.Testing of the slagging combustor also showed that thecontract goals were achieved, which included greater than99% carbon burnout at 100% MCR for the performance,ROM, 50/50 blend of ROM/waste coal, and 55/45 blend;and greater than 98% carbon burnout at 100% MCR forwaste coal. The carbon burnout was typically 99.7%.Slag recovery ranged from 78–87%, with a typical reading of 83%, easily meeting the contract goal for slagrecovery of greater than 70% at 100% MCR for all coals.The SDA system also performed well. During performance testing in June 1999, system pressure drops werewell below the 13 in. WG guarantee. The range was 9.6–10.0 in. WG as can be seen in Exhibit 5-48. Power consumption was approximately 38–41% less than the guaranteed level. Based on these results, Stone & Websterconcluded that the SDA system met all performanceguarantees.

Economic Performance

Economic data are not yet available.

Commercial Applica

This technology is approdustrial boiler in new or coal-fired boilers as welbecause of its high ash-rcyclone boilers may be with the entrained/slagglimited supply of high-Btemperature coal that cymercial availability of cfor SO2, NOx, and partic

potential users planning retrofits to existing capaCAAA requirements.Continued use of the coone year while GVEA eand regulatory feasibilittional low-NOx burner tthat repairs and improvecombustor. Preliminary retrofit” option is the mcommercial viability of Contacts ContactsContactsArthur E. Copoulos, Pro

Alaska Industrial De813 West Northern LAnchorage, AK 995(907) 269-3044 (fax)

George Lynch, DOE/HQRobert M. Kornosky, N

References

• TRW, Inc. Healy Cl

stration Program Top

tem Operation Final 

• Stone & Webster En

Dryer Absorber Syst

June 7-11, 1999. Feb
5-134 Program Update 2000 Adva
Coal Processing for Clean Fuels 

Coal Processing for Clean Fu
5-136 Program Update 2000 

Coal Processing for Clean Fuels

Indirect Liquefaction

Commercial-Scale Demon- Commercial-Scale Demonstration of the Liquid PhaseMethanol (LPMEOHTM) Methanol (LPMEOHTM)

Process Process

Participant

Air Products Liquid Phase Conversion Company, L.P.(a limited partnership between Air Products andChemicals, Inc., the general partner, and EastmanChemical Company)

Additional Team Members

Air Products and Chemicals, Inc.—technology supplier

and cofunder

Eastman Chemical Company—host, operator, synthesis

gas and services provider

ARCADIS Geraghty & Miller—fuel methanol tester and

cofunder

Electric Power Research Institute—utility advisorLocation LocationLocationKingsport, Sullivan County, TN (Eastman Chemical

Company’s Chemicals-from-Coal Complex)

TechnologyAir Products and Chemicals, Inc.’s liquid phase methanol

process

Plant Capacity/Production

80,000 gallons/day of methanol (nominal)CoalEastern high-sulfur bituminous, 3–5% sulfur

Project Funding

Total project cost $213,700,000 100%DOE 92,708,370 43Participant 120,991,630 57

Project Objective

To demonstrate on a commercial scale the production ofmethanol from coal-derived synthesis gas using theLPMEOHTMprocess; to determine the suitability of

methanol produced during this demonstration for use as achemical feedstock or as a low-SO

x emitting, low-NOx

emitting alternative fuel in stationary and transportationapplications; and to demonstrate, if practical, the production of dimethyl ether (DME) as a mixed coproduct withmethanol.Technology/Project DescriptionThis project is demonstrating, at commercial scale, theLPMEOHTM process to produce methanol from coalderived synthesis gas. The combined reactor and heatremoval system is different from other commercialmethanol processes. The liquid phase not only suspends

the catalyst but functions the heat of reaction away feature permits the direct feed to the reactor withouconversion.Methanol fuel testing is btionary and mobile applicand distributed electric pomethanol from the projecseveral test locations to stproduct as a feedstock in eration applications. Eas(Mason seam) containing 10% ash is being used.

LPMEOH is a trademark of Air Products and Chemicals, Inc.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels 

Project Status/Accomplishments

The first production of methanol from the 80,000 gal/dayunit occurred on April 2, 1997 with the first stable operation at nameplate capacity occurring on April 6, 1997. Astable test period at over 92,000 gal/day revealed nosystem limitations.The LPMEOHTM process demonstration unit continues toexceed expectations. Tests have given increased confidence in the use of the LPMEOHTM process for IGCCapplications. This confidence level will increase withadditional testing of the LPMEOHTM process. Since startup in April 1997, about 66 million gallons ofmethanol have been produced and plant availability hasexceeded 97.7%. Availability in 1998 through 2000 wasin excess of 99.1%. As a result of the successesachieved, the demonstration operations were extended anadditional 15 months (through June 30, 2002) to allowfor the opportunity to perform new tests that are considered to be 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 guardbed will incorporate an improved adsorbent material,which is expected to reduce significant poisons such asarsine. The new adsorbent material is a copper oxideimpregnated activated carbon that is commercially available. The guard bed and new adsorbent will be placed inservice after the implementation of some plant equipmentmodifications to allow for the adsorbent change.Engineering for the plant modifications to support in situ

catalyst activation in the LPMEOHTM reactor has beencompleted. Currently, catalyst is activated in smallbatches in a separate vessel and transferred into theLPMEOHTM reactor. In situ activation of the methanol

catalyst is of commercial significance as it has the potential to simplify equipment and to reduce capital requirements. It is expected that the in situ activation demonstration will occur prior to mid-2001.

Commercial Applica

The LPMEOHTM procesIGCC power generation storable-liquid fuel (megas. Methanol also has applications; it can be sin stationary and mobile an excellent fuel for utilcontains no sulfur and h

teristics when burned.DME has several commwith methanol, the mixtIGCC electric power gemethanol and DME also stock for the synthesis ofuel additives. Pure DMaerosol for personal proTypical commercial-scato range in size from 50nol produced when assopower generation trains 

Operation and Reporting

1989 1992 1995 1993 1994 1996 1997 1998 2002

12/89 10/92

DOE selectedproject (CCT-III)12/19/89

Cooperative agreement awarded 10/16/92

NEPA process completed (EA) 6/30/95

Construction started 10/95

Design completed 6/96

Environmental monitoring plan completed 8/29/96

4/97

Operation initiated 4/97

Construction completed 1/97Preoperational tests initiated 1/97

Project transferred to Air Products

Liquid Phase Conversion

Company, L.P. 3/95

Project resited toKingsport, TN10/93

Operaticomple6/02*

**

**

Preaward PreawardPreaward Design and Construction
5-138 Program Update 2000 

Coal Processing for Clean Fuels

Coal Preparation Technologies

Advanced Coal ConversionProcess Demonstration

Participant

Western SynCoal LLC (formerly Rosebud SynCoalPartnership; a subsidiary of Montana Power Company’sEnergy Supply Division)

Additional Team Members

NoneLocation LocationLocationColstrip, Rosebud County, MT (adjacent to WesternEnergy Company’s Rosebud Mine)TechnologyWestern SynCoal LLC’s Advanced Coal ConversionProcess for upgrading low-rank subbituminous andlignite coals

Plant Capacity/Production

45 tons/hr of SynCoal® product

CoalPowder River Basin subbituminous (Rosebud Mine),0.5–1.5% sulfur, plus tests of other subbituminous coalsand lignites

Project Funding

Total project cost $105,700,000 100%DOE 43,125,000 41

Participant 62,575,000 59

Project Objective

To demonstrate Western SynCoal LLC’s Advanced CoalConversion Process (ACCP) to produce SynCoal®, a

stable coal product having a moisture content as low as1%, sulfur content as low as 0.3%, and heating value upto 12,000 Btu/lb.

Technology/Project DescriptionThe process demonstrated is an advanced thermal coalconversion process coupled with physical cleaning techniques to upgrade high-moisture, low-rank coals to produce a high-quality, low-sulfur fuel. The raw coal isscreened and fed to a vibratory fluidized-bed reactorwhere surface moisture is removed by heating with hotcombustion gas. Coal exits this reactor at a temperatureslightly higher than that required to evaporate water andflows to a second vibratory reactor where the coal isheated to nearly 600 °F. This temperature is sufficient toremove chemically bound water, carboxyl groups, andvolatile sulfur compounds. In addition, a small amountof tar is released, partially sealing the dried product.Particle shrinkage causes fracturing, destroys moisturereaction sites, and liberates the ash-forming mineral matter.

The coal is then cooled to with an inert gas in a vibrcooled coal is sized and fair pressure and vibration ing much of the pyrite, frthe sulfur content of the pity fractions are sent to a fractions go to fluidized-bremoval.The fines handling system are produced throughout gathered by screw conveyconveyors to a bulk cooliblended with the coarse pcapacity bin until loaded site sales, or returned to t

SynCoal is a registered trademark of the Rosebud SynCoal Partnership.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels 

Project Status/Accomplishments

The ACCP facility was scheduled to complete demonstration operations in January 1999 but was granted a twoyear no-cost extension. The ACCP facility has processedover 2.6 million tons of raw coal to produce over 1.7million tons of SynCoal. The SynCoal is used by electricutilities and industrial facilities (primarily cement andlime plants). The ACCP facility continues to supply sixcommercial customers including the 330-MWe ColstripUnit No. 2. SynCoal is trucked to Colstrip Unit No. 2and fed to three of the five pulverizers using a dedicatedpneumatic feed system.The demonstration of SynCoal as a supplemental fuel forUnit No. 2 started in February 1999. About 131,000 tonsof SynCoal were used during 1999, or approximately11.6% of the total thermal input on an annual basis. Ondays that SynCoal was used as a supplemental fuel, UnitNo. 2 produced an average of 3.7%, or 10.5 MWe (net),of additional generation. The gross unit heat rate for UnitNo. 2 improved by 85 Btu/kWh when firing SynCoal(auxiliary power demand decreased about 1.9 MWe).

When the demonstration started, baseline testing indicated that Unit No. 2 was typically producing 2.9 MWe(net) less than Unit No. 1, a sister unit of comparablecapacity. In late Spring 1999, Unit No. 1 was overhauled,resulting in an increase in its average output of 7 MWe(net). With this increase in output, the overhauled UnitNo. 1 would have produced 5.4 MWe more than Unit No.2. However, for the days that SynCoal was used, UnitNo. 2 out-produced the overhauled Unit No. 1 by anaverage of 7.3 MWe—285.7 MWe versus 278.4 MWe(net)—with 15.0% of the total heat input coming fromSynCoal. Furthermore, SynCoal can be credited foractual 1999 SO2 emissions reductions for Unit No. 2 of

approximately 430 tons, or an 8% reduction, and NOx

emissions reductions of approximately 826 tons, or a 19%reduction, when compared with Unit No. 1 emissions.Three different feedstocks were tested at the ACCP facility—North Dakota lignite, Knife River lignite, and Amaxsubbituminous coal. Approximately 190 tons of theSynCoal® product produced with the North Dakota lignite

was burned at the 250-MWe cyclone-fired Milton R.Young Power Plant Unit No. 1. Testing showed dramatic

improvement in cyclone tapping, and a 13% reduments. In addition, boilto over 86% and the totaBtu/kWh.

Commercial Applica

ACCP has the potential western subbituminous 

is a viable compliance o

reduction requirements. 

tal fuel for plants seekinbecause the ACCP allowraw coals without deratisix long-term agreemen

industrial and utility cusThe ACCP has the potesulfur low-rank coals inagents for many metalluSynCoal® enhances cem

provides a value-added 

Preaward PreawardPreaward Design and Construction Operation and Reporting

1988 1989 1990 1991 1992 1993 1994 1999 2000

12/88 9/90 6/92

Design completed 8/91

DOE selected project(CCT-I) 12/9/88

Cooperative agreement

awarded 9/21/90

Ground breaking/construction started 3/28/91NEPA process completed (EA) 3/27/91

Preoperational tests initiated 12/91

Construction completed 2/92

Environmental monitoring plan completed 4/7/92

Test operation initiated 6/92

**

Project complete

Operation completed 1
5-140 Program Update 2000 

Coal Processing for Clean Fuels

Coal Preparation Technologies

Development of the Coal Development of the CoalQuality ExpertTM

Project completed. Project completed.Participants

ABB Combustion Engineering, Inc. and CQ Inc.

Additional Team Members

Black & Veatch—cofunder and software

developer

Electric Power Research Institute—cofunderThe Babcock & Wilcox Company—cofunder and pilotscale testerElectric Power Technologies, Inc.—field testerUniversity of North Dakota, Energy and Environmental

Research Center—bench-scale tester

Utility Companies—(5 hosts)Locations LocationsLocationsGrand Forks, Grand Forks County, ND (bench tests)Windsor, Hartford County, CT (bench- and pilot-scale

tests)

Alliance, Columbiana County, OH (pilot-scale tests)Five utility host sitesTechnologyCQ Inc.’s EPRI Coal Quality ExpertTM (CQETM) computer software

Plant Capacity/Production

Full-scale testing took place at six utility sites ranging insize from 250–880 MWe.CoalWide variety of coals and blends

Project Funding

Total project cost $21,746,004 100%DOE 10,863,911 50Participants 10,882,093 50

Project Objective

The objective of the project was to provide the utilityindustry with a PC software program it could use to confidently and inexpensively evaluate the potential for coalcleaning, blending, and switching options to reduce emissions while producing the lowest cost electricity. Specifically the project was to: (1) enhance the existing CoalQuality Information System (CQISTM) database and CoalQuality Impact Model (CQIMTM) to allow assessment ofthe effects of coal-cleaning on specific boiler costs andperformance; and (2) develop and validate CQETM, amodel that allows accurate and detailed prediction of coal

quality impacts on total pperformance.Technology/Project DThe CQETM is a software sophistication to fueling dsystem-wide impact of fufired power plant performgeneration costs. The imimprovements; operationacompliance alternatives omance, and production coCQETM. CQETM can be uall such impacts, or it may default data to perform mstudies.

Coal Quality Expert, CQE, CQIS, and CQIM are trademarks of theElectric Power Research Institute.Pentium is a registered trademark of Intel.OS/2 Warp is a registered trademark of IBM.Windows is a registered trademark of Microsoft Corporation.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels 

Results Summary

Environmental Environmental

• CQETM includes models to evaluate emission and

regulatory issues.

Operational Operational

• CQETM can be used on a stand-alone computer or as a

network application for utilities, coal producers, andequipment manufacturers to perform detailed coalimpact analyses.

• Four features included in the CQETM program are:

– Fuel Evaluator,– Plant Engineer,– Environmental Planner, and– Coal-Cleaning Expert.

• CQETM can be used to evaluate:

– Coal quality,

– Transportation system options,– Performance issues, and– Alternative emissions control strategies.

• CQETM operates on an OS/2 Warp® (Version 3 or later)

operating system with preferred hardware requirements of a Pentium®-equipped personal computer, 1

gigabyte hard disk space, 32 megabytes RAM,1024x768 SVGA, and CD-ROM.

Economic EconomicEconomic• CQETM includes economic models to determine production cost components for coal-cleaning processes,

power production equipment, and emissions controlsystems.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

DOE selectedproject (CCT-I)12/9/88

12/88

Cooperative agreement awarded 6/14/90

NEPA process completed

(MTF) 4/27/90

Environmental monitoringplan completed 7/31/90

Operation initiated 8/90

Preaward PreawardPreaward

Development

6/90

Field testing completed 4/93

8/90

CQE R

CQE CD-ROM is
5-142 Program Update 2000 

Project Summary

Background

CQETM began with EPRI’s CQIMTM, developed for EPRIby Black & Veatch and introduced in 1989. CQIMTMwas endowed with a variety of capabilities, includingevaluating Clean Air Act compliance strategies, evaluating bids on coal contracts, conducting test-burn planningand analysis, and providing technical and economicanalyses of plant operating strategies. CQETM, whichcombines CQIMTM with other existing software anddatabases, extends the art of model-based fuel evaluationestablished by CQIMTM in three dimensions: (1) newflexibility and application, (2) advanced technical modelsand performance correlations, and (3) advanced userinterface and network awareness.

Algorithm Development

Data derived from bench-, pilot-, and full-scale testingwere used to develop the CQETM algorithms. Benchscale testing was performed at ABB CombustionEngineering’s facilities in Windsor, Connecticut and theUniversity of North Dakota’s Energy and EnvironmentalResearch Center in Grand Forks, North Dakota. Pilotscale testing was performed at ABB CombustionEngineering’s facilities in Windsor, Connecticut andAlliance, Ohio. The five field test sites were:• Alabama Power’s Gatson, Unit No. 5 (880 MWe),

Wilsonville, Alabama;

• Mississippi Power’s Watson, Unit No. 4 (250 MWe),

Gulfport, Mississippi;

• New England Power’s Brayton Point, Unit No. 2 (285

MWe) and Unit No. 3 (615 MWe), Somerset, Massachusetts;

• Northern States Power’s King Station (560 MWe),

Bayport, Minnesota; and

• Public Service Company of Oklahoma’s Northeastern,

Unit No. 4 (445 MWe), Oologah, Oklahoma.

The six large-scale field tests consisted of burning a baseline coal and an alternate coal over a two-month period.The baseline coal was used to characterize the operatingperformance of the boiler. The alternate coal, a blendedor cleaned coal of improved quality, was burned in theboiler for 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 at CQInc. to determine what quality levels of clean coal can beproduced economically and then transported to the benchand pilot-scale facilities for testing. All data from bench-,pilot-, and full-scale facilities were evaluated and correlated to formulate algorithms used to develop the model.

CQETM Capability

The OS/2®-based program evaluates coal quality, transportation system options, performance issues, and alternative emissions control strategies for utility power plants.

CQETM is composed of technical tools to evaluateperformance issues, environmental models to evaluateemissions and regulatory issues, and economic models todetermine production cost components, including consumables (e.g., fuel, scrubber additives), waste disposal,

operation and maintenance, replacement energy costs, andoperation and maintenance costs for coal-cleaning processes, power production equipment, and emissions control systems. CQETM has four main features:• Fuel Evaluator—Performs system-, plant-, or unitlevel fuel quality, economic, and technical assessments.• Plant Engineer—Provides in-depth performance evaluations with a more focused scope than provided in the

Fuel Evaluator.

• Environmental Planner—Provides access to evaluation

and presentation capabilities of the Acid Rain Advisor.

• Coal-Cleaning Expert—Establishes the feasibility of

cleaning a coal, determines cleaning processes, andpredicts associated costs.

Software Description

The CQETM includes morthe data generated in the CQETM design philosophy flexibility by modeling alment and systems and thesituations. This level of scations to be added by asjects interact. Updated inshared among all affected work-aware, enabling useshare data and results. Thsign, coupled with an objtem, allows different viewstaff efficiency is enhanceCQETM also can be expanthe system. Object-orientobjects to be added and ohanced easily. For exampare made with respect to p(i.e., slagging and fouling

object that provides these augmented. Other object(e.g., ash collection and d

systems) do not need to bthe underlying system is m

System Requirements

CQETM currently uses the 

developers are planning t

platform. CQETM can opsingle computer or on a navailable from Black & V

Commercial Applicati

The CQETM system is appgeneration plants and largthat burn pulverized coalsuppliers, environmental regulatory institutions, antional markets for CQETM Inc. and Black & Veatch.
Coal Processing for Clean Fuels 

EPRI owns the software and distributes CQETM to EPRImembers for their use. CQETM is available to others inthe form of three types of licenses: user, consultant, andcommercializer. 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 CQETM software. Two U.S. utilities have beenlicensed to use copies of CQETM’s stand-alone Acid RainAdvisor. Over 30 U.S. utilities and one U.K. utility haveCQETM through their EPRI membership. Over 100 utilities and coal companies are now using CQETM. Proposals are pending with several non-EPRI-member U.S. andforeign utilities to license their software.The CQETM team has a Home Page on the World WideWeb (http://www.fuels.bv.com:80/cqe/cqe.htm) and usesthe EPRI Fuels Web Server to promote CQETM, facilitate

New England Power

Five utilities acted as hosts for field tests of CQETM.

communications between CQETM developers and users, and eventually allow softwareupdates to be distributed over the Internet.It also makes availablean on-line updatableuser’s manual. TheHome Page also helpsattract the interest ofinternational utilitiesand consulting firms.CQETM was recognizedby the Secretary ofEnergy and the President of EPRI in 1996 asthe best of nine DOE/EPRI cost-shared utilityresearch and development projects under the“Sustainable ElectricPartnership” program.

Contacts ContactsContactsClark 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

References

• Final Report: Development of a Coal Quality Expert.

CQ Inc. June 20, 1998.

• Harrison, Clark D. et al. “Recent Experience with the

CQETM.” Fifth Annual Clean Coal Technology Conference: Technical Papers. January 1997.

• CQETM Users Manual, CQETM Home Page at

http://www.fuels.bv.com/unused/cqe/cqe.htm.

• Comprehensive Repo

Technology Program

ity Expert. ABB Com

CQ Inc. Report No. ment of Energy. MaDE90010381.)
5-144 Program Update 2000 

Coal Processing for Clean Fuels

Mild Gasification

ENCOAL® Mild Coal Gasifica- Mild Coal Gasification Project tion Project

Project completed. Project completed.Participant

ENCOALCorporation (a wholly owned subsidiary of

Bluegrass Coal Development Company)

Additional Team Members

Bluegrass Coal Development Company (a wholly owned

subsidiary of AEI Resources, Inc.)—cofunder

SGI International—technology developer, owner,

licensor

Triton Coal Company (a wholly owned subsidiary of

Vulcan Coal Company)— host

Location LocationLocationNear 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/Production

1,000 tons/day of subbituminous coal feed

Project Funding

Total project cost $90,664,000 100%DOE 45,332,000 50Participant 45,332,000 50

Project Objective

To demonstrate the integrated operation of a number ofnovel processing steps to produce two higher-heating

value fuel forms from mild gasification of low-sulfursubbituminous coal, and to provide sufficient products forpotential end users to conduct burn tests.Technology/Project DescriptionCoal is fed into a rotary grate dryer where it is heated toreduce moisture. The temperature is controlled so that nosignificant amounts of methane, CO2, or CO are released.

The solids are then fed to the pyrolyzer where the temperature is about 1,000 °F, and all remaining water isremoved. A chemical reaction releases the volatile gaseous material. Solids exiting the pyrolyzer are quenchedto stop the pyrolysis reactions.In the original process, the quench table solids were further cooled in a rotary cooler and transferred to a surgebin. A single 50% flow rate vibrating fluidized bed

(VFB) was added to stabi(PDF®) with respect to ox

partially cooled, pyrolyzecontaining a controlled amdative deactivation,” a reasites on the particles, reduous ignition.Following the VFB, the sspheric temperature in an water is added to rehydra

suppressant is added as th

The hot gas produced in tcyclone for removal of thin a quench column to stotions and to condense the 

ENCOAL, LFC, CDL, and PDF are registered trademarks of SGIInternational and Bluegrass Coal Development Company.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels 

Results Summary

Environmental Environmental

• The PDF® contains 0.36% sulfur with a heat content of

11,100 Btu/lb (compared with 0.45% sulfur and 8,300Btu/lb for the feed coal).

• The CDL® contains 0.6% sulfur and 140,000 Btu/gal

(compared with 0.8% sulfur and 150,000 Btu/gal forNo. 6 fuel oil).

• In utility applications, PDF® enabled reduction in SO2

emissions, reduction in NOx emissions (through flame

stabilization), and maintenance of boiler rated capacitywith fewer mills in service.

• LFC® products contained no toxins in concentrations

anywhere close to federal limits.

Operational Operational

• Steady-state operation exceeding 90% availability was

achieved for extended periods for the entire plant(numerous runs exceeded 120 days duration).

• The LFC® process consistently produced 250 tons/day

of PDF® and 250 barrels/day of CDL® from 500 tons/

day of run-of-mine PRB coal.

• Integrated operation of the LFC® process components

over five years has provided a comprehensive databasefor evaluation and design of a commercial unit.

• Over 83,500 tons of PDF® were shipped via 17 unit

trains and one truck shipment to seven customers insix states. Shipments included 100% PDF® and blends

from 14–94% PDF®.

• PDF®, alone and in blends, demonstrated excellent

combustion characteristics in utility applications,providing heating values comparable to bituminouscoal, more reactivity than bituminous coal, and astable flame.

• The low-volatile PDF® also showed promise as a

reductant in direct iron reducing testing and also as ablast furnace injectant in place of coke.

