tment of Energy

or Fossil Energy

gton, DC 20585

Clean Coal TechnologyDemonstration ProgramProject Fact Sheets 2000Status as of June 30, 2000September 2000

DOE/FE-0419
This report has been reproduced directly from the best available copy.

Available to DOE and DOE contractors from the Office of Scientific and Technical Information,P.O. Box 62, Oak Ridge, TN 37831. (865) 576-8401 www.osti.govAvailable to the public from the National Technical Information Service, U.S. Department ofCommerce, 5285 Port Royal Rd., Springfield, VA 22161. (800) 553-6847 www.ntis.gov

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

David J. BeecyProduct Line DirectorEnvironmental SystemsU.S. Department of EnergyMail Stop FE-23 GTN19901 Germantown RoadGermantown, MD 20874-1290(301) 903-2787

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

Comments or contributive information may be directed to:Program Update and Program Fact Sheetsc/o Gene H. KightSr. Financial & Procurement DirectorU.S. Department of EnergyMail Stop FE-20 GTN19901 Germantown RoadGermantown, MD 20874-1290(301) 903-2624(301) 903-9301 (fax)gene.kight@hq.doe.gov
tment of Energy

or Fossil Energy

gton, DC 20585

Clean Coal TechnologyDemonstration ProgramProject Fact Sheets 2000Status as of June 30, 2000September 2000

DOE/FE-0419
Project Fact Sheets i

oal Technology

m

Introduction 1-1Evolution of the Coal Technology Portfolio 1-2Program Status 1-3Program Accomplishments 1-3Technology Overview 1-6

Environmental Control Devices 1-6Advanced Electric Power Generation 1-11Coal Processing for Clean Fuels 1-14Industrial Applications 1-16

Project Fact Sheets 2-1

Environmental Control Devices 2-7

SO2 Control Technologies 2-7NO

x Control Technologies 2-29

Combined SO2/NOx Control Technologies 2-59

Advanced Electric Power Generation 2-85

Fluidized-Bed Combustion 2-85Integrated Gasification Combined-Cycle 2-101Advanced Combustion/Heat Engines 2-113

Coal Processing for Clean Fuels 2-121Industrial Applications 2-135

Project Contacts A-1

Environmental Control Devices A-1Advanced Electric Power Generation A-4Coal Processing for Clean Fuels A-6Industrial Applications A-7

Acronyms, Abbreviations, and Symbols B-1Index Index-1

oal Technology

ct Contacts

 Abbreviations,

and Participants
Completed Projects by Category 1-3Project Schedules and Funding by Application Category 1-4CCT Program SO2 Control Technology Characteristics 1-8

Group 1 and 2 Boiler Statistics and Phase II NOx Emission Limits 1-9

CCT Program NOx Control Technology Characteristics 1-10CCT Program Combined SO2/NOx Control Technology Characteristics 1-12

CCT Program Advanced Electric Power Generation Technology Characteristics 1-15CCT Program Coal Processing for Clean Fuels Technology Characteristics 1-17CCT Program Industrial Applications Technology Characteristics 1-18Project Fact Sheets by Application Category 2-2Project Fact Sheets by Participant 2-4Key to Milestone Charts in Fact Sheets 2-6Variables and Levels Used in GSA Factorial Testing 2-10GSA Factorial Testing Results 2-10Pure Air SO2 Removal Performance 2-22Estimated Costs for an AFGD System 2-23Flue Gas Desulfurization Economics 2-23Operation of CT-121 Scrubber 2-26SO2 Removal Efficiency 2-26

CT-121 Particulate Capture Performance 2-27CT-121 Air Toxics Removal 2-27LOI Performance Test Results 2-32NO

x

 vs. LOI Tests–All Sensitivities 2-32

Typical Trade-Offs in Boiler Optimization 2-32Major Elements of GNOCIS 2-33Coal Reburn Test Results 2-96

al Technologyal Technology
Project Fact Sheets iii

Coal Reburn Economics 2-37NO

x Data from Cherokee Station, Unit No. 3 2-44

Parametric Testing Results 2-49Catalysts Tested 2-52Average SO2 Oxidation Rate 2-52

Design Criteria 2-53LNCFSTM Configurations 2-56Concentric Firing Concept 2-56Unit Performance Impacts Based on Long-Term Testing 2-57Average Annual NOx Emissions and Percent Reduction 2-57LIMB SO2 Removal Efficiencies 2-66LIMB Capital Cost Comparison 2-67LIMB Annual Levelized Cost Comparison 2-67Effect of Limestone Grind 2-78Pressure Drop vs. Countercurrent Headers 2-78Effect of Bed Temperature on Ca/S Requirement 2-98Calcium Requirements and Sulfur Retentions for Various Fuels 2-99Wabash Thermal Performance Summary 2-111Wabash Fuel Analysis 2-111Wabash Product Syngas Analysis 2-111Healy Performance Goals and Combustion System Characterization Testing Results (June – December 1998 2-119Healy SDA Performance Test Results and Performance Guarantees 2-119ENCOAL® Production 2-132

BFGCI Test Results 2-143Summary of Emissions and Removal Efficiencies 2-150

oal Technology
10-MWe Demonstration of Gas Suspension Absorption 2-8Confined Zone Dispersion Flue Gas Desulfurization Demonstration 2-12LIFAC Sorbent Injection Desulfurization Demonstration Project 2-16Advanced Flue Gas Desulfurization Demonstration Project 2-20Demonstration of Innovative Applications of Technology for the CT-121 FGD Process 2-24Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 2-30Demonstration of Coal Reburning for Cyclone Boiler NOx Control 2-34Full-Scale Demonstration of Low-NO

x

 Cell Burner Retrofit 2-38

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler 2-42Micronized Coal Reburning Demonstration for NOx Control 2-46Demonstration of Selective Catalytic Reduction Technology for the Control ofNO

x Emissions from High-Sulfur, Coal-Fired Boilers 2-50

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques forthe Reduction of NO

x

 Emissions from Coal-Fired Boilers 2-54

SNOXTM Flue Gas Cleaning Demonstration Project 2-60LIMB Demonstration Project Extension and Coolside Demonstration Gas Cleanup System 2-64

SO

x

-NO

x-Rox BoxTM Flue Gas Cleanup Demonstration Project 2-68

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection 2-72Milliken Clean Coal Technology Demonstration Project 2-76Integrated Dry NOx/SO2 Emissions Control System 2-80

McIntosh Unit 4A PCFB Demonstration Project 2-86McIntosh Unit 4B Topped PCFB Demonstration Project 2-88

act Sheets by Application Category

rol Devices

s

es

rol

ower

on
Project Fact Sheets v

JEA Large Scale CFB Combustion Demonstration Project 2-90Tidd PFBC Demonstration Project 2-92Nucla CFB Demonstration Project 2-96Kentucky Pioneer IGCC Demonstration Project 2-102Piñon Pine IGCC Power Project 2-104Tampa Electric Integrated Gasification Combined-Cycle Project 2-106Wabash River Coal Gasification Repowering Project 2-108Clean Coal Diesel Demonstration Project 2-114Healy Clean Coal Project 2-116Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Process 2-122Advanced Coal Conversion Process Demonstration 2-124Development of the Coal Quality ExpertTM 2-126ENCOAL® Mild Coal Gasification Project 2-130

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) 2-136Pulse Combustor Design Qualification Test 2-138Blast Furnace Granular-Coal Injection System Demonstration Project 2-140Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 2-144Cement Kiln Flue Gas Recovery Scrubber 2-148

 Combined-Cycle

/Heat Engines

r Clean Fuels

ons
act Sheets by Participant

ering, Inc., and

ems

se Conversion

pment and

Company Demonstration of Coal Reburning for Cyclone Boiler NOx Control 2-34

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit 2-38

LIMB Demonstration Project Extension and Coolside Demonstration 2-64SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project 2-68

ation

Company, LLC

Development of the Coal Quality ExpertTM 2-126SNOXTM Flue Gas Cleaning Demonstration Project 2-60

Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Process 2-122

10-MWe Demonstration of Gas Suspension Absorption 2-8

Healy Clean Coal Project 2-116Clean Coal Diesel Demonstration Project 2-114Confined Zone Dispersion Flue Gas Desulfurization Demonstration 2-12

Blast Furnace Granular-Coal Injection System Demonstration Project 2-140

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 2-144

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) 2-136

ENCOAL® Mild Coal Gasification Project 2-130

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection 2-72Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler 2-42

see ABB Combustion Engineering and CQ Inc.

al Research
Project Fact Sheets vii

Nucla CFB Demonstration Project 2-96

gy, LLC

land Electric

JEA Large-Scale CFB Combustion Demonstration Project 2-90

Kentucky Pioneer IGCC Demonstration Project 2-102

McIntosh Unit 4A PCFB Demonstration Project 2-86

McIntosh Unit 4B Topped PCFB Demonstration Project 2-88LIFAC Sorbent Injection Desulfurization Demonstration Project 2-16Micronized Coal Reburning Demonstration for NOx Control 2-46

Milliken Clean Coal Technology Demonstration Project 2-76

c & Gas

ny

y of Colorado

P.

ompany

vices, Inc.

Tidd PFBC Demonstration Project 2-92Cement Kiln Flue Gas Recovery Scrubber 2-148Integrated Dry NOx/SO2 Emissions Control System 2-80

Advanced Flue Gas Desulfurization Demonstration Project 2-20Piñon Pine IGCC Power Project 2-104Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 2-30Demonstration of Innovative Applications of Technology for the CT-121 FGD Process 2-24Demonstration of Selective Catalytic Reduction Technology for the Control ofNO

x Emissions from High-Sulfur, Coal-Fired Boilers 2-50

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniquesfor the Reduction of NO

x

 Emissions from Coal-Fired Boilers 2-54

ny

nd Transmission

Tampa Electric Integrated Gasification Combined-Cycle Project 2-106Pulse Combustor Design Qualification Test 2-138
Advanced Coal Conversion Process Demonstration 2-124

fication Wabash River Coal Gasification Repowering Project Joint Venture 2-108
Project Fact Sheets 1-1

1. The Clean Coal Technology

ration Program

gy Demonstration Pro

 of government and

 to the Department of

ter a secure and reliable

mentally and economi

ogram represents an

 in advanced coal-based

state governments pro

rcent of the funding.

ts having completed

has yielded clean coal

apable of meeting exist

al regulations and com

 power marketplace.

iding a portfolio of

at U.S. recoverable coal

n continue to supply the

cally and in an environ

e nation embarks on a

clean coal technologies

ication. Industry stands

 and environmental

oth domestically and

ower plants, there are

ontrol devices to control

oxides (NOx), and par

dy is a new generation

ce electricity and other

commodities, such as steam and synthetic gas, andprovide efficiencies and environmental performanceresponsive to global climate change concerns. TheCCT Program took a pollution prevention approach aswell, demonstrating technologies that remove pollutants or their precursors from coal-based fuels beforecombustion. Finally, new technologies were introduced into the major coal-based industries, such assteel production, to enhance environmental performance. Thanks in part to the CCT Program, coal—abundant, secure, and economical—can continue in itsrole as a key component in the U.S. and world energymarkets.

The CCT Program also has global importance in

providing clean, efficient coal-based technology to aburgeoning energy market in developing countrieslargely dependent on coal. Based on 1997 data, worldenergy consumption is expected to increase 60 percentby 2020, with almost half of the energy incrementoccurring in developing Asia (including China andIndia). By 2020, energy consumption in developingAsia is projected to surpass consumption in NorthAmerica. The energy form contributing most to thegrowth is electricity, as developing Asia establishes itsenergy infrastructure. Coal, the predominant indigenous fuel, in that region will be the fuel of choice inelectricity production. The CCTs offer a means tomitigate potential environmental problems associatedwith unprecedented energy growth, and to enhance theU.S. economy through foreign equipment sales andengineering services.

World energy consumption by fuel type for the years

1997 and 2020.

1997 World Energy Consumption

380 Quads

2020 World Energy Consumption

608 Quads

Source: IEO2000, Table A2.

Hydro & Other

Renewables 8% Nuclear 6%

Petroleum

40%

Coal 24%

Natural

Gas 22%

Hydro & Other

Renewables 8%

Nuclear 4%

Natural

Gas 29%

Coal 22%

Petroleum

37%
Coal

folio

 implemented through

etitive solicitations.

d toward demonstrat

mercial application of

would balance the

 minimizing environ

licitations sought

 the potential impacts

ired power plants in

s of the Special En

and fifth solicitations

supply and demand

pped under the Clean

CAAA), increased

need to alleviate

ange

—a situation

 high efficiencies and

ns provide a portfolio

coal to continue to

 vital to the nation’s

y and environmental

This is being carried

rket sectors: (1) envi

isting and new power

wer generation for

d providing new gen

sing for clean fuels to

sources to clean fuels,

and (4) industrial applications dependent upon coaluse.

In response to the initial thrust of the program,

operations have been completed for 17 of 18 projectsthat address SO2 and NOx control for coal-fired boilers. (One project was reopened and extended to demonstrate an overall unit optimization system.) Theresultant technologies provide a suite of cost-effectivecontrol options for the full range of boiler types. The18 environmental control device projects are valued atmore than $620 million. These include seven NOx

emission control systems installed on more than 1,750MWe of utility generating capacity, five SO2 emissions systems installed on approximately 770 MWe of

capacity, and six combined SO2/NOx emission controlsystems installed on more than 665 MWe of capacity.

To respond to increasing demand, as well as

growing environmental concerns, theCCT Program provides a range of advanced electric power generation optionsfor both repowering and new generation.These advanced options offer greaterthan 20 percent reductions in greenhousegas emissions; SO2, NOx, and PM emissions far below New Source Performance Standards (NSPS); and salablesolid and liquid by-products in lieu ofwastes that require disposal. Over 1,800MWe of capacity are represented by 11projects valued at nearly $2.9 billion.These projects include five fluidized-bedcombustion (FBC) systems, four integrated gasification combined-cycle(IGCC) systems, and two advancedcombustion/heat engine systems. Theseprojects will not only provide environmentally sound electric generation now, but also will provide the demonstrated technology base necessary to meet new capacity requirements in the 21st century. Also addressed are approaches to converting raw, run-of-mine (ROM) coals to high-energy-density, low-sulfur products. These products have application domestically for compliance with the CAAA. Inter- nationally, both the products and processes have ex- cellent market potential. Valued at $432 million, the four projects in the coal processing for clean fuels category represent a diversified portfolio of technolo- gies. Two projects involve the production of high- energy-density solid fuels, one of which also produces a liquid product equivalent to No. 6 fuel oil. A third project is demonstrating a new methanol production process. A fourth effort complements the process demonstrations by providing an expert computer Low-NOx burner technologies: ABB Combustion Engineering’s LNCFS

TM for

tangentially firedboilers (top left),Foster Wheeler’s lowNOx burner for wallfired boilers (top

right), Babcock &Wilcox’s LNCB® for

cell-burner boilers(center), and Babcock& Wilcox’s DRBXCL® for down-fired

boilers (bottom).
Project Fact Sheets 1-3

utility to assess the

d economic impacts of

ned at a facility, includ

ends.

o address pollution

use in the industrial

ed dependence of the

inherent pollutant emis

of the cement industry

ften high-sulfur, coal

ndustrial boiler opera

oal fuels to reduce oper

 applications projects

ly $1.3 billion.

on of coal for 40 per

ntegration of a direct

production of electric

missions and solid

on of an industrial

 a pulse combustor

Program Status

The CCT Program has extended the technical,

economic, and environmental performance envelopeof a broad portfolio of advanced coal technologies.As of June 30, 2000, a total of 26 CCT demonstrationprojects have completed operations, 5 are in operation, 2 are in construction, and 5 are in design. Exhibit1-1 shows the number of projects having completed

operations, by application category. Exhibit 1-2 provides a schedule for the 38 projects as of June 30,2000.

Program Accomplishments

Some of the accomplishments of the

CCT Program to date are summarizedbelow.• The CCT Program enabled the utility

industry to respond cost-effectively tothe first wave of NOx control requirements (using low-NOx burners), and has

positioned the utility industry to respondto NOx control requirements in the 21st

century. The CCT Program also provided valuable input to the regulatoryprocess by furnishing real-time NOxcontrol data. To date, about one-half ofthe coal-fired generating capacity in theUnited States has low-NOx burners,worth more than $1.5 billion.

• The CCT Program also has provided a

portfolio of SO2 control technologies that

enables utilities to respond cost effectively to year2000 CAAA requirements. Technologies areavailable for the full range of units from old spaceconstrained boilers to relatively new large boilers.The two advanced wet flue gas desulfurizationtechnologies demonstrated under the CCT Programredefined the state-of-the-art for sorbent-basedscrubbers by (1) halving operating costs and significantly reducing capital costs; (2) producing byproducts instead of waste; and (3) mitigating plantefficiency loses by using high-capture-efficiencydevices.

• The CCT Program was instrumental in commercializing atmospheric circulating fluidized-bed

combustion (ACFB) technology through the TriState Generation and Transmission Association,Inc. project in Nucla, Colorado. An industry con

wer’s Plant Hammond 

oster Wheeler’s low-NOx 

d overfire air.

Number of Projects

Application Category Completed Total

Operations

Environmental Control DevicesSO2 Control Technology 5 5NOx Control Technology 6 7Combined SO2/NOx Control Technology 6 6

Advanced Electric Power GenerationFluidized-Bed Combustion 2 5Integrated Gasification Combined-Cycle 1 4Advanced Combustion/Heat Engines 1 2Coal Processing for Clean Fuels 2 4Industrial Applications 3 5 Total 26 38

Exhibit 1-1

Completed Projects by Category
Exhibit 1-2

Project Schedules and Funding by Application Category

988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 DOE Total

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

 Environmental Control Devices 7,592 19,311

6,554 15,854

18,748 37,589

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

15,719 31,438

6,078 13,272

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

2,315 7,7178,896 17,807

21,085 43,075

9,407 23,230

45,000 158,608

2,701 9,096

reaward Design and Construction Operation and Reporting
Project Fact Sheets 1-5

Exhibit 1-2 (continued)

Project Schedules and Funding by Application Category

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 DOE Total

41234123412341234123412341234123412341234123412341234123412341234123412341234 ($1,000)

 Advanced Electric Power Generation 17,130 160,050

66,957 189,886

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

23,818 47,63674,734 309,09778,086 431,933

 Project on hold 93,253 186,588 Project on hold 109,609 219,636

 Coal Processing for Clean Fuels 10,864 21,746

43,125 105,70045,332 90,66492,708 213,700

Industrial Applications 490 984

5,983 17,800

31,824 194,302

4,306 8,612

149,469 1,065,805

 Preaward Design and Construction Operation and Reporting
ully evaluate the

r utility application.

comprehensive data

B as a commercial

5 gigawatts of capac

mbustion (PFBC)

ake market penetra

rmed at The Ohio

. The CCT Program

 development work

mercial sales, includ

 and a 220-MWe unit

 represents a new

r systems, with effi

entional coal-fired

ons far below NSPS,

mission controls. The

he basis for second

ions to be conducted

ojects, representing a

d cleanup systems, are

f a new approach to

ash IGCC plant has

tions. Two of the

operating in a com

ding valuable perfor

racting worldwide

ntial to significantly

ollutant emissions,

for even more ad

successful demonstra

nology that produces

a high-energy-density solid fuel and a liquid product from low-rank coal. The solid fuel is lowenough in sulfur to be considered a compliancefuel,—capable of meeting CAAA standards for

2000. Also, the solid product has demonstratedcombustion characteristics that enable reduced NO

x

emissions. The liquid product has the most potential as a chemical feedstock and can be used as alow-sulfur boiler fuel.

• The liquid phase methanol process (LPMEOHTM) at

the Eastman Chemical Company in Kingsport,Tennessee is demonstrating a cost-effective meansof coproducing electricity and methanol. Continued stable production of methanol at or beyonddesign rates from high-sulfur bituminous coalsuggests that IGCC with LPMEOHTM offers a very

clean, highly efficient means of using high-sulfurcoal in chemical and electricity production.

• Demonstration of granular-coal injection at Bethlehem Steel’s Burns Harbor blast furnace operations

proved that coal can replace up to 40 percent of thecoke requirement in iron making. This has significant environmental and economic ramificationsbecause of the magnitude and extent of pollutantemissions from coke production. Emissions fromgranular-coal injection are controlled within theblast furnace.

Technology OverviewEnvironmental Control Devices

Environmental control devices are those technologies retrofitted to existing facilities or installed

on new facilities for the purpose of controlling SO2

and NO

x emissions. Although boilers may be modified and combustion affected, the basic boiler configuration and function remain unchanged with these

technologies.

SO2 Control Technology. Sulfur dioxide is an

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

Title IV of the CAAA. Phase I of Title IV, effectivein 1995, affected 261 coal-fired units nationwide.The required SO2 reduction was moderate and largelymet by switching to low-sulfur fuels. This year, PhaseII of Title IV became effective, impacting all fossilfuel-fired units, but most of all, the approximately700 pre-NSPS coal-fired facilities. The CAAA provides utilities flexibility in control strategies throughSO2 allowance trading. This permits a range of control options to be applied by a utility, as well as allowance purchasing. Recognizing this, the CCT

Unique CT-121 SO2 scrubber at Plant Yates combined

a number of functions and eliminated process steps.
Project Fact Sheets 1-7

e a portfolio of SO2

ices embody those

d act upon the flue gas

 the combustion itself,

ng SO2. Three basic

have evolved and are

onditions that exist

pulation impacted by

dous range in critical

 and space availability

m are the smaller, older

adding equipment. For

ques hold promise.

ler or the ductwork, and

in some fashion to

 for efficient SO2 cap

plexity are held to a

 and space requirements

sorbents are used.

third that of hydrated

nditioned (calcined),

and even then, it is less effective in SO2 capture (under simple sorbent injection conditions) than hydratedlime. Where limestone is used, it is injected in theboiler to produce calcium oxide, which reacts withSO2 to form solid compounds of calcium sulfite andcalcium sulfate. Both limestone and lime injectionrequire the presence of water (humidification) and acalcium-to-sulfur (Ca/S) molar ratio of about 2.0 forsulfur capture efficiencies of 50 to 70 percent.

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

MWe boilers less than 30 years old and somewhatspace constrained. For many of these, an increase inequipment cost is justified by enhanced performance.The approach involves introduction of a reactor vesselin the flue gas stream to create conditions to enhanceSO2 capture beyond that achievable with the simplersorbent injection systems. Lime is used, as opposedto limestone, and sulfur capture efficiencies up to 90percent can be achieved at Ca/S molar ratios of 1.3 to2.0. This category of control device is called a spraydryer because the solid by-product from the reactionis dry.

At the other end of the spectrum are the larger

(300-MWe and larger) existing boilers, with somelatitude in space availability, and new plants. Forthese boilers, advanced flue gas desulfurization(AFGD) wet scrubbers, with higher capital cost buthigher sulfur capture efficiency than other approaches, become cost effective. These systems applylarger and somewhat more complex reactors that driveup the capital cost. However, the sorbent is the lowercost limestone, which reduces operating costs. Inaddition, new technologies reduce capital costs, improve reliability, and increase overall plant efficiency.The AFGD achieved SO2 removal efficiencies ofgreater than 90 percent at a Ca/S molar ratio of about1.0, making operating costs significantly lower than

those of the other two approaches. Furthermore,although the initial AFGD solid by-product is inslurry form, it is dewatered to produce gypsum 

— a

salable product.

The CCT Program successfully demonstrated two

sorbent injection systems, one spray dryer system, andtwo AFGD systems. All have completed testing.Exhibit 1-3 briefly summarizes the characteristics andperformance of the SO2 control technologies that are

described in the project fact sheets in Section 2.

NOx Control Technology. Nitrogen oxides are

formed from oxidation of nitrogen contained withinthe coal (fuel-bound NOx) and oxidation of the nitrogen in the air at high temperatures of combustion(thermal NOx). To control fuel-bound NOx formation,

it is important to limit oxygen at the early stages ofcombustion. To control thermal NOx

, it is important

to limit peak temperatures.

Nitrogen oxides were identified both as a precursor to acid rain (targeted under Title IV of the

CAAA) and as a contributor to ozone formation(targeted under Title I). Phase I of Title IV, effecThe Babcock & Wilcox Company DRB-XCL® burners,

installed on a down-fired boiler, were used in the IntegratedDry NOx/SO2 Emissions Control System project.

d 50% SO2 removal

k, where the lime slurry
Exhibit 1-3

CCT Program SO2 Control Technology Characteristics

Coal Sulfur SO2

Process Content Reduction Page

Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7–3.5% 60–90% 2-8

particulate recycle (lime sorbent)

Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.5–2.5% 50% 2-12

urization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% 70% 2-16

humidification vessel and sorbent recycle

ion AFGD—cocurrent flow, integrated quench absorber tower, and reaction 2.25–4.7% 94% 2-20

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

plications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2–3% 90+% 2-24

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

nsion absorption demonstration unit.

The water inlet connections to the Pure Air absorber module used in the Advanced Flue

Gas Desulfurization Demonstration Project.
Project Fact Sheets 1-9

l- and tangentially

sions to 0.50 and 0.45

00, Phase II of Title IV

but most notably, the

fired units (see Exhibit

ompted the U.S. Envi

EPA) to issue a NOx

 Plan (SIP) call for 22

mbia to cut NO

x

 emis

0 rates or achieve a 0.15

ay 2003. The fate of

gation proceeds.

ught to provide a num

over the range of boiler

equirements. Control

mplished either by

cess or by acting upon

 combinations thereof).

nologies include low

d overfire air (AOFA),

either natural gas or

es used to act upon flue

reduction (SCR) and

n (SNCR). Advanced

eductions.

tial fuel-air mixture,

eate a fuel-rich flame

ich additional air re

 is mixed. This staging

oxidized environment

l-bound NOx and ther

NBs typically can

duction.

volves injection of air

 zone to allow the pri

hout the amount of

ombustion. This oxygen deficiency mitigates fuel-bound NOx formation. The AOFA injected at high velocity creates turbulent mixing to complete the combustion in a gradual fash- ion at lower temperatures to mitigate thermal NOx formation. Usually, AOFA is used in combination with LNBs; but alone, AOFA can achieve 10–25 percent NOx emission reductions. The LNB/AOFA systems generally can achieve NOx emission reduc- tions of 37 to 68 percent, depending upon boiler type. In reburning, a percentage of the fuel input to the boiler is diverted to injection ports above the primary combustion zone. Either gas or coal is typi- cally used as the reburning fuel to provide 10 to 30 percent of the heat input to the boiler. The reburning fuel is injected to create a fuel-rich zone deficient in oxygen (a reducing rather than oxidizing zone). The NOx entering this zone is stripped of oxygen, resulting in elemental nitrogen. Combustion is completed in a burnout zone where air is in- jected by an AOFA system. Reburning has application to all boiler types, including cyclone boilers, and can achieve NOx emis- sion reductions of 50–67 percent. The SCR and SNCR technolo- gies can be used alone or in combina- tion with combustion modification. These processes use ammonia or urea in a reducing reaction with NOx to form elemental nitrogen and water. The SNCR system can only be used at high temperatures (1,600 oF to 2,200 oF) where a catalyst is not needed. The SCR system is typically applied at temperatures between 600– 800 oF. Generally, SNCR and SCR systems alone can achieve NOx emission reductions of 30–50 percent and 80–90+ percent, respectively. Advanced control systems using artificial intelli- gence are also becoming an integral part of NOx con- trol systems. These systems can handle the numerous parameters and optimize performance to reduce NOx while enhancing boiler performance. Under the CCT Program, seven NOx control technologies were assessed encompassing LNBs, AOFA, reburning, SNCR, SCR, and combinations thereof. Six of the seven projects have completed operations. One project has been extended. Exhibit 1-5 briefly summarizes the characteristics and perfor- mance of the technologies that are described in more detail in the project fact sheets. Exhibit 1-4 Group 1 and 2 Boiler Statistics and Phase II NOx Emission Limits Number Phase II of NOx Emission Limits Boiler Types Boilers (lb/106 Btu) Group 1 Tangentially fired 299 0.40 Dry-bottom, wall-fired 308 0.46 Group 2 Cell burner 36 0.68 Cyclone >155 MWe 55 0.86 Wet-bottom, wall-fired >65 MWe 26 0.84 Vertically fired 28 0.80 Source: U.S. Environmental Protection Agency, Nitrogen Oxides Emission Reduction Program, Final Rule for Phase II, Group 1 and Group 2 Boilers (http://www.epa.gov/docs/acidrain/noxfs3.html).
Exhibit 1-5

CCT Program NOx Control Technology Characteristics

Boiler Size/ NO

x

Process Type Reduction Page

mbustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500-MWe/wall 68% 2-30

and artificial intelligence controls

g for Cyclone Coal reburning—30% heat input 100-MWe/cyclone 52–62% 2-34

w-NO

x

 Cell Burner LNB—separation of coal and air ports on plug-in unit 605-MWe/cell burner 48–58% 2-38

 Low-NOx Burners LNB/gas reburning/AOFA—13–18% gas heat input 172-MWe/wall 37–65% 2-42

monstration Coal reburning—14% heat input (tangentially fired) and 148-MWe/tangential 28% 2-46

17% heat input (cyclone) 50-MWe/cyclone 59%

ytic Reduction SCR—eight catalysts with different shapes and 8.7-MWe/various 80% 2-50

Ox Emissions chemical compositions

ilers

anced Tangentially LNB/AOFA—advanced LNB with close-coupled 180-MWe/tangential 37–45% 2-54

r the Reduction of NOx and separated overfire air

rs

 Cherokee Station for

New air fan in the foreground and new pulverizer in the

background for the micronized coal reburning project.

The SCR demonstration facility at Southern Company’s

Plant Crist.
Project Fact Sheets 1-11

rol Technology. Com

 encompass those tech

ly described control

her synergistic tech

ombine either LNBs or

ction. In one of these,

hance performance.

mber of techniques to

mance, such as LNBs

ng and durable wet

ve, and artificial intelli

 the six projects use

usly described.

rporates an SCR cata

r bag for NOx control

or SO2 control. The

erated in a standard

he SCR catalyst, allows

ol temperatures, forms

o enhance SO2 capture,

articulate capture.

ed by catalytic oxida

nsation of the SO3 in the

ulfuric acid. Following

dation allows the SCR

 concentration without

nia passing to the sec

to water vapor, nitro

Ox). Furthermore, most

e upstream baghouse

d condensing unit. The

e.

O2/NOx control technol

perations. Exhibit 1-6

eristics and perfor

 are described in the

Advanced Electric Power GenerationTechnology

Advanced electric power generation technologies enable the efficient and environmentally superior generation of electricity. The advanced electric

power generation projects selected under the CCTProgram are responsive to capacity expansion needsrequisite to meeting long-term demand, offsettingnuclear retirements, and meeting stringent CAAAemission limits effective in 2000. These technologies are characterized by high thermal efficiency,very low pollutant emissions, reduced CO2 emissions, few solid waste problems, and enhanced economics. Advanced electric power generation technologies may be deployed in modules, allowing

phased construction to better match demand growth,and to meet the smaller capacity requirements ofmunicipal, rural, and nonutility generators.

There are five generic advanced electric power

generation technologies demonstrated in the CCTProgram. The characteristics of these five technologies are outlined here, and the specific projects andtechnologies are presented in more detail in the factsheets.

Fluidized-Bed Combustion. Fluidized-bed combustion reduces emissions of SO2 and NOx by controlling combustion parameters and by injecting a sorbent

(such as crushed limestone) into the combustionchamber along with the coal. Pulverized coal mixedwith the limestone is fluidized on jets of air in thecombustion chamber. Sulfur released from the coal asSO2 is captured by the sorbent in the bed to form a

solid calcium compound that is removed with the ash.The resultant waste is a dry, benign solid that can bedisposed of easily or used in agricultural and construction applications. More than 90 percent of the SO2 can be captured in this manner. At combustion temperatures of 1,400–1,600 oF, the fluidized mixing of the fuel and sorbent enhances both combustion and sulfur capture. The operating temperature range is about half that of a conventional pulverized-coal boiler and below the temperature that thermal NOx is formed. In fact, FBC NOx emissions are about 70 to 80 percent lower than those for con- ventional pulverized-coal boilers. Thus, fluidized-bed combustors substantially reduce both SO2 and NOx emissions. Also, FBC has the capability of using high-ash coal, whereas conventional pulverized-coal units must limit ash content in the coal to relatively low levels. Two parallel paths were pursued in FBC develop- ment—bubbling and circulating beds. Bubbling fluid- ized-beds use a dense fluid bed and low fluidization velocity to effect good heat transfer and mitigate erosion of an in-bed heat exchanger. Circulating fluidized-beds use a relatively high fluidization veloc- ity that entrains the bed material, in conjunction with hot cyclones, to separate and recirculate the bed mate- rial from the flue gas before it passes to a heat ex- changer. Hybrid systems have evolved from these two basic approaches. Fluidized-bed combustion can be either atmo- spheric (AFBC) or pressurized (PFBC). The AFBC systems operate at atmospheric pressure while PFBC operates at pressure 6 to 16 times higher. The PFBC systems offer higher efficiency by using both a gas turbine and steam turbine. Consequently, operating costs and waste are reduced relative to AFBC, as well as boiler size per unit of power output. Second-generation PFBC integrates the combus- tor with a pyrolyzer (coal gasifier) to fuel a gas tur-
Exhibit 1-6

CT Program Combined SO2/NOx Control Technology Characteristics

Coal Sulfur SO2/NOx

Process Content Reduction Page

monstration SCR/oxidation catalyst/sulfuric acid condenser—synergistic 3.4% 95%/94% 2-60

catalyst effect and no solid waste

tension and LNB/sorbent injection—furnace and duct injection, calcium-based 1.6–3.8% 60–70%/40–50% 2-64

sorbents

leanup SCR/high temperature baghouse/sorbent injection—SCR in high- 3.4% 80–90%/90% 2-68

temperature filter bag and calcium-based sorbent injection

Gas Reburning Gas reburning/sorbent injection (GR-SI)—calcium-based sorbents 3.0% 50–60%/67% 2-72

used in duct injection

 Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5–4.0% 98%/53–58% 2-76

durable scrubber design

ns LNB/SNCR/sorbent injection—calcium- and sodium-based 0.4% 70%/62–80% 2-80

sorbents used in duct injection

bution bottle and feed

Humidification panels and controls on the side of duct

work where water is injected into the flue gas for GR-SIdemonstration.

The SO

x

-NO

x

-Rox BoxTM baghouse, silos, duct work,

and tie-in.
Project Fact Sheets 1-13

The 110-MWe Nucla ACFB demonstration enabled

Pyropower Corporation (now owned by Foster Wheeler) tosave almost three years in establishing a commercial line ofACFB units.

aste heat is used to

bine (bottoming cycle).

gas turbine and waste

-cycle mode signifi

ncy. Such advanced

ial for efficiencies over

ombustion projects,

ed demonstration (one

 other three are in the

hase.

Combined-Cycle. The

teps: (1) fuel gas is

with high-temperature

 or air) in a reducing

 either passed directly

 remove particulates,

ds, or the gas is first

hen cleaned conven

 is combusted in a gas

lectricity; and (4) the

t from the gas turbine

y steam generator, and

dditional electricity in a

mbined-cycle systems

st efficient of the

ies. Sulfur, nitrogen

re removed before the

e, that is, before com

eason, there is a much

ted than in a postcom

al composition of the

m must be cleaned to a

e low emissions, but to

protect downstream components, such as the gas turbine and catalysts, from erosion and corrosion.

In a coal gasifier, the sulfur in the coal is released

in the form of hydrogen sulfide (H2S) rather than asSO2. In some IGCC systems, much of the sulfurcontaining gas is captured by a sorbent injected intothe gasifier. Others use existing proven commercialhydrogen sulfide removal processes, which removemore than 99 percent of the sulfur, but require the fuelto be cooled, which is an efficiency penalty. Therefore, hot-gas cleanup systems are now being considered. In these hot cleanup systems, the hot coal gas ispassed through a bed of metal oxide particles, such aszinc oxides. Zinc oxide can absorb sulfur contaminants at temperatures in excess of 1,000 oF, and the

compound can be regenerated and reused with littleloss of effectiveness. Produced during the regeneration stage are salable sulfur, sulfuric acid, or sulfurcontaining compounds that may be used to produceuseful by-products. The technique is capable of removing more than 99.9 percent of the sulfur in the gasstream. With hot-gas cleanup, IGCC systems have thepotential for efficiencies of over 50 percent.

High levels of nitrogen removal are also possible.

Some of the coal’s nitrogen is converted to ammonia,

which can be almost totally removed by commerciallyavailable chemical processes. Nitrogen oxides formedin the gas turbine can be held to well within allowablelevels by staged combustion in the gas turbine or byadding moisture to control flame temperature.

Integrated Gasification Fuel Cell. A typical

fuel cell system using coal as fuel includes a coalgasifier with a gas cleanup system, a fuel cell to usethe coal gas to generate electricity (direct current) andheat, an inverter to convert direct current to alternating current, and a heat recovery system. The heatrecovery system would be used to produce additionalelectric power in a bottoming steam cycle.

Energy conversion in fuel cells is more efficient

than traditional energy conversion devices (up to 60percent, depending on fuel and type of fuel cell). Fuelcells directly transform the chemical energy of a fueland an oxidant (air or oxygen) into electrical energyinstead of going through intermediate steps—burner,boiler, turbines, and generators. Each fuel cell includes an anode and a cathode separated by an electrolyte layer. In a coal gasification/fuel cell application, coal gas is supplied to the anode and air is supplied to the cathode to produce electricity and heat.
one has completed

 and one is in the

ase. The project in

molten carbonate fuel

red diesels use either a

 to drive an electric

aust from the diesel

recovery unit to pro

lectric generating

onmental control

culate removal treat

e to the atmosphere.

 achieve a 41

–48

 5- to 20-MWe capac

ost amenable to dis

e CCT coal-fired

ny new coal burning

move the coal ash as

her than the furnace.

ors are based on a

ombustor, coal is

tside the furnace

es then pass into the

hange takes place.

combustor is that the

vity where it could

r heat transfer effi

 blown into the fur

re is kept so hot that

m slag, hence the name

f air (the cyclone)

 of the combustor

e.

Results show that by positioning air injection

ports so that coal is combusted in stages, NOx emissions can be reduced by 70 to 80 percent. Injecting

limestone into the combustion chamber has the potential to reduce sulfur emissions by 90 percent in combination with a spray dryer absorber. Advanced slagging combustors could replace oil-fired units in bothutility and industrial applications or be used to retrofitolder, conventional cyclone boilers.

Exhibit 1-7 summarizes the process characteristics and size of the advanced electric power generating technologies presented in the project fact sheets.

Coal Processing for Clean FuelsTechnology

The coal processing category includes a range of

technologies designed to produce high-energy-density, low-sulfur solid and clean liquid fuels, as well assystems to assist users in evaluating impacts of coalquality on boiler performance.

The Western SynCoal LLC’s advanced coal conversion process applies mostly physical-cleaning

methods to low-Btu, low-sulfur subbituminous coals,primarily to remove moisture and secondarily to remove ash. The objective is to enhance the energydensity of the already low-sulfur coal. Some conversion of the properties of the coal is required, however,to provide stability (prevent spontaneous combustion)in transport and handling. In the process, coal with5,500

–9,000 Btu/lb, 25

–40 percent moisture content,

and 0.5

–1.5 percent sulfur is converted to a 12,000

Btu/lb product with 1.0 percent moisture and as lowas 0.3 percent sulfur. The SynCoal® product is used at

utility and industrial facilities. Project operation wasextended through 2001.

The ENCOAL project, which completed operational testing in July 1997, used mild gasification to

convert low-Btu, low-sulfur subbituminous coal to ahigh-energy-density, low-sulfur solid product and aclean liquid fuel comparable to No. 6 fuel oil. Mildgasification is a pyrolysis process (heating in the absence of oxygen) performed at moderate temperaturesand pressures. It produces condensable volatile hydrocarbons in addition to solids and gas. The condensable fraction is drawn off as a liquid product.Most of the gas is used to provide on-site energyrequirements. The process solid is significantly beneficiated to produce an 11,000 Btu/lb low-sulfur solidfuel. The demonstration plant processed 500 tons perday of subbituminous coal, and produced 250 tons perday of solid Process-Derived Fuel (PDF®) and 250

barrels per day of Coal-Derived Liquids (CDL®).Both the solid and liquid fuels have undergone testburns at utility and industrial sites. The project wassuccessfully completed.

Shown is the Coltec coal-fired diesel being installed at

the University of Alaska in Fairbanks.
Project Fact Sheets 1-15

Exhibit 1-7

rogram Advanced Electric Power Generation Technology Characteristics

Process Size Page

onstration Project Pressurized circulating fluidized-bed combustion 137 MWe (net) 2- 86

FB Demonstration Project McIntosh 4A with pyrolyzer and topping combustor 240 MWe (net) 2- 88

ion Demonstration Project Atmospheric circulating fluidized-bed combustion 297.5 MWe (gross); 265 MWe (net) 2- 90

ject Pressurized bubbling fluidized-bed combustion 70 MWe 2-92

ect Atmospheric circulating fluidized-bed combustion 100 MWe 2-96

mbined Cycle

C Demonstration Project Oxygen-blown, slagging fixed-bed gasifier with cold gas cleanup 400 MWe (net); 2.0 MWe MCFC 2-102

t Air-blown, fluidized-bed gasifier with hot gas cleanup 107 MWe (gross); 99 MWe (net) 2-104

fication Oxygen-blown, entrained-flow gasifier with hot and cold gas cleanup 313 MWe (gross); 250 MWe (net) 2-106

n Repowering Project Oxygen-blown, two-stage entrained-flow gasifier with cold gas cleanup 296 MWe (gross); 262 MWe (net) 2-108

at Engines

on Project Coal-fueled diesel engine 6.4 MWe (net) 2-114

Advanced slagging combustor, spray dryer with sorbent recycle 50 MWe (nominal) 2-116

njectors for the Tidd PFBC

The Wabash IGCC gas cleanup system. The TRW slagging combustor for the Healy Station.
LPMEOHTM) process

 gallon/day indirect

esis gas from a coal

he process is the use

conversion catalyst.

n and eliminates the

gas shift conversion.

e the load-following

ulating application in

aracteristics of the

ing, Inc. and CQ Inc.

puter software package

ol to assist utilities in

r a specific boiler

 and environmental

e developed and veri

 at bench, pilot, and

d tests were con

The software has

e. More than 35 U.S.

e received CQE®

h Institute (EPRI)

 CQE® saves U.S.

lly.

 process characteris

ng for clean fuels

oject fact sheets.

chnology

the industrial sector

al issues and barriers

strial processes.

at both continuing

coal use and introducing coal use in various industrial sectors.

One of the critical environmental concerns has to

do with pollutant emissions resulting from producingcoke from coal for use in steel making. Two approaches to mitigate or eliminate this problem arebeing demonstrated. In one, about 40 percent of thecoke is displaced through direct injection of granularcoal into a blast furnace system. The coal is essentially burned in the blast furnace where the pollutantemissions are readily controlled (as opposed to firstcoking the coal). The other approach eliminates theneed for coke making by using a direct iron-makingprocess. In this process, raw coal is introduced into areactor to produce reducing gas and heat for a uniquereduction furnace; no coke is required. Excess reducing gas is cleaned and used to fuel a boiler for electricpower generation.

Coal is often the fuel of choice in cement production because production costs are largely driven by

fuel cost. Faced with the need to control SO2 emissions and to address growing solid waste managementproblems, industry sponsored the demonstration of aninnovative SO2 scrubber. The successfully demonstrated Passamaquoddy Technology Recovery ScrubberTM uses cement kiln dust, otherwise discarded aswaste, to control SO2 emissions, convert the sulfurand chloride acid gases to fertilizer, return the solidby-product as cement kiln feedstock, and producedistilled water. No new wastes are generated, andcement kiln dust waste is converted to feedstock.This technology also has application for controllingpollutant emissions in paper production and waste-toenergy applications.

In many industrial boiler applications, the relatively low, stable price of coal makes it an attractive

substitute for oil and gas feedstock. However, drawbacks to conversion of oil- and gas-fired units to coalinclude addition of SO2 and NOx controls, tube fouling, and the need for a coolant water circuit for thecombustor. Oil- and gas-fired units are not high SO2

or NO

x emitters; use relatively tight tube spacing in

the absence of potential ash fouling; and the flow ofoil or gas cools the combustor, precluding the needfor water cooling. For these reasons, the CCT Program demonstrated an advanced air-cooled, slaggingcombustor that could avoid these potential problems.The cyclone combustor stages introduction of air tocontrol NO

x, injects sorbent to control SO2, slags the

ash in the combustor to prevent tube fouling, and usesair cooling to preclude the need for water circuitry.

The pulse combustor to be demonstrated by ThermoChem has a wide range of applications. The technology can be used in many coal processes, including

coal gasification and waste-to-energy applications.

The cement kiln, slagging combustor, and blast

furnace granular-coal injection projects are completed. The CPICORTM and the ThermoChemprojects are in the design phase and the constructionphase, respectively.

Exhibit 1-9 summarizes process characteristics

and size for the industrial applications technologiespresented in more detail in the project fact sheets.
Project Fact Sheets 1-17

The LPMEOHTM process produces over 80,000 gal/day

of methanol, all of which is used by the Eastman ChemicalCompany in Kingsport, Tennessee.

’s advanced coal

p, Montana has produced

products.

Exhibit 1-8

T Program Coal Processing for Clean Fuels Technology Characteristics

Process Size Page

ion of the Liquid Phase Methanol Liquid phase process for methanol production from 80,000 gal/day 2-122

coal-derived syngas

ocess Demonstration Advanced coal conversion process for upgrading 45 tons/hr 2-124

low-rank coals

ty ExpertTM Coal Quality ExpertTM computer software Tested at 250–880 MWe 2-126

tion Project Liquids-from-coal (LFC®) mild gasification to 1,000 tons/day* 2-130

produce solid and liquid fuels

*Operated at 500 tons/day

The ENCOALmild gasification plant near Gillette,

Wyoming has operated 12,800 hours and processedapproximately 260,000 tons of raw coal and produced over120,000 tons of PDF® and 121,000 barrels of CDL®.
The Cement Kiln Flue Gas Recovery Scrubber project’s crystallizer and condenser in

foreground and flue gas condenser in background.

on facility, which demonstrated the injection of

st furnaces at Burns Harbor, Indiana.

Exhibit 1-9

CCT Program Industrial Applications Technology Characteristics

Process Size Page

al/Ore Direct reduction iron-making process to eliminate coke; 3,300 tons/day of hot metal 2-136

combined-cycle electric power generation 170 MWe

cation Test Advanced combustion using Manufacturing and Technology 30x106 Btu/hr 2-138

Conversion International’s pulse combustor/gasifier

ection System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of hot 2-140

metal/furnace

ith Internal Advanced slagging combustor with staged combustion and sorbent 23 x 106 Btu/hr 2-144

ol injection

Scrubber Cement kiln dust used to capture SO2; dust converted to feedstock; 1,450 tons/day of cement 2-148

and fertilizer and distilled water produced
Project Fact Sheets 2-1

eets

ument contains fact

 types of fact sheets are

 overview for ongoing

our-page summary for

completed operational

ets for completed

the major results from

urces for obtaining

y, contact persons and

ovided in the fact sheets

 and team members,

roject features, process

progress (if ongoing) or

ed), and commercial

lease of project-specific

ture, process flow

sheets are highly

s illustrations of the

nstrations. The portion

l to the demonstration is

heets by application

t 2-1. An index by

bit 2-2. Ongoing

ar first followed by

rations. A shaded area

completed operations

n these breakdowns,

projects are listed alphabetically by participant. Inaddition, Exhibit 2-1 indicates the solicitation underwhich the project was selected; its status as of June30, 2000; and the page number for each fact sheet.Exhibit 2-2 lists the projects alphabetically byparticipant and provides project location and pagenumbers. A key to interpreting the milestone chartsis provided in Exhibit 2-3.

An appendix containing contact information for

all of the projects is provided as Appendix A. A list ofacronyms used in this document is provided asAppendix B.

2. The Clean Coal Technology Projects
ects having completed operations.

Exhibit 2-1

Project Fact Sheets by Application Category

Participant Solicitation/Status Page

es

uspension Absorption AirPol, Inc. CCT-III/completed 3/94 2-8

as Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93 2-12

ization Demonstration Project LIFAC-North America CCT-III/completed 6/94 2-16

n Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95 2-20

ications of Technology for the CT-121 FGD Process Southern Company Services, Inc. CCT-II/completed 12/94 2-24

bustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/extended 2-30

 for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/completed 12/92 2-34

NO

x Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 4/93 2-38

Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 1/95 2-42

onstration for NOx Control New York State Electric & Gas Corporation CCT-IV/completed 4/99 2-46

tic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95 2-50

from High-Sulfur, Coal-Fired Boilers

nced Tangentially Fired Combustion Southern Company Services, Inc. CCT-II/completed 12/92 2-54

NOx Emissions from Coal-Fired Boilers

hnologies

onstration Project ABB Environmental Systems CCT-II/completed 12/94 2-60

nsion and Coolside Demonstration The Babcock & Wilcox Company. CCT-I/completed 8/91 2-64

eanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5/93 2-68

s Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 10/94 2-72

Demonstration Project New York State Electric & Gas Corporation CCT-IV/completed 6/98 2-76

s Control System Public Service Company of Colorado CCT-III/completed 12/96 2-80

neration

tration Project Lakeland, City of, Lakeland Electric CCT-III/design 2-86

Demonstration Project Lakeland, City of, Lakeland Electric CCT-V/design 2-88

n Demonstration Project JEA CCT-I/design 2-90
Project Fact Sheets 2-3

ojects having completed operations.

Exhibit 2-1 (continued)

Project Fact Sheets by Application Category

Participant Solicitation/Status Page

ct The Ohio Power Company CT-I/completed 3/95 2-92

ct Tri-State Generation and Transmission

Association, Inc. CCT-I/completed 1/91 2-96

ned-Cycle

Demonstration Project Kentucky Pioneer Energy, LLC CCT-V/design 2-102

Sierra Pacific Power Company CCT-IV/operational 2-104

cation Combined-Cycle Project Tampa Electric Company CCT-III/operational 2-106

Repowering Project Wabash River Coal Gasification Repowering CCT-IV/completed 12/99 2-108

Project Joint Venture

ngines

n Project Arthur D. Little, Inc. CCT-V/construction 2-114

Alaska Industrial Development and

Export Authority CCT-III/completed 12/99 2-116

Fuels

n of the Liquid Phase Methanol (LPMEOHTM) Process Air Products Liquid Phase

Conversion Company, L.P. CCT-III/operational 2-122

ess Demonstration Western SynCoal LLC CT-I/operational 2-124

 ExpertTM ABB Combustion Engineering, Inc.

and CQ Inc. CCT-I/completed 12/95 2-126

on Project ENCOAL Corporation CCT-III/completed 7/97 2-130

al/Ore Reduction (CPICORTM) CPICORTM Management Company LLC CCT-V/design 2-136

cation Test ThermoChem, Inc. CCT-IV/construction 2-138

ection System Demonstration Project Bethlehem Steel Corporation CCT-III/completed 11/98 2-140

ith Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/completed 5/90 2-144

Scrubber Passamaquoddy Tribe CCT-II/completed 9/93 2-148
Exhibit 2-2

Project Fact Sheets by Participant

Project Location Page

nc. and CQ Inc. Development of the Coal Quality ExpertTM Homer City, PA 2-126

SNOXTM Flue Gas Cleaning Demonstration Project Niles, OH 2-60

ersion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Kingsport, TN 2-122

Process

10-MWe Demonstration of Gas Suspension Absorption West Paducah, KY 2-8

nd Export Authority Healy Clean Coal Project Healy, AK 2-116

Clean Coal Diesel Demonstration Project Fairbanks, AK 2-114

he Demonstration of Coal Reburning for Cyclone Boiler NOx Control Cassville, WI 2-34

he Full-Scale Demonstration of Low-NOx Cell Burner Retrofit Aberdeen, OH 2-38

he LIMB Demonstration Project Extension and Coolside Demonstration Loraine, OH 2-64

he SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project Dilles Bottom, OH 2-68

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Seward, PA 2-12

Blast Furnace Granular-Coal Injection System Demonstration Project Burns Harbor, IN 2-140

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Williamsport, PA 2-144

ny LLC Clean Power from Integrated Coal/Ore Reduction (CPICORTM) Vineyard, UT 2-136

(see ABB Combustion Engineering and CQ Inc.)

ENCOAL® Mild Coal Gasification Project Gillette, WY 2-130

arch Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Hennepin, IL 2-72

Springfield, IL

arch Corporation Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Denver, CO 2-42

JEA Large-Scale CFB Combustion Demonstration Project Jacksonville, FL 2-90

Kentucky Pioneer Energy IGCC Demonstration Project Trapp, KY 2-102

tric McIntosh Unit 4A PCFB Demonstration Project Lakeland, FL 2-86

tric McIntosh Unit 4B Topped PCFB Demonstration Project Lakeland, FL 2-88

LIFAC Sorbent Injection Desulfurization Demonstration Project Richmond, IN 2-16

Corporation Micronized Coal Reburning Demonstration for NOx Control Lansing, NY 2-46
Project Fact Sheets 2-5

Exhibit 2-2 (continued)

Project Fact Sheets by Participant

Project Location Page

 Corporation Milliken Clean Coal Technology Demonstration Project Lansing, NY 2-76

Tidd PFBC Demonstration Project Brilliant, OH 2-92

Cement Kiln Flue Gas Recovery Scrubber Thomaston, ME 2-148

lorado Integrated Dry NOx /SO2 Emissions Control System Denver, CO 2-80

Advanced Flue Gas Desulfurization Demonstration Project Chesterton, IN 2-20

Piñon Pine IGCC Power Project Reno, NV 2-104

nc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coosa, GA 2-30

nc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newnan, GA 2-24

Process

nc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensacola, FL 2-50

NO

x Emissions from High-Sulfur, Coal-Fired Boilers

nc. 180-MWe Demonstration of Advanced Tangentially Fired Combustion Lynn Haven, FL 2-54

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

Tampa Electric Integrated Gasification Combined-Cycle Project Mulberry, FL 2-106

Pulse Combustor Design Qualification Test Baltimore, MD 2-138

mission Association, Inc. Nucla CFB Demonstration Project Nucla, CO 2-96

n Repowering Wabash River Coal Gasification Repowering Project West Terre Haute, IN 2-108

Advanced Coal Conversion Process Demonstration Colstrip, MT 2-124
t contains a bar chart that highlights major milestones—past and planned. The bar chart shows a project’s duration and indicates the time

ee general categories of project activities—preaward, design and construction, and operation. The key provided below explains what is

ch of these categories.

PreawardIncludes preaward briefings, negotiations, and other activities conducted during the period between DOE’s selectionof the project and award of the cooperative agreement.Design and ConstructionIncludes the NEPA process, permitting, design, procurement, construction, preoperational testing, and other activitiesconducted prior to the beginning of operation of the demonstration.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 demonstration project.

Exhibit 2-3

Key to Milestone Charts in Fact Sheets
Project Fact Sheets 2-7

nvironmental Control Devices

SO2 Control Technologies
Environmental Control Devices

ation of Gas

rption

gy owner

under and site owner

y, KY

(GSA) system for flue

 flue gas from a

eabody Martwick,

61% sulfur; Andalax,

3.5% sulfur (used

189 100%

259 30

930 70

ity of Gas Suspension

 for achieving Phase II

zed coal-fired boilers

Technology/Project Description

The GSA system consists of a vertical reactor in

which flue gas comes into contact with suspended solidsconsisting of lime, reaction products, and fly ash. About99% of the solids are recycled to the reactor via a cyclonewhile the exit gas stream passes through an electrostaticprecipitator (ESP) or pulse jet baghouse (PJBH) beforebeing released to the atmosphere. The lime slurry, prepared from hydrated lime, is injected through a spraynozzle at the bottom of the reactor. The volume of limeslurry is regulated with a variable-speed pump controlledby the measurement of the acid content in the inlet andoutlet gas streams. The dilution water added to the limeslurry is controlled by on-line measurements of the fluegas exit temperature.

A test program was structured to (1) optimize design

of the GSA reactor for reduction of SO2 emissions from

boilers using high-sulfur coal, and (2) evaluate the environmental control capability, economic potential, andmechanical performance of GSA. A statistically designedparametric (factorial) test plan was developed involvingsix variables. Beyond evaluation of the basic GSA unit tocontrol SO2, air toxics control tests were conducted, and

the effectiveness of a GSA/ESP and GSA/PJBH to control both SO2 and particulates were tested. Factorial tests

were followed by continuous runs to verify consistency ofperformance over time.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Project Fact Sheets 2-9

test effect on SO2 re

ration temperature next,

content.

/S molar ratio of 1.3 with

n and 0.04% chloride,

/S molar ratio of 1.4 with

on and 0.12% chloride,

e removal efficiency.

/S molar ratio of 1.4 with

on and 0.12% chloride,

uction relative to

– 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.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation and Reporting

Ground breaking/construction started 5/92

reaward

10/90 10/92

Design and Construction

Environmental monitoring plan completed 10/2/92Operation initiated 10/92

Design completed 12/91

ed 10/11/90

F) 9/21/90

Preoperational tests initiated 9/92Construction completed 9/92

6/95

Project completed/final report issued 6/95

Operation completed 3/94

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

simple design.

Economic• Capital and levelized (15-year constant 1990$) costs

for GSA installed in a 300-MWe plant using 2.6%sulfur coal are compared below to costs for a wetlimestone scrubber with forced oxidation (WLFOscrubber). EPRI’s TAGTM cost method was used.Based on EPRI cost studies of FGD processes, thecapital cost (1990$) for a conventional spray dryerwas $172/kW.

Capital Cost Levelized Cost(1990 $/kW) (mills/kWh)

GSA—3 units at 149 10.3550% capacityWLFO 216 13.04
Environmental Control Devices

Exhibit 2-5

GSA Factorial Testing Results

Exhibit 2-4

Variables and Levels Used in

GSA Factorial Testing

Variable LevelApproach-to-saturation temperature (°F) 8*, 18, 28

Ca/S (moles Ca(OH)2/mole inlet SO2) 1.00 and 1.30

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

suspending a high

y drying the solids,

gh rate with precise

rol comparable to that

ilization. The high

he sorbent/SO2

low approach-to

de usage. The

stem sustains the

gh lime utilization

st (lime) and fur

e amount of by

istinguished from

dest size, simple

he reactor, direct

me, and low reagent

ry coats recycled

rosion and en

cation.

bles used in the

ch they were ap

was held constant

d that lime stoichi

O2 removal. Ap

was the next most

by chloride levels.

n temperature of 8

the system, the

hloride level

on rates decrease

F approach-to

 for the higher

t 2-5 summarizes

valuate the

 with bituminous

coals averaging 2.7% sulfur, 0.12% chloride levels, and18 oF approach-to-saturation temperature. A subsequent14-day continuous run to evaluate the GSA/PJBH configuration was performed under the same conditions asthose of the 28-day run, except for adjustments in fly ashinjection rate from 1.5–1.0 gr/ft3 (actual).

The 28-day run on the GSA/ESP system showed that

the overall SO2 removal efficiency averaged slightly morethan 90%, very close to the set point of 91%, at an average Ca/S molar ratio of 1.40–1.45 moles Ca(OH)2/mole

inlet SO2. The system was able to adjust rapidly to the

surge in inlet SO2 caused by switching to 3.5% sulfur

Warrior Basin coal for a week. Lime utilization averaged66.1%. The particulate removal efficiency averaged99.9+% and emission rates were maintained below0.015 lb/106 Btu. The 14-day run on the GSA/PJBH

system showed that the SO2 removal efficiency averaged

more than 96% at an average Ca/S molar ratio of 1.34–1.43 moles Ca(OH)2/mole inlet SO2. Lime utilization

averaged 70.5%. The particulate removal efficiencyaveraged 99.99+% and emission rates ranged from0.001–0.003 lb/106 Btu.

All air toxics tests were conducted with 2.7% sulfur,

low-chloride coal with a 12 oF approach-to-saturationtemperature and a high fly ash loading of 2.0 gr/ft3 (actual). The GSA/ESP arrangement indicated average

removal efficiencies of greater than 99% for arsenic,barium, chromium, lead, and vanadium; somewhat lessfor manganese; and less than 99% for antimony, cadmium, mercury, and selenium. The GSA/PJBH configuration showed 99+% removal efficiencies for arsenic,barium, chromium, lead, manganese, selenium, and vanadium; with cadmium removal much lower and mercuryremoval lower than that of the GSA/ESP system. Theremoval of HCl and HF was dependent upon the utilization of lime slurry and was relatively independent ofparticulate control configuration. Removal efficiencieswere greater than 98% for HCl and 96% for HF.Operational Performance

Because the GSA system has suspended recycle

solids to provide a contact area for SO2 capture, multiple

high-pressure atomizer nozzles or high-speed rotarynozzles are not required to achieve uniform, fine dropletsize. Also, recycle of solids is direct and avoids recy-
Project Fact Sheets 2-11

AirPol, Inc. successfully demonstrated the GSA system

at TVA’s Center for Emissions Research, located at TVA’sShawnee Plant.

 which would necessi

t materials in the

nsfer characteristics of

m to be significantly

y dryer for the same

ird the size. This makes

ed plants and reduces

em slurry is sprayed on

or walls, avoiding direct

rrosion-resistant alloy

ncentration of rapidly

r walls and mitigates

ates a significantly

ntional spray dryer, 2–5

3 for a spray dryer,

rticulate controls. The

y-product containing

al contains both fly ash

ddition of water, the by

c reaction, essentially

a low-grade cement.

ds, which have been

rocesses, economics

 difficult retrofit of a

sulfur coal. The design

% at a lime feed rate

mole inlet SO2. Lime

 cost of limestone. It

l cost was $149/kW

 capacity, and (2) the

 1990$) was 10.35 mills/

pacity.

 WLFO scrubber showed

 be $216/kW and 13.04

apital cost listed in EPRI

ay dryer at 300-MWe

W (1990$). Also, because the GSA requires less power and has better lime utilization than a spray dryer, the GSA will have a lower operating cost. Commercial Applications The low capital cost, moderate operating cost, and high SO2 capture efficiency make the GSA system par- ticularly attractive as a CAAA compliance option for boilers in the 50- to 250-MWe range. Other major advan- tages include the modest space requirements comparable to duct injection systems; high availability/reliability

owing to design simplicity; and low dust loading, minimizing particulate upgrade costs.

GSA market entry was significantly enhanced with

the sale of a 50-MWe unit worth $10 million to the cityof Hamilton, Ohio, subsidized by the Ohio Coal Development Office. A sale worth $1.3 million has been made tothe U.S. Army for hazardous waste disposal. AnotherGSA system has been sold to a Swedish iron ore sinterplant. Sales to Taiwan, Indonesia, and India have acombined value of $20 million. Furthermore, Taiwancontracted for technical assistance and proprietary equipment valued at $1.0 million.ContactsNiels H. Kastrup, (281) 539-3400

FLS miljo, Inc.100 Glennborough DriveHouston, TX 77067(281) 539-3411 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• 10-MWe Demonstration of Gas Suspension Absorption Final Project Performance and Economics Report. Report No. DOE/PC/90542-T9. AirPol, Inc.

June 1995. (Available from NTIS as DE95016681.)

• 10-MW Demonstration of Gas Suspension Absorption

Final Public Design Report. Report No. DOE/PC/

90542-T10. AirPol, Inc. June 1995. (Availablefrom NTIS as DE960003270.)

• SO2 Removal Using Gas Suspension Absorption Technology. Topical Report No. 4. U.S. Department of

Energy and AirPol, Inc. April 1995.

• 10-MWe Demonstration of the Gas Suspension Absorption Process at TVA’s Center for Emissions Research: Final Report. Report No. DOE/PC/90542-

T10. Tennessee Valley Authority. March 1995.(Available from NTIS as DE96000327.)
Environmental Control Devices

spersion

zation

cofunder and host

t Authority—cofunder

orporation—cofunder

der

nsylvania Electric

No. 5)

nfined zone dispersion

D) process

% sulfur

600 100%

800 50

800 50

capabilities of in-duct

y, to define the opti

s and to determine

CZD/FGD’s operability, reliability, and cost-effectiveness during long-term testing and its impact on downstream operations and emissions.Technology/Project Description

In Bechtel’s CZD/FGD process, a finely atomized

slurry of reactive lime is sprayed into the flue gas streambetween the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the center ofthe duct by spray nozzles designed to produce a cone offine spray. As the spray moves downstream and expands, the gas within the cone cools and the SO2 is

quickly absorbed on the liquid droplets. The dropletsmix with the hot flue gas, and the water evaporates rapidly. Fast drying precludes wet particle buildup in the

duct and aids the flue gas in carrying the dry reactionproducts and the unreacted lime to the ESP.

 This project included injection of different types of

sorbents (dolomitic and calcitic limes) with several atomizer designs using low- and high-sulfur coals to evaluatethe effects on SO2 removal and ESP performance. The

demonstration was conducted at Pennsylvania ElectricCompany’s Seward Station in Seward, PA. One-half ofthe flue gas capacity of the 147-MWe Unit No. 5 wasrouted through a modified, extended straight section ofduct between the first- and second-stage ESPs.

ded 100% by the participant

.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Project Fact Sheets 2-13

1990 1991 1992 1993 1994 1995 1996 1997 1998

ime proved to be a more

ry hydrated calcitic lime

.

 most influential param

 temperature was the

te. For SO2 capture

flue gas temperature of

en sorbent did not in

y beyond a certain

moval efficiencies of

 with flue gas tempera

), sorbent injection rate

me of 2 seconds, and a

ime concentration of

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

dolomitic lime slurry concentration, and a stoichiometric ratio of 2–2.5 resulted in a 40–50% lime utilizationrate. That is, 2–2.5 moles of CaO or CaO•MgO wererequired for every mole of SO2 removed.

• Assuming 92% lime purity, 1.9–2.4 tons of lime was

required for every ton of SO2 removed.

Operational• About 100 ft of straight duct was required to assure

the 2-second residence time needed for effectiveCZD/FGD operation.

• At Seward Station, stack opacity was not detrimentally

affected by CZD/FGD.

• Availability of CZD/FGD was very good.• Some CZD/FGD modification will be necessary to

assure consistent SO2 removal and avoid deposition of

solids within the ductwork during upsets.

Economic• Capital cost of a 500-MWe system operating on 4%

sulfur coal and achieving 50% SO2 reduction was

estimated at less than $30/kW and operating cost at$300/ton of SO2 removed (1994$).

reaward Operation and Reporting

10/90

art 6/90

MTF) 9/90

arded 10/90

eted 10/90

Ground breaking/construction started 3/91

Construction completed 6/91Environmental monitoring plan 6/12/91

Preoperational tests initiated 7/91Operation initiated 7/91

Design and Construction

Operation completed 6/93

7/91

Project completed/final report issued 6/94

6/94
Environmental Control Devices

D is to form

e middle of a

ot gas be

alls. The

SO2 in the

o form solid

om the point

products

 the flue

pecial reac

uctwork.

 Type S

educed

ZD/FGD

The in

ocessed flue

iminating the need for

wo-part test program

with the first

sisting primarily of

onths consisting of

uring the continuous

 was operated under

 utility boiler operators.

horoughly tested both

o testing.

est program, which

leted in August 1992.

s:

l of 50%;

ess than $300/ton; and

ormal boiler operations

missions and opacity.

The parametric tests included duct injection of atomized lime slurry made of dry hydrated calcitic lime,

freshly slaked calcitic lime, and pressure-hydrated dolomitic lime. All three reagents remove SO2 from the flue

gas but require different feed concentrations of limeslurry for the same percentage of SO2 removed. The most

efficient removals and easiest operation were achievedusing pressure-hydrated dolomitic lime.Environmental Performance

Sorbent injection rate proved to be the most influential factor on SO2 capture. The rate of injection possible

was limited by the flue gas temperature. This impacted aportion of the demonstration when air leakage caused fluegas temperature to drop from 300–310 oF to 260–280 oF.At 300–310 oF, injection rates of 52–57 gal/min werepossible and SO2 reductions greater than 50% were

achieved. At 260–280 oF, injection rates had to bedropped to 30–40 gal/min, resulting in a 15–30% drop inSO2 removal efficiency. Slurry concentration for a given

sorbent did not increase SO2 removal efficiency beyond a

certain threshold concentration. For example, with pressure-hydrated dolomitic lime, slurry concentrations above 9% did not increase SO2 capture efficiency. Parametric tests indicated that SO2 removals above 50% are possible under the following conditions: flue gas temperature of 300–310 oF; boiler load of 145–147 MWe; residence time in the duct of 2 seconds; and lime slurry injection rate of 52–57 gal/min. Operational Performance The percentage of lime utilization in the CZD/FGD significantly affected the total cost of SO2 removal. An analysis of the continuous operational data indicated that the percentage of lime utilization was directly dependent on two key factors: (1) percentage of SO2 removed, and (2) lime slurry feed concentration. For operating conditions at Seward Station, data indicated that for 40–50% SO2 removal, a 6–8% lime or dolomitic lime slurry concentration, and a stoichiometric ratio of 2–2.5 resulted in a 40–50% lime utilization rate. That is, 2–2.5 moles of CaO or CaO•MgO were required for every mole of SO2 removed; or assuming 92% lime purity, 1.9–2.4 tons of lime were required for every ton of SO2 removed. In summary, the demonstration showed the following results: • A 50% SO2 removal efficiency with CZD/FGD was possible. • Drying and SO2 absorption required a residence time of 2 seconds, which required a long and straight hori- zontal gas duct of about 100 feet. • The fully automated system integrated with the power plant operation demonstrated that the CZD/FGD pro- cess responded well to automated control operation. However, modifications to the CZD/FGD were re- quired to assure consistent SO2 removal and avoid deposition of solids within the gas duct during upsets. • Availability of the system was very good. • At Seward Station, stack opacity was not detrimentally affected by the CZD/FGD system. Bechtel’s demonstration showed that 50% SO2 removal efficiency was possible using CZD/FGD technology. The extended duct into which lime slurry was injected is in the foreground.
Project Fact Sheets 2-15

D/FGD process can

 removed (1994$) when

ng 4% sulfur coal.

fitted with CZD/FGD for

al cost is estimated to be

DOE-funded CZD/FGD

Station, the CZD/FGD

 SO2 removal during

wing daily load cycles.

nsylvania Electric Com

emonstration for an

that CZD/FGD opera

han 50% could be sus

 significant process prob

etrofiting existing plants

iler flue gas facilities to

of sulfur-containing

coals. A CZD/FGD system can be added to a utilityboiler with a capital investment of about $25–50/kW ofinstalled capacity, or approximately one-fourth the cost ofbuilding a conventional wet scrubber. In addition to lowcapital cost, other advantages include small space requirements, ease of retrofit, low energy requirements, fullyautomated operation, and production of only nontoxic,disposable waste. The CZD/FGD technology is particularly well suited for retrofitting existing boilers, independent of type, age, or size. The CZD/FGD installationdoes not require major power station alterations and canbe easily and economically integrated into existing powerplants.ContactsJoseph T. Newman, Project Manager, (415) 768-1189

Bechtel CorporationP.O. Box 193965San Francisco, CA 94119-3965(415) 768-2095 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

GD lime slurry injector control system.

References• Confined Zone Dispersion Project: Final Technical

Report. Bechtel Corporation. June 1994.

• Confined Zone Dispersion Project: Public Design

Report. Bechtel Corporation. October 1993.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Confined Zone DispersionFlue Gas Desulfurization Demonstration. BechtelCorporation. Report No. DOE/FE-0203P. U.S. Department of Energy. September 1990. (Availablefrom NTIS as DE91002564.)
Environmental Control Devices

ection

monstration

nture partnership

tion and ICF Kaiser

nder and project

funder

r

nder and host utility

—cofunder

funder

chmond Power &

, Unit No. 2)

 with sulfur capture in

on reactor

772 100%

864 50

908 50

Project Objective

To demonstrate that electric power plants—especially those with space limitations and burning highsulfur coals—can be retrofitted successfully with the

LIFAC limestone injection process to remove 75–85% ofthe SO2 from flue gas and produce a dry solid waste

product for disposal in a landfill.Technology/Project Description

Pulverized limestone is pneumatically blown into

the upper part of the boiler near the superheater where itabsorbs some of the SO2 in the boiler flue gas. The limestone is calcined into calcium oxide and is available for

capture of additional SO2 downstream in the activation,

or humidification, reactor. In the vertical chamber, watersprays initiate a series of chemical reactions leading to

SO2 capture. After leaving the chamber, the sorbent is

easily separated from the flue gas along with the fly ashin the electrostatic precipitator (ESP). The sorbent material from the reactor and electrostatic precipitator arerecirculated back through the reactor for increased efficiency. The waste is dry, making it easier to handle thanthe wet scrubber sludge produced by conventional wetlimestone scrubber systems.

The technology enables power plants with space

limitations to use high-sulfur midwestern coals, by providing an injection process that removes 75–85% of theSO2 from flue gas and produces a dry solid waste productsuitable for disposal in a landfill.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Project Fact Sheets 2-17

1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Design and Construction Operation and Reporting

Original design completed 7/91

Cooperative agreement awarded 11/20/90

NEPA process completed (MTF) 10/2/90

Ground breaking/construction started 5/29/91

 selected project (CCT-III) 12/19/89

Preoperational tests initiated 7/92

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

Operation completed 6/94

Operation initiated 9/92

11/90 9/92

0% at a calcium-to-sulfur

roach-to-saturation tem

stone fineness of 80%

imestone fineness of

% lower at a Ca/S molar

oach-to-saturation

he greatest influence on

e limestone fineness, Ca/

uration temperature, and

ted in the demonstration

sing the recycle rate and

saturation temperature

2 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 operation during steady-stateoperation.

• Fly and bottom ash were dry and readily disposed of

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

Operational• When operating with fine limestone (80% minus

325 mesh), the soot-blowing cycle had to be reducedfrom 6.0 to 4.5 hours.

• Automated programmable logic and simple design

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

• The amount of bottom ash increased slightly, but

there was no negative impact on the ash-handlingsystem.

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

(300 MWe); $76/kW for one LIFAC reactor(150 MWe); $99/kW for one LIFAC reactor(65 MWe).

• Operating cost (1994$)—$65/ton of SO2 removal,

assuming 75% SO2 capture, Ca/S molar ratio of 2.0,

limestone composed of 95% CaCO3, and costing

$15/ton.

4/98

Project completed/final

report issued 4/98
Environmental Control Devices

The LIFAC system successfully demonstrated at

Whitewater Valley Station Unit No. 2 is being retained byRichmond Power & Light for commercial use with highsulfur coal. There are 10 full-scale LIFAC units in Canada,China, Finland, Russia, and the United States.

esigned to enhance the

on systems for SO2

ble aspects of low capi

of retrofit. Further

orbent (about 1/3 of the

 system was incorpo

as composed of five

n objectives. These

 operation of the host

ms prior to LIFAC

to evaluate the many

C process parameters

l.

med after the parametric

and operability of the

tinuous operating peri

d to demonstrate

mmercial operating

eating the baseline test

by the LIFAC system.

monstration varied in

wever, most of the

her sulfur coals

 phase, the numerous

fects on sulfur removal

ur major parameters

ulfur removal efficiency

were limestone fineness, Ca/S molar ratio, reactor bottomtemperature (approach-to-saturation), and ESP ash recycling rate. Total SO2 capture was about 15% better when

injecting fine limestone (80% minus 325 mesh) than itwas with coarse limestone (80% minus 200 mesh).

While injecting the fine limestone, the soot blowing

frequency had to be increased from 6-hour to 4.5-hourcycles. The coarse-quality limestone did not affect sootblowing but was found to be more abrasive on the feedand transport hoses.

Parametric tests indicated that a 70% SO2 reduction

was achievable with a Ca/S molar ratio of 2.0. ESP ashcontaining unspent sorbent and fly ash was recycled fromthe ESP hoppers back into the reactor inlet duct work.Ash recycling was found to be essential for efficient SO2

capture. However, the large quantity of ash removedfrom the LIFAC reactor bottom and the small size of theESP hoppers limited the ESP ash recycling rate. As aresult, the amount of material recycled from the ESP wasapproximately 70% less than had been anticipated, buteven this low recycling rate was found to affect SO2capture. During a brief test, it was found that increasingthe recycle rate by 50% resulted in a 5% increase in SO2removal efficiency. It was estimated that if the reactorbottom ash is recycled along with ESP ash, while sustaining a reactor temperature of 5 oF above saturation temperature, an SO2 reduction of 85% could be maintained.

Operational Performance

Optimization testing began in March 1994 and was

followed by long-term testing in June 1994. The boilerwas operated at an average load of 60 MWe during longterm testing, although it fluctuated according to powerdemand. The LIFAC process automatically adjusted toboiler load changes. A Ca/S molar ratio of 2.0 was selected to attain SO2 reductions above 70%. Reactor bottom temperature was about 5 oF higher than optimum to

avoid ash buildup on the steam reheaters. Atomizedwater droplet size was smaller than optimum for the same

reason. 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 boileroperating ranges. Stack opacity was low (about 10%)and ESP efficiency was high (99.2%). The amount of
Project Fact Sheets 2-19

 is shown being lifted into

ation, long-term testing

% or more could be

ration.

tly during testing, but

the power plant’s bottom

 solid waste generated

ium compounds, and

l landfill.

o be highly operable

and is simple to operate.

own and restarted. The

mmable logic system

that regulates process control loops, interlocking, startup,shutdowns, and data collection. The entire LIFAC process was easily managed via two personal computerslocated in the host utility’s control room.Economic Performance

The economic evaluation indicated that the capital

cost of a LIFAC installation is lower than for either aspray dryer or wet scrubber. Capital costs for LIFACtechnology vary, depending on unit size and the quantityof reactors needed:• $99/kW for one LIFAC reactor at Whitewater Valley

Station (65 MWe) (1994$),

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

(150 MWe), and

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

(300 MWe).

Crushed limestone accounts for about one-half of

LIFAC’s operating costs. LIFAC requires 4.3 tons oflimestone to remove 1.0 ton of SO2, assuming 75%

SO2 capture, a Ca/S molar ratio of 2.0, and limestone

containing 95% CaCO3. Assuming limestone costs of

$15/ton, LIFAC’s operating cost would be $65/ton ofSO2 removed.

Commercial Applications

There are 10 full-scale LIFAC units in operation in

Canada, China, Finland, Russia, and the United States.The LIFAC system at Richmond Power & Light is thefirst to be applied to a power plant using high-sulfur (2.0–2.9%) coal. The LIFAC system is being retained byRichmond Power & Light at Whitewater Valley Station,Unit No. 2. The other LIFAC installations on powerplants are using bituminous and lignite coals havinglower sulfur contents (0.6–1.5%).

ContactsDarryl Brogan, (412) 497-2144

ICF Kaiser Engineers, Inc.Gateway View Plaza1600 West Carson StreetPittsburgh, PA 15219-1031(412) 497-2212 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• LIFAC Sorbent Injection Desulfurization Demonstration Project. Final Report, Vol. II: Project Performance and Economics. LIFAC-North America. February 1998. (Available from NTIS as DE96004421.)• “LIFAC Nearing Marketability.” Clean Coal Today.

Report No. DOE/FE-0215P-21. Spring 1996.

• Viiala, J., et al. “Commercialization of the LIFAC

Sorbent Injection Process in North America.” ThirdAnnual Clean Coal Technology Conference: Technical Papers. September 1994.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: LIFAC Sorbent InjectionDesulfurization Demonstration Project. LIFAC-NorthAmerica. Report No. DOE/FE-0207P. U.S. Department of Energy, October 1990. (Available from NTISas DE91001077.)
Environmental Control Devices

s

monstration

diary of Pure Air,

ween Air Products and

eavy Industries

ompany—cofunder

—process designer

Engineers and Con

—constructor and

rthern Indiana Public

ting Station, Unit Nos.

lfurization (AFGD)

ration process

898 100%

200 42

698 58

Project Objective

To reduce SO2 emissions by 95% or more at approximately one-half the cost of conventional scrubbing technology, significantly reduce space requirements, and

create no new waste streams.Technology/Project Description

Pure Air built a single SO2 absorber for a 528-MWe

power plant. Although the largest capacity absorbermodule of its time in the United States, space requirements were modest because no spare or backup absorbermodules were required. The absorber performed threefunctions in a single vessel: prequenching, absorbing, andoxidation of sludge to gypsum. Additionally, the absorber was of a co-current design, in which the flue gasand scrubbing slurry move in the same direction and at arelatively high velocity compared to that in conventional

scrubbers. These features all combined to yield a stateof-the-art SO2 absorber that was more compact and less

expensive than contemporary conventional scrubbers.

Other technical features included the injection of

pulverized limestone directly into the absorber, a devicecalled an air rotary sparger located within the base of theabsorber, and a novel wastewater evaporation system.The air rotary sparger combined the functions of agitationand air distribution into one piece of equipment to facilitate the oxidation of calcium sulfite to gypsum.

Pure Air also demonstrated a unique gypsum

agglomeration process, PowerChip®, to significantly

enhance handling characteristics of AFGD-derived gypsum.

e Air on the Lake, L.P.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Project Fact Sheets 2-21

single 600-MWe ab

 to remove 95% or more

 when operating with

 produced in lieu of

roduced was sold

ystem (WES) mitigated

ater generation associated

showed the potential for

charge (only a partial

rket potential for AFGD

tively converting it to a

racteristics of natural

• Air toxics testing established that all acid gases were

effectively captured and neutralized by the AFGD.Trace elements largely became constituents of thesolids streams (bottom ash, fly ash, and gypsum product). Some boron, selenium, and mercury passed tothe stack 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.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction Operation and Reporting

Project completed/final report issued 6/96

perative agreement awarded 12/20/89

Preoperational tests initiated 3/92

Operation initiated 6/92

Design completed 9/92Construction completed 9/92

Operation completed 6/95

6/92

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

Environmental monitoring plan completed 1/31/91

6/96

Economic• Capital costs and space requirements for AFGD were

about half those of conventional systems.
Environmental Control Devices

Exhibit 2-6

 Pure Air SO2 Removal Performance

(100% Boiler Load)

e absorber modules of

ge volumes of flue gas

ity and reliability with

les. The major perfor

n, the AFGD unit accu

 with an availability of

ns of SO2 were re

f 95% or more, and

m were produced. The

rvice, which includes

.S. Gypsum’s East

ction plant.

d clearly established

sign parameters (with

chieve 95% SO2 reduc

 coals. The design

ichiometric ratio was

t by gypsum purity

acted reagent allowed

ol parameter was the

reagent slurry injected

lume of flue gas (G).

 gal/1,000 ft3. The

ermined by solids

requirement for full

igh end of the L/G ratio

ance leveled out.

ur contents were se

amine SO2 removal

lfur content, stoichio

d were 33%, 67%, and

well above 95%, were

with low to moderate

gs, even for 4.5%

es the results of para

In the AFGD process, chlorides that would have

been released to the air are captured, but potentially become a wastewater problem. This was mitigated by theaddition of the WES, which takes a portion of the wastewater stream with high chloride and sulfate levels andinjects it into the ductwork upstream of the ESP. The hotflue gas evaporates the water and the dissolved solids arecaptured in the ESP. Problems were experienced earlyon, with the WES nozzles failing to provide adequateatomization, and plugging as well. This was resolved byreplacing the original single-fluid nozzles with dual-fluidsystems employing air as the second fluid.

Commercial-grade gypsum quality (95.6–99.7%)

was maintained throughout testing, even at the lowersulfur concentrations where the ratio of fly ash to gypsumincreases due to lower sulfate availability. The primaryimportance of producing a commercial-grade gypsum isavoidance of the environmental and economic consequences of disposal. Marketability of the gypsum isdependent upon whether users are in range of economic

transport and whether they canhandle the gypsum by-product.For these reasons, PowerChip®

technology was demonstrated aspart of the project. This technology uses a compression mill toconvert the highly cohesiveAFGD gypsum cake into a flakedproduct with handling characteristics equivalent to natural rockgypsum. The process avoids useof binders, pre-drying, or precalcining normally associatedwith briquetting, and is 30–55%cheaper at $2.50–$4.10/ton.

Air toxics testing established

that all acid gases are effectivelycaptured and neutralized by theAFGD. Trace elements largelybecome constituents of the solids

streams (bottom ash, fly ash, gypsum product). Someboron, selenium, and mercury pass to the stack gas in avapor state.Operational Performance

Availability over the 3-year operating period averaged 99.5% while maintaining an average SO2 removal

efficiency of 94%. This was attributable to the simple,effective design and an effective operating/maintenancephilosophy. Modifications contributed to the high availability. An example was the implementation of new alloytechnology, C-276 alloy over carbon steel clad material,to replace alloy wallpaper construction within the absorber tower wet/dry interface. The use of co-currentrather than conventional counter-current flow resulted inlower pressure drops across the absorber and afforded theflexibility to increase gas flow without an abrupt drop inremoval efficiency. The AFGD SO2 capture efficiency

with limestone was comparable to that in wet scrubbersusing lime, which is far more expensive. The 24-hour

100

95

90

85

80
Project Fact Sheets 2-23

0

50

100150200250300350400

AB CDE

00.20.40.60.811.2

Delivered Fuel

Plant Modifications

Exhibit 2-8

Flue Gas Desulfurization

Economics

500-MWe plant, 30-yr levelized costs, allowance value of$300/tonIncremental cases:A

—Conventional FGD (EPRI model)

B

—AFGD, own-and-operate arrangement

C

—Adds gypsum sales

D

—Adds emission allowance credits at $300/ton, for 90% SO2

removal

E

—Increases SO2 removal to 95%

Exhibit 2-7

Estimated Costs for an AFGD System

(1995 Current Dollars)

Cases: 1 2 3 456789

e (MWe) 100 100 100 300 300 300 500 500 500

fur content (%) 1.5 3.0 4.5 1.5 3.0 4.5 1.5 3.0 4.5

ost ($/kW) 193 210 227 111 121 131 86 94 101

d cost ($/ton SO2

)

ar life 1,518 840 603 720 401 294 536 302 223ar life 1,527 846 607 716 399 294 531 300 223

d cost (mills/kWh)

ar life 16.39 18.15 19.55 7.78 8.65 9.54 5.79 6.52 7.24ar life 16.49 18.28 19.68 7.73 8.62 9.52 5.74 6.48 7.21

ntent. A capacity factor

ciency of 90% were

lized cost followed

Technical Assessment

he own-and-operate ar

 and emission allowances

depicts the relative costs

ating unit in the Midwest

ase case conventional

 cases. The horizontal

e of costs for a fuel

 the cost of fuel delivered

nd the upper bar allows

commodate the compli

ositioned well to com

na of 2000 and beyond.

kedly reduced cost and

pete with fuel switching

n with a first-generation

system. Advances in technology, e.g., in materials and

components, should lower costs for AFGD. The ownand-operate business approach has done much to mitigate risk on the part of prospective users. High SO2

capture efficiency places an AFGD user in the possibleposition to trade allowances or apply credits to otherunits within the utility. WES and PowerChip® mitigate

or eliminate otherwise serious environmental concerns.AFGD effectively deals with hazardous air pollutants.

The project received Power magazine’s 1993 Powerplant Award and the National Society of Professional Engineers’ 1992 Outstanding Engineering Achievement Award.

ContactsTim Roth, (610) 481-6257

Pure Air on the Lake, L.P.c/o Air Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501(610) 481-7166 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991

References• Advanced Flue Gas Desulfurization (AFGD) Demonstration Project. Final Technical Report, Vol. II:

Project Performance and Economics. Pure Air on the

Lake, L.P. April 1996. (Available from NTIS asDE96050313.)

• Advanced Flue Gas Desulfurization Project: Public

Design Report. Pure Air on the Lake, L.P. March 1990.

• Summary of Air Toxics Emissions Testing at Sixteen

Utility Power Plants. Prepared by Burns and Roe Services Corporation for U.S. Department of Energy, Pittsburgh Energy Technology Center. July 1996.

$/Ton SO2 $/106 Btu
Environmental Control Devices

Innovative

chnology for

ocess

—cofunder

tal and analytical

r

pment—fiberglass

ant

ultant

oundation—

onsultant

rgia Power Company’s

oroughbred-121

urization (AFGD) pro

®

sulfur

Project FundingTotal project cost $43,074,996 100%DOE 21,085,211 49Participant 21,989,785 51Project Objective

To demonstrate 90% SO2 control at high reliability

with and without simultaneous particulate control requisite to eliminating spare absorber modules; to evaluateuse of fiberglass-reinforced plastic (FRP) vessels to eliminate flue gas prescrubbing and reheat, and to enhancereliability; and to evaluate use of gypsum to reduce wastemanagement costs.Technology/Project Description

The project demonstrated the CT-121 AFGD process, which uses a unique absorber design known as the

Jet Bubbling Reactor® (JBR). The process combines

limestone AFGD reaction, forced oxidation, and gypsumcrystallization in one process vessel. The process ismechanically and chemically simpler than conventionalAFGD processes and can be expected to exhibit lowercost characteristics.

The flue gas enters underneath the scrubbing solution in the JBR. The SO2 in the flue gas is absorbed and

forms calcium sulfite (CaSO3). Air is bubbled into the

bottom of the solution to oxidize the calcium sulfite toform gypsum. The slurry is dewatered in a gypsum stack,which involves filling a diked area with gypsum slurry.Gypsum solids settle in the diked area by gravity, andclear water flows to a retention pond. The clear waterfrom the pond is returned to the process.

ark of the Chiyoda Corp.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

**Years omitted

1 2

Project Fact Sheets 2-25

1990 1991 1992 1993 1994 1995 1996 1999 2000

4/90

Design and Construction Operation and Reporting

10/92

Cooperative agreement awarded 4/2/90

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

Environmental monitoringplan completed 12/18/90

Preoperational tests initiated 5/92

Design completed 9/92

Operation initiated 10/92Construction completed 10/92

ency was achieved at

000–3,500 ppm with

%.

oval efficiencies of

adings of 0.303–

ange of 50–100 MWe.

ction of particle size:

re

ure

capture

e

P) testing showed greater

n chloride (HCl) and

, 80–98% capture of

0% capture of mercury

0% capture of selenium.

• Gypsum stacking proved effective for producing

wallboard/cement-grade gypsum.

Operational• FRP-fabricated equipment proved durable both structurally and chemically, eliminating the need 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, precluding the need for aspare reactor module.

• Simultaneous SO2 and particulate control were

achieved at fly ash loadings similar to an electrostaticprecipitator (ESP) with marginal performance.

10/99

Operation completed 12/94

Project completed/final

report issued 10/99

**

Economic• Capital costs for project equipment, process, and

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

• Fixed O&M costs were $357,000/yr (1994$), and

variable operating costs were $34–64/ton of SO2

removed, depending on specific test conditions.

• Generic plant costs were not estimated; however,

elimination of the need for flue gas prescrubbing,reheat, and a spare module should result in capitalrequirements far below those of contemporary conventional flue gas desulfurization (FGD) systems.
Environmental Control Devices

w Ash Elevated Ash Cumulative

ase Phase for Project

,750 7,250 19,000

,430 6,310 18,340

,600 5,210 13,810

,800 5,490 14,290

8 0.95 0.967 0.95 0.973 0.72 0.75

ted divided by the hours called upon to operate

lable divided by the total hours in the period

ted divided by the total hours in the period

xhibit 2-9

f CT-121 Scrubber

Exhibit 2-10

SO2 Removal Efficiency

iffers from the more

gas desulfurization

ssel is used in place of

k/thickener arrange

o a gypsum transfer

rystal growth to pro

ulting in large, easily

ntional systems employ

eacted slurry causing

leation).

7 months, including

ich approximately

t 2-9 summarizes oper

te loading included a

cipitator (ESP) com

erm testing was con

ergized to simulate a

121 retrofit to a boiler

culate collection device. The SO2 removal efficiency was measured under five different inlet concentrations with coals averaging 2.4% sulfur and ranging from 1.2

– 4.3% sulfur (as

burned).Operating Performance

Use of FRP construction proved very successful.

Because their large size precluded shipment, the JBR andlimestone 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 gasprescrubber to remove chlorides was eliminated. Similarly, the FRP-constructed chimney proved resistant tothe corrosive condensates in wet flue gas, precluding theneed for flue gas reheat.

Availability of the CT-121 scrubber during the low

ash test phase was 97%. Availability dropped to 95%under the elevated ash loading conditions due largely tosparger tube plugging problems, precipitated by fly ash

agglomeration on the sparger tubewalls during high ash loading whenthe ESP was deenergized. The highreliability demonstrated verified thata spare JBR is not required in acommercial design offering.Environmental Performance

Exhibit 2-10 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 utilizationremained above 97% throughout the demonstration.Long-term particulate capture performance was testedwith a partially deenergized ESP (approximately 90%efficiency), and is summarized in Exhibit 2-11.

Analysis indicated that a large percentage of the

outlet particulate matter is sulfate, likely a result of acidmist and gypsum carryover. This reduces the estimate ofash mass loading at the outlet to approximately 70% ofthe measured outlet particulates.

For particulate sizes greater than 10 microns, capture

efficiency was consistently greater than 99%. In the 1

–10

micron range, capture efficiency was over 90%. Between0.5 and 1 micron, the particulate removal dropped attimes to negligible values, possibly due to acid mist carryover entraining particulates in this size range. Below0.5 micron, the capture efficiency increased to over 90%.
Project Fact Sheets 2-27

Exhibit 2-12

CT-121 Air Toxics Removal

(JBR Components Only)

0

20406080

100

Chloride Fluoride Arsenic Cadmium Mercury Selenium Vanadium

Removal Efficiency, %

Exhibit 2-11

ulate Capture Performance

 Marginally Operating)

r Inlet Mass Outlet Mass Removal

Loading Loading* Efficiency

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

1.288 0.02 97.7

1.392 0.010 99.3

0.325 0.005 98.50.303 0.006 98.0

or units constructed after September 18, 1978. Plant Yates

an existing unit.

cross the CT-121 JBR,

n during the demonstra

ypsum stacking method

. Although chloride

stack due to the closed

concentrations often

ater the chloride concen

 less than 50 ppm, suit

pplications. The reduc

buted to rainwater wash

t Yates CT-121 project

which includes equip

 The annual fixed O&M

 Variable operating

moved (1994$), depend

the need for prescrubbing

em availability eliminates

ule. Particulate removal

capability precludes the needfor expensive (capital-intensive) ESP upgrades to meetincreasingly strict environmental regulations.Commercial Applications

Involvement of Southern

Company (which ownsSouthern Company Services,Inc.), with more than 20,000MWe of coal-fired generatingcapacity, is expected to enhance confidence in the CT121 process among otherlarge high-sulfur coal boilerusers. This process will beapplicable to 370,000 MWe

of new and existing generating capacity by the year 2010.A 90% reduction in SO2 emissions from only the retrofit

portion of this capacity represents more than 10,500,000tons/yr of potential SO2 control.

Plant Yates continues to operate with

the CT-121 scrubber as an integral part ofthe site’s CAAA compliance strategy.Since the CCT Program demonstration, over8,200 MWe equivalent of CT-121 AFGDcapacity has been sold to 16 customers inseven countries.

The project received Power

magazine’s 1994 Powerplant Award.Other awards include the Georgia Chapterof the Air and Waste ManagementAssociation’s 1994 Outstanding Achievement Award, the Georgia Chamber of

Commerce’s 1993 Air Quality Citizen of

the Year award, and the Composites Institute (Society of Plastics Industries) 1996Design Award of Excellence.

ContactsDavid P. Burford, Project Manager, (205) 992-6329

Southern Company42 Inverness Parkway, Suite 340Birmingham, AL 35242(205) 992-7535 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, DOE/NETL, (412) 386-5991References• Southern Company Services, Inc. Demonstration of

Innovative Applications of Technology for Cost Reductions to the CT-121 FGD Process. Final Report.Volumes 1-6. January 1997.

• Comprehensive Report to Congress on the Clean

Coal Technology Program: Demonstration of Innovative Applications of Technology for the CT-121FGD Process. Southern Company Services, Inc.Report No. DOE/FE-0158. U.S. Department ofEnergy. February 1990. (Available from NTIS asDE9008110.)
Environmental Control Devices
Project Fact Sheets 2-29

nvironmental Control Devices

NO

x Control Technologies
Environmental Control Devices

Advanced

iques for a

SCS)

EPRI)—cofunder

n (Foster Wheeler)—

ustry—cofunder

ty—technology sup

 Power Company’s

LNB) with advanced

neric NOx Control

puter software.

fur

900 100%

526 41

374 59

Project Objective

To achieve 50% NO

x

 reduction with the LNB/

AOFA system; to determine the contributions of AOFAand LNB to NO

x reduction and the parameters for optimal LNB/AOFA performance; and to assess the longterm effects of LNB, AOFA, combined LNB/AOFA, and

the GNOCIS advanced digital controls on NOx reduction, boiler performance, and peripheral equipment performance. The project has been reopened and extended

to demonstrate an overall unit optimization system.

Technology/Project DescriptionAOFA involves: (1) improving OFA mixing to

enable operation 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 Controlled Flow/Split Flame

(CFSF) LNB, fuel and air mixing is staged by regulatingthe primary air/fuel mixture, velocities, and turbulence tocreate a fuel-rich core with sufficient air to sustain combustion at a severely sub-stoichiometric air/fuel ratio.The burner also controls the rate at which additional air,necessary to complete combustion, is mixed with theflame solids and gases so as to maintain a deficiency ofoxygen until the remaining combustibles fall below thepeak NOx producing temperature (around 2,800 °F). The

final excess air then can be allowed to mix with theunburned products so that combustion is completed at arelatively low temperature. The CFSF LNB splits thecoal/air mixture into four streams, which minimizes coaland air mixing and combustion staging.

AIR

WINDBOX WINDBOX

BOILER

ECONOMIZER

ADVANCED

OVERFIRE AIR

PORTS

COMBUSTION

AIR

PULVERIZED

COAL

LOW-NO

BURNERS

X

ASH

BOUNDARY AIR PORTS

LOW-NO

BURNERS

X

DRY WASTE TO DISPOSAL

PULVERIZED

COAL

AOFA

PORTS

AIR

AIR

PREHEATER STACK

ELECTROSTATIC

PