Volume 2Clean Coal Technology PCompleted Projects 2003Includes Completed Clean Coal TechnologyDemonstration Program ProjectsAs of May 2003

U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

December 2003
U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

Volume 2Clean Coal Technology PCompleted Projects 2003Includes Completed Clean Coal TechnologyDemonstration Program ProjectsAs of May 2003

December 2003
This report has been reproduced directly from the best available copy.

Available to DOE and DOE contractors from the Office of Scientific and Technical InformatioP.O. Box 62, Oak Ridge, Tennessee 37831; prices available from (615) 576-8401. http://wwwAvailable to the public from the National Technical Information Service, U.S. Department of C5285 Port Royal Rd., Springfield, Virginia 22161. http://www.ntis.govAvailable to the public from the National Energy Technology Laboratory’s Clean Coal Technohttp://www.lanl.gov/projects/cctc/index.html

For further information about this publication or related U.S. DOE programs p

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

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

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

Background 1Accomplishments 2Summary of Results 3Project Fact Sheets 3Environmental Control Devices 11

SO2 Control Technologies 11NO

x Control Technologies 33

Multi-Pollutant Control Technologies 63

Advanced Electric Power Generation 89

Fluidized-Bed Combustion 89Integrated Gasification Combined-Cycle 99Advanced Combustion/Heat Engines 113

Coal Processing for Clean Fuels 119Industrial Applications 133Appendix A. Acronyms, Abbreviations, and Symbols A-1Index of Projects and Participants

CCTDP Completed ProjectsAppendicesIndex
ii Completed Projects 2003

Exhibits

Exhibit 1, Completed CCTDP SO2 Control Technology Projects 4

Exhibit 2, Completed CCTDP NOx Control Technology Projects 4Exhibit 3, Completed CCTDP Multi-Pollutant Control Technology Projects 5Exhibit 4, Completed CCTDP Advanced Electric Power Generation Technology PExhibit 5, Completed CCTDP Coal Processing for Clean Fuels Technology ProjecExhibit 6, Completed CCTDP Industrial Applications Technology Projects 6Exhibit 7, Completed CCTDP Project Fact Sheets by Application Category 7Exhibit 8, Completed CCTDP Project Fact Sheets by Participant 9Exhibit 9, Key to Milestone Charts in Project Fact Sheets 10Exhibit 10, Variables and Levels Used in GSA Factorial Testing 14Exhibit 11, GSA Factorial Testing Results 14Exhibit 12, Cost Comparison of GSA and WLFO 15Exhibit 13, Pure Air SO2 Removal Performance 26

Exhibit 14, Estimated Costs for an AFGD System 27Exhibit 15, Flue Gas Desulfurization Economics 27Exhibit 16, Operation of CT-121 Scrubber 30Exhibit 17, SO2 Removal Efficiency 30

Exhibit 18, CT-121 Particulate Capture Performance 31Exhibit 19, CT-121 Air Toxics Removal 31Exhibit 20, LOI Performance Test Results 36Exhibit 21, NOx vs. LOI Tests—All Sensitivities 36Exhibit 22, Typical Trade-Offs in Boiler Optimization 36

Exhibit 23, Major Elements of Optimization System 37

Exhibit 24, Coal Reburning Test Results 40Exhibit 25, Coal Reburning Economics 41Exhibit 26, NOx Data from Cherokee Station, Unit No. 3 48

Introduction

CCTDP Completed Projects
Exhibit 27, Reactor Baseline Conditions 56

Exhibit 28, Catalysts Tested 56Exhibit 29, Average SO2 Oxidation Rate 56Exhibit 30, SCR Design Criteria for Economic Evaluation 57Exhibit 31, SCR Economics by Unit Size 57Exhibit 32, SCR Economics by NOx Removal 57Exhibit 33, LNCFSTM Configurations 60Exhibit 34, Concentric Firing Concept 60Exhibit 35, Unit Performance Impacts Based on Long-Term Testing 61Exhibit 36, Average Annual NOx Emissions and Percent Reduction 61

Exhibit 37, LIMB SO2 Removal Efficiencies 70

Exhibit 38, LIMB Capital Cost Comparison 71Exhibit 39, LIMB Annual Levelized Cost Comparison 71Exhibit 40, Effect of Limestone Grind 82Exhibit 41, Boiler Load Parametric Testing of LNB/OFA System 86Exhibit 42, CO Emissions During Parametric Testing 86Exhibit 43, Effect of Bed Temperature on Ca/S Requirement 96Exhibit 44, Calcium Requirements and Sulfur Retentions for Various Fuels 97Exhibit 45, Wabash Thermal Performance Summary 110Exhibit 46, Wabash River Coal Gasification Repowering Project Production StatExhibit 47, Healy Performance Goals and Demonstration Test Program Results Exhibit 48, Healy SDA Performance Test Results and Performance Guarantees Exhibit 49, ENCOAL Production 130Exhibit 50, Summary of Emissions and Removal Efficiencies 144Exhibit 51, Schematic of ThermoChem’s Pulse Combustor Operation 148Exhibit 52, Schematic of ThermoChem’s Process Development Unit 149
iv Completed Projects 2003

Project Fact Sheets by Application Category

SO2 Control Technologies10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) 12Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corp

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC-North AAdvanced Flue Gas Desulfurization Demonstration Project (Pure Air on the LakeDemonstration of Innovative Applications of Technology for the CT-121 FGD Pro(Southern Company Services, Inc.) 28NO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler(Southern Company Services, Inc.) 34Demonstration of Coal Reburning for Cyclone Boiler NOx Control (The Babcock Full-Scale Demonstration of Low-NO

x Cell Burner Retrofit (The Babcock & Wilc

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

(Energy and Environmental Research Corporation) 46Micronized Coal Reburning Demonstration for NOx Control (New York State EleDemonstration of Selective Catalytic Reduction Technology for the Control of NO

Sulfur, Coal-Fired Boilers (Southern Company Services, Inc.) 54180-MWe Demonstration of Advanced Tangentially Fired Combustion TechniqueNO

x Emissions from Coal-Fired Boilers (Southern Company Services, Inc.) 58

Multi-Pollutant Control TechnologiesSNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental SystemLIMB Demonstration Project Extension and Coolside Demonstration (The BabcoSOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project (The Babcock & Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Research Corporation) 76Milliken Clean Coal Technology Demonstration Project (New York State Electric Integrated Dry NOx/SO2 Emissions Control System (Public Service Company of C

Environmental Control Devices
Fluidized-Bed CombustionTidd PFBC Demonstration Project (The Ohio Power Company) 90Nucla CFB Demonstration Project (Tri-State Generation and Transmission AssoIntegrated Gasification Combined-CyclePiñon Pine IGCC Power Project (Sierra Pacific Power Company) 100Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa ElectriWabash River Coal Gasification Repowering Project (Wabash River Coal GasifiProject Joint Venture) 108Advanced Combustion/Heat EnginesHealy Clean Coal Project (Alaska Industrial Development and Export AuthorityCommercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOHTM) PLiquid Phase Conversion Company, L.P.) 120Development of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc.ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) 128

Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) 142Pulse Combustor Design Qualification Test (ThermoChem, Inc.) 146

Advanced Electric Power GenerationCoal Processing for Clean FuelsIndustrial Applications
vi Completed Projects 2003

ABB Combustion Engineering, Inc., and CQ Inc. (Development of the Coal Quality ExpertTM) 124ABB Environmental Systems (SNOXTM Flue Gas Cleaning Demonstration Project) 64Air Products Liquid Phase Conversion Company, L.P. (Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) ProceAirPol, Inc. (10-MWe Demonstration of Gas Suspension Absorption) 12Alaska Industrial Development and Export Authority (Healy Clean Coal Project) 114Babcock & Wilcox Company, The (Demonstration of Coal Reburning for Cyclone Boiler NOx Control) 38Babcock & Wilcox Company, The (Full-Scale Demonstration of Low-NOx Cell Burner Retrofit) 42

Babcock & Wilcox Company, The (LIMB Demonstration Project Extension and Coolside Demonstration) 68Babcock & Wilcox Company, The (SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project) 72Bechtel Corporation (Confined Zone Dispersion Flue Gas Desulfurization Demonstration) 16Bethlehem Steel Corporation (Blast Furnace Granular-Coal Injection System Demonstration Project) 134Coal Tech Corporation (Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control) 138CQ Inc. (see ABB Combustion Engineering and CQ Inc.)ENCOAL Corporation (ENCOAL® Mild Coal Gasification Project) 128

Energy and Environmental Research Corporation (Enhancing the Use of Coals by Gas Reburning and Sorbent Injection) 76

Energy and Environmental Research Corporation (Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler) 46

LIFAC-North America (LIFAC Sorbent Injection Desulfurization Demonstration Project) 20New York State Electric & Gas Corporation (Micronized Coal Reburning Demonstration for NOx Control) 50

New York State Electric & Gas Corporation (Milliken Clean Coal Technology Demonstration Project) 80Ohio Power Company, The (Tidd PFBC Demonstration Project) 90Passamaquoddy Tribe (Cement Kiln Flue Gas Recovery Scrubber) 142Public Service Company of Colorado (Integrated Dry NOx/SO2 Emissions Control System) 84

Pure Air on the Lake, L.P. (Advanced Flue Gas Desulfurization Demonstration Project) 24Sierra Pacific Power Company (Piñon Pine IGCC Power Project) 100Southern Company Services, Inc. (Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler) 34Southern Company Services, Inc. (Demonstration of Innovative Applications of Technology for the CT-121 FGD Process) 28

Project Fact Sheets by Participant
Southern Company Services, Inc. (Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions from High

Coal-Fired Boilers) 54Southern Company Services, Inc. (180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of 

from Coal-Fired Boilers) 58Tampa Electric Company (Tampa Electric Integrated Gasification Combined-Cycle Project) 104ThermoChem, Inc. (Pulse Combustor Design Qualification Test) 146Tri-State Generation and Transmission Association, Inc. (Nucla CFB Demonstration Project) 94Wabash River Coal Gasification Repowering Project Joint Venture (Wabash River Coal Gasification Repowering Project) 108
viii Completed Projects 2003
This document provides a summary of projects completed under the U.S. Department of Energy’s (DOE)Clean Coal Technology Demonstration Program(CCTDP). These summaries are embodied in projectfact sheets that provide: (1) information on the participants; (2) project and technology descriptions; (3) keyfindings and sufficient project discussion to establish acontext for the findings; and (4) contacts and a bibliography to link readers to more in-depth information.The project fact sheets are organized and presented bymarket sector: (1) environmental control devices forexisting and new power plants; (2) advanced electricpower generation for repowering existing facilities andproviding new generation capacity; (3) coal processingfor clean fuels to convert the nation’s vast coal resources to clean fuels; and (4) industrial applicationsdependent upon coal use.This compendium of project fact sheets represents animportant technical reference for researchers and potential users of the technologies in each of the fourmarket areas. Of the 36 active or completed CCTDPprojects, 31 projects are covered in this document.Continued coverage of the five active CCTDP projects,along with Power Plant Improvement Initiative andClean Coal Power Initiative projects, is provided in theProgram Update 2003 Volume 1. Also presented hereis a brief background on the CCTDP, a summary ofaccomplishments attributable to the completedprojects, and summary of results tables for the completed projects.CCTDP Completed Projects

BackgroundThe CCTDP began in Fiscal Year 1985. Program implementation (solicitation, selection, and award) wasthrough five competitive solicitations and spanned anine-year period. Early solicitations in 1986 and 1988(CCTDP- I and CCTDP- II) stressed SO2 and NOx control in response to acid rain concerns. The CCTDP- IIIsolicitation in 1989 continued to stress acid rain controls, but also encouraged process technologies thatwould produce clean fuels from run-of-mine coal. Thenext two solicitations (CCTDP- IV and CCTDP-V)issued in 1991 and 1992, respectively, recognized theneed for highly efficient power generation systems andenvironmental controls to address global climate changeconcerns and SO2 cap impacts on capacity additions. Asa result of these solicitations, a total of 60 projects wereselected, of which 36, valued at more than $4.8 billion,either have been successfully completed (documentedhere) or remain active (documented in Program Update2003 Volume 1).Founding principles forged at program inception havemade the CCTDP one of the most successful costshared government/industry demonstration programsever implemented. These principles provide checksand balances to ensure that the industry and government roles are appropriate and that the governmentserves as a risk-sharing partner without impeding industry in moving the technology into the marketplace.Recognizing the success of the CCTDP, Congress hasadopted these principles in implementing legislationfor the Power Plant Improvement Initiative and CleanCoal Power Initiative. Following is a summary of theprinciples:

• A strong and stable 

the life of the projegovernment’s share priated by Congress This up-front commindustry’s response of proposals receivepercent cost-sharing 

• Multiple solicitation

years enabled the prange of national ning technologies. Ations enabled Congrprogram to meet chaDOE time to revise based on lessons leaprovided industry thprojects and more ctechnologies.

• Demonstrations are 

scale in actual user technology is constrfull system integratiomercial configuratiofacility or installed oThis enables the techto be judged in the inment.

• The technical agend

not the governmentCongress and policy definitive performanbased evaluation criwould be judged. Inuse its expertise and ogy and proposed ptives and criteria. Ththe projects that best 
2 Completed Projects 2003

• Roles of the government and industry are clearly

defined and reflect the degree of cost-sharingrequired. The government plays a significant roleup front in structuring the cooperative agreementsto protect public interests. This includes negotiating definitive performance milestones and decisionpoints throughout the project. Once the projectbegins, the industrial participant is responsible fortechnical management, while the government oversees the project through aggressive monitoring andbecomes involved in implementation only at decision points. Continued government support isassured as long as project milestones and the termsand conditions of the original cooperative agreement continue to be met.

• At least 50 percent cost-sharing by industry is

required throughout all project phases.Industry’s cost-share was required to be tangible anddirectly related to the project, with no credit forprevious work. By sharing essentially in each dollarexpended along the way, on at least an equal basis,industry’s commitment to fulfilling project objectives was strengthened.

• Allowance for cost growth provides an important

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

• Industry retains real and intellectual property

rights. The level of cost-sharing warrants theindustrial participant retaining intellectual and realproperty rights and removes potential constraints to

commercialization. Industries would otherwise bereluctant to come forward with technologies developed to the point of demonstration, relinquishingtheir competitive position.

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

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

• Upon successful commercialization of the technology, repayment up to the government’s

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

AccomplishmentsThe CCTDP SO2 control projects (all of which arepresented here) provided technologies that essentiallyremoved SO2 control as a technical issue for all mannerof existing plants. Advanced wet flue gas desulfurization projects demonstrated in the CCTDP redefined thestate-of-the-art for sorbent-based scrubbers. Theseadvanced scrubbers nearly halved capital and operatingcosts, increased SO2 removal to 95 percent or more,produced salable by-products instead of wastes, andreduced plant efficiency losses through high-captureefficiency devices. A portfolio of relatively low-capital-cost sorbent injection technologies demonstratedSO2 removal up to 90 percent for older, smaller, spaceconstrained plants.

The CCTDP NOx controsented here) combined to major boiler types that etively comply with 1996 under the Clean Air Act Aof the projects provided to the ongoing regulatorprojects succeeded in coproducing commercially 

all major boiler types excyclone boilers, which wmodification or replacemNOx control technologie

to these combustion modincluded demonstration (SCR) and selective nonpost-combustion technolcomplement combustion reduction. Together, thetechnical foundation for sions in the 21st century.

The multi-pollutant (com

projects (all of which are those technologies that ccontrol methods and thotechniques. Three of the burners or gas reburning other project combined l

enhance performance alowet scrubber. The balanother synergistic methodMost of the advanced eleunder the CCTDP have bsented in this document htions to improving the eneconomic performance okey utility-sponsored demconsortium of power genResearch Institute (EPRIdation and impetus for raputility-scale atmospheric 
bustion technology. In another project, a major utilitysuccessfully undertook a four-year campaign to transform pressurized fluidized-bed combustion technologyinto a viable commercial design. Two integratedgasification combined-cycle (IGCC) projects documented here represent pioneering efforts to bring nextgeneration power systems into mainstream commercialmarkets. All of the advanced electric power generationprojects but three are presented in this document.The completed coal processing for clean fuels projectsunder the CCTDP have demonstrated: (1) the feasibility of producing clean high-energy-density solid andliquid fuels from low-rank coals; (2) the cost-effectiveco-production of methanol in association with an IGCCplant; and (3) computer-based programs for assessingimpacts of various coals and coal blends on plant operations. All of the coal processing projects but oneare presented in this document.One of the major accomplishments coming out of theindustrial application sector of the CCTDP was successful demonstration of a process that enabled displacementof a significant amount of coke with coal in steel production. Other projects contributed to furthering coal use inthe industrial sector. All of the industrial projects butone are presented in this document.Summary of ResultsFollowing is a series of exhibits highlighting key resultsand providing capital costs for the completed projects.Separate tables are provided for environmental controltechnologies, advanced electric power generationprojects, coal processing for clean fuels technologies,and industrial applications projects.

Project Fact SheetsThe Project Fact Sheets follow the Summary of Resultstables. The order of presentation is as follows:• Environmental Control Devices

- SO2 Control Technology- NO

x Control Technology

- Multi-Pollutant Control Technology

• Advanced Electric Power Generation

- Fluidized-Bed Combustion

- Integrated Gasification Combined-Cycle- Advanced Combustion/Heat Engines

• Coal Processing for Clean Fuels• Industrial ApplicationsTo prevent the release of project-specific information of aproprietary nature, process flow diagrams contained in theproject fact sheets are highly simplified and presentedonly as illustrations of the concepts involved in the demonstrations. The portion of the process or system centralto the demonstration is demarcated by a shaded area.
4 Completed Projects 2003

Exhibit 1

Completed CCTDP SO2 Control Technology Projects

Coal Sulfur SO

Project Process Content Re10-MWe Demonstration of Gas Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.6–3.5% 60

Absorption particulate recycle (lime sorbent)Confined Zone Dispersion Flue Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.2–2.5% 50

Desulfurization DemonstrationLIFAC Sorbent Injection Desulfurization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.8% 70

Demonstration Project humidification vessel and sorbent recycleAdvanced Flue Gas Desulfurization AFGD—cocurrent flow, integrated quench absorber tower, and reaction 2.25–4.5% 94

Demonstration Project tank with combined agitation/oxidation (gypsum by-product)Demonstration of Innovative Applications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2–4.3% 90

of Technology for the CT-121 FGD Process Reactor®) for combined SO2 and particulate capture (gypsum by-product)

Exhibit 2

Completed CCTDP NOx Control Technology Projects

Boiler Size/ 

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

x

 Control

Full-Scale Demonstration of Low-NO

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

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

on a Wall-Fired BoilerMicronized Coal Reburning Demonstration Coal reburning—14% heat input (tangentially fired) and 148 MWe/tangential for NO

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

Demonstration of Selective Catalytic Reduction SCR—eight catalysts with different shapes and 8.7 MWe/tangential Technology for the Control of NOx Emissions chemical compositions (slip stream)

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

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

Emissions from Coal-Fired Boilers
Exhibit 3

Completed CCTDP Multi-Pollutant Control Technology Projects

Project Process % Sulfur SNOXTM Flue Gas Cleaning Demonstration SCR/oxidation catalyst/sulfuric acid condenser—synergistic 2.8% Project catalyst effect and no solid wasteLIMB Demonstration Project Extension and LNB/sorbent injection—furnace and duct injection, calcium-based 1.6–3.8% 

Coolside Demonstration sorbents (LIMB) and calcium/sodium based sorbents (Coolside)SOx-NOx-Rox BoxTM Flue Gas Cleanup SCR/high-temperature baghouse/sorbent injection—SCR in high- 3.7% Demonstration Project temperature filter bag and calcium- and sodium-based sorbent injectionEnhancing the Use of Coals by Gas Reburning Gas reburning/sorbent injection (GR-SI)—calcium-based sorbents 3.0% and Sorbent Injection used in duct injectionMilliken Clean Coal Technology Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5–4.0% 

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

Control System sorbents used in duct injection

Exhibit 4

Completed CCTDP Advanced Electric Power Generation Technology 

Project Process Size Fluidized-Bed CombustionTidd PFBC Demonstration Project Pressurized bubbling fluidized-bed combustion 70 MWe Nucla CFB Demonstration Project Atmospheric circulating fluidized-bed combustion 110 MWe (gross)Integrated Gasification Combined CyclePiñon Pine IGCC Power Project Air-blown, fluidized-bed gasifier with hot gas cleanup 107 MWe (gross)Tampa Electric Integrated Gasification Combined- Oxygen-blown, entrained-flow gasifier with hot and cold gas cleanup 315 MWe (gross)Cycle ProjectWabash River Coal Gasification Repowering Project Oxygen-blown, two-stage entrained-flow gasifier with cold gas cleanup 296 MWe (gross)Advanced Combustion/Heat EnginesHealy Clean Coal Project Advanced slagging combustor, spray dryer with sorbent recycle 50 MWe (nomina
6 Completed Projects 2003

Exhibit 5

Completed CCTDP Coal Processing for Clean Fuels Technology Proje

Project Process Size Commercial-Scale Demonstration of the Liquid Phase Methanol Liquid phase process for methanol production from 80,000 gal/day (LPMEOHTM) Process coal-derived syngasDevelopment of the Coal Quality ExpertTM Coal Quality ExpertTM computer software Tested at 250–880 ENCOAL® Mild Coal Gasification Project Liquids-from-coal (LFC®) mild gasification to 1,000 tons/day* 

produce solid and liquid fuels

*Operated at 500 ton

Exhibit 6

Completed CCTDP Industrial Applications Technology Projects

Project Process Size Blast Furnace Granular-Coal Injection System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of hDemonstration Project metal/furnaceAdvanced Cyclone Combustor with Internal Advanced slagging combustor with staged combustion and sorbent 23x106 Btu/hr 

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

and fertilizer and distilled water produced

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

Conversion International’s pulse combustor/gasifier
Environmental Control DevicesSO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCTDPConfined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCTDPLIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCTDPAdvanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCTDPDemonstration of Innovative Applications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCTDP

NO

x Control Technologies

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCTDPDemonstration of Coal Reburning for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCTDP

Full-Scale Demonstration of Low-NO

x Cell Burner Retrofit The Babcock & Wilcox Company CCTDP

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

Micronized Coal Reburning Demonstration for NOx Control New York State Electric & Gas Corporation CCTDP

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCTDPfor the Control of NO

x Emissions from High-Sulfur, Coal-Fired Boilers

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

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCTDPLIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCTDPSOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCTDPEnhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCTDP

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCTDPIntegrated Dry NOx/SO2 Emissions Control System Public Service Company of Colorado CCTDP

Exhibit 7

Completed CCTDP Project Fact Sheets by Application Category

Project Participant Solicita
8 Completed Projects 2003

Exhibit 7 (continued)

Completed CCTDP Project Fact Sheets by Application Category

Project Participant SolicitatAdvanced Electric Power GenerationFluidized-Bed CombustionTidd PFBC Demonstration Project The Ohio Power Company CCTDP-I/coNucla CFB Demonstration Project Tri-State Generation and Transmission CCTDP-I/co

Association, Inc.

Integrated Gasification Combined-CyclePiñon Pine IGCC Power Project Sierra Pacific Power Company CCTDP-IV/Tampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCTDP-III/Wabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering CCTDPIV/c

Project Joint Venture

Advanced Combustion/Heat EnginesHealy Clean Coal Project Alaska Industrial Development and CCTDP-III/

Export Authority

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

Conversion Company, L.P.

Development of the Coal Quality ExpertTM ABB Combustion Engineering, Inc. CCTDP-I/co

and CQ Inc.

ENCOAL® Mild Coal Gasification Project ENCOAL Corporation CCTDP-III/

Industrial ApplicationsBlast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCTDP-III/Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCTDP-I/coCement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCTDP-II/cPulse Combustor Design Qualification Test ThermoChem, Inc. CCTDP-IV/
ABB Combustion Engineering, Inc. and CQ Inc. Development of the Coal Quality ExpertTM HomABB Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project NilesAir Products Liquid Phase Conversion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) King

Process

AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption West Alaska Industrial Development and Export Authority Healy Clean Coal Project HealyBabcock & Wilcox Company, The Demonstration of Coal Reburning for Cyclone Boiler NOx Control Cassv

Babcock & Wilcox Company, The Full-Scale Demonstration of Low-NOx Cell Burner Retrofit Aber

Babcock & Wilcox Company, The LIMB Demonstration Project Extension and Coolside Demonstration LoraiBabcock & Wilcox Company, The SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project DilleBechtel Corporation Confined Zone Dispersion Flue Gas Desulfurization Demonstration SewaBethlehem Steel Corporation Blast Furnace Granular-Coal Injection System Demonstration Project BurnCoal Tech Corporation Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control WilliCQ Inc. (see ABB Combustion Engineering and CQ Inc.)ENCOAL Corporation ENCOAL® Mild Coal Gasification Project Gille

Energy and Environmental Research Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Henn

Sprin

Energy and Environmental Research Corporation Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler DenvLIFAC–North America LIFAC Sorbent Injection Desulfurization Demonstration Project RichmNew York State Electric & Gas Corporation Micronized Coal Reburning Demonstration for NOx Control Lansi

Roch

New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project LansiOhio Power Company, The Tidd PFBC Demonstration Project BrilliPassamaquoddy Tribe Cement Kiln Flue Gas Recovery Scrubber ThomPublic Service Company of Colorado Integrated Dry NOx/SO2 Emissions Control System Nucla

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project ChesSierra Pacific Power Company Piñon Pine IGCC Power Project RenoSouthern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coos

Exhibit 8

Completed CCTDP Project Fact Sheets by Participant

Participant Project Loca
10 Completed Projects 2003

Exhibit 8 (continued)

Completed CCTDP Project Fact Sheets by Participant

Participant Project Locat

Exhibit 9

Key to Milestone Charts in Project Fact Sheets

Each fact sheet contains a bar chart that highlights major milestones—past and planned. The bar chart shows a project’s duration and indicates the time perof project activities—preaward, design and construction, and operation and reporting. The key provided below explains what is included in each of these c

PreawardIncludes preaward briefings, negotiations, and other activities conducted during the period between DOE’s selection of the project and award of thDesign and ConstructionIncludes the NEPA process, permitting, design, procurement, construction, preoperational testing, and other activities conducted prior to the beginndemonstration.MTF Memo-to-fileCX Categorical exclusionEA Environmental assessmentEIS Environmental impact statementOperation and ReportingBegins with startup and includes operational testing, data collection, analysis, evaluation, reporting, and other activities to complete the demonstra

Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newna

Process

Southern Company Services, Inc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensac

NO

x Emissions from High-Sulfur, Coal-Fired Boilers

Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Combustion Lynn H

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

Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project MulberThermoChem, Inc. Pulse Combustor Design Qualification Test BaltimTri-State Generation and Transmission Association, Inc. Nucla CFB Demonstration Project Nucla, Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project West TProject Joint Venture
Environmental Control Devi

SO

2 Control Technologies
12 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesSO2 Control Technologies10-MWe Demonstration ofGas Suspension AbsorptionProject completedParticipantAirPol, Inc.Additional Team MembersFLS miljo, Inc. (FLS)—technology ownerTennessee Valley Authority—cofunder and site ownerLocationWest Paducah, McCracken County, KYTechnologyFLS’ Gas Suspension Absorption (GSA) system for fluegas desulfurization (FGD)Plant Capacity/Production10-MWe equivalent slipstream of flue gas from a175-MWe wall-fired boilerCoalWestern Kentucky bituminous: Peabody Martwick, 3.05%sulfur; Emerald Energy, 2.61% sulfur; Andalax, 3.06%sulfur; and Warrior Basin, 3.5% sulfur (used intermittently)Project FundingTotal $7,717,189 100%DOE 2,315,259 30Participant 5,401,930 70Project ObjectiveTo demonstrate the applicability of Gas Suspension Absorption as an economic option for achieving Phase IICAAA SO2 compliance in pulverized coal-fired boilers

using high-sulfur coal.

Technology/Project DescriptionThe GSA system consists of a vertical reactor in whichflue gas comes into contact with suspended solids consisting of lime, reaction products, and fly ash. About 99%of the solids are recycled to the reactor via a cyclonewhile the exit gas stream passes through an electrostaticprecipitator (ESP) or pulse jet baghouse (PJBH) beforebeing released to the atmosphere. The lime slurry, prepared from hydrated lime, is injected through a spraynozzle at the bottom of the reactor. The volume of limeslurry is regulated with a variable-speed pump controlledby the measurement of the acid content in the inlet andoutlet gas streams. The dilution water added to the limeslurry is controlled by on-line measurements of the fluegas exit temperature.

A test program was structhe GSA reactor for reduc

boilers using high-sulfur ronmental control capabilmechanical performance parametric (factorial) test six variables. Beyond evacontrol SO2, air toxics con

the effectiveness of GSA/tions to control both SO2 

Factorial tests were followconsistency of performan
Calendar Year

 3 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 

Results SummaryEnvironmental• Ca/S molar ratio had the greatest effect on SO2 removal, with approach-to-saturation temperature next,

followed closely by chloride content.

• GSA/ESP achieved

– 90% sulfur capture at a Ca/S molar ratio of 1.3

with 8 oF approach-to-saturation and 0.02–0.04%chloride,

– 90% sulfur capture at a Ca/S molar ratio of 1.4

with 18 oF approach-to-saturation and 0.12%chloride, and

– 99.9+% average particulate removal efficiency.

• GSA/PJBH achieved

– 96% sulfur capture at a Ca/S molar ratio of 1.4

with 18 oF approach-to-saturation and 0.12%chloride,

– 3–5% increase in SO2 reduction relative to GSA/

ESP, and

– 99.99+% average particulate removal efficiency.

• GSA/ESP and GSA/PJBH removed 98% of the hydrogen chloride (HCl), 96% of the hydrogen fluoride

(HF), and 99% or more of most trace metals, exceptcadmium, antimony, mercury, and selenium. (GSA/PJBH removed 99+% of the selenium.)

• The solid by-product was usable as low-grade cement.Operational• GSA/ESP lime utilization averaged 66.1% and GSA/

PJBH averaged 70.5%.

• The reactor achieved the same performance as a conventional spray dryer, but at one-quarter to one-third

the size.

• GSA generated lower particulate loading than a conventional spray dryer, enabling compliance with a

lower ESP efficiency.

• Special steels were not required in construction, and

only a single spray nozzle is needed.

• High availability and reliability similar to other commercial applications were demonstrated.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

Ground breaking/construction started 5/92

Preaward

12/89 10/90 10/92

Design and Construction

DOE selected project

(CCTDP-III) 12/19/89 Environmental monitoring plan completed

10/2/92Operation initiated 10/92

Design completed 12/91

Cooperative agreement awarded 10/11/90

NEPA process completed (MTF) 9/21/90

Preoperational tests initiated 9/92Construction completed 9/92

6/95

Project completed/final rep

Operation completed 3/94

Economic• The capital cost for 

(1990 constant dolla$126/kW without a MWe plant using 2.

• Levelized costs over 

at 10.91 mills/kWh (spare module and 6.module.
14 Completed Projects 2003

Exhibit 10

Variables and Levels Used in GSA

Factorial Testing

Variable LevelApproach-to-saturation temperature (°F) 8*, 18, and 28Ca/S (moles Ca(OH)2/mole inlet SO2) 1.00 and 1.30

Fly ash loading (gr/ft3, actual) 0.50 and 2.0

Coal chloride level (%) 0.04 and 0.12Flue gas flow rate (103 scfm) 14 and 20

Recycle screw speed (rpm) 30 and 45

*8 °F was only run at the low coal chloride level.

Exhibit 11

GSA Factorial Testing Results

Project SummaryThe GSA has a capability of suspending a high concentration of solids, effectively drying the solids, and recirculating the solids at a high rate with precise control. Thisresults in SO2 control comparable to that of wet scrubbers

and high lime utilization. The high concentration of solidsprovides the sorbent/SO2 contact area. The drying enables

low approach-to-saturation temperature and chloride usage. The rapid, precise, integral recycle system sustainsthe high solids concentration. The high lime utilizationmitigates the largest operating cost (lime) and furtherreduces costs by reducing the amount of by-product generated. The GSA is distinguished from the average spraydryer by its modest size, simple means of introducingreagent to the reactor, direct means of recirculating unused lime, and low reagent consumption. Also, injectedslurry coats recycled solids, not the walls, avoiding corrosion and enabling use of carbon steel in fabrication.Environmental PerformanceExhibit 10 lists the six variables used in the factorial testsand the levels at which they were applied. Inlet flue gastemperature was held constant at 320 oF. Factorial testingshowed that lime stoichiometry had the greatest effect onSO2 removal. Approach-to-saturation temperature was the

next most important factor, followed closely by chloridelevels. Although an approach-to-saturation temperature of8 oF was achieved without plugging the system, the testwas conducted at a very low chloride level (0.04%). Because water evaporation rates decrease as chloride levelsincrease, an 18 oF approach-to-saturation temperaturewas chosen for the higher 0.12% coal chloride level.Exhibit 11 summarizes key results from factorial testing.A 28-day continuous run to evaluate the GSA/ESP configuration was made with bituminous coals averaging2.7% sulfur, 0.12% chloride levels, and 18 oF approachto-saturation temperature. A subsequent 14-day continuous run to evaluate the GSA/PJBH configuration wasperformed under the same conditions as those of the 28-day run, except for adjustments in fly ash injection ratefrom 1.5–1.0 gr/ft3 (actual).

The 28-day run on the GSA/ESP system showed that theoverall SO2 removal efficiency averaged slightly more than

90%, very close to the set point of 91%, at an average Ca/Smolar ratio of 1.40–1.45 (moles Ca(OH)2/mole inlet SO2).

The system was able to adjust rapidly to the surge in inletSO2 caused by switching to 3.5% sulfur Warrior Basin coal

for a week. Lime utilization averaged 66.1%. The particulate removal efficiency averaged 99.9+% and emissionrates were maintained below 0.015 lb/106 Btu. The 14-day

run on the GSA/PJBH sys

efficiency averaged more molar ratio of 1.34–1.43 (m

Lime utilization averaged efficiency averaged 99.99from 0.001–0.003 lb/106 B

All air toxics tests were cchloride coal with a 12 oF perature and a high fly as

The GSA/ESP arrangemeefficiencies of greater thamium, lead, and vanadiumnese; and less than 99% fand selenium. The GSA/P99+% removal efficienciemium, lead, manganese, scadmium removal much llower than that of the GSAHCl and HF was dependeslurry and was relatively trol configuration. Remov98% for HCl and 96% for Operational PerformaBecause the GSA system provide a contact area for 

pressure atomizer nozzles are not required to achievAlso, recycle of solids is terial in the feed slurry, wsive abrasion-resistant maThe high heat and mass trGSA enable the GSA systthan a conventional spray one-quarter to one-third thsible for space-confined pcost. The GSA system slusolids, not the reactor waland the need for corrosionmore, the high concentratscours the reactor walls ansystem generates a significonventional spray dryer, 

6–10 gr/ft3 for a spray dry

100

0.90 1.0 1.1 1.2 1.3 1.4

9080706050

Overall System SO2 Removal (%)

Note: All tests were conducted at a 320 oF inlet  flue gas temperature

Fresh Lime Stoichiometry (moles Ca/mole SO2)

8 oF Approach—0.04% Cl18 oF Approach—0.04% Cl18 oF Approach—0.12% Cl
particulate controls. The GSA system produces a solidby-product containing very low moisture. This materialcontains both fly ash and unreacted lime. With the addition of water, the by-product undergoes a pozzuolanicreaction, essentially providing the characteristics of alow-grade cement.Economic PerformanceUsing EPRI costing methods, which have been applied to30 to 35 other FGD processes, economics were estimatedfor a moderately difficult retrofit of a 300-MWe boilerburning 2.6% sulfur coal. The design SO2 removal efficiency was 90% at a lime feed rate equivalent to 1.30

moles of Ca per mole of inlet SO2. Lime was assumed to

be 2.8 times the cost of limestone. It was estimated thatthe capital cost was $149/kW (1990$) with three units at50% capacity, and the levelized cost (15-year constant1990$) was 10.35 mills/kWh with three units at 50%capacity. With no spare capacity, the capital cost wasestimated at $126/kW and the levelized cost was estimated at 6.8 mills/kWh.As shown in Exhibit 12, a cost comparison for a wetlimestone scrubber with forced oxidation (WLFO) scrubber showed the capital and levelized costs to be $216/kWand 13.04 mills/kWh, respectively. The capital cost listedin EPRI cost tables for a conventional spray dryer at 300MWe and 2.6% sulfur coal was $172/kW (1990$). Also,because the GSA requires less power and has better limeutilization than a spray dryer, the GSA will have a loweroperating cost.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.

ContactsNiels H. Kastrup, (281) 

F.L. Smith Airtech, I100 Glennborough DHouston, TX 77067-(281) 539-3411 (fax)nhk@flsairtech.com

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Sharon K. Marchant, NE

marchant@netl.doe.g

References10-MWe Demonstration Final Project Performanport No. DOE/PC/90542(Available from NTIS a10-MW Demonstration Final Public Design RepT10. AirPol, Inc. June 1DE960003270.)SO2 Removal Using Gas 

ogy. Topical Report No. and AirPol, Inc. April 1910-MWe Demonstration tion Process at TVA’s CeFinal Report. Report NoValley Authority. March DE96000327.)10-MWe Demonstration Project Performance Suergy. June 1999.

AirPol, Inc. successfully demonstrated the GSA system atTVA’s Center for Emissions Research, located at TVA’sShawnee Plant.

Capital Cost Levelized Cost

(1990 $/kW) (mills/kWh)

GSA—3 units at 149 10.3550% capacityWLFO 216 13.04

Exhibit 12

Cost Comparison of GSA and

WLFO
16 Completed Projects 2003

Confined Zone DispersionFlue Gas DesulfurizationDemonstrationProject completedParticipantBechtel CorporationAdditional Team MembersPennsylvania Electric Company—cofunder and hostPennsylvania Energy Development Authority—cofunderNew York State Electric & Gas Corporation—cofunderRockwell Lime Company—cofunderLocationSeward, Indiana County, PA (Pennsylvania ElectricCompany’s Seward Station, Unit No. 5)TechnologyBechtel Corporation’s in-duct, confined zone dispersionflue gas desulfurization (CZD/FGD) processPlant Capacity/Production73.5 MWe equivalent from a 147 MWe unitCoalPennsylvania bituminous, 1.2–2.5% sulfurProject FundingTotal* $10,411,600 100%DOE 5,205,800 50Participant 5,205,800 50Project ObjectiveTo demonstrate SO2 removal capabilities of in-duct

CZD/FGD technology; specifically, to define the optimum process operating parameters and to determineCZD/FGD’s operability, reliability, and cost-effectiveness

*Additional project overrun costs were funded 100% by the participant fora final total project funding of $12,173,000.

during long-term testing and its impact on downstreamoperations and emissions.Technology/Project DescriptionIn Bechtel’s CZD/FGD process, a finely atomized slurryof reactive lime is sprayed into the flue gas stream between the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the center of theduct by spray nozzles designed to produce a cone of finespray. As the spray moves downstream and expands, thegas within the cone cools and the SO2 is quickly absorbedon the liquid droplets. The droplets mix with the hot fluegas, and the water evaporates rapidly. Fast drying precludes wet particle buildup in the duct and aids the fluegas in carrying the dry reaction products and the unreacted lime to the ESP.

This project included injebents (dolomitic and calcdesigns using low- and hieffects on SO2 removal an

onstration was conducted Company’s Seward StatioOne-half of the flue gas cNo. 5 was routed through section of duct between th

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesSO2 Control Technologies
Calendar Year

 3 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 

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

Ground breaking/construction started 5/92

Preaward

12/89 10/90 10/92

Design and Construction

DOE selected project

(CCTDP-III) 12/19/89 Environmental monitoring plan completed

10/2/92Operation initiated 10/92

Design completed 12/91

Cooperative agreement awarded 10/11/90

NEPA process completed (MTF) 9/21/90

Preoperational tests initiated 9/92Construction completed 9/92

6/94

Project completed/final report issued 6/94

Operation completed 3/94

Results SummaryEnvironmental• Pressure-hydrated dolomitic lime proved to be a more

effective sorbent than either dry hydrated calcitic limeor freshly slaked calcitic lime.

• Sorbent injection rate was the most influential parameter on SO2 capture. Flue gas temperature was the

limiting factor on injection rate. For SO2 capture efficiency of 50% or more, a flue gas temperature of

300 oF or more was needed.

• Slurry concentration for a given sorbent did not increase SO2 removal efficiency beyond a certain threshold concentration.

• Testing indicated that SO2 removal efficiencies of 50%

or more were achievable with flue gas temperatures of300–310 oF (full load), sorbent injection rate of 52–57gal/min, residence time of 2 seconds, and a pressurehydrated dolomitic-lime concentration of about 9%.

• For operating conditions at Seward Station, data indicated that for 40–50% SO2 removal, a 6–8% lime or

dolomitic lime slurry concentration, and a stoichiometric ratio of 2–2.5 resulted in a 40–50% lime utilization rate. That is, 2–2.5 moles of CaO or CaO•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 effective CZD/ FGD operation. • At Seward Station, stack opacity was not detrimentally affected by CZD/FGD. • Availability of CZD/FGD was very good. • Some CZD/FGD modification will be necessary to assure consistent SO2 removal and avoid deposition of solids within the ductwork during upsets. Economic • Capital cost of a 500-MWe system operating on 4% sulfur coal and achieving 50% SO2 reduction was estimated at less than $30/kW and operating cost at $300/ton of SO2 removed (1994$).

 3 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 
18 Completed Projects 2003

Bechtel’s demonstration showed that 50% SO2 removal efficiency waspossible using CZD/FGD technology. The extended duct into which limeslurry was injected is in the foreground.

Project SummaryThe principle of the CZD/FGD is to form awet zone of slurry droplets in the middle of aduct confined in an envelope of hot gas between the wet zone and the duct walls. Thelime slurry reacts with part of the SO2 in the

gas and the reaction products dry to formsolid particles. An ESP, downstream from thepoint of injection, captures the reaction products along with the fly ash entrained in theflue gas.CZD/FGD did not require a special reactor,simply a modification to the ductwork. Use ofthe commercially available Type S pressurehydrated dolomitic lime reduced residencetime requirements for CZD/FGD and enhancedsorbent utilization. The increased humidity ofCZD/FGD processed flue gas enhanced ESPperformance, eliminating the need for upgradesto handle the increased particulate load.Bechtel began its 18-month, two-part test program for theCZD process in July 1991, with the first 12 months of thetest program consisting primarily of parametric testingand the last 6 months consisting of continuous operational testing. During the continuous operational testperiod, the system was operated under fully automaticcontrol by the host utility boiler operators. The new atomizing nozzles were thoroughly tested both outside andinside the duct prior to system testing.The SO2 removal parametric test program, which began in

October 1991, was completed in August 1992. Specificobjectives were as follows:• Achieve projected SO2 removal of 50%;

• Realize SO2 removal costs of less than $300/ton; and

• Eliminate negative effects on normal boiler operations

without increasing particulate emissions and opacity.

The parametric tests included duct injection of atomizedlime slurry made of dry hydrated calcitic lime, freshlyslaked calcitic lime, and pressure-hydrated dolomiticlime. All three reagents remove SO2 from the flue gas but

require different feed concentrations of lime slurry for thesame percentage of SO2 removed. The most efficient

removals and easiest operation were achieved using pressure-hydrated dolomitic lime.Environmental PerformanceSorbent injection rate proved to be the most influentialfactor on SO2 capture. The rate of injection possible was

limited by the flue gas temperature. This impacted a portion of the demonstration when air leakage caused flue gastemperature to drop from 300–310 oF to 260–280 oF. At300–310 oF, injection rates of 52–57 gal/min were possibleand SO2 reductions greater than 50% were achieved. At

260–280 oF, injection rates had to be dropped to 30–40 gal/min, resulting in a 15–30% drop in SO2 removal efficiency.

Slurry concentration for a given sorbent did not increaseSO2 removal efficiency beyond a certain threshold concentration. For example, with pressure-hydrated dolomitic

lime, slurry concentrations above 9% did not increase SO2

capture efficiency.Parametric tests indicated that SO2 removals above 50%

are possible under the following conditions: flue gas temperature of 300–310 oF; full boiler load of 145–147 MWe;residence time in the duct of 2 seconds; and lime slurryinjection rate of 52–57 gal/min.

Operational PerformaThe percentage of lime utnificantly affected the tot

analysis of the continuouthe percentage of lime ution two key factors: (1) pe

(2) lime slurry feed conceFor operating conditions that for 40–50% SO2 rem

lime slurry concentration2–2.5 resulted in a 40–502–2.5 moles of CaO or Camole of SO2 removed; or 

1.9–2.4 tons of lime were 

removed. In summary, the following results:• A 50% SO2 removal ef

possible.

• Drying and SO2 absorp

of 2 seconds, which rezontal gas duct of abou

• The fully automated sy

plant operation demoncess responded well to However, modificationquired to assure consis

deposition of solids w

• Availability of the syst• At Seward Station, sta

affected by the CZD/F

Economic PerformancEstimates show that the Ccosts of $300/ton of SO2 

ing a 500-MWe unit burn500-MWe plant retrofitted 

removal, the total capital $30/kW (1994$).Commercial ApplicatiAfter the conclusion of thdemonstration project at Ssystem was modified to im
CZD/FGD lime slurry injector control system.continuous operation while following daily load cycles.Bechtel and the host utility, Pennsylvania Electric Company, continued the CZD/FGD demonstration for an additional year. Results showed that CZD/FGD operation atSO2 removal rates lower than 50% could be sustained

over long periods without significant process problems.CZD/FGD can be used for retrofitting existing plants andinstallation in new utility boiler flue gas facilities to remove SO2 from a wide variety of sulfur-containing coals.

A CZD/FGD system can be added to a utility boiler with acapital investment of about $25–50/kW of installed capacity, or approximately one-fourth the cost of building aconventional wet scrubber. In addition to low capital cost,other advantages include small space requirements, easeof retrofit, low energy requirements, fully automated operation, and production of only nontoxic, disposablewaste. The CZD/FGD technology is particularly wellsuited for retrofitting existing boilers, independent oftype, age, or size. The CZD/FGD installation does notrequire major power station alterations and can be easilyand economically integrated into existing power plants.

ContactsJoseph T. Newman, Project Manager

(415) 768-1014Bechtel CorporationP.O. Box 193965San Francisco, CA 94119-3965(415) 768-3535 (fax)

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Thomas A. Sarkus, NETL, (412) 386-5981

sarkus@netl.doe.gov

ReferencesConfined Zone Dispersion Project: FinalTechnical Report. Bechtel Corporation. June1994.Confined Zone Dispersion Project: PublicDesign Report. Bechtel Corporation. October 1993.

Comprehensive Report to Congress on the Clean CoalTechnology Program: Confined Zone Dispersion FlueGas Desulfurization Demonstration. Bechtel Corporation.

Report No. DOE/FE-0203P. U.S. Department of Energy.September 1990. (Available from NTIS as DE91002564.)
20 Completed Projects 2003

LIFAC Sorbent InjectionDesulfurizationDemonstration ProjectProject completedParticipantLIFAC–North America (a joint venture partnershipbetween Tampella Power Corporation and ICF KaiserEngineers, Inc.)Additional Team MembersICF Kaiser Engineers, Inc.—cofunder and project

manager

Tampella Power Corporation—cofunderTampella, Ltd.—technology ownerRichmond Power and Light—cofunder and host utilityElectric Power Research Institute—cofunderBlack Beauty Coal Company—cofunderState of Indiana—cofunderLocationRichmond, Wayne County, IN (Richmond Power &Light’s Whitewater Valley Station, Unit No. 2)TechnologyLIFAC’s sorbent injection process with sulfur capture in aunique, patented vertical activation reactorPlant Capacity/Production60 MWeCoalBituminous, 2.0–2.8% sulfurProject FundingTotal $21,393,772 100%DOE 10,636,864 50Participants 10,756,908 50

Project ObjectiveTo demonstrate that electric power plants—especiallythose with space limitations and burning high-sulfurcoals—can be retrofitted successfully with the LIFAClimestone injection process to remove 75–85% of the SO2from flue gas and produce a dry solid waste product fordisposal in a landfill.Technology/Project DescriptionPulverized limestone is pneumatically injected into theupper part of the boiler near the superheater where it absorbs some of the SO2 in the boiler flue gas. The limestone is calcined into calcium oxide and is available for

capture of additional SO2 downstream in the activation, or

humidification, reactor. In the vertical chamber, watersprays initiate a series of chemical reactions leading toSO2 capture. After leaving the chamber, the sorbent is

easily separated from the the electrostatic precipitatfrom the reactor and electlated back through the reaThe waste is dry, making scrubber sludge produced scrubber systems.The technology enables ptions to use high-sulfur minjection process that rem

flue gas and produces a dfor disposal in a landfill.

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesSO2 Control Technologies
Calendar Year

 3 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 

1988 1989 1990 1991 1992 1993 1994 1995 1996

Preaward Design and Construction Operation and Reporting

Preoperational tests initiated 7/92

Environmental monitoring plancompleted 6/12/92Construction completed 6/92

12/89 11/90 9/92

DOE selected project (CCTDP-III) 12/19/89

NEPA process completed (MTF) 10/2/90

Cooperative agreement awarded 11/20/90

Ground breaking/construction started 5/29/91

Original design completed 7/91

Operation initiated 9/92

Operation completed 6/94

Results SummaryEnvironmental• SO2 removal efficiency was 70% at a calcium-to-sulfur

(Ca/S) molar ratio of 2.0, approach-to-saturation temperature of 7–12 oF, and limestone fineness of 80%minus 200 mesh.

• SO2 removal efficiency was increased an additional

15% by increasing limestone fineness to 80% minus325 mesh and maintaining a Ca/S molar ratio of 2.0and7–12 oF approach-to-saturation temperature.

• The four parameters having the greatest influence on

sulfur removal efficiency were limestone fineness,Ca/S molar ratio, approach-to-saturation temperature,and ESP ash recycle rate.

• ESP ash recycle rate was limited in the demonstration

system configuration. Increasing the recycle rate andsustaining a 5 oF approach-to-saturation temperaturewere projected to increase SO2 removal efficiency to

85% at a Ca/S molar ratio of 2.0 and limestone fineness of 80% minus 325 mesh.

• ESP efficiency and operating levels were essentially

unaffected by LIFAC during steady-state operation.

• Fly and bottom ash were dry and readily disposed of

at a local landfill. The quantity of additional solidwaste can be determined by assuming that approximately 4.3 tons of limestone is required to remove1.0 ton of SO2.

Operational• When operating with fine limestone (80% minus 325

mesh), the sootblowing cycle had to be reduced from6.0–4.5 hours.

• Automated programmable logic and simple design

make the LIFAC system easy to operate in startup,shutdown, or normal duty cycles.

• The amount of bottom ash increased slightly, but there

was no negative impact on the ash-handling system.

Economic• Capital cost (1994$)—$66/kW for two LIFAC

reactors (300 MWe); $76/kW for one LIFACreactor (150 MWe); $99/kW for one LIFACreactor (65 MWe).

• Operating cost (1994

assuming 75% SO2 climestone composed $15/ton.
22 Completed Projects 2003

The LIFAC system successValley Station Unit No. 2 is & Light for commercial use full-scale LIFAC units in Cathe United States.

Project SummaryThe LIFAC technology was designed to enhance the effectiveness of dry sorbent injection systems for SO2 control and to maintain the desirable aspects of low capital

cost and compactness for ease of retrofit. Furthermore,limestone was used as the sorbent (about 1/3 of the costof lime) and a sorbent recycle system was incorporated toreduce operating costs.The process evaluation test plan was composed of fivedistinct phases, each having its own objectives. Thesetests were:• Baseline tests characterized the operation of the host

boiler and associated subsystems prior to LIFACoperations.

• Parametric tests were designed to evaluate the many

possible combinations of LIFAC process parametersand their effect on SO2 removal.

• Optimization tests were performed after the parametric

tests to evaluate the reliability and operability of theLIFAC process over short, continuous operating periods.

• Long-term tests were designed to demonstrate LIFAC’s

performance under commercial operating conditions.

• Post-LIFAC tests involved repeating the baseline test

to identify any changes caused by the LIFAC system.

The coals used during the demonstration varied in sulfurcontent from 1.4–2.8%. However, most of the testing wasconducted with the higher (2.0–2.8%) sulfur coals.Environmental PerformanceDuring the parametric testing phase, the numerous LIFACprocess values and their effects on sulfur removal efficiency were evaluated. The four major parameters havingthe greatest influence on sulfur removal efficiency werelimestone fineness, Ca/S molar ratio, reactor bottom temperature (approach-to-saturation), and ESP ash recyclingrate. Total SO2 capture was about 15% better when injecting fine limestone (80% minus 325 mesh) than it was

with coarse limestone (80% minus 200 mesh).While injecting the fine limestone, the sootblowing frequency had to be increased from 6-hour to 4.5-hourcycles. The coarse-quality limestone did not affect sootblowing but was found to be more abrasive on the feed and transport hoses. Parametric tests indicated that a 70% SO2 reduction was achievable with a Ca/S molar ratio of 2.0. ESP ash con- taining unspent sorbent and fly ash was recycled from the ESP hoppers back into the reactor inlet duct work. Ash recycling was found to be essential for efficient SO2 cap- ture. However, the large quantity of ash removed from the LIFAC reactor bottom and the small size of the ESP hop- pers limited the ESP ash recycling rate. As a result, the amount of material recycled from the ESP was approxi- mately 70% less than had been anticipated, but even this low recycling rate was found to affect SO2 capture. Dur- ing a brief test, it was found that increasing the recycle rate by 50% resulted in a 5% increase in SO2 removal efficiency. It was estimated that if the reactor bottom ash is recycled along with ESP ash, while sustaining a reactor temperature of 5 oF above saturation temperature, an SO2 reduction of 85% could be maintained. Operational Performance Optimization testing began in March 1994 and was fol- lowed by long-term testing in June 1994. The boiler was operated at an average load of 60 MWe during long-term testing, although it fluctuated according to power de- mand. The LIFAC process automatically adjusted to boiler load changes. A Ca/S molar ratio of 2.0 was se- lected to attain SO2 reductions above 70%. Reactor bot- tom temperature was about 5 oF higher than optimum to avoid ash buildup on the steam reheaters. Atomized water droplet size was smaller than optimum for the same rea- son. Other key process parameters held constant during the long-term tests included the degree of humidification, grind size of the high-calcium-content limestone, and recycle of spent sorbent from the ESP. Long-term testing showed that SO2 reductions of 70% or more can be maintained under normal boiler operating conditions. Stack opacity was low (about 10%) and ESP efficiency was high (99.2%). The amount of boiler bot- tom ash increased slightly during testing, but there was no negative impact on the power plant’s bottom and fly ash removal system. The solid waste generated was a mixture of fly ash and calcium compounds, and was readily dis- posed of at a local landfill. The LIFAC system prove

it has few moving parts anprocess can be easily shut cess is automated by a proregulates process control shutdown, and data collecwas easily managed via twin the host utility’s contro
The top of the LIFAC reactor is shown being lifted into place.During 2,800 hours of operation, long-term testing showedthat SO2 reductions of 70% or more could be sustained under

normal boiler operation.

Economic PerformanceThe economic evaluation indicated that the capital cost ofa LIFAC installation is lower than for either a spray dryeror wet scrubber. Capital costs for LIFAC technology vary,depending on unit size and the quantity of reactorsneeded:• $99/kW for one LIFAC reactor at Whitewater Valley

Station (65 MWe) (1994$),

• $76/kW for one LIFAC reactor at Shand Station

(150 MWe), and

• $66/kW for two LIFAC reactors at Shand Station

(300 MWe).

Crushed limestone accounts for about one-half ofLIFAC’s operating costs. LIFAC requires 4.3 tons of limestone to remove 1.0 ton of SO2, assuming 75% SO2 capture, a Ca/S molar ratio of 2.0, and limestone containing

95% CaCO3. Assuming limestone costs of $15/ton,LIFAC’s operating cost would be $65/ton of SO2

removed.Commercial ApplicationsThe LIFAC system at Richmond Power & Light is thefirst to be applied to a power plant using high-sulfur(2.0–2.8%) coal. The LIFAC system is being retained byRichmond Power & Light at Whitewater Valley Station,Unit No. 2.ContactsIlari Ekman, 358-9-348-5-511

Enprima Engineering, Ltd.P.O. Box 61, 01601Vantaa, Finlandilari.ekman@enprima.com

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Thomas A. Sarkus, NETL, (412) 386-5981

sarkus@netl.doe.gov

ReferencesLIFAC Sorbent Injection Desulfurization DemonstrationProject. Final Report, Vol. II: Project Performance andEconomics. LIFAC-North America. February 1998.(Available from NTIS as DE96004421.)“LIFAC Nearing Marketability.” Clean Coal Today. Report No. DOE/FE-0215P-21. Spring 1996.“Commercialization of the LIFAC Sorbent Injection Process in North America.” Third Annual Clean Coal Technology Conference: Technical Papers. Viiala, J., et al.

September 1994.

Comprehensive Report Technology Program: Lization Demonstration PReport No. DOE/FE-02October 1990. (Availabl
24 Completed Projects 2003

Advanced Flue GasDesulfurizationDemonstration ProjectProject completedParticipantPure Air on the Lake, L.P. (a project company of Pure Air,which is a general partnership between Air Products andChemicals, Inc., and Mitsubishi Heavy IndustriesAmerica, Inc.)Additional Team MembersNorthern Indiana Public Service Company—cofunder and

host

Mitsubishi Heavy Industries, Ltd.—process designerStearns-Roger Division of United Engineers and

Constructors—facility designer

Air Products and Chemicals, Inc.—constructor and

operator

LocationChesterton, Porter County, IN (Northern Indiana PublicService Company’s Bailly Generating Station, Unit Nos.7 and 8)TechnologyPure Air’s advanced flue gas desulfurization (AFGD)process and PowerChip® agglomeration process

Plant Capacity/Production528 MWeCoalBituminous, 2.25 –4.5% sulfurProject FundingTotal $151,707,898 100%DOE 63,913,200 42Participant 87,794,698 58

PowerChip is a registered trademark of Pure Air on the Lake, L.P.

Project ObjectiveTo reduce SO2 emissions by 95% or more at approximately one-half the cost of conventional scrubbing

technology, significantly reduce space requirements, andcreate no new waste streams.Technology/Project DescriptionPure Air built a single SO2 absorber for a 528-MWe

power plant. Although the largest capacity absorber module of its time in the United States, space requirementswere modest because no spare or backup absorber modules were required. The absorber performed three functions in a single vessel: prequenching, absorbing, andoxidation of sludge to gypsum. Additionally, the absorberwas of a co-current design, in which the flue gas andscrubbing slurry move in the same direction and at a relatively high velocity compared to that in conventional

counter-current scrubbersyield a state-of-the-art SO

pact and less expensive thscrubbers.Other technical features iized limestone directly inan air rotary sparger locatsorber, and a novel wastewair rotary sparger combinair distribution into one pthe oxidation of calcium sPure Air also demonstratetion process, PowerChip®

dling characteristics of AF

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesSO2 Control Technologies
Calendar Year

 3 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 

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward Design and Construction Operation and Reporting

9/88

Design completed 9/92 ProjecConstruction completed 9/92

12/89 6/92

Environmental monitoring plan completed 1/31/91

6/96

DOE selected project(CCTDP-II) 9/28/88

NEPA process completed (EA) 4/16/90Ground breaking/construction started 4/20/90

Cooperative agreement awarded 12/20/89

Preoperational tests initiated 3/92

Operation initiated 6/92 Operation completed 6/95

Results SummaryEnvironmental• The AFGD design enabled a single 600-MWe absorber

module without spares to remove 95% or more SO2 at

availabilities of 99.5% when operating with highsulfur coals.

• Wallboard-grade gypsum was produced in lieu of solid

waste, and all gypsum produced was sold commercially.

• The wastewater evaporation system (WES) mitigated

expected increases in wastewater generation associatedwith gypsum production and showed the potential forachieving zero wastewater discharge (only a partialcapacity WES was installed).

• Air toxics testing established that all acid gases were

effectively captured and neutralized by the AFGD.Trace elements largely became constituents of thesolids streams (bottom ash, fly ash, and gypsum product). Some boron, selenium, and mercury passed to thestack gas in a vapor state.

Operational• AFGD use of co-current, high-velocity flow; integration of functions; and a unique air rotary sparger

proved to be highly efficient, reliable (to the exclusionof requiring a spare module), and compact. The compactness, combined with no need for a spare module,significantly reduced space requirements.

• The own-and-operate contractual arrangement—Pure

Air took on the turnkey, financing, operating, andmaintenance risks through performance guarantees—was successful.

• PowerChip® increased the market potential for AFGDderived gypsum by cost-effectively converting it to a

product with the handling characteristics of naturalrock gypsum.

Economic• Capital costs and space requirements for AFGD were

about half those of conventional systems.
26 Completed Projects 2003

Exhibit 13

 Pure Air SO2 Removal Performance

(100% Boiler Load)

Project SummaryThe project proved that single absorber modules of advanced design could process largevolumes of flue gas and provide the requiredavailability and reliability without the usualspare absorber modules. The major performance objectives were met.Over the three-year demonstration, the AFGDunit accumulated 26,280 hours of operationwith an availability of 99.5%. Approximately237,000 tons of SO2 were removed, with capture efficiencies of 95% or more, and over

210,000 tons of salable gypsum were produced.The AFGD continues in commercial service,which includes sale of all by-product gypsumto U.S. Gypsum’s East Chicago, Indiana wallboard production plant.Environmental PerformanceTesting over the three-year period clearly established thatAFGD operating within its design parameters (withoutadditives) could consistently achieve 95% SO2 reduction or

more with 2.25–4.5% sulfur coals. The design range for thecalcium-to-sulfur stoichiometric ratio was 1.01–1.07, withthe upper value set by gypsum purity requirements (i.e.,

amount of unreacted reagent allowed in the gypsum). Another key control parameter was the ratio L/G, which is theamount of reagent slurry injected into the absorber grid (L)to the volume of flue gas (G). The design L/G range was50–128 gal/1,000 ft3. The lower end of the L/G ratio was

determined by solids settling rates in the slurry and therequirement for full wetting of the grid packing. The highend of the L/G ratio was determined by where performanceleveled out.Four coals with differing sulfur contents were selected forparametric testing to examine SO2 removal efficiency as a

function of load, sulfur content, stoichiometric ratio, andL/G. Loads tested were 33%, 67%, and 100%. High removal efficiencies, well above 95%, were possible atloads of 33% and 67% with low to moderate stoichiometric ratio and L/G settings, even for 4.5% sulfur coal.Exhibit 13 summarizes the results of parametric testing atfull load.

In the AFGD process, chlorides that would have beenreleased to the air are captured, but potentially become awastewater problem. This was mitigated by the additionof the WES, which takes a portion of the wastewaterstream with high chloride and sulfate levels and injects itinto the ductwork upstream of the ESP. The hot flue gasevaporates the water and the dissolved solids are capturedin the ESP. Problems were experienced early on with theWES nozzles failing to provide adequate atomization andplugging. These problems were resolved by replacing theoriginal single-fluid nozzles with dual-fluid systems employing air as the second fluid.Commercial-grade gypsum quality (95.6–99.7%) wasmaintained throughout testing, even at the lower sulfurconcentrations where the ratio of fly ash to gypsum increases due to lower sulfate availability. The primaryimportance of producing a commercial-grade gypsum isavoidance of the environmental and economic consequences of disposal. Marketability of the gypsum is dependent upon whether users are in range of economictransport and whether they can handle the gypsum byproduct. For these reasons, PowerChip® technology was

demonstrated as part of the project. This technology usesa compression mill to convert the highly cohesive AFGDgypsum cake into a flaked product with handling characteristics equiv

The process aing, or pre-cabriquetting, a$4.10/ton. Air toxics tesgases are effeby the AFGDconstituents oash, fly ash, gselenium, and in a vapor staOperationaAvailability oaveraged 99.5age SO2 remo

attributable to and an effectlosophy. Mod

high availability. An examnew alloy technology, C-2material, to replace alloy the absorber tower wet/drrent rather than conventiosulted in lower pressure dafforded the flexibility to abrupt drop in removal ef

efficiency with limestone scrubbers using lime, whi24-hour power consumptexpected consumption, angal/min, or 52% of expecEconomic PerformancExhibit 14 summarizes cadollar cost estimates for ncapacity and coal sulfur cand a sulfur removal efficThe calculation of levelizestablished in EPRI’s TecThe incremental benefits ment, by-product utilizatiwere also evaluated. Exhi
Exhibit 14

Estimated Costs for an AFGD System

(1995 Current Dollars)

Cases: 1 2 3456 78 9

Plant size (MWe) 100 100 100 300 300 300 500 500 500Coal sulfur content (%) 1.5 3.0 4.5 1.5 3.0 4.5 1.5 3.0 4.5Capital cost ($/kW) 193 210 227 111 121 131 86 94 101Levelized cost ($/ton SO2)

15-year life 1,518 840 603 720 401 294 536 302 22320-year life 1,527 846 607 716 399 294 531 300 223

Levelized cost (mills/kWh)

15-year life 16.39 18.15 19.55 7.78 8.65 9.54 5.79 6.52 7.2420-year life 16.49 18.28 19.68 7.73 8.62 9.52 5.74 6.48 7.21

E

Flue Gas 

Ec

500-MWe plant, 30-yr levtonIncremental cases:A—Conventional FGD (EB—AFGD, own-and-operC—Adds gypsum salesD—Adds emission allowa

removal

E—Increases SO2 remova

of a hypothetical 500-MWe generating unit in the Midwest burning 4.3% sulfur coal with a base case conventional FGD system and four incremental cases. The horizontal lines in Exhibit 15 show the range of costs for afuel-switching option. The lower line is the cost of fueldelivered to the hypothetical midwest unit, and the upperline allows for some plant modifications to accommodatethe compliance fuel.Commercial ApplicationsThe AFGD technology is positioned well to compete inthe pollution control arena of the 21st century. The AFGD

technology has markedly reduced cost and demonstratedthe ability to compete with fuel switching under certaincircumstances even with a first-generation system. Advances in technology, e.g., in materials and components,should lower costs for AFGD. The own-and-operate business approach has done much to mitigate risk on the partof prospective users. High SO2 capture efficiency offers

the AFGD user the possibility of generating allowances orapplying credits to other units within the utility. WES 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, LPc/o Air Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501rothtj@apci.com

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Thomas A. Sarkus, NETL, (412) 386-5981

sarkus@netl.doe.gov

ReferencesSummary of Air Toxics Emissions Testing at Sixteen Utility Power Plants. Prepared by Burns and Roe ServicesCorporation for U.S. Department of Energy, PittsburghEnergy Technology Center. July 1996.

$/Ton SO2 

Advanced Flue Gas Destion Project. Final Tech

formance and EconomicApril 1996. (Available fAdvanced Flue Gas Dessign Report. Pure Air on Advanced Flue Gas DesProject—Project Perfor

ment of Energy. June 19
28 Completed Projects 2003

Demonstration of InnovativeApplications of Technologyfor the CT-121 FGD ProcessProject completedParticipantSouthern Company Services, Inc.Additional Team MembersGeorgia Power Company—hostElectric Power Research Institute—cofunderRadian Corporation—environmental and analytical

consultant

Ershigs, Inc.—fiberglass fabricatorComposite Construction and Equipment—fiberglass

sustainment consultant

Acentech—flow modeling consultantArdaman—gypsum stacking consultantUniversity of Georgia Research Foundation—

by-product utilization studies consultant

LocationNewnan, Coweta County, GA (Georgia Power Company’sPlant Yates, Unit No. 1)TechnologyChiyoda Corporation’s Chiyoda Thoroughbred-121(CT-121) advanced flue gas desulfurization (AFGD) process using the Jet Bubbling Reactor®Plant Capacity/Production100 MWeCoalIllinois No. 5 & No. 6 blend, 2.5% sulfur (baseline)Range of test coals 1.2–4.3% sulfur

Project FundingTotal $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 demonstrate reliable operation while eliminating spare absorbermodules; to evaluate use of fiberglass-reinforced plastic(FRP) vessels to eliminate flue gas prescrubbing and reheat, and to enhance reliability; and to evaluate use ofgypsum to reduce waste management costs.Technology/Project DescriptionThe project demonstrated the CT-121 AFGD process,which uses a unique absorber design known as the Jet

Bubbling Reactor® (JBR)

stone AFGD reaction, forcrystallization in one procchanically and chemically AFGD processes and can cost characteristics.The flue gas enters underthe JBR. The SO2 in the f

calcium sulfite (CaSO3). A

the solution to oxidize the sum. The slurry is dewateinvolves filling a diked arsolids settle in the diked aflows to a retention pond. is returned to the process.

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesSO2 Control Technologies
Calendar Year

 3 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 

Results SummaryEnvironmental• Over 90% SO2 removal efficiency was achieved at SO2

inlet concentrations of 1,000–3,500 ppm with limestone utilization over 97%.

• JBR achieved particulate removal efficiencies of 97.7–

99.3% for inlet mass loadings of 0.303–1.392 lb/106Btu over a load range of 50–100 MWe.

• Capture efficiency was a function of particle size:

– >10 microns—99% capture– 1–10 microns—90% capture– 0.5–1 micron—negligible capture– <0.5 micron—90% capture

• Hazardous air pollutant (HAP) testing showed greater

than 95% capture of hydrogen chloride (HCl) andhydrogen fluoride (HF) gases, 80–98% capture ofmost trace metals, less than 50% capture of mercuryand cadmium, and less than 70% capture of selenium.

• Gypsum stacking proved effective for producing wallboard/cement-grade gypsum.

Operational• FRP-fabricated equipment proved durable both structurally and chemically, eliminating the need for a flue

gas prescrubber and reheat.

• FRP construction combined with simplicity of design

resulted in 97% availability at low ash loadings and95% at high ash loadings, eliminating the need for aspare reactor module.

• Simultaneous SO2 and particulate control were

achieved at fly ash loadings similar to those of anelectrostatic precipitator (ESP) that has marginalperformance.

Economic• Capital costs for project equipment, process, and

startup were $29 million, or $293/kW at Plant Yates.

• Fixed O&M costs were $354,000/yr (1994$), and variable operating costs were $34–64/ton of SO2 removed,

depending on specific test conditions.

• Generic plant costs w

elimination of the nereheat, and a spare mrequirements far belotional flue gas desulf

1988 1989 1990 1991 1992 1993 1994 1995 1996 

4/90

Preaward Design and Construction Operation and Reporting

9/88 10/92

DOE selected project(CCTDP-II) 9/28/88

Cooperative agreement awarded 4/2/90

NEPA process completed (EA)8/10/90Ground breaking/constructionstarted 8/23/90

Environmental monitoringplan completed 12/18/90

Preoperational tests initiated 5/92

Design completed 9/92

Operation initiated 10/92Construction completed 10/92

Operation completed 12/94

P
30 Completed Projects 2003

Project SummaryThe CT-121 AFGD process differs from the more common spray tower type of flue gas desulfurization systemsin that a single process vessel is used in place of the usualspray tower/reaction tank/thickener arrangement. Pumping of reacted slurry to a gypsum transfer tank is intermittent. This allows crystal growth to proceed essentiallyuninterrupted, resulting in large, easily dewatered gypsumcrystals (conventional systems employ large centrifugalpumps to move reacted slurry causing crystal attrition andsecondary nucleation).The demonstration spanned 27 months, including startupand shakedown, during which approximately 19,000hours were logged. Exhibit 16 summarizes operatingstatistics. Elevated particulate loading included a shorttest with the electrostatic precipitator (ESP) completelydeenergized, but the long-term testing was conductedwith the ESP partially deenergized to simulate a morerealistic scenario, i.e., a CT-121 retrofit to a boiler with a

marginally performing particulate collection device. TheSO2 removal efficiency was measured under five different

inlet concentrations with coals averaging 2.5% sulfur andranging from 1.2– 4.3% sulfur (as burned).

Operating PerformanceUse of FRP construction proved very successful. Becausetheir large size precluded shipment, the JBR and limestone slurry storage tanks were constructed on site.Except for some erosion experienced at the JBR inlettransition duct, the FRP-fabricated equipment proved tobe durable, both structurally and chemically. Because ofthe high corrosion resistance, the need for a flue gas prescrubber to remove chlorides was eliminated. Similarly,the FRP-constructed chimney proved resistant to the corrosive condensates in wet flue gas, eliminating the needfor flue gas reheat.Availability of the CT-121 scrubber during the low ashtest phase was 97%. Availability dropped to 95% underthe elevated ash loading conditions due largely to spargertube plugging problems, precipitated by fly ash agglomeration on the sparger tube walls during high ash loadingwhen the ESP was deenergized. The high reliability demonstrated verified that a spare JBR is not required in acommercial design offering.Environmental PerformanceExhibit 17 shows SO2 removal efficiency as a function of

pressure drop across the JBR forfive different inlet concentrations.The greater the pressure drop, thegreater the depth of slurry traversedby the flue gas. As the SO2 concentration increased, removal efficiency

decreased, but adjustments in JBRfluid level could maintain the efficiency above 90% and, at lower SO2

concentration levels, above 98%.Limestone utilization remainedabove 97% throughout the demonstration. Long-term particulatecapture performance was testedwith a partially deenergized ESP(approximately 90% efficiency),and is summarized in Exhibit 18.Analysis indicated that a large percentage of the outlet particulatematter is sulfate, likely a result ofacid mist and gypsum carryover.

This reduces the estimate to approximately 70% of For particulate sizes greatefficiency was consistentlmicron range, capture eff0.5 and 1 micron, the parttimes to negligible valuescarryover entraining parti0.5 micron, the capture efCalculated air toxics remobased on the measuremention, are shown in ExhibiAs to solids handling, the geffective in the long term. Ainitially high in the stack dprocess (with concentrationyear later the chloride concto less than 50 ppm, suitabcations. The reduction in crainwater washing the stac

Exhibit 16

Operation of CT-121 Scrubber

Low Ash Elevated Ash CumulativePhase Phase for Project

Total test period (hr) 11,750 7,250 19,000Scrubber available (hr) 11,430 6,310 18,340Scrubber operating (hr) 8,600 5,210 13,810Scrubber called upon (hr) 8,800 5,490 14,290Reliabilitya 0.98 0.95 0.96Availabilityb 0.97 0.95 0.97Utilizationc 0.73 0.72 0.75

a Reliability = hours scrubber operated divided by the hours called upon to operateb Availability = hours scrubber available divided by the total hours in the periodc Utilization = hours scrubber operated divided by the total hours in the period

Ex

SO2 Remo
Economic PerformanceThe capital cost of the Plant Yates CT-121 project was$29,335,979, or $293/kW, which includes equipment,process, and start-up costs. The annual fixed O&M costwas $354,000/yr. (1994$). Variable operating cost was$34–64/ton of SO2 removed (1994$), depending on specific test conditions.

FRP construction eliminates the need for prescrubbingand reheating flue gas. High system availability eliminates the need for a spare absorber module. Particulateremoval capability eliminates the need for expensive(capital-intensive) ESP upgrades to meet increasinglystrict environmental regulations.Commercial ApplicationsInvolvement of Southern Company (which owns SouthernCompany Services, Inc.), with more than 20,000 MWe ofcoal-fired generating capacity, is expected to enhance confidence in the CT-121 process among other large high-sulfurcoal boiler users. This process will be applicable to 370,000MWe of new and existing generating capacity by the year2010. A 90% reduction in SO2 emissions from only the retrofit portion of this capacity represents more than 10,500,000

tons/yr of potential SO2 control.

Plant Yates continues to operate with the CT-121 scrubberas an integral part of the site’s CAAA compliance strategy.The project received Power magazine’s 1994 PowerplantAward. Other awards include the Georgia Chapter of theAir and Waste Management Association’s 1994 Outstanding Achievement Award, the Georgia Chamber ofCommerce’s 1993 Air Quality Citizen of the Year Award,and the Composites Institute (Society of Plastics Industries) 1996 Design Award of Excellence.ContactsSteve Woodfield, (205) 992-6223

Southern CompanyP.O. Box 2625 / bin no. B223Birmingham, AL 35291(205) 257-7161 (fax)swwoodfi@southernco.com

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Thomas A. Sarkus, NETL, (412) 386-5981

sarkus@netl.doe.gov

Exhibi

CT-121 Air Tox

(JBR Compon

ReferencesDemonstration of Innovfor Cost Reductions to t

Report. Volumes 1-6. SoJanuary 1997.Comprehensive Report Technology Program: Dcations of Technology foSouthern Company Serv0158. U.S. Department able from NTIS as DE9Demonstration of Innovfor the CT-121 FGD Promary. U.S. Department 

Exhibit 18

CT-121 Particulate Capture Performance

(ESP Marginally Operating)

JBR Pressure Boiler Inlet Mass Outlet Mass RemovalChange (inches of Load Loading Loading* Efficiencywater column) (MWe) (lb/106 Btu) (lb/106 Btu) (%)

18 100 1.288 0.02 97.710 100 1.392 0.010 99.318 50 0.325 0.005 98.510 50 0.303 0.006 98.0

*Federal NSPS is 0.03 lb/106 Btu for units constructed after September 18, 1978. Plant Yates permit limit is

0.24 lb/106 Btu as an existing unit. Chloride Fluoride Arsenic Ca

Removal Efficiency, %

0

20406080

100
32 Completed Projects 2003
Environmental Control Devi

NO

x Control Technologie
34 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesNO

x Control Technologies

Demonstration of AdvancedCombustion Techniques for aWall-Fired BoilerProject completedParticipantSouthern Company Services, Inc. (SCS)Additional Team MembersSouthern Company—cofunderElectric Power Research Institute (EPRI)—cofunderFoster Wheeler Energy Corporation (Foster Wheeler)—

technology supplier

Georgia Power Company—hostPowerGen—cofunderU.K. Department of Trade and Industry—cofunderEnTEC—technology supplierRadian—technology supplierTennessee Technological University—technology supplierLocationCoosa, Floyd County, GA (Georgia Power Company’sPlant Hammond, Unit No. 4)TechnologyFoster Wheeler’s low-NO

x burner (LNB) with advanced

overfire air (AOFA) and EPRI’s Generic NOx Control

Intelligent System (GNOCIS) computer software.Plant Capacity/Production500 MWeCoalEastern bituminous coals, 1.7% sulfurProject FundingTotal $15,853,900 100%DOE 6,553,526 41Participant 9,300,374 59

Project ObjectiveTo achieve 50% NO

x reduction with the LNB/AOFA system; to determine the contributions of AOFA and LNB to

NO

x reduction and the parameters for optimal LNB/

AOFA performance; and to assess the long-term effects ofLNB, AOFA, combined LNB/AOFA, and the GNOCISadvanced digital controls on NOx reduction, boiler performance, and peripheral equipment performance. The

project has been reopened and extended to demonstratean overall unit optimization system.Technology/Project DescriptionAOFA involves: (1) improving OFA mixing to enableoperation of the burners below the air/fuel ratiotheoretically required to complete combustion (substoichiometric), without increasing combustible losses;and (2) introducing “boundary air” at the boiler walls toprevent corrosion caused by the reducing atmosphere.

In the Foster Wheeler Con(CFSF) LNB, fuel and air the primary air/fuel mixtucreate a fuel-rich core witbustion at a severely sub-burner also controls the raessary to complete combusolids and gases so as to muntil the remaining combNO

x-producing temperatu

excess air then can be alloproducts so that combustilow temperature. The CFSmixture into four streamsmixing and combustion s
Calendar Year

 3 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 

Results SummaryEnvironmental• Using LNB alone, long-term NOx emissions were 0.65

lb/106 Btu, representing a 48% reduction from baseline

conditions (1.24 lb/106 Btu).

• Using AOFA only, long-term NOx emissions were 0.94

lb/106 Btu, representing a 24% reduction from baseline

conditions.

• Using LNB/AOFA, long-term NOx emissions were

0.40 lb/106 Btu, representing a 68% reduction from

baseline conditions.

• Chemical emissions testing showed no evidence of

organic compound emissions resulting from the combustion modifications installed for NO

x

 control. Trace

element control, except for mercury and selenium,proved to be a function of electrostatic precipitator(ESP) performance.

Operational• AOFA accounted for an incremental NO

x

 reduction

beyond the use of LNB of approximately 17%, withadditional reductions resulting from other operationalchanges.

• GNOCIS achieved a boiler efficiency gain of 0.5 percentage points, a reduction in fly ash loss-on-ignition

(LOI) levels of 1–3 percentage points, and a reductionin NO

x

 emissions of 10–15% at full load.

• Fly ash LOI increased from a baseline of 7% (corrected to representative excess oxygen conditions) to

10% with AOFA and 8% with LNB and LNB/AOFA,despite significant improvements in coal fineness.

Economic• Capital cost for a 500-MWe wall-fired unit is $8.8/kW

for AOFA alone, $10.0/kW for LNB alone, $18.8/kWfor LNB/AOFA, and $0.5/kW for GNOCIS.

• Estimated cost of NO

x removal is $79/ton using LNB/

AOFA in a baseload dispatch scenario as experiencedat Plant Hammond.

Preaward

1988 1989 1990 1991 1992 1993 1994 1996 1998 

9/88 12/89 6/90

Design and Construction

DOEselectedproject(CCTDP-II)9/28/88

Design completed, 3/90

Construction started, AOFA 4/90

Construction completed, AOFA 5/90

Operation initiated, AOFA 6/90

Environmental monitoring plan completed 9/14/90

Construction started, LNB;Operation completed, AOFA 3/91

Construction completed, LNB;Operation initiated, LNB 4/91

NEPA process

completed (MTF)

5/22/89

Operation completed,LNB 1/92

Operation initiated, LNB/AOFA 5/93

Operation and Reporting

Operation completed, LNB/AOFA 8/93

Operation initiated,LNB/AOFA with digital controlsystem 6/94

Final report

(Phase 1-3B)

issued 1/98

**

GNOCIS testinginitiated 2/96

Fin(Phiss

Project co

Coope

r

**

Cooperative agreement awarded, 12/20/89

Ope
36 Completed Projects 2003

Project SummarySCS conducted baseline characterization of the unit in an“as-found” condition from August 1989 to April 1990.The AOFA system was tested from August 1990 to March1991. Following installation of the LNBs in the secondquarter of 1991, the LNBs were tested from July 1991 toJanuary 1992, excluding a three-month delay when theplant ran at reduced capacity. Post-LNB increases in flyash LOI, along with increases in combustion air requirements and fly ash loading to the electrostatic precipitator(ESP), adversely affected the unit’s stack particulate emissions. The LNB/AOFA testing was conducted from January 1992 to August 1993, excluding downtime for ascheduled outage and for portions of the test period dueto excessive particulate emissions. However, an ammoniaflue gas conditioning system was added to improve ESPperformance, which enabled the unit to operate at fullload, and allowed testing to continue.Operational PerformanceLOI increased for the AOFA, LNB, and LNB/AOFAphases, as shown in Exhibit 20, despite improved millperformance due to the replacement of the mills. Increased LOI was a concern not only because of the associated efficiency loss, but also due to a potential loss of

Exhibit 20

LOI Performance Test Results

Exhibi

NOx vs. LOI Tests—

Exhibit 22

Typical Trade-Offs in Bo

fly ash sales. The increased carbon in the flyash renders the material unsuitable for use inmaking concrete.During October 1992, SCS conducted parametric testing to determine the relationshipbetween NOx and LOI emissions. The parameters tested were: excess oxygen, mill coal

flow bias, burner sliding tip position, burnerouter register position, and burner inner register position. Nitrogen oxide emissions andLOI levels varied from 0.44–0.57 lb/106 Btu

and 3–10%, respectively. As expected, excessoxygen levels had considerable effect on bothNOx and LOI. The results showed that there is

some flexibility in selecting the optimumoperating point and making trade-offs between NOx emissions and fly ash LOI; however, much of the variation was the result of

changes in excess oxygen. This can be more clearly seenin Exhibit 21 in which all sensitivities are plotted. Thisexhibit shows that, for excess oxygen, mill bias, innerregister, and sliding tip, any adjustments to reduce NOx

emissions are at the expense of increased fly ash LOI. Incontrast, the slope of the outer register adjustment suggests that improvement in both NOx emissions and LOI

can be achieved by adjustment of this damper. However,

due to the relatively small impact of the outerregister adjustment on both NOx and LOI, it is

likely the positive NOx/LOI slope is an artifact of

process noise.A subsidiary goal of theproject was to evaluate advanced instrumentation andcontrols (I&C) as applied tocombustion control. The needfor more sophisticated I&Cequipment is illustrated inExhibit 22. There are tradeoffs in boiler operation, e.g.,

as excess air increases, NOx

increases, LOI decreases, andboiler losses increase. Thegoal is to find and maintain

an optimal operating condcontrol (I&C) systems tesbon-in-ash analyzers.The GNOCIS software apto identify the best set poimplemented automatical(closed-loop), or conveyeimplementation (open-looGNOCIS are shown in Exprovided advice that redu

10–15% at full load, whilreducing fly ash LOI by 1
Environmental PerformanceLong-term testing showed that the AOFA, LNBs, andLNB/AOFA provide full-load NOx reductions of 24, 48,

and 68%, respectively. Although the long-term LNB/AOFA NOx level represents a 68% reduction from baseline levels, a substantial portion of the incremental change

in NOx emissions between the LNB and the LNB/AOFA

configurations is the result of operational changes and isnot the result of adding AOFA.During the LNB/AOFA test phase a total of 63 days ofvalid long-term NOx emissions data was collected. Based

on this data set, the full-load, long-term NOx emissions

were 0.40 lb/106 Btu, which was consistent with earlier

short-term test data. Earlier long-term testing had resultedin NOx emissions of 0.94 lb/106 Btu for AOFA only and

0.65 lb/106 Btu for LNB only.

Chemical emissions testing showed no evidence of organic compound emissions resulting from the combustionmodifications installed for NOx control. Trace element

control, except for mercury and selenium, proved to be afunction of electrostatic precipitator (ESP) performance.Only a small portion of the mercury and selenium, whichadopt a vapor phase, and none of the vapor-phase chlorine (as hydrochloric acid) and fluorine (as hydrofluoricacid) were captured.

Exhibit 23

Major Elements of

Optimization System

Economic PerformanceEstimated capital costs for a commercial 500-MWe wallfired installation are: AOFA—$8.8/kW, LNB—$10.0/kW, LNB/AOFA—$18.8/kW, and GNOCIS—$0.5/kW.Annual O&M costs and NOx reductions depend on the

assumed load profile. Based on the actual load profileobserved in the testing, the estimated annual O&M costincrease for LNB/AOFA is $333,351. Efficiency is decreased by 1.3 percent, and the NOx reduction is 68 percent of baseline, or 11,615 tons/year at full load. The

capital cost is $8,300,000 and the calculated cost of NOxremoved is $79/ton for the Hammond baseload dispatchscenario.The addition of GNOCIS to the LNB/AOFA, using theactual load profile observed in the testing, results in arange of costs depending on whether the unit is operatedto maximize NOx removal efficiency, or LOI. For the

maximum NOx removal case, the efficiency is improved

by 0.6 percent, the annual O&M cost is decreased by$228,058, the incremental NOx reduction is 11 percent

(696 tons/year), and the capital cost is $250,000. Thecalculated cost per ton of NOx removed is -$299 (net gain

due to increased efficiency).Project ExtensionOn September 15, 1999, the cooperative agreement wasextended and work began on the design and installationof an overall unit optimization system. The work hasbeen carried out as part of Phase 4 of the project. Theoverall goal of Phase 4 is to demonstrate on-line optimization techniques, including use of a real-time heat ratemonitor, for power plant processes and for the unit as awhole. The major tasks include unit optimization, boileroptimization, automated sootblowing, and precipitatormodeling/optimization.Commercial ApplicationsThe technology is applicable to the 411 existing preNSPS dry-bottom wall-fired boilers in the United States,which burn a variety of coals. The GNOCIS technology isapplicable to all fossil fuel-fired boilers, including unitsfired with natural gas and units cofiring coal and naturalgas. The host has retained the technologies for commercial use.

ContactsJohn N. Sorge, Research 

Southern Company SMail stop 14N-8195P.O. Box 2641Birmingham, AL 352(205) 257-5367 (fax)jnsorge@southernco

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

James R. Longanbach, N

james.longanbach@n

References500-MW Demonstration bustion Techniques for t(NOx) Emissions from C

Digital Control System pany Services, Inc. Sept500-MW Demonstration tion Techniques for the R

Emissions from Coal-FirReport. Southern Compa
38 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesNO

x Control Technologies

Demonstration of CoalReburning for Cyclone BoilerNO

x

 Control

Project completedParticipantThe Babcock & Wilcox CompanyAdditional Team MembersWisconsin Power and Light Company—cofunder and

host

Sargent and Lundy—engineer for coal handlingElectric Power Research Institute—cofunderState of Illinois, Department of Energy and Natural

Resources—cofunder

Utility companies (14 cyclone boiler operators)—

cofunders

LocationCassville, Grant County, WI (Wisconsin Power and LightCompany’s Nelson Dewey Station, Unit No. 2)TechnologyThe Babcock & Wilcox Company’s Coal Reburning System (Coal Reburning)Plant Capacity/Production100 MWeCoalIllinois Basin bituminous (Lamar), 1.15% sulfur, 1.24%nitrogenPowder River Basin (PRB) subbituminous, 0.27% sulfur,0.55% nitrogenProject FundingTotal $13,646,609 100%DOE 6,340,788 46Participant 7,305,821 54

Project ObjectiveTo demonstrate the technical and economic feasibility ofCoal Reburning to achieve greater than 50% reduction inNO

x emissions with no serious impact on cyclone combustor operation, boiler performance, or other emission

streams.Technology/Project DescriptionBabcock & Wilcox Coal Reburning reduces NOx in the

furnace through the use of multiple combustion zones.The main combustion zone uses 70–80% of the total heatequivalent fuel input to the boiler, and slightly less thannormal combustion air input. The balance of the coal (20–30%), along with significantly less than the theoreticallydetermined requirement of air, is fed to the reburningzone above the cyclones to create an oxygen-deficientcondition. The NO

x formed in the cyclone burners reacts

with the resultant reducininto elemental nitrogen in combustion process occurburnout zone, where the bintroduced.
Calendar Year

 3 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 

Results SummaryEnvironmental• Coal Reburning achieved greater than 50% NOx reduction at full load with Lamar bituminous and PRB subbituminous coals.

• Reburning-zone stoichiometry had the greatest effect

on NO

x

 control.

• Gas recirculation was vital to maintaining reburningzone stoichiometry while providing necessary burner

cooling, flame penetration, and mixing.

• Opacity levels and electrostatic precipitator (ESP)

performance were not affected by Coal Reburningwith either coal tested.

• Optimal Coal Reburning heat input was 29–30% at

full load and 33–35% at half to moderate loads.

Operational• No major boiler performance problems were experienced with Coal Reburning operations.• Boiler turndown capability was 66%, exceeding the

50% goal.

• ESP efficiency improved slightly during Lamar coal

testing and did not change with PRB coal.

• Coal fineness levels above the nominal 90% through

200 mesh were maintained, reducing unburned carbonlosses (UBCL).

• UBCL was the only major contributor to boiler efficiency loss, which was 0.1, 0.25, and 1.5 percentage

points at loads of 110, 82, and 60 MWe, respectively,when using Lamar coal. With PRB coal, the efficiencyloss ranged from zero at full load to 0.3 percentagepoints at 60-MWe.

• Superior flame stability was realized with PRB coal,

contributing to better NOx control than with Lamar

coal.

• Expanded volumetric fuel delivery with reburning

burners enabled switching to PRB low-rank coal without boiler derating.

Economic• Capital costs for 110 and 605 MWe plants were

$66/kW and $43/kW, respectively (1990$).

• Levelized 10- and 30

110-MWe plant were tively (constant 1990

• Levelized 10- and 30

605-MWe plant were tively (constant 1990

Operationinitiated 12/91

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Design and Construction

9/88

Preaward

DOE selected project(CCTDP-II) 9/28/88

4/90 12/91

Operation and Reporting

3/94

Project completed/final report issued 3/94

Operationcompleted 12/92

Environmental monitoring plan completed 11/18/91Construction completed 11/91Preoperational tests initiated 11/91

NEPA process completed (EA) 2/12/91

Design completed 6/91

Ground breaking/construction started 11/90

Cooperative agreement

awarded 4/2/90
40 Completed Projects 2003

Wisconsin Power and Light hosted the successful demo

Boiler Load

110 MWe 82 MWe 60 MWe

Lamar coalNOx (lb/106 Btu/% reduction) 0.39/52 0.36/50 0.44/36

Boiler efficiency losses due to 0.1 0.25 1.5unburned carbon (%)Powder River Basin coalNOx (lb/106 Btu/% reduction) 0.34/55 0.31/52 0.30/53

Boiler efficiency losses due 0.0 0.2 0.3to unburned carbon (%)

Exhibit 24

Coal Reburning Test Results

Project SummaryAlthough cyclone boilers represent only 8.5% of the preNSPS coal-fired generating capacity, they contribute 12%of the NOx formed by pre-NSPS coal-fired units. This is

due to the cyclone combustor’s inherent turbulent, hightemperature combustion process. However, at the time ofthis demonstration, there was no cost-effective combustion modification available for cyclone boiler NOx control.Babcock & Wilcox Coal Reburning offers an economicand operationally sound response to the environmentalrequirements. This technology avoids cyclone combustormodification and associated performance complications,and provides an alternative to postcombustion NOx control options, such as SCR, which have relatively high

capital and/or operating costs.The majority of the testing was performed firing IllinoisBasin bituminous coal (Lamar), because it is typical ofthe coal used by many utilities operating cyclones. Subbituminous PRB coal tests were performed to evaluate theeffect of coal switching on reburning operation. Wisconsin Power and Light’s strategy to meet Wisconsin’s sulfuremission limitations as of January 1, 1993, was to firelow-sulfur coal.

Environmental PerformanceThree sequential tests of Coal Reburning used Lamarcoal. Parametric optimization testing set up the automaticcontrols. Performance testing evaluated the unit in fullautomatic control at set load points. Long-term testingassessed performance in a load-following mode. PRBcoal was used for parametric optimization and performance modes. Exhibit 24 shows changes in NOx emissions and boiler efficiency using the reburning system for

various load conditions and coal types.Coal Reburning tests on both the Lamar and PRB coalsindicated that variation of reburning-zone stoichiometrywas the most critical factor in changing NOx emissions

levels. The reburning-zone stoichiometry can be varied byalternating the air flow quantities (oxygen availability) tothe reburning burners, the percent reburning heat input, thegas recirculation flow rate, or the cyclone stoichiometry.Hazardous air pollutant (HAP) testing was performedusing Lamar test coal. HAP emissions were generally wellwithin expected levels, and emissions with Coal Reburning were comparable to baseline operation. No majoreffect of reburning on trace-metals partitioning was discernible. None of the 16 targeted polynuclear aromaticsemi-volatile organics (controlled under Title III of

CAAA) were present in detectable concentrations, at a detection limit of 1.2parts per billion.Operational PerformanceFor Lamar coal, the full-, medium-, andlow-load efficiency losses due to unburned carbon were higher than thebaseline by 0.1, 0.25, and 1.5 percentage points, respectively. Full-, medium-,and low-load efficiency losses withPRB coal were 0.0, 0.2, and 0.3 percentage points, respectively. Coal Reburning burner flame stability improvedwith PRB coal.During Coal Reburning operation withLamar coal, the operators continuallymonitored boiler internals for increasedash deposition and the on-line performance monitoring system 

time throughout the systeoperation period were any observed. In fact, during boiler inspections revealeactually improved. Extensurements were taken of tservable decrease in wall Another significant findinminimizes and possibly enormally associated with in a cyclone unit. This deBtu fuel in a cyclone comfeed capacity. Coal Reburthe coal feed out of the cybringing the cyclone feed while maintaining full-loaEconomic PerformancAn economic analysis of enue requirements was coPower Research Institute of 110- and 605-MWe placosts per ton of NOx remo

and 605-MWe plants over sults of these analyses are values assumed typical re
The coal pulverizer is part of Babcock & Wilcox coalreburning. This system has been retained by WisconsinPower and Light for NOx emission control at the NelsonDewey Station.

E

Coal Rebu

(1990 Co

Costs Total capital cost ($/kWLevelized busbar powercost (mills/kWh)

10-year life 30-year life 

Annualized cost ($/ton of NOx removed

10-year life 30-year life 

take into account any fuel savings from use of low-rankcoal. The pulverizers and associated coal handling weretaken into account. Site-specific parameters that can significantly impact these retrofit costs included the state ofthe existing control system, availability of flue gas recirculation, space for coal pulverizers, space for reburningburners and overfire air ports within the boiler, scope ofcoal-handling modification, sootblowing capacity, ESPcapacity, steam temperature control capacity, and boilercirculation considerations.

Commercial ApplicationsCoal Reburning is a retrofit technology applicable to awide range of utility and industrial cyclone boilers. Thecurrent U.S. coal reburning market is estimated to beapproximately 27,000 MWe and consists of about 89units ranging from 100–1,150 MWe with most in the100- to 300-MWe range.The project technology has been retained by WisconsinPower and Light for commercial use.ContactsDot K. Johnson, (330) 860-1757

The Babcock & Wilcox Company20 South Van Buren AvenueP.O. Box 351Barberton, OH 44203-0351(330) 860-2348 (fax)dkjohnson1@babcock.com

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

John C. McDowell, NETL, (412) 386-6175

mcdowell@netl.doe.gov

ReferencesDemonstration of Coal Reburning for Cyclone BoilerNO

x Control: Final Project Report. Report No. DOE/PC/

89659-T16. The Babcock & Wilcox Company. February1994. (Available from NTIS as DE94013052, Appendix 1as DE94013053, Appendix 2 as DE94013054.)Public Design Report: Coal Reburning for CycloneBoiler NO

x

 Control. The Babcock & Wilcox Company.

August 1991. (Available from NTIS as DE92012554.)Comprehensive Report to Congress on the Clean CoalProgram: Demonstration of Coal Reburning for CycloneBoiler NO

x

 Control. Report No. DOE/FE-0157. U.S. Department of Energy. February 1990. (Available from NTIS

as DE90008111.)
42 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesNO

x Control Technologies

Full-Scale Demonstration ofLow-NO

x

 Cell Burner Retrofit

Project completedParticipantThe Babcock & Wilcox CompanyAdditional Team MembersThe Dayton Power and Light Company—cofunder and

host

Electric Power Research Institute—cofunderOhio Coal Development Office—cofunderTennessee Valley Authority—cofunderNew England Power Company—cofunderDuke Power Company—cofunderAllegheny Power System—cofunderCenterior Energy Corporation—cofunderCincinnati Gas & Electric Company—cofunderColumbus and Southern Power Company—cofunderLocationAberdeen, Adams County, OH (Dayton Power and LightCompany’s J.M. Stuart Plant, Unit No. 4)TechnologyThe Babcock & Wilcox Company’s low-NOx cell-burner

(LNCB®) system

Plant Capacity/Production605 MWeCoalBituminous, 1.2% sulfurProject FundingTotal $11,233,392 100%

DOE 5,442,800 48Participant 5,790,592 52

Project ObjectiveTo demonstrate, through the first commercial-scale fullburner retrofit, the cost-effective reduction of NOx from

a large, baseload coal-fired utility boiler with LNCB®

technology and to achieve at least a 50% NOx reduction

without degradation of boiler performance at less costthan that of conventional low-NO

x

 burners.

Technology/Project DescriptionThe LNCB® technology replaces the upper coal nozzle of

the standard two-nozzle cell burner with a secondary airport. The lower burner coal nozzle is enlarged to the samefuel input capacity as the two standard coal nozzles. TheLNCB® operates on the principle of staged combustion to

reduce NO

x emissions. Combustion is staged by providing only about 58% of the air theoretically required for

complete combustion through the lower burner and the

balance of the air through 

port).The demonstration was coWilcox-designed, supercrequipped with an electrosunit, which is typical of ctwo-nozzle cell burners aconfiguration. Twelve bursix burners each) were mwalls of the boiler. All 24 moved and 24 new LNCB

LNCBs® on the bottom ro

port then being on the botbustion in the lower furna
Calendar Year

 3 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 

Results SummaryEnvironmental• Short-term optimization testing (all mills in service)

showed NO

x reductions in the range of 53.0–55.5%,

52.5–54.7%, and 46.9–47.9% at loads of 605 MWe,460 MWe, and 350 MWe, respectively.

• Long-term testing at full load (all mills in service)

showed an average NOx reduction of 58% (over 8

months).

• Long-term testing at full load (one mill out of service)

showed an average NOx reduction of 60% (over 8months).

• Carbon monoxide (CO) emissions averaged 28–55

ppm at full load with LNCB® in service.

• Fly ash increased, but ESP performance remained virtually unchanged.Operational• Unit efficiency remained essentially unchanged.• Unburned carbon losses (UBCL) increased by approximately 28% for all tests, but boiler efficiency loss was

offset by a decrease in dry gas loss due to a lowerboiler economizer outlet gas temperature.

• Boiler corrosion with LNCB® was roughly equivalent

to boiler corrosion rates prior to retrofit.

Economic• Capital cost for a 600 MWe plant in the Midwest, with

a 1.2 lb/106 Btu initial NO

x

 emission rate and 65%

capacity factor, was $9/kW (1994$).

• Levelized cost (15-year) for the same 600 MWe plant

was estimated at 0.284 mills/kWh and $96.48/ton ofNO

x removed (constant 1994$).

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operationinitiated 12/91

10/90

Operation and Reporting

Design and

Preaward Construction

12/91

NEPA process completed (MTF) 8/10/90

DOE selected project

(CCTDP-III) 12/19/89

Project complete

12/95

Operation completed 4/93

12/89

Construction completed 11/91Preoperational tests initiated 11/91

Cooperative agreement

awarded 10/11/90

Design completed 10/90

Environmental monitoring plancompleted 8/9/91

Ground breaking/construction started 9/91
44 Completed Projects 2003

Project SummaryUtility boilers equipped with cell burners represent 7.4%or approximately 24,000 MWe of pre-NSPS coal-firedgenerating capacity. Cell burners are designed for rapidmixing of fuel and air. The tight burner spacing and rapidmixing minimize flame size while maximizing the heatrelease rate and unit efficiency. Combustion efficiency isgood, but the rapid heat release produces relatively largequantities of NOx

.

To reduce NOx emissions, the LNCB® has been designed

to stage mixing of fuel and combustion air. A key designcriterion was accomplishing delayed fuel-air mixing withno modifications to boiler walls. The plug-in LNCB®

design reduces material costs and outage time required tocomplete the retrofit, compared to installing conventional,internally staged low-NOx burners, thereby providing a

lower cost alternative to address NOx reduction requirements for cell burners.

Environmental PerformanceThe initial LNCB® configuration resulted in excessive CO

and hydrogen sulfide (H2S) emissions. Through modeling,

a revised configuration was developed (inverting alternateburners on the lower rows), which addressed the problemwithout compromising boiler performance. The modification served to validate model capabilities.Following parametric testing to establish optimal operating modes, a series of optimization tests were conductedon the LNCB® to assess environmental and operational

performance. Two sets of measurements were taken, oneby Babcock & Wilcox and the other by an independentcompany, to validate data accuracy. Consequently, thedata provided is a range reflecting the two measurements.The average NOx emissions reduction achieved at full

load with all mills in service ranged from 53.0–55.5%.With one mill out of service at full load, the average NOx

reduction ranged from 53.3–54.5%. Average NOx reduction at intermediate load (about 460 MWe) ranged from

52.5–54.7%. At low loads (about 350 MWe), averageNOx reduction ranged from 46.9–47.9%. NOx emissions

were monitored over the long term at full load with allmills in service and one mill out of service. Each testspanned an 8-month period. The NOx emission reductions

Single LNCB® retrofit.

realized were 58% for all mills in service and about 60%for one mill out of service.Complications arose in assessing CO emissions relative tobaseline because baseline calibration was not sufficientlyrefined. However, accurate measurements were madewith LNCB® in service. Carbon monoxide emissions were

corrected for 3.0% O2 and measured at full, intermediate,

and low loads. The range of CO emissions at full loadwith all mills in service was 28–55 ppm, and 20–38 ppmwith one mill out of service. At intermediate loads (about460 MWe), CO emissions were 28–45 ppm, and at lowloads (about 350 MWe), 5–27 ppm.Particulate emissions were minimally impacted. TheLNCB® had little effect on fly ash resistivity, largely due

to SO3 injection, and therefore ESP removal efficiency

remained very high. Baseline ESP collection efficienciesfor full load with all mills in service, full load with onemill in service, and intermediate load with one mill out ofservice were 99.50%, 99.49%, and 99.81%, respectively.For the same conditions, in the same sequence withLNCB® in operation, ESP collection efficiencies were

99.43%, 99.12%, and 99.35%, respectively.Operational PerformanceFurnace exit gas temperature initially decreased by100 oF, but eventually rose to within 10 oF of baselineconditions. The UBCL increased by approximately 28%for all tests. The most significant increase from baselinedata occurred for a test with one mill out of service. A52% increase in UBCL resulted in an efficiency loss of0.69%.Boiler efficiency showed very little change from baseline.The average with all mills in service increased by 0.16%.The higher post-retrofit efficiency was attributed to adecrease in dry gas loss with lower economizer gas outlettemperature (and subsequent lower air heater gas outlettemperature), offsetting UBCL and CO emission losses.Also, increased coal fineness mitigated UBCL.Because sulfidation is the primary corrosion mechanismin substoichiometric combustion of sulfur-containingcoal, H2S levels were monitored in the boiler. After optimizing LNCB® operation, levels were largely at the lower

detection limit. There were some higher local readings,

but corrosion panel tests ewith LNCB® were roughl

Ash sample analyses indinot be a problem. The LN

baseline ash. Furthermorein furnace exit gas temperLNCB® indicated little ch

Startup and turndown of tversion to LNCB®.

Economic PerformancThe economic analyses wnominal unit size and typUnited States. A medium-nous coal was chosen as tNOx emission level of 1.2 

tor, and a 50% reduction was $9/kW (1994$). The 
The S-Type burner impellers used in the LNCB® design.

Cell burner AOFA connection with air control vanes open (right) lying next to cellburner housing showing primary air directional vanes and coal tube (left).

tricity was estimated at 0.284 mills/kWh, or $96.48/ton ofNO

x

 removed in constant 1994 dollars.

Commercial ApplicationsThe market for LNCB® technology is 33, two-nozzle type

cell burner boilers in the U.S. (5 cell burners are threenozzle types) with a total generating capacity of 25,200MWe. The LNCB® system installed at the Dayton Power

& Light Company’s J.M. Stuart Plant unit No. 4 has beenretained for commercial service.Commercial success to date, and likely to come, is owedlargely to the establishment of the LNCB® Advisory

Committee composed of most of the cell burner equippedboiler owners. The Committee participated in thedemonstration, becoming familiar with the technology,supporting numerical models, providing inputs to thedemonstration, and reviewing field data.The demonstration project received R&D magazine’s1994 R&D Award.ContactsDot K. Johnson, (330) 860-1757

The Babcock & Wilcox Company20 South Van Buren AvenueP.O. Box 351Barberton, OH 44203-0351(330) 860-2348 (fax)dkjohnson1@babcock.com

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Thomas A. Sarkus, NETL, (412) 386-5981

sarkus@netl.doe.gov

RefereFinal Rof Low

port NoBabcocand De1995. (DE960Full-Sc

Cell Buport. RThe Baergy Se(AvailaComprthe CleFull-ScCell Bu

Wilcox 0197P. 1990. (DE900Full-ScCell Bu

mance Energy
46 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesNO

x Control Technologies

Evaluation of Gas Reburningand Low-NO

x

 Burners on a

Wall-Fired Boiler

Project completedParticipantEnergy and Environmental Research CorporationAdditional Team MembersPublic Service Company of Colorado—cofunder and hostGas Research Institute—cofunderColorado Interstate Gas Company—cofunderElectric Power Research Institute—cofunderFoster Wheeler Energy Corp.—technology supplierLocationDenver, Adams County, CO (Public Service Company ofColorado’s Cherokee Station, Unit No. 3)TechnologyEnergy and Environmental Research Corporation’s gasreburning (GR) system and Foster Wheeler EnergyCorp.’s low-NOx burners (LNB)

Plant Capacity/Production172 MWe (gross), 158 MWe (net)CoalColorado bituminous, 0.40% sulfur, 10% ash, 1.51%nitrogenProject FundingTotal $17,807,258 100%DOE 8,895,790 50Participant 8,911,468 50Project ObjectiveTo attain up to a 70% decrease in NOx emissions from an

existing wall-fired utility boiler, firing low-sulfur coalusing both gas reburning and low-NOx burners (GRLNB); and to assess the impact of GR-LNB on boiler performance. Technology/Project Description Gas reburning involves injecting natural gas (up to 25% of total heat input) above the primary combustion zone in a boiler. This upper-level injection and partial combustion by limiting available oxygen creates a fuel-rich zone. NOx moving upward from coal combustion in the lower fur- nace is stripped of oxygen as the reburn fuel is partially combusted in the reburn zone and converted to molecular nitrogen. Overfire air ports above the reburn zone provide for complete combustion in a relatively cool region of the boiler. Reburning allows the low-NOx burners to operate at excess air levels far below that needed for complete combustion, thus enhancing their effectiveness. The syn- ergistic effect of adding a reburning stage to wall-fired boilers equipped with low

lower NOx emissions by u

was demonstrated with anrecirculation (FGR). A series of parametric testburning system, varying oassessing the effect on boicombustion (carbon-in-ash efficiency, and heat rate. A gram was performed in orsystem outputs, assess the the boiler equipment, gain LNB in a normal load-folla database for use in subseBoth first- (with FGR) and FGR) gas reburning tests w
Calendar Year

 3 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 

Results SummaryEnvironmental• LNB alone reduced NO

x emissions from a pre-construction baseline of 0.73 lb/106 Btu to 0.46 lb/106 Btu

(at 3.5% O2), a 37% NOx reduction.

• First-generation GR, which incorporated FGR in

combination with LNB, reduced NOx emissions to an

average 0.25 lb/106 Btu (at 3.25% O2), a 66% NOx

reduction at an 18% gas heat input rate.

• Second-generation GR, without FGR and in combination with LNB, reduced NOx emissions to an average

0.26 lb/106 Btu, a 64% NOx reduction with only 12.5%

gas heat input.

• Both first- and second-generation GR with LNB were

capable of reducing NOx emissions by up to 70% for

short periods of time, but only with higher than acceptable reburn gas heat inputs.

• The average NOx emission reduction achieved in a

dispatch mode over the longer term was approximately64% for both first- and second-generation GR.

• 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 by 1%.• There was no measurable boiler tube wear and only a

small amount of slagging.

• Carbon-in-ash and CO levels were acceptable for firstand second-generation GR with LNB, but not with

LNB alone.

Economic• Capital cost for a GR-LNB retrofit of a 300-MWe

plant is $26.01/kW (1996$) plus the gas pipeline cost,if not already existing ($12.14/kW for GR only and$13.87/kW for LNB only).

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward Operation and Reporting

12/89

Design and Construction

10/90 11/92

DOE selected project (CCTDP-III) 12/19/89

Environmental monitoring plan completed 7/26/90

NEPA process completed (MTF) 9/6/90

Cooperative agreement awarded 10/13/90

Ground breaking/construction started 6/91

Design completed 8/91

Construction completed;Operation initiated 11/92

Long-term operationsstarted 4/93

Operation completed 1/95

Restorationcompleted 11/95

Pr

• Operating costs were 

ential and the value o

cause GR reduces SO

coal.
48 Completed Projects 2003

Project SummaryThe demonstration established that GR-LNB offers acost-effective option for deep NOx reductions on wallfired boilers. GR-LNB NOx control performance approached that of selective catalytic reduction (SCR), but

at significantly lower cost. The importance of cost-effective technology for deep NOx reductions is that it meets

the need for NOx reduction in ozone nonattainment areas

beyond what is currently projected in Title IV of theCAAA. Title I of the CAAA deals with ozone nonattainment and is currently the driving force for deep NOx reduction in many regions of the country. Even for the more

stringent levels required under Title I, GR-LNB can beused to reduce the size and cost of downstream treatment.The GR-LNB was installed and evaluated on a 172-MWe(gross) wall-fired boiler—a Babcock & Wilcox balancedA worker inspects the support ring for the Foster Wheeler lowNOx burner installed in the boiler wall. 

Baseline (lb/106 Btu) 

Avg NOx reduction (%) LNB 

GR-LNB 

Avg gas heat input (%) 

Ex

NOx Data f

Station

draft pulverized coal-fired unit. The GR system, includingan overfire air system, was designed and installed byEnergy and Environmental Research Corporation. TheLNBs were designed and installed by Foster WheelerEnergy Corp.Parametric testing began in October 1992 and was completed in April 1993. The parametric tests examined theeffect of process variables (such as zone stoichiometricratio, percent gas heat input, percent overfire air, andload) on NOx reduction, SO2 reduction, CO emissions,

carbon-in-ash, and heat rates. The baseline performanceof the LNB was also established.Environmental PerformanceAt a constant load (150 MWe) and a constant oxygenlevel at the boiler exit, NOx emissions were reduced with

increasing gas heat input. At gas heat inputs greater than10%, NOx emissions were reduced marginally as gas heat

input increased. Natural gas also reduced SO2 emissions

in proportion to the gas heat input. At the Cherokee Station, low-sulfur (0.40%) coal is used, and typical SO2

emissions are 0.65 lb/106 Btu. With a gas heat input of

20%, SO2 emissions decreased by 20% to 0.52 lb/106 Btu.

The CO2 emissions were also reduced as a result of using

natural gas because it has a lower carbon-to-hydrogenratio than coal. At a gas heat input of 20%, the CO2 emissions were reduced by 8%.

Long-term testing was initiated in April 1993 and completed in January 1995. The objectives of the test were toobtain operating data over an extended period when theunit was in routine commercial service, determine theeffect of GR-LNB operation on the unit, and obtain incremental maintenance and operating costs with GR.During long-term testing, it was determined that flue gasrecirculation had minimal effect on NOx emissions.

A second series of tests was added to the demonstrationto evaluate a modified or second-generation system.Modifications included the following:• The FGR system, originally designed to provide momentum to the natural gas, was removed. (This

change significantly reduced capital costs.)

• Natural gas injection was optimized at 10% gas heat

input compared to the initial design value of 18%.

• Removal of the flue ga

installation of high-vegreater use of availablmodification reduced nating costs.)

• Overfire air ports were 

momentum, particular

Over 4,000 hours of operresults shown in Exhibit 2

duction performance of L45%, the overall objectivmet. Boiler efficiency decreburning due to increasefrom natural gas use. Furttube wear, and only small during the GR-LNB demoalone, carbon-in-ash and acceptable levels.Economic PerformancGR-LNB is a retrofit techbenefits are dependent on factors:• Gas availability at the • Gas/coal cost different• Boiler efficiency,
• SO2 removal requirements, and

• Value of SO2 emission credits.

Based on the demonstration, GR-LNB is expected toachieve at least a 64% NOx reduction with a gas heat

input of 12.5%. The capital cost estimate for a 300-MWewall-fired installation is $26.01/kW (1996$), plus gaspipeline costs, if required. This cost includes both equipment and installation costs and a 15% contingency. TheGR and LNB system capital costs can be easily separatedfrom one another because they are independent systems.The capital cost for the GR system only is estimated at$12.14/kW. The LNB system capital cost is $13.87/kW.Operating costs are almost entirely related to the differential cost of natural gas and coal and reduced by the valueof the SO2 emission credits received due to absence of

sulfur in the gas. A fuel differential of $1.00/106 Btu was

used because gas costs more than coal on a heating valuebasis. Boiler efficiency was estimated to decline by0.80%; the cost of this decline was calculated using acomposite fuel cost of $1.67/106 Btu. Overfire air booster

and cooling fan auxiliary loads will be partially offset bylower loads on the pulverizers. No additional operatinglabor is required, but there is an increase in maintenancecosts. Allowances also were made for overhead, taxes,and insurance. Based on these assumptions and assumingan SO2 credit allowance of $95/ton (Feb. 1996$), the net

operating cost is $2.14 million per year and the NOx removal cost is $786/ton (constant 1996$).

Commercial ApplicationsThe technology can be used in retrofit, repowering, orgreenfield installations of wall-fired boilers. There is noknown limit to the size or scope of the application of thistechnology combination. GR-LNB is expected to be lesscapital intensive, or less costly, than selective catalytic reduction. GR-LNB functions equally well with any kind of coal.Public Service Company of Colorado, the host utility,decided to retain the low-NOx burners and the gas-reburning system for immediate use; however, a restoration was

required to remove the flue gas recirculation system.This demonstration project was one of two that receivedthe Air and Waste Management Association’s 1997 J.Deane Sensenbaugh Award.

ContactsBlair A. Folsom, Sr., V.P., (949) 859-8851, ext. 140

General Electric Energy and Environmental Research Corporation18 MasonIrvine CA 92618blair.folsom@ps.ge.com(949) 859-3194 (fax)

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Thomas A. Sarkus, NETL, (412) 386-5981

sarkus@netl.doe.gov

ReferencesEvaluation of Gas Reburning and Low-NOx Burners on a

Wall-Fired Boiler: Performance and Economics Report,Gas Reburning—Low-NOx Burner System, Cherokee

Station Unit No. 3, Public Service Company of Colorado.

Final Report. July 1998.Guideline Manual: Gas Reburning—Low-NOx Burner

System, Cherokee Station Unit No. 3. Public ServiceCompany of Colorado. Final Report. July 1998.Evaluation of Gas Reburning and Low-NOx Burners on a

Wall-Fired Boiler (Long-Term Testing, April 1993–January 1995). Report No. DOE/PC/90547-T20. Energy andEnvironmental Research Corporation. June 1995. (Available from NTIS as DE95017755.)Evaluation of Gas Reburning and Low-NOx Burners on aWall-Fired Boiler (Optimization Testing, November1992–April 1993). Report No. DOE/PC/90547-T19. Energy and Environmental Research Corporation. June1995. (Available from NTIS as DE95017754.)Evaluation of Gas Reburning and Low-NOx Burners on aWall-Fired Boiler—Project Performance Summary. U.S.Department of Energy. October 2001.
50 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesNO

x Control Technologies

Micronized Coal ReburningDemonstration for NO

x

ControlProject completedParticipantNew York State Electric & Gas Corporation (NYSEG)Additional Team MembersEastman Kodak Company—host and cofunderCONSOL (formerly Consolidation Coal Company)—

coal sample tester

DB Riley—technology supplierFuller Company—technology supplierEnergy and Environmental Research Corporation (EER)

—reburn system designer

New York State Energy Research and Development

Authority—cofunder

Empire State Electric Energy Research Corporation—

cofunder

LocationsLansing, Tompkins County, NY (NYSEG’s Milliken Station, Unit No. 1). This station is currently owned by AESCorporation and is designated AES Cayuga.Rochester, Monroe County, NY (Eastman KodakCompany’s Kodak Park Power Plant, Unit No. 15)TechnologyMicronized coal reburning using DB Riley’s MPS mill (atMilliken Station) and Fuller’s MicroMillTM (at EastmanKodak) technologies for producing micronized coalPlant Capacity/ProductionMilliken Station: 148-MWe tangentially fired boilerKodak Park: 60-MWe cyclone boiler

CoalPittsburgh seam bituminous, medium- to high-sulfur(3.2% sulfur and 1.5% nitrogen at Milliken and 2.2%sulfur and 1.6% nitrogen at Kodak Park)Project FundingTotal $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 (ESP)performance.

Technology/Project DThe reburn coal, which ctotal fuel, is micronized (p325 mesh) and injected inabove the primary combusgentially fired boiler site, N

close-coupled overfire air top coal injector of the LNinjecting the micronized csystem completes combusers and air ports are adjustby re-aiming them to creatlean outer zone providing Park cyclone boiler site, thproduce the micronized coabove the cyclone combusto complete the combustio
Calendar Year

 3 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 

Results SummaryEnvironmental• Using a 14.4% reburn fuel heat input on the Milliken

Station tangentially fired boiler at full load resulted ina NO

x

 emission rate of 0.25 lb/106 Btu, which represents a 29% NO

x

 reduction from the 0.35 lb/106 Btu

achieved with the LNCFS IIITM burner alone (baseline).

• Using a 17.3% reburn fuel heat input (reburn stoichiometry of 0.89) on the Kodak Park cyclone boiler

resulted in a NO

x

 emission rate of 0.59 lb/106 Btu,

which represents a 59% NOx reduction from 1.36

lb/106 Btu (baseline). Higher reburn rates (estimated at

18.4% reburn or stoichiometry of 0.87) would be required for long-term compliance with 0.60 lb/106 Btu

NO

x

 emission limits.

Operational• Reburning was successfully applied at Milliken Station

using the top coal injector of the LNCFS IIITM burnerfor the reburn fuel and reducing the top burner levelair flows. This eliminated the need for a separate

reburn system. Testing on the tangentially firedboiler at Milliken Station showed:

– Unburned carbon in ash, also referred to as losson-ignition (LOI), was maintained under 5%;– Increasing the economizer O2 generated the

classical response of higher NOx emissions and

lower LOI—the sensitivity was estimated at0.1 lb/106 Btu per 1% change in O2 and was relatively independent of coal fineness;

– Increasing coal fineness reduced both NOx emissions and LOI—the effect on NO

x was significant

only for large variations in coal fineness; and

– Pulverizing the reburn coal to the micronized level

(greater than 80% passing 325 mesh) was not arequirement for the successful application of reburning, but significantly impacted LOI.

• Testing on the cyclone boiler at Kodak Park showed:

– The reburn stoichiometry had a significant effect

on both NO

x

 emissions and LOI—lower reburn

stoichiometries reduced NO

x

 emissions and increased LOI to 40–45% compared with a LOI

baseline of 10–15%.

– Short-term testing 

maintained at levout significantly a

taining a baseline 

Economic• The estimated capital 

300-MWe tangentiallreburning is $4.3 mill(1999$). The corresp$0.30 million per yeayear levelized cost is 

rent 1999$) or $1,023 

• The estimated capita

300-MWe cyclone boing is $16.9 million, (1999$). The correspat $0.80 million per ylevelized cost is $74

1999$) or $571/ton (

3/97

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

9/91 7/92

DOE selectedproject (CCTDPIV) 9/12/91

Design and Construction Operation and Reporting

Operation complete

Ground breaking/construction started (Lansing) 3/15/96

Design completed (Rochester) 9/96

Ground breaking/construction started (Rochester) 9/8/96

NEPA process completed(CX) 8/13/92

Cooperative agreement awarded 7/28/92

Preoperational tests initiated (Rochester) 1/97

Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

Operation initiated (Rochester) 4/97

Environmental monitoring plan completed (Environmental monitoring plan completed (

Construction completed (Lansing) 1/97

Operation initiated (Lansing) 3/97

Project relocated to Lansing and Rochester 12/95

Operation 

Fin
52 Completed Projects 2003

Project SummaryNYSEG demonstrated the micronized coal reburningtechnology in both tangentially fired and cyclone boilers.The tangentially fired boiler was NYSEG’s Milliken Station 148-MWe tangentially fired Unit No. 1 (also the hostfor another CCT Program demonstration). The cycloneboiler was Eastman Kodak Company’s Kodak Park PowerPlant 60-MWe cyclone Unit No. 15.The challenge with this coal reburning demonstration wasto achieve adequate combustion of the reburn coal in theoxygen-deficient, short-residence-time reburn zone toreduce NOx emissions without detrimentally increasing

the unburned carbon in the ash, i.e., loss-on-ignition. The

primary objective of this two-site project was to demonstrate improvements in coal reburning for NOx emission

control by reducing the particle size of the reburn coal. Inthis demonstration, the coal was finely ground to 80% ormore passing 325 mesh and injected into the boilersabove the primary combustion zone. The resulting typicalparticle size is 20 microns compared to 60 microns fornormal pulverized coal particles. This smaller size increases surface area ninefold.With this increased surface area and coal fineness (micronized coal has the combustion characteristics of atomized oil), carbon combustion occurs in milliseconds andvolatiles are released at an even rate.Operating PerformanceAt the Milliken Station, the existing ABB Low-NOx Concentric Firing SystemTM (LNCFS-III), which includes

both CCOFA and separated overfire air (SOFA) ports, wasused for the reburn demonstration. Four DB Riley MPS150 mills with dynamic classifiers provided the pulverized coal. With LNCFS-III, there are four levels of burners. To simulate and test the coal reburning application,the top-level coal injection nozzles fed micronized coal tothe upper part of the furnace for this demonstration. Thecoal injection nozzles at the three lower elevations werebiased to carry approximately 80% of the fuel required forfull load. The speed of the dynamic classifier serving themill feeding the top burners was increased to produce themicronized coal (greater than 80% passing 325 mesh).

During the evaluation, several conclusions were reachedon how operating variables affected performance. Whilemaintaining a constant economizer O2 level, no single

operating variable had a dominant effect on reburningperformance. A combination of operating settings determined from short-term testing were selected for long-termoperation to achieve the lowest NOx emissions and reliable operation. Operating settings for long-term operation

were 14–16% reburn coal, 105 rpm top mill classifierspeed (corresponds to 70–72% passing 325 mesh), –5degrees main burner tilt and 2.8% economizer O2. No

additional improvement in LOI was observed at top millclassifier speeds above 105 rpm.At Kodak Park, EER designed the micronized coal reburnsystem using a combination of analytical and empiricaltechniques. The reburn fuel and overfire air (OFA) injection components were designed with a high degree offlexibility to allow for field optimization to accommodatethe complex furnace flow patterns in the cyclone boiler.Two Fuller MicroMillsTM were installed in parallel onKodak Park Unit No. 15 to provide the capacity necessaryfor high reburn rates, with the second mill serving as aspare at lower reburn rates. The mills produced the micronized coal reburn fuel at greater than 90% passing 325mesh. Eight injectors, six on the rear wall and one oneach of the side walls, introduced the micronized coalinto the reburn zone. The optimization variables includedthe number of injectors, swirl, and velocity. Four ports onthe front wall provided OFA using EER’s second-generation, dual-concentric overfire air design, which has variableinjection velocity and swirl. To maximize NOx reduction,

the reburn fuel was injected with flue gas rather than air.The flue gas was extracted downstream of the electrostaticprecipitator and was boosted by a single fan. A new boilercontrol system was also installed on Unit No. 15.Environmental PerformanceAt the Milliken Station, micronized coal reburning with14.4% reburn fuel at full load reduced NOx emissions from

the 0.35 lb/106 Btu baseline level to 0.25 lb/106 Btu, a 29%

reduction. This reduction represents an addition to the 39%reduction achieved with the LNCFS IIITM low-NOx burner

alone. Boiler efficiency was maintained at 88.4–88.8%.Furthermore, concentrating the overfire air through fewer

and higher ports and using tained LOI below 5%. Basing of 23 days of continuoannual NOx emissions usin

were estimated at 0.245 ± dence), and the estimated 0.4%. Based on replicated confidence level, variation

0.006 lb/106 Btu and in fly 

age points were assumed tThere were large uncertainLOI, possibly because LOtively narrow range (betwchanging operating variabWith regard to reburn coaquantity, using a finer grinboth NOx emissions and L

significant (relative to the lb/106 Btu) only for relati

mill classifier speed (and finer grind coal (all mills) 

and LOI. Decreasing the r14% decreased NOx emis

Btu and had a minor effec1.5 percentage points). Th

creasing the coal reburn fexcess air levels in the pricoal was diverted to the loReducing the boiler load 

effect was greater when thservice. Thus, reducing thond mill out of service is the second mill out of serboiler load reduced NOx e

MW) and low (110 MW) longer residence times in Changes in air flow resultNOx reduction and LOI. A

transport air (top burner pr20% increase in the air-to-increased NOx emissions f

106 Btu. This increase in N

ing reburn zones with the 
oxidant with the reburn fuel. Increasing the top level auxiliary airflow increased both NOx emissions and LOI. This

increase in NOx was attributed to less reducing reburn

zones as more oxidant was introduced through the auxiliaryair nozzle situated directly below the reburn coal nozzle.The increase in LOI from increasing the top level auxiliaryairflow was attributed to lower excess air levels in the primary combustion zone as more air was diverted away fromthe lower burners. Increasing the economizer O2 generated

the classical response of higher NOx emissions and lower

or stable LOI. The economizer O2 sensitivity was estimated

at 0.1 lb NOx/106 Btu per 1% change in O2 and was relatively independent of the reburn coal fineness.

The SOFA and main burner tilts had minimal effects onperformance. Variations in the SOFA tilt between 0 and15 degrees (above horizontal) had minor effects on bothNOx emissions and LOI in both LNCFS IIITM and reburn

configurations. Operating the main burner tilt slightlybelow the horizontal (about -5 degrees) improved thereburning performance (lower LOI without increasingNOx), relative to the horizontal setting, which was attributed to longer residence times in the furnace prior to overfire air introduction. Overall, the effect was difficult toquantify due to the limited number of tests.At Kodak Park, the application of micronized coal reburning reduced NOx emissions and increased LOI, as

expected. Micronized coal reburning with 17.3% reburnfuel at a reburn stoichometry of 0.89 reduced NOx emissions to 0.59 lb/106 Btu from a baseline of 1.36

lb/106 Btu, a 59% reduction, and reduced the boiler efficiency from 87.8% to 87.3%. At greater reburn rates,

further NOx reduction was achieved to a degree comparable with gas reburning systems. At full load, LOI was

40–45%, compared with a baseline level of 10–12%.Based on long-term testing, the achievable annual NOx

emissions (at 15.6% reburn or stoichiometry of 0.90)were 0.69 ± 0.03 lb/106 Btu (95% confidence), corresponding to an LOI of 38% ± 2%. Higher reburn feeds

(estimated at 18.4% reburn or stoichiometry of 0.87)would be required for long-term compliance with the0.6 lb/106 Btu NOx emissions limit.

The reburn stoichiometry had a significant effect on NOx

emissions and a significant effect on the LOI. Lowerreburn stoichiometries reduced NOx emissions and increased the LOI, typically dropping below 0.6 lb/106 Btu

at reburn stoichiometries below 0.9 and corresponding to40–45% LOI. The increase in the LOI relative to baselinewas partially due to a lower cyclone heat input, whichresulted in lower temperatures in the primary combustionzone. The lower temperatures produced less thermal NOx

formation and less efficient char burnout. The LOI increase was also partially due to the staged combustionresulting in shorter residence times under oxidizing conditions. At constant heat input levels, the LOI was notsignificantly different with or without reburning, suggesting that in reburn applications, the LOI could be maintained at levels similar to baseline by maintaining a highcyclone heat input. The contribution of reburning alone(assuming no change in the cyclone heat input) to theincrease in the LOI was estimated at 0–12% (absolute).Economic PerformanceEstimates were prepared for retrofitting micronized coalreburning on generic 300-MWe tangentially fired andcyclone boilers. For the tangentially fired boiler, the capital costs were estimated at $4.3 million, or approximately$14/kW (1999$). The O&M costs were estimated at $0.30million per year (1999$). Costs were levelized both on acurrent dollar and constant dollar basis. The 15-year levelized cost for the 300-MWe unit is $1,329/ton of NOxremoved on a current dollar basis, and $1,023/ton of NOxremoved on a constant dollar basis (1999$).For the cyclone boiler, the estimated capital cost is $16.9million, or approximately $56/kW (1999$). The estimatedO&M costs are $0.80 million per year (1999$). The total15-year levelized cost is $741/ton of NOx removed on a

current dollar basis or $571 on a constant dollar basis(1999$).Commercial ApplicationsMicronized coal reburning technology can be applied toexisting and greenfield cyclone-fired, wall-fired, andtangentially fired pulverized coal units. The technologyreduces NOx emissions by 20–59% with minimal furnace

modifications for existing units.

The availability of a coafuel to the furnace, enabvalue coals without boilachieve a turndown of 8out consuming expensivContactsJim Harvilla, (607) 762-

New York State ElecCorporate Drive—KP.O. Box 5224Binghamton, NY 139jjharvilla@nyseg.com(607) 762-4002 (fax)

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Thomas A. Sarkus, NET

sarkus@netl.doe.gov

ReferencesMicronized Coal Reburn

Control. Final Report. NCorporation and CONSReburning Technologies ides from Coal-Fired BoBabcock & Wilcox, EER Report No. 14. May 199“Micronized Coal Rebu

trol.” Sixth Clean Coal cal Papers. Savichky et 
54 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesNO

x Control Technologies

Demonstration of SelectiveCatalytic ReductionTechnology for the Control ofNO

x Emissions from HighSulfur, Coal-Fired Boilers

Project completedParticipantSouthern Company Services, Inc.Additional Team MembersElectric Power Research Institute—cofunderOntario Hydro—cofunderGulf Power Company—hostLocationPensacola, Escambia County, FL (Gulf Power Company’sPlant Crist, Unit No. 5)TechnologySelective catalytic reduction (SCR)Plant Capacity/Production8.7-MWe equivalent (three 2.5-MWe and six 0.2-MWeequivalent SCR reactor plants)CoalIllinois bituminous, 2.7% sulfurProject FundingTotal $23,229,729 100%DOE 9,406,673 40Participant 13,823,056 60Project ObjectiveTo evaluate the performance of commercially availableSCR catalysts when applied to operating conditions foundin U.S. pulverized coal-fired utility boilers using highsulfur U.S. coal under various operating conditions, while achieving as much as 80% NOx removal. Technology/Project Description The SCR technology consists of injecting ammonia into boiler flue gas and passing it through a catalyst bed where the NOx 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 were calcu- lated to be large enough to produce design data that will allow the SCR process to be scaled up to commercial size. Catalyst suppliers (two U.S., two European, and two Japanese) provided eight catalysts with various shapes and chemical compositions for evaluation of process chemistry and economics 

demonstration. The project demonstratedof flue gas, the applicabilvide a cost-effective mean

from power plants burninThe demonstration plant, Power Company’s Plant Cused flue gas from the bu
Calendar Year

 3 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 

Results SummaryEnvironmental• NO

x reductions of over 80 percent were achieved at an

ammonia slip well under the 5 ppm deemed acceptablefor commercial operation.

• For most catalysts, flow rates could be increased to

150 percent of design without exceeding the ammoniaslip design level of 5 ppm at 80 percent NOx

reduction.

• While catalyst performance increased above 700 °F,

the benefit did not outweigh the heat rate penalties.

• Ammonia slip, a sign of catalyst deactivation, went

from less than 1 ppm to approximately 3 ppm over thenearly 12,000 hours of operation, thus demonstratingthat deactivation in coal-fired units was in line withworldwide experience.

• Long-term testing showed that SO2 oxidation was

within or below the design limits necessary to protectdownstream equipment.

Operational• Fouling of catalysts was controlled by adequate sootblowing procedures.• Long-term testing showed that catalyst erosion was not

a problem once sootblowing procedures were adopted.

• Air preheater performance was degraded because of

ammonia slip and subsequent by-product formation;however, solutions were identified.

• The SCR process did not significantly affect the results

of Toxicity Characteristic Leaching Procedure (TCLP)analysis of the fly ash.

Economic• Levelized costs on a 30-year basis for a 250-MWe unit,

with a SCR inlet NO

x

 concentration of 0.35 lb/106 Btu,

were 2.39, 2.57, and 2.79 mills/kWh (constant 1996$)for 40, 60, and 80 percent removal efficiency, respectively, which equates to 3,502; 2,500; and 2,036 $/ton(constant 1996$), respectively.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward

9/88

Design and Construction Operation and Reporting

6/90

DOE selected project(CCTDP-II) 9/28/88

NEPA processcompleted(MTF) 8/16/89

Cooperative agreementawarded 6/14/90

Ground breaking/construction started 3/92

7/93

Preoperational tests initiated 3/93Environmental monitoring plan completed 3/11/93

Construction completed 2/93

Design completed 12/92

Operation initiated 7/93

Operation completed 7/9
56 Completed Projects 2003

Project SummaryThe demonstration tests were designed to address severaluncertainties, including potential catalyst deactivation dueto poisoning by trace metals species in U.S. coals, performance of the technology and its effects on the balance-ofplant equipment in the presence of high amounts of SO2and SO3, and performance of the SCR catalyst under

typical U.S. high-sulfur coal-fired utility operating conditions. Catalyst suppliers were required to design the catalyst baskets to match predetermined reactor dimensions,provide a maximum of four catalyst layers, and meet theconditions shown in Exhibit 27.The catalysts tested are listed in Exhibit 28. Catalyst suppliers were given great latitude in providing the amountof catalyst for this demonstration.Environmental PerformanceAmmonia slip, the controlling factor in the long-termoperation of commercial SCR, was usually <5 ppm because of plant and operational considerations. Ammonia

slip was dependent on catalyst exposure time, flow rate,temperature, NH3/NOx distribution, and NH3/NOx ratio

(NOx reduction). Changes in NH3/NOx ratio and consequently NOx reduction generally produced the most significant changes in ammonia slip. The ammonia slip at

60% NOx reduction was at or near the detection limit of

1 ppm. As NOx reduction was increased above 80%, amParameter Minimum Baseline Maximum

Temperature (oF) 620 700 750

NH3/NOx molar ratio 0.6 0.8 1.0

Space velocity(% design flow) 60 100 150Flow rateLarge reactor (scfm) 3,000 5,000 7,500

Small reactor (scfm) 240 400 600

Exhibit 27

Reactor Baseline Conditions

Exhibit 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

Ex

Average SO

(Ba

monia slip also increased and remained at reasonablelevels up to NOx reductions of 90%. Over 90%, the ammonia slip levels increased dramatically.

The flow rate and temperature effects on NOx reduction

were also measured. In general, flows could be increasedto 150% of design without the ammonia slip exceeding 5ppm, at 80% NOx reduction and at the design temperature. With respect to temperature, most catalysts exhibited

fairly significant improvements in overall performance astemperatures increased from 620 °F to 700 °F, but relatively little improvement as temperature increased from700 °F to 750 °F. The conclusion was that the benefits ofhigh-temperature operation probably do not outweigh theheat rate penalties involved in operating SCR at thehigher temperatures.Catalyst deactivation was observed by an increase in ammonia slip over time, assuming the NOx reduction efficiency was held constant. Over the 12,000 hours of the

demonstration tests, the ammonia slip did increase fromless than 1 ppm to approximately 3 ppm. These resultsdemonstrated the maturity of catalyst design and thatdeactivation was in line with prior worldwide experience.Experience has shown that the catalytic active species thatresult in NOx reduction often contributed to SO2 oxidation

(i.e., SO3 formation), whi

stream equipment. In gen

creased as the tolerance fo

upper bound for SO2 oxid

catalyst was set at 0.75% age SO2 oxidation rate for 

in Exhibit 29. These data the life of the demonstratiwithin design limits, with below the design limit.Other factors affecting SO

temperature. Most of the stant SO2 oxidation with r

velocity). In theory, SO2 o

proportional to flow rate. between SO2 oxidation an

nential as temperature incshowed the relationship to in SO2 oxidation between 

other hand, between 700 

tion increased more signiOther findings from the ddrop, fouling, erosion, air 
Exhibit 32

SCR Economics by NOx Removal

40% 60% 80%

Capital cost ($/kW) 52 54 57Operating costs ($/yr) 926,000 1,045,000 1,181,000Constant 1996$ levelized costmills/kWh 2.39 2.57 2.79$/ton NOx removed 3,502 2,500 2,036Note: 250MWe; 0.35 lb/106 Btu of inlet NOx

Exhibit 30

SCR Design Criteria for

Economic Evaluation

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 catalyst cost $400/ft3

125 MWe 250 MWe 700 MWe

Capital cost ($/kW) 61 54 45Operating cost ($/yr) 580,000 1,045,000 2,667,000Constant 1996$ levelized costMills/kWh 2.89 2.57 2.22$/ton NOx removed 2,811 2,500 2,165Note: 30 year life; 60% NOx removal

Exhibit 31

SCR Economics by Unit Size

nia volatilization, and TCLP analysis. Overall reactorpressure drop was a function of the catalyst geometry andvolume, but tests were inconclusive in determining whichparameter was controlling. The fouling characteristics ofthe catalyst were important to long-term operation. During the demonstration, measurements showed a relativelylevel pressure drop over time, indicating that sootblowingprocedures were effective. The plate-type configurationhad somewhat less fouling potential than did the honeycomb configuration, but both were acceptable. Catalysterosion was not considered to be a significant problembecause most of the erosion was attributed to aggressivesootblowing. With regard to air preheater performance,the demonstration showed that the SCR process exacerbated performance degradation of the air preheaters,mainly due to ammonia slip and subsequent by-productformation. Regenerator-type air heaters outperformedrecuperators in SCR applications in terms of both thermalperformance and fouling. The ammonia volatilized fromthe SCR fly ash when a significant amount of water wasabsorbed by the ash. This was caused by formation of amoist layer on the ash with a pH high enough to convertammonia compounds in the ash to gas-phase ammonia.TCLP analyses were performed on fly ash samples. The

SCR process did not significantly affect the toxics leachability of the fly ash.Economic PerformanceAn economic evaluation was performed for full-scaleapplications of SCR technology to a new 250-MWepulverized coal-fired plant located in a rural area withminimal space limitations. The fuel considered was highsulfur Illinois No. 6 coal. Other key base case designcriteria are shown in Exhibit 30.The economic analysis of capital, operating and maintenance (O&M), and levelized cost for various unit sizesfor an SCR system are shown in Exhibit 31. Results ofthe economic analysis of capital, O&M, and levelized

cost for various NOx rem

unit are shown in Exhibestimated capital costs wthe size of the installatiothe retrofit. The levelizetions were $1,850–5,10Commercial ApplicaAs a result of this demobeen shown to be applicgenerating capacity for r

of virtually any size boifired utility boilers in acUnited States; these boicapacity of approximateContactsLarry Monroe, (205) 25

Southern Company SMail Stop 14N-8195P.O. Box 2641Birmingham, AL 352lsmonroe@southernc(205) 257-5367 (fax)

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Thomas A. Sarkus, NET

sarkus@netl.doe.gov

References“Demonstration of SCR NOx Emissions from Hig

ers.” Fifth Annual CleaTechnical Papers. MaxwDemonstration of SCR T

Emissions from High-SuFinal Report. Vol. 1. So

October 1996. (AvailablDE97050873, Vol. 2: Aand Vol. 3: Appendixes U.S. Department of EneCatalytic Reduction for from High-Sulfur, Coal-Performance Summary. 
58 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesNO

x Control Technologies

180-MWe Demonstration ofAdvanced Tangentially FiredCombustion Techniques forthe Reduction of NO

x

Emissions from Coal-FiredBoilersProject completedParticipantSouthern Company Services, Inc.Additional Team MembersGulf Power Company—cofunder and hostElectric Power Research Institute—cofunderABB Combustion Engineering, Inc.—cofunder and

technology supplier

LocationLynn Haven, Bay County, FL (Gulf Power Company’sPlant Lansing Smith, Unit No. 2)TechnologyABB Combustion Engineering’s Low-NOx Concentric

Firing System (LNCFSTM) with advanced overfire air(AOFA), clustered coal nozzles, and offset airPlant Capacity/Production180 MWeCoalEastern bituminous, high reactivityProject FundingTotal $8,553,665 100%DOE 4,149,382 49Participant 4,404,283 51

Project ObjectiveTo demonstrate in a stepwise fashion the short- and longterm NO

x reduction capabilities of LNCFSTM levels I, II,

and III on a single reference boiler.Technology/Project DescriptionTechnologies demonstrated included LNCFSTM levels I,II, and III. Each level of the LNCFSTM used differentcombinations of overfire air and clustered coal nozzlepositioning to achieve NOx reductions. With the

LNCFSTM, primary air and coal are surrounded by oxygen-rich secondary air that blankets the outer regions ofthe combustion zone. LNCFSTM I used a close-coupledoverfire air (CCOFA) system integrated directly into thewindbox of the boiler. A separated overfire air (SOFA)system located above the combustion zone was featuredin the LNCFSTM II system. This was an advanced overfire

air system that incorporatmeasurement capabilitiesused in the LNCFSTM III Carefully controlled shortlowed by long-term testinconditions. Long-term tesmonths for each phase, becharacteristics of each tecbased on long-term test d

LNCFS is a trademark of ABB Combustion Engineering, Inc.
Calendar Year

 3 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 

Results SummaryEnvironmental• At full load, the NOx emissions using LNCFSTM I, II,

and III were 0.39, 0.39, and 0.34 lb/106 Btu, respectively, which represent reductions of 37, 37, and 45%

from the baseline emissions, respectively.