• Nearly 5 million gallons of CDL® were produced and

shipped to eight customers in seven states.

• CDL® demonstrated 

sulfur No. 6 fuel oil lower sulfur content. content, however, ma

chemical feedstock.

Economic EconomicEconomic• A commercial plant 

tons per day would c(2,001$) to constructtenance costs of $52 

Design and Construction Operation and Reporting

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Cooperative agreement awarded 9/17/90

DOEselectedproject(CCT-III)12/19/89

NEPA process completed (EA) 8/1/90

Ground breaking/construction started 10/26/90

Operation initiated 7/92

Construction completed 6/92

Preoperational tests initiated 4/92

Design completed 7/91

Environmental monitoring plan completed 5/29/92

12/89 9/90 7/92

Preaward PreawardPreaward

Operation 
5-146 Program Update 2000 

Project Summary

Operational Performance

The LFC® facility operated for more than 15,000 hoursover a five-year period. Steady-state operation was maintained for much of the demonstration with availabilitiesof 90% for extended periods. The length of operationand volume of production proved the soundness anddurability of the process.Exhibit 5-49 summarizes ENCOAL’s production history.By the end of the demonstration, over 83,500 tons ofPDF® were shipped via 17 unit trains and one truck shipment to seven customers in six states. Shipments included 100% PDF® and blends from 14–94% PDF®.

Over 5 million gallons of CDL® were produced and

shipped to eight customers in seven states.PDF® Product. As with most demonstrations, however,

success required overcoming many challenges. The mostdifficult challenge was achieving stability of the PDF®

product, which had to be resolved in order to achievemarket acceptance.In June 1993, efforts ceased in trying to correct persistentPDF® stability problems within the bounds of the original

plant design. The rotary cooler failed to provide thedeactivation necessary to quell spontaneous ignition ofPDF®. ENCOAL concluded that a separate, sealed vesselwas needed for product deactivation. A search for asuitable design led to adoption of a VFB. A 500-ton/dayVFB was installed between the quench table and rotarycooler. (Plans were made for installation of a second 500ton/day VFB but were never implemented.)Although the VFB enhanced deactivation, the PDF stillrequired “finishing” to achieve stabilization. Extensivestudy revealed that more oxygen was needed for deactivation. Two courses of action were pursued: (1) development of interim measures to finish deactivation externalto the plant, enabling immediate PDF® shipment for test

burns; and (2) development of an in-plant process forfinishing, eliminating product quality and labor penaltiesfor external finishing.

“Pile layering” was the primary external PDF® finishing

measure adopted. However, PDF® quality becomes somewhat impaired due to changes in size, moisture, and ash

content.Pursuit of a finishing process step resulted in establishment of a stabilization task force composed of privatesector and government engineers and scientists. Theoutcome was construction and testing of a Pilot Air Stabilization System (PASS) to complete the oxidative deactivation of PDF®. The PASS controls temperature and

humidity during forced oxidation. The data obtainedwere used to develop specifications and design requirements for a full-scale, in-plant PDF® finishing unit based

upon a commercial (Aeroglide) tower dryer design.CDL® Product. The first shipment of ENCOAL’s liquid

product experienced unloading problems. The use of heattracing and tank heating coils solved the unloading problems for subsequent customers. The CDL® also contained more solids and water than had been hoped for, but

was considered usable as a lower grade oil.Following VFB installation, CDL® quality improved. The

pour point ranged from 75–95 oF, and the flash point

averaged 230 oF, both witcontent was down to 1–2Improvements resulted frand lower pyrolysis tempflow rates enabled by a ne

Environmental Perfor

PDF® Product. PDF® of

Powder River Basin coal In fact, the LFC® process 

sulfur, making the PDF® p

parent coal on a Btu basisin ash, PDF® ash levels re

ing, even though the ash lfrom one ton of ROM coaPDF®).

Dust emissions were not 

suppressant (MK) was sp

surface as it leaves the sto

narrower particle size disa larger fines content but dust range than ROM coa

Pre-VFB Pre-VFB Post-VFB Post-VFBPost-VFB

1992 1993 1994 1995 1996 

Raw Coal Feed (tons)5,200 12,400 67,500 65,800 68,000 PDF® Produced (tons)2,200 4,900 31,700 28,600 33,300 

PDF® Sold (tons)0 0 23,700 19,100 32,700 CDL® Produced (bbl)2,600 6,600 28,000 31,700 32,500 Hours on Line 314 980 4,300 3,400 3,600 Average Length ofRuns (Days)2 8 26 38 44 

1Through June 1997.

Exhibit 5-49

ENCOAL Production
Coal Processing for Clean Fuels 

ENCOAL’s test burn shipments became internationalwhen Japan’s Electric Power Development Company(EPDC) evaluated six metric tons of PDF® in 1994. The

EPDC, which must approve all fuels being considered forelectric power generation in Japan, found PDF® acceptable for use in Japanese utility boilers.

In October 1996, instrumented combustion testing wasconducted at the Indiana-Kentucky Electric Cooperative’s (IKEC) Clifty Creek Station, Unit #3. Important findings included the following:• Full generating capacity using PDF® was possible with

one mill out of service, which was not possible usingthe baseline fuel. Operation using PDF® afforded time

to perform mill maintenance and calibration withoutlosing capacity or revenues, increasing capacity factorand availability, and decreasing operation and maintenance costs.

• NOx emissions were reduced by 20% due to high

PDF® reactivity, resulting in almost immediate ignition

upon leaving the burner coal nozzle. Furthermore,PDF® sustained effective combustion (maintaining lowloss on ignition) with very low excess oxygen, whichis conducive to low NOx emissions.

• PDF® use precipitated increased ash deposits in the

convective pass that were wetter than those resultingfrom baseline coal use, requiring increased sootblowing to control build-up.

CDL® Product. The CDL® liquid product is a low-sulfur,

highly aromatic, heavy liquid hydrocarbon. CDL® fuel

characteristics are similar to those of a low-sulfur No. 6fuel oil, except that the sulfur content is significantlylower. CDL®’s market potential as a straight industrial

residual fuel, however, appears limited. The market forCDL® as a fuel never materialized, and CDL® has limited

application as a blend for high-sulfur residual fuels due toincompatibility of the aromatic CDL® with many straightchain hydrocarbon distillates.

ENCOAL determined that a centrifuge was needed toreduce solids retention and improve marketability of

CDL® (tests validated a 90% removal capability); and an

optimum slate of upgraded products was identified. Theupgraded products were: (1) crude cresylic acid, (2) pitch,(3) refinery feedstock (low-oxygen middle distillate), and(4) oxygenated middle distillate (industrial fuel).Economic EconomicEconomicThe “base case” for economics of a commercial plant isthe 15,000-metric-ton/day, three-unit North RochelleLFC® plant, the commercial-scale plant proposed by

ENCOAL, with an independent 80-MWe cogenerationunit, and no synthetic fuel tax credit (29c tax credit). It isassumed that the cogeneration unit is owned and operatedby an independent third party. The capital cost for a fullscale, three-module LFC® plant is $475 million.

Economic benefits from an LFC® commercial plant are

derived from the margin in value between a raw, unprocessed coal and the upgraded products, making an LFC®

plant dependent on the cost of feed coal. In fact, this isthe largest single operating cost item. The total estimatedoperating cost is $9.00/ton of feed coal including the costof feed coal, chemical supplies, maintenance, and labor.

Commercial Applications

In a commercial application, CDL® would be upgraded to

cresylic acid, pitch, refinery feedstock, and oxygenatedmiddle distillate. Oxygenated middle distillate, the lowest value by-product, would be used in lieu of natural gasas a make-up fuel for the process (30% of the processheat input). PDF® would be marketed not only as a boiler

fuel but as a supplement to or substitute for coke in thesteel industry. PDF® characteristics make it attractive tothe metallurgical market as a coke supplement in pulverized-coal-injection and granular-coal-injection methods,and as a reductant in direct reduced iron processes.Partners in the ENCOAL® project completed five detailed

commercial feasibility studies over the course of thedemonstration and shortly thereafter—two Indonesian,one Russian, and two U.S. projects. A U.S. project hasreceived an Industrial Siting Permit and an Air QualityConstruction Permit, but the project is on hold due to lackof funding.

Contacts ContactsContactsJames P. Frederick, (307

SGI International319 South Gillette AP.O. Box 3038Gillette, WY 82717(307) 686-2894 (fax)

Douglas Archer, DOE/HDouglas M. Jewell, NET

References

• ENCOAL® Mild Gas

Feasibility Study. U

tember 1997. Reporable from NTIS as D

• Final Design Modifi

of Energy. Septembe27339-5797. (Availa

• ENCOAL® Mild Gas

Project Final Report

5798. U.S. Departm(Available from NTI

• Johnson, S.A., and K

PDF® Test Burn at C

ment of Energy Topic

• ENCOAL® Mild Coa

Project Public Desig

port No. DOE/MC/2tion. December 199DE95009711.)
5-148 Program Update 2000 
Industrial Applications 

Industrial Industrial Industrial Industrial Industrial Applications Applications Applications
5-150 Program Update 2000 

Industrial Applications

Clean Power from IntegratedCoal/Ore Reduction(CPICORTM) (CPICORTM)

Participant

CPICORTM Management Company LLC (a limited liability company composed of subsidiaries of the GenevaSteel Company)

Additional Team Members

Geneva Steel Company—cofunder, constructor, host,and operator of unitLocation LocationLocationVineyard, Utah County, UT (Geneva Steel Co.’s mill)TechnologyHIsmelt® direct iron-making process

Plant Capacity/Production

3,300 ton/day liquid iron productionCoalBituminous, 0.5% sulfur

Project Funding

Total project cost $1,065,805,000 100%

DOE 149,469,242 14Participant 916,335,758 86

Project Objective

To 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 metal

and slag from iron ore fines and non-coking coals. Theheart of the process is producing sufficient heat and

maintaining high heat transfer efficiency in the postcombustion zone above the reaction zone to reduce andsmelt iron oxides. The HIsmelt® process uses a vertical

smelt reduction reactor, which is a closed molten bathvessel, into which iron ore fines, coal, and fluxes areinjected. The coal is injected into the bath where carbonis dissolved rapidly. The carbon reacts with O2 (from theiron ore) to form CO and metallic iron. Injection gasesand evolved CO entrain and propel droplets of slag andmolten iron upward into the post-combustion zone.The iron reduction reaction in the molten bath isendothermic; therefore, additional heat is needed to sustain the process and maintain hot metal temperature. Thisheat is generated by post-combusting the CO and hydrogen from the bath with an O2-enriched hot air blast from

the central top lance. The heat is absorbed by the slag

and molten iron droplets, by gravity. Droplets in cocombustion zone absorb hdescent by ascending redwith bath carbon, prevent the slag. The molten iron bath and is continuously ta fore-hearth, which mainthe reactor. Slag, which iconventional blast furnacand control the internal cheat loss. Reacted gases, 

H2O, exit the vessel. Afte

the cleaned gases will be of power and can be used the incoming iron ore.

HIsmelt is a registered trademark of HIsmelt Corporation Pty Limited.CPICOR is a trademark of the CPICORTM Management Company, LLC.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Industrial Applications 

Project Status/Accomplishments

The cooperative agreement was awarded on October 11,1996. CPICORTM analyzed the global assortment of newdirect iron-making technologies to determine which technology would be most adaptable to western U.S. coalsand raw materials. Originally, the COREX® process

appeared suitable for using Geneva’s local raw materials;however, lack of COREX® plant data on 100% raw coals

and ores prevented its application in this demonstration.Thus, CPICORTM chose to examine alternatives. Theprocesses evaluated included: AISI direct iron-making,DIOS, Romelt, Tecnored, Cyclonic Smelter, andHIsmelt®. The HIsmelt® process appears to offer good

economic and operational potential, as well as the prospect of rapid commercialization. CPICORTM has completed testing of two U.S. coals at the HIsmelt® pilot plant

near Perth, Australia.Project definition, preliminary design, and environmentalpermitting are ongoing. On July 28, 1999, DOE issued aNotice of Intent to prepare an Environmental ImpactStatement for the project. A NEPA public scoping meeting was held in Provo, Utah on July 15, 1999.

On February 1, 1999, Geneva Steel Company (CPICORTM

Management Company’s parent corporation) filed a voluntary petition for bankruptcy under Chapter 11 of theUnited States Bankruptcy Code in the U.S. BankruptcyCourt for the District of Utah. Geneva Steel is expected toemerge from Chapter 11 bankruptcy in early 2001 with arestructured balance sheet that enables full participationin this demonstration project.

Commercial Commercial Applications

The HIsmelt® technology is a direct replacement for

existing blast furnace and coke-making facilities withadditional potential to produce steam for power production. Of the existing 79 coke oven batteries, half are 30years of age or older and are due for replacement or majorrebuilds. 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. Two

pilot plants have been built, one in Germany in 1984 and

one in Kwinana, AustraAustralia, the process hcontrol parameters have computer models have bproven.

1993 1997 2001 1994 1996 2002 2003 2004 2005 

DOE selected project(CCT-V) 5/4/93

5/93

Preaward PreawardPreaward

Cooperative agreement awarded 10/11/96

NEPA process completed 12/01*

Construction started 12/01*

Design and Construction

Operation initiated 5/04*Construction completed 5/0

Operation and R

re

**

Environmental monitoring

plan completed 9/03*

5/04

**

10/96 
5-152 Program Update 2000 

Industrial Applications

Pulse Combustor DesignQualification Test

Participant

ThermoChem, Inc.

Additional Team Member

Manufacturing and Technology Conversion International, Inc. (MTCI)—technology supplierLocation LocationLocationBaltimore, MD (MTCI Test Facility)TechnologyMTCI’s Pulsed EnhancedTM Steam Reforming processusing a multiple resonance-tube pulse combustor.

Plant Capacity/Production

30 million Btu/hr (steam reformer)CoalBlack Thunder (Powder River Basin) subbituminous

Project Funding

Total project cost $8,612,054 100%DOE 4,306,027 50Participants 4,306,027 50

Project Objective

To demonstrate the operational/commercial viability of asingle 253-resonance-tube pulse combustor unit andevaluate characteristics of coal-derived fuel gas generatedby an existing Process Data Unit.Technology/Project DescriptionMTCI’s Pulsed EnhancedTM Steam Reforming processincorporates an indirect heating process for thermochemical steam gasification of coal to produce hydrogen-rich,clean, medium-Btu content fuel gas without the need foran oxygen plant. Indirect heat transfer is provided by

immersing a multiple resonance-tube pulse combustor ina fluidized-bed steam gasification reactor. Pulse combustion increases the heat transfer rate by a factor of 3 to 5,thus greatly reducing the heat transfer area required in thegasifier.The pulse combustor represents the core of the PulsedEnhancedTM Steam Reforming process because it provides a highly efficient and cost-effective heat source.Demonstration of the combustor at the 253-resonancetube commercial scale is critical to market entry. The253-resonance-tube unit represents a 3.5:1 scale-up fromprevious tests. Testing will seek to verify scale-up criteriaand appropriateness of controls and instrumentation.Also, an existing process data unit will be used to gasifycoal feedstock to provide fuel gas data, including energycontent, species concentration, and yield. Char from theprocess data unit will be evaluated as well.

The facility will also have includes two stages of cyscrubber tank, and a gas qheat exchanger will be usdensation of excess steam quenched in the venturi sAll project testing will be facility in Baltimore, Mar

Pulsed Enhanced is a trademark of MTCI.
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Calendar Year

Industrial Applications 

Project Status/Accomplishments

On September 10, 1998, DOE approved revision ofThermoChem, Inc.’s Cooperative Agreement for a scaleddown project. The original project, awarded in October1992, was a commercial demonstration facility that wouldemploy 10 identical 253-resonance-tube pulse combustorunits. After fabrication of the first combustor unit, theproject went through restructuring. The revised projectwill demonstrate a single 253-resonance-tube pulse combustor. NEPA requirements were satisfied on November30, 1998, with a Categorical Exclusion. The first majormilestone was completion of the design on February 15,1999.Construction of the 253-resonance-tube combustor unit iscontinuing. Operation is expected to begin in November2000. Shakedown tests of the process data unit wereconducted in April 2000. Following modifications toimprove operability, PDU tests with Black Thunder subbituminous coal are expected to be completed in December 2000.

Commercial Commercial Applications

PulsedEnhancedTM 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.Although the project will demonstrate mild gasificationonly, the following coal-based applications areenvisioned:• Coal processing for combined-cycle power generation,• Coal processing for fuel cell power generation,• Coal pond waste and coal rejects processing to produce

a hydrogen-rich gas from the steam reformer for use inoverfiring or reburning to reduce NOx emissions,

• Coal processing for p

and char for the steel tion of iron ore,

• Coal processing for p• Mild gasification of • Coprocessing of coa• Coal drying.In addition, the technololiquor processing and chous, low-level radioactivolume reduction and d

1991 1992 1993 1994 1997 1998 1999 

Preaward PreawardPreaward

1995 1996

9/91 10/92

DOE selectedproject (CCT-IV)9/12/91

Cooperative agreementawarded 10/27/92

Project relocationrequested 10/26/94

Design and Construction

Revised Cooperative Agreement

Awarded 9/29/98

Co

ope

Design complete 2/15/99

Restructuring complete

3/21/98

En

NEPA process completed 11/98
5-154 Program Update 2000 

TO STEEL MAKING

Industrial Applications

Blast Furnace Granular-Coal Blast Furnace Granular-CoalInjection System Demonstra- Injection System Demonstration Project tion Project

Project completed. Project completed.Participant

Bethlehem Steel Corporation

Additional Team Members

British 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)

Location LocationLocationBurns Harbor, Porter County, IN (Bethlehem Steel’s

Burns Harbor Plant, Blast Furnace Units C and D)

TechnologyBritish Steel and Clyde Pneumatic blast furnace granularcoal injection (BFGCI) process

Plant Capacity/Production

7,000 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 Funding

Total project cost $194,301,790 100%DOE 31,824,118 16Participant 162,477,672 84

Project Objective

To demonstrate that granular coal could effectively displace coke and maintain established blast furnace production rates and quality specifications; to determine the effect of coal chemistry, such as ash content (quantity and sulfur levels) and volatile levels, on blast furnace perfor- mance; and to evaluate the economics of granular coal injection relative to natural gas injection. Technology/Project Description The BFGCI process uses granular coal, which requires significantly less grinding energy than pulverized coal to produce. The coal, along with heated air, is blown into the lower part of the blast furnace through passages called tuyeres, which create swept zones in the furnace called raceways. This preheated blast air provides partial oxida- tion of the coke introduced along with the iron ore and limestone at the top of the furnace. The coke serves as the primary fuel and reducing agent for the process. The carbon reacts with the air and the iron oxide ore to pro- duce heat, iron, and carbo

acts as a fluxing agent, crconstituents such as sulfuproduct. The low-Btu gatially free of sulfur and is a boiler for on-site powerBethlehem Steel introducreduce the amount of cokwhich also replaced the nthe tuyeres for supplementoxics emissions result froextensive, expensive contretrofitted Units C and D rated at 7,000 NTHM/daymine the effect of coal sizprocess performance and 
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Calendar Year

Industrial Applications 

1989 1990 1991 1993 1994 1995 1996 1997 1998 

Preaward PreawardPreaward

DOE selectedproject (CCT-III)12/19/89

12/89 11/90

Cooperative agreement awarded 11/26/90

Design and Construction Operation and Reporting

final 

Operation completed 1

**

NEPA process completed (EA) 6/8/93

Construction started 9/93

Design completed 12/93

Environmental monitoring plan completed 12/23/94

Construction completed 1/95

Preoperational tests initiated 2/95

Operation initiated 11/95

11/95

Results Summary

Environmental Environmental

• BFGCI technology, using low-volatile, low-ash coal,

displaced up to 0.96 pounds of coke for every poundof coal, which avoids the air toxics emissions associated with comparable coke production. By adjustingblast furnace slag, no additional sulfur emissionsresulted from the coal injection, and sulfur levels inthe product remained within the specified range.

Operational Operational

• Granular coal performed as well as pulverized coal on

the large blast furnaces and proved easier to handlethan pulverized coal, which tended to plug when usinglow-volatile coals. Direct comparative testing on aspecific coal showed that 60% less energy is consumed in granulating coal than in pulverizing coal.

• Coal injection decreased furnace permeability, which

can adversely affect hot blast flow rate and furnaceproductivity, but increasing oxygen enrichment and

moisture content returned permeability and productivity 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 for

each 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 EconomicEconomic• 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, natural gas, and nitrogen) were $3.56/ton of coal. Coal

costs were $50-60/tonatural gas cost of $2

would be about $6.5the Burns Harbor proiron per year, the ann
5-156 Program Update 2000 

Project Summary

Bethlehem Steel retrofitted two high-capacity blast furnaces with BFGCI technology, Units C and D, at theirBurns Harbor facility in a successful attempt to reducecoke use and become a self-sufficient supplier. The questions posed in applying the technology went to the effectof coal grind (size) and coal chemistry on coke displacement and furnace performance. A coal pulverizer in lieuof a less energy- and capital-intensive hammer mill, wasused to provide a range of coal grinds from granular (30%passing 200 mesh) to pulverized (80% passing 200mesh). Each 7,000-NTHM/day furnace required approximately 2,800 tons/day of coal. Each BFGCI unit included a raw coal reclaim area and two 240-ton enclosedstorage bins, a 500-Hp Williams variable speed coalgrinding mill and integrated dryer, two 180-ton productcoal silos designed to exclude oxygen, two distributionbins each with 14 conical pant leg distributors, 28 injectors with lock hoppers and metered screw feeders, and ahigh-pressure air system transporting the coal 600 feet toinjection lances mounted on 28 separate tuyeres.

Operational Performance

Initial steady-state testing involved operation on granulated (15% passing 200 mesh) Virginia Pocahontas lowash, low-volatile, high-carbon coal in the Unit C furnace.This coal was selected as the baseline coal after a seriesof trials on different coal types. An average coal injectionrate of 264 lb/NTHM was achieved over the baselineOctober 1996 performance period. The furnace coke rateduring the period was 661 lb/NTHM, down from 740 lb/NTHM when operating on natural gas.Increasing slag volume in the furnace controlled theadditional sulfur and silicon loading from the coal injection to specified levels in the hot metal product. The slagalso captured sufficient sulfur to prevent any additionalsulfur in the furnace gas output. An adverse downturn infurnace permeability resulting from coal injection wasmoderately increased and compensated for by increasingthe oxygen enrichment from 24.4–27.3% and increasing

steam input from 3.7 grains/scf to 19.8 grains/scf. Thepermeability adjustments enabled furnace productivity tobe 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, onlythe percentage of ash was increased, not the coal or ashchemistry. This was done by eliminating a coal cleaningstep on the Pocahontas Seam coal (obtained from theBuchanan Mine), which increased the ash content from5.3–7.7%. Tests showed that there is a coke rate disadvantage of 3 lb/NTHM for each one percentage pointincrease in coal ash content at an injection rate of 260 lb/NTHM; and the higher ash coal had no adverse impact onfurnace permeability, productivity, or product quality.Comparative testing followed to evaluate the effect ofcoal grind size (granular versus pulverized) on coke displacement and furnace performance as well as the effectsof coal chemistry. Furnace D was used because of sometemporary operating difficulties on Furnace C. A highvolatile, low-carbon Oxbow western coal was used in lieuof the baseline coal because of plugging problems experienced when pulverizing the baseline low-volatile coal andbecause there was the need to evaluate the impact ofhigh-volatile coal on furnace performance. The Oxbowcoal averaged 73.2% carbon and 11.2% ash versus 86.3%carbon and 5.3% ash for the baseline coal. The granularOxbow coal grind was 15% passing 200 mesh and thepulverized Oxbow coal grind was 74% passing 200 mesh.Granular coal production required 60% less energy (19.6kWh/ton) than pulverized coal production (31.4 kWh/ton). The grinding mill production rate for pulverizingthe coal limited the coal injection rate to 183 lb/NTHM.After adjusting for the lower coal injection rate and otherfactors, it was determined that the coke rate when usingthe Oxbow coal was 46 lb/NTHM higher than when

using the low-volatile basstantial disadvantage. Thunaffected by whether the at the coal injection rate o

Environmental Perfor

Data collected over each injected coal in the blast fcrease in the sulfur conten0.76% sulfur. Evidence svolume and chemistry cosulfur coals. However, thapplication of the BFGCI coke usage. Coke producto be avoided if at all posthe BFGCI technology, Bsteel production with the rently on site.

Economic Summary

Capital cost for one compHarbor was approximateldoes not include infrastru$87 million at Burns Harbwhich includes labor and coal. The variable operatelectricity, natural gas, ancoal. Coal costs were $5operating costs to $59.81ton of coal and a natural g

cost savings would be abAt Burns Harbor, which pper year, the annual savinand the payback period 3return calculation.

Commercial Commercial Applicati

There are 35 operating blSeventeen of them are alrinjection. An extensive mBethlehem Steel showed 
Industrial Applications 

have 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.Contacts ContactsContactsRobert 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

References

• Bethlehem Steel Corporation. Blast Furnace Granular Coal Injection System, Final Report Volume 2—

Project Performance and Economics. October 1999

• Hill, D.G. et al. “Blast Furnace Granular-Coal Injection

System Demonstration Project.” Sixth Clean Coal

Conference Proceedings: Volume II—Technical Papers.

April–May, 1998.
5-158 Program Update 2000 

Industrial Applications

Advanced Cyclone Combus- Advanced Cyclone Combustor with Internal Sulfur tor with Internal Sulfur, Nitro- , Nitro-, Nitro- , Nitro-, Nitrogen, and gen, and gen, and gen, and gen, and Ash Control Ash Control

Project completed. Project completed.Participant

Coal Tech Corporation

Additional Team Members

Commonwealth of Pennsylvania, Energy Development

Authority—cofunder

Pennsylvania Power and Light Company—supplier of

test coals

Tampella Power Corporation—hostLocation LocationLocationWilliamsport, Lycoming County, PA (Tampella PowerCorporation’s boiler manufacturing plant)TechnologyCoal Tech’s advanced, air-cooled, slagging combustor

Plant Capacity/Production

23 x 106 Btu/hr of steam

CoalPennsylvania bituminous, 1.0–3.3% sulfur

Project Funding

Total project cost $984,394 100%DOE 490,149 50

Participant 494,245 50

Project Objective

To demonstrate that an advanced cyclone combustor canbe retrofitted to an industrial boiler and that it can simultaneously remove up to 90% of the SO2 and 90–95% of

the ash within the combustor and reduce NO

x to 100 ppm.

Technology/Project DescriptionCoal Tech’s horizontal cyclone combustor is lined with anair-cooled ceramic. Pulverized coal, air, and sorbent areinjected tangentially toward the wall through tubes in theannular region of the combustor to cause cyclonic action.In this manner, coal-particle combustion takes place in aswirling flame in a region favorable to particle retentionin the combustor. Secondary air is used to adjust theoverall combustor stoichiometry. Tertiary air is injectedat the combustor/boiler interface. The ceramic liner iscooled by the secondary air and maintained at a temperature high enough to keep the slag in a liquid, free-flowingstate. The secondary air is preheated by the combustorwalls to attain efficient combustion of the coal particles inthe fuel-rich combustor. Fine coal pulverization allowscombustion of most of the coal particles near the cyclonewall. The combustor was designed so that a high percentage of the ash and sorben

tained as slag. For NOx c

ated fuel rich, with final cboiler furnace to which th

captured by injection of lThe cyclonic action insidash and sorbent to the waliquid slag. Under optimcontains a significant fracDownstream sorbent injeadditional sulfur removal In Coal Tech’s demonstracyclone coal combustor w

hr, oil-fired package boileCorporation boiler factory 
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Calendar Year

Industrial Applications 

Results Summary

Environmental Environmental

• SO2 removal efficiencies of over 80% were achieved

with sorbent injection in the furnace at various calcium-to-sulfur (Ca/S) molar ratios.

• SO2 removal efficiencies up to 58% were achieved

with sorbent injection in the combustor at a Ca/Smolar ratio of 2.0.

• A maximum of one-third of the coal’s sulfur was retained in the dry ash removed from the combustor (as

slag) and furnace hearth.

• At most, 11% of the coal’s sulfur was retained in the

slag rejected through the combustor’s slag tap.

• NO

x emissions were reduced to 184 ppm by the combustor and furnace, and to 160 ppm with the addition

of a wet particulate scrubber.

• Combustor slag was essentially inert.

• Ash/sorbent retention in the combustor as slag averaged 72% and ranged from 55–90%. Under more fuellean conditions, retention averaged 80%.• Meeting local particulate emissions standards required

the addition of a wet venturi scrubber.

Operational Operational

• Combustion efficiencies of over 99% were achieved.• A 3-to-1 combustor turndown capability was demonstrated. Protection of combustor refractory with slag

was shown to be possible.

• A computer-controlled system for automatic combustor operation was developed and demonstrated.

Economic EconomicEconomic• Because the technology failed to meet commercialization criteria, economics were not developed during the

demonstration. However, subsequent efforts indicatethat the incremental capital cost for installing the coalcombustor in lieu of oil or gas systems is $100–200/kW.

1986 1989 1990 1987 1988 1991 1992 1993 1994 

Preaward PreawardPreaward

Operation and Reporting

7/86 3/87 11/87

Design and

Construction

DOE selected project (CCT-I) 7/24/86

Design completed 7/87Ground breaking/construction started 7/87

Cooperative agreement awarded 3/20/87NEPA process completed (MTF) 3/26/87

Environmental monitoring plan completed 9/22/87

Construction completed 11/87Operation initiated 11/87

Operation

completed 5/90

9/91

Project completed/final report issued 9/91
5-160 Program Update 2000 

Project Summary

The novel features of Coal Tech’s patentedceramic-lined, slagging cyclone combustorincluded its air-cooled walls and environmental control of NOx, SO2, and solid waste emissions. Air cooling took place in a very compact combustor, which could be retrofitted to

a wide range of industrial and utility boilerdesigns without disturbing the boiler’s watersteam circuit. In this technology, NOx reduction was achieved by staged combustion, and

SO2 was captured by injection of limestone

into the combustor and/or boiler. Critical tocombustor performance was removal of ashas slag, which would otherwise erode boilertubes. This was particularly important in oilfurnace retrofits where tube spacing is tight(made possible by the low-ash content of oilbased fuels).The test effort consisted of 800 hours of operation, including five individual tests, each of four days duration.An additional 100 hours of testing was performed as partof a separate ash vitrification test. Test results obtainedduring operation of the combustor indicated that CoalTech attained most of the objectives contained in thecooperative agreement. About eight different Pennsylvania bituminous coals with sulfur contents ranging from1.0–3.3% and volatile matter contents ranging from 19–37% were tested.

Environmental Performance

A maximum of over 80% SO2 reduction measured at the

boiler outlet stack was achieved using sorbent injection inthe furnace at various Ca/S molar ratios. A maximumSO2 reduction of 58% was measured at the stack with

limestone injection into the combustor at a Ca/S molarratio of 2. A maximum of one-third of the coal’s sulfurwas retained in the dry ash removed from the combustorand furnace hearths, and as much as 11% of the coal’ssulfur was retained in the slag rejected through the slagtap. Additional sulfur retention in the slag is possible by

increasing the slag flow rate and further improving fuelrich combustion and sorbent-gas mixing.With fuel-rich operation of the combustor, a three-fourthsreduction in measured boiler outlet stack NOx was obtained, corresponding to 184 ppm. An additional 5–10%

reduction was obtained by the action of the wet particulate scrubber, resulting in atmospheric NOx emissions as

low as 160 ppm.All the slag removed from the combustor produced tracemetal leachates well below EPA’s Drinking Water Standard.Total ash/sorbent retention as slag in the combustor,under efficient combustion operating conditions, averaged 72% and ranged from 55–90%. Under more fuellean conditions, the slag retention averaged 80%. Afterthe CCT project, tests on fly ash vitrification in the combustor, modifications to the solids injection system, andincreases in the slag flow rate produced substantial increases in the slag retention rate. To meet local stackparticulate emission standards, a wet venturi particulatescrubber was installed at the boiler outlet.

Operational Performa

Combustion efficiencies eating procedures were ach6 x 106 Btu/hr from a pea

turndown) was achieved. ing the tests was around 2

combustor was designed 

boiler was thermally rated 

situation resulted from fafor the boiler. In fact, due cooling, even 20 x 106 Bt

most of the testing was coDifferent sections of the cals requirements. Suitablidentified. Also, the test procedures were closely city. As an example, by imsuch as changing the compossible to replenish the cness with slag produced dadding ceramic to the comThe combustor’s total opeCCT project was about 90mately 100 hours of operation test projects. Of the twith coal; about 125 tons Developing proper combualso a project objective. Nproperly operating an air-but the entire operating dcomputer-controlled systeoperation.

Commercial Commercial Applicati

The goal of this project wof the air-cooled combustthe combustor was not yemercial guarantees, it was potential. Subsequent wobrought the technology cl

The slagging combustor, associated piping, and control panel for CoalTech’s advanced ceramic-lined slagging combustor are shown.
Industrial Applications 

Contacts ContactsContactsBert Zauderer, President, (610) 667-0442

Coal Tech CorporationP.O. Box 154Merion Station, PA 19066coaltechbz@compuserve.com

William E. Fernald, DOE/HQ, (301) 903-9448James U. Watts, NETL, (412) 386-5991

References

• The Coal Tech Advanced Cyclone Combustor Demonstration Project—A DOE Assessment. Report No.

DOE/PC/79799-T1. U.S. Department of Energy. May1993. (Available from NTIS as DE93017043.)

• The Demonstration of an Advanced Cyclone Coal

Combustor, with Internal Sulfur, Nitrogen, and Ash

Control for the Conversion of a 23-MMBtu/Hour Oil

Fired Boiler to Pulverized Coal; Vol. 1: Final Technical Report; Vol. 2: Appendixes I–V; Vol. 3: Appendix

VI. Coal Tech Corporation. August 1991. (Available

from NTIS as DE92002587 and DE92002588.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Advanced Cyclone Combustor

with Internal Sulfur, Nitrogen, and Ash Control. Coal

Tech Corporation. Report No. DOE/FE-0077. U.S.Department of Energy. February 1987. (Availablefrom NTIS as DE87005804.)

Coal Tech’s slagging combustor demonstrated the capability to retain, as slag, a high perceof the non-fuel components injected into the combustor. The slag, shown on the conveyor, essentially an inert, glassy by-product with value in the construction industry as an aggregaand in the manufacture of abrasives.
5-162 Program Update 2000 

Industrial Applications

Cement Kiln Flue GasRecovery Scrubber Recovery Scrubber

Project completed. Project completed.Participant

Passamaquoddy Tribe

Additional Team Members

Dragon Products Company—project manager and hostHPD, Incorporated—designer and fabricator of tanks and

heat exchanger

Cianbro Corporation—constructorLocation LocationLocationThomaston, Knox County, ME (Dragon ProductsCompany’s coal-fired cement kiln)TechnologyPassamaquoddy Technology Recovery ScrubberTM

Plant Capacity/Production

1,450 ton/day of cement; 250,000 scfm of kiln gas; andup to 274 ton/day of coalCoalPennsylvania bituminous, 2.5–3.0% sulfur

Project Funding

Total project cost $17,800,000 100%DOE 5,982,592 34Participant 11,817,408 66

Project Objective

To 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 a commercial by-product, potassiumbased fertilizer by-products.

Technology/Project DescriptionThe Passamaquoddy Technology Recovery ScrubberTMuses cement kiln dust (CKD), an alkaline-rich (potassium) waste, to react with the acidic flue gas. This CKD,representing about 10% of the cement feedstock otherwise lost as waste, is formed into a water-based slurry andmixed with the flue gas as the slurry passes over a perforated tray that enables the flue gas to percolate throughthe slurry. The SO2 in the flue gas reacts with the potassium to form potassium sulfate, which stays in solution

and remains in the liquid as the slurry undergoes separation into liquid and solid fractions. The solid fraction, inthickened slurry form and freed of the potassium andother alkali constituents, is returned to the kiln as feedstock (it is the alkali content that makes the CKD unusable as feedstock). No dewatering is necessary for the wet

process used at the Dragoplant. The liquid fraction uses waste heat in the flurecover dissolved alkali mthe incoming flue gas temevaporation, enables the ustruction material, and prwater through condensatiThe Passamaquoddy Techwas constructed at the DrThomaston, Maine, a planmately 450,000 ton/yr of oped by the Passamaquodseeking ways to solve lanfrom the need to dispose ing process.

Passamaquoddy Technology Recovery Scrubber is a trademark of thePassamaquoddy Tribe.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Industrial Applications 

Results Summary

Environmental Environmental

• The SO2 removal efficiency averaged 94.6% during

the last several months of operation and 89.2% for theentire operating period.

• The NO

x removal efficiency averaged nearly 25%

during the last several months of operation and 18.8%for the entire operating period.

• All of the 250 ton/day CKD waste produced by the

plant was renovated and reused as feedstock, whichresulted in reducing the raw feedstock requirement by10% and eliminating solid waste disposal costs.

• Particulate emission rates of 0.005–0.007 gr/scf, about

one-tenth that allowed for cement kilns, were achievedwith dust loadings of approximately 0.04 gr/scf.

• Pilot testing conducted at U.S. Environmental Protection Agency laboratories under Passamaquoddy Technology, L.P. sponsorship showed 98% HCl removal.

• On three different runs, VOC (as represented by alphapinene) removal efficiencies of 72.3, 83.1, and 74.5%

were achieved.

• A reduction of approximately 2% in CO2 emissions

was realized through recycling of the CKD.

Operational 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 EconomicEconomic• Capital costs are approximately $10,090,000 (1990$)

for a recovery scrubber to control emissions from a450,000-ton/yr wet process plant, with a simple payback estimated in 3.1 years.

• Operation and maintenance costs, estimated at

$500,000/yr, plus capital and interest costs, are generally offset by avoided costs associated with fuel, feedstock, and waste disposal and with revenues from thesale of fertilizer.

1988 1991 1992 1989 1990 1993 1994 1995 1996 

Preaward PreawardPreaward Design and Construction

9/88 8/91

Operation and Reporting

DOEselectedproject(CCT-II)9/28/88

12/89

Design completed 4/90

Environmental monitoring plancompleted 3/26/90

Operation initiated 8/91

Construction completed 5/91Preoperational tests initiated 5/91

NEPA process completed (EA) 2/16/90

Cooperative agreement awarded 12/20/89

2/94

Project completed/final report issued 2/94

Construction started 6/89

Operation

completed 9/93
5-164 Program Update 2000 

Project Summary

The Passamaquoddy Technology Recovery ScrubberTM isa unique process that achieves efficient acid gas andparticulate control through effective contact between fluegas and a potassium-rich slurry composed of waste kilndust. Flue gas passes through the slurry as it moves overa special sieve tray. This results in high SO2 and particulate capture, some NOx reduction, and sufficient uptake of

the potassium (an unwanted constituent in cement) toallow the slurry to be recycled as feedstock. Waste cement kiln dust, exhaust gases (including waste heat), andwastewater are the only inputs to the process. Renovatedcement kiln dust, potassium-based fertilizer, scrubbedexhaust gas, and distilled water are the only proven outputs. There is no waste.The scrubber was evaluated over three basic operatingintervals dictated by winter shutdowns for maintenanceand inventory and 14 separate operating periods (withinthese basic intervals) largely determined by unforeseenhost-plant maintenance and repairs and a depressed cement market. Over the period August 1991 to September1993, more than 5,300 hours were logged, 1,400 hours inthe first operating interval, 1,300 hours in the secondinterval, and 2,600 hours in the third interval. Sulfurloadings varied significantly over the operating periodsdue to variations in feedstock and operating conditions.

Operational Performance

Several design problems were discovered and correctedduring startup. No further problems were experienced inthese areas during actual operation.Two problems persisted into the demonstration period.The mesh-type mist eliminator, which was installed toprevent slurry entrainment in the flue gas, experiencedplugging. Attempts to design a more efficient water sprayfor cleaning failed. However, replacement with a chevron-type mist eliminator prior to the third operating interval was effective. Potassium sulfate pelletization provedto be a more difficult problem. The cause was eventuallyisolated and found to be excessive water entrainment due

to carry-over of gypsum and syngenite. Hydrocloneswere installed in the crystallizer circuit to separate thevery fine gypsum and syngenite crystals from the muchcoarser potassium sulfate crystals. Although the correction was made, it was not completed in time to realizepellet production during the demonstration period. Afterall modifications were completed, the recovery scrubberentered into the third and final operating interval—Aprilto September 1993. During this interval, recovery scrubber availability (discounting host site downtime) steadilyincreased from 65% in April to 99.5% in July.

Environmental Performance

An average 250 ton/day of CKD waste generated by theDragon Products plant was used as the sole reagent in the

recovery scrubber to treat flue gas. All the CKD, or renovated and returned to mixed with about 90 ton/required 100 ton/hr. The verted to potassium-based waste. Exhibit 5-50 lists ing period, SO2 and NOx 

pounds per hour, and remfor each operating periodAverage removal efficienperiod were 89.2% for SO

No definitive explanation 

was available at the concl

Exhibit 5-50

Summary of Emissions and Removal Eff

Operating OperatingOperating Operating OperatingOperating Inlet (lb/hr) Outlet (lb/hr) Period

Time (hr) ime (hr)ime (hr) SO2 NOx SO2 NOx 

1 211 73 320 10 279 2 476 71 284 11 260 

3 464 87 292 13 251 4 259 131 252 16 165 5 304 245 293 28 243 6 379 222 265 28 208 7 328 281 345 28 244 8 301 124 278 10 188 9 314 47 240 7 194 10 402 41 244 6 218 11 460 36 315 6 267 12 549 57 333 2 291 13 464 86 288 4 223 14 405 124 274 9 199 Total operating time 5,316Weighted eighted eighted eighted eighted 

Average 109 289 12 234 
Industrial Applications 

Aside from the operating period emissions data, an assessment was made of inlet SO2 load impact on removal

efficiency. For SO2 inlet loads in the range of 100 lb/hr

or less, recovery scrubber removal efficiency averaged82.0%. For SO2 inlet loads in the range of 100–200 lb/hr,

removal efficiency increased to 94.1% and up to 98.5%for loads greater than 200 lb/hr.In compliance testing for Maine’s Department of Environmental Quality, the recovery scrubber was subjected to

dust loadings of approximately 0.04 gr/scf and demonstrated particulate emission rates of 0.005–0.007 gr/scf—less than one-tenth the current allowable limit.

Economic Performance

The estimated “as-built” capital cost to reconstruct theDragon Products prototype, absent the modifications, is$10,090,000 in 1990 dollars.

Annual operating and maintenance costs are estimated at$500,000. Long-term annual maintenance costs are estimated at $150,000. Power costs, estimated at $350,000/yr, are the only significant operating costs. There are nocosts for reagents or disposal, and no dedicated staffing ormaintenance equipment is required.The simple payback on the investment is projected in aslittle as 3.1 years considering various revenues andavoided costs that may be realized by installing a recovery scrubbersimilar in size to the one used at Dragon

Products. In making this projection, $6,000,000 wasadded to the “as-built” capital costs to allow for contingency, design/permitting, construction interest, and licensing fees.

Commercial Commercial Applications

Of the approximately 2,000 Portland cement kilns in theworld, about 250 are in the United States and Canada.These 250 kilns emit an estimated 230,000 ton/yr of SO2

(only three plants have SO2 controls, one of which is the

Passamaquoddy Technology Recovery ScrubberTM). Theapplicable market for SO2 control is estimated at 75% of

the 250 installations. If full penetration of this estimatedmarket were realized, approximately 150,000 ton/yr ofSO2 reduction could be achieved.

The scrubber became a permanent part of the cementplant at the end of the demonstration. A feasibility studyhas been completed for a Taiwanese cement plant.Contacts ContactsContactsThomas 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

The Passamaquoddy Technology Recovery ScrubberTM wassuccessfully demonstrated at Dragon Products Company’scement plant in Thomaston, Maine.

References

• Passamaquoddy Tech

Final Report. Volum

Passamaquoddy Tribable from NTIS as DDE94011176.)

• Passamaquoddy Tech

Public Design Repor

T2. Passamaquoddy from NTIS as DE940

• Passamaquoddy Tec

Topical Report. Rep

Passamaquoddy TribNTIS as DE9201986

• Comprehensive Repo

Technology Program

Scrubber. Passamaq

FE-0152. U.S. Depa1989. (Available fro
5-166 Program Update 2000 
Appendix A: Historical Perspective and Appendix A: Historical Perspective and

Legislative History Legislative History Legislative History

Historical Perspective Historical Perspective

There were a number of key events that promptedcreation of the CCT Program and impacted its focusover the course of the five solicitations. The roots ofthe CCT Program can be traced to the acid raindebates of the early 1980s, culminating in U.S. andCanadian envoys recommending a five-year, $5 billionU.S. effort to curb precursors to acid rain formation—SO2 and NOx. This recommendation was adopted and

became a Presidential initiative in March 1987.As a part of the response to the recommendations ofthe Special Envoys on Acid Rain in April 1987, the

President directed the Secretary of Energy to establisha panel to advise the President on innovative cleancoal technology activities. This panel was theInnovative Control Technology Advisory Panel. As apart of the panel’s activities, the state and federalincentive subcommittee prepared a report, Report to

the Secretary of Energy Concerning Commercialization Incentives, that addressed actions that states

could take to provide incentives for demonstratingand deploying clean coal technologies. The paneldetermined that demonstration and deploymentshould be managed through both state and federalinitiatives.In the same time frame, the Vice President’s Task Forceon Regulatory Relief (later referred to as the Presidential

Task Force on Regulatory Relief) was established.Among other things, the task force was asked toexamine incentives and disincentives to the commercialrealization of new clean coal technologies. The taskforce also examined cost-effective emissions reductionmeasures that might be inhibited by various federal,state, and local regulations. The task force recommended that preference be given to projects located instates 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 SO2and NOx emissions from existing coal-based powergenerators. Approaches demonstrated through theprogram were coal processing to produce clean fuels,combustion modification to control emissions,postcombustion cleanup of flue gas, and repoweringwith advanced power generation systems. Theseearly efforts (projects resulting from the first threesolicitations) produced a suite of cost-effectivecompliance options available today to address acidrain concerns.As the CCT Program evolved, work began on draftingwhat was to become the Clean Air Act Amendmentsof 1990. Through a dialog with EPA and Congress,the program was able to remain responsive to shifts inenvironmental emphasis. Also, projects in placeenabled CAAA architects to have access to real-timedata on emission control capabilities while structuring

proposed acid rain regCAAA.Aside from acid rain, tthe area of hazardous referred to as air toxic189 airborne compountrace elements and volpounds. To assess the generation, CCT Progobtain data through an EPA, EPRI, and the UtThrough this effort, ccoal-based power genmitigated, enabling foconstituents. Also, beozone formation, the p

nonattainment areas, eissue. This precipitateinclude technologies cthe portfolio of technIn the course of the laProgram, a number of considerations combintoward seeking high-epower generation techprojections in the Unicontinued reliance on with significant growtThe CAAA, however, 2000 levels, and NOx attention relative to oz
A-2 Program Update 2000

more, particulate emissions were coming underincreased scrutiny because of correlations with lungdisorders and the tendency for toxic compounds toadhere to particulate matter. Added to these concernswas the growing concern over global warming, andmore specifically, the CO2 produced from burning

fossil fuels. Coal became a primary target because ofthe high carbon-to-hydrogen ratio relative to naturalgas, resulting in somewhat higher CO2 emissions per

unit of energy produced. However, coal is the fuel ofchoice (if not necessity) for many developing countries where projected growth in electric power generation is the greatest. The path chosen to respond tothese considerations was to pursue advanced powergeneration systems that could provide major enhancements in efficiency and control SO2, NOx, and particulates without introducing external parasitic control

devices. (Increased efficiency translates to less coalconsumption per unit of energy produced.) As aresult, a number of advanced power generationprojects were undertaken, representing pioneer effortsrecognized throughout the world.

