Clean Coal Technology

Demonstration ProgramProgram UpdateAs of September 1999

tment of Energy

or Fossil Energy

gton, DC 20585

DOE/FE-0415

April 2000
tment of Energy

or Fossil Energy

gton, DC 20585

Clean Coal TechnologyDemonstration ProgramProgram UpdateAs of September 1999

April 2000

DOE/FE-0415
This report has been reproduced directly from the best available copy.

Available to DOE and DOE contractors from the Office of Scientific and Technical Information,P.O. Box 62, Oak Ridge, TN 37831; prices available from (615) 576-8401.Available to the public from the National Technical Information Service, U.S. Department ofCommerce, 5285 Port Royal Rd., Springfield, VA 22161.

For further information about this publication or related U.S. DOE programs please contact:Victor K. DerProduct Line DirectorPower SystemsU.S. Department of EnergyMail Stop FE-22 GTN19901 Germantown RoadGermantown, MD 20874-1290(301) 903-2700

Dr. C. Lowell MillerProduct Line DirectorFuels & Industrial SystemsU.S. Department of EnergyMail Stop FE-24 GTN19901 Germantown RoadGermantown, MD 20874-1290(301) 903-9453

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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Program Update 1999 i

CCT

Introduction ES-1Role of the CCT Program ES-2Program Implementation ES-4Funding and Costs ES-5CCT Program Accomplishments ES-6CCT Projects ES-20Introduction 1-1Coal Technologies Respond to Need 1-1Coal Technologies for Environmental Performance 1-3

SO2 Regulation 1-3

NO

x Regulation 1-4

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

Coal Technologies for Competitive Performance 1-8Coal Technologies to Sustain Economic Growth 1-10Coal Technology for the Future 1-11Introduction 2-1Implementation Principles 2-1Implementation Process 2-2Commitment to Commercial Realization 2-4Solicitation Results 2-6Future Implementation Direction 2-13

 Program

mentation
Introduction 3-1Program Funding 3-2

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

Cost-Sharing 3-8Recovery of Government Outlays (Recoupment) 3-8Introduction 4-1Marketplace Commitment 4-2

Environmental Control Devices 4-2Advanced Electric Power Generation 4-6Coal Processing for Clean Fuels 4-9Industrial Applications 4-11Awards 4-11

Market Communications—Outreach 4-11

Information Sources 4-14Publications Issued in FY1999 4-14Information Access 4-15Information Dissemination and Feedback 4-16Seventh Clean Coal Technology Conference 4-16Conferences and Workshops Held in FY1999 4-20Trade Mission Activities in FY1999 4-24

Introduction 5-1Technology Overview 5-2

Environmental Control Devices 5-2Advanced Electric Power Generation Technology 5-7Coal Processing for Clean Fuels Technology 5-10Industrial Applications Technology 5-10

ts

complishments
Program Update 1999 iii

Project Fact Sheets 5-12

Environmental Control Devices 5-19

SO2 Control Technologies 5-19NO

x Control Technologies 5-41

Combined SO2/NOx Control Technologies 5-71

Advanced Electric Power Generation 5-99

Fluidized-Bed Combustion 5-99Integrated Gasification Combined-Cycle 5-115Advanced Combustion/Heat Engines 5-125

Coal Processing for Clean Fuels 5-131Industrial Applications 5-147

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

ontinued)

spective and

ory

al Aspects
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-4Index Index-1

breviations,

Participants

ontacts
Program Update 1999 v

Completed Projects by Application Category ES-6Summary of Results of Completed Environmental Control Technology Projects ES-7Commercial Successes—Environmental Control Technologies ES-11Summary of Results of Completed Advanced Electric Power Generation Projects ES-15Commercial Successes—Advanced Electric Power Generation Technologies ES-16Summary of Results of Completed Coal Processing for Clean Fuels Projects ES-17Commercial Successes—Coal Processing for Clean Fuels Technologies ES-18Summary of Results of Completed Industrial Application Projects ES-19Commercial Successes—Industrial Application Technologies ES-19Project by Application Category ES-22Award-Winning CCT Projects 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 2-6Clean Coal Technology Demonstration Projects by Solicitation 2-7Geographic Locations of CCT Projects—Environmental Control Devices 2-9Geographic Locations of CCT Projects—Advanced Electric Power Generation 2-10Geographic Locations of CCT Projects—Coal Processing for Clean Fuels 2-11Geographic Locations of CCT Projects—Industrial Applications 2-12CCT Project Costs and Cost-Sharing 3-1Relationship between Appropriations and Subprogram Budgets for the CCT Program 3-2Annual CCT Program Funding by Appropriations and Subprogram Budgets 3-3CCT Financial Projections as of September 30, 1999 3-4

mentation

CCT Program

 Program

sts
Financial Status of the CCT Program as of September 30, 1999 3-5CCT Project Schedules and Funding, by Application Category 3-6Commercial Successes—SO2 Control Technology 4-4

Commercial Successes—NOx Control Technology 4-5

Commercial Successes—Combined SO2/NOx Control Technology 4-7Commercial Successes—Advanced Electric Power Generation 4-10Commercial Successes—Coal Processing for Clean Fuels 4-12Commercial Successes—Industrial Applications 4-12Award-Winning CCT Projects 4-13How to Obtain Updated CCT Program Information 4-15CCT Program SO2 Control Technology Characteristics 5-3Group 1 and 2 Boiler Statistics and Phase II NOx Emission Limits 5-4

CCT Program NOx Control Technology Characteristics 5-5CCT Program Combined SO2/NOx Control Technology Characteristics 5-6CCT Program Advanced Electric Power Generation Technology Characteristics 5-9

CCT Program Coal Processing for Clean Fuels Technology Characteristics 5-11CCT Program Industrial Applications Technology Characteristics 5-13Key to Milestone Charts in Fact Sheets 5-14Project Fact Sheets by Application Category 5-15Project Fact Sheets by Participant 5-17Variables and Levels Used in GSA Factorial Testing 5-22GSA Factorial Testing Results 5-22SO2 Removal Performance 5-34

Estimated Costs for an AFGD System 5-35Flue Gas Desulfurization Economics 5-35Operation of CT-121 Scrubber 5-38SO2 Removal Efficiency 5-38Particulate Capture Performance 5-39

complishments

ts (continued)
Program Update 1999 vii

ontinued) CT-121 Air Toxics Removal 5-39

LOI Performance Test Results 5-44

NO

x

 vs. LOI Tests—All Sensitivities 5-44

Typical Trade-Offs in Boiler Optimization 5-44Major Elements of GNOCIS 5-45Coal Reburn Test Results 5-48Coal Reburn Economics 5-49NO

x Data from Cherokee Station, Unit No. 3 5-56

Parametric Testing Results 5-61Catalysts Tested 5-64Average SO2 Oxidation Rate 5-64Design Criteria 5-65LNCFSTM Configurations 5-68Concentric Firing Concept 5-68Unit Performance Impacts Based on Long-Term Testing 5-69

Average Annual NOx Emissions and Percent Reduction 5-69LIMB SO2 Removal Efficiencies 5-88Capital Cost Comparison 5-89Annual Levelized Cost Comparison 5-89Effect 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 5-113ENCOAL Production 5-144BFGCI Test Results 5-155Summary of Emissions and Removal Efficiencies 5-162

spective and CCT Program Legislative History A-4
 Aspects NEPA Reviews Completed through September 30, 1999 C-1

Memoranda-to-File Completed C-3Environmental Assessments Completed C-4

Environmental Impact Statements Completed C-5NEPA Reviews in Progress C-5Status of Environmental Monitoring Plans for CCT Projects C-7CCT Projects Monitoring Hazardous Air Pollutants C-9
Program Update 1999 ix

Participant Page

ces

Suspension Absorption AirPol, Inc. 5-20

Gas Desulfurization Demonstration Bechtel Corporation 5-24

urization Demonstration Project LIFAC-North America 5-28

ion Demonstration Project Pure Air on the Lake, L.P. 5-32

plications of Technology for the CT-121 FGD Process Southern Company Services, Inc. 5-36

mbustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. 5-42

g for Cyclone Boiler NOx Control The Babcock & Wilcox Company 5-46

w-NO

x

 Cell Burner Retrofit The Babcock & Wilcox Company 5-50

d Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation 5-54

monstration for NOx Control New York State Electric & Gas Corporation 5-58

ytic Reduction Technology Southern Company Services, Inc. 5-62

s from High-Sulfur, Coal-Fired Boilers

anced Tangentially-Fired Combustion Southern Company Services, Inc. 5-66

NOx Emissions from Coal-Fired Boilers

chnologies

e NOXSO SO2/NOx Removal Flue Gas Cleanup System NOXSO Corporation 5-72

monstration Project ABB Environmental Systems 5-74

leanup Demonstration Project The Babcock & Wilcox Company 5-78

Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation 5-82

tension and Coolside Demonstration McDermott Technology, Inc. 5-86

 Demonstration Project New York State Electric & Gas Corporation 5-90

ns Control System Public Service Company of Colorado 5-94

eneration

stration Project City of Lakeland, Lakeland Electric 5-100

 Demonstration Project City of Lakeland, Lakeland Electric 5-102

on Demonstration Project JEA 5-104

act Sheets by Application Category
Participant Page

The Ohio Power Company 5-106

Tri-State Generation and Transmission Association, Inc. 5-110

bined-Cycle

ration Project Kentucky Pioneer Energy, L.L.C. 5-116

Sierra Pacific Power Company 5-118

ation Combined-Cycle Project Tampa Electric Company 5-120

epowering Project Wabash River Coal Gasification Repowering 5-122

Project Joint Venture

Engines

Alaska Industrial Development and

Export Authority 5-126

Project Arthur D. Little, Inc. 5-128

els

of the Liquid Phase Methanol (LPMEOHTM) Process Air Products Liquid Phase Conversion Company, L.P 5-132

ated Approach to Clean Air Custom Coals International 5-134

ss Demonstration Western SynCoal L.L.P 5-136

ExpertTM ABB Combustion Engineering, Inc., and CQ Inc. 5-138

n Project ENCOAL Corporation 5-142

/Ore Reduction (CPICORTM) CPICORTM Management Company, L.L.C. 5-148

tion Test ThermoChem, Inc. 5-150

tion System Demonstration Project Bethlehem Steel Corporation 5-152

h Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation 5-156

crubber Passamaquoddy Tribe 5-160
Program Update 1999 xi

Project Page

 Inc., and CQ Inc. Development of the Coal Quality ExpertTM 5-138

SNOXTM Flue Gas Cleaning Demonstration Project 5-74

version Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Process 5-132

10-MWe Demonstration of Gas Suspension Absorption 5-20

 and Export Authority Healy Clean Coal Project 5-126

Clean Coal Diesel Demonstration Project 5-128

The Demonstration of Coal Reburning for Cyclone Boiler NOx Control 5-46

The Full-Scale Demonstration of Low-NOx Cell Burner Retrofit 5-50

The SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project 5-78

Confined Zone Dispersion Flue Gas Desulfurization Demonstration 5-24

Blast Furnace Granular-Coal Injection System Demonstration Project 5-152

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 5-156

pany, L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICORTM) 5-148

 Engineering and CQ Inc.)

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air 5-134

ENCOAL® Mild Coal Gasification Project 5-142

earch Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection 5-82

earch Corporation Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler 5-54

JEA Large-Scale CFB Combustion Demonstration Project 5-104

C. Kentucky Pioneer IGCC Demonstration Project 5-116

ectric McIntosh Unit 4A PCFB Demonstration Project 5-100

ectric McIntosh Unit 4B Topped PCFB Demonstration Project 5-102

LIFAC Sorbent Injection Desulfurization Demonstration Project 5-28

LIMB Demonstration Project Extension and Coolside Demonstration 5-86

 Corporation Micronized Coal Reburning Demonstration for NOx Control 5-58

act Sheets by Participant
Project Page

Corporation Milliken Clean Coal Technology Demonstration Project 5-90

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas Cleanup System 5-72

Tidd PFBC Demonstration Project 5-106

Cement Kiln Flue Gas Recovery Scrubber 5-160

rado Integrated Dry NOx /SO2 Emissions Control System 5-94

Advanced Flue Gas Desulfurization Demonstration Project 5-32

Piñon Pine IGCC Power Project 5-118

. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 5-42

. Demonstration of Innovative Applications of Technology for the CT-121 FGD Process 5-36

. Demonstration of Selective Catalytic Reduction Technology for the Control of 5-62

NO

x Emissions from High-Sulfur, Coal-Fired Boilers

. 180-MWe Demonstration of Advanced Tangentially-Fired Combustion 5-66

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

Tampa Electric Integrated Gasification Combined-Cycle Project 5-120

Pulse Combustor Design Qualification Test 5-150

ission Association, Inc. Nucla CFB Demonstration Project 5-110

Repowering Wabash River Coal Gasification Repowering Project 5-122

Advanced Coal Conversion Process Demonstration 5-136
Program Update 1999 ES-1

e Summary: CCT Program Update 1999

n Coal Technology

Program), a model of

ration, advances the

 mission to foster a

m that is environmen

ble. With 24 of the 40

ed operations, the CCT

 technologies (CCTs)

ting and emerging

competing in a deregu

e.

ding a portfolio of

at the U.S. recoverable

s can continue to supply

omically and in an

 As the 20th century

lean coal technologies

cation. Industry now

nergy and environmen

 both domestically and

wer plants, there are

ntrol devices to control

xides (NOx), and partic

are a new generation of

lectricity and other

d synthetic gas, and

vironmental performance

ange. The CCT Pro

n approach as well,

t produce clean coalTampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company)—1997 Powerplant Award presented by Power magazine.

Tidd PFBC Demonstration Project (The Ohio Power

Company)—1991 Powerplant Award presented by Powermagazine.

based solid and liquid fuels by removing pollutants ortheir 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 1999 Major Accomplishments. The

major accomplishments of the CCT Program duringfiscal year 1999 are fivefold. First, low-NOx burner(LNB) technologies, integrated gasification combinedcycle (IGCC), and pressurized fluidized-bed combustion (PFBC) has established a strong foothold in thepower generation market.

Commercialization of LNBs continued, resulting

in nearly half of the U.S. coal-fired boilers beingretrofitted with LNBs. The Texaco gasification process that is being demonstrated in the Tampa ElectricIntegrated Gasification Combined-Cycle Project beganto see market penetration with the Texaco technologybeing used in nearly half of 21 new IGCC projects.Additionally, the ABB Carbon PFBC technologydemonstrated in the Tidd PFBC Demonstration Projectis seeing commercial replication at 70-MWe and 360-MWe scale in Germany and Japan, respectively.

Second, the Kentucky Pioneer Energy IGCC

Demonstration Project has begun. The Kentuckybased project will help resolve a solid waste management problem and evaluate integration of gasificationand fuel cell technologies. The project will use theBGL gasification technology in both an IGCC modeand coupled with a molten carbonate fuel cell (MCFC).Municipal solid waste will be collected and combined
Demonstration of Innovative Applications of

Technology for the CT-121 FGD Process Project (SouthernCompany Services, Inc.)—1994 Powerplant Awardpresented by Power magazine.

for the gasification

ed through gasifica

minal 400-MWe plant

in 2003.

anular-Coal Injection

 Project operations

99. The project

cement of coke with

tant emissions associ

isplaced coke. The

million savings in

eel Corporation over

lted in commercial

el Corporation facility.

d operation for the

mpleted in November

ontinues at no cost to

hat the TRW slagging

 system at Healy kept

dioxide (SO2), and

s well below the

ll continue until 2001.

ere successfully

nized Coal Reburning

project. The technolo

ves industry another

he results met or

s reductions at the

d boiler and Kodak

very low (14 percent)

 more are described in

Technology Demon

ate 1999. Final

ral projects, providing

uating clean coal

ions and periodicals

have been produced to keep stakeholders informed ofCCT Program progress. Conferences and trade missions have been attended in order to promote thesetechnologies. In sum, the CCT Program continuing toserve as a role model for successful government/industry partnerships.

Subsequent to the end of fiscal year 1999, but prior

to publication of this report, the cooperative agreementfor two demonstration projects expired—NOXSOCorporation and Custom Coals International are inbankruptcy and were not able to restructure and continue work under the CCT Program. Information onNOXSO Corporation’s Commercial Demonstration ofthe NOXSO SO2/NOx Removal Flue Gas Cleanup

System and Custom Coals International’s Self-Scrubbing CoalTM: An Integrated Approach projects are included in this report because there is data that readers may

find beneficial. Furthermore, this report is based on thestatus as of September 30, 1999 and the expiration ofthese cooperative agreements occurred after that date.These two projects will not be included in future reports.

Role of the CCT Program

Coal Technologies Respond to Need. Coal

accounts for over 94 percent of the proven fossilenergy reserves in the United States and supplies thebulk of the low-cost, reliable electricity vital to thenation’s economy and global competitiveness. In1996, over half of the nation’s electricity was producedwith coal, and projections by the Energy InformationAgency (EIA) predict that coal will continue to dominate electric power production well into the firstquarter of the 21st century. However, there is a need touse U.S. coal resources in an environmentally responsible manner.

The CCT Program was established to demonstrate

the commercial feasibility of CCTs to respond to agrowing demand for a new generation of advancedcoal-based technologies characterized by enhancedoperational, economic, and environmental performance. The first solicitation (CCT-I) for clean coalprojects resulted in a broad range of projects beingselected in four major product markets—environmentalcontrol devices, advanced electric power generation,coal processing for clean fuels, and industrialapplications.

The second round of solicitations (CCT-II) became the centerpiece for satisfying the recommendations contained in the Joint Report of the Special

Envoys on Acid Rain (1986). The goal was to demonstrate technologies that could achieve significantreductions in the emissions of precursors of acid rain,namely SO2 and NOx. The third round of solicitations(CCT-III) furthered the goal of CCT-II and addedtechnologies that could produce clean fuel from run-ofmine coal.
Program Update 1999 ES-3

Advanced Flue Gas Desulfurization Demonstration

Project (Pure Air on the Lake, L.P.)—1993 PowerplantAward presented by Power magazine.

ations (CCT-IV and

ed emerging energy and

lobal climate change

d thus focused on

of addressing these

gy efficient, economi

capable of retrofitting,

ng facilities, while at the

g SO2 and NOx emis

nologies applicable to

ould significantly im

ental performance.

vironmental Perfor

t of the Clean Air Act

 the CCT Program was

ctric power generation

the statute. Several

ere implemented at

s in Title IV of the

 meet SO2 reductions by

gram projects at Phase I

emissions using ad

 (AFGD) and repower

 combined-cycle. With

itle IV CAAA provi

ogram’s portfolio of

meet the more stringent

ators now have several

on limits or exceeding

at can be sold in the

ermore, these SO2

important in meeting

rticulate matter 2.5

r) because some sulfur

In addition to SO2 reductions, Title IV also called

for reductions in NO

x

 emissions. Phase I of the NO

x

provisions 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 NOxemission 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 NO

x emission control techniques that

are applicable to all of these boiler types. Furthermore,these technologies are not only applicable to Phase Iand II NO

x emission reductions, but can be used in

ozone 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 statesand the District of Columbia to take action to reduceregional transport of pollutants that contribute to ozonenonattainment in the Northeast. The SIP Call requiresthe 23 affected jurisdictions to revise their state implementation plans (SIP) to reduce NOx emissions 85percent below 1990 rates or achieve a 0.15 lb/106 Btuemission rate by May 2003. In addition, EPA hastightened the New Source Performance Standard(NSPS) for electric and industrial boilers built ormodified after July 9, 1997. The CCT Program hasdemonstrated several advanced electric power generation technologies that can be used to meet the newrequirements or exceed the requirements to produceNO

x credits that could be sold to unit operators unable

to meet the requirements. Furthermore, an environmental controls database has been developed that

provides a foundation for evaluating technologies tomeet the increasingly stringent standards for existingunits.

Air toxics is another important area of environmental concern addressed by the CCT Program. Under

Title I of the CAAA, EPA is responsible for determining the hazards to public health posed by 189 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 other studies have significantlymitigated concerns about HAP emissions from coalfired power plants and focused attention on mercuryemissions.

The CCT Program is also cognizant of concerns

about global climate change. Clean coal technologies(such as IGCC) being demonstrated in the CCT Program offer utilities an option to reduce greenhousegases (GHG) by as much as 25 percent with firstgeneration systems through enhanced efficiency.Commercialization of atmospheric fluidized-bed
ized fluidized-bed

duce GHGs.

mpetitive Perfor

on market moves from

rket, the CCT Program

Whether the changes

government through

state governments, the

he first generation of

eeded in a competitive

 new technologies will

g plants and environ

ain Economic

erest to maintain a

mestic economic

ntributing to this

ying a technology

ent use of the United

hile simultaneously

tal goals. The ad

gy resulting from the

dence on foreign

nternational market for

rldwide market for

ould be as high as $80

uture. The invest

ming a solid foundation

e future for fossil

g global and regional

viding low cost energy.

ice of Coal & Power

d specific program

s of the CCT Program

pon which to progress

toward Vision 21. Vision 21 is a long-term strategicconcept which integrates OC&PS program goals todevelop 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 the ComprehensiveNational Energy Strategy. The OC&PS programaddresses key domestic and global environmentalconcerns, while being responsive to DOE strategies toenhance scientific understanding and promote secure,efficient, and comprehensive energy systems.Program Implementation

Implementation Principles. There are 10 guiding

principles that have been instrumental in the success ofthe CCT Program. These principles are:

• Strong and stable financial commitment for the

life of the project, including full funding of thegovernment’s share of the costs;

• Multiple solicitations spread over a number of

years, enabling the CCT Program to address abroad range of national needs with a portfolioof evolving technologies;

• Demonstrations conducted at commercial scale

in actual user environments, allowing clearassessment of the technology’s commercialpotential;

• A technical agenda established by industry, not

the government, enhancing commercializationpotential;

• Clearly defined roles of government and

industry, reflecting the degree of cost-sharingrequired;

• A requirement for at least 50 percent costsharing throughout all project phases, enhancing participant’s commitment;• An allowance for cost growth, but with a ceiling

and cost-sharing, recognizing demonstrationrisk and providing an important check-andbalance to the program;

• Industry retention of real and intellectual

property rights, enhancing commercializationpotential;

• A requirement for industry to commit to

commercialize the technology, reflectingcommercialization goals; and

• A requirement for repayment up to the

government’s cost-share upon successfulcommercialization of the technology beingdemonstrated.

Implementation Process. Public and private

sector involvement is integral to the CCT Programprocess and was crucial to the program’s success.Environmental concerns are publicly addressed throughthe process instituted under the National EnvironmentalPolicy Act (NEPA). Through programmatic environ-
Program Update 1999 ES-5

 environmental impact

cific environmental

mental impact state

documents, the public is

omments addressed

mplementation. In

ring programs are

ess non-regulated

ss, Congress set the

 Department of Energy

dance into perfor

oped approaches to

 previous solicitations.

cedures were offered

ted at pre-proposal

were objectively evalu

 criteria.

e participants, not the

ect the public interest,

track and monitor

The Department of

ct at key negotiated

) to approve or disap

t. Also, any changes to

nges require DOE

 project reporting

ram was instituted to

able to customers and

pdate 1999 is only one

e available through the

cial Realization. The

chieving commercial

inception. All five

tial participants to

address the commercial plans and approaches to beused by the participants to achieve full commercialization of the proposed technology. The cooperativeagreements contain balanced provisions that provideprotection for intellectual property but required theparticipants to make the technology available underlicense on a nondiscriminatory basis.

Solicitation Results. Each solicitation was issued

as a Program Opportunity Notice (PON)—a solicitation mechanism for cooperative agreements where theprogram goals and objectives are defined, but thetechnology is not defined. The procurements followedspecific statutory requirements that would eventuallylead to a cooperative agreement between DOE and theparticipant. The result was a broad spectrum of technologies involving customers and stakeholders from allmarket segments. In sum, 211 proposals were submitted and 60 of those were selected. As of September1999, a total of 40 projects have been completed or arecurrently active. These 40 projects are spread acrossthe nation in 18 states.

Future Implementation Direction. The future

direction 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 affect commercialization. InFY2000, three projects are scheduled to completeoperations.

The body of knowledge obtained as a result of the

CCT Program is being used in decision making relativeto regulatory compliance, forging plans for meetingfuture energy and environmental demands, and developing the next generation of technologies responsive toever increasing demands on environmental performance at competitive costs.

Funding and Costs

Program Funding. Congress has appropriated a

federal budget of $1.8 billion for the CCT Program.For the 40 completed and active projects, the participants have contributed $3.5 billion dollars for a combined commitment of more than $5.4 billion. By law,DOE’s contribution can not exceed 50 percent of thetotal cost of any project. However, industry hasstepped forward and cost shared an unprecedented 66percent of the project funding.

Congress has provided CCT Program funding for

all five solicitations through appropriation acts andadjustments. Additional activities funded by the CCTProgram are the Small Business Innovation ResearchProgram and the Small Business Technology TransferProgram. Funding is also provided for administrationand management of the CCT Program. Use of appropriated funds is controlled and monitored using avariety of financial management techniques. The fullgovernment cost-share specified in the cooperativeagreement is considered committed to each project;however, DOE obligates funds for the project in increments by budget period. This procedure reduces thegovernment’s financial exposure and assures that DOEfully participates in the decision to proceed with eachmajor phase of project implementation.

Cost Sharing. As stated above, DOE’s contribution can not exceed 50 percent of the total cost of any

project. 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 can not be
nues, proceeds, or

 in facilities by partici

rticipant’s share.

Outlays (Recoup

DOE is to recover an

nt’s financial contribu

ology is successfully

e required to submit a

le for recoupment.

. The success of the

measured by the

ke to the resolution of

ental issues. These

ed if the public and

ean coal technologies

rgy use and enhance

sts that are competi

ns. The demonstra

ressive outreach

t understanding. Also,

om a market perspec

major product lines—

dvanced electric

g for clean fuels, and

ary of the number of

tions by category is

 environmental con

ree groups—SO2

l technologies, and

ologies. Both wet

and dry lime- and limestone-based systems weredemonstrated to achieve a range of SO2 capture efficiencies from 50 to 99 percent. All five of the SO2

control technology demonstrations have successfullycompleted operations.

For NO

x control technologies, two basic approaches were used: (1) combustion modification techniques

including low-NOx burners, overfire air, advancedcontrols, and reburning systems; and (2) post-combustion techniques using selective catalytic reduction(SCR) and selective non-catalytic reduction (SNCR)systems. These NOx control techniques were appliedin a variety of combinations on a variety of boilers,which are representative of 90 percent of the pre-NSPSboilers, i.e., those boilers built before NSPS were

imposed by the Clean Air Act of 1970. The result ofthe NO

x control technology demonstrations is a portfolio of technologies that can be

applied to the full range ofboiler types and used to addresstoday’s pressing environmentalconcerns, e.g., ozone. Six ofthe seven NO

x

 control technology demonstrations have successfully completed operations.

For the seventh project, thefinal reports were issued, butthe project was extended foradditional demonstrationactivities.

Six of the seven combined

SO2/NOx control technologydemonstrations have successfully completed operations.The demonstrations tested amultiplicity of complementaryand synergistic control methods

to achieve cost-effective SO2 and NOx emission

reductions.

A summary of the results of the completed environmental control device projects can be found in

exhibit ES-2. The commercial successes of the environmental control devices can be seen in Exhibit ES-3.

The second major product line, advanced electric

power generation, is subdivided into three groups–(1)fluidized-bed combustion, (2) integrated 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 were

used: atmospheric fluidized-bed combustion and pressurized fluidized-bed combustion. The two AFBCprojects use a circulating-bed, as opposed to a bubblingExhibit ES-1

Completed Projects by Application Category

Number of Projects

Application Category Completed Total

Operations

Environmental Control DevicesSO2 Control Technology 5 5

NO

x Control Technology 6 7

Combined SO2/NOx Control Technology 6 7

Advanced Electric Power GenerationFluidized-Bed Combustion 2 5Integrated Gasification Combined-Cycle 0 4Advanced Combustion/Heat Engines 0 2Coal Processing for Clean Fuels 3 5Industrial Applications 2 5

 Total 24 40
Program Update 1999 ES-7

Exhibit ES-2

mary of Results of Completed Environmental Control Technology Projects

Key Results Capital Cost

Suspension Absorption Gas suspension absorption (GSA)/electrostatic precipita- $149/kW for GSA (2.6% sulfur coal) vs. $216/kW for

tor (ESP)—SO2 removal efficiency of 90% at Ca/S molar conventional wet limestone forced oxidation (1990$)

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)

Gas Desulfurization SO2 reduction of 50% (1.2–2.5% sulfur bituminous coal) Less than $30/kW at 500 MWe (4% sulfur coal) (1994$)

ation)

urization Demonstration SO2 removal efficiency of 70% at 2.0 Ca/S molar ratio $66/kW for two reactors (300 MWe); $76/kW for one

(2.0–2.8% sulfur bituminous coal) reactor (150 MWe); $99/kW for one reactor (65 MWe)

(1994$)

ion Demonstration Project SO2 removal efficiency of 95% or more at availabilities of $210/kW at 100 MWe; $121/kW at 300 MWe;

99.5% when operating on 2.0–4.5% sulfur bituminous $94/kW at 500 MWe (3.0% sulfur coal) (1995$)

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)

plications of Technology SO2 removal efficiency of over 95% at SO2 inlet $313/kW for $408/ton SO2 for 100 MWe

outhern Company concentrations of 1,000–3,500 ppm using 3% sulfur coal $131/kW for $171/ton SO2 for 300 MWe

$104/kW for $136/ton SO2 for 500 MWe

Particulate removal efficiency of 97.7–99.3% (Costs based on limestone at $20/ton delivered)at 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
Exhibit ES-2 (continued)

ary of Results of Completed Environmental Control Technology Projects

Key Results Capital Cost

for Cyclone Boiler NOx NOx reductions of 52% using bituminous coal and 55% $66/kW at 110 MWe; $43/kW at 605 MWe (1990$)

Company) using subbituminous coal at full load (110 MWe); 36%

and 53%, respectively, at 60 MWe

NO

x

 Cell Burner NO

x reductions of 58% using bituminous coal at full load $9/kW at 600 MWe (1994$)

Company) (605 MWe); 48% at 350 MWe

Low-NOx Burners on a LNB alone (second generation)—37% NOx reduction; GR-LNB $26/kW at 300MWe GR alone $12/kW, plus

vironmental Research GR-LNB (second generation)—64% NOx reduction gas pipeline cost (1996$)

(13% gas heat input)

ytic Reduction NOx reductions of over 80% at ammonia slip well under Levelized cost at 80% NOx reduction—

Ox Emissions from High- 5 ppm 2.79 mills/kWh or $2,036/ton of NOx removed

ern Company (1996$)

nced Tangentially- NOx reductions of 37% for LNCFSTM I and II, and 45% LNCFS I—$5–15/kW (1993$)

Reduction of NOx for LNCFSTM III, which includes both separated overfire LNCFS II/III—$15–25/kW (1993$)

(Southern Company air and close-coupled overfire air

ustion Techniques for Using LNB alone, NOx emissions were 0.65 lb/106 Btu at Capital cost for a 500 MWe wall-fired unit is $18.8/kW

mpany Services, Inc.) full load, representing a 48% reduction from baseline for LNB/AOFA, $8.8/kW for AOFA alone, $10.0/kW

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

Using AOFA only, NOx reductions of 24% below Estimated cost of NOx removal is $86/ton

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

nstration for NOx Using a 14% reburn fuel heat input on the Milliken Station Final results are not yet available, but in general, the

& Gas Corporation) tangentially-fired (T-fired) boiler resulted in a NOx capital cost of a micronized coal reburning system

emission rate of 0.25 lb/106 Btu, which represents a 28% exceeds that of a gas reburning system due to millingNO

x

 reduction system costs. On the other hand, the operating cost of

Using a 17% reburn fuel heat input on the Kodak Park cyclone a micronized coal reburning system is much lower thanboiler resulted in a NO

x

 emission rate of 0.60 lb/106 Btu, a gas reburning system because of the reburn fuel cost

which represents a 59% NOx reduction differential
Program Update 1999 ES-9

Exhibit ES-2 (continued)

mary of Results of Completed Environmental Control Technology Projects

Key Results Capital Cost

echnology

emonstration Project NOx reduction with SCR over 94% at inlet concentra- $305/kW at 500 MWe (3.2% sulfur coal) (1995$)

tions of 500–700 ppm

SO2 removal efficiency over 95% at inlet concentrations

of 2,000 ppmProduced salable sulfuric acid by-product

xtension and Coolside SO2 removal efficiency (3.8% sulfur coal, Ca/S molar ratio LIMB—$31–102/kW (100–500 MWe) (1992$)

chnology, Inc.) of 2.0): Coolside—$69–160/kW (100–500 MWe) (1992$)

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

 – Coolside—70% for hydrated limeNO

x

 reduction of 40–50%

Cleanup Demonstration SO2 reductions of 80–90% using 3–4% sulfur bituminous $233/kW at 250 MWe (3.5% sulfur coal and inlet

x Company) coal, depending on sorbent and conditions NOx level of 1.2 lb/106 Btu) (1994$)

NO

x

 reduction of 90% with 0.9 NH3/NOx ratio

Gas Reburning and Hennepin—NOx reduction of 67% avg with 18% gas heat $15/kW for gas reburning, plus gas pipeline cost

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

ratio $50/kW for sorbent injection

Lakeside—NO

x reduction of 66% avg 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

y Demonstration Project The maximum SO2 removal demonstrated has been 98% $300/kW at 300 MWe (1998$) for total capital

s Corporation) with all seven recycle pumps operating and using formic requirements

acid. The maximum SO2 removal without formic acid has $217/kW at 300 MWe for total plant costs and $83/kWbeen 95% for other related costs

$4,620,000/yr for O&M costs

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) at 36% reduction
Key Results Capital Cost

hnology (continued)

s Control System NOx reduction of 62–69% with low-NOx burners and Not yet available

rado) maximum overfire air (50–110 MWe)

NOx reduction of 63% with low-NOx burners and minimum

overfire air; steady state conditionsNOx reduction decreased by 10–25% under load followingSNCR obtained NOx reduction of 30–50%, therebyincreasing 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)

ary of Results of Completed Environmental Control Technology Projects
Program Update 1999 ES-11

Commercial Use

Suspension Absorption Sold domestically and internationally. GSA market entry was significantly enhanced with the sale of a

50-MWe unit, worth $10 million, to the city of Hamilton, Ohio, subsidized by the Ohio Coal Development

Office. A sale worth $1.3 million has been made to the U.S. Army for hazardous waste disposal. A GSAsystem has been sold to a Swedish iron ore sinter plant. Sales to Taiwan, Indonesia, and India have acombined value of $20 million. Furthermore, Taiwan contracted for technical assistance and proprietaryequipment valued at $1.0 million.

Gas Desulfurization Demonstration No sales reported. CZD/FGD can be used to retrofit existing plants or for new installations at a

cost of about one-fourth the cost of a commercial wet scrubber.

urization Demonstration Project Sold domestically and internationally. There are 10 full-scale LIFAC units in operation in

Canada, China, Finland, Russia, and the United States. The LIFAC system at Richmond Power

& Light is the first to be applied to a power plant using high-sulfur (2.0-2.9%) coal. The LIFACsystem has been retained for commercial use by Richmond Power & Light at Whitewater ValleyStation, Unit No. 2.

ion Demonstration Project No sales reported. The AFGD continues in commercial service at Northern Indiana Public

Service Company’s Bailly Generating Station. Gypsum produced by the PowerChip® process is

being sold commercially.

plications of Technology for the Sold internationally. Plant Yates continues to operate with the CT-121 scrubber as an integral

Company Services, Inc.) part of the site’s CAAA compliance strategy. Since the CCT Program demonstration, over 8,200

MWe equivalent of CT 121 FGD capacity has been sold to 16 customers in 7 countries.

monstration for NOx Control No sales reported. Technology retained for commercial use at Kodak Power Plant.

Corp.)

g for Cyclone Boiler NOx Control No sales reported. Technology retained for commercial use at Wisconsin Power and Light

ny) Company’s Nelson Dewy Station

w-NO

x

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

ny) service. Seven commercial contracts have been awarded for 172 burners, valued at $27 million.

The LNCB® technology has already been installed on more than 4,900 MWe of capacity.

d Low-NOx Burners on a Wall-Fired Boiler Sold domestically and internationally. Public Service Company of Colorado, the host utility,

arch Corp.) decided to retain the low-NOx burners and the gas-reburning system for immediate use; however,

a restoration was required to remove the flue gas recirculation system. Energy and EnvironmentalResearch Corporation has been awarded two contracts to provide gas reburning systems forcyclone coal-fired boilers: TVA’s Allen Unit 1 (a 330-MWe unit) as well as Baltimore Gas &Electric’s C. P. Crane Units 1 and 2 (similar 200-MWe units). The technology is also installed atLadyzkin State Power Station in Ladyzkin, Ukraine.

ytic Reduction Technology No sales reported. SCR has realized commercial acceptance abroad. The demonstration tests

s from High-Sulfur, Coal-Fired Boilers established SCR as a viable U.S. compliance option and aided utilities in developing the most

c.) cost-effective site-specific applications of SCR.

Exhibit ES-3

Commercial Successes—Environmental Control Technologies
Commercial Use

nced Tangentially-Fired Combustion Sold domestically and internationally. LNCFSTM has been retained at the host site for commercial use.

NOx Emissions from Coal-Fired Boilers ABB Combustion Engineering has modified 116 tangentially fired boilers, representing over 25,000 MWe,

) with LNCFSTM and derivative TFS 2000TM burners.

bustion Techniques for a Wall-Fired Boiler Sold domestically and internationally. The host has retained the technologies for commercial use.

) Foster Wheeler has equipped 86 boilers (51 domestic and 35 international) with low-NOx burner technol

ogy—a total of 1,800 burners representing over 30,000 MWe capacity valued at $35 million. Twenty-sixcommercial installations of GNOCIS, the associated AI control system, are underway or planned. Thisrepresents over 12,000 MWe of capacity. In a strict sense, this project has not been completed; it has beenextended to apply GNOCIS to other pieces of plant equipment, which may increase its commercialpotential.

onstration Project (ABB International use. The host utility, Ohio Edison, is retaining the SNOXTM technology as a permanent

part of the pollution control system at Niles Station to help meet its overall SO2 and NOx reduction goals.

Commercial SNOXTM plants are also operating in Denmark and Sicily. In Denmark, a 305-MWe planthas operated since August 1991. The boiler at this plant burns coals from various suppliers around theworld, including the United States; the coals contain 0.5–3.0% sulfur. The plant in Sicily, in operationsince March 1991, has a capacity of about 30 MWe and fires petroleum coke.

nsion and Coolside Demonstration Sold domestically and internationally. LIMB has been sold to an independent power plant in Canada.

Babcock & Wilcox has signed contracts for 124 units for DRB-XCL® low-NOx burners, representing 2,428

burners for 31,467 MWe of capacity. The low-NOx burners have an estimated value of $240 million.

eanup Demonstration Project No sales reported. Commercialization of the technology is expected to develop with an initial larger

y) scale application equivalent to 50–100 MWe. The focus of marketing efforts is being tailored to match the

specific needs of potential industrial, utility, and independent power producers for both retrofit and newplant construction. SNRBTM is a flexible technology that can be tailored to maximize control of SO2, NOx,

particulate, or combined emissions to meet current performance requirements while providing flexibilityto address future needs.

s Reburning and Sorbent Injection No sales reported. Illinois Power has retained the gas-reburning system and City Water, Light & Power

rch Corp.) has retained the full technology for commercial use. (See Evaluation of Gas Reburning and Low-NOx

Burner on a Wall-Fired Boiler project for a complete understanding of commercial success of thetechnology.)

Demonstration Project Sold domestically. Six modules of DHR Technologies’ Plant Emissions Optimization Advisor, with an

orp.) estimated value of $210,000, have been sold. A U.S. company, SHN, has been established to market the

S-H-U scrubber. SHN is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABBCombustion Engineering has modified 116 units representing over 25,000 MWe with LNCFSTM or itsderivative TFS 2000TM.

Exhibit ES-3 (continued)

Commercial Successes—Environmental Control Technologies
Program Update 1999 ES-13

Commercial Use

Demonstration Project Sold domestically. Six modules of DHR Technologies’ Plant Emissions Optimization Advisor, with an

Corp.) estimated value of $210,000, have been sold. A U.S. company, SHN, has been established to market the

S-H-U scrubber. SHN is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABBCombustion Engineering has modified 116 units representing over 25,000 MWe with LNCFSTM or itsderivative TFS 2000TM.

ns Control System Sold domestically. The technology was retained by Public Service Company of Colorado for commercial

rado) service at its Arapahoe Station. The Babcock & Wilcox DRB-XCL® burner that was demonstrated has

realized sales of 2,428 burners, representing 31,467 MWe. The burners are valued at $240 million.

Exhibit ES-3 (continued)

Commercial Successes—Environmental Control Technologies
essure to generate

One project is com

oing. There are three

am. The completed

ed operating at 16

nd drive a gas turbine

 ongoing interrelated

ing-bed operating at

ned-cycle mode.

gasification combined

in operation. A fourth

e IGCC projects

ypes, cleanup systems,

ing advanced combus

e uses an entrained

er uses a heavy duty

Both of these projects

A summary of the results of the completed advanced electric power generation projects can be found

in Exhibit ES-4. The commercial successes of theseprojects can be seen in Exhibit ES-5.

For the third major product line, coal processing

for clean fuels, there are five projects. Three projectsare using chemical and physical processes to transformraw coal into high-energy-density environmentallycompliant fuels. Another project is converting coal tomethanol from coal-derived synthesis gas. A fifthproject in this product line is a software program usedto assess the environmental and operational performance and determine the least-cost option for availablecoals. Two of the five coal processing for clean fuelsprojects are complete.

A summary of the results of the completed coal

processing 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 industrial applications. This product line is addressing the

environmental issues and barriers associated with coaluse in industry. There are five diverse projects in thiscategory; three are completed and two are ongoing. Asummary of the results of the industrial applicationprojects can be found in Exhibit ES-8. Commercialsuccesses of these projects can be seen in Exhibit ES-9.

Market Communications—Outreach. Outreach

has been a hallmark of the CCT Program since it’sinception. Commercialization of new technologiesrequires acceptance by a wide range of interests—customers, manufacturers, suppliers, financiers, government, and public interest groups. The CCT Program has aggressively sought to disseminate keyinformation to this full range of customers and stakeholders and to obtain feedback on changing needs. This dissemination of information takes the form of printed media, exhibits, and electronic media. Printed Full-Scale Demonstration of Low-NOx Cell Burner Retrofit Project (The Babcock & Wilcox Company)—1994 R&D 100 Award presented by R&D magazine. Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture)—1996 Powerplant Award presented by Power magazine. 

ool, can be used to 

ious fuel options by 

ase decisions on power 

power generation costs.
Program Update 1999 ES-15

Exhibit ES-4

ary of Results of Completed Advanced Electric Power Generation Projects

Key Results Capital Cost

ect (The Ohio Power SO2 reduction of 90–95% (Ohio bituminous coal, 2–4% $1,263/kW at 360 MWe (1997$)

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

ect (Tri-State Generation SO2 reduction of 70–95% (up to 1.8% sulfur coal), Approximately $1,123/net kW (repowering cost) (1990$)

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
Exhibit ES-5

mercial Successes—Advanced Electric Power Generation Technologies

Commercial Use

 (The Ohio Power Company) Sold internationally. Success of the project has led Babcock & Wilcox to invest in the technology and

acquire domestic licensing rights. Commercial ventures abroad include the following:– Vartan Sweden is operating two P200 units to produce 135 MWe and 224 MWt– Escatron in Spain is operating one P200 unit producing 80 MWe– Wakamatsu in Japan is operating one P200 unit to produce 71 MWe– Cottbus in Germany is operating one P200 unit to produce 71 MWe and 40 MWt– Karita in Japan operates one P800 unit to produce 360 MWe– Other projects under construction are in China, South Korea, U.K., and Israel

 (Tri-State Generation and Sold domestically and internationally. Today, every major boiler manufacturer offers an ACFB system

in its product line. Since the demonstration, commercial sales of 29 units greater than 100 MWe have

been realized, representing 6.2 gigawatts of capacity valued at nearly $6 billion.

tion Combined-Cycle Sold domestically and internationally. First greenfield IGCC unit in commercial service. Texaco, Inc.,

and ASEA Brown Boveri signed an agreement forming an alliance to market IGCC technology in Europe.

There are currently 10 projects using a Texaco gasifier that are either planned or under construction.

epowering Project (Wabash No sales reported. First repowered IGCC unit in commercial service and world’s largest single train

ng Project Joint Venture) IGCC in commercial service. Preferentially dispatched over other coal-fired units in PSI Energy’s system

because of high efficiency.

Industrial Development and No sales reported. TRW offering licensing of combustor worldwide (China agreement in place).
Program Update 1999 ES-17

Exhibit ES-6

mary of Results of Completed Coal Processing for Clean Fuels Projects

Key Results Capital Cost

ty ExpertTM CQETM features: CQETM package sells for between $75,000 and

, 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

roject (ENCOAL The liquid (CDL®) and solid (PDF®) product fuels have A commercial plant designed to process 15,000-metric

been used economically in commercial boilers and ton/day would cost $475 million (2001$) to construct

furnaces and have reduced SO2 and NOx emissions with annual operating and maintenance costs of $52

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®
Exhibit ES-7

mmercial Successes—Coal Processing for Clean Fuels Technologies

Commercial Use

ExpertTM (ABB Combustion Sold domestically and internationally. The Electric Power Research Institute (EPRI) owns the software

and distributes it to EPRI members for their use. CQ Inc. and Black and Veatch have signed

commercialization agreements that give both companies nonexclusive worldwide rights to sell user licensesand offer consulting services that include use of CQE®. More than 35 U.S. utilities and one U.K.

utility have received CQE® through EPRI membership. Two modules of the Acid Rain Advisor

valued at $6,000 have been sold. It is estimated that CQE® saves U.S. utilities about $26 million annually.

n Project (ENCOAL Corporation) Domestic and international sales pending. In order to determine the viability of potential LFC® plants,

five detailed commercial feasibility studies—two Indonesian, one Russian, and two U.S. projects—havebeen completed. Permitting of a 15,000 metric-ton/day commercial plant in Wyoming is nearly complete.

s Demonstration (Western SynCoal LLC) No sales reported. Total sales of SynCoal® product exceed 1.5 million tons. Six long-term agreements are

in place to purchase the product. One domestic and five international projects have been investigated. Western SynCoal LLC has a joint marketing agreement with Ube Industries of Japan providing Ubenon-exclusive marketing rights outside of the United States. Ube is pursuing several projects in Asia.Western SynCoal is also discussing a potential marketing and development agreements with a U.S.engineering firm.

of the Liquid Phase Methanol No sales reported. Nominal 80,000 gallon/day methanol production being used by Eastman Chemical

cts Liquid Phase Conversion Company
Program Update 1999 ES-19

Exhibit ES-8

Summary of Results of Completed Industrial Application Projects

Key Results Capital Cost

with Internal Sulfur, SO2 reduction of over 80% with sorbent injection; 58% Not available

 Tech Corporation) maximum with limestone injection 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

 Scrubber (Passama- SO2 reduction of 90–95% (2.5–3% sulfur bituminous $10 million for 450,000 ton/yr wet-process plant (1990$)

coal); 98% maximum reduction

NO

x reduction of 18.8% avg

Particulate emissions of 0.005–0.007 gr/std ft3 with

loading of 0.04 gr/std ft3

Exhibit ES-9

Commercial Successes—Industrial Application Technologies

Commercial Use

with Internal No sales reported. While the combustor was not yet fully ready for sale with commercial guarantees, it was believed to

ol (Coal Tech have commercial guarantees, it was believed to have commercial potential. Subsequent work was undertaken, which

has brought the technology close to commercial introduction.

 Scrubber No sales reported. The scrubber became a permanent part of the cement plant at the end of the demonstration. A

feasibility study has been completed for a Taiwanese cement plant.

ection System Domestic sale. British Steel’s Blast Furnace Granular Coal Injection System was sold and installed on a facility owned

m Steel by United States Steel Corporation.
etters, proceedings,

gram updates, and

m currently uses four

s and complexity that

ecific forums. Elec

 the World Wide Web.

OE is making more

rld Wide Web.

nt part of the outreach

ring the PON process

sites, the CCT Pro

mers and stakeholders.

meetings, conferences,

re used by the CCT

ion and obtain feed

outreach event is the

nference.

hnology Conference

e from June 21-24,

n “21st Century Coal

mic Viability, Global

nment” to realize the

n coal technologies.

scuss topics related to

1st century.

In addition to the Seventh Clean Coal Technology

Conference, several domestic and international conferences and workshops were attended or sponsored infiscal year 1999. The forums for conferences variedfrom Ankara, Turkey to Baltimore, Maryland. Trademissions during fiscal year 1999 included China, India,Poland, Russia, Taiwan, and Ukraine. All of theseevents were used to endorse and promote the technologies demonstrated in the CCT Program.

CCT Projects

Technology Overview. The 40 CCT Program

projects provide a portfolio of technologies that willenable coal to continue to provide low-cost secureenergy vital to the nation’s economy while satisfyingenergy and environmental goals well into the 21stcentury.

Environmental Control Devices. The environmental control technologies provide a suite of costeffective control options for the full range of boiler

types. The 19 environmental control device projectsare valued at $703 million. These include seven NOxemission control systems installed in more than 1,750MWe of utility generating capacity, five SO2 emissions

systems installed on approximately 770 MWe, andseven combined SO2/NOx emission control systemsinstalled or planned for installation on more than 665MWe of capacity.

Advanced Electric Power Generation. To

respond to load growth, as well as growing environmental concerns, the CCT Program provides a range ofadvanced electric power generation options for bothrepowering and new power generation. These advanced

options offer greater than 20 percent reductions ingreenhouse gas emissions; SO2, NOx, and particulate

emissions 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 inthe mid- to late-1990s, but also will provide the demonstrated technology base necessary to meet newcapacity requirements in the 21st century.

Coal Processing for Clean Fuels. Also addressed

are approaches to converting run-of-mine coals to highenergy-density, low-sulfur products. These productshave application domestically for compliance with theCAAA. Internationally, both the products and processes have excellent market potential. Valued at $519million, the five projects in the coal processing forclean fuels category represent a diversified portfolio oftechnologies.

Industrial Processes. Projects were undertaken

as well to address pollution problems associated withcoal use in the industrial sector. The problems addressed include dependence of the steel industry oncoke and the inherent pollutant emissions in cokemaking; reliance of the cement industry on low-costindigenous, and often high-sulfur, coal fuels; and theneed for many industrial boiler operators to considerswitching to coal fuels to reduce operating costs. Thefive industrial applications projects have a combinedvalue of nearly $1.3 billion. The projects encompasssubstitution of coal for 40 percent of coke in ironmaking; integration of a direct iron-making processwith the production of electricity; reduction of cementkiln emissions and solid waste generation; demonstration of an industrial-scale slagging combustor; anddemonstration of a pulse combustor system.

th Clean Coal

erence attendees included
Program Update 1999 ES-21

core of this Program

sheets. Two types of

rief two-page overview

xpanded four-page

successfully completed

contains a summary of

onstrations, as well as

formation. Technology

es are provided for all

with the participant,

n in Exhibit ES-10. A

Program projects is
jects having completed operations.

Exhibit ES-10

Project by Application Category

Participant Solicitation/Status

es

uspension Absorption AirPol, Inc. CCT-III/completed 3/94

as Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93

ization Demonstration Project LIFAC–North America CCT-III/completed 6/94

n Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95

ications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/completed 12/94

bustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/extended

 for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/completed 12/92

NO

x

 Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 4/93

Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corp. CCT-III/completed 1/95

onstration for NOx Control New York State Electric & Gas Corp. CCT-IV/completed 9/99

tic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95

from High-Sulfur, Coal-Fired Boilers

nced Tangentially-Fired Combustion Southern Company Services, Inc. CCT-II/completed 12/92

NOx Emissions from Coal-Fired Boilers

hnologies

 NOXSO SO2/NOx Removal Flue Gas Cleanup System NOXSO Corporation CCT-III/on hold

onstration Project ABB Environmental Systems CCT-II/completed 12/94

eanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5/93

as Reburning and Sorbent Injection Energy and Environmental Research Corp. CCT-I/completed 10/94

ension and Coolside Demonstration McDermott Technology, Inc. CCT-I/completed 8/91

Demonstration Project New York State Electric & Gas Corp. CCT-IV/completed 6/98

s Control System Public Service Company of Colorado CCT-III/completed 12/96

neration

tration Project City of Lakeland, Lakeland Electric CCT-III/design

Demonstration Project City of Lakeland, Lakeland Electric CCT-V/design

n Demonstration Project JEA CCT-I/design
Program Update 1999 ES-23

ojects having completed operations.

Exhibit ES-10 (continued)

Project by Application Category

Participant Solicitation/Status

ct The Ohio Power Company CCT-I/completed 3/95

ct Tri-State Generation and Transmission Association, Inc. CCT-I/completed 1/91

ned Cycle

Demonstration Project Kentucky Pioneer Energy, L.L.C. CCT-V/design

Sierra Pacific Power Company CCT-IV/operational

cation Combined-Cycle Project Tampa Electric Company CCT-III/operational

Repowering Project Wabash River Coal Gasification Repowering Project Joint Venture CCT-IV/operational

ngines

Alaska Industrial Development and Export Authority CCT-III/operational

n Project Arthur D. Little, Inc. CCT-V/construction

Fuels

n of the Liquid Phase Methanol Air Products Liquid Phase Conversion Company, L.P CCT-III/operational

rated Approach to Clean Air Custom Coals International CCT-IV/on hold

ess Demonstration Western SynCoal LLC CCT-I/operational

 ExpertTM ABB Combustion Engineering, Inc., and CQ Inc. CCT-I/completed 12/95

on Project ENCOAL Corporation CCT-III/completed 7/97

al/Ore Reduction (CPICORTM) CPICORTM Management Company L.L.C. CCT-V/design

cation Test ThermoChem, Inc. CCT-IV/design

ction System Demonstration Project Bethlehem Steel Corporation CCT-III/completed 9/99

ith Internal Sulfur, Nitrogen, Coal Tech Corporation CCT-I/completed 5/90

Scrubber Passamaquoddy Tribe CCT-II/completed 9/93
w-NO

x

 Cell Burner

 Company)

d Low-NOx Burners

ng the Use of Coals by

ction (Energy and

ation)

ion Demonstration

P.)

plications of Technol

c.)

ct (The Ohio Power

cation Combined

ompany)

Repowering Project

 Repowering Project

y ExpertTM (ABB

d 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 development of the low-NOx cell

burner.1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management Association to the U.S. Department ofEnergy, Gas Research Institute, and U.S. Environmental Protection Agency for the development and commercialization ofgas-reburning technology.1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service Company’s Bailly Generating

Station.1992 Outstanding Engineering Achievement Award presented by the National Society of Professional Engineers.1995 Design Award presented by the Society of Plastics Industries in recognition of the mist eliminator.1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. Co-recipient was the U.S.

Department of Energy.1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and Waste Management Association.1993 Environmental Award presented by the Georgia Chamber of Commerce.1992 National Energy Resource Organization award for demonstration of energy-efficient technology.1991 Powerplant Award presented by Power magazine to American Electric Power Company’s Tidd project. Co-recipient

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

1996 Association of Builders and Contractors Award presented to Tampa Electric for quality of construction.1993 Ecological Society of America Corporate Award presented to Tampa Electric for its innovative siting process.1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of Florida for the innovative sitingprocess.1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innovative siting process.1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc.1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 1996 American Consulting Engineers Council competition.In 1996 recognized by then Secretary of Energy Hazel O’Leary and EPRI President Richard Balzhiser as the best of nineDOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Program.

Award
Program Update 1999 1-1

f the CCT Program

ury, both the national

es have been one of

e the oil embargoes of

al debates of the

ut more changes in

reductions for acid rain

ringent NOx standards

tighter standards on

of electric utility restruc

 warming.

etween government and

oal Technology Dem

am), has responded to

hese dynamic changes.

and extent of industry

m is unprecedented.

expended, with indus

sting two dollars for

r invested. With 60

completed operations

he technological

mselves in the market

uce the emissions of

fur dioxide (SO2) and

in the marketplace and

er producers and heavy

wer generation sys

th greater efficiency

quences are now

t plentiful fossil

energy resource—coal. Coal, which accounts forover 94 percent of the proven fossil energy reservesin the United States, supplies the bulk of the lowcost, reliable electricity vital to the nation’s economyand global competitiveness. According to the U.S.Department of Energy’s (DOE) Energy InformationAdministration (EIA) Annual Energy Review 1998(July 1999) (AER98), 933 million tons of coal were

used to produce over 1,872 billion kilowatt-hours or52 percent of the nation’s electricity in 1998. EIAprojections count on coal continuing to dominateelectric power production, at least through 2020(the end of the forecast period). In the AnnualEnergy Outlook 2000 (December 1999) (AEO2000),

EIA estimates 1,177 million tons of coal will generate an estimated 2,347 billion kilowatt-hours ornearly 49 percent of all electricity generated in2020.

The ability of coal and coal technologies to

respond to the nation’s need for low-cost, reliableelectricity hinges on the ability to meet two centralrequirements: (1) environmental performancerequirements established in current and emerginglaws and regulations, and (2) operational andeconomic performance requirements to compete inthe era of utility restructuring and competition. TheCCT Program is responding to these requirementsby producing a portfolio of advanced coal-basedtechnologies that will enable coal to retain itsprominent role in the nation’s power generationfuture. Furthermore, advanced technologies emerging from the CCT Program will also enhance coal’scompetitive position in the industrial sector. Forexample, technology advances in steel making,

involving direct use of coal, will reduce the cost ofproduction while greatly improving environmentalperformance. Also, coal could increase its market sharein the industrial sector through cogeneration (steamand electricity) and coproduction of products (cleanfuels and chemicals).

While the CCT Program responds to domestic

needs for competitive and clean coal-based technology,it also positions U.S. industry to compete in a burgeoning power market abroad. Electricity continues tobe the most rapidly growing form of energy consumption in the world. Projections from EIA’s International Energy Outlook 1999 (March 1999) (IEO99) showelectricity rising from 12 trillion kilowatt-hours in1996 to almost 22 trillion kilowatt-hours in 2020. Thestrongest growth is projected for the coal-dependentdeveloping countries of Asia. This growth not onlyrepresents a tremendous market opportunity, but anopportunity to make a reduction in global carbonemissions through the application of highly efficientclean coal technologies.Coal Technologies Respondto Need

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, which
gy source, could

nergy needs econom

 acceptable manner.

1980s, many of the

gy demonstrations

ction technology.

of 1980, the Synthetic

tablished for the

nerability to disrup

omplished by encour

and operate synthetic

uld use abundant

arily coal and oil

SFC to be primarily a

 and near-commer

the SFC was to

 500,000 barrels per

nd 2 million barrels

 cost of $8.8 billion.

t that the need for

oil prices declined,

d a short-term supply

egic Petroleum

ponded to the decline

roduction of synthet

conditions. Public

Interior and Related

r Fiscal Year 1986,

ed project manage

nt.

ated in October

Resolution Making

scal Year 1985 and

million from the

eposited in a separate

account in the U.S. Treasury entitled The Clean CoalTechnology Reserve. The nation moved from anenergy policy based on synthetic fuels production to amore balanced policy. This policy established thatthe nation should have an adequate supply of energy,maintained at a reasonable cost, and consistent withenvironmental, health, and safety objectives. Energystability, security, and strength were the foundationsfor this policy. Coal was recognized as an essentialelement in this energy policy for the foreseeablefuture 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 thisvaluable energy commodity to serve thedomestic 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 cementproduction, as well as industrial power.

• This abundant fossil energy resource is secure

within the nation’s borders and relativelyinvulnerable to disruptions because of the coalindustry’s production responsiveness andstockpiling capability.

• Coal is the fuel of necessity in many lesser

developed economies, which provides exportopportunities for U.S.-developed, coal-basedtechnologies.

Congress recognized that the continued viability

of coal as a source of energy was dependent on thedemonstration and commercial application of a newgeneration of advanced coal-based technologiescharacterized by enhanced operational, economic,and environmental performance. The CCT Programwas established to demonstrate the commercialfeasibility of clean coal technology applications inresponse to that need. In 1986, the first solicitation(CCT-I) for clean coal technology projects wasissued. The CCT-I solicitation resulted in a broadrange of projects being selected in four major productmarkets—environmental control devices, advancedelectric power generation, coal processing for cleanfuels, and industrial applications.

In 1987, the CCT Program became the centerpiece for satisfying the recommendations contained

in the Joint Report of the Special Envoys on AcidRain (1986). A presidential initiative launched afive-year, $5-billion U.S. government/industry effortto curb precursors of acid rain formation—SO2 and

NO

x. Thus, the second solicitation (CCT-II) issued

in February 1988 provided for the demonstration oftechnologies that were capable of achieving significant emission reductions in SO2, NOx, or both, fromexisting power plants. These technologies were to bemore cost-effective than current technologies andcapable of commercial deployment in the 1990s. InMay 1989, a third solicitation (CCT-III) was issuedwith essentially the same objective as the second, butadditionally encouraged technologies that wouldproduce clean fuels from run-of-mine coal.

The next two solicitations recognized emerging

energy and environmental issues, such as globalclimate change and capping of SO2 emissions, and

thus focused on seeking highly efficient, economically competitive, and low-emission technologies.
Program Update 1999 1-3

on (CCT-IV), released

ctive the demonstra

ically competitive

ting, repowering, or

e achieving significant

sions. In July 1992,

CT-V) was issued to

ects that significantly

vironmental perfor

le to new or existing

ve solicitations, a total

-shared projects were

more than $5.4 billion

ompleted or remain

ment/industry CCT

 to the CCT Pro

c and private sector

 emissions and maxi

nergy production. The

the economy, enhance

 vulnerability of the

ket shocks.

es for

Performance

uring the late 1980s,

as to become the

 1990 (CAAA). On

enacted the CAAA as

Public Law 101-549. Title IV, Acid Deposition Control,established emissions reduction targets for SO2 and

capped SO2 emission in the post-2000 timeframe. Title

IV is the first large-scale approach to regulatingoverall emissions levels by using marketable allowances. The utilities can adopt a control strategy that ismost cost-effective for their given systems and plantsrather than having to apply a “command-and-control”approach wherein the emission-reduction method isspecified.

The emission reduction requirements for SO2 were

to be met in two phases. Phase I, which provided forthe initial increment of SO2 reduction, began on

January 1, 1995. The second increment implementedthrough Phase II began January 1, 2000. Title IVidentified 261 generating units (designated as “affected units”) that were required to comply withPhase I. Most of these units are coal-fired with fairlyhigh emission rates.Exhibit 1-1 summarizes the compliancemethods used bythe 261 affectedunits listed in TitleIV to satisfy Phase Irequirements. Anadditional 174 unitsparticipated inPhase I based onU.S. EnvironmentalProtection Agency(EPA) rules thatallow a utility todesignate substitution or compensating units as part of Phase I compliance strategies. Therefore, 435 units are considered Phase I units. Under Phase II, more than 2,500 units are affected. As a result of Phase I, SO2 emissions at electric utilities declined from 15.6 million tons in 1990 to 12.5 million tons in 1997, a 20 percent decline. As shown in Exhibit 1-1, switching to low-sulfur coal was the option chosen by more than half of the owners of Phase I affected units. In Phase II, beginning in 2000, emission con- straints on Phase I plants are tightened, and limits are set for the remaining 2,500 boilers at 1,000 plants. With allowance banking, SO2 emissions are expected to decline to 11.6 million tons in 2000 and 9.2 million tons by 2010, and will essentially remain at that level through 2020, the end of the forecast period of AEO2000. Since allowance prices are expected to increase after 2000, EIA predicts that 21 Exhibit 1-1 Phase I SO2 Compliance Methods % SO2 Method No. of % of Reduction from % of Total Units Units 1985 Baseline SO2 Reduction Fuel switching/blending 136 52 60 59 Additional SO2 allowances 83 32 16 9a Scrubbers 27 10 83 28 Retirements 7 3 100 2 Otherb 8 3 86 2 Total 261 100 345 100 aIncludes reduced coal consumption of 2.5 million tons and 16% reduction in sulfur content. bIncludes 1 repowered unit, 2 switched to natural gas, and 5 switched to No. 6 fuel oil. Source: The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update, Energy

Information Administration, March 1997.
ed with scrubbers to

CCT Program, listed

units and were

with Phase I

Services Company’s

n, 528-MWe Unit

dvanced flue gas

;

’s Plant Yates,

hiyoda Thorough

gas desulfurization

& Gas Corporation’s

We Unit Nos. 1 and 2

nced wet limestone

ver Station,

powered with Destec

mbined-cycle unit).

projects served to

et limestone scrubber

e first to introduce

-cycle as a repower

crubbers essentially

crubbers of the time.

ted an option provid

a four-year extension

pliance with Phase II

ctric power genera

ether with the other

fforded a portfolio of

diverse fleet of

ating units and the

means 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. In Title IV of the

CAAA, Congress also required the EPA to establishannual allowable emissions limitations for NOx in

two phases. Phase I required NOx reductions from

tangentially-fired and dry-bottom wall-fired boilers.These boilers are referred to as Group 1 boilers. InMarch 1994, EPApromulgated a ruleestablishing NOxemission limitations of0.45 lb/106 Btu fortangentially-fired unitsand 0.50 lb/106 Btu forwall-fired units. Ultimately, a compliancedate of January 1, 1996,was established.

On December 19,

1996, EPA issued arule to implementPhase II. The ruleestablished NOxemission limitationsfor additional coalfired boilers (Group 2)and reduced the NOxemissions limitationson Group 1 boilers.

The types of Group 1 and 2 boilers and the Phase I andII NOx emission limits are shown in Exhibit 1-2.

In response to the need to formulate NOx emission

reductions that were realistic and achievable for Group1, EPA was able to use data developed during theSouthern Company Services’ evaluation of NOx control technologies on wall-fired and tangentially-firedboilers. Furthermore, operational, environmental, andeconomic data on NOx controls were developed underthe CCT Program for all four major boiler types (wallfired, tangentially-fired, cyclone-fired, and cell-burner),which constitute over 90 percent of the pre-NewSource Performance Standard (NSPS) boiler types. Inaddition, low-NOx burners were installed and tested on

Exhibit 1-2

CAAA NOx Emission Limits

Group 1 Group 2 Phase I NOx Phase II NOxBoiler Type Boiler Type Emission Limitsa Emission Limitsa

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

Tangentially-firedboilers 0.45 0.40Dry-bottom wallfired boilersb 0.50 0.46

Cell-burnerboilers 0.68Cyclone boiler >155 MWe 0.86Wet-bottom wallfired boilers>65 MWe 0.84Vertically fired boilers 0.80

aEmission limits are lb/106Btu of heat input on an annual average basis.bOther than units applying cell-burner technology.
Program Update 1999 1-5

Ox burners were devel

ble to burner modifica

the pre-NSPS boilers

ners (LNB). The CCT

nge of NOx control

here burner modifica

ide methods to en

NOx burner capability.

d gas reburning,

 (SNCR), and selective

 portfolio of NOx

at Phase I and II

able, but will provide

to achieve even

y be necessary to meet

ew National Ambient

) for ozone.

n Air Act requires EPA

revise NAAQS for

the agency as meeting

ach pollutant, EPA sets

tration level “requisite

to protect the public health” with an “adequate marginof safety”) and a “secondary standard” (a level“requisite to protect the public welfare”). In July 1997,EPA issued final rules revising the primary and secondary NAAQS for particulate matter (“PM”) andozone (O3) (commonly referred to as “soot and smog”

regulations).

For ozone, the standard was tightened from 0.12

parts per million (or 120 parts per billion) of ozonemeasured over one hour to a new standard of 0.08parts per million (or 80 parts per billion) measuredover eight hours, with the average fourth highestconcentration over a three-year period determiningwhether an area is out of compliance. (Particulatematter rules are addressed later.)

On May 14, 1999, the U.S. Court of Appeals for

the District of Columbia Circuit remanded EPA’s“soot and smog” regulations, challenging EPA’slegal rationale as well as EPA’s authority to enforceany new ozone standard under the CAAA. The courtdid not challenge the underlying science. The Department of Justice filed a petition for rehearing bythe full court on June 28, 1999. As of the end ofFY99, EPA is awaiting the court’s decision onwhether to rehear the case.

EPA is considering reinstating the old one-hour

ozone standard nationwide. Since issuing the moreprotective 8-hour ozone standard, EPA has revokedthe one-hour standard in much of the country (wherever ozone levels met the old standard). But the courtopinion now leaves much of the nation without anadequately enforceable standard for ground-levelozone pollution to guard against deterioration in airquality. EPA is concerned about that possibility inlight of recent air quality data showing that the national average ozone level increased five percent in 1998.

In addition to the nationwide soot and smog

regulations, efforts are underway to address regionalozone issues.

Attainment of Ozone Standards (Title I).

CAAA Title I established an ozone transport commission to address regional transport of pollutantsthat contribute to ozone nonattainment in the northeast United States. The Northeast Ozone TransportCommission approved a Memorandum of Understanding in September 1994 stipulating an intent toreduce power plant NOx emissions (a precursor toozone formation) by as much as 70 percent by 2003.

Low-NO

x burner technologies: ABB Combustion

Engineering’s LNCFSTM for tangentially-fired boilers (topleft), Foster Wheeler’s low-NOx burner for wall-fired

boilers (top right), Babcock & Wilcox’s LNCB® for cellburner boilers (center), and Babcock & Wilcox’s DRBXCL® for down-fired boilers (bottom).

ower’s Plant Hammond

Foster Wheeler’s low

vanced overfire air.
t Group (OTAG), a

nd the District of

ne 1995 to address the

onse to recommen

e OTAG Policy

to 22 states and the

l (effective Decem

nsport Rule) initially

 submit emission

 1999, on how to cut

1990 rates or achieve

 May 2003. Howev

nal Ambient Air

nion, the Court of

ed the deadline for

ing with the SIP call

t.

 a plan for utilities

s for NO

x

 emissions.

uld apply to the 23

Call. Under the plan,

establish a cap on

wer plants and

industries the flexibility to cut NOx emissions in the

most cost-effective manner. Power plants and industries that cut NO

x emissions below the caps could sell

credits to facilities that could not cut emissions asquickly or cost-effectively. The NOx trading program,

similar to the existing SO2 trading program, allowssources to pursue various compliance strategies, suchas fuel switching; installing pollution control devices,like the devices demonstrated in the CCT Program; orbuying allowances from sources that over-complied.

New Source Performance Standards. On the

national level, the EPA has tightened its NOx emissionstandards 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 modified afterJuly 9, 1997, must meet an emission limit of 1.6 lb/MWh regardless of fuel type. For existing sourcesthat become subject to NSPS, the NOx limit will be 0.15lb/106 Btu. By basing the standard on electricity

output, there is an economic incentive to use moreefficient systems.

Particulate Regulation

Respirable particles. The standard for inhalable

particles (PM10)—those measuring 10 microns indiameter and smaller—established under Title I of theCAAA remains essentially unchanged, while a newstandard for respirable particles (PM2.5)—those measuring 2.5 micrometers in diameter and smaller—wasestablished under the new “soot and smog” regulations. The PM2.5 regulations sets an annual limit of 15micrograms per cubic meter, with a 24-hour limit of 65micrograms per cubic meter under the “soot and smog”regulations mentioned above. The revisions to

NAAQS for PM 2.5 could require additional SO2 control

because many sulfur species are in this size range.Establishing a reliable relationship between fine sulfateemissions and ambient PM 2.5 concentrations couldhave serious repercussions for coal burning facilities.

Eight SCR catalysts with various shapes and

compositions were evaluated side-by-side at Gulf Power’sPlant Crist using high-sulfur coal. NOx reductions of 80

percent were achieved.

nute are PM2.5 particles

PM2.5 Particle

Magnified 1,000x
Program Update 1999 1-7

Monitoring. Under

esponsible for deter

alth posed by 189

), and is required to

ermine the public

cur as a result of power

s issue, DOE imple

y to monitor HAPs

ect sites. Objectives of

improve the quality of

(2) monitor a broader

nd emissions control

rogram, 21 CCT

with 11 having been

see Appendix C,

 January 1993, EPA,

 under the Coal Re

am, the Electric Power

the Utility Air Regu

n emissions data

-of-the-art sampling

sions data were col

senting nine process

h were sites for CCT

ented different coal

furnace types, and

e report, A Compre

missions from Coal

Results from the U.S.

was released in Sep

raw data from the

phase of the DOE/

at other sites, includ

h River, Tampa

Electric, and Sierra Pacific integrated gasificationcombined-cycle (IGCC) projects.

In another DOE study, HAPs data were collected

from 16 power plants and reported in Summary of Air

Toxics Emissions Testing at Sixteen Utility Plants.The report, issued in July 1996, provides an assessment of HAPs measured in the coal, across the majorpollution control devices, and emitted from the stack.The results of the HAPs program have significantlymitigated concerns about a broad range of HAPsemission from coal-fired power generation, and focused attention on mercury.

Mercury. Following up on the October 1996

EPA report to Congress, Study of Hazardous Air

Pollutant Emissions from Electric Utility SteamGenerating Units—Interim Final Report (final report

was issued February 1998), a new report has beenreleased by EPA focusing on mercury emissions.The Mercury Study Report to Congress, issued

December 1997, estimates that the U.S.industrial sources were responsible forreleasing 158 tons of mercury into theatmosphere in 1994 and 1995. The EPAestimates that 87 percent of those emissions originate from combustion sourcessuch as waste and fossil fuel facilities, 10percent from manufacturing facilities, 2percent from area sources, and 1 percentfrom other sources. The EPA also identified four specific categories that accountfor about 80 percent of the total anthropogenic sources: coal-fired power plants, 33percent; municipal waste incinerators, 18percent; commercial and industrial boilers,18 percent; and medical waste incinerators, 10 percent.

Global Climate Change

The CCT Program had its roots in the reduction of

acid rain precursors and was responsive to the recommendations 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 emphasize demonstration 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

percent higher than conventional coal-fired systems,which results in a like reduction in carbon emissions.Also, the PFBC technology reduces pollutant emissions far below NSPS, without expensive add-onemission controls. As a result of the CCT Program’sTidd PFBC Demonstration Project and associated

Hazardous air pollutants were measured at the Babcock & Wilcox

Company’s Demonstration of Coal Reburning for Cyclone Boiler NOxControl at Nelson Dewey Station.
gy is achieving

eral commercial sales

ed power system in

t Tidd is also provid

ration PFBC demon

land, Florida with

ced power system is

nstration projects in

diversity of gasifier

e projects are pioneer

technology, which in

ns, boasts very low SO2

chnology offers

e constructed in

ent worldwide market

pproximately 5 GW,

 a new rule calling for

ovement in visibility

rness areas across the

roups believe coal

f regional haze in the

eas.

8, states are required to

ibility in each of these

duction strategies for

tes have flexibility to

in factors, but as part

er the rate of progress

 conditions in 60

e likely targets for new

Solid Waste

The CCT Program also addresses the issue of

solid waste. For example, several projects redefinedthe state-of-the-art in wet flue gas desulfurization.Included in this significant technology improvementwas production of commercial-grade gypsum in lieuof the scrubber sludge associated with conventionalscrubbers of the early 1990s. Scrubber sludge hadbeen projected to require over 4,500 acres per yearfor disposal by 2015. Advances under the CCTProgram precluded that need. The balance of technologies in the CCT Program also address solidwaste concerns by producing salable by-productsinstead of wastes (e.g., sulfur, sulfuric acid, or fertilizer) or dry, environmentally benign materials. Thesedry materials can either be used as constructionmaterials (e.g., for use in soil and road bed stabilization, or as a cement ingredient), agricultural supplements, a means to mitigate mine subsidence and acidmine drainage, or can be readily disposed of inlandfills.Toxics Release Inventory

Section 313 of the Emergency Planning and

Community Right-To-Know Act (EPCRA) andsection 6607 of the Pollution Prevention Act (PPA)mandates establishment of a publicly accessibledatabase containing information on the release oftoxic chemicals by facilities that manufacture, process, or otherwise use them. This database is knownas the Toxics Release Inventory (TRI). Starting in2000, electric utilities are required to report onreleases of toxic chemicals into the air, water, andland. EPA compiles this data in an online TRI thatgives the public access to detailed information aboutreleases of toxic chemicals in their communities. It

is expected that electric utilities will exceed chemicalmanufacturers as the largest emitters of toxic chemicals into the environment. Although the emissionrates are low for electric utilities, the volume ofemissions will likely bring pressure for furtherreductions.

Coal Technologies forCompetitive Performance

When the CCT Program started in 1985, the

electric utility industry was highly regulated. Themajor uncertainty was the breadth and depth ofenvironmental regulatory requirements that would beimposed on the industry. Even this uncertainty wasmitigated by the fact that the environmental controlcosts could be passed through to the consumer ifapproved by the state regulatory commission. Aslong as the utility made prudent investments in plantand equipment, their economic future was fairlystable and predictable. Most industry observersassumed that coal and nuclear energy would carry theburden of baseload generation, oil would be phasedout, and natural gas would be used for meeting peakload requirements.

By mid-1997, the picture was entirely different—the utility industry was in the midst of a major

restructuring to accommodate a competitive marketplace. Under utility restructuring, power generatorsmust assume the risk for new capacity additions. Therelatively low capital cost and short lead times fornatural gas-based systems makes them the preferredoption for the foreseeable future. As a result, projections now call for natural gas to be the fuel of choice
Program Update 1999 1-9

ugh 2020. During the

pacity will decline and

se moderately.

or factor in pushing for

orm even though

t necessary to assure

fair price. Consumer

riced power have been

mpetition in retail as

ets. Deregulation of

he state level. (The

mmission (FERC) is

 wheeling.) Under the

Act), states continue

ating (1) any electric

urisdiction, (2) any

ale to such a utility,

hat was an associate or

wer to a regulated

ar 1999, twenty-one

states had enacted legislation to allow competition inthe retail electricity market in one form or another.In three other states, there have been comprehensiveregulatory orders issued. Twenty-six states and theDistrict of Columbia are currently investigatingderegulation options. Only in two states is there nosignificant deregulation activity. Under retail deregulation, end users are not required to purchase powerfrom their local utility company, but instead maypurchase power from generators or marketers locatedin other states and regions of the country. In thiscompetitive market environment, power is pricedaccording to market conditions, not necessarilyaccording to generation costs.

Advancement in the technology of electricity

production is another factor that has had an impacton restructuring. Nonutility generators have takenadvantage of these advances, such as aero-derived gasturbines, to generate electricity cheaper than can beachieved using conventional fossil steam or nuclear

Exhibit 1-3

Comparison of Energy Projections for Electric Generators

ales Coal Consumption Gas Consumptiona Oil Consumptiona

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

B % dif A B % dif A B % dif A B % dif

,026b 0.3 924 958b 3.7 3.0 3.37b 12 73 110 51

3,909 -6.4 1,355 1,092 -19.4 1.7 6.45 279 146 77 -47

Projections to 2010, U.S. Department of Energy, December 1985.

 with Projections to 2020, Energy Information Agency, December 1999.

n the two projections.

erators excluding cogenerators.

Outlook 1998, December 1997.

generators. The new technologies are often moreefficient, less environmentally obtrusive, and can beinstalled in a very short period of time in capacitymodules closely matching the load growth curves.

These factors have had a pronounced effect on

the utility market for coal and clean coal technology.A comparison of 1985 and 1999 energy projectionsfor coal, natural gas, and oil, which is shown inExhibit 1-3, illustrates the magnitude of the changethat restructuring is playing, as well as environmental regulation discussed previously. According toEIA’s AEO2000, coal is projected to maintain itslead in the production of electricity in 2010 at 50 percent; however, that is down from 60 percent whenthe CCT Program started. The differential has been,for the most part, made up by the growth in naturalgas power generation. Nuclear power’s contributionto the nation’s electric power generation in 2010 isexpected to drop by almost 30 percent between the1985 and 1999 projections.
ompetition will impact

e foreseeable future.

their operating

nts at higher capacity

d capacity factors is

pacity not only from

acity losses where

 The EIA has

 for coal-fired power

nt in 1998 to 83

dicts that more than 21

 expected to come on

unting for almost 7

uring this time, new

wer systems will

ets. New concepts to

 will likely be em

mouth plants that

portation cost com

so, cogeneration and

ilable, which allow

y to be offset by the

s to

c Growth

to maintain a multi

nal economic growth.

onal energy security

ability, and abun

s. The CCT Pro

elopment and deploy

hat enhances the

efficient use of this coal resource while assuring thatnational and global environmental goals areachieved. The domestic coal resources are largeenough to supply U.S. needs for more than 250 yearsat current rates of production.

The United States is increasingly dependent on

imported oil as low prices have resulted in decreaseddomestic oil production for 13 years. That trend wasbroken in 1995 by an oil production capacity increaseof 0.4 million barrels per day. In 1998, net petroleum imports were 9.8 million barrels per day, or 51percent of domestic consumption. In its AEO2000

projections for 2020, EIA expects crude oil importsto range from 11.42 to 11.71 million barrels per daydepending on oil price. The AEO2000 reference casefor 2020 calls for net imports of 11.59 million barrelsper day, which is over 65 percent of the total crudesupply. Also, natural gas imports are expected togrow from 14.6 percent of total gas consumption in1998 to 16.3 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 to

approximately 3.6 billion barrels of oil per day,which would equate to $44 billion per year. TheCCT Program will provide the technologies that willenable coal to continue as a major component in thenation’s economy while achieving the environmentalquality that society demands. The domestic andexport value of 1998 coal production approaches $60billion in the U.S. economy. Coal related jobs aredispersed through the mining, transportation, manufacturing, utility, and supporting industries.

A U.S. coal conversion industry could directly

reduce the nation’s dependency on imported oil. The

economic impact of adding to domestic oil productionor reducing the cost of imported oil is very significant.The CCT Program is responding to this opportunitythrough development and demonstration of mildgasification and liquid-phase methanol productiontechnologies.

According to EIA’s AER98, the U.S. exported 84

million tons of coal in 1997. Coal exports to foreigndestinations contributed $3.41 billion to the U.S.balance of trade in 1997. Worldwide demand forenergy is expected to reach 612 quadrillion Btu by2020, over 1.6 times the current level. According tothe EIA, worldwide coal use in 1996 accounted forabout 25 percent of total energy consumption and 38percent of the energy consumed worldwide for electricity generation. Those market shares are not projected to change substantially through 2020. Exportsof U.S. coal are projected to increase to over 58 milliontons by 2020.

According to the latest DOE projections, the

worldwide market for power generation technologiescould be as high as $80 billion between 1995 and 2020.Most of the investment will be in developing countries. This market provides opportunities for U.S.technology suppliers, developers, architect/engineers,and other U.S. firms to capitalize on the advantagesgained through experiences in the CCT Program.However, aggressive action is needed, as othergovernments are recognizing the enormous economicbenefits that their economies can enjoy if their manufacturers capture a greater share of this market.

Beyond the CCT Program, DOE activities are

aimed at creating a favorable export climate for U.S.coal and coal technology. These efforts include: (1)improving the visibility of U.S. firms and their products by establishing an information clearinghouse and
Program Update 1999 1-11

ntatives in other coun

ency coordination of

hese exports, and (3)

d policies for facilitat

d projects abroad.

y for the

ding the foundation

tion of fossil energy

f meeting the energy

 the 21st century. The

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 producingboth electricity and fuels will be calculated on a pro-rata basis.

mbined in a variety of configurations.

 to produce a variety of energy

Electricity

Pro c es sHeat/S team

P OWER

FUELS

Fu e ls/C h em ica ls

F ue l Cel l Fue l Ce l l

L i q ui d s C o nv er s i on

H ig h E f f icie ncy T u r bin e H i g h E f f icie n cy T u r bin e

hardware and attendant databases serve as platformsfor power, environmental, and fuels systems thattogether can meet the long-term goals of the Office ofFossil Energy’s Coal & Power Systems Program.These “Vision 21” goals are delineated in Exhibit1-4. The expected result is a suite of technologymodules capable of using a broad range of fuels (coal;biomass; and forestry, agricultural, municipal, andrefinery wastes) to produce a varied slate of highvalue commodities (electricity, steam, clean fuels,and chemicals) at greater than 60 percent efficiencyand near-zero emissions.

First generation systems emerging from the CCT

Program provide: (1) the knowledge base to launchcommercial systems, which will experience increasingly improved cost and performance over time through design refinement; and (2) platforms to test new components, which will result in quantum jumps in cost and performance. Examples of new components include advanced hot gas particulate filtration, hot gas sulfur and alkali removal, air separation membranes, high temperature heat exchangers, artificially intelli- gent controls and sensors, and CO2 and hydrogen separation technologies. A strategy of the Vision 21 effort is to develop and spin off such key components to mitigate the risk and cost of integrating the technol- ogies into power, environmental, and fuel system modules.

Program Update 1999 2-1

am Implementation

g principles and imple

 of the most successful

ry partnerships forged to

ds. Through five na

f 60 government/

ere selected, of which

llion have either been

he end of fiscal year

ndustry cost-share is an

ty percent of the

completed operations.

d, with operational

ts.

of soliciting and award

vironmental concerns

ed. Nevertheless, the

the program to remain

ds. The result is a

database of technical

nable coal to remain a

nergy mix without being

is result will ensure

te to a healthy economy

am is measured by the

, environmental, and

hnology can be project

 Decision makers must

oject performance and

oduction and deployment of new technologies. This need was a driving force in establishing the principles that created the foundation for the implementation process. The government role is non-traditional, moving away from a command-and-control approach to a performance- based approach, where the government sets perfor- mance objectives and industry responds with its ideas and is allowed broad latitude in technical management of the projects. This approach encourages technology innovation and cost-sharing. Industry and the public play major roles in the process, reflecting their respec- tive roles in moving technologies into the marketplace. Implementation Principles The principles underlying the CCT Program were developed after much study of previous government demonstration programs, assessing both positive and negative results. The principles represent a composite of incentives and checks and balances that allows all participants to best apply their expertise and resources. These guiding principles are outlined below.

• A strong and stable financial commitment

exists for the life of the projects. Full fundingfor the government’s share of selected projectswas appropriated by Congress at the start of theprogram. This up-front commitment has beenvital to getting industry’s response in terms ofquantity and quality of proposals received andthe achievement of 66 percent cost-sharing.

• Multiple solicitations spread over a number

of years enabled the program to address abroad range of national needs with aportfolio of evolving technologies. Allowing

time between solicitations enabled Congress toadjust the goals of the program to meet changing national needs; provided DOE time torevise the implementation process based onlessons learned in prior solicitations; andprovided industry the opportunity to developbetter projects and more confidently proposeevolving technologies.

• Demonstrations are conducted at commercial scale in actual user environments.

Typically, a technology is constructed atcommercial scale with full system integration,reflective of its intended commercial configuration, and operated as a commercial facility orinstalled on an existing commercial facility.This enables the technology’s performancepotential to be judged in the intended commercial environment.

• The technical agenda is determined by

industry and not the government. Based on

goals established by Congress and policyguidance received, DOE set definitive performance objectives and performance-basedevaluation criteria against which proposalswould be judged. Industry was given theflexibility to use their expertise and innovationto define the technology and proposed projectin response to the objectives and criteria. DOE
d on those that best

a.

t and industry are

ect the degree of cost

overnment plays a

n structuring the

o protect public

egotiating definitive

and decision points

Once the project

icipant is responsible

t, while the govern

 through aggressive

n implementation only

nued government

g as project milestones

ons of the original

ontinue to be met.

sharing by industry

all project phases.

 required to be

ted to the project, with

rk. By sharing

expended along the

basis, industry’s

project objectives was

wth provides an

alance feature to the

isions allow for

ance beyond the

amount up to 25

l contribution. Such

ovided, must be cost

articipant at no less

than the cost-share ratio of the original cooperative agreement. This statutory provisionrecognizes the risk involved in first-of-a-kinddemonstrations by allowing for cost growth. Atthe same time, it recognizes the need for theindustrial participant’s commitment to share costgrowth and limits the government’s exposure.

• Industry retains real and intellectual property rights. The level of cost-sharing warrants

the industrial participant retaining intellectualand real property rights and removes potentialconstraints to commercialization. Industrywould otherwise be reluctant to come forwardwith technologies they have developed to thepoint of demonstration, relinquishing theircompetitive position.

• Industry must make a commitment to

commercialize the technology. Consistentwith program goals, the industrial participant isrequired to make the technology available on anondiscriminatory basis to all U.S. companiesthat seek, under reasonable terms and conditions, to use the technology. While the technology owner is not forced to divulge know-how toa competitor, the technology must be madeavailable to potential domestic users on reasonable commercial terms.

• Upon successful commercialization of the

technology, repayment up to the government’s cost-share is required. The repaymentobligation occurs only upon successful commercialization of the technology. It is limited to thegovernment’s level of cost-sharing and the 20-year period following the demonstration.

In summary, these principles provide built-in

checks and balances to ensure that the industry andgovernment roles are appropriate and that the government serves as a risk-sharing partner without impedingindustry from using its expertise and getting the technology into the marketplace.Implementation Process

Significant public and private sector involvement

was integral to the process leading to technologydemonstration and critical to program success. Evenbefore engaging in a solicitation, a public process wasinstituted under the National Environmental Policy Act(NEPA) to review the environmental impacts. Aprogrammatic environmental impact assessment(PEIA), followed by a programmatic environmentalimpact statement (PEIS), was prepared prior to initiating solicitations. Public comment and resolution ofcomments were required prior to proceeding with theprogram.

As to the solicitation process, Congress set the

goals for each solicitation in the enabling legislationand report language (see Appendix A for legislativehistory and Appendix B for program implementationhistory). The Department of Energy translated thecongressional guidance and direction into performance-based criteria, and developed approaches toaddress lessons learned from previous solicitations.Before proceeding with a solicitation, however, anoutline of the impending solicitation and attendantissues and options was presented in a series of regionalpublic meetings to obtain feedback. The public meetings were structured along the lines of workshops to
Program Update 1999 2-3

comments from the

mments from the public

paring a draft solicita

or public comment.

ally resolved prior to

osal conferences were

ng any aspects of the

mpt was made in the

derstanding of what was

evaluated, and what con

ould apply. A section

to helping potential pro

igibility, and numerical

 criteria was provided.

a model cooperative

t contractual terms and

iation leading to award

 rules carrying criminal

roposals were evaluated

against and within the

ns established in the

PA, information re

project-specific environ

oeconomic aspects of

er public process was

pecific environmental

National Environmen

gorous environmental

dress all potential

nd socioeconomic

ject. The findings can

onmental impact state

ngs can remain as an

) along with a finding of

no significant impact (FONSI). During the EIS process, public meetings are held for the purpose of disclosing the intended project activities, with emphasison potential environmental, health, safety, socioeconomic impacts, and planned mitigating measures.Comments are sought and must be resolved before theproject can proceed. This process has led to additionalactions taken by the industrial participants beyond theoriginal project scope. To facilitate the NEPA process,DOE encouraged environmental data collection throughcost-sharing during the negotiation period contingentupon project award.

Because of the environmental nature of the CCT

Program, DOE took a proactive posture in carrying outthe 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. As environmental issues emerged, every effort was made toaddress them directly with the understanding thatcommercial technology acceptance hinged on satisfying users and the public as to acceptable environmentalperformance. Appendix C reviews the proactiveenvironmental stance taken by the program, furtherdelineates the NEPA process, and provides the statusof key actions.

Projects are managed by the participants, not the

government. However, public interests are protectedby requiring defined periods of performance referred toas budget periods, throughout the project. Budgetperiods are keyed to major decision points. A setamount of funds is allotted to each budget period,along with performance criteria to be met beforereceiving funds for the next budget period. These

criteria are contained in project evaluation plans(PEPs). Progress reports and meetings during budgetperiods serve to keep the government informed. At thedecision points, progress against PEPs is formallyevaluated, as is the PEP for the next budget period.Financial data is also examined to ensure the participants’ capability to continue required cost-sharing.Failure to perform as expected results in greatergovernment involvement in the decision makingprocess. Proposal of major project changes precipitates not only in-depth programmatic assessment, butlegal and procurement review as well. Decisionsregarding continuance into succeeding budget periods,any increase in funding, or major project changesrequire the approval of DOE’s Assistant Secretary ofFossil Energy.

The NEPA process assured environmental acceptability

of the Healy Clean Coal Project on the border of DenaliNational Park in Alaska.
ssociated with the

e conducted to inform

esults, and issues and

matters pertinent to

ned responsive to

facilitated by direct

arge number of

d states, as well as key

tions (e.g., the Electric

s Research Institute).

ive seminars designed

 the utility, indepen

 insurance underwrit

proach was to identify

missing and then

ormation on the

es’ perspectives and

m performance.

nference was instituted

project progress and

cting the outcome of

each program was put

ormation was pre

ost efficient manner,

and international

kshops. These activi

l in Section 4.

e CCT Program, many

ken and many innova

c and private sectors

s, create new manage

move toward accom

The experience devel

siness arrangements of

s is a significant asset

e CCT Program’s

success—an asset of value to other programs seekingto forge government/industry partnerships. To document lessons learned, Clean Coal Technology Program Lessons Learned was published in July 1994.This report documents the knowledge acquired overthe course of the CCT Program through the completionof five solicitations. The report was based on thebelief that it is of mutual advantage to the private andpublic sectors to identify those factors thought tocontribute to the program’s success and to point outpitfalls encountered and corrective actions taken.

Commitment to CommercialRealization

The CCT Program has been committed to commercial realization since its inception. The significant

environmental, operational, and economic benefits ofthe technologies being demonstrated in the programwill be realized when the technologies achieve widespread commercial success. The importance attachedto commercial 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 of such size as to permit rapidcommercial scale-up.”

The commitment to commercial realization

recognizes the complementary but distinctive roles ofthe technology owner and the government. It is thetechnology owner’s role to retain and use the information and experience gained during the demonstrationand to promote the use of the technology in the domestic and international marketplaces. The detailed opera- tional, economic, and environmental data and the experience gained during the demonstration are vital to efforts to commercialize the technology. The govern- ment’s role is to capture, assess, and transfer operation- al, economic, and environmental information to a broad spectrum of the private sector and international com- munity. The information must be sufficient to allow potential commercial users to confidently screen the technologies and to identify those meeting operational requirements. The importance of commercial realiza- tion is confirmed by the requirement in the solicitations and cooperative agreements that the project participant must pursue commercialization of the technology after successful demonstration. The results of the Tidd PFBC Demonstration Project have helped pave the way to 10 other projects worldwide. The pressure vessel from Tidd is shown above.
Program Update 1999 2-5

ns contained require

 to include a discussion

and approaches to be

roposer was required to

ired to achieve com

ch as financing, licens

acturing, and marketing;

major commercializa

for completion;

s for demonstration of

operational scales, as

ned parallel efforts to the

hat may affect the

oach or schedule; and

enior management on

mercialization effort and

 the various corpora

ng, or energy utilization

t contains three mecha

strated technology can

ms while protecting the

n of the technology

ms are:

clause requires the

et U.S. market demands

nondiscriminatory basis

n” from the project

t team members and

• The clauses concerning rights to technical data

deal with the treatment of data developedjointly in the project as well as data broughtinto the project; and

• The patent clause affords protection for new

inventions developed in the project.

In addition to ensuring implementation of the

above project-specific mechanisms, the governmentrole also includes disseminating the operational, environmental, and economic performance information onthe technologies to potential customers and stakeholders. To carry out this role, a CCT Outreach Programwas established to perform the following functions:

• Make the public and local, state, and federal

government policy makers aware of the CCTsand their operational, economic, and environmental benefits;

• Provide potential domestic and foreign users of

the technologies with the information neededfor decision making;

• Inform financial institutions and insurance

underwriters about the advancements intechnology and associated risk mitigation toincrease confidence; and

• Provide customers and stakeholders opportunities for feedback on program direction and

information requirements.

Specific accomplishments of the CCT Outreach

Program are discussed in Section 4.

Publications keep stakeholders informed of CCT

Program demonstration results.

Exhibits communicate the progress of the CCT Program

at worldwide conferences and trade shows.
Exhibit 2-1

CCT Program Selection Process Summary

Projects in

Proposals Projects CCT Program as

Solicitation PON Issued Submitted Selected of Sept. 30, 1999CCT-I February 17, 1986 51 17 8CCT-II February 22, 1988 55 16 9CCT-III May 1, 1989 48 13 13CCT-IV January 17, 1991 33 9 6CCT-V July 6, 1992 24 5 4

211 60 40

 as a Program Oppor

on mechanism for

e program goals and

hnology is not. Pro

s consistent with the

mitted to DOE by

ed, selected, and

n the bounds of the

de only after Congress

o consider the projects

Report to Congress

results of solicitations.

s currently in the CCT

Program and the solicitationunder which the projectswere selected. Appendix Bprovides a summary of theprocurement history and achronology of projectselection, negotiation,restructuring, and completion or termination. Projectsites are mapped in Exhibits2-3 through 2-6, whichindicate the geographiclocations of projects byapplication category.

The resultant projects

have achieved broad-based industry involvement.More than 55 individual electric generators serving 33

states have participated in the program. These utilitiesgenerate more than 178,000 MWe, approximately 25percent of U.S. capacity, and consume about 36 percent of the coal produced domestically. Also participating were over 50 companies supplying technologyand 30 providing engineering, construction, andconsulting services.

The contributions of the selected projects to

domestic and international energy and environmentalneeds are significant. These contributions include:

• Completing demonstration and proving

commercial viability of a suite of cost-effectiveSO2 and NOx control options capable ofachieving moderate (50 percent) to deep (70–95 percent) emission reduction for the fullrange of coal-fired boiler types;

• Providing the database and operating experience requisite to making atmospheric fluidizedbed combustion a commercial technology at utility scale; • Completing demonstration of a number of coal processes to produce high-energy-density, low- sulfur solid fuels and clean liquids from a range of coal types; • Laying the foundation for the next generation of technologies to meet the energy and environ- mental demands of the 21st century—three IGCC plants in operation at three separate utilities; and successful demonstration of pressurized fluidized-bed combustion at 70 MWe and two larger scale demonstrations in progress; and • Demonstrating significant efficiency and pollutant emission reduction enhancements in steel making, advanced combustion for com- bined SO2/NOx/PM control for industrial and small utility boilers, and innovative SO2 control 

ress for waste elimination in cement production. was issued after

oject.
Program Update 1999 2-7

Location

ty ExpertTM (ABB Combustion Engineering, Inc. and CQ Inc.) Homer City, PA

xtension and Coolside Demonstration (McDermott Technology, Inc.) Lorain, OH

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

 Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Hennepin and Springfield, IL

ect (The Ohio Power Company) Brilliant, OH

cess Demonstration (Western SynCoal LLC) Colstrip, MT

ect (Tri-State Generation and Transmission Association, Inc.) Nucla, CO

tion Demonstration Project (JEA) Jacksonville, FL

emonstration Project (ABB Environmental Systems) Niles, OH

ng for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) Cassville, WI

Cleanup Demonstration Project (The Babcock & Wilcox Company) Dilles Bottom, OH

y Scrubber (Passamaquoddy Tribe) Thomaston, ME

ation Demonstration Project (Pure Air on the Lake, L.P.) Chesterton, IN

ombustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Coosa, GA

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

alytic Reduction Technology for the Control of NOx Emissions from High-Sulfur, Coal-Fired Boilers Pensacola, FL

nc.)

dvanced Tangentially-Fired Combustion Techniques for the Reduction of NOx Emissions from Coal-Fired Lynn Haven, FL

rvices, Inc.)

on of the Liquid Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Kingsport, TN

s Suspension Absorption (AirPol, Inc.) West Paducah, KY

ka Industrial Development and Export Authority) Healy, AK

ow-NO

x Cell Burner Retrofit (The Babcock & Wilcox Company) Aberdeen, OH

Exhibit 2-2

Clean Coal Technology Demonstration Projects by Solicitation
Gas Desulfurization Demonstration (Bechtel Corporation) Seward, PA

ection System Demonstration Project (Bethlehem Steel Corporation) Burns Harbor, IN

stration Project (City of Lakeland, Lakeland Electric) Lakeland, FL

on Project (ENCOAL Corporation) Gillette, WY

d Low-NOx Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) Denver, CO

urization Demonstration Project (LIFAC–North America) Richmond, IN

ns Control System (Public Service Company of Colorado) Denver, CO

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

e NOXSO SO2/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) On hold

monstration for NOx Control (New York State Electric & Gas Corporation) Lansing and Rochester, NY

 Demonstration Project (New York State Electric & Gas Corporation) Lansing, NY

(Sierra Pacific Power Company) Reno, NV

cation Test (ThermoChem, Inc.) Baltimore, MD

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

rated Approach to Clean Air (Custom Coals International) Central City, PA

n Project (Arthur D. Little, Inc.) Fairbanks, AK

al/Ore Reduction (CPICORTM) (CPICORTM Management Company L.L.C.) Vineyard, UT

Demonstration Project (Kentucky Pioneer Energy, L.L.C.) Trapp, KY

 Demonstration Project (City of Lakeland, Lakeland Electric) Lakeland, FL

Location

Exhibit 2-2 (continued)

Clean Coal Technology Demonstration Projects by Solicitation
Program Update 1999 2-9

Southern Company Services, Inc.

Coosa, GA

Energy and Environmental

Research Corporation

Denver, CO

Exhibit 2-3

ographic Locations of CCT Projects—Environmental Control Devices

AirPol, Inc.

West Paducah, KY

The Babcock & Wilcox

Company

Cassville, WI

Pure Air

on the Lake, L.P.

Chesterton, IN

New York State Electric & Gas Corporation

Lansing and Rochester, NY

The Babcock & Wilcox

Company

Lorain, OH

New York State

Electric & Gas Corporation

Lansing, NY

ABB Environmental Systems

Niles, OH

Bechtel Corporation

Seward, PA

The Babcock & Wilcox Company

Dilles Bottom, OH

The Babcock & Wilcox Company

Aberdeen, OH

LIFAC–North America

Richmond, IN

Southern Company Services, Inc.

Newnan, GA

Southern Company Services, Inc.

Pensacola, FL

Southern Company Services, Inc.

Lynn Haven, FL

NOXSO Corporation

On hold
Kentucky Pioneer Energy, LLC

Trapp, KY

Wabash River Coal Gasification

Repowering Project Joint Venture

West Terre Haute, IN

The Ohio Power

Company

Brilliant, OH

Exhibit 2-4

aphic Locations of CCT Projects—Advanced Electric Power Generation

Tampa Electric Company

Mulberry, FL

Tri-State Generation

and Transmission

Association, Inc.

Nucla, CO

City of Lakeland,

Lakeland, FL

(2 projects)

rthur D. Little, Inc.

Fairbanks, AK

JEA

Jacksonville, FL
Program Update 1999 2-11

Rosebud SynCoal

Partnership

Colstrip, MT

ENCOAL Corporation

Gillette, WY

ABB Combustion

Engineering, Inc., and CQ Inc.

Homer City, PA

Air Products Liquid

Phase Conversion

Company, L.P.

Kingsport, TN

Exhibit 2-5

ographic Locations of CCT Projects—Coal Processing for Clean Fuels

Custom Coals International

Central City, PA
Bethlehem Steel Corporation

Burns Harbor, IN

Exhibit 2-6

Geographic Locations of CCT Projects—Industrial Applications

Passamaquoddy Tribe

Thomaston, ME

Coal Tech Corporation

Williamsport, PA

ThermoChem, Inc.

Baltimore, MD
Program Update 1999 2-13

ation

 direction of the CCT

g the existing projects as

ng the collection,

perational, economic,

e results that are needed

scal year 1999, but

rt, the cooperative

on projects expired—

om Coals International

 able to restructure and

Program. Information

mmercial Demonstration

val Flue Gas Cleanup

national’s Self-Scrub

roach projects are

there is data that readers

ore, this report is based

0, 1999, and the expira

ments occurred after that

ot be included in future

owing projects are

ns:

r Project,

ct, and

n Qualification Test.

tained as a result of the

s being used in immedi

regulatory compliance,

forging plans for meeting future energy and environmental demands, and developing the next generation oftechnology responsive to ever-increasing demands onenvironmental performance at competitive costs. Anexpanded portfolio of information will be forthcomingto make it easier for stakeholders and customers to siftthrough the already enormous amount of data resultingfrom the demonstrations.

Efforts will continue toward refining the effectiveness in responding to customer and stakeholder needs.

Toward that end, as needs change, forums will besought to obtain feedback particularly in view of utilityrestructuring, continued environmental concerns, and aburgeoning foreign market. Objectives are to ensurethat CCT Program efforts are fully leveraged and thatfollow-on efforts under the OC&PS Research, Development, and Demonstration Program are appropriate.

Program Update 1999 3-1

ng and Costs

 a federal budget of

m. These funds have

on projects selected

ations. As of Septem

isted of 40 active or

projects have resulted

the federal government

 $5.4 billion. DOE’s

ceeds $1.8 billion, or

e total. The project

al-government partici

ing $3.5 billion, or 66

1 summarizes the total

s cost-sharing by DOE

hapter 3 is based on

 in the CCT Program

ce then, the projects

tion and Custom Coals

 projects were in

o restructure and

Program. Future

 these two projects.

Exhibit 3-1

CCT Project Costs and Cost-Sharing

(Dollars in Thousands)

Total Cost-Share Dollars Cost-Share PercentProject Costs % DOEb Participants DOE Participants

SubprogramCCT-I 844,363 16 239,640 604,723 28 72CCT-II 318,577 6 139,229 179,348 44 56CCT-III 1,408,141 26 618,324 789,817 44 56CCT-IV 1,037,815 19 477,058 560,757 46 54CCT-V 1,765,009 33 360,982 1,404,027 20 80 Totala 5,373,905 100 1,835,233 3,538,672 34 66

Application CategoryAdvanced Electric Power 2,864,284 53 1,118,865 1,745,419 39 61GenerationEnvironmental Control Devices 702,922 13 294,272 408,650 42 58Coal Processing for Clean Fuels 519,196 10 230,024 289,172 44 56Industrial Applications 1,287,503 24 192,072 1,095,431 15 85 Totala 5,373,905 100 1,835,233 3,538,672 34 66

a Totals may not add due to rounding.b DOE share does not include $52,986,136 obligated for withdrawn projects and audit expenses.
Congress has provided program funding through

appropriation acts and adjustments. (See Appendix Afor legislative history and excerpts from the relevantfunding legislation.)

Exhibit 3-2 presents the allocation of appropriated

CCT Program funds (after adjustment) and theamount available for each CCT solicitation. Additional activities funded by CCT Program appropriationsare the Small Business Innovation Research (SBIR)Program, the Small Business Technology Transfer(STTR) Program, and CCT Program direction. TheSBIR Program implements the Small Business Innovation Development Act of 1982 and provides a rolefor small, innovative firms in selected research anddevelopment (R&D) areas. The STTR Programimplements the Small Business Technology TransferAct of 1992 that establishes a pilot program andfunding for small business concerns performingcooperative R&D efforts.

The CCT program direction budget provides for

the management and administrative costs of theprogram and includes federal employees’ salaries,benefits and travel, site support services, and servicesprovided by national laboratories and private firms.Availability of Funding

Although all funds necessary to implement the

entire CCT Program were appropriated by Congressprior to FY1990, the legislation also directed thatthese funds be made available (i.e., apportioned) toDOE on a time-phased basis. Exhibit 3-3 depicts thisapportionment of funding to DOE. Exhibit 3-3 alsoshows the program’s yearly funding profile by appropriations act and by subprogram. Funds can betransferred among subprogram budgets to meetproject and program needs.

derived from the demonstration and commercialdeployment of technologies that improve environmental quality and promote the efficient use of the nation’s coal resources.

The project participant has primary responsibility

for the project. The federal government monitorsproject activities, provides technical advice, andassesses progress by periodically reviewing projectperformance with the participant. The federal government also participates in decision making at majorproject junctures negotiated into the cooperativeagreement. Through these activities, the federalgovernment ensures the efficient use of public fundsin the achievement of individual project and overallprogram objectives.

eral government’s

ercent of the total

he federal govern

 other terms of federal

operative agreement

 program. Terms of

nclude a plan for the

to the full amount of

ution. This approach

 commercially

dition to the benefits

Exhibit 3-2

ween Appropriations and Subprogram Budgets

for the CCT Program

(Dollars in Thousands)

SBIR Program

Adjusted & STTR Direction Projects

ogram Appropriations Budgetsa Budget Budget

380,600 4,902 101,767 273,931

473,959 6,781 32,512 434,666

I 574,998 6,906 22,548 545,544

V 427,000 7,065 25,000 394,935

450,000 5,427 25,000 419,573

2,306,557 31,081 206,827 2,068,649

h (SBIR) and Small Business Technology Transfer (STTR) Programs.

101-512, 102-154, 102-381, 103-138, 103-332, 104-6, 104-208, 105-18, 105-83, 105-277, and
Program Update 1999 3-3

Exhibit 3-3

ual CCT Program Funding by Appropriations and Subprogram Budgets

(Dollars in Thousands)

1986–91 1992e 1994e 1995 1996 1997 1998 1999 2000 2001 2002 Totald

397,600 (17,000) 380,600

574,997 (101,000) (40,000) 9,962 15,000 15,000 473,959

574,998 (156,000) 156,000 574,998

35,000 315,000 100,000 18,000 50,000 (91,000) 427,000

100,000 125,000 19,121 100,000 105,879 450,000

1,582,595 415,000 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 171,000 15,000 2,306,557

387,231 (18,000) (18,000) (33,000) (15,000) (14,900) (14,400) 273,931

535,704 (101,000) (40,000) 9,962 15,000 15,000 434,666

545,544 (156,000) 156,000 545,544

9,875 311,063 98,450 17,622 48,925 (91,000) 394,935

74,062 123,063 18,719 97,850 105,879 419,573

1,478,354 385,125 221,513 18,341 128,775 (18,121) (116,000) (54,900) (160,438) 171,000 15,000 2,068,649

85,527 25,000 18,000 18,000 16,000 15,000 14,900 14,400 206,827

1,563,881 410,125 221,513 36,341 146,775 (2,121) (101,000) (40,000) (146,038) 171,000 15,000 2,275,476

18,714 4,875 3,487 779 3,225 31,081

1,582,595 415,000 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 171,000 15,000 2,306,557

mounts sequestered under the Gramm-Rudman-Hollings Deficit Reduction Act.

onment schedule of P.L. 101-121 as revised by P.L. 101-512, 102-154, 102-381, 103-138, 103-332, 104-6, 104-208, 105-18, 105-83, 105-277, and 106-113.

arch (SBIR) and Small Business Technology Transfer (STTR) Programs.

e to rounding.

ng amounts in 1993.
-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 99 00 01 02 03 04 05

Fiscal Year

Dollars x 1,000

Budget Authority Costs Obligations

The full government cost-share specified in the

cooperative 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 sufficient fundsat the beginning of each budget period to cover thegovernment’s cost-share for that period. This procedurelimits the government’s financial exposure and assuresthat DOE fully participates in the decision to proceedwith each major phase of project implementation.

The overall financial profile for the CCT Program is presented in Exhibit 3-4. The graph shows

actual performance for FY1986 through FY1999 andDOE estimates for FY2000 through program completion. Excluded from thegraph are SBIR and STTRfunds, as these are usedand tracked separatelyfrom the CCT Program.The financial projectionspresented in Exhibit 3-4are based on individualproject schedules andbudget periods as definedin the cooperative agreements and modifications.The negative BudgetAuthority values shown inExhibit 3-4 result fromrescission of $101 millionin FY1998, the deferral of$40 million in FY1999,and the deferral of $146million in FY2000.

terms used by the

 use of appropriated

ommitments, (3)

penditures. The

is described below.

 is the legal authori

ion (i.e., an appro

 the federal govern

he context of the CCT

 established when

negotiation. The

ual to DOE’s share of

d in the cooperative

ative agreement for

nding increments,

ds. The cooperative

ks to be performed in

bligation occurs in the

period and establishes

 federal funds

t for use in performing

perative agreement.

ment submitted by

the federal govern

of tasks performed

operative agreement

ts are equivalent to a

e.

res represent payment

ticipant from checks

sury.

Exhibit 3-4

CCT Financial Projectionsa

as of September 30, 1999

aIncludes changes resulting from P.L. 106-113.

The financial status of the program through

September 30, 1999, is presented by subprogram inExhibit 3-5. SBIR and STTR funds are included inthis exhibit to account for all funding. Exhibit 3-5also indicates the apportionment sequence as modified by Public Law 106-113. These values representthe amount of budget authority available for the CCTProgram.

Project Funding, Costs, and Schedules

Information for individual CCT projects, including

funding and the status of key milestones, is provided inSection 5. An overview of project schedules andfunding is presented in Exhibit 3-6.
Program Update 1999 3-5

propriations

ocated to Apportioned Committed Obligated Cost

bprogramb to Date to Date to Date to Date

1986 99,400 99,400

1987 149,100 248,5001988 199,100 447,6001989 190,000 637,6001990 554,000 1,191,6001991 390,995 1,582,5951992 415,000 1,997,5951993 0 1,997,5951994 225,000 2,222,5951995 37,121 2,259,7161996 150,000 2,409,7161997 (2,121) 2,407,5951998 (101,000) 2,306,5951999 (40,000) 2,266,5952000 (146,038) 2,120,5572001 171,000 2,291,5572002 15,000 2,306,557

73,931 273,931 257,126 257,126 183,854

34,666 404,666 171,198 172,026 165,275

45,544 389,544 618,324 618,061 470,076

94,935 394,935 478,389 478,389 463,751

9,573 419,573 363,182 148,331 15,840

68,649 1,882,649 1,888,219 1,673,933 1,298,796

1,081 31,081 31,081 31,081 31,081

06,827 206,827 192,427 190,847 187,806

06,557 2,120,557 2,111,727 1,895,861 1,517,683

Apportionment SequenceFY Annual Cumulative

arch (SBIR) and Small Business Technology Transfer (STTR) Programs

e to rounding

113

Exhibit 3-5

Financial Status of the CCT Program as of September 30, 1999c

(Dollars in Thousands)
Exhibit 3-6

CCT Project Schedules and Funding, by Application Category

8 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 DOE Total

4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 ($1,000)

 Environmental Control Devices 7,592 19,311

6,554 15,854

18,748 37,589

4,149 8,5545,206 10,4126,341 13,6475,443 11,233

15,719 31,438

6,078 13,272

63,913 151,70810,637 21,39413,083 26,165

2,315 7,7178,896 17,807

21,085 43,075

9,407 23,230

45,000 158,608

2,701 9,096

 On hold 41,406 82,812

eaward - Design and Construction - Operation and Reporting
Program Update 1999 3-7

Exhibit 3-6 (continued)

CCT Project Schedules and Funding, by Application Category

88 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 DOE Total

34123412341234123412341234123412341234123412341234123412341234123412341234 ($1,000)

 Advanced Electric Power Generation 17,130 160,050

66,957 189,886

219,100 438,200150,894 303,288167,957 335,913117,327 242,058

23,818 47,63674,734 309,09793,253 186,58878,086 431,933

109,609 219,636

 Coal Processing for Clean Fuels 10,864 21,746

43,125 105,70045,332 90,664

 On hold 37,994 87,386

92,708 213,700

Industrial Applications 490 984

5,983 17,800

31,824 194,302

4,306 8,612

149,469 1,065,805

reaward - Design and Construction - Operation and Reporting (1) - completion scheduled for July 2007

(1)
e CCT Program is

nt between the

nment referred to as

pproach, as imple

s introduced in Public

propriations for the

elated Agencies for

er 30, 1986, and for

ts and requirements

pplied to the CCT

ements:

may not finance more

l costs of a project;

t participants is

oject (design,

n);

may share in project

cope of work defined

e agreement) up to

ly negotiated

project;

ring contribution must

are incurred and

d based on prospective

s, or royalties; and

cilities, equipment, or

D funds are not

f cost-sharing.

hibit 3-1 summarizes

gram and by applica

 completed projects.

In the advanced electric power generation category,which accounts for 53 percent of total project costs,participants are contributing 61 percent of the funds.Cost-sharing by participants for environmental controldevices, coal processing for clean fuels, and industrialapplications categories is 58 percent, 56 percent, and85 percent, respectively. For the overall program,participants are contributing 66 percent of the totalfunding, or $1.7 billion more than the federalgovernment.Recovery of GovernmentOutlays (Recoupment)

The policy objective of DOE is to recover an

amount up to the government’s financial contributionto each project. Participants are required to submit aplan outlining a proposed schedule for recovering thegovernment’s financial contribution. The solicitationshave featured different sets of recoupment rules.

Under the first solicitation, CCT-I, repayment

was derived from revenue streams that include netrevenue from operation of the demonstration plantbeyond the demonstration phase and the commercialsale, lease, manufacture, licensing, or use of thedemonstrated technology. In CCT-II, repayment waslimited to revenues realized from the future commercialization of the demonstrated technology. Thegovernment’s share would be 2 percent of grossequipment sales and 3 percent of the royalties realizedon the technology subsequent to thedemonstration.

The CCT-III repayment formula was adjusted to

0.5 percent of equipment sales and 5 percent of

royalties. Limited grace periods were allowed on aproject-by-project basis. A waiver on repayment maybe sought from the Secretary of Energy if the projectparticipant determines that a competitive disadvantagewould result in either the domestic or internationalmarketplace. The recoupment provisions for CCT-IVand CCT-V were identical to those inCCT-III.

As of September 30, 1999, five projects have

made repayments to the federal government: NuclaCFB Demonstration Project (Tri-State Generation andTransmission Association, Inc.); Full-Scale Demonstration of Low-NOx Cell Burner Retrofit (The Babcock & Wilcox Company); Development of the CoalQuality ExpertTM (ABB Combustion Engineering, Inc.and CQ Inc.); 10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.); and the Advanced FlueGas Desulfurization Demonstration Project (Pure Airon the Lake, L.P.).

In September 1997, the CCT Program office

issued a report entitled Recoupment Lessons Learned— Clean Coal Technology Demonstration Program.The report: (1) reviewed the lessons learned on“recoupment” during the implementation of the CCTProgram; (2) addressed recommended actions setforth in General Accounting Office (GAO) ReportRCED-92-17, GAO Report RCED-96-141, andInspector General Audit Report IG-0391 relative to“recoupment”; and (3) provided input into DOEdeliberations on “recoupment” policy.
Program Update 1999 4-1

Program Accomplishments

nued success is exempli

owing demonstrations

Year 1999:

-Coal Injection System

ning Demonstration for

g with the other 38

are producing a wealth

hnologies.

ogram ultimately will

n the technologies make

nomic, and environmen

 can only be achieved if

nderstand that clean

the efficiency of energy

l quality at costs that are

ergy options.

tinued efforts to define

mestic and international

gies. Domestically, this

ialogue with electric

 commissioners, and

uired are analyses of the

acity requirements,

tegies, and electric

e demand for clean coal

activities include partici

ces and workshops,

n coal technologies, and

providing technical support to trade agencies, trademissions, and financial organizations.

Throughout the 1999 fiscal year, the CCT Program staff participated in over 16 domestic and international events involving users and vendors of clean

coal technologies, regulators, financiers, environmental groups, and other public and private institutions.Included was the Seventh Clean Coal TechnologyConference, held in Knoxville, Tennessee and attended by 230 participants from 12 countries. Four issuesof the Clean Coal Today newsletter were published in

the same period, along with the fourth annual editionof the Clean Coal Today Index, which cross-referencesall articles published in the newsletter. A new series ofreports, 12-page Project Performance Summarydocuments, were issued for 10 of the completed CCTProgram projects. Also, four Clean Coal Technologytopical reports were issued during the fiscal year. TheDOE also continued expanded coverage of the program by publishing the Clean Coal Technology Demonstration Program: Update 1998, and the mid-year

update of project fact sheets, Clean Coal TechnologyDemonstration Program: Project Fact Sheets 1999.

Subsequent to the end of fiscal year 1999, but

prior to publication of this report, the cooperativeagreement for two demonstration projects expired—NOXSO Corporation and Custom Coals Internationalare in bankruptcy and were not able to restructure andcontinue work under the CCT Program. Informationon NOXSO Corporation’s Commercial Demonstrationof the NOXSO SO2/NOx Removal Flue Gas Cleanup

System and Custom Coals International’s Self-Scrubbing Coal

TM: An Integrated Approach projects are

included in this report because there is data that read-
more, this report is

ber 30, 1999 and the

greements occurred

ts will not be included

mitment

mmercialization goals,

ve demonstrations at

opportunity for the

n of the demonstrated

egy to comply with the

 a risk-sharing partner,

ged to:

,

iance with environ

city generation,

• Improve power generation efficiencies, and• Position U.S.-based industry to export innovative services and equipment.Reflecting the marketplace commitment, the CCT

projects 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 highlights some of the program and

project accomplishments to date along with commercialization successes by market sector.Environmental Control Devices

All but 2 of the 19 environmental control device

projects have now completed operations. The completed demonstrations proved commercial viability of asuite of cost-effective SO2 and NOx control options forthe full range of coal-fired boiler types. Risk wassignificantly mitigated in successfully applying thetechnologies commercially because of the extensivedatabases and attendant predictive models developedthrough the demonstrations. Also, projects were leveraged to provide input in formulating NOx control requirements under the CAAA and to evaluate the impact of emerging issues, such as air toxics, on the existing boiler population and control options. Exten- sive air toxics testing was performed in conjunction with 10 of the environmental control projects. To a great extent, the technologies were retained for com- mercial service at the demonstration sites and many technology suppliers have realized commercial sales. SO2 Control Technologies. All five SO2 control technology demonstrations have completed operations, evaluating three basic approaches to address the di- verse coal-fired boiler population: (1) sorbent injec- tion, (2) gas-suspension absorption, and (3) advanced flue gas desulfurization. • Two low-capital cost sorbent injection systems, sponsored by LIFAC–North America and Bechtel Corporation, demonstrated SO2 capture efficiencies in the range of 50 to 70 percent. These systems hold particular promise for the older, smaller units, particularly those with space constraints. • A moderate-capital cost gas-suspensionabsorption system, sponsored by AirPol, Inc.,

demonstrated SO2 capture efficiencies in therange of 60 to 90 percent. The system hasparticular applicability to the small- to midrange units with some space limitations.

• Two advanced flue gas desulfurization

(AFGD) systems, sponsored by Pure Air on theLake, L.P. and Southern Company Services,having somewhat higher capital costs than theother approaches, demonstrated SO2 captureefficiencies in the range of 90 to 95 percent.These systems are primarily applicable to thelarger, newer units that have space available.

ol (left), CT-121
Program Update 1999 4-3

ned the state-of-the-art

ing that a single absorb

could process large

e the required availabili

odule design, without

h integration of func

le and use of high

ved capital cost and

D testing also estab

psum could be produced

er discharge could be

corrosion, fiberglass

ould eliminate process

hloride removal and flue

by Southern Company

1 showed that the system

ticulate control. Pure

ed an innovative busi

pany builds, owns, and

ted service to a utility.

ies of the burden of

ses to date for the SO2

arized in Exhibit 4-1.

. Six of the seven NOx

ons have successfully

 was conducted on the

red, tangentially-fired,

boilers), representing

d boiler population;

to all boiler types.

eductions achieved for

45 to 68 percent

50 to 67 percent

• SNCR systems: 30 to 50 percent• SCR systems: 80 to 90+ percent• Advanced controls: 10 to 15 percentThe database developed during Southern Company

Services’ evaluation of NOx control on wall-fired andtangentially-fired boilers at Plant Smith and PlantHammond, respectively, was used by EPA in formulating NOx provisions under the CAAA. ABB Combustion Engineering’s LNCFSTM proved effective indemonstration for tangentially-fired boilers and realized commercial acceptance, as did Foster Wheeler’sControlled Flow/Split Flame and Babcock & Wilcox’sDRB-XCL® low-NOx burners for wall-fired boilers.The Babcock & Wilcox Company’s low-NOx cell

burner, LNCB®, provided an effective low-cost plug-inNOx control system for cell-burner boilers, which are

known for their inherently high NOx emissions.

Integration of neural-network systems into digital

boiler controls, such as the Generic NOx Control

Intelligence System (GNOCIS) installed at PlantHammond, demonstrated effective optimization ofparameters for NOx control and boiler performance

under load-following operations.

The Babcock & Wilcox Company’s coal reburning

technology proved not only to be an effective way tocontrol NOx on cyclone boilers, but a means to avoid

derating cyclone boilers when switching to low-sulfur,low-rank western coals. Energy and EnvironmentalResearch Corporation’s use of gas reburning, applicable to all boiler types, introduced an alternative to SCRfor high NOx emission reduction particularly when usedwith low-NOx burners.

In another project, comparative analyses were

conducted on a range of SCR catalysts operated onhigh-sulfur U.S. coals, providing needed insight on theenvironmental and economic performance potential of

SCR. Other SCR systems and selective non-catalyticreduction (SNCR) systems were demonstrated inconjunction with 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.

Six of the seven combined SO2/NOx control technology demonstrations have successfully completed

operations. The demonstrations evaluated a multiplicity of complementary and synergistic controlmethods to achieve cost-effective SO2 and NOx

emissions reductions.

SNOXTM, a catalytic process developed by Haldor

Topsoe a/s, consistently achieved 95 and 94 percentSO2 and NOx control, respectively. The process alsodemonstrated excellent particulate control, whileproducing a salable by-product in lieu of solid waste.

In a project sponsored by Public Service Company

of Colorado, complementary use of low-NOx burnerswith SNCR resulted in NOx emission reductions of

greater than 80 percent. SNCR interacted synergistically with sorbent injection to reduce ammonia slip andNOx emissions. Sodium-based sorbent injectionachieved 70 percent SO2 removal at high sorbentutilization rates.

New York State Electric & Gas Corporation

(NYSEG) evaluated an advanced flue gas desulfurization system, the S-H-U scrubber process. The S-H-Uprocess, an advanced formic acid-enhanced wet limestone scrubbing process, demonstrated a 98 percentSO2 capture efficiency. In conjunction with the S-H-Uprocess, NYSEG also evaluated micronized coal as areburn fuel using close-coupled reburning techniquesand deep staged combustion incorporated into ABBCombustion Engineering, Inc.’s LNCFSTM burners.
Exhibit 4-1

Commercial Successes—SO2 Control Technology

Commercial Use

uspension Absorption Sold domestically and internationally. GSA market entry was significantly enhanced with the sale of a 50-MWe

unit, worth $10 million, to the city of Hamilton, Ohio subsidized by the Ohio Coal Development Office. A sale worth

$1.3 million has been made to the U.S. Army for hazardous waste disposal. A GSA system has been sold to a Swedishiron ore sinter plant. Sales to Taiwan, Indonesia, and India have a combined value of $20 million. Furthermore,Taiwan contracted for technical assistance and proprietary equipment valued at $1.0 million.

as Desulfurization No sales reported. CZD/FGD can be used to retrofit existing plants or for new installations at a cost of about

on) one-tenth that of a commercial wet scrubber.

ization Sold domestically and internationally. There are 10 full-scale LIFAC units in operation in Canada, China,

orth America) Finland, Russia, and the United States. The LIFAC system at Richmond Power & Light is the first to be applied to a

power plant using high-sulfur (2.0-2.9%) coal. The LIFAC system has been retained for commercial use by RichmondPower & Light at Whitewater Valley Station, Unit No. 2.

n Demonstration Project No sales reported. The AFGD continues in commercial service at Northern Indiana Public Service Company’s

Bailly Generating Station. Gypsum produced by the PowerChip® process is being sold commercially.

ications of Sold internationally. Plant Yates continues to operate with the CT-121 scrubber as an integral part of the site’s

Process CAAA compliance strategy. Since the CCT Program demonstration, over 8,200 MWe equivalent of CT-121 FGD

) capacity has been sold to 16 customers in 7 countries.
Program Update 1999 4-5

Exhibit 4-2

Commercial Successes—NO

x Control Technology

Commercial Use

monstration for NOx Control No sales reported. Technology retained for commercial use at Kodak Power Plant.

Corporation)

g for Cyclone Boiler NOx Control No sales reported. Technology retained for commercial use at Wisconsin Power and Light Company’s Nelson

ny) Dewy Station.

w-NO

x

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

ny) commercial contracts have been awarded for 172 burners, valued at $27 million. The LNCB® technology has

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

d Low-NOx Burners on a Sold domestically and internationally. Public Service Company of Colorado, the host utility, decided to

nvironmental Research retain the low-NOx burners and the gas-reburning system for immediate use; however, a restoration was required to

remove the flue gas recirculation system. Energy and Environmental Research Corporation has been awarded two

contracts to provide gas reburning systems for cyclone coal-fired boilers: TVA’s Allen Unit 1 (a 330-MWe unit) aswell as Baltimore Gas & Electric’s C. P. Crane Units 1 and 2 (similar 200-MWe units). The technology is alsoinstalled at Ladyzkin State Power Station in Ladyzkin, Ukraine.

ytic Reduction Technology No sales reported. SCR has realized commercial acceptance abroad. The demonstration tests established SCR as

s from High-Sulfur, a viable U.S. compliance option and aided utilities in developing the most cost-effective site-specific applications

mpany Services, Inc.) of SCR.

vanced Tangentially-Fired Sold domestically and internationally. LNCFSTM has been retained at the host site for commercial use. ABB

Reduction of NOx Emissions from Combustion Engineering has modified 116 tangentially-fired boilers, representing over 25,000 MWe, with

mpany Services, Inc.) LNCFSTM and derivative TFS 2000TM burners.

mbustion Techniques Sold domestically and internationally. The host has retained the technologies for commercial use. Foster

n Company Services, Inc.) Wheeler has equipped 86 boilers (51 domestic and 35 international) with low-NOx burner technology—a total of

1,800 burners representing over 30,000 MWe capacity valued at $35 million. Twenty-six commercial installationsof GNOCIS, the associated AI control system, are underway or planned. This represents over 12,000 MWe ofcapacity. In a strict sense, this project has not been completed; it has been extended to apply GNOCIS to otherpieces of plant equipment, which may increase its commercial potential.
While the Nucla project established commercial

acceptance of ACFB at moderate utility capacities, asecond CCT demonstration project, located in Jacksonville, Florida, is carrying on where Nucla left off. JEAwill build a 300-MWe plant, which will have thedistinction of being the largest ACFB in the world, aswell as one of the cleanest.

Today, every major U.S. boiler manufacturer

offers an ACFB in its product line. There are nowmore than 120 fluidized-bed combustion boilers ofvarying capacities operating in the United States, andthe technology has made significant market penetrationabroad.

Through the Ohio Power Company’s repowering

of the Tidd Plant (70 MWe), the potential of PFBC asa highly efficient, very low pollutant emission technology was established and the foundation was laid forcommercialization. The PFBC system constructed wasthe first utility-scale system in the United States.Efforts were focused on fully evaluating the performance potential. Over 11,444 hours of operation, thetechnology successfully demonstrated SO2 removalefficiencies up to 95 percent with very high sorbentutilization (calcium-to-sulfur molar ratio of 1.5), andNO

x emissions in the range of 0.15 to 0.33 lb/106 Btu.

The Tidd Plant PFBC was one of the first generation 70-MWe P200 units installed in the early 1990s.

Others were built and operated in Sweden, Spain, andJapan. ABB Carbon, 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 is scheduled for operation in1999. And, a “second generation” P200 PFBC withfreeboard-firing is operating in Cottbus, Germany. Anumber of other ABB Carbon PFBC projects are under

ant optimization

nt Emission Optimiza

has been sold to a

ustry.

mpany’s SOx-NOx-Rox

 developed high

 baghouse installa

ction, proved to be an

ontrol system for SO2,

erformance was 80

NOx removal, and

ge burner (LIMB) and

that sorbent injection

percent SO2 reduction.

CL® advanced low

ons by 45 percent.

Research Corporation’s

nd sorbent injection

 greater than 60

nly 13 percent natural

val of over 55 percent

al sorbents. NOXSO

a dry, regenerable flue

o remove 98 percent

NOx from a coal-fired

s to date for the

echnologies are

neration

ority early in the CCT

s included technolo

er aging plants faced

ssions and respond to

growing power demands. Repowering is an importantoption because existing power generation sites havesignificant value and warrant investment because theinfrastructure is in place and siting new plants represents a major undertaking. This recognition led toaward early on of three key repowering projects—twoACFB projects and a PFBC project.

As the CCT Program unfolded, a number of

energy and environmental issues combined to changethe emphasis toward seeking highly-efficient, very lowemission power generation technologies for bothrepowering and new power generation. This emphasiswas deemed essential to enable coal to fulfill its projected contribution to the nation’s energy mix well intothe 21st century. Environmental issues included agrowing concern over greenhouse gas emissions,capping of SO2 emissions, increasing attention to NOx

in ozone nonattainment areas, and recognizing fineparticulate emissions (respirable particulates) as aparticular health threat. These issues prompted followon projects in PFBC, initiation of projects in IGCC,and projects in advanced combustion and heat engines.

Fluidized-Bed Combustion. The Tri-State

Generation and Transmission Association, Inc.’s NuclaStation repowering project provided the database andoperating experience requisite to making ACFB acommercial technology option at utility scale. At 110MWe, the Nucla ACFB unit was more than 40 percentlarger than any other ACFB at that time. Up to 95percent SO2 removal was achieved during the 15,700hours of demonstration, and NOx emissions averaged a

very low 0.18 lb/106 Btu. The thrust of this effort wasto fully evaluate the environmental, operational, andeconomic performance of ACFB. As a result, the mostcomprehensive database on ACFB technology available to date was developed. Based on this knowledge,commercial units were offered and built.
Program Update 1999 4-7

Exhibit 4-3

Commercial Successes—Combined SO2/NOx Control Technology

Commercial Use

monstration Project (ABB International use. The host utility, Ohio Edison, is retaining the SNOXTM technology as a permanent part of the

pollution control system at Niles Station to help meet its overall SO2 and NOx reduction goals. Commercial SNOXTM

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

tension and Coolside Sold domestically and internationally. LIMB has been sold to an independent power plant in Canada. Babcock &

hnology, Inc.) Wilcox has signed contracts for 124 units for DRB-XCL® low-NOx burners, representing 2,428 burners for 31,467 MWe

of capacity. The low-NOx burners have an estimated value of $240 million.

leanup No sales reported. Commercialization of the technology is expected to develop with an initial larger scale application

cock & Wilcox Company) equivalent to 50-100 MWe. The focus of marketing efforts is being tailored to match the specific needs of potential

industrial, utility, and independent power producers for both retrofit and new plant construction. SNRBTM is a flexibletechnology that can be tailored to maximize control of SO2, NOx, particulate, or combined emissions to meet currentperformance requirements while providing flexibility to address future needs.

Gas Reburning and No sales reported. Illinois Power has retained the gas-reburning system and City Water, Light & Power has retained

nvironmental Research the full technology for commercial use. (See Evaluation of Gas Reburning and Low-NOx Burner on a Wall-Fired

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

 Demonstration Project Sold domestically. Six modules of DHR Technologies’ Plant Emissions Optimization Advisor, with an estimated

Corporation) value of $210,000, have been sold. A U.S. company, SHN, has been established to market the S-H-U scrubber. SHN

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

ns Control System Sold domestically. The technology was retained by Public Service Company of Colorado for commercial service at its

orado) Arapahoe Station. The Babcock & Wilcox DRB-XCL® burner that was demonstrated has realized sales of 2,428

burners, representing 31,467 MWe. The burners are valued at $240 million.
orea, the United King

ojects, McIntosh 4A

ate PCFB at utility

zation velocity than

rains the bed material.

he flue gas by cyclones

r. The economizer,

e gas, is downstream of

evaluate a 137-MWe

on using Foster Wheel

demonstrate a second

a small coal gasifier

 “topping cycle,”

ty. The second genera

nificantly improve the

d-bed systems by

 the gas turbine, which

ottom cycle.

mbined-Cycle. Three

ration under the CCT

sity of gasifier types,

s. PSI Energy’s 262-

cation Repowering

mber 1995 and contin

ial service. The utility

al-fired units because

which is the world’s

erated on coal for over

e than one million tons

onthly production

gas on several

ric Integrated Gasifi

began commercial

d continues to accumu

cumulated over

15,000 hours of operation and produced over3,500,000 MWh of electricity on syngas. Tests haveincluded evaluation of various coal types on systemperformance.

The Sierra Pacific Power Company (SPPC)

continues to make progress on its IGCC system. The99-MWe Piñon Pine IGCC Power Project at SPPC’sTracy Station began operation on natural gas in November 1996. The GE Frame 6FA, the first of its kindin the world, performed well. The plant has undergoneshakedown, and design modifications have been made.The system has achieved steady state gasifier operationfor short periods through September 1999, but continues to experience difficulty with sustained operations.

The Kentucky Pioneer Energy IGCC Demonstration Project, which is in the design stage, will offer yet

another gasifier design and include the testing of a fuelcell operated on syngas from the coal gasifier. This willprovide valuable data for design of an integratedgasification fuel cell (IGFC) system. IGFC has thepotential to achieve efficiencies greater than 60percent.

Commercial configurations resulting from the

current IGCC and PFBC demonstrations will typicallyhave efficiencies at least 20 percent greater thanconventional coal-fired systems (with like CO2 emission reductions), remove 95 to 99 percent of the SO2,

reduce NO

x 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. Two

projects are demonstrating advanced combustion/heatengine technology. The Healy Clean Coal Project isdemonstrating TRW’s entrained (slagging) combustorcombined with Babcock & Wilcox’s spray-dryer

absorber using sorbent recycle. Operations commenced in January 1998. Results from environmentalcompliance testing showed very low emissions—0.26lb/106 Btu for NO

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

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

Btu for NO

x, 0.086 lb/106 Btu for SO2, and 0.03 lb/106

Btu for particulates because of the plant’s proximity to anational park. NSPS allows 1.2 lb/106 Btu for SO2.

The Clean Coal Diesel Demonstration Project is

evaluating 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 percent

Three IGCC plants are in operation: Tampa Electric

(top), Piñon Pine (middle), and Wabash River (bottom).
Program Update 1999 4-9

mercial feasibility studies have been completed—twofor Indonesia, one for Russia, and two for U.S.projects. Permitting of a 15,000 metric ton/day commercial plant in Wyoming is nearly complete.

The Western SynCoal LLC project is demonstrating another route to producing high-quality fuel from

low-rank coals. The advanced coal conversion process(ACCP) upgrades low-rank coal to produce a lowsulfur (as low as 0.3 percent sulfur) SynCoal® producthaving a heating value of about 12,000 Btu per pound.The Western SynCoal LLC has signed a letter ofagreement to supply fuel to Montana Power’s 330-MWe Colstrip Unit No. 2. Five other agreements havebeen signed.

The advanced physical coal-cleaning technology

developed by Custom Coals International uses highsulfur bituminous feedstocks to produce two types ofcompliance coal—Carefree CoalTM and Self-ScrubbingCoalTM.

Air Products Liquid Phase Conversion Company,

L.P., is demonstrating the LPMEOHTM process toproduce methanol from coal-derived synthesis gas.The LPMEOHTM process has been developed toenhance integrated gasification combined-cycle powergeneration facilities by coproducing a clean-burningstorable liquid fuel from coal-derived synthesis gas.The production of dimethyl ether (DME) as a mixedcoproduct with methanol will also be demonstrated.Methanol and DME may be used as a low-SO2, lowNO

x alternative liquid fuel, a feedstock for the synthesis of chemicals, or as a new oxygenate fuel additive.

Since start-up, the LPMEOHTM demonstration unit hasproduced over 43 million gallons of methanol, all ofwhich was accepted by Eastman Chemical Companyfor use in downstream chemical processing. Sincerestart of the unit with fresh catalyst in December

999, the checkout of the

ses for the advanced

ms to date are summa

Fuels

 coal processing for

 operations and submit

is category include

es that can be used to

al reserves into eco

ant solid and liquid

d products from coal

d to be readily transport

d low in sulfur, ash, and

are designed to be

tationary power genera

tocks. Both solid and

ses that produce them,

al both domestically

n SynCoal LLC projects

o using the nation’s vast

sity western coal re

ve particular application

iance and internationally

.

duct has an energy

r pound, and the sulfur

ENCOAL’s liquid fuel

6 fuel oil or serve as a

e demonstration, over

hipped to seven custom

tank cars of liquid

even states. Five com1997, availability of the unit has been greater than 99 percent and catalyst activity decline has approached 0.4 percent/day. ABB Combustion Engineering, Inc. and CQ Inc. developed PC-based software, CQETM, to assist utilities in assessing the environmental and operational perfor- mance of their systems for the available range of coal fuels to determine the least-cost option. The CQETM software has been distributed to over 35 utility members of EPRI and is being marketed commercially worldwide. Two U.S. utilities also have been licensed to use copies of the CQETM stand-alone Acid Rain Advisor. The LPMEOHTM demonstration unit at Eastman Chemical Company’s vast chemicals-from-coal complex in Kingsport, TN.
Exhibit 4-4

Commercial Successes—Advanced Electric Power Generation

Commercial Use

Sold internationally. Success of the project has led Babcock & Wilcox to invest in the technology and

acquire domestic licensing rights.

Commercial ventures abroad include the following:– Vartan in Sweden is operating two P200 units to produce 135 MWe and 224 MWt;– Escatron in Spain is operating one P200 unit producing 80 MWe;– Wakamatsu in Japan is operating one P200 unit to produce 71 MWe;– Cottbus in Germany is operating one P200 unit to produce 71 MWe and 40 MWt;– Karita in Japan operates one P800 unit to produce 360 MWe; and– Other projects under construction are in China, South Korea, U.K., and Israel.

 (Tri-State Sold domestically and internationally. Today, every major boiler manufacturer offers an ACFB system in its product line.

ciation, Inc.) Since the demonstration, commercial sales of 29 units greater than 100 MWe have been realized, representing 6.2 gigawatts

of capacity valued at nearly $6 billion.

tion Sold domestically and internationally. First greenfield IGCC unit in commercial service. Texaco, Inc., and ASEA Brown

Electric Company) Boveri signed an agreement forming an alliance to market IGCC technology in Europe. There are currently 10 IGCC projects

using a Texaco gasifier that are either planned or under construction.

epowering Project No sales reported. First repowered IGCC unit in commercial service and is the world’s largest single train

Repowering Project IGCC in commercial service. Preferentially dispatched over other coal-fired units is PSI Energy’s system

because of high efficiency.

Sierra Pacific No sales reported. Unit in initial operation preparatory to commercial service.

Industrial Development No sales reported. TRW offering licensing of combustor worldwide (China agreement in place). Commercial operation tests

are ongoing.
Program Update 1999 4-11

ses for the coal pro

e summarized in

ssing the environmental

with coal use in industri

rojects have completed

 steel has been depen

 however, is an inher

us air pollutants. Also,

on coal fuel because

ven by fuel costs.

 coal is an attractive

ustrial boilers, but

d NOx emissions and

d coal use.

ehem Steel Corporation,

nular-coal injection

ated that 40 percent of

oal injected directly

sions from coal combus

n the process.

Company L.L.C. is in the

direct iron ore reduction

ng coal in lieu of coke.

for coke.

 successfully demon

ber that uses cement

f as waste, to remove 90

tilizer and distilled

 to feedstock with no

ved closer to commer

trial boilers that slags

the ash in the combustor to prevent boiler tube fouling,controls NO

x (70 to 80 percent reduction) through

staged combustion, and controls SO2 (90 percent) withsorbent injection. ThermoChem, Inc. has completedrestructuring of its project and will be demonstrating amultiple resonance tube pulse combustor design.

Commercialization successes for the industrial

applications technologies to date are summarized inExhibit 4-6.

Awards

The projects in the CCT Program have won

numerous awards from news, professional, and nonprofit organizations. A listing of those awards iscontained in Exhibit 4-7.Market Communications—Outreach

Outreach has been a hallmark of the CCT Program

since its inception. It was recognized early on thatcommercialization of technology requires acceptanceby a range of interests including: technology users;equipment manufactures; suppliers and users of rawmaterials and products; financial institutions andinsurance underwriters; government policy makers,legislators, and regulators; and public interest groups.Requisite to acceptance is an outreach program toprovide these customers and stakeholders with bothprogram and project information and to seek, on acontinuing basis, feedback on program direction andinformation requirements. An ongoing outreachprogram has aggressively sought to disseminate keyinformation to the full range of customers and stakeThe Burns Harbor Plant was the site of the BFGCI demonstration. holders and to obtain feedback on changing needs. The effort has recognized the need to highlight envi- ronmental, operational, and economic performance characteristics of clean coal technologies and to rede- sign information packages as customers and stakehold- ers, and their respective needs, change with the market. Specific objectives of the outreach program include the following: • Achieving public and government awareness of advanced coal-using technologies as viable energy options; • Providing potential technology users, both foreign and domestic, with information that is timely and relevant to their decision making process; • Providing policy makers, legislators, and regulators with information about the advan- tages of clean coal technologies; • Convincing financial institutions and insurance underwriters that clean coal technologies are viable options; and
Exhibit 4-5

Commercial Successes—Coal Processing for Clean Fuels

Commercial Use

xpertTM Sold domestically and internationally. The Electric Power Research Institute (EPRI) owns the software and distributes it to

c. and CQ, Inc.) EPRI members for their use. CQ Inc. and Black and Veatch have signed commercialization agreements that give both companies

nonexclusive worldwide rights to sell user licenses and offer consulting services that include use of CQE®. More than 35 U.S.

utilities and one U.K. utility have received CQE® through EPRI membership. Two modules of the Acid Rain Advisor valued at

$6,000 have been sold. It is estimated that CQE® saves U.S. utilities about $26 million annually.

Project (ENCOAL Domestic and international sales pending. In order to determine the viability of potential LFC® plants, five detailed

commercial feasibility studies—two Indonesian, one Russian, and two U.S. projects—have been completed. Permitting of

a 15,000 metric-ton/day commercial plant in Wyoming is nearly complete.

of the Liquid No sales reported. Nominal 80,000 gallon/day methanol production being used by Eastman Chemical Company.

cess (Air Products

y, L.P.)

s Demonstration No sales reported. Total sales of SynCoal® product exceed 1.5 million tons. Six long-term agreements are in place to purchase

the product. One domestic and five international projects have been investigated. Western SynCoal LLC has a joint marketing

agreement with Ube Industries of Japan providing Ube non-exclusive marketing rights outside of the United States. Ube ispursuing several projects in Asia. Western SynCoal is also discussing a potential marketing and development agreement with aU.S. engineering firm.

Exhibit 4-6

Commercial Successes—Industrial Applications

Commercial Use

rubber (Passamaquoddy Tribe) No sales reported. The scrubber became a permanent part of the cement plant at the end of the demonstration. A

feasibility study has been completed for a Taiwanese cement plant.

on System Demonstration Domestic sale. British Steel’s Blast Furnace Granular-Coal Injection System was sold and installed on a facility

on) owned by United States Steel Corporation.

 Internal Sulfur, Nitrogen, No sales reported. While the combustor is not yet fully ready for sale with commercial guarantees, it is believed to

ration) have commercial potential. Follow-on work to the CCT Program demonstration was undertaken, which has brought

the technology close to commercial introduction.
Program Update 1999 4-13

ow-NO

x

 Cell Burner

ox Company)

nd Low-NOx Burners

ing the Use of Coals by

ection (Energy and

oration)

ation Demonstration

L.P.)

pplications of Technol

ss

nc.)

ject (The Ohio Power

fication Combined

Company)

n Repowering Project

on Repowering Project

ty ExpertTM (ABB

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 development of the low-NOx cell

burner.1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management Association to the U.S. Department ofEnergy, Gas Research Institute, and U.S. Environmental Protection Agency for the development and commercialization ofgas-reburning technology.1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service Company’s Bailly Generating

Station.1992 Outstanding Engineering Achievement Award presented by the National Society of Professional Engineers.1995 Design Award presented by the Society of Plastics Industries in recognition of the mist eliminator.1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. Co-recipient was the U.S.

Department of Energy.1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and Waste Management Association.1993 Environmental Award presented by the Georgia Chamber of Commerce.1992 National Energy Resource Organization award for demonstration of energy-efficient technology.1991 Powerplant Award presented by Power magazine to American Electric Power Company’s Tidd project. Co-recipient

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

1996 Association of Builders and Contractors Award presented to Tampa Electric for quality of construction.1993 Ecological Society of America Corporate Award presented to Tampa Electric for its innovative siting process.1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of Florida for the innovative sitingprocess.1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innovative siting process.1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc.1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 1996 American Consulting Engineers Council competition.In 1996 recognized by then Secretary of Energy Hazel O’Leary and EPRI President Richard Balzhiser as the best of nineDOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Program.