• Emissions with LNCFSTM were not sensitive to power

outputs between 100 MWe and 200 MWe, but emissions increased significantly below 100 MWe, reaching baseline emission levels at 70 MWe.

• Because of reduced effectiveness at low loads,

LNCFSTM proved marginal as a compliance option forpeaking load conditions.

• Average CO emissions increased at full load.• Air toxics testing found LNCFSTM to have no clear-cut

effect on the emissions of trace metals or acid gases.Volatile organic compounds (VOCs) appeared to bereduced and semi-volatile compounds increased.

Operational• Loss-on-ignition (LOI) was not sensitive to the

LNCFSTM retrofits, but very sensitive to coal fineness.

• Furnace slagging was reduced, but backpass fouling

was increased for LNCFSTM II and III.

• Boiler efficiency and unit heat rate were impacted

minimally.

• Unit operation was not significantly affected, but operating flexibility of the unit was reduced at low loads

with LNCFSTM II and III.

Economic• The capital cost estimate for LNCFSTM I was

$5–15/kW, and for LNCFSTM II and III, $15–25/kW(1993$).

• The cost-effectiveness for LNCFSTM I was $103/ton of

NO

x removed; LNCFSTM II, $444/ton; and LNCFSTM

III, $400/ton (1993$).

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward Operation and Reporting

9/88 9/90

Design and Construction

Project completed/final report issued 6/94

6/94

Environmental monitoringplan completed 12/27/90

Ground breaking/construction started 11/90

Design completed 4/91

Constructioncompleted 5/91Operation initiated 5/91 Operation completed 12/92

NEPA processcompleted (MTF)7/21/89

DOE selectedproject(CCTDP-II)9/28/88

Cooperative agreement awarded 9/20/90

5/91
60 Completed Projects 2003

Project SummaryLNCFSTM technology was designed for tangentially firedboilers, which represent a large percentage of the preNSPS coal-fired generating capacity. The technologyreduces NOx by staging combustion vertically in the

boiler with separate coal and air injectors, and horizontally by creating fuel-rich and lean zones with offset airnozzles. The objective was to determine NOx emission

reductions and impact on boiler performance under normal dispatch and operating conditions over the long term.By using the same boiler, the demonstration provideddirect comparative performance analysis of the threeconfigurations. Short-term parametric testing enabledextrapolation of results to other tangentially fired unitsby evaluating the relationship between NOx emissions

and key operating parameters.At the time of the demonstration, specific NOx emission

regulations were being formulated under the CAAA. Thedata developed over the course of this project providedneeded real-time input to regulation development.Exhibit 33 shows the various LNCFSTM configurationsused to achieve staged combustion. In addition to overfireair, the LNCFSTM incorporates other NOx-reducing techniques into the combustion process as shown in Exhibit

34. Using offset air, two concentric circular combustionregions are formed. The majority of the coal is containedin the fuel-rich zone. This region is surrounded by a fuellean zone containing combustion air. The size of thisouter annulus of combustion air can be varied using adjustable offset air nozzles.Operational PerformanceExhibit 35 summarizes the impacts of LNCFSTM on unitperformance.Environmental PerformanceAt full load, LNCFSTM I, II, and III reduced NOx emissions by 37, 37, and 45%, respectively. Exhibit 36 presents the NOx emission estimates obtained from the

assessment of the average annual NOx emissions for three

dispatch scenarios.Air toxics testing found LNCFSTM to have no clear-cuteffect on the emission of trace metals or acid gases. The

Exhibit 33

LNCFSTM Configurations

Ex

Concentric 

data provided marginal evidence for a decreased emissionof chromium. The effect on aldehydes/ketones could notbe assessed because baseline data were compromised.VOCs appeared to be reduced and semi-volatile compounds increased. The increase in semi-volatile compounds was deemed to be consistent with increases in theamount of unburned carbon in the ash.Economic PerformanceLNCFSTM II was the only complete retrofit (LNCFSTM Iand III were modifications of LNCFSTM II), and thereforecapital cost estimates were based on the Lansing SmithUnit No. 2 retrofit as well as other tangentially firedLNCFSTM retrofits. The capital cost ranges in 1993 dollars follow:• LNCFSTM I—$5–15/kW• LNCFSTM II—$15–25/kW• LNCFSTM III—$15–25/kW

Site-specific consideratiocapital costs; however, thexperience and are plannicost for LNCFSTM II at Lmillion, or $17/kW, which range.The cost-effectiveness of based on the capital and oand the NOx removal effi

cost-effectiveness of the L(based on a levelization fdollars):• LNCFSTM I—$103/ton 

• LNCFSTM II—$444/to

• LNCFSTM III—$400/t

Commercial ApplicatiThe LNCFSTM technology plication to all the 423 U.fired utility units. These u
Exhibit 35

Unit Performance Impacts Based on Long-Term Testing

Baseline LNCFSTM I LNCFSTM II LNCFSTM III

Avg CO at full load (ppm) 10 12 22 33Avg excess O2 at full load (%) 3.7 3.2 4.5 4.3LOI at full load (%) 4.8 4.6 4.2 5.9O2 (%) 4.0 3.9 5.3 4.7

Steam outlet conditions Satisfactory at full Full load: 5–10 oF Same as baseline 160–200 MWe:

load; low temper- lower than baseline satisfactory

atures at low loads Low loads: 10–30 oF 80 MWe: 15–35 oF

lower than baseline lower than baseline

Furnace slagging and Medium Medium Reduced slagging, Reduced slagging,

backpass fouling but increased fouling but increased foulingOperating flexibility Normal Same as baseline More care required More difficult to

at low loads operate than other

systems

Boiler efficiency (%) 90 90.2 89.7 89.85

Efficiency change (points) N/A +0.2 -0.3 -0.15Turbine heat rate (Btu/kWh) 9,000 9,011 9,000 9,000Unit net heat rate (Btu/kWh) 9,995 9,986 10,031 10,013Change (%) N/A -0.1 +0.36 +0.18

Exhibit 36

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

MWe in size and fire a wvolatile bituminous throContactsLarry Monroe, (205) 25

Southern Company SMail Stop 14N-8195P.O. Box 2641Birmingham, AL 352lsmonroe@southernc(205) 257-5367 (fax)

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Thomas A. Sarkus, NET

sarkus@netl.doe.gov

References180-MWe DemonstratioCombustion Techniques Oxide (NOx) Emissions f

Report and Key Project 89653-T14. Southern C1994. (Available from N180-MWe DemonstratioCombustion Techniques Oxide (NOx) Emissions fLansing Smith—Phase IMonitoring Program Revices, Inc. December 19180-MWe DemonstratioCombustion Techniques 

sions—Project Performaof Energy. June 1999.
62 Completed Projects 2003
Environmental Control Devi

Multi-Pollutant Control Techno
64 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesMulti-Pollutant Control TechnologiesSNOXTM Flue Gas CleaningDemonstration ProjectProject completedParticipantABB Environmental SystemsAdditional Team MembersOhio Coal Development Office—cofunderOhio Edison Company—cofunder and hostHaldor Topsoe a/s—patent owner for process technology,

catalysts, and WSA Condenser

Snamprogetti, U.S.A.—cofunder and process designerLocationNiles, Trumbull County, OH (Ohio Edison’s Niles Station, Unit No. 2)TechnologyHaldor Topsoe’s SNOXTM catalytic advanced flue gascleanup systemPlant Capacity/Production35-MWe equivalent slipstream from a 108-MWe boilerCoalOhio bituminous, 2.8% sulfurProject FundingTotal $31,438,408 100%DOE 15,719,200 50Participant 15,719,208 50Project ObjectiveTo demonstrate SNOXTM technology at an electric powerplant using U.S. high-sulfur coals in which it will catalytically remove 95% of SO2 and more than 90% of NOxfrom flue gas and produce a salable by-product of concentrated sulfuric acid.

Technology/Project DescriptionIn the SNOXTM process, the stack gas leaving the boiler iscleaned of fly ash in a high-efficiency fabric filter baghouse to minimize the cleaning frequency of the sulfuricacid catalyst in the downstream SO2 converter. The ashfree gas is reheated, and NOx is reacted with small quantities of ammonia in the first of two catalytic reactors

where the NO

x is converted to harmless nitrogen and

water vapor. The SO2 is oxidized to SO3 in a second catalytic converter. The gas then passes through a novel

glass-tube condenser that allows SO3 to hydrolyze to

concentrated sulfuric acid.Because the SO2 catalyst follows the NOx catalyst, any

unreacted ammonia (slip) is oxidized in the SO2 catalyst

largely to nitrogen and water vapor. Downstream foulingby ammonia compounds is eliminated, permitting operation at higher than norma

stoichiometries allow smareduction efficiencies. The technology was desig

and more than 90% of the 

duce a salable sulfuric aciThis was accomplished wout creating waste streamThe demonstration was coNiles Station in Niles, Ohtreated a 35-MWe equivathe 108-MWe Unit No. 2 sulfur Ohio coal. The prosame as for a full-scale cocial-scale components we

SNOX is a trademark of Haldor Topsoe a/s.
Calendar Year

 3 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 

Results SummaryEnvironmental• SO2 removal efficiency was normally in excess of 95%

for inlet concentrations, averaging about 2,000 ppm.

• NO

x reduction averaged 94% for inlet concentrations

ranging from 500–700 ppm.

• Particulate removal efficiency for the high-efficiency

fabric filter baghouse with SNOXTM system wasgreater than 99%.

• Sulfuric acid purity exceeded federal specifications for

Class I acid.

• Air toxics testing showed high capture efficiency of

most trace elements in the baghouse. A significantportion of the boron and almost all of the mercuryescaped to the stack; but selenium and cadmium, normally a problem, were effectively captured in the aciddrain, as were organic compounds.

• Absence of an alkali reagent contributed to elimination

of secondary pollution streams and no increases inCO2 emissions.

• Presence of the SO2 catalyst virtually eliminated CO

and hydrocarbon emissions.

Operational• Having the SO2 catalyst downstream of the NOx catalyst eliminated ammonia slip and allowed the SCR to

function more efficiently.

• Heat developed in the SNOXTM process was used to

enhance thermal efficiency.

Economic• Capital cost was estimated at $305/kW for a 500-MWe

unit firing 3.2% sulfur coal. The 15-year levelizedincremental cost was estimated at 6.1 mills/kWh,$219/ton of SO2 removed, and $198/ton of SO2 and

NO

x

 removed on a constant 1995 dollar basis.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

9/88

Preaward Design and Construction

Operation initiated 3/92

12/89 3/92

Cooperative agreement

awarded 12/20/89

NEPA process completed (MTF) 1/31/90

Construction completed 12/91Preoperational tests initiated 12/91

Dedication ceremony held 10/17/91Environmental monitoring plan completed 10/31/91

Design completed 8/91

Construction started 1/91

DOE selectedproject (CCTDP-II)9/28/88

7/96

Operation completed 12/94

Projefinal r
66 Completed Projects 2003

Project SummaryNo reagent was required for the SO2 removal step because

the SNOXTM process utilized an oxidation catalyst toconvert SO2 to SO3 and ultimately to sulfuric acid. As a

result, the process produced no waste streams.In order to demonstrate and evaluate the performance ofthe SNOXTM process, general operating data were collected and parametric tests conducted to characterize theprocess and equipment. The system operated for approximately 8,000 hours and produced more than 5,600 tons ofcommercial-grade sulfuric acid. Many of the tests for theSNOXTM system were conducted at three loads—75, 100,and 110% of design capacity.Environmental PerformanceParticulate emissions from the process were very low(<1 mg/Nm3) due to the characteristics of the SO2 catalyst

and the sulfuric acid condenser (WSA Condenser). TheNiles SNOXTM plant was fitted with a baghouse (ratherthan an ESP) on its inlet. This was not necessary for lowparticulate emissions, but rather was needed to maintainan acceptable cleaning frequency for the SO2 catalyst. At

operating temperature, the SO2 catalyst retained about

90% of the dust that entered the catalyst vessel because ofits sticky surface. Dust that passed through was subsequently removed in the WSA Condenser, which acted as acondensing particulate removal device (utilizing the dustparticulates as nuclei).Minimal or no increase in CO2 emissions by the process

resulted from two features—the lack of a carbonate-basedalkali reagent that releases CO2, and the fact that the process recovered additional heat from the flue gas to offset

its parasitic energy requirements. Under most designconditions this heat recovery results in the net heat rate ofthe boiler remaining the same or decreasing after additionof the SNOXTM process, and consequently no increaseoccurs in CO2 generation.

With respect to CO and hydrocarbons, the SO2 catalyst

acted to virtually eliminate these compounds as well.This aspect also positively affected the interaction of theNOx and SO2 catalysts. Because the SO2 catalyst followed the NOx catalyst, any unreacted ammonia (slip)

was oxidized in the SO2 catalyst to nitrogen, water vapor,

The bottom portion of the S

catalyst dust collector hopp

and a small amount of NOx. As a result, downstream

fouling by ammonia compounds was eliminated, and theSCR was operated at slightly higher than typical ammoniastoichiometries. These higher stoichiometries allowedsmaller SCR catalyst volumes and permitted the attainment of very high reduction efficiencies. Normal operating stoichiometries for the SCR system were in the rangeof 1.02–1.05, and system reduction efficiencies averaged94% with inlet NOx levels of approximately 500–700 ppm.

Sulfur dioxide removal in the SNOXTM process was controlled by the efficiency of the SO2-to-SO3 oxidation,

which occurred as the flue gas passed through theoxidation catalyst beds. The efficiency was controlled bytwo factors—space velocity and bed temperature. Spacevelocity governed the amount of catalyst necessary atdesign flue gas flow conditions, and gas and bed temperature had to be high enough to activate the SO2 oxidation

reaction. During the test program, SO2 removal efficiency

was normally in excess of 95% for inlet concentrationsaveraging about 2,000 ppm.Sulfuric acid concentration and composition have met orexceeded the requirements of the federal specificationsfor Class I acid. During the design and construction ofthe SNOXTM demonstration, arrangements were madewith a sulfuric acid supplier to purchase and distribute theacid from the plant. The acid has been sold to the agriculture industry for production of diammonium phosphatefertilizer and to the steel industry for pickling. OhioEdison also has used a significant amount in boiler waterdemineralizer systems throughout its plants.Air toxics testing conducted at the Niles SNOXTM plantmeasured the following substances:• Five major and 16 trace elements including mercury,

chromium, cadmium, lead, selenium, arsenic, beryllium, and nickel;

• Acids and corresponding anions (hydrogen chloride,

hydrogen fluoride, chloride, fluoride, phosphate,sulfate);

• Ammonia and cyanide;• Elemental carbon;• Radionuclides;

• Volatile organic compo• Semi-volatile compoun

matic hydrocarbons; a

• Aldehydes.Most trace elements were along with the particulateboron and almost all of thbut selenium and cadmiumeffectively captured in the compounds.
The SNOXTM demonstration at Ohio Edison’s Niles Station Unit No. 2 achieved SO2removal efficiencies exceeding 95% and NOx reduction effectiveness averaging

94%. Ohio Edison is retaining the SNOXTM technology as part of its environmentalcontrol system.

Operational PerformanceHeat recovery was accomplished by the SNOXTM process.In a commercial configuration, it can be utilized in thethermal cycle of the boiler. The process generated recoverable heat in several ways. All of the reactions that tookplace with respect to NOx and SO2 removal were exothermic and increased the temperature of the flue gas. This

heat, plus fuel-fired support heat added in the high-temperature SCR/SO2 catalyst loop, was recovered in the WSA

Condenser cooling air discharge for use in the furnace ascombustion air. Because the WSA Condenser lowered thetemperature of the flue gas to about 210 oF, compared withapproximately 300 oF for a typical power plant, additionalthermal energy was recovered along with that from theheats of reaction.Economic PerformanceThe economic evaluation of the SNOXTM process showeda capital cost of approximately $305/kW for a 500-MWeunit firing 3.2% sulfur coal. The 15-year levelized incremental cost was 6.1 mills/kWh on a constant dollar basis(1995$). The equivalent costs of pollutant removed were$219/ton of SO2, and $198/ton of SO2

and NOx

.

Commercial ApplicationsThe SNOXTM technology is applicableto all electric power plants and industrial/institutional boilers firing coal,oil, or gas. The high removal efficiency for NOx and SO2 makes the

process attractive in many applications. Since the SNOXTM technologyproduces no solid waste, its marketability is enhanced in urban and otherareas where solid waste disposal is asignificant problem.The host utility, Ohio Edison, is retaining the SNOXTM technology as a permanent part of the pollution controlsystem at Niles Station to help OhioEdison meet its overall SO2/NOx reduction goals.

Commercial SNOXTM plants also are operating in Denmarkand Sicily. In Denmark, a 305-MWe plant has operatedsince August 1991. The boiler at this plant burns coalsfrom various suppliers around the world, including theUnited States; the coals contain 0.5–3.0% sulfur. The plantin Sicily, operating since March 1991, has a capacity ofabout 30 MWe and fires petroleum coke.ContactsPaul Yosick, Project Manager, (865) 694-5300

Alstom Power, Inc.1409 Center Port BoulevardKnoxville, TN 37922(865) 694-5213 (fax)paul.yosick@power.alstom.com

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Thomas A. Sarkus, NETL, (412) 386-5981

sarkus@netl.doe.gov

ReferencesFinal Report Volume II: nomics. July 1996. RepFinal Report Volume I: PC/89655-T21. (AvailaA Study of Toxic EmissioPlant Utilizing the SNOnology Demonstration. Special Topics: Final R93251-T3-Vol. 1. Battel1994. (Available from NA Study of Toxic EmissioPlant Utilizing the SNOnology Demonstration. Report. Report No. DOColumbus Operations. as DE94018833.)ABB Environmental SysDemonstration Project—U.S. Department of Ene
68 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesMulti-Pollutant Control TechnologiesLIMB Demonstration ProjectExtension and CoolsideDemonstrationProject completedParticipantThe Babcock & Wilcox CompanyAdditional Team MembersOhio Coal Development Office—cofunderConsolidation Coal Company—cofunder and technology

supplier

Ohio Edison Company—hostLocationLorain, Lorain County, OH (Ohio Edison’s EdgewaterStation, Unit No. 4)TechnologyThe Babcock & Wilcox Company’s (B&W) limestoneinjection multistage burner (LIMB) system; Babcock &Wilcox DRB-XCL® low-NO

x burners; Consolidation Coal

Company’s Coolside duct injection of lime sorbentsPlant Capacity/Production105 MWeCoalOhio bituminous, 1.6, 3.0, and 3.8% sulfurProject FundingTotal $19,311,033 100%DOE 7,591,655 39Participant 11,719,378 61Project ObjectiveTo demonstrate, with a variety of coals and sorbents, thatthe LIMB process can achieve up to 50% NOx and SO2

reductions, and to demonstrate that the Coolside processcan achieve SO2 removal of up to 70%.

Technology/Project DescriptionThe LIMB process reduces SO2 by injecting dry sorbent

into the boiler at a point above the burners. The sorbentthen travels through the boiler and is removed along withfly ash in an electrostatic precipitator (ESP) or baghouse.Humidification of the flue gas before it enters an ESP isnecessary to maintain normal ESP operation and to enhance SO2 removal. Combinations of three bituminous

coals (1.6, 3.0, and 3.8% sulfur) and four sorbents weretested. Other variables examined were stoichiometry,humidifier outlet temperature, and injection elevationlevel in the boiler.In the Coolside process, dry sorbent is injected into the fluegas downstream of the air preheater, followed by flue gashumidification. Humidification enhances ESP performance and SO2 absorption. SO2 absorption is improved by

dissolving sodium hydrox(Na2CO3) in the humidific

collected with the fly ash, nous coal with 3.0% sulfuBabcock & Wilcox DRB-

control NO

x through stage

demonstrating both LIMB 
Calendar Year

 3 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 

Results SummaryEnvironmental• LIMB SO2 removal efficiencies at a calcium-to-sulfur

(Ca/S) molar ratio of 2.0, and minimal humidificationacross the range of coal sulfur contents were 53–61%for ligno lime, 51–58% for calcitic lime, 45–52% fordolomitic lime, and 22–25% for limestone ground to80% less than 44 microns (325 mesh).

• LIMB SO2 removal efficiency increased from 22–

25% to 32% using limestone ground to 100% less than44 microns, and increased an additional 5–7% whenground to 100% less than 10 microns.

• LIMB SO2 removal efficiencies were enhanced by

about 10% with humidification at a 20 oF approach-tosaturation temperature.

• LIMB, which incorporated Babcock & Wilcox

DRB-XCL® low-NO

x burners, achieved 40–50% NOx

reduction.

• Coolside SO2 removal efficiency was 70% at a Ca/S

molar ratio of 2.0, a sodium-to-calcium (Na/Ca) ratioof 0.2, and a 20 oF approach-to-saturation temperature using commercial hydrated lime and 2.8–3.0%sulfur coal.

• Sorbent recycle tests demonstrated the potential to

improve sorbent utilization.

Operational• Humidification enhanced ESP performance, which

enabled opacity levels to be kept well within limits.

• LIMB availability was 95%. Coolside did not undergo

testing of sufficient length to establish availability.

• Humidifier performance indicated that operation in a

vertical rather than horizontal mode would be better.

Economic• LIMB capital costs were $31–102/kW (1992$) for

plants ranging from 100–500 MWe and coals with1.5–3.5% sulfur, with a target SO2 reduction of 60%.

Annual levelized costs (15-year) for this range of conditions were $392–791/ton of SO2 removed.

1986 1987 1988 1989 1990 1991 1992 1993 1994 

Preaward Design and Construction

11/92

Project completed/final report issued 1

LIMB operational tests completed 8/91

NEPA process

 completed (MTF)

6/2/87

Cooperative

agreement

awarded 6/25/87

Coolside operational tests initiated 7/89

Construction completed 9/89

Ground breaking/constructionstarted 8/87

Environmental monitoring plan

completed 10/19/88

Operation and Reporting

6/87

LIMB operational testsinitiated 4/90

Coolside operational testscompleted 2/90

DOE selectedproject (CCTDP-I)7/24/86

7/86 7/89

• Coolside capital cost

plants ranging from 1.5–3.5% sulfur, with 

Annualized levelized conditions were $482
70 Completed Projects 2003

Project SummaryThe initial expectation with LIMB technology was thatlimestone calcined by injection into the furnace wouldachieve adequate SO2 capture. Use of limestone in lieu of

the significantly more expensive lime would keep operating costs relatively low. However, the demonstrationshowed that, even with fine grinding of the limestone anddeep humidification, performance with limestone wasmarginal. As a result, a variety of hydrated limes wereevaluated in the LIMB configuration, demonstrating enhanced performance. Although LIMB performance wasenhanced by applying humidification to the point of approaching adiabatic saturation temperatures, performancedid not rely on this deep humidification.Coolside design was dependent upon deep humidificationto improve sorbent reactivity and the use of hydratedlime. Sorbent injection was downstream of the furnace.In addition, sorbent activity was enhanced by dissolvingsodium hydroxide (NaOH) or sodium carbonate (Na2CO3

)

in the humidification water.

Water mist, sprayed into the flue gas, enhanced sulfurcapture by the sorbent by approximately 10% in the LIMBprocess when 20 °F approach-to-saturation was used.

Exh

LIMB SO2 Rem

(Per

No

Sorbent Ligno lime Commercial calcitic lime Dolomitic lime Limestone (80% <44 microns)

NT = Not testedTest conditions: injection at 181 minimal humidification.

Environmental Performance (LIMB)LIMB tests were conducted over a range of Ca/Smolar ratios and humidification conditions whileburning Ohio coals with nominal sulfur contents of1.6, 3.0, and 3.8% by weight. Each of four differentsorbents was injected while burning each of the threedifferent coals with one exception. Other variablesexamined were stoichiometry, humidifier outlet temperature, and injection elevation level in the boiler.Exhibit 37 summarizes SO2 removal efficiencies forthe range of sorbents and coals tested.While injecting commercial limestone with 80% ofthe particles less than 44 microns in size (minus 325mesh), removal efficiencies of about 22% were obtained at a stoichiometry of 2.0 while burning 1.6%sulfur coal. However, removal efficiencies of about32% were achieved at a stoichiometry of 2.0 whenusing a limestone with a smaller particle size (i.e., all

particles were less than 44 microns). A third limestone with essentially all particles less than 10 micronswas used to determine the removal efficiency limit. Theremoval efficiency for this very fine limestone wasapproximately 5–7% higher than that obtained undersimilar conditions for limestone with particles all sizedless than 44 microns.During the design phase, it was expected that injection atthe 181-foot plant elevation level inside the boiler wouldpermit the introduction of the limestone at close to theoptimum furnace temperature of 2,300 oF. Testing confirmed that injection at this level, just above the nose ofthe boiler, yielded the highest SO2 removal. Injection was

also performed at the 187-foot level and similar removalswere observed. Removal efficiencies while injecting atthese levels were about 5% higher than while injectingsorbent at the 191-foot level.Removal efficiencies were enhanced by approximately10% over the range of stoichiometries tested when usinghumidification down to a 20 oF approach-to-saturationtemperature. The continued use of the low-NOx burners

resulted in an overall average NOx emissions level of

0.43 lb/106 Btu, which is about a 45% reduction.

Operational PerformaLong-term test data showavailable about 95% of thoperate. Even with minimmance was adequately enwell below the permitted the 2–5% range (limit waEnvironmental PerforThe Coolside process was ance (1.2–1.6% sulfur) ansulfur) coals. Objectives were to verify short-term velop a design performaneconomics for Coolside. molar ratio, Na/Ca molar tion temperatures—were hours) parametric tests ancess operability tests.The test program demonsroutinely achieved 70% S

of 2.0 Ca/S molar ratio, 0approach-to-saturation temavailable hydrated lime. 
Exhibit 38

LIMB Capital Cost Comparison

(1992 $/kW)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe

1.5 93 150 413 66 116 3122.5 95 154 421 71 122 3163.5 102 160 425 73 127 324

250 MWe 500 MWe

1.5 46 96 228 31 69 1632.5 50 101 235 36 76 1693.5 54 105 240 40 81 174

Exhibit 39

LIMB Annual Levelized Cost Comparison

(1992 $/Ton of SO2 Removed)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe

1.5 791 943 1418 653 797 10982.5 595 706 895 520 624 6923.5 525 629 665 461 570 527

250 MWe 500 MWe

1.5 549 704 831 480 589 6232.5 456 567 539 416 502 411

on Ca/S molar ratio, Na/Ca molar ratio, approach-toadiabatic-saturation, and the physical properties of thehydrated lime. Sorbent recycle showed significant potential to improve sorbent utilization. The observed SO2removal with recycled sorbent alone was 22% at 0.5available Ca/S molar ratio and 18 oF approach-to-adiabatic-saturation. The observed SO2 removal with simultaneous recycle and fresh sorbent feed was 40% at 0.8 fresh Ca/S molar ratio, 0.2 fresh Na/Ca molar ratio, 0.5 available recycle, and 18 oF ap- proach-to-adiabatic-saturation. Operational Performance (Coolside) Floor deposits experienced in the ductwork with the horizontal humidification led designers to consider a vertical unit in a com- mercial configuration. Short-term testing did not permit evaluation of Coolside system availability. Economic Performance (LIMB & Coolside) Economic comparisons were made between LIMB, Coolside, and a wet scrubber with limestone injection and forced oxidation (LSFO). Assumptions on performance were SO2 removal efficiencies of 60, 70, and 95% for LIMB, Coolside, and LSFO, respectively. The EPRI TAGTM methods were used for the eco- nomics, which are summarized in Exhibits 38 and 39. Commercial Application Both LIMB and Coolside tech- nologies are applicable to most utility and industrial coal-fired units, and provide alternatives to conventional wet flue gas desulfu- rization processes. LIMB and Coolside can be retrofitted with modest capital investment and downtime, and their space requirements are substantially less than for conven- tional flue gas desulfurization processes. Contacts Greg Bielawski (330) 8

The Babcock & Wilc20 South Van Buren P.O. Box 351 Barberton, OH 4420gtbielawski@babcoc(330) 860-9292 (fax) Victor K. Der, DOE/HQvictor.der@hq.doe.g

John C. McDowell, NET

mcdowell@netl.doe.

References LIMB Demonstration PDemonstration: Final R79798-T27. The Babcober 1992. (Available froThe Edgewater Coolsidcal Report. Report No. Inc. February 1992. (ADE93001722.) Coolside and LIMB: SoNearing Completion. Tment of Energy and The September 1990.
72 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesMulti-Pollutant Control TechnologiesSOx-NOx-Rox BoxTM Flue GasCleanup DemonstrationProjectProject completedParticipantThe Babcock & Wilcox CompanyAdditional Team MembersOhio Edison Company—cofunder and hostOhio Coal Development Office—cofunderElectric Power Research Institute—cofunderNorton Company—cofunder and SCR catalyst supplier3M Company—cofunder and filter bag supplierOwens Corning Fiberglas Corporation—cofunder and

filter bag supplier

LocationDilles Bottom, Belmont County, OH (Ohio EdisonCompany’s R.E. Burger Plant, Unit No. 5)TechnologyThe Babcock & Wilcox Company’s SOx-NOx-RoxBoxTM (SNRBTM) processPlant Capacity/Production5-MWe equivalent slipstream from a 156-MWe boilerCoalBituminous coal blend, 3.7% sulfur averageProject FundingTotal $13,271,620 100%DOE 6,078,402 46Participant 7,193,218 54

Project ObjectiveTo achieve greater than 70% SO2 removal and 90% orhigher 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. The NOx

removal is accomplished by injecting ammonia (NH3) to

selectively reduce NOx in the presence of a selective catalytic reduction (SCR) catalyst. Particulate removal is accomplished by high-temperature fiber bag filters.

The 5-MWe SNRBTM demonstration unit is large enoughto demonstrate commercial-scale components while minimizing the demonstration cost. Operation at this scale

also permitted cost-effectperature, which allowed fover a wide range of sorbating temperatures. Thusfor potential commercial 

SOx-NOx-Rox Box and SNRB are trademarks of The Babcock & WilcoxCompany.
Calendar Year

 3 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 

Results SummaryEnvironmental• The SO2 removal efficiency of 80% was achieved with

commercial-grade lime at a calcium-to-sulfur (Ca/S)molar ratio of 2.0 and temperature of 800–850 oF.

• The SO2 removal efficiency of 90% was achieved

with sugar-hydrated lime and lignosulfonate-hydratedlime at a Ca/S molar ratio of 2.0 and temperature of800–850 oF.

• The SO2 removal efficiency of 80% was achieved with

sodium bicarbonate at a sodium-to-sulfur (Na2/S) molar ratio of 1.0 and temperature of 425 oF.

• The SO2 emissions were reduced to less than

1.2 lb/106 Btu with 3–4% sulfur coal, with a Ca/S

molar ratio as low as 1.5 and Na2/S molar ratio of 1.0.

• Injection of calcium-based sorbents directly upstream

of the baghouse at 825–900 oF resulted in higher overall SO2 removal than injection further upstream at

temperatures up to 1,200 oF.

• The NO

x

 reduction of 90% was achieved with an NH3/

NO

x molar ratio of 0.9 and temperature of 800–850 oF.

• Air toxics removal efficiency was comparable to that

of an electrostatic precipitator (ESP), except that hydrogen fluoride (HF) was reduced by 84% and hydrogen chloride (HCl) by 95%.

Operational• 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.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

9/88

Preaward

12/89

Design completed 8/91

DOE selected project(CCTDP-II) 9/28/88

Cooperative agreementawarded 12/20/89

NEPA process completed (MTF) 9/22/89

Ground breaking/construction started 5/9/91

5/92

Design and Construction Operation and Reporting

Preoperational tests initiated 11/91

Construction completed 12/91Environmental monitoring plan completed 12/31/91

Operationinitiated 5/92 Operation completed 5/93 Project completed/fina

9/95

Economic• Capital cost in 1994 

was $253/kW, assumNO

x

 emissions of 1.0

and 85% SO2 and 90

• Levelized cost over 1

was $553/ton of SO2 
74 Completed Projects 2003

The sorbent injection into the duct upstream of SOx-NOx-RoxBoxTM system.

Project SummarySNRBTM incorporates two successful technology development efforts that offer distinct advantages over other control technologies. High-temperature filter bags and circular monolith catalyst developments enabled multipleemission controls in a single component with a low planarea space requirement. As a post-combustion controlsystem, it is simple to operate. The high-temperature bagprovides a clean, high-temperature environment compatible with effective SCR operation, and a surface for enhanced SO2/sorbent contact (creates a sorbent cake on the

surface).

Environmental PerformanceFour different sorbents were tested for SO2 capture. Calcium-based sorbents included commercial grade hydrated

lime, sugar-hydrated lime, and lignosulfonate-hydratedlime. In addition, sodium bicarbonate was tested. Theoptimal location for injecting the sorbent into the flue gaswas immediately upstream of the baghouse. Essentially,the SO2 was captured by the sorbent in the form of a filter

cake on the filter bags (along with fly ash).With the baghouse operating above 830 oF, injection ofcommercial-grade hydrated lime at Ca/S molar ratios of1.8 and above resulted in SO2 removals of over 80%. At

a Ca/S molar ratio of 2.0, sugar-hydrated lime and lignosulfonate-hydrated lime increased performance by approximately 8%, for overall removal of approximately90%. SO2 removal of 85–90% was obtained with calcium

utilization in the range of 40–45%. Injection of the calcium-based sorbents directly upstream of the baghouse at825–900 oF resulted in higher overall SO2 removal than

injection further upstream at temperatures up to 1,200 oF.The SO2 removal using sodium bicarbonate was 80% at

an Na2/S molar ratio of 1.0 and 98% at an Na2/S molar

ratio of 2.0, at a significantly reduced baghouse temperature of 450–460 oF. The SO2 emissions while burning a

3–4% sulfur coal were reduced to less than 1.2 lb/106 Btu

with a Ca/S molar ratio as low as 1.5 and Na2/S molar

ratio less than 1.0.To capture NOx, ammonia was injected between the sorbent injection point and the baghouse. The ammonia and

NOx reacted to form nitrogen and water in the presence of

Norton Company’s NC-300 series zeolite SCR catalyst.With the catalyst being located inside the filter bags, itwas well protected from potential particulate erosion orfouling. The sorbent reaction products, unreacted lime,and fly ash were collected on the filter bags and thusremoved from the flue gas.A NOx emission reduction of 90% was readily achieved

with ammonia slip limited to less than 5 ppm. This performance reduced NOx emissions to less than 0.10 lb/106 Btu.

NOx reduction was insensitive to temperatures over the

catalyst design temperature range of 700–900 oF. Catalyst

space velocity (volumetric minimal effect on NOx rem

Turndown capability for t

duction by varying the ratdemonstrated for a range 

appreciable physical degractivity was observed ovegram. The degree of oxid

zeolite catalyst appeared t

oxidation is a concern for vanadium.) Leach potentcompletion of the field teremained nonhazardous fParticulate emissions werstandards of 0.03 lb/106 B

lb/106 Btu, which corresp

99.89%. Hydrated lime iinlet particulate loading f

Emissions testing with anstalled revealed no appareefficiency. On-line clean30–40 lb/in2 was sufficien

assemblies. Typically, onservice was cleaned every A comprehensive air toxiperformed at the end of thprogram. The targeted emtrace metals, volatile orgaorganic compounds, aldehclides. These species wersubstances identified in thmercury speciation, dioxifeatures of this test prograefficiencies achieved for vSNRBTM system were genthe conventional ESP at tSNRBTM system did reduand HF emissions by an ahad no effect on these conOperation of the SNRBTM production of approximatproduct solids. An evaluaby-product showed that th
Workers lower one of the mounting plate in the penbaghouse.

agricultural liming (if pelletized). Also, the solids potentially could be used as a partial cement replacement tolower the cost of concrete.Operational PerformanceA 3,800-hour durability test of three fabric filters wascompleted at the Filter Fabric Development Test Facilityin Colorado Springs, Colorado in December 1992. Nosigns of failure were observed. All of the demonstrationtests were conducted using the 3M Company Nextelceramic fiber filter bags or the Owens Corning FiberglasS-Glass filter bags. No excessive wear or failuresoccurred in over 2,000 hours of elevated temperatureoperation.Economic PerformanceFor a 150-MWe boiler fired with 3.5% sulfur coal andNOx emissions of 1.02 lb/106 Btu, 65% capacity factor,

and 85% SO2 and 90% NOx removal, the projected capital

cost of a SNRBTM system is approximately $253/kW(1994$), including various technology and project contingency factors. A combination of fabric filter, SCR, andwet scrubber for achieving comparable emissions controlhas been estimated at $360–400/kW. Variable operatingcosts are dominated by the cost of the SO2 sorbent for a

system designed for 85–90% SO2 removal. Fixed operating costs primarily consist of system operating labor and

projected labor and material for the hot baghouse andash-handling systems. Levelized costs over 15 years inconstant 1994 dollars are estimated at $553/ton of SO2

and NOx removed.

Commercial ApplicationsCommercialization of the technology is expected to develop with an initial application equivalent to 50–100MWe. The focus of marketing efforts is being tailored tomatch the specific needs of potential industrial, utility,and independent power producers for both retrofit andnew plant construction. SNRBTM is a flexible technologythat can be tailored to maximize control of SO2, NOx, or

combined emissions to meet current performance requirements while providing flexibility to address future needs.

ContactsDot K. Johnson, (330) 860-1757

The Babcock & Wilcox Company20 South Van Buren AvenueP.O. Box 351Barberton, OH 44203-0351dkjohnson1@babcock.com(330) 860-2348 (fax)

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Thomas A. Sarkus, NETL, (412) 386-5981

sarkus@netl.doe.gov

ReferencesSOx-NOx-Rox BoxTM Flue Gas Cleanup DemonstrationFinal Report. Report No. DOE/PC/89656-T1. The Babcock & Wilcox Company. September 1995. (Availablefrom NTIS as DE96003839.)5-MWe SNRBTM Demonstration Facility: Detailed DesignReport. The Babcock & Wilcox Company. November1992.Comprehensive Report to Congress on the Clean CoalTechnology Program: SOx-NOx-Rox BoxTM Flue GasCleanup Demonstration Project. The Babcock & WilcoxCompany. Report No. DOE/FE-0145. U.S. Departmentof Energy. November 1989. (Available from NTIS asDE90004458.)SOx-NOx-Rox BoxTM Flue Gas Cleanup DemonstrationProject—Project Performance Summary. U.S. Department of Energy. June 1999.
76 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesMulti-Pollutant Control TechnologiesEnhancing the Use of Coalsby Gas Reburning andSorbent InjectionProject completedParticipantEnergy and Environmental Research CorporationAdditional Team MembersGas Research Institute—cofunderState of Illinois, Department of Commerce & Community

Affairs—cofunder

Illinois Power Company—hostCity Water, Light and Power—hostLocationsHennepin, Putnam County, IL (Illinois Power Company’sHennepin Plant, Unit No. 1)Springfield, Sangamon County, IL (City Water, Light andPower’s Lakeside Station, Unit No. 7)TechnologyEnergy and Environmental Research Corporation’s gasreburning and sorbent injection (GR-SI) processPlant Capacity/ProductionHennepin: tangentially fired 80 MWe (gross),71 MWe (net)Lakeside: cyclone-fired 40 MWe (gross), 33 MWe (net)CoalIllinois bituminous, 3.0% sulfurProject FundingTotal $37,588,955 100%DOE 18,747,816 50Participant 18,841,139 50PromiSORB is a trademark of Energy and Environmental ResearchCorporation.

Project ObjectiveTo demonstrate 60% NO

x reduction with gas reburning and

at least 50% SO2 removal with sorbent injection on two

different boiler configurations—tangentially fired andcyclone-fired—while burning high-sulfur midwestern coal.Technology/Project DescriptionIn this process, 80–85% of the fuel as coal is supplied tothe main combustion zone. The remaining 15–20% of thefuel, provided as natural gas, bypasses the main combustion zone and is injected above the main burners to form areducing (reburning) zone in which NOx is converted to

molecular nitrogen (N2). A calcium compound (sorbent)

is injected in the form of dry, fine particulates above thereburning zone in the boiler. Hydrated lime (Ca(OH)2)

serves as the baseline sorbent.

This project demonstrated separate boilers representrations—a tangentially firIllinois Power Company’Illinois, and a cyclone-firCity Water, Light and Powfield, Illinois. Illinois bitusulfur was the test coal foA comprehensive test prothe two sites, operating thof boiler conditions. Ovwere achieved, enabling be obtained. Intensive mquantify the reductions in 

impact on boiler equipmetors influencing costs.
Calendar Year

 3 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 

Results SummaryEnvironmental• On the tangentially fired boiler, GR-SI NOx reductions

of up to 75% were achieved, and an average 67% reduction was realized at an average gas heat input of 18%.

• GR-SI SO2 removal efficiency on the tangentially fired

boiler averaged 53% with hydrated lime at a calciumto-sulfur (Ca/S) molar ratio of 1.75 (corresponding toa sorbent utilization of 24%).

• On the cyclone-fired boiler, GR-SI NOx reductions of

up to 74% were achieved, and an average 66% reduction was realized at an average gas heat input of 22%.

• GR-SI SO2 removal efficiency on the cyclone-fired

boiler averaged 58% with hydrated lime at a Ca/Smolar ratio of 1.8 (corresponding to a sorbent utilization of 24%).

• Particulate emissions were not a problem on either unit

undergoing demonstration, but humidification had tobe introduced at Hennepin to enhance electrostaticprecipitator (ESP) performance.

• Three advanced sorbents tested achieved higher SO2

capture efficiencies than the baseline Linwood hydrated lime. PromiSORBTM A achieved 53% SO2capture efficiency and 31% utilization without gasreburning (GR) at a Ca/S molar ratio of 1.75. Underthe same conditions, PromiSORBTM B achieved 66%SO2 reduction and 38% utilization, and high-surfacearea hydrated lime 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.Economic• Capital cost for 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 r

reduces SO2 emission

• Capital cost for sorbe

mately $50/kW. • Operating costs for Ssorbent and sorbent/amated to be competit

Preaward Design and Construction

1986 1987 1988 1989 1990 1991 1992 1993 1994 

7/86 1/91

DOE selectedproject (CCTDP-I)7/24/86

7/87

Operation initiated,Lakeside 5/93

Operation completed,Hennepin 1/93

Construction completed, Hennepin 8/91

Operation initiated, Hennepin 1/91

Construction started, Lakeside 6/90

Environmental monitoring plan completed,Lakeside 11/15/89

Environmental monitoring plan

completed, Hennepin 10/15/89

NEPA process completed, Lakeside (EA) 6/25/89

Design completed, both sites 5/89

Construction started, Hennepin 5/89

NEPAprocesscompleted,Hennepin(MTF) 5/9/88

Cooperativeagreementawarded7/14/87

Construction completed, Lakeside 5/92

RestoHenn

OL

Operation and Reporting
78 Completed Projects 2003

The flexible lime-sorbent disorbent splitter to the top oLakeside Station.

Project SummaryThe GR-SI project demonstrated the success of gas reburning and sorbent injection technologies in reducingNOx and SO2 emissions. The process design conducted

early in the project combined with the vast amount ofdata collected during the testing created a database enabling effective design for any site-specific utility or industrial application.Environmental Performance (Hennepin)Following optimization testing throughout 1991, the GR-SIlong-term demonstration tests spanned 1992. The unit wasoperated at constant loads and with the system under dispatch load following. With the system under dispatch, theload fluctuated over a wide range from 40 MWe to a maximum load of 75 MWe. Over the long-term demonstrationperiod, the average gross power output was 62 MWe.For long-term demonstration testing, the average NOx

reduction was approximately 67%. The average SO2removal efficiency was over 53% at a Ca/S molar ratio of1.75. (Linwood hydrated lime was used throughout thesetests except for a few days when Marblehead lime wasused.) CO emissions were below 50 ppm in most cases,but were higher during operation at low load.A significant reduction in CO2 was also realized. This

was due to partial replacement of coal with natural gashaving a lower carbon-to-hydrogen ratio. This cofiringwith 18% natural gas resulted in a theoretical CO2 emissions reduction of nearly 8% from the coal-fired baseline

level. With flue gas humidification, ESP collection efficiencies greater than 99.8% and particulate emissions lessthan 0.025 lb/106 Btu were measured, even with an increase in inlet particulate loading resulting from sorbentinjection. These levels compared favorably to baselineemissions of 0.035 lb/106 Btu and a collection efficiency

greater than 99.5%.Following completion of the long-term tests, threespecially prepared sorbents were tested. Two were manufactured by the participant and contained proprietary additives to increase their reactivity toward SO2, and were

referred to as PromiSORBTM A and B. The IllinoisGeological Survey developed the other sorbent—highsurface-area hydrated lime—in which alcohol is used to

form a material that gives rise to a much higher surfacearea than that of conventionally hydrated limes.The SO2 capture without GR, at a nominal 1.75 Ca/S

molar ratio, was 53% for PromiSORBTMA, 66% for

PromiSORBTM B, 60% for high-surface-area hydratedlime, and 42% for Linwood lime. At a 2.6 Ca/S molarratio, the PromiSORBTM B yielded 81% SO2 removal

efficiency.Environmental Performance (Lakeside)Parametric tests were conducted in three series: GR parametric tests, SI parametric tests, and GR-SI optimizationtests. A total of 100 GR parametric tests were conductedat boiler loads of 33, 25, and 20 MWe. Gas heat inputvaried between 5% and 26%. The GR parametric testsachieved a NOx reduction of approximately 60% at a gas

heat input of 22–23%. Additional flow modeling andcomputer modeling studies indicated that smaller reburning fuel jet nozzles could increase reburning fuel mixingand thus improve the NOx reduction performance.