Legislative History Legislative History

The legislation authorizing the CCT Program is foundin Public Law 98-473, Joint Resolution MakingContinuing Appropriations for Fiscal Year 1985 andfor Other Purposes. Title I set aside $750 million of thecongressionally rescinded $5.375 billion of theSynthetic Fuels Corporation into a special U.S.Treasury account entitled the “Clean Coal TechnologyReserve.” This account was dedicated to “conducting cost-shared clean coal technology projects for theconstruction and operation of facilities to demonstratethe feasibility of future commercial applications of

such technology.” Title III of this act directed theSecretary of Energy to solicit statements of interest inand proposals for clean coal projects. In keeping withthis mandate, DOE issued a program announcement,which resulted in the receipt of 176 proposals representing both domestic and international projects witha total estimated cost in excess 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 beselected through a competitive solicitation, or ProgramOpportunity Notice (PON), referred to as CCT-I. (Theremaining funds were required for program directionand the legislatively mandated Small BusinessInnovation Research Program [SBIR] and SmallBusiness Technology Transfer Program [STTR].)In a manner similar to the initiation of CCT-I, Congressagain directed DOE to solicit information from theprivate sector in the Department of the Interior andRelated Agencies Appropriations Act for FY1987(Public Law 99-591), enacted October 30, 1986). Theinformation received was to be used to establish thelevel of potential industrial interest in another solicitation, this time involving clean coal technologiescapable of retrofitting, repowering, or modernizingexisting facilities. Projects were to be cost-shared,with industry sharing at least 50 percent of the cost.As a result of the solicitation, a total of 39 expressionsof interest were received by DOE in January 1987.On March 18, 1987, the President announced theendorsement of the recommendations of the SpecialEnvoys on Acid Rain, including a $2.5 billion government share of funding for industry/governmentdemonstrations of innovative control technology overa five-year period. The Secretary of Energy stated

that the department woadditional $350 million appropriation of $500 mappropriations of $500 mfiscal years 1990, 1991, made by the President oPublic Law 100-202, enaamended by Public Law of $575 million to conduwas for projects, with thdirection and the SBIR aThe Department of the Appropriations Act for Fenacted September 27, 1necessary expenses asstechnology demonstratiOf the total funding, aboavailable for cost-sharinfor program direction angrams. The act continuproposals must demonsretrofitting or repowerinstatute also authorized Authority power progranonfederal cost-sharingappropriations acts. In Rural Electrification AdUtilities Service) electriFinancing Bank became CCT-III solicitation, exappropriations.In the Department of thcies Appropriations Act enacted October 23, 198million for the CCT-IV sto the act, “shall demonreplacing, retrofitting, oand shall be subject to 
this head in Public Laws 99-190, 100-202 and 100-446as amended by this Act.” About $563 million wasmade available for federal cofunding of projectsselected in CCT-IV, with the remainder for programdirection and the 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 beselected in this solicitation, with the remainder againfor program direction and the SBIR and STTR Programs.Subsequent acts (Public Laws 101-164, 101-302, 101-512, and 102-154) modified the schedule for issuingCCT-IV and/or CCT-V PONs and selecting projects.In Public Law 101-512, Congress directed DOE toissue the PON for CCT-IV not later than February 1,1991, with selections to be made within 8 months. InPublic Law 102-154, Congress directed DOE to issueCCT-V PON not later than July 6, 1992, with selectionsto be made within 10 months. This later act alsodirected that CCT-V proposals should advancesignificantly the efficiency and environmentalperformance of coal-using technologies and beapplicable to either new or existing facilities.Public Laws 101-164, 101-302, 101-512, 103-138, and103-332 adjusted the rate at which funds were to bemade available to the program.CCT Program funds have been further adjustedthrough sequestering requirements of the GrammRudman-Hollings Deficit Reduction Act as well asrescissions. Sequestering reduced CCT Programappropriations as follows:

• $2.4 million was sequestered from the $400 million

appropriated by Public Law 99-190.

• $2,600 was sequestered from the $575 million

appropriated by Public Law 100-202, as amendedby Public Law 100-446.

• $2,028 was sequestered from the $575 million

appropriated by Public Law 100-446, as amendedby Public Law 101-164.

• $455 was sequestered from the $1.2 billion appropriated by Public Law 101-121, as amended by

Public Laws 101-512, 102-154, 102-381, 103-138, 103-332, 104-6, 104-208, and 105-18.

Rescissions have reduced CCT Program appropriations as follows:• $200 million was rescinded by Public Law 104-6.• $123 million was rescinded by Public Law 104-208.• $17 million was rescinded by Public Law 105-18.• $101 million was rescinded by Public Law 105-83.• $38,000 was rescinded by Public Law 106-113

(general reduction).

In 1998, $40 million of the CCT program funds weredeferred by Public Law 105-277. Funds will berestored 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 again in 2000,Congress deferred $67,000,000 until October 1, 2001.Exhibit A-1 lists all the key legislation relating to theCCT Program and provides a summary of provisionsrelating to program funding as well as programimplementation. Following this exhibit are fundingprovisions excerpted from appropriations and otherrelevant funding-related acts.
A-4 Program Update 2000

Exhibit A-1

CCT Program Legislative History

Public DateLaw Enacted Enacted CCT Round Program Funding Implementation Provi

98-473 10/12/84 Initiation of CCT

Program; informationalsolicitation

99-88 8/15/8599-190 12/19/85 CCT-I99-591 10/30/86 Second informational

solicitation

100-202 12/22/87 CCT-II

Title III required publicatstatements of interest in aemploying emerging CCTrequired no later than 4/1Conference Report (H. ReCCT project guidelines c99-82, with certain modifRequired a PON (CCT-I) selected no later than 8/1provisions were detailed.Title II required publicatistatements of interest in, for projects employing emretrofitting, repowering, ofacilities. A report to Cothan 3/6/87.Required a request for prono later than 60 days folloing CCTs capable of retrofacilities. Extended proje160 days after receipt of psharing of pre-award costsion of environmental datcooperative agreement. C100-498) provided that prmade available to nonutiltions. No funds were maalone applications. House Report 100-165 outlined repay government contrib

Rescinded $750 million of $5.375 billion from the EnergySecurity Reserve (Synthetic Fuels Corporation) to bedeposited in a U.S. Treasury Department account entitled“Clean Coal Technology Reserve” for conducting costshared CCT projects for the construction and operation offacilities to demonstrate the feasibility for future commercial application of such technology, without fiscal yearlimitation, subject to subsequent annual appropriation.Deferred $1.6 million for obligation until 10/1/85.Conference Report (H. Rep. 99-450) agreed to a$400-million CCT Program as described under the U.S.Treasury Department Energy Security Reserve, with therequest for proposals to be for the full $400 million.(Contained no funding provisions for CCT Program)Appropriated $50 million for FY beginning 10/1/87 untilexpended and $525 million for FY beginning 10/1/88 untilexpended.
Exhibit A-1 (continued) Exhibit A-1 (continued)

CCT Program Legislative History

Public DateLaw Enacted Enacted CCT Round Program Funding Implementation Prov

Made available $575 million on 10/1/89 until expended.Pub. L. 100-202 was amended by striking $525 million andinserting $190 million for FY beginning 10/1/88 untilexpended, $135 million for fiscal year beginning 10/1/89until expended, and $200 million for FY beginning 10/1/90until expended, provided that outlays for FY89 resultingfrom use of funds appropriated under Pub. L. 100-202, asamended, did not exceed $15.5 million.Funds appropriated for FY1989 were made available for athird solicitation.Made available $600 million on 10/1/90 until expended and$600 million on 10/1/91 until expended. Pub. L. 100-446was amended by striking $575 million and inserting$450 million to be made available on 10/1/89 until expendedand $125 million to be made available on 10/1/90. Unobligated balances excess to the needs of the procurement forwhich they originally were made available may be applied toother procurements for which requests for proposals hadnot yet been issued, except that no supplemental, backup,or contingent selection of projects could be made over andabove the projects originally selected.Appropriation for FY1990 was amended by striking$450 million and inserting $419 million and by striking $125million and inserting $156 million.Obligation of funds previously appropriated for CCT-IVand CCT-V was deferred until 9/1/91.

100-446 9/27/88 CCT-III101-45 6/30/89 CCT-III101-121 10/23/89 CCT-IV and CCT-V101-164 11/21/89 CCT-IV and CCT-V101-302 5/25/90 CCT-IV and CCT-V

Request for proposals (Cfor emerging CCTs capaexisting facilities. Propoafter issuance of the POno later than 120 days aFunds borrowed by REA Federal Financing Bank sharing. Funds derived Authority from its poweallowable as cost-sharinappropriations acts.Project selections for the made not later than 1/1/9Two solicitations (CCT-one for each appropriaticapable of replacing, retrfacilities, subject to all p99-190, 100-202, and 10(CCT-IV) using funds beto be issued by 6/1/90, w2/1/91. The PON (CCTavailable on 10/1/91 wa9/1/91, with selections mSolicitations could not bobligate funds. RepaymCCT-V were to be the s
A-6 Program Update 2000

Exhibit A-1 (continued) Exhibit A-1 (continued)

CCT Program Legislative History

Public DateLaw Enacted Enacted CCT Round Program Funding Implementation Provi

Pub. L. 101-121 was amended by striking $600 millionmade available on 10/1/90 until expended and $600million made available on 10/1/91 until expended andinserting $600 million made available as follows: $35million on 9/1/91, $315 million on 10/1/91, and $250million on 10/1/92, all sums remaining until expended, foruse in conjunction with a separate general request forproposals, and $600 million made available as follows:$150 million on 10/1/91, $225 million on 10/1/92, and$225 million on 10/1/93, all sums remaining untilexpended, for use with a separate general request forproposals.Pub. L. 102-512 was amended by striking $150 million on10/1/91 and $225 million on 10/1/92 and inserting$100 million on 10/1/91 and $275 million on 10/1/92.

101-512 11/5/90 CCT-IV and CCT-V102-154 11/13/91 CCT-V

The CCT-IV solicitation w2/1/91. The CCT-V PON than 3/1/92. Project seleceight months of PON’s iswere to be the same as foincluded to provide proteproprietary information. 101-971) recommends chfactors.The CCT-V PON was del7/6/92, with selection to b(extended by two monthsprojects that advance signenvironmental performanand would be applicable to facilities. Conference Repexpectations that the CCTconducted under the same CCT-IV, principally modiwider range of eligible tecadjust technical criteria to ment activities, strengthen demonstrations, and adjuscriteria for additional facilregard to aspects of generaenvironmental performancstrengthen cost and financregard to development actFunding was allowed for pactivities for process perfdesign verification, materof alternative designs on limit of 10 percent of the cost.
Exhibit A-1 (continued) Exhibit A-1 (continued)

CCT Program Legislative History

Public DateLaw Enacted Enacted CCT Round Program Funding Implementation Prov

Pub. L. 101-512 was amended by striking $250 million on10/1/92 and inserting $150 million on 10/1/93 and$100 million on 10/1/94; and by striking $275 million on10/1/92 and $225 million on 10/1/93 and inserting $250million on 10/1/93 and $250 million on 10/1/94.(Contained no funding provisions for CCT Program)Pub. L. 101-512 was amended by striking $150 million on10/1/93 and $100 million on 10/1/94 and inserting$100 million on 10/1/93, $100 million on 10/1/94, and$50 million on 10/1/95; and by striking $250 million on10/1/93 and $250 million on 10/1/94 and inserting$125 million on 10/1/93, $275 million on 10/1/94, and$100 million on 10/1/95.Pub. L. 101-512 was amended by striking $100 million on10/1/94 and $50 million on 10/1/95 and inserting$18 million on 10/1/94, $100 million on 10/1/95, and$32 million on 10/1/96; and by striking $275 million on10/1/94 and $100 million on 10/1/95 and inserting$19.121 million on 10/1/94, $100 million on 10/1/95, and$255.879 million on 10/1/96.

102-154(continued)102-381 10/5/92102-486 10/24/92103-138 11/11/93103-332 9/30/94

Development activities included limited modificproject-related testing bufacilities.Section 1301—Coal RDtions Programs (Title XIto conduct programs for applications of coal-baseEnergy was directed to sthat included, among othregarding the manner in demonstrations conductProgram (Pub. L. 98-47extended in order to ensadvanced coal-based tecstatus reports on the devbased technologies and application attributes.An amount not to exceeFY1995 may be used foCCT Program.
A-8 Program Update 2000

Exhibit A-1 (continued) Exhibit A-1 (continued)

CCT Program Legislative History

Public DateLaw Enacted Enacted CCT Round Program Funding Implementation Provisio

Of funds available for obligation in FY1996, $50 million wasrescinded. Of the funds to be made available for obligation inFY1997, $150 million was rescinded.Conference Report (H. Rep. 104-863 to accompanyH.R. 3610) noted rescission of $123 million for FY1997 orprior years.Of funds made available for obligation in FY1997 or prioryears, $17 million was rescinded.Of funds made available for obligation in FY1997 or prioryears, $101 million was rescinded.Of funds made available for obligation in prior years,$40 million was deferred.Of funds made available for obligation in prior years, $156million was deferred. Also, $38,000 was rescinded as a resultof the general reduction.Of funds made available for obligation in prior years, $67million was deferred.

104-6 4/10/95104-134a 4/26/96

104-208b 9/30/96105-18 6/12/97105-83 11/14/97105-277 10/21/98106-113 11/29/99106-291 10/11/00

Conference Report (H. Rep1977) allowed for the use oProgram funds for program House and Senate committeto $16 million in available fCCT Program in FY1997 (H104-319 to accompany H.RConference Report (H. Repmillion in CCT Program funConference Report (H. Repthe use of up to $14.4 millioprogram administration.

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

Public Law 99-190, 99 Stat. 1251 (1985) Public Law 99-190, 99 Stat. 1251 (1985)

CLEAN COAL TECHNOLOGY

Within 60 days following enactment of this Act [Dec.19, 1985] the Secretary of Energy shall, pursuant to theFederal Nonnuclear Energy Research and Development Act of 1974 (42 U.S.C. 5901, et seq.), issue ageneral request for proposals for clean coal technology projects for which the Secretary of Energy uponreview may provide financial assistance awards.Proposals for clean coal technology projects underthis section shall be submitted to the Department ofEnergy within 60 days after issuance of the generalrequest for proposals. The Secretary of Energy shallmake any project selections no later than August 1,1986: Provided, That the Secretary may vest fee title orother property interests acquired under cost-sharedclean coal technology agreements in any entity,including the United States: Provided further, That theSecretary shall not finance more than 50 per centum ofthe total costs of a project as estimated by theSecretary as of the date of award of financial assistance: Provided further, That cost-sharing by projectsponsors is required in each of the design, construction, and operating phases proposed to be included ina project: Provided further, That financial assistancefor costs in excess of those estimated as of the date ofaward of original financial assistance may not beprovided in excess of the proportion of costs borne bythe Government in the original agreement and only upto 25 per centum of the original financial assistance:Provided further, That revenues or royalties fromprospective operation of projects beyond the time

considered in the award of financial assistance, orproceeds from prospective sale of the assets of theproject, or revenues or royalties from replication oftechnology in future projects or plants are not costsharing for the purposes of this appropriation:Provided further, That other appropriated Federalfunds are not cost-sharing for the purposes of thisappropriation: Provided further, That existing facilities,equipment, and supplies, or previously expendedresearch or development funds are not cost-sharingfor the purposes of this appropriation, except asamortized, depreciated, or expensed in normal business practice.

Conference Report (H.R. Conf. Rep. No. Conference Report (H.R. Conf. Rep. No.

450, 99th Cong., 1st Sess. [1985]) 450, 99th Cong., 1st Sess. [1985])

CLEAN COAL TECHNOLOGY

The managers have agreed to a $400,000,000 CleanCoal Technology program as described under theDepartment of the Treasury, Energy Security Reserve.Bill language is included which provides for theselection of projects no later than August 1, 1986.Within that period, a general request for proposalsmust be issued within 60 days and proposals must besubmitted to the Department within 60 days afterissuance of the general request for proposals.Language is also included allowing the Secretary ofEnergy to vest title in interests acquired underagreements in any entity, including the United States,and delineating cost-sharing requirements. Funds forthese activities and projects are made available to theClean Coal Technology program in the EnergySecurity program.It is the intent of the managers that contributions inthe form of facilities and equipment be consideredonly to the extent that they would be amortized,

depreciated or expensNormal business pracSecretary and is not nsingle proposer. Propdepreciated would noexcept to the extent thby the proposer during preceding the enactmeerty, a fair use value foassigned. Property ofproposer that is currenlimited in its cost-sharclaimed during the life Furthermore, in determthe Secretary should nsold, transferred, exchto acquire a new basis establish a rental valuamount to a transactioparticipating in this prThe managers agree ttax implications of proavailable to individuaconsidered in determicost-sharing. This is historical practices in ments.It is the intent of the mopen competition and all markets utilizing thHowever, projects shoUnited States mined cdemonstration sites shUnited States.The managers agree thbe available in FY1986 thereafter for contractthe program, and that 
A-10 Program Update 2000

Conference Report 

Conference Report 

498, 100th Cong., 1

498, 100th Cong., 1

CLEAN CO

Appropriates $575,000,instead of $350,000,000 $850,000,000 as proposson by year is as follow

House 

Fiscal year:1988 $50,000,000 1989 200,000,000 1990 100,000,000Total 350,000,000 

Bill language, proposed have prohibited using gmanagers agree that probased on cooperative amight be applicable to sthis account.The managers agree to providing personnel floThe managers further afor personnel and contrThe agreement included current employment floorganization and 30 posclean coal technology fufiscal year 1988 person$16,520,000 is for all coproject selections and cclean coal procurementmonitor approved proje

funded under the fossil energy research and development program.The managers direct the Department, after projects areselected, to provide a comprehensive report to theCongress 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

Public Law 100-202, 101 Stat. 1329-1

(1987)

CLEAN COAL TECHNOLOGY

For necessary expenses of, and associated with, CleanCoal Technology demonstrations pursuant to 42U.S.C. 5901 et seq., $50,000,000 are appropriated forthe fiscal year beginning October 1, 1987, and shallremain available until expended, and $525,000,000 areappropriated 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 theFederal Nonnuclear Energy Research and Development Act of 1974 (42 U.S.C. 5901 et seq.), issue ageneral request for proposals for emerging clean coaltechnologies which are capable of retrofitting orrepowering existing facilities, for which the Secretaryof Energy upon review may provide financial assistance awards. Proposals under this section shall besubmitted to the Department of Energy no later than

ninety days after issuance of the general request forproposals required herein, and the Secretary of Energyshall make any project selections no later than onehundred and sixty days after receipt of proposal:Provided, That projects selected are subject to allprovisos contained under this head in Public Law 99-190: Provided further, That pre-award costs incurredby project sponsors after selection and before signingan agreement are allowable to the extent that they arerelated to (1) the preparation of material requested bythe Department of Energy and identified as requiredfor the negotiation; or (2) the preparation and submission of environmental data requested by the Department of Energy to complete National EnvironmentalPolicy Act requirements for the projects: Provided

further, That pre-award costs are to be reimbursed

only upon signing of the project agreement and onlyin the same ratio as the cost-sharing for the totalproject: Provided further, That reports on projectsselected by the Secretary of Energy pursuant toauthority granted under the heading “Clean coaltechnology” in the Department of the Interior andRelated Agencies Appropriations Act, 1986, ascontained in Public Law 99-190, which are received bythe Speaker of the House of Representatives and thePresident of the Senate prior to the end of the firstsession of the 100th Congress shall be deemed tohave met the criteria in the third proviso of the fourthparagraph under the heading “Administrative provision, Department of Energy” in the Department of theInterior and Related Agencies Appropriations Act,1986, as contained in Public Law 99-190, uponexpiration of 30 calendar days from receipt of thereport by the Speaker of the House of Representativesand the President of the Senate.
fiscal year 1989 budget. Increases above thoseamounts are subject to reprogramming procedures.No funds other than personnel related costs for the 30positions included in the program direction are to beprovided from the fossil energy research and development account.The length of time for selection of projects by theSecretary of Energy has been extended from 120 daysto 160 days based on experience from the originalclean coal procurement. Once projects have beenselected the Secretary should establish projectmilestones and guidelines for project negotiations inorder to expedite the negotiation process to the extentfeasible.The managers agree that the funds provided areavailable for nonutility applications as well as forutility applications.The managers agree that no funds are provided for thedemonstration of clean coal technologies which areintended solely for new, stand alone, applications.The Senate had proposed up to 25% of the funds beavailable 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 satisfyreporting requirements 30 calendar days after receiptby Congress. This provision applies to a maximum oftwo project reports.

Public Law 100-446 Public Law 100-446

Public Law 100-446, 102 Stat. 1774 (1988) Public Law 100-446, 102 Stat. 1774 (1988)

CLEAN COAL TECHNOLOGY

For necessary expenses of, and associated with, CleanCoal Technology demonstrations pursuant to 42U.S.C. 5901 et seq., $575,000,000 shall be madeavailable on October 1, 1989, and shall remain available until expended: Provided, That projects selectedpursuant to a general request for proposals issuedpursuant to this appropriation shall demonstratetechnologies capable of retrofitting or repoweringexisting facilities and shall be subject to all provisionscontained under this head in Public Laws 99-190 and100-202 as amended by this Act.The first paragraph under this head in Public Law 100-202 is amended by striking “and $525,000,000 areappropriated for the fiscal year beginning October 1,1988” and inserting “$190,000,000 are appropriated forthe 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 yearbeginning October 1, 1990”: Provided, That outlays in

fiscal year 1989 resulting from the use of fundsappropriated under this head in Public Law 100-202, asamended by this Act, may not exceed $15,500,000:

Provided further, That these actions are takenpursuant to section 202(b)(1) of Public law 100-119 (2U.S.C. 909).For the purposes of the sixth proviso under this headin Public Laws 99-190, funds derived by the Tennessee Valley Authority fr

hereafter not to be prepart of any cost-sharinextent that such funds appropriations Acts: Pbalances of funds madSecurity Reserve” accClean Coal Technologthe Interior and RelateActs, 1986, as containLaw 99-190, shall be mProvided further, Tha

proviso in Public Law funds provided under shall be considered no

That reports on projecEnergy pursuant to auheading “Clean coal tthe Interior and Relate1986, as contained in Preceived by the Speaktives and the Presidenof the second session deemed to have met ththe fourth paragraph utive provisions, Deparment of the Interior antions Act, 1986, as conupon expiration of 30 report by the Speaker and the President of th
A-12 Program Update 2000

Conference Report (H.R. Conf. Rep. No. Conference Report (H.R. Conf. Rep. No.

862, 100th Cong., 2nd Sess. [1988]) 862, 100th Cong., 2nd Sess. [1988])

CLEAN COAL TECHNOLOGY

Amendment No. 131: Reported in technical disagreement. The managers on the part of the House willoffer a motion to recede and concur in the amendmentof the Senate with an amendment as follows:In lieu of the matter proposed by said amendmentinsert the following: For necessary expenses of, and

associated with, Clean Coal Technology demonstrations pursuant to 42 U.S.C. 5901 et seq.,

$575,000,000 shall be made available on October 1,

1989, and shall remain available until expended:

Provided, That projects selected pursuant to a

general request for proposals issued pursuant to this

appropriation shall demonstrate technologies

capable of retrofitting or repowering existing

facilities and shall be subject to all provisos contained under this head in Public Laws 99-190 and

100-202 as amended by this Act.

The managers on the part of the Senate will move toconcur in the amendment of the House to the amendment of the Senate. The amendment provides$575,000,000 in fiscal year 1990 for a third Clean CoalTechnology procurement as proposed by the Senate,and clarifies that the procurement is for retrofit andrepowering technologies and is subject to the costsharing provisions of the previous two procurements.The managers agree that a request for proposalsshould be issued by May 1, 1989, with proposals dueno later than 120 days after issuance of the request forproposals, and that the Secretary of Energy shouldmake project selections no later than 120 days afterreceipt of proposals.

Amendment No. 132: Reported in technical disagreement. The managers on the part of the House willoffer a motion to recede and concur in the amendmentof the Senate with an amendment as follows:Restore the matter stricken by said amendment,amended to read as follows: The first paragraph

under this head in Public Law 100-202 is amended

by striking “and $525,000,000 are appropriated for

the fiscal year beginning October 1, 1988” and

inserting “$190,000,000 are appropriated for the

fiscal year beginning October 1, 1988, and shall

remain available until expended, $135,000,000 are

appropriated for the fiscal year beginning October 1,

1989, and shall remain available until expended,

and $200,000,000 are appropriated for the fiscal

year beginning October 1, 1990”: Provided, That

outlays in fiscal year 1989 resulting from the use of

funds appropriated under this head in Public Law

100-202, as amended by this Act, may not exceed

$15,500,000: Provided further, That these actions

are taken pursuant to section 202(b)(1) of Public

Law 100-119 (2 U.S.C. 909).