Award
portunities for feed

n and information

nd information access

ved upon as program

Information is current

mers and stakeholders,

rticipants. The fol

of the publications and

 currently in place:

monstration Program:

nual summary of

complishments, and

torical backdrop and

policy.

monstration Program:

mid-year update on each

nference Proceedings

pacting the program,

n requirements, and a

f the active projects is

 technical depth.

r offers the readership

highlighting key

eporting on related

cations and upcoming

ary documents provide

 projects, highlighting

economic performance.

ical Reports capture

highlight particular

technological advantages, project plans, and expectedoutcomes.

National Technical Information Service (NTIS)

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

CCT Program Bibliography of Publications,

Papers, and Presentations periodically updates the keymaterials available on the technologies demonstratedunder the CCT Program.

The Investment Pays Off periodically takes a

market-based view of the success of the CCT Programby 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 canbe accessed on the Internet (http://www.lanl.gov/projects/cctc/).

Exhibits provide a means through graphics, photos, broadcast videos, and interactive videos to convey

program 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.

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 publications

can be obtained and information sources can be accessed.

The CCT Compendium is a new source of information

on the CCT Program

Publications Issued in FY1999

The following publications were issued in fiscal

year 1999 by the CCT Program. Similar publicationscan be expected in fiscal year 2000.

• Seventh Clean Coal Technology Conference—

21st Century Coal Utilization: Prospects forEconomic Viability, Global Prosperity, and aCleaner Environment, Volume 1 Policy Paper,and Volume 2 Technical Papers

• Clean Coal Technology Demonstration

Program: Program Update 1998

• Clean Coal Technology Demonstration

Program: Project Fact Sheets 1999

• Clean Coal Today: Winter 1998, Spring 1999,

Summer 1999, Fall 1999

• Clean Coal Today Index• Project Performance Summary—10-MWe

Demonstration of Gas Suspension Absorption
Program Update 1999 4-15

ummary—180-MWe

nced Tangentially-Fired

s for the Reduction of

ummary—ABB Environ

TM Flue Gas Cleaning

ummary—Advanced

on Demonstration

ummary—Cement Kiln

ubberTM

ummary—Demonstra

for Cyclone Boiler NOx

ummary—Full-Scale

NOx Cell Burner®

• Project Performance Summary—Nucla ACFB

Demonstration Project

• Project Performance Summary—SOx-NOx-Rox

BoxTM Flue Gas Cleanup DemonstrationProject

• Project Performance Summary—Tidd PFBC

Demonstration Project

• Topical Report—Advanced Technologies for

the Control of Sulfur Dioxide Emissions fromCoal-Fired Boilers

• Topical Report—Commercial-Scale Demonstration of the Liquid Phase Methanol

(LPMEOHTM) Process

• Topical Report—Reburning Technologies for

the Control of Nitrogen Oxides from CoalFired Boilers

• Topical Report—Technologies for the Combined control of Sulfur Dioxide and Nitrogen

Oxides Emissions from Coal-Fired Boilers

Information Access

The Department of Energy continued to expand its

website to provide information on federal fossil 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 at Oak Ridge, Tennessee.The gateways link to more than a hundred energyrelated websites operated by private companies, tradeassociations, and other agencies worldwide.

Furthermore, the Fossil Energy International

Activities site on the World Wide Web has beenexpanded with the addition of new country pages inthe Western Hemisphere region (Dominican Republic,El Salvador, and Haiti). Many of the existing countrypages have also been upgraded, with new hyperlinks tobusiness- or energy-related information sources. Aninnovation at the Fossil Energy International Activitieswebsite is a series of newly created Country EnergyOverviews. Each overview, individualized for aparticular country, includes a status summary of thatcountry’s energy infrastructure, energy and environmental policies, and privatization efforts. Fifteencountry pages are now available. The Uniform Resource Locator (URL) for the Fossil Energy International main page is http://www.fe.doe.gov/international

Exhibit 4-8

btain Updated CCT Program Information

Description and Action

Subscription to quarterly newsletter—Send name and address to U.S.Department of Energy, FE-24, Washington, DC 20585.Primary gateway to extensive information on DOE’s Fossil EnergyProgram and to relevant Web links—On the Internet, accesshttp://www.fe.doe.gov and use menu and/or search options.On the Internet, access http://www.lanl.gov/projects/cctc/.

publications Send name and address to U.S. Department of Energy, FE-20,

Washington, DC 20585.

Service (NTIS) U.S. Department of Commerce, 5285 Port Royal Road,

Springfield, VA 22161.
rnational” hyperlink in

tp://www.fe.doe.gov).

lished a new informa

 Clean Coal Technolo

e Office of Fossil

echnology Laboratory

e maximum use of

T Program. The com

e ease of use, and

erent types of data and

 to the needs of both

mple, one can access

 Demonstration Pro

cal Reports published

rojects. The CCT

 Internet at

/.

nd Feedback

e used to disseminate

rs and stakeholders

n specific issues,

on requirements. The

e of the mechanisms.

ely held over the

f the CCT Program to

ons. Subsequently,

lding open houses for

monstration facilities,

groundbreaking and

program officials

als at their places of

Discussions seek to:

he dynamics of the

pting new power

generating technologies, determine how the programcould best support the process and achieve a positiveoutcome, and gain insights on the future direction ofthe power industry. Over 50 meetings have been heldsince 1992 with influential leaders in the utility, independent power, regulatory, and financial communities.

Stakeholder Meetings bring together key stakeholder organizations for the purpose of coordinating

programs, where appropriate, and discussing pertinentissues and implementation strategies to address theissues and outreach needs. Such stakeholder organizations include the Electric Power Research Institute(EPRI), Gas Research Institute (GRI), Coal UtilizationResearch Council, Center for Energy & EconomicDevelopment (CEED), Council of Industrial BoilerOwners (CIBO), Clean Coal Technology Coalition, andNational Mining Association (NMA).

Conferences and Workshops bring together targeted audiences to review and discuss topics of interest,

document discussions and findings, and provide recommendations, as appropriate. Trade Missions are asubset of these and differ only in that the thrust isinternational in character with the purpose of promoting the export of U.S. services and technology. Theoutreach program has participated in over 200 technicalconferences, workshops, and trade missionssince 1991.Seventh Clean Coal Technology Conference

On June 21–24, 1999, over 230 people from 12

countries gathered in Knoxville, Tennessee for theSeventh Clean Coal Technology Conference. Cosponsors included CEED, NMA, EPRI, CIBO, and DOE.Air Products and Chemicals, Inc. and the EastmanChemical Company hosted the conference and a site visitto the Commercial-Scale Demonstration of the Liquid

Phase Methanol Process being demonstrated at theEastman Chemical Company facility in Kingsport,Tennessee. The following is a summary of the papersand presentations at the conference. The views of thevarious speakers do not necessarily reflect the viewsof DOE.

Opening Remarks. The DOE Assistant Secretary

for Fossil Energy provided opening remarks, reflectingon how far coal technologies have come and on thepromise for the future. The Assistant Secretary notedthat progress in power system technology has farsurpassed projections made in the 1970s, when onlymagnetohydrodynamics was expected to approach 50percent efficiency. Now gasification, fluidized-bedcombustion, and advanced gas turbine technologiesprovide a clear path to the 50 percent efficiency threshold. Moreover, only 20 years ago environmentalcontrol was more art than science. Through the CCTProgram, advances in science-based gas cleanuptechnology have saved more than $40 billion in compliance costs.

In looking to the future, the Assistant Secretary

shared his vision of virtually pollution-free coal-basedpower systems, producing multiple products at 60percent generating efficiency and reaching 85 percentthermal efficiency. He reflected on the fact that thisvision approached that of the first Assistant Secretaryfor Fossil Energy over 20 years ago—“the day pollution would no longer be associated with the wordcoal.”

Keynote Speakers. Keynote speakers from both

the coal industry and the utility industry addressed theconference participants.

Coal Industry Perspective. The coal industry, as

represented by the President of NMA, perceives thechallenge for the power industry as maintaining low
Program Update 1999 4-17

n meeting the projected

w electric power capaci

e the growth of the last

ge, the coal industry

E’s CCT Program,

 Future. These pro

al and power producers

m. NMA views perfor

public policy unfavor

 provided the needed

y build-up between

watt-hours), this despite

d a nuclear power

on. As a result, the

rgy costs than other

merican households

can industry relies on

ested lessons to be

must be maintained to

es and that performance

Utility Perspective. The Chairman and President

of American Electric Power (AEP) suggested that thereare three givens regarding the future of coal in electricity generation: (1) powering the future will require adiversified fuel mix; (2) coal will continue in a prominent role in that mix; and (3) the advancement of cleancoal and related technologies will be more critical thanever in going forward. There also is a need to change

the public perception of coal, includingspeaking on the issues affecting coal,including: (1) air quality issues of urbanand regional smog, or ozone, associatedwith nitrogen oxide emissions; (2) fineparticulates, acid rain, mercury, andregional haze, primarily associated withsulfur dioxide emissions; and (3) theclimate change questions of greenhousegases, principally carbon dioxide, andglobal warming.

AEP sees the need to deflect environmental concerns with a technological

response to preserve coal as the primarysource for electric power generation, but

also recognizes the need to protect all other options aswell. This includes continuing development of renewable energy sources, expanding use of natural gas, andkeeping the nuclear option open. The AEP speakernoted that nuclear generation has ceased to be a sourcefor new capacity, with no new plants having beenordered since 1973 (that weren’t canceled).

Preserving the existing 100 nuclear plants is seen as

a challenge. Further observations were that manyhydroelectric plants may not be relicensed; despitesupport by utilities, renewables cannot begin to replacefossil fuels; and natural gas can not take the strain ofreplacing nuclear and coal generating capacity. Themessage conveyed was that fuel diversity is essential topreserving our nation’s security and economic stability,which could be compromised if the public’s negativeperception of coal leads to public policy limiting coal

use.

Issues. The issues identified at the conference

include: (1) Deploying Clean Coal Technologies; (2)Global Community Responsibility—Role of Technology and Project Developers, Financiers, Consumers, andGovernments; and (3) Coal in Tomorrow’s EnergyFleet—Pressures and Responsibilities.

Deploying Clean Coal Technologies. For both

developed and developing countries, coal is projectedto be a key component in the energy supplies. However, current coal technologies can not satisfy the energysecurity and environmental goals of society and deliveraffordable energy. On the other hand, power systemtechnologies emerging from the CCT Program offerthe economic, environmental, and operational performance potential needed to maintain coal in the fuelsupply, meet environmental goals, and keep energyaffordable. The challenge is in achieving widespreaddeployment of these clean coal technologies.

Seventh CCT Conference attendees toured the

LPMEOHTM demonstration project.

logy exhibits, shown here, was used at

onvey a technical message.
Advisors on Science

fied deficiencies in the

from the demonstration

. So despite success

T Program, work

s into the marketplace.

n” phase must ensue

st between the new

hnology is covered.

 and risk are reduced,

nd design and manu

d standardized.

entity is required to

support for the buy

nologies vis-a-vis the

d. Clean coal technolo

igher than convention

r than natural gas

al technology capital

 will be 20 to 25

al, but 50 percent

d-cycle. Integrated

 pressurized fluidizedbed combustion technologies are cost-competitive with pulverized coal now, but not natural gas combined- cycle. The IGCC and PFBC technologies could be competitive with natural gas combined-cycle in 2010, if fuel prices follow projected trends. The fuel price differential between coal and natural gas must be greater than $2.00/106 Btu for clean coal technologies to be competitive with natural gas combined-cycle. Barriers identified for coal technologies by devel- opers include capital cost, restructuring of the electric utility industry, and construction lead time. The capital risk of clean coal technologies is estimated at twice that of natural gas combined-cycle, which also means higher taxes, insurance, and financing costs. The electric utility industry favors less capital-intensive projects to maximize short term profits. Longer con- struction schedules for coal plants means slower response to market signals for new capacity and greater risk from more stringent environmental regulations. From an environmental perspective, clean coal technologies provide high levels of pollution control and efficiency, but still fall short of a natural gas combined-cycle plant. Carbon sequestration represents a leveling factor for clean coal technologies in carbon control, but much work remains to be done. Achieving widespread clean coal technology deployment and the benefits derived from having fuel diversity will require financial support for the developer. The preferred financial mechanisms identified were incentives, rather than grants or subsidies. Moreover, incentives must address higher capital costs, higher operating cost and risk, and start-up risk. These risks can be addressed by investment tax credits, production tax credits, and risk pools, respectively. A further stipulation was that such an incentives program would qualify technologies on the basis of increased efficiency over time and would be limited in scope and duration. Global Community Responsibility—Role of Tech- nology and Project Developers, Financiers, Consumers, and Governments. Speakers on this subject suggested that there is a global community responsibility to put energy resources and the advanced technology needed to use those resources in the hands of the two billion people in the world who currently lack access to these basic building blocks of modern society. Furthermore, by applying advanced technology, the global energy resources are more than sufficient to support economic growth without compromising the environment. Speakers observed that little progress has been made in addressing the one-third of the six billion world population lacking access to commercial forms of energy. Most of these people live in developing countries where 90 percent of the population growth is occurring, and will increase by another two billion people by 2020. This will contribute to an estimated 50 percent increase in global energy consumption over the next two decades. New partnerships and economic models are needed to address the problem, such as: • Restructuring and commercialization of energy enterprises; • Sharing information through energy partner- ships; • Establishing transparent regulatory, pricing, and procurement policies; • Investing in technology development reflecting a long-term, global view; and • Providing tools for developing countries to solve their own problems. Coal must play a role in meeting energy demands because coal is the predominant indigenous resource for many of the developing economies. But bringing in 

keholders the opportunity 

management.
Program Update 1999 4-19

s the hurdles of least

rs, the “NIMBY” (not in

nrealistic expectations

developing countries

h in energy requirement

d financial requirement

h developing countries

nfrastructure needs.

made by several speak

 share their prosperity

gy to rural impover

ot, poverty will contin

and possibly four

e projected world popu

s adopted a number of

orms of energy to the

y do not have access.

These policies include insisting upon reforms in theenergy sector to support competition, private sectorinvestment, and sound regulation of the sector. Policies also promote energy efficiency both on the supplyand demand-side and integrate energy pricing andenvironmental policies. The World Bank Group willundertake upstream “Energy-Environmental Reviews”to set priorities for action across the whole energychain. For coal, the World Bank launched the CleanCoal Initiative, which addresses the entire coal chainfrom mining to end-use, and in parallel, seeks sectorreforms and least-cost environmental control options.

The view from the commercial debt financing

market, as presented at the conference, does not lookpromising for new coal technologies. The debt financing market does not see its role as accepting the riskassociated with new technologies. Corporate entitiesor governments are expected to shoulder the risk untilsuch time as the technology reaches commercial maturity. Furthermore, computer models used by powerrate consultants include the choice of building a coalplant instead of a natural gas plant to supply futurecapacity needs. These computer models invariablychoose natural gas plants because of lower capital costand permitting ease. The operating assumption is,therefore, that new generation over the next 15 to 25years will be supplied overwhelmingly by simple-cycleor combined-cycle natural gas-fired plants.

Coal in Tomorrow’s Energy Fleet—Pressures and

Responsibilities. According to views expressed at theconference on this issue, the energy business is changing. In this new energy business environment, researchand development is not considered one of the factorsdriving corporate growth and value. The energy tradingand marketing function will drive actions in the energybusiness. Traders primarily think in financial and

commodity market terms. This includes conductingdaily assessments of “value at risk” and viewing generating assets as “real options.”

The growing use of options analysis for corporate

decision making, or real options, represents a decisionmaking revolution, according to Business Week. Research and development investments and technologiesare considered real options because investment todaycan generate the possibility of new opportunitiestomorrow. Also, technologies such as clean non-naturalgas fossil fuel systems are options that can hedgeagainst price risk and price volatility. For example, aplant that could produce syngas from coal (or otherlow-cost fuel) at an “out-of-the-money” price of $4.00/106 Btu, theoretically has value today as a hedge

against natural gas exposure. Indicative values mightbe $500–750/kW based on selling forward 15 yearsand the degree of price volatility. The question thenbecomes whether the syngas plant can be built for$500–750/kWe.

From a real options perspective, “high tech” may

not have as much option value as “low tech,” andintegrated systems may lose option value versus nonintegrated systems. “Enabling technologies” with thehighest market value are those that allow rapid installation, are not location sensitive, and are deployed in amodular fashion.

The Department of Energy presented its view of

tomorrow’s energy fleet, which is embodied in theagency’s Vision 21 Program. Vision 21 is a government/industry/academia cost-shared partnership todevelop the technology basis for integrated energyplants that will result in the deployment of ultra-cleanplants that produce electricity and “opportunity”products. Opportunity products could include cleanliquid transportation fuels, steam, high-value chemicals,

esses conference attendees

nce.
els include coal and

other resources such as

etroleum coke. Vision

e environmental

fuel use by reducing

 increasing efficiency

ons by up to 50 per

to achieve net zero

ted were 60 percent

5 percent (LHV) for

rcent efficiency

wer applications, and

ency in fuels produc

nabling technologies

 the foundation for the

m the building blocks

ling technologies

paration membranes,

s, fuel flexible gasifi

d combustion, fuel

dvanced catalysts.

sscut enabling technol

vanced computational

, advanced controls

ental controls, and

dularization.

es, such as a gasifica

cycle, were presented

s were feasible. The

ative pointed out that,

 there will be spinoff

he sequential commer

hnologies will mitigate

opment.

Industry representatives identified several targets

for coal-based generation technologies by 2020 alongwith several cross-cutting enabling technologies. Thetargets are capital costs of $800/kW, efficiencies of 50-60 percent, SO2 removal of 99 percent, NOx emissions

of 0.05 lb/106 Btu, and 100 percent waste utilization.The enabling technologies are high temperature/highpressure filters, advanced combustion turbines, hightemperature steam cycle materials, and hazardous airpollutant controls. With these capabilities, it is projected that coal can account for 20 percent of primaryenergy in a balanced 2050 portfolio.

Looking to the future, it was also pointed out that

carbon capture and sequestration offer an opportunityto remove the single greatest concern over continuedreliance on fossil fuels—global climate change. Toscope the challenge, results were presented fromdetailed cost analyses on CO2 capture followed by adiscussion of the challenges involved in developingsecure storage reservoirs.

In addressing CO2 capture costs, analysts selected

three representative power generation technologies:IGCC, natural gas combined-cycle, and pulverizedcoal-fired combustion. Analysis showed the incremental cost of electricity for CO2 capture to be 1.1 to 1.7cents/kWh for IGCC; 1.9 to 2.1 cents/kWh for naturalgas combined-cycle; and 2.3 to 3.1 cents/kWh forpulverized coal. This suggests that coal-based IGCCcould compete with natural gas in a greenhouse gasconstrained world.

The CO2 capture costs presented represent commercial technology today. The potential to reduce

these costs is great, e.g., improving thermal efficiencyof the basic plant, or reducing the energy requirementfor CO2 capture by improving separation technologies.The sequestration options identified along with capacity estimates are listed below. For reference, the total annual worldwide anthropogenic carbon emissions are about 7 gigatons of carbon (Gtc). Reservoir Capacity (Gtc/yr) Ocean 1,000s Deep Saline Formations 100s to 1,000s Oil & Gas Reservoirs 100s Unminable Coal Seams 10s to 100s Terrestrial Biosphere 10s to 100s Utilization 0.1 Geologic sequestration issues identified include uncertainties in storage volumes available, long-term integrity of the storage, and costs of CO2 transport and storage. Storage integrity is both a performance and public safety issue. Ocean sequestration issues include sequestration efficiency for the proposed methods and environmental impacts. Conferences and Workshops Held in FY1999 Third Meeting of Energy Ministers from the Asia Pacific Economic Cooperation, and Sixth Annual Technical Seminar. In October 1998, the Energy Ministers from the Asia Pacific Economic Cooperation (APEC) held their third meeting in Okina- wa, Japan to consider policy issues, many of which are important to vendors of clean coal technologies and other fossil energy technologies in foreign markets. The U.S. Secretary of Energy led the U.S. delegation. APEC was formed in 1989 to address issues of grow- ing regional interdependence. Members include 18 countries bordering the Pacific Ocean with a combined Gross Domestic Product of $13 trillion in 1995. Con- current with the Ministers’ meeting, the FE-led Experts Group on Clean Fossil Energy (part of the APEC’s Energy Working Group (EWG)) hosted its Sixth
Program Update 1999 4-21

h a focus on practical

ies for developing

nce to the Pacific Rim

pplies. In fact, an

February 1998 in

curity: Fuel Supplies for

d that coal would contin

he region’s fuel mix.

ble due to its environ

vailability, while oil use

as not expected to grow.

inancial crisis pervaded

Ministers agreed that

conomic recovery.

key goal, could induce a

e economic downturn

 demand, the region’s

to outpace energy

The Asia Pacific Energy

y the EWG, presented

ast that predicts total

region will increase 41

010. This growth will

ment capital. To reduce

PEC nations are inter

pplies, developing

ure, and encouraging

Okinawa endorsed a work

und infrastructure for all

ot only for environmen

nance practices and

 the work program is to

cation of predictable,

rgy policy practices.

Policy recommendations to accelerate investment

in natural gas infrastructure (part of the Natural GasInitiative launched at the first meeting of the Ministersin Edmonton, Canada) were also approved. Recommendations were included in the report, “AcceleratingInvestment in Natural Gas Supplies, Infrastructure andTrading Networks in the APEC Region.” The Initiative stresses not only the building of pipelines, butaddressing regulatory and cross-border issues that mayact as impediments.

Reducing costs through cooperation in energy

standards was another endorsement by the Ministersthat has potential bearing on coal and the standards forequipment to be sold. APEC members’ economieshave been surveyed to determine the range of testingpractices and procedures and the degree of mutualrecognition of facility test results. The standardsnotification provision endorsed by the Ministers wouldincrease transparency and consistency in energy efficient product standards within APEC. To improveenergy efficiency, Ministers also endorsed a voluntary“pledge and review” system. Energy efficiency meansnot only “green” technologies, but better use of conventional fossil fuel resources.

Although APEC is an organization of government

representatives, the Energy Ministers have directed theEWG to expeditiously engage with businesses onmeasures to improve investor confidence in APECnations’ energy sectors. The EWG has established aBusiness Network comprising two private sectorenergy executives from each member economy. TheMinisters instructed the EWG to work with industry toimplement the principles in the “APEC Manual of BestPractice Principles for IPPs,” which was endorsed atEdmonton.

Trends in Development in Mining and Power

Production From the Point of View of FutureApplications of Clean Coal Technologies. In November 1998, two FE representatives were invited tochair panels and present papers at the conferenceTrends in Development in Mining and Power Production From the Point of View of Future Applications ofClean Coal Technologies, held in Kocise, Slovakia.The conference was hosted by the Slovak Academy ofSciences Institute of Geotechnics (Slovak Academy),with broad sponsorship by the mining and powerindustry in Slovakia. The Office of Fossil Energy,under a Science and Technology grant from the U.S.Department of State, has collaborated with the SlovakAcademy on research focusing on the region’s highash, high-arsenic coals, specifically the process ofcleaning the coal using the concept of triboelectrostaticcharging. This process avoids expensive dewatering.Slovakian brown coal is currently used for powergeneration in pulverized coal plants with few environmental controls, and is also used extensively for districtheating and rural home stoves. Coal supplies aredwindling and expected to last for only another 20 years.

The conference, attended by some 75 key representatives from the academic, mining, power, district

heating, chemical, steel, and environmental sectors inCentral and Eastern Europe, addressed various technical issues common to this area, particularly cost issuesof environmental compliance and power production.Currently, 60 percent of Slovakia’s power comes fromolder nuclear plants, 30 percent from coal plants, and10 percent from natural gas. Slovakia is under pressureto shut down the Chernobyl-type nuclear plants andmust find replacement capacity, or it will have toimport electricity. There is hesitancy to become overlydependent on natural gas, and strong interest (including
r) in continuing to use

hey last. In general,

e between nuclear-,

er plants.

a are slowly being

d-bed combustion

 for cleaner coal

 small combined heat

cal raw materials.

ost interested in the

articularly the Nucla

ed combustion

id Phase Methanol,

demonstrated by the

e these technologies

ut all of Central and

 and other countries in

ching coal R&D

 to deploy new tech

ves.

Combustion Technol

ation. In December

articipated in the

ustion Technologies

ld in Mexico City.

-Mexican Bilateral

on, under the Hemi

Energy Working

ors included the

 Savings (CONAE)

arch.

minar was FE’s presen

ombustion Repowering

d to more than 100

ntly, 60–70 percent of

m fossil fuels, 80–90

percent of which comes from oil, with therest generated from natural gas and twopulverized-coal plants that burn high-ash(approximately 50 percent ash) Mexicancoal. A new coal plant being built willrun on imported, low-sulfur coal. Approximately 17 percent of Mexico’spower is generated by hydroelectricplants and the remaining national demandis met by two 650-MW nuclear units,supplemented by some geothermal, wind,and solar units.

The presentation focused on four

fluidized-bed combustion (FBC) repowering optionsfor Mexico’s aging oil-fired power boilers. Theseoptions included (1) replacement of existing units withatmospheric fluidized-bed boilers, (2) conversion ofexisting units into fluidized-bed boilers using compactseparator designs, and replacement of existing boilerswith either (3) first generation PFBC or (4) secondgeneration (topped) PFBC units. The fuel flexibility ofFBC was stressed. Particular attention was devoted topetroleum coke in recognition of Mexico’s globalposition as a major oil producing nation. The audienceasked a number of questions concerning burning ofpetroleum coke in the United States. Examples such asthe NIBSCO 300-MW petroleum coke-fired plant inLake Charles, Louisiana were discussed. The NIBSCOplant is completing its sixth year of successful operation, which includes the sale of all produced ash byproduct for use in highway construction.

The Office of Fossil Energy’s final technical

presentation was on the Vision 21 program. Audiencequestions focused on the continuing use of fossil fuels,especially coal, into the next millennium. The Mexicanaudience was surprised to see that such focused and

careful attention is still being given to fossil-basedpower technologies. The FE presenter indicated that,with the exception of nuclear, which is politically notan option in many countries, fossil is the only viableenergy source to meet the bulk of the world’s demandfor power. The presenter stressed the need to developand deploy technologies that will allow use of fossilfuels as cleanly and efficiently as possible.

On December 4, 1998, a follow-up meeting was

held at the offices of Mexico’s Secretariat of Energy,which generated further questions about FBC operations. CONAE indicated that it would take the lead topromote future FBC activities between FE and Mexico.

13th Annual U.S./Japan Joint Technical Workshop on Coal Technology. A successful 13th Annual

U.S./Japan Joint Technical Workshop on Coal Technology was held in early March 1999 at the Rocky GapLodge near Cumberland, Maryland. Sixty-six workshop participants exchanged R&D project informationrelating to advanced clean coal technologies, coalliquefaction, liquefaction materials, and surface gasification. Japan has recently been pursuing coal utilization R&D quite aggressively, and has been involved indirect liquefaction research.

Representatives from the U.S. DOE participated in the “International

Seminar on Combustion Technologies for Clean Energy Generation,” heldin Mexico City in December 1998.
Program Update 1999 4-23

al Energy Technology

o Co-Chair of the U.S.-

 on Coal Energy R&D,

deregulation forces

, and summarized FE’s

L Director led a U.S.

tives, members of

 private sector. The

Ministry of International

d Co-Chair of the

gation of 24 scientists

earch organizations,

gy companies.

as open and frank. A

cy of Natural Resources

 coal utilization policy,

rcent of its total energy

ts oil (with oil account

tal energy consump

st foreign consumer of

coal used in Japan is

 nations (e.g., Germany,

95 percent of their oil.

or 20 percent of its total

oil, with oil comprising

consumption.

ed that ample, low cost,

 support a measure of

afety for both industrial

making the develop

ilization technologies an

E presentations intro

rogram the Department

wer and fuel systems in

nternational, Inc. sum

ell as emissions control

nd trace elements. The

Energy & Environmental Research Center described anadvanced hybrid particulate collector, AmericanElectric Power gave a presentation on the 600-MWedemonstration of selective non-catalytic reduction to beconducted at its Cardinal Unit 1, and Air Products &Chemicals presented an overview of advanced integration concepts for oxygen plants and gas turbines ingasification/IGCC facilities using ion transport membranes.

Japan’s New Energy Development Organization

described the EAGLE (Energy Application for Gas,Liquids, and Electricity) integrated coal gasification,molten carbonate fuel cell combined-cycle plant that ismoving toward pilot-scale demonstration in the 2000 to2002 time frame. About 90 percent of the project isfunded by the Japanese government. Japan’s ElectricPower Development Company presented recent resultsfrom the 71-MWe Wakamatsu PFBC plant, as well asfrom recent PDU testing of an advanced PFBC process. Representatives from Tokyo Electric discussedresults obtained from a 200 ton/day IGCC pilot plant atNakoso, using a process design by Mitsubishi HeavyIndustries.

Following the workshop, representatives from the

Japanese delegation toured NETL in-house laboratoryfacilities and the Tampa Electric IGCC project.

Prospects for Cleaner Fossil Fuels Systems in

Sustainable Development: Communicating TheirStrategic Value in the Euro-Asian Region. The U.S.Department of Energy was among the sponsors of thehighly successful conference, Prospects for CleanerFossil Fuels Systems in Sustainable Development:Communicating Their Strategic Value in the EuroAsian Region, held in Ankara, Turkey in May 1999.

Other conference sponsors included the World EnergyCouncil (WEC), as well as the WEC Turkish NationalCommittee and the Regional Working Group forCooperation in the Field of Energy, the U.S. Agencyfor International Development (USAID), and the U.S.Energy Association.

The highlight of the conference was an appearance

by the President of Turkey. In his remarks, the TurkishPresident emphasized the role of Turkey as a majorenergy distribution point as well as energy consumer.Turkey’s average energy demand is predicted to grow8–10 percent per year through 2010. A $280 billioninvestment program is planned for the energy sectorover the next 30 years. While the most timely energyissue is planned commencement of the Baku-Ceyhanoil pipeline and the Trans-Caspian natural gas pipeline,Turkish energy officials highlighted the importance ofcoal. Turkey has 8 billion tons of lignite (brown coal)reserves as well as some “hard” coal. Sixty percent ofcoal produced is used for generating electricity, withthe remainder going for industry and household use.By 2020, lignite and hard coal are expected to represent 20 percent of installed capacity.

DOE’s Office of Fossil Energy showed a strong

presence at the conference, with the FE Assistant

NETL Director addresses attendees at 13th Annual U.S./

Japan Joint Technical Workshop on Coal Technology.
The Director of FE’s Office of Import and Export

(middle) and the FE Assistant Secretary (right) address WECconference attendees.

r, the Director of the

in the Office of Coal

erving as President of

irector of the Office of

 making a presentation

Vision 21. The Assis

gy as a link between a

e and a cleaner envi

fits of carbon

nts was discussed as

rivate power partner

 Electric indicated that

 as well as other fuels,

icted a growth in

Coal provides over 50

in Germany, and 97

d India, the figure is

nference participants

orld Energy Council

ng as a main condition

ment. Such a restruc

he barriers of poor

FE delegation and

t with representatives

o asked for U.S. techni

ocess. As a result of

ergy Science and

lize the effort. At the

xpressed interest in

possibility of informa

Trade Mission Activities in FY1999

China. In April 1999, the U.S.-China Energy and

Environmental Technology Center (EETC) held itsfirst annual Board of Directors meeting. At the meeting, held in Washington, D.C., the Board of Directorsreviewed accomplishments over the past year, as wellas new directions. EETC is funded jointly by DOE,U.S. Environmental Protection Agency and the ChineseState Science and Technology Commission. The U.S./China Institute has a cooperative agreement with U.S.DOE to manage and operate the EETC. Tulane andTsinghua Universities, in turn, are subcontracted to runthe day-to-day operations. EETC’s mission is toenhance the competitiveness and adoption of U.S.clean and environmentally superior technologies inChina by focusing on education and training, promoting the use and profitability of U.S. technology, and

supporting policy development in China to encouragethe responsible use of coal.

Over the past year, the Hydrocarbon Technologies,

Inc. (HTI) direct liquefaction project, proposed to belocated near Shaanxi Province, has advanced from prefeasibility to the feasibility study phase. EETC has actedto promote the project to the Chinese Government.Other liquefaction projects, sponsored by German andJapanese companies with financial support from theirrespective governments, are also contending for theultimate award. A commercial plant using HTI technology could produce 50,000 barrels/day of gasoline anddiesel fuel using 10,000-12,000 tons/day of bituminouscoal. The pre-feasibility study established that theproject can use a variety of Chinese coals. The feasibility study will include further testing as well as evaluationof economics and project financing. DOE has supportedtest runs on Chinese coals at a bench test unit.

The Chinese government appears ready to make a

decision on another project, a 300-MW commercialIGCC project to be located in Yantai in the ShandongProvince. Foreign investment is being sought. Construction is expected to start in 2000-2001. Since1993, DOE and U.S. industry have been workingclosely with the Chinese government, industry, andR&D organizations to help China develop this firstIGCC project.

EETC is also supporting the efforts of The Babcock & Wilcox Company (B&W) to secure an FGD

joint venture from China’s State Power Corporation, agovernment agency that has decided to increase theengineering and fabrication capacity of FGD systemsthroughout China. B&W was a co-sponsor with theEETC of the February 1998 U.S.-China Workshop onSOx Control Technology.
Program Update 1999 4-25

een sponsoring studies

er plants to become

as helped the city of

 plant to natural gas, but

es are not available.

 activities in climate

blishing a special task

oal gasification, coal

or distributed power,

l Energy, with funding

ction with Tennessee

PRI, is preparing to

ment testing aimed at

 210-MW Unit No. 7 of

ty Board’s coal-fired

g with USAID support,

r (ESP) specialist to

ness of “sodium condi

given the high ash

 at Indian coal-fired

ple test setup, approxi

of sodium was added to

 four 67-MW units at a

he results were out

ticulate loading of 340

meter (a very dirty

ced to 60 milligrams per

an essentially clean

dium material used is

 the primary cost was

e cost of electricity was

er kilowatt-hour.

ny Central European

past several decades

with heavy use of solid fuels for heating. Since 1990,the U.S. Department of Energy has been involved in aprogram aimed at reducing air pollution caused bysmall coal-fired sources in Krakow, Poland. Althoughthe activity is focused on the city of Krakow, it isexpected that the results will be applicable to the entireregion. Formal basis for the U.S. assistance to Polandin this area was provided by the Support for EasternEuropean Democracy Act of 1989 (SEED). Part of thislegislation directed that DOE cooperate with U.S. andPolish experts to undertake an assessment and implementation program in Poland to use fossil fuels cleanlyin small-scale combustion equipment. Funding for thisprogram has been provided to DOE by the USAID.

The SEED program was specifically directed

toward the problems of low altitude emissions sourcesin Krakow. A city of 750,000 and Poland’s capitalfrom the 11th to 17th centuries, Krakow is a major

university and industrial center, and contains numeroushistoric buildings. The city has been included in theUnited Nations Educational, Scientific and CulturalOrganization (UNESCO) list of world cultural heritages. The program was designed to assess the totalproblem of low-level emission sources within thecenter of “Old Krakow” and progress to the outskirts;

identify specific large emission sources; determinecost-effective approaches for long-term remediation;and use a multi-faceted technical approach to implement new technologies. Air quality has improveddramatically since the program began. A number ofmajor emitters have already had numerous thermal/burner/particulate control systems installed. Theprogram is currently in its last phase, in which manyparticulate sources are being closed due to connectionto an expanded district heating system, home stovesare having electric heating elements installed, andelectrical upgrading is being implemented. UnitedStates funding provides new equipment, preferablythrough joint US-Polish suppliers, to a variety of city,regional, and private energy offices and partners. Asignificant upgrade to the large Polish AmericanChildren’s Hospital is also underway—the only dedicated pediatric medical research facility in Poland.

A number of projects have evolved from the

Krakow effort and have been implemented in otherparts of Poland and Central Europe. Due to lowerinitial capital costs and operating costs, mechanicalparticulate collectors traditionally have been installedin industrial applications in Poland rather than morecomplex devices. One such device is the core separator developed by LSR Technologies, of Acton, Massachusetts. Original development work on the coreseparator was done under the DOE Small BusinessInnovative Research Program. Dust emissions fromthis device are typically 3–6 times lower than from thebest cyclone collectors, and its performance approaches that of fabric filters and electrostatic precipitators,but at a much lower cost. Within Krakow, core separators were installed at a 6-MW stoker fired boiler in amotor manufacturing plant and at a 1.5-MW boilerlocated at the central bus service center. Particulate

 The Bilaspur Coal Washery Project in the state of

Madhya Pradesh is India’s first private commercial coalwashery for electric power generation.
4 percent. Another 52

ation or being in

oring countries.

ontinues to show

ty due to the many

being controlled or

e are removing more

r of particulates in the

mated that more than

sions per year have

ng remediation

ons/year will be

Children’s Hospital

proximately 15,000

ure of a large coal

r. Clearly, the joint

sitive environmental

a delegation from

nd Office of Interna

ussia for technology

an organizations

logy, and power

 were directed toward

l technologies as a

tection, including (1)

 to improve combus

plants and advanced

mbined-cycle technolo

nding of the present

il fuels for electric

ussia and in the U.S.

d included: the Fossil

r Fuel and Energy of

 Engineering Institute;

r, Ministry of Fuel and

Energy of Russia; the Moscow Center for EnergyEfficiency; and the Committee of Coal Industry of theRussian Federation. As a result of the visit, a numberof areas for cooperation were identified that could beof potential mutual benefit. It was agreed that DOEwould initiate preparation of a draft Annex under theexisting bilateral Science and Technology Agreement,specific to the development and utilization of clean andefficient fossil fuels. The Annex will identify andinstitutionalize cooperation between the DOE andRussian counterpart governmental organizations.

Taiwan. Agreements are being prepared with

Taiwan allowing FE to provide technical expertise,training, and scientific exchange activities in the areasof clean coal technology, coal utilization, and wasteand by-product utilization. A major expected outcomeincludes FE technical support for an IGCC feasibilitystudy. FE would advise Taiwan on project financing (amix of Taiwan government and private funding), plantsiting, and technology selection. The agreement wouldfirst be signed between FE and the Taipei Economicand Cultural Representative Office (TECRO), and thenbetween the Energy Commission of the Ministry ofEconomic Affairs and the American Institute in Taiwan. After the agreements are finalized, both Taiwanand the United States hope to branch out into othercooperative work—fuel cell development, independentpower production, rural electrification, computermodeling for energy policy decisions, environmentalmanagement, cement and steel factory cleanup, andpaper mill waste treatment. Tulane University’s U.S./China Institute has been active in coordinating andsupporting FE efforts on these agreements.

FE began working a year and-a-half ago with Taiwan

to promote adoption of clean coal technologies. Taiwanimports about 96 percent of its primary energy—mostly

oil, coal, and liquefied natural gas. The country seeks todevelop a long-term energy policy and emissions controlstrategy, preferably regional in scope.

Ukraine. U.S. and Ukrainian participants met in

April 1999 in Research Triangle Park, North Carolinato discuss progress to date on an EPA and DOE sponsored fuel reburning project in Ladyzhin, Ukraine. Amulti-fuel reburn system (capable of using natural gas,coal, heavy fuel oil, or combinations thereof) is beinginstalled to reduce NO

x emissions from Unit 6, a 300-

MW wet-bottom coal-fired boiler at Ladyzhin PowerStation, 200 miles south of Kiev. Under an interagencyagreement, funding is provided by EPA’s Environmental Technology Initiative. Technical guidance forprocess design and operation are provided jointly byEPA’s National Risk Management Research Laboratoryand FE.

The project follows an earlier collaborative effort

in 1992 (in which DOE did not participate) where anatural gas reburning system was installed at LadyzhinPower Station Unit 4. This operation reduced NOxemissions by more than 50 percent. The success of thisearly demonstration encouraged the Ladyzhin PowerStation and the Ukrainian Power Ministry to extend theapplication of this technology to other units. Theseunits were needed to help meet pending regulations thatwill place a tax on all emissions. Fuel cost, availability, and distribution problems in Ladyzhin made amulti-fuel approach desirable.

In the reburn method, 5–20 percent of total boiler

fuel is injected downstream of the main burners tocreate a fuel-rich zone, followed by injection of burnout air, and can remove 50 percent or more of uncontrolled NO

x emissions. The technology is very promising for Ukraine and Russia, where 50 percent of all

boilers are of a slagging or wet-bottom design, for
Program Update 1999 4-27

urners are not generally

 Research Corporation

ng system design.

 and installation are

 Station staff. To date,

coal mills for supplying

ed preliminary tests of

en oxides reductions of

ved compared to opera

ing fuel, i.e., using only

t of the reburning

 coal as the reburning

s into total NOx reduc

 system optimization is

 the reburn coal feed

y.

Project Fact Sheets 5-1

ons provide a portfolio

 coal to continue to

y vital to the nation’s

y and environmental

This is being carried

arket sectors: (1)

for existing and new

ctric power generation

s and providing new

ocessing for clean fuels

l resources to clean

tions dependent upon

rust of the CCT

 completed for 18 of 19

NOx control for coal

hnologies provide a

ptions for the full range

mental control device

n $702 million. These

ntrol systems installed

lity generating capacity,

alled on approximately

d SO2/NOx emission

nned on more than 665

 as well as growing

ogram provides a range

eration options for both

repowering and new power generation. These advanced options offer greater than 20 percent reductionsin greenhouse gas emissions; SO2, NOx, and particulate

emissions far below New Source Performance Standards (NSPS); and salable solid and liquid by-productsin lieu of solid wastes. Over 1,800 MWe of capacityare represented by 11 projects valued at more than $2.8billion. These projects include five fluidized-bedcombustion (FBC) systems, four integrated gasificationcombined-cycle (IGCC) systems, and two advancedcombustion/heat engine systems. These projects willprovide the demonstrated technology base necessary tomeet new capacity requirements in the 21st century.

Also addressed are approaches to converting raw,

run-of-mine coals to high-energy-density, low-sulfurproducts. These products have application domestically for compliance with the Clean Air Act Amendmentsof 1990 (CAAA). Internationally, both the productsand processes have excellent market potential. Valuedat more than $519 million, the five projects in the coalprocessing for clean fuels category represent a diversified portfolio of technologies. Three projects involvethe production of high-energy-density solid fuels, oneof which also produces a liquid product equivalent toNo. 6 fuel oil. A fourth project is demonstrating a newmethanol production process. A fifth effort complements the process demonstrations by providing anexpert computer software system that enables a utilityto assess the environmental, operational, and costimpact of utilizing coals not previously burned at afacility, including upgraded coals and coal blends.

Projects also were undertaken to address pollution

problems associated with coal use in the industrialsector. These included dependence of the steelindustry on coke and the inherent pollutant emissionsin coke making; reliance of the cement industry onlow-cost indigenous, and often high-sulfur, coal fuels;and the need for many industrial boiler operators toconsider switching to coal fuels to reduce operatingcosts. The five industrial applications projects have acombined value of nearly $1.3 billion. Projectsencompass substitution of coal for 40 percent of cokein iron making, integration of a direct iron makingprocess with the production of electricity, reduction ofcement kiln emissions and solid waste generation, anddemonstrations of an industrial-scale slagging combustor and a pulse combustor system.

The remainder of this section contains a discussion

of the technologies being demonstrated and fact sheetsfor each project.

Projects

The CCT projects are spread across the nation in 18

states, indicated in white.
ew

l Devices

es are those technolo

es or installed on new

olling SO2 and NOx

 be modified and

oiler configuration and

h these technologies.

Sulfur dioxide is an

bustion, which

lfur (Fe2S), and

oal. Identified as a

in, SO2 was targeted in

f Title IV, effective in

ts nationwide. The

erate and largely met

In year 2000, Phase II

pacting all fossil-fuel

proximately 700 pre

r the stricter Phase II

l switching alone is

ilities flexibility in

owance trading. This

s to be applied by a

hasing. Recognizing

ht to provide a portfo

es embody those

ct upon the flue gas

he combustion itself,

 SO2. Three basic

arily by different

re-NSPS boiler

population impacted by the CAAA. There is a tremendous range in critical factors, e.g., size, type, age, andspace availability.

On one end of the spectrum are the smaller, older

boilers 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 in 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 to 70 percent.

In the mid-range of the spectrum are 100- to 300-

MWe boilers less than 30 years old and somewhat spaceconstrained. For many of these, an increase in higherequipment cost is justified by enhanced performance.The approach involves introduction of a reactor vessel inthe flue gas stream to create conditions to enhance SO2capture beyond that achievable with the simpler sorbentinjection systems. Lime, as opposed to limestone, is usedand sulfur capture efficiencies up to 90 percent can beachieved at Ca/S molar ratios of 1.3 to 2.0. Thiscategory of control device is called a spray dryer(because the solid by-product from the reaction is dry).

At the other end of the spectrum are the larger

(300-MWe and more) boilers with some latitude inspace availability, as well as new capacity additions.For these boilers, advanced flue gas desulfurization(AFGD) wet scrubbers, with higher capital cost buthigher sulfur capture efficiency than other approaches,become cost effective. These systems apply larger andsomewhat more complex reactors that drive up thecapital cost. However, the sorbent is limestone, andSO2 removal efficiencies greater than 90 percent are

achieved at a Ca/S molar ratio of about 1.0, makingoperating costs significantly lower than those of theother two approaches. Furthermore, although the initialAFGD solid by-product is in slurry form, it is dewatered to produce gypsum—a salable product.

Under the CCT Program, two sorbent injection

systems, one spray dryer, and two AFGD processes,were successfully demonstrated. All have completedtesting. Exhibit 5-1 briefly summarizes the characteristics and performance of the technologies that aredescribed in more detail in the project fact sheets.

NOx Control Technology. Nitrogen oxides (NOx

)

are formed from oxidation of nitrogen contained within

Unique CT-121 SO2 scrubber at Plant Yates combined a

number of functions and eliminated process steps.
Project Fact Sheets 5-3

Exhibit 5-1

CCT Program SO2 Control Technology Characteristics

Coal Sulfur SO2 Fact

Process Content Reduction Sheet

 Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.5–2.5% 50% 5-24

furization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% 70% 5-28

humidification vessel and sorbent recycle

s Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7–3.5% 60–90% 5-20

particulate recycle (lime sorbent)

ation AFGD—cocurrent flow, integrated quench absorber tower, and reaction 2.25–4.7% 94% 5-32

tank with combined agitation/oxidation (gypsum by-product)

Applications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2–3% 90+% 5-36

FGD Process Reactor®) for combined SO2 and particulate capture (gypsum by-product)

irPol gas suspension absorption demonstration unit. Shown is the water inlet connections to the Pure Air absorber module.
 and oxidation of the

atures of combustion

 fuel-bound NOx

 oxygen at the early

 thermal NOx

,it is

ures.

fied both as a precur

itle IV of the CAAA)

mation (targeted under

ctive in 1995, required

coal units to reduce

6 Btu, respectively. In

ome into effect,

but most of all, the

ed units (see Exhibit

mpted the EPA to issue

a NO

x transport State Implementation Plan (SIP) call

for 22 states and the District of Columbia to cut NOxemissions 85 percent below 1990 rates or achieve a0.15 lb/106 Btu emission rate by May 2003.

 The CCT Program has sought to provide a

number of NOx control options to cover the range of

boiler types and emission reduction requirements.Control of NOx emissions can be accomplished byeither modifying the combustion process or actingupon the products of combustion (or combinationsthereof). Combustion modification technologiesinclude low-NOx burners (LNBs), advanced overfire

air (AOFA), and reburning processes using eithernatural gas or coal. Post-combustion processes used toact upon flue gas include selective catalytic reduction(SCR) and selective noncatalytic reduction (SNCR).

LNBs regulate the initial fuel-air

mixture, velocities, and turbulence tocreate a fuel-rich flame core andcontrol the rate at which additional airrequired to complete combustion ismixed. This staging of combustionavoids a highly oxidized environmentand hot spots conducive to fuel-boundNOx and thermal NOx formation. LNBsalone typically can achieve 40 to 50percent NOx reduction.

AOFA involves injection of air

above the primary combustion zone toallow the primary combustion to occurwithout the amount of oxygen neededfor complete combustion. This oxygendeficiency mitigates fuel-bound NOxformation. AOFA injected at highvelocity creates turbulent mixing tocomplete the combustion in a gradual

fashion at lower temperatures to mitigate thermal NOx

formation. Usually, AOFA is used in combination withLNBs; but alone, AOFA can achieve 10 to 25 percentNOx emission reductions. The LNB/AOFA systems

generally can achieve NOx emission reductions of 37 to

68 percent, depending upon boiler type.

Advanced control systems using artificial intelligence are also becoming an integral part of NOx control

systems. These systems can handle the numerousparameters and optimize performance to reduce NOxwhile enhancing boiler performance.

In reburning, a percentage of the fuel input to the

boiler is diverted to injection ports above the primarycombustion zone. Either gas or coal is typically used asthe reburning fuel to provide 10 to 30 percent of the heatinput to the boiler. The reburning fuel is injected to createa fuel-rich zone deficient in oxygen (a reducing ratherthan oxidizing zone). NOx entering this zone is stripped

of oxygen, resulting in elemental nitrogen. Combustion iscompleted in a burnout zone where air is injected by anAOFA system. Reburning has application to all boilertypes, including cyclone boilers, and can achieve NOx

emission reductions of 50 to 67 percent.

hibit 5-2

2 Boiler Statistics

Ox Emission Limits

 Number Phase II of NOx Emission Limits

 Boilers (lb/106 Btu)

299 0.40

308 0.46

36 0.68

55 0.86

e 26 0.84

28 0.80

gency, Nitrogen Oxides Emission Reduction

oup 1 and Group 2 Boilers

oxfs3.html).

Shown are The Babcock & Wilcox Company DRBXCL® burners installed on a down-fired boiler.
Project Fact Sheets 5-5

Exhibit 5-3

CCT Program NOx Control Technology Characteristics

Boiler Size/ NO

x

Fact

Process Type Reduction Sheet

ng for Cyclone Coal reburning—30% heat input 100-MWe/cyclone 52–62% 5-46

d Low-NOx Burners LNB/gas reburning/AOFA—13–18% gas heat input 172-MWe/wall 37–65% 5-54

monstration Coal reburning—14% heat input (tangentially-fired) and 148-MWe/tangential 28% 5-58

17% heat input (cyclone) 50-MWe/cyclone 59%

w-NO

x Cell Burner LNB—separation of coal and air ports on plug-in unit 605-MWe/cell burner 48–58% 5-50

mbustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500-MWe/wall 68% 5-42

and artificial intelligence controls

vanced Tangentially- LNB/AOFA—advanced LNB with close-coupled 180-MWe/tangential 37–45% 5-66

or the Reduction of NOx and separated overfire air

ers

alytic Reduction SCR—eight catalysts with different shapes and 8.7-MWe/various 80% 5-62

Ox Emissions chemical compositions

oilers

d alone or in combina

ion. These processes

ing reaction with NOx

water. SNCR can only

,600 to 2,200 oF) where

 typically applied at

00 oF. Generally, SNCR

ieve NOx emission

and 80 to 90+ percent,

even NOx control

ompassing LNBs,

, and combinations

thereof. Six of the seven of the projects have completed operations. One project has been extended.

Exhibit 5-3 briefly summarizes the characteristics

and performance of the technologies that are describedin more detail in the project fact sheets.

Combined SO2/NOx Control Technology.

Combined SO2/NOx control systems encompass thosetechnologies 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 to

improve overall system performance, such as LNBswith SNCR, unique space-saving and durable wetscrubber design, sorbent additive, and artificialintelligence controls. The balance of the sevenprojects use synergistic methods not previouslydescribed.

SO

x

-NO

x-Rox BoxTM incorporates an SCR catalyst

in a high-temperature filter bag for NOx control and

applies sorbent injection for SO2 control. The hightemperature filter bag, operated in a standard pulsed-jet

baghouse, protects the SCR catalyst, allows operationat optimal NOx control temperatures, forms a sorbent

cake on the surface to enhance SO2 capture, and

provides high-efficiency particulate capture.
d by catalytic oxida

ation of the SO3 in the

furic acid. Following

ion allows the SCR to

entration without

a passing to the second

er vapor, nitrogen, and

more, most particulates

ghouse are captured in

 The system produces

nerable adsorber

nated with sodium

nd NOx. The adsorber

eve effective mixing

Exhibit 5-4

CT Program Combined SO2/NOx Control Technology Characteristics

Coal Sulfur SO2/NOx Fact

Process Content Reduction Sheet

tension and LNB/sorbent injection—furnace and duct injection, calcium-based 1.6–3.8% 60–70%/40–50% 5-86

sorbents

ns LNB/SNCR/sorbent injection—calcium- and sodium-based 0.4% 70%/62–80% 5-94

sorbents used in duct injection

Gas Reburning Gas reburning/sorbent injection—calcium-based sorbents used in 3.0% 50–60%/67% 5-82

duct injection

 Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5–4.0% 98%/53–58% 5-90

durable scrubber design

leanup SCR/high temperature baghouse/sorbent injection—SCR in high- 3.4% 80–90%/90% 5-78

temperature filter bag and calcium-based sorbent injection

monstration SCR/oxidation catalyst/sulfuric acid condenser—synergistic 3.4% 95%/94% 5-74

catalyst effect and no solid waste

e NOXSO Regenerable adsorbent—spherical alumina beads impregnated 3.4% (planned) 98% (goal)/75% (goal) 5-72

nup System with sodium carbonate in fluidized-bed adsorber

with the flue gas. The adsorber is then processedthrough a regenerator system to release the NOx andSO2 before return to the fluidized bed. The flue gas

passes through a baghouse to remove particulates.

Six of the seven combined SO2/NOx control

technology projects have completed operations and oneis on hold. Exhibit 5-4 briefly summarizes the characteristics and performance of the technologies that aredescribed in more detail in the project fact sheets.

The SNOXTM SCR catalyst and the catalytic oxidation

system has been retained as a permanent part of the NilesStation.
Project Fact Sheets 5-7

wer Generation

eneration technologies

mentally superior

dvanced electric power

der the CCT Program

nsion needs requisite to

 setting nuclear retire

AAA emission limits

ologies are character

 very low pollutant

ons, few solid waste

mics. Advanced electric

may be deployed in

truction to better match

e smaller capacity

l, and nonutility

anced electric power

strated in the CCT

f these five technologies

fic projects and

more detail in the fact

on. Fluidized-bed

ssions of SO2 and NOx

meters and by injecting

stone) into the combus

al. Pulverized coal

dized on jets of air in

ur released from the coal

nt in the bed to form a

 removed with the ash.

nign solid that can be

ricultural and construction applications. More than 90 percent of the SO2 can be captured this way. At combustion temperatures of 1,400 to 1,600 oF, the fluidized mixing of the fuel and sorbent enhances both combustion and sulfur capture. The operating temperature range is about half that of a conventional pulverized-coal boiler and below the temperature at which thermal NOx is formed. In fact, fluidized-bed NOx emissions are about 70 to 80 percent lower than those for conventional pulverized-coal boilers. Thus, fluidized-bed combustors substantially reduce both SO2 and NOx emissions. Also, fluidized-bed combustion has the capability of using high-ash coal, whereas conventional pulverized-coal units must limit ash content in the coal to relatively low levels. Two parallel paths were pursued in fluidized-bed development—bubbling and circulating beds. Bub- bling beds use a dense fluid bed and low fluidization velocity to effect good heat transfer and mitigate erosion of an in-bed heat exchanger. Circulating fluidized-beds use a relatively high fluidization velocity that entrains the bed material, in conjunction with hot cyclones to separate and recirculate the bed material from the flue gas before it passes to a heat exchanger. Hybrid systems have also evolved from these two basic approaches. Fluidized-bed combustion can be either atmo- spheric (AFBC) or pressurized (PFBC). AFBC operates at atmospheric pressure while PFBC operates at pressure 6 to 16 times higher. PFBC offers higher efficiency by using both a gas turbine and steam turbine. Consequently, operating costs and waste are reduced relative to AFBC, as well as boiler size per unit of power output. Second-generation PFBC integrates the combustor with a pyrolyzer (coal gasifier) to fuel a gas turbine (topping cycle), the waste heat from which is used to generate steam for a steam turbine (bottoming cycle). The inherent efficiency of the gas turbine and waste heat recovery in this combined-cycle mode significant- ly increases overall efficiency. Such advanced PFBC systems have the potential for efficiencies over 50 percent. Of the five fluidized-bed combustion projects, two have successfully completed demonstration (one PFBC and one AFBC), and the other three are in the project definition and design phase. Integrated Gasification Combined-Cycle. The integrated coal gasification combined-cycle process has four basic steps: (1) fuel gas is generated from coal reacting with high-temperature steam and an oxidant The 110-MWe Nucla ACFB demonstration enabled Pyropower Corporation (now owned by Foster Wheeler) to save almost 3 years in establishing a commercial line of ACFB units.
osphere; (2) the fuel

hot-gas cleanup system

d nitrogen compounds

and then cleaned

 gas is combusted in a

electricity; and (4) the

as from the gas turbine

eam generator, and

tional electricity in a

ined-cycle systems are

cient of the emerging

nitrogen compounds,

ore the fuel is burned

combustion air is

 much lower volume

combustion scrubber.

 gas requires that the

high degree, not only

protect downstream

ine, from erosion and

in the coal is released

H2S) rather than as

ch of the sulfur

orbent injected into the

ven commercial

ses, which remove

r, but require the fuel

cy penalty. There

 now being demon

s, the hot coal gas is

ide particles, such as

rb sulfur contami

f 1,000 oF, and the

d reused with little

loss of effectiveness. Produced during the regenerationstage are salable sulfur, sulfuric acid, or sulfurcontaining compounds that may be used to produceuseful by-products. The technique is capable ofremoving more than 99.9 percent of the sulfur in thegas stream. With hot-gas cleanup, IGCC systems havethe 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. NOx formed in the gas

turbine can be held to well within allowable levels bystaged combustion in the gas turbine or by addingmoisture to control flame temperature.

Integrated Gasification Fuel Cell. A typical fuel

cell system using coal as fuel includes a coal gasifierwith a gas cleanup system, a fuel cell to use the coalgas to generate 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

than traditional 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 an intermediate step, i.e.,

burner, boiler, turbines, and generators. Each fuel cellincludes an anode and a cathode separated by anelectrolyte layer. In a coal gasification/fuel cellapplication, coal gas is supplied to the anode and air issupplied to the cathode to produce electricity and heat.

Of the four IGCC projects, three are in operation

and one is in the project definition and design phase.

Coal-Fired Diesel. Coal-fired diesels use either a

coal-oil or coal-water slurry fuel to drive an electricgeneration system. The hot exhaust from the dieselengine is routed through a heat-recovery unit to produce steam for a steam-turbine electric generatingsystem (combined cycle). Environmental controlsystems for SO2, NOx, and particulate removal treat thecooled exhaust before release to the atmosphere. Thediesel system is expected to achieve 41 to 48 percentthermal efficiencies. 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 in 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 is kept out of the furnace cavity where it could Shown is the Coltec coal-fired diesel being installed at the University of Alaska.
Project Fact Sheets 5-9

er heat transfer efficien

wn into the furnace, the

 so hot that mineral

hence the name slagging

e cyclone) forces the

mbustor where it can be

Results to date show that by positioning air injection ports so that coal is combusted in stages, NOx

emissions can be reduced by 70 to 80 percent. Injecting limestone into the combustion chamber has thepotential to reduce sulfur emissions by 90 percent incombination with a spray dryer absorber. Advancedslagging combustors could replace oil-fired units inboth utility and industrial applications or be used to

retrofit older, conventional cyclone boilers. The CCTadvanced slagging combustor project is in operation.

Exhibit 5-5 summarizes the process characteristics

and size of the advanced electric power generatingtechnologies presented in more detail in the projectfact sheets.

Exhibit 5-5

rogram Advanced Electric Power Generation Technology Characteristics

Process Size Fact Sheet

n

onstration Project Pressurized circulating fluidized-bed combustion 137-MWe (net) 5-100

FB McIntosh 4A with pyrolyzer and topping combustor 240-MWe (net) 5-102

ject Pressurized bubbling fluidized-bed combustion 70-MWe 5-106

Atmospheric circulating fluidized-bed combustion 297.5-MWe (gross) 5-104

oject 265-MWe (net)

ject Atmospheric circulating fluidized-bed combustion 100-MWe 5-110

mbined Cycle

C Demonstration Project Oxygen-blown, slagging fixed-bed gasifier with cold 400-MWe (net) 5-116

gas cleanup, fuel cell slipstream 2.0 MWe MCFC

ct Air-blown, fluidized-bed gasifier with hot gas cleanup 107 MWe (gross) 5-118

99-MWe (net)

fication Oxygen-blown, entrained-flow gasifier with hot and 313 MWe (gross) 5-120

cold gas cleanup and molten carbonate fuel cell (MCFC) 250-MWe (net)

n Oxygen-blown, two-stage entrained-flow gasifier with 296-MWe (gross); 5-122

cold gas cleanup 262-MWe (net)

at Engines

Advanced slagging combustor, spray dryer with sorbent 50-MWe (nominal) 5-126

recycle

on Project Coal-fueled diesel engine 6.4-MWe (net) 5-128
lean Fuels

y includes a range of

e high-energy-density,

fuels, as well as

ing impacts of coal

oals International

ing techniques are

an already high Btu

 contains sulfur in the

compound. A dense

ed magnetite effective

ritic sulfur. But,

t remove the organi

m-cyclone processed

mpliance coals

ts) if the organic

processed compliance

For coals with signifi

ents and other addi

e sulfur released upon

to compliance. This

ubbing CoalTM. The

s advanced coal

y physical-cleaning

ubbituminous coals,

d secondarily to

enhance the energy

 coal. Some conver

is required, however,

taneous combustion)

 process, coal with

ercent moisture

content, and 0.5 to 1.5 percent sulfur is converted to a12,000 Btu/lb product with 1.0 percent moisture and aslow as 0.3 percent sulfur. The SynCoal® product is

used at utility and industrial facilities. Project operation was extended through 2001.

The ENCOAL project, which completed operational testing in July 1997, used mild gasification to

convert low-Btu, low-sulfur subbituminous coal to ahigh-energy-density, low-sulfur solid product and aclean liquid fuel comparable to No. 6 fuel oil. Mildgasification is a pyrolysis process (heating in theabsence of oxygen) performed at moderate temperatures and pressures. It produces condensable volatilehydrocarbons in addition to solids and gas. Thecondensable fraction is drawn off as a liquid product.Most of the gas is used to provide on-site energyrequirements. The process solid is significantlybeneficiated to produce an 11,000 Btu/lb low-sulfursolid fuel. The demonstration plant processed 500 tonsper day of subbituminous coal, and produced 250 tonsper day of solid Process-Derived Fuel (PDF®) and 250barrels per day of Coal-Derived Liquids (CDL®). Boththe solid and liquid fuels have undergone test burns atutility and industrial sites. The project was successfully completed.

The liquid phase methanol (LPMEOHTM) process

being 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 IGCCsystem, and fuel characteristics of the unrefinedproduct. Since operations began in April 1997,

approximately 43 million gallons of methanol havebeen produced and plant availability has exceeded 97percent. Plant availability in 1998 and 1999 hasexceeded 99.7 percent.

ABB Combustion Engineering, Inc. and CQ Inc.

have developed a personal computer software packagethat will serve as a predictive tool to assist utilities inselecting optimal quality coal for a specific boilerbased on operational efficiency, cost, and environmental considerations. Algorithms were developed andverified through comparative testing at bench, pilot,and utility scale. Six large-scale field tests wereconducted at five separate utilities. The software hasbeen released for commercial use.

Exhibit 5-6 summarizes the process characteristics

and size of the coal processing for clean fuels technologies presented in more detail in the project fact sheets.

Industrial Applications Technology

Technologies applicable to the industrial sector

address significant environmental issues and barriersassociated with coal use in industrial processes. Thesetechnologies are directed at both continued coaluse and introduction of coal use in variousindustrial sectors.

One of the critical environmental concerns has to

do with pollutant emissions resulting from producingcoke from coal for use in steel making. Two approaches to mitigate or eliminate this problem are beingdemonstrated. 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 eliminates the need for cokemaking by using a direct iron-making process. In this
Project Fact Sheets 5-11

The LPMEOHTM process produces over 80,000 gal/day

of methanol, all of which is used by the Eastman ChemicalCompany in Kingsport, TN.

’s advanced coal

p, MT has produced over

ucts.

Exhibit 5-6

T Program Coal Processing for Clean Fuels Technology Characteristics

Process Size Fact Sheet

ty ExpertTM Coal Quality ExpertTM computer software Tested at 250–880-MWe 5-138

ocess Demonstration Advanced coal conversion process for upgrading 45 tons/hr 5-136

low-rank coals

tion Project Liquids-from-coal (LFC®) mild gasification to 1,000 tons/day* 5-142

produce solid and liquid fuels

ion of the Liquid Phase Methanol Liquid phase process for methanol production from 80,000 gal/day 5-132

coal-derived syngas

egrated Approach to Clean Air Dense-medium cyclones with finely sized magnetic and 500 tons/hr 5-134

sorbent addition for bituminous coals

The ENCOALmild gasification plant near Gillette, WY

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®.
nto a reactor to

r a unique reduction

cess reducing gas is

for electric power

e largely driven by

 choice in cement

 to control SO2

owing solid waste

sponsored the demon

ubber. The successful

 Technology Recovery

t, otherwise discarded

ns, convert the sulfur

er, return the solid by

, and produce distilled

ated and cement kiln

ock. This technology

ng pollutant emissions

-energy applications.

plications, the relative

s it an attractive

ck. However, draw

as-fired units to coal

 controls, tube fouling,

circuit for the combus

not high SO2 or NOx

 spacing in the

and the flow of oil or

ing the need for water

CCT Program demon

lagging combustor

roblems. The cyclone

 air to control NOx,

ags the ash in the

g, and uses air cooling

cuitry.

The pulse combustor to be demonstrated by

ThermoChem 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 projects, and

granular-coal injection into a blast furnace projects arecompleted. The CPICORTM and the ThermoChemprojects are in the project definition and design phase,and construction phase, respectively.

Exhibit 5-7 summarizes process characteristics and

size for the industrial applications technologiespresented in more detail in the project fact sheets.Project Fact Sheets

The remainder of this document contains fact

sheets for all 40 projects. Two types of facts sheets areprovided: (1) a brief, two page overview for ongoingprojects; and (2) an expanded four page summary forprojects that have successfully completed operationaltesting. The expanded fact sheets for completedprojects contain a summary of the major results fromthe demonstration as well as sources for obtainingfurther information, specifically, contact persons andkey references. Information provided in the fact sheetsincludes the project participant and team members,project objectives, significant project features, processdescription, major milestones, progress (if ongoing) orsummary of results (if completed), and commercialapplications. A key to interpreting the milestone chartsis provided in Exhibit 5-8. To prevent the release ofproject-specific information of a proprietary nature,process flow diagrams contained in the fact sheets are

highly simplified, and are presented only as illustrations of the concepts involved in the demonstrations.The portion of the process or facility central to thedemonstration is demarcated by the shaded area.

An index to project fact sheets is provided in

Exhibit 5-9. Projects are listed by application category. Ongoing projects in each category appear firstfollowed by projects having completed operations. Ashaded area distinguishes projects having completedoperations from ongoing projects. Within thesebreakdowns, projects are listed alphabetically byparticipant. In addition, Exhibit 5-9 indicates thesolicitation under which the project was selected; itsstatus as of September 30, 1999; and the page numberfor each Fact Sheet. Exhibit 5-10 lists the projectsalphabetically by participant and provides project,location, and page numbers.

An appendix containing contact information for all

of the projects is provided as Appendix D. A list ofacronyms used in this document is provided asAppendix E.
Project Fact Sheets 5-13

Shown here is the Cement Kiln Flue Gas Recovery Scrubber project’s crystallizer and

condensor in foreground and flue gas condensor in background.

Steel Corporation facility, which demonstrated the

y into two blast furnaces at Burns Harbor, IN.

Exhibit 5-7

CCT Program Industrial Applications Technology Characteristics

Process Size Fact Sheet

jection System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of hot 5-152

metal/furnace

with Internal Advanced slagging combustor with staged combustion and sorbent 23 x 106 Btu/hr 5-156

rol injection

oal/Ore Direct reduction iron-making process to eliminate coke; 170-MWe 5-148

combined-cycle power generation 3,300 tons/day of hot metal

y Scrubber Cement kiln dust used to capture SO2; dust converted to feedstock; 1,450 tons/day of cement 5-160

and fertilizer and distilled water produced

fication Test Advanced combustion using Manufacturing and Technology To be determined 5-150

Conversion International’s pulse combustor/gasifier
t contains a bar chart that highlights major milestones—past and planned. The bar chart shows a project’s duration and indicates the time

e general categories of project activities—preaward, design and construction, and operation. The key provided below explains what is in

 of these categories.

ward briefings, negotiations, and other activities conducted during the period between DOE’s selection of the project and award of the cooper

nt.

Construction

EPA process, permitting, design, procurement, construction, preoperational testing, and other activities conducted prior to the beginning of

e demonstration.

o-file

ical exclusion

mental assessment

mental impact statement

art-up of operation and includes operational testing, data collection, analysis, evaluation, reporting, and other activities to complete the dem

ect.

Exhibit 5-8

Key to Milestone Charts in Fact Sheets
Project Fact Sheets 5-15

ojects having completed operations.

Exhibit 5-9

Project Fact Sheets by Application Category

Participant Solicitation/Status Page

ces

Suspension Absorption AirPol, Inc. CCT-III/completed 3/94 5-20

Gas Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93 5-24

urization Demonstration Project LIFAC-North America CCT-III/completed 6/94 5-28

ion Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95 5-32

plications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/completed 12/94 5-36

mbustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/extended 5-42

g for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/completed 12/92 5-46

w-NO

x

 Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 4/93 5-50

d Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 1/95 5-54

monstration for NOx Control New York State Electric & Gas Corporation CCT-IV/completed 9/99 5-58

lytic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95 5-62

s from High-Sulfur, Coal-Fired Boilers

vanced Tangentially-Fired Combustion Southern Company Services, Inc. CCT-II/completed 12/92 5-66

NOx Emissions from Coal-Fired Boilers

chnologies

e NOXSO SO2/NOx Removal Flue Gas Cleanup System NOXSO Corporation CCT-III/on hold 5-72

monstration Project ABB Environmental Systems CCT-II/completed 12/94 5-74

Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5/93 5-78

Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 10/94 5-82

tension and Coolside Demonstration McDermott Technology, Inc. CCT-I/completed 8/91 5-86

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

ns Control System Public Service Company of Colorado CCT-III/completed 12/96 5-94

eneration

nstration Project Lakeland, City of, Lakeland Electric CCT-III/design 5-100

B Demonstration Project Lakeland, City of, Lakeland Electric CCT-V/design 5-102

on Demonstration Project JEA CCT-I/design 5-104
ects having completed operations.

Exhibit 5-9 (continued)

Project Fact Sheets by Application Category

Participant Solicitation/Status Page

The Ohio Power Company CT-I/completed 3/95 5-106

Tri-State Generation and Transmission

Association, Inc. CCT-I/completed 1/91 5-110

d-Cycle

emonstration Project Kentucky Pioneer Energy, L.L.C. CCT-V/design 5-116

Sierra Pacific Power Company CCT-IV/operational 5-118

tion Combined-Cycle Project Tampa Electric Company CCT-III/operational 5-120

epowering Project Wabash River Coal Gasification Repowering CCT-IV/operational 5-122

Project Joint Venture

ines

Alaska Industrial Development and

Export Authority CCT-III/operational 5-126

Project Arthur D. Little, Inc. CCT-V/construction 5-128

els

of the Liquid Phase Methanol (LPMEOHTM) Process Air Products Liquid Phase

Conversion Company, L.P CCT-III/operational 5-132

ated Approach to Clean Air Custom Coals International CCT-IV/on hold 5-134

s Demonstration Western SynCoal LLC CT-I/operational 5-136

ExpertTM ABB Combustion Engineering, Inc.

and CQ Inc. CCT-I/completed 12/95 5-138

 Project ENCOAL Corporation CCT-III/completed 7/97 5-142

/Ore Reduction (CPICORTM) CPICORTM Management Company L.L.C. CCT-V/design 5-148

tion Test ThermoChem, Inc. CCT-IV/design 5-150

tion System Demonstration Project Bethlehem Steel Corporation CCT-III/completed 9/99 5-152

h Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/completed 5/90 5-156

crubber Passamaquoddy Tribe CCT-II/completed 9/93 5-160
Project Fact Sheets 5-17

Exhibit 5-10

Project Fact Sheets by Participant

Project Location Page

 Inc. and CQ Inc. Development of the Coal Quality ExpertTM Homer City, PA 5-138

SNOXTM Flue Gas Cleaning Demonstration Project Niles, OH 5-74

version Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Kingsport, TN 5-132

Process10-MWe Demonstration of Gas Suspension Absorption West Paducah, KY 5-20

 and Export Authority Healy Clean Coal Project Healy, AK 5-126

Clean Coal Diesel Demonstration Project Fairbanks, AK 5-128

The Demonstration of Coal Reburning for Cyclone Boiler NOx Control Cassville, WI 5-46

The Full-Scale Demonstration of Low-NOx Cell Burner Retrofit Aberdeen, OH 5-50

The SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project Dilles Bottom, OH 5-78

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Seward, PA 5-24

Blast Furnace Granular-Coal Injection System Demonstration Project Burns Harbor, IN 5-152

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Williamsport, PA 5-156

pany L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICORTM) Vineyard, UT 5-148

 Engineering and CQ Inc.)