A total of 25 SI parametric tests were conducted to isolatethe effects of sorbent on boiler performance and operability. Results showed that SO2 reduction levels varied with

load because of the effect of temperature on the sulfationreaction. At a Ca/S molar ratio of 2.0, a 44% SO2 reduction was achieved at full load (33 MWe); a 38% SO2 reduction was achieved at mid load (25 MWe); and a 32%

SO2 reduction was achieved at low load (20 MWe).

In the GR-SI optimization tests, the two technologieswere integrated. Modifications were made to the reburning fuel injection nozzles based on the results of the initial GR parametric tests and flow modeling studies. Thetotal cross-sectional area of the reburning jets was decreased by 32% to increase the reburning jet’s penetrationcharacteristics. The decrease in nozzle diameter increasedNOx reduction by an additional 3–5% compared with the

initial parametric tests. With GR-SI, total SO2 reductionsresulted from partial replacement of coal with natural gasand sorbent injection. At a gas heat input of 22% andCa/S molar ratio of 1.8, average NOx reduction during the

long-term testing of GR-SI was 66% and the average SO2

reduction was 58%.

Operational PerformaSorbent injection increaseoperation but did not advequipment performance. efficiency by approximatein moisture formed with camination of the boiler bemeasurable change in tube the scheduled life of the bThe ESPs adequately accoloading and resistivity witash. No adverse condition
The natural gas injector was installed on the corner ofHennepin Station’s tangentially fired boiler.mentioned, humidification was added at Hennepin toachieve acceptable ESP performance with GR-SI.Economic Performance (Hennepin/Lakeside)Capital and operating costs depend largely on sitespecific factors, such as gas availability at the site, coal/gas cost differential, SO2 removal requirements, and value

of SO2 allowances. It was estimated that for most installations, a 15% gas heat input will achieve a 60% NOx

reduction. The capital cost for such a GR installation wasestimated at $15/kW for 100-MWe and larger plants plusthe cost of the gas pipeline (if required) (1996$). Operating costs were almost entirely related to the differentialcost of the gas over the coal as reduced by the value ofSO2 emission allowances.

The capital cost estimate for SI was $50/kW. Operatingcosts for SI were dominated by the cost of the sorbent andsorbent/ash disposal costs. SI was projected to be costcompetitive at $300/ton of SO2 removed.

Commercial ApplicationsThe GR-SI process is a unique combination of two separate technologies. The commercial applications for thesetechnologies, both separately and combined, extend toboth utility companies and industry in the United Statesand abroad. In the United States alone, these two technologies can be applied to more than 900 pre-NSPS utility boilers. The technologies also can be applied to newutility boilers. With NOx and SO2 removal exceeding

60% and 50%, respectively, these technologies have thepotential to extend the life of a boiler or power plant andalso provide a way to use higher sulfur coals.Illinois Power has retained the gas-reburning system andCity Water, Light & Power has retained the full technology for commercial use. The project was one of tworeceiving the Air and Waste Management Association’s1997 J. Deane Sensenbaugh Award.ContactsBlair A. Folsom, Senior V.P., (949) 859-8851, ext. 140

General Electric Energy and Environmental ResearchCorporation18 MasonIrvine, CA 92618blair.folsom@ps.ge.com(949) 859-3194 (fax)

Victor K. Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

ReferencesEnhancing the Use of Coals by Gas Reburning andSorbent Injection; Volume 1–Program Overview.February 1997.Enhancing the Use of Coals by Gas Reburning–SorbentInjection: Volume 4: Gas Reburning Sorbent Injection atLakeside Unit 7, City Water, Light and Power, Springfield, Illinois. Final Report. Energy and Environmental

Research Corporation. PC/79796-T48-Vol.4. (DE96011869.)Enhancing the Use of CInjection; Long Term TeJanuary 15, 1993. RepEnergy and Environmenary 1995. (Available froEnhancing the Use of Cbent Injection; Volume 2tion at Hennepin Unit 1No. DOE/PC/79796-T3mental Research Corporfrom NTIS as DE95009Enhancing the Use of Cbent Injection; Volume 3tion at Edwards Unit 1, Report No. DOE/PC/79vironmental Research C(Available from NTIS a
80 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesMulti-Pollutant Control TechnologiesMilliken Clean CoalTechnology DemonstrationProjectProject completedParticipantNew York State Electric & Gas Corporation (NYSEG)Additional Team MembersNew York State Energy Research and Development

Authority—cofunder

Empire State Electric Energy Research Corporation—

cofunder

Consolidation Coal Company—technical consultantSaarberg-Hölter Umwelttechnik, GmbH (S-H-U)—

technology supplier

The Stebbins Engineering and Manufacturing

Company—technology supplier

ABB Air Preheater, Inc.—technology supplierElectric Power Research Institute—cofunderLocationLansing, Tompkins County, NY (NYSEG’s Milliken Station, Unit Nos. 1 and 2). This station is currently ownedby AES Corporation and is designated AES Cayuga.TechnologyFlue gas cleanup using S-H-U formic-acid-enhanced, wetlimestone scrubber technology; ABB CombustionEngineering’s Low-NOx Concentric Firing System

(LNCFSTM) Level III; Stebbins’ tile-lined, split-moduleabsorber; ABB Air Preheater’s heat-pipe air preheater;and NYSEG’s PEOA Control System.Plant Capacity/Production300 MWe

LNCFS is a trademark of ABB Combustion Engineering, Inc. PEOA is atrademark of DHR Technologies, Inc.

CoalPittsburgh, Freeport, and Kittanning Coals; 1.5, 2.9 and4.0% sulfur, respectively.Project FundingTotal $158,607,807 100%DOE 45,000,000 28Participant 113,607,807 72Project ObjectiveTo demonstrate high sulfur capture efficiency and NOxand particulate control at minimum power requirements,zero waste water discharge, and the production of byproducts in lieu of wastes.

Technology/Project DThe formic acid enhanced remove up to 98% of SO2 

The Stebbins tile-lined, spabsorber vessel provides sresistance. Placement beloprovides operational flexib

trolled by LNCFS IIITMlo

preheater is integrated to iducing both air leakage antemperature. To enhance breductions, a Plant Emissiprovides state-of-the-art, atrol of key boiler and plancronized Coal Reburning 

for another CCT Program 
Calendar Year

 3 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 

Results SummaryEnvironmental• The maximum SO2 removal demonstrated was 98%

with all seven recycle pumps operating and using formic acid. The maximum SO2 removal without formic

acid was 95%.

• The difference in SO2 removal between the two limestone grind sizes tested (90%–325 mesh and 90%–170

mesh) while using low-sulfur coal was an average of2.6 percentage points.

• The SO2 removal efficiency was greater than the design efficiency during the high-velocity test of the

concurrent scrubber section up to a liquid-to-gas ratio(L/G) of 110 gallons per 1,000 actual cubic feet (kacf)of gas.

• At full load, LNCFSTM III lowered NOx emissions to

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

original burners)—a 39% reduction.

• LNCFSTM III maintained carbon in the fly ash below

4% and carbon monoxide emissions at baseline levels.

Operational• For more than 30,000 hours, the S-H-U FGD unit demonstrated nearly 100% availability at capacity factors

of 70–80%.

• The Stebbins tile-lined absorber demonstrated superior

corrosion and abrasion resistance.

• The heat-pipe air preheater reduced power requirements by an average of 778 kW.• 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 essentially unchanged by the

application of LNCFSTM III.

• Boiler efficiency was 88.3–88.5% for LNCFSTM III,

compared to a baseline of 89.3–89.6%.

Economic• The capital cost (1998$) of the FGD system is estimated at $300/kW for a 300-MWe unit with a 65%

capacity factor, 3.2% sulfur coal, and 95% sulfurremoval.

• The annual FGD ope

million (1998$); and mated at $412/ton of 

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Preaward Operation and Reporting

9/91 10/92

DOE selectedproject (CCTDP-IV)9/12/91

Cooperative agreement awarded 10/20/92

Design completed 4/93Ground breaking/construction started 4/93

NEPA process completed(EA) 8/18/93

10/

Operation completed 6/98

Operation initiated on Unit 2 1/95

6/95

Design and Construction

Environmental

monitoring

plan completed

12/1/94 Construction completed 6/95

Fully integrated operation of Units 1 and 2 initiated 6/95

P9
82 Completed Projects 2003

Exhib

Effect of Lime

Project SummaryThe S-H-U FGD unit at the Milliken Plant operated formore than 30,000 hours during the demonstration withnearly 100% availability and 90–95% SO2 removal. Combined with LNCFSTM III low-NOx burners which reduced

NOx emissions by 39%, the demonstrated system offers

an effective option for controlling both SO2 and NOx for

over 400 U.S. pulverized coal, tangentially fired units.The test plan used in this demonstration was developed tocover all of the new technologies used in the project. Inaddition to the technologies tested, the project demonstrated that existing technologies can be used in conjunction with new processes to produce salable by-products.Generally, each test program was divided into four independent subtests: diagnostic, performance, long-term, andvalidation.Environmental PerformanceFGD Performance. An overall assessment of theS-H-U process is that it performed well in tests burninglow- (1.6%), design- (2.2%), and high-(3.2–4.1%) sulfur(S) coals. The maximum SO2 removal demonstrated was

98% with all seven recycle pumps operating and usingformic acid, and the maximum SO2 removal without formic acid was 95%. The unit operated routinely in the 90–

95% SO2 removal range.

Design-Sulfur Coal (2.2% S). Availability of design coaland time constraints truncated design coal testing. But,testing did show that the L/G ratio is an important variable for SO2 removal. The SO2 removal efficiency ranged

from 85.6% with five spray headers in service to 95.1%with all seven spray headers in service, while using anominal 800 parts per million (ppm) formic acid concentration, a limestone grind of 90% passing through 170mesh, and a gas velocity rate of 20 feet per second (ft/s)in the cocurrent section. More SO2 removal was achieved

when a higher percentage of the total slurry was sprayedin the countercurrent section. A single test indicated theimportance of pH. The SO2 removal rates ranged from

91.5% at a normal pH of 4.1 ± 0.1 to 85.4% at a loweredpH of 3.9, with all other operating conditions the same.Low-Sulfur Coal (1.6% S). A shortened demonstrationperiod and availability problems with design coal resulted

in most testing being performed on the low-sulfur coal.Parametric tests were performed on the full rangeof variables. The number of spray headers in service impacted SO2 removal efficiency. The SO2 removal rate

ranged from a low of 30% using only two spray headerswithout formic acid to 98% using all seven spray headersand 800 ppm of formic acid. The maximum SO2 removal

was 98% at a 95% confidence level of ± 0.7%.The SO2 removal efficiency was increased significantly

with the addition of formic acid. With five spray headers inservice, SO2 removal efficiency increased from 82% without formic acid to 97% with 800 ppm of formic acid

added. Formic acid effects diminished with increasingconcentration. Also, the pH of the spray slurry affected SO2

removal efficiency. Increasing the pH from 4.2 to 5.0 without formic acid additive increased SO2 removal efficiency

an average of 10.1 percentage points.High-Sulfur Coal (3.2–4.1% S). Both time contraints andslurry pump capacity limited high-sulfur coal testing.Nevertheless, certain conclusions were reached as a resultof those tests. As expected, sulfur removal efficiencydecreased as the coal sulfur content increased. The SO2

removal efficiency depended more on the system pH thanthe L/G ratio. Indications were that an S-H-Uwith higher slurry pump capacity would perform at high SO2 removal efficiencies using

high sulfur coals.Nine tests were performed using an alternativelimestone grind size. Higher SO2 removal resulted using the finer grind (90% passing

through 325 mesh) limestone in lieu of thecoarser grind (90% passing through 170 mesh).The average difference in SO2 removal between

the two grind sizes was 2.6 percentage points,as shown in Exhibit 40.Low-NOx Burner Performance. At full boiler

load (145–150 MWe) and 3.0–3.5% economizeroxygen (O2), the LNCFSTM III system lowered

NOx emissions from a baseline value of 0.64 lb/

106 Btu to 0.39 lb/106 Btu, a 39% reduction. At a

reduced boiler load of 80–90 MWe and 4.3–5.0% economizer O2, the LNCFSTM III system

lowered NOx emissions from a baseline value of

0.58 lb/106 Btu to 0.41 lb/

bon in the fly ash was maimonoxide emissions did nESP Performance. Perfowith wider plate spacing plate area, and reduced pothat of the original ESP. Tpenetration before the ESdecreased to 0.12% after Air Toxics. Comprehenscharacterization testing wMilliken demonstration. Icombined to remove 99.8primarily in the solid pha99.7% removal. The ESP ash elements. The ESP rewas 16.7% and the FGD rOperational PerformaThe demonstrated technolMilliken Plant with the exing system, which suffered gypsum and fly ash bypro
FGD Performance. For more than 30,000 hours of demonstration operation, the S-H-U FGD unit reliability washigh and availability held at nearly 100% at capacity factors of 70–80%. Unit thermal efficiencies hovered around35%. However, some initial problems had to be overcomeand the demonstration identified some areas to improveperformance in future applications.Plugging of the slurry spray nozzles and hydrocycloneelements with rubber coming off the rubber-clad turningvanes and gypsum deposits resulting from insufficientseed crystals in the absorber slurry tank was solved byinstalling screens at the slurry pump intakes and keepinggypsum levels up in the absorber reaction tank. Mixing inthe slurry tank was problematic and resulted in continuous operation of the slurry pumps to alleviate the problem, albeit at higher power requirements.The expected high limestone utilization, due to formicacid-enabled low pH, was somewhat compromised by therelatively close proximity of the limestone injection andgypsum bleed pump suction ports, causing some limestoneto be drawn off with the gypsum. Poor mixing in the absorber tank exacerbated the situation. The problem waslargely resolved by moving the limestone injection portfurther into the tank. But, wider separation is warranted infuture designs.The Stebbins split-module, tile-lined absorber demonstrated superior abrasion and corrosion resistance, suggesting a liner life three to four times that of rubber liners. Theconstruction allowed installation beneath the stack to savespace and the configuration allowed flexibility in operationand maintenance (one unit can be shut down for low loadsituations or for on-line repairs).Low-NOx Burner Performance. Boiler efficiency was

88.3–88.5% using LNCFSTM III, compared to a baseline of89.3–89.6%. The lower boiler efficiency was attributed tohigher post-retrofit flue gas O2 levels and higher stack

temperatures, which accompanied the air preheater retrofit.The LNCFSTM III and baseline results were adjusted so thatthey could be compared at similar flue gas temperatures.Under comparable conditions, the LNCFSTM III boilerefficiency was estimated to be 0.2 of a percentage pointhigher than baseline.

Heat Pipe Air Preheater. An expected thermal efficiencyboost from applying the heat pipe principle did not materialize (a 20 °F reduction in flue gas exit temperature was

projected), but an overall efficiency gain resulted fromreduced leakage. Fan power savings averaged 778 kW, orabout 0.49% of gross load. Pressure losses across flue gasand air sides were less than the design values of 3.65inches of water and 5.35 inches of water, respectively.ESP. Performance tests on the original and modifiedESPs showed that the modified ESP had better removalefficiency, as discussed previously, even though it hadone-half of the collection plate area of the original ESP.The data show that the power requirement is 25% lessthan that of the original ESP.POEATM. The POEATM control system is an online support system designed to help meet economic performancetargets by integrating key information and analyses thatassist plant personnel in optimizing plant performance,including steam and waste management systems. Although not necessary for S-H-U operation, the promise ofPOEATM is that it will compensate for parasitic powerlosses. Due to data collection problems, the two tests onthe POEATM system were promising, but inconclusive.CAPCIS. NYSEG installed and tested an online, realtime corrosion monitoring system to identify the lowestflue gas outlet temperature possible without compromising equipment subject to corrosion. Probes were placed atthe heat pipe air preheater outlet and S-H-U FGD inletduct. Software was to use probe signals to control thesecondary air bypass damper in the heat pipe preheater. Atthe time of the project final report, the data was insufficient to draw any conclusions on the system.Economic PerformanceThe estimated capital cost of the total FGD system in 1998dollars was estimated at $300/kW for a 300-MWe unit with

a 65% capacity factor using 3.2% sulfur coal and achieving 95% sulfur removal. The annual operating cost isestimated at $4.62 million. The 15-year levelized cost isestimated at $412/ton of SO2 removed in 1998 constant

dollars. On a unit cost basis, total capital requirements foran S-H-U FGD retrofit similar to Milliken Station can beexpected to range from $385/kW for a 150-MW plant to$260/kW for a 500-MW plant.

Commercial ApplicaThe S-H-U process, Stebpipe air preheater are apppower plants. In a NYSEmarket for which the S-Hdivided into two parts: refired boilers not equippe

capacity (projected coal-analysis suggests a total MWe through 2030 and ket of 96,200 MWe. Althremains reasonably accupotential commercial appized coal, tangentially firfrom 25 MWe to 950 MWof coals, from low-volatContactsJim Harvilla, Project M

New York State ElecCorporate Drive—KP.O. Box 5224Binghamton, NY 139jjharvilla@nyseg.com(607) 762-4002 (fax)

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Thomas A. Sarkus, NET

sarkus@netl.doe.gov

ReferencesMilliken Clean Coal TecProject Performance anport Volumes I & II. Neporation. October 1999Comprehensive Report Technology Program: MDemonstration Project. Corporation. Report Noment of Energy. Septemas DE93001756.)Milliken Clean Coal TecProject—Project Performent of Energy. Novem
84 Completed Projects 2003

Clean Coal Technology Demonstration ProgramEnvironmental Control DevicesMulti-Pollutant Control TechnologiesIntegrated Dry NOx/SO2Emissions Control SystemProject completedParticipantPublic Service Company of ColoradoAdditional Team MembersElectric Power Research Institute—cofunderStone and Webster Engineering Corp.—engineerThe Babcock & Wilcox Company—burner developerFossil Energy Research Corporation—operational testerWestern Research Institute—fly ash evaluatorColorado School of Mines—bench-scale engineering

researcher and tester

NOELL, Inc.—urea injection system providerLocationDenver, Denver County, CO (Public Service Company ofColorado’s Arapahoe Station, Unit No. 4)TechnologyThe Babcock & Wilcox Company’s DRB-XCL® low-NOxburners (LNB) with overfire air (OFA), in-duct drysorbent injection (DSI) with and without flue gas humidification (FGH), and NOELL’s urea-based selective noncatalytic reduction (SNCR) injectionPlant Capacity/Production100 MWeCoalColorado bituminous, 0.4% sulfurWyoming subbituminous (short test), 0.35% sulfurDRB-XCL is a registered trademark of The Babcock & Wilcox Company.

Project FundingTotal $26,165,306 100%DOE 13,082,653 50Participant 13,082,653 50Project ObjectiveTo demonstrate the integration of five technologies (LNB,OFA, DSI, FGH, and SNCR) to achieve up to 70% reductionin NO

x

 and SO2 emissions; more specifically, to assess the

integration of a down-fired, low-NOx burner with in-furnace

urea injection for additional NOx removal and dry sorbent induct 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 (12 DRBXCL® burners and 6 B&W Dual-Zone NO

x ports). These

burners control NO

x by injecting the coal and the combustion air in an oxygen-defic

is introduced via overfire tion process and further en

based SNCR system was tadditional NOx can be rem

Two types of dry sorbentwork downstream of the 

Either calcium-based sorthe economizer, or sodiuof the air heater. Humidisorbent injection was inc

and lower flue gas tempetering the fabric filter dusThe Integrated Dry NOx/SO

(IDECS) was installed on PColorado’s Arapahoe Statifired, pulverized-coal boile
Calendar Year

 3 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 

Results SummaryEnvironmental• DRB-XCL® burners with minimum OFA reduced NO

x

emissions by more than 61% over the load range of80–100 MWe. With maximum OFA (32% of totalsecondary air at 50 MWe to 24% at 80 MWe andabove), NOx reduction was 62–69% across the load

range of 50- to 110-MWe.

• DRB-XCL® burners with maximum OFA maintained

CO below baseline emission levels, reaching amaximum of 50 ppm.

• The SNCR system, using both stationary and retractable

injection lances in the furnace, provided NOx removal

of 30–50% at an ammonia (NH3) slip of 10 parts per

million (ppm), thus increasing performance of the totalNO

x control system to greater than 80% NOx reduction.

The advanced retractable injection lances (ARIL) system increased NO

x

 emission reduction at low loads

(below 70 MWe) from 11% to 35–52%.

• Hydrated lime injection into the boiler economizer at

950–1,150 °F reduced SO2 emissions by 5–10%;

and hydrated lime injection into the FFDC ductreduced SO2 emissions by 28–40% at a normalized

stoichiometric ratio (NSR) of 2.0 and 25–30 °Fapproach to saturation temperature.

• A 70% SO2 removal was achieved by injecting

sodium bicarbonate before the AP (650 °F) at an NSR

of 1.0; and by injecting sodium sesquicarbonate afterthe APU (220–280 °F) at an NSR of 1.9.

• At 70% SO2 removal, both sodium-based sorbents

reduced NO

x emissions by approximately 10%.

• Integration of SNCR and sodium-based DSI decreased

the level of unwanted nitrogen dioxide emissions by50% and, in turn, DSI decreased the level of ammoniaslip that would occur with SNCR alone.

• IDECS with the FFDC successfully removed

96.9–98.6% of trace metal emissions and 67.5–93.7%of the mercury.

Operational• LNB/OFA maintaine

ignition (LOI) at esse

• DRB-XCL® burners 

200 °F decrease in fuimpacted the amount steam temperature at 

• Temperature differen

surfaces of the ARIL downward 12–18 incmoval difficult.

Economic• Total estimated capit

100-MWe boiler is $estimated at $0.32 mcosts at $1.49 million

• Estimated levelized c

SO2, or 9.7 mills/kWh 

of NO

x plus SO2, or 

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Preaward Operation

Design and 8/92

Construction

12/89 3/91

NEPA process completed (MTF) 9/27/90

Design initiated 6/90

DOE selected project

(CCTDP-III) 12/19/89

Ground breaking/construction started 5/21/91

Design completed 3/92

Preoperational tests initiated 6/92

Construction completed 8/92Operation initiated 8/92

Environmental monitoring plancompleted 8/5/93

Cooperative agreement awarded 3/11/91
86 Completed Projects 2003

NOx= 63% 64% 61%

69% 68%

Original BurnersXCL Burners w/Min OFAXCL Burners w/Max OFA

900600800500

700

400

300

200

100

 0

 40 50 60 70 80 90 100 110 120

Load (MWe)

NOx (ppmc)

Project SummaryIDECS was composed of five technologies: LNBs, OFA,SNCR, DSI, and FGH. However, the combinations of thefive separate technologies equated to three separate emission control systems for purposes of testing because theLNBs were always used in conjunction with OFA, andFGH was used only with DSI. The three systems—LNB/OFA, SNCR, and DSI with or without FGH—were individually tested using both parametric tests and long-termtests. Individual system tests were followed by testing thetechnologies as one integrated system.Environmental PerformanceLNB/OFA. The testing of the LNB/OFA system was performed in two phases, parametric testing and long-termtesting. The results of LNB/OFA parametric testing areshown in Exhibit 41. Parametric testing was conductedwith minimum OFA and maximum OFA. Minimum OFArepresents 15% of total secondary air. Maximum OFA varies as boiler load, air flow, and fan pressure change. Maximum OFA varied from 32% of total secondary air at a loadof 50 MWe to 24% at 80 MWe and above. The LNB/OFAsystem using minimum OFA reduced NOx emissions from

61–64% in the 80–100 MWe load range. At maximumOFA, the LNB/OFA system reduced NOx emissions 61–

69% in the 50–100 MWe load range. Maximum OFA keptCO levels lower than the original burners, holding COlevels to a maximum of 50 ppm, as shown in Exhibit 42.However, the LNBs required higher than baseline excessair to maintain adequate steam temperature and to staybelow 50 ppm CO at boiler loads below 100 MWe.During long-term testing, the NOx emissions were 10–

20% (30–60 ppm) higher than the parametric tests. Theseincreased NOx emissions were attributed to higher oxygen

(O2) levels (1.0–1.5% higher) experienced during normal

load-following conditions. The NOx levels increased by

about 40 ppm for each % increase in O2 levels.

SNCR. The SNCR system underwent both parametric andlong-term testing. Boiler load was the predominant factorin determining the flue gas temperature at SNCR injectionlocations and, therefore, had the greatest effect on performance. The original two-row SNCR injector design provedrelatively ineffective because one row was in a regionwhere the flue gas temperature was too low for effective

operation. This situation was exacerbated by a 200 °Fboiler temperature drop resulting from LNB/OFA installation. Thus, installation of the ARIL retractable lance systemin the appropriate temperature region was required to bringSNCR performance to an acceptable level. With the ARILsystem, NOx reduction increased from 11% to 35–52% at

loads below 70 MWe. The ability to follow the temperature window by rotating the lances proved to be an important feature in optimizing performance. As a result, theSNCR system achieved NOx removals of 30–50% (at an

ammonia slip limited to 10 ppm at the FFDC inlet) over thenormal load range. The 30–50% reduction was with LNB/OFA and resulted in total NOx emission reductions of

greater than 80%.DSI/FGH. DSI testing examined two sodium-basedsorbents (sodium-sesquicarbonate and sodium-bicarbonate) and hydrated lime. Objectives of the sodium-basedDSI test extended beyond SO2 removal to evaluating the

effects on NOx removal and NO2 emissions. Variables

investigated included sorblocation, sorbent particle to-saturation temperatureof sorbent to SO2 that has 

removal of all SO2. For ca

mole of calcium is needed whereas 2.0 moles of sodtion is the ratio of percent 

Boiler load had little, if an

removals of 70% were acat an NSR of 1.0, while san NSR of 1.9 for the samdium-bicarbonate was injunit (APU) at 650 °F to creaching steady-state conbonate was injected after equal effect when injected Particle size proved to be removal efficiency for sod

Exhibit 41

Boiler Load Parametric Testing

of LNB/OFA System

Ex

CO Emis

Parame

100

908070605040302010

0

CO (ppmc)

40 50 60 

OrigXCL XCL 
from 28% at a 28 microns mean particle diameter to 48%at 15 microns (both measurements at an NSR of 0.9). TheSO2 removal efficiency with sodium-bicarbonate showed

less dependence on particle size. Humidification at a60 °F approach-to-saturation temperature increased sodium-sesquicarbonate SO2 removal efficiency by 20% at an

NSR of 2.0, but had little effect at an NSR of 1.0.Both sodium sorbents reduced NOx emissions by

approximately 10% at injection levels comparable to 70%SO2 removal, but oxidized NO to NO2. However, sodiumsesquicarbonate produces only half a much NO2 as sodium-bicarbonate at comparable SO2 removal efficiencies.

Hydrated lime achieved only 5–10% SO2 removal when

injected into the economizer at 950–1,150 °F and an NSRof 2.0. This performance was attributed in large part topoor sorbent distribution. Humidification failed to significantly improve the performance. Hydrated lime injectiondownstream of the APU at a 25–30 °F approach-to-saturation temperature and NSR of 2.0 achieved only 28–40%SO2 removal, short of the 50% target.

SNCR/DSI Synergy. Operation of the SNCR with

sodium-based DSI reduced the NO2 emissions that occur

with sodium-based DSI alone by approximately 50%.Sodium-based DSI reduces ammonia slip by an estimated50% by inducing precipitation onto the fly ash. At 8 ppmNH3 slip, fly ash NH3 ranged from 400–700 ppm versus

100–200 ppm with SNCR alone. Adjusting NH3 slip to

4 ppm returned fly ash NH3 levels to 100–200 ppm.

Air Toxics. The IDECS project included a comprehensiveinvestigation into many potential air toxics. Tests showthat the use of a FFDC was very effective for controllingnearly all air toxic emissions. Overall particulate removalwas greater than 99.9%, and trace metal emission removalranged from 96.9–98.6%. Mercury removal across theFFDC was 67.5% with dry sodium-based DSI, 77.9%,with SNCR, and 93.7% with calcium-based DSI/FGH.Operating PerformanceThe Arapahoe Unit No. 4 operated more than 34,000hours with the combustion modifications in place. Theavailability factor during the period was over 91%.LNB/OFA. The new LNBs resulted in an approximately200 °F decrease in furnace exit temperature, which required more excess air than baseline to maintain steam

temperature at low loads. The LOI essentially remained thesame between the new and original burners, except at 50MWe. High LOI at this low load was attributed to an uneven distribution of coal and a coarser grind as the numberof mills in service dropped from three to two.SNCR. The ARIL lances proved to be effective NOx

control devices, but experienced some operational problems. A large differential heating pattern between opposite sides of the lance caused a differential in thermalexpansion and bending of the lance approximately 12–18 inches, making insertion and retraction difficult. Theproblem was partially resolved by adding cooling slots atthe end of the lance. An alternative design, provided byDiamond Power Specialty Company, was tested andfound to have less bending due to evaporative cooling,but NOx reduction and ammonia slip performance

dropped relative to the ARIL system.DSI/FGH. During the operation of the DSI system withhydrated lime and FGH under load-following conditions,the FFDC pressure drop significantly increased as a resultof buildup of a hard ash cake on the fabric bags that couldnot be cleaned under normal reverse-air cleaning. The FGHsystem caused the heavy ash cake, but it was not determined whether the problem was due to operation at 30 °Fapproach-to-saturation temperature or an excursion causedby a rapid decrease in load.When the SNCR and DSI systems were operated concurrently, an ammonia odor problem was encountered aroundthe ash silo due to the rapid change in pH attributable tothe presence of sodium in the ash and the wetting of thefly ash to minimize fugitive dust. This problem was resolved by transporting the ash in enclosed tanker trucksand by not adding water.Economic PerformanceThe technology is an economical method of obtainingSO2 and NOx reduction on low-sulfur coal units. Total

estimated capital costs range from 125–281 $/kW (1994$)for capacities ranging from 300–50 MWe. Comparably,wet scrubber and SCR capital costs range from 270–474 $/kW for the same unit size range. On a levelizedcost basis, the demonstrated system costs vary from12.43–7.03 mills/kWh (1,746–987 $/ton of SO2 and NOx

removed) compared to wet scrubber and SCR levelized

costs of 23.34–12.67 miSO2 and NOx removed) 

integrated system is mocoal units. As size and advantages decrease.Commercial ApplicaThe IDECS system was specific requirements of emission-control situatiothat 65 down-fired boilewet bottom boilers, totadates for the IDECS sysdesign, these units gene

cause of lack of plot areplants also tend to be reconsiderations, utilities capital investments in thvides an economic alterContactsTerry Hunt, Production 

Xcel Energy4653 Table Mountain Golden, CO 80403terry.hunt@xcelenerg(720) 497-2123 (fax)

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Jerry L. Hebb, NETL, (4

hebb@netl.doe.gov

ReferencesIntegrated Dry NOx /SO

Final Report, Volume 1: Company of Colorado. Integrated Dry NOx /SOReport, Volume 2: ProjePublic Service Company Integrated Dry NOx/SO2 

DOE Assessment. U.S. DIntegrated Dry NOx/SO2 

Project Performance SuEnergy. February 2003.
88 Completed Projects 2003
Advanced Electric Power Gene

Fluidized-Bed Combustion
90 Completed Projects 2003

Tidd PFBC DemonstrationProjectProject completedParticipantThe Ohio Power CompanyAdditional Team MembersAmerican Electric Power Service Corporation—designer,

constructor, and manager

The Babcock & Wilcox Company—technology supplierOhio Coal Development Office—cofunderLocationBrilliant, Jefferson County, Ohio (Ohio Power Company’sTidd Plant, Unit No. 1)TechnologyThe Babcock & Wilcox Company’s pressurized fluidizedbed combustion (PFBC) system (under license from ABBCarbon)Plant Capacity/Production70 MWe (net)CoalOhio bituminous, 2–4% sulfurProject FundingTotal $189,886,339 100%DOE 66,956,993 35Participant 122,929,346 65Project ObjectiveTo verify expectations of PFBC economic, environmental,and technical performance in a combined-cycle repowering application at utility scale; and to accomplish greaterthan 90% SO2 removal and NOx emission level of

0.2 lb/106 Btu at full load.

Technology/Project DescriptionTidd was the first large-scale operational demonstrationof PFBC in the United States. The project represented a13:1 scaleup from the pilot facility.The boiler, cyclones, bed reinjection vessels, and associated hardware were encapsulated in a pressure vessel 45feet in diameter and 70 feet high. The facility was designed so that one-seventh of the hot gases producedcould be routed to an advanced particulate filter (APF).The Tidd facility used a bubbling fluidized-bed combustionprocess operating at 12 atm (175 psi). Pressurized combustion air is supplied by the turbine compressor to fluidize thebed material, which consists of a coal-water fuel paste, coalash, and a dolomite or limestone sorbent. Dolomite orlimestone in the bed reacts with sulfur to form calciumsulfate, a dry, granular bed-ash material, which is easily

disposed of or is usable as perature of about 1,600 oF 

The hot combustion gases trained ash particles, 98% gases pass through cyclonexpanded through a 15-Mgases exiting the turbine, bundle in the fluid bed, ging 55-MWe steam turbin

Clean Coal Technology Demonstration ProgramAdvanced Electric Power GenerationFluidized-Bed Combustion
Calendar Year

 3 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 

Results SummaryEnvironmental• Sorbent size had the greatest effect on SO2 removal

efficiency as well as stabilization and heat transfercharacteristics of the fluidized-bed.

• SO2 removal efficiency of 90% was achieved at full

load with a calcium-to-sulfur (Ca/S) molar ratio of1.14 and temperature of 1,580 oF.

• SO2 removal efficiency of 95% was achieved at full

load with a Ca/S molar ratio of 1.5 and temperature of1,580 oF.

• NO

x

 emissions were 0.15–0.33 lb/106 Btu.

• CO emissions were less than 0.01 lb/106 Btu.

• Particulate emissions were less than 0.02 lb/106 Btu.

Operational• Combustion efficiency ranged from an average 99.3%

at low bed levels to an average 99.5% at moderate tofull bed levels.

• Heat rate was 10,280 Btu/kWh (HHV, gross output)

(33.2% efficiency) because the unit was small and noattempt was made to optimize heat recovery.

• An advanced particulate filter (APF), using a silicon

carbide candle filter array, achieved 99.99% filtrationefficiency on a mass basis.

• PFBC boiler demonstrated commercial readiness.• ASEA Stal GT-35P gas turbine proved capable of operating commercially in a PFBC flue gas environment.Economic• The Tidd plant was a relatively small-scale facility, and

as such, detailed economics were not prepared as partof this project.

• A recent cost estimate performed on Japan’s 360-MWe

PFBC Karita Plant projected a capital cost of$1,263/kW (1997$).

1986 1987 1988 1989 1990 1991 1992 1993 1994 

Design and Construction Operation and Reporting 3/87

Cooperative agreement awarded 3/20/87NEPA process completed (MTF) 3/5/87

Environmental monitoring plancompleted 5/25/88

Ground breaking ceremony 4/6/88

Construction started 12/9/87

Operation initiated 3/91

Design completed 12/90Construction completed 12/90Preoperational tests started 12/90

3/91

DOE selected project (CCTDP-I) 7/24/86

7/86

Preaward
92 Completed Projects 2003

Project SummaryThe Tidd PFBC technology is a bubbling fluidized-bedcombustion process operating at 12 atmospheres (175psi). Fluidized-bed combustion is inherently efficientbecause the pressurized environment enhances combustion efficiency, allows very low temperatures that mitigatethermal NOx generation, promotes flue gas/sorbent reactions that increase sorbent utilization, and produces flue

gas energy that is used to drive a gas turbine. The lattercontributed significantly to system efficiency because ofthe high efficiency of gas turbines and the availability ofgas turbine exhaust heat that can be applied to the steamcycle. A bed design temperature of 1,580 oF was established because it was the maximum allowable temperatureat the gas turbine inlet and was well below temperaturesfor coal ash fusion, thermal NOx formation, and alkali

vaporization.Coal crushed to one-quarter inch or less was injected intothe combustor as a coal/water paste containing 25% waterby weight. Crushed sorbent, either dolomite or limestone,was injected into the fluidized bed via two pneumatic feedlines, supplied from two lock hoppers. The sorbent feedsystem initially used two injector nozzles but was modified to add two more nozzles to enhance distribution.In 1992, a 10-MWe equivalent APF was installed andcommissioned as part of a research and developmentprogram and not part of the CCT Program demonstration.This system used ceramic candle filters to clean oneseventh of the exhaust gases from the PFBC system. Thehot gas cleanup system unit replaced one of the sevensecondary cyclones.The Tidd PFBC demonstration plant accumulated 11,444hours of coal-fired operations during its 54 months ofoperation. The unit completed 95 parametric tests, including continuous coal-fired runs of 28, 29, 30, 31, and 45days. Ohio bituminous coals having sulfur contents of2–4% were used in the demonstration.Environmental PerformanceTesting showed that 90% SO2 capture was achievable

with a Ca/S molar ratio of 1.14 and that 95% SO2 capture

was possible with a Ca/S molar ratio of 1.5, provided 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 that sulfur capture as well as sintering was sensitive to the fineness of the dolomite sorbent (Plum Run Greenfield dolomite was the design sorbent). Sintering of fluidized- bed materials, a fusing of the materials rather than effec- tive reaction, had become a serious problem that required operation at bed temperatures below the optimum for effective boiler operation. Tests were conducted with sorbent size reduced from minus 6 mesh to a minus 12 mesh. The result with the finer material was a major posi- tive impact on process performance without the expected excessive elutriation of sorbent. The finer material in- creased the fluidization activity as evidenced by a 10% improvement in heat transfer rate and an approximately 30% increase in sorbent utilization. In addition, the pro- cess was much more stable as indicated by reductions in temperature variations in both the bed and the evaporator tubes. Furthermore, sintering was effectively eliminated. NOx emissions ranged from 0.15–0.33 lb/106 Btu, but were typically 0.2 lb/106 Btu during the demonstration. These emissions were inherent in the process, which was operating at approximately 1,580 oF. No NOx control enhancements, such as ammonia injection, were required. Emissions of carbon monoxide and particulates were less than 0.01 lb/106 Btu and 0.02 lb/106 Btu, respectively. Operational Performance Except for localized erosion of the in-bed tube bundle and the more general erosion of the water walls, the Tidd boiler performed extremely well and was considered a commercially viable design. The in-bed tube bundle expe- rienced no widespread erosion that would require signifi- cant maintenance. While the tube bundle experienced little wear, a significant amount of erosion on each of the four water walls was observed. This erosion posed no problem, however, because the area affected is not critical to heat transfer and could be protected by refractory. The prototype gas turbine experienced structural prob- lems and was the leading cause of unit unavailability during the first three years of operation. However, design changes instituted over the course of the demonstration proved effective in addres

demonstration showed tha PFBC flue gas environmEfficiency of the PFBC clated during testing from in cyclone and bed ash, tothe amount of carbon montion efficiencies averaged heights, surpassing the deUsing data for typical ful10,280 Btu/kWh (HHV) wto a cycle thermodynamic where the cycle produced power while burning PittsTidd plant was a repowertively small scale, the mesent what would be expecplant using Tidd technoloPFBC Utility Demonstratcies of over 40% are likelplant. The PFBC demonstration a

Ohio Power’s Tidd Plant led understanding of the techno
In summary, the Tidd project showed that the PFBCsystem could be applied to electric power generation.Further, the demonstration project led to significant refinements and understanding of the technology in theareas of turbine design, sorbent utilization, sintering,post-bed combustion, ash removal, and boiler materials.Testing of the APF for over 5,800 hours of coal-firedoperation showed that the APF vessel was structurallyadequate; the clay-bonded silicon carbide candle filterswere structurally adequate unless subjected to side loadsfrom ash bridging or buildup in the vessel; bridging wasprecluded with larger particulates included in the particulate matter; and filtration efficiency (mass basis) was99.99%.Economic PerformanceThe Tidd plant was a relatively small-scale demonstrationfacility, so detailed economics were not prepared as partof this project. However, a recent cost estimate performedon Japan’s 360-MWe PFBC Karita Plant projected a capital cost of $1,263/kW (1997$).Commercial ApplicationsCombined-cycle PFBC permits use of a wide range ofcoals, including high-sulfur coals. The compactness ofbubbling-bed PFBC equipment allows utilities to significantly increase capacity at existing sites. Compactnessdue to pressurized operation reduces space requirementsper unit of energy generated. PFBC technology appears tobe best suited for applications of 50 MWe or larger. Capable of being constructed modularly, PFBC generatingplants permit utilities to add increments of capacity economically to match load growth. Plant life can be extended by repowering with PFBC using the existing plantarea, coal- and waste-handling equipment, and steamturbine equipment.The 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) 716-1585

American Electric Power1 Riverside PlazaColumbus, OH 43215mjmudd@aep.com(614) 716-1292 (fax)

Victor Der, DOE/HQ, (301) 903-2700

victor.der@hq.doe.gov

Donald W. Geiling, NETL, (304) 285-4784

donald.geiling@netl.doe.gov

ReferencesTidd PFBC Hot Gas Cleanup Program Final Report.Report No. DOE/MC/26042-5130. The Ohio PowerCompany. October 1995. (Available from NTIS asDE96000650.)Tidd PFBC Demonstration Project Final Report, Including Fourth Year of Operation. The Ohio Power Company.August 1995. (Available from DOE Library/Morgantown,1-800-432-8330, ext. 4184 as DE96000623.)

Tidd PFBC Demonstrat1, 1994–March 30, 199T8. The Ohio Power Cofrom NTIS as DE96004Tidd PFBC DemonstratOperation. Report No. D2. The Ohio Power ComNTIS as DE96000559 fVol. 2.)Tidd PFBC DemonstratSummary. U.S. Departm

Coal and sorbent conveyors can be seen just after entering theTidd plant.
94 Completed Projects 2003

Nucla CFB DemonstrationProjectProject completedParticipantTri-State Generation and Transmission Association, Inc.Additional Team MembersFoster Wheeler Energy Corporation*—technology

supplier

Technical Advisory Group (potential users)—cofunderElectric Power Research Institute (EPRI)—technical

consultant

LocationNucla, Montrose County, CO (Nucla Station)TechnologyFoster Wheeler’s atmospheric circulating fluidized-bed(ACFB) combustion systemPlant Capacity/Production110 MWe (gross), 100 MWe (net)CoalWestern bituminous—Salt Creek, 0.5% sulfur, 17% ashPeabody, 0.7% sulfur, 18% ashDorchester, 1.5% sulfur, 23% ashProject FundingTotal $160,049,949 100%DOE 17,130,411 11Participant 142,919,538 89

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 atatmospheric pressure. In the combustion chamber, astream of air fluidizes and entrains a bed of coal, coalash, and sorbent (e.g., limestone). Relatively low combustion temperatures limit NOx formation. Calcium in

the sorbent combines with SO2 gas to form calcium

sulfite and sulfate solids, and solids exit the combustionchamber and flow into a hot cyclone. The cyclone separates the solids from the gases, and the solids are recycled for combustor temperature control. Continuouscirculation of coal and sorbent improves mixing and

extends the contact time moting high utilization oture efficiency. Heat in thclone is recovered in the through a baghouse wherSteam generated in the Apower.Three small, coal-fired, sStation were replaced wisteam generator capable (gross) turbine generatorturbine generator powers tors (12.5 MWe gross eac

* Pyropower Corporation, the original technology developer and supplier,was acquired by Foster Wheeler Energy Corporation.Clean Coal Technology Demonstration ProgramAdvanced Electric Power GenerationFluidized-Bed Combustion
Calendar Year

 3 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 

Results SummaryEnvironmental• Bed temperature had the greatest effect on pollutant

emissions and boiler efficiency.

• At bed temperatures below 1,620 oF, sulfur capture

efficiencies of 70% and 95% were achieved at calcium-to-sulfur (Ca/S) molar ratios of 1.5 and 4.0,respectively.

• During all tests, NOx emissions averaged

0.18 lb/106 Btu and did not exceed 0.34 lb/106 Btu.

• CO emissions ranged from 70–140 ppmv.• Particulate emissions ranged from 0.0072–0.0125

lb/106 Btu, corresponding to a removal efficiency of

99.9%.

• Solid waste was essentially benign and showed potential as an agricultural soil amendment, soil/roadbed

stabilizer, or landfill cap.

Operational• Boiler efficiency ranged from 85.6–88.6% and combustion efficiency ranged from 96.9–98.9%.

• A 3:1 boiler turndown capability was demonstrated.• Heat rate at full load was 11,600 Btu/kWh and was

12,400 Btu/kWh at half load.

Economic• Capital cost for the Nucla retrofit was $1,123/kW and

normalized power production cost was 64 mills/kWh.

1987 1988 1989 1990 1991 1992 1993 1994 1995 

Preaward Operation and Reporting

10/87 10/88

DOE selectedproject (CCTDP-I)10/7/87

Environmental monitoringplan completed 2/27/88

NEPA process completed (MTF) 4/18/88

Operationcompleted 1/91

Operation test program initiated 8/88

Cooperative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92
96 Completed Projects 2003

Project SummaryFluidized-bed combustion evolved from efforts to find acombustion process conducive to controlling pollutantemissions without external controls. Fluidized-bed combustion enables efficient combustion at temperatures of1,400–1,700 oF, well below the thermal NOx formationtemperature (2,500 oF), and enables high SO2-capture

efficiency through effective sorbent/flue gas contact.ACFB differs from the more traditional fluid-bed combustion. Rather than submerging a heatexchanger in the fluid bed, which dictates a low fluidization velocity, ACFB uses a relatively high fluidizationvelocity, which entrains the bed material. Hot cyclonescapture and return the solids emerging from the turbulentbed to control temperature, extend the gas/solid contacttime, and protect a downstream heat exchanger.Interest and participation of DOE, EPRI, and the Technical Advisory Group (potential users) resulted in the evaluation of ACFB potential for broad utility applicationthrough a comprehensive test program. Over a two-and-ahalf-year period, 72 steady-state performance tests wereconducted and 15,700 hours logged. The result was adatabase that remains the most comprehensive availableresource on ACFB technology.Operational PerformanceBetween July 1988 and January 1991, the plant operatedwith an average availability of 58% and an average capacity factor of 40%. However, toward the end of the demonstration, most of the technical problems had been overcome. During the last three months of the demonstration,average availability was 97% and the capacity factor was66.5%.Over the range of operating temperature at which testingwas performed, bed temperature was found to be the mostinfluential operating parameter. With the exception ofcoal-fired configuration and excess air at elevated temperatures, bed temperature was the only parameter thathad a measurable impact on emissions and efficiency.Combustion efficiency, a measure of the quantity of carbon that is fully oxidized to CO2, ranged from 96.9–

98.9%. Of the four exit sources of incompletely burned

carbon, the largest was carbon contained in the fly ash(93%). The next largest (5%) was carbon contained in thebottom ash stream, and the remaining feed-carbon loss(2%) was incompletely oxidized CO in the flue gas. Thefourth possible source, hydrocarbons in the flue gas, wasmeasured and found to be negligible.Boiler efficiencies for 68 performance tests varied from85.6–88.6%. The contributions to boiler heat loss wereidentified as unburned carbon, sensible heat in dry flue gas,fuel and sorbent moisture, latent heat in burning hydrogen,sorbent calcination, radiation and convection, and bottomash cooling water. Net plant heat rate decreased with increasing boiler load, from 12,400 Btu/kWh at 50% of fullload to 11,600 Btu/kWh at full load. The lowest valueachieved during a full-load steady-state test was 10,980Btu/kWh. These values were affected by the absence ofreheat, the presence of the three older 12.5-MWe turbinesin the overall steam cycle, the number of unit restarts, andpart-load testing.

Environmental PerforAs indicated above, bed timpact on ACFB performsions. Exhibit 43 shows ththe Ca/S molar ratio requThe Ca/S molar ratios wecium content of the sorbethe calcium content of the of about 1.5 was sufficiention in the 1,500–1,620 °F requirement jumped to 5.Exhibit 44 shows the effecretention at average bed teCreek and Peabody coals respectively. To achieve 7

106 Btu emission rate requ

a Ca/S molar ratio of apprachieve an SO2 reduction 

approximately 4.0 is neces1.5% sulfur content, requilar ratio for a given reduct

Ex

 Effect of B

on Ca/S 

Plant layout with coal and limestone feed locations.
The NOx emissions measured throughout the demonstration were less than 0.34 lb/106 Btu, which is well below

the regulated value of 0.5 lb/106 Btu. The average level of

NOx emissions for all tests was 0.18 lb/106 Btu. The NOx

emissions indicate a relatively strong correlation withtemperature, increasing from 40 ppmv (0.06 lb/106 Btu) at

1,425 oF to 240 ppmv (0.34 lb/106 Btu) at 1,700 °F. Limestone feed rate was also identified as a variable affecting

NOx emissions, i.e., somewhat higher NOx emissions

resulted from increasing calcium-to-nitrogen (Ca/N) molar ratios. The mechanism was believed to be oxidation ofvolatile nitrogen in the form of ammonia (NH3) catalyzed

by calcium oxide. The CO emissions decreased as temperature increased, from 140 ppmv at 1,425 oF to 70ppmv at 1,700 oF.At full load, the hot cyclones removed 99.8% of the particulates. With the addition of baghouses, removal efficiencies achieved on Peabody and Salt Creek coals were99.905% and 99.959%, respectively. This equated toemission levels of 0.0125 lb/106 Btu for Peabody coal and

0.0072 lb/106 Btu for Salt Creek coal, well below the

required 0.03 lb/106 Btu.

Economic PerformanceThe final capital costs associated with the engineering, construction, and start-up of the NuclaACFB system were $112.3 million. This represents a cost of $1,123/kW (net). The total powercost associated with plant operations betweenSeptember 1988 and January 1991 was approximately $54.7 million, resulting in a normalizedcost of power production of 64 mills/kWh. Theaverage monthly operating cost over this periodwas about $1,888,000. Fixed costs representabout 62% of the total and include interest(47%), taxes (4.8%), depreciation (6.9%), andinsurance (2.7%). Variable costs represent morethan 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 a U.S. utility plant with ACFB technology and showed the technology’s ability to burn a

wide variety of coals cleanly and efficiently. The comprehensive database resulting from the Nucla project enabledthe resultant technology to be replicated in numerouscommercial plants throughout the world. Nucla continuesin commercial service.Today, every major boiler manufacturer offers an ACFBsystem in its product line. There are now more than 170fluidized-bed combustion boilers of varying capacityoperating in the U.S. and the technology has made significant market penetration abroad. The fuel flexibility andease of operation make it a particularly attractive powergeneration option for the burgeoning power market indeveloping countries.

ContactsJoe Egloff, (303) 452-6

Tri-State Generation Association, Inc.P.O. Box 33695Denver, CO 80233(303) 254-6066 (fax)

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Thomas Sarkus, NETL, 

sarkus@netl.doe.gov

ReferencesDemonstration Program Reports. Report No. DOUte Electric Associationfrom NTIS as DE92001Economic Evaluation RDOE/MC/25137-3127. tion, Inc., March 1992. DE93000212.)Colorado-Ute Nucla Sta(CFB) Demonstration—EPRI Report No. GS-74Nucla CFB Demonstratsign Report. Report No. rado-Ute Electric Assoc(Available from NTIS a

Exhibit 44

Calcium Requirements and

Sulfur Retentions for Various Fuels
98 Completed Projects 2003
Advanced Electric Power Gener

Integrated Gasification Combine
100 Completed Projects 2003

Clean Coal Technology Demonstration ProgramAdvanced Electric Power GenerationIntegrated Gasification Combined-CyclePiñon Pine IGCC PowerProjectProject completedParticipantSierra Pacific Power CompanyAdditional Team MembersFoster Wheeler USA Corporation—architect, engineer,

and constructor

The M.W. Kellogg Company—technology supplierBechtel Corporation—start-up engineerWestinghouse Corporation—technology supplierGeneral Electric—technology supplierLocationReno, Storey County, NV (Sierra Pacific PowerCompany’s Tracy Station)TechnologyIntegrated gasification combined-cycle (IGCC) using theKRW air-blown pressurized fluidized-bed coal gasification systemPlant Capacity/Production107 MWe (gross), 99 MWe (net)CoalSouthern Utah bituminous, 0.5–0.9% sulfur (design coal);Eastern bituminous, 2–3% sulfur (planned test)Project FundingTotal $335,913,000 100%DOE 167,956,500 50Participant 167,956,500 50Project ObjectiveTo demonstrate air-blown pressurized fluidized-bed IGCCtechnology incorporating hot gas cleanup (HGCU); toevaluate a low-Btu gas combustion turbine; and to assess

long-term reliability, availability, maintainability, andenvironmental performance at a scale sufficient to determine commercial potential.Technology/Project DescriptionDried and crushed coal and limestone are introduced intoa KRW air-blown pressurized fluidized-bed gasifier.Crushed limestone is used to capture a portion of thesulfur. The sulfur reacts with the limestone to form calcium sulfide which, after oxidation, exits as calcium sulfate along with the coal ash in the form of agglomeratedparticles suitable for landfill.Low-Btu coal gas (140 Btu/standard cubic foot) leavingthe gasifier passes through cyclones, which return most ofthe entrained particulate matter to the gasifier. The gas,which leaves the gasifier at about 1,700 oF, is cooled toabout 1,100 oF before entering the hot gas cleanup system. During cleanup, virtu

ticulates are removed by ctraces of sulfur are removoxide sorbent in a transpoThe cleaned gas then ente6FA) combustion turbine, (gross) generator. Exhausbine is used to produce stgenerator (HRSG). Superdrives a condensing steam produce about 46 MWe (gThe IGCC plant is designthe sulfur in the coal and 

less CO2 than a comparab

The superior environmenthe inherent efficiency of gasifier and incorporation 
Calendar Year

 3 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 

Results SummaryOperational• The project succeeded in identifying and working

through a number of problems, made possible onlythrough full-scale system demonstrations, and positioned the technology for commercialization.

• Operational testing proved the ability of the KRW

gasifier to produce coal-derived synthesis gas of design quality—two runs achieved 145 Btu/standardcubic foot.

• The power island demonstrated a 94% availability in a

base load operating mode after working through aquality control problem in the HRSG, replacing anundersized turbine/generator coupling, and uncovering a shortcoming in the 2nd stage bucket shroud design in the hot gas path of the first-of-a-kind GEMS6001FA gas turbine.

• New start-up procedures for the IGCC system were

developed to avoid accelerated temperature rampsupon ignition, which threatened the integrity of therefractory and ceramic candle filters, and to avoid useof an oxidant (air), which introduced the potential for

fire. But, once up to temperature and operating, thegasifier proved to be easy to control.

• The fines removal system for the hot gas particulate

filtration vessel was modified, which included increasing the size of the filter fines depressurization binfilters, using nuclear- and vibration-based level detectors in all the bins, and incorporating Skimmer valves(which provide bursts of high-pressure gas) to preventbridging of fines in bin outlet sections.

• Testing suggested modifying the hot gas particulate

filter to improve durability and enhance protection forthe gas turbine in the event of candle element failures.

• The lower section of the gasifier was enlarged to facilitate limestone and ash (LASH) removal and cooling.• The hot gas desulfurizer and regenerator system, using

a transport reactor, showed promise after replacing thesorbent with a more physically durable material.

Environmental• Steady-state operation was not reached in the course of

testing, so environmental performance could not beevaluated.

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Design and Construction Operation and Re

9/91 8/92 

DOE selectedproject(CCTDP-IV)9/12/91

Cooperative agreement awarded 8/1/92

Project co

Ground breaking/construction started 2/95

NEPA process completed (EIS) 11/8/94

Design completed 8/95

Environmental monitoring plancompleted 10/31/96

Preoperational tests initiated 11/96

1/98

Operation initiated 1/98

Construction completed 2/97

Economic• Steady-state operatio

testing, so economic ated.
102 Completed Projects 2003

Project SummaryThe project set out to assess pressurized fluidized-bedgasification technology, hot gas (1,000 °F) sulfur andparticulate removal, and low-Btu gas combustion turbineperformance in an IGCC application. The testing provided valuable information to guide developers in completing a course of action toward design of a commercialIGCC configuration embodying the basic system technologies. But the IGCC system did not reach steady-stateoperation, so environmental and economic performancecould not be evaluated. Following is a synopsis of theresults coming out of the operational assessment completed during the demonstration period.Operational PerformanceThe power island, which includes the gas turbine, heatrecovery steam generator (HRSG), and steam turbinebegan operation on natural gas in October 1996. The gasturbine is a General Electric MS6001FA—a first-of-akind unit designed to operate at a 2,350 °F firing temperature on 140 Btu/standard cubic foot coal-derived syntheticgas (syngas). Overall, the power island performance wasgood, demonstrating a 94% availability in a base loadoperating mode. Early operations uncovered some qualitycontrol problems in the HRSG and an undersized gasturbine/generator coupling, which were easily resolved.Also identified was a shortcoming in the 2nd stage bucket

shroud design, which caused a premature failure. Theshroud on the periphery of the 2nd stage bucket in the hot

gas path distorted radially and contacted and damaged thehoneycomb seal blocks. General Electric replaced thebucket assembly and returned the damaged parts for rootcause analysis.Testing of the gasifier island included 18 separatestart-up attempts, each ending with a malfunction and incorporation of modifications to improve system performance. The longest syngas production run was 25 hoursand the cumulative hours totaled 127.5. Although brief, theoperation proved the ability of the KRW gasifier to producecoal-derived syngas of the quality predicted by design—two runs achieved 145 Btu/standard cubic foot. The unitexperienced accelerated temperature ramps during start-up(once the bed is ignited), which induced spalling of thegasifier refractory and threatened the integrity of the ceramic candle filters in the hot gas particulate filtration sys- tem. Moreover, start-up used hot air, an oxidant, which has the potential to cause fires in a system normally operated in a reducing environment—residual fuel on or in compo- nents can catch fire if ignition temperatures are reached. A fire occurred during the last start-up and caused extensive damage to the hot gas particulate filtration system. At the close of the demonstration period, new inert gas start-up schemes were developed to address both rapid heat up and oxidation problems. Once up to temperature and operating, the gasifier proved easy to control. Failure to remove fines from the hot gas particulate filtra- tion (HGPF) vessel caused the bulk of failed start-ups. The system includes the HGPF, a screw feeder/cooler at the base of the HGPF, a filter fines collection bin (collec- tion bin) to receive the HGPF fines, a filter fines depres- surization bin (depressurization bin) to bring the system down to atmospheric pressure, and a filter fines feed bin (feed bin) to serve as a surge bin for the fines combustor. Testing led to development of several modifications to resolve the fines removal problems. Depressurization bin filters, through which vented gas passes to prevent emissions, were increased by an order of magnitude. Capacitance- type bin level detectors, including those in the HGPF, were replaced with nuclear level detection devices and vibration-based level detection, which subsequently functioned well. The HGPF vessel was further modified by incorporating a thermocouple array. Incorporation of Skimmer valves, pro- viding a burst of high-pressure gas against the bin wall, in lieu of Evaser fluidizing nozzles, resolved the problem of fines bridging in the cone sections of the collection and depressurization bins. Also, testing suggested modifying the hot gas particulate filter to improve dura- bility and enhance protection for the gas turbine in the event of candle element failures. The ceramic candles are subject to failure from back-up of material in the fines removal system and thermal shock and fatigue failures. And, 

installed with each candle did not perform effectivelyrequires system shutdown the fines removal system. native candle filter system SGD designs that show prRepeated start-ups, accelestart-up in early testing, anresulted in spalling of the plugged the LASH removvolume of the annulus prosufficient cooling of the Lplacing the original two-lalayer refractory and fire brincreasing the annulus volrefractory, using a revised from the grid area of the afluidized-bed region to profatigue failure. HRSG in foreground and gasifier island in bac
Failure of the fines removal system to provide a continuous output caused erratic operation of the fines combustor due to surging feed rates. The resultant surging of thecombustor also contributed to seal damage between thecombustor and HRSG. The solution was the addition ofa diverter line from the fines removal system to thewaste silo to provide an option prior to establishing asteady-state feed rate. An early candle filter failurepointed out poor SGD performance and inadequate protection for the recycle gas compressor, which experienced erosion of the impeller as a result of particulateincursion. The only other major failure was in the combustion air line, which burned through as a result of fuelaccumulating in the line following system shutdown andbed slump. The solution was simply to blow out the lineprior to start-up.The hot gas desulfurizer and regeneration system showedpromise. After the initial sorbent did not hold up physically in the entrained bed transport reactor system, an- other sorbent was identified and installed, and it per- formed well during the short runs. The demonstration ended with Sierra Pacific trying to divest its power generation facilities, a condition of its earlier merger with Nevada Power. Wisconsin Public Service had expressed intentions to pursue commercial- ization of the Piñon Pine IGCC system and planned to purchase Sierra’s Tracy Station, including the Piñon Pine Plant; however, the sale was cancelled by the Nevada legislature’s imposition of a moratorium on sale of gen- eration assets until July 2003. This reflects recognition that despite the difficulties encountered, the IGCC system shows promise. The demonstration resulted in the engi- neering knowledge requisite to establishing a commercial design for fluidized-bed gasification. The demonstration also provided valuable lessons learned for a broad range of advanced power generation technologies. Commercial Applications The Piñon Pine IGCC system concept is suitable for new power generation, repowering needs, and cogeneration applications. The net heat rate for a proposed greenfield plant using this technology is projected to be 7,800 Btu/kWh (43.7% efficiency), representing a 20% increase in thermal efficiency compared with a conven- tional pulverized coal plant with a scrubber and a compa- rable reduction in CO2 emissions. The compactness of an IGCC system reduces space requirements per unit of en- ergy generated relative to other coal-based power genera- tion systems. The advantages provided by phased modular construction reduce the financial risk associated with new capacity additions. Furthermore, hot gas cleanup provides for extremely low emissions and efficiency gains through reduced heat loss. The KRW IGCC technology offers tremendous fuel flexibility. It is capable of gasifying all types of coals, including high-sulfur, high-ash, low-rank, and high- swelling coals, as well as biowaste or refuse-derived waste, with minimal environmental impact. There are no significant process waste streams that require remedi- ation. The only solid waste from the plant is a mixture of ash and calcium sulfate, a nonhazardous waste. Conveyor leading to coal storage facility. Contacts Bob Werner, Vice Presi

Sierra Pacific Power P.O. Box 10100 Reno, NV 89520-00bwerner@npc.com Victor K. Der, DOE/HQvictor.der@hq.doe.g

Donald W. Geiling, NE

donald.geiling@netl

References Piñon Pine IGCC PoweU.S. Department of EneSierra Pacific ResourceDepartment of Energy. FCompany. January 2001Tracy Power Station – UProject Public Design Rpany. December 1994. Comprehensive Report Technology Programs: U.S. Department of Ene
104 Completed Projects 2003

Tampa Electric IntegratedGasification Combined-CycleProjectProject CompletedParticipantTampa Electric CompanyAdditional Team MembersTexaco Development Corporation—gasification

technology supplier

General Electric Corporation—combined-cycle

technology supplier

Air Products and Chemicals, Inc.—air separation unit

supplier

Monsanto Enviro-Chem Systems, Inc.—sulfuric acid

plant supplier

TECO Power Services Corporation—project manager and

marketer

Bechtel Power Corporation—architect and engineerLocationMulberry, Polk County, FL (Tampa Electric Company’sPolk Power Station (PPS), Unit No. 1)TechnologyAdvanced integrated gasification combined-cycle(IGCC) system using Texaco’s pressurized, entrainedflow, oxygen-blown gasifier technologyPlant Capacity/Production315 MWe (gross), 250 MWe (net)CoalIllinois #5 & #6, Pittsburgh #8, West Kentucky #11, andKentucky #9, Indiana #5 & #6 (2.5–3.5% sulfur); petcoke; petcoke/coal blends; and biomassClean Coal Technology Demonstration ProgramAdvanced Electric Power GenerationIntegrated Gasification Combined-Cycle

Project FundingTotal* $303,288,446 100%

DOE 150,894,223 49Participant 152,394,223 51Project ObjectiveTo demonstrate IGCC technology in a greenfield commercial electric utility application at the 250-MWe size using apressurized, entrained-flow, oxygen-blown gasifier withfull heat 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 approximately 245 Btu/SCFsyngas (LHV) in a Texaco gasifier. Molten ash flows out ofthe bottom of the gasifier into a water-filled sump where itforms a solid slag. The syngas moves from the gasifier to a

radiant syngas cooler and (CSC), which cool the synpressure steam. The coolesyngas scrubber for particsis reactor converts carbosyngas to hydrogen sulfid

moved. The raw syngas is tering a conventional amisulfuric acid plant (SAP). heated and routed to a comgeneration. A GE MS 700MWe. Thermal NO

x is con

ing nitrogen. A steam turbing the syngas and superhgases in the HRSG to prodair separation unit consumquire 10 MW, resulting in The plant heat rate is 9,65

*Additional project cost overruns were funded 100% by the participant for a final total project funding of $606,916,000.
Calendar Year

 3 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 

Results SummaryEnvironmental Performance• The PPS IGCC removed over 97% of feedstock sulfur

when operated on low-cost, high-sulfur coal, petcoke,and coal/petcoke blends.

• Typical NOx emissions were 0.7 lb/MWh, which were

below the permitted limit of 0.9 lb/MWh and far below New Source Performance Standard (NSPS) NOx

levels of 1.6 lb/MWh for electric utility units.

• The PM emissions were typically less than 0.04 lb/ MWh,

which is about 5% of those from conventional coal-firedplants equipped with electrostatic precipitation.

• The CO emissions were permitted at 99 lb/hr and averaged 7.2 lb/hr; volatile organic compound (VOC)

emissions were negligible; and mercury emissions (oncoal) without controls were half the potential releasebased on mercury levels in the coal.

1988 1989 1990 1991 1994 1995 1996 1997 2001 

Preaward Design and Construction 12/89 3/91

**

DOE selected project (CCTDP-III)12/19/89

Cooperative agreement awarded 3/11/91

Preoperational tests initiated 6/96

Construction completed 8/96

Operation initiated 9/96

9/96

Design completed 8/94NEPA process completed (EIS) 8/17/94Construction started 8/94

Operation and Repo

Environmental monitoring plan completed 5/96

**

Deopecom

Operational Performance• The PPS combustion turbine logged 34,800 hours over

the 5-year demonstration, of which 28,500 hours weresyngas-fired; syngas firing produced over 8.6 millionMWh of electricity.

• The gasifier on-stream factor steadily increased,

reaching 70–80% after 21⁄2 years; overall PPS availability, with distillate fuel as backup, averaged 90%after 11⁄2 years.

• Carbon conversion was lower than expected—in the

low to mid 90% range versus the expected 97.5–98%.This rendered the ASU design capacity inadequatebecause of a need to recycle flyash, lowering PPSoutput to 235 MWe net, and required doubling thecapacity of the solids handling system.

• Refractory liner life was problematic during the demonstration largely due to frequent fuel changes and

attendant undesirable fluctuations in operating conditions, but a coal/petcoke blend was identified toeliminate the problem in commercial service.

• In the high-temperature heat recovery systems downstream of the gasifier, the radiant syngas cooler seals

underwent design chtion defects; convectmetric improvements clean gas heat exchanstress corrosion.

• A COS hydrolysis u

fur-reduction targetadded to prevent buMDEA unit.

• “Y” strainers and a 1

critical to turbine prostart-ups.

Economic Performa• A capital cost of $1,6

a new 250 MWe (netconfiguration incorpcost of $1,300/kW (2plant that allowed foof scale, technology proven configuration
106 Completed Projects 2003

Project SummaryTampa Electric worked with the local community, stateorganizations, and environmental groups to make theproject an environmental showcase; and engaged DOE andthe technical community to move IGCC closer to mainstream market acceptance. Both of these goals were met.This project has been the recipient of numerous environmentaland technological achievement awards. These include theEcological Society of America Corporate Award, the FloridaAudubon Society Corporate Award, and Power magazine’s

1997 Power Plant of the Year Award. The plant was inductedinto Power magazine’s Power Plant Hall of Fame.

Over the 5-year demonstration period, Tampa Electriccarried out a systematic campaign to address and resolvethe usual technical issues accompanying first-of-a-kindplants. Tampa Electric showed through the demonstration that a modest-sized utility, with expertise in coalfired generation, can build and operate an IGCC plant.Environmental PerformanceThe PPS IGCC removed over 97% of the feedstock sulfurwhen operated on low-cost, high-sulfur coals, petcoke, andblends. A material balance on a 3.0% sulfur coal showedthat 7.0% of the sulfur is locked up in the inert slag leavingthe gasifier. The MDEA acid gas system removed 97.5% ofthe H2S from the raw syngas. The COS hydrolysis to H2

S

proved critical to maintaining high sulfur capture efficiencybecause 5% of the sulfur in coal feedstocks was convertedto COS (twice the amount expected) and the MDEA system was not effective in removing COS. The SAP recovered 99.7% of the sulfur it was fed.Permit limits on NOx emissions during the PPS demonstration period were 25 parts per million by volume on a

dry basis (ppmvd) corrected to 15% O2. This value

equated to 35 parts per million (ppm) as measured at thestack by a continuous emissions monitor (CEM). Thepermit limit is also equivalent to about 220 lb/hr NOx or

0.9 lb/MWh. Typical Polk IGCC NOx emissions were

about 0.7 lb/MWh, or below 30 ppm by CEM. Theseemission rates are a fraction of those from conventionalcoal-fired power plants equipped with low-NOx combustion systems. For comparison, the NSPS for electric utility

units is 1.6 lb/MWh, regardless of fuel type.

The PM emissions from the IGCC are typically less than0.04 lb/MWh, which is approximately 5% of those fromconventional coal-fired plants equipped with electrostaticprecipitators. These near-zero emissions are the result ofthe concentrated, low-volume raw syngas flow and application of intensive liquid scrubbing and no less than 15stages of liquid-gas contact.The CO emissions, permitted at 99 lb/hr, averaged7.2 lb/hr. The VOC emissions, permitted at 3 lb/hr, averaged 0.02 lb/hr. Mercury emissions were not regulated,but measurements taken showed that the IGCC removedabout half of the mercury constituent in coal feedstocks.Operational PerformanceOver the course of the demonstration, the PPS combustion turbine logged 34,800 hours of which 28,500 hourswere syngas fired. The 28,500 hours of syngas firingproduced over 8.6 million MWh of electricity. In producing the syngas, the gasifier typically consumed 2,500 tonsof coal or coal/petcoke blends per day.The gasifier and associated systems involved in producingclean syngas showed steady improvement in the unit’s inservice (on-stream) factor over the first four years, reaching 70–80% after 21⁄2 years, before suffering a setback inthe fifth and final demonstration year. The fifth year wasnot considered representative. It included a lengthyplanned outage to deal with gasifier refractory damageincurred by frequent feedstock changes, followed by arare ASU forced outage and the one-time removal ofsootblower lances. The on-stream factor is the percentageof time the gasifier and associated systems were in operation over the total number of hours in the year of operation. The availability of the combined-cycle power blockto produce electricity from either syngas or distillate wasapproximately 90% over the last four years of the demonstration. Tampa Electric also calculated on-peak availability because of the importance of the plant in meetingpeak summer demand. The peak availabilities for 2000and 2001 were 94.9% and 97.7%, respectively.The following is a summary of the highlights of the technical issues that emerged during the demonstration. Most ofthe issues were resolved, and others served as lessonslearned to improve the technology for future plants. Together, the issues served to 

to widespread commercial Lower-than-anticipated chad major cost and perforthrough the IGCC system98% per pass were expecsmaller Texaco gasifiers. pass carbon conversion in Even at design capacity, tenough air to meet the totgiven the unexpectedly loresulting need to recycle fity). Moreover, Tampa Elprocess low-quality fuelsEssentially all carbon steefeedstock had to be replacresistant materials, and higTampa Electric evaluated nslurry feed injectors in an aversion issue. Only marginA two-year gasifier refractestablished for the PPS wation period primarily becaThe fuel changes introducless-than-optimal operatinmade. Also, the high numbcycles experienced during erated refractory spalling. Tampa Electric carried ouduring the demonstration prime consideration. TestBlack Beauty and Mina Ncoke provided excellent ctics and the potential for lContributing to the refracity to directly measure gabasis. Thermocouples failpath. Gasifier temperature on “inferential measuremtion. Monitoring and contis critical for control of sl
All radiant syngas cooler seals eventually failed due toeither fabrication defects or design flaws, all of which werecorrected. Corrections included removal of all but 8 of the122 sootblower lances. Only four lances are used as sootblowers. The other four serve as purge points for injectionof N2 during start-up and shutdown.

The CSC fire-tube heat exchanger was a source of frequent plugging and forced outages through 1999. Theplugging primarily occurred at the CSC tubesheet inlet. In1999, significant geometric improvements dramaticallyreduced plugging by more than half. Although not eliminated, CSC pluggage is deemed manageable.The gasifier’s lower-than-expected carbon conversionrequired twice as much fly ash and associated blackwater to be processed as originally designed. This increased volume essentially overwhelmed the solidshandling system, precluded slag sales, and posed significant disposal costs. To resolve these issues, Tampa Electric (1) doubled the capacity of the fines (predominatelyflyash) handling system; (2) provided the capability torecycle 100% of the settler bottoms flyash to the gasifierslurry preparation system; (3) used condensate waterinstead of grey water in the slag removal system andstripped the ammonia from that condensate water; and(4) added a drag conveyor and screen to de-water andseparate the fly-ash from the slag. With these changes,operation on 100% coal enabled sales of the slag whilerecycling 100% of the settler bottom flyash and generating 235 MWe (net). Tampa Electric future plans includeincreasing ASU capacity to provide enough oxygen tocompensate for added fuel required to boost output tothe rated capacity of 250 MWe year round.In the original IGCC design, heat exchangers were incorporated downstream of the CSC to recover process heat bywarming clean gas and diluent N2 going to the combustion

turbine. Flyash deposits from the raw syngas resulted instress corrosion, cracking of the tubes, and turbine bladedamage. These heat exchangers were removed because theheat recovery, less than 1.7% of the fuel’s heating value,did not warrant the cost of redesign.Tampa Electric incorporated a COS hydrolysis system inAugust 1999. An ion exchange system was subsequently

added to control a high rate of heat-stable salt formationresulting from COS hydrolysis.The only major power block forced outages during syngas-based operation resulted from failures of the raw gas/clean gas heat exchanger (since removed) in the absenceof protective “Y” strainers. The “Y” strainers had beenremoved for repair. “Y” strainers subsequently provedcritical for start-ups because of the release of large volumes of pipe scale. To increase turbine protection andreduce “Y” strainer cleaning, a 10 micron final syngasfilter was installed upstream of the syngas strainers. Thisfilter was sized to catch a year’s worth of pipe scale.Economic PerformanceTampa Electric estimated a capital cost of $1,650/kW(2001$) for installing a new single-train 250-MWe unitat the Polk site, based on the PPS configuration andincorporating all lessons learned. This estimate reflectedthe cost of the plant as if it were instantaneously conceived, permitted, and erected (overnight cost) in mid2001. The single-train PPS configuration contributed tothe high cost in that no benefits accrued from economiesof scale in using common balance-of-plant systems.Tampa Electric also noted a number of site-specific factors adding to high costs. Tampa Electric developedanother capital cost estimate, that included moderatedsite-specific factors and allowed benefits from economies of scale, technical improvement, and replication ofproven configurations to eliminate costly re-invention.Application of these benefits reduced the estimatedcapital cost to $1,300/kW (2001$).Commercial ApplicationsDuring the course of the demonstration, Tampa Electric

addressed the future of IGCC, reflecting on typical concerns expressed by visitors, numbering over 2,500 andrepresenting 20 countries. In regard to cost, the primaryconcern, Tampa Electric pointed out that capital costs willbe lower for next-generation IGCC, further IGCC demonstrations would accelerate cost reduction, and higher initialcosts for IGCC can be offset by long-term fuel savings. Asto the associated factor of economic risk, Tampa Electricobserved that (1) assumption of overall plant performancerisk by a single entity rather than separate entities for individual process units wou

ing financing; (2) a returUnited States would enctake a longer-term investchange in the expected anatural gas to coal would 

toward IGCC. Also, envmercury or CO2 removal 

vantage to IGCC over coeration because these emconcentrated IGCC gas sAs to availability, Tampgasifier availability is losubsequent IGCC plants (2) overall PPS availabibackup fuel, is very highshowed that availability Contacts Mark Hornick, (863) 42

General Manager, PoTECO Energy P.O. Box 111 Tampa, FL 33601-01(863) 428-5927 (fax) Victor K. Der, DOE/HQvictor.der@hq.doe.g

Leo E. Makovsky, NET

leo.makovsky@netl.

References Tampa Electric Polk Potion Combined-Cycle PrTampa Electric CompanTampa Electric IntegraCycle Project—An UpdJuly 2000.
108 Completed Projects 2003

Clean Coal Technology Demonstration ProgramAdvanced Electric Power GenerationIntegrated Gasification Combined-CycleWabash River CoalGasification RepoweringProjectProject completedParticipantWabash River Coal Gasification Repowering Project JointVenture (a joint venture of Dynegy and PSI Energy, Inc.)Additional Team MembersPSI Energy, Inc.—hostDynegy (formerly Destec Energy, Inc., a subsidiary of

Natural Gas Clearinghouse)—engineer and gas plantoperator

LocationWest Terre Haute, Vigo County, IN (PSI Energy’s WabashRiver Generating Station, Unit No. 1)TechnologyIntegrated gasification combined-cycle (IGCC) usingGlobal Energy’s two-stage pressurized, oxygen-blown,entrained-flow gasification system—E-GasTechnologyTMPlant Capacity/Production296 MWe (gross), 262 MWe (net)CoalIllinois Basin bituminous (Petroleum coke also used)Project FundingTotal $438,200,000 100%DOE 219,100,000 50Participant 219,100,000 50Project ObjectiveTo demonstrate utility repowering with a two-stage, pressurized, oxygen-blown, entrained-flow IGCC system,including advancements in the technology relevant to theuse of high-sulfur bituminous coal; and to assess longterm reliability, availability, and maintainability of the system at a fully commercial scale. Technology/Project Description The Destec, now E-Gas TechnologyTM, process features an oxygen-blown, continuous-slagging, two-stage, en- trained flow gasifier. Coal is slurried, combined with 95% pure oxygen, and injected into the first stage of the gas- ifier, which operates at 2,600 °F/400 psig. In the first stage, the coal slurry undergoes a partial oxidation reac- tion at temperatures high enough to bring the coal’s ash above its melting point. The fluid ash falls through a tap hole at the bottom of the first stage into a water quench, forming an inert vitreous slag. The syngas flows to the second stage, where additional coal slurry is injected. This coal is pyrolyzed in an endothermic reaction with the hot syngas to enhance syngas heating value and improve efficiency. The syngas then flows to 

fire tube steam generator, rated steam. After cooling lates are removed in a hotgasifier. The syngas is furexchangers. The syngas is rides and passed through nyl sulfide into hydrogen removed in the acid gas rebased absorber/stripper coproduce elemental sulfur “sweet” gas is then moistthe power block. The pow192-MWe General Electriturbine, a Foster Wheeler steam generator with rehehouse reheat steam turbin
Calendar Year

 3 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 

Results SummaryEnvironmental• The SO2 capture efficiency was greater than 99%, keeping SO2 emissions consistently below 0.1 lb/106 Btu and

reaching as low as 0.03 lb/106 Btu. Sulfur-based pollutants were transformed into 99.99% pure sulfur, a highly

valued by-product—33,388 tons produced during thedemonstration period.

• The NO

x

 emissions were 0.15 lb/106 Btu, which meets

the 2003 target emission limits for ozone non-attainment areas, or 1.09 lb/MWh, and exceeds performancerequirement based on the New Source PerformanceStandard of 1.6 lb/MWh.

• Particulate emissions were below detectable limits.• Carbon monoxide emissions, averaging 0.05 lb/106 Btu,

were well within industry standards.

• Coal ash was converted to a low-carbon vitreous slag,

impervious to leaching and valued as an aggregate inconstruction or as grit for abrasives and roofing materials; and trace metals from petroleum coke were alsoencased in an inert vitreous slag.

Operational• Over the course of the demonstration, the IGCC unit

operated on coal for over 15,000 hrs, processed over1.5 million tons of coal, and produced over 23 trillionBtu of syngas and 4 million MWh of electricity.

• Design changes in the first year included: (1) using

a less tenacious refractory in the second-stage gasifierand changing the flow path geometry to eliminate ashdeposition on the second-stage gasifier walls and downstream piping; (2) changing to improved metallic candlefilters to prevent particulate breakthrough in the hot gasfilter; and (3) installing a wet chloride scrubber and aCOS catalyst less prone to poisoning to eliminate chloride and metals poisoning of the COS catalyst.

• The second year identified cracking in the gas turbine

combustion liners and tube leaks in the heat recoverysteam generator (HRSG). Resolution involved replacement of the gas turbine fuel nozzles and liners andmodifications to the HRSG to allow for more tubeexpansion.

• The third year was essentially trouble free and the

IGCC unit underwent fuel flexibility tests, which

showed that the unit modification, on a setwo different Illinois Overall thermal perfopetroleum coke operfrom 39.7% to 40.2%

• In the fourth year, the 

the rotor and stator in compressor causing a years of operation, avsteadily improved rea

Economic• The overall cost of th

which equates to aboFor an equivalent gremated at $1,700/kW. 285 MWe (net) greenlessons learned, techrate of 8,526 Btu/kWcoal-fueled unit and coke-fueled unit.

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Design and Construction Operation and Reporting 9/91 7/92

NEPA process completed (EA) 5/28/93

Design completed 5/94

Cooperative agreement awarded 7/28/92

Environmental monitoring plan completed 7/9/93Groundbreaking ceremony 7/7/93

Preoperational tests initiated 8/95

11/95 

Demonstration operati

completed 12

Construction completed 11/95Operation initiated 11/95

DOE selectedproject(CCTDP-IV)9/12/91
110 Completed Projects 2003

Design A

Coal Coal 

Nominal Throughput, tons/day 2,550 2,450 

Syngas Capacity, 106 Btu/hr 1,780 1,690 

Combustion Turbine, MWe 192 192 Steam Turbine, MWe 105 96 Auxiliary Power, MWe 35 36 Net Generation, MWe 262 261 Plant Efficiency, % (HHV) 37.8 39.7 Sulfur Removal Efficiency, % >98 >99 

Exhibit 45

Wabash Thermal Performance Summ

Project SummaryThe Wabash River Coal Gasification Repowering Projectrepowered a 1950s vintage pulverized coal-fired plant,transforming the plant from a nominally 33% efficient,90-MWe unit into a nominally 40% efficient, 262-MWe(net) unit. Cinergy, PSI’s parent company, dispatchespower from the project, with a demonstrated heat rate of8,910 Btu/kWh (HHV), second only to their hydroelectricfacilities on the basis of environmental emissions andefficiency.Beyond the integration of an advanced gasification system, a number of other advanced features contributed tothe high energy efficiency. These included:(1) hot/dry particulate removal to enable gas cleanupwithout heat loss, (2) integration of the gasifier hightemperature heat recovery steam generator with the gasturbine-connected HRSG to ensure optimum steam conditions for the steam turbine, (3) use of a carbonyl sulfide(COS) hydrolysis process to enable high-percentage sulfur removal, (4) recycle of slag fines for additional carbonrecovery, (5) use of 95% pure oxygen to lower powerrequirements for the oxygen plant, and (6) fuel gas moisturization to reduce steam injection requirements for NOxcontrol.Over the four-year demonstration period starting in November 1995, the facility operated on coal for more than 15,000hours and processed over 1.5 million tons of coal to producemore than 23 trillion Btu of syngas. For several of themonths, syngas production exceeded one trillion Btu. By theend of the demonstration, the 262-MWe IGCC unit hadcaptured and produced 33,388 tons of sulfur.Operational PerformanceThe first year of operation resolved problems with:(1) ash deposition on the second stage gasifier walls anddownstream piping, (2) particulate breakthrough in the hotgas filter system, and (3) chloride and metals poisoning ofthe COS catalyst. Modifications to the second-stage refractory to avoid tenacious bonds with the ash and to the hotgas path flow geometry corrected the ash deposition problem. Replacement of the ceramic candle filters with metallic candles proved to be largely successful. A follow-onmetallic candle filter development effort ensued using a

hot gas slipstream, which resulted in improved candle filtermetallurgy, blinding rates, and cleaning techniques. Thecombined effort all but eliminated downtime associatedwith the filter system by the close of 1998. Installation of awet chloride scrubber eliminated the chloride problem bySeptember 1996 and use of an alternate COS catalyst lessprone to trace metal poisoning provided the final cure forthe COS system by October 1997.The second year of operation identified cracking problemswith the gas turbine combustion liners and tube leaks in theHRSG. Replacement of the fuel nozzles and liners solved thecracking problem. Resolution of the HRSG problem required modification to the tube support and HRSG roof/penthouse floor to allow for more expansion.By the third year, downtime was reduced to nuisanceitems such as instrumentation-induced trips in the oxygenplant and high-maintenance items such as replacement ofhigh-pressure slurry burners every 40–50 days. In thethird year, the IGCC unit underwent fuel flexibility tests.The unit operated effectively, without modification orincident, on a second coal feedstock, a blend of two different Illinois #6 coals, and petroleum coke (petcoke).These tests added to the fuel flexibility portfolio of thegasifier, which had previously processed both lignite andsubbituminous coals during its earlier development. Theoverall thermal performance of the IGCC unit actuallyimproved during petcoke operation. The unit processed

over 18,000 tons of high-350 billion Btu of syngasof tar production and no premoving the dry char parloading. Exhibit 45 providperformance of the unit oThe fourth year of operation due to damage to the rotor of the gas turbine air comprof operation, availability of improved, reaching 79.1% summary of the production period.Environmental PerforThe IGCC unit operates w

greater than 99%. As a re

tently below 0.1 lb/106 Bt

as 0.03 lb/106 Btu. Moreo

fur-based pollutants into 9valued by-product, rather Moisturizing the syngas in tion reduced NOx emission

ment established by EPA fattainment areas. Because tion necessary for combusbine, particulate emissions 
0.012 lb/106 Btu. Also, carbon monoxide emissions were

quite low, averaging 0.05 lb/106 Btu.

The ash component of the coal results in a low-carbonvitreous slag, impervious to leaching and valued as anaggregate in construction or as grit for abrasives and roofing materials. Also, the trace metal constituents in thepetcoke were effectively captured in the slag produced.Economic PerformanceThe overall cost of the IGCC demonstration plant was$417 million, which equates to about $1,590/kW in 1994dollars. For an equivalent greenfield project, allowing foradditional new equipment required, the installed cost wasestimated at $1,700/kW. Costs include engineering, permitting, equipment procurement, project and constructionmanagement, construction, start-up, and hiring and training personnel.In the final report, the participant estimates capital costfor a new 262-MWe greenfield IGCC plant incorporatinglessons learned, technology improvements, and a heat rateof 8,250 Btu/kWh are $1,275/kW (2000$) for a coalfueled unit and $1,150/kW (2000$) for a petroleum cokeExhibit 46

Wabash River Coal Gasification Repowering Project

Production Statistics

Coal On Spec. Steam Power Sulfur

On Coal Processed Gas Produced Produced Produced

Time Period (Hr) (tons) (106 Btu) (106 lb) (MWh) (tons)

Start-up 1995 505 41,000a 230,784 171,613 71,000a 559

1996 1,902 184,382 2,769,685 820,624 449,919 3,2991997 3,885 392,822 6,232,545 1,720,229 1,086,877 8,5211998 5,279 561,495 8,844,902 2,190,393 1,513,629 12,452

1999b 3,496 369,862 5,813,151 1,480,908 1,003,853 8,557Overall 15,067 1,549,561 23,891,067 6,383,767 4,125,278 33,388aEstimates.bThe combustion turbine was unavailable from 3/14/99 through 6/22/99.

fueled unit. In designing for petcoke, some equipment canbe reduced in size and some eliminated.More recent data developed by DOE shows that a 285-MWe (net) coal-fired greenfield IGCC plant with a heatrate of 8,526 Btu/kWh would cost $1,318/kW (2000$).A 291-MWe (net) petroleum coke-fired IGCC unit witha 8,400 Btu/kWh heat rate would cost $1,260/kW.Annual fuel costs for the Wabash project ranged from$15.3–19.2 million, with an annual availability of 75%and using high-sulfur bituminous coal ranging from$1.00–1.25/106 Btu ($22–27/ton). Non-fuel operation and

maintenance (O&M) costs for the syngas facility (excluding the power block) was 6.8% of installed capital basedon 75% availability. O&M costs include operating laborand benefits, technical and administrative support on andoff site, all maintenance, chemicals, waste disposal, operating services, supplies, and 5% of the total O&M cost forbetterments. Projected O&M costs for a mature IGCCfacility (including the power block) are 5.2% of installedcapital.

Commercial ApplicaAt the end of the demonsEnergy, Inc. purchased Dtechnology. Global Energder the name “E-Gas Tecing to operate in commerergy, Ltd., a subsidiary of The immediate future for with both foreign and domfeedstocks such as petrolduction options are affordfuels/chemicals, and elecwith refinery operations acreased use of IGCC ovein IGCC cost and performdifferentials between coatance placed on displacemfuels production.ContactsPhil Amick, Technology 

(281) 293-2724ConocoPhillipsHouston, TXamickpr@conocophi

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Leo E. Makovsky, NET

leo.makovsky@netl.

ReferencesWabash River Coal GasFinal Technical Report. 

Project Joint Venture. AWabash River Coal GasProject Performance Suergy. January 2002.
112 Completed Projects 2003
Advanced Electric Power Gene

Advanced Combustion/Heat En
114 Completed Projects 2003

Clean Coal Technology Demonstration ProgramAdvanced Electric Power GenerationAdvanced Combustion/Heat EnginesHealy Clean Coal ProjectProject completedParticipantAlaska Industrial Development and Export AuthorityAdditional Team MembersGolden Valley Electric Association, Inc.—host and

operator

Stone and Webster Engineering Corp.—engineerTRW, Inc., Space & Technology Division—combustor

technology supplier

The Babcock & Wilcox Company (B&W)—spray dryer

absorber technology supplier

Usibelli Coal Mine, Inc.—coal supplierSteigers Corporation—environmental and permitting

support

LocationHealy, Denali Borough, AK (adjacent to Healy Unit No. 1)TechnologyTRW’s Clean Coal Combustion System; Babcock &Wilcox’s spray dryer absorber (SDA) with sorbent recyclePlant Capacity/Production50 MWe (nominal)CoalUsibelli subbituminous 50% run-of-mine (ROM) coal and50% waste coalProject FundingTotal $242,058,000 100%DOE 117,327,000 48Participant 124,731,000 52Project ObjectiveTo demonstrate an innovative new power plant designfeaturing integration of an advanced combustor coupledwith both high- and low-temperature emissions controlprocesses.

Technology/Project DescriptionEmissions are controlled using TRW’s clean coal combustion system, an advanced entrained/slagging combustors through staged fuel and air injection for NOx control

and limestone injection for SO2 control. Additional SO2 is

removed using B&W’s activated recycle SDA.A coal-fired precombustor increases the air inlet temperature for optimum slagging performance. The slaggingcombustors are bottom mounted, injecting the combustion products into the boiler. The main slagging combustor consists of a water-cooled cylinder that slopes towarda slag opening. The precombustor burns 25–40% of thetotal coal input. The remaining coal is injected axiallyinto the combustor, rapidly entrained by the swirling precombustor gases and additional air flow, and burned under substoichiometric conditions for NO

x

 control. The ash

forms molten slag, which flows along the water-cooled

walls and is driven by aerforces through a slot into 70–80% of the ash is remis then ducted to the furnacombustion, additional aiwindbox to NO

x ports and 

verized limestone (CaCO

combustors where it is flato lime (CaO). The mixtunot removed in the comburial, is removed in the fabflash-calcined material is slurry, which is injected in

the flue gas reacts with thsimultaneously evaporate

from the flue gas by reactmaterial on the baghouse 
Calendar Year

 3 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 

Results SummaryEnvironmental• NO

x emissions ranged from 0.208–0.278 lb/106 Btu,

with typical emissions of 0.245 lb/106 Btu on a 30-day

rolling average, which is well below the permit limitof 0.350 lb/106 Btu on a rolling day average.

• SO2 emissions were consistently less than 0.09

lb/106 Btu, with typical emissions of 0.038 lb/106 Btu,

which are below the permit limit of 0.10 lb/106 Btu(3-hour average).

• High SO2 removal efficiencies in excess of 90% were

achieved with low-sulfur coal and Ca/S molar ratios of1.4–1.8.

• Particulate matter (PM) emissions were 0.0047

lb/106 Btu, which is well below the permit limit of

0.02 lb/106 Btu.

• CO emissions were less than 130 ppm at 3.0% O2,

with typical emissions of 20–50 ppm at 3.0% O2,

which is well below the permit limit of 202 ppm at3.0% O2.

• Tests showed that the SDA system SO2 emissions, PM

emissions, and opacity were well within guarantees ofthe technology supplier.

Operational• Carbon burnout goals for the technology supplier

were achieved—greater than 99% carbon burnout at100% maximum continuous rating (MCR) for theROM, 50/50 blend of ROM/waste coal, and 55/45blend. The carbon burnout was typically 99.7%.

• The contract goal of the technology supplier for slag

recovery greater than 70% at 100% MCR for all coalswas also achieved. Slag recovery ranged from 78–87%, with a typical recovery of 83%.

• During a 90-day test in the second half of 1999, the

plant availability was 97% at a capacity factor of 95%.

• The SDA pressure drops and power consumption were

well below guarantee levels of the technology supplier.

• The system required less limestone and produced less

solid waste by-product than anticipated.

Economic• The capital costs of a 

using this system are $450.7 million ($1,5

• The variable operatin

is $7.2 million/yr (19million/yr (1993$) fo90% capacity factor)

• The levelized cost of 

stant 1993$) for the 3capacity factor).

• The levelized cost pe

$6,499/ton (constant (based on 90% capac

1989 1990 1991 1993 1994 1995 1997 1998 1999 

Preaward Design and Construction

Designstarted 7/90

4/91

Cooperativeagreementawarded 4/11/91

DOE selected project(CCTDP-III) 12/19/89

Operation and 

12/89 1/98

**

Operation initiated 1/98

Preoperational testsinitiated 8/97

NEPA process completed (EIS) 3/10/94

Design completed 10/93 Ground breaking/

construction

started 5/30/95 Environmental monitoring

plan completed 4/11/97

Constructioncompleted 11/97 

**
116 Completed Projects 2003

Project SummaryThe Healy Clean Coal Project is the first utility-scaledemonstration of the TRW clean coal combustion system.The project site is adjacent to the existing Healy Unit No.1 near Healy, Alaska and the Usibelli coal mine. Power issupplied to the Golden Valley Electric Association(GVEA).Environmental PerformanceThe entrained/slagging combustor is designed to minimize NO

x emissions, achieve high carbon burnout, and

remove the majority of fly ash from the flue gas prior tothe boiler. The slagging combustor is also the first step ofa three-step process for controlling SO2 by first converting limestone to flash-calcined lime. Second, the flash

calcined-lime absorbs SO2 within the boiler. Third, the

majority of the SO2 is removed with B&W’s SDA system,

which uses the flash-calcined lime and fly ash captured inthe baghouse. Because most of the coal ash is removed bythe slagging combustors, the recycled material is richenough in calcium content that the SDA can be operatedsolely on the recycled solids, eliminating the need to purchase or manufacture lime for the back end scrubbingsystem.During a cumulative six-month combustion system characterization test, a series of tests were performed to establish baseline performance of the combustion system whileburning ROM and ROM/waste coal blends, to map combustor performance characteristics over a broad range ofoperating conditions and hardware configurations, and todetermine the best configuration and operating conditionsfor long-term operation. During the 24-month demonstration test period, the NOx, SO2, PM, opacity, and CO emission goals were met with the exception of short-term SO2

and opacity exceed-ances emissions, as well as permpresented in Exhibit 47.Performance testing of th1999 showed that the techsurements of the SDA inlfeed, coal feed, air preheaelectrical power consumpas normal plant data from system, showed that the tetees. The results of the testees are shown in Exhibit environmental performan

 Exhibit 47

 Healy Performance Goals and Demonstration Test Program Results

(January 1998–December 1999)

Parameter NSPS Permit Goal Actual Range Actua

NO

x

0.5 lb/106 Btu (new plant after 7/97) 0.350 lb/106 Btu (30-day rolling avg) 0.20–0.35 lb/106 Btu 0.208–0.278 lb/106 Btu 0.245 

1,010 tons/yr (full load) (30-day rolling avg) (30-day rolling avg) (30-da

SO2 70% removal with emissions 0.086 lb/106 Btu (annual avg) 70% removal (minimum) ~90% removal 0.038 

<0.60 lb/106 Btu 0.10 lb/106 Btu (3-hour avg) 79.6 lb/hr max (3-hour <0.09 lb/106 Btu (30-m

65.8 lb/hr max (3-hour avg) avg) (30-minute avg correc

248 tons/yr (full load) corrected to 3% O2)

PM 0.03 lb/106 Btu 0.020 lb/106 Btu (hourly avg) 0.015 lb/106 Btu NA 0.004

99% reduction 13.2 lb/hr (hourly avg) (hourly avg)

58 tons/yr (full load)

Opacity 20% Opacity (6-minute avg) 20% Opacity (3-minute avg) 20% Opacity (3- 2–6% Opacity 3.9% 

27% Opacity (one 6-minute minute avg) (30-minute avg) (30-mperiod per hour)

CO Dependent on ambient CO 0.20 lb/106 Btu (hourly avg) 206 ppm (corrected 20–50 ppm 25.9 p

levels in the local region 202 ppm (corrected to 3% O2) to 3.0% O2) (30-minute avg (30-m

132 lb/hr, 577 tons/yr (full load) 200 ppm (corrected corrected to 3% O2) correc

to 3.5% O2)

a Measured 2.3% after correction of problems with premature filter bag failures in the baghouse.b Not measured during demonstration test program. Data are from source test in March 1999.
Operational PerformanceThe slagging stage of the combustor performed extremelywell and continuously demonstrated the capability to burnboth ROM and ROM/waste coal blends over a broadrange of operating conditions. The precombustor performed very well with ROM coal, but exhibited morevariable performance, in terms of slagging behavior, during the initial tests with ROM/waste coal blends.Localized slag freezing was observed in the precombustorduring early testing. A combination of hardware configuration and operational configuration changes were made thatminimized slag freezing. These changes included relocating the secondary air from the precombustor mix annulusto the head end of the slagging stage and completely transferring the precombustor mill air to the boiler NOx ports

following boiler warmup. These changes eliminated themixing of excess air downstream of the precombustorchamber to minimize local slag freezing and increased theprecombustor operating temperature to provide additionaltemperature margin. The mill air change had the addedbenefit of simplifying combustor operation by eliminatingthe need to monitor and control coal-laden mill air flow tothe precombustor mill air ports during steady-state operation.Testing of the slagging combustor also showed that thecontract goals were achieved, which included greater than

 Exhibit 48

Healy SDA Performance Test Results and Performance Guarantees

Operating Parameter Guarantee Range of Parameter ValuesSO2 79.6 lb/hr (max) <2.15PM 0.015 lb/106 Btu 0.0014-0.0052Opacity 20% Opacity 1.0-2.0

(3-minute avg) 27% Opacity for 3 minutes per hour

System Pressure Drop 13 in. w.g. 9.6-10.0System Power Consumption 550.5 kW 324-340

99% carbon burnout at 100% maximum continuous rating(MCR) for the performance, ROM, 50/50 blend of ROM/waste coal, and 55/45 blend; and greater than 98% carbonburnout at 100% MCR for waste coal. The carbon burnout was typically 99.7%. Slag recovery ranged from 78–87%, with a typical reading of 83%, easily meeting thecontract goal for slag recovery of greater than 70% at100% MCR for all coals.The SDA system also performed well. During performancetesting in June 1999, system pressure drops were well below the 13 inches water gage (in. w.g.) guarantee. Therange was 9.6–10.0 in. w.g. as can be seen in Exhibit 48.Power consumption was approximately 38–41% less thanthe guaranteed level. Based on these results, Stone & Webster concluded that the SDA system met all performanceguarantees.Economic PerformanceCapital and operating cost estimates were prepared by anindependent consultant to the participant for new plantsin the “lower 48” that incorporate the technology demonstrated at Healy. The capital costs for a 50-MWe and 300-MWe plant are $90.6 million (1,812 $/kW) and $450.7million (1,502 $/kW) (1993$), respectively. The variableoperating cost for the 300-MWe plant is estimated at $7.2million per year and the fixed operating costs are estimatedat $28.4 million per year based on a 90 percent capacity

factor (1993$). The leve36.5 mills/kWh (constanton of SO2 and NOx rem

1993$) for the 300-MWe Commercial ApplicaThis technology is approdustrial boiler in new or coal-fired boilers as welbecause of its high ash-rcyclone boilers may be with the entrained/slagglimited supply of high-Btemperature coal that cymercial availability of cfor SO2, NOx, and partic

tential users planning nefits to existing capacity requirements.ContactsArthur E. Copoulos, Pro

Alaska Industrial De813 West Northern LAnchorage, AK 995(907) 269-3044 (fax)acopoulos@aidea.org

Victor K. Der, DOE/HQ

victor.der@hq.doe.g

Robert M. Kornosky, NE

robert.kornosky@ne

ReferencesHealy Clean Coal ProjeEconomics Report FinaApril 2001.Spray Dryer Absorber SJune 7-11, 1999. Stone tion. February 2000.
118 Completed Projects 2003
Coal Processing for Clean Fu
120 Completed Projects 2003

Clean Coal Technology Demonstration ProgramCoal Processing for Clean FuelsCoal Preparation TechnologiesCommercial-ScaleDemonstration of the LiquidPhase Methanol (LPMEOHTM)ProcessParticipantAir Products Liquid Phase Conversion Company, L.P.(a limited partnership between Air Products and Chemicals, Inc., the general partner, and Eastman ChemicalCompany)Additional Team MembersAir Products and Chemicals, Inc.—technology supplier

and cofunder

Eastman Chemical Company—host, operator, synthesis

gas and services provider

ARCADIS Geraghty & Miller—fuel methanol tester and

cofunder

LocationKingsport, Sullivan County, TN (Eastman ChemicalCompany’s Chemicals-from-Coal Complex)TechnologyAir Products and Chemicals, Inc.’s LPMEOHTM processPlant Capacity/Production80,000 gallons/day of methanol (nominal)CoalEastern high-sulfur bituminous, 3–5% sulfurProject FundingTotal $213,700,000 100%DOE 92,708,370 43Participant 120,991,630 57

Project ObjectiveTo demonstrate on a commercial scale the production ofmethanol from coal-derived synthesis gas using theLPMEOHTM process; to determine the suitability ofmethanol produced during this demonstration for use as achemical feedstock or as a low-SO

x emitting, low-NOx

emitting alternative fuel in stationary and transportationapplications; and to demonstrate, if practical, the production of dimethyl ether (DME) as a mixed co-product withmethanol.Technology/Project DescriptionThis project has completed the demonstration, at commercial scale, of the LPMEOHTM process to produce methanol from coal-derived synthesis gas. The combined reactor and heat removal system is different from other commercial methanol processes. The liquid phase not only

suspends the catalyst but to remove the heat of reacsurface. This feature permgas streams as feed to the water-gas shift conversionLPMEOHTM reactor is preastern high-sulfur bitumtaining 3% sulfur (5% maMethanol fuel testing was and mobile applications, sutributed electric power genthe project was made availstudy the feasibility of usintransportation and power g
Calendar Year

 3 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 

Operation and Reporting

1989 1991 1995 1992 1993 1996 1997 1998 2002 

NEPA process completed (EA) 6/30/95

Construction started 10/95

Design completed 6/96

Environmental monitoring plan completed 8/29/96

4/97

Operation initiated 4/97

Construction completed 1/97Preoperational tests initiated 1/97

Operation comple

12

Project transferred to Air Products

Liquid Phase Conversion

Company, L.P. 3/95

Project resited to

Kingsport, TN 10/

93

**

Preaward

Design and Construction

12/89 10/92

DOE selectedproject (CCTDP-III)12/19/89

Cooperative agreement awarded 10/16/92

**

Results SummaryEnvironmental• Stabilized methanol from the LPMEOHTM process has

less than 1% of water by weight, is free of sulfur, andcan potentially be used directly in transportation andpower applications.

• Stabilized methanol produced from the LPMEOHTM

demonstration unit has been tested in bus and flexiblefuel vehicles. Results show that methanol producedfrom the process provides the same environmentalbenefits as chemical-grade methanol with no penaltyon fuel economy or performance.

• Diesel generator and gas turbine tests show that levels

of NO

x

 in exhaust air can be lowered when stabilized

methanol or methanol-oil-water emulsions are usedinstead of conventional oil fuels.

Operational• During the 69-month demonstration test program, the

LPMEOHTM test unit had an overall availability of97.5% with the longest operating run without interruption at 94 days.

• Over 103.9 million gallons of methanol were produced

from the facility and accepted by Eastman ChemicalCompany for use in the production of methyl acetate.

Methanol from the project was shipped to seven testlocations to study the feasibility of its use in powerand transportation applications.

• Nameplate production capacity of 80,000 gallons per

day for the demonstration unit was achieved within fourdays of start-up, and production rates exceeding 115%of design capacity were achieved within six days.

• Investigations during the LPMEOHTM demonstration

project were able to improve the long-term performanceof the methanol synthesis catalyst. The average rate ofcatalyst deactivation during one six-month period was0.17% per day, which is one-half of the original designbasis, based on earlier proof-of-concept tests.

• In either baseload or cycling operation, partial conversion of between 20% and 33% of the syngas is

economically optimal and conversion approaching50% is feasible.

• Commercial viability 

Ether (LPDMETM) prshort ton per day scacatalysts.

• The deactivation rate 

and dehydration catacess was 0.7% per daper day rate calculate

Economic• The capital cost of a 5

plant that coproduces based IGCC plant wa

• Economic studies sho

produced in an IGCC $0.50 per gallon.

**
122 Completed Projects 2003

Project SummaryThe LPMEOHTM process accomplished the objectives setout in the cooperative agreement. The demonstration unitproduced over 103.9 million gallons of methanol, operating at 97.5% availability. Originally developed to enhanceelectrical power generation using IGCC technology, theLPMEOHTM process is ideally suited for directly processing gases produced by modern coal gasifiers. TheLPMEOHTM technology provides several improvementsessential for the economic co-production of methanol andelectricity directly from gasified coal. The liquid phaseprocess suspends fine catalyst particles in an inert liquid,forming a slurry. The slurry dissipates the heat of thechemical reaction away from the catalyst surface, protecting the catalyst, and allowing the methanol synthesisreaction to proceed at higher rates.Operational PerformanceOperations began on April 2, 1997 and nameplate production capacity of 80,000 gallons per day was reachedwithin four days. Production rates exceeding 115% ofthe design level were achieved within six days.During the performance period, ideas to reduce the capitalcost of future plants were implemented. The use of gravityto return entrained catalyst slurry and condensed processoil from downstream equipment back to the LPMEOHTMreactor was successfully demonstrated, and it eliminatedthe need for expensive slurry pumps within the synthesisloop. A new, in situ catalyst activation procedure was also

developed. Previously, catalyst was activated in smallquantities and transferred to the LPMEOHTM reactor. In

situ activation involved charging the reactor with freshcatalyst and activating it at one time. The first in situ activation study began on August 24, 2001 and was completed

on June 4, 2002. Additionally, “temperature programming”was used during this demonstration to improve catalystperformance. Temperature programming is the techniqueof initially operating at low temperatures and slowly increasing the temperature with time to maintain constantproduction of methanol and extend the life of the catalyst.The average catalyst deactivation rate for this demonstration was similar to earlier results.

A second, six-month, in situ activation study began on June

28, 2002. This study was similar to the first in situ activation study except that the procedure was revised to eliminate the storage of unreduced catalyst slurry at elevatedtemperatures. The average rate of catalyst deactivationduring this study was 0.17% per day, which was about onehalf of the design basis and lower than earlier results.The LPMEOHTM demonstration project also focused onthe impact of trace contaminants in coal-derived synthesisgas on catalyst performance and lifetime. The catalystguard bed was changed to a new material that is expectedto reduce catalyst poisons such as arsenic. This new adsorbent is an activated carbon impregnated with copperoxide. Typically, fresh adsorbent can be used for about

two months before breaktLPMEOHTM demonstratiotreatment was employed wof the adsorbent by an adMethanol product-use tesoff-site. The on-site produmonitoring of the refinedset of Eastman Chemical sionally, a tank lot sample the lot could be accepted was no impact once the loprimary methanol storage cember 1997, a total of 24 ner. Eastman Chemical acmethanol for use in the prultimately cellulose acetaOff-site product testing ctems and power generatioFlorida Institute of Technand methanol blends for bing was limited, but no mAnother set of tests at ARshowed methanol blends exhibited similar performemissions as when operatlized methanol or chemicUniversity (WVU) also temethanol. On average, hymethanol and aldehydes) were slightly higher than was used.Power generation testing conducted by WVU on an ARCADIS on a U.S. Air diesel generator, by ARCA

microturbine combustor, on a fuel cell. All of the teThe LPMEOHTM project verification test run of the DME. The test was condtons per day at the LaPortvelopment Unit (AFDU). days using commercially 

The LPMEOHTM plant continues in commercial operation atEastman Chemical Company.
scale-up information and to compare catalyst aging compared to laboratory results. The deactivation rate for bothLPDMETM catalysts during the pilot scale test was 0.7%,which was an improvement over the 1.2% rate calculatedduring laboratory experiments.Environmental PerformanceMethanol produced from the LPMEOHTM process offersseveral advantages. It is a stabilized product that containsless than one percent of water by weight and is sulfurfree, and could potentially be used as a replacement fuelfor petroleum in transportation, a peaking fuel in powerapplications, a chemical feedstock, or as a source of hydrogen for fuel cells. Transportation tests were performedat three different locations on a variety of vehicles andmethanol fuel blends. Methanol produced from theLPMEOHTM process showed little difference in vehicleperformance when compared to fuels made with chemical-grade methanol. The LPMEOHTM methanol typicallyformed less NOx than the chemical-grade methanol

blends. Power application tests showed that stabilizedmethanol and methanol-oil-water emulsions could lowerNOx levels in the exhaust air from gas turbines and diesel

engines that operate on conventional oil fuels.Economic PerformanceThe economic base case for this project is a 500 short tonper day, LPMEOHTM plant that co-produces fuel-grademethanol in a coal-based IGCC power plant. The estimated capital cost for the LPMEOHTM facility in anIGCC power plant is $31.08 million. Improvements incatalyst performance, such as in situ activation, and temperature programming could provide an additional capital

cost reduction of 10%.Economic analyses show that methanol from thePMEOHTM process has a cost of less than $0.50 pergallon when co-produced in an IGCC power plant. Asthe economics of IGCC technology improve, so will theeconomics for coproduction of methanol. If the catalystperformance and lifetime improvements over the lastsix months can be maintained, variable costs for theLPMEOHTM process can be reduced by 25%. Whencombined with IGCC technology, the LPMEOHTM process can provide a pathway for local communities to

meet their electric power, transportation, and chemicalproduct needs.Commercial ApplicationsIn commercial U.S. applications, methanol is typically usedas a feedstock to produce chemicals such as formaldehyde,methyl tertiary butyl ether (MTBE—a gasoline additive),acetic acid, dimethyl terephthalate, methyl methacrylate, andfuels and solvents. Future markets for methanol could include fuel cell applications. Currently, over 50% of thedemand for DME is for use as a projectile agent. However,it is also used as a methylating agent, a laboratory systemcleaning material, and in electronics. Future markets couldinclude large-scale power production, substitution for dieselfuel, or as a replacement transportation fuel for liquefiedpetroleum gas.Development of the LPMEOHTM process in the UnitedStates will depend on several factors, including development and timing of the IGCC industry, improvements inIGCC economics, new environmental regulations affecting coal-based power generation, and other incentives.Outside of the United States, most of the current interestin the LPMEOHTM technology has come from China.China has an abundance of coal and an historical dependence on domestic chemical production, making it along-term option for use of the LPMEOHTM process.ContactsRobert J. Kirkland

Air Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501(610) 481-4866(610) 706-4811 (fax)kirklarj@apci.com

Edward Schmetz, DOE/HQ, (301) 903-3931

edward.schmetz@hq.doe.gov

Robert M. Kornosky, NETL, (412) 386-4521

robert.kornosky@netl.doe.gov

ReferencesCommercial-Scale Demonstration of the Liquid PhaseMethanol (LPMEOHTM) Process—Final Report. Air Products Liquid Phase Conversion Company, L.P. June 2003.

Topical Report Number Commercial-Scale DemMethanol (LPMEOHTM) Energy. April 1999.
124 Completed Projects 2003

Clean Coal Technology Demonstration ProgramCoal Processing for Clean FuelsCoal Preparation TechnologiesDevelopment of the CoalQuality ExpertTMProject completedParticipantsABB Combustion Engineering, Inc. and CQ Inc.Additional Team MembersBlack & Veatch—cofunder and software developerElectric Power Research Institute—cofunderThe Babcock & Wilcox Company—cofunder and pilotscale testerElectric Power Technologies, Inc.—field testerUniversity of North Dakota, Energy and Environmental

Research Center—bench-scale tester

Utility Companies—(5 hosts)LocationsGrand Forks, Grand Forks County, ND (bench tests)Windsor, Hartford County, CT (bench- and pilot-scaletests)Alliance, Columbiana County, OH (pilot-scale tests)Five utility host sitesTechnologyCQ Inc.’s EPRI Coal Quality ExpertTM (CQETM) computer softwarePlant Capacity/ProductionFull-scale testing took place at utility sites ranging in sizefrom 250–880 MWe.CoalWide variety of coals and blends

Project FundingTotal $21,746,004 100%DOE 10,863,911 50Participants 10,882,093 50Project ObjectiveThe objective of the project was to provide the utilityindustry with a PC software program it could use toconfidently and inexpensively evaluate the potential forcoal-cleaning, blending, and switching options to reduceemissions while producing the lowest cost electricity.Specifically the project was to: (1) enhance the existingCoal Quality Information System (CQISTM) database andCoal Quality Impact Model (CQIMTM) to allow assessment of the effects of coal-cleaning on specific boilercosts and performance; and (2) develop and validateCQETM, a model that allows accurate and detailed prediction of coal quality impac

cost and performance. Technology/Project DThe CQETM is a software sophistication to fueling dsystem-wide impact of fufired power plant performgeneration costs. The impimprovements; operationacompliance alternatives omance, and production coCQETM. CQETM can be ussuch impacts, or it may be default data to perform mstudies. Coal Quality Expert, CQE, CQIS, and CQIM are trademarks of the Electric Power Research Institute. Pentium is a registered trademark of Intel. OS/2 Warp is a registered trademark of IBM.

Windows is a registered trademark of Microsoft Corporation.
Calendar Year

 3 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 

Results SummaryEnvironmental• CQETM includes models to evaluate emission and

regulatory issues.

Operational• CQETM can be used on a stand-alone computer or as a

network application for utilities, coal producers, andequipment manufacturers to perform detailed coalimpact analyses.

• Four features included in the CQETM program are:

– Fuel Evaluator,– Plant Engineer,– Environmental Planner, and– Coal-Cleaning Expert.

• CQETM can be used to evaluate:

– Coal quality,– Transportation system options,– Performance issues, and– Alternative emissions control strategies.

• CQETM operates on an OS/2 Warp® (Version 3 or later)

operating system with preferred hardware requirements of a Pentium®-equipped personal computer, 1

gigabyte hard disk space, 32 megabytes RAM,1024x768 SVGA, and CD-ROM.

Economic• CQETM includes economic models to determine production cost components for coal-cleaning processes,

power production equipment, and emissions controlsystems.

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation and Reporting

DOE selectedproject (CCTDP-I)12/9/88

12/88

Cooperative agreement awarded 6/14/90

NEPA process completed

(MTF) 4/27/90

Environmental monitoringplan completed 7/31/90

Operation initiated 8/90

Preaward

Development

6/90

Field testing completed 4/93

8/90

CQE R

CQE CD-ROM is
126 Completed Projects 2003

Project SummaryCQETM began with EPRI’s CQIMTM, developed for EPRIby Black & Veatch and introduced in 1989. CQIMTM wasendowed with a variety of capabilities, including evaluating Clean Air Act compliance strategies, evaluating bidson coal contracts, conducting test-burn planning andanalysis, and providing technical and economic analysesof plant operating strategies. CQETM, which combinesCQIMTM with other existing software and databases, extends the art of model-based fuel evaluation establishedby CQIMTM in three dimensions: (1) new flexibility andapplication, (2) advanced technical models and performance correlations, and (3) advanced user interface andnetwork awareness.Operational PerformanceAlgorithm Development. Data derived from bench-,pilot-, and full-scale testing were used to develop theCQETM algorithms. Bench-scale testing was performed atABB Combustion Engineering’s facilities in Windsor,Connecticut and the University of North Dakota’s Energyand Environmental Research Center in Grand Forks,North Dakota. Pilot-scale testing was performed at ABBCombustion Engineering’s facilities in Windsor, Connecticut and Alliance, Ohio. The five field test sites were:• Alabama Power’s Gatson, Unit No. 5 (880 MWe),

Wilsonville, Alabama;

• Mississippi Power’s Watson, Unit No. 4 (250 MWe),

Gulfport, Mississippi;

• New England Power’s Brayton Point, Unit No. 2

(285 MWe) and Unit No. 3 (615 MWe), Somerset,Massachusetts;

• Northern States Power’s King Station (560 MWe),

Bayport, Minnesota; and

• Public Service Company of Oklahoma’s Northeastern,

Unit No. 4 (445 MWe), Oologah, Oklahoma.

The six large-scale field tests consisted of burning a baseline coal and an alternate coal over a two-month period.The baseline coal was used to characterize the operatingperformance of the boiler. The alternate coal, a blended orcleaned coal of improved quality, was burned in the boilerfor the remaining test period.

The baseline and alternate coals for each test site alsowere burned in bench- and pilot-scale facilities undersimilar conditions. The alternate coal was cleaned at CQInc. to determine what quality levels of clean coal canbe produced economically and then transported to thebench- and pilot-scale facilities for testing. All data frombench-, pilot-, and full-scale facilities were evaluatedand correlated to formulate algorithms used to developthe model.CQETM Capability. The OS/2®-based program evaluates

coal quality, transportation system options, performanceissues, and alternative emissions control strategies for utility power plants. CQETM is composed of technical tools toevaluate performance issues, environmental models toevaluate emissions and regulatory issues, and economicmodels to determine production cost components. Theseinclude consumables (e.g., fuel, scrubber additives), wastedisposal, operation and maintenance, replacement energycosts, and operation and maintenance costs for coal-cleaning processes, 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 Description. The CQETM includes more than100 algorithms based on the data generated in the sixfull-scale field tests. The CQETM design philosophy underscores the importance of flexibility by modeling allimportant power plant equipment and systems and theirperformance in real-world situations. This level of sophistication allows new applications to be added by assembling a model of how objects interact. Updated information records can be readily shared among all affectedusers because CQETM is network-aware, enabling users

throughout an organizatioCQETM object-oriented dedatabase management systhe same data. As a resultwhen decisions are madeCQETM also can be expanthe system. Object-orientobjects to be added and ohanced easily. For exampmade with respect to pred(i.e., slagging and fouling

object that provides these augmented. Other objects ash collection and disposado not need to be altered; lying system is maintaineSystem Requirements. C

system. CQETM can operasingle computer or on a navailable from Black & VCommercial ApplicatiThe CQETM system is appgeneration plants and largthat burn pulverized coal. suppliers, environmental regulatory institutions, antional markets for CQETM Inc. and Black & Veatch.EPRI owns the software amembers for their use. CQform of three types of licemercializer. CQ Inc. and Bsigned commercialization companies non-exclusive licenses and to offer consuse of CQETM software.CQETM was recognized in and the President of EPRI cost-shared utility research the “Sustainable Electric P
The CQETM program has been incorporated in the Vistaprogram package, which is the latest version of the software. Vista operates in the Windows® environment. The

Vista Fuels Web server has a Home Page on the WorldWide Web (http://www.fuels.bv.com) to promote the software, facilitate communications between developers andusers, and eventually allow software updates to be distributed over the Internet. The Home Page also helps attractthe interest of international utilities and consulting firms.ContactsClark D. Harrison, President, (724) 479-3503

CQ Inc.160 Quality Center Rd.Homer City, PA 15748(724) 479-4181 (fax)clarkh@cq-inc.com

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

ReferencesFinal Report: Development of a Coal Quality Expert. CQInc. June 20, 1998.“Recent Experience with the CQETM.” Harrison, Clark D.et al. Fifth Annual Clean Coal Technology Conference:Technical Papers. January 1997.Comprehensive Report to Congress on the Clean CoalTechnology Program: Development of the Coal QualityExpert. ABB Combustion Engineering, Inc., and CQ Inc.Report No. DOE/FE-0174P. U.S. Department of Energy.May 1990. (Available from NTIS as DE90010381.)

New England Power

Five utilities acted as hosts for field tests of CQETM.
128 Completed Projects 2003

Clean Coal Technology Demonstration ProgramCoal Processing for Clean FuelsCoal Preparation TechnologiesENCOAL® Mild Coal

Gasification Project

Project completedParticipantENCOAL Corporation (a wholly owned subsidiary ofBluegrass Coal Development Company)Additional Team MembersBluegrass Coal Development Company (a wholly owned

subsidiary of AEI Resources, Inc.)—cofunder

SGI International—technology developer, owner, licensorTriton Coal Company (a wholly owned subsidiary of

Vulcan Coal Company)— host

LocationNear Gillette, Campbell County, WY (Triton CoalCompany’s Buckskin Mine site)TechnologySGI International’s Liquids-From-Coal (LFC®) process

CoalLow-sulfur Powder River Basin (PRB) subbituminouscoal, 0.45% sulfurPlant Capacity/Production1,000 tons/day of subbituminous coal feedProject FundingTotal $90,664,000 100%DOE 45,332,000 50Participant 45,332,000 50Project ObjectiveTo demonstrate the integrated operation of a number ofnovel processing steps to produce two higher-heatingvalue fuel forms from mild gasification of low-sulfursubbituminous coal, and to provide sufficient products forpotential end users to conduct burn tests.

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 furthercooled in a rotary cooler and transferred to a surge bin. Asingle 50% flow rate vibrating fluidized bed (VFB) wasadded to stabilize the Process-Derived Fuel (PDF®) with

respect to oxygen and water. In the VFB, the partiallycooled, pyrolyzed solids contact a gas stream containing acontrolled amount of oxygen. Termed “oxidative deactivation,” a reaction occurs at 

ticles, reducing the tendenFollowing the VFB, the sspheric temperature in an water is added to rehydra

suppressant is added as th

The hot gas produced in tcyclone for removal of thin a quench column to stotions and to condense the 
Calendar Year

 3 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 

Results SummaryEnvironmental• The PDF® contains 0.36% sulfur with a heat content of

11,100 Btu/lb (compared with 0.45% sulfur and 8,300Btu/lb for the feed coal).

• The CDL® contains 0.6% sulfur and 140,000 Btu/gal

(compared with 0.8% sulfur and 150,000 Btu/gal forNo. 6 fuel oil).

• In utility applications, PDF® enabled reduction in SO2

emissions, reduction in NOx emissions (through flame

stabilization), and maintenance of boiler rated capacitywith fewer mills in service.

• LFC® products contained no toxins in concentrations

anywhere close to federal limits.

Operational• Steady-state operation exceeding 90% availability was

achieved for extended periods for the entire plant (numerous runs exceeded 120 days duration).

• The LFC® process consistently produced 250 tons/day

of PDF® and 250 barrels/day of CDL® 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 hydrocarbon content, however, may make CDL® more valuable as a

chemical feedstock.

Economic• A commercial plant d

tons per day would c(2001$) to construct, tenance costs of $52 

Design and Construction Operation and Reporting

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Environmental monitoring plan completed 5/29/92

12/89 9/90 7/92

Preaward

Operation 

DOEselectedproject(CCTDP-III)12/19/89

Cooperative agreement awarded 9/17/

NEPA process completed (EA) 8/1/90

Ground breaking/construction started 10/26/90

Preoperational tests initiated 4/92

Design completed 7/91

Operation initiated 7/92

Construction completed 6/92
130 Completed Projects 2003

Project SummaryOperational PerformanceThe LFC® facility operated for more than 15,000 hours

over a five-year period. Steady-state operation was maintained for much of the demonstration with availabilitiesof 90% for extended periods. The length of operation andvolume of production proved the soundness and durability of the process.Exhibit 49 summarizes ENCOAL’s production history. Bythe end of the demonstration, over 83,500 tons of PDF®

were shipped via 17 unit trains and one truck shipment toseven customers in six states. Shipments included 100%PDF® and blends from 14–94% PDF®. Over 5 million

gallons of CDL® were produced and shipped to eight

customers in seven states.As with most demonstrations, however, success requiredovercoming many challenges. The most difficult challenge was achieving stability of the PDF® product, which

had to be resolved in order to achieve market acceptance.In June 1993, efforts ceased in trying to correct persistentPDF® stability problems within the bounds of the original

plant design. The rotary cooler failed to provide the deactivation necessary to quell spontaneous ignition of PDF®.

ENCOAL concluded that a separate, sealed vessel wasneeded for product deactivation. A search for a suitabledesign led to adoption of a VFB. A 500-ton/day VFB wasinstalled between the quench table and rotary cooler.(Plans were made for installation of a second 500 ton/dayVFB but were never implemented.)Although the VFB enhanced deactivation, the PDF stillrequired “finishing” to achieve stabilization. Extensivestudy revealed that more oxygen was needed for deactivation. Two courses of action were pursued: (1) development of interim measures to finish deactivation externalto the plant, enabling immediate PDF® shipment for test

burns; and (2) development of an in-plant process forfinishing, eliminating product quality and labor penaltiesfor external finishing.“Pile layering” was the primary external PDF® finishing

measure adopted. However, PDF® quality becomes somewhat impaired due to changes in size, moisture, and

ash content.

Pursuit of a finishing process step resulted in establishmentof a stabilization task force composed of private sector andgovernment engineers and scientists. The outcome wasconstruction and testing of a Pilot Air Stabilization System(PASS) to complete the oxidative deactivation of PDF®.

The PASS controls temperature and humidity during forcedoxidation. The data obtained were used to develop specifications and design requirements for a full-scale, in-plantPDF® finishing unit based upon a commercial (Aeroglide)

tower dryer design.The first shipment of ENCOAL’s liquid CDL® productexperienced unloading problems. The use of heat tracingand tank heating coils solved the unloading problems forsubsequent customers. The CDL® also contained more

solids and water than had been hoped for, but was considered usable as a lower grade oil.Following VFB installation, CDL® quality improved. The

pour point ranged from 75–95 oF, and the flash pointaveraged 230 oF, both within the design range. Watercontent was down to 1–2%, and solids content was 2–4%.Improvements resulted from more consistent operationand lower pyrolysis temperatures and higher pyrolysisflow rates enabled by a new pyrolyzer water seal.

Environmental PerforPDF® offers the advantag

Basin coal without a heatLFC® process removes orthe PDF® product lower i

Btu basis. Because the RO

levels remain reasonable the ash level is essentially ROM coal goes into one-

Dust emissions were not a 

suppressant (MK) was sp

surface as it leaves the sto

rower particle size distriblarger fines content but ferange than ROM coal.ENCOAL’s test burn shipwhen Japan’s Electric Pow(EPDC) evaluated six me

EPDC, which must approelectric power generation 

able for use in Japanese uIn October 1996, instrumwas conducted at the Indi

Pre-VFB Post-VFB

1992 1993 1994 1995 1996 

Raw Coal Feed (tons) 5,200 12,400 67,500 65,800 68,000 PDF® Produced (tons) 2,200 4,900 31,700 28,600 33,300 

PDF® Sold (tons) 0 0 23,700 19,100 32,700 

CDL® Produced (bbl) 2,600 6,600 28,000 31,700 32,500 

Hours on Line 314 980 4,300 3,400 3,600 Average Length ofRuns (Days) 2 8 26 38 44 

Exhibit 49

ENCOAL Production

1Through June 1997.
operative’s (IKEC) Clifty Creek Station, Unit No. 3. Important findings included the following:• Full generating capacity using PDF® was possible with

one mill out of service, which was not possible usingthe baseline fuel. Operation using PDF®

afforded time to perform mill maintenance andcalibration without losing capacity or revenues, increasing capacity factor and availability, and decreasing operation and maintenance costs.

• NOx emissions were reduced by 20% due to high PDF®

reactivity, resulting in almost immediateignition upon leaving the burner coal nozzle. Furthermore, PDF® sustained effective combustion (maintaining low loss on ignition) with very low excess oxygen,

which is conducive to low NOx emissions.

• PDF® use precipitated increased ash deposits in the

convective pass that were wetter than those resultingfrom baseline coal use, requiring increased sootblowing to control build-up.

The CDL® liquid product is a low-sulfur, highly aromatic,

heavy liquid hydrocarbon. CDL® fuel characteristics are

similar to those of a low-sulfur No. 6 fuel oil, except thatthe sulfur content is significantly lower. CDL®’s market

potential as a straight industrial residual fuel, however,appears limited. The market for CDL® as a fuel never

materialized, and CDL® has limited application as a blend

for high-sulfur residual fuels due to incompatibility of thearomatic CDL® with many straight-chain hydrocarbon

distillates.ENCOAL determined that a centrifuge was needed toreduce solids retention and improve marketability ofCDL® (tests validated a 90% removal capability); and an

optimum slate of upgraded products was identified. Theupgraded products were: (1) crude cresylic acid, (2) pitch,(3) refinery feedstock (low-oxygen middle distillate), and(4) oxygenated middle distillate (industrial fuel).EconomicThe “base case” for economics of a commercial plant isthe 15,000-metric-ton/day, three-unit North RochelleLFC® plant, the commercial-scale plant proposed by

ENCOAL, with an independent 80-MWe cogeneration

unit, and no synthetic fuel tax credit (294 tax credit). It is

assumed that the cogeneration unit is owned and operatedby an independent third party. The capital cost for a fullscale, three-module LFC® plant is $475 million.

Economic benefits from an LFC® commercial plant are

derived from the margin in value between a raw, unprocessed coal and the upgraded products, making an LFC®

plant dependent on the cost of feed coal. In fact, this isthe largest single operating cost item. The total estimatedoperating cost is $9.00/ton of feed coal including the costof feed coal, chemical supplies, maintenance, and labor.Commercial ApplicationsIn a commercial application, CDL® would be upgraded to

cresylic acid, pitch, refinery feedstock, and oxygenatedmiddle distillate. Oxygenated middle distillate, the lowestvalue by-product, would be used in lieu of natural gas asa make-up fuel for the process (30% of the process heatinput). PDF® would be marketed not only as a boiler fuel

but as a supplement to or substitute for coke in the steelindustry. PDF® characteristics make it attractive to the

metallurgical market as a coke supplement in pulverizedcoal-injection and granular-coal-injection methods, and asa reductant in direct reduced iron processes.ContactsDouglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk III, NETL, (304) 285-6406

joseph.renk@netl.doe.gov

ReferencesENCOAL® Mild Gasification Plant Commercial Plant

Feasibility Study. U.S. Department of Energy. September1997. Report No. DOE/MC/27339. (Available from NTISas DE98002005.)Final Design Modifications Report. U.S. Department ofEnergy. September 1997. Report No. DOE/MC/27339-5797. (Available from NTIS as DE98002006.)ENCOAL® Mild Gasification Project: ENCOAL ProjectFinal Report. Report No. DOE/MC/27339-5798. U.S.Department of Energy. September 1997. (Available fromNTIS as DE98002007.)

“Results of the PDF® Te

Topical Report. S.A. JohOctober 1996.ENCOAL® Mild Coal G

Public Design and ConsDOE/MC/27339-4065. 1994. (Available from NENCOAL® Mild Gasificmance Summary. Reporment of Energy. Novem
132 Completed Projects 2003
Industrial Applications
134 Completed Projects 2003

Clean Coal Technology Demonstration ProgramIndustrial ApplicationsBlast Furnace Granular-CoalInjection SystemDemonstration ProjectProject completedParticipantBethlehem Steel CorporationAdditional Team MembersBritish Steel Consultants Overseas Services, Inc.

(marketing arm of British Steel Corporation)—technology owner

Clyde Pneumatic (formerly named Simon-Macawber,

Ltd.)—equipment supplier

Fluor Daniel, Inc.—architect and engineerATSI, Inc.—injection equipment engineer (North

America technology licensee)

LocationBurns Harbor, Porter County, IN (Bethlehem Steel’sBurns Harbor Plant, Blast Furnace Units C and D)TechnologyBritish Steel and Clyde Pneumatic blast furnace granularcoal injection (BFGCI) processPlant Capacity/Production7,000 net tons of hot metal (NTHM)/day requiring 2,800tons/day of coal (each blast furnace)CoalVirginia Pocahontas/Buchanan; 0.76% S, 86.39% COxbow; 0.76% S, 73.2% CProject FundingTotal $194,301,790 100%DOE 31,824,118 16Participant 162,477,672 84

Project ObjectiveTo demonstrate that granular coal could effectively displace coke and maintain established blast furnace production rates and quality specifications; to determine theeffect of coal chemistry, such as ash content (quantity andsulfur levels) and volatile levels, on blast furnace performance; and to evaluate the economics of granular coalinjection relative to natural gas injection.Technology/Project DescriptionThe BFGCI process uses granular coal, which requiressignificantly less grinding energy than pulverized coal toproduce. The coal, along with heated air, is blown into thelower part of the blast furnace through passages calledtuyeres, which create swept zones in the furnace calledraceways. This preheated blast air provides partial oxidation of the coke introduced along with the iron ore andlimestone at the top of the furnace. The coke serves as the

primary fuel and reducing bon reacts with the air anheat, iron, and carbon mofluxing agent, creating a sents such as sulfur and silThe low-Btu gas leaving sulfur and is used to prehon-site power.Bethlehem Steel introducreduce the amount of cokNatural gas was normally supplemental fuel. High lresult from coke productisive control systems. Bethand D at its Burns Harbor NTHM/day. The project scoal size and chemical comance and economics.

TO STEEL MAKING
Calendar Year

 3 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 

Results SummaryEnvironmental• BFGCI technology, using low-volatile, low-ash coal,

displaced up to 0.96 pounds of coke for every poundof coal, thereby reducing the air toxics emissions associated with coke production. By adjusting blast furnace slag, no additional sulfur emissions resulted fromthe coal injection, and sulfur levels in the productremained within the specified range.

Operational• Granular coal performed as well as pulverized coal on

the large blast furnaces and proved easier to handle thanpulverized coal, which tended to plug equipment whenusing low-volatile coals. Direct comparative testing on aspecific coal showed that 60% less energy is consumedin granulating coal than in pulverizing coal.

• Coal injection decreased furnace permeability, which

can adversely affect hot blast flow rate and furnaceproductivity, but increasing oxygen enrichment andmoisture content returned permeability and productivity to acceptable levels. Low-volatile coal replacedsignificantly more coke than did lower carbon content,

high-volatile coal, which was a major objective andalso a measure of the quality of the overall operation.Using low-volatile Virginia Pocahontas coal, the cokerate was reduced from approximately 740 lb/NTHM to661 lb/NTHM.

• There is a coke rate disadvantage of 3 lb/NTHM for

each one percent increase in ash content at an injectionrate of 260 lb/NTHM. Higher ash coal had no adverseeffect on furnace permeability, productivity, or productquality, but the slag volume increased.

Economic• The capital cost for one complete injection system

at Burns Harbor was $15,073,106 (1990$) for the7,000 NTHM/day blast furnace. The total fixed costs(labor and repair costs) at Burns Harbor were $6.25/tonof coal. The total variable costs (water, electricity, natural gas, and nitrogen) were $3.56/ton of coal. Coal costswere $50-60/ton. At a total cost of $60/ton and a naturalgas cost of $2.80/106 Btu, the iron cost savings would

be about $6.50/ton of iron produced. Based on theBurns Harbor production of 5.2 million tons of iron peryear, the annual savings is about $34 million.

1989 1990 1991 1993 1994 1995 1996 1997 1998 

Preaward

DOE selectedproject (CCTDPIII) 12/19/89

12/89 11/90

Cooperative agreement awarded 11/26/90

Design and Construction Operation and Reporting

final 

Operation completed 1

**

NEPA process completed (EA) 6/8/93

Construction started 9/93

Design completed 12/93

Environmental monitoring plan completed 12/23/94

Construction completed 1/95

Preoperational tests initiated 2/95

Operation initiated 11/95

11/95
136 Completed Projects 2003

Project SummaryBethlehem Steel retrofitted two high-capacity blast furnaces with BFGCI technology, Units C and D, at theirBurns Harbor facility in a successful attempt to reducecoke use and become a self-sufficient supplier. The questions posed in applying the technology went to the effectof coal grind (size) and coal chemistry on coke displacement and furnace performance. A coal pulverizer wasused to provide a range of coal grinds from granular (30%passing 200 mesh) to pulverized (80% passing 200 mesh).Each 7,000-NTHM/day furnace required approximately2,800 tons/day of coal. Each BFGCI unit included a rawcoal reclaim area and two 240-ton enclosed storage bins,a 500-Hp Williams variable speed coal-grinding mill andintegrated dryer, two 180-ton product coal silos designedto exclude oxygen, two distribution bins each with 14conical pant leg distributors, 28 injectors with lock hoppers and metered screw feeders, and a high-pressure airsystem transporting the coal 600 feet to injection lancesmounted on 28 separate tuyeres.Operational PerformanceInitial steady-state testing involved operation on granulated (15% passing 200 mesh) Virginia Pocahontas lowash, low-volatile, high-carbon coal in the Unit C furnace.This coal was selected as the baseline coal after a seriesof trials on different coal types. An average coal injectionrate of 264 lb/NTHM was achieved over the baselineOctober 1996 performance period. The furnace cokerate during the period was 661 lb/NTHM, down from740 lb/NTHM when operating on natural gas.Increasing slag volume in the furnace controlled the additional sulfur and silicon loading from the coal injection tospecified levels in the hot metal product. The slag alsocaptured sufficient sulfur to prevent any additional sulfurin the furnace gas output. An adverse downturn in furnacepermeability resulting from coal injection was moderatelycompensated for by increasing the oxygen enrichmentfrom 24.4% to 27.3% and increasing steam input from3.7 grains/scf to 19.8 grains/scf. The permeability adjustments enabled furnace productivity to be maintained.To determine the coal/coke replacement ratio, all factorsimpacting on coke rate other than coal injection had to be

removed from the equation. After doing so, the adjustedfurnace coke rate shows that one pound of VirginiaPocahontas baseline coal displaces 0.96 pounds of coke.The next test addressed the impact of ash volume on cokedisplacement and furnace performance. To do so, only thepercentage of ash was increased, not the coal or ash chemistry. This was done by eliminating a coal cleaning step onthe Pocahontas Seam coal (obtained from the BuchananMine), which increased the ash content from 5.3–7.7%.Tests showed that there is a coke rate disadvantage of3 lb/NTHM for each one percentage point increase in coalash content at an injection rate of 260 lb/NTHM; and thehigher ash coal had no adverse impact on furnace permeability, productivity, or product quality.Comparative testing followed to evaluate the effect ofcoal grind size (granular versus pulverized) on coke displacement and furnace performance as well as the effectsof coal chemistry. Furnace D was used because of sometemporary operating difficulties on Furnace C. A highvolatile, low-carbon Oxbow western coal was used in lieuof the baseline coal because of plugging problems experienced when pulverizing the baseline low-volatile coal andbecause there was the need to evaluate the impact ofhigh-volatile coal on furnace performance. The Oxbowcoal averaged 73.2% carbon and 11.2% ash versus86.3% carbon and 5.3% ash for the baseline coal. Thegranular Oxbow coal grind was 15% passing 200 meshand the pulverized Oxbow coal grind was 74% passing200 mesh. Granular coal production required 60% lessenergy (19.6 kWh/ton) than pulverized coal production(31.4 kWh/ton). The grinding mill production rate forpulverizing the coal limited the coal injection rate to183 lb/NTHM. After adjusting for the lower coal injection rate and other factors, it was determined that the cokerate when using the Oxbow coal was 46 lb/NTHM higherthan when using the low-volatile baseline coal duringtests—a substantial disadvantage. The blast furnace performance was unaffected by whether the coal was pulverized or granular at the coal injection rate of 183 lb/NTHM.Environmental PerformanceData collected over each test period show that the use ofinjected coal in the blast furnace does not cause an increase in the sulfur content of the gas for coals averaging

0.76% sulfur. Evidence suvolume and chemistry cousulfur coals. However, thderived from application reduction in coke usage. Cintensive and to be avoideapplication of the BFGCI can maintain steel producduction currently on site.Economic SummaryCapital cost for one compHarbor was approximatelnot include infrastructure million at Burns Harbor. Tincludes labor and repair The variable operating cotricity, natural gas, and niCoal costs were $50–60/tating costs to $59.81–69.coal and a natural gas cos

ings would be about $6.5Harbor, which produces 5the annual savings would payback period 3.44 yearcalculation.Commercial ApplicatiThere are 35 operating blSeventeen of them are alrinjection. An extensive mBethlehem Steel showed have the potential to utiliz1994, U.S. Steel Group coPneumatic for the installaFairfield Works in Alabamwhich began operating in except that no added coal meet the granular coal sizWorks Blast Furnace #8 pBFGCI installation cost awith an additional $5.5 mload-out facility.
ContactsDouglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Leo E. Makovsky, NETL, (412) 386-5814

leo.makovsky@netl.doe.gov

ReferencesBlast Furnace Granular Coal Injection System, FinalReport Volume 2—Project Performance and Economics.Bethlehem Steel Corporation. October 1999.“Blast Furnace Granular-Coal Injection System Demonstration Project.” Hill, D.G. et al. Sixth Clean Coal Conference Proceedings: Volume II—Technical Papers.April–May, 1998.
138 Completed Projects 2003

Clean Coal Technology Demonstration ProgramIndustrial ApplicationsAdvanced CycloneCombustor with InternalSulfur, Nitrogen, and AshControlProject completedParticipantCoal Tech CorporationAdditional Team MembersCommonwealth of Pennsylvania, Energy Development

Authority—cofunder

Pennsylvania Power and Light Company—supplier of test

coals

Tampella Power Corporation—hostLocationWilliamsport, Lycoming County, PA (Tampella PowerCorporation’s boiler manufacturing plant)TechnologyCoal Tech’s advanced, air-cooled, slagging combustorPlant Capacity/Production23 x 106 Btu/hr of steam

CoalPennsylvania bituminous, 1.0–3.3% sulfurProject FundingTotal $984,394 100%

DOE 490,149 50Participant 494,245 50Project ObjectiveTo demonstrate that an advanced cyclone combustor canbe retrofitted to an industrial boiler and that it can simultaneously remove up to 90% of the SO2 and 90–95% of

the ash within the combustor and reduce NO

x to 100 ppm.

Technology/Project DescriptionCoal Tech’s horizontal cyclone combustor is lined with anair-cooled ceramic. Pulverized coal, air, and sorbent areinjected tangentially toward the wall through tubes in theannular region of the combustor to cause cyclonic action.In this manner, coal-particle combustion takes place in aswirling flame in a region favorable to particle retentionin the combustor. Secondary air is used to adjust the overall combustor stoichiometry. Tertiary air is injected at thecombustor/boiler interface. The ceramic liner is cooled bythe secondary air and maintained at a temperature highenough to keep the slag in a liquid, free-flowing state.The secondary air is preheated by the combustor walls toattain efficient combustion of the coal particles in thefuel-rich combustor. Fine coal pulverization allows combustion of most of the coal particles near the cyclonewall. The combustor was designed so that a high percentage of the ash and sorben

tained as slag. For NOx co

fuel rich, with final combfurnace to which the com

captured by injection of lThe cyclonic action insidash and sorbent to the waliquid slag. Under optimacontains a significant fracDownstream sorbent injeadditional sulfur removal In Coal Tech’s demonstracyclone coal combustor w

oil-fired package boiler loCorporation boiler factory 
Calendar Year

 3 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 

Results SummaryEnvironmental• SO2 removal efficiencies of over 80% were achieved

with sorbent injection in the furnace at various calcium-to-sulfur (Ca/S) molar ratios.

• SO2 removal efficiencies up to 58% were achieved

with sorbent injection in the combustor at a Ca/Smolar ratio of 2.0.

• A maximum of one-third of the coal’s sulfur was

retained in the dry ash removed from the combustor(as slag) and furnace hearth.

• At most, 11% of the coal’s sulfur was retained in the

slag rejected through the combustor’s slag tap.

• NO

x emissions were reduced to 184 ppm by the combustor and furnace, and to 160 ppm with the addition

of a wet particulate scrubber.

• Combustor slag was essentially inert.• Ash/sorbent retention in the combustor as slag averaged 72% and ranged from 55–90%. Under more fuellean conditions, retention averaged 80%.

• Meeting local particulate emissions standards required

the addition of a wet venturi scrubber.

Operational• Combustion efficiencies of over 99% were achieved.• A 3-to-1 combustor turndown capability was demonstrated. Protection of combustor refractory with slag

was shown to be possible.

• A computer-controlled system for automatic combustor

operation was developed and demonstrated.

Economic• Because the technology failed to meet commercialization criteria, economics were not developed during the

demonstration. However, subsequent efforts indicatethat the incremental capital cost for installing the coalcombustor in lieu of oil or gas systems is $100–200/kW.

1986 1989 1990 1987 1988 1991 1992 1993 1994 

Preaward

Operation and Reporting

7/86 3/87 11/87

Design and

Construction

DOE selected project (CCTDP-I) 7/24/86

Design completed 7/87Ground breaking/construction started 7/87

Cooperative agreement awarded 3/20/87NEPA process completed (MTF) 3/26/87

Environmental monitoring plan completed 9/22/87

Construction completed 11/87Operation initiated 11/87

Operation

completed 5/90

9/91

Project completed/final report issued 9/91
140 Completed Projects 2003

Project SummaryThe novel features of Coal Tech’s patentedceramic-lined, slagging cyclone combustorincluded its air-cooled walls and environmental control of NOx, SO2, and solid waste

emissions. Air cooling took place in a verycompact combustor, which could be retrofitted to a wide range of industrial and utilityboiler designs without disturbing the boiler’swater-steam circuit. In this technology, NOx

reduction was achieved by staged combustion, and SO2 was captured by injection of

limestone into the combustor and/or boiler.Critical to combustor performance was removal of ash as slag, which would otherwiseerode boiler tubes. This was particularly important in oil furnace retrofits where tubespacing is tight (made possible by the low-ash content ofoil-based fuels).The test effort consisted of 800 hours of operation, including five individual tests, each of four days duration.An additional 100 hours of testing was performed as partof a separate ash vitrification test. Test results obtainedduring operation of the combustor indicated that CoalTech attained most of the objectives contained in thecooperative agreement. About eight different Pennsylvania bituminous coals with sulfur contents ranging from1.0–3.3% and volatile matter contents ranging from 19–37% were tested.Environmental PerformanceA maximum of over 80% SO2 reduction measured at the

boiler outlet stack was achieved using sorbent injection inthe furnace at various Ca/S molar ratios. A maximum SO2

reduction of 58% was measured at the stack with limestone injection into the combustor at a Ca/S molar ratioof 2. A maximum of one-third of the coal’s sulfur wasretained in the dry ash removed from the combustor andfurnace hearths, and as much as 11% of the coal’s sulfurwas retained in the slag rejected through the slag tap.Additional sulfur retention in the slag is possible by increasing the slag flow rate and further improving fuel-richcombustion and sorbent-gas mixing.

With fuel-rich operation of the combustor, a three-fourthsreduction in measured boiler outlet stack NOx was obtained, corresponding to 184 ppm. An additional reduction was obtained by the action of the wet particulate

scrubber, resulting in atmospheric NOx emissions as low

as 160 ppm.All the slag removed from the combustor produced tracemetal leachates well below EPA’s Drinking Water Standard. Total ash/sorbent retention as slag in the combustor,under efficient combustion operating conditions, averaged 72% and ranged from 55–90%. Under more fuellean conditions, the slag retention averaged 80%. Afterthe CCT project, tests on fly ash vitrification in the combustor, modifications to the solids injection system, andincreases in the slag flow rate produced substantial increases in the slag retention rate. To meet local stack

particulate 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 duringthe 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 fafor the boiler. In fact, due cooling, even 20 x 106 Bt

of the testing was conducDifferent sections of the cals requirements. Suitable identified. Also, the test eprocedures were closely cAs an example, by implemas changing the combustosible to replenish the comwith slag produced during adding ceramic to the comThe combustor’s total opeCCT project was about 90mately 100 hours of operacation test projects. Of thwith coal; about 125 tons Developing proper combualso a project objective. Nating an air-cooled combuoperating database was inctrolled system for automatCommercial ApplicatiThe goal of this project wof the air-cooled combustthe combustor was not yemercial guarantees, it was potential. Subsequent wobrought the technology clContactsBert Zauderer, President, 

Coal Tech CorporationP.O. Box 154Merion Station, PA 19bz.coaltech@verizon.n(610) 677-0576 (fax)

William E. Fernald, DOE

william.fernald@hq.d

Thomas A. Sarkus, (412) 

sarkus@netl.doe.gov

The Coal Tech combustor.
ReferencesThe Coal Tech Advanced Cyclone Combustor Demonstration Project—A DOE Assessment. Report No. DOE/PC/79799-T1. U.S. Department of Energy. May 1993. (Available from NTIS as DE93017043.)The Demonstration of an Advanced Cyclone Coal Combustor, with Internal Sulfur, Nitrogen, and Ash Control forthe Conversion of a 23-MMBtu/Hour Oil Fired Boiler toPulverized Coal; Vol. 1: Final Technical Report; Vol. 2:Appendixes I–V; Vol. 3: Appendix VI. Coal Tech Corporation. August 1991. (Available from NTIS as DE92002587and DE92002588.)Comprehensive Report to Congress on the Clean CoalTechnology Program: Advanced Cyclone Combustor withInternal Sulfur, Nitrogen, and Ash Control. Coal TechCorporation. Report No. DOE/FE-0077. U.S. Departmentof Energy. February 1987. (Available from NTIS asDE87005804.)

Coal Tech’s slagging combustor demonstrated the capability to of the non-fuel components injected into the combustor. The slaessentially an inert, glassy by-product with value in the construcin the manufacture of abrasives.
142 Completed Projects 2003

Clean Coal Technology Demonstration ProgramIndustrial ApplicationsCement Kiln Flue GasRecovery ScrubberProject completedParticipantPassamaquoddy TribeAdditional Team MembersDragon Products Company—project manager and hostHPD, Incorporated—designer and fabricator of tanks and

heat exchanger

Cianbro Corporation—constructorLocationThomaston, Knox County, ME (Dragon ProductsCompany’s coal-fired cement kiln)TechnologyPassamaquoddy Technology Recovery ScrubberTMPlant Capacity/Production1,450 ton/day of cement; 250,000 scfm of kiln gas; andup to 274 ton/day of coalCoalPennsylvania bituminous, 2.5–3.0% sulfurProject FundingTotal $17,800,000 100%DOE 5,982,592 34Participant 11,817,408 66Project ObjectiveTo retrofit and demonstrate a full-scale industrial scrubberand waste recovery system for a coal-burning wet processcement kiln using waste dust as the reagent to accomplish90–95% SO2 reduction using high-sulfur eastern coals;

and to produce commercial, potassium-based fertilizerby-products.

Technology/Project DescriptionThe Passamaquoddy Technology Recovery ScrubberTMuses cement kiln dust (CKD), an alkaline-rich (potassium)waste, to react with the acidic flue gas. This CKD, representing about 10% of the cement feedstock otherwise lostas waste, is formed into a water-based slurry and mixedwith the flue gas as the slurry passes over a perforatedtray that enables the flue gas to percolate through theslurry. The SO2 in the flue gas reacts with the potassium

to form potassium sulfate, which stays in solution andremains in the liquid as the slurry undergoes separationinto liquid and solid fractions. The solid fraction, in thickened slurry form and freed of the potassium and otheralkali constituents, is returned to the kiln as feedstock (itis the alkali content that makes the CKD unusable asfeedstock). No dewatering is necessary for the wet process used at the Dragon Products Company cement plant.

The liquid fraction is passwaste heat in the flue gas cover dissolved alkali methe incoming flue gas temevaporation, enables the ustruction material, and proter through condensation The Passamaquoddy Techwas constructed at the DrThomaston, Maine, a planmately 450,000 ton/yr of oped by the Passamaquodseeking ways to solve lanfrom the need to dispose ing process.
Calendar Year

 3 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 

Results SummaryEnvironmental• The SO2 removal efficiency averaged 94.6% during the

last several months of operation and 89.2% for theentire operating period.

• The NO

x removal efficiency averaged nearly 25%

during the last several months of operation and 18.8%for the entire operating period.

• All of the 250 ton/day CKD waste produced by the

plant was renovated and reused as feedstock, whichresulted in reducing the raw feedstock requirement by10% and eliminating solid waste disposal costs.

• Particulate emission rates of 0.005–0.007 gr/scf, about

one-tenth that allowed for cement kilns, were achievedwith dust loadings of approximately 0.04 gr/scf to thescrubber.

• Pilot testing conducted at U.S. Environmental Protection Agency laboratories under Passamaquoddy Technology, L.P. sponsorship showed 98% HCl removal.

• On three different runs, VOC (as represented by alphapinene) removal efficiencies of 72.3, 83.1, and 74.5%

were achieved.

• A reduction of approximately 2% in CO2 emissions

was realized through recycling of the CKD.

Operational• During the last operating interval, April to September

1993, recovery scrubber availability (discounting hostsite downtime) steadily increased from 65% in April1993 to 99.5% in July 1993.

Economic• Capital costs are approximately $10,090,000 (1990$)

for a recovery scrubber to control emissions from a450,000-ton/yr wet process plant, with a simple payback estimated in 3.1 years.

• Operation and maintenance costs, estimated at

$500,000/yr, plus capital and interest costs, are generally offset by avoided costs associated with fuel, feedstock, and waste disposal and with revenues from thesale of fertilizer.

1988 1991 1992 1989 1990 1993 1994 1995 1996 

Preaward Design and Construction

9/88 8/91

Operation and Reporting

DOEselectedproject(CCTDP-II)9/28/88

12/89

Design completed 4/90

Environmental monitoring plancompleted 3/26/90

Operation initiated 8/91

Construction completed 5/91Preoperational tests initiated 5/91

NEPA process completed (EA) 2/16/90

Cooperative agreement awarded 12/20/89

2/94

Project completed/final report issued 2/94

Construction started 6/89

Operation

completed 9/93
144 Completed Projects 2003

Project SummaryThe Passamaquoddy Technology Recovery ScrubberTM isa unique process that achieves efficient acid gas and particulate control through effective contact between flue gasand a potassium-rich slurry composed of waste kiln dust.Flue gas passes through the slurry as it moves over a special sieve tray. This results in high SO2 and particulate

capture, some NOx reduction, and sufficient uptake of the

potassium (an unwanted constituent in cement) to allowthe slurry to be recycled as feedstock. Waste cement kilndust, exhaust gases (including waste heat), and wastewater are the only inputs to the process. Renovated cementkiln dust, potassium-based fertilizer, scrubbed exhaustgas, and distilled water are the only proven outputs. Thereis no waste.The scrubber was evaluated over three basic operatingintervals dictated by winter shutdowns for maintenanceand inventory and 14 separate operating periods (withinthese basic intervals) largely determined by unforeseenhost-plant maintenance and repairs and a depressed cement market. Over the period August 1991 to September1993, more than 5,300 hours were logged, 1,400 hours inthe first operating interval, 1,300 hours in the secondinterval, and 2,600 hours in the third interval. Sulfur loadings varied significantly over the operating periods due tovariations in feedstock and operating conditions.Operational PerformanceSeveral design problems were discovered and correctedduring startup. No further problems were experienced inthese areas during actual operation.Two problems persisted into the demonstration period.The mesh-type mist eliminator, which was installed toprevent slurry entrainment in the flue gas, experiencedplugging. Attempts to design a more efficient water sprayfor cleaning failed. However, replacement with a chevron-type mist eliminator prior to the third operating interval was effective. Potassium sulfate pelletization provedto be a more difficult problem. The cause was eventuallyisolated and found to be excessive water entrainment dueto carry-over of gypsum and syngenite. Hydroclones wereinstalled in the crystallizer circuit to separate the very finegypsum and syngenite crystals from the much coarser

potassium sulfate crystals. Although the correction wasmade, it was not completed in time to realize pellet production during the demonstration period. After all modifications were completed, the recovery scrubber enteredinto the third and final operating interval—April to September 1993. During this interval, recovery scrubberavailability (discounting host site downtime) steadilyincreased from 65% in April to 99.5% in July.Environmental PerformanceAn average 250 ton/day of CKD waste generated by theDragon Products plant was used as the sole reagent in therecovery scrubber to treat approximately 250,000 scfm offlue gas. All the CKD, or approximately 10 ton/hr, wasrenovated and returned to the plant as feedstock and mixedwith about 90 ton/hr of fresh feed to make up the required

100 ton/hr. The alkali in thsium-based fertilizer, elimlists the number of hours p

NOx inlet and outlet readin

moval efficiency as a percAverage removal efficienperiod were 89.2% for SO

No definitive explanation 

was available at the conclAside from the operating sessment was made of inl

efficiency. For SO2 inlet l

less, recovery scrubber re82.0%. For SO2 inlet load

Exhibit 50

Summary of Emissions and Removal Eff

Operating Operating Inlet (lb/hr) Outlet (lb/hr) Period Time (hr) SO2 NOx SO2 NOx 1 211 73 320 10 279 2 476 71 284 11 260 3 464 87 292 13 251 4 259 131 252 16 165 5 304 245 293 28 243 6 379 222 265 28 208 7 328 281 345 28 244 8 301 124 278 10 188 9 314 47 240 7 194 10 402 41 244 6 218 11 460 36 315 6 267 12 549 57 333 2 291 13 464 86 288 4 223 14 405 124 274 9 199 Total operating time 5,316Weighted Average 109 289 12 234 
removal efficiency increased to 94.1% and up to 98.5%for loads greater than 200 lb/hr.In compliance testing for Maine’s Department of Environmental Quality, the recovery scrubber was subjected todust loadings of approximately 0.04 gr/scf and demonstrated particulate emission rates of 0.005–0.007 gr/scf—less than one-tenth the current allowable limit.Economic PerformanceThe estimated “as-built” capital cost to reconstruct theDragon Products prototype, absent the modifications, is$10,090,000 in 1990 dollars.Annual operating and maintenance costs are estimated at$500,000. Long-term annual maintenance costs are estimated at $150,000. Power costs, estimated at $350,000/yr, are the only significant operating costs. There are nocosts for reagents or disposal, and no dedicated staffing ormaintenance equipment is required.The simple payback on the investment is projected in aslittle as 3.1 years considering various revenues and

avoided costs that may be realized by installing a recovery

The Passamaquoddy Technology Recovery ScrubberTM wassuccessfully demonstrated at Dragon Products Company’scement plant in Thomaston, Maine.

scrubber similar in size to the one used at Dragon Products. In making this projection, $6,000,000 was added tothe “as-built” capital costs to allow for contingency, design/permitting, construction interest, and licensing fees.Commercial ApplicationsOf the approximately 2,000 Portland cement kilns in theworld, about 250 are in the United States and Canada.These 250 kilns emit an estimated 230,000 ton/yr of SO2(only three plants have SO2 controls, one of which is the

Passamaquoddy Technology Recovery ScrubberTM). Theapplicable market for SO2 control is estimated at 75% of

the 250 installations. If full penetration of this estimatedmarket were realized, approximately 150,000 ton/yr ofSO2 reduction could be achieved.

The scrubber became a permanent part of the cementplant at the end of the demonstration. A feasibility studyhas been completed for a Taiwanese cement plant.ContactsThomas N. Tureen, Project Manager, (207) 773-7166

Passamaquoddy Technology, L.P.1 Monument Way, Suite 200Portland, ME 04101(207) 773-7166(207) 773-8832 (fax)

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

John C. McDowell, NETL, (412) 386-6175

john.mcdowell@netl.doe.gov

ReferencesPassamaquoddy Technology Recovery ScrubberTM: FinalReport. Volumes 1 and 2 (Appendices A–M. Passamaquoddy Tribe. February 1994. (Vol. 1 available fromNTIS as DE94011175, Vol. 2 as DE94011176.)Passamaquoddy Technology Recovery ScrubberTM: Public Design Report. Report No. DOE/PC/89657-T2. Passamaquoddy Tribe. October 1993. (Available from NTIS asDE94008316.)Passamaquoddy Technology Recovery ScrubberTM:Topical Report. Report No. DOE/PC/89657-T1. Passamaquoddy Tribe. March 1992. (Available from NTIS asDE92019868.)

Comprehensive Report Technology Program: CScrubber. Passamaquod0152. U.S. Department (Available from NTIS a
146 Completed Projects 2003

Clean Coal Technology Demonstration ProgramIndustrial ApplicationsPulse Combustor DesignQualification TestProject completedParticipantThermoChem, Inc.Additional Team MemberManufacturing and Technology Conversion International,

Inc. (MTCI)—technology supplier

LocationBaltimore, MD (MTCI Test Facility)TechnologyMTCI’s Pulsed EnhancedTM Steam Reforming processusing a multiple resonance-tube pulse combustor.Plant Capacity/Production30 million Btu/hr (steam reformer)CoalBlack Thunder (Powder River Basin) subbituminousProject FundingTotal $8,612,054 100%DOE 4,306,027 50Participants 4,306,027 50Project ObjectiveTo demonstrate the operational/commercial viability of asingle 253-resonance-tube pulse combustor unit andevaluate characteristics of coal-derived fuel gas generatedby an existing Process Development Unit (PDU).Technology/Project DescriptionMTCI’s Pulsed EnhancedTM Steam Reforming processincorporates an indirect heating process for thermochemical steam gasification of coal to produce hydrogen-rich,clean, medium-Btu-content fuel gas without the need foran oxygen plant. Indirect heat transfer is provided by

immersing a multiple resonance-tube pulse combustor ina fluidized-bed steam gasification reactor.The combustor design qualification test facility consistedof a reformer vessel, pulse combustor, fuel train andburner management system, combustion air system, pulsecombustor cooling water circuit, cyclone, and water injection system. The reformer was a one-inch thick carbonsteel rectangular vessel. The pulse combustor consistedof a 253-tube bundle complete with refractory-lined combustion chamber, aerovalve plate assembly, inlet air plenum, and exhaust expansion bellows. The fuel train andburner management system consisted of a natural gaspressure reducing station, double block and bleed, modulating control valve, and orifice metering station. Thecombustion air system included forced draft fans, dampercontrol, and flow measurement instrumentation. Thepulse combustor cooling water circuit consisted of a

steam drum, recirculation feedwater makeup. The cwith drip leg isolation valinjection system consisted modulating control valve, 
Calendar Year

 3 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 

1991 1992 1993 1994 1998 1999 2000 

Preaward

1995 1997

9/91 10/92

DOE selectedproject (CCTDP-IV)9/12/91

Cooperative agreementawarded 10/27/92

Project relocationrequested 10/26/94

Design and Construction

Revised cooperative agreement

awarded 9/29/98

Construction completed;

operation initiated 10/00

Operation co

10/0

Final r

Design complete 2/15/99

Restructuring complete

3/21/98

Environmental monito

plan complete 12

NEPA process completed 11/98

**

PDU gasification 

Results SummaryEnvironmental• For the condensate from the coal characterization tests,

the biological oxygen demand (BOD) was 13.98,15.27, and 3.04 pounds per ton of dry coal for the1,000 °F; 1,100 °F; and 1,200 °F tests, respectively.

• For the condensate from the coal characterization tests,

volatile organic compounds (VOCs) were 593.7,183.2, and 52.2 milligrams/kilogram (mg/kg) of dryfeed for the 1,000 °F; 1,100 °F; and 1,200 °F tests,respectively.

• For the condensate from the coal characterization tests,

semi-volatile organic compounds (SVOCs) were1,868.3; 1,117.5; and 278.3 mg/kg of dry feed for the1,000 °F; 1,100 °F; and 1,200 °F tests, respectively.

Operational• The char product from the coal characterization tests

was deemed acceptable for use in direct reduction ofiron (DRI).

• The heat transfer rate for the pulse combustor tubes

was 2.5 times higher than for conventional fire tubes.

• The sound pressure level varied from 165 dB (approximately 1.5 psi peak-to-peak pressure fluctuation) at

about a 6 x 106 Btu/hr firing rate to about 173 dB (approximately 4 psi peak-to-peak pressure fluctuation) at

about a 21 x 106 Btu/hr firing rate, although it may be

possible to reduce these levels in a full-scale project.

Economic• The total project installed cost for five 253-tube pulse

combustors rated at 40 tons/hr to be used for charproduction is estimated at $28,184,000, which includes $8,095,170 for direct equipment and materialcosts, $3,438,830 for direct installation and subcontract costs, $6,100,000 for indirect costs, and$10,500,000 for start-up, escalation, land, preliminaryexpenses, insurance, permits, warranties, licenses, andcontingency.

• Fixed operating costs for char production were estimated

at $4,508,200 per year, and variable operating costswere estimated at $8,696,600 per year, which includes a$25/ton coal feedstock price. A by-product credit for thesyngas was estimated at $9,968,900 per year.
148 Completed Projects 2003

Project SummaryOn September 10, 1998, DOE approved revision ofThermoChem, Inc.’s Cooperative Agreement for a scaleddown project. The original project, awarded in October1992, was a commercial demonstration facility that wouldemploy 10 identical 253-resonance-tube pulse combustorunits. After fabrication of the first combustor unit, theproject went through restructuring. The revised projectdemonstrated coal characterization tests on a single 2-tube pulse combustor operating on coal and combustorqualification tests on a single 253-tube pulse combustoroperating on natural gas as a proxy for coal-derived synthesis gas (syngas). NEPA requirements were satisfied onNovember 30, 1998, with a Categorical Exclusion.ThermoChem initiated shakedown and commissioningtests in October 2000 and carried out emissions testingfrom December 2000 through May 2001.Operational PerformancePulse combustion involves the combustion-induced flowoscillations produced intentionally by the design of theequipment. The ThermoChem pulse combustor consistsof an aerodynamic air inlet valve, a combustion chamber,and a resonance tube (tailpipe) as shown in Exhibit 51.The combustor configuration has no moving parts and isinherently reliable.Operating as a fire tube boiler, ThermoChem claims thatits pulse combustor increases heat transfer rates 3–5 timeshigher than conventional fire tubes used to heat fluidizedbed reactors. The increased heat transfer is probably dueto flue gas oscillations resulting in a reduction in theboundary layer inside the tube. The data indicate that theheat transfer rate was 2.5 times higher than that in conventional fire tubes.Coal Characterization Tests. For the 2-tube pulse combustor, tests were conducted on Black Thunder PowderRiver Basin coal supplied by Northside Mining. Thechoice of coal was based on the specific application ofproducing char for DRI.The primary variable is an operating temperature that isthe lowest possible temperature where satisfactory volatile matter and sulfur content in the char is achieved. Thelowest possible operating temperature will result in the

Ex

Schematic of 

Op

lowest amount of fixed carbon converted to gas and thehighest char yield.The coal characterization tests were conducted in a PDUconsisting of a steam reformer reactor and two-stage cyclone, coal metering and injection equipment, steam boilerand reverse osmosis unit, two stages of steam superheat,gas chromatography dry gas sampling and measurement,and instrumentation and controls. A schematic of the PDUis shown in Exhibit 52.Three operating temperatures were evaluated for the coalcharacterization test—1,000 °F;1,100 °F; and 1,200 °F.Despite some questions regarding the operating data collected, the resultant char was deemed suitable for DRI.Pulse Combustor Qualification Test. Six series of testswere completed while firing the 253-tube pulse combustor. Data were obtained for both the up and down ramp ofthe pulse-combustor firing rate. Based on available data,the heat transfer coefficient inside the pulsed tube wasabout 2.5 times higher than for a non-pulsed tube.The natural gas firing rate was ramped up to about 21 x106 Btu/hr and held steady for about 10 hours. The

pulse combustor operated well with strong pulsationsand air suction with self-aspiration increasing significantly with firing rate. The dynamic pressure in thecombustion chamber was monitored during the testthrough a Hewlett-Packard spectrum analyzer. The pulsation frequency was generally on the order of 58 Hz.The sound pressure level varied from 165 dB (approximately 1.5 psi peak-to-peak pressure fluctuation) atabout a 6 x 106 Btu/hr firing rate to about 173 dB (approximately 4 psi peak-to-peak pressure fluctuation) at

about a 21 x 106 Btu/hr firing rate. Due to self-aspiration, the demand on static pressure in the air plenum of

the pulse combustor was rather low, less than 12 inchesof water at a 21 x 106 Btu/hr firing rate. ThermoChem

states that sound levels can be reduced to 85 dB at 3 feetby operating the combustors in a tandem arrangement at180 degrees out of phase to cancel out noise emissions.Environmental PerformanceCoal Characterization Tests. For the 2-tube pulse combustor coal characterization tests, VOCs and SVOCs werecollected and measured in the condensate. The total

VOCs were 593.7, 183.2, the 1,000 °F; 1,100 °F; anThe total SVOCs were 1,of dry feed for the 1,000 °respectively.A process condensate is thin this process because thand the char is the primardemand is the primary cosate effluent. For the 1,00tests, the BOD was 13.98of dry coal, respectively. Tbetween the two lower opbe expected because there gas yields for those two tetemperatures, gasification ics that contribute to BOD Pulse Combustor Qualifof the flue gas from the ccontinuous emissions mo(O2) concentration was in 

firing of the combustor, cand 80% excess air. Whethe O2 concentration was 

air operation was necessa
Exhibit 52

Schematic of ThermoChem’s

Process Development Unit

chamber temperature, and NOx emissions were relatively

high due to the high O2 concentration. With flue gas

recycle, the O2 and NOx levels were reduced significantly.

NOx concentrations were in the 10–30 parts per million

by volume (ppmv) range.Carbon monoxide (CO) concentration ranged from 100–400 ppmv during stable firing. Flow and temperatureprofiles had to be established and stabilized to achievecomplete combustion. Total hydrocarbons (THC) emissions were generally low (<20 ppmv) except during transients, indicating high combustion efficiency. Carbondioxide concentration ranged 7–10% during stable firing.With only two exceptions, combustion efficiency was inthe range of 99.6–100%, independent of firing rate, excess air, or fluidized-bed temperature. The percent of theheat released that is transferred to the fluidized-bed andthe water jacket as a function of firing rate. This percentremains relatively constant at a little over 50%, except atlow firing rates (less than about 7 x 106 Btu/hr).

Economic PerformanceA capital cost estimate was prepared based on a reactorwith five 253-tube pulse combustors having a nominalcoal processing (mild gasification) capacity of 40 tons/hr.The plant was assumed to be operating at 36 tons/hr (90% ThermoChem’s 253-tube 

onstream factor). The total project installed cost is estimated at $28,184,000, which includes $8,095,170 fordirect equipment and material costs, $3,438,830 for direct

installation and subcontract costs, $6,100,000 for indirectcosts, and $10,500,000 for start-up, escalation, land,preliminary expenses, insurance, permits, warranties,licenses, and contingency.Fixed operating costs for char production were estimatedat $4,508,200 per year and variable operating costs wereestimated at $8,696,600 per year, which includes a$25/ton coal feedstock price. A by-product credit for thesyngas was estimated at $9,968,900 per year. The resulting levelized cost of char would be $88.67/ton (current2002 dollars) and $63.19/ton (constant 2002 dollars).Commercial ApplicationsPulsed EnhancedTM Steam Reforming has application inmany different processes. Coal, with world production onthe order of four billion tons per year, constitutes thelargest potential feedstock for steam reforming. Otherpotential feedstocks include spent liquor from pulp andpaper mills, refuse-derived fuel, municipal solid waste,sewage sludge, biomass, and other wastes.Although the project demonstrated mild gasification ofcoal only, the technology has application to (1) blackliquor processing and chemical recovery; (2) hazardous,low-level mixed waste volume reduction and destruction;(3) coal processing for production of hydrogen for fuelcell power generation and other uses, production of gasand char for the steel industry, and production of solidClean Air Act compliance fuels, production of syngas foruse as a fuel or as a feedstock for chemicals or high-quality liquid fuels production; (4) coal-pond waste and coalrejects processing for overfiring/reburning for utility NOx

control; and (5) utilization of a range of other fuels andwastes to produce a variety of value-added products. Application of the technology to the production of char foruse in DRI has the potential for accomplishing significantreductions in pollutant emissions by reducing productionof conventional metallurgical coke and facilitating the useof a new efficient iron-making process.

Project ContactsLee Rockvam, Project M

(410) 354-9890(410) 354-9894 (fax)lrockvam@tchem.neThermoChem, Inc.6001 Chemical RoadBaltimore, MD 2122

William E. Fernald, DO

william.fernald@hq.

Leo E. Makovsky, NET

leo.makovsky@netl.

ReferencesPulse Combustor Desigsessment. U.S. DepartmFinal Report Volume 2: nomics—Pulse CombusClean Coal Feedstock T

2002.Final Report Volume 1: Combustor Design QuaFeedstock Test. ThermoComprehensive Report Technology Program: Dtion in an Application fopartment of Energy. Oct
150 Completed Projects 2003
¢ cent°C degrees Celsius°F degrees Fahrenheit$ dollars (U.S.)$/kW dollars per kilowatt$/ton dollars per ton% percent® registered trademarkTM trademarkABB CE ABB Combustion Engineering, Inc.ABB ES ABB Environmental SystemsACCP advanced coal conversion processACFB atmospheric circulating fluidized-bedADL Arthur D. Little, Inc.A/E architect/engineeringAEO2002 Annual Energy Outlook 2002AER2001 Annual Energy Review 2001AFBC atmospheric fluidized-bed

combustion

AFGD advanced flue gas desulfurizationAIDEA Alaska Industrial Development and

Export Authority

AOFA advanced overfire airAPEC Asia Pacific Economic CooperationAPF advanced particulate filterARIL Advanced Retractable Injection

Lances

ASFE Assistant Secretary for Fossil EnergyASME American Society of Mechanical

Engineers

Ass’n. AssociationATCF after tax cash flowsatm atmosphere(s)avg. averageB&W The Babcock & Wilcox CompanyBFGCI blast furnace granular-coal injectionBG British GasBtu British thermal unit(s)Btu/kWh British thermal units per kilowatthour

BOD biological oxygen demandCAAA Clean Air Act Amendments of 1990CaCO3 calcium carbonate (calcitic

limestone)

CAG Coal Advisory GroupCa/N calcium-to-nitrogenCaO calcium oxide (lime)Ca(OH)2 calcium hydroxide (calcitic hydrated

lime)

Ca(OH)2•MgO dolomitic hydrated lime

CAPI Clean Air Power InitiativeCa/S calcium-to-sulfurCaSO3 calcium sulfite

CaSO4 calcium sulfateCCOFA close-coupled overfire airCCT clean coal technologyCCTDP Clean Coal Technology

Demonstration Program

CCTDP-I First CCTDP solicitationCCTDP-II Second CCTDP solicitation

CCTDP-III Third CCTDP-IV FourCCTDP-V Fifth CCPI CleaCCPI-I First CCPI-II SecoCCRI ChinCDL® Coal

CD-ROM ComCEED Cent

Deve

CEM contiCenPEEP Cent

Envi

CEQ CounCFB circuCFD ComC/H carboCHP combCKD cemeCO carboCO2 carboCOP ConfCQETM Coal CQIMTM Coal CSC convCSI CleaCT-121 ChiyCTI Clim

Appendix A. Acronyms, Abbreviations, aSymbols
A-2 Completed Projects 2003

CUB coal utilization by-product(s)CURC Coal Utilization Research CouncilCX categorical exclusionCZD confined zone dispersiondB decibelsDER discrete emissions reductionDME dimethyl etherDOE U.S. Department of EnergyDOE/HQ U.S. Department of Energy

Headquarters

DRI direct reduction of ironDSE dust stabilization enhancementDSI dry sorbent injectionEA environmental assessmentEE Eastern EuropeEE/FSU Eastern Europe/Former Soviet UnionEEI Edison Electric InstituteEER Energy and Environmental Research

Corporation

EERC Energy and Environmental Research

Center, University of North Dakota

EETC Energy and Environmental

Technology Center

EFCC externally fired combined-cycleEIA U.S. Energy Information

Administration

EIS environmental impact statementEIV Environmental Information VolumeEMP environmental monitoring planEPA U.S. Environmental Protection

Agency

EPAct Energy Policy Act of 1992EPCRA Emergency Planning and Community

Right-To-Know Act

EPDC Japan’s Electric Power Development

Company

EPRI Electric Power Research InstituteESP electrostatic precipitatorEU European UnionEWG exempt wholesale generatorext. extensionFBC fluidized-bed combustionFCCC Framework Convention on Climate

Change

FE Office of Fossil EnergyFeO iron oxideFe2S pyritic sulfurFERC Federal Energy Regulatory

Commission

FETC Federal Energy Technology Center

(now NETL)

FGD flue gas desulfurizationFLGR flue gas recirculationFLGR/SNCR flue gas recirculation/selective

noncatalytic reduction

FONSI finding of no significant impactFRP fiberglass-reinforced plasticFSU Former Soviet Unionft, ft2, ft3 foot (feet), square feet, cubic feet

FY fiscal yeargal gallon(s)gal/ft3 gallons per cubic footGB gigabyte(s)GDP gross domestic productGE General ElectricGEP Greenhouse Gas Pollution

Prevention

GHG greenhouse gasesGNOCIS Generic NOx Control Intelligent

System

GPC Gilberton Power Companygpm gallons per minute

gr grainsGR gas rebGRI Gas RGR-LNB gas reb

GR-SI gas rebGSA gas suGVEA GoldeGW gigawGWe gigawH elemeH2 molec

H2S hydrog

H2SO4 sulfur

HAPs hazardHCl hydroHF hydrogHg mercuHGPFS hot gaHHV higher hr. hour(sHRSG heat reICCR Intern

Resea

ICR informID InduceIEA InternIEAT Indust

Thaila

IEO2003 InternIGCC integr

cycle

IGFC integrin, in2, in3 inch(e

inch(e

JBR Jet Bu
KCl potassium chlorideK2SO4 potassium sulfatekW kilowatt(s)kWh kilowatt-hour(s)LAC Latin America and the Caribbeanlb pound(s)L/G liquid-to-gasLHV lower heating valueLIMB limestone injection multistage

burner

LNB low-NOx burnerLNCB® low-NOx cell burnerLNCFS Low-NOx Concentric-Firing SystemLNG liquefied natural gasLOI loss-on-ignitionLPMEOHTM Liquid phase methanolLRCWF low-rank coal-water-fuelLSDE Laboratorium Sumderdaya EnergiLSFO limestone forced oxidationMACT maximum achievable control

technology

MASB multi-annular swirl burnerMB megabyte(s)MCFC molten carbonate fuel cellMCR Maximum Continuous RatingMDEA methyldiethanolamineMgCO3 magnesium carbonateMgO magnesium oxideMHz megahertzmills/kWh mills per kilowatt hourmin minute(s)mo month(s)MOST Ministry of Science and TechnologyMPF multiphase flowMSW municipal solid waste

MTBE methy tertiary butyl etherMTCI Manufacturing and Technology

Conversion International

MTF memorandum (memoranda)-to-fileMW megawatt(s)MWe megawatt(s)-electricMWt megawatt(s)-thermalN elemental nitrogenN2 molecular nitrogen

n.d. not datedN/A not applicableNAAQS National Ambient Air Quality

Standards

Na/Ca sodium-to-calciumNa2/S sodium-to-sulfurNaHCO3 sodium bicarbonateNaOH sodium hydroxideNa2CO3 sodium carbonateNARSTO North American Research Strategy

for Tropospheric Ozone

NEDO New Energy Development

Organization

NEP National Energy PolicyNEPA National Environmental Policy ActNETL National Energy Technology

Laboratory (formerly FETC)

NGCC natural gas combined cycleNH3 ammoniaNm3 normal cubic meterNMA National Mining AssociationNO2 nitrogen dioxideNOPR Notice of Proposed RulemakingNOx nitrogen oxidesNRC National Research CouncilNSPS New Source Performance Standards

NSR New NSR normNTHM net toNTIS Natio

Serv

NTPC NatioNYSEG New 

Corp

O elemO2 mole

O3 ozonO&M operOC&PS OfficOECD Orga

oper

OSTI Offic

Infor

OTAG OzonOTC OzonPASS Pilot PC persoPCAST Presi

on S

PCFB pressPDF® ProcPEIA prog

asses

PEIS prog

state

PEOATM Plan

Advi

PENELEC PennPEP progPFBC press

comb

PJBH pulse 
A-4 Completed Projects 2003

PM particulate matterPM10 particulate matter less than 10

microns in diameter

PM2.5 particulate matter less than 2.5

microns in diameter

PON program opportunity noticePPA Pollution Prevention ActPPII Power Plant Improvement InitiativePRB Powder River Basinppm parts per million (mass)ppmv parts per million by volumePRC People’s Republic of ChinaPSCC Public Service Company of ColoradoPSD Prevention of Significant

Deterioration

PSDF Power Systems Development Facilitypsi pound(s) per square inchpsia pound(s) per square inch absolutepsig pound(s) per square inch gaugePUHCA Public Utility Holding Company Act

of 1935

PURPA Public Utility Regulatory Policies

Act of 1978

QF qualifying facilityRAM random access memoryR&D research and developmentRD&D research, development, and

demonstration

RDF refuse derived fuelREA Rural Electrification AdministrationROD Record of DecisionROM run-of-mineRP&L Richmond Power & Lightrpm revolutions per minuteRUS Rural Utility ServiceS sulfur

SAP sulfuric acid plantSBIR Small Business Innovation ResearchSCADA supervisory control and data

acquisition

scf standard cubic feetscfm standard cubic feet per minuteSCR selective catalytic reductionSCS Southern Company Services, Inc.SDA spray dryer absorberSER Schuylkill Energy ResourcesSFC Synthetic Fuels CorporationS-H-U Saarberg-Hölter-UmwelttechnikSI sorbent injectionSIP State Implementation PlanSM service markSNCR selective noncatalytic reductionSNRBTM SOx-NOx-Rox BoxTMSO2 sulfur dioxide

SO3 sulfur trioxideSOFA separated overfire airSOFC solid oxide fuel cellSOW statement of workSPG Shangdong Power GroupSPPC Sierra Pacific Power Companystd ft3 standard cubic feetSTTR Small Business Technology Transfer

Program

SVGA super video graphics adapterSVOC semi-volatile organic compoundsTAGTM Technical Assessment GuideTMTCLP toxicity characteristics leaching

procedure

TRI Toxics Release InventoryTVA Tennessee Valley AuthorityUAF University of Alaska, Fairbanks

UARG Utility UBC unburnUBCL unburnU.K. United UNDEERC Unive

and En

UNESCO United 

Scient

URL UniforU.S. United USAID U.S. A

Devel

VFB vibratV·I voltagVOC volatilw.c. water WDNR Wisco

Resou

WES wasteww.g. water WLFO wet limWMPI Waste WPFF Workiwt. weighyr. year(sZPEG Zhejia

State AbbrevAK AlaskaAL AlabaAR ArkanAZ Arizon
CA CaliforniaCO ColoradoCT ConnecticutDC District of ColumbiaDE DelawareFL FloridaGA GeorgiaHI HawaiiIA IowaID IdahoIL IllinoisIN IndianaKS KansasKY KentuckyLA LouisianaMA MassachusettsMD MarylandME MaineMI MichiganMN MinnesotaMO MissouriMS MississippiMT MontanaNC North CarolinaND North DakotaNE NebraskaNH New HampshireNJ New JerseyNM New MexicoNV NevadaNY New YorkOH OhioOK OklahomaOR Oregon

PA PennsylvaniaPR Puerto RicoRI Rhode IslandSC South CarolinaSD South DakotaTN TennesseeTX TexasUT UtahVA VirginiaVI Virgin IslandsVT VermontWA WashingtonWI WisconsinWV West VirginiaWY Wyoming

OtherSome companies have adopted an acronym as theircorporate names. The following corporate namesreflect the former name of the company.BG/L British Gas LurgiJEA Jacksonville Electric AuthorityKRW Kellogg Rust Westinghouse
A-6 Completed Projects 2003
 

Index of Projects and ParticipantsSymbols10-MWe Demonstration of Gas Suspension Absorption

4, 7, 9, 12

180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reductionof NOx Emissions from Coal-Fired Boilers4, 7, 10, 58

AABB Combustion Engineering, Inc. 8, 9, 124ABB Environmental Systems 7, 9, 64Advanced Cyclone Combustor with Internal Sulfur,

Nitrogen, and Ash Control 6, 8, 9, 138

Advanced Flue Gas Desulfurization Demonstration

Project 4, 7, 9, 24

Air Products Liquid Phase Conversion Company, L.P.

8, 9, 120

AirPol, Inc. 7, 9, 12Alaska Industrial Development and Export Authority

8, 9, 114

BBabcock & Wilcox Company, The

7, 9, 38, 42, 68, 72

Bechtel Corporation 7, 9, 16Bethlehem Steel Corporation 8, 9, 134Blast Furnace Granular-Coal Injection System Demonstration Project 6, 8, 9, 134CCement Kiln Flue Gas Recovery Scrubber

6, 8, 9, 142

Coal Tech Corporation 8, 9, 138Commercial-Scale Demonsatration of the Liquid Phase

Methanol (LPMEOHTM) Process 6, 8, 9, 120

Confined Zone Dispersion Flue Gas Desulfurization

Demonstration 4, 7, 9, 16

CQ Inc. 8, 9, 124

DDemonstration of Advanced Combustion Techniques

for a Wall-Fired Boiler 4, 7, 9, 34

Demonstration of Coal Reburning for Cyclone Boiler

NOx Control 4, 7, 9, 38

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process 4, 7, 10, 28Demonstration of Selective Catalytic Reduction

Technology for the Contrl of NOx Emissions from

High-Sulfur, Coal-Fired Boilers 4, 7, 10, 54

Development of the Coal Quality ExpertTM

6, 8, 9, 124

EENCOAL Corporation 8, 9, 128ENCOAL® Mild Coal Gasification Project

6, 8, 9, 128

Energy and Environmental Research Corporation

7, 9, 46, 76

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection 5, 7, 9, 76

Evaluation of Gas Reburning and Low-NOx Burners on

a Wall-Fired Boiler 4, 7, 9, 46

FFull-Scale Demonstration of Low-NOx Cell Burner

Retrofit 4, 7, 9, 42

HHealy Clean Coal Project 5, 8, 9, 114

IIntegrated Dry NOx/SO

5, 7, 9, 84

LLIFAC Sorbent Injectio

tion Project 4, 7

LIFAC–North America LIMB Demonstration P

Demonstration 5, 

MMicronized Coal Rebu

Control 4, 7, 9, 

Milliken Clean Coal Te

Project 5, 7, 9, 

NNew York State Electri

7, 9, 50, 80

Nucla CFB DemonstraOOhio Power Company, PPassamaquoddy Tribe Piñon Pine IGCC PowPublic Service CompanPulse Combustor Desig

6, 8, 10, 146

Pure Air on the Lake, L
Index-2 Completed Projects 2003

SSierra Pacific Power Company 8, 9, 100SNOXTM Flue Gas Cleaning Demonstration Project

5, 7, 9, 64

Southern Company Services, Inc.

7, 9, 10, 28, 34, 54, 58

SOx-NOx-Rox BoxTM Flue Gas Demonstration Project

5, 7, 9, 72

TTampa Electric Company 8, 10, 104Tampa Electric Integrated Gasification CombinedCycle Project 5, 8, 10, 104ThermoChem, Inc. 8, 10, 146Tidd PFBC Demonstration Project 5, 8, 9, 90Tri-State Generation and Transmission Association,

Inc. 8, 10, 94

WWabash River Coal Gasification Repowering Project

Joint Venture 8, 10, 108

Wabash River Coal Gasification Repowering Project

5, 8, 10, 108, 111
Contents

CCTDP Completed Projects

SO2 Control Technologies

NO

x Control Technologies

Multi-Pollutant Control TechnologiesFluidized-Bed CombustionIntegrated Gasification Combined-CycleAdvanced Combustion/Heat EnginesCoal Processing for Clean FuelsIndustrial Applications

Appendex A. Acronyms, Abbreviations, and SymbolsIndex of Projects and Participants