The managers on the part of the Senate will move toconcur in the amendment of the House to the amendment of the Senate. The amendment changes theavailability of $525,000,000 originally made availablefor fiscal year 1989 in Public Law 100-202 by making$190,000,000 available in 1989, $135,000,000 availablein 1990, and $200,000,000 available in 1991 and alsoprovides 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 ofbudget allocation constraints, but neither action has

an effect on the executioor on the Congress’ oveas is evidenced by addifor a third procurement The managers agree thaexpenses may be incurr$9,820,000, but caution expenditures is necessaceiling provided will be costs.Amendment No. 133: Mproposed by the SenateAmendment No. 134: Rment. The managers on offer a motion to recede of the Senate which claREA Electric CooperatiBank are eligible as costechnology program.Amendment No. 135: Rment. The managers on offer a motion to recede of the Senate which speproceed 30 calendar darequired reports, providprior to the end of the 1
Public Law 101-45 Public Law 101-45

Public Law 101-45, 103 Stat. 97 (1989) Public Law 101-45, 103 Stat. 97 (1989)

CLEAN COAL TECHNOLOGY

 Notwithstanding any other provision of law, fundsoriginally appropriated under this head in the Department of the Interior and Related Agencies Appropriations Act, 1989, shall be available for a third solicitation of clean coal technology demonstration projects,which projects are to be selected by the Departmentnot later than January 1, 1990.

Public Law 101-121 Public Law 101-121

Public Law 101-121, 103 Stat. 701 (1989) Public Law 101-121, 103 Stat. 701 (1989)

CLEAN COAL TECHNOLOGY

 For necessary expenses of, and associated with,Clean Coal Technology demonstrations pursuant to 42U.S.C. 5901 et seq., $600,000,000 shall be madeavailable on October 1, 1990, and shall remain available until expended, and $600,000,000 shall be madeavailable on October 1, 1991, and shall remain available until expended: Provided, That projects selectedpursuant to a separate general request for proposalsissued pursuant to each of these appropriations shalldemonstrate technologies capable of replacing,retrofitting or repowering existing facilities and shallbe subject to all provisos contained under this head in

Public Laws 99-190, 100-202, and 100-446 as amendedby this Act: Provided further, That the general requestfor proposals using funds becoming available onOctober 1, 1990, under this paragraph shall be issuedno later than June 1, 1990, and projects resulting fromsuch a solicitation must be selected no later thanFebruary 1, 1991: Provided further, That the generalrequest for proposals using funds becoming availableon October 1, 1991, under this paragraph shall beissued no later than September 1, 1991, and projectsresulting from such a solicitation must be selected nolater than May 1, 1992.The first paragraph under this head in Public Law 100-446is amended by striking “$575,000,000 shall be madeavailable on October 1, 1989” and inserting “$450,000,000shall be made available on October 1, 1989, and shallremain available until expended, and $125,000,000 shall bemade available on October 1, 1990”: Provided, That theseactions are taken pursuant to section 202(b)(1) of PublicLaw 100-119 (2 U.S.C. 909).With regard to funds made available under this headin this and previous appropriations Acts, unobligatedbalances excess to the needs of the procurement forwhich they originally were made available may beapplied to other procurements for which requests forproposals have not yet been issued: Provided, Thatfor all procurements for which project selections havenot been made as of the date of enactment of this Actno supplemental, backup, or contingent selection ofprojects shall be made over and above projectsoriginally selected for negotiation and utilization ofavailable funds: Provided further, That reports onprojects selected by the Secretary of Energy pursuantto authority granted under this heading which arereceived by the Speaker of the House of Representatives and the President of the Senate less than 30legislative days prior to the end of the first session ofthe 101st Congress shall be deemed to have met the

criteria in the third prounder the heading “ADepartment of EnergyInterior and Related A1986, as contained in Pexpiration of 30 calendreport by the Speaker and the President of thsession, whichever oc

Conference Repo

Conference Repo

264, 101st Cong., 

264, 101st Cong., 

CLEAN C

Amendment No. 112: ment. The managers ooffer a motion to recedof he Senate which addefinition of clean coaagree that the inclusioIV and V is intended tment of an existing faspecific limitations, replant is not a desirable Amendment No,. 113: fiscal year 1990 for cl$500,000,000 as prop$325,000,000 as propopriation along with $12year 1991 in Amendmround of clean coal teers agree that additionparticularly at the DepCenters, in order to mworkload from the acctechnology projects aprocurements in this b
A-14 Program Update 2000

is not included, the managers agree that at least eightypersonnel will be required in addition to the approximately thirty FTE’s now included in the fossil energyresearch and development appropriation. Themanagers agree further that funds from the fossilenergy research and development appropriationshould not be used to pay the cost of more than theequivalent FTE’s paid under that account in fiscal year1989.Amendment No. 114: Reported in technical disagreement. The managers on the part of the House willoffer a motion to recede and concur in the amendmentof the Senate with an amendment as follows:In lieu of the matter stricken and inserted by saidamendment, insert: and shall remain available until

expended, and $125,000,000

The managers on the part of the Senate will move toconcur in the amendment of the House to the amendment of the Senate. The amendment provides$125,000,000 in fiscal year 1991 for the third clean coaltechnology procurement instead of $75,000,000 asproposed by the House and $100,000,000 as proposedby the Senate.Amendment No 115: Deletes Senate proposedappropriation of $150,000,000 for fiscal year 1992 forclean coal technology. The House proposed no suchappropriation.Amendment No. 116: Restores House languagestricken by the Senate which prohibits the use ofsupplemental, backup, or contingent project selections in clean coal technology procurements.Amendment No. 117: Restores the word “further”stricken by the Senate.

Public Law 101-164 Public Law 101-164

Public Law 101-164, 103 Stat. 1069 (1989) Public Law 101-164, 103 Stat. 1069 (1989)

CLEAN COAL TECHNOLOGY

The second paragraph under this head contained inthe Act making appropriations for the Department ofthe Interior and Related Agencies for the fiscal yearending September 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. Conference Report (H.R. Conf. Rep. No.

315, 101st Cong., 1st Sess. [1989]) 315, 101st Cong., 1st Sess. [1989])

The managers have agreed to reduce the fundsappropriated by the Energy and Water DevelopmentAppropriations 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 theInterior and Related Agencies Appropriations Act forFiscal Year 1990 (Public Law 101-121) in order toaccommodate additional drug related appropriations.The reductions are in three areas. The new budgetauthority for Clean Coal Technology of $450,000,000for fiscal 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 StrategicPetroleum Reserve oil acquisition. Outlays will be

reduced from an estimat$147,125,000 and will dapproximately 50,000 b46,000 or 47,000 barrelrelates to the PennsylvaCorporation. The borro$5,000,000 to $100,000.The conference agreemreducing the amount of funds to the Health CarProgram Management a$1,917,172,000 to $18,8along with the outlays rLabor, Health and Humappropriations bill, will Subcommittee’s share ofunding. The conferees trust fund transfers be aimplement catastrophic funding needs may be d

Public Law Public Law 

Public Law 101-30

Public Law 101-30

CLEAN CO

Funds previously approclean coal technology slater than June 1, 1990, 1991, respectively, shalber 1, 1991: Provided, Tsolicitations shall not bto obligate these funds: 
pursuant to section 202(b) of the Balanced Budgetand Emergency Deficit Control Reaffirmation Act of1987, this action is a necessary (but secondary) resultof a significant policy change: Provided further, Thatfor the clean coal solicitations identified herein,provisions included for the repayment of governmentcontributions to individual projects shall be identicalto those included in the Program Opportunity Notice(PON) for Clean Coal Technology III (CCT-III)Demonstration Projects (solicitation number DE-PSO1-89 FE 61825), issued by the Department of Energy onMay 1, 1989.

Conference Report (H.R. Conf. Rep. No. Conference Report (H.R. Conf. Rep. No.

493, 101st Cong., 2nd Sess. [1990]) 493, 101st Cong., 2nd Sess. [1990])

CLEAN COAL TECHNOLOGY

Amendment No. 89. Reported in technical disagreement. The managers on the part of the House willoffer a motion to recede and concur in the amendmentof the senate with an amendment as follows:In lieu of the matter proposed by said amendmentinsert:

DEPARTMENT OF ENERGY

CLEAN COAL TECHNOLOGY

Funds previously appropriated under this head for

clean coal technology solicitations to be issued no

later than June 1, 1990, and no later than September

1, 1991, respectively, shall not be obligated until

September 1, 1991: Provided, That the aforementioned solicitations shall not be conducted prior to

the ability to obligate these funds: Provided further,

That pursuant to section 202 (b) of the Balanced

Budget and Emergency Deficit Control reaffirmation

/Act of 1987 this action is a necessary (but secondary) result of a significant policy change: Provided further, That for the clean coal solicitations identi- fied herein, provisions included for the repayment of government contributions to individual projects shall be identical to those included in the Program Opportunity Notice (PON) for Clean Coal Technol- ogy III (CCT-III) Demonstration Projects (solicita- tion number DE-PS01-89 FE 61825), issued by the Department of Energy on May 1, 1989. The managers on the part of the Senate will move to concur in the amendment of the House to the amend- ment of the Senate. The amendment delays the fourth and fifth clean coal technology solicitations as proposed by the Senate and specifies that, when issued, these solicitations must use repayment provisions used successfully in the third solicitation. This provision was included in the House introduced bill (H.R. 4828) and modifies a Senate amendment to the original Dire Emergency Supplemental. The managers agree that changes to the clean air bill, proposed by a House authorizing committee, that would modify the clean coal technology program must be resolved before a reasonable solicitation can be issued. The proposed delay will allow such resolution. The managers have added language to ensure that provisions dealing with the repayment of government provided funds will remain the same as the third round of procurements. These provisions were developed over a four year period based on experience of previous procurements and negotiations, and input from industrial participants, Congress, and the managers of the program. They appear to be working well. Based on the long-term experience, and the clear fact that implementation of this type of technology will become even more important with passage of clean air legislation, the managers reject proposals put forth by the Department of En

tially. Such proposalsrecovery of governmeof up to 20 years, migindustrial participation already over 50 percepurpose of the program tion of clean uses of cocompliance with strinnot the provision of inGovernment at the exp

Public Law Public Law 

Public Law 101-5

Public Law 101-5

CLEAN C

The first paragraph un121 is amended by strimade available on Octavailable until expendemade available on Octavailable until expendeshall be made available September 1, 1991, $31and $250,000,000 on Oremain available until with a separate genera$600,000,000 shall be $150,000,000 on OctobOctober 1, 1992, and $all such sums to remaiuse in conjunction wiproposals”: Provided, 
A-16 Program Update 2000

pursuant to section 202(b)(1) of Public Law 100-119 (2

U.S.C. 909): Provided further, That a fourth general

request for proposals shall be issued not later thanFebruary 1, 1991, and a fifth general request forproposals shall be issued not later than March 1, 1992:Provided further, That project proposals resulting fromsuch solicitations shall be selected not later than eightmonths after the date of the general request forproposals: Provided further, That for clean coalsolicitations required herein, provisions included forthe repayment of government contributions toindividual projects shall be identical to those includedin the Program Opportunity Notice (PON) for CleanCoal Technology III (CCT-III) Demonstration Projects(solicitation number DE-PS01-89 FE 61825), issued bythe Department of Energy on May 1, 1989: Providedfurther, That funds provided under this head in this orany other appropriations Act shall be expended onlyin accordance with the provisions governing the useof such funds contained under this head in this or anyother appropriations Act.With regard to funds made available under this headin this and previous appropriations Acts, unobligatedbalances excess to the needs of the procurement forwhich they originally were made available may beapplied 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, Thatthe Department of Energy, for a period of up to five (5)years after completion of the operations phase of acooperative agreement may provide appropriateprotections, including exemptions from subchapter IIof chapter 5 of title 5, United States Code, against thedissemination of information that results from demonstration activities conducted under the Clean CoalTechnology Program and that would be a trade secretor commercial or financial information that is privileged or confidential if the information had been

obtained from and first produced by a non-Federalparty participating in a Clean Coal Technology project:Provided further, That, in addition to the full-timepermanent Federal employees specified in section 303of Public Law 97-257, as amended, no less than 90 fulltime 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 appropriationsAct and of which 35 shall be for PETC and 30 shall befor METC: Provided further, That reports on projectsselected by the Secretary of Energy pursuant toauthority granted under this heading which arereceived by the Speaker of the House of Representatives and the President of the Senate less than 30legislative days prior to the end of the second sessionof the 101st Congress shall be deemed to have met thecriteria in the third proviso of the fourth paragraphunder the heading “Administrative provisions,Department of Energy” in the Department of theInterior and Related Agencies Appropriations Act,1986, as contained in Public Law 99-190, uponexpiration of 30 calendar days from receipt of thereport by the Speaker of the House of Representativesand the President of the Senate or at the end of thesession, whichever occurs later.

Conference Report (H.R. Conf. Rep. No. Conference Report (H.R. Conf. Rep. No.

971, 101st Cong., 2nd Sess. [1990]) 971, 101st Cong., 2nd Sess. [1990])

CLEAN COAL TECHNOLOGY

Amendment No. 142: Provides $35,000,000 for cleancoal technology on September 1, 1991 as proposed bythe House instead of $100,000,000 as proposed by theSenate. This amendment and Amendment No. 143shift the availability of $65,000,000 from fiscal year1991 to fiscal year 1992.

Amendment No. 143: Pcoal technology on Octthe House instead of $2Senate. This amendmenshift the availability of $1991 to fiscal year 1992.Amendment No. 144: Ptions for clean coal techSenate. The date for CC1, 1991 from January 1, not changed from the SThe managers have agrfor the next solicitation publish a draft solicitatiparties. It is expected tevaluation criteria and oimperative that potentianity to comment on the The managers urge the potential benefits to rema program policy factor Department should also provide multiple fuel rewhich are more than seon one fuel form for totAmendment No. 145: Rwithin eight months of required by AmendmenSenate. The House had Amendment No. 146: Rment contributions to pidentical to the most recproposed by the Senateprovision.Amendment No. 147: Pcoal technology may be 
tions contained in appropriations Acts. The Senatelanguage had prohibited geographic restrictions onthe expenditure of funds. The House had no suchprovision. The managers direct that no preferentialconsideration be given to any project referencedexplicitly or implicitly in other legislation.The managers agree to delete bill language dealingwith geographic restrictions based on such restrictions being deleted from clean air legislation.Amendment No. 148: Earmarks employees to two fossilenergy technology centers as proposed by the Senate.The House had no such provision. The managersagree that the earmarks for PETC and METC areminimum levels and may be increased as necessary.The managers agree that no more than the current 30full-time equivalent positions from fossil energyresearch and development may be used in the cleancoal program in fiscal year 1991.

Public Law 102-154 Public Law 102-154

Public Law 102-154, 105 Stat. 990 (1991) Public Law 102-154, 105 Stat. 990 (1991)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-512 is amended by striking the phrase “$150,000,000on October 1, 1991, $225,000,000 on October 1, 1992”and inserting “$100,000,000 on October 1, 1991,$275,000,000 on October 1, 1992”. Notwithstanding the issuance date for the fifthgeneral request for proposals under this head inPublic Law 101-512, such request for proposals shall

be issued not later than July 6, 1992, and notwithstanding the proviso under this head in Public Law101-512 regarding the time interval for selection ofproposals resulting from such solicitation, projectproposals resulting from the fifth general request forproposals shall be selected not later than ten monthsafter the issuance date of the fifth general request forproposals: Provided, That hereafter the fifth generalrequest for proposals shall be subject to all provisoscontained under this head in previous appropriationsActs unless amended by this Act. Notwithstanding the provisos under this head inprevious appropriations Acts, projects selectedpursuant to the fifth general request for proposalsshall advance significantly the efficiency and environmental performance of coal-using technologies and beapplicable to either new or existing facilities: Provided,That budget periods may be used in lieu of design,construction, and operating phases for cost-sharingcalculations: Provided further, That the Secretary shallnot finance more than 50 per centum of the total costsof any budget period: Provided further, That projectspecific development activities for process performance definition, component design verification,materials selection, and evaluation of alternativedesigns may be funded on a cost-shared basis up to alimit of 10 per centum of the Government’s share ofproject cost: Provided further, That developmentactivities eligible for cost-sharing may include limitedmodifications to existing facilities for project relatedtesting but do not include construction of newfacilities.With regard to funds made available under this headin this and previous appropriations Acts, unobligatedbalances excess to the needs of the procurement forwhich they originally were made available may beapplied to other procurements for use on projects forwhich cooperative agreements are in place, within the

limitations and proporincreases currently allhereafter, the Departmto five years after comof a cooperative agreeprotections, including of chapter 5 of title 5, dissemination of inforstration activities condTechnology Program or commercial or finanleged or confidential iobtained from and firsparty participating in a Provided further, That time permanent Feder303 of Public Law 97-full-time Federal empAssistant Secretary fothe programs under thunder this head in this Act and of which not land not less than 30 shfurther, That hereafter the Secretary of Energunder this heading whof the House of Reprethe Senate less than 3end of each session ohave met the criteria iparagraph under the hsions, Department of EInterior and Related A1986, as contained in Pexpiration of 30 calendreport by the Speaker and the President of thsession, whichever oc
A-18 Program Update 2000

Conference Report (H.R. Conf. Rep. No. Conference Report (H.R. Conf. Rep. No.

256, 102nd Cong., 1st Sess. [1991]) 256, 102nd Cong., 1st Sess. [1991])

CLEAN COAL TECHNOLOGY

Amendment No. 165: Reported in technical disagreement. The managers on the part of the House willoffer a motion to recede and concur in the amendmentof the Senate with an amendment as follows:In lieu of the matter stricken and inserted by saidamendment insert:Notwithstanding the issuance date for the fifth

general request for proposals under this head in

Public Law 101-512, such request for proposals shall

be issued not later than July 6, 1992, and notwithstanding the proviso under this head in Public Law

101-512 regarding the time interval for selection of

proposals resulting from such solicitation, project

proposals resulting from the fifth general request for

proposals shall be selected not later than ten months

after the issuance date of the fifth general request for

proposals: Provided, That hereafter the fifth general

request for proposals

The managers on the part of the Senate will move toconcur in the amendment of the House to the amendment of the Senate.The amendment changes the issuance date for thefifth general request for proposals to July 6, 1992instead of March 1, 1992 as proposed by the Houseand August 10, 1992 as proposed by the Senate andthe allowable length of time from issuance of therequest for proposals to selection of projects to tenmonths. The amendment also deletes Senate proposed bill language pertaining to a sixth generalrequest for proposals as discussed below.

The managers agree that the additional two months inthe procurement process for the fifth round ofproposals should include an additional month to allowfor the preparation of proposals by the private sector,and up to an additional month for Department ofEnergy review and evaluation of proposals whencompared to the 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 fromthe Secretary on available funds, which was originallyin the Senate amendment, is still a requirement andsuch report should be submitted to the House andSenate Committees on Appropriations not later thanMay 1, 1994. Based on that report, the funding, datesand conditions for the sixth round will be included inthe fiscal year 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 nonutility demonstrations, and to adjust commercial performance criteria for additional facilities andtechnologies with regard to aspects of general energyefficiency and environmental performance; and (3) toclarify and strengthen cost and finance criteriaparticularly with regard to development activities.Amendment No. 166: Restores House languagedeleted by the Senate which refers to a fifth generalrequest for proposals. The Senate proposed languagedealing with both a fifth and a sixth round.Amendment No. 167: Reported in technical disagreement. The managers on the part of the House will

offer a motion to recede of the Senate which dirreobligate up to $44,000Clean Coal Technology ranked highest in its spthe Source Evaluation Branking project in that cnally by the Secretary, aunobligated and are sufThis amendment would become available, to a sthe Department of Enerfourth round of Clean CAmendment No. 168: Tdeletes House proposed as proposed by the SenAmendment No. 169: Dlanguage which made uprocurements for which not been issued.Amendment No. 170: Rment. The managers on offer a motion to recede of the Senate which addment floor language for Senate. The House had Amendment No. 171: Rment. The managers on offer a motion to recede of the Senate which addment floor language for Senate. The House had 
Public Law 102-381 Public Law 102-381

Public Law 102-381, 106 Stat. 1374 (1992) Public Law 102-381, 106 Stat. 1374 (1992)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-512, as amended, is further amended by striking thephrase “and $250,000,000 on October 1, 1992” andinserting “$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 onOctober 1, 1994”.

Public Law 103-138 Public Law 103-138

Public Law 103-138, 107 Stat. 1379 (1993) Public Law 103-138, 107 Stat. 1379 (1993)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-512, as amended, is further amended by striking thephrase “$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 on October 1,1993, and $250,000,000 on October 1, 1994” andinserting “$125,000,000 on October 1, 1993,$275,000,000 on October 1, 1994, and $100,000,000 onOctober 1, 1995”.

Public Law 103-332 Public Law 103-332

Public Law 103-332, 108 Stat. 2499 (1994) Public Law 103-332, 108 Stat. 2499 (1994)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law

101-512, as amended, is further amended by 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 on October 1,1994, and $100,000,000 on October 1, 1995” andinserting “$19,121,000 on October 1, 1994, $100,000,000on October 1, 1995, and $255,879,000 on October 1,1996”: Provided, That not to exceed $18,000,000available in fiscal year 1995 may be used for administrative oversight of the Clean Coal Technologyprogram.

Public Law 104-6 Public Law 104-6

Public Law 104-6, 109 Stat. 73 (1995) 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 rescinded and of the funds made available under thisheading for obligation in fiscal year 1997, $150,000,000

are rescinded: Provideprevious appropriationany ongoing project rrequest for proposal uselected.

Public Law Public Law 

Conference Repo

Conference Repo

402, 104th Cong., 

402, 104th Cong., 

The manager

to $18,000,000 in cleafor administration of t

Public Law Public Law 

Public Law 104-2

CLEAN C

(R

Of the funds made avaobligation in fiscal yea$123,000,000 are resc

made available in prevbe available for any oseparate request for pwas selected.
A-20 Program Update 2000

Conference Report (H.R. Conf. Rep. No. Conference Report (H.R. Conf. Rep. No.

863, 104th Cong., 2nd Sess., [1996]) 863, 104th Cong., 2nd Sess., [1996])

CLEAN COAL TECHNOLOGY

(RESCISSION)

Of the funds made available under this heading forobligation in fiscal year 1997 or prior years,$123,000,000 are rescinded: Provided, That funds madeavailable in previous appropriations Acts shall beavailable for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.Senate Report (S. Rep. No. 319, 104th Cong., 2ndSess. [1996])The Committee does not object to the use of up to$16,000,000 in available funds for administration of theclean coal program in fiscal year 1997.House Report (H.R. Rep. No. 625, 104th Cong., 2ndSess. [1996])The Committee does not object to the use of up to$16,000,000 in available funds for administration of theclean coal program in fiscal year 1997.

Public Law 105-18 Public Law 105-18

Public Law 105-18, 111 Stat. 158 (1997) 1 Stat. 158 (1997)

CLEAN COAL TECHNOLOGY

(RESCISSION)

Of the funds made available under this heading forobligation in fiscal year 1997 or prior years,$17,000,000 are rescinded: Provided, That funds 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 105-83 Public Law 105-83

Public Law 105-83, 111 Stat. 37 (1997) 1 Stat. 37 (1997)

Of the funds made available under this heading forobligation in fiscal year 1997 or prior years,$101,000,000 are rescinded: Provided, That funds

made available in previous appropriations Acts shallbe available for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.

Public Law Public Law 

Public Law 105-27

CLEAN CO

(D

 Of the funds made avobligation in prior yearsshall not be available un$15,000,000 shall not be 2000; and $15,000,000 sOctober 1, 2001: Providin previous appropriatioany ongoing project regrequest for proposal unselected.

Conference Report 

Conference Report 

825, 105th Cong. 2

825, 105th Cong. 2

CLEAN CO

The conference agreem$40,000,000 in previouclean coal technology pSenate. The House did The Committees agree tfor administration of thprogram.
Public Law 106-1 Public Law 106-113

Public Law 106-113, ___ Stat. ___ (1999) 13, ___ Stat. ___ (1999)

CLEAN COAL TECHNOLOGY

(DEFERRAL EFERRAL)

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 shallbe available for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.

Conference Report (H.R. Rep. No. 406, Conference Report (H.R. Rep. No. 406,

106th Cong., 1st Sess. [1999]) 106th Cong., 1st Sess. [1999])

CLEAN COAL TECHNOLOGY

(DEFERRAL EFERRAL)

The conference agreement provides for the deferral of$156,000,000 in previously appropriated funds for theclean coal technology program as proposed by theSenate instead of a deferral of $256,000,000 as proposed by the House. The managers agree that up to$14,400,00 may be used for program direction.

Public Law 106-291 Public Law 106-291

Public Law 106-291, __ Stat. __ (2000) Public Law 106-291, __ Stat. __ (2000)

CLEAN COAL TECHNOLOGY

(DEFERRAL EFERRAL)

Of the funds made available under this heading forobligation in prior years, $67,000,000 shall not beavailable until October 1, 2001: Provided, That fundsmade available in previous appropriations Acts shallbe available for any ongoing project regardless of theseparate request for proposal under which the projectwas selected.
A-22 Program Update 2000
Appendix B: Pr Appendix B: Pr Appendix B: Program Histor ogram Histor ogram Histor

y

Solicitation History Solicitation History

The objective of the CCT-I solicitation, issuedFebruary 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 projects wereselected 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 ofbeing commercialized in the 1990s, more cost-effectivethan current technologies, and capable of achievingsignificant reductions in SO2 and/or NOx emissionsfrom existing coal-burning facilities, particularly thosethat contribute to transboundary air pollution. TheCCT-II PON was the first solicitation implementing therecommendations of the U.S. and Canadian SpecialEnvoys’ report on acid rain. DOE received 55 proposals 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 technologyprojects to demonstrate innovative, energy-efficienttechnologies capable of being commercialized in the1990s. These technologies were to be capable of (1)

achieving significant reductions in emissions of SO2and/or NOx from existing facilities to minimize environmental impacts, such as transboundary and interstate

air pollution; and/or (2) providing for future energyneeds in an environmentally acceptable manner. DOEreceived 48 proposals and selected 13 projects as bestfurthering the goals and objectives of the PON.The CCT-IV PON, issued January 17, 1991, solicitedproposals to conduct cost-shared clean coal technology projects to demonstrate innovative, energyefficient, economically competitive technologies.These technologies were to be capable of (1) retrofitting, repowering, or replacing existing facilities whileachieving significant reductions in the emissions ofSO2, NOx, or both, and/or (2) providing for futureenergy needs in an environmentally acceptablemanner. A total of 33 proposals were submitted inresponse to the PON. Nine projects were selected.The objective of the CCT-V PON, issued July 6, 1992,was to solicit proposals to conduct cost-shareddemonstration projects that significantly advance theefficiency and environmental performance of coalusing technologies and are applicable to either new orexisting facilities. In response to the solicitation, DOEreceived proposals for 24 projects and selected 5projects.

Selection anSelection an

History History HistoryThe following is a hisnegotiations for the CCprovided through SeptJuly 1986 July 1986July 1986Nine projects were selprojects selected to renegotiations were uns

March 1987

DOE signed cooperatiparticipants, Coal TecCyclone Combustor wAsh Control) and The PFBC Demonstration June 1987 June 1987June 1987DOE signed a cooperaparticipant, The BabcoMcDermott TechnologProject Extension and July 1987 July 1987July 1987DOE signed a cooperaparticipant, Energy anCorporation (EnhanciReburning and Sorben
B-2 Program Update 2000

September 1987

General Electric Company withdrew its proposal(Integrated Coal Gasification Steam Injection GasTurbine Demonstration Plants with Hot Gas Cleanup).

October 1987

Weirton Steel Corporation withdrew its proposal,Direct Iron Ore Reduction to Replace Coke Oven/BlastFurnace for Steelmaking, from furtherconsideration.Four more CCT-I projects were selected: Colorado-UteElectric Association, Inc. (Nucla CFB DemonstrationProject); TRW, Inc. (Advanced Slagging Coal Combustor Utility Demonstration Project); MinnesotaDepartment of Natural Resources (COREX IronmakingDemonstration Project); and Foster Wheeler PowerSystems, Inc. (Clean Energy IGCC DemonstrationProject).

December 1987

DOE signed cooperative agreements with two moreCCT-I participants, Ohio Ontario Clean Fuels, Inc.,(Prototype Commercial Coal/Oil Coprocessing Project)and Energy International, Inc. (Underground CoalGasification Demonstration Project).

January 1988

DOE signed a cooperative agreement with The M.W.Kellogg Company and Bechtel Development Companyfor a CCT-I project, The Appalachian IGCC Demonstration Project.

September 1988

Sixteen projects were selected under CCT-II.

November 1988

DOE signed a cooperative agreement with CCT-Iparticipant, TRW, Inc. (Advanced Slagging CoalCombustor Utility Demonstration Project).

December 1988

Negotiations were terminated with MinnesotaDepartment of Natural Resources (COREX IronmakingDemonstration Project) under CCT-I.DOE selected three more CCT-I projects: ABBCombustion Engineering, Inc. and CQ Inc. (Development of the Coal Quality ExpertTM); Western EnergyCompany (formerly Rosebud SynCoal Partnership,now Western SynCoal LLC; Advanced Coal Conversion Process Demonstration); and United CoalCompany (Coal Waste Recovery Advanced Technology Demonstration).June 1989 June 1989June 1989The City of Tallahassee CCT-I project, ACFB Repowering, was selected from the alternate list.The M.W. Kellogg Company and Bechtel Development Company withdrew their CCT-I project, CleanEnergy IGCC Demonstration Project.

September 1989

United Coal Company withdrew its CCT-I project, CoalWaste Recovery Advanced TechnologyDemonstration.

November 1989

DOE 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 1989

Thirteen projects were selected under CCT-III.

DOE signed cooperativparticipants: ABB Com(SNOXTM Flue Gas CleaThe Babcock & Wilcox CFlue Gas Cleanup DemoPassamaquoddy Tribe (ery Scrubber); Pure Air Flue Gas DesulfurizatioSouthern Company SerAdvanced Combustion Boiler).Energy International, InUnderground Coal Gasi

February 1990

Foster Wheeler Power SCCT-I proposal, Clean EProject.April 1990 April 1990April 1990DOE signed cooperativparticipants: The Appa(PFBC Utility DemonstWilcox Company (Demfor Cyclone Boiler NOx 

Company Services, IncApplications of TechnoProcess).June 1990 June 1990June 1990DOE signed cooperativparticipants of one CCTEngineering, Inc. and CCoal Quality ExpertTM), pants: Southern Compation of Selective Catalythe Control of NOx Emis

Fired Boilers) and Tran
Corporation (LNS Burner for Cyclone-Fired BoilersDemonstration Project).

September 1990

DOE signed cooperative agreements with one CCT-Iparticipant, Western Energy Company (formerlyRosebud SynCoal Partnership, now Western SynCoalLLC); Advanced Coal Conversion Process Demonstration); one CCT-II participant, Southern CompanyServices, Inc. (180-MWe Demonstration of AdvancedTangentially Fired Combustion Techniques for theReduction of NOx Emissions from Coal-Fired Boilers);

and one CCT-III participant, ENCOAL Corporation(ENCOAL® Mild Coal Gasification Project).

Negotiations were terminated with CCT-II participant,Southwestern Public Service Company (Nichols CFBRepowering Project).

October 1990

DOE signed cooperative agreements with four CCT-IIIparticipants: AirPol, Inc. (10-MWe Demonstration ofGas Suspension Absorption); The Babcock & WilcoxCompany (Full-Scale Demonstration of Low-NOx Cell

Burner Retrofit); Bechtel Corporation (Confined ZoneDispersion Flue Gas Desulfurization Demonstration);and Energy and Environmental Research Corporation(Evaluation of Gas Reburning and Low-NOx Burners

on a Wall-Fired Boiler).

November 1990

DOE signed cooperative agreements with one CCT-Iparticipant, The City of Tallahassee (Arvah B.Hopkins Circulating Fluidized-Bed RepoweringProject; now JEA and the JEA Large-Scale CFBCombustion Demonstration Project); one CCT-IIparticipant, ABB Combustion Engineering, Inc.(Combustion Engineering IGCC Repowering Project);and two CCT-III participants, Bethlehem Steel

Corporation (Blast Furnace Granular-Coal InjectionSystem Demonstration Project) and LIFAC–NorthAmerica (LIFAC Sorbent Injection DesulfurizationDemonstration Project).

December 1990

Negotiations terminated with CCT-II participant,Otisca Industries, Ltd. (Otisca Fuel DemonstrationProject) and CPICORTM.

March 1991

DOE signed cooperative agreements with three CCTIII participants: MK-Ferguson Company (now NOXSOCorporation (Commercial Demonstration of theNOXSO SO2/NOx Removal Flue Gas Cleanup System);

Public Service Company of Colorado (Integrated DryNOx/SO2 Emissions Control System); and TampaElectric Company (formerly Clean Power CogenerationLimited Partnership; now Tampa Electric IntegratedGasification Combined-Cycle Project).TRW, Inc., withdrew its CCT-I project (AdvancedSlagging Coal Combustion Utility DemonstrationProject).April 1991 April 1991April 1991DOE signed a cooperative agreement with CCT-IIIparticipant, Alaska Industrial Development and ExportAuthority (Healy Clean Coal Project).June 1991 June 1991June 1991DOE withdrew its sponsorship of the Ohio OntarioClean Fuels, Inc., CCT-I project, Prototype CommercialCoal/Oil Coprocessing Plant.

August 1991

DOE signed a cooperative agreement with CCT-IIIparticipant, DMEC-1 Limited Partnership (formerlyDairyland Power Cooperative; PCFB DemonstrationProject).

TransAlta Resources withdrew its CCT-II prFired Boilers Demons

September 1991

Nine projects were selCoal Tech CorporationCyclone Combustor wAsh Control, final reppleted.April 1992 April 1992April 1992Tri-State Generation aInc.’s (formerly ColorInc.) CCT-I project, Nfinal reports issued anJune 1992 June 1992June 1992The City of Tallahassetured and transferred tL.P. (York County EneProject).July 1992 July 1992July 1992DOE signed cooperatiparticipants: TennesseYork State Electric & GCoal Reburning Demo175-MWe Wall-Fired Coal Gasification Rep(Wabash River Coal G

August 1992

DOE signed a cooperaparticipant, Sierra PacIGCC Power Project).Cordero Mining Compfor its CCT-IV projectDemonstration Projec
B-4 Program Update 2000

At the participant’s request, Union Carbide Chemicalsand Plastics Company, Inc. (CCT-IV) was granted anextension of one year to the DOE deadline for completing negotiations of its Demonstration of the UnionCarbide CANSOLVTM System at the Alcoa GeneratingCorporation Warrick Power Plant.

October 1992

DOE signed cooperative agreements with one CCT-IIIparticipant, Air Products and Chemicals, Inc. (Commercial-Scale Demonstration of the Liquid PhaseMethanol [LPMEOHTM] Process) and with four CCTIV participants: Custom Coals International (SelfScrubbing CoalTM: 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 1992

The Babcock & Wilcox Company’s (now McDermottTechnology, Inc.) CCT-I project, LIMB DemonstrationProject Extension and Coolside Demonstration, finalreports issued and project completed.May 1993 May 1993May 1993Five projects were selected under CCT-V: Four RiversEnergy Partners, L.P. (Four Rivers Energy Modernization Project (formerly Calvert City Advanced EnergyProject, now McIntosh Unit 4B Topped PCFB Demonstration Project); Duke Energy Corporation (CamdenClean Energy Demonstration Project); CenteriorEnergy Corporation, on behalf of CPICORTM Management Company LLC (Clean Power from IntegratedCoal/Ore Reduction [CPICORTM]); Arthur D. Little, Inc.(Clean Coal Combined-Cycle Project; formerlyDemonstration of Coal Diesel Technology at EastonUtilities; now Clean Coal Diesel Demonstration

Project); and Pennsylvania Electric Company (WarrenStation Externally Fired Combined-Cycle Demonstration Project).July 1993 July 1993July 1993Union Carbide Chemicals and Plastics Company, Inc.,withdrew its CCT-IV proposal, Demonstration of theUnion Carbide CANSOLVTM System at the AlcoaGenerating Corporation Warrick Power Plant.

February 1994

The Passamaquoddy Tribe’s CCT-III project, CementKiln Flue Gas Recovery Scrubber, final reports issuedand project completed.

March 1994

The Babcock & Wilcox Company’s CCT-II project,Demonstration of Coal Reburning for Cyclone BoilerNOx Control, final reports issued and project completed.June 1994 June 1994June 1994DOE signed a cooperative agreement with CCT-Vparticipant, Arthur D. Little, Inc. (Coal Diesel Combined-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 1994

DOE signed cooperative agreements with two CCT-Vparticipants, Four Rivers Energy Partners, L.P. (FourRivers Energy Modernization Project); and Pennsylvania Electric Company (W

Combined-Cycle DemoThe CCT-III project, CoNOXSO SO2/NOx Remowas relocated and trans

September 1994 The Air Products and Ch

Commercial-Scale DemMethanol (LPMEOHTMAir Products Liquid Pha

December 1994 DOE signed a cooperati

participant, Clean Energ(formerly Duke Energy Demonstration Project; Demonstration Project)

March 1995 TAMCO Power Partner

IGCC Demonstration Pextension and the projeApril 1995 April 1995April 1995 Bethlehem Steel CorporInnovative Coke Oven GRetrofit Applications, wagreement with DOE besuspended at the demonJune 1995 June 1995June 1995 AirPol, Inc.’s CCT-II prof Gas Suspension Absand project completed.
September 1995

The Babcock & Wilcox Company’s CCT-II project,SOx-NOx-Rox BoxTM Flue Gas Cleanup DemonstrationProject, final reports issued and project completed.

December 1995

The Tennessee Valley Authority and New York StateElectric & Gas Corporation finalized an agreement toallow the project, Micronized Coal Reburning Demonstration for NOx Control, to be conducted at bothMilliken Station in Lansing, NY and Eastman KodakCompany in Rochester, NY.The Babcock & Wilcox 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, Tidd PFBCDemonstration Project, final reports issued and projectcompleted.May 1996 May 1996May 1996The ABB Combustion Engineering, Inc. CCT-IIproject, Combustion Engineering IGCC RepoweringProject, was concluded.June 1996 June 1996June 1996Pure Air on the Lake’s CCT-II project, Advanced FlueGas Desulfurization Project, final reports issued andproject completed.

August 1996

The Arthur D. Little, Inc., CCT-V project was restructured and retitled as the Clean Coal Diesel Demonstration Project.

September 1996

The Appalachia Power Company CCT-II project, PFBCUtility Demonstration Project, was concluded.

October 1996

DOE signed a cooperative agreement with CCT-Vparticipant, CPICORTM Management Company LLC(Clean Power from Integrated Coal/Ore Reduction[CPICORTM]).

November 1996

Southern Company Services’ CCT-II project, Demonstration of Selective Catalytic Reduction Technologyfor the Control of NOx Emissions from High-Sulfur,

Coal-Fired Boilers, final reports issued and projectcompleted.

December 1996

ABB Environmental Systems’ CCT-II project, SNOXTMFlue Gas Cleaning Demonstration Project, final reportsissued and project completed.May 1997 May 1997May 1997The Pennsylvania Electric Company CCT-V project,Externally Fired Combined-Cycle DemonstrationProject, was concluded.

September 1997

DOE 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 1997

ENCOAL 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 1998

DOE signed a new corestructured City of LaMcIntosh Unit 4B TopProject (formerly the Fproject).April 1998 April 1998April 1998LIFAC–North AmericSorbent Injection DesuProject, final reports iJune 1998 June 1998June 1998Southern Company Sestration of Innovative the CT-121 FGD Procproject completed.The ABB Combustion CCT-I project, DeveloExpertTM, final reports 

September 1998

Energy and EnvironmCCT-I project, EnhanReburning and Sorbenand project completedDOE signed a revised restructured ThermoCCombustor Design Qu

October 1998

Energy and EnvironmCCT-III project, EvaluLow-NOx Burners on a 

issued and project com
B-6 Program Update 2000

September 1999

Energy 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 1999

Southern Company Services, Inc.’s CCT-II project,Demonstration of Innovative Applications of Technology for the CT-121 FGD Process, final report issuedand project completed.New York State Electric & Gas Corporation’s CCT-IVproject, Milliken Clean Coal Technology Demonstration Project, final report issued and project completed.Bethlehem Steel Corporation’s CCT-III project, BlastFurnace Granular-Coal Injection System Demonstration Project, final report issued and project completed.

December 1999

New York State Electric & Gas Corporation’s CCT-IVproject, Micronized Coal Reburning Demonstration forNO

x Control, final report issued and project completed.

NOXSO Corporation’s project, Commercial Demonstration of the NOXSO SO2/NOx Removal Flue GasCleanup System, was terminated.

January 2000

Custom Coal International’s CCT-IV project, SelfScrubbing CoalTM : An Integrated Approach to CleanAir, was terminated.

February 2000

Public Service Company of Colorado’s CCT-III project,Integrated Dry NOx/SO2 Emissions Control System,

final report issued and project completed.

September 2000

Wabash River Coal Gasification Repowering ProjectJoint Venture’s CCT-IV project, Wabash River CoalGasification Repowering Project, final report issuedand project completed.
cant technical and envand disseminated. Dacompliance data to merequirements and perfcommercialization of 

Appendix C: Appendix C: Appendix C: Environmental onmental onmental onmental onmental Aspects Aspects Aspects

and EISs for 4 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) thatwill ensure operational compliance and that signifiIntroduction oductionoduction oductionoduction The U.S. Department of Energy employs a three-step process to ensure that the CCT Program and its projects comply with the procedural requirements of

the National Environmental Policy Act (NEPA), 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 programmatic 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), environmental 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 September 30, 2000, to complete NEPA reviews of projects inthe CCT Program. By September 30, 2000, NEPAreviews were completed for 34 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 30,2000, NEPA requirements were satisfied with a CX for1 project, MTFs for 17 projects, EAs for 18 projects

a Includes an MTF (1988) and an EA (1989)

required for one project

Memoranda-to-fileEnvironmental assessments

b Includes an EA for a project that

was withdrawn

Exhibit C-1

NEPA Reviews Completed as of Septemb

Categorical exclusioEnvironmental imp

Number of Projects

Fiscal Year Fiscal YearFiscal Year
C-2 Program Update 2000

tion is used, along with gathered by DOE, as thdocuments that are prepproject. These NEPA dconsidered, and publishCEQ and DOE regulati

Categorical Exclus

Categorical Exclus

“Subpart D—Typical CNEPA regulations provas a class of actions thaindividually or cumulaton the human environmCoal Reburning Demon

Pulse Combustor Desigdetermined to be covereAugust 1992 and Nove

Memoranda-to-Fil

The MTF was establishguidelines were first issintended for circumstanof the proposed action wthe action had not been exclusion from NEPA dMTF was terminated as Exhibit C-2 lists the 17 was prepared.

Environmental Ass

Environmental Ass

An EA has the followin1. To provide sufficien

determining whether preparation of an EIimpact (FONSI);

The Role of NEPA in the

CCT Program

NEPA was initially enacted in 1969 as Public Law 91-190 and is codified at 42 U.S.C. §4321 et seq. The

applicability of NEPA to the CCT Program is encapsulated in the following provision (Section 102):

[A]ll agencies of the Federal Government shall—. . .(C) include in every recommendation or report on proposals for legislation and other major Federal actions significantly affecting the quality of the human environment, adetailed statement by the responsible official on—i. the environmental impact of the proposed action,ii. any adverse environmental effects which cannot be

avoided should the proposal be implemented,

iii. alternatives to the proposed action,iv. the relationship between local short-term uses of man’s

environment and the maintenance and enhancement oflong-term productivity, and

v. any irreversible and irretrievable commitments of

resources which would be involved in the proposedaction should it be implemented. . . .

(E) study, develop, and describe appropriate alternatives torecommended courses of action in any proposal whichinvolves unresolved conflicts concerning alternative uses ofavailable resources[.]Through NEPA, Congress created the CEQ, which haspromulgated regulations that ensure compliance withthe Act.

Compliance with NEPA

In November 1989, a PEIS was completed for theCCT Program. This PEIS addressed issues such aspotential global climatic modification and theecological and socioeconomic impacts of the CCTProgram. The PEIS evaluated the following twoalternatives:• “No action,” which assumed that conventional

coal-fired technologies with conventional flue gasdesulfurization controls would continue to be used,and

• “Proposed action,” which assumed that successfully demonstrated clean coal technologies would

undergo widespread commercialization by the year2010.

In preselection project-specific environmentalreviews, DOE evaluates the environmental aspects ofeach proposed demonstration project. Reviews areprovided to the Source Selection Official for consideration in the project selection process. The sitespecific environmental, health, safety, and socioeconomic issues associated with each proposed projectare examined during the NEPA review. As part of thecomprehensive evaluation prior to selecting projects,the strengths and weaknesses of each proposal arecompared with the environmental evaluation criteria.To the maximum extent possible, the environmentalimpacts of each proposed project and practicalmitigating measures are considered. Also, a list ofnecessary permits is prepared, to the extent known;these are permits that would need to be obtained inimplementing the proposed project.Upon selection, project participants are required toprepare and submit additional environmental information. This detailed site- and project-specific informa-
2. To aid an agency’s 

no EIS is necessary

nary review of propimpacts, and identimitigation measure

3. To facilitate prepar

necessary.

An EA’s contents are basis and depend on thappropriate, a DOE Eor wetlands assessmenmay include analyses determinations.If an agency determinnot necessary to prepaCouncil on Environmdescribe the FONSI apresents the reasons wsignificant effect on thwhich an EIS thereforFONSI includes the Eany other related enviand DOE regulations the public that a FONprovides copies of the request.Exhibit C-3 lists the 1been prepared. The eproject that was subseprogram—TransAlta RCorporation’s Low-N

Utility Cyclone Boilerterminated—ABB Cobustion Engineering IBethlehem Steel CorpGas Cleaning System Pennsylvania ElectricFired Combined-Cycl

Project and Participant Completed

CCT-IDevelopment of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc. and CQ Inc.) 4/27/90LIMB Demonstration Project Extension and Coolside Demonstration 6/2/87(McDermott Technology, Inc.)Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 3/26/87(Coal Tech Corporation)Nucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State 4/18/88Generation and Transmission Association, Inc.)Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Hennepin site) 5/9/88(Energy and Environmental Research Corporation)Tidd PFBC Demonstration Project (The Ohio Power Company) 3/5/87CCT-IISNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) 1/31/90SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project 9/22/89

(The Babcock & Wilcox Company)Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 5/22/89(Southern Company Services, Inc.)Demonstration of Selective Catalytic Reduction Technology for the Control of NOx 8/16/89

Emissions from High-Sulfur, Coal-Fired Boilers (Southern Company Services, Inc.)180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the 7/21/89Reduction of NOx Emissions from Coal-Fired Boilers (Southern Company Services, Inc.)

CCT-III CCT-III CCT-III10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) 9/21/90

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit (The Babcock & Wilcox Company) 8/10/90

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) 9/25/90Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler (Energy and 9/6/90

Environmental Research Corporation)LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) 10/2/90Integrated Dry NOx/SO2 Emissions Control System (Public Service Company of Colorado) 9/27/90

Exhibit C-2

Memoranda-to-File Completed
C-4 Program Update 2000

Project and Participant 

CCT-IEnhancing the Use of Coals by Gas Reburning and Sorbent Injection (Lakeside site) (Energy and Environmental Research Corporation) 

Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) 

CCT-IICombustion Engineering IGCC Repowering Project (ABB Combustion Engineering, Inc.) (project terminated) 

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

Innovative Coke Oven Gas Cleaning System for Retrofit Applications (Bethlehem Steel Corporation) (project terminated) Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Low-NO

x

/SO2 Burner Retrofit for Utility Cyclone Boilers (TransAlta Resources Investment Corporation) (project withdrawn) 

CCT-III CCT-III CCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Company, L.P.) 

Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) ENCOAL® Mild Coal Gasification Project (ENCOALCorporation) 

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) 

CCT-IVSelf-Scrubbing CoalTM: An Integrated Approach to Clean Air (Custom Coals International) Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) Warren Station Externally-Fired Combined-Cycle Demonstration Project (Pennsylvania Electric Company) (Warren Station site) (project terminated) Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) CCT-VClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) 

Exhibit C-3

Environmental Assessments Completed as of September 30, 2000
Project and Participant 

CCT-IJEA Large-Scale CFB Combustion Demonstration Project (JEA)a 

CCT-III CCT-III CCT-IIIMcIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland ElecCCT-VMcIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, 

Lakeland Electric)Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM ManagemCompany LLC)Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LL

a EIS completed in June 2000.

Project and Participant 

CCT-IYork County Energy Partners Cogeneration Project (York County, PA site) 

(York County Energy Partners, L.P.) (project relocated)CCT-III CCT-III CCT-IIIHealy Clean Coal Project (Alaska Industrial Development and Export Authority) Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company)CCT-IVPiñon Pine IGCC Power Project (Sierra Pacific Power Company) * Completion is the date DOE issued a record of decision.

Environmental Impact Statements 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 alternatives that would avoid or minimize adverse impacts orenhance the quality of the human environment.The CEQ regulations state that an EIS is to be morethan a disclosure document; it is to be used by federalofficials in conjunction with other relevant material toplan actions and make decisions. Analysis of alternatives is to encompass those alternatives to be considered by the ultimate decision maker, including acomplete description of the proposed action. In short,the EIS is a means of assessing the environmentalimpacts of a proposed DOE action (rather thanjustifying decisions already made), prior to making adecision to proceed with the proposed action. Consequently, before a record of decision (ROD) is issued,DOE may not take any action that would have anadverse environmental effect or limit the choice ofreasonable alternatives. As seen in Exhibit C-4, theEISs for three projects were completed in 1994. In1995, DOE issued a ROD on the EIS prepared for theYork County Energy Partners project located in YorkCounty, Pennsylvania. This project has been restructured, and a new NEPA compliance document for theJEA project site was completed in 2000, but the RODhad not been issued by the end of the fiscal year.

NEPA Actions in Progress Actions in Progress

Exhibit C-5 lists the status of projects for which theNEPA process has not yet been completed.

Exhibit C-4

Environmental Impact Statements CompEnvironmental Impact Statements Comp

September 30, 2000

Exhibit C-5

NEPA Reviews in Progress as of Septem
C-6 Program Update 2000

Also, in the instructions PON directed proposer

With respect to emisProposers should coelements and compothe PON, “Specific tored”]. Proposers sinformation known emissions of these ttechnology. Some oproposed technology likely unregulated in present. The signifithe additional controtechnology for the cbe explained. An exbe one or more particontrolled by a techpower generation.

The CCT-V PON also stoxics be presented in threquired by DOE. Exhprovide for HAPs monihave completed the HAThe objective of the HAimprove the quality of Hto monitor a broader ranemissions control equipThe CCT Program is cosuch as the Electric Powand the Ohio Coal Devefocused on HAPs moniunder the DOE Coal R&summarizing the sourcefrom coal-fired power pA report released in Jul

Emissions Testing at Six

assessment of HAPs memajor pollution control from the stack. A secon

Assessment of Toxics E

Environmental Monitoring onmental MonitoringCCT project participants are required to develop andimplement an EMP that addresses both complianceand supplemental monitoring. Exhibit C-6 lists thestatus of EMPs for all 38 projects in the CCT Program.The EMP is intended to ensure collection and dissemination of the significant technology-, project-, and sitespecific environmental data necessary for evaluation ofimpacts upon health, safety, and the environment.Further, the data are used to characterize and quantifythe environmental performance of the technology inorder to evaluate its commercialization and deployment potential. In addition to regulatory compliancedata, further monitoring is required to fulfill thefollowing:• Ensure that emissions, ambient levels of pollutants,

and environmental impacts do not exceed expectations projected in the NEPA documents,

• Identify any need for corrective action,• Verify the implementation of any mitigative

measure that may have been identified in a mitigation action plan pursuant to the provisions of an EAor EIS, and

• Provide the essential data on the environmental

performance of the technology needed to evaluatethe potential impact of future commercialization,including the ability of the technology to meetrequirements of the Clean Air Act and the 1990amendments.

The objective of the CCT Program’s environmentalmonitoring efforts is to ensure that, when commerciallyavailable, clean coal technologies will be capable ofresponding fully to air toxics regulations that emerge

from the CAAA, and to the maximum extent possible,are in the vanguard of cost-effective solutions toconcerns about public health and safety related to coaluse.Air

Toxics

Title III of the CAAA lists known hazardous airpollutants (HAPs) and, among other things, calls forthe EPA to establish categories of sources that emitthese pollutants. Exploratory analyses suggest thatHAPs may be released by conventional coal-firedpower plants and, presumably, by plants using cleancoal technologies. It is expected that emissionsstandards will be proposed for the electric-powerproduction-source categories. However, there aremany uncertainties as to which HAPs will be regulated, their prevalence in various types and sources ofcoal, and their nature and fate as functions of combustion characteristics and the particular clean coaltechnology used.The CCT Program recognizes the importance ofmonitoring HAPs in achieving widespread commercialization in the late 1990s and beyond. For allprojects with existing cooperative agreements, DOEsought to include HAPs monitoring. A total of 20projects contain provisions for monitoring HAPs.The CCT-V Program Opportunity Notice (PON)acknowledged the importance of HAPs throughout thesolicitation, including them as an aspect of proposalevaluation. The PON addressed the control of airtoxics as an environmental performance criterion.
Project and Participant Stat

CCT-IDevelopment of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc. and CQ Inc.) ComLIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) Com

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) ComNucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State Generation and Transmission Association, Inc.) ComEnhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Com

Com

Tidd PFBC Demonstration Project (The Ohio Power Company) ComAdvanced Coal Conversion Process Demonstration (Western SynCoal LLC) ComJEA Large-Scale CFB Combustion Demonstration Project (JEA) Proje

CCT-IISNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) ComDemonstration of Coal Reburning for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) Com

SO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Com

Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) ComAdvanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) ComDemonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) ComDemonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Com

Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High-Sulfur-Coal-Fired Com

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

Coal-Fired Boilers (Southern Company Services, Inc.)

Exhibit C-6

Status of Environmental Monitoring Plans for CCT Projects as of Septembe
C-8 Program Update 2000

Project and Participant Sta

CCT-III CCT-III CCT-IIICommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Company, L.P.) Com

10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) ComHealy Clean Coal Project (Alaska Industrial Development and Export Authority) ComFull-Scale Demonstration of Low-NO

x Cell Burner Retrofit (The Babcock & Wilcox Company) Com

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) ComBlast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) ComMcIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) On 

ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Com

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

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

Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Com

CCT-IVMicronized Coal Reburning Demonstration for NOx Control (New York State Electric & Gas Corporation) Com

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) ComPiñon Pine IGCC Power Project (Sierra Pacific Power Company) ComWabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Com

Pulse Combustor Design Qualification Test (ThermoChem, Inc.) Com

CCT-VClean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) Com

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management Company LLC) ProjKentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, LLC) To McIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) On 

Exhibit C-6 (continued) Exhibit C-6 (continued)

Status of Environmental Monitoring Plans for CCT Projects as of Septembe
Coal Processing forClean FuelsApplication Category Participant Project Project 

Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project Kentucky Pioneer Energy, LLC Kentucky Pioneer Energy IGCC Demonstration Project Lakeland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project The Ohio Power Company Tidd PFBC Demonstration Project Sierra Pacific Power Company Piñon Pine IGCC Power Project Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle ProjecWabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project Project Joint VentureJEA JEA Large-Scale CFB Combustion Demonstration Project 

ABB Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project 

AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption The Babcock & Wilcox Company Demonstration of Coal Reburning for Cyclone Boiler NOx Cont

The Babcock & Wilcox Company SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project 

Public Service Company of Colorado Integrated Dry NOx/SO2 Emissions Control System 

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project 

Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a WalSouthern Company Services, Inc. Demonstration of Innovative Applications of Technology for th

CT-121 FGD Process

Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Com

Techniques for the Reduction of NOx Emissions from Coal-Fire

ENCOAL Corporation ENCOAL® Mild Coal Gasification Project CPICORTM Management Company LLC Clean Power from Integrated Coal/Ore Reduction (CPICORTM) 

Exhibit C-7

Status of CCT Projects Monitoring Hazardous Air Pollutants as of Septemb

Advanced ElectricPower Generation

Industrial IndustrialIndustrial IndustrialIndustrial

ApplicationsEnvironmental EnvironmentalControl Devices
C-10 Program Update 2000

Power Plants: Phase I Results from the U.S. Department of Energy Study, was released in September

1996 and provided the raw data from the emissionstesting. Emissions data were collected from 16 powerplants, representing nine process configurations,operated by eight different utilities; several powerplants were sites for CCT Program projects. Thepower plants represented a range of different coaltypes, process configurations, furnace types, andpollution 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 of

Hazardous Air Pollutant Emissions from Electric

Utility 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, Mercury

Study Report to Congress, estimates that U.S. industrial sources were responsible for releasing 158 tons

of Mercury into the atmosphere in 1994 and 1995.The EPA estimates that 87 percent of those emissionsoriginate from combustion sources such as waste and

fossil fuel facilities, 10 percent from manufacturingfacilities, 2 percent from area sources, and 1 percentfrom other sources. The EPA also identified fourspecific categories that account for about 80 percentof the total anthropogenic sources: coal-fired powerplants, 33 percent; municipal waste incinerators, 18percent; commercial and industrial boilers, 18 percent;and medical waste incinerators, 10 percent. The nextstep for EPA is to assess the need for enhancedresearch on health effects and on new pollutioncontrol technologies, community “right-to-know”approaches, and regulatory actions.Most recently, the National Academy of Sciencesreleased a report in June 2000 reinforcing the importance, especially for women in their child-bearingyears, of heeding consumption advisories on noncommercial fish to avoid methylmercury. As a result ofthe study, EPA has announced it will regulate mercuryemissions from power plants. The EnvironmentalProtection Agency will propose regulations byDecember 2003.The results of the HAPs program have significantlymitigated concerns about HAPs emission from coalfired generation and focused attention on but a fewflue gas constituents. The results have the potentialto make the forthcoming EPA regulations less strict,which could avoid unnecessary control costs and thussave consumers money on electricity bills.
Appendix D: CCT Appendix D: CCT Project Contacts oject Contacts oject Contacts

Project Contacts oject ContactsListed below are contacts for obtaining further information about specific CCT Program demonstrationprojects. Listed are the name, title, phone number, faxnumber, mailing address, and e-mail address, ifavailable, for the project participant contact person. Inthose instances where the project participant consists ofmore than one company, a partnership, or joint venture,the mailing address listed is that of the contact person.In addition, the names, phone numbers, and e-mailaddresses for contact persons at DOE Headquartersand the National Energy Technology Laboratory(NETL) are provided.

Environmental Contr onmental Control

Devices Devices Devices

SO2 Control T Control T Control Technologies echnologiesechnologies

10-MWe Demonstration of Gas Suspension e Demonstration of Gas Suspension Absorp- Absorp- Absorption

Participant:AirPol, Inc.Contacts:Niels H. Kastrup

(281) 539-3400(281) 539-3411 (fax)nhk@flsmiljous.com

FLS miljo, Inc.

100 Glenborough DriveHouston, TX 77067

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Confined Zone DispeDemonstration

Participant:Bechtel CorporationContacts:Joseph T. Newman, Pr

(415) 768-1189(415) 768-2095 (fax

Bechtel Corporation

P.O. Box 193965

San Francisco, CA 

Lawrence Saroff, DOE

lawrence.saroff@hq

James U. Watts, NETL

james.watts@netl.d

LIFAC Sorbent Injec

AC Sorbent Injec

stration Pr stration Prstration ProjectParticipant:LIFAC–North AmericaContacts:John Scott

(703) 218-2744(703) 934-3029 (fax

Kaiser Engineers, In

9300 Lee HighwayFairfax, VA 22031

Lawrence Saroff, DOE

lawrence.saroff@hq

James U. Watts, NETL

james.watts@netl.d
D-2 Program Update 2000

Advanced Flue Gas Desulfurization Demonstration

Project

Participant:Pure Air on the Lake, L.P.Contacts:Tim Roth

(610) 481-6257(610) 481-7166 (fax)

Pure Air on the Lake, L.P.

c/o Air Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Demonstration of Innovative Applications of Demonstration of Innovative Applications of

Technology for the CT-121 FGD Process

Participant:Southern Company Services, Inc.Contacts:David P. Burford, Project Manager

(205) 992-6329(205) 992-7535 (fax)dpburfor@southernco.comSouthern Company42 Inverness ParkwaySuite 340Birmingham, AL 35242

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

NOx Control T Control T Control Technologies echnologiesechnologies

Micronized Coal Reburning Demonstration for NOxControl

Participant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)

New York State Electric & Gas Corporation

Corporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Demonstration of Coal Reburning for Cyclone

Boiler NO Boiler NOBoiler NOx Control Control Control Control Control

Participant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)dot.k.johnson@mcdermott.comMcDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

John C. McDowell, NETL, (412) 386-6175

mcdowell@netl.doe.gov

Full-Scale Demonstrat

Retrofit RetrofitRetrofit RetrofitRetrofitParticipant:The Babcock & Wilcox Contacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fadot.k.johnson@mcMcDermott Techn1562 Beeson StreeAlliance, OH 4460

Lawrence Saroff, DOE

lawrence.saroff@h

James U. Watts, NETL, 

james.watts@netl.do

Evaluation of Gas RebBurners on a Burners on a 

Wall-Fir all-Fire

e

e

Participant:Energy and EnvironmenContacts:Blair A. Folsom, Senior 

(949) 859-8851, ext. (949) 859-3194 (fax)

General Electric Ener

Research Corporation18 MasonIrvine, CA 92618

Lawrence Saroff, DOE/

lawrence.saroff@hq.

Jerry L. Hebb, NETL, (4

hebb@netl.doe.gov
Demonstration of Selective Catalytic Reduction

Technology for the Contr the Contr the Control of NO ol of NOol of NOx Emissions from

High-Sulfur, Coal-Fir , Coal-Fir, Coal-Fired Boilers ed Boilersed Boilers

Participant:Southern Company Services, Inc.Contacts:Larry Monroe

(205) 257-7772(205) 257-5367 (fax)

Southern Company Services, Inc.

Mail Stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

180-MWe Demonstration of e Demonstration of Advanced Advanced Advanced Advanced Advanced 

Tangentially angentiallyangentially

Fired Combustion ed Combustion 

Techniques for the Reduction of the Reduction of

NOx Emissions from Coal-Fired Boilers ed Boilersed Boilers

Participant:Southern Company Services, Inc.Contacts:Larry Monroe

(205) 257-7772(205) 257-5367 (fax)

Southern Company Services, Inc.

Mail Stop 14N-8195P.O. Box 2641Birmingham, AL 35291-8195

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Demonstration of Demonstration of Advanced Combustion Advanced Combustion 

Techniques for niques forniques for a 

Wall-Fir all-Fired Boiler ed Boilered Boiler

Participant:Southern Company Services, Inc.Contacts:John N. Sorge, Research Engineer

(205) 257-7426(205) 257-5367 (fax)

Southern Company Services, Inc.

P.O. Box 2641Birmingham, AL 35291-8195

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James R. Longanbach, NETL, (304) 285-4659

jlonga@netl.doe.gov

Combined SO2 /NOx Control Technologies

Milliken Clean Coal Milliken Clean Coal 

Technology Demonstration

Project

Participant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)

New York State Electric & Gas Corporation

Corporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

SNOXTM Flue Gas Cl

Participant:ABB Environmental SyContacts:Paul Yosick, Project M

(865) 694-5300(865) 694-5213 (fax

Alstom Power, Inc.

1409 Center Point BKnoxville, TN 3793

Lawrence Saroff, DOE

lawrence.saroff@hq

James U. Watts, NETL

james.watts@netl.d

LIMB Demonstration Coolside Demonstrat

Participant:The Babcock & Wilcox Contacts:Paul Nolan

(330) 860-1074(330) 860-2045 (fax

The Babcock & Wi

20 South Van BureP.O. Box 351Barberton, OH 442

Lawrence Saroff, DOE

lawrence.saroff@hq

John C. McDowell, NE

mcdowell@netl.doe
D-4 Program Update 2000

SO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstra- -Rox BoxTM Flue Gas Cleanup Demonstration Pr tion Project

Participant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)dot.k.johnson@mcdermott.com

McDermott Technology, Inc.

1562 Beeson StreetAlliance, OH 44601

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Enhancing the Use of Coals by Gas Reburning andSorbent Injection

Participant:Energy and Environmental Research CorporationContacts:Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140(949) 859-3194 (fax)

General Electric Energy and Environmental

Research Corporation18 MasonIrvine, CA 92618

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

Integrated Dry NOx/SO2 Emissions Control System ol Systemol System

Participant:Public Service Company of ColoradoContacts:Terry Hunt, Project Manager

(303) 571-7113(303) 571-7868 (fax)terryh@ueplaza.com

Utility Engineering

550 15th Street, Suite 900

Denver, CO 80202-4256

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

Advanced ElAdvanced El

Generation GenerationGeneration GenerationGeneration

Fluidized-Bed Combu

McIntosh Unit 4A PCF

Participant:City of Lakeland, LakelaContacts:Alfred M. Dodd, Projec

(863) 834-6461(863) 834-6488 (fax)

Lakeland Electric

501 E. Lemon StreetLakeland, FL 33801-

George Lynch, DOE/HQ

george.lynch@hq.do

Donald L. Bonk, NETL

dbonk@netl.doe.gov
McIntosh Unit 4B McIntosh Unit 4B 

Topped PCFB Demonstration

Project

Participant:City of Lakeland, Lakeland ElectricContacts:Alfred M. Dodd, Project Manager

(863) 834-6461(863) 834-6488 (fax)

Lakeland Electric

501 E. Lemon StreetLakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald L. Bonk, NETL, (304) 285-4889

dbonk@netl.doe.gov

JEA Large-Scale CFB Combustion Demonstration

Project

Participant:JEAContacts:Joey Duncan

(904) 714-4831(904) 714-4895 (fax)

JEA

4377 Heckscher Drive, NSRPCOJacksonville, FL 32226

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

Tidd PFBC Demonstration Project

Participant:American Electric Power Service Corporation as agentfor The Ohio Power CompanyContacts:Michael J. Mudd

(614) 223-1585(614) 223-2027 (fax)mjmudd@aep.com

American Electric Power

1 Riverside PlazaColumbus, OH 43215

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, NETL, (304) 285-4784

dgeili@netl.doe.gov

Nucla CFB Demonstration Project

Participant:Tri-State Generation and Transmission Association,Inc.Contacts:Stuart Bush

(303) 452-6111(303) 254-6066 (fax)

Tri-State Generation and Transmission Association,

Inc.P.O. Box 33695Denver, CO 80233

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Thomas Sarkus, NETL (412) 386-5981

sarkus@netl.doe.gov

Integrated Gasificat

Kentucky Pioneer IG

Participant:Kentucky Pioneer EnerContacts:H. H. Graves, Presiden

(513) 621-0077(513) 621-5947 (faxhhgraves@globalen

Kentucky Pioneer E

312 Walnut Street, Cincinnati, OH 452

George Lynch, DOE/H

george.lynch@hq.d

Douglas M. Jewell, NE

doug.jewell@netl.d

Piñon Pine IGCC Pow

Participant:Sierra Pacific Power CContacts:Jeffrey W. Hill, Direct

(775) 834-5650(775) 834-4604 (faxjhill@sppc.com

Sierra Pacific Powe

P.O. Box 10100Reno, NV 89520-00

George Lynch, DOE/H

george.lynch@hq.d

Donald W. Geiling, NE

dgeili@netl.doe.gov

Web Site:www.sierrapacific.com
D-6 Program Update 2000

Tampa Electric Integrated Gasification Combined- ampa Electric Integrated Gasification CombinedCycle Pr Cycle PrCycle Project

Participant:Tampa Electric CompanyContacts:Mark Hornick, General Manager, Polk Power Station

(813) 228-1111, ext. 39988(863) 428-5927 (fax)mjhornick@tecoenergy.com

TECO Energy

P.O. Box 111Tampa, FL 33601-0111

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Web Site:www.teco.net/teco/TEKPlkPwrStn.html

Wabash River Coal Gasification Repowering

Project

Participant:Wabash River Coal Gasification Repowering ProjectJoint VentureContacts:Phil Amick, Vice President, Commercial Development

(713) 374-7252(713) 374-7279 (fax)pramick@globalenergyinc.com

Global Energy, Inc.

1000 Louisiana St., Suite 3800Houston, TX 77002

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Leo E. Makovsky, NETL, (412) 386-5814

makovsky@netl.doe.gov

Advanced Combustion/Heat Engines

Healy Clean Coal Project

Participant:Alaska Industrial Development and Export AuthorityContacts:Arthur E. Copoulos, Project Manager II

(907) 269-3029(907) 269-3044 (fax)acopoulos@aidea.org

Alaska Industrial Development and Export

Authority813 W. Northern Lights Blvd.Anchorage, AK 99503

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Robert M. Kornosky, NETL, (412) 386-4521

robert.kornosky@netl.doe.gov

Clean Coal Diesel Demonstration 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

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Coal Pr Coal Pr Coal Process

ocess

Fuels

Indirect Liquefaction

Commercial-Scale Dem

Phase Methanol (LPM

Participant:Air Products Liquid PhaContacts:Edward C. Heydorn, Pro

(610) 481-7099(610) 481-2247 (fax)heydorec@apci.com

Air Products and Che

7201 Hamilton BouleAllentown, PA 1819

Edward Schmetz, DOE/

edward.schmetz@hq

Robert M. Kornosky, N

robert.kornosky@net
Coal Preparation Technologies echnologiesechnologies

Advanced Coal Conversion Process Demonstration

Participant:Western SynCoal LLCContacts:Ray W. Sheldon, P.E., Director of Development

(406) 252-2277, ext. 456(406) 252-2090 (fax)

Western SynCoal LLC

P.O. Box 7137Billings, MT 59103-7137

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk III, NETL, (412) 386-6406

joseph.renk@netl.doe.gov

Development of the Coal Quality ExpertTM

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) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk III, NETL, (412) 386-6406

joseph.renk@netl.doe.gov

Web Site:www.fuels.bv.com:80/cqe/cqe.htm

Mild Gasification

ENCOAL® Mild Coal Gasification Project

Participant:ENCOAL CorporationContacts:James P. Frederick, Project Director

(307) 686-2720, ext. 29(307) 686-2894 (fax)jfrederick@vcn.com

SGI International

319 South Gillette Ave., Suite 260P.O. Box 3038Gillette, WY 82717

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Douglas M. Jewell, NETL, (304) 285-4720

doug.jewell@netl.doe.gov

Industrial AIndustrial A

Blast Furnace GranuDemonstration Proje

Participant:Bethlehem Steel CorpoContacts:Robert W. Bouman, M

(610) 694-6792(610) 694-2981 (fax

Bethlehem Steel Co

Building C, Room 2Homer Research LaMountain Top CamBethlehem, PA 180

Douglas Archer, DOE/

douglas.archer@hq

Leo E. Makovsky, NE

makovsky@netl.do
D-8 Program Update 2000

Clean Power from Integrated Coal/Ore Reduction

(CPICORTM) (CPICORTM)

Participant:CPICORTM Management Company, LLCContacts:Reginald Wintrell, Project Director

(801) 227-9214(801) 227-9198 (fax)

CPICORTM Management Company, LLC

P.O. Box 2500Provo, UT 84603

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Douglas M. Jewell, NETL, (304) 285-4720

doug.jewell@netl.doe.gov

Advanced Cyclone Combustor with Internal Sulfur,

Nitrogen, and ogen, and ogen, and ogen, and ogen, and Ash Contr Ash ContrAsh Control

Participant:Coal Tech CorporationContacts:Bert Zauderer, President

(610) 667-0442(610) 667-0576 (fax)coaltechbz@compuserve.com

Coal Tech Corporation

P.O. Box 154Merion Station, PA 19066

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Cement Kiln Flue Gas Recovery Scrubber

Participant:Passamaquoddy TribeContacts:Thomas N. Tureen, Project Manager

(207) 773-7166(207) 773-8832 (fax)tntureen@gwi.net

Passamaquoddy Technology, L.P.

1 Monument Way, Suite 200Portland, ME 04101

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

John C. McDowell, NETL, (412) 386-6175

mcdowell@netl.doe.gov

Pulse Combustor Design Qualification Design Qualification Test

Participant:ThermoChem, Inc.Contacts:William G. Steedman, Senior Systems Engineer

(410) 354-9890, ext. 43(410) 354-9894 (fax)wsteedman@tchem.net

ThermoChem, Inc.

6001 Chemical RoadBaltimore, MD 21226

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Leo Makovsky, NETL, (412) 386-5814

makovsky@netl.doe.gov
Appendix E: Appendix E: Appendix E: Acronyms, Abbreviations, a

eviations, a

Symbols Symbols Symbols

¢ cent°C degrees Celsius°F degrees Fahrenheit$ dollars (U.S.)$/kw dollars per kilowatt$/ton dollars per ton% percent® registered trademarkTM trademarkABB CE ABB Combustion Engineering, Inc.ABB ES ABB Environmental SystemsACFB atmospheric circulating fluidized-bedADL Arthur D. Little, Inc.AEO2000 Annual Energy Outlook 2000

AER99 Annual Energy Review 1999

AFBC atmospheric fluidized-bed

combustion

AFGD advanced flue gas desulfurizationAIDEA Alaska Industrial Development and

Export Authority

AOFA advanced overfire airAPEC Asia Pacific Economic CooperationAPF advanced particulate filterARIL Advanced Retractable Injection

Lances

ASME American Society of Mechanical

Engineers

Ass’n. AssociationATCF after tax cash flowsatmatmosphere(s)

avg. averageBFGCI blast furnace granular-coal injectionBG British GasBtu British thermal unit(s)Btu/kWh British thermal units per kilowatthourB&W The Babcock & Wilcox CompanyCAAA Clean Air Act Amendments of 1990CaCO3 calcium carbonate (calcitic

limestone)

CaO calcium oxide (lime)Ca(OH)2 calcium hydroxide (calcitic hydrated

lime)

Ca(OH)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 Program

CCT I First CCT Program solicitationCCT II Second CCT Program solicitationCCT III Third CCT Program solicitationCCT IV Fourth CCT Program solicitationCCT V Fifth CCT Program solicitationCCT ProgramClean Coal Technology

Demonstration Program

CD-ROM ComCDL® Coal

CenPEEP Cent

Envi

CEQ CounCFB circuC/H carboCKD cemeCO carboCO2 carboCOP ConfCT-121 ChiyCQETM Coal CQIMTM Coal CX categCZD confDER discrDME dimeDOE U.S. DOE/HQ U.S. 

Head

DSE dust DSI dry sEA envirEER Ener

Corp

EERC Ener

Cent

EFCC exter
E-2 Program Update 2000

EIA Energy Information AdministrationEIS environmental impact statementEIV Environmental Information VolumeEMP environmental monitoring planEPA U.S. Environmental Protection

Agency

EPAct Energy Policy Act of 1992EPDC Japan’s Electric Power Development

Company

EPRI Electric Power Research InstituteESP electrostatic precipitatorEWG exempt wholesale generatorext. extensionFBC fluidized-bed combustionFCCC Framework Convention on Climate

Change

FE Office of Fossil EnergyFeO iron oxideFe2S pyritic sulfur

FERC Federal Energy Regulatory

Commission

FETC Federal Energy Technology Center

(now NETL)

FGDflue gas desulfurizationFONSI finding of no significant impactFRP fiberglass-reinforced plasticft, ft2, ft3 foot (feet), square feet, cubic feet

FY fiscal yeargal. gallon(s)gal/ft3 gallons per cubic footGB gigabyte(s)GE General ElectricGHG greenhouse gasesGNOCIS Generic NO

x Control Intelligent

System

gpm gallons per minute

gr grainsGR gas reburningGR-LNB gas reburning and low-NOx burnerGR-SI gas reburning and sorbent injectionGSA gas suspension absorptionGVEA Golden Valley Electric AssociationGW gigawatt(s)GWe gigawatt(s)-electricH elemental hydrogenH2 molecular hydrogen

H2S hydrogen sulfide

H2SO4 sulfuric acid

HAP hazardous air pollutantHCl hydrogen chlorideHF hydrogen fluorideHGPFS hot gas particulate filter systemHHV higher heating valuehr. hour(s)HRSG heat recovery steam generatorIDInduced DraftIEA International Energy AgencyIEO2000 International Energy Outlook 2000IGCC integrated gasification combinedcyclein, 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)lb. pound(s)L/G liquid-to-gas ratioLHV lower heating valueLIMB limestone injection multistage

burner

LNB low-N

LNCB® low-NLNCFS Low-NLOI loss-oLPMEOHTM Liquid LRCWF low-raLSDE LaborLSFO limestMASB multi-MB megabMCFC molten MCR MaximMDEA methyMgCO3 magneMgO magneMHz megahmills/kWh mills pmin. minutemo. monthMSW municMTCI Manu

Conve

MTF memoMW megawMWe megawMWt megawN elemeN2 molecn.d. not daN/A not apNa/Ca sodiumNa2/S sodiumNaOH sodium Na2CO3 sodium NAAQS Nation

Standa
NEDO New Energy Development

Organization

NEPA National Environmental Policy ActNETL National Energy Technology

Laboratory (formerly FETC)

NH3 ammoniaNm3 Normal cubic meterNO2 nitrogen dioxideNOPR Notice of Proposed RulemakingNO

x nitrogen oxides

NSPS New Source Performance StandardsNSR normalized stoichiometric ratioNTHM net tons of hot metalNTIS National Technical Information

Service

NTPC National Thermal Power CorporationNYSEG New York State Electric & Gas

Corporation

O elemental oxygenO2 molecular oxygenO&M operation and maintenanceOC&PS Office of Coal & Power SystemsOTAG Ozone Transport Assessment GroupOTC Ozone Transport CommissionPASS Pilot Air Stabilization SystemPC personal computerPCAST Presidential Committee of Advisors

on Science and Technology

PCFB pressurized circulating fluidized-bedPDF® Process-Derived Fuel®PEIA programmatic environmental impact

assessment

PEIS programmatic environmental impact

statement

PEOATM Plant Emission Optimization

AdvisorTM

PENELEC Pennsylvania Electric CompanyPEP progress evaluation planPFBC pressurized fluidized-bed

combustion

PJBH pulse jet baghousePM particulate matterPM10 particulate matter less than 10

microns in diameter

PM2.5 particulate matter less than 2.5

microns in diameter

PON program opportunity noticePRB Powder River Basinppm parts per million (mass)ppmv parts per million by volumePSCC Public Service Company of ColoradoPSD Prevention of Significant

Deterioration

psi pound(s) per square inchpsia pound(s) per square inch absolutepsig pound(s) per square inch gaugePUHCA Public Utility Holding Company Act

of 1935

PURPA Public Utility Regulatory Policies

Act of 1978

QF qualifying facilityRAM random access memoryR&D research and developmentRD&D research, development, and

demonstration

REA Rural Electrification AdministrationRP&L Richmond Power & LightROD Record of DecisionROM run-of-minerpmrevolutions per minuteRUS Rural Utility Service

S sulfuSBIR Smascf standscfm standSCR selecSCS SoutSDA spray SFC SyntS-H-U SaarSI sorbeSIP state SM serviSNCR selecSNRBTM SO

x

-

SO2 sulfuSO3 sulfustd ft3 standSOFA sepaSTTR Sma

Prog

SVGA supeTAGTM TechTCLP toxic

proc

TVA TennUAF UnivUARG UtiliUBCL unbuU.K. UnitUNESCO Unit

Scien

URL UnifU.S. UnitUSAID U.S. 

Deve
E-4 Program Update 2000

VFB vibrating fluidized bedVOC volatile organic compoundWC water columnWES wastewater evaporation systemW.G. water gageWLFO wet limestone, forced oxidationwt. weightyr. year(s)State Abbreviations eviationseviations eviationseviationsAK AlaskaAL AlabamaAR ArkansasAZ ArizonaCA CaliforniaCO ColoradoCT ConnecticutDC District of ColumbiaDE DelawareFL FloridaGA GeorgiaHI HawaiiIA IowaID IdahoIL IllinoisIN IndianaKS KansasKY KentuckyLA LouisianaMA MassachusettsMD MarylandME Maine

MI Michigan

MN 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 WisconsinWV West VirginiaWY Wyoming

OtherSome companies have acorporate names. The foreflect the former name BG/L British JEA JacksoKRW Kellog
Index of CCT Index of CCT Projects and Par ojects and Par ojects and Participants ticipantsticipants ticipantsticipants

#10-MWe Demonstration of Gas Suspension

Absorption ES-7, ES-11, ES-21, 2-6, 3-8,3-10, 4-4, 5-3, 5-15, 5-17, 5-22, B-3, B-4,C-3, C-8, C-9, D-1

180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reductionof NOx Emissions from Coal-Fired Boilers

ES-8, ES-12, ES-21, 2-6, 3-8, 4-6, 5-6, 5-15,5-18, 5-68, B-3, B-4, C-3, C-7, C-9, D-3

AABB Combustion Engineering, Inc. ES-17, ES18, ES-22, ES-23, 2-6, 3-10, 4-3, 4-9, 4-11,

4-13, 5-11, 5-16, 5-17, 5-68, 5-140, 5-142,B-2, B-3, B-5, C-3, C-4, C-7, D-7, E-1

ABB Environmental Systems ES-9, ES-12,

ES-21, 2-6, 4-7, 5-15, 5-17, 5-74, B-5, C-3,C-7, C-9, D-3, E-1

ACFB Repowering B-2Advanced Coal Conversion Process

Demonstration ES-18, ES-22, 2-6, 2-12,3-9, 4-11, 5-12, 5-16, 5-18, 5-138, B-2, B-3,C-4, C-7, D-7

Advanced Cyclone Combustor with Internal Sulfur,

Nitrogen, and Ash Control ES-19, ES-22,2-6, 3-9, 4-12, 5-16, 5-17, 5-158, B-1, B-3,C-3, C-7, D-8

Advanced Flue Gas Desulfurization Demonstration

Project ES-7, ES-11, ES-21, ES-23, 2-6,3-8, 3-10, 4-4, 4-13, 5-3, 5-15, 5-18, 5-34,B-2, B-5, C-4, C-7, C-9, D-2

Advanced Slagging Coal Combustor Utility

Demonstration Project B-2, B-3

Air Products and Chemicals, Inc. B-4Air Products Liquid Phase Conversion Company,

L.P. ES-18, ES-22, 2-6, 4-9, 4-11, 5-16,5-17, 5-136, 5-137, B-4, C-4, C-8, D-6

AirPol, Inc. ES-7, ES-11, ES-21, 2-6, 3-10, 4-3,

4-4, 5-15, 5-17, 5-22, 5-25, B-3, B-4, C-3,C-8, C-9, D-1

Alaska Industrial Development and Export

Authority ES-16, ES-22, 2-6, 4-10, 5-16,5-17, 5-130, B-3, C-5, C-8, D-6, E-1

Appalachian IGCC Demonstration Project, The B-2Appalachian Power Company B-2, B-5Arthur D. Little, Inc. ES-15, ES-22, 2-7, 5-16,

5-17, 5-128, B-4, B-5, C-4, C-8, C-9, D-6, E-1

Arvah B. Hopkins Circulating Fluidized-Bed Repowering Project B-3BBabcock & Wilcox Company, The ES-8, ES-9,

ES-11, ES-12, ES-21, ES-23, 2-6, 3-10, 4-3,4-5, 4-6, 4-7, 4-9, 4-13, B-1, B-2, B-3, B-4,B-5, C-3, C-4, C-7, C-8, C-9, 5-15, 5-17,5-48, 5-52, 5-78, 5-82, 5-94, 5-106, 5-130,5-140, D-2, D-3, D-4, E-1

Bechtel Corporation ES-7, ES-11, ES-21, 2-7,

4-3, 4-4, 5-15, 5-17, 5-26, 5-118, B-3, B-4,C-3, C-8, D-1

Bechtel Development Company B-2Bethlehem Steel Corporation ES-19, ES-22, 2-7,

4-12, 5-16, 5-17, B-2, B-3, B-4, B-6, C-3,C-4, C-8, D-7

Blast Furnace Granula

Demonstration Pr2-7, 3-9, 4-1, 4-B-6, C-4, C-8, D

C

Calvert City AdvanceCamden Clean Energy Cement Kiln Flue Gas 

ES-19, ES-22, 25-162, B-2, B-4, 

Centerior Energy CorpClean Coal CombinedClean Coal Diesel Dem

2-7, 3-9, 4-9, 5-B-5, C-4, C-8, C

Clean Energy IGCC DClean Energy Partners Clean Power CogenerClean Power from Inte

(CPICORTM) E5-150, B-4, B-5, 

Coal Diesel CombinedCoal Tech Corporation 

5-16, 5-17, 5-15

Coal Waste Recovery 

Demonstration 

Colorado-Ute Electric Combustion Engineeri

Project B-3, B-

Combustion Engineer
Index-2 Program Update 2000

Commercial Demonstration of the NOXSO SO2/NOx

Removal Flue Gas cleanup System ES-2,B-3, B-4, B-6, C-4

Commercial-Scale Demonstration of the Liquid Phase

Methanol (LPMEOHTM) ES-18, ES-22, 2-6,3-9, 4-11, 5-12, 5-16, 5-17, 5-136, B-4, C-4,C-8, D-6

Confined Zone Dispersion Flue Gas

Desulfurization ES-7, ES-11, ES-21, 2-7,3-8, 4-4, 5-3, 5-15, 5-17, 5-26, B-3, B-4,C-3, C-8, D-1

Cordero Coal-Upgrading Demonstration Project B-3Cordero Mining Company B-3COREX Ironmaking Demonstration Project B-2CPICORTM Management Company LLC ES-22,

2-7, 4-12, 5-16, 5-17, 5-150, B-3, B-4, B-5,C-5, C-8, C-9, D-8

CQ Inc. ES-17, ES-18, ES-23, 2-6, 3-10, 4-9,

4-11, 4-13, 5-11, 5-17, 5-140, 5-142, 5-143,B-2, B-5, C-3, C-7, D-7

Custom Coals International ES-2, B-4, B-6, C-4DDairyland Power Cooperative B-3Demonstration of Advanced Combustion Techniques

for a Wall-Fired Boiler ES-8, ES-12, ES-21,2-6, 2-12, 3-8, 4-6, 5-6, 5-15, 5-18, 5-44,B-2, B-6, C-3, C-7, C-9, D-3

Demonstration of Coal Diesel Technology at Easton

Utilities B-4

Demonstration of Coal Reburning for Cyclone Boiler

NOx Control ES-8, ES-11, ES-21, 2-6, 3-8,

4-6, 5-6, 5-15, 5-17, 5-48, B-2, B-4, C-4,C-7, C-9, D-2

Demonstration of Innovative Applications of

Technology for the CT-121 FGD ES-7,ES-11, ES-21, ES-23, 2-6, 3-8, 4-4, 4-13,5-3, 5-15, 5-18, 5-38, B-2, B-5, B-6, C-4,C-7, C-9, D-2

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx Emissionsfrom High-Sulfur, Coal-Fired Boilers ES-8,ES-12, ES-21, 2-6, 3-8, 4-6, 5-6, 5-15, 5-18,5-64, B-2, B-5, C-3, C-7, D-3

Demonstration of the Union Carbide CANSOLVTM

System at the Alcoa Generating CorporationWarrick Power Plant B-4

Development of the Coal Quality ExpertTM

ES-17, ES-18, ES-22, ES-23, 2-6, 3-9, 3-10,4-11, 4-13, 5-12, 5-16, 5-17, 5-140, 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 Corp. B-4EEastman Kodak Company 5-60, B-5ENCOAL Corporation ES-17, ES-18, ES-22, 2-7,

4-9, 4-11, 5-16, 5-17, 5-144, B-3, B-5, C-4,C-8, C-9, D-7

ENCOAL® Mild Coal Gasification Project ES-2,

ES-17, ES-18, ES-22, 2-7, 3-9, 4-1, 4-11,5-12, 5-16, 5-17, 5-144, B-3, B-5, C-4, C-8,C-9, D-7

Energy and Environmental Research

Corporation ES-8, ES-9, ES-11, ES-12,ES-21, ES-23, 2-6, 2-7, 4-3, 4-5, 4-6, 4-7,4-13, 5-15, 5-17, 5-56, 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, InEnhancing the Use of C

Sorbent Injection ES-23, 2-6, 3-8, 4B-1, B-5, B-6, C-

Evaluation of Gas Rebu

on a Wall-Fired BoES-23, 2-7, 3-8, 45-56, B-3, B-5, C

Externally Fired Combi

Project B-5

F

Foster Wheeler Power SFour Rivers Energy Mo

5-103, B-4

Four Rivers Energy PartFull-Scale Demonstratio

Retrofit ES-8, ES3-8, 3-10, 4-6, 4-B-3, B-5, C-3, C-

G

General Electric Compa

H

Healy Clean Coal Projec

ES-22, 2-6, 3-9, 45-17, 5-130, 5-132

I

Innovative Coke Oven 

Retrofit B-2, B-4

Integrated Coal Gasific

Turbine DemonstrCleanup B-2
Integrated Dry NOx/SO2 Emissions Control

System ES-2, ES-10, ES-13, ES-21, 2-7,3-8, 4-7, 5-7, 5-15, 5-18, 5-94, B-3, B-6,C-3, C-8, C-9, D-4

JJacksonville Electric Authority B-5JEA ES-21, 2-6, 4-8, 5-15, 5-17, 5-104, 5-105,

B-3, B-5, C-5, C-7, C-9, D-5, E-4

JEA Large-Scale CFB Combustion Demonstration

Project ES-21, 2-6, 3-9, 5-10, 5-15, 5-17,5-104, B-3, B-5, C-7, C-9, D-5

KKentucky Pioneer Energy IGCC Demonstration

Project ES-22, 2-7, 3-9, 4-8, 5-10, 5-16,5-17, 5-116, 5-119, B-4, C-5, C-8, C-9, D-5

Kentucky Pioneer Energy, LLC ES-22, 2-7, 5-16,

5-17, 5-116, 5-117, C-5, C-8, C-9, D-5

LLakeland, City of, Lakeland Electric 2-7, B-5,

C-5, C-8, C-9, ES-21, 5-15, 5-17, 5-100,5-102, D-4, D-5

LIFAC Sorbent Injection Desulfurization

Demonstration Project ES-7, ES-11, ES-21,2-7, 3-8, 4-4, 5-3, 5-15, 5-17, 5-30, B-3,B-5, C-3, C-8, D-1

LIFAC–North America ES-7, ES-11, ES-21, 2-7,

4-3, 4-4, 5-15, 5-17, 5-30, B-3, B-5, C-3,C-8, D-1

LIMB Demonstration Project Extension and Coolside

Demonstration ES-9, ES-12, ES-21, 2-6,3-8, 4-7, 5-7, 5-15, 5-17, 5-78, B-1, B-4,C-3, C-7, D-3

LNS Burner for Cyclone-Fired Boilers Demonstration

Project B-3

LPMEOHTM 4-9MM.W. Kellogg Company, The B-2McDermott Technology, Inc. ES-9, ES-12, 2-6,

4-7, B-1, B-4, C-3, C-7

McIntosh Unit 4A PCFB Demonstration Project

ES-21, 2-7, 3-9, 4-8, 5-10, 5-15, 5-17,5-100, B-5, C-5, C-8, D-4

McIntosh Unit 4B Topped PCFB Demonstration

Project ES-21, 2-7, 3-9, 4-8, 5-10, 5-15,5-17, 5-100, 5-102, B-4, B-5, C-5, C-8,C-9, D-5

Micronized Coal Reburning Demonstration for NOx

Control ES-2, ES-8, ES-11, ES-21, 2-7,3-8, 4-6, 5-6, 5-15, 5-17, 5-60, B-3, B-5,B-6, C-8, D-2

Milliken Clean Coal Technology Demonstration

Project ES-2, ES-9, ES-13, ES-21, 2-7, 3-8,4-7, 5-7, 5-15, 5-18, 5-90, B-4, B-6, C-4,C-8, C-9, D-3

Milliken Station B-5Minnesota Department of Natural Resource B-2MK-Ferguson Company B-3

NNew York State Electric & Gas Corporation

ES-8, ES-9, ES-11, ES-13, ES-21, 2-7, 4-5,4-6, 4-7, 5-15, 5-17, 5-18, 5-60, 5-90, B-3,B-4, B-5, B-6, C-4, C-8, C-9, D-2, D-3, E-3

Nichols CFB Repowering Project B-3NOXSO Corporation ES-2, B-3, B-4, B-6, C-4

Nucla CFB Demonstra

ES-16, ES-22, 25-16, 5-18, 5-110

O

Ohio Power Company

ES-22, ES-23, 25-18, 5-106, B-1

Ohio Ontario Clean FuOtisca Fuel DemonstrOtisca Industries, Ltd

P

Passamaquoddy Tribe 

5-16, 5-18, 5-162

Pennsylvania Electric PFBC Utility DemonstPiñon Pine IGCC Powe

3-9, 4-8, 4-10, 5C-5, C-8, C-9, D

Postcombustion Sorb

Project B-2

Prototype Commercia

Project B-2, B-

Public Service Compa

ES-13, ES-21, 25-56, 5-94, B-3, 

Pulse Combustor Des

ES-22, 2-7, 2-12B-4, B-5, C-8, D

Pure Air on the Lake, L

ES-23, 2-6, 3-105-34, B-2, B-5, 
Index-4 Program Update 2000

RRosebud SynCoal Partnership B-2, B-3SSelf-Scrubbing CoalTM: An Integrated Approach to

Clean Air ES-2, B-4, B-6, C-4

Sierra Pacific Power Company ES-22, 2-7, 4-8,

4-10, 5-16, 5-18, 5-118, B-3, C-5, C-8, C-9,D-5

SNOXTM Flue Gas Cleaning Demonstration

Project ES-9, ES-12, ES-21, 2-6, 3-8, 4-7,5-5, 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-7, ES-8,

ES-11, ES-12, ES-21, ES-23, 2-6, 4-3, 4-4,4-6, 4-13, 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-3SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration

Project ES-12, ES-21, 2-6, 3-8, 4-7, 5-5,5-7, 5-15, 5-17, 5-82, B-2, B-5, C-3, C-7,C-9, D-4

TTallahassee, City of B-2, B-3, B-5TAMCO Power Partners B-4Tampa Electric Company ES-1, ES-16, ES-22,

ES-23, 2-7, 4-10, 4-13, 5-16, 5-18, 5-120,B-3, C-5, C-8, C-9, D-6

Tampa Electric Integrated Gasification CombinedCycle Project ES-2, ES-16, ES-22, ES-23,

2-7, 3-9, 4-1, 4-8, 4-10, 4-13, 4-16, 5-10,5-16, 5-18, 5-120, B-3, C-5, C-8, C-9, D-6

Tennessee Valley Authority B-3, B-5ThermoChem, Inc. ES-22, 2-7, 4-12, 5-16, 5-18,

5-152, 5-153, B-4, B-5, C-8, D-8

Tidd PFBC Demonstration Project ES-15,

ES-16, ES-22, ES-23, 2-6, 3-9, 4-10, 4-13,5-10, 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

Tri-State Generation and Transmission

Association ES-15, ES-16, ES-22, 2-6,3-10, 4-5, 4-10, 5-16, 5-18, 5-110, B-3, C-3,C-7, D-5

TRW, Inc. B-2, B-3UUnderground Coal Gasification Demonstration

Project B-2

Union Carbide Chemicals and Plastics Company

Inc. B-4

United Coal Company B-2WWabash River Coal Gasification Repowering Joint

Venture ES-16, ES-22, ES-23, 2-7, 4-10,4-13, 5-16, 5-18, 5-122, B-3, B-6, C-8, C-9,D-6

Wabash River Coal Gasification Repowering

Project ES-1, ES-16, ES-22, ES-23, 2-7,3-9, 3-10, 4-1, 4-8, 4-10, 4-13, 5-10, 5-16,5-18, 5-122, 5-124, B-3, B-6, C-4, C-8,C-9, D-6

Warren Station External

Demonstration B

Weirton Steel CorporatWestern Energy CompaWestern SynCoal LLC 

4-11, 5-9, 5-16, 5C-7, D-7

Y

York County Energy Pa

Project B-3, B-5

York County Energy Pa