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Central City, PA 5-134

ENCOAL® Mild Coal Gasification Project Gillette, WY 5-142

earch Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Hennepin, IL 5-82

Springfield, IL

earch Corporation Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Denver, CO 5-54

JEA Large-Scale CFB Combustion Demonstration Project Jacksonville, FL 5-104

C. Kentucky Pioneer Energy IGCC Demonstration Project Trapp, KY 5-116

ectric McIntosh Unit 4A PCFB Demonstration Project Lakeland, FL 5-100

ectric McIntosh Unit 4B Topped PCFB Demonstration Project Lakeland, FL 5-102

LIFAC Sorbent Injection Desulfurization Demonstration Project Richmond, IN 5-28

LIMB Demonstration Project Extension and Coolside Demonstration Loraine, OH 5-86

 Corporation Micronized Coal Reburning Demonstration for NOx Control Lansing, NY 5-58
Exhibit 5-10 (continued)

Project Fact Sheets by Participant

Project Location Page

Corporation Milliken Clean Coal Technology Demonstration Project Lansing, NY 5-90

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas On hold 5-72

Cleanup System

Tidd PFBC Demonstration Project Brilliant, OH 5-106

Cement Kiln Flue Gas Recovery Scrubber Thomaston, ME 5-160

rado Integrated Dry NOx /SO2 Emissions Control System Denver, CO 5-94

Advanced Flue Gas Desulfurization Demonstration Project Chesterton, IN 5-32

Piñon Pine IGCC Power Project Reno, NV 5-118

. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coosa, GA 5-42

. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newnan, GA 5-36

Process

. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensacola, FL 5-62

NO

x Emissions from High-Sulfur, Coal-Fired Boilers

. 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Lynn Haven, FL 5-66

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

Tampa Electric Integrated Gasification Combined-Cycle Project Mulberry, FL 5-120

Pulse Combustor Design Qualification Test Baltimore, MD 5-150

ission Association, Inc. Nucla CFB Demonstration Project Nucla, CO 5-110

Repowering Wabash River Coal Gasification Repowering Project West Terre Haute, IN 5-122

Advanced Coal Conversion Process Demonstration Colstrip, MT 5-136
Program Update 1999 5-19

nvironmental Control Devices

SO2 Control Technologies
Environmental Control Devices

ation of Gas

rption

y owner

nder and site owner

y, KY

(GSA) system for flue

flue gas from a

ntermittently)

189 100%

259 30

930 70

f Gas Suspension Ab

r achieving Phase II

zed coal-fired boilers

Technology/Project DescriptionThe GSA system consists of a vertical reactor in whichflue gas comes into contact with suspended solids consisting of lime, reaction products, and fly ash. About 99%of the solids are recycled to the reactor via a cyclonewhile the exit gas stream passes through an electrostaticprecipitator (ESP) or pulse jet baghouse (PJBH) beforebeing released to the atmosphere. The lime slurry, prepared from hydrated lime, is injected through a spraynozzle at the bottom of the reactor. The volume of limeslurry is regulated with a variable-speed pump controlledby the measurement of the acid content in the inlet andoutlet gas streams. The dilution water added to the limeslurry is controlled by on-line measurements of the fluegas exit temperature.

A test program was structured to (1) optimize design

of the GSA reactor for reduction of SO2 emissions from

boilers using high-sulfur coal, and (2) evaluate the environmental control capability, economic potential, andmechanical performance of GSA. A statistically designedparametric (factorial) test plan was developed involvingsix variables. Beyond evaluation of the basic GSA unit tocontrol SO2, air toxics control tests were conducted, and

the effectiveness of a GSA/ESP and GSA/PJBH to control both SO2 and particulates were tested. Factorial tests

were followed by continuous runs to verify consistency ofperformance over time.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Program Update 1999 5-21

est effect on SO2 re

ration temperature next,

content.

/S molar ratio of 1.3 with

n and 0.04% chloride,

/S molar ratio of 1.4 with

on and 0.12% chloride,

e removal efficiency.

/S molar ratio of 1.4 with

on and 0.12% chloride,

ction relative to

te removal efficiency.

• GSA/ESP and GSA/PJBH removed 98% of the hydrogen chloride (HCl), 96% of the hydrogen fluoride

(HF), and 99% on more of most trace metals, exceptcadmium, antimony, mercury, and selenium.(GSA/PJBH removed 99+% of the selenium.)

• The solid by-product was usable as low-grade cement.Operational• GSA/ESP lime utilization averaged 66.1% and

GSA/PJBH averaged 70.5%.

• The reactor achieved the same performance as a conventional spray dryer, but at one-quarter to one-third

the size.

• GSA generated lower particulate loading than a conventional spray dryer, enabling compliance with a

lower ESP efficiency.

• Special steels were not required in construction, and

only a single spray nozzle is needed.

• High availability and reliability similar to other commercial applications were demonstrated, reflecting

simple design.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

Ground breaking/construction started 5/92

reaward

10/90 10/92

Design and Construction

Operation initiated 10/92Environmental monitoring plan completed 10/2/92

Design completed 12/91

ed 10/11/90

F) 9/21/90

Preoperational tests initiated 9/92Construction completed 9/92

6/95

Project completed/final report issued 6/95

Operation completed 3/94

Economic• Capital and levelized (15-year) costs for GSA installed

in a 300-MWe plant using 2.6% sulfur coal are compared below to costs for a wet limestone scrubber withforced oxidation (WLFO scrubber). EPRI’s TAGTMcost method was used. Based on EPRI cost studies ofFGD processes, the capital cost (1990$) for a conventional spray dryer was $172/kW.

Capital Cost Levelized Cost(1990 $/kW) (mills/kWh)

GSA—3 units at 149 10.3550% capacityWLFO 216 13.04
Environmental Control Devices

Exhibit 5-12

GSA Factorial Testing Results

Exhibit 5-11

Variables and Levels Used in

GSA Factorial Testing

Variable LevelApproach-to-saturation temperature (°F) 8*, 18, 28

Ca/S (moles Ca(OH)2/mole inlet SO2) 1.00 and 1.30

Flyash 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.

nding a high concentra

e solids, and recirculat

recise control. This

to that of wet scrubbers

h concentration of

ntact area. The

turation tempera

, precise, integral

lids concentration.

 the largest operat

 costs by reducing

d. The GSA is

ay dryer by its

ducing reagent to

lating unused lime,

o, injected slurry

, avoiding corrosion

 fabrication.

used in the factorial

were applied. Inlet

stant at

hat lime stoichi

O2 removal. Ap

was the next most

by chloride levels.

n temperature of 8

the system, the test

de level (0.04%).

ecrease as chloride

to-saturation tem

 0.12% coal chlo

es key results from

valuate the

 with bituminous

% chloride levels,

emperature. 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 inflyash 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 the set point of 91%, at an average Ca/S molar ratio of 1.40–1.45 moles Ca(OH)2/mole

inlet SO2. The system was able to adjust rapidly to the

surge in inlet SO2 caused by switching to 3.5% sulfur

Warrior Basin coal for a week. Lime utilization averaged66.1%. The particulate removal efficiency averaged99.9+% and emission rates were maintained below0.015 lb/106 Btu. The 14-day run on the GSA/PJBH

system showed that the SO2 removal efficiency averaged

more than 96% at an average Ca/S molar ratio of 1.34–1.43 moles Ca(OH)2/mole inlet SO2. Lime utilization

averaged 70.5%. The particulate removal efficiencyaveraged 99.99+% and emission rates ranged from0.001–0.003 lb/106 Btu.

All air toxics tests were conducted with 2.7% sulfur,

low-chloride coal with a 12 oF approach-to-saturationtemperature and a high flyash loading of 2.0 gr/ft3 (actual). The GSA/ESP arrangement indicated average

removal efficiencies of greater than 99% for arsenic,barium, chromium, lead, and vanadium; somewhat lessfor manganese; and less than 99% for antimony, cadmium, mercury, and selenium. The GSA/PJBH configuration showed 99+% removal efficiencies for arsenic,barium, chromium, lead, manganese, selenium, and vanadium; with cadmium removal much lower and mercuryremoval lower than that of the GSA/ESP system. Theremoval of HCl and HF was dependent upon the utilization of lime slurry and was relatively independent ofparticulate control configuration. Removal efficiencieswere greater than 98% for HCl and 96% for HF.Operational PerformanceBecause the GSA system has suspended recycle solids toprovide a contact area for SO2 capture, multiple highpressure atomizer nozzles or high-speed rotary nozzles to

achieve uniform, fine droplet size are not required. Also,recycle of solids is direct and avoids recycling material inthe feed slurry, which would necessitate expensive abrasion-resistant materials in the atomizer(s).

50

6070

80

90

100

0.90 1.0 1.1 1.2 1.3 1.4

Note: All tests were conducted at a 320 °F inlet flue gastemperature.

Overall System SO Removal (%) 2 8 °F Approach - 0.04% Cl 18 °F Approach - 0.04% Cl 18 °F Approach - 0.12% Cl

Fresh Lime Stoichiometry (moles Ca/mole SO ) 2
Program Update 1999 5-23

AirPol, Inc. successfully demonstrated the GSA system

at TVA’s Center for Emissions Research.

ansfer characteristics of

m to be significantly

ay dryer for the same

ird the size. This

e-confined plants and

GSA system slurry is

not the reactor walls,

d the need for corrosion

ore, the high concentra

cours the reactor walls

A system generates a

g than a conventional

A versus 6–10 gr/ft3 for a

ce even with lower ESP

The GSA system pro

ning very low moisture.

ash and unreacted lime.

by-product undergoes a

providing the charac

hich have been applied to

conomics were estimated

 of a 300-MWe boiler

esign SO2 removal effi

te equivalent to 1.30

me was assumed to be 2.8

was determined that (1)

$) with three units at 50%

15-year) was 10.35 mills/

acity.

 WLFO scrubber showed

 be $216/kW and 13.04

pital cost listed in EPRI

ay dryer at 300-MWe

W (1990$). Also, be

er and has better lime

e GSA will have a lower

Commercial ApplicationsThe low capital cost, moderate operating cost, and highSO2 capture efficiency make the GSA system particularly

attractive as a CAAA compliance option for boilers in the50- to 250-MWe range. Other major advantages includethe modest space requirements comparable to duct injection systems; high availability/reliability owing to designsimplicity; and low dust loading, minimizing particulateupgrade costs.

GSA market entry was significantly enhanced with

the sale of a 50-MWe unit, worth $10 million, to the cityof Hamilton, Ohio, subsidized by the Ohio Coal Development Office. A sale worth $1.3 million has been made tothe U.S. Army for hazardous waste disposal. A GSAsystem has been sold to a Swedish iron ore sinter plant.Sales to Taiwan and India have a combined value of $5.5million.ContactsNiels H. Kastrup, (281) 539-3400

FLS miljo, Inc.100 GlennboroughHouston, TX 77067(281) 539-3411 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• 10-MWe Demonstration of Gas Suspension Absorption Final Project Performance and Economics

Report. Report No. DOE/PC/90542-T9. AirPol,Inc. June 1995. (Available from NTIS asDE95016681.)

• 10-MW Demonstration of Gas Suspension Absorption Final Public Design Report. Report No.

DOE/PC/90542-T10. AirPol, Inc. June 1995.(Available from NTIS as DE960003270.)

• SO2 Removal Using Gas Suspension Absorption

Technology. Topical Report No. 4. U.S. Department of Energy and AirPol, Inc. April 1995.

• 10-MWe Demonstration of the Gas Suspension

Absorption Process at TVA’s Center for EmissionsResearch: Final Report. Report No. DOE/PC/90542-T10. Tennessee Valley Authority. March1995. (Available from NTIS as DE96000327.)
Environmental Control Devices

s

persion

ization

cofunder and host

t Authority—cofunder

orporation—cofunder

der

sylvania Electric

No. 5)

nfined zone disper

D/FGD) process

% sulfur

600 100%

800 50

800 50

bilities of in-duct CZD/

efine the optimum

o determine CZD/

FGD’s operability, reliability, and cost-effectivenessduring 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 in the liquid droplets. The droplets mix withthe hot flue gas, and the water evaporates rapidly. Fastdrying precludes wet particle buildup in the duct and aidsthe flue gas in carrying the dry reaction products and theunreacted lime to the ESP.

 This project included injection of different types

of sorbents (dolomitic and calcitic limes) with severalatomizer designs using low- and high-sulfur coals toverify the effects on SO2 removal and the capability of

the ESP to control particulates. The demonstrationwas conducted at Pennsylvania Electric Company’sSeward Station in Seward, PA. One-half of the flue gascapacity of the 147-MWe Unit No. 5 was routedthrough a modified, longer duct between the first- andsecond-stage ESPs.

ded 100% by the participant
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Program Update 1999 5-25

1990 1991 1992 1993 1994 1995 1996 1997 1998

lime proved to be a

either dry hydrated

 calcitic lime.

e most influential pa

e gas temperature was

n rate. For SO2 capture

flue gas temperature of

en sorbent did not in

y beyond a certain

moval efficiencies of

 with flue gas tempera

), sorbent injection rate

me of 2 seconds, and a

lime concentration of

• 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% limeutilization rate. That is, 2–2.5 moles of CaO orCaO•MgO were required for every mole of SO2

removed.

• Assuming 92% lime purity, 1.9–2.4 tons of lime was

required for every ton of SO2 removed.

Operational• About 100 ft of straight duct was required to assure

the 2-second residence time needed for 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• Capital cost of a 500-MWe system operating on 4%

sulfur coal and achieving 50% SO2 reduction was

estimated at less than $30/kW and operating cost at$300/ton of SO2 removed (1994$).

reaward Operation

10/90

art 6/90

MTF) 9/90

arded 10/90

eted 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
Environmental Control Devices

o form a

middle of a

ot gas be

s. The lime

n the gas

rm solid

om the point

products

 the flue gas.

pecial reac

uctwork.

e Type S

 reduced

ZD/FGD

The in

rocessed

ce, elimi

handle the increased

wo-part test program

with the first

sisting primarily of

onths consisting of

uring the continuous

 was operated under

 utility boiler operators.

horoughly tested both

o testing.

est program, which

leted in August 1992.

s:

l of 50%

ess than $300/ton

ormal boiler operations

missions and opacity

 duct injection of atom

ted calcitic lime,

freshly slaked calcitic lime, and pressure-hydrateddolomitic lime. All three reagents remove SO2 from the

flue gas but require different feed concentrations oflime slurry for the same percentage of SO2 removed.

The most efficient removals and easiest to operatesystem were obtained using pressure-hydrated dolomitic lime.Environmental PerformanceSorbent injection rate proved to be the most influentialfactor on SO2 capture. The rate of injection possible was

limited by the flue gas temperature. This impacted 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 above 9% did not increase SO2 capture effi- ciency. Parametric tests indicated that SO2 removals above 50% are possible under the following conditions: flue gas temperature of 300–310 oF; boiler load of 145- to 147-MWe; residence time in the duct of 2 seconds; and lime slurry injection rate of 52–57 gal/min. Operational Performance The percentage of lime utilization in the CZD/FGD sig- nificantly affected the total cost of SO2 removal. An analysis of the continuous operational data indicated that the percentage of lime utilization was directly dependent on two key factors: (1) percentage of SO2 removed, and (2) lime slurry feed concentration. 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 utilization rate. That is, 2–2.5 moles of CaO or CaO•MgO were required for every mole of SO2 removed; or assuming 92% lime purity, 1.9–2.4 tons of lime were required for every ton of SO2 removed. In summary, the demonstration showed the following results: • A 50% SO2 removal efficiency with CZD/FGD was possible. • Drying and SO2 absorption required a residence time of 2 seconds, which required a long and straight hori- zontal gas duct of about 100 feet. • The fully automated system integrated with the power plant operation demonstrated that the CZD/FGD pro- cess responded well to automated control operation. However, modifications to the CZD/FGD were re- quired to assure consistent SO2 removal and avoid deposition of solids within the gas duct during upsets. Bechtel’s demonstration showed that 50% SO2 removal efficiency was possible using CZD/FGD technology. The extended duct into which lime slurry was injected is in the foreground.
Program Update 1999 5-27

as very good.

acity was not detrimen

GD system.

eve costs of $300/ton of

00-MWe unit burning

MWe plant retrofitted

moval, the total capital

$30/kW (1994$).

-funded CZD/FGD dem

ion, the CZD/FGD sys

O2 removal during con

g daily load cycles.

sylvania Electric Com

emonstration for an

that CZD/FGD operation

50% could be sustained

cant process problems.

etrofit of existing plants

iler flue gas facilities to

of sulfur-containing

be added to a utility

of about $25–50/kW of

ely one-fourth the cost of

bber. In addition to low

lude small space require

y requirements, fully

uction of only nontoxic,

GD technology is par

ng existing boilers,

e. The CZD/FGD instal

ower station alterations

cally integrated into

ContactsJoseph T. Newman, Project Manager, (415) 768-1189

Bechtel CorporationP.O. Box 193965San Francisco, CA 94119-3965(415) 768-5420 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• 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 as DE91002564.)

This photo shows the CZD/FGD lime slurry injector control system.
Environmental Control Devices

ection

monstration

nture partnership

ion and ICF Kaiser

nder and project

funder

r

nder and host utility

—cofunder

funder

chmond Power %

 Unit No. 2)

 with sulfur capture in a

n reactor

772 100%

864 50

908 50

Project ObjectiveTo demonstrate that electric power plants—especiallythose with space limitations and burning high-sulfurcoals—can be retrofitted successfully with the LIFAClimestone injection process to remove 75–85% of the SO2

from flue gas and produce a dry solid waste product fordisposal in a landfill.Technology/Project DescriptionPulverized limestone is pneumatically blown 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 to

SO2 capture. After leaving the chamber, the sorbent is

easily separated from the flue gas along with the fly ashin the electrostatic precipitator (ESP). The sorbent material from the reactor and electrostatic precipitator arerecirculated back through the reactor for increased efficiency. The waste is dry, making it easier to handle thanthe wet scrubber sludge produced by conventional wetlimestone scrubber systems.

The technology enables power plants with space

limitations to use high-sulfur midwestern coals by providing an injection process that removes 75–85% of the SO2

from flue gas and produces a dry solid waste productsuitable for disposal in a landfill.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 5-29

1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Design and Construction Operation

Original design completed 7/91

Cooperative agreement awarded 11/20/90

NEPA process completed (MTF) 10/2/90

Ground breaking/construction started 5/29/91

 selected project (CCT-III) 12/19/89

Preoperational tests initiated 7/92

Environmental monitoring plancompleted 6/12/92Construction completed 6/92

Operation completed 6/94

Operation initiated 9/92

11/90 9/92

0% at a calcium-to

2.0, approach-to-satura

and limestone fineness

limestone fineness of

% lower at a Ca/S molar

roach-to-saturation

the greatest influence

were limestone fine

-saturation temperature,

ted in the demonstration

ing the recycle rate and

saturation temperature

2 removal efficiency to

2.0 (fine limestone).

• ESP efficiency and operating levels were essentially

unaffected by LIFAC operation during steady-stateoperation.

• Fly and bottom ash were dry and readily disposed of

at a local landfill. The quantity of additional solidwaste can be determined by assuming that approximately 4.3 tons of limestone is required to remove1.0 ton of SO2.

Operational• When operating with fine limestone (80% minus

325 mesh), the soot-blowing cycle had to be reducedfrom 6.0 to 4.5 hours.

• Automated programmable logic and simple design

make the LIFAC system easy to operate in startup,shutdown, or normal duty cycles.

• The amount of bottom ash increased slightly, but there

was no negative impact on the ash-handling system.

Economic• Capital cost—$66/kW for two LIFAC reactors

(300-MWe); $76/kW for one LIFAC reactor(150-MWe); $99/kW for one LIFAC reactor(65-MWe) (1994$).

• Operating cost—$65/ton of SO2 removal, assuming

75% SO2 capture, Ca/S molar ratio of 2.0, limestone

composed of 95% CaCO3, and costing $15/ton.

4/98

Project completed/final

report issued 4/98
Environmental Control Devices

The LIFAC system successfully demonstrated at

Whitewater Valley Station Unit No. 2 is being retained byRichmond Power % Light for commercial use with highsulfur coal. There are 10 full-scale LIFAC units in Canada,China, Finland, Russia, and the United States.

ned to enhance the

on systems for SO2

le aspects of low capi

of retrofit. Furthermore,

(about 1/3 of the cost of

 was incorporated to

an was composed of

s own objectives.

e operation of the

bsystems prior to

d to evaluate the many

C process parameters

l.

ed after the parametric

nd operability of the

nuous operating periods.

 to demonstrate LIFAC’s

operating conditions.

ating the baseline test to

he LIFAC system.

monstration varied in

wever, most of the

her sulfur coals

e, the numerous LIFAC

 sulfur removal effi

major parameters having

moval efficiency were

o, reactor bottom tem

and ESP ash recycling

15% better when in

 325 mesh) than it was

 200 mesh).

While injecting the fine limestone, the soot blowing

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 ashcontaining unspent sorbent and fly ash was recycled fromthe ESP hoppers back into the reactor inlet duct work.Ash recycling is essential for efficient SO2 capture. The

large quantity of ash removed from the LIFAC reactorbottom and the small size of the ESP hoppers limited theESP ash recycling rate. As a result, the amount of material recycled from the ESP was approximately 70% lessthan had been anticipated. However, this low recyclingrate was found to affect SO2 capture. During a brief test,

it was found that increasing the recycle rate by 50% resulted in a 5% increase in SO2 removal efficiency. It was

estimated that if the reactor bottom ash is recycled alongwith ESP ash, while sustaining a reactor temperature of5 oF above saturation temperature, an SO2 reduction of

85% could be maintained.Operational PerformanceOptimization 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 that SO2 reductions of

70% or more can be maintained under normal boiler

operating ranges. Stack opacity was low (about 10%) andESP efficiency was high (99.2%). The amount of boilerbottom ash increased slightly during testing, but there wasno negative impact on the power plant’s bottom andflyash removal system. The solid waste generated was amixture of fly ash and calcium compounds and wasreadily disposed of at a local landfill.

The LIFAC system proved to be highly operable

because it has few moving parts and is simple to operate.
Program Update 1999 5-31

 is shown being lifted into

ation, long-term testing

% or more could be

ation.

own and restarted. The

mmable logic system that

nterlocking, startup,

The entire LIFAC pro

 personal computers

rol room.

Economic PerformanceThe economic evaluation indicated that the capital costof a LIFAC installation is lower than for either a spraydryer or wet scrubber. Capital costs for LIFAC technology vary, depending on unit size and the quantity ofreactors needed:• $99/kW for one LIFAC reactor at Whitewater Valley

Station (65-MWe) (1994$),

• $76/kW for one LIFAC reactor at Shand Station

(150-MWe), and

• $66/kW for two LIFAC reactors at Shand Station

(300-MWe).

Crushed limestone accounts for about one-half of

LIFAC’s operating costs. LIFAC requires 4.3 tons 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 ApplicationsThere are 10 full-scale LIFAC units in operation inCanada, China, Finland, Russia, and the United States.The LIFAC system at Richmond Power % Light is thefirst to be applied to a power plant using high-sulfur (2.0–2.9%) coal. The LIFAC system is being retained by Richmond Power % Light at Whitewater Valley Station, UnitNo. 2. The other LIFAC installations on power plants areusing bituminous and lignite coals having lower sulfurcontents (0.6–1.5%).ContactsJim Hervol, Project Manager, (412) 497-2235

ICF Kaiser Engineers, Inc.Gateway View Plaza1600 West Carson StreetPittsburgh, PA 15219-1031(412) 497-2235 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

References• LIFAC Sorbent Injection Desulfurization Demonstration Project. Final Report, Vol. II: Project

Performance and Economics. LIFAC-NorthAmerica. February 1998. (Available from NTIS asDE96004421.)

• “LIFAC Nearing Marketability.” Clean Coal Today.

Report No. DOE/FE-0215P-21. Spring 1996.

• Viiala, J., et al. “Commercialization of the LIFAC

Sorbent Injection Process in North America.” ThirdAnnual Clean Coal Technology Conference: Technical Papers. September 1994.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: LIFAC Sorbent InjectionDesulfurization Demonstration Project. LIFACNorth America. Report No. DOE/FE-0207P. U.S.Department of Energy, October 1990. (Availablefrom NTIS as DE91001077.)
Environmental Control Devices

s

monstration

diary of Pure Air,

ween Air Products and

avy Industries

ompany—cofunder and

—process designer

Engineers and Con

—constructor and

rthern Indiana Public

ting Station, Unit Nos.

furization (AFGD)

898 100%

200 42

698 58

Project ObjectiveTo 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 all combined to yield a state-ofthe-art SO2 absorber that was more compact and less

expensive than contemporary conventional scrubbers.

Other technical features included the injection of

pulverized limestone directly into the absorber, a devicecalled an air rotary sparger located within the base of theabsorber, and a novel wastewater evaporation system.The air rotary sparger combined the functions of agitationand air distribution into one piece of equipment to facilitate the oxidation of calcium sulfite to gypsum.

Pure Air also demonstrated a unique gypsum

agglomeration process, PowerChip®, to significantly

enhance handling characteristics of adsorbed flue gasdesulfurization (AFGD)-derived gypsum.

e Air on the Lake, L.P.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Program Update 1999 5-33

e 600-MWe absorber

ove 95% or more SO2 at

operating with high

 produced in lieu of

roduced was sold

ystem (WES) mitigated

ater generation associated

showed the potential for

charge (only a partial

rket potential for AFGD

tively converting it to a

racteristics of natural

• 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, gypsum product).Some boron, selenium, and mercury passed to thestack gas in a vapor state.

Operational• AFGD use of co-current, high-velocity flow; integration of functions; and a unique air rotary sparger

proved to be highly efficient, reliable (to the exclusionof requiring a spare module), and compact. The compactness, combined with no need for a spare module,significantly reduced space requirements.

• The own-and-operate contractual arrangement

whereby Pure Air took on the turnkey, financing,operating, and maintenance risks through performanceguarantees was successful.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction Operation

Project completed/final report issued 6/96

perative agreement awarded 12/20/89

Preoperational tests initiated 3/92

Operation initiated 6/92

Design completed 9/92Construction completed 9/92

Operation completed 6/95

6/92

NEPA process completed (EA) 4/16/90Ground breaking/construction started 4/20/90

Environmental monitoring plan completed 1/31/91

6/96

Economic• Capital costs and space requirements for AFGD were

about half those of conventional systems.
Environmental Control Devices

Exhibit 5-13

 SO2 Removal Performance

(100% Boiler Load)

orber modules of ad

volumes of flue gas

ty and reliability with

rformance objectives

n, the AFGD unit accu

 with an availability of

ns of SO2 were re

f 95% or more, and

um were produced. The

rvice, which includes

U.S. Gypsum’s East

ction plant.

rly established that

 parameters (without

ve 95% SO2 reduction

s. The design range

metric ratio was

t by gypsum purity

acted reagent allowed

ol parameter was the

reagent slurry injected

lume of flue gas (G).

 gal/1,000 ft3. The

ds settling rates in the

 wetting of the grid

ined by where perfor

ur contents were se

amine SO2 removal

lfur content, stoichio

d were 33%, 67%, and

well above 95%, were

with low to moderate

gs, even for 4.5%

zes the results of para

In the AFGD process, chlorides that would have

been released to the air are captured but potentially become a wastewater problem. This was mitigated by theaddition of the WES, which takes a portion of the wastewater stream with high chloride and sulfate levels andinjects it into the ductwork upstream of the ESP. The hotflue gas evaporated the water and the dissolved solidswere captured in the ESP. Problems were experiencedearly on, with the WES nozzles failing to provide adequate atomization, and plugging as well. This was resolved by replacing the original single-fluid nozzles withdual-fluid systems employing air as the second fluid.

Commercial-grade gypsum quality (95.6–99.7%) was

maintained 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 isdependent upon whether users are in range of economic

transport and whether theycan handle the gypsum byproduct. For these reasons,PowerChip® technology was

demonstrated as part of theproject. This technology usesa compression mill to convert the highly cohesiveAFGD gypsum cake into aflaked product with handlingcharacteristics equivalent tonatural rock gypsum. Theprocess avoids use of binders, pre-drying or pre-calcining normally associated withbriquetting, and is 30–55%cheaper at $2.50–$4.10/ton.

Air toxics testing established that all acid gases are

effectively captured and

neutralized by the AFGD. Trace elements largely becomeconstituents of the solids streams (bottom ash, fly ash,gypsum product). Some boron, selenium, and mercurypass to the stack gas in a vapor state.Operational PerformanceAvailability over the 3-year operating period averaged99.5% while maintaining an average SO2 removal efficiency of 94%. This was attributable to the simple, effective design and an effective operating/maintenance philosophy. Modifications were also made to the AFGD

system. An example was the implementation of new alloytechnology, C-276 alloy over carbon steel clad material,to replace alloy wallpaper construction within the absorber tower wet/dry interface. Also, use of co-currentrather than conventional counter-current flow resulted inlower pressure drops across the absorber and afforded theflexibility to increase gas flow without an abrupt drop inremoval efficiency. AFGD SO2 capture efficiency with

limestone was comparable to that in wet scrubbers using
Program Update 1999 5-35

Exhibit 5-15

Flue Gas Desulfurization

Economics

0

50

100150200250300350400

00.20.40.60.811.2

$/Ton SO2 $/106 Btu

A B C D E

Plant Modifications

Delivered Fuel

500-MWe plant, 30-yr levelized costs, allowance value of$300/tonIncremental cases:A—Conventional FGD (EPRI model)B—AFGD, own-and-operate arrangementC—Adds gypsum salesD—Adds emission allowance credits at $300/ton, for 90%

SO2 removal

E—Increases SO2 removal to 95%

Exhibit 5-14

Estimated Costs for an AFGD System

(1995 Current Dollars)

Cases: 1 2 3 456789

e (MWe) 100 100 100 300 300 300 500 500 500

ur content (%) 1.5 3.0 4.5 1.5 3.0 4.5 1.5 3.0 4.5

ost ($/kW) 193 210 227 111 121 131 86 94 101

d cost ($/ton SO2

)

ar life 1,518 840 603 720 401 294 536 302 223ar life 1,527 846 607 716 399 294 531 300 223

d cost (mills/kWh)

ar life 16.39 18.15 19.55 7.78 8.65 9.54 5.79 6.52 7.24ar life 16.49 18.28 19.68 7.73 8.62 9.52 5.74 6.48 7.21

e. The 24-hour power

1% of expected con

n was 1,560 gal/min, or

and levelized current

es with varying plant

A capacity factor of 65%

f 90% were assumed.

 followed guidelines

Assessment GuideTM.

the own-and-operate

on, and emission allow

bit 5-15 depicts the rela

MWe generating unit in

r coal with a base case

ur incremental cases.

-15 show the range of

 The lower bar is the

thetical midwest unit

e plant modifications to

el.

technology, e.g., in materials and components, should

lower costs for AFGD. The own-and-operate businessapproach has done much to mitigate risk on the part ofprospective users. High SO2 capture efficiency places an

AFGD user in the possible position to trade allowances orapply credits to other units within the utility. WES andPowerChip® 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.ContactsTim Roth, (610) 481-6257

Pure Air on the Lake, L.P.c/o Air Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501(610) 481-5820 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

References• Advanced Flue Gas Desulfurization (AFGD) Demonstration Project. Final Technical Report, Vol. II:

Project Performance and Economics. Pure Air on

the Lake, L.P. April 1996. (Available from NTIS asDE96050313.)

• Advanced Flue Gas Desulfurization Project: Public

Design Report. Pure Air on the Lake, L.P. March1990.

• Summary of Air Toxics Emissions Testing at Sixteen

Utility Power Plants. Prepared by Burns and RoeServices Corporation for U.S. Department of Energy,Pittsburgh Energy Technology Center. July 1996.
Environmental Control Devices

Innovative

chnology for

ocess

—cofunder

tal and analytical

r

pment—fiberglass

ant

ultant

oundation—

onsultant

orgia Power

1)

horoughbred-121

furization (FGD)

 sulfur

Project FundingTotal project cost $43,074,996 100%DOE 21,085,211 49Participant 21,989,785 51Project ObjectiveTo demonstrate 90% SO2 control at high reliability with

and without simultaneous particulate control; to evaluateuse of fiberglass-reinforced plastic (FRP) vessels to eliminate flue gas reheat and spare absorber modules;and to evaluate use of gypsum to reduce waste management costs.Technology/Project DescriptionThe project demonstrated the CT-121 FGD process,which uses a unique absorber design known as the JetBubbling Reactor® (JBR). The process combines limestone FGD reaction, forced oxidation, and gypsum crystallization in one process vessel. The process is mechanically and chemically simpler than conventional FGD processes and can be expected to exhibit lower cost characteristics. The flue gas enters underneath the scrubbing solu- tion in the JBR. The SO2 in the flue gas is absorbed and forms calcium sulfite (CaSO3). Air is bubbled into the bottom of the solution to oxidize the calcium sulfite to form gypsum. The slurry is dewatered in a gypsum stack, which involves filling a diked area with gypsum slurry. Gypsum solids settle in the diked area by gravity, and clear water flows to a retention pond. The clear water from the pond is returned to the process. 

ark of the Chiyoda Corp.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

**Years omitted

1 2

Program Update 1999 5-37

1990 1991 1992 1993 1994 1995 1996 1999 2000

4/90

Design and Construction Operation

10/92

Cooperative agreement awarded 4/2/90

NEPA processcompleted (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

iency was achieved at

000–3,500 ppm with

%.

moval efficiencies of

adings of 0.303–

ange of 50–100-MWe.

tion of particle size:

e

re

capture

e

) testing showed greater

n chloride (HCl) and

, 80–98% capture of

0% capture of mercury

0% capture of selenium.

• Gypsum stacking proved effective for producing

wallboard/cement-grade gypsum.

Operational• FRP-fabricated equipment proved durable both

structurally and chemically, eliminating the need fora flue gas prescrubber and reheat.

• FRP construction combined with simplicity of design resulted in 97% availability at low ash loadings

and 95% at high ash loadings, precluding the needfor a spare reactor module.

• Simultaneous SO2 and particulate control were

achieved at flyash loadings reflective of an electrostatic (ESP) with marginal performance.

10/99

Operation completed 12/94

Project completed/final

report issued 10/99*

**

Economic• Final results are not yet available. However, elimination of the need for flue gas prescrubbing, reheat, and

spare module requirement should result in capitalrequirements far below those of contemporary conventional FGD systems.
Environmental Control Devices

w Ash Elevated Ash Cumulative

ase Phase for Project

750 7,250 19,000

430 6,310 18,340

,600 5,210 13,810

,800 5,490 14,290

8 0.95 0.967 0.95 0.973 0.72 0.75

ed divided by the hours called upon to operate

able divided by the total hours in the period

ed divided by the total hours in the period

xhibit 5-16

f CT-121 Scrubber

Exhibit 5-17

SO2 Removal Efficiency

he more common spray

ion systems in that a

ce of the usual spray

ngement. Pumping of

 tank is intermittent.

eed essentially uninter

watered gypsum crys

 large centrifugal

ing crystal attrition and

7 months, including

ich approximately

t 5-16 summarizes

culate loading included

recipitator (ESP) com

erm testing was con

ergized to simulate a

121 retrofit to a boiler

culate collection device. The SO2 removal efficiency was measured under five different inlet concentrations with coals averaging 2.4% sulfur and ranging from 1.2– 4.3% sulfur (as burned). Operating Performance Use of FRP construction proved very successful. Because their large size precluded shipment, the JBR and lime- stone slurry storage tanks were constructed on site. Ex- cept for some erosion experienced at the JBR inlet transi- tion duct, the FRP-fabricated equipment proved to be durable both structurally and chemically. Because of the high corrosion resistance, the need for a flue gas prescrubber to remove chlorides was eliminated. Simi- larly, the FRP-constructed chimney proved resistant to the corrosive condensates in wet flue gas, precluding the need for flue gas reheat. Availability of the CT-121 scrubber during the low ash test phase was 97%. Availability dropped to 95% under the elevated ash-loading conditions due largely to sparger tube plugging problems precipitated by flyash

agglomeration on the sparger tubewalls during high ash loading whenthe ESP was deenergized. The highreliability demonstrated verified thata spare JBR is not required in acommercial design offering.Environmental PerformanceExhibit 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 utilizationremained above 97% throughout the demonstration.Long-term particulate capture performance was testedwith a partially deenergized ESP (approximately 90%efficiency), and is summarized in Exhibit 5-18.

Analysis indicated that a large percentage of the

outlet particulate matter is sulfate, likely a result of acidmist and gypsum carryover. This reduces the estimate ofash mass loading at the outlet to approximately 70% ofthe measured outlet particulates.

For particulate sizes greater than 10 microns, capture

efficiency was consistently greater than 99%. In the 1–10micron range, capture efficiency was over 90%. Between0.5 and 1 micron, the particulate removal dropped attimes to negligible values possibly due to acid mistcarryover entraining particulates in this size range. Below0.5 micron, the capture efficiency increased to over 90%.Calculated air toxics removals across the CT-121 JBR,
Program Update 1999 5-39

Exhibit 5-19

CT-121 Air Toxics Removal

(JBR Components Only)

0

20406080

100

Chloride Fluoride Arsenic Cadmium Mercury Selenium Vanadium

Removal Efficiency (%)

Exhibit 5-18

e Capture Performance

 Marginally Operating)

r Inlet Mass Outlet Mass Removal

Loading Loading* Efficiency

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

1.288 0.02 97.7

1.392 0.010 99.3

0.325 0.005 98.50.303 0.006 98.0

or units constructed after September 18, 1978. Plant Yates

an existing unit.

en during the demon

19.

ypsum stacking method

. Although chloride

stack due to the closed

concentrations often

ater the chloride concen

 less than 50 ppm, suit

pplications. The reduc

buted to rainwater wash

lyses are not yet avail

1 technology offers sig

RP construction elimi

and reheating flue gas.

tes the need for a spare

moval capability pre

apital-intensive) ESP

tough environmental

CommercialApplicationsInvolvement 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 compliance strategy. Since the CCT Programdemonstration, over 8,200 MWe equivalent of CT-121 FGD capacity has been soldto 16 customers in seven countries.

The project received Power

magazine’s 1994 Powerplant Award. Otherawards include the Society of PlasticsIndustries’ 1995 Design Award for the misteliminator, the Georgia Chapter of the Airand Waste Management Association’s1994 Outstanding Achievement Award,and the Georgia Chamber of Commerce’s1993 Environmental Award.

ContactsDavid P. Burford, Project Manager, (205) 992-6329

Southern Company Services, Inc.P.O. Box 2625Birmingham, AL 35202-2625(205) 992-7535 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, DOE/NETL, (412) 386-5991References• A Study of Toxic Emissions from a Coal-Fired Power

Plant Utilizing an ESP while Demonstrating the CCTCT-121 FGD Project. Final Report. Report No.DOE/PC/93253-T1. Radian Corporation. June 1994.(Available from NTIS as DE94016053.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Demonstration of InnovativeApplications of Technology for the CT-121 FGD Process. Southern Company Services, Inc. Report No.DOE/FE-0158. U.S. Department of Energy. February1990. (Available from NTIS as DE9008110.)
Environmental Control Devices
Program Update 1999 5-41

nvironmental Control Devices

NO

x Control Technologies
Environmental Control Devices

Advanced

iques for a

SCS)

EPRI)—cofunder

n (Foster Wheeler)—

ustry—cofunder

y—technology supplier

a Power Company’s

(LNB) with advanced

eneric NOx Control

mputer software.

lfur

900 100%

526 41

374 59

Project ObjectiveTo achieve 50% NO

x

 reduction with the LNB/AOFA

system; to determine the contributions of AOFA and LNBto NO

x reduction and the parameters for optimal LNB/

AOFA performance; and to assess the long-term effects ofLNB, AOFA, combined LNB/AOFA, and the GNOCISadvanced digital controls on NOx reduction, boiler performance, and peripheral equipment performance.

Technology/Project DescriptionAOFA involves (1) improving OFA mixing to lower overall stoichiometry (less total excess air) while still avoidinghigh unburned combustible losses, (2) allowing deeperstaging (sub-stoichiometric conditions in the flame zone,i.e., reducing atmosphere) without increasing combustiblelosses, and (3) introducing “boundary air” at the boilerwalls to prevent corrosion caused by the reducingatmosphere.

In the Foster Wheeler Controlled Flow/Split Flame

(CFSF) LNB, fuel and air mixing (staged combustion) iscontrolled for localized, individual burner flames, ratherthan on a furnace-wide basis, by regulating the primary air/fuel mixture, velocities, and turbulence to create a fuel-richcore with sufficient air to sustain combustion at a severelysub-stoichiometric air/fuel ratio. The burner also controlsthe rate at which additional air necessary to complete combustion is mixed with the flame solids and gases so as tomaintain a deficiency of oxygen until the remaining combustibles fall below the peak NOx producing temperature

(around 2,800 °F). The final excess air then can be allowedto mix with the unburned products so that combustion iscompleted at a relatively low temperature.

The project has been reopened and extended to demonstrate an overall unit optimization system.

AIR

WINDBOX WINDBOX

BOILER

ECONOMIZER

ADVANCED

OVERFIRE AIR

PORTS

COMBUSTION

AIR

PULVERIZED

COAL

LOW-NO

BURNERS

X

ASH

BOUNDARY AIR PORTS

LOW-NO

BURNERS

X

DRY WASTE TO DISPOSAL

PULVERIZED

COAL

AOFA

PORTS

AIR

AIR

PREHEATER STACK

ELECTROSTATIC

PRECIPITATOR
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

**Years omitted

1 2

Program Update 1999 5-43

1990 1991 1992 1993 1994 1996 1998 1999 2001

6/90

Design and Construction

erative 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 3/91Operation completed, AOFA 3/91

Operation initiated, LNB 4/91Construction completed, LNB 4/91

Operation completed, LNB 1/92

Operation initiated, LNB/AOFA 5/93

Operation

Operation completed, LNB/AOFA 8/93

Operation initiated,LNB/AOFA with digital controlsystem 6/94

gnition (LOI) was near

f 5%) for LNB alone and

mental NO

x

 reduction

roximately 17%, with

g from other operational

ficiency gain of 0.5 per

fly ash LOI levels of 1–3

ction in NOx emissions of

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, which represents a 68% reduction

from baseline conditions.

• There was not a significant difference in emissions of

trace metals, acid gases, and volatile organic compounds between AOFA and LNB operations. However, there was a slight downward trend in emissionsduring LNB/AOFA operation.

1 2

Final report

(Phase 1-3B)

issued 1/98

**

GNOCIS testinginitiated 2/96

Final report(Phase 4)issued 9/98

Project completed/

final report issued 1/01*

1/01

**

Cooperative agreement

resigned 9/15/99

**

Economic• Capital cost for a 500-MWe wall-fired unit is $8.8/

kW for AOFA alone, $10.0/kW for LNB alone, $18.8/kW for LNB/AOFA, and $0.5/kW for GNOCIS.

• Estimated cost of NO

x removal is $86/ton using

LNB/AOFA.
Environmental Control Devices

Exhibit 5-22

Typical Trade-Offs in Boiler Optimization

Exhibit 5-21

NOx vs. LOI Tests—All Sensitivities

t 5-20

ce Test Results

zation of the unit in an

 1989 to April 1990.

m August 1990 to

on of the LNBs in the

were tested from July

 three-month delay

city. Post-LNB in

increases in combus

oading to the electro

 affected the unit’s

LNB/AOFA testing was

ugust 1993, excludingnd for portions of the

ulate emissions. How

oning system was added

ch enabled the unit to

sting to continue.

 AOFA, LNB, and

ibit 5-20, despite im

e replacement of the

n not only because of

the associated efficiency loss, but a potentialloss of fly ash sales. The increased carbon inthe fly ash renders the material unsuitable foruse in making concrete.

During October 1992, SCS conducted

parametric testing to determine the relationship between NOx and LOI emissions. The

parameters tested were: excess oxygen, millcoal flow bias, burner sliding tip position,burner outer register position, and burnerinner register position. Nitrogen oxide emissions and LOI levels varied from 0.44–0.57 lb/106 Btu and 3–10%, respectively. Asexpected, 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-offsbetween 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 inwhich all sensitivities are plotted. This exhibit showsthat, for excess oxygen, mill bias, inner register, andsliding tip, any adjustments to reduce NOx emissions are

at the expense of increased fly ash LOI. In contrast, the slope of the outer register characteristicsuggests improvement in both NOx emissions and

LOI can be achieved by adjustment of thisdamper. However, due tothe relatively small impact

of the outer register adjustment on both NOx and LOI,

it is likely the positive NOx

/

LOI slope is an artifact ofprocess noise.

A subsidiary goal of the

project was to evaluateadvanced instrumentationand controls (I&C) as applied to combustion control.

The need for more sophisticated I&C equipment is illustrated in Exhibit 5-22. There are trade-offs in boiler operation, e.g., as excess air increases, NOx increases, LOI

decreases, and boiler losses increase. The goal is to findand maintain an optimal operating condition. The I&Csystems tested included GNOCIS and carbon-in-ashanalyzers.

The GNOCIS software applies an optimizing procedure to identify the best set points for the plant, which are

implemented automatically without operator intervention(closed-loop), or conveyed to the plant operators forimplementation (open-loop). The major elements of
Program Update 1999 5-45

5-23

 of GNOCIS

-23. The GNOCIS sys

uced NOx emissions by

ash LOI by 1–3 percent

fficiency by 0.5 percent

he AOFA, LNBs, and

Ox reductions of 24, 48,

weighted average of NOx

 and 63%, respectively,

Although the long-term

s a 68% reduction from

ion of the incremental

n the LNB and the LNB/

t of operational changes

OFA.

ong-term NOx emissions

NB/AOFA test phase.

ad, long-term NOx emis

h was consistent with

er long-term testing had

4 lb/106 Btu for AOFA

LNB only, respectively.

For reference, long-term baseline testing revealed aninitial NOx emission rate of 1.4 lb/106 Btu.

Air toxics testing was conducted for AOFA and

LNB/AOFA operation. There was not a significant difference in emissions of trace metals, acid gases, and volatileorganic compounds for the two tests. There was a slightdownward trend, however, in emissions during LNB/AOFA operation. For elements associated with particulate matter, ten show lower mean emissions during LNB/AOFA operation (barium, beryllium, chromium, cobalt,copper, lead, manganese, nickel, phosphorus, and vanadium); only two (arsenic and cadmium) show highermean emissions during LNB/AOFA operation. Totalparticulate matter emissions also were lower during LNB/AOFA operation; however, this was more an indication ofESP performance rather than burner configuration.

EconomicEstimated 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 and AOFA is $333,351. Efficiency isdecreased by 1.3 percent, and the NOx reduction is 68

percent of baseline, or 11,615 tons/year. The capital costis $8,300,000 and the calculated cost of NOx removed is

$86/ton.

The addition of GNOCIS to the LNB/AOFA, using

the actual 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

(834 tons/year), and the capital cost is $250,000. Thecalculated cost per ton of NOx removed is -$299 (net gain

due to increased efficiency).

Project ExtensionOn September 15, 1999, the cooperative agreement wasextended and work has now begun on the design andinstallation of an overall unit optimization system. Thework will be carried out as part of Phase 4 of the project.The overall goal of Phase 4 is to demonstrate on-lineoptimization techniques for power plant processes and forthe unit as a whole. The major tasks include unit optimization, boiler optimization, intelligent sootblowing, andprecipitator modeling/optimization.Commercial ApplicationsThe technology is applicable to the 422 existing preNSPS wall-fired boilers in the United States, which burna variety of coals. The GNOCIS technology is applicableto all fossil fuel-fired boilers, including units fired withnatural gas and units cofiring coal and natural gas.

The host has retained the technologies for commercial use. Foster Wheeler has equipped 86 boilers with

low-NOx burner technology (51 domestic and 35 international)—1,800 burners for over 30,000 MWe capacity.

ContactsJohn N. Sorge, (205) 257-7426

ICCT Project ManagerSouthern Company Services, Inc.P.O. Box 2625Birmingham, AL 35202-2625jnsorge@southernco.com

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James R. Longanbach, NETL, (304) 285-4659

jlonga@netl.doe.gov

References• 500-MW Demonstration of Advanced Wall-Fired

Combustion Techniques for the Reduction of NitrogenOxide (NOx) Emissions from Coal-Fired Boilers–

Phases 4—Digital Control System and Optimization. Southern Company Services, Inc. September1998.
Environmental Control Devices

s

Coal

lone Boiler

any—cofunder and

coal handling

—cofunder

ergy and Natural

iler operators)—

consin Power and Light

, Unit No. 2)

y’s coal-reburning

 1.15% sulfur,

uminous, 0.27% sulfur,

609 100%

788 46

821 54

Project ObjectiveTo demonstrate the technical and economic feasibility ofachieving greater than 50% reduction in NOx emissions

with no serious impact on cyclone combustor operation,boiler performance, or other emission streams.Technology/Project DescriptionBabcock & Wilcox Coal Reburn reduces NO

x

 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 reburningzone above the cyclones to create an oxygen-deficientcondition. The NO

x formed in the cyclone burners reacts

with the resultant reducing flue gas and is converted into

nitrogen in this zone. Completion of the combustionprocess occurs in the third zone, called the burnout zone,where the balance of the combustion air is introduced.

Coal Reburn can be applied with the cyclone burners

operating within their normal, noncorrosive, oxidizingconditions, thereby minimizing any adverse effects ofreburn on the cyclone combustor and boiler performance.

This project involved retrofitting an existing

100-MWe cyclone boiler that is representative of a largepopulation of cyclone units.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 5-47

r than 50% NOx reduc

bituminous and PRB

had the greatest effect

o maintaining reburn

oviding necessary

ation, and mixing.

tic precipitator (ESP)

d by Coal Reburn with

put was 29–30% at full

oderate loads.

Operational• No major boiler performance problems were experienced with Coal Reburn operations.• Boiler turndown capability was 66%, exceeding the

50% goal.

• ESP efficiency improved slightly during Lamar coal

testing and did not change with PRB coal.

• Coal fineness levels above the nominal 90% through

200 mesh were maintained, reducing unburned carbonlosses (UBCL).

• UBCL was the only major contributor to boiler efficiency loss, which was 0.1, 0.25, and 1.5% at loads of

110-, 82-, and 60-MWe, respectively, when usingLamar coal. With PRB coal, the efficiency loss rangedfrom zero at full load to 0.3% at 60-MWe.

• Superior flame stability was realized with PRB coal,

contributing to better NOx control than with Lamar

coal.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction

nt

90

4/90 12/91

Operation

3/94

Project completed/final report issued 3/94

Operationcompleted 12/92 Operation initiated 12/91

Construction completed 11/91Preoperational tests initiated 11/91Environmental monitoring plan completed 11/18/91

NEPA process completed (EA) 2/12/91

Design completed 6/91

Ground breaking/construction started 11/90

• Expanded volumetric fuel delivery with reburn burners enabled switching to PRB low-rank coal without

boiler derating.

Economic• Capital costs for 110- and 605-MWe plants were

$66/kW and $43/kW, respectively.

• Levelized 10- and 30-year busbar power costs for a

110-MWe plant were 2.4 and 2.3 mills/kWh, respectively.

• Levelized 10- and 30-year busbar power costs for a

605-MWe plant were 1.6 and 1.5 mills/kWh, respectively. (Costs are in 1990 constant dollars.)
Environmental Control Devices

Boiler Load110-MWe 82-MWe 60-MWe

0.39/52 0.36/50 0.44/36

0.1 0.25 1.5

0.34/55 0.31/52 0.30/53

0.0 0.2 0.3

ibit 5-24

rn Test Results

Wisconsin Power and Light Company’s Nelson Dewey

Station hosted the successful demonstration of Coal Reburn.

t only 15% of the pre

ty, they contribute 21%

oal-fired units. This is

herent turbulent, high

Consequently, cyclone

ion under the CAAA

owever, at the time of

ost-effective combus

lone boiler NOx control.

urn offers an economic

o the environmental

yclone combustor

mance complications

combustion NOx con

relatively higher capital

s performed firing

mar), as it is typical of

rating cyclones. Subbi

ormed to evaluate the

operation. Wisconsin

Power and Light’s strategy to meet Wisconsin’s sulfuremission limitations as of January 1, 1993, was to firelow-sulfur coal.Environmental PerformanceThree sequences of testing of Coal Reburn used Lamarcoal. Parametric optimization testing was used to set upthe automatic controls. Performance testing was run withthe unit in full automatic control at set load points. Longterm testing was performed with reburn in operationwhile the unit followed system load demand requirements. PRB coal was tested by parametric optimizationand performance modes. Exhibit 5-24 shows changes inNOx emissions and boiler efficiency using the reburn

system for various load conditions and coal types.

Coal Reburn tests on both the Lamar and PRB coals

indicated that variation of reburn-zone stoichiometry wasthe most critical factor in changing NOx emissions levels.

The reburn-zone stoichiometry can be varied by alternating the air flow quantities (oxygen availability) to thereburn burners, the percent reburn heat input, the gasrecirculation flow rate, or the cyclone stoichiometry.

Hazardous air pollutant (HAP) testing was performed

using Lamar test coal. HAP emissionswere generally well within expectedlevels, and emissions with Coal Reburnwere comparable to baseline operation.No major effect of reburn on tracemetals partitioning was discernible.None of the 16 targeted polynucleararomatic semi-volatile organics (controlled under Title III of CAAA) waspresent in detectable concentrations, ata detection limit of 1.2 parts per billion.Operational PerformanceFor Lamar coal, the full-, medium-, andlow-load efficiency losses, due to unburned carbon, were higher than thebaseline by 0.1, 0.25, and 1.5% respectively. Full-, medium-, and low-load efficiency losses with PRB coal were 0.0, 0.2, and 0.3%, respectively. Coal Reburn burner flame stability improved with PRB coal.During Coal Reburn operation with Lamar coal, the operators continually monitored boiler internals for in- creased ash deposition and the on-line performance moni- toring system for heat transfer changes. At no time throughout the system optimization or long-term opera- tion period were any slagging or fouling problems ob- served. In fact, during scheduled outages, internal boiler inspections revealed that boiler cleanliness had actually improved. Extensive ultrasonic thickness measurements were taken of the furnace wall tubes. No observable decrease in wall tube thickness was measured. Another significant finding was that Coal Reburn minimizes and possibly eliminated a 0–25% derating normally associated with switching to subbituminous coal in a cyclone unit. This derating results from using a lower Btu fuel in a cyclone combustor, which has a limited coal feed capacity. The Coal Reburn system transferred about 30% of the coal feed out of the cyclone to the reburn burn- ers, bringing the cyclone feed rate down to a manageable level, while maintaining full-load heat input to the unit.
Program Update 1999 5-49

Babcock & Wilcox Coal

ained by Wisconsin Power

l at the Nelson Dewey

Exhibit 5-25

Coal Reburn Economics

(1990 Constant Dollars)

Plant Size

Costs 110-MWe 605-MWeTotal capital cost ($/kW) 66 43Levelized busbar powercost (mills/kWh)

10-year life 2.4 1.630-year life 2.3 1.5

Annualized cost ($/ton of NOx removed)

10-year life 1,075 40830-year life 692 263

pital and levelized rev

d using the “Electric

mic Premises” for retrofit

addition, annualized

re developed for 110-

0 and 30 years. The

wn in Exhibit 5-25.

rofit conditions and did

vings from use of low

sociated coal handling

were taken into account. Site-specific parameters thatcan significantly impact these retrofit costs includedthe state of the existing control system, availability offlue gas recirculation, space for coal pulverizers, spacefor reburn burners and overfire air ports within theboiler, scope of coal-handling modification, sootblowing capacity, ESP capacity, steam temperature controlcapacity, and boiler circulation considerations.Commercial ApplicationsCoal Reburn is a retrofit technology applicable to a widerange of utility and industrial cyclone boilers. The currentU.S. Coal Reburn market is estimated to be approximately 26,000 MWe and consists of about 120 unitsranging from 100- to 1,150-MWe with most in the100- to 300-MWe range.

The project technology has been retained by Wisconsin Power and Light for commercial use.

ContactsDot K. Johnson, (330) 829-7395

McDermott Technologies, Inc.1562 Beeson StreetAlliance, OH 44601(330) 821-7801 (fax)dot.k.johnson@mcdermott.com

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 & WilcoxCompany. February 1994. (Available from NTIS asDE94013052, Appendix 1 as DE94013053,Appendix 2 as DE94013054.)

• Public Design Report: Coal Reburning for Cyclone

Boiler NO

x

 Control. The Babcock & Wilcox Company. August 1991. (Available from NTIS as

DE92012554.)

• Comprehensive Report to Congress on the Clean

Coal Program: Demonstration of Coal Reburningfor Cyclone Boiler NOx Control. Report No. DOE/

FE-0157. U.S. Department of Energy. February 1990.(Available from NTIS as DE90008111.)
Environmental Control Devices

s

stration of

ner Retrofit

pany—cofunder and

—cofunder

ofunder

nder

ofunder

er

funder

ayton Power and Light

 No. 4)

’s low-NOx cell burner

392 100%

800 48

592 52

the air is directed to the upper port of each cell to complete the combustion process. The fuel-bound nitrogencompounds are converted to nitrogen gas, and the

reduced flame temperature minimizes the formation ofthermal NO

x

.

The demonstration was conducted on a Babcock &

Wilcox-designed, supercritical, once-through boilerequipped with an electrostatic precipitator (ESP). Thisunit, which is typical of cell burner boilers, contained 24two-nozzle cell burners arranged in an opposed-firingconfiguration. Twelve burners (arranged in two rows ofsix burners each) were mounted on each of two opposingwalls of the boiler. All 24 standard cell burners wereremoved and 24 new LNCBs® were installed. Alternate

LNCB® on the bottom rows were inverted, with the air

port then being on the bottom to ensure complete combustion in the lower furnace.

Project ObjectiveTo demonstrate, through the first commercial-scale fullburner retrofit, the cost-effective reduction of NOx from a

large baseload coal-fired utility boiler with LNCB® technology; to achieve at least a 50% NOx reduction without

degradation of boiler performance at less cost than that ofconventional low-NO

x

 burners.

Technology/Project DescriptionThe LNCB® technology replaces the upper coal nozzle of

the standard two-nozzle cell burner with a secondary airport. The lower burner coal nozzle is enlarged to the samefuel input capacity as the two standard coal nozzles. TheLNCB® operates on the principle of staged combustion to

reduce NO

x emissions. Approximately 70% of the total

air (primary, secondary, and excess air) is suppliedthrough or around the coal-feed nozzle. The remainder of 

bcock & Wilcox Company.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 5-51

ng (all mills in service)

 range of 53.0–55.5%,

 at loads of 605-MWe,

pectively.

 (all mills in service)

ction of 58% (over

 (one mill out of service)

ction of 60% (over

5 ppm at full load with

rformance remained

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 toa lower boiler economizer outlet gas temperature.

• Boiler corrosion with LNCB® was roughly equivalent

to boiler corrosion rates prior to retrofit.

Economic• Capital cost for a 600-MWe plant was $9/kW

(1994$).

• Levelized cost for a 600-MWe plant was estimated at

0.284 mills/kWh and $96.48/ton of NOx removed.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operationinitiated 12/91

10/90

Operation

Design and

reaward Construction

12/91

 8/10/90

Project completed/final report issued 12/95

12/95

Operation completed 4/93

Construction completed 11/91Preoperational tests initiated 11/91

ve agreement

ded 10/11/90

pleted 10/90

Environmental monitoring plancompleted 8/9/91

Ground breaking/construction started 9/91
Environmental Control Devices

urners currently com

0-MWe of pre-NSPS

ll burners are designed

. The tight burner

e the flame size while

nd unit efficiency.

t the rapid heat release

s of NOx

.

 LNCB® has been de

and combustion air. A

shing delayed fuel-air

aterwall panels. A

sts and outage time

ompared to installing

w-NOx burners. LNCB®

o address NOx reduction

esulted in excessive CO

eling, a revised configu

e problem without

 The modification was

capabilities.

to establish optimal

ization tests were con

vironmental and opera

easurements were

 and the other by an

data accuracy. Conse

ge reflecting the two

eduction achieved at full

d from 53.0–55.5%.

 load, the average NOx

. Average NOx reduc

0-MWe) ranged from

350-MWe), average

NOx 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. 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

relative to baseline because baseline calibration was notsufficiently refined. However, accurate measurementswere made 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 emissions at full load with all mills in service was 28–55 ppmand 20–38 ppm with one mill out of service. At intermediate loads (about 460-MWe), CO emissions were 28–45ppm and at low loads (about 350-MWe), 5–27 ppm.

Particulate emissions were minimally impacted. The

LNCB® had little effect on flyash resistivity, largely due to

SO3 injection, and therefore ESP removal efficiency remained very high. Baseline ESP collection efficiencies

for 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. Forthe same conditions, in the same sequence with LNCB®

in operation, ESP collection efficiencies were 99.43,99.12, and 99.35%, respectively.Operational PerformanceFurnace exit gas temperature, or secondary superheaterinlet temperature, initially decreased by 100 oF but eventually rose to within 10 oF of baseline conditions. TheUBCL increased by approximately 28% for all tests. Themost significant increase from baseline data occurred for atest with one mill out of service. A 52% increase inUBCL resulted in an efficiency loss of 0.69%.

Boiler efficiency showed very little change from

baseline. The average for all mills in service increased by0.16%. The higher post-retrofit efficiency was attributedto a decrease in dry gas loss with lower economizer gas

outlet temperature (and subsequent lower air heatergas outlet temperature), offsetting UBCL, and CO emission losses. Also, increased coal fineness mitigatedUBCL.

Because sulfidation is the primary corrosion mechanism in substoichiometric combustion of sulfur-containing coal, H2S levels were monitored in the boiler. After

optimizing LNCB® operation, levels were largely at the

lower detection limit. There were some higher localreadings, but corrosion panel tests established that corrosion rates with LNCB® were roughly equivalent to preretrofit rates.

Ash sample analyses indicated that ash deposition

would not be a problem. The LNCB® ash differed little

from baseline ash. Furthermore, the small variationsobserved in furnace exit gas temperature between baseline

Single LNCB® Retrofit.
Program Update 1999 5-53

The levelized cost of electricity was estimated at 0.284mills/kWh or $96.48/ton of NOx removed.

Commercial ApplicationsThe low cost and short outage time for retrofit makethe LNCB® design the most cost-effective NOx control

technology available today for cell burner boilers. TheLNCB® system can be installed at about half the cost

and time of other commercial low-NO

x

 burners.

Dayton Power & Light has retained the LNCB® for

use in commercial service. Seven commercial contractshave been awarded for 172 burners, valued at $24 million. LNCB® have already been installed on more than

4,600 MWe of capacity.

The demonstration project received R&D

magazine’s 1994 R&D Award.ContactsDot K. Johnson, (330) 829-7395

McDermott Technologies, Inc.1562 Beeson StreetAlliance, OH 44601(330) 821-7801 (fax)dot.k.johnson@mcdermott.com

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

The connections to the LNCB® are viewed from outside the boiler.

nge in furnace slagging.

were unaffected by

formed for a 600-MWe

ation in the midwest

 medium-volatile bitumi

cal fuel. For a baseline

Btu and a 50% reduction

 was $9/kW (1994$).

References• Final Report: Full-Scale Demonstration of LowNO

x Cell Burner Retrofit. Report No. DOE/PC/

90545-T2. The Babcock & Wilcox Company. December 1995. (Available from NTIS as DE96003766.)

• Public Design Report: Full-Scale Demonstration

of Low-NOx Cell Burner Retrofit. Report No. DOE/

PC/90545-T4. The Babcock & Wilcox Company.August 1991. (Available from NTIS as DE92009768.)

• Comprehensive Report to Congress on the Clean

Coal Technology Program: Full-Scale Demonstration of Low-NOx Cell-Burner Retrofit. The Babcock

& Wilcox Company. Report No. DOE/FE-0197P.U.S. Department of Energy. July 1990. (Availablefrom NTIS as DE90018026.)

within the boiler.
Environmental Control Devices

Reburning

ers on a

ch Corporation

do—cofunder and host

—cofunder

—cofunder

hnology supplier

c Service Company of

 No. 3)

ch Corporation’s gas

 Wheeler Energy

r, 10% ash

258 100%

790 50

468 50

he emissions of NOx

boiler firing low-sulfur

low-NOx burners

t of GR-LNB on boiler

A series of parametric tests were performed on the

gas reburning system, varying operational control parameters, and assessing the effect on boiler emissions, completeness of combustion (carbon-in-ash or loss-on-ignition), thermal efficiency, and heat rate. A one-year, longterm testing program was performed in order to judge theconsistency of system outputs, assess the impact of longterm operation on the boiler equipment, gain experiencein operating GR-LNB in a normal load-following environment, and develop a database for use in subsequent GRLNB applications. Both first- and second-generation gasreburning tests were performed.

Technology/Project DescriptionGas reburning involves firing natural gas (up to 25% oftotal heat input) above the main coal combustion zone in aboiler. This upper-level firing creates a slightly fuel-richzone. NO

x drifting upward from the lower region of the

furnace is stripped of oxygen as the reburn fuel is combusted in this zone and converted to molecular nitrogen.Low-NO

x burners positioned in the coal combustion zone

retard the production of NOx by staging the burning process so that the coal-air mixture can be carefully controlled at each stage. The synergistic effect of adding a

reburning stage to wall-fired boilers equipped with lowNO

x

 burners was intended to lower NO

x emissions by up

to 70%. Gas reburning was demonstrated with and without the use of recirculated flue gas.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

**Years omitted

1 2

Program Update 1999 5-55

sions from a pre-con

06 Btu to 0.46 lb/106 Btu

uction.

corporated flue gas

with LNB, reduced NOx

lb/106 Btu (at 3.25% O2),

% gas heat input rate.

ut flue gas recirculation,

uced NO

x

 emissions to

64% NOx reduction with

tion GR with LNB were

sions by up to 70%

average was approxi

1990 1991 1992 1993 1994 1995 1996 1998 1999

reaward Operation

Design and Construction

10/90 11/92

 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

Operation initiated 11/92Constructioncompleted 11/92

• After modifying the overfire air system to enhance

penetration and turbulence (as part of second-generation GR), CO emissions were controlled to acceptablelevels at low gas heat input rates.

• SO2 emissions and particulate loadings were reduced

by the percentage heat input supplied by GR.

Operational• Boiler efficiency decreased < 1.0%.

• There was no measurable boiler tube wear and only a

small amount of slagging.

• Carbon-in-ash and CO levels were acceptable for firstand second-generation GR with LNB, but not with

LNB alone.

Long-term operations started 4/93

Operation completed 1/95

Restorationcompleted 11/95

10/98

Project completed/final

report issued 10/98

**

Economic• Capital cost for a GR-LNB retrofit of a 300-MWe

plant is $26.01/kW (1996$) plus the gas pipeline cost,if not in place ($12.14/kW for GR only and $13.87/kWfor LNB only).

• Operating costs were related to the gas/coal cost differential and the value of SO2 emission allowances because GR reduces SO2 emissions when displacing

coal.
Environmental Control Devices

GR GenerationFirst Second

Baseline (lb/106 Btu) 0.73 0.73Avg NOx reduction (%)

LNB 37 44GR-LNB 66 64

Avg gas heat input (%) 18 12.5

Exhibit 5-26

NO

x

 Data from Cherokee

Station, Unit No. 3

ring for the Foster

n the boiler wall.

t GR-LNB offers a cost

ction on wall-fired

formance approached

n (SCR) but at signifi

 of cost-effective tech

he need for NOx reduc

beyond what is cur

CAAA. Title I of the

ment and is currently

uction in many regions

nd evaluated on a 172-

Babcock & Wilcox

d unit. The GR system,

including an overfire air system, was designed andinstalled by Energy and Environmental Research Corporation. The LNBs were designed and installed byFoster Wheeler Energy Corp.

Parametric testing began in October 1992 and was

completed in April 1993. The parametric tests examinedthe effect of process variables (such as zone stoichiometricratio, percent gas heat input, percent overfire air, andload) on NOx reduction, SO2 reduction, CO emissions,

carbon-in-ash, and heat rates. The baseline performanceof the LNB was also established.Environmental PerformanceAt a constant load (150-MWe) and a constant oxygenlevel at the boiler exit, NOx emissions were reduced with

increasing gas heat input. At gas heat inputs greater than10%, NOx emissions were reduced marginally as gas heat

input increased. Natural gas also reduced SO2 emissions

in proportion to the gas heat input. At the 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 usingnatural 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 testwere to obtain operating data over an extended periodwhen the unit was under routine commercial service,determine the effect of GR-LNB operation on the unit, andobtain incremental maintenance and operating costs withGR. During long-term testing, it was determined that fluegas recirculation had minimal effect on NOx emissions.

 A second series of tests were added to the demonstration to evaluate a modified or second-generation system. Modifications are summarized as follows:

• The flue gas recirculation system, originally designed to provide momentum to the natural gas, was

removed. (This change significantly reduced capitalcosts.)

• Natural gas injection was optimized at 10% gas heat

input compared to the initial design value of 18%.The removal of the flue gas recirculation systemrequired installation of high-velocity injectors,which made greater use of available natural gaspressure. (This modification reduced natural gasusage and thus operating costs.)

• Overfire air ports were modified to provide higher jet

momentum, especially at low total flows.

Over 4,000 hours of operation were achieved, with

the results as shown in Exhibit 5-26. Although the 37%NO

x reduction performance of LNB was less than the

expected 45%, the overall objectives of the demonstration were met. Boiler efficiency decreased by only 1%during gas reburning due to increased moisture in thefuel resulting from natural gas use. Further, there wasno measurable tube wear, and only small amounts ofslagging occurred during the GR-LNB demonstration.However, with LNB alone, carbon-in-ash and CO couldnot be maintained at acceptable levels.
Program Update 1999 5-57

in which the economic

owing site-specific fac

d

.

 GR-LNB is expected to

ction with a gas heat

 estimate for a 300-MWe

kW (1996 $) plus gas

cost includes both equip

 15% contingency. The

s can be easily separated

e independent systems.

m only is estimated at

pital cost is $13.87/kW.

ntirely related to the

d coal and reduced by the

 received due to absence

ential of $1.00/106 Btu

 than coal on a heating

s estimated to decline by

as calculated using a

Btu. Overfire air booster

ill be partially offset by

No additional operating

ncrease in maintenance

de for overhead, taxes,

ssumptions and assum

95/ton (Feb. 1996$), the

n per year and the NOx

ant 1996$).

Commercial ApplicationsCurrent estimates indicate that about 35 existing wallfired utility installations, plus industrial boilers, couldmake immediate use of this technology. The technologycan be used in retrofit, repowering, or greenfield installations. There is no known limit to the size or scope of theapplication of this technology combination. GR-LNB isexpected to be less capital intensive, or less costly, thanselective catalytic reduction. GR-LNB functions equallywell with any kind of 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

has been awarded two contracts to provide gas-reburning systems for five cyclone coal-fired boilers: TVA’sAllen Unit No. 1, with options for Unit Nos. 2 and 3(identical 330-MWe Units); and Baltimore Gas &Electric’s C.P. Crane, Unit No. 2, with an option for UnitNo. 1 (similar 200-MWe Units). Use of the technologyalso extends to overseas markets. One of the firstinstallations of the technology took place at theLadyzkin State Power Station in Ladyzkin, Ukraine.

This demonstration project was one of two that received the Air and Waste Management Association’s

1997 J. Deanne Sensenbaugh Award.ContactsBlair A. Folsom, Sr. V.P., (949) 859-8851, ext. 140

General Electric Energy and Environmental 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. July1998.

• Guideline Manual: Gas Reburning—Low-NOx

Burner System, Cherokee Station Unit No. 3, PublicService Company of Colorado. Final Report. July1998.

• Evaluation of Gas Reburning and Low-NOx Burners

on a Wall-Fired Boiler (Long-Term Testing, April1993–January 1995). Report No. DOE/PC/90547-T20. Energy and Environmental Research Corporation. June 1995. (Available from NTIS asDE95017755.)

• Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler (Optimization Testing,

November 1992–April 1993). Report No. DOE/PC/90547-T19. Energy and Environmental ResearchCorporation. June 1995. (Available from NTIS asDE95017754.)
Environmental Control Devices

s

eburning

 NO

x

 Control

orporation

nd cofunder

 Coal Company)—

plier

arch Corporation

r

and Development

arch Corporation—

New York State Electric

Station, Unit No. 1)

Eastman Kodak

Plant, Unit No. 15)

n Station) and

Kodak) technologies

ntially-fired boiler

oiler

pany.

n Engineering, Inc.

CoalPittsburgh seam bituminous, medium- to high-sulfur(3.2% sulfur and 1.5% nitrogen at Milliken and 2.2%sulfur and 1.6% nitrogen at Kodak Park)Project FundingTotal project cost $9,096,486 100%DOE 2,701,011 30Participant 6,395,475 70Project ObjectiveTo achieve at least 50% 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 DescriptionThe reburn coal, which can comprise up to 30% of thetotal fuel, is micronized (pulverized to achieve 85% below325 mesh) and injected into a pulverized coal-fired furnace above the primary combustion zone. At the Millikensite, coal is reburned for NOx control using the following

methods: (1) close-coupled overfire air (CCOFA)reburning in which the top burner of the LNCFS IIITMburners are used for injecting the micronized coal, and theremaining burners and air ports are re-aimed; and (2)adjustment of the remaining burners and air ports for deepstage combustion by re-aiming them to create a fuel-richinner zone and fuel-lean outer zone providing combustionair. At Kodak Park, the Fuller MicroMillTM is used toproduce the micronized coal, reburn fuel is introducedabove the cyclone combustor, and overfire air is employedto complete the combustion.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Program Update 1999 5-59

3/97

1993 1994 1995 1996 1997 1998 1999 2000 2001

Design and Construction Operation

12/99

Operation completed (Lansing) 4/99

Operation completed (Rochester) 10/98

Ground breaking/construction started (Lansing) 3/15/96

Ground breaking/construction started (Rochester) 9/8/96

Design completed (Rochester) 9/96

ess completed

92

agreement awarded 7/28/92

Preoperational tests initiated (Rochester) 1/97

Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

Project completed/final reportissued 12/99*

Operation initiated (Rochester) 4/97

Environmental monitoring plan completed (Lansing) 8/97Environmental monitoring plan completed (Rochester) 8/97

Construction completed (Lansing) 1/97

Operation initiated (Lansing) 3/97

Project relocated to Lansing and Rochester 12/95

 input on the Milliken

ired) boiler resulted in a

106 Btu, which represents

 input on the Kodak Park

Ox emission rate of 0.60

 59% NOx reduction.

t Milliken Station

lso referred to as loss-on

ained under 4%, which is

 LOI for marketable fly

st important parameter

;

– Increasing coal fineness only marginally improved

NO

x emissions; and

– Increasing the percent of reburn fuel slightly decreased NO

x, but increased LOI.

• Testing on the cyclone boiler at Kodak Park showed:

– Increasing reburn fuel rates resulted in lower NOx

emissions;

– NO

x

 emission reductions on micronized coal were

comparable to NOx reductions achieved with gas

reburning;

– LOI increased with the reburn system in operation—LOI was 35–45% during full load (compared

to a baseline of 10–12% without reburning); and

– Stoichiometric ratios needed in the primary combustion zone and the reburn zone were 1.05–1.15

and 0.9, respectively.

Economic• Final results are not yet available, but in general, the

capital cost of a micronized coal reburning systemexceeds that of a gas reburning system due to millingsystem costs. On the other hand, the operating cost ofa micronized coal reburning system is much lower thana gas reburning system because of the reburn fuel costdifferential.
Environmental Control Devices

zed coal reburning

ed and cyclone-fired

YSEG’s Milliken Sta

T Program demonstra

yclone-fired boiler was

k Park Power Plant,

eburning demonstration

on of the reburn coal in

ce time reburn zone to

rimentally increasing

., loss-on-ignition. The

project was to demon

ing for NOx emission

e of the reburn coal. In

nely ground to 85%

the boilers above the

ulting typical particle

 microns for normal

aller size increases

creased surface area

 has the combustion

ich allows carbon com

e of volatiles at an even

onized coal combined

e uniform, compact

olume compared to

preventing furnace

r NOx control tech

g ABB Low-NOx

FS-III), which includes

verfire air (OFA) ports,

tion. Four D.B. Riley

ifiers provided the

 there are four levels of

eburning application,

the top-level burner nozzles fed micronized coal to theupper part of the furnace for this demonstration. Thelower three burner nozzles were biased to carry approximately 80% of the fuel required for full load, with the topburner supplying the remaining fuel. The speed of thedynamic classifier serving the mill feeding the top burnerswas increased to produce the micronized coal.

At Kodak Park, EER designed the micronized coal

reburn system using a combination of analytical andempirical techniques. The reburn fuel and OFA injectioncomponents were designed with a high degree of flexibility to allow for field optimization to accommodate thecomplex furnace flow patterns in the cyclone boiler. AFuller MicroMillTM produced the micronized coal reburnfuel with a particle size of about 20 microns. To maximize NO

x reduction, the reburn fuel was injected with flue

gas rather than air. The flue gas was extracted downstream of the electrostatic precipitator and boosted by asingle fan.

Two Fuller MicroMillsTM were installed in parallel

on Kodak Park Unit 15 to provide the capacity necessaryfor high reburn rates, the second mill serving as a spare atlower reburn rates. Eight injectors, six on the rear walland one on each of the side walls, introduced the micronized coal into the reburn zone. The optimization variablesincluded the number of injectors, swirl, and velocity.Four injectors on the front wall provided OFA usingEER’s second generation, dual-concentric OFA air design, which has variable injection velocity and swirl. Anew boiler control system was also installed on UnitNo. 15.

Some mechanical problems were encountered during

the demonstration, including plugging of the coal handling system that feeds the MicroMillTM, vibration andblade wear on the mills, erosion of the classifiers, andcorrosion due to low temperature flue gas when the reburnsystem was out of service. These problems were correctedand successful operation was achieved.

Environmental PerformanceAt the Milliken Station, micronized coal reburning with14% reburn fuel reduced NO

x

 from 0.35 lb/106 Btu baseline level to 0.25 lb/106 Btu, a 28% reduction, which is

within the target range of 25–35% reduction.

A primary objective at Milliken was to determine the

minimum NO

x level attainable while maintaining marketable fly ash (fly ash having less than 4.5% carbon). Variables studied at Milliken included boiler load, reburn coal

fineness, oxygen level at the economizer, percent reburnfuel, main burner tilt, and OFA tilt. During the testing,NYSEG found that excess air was the single most important parameter that affects NOx emissions. As shown in

Exhibit 5-27, higher excess air results in higher NOx

emissions, but lower LOI. In the case of the top mill(feeding reburning level) adjusted for regular grind (80%through 200 mesh), an increase in measured O2 at the

economizer inlet from 2.5% to 3.75% yields an increase inNO

x

 emissions from 0.36 lb/106 Btu to 0.43 lb/106 Btu, or

about a 20% increase. When the top mill is adjusted forfine grind (micronized), the NOx emissions are only marginally better. Exhibit 5-27 also shows the dramatic

impact of excess air on LOI. When the economizer O2 is

varied from 2.5% to 3.5%, the LOI will drop from 6.2% to3.8% (39% reduction) for the case of the top mill adjustedfor regular grind. When the same measurements aremade while the top mill is micronizing, the reduction inLOI is less significant.

Results from other parametric testing at Milliken

revealed that increasing coal fineness improved NOx

emissions only marginally, but lowered LOI. Other results showed that increasing the percent reburn fuelslightly decreased NOx, but substantially increased LOI.

At Kodak Park, micronized coal reburning with 17%

reburn fuel reduced NO

x

 emissions to 0.60 lb/106 Btu

from a baseline of 1.45 lb/106 Btu, a 59% reduction. At

greater reburn rates, further NOx reduction was achieved

to a degree comparable with gas reburning systems. As
Program Update 1999 5-61

e reburn system in

 35–45%, as compared

t available, the demon

d coal reburning has the

 NOx control costs than

ning, the differential cost

omponent of the cost of

 is zero when micron

uel. However, the capi

her than gas reburning

due to the capital and operating costs of coal millingsystem and other coal-handling equipment.Commercial ApplicationsMicronized coal reburning technology can be applied toexisting and greenfield cyclone-fired, wall-fired, andtangentially-fired pulverized coal units. The technologyreduces NO

x emissions by 20–59% with minimal furnace

modifications for existing units.

The availability of a coal-reburning fuel, as an additional fuel to the furnace, enables switching to lower

heating value coals without boiler derating. Reburn burners also can serve as low-load burners, and commercialunits can achieve a turndown of 8:1 on nights and weekends without consuming expensive auxiliary fuel.ContactsJim Harvilla, (607) 762-8630

New York State Electric & Gas CorporationCorporate Drive-Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224(607) 762-8457 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• Reburning Technologies for the Control of Nitrogen Oxides from Coal-Fired Boilers. (U.S. Department of Energy, Babcock & Wilcox, EER Corp., and

NYSEG) Topical Report No. 14. May 1999.

• Savichky et al. “Micronized Coal Reburning Demonstration of NOx Control.” Sixth Clean Coal Technology Conference: Technical Papers. April-May

1998.

5-27

ing Results

op Mill Regular Grind

lar Grind

Mill Fine Grind

zer O , %2

.5 4.0 4.5 5.0
Environmental Control Devices

Selective

n

e Control of

m High

Boilers

—cofunder

Gulf Power Company’s

)

We and six 0.2-MWe

729 100%

673 40

056 60

mmercially available

rating conditions found

y boilers using high

rating conditions while

moval.

Technology/Project DescriptionThe SCR technology consists of injecting ammonia intoboiler flue gas and passing it through a catalyst bedwhere the NO

x and ammonia react to form nitrogen and

water vapor.

In this demonstration project, the SCR facility consisted of three 2.5-MWe equivalent SCR reactors, supplied by separate 5,000 scfm flue gas slipstreams, and six

0.20-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 demonstrated, at high- and low-dust

loadings of flue gas, the applicability of SCR technologyto provide a cost-effective means of reducing NOx emissions from power plants burning high-sulfur U.S. coal.

The demonstration plant, which was located at Gulf

Power Company’s Plant Crist near Pensacola, FL, usedflue gas from the burning of 2.7% sulfur coal.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 5-63

were achieved at an am

pm deemed acceptable

 to 150% of design with

ip design level of 5 ppm

ncreased above 700 oF,

he heat rate penalties.

ign of catalyst deactiva

m to approximately

hours of operation, thus

 coal-fired units was in

ce.

t SO2 oxidation was

mits necessary to protect

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction Operation

6/90

ess

/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

11/96

Operation initiated 7/93

Operation completed 7/95

Project completed/finalreport issued 11/96

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 analysisof the fly ash.

Economic• Levelized costs for various NO

x

 removal levels for a

250-MWe unit at 0.35 lb/106 Btu inlet follow:

40% 60% 80%

1996 levelized cost(mills/kWh) 2.39 2.57 2.791996 levelized cost($/ton) 3,502 2,500 2,036
Environmental Control Devices

Exhibit 5-28

Catalysts Tested

Catalyst Reactor Size* Catalyst

Configuration

Nippon/Shokubai Large HoneycombSiemens AG Large PlateW.R. Grace/Noxeram Large HoneycombW.R. Grace/Synox Small HoneycombHaldor Topsoe Small PlateHitachi/Zosen Small PlateCormetech/High dust Small HoneycombCormetech/Low dust Small Honeycomb* Large = 2.5-MWe; 5,000 scfm Small = 0.2-MWe; 400 scfm

Exhibit 5-29

Average SO2 Oxidation Rate

(Baseline)

Average SO2 Oxidation (%)

NH3/NOx = 0.8, 700 oF, design flow

gned to address several

atalyst deactivation due

es in U.S. coals, perfor

n the balance-of-plant

amounts of SO2 and

catalyst under typical

perating conditions.

o design the catalyst

actor dimensions, pro

ayers, and meet the

ns:

m Baseline Maximum

700 750

0.8 1.0

100 150

5,000 7,500

400 600

in Exhibit 5-28. Cata

tude in providing the

tration.

or in the long-term

s usually <5 ppm be

siderations. Ammonia

osure time, flow rate,

, and NH3/NOx ratio

/NOx ratio and conse

roduced the most sig

The ammonia slip at

the detection limit of

reased above 80%,

emained at reasonable

%. Over 90%, the am

ically.

e effects on NOx reduc

al, flows could be increased to 150% of design without the ammonia slip exceeding 5 ppm, at 80% NOx reduction and design tem- perature. With respect to temperature, most catalysts exhibited fairly significant improvements in overall per- formance as temperatures increased from 620 °F to 700 °F, but relatively little improvement as temperature increased from 700 °F to 750 °F. The conclusion was that the benefits of high-temperature operation probably do not outweigh the heat rate penalties involved in operating SCR at the higher temperatures. Catalyst deactivation was generally observed by an increase in ammonia slip over time, assuming the NOx reduction efficiency was held constant. Over the 12,000 hours of the demonstration tests, the ammonia slip did increase from less than 1 ppm to approximately 3 ppm. These results demonstrated the maturity of catalyst design and that deactivation was in line with prior worldwide experience. Experience has shown that the catalytic active spe- cies that result in NOx reduction often contributed to SO2 oxidation (i.e., SO3 formation), which can be detrimental to downstream equipment. In general, NOx reduction can

be increased as the tolerance for SO3 is also increased.

The upper bound for SO2 oxidation for the demonstration

catalyst was set at 0.75% at baseline conditions. Theaverage SO2 oxidation rate for each of the catalysts is

shown in Exhibit 5-29. These data reflect baseline conditions over the life of the demonstration. All of the catalysts were within design limits, with most exhibitingoxidation rates below the design limit.

Other factors affecting SO2 oxidations were flow rate

and temperature. Most of the catalysts exhibited fairlyconstant SO2 oxidation with respect to flow rate (i.e.,

space velocity). In theory, SO2 oxidation should be inversely proportional to flow rate. Theoretically, the relationship between SO2 oxidation and temperature should

be exponential as temperature increases; however, measurements showed the relationship to be linear with littledifference in SO2 oxidation between 620 oF and 700 oF.

On the other hand, between 700 °F and 750 °F, the SO2

oxidation increased more significantly.

Other findings from the demonstration deal with

pressure drop, fouling, erosion, air preheater performance,
Program Update 1999 5-65

city characteristic leach

Overall reactor pressure

st geometry and volume,

was controlling were

teristics of the catalyst

ration. During the dem

d relatively level pressure

otblowing procedures

nfigurations had some

id the honeycomb con

ble for application.

red to be a significant

sion was attributed to

gard to air preheater

showed that the SCR

 degradation of the air

ia slip and subsequent

tor-type air heaters out

pplications in terms of

uling. The ammonia

when a significant

y the ash. This was

ayer on the ash with a pH

 compounds in the ash to

ses were performed on

s did not significantly

e fly ash.

formed for full-scale

to a new 250-MWe pul

n a rural area with mini

considered was high

key base case design

0.

lysis of capital, operating

velized cost based on a

nit sizes for an SCR

ency of 60% follow:

125-MWe 250-MWe 700-MWe

Capital cost ($/kW) 61 54 45Operating cost ($) 580,000 1,045,000 2,667,0001996 levelized costmills/kWh 2.89 2.57 2.22$/ton 2,811 2,500 2,165

Results of the economic analysis of capital, O&M,

and levelized cost for various NOx removal efficiencies for

a 250-MWe unit with 0.35 lb/106 Btu of inlet NOx are as

follows:

40% 60% 80%

Capital cost ($/kW) 52 54 57Operating costs ($) 926,000 1,045,000 1,181,000

1996 levelized costmill/kWh 2.39 2.57 2.79$/ton 3,502 2,500 2,036

For retrofit applications, the estimated capital costs

were $59–112/kW, depending on the size of the installation and the difficulty and scope of the retrofit. The levelized costs for the retrofit applications were $1,850–5,100/ton (1996$). Commercial Applications As a result of this demonstration, SCR technology has been shown to be applicable to existing and new utility generating capacity for removal of NOx from the flue gas of virtually any size boiler. There are over 1,000 coal- fired utility boilers in active commercial service in the United States; these boilers represent a total generating capacity of approximately 300,000 MWe. Contacts Larry Monroe, (205) 257-7772 Southern Company Services, Inc. P.O. Box 2641 Birmingham, AL 35291-8195 (205) 257-5367 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991

References• Control of Nitrogen Oxide Emissions: Selective Catalytic Reduction (SCR). Topical Report No. 9. U.S.

Department of Energy and Southern Company Services, Inc. July 1997.

• Maxwell, J. D., et al. “Demonstration of SCR Technology for the Control of NOx Emissions from HighSulfur Coal-Fired Utility Boilers.” Fifth Annual Clean

Coal Technology Conference: Technical Papers,January 1997.

• Demonstration of SCR Technology for the Control

of NOx Emissions from High-Sulfur, Coal-Fired

Utility Boilers: Final Report. Vol. 1. SouthernCompany Services, Inc. October 1996. (Availablefrom NTIS, Vol. 1 as DE97050873, Vol. 2: AppendixesA–N as DE97050874, and Vol. 3: Appendixes O–Tas DE97050875.)

Exhibit 5-30

Design Criteria

Parameter SpecificationType of SCR Hot sideNumber of reactors OneReactor configuration 3 catalyst support layersInitial catalyst load 2 of 3 layers loadedRange of operation 35–100% boiler loadNOx inlet concentration 0.35 lb/106 Btu

Design NOx reduction 60%

Design ammonia slip 5 ppmCatalyst life 16,000 hrAmmonia cost $250/tonSCR cost $400/ft3
Environmental Control Devices

s

tration of

ially-Fired

niques for

NOx

oal-Fired

and host

e—cofunder

nc.—cofunder and

f Power Company’s

Low-NOx Concentric

vanced overfire air

nd offset air

y

665 100%

382 49

283 51

n Engineering, Inc.

fire air system that incorporates back pressuring and flowmeasurement capabilities. CCOFA and SOFA were bothused in the LNCFSTM III tangential-firing approach.

Carefully controlled short-term tests were conducted

followed by long-term testing under normal load dispatchconditions. Long-term tests, which typically lasted 2–3months for each phase, best represent the true emissionscharacteristics of each technology. Results presented arebased on long-term test data.

Project ObjectiveTo demonstrate in a stepwise fashion the short- and longterm NO

x reduction capabilities of LNCFSTM levels I, II,

and III on a single reference boiler.Technology/Project DescriptionTechnologies demonstrated included LNCFSTM levels I,II, and III. Each level of the LNCFSTM used differentcombinations of overfire air and clustered coal nozzlepositioning to achieve NOx reductions. With the

LNCFSTM, primary air and coal are surrounded by oxygen-rich secondary air that blankets the outer regions ofthe combustion zone. LNCFSTM I used a close-coupledoverfire air (CCOFA) system integrated directly into thewindbox of the boiler. A separated overfire air (SOFA)system located above the combustion zone was featuredin the LNCFSTM II system. This was an advanced over-
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 5-67

ns using LNCFSTM I, II,

.34 lb/106 Btu, respec

ions of 37, 37, and 45%

re not sensitive to power

0-MWe, but emissions

100-MWe, reaching

-MWe.

ess at low loads,

s a compliance option for

sed at full load.

FSTM to have no clear-cut

e metals or acid gases.

VOCs) appeared to be

mpounds increased.

Operational• Loss-on-ignition (LOI) was not sensitive to the

LNCFSTM retrofits but very sensitive to coal fineness.

• Furnace slagging was reduced but backpass fouling

was increased for LNCFSTM II and III.

• Boiler efficiency and unit heat rate were impacted

minimally.

• Unit operation was not significantly affected, but operating flexibility of the unit was reduced at low loads

with LNCFSTM II and III.

Economic• The capital cost estimate for LNCFSTM I was

$5–15/kW and for LNCFSTM II and III, $15–25/kW(1993$).

• The cost effectiveness for LNCFSTM I was $103/ton of

NO

x removed; LNCFSTM II, $444/ton; and LNCFSTM

III, $400/ton (1993$).

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

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

Operation initiated 5/91Constructioncompleted 5/91 Operation completed 12/92

s

TF)

ed 9/20/90

5/91
Environmental Control Devices

Exhibit 5-31

LNCFSTM Configurations

d for tangentially-fired

rcentage of the pre

ty. The technology

n in the boiler verti

ectors and horizontally

s with offset air

rmine NOx emission

rformance over the

nd operating condi

e demonstration pro

nce analysis of the

arametric testing en

her tangentially-fired

p between NOx emis

s.

on, specific NOx emis

lated under the CAAA.

e of this project pro

gulation development.

us LNCFSTM configu

mbustion. In addition to

rates other NOx-reduc

n process as shown in

 concentric circular

he majority of the coal

egion. This region is

ntaining combustion air.

ombustion air can be

ozzles.

cts of LNCFSTM on

I reduced NOx emis

vely. Exhibit 5-34

es obtained in the as

Ox emissions for three

Air toxics testing found LNCFSTM to have no clearcut effect on the emission of trace metals or acid gases.

The data provided marginal evidence for a decreasedemission of chromium. The effect on aldehydes/ketonescould not be assessed because baseline data were compromised. VOCs appeared to be reduced and semi-volatilecompounds increased. The increase in semi-volatilecompounds was deemed to be consistent with increases inthe amount of unburned carbon in the ash.Economic PerformanceLNCFSTM II was the only complete retrofit (LNCFSTM Iand III were modifications of LNCFSTM II), and thereforecapital cost estimates were based on the Lansing SmithUnit No. 2 retrofit as well as other tangentially-firedLNCFSTM retrofits. The capital cost ranges in 1993 constant dollars follow:

• LNCFSTM I—$5–15/kW• LNCFSTM II—$15–25/kW• LNCFSTM III—$15–25/kW

Site-specific considerations have a significant

effect on capital costs; however, the above rangesreflect actual experience and are planning estimates.The actual capital cost for LNCFSTM II at Lansing SmithUnit No. 2 was $3 million, or $17/kW, which fallswithin the projected range.

The cost effectiveness of the LNCFSTM technologies

is based on the capital and operating and maintenancecosts and the NO

x removal efficiency of the technologies.

The cost effectiveness of the LNCFSTM technologiesfollows (based on a levelization factor of 0.144 in 1993constant dollars):

Exhibit 5-32

Concentric Firing Concept
Program Update 1999 5-69

Exhibit 5-33

Unit Performance Impacts Based on Long-Term Testing

Baseline LNCFSTM I LNCFSTM II LNCFSTM III

Avg CO at full load (ppm) 10 12 22 33Avg excess O2 at full load (%)3.7 3.2 4.5 4.3

LOI at full load (%) 4.8 4.6 4.2 5.9

O2 (%) 4.0 3.9 5.3 4.7

Steam outlet conditions Satisfactory at full Full load: 5–10 oF Same as baseline 160- to 200-MWe:

load; low temper- lower than baseline satisfactoryatures at low loads Low loads: 10–30 oF 80-MWe: 15–35 oF

lower than baseline lower than baseline

Furnace slagging and Medium Medium Reduced slagging, Reduced slagging,backpass fouling but increased fouling but increased foulingOperating flexibility Normal Same as baseline More care required More difficult to

at low loads operate than other

systems

Boiler efficiency (%) 90 90.2 89.7 89.85

Efficiency change N/A +0.2 -0.3 -0.15Turbine heat rate (Btu/kWh) 9,000 9,011 9,000 9,000Unit net heat rate (Btu/kWh) 9,995 9,986 10,031 10,013Change (%) N/A -0.1 +0.36 +0.18

Exhibit 5-34

Average Annual NOx Emissions and Percent Reduction

Boiler Duty Cycle Units Baseline LNCFSTM I LNCFSTM II LNCFSTM IIIBaseload Avg NOx emissions (lb/106 Btu) 0.62 0.41 0.41 0.36

(161.8-MWe avg) Avg reduction (%) 38.7 38.7 42.2

Intermediate load Avg NOx emissions (lb/106 Btu) 0.62 0.40 0.41 0.34

(146.6-MWe avg) Avg reduction (%) 39.2 35.9 45.3

Peaking load Avg NOx emissions (lb/106 Btu) 0.59 0.45 0.47 0.43

(101.8-MWe avg) Avg reduction (%) 36.1 20.3 28.0

Ox removed

Ox removed

Ox removed

ial commercial applica

lverized coal, tangen

nits range from 25-MWe

de range of coals, from

lignite.

 at the host site for com

Engineering has modi

rs, representing over

d derivative TFS 2000TM

 Inc.

) 903-9483

6-5991

Advanced Tangen

hniques for the

 (NOx) Emissions from

eport and Key Project

C/89653-T14. Southern

uary 1994. (Available

Advanced Tangen

hniques for the Reduc

) Emissions from Coal

g Smith—Phase III and

oring Program Report.

 Inc. December 1993.
Environmental Control Devices
Program Update 1999 5-71

nvironmental Control Devices

ned SO2/NOx Control Technologies
Environmental Control Devices

chnology

nstration of

Ox Removal

System

—cofunder

der

—host

rable flue gas cleanup

120 100%

060 50

060 50

f the SO2 and 75% of

flue gas using the

Technology/Project DescriptionThe NOXSO process is a dry, regenerable system capableof removing both SO2 and NOx in flue gas from coal-fired

utility boilers burning medium- to high-sulfur coals. Inthe basic process, the flue gas passes through a fluidizedbed adsorber located downstream of the precipitator; SO2and NO

x are adsorbed by the sorbent, which consists of

spherical beads of high-surface-area alumina impregnatedwith sodium carbonate. Cleaned flue gas then passesthrough a baghouse to the stack.

The NO

x

 is desorbed from the NOXSO sorbent when

heated by a stream of hot air. Hot air containing thedesorbed NO

x is recycled to the boiler where equilibrium

processes cause destruction of the NOx. The adsorbed

sulfur is recovered from the sorbent in a regeneratorwhere it reacts with methane at high temperature to produce an offgas with high concentrations of SO2 and hy- drogen sulfide (H2S). This offgas is processed to produce elemental sulfur, which can be further processed to pro- duce liquid SO2, a higher valued by-product. The process is expected to achieve SO2 reductions of 98% and NOx reductions of 75%.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 5-73

ments

hose to cancel a host site

nable to obtain full

1997, as specified in the

nditional Host Site

y 1998.

y under Chapter 11 -

 plan was approved by

ber 2, 1998, but NOXSO

nds. NOXSO closed its

r of the bankruptcy court,

of reorganization under

cember 9, 1999. One of

an was the rejection of

esult, the cooperative

r to publication of this

mber 1999 in accordance

 Court.

1991 1992 1993 1994 1995 1996 1997 1998 1999

91

CT-III) 12/19/89

Cooperative agreementawarded 3/11/91

Design

Alcoa Generating Corp. cancelledhost site agreement 2/97

Novation of cooperative agreement with NOXSO Corp. 8/94

Selected Alcoa host site 8/94

Project definition phase completed 10/94

NEPA process completed, Alcoa (EA) 6/26/95

Identified conditional host site,RP&L 1/98

Schedule pending actionin bankruptcy court

On Hold

Commercial ApplicationsThe NOXSO process is applicable to existing or newfacilities. The process is suitable for utility and industrialcoal-fired boilers. The process is adaptable to coals withmedium- to high-sulfur content.

The process produces one of the following as a salable by-products: elemental sulfur, sulfuric acid, or liquid

SO2. A readily available market exists for these products.

The technology is expected to be especially attractive

to utilities that require high removal efficiencies for bothSO2 and NOx, need to eliminate solid wastes, and/or have

inadequate water supply for a wet scrubber.
Environmental Control Devices

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.

The technology was designed to remove 95% of the

SO2 and more than 90% of the NOx from flue gas and

produce a salable sulfuric acid by-product using U.S.coals. This was accomplished without using sorbents andwithout creating waste streams.

The demonstration was conducted at Ohio Edison’s

Niles Station in Niles, Ohio. The demonstration unittreated a 35-MWe equivalent slipstream of flue gas fromthe 108-MWe Unit No. 2 boiler, which burned a 3.4%sulfur Ohio coal. The process steps were virtually thesame as for a full-scale commercial plant, and commercial-scale components were installed and operated.

chnology

Cleaning

oject

cofunder

 and host

for process technology,

and process designer

o Edison’s Niles Sta

c advanced flue gas

m a 108-MWe boiler

408 100%

200 50

208 50

er plant using U.S.

TM technology will

nd more than 90% of

alable by-product of
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 5-75

• Presence of the SO2 catalyst virtually eliminated CO

and hydrocarbon emissions.

Operational• Having the SO2 catalyst downstream of the NOx catalyst eliminated ammonia slip and allowed the SCR to

function more efficiently.

• Heat developed in the SNOXTM process was used to

enhance thermal efficiency.

Economic• Capital cost was estimated at $305/kW for a

500-MWe unit firing 3.2% sulfur coal. The levelizedincremental cost was estimated at 6.1 mills/kWh or$219/ton of SO2 removal on a constant 1995 dollar

basis. Comparable current dollar costs were 7.8 mills/kWh and $284/ton of SO2.

ormally in excess of 95%

ging about 2,000 ppm.

for inlet concentrations

m.

y for the high-efficiency

NOXTM system was

 federal specifications for

h capture efficiency of

ghouse. A significant

st all of the mercury

nium and cadmium,

ectively captured in the

mpounds.

contributed to having no

r increases in CO2

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

Design and Construction

Operation initiated 3/92

3/92

PA 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

7/96

Project completed/final report issued 7/96

Operation completed 12/94
Environmental Control Devices

The bottom portion of the SO2 converter catalyst, with

the catalyst dust collector hopper mounted on steel rails(center), is shown.

O2 removal step because

xidation catalyst to

 to sulfuric acid. As a

her waste streams.

valuate the performance

operating data were

ducted to characterize

ystem operated for

oduced more than

ulfuric acid. Many of

were conducted at three

gn capacity.

cess were very low

istics of the SO2 cata

r (WSA Condenser).

d with a baghouse

This was not necessary

rather was needed to

equency for the SO2

, the SO2 catalyst,

ned about 90% of the

l. Dust that passed

d in the WSA Con

ng particulate removal

tes as nuclei).

2 emissions by the

the lack of a carbonate

CO2 and the fact that the

from the flue gas to

ments. This heat recov

 results in the net heat

r better after addition of

ently no increase in

carbons, the SO2 cata

se compounds as well.

d 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 (>95%).

Sulfur dioxide removal in the SNOXTM process was

controlled by the efficiency of the SO2-to-SO3 oxidation,

which occurred as the flue gas passed through 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.

The SCR portion of the SNOXTM process was able to

operate at higher than typical ammonia stoichiometriesdue to its location ahead of the SO2 catalyst beds. Normal

operating stoichiometries for the SCR system were in therange of 1.02–1.05, and system reduction efficienciesaveraged 94% with inlet NOx levels of approximately500–700 ppm.

Sulfuric acid concentration and composition has met

or exceeded the requirements of the federal specificationsfor Class I acid. During the design and construction ofthe SNOXTM demonstration, arrangements were madewith a sulfuric acid supplier to purchase and distribute theacid from the plant. The acid has been sold to the agriculture industry for production of diammonium phosphatefertilizer and to the steel industry for pickling. OhioEdison also has used a significant amount in boiler waterdemineralizer systems throughout its plants.

Air toxics testing conducted at the Niles SNOXTM

plant measured the following substances:

• Five major and 16 trace elements including mercury,

chromium, cadmium, lead, selenium, arsenic, beryllium, and nickel

• Acids and corresponding anions (hydrogen chloride,

hydrogen fluoride, chloride, fluoride, phosphate,sulfate)

• Ammonia and cyanide• Elemental carbon• Radionuclides• Volatile organic compounds
Program Update 1999 5-77

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 aspart of its environmental control system.

uding polynuclear aro

aptured in the baghouse

gnificant portion of the

ury escaped to the stack.

mally a problem, were

rain, as were organic

 by the SNOXTM process.

 can be utilized in the

process generated recov

of the reactions that took

O2 removal were exother

re of the flue gas. This

added in the high-tem

was recovered in the

harge for use in the

use the WSA Condenser

ue gas to about 210 oF,

oF for a typical power

was

he

al

for a

r

cost

n a

e

e

).

Commercial ApplicationsThe SNOXTM technology is applicable to all electricpower plants and industrial/institutional boilers firingcoal, oil, or gas. The high removal efficiency for NOx and

SO2 makes the process attractive in many applications.

Elimination of additional solid waste (except ash) enhances the marketability in urban and other areas wheresolid waste disposal is a significant problem.

The host utility, Ohio Edison, is retaining the

SNOXTM technology as a permanent part of the pollutioncontrol system at Niles Station to help Ohio Edisonmeet its overall 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.

ContactsPaul Yosick, Project Manager, (423) 693-7550

ABB Environmental Systems1409 Center Port BoulevardKnoxville, TN 37932(423) 694-5203 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• Final Report Volume II: Project Performance and

Economics. July 1996. Report No. DE-FC22-90PC89C55.

• Final Report Volume I: Public Design. Report No.

DOE/PC/89655-T21. (Available from NTIS asDE96050312.)

• A Study of Toxic Emissions from a Coal-Fired Power

Plant Utilizing the SNOXTM Innovative Clean CoalTechnology Demonstration. Volume 1, Sampling/Results/Special Topics: Final Report. Report No.

DOE/PC/93251-T3-Vol. 1. Battelle Columbus Operations. July 1994. (Available from NTIS asDE94018832.)

• A Study of Toxic Emissions from a Coal-Fired Power

Plant Utilizing the SNOXTM Innovative Clean CoalTechnology Demonstration. Volume 2, Appendices:Final Report. Report No. DOE/PC/93251-T3-Vol. 2.Battelle Columbus Operations. July 1994. (Availablefrom NTIS as DE94018833.)
Environmental Control Devices

9/95

Project ObjectiveTo achieve greater than 70% SO2 removal and 90% or

higher reduction in NOx emissions while maintaining

particulate emissions below 0.03 lb/106 Btu.

Technology/Project DescriptionThe 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.

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 demonstration unit is large

enough to demonstrate commercial-scale components

while minimizing the demonstration cost. Operation atthis scale also permitted cost-effective control of the fluegas temperature, which allowed for evaluation of performance over a wide range of sorbent injection and baghouse operating temperatures. Thus, several differentarrangements for potential commercial installations couldbe simulated.

chnology

TM Flue Gas

ration

 and host

cofunder

—cofunder

SCR catalyst supplier

r bag supplier

tion—cofunder and

OH (Ohio Edison

t No. 5)

s SOx-NOx-Rox BoxTM

m a 156-MWe boiler

ur average

620 100%

402 46

218 54

ks of The Babcock & Wilcox
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 5-79

% was achieved with

alcium-to-sulfur (Ca/S)

ature of 800–850 oF.

% was achieved with

nate hydrated lime at a

mperature of

% was achieved with

m-to-sulfur (Na2/S)

ature of 425 oF.

o less than 1.2 lb/106 Btu

Ca/S molar ratio as low

f 1.0.

rbents directly upstream

F resulted in higher over

 further upstream at

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design completed 8/91

perative agreement

ded 12/20/89

ocess completed (MTF) 9/22/89

Ground breaking/construction started 5/9/91

5/92

Design and Construction Operation

Preoperational tests initiated 11/91• NO

x

 reduction of 90% was achieved with an NH3/NOx

molar ratio of 0.9 and temperature of 800–850 oF.

• Air toxics removal efficiency was comparable to that

of an electrostatic precipitator (ESP), except that hydrogen fluoride (HF) was reduced by 84% and hydrogen chloride (HCl) by 95%.

Operational• Calcium utilization was 40–45% for SO2 removals of

85–90%.

• Norton Company’s NC-300 zeolite SCR catalyst

showed no appreciable physical degradation or changein catalyst activity over the course of the demonstration.

• No excessive wear or failures occurred with the filter

bags tested: 3M’s Nextel ceramic fiber filter bag andOwens Corning Fiberglas’ S-Glass filter bag.

Construction completed 12/91Environmental monitoring plan completed 12/31/91

Operationinitiated 5/92 Operation completed 5/93 Project completed/final report issued 9/95

9/95

Economic• Capital cost in 1994 constant dollars for a 250-MWe

retrofit was $233/kW, assuming 3.5% sulfur coal andbaseline NO

x

 emissions of 1.2 lb/106 Btu.
Environmental Control Devices

ful technology devel

dvantages over other

rature filter bags and

ments enabled multiple

onent with a low plan

combustion control

e high-temperature bag

 environment compat

and a surface for en

es a sorbent cake on the

h is receiving increas

rior performance of

d for SO2 capture. Cal

mercial grade hydrated

nosulfonate-hydrated

nate was tested. The

orbent into the flue gas

baghouse. Essentially,

nt in the form of a filter

 fly ash).

above 830 oF, injection

e at Ca/S molar ratios

emovals of over 80%.

rmance of the sugar

hydrated lime increased

, for overall removal of

 of 85–90% was ob

he of 40–45%. Injec

 directly upstream of

ed in higher overall SO2

tream at temperatures

carbonate was 80% at

% at an Na2/S molar

ced 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 pres- ence of Norton Company’s NC-300 series zeolite SCR catalyst. With the catalyst being located inside the filter bags, it was well protected from potential particulate erosion or fouling. The sorbent reaction products, unre- acted lime, and fly ash were collected on the filter bags and thus removed from the flue gas. A NOx emission reduction of 90% was readily achieved with ammonia slip limited to less than 5 ppm. This performance reduced NOx emissions to less than 0.10 lb/106 Btu. NOx reduction was insensitive to tem- peratures over the catalyst design temperature range of 700–900 oF. Catalyst space velocity (volumetric gas flow/ catalyst volume) had a minimal effect on NOx removal over the range evaluated. Turndown capability for tailoring the degree of NOx reduction by varying the rate of ammonia injection was demonstrated for a range of 50–95% NOx reduction. No appreciable physical degradation or change in the catalyst activity was observed over the duration of the test pro- gram. The degree of oxidation of SO2 to SO3 over the zeolite catalyst appeared to be less than 0.5%. (SO2 oxi- dation is a concern for SCR catalysts containing vana- dium.) Leach potential analysis of the catalyst after completion of the field test showed that the catalyst re- mained nonhazardous for disposal. Particulate emissions were consistently below NSPS standards of 0.03 lb/106 Btu, with an average over 30 baghouse particulate emission measurements of 0.018 lb/106 Btu, which corresponds to a collective effi- ciency of 99.89%. Hydrated lime injection increased the baghouse inlet particulate loading from 5.6 to 16.5 lb/106 Btu. Emissions testing with and without the SCR catalyst installed revealed no apparent differences in collection efficiency. On-line cleaning with a pulse air pressure of 30–40 lb/in2 was sufficient for cleaning the bag/catalyst assemblies. Typically, one of five baghouse modules in service was cleaned every 30–150 minutes. A comprehensive air toxics emissions monitoring test was performed at the end of the SNRBTM demonstra- tion test program. The targeted emissions monitored included trace metals, volatile organic compounds, semi- volatile organic compounds, aldehydes, halides, and radionuclides. These species were a subset of the 189 The demonstration baghouse is installed on the back side of the power plant. Workers stand by the catalyst holder tube prior to lifting it into the penthouse.
Program Update 1999 5-81

Workers lower one of the catalyst holder tubes into a

mounting plate in the penthouse of the high-temperaturebaghouse.

n the CAAA. Measure

xins, and furans were

am. The emissions con

ous air toxics by the

comparable to those of

er plant. However, the

by an average of 95%

of 84%, whereas the

ituents.

emonstration resulted in

830 tons of fly ash and

n of potential uses for the

rial might be used for

. Also, the solids poten

ement replacement to

hree fabric filters was

velopment Test Facility

n December 1992. No

All of the demonstration

M Company Nextel

wens Corning Fiberglas

e wear or failures oc

vated temperature opera

 3.5% sulfur coal and

 the projected capital

oximately $233/kW

ology and project contin

 fabric filter, SCR, and

arable emissions control

kW. Variable operating

of the SO2 sorbent for a

2 removal. Fixed operat

tem operating labor and

he hot baghouse and

Commercial ApplicationsCommercialization of the technology is expected to develop with an initial larger scale application equivalent to50- to 100-MWe. The focus of marketing efforts is beingtailored to match the specific needs of potential industrial,utility, and independent power producers for both retrofitand new plant construction. SNRBTM is a flexible technology that can be tailored to maximize control of SO2,

NO

x, or combined emissions to meet current performance

requirements while providing flexibility to addressfuture needs.ContactsDot K. Johnson, (330) 829-7395

McDermott Technologies1562 Belson StreetAlliance, OH 44601(330) 829-7801 (fax)dot.k.johnson@mcdermott.com

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• SO

x

-NO

x

-Rox BoxTM Flue Gas Cleanup Demonstration

Final Report. Report No. DOE/PC/89656-T1. TheBabcock & 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.)
Environmental Control Devices

chnology

e of Coals by

d Sorbent

ch Corporation

mmerce & Community

t

nois Power Company’s

 (City Water, Light and

 No. 7)

ch Corporation’s gas

R-SI) process

We (gross),

gross), 33-MWe (net)

955 100%

816 50

139 50

Project ObjectiveTo demonstrate gas reburning to attain at least 60% NOx

reduction along with sorbent injection to capture at least50% of the SO2 on two different boiler configurations—

tangentially-fired and cyclone-fired—while burning highsulfur midwestern coal.Technology/Project DescriptionIn this process, 80–85% of the fuel was coal and wassupplied to the main combustion zone. The remaining15–20% of the fuel, provided by natural gas, bypassed themain combustion zone and was injected above the mainburners to form a reducing (reburning) zone in whichNO

x was converted to nitrogen. A calcium compound

(sorbent) was injected in the form of dry, fine particulatesabove the reburning zone in the boiler. Lime (Ca(OH)2)

was the sorbent tested at both sites. This project demonstrated the GR-SI process on two separate boilers repre- senting two different firing configurations—a tangen- tially-fired, 80-MWe (gross) boiler at Illinois Power Company’s Hennepin Plant in Hennepin, Illinois, and a cyclone-fired, 40-MWe (gross) boiler at City Water, Light and Power’s Lakeside Station in Springfield, Illinois. Illinois bituminous coal containing 3% sulfur was the test coal for both Hennepin and Lakeside. A comprehensive test program was conducted at each of the two sites, operating the equipment over a wide range of boiler conditions. Over 1,500 hours of operation was achieved, enabling a substantial amount of data to be obtained. Intensive measurements were taken to quantify the reductions in NOx and SO2 emissions, the impact on boiler equipment and operability, and all fac- tors influencing costs. 

Environmental Research
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

**Years omitted

1 2

Program Update 1999 5-83

er, GR-SI NOx reductions

and an average 67%

verage gas heat input of

y on the tangentially-fired

drated lime at a calcium

f 1.75 (corresponding to

GR-SI NOx reductions of

d an average 66% reduc

e gas heat input of 22%.

y on the cyclone-fired

drated lime at a Ca/S

ding to a sorbent utiliza

• Particulate emissions were not a problem on either

unit undergoing demonstration, but humidificationhad to be introduced at Hennepin to enhance ESPperformance.

• 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 ata Ca/S molar ratio of 1.75. Under the same conditions, PromiSORBTM B achieved 66% SO2 reduction

and 38% utilization, and high-surface-area hydratedlime achieved 60% SO2 reduction and 34% utilization.

Operational• Boiler efficiency decreased by approximately 1% as a

result of increased moisture formed in combustionfrom natural gas use.

• There was no change in boiler tube wastage, tube

metallurgy, or projected boiler life.

Design and Construction

1988 1989 1990 1991 1992 1993 1994 1995 1998

1/91

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

nvironmental monitoring plan

mpleted, Hennepin 10/15/89

akeside (EA) 6/25/89

mpleted, both sites 5/89

started, Hennepin 5/89

NEPAprocesscompleted,Hennepin(MTF) 5/9/88

Construction completed, Lakeside 5/92

Restoration completed,Hennepin 12/93

9/98

Project completed/

final report issued 9/98

Operation completed,Lakeside 10/94

Operation

Restoration completed,

Lakeside 12/95

Economic• Capital cost for gas reburning (GR) was approximately

$15/kW plus the gas pipeline cost, if not in place(1996$).

• Operating costs for GR were related to the gas/coal

cost differential and the value of SO2 emission allowances (because GR replaces some coal with gas, it also

reduces SO2 emissions).

• Capital cost for sorbent injection (SI) was approximately $50/kW.• 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.

**

3 4
Environmental Control Devices

The flexible lime-sorbent distribution lines lead from

the sorbent splitter to the top of the cyclone-fired boiler atLakeside Station.

he success of gas re

nologies in reducing

ess design conducted

 the vast amount of

eated a database ca

o all major coal-firing

e-, and wall-fired) on

he emissions control

y projected as can the

Hennepin)

d optimization testing

ted between January

SI long-term demon

m January 1992 to Octo

ormance over an ex

ated at constant loads

h operation where load

tput requirements.

e load fluctuated over a

ximum load of 75-MWe.

period, the average

testing, the average

67%. The average SO2

at a Ca/S molar ratio of

s used throughout these

Marblehead lime was

50 ppm in most cases

t low load.

2 was also realized.

nt of coal with natural

ogen ratio. This cofir

in a theoretical CO2

from the coal-fired

idification, electrostatic

encies greater than

ss than 0.025 lb/106 Btu

were measured even with an increase in inlet particulateloading resulting from sorbent injection. These levelswere comparable to measured baseline emissions of0.035 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 proprietaryadditives to increase their reactivity toward SO2, and were

referred to as PromiSORBTM A and B. The Illinois StateGeological Survey developed the other sorbent—highsurface-area hydrated lime—in which alcohol is used toform a material that gives rise to a much higher surfacearea than that of conventionally hydrated limes.

The SO2 capture without GR, at a nominal 1.75 Ca/S

molar ratio, was 53% for PromiSORBTMA, 66% for

PromiSORBTM B, 60% for high-surface-area hydratedlime, and 42% for Linwood lime. At a 2.6 Ca/S molarratio, the PromiSORBTM B yielded 81% SO2 removal

efficiency.Environmental Performance (Lakeside)Parametric tests were conducted in three series: 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 5-126%. 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

isolate the effects of sorbent on boiler performance andoperability. Results showed that SO2 reduction levels

varied with load because of the effect of temperature onthe sulfation reaction. 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); and32% SO2 reduction was achieved at low load (20-MWe).

In the GR-SI optimization tests, the two technologies

were 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 wasdecreased by 32% to increase the reburning jet’s penetration characteristics. The decrease in nozzle diameterincreased NOx reduction by an additional 3–5% compared

to the initial parametric tests. With GR-SI, total SO2

reductions resulted from partial replacement of coal withnatural gas and sorbent injection. At a gas heat input of22% and Ca/S molar ratio of 1.8, average NOx reduction
Program Update 1999 5-85

R-SI

duc

re

but

fi

e.

ffi

e

ral

efore

sur

l

 life

ed.

mo

 and

or

ditions were found to

fication was added at

ESP performance with

nnepin/Lakeside)

nd largely on site-spe

lity at the site, coal/gas

quirements, and value of

d that for most installa

chieve 60% NOx reduc

GR installation was

We and larger plants plus

quired) (1996$). Operat

ated to the differential

educed by the value of

The capital cost estimate for SI

was $50/kW. Operating costs for SIwere dominated by the cost of thesorbent and sorbent/ash disposalcosts. SI was projected to be costcompetitive at $300/ton of SO2

removed.Commercial ApplicationsThe GR-SI process is a unique combination of two separate technologies. The commercial applicationsfor these technologies, both separately and combined, extend to bothutility companies and industry in theUnited States and abroad. In theUnited States alone, these two technologies can be applied to more than900 pre-NSPS utility boilers. Thetechnologies also can be applied tonew utility boilers. With NOx and

SO2 removal exceeding 60% and

50%, respectively, these technologies have the potentialto extend the life of a boiler or power plant and alsoprovide a way to use higher sulfur coals.

Illinois Power has retained the gas-reburning system

and City Water, Light & Power has retained the full technology for commercial use. The project was one of tworeceiving the Air and Waste Management Association’s1997 J. Deanne Sensenbaugh Award.ContactsBlair A. Folsom, Sr. V.P., (949) 859-8851, ext. 140

General Electric Energy and Environmental ResearchCorporation18 MasonIrvine, CA 92618

Lawrence Saroff, DOE/HQ, (301) 903-9483Jerry L. Hebb, NETL, (412) 386-6079

References• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 1–Program Overview.February 1997.

• Enhancing the Use of Coals by Gas Reburning–Sorbent Injection: Volume 4: Gas Reburning Sorbent

Injection at Lakeside Unit 7, City Water, Light andPower, Springfield, Illinois. Final Report. Energy andEnvironmental Research Corporation. March 1996.Report No. DOE/PC/79796-T48-Vol.4. (Availablefrom NTIS as DE96011869.)

• Enhancing the Use of Coals by Gas Reburning–Sorbent Injection; Long Term Testing Period, September

1, 1991–January 15, 1993. Report No. DOE/PC/79796-T40. Energy and Environmental ResearchCorporation. February 1995. (Available from NTIS asDE95011481.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 2: Gas Reburning–SorbentInjection at Hennepin Unit 1, Illinois Power Company.Report No. DOE/PC/79796-T38-Vol. 2. Energy andEnvironmental Research Corporation. October 1994.(Available from NTIS as DE95009448.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 3: Gas Reburning–SorbentInjection at Edwards Unit 1, Central Illinois LightCompany. Report No. DOE/PC/79796-T38-Vol. 3.Energy and Environmental Research Corporation.October 1994. (Available from NTIS asDE95009447.)

The natural gas injector was installed

on the corner of Hennepin Station’stangentially-fired boiler.
Environmental Control Devices

Project ObjectiveTo demonstrate, with a variety of coals and sorbents, thatthe LIMB process can achieve up to 50% NOx and SO2reductions and to demonstrate that the Coolside processcan achieve SO2 removal up to 70%.

Technology/Project DescriptionThe LIMB process reduces SO2 by injecting dry sorbent

into the boiler at a point above the burners. The sorbentthen travels through the boiler and is removed along withfly ash in an electrostatic precipitator (ESP) or baghouse.Humidification of the flue gas before it enters an ESP isnecessary to maintain normal ESP operation and to enhance SO2 removal. Combinations of three bituminous

coals (1.6, 3.0, and 3.8% sulfur) and four sorbents weretested. Other variables examined were stoichiometry,humidifier outlet temperature, and injection level in theboiler.

 Babcock & Wilcox Company.

Research Institute.

In the Coolside process, dry sorbent is injected into

the flue gas downstream of the air preheater, followed byflue gas humidification. Humidification enhances ESPperformance and SO2 absorption. SO2 absorption is

improved by dissolving sodium hydroxide (NaOH) orsodium carbonate (Na2CO3) in the humidification water.

The spent sorbent is collected with the fly ash, as in theLIMB process. Bituminous coal with 3.0% sulfur wasused in testing.

Babcock & Wilcox DRB-XCL® low-NO

x burners,

which control NO

x through staged combustion, were used

in demonstrating both LIMB and Coolside technologies.

chnology

on Project

olside

merly The Babcock &

cofunder

funder and technology

Edison’s Edgewater

s (B&W) limestone

MB) system; Babcock &

urners

oolside duct injection of

% sulfur

033 100%

655 39

378 61
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Program Update 1999 5-87

• 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• 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.

1988 1989 1990 1991 1992 1993 1994 1995 1996

and Construction

11/92

Project completed/final report issued 11/92

LIMB operational tests completed 8/91

Coolside operational tests initiated 7/89

Construction completed 9/89

eaking/

n

87

itoring plan

 10/19/88

es at a calcium-to-sulfur

minimal humidification

r contents were 53–61%

lcitic lime, 45–52% for

for limestone ground to

5 mesh).

y increased to 32% using

nus 325 mesh and in

when ground to 100% less

es were enhanced by

on down to 20 oF ap

ure was used.

abcock & Wilcox

, achieved 40–50% NOx

Operation

LIMB operational testsinitiated 4/90

Coolside operational testscompleted 2/90

7/89

Economic• LIMB capital costs were $31–102/kW for plants

ranging from 100- to 500-MWe and coals with 1.5–3.5% sulfur, with a target SO2 reduction of 60%

(1992$). Annual levelized costs (15-year) for thisrange of conditions were $392–791/ton of SO2 removed.

• Coolside capital costs were $69–160/kW for plants

ranging from 100- to 500-MWe and coals with 1.5–3.5% sulfur, with a target SO2 reduction of 70%

(1992$). Annualized levelized costs (15-year) for thisrange of conditions were $482–943/ton of SO2

removed.
Environmental Control Devices

Exhibit 5-35

LIMB SO2 Removal Efficiencies

(Percent)

Nominal Coal Sulfur Content

Sorbent 3.8% 3.0% 1.6%Ligno lime 61 63 53Commercial calcitic lime 58 55 51Dolomitic lime 52 48 45Limestone NT 25 22(80% <44 microns)

NT = Not testedTest conditions: injection at 181 ft, Ca/S molar ratio of 2.0,minimal humidification.

 technology was that

o the furnace would

e of limestone in lieu of

me would keep operat

 the demonstration

ng of the limestone and

with limestone was

hydrated limes were

on, demonstrating

LIMB performance

fication to the point of

emperatures, perfor

midification.

nt upon deep humidifi

y and use of hydrated

stream of the furnace.

nhanced by dissolving

um carbonate (Na2CO3

)

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 level in the boiler. Exhibit 5-35 summarizes SO2 removal efficiencies for the range of sorbents and coals tested.

While injecting commercial limestone with 80%

of the 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% wereachieved at a stoichiometry of 2.0 when using alimestone with a smaller particle size (i.e., all particles were less than 44 microns). A third limestone withessentially all particles less than 10 microns was used todetermine what might be the removal efficiency limit.The removal efficiency for this very fine limestone wasapproximately 5–7% higher than that obtained at similarconditions for limestone with particles all sized less than44 microns.

During the design phase, it was expected that injection at the 181-foot plant elevation level inside the boiler

would permit the introduction of the limestone at close tothe optimum furnace temperature of 2,300 oF. Testingconfirmed that injection at this level, just above the noseof the boiler, yielded the highest SO2 removal. Injectionwas also performed at the 187-foot level and similarremovals were observed. Removal efficiencies whileinjecting at these levels were about 5% higher than whileinjecting sorbent at the 191-foot level.

Removal efficiencies were enhanced by approximately 10% over the range of stoichiometries tested when

humidification down to a 20 oF approach-to-saturationtemperature was used. The continued use of the low-NOx

burners resulted in an overall average NOx emissions

level of 0.43 lb/106 Btu, which is about a 45% reduction.

Operational Performance (LIMB)Long-term test data showed that the LIMB system wasavailable about 95% of the time it was called upon tooperate. Even with minimal humidification, ESP performance was adequately enhanced to keep opacity levelswell below the permitted limit. Opacity was generally inthe 2–5% range while the limit was 20%.Environmental Performance (Coolside)The Coolside process was tested while burning compliance (1.2–1.6% sulfur) and noncompliance (2.8–3.2%sulfur) coals. Objectives of the full-scale test programwere to verify short-term process operability and to develop a design performance database to establish processeconomics for Coolside. Key process variables—Ca/Smolar ratio, Na/Ca molar ratio, and approach-to-saturation temperatures—were evaluated in short-term (6–8hour) parametric tests and longer term (1–11 day) processoperability tests.

e gas, enhanced sulfur

tely 10% in the LIMB

uration was used.
Program Update 1999 5-89

ted that the Coolside

SO2 removal at design

o, 0.2 Na/Ca molar ratio,

 temperature using commercially available hydrated lime. Coolside SO2 removal depended on Ca/S molar ratio, Na/Ca molar ratio, approach-to-adiabatic-satu- ration, and the physical properties of the hydrated lime. Sorbent recycle showed significant poten- tial to improve sorbent utilization. The observed SO2 removal with recycled sorbent alone was 22% at 0.5 available Ca/S molar ratio and 18 oF approach-to-adiabatic-satu- ration. 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) Floor deposits experienced in the ductwork with the horizontal humidification led designers to consider a vertical unit in a com- mercial configuration. Short-term testing did not permit evaluation of Coolside system availability. Economic Performance (LIMB & Coolside) Economic comparisons were made between LIMB, Coolside, and a wet scrubber with limestone injection and forced oxidation (LSFO). Assumptions on performance were SO2 removal efficiencies of 60, 70, and 95% for LIMB, Coolside, and LSFO, respectively. The EPRI TAGTM methods were used for the economics, which are summarized in

Exhibits 5-36 and 5-37.

Exhibit 5-36

Cost Comparison

(1992 $/kW)

de LSFO LIMB Coolside LSFO

150-MWe

413 66 116 312

421 71 122 316

425 73 127 324

500-MWe

228 31 69 163

235 36 76 169240 40 81 174

Exhibit 5-37

ized Cost Comparison

Ton of SO2 Removed)

side LSFO LIMB Coolside LSFO

150-MWe

1418 653 797 1098

895 520 624 692665 461 570 527

500-MWe

831 480 589 623

539 416 502 411

413 392 482 321

Commercial ApplicationBoth LIMB and Coolside technologies are applicable tomost utility and industrial coal-fired units and providealternatives to conventional wet flue gas desulfurizationprocesses. LIMB and Coolside can be retrofitted withmodest capital investment and downtime, and their spacerequirements are substantially less than for conventionalflue gas desulfurization processes.

LIMB has been sold to an independent power plant

in Canada. Babcock & Wilcox has signed 124 contractsfor DLB-XCL® low-NOx burners, representing 2,428

burners for 31,467 MWe of capacity.ContactsPaul Nolan, (330) 860-1074

McDermott Technology, Inc.20 South Van Buren AvenueP.O. Box 351Barberton, OH 44203-0351

Lawrence Saroff, DOE/HQ, (301) 903-9483John C. McDowell, NETL, (412) 386-6175References• T.R. Goots, M.J. DePero, and P.S. Nolan. LIMB Demonstration Project Extension and Coolside Demonstration: Final Report. Report No. DOE/PC/79798-

T27. The Babcock & Wilcox Company. November1992. (Available from NTIS as DE93005979.)

• D.C. McCoy et al. The Edgewater Coolside Process

Demonstration: A Topical Report. Report No. DOE/PC/79798-T26. CONSOL, Inc. February 1992.(Available from NTIS as DE93001722.)

• Coolside and LIMB: Sorbent Injection Demonstrations Nearing Completion. Topical Report No. 2.

U.S. Department of Energy and The Babcock & Wilcox Company. September 1990.
Environmental Control Devices

Plant Capacity/Production300-MWeCoalPittsburgh, Freeport, and Kittanning Coals; 1.5, 2.9 and4.0% sulfur, respectively.Project FundingTotal project cost $158,607,807 100%DOE 45,000,000 28Participant 113,607,807 72Project ObjectiveTo demonstrate high sulfur capture efficiency and NOxand particulate control at minimum power requirements,zero waste water discharge, and the production of byproducts in lieu of wastes.

chnology

al

nstration

orporation

and Development

arch Corporation—

chnical consultant

GmbH (S-H-U)—tech

nufacturing Com

ogy supplier

operator of advisor

New York State Electric

ion, Unit Nos. 1 and 2)

mic-acid-enhanced, wet

BB Combustion

c Firing System

e-lined split-module

at-pipe air preheater;

em.

n Engineering, Inc.

, Inc.

Technology/Project DescriptionThe formic acid enhanced S-H-U process is designed toremove up to 98% SO2 at high sorbent utilization rates.

The Stebbins tile-lined, split-module reinforced concreteabsorber vessel provides superior corrosion and abrasionresistance. Placement below the stack saves space andprovides operational flexibility. NOx emissions are controlled by LNCFS IIITMlow-NOx burners and by micronized coal reburning. A heat-pipe air preheater is integrated to increase boiler efficiency by reducing both air

leakage and the air preheater’s flue gas exit temperature.To enhance boiler efficiency and emissions reductions,DHR’s Plant Emission Optimization Advisor (PEOATM)provides state-of-the-art artificial-intelligence-basedcontrol of key boiler and plant operating parameters.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Program Update 1999 5-91

1993 1994 1995 1996 1997 1998 1999 2000 2001

Operation

tive agreement awarded 10/20/92

Ground breaking/construction started 4/93Design completed 4/93

NEPA process completed(EA) 8/18/93

10/99

Operation completed 6/98

Project completed/final reportissued 10/99*

Operation initiated on Unit 2 1/95

6/95

Design and Construction

Environmental

monitoring

plan completed

12/1/94 Fully integrated operation of Units 1 and 2 initiated 6/95

Construction completed 6/95

emonstrated was 98%

operating and using

O2 removal without

l between the two lime

–325 mesh and 90%–170

 coal was an average of

was greater than the de

h velocity test of the

p to a liquid-to-gas ratio

0 actual cubic feet of gas.

 measurable effect on

untercurrent pumps

ubber pressure drop.

untercurrent header was

.45 inches water column

(WC) in the design flow tests and 0.64 inches WC inthe high velocity tests.

• 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 overfireair limitations were relaxed), the LOI dropped by 0.7to 1.7 percentage points, with a minor effect on NOx

emissions.

Operational• 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 pressure loss for both heat pipes was

less than the design maximum of 3.65 inches WC.The primary side pressure drops for both heat pipeswere less than the design maximum of 3.6 inches WC.The secondary air side pressure drops for both heatpipes were less than the design maximum of 5.35inches WC.

Economic• Economic data are not yet available.
Environmental Control Devices

Exhibit 5-38

of Limestone Grind

ver all of the new tech

dition to the technolo

ed that existing tech

n with new processes

upplemental monitoring

mance data illustrating

er a variety of operating

ogram was divided into

tic, performance, long

nized Coal Reburning

r another CCT Program

d over a 36-month

ed SO2 removal effi

ss economics, load

following capability, reagent utilization, by-product quality, and additive effects. Parametric testing includedformic acid concentration, L/G ratio, mass transfer, coalsulfur content, and flue gas velocity. The maximum SO2

removal demonstrated was 98% with all seven recyclepumps operating and using formic acid, and the maximum SO2 removal without formic acid was 95%. The

difference in SO2 removal between the two limestone

grind sizes tested (90%–325 mesh and 90%–170 mesh),while using low-sulfur coal was an average of 2.6 percentage points as shown in Exhibit 5-38. The SO2 removal efficiency was greater than the design efficiency

during the high velocity test of the cocurrent scrubbersection up to a liquid-to-gas ratio of 110. The cocurrentpumps had no measurable effect on pressure drop,whereas the countercurrent pumps significantly increasedthe scrubber pressure drop. As seen in Exhibit 5-39, theaverage effect of each countercurrent header was to increase pressure drop by

0.45 inches water column(WC) in the design flowtests, and 0.64 inches WCin the high velocity tests.

Performance of a

modified ESP with widerplate spacing and reducedplate area exceeded that ofthe original ESPs at lowerpower consumption. Theaverage particulate matterpenetration before the ESPmodification was 0.22%and decreased to 0.12%after the modifications.

At full boiler load

(145–150 MWe) and 3.0–3.5% economizer O2, the

LNCFSTM III lowered NO

x

emissions from a baseline

of 0.64 lb/106 Btu to 0.39 lb/106 Btu (39% reduction). At

80- to 90-MWe boiler load and 4.3–5.0% economizer O2,

the LNCFSTM III lowered NO

x

 emissions from a baseline

of 0.58 lb/106 Btu to 0.41 lb/106 Btu (29% reduction).

With LNCFSTM III, LOI was maintained below 4% andCO emissions did not increase.Operational PerformanceThe S-H-U FGD system performance goal of 98% SO2

removal efficiency was achieved. Similarly, the objective ofproducing a marketable gypsum by-product from the FGDsystem was achieved. The test results indicate that thegypsum produced can be maintained at a purity level exceeding 95% with a chloride level less than 100 ppm.

Exhibit 5-39

Pressure Drop vs.

Countercurrent Headers
Program Update 1999 5-93

 marketable calcium

lowdown stream was not

e test period was 99.9%.

rmed better than the

e. The total voltage

 directly proportional to

e modified ESP required

he original ESPs. The

t footprint with fewer

tal internal plate area is

inal ESPs, tending to

88.5% for LNCFSTM III,

89.6%. The lower effi

ost-retrofit flue gas O2

hich accompanied the air

III and baseline condi

ncy with LNCFSTM III

 than baseline.

accordance with ASME

 4.3. Air infiltration was

unted for air leakage

ween 2.0–2.4%. The

e pressure loss for both

gn maximum of 3.65

essure drops for both

ign maximum of 3.6

de pressure drops for

e design maximum of

le.

orber module, and heat

to virtually all power

features of the technolo

on of marketable by

ives to generating stations with limited space. There have been four commer- cial sales of the PEOATM system. Contacts Jim Harvilla, Project Manager, (607) 762-8630 New York State Electric & Gas Corporation Corporate Drive - Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 References • 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.
Environmental Control Devices

chnology

/SO2 

 System

ado

—cofunder

orp.—engineer

—burner developer

n—operationaltester

h evaluator

h-scale engineering

em provider

ic Service Company of

t No. 4)

s DRB-XCL® low-NOx

and furnace (urea)

st), 0.35% sulfur

306 100%

653 50

653 50

Project ObjectiveTo demonstrate the integration of five technologies toachieve up to 70% reduction in NOx and SO2 emissions;

more specifically, to assess the integration of a downfired low-NO

x burner with in-furnace urea injection for

additional NO

x removal and dry sorbent in-duct injection

with humidification for SO2 removal.

Technology/Project DescriptionAll of the testing used Babcock & Wilcox’s low-NOx

DRB-XCL® down-fired burners with overfire air. These

burners control NO

x by injecting the coal and the combustion air in an oxygen-deficient environment. Additional air was introduced via overfire air ports to complete

the combustion process and further enhance NOx removal. A urea-based selective noncatalytic reduction

(SNCR) system was tested to determine how much additional NO

x can be removed from the combustion gas. 

 Babcock & Wilcox Company.

Two types of dry sorbents were injected into the

ductwork downstream of the boiler to reduce SO2 emissions. Either calcium-based sorbent was injected upstream of the boiler economizer, or sodium-based sorbent

downstream of the air heater. Humidification downstream of the dry sorbent injection was incorporated toaid SO2 capture and lower flue gas temperature and gasflow before entering the fabric filter dust collector.

The systems were installed on Public Service Company of Colorado’s Arapahoe Station Unit No. 4, a

100-MWe down-fired, pulverized-coal boiler with roofmounted burners.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

**Years omitted

1 2

Program Update 1999 5-95

1990 1991 1992 1993 1994 1995 1996 1999 2000

Preaward Operation Design and 8/92 Construction 

3/91

) 9/27/90

 6/90

Ground breaking/construction started 5/21/91

Design completed 3/92

Preoperational tests initiated 6/92

Operation initiated 8/92Construction completed 8/92

Environmentalmonitoring plancompleted8/5/93

imum overfire air re

e than 63% under steady

24% of total combustion

9% was achieved across

ge.

h stationary and retract

rnace, provided NOx

monia (NH3) slip of

rmance of the total NOx

 80% NOx reduction.

m hydroxide injection into

oximately 1,000 oF was

tion into the fabric filter

an 40% at a calcium/

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• Arapahoe Unit No. 4 operated more than 34,000 hours

with the combustion modifications in place. Availability factor was over 91%.

2/00

Operation completed 12/96

Cooperative agreement awarded 3/11/91

Project completed/

final report issued

2/00*

• Control system modifications and additional operator

training may be necessary to improve NOx control

under load-following conditions.

• Temperature differential between the top and bottom

surfaces of the Advanced Retractable Injection Lances(ARIL) caused the lances to bend downward12–18 inches. Alternative designs corrected theproblem.

Economic• When used on units burning low sulfur coal, the technology offers SO2 and NOx removals comparable to a

wet scrubber and SCR, but at a lower cost.

• Total capital costs for the technology ranges from

$125/kW to $281/kW for 300 MWe to 50 MWe plants,respectively. Levelized costs are 12.43–7.03 mills/kWh or 1746–987 $/ton, respectively.

**
Environmental Control Devices

Public Service Company of Colorado demonstrated

low-NOx burners, in-duct sorbent injection, and SNCR at

Arapahoe Station near Denver.

sions Control System

ologies to form an

NOx and SO2. The low

f 12 Babcock & Wil

installed on the boiler

stem also incorporates

e NO

x ports added to

ately 20 feet below the

to 25% of the total

e sidewalls.

chieved using the urea

when used with the

wed the goal of 70%

her, the SNCR system

ated system, interacting

t injection (DSI) system

onia slip.

ned and installed to

 with 10 injectors at

ed by temperature

nal combustion system.

mbustion system re

 gas temperature by

g one injector level out

for effective SNCR

nal injector level, load

omised.

ble NOx reduction at

xplored. The first

ia for urea. It was

ective than urea at low

a conversion system

oved low-load perfor

not as large as desired

e second approach was

mperature regions of the

talling two NOELL

ugh 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 not only for removal and cleaning but adjustment of the injection pattern along the length of the lance in order to compensate for any significant maldistributions of flue gas velocity, temperature, or baseline 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 performance. The SO2 control system was a direct sorbent injec- tion system that could inject either calcium- or sodium- based reagents into the flue gas upstream of the fabric filter. Sorbent was injected into three locations: (1) air heater exit where the temperature was approximately 260 oF, (2) air heater entrance where the temperature was approximately 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 included 84 I-Jet nozzles that caninject up to 80 gal/min into the flue gas duct work.Environmental PerformanceThe combined DRB-XCL® burner and minimum overfire

air reduced NOx emissions by over 63% under steadystate conditions and with carefully supervised operations.

Under load-following conditions, NOx emissions were

about 10–25% higher. At maximum overfire air (4% oftotal combustion air), the low-NOx combustion system

reduced NOx emissions by 62–69% across the load range

(60- to 110-MWe). The results verified that the low-NOx

burners were responsible for most of the NOx reduction.

The original design of two rows of injector nozzles

proved relatively ineffective because one row of injectorswas in a region where the flue gas temperature was toolow for effective operation. At full load, the originaldesign achieved NOx reduction of 45%. However, the

performance decreased significantly as load decreased; at60-MWe, NOx removal was limited to about 11% with anammonia slip of 10 ppm. The addition of the retractablelances improved low-load performance of the urea-basedSNCR injection system. The ability to follow the temperature window by rotating the ARIL lances proved tobe an important feature in optimizing performance. Asa result, the SNCR system achieved NOx removal in the

range of 30–50% (at a NH3 slip limited to 10 ppm at the

fabric filter inlet), increasing total NOx reduction to

greater than 80%, significantly exceeding the goalof 70%.

Testing of calcium hydroxide injection at the economizer without humidification resulted in SO2 removal in

the range of 5–8% at a Ca/S molar ratio of 2.0. HigherSO2 removal was achieved with duct injection of calcium

hydroxide and humidification, with SO2 removals approaching 40% at a Ca/S molar ratio of 2.0 and within

20–30 oF approach-to-saturation. Sodium-based reagentswere found to be much more effective than calcium-basedsorbents and achieved significantly higher SO2 removals

during dry injection. Sodium bicarbonate injection be-
Program Update 1999 5-97

short-time SO2 removals

f 70% were achieved

quicarbonate achieved

when injected ahead of

of the sodium-based

me existing NO to NO2

.

was reduced during the

exiting at the stack was

s, small quantities of

ble plume.

emonstration of the

Ox emissions control

hnologies. The results

 occurred during the

NCR and the sodium DSI

the SNCR process sup

iated with NO-to-NO2

n.

ed more than 34,000

fications in place. The

od was over 91%. The

met or exceeded. How

ons learned during the

 in future deployment of

duct injection of calcium

der load-following con

p significantly increased.

of a hard ash cake on the

e cleaned under normal

ash cake was caused by

was not determined

operation at 30 oF ap

 or an excursion caused

L lances in NOx removal

created some operational

problems. A large differential heating pattern betweenthe top and bottom of the lance caused a significantamount 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 were slightly less

than for the ARIL lance.

When the SNCR and dry sodium systems were operated concurrently, an NH3 odor problem was encountered

around the ash silo. Reducing the NH3 slip set points to

the range of 4–5 ppm reduced the ammonia concentrationin the fly ash to the 100–200 ppm range, but the odorpersisted. It was found that the problem was related tothe rapid change in pH due to the presence of sodium inthe ash. The rapid development of the high pH level andthe attendant release of the ammonia vapor appear to berelated to the wetting of the fly ash necessary to minimizefugitive dust emissions during transportation and handling. Handling ash in dry transport trucks solved thisproblem.Economic PerformanceThe technology is an economical method of obtainingSO2 and NOx reduction on low sulfur coal units. Total

estimated capital costs range from 125 to 281 $/kW forcapacities ranging from 300 to 50 MWe. Comparably,wet scrubber and SCR capital costs range from 270 to474 $/kW for the same unit size ranges. On a levelizedcost basis, the demonstrated system costs vary from12.43–7.03 mills/kWh (1,746–987 $/ton of SO2/NOx

removed) compared to wet scrubber and SCR levelizedcosts of 23.34–12.67 mills/kWh (4,974–2,701 $/ton)based on 0.4% sulfur coal. The integrated system is most

efficient on smaller low sulfur coal units. As size andsulfur content increases, the cost advantages decrease.Commercial ApplicationsEither the entire Integrated Dry NOx/SO2 Emissions Control System or the individual technologies are applicable

to most utility and industrial coal-fired units and providelower capital-cost alternatives to conventional wet fluegas desulfurization processes. They can be retrofittedwith modest capital investment and downtime, and theirspace requirements are substantially less. They can beapplied to any unit size but are mostly applicable to theolder, small- to mid-size units.ContactsTerry Hunt, Project Manager, (303) 571-7113

Utility Engineering550 15th Street, Suite 800

Denver, CO 80202-4256

Lawrence Saroff, DOE/HQ, (301) 903-9483Jerry L. Hebb, NETL, (412) 386-6079References• Hunt, Terry, et al. “Integrated Dry NOx/SO2 Emissions

Control System: Performance Summary.” Fifth Annual Clean Coal Technology Conference: TechnicalPapers. January 1997.

• Integrated Dry NOx/SO2 Emissions Control System

Calcium-Based Dry Sorbent Injection: Test Report,April 30–November 2, 1993. Report No. DOE/PC/90550-T14. Fossil Energy Research Corporation andPublic Service Company of Colorado. December1994. (Available from NTIS as DE95007932.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Integrated Dry NOx/SO2 Emission Control System. Public Service Company of

Colorado. Report No. DOE/FE-0212P. U.S. Department of Energy. January 1991. (Available from NTISas DE91008624.)
Environmental Control Devices
tion Program Update 1999 5-99

anced Electric Power Generation

Fluidized-Bed Combustion
Advanced Electric Power Generation

eration

PCFB

oject

c

plier of pressurized

B) combustor and heat

poration—supplier of

team turbine

and Electric’s McIntosh

y integrated with

articulate filter system

chnologies

gh-sulfur bituminous

000 100%

864 50

136 50

PCFB technology

se’s ceramic candle

n technologies, which

iciency, low-emissions

ty at greenfield sites or

Technology/Project DescriptionThe project resulted from a restructuring of the DMEC-1PCFB Demonstration Project awarded under CCT-III. Inthe first of the two Lakeland Electric projects, McIntoshUnit No. 4A is being constructed with a PCFB combustoradjacent to the existing Unit No. 3 (see also McIntoshUnit 4B Topped PCFB Demonstration Project).

Coal and limestone are mixed and fed into the combustion chamber. Combustion takes place at a temperature of approximately 1,560–1,600 °F and a pressure of

about 200 psig. The resulting flue gas and fly ash leavingthe combustor pass through a cyclone and ceramic candletype HGPFS where the particulates are removed. The hotgas leaving the HGPFS is expanded through a SiemensV64.3 gas turbine. The gas inlet temperature of less than1,650 °F allows for a simplified turbine shaft and bladecooling system. The hot gas leaving the gas turbine passes through a heat recovery steam generator (HRSG). Heat recovered from both the combustor and HRSG is used to generate steam to power a reheat steam turbine. Approximately 5–10% of the gross power is derived from the gas turbine, with the steam turbine contributing the balance. The project also includes an atmospheric fluidized- bed unit that can be fired on coal or char from the carbon- izer and will replace the PCFB unit during times of PCFB unavailability, allowing various modes of operation.

SORBENT

STORAGE

PCFB

COMBUSOR

COAL

STORAGE CRUSHER

BOTTOM ASH

STEAM

CONDENSER

STACK

HEAT RECOVERY

STEAM GENERATOR

GEN.

EXHAUST

GAS

STEAM TURBINE

FLY ASH

HOT

VITIATED AIR

HOT

CYCLONE

PRESSURE

VESSEL

HGPFS

AIR

GEN.

GAS

TURBINE

COMPRESSED AIR

TO PCFB COMUSTOR
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

tion Program Update 1999 5-101

ments

rative Agreement modi

g the project restructur

Lakeland. The Lakeland

pril 1998 for the 10 year

rly Department of Elec

luded this project. The

tart of commercial op

A) in 2003. In parallel

ion of the PCFB, the

tion of the topped PCFB

ccur, with a planned start

ns continue between

 the Engineer-Procure

ology island.

are an EIS was published

 26, 1999. The public

13, 1999, in Lakeland,

Recent efforts focused on testing the HGPFS, which

is critical to system performance. Silicon carbide andalumina/mullite candle filters proved effective underconditions simulating those of the demonstration unit. Atboth 1,550 oF and 1,400 oF, the candle filters performedfor over 1,000 hours at design levels without evidence ofash bridging or structural failure. Three new oxide-basedcandle filters showed promise as well and will undergofurther testing because of the potential for reduced costand operation at higher temperatures.Commercial ApplicationsThe project serves to demonstrate the PCFB technologyfor widespread commercial deployment in post-2000.The project will include the first commercial applicationof hot gas particulate cleanup and one of the first to use anon-ruggedized gas turbine in a pressurized fluidized-bedapplication.

The combined-cycle PCFB system permits the combustion of a wide range of coals, including high-sulfur

1999 2000 

1997 2001 2002 2003 2004 2005 2006

7/03 7/05

**Years omitted

Design and Construction Operation

Design completed 9/00*

NEPA process completed (EIS)10/00*

Environmental monitoringplan completed 4/03*

Operation initiated 7/03*Preoperational tests initiated 7/03*Construction completed 7/03* Project completed/ final report issued

7/05*Operationcompleted 7/05*

coals, and would compete with the pressurized bubblingbed fluidized-bed system. PCFB can be used to repoweror replace conventional power plants. Because of modular construction capability, PCFB generating plants permitutilities to add economical increments of capacity tomatch load growth or to repower plants using existingcoal- and waste-handling equipment and steam turbines.Another advantage for repowering applications is thecompactness of the process due to pressurized operation,which reduces space requirements per unit of energygenerated.

The projected net heat rate for the system is approximately 9,480 Btu/kWh (HHV), which equates to an efficiency greater than 36%. Environmental attributes include in-situ sulfur removal of 95%, NOx emissions less

than 0.3 lb/106 Btu, and particulate matter discharge less

than 0.03 lb/106 Btu. Solid waste will increase slightly as

compared to conventional systems, but the dry material isreadily disposable or potentially usable.

tive Agreement

gned 12/19/97

**

Groundbreaking/constructionstarted 7/01*

rocess started 3/99
Advanced Electric Power Generation

eration

Topped PCFB

oject

c

plier of carbonizer;

poration—supplier of

mperature filter

and Electric’s McIntosh

n PCFB technology with

 that includes Siemens

rl burner (MASB)

7-MWe (net) McIntosh

gh-sulfur bituminous

546 100%

507 50

039 50

nology in a fully com

thereby advancing the

ill operate at higher gas

 be expected to achieve

%.

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 through the turbine, cooled in a heat

recovery steam generator, and exhausted to the stack. Thenet impact of the addition of the topping cycle is an increase in both power output and efficiency. The coal andlimestone used in McIntosh 4B are the same as those usedin McIntosh 4A.

The 240-MWe (net) plant is expected to have a heat

rate of 8,406 Btu/kWh (40.6% efficiency, HHV). Thedesign SO2 capture efficiency rate is 95%. Particulate

and NO

x emissions are expected to be 0.02 lb/106 Btu and

0.17 lb/106 Btu, respectively. In the final configuration,

the gas turbine will produce 58 MWe and the steam turbine will produce 207 MWe, while plant auxiliaries willconsume about 25 MWe.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Program Update 1999 5-103

1999

proposal for the technology island.

 The Notice of Intent to prepare an EIS was published in the Federal Register on March 26, 1999. The

public scoping meeting was held April 13, 1999, in Lakeland, Florida.

Recent efforts focused on testing the HGPFS, which

is critical to system performance. Silicon carbide andalumina/mullite candle filters proved effective underconditions simulating those of the demonstration unit. Atboth 1,550 oF and 1,400 oF, the candle filters performedfor over 1,000 hours at design levels without evidence ofash bridging or structural failure. Three new oxide-basedcandle filters showed promise as well. These will undergofurther testing because of the potential for reduced cost andoperation at higher temperatures.Commercial ApplicationsThe commercial version of the topped PCFB technologywill have a greenfield net plant efficiency of 45% (whichequates to a heat rate approaching 7,500 Btu/kWh,HHV). In addition to higher plant efficiencies, the plant

2000 2001 2003 2004 2005 2006 2007 2008

Design and Construction

7/05 7/07

Project completed/

final report issued 7/07*

Operation completed 7/07*

Operation

NEPA processcompleted (EIS) 10/00*

Design initiated 7/03*

Ground breaking/construction started 5/04*Design completed 5/04*

Operation initiated 7/05*Preoperational tests initiated 7/05*Construction completed 7/05*

Environmental monitoring plan completed 4/05*

ments

ucturing of the Four

oject awarded under the

rs project was to demon

zer (gasifier) and top

with the PCFB technol

h, Lakeland Electric will

B (McIntosh 4A) and

hnologies at one plant

operative Agreement

enting the project re

ergy Partners to the City

 Council gave approval

n of Lakeland Electric

 & Water Utilities),

arallel with the first

FB (McIntosh 4A), the

tion of the topped PCFB

 of operation is planned

nue between Lakeland

eer-Procure-Construct

perative Agreement signed

98

will (1) have a cost of electricity that is projected to be20% lower than that of a conventional pulverized-coalfired plant with flue gas desulfurization, (2) meet emission limits allowed by New Source Performance Standard(NSPS), (3) operate economically on a wide range ofcoals, and (4) be amenable to shop fabrication. The benefits of improved efficiency include reduced cost for fuelsand a reduction in CO2 emissions.

The commercial version of the topped PCFB technology has other environmental attributes, which include

in-situ sulfur retention that can meet 95% removal, NOx

emissions that will meet or exceed NSPS, and particulatematter discharge of approximately 0.03 lb/106 Btu. Although the system will generate a slight increase in solid

waste compared to conventional systems, the material is adry, readily disposable, and potentially usable material.

**

NEPA process

tarted 3/99
Advanced Electric Power Generation

eration

CFB

onstration

c Authority)

n—technology supplier

EA’s Northside Station,

ulating fluidized-bed

t)

design)

512 100%

633 24

679 76

We gross (265-MWe

reviously constructed

 the technology’s eco

al performance to

ta necessary for evalu

mercial alternative; to

removal; and to reduce

pared with conven

through the use of a polishing scrubber to be installedahead of the particulate control equipment.

Steam is generated in tubes placed along the

combustor’s walls and superheated in tube bundles placeddownstream of the particulate separator to protect againsterosion. The system will produce approximately 2 x 106

lb/hr of main steam at about 2,400 psig and 1,005 oF, and1.73 x 106 lb/hr of reheat steam at 600 psig and 1,005 oF.

The steam will be used in an existing 297.5-MWe (nameplate) steam turbine. The heat rate for the retrofit plant isexpected to be approximately 9,950 Btu/kWh (34% efficiency; HHV).

Technology/Project DescriptionA circulating fluidized-bed combustor, operating at atmospheric pressure, will be retrofitted into Unit No. 2 ofthe Northside Station. Coal or the secondary fuel (petroleum coke), primary air, and a solid sorbent (such aslimestone), are introduced into the lower part of thecombustor where initial combustion occurs. As the coalparticles 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

Energy Corp.

POLISHING

SCRUBBER

FEED WATER

CYCLONE HEAT

EXCHANGER

CIRCULATING

FLUIDIZED-BED BOILER

COAL/COKE LIMESTONE

SECONDARY

AIR

AIR

BOTTOM

ASH

TO BY-PRODUCT STORAGE STEAM TURBINE

AIR

GENERATOR

L.P. STEAM

L.P. STEAM

L.P. STEAM

H.P. STEAM

CONDENSER

PARTICULATE

CONTROL

DEVICE

PARTICULATES

STACK

INTREX

TO BY-PRODUCT STORAGE

LIME

SLURRY

AIR

HEATED AIR

TO BOILER

AIR

PREHEATER

ECONOMIZER
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Program Update 1999 5-105

Preoperational tests started 7/01*Environmental monitoring plancompleted 7/01*

ments

ited to Jacksonville,

y partners and Metropoli

activities on the ACFB

26, 1997, DOE approved

oal project from York,

orida. On September 29,

operative agreement

ment of the first (Unit

Generating Station.

on the Environmental

d on December 3, 1997, at

c hearing on the draft

1999. The closing date

 October 15, 1999.

ign, moves atmospheric

logy to the larger sizes of

d in capacity additions

300-MWe demonstration

ore than double the size

eatures include an integrated recycle heat exchanger (INTREXTM) in the fur- nace, steam-cooled cyclones, a parallel pass reheat con- trol, an SO2 polishing scrubber, and a fabric filter for particulate control. Expected environmental performance is 0.17 lb/106 Btu for SO2 (98% reduction), 0.11 lb/106 Btu for NOx, and 0.017 lb/106 Btu for total particulates (0.013 lb/106 Btu for PM10). Commercial Applications ACFB technology has good potential for application in both the industrial and utility sectors, whether for use in repowering existing plants or in new facilities. ACFB is attractive for both baseload and dispatchable power appli- cations because it can be efficiently turned down to 25% of full load. Coal of any sulfur or ash content can be used, and any type or size unit can be repowered. In repowering applications, an existing plant area is used, and coal- and waste-handling equipment as well as steam turbine equip- ment are retained, thereby extending the life of a plant. In its commercial configuration, ACFB technology offers several potential benefits when compared to conven

1992 1993 1995 1997 1999 2000 2001 2002 

Project Restructuring Operation 

2003

**

ative agreement

d 11/30/90

Project restructured 6/92

Project resited

(York) 6/93

9/97

Project restructured and resited

(Jacksonville) 8/26/97

** **

5/02 5/04

Design and Construction

NEPA process completed

(EIS York site) 8/11/95

Cooperative agreement modified 9/29/97

Operation initiated5/02*

Project completed/final report issued 5/04*

Operation completed 5/04*

Design completed

11/00*

Pre-construction

started

8/99

tional pulverized coal-fired systems: lower capital costs;reduced SO2 and NOx emissions at lower costs; higher

combustion efficiency; a high degree of fuel flexibility(including use of renewable fuels) and dry, granular solidmaterial that is easily disposed of or potentially salable.

Construction completed3/02*

NEPA process

completed

(EIS Jacksonville

site) 4/00*
Advanced Electric Power Generation

eration

stration

Corporation—

ager

—technology supplier

cofunder

hio Power Company’s

s pressurized fluidized

nder license from ABB

339 100%

993 35

346 65

onomic, environ

 in a combined-cycle

cale; and to accomplish

 NOx emission level of

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 pressurevessel 45 feet in diameter and 70 feet high. The facilitywas designed so that one-seventh of the hot gases produced could be routed to an advanced particulatefilter (APF).

The Tidd facility is a bubbling fluidized-bed combustion process operating at 12 atm (175 psi). Pressurized combustion air is supplied by the turbine compressor

to fluidize the bed material, which consists of a coalwater fuel paste, coal ash, and a dolomite or limestonesorbent. Dolomite or limestone in the bed reacts with

sulfur to form calcium sulfate, a dry, granular bed-ashmaterial, which is easily disposed of or is usable as a byproduct. A low bed-temperature of about 1,600 oF limitsNO

x

 formation.

The hot combustion gases exit the bed vessel with

entrained ash particles, 98% of which are removed whenthe gases pass through cyclones. The cleaned gases arethen expanded through a 15-MWe gas turbine. Heatfrom the gases exiting the turbine, combined with heatfrom a tube bundle in the fluid bed, generates steam todrive an existing 55-MWe steam turbine.

PRESSURIZED

FLUIDIZED-BED BOILER

PRESSURE

VESSEL

DOLOMITE/

LIMESTONE

COMPRESSED

AIR

AIR

COMBUSTION

TURBINE GEN.

GEN.

BED

VESSEL

COAL

WATER

CLEAN

HOT GAS

STEAM

CYCLONES STEAM TURBINE

BED

PREHEATER CONDENSER

FEED

WATER

WASTE

HEAT

RECOVERY

ELECTROSTATIC

PRECIPITATOR

STACK

TO DISPOSAL

ASH

COOLER

CYCLONE

ASH

BED ASH

FEED WATER

INLET

FLY ASH
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

tion Program Update 1999 5-107

effect on SO2 removal

ion and heat transfer

d-bed.

% was achieved at full

(Ca/S) molar ratio of

0 oF.

% was achieved at full

of 1.5 and temperature of

3 lb/106 Btu.

0.01 lb/106 Btu.

ss than 0.02 lb/106 Btu.

Operational• Combustion efficiency ranged from an average 99.3%

at low bed levels to an average 99.5% at moderate tofull bed levels.

• Heat rate was 10,280 Btu/kWh (HHV, gross output)

(33.2% efficiency) because the unit was small and noattempt was made to optimize heat recovery.

• An advanced particulate filter (APF), using a silicon

carbide candle filter array, achieved 99.99% filtrationefficiency on a mass basis.

• PFBC boiler demonstrated commercial readiness.• ASEA Stal GT-35P gas turbine proved capable of

operating commercially in a PFBC flue gasenvironment.

Economic• The Tidd plant was a relatively small-scale facility,

and as such, detailed economics were not prepared aspart of this project.

• A recent cost estimate performed on Japan’s 360-MWe

PFBC Karita Plant projected a capital cost of$1,263/kW (1997$).

1988 1989 1990 1991 1992 1993 1994 1995 1996

Design and Construction Operation

ment awarded 3/20/87

pleted (MTF) 3/5/87

Environmental monitoringplan completed 5/25/88

Groundbreaking ceremony 4/6/88

truction started 12/9/87

Operation initiated 3/91

Preoperational tests started 12/90Construction completed 12/90Design completed 12/90

3/91

/24/86

12/95

Projectcompleted/final reportissued 12/95

Operation completed 3/95
Advanced Electric Power Generation

significant maintenance. While the tube bundle experienced little wear, a significant amount of erosion on eachof the four water walls was observed. This erosion posedno problem, however, because the area affected is notcritical to heat transfer and could be protected byrefractory.

The prototype gas turbine experienced structural

problems and was the leading cause of unit unavailabilityduring the first 3 years of operation. However, designchanges instituted over the course of the demonstrationproved effective in addressing the problem. The Tidddemonstration showed that a gas turbine could operate ina PFBC flue gas environment.

Efficiency of the PFBC combustion process was

calculated during testing from the amount of unburnedcarbon in cyclone and bed ash, together with measurements of the amount of carbon monoxide in the flue gas.Combustion efficiencies averaged 99.5% at moderate to

The PFBC demonstration at the repowered 70-MWe

unit at Ohio Power’s Tidd Plant led to significant refinementsand understanding of the technology.

bbling fluidized-bed

2 atmospheres

s inherently efficient.

 enhances combustion

eratures that mitigate

orbent reactions that

ue gas energy that is

tter contributed signifi

e of the high efficiency

 of gas turbine exhaust

m cycle. A bed design

ished because it was

re at the gas turbine

ures for coal ash fu

alkali vaporization.

nch or less was injected

 paste containing 25%

t, either dolomite or

uidized bed via two

m two lock hoppers.

sed two injector

wo more nozzles to

t APF was installed

earch and development

Program demonstration.

ilters to clean one

the PFBC system. The

ed one of the seven

n plant accumulated

ons during its 54

mpleted 95 parametric

red runs of 28, 29, 30,

coals having sulfur

 demonstration.

Environmental PerformanceTesting showed that 90% SO2 capture was achievable

with a Ca/S molar ratio of 1.14 and that 95% SO2 capture

was possible with a Ca/S molar ratio of 1.5, provided 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 to the process, which wasoperating at approximately 1,580 oF. No NOx control

enhancements, such as ammonia injection, were required.Emissions of carbon monoxide and particulates were lessthan 0.01 and 0.02 lb/106 Btu, respectively.

Operational PerformanceExcept for localized erosion of the in-bed tube 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 require
tion Program Update 1999 5-109

esign or expected effi

oad operation, a heat rate

 was calculated. This

namic efficiency of

 produced 70-MWe of

ning Pittsburgh No. 8

s a repowering applica

le, the measured effi

would be expected for a

dd technology. Studies

y Demonstration Project

40% are likely for a

t showed that the PFBC

ic power generation.

ct led to significant re

he technology in the

utilization, sintering,

al, and boiler materials.

5,800 hours of coal-fired

essel was structurally

n carbide candle filters

s subjected to side loads

he vessel; bridging was

s included in the particu

 (mass basis) was 99.99%.

mall-scale demonstration

ere not prepared as part

nt cost estimate per

BC Karita Plant pro

W (1997$).

use of a wide range of

s. The compactness of

allows utilities to signifi

ng sites. Compactness of

the process due to pressurized operation reduces spacerequirements per unit of energy generated. PFBC technology appears to be best suited for applications of 50 MWeor larger. Capable of being constructed modularly, PFBCgenerating plants permit utilities to add increments ofcapacity economically to match load growth. Plant lifecan be extended by repowering with PFBC using theexisting plant area, coal- and waste-handling equipment,and steam turbine equipment.

The 360-MWe Karita Plant in Japan, which uses

ABB Carbon P800 technology, represents a major movetoward commercialization of PFBC bubbling-bed technology. A second generation P200 PFBC is under construction in Germany. Other PFBC projects are underconsideration in China, South Korea, the United Kingdom, Italy, and Israel.

The Tidd project received Power magazine’s 1991

Powerplant Award. In 1992, the project received theNational Energy Resource Organization award for demonstrating energy efficient technology.ContactsMichael J. Mudd, (614) 223-1585

American Electric Power Service Corporation1 Riverside PlazaColumbus, OH 43215,(614) 223-2499 (fax)

George Lynch, DOE/HQ, (301) 903-9434Donald W. Geiling, NETL, (304) 285-4784References• Tidd PFBC Hot Gas Cleanup Program Final Report.

Report No. DOE/MC/26042-5130. The Ohio PowerCompany. October 1995. (Available from NTIS asDE96000650.)

• Tidd PFBC Demonstration Project Final Report,

Including Fourth Year of Operation. The Ohio PowerCompany. August 1995. (Available from DOE Library/Morgantown, 1-800-432-8330, ext. 4184 as Coal and sorbent conveyors can be seen just after

entering the Tidd plant.

DE96000623.)

• Tidd PFBC Demonstration Project Final Report,

March 1, 1994–March 30, 1995. Report No. DOE/MC/24132-T8. The Ohio Power Company. August1995. (Available from NTIS as DE96004973.)

• Tidd PFBC Demonstration Project—First Three Years

of Operation. Report No. DOE/MC/24132-5037-Vol.1 and 2. The Ohio Power Company. April 1995.(Available from NTIS as DE96000559 for Vol. 1 andDE96003781 for vol. 2.)
Advanced Electric Power Generation

bent improves mixing and extends the contact time ofsolids and gases, thus promoting high utilization of thecoal and high-sulfur-capture efficiency. Heat in the fluegas exiting the hot cyclone is recovered in the economizer. Flue gas passes through a baghouse where particulate matter is removed. Steam generated in theACFB is used to produce electric power.

Three small, coal-fired, stoker-type boilers at Nucla

Station were replaced with a new 925,000-lb/hr ACFBsteam generator capable of driving a new 74-MWe turbine generator. Extraction steam from this turbine generator powers three existing turbine generators (12-MWeeach).

Project ObjectiveTo demonstrate the feasibility of ACFB technology atutility scale and to evaluate the economic, environmental,and operational performance at that scale.Technology/Project DescriptionNucla’s circulating fluidized-bed system operates at atmospheric pressure. In the combustion chamber, a streamof air fluidizes and entrains a bed of coal, coal ash, andsorbent (e.g., limestone). Relatively low combustiontemperatures limit NOx formation. Calcium in the sorbent

combines with SO2 gas to form calcium sulfite and sulfate

solids, and solids exit the combustion chamber and flowinto a hot cyclone. The cyclone separates the solids fromthe gases, and the solids are recycled for combustor temperature control. Continuous circulation of coal and sor

eration 

stration 

sion Association, Inc. 

n*—technology 

ial users)—cofunder 

—technical consultant 

cla Station) 

ulating fluidized-bed 

sh 

sh 

949 100% 

411 11 

538 89 

ology developer and

nergy Corp.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

tion Program Update 1999 5-111

test effect on pollutant

y.

620 oF, sulfur capture

ere achieved at calcium

of 1.5 and 4.0,

ns averaged 0.18 lb/106

b/106 Btu.

0–140 ppmv.

from 0.0072–0.0125

a removal efficiency

enign and showed poten

endment, soil/roadbed

Operational• Boiler efficiency ranged from 85.6–88.6% and combustion efficiency ranged from 96.9–98.9%.• A 3:1 boiler turndown capability was demonstrated.• Heat rate at full load was 11,600 Btu/kWh and was

12,400 Btu/kWh at half load.

Economic• Capital cost for the Nucla retrofit was $1,123/kW and a

normalized power production cost was 64 mills/kWh.

1989 1990 1991 1992 1993 1994 1995 1996

Operation

1997

ring

88

mpleted (MTF) 4/18/88

Operationcompleted 1/91

est program initiated 8/88

ative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92
Advanced Electric Power Generation

Exhibit 5-40

 Effect of Bed Temperature

on Ca/S Requirement

d from efforts to find a

controlling pollutant

s. Fluidized-bed com

on at temperatures of

ermal NOx formation

s high SO2-capture

nt/flue gas contact.

ional fluid-bed combus

at exchanger in the fluid

ion velocity, ACFB

velocity, which entrains

pture and return the

 bed to control tempera

ct time and to protect a

DOE, EPRI, and the

ial users) resulted in the

broad utility application

ram. Over a two-and-a

erformance tests were

d. The result was a

mprehensive, available

991, the plant operated

% and an average capac

rd the end of the demon

blems had been over

hs of the demonstration,

the capacity factor was

mperature at which

ature was found to be the

er. With the exception of

 air at elevated tempera

 parameter that had a

d 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

from 85.6–88.6%. The contributions to boiler heat losswere identified as unburned carbon, sensible heat in dryflue gas, fuel and sorbent moisture, latent heat in burninghydrogen, sorbent calcination, radiation and convection,and bottom-ash cooling water. Net plant heat rate decreased with increasing boiler load, from 12,400 Btu/kWhat 50% of full load to 11,600 Btu/kWh at full load. Thelowest value achieved during a full-load steady-state testwas 10,980 Btu/kWh. These values were affected by the

Ca/S Molar Ratio

Mean Bed Temperature ( F)

1450 1500 1550 1600 1650 1700 1750

6.56.05.55.04.54.03.53.02.52.01.51.0

absence of reheat, the presence of the three older 12.5-MWe turbines in the overall steam cycle, the number ofunit restarts, and part-load testing.Environmental PerformanceAs indicated above, bed temperature had the greatestimpact on ACFB performance, including pollutant emissions. Exhibit 5-40 shows the effect of bed temperatureson the Ca/S molar ratio requirement for 70% sulfur retention. The Ca/S molar ratios were calculated based on thecalcium content of the sorbent only, and do not accountfor the calcium content of the coal. While a Ca/S molarratio of about 1.5 was sufficient to achieve 70% sulfurretention in the 1,500–1,620 °F range, the Ca/S molarratio requirement jumped to 5.0 or more at 1,700 °F orgreater.

Exhibit 5-41 shows the effect of Ca/S molar ratio on

sulfur retention at average bed temperatures below 1,620 oF.Salt Creek and Peabody coals contain 0.5% and 0.7%sulfur, respectively. To achieve 70% SO2 reduction, or

the 0.4 lb/106 Btu emission rate required by the licensing

Plant layout with coal and limestone feed locations.
tion Program Update 1999 5-113

 approximately 1.5 is

duction of 95%, a Ca/S

is necessary. Dorchester

ent, required a somewhat

n reduction.

roughout the demonstra

tu, which is well below

Btu. The average level

s 0.18 lb/106 Btu. NOx

rong correlation with

ppmv (0.06 lb/106 Btu) at

06 Btu) at 1,700 °F.

ntified as a variable

mewhat higher NOx

ng calcium-to-nitrogen

nism was believed to be

the form of ammonia

e. CO emissions de

rom 140 ppmv at 1,425 oF

At full load, the hot cyclones removed

99.8% of the particulates. With the additionof baghouses, removal efficienciesachieved on Peabody and Salt Creek Coalswere 99.905% and 99.959%, respectively.This equated to emission levels of 0.0125lb/106 Btu for Peabody coal and 0.0072 lb/

106 Btu for Salt Creek coal, well below the

required 0.03 lb/106 Btu.

Economic PerformanceThe final capital costs associated with theengineering, construction, and startup of theNucla ACFB system were $112.3 million.This represents a cost of $1,123/kW (net).Total power costs associated with plant operations between September 1988 and January 1991 were approximately $54.7 million,resulting in a normalized cost of power production of 64 mills/kWh. The average

monthly operating cost over this period was about$1,888,000. Fixed costs represent about 62% of thetotal and include interest (47%), taxes (4.8%), depreciation (6.9%), and insurance (2.7%). Variable costs represent more than 38% of the power production costs andinclude fuel expenses (26.2%), non-fuel expenses(6.8%), and maintenance expenses (5.5%).Commercial ApplicationsThe Nucla project represented the first repowering of aU.S. utility plant with ACFB technology and showed thetechnology’s effectiveness 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

ACFB system in its product line. There are now more

than 120 fluidized-bed combustion boilers of varyingcapacity operating in the U.S. and the technology hasmade significant market penetration abroad. The fuelflexibility and ease of operation make it a particularlyattractive power generation option for the burgeoningpower market in developing countries.ContactsStuart Bush, (303) 452-6111

Tri-State Generation and Transmission Ass’n., Inc.P.O. Box 33695Denver, CO 80233

George Lynch, DOE/HQ, (301) 903-9434Thomas Sarkus, NETL, (412) 386-5981References• Colorado-Ute Nucla Station Circulating FluidizedBed (CFB) Demonstration—Volume 2: Test Program

Results. EPRI Report No. GS-7483. October 1991.

• Demonstration Program Performance Test: Summary

Reports. Report No. DOE/MC/25137-3104. ColoradoUte Electric Association, Inc. March 1992. (Availablefrom NTIS as DE92001299.)

• Economic Evaluation Report: Topical Report. Report

No. DOE/MC/25137-3127. Colorado-Ute ElectricAssociation, Inc., March 1992. (Available from NTISas DE93000212.)

• Nucla CFB Demonstration Project: Detailed Public

Design Report. Report No. DOE/MC/25137-2999.Colorado-Ute Electric Association, Inc., December1990. (Available from NTIS as DE91002081.)

bit 5-41

quirements and

s for Various Fuels
Advanced Electric Power Generation
tion Program Update 1999 5-115

anced Electric Power Generation

ated Gasification Combined-Cycle
Advanced Electric Power Generation

eration

ed Cycle

Energy IGCC

oject

nergy Research Corpo

 cell designer and sup

ntucky Power

ycle (IGCC) using a

slagging fixed-bed

Energy Research

el cell (MCFC)

MCFC

coal blended with mu

714 100%

357 18

225 82

ability, availability, and

GCC system using a

unicipal solid waste

ed, slagging gasifier

bonate fuel cell fueled

Technology/Project DescriptionThe BGL gasifier is supplied with steam, oxygen, limestone flux, and a coal and municipal waste blend. Duringgasification, the oxygen and steam react with the coal andlimestone flux to produce a raw, coal-derived fuel gasrich in hydrogen and carbon monoxide. Raw fuel gasexiting the gasifier is washed and cooled. Hydrogensulfide and other sulfur compounds are removed. Elemental sulfur is reclaimed and sold as a by-product.Tars, oils, and dust are recycled to the gasifier. The resulting clean, medium-Btu fuel gas fires a gas turbine. Asmall portion of the clean fuel gas is used for the MCFC.

The MCFC is composed of a molten carbonate electrolyte sandwiched between porous anode and cathode

plates. Fuel (desulfurized, heated medium-Btu fuel gas)and steam are fed continuously into the anode;

CO2-enriched air is fed into the cathode. Chemical reactions produce direct electric current, which is converted

to alternating power in an inverter.

HEAT RECOVERY

STEAM

GENERATOR

STEAM TURBINE

STACK

GEN.

COMBUSTOR

GAS

SLIPSTREAM

GAS-POLISHING

AND

MOISTURIZATION 1.25 MWe FUEL CELL

FUEL

GAS

TARS,

OILS,

PARTICULATES

SLAG

GRATE AIR

BRITISH GAS

LURGI

COAL

GASIFIER

EXHAUST

GAS

STEAM

AND

OXYGEN

STEAM

STEAM

STEAM

TARS,

OILS,

PARTICULATES

CONVENTIONAL

GAS

CLEANUP

GAS

LIQUOR

SEPARATOR

COAL AND

BRIQUETTES

O2

OXYGEN

PLANT

N TO

COMBUSTOR

2

AQUEOUS

EFFLUENT

SULFUR

BY-PRODUCT

GAS TURBINE HOT GAS

N2

SULFUR

RECOVERY

GEN.

PRODUCT

GAS

COOLER

TO DISPOSAL
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Program Update 1999 5-117

1998 1999 

1994 2000 2001 2002 2003 2004 2005

award

ments

tionally approved

ger of Union Electric Co.

ce Co.) as an equity

bject to completing spe

tones. The new project

as at their Venice Station

East St. Louis, Illinois.

ices Company withdrew

d business reasons.

y USA Limited (Global),

Energy L.L.C. (KPE),

e project and providing a

 Cooperative’s Smith

Subsequently, Global

ments with DOE and

P) to acquire the project.

ative Agreement

d 12/2/94

Design and Construction

Commercial ApplicationsThe IGCC system being demonstrated in this project issuitable for both repowering applications and new powerplants. The technology is expected to be adaptable to awide variety of potential market applications because ofseveral factors. First, the BGL gasification technologyhas successfully used a wide variety of U.S. coals. Also,the highly modular approach to system design makes theBGL-based IGCC and molten carbonate fuel cell competitive in a wide range of plant sizes. In addition, thehigh efficiency and excellent environmental performanceof the system are competitive with or superior to otherfossil-fuel-fired power 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

12/94 7/03

Operation

Operation initiated 7/03*

Final report issued/projectcompleted 7/04*

**

Novation of cooperativeagreement; New siteapproved 11/99* New site approved 5/98

CO2 when compared to a conventional pulverized coalplant equipped with a scrubber. SO2 emissions from the

IGCC system are expected to be less than 0.1 lb/106 Btu

(99% reduction); and NOx emissions less than 0.15 lb/106

Btu (90% reduction).

Also, the slagging characteristic of the gasifier produces a nonleaching, glass-like slag that can be marketed

as a usable by-product.

7/04

Start construction 2/01*
Advanced Electric Power Generation

eration

ed Cycle

Power

—architect, engineer,

hnology supplier

ineer

Pacific Power

ycle (IGCC) using the

zed-bed coal

9% sulfur (design coal);

planned test)

000 100%

500 50

500 50

zed fluidized-bed

ot gas cleanup; to evalu

ine; and to assess long

ainability, and environ

icient to determine

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 formcalcium 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

through cyclones, which return most of the entrainedparticulate matter to the gasifier. The gas, which leavesthe gasifier at about 1,700 oF, is cooled to about 1,100 oFbefore entering the hot gas cleanup system. Duringcleanup, virtually all of the remaining particulates areremoved by ceramic candle filters, and final traces ofsulfur are removed by reaction with a metal oxide sorbent in a transport reactor.

The cleaned gas then enters the GE MS6001FA

(Frame 6FA) combustion turbine, which is coupled to a61-MWe (gross) generator. Exhaust gas from the combustion turbine is used to produce steam in an HRSG.Superheated high-pressure steam drives a condensingsteam turbine-generator designed to produce about46 MWe (gross).

The IGCC plant will remove 95+% of the sulfur in

the coal. Due to the relatively low operating temperatureof the gasifier and the injection of steam into the combustion fuel stream, the NOx emissions are expected to be

70% less than a conventional coal-fired plant. The IGCCwill produce 20% less CO2 than conventional plants.

STEAM TURBINE

STEAM

GEN.

GEN.

STACK STEAM

HEAT RECOVERY

STEAM

GENERATOR

FEED

WATER

HOT GAS

STEAM FROM

GAS COOLER

COMBUSTION TURBINE

STEAM

AIR

AIR

COMP.

SOLID WASTE

AGGLOMERATES

SULFUR

REMOVAL

GAS

COOLER

HOTGAS

CLEANUP COAL & LIMESTONE

HANDLING

FLUIDIZED-BED

GASIFIER CYCLONE

STEAM TO HRSG
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

tion Program Update 1999 5-119

1993 1994 1995 1996 1997 1998 1999 2000 2001

Design and Construction Operation

1/01

e agreement awarded 8/1/92

Project completed/final report issued 1/01*

Operation completed 1/01*

Ground breaking/construction started 2/95

NEPA process completed (EIS) 11/8/94

Design completed 8/95

Despite the problems with the gasifier, the plant

continues to operate on natural gas. The first-of-a-kindGE Frame 6FA CT had an 85 percent availability in 1998and a 100 percent availability in the first quarter of 1999.Sierra Pacific’s 2000 performance goals include: 90 percent combined-cycle availability; achieve stable, sustained production of syngas; demonstrate sustained operation on syngas; and successfully run the gas turbine onsyngas.Commercial ApplicationsThe Piñon Pine IGCC system concept is suitable for newpower generation, repowering needs, and cogenerationapplications. The net heat rate for a proposed greenfieldplant using this technology is projected to be 7,800 Btu/kWh (43.7% efficiency), representing a 20% increase inthermal efficiency compared to a conventional pulverizedcoal plant with a scrubber and a comparable reduction inCO2 emissions. The compactness of an IGCC system

reduces space requirements per unit of energy generatedrelative to other coal-based power generation systems.

ments

n operations but contin

ficulties. The station

n November 1996. Pre

wn of the coal gasification

d through 1997 with

8. The plant was dedi

fer from a number of

ve been solved, but oth

 three months of 1999,

ns, which averaged 7

g 12 hours. The gasifier

hours. Problems have

e of new technology,

 components, and some

ies. Nevertheless, Sierra

flaws exist that will

on and subsequent com

cation technology.

Environmental monitoring plancompleted 10/31/96

Preoperational tests initiated 11/96

1/98

Operation initiated 1/98

Construction completed 2/97

The advantages provided by phased modular constructionreduce the financial risk associated with new capacityadditions.

The KRW IGCC technology is capable of gasifying

all types of coals, including high-sulfur, high-ash, lowrank, and high-swelling coals, as well as bio- or refusederived waste, with minimal environmental impact.There are no significant process waste streams that require remediation. The only solid waste from the plant isa mixture of ash and calcium sulfate, a nonhazardous waste.
Advanced Electric Power Generation

eration

ed Cycle

egrated

bined-Cycle

—gasification

mbined-cycle

—air separation unit

Inc.—sulfuric acid

n—project manager and

itect and engineer

a Electric Company’s

ombined-cycle (IGCC)

, oxygen-blown en

We (net)

y # 11, and Kentucky

446 100%

223 49

223 51

Project ObjectiveTo 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 DescriptionCoal/water slurry and oxygen are reacted at high temperature and pressure to produce a medium BTU syngas in aTexaco gasifier. Molten ash flows out of the bottom ofthe gasifier into a water-filled sump where it is forms asolid slag. The syngas moves from the gasifier to a hightemperature heat-recovery unit, which cools the syngaswhile generating high pressure steam. The cooled gasesflow to a water wash for particulate removal. Next, a

COS hydrolysis reactor converts one of the sulfur speciesin the gas to a form which is more easily removed. Thesyngas is then further cooled before entering a conventional amine sulfur removal system. The amine systemkeeps SO2 emissions below 0.15 lb/106 Btu (97% capture). The cleaned gases are then reheated and routed to a

combined-cycle system for power generation. (A 10 MWeslipstream for hot syngas cleanup system had been envisioned but has been placed on hold pending resolution oftechnical problems.) A GE MS 7001FA combustionturbine (CT) generates 192 MWe. Thermal NOx is controlled to below 0.27 lb/ 106 Btu by injecting nitrogen. A

steam turbine uses steam produced by cooling the syngasand superheated with the CT exhaust gases in the HRSGto produce an additional 124-MWe. The plant heat rate is9350 Btu/KWH (HHV), which is an efficiency of 38.4%(LHV).

STEAM TURBINE

GEN.

HEAT RECOVERY

STEAM

GENERATOR

STACK

SULFURIC ACID

PLANT

HOT EXHAUST

GAS

GAS TURBINE

GEN.

SULFURIC

ACID

STEAM

STEAM

BLACK WATER

RECYCLED

SLAG

DISPOSAL

RADIANT

SYNGAS

COOLER

FEED WATER

HIGH-PRESSURE

STEAM

RAWSYNGAS SULFUR REMOVAL

CLEAN

SYNGAS

COMBUSTOR N2

AIR

SYNGAS

PARTICULATES

N

TO COMBUSTOR

2

TEXACO

GASIFIER

CYCLONE

OXYGEN

PLANT

PRODUCT

GAS

COOLER

RAW

SYNGAS

RAWSYNGAS

RAWSYNGAS

HOT-GAS

CLEANUP

CONVENTIONAL

GAS

CLEANUP

10%

90%

O2

SLURRY

PLANT

COAL

SLURRY

ENTRAINEDFLOW GASIFIER

- - - - Future
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Program Update 1999 5-121

1990 1991 1994 1995 1996 1997 1998 1999 2001

Preaward Design and Construction

3/91

**

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

Project completed/final report issued 10/01*

Operation completed 10/01*

10/01

Operation

Environmental monitoring plan completed 5/96

**

3 4

ments

gasifier run in July 1996,

000 hours. The station

MWh of electricity from

ember 1999. During one

d an 83.5% on-stream

vailability was 94%. The

continuous operation

ctively.

 original design and

eve the recent high avail

r modifying some of the

erature heat recovery

g adjustments in the

ash plugging problems,

on protection for the

e machine from ash, (3)

ures to reducer gasifier

ng a duplicate fines

reased fines loading

resulting 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.

Tampa Electric will face two major challenges in

2000, both of which have efficiency improvement as amajor objective. The first will be to commission the slaghandling system that separates the slag into its mainconstituents, a useful by-product for sale and a suitablefuel for recycle. The second will be to upgrade the brineconcentration system.ApplicationsThe project was presented the 1997 Powerplant Award byPower magazine. In 1996 the project received the association of Builders and Contractors Award for construction quality. Several awards were presented for using and

innovative siting process: 1993 Ecological Society ofAmerica Corporate Award and 1993 Timer Powers Conflict Resolution Award from the State of Florida, and the1991 Florida Audubon Society Corporate Award.

As a result of the Polk Power Station demonstration,

Texaco-based IGCC can be considered commercially andenvironmentally suitable for electric power generationutilizing a wide variety of feedstocks. Sulfur capture forthe project is greater than 98%, while NOx emission reduction are 90% that of a conventional pulverized coalfired power plant. The integration and control approaches

utilized at Polk can also be applied in IGCC projectsusing different gasification technologies.

TECO Energy is not only actively working with

Texaco to commercialize the technology in the UnitedStates, but has been contacted by European powerproducers to discuss possible technical assistance onusing the gasifier technology.
Advanced Electric Power Generation

eration

ed Cycle

l

wering

epowering Project Joint

 and PSI Energy, Inc.)

Inc., a subsidiary of

ngineer and gas plant

N (PSI Energy’s Wabash

. 1)

ycle (IGCC) using

ized, oxygen-blown,

000 100%

000 50

000 50

with a two-stage pres

ow IGCC system,

hnology relevant to the

; and to assess long

aintainability of the

e.

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 at2600 °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 the syngas cooler, essentially a firetube steam generator, to produce high-pressure saturated steam. After cooling in the syngas cooler, particulates are removed in a hot/dry filter and recycled to the gasifier. The syngas is further cooled in a series of heat exchangers. The syngas is water- scrubbed to remove chlorides and passed through a catalyst that hydrolyzes carbonyl sulfide into hydrogen sulfide. Hydrogen sulfide is removed in the acid gas removal system using MDEA-based absorber/stripper columns. A Claus unit is used to produce elemental sulfur as a salable by-product. The “sweet” gas is then moisturized, preheated, and piped to the power block. The power block consists of a single 192-MWe GE MS 7001FA (Frame 7 FA) gas turbine, a Foster Wheeler single-drum heat recovery steam generator with reheat, and a 1952 vintage Westinghouse reheat steam turbine.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

tion Program Update 1999 5-123

ments

ation Repowering

gest single train IGCC

 currently in its fourth

he end of the planned

asification process (for

cation process) has

ate at full load while

ments for SO2 and NOx

nstrating a heat rate of

emissions of 0.1 lb/106

re 0.15 lb/106 Btu and

detectable limits. The

ely 15,000 hours and

llion tons of coal to

syngas.

bine has performed well

ems. In addition to

ves and in the combustion

ressor rows 4 through 17

amage in mid-March

1993 1994 1995 1996 1997 1998 1999 2000 2001

Operation

Design and Construction

NEPA process completed (EA) 5/28/93

Design completed 5/94

greement awarded 7/28/92

Environmental monitoring plan completed 7/9/93Groundbreaking ceremony 7/7/93

Preoperational tests initiated 8/95

11/95 4/00

Demonstration completed 12/99*

Operation initiated 11/95Construction completed 11/95

1999, resulting in a three month outage. The outageallowed time to focus on other issues. Efforts are nowfocused on reducing nuisance trips in the air separationunit, which produces 2,060 tons/day of 95% pure oxygen.The particulate removal system has performed well sincea major improvement project in 1997. Downtime associated with the barrier filter system had been reduced bynearly 80% over the first commercial year statistics. Anongoing filter element development program reduced1998 filter-related downtime by an additional 66 percentover 1997. An extended outage adversely affected the1999 operating statistics; however, the facility was able toset another quarterly production record of 2.7 x 1012 Btu.

In 1999, the annual contract capacity was 69.9% and theannual availability was 79.1%. For comparison, the 1998annual availability was 71.8%.

Destec Energy and CINergy Corp./PSI Energy received the 1996 Powerplant Award from Power magazine.

Sargent & Lundy, engineer for the combined-cycle facility,won the American Consulting Engineers Council’s 1996Engineering Excellence Award.

Project completed/final reportissued 4/00*

On December 31, 1999, the demonstration was

completed and Global Energy, Inc. purchased Dynegy’sgasification assets and technology. Global Energy plansto market the technology under the name “E-GasTechnologyTM.”Commercial Applications

Throughout the United States, particularly in the

Midwest and East, there are more than 95,000-MWe ofexisting coal-fired utility boilers over 30 years old. Manyof these plants are without air pollution controls and arecandidates for repowering with IGCC technology. Repowering these plants with IGCC systems will improve plantefficiencies and reduce SO2, NOx, particulate, and CO2

emissions. The modularity of the gasifier technology willpermit a range of units to be considered for repowering,and the relatively short construction schedule for the technology will allow utilities greater flexibility in designingstrategies to meet load requirements. Also, the high degreeof fuel flexibility inherent in the gasifier design will provide utilities with more choice in selecting fuel supplies tomeet increasingly stringent air quality regulations.
Advanced Electric Power Generation
tion Program Update 1999 5-125

anced Electric Power Generation

anced Combustion/Heat Engines
Advanced Electric Power Generation

eration

ngines

Project

d Export Authority

n—host and operator

orp.—engineer

ivision—combustor

(B&W) (which has

mental Technologies,

hnology supplier

pplier

ent to Healy Unit

ng) combustor; Bab

rber with sorbent re

f-mine (ROM) and

000 100%

000 48

000 52

 power plant design

ed combustor and heat

h high- and low-tem

es.

control. The ash forms molten slag, which accumulateson the water-cooled walls and is driven by aerodynamicand gravitational forces through a slot into the slag recovery section. About 70–80% of the ash is removed asmolten slag. The hot gas is then ducted to the furnacewhere, to ensure complete combustion, additional air issupplied from the tertiary air windbox to NOx ports and to

final overfire air ports. Pulverized limestone (CaCO3) for

SO2 control is fed into the combustor where it is flash

calcined (converting CaCO3 to lime (CaO). The mixture

of this CaO and ash not slagged, called flash-calcinedmaterial, is removed in the fabric filter system. Most ofthe flash-calcined material is used to form a 45% flashcalcined-material solids slurry. The SO2 in the flue gas

reacts with the slurry droplets as water is simultaneouslyevaporated. The SO2 is further removed from the flue gas

by reacting with the dry flash-calcined material on the

Technology/Project DescriptionThe project involves two unique slagging combustors.Emissions of SO2 and NOx are controlled using TRW’s

slagging combustion systems with staged fuel and air andlimestone injection for SO2 control. Additional SO2 is

removed using B&W’s activated recycle spray dryer absorber system.

A coal-fired precombustor increases the air inlet

temperature for optimum slagging performance. Theslagging combustors are side mounted, injecting the combustion products vertically into the boiler. The main slagging combustor consists of a water-cooled cylinder thatslopes toward a slag opening. The precombustor burns25–40% of the total coal input. The remaining coal isinjected axially into the combustor, rapidly entrained bythe swirling precombustor gases and additional air flow,and burned under substoichiometric conditions for NO

x
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Program Update 1999 5-127

ments

 existing Healy Unit No.

Usibelli coal mine.

Valley Electric Associa

0 tons/day of subbitumi

otential impact to the

 Preserve, DOE, the

nd the project participant

uce emissions from Unit

s from the two units will

e currently emitted from

sions will be further

sary to protect the park.

ained slagging combus

uary 1998. The results

testing showed that NOx

missions of 0.01 lb/106 Btu,

47lb/106 Btu were

late emission measures

were within permit requirements. The permit requiresNO

x

 emissions to be less than 0.35 lb/106 Btu, SO2 emissions less than 0.086 lb/106 Btu, and particulate emissions

less than 0.03 lb/106 Btu. The stringent SO2 emission

level required by the permit is significantly lower than the1.2 lb/106 Btu NSPS limit.

The following modifications were made during a

routine outage completed in January 1999: combustorimprovements to minimize slag buildup in the precombustor/combustor, addition of an acoustical silencer to the IDfan area, and insertion of a flow distribution device priorto the baghouse to minimize bag wear. In addition, sootblowers were added in July 1999 to reduce furnace slagbuildup around the combustor outlet. During a 90-daycapacity factor test that began on August 17, 1999, theplant achieved an average capacity factor of over 90%through September 30, 1999. The test requirement is acapacity factor of 85%. Capacity factor testing and sustained operations testing will continue into December 1999.Commercial ApplicationsThis technology is appropriate for any size utility or industrial boiler in new and retrofit uses. It can be used in coal-fired boilers as well as in oil- and gas-fired boilers because of its high ash-removal capability. However, cyclone boilers may be the most amenable type to retrofit with the slagging combustor because of the limited sup- ply of high-Btu, low-sulfur, low-ash-fusion-temperature coal that cyclone boilers require. The commercial avail- ability of cost-effective and reliable systems for SO2, NOx, and particulate control is important to potential users planning new capacity, repowering, or retrofits to existing capacity in order to comply with CAAA require- ments.

1993 1994 1995 1997 1998 1999 2000 2001 2002

Design and Construction

Operation

1/98

DOE cost-shared operationcompleted 12/99*

6/00

Operation initiated 1/98

Preoperational testsinitiated 8/97

pleted (EIS) 3/10/94

eted 10/93

Ground breaking/

construction

started 5/30/95 Environmental monitoring

plan completed 4/11/97

Constructioncompleted 11/97

Project completed/final reportissued 6/00*

**
Advanced Electric Power Generation

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, while future plant designs areexpected to reach 48% efficiency. This will result in a25% reduction in CO2 emissions compared to conventional coal-fired plants.

The LRCWF is prepared using an advanced coal

drying process that allows dried coal to be slurried inwater. In addition to the LRCWF being capable for use inthe coal-fueled diesel engine, the LRCWF is expected

to be an alternative to fuel oil in conventional oil-firedindustrial boilers.

eration

ngines

oject

—host and cofunder

undation—cofunder

ne technology vendor

ch Center, University

 preparation

er, designer,

pplier

ka facility)

000 100%

000 50

000 50

nd durability of the

urs of operation; verify

anced drying/slurrying

n coals; and test the

fitted oil-fired boiler.

SLURRY

PLANT

COAL

WATER

EXHAUST

GAS WASTE HEAT

BOILER

STEAM FOR

SPACE HEATING

FGD/

SCR

BAGHOUSE

STACK

GEN.

SHAFT

COAL-FUELED POWER

DIESEL ENGINE
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

tion Program Update 1999 5-129

1996 1997 

1995 1998 1999 2000 2001 2002 2003

agreement awarded 7/12/94

Design and Construction

ments

milestones. A 95%

 January 1999 at the

 (UAF). Representa

AF, DOE, and GHEMM

n attendance. The

d for a sorbent injection

ne was able to locate a

han 0.2% sulfur in the

tem originally proposed

 for use with bitumi

% sulfur levels. Coltec,

worked with EERC to

hire orifices sized for the

operate the engine at full

d on higher energy

ved in January 1999, but

d movement into the

f February 1999. The

erated on oil during

NEPA process completed (EA) 6/2/97

September 1999. Prior to the 18-cylinder engine testson coal slurry, Coltec will run their 2-cylinder test engine to optimize the operation settings, verify coal fuelperformance, and finalize hard coatings for criticalcomponents. Tests are scheduled for May–September2000.

Samples of the Usibelli coal were sent to CQ Inc.,

for washability tests; to ADL for wear tests; and to EERCfor preliminary hot water drying tests and bench weartests. Several plant design changes were made in order tokeep the project within budget. Notably, a small commercial oil-fired boiler will be converted for coal slurry testsinstead of an industrial-scale boiler, and several of theslurry holding tanks will be located closer to the dieselengine to reduce underground piping.

Final design of the LRCWF processing plant has

been completed. Construction of the LRCWF has beendelayed until May 2001 due to funding shortages. Arevised plan and schedule for the demonstration test ofthe 18-cylinder diesel on coal slurry is being developed.

Construction started 6/98

Environmental monitoring plan completed 2/99

Coal Diesel Operation initiated 6/02*

6/02 4/04

Project completed/final

report issued 4/04*

Operation

completed 1/04*

Operation

Project restructured 8/96

Design completed 1/99

Commercial ApplicationsThe U.S. diesel market is projected to exceed 60,000-MWe(over 7,000 engines) through 2020. The worldwidemarket is 70 times the U.S. market. The technology isparticularly applicable to distributed power generationin the 5- to 20-MWe range, using indigenous coal indeveloping countries.

The net effective heat rate for the mature diesel

system is expected to be 6,830 Btu/kWh (48%), whichmakes it very competitive with similarly sized coal- andfuel oil-fired installations. Environmental emissions fromcommercial diesel systems should be reduced to levelsbetween 50% and 70% below NSPS. The estimatedinstallation cost of a mature commercial unit is approximately $1,300/kW.

Coaltec 2-cylinderengine test on LRCWF

Program Update 1999 5-131

oal Processing for Clean Fuels
Coal Processing for Clean Fuels

ls

the Liquid

LPMEOHTM)

sion Company, L.P.

 Products and

r, and Eastman

—technology supplier

st, operator, synthesis

uel methanol tester and

—utility advisor

Eastman Chemical

cation Facility)

d phase methanol

ominal)

–5% sulfur

000 100%

370 43

630 57

catalyst but functions as an efficient means to remove theheat of reaction away from the catalyst surface. Thisfeature permits the direct use of synthesis gas streams asfeed to the reactor without the need for water-gasshift conversion.

Methanol fuel testing is being conducted in off-site

stationary and mobile applications, such as fuel cells,buses, and distributed electric power generation. Designverification testing for the production of DME as a mixedcoproduct with methanol for use as a storable fuel isplanned for fall 1999, and a decision on whether or not todemonstrate at Kingsport will be made. Eastern highsulfur bituminous coal (Mason seam) containing 3%sulfur (5% maximum) and 10% ash is being used.

Project ObjectiveTo 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 a

chemical 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 coproductwith methanol.Technology/Project DescriptionThis project is demonstrating, at commercial scale, theLPMEOHTM process to produce methanol from coalderived synthesis gas. The combined reactor and heatremoval system is different from other commercial metha

nd Chemicals, Inc. nol processes. The liquid phase not only suspends the
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

* Projected date

Program Update 1999 5-133

ments

anuary of 1997. Follow

wn activities, the first

 80,000 gal/day unit

first stable operation of

 nameplate capacity

ble test period at over

m limitations. The

njury or environmental

noxide (H2/CO) ratio in

d from 0.4 to 5.6 with no

rmance. Operation of

d the engineering meth

MEOHTM reactor, and

verall heat transfer coef

nger) were demonstrated

vels.

monstration unit contin

e startup in April 1997,

anol have been produced

and plant availability has exceeded 97%. Availability in1998 and 1999 was in excess of 99.7%.

During 1998, catalyst life significantly improved due

primarily to the elimination of trace iron contamination,which may have been caused by construction debris in thesystem, and to lower operating temperatures to meetproduction rates. Catalyst life has now met or exceededthe results obtained on poison-free synthesis gas inDOE’s LaPorte (Texas) Process Development Unit.

In March 1999, an inspection of all pressure vessels

revealed no problems with erosion or corrosion. To further mitigate the effects of arsenic (a catalyst poison),arsenic removal capacity was increased in guard bedslocated both upstream and within the LPMEOHTM process during June 1999. Analytical work performed immediately after the guard bed systems change confirmed thatthe levels of arsenic in the feed gas had been reduced tovery low levels. The effect of this change on catalystperformance and the level of all potential poisons willcontinue to be monitored during the ongoing plant operation.

Commercial ApplicationsThe LPMEOHTM process has been developed to enhanceIGCC power generation by producing a clean-burning,storable-liquid fuel (methanol) from clean coal-derivedgas. Methanol also has a broad range of commercialapplications; it can be substituted for conventional fuelsin stationary and mobile combustion applications and isan excellent fuel for utility peaking units. Methanolcontains no sulfur and has exceptionally low NOx characteristics when burned.

DME has several commercial uses. In a storable

blend with methanol, the mixture can be used as peakingfuel in IGCC electric power generating facilities. Blendsof methanol and DME also can be used as a chemicalfeedstock for the synthesis of chemicals or new oxygenatefuel additives. Pure DME is an environmentally friendlyaerosol for personal products.

Typical commercial-scale LPMEOHTM units are

expected to range in size from 50,000–300,000 gal/day ofmethanol produced when associated with commercialIGCC power generation trains of 200–500 MWe.

Design and Construction Operation

1995 1993 1994 1996 1997 1998 1999 2001 2002

ive agreement awarded 10/16/92

12/01

Project completed/final report issued 12/01*

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

Preoperational tests initiated 1/97Construction completed 1/97

Operation completed 3/01*

 3 4

Project transferred to Air Products

Liquid Phase Conversion

Company, L.P. 3/95

Project resited toKingsport, TN10/93
Coal Processing for Clean Fuels

Project FundingTotal project cost $87,386,102 100%DOE 37,994,437 43Participant 49,391,665 57Project ObjectiveTo demonstrate advanced coal-cleaning unit processes toproduce low-cost compliance coals that can meet therequirements for commercial-scale utility power plants tosatisfy provisions of the CAAA.Technology/Project DescriptionAn advanced coal-cleaning plant has been designed,blending existing and new processes, to produce twotypes of compliance coals—Carefree CoalTM and SelfScrubbing CoalTM—from various feedstocks.

Carefree CoalTM is produced by breaking and screening run-of-mine coal and by using innovative densemedium cyclones and finely sized magnetite to remove up

to 90% of the pyritic sulfur and most of the ash. CarefreeCoalTM is designed to be a competitively-priced, high-Btufuel that can be used without major plant modifications oradditional capital expenditures.

Self-Scrubbing CoalTM is produced by taking Carefree CoalTM, with its reduced pyritic sulfur and ash content, and adding to it sorbents, promoters, and catalysts.

Self-Scrubbing CoalTM is expected to achieve compliancewith virtually any U.S. coal feedstock through in-boilerabsorption of SO2 emissions. The reduced ash content of

the Self-Scrubbing CoalTM permits addition of relativelylarge amounts of sorbent without exceeding ash specifications of boilers or overloading electrostatic precipitators.

ls

alTM: An

ch to Clean

pany—host

 (advanced

hampton County, PA

nia Power & Light’s

Unit No. 2)

mbustion tests at

hitewater Valley

(combustion tests at

C)

als’ advanced physical

eparation technology

r Freeport (3.9% sul

sulfur)

trademarks of Custom Coals

SELF-SCRUBBING COAL

CAREFREE COAL

COMPLIANCE

COAL

?

RUN-OF-MINE COAL

ADVANCED

TECHNOLOGY

COAL CLEANING

PLANT

CLEANED COAL

CLEANED

COAL

ASH MAGNETITE

CYCLONE

ULTRAFINE

COAL

NO

YES

SORBENT

ADDITION

COAL

BREAKER

ASH & PYRITIC

SULFUR

TO

POWER STATION
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

Program Update 1999 5-135

Coals’ inability to find a buyer for the facility, the CustomCoals Laurel facility was sold at auction on December 16,1998, to C.J. Betters Enterprises of Monaca, Pennsylvania. C.J. Betters has met with DOE to discuss continuation of the project and was working to complete a continuation package. However, C.J. Betters was unable tolocate a suitable partner to assist with the completion ofthe project. The project’s performance period has expired. Prior to the publication of this report, the projecthas completed closeout procedures and is no longeractive.Commercial ApplicationsWhile many utilities can use Carefree CoalTM to complywith SO2 emissions limits, others cannot due to the highcontent of organic sulfur in their coal feedstocks. Whencompliance coal cannot be produced by reducing pyriticsulfur, Self-Scrubbing CoalTM can be produced to achievecompliance.

Commercialization of Self-Scrubbing CoalTM has the

potential of bringing into compliance about 164 million

ments

1995, and the first coal

 In May 1996, the facil

Equipment and circuit

diately thereafter and

 (cleaned Lower Kittan

wer Station was conducted

gh plant optimization was

ct made for the test was

y of the plant feed coal.

ty problems due to the

inal electrostatic

w coal created problems

liance quality clean coal.

t resulted in an excessive

refuse pond, and plant

uary 1997. Financial

orts to resolve the matter,

r 11. Due to Custom

1993 1994 1995 1996 1997 1998 1999 2000 2001

Construction started 12/93

ive agreement awarded 10/29/92

NEPA process completed (EA) 2/14/94

Design and Construction Operation

2/96

Design completed 12/94

Preoperational tests initiated 11/95Construction completed 11/95

Operation initiated 2/96

2/97

Project on hold

tons/yr of bituminous coal that cannot meet emissionslimits through conventional coal-cleaning. This represents more than 38% of the bituminous coal burned in50-MWe or larger U.S. generating stations.
Coal Processing for Clean Fuels

ls

onversion

ration

Rosebud SynCoal

na Power Company’s

jacent to Western

ine)

d Coal Conversion

bbituminous and lignite

s (Rosebud Mine),

r subbituminous coals

000 100%

000 41

000 59

LLC’s Advanced Coal

oduce SynCoal®, a

ure content as low as

 and heating value up

osebud SynCoal Partnership.

Technology/Project DescriptionThe process demonstrated is an advanced thermal coalconversion process coupled with physical cleaning techniques to upgrade high-moisture, low-rank coals to produce a high-quality, low-sulfur fuel. The raw coal isscreened and fed to a vibratory fluidized-bed reactorwhere surface moisture is removed by heating with hotcombustion gas. Coal exits this reactor at a temperatureslightly higher than that required to evaporate water andflows to a second vibratory reactor where the coal isheated to nearly 600 °F. This temperature is sufficient toremove chemically-bound water, carboxyl groups, andvolatile sulfur compounds. In addition, a small amount oftar is released, partially sealing the dried product. Particleshrinkage causes fracturing, destroys moisture reactionsites, and liberates the ash-forming mineral matter.

The coal is then cooled to less than 150 °F by contact

with an inert gas in a vibrating fluidized-bed cooler. Thecooled coal is sized and fed to deep bed stratifiers whereair pressure and vibration separate mineral matter, including much of the pyrite, from the coal, thereby reducingthe sulfur content of the product. The low specific gravity fractions are sent to a product conveyor while heavierfractions go to fluidized-bed separators for additional ashremoval.

The fines handling system consolidates the coal fines

that are produced throughout the ACCP facility. Thefines are gathered by screw conveyors and transported bydrag conveyors to a bulk cooling system. The cooledfines are blended with the coarse product, stored in a250-ton capacity bin until loaded into pneumatic trucksfor off-site sales, or returned to the mine pit.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

* Projected date

**Years omitted

Program Update 1999 5-137

ments

d to complete demonstra

but was granted a two

CP facility continues to

atic feed system to sup

’s 330-MWe Colstrip No.

The ACCP facility has

of raw coal to produce

®. The SynCoal® is used

 facilities (primarily

process 1,000 tons per

h the size of a commercial

s advantage of existing

year period, 321,528 tons

60-MWe J.E. Corette

testing involved both

f dust stabilization en

based suppressant)

blends. These blends

with raw coal. Overall,

the results indicate that a 50/50 blend of SynCoal®/raw

coal provides improved plant performance, includingreduced SO2 emissions. The use of SynCoal® permitteddeslagging the boiler at full load, thereby eliminatingcostly ash shedding operations. The result was reducedgas flow resistance in the boiler and convection passage,which reduced fan horsepower and improved heat transferin the boiler, leading to a 3-MWe net increase.

Three different feedstocks were tested at the ACCP

facility—North Dakota lignite, Knife River lignite, andAmax subbituminous coal. Approximately 190 tons ofthe SynCoal® product produced with the North Dakota

lignite was burned at the 250-MWe cyclone-fired MiltonR. Young Power Plant Unit No. 1. Testing showed dramatic improvement in cyclone combustion, improved slagtapping, and a 13% reduction in boiler air flow requirements. In addition, boiler efficiency increased from 82%to over 86% and the total gross heat rate improved by123 Btu/kWh.

Commercial ApplicationsWestern SynCoal LLC owns the ACCP technology and isresponsible for all activities related to commercialization.

ACCP has the potential to enhance the use of lowrank western subbituminous and lignite coals. The SynCoal® is a viable compliance option for meeting SO2

emission reduction requirements. SynCoal® is an ideal

supplemental fuel for plants seeking to burn western lowrank coals because the ACCP allows a wider range oflow-sulfur raw coals without derating the units. Theparticipant has six long-term agreements in place to provide SynCoal® to industrial and utility customers.

The ACCP has the potential to convert inexpensive,

low-sulfur low-rank coals into valuable carbon-basedreducing agents for many metallurgical applications.Furthermore, SynCoal® enhances cement and lime production and provides a value-added bentonite product.

Design and Construction Operation

1990 1991 1992 1993 1994 1999 2000 2001 2002

9/90 6/92

Design completed 8/91

agreement

d 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

6/01

**

Project completed/final report

issued 6/01*

Operation completed 1/01*
Coal Processing for Clean Fuels

ls

e Coal

c. and

ftware

—cofunder

—cofunder and

—field tester

y and Environmental

tester

 ND (bench tests)

nch- and pilot-scale

 (pilot-scale tests)

rtTM (CQETM) computer

utility sites ranging in

Project FundingTotal project cost $21,746,004 100%DOE 10,863,911 50Participants 10,882,093 50Project ObjectiveThe objective of the project was to provide the utilityindustry with a PC software program to confidently andinexpensively evaluate the potential for coal-cleaning,blending, and switching options to reduce emissionswhile producing the lowest cost electricity. Specificallythe project was to (1) enhance the existing Coal QualityInformation System (CQISTM) database and Coal QualityImpact Model (CQIMTM) to allow assessment of theeffects of coal-cleaning on specific boiler costs and performance, and (2) develop and validate CQETM, a model

that allows accurate and detailed prediction of coalquality impacts on total power plant operating cost andperformance.Technology/Project DescriptionThe CQETM is a software tool that brings a new level ofsophistication to fuel decisions by integrating the systemwide impact of fuel purchase decisions on coal-firedpower plant performance, emissions, and power generation costs. The impacts of coal quality; capital improvements; operational changes; and environmental compliance alternatives on power plant emissions, performance,and production costs can be evaluated using CQETM.CQETM can be used to systematically evaluate all suchimpacts, or it may be used in modules with some defaultdata to perform more strategic or comparative studies.

M are trademarks of the

osoft Corporation.

SELECTED

COALS

SUBBITUMINOUS BITUMINOUS

LIGNITE

BENCH-SCALE

TESTING

FULL-SCALE

BOILER

WASTE

COMPUTER EXPERT

MODEL

ANTHRACITE

CLEAN COAL

DATA EVALUATION

AND CORRELATION

PILOT-SCALE

BOILER
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

Program Update 1999 5-139

aluate emission and

d-alone computer or as a

es, coal producers, and

erform detailed coal

CQETM program:

d

te:

ons,

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

Cooperative agreement awarded 6/14/90

d

0

Environmental monitoringplan completed 7/31/90

Operation initiated 8/90

Development

6/90

Field testing completed 4/93

8/90

CQE Release 1.1 beta issued 6/96

CQE CD-ROM issued 12/95

Project completed/

final report issued 6/98

6/98

CQE Release 1.2

issued 12/97

– Performance issues, and– Alternative emissions control strategies.

• Operates on an OS/2 Warp® (Version 3 or later) operating system with preferred hardware requirements of a

Pentium® personal computer, 1 gigabyte hard disk

space, 32 megabytes RAM, 1024x768 SVGA, andCD-ROM.

Economic• CQETM includes economic models to determine production cost components for coal-cleaning processes,

power production equipment, and emissions controlsystems.
Coal Processing for Clean Fuels

TM, developed for EPRI

d in 1989. CQIMTM was

ities, including evaluat

tegies, evaluating bids

burn planning and

and economic analyses

ETM, which combines

are and databases,

el evaluation established

new flexibility and

odels and performance

terface and network

and full-scale testing

algorithms. Bench

B Combustion

r, Connecticut and the

rgy and Environmental

North Dakota. Pilot

B Combustion

r, Connecticut and

 sites were:

 No. 5 (880-MWe),

nit No. 4 (250-MWe),

 Point, Unit No. 2

5-MWe), Somerset,

Station (560-MWe),

lahoma’s Northeastern,

ah, Oklahoma.

The six large-scale field tests consisted of burning

a baseline coal and an alternate coal over a two monthperiod. The baseline coal was used to characterize theoperating performance of the boiler. The alternate coal, ablended or cleaned coal of improved quality, was burnedin the boiler for the remaining test period.

The baseline and alternate coals for each test site also

were burned in bench- and pilot-scale facilities 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.CQE

TM 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, andoperational and maintenance costs for coal-cleaningprocesses, power production equipment, and emissionscontrol 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 DescriptionCQETM includes more than 100 algorithms based on thedata generated in the six full-scale field test.

CQETM’s design philosophy underscores the importance of flexibility by modeling all important power plant

equipment and systems and their performance in realworld situations. This level of sophistication allows newapplications to be added by assembling a model of howobjects interact. Updated information records can bereadily shared among all affected users because CQETM isnetwork-aware, enabling users throughout an organizationto share data and results. The CQETM object-orienteddesign, coupled with an object database managementsystem, allows different views into the same data. As aresult, staff efficiency is enhanced when decisionsare made.

CQETM also can be expanded without major revisions to the system. Object-oriented programming allows

new objects to be added and old objects to be deleted orenhanced easily. For example, if modeling advancementsare made with respect to predicting boiler ash deposition(i.e., slagging and fouling), the internal calculations of theobject that provides these predictions can be replaced oraugmented. Other objects affected by ash deposition(e.g., ash collection and disposal systems, soot blowersystems) do not need to be altered; thus, the integrity ofthe underlying system is maintained.System RequirementsCQETM currently uses the OS/2® operating system, but the

developers are planning to migrate to a Windows®-based

platform. CQETM can operate in stand-alone mode on asingle computer or on a network. Technical support isavailable from Black & Veatch for licensed users.
Program Update 1999 5-141

e to all electric power

dustrial/institutional

l. Potential users in

ntal organizations,

titutions, and engineer

 for CQETM are being

lack & Veatch.

d distributes CQETM to

QETM is available to oth

icenses: user, consult

. and Black & Veatch

ion agreements, which

ve worldwide rights to

onsulting services that

re. Two U.S. utilities

 of CQETM’s stand-alone

. utilities and one U.K.

 EPRI membership.

panies are now using

with several non-EPRI

s to license their soft

me Page on the World

com:80/cqe/cqe.htm) and

omote CQETM, facilitate

TM developers and users,

pdates to be distributed

veloped to provide an on

he Home Page also helps

al utilities and consulting

he Secretary of Energy

6 as the best of nine

search and development

Electric Partnership”

ContactsClark D. Harrison, President, (724) 479-3503

CQ Inc.160 Quality Center Rd.Homer City, PA 15748

Douglas Archer, DOE/HQ, (301) 903-9443Joseph B. Renk, NETL, (412) 386-6406References• Final Report: Development of a Coal Quality Expert.

June 20, 1998.

• Harrison, Clark D., et al. “Recent Experience with the

CQETM.” Fifth Annual Clean Coal Technology Conference: Technical Papers. January 1997.

New England Power

Utilities acted as hosts for field tests of CQETM.

• CQETM Users Manual, CQETM Home Page at http://

www.fuels.bv.com:80/cqe/cqe.htm.

• Comprehensive Report to Congress on the Clean

Coal Technology Program: Development of theCoal Quality Expert. ABB Combustion Engineering, Inc., and CQ Inc. Report No. DOE/FE-0174P.U.S. Department of Energy. May 1990. (Availablefrom NTIS as DE90010381.)
Coal Processing for Clean Fuels

ls

al

ct

wned subsidiary of

ompany)

mpany (a wholly owned

nc.)—cofunder

veloper, owner,

wned subsidiary of

WY (Triton Coal

)

Coal (LFC®) process

PRB) subbituminous

oal feed

000 100%

000 50

000 50

ration of a number of

two higher-heating

ation of low-sulfur

red trademarks of SGI

ment Company.

subbituminous 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 stabilize the Process-Derived Fuel(PDF®) with respect to oxygen and water. In the VFB, the

partially-cooled, pyrolyzed solids contact a gas stream

containing a controlled amount of oxygen. Termed “oxidative deactivation,” a reaction occurs at active surfacesites in the particles, reducing the tendency forspontaneous ignition.

Following the VFB, the solids are cooled to near

atmospheric temperature in an indirect rotary coolerwhere water is added to rehydrate the PDF®. A patented

dust suppressant is added as the PDF® leaves the surge

bin. The hot gas produced in the pyrolyzer is sent througha cyclone for removal of the particulates, and then cooledin a quench column to stop any additional pyrolysis reactions and to condense the Coal-Derived Liquid (CDL®).

RAW COAL

CYCLONE

PRODUCT

GAS

DRYER

ELECTROSTATIC

PRECIPITATORS

LIQUIDS

PROCESS GAS

TO PDF STORAGE

COALDERIVED

LIQUID

RECOVERY

DRYER GAS

PROCESS HEAT

PYROLYZER

BLOWER STACK

DRYER

GAS

CYCLONE

COAL

SCREEN

FINES TO

PROCESS-DERIVED

FUEL STORAGE

DRYER

FINES TO COMBUSTOR

PROCESS-DERIVED

FUEL STORAGE

PYROLYZER

COMBUSTOR

BLOWER

TO TRUCK AND RAIL LOADOUT

COAL-DERIVED

LIQUID STORAGE

QUENCH

DEACTIVATION

AIRFINISHER

COOLER

FLUE GAS

DESULFURIZATION
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

Program Update 1999 5-143

Design and Construction Operation

1990 1991 1992 1993 1994 1995 1996 1997 1998

Cooperative agreement awarded 9/17/90

ted

ct

-III)

/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

9/90 7/92

eaward

Project completed/final

report issued 12/97

Operation completed 7/97

12/97

fur with a heat content of

.45% sulfur and 8,300

fur and 140,000 Btu/gal

 150,000 Btu/gal for No.

enabled reduction in SO2

missions (through flame

e of boiler rated capacity

oxins in concentrations

its.

ing 90% availability was

s for the entire plant

 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 a

blast furnace injectant in place of coke.

• Nearly 5 million gallons of CDL® were produced and

shipped to eight customers in seven states.

• CDL® demonstrated fuel properties similar to a lowsulfur No. 6 fuel oil but with the added benefit of

lower sulfur content. High aromatic hydrocarboncontent, however, may make CDL® more valuable as a

chemical feedstock.

Economic• A commercial plant designed to process 15,000 metric-ton/day would cost an estimated $475,000,000

(2001$) to construct, with annual operating and maintenance costs of $52,000,000 per year.
Coal Processing for Clean Fuels

Pre-VFB Post-VFB

1992 1993 1994 1995 1996 19971 Sum

Raw Coal Feed (tons) 5,200 12,400 67,500 65,800 68,000 39,340 258,300PDF® Produced (tons) 2,200 4,900 31,700 28,600 33,300 19,300 120,500

PDF® Sold (tons) 0 0 23,700 19,100 32,700 7,400 82,900

CDL® Produced (bbl) 2,600 6,600 28,000 31,700 32,500 20,300 121,700

Hours on Line 314 980 4,300 3,400 3,600 2,603 15,197Average Length ofRuns (Days) 2 8 26 38 44 75

1Through June 1997.

Exhibit 5-42

ENCOAL Production

re than 15,000 hours

ate operation was main

on with availabilities

length of operation and

oundness and durabil

COAL’s production

tration, over 83,500

unit trains and one

 in six states. Ship

lends from 14–94%

CDL® were produced

seven states.

t demonstrations, how

 many challenges. The

with stability of the

olved in order to

n trying to correct per

thin the bounds of the

ooler failed to provide

 spontaneous ignition

at a separate, sealed

ctivation. A search for

f a VFB. A 500-ton/

e quench table and

ond 500 ton/day VFB

ed.)

deactivation, the PDF

e stabilization. Exten

gen was needed for

n were pursued:

res to finish deactiva

 immediate PDF® ship

pment of an in-plant

product quality and

ng.

“Pile layering” was the primary external PDF® finishing measure adopted. However, PDF® quality becomes

somewhat impaired by impacting size, moisture andash content.

Pursuit of a finishing process step resulted in establishment of a stabilization task force composed of private

sector 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 useof heat tracing 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 within the design range. Watercontent was down to 1–2%, and solids content was 2–4%.Improvements resulted from more consistent operationand lower pyrolysis temperatures and higher pyrolysisflow rates enabled by a new pyrolyzer water seal.Environmental PerformancePDF® Product. PDF® offers the advantages of low-sulfur

Powder River Basin coal without a heating value penalty.In fact, the LFC® process removes organically-bound

sulfur, making the PDF® product lower in sulfur than the

parent coal on a Btu basis. Because the ROM coal is lowin ash, PDF® ash levels remain reasonable after processing, even though the ash level is essentially doubled (ash

from one ton of ROM coal goes into one-half ton ofPDF®).

Dust emissions were not a problem with PDF®. A

dust suppressant (MK) was sprayed on the PDF® to coat

the surface as it leaves the storage bin. Also, PDF® has a

narrower particle size distribution than ROM coal, havinga larger fines content but fewer particles in the fugitivedust range than ROM coal.
Program Update 1999 5-145

ents became international

velopment Company

s of PDF® in 1994. The

uels being considered for

n, found PDF® accept

oilers.

ed combustion testing

ntucky Electric Co

Station, Unit #3. Impor

ing:

g PDF® was possible with

 was not possible on the

DF® afforded time to

d calibration without

ncreasing capacity factor

ng operating and mainte

by 20% due to high

lmost immediate ignition

nozzle. Furthermore,

bustion (maintaining low

w excess oxygen, which

sions.

ed ash deposits in the

ter than those resulting

ing increased sootblow

d product is a low-sulfur,

drocarbon. CDL® fuel

w-sulfur No. 6 fuel oil,

ignificantly less.

aight industrial residual

The market for CDL® as a

® has limited application

al fuels due to incompat

h many straight-chain

ENCOAL determined that a centrifuge was needed

to reduce solids retention and improve marketability ofCDL® (tests validated a 90% removal capability); and an

optimum slate of upgraded products was identified. Theupgraded products were: (1) crude cresylic acid,(2) pitch, (3) refinery feedstock (low-oxygen middledistillate), and (4) oxygenated middle distillate (industrialfuel).EconomicThe “base case” for economics of a commercial plant isthe 15,000-metric-ton/day, three-unit North RochelleLFC® plant, the commercial-scale plant proposed by

ENCOAL, with an independent 80-MWe 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 anLFC® plant dependent on the cost of feed coal. In fact,

this is the largest single operating cost item. The totalestimated operating cost is $9.00/ton of feed coal including the cost of feed coal, chemical supplies, maintenance,and labor.Commercial ApplicationsIn a commercial application, CDL® would be upgraded to

cresylic acid, pitch, refinery feedstock, and oxygenatedmiddle distillate. Oxygenated middle distillate, the 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 or substitute for coke in the steelindustry. PDF® characteristics make it attractive to the

metallurgical market as a coke supplement in pulverizedcoal injection and granular coal injection methods, and asa reductant in direct reduced iron processes.

Partners in the ENCOAL® project completed five

detailed commercial feasibility studies over the course ofthe demonstration and shortly thereafter—two Indonesian, one Russian, and two U.S. projects. A U.S. projecthas received an Industrial Siting Permit and an Air Quality Construction Permit, but the project is on hold due tolack of funding.ContactsJames P. Frederick

SGI InternationalP.O. Box 3038Gillette, WY 82717(307) 686-2894 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Douglas M. Jewell, NETL, (304) 285-4720References• ENCOAL® Mild Gasification Plant Commercial Plant

Feasibility Study. U.S. Department of Energy. September 1997. Report No. DOE/MC/27339. (Availablefrom NTIS as DE98002005.)

• Final Design Modifications Report. U.S. Department

of Energy. September 1997. Report No. DOE/MC/27339-5797. (Available from NTIS as DE98002006.)

• ENCOAL® Mild Gasification Project: ENCOAL

Project Final Report. Report No. DOE/MC/27339-5798. U.S. Department of Energy. September 1997.(Available from NTIS as DE98002007.)

• Johnson, S.A., and Knottnerus, B.A. “Results of the

PDF® Test Burn at Clifty Creek Station.” U.S. Department of Energy Topical Report. October 1996.

• ENCOAL® Mild Coal Gasification Demonstration

Project Public Design and Construction Report. Report No. DOE/MC/27339-4065. ENCOAL Corporation. December 1994. (Available from NTIS asDE95009711.)
Coal Processing for Clean Fuels
Program Update 1999 5-147

Industrial Applications
Industrial Applications

taining high heat transfer efficiency in the post-combustion zone above the reaction zone, to reduce and smeltiron oxides. Tests have demonstrated 60% post-combustion levels (degree of post-combustion attained) with 90%heat transfer efficiency.

The HIsmelt® process uses a vertical smelt reduction

reactor, which is a closed molten bath vessel, into whichiron ore fines, coal, and fluxes are injected. The coal isinjected into the bath where carbon is dissolved rapidly.The carbon reacts with oxygen (from the iron ore) to formCO and metallic iron. Injection gases and evolved COentrain and propel droplets of slag and molten iron upward into the post-combustion zone.

The iron reduction reaction in the molten bath is

endothermic; therefore, additional heat is needed to sustain the process and maintain hot metal temperature. This

Integrated

n

y L.L.C. (a limited

bsidiaries of the Geneva

r, constructor, host, and

va Steel Co.’s mill)

ess

ion

000 100%

242 14

758 86

direct iron making with

ng various U.S. coals in

esponsible manner.

on

producing hot metal

on-coking coals. The

ufficient heat and main

lt Corporation Pty Limited.

Management Company, L.L.C.

heat is generated by post-combusting the CO and hydrogen from the bath with an O2-enriched hot air blast from

the central top lance. The heat is absorbed by the slagand molton iron droplets and returned to the bath bygravity. Droplets in contact with the gas in the postcombustion zone absorb heat, but are shrouded during thedescent by ascending reducing gases (CO), which, together with bath carbon, prevent unacceptable levels ofFeO in the slag.

The molten iron collects in the bottom of the bath

and is continuously tapped from the reactor through afore-hearth, which maintains a constant level of iron inthe reactor. Slag, which is periodically tapped through aconventional blast furnace-type tap hole, is used to coatand control the internal cooling system and reduce theheat loss.

FUEL GAS

COLD BLAST

OXYGEN

GAS CLEANING

COAL,

IRON ORE,

AND FLUXES COAL,

IRON ORE,

AND FLUXES

POST-COMBUSTION

ZONE

REACTOR

VESSEL HOT METAL

SLAG

HOT BLAST

STOVES
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

**Years omitted

 1 2

Program Update 1999 5-149

1997 2000 

1996 2001 2002 2003 2004 2005 2006

Cooperative agreement awarded 10/11/96

NEPA process completed 12/00*

Construction started 12/00*

Design and Construction

Operation initiated 5/03*Construction completed 5/03*

Operation

Project

completed/final

report issued 10/05*

Operation

completed 10/05*

O2, CO, H2, and H2O,

he reacted gases, the

 to produce 170 MWe of

so be used to pre-heat

g iron ore.

ments

awarded on October 11,

global assortment of new

o determine which tech

 to western U.S. coals

e COREX® process

va’s local raw materials;

data on 100% raw coals

n in this demonstration.

ine alternatives. The

SI direct ironmaking,

nic Smelter, and

 appears to offer good

ial, as well as the pros

CPICORTM has completed testing of two U.S. coals at the HIsmelt® pilot plant near Perth, Australia. On February 1, 1999, Geneva Steel Company (CPICORTM Management Company’s parent corporation) filed a voluntary petition for bankruptcy under Chapter 11 of the United States Bankruptcy Code in the U.S. Bank- ruptcy Court for the District of Utah. Geneva Steel in- tends to emerge from Chapter 11 with a restructured balance sheet that will enable full participation in this demonstration project. Other developments include the following: DOE is reviewing final drafts of license and marketing agreements between HIsmelt® and CPICORTM; DOE has established a NEPA Team to review the Envi- ronmental Information Volume and begin the NEPA scoping process; and baseline air monitoring is in progress. Commercial Applications The HIsmelt® technology is a direct replacement for exist- ing blast furnace and coke-making facilities with addi- tional potential to produce steam for power production. Of the existing 79 coke oven batteries, half are 30 years of age or older and are due for replacement or major rebuilds. There are about 60 U.S. blast furnaces, all of which have been operating for more than 10 years, with some originally installed up to 90 years ago. HIsmelt® represents a viable option as a substitute for conventional iron making technology. The HIsmelt® process is ready for demonstration. Two pilot plants have been built, one in Germany in 1984 and one in Kwinana, Western Australia in 1991. Through test work in Australia, the process has been proven— operational control parameters have been identified and complete computer models have been successfully devel- oped and proven. The goal is to have a fully operational commercial plant by early next decade.

**

Environmental monitoring

plan completed 9/02*

5/03

10/96 10/05
Industrial Applications

Design

onversion International,

y)

m Reforming using a

mbustor.

in) subbituminous

054 100%

027 50

027 50

mmercial viability of a

ombustor unit and

rived fuel gas generated

nt Unit (PDU).

on

m Reforming process

ocess for thermochemi

oduce hydrogen-rich,

s without the need for

nsfer is provided by

e pulse combustors in a

fluidized-bed steam gasification reactor. Pulse combustion increases the heat transfer rate by a factor of 3 to 5,thus greatly reducing the heat transfer area required in thegasifier.

The pulse combustor represents the core of the

PulsedEnhancedTM Steam Reforming process because itprovides 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 scale-up fromprevious tests. Testing will seek to verify scale-up criteriaand appropriateness of controls and instrumentation.Also, an existing PDU will be used to gasify coal feedstock to provide fuel gas data, including energy content,species concentration, and yield. Char from the PDU willbe evaluated as well.

The facility will also have a product gas cleanup

train that includes two stages of cyclones, a venturi scrubber with a scrubber tank, and a gas quench column. Anair-cooled heat exchanger will be used to reject heat fromthe condensation of excess steam (unreacted fluidizationsteam) quenched in the venturi scrubber and gas quenchcolumn. All project testing will be performed at theMTCI test facility in Baltimore, Maryland.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

Program Update 1999 5-151

1993 1994 1997 1998 1999 2000 2001

1995 1996

tive agreement

 10/27/92

Project relocationrequested 10/26/94

Design and Construction

*Projected Date

Revised Cooperative AgreementAwarded 9/29/98

Operation initiated 04/00*PDU Gasification data 4/00*

Operation complete 6/00*

4/00 7/00

ments

proved revision of Ther

reement for a scaled

ct, awarded in October

tration facility that would

ce-tube pulse combustor

st combustor unit, the

g. The revised project

onance-tube pulse com

e satisfied on November

lusion. The first major

design on February

tor unit is scheduled to

th operations beginning

sification data will be

 existing PDU.

Commercial ApplicationsPulsedEnhancedTM Steam Reforming has application inmany different processes. Coal, with the world productionon the 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 gasification only, the following coal-based applications are

envisioned:• Coal processing for combined-cycle power generation,• Coal processing for fuel cell power generation,• Coal pond waste and coal rejects processing to produce a hydrogen-rich gas from the steam reformer for

use in overfiring or reburning to reduce NOx emissions,

• Coal processing for production of gas or liquid fuel,

and char for the steel industry for use in direct reduction of iron ore,

Final report 7/00*

Design complete 2/15/99

Restructuring complete

3/21/98

• Coal processing for producing compliance fuels,• Mild gasification of coal,• Co-processing of coal and wastes, and• Coal drying.

In addition, the technology has application for black

liquor processing and chemical recovery and for hazardous, low-level radioactive, and low-level mixed wastevolume reduction and destruction.
Industrial Applications

nular-Coal

oject

 Services, Inc.

 Corporation)—

med Simon-Macawber,

engineer

ngineer (North

Bethlehem Steel’s

 Units C and D)

blast furnace granular

M)/day (each blast

fur

 sulfur

790 100%

118 16

672 84

Project ObjectiveTo demonstrate that existing iron making blast furnacescan be retrofitted with blast furnace granular-coal injection technology; to demonstrate sustained operation witha variety of coal types, particle sizes, and injection rates;and to assess the interactive nature of these parameters.Technology/Project DescriptionIn the BFGCI process, either granular or pulverized coalis injected into the blast furnace in place of natural gas oroil as a blast furnace fuel supplement. The coal, alongwith heated air, is blown into the barrel-shaped section inthe lower part of the blast furnace through passages calledtuyeres, which creates swept zones in the furnace calledraceways. The size of a raceway is important and is dependent upon many factors, including temperature. Lowering of a raceway temperature, which can occur withnatural gas injection, reduces blast furnace production

rates. Coal, with a lower hydrogen content than eithernatural gas or oil, does not cause as severe a reduction inraceway temperatures. In addition to displacing naturalgas, the coal injected through the tuyeres displaces coke,the primary blast furnace fuel and reductant (reducingagent), on approximately a pound-for-pound basis up to40% of total requirements. Emissions generated by theblast furnace itself remain virtually unchanged by theinjected coal; the gas exiting the blast furnace is cleanedand used in the mill. Sulfur from the coal is removed bythe limestone flux and bound up in the slag, which is asalable by-product. Two high-capacity blast furnaces,Units C and D at Bethlehem Steel’s Burns Harbor Plant,were retrofitted with BFGCI technology. Each unit has aproduction capacity of 7,200 NTHM/day. The two unitsuse about 2,800 tons/day of coal during full load operation.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

**Years omitted

 1 2

Program Update 1999 5-153

1991 1993 1994 1995 1996 1997 1998 1999 2000

rative agreement awarded 11/26/90

Design and Construction Operation

11/99

Final report issued 10/99*

Operation completed 11/98

**

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

• Granular coals are easier to handle in pneumatic conveying systems than pulverized coal because granular

coals are not as likely to stick to conveying pipes ifmoisture control is not adequately maintained.

• Any decrease in furnace permeability as a result of

coal injection can be minimized by increasing oxygenenrichment and raising moisture additions to the blastfurnace.

• Higher ash coal had no adverse effect on furnace

permeability.

• The productivity rate of the furnace was not affected

by the 2.4 percentage point increase in coal ash at aninjection rate of 260 lb/NTHM.

• There is a coke rate disadvantage of 3 lb/NTHM for

each 1 percentage point increase of ash in the coal atan injection rate of 260 lb/NTHM.

• Hot metal quality was not affected by the increased

ash content of the injection coal.

Economic• The capital cost for one complete injection system at

Burns Harbor was $15,073,106 (1990$) for the 7,200NTHM/day blast furnace.

• The total fixed costs (labor and repair costs) at Burns

Harbor were $6.25/ton of coal. The total variablecosts (water, electricity, natural gas, and nitrogen) were$3.56/ton of coal. Coal costs were $50-60/ton.

• At a total cost of $60/ton and a natural gas cost of

$2.85/106 Btu, the iron cost savings would be about

$6.50/ton of iron produced.

• Based on the Burns Harbor production of 5.2 million

tons of iron per year, the annual savings is about$34 million/yr.

he potential to reduce

ally by displacing coke,

ts in significant emis

gh-carbon coal provided a

enabled the operators to

rate of 661 lb/NTHM

40 lb/NTHM).

eability of the carbon

en column (a critical

cceptable operation

igh-carbon coal.

Project completed 11/99*
Industrial Applications

Units C and D at Beth

 were retrofitted with

 a production capacity

ts use about 2,800 tons/

This project represents

d to deliver granular

urnaces have been de

coal. The project also

from CPC-Macawber’s

ere the technology was

nology on large, high

em Steel conducted

oal to determine the

e. Tests included east

ontents of 0.8–2.8%

having 0.4–0.9% sulfur.

st program was to

and coal type on blast

nclude determining the

mistry on furnace perfor

ls have been reported—

volatile coal and a trial

e coal.

n, a chemically similar

m a different mine, were

e month of October

rnace operated without

ntas. This low-ash,

vided a high coke re

d test. The coal feed

M on a daily basis for

HM. The furnace coke

1 lb/NTHM. The

 was about 15% minus

The injected coal rate of 264 lb/NTHM is one of the

highest achieved since startup of the coal facility. Reliability of the coal system enabled the operators to reducefurnace coke to a low rate of 661 lb/NTHM. This lowcoke rate is not only economically beneficial, it is anindicator of the efficiency of furnace operation withregard to displacing coke with injected coal.

Hot metal chemistry, particularly silicon and sulfur

content, is an important iron making parameter. Specificsilicon and sulfur values with low variability are vital tomeeting steel-making specifications. The average valuesand standard deviations for silicon and sulfur can be seenin Exhibit 5-43. These values are compared totypical operation data on natural gas collected inJanuary 1995.

Exhibit 5-43 also shows the significant operating

changes that occur with the use of injected coal versusnatural gas. The wind volume on the furnace decreasedsignificantly with the use of coal. Oxygen enrichmentincreased from 24.4% to 27.3% with coal. The amountof moisture added to the furnace in the form of steamsignificantly increased from 3.7 grains/SCF to 19.8grains/SCF. All of these variables were increased byoperating personnel to maintain adequate burden materialmovement. These actions also increased the permeabilityof the furnace burden column, which is a function of theblast rate and the pressure drop through the furnace. Thelarger the permeability value, the better the furnace burden movement and the better the reducing gas flow ratethrough the furnace column. During the base period, thepermeability indicated overall acceptable operation usinglow-ash, low-volatile, high-carbon coal.

The next series of tests involved using a higher ash

coal. In order to ensure that other variables did not influence the test results, Buchanan coal was used, but the ashcontent was increased by eliminating one of the usualcoal cleaning steps. The ash content of the coal used forthe high-ash trial was 7.70% compared to 5.30% for thebase period trial and the 4.72% for the period immediately prior to the high-ash coal trial. As during the base trial period, the granular coal was about 15% minus 200 mesh. To ensure comparable results, Bethlehem Steel operators maintained consistent operation with the base period trials. A comparison of the high-ash trial to the base period is also contained in Exhibit 5-43. The amount of injected coal, general blast conditions, wind volume, blast pressure, top pressure, and moisture addi- tions were comparable during the two trials. The primary change in operation, as expected, was the increase in the blast furnace slag volume. With the higher ash coal, the 461 lb/NTHM slag volume was 8.7% higher than the baseline period of 424 lb/NTHM. The general conclusion is that higher ash content in the in- jected coal can be adjusted by the furnace operators and does not adversely affect overall furnace operations. However, the results lead to the conclusion that a 2.4 percentage point increase in injected coal ash results in a 8 lb/NTHM increase in the furnace coke rate after correct- ing for other variables. This is the amount of coke carbon needed to replace the lower carbon in the higher-ash coal without an additional process penalty. Environmental Summary The greatest environmental benefit to the BFGCI is dis- placement of coke in favor of coal. Coke is essentially replaced on a pound-for-pound basis with granulated coal, up to 40% of the total requirements. The BFGCI technology has the potential to reduce pollutant emissions because coke production results in significant emissions of air toxics. Economic Summary Capital cost for one complete injection system at Burners Harbor was approximately $15 million (1990$). This does not include infrastructure improvements, which cost $87 million at Burns Harbor. The fixed operating costs, which includes labor and repair costs, were $6.25/ton of coal. The variable operating costs, which include water, electricity, natural gas, and nitrogen, were $3.56/ton of
Program Update 1999 5-155

coal. Coal costs were $50–60/ton. This brought the totaloperating costs to $59.81–69.81/ton of coal. Using$60/ton of coal and a natural gas cost of $.88/106 Btu, thecost savings would be about $6.50/ton of iron produced.At Burns Harbor, which produces 5.2 million tons of ironper year, the savings would be about $34 million/yr. AtBurners Harbor, the payback period is 3.44 years using asimple rate of return calculation.Commercial ApplicationsBFGCI technology can be applied to essentially all U.S.blast furnaces. The technology should be applicable toany rank coal commercially available in the U.S. that hasa moisture content no higher than 10%. The environmental impacts of commercial application are primarily indirect and consist of a significant reduction of emissionsresulting from diminished coke-making requirements. TheBFGCI technology was developed jointly by British Steeland Simon-Macawber (now CPC-Macawber). BritishSteel has granted exclusive rights to market BFGCI technology worldwide to CPC-Macawber. CPC-Macawberalso has the right to sublicense BFGCI rights to otherorganizations throughout the world. CPC-Macawber hasalso recently installed a similar facility at United StatesSteel Corporation’s Fairfield blast furnace.ContactsRobert Bouman, (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) 386-5814ReferencesHill, D.G. et al. “Blast Furnace Granular-Coal Injection

System Demonstration Project.” Sixth Clean Coal Conference Proceedings: Volume II - Technical Papers. AprilMay, 1998.

Exhibit 5-43

BFGCI Test Results

Pre-Demonstration Base High Ash Test

January 1995 October 1996 May 28 

– June 23, 1997

ays 7,436 6,943 7,437

740 661 674141 0 5.0

0 264 262

881 925 940

167,381 137,005 135,370

38.9 38.8 38.3

1.57 1.19 1.23

24.4 27.3 28.6

2,067 2,067 2,012

3.7 19.8 20.7

4.8 5.0 5.0

0.44 (.091) 0.50 (.128) 0.49 (0.97)

0.043 (.012) 0.040 (.014) 0.035 (.012)

0.070 0.072 0.073

0.40 0.43 0.46

2,745 2,734 2,733

38.02 36.54 36.21

8.82 9.63 9.91

37.28 39.03 39.4012.02 11.62 11.32

0.45 0.46 0.45

0.85 1.39 1.40

1.05 1.10 1.10

1.30 1.39 1.40

394 424 461
Industrial Applications

high percentage of the ash and sorbent fed to the combustor as slag. For NOx control, the combustor is operated

fuel rich, with final combustion taking place in the boilerfurnace to which the combustor is attached. SO2 is captured by injection of limestone into the combustor. The

cyclonic action inside the combustor forces the coal ashand sorbent to the walls where it can be collected as liquidslag. Under optimum operating conditions, the slag contains a significant fraction of vitrified coal sulfur. Downstream sorbent injection into the boiler provides additional sulfur removal capacity.

In Coal Tech’s demonstration, an advanced, aircooled cyclone coal combustor was retrofitted to a

23 x 106 Btu/hr, oil-designed package boiler located at the

Tampella Power Corporation boiler factory inWilliamsport, Pennsylvania.

Technology/Project DescriptionCoal Tech’s horizontal cyclone combustor is internallylined with an air-cooled ceramic. Pulverized coal, air, andsorbent are injected tangentially toward the wall throughtubes in the annular region of the combustor to causecyclonic action. In this manner, coal-particle combustiontakes place in a swirling flame in a region favorable toparticle retention in the combustor. Secondary air is usedto adjust the overall combustor stoichiometry. Tertiary airis injected at the combustor/boiler interface. The ceramicliner is cooled by the secondary air and maintained at atemperature high enough to keep the slag in a liquid, freeflowing state. The secondary air is preheated by thecombustor walls to attain efficient combustion of the coalparticles in the fuel-rich combustor. Fine coal pulverization allows combustion of most of the coal particles nearthe cyclone wall. The combustor was designed to retain a

e Combustor

r, Nitrogen,

Energy Development

mpany—supplier of test

st

PA (Tampella Power

g plant)

slagging combustor

% sulfur

394 100%

149 50

245 50

yclone combustor can

r and that it can simul

e SO2 and 90–95% of

educe NO

x to 100 ppm.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

 1 2

Program Update 1999 5-157

1989 1990 

1988 1991 1992 1993 1994 1995 1996

Operation

Construction

7/24/86

eted 7/87

king/construction started 7/87

ent awarded 3/20/87

leted (MTF) 3/26/87

ental monitoring plan completed 9/22/87

uction completed 11/87

tion initiated 11/87

Operation

completed 5/90

ver 80% were achieved

urnace at various

ar ratios.

o 58% were achieved

ombustor at a Ca/S

he coal’s sulfur was

ed from the combustor

lfur was retained in the

bustor’s slag tap.

to 184 ppm by the com

0 ppm with the addition

ly inert.

• Ash/sorbent retention in the combustor as slag averaged 72% and ranged from 55–90%. Under more

fuel- lean conditions, retention averaged 80%.

• Meeting local particulate emissions standards required

the addition of a wet venturi scrubber.

Operational• Combustion efficiencies of over 99% were achieved.• A 3-to-1 combustor turndown capability was demonstrated. Protection of combustor refractory with slag

was shown to be possible.

• A computer-controlled system for automatic combustor operation was developed and demonstrated.

Economic• Because the technology failed to meet commercialization criteria, economics were not developed during the

demonstration. However, subsequent efforts indicatethat incremental capital costs for installing the coalcombustor in lieu of oil or gas systems are$100–200/kW.

9/91

Project completed/final report issued 9/91
Industrial Applications

The slagging combustor, associated piping, and control panel for

Coal Tech’s advanced ceramic-lined slagging combustor are shown.

patented

mbustor

nvironmen

waste emis

very com

trofitted to

ty boiler

ler’s water

NOx reduc

ustion, and

imestone

Critical to

val of ash

ode boiler

rtant in oil

g is tight

tent of oil

00 hours of operation,

h of four days, dura

esting was performed

on test. Test results

ombustor indicated that

ectives contained in the

ght different Pennsylva

ontents ranging from

ents ranging from

uction measured at the

sing sorbent injection in

ratios. A maximum

ed at the stack with

ustor at a Ca/S molar

rd of the coal’s sulfur

ed from the combustor

as 11% of the coal’s

cted through the slag

tap. Additional sulfur retention in the slag is possible byincreasing the slag flow rate and further improving fuelrich combustion and sorbent-gas mixing.

With fuel-rich operation of the combustor, a threefourths reduction in measured boiler outlet stack NOx was

obtained, corresponding to 184 ppm. An additional 5–10% reduction was obtained by the action of the wetparticulate scrubber, resulting in atmospheric NOx emissions as low as 160 ppm.

All the slag removed from the combustor produced

trace metal leachates well below EPA’s Drinking WaterStandard.

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%. In postCCT project, tests on flyash 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 PerformanceCombustion efficiencies exceeded 99% after proper operating procedures were achieved. Combustor turndown to6 x 106 Btu/hr from a peak of 19 x 106 Btu/hr (or a 3-to-1

turndown) was achieved. The maximum heat input during the tests was around 20 x 106 Btu/hr, even though the

combustor was designed for 30 x 106 Btu/hr and the

boiler was thermally rated at around 25 x 106 Btu/hr. This

situation resulted from facility limits on water availabilityfor the boiler. In fact, due to the lack of sufficient watercooling, even 20 x 106 Btu/hr was borderline, so that most

of the testing was conducted at lower rates.

Different sections of the combustor had different

materials requirements. Suitable materials for each section were identified. Also, the test effort showed thatoperational procedures were closely coupled with materials durability. As an example, by implementing certainprocedures, such as changing the combustor wall temperature, it was possible to replenish the combustor refractory wall thickness with slag produced during combustion rather than by adding ceramic to the combustor

walls.

The combustor’s total operating time during the life

of the CCT project was about 900 hours. This includedapproximately 100 hours of operation in two other flyashvitrification tests projects. Of the total time, about onethird was with coal; about 125 tons of coal wereconsumed.

Developing proper combustor operating procedures

was also a project objective. Not only were proceduresfor properly operating an air-cooled combustor developed, but the entire operating database was incorporatedinto a computer-controlled system for automatic combustor operation.Commercial ApplicationsIn conclusion, the goal of this project was to validate theperformance of the air-cooled combustor at a commercialscale. While the combustor was not yet fully ready for
Program Update 1999 5-159

Coal Tech’s slagging combustor demonstrated the capability to retain, as slag, a high

percentage of the non-fuel components injected into the combustor. The slag, shown on theconveyor, is essentially an inert, glassy by-product with value in the construction industry asan aggregate or in the manufacture of abrasives.

, it was believed to have

nt work was undertaken,

y close to commercial

67-0442

01) 903-9448

6-5991

lone Combustor Demon

essment. Report No.

partment of Energy. May

as DE93017043.)

anced Cyclone Coal

fur, Nitrogen, and Ash

f a 23-MMBtu/Hour Oil

al; Vol. 1: Final Techni

s I–V; Vol. 3: Appendix

August 1991. (Available

nd DE92002588.)

ngress on the Clean Coal

ced Cyclone Combustor

 and Ash Control. Coal

. DOE/FE-0077. U.S.

ary 1987. (Available
Industrial Applications

Gas

r

ect manager and host

 fabricator of tanks and

ragon Products

)

very ScrubberTM

0 scfm of kiln gas; and

% sulfur

000 100%

592 34

408 66

scale industrial scrubber

oal-burning wet process

e reagent to accomplish

-sulfur eastern coals;

roduct, potassium

Technology/Project DescriptionThe Passamaquoddy Technology Recovery ScrubberTMuses cement kiln dust (CKD), an alkaline-rich (potassium)waste, to react with the acidic flue gas. This CKD, representing about 10% of the cement feedstock otherwise lostas waste, is formed into a water-based slurry and mixedwith the flue gas as the slurry passes over a perforatedtray that enables the flue gas to percolate through theslurry. The SO2 in the flue gas reacts with the potassium

to form potassium sulfate, which stays in solution andremains in the liquid as the slurry undergoes separationinto liquid and solid fractions. The solid fraction, in thickened slurry form and freed of the potassium and otheralkali constituents, is returned to the kiln as feedstock (itis the alkali content that makes the CKD unusable asfeedstock). No dewatering is necessary for the wet process used at the Dragon Products Plant. The liquid frac- tion is passed to a crystallizer that uses waste heat in the flue gas to evaporate the water and recover dissolved alkali metal salts. A recuperator lowers the incoming flue gas temperature to prevent slurry evaporation, enables the use of low-cost fiberglass construction material, and provides much of the process water through condensation of exhaust gas moisture. The Passamaquoddy Technology Recovery Scrub- berTM was constructed at the Dragon Products Company’s cement plant in Thomaston, Maine, a plant that can pro- cess approximately 450,000 tons/yr of cement. The pro- cess was developed by the Passamaquoddy Indian Tribe while it was seeking ways to solve landfill problems, which resulted from the need to dispose of CKD from the 

ubber is a trademark of the cement-making process.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

 1 2

Program Update 1999 5-161

veraged 94.6% during

ration and 89.2% for the

veraged nearly 25%

 of operation and 18.8%

d.

waste produced by the

ed as feedstock, which

eedstock requirement by

ste disposal costs.

0.005–0.007 gr/scf, about

ment kilns, were achieved

mately 0.04 gr/scf.

. Environmental Protec

er Passamaquoddy Tech

wed 98% HCl removal.

• On three different runs, VOC (as represented by alphapinene) removal efficiencies of 72.3, 83.1, and 74.5%

were achieved.

• A reduction of approximately 2% in CO2 emissions

was realized through recycling of the CKD.

Operational• During the last operating interval, April to September

1993, recovery scrubber availability (discounting hostsite downtime) steadily increased from 65% in April1993 to 99.5% in July 1993.

1991 1992 

1990 1993 1994 1995 1996 1997 1998

esign and Construction

8/91

Operation

Design completed 4/90

Environmental monitoring plancompleted 3/26/90

Operation initiated 8/91

Construction completed 5/91Preoperational tests initiated 5/91

EPA process completed (EA) 2/16/90

erative agreement awarded 12/20/89

Economic• Capital costs are approximately $10,090,000 (1990$)

for a recovery scrubber to control emissions from a450,000-ton/yr wet process plant, with a simple payback estimated in 3.1 years.

• Operating 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.

2/94

Project completed/final report issued 2/94

arted 6/89

Operation

completed 9/93
Industrial Applications

Exhibit 5-44

Summary of Emissions and Removal Efficiencies

Operating Operating Inlet (lb/hr) Outlet (lb/hr) Removal Efficiency (%)Period Time (hr) SO2 NOx SO2 NOx SO2 NOx1 211 73 320 10 279 87.0 12.82 476 71 284 11 260 84.6 08.6

3 464 87 292 13 251 85.4 14.04 259 131 252 16 165 87.6 34.55 304 245 293 28 243 88.7 17.16 379 222 265 28 208 87.4 21.37 328 281 345 28 244 90.1 29.38 301 124 278 10 188 91.8 32.49 314 47 240 7 194 85.7 19.010 402 41 244 6 218 86.1 10.511 460 36 315 6 267 83.4 15.012 549 57 333 2 291 95.9 12.413 464 86 288 4 223 95.0 22.614 405 124 274 9 199 92.4 27.4Total operating time 5,316Weighted Average 109 289 12 234 89.2 18.8

Recovery ScrubberTM is

cient acid gas and

ve contact between flue

mposed of waste kiln

slurry as it moves over

n high SO2 and particu

and sufficient uptake of

tuent in cement) to

eedstock. Waste ce

uding waste heat), and

he process. Renovated

 fertilizer, scrubbed

e the only proven out

ver three basic operat

utdowns for mainte

te operating periods

ly determined by un

nd repairs and a de

eriod August 1991 to

hours was logged,

nterval, 1,300 hours in

rs in the third interval.

y over the operating

ock and operating

overed and corrected

s were experienced in

n.

he demonstration pe

or, which was installed

e flue gas, experienced

ore efficient water spray

acement with a chev

he third operating inter

te pelletization proved

to be a more difficult problem. The cause was eventuallyisolated and found to be excessive water entrainment dueto 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 PerformanceAn average 250 tons/day of CKD waste generated by theDragon Products plant was used as the sole reagent in therecovery scrubber to treat approximately 250,000 scfm offlue gas. All the CKD, or approximately 10 tons/hr, wererenovated and returned to the plant as feedstock andmixed with about 90 tons/hr of fresh feed to make up therequired 100 tons/hr. The alkali in the CKD was converted to potassium-based fertilizer, eliminating all solidwaste. Exhibit 5-44 lists the number of hours per operating period, SO2 and NOx inlet and outlet readings in

pounds per hour, and removal efficiency as a percentagefor each operating period.
Program Update 1999 5-163

s during the demonstra

and 18.8% for NOx emis

 for the NOx control

onclusion of the

riod emissions data, an

O2 load impact on removal

n the range of 100 lb/hr or

efficiency averaged

 range of 100–200 lb/hr,

94.1% and up to 98.5%

aine’s Department of

very scrubberwas sub

imately 0.04 gr/scf and

n rates of 0.005–0.007

urrent allowable limit.

Economic PerformanceThe estimated “as-built” capital cost to reconstruct theDragon Products prototype, absent the modifications, is$10,090,000 in 1990 dollars.

Annual operating and maintenance costs are estimated at $500,000. Long-term annual maintenance costs

are estimated at $150,000. Power costs, estimated at$350,000/yr, are the only significant operating costs.There are no costs for reagents or disposal, and no dedicated staffing or maintenance equipment are required.

Considering various revenues and avoided costs that

may be realized by installing a recovery scrubbersimilar

in size to the one used at Dragon Products, simple payback on the investment is projected in as little as3.1 years. 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 ApplicationsOf the approximately 2,000 Portland cement kilns in the

world, about 250 are in the United States and Canada.These 250 kilns emit an estimated 230,000 tons/yr of 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 tons/yr ofSO2 reduction could be achieved.

The scrubber became a permanent part of the cement

plant at the end of the demonstration. A feasibility studyhas been completed for a Taiwanese cement plant.

ContactsThomas N. Tureen, Project Manager, (207) 773-7166

Passamaquoddy Technology, L.P.1 Monument WayPortland, ME 04101(207) 773-7166(207) 773-8832 (fax)

William E. Fernald, DOE/HQ, (301) 903-9448John C. McDowell, NETL, (412) 386-6175References• Passamaquoddy Technology Recovery ScrubberTM:

Final Report. Volumes 1 and 2 (Appendices A–M.Passamaquoddy Tribe. February 1994. (Vol. 1 available from NTIS as DE94011175, Vol. 2 asDE94011176.)

• Passamaquoddy Technology Recovery ScrubberTM:

Public Design Report. Report No. DOE/PC/89657-T2. Passamaquoddy Tribe. October 1993. (Availablefrom NTIS as DE94008316.)

• Passamaquoddy Technology Recovery ScrubberTM:

Topical Report. Report No. DOE/PC/89657-T1. Passamaquoddy Tribe. March 1992. (Available fromNTIS as DE92019868.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Cement Kiln Flue Gas RecoveryScrubber. Passamaquoddy Tribe. Report No. DOE/FE-0152. U.S. Department of Energy. November1989. (Available from NTIS as DE90004462.)

logy Recovery ScrubberTM

Dragon Products

aston, Maine.
Industrial Applications
Program Update 1999 A-1

x A: Historical Perspective and

ve History

ctive

ey events that prompt

m and impacted its

e solicitations. The

be traced to the acid

, culminating in U.S.

ending a five year,

recursors to acid rain

s recommendation was

ntial initiative in

o the recommenda

Acid Rain in April

e Secretary of Energy

he President on innova

vities. This panel was

logy Advisory Panel.

es, the state and

e prepared a report,

rgy Concerning Com

addressed actions that

entives for demon

oal technologies. The

ration and deployment

th state and federal

In the same time frame, the Vice President’s

Task Force on Regulatory Relief (later referred to asthe Presidential Task Force on Regulatory Relief)was established. Among other things, the task forcewas asked to examine incentives and disincentives tothe commercial realization of new clean coal technologies. The task force also examined cost-effectiveemissions reduction measures that might be inhibitedby various federal, state, and local regulations. Thetask force recommended that preference be given toprojects located in states that offer certain regulatoryincentives to encourage such technologies. Thisrecommendation was accepted and became part ofthe project selection considerations beginning withCCT-II.

Initial CCT Program emphasis was on controlling SO2 and NOx emissions from existing coal-based

power generators. Approaches demonstrated throughthe program were coal processing to produce cleanfuels, 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-effective compliance options available today to address acid rainconcerns.

As the CCT Program evolved, work began on

drafting what was to become the Clean Air ActAmendments of 1990. Through a dialog with EPA

and Congress, the program was able to remainresponsive to shifts in environmental emphasis.Also, projects in place enabled CAAA architects tohave access to real-time data on emission controlcapabilities while structuring proposed acid rainregulations under Title IV of the CAAA. Aside fromacid rain, there was an emerging issue in the area ofhazardous air pollutants (HAPs), also referred to asair toxics. Title III of the CAAA listed 189 airbornecompounds subject to control, including trace elements and volatile and semi-volatile compounds. Toassess the impacts on coal-based power generation,CCT Program projects were leveraged to obtain datathrough an integrated effort among DOE, EPA,EPRI, and the Utility Air Regulatory Group.Through this effort, concerns about HAPs relative tocoal-based power generation have been significantlymitigated, enabling focus on but a few flue gasconstituents. Also, because NOx is a precursor to

ozone formation, the presence of NOx in ozone

nonattainment areas, even at low levels, became anissue. This precipitated action in the CCT Programto include technologies capable of deep NOx reduction in the portfolio of technologies sought.

In the course of the last two solicitations of the

CCT Program, a number of energy and environmental considerations combined to change the emphasistoward seeking high-efficiency, very-low-emissionpower generation technology. Energy demand
showed the need for

d power generation,

 into the 21st centu

d SO2 emissions at

nued to receive

zone nonattainment.

ns were coming

e of correlations with

for toxic compounds

Added to these

rn over global warm

O2 produced from

me a primary target

ydrogen ratio relative

what higher CO2

duced. However,

necessity) for many

ected growth in

greatest. The path

derations was to

on systems that could

efficiency and con

without introducing

s. (Increased effi

sumption per unit of

number of advanced

undertaken, repre

ed throughout the

the CCT Program is

nt Resolution Mak

or Fiscal Year 1985

and for Other Purposes. Title I set aside $750 million of the congressionally rescinded $5.375 billionof the Synthetic Fuels Corporation into a special U.S.Treasury account entitled the “Clean Coal Technology Reserve.” This account was dedicated to “conducting cost-shared clean coal technology projects forthe construction and operation of facilities to demonstrate the feasibility of future commercial applications of such technology.” Title III of this act directed the Secretary of Energy to solicit statements ofinterest in and proposals for clean coal projects. Inkeeping with this mandate, DOE issued a programannouncement, which resulted in the receipt of 176proposals representing both domestic and international projects with a total estimated cost in excess of$8 billion.

After this significant initial expression of interest in clean coal demonstration projects, Public Law

99-190, enacted December 1985, appropriated$400 million to conduct cost-shared demonstrationprojects. Of the total appropriated funds, approximately $387 million was made available for costshared projects to be selected through a competitivesolicitation, or Program Opportunity Notice (PON),referred to as CCT-I. (The remaining funds wererequired for program direction and the legislativelymandated Small Business Innovation ResearchProgram [SBIR] and Small Business TechnologyTransfer Program [STTR].)

In a manner similar to the initiation of CCT-I,

Congress again directed DOE to solicit informationfrom the private sector in the Department of theInterior and Related Agencies Appropriations Act forFY1987 (Public Law 99-591, enacted October 30,1986). The information received was to be used toestablish the level of potential industrial interest inanother solicitation, this time involving clean coal

technologies capable of retrofitting, repowering, ormodernizing existing facilities. Projects were to becost-shared, with industry sharing at least 50 percentof the cost. As a result of the solicitation, a total of39 expressions of interest were received by DOE inJanuary 1987.

On March 18, 1987, the President announced the

endorsement of the recommendations of the SpecialEnvoys on Acid Rain, including a $2.5 billion government share of funding for industry/governmentdemonstrations of innovative control technology overa five year period. The Secretary of Energy statedthat the department would ask Congress foran additional $350 million in FY1988 and an advanced appropriation of $500 million in FY1989.Additional appropriations of $500 million would berequested in fiscal years 1990, 1991, and 1992. Thisrequest was made by the President on April 4, 1987.

Public Law 100-202, enacted December 22,

1987, as amended by Public Law 100-446, appropriated a total of $575 million to conduct CCT-II.About $536 million was for projects, with the remainder for program direction and the SBIR andSTTR Programs.

The Department of the Interior and Related

Agencies Appropriations Act for FY1989 (PublicLaw 100-446, enacted September 27, 1988) provided$575 million for necessary expenses associated withclean coal technology demonstrations in the CCT-IIIsolicitation. Of the total funding, about $546 millionwas made available for cost-sharing projects, with theremainder for program direction and the SBIR andSTTR Programs. The act continued the requirementthat proposals must demonstrate technologies capableof retrofitting or repowering existing facilities. Thestatute also authorized the use of Tennessee ValleyAuthority power program funds as a source of non-
Program Update 1999 A-3

provided by annual

n, funds borrowed by

ration )now Rural

eratives from the

e eligible as cost

ion, except if provided

nterior and Related

f 1990 (Public Law

1989), Congress

CCT-IV solicitation.

“shall demonstrate

ng, retrofitting, or

nd shall be subject to

is head in Public Laws

as amended by this

 made available for

elected in CCT-IV,

m direction and the

acted October 23,

$600 million for the

ccording to the act,

s contained under this

00-202 and 100-446 as

ximately $568 million

cofunding of projects

n, with the remainder

d the SBIR and STTR

aws 101-164, 101-302,

ed the schedule for

 PONs and selecting

12, Congress directed

T-IV not later than

ns to be made within

8 months. In Public Law 102-154, Congress directedDOE to issue CCT-V PON not later than July 6,1992, with selections to be made within 10 months.This later act also directed that CCT-V proposalsshould advance significantly the efficiency andenvironmental performance of coal-using technologies and be applicable to either new or existingfacilities.

Public Laws 101-164, 101-302, 101-512, 103-

138, and 103-332 adjusted the rate at which fundswere to be made available to the program.

CCT Program funds have been further adjusted

through 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, asamended by Public Law 100-446.

• $2,028 was sequestered from the $575 million

appropriated by Public Law 100-446, asamended by Public Law 101-164.

• $455 was sequestered from the $1.2 billion

appropriated by Public Law 101-121, asamended 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

were deferred by Public Law 105-277. Funds will berestored over a three year period beginning October1, 1999. Again in 1999, Congress deferred programfunds. In Public Law 106-113, Congress deferred$156,000,000 until October 1, 2000.

Exhibit A-1 lists all the key legislation relating

to the CCT Program and provides a summary ofprovisions relating to program funding as well asprogram implementation. Following this exhibit arefunding provisions excerpted from appropriationsand other relevant funding-related acts.
Exhibit A-1

CCT Program Legislative History

T Round Program Funding Implementation Provisions

ation of CCT

ram; informational

itation

-I

nd informational

itation

-II

Title III required publication of a notice solicitingstatements of interest in and proposals for projectsemploying emerging CCTs. A report to Congress wasrequired no later than 4/15/85.Conference Report (H. Rep. 99-236) concurred withCCT project guidelines contained in Senate Report99-82, with certain modifications.Required a PON (CCT-I) to be issued and projects to beselected no later than 8/1/86. Project cost-sharingprovisions were detailed.Title II required publication of a notice solicitingstatements of interest in, and informational proposalsfor projects employing emerging CCTs capable ofretrofitting, repowering, or modernizing existingfacilities. A report to Congress was required no laterthan 3/6/87.Required a request for proposals (CCT-II) to be issuedno later than 60 days following enactment, for emerging CCTs capable of retrofitting or repowering existingfacilities. Extended project selection from 120 days to160 days after receipt of proposals. Provided for costsharing of pre-award costs for preparation and submission of environmental data upon signing of thecooperative agreement. Conference Report (H. Rep.100-498) provided that project cost-sharing funds bemade available to nonutility as well as utility applications. No funds were made available for new, standalone applications. H. Rep. Report 100-171 and SenateReport 100-165 outlined provisions for participant torepay government contributions.

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.
Program Update 1999 A-5

Exhibit A-1 (continued)

CCT Program Legislative History

CT Round Program Funding Implementation Provisions

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 expendedand $600 million on 10/1/91 until expended. Pub. L. 100-446 was amended by striking $575 million and inserting$450 million to be made available on 10/1/89 untilexpended and $125 million to be made available on10/1/90. Unobligated balances excess to the needs of theprocurement for which they originally were made availablemay be applied to other procurements for which requestsfor proposals had not yet been issued, except that nosupplemental, backup, or contingent selection of projectscould be made over and above the projects originallyselected.Appropriation for FY1990 was amended by striking$450 million and inserting $419 million and by striking$125 million and inserting $156 million.Obligation of funds previously appropriated for CCT-IVand CCT-V was deferred until 9/1/91.

T-IIIT-III

T-IV and CCT-V

T-IV and CCT-V

T-IV and CCT-V

Request for proposals (CCT-III) to be issued by 5/1/89for emerging CCTs capable of retrofitting or repoweringexisting facilities. Proposals were to be due 120 daysafter issuance of the PON; projects were to be selectedno later than 120 days after receipt of proposals.Funds borrowed by REA electric cooperatives from theFederal Financing Bank were made eligible as costsharing. Funds derived by the Tennessee ValleyAuthority from its power program were deemedallowable as cost-sharing except if provided by annualappropriations acts.Project selections for the third solicitation were to bemade not later than 1/1/90.Two solicitations (CCT-IV and CCT-V) to be issued,one for each appropriation, to demonstrate technologiescapable of replacing, retrofitting, or repowering existingfacilities, subject to all provisos contained in Pub. L.99-190, 100-202, and 100-446 as amended. The PON(CCT-IV) using funds becoming available on 10/1/90was to be issued by 6/1/90, with selections made by2/1/91. The PON (CCT-V) using funds becomingavailable on 10/1/91 was to be issued no later than9/1/91, with selections made by 5/1/92.Solicitations could not be conducted prior to ability toobligate funds. Repayment provisions for CCT-IV andCCT-V were to be the same as for CCT-III.
Exhibit A-1 (continued)

CCT Program Legislative History

T Round Program Funding Implementation Provisions

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.

-IV and CCT-V

-V

The CCT-IV solicitation was to be issued not later than2/1/91. The CCT-V PON was to be issued not laterthan 3/1/92. Project selections were to be made withineight months of PON’s issuance. Repayment provisionswere to be the same as for CCT-III. Provisions wereincluded to provide protections for trade secrets andproprietary information. Conference Report (H. Rep.101-971) recommends changes to program policyfactors.The CCT-V PON was delayed to not later than7/6/92, with selection to be made within 10 months(extended by two months). The PON was to be forprojects that advance significantly the efficiency andenvironmental performance of coal-using technologiesand be applicable to either new or existing facilities.Conference Report (H. Rep. 102-256) stated expectations that the CCT-V solicitation would be conductedunder the same general types of criteria as CCT-IV,principally modified only to (1) include the wider rangeof eligible technologies or applications; (2) adjusttechnical criteria to consider allowable developmentactivities, strengthen criteria for nonutility demonstrations, and adjust commercial performance criteria foradditional facilities and technologies with regard toaspects of general energy efficiency and environmentalperformance; and (3) clarify and strengthen cost andfinance criteria, particularly with regard to developmentactivities.Funding was allowed for project-specific developmentactivities for process performance definition, componentdesign verification, materials selection, and evaluationof alternative designs on a cost-shared basis up to alimit of 10 percent of the government share of projectcost.
Program Update 1999 A-7

Exhibit A-1 (continued)

CCT Program Legislative History

CT Round Program Funding Implementation Provisions

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.

Development activities eligible for cost-sharingincluded limited modifications to existing facilities forproject-related testing but not construction of newfacilities.Section 1301—Coal RD&D and Commercial Applications Programs (Title XIII; Subtitle A) authorized DOEto conduct programs for RD&D and commercialapplications of coal-based technologies. Secretary ofEnergy was directed to submit to Congress (1) a reportthat included, among other things, recommendationsregarding the manner in which the cost-sharingdemonstrations conducted pursuant to the Clean CoalProgram (Pub. L. 98-473) might be modified andextended in order to ensure the timely demonstration ofadvanced coal-based technologies and (2) periodicstatus reports on the development of advanced coalbased technologies and RD&D and commercialapplication attributes.An amount not to exceed $18 million available inFY1995 may be used for administrative oversight of theCCT Program.
Exhibit A-1 (continued)

CCT Program Legislative History

T Round Program Funding Implementation Provisions

Of funds available for obligation in FY1996, $50 millionwas rescinded. Of the funds to be made available forobligation in FY1997, $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 orpriors, $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. $38,000 was rescinded as a result ofthe general reduction.

Conference Report (H. Rep. 104-402 to accompanyH.R. 1977) allowed for the use of up to $18 million inCCT Program funds for program administration.House and Senate committees did not object to use ofup to $16 million in available funds for administrationof the CCT Program in FY1997 (H. Rep. 104-625 andSenate 104-319 to accompany H.R. 3662).Conference Report allowed $14.9 million in CCTProgram funds for program administration.Conference Report did not object to the use of up to$14.4 million in CCT Program funds for programadministration.

Pub. L. 104-134, replaced H.R. 1977.Pub. L. 104-208, replaced H.R. 3662.
Program Update 1999 A-9

0

 1251 (1985)

AN COAL TECHNOLOGY

enactment of this Act [Dec. 19, 1985] the Secretary

 Federal Nonnuclear Energy Research and Develop

01, et seq.), issue a general request for proposals for

for which the Secretary of Energy upon review may

wards. Proposals for clean coal technology projects

itted to the Department of Energy within 60 days after

or proposals. The Secretary of Energy shall make any

August 1, 1986: Provided, That the Secretary may vest

sts acquired under cost-shared clean coal technology

uding the United States: Provided further, That the

e than 50 per centum of the total costs of a project as

f the date of award of financial assistance: Provided

project sponsors is required in each of the design,

ases proposed to be included in a project: Provided

e for costs in excess of those estimated as of the date

 assistance may not be provided in excess of the

e Government in the original agreement and only up

financial assistance: Provided further, That revenues

eration of projects beyond the time considered in the

r proceeds from prospective sale of the assets of the

s from replication of technology in future projects or

he purposes of this appropriation: Provided further,

l funds are not cost-sharing for the purposes of this

, That existing facilities, equipment, and supplies, or

or development funds are not cost-sharing for the

 except as amortized, depreciated, or expensed in

Conference Report (H.R. Conf. Rep. No. 450, 99th Cong., 1st Sess.[1985])

CLEAN COAL TECHNOLOGY

The managers have agreed to a $400,000,000 Clean Coal Technology program

as described under the Department of the Treasury, Energy Security Reserve. Billlanguage is included which provides for the selection of projects no later than August1, 1986. Within that period, a general request for proposals must be issued within60 days and proposals must be submitted to the Department within 60 days afterissuance of the general request for proposals. Language is also included allowing theSecretary of Energy to vest title in interests acquired under agreements in any entity,including the United States, and delineating cost-sharing requirements. Funds forthese activities and projects are made available to the Clean Coal Technologyprogram in the Energy Security program.

It is the intent of the managers that contributions in the form of facilities and

equipment be considered only to the extent that they would be amortized, depreciatedor expensed in normal business practice. Normal business practice shall bedetermined by the Secretary and is not necessarily the practice of any single proposer.Property which has been fully depreciated would not receive nay cost-sharing valueexcept to the extent that it has been in continuous use by the proposer during thecalendar year immediately preceding the enactment of this Act. For this property,a fair use value for the life of the project may be assigned. Property offered as a costshare by the proposer that is currently being depreciated would be limited in its costshare value to the depreciation claimed during the life of the demonstration project.Furthermore, in determining normal business practice, the Secretary should notaccept valuation for property sold, transferred, exchanged, or otherwise manipulatedto acquire a new basis for depreciation purposes or to establish a rental value incircumstances which would amount to a transaction for the mere purpose ofparticipating in this program.

The managers agree that, with respect to cost-sharing, tax implications of

proposals and tax advantages available to individual proposers should not beconsidered in determining the percentage of Federal cost-sharing. This is consistentwith current and historical practices in Department of Energy procurements.
ers that there be full and open competition and that

markets utilizing the entire coal resource base.

mited to the use of United States mined coal as the

es should be located within the United States.

more than $1,500,000 shall be available in FY1986

fter for contracting, travel and ancillary costs of the

ts are to be funded under the fossil energy research

partment, after projects are selected, to provide a

ngress on proposals received.

he request for proposals to be or the full

only for the first $100,000,000 available in fiscal

2

t. 1329-1 (1987)

N COAL TECHNOLOGY

nd associated with, Clean Coal Technology demon

5901 et seq., $50,000,000 are appropriated for the

987, and shall remain available until expended, and

or the fiscal year beginning October 1, 1988, and

ended.

wing enactment of this Act, the Secretary of Energy

nnuclear Energy Research and Development Act of

ssue a general request for proposals for emerging

are capable of retrofitting or repowering existing

ry of Energy upon review may provide financial

der this section shall be submitted to the Department

ys after issuance of the general request for proposals

 of Energy shall make any project selections no later

 after receipt of proposal: Provided, That projects

selected are subject to all provisos contained under this head in Public Law 99-190:Provided further, That pre-award costs incurred by project sponsors after selectionand before signing an agreement are allowable to the extent that they are related to(1) the preparation of material requested by the Department of Energy and identifiedas required for 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 areto be reimbursed only upon signing of the project agreement and only in the sameratio as the cost-sharing for the total project: Provided further, That reports onprojects selected by the Secretary of Energy pursuant to authority granted under theheading “Clean coal technology” in the Department of the Interior and RelatedAgencies Appropriations Act, 1986, as contained in Public Law 99-190, which arereceived by the Speaker of the House of Representatives and the President of theSenate prior to the end of the first session of the 100th Congress shall be deemed tohave met the criteria in the third proviso of the fourth paragraph under the heading“Administrative provision, Department of Energy” in the Department of the Interiorand Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190,upon expiration of 30 calendar days from receipt of the report by the Speaker of theHouse of Representatives and the President of the Senate.

Conference Report (H.R. Conf. Rep. No. 498, 100th Cong., 1st Sess.[1987])

CLEAN COAL TECHNOLOGY

Appropriates $575,000,000 for clean coal technology instead of

$350,000,000 as proposed by the House and $850,000,000 as proposed by theSenate. The comparison by year is as follows:

House Senate Conference

Fiscal year:1988 $50,000,000 $350,000,000 $50,000,0001989 200,000,000 500,000,000 525,000,0001990 100,000,000Total 350,000,000 850,000,000 575,000,000
Program Update 1999 A-11

the House, which would have prohibited using grants

rs agree that project funding is expected to be based

 that grants might be applicable to support work also

eted Senate language providing personnel floors for

managers further agree that the budget estimates for

are to be followed. The agreement included 58 new

ment floors for the fossil energy organization and 30

t of clean coal technology funds, up to $3,980,000 is

elated costs and up to $16,520,000 is for all contract

ections and complete negotiations for both clean coal

necessary to monitor approved projects should be

 budget. Increases above to those amount are subject

No funds other than personnel related costs for the

ogram direction are to be provided from the fossil

ent account.

ction of projects by the Secretary of Energy has been

days based on experience from the original clean coal

ve been selected the Secretary should establish project

oject negotiations in order to expedite the negotiation

 the funds provided are available for non-utility

ty applications.

o funds are provided for the demonstration of clean

ended solely for new, stand alone, applications. The

% of the funds be available for this purpose.

uded which provides that reports on projects selected

procurements that are received before the end of the

ress will satisfy reporting requirements 30 calendar

This provision applies to a maximum of two project

Public Law 100-446Public Law 100-446, 102 Stat. 1774 (1988)

CLEAN COAL TECHNOLOGY

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 thisappropriation shall demonstrate technologies capable of retrofitting or repoweringexisting facilities and shall be subject to all provisions contained under this head inPublic Laws 99-190 and 100-202 as amended by this Act.

The first paragraph under this head in Public Law 100-202 is amended by

striking “and $525,000,000 are appropriated for the fiscal year beginning October 1,1988” and inserting “$190,000,000 are appropriated for the fiscal year beginningOctober 1, 1988, and shall remain available until expended, $135,000,000 areappropriated for the fiscal year beginning October 1, 1989, and shall remain availableuntil expended, and $200,000,000 are appropriated for the fiscal year beginningOctober 1, 1990”: Provided, That outlays in fiscal year 1989 resulting from the useof funds appropriated under this head in Public Law 100-202, as amended by this Act,may not exceed $15,500,000: Provided further, That these actions are taken

pursuant to section 202(b)(1) of Public law 100-119 (2 U.S.C. 909).

For the purposes of the sixth proviso under this head in Public Laws 99-190,

funds derived by the Tennessee Valley Authority from its power program arehereafter not to be precluded from qualifying as all or part of any cost-sharingrequirement, except to the extent that such funds are provided by annual appropriations Acts: Provided, That unexpended balances of funds made available in the“Energy Security Reserve” account in the Treasury for the Clean Coal TechnologyProgram by the Department of the Interior and Related Agencies AppropriationsActs, 1986, as contained in section 101(d) of Public Law 99-190, shall be merged withthis account: Provided further, That for the purposes of the sixth proviso in PublicLaw 99-190 under this heading, funds provided under section 306 of Public Law 93-32 shall be considered non-Federal: Provided further, That reports on projectsselected by the Secretary of Energy pursuant to authority granted under the heading
Department of the Interior and Related Agencies

tained in Public Law 99-190, which are received by

esentatives and the President of the Senate prior to

he 100th Congress shall be deemed to have met the

e fourth paragraph under the heading “Administra

rgy” in the Department of the Interior and Related

1986, as contained in Public Law 99-190, upon

om receipt of the report by the Speaker of the House

dent of the Senate.

nf. Rep. No. 862, 100th Cong., 2nd Sess.

N COAL TECHNOLOGY

orted in technical disagreement. The managers on

 motion to recede and concur in the amendment of

s follows:

ed by said amendment insert the following: For

iated with, Clean Coal Technology demonstrations

, $575,000,000 shall be made available on October

ble until expended: Provided, That projects selected

r proposals issued pursuant to this appropriation

 capable of retrofitting or repowering existing

 all provisos contained under this head in Public

mended by this Act.

 the Senate will move to concur in the amendment

 the Senate. The amendment provides $575,000,000

ean Coal Technology procurement as proposed by

the procurement is for retrofit and repowering

the cost-sharing provisions of the previous two

quest for proposals should be issued by May 1, 1989,

120 days after issuance of the request for proposals,

hould make project selections no later than 120 days

Amendment No. 132: Reported in technical disagreement. The managers

on the part of the House will offer a motion to recede and concur in the amendment of the Senate with an amendment as follows:

Restore the matter stricken by said amendment, amended to read as follows: The

first paragraph under this head in Public Law 100-202 is amended by striking “and$525,000,000 are appropriated for the fiscal year beginning October 1, 1988” andinserting “$190,000,000 are appropriated for the fiscal year beginning October 1,1988, and shall remain available until expended, $135,000,000 are appropriated forthe fiscal year beginning October 1, 1989, and shall remain available untilexpended, and $200,000,000 are appropriated for the fiscal year beginning October1, 1990”: Provided, That outlays in fiscal year 1989 resulting from the use of fundsappropriated under this head in Public Law 100-202, as amended by this Act, maynot exceed $15,500,000: Provided further, That these actions are taken pursuant tosection 202(b)(1) of Public Law 100-119 (2 U.S.C. 909).

The managers on the part of the Senate will move to concur in the amendment

of the House to the amendment of the Senate. The amendment changes theavailability of $525,000,000 originally made available for fiscal year 1989 in PublicLaw 100-202 by making $190,000,000 available in 1989, $135,000,000 available in1990, and $200,000,000 available in 1991 and also provides an outlay ceiling infiscal year 1989. The House had proposed $100,000,000 in fiscal year 1989,$225,000,000 in fiscal year 1990, and $200,000,000 in fiscal year 1989, $225,000,000in fiscal year 1990, and $200,000,000 in fiscal year 1991, and the Senate struck theHouse language.

Both of these changes are necessary because of budget allocation constraints, but

neither action has an effect on the execution of the Clean Coal program, or on theCongress’ overall support for the program, as is evidenced by additional appropriations provided for a third procurement of technologies.

The managers agree that administrative contract expenses may be incurred up

to the budget level of $9,820,000, but caution that close control of such expendituresis necessary to assure that the outlay ceiling provided will be sufficient to cover projectcosts.

Amendment No. 133: Modifies public law citation as proposed by the Senate.Amendment No. 134: Reported in technical disagreement. The managers on

the part of the House will offer a motion to recede and concur in the amendment ofthe Senate which clarifies that funds borrowed by REA Electric Cooperatives fromthe Federal Financing Bank are eligible as cost-sharing in the clean coal technologyprogram.
Program Update 1999 A-13

ported in technical disagreement. The managers

ffer a motion to recede and concur in the amend

fies clean coal projects may proceed 30 calendar

of required reports, provided the reports are re

00th Congress.

5

t. 97 (1989)

AN COAL TECHNOLOGY

r provision of law, funds originally appropriated

ment of the Interior and Related Agencies Appropri

able for a third solicitation of clean coal technolo

ch projects are to be selected by the Department

21

at. 701 (1989)

AN COAL TECHNOLOGY

of, and associated with, Clean Coal Technology

 U.S.C. 5901 et seq., $600,000,000 shall be made

, and shall remain available until expended, and

ailable on October 1, 1991, and shall remain available

at projects selected pursuant to a separate general

rsuant to each of these appropriations shall demon

eplacing, retrofitting or repowering existing facilities

os contained under this head in Public Laws 99-190,

100-202, and 100-446 as amended by this Act: Provided further, That the generalrequest for proposals using funds becoming available on October 1, 1990, under thisparagraph shall be issued no later than June 1, 1990, and projects resulting from sucha solicitation must be selected no later than February 1, 1991: Provided further, Thatthe general request for proposals using funds becoming available on October 1, 1991,under this paragraph shall be issued no later than September 1, 1991, and projectsresulting from such a solicitation must be selected no later than May 1, 1992.

The first paragraph under this head in Public Law 100-446 is amended by

striking “$575,000,000 shall be made available on October 1, 1989” and inserting“$450,000,000 shall be made available on October 1, 1989, and shall remainavailable until expended, and $125,000,000 shall be made available on October 1,1990”: Provided, That these actions are taken pursuant to section 202(b)(1) of PublicLaw 100-119 (2 U.S.C. 909).

With regard to funds made available under this head in this and previous

appropriations Acts, unobligated balances excess to the needs of the procurement forwhich they originally were made available may be applied to other procurements forwhich requests for proposals have not yet been issued: Provided, That for allprocurements for which project selections have not been made as of the date ofenactment of this Act no supplemental, backup, or contingent selection of projectsshall be made over and above projects originally selected for negotiation andutilization of available funds: Provided further, That reports on projects selected bythe Secretary of Energy pursuant to authority granted under this heading which arereceived by the Speaker of the House of Representatives and the President of theSenate less than 30 legislative days prior to the end of the first session of the 101stCongress shall be deemed to have met the criteria in the third proviso of the fourthparagraph under the heading “Administrative provisions, Department of Energy” inthe Department of the Interior and Related Agencies Appropriations Act, 1986, ascontained in Public Law 99-190, upon expiration of 30 calendar days from receiptof the report by the Speaker of the House of Representatives and the President of theSenate or at the end of the session, whichever occurs later.
nf. Rep. No. 264, 101st Cong., 1st Sess.

N COAL TECHNOLOGY

orted in technical disagreement. The managers on

 motion to recede and concur in the amendment of

eplacing” to the definition of clean coal technology.

clusion of “replacing” for clean coal IV and V is

placement of an existing facility if because of design

wering or retrofitting of the plant is not a desirable

opriates $450,000,000 for fiscal year 1990 for clean

00,000 as proposed by the House and $325,000,000

ppropriation along with $125,000,000 provided for

t 114 fully funds the third round of clean coal

gers agree that additional manpower is required,

 Energy Technology Centers, in order to manage

oad from the accumulation of active clean coal

clusion of additional procurements in this bill.

ot included, the managers agree that at least eighty

addition to the approximately thirty FTE’s now

arch and development appropriation. The managers

 fossil energy research and development appropri

e cost of more than the equivalent FTE’s paid under

orted in technical disagreement. The managers on

 motion to recede and concur in the amendment of

s follows:

 and inserted by said amendment, insert: and shall

, and $125,0000,000

 the Senate will move to concur in the amendment

 the Senate. The amendment provides $125,000,000

d clean coal technology procurement instead of

House and $100,000,000 as proposed by the Senate.

Amendment No 115: Deletes Senate proposed appropriation of $150,000,000

for fiscal year 1992 for clean coal technology. The House proposed no suchappropriation.

Amendment No. 116: Restores House language stricken by the Senate which

prohibits the use of supplemental, backup, or contingent project selections in cleancoal technology procurements.

Amendment No. 117: Restores the word “further” stricken by the Senate.

Public Law 101-164Public Law 101-164, 103 Stat. 1069 (1989)

CLEAN COAL TECHNOLOGY

The second paragraph under this head contained in the Act making appropriations for the Department of the Interior and Related Agencies for the fiscal year

ending September 30, 1990, is amended by striking “$450,000,000” and inserting“$419,000,000” and by striking “$125,000,000” and inserting “$156,000,000”.Conference Report (H.R. Conf. Rep. No. 315, 101st Cong., 1st Sess.[1989])

The managers have agreed to reduce the funds appropriated by the Energy and

Water Development Appropriations Act for Fiscal Year 1990 (Public Law 101-101)for the “Nuclear Waste Disposal Fund” by $46,000,000. This reduction will makefunds available for the drug prevention effort.

The managers have agreed to reductions to the Interior and Related Agencies

Appropriations Act for Fiscal Year 1990 (Public Law 101-121) in order to accommodate additional drug related appropriations.

The reductions are in three areas. The new budget authority for Clean Coal

Technology of $450,000,000 for fiscal year 1990 is reduced by $31,000,000 with thissame amount added to the advance appropriation for fiscal year 1991. With thischange the new amount for fiscal year 1990 is $419,000,000 while fiscal year 1991increases to $156,000,000. The second area of change is the imposition of an outlayceiling on Strategic Petroleum Reserve oil acquisition. Outlays will be reduced from
Program Update 1999 A-15

$147,125,000 and will decrease the fill rate from

er day to approximately 46,000 or 47,000 barrels per

s to the Pennsylvania Avenue Development Corpo

ty is reduced from $5,000,000 to $100,000.

 includes bill language reducing the amount of funds

the Health Care Financing Administration Program

000,000 from $1,917,172,000 to $18,851,712,000.

utlays reserved from the regular 1990 Labor, Health

ation appropriations bill, will be sufficient to support

he cost of anti-drug abuse funding. The conferees

ust fund transfers be associated with activities to

insurance, where funding needs may be diminished.

02

at. 213 (1990)

AN COAL TECHNOLOGY

ated under this head for clean coal technology

er than June 1, 1990, and no later than September

 be obligated until September 1, 1991: Provided,

tations shall not be conducted prior to the ability to

further, That pursuant to section 202(b) of the

cy Deficit Control Reaffirmation Act of 1987, this

ndary) result of a significant policy change: Provid

oal solicitations identified herein, provisions

government contributions to individual projects

ded in the Program Opportunity Notice (PON) for

CT-III) Demonstration Projects (solicitation num

sued by the Department of Energy on May 1,

Conference Report (H.R. Conf. Rep. No. 493, 101st Cong., 2nd Sess.[1990])

CLEAN COAL TECHNOLOGY

Amendment No. 89. Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of thesenate with an amendment as follows:

In lieu of the matter proposed by said amendment insert:

DEPARTMENT OF ENERGY

CLEAN COAL TECHNOLOGY

Funds previously appropriated under this head for clean coal technology

solicitations to be issued no later than June 1, 1990, and no later than September 1,1991, respectively, shall not be obligated until September 1, 1991: Provided, Thatthe aforementioned solicitations shall not be conducted prior to the ability toobligate these funds: Provided further, That pursuant to section 202 (b) of theBalanced Budget and Emergency Deficit Control reaffirmation /Act of 1987 thisaction is a necessary (but secondary) result of a significant policy change: Providedfurther, That for the clean coal solicitations identified herein, provisions includedfor the repayment of government contributions to individual projects shall beidentical to those included in the Program Opportunity Notice (PON) for Clean CoalTechnology III (CCT-III) Demonstration Projects (solicitation number DE-PS01-89FE 61825), issued by the Department of Energy on May 1, 1989.

The managers on the part of the Senate will move to concur in the amendment

of the House to the amendment of the Senate.

The amendment delays the fourth and fifth clean coal technology solicitations

as proposed by the Senate and specifies that, when issued, these solicitations must userepayment provisions used successfully in the third solicitation. This provision wasincluded in the House introduced bill (H.R. 4828) and modifies a Senate amendmentto 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 mustbe resolved before a reasonable solicitation can be issued. The proposed delay willallow such resolution.
anguage to ensure that provisions dealing with the

ed funds will remain the same as the third round of

 were developed over a four year period based on

ments and negotiations, and input from industrial

anagers of the program. They appear to be working

rience, and the clear fact that implementation of this

e even more important with passage of clean air

roposals put forth by the Department of Energy to

h proposals, while they might increase the recovery

ver periods of up to 20 years, might also act as a

on in the program, which is already over 50 percent

pose of the program is to accelerate the introduction

ficient manner in compliance with stringent new air

on of investment returns to the Government at the

2

t. 1915 (1990)

N COAL TECHNOLOGY

his head in Public Law 101-121 is amended by

made available on October 1, 1990, and shall remain

00,000,000 shall be made available on October 1,

until expended” and inserting “$600,000,000 shall

5,000,000 on September 1, 1991, $315,000,000 on

000 on October 1, 1992, all such sums to remain

in conjunction with a separate general request for

all be made available as follows: $150,000,000 on

on October 1, 1992, and $225,000,000 on October

available until expended for use in conjunction with

roposals”: Provided, That these actions are taken

pursuant to section 202(b)(1) of Public Law 100-119 (2 U.S.C. 909): Providedfurther, That a fourth general request for proposals shall be issued not later thanFebruary 1, 1991, and a fifth general request for proposals shall be issued not laterthan March 1, 1992: Provided further, That project proposals resulting from suchsolicitations shall be selected not later than eight months after the date of the generalrequest for proposals: Provided further, That for clean coal solicitations requiredherein, provisions included for the repayment of government contributions toindividual projects shall be identical to those included in the Program OpportunityNotice (PON) for Clean Coal Technology III (CCT-III) Demonstration Projects(solicitation number DE-PS01-89 FE 61825), issued by the Department of Energy onMay 1, 1989: Provided further, That funds provided under this head in this or anyother appropriations Act shall be expended only in accordance with the provisionsgoverning the use of such funds contained under this head in this or any otherappropriations Act.

With regard to funds made available under this head in this and previous

appropriations Acts, unobligated balances excess to the needs of the procurement forwhich they originally were made available may be applied to other procurements foruse on projects for which cooperative agreements are in place, within the limitationsand proportions of Government financing increases currently allowed by law:Provided, That the Department of Energy, for a period of up to five (5) years aftercompletion of the operations phase of a cooperative agreement may provide appropriate protections, including exemptions from subchapter II of chapter 5 of title 5,United States Code, against the dissemination of information that results fromdemonstration activities conducted under the Clean Coal Technology Program andthat would be a trade secret or commercial or financial information that is privilegedor confidential if the information had been obtained from and first produced by a nonFederal party participating in a Clean Coal Technology project: Provided further,That, in addition to the full-time permanent Federal employees specified in section303 of Public Law 97-257, as amended, no less than 90 full-time Federal employeesshall be assigned to the Assistant Secretary for Fossil Energy for carrying out theprograms under this head using funds available under this head in this and any otherappropriations Act and of which 35 shall be for PETC and 30 shall be for METC:Provided further, That reports on projects selected by the Secretary of Energypursuant to authority granted under this heading which are received by the Speakerof the House of Representatives and the President of the Senate less than 30 legislativedays prior to the end of the second session of the 101st Congress shall be deemed to
Program Update 1999 A-17

d proviso of the fourth paragraph under the heading

partment of Energy” in the Department of the Interior

ations Act, 1986, as contained in Public Law 99-190,

days from receipt of the report by the Speaker of the

he President of the Senate or at the end of the session,

Conf. Rep. No. 971, 101st Cong., 2nd Sess.

AN COAL TECHNOLOGY

rovides $35,000,000 for clean coal technology on

by the House instead of $100,000,000 as proposed by

and Amendment No. 143 shift the availability of

991 to fiscal year 1992.

ovides $315,000,000 for clean coal technology on

y the House instead of $250,000,000 as proposed by

and Amendment No. 142 shift the availability of

991 to fiscal year 1992.

rovides dates for two solicitations for clean coal

Senate. The date for CCT-IV is amended to February

The date for CCT-V is not changed from the Senate

 to a February 1, 1991 date for the next solicitation

ublish a draft solicitation for comment by interested

re will be changes to evaluation criteria and other

e that potential proposers have an opportunity to

 solicitation.

epartment to include potential benefits to remote,

ogram policy factor in evaluating proposals. The

er projects which can provide multiple fuel resource

more than seventy-five percent dependent on one fuel

ents.

uires selection of projects within eight months of the

 by Amendment No. 144 as proposed by the Senate.

on.

Amendment No. 146: Requires repayment of government contributions to projects

under conditions identical to the most recent clean coal solicitation as proposed by theSenate. The House had no such provision.

Amendment No. 147: Provides that funds for clean coal technology may be

expended only under conditions contained in appropriations Acts. The Senatelanguage had prohibited geographic restrictions on the expenditure of funds. TheHouse had no such provision. The managers direct that no preferential considerationbe given to any project referenced explicitly or implicitly in other legislation.

The managers agree to delete bill language dealing with geographic restrictions

based on such restrictions being deleted from clean air legislation.

Amendment No. 148: Earmarks employees to two fossil energy technology

centers as proposed by the Senate. The House had no such provision. The managersagree that the earmarks for PETC and METC are minimum levels and may beincreased as necessary.

The managers agree that no more than the current 30 full-time equivalent

positions from fossil energy research and development may be used in the clean coalprogram in fiscal year 1991.

Public Law 102-154Public Law 102-154, 105 Stat. 990 (1991)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-512 is amended by

striking the phrase “$150,000,000 on October 1, 1991, $225,000,000 on October 1,1992” and inserting “$100,000,000 on October 1, 1991, $275,000,000 on October1, 1992”.

 Notwithstanding the issuance date for the fifth general request for proposals

under this head in Public Law 101-512, such request for proposals shall be issued notlater than July 6, 1992, and notwithstanding the proviso under this head in PublicLaw 101-512 regarding the time interval for selection of proposals resulting fromsuch solicitation, project proposals resulting from the fifth general request forproposals shall be selected not later than ten months after the issuance date of the fifth
ovided, That hereafter the fifth general request for

l provisos contained under this head in previous

ded by this Act.

os under this head in previous appropriations Acts,

 fifth general request for proposals shall advance

nvironmental performance of coal-using technolo

new or existing facilities: Provided, That budget

esign, construction, and operating phases for cost

urther, That the Secretary shall not finance more

costs of any budget period: Provided further, That

ivities for process performance definition, compo

ls selection, and evaluation of alternative designs

ed basis up to a limit of 10 per centum of the

ost: Provided further, That development activities

lude limited modifications to existing facilities for

 include construction of new facilities.

e available under this head in this and previous

 balances excess to the needs of the procurement for

 available may be applied to other procurements for

ative agreements are in place, within the limitations

t financing increases currently allowed by law:

partment of Energy, for a period of up to five years

ns phase of a cooperative agreement may provide

g exemptions from subchapter II of chapter 5 of title

he dissemination of information that results from

ed under the Clean Coal Technology Program and

mmercial or financial information that is privileged

had been obtained from and first produced by a non

Clean Coal Technology project: Provided further,

full-time permanent Federal employees specified in

57, as amended, no less than 90 full-time Federal

e Assistant Secretary for Fossil Energy for carrying

d using funds available under this head in this and

 of which not less than 35 shall be for PETC and not

Provided further, That hereafter reports on projects

gy pursuant to authority granted under this heading

which are received by the Speaker of the House of Representatives and the Presidentof the Senate less than 30 legislative days prior to the end of each session of Congressshall be deemed to have met the criteria in the third proviso of the fourth paragraphunder the heading “Administrative provisions, Department of Energy” in theDepartment of the Interior and Related Agencies Appropriations Act, 1986, ascontained in Public Law 99-190, upon expiration of 30 calendar days from receiptof the report by the Speaker of the House of Representatives and the President of theSenate or at the end of the session, whichever occurs later.

Conference Report (H.R. Conf. Rep. No. 256, 102nd Cong., 1st Sess.[1991])

CLEAN COAL TECHNOLOGY

Amendment No. 165: Reported in technical disagreement. The managers on

the part of the House will offer a motion to recede and concur in the amendment ofthe Senate with an amendment as follows:

In lieu of the matter stricken and inserted by said amendment insert:Notwithstanding the issuance date for the fifth general request for proposals

under this head in Public Law 101-512, such request for proposals shall be issuednot later than July 6, 1992, and notwithstanding the proviso under this head in PublicLaw 101-512 regarding the time interval for selection of proposals resulting fromsuch solicitation, project proposals resulting from the fifth general request forproposals shall be selected not later than ten months after the issuance date of thefifth general request for proposals: Provided, That hereafter the fifth general requestfor proposals

The managers on the part of the Senate will move to concur in the amendment

of the House to the amendment of the Senate.

The amendment changes the issuance date for the fifth general request for

proposals to July 6, 1992 instead of March 1, 1992 as proposed by the House andAugust 10, 1992 as proposed by the Senate and the allowable length of time fromissuance of the request for proposals to selection of projects to ten months. Theamendment also deletes Senate proposed bill language pertaining to a sixth generalrequest for proposals as discussed below.

The managers agree that the additional two months in the procurement process

for the fifth round of proposals should include an additional month to allow for thepreparation of proposals by the private sector, and up to an additional month for
Program Update 1999 A-19

and evaluation of proposals when compared to the

d to delete bill language regarding a sixth round of

ding will be provided for a sixth round based on

ounts that may become available from the first five

ecretary on available funds, which was originally in

 requirement and such report should be submitted to

tees on Appropriations not later than May 1, 1994.

ng, dates and conditions for the sixth round will be

5 appropriation.

he fifth solicitation will be conducted under the same

 fourth solicitation principally modified only (1) to

ligible technologies or applications; (2) to adjust

owable development activities, to strengthen criteria

 and to adjust commercial performance criteria for

ologies with regard to aspects of general energy

erformance; and (3) to clarify and strengthen cost and

h regard to development activities.

stores House language deleted by the Senate which

or proposals. The Senate proposed language dealing

und.

ported in technical disagreement. The managers on

 a motion to recede and concur in the amendment of

retary of Energy to reobligate up to $44,000,000 from

 Technology proposals to a proposal ranked highest

ory by the Source Evaluation Board if other than the

ategory was selected originally by the Secretary, and

ated and are sufficient to fund such projects. This

h funds, if they become available, to a specific project

of Energy selection process for the fourth round of

chnical amendment which deletes House proposed

proposed by the Senate.

tes House proposed language which made unobligat

ments for which requests for proposals have not been

Amendment No. 170: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the Senatewhich adds “not less than” to employment floor language for PETC as proposed bythe Senate. The House had no such language.

Amendment No. 171: Reported in technical disagreement. The managers on

the part of the House will offer a motion to recede and concur in the amendment ofthe Senate which adds “not less than” to employment floor language for METC asproposed by the Senate. The House had no such language.

Public Law 102-381Public Law 102-381, 106 Stat. 1374 (1992)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-512, as amended, is

further amended by striking the phrase “and $250,000,000 on October 1, 1992” andinserting “$150,000,000 on October 1, 1993, and $100,000,000 on October 1, 1994”and by striking the phrase “$275,000,000 on October 1, 1992, and $225,000,000 onOctober 1, 1993” and inserting “$250,000,000 on October 1, 1993, and $250,000,000on October 1, 1994”.
8

tat. 1379 (1993)

N COAL TECHNOLOGY

s head in Public Law 101-512, as amended, is further

50,000,000 on October 1, 1993, and $100,000,000 on

$100,000,000 on October 1, 1993, $100,000,000 on

00 on October 1, 1995” and by striking the phrase

, and $250,000,000 on October 1, 1994” and inserting

$275,000,000 on October 1, 1994, and $100,000,000 on

2

tat. 2499 (1994)

N COAL TECHNOLOGY

is head in Public Law 101-512, as amended, is further

100,000,000 on October 1, 1994, and $50,000,000 on

,000,000 on October 1, 1994, $100,000,000 on October

er 1, 1996”; and by striking the phrase “$275,000,000

000 on October 1, 1995” and inserting “$19,121,000

 on October 1, 1995, and $255,879,000 on October 1,

d $18,000,000 available in fiscal year 1995 may be used

e Clean Coal Technology program.

Public Law 104-6Public Law 104-6, 109 Stat. 73 (1995)

CLEAN COAL TECHNOLOGY

(RESCISSION)

 Of the funds made available under this heading for obligation in fiscal year 1996,

$50,000,000 are rescinded and of the funds made available under this heading forobligation in fiscal year 1997, $150,000,000 are rescinded: Provided, That funds madeavailable in previous appropriations Acts shall be available for any ongoing projectregardless of the separate request for proposal under which the project was selected.Public Law 104-134Conference Report (H.R. Conf. Rep. No. 402, 104th Cong., 1st Sess.[1995])

The managers do not object to the use of up to $18,000,000 in clean coal

technology program funds for administration of the clean coal program.
Program Update 1999 A-21

8

Stat. 3009 (1999)

AN COAL TECHNOLOGY

(RESCISSION)

e under this heading for obligation in fiscal year 1997

e rescinded: Provided, That funds made available in

all be available for any ongoing project regardless of

al under which the project was selected.

onf. Rep. No. 863, 104th Cong., 2nd Sess.,

AN COAL TECHNOLOGY

(RESCISSION)

e under this heading for obligation in fiscal year 1997

e rescinded: Provided, That funds made available in

all be available for any ongoing project regardless of

al under which the project was selected.

319, 104th Cong., 2nd Sess. [1996])

ject to the use of up to $16,000,000 in available funds

coal program in fiscal year 1997.

o. 625, 104th Cong., 2nd Sess. [1996])

ject to the use of up to $16,000,000 in available funds

coal program in fiscal year 1997.

Public Law 105-18Public Law 105-18, 111 Stat. 158 (1997)

CLEAN COAL TECHNOLOGY

(RESCISSION)

Of the funds made available under this heading for obligation in fiscal year 1997

or prior years, $17,000,000 are rescinded: Provided, That funds made available in

previous appropriations Acts shall be available for any ongoing project regardless ofthe separate request for proposal under which the project was selected.

Public Law 105-83Public Law 105-83, 111 Stat. 37 (1997)

Of the funds made available under this heading for obligation in fiscal year 1997

or prior years, $101,000,000 are rescinded: Provided, That funds made available inprevious appropriations Acts shall be available for any ongoing project regardless ofthe separate request for proposal under which the project was selected.
7

tat. 2681 (1998)

N COAL TECHNOLOGY

(DEFERRAL)

ble under this heading for obligation in prior years,

ot be available until October 1, 1999; $15,000,000

er 1, 2000; and $15,000,000 shall not be available

That funds made available in previous appropria

any ongoing project regardless of the separate

h the project was selected.

onf. Rep. No. 825, 105th Cong. 2nd Sess.

N COAL TECHNOLOGY

provides for the deferral of $40,000,000 in previ

clean coal technology program as proposed by

ropose to defer funding. The Committees agree

or administration of the clean coal technology

Public Law 106-113Public Law 106-113, ___ Stat. ___ (1999)

CLEAN COAL TECHNOLOGY

(DEFERRAL)

Of the funds made available under this heading for obligation in prior years,

$156,000,000 shall not be available until October 1, 2000: Provided, That fundsmade available in previous appropriations Acts shall be available for any ongoingproject regardless of the separate request for proposal under which the project wasselected.Conference Report (H.R. Rep. No. 406, 106th Cong., 1st Sess. [1999])

CLEAN COAL TECHNOLOGY

(DEFERRAL)

The conference agreement provides for the deferral of $156,000,000 in previously appropriated funds for the clean coal technology program as proposed by the Senate

instead of a deferral of $256,000,000 as proposed by the House. The managers agreethat up to $14,400,00 may be used for program direction.
Program Update 1999 B-1

x B: Program History

ry

I solicitation, issued

 cost-shared projects to

lean coal technologies

The Program Opportu

proposals. Nine

rojects were placed on

nt negotiations on the

cessful; 8 alternate

ed as replacement

d from the list of

casions.

February 22, 1988,

e clean coal technolo

nologies that were

ed in the 1990s, more

nologies, and capable

ons in SO2 and/or NOx

urning facilities,

te to transboundary air

as the first solicitation

tions of the U.S. and

ort on acid rain. DOE

cted 16 as best further

the PON (no alternates

III PON, issued May 1,

d clean coal technology

tive, energy-efficient

technologies capable of being commercialized in the1990s. These technologies were to be capable of (1)achieving significant reductions in emissions of SO2and/or NO

x from existing facilities to minimize

environmental impacts, such as transboundary andinterstate air pollution; and/or (2) providing forfuture energy needs in an environmentally acceptablemanner. DOE received 48 proposals and selected 13projects as best furthering the goals and objectives ofthe PON.

The CCT-IV PON, issued January 17, 1991,

solicited proposals to conduct cost-shared clean coaltechnology projects to demonstrate innovative,energy-efficient, economically competitive technologies. These technologies were to be capable of (1)retrofitting, repowering, or replacing existing facilities while achieving significant reductions in theemissions of SO2, NOx, or both, and/or (2) providingfor future energy needs in an environmentally acceptable manner. A total of 33 proposals were submittedin response to the PON. Nine projects were selected.

The objective of the CCT-V PON, issued July 6,

1992, was to solicit proposals to conduct cost-shareddemonstration projects that significantly advance theefficiency and environmental performance of coalusing technologies and are applicable to either newor existing facilities. In response to the solicitation,DOE received proposals for 24 projects and selected5 projects.

Selection and NegotiationHistoryThe following is a history of the selection andnegotiations for the CCT Program Projects. Data areprovided through September 1999.July 1986Nine projects were selected under CCT-I (14 alternate projects selected to replace any selected projectsif negotiations were unsuccessful).March 1987DOE signed cooperative agreements with two CCT-Iparticipants, Coal Tech Corporation (AdvancedCyclone Combustor with Internal Sulfur, Nitrogen,and Ash Control) and The Ohio Power Company(Tidd PFBC Demonstration Project).June 1987DOE signed a cooperative agreement with CCT-Iparticipant, The Babcock & Wilcox Company (nowMcDermott Technology, Inc.) LIMB DemonstrationProject Extension and Coolside Demonstration.
ment with CCT-I

mental Research

of Coals by Gas

n).

rew its proposal

am Injection Gas

ith Hot Gas

rew its proposal,

lace Coke Oven/Blast

rther

elected: Colorado-Ute

CFB Demonstration

lagging Coal

n Project); Minnesota

 (COREX Ironmaking

er Wheeler Power

C Demonstration

ents with two more

 Clean Fuels, Inc.,

Coprocessing Project)

nderground Coal

ct).

January 1988DOE signed a cooperative agreement with The M.W.Kellogg Company and Bechtel Development Companyfor a CCT-I project, The Appalachian IGCC Demonstration Project.September 1988Sixteen projects were selected under CCT-II.November 1988DOE signed a cooperative agreement with CCT-Iparticipant, TRW, Inc. (Advanced Slagging CoalCombustor Utility Demonstration Project).December 1988Negotiations were terminated with 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 1989The City of Tallahassee CCT-I project, ACFB Repowering, was selected from the alternate list.The M.W. Kellogg Company and Bechtel Development Company withdrew their CCT-I project, CleanEnergy IGCC Demonstration Project.

September 1989United Coal Company withdrew its CCT-I project, CoalWaste Recovery Advanced TechnologyDemonstration.November 1989DOE signed a cooperative agreement with CCT-IIparticipant, Bethlehem Steel Corporation (InnovativeCoke Oven Gas Cleaning System for RetrofitApplications).Combustion Engineering, Inc., (CCT-II) withdrew itsPostcombustion Sorbent Injection DemonstrationProject.December 1989Thirteen projects were selected under CCT-III.DOE signed cooperative agreements with five CCTII participants: ABB Combustion Engineering, Inc.(SNOXTM Flue Gas Cleaning Demonstration Project);The Babcock & Wilcox Company (SOx-NOx-Rox BoxTM

Flue Gas Cleanup Demonstration Project); Passamaquoddy Tribe (Cement Kiln Flue Gas RecoveryScrubber); Pure Air on the Lake, L.P. (Advanced FlueGas Desulfurization Demonstration Project); andSouthern Company Services, Inc. (Demonstration ofAdvanced Combustion Techniques for a Wall-FiredBoiler).Energy International, Inc., withdrew its CCT-I project,Underground Coal Gasification Demonstration Project.
Program Update 1999 B-3

 Inc., withdrew its

GCC Demonstration

ments with three CCT

n Power Company

roject); The Babcock &

on of Coal Reburning

); and Southern

nstration of Innovative

 the CT-121 FGD

ments with the co

ct, ABB Combustion

Development of the

ith two CCT-II

y Services, Inc.

talytic Reduction

NOx Emissions from

) and TransAlta

ion (LNS Burner for

tration Project).

ments with one CCT-I

mpany (formerly

now Western SynCoal

on Process Demon

t, Southern Company

onstration of Advanced

 Techniques for the

m Coal-Fired Boilers);

and one CCT-III participant, ENCOAL Corporation(ENCOAL® Mild Coal Gasification Project).

Negotiations were terminated with CCT-II participant,Southwestern Public Service Company (Nichols CFBRepowering Project).October 1990DOE signed cooperative agreements with four CCTIII participants: AirPol, Inc. (10-MWe Demonstrationof Gas Suspension Absorption); The Babcock &Wilcox Company (Full-Scale Demonstration of LowNOx Cell Burner Retrofit); Bechtel Corporation(Confined Zone Dispersion Flue Gas DesulfurizationDemonstration); and Energy and EnvironmentalResearch Corporation (Evaluation of Gas Reburningand Low-NOx Burners on a Wall-Fired Boiler).November 1990DOE 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 SteelCorporation (Blast Furnace Granular-Coal InjectionSystem Demonstration Project) and LIFAC–NorthAmerica (LIFAC Sorbent Injection DesulfurizationDemonstration Project).December 1990Negotiations terminated with CCT-II participant,Otisca Industries, Ltd. (Otisca Fuel DemonstrationProject) and CPICOR.

March 1991DOE signed cooperative agreements with three CCTIII participants: MK-Ferguson Company (now NOXSOCorporation (Commercial Demonstration of theNOXSO SO2/NOx Removal Flue Gas Cleanup System);

Public Service Company of Colorado (Integrated DryNOx/SO2 Emissions Control System); and Tampa

Electric 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 1991DOE signed a cooperative agreement with CCT-IIIparticipant, Alaska Industrial Development and ExportAuthority (Healy Clean Coal Project).June 1991DOE withdrew its sponsorship of the Ohio OntarioClean Fuels, Inc., CCT-I project, Prototype CommercialCoal/Oil Coprocessing Plant.August 1991DOE signed a cooperative agreement with CCT-IIIparticipant, DMEC-1 Limited Partnership (formerlyDairyland Power Cooperative; PCFB DemonstrationProject).TransAlta Resources Investment Corporationwithdrew its CCT-II project, LNS Burner for CycloneFired Boilers Demonstration Project.
r CCT-IV.

project, Advanced

 Sulfur, Nitrogen, and

 and project com

ission Association,

lectric Association,

emonstration Project,

ompleted.

CCT-I) was restruc

unty Energy Partners,

rs Cogeneration

ents with two CCT

y Authority (now

orporation; Micron

tion for NOx Control

 and the Wabash

ring Project Joint

ification Repowering

ment with CCT-IV

Company (Piñon Pine

Cordero Mining Company withdrew from negotiationsfor its CCT-IV project, Cordero Coal-UpgradingDemonstration Project.At the participant’s request, Union Carbide Chemicalsand Plastics Company Inc. (CCT-IV) was granted anextension of one year to the DOE deadline for completing negotiations of its Demonstration of the UnionCarbide CANSOLVT System at the Alcoa GeneratingCorporation Warrick Power Plant.October 1992DOE signed cooperative agreements with one CCTIII participant, 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 1992The Babcock & Wilcox Company’s (now McDermottTechnology, Inc.) CCT-I project, LIMB DemonstrationProject Extension and Coolside Demonstration, finalreports issued and project completed.

May 1993Five projects were selected under CCT-V: Four RiversEnergy Partners, L.P. (Four Rivers Energy Modernization Project (formerly Calvert City Advanced EnergyProject, now McIntosh Unit 4B Topped PCFBDemonstration Project); Duke Energy Corporation(Camden Clean Energy Demonstration Project);Centerior Energy Corporation, on behalf of CPICORTMManagement Company L.L.C. (Clean Power fromIntegrated Coal/Ore Reduction [CPICORTM]); ArthurD. Little, Inc. (Clean Coal Combined-Cycle Project;formerly Demonstration of Coal Diesel Technology atEaston Utilities; now Clean Coal Diesel DemonstrationProject); and Pennsylvania Electric Company (WarrenStation Externally Fired Combined-Cycle Demonstration Project).July 1993Union Carbide Chemicals and Plastics Company, Inc.,withdrew its CCT-IV proposal, Demonstration of theUnion Carbide CANSOLVT System at the AlcoaGenerating Corporation Warrick Power Plant.February 1994The Passamaquoddy Tribe’s CCT-III project, CementKiln Flue Gas Recovery Scrubber, final reports issuedand project completed.March 1994The Babcock & Wilcox Company’s CCT-II project,Demonstration of Coal Reburning for Cyclone BoilerNOx Control, final reports issued and project completed.
Program Update 1999 B-5

ment with CCT-V

 (Coal Diesel Com

CT-III project, 180-

ced Tangentially

for the Reduction of

d Boilers, final reports

project, Confined Zone

ation Demonstration,

completed.

ments with two CCT

rgy Partners, L.P. (Four

roject); and Pennsylva

tation Externally-Fired

n Project).

al Demonstration of the

e Gas Cleanup System,

 NOXSO Corporation.

s CCT-III project,

on of the Liquid Phase

s, was transferred to

version Company, L.P.

December 1994DOE signed a cooperative agreement with CCT-Vparticipant, Clean Energy Partners Limited Partnership(formerly Duke Energy Corporation; Clean EnergyDemonstration Project; now Kentucky Pioneer IGCCDemonstration Project).March 1995TAMCO Power Partner’s CCT-IV project, Toms CreekIGCC Demonstration Project, was not granted a furtherextension and the project was concluded.April 1995Bethlehem Steel Corporation’s CCT-II project,Innovative Coke Oven Gas Cleaning System forRetrofit Applications, was terminated by mutualagreement with DOE because coke production wassuspended at the demonstration facility.June 1995AirPol, Inc.’s CCT-II project, 10-MWe Demonstrationof Gas Suspension Absorption, final reports issuedand project completed.September 1995The Babcock & Wilcox Company’s CCT-II project, SOxNO

x-Rox BoxTM Flue Gas Cleanup Demonstration

Project, final reports issued and project completed.

December 1995The Tennessee Valley Authority and New York StateElectric & Gas Corporation finalized an agreement toallow the project, Micronized Coal Reburning Demonstration for NO

x Control, to be conducted at both

Milliken Station in Lansing, NY and Eastman KodakCompany in Rochester, NY.The Babcock & Wilcox Company’s CCT-II project,Full-Scale Demonstration of Low-NO

x

 Cell Burner

Retrofit, final reports issued and project completed.The Ohio Power Company’s CCT-I project, Tidd PFBCDemonstration Project, final reports issued and projectcompleted.

May 1996The ABB Combustion Engineering, Inc. CCT-IIproject, Combustion Engineering IGCC RepoweringProject, was concluded.June 1996Pure Air on the Lake’s CCT-II project, Advanced FlueGas Desulfurization Project, final reports issued andproject completed.August 1996The Arthur D. Little, Inc., CCT-V project was restructured and retitled as the Clean Coal Diesel Demonstration Project.September 1996The Appalachia Power Company CCT-II project, PFBCUtility Demonstration Project, was concluded.
ment with CCT-V

ent Company L.L.C.

al/Ore Reduction

T-II project, Demon

duction Technology

from High-Sulfur,

ssued and project

T-II project, SNOXTM

n Project, final reports

any CCT-V project,

 Demonstration

reement for JEA’s

uthority) CCT-I

mbustion Project

e project, then the

ject).

project, ENCOAL®

final reports issued

DOE signed a new cooperative agreement for therestructured City of Lakeland’s CCT-III project,McIntosh Unit 4A PCFB Demonstration Project(formerly the DMEC-1 Limited Partnership project).January 1998DOE signed a new cooperative agreement for therestructured City of Lakeland’s CCT-III project,McIntosh Unit 4B Topped PCFB DemonstrationProject (formerly the Four Rivers Energy Partners, L.P.project).April 1998LIFAC–North America’s CCT-III project, LIFACSorbent Injection Desulfurization DemonstrationProject, final reports issued and project completed.June 1998Southern Company Services’ CCT-II project, Demonstration of Innovative Applications of Technology forthe CT-121 FGD Process, final reports issued andproject completed.The ABB Combustion Engineering, Inc. and CQ Inc.’sCCT-I project, Development of the Coal QualityExpertTM, final reports issued and project completed.September 1998Energy and Environmental Research Corporation’sCCT-I project, Enhancing the Use of Coals by GasReburning and Sorbent Injection, final reports issuedand project completed.

DOE signed a revised cooperative agreement for therestructured ThermoChem Inc.’s CCT IV project, PulseCombustor Design Qualification test.

October 1998Energy and Environmental Research Corporation’sCCT III project, Evaluation of Gas Reburning andLow-NO

x Burners on a Wall-Fired Boiler, final

reports issued and project completed.

September 1999Energy and Environmental Research Corp.’s CCT-Iproject, Enhancing the Use of Coals by Gas Reburningand Sorbent Injection, final report issued and projectcompleted.New York State Electric and Gas Corp.’s CCT-IVproject, Milliken Station Clean Coal TechnologyProject, final report issued and project completed.New York State Electric and Gas Corp.’s CCT-IVproject, Micronized Coal Reburning Demonstration forNO

x Control, final report issued and project completed.

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.
Program Update 1999 C-1

that will ensure operational compliance and thatsignificant technical and environmental data arecollected and disseminated. Data to be collectedinclude compliance data to meet federal, state, andlocal requirements and performance data to aid infuture commercialization of the technology.

x C: Environmental Aspects

projects, EAs for 18 projects and EISs for 4 projects(actions exceed 33 because of project terminations,withdrawals, and restructuring).

For each project cofunded by DOE under the

CCT Program, the industrial participant is requiredto develop an environmental monitoring plan (EMP)

nergy employs a three

CCT Program and its

dural requirements of

licy Act (NEPA), and

pliance promulgated by

Quality (CEQ) (40

DOE (10 CFR Part

1) preparation of a

mpact statement

n of preselection,

reviews; and (3) prepa

cific NEPA documen

 documents have been

uding memoranda-to

September 30, 1990),

A), and environmental

Department of Ener

ovide for categorical

sses of actions.

gress made through

te NEPA reviews of

By September 30,

mpleted for 35 of the 40

 program (two NEPA

e project, Enhancing

ning and Sorbent

eted for the Hennepin

e site). From 1987

NEPA requirements

project, MTFs for 17

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 through September 30, 1999

c Includes an EA for a project

that was terminated

Categorical exclusionsEnvironmental impact statements

Number of Projects
published in full conformance with CEQ and DOEregulations for NEPA compliance.Categorical Exclusions

“Subpart D—Typical Classes of Actions” of the

DOE NEPA regulations provides for categoricalexclusions as a class of actions that DOE has determined do not individually or cumulatively have asignificant effect on the human environment. Twoprojects, Micronized Coal Reburning Demonstrationfor NOx Control and Pulse Combustor Design Qualification Test, were covered by a categorical exclusion.

Memoranda-to-File

The MTF was established when DOE’s NEPA

guidelines were first issued in 1980. The MTF wasintended for circumstances when the expected impacts of the proposed action were clearly insignificant, yet the action had not been specified as a categorical exclusion from NEPA documentation. Theuse of the MTF was terminated as of September 30,1990. Exhibit C-2 lists the 17 projects for which anMTF was prepared.

Environmental Assessments

An EA has the following three functions:1. To provide sufficient evidence and analysis

for determining whether a proposed actionrequires preparation of an EIS or a finding ofno significant impact (FONSI);

2. To aid an agency’s compliance with NEPA

when no EIS is necessary, i.e., to provide aninterdisciplinary review of proposed actions,assess potential impacts, and identify betteralternatives and mitigation measures; and

n the CCT

n 1969 as Public Law

C. §4321 et seq. The

T Program is encapsu

Section 102):

nment shall—. . .

on or report on propos

Federal actions signifi

uman environment, a

le official on—

 proposed action,

cts which cannot be

implemented,

on,

hort-term uses of man’s

ce and enhancement of

e commitments of

ved in the proposed

d. . . .

propriate alternatives to

ny proposal which

rning alternative uses of

reated the CEQ,

ons that ensure

NEPA

was completed for the

ssed issues such as

potential global climatic modification and the ecological and socioeconomic impacts of the CCT Program.The PEIS evaluated the following two alternatives:

• “No action,” which assumed that conventional

coal-fired technologies with conventional fluegas desulfurization controls would continue tobe used, and

• “Proposed action,” which assumed that

successfully demonstrated clean coal technologies would undergo widespread commercialization by the year 2010.

In preselection project-specific environmental

reviews, 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 ofthe comprehensive evaluation prior to selectingprojects, the strengths and weaknesses of each proposal are compared with the environmental evaluation criteria. To the maximum extent possible, theenvironmental impacts of each proposed project andpractical mitigating measures are considered. Also,a list of necessary permits is prepared, to the extentknown; these are permits that would need to beobtained in implementing the proposed project.

Upon selection, project participants are required to

prepare and submit additional environmental information. This detailed site- and project-specific informationis used, along with independent information gatheredby DOE, as the basis for site-specific NEPA documentsthat are prepared by DOE for each selected project.These NEPA documents are prepared, considered, and
Program Update 1999 C-3

3. To facilitate preparation of an EIS when one is

necessary.

An EA’s contents are determined on a case-bycase basis and depend on the nature of the action. If

appropriate, a DOE EA also includes any floodplainor wetlands assessment that has been prepared, andmay include analyses needed for other environmentaldeterminations.

If an agency determines on the basis of an EA

that it is not necessary to prepare an EIS, a FONSI isissued. Council on Environmental Quality regulations describe the FONSI as a document that brieflypresents the reasons why an action will not have asignificant effect on the human environment and forwhich an EIS therefore will not be prepared. TheFONSI includes the EA, or a summary of it, andnotes any other related environmental documents.The CEQ and DOE regulations also provide fornotification of the public that a FONSI has beenissued. Also, DOE provides copies of the EA andFONSI to the public on request.

Exhibit C-3 lists the 18 projects for which an EA

has been prepared. The exhibit includes EAs for oneproject that was subsequently withdrawn from theprogram—TransAlta Resources Investment Corporation’s Low-NO

x

/SO2 Burner Retrofit for Utility

Cyclone Boilers project—and three that were terminated—ABB Combustion Engineering’s CombustionEngineering IGCC Repowering Project, BethlehemSteel Corporation’s Innovative Coke Oven GasCleaning System for Retrofit Applications, andPennsylvania Electric’s Warren Station ExternallyFired Combined-Cycle Demonstration Project.

Completed

ty ExpertTM (ABB Combustion Engineering, Inc. and CQ Inc.) 4/27/90

xtension and Coolside Demonstration 6/2/87

with Internal Sulfur, Nitrogen, and Ash Control 3/26/87

ect (Colorado-Ute Electric Association, Inc.; now Tri-State 4/18/88

Association, Inc.)

Gas Reburning and Sorbent Injection (Hennepin site) 5/9/88

search Corporation)

ject (The Ohio Power Company) 3/5/87

emonstration Project (ABB Environmental Systems) 1/31/90

Cleanup Demonstration Project 9/22/89

any)

mbustion Techniques for a Wall-Fired Boiler 5/22/89

nc.)

alytic Reduction Technology for the Control of NOx 8/16/89

oal-Fired Boilers (Southern Company Services, Inc.)

dvanced Tangentially-Fired Combustion Techniques for the 7/21/89

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

s Suspension Absorption (AirPol, Inc.) 9/21/90

w-NO

x Cell Burner Retrofit (The Babcock & Wilcox Company) 8/10/90

 Gas Desulfurization Demonstration (Bechtel Corporation) 9/25/90

nd Low-NOx Burners on a Wall-Fired Boiler (Energy and 9/6/90

ration)

furization Demonstration Project (LIFAC–North America) 10/2/90

ons Control System (Public Service Company of Colorado) 9/27/90

Exhibit C-2

Memoranda-to-File Completed
Completed

as Reburning and Sorbent Injection (Lakeside site) (Energy and Environmental Research Corporation) 6/25/89

ess Demonstration (Western SynCoal LLC) 3/27/91

Repowering Project (ABB Combustion Engineering, Inc.) (project terminated) 3/27/92

g for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) 2/12/91

ning System for Retrofit Applications (Bethlehem Steel Corporation) (project terminated) 12/22/89

Scrubber (Passamaquoddy Tribe) 2/16/90

on Demonstration Project (Pure Air on the Lake, L.P.) 4/16/90

plications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) 8/10/90

r Utility Cyclone Boilers (TransAlta Resources Investment Corporation) (project withdrawn) 3/21/91

n of the Liquid Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Company, L.P.) 6/30/95

ction System Demonstration Project (Bethlehem Steel Corporation) 6/8/93

on Project (ENCOALCorporation) 8/1/90

e NOXSO SO2/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) 6/26/95

rated Approach to Clean Air (Custom Coals International) 2/14/94

 Demonstration Project (New York State Electric & Gas Corporation) 8/18/93

Combined-Cycle Demonstration Project (Pennsylvania Electric Company) (Warren Station site) (project terminated) 5/18/95

Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) 5/28/93

n Project (Arthur D. Little, Inc.) 6/2/97

Exhibit C-3

Environmental Assessments Completed
Program Update 1999 C-5

Project and Participant Completed*CCT-IYork County Energy Partners Cogeneration Project (York County, PA site) 8/11/95(York County Energy Partners, L.P.) (project relocated)CCT-IIIHealy Clean Coal Project (Alaska Industrial Development and Export Authority) 3/10/94Tampa Electric Integrated Gasification Combined-Cycle Project 8/17/94(Tampa Electric Company)CCT-IVPiñon Pine IGCC Power Project (Sierra Pacific Power Company) 11/8/94

* Completion is the date DOE issued a record of decision.

tements

 EIS is to serve as an

 that the policies and

sed into the programs

rnment. An EIS con

of all significant envi

hould inform decision

nable alternatives that

rse impacts or enhance

onment.

 that an EIS is to be

nt; it is to be used by

 with other relevant

ake decisions. Analy

ass those alternatives

e decision maker,

on of the proposed

means of assessing the

oposed DOE action

s already made), prior

d with the proposed

 record of decision

t take any action that

mental effect or limit

atives. As seen in

 projects were complet

ued a ROD on the EIS

Energy Partners project

ylvania. However,

estructured, a new

will be required for the

 of projects for which

been completed.

Exhibit C-4

Environmental Impact Statements Completed

Project and Participant StatusCCT-IJEA Large-Scale CFB Combustion Demonstration Project EIS planned (4/00)CCT-IIIMcIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) EIS planned (10/00)CCT-VMcIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, EIS planned (10/00)Lakeland Electric)Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management EIS planned (12/00)Company L.L.C.)Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, L.L.C.) To be determined

Exhibit C-5

NEPA Reviews in Progress
With respect to emission of air toxics,Proposers should consider . . . the particularelements and compounds [listed in Table 5-1of the PON, “Specific Air Toxics to beMonitored”]. Proposers should present anyinformation known concerning the reduction ofemissions of these toxics by [the proposed]technology. Some of the toxics for which theproposed technology may offer control arelikely unregulated in the target market atpresent. The significance and importance ofthe additional control afforded by the proposedtechnology for the continued use of coalshould be explained. An example of this kindwould be one or more particular air toxiccompounds controlled by a technology meantfor use in power generation.

The CCT-V PON also stipulates that information

on air toxics be presented in the environmental information required by DOE. Exhibit C-7 lists the 20projects that provide for HAPs monitoring. Eleven ofthese projects have completed the HAPs monitoringrequirements. The objective of the HAPs monitoringprogram is to improve the quality of HAPs data beinggathered and to monitor a broader range of plantconfigurations and emissions control equipment.

The CCT Program is coordinating with organizations such as the Electric Power Research Institute

(EPRI) and the Ohio Coal Development Office inactivities focused on HAPs monitoring and analysis.Further, under the DOE Coal R&D Program, tworeports summarizing the source, distribution, and fateof HAPs from coal-fired power plants were publishedin 1996. A report released in July 1996, Summary of

Air Toxics Emissions Testing at Sixteen Utility Plants,provided assessment of HAPs measured in the coal,across the major pollution control devices, and theHAPs emitted from the stack. A second report, 

A

Comprehensive Assessment of Toxics Emissions fromCoal-Fired Power Plants: Phase I Results from the

nitoring

 required to develop

resses both compli

ng. Exhibit C-6 lists

jects in the CCT

to ensure collection

cant technology-,

nmental data neces

pon health, safety, and

ata are used to char

nmental performance

luate its commercial

l. In addition to

her monitoring is

mbient levels of

ental impacts do not

ected in the NEPA

rective action,

n of any mitigative

een identified in a

ursuant to the provi

nd

a on the environmen

chnology needed to

pact of future com

 the ability of the

rements of the Clean

mendments.

gram’s environmental

t, when commercially

available, clean coal technologies will be capable ofresponding fully to air toxics regulations that emergefrom the CAAA, and to the maximum extent possible, arein the vanguard of cost-effective solutions to concernsabout public health and safety related to coal use.Air Toxics

Title III of the CAAA lists known hazardous air

pollutants (HAPs) and, among other things, calls 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 of

monitoring HAPs in achieving widespread commercialization in the late 1990s and beyond. For allprojects with existing cooperative agreements, DOEsought to include HAPs monitoring. A total of 20projects contain provisions for monitoring HAPs.

The CCT-V Program Opportunity Notice (PON)

acknowledged the importance of HAPs throughout thesolicitation, including them as an aspect of proposalevaluation. The PON addressed the control of airtoxics as an environmental performance criterion.Also, in the instructions on proposal preparation, thePON directed proposers as follows:
Program Update 1999 C-7

Status

ty ExpertTM (ABB Combustion Engineering, Inc. and CQ Inc.) Completed 7/31/90

Extension and Coolside Demonstration (McDermott Technology, Inc.) Completed 10/19/88

 with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) Completed 9/22/87

ect (Colorado-Ute Electric Association, Inc.; now Tri-State Generation and Transmission Association, Inc.) Completed 2/27/88

Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Completed 10/15/89 (Hennepin)

Completed 11/15/89 (Lakeside)

ject (The Ohio Power Company) Completed 5/25/88

ocess Demonstration (Western SynCoal LLC) Completed 4/7/92

tion Demonstration Project (JEA) Projected 6/01

emonstration Project (ABB Environmental Systems) Completed 10/31/91

ng for Cyclone Boiler NOx Control (The Babcock & Wilcox Company) Completed 11/18/91

Cleanup Demonstration Project (The Babcock & Wilcox Company) Completed 12/31/91

y Scrubber (Passamaquoddy Tribe) Completed 3/26/90

ation Demonstration Project (Pure Air on the Lake, L.P.) Completed 1/31/91

ombustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Completed 9/14/90

pplications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Completed 12/18/90

alytic Reduction Technology for the Control of NOx Emissions from High-Sulfur-Coal-Fired Completed 3/11/93

rvices, Inc.)

dvanced Tangentially-Fired Combustion Techniques for the Reduction of NOx Emissions from Completed 12/27/90

ompany Services, Inc.)

Exhibit C-6

Status of Environmental Monitoring Plans for CCT Projects
Status

n of the Liquid Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Company, L.P.) Completed 8/29/96

Suspension Absorption (AirPol, Inc.) Completed 10/2/92

a Industrial Development and Export Authority) Completed 4/11/97

w-NO

x Cell Burner Retrofit (The Babcock & Wilcox Company) Completed 8/9/91

Gas Desulfurization Demonstration (Bechtel Corporation) Completed 6/12/91

ction System Demonstration Project (Bethlehem Steel Corporation) Completed 12/23/94

stration Project (Lakeland, City of, Lakeland Electric) Projected 8/01

on Project (ENCOAL Corporation) Completed 5/29/92

 Low-NOx Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) Completed 7/26/90

urization Demonstration Project (LIFAC–North America) Completed 6/12/92

ns Control System (Public Service Company of Colorado) Completed 8/5/93

cation Combined-Cycle Project (Tampa Electric Company) Completed 5/96

e NOXSO SO2/ NOx Removal Flue Gas Cleanup System (NOXSO Corporation) To be determined

monstration for NOx Control (New York State Electric & Gas Corporation) Completed 8/97

 Demonstration Project (New York State Electric & Gas Corporation) Completed 12/1/94

(Sierra Pacific Power Company) Projected 12/31/00

Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Completed 7/9/93

cation Test (ThermoChem, Inc.) To be determined

rated Approach to Clean Air (Custom Coals International) To be determined

n Project (Arthur D. Little, Inc.) Projected 2/99

al/Ore Reduction (CPICORTM) (CPICORTM Management Company L.L.C.) Projected 9/02

Demonstration Project (Kentucky Pioneer Energy, L.L.C.) To be determined

 Demonstration Project (Lakeland, City of, Lakeland Electric) Projected 8/03

Exhibit C-6 (continued)

Status of Environmental Monitoring Plans for CCT Projects
Program Update 1999 C-9

rticipant Project Status

thur D. Little, Inc. Clean Coal Diesel Demonstration Project Planned

ntucky Pioneer Energy, L.L.C. Kentucky Pioneer Energy IGCC Demonstration Project Planned

keland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project Planned

e Ohio Power Company Tidd PFBC Demonstration Project Completed

rra Pacific Power Company Piñon Pine IGCC Power Project Planned

mpa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project In progress

abash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project In progress

oject Joint Venture

A JEA Large-Scale CFB Combustion Demonstration Project Planned

B Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project Completed

rPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption Completed

e Babcock & Wilcox Company Demonstration of Coal Reburning for Cyclone Boiler NOx Control Completed

e Babcock & Wilcox Company SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project Completed

w York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project Completed

blic Service Company of Colorado Integrated Dry NOx/SO2 Emissions Control System Completed

re Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Completeduthern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Completeduthern Company Services, Inc. Demonstration of Innovative Applications of Technology for the Completed

CT-121 FGD Process

uthern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Completed

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

COAL Corporation ENCOAL® Mild Coal Gasification Project Completed

ICORTM Management Company L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICORTM) Planned

Exhibit C-7

CCT Projects Monitoring Hazardous Air Pollutants
y, was released in

e raw data from the

ta were collected

ng nine process

t different utilities;

or CCT Program

esented a range of

figurations, furnace

hods.

OE/EPRI effort cur

 other sites, including

er IGCC project.

t phase will be used to

d coal types require

mitted to Congress an

ssessment of toxic air

plants, Study of

ons from Electric

Interim Final Report.

g the potential expo

 concerns from

. In addition, the

n on various potential

. If EPA decides that

cy must propose air

ember 15, 1998, and

r 1996 report to

by EPA focusing on

ber 1997 report,

ess, estimates the U.S.

ble for releasing 158

ere in 1994 and 1995.

nt of those emissions

es 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 next step for EPA is to assess the need forenhanced research on health effects and on newpollution control technologies, community “right-toknow” approaches, and regulatory actions.

The results of the HAPs program have significantly mitigated concerns about HAPs emission

from coal-fired generation and focused attention onbut a few flue gas constituents. The results havethe potential to make the forthcoming EPA regulations less strict, which could avoid unnecessarycontrol costs and thus save consumers money onelectricity bills.
Program Update 1999 D-1

x D: CCT Project Contacts

Environmental Control DevicesSO2 Control Technologies10-MWe Demonstration of Gas SuspensionAbsorptionParticipant:AirPol, Inc.Contacts:Niels H. Kastrup

(281) 539-3400(281) 539-3411 (fax)nhk@flsmiljous.comFLS 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 Dispersion Flue GasDesulfurization DemonstrationParticipant:Bechtel CorporationContacts:Joseph T. Newman, Project Manager

(415) 768-1189(415) 768-5420 (fax)Bechtel CorporationP.O. Box 193965San Francisco, CA 94119-3965

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

LIFAC Sorbent Injection DesulfurizationDemonstration ProjectParticipant:LIFAC-North AmericaContacts:Dan Stap, Project Manager

(412) 497-2231(412) 497-2212 (fax)ICF Kaiser Engineers, Inc.Gateway View Plaza1600 West Carson StreetPittsburgh, PA 15219-1031

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

for obtaining further

T Program

d are the name, title,

ailing address, and

r the project

n those instances

onsists of more than

r joint venture, the

f the contact person.

numbers, and e-mail

at DOE Headquarters

nology Laboratory
NOx Control TechnologiesMicronized Coal Reburning Demonstration for NOxControlParticipant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)New York State Electric & Gas CorporationCorporate 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 CycloneBoiler NOx ControlParticipant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)dot.k.johnson@mcdermott.comMcDermott Technologies1562 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 Demonstration of Low-NOx CellBurnerRetrofitParticipant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)dot.k.johnson@mcdermott.comMcDermott Technologies1562 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

Evaluation of Gas Reburning and Low-NOx

Burners on a Wall-Fired BoilerParticipant:Energy and Environmental Research CorporationContacts:Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140(949) 859-3194 (fax)General Electric Energy and EnvironmentalResearch 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

ation

icals, Inc.

1) 903-9483

v

86-5991

Applications of

GD Process

c.

ger

s, Inc.

25

1) 903-9483

v

86-5991
Program Update 1999 D-3

Demonstration of Advanced Combustion Techniquesfor a Wall-Fired BoilerParticipant: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 TechnologiesMilliken Clean Coal Technology DemonstrationProjectParticipant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)New York State Electric & Gas CorporationCorporate 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 Cleaning Demonstration ProjectParticipant:ABB Environmental SystemsContacts:Paul Yosick, Project Manager

(423) 693-7550(423) 694-5203 (fax)ABB Environmental Systems1409 Center Point BoulevardKnoxville, TN 37932

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

LIMB Demonstration Project Extension andCoolside DemonstrationParticipant:The McDermott Technology, Inc.Contacts:Paul Nolan

(330) 860-1074(330) 860-2045 (fax)The McDermott Technology, Inc.20 South Van Buren AvenueP.O. Box 351Barberton, OH 44203-0351

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

John C. McDowell, NETL, (412) 386-6175

mcdowell@netl.doe.gov

atalytic Reduction

f NOx Emissions

d Boilers

nc.

es, Inc.

195

01) 903-9483

ov

386-5991

Advanced

on Techniques for

ons from Coal-Fired

nc.

es, Inc.

195

01) 903-9483

ov

386-5991
Cleanup

y

com

1) 903-9483

v

86-5991

y Gas Reburning

arch Corporation

esident

Environmental

1) 903-9483

v

6-6079

Advanced Electric PowerGenerationFluidized-Bed CombustionMcIntosh Unit 4A PCFB Demonstration ProjectParticipant:City of Lakeland, Lakeland ElectricContacts:Alfred M. Dodd, Project Manager

(941) 499-6461(941) 499-6344 (fax)Lakeland Electric501 E. Lemon StreetLakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald L. Bonk, NETL, (304) 285-4889

dbonk@netl.doe.gov

Integrated Dry NOx/SO2 Emissions Control

SystemParticipant:Public Service Company of ColoradoContacts:Terry Hunt, Project Manager

(303) 571-7113(303) 571-7868 (fax)thunt@ueplaza.comUtility Engineering550 15th Street, Suite 800Denver, CO 80202-4256

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

Commercial Demonstration of the NOXSO SO2/

NO

x Removal Flue Gas Cleanup System

Participant:NOXSO CorporationContacts:Lawrence Saroff DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov
Program Update 1999 D-5

B Demonstration

tric

ger

) 903-9434

 285-4889

stion Demonstration

ower 10

39

) 903-9434

86-6079

Tidd PFBC Demonstration ProjectParticipant:American Electric Power Service Corporation asagent for The Ohio Power CompanyContacts:Michael J. Mudd

(614) 223-1585(614) 223-2499 (fax)mjmudd@aep.comAmerican Electric Power Service Corporation1 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 ProjectParticipant:Tri-State Generation and TransmissionAssociation, Inc.Contacts:Stuart Bush

(303) 452-6111(303) 254-6066 (fax)Tri-State Generation and TransmissionAssociation, 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 Gasification Combined-CycleKentucky Pioneer IGCC Demonstration ProjectParticipant:Kentucky Pioneer Energy, L.L.C.Contacts:H. H. Graves, President

(513) 621-0077(513) 621-5947 (fax)hhg@globalenergyinc.comKentucky Pioneer Energy, L.L.C.312 Walnut Street, Suite 200Cincinnati, OH 45202

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Douglas M. Jewell, NETL, (304) 285-4720

doug.jewell@netl.doe.gov

Piñon Pine IGCC Power ProjectParticipant:Sierra Pacific Power CompanyContacts:Jeffrey W. Hill, Director Power Generation

(775) 834-5650(775) 834-5704 (fax)jhill@sppc.comSierra Pacific Power CompanyP.O. Box 10100Reno, NV 89520-0024

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, NETL, (304) 285-4784

dgeili@netl.doe.gov

Web Site:http://www.sierrapacific.com/utilserv/electric/pinon/
ication Combined

nced Technology

903-9434

86-5991

kPwrStn.html

 Repowering Project

Repowering Project

ation Development

800

903-9434

 386-5814

Advanced Combustion/Heat EnginesHealy Clean Coal ProjectParticipant:Alaska Industrial Development and Export AuthorityContacts:Dennis V. McCrohan, Deputy Director, Project

Development and Operations(907) 269-3025(907) 269-3044 (fax)dmccrohan@aidea.orgAlaska Industrial Development and ExportAuthority480 West Tudor RoadAnchorage, AK 99503-6690

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Robert M. Kornosky, NETL, (412) 386-4521

robert.kornosky@netl.doe.gov

Clean Coal Diesel Demonstration ProjectParticipant:Arthur D. Little, Inc.Contacts:Robert P. Wilson, Vice President

(617) 498-5806(617) 498-7206 (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 Processing for Clean FuelsIndirect LiquefactionCommercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOHTM) ProcessParticipant:Air Products Liquid Phase Conversion Company, L.P.Contacts:Edward C. Heydorn, Project Manager

(610) 481-7099(610) 706-7299 (fax)heydorec@apci.comAir Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501

Edward Schmetz, DOE/HQ, (301) 903-3931

edward.schmetz@hq.doe.gov

Robert M. Kornosky, NETL, (412) 386-4521

robert.kornosky@netl.doe.gov
Program Update 1999 D-7

ogies

ocess Demonstration

r of Development

hip

01) 903-9443

ov

 386-6406

ty ExpertTM

 Inc. and CQ Inc.

01) 903-9443

ov

 386-6406

qe/cqe.htm

Mild GasificationENCOAL® Mild Coal Gasification Project

Participant:ENCOAL CorporationContacts:James P. Frederick, Project Director

(307) 686-2720, ext. 27(307) 686-2894 (fax)jfrederick@vcn.comSGI InternationalP.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

Self-Scrubbing CoalTM: An Integrated Approach toClean AirParticipant:Custom Coals InternationalContacts:Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk III, NETL, (412) 386-6406

joseph.renk@netl.doe.gov

Industrial ApplicationsBlast Furnace Granular-Coal Injection SystemDemonstration ProjectParticipant:Bethlehem Steel CorporationContacts:Robert W. Bouman, Project Director

(610) 694-6792(610) 694-2981 (fax)Bethlehem Steel CorporationBuilding C, Room 211Homer Research LaboratoryMountain Top CampusBethlehem, PA 18016

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Leo E. Makovsky, NETL, (412) 386-5814

makovsky@netl.doe.gov

Clean Power from Integrated Coal/Ore Reduction(CPICORTM)Participant:CPICORTM Management Company, L.L.C.Contacts:Reginal Wintrell, Project Director

(801) 227-9214(801) 227-9198 (fax)CPICORTM Management Company L.L.C.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
with Internal Sulfur,

m

301) 903-9448

v

86-5991

 Scrubber

nager

y, L.P.

301) 903-9448

v

2) 386-6175

Pulse Combustor Design Qualification TestParticipant:ThermoChem, Inc.Contacts:William G. Steedman, Sr. Systems Engineer

(410) 354-9890(410) 354-9894 (fax)wsteedman@tchem.netThermoChem, Inc.6001 Chemical RoadBaltimore, MD 21226

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Robert M. Kornosky, NETL, (412) 386-4521

robert.kornosky@netl.doe.gov
Program Update 1999 E-1

x E: Acronyms, Abbreviations, and

viations, and

us

enheit

lowatt

n

demark

stion Engineering, Inc.

nmental Systems

circulating fluidized

tle, Inc.

gy Outlook 1999

gy Outlook 2000

gy Review 1998

fluidized-bed

e gas desulfurization

trial Development and

rity

erfire air

ticulate filter

tractable Injection

ASME American Society of Mechanical

Engineers

Ass’n. AssociationATCF after tax cash flowsatm atmosphere(s)avg. averageBFGCI blast furnace granular-coal injectionBG British GasBG/L British Gas/LurgiBtu 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 lime

Ca/N calcium/nitrogenCAPI Clean Air Power InitiativeCa/S calcium-to-sulfurCaSO3 calcium sulfite

CaSO4 calcium sulfateCCOFA close-coupled overfire airCCT clean coal technologyCCT I First CCT Program solicitationCCT II Second CCT Program solicitation

CCT III Third CCT Program solicitationCCT IV Fourth CCT Program solicitationCCT V Fifth CCT Program solicitationCCT Program Clean Coal Technology

Demonstration Program

CD-ROM Compact disk-read only memoryCDL® Coal-Derived Liquid®

CEQ Council on Environmental QualityCFB circulating fluidized-bedC/H carbon/hydrogenCKD cement kiln dustCO carbon monoxideCO2 carbon dioxideCOP Conference of PartiesCT-121 Chiyoda Thoroughbred-121CQETM Coal Quality ExpertTMCQIMTM Coal Quality Impact ModelTMCX categorical exclusionCZD confined zone dispersionDER discrete emissions reductionDME dimethyl etherDOE U.S. Department of EnergyDOE/HQ U.S. Department of Energy

Headquarters

DSE dust stabilization enhancementDSI dry sorbent injectionEA environmental assessmentEER Energy and Environmental

Research Corporation
vironmental Research

sity of North Dakota

d combined cycle

ation Administration

 impact statement

 Information Volume

 monitoring plan

ental Protection

Act of 1992

c Power

Company

 Research Institute

ecipitator

ale generator

ombustion

nvention on Climate

y Regulatory

y Technology Center

urization

ignificant impact

forced plastic

are feet, cubic feet

bic feet

ic

ses

GNOCIS Generic NO

x Control Intelligence

System

gpm gallons per minuteGR gas reburningGR-LNB gas reburning and low-NOx burner

GR-SI gas reburning and sorbent injectionGSA gas suspension absorptionGVEA Golden Valley Electric AssociationGW gigawatt(s)GWe gigawatt(s)-electricH2S hydrogen sulfideH2SO4 sulfuric acid

HAP hazardous air pollutantHCl hydrogen chlorideHF hydrogen fluorideHGPFS hot gas particulate filter systemHHV high heating valuehr. hour(s)HRSG heat recovery steam generatorID Induced DraftIEA International Energy AgencyIEO99 International Energy Outlook 1999IGCC integrated gasification combinedcyclein, in2, in3 inch(es), square inches, cubic inchesJBR Jet Bubbling Reactor®KCl potassium chlorideK2SO4 potassium sulfatekW kilowatt(s)kWh kilowatt-hour(s)lb. pound(s)L/G liquid-to-gas ratioLHV low heating valueLIMB limestone injection multistage

burner

LNB low-NO

x

 burner

LNCB® low-NO

x

 cell burner

LNCFS Low-NO

x Concentric-Firing System

LOI loss-on-ignitionLPMEOHTM Liquid phase methanolTMLRCWF low-rank coal-water-fuelLSFO limestone forced oxidationMASB multi-annular swirl burnerMB megabyte(s)MCFC molten carbonate fuel cellMDEA methyldiethanolamineMgCO3 magnesium carbonateMgO magnesium oxideMhz megahertzmills/kWh mills per kilowatt hourmin. minute(s)mo. month(s)MTCI Manufacturing and Technology

Conversion International

MTF memorandum (memoranda)-to-fileMW megawatt(s)MWe megawatt(s)-electricMWt megawatt(s)-thermalN2 atmospheric nitrogenNa/Ca sodium/calciumNa2/S sodium/sulfurNaOH sodium hydroxideNa2CO3 sodium carbonateNAAQS National Ambient Air Quality

Standards

NEPA National Environmental Policy ActNETL National Energy Technology

Laboratory (formerly FETC)

NH3 ammoniaNm3 Normal cubic meterNO2 nitrogen dioxide
Program Update 1999 E-3

posed Rulemaking

es

Performance Standards

oichiometric ratio

t metal

hnical Information

ate Electric & Gas

al & Power Systems

d maintenance

port Assessment Group

port Commission

bilization System

puter

Committee of Advisors

nd Technology

irculating fluidized bed

ved Fuel®

c environmental impact

c environmental impact

on Optimization

 Electric Company

uation plan

uidized-bed

house

atter

atter less than 10

ameter

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

Colorado

PSD 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-minerpm revolutions per minuteRUS Rural Utility ServiceS sulfurSBIR Small Business Innovation Researchscf standard cubic feetscfm standard cubic feet per minuteSCR selective catalytic reductionSCS Southern Company Services, Inc.

SFC Synthetic Fuels CorporationS-H-U Saarberg-Hölter-UmwelttechnikSI sorbent injectionSIP state implementation planSM service markSNCR selective noncatalytic reductionSNRBTM SO

x

-NO

x

-Rox BoxTM

SO2 sulfur dioxide

SO3 sulfur trioxidestd ft3 standard cubic feetSOFA separated overfire airSTTR Small Business Technology

Transfer Program

SVGA super video graphics adapterTAGTM Technical Assessment GuideTMTCLP toxicity characteristics leaching

procedure

TVA Tennessee Valley AuthorityUAF University of Alaska, FairbanksUARG Utility Air Regulatory GroupUBCL unburned carbon lossesU.K. United KingdomUNESCO United Nations Educational,

Scientific and Cultural Organization

U.S. United StatesVFB vibrating fluidized-bedVOC volatile organic compoundWC water columnWES wastewater evaporation systemWLFO wet limestone, forced oxidationwt. weightyr. year(s)
s

umbia

re

NC North CarolinaND North DakotaOH OhioOK OklahomaOR OregonPA PennsylvaniaPR Puerto RicoRI Rhode IslandSC South CarolinaSD South DakotaTN TennesseeTX TexasUT UtahVT VermontVA VirginiaVI Virgin IslandsWA WashingtonWV West VirginiaWI WisconsinWY Wyoming

OtherSome companies have adopted an acronym as theircorporate names. The following corporate namesreflect the former name of the company.BG/L British Gas LurgiJEA Jacksonville Electric Authority
Program Update 1999 Index-1

CCT Projects and Participants

s Suspension

, ES-22, 2-7, 3-8,

, B-3, B-5, C-3,

dvanced Tangentially

ques for the Reduction

oal-Fired Boilers ES

5,

-3, B-5, C-3, C-7,

 Inc. ES-17,

7, 3-8, 4-3, 4-9,

5-17, 5-58, 5-66,

B-5, B-6, C-3,

ES-9, ES-12,

-17, 5-74, B-6,

ocess

ES-23, 2-7, 4-12,

B-2, B-3, C-4,

 with Internal Sulfur,

ES-19, ES-23,

17, 5-156, B-1,

ation Demonstration

S-22, ES-24, 2-7,

, 5-18, 5-32, B-2,

Advanced Slagging Coal Combustor Utility Demonstration Project B-2, B-3Air Products and Chemicals, Inc. B-4, B-5Air Products Liquid Phase Conversion Company,

L.P. ES-18, ES-23, 2-7, 4-9, 4-12, 5-16,5-17, 5-132, 5-133, B-5, C-4, C-8, D-6

AirPol, Inc. ES-11, ES-22, 2-7, 3-8, 4-2, 4-4,

5-15, 5-17, 5-20, 5-23, B-3, B-5, C-3,C-8, C-9, D-1

Alaska Industrial Development and Export

Authority ES-16, ES-23, 2-7, 4-10, 5-16,5-17, 5-126, B-3, C-5, C-8, D-6, E-1

Appalachian IGCC Demonstration Project, The B-2Appalachian Power Company B-3, B-5Arthur D. Little, Inc. ES-23, 2-8, 5-16, 5-17,

5-128, B-4, B-5, C-4, C-8, C-9, D-6, E-1

Arvah B. Hopkins Circulating Fluidized-Bed Repowering Project B-3BBabcock & Wilcox Company, The ES-8,

ES-9, ES-11, ES-12, ES-22, ES-24, 2-7,3-8, 4-3, 4-5, 4-6, 4-7, 4-13, 5-15, 5-17,5-46, 5-50, 5-78, 5-86, B-1, B-2, B-3,B-4, B-5, C-3, C-4, C-7, C-8, C-9, D-2,D-4, E-1

Bechtel Corporation ES-7, ES-11, ES-22, 2-8,

4-2, 4-4, 5-15, 5-17, 5-24, B-3, B-5, C-3,C-8, D-1

Bechtel Development Company B-2Bethlehem Steel Corporation ES-2, ES-19,

ES-23, 2-8, 4-11, 4-12, 5-16, 5-17, 5-152,B-2, B-3, B-5, C-3, C-4, C-8, D-7

Blast Furnace Granular-Coal Injection System

Demonstration Project ES-2, ES-19,ES-23, 2-8, 4-12, 5-13, 5-16, 5-17, 5-152,B-3, C-4, C-8, D-7

CCalvert City Advanced Energy Project B-4Camden Clean Energy Demonstration Project B-4Cement Kiln Flue Gas Recovery Scrubber

ES-19, ES-23, 2-7, 4-12, 5-13, 5-16, 5-18,5-160, B-2, B-4, C-4, C-7, D-8

Centerior Energy Corporation B-4Clean Coal Combined-Cycle Project B-4Clean Coal Diesel Demonstration Project ES-23,

2-8, 4-8, 5-9, 5-16, 5-17, 5-128, B-4, B-5,C-4, C-8, C-9, D-6

Clean Energy IGCC Demonstration Project B-2,

B-3, B-5, D-5

Clean Energy Partners Limited Partnership B-5Clean Power Cogeneration Limited Partnership B-3Clean Power from Integrated Coal/Ore Reduction

(CPICORTM) ES-23, 2-8, 5-13, 5-16,5-17, 5-148, B-4, B-6, C-5, C-8, C-9, D-7

Coal Diesel Combined-Cycle Project B-5Coal Tech Corporation ES-19, ES-23, 2-7,

4-11, 4-12, 5-16, 5-17, 5-156, B-1, B-4,C-3, C-7, D-8

Coal Waste Recovery Advanced Technology

Demonstration B-2

Colorado-Ute Electric Association, Inc. B-2Combustion Engineering IGCC Repowering

Project B-3, B-5, C-4
B-2

he NOXSO SO2/NOx

 System ES-2,

, 5-15, 5-18,

D-4

on of the Liquid Phase

ES-18, ES-23,

6, 5-17, 5-132,

Gas

-11, ES-22, 2-8,

, B-3, B-5, C-3,

nstration Project

tion Project B-2

any L.L.C.

16, 5-17, 5-148,

C-9, D-7

, ES-24, 2-7,

, 5-16, 5-17,

, C-7, D-7

-2, ES-23, 2-8,

, 5-17, 5-134,

B-3

mbustion Techniques

S-8, ES-12,

, 5-18, 5-42,

D-3

echnology at Easton

Demonstration of Coal Reburning for Cyclone Boiler

NOx Control ES-8, ES-11, ES-22, 2-7,

4-5, 5-5, 5-15, 5-17, 5-46, B-3, B-4, C-4,C-7, C-9, D-2

Demonstration of Innovative Applications of Technology for the CT-121 FGD ES-7, ES-11,

ES-22, ES-24, 2-7, 4-4, 4-13, 5-3, 5-15,5-18, 5-36, B-3, B-6, C-4, C-7, C-9, D-2

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx Emissions

from High-Sulfur, Coal-Fired BoilersES-8, ES-11, ES-22, 2-7, 4-5, 5-5, 5-15,5-18, 5-62, B-3, B-6, C-3, C-7, D-3

Demonstration of the Union Carbide CANSOLVT

System at the Alcoa Generating CorporationWarrick Power Plant B-4

Development of the Coal Quality ExpertTM

ES-17, ES-18, ES-23, ES-24, 2-7, 3-8,4-12, 4-13, 5-11, 5-16, 5-17, 5-138, B-2,B-3, B-6, C-3, C-7, D-7

Direct Iron Ore Reduction to Replace Coke Oven/

Blast Furnace for Steelmaking B-2

DMEC-1 Limited Partnership B-3, B-6Duke Energy Corp. B-4, B-5EEastman Kodak Company B-5ENCOAL Corporation ES-17, ES-18, ES-23, 2-

8, 4-9, 4-12, 5-16, 5-17, 5-142, B-3, B-6, C4, C-8, C-9, D-7

ENCOAL® Mild Coal Gasification Project

ES-17, ES-18, ES-23, 2-8, 4-12, 5-10,5-11, 5-16, 5-17, 5-142, B-3, B-6, C-4,C-8, C-9, D-7

Energy and Environmental Research

Corporation ES-8, ES-9, ES-11, ES-12,ES-22, ES-24, 2-7, 2-8, 4-3, 4-5, 4-6, 4-7,4-13, 4-26, 5-15, 5-17, 5-54, 5-82, B-2,B-3, B-6, C-3, C-4, C-7, C-8, D-2, D-4, E-1

Energy International, Inc. B-2Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection ES-9, ES-12, ES-22,ES-24, 2-7, 4-7, 5-6, 5-15, 5-17, 5-82,B-2, B-6, C-3, C-4, C-7, D-4

Evaluation of Gas Reburning and Low-NOx Burners

on a Wall-Fired Boiler ES-8, ES-11,ES-22, ES-24, 2-8, 4-5, 4-13, 5-5, 5-15,5-17, 5-54, B-3, B-6, C-3, C-8, D-2

Externally Fired Combined-Cycle Demonstration

Project B-6

FFoster Wheeler Power Systems, Inc. B-2, B-3Four Rivers Energy Modernization Project B-4, B-5Four Rivers Energy Partners, L.P. B-4, B-5, B-6Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit ES-8, ES-11, ES-22, ES-24, 2-7,

3-8, 4-5, 4-13, 5-5, 5-15, 5-17, 5-50, B-3,B-5, C-3, C-8, D-2

GGeneral Electric Company B-2HHealy Clean Coal Project ES-2, ES-16, ES-23,

2-7, 2-13, 4-8, 4-10, 5-9, 5-16, 5-17,5-126, B-3, C-5, C-8, D-6
Program Update 1999 Index-3

aning System for

C-4

eam Injection Gas

ants with Hot Gas

ions Control

ES-22, 2-8, 4-7,

-3, C-3, C-8, C-9,

B-6

5-17, 5-104, B-3,

tion Demonstration

, 5-15, 5-17,

-7, C-9, D-5

C Demonstration

8, 4-8, 5-9, 5-16,

C-8, C-9

C. ES-23, 2-8,

C-8, C-9, D-5

ectric ES-22, 2-8,

, B-6, C-5, C-8,

furization Demonstra

1, ES-22, 2-8, 4-4,

-3, B-6, C-3, C-8,

LIFAC–North America ES-7, ES-11, ES-22,

2-8, 4-2, 4-4, 5-15, 5-17, 5-28, B-3, B-6,C-3, C-8, D-1

LIMB Demonstration Project Extension and Coolside

Demonstration ES-9, ES-12, ES-22, 2-7,4-7, 5-6, 5-15, 5-17, 5-86, B-1, B-4, C-3,C-7, D-3

LNS Burner for Cyclone-Fired Boilers Demonstration Project B-3MM.W. Kellogg Company, The B-2McDermott Technology, Inc. ES-9, ES-12,

ES-22, 2-7, 4-7, 5-15, 5-17, 5-86, B-1,B-4, C-3, C-7, D-3

McIntosh Unit 4A PCFB Demonstration

Project ES-22, 2-8, 4-8, 5-9, 5-15, 5-17,5-100, 5-102, B-6, C-5, C-8, D-4

McIntosh Unit 4B Topped PCFB Demonstration

Project ES-22, 2-8, 4-8, 5-9, 5-15, 5-17,5-100, 5-102, B-4, B-6, C-5, C-8, C-9, D-5

Micronized Coal Reburning Demonstration for NOx

Control ES-2, ES-8, ES-11, ES-22, 2-8,4-5, 5-5, 5-15, 5-17, 5-58, B-4, B-5, B-6,C-8, D-2

Milliken Clean Coal Technology Demonstration

Project ES-9, ES-12, ES-13, ES-22, 2-8,4-7, 5-6, 5-15, 5-18, 5-90, B-4, B-6, C-4,C-8, C-9, D-3

Milliken Station B-5Minnesota Department of Natural Resources B-2MK-Ferguson Company B-3

NNew York State Electric & Gas Corporation

ES-8, ES-9, ES-11, ES-12, ES-13, ES-22,2-8, 4-3, 4-5, 4-7, 5-15, 5-17, 5-18, 5-58,5-90, B-4, B-5, B-6, C-4, C-8, C-9, D-2,D-3, E-3

Nichols CFB Repowering Project B-3NOXSO Corporation ES-2, ES-22, 2-8, 2-13,

3-1, 4-1, 4-6, 5-15, 5-18, 5-72, B-3, B-5,C-4, C-8, D-4

Nucla CFB Demonstration Project ES-15,

ES-16, ES-23, 2-7, 3-8, 4-10, 5-9, 5-16,5-18, 5-110, B-2, B-4, C-3, C-7, D-5

OOhio Power Company, The ES-15, ES-16,

ES-23, ES-24, 2-7, 4-6, 4-10, 4-13, 5-16,5-18, 5-106, B-1, B-5, C-3, C-7, C-9, D-5

Ohio Ontario Clean Fuels, Inc. B-2, B-3Otisca Fuel Demonstration Project B-3Otisca Industries, Ltd. B-3PPassamaquoddy Tribe ES-19, ES-23, 2-7, 4-11,

4-12, 5-16, 5-18, 5-160, B-2, B-4, C-4,C-7, D-8

Pennsylvania Electric Company B-4, B-5, B-6, C-4PFBC Utility Demonstration Project B-3, B-5Piñon Pine IGCC Power Project ES-23, 2-8,

2-13, 4-8, 4-10, 5-9, 5-16, 5-18, 5-118,B-4, C-5, C-8, C-9, D-5

Postcombustion Sorbent Injection Demonstration

Project B-2
Coprocessing

orado ES-10,

-7, 5-15, 5-18,

D-4

cation Test

16, 5-18, 5-150,

7, ES-11,

-2, 4-3, 4-4,

2, B-5, C-4,

B-2, B-3

grated Approach to

2-8, 2-13, 4-1,

B-4, C-4, C-8, D-7

ES-23, 2-8, 4-8,

B-4, C-5, C-8,

monstration

-22, 2-7, 4-7,

2, B-6, C-3,

. ES-7, ES-8,

24, 2-7, 4-2, 4-3,

5-36, 5-42,

B-6, C-3, C-4,

mpany B-3

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project ES-9, ES-12, ES-22, 2-7, 4-7,

5-6, 5-15, 5-17, 5-78, B-2, B-5, C-3, C-7,C-9, D-4

TTallahassee, City of B-2, B-3, B-4, B-6TAMCO Power Partners B-4, B-5Tampa Electric Company ES-1, ES-16,

ES-23, ES-24, 2-8, 4-10, 4-13, 5-16, 5-18,5-120, B-3, C-5, C-8, C-9

Tampa Electric Integrated Gasification CombinedCycle Project ES-1, ES-16, ES-23, ES-24,

2-8, 4-8, 4-10, 4-13, 5-9, 5-16, 5-18,5-120, B-3, C-5, C-8, C-9, D-6

Tennessee Valley Authority B-4, B-5ThermoChem, Inc. ES-23, 2-8, 5-12, 5-16,

5-18, 5-150, B-4, B-6, C-8, D-8

Tidd PFBC Demonstration Project ES-1,

ES-15, ES-16, ES-23, ES-24, 2-7, 4-10,4-13, 5-9, 5-16, 5-18, 5-106, B-1, B-5,C-3, C-7, C-9, D-5

Toms Creek IGCC Demonstration Project B-4, B-5TransAlta Resources Investment Corporation B-3Tri-State Generation and Transmission

Association ES-15, ES-16, ES-23, 2-7,3-8, 4-6, 4-10, 5-16, 5-18, 5-110, B-4,C-3, C-7, D-5

TRW, Inc. B-2, B-3UUnderground Coal Gasification Demonstration

Project B-2

Union Carbide Chemicals and Plastics Company

Inc. B-4

United Coal Company B-2

WWabash River Coal Gasification Repowering Joint

Venture ES-16, ES-23, ES-24, 2-8, 4-10,4-13, 5-16, 5-18, 5-122, B-4, C-8, C-9, D-6

Wabash River Coal Gasification Repowering

Project ES-16, ES-23, ES-24, 2-8, 4-8,4-10, 4-13, 5-9, 5-16, 5-18, 5-122, B-4,C-4, C-8, C-9, D-6

Warren Station Externally Fired Combined-Cycle

Demonstration B-4, B-5, C-4

Weirton Steel Corporation B-2Western Energy Company B-2, B-3Western SynCoal LLC ES-18, ES-23, 2-7, 4-9,

4-12, 5-10, 5-11, 5-16, 5-18, 5-136, B-2,B-3, C-4, C-7, D-7

YYork County Energy Partners Cogeneration

Project B-4, B-6

York County Energy Partners, L.P. B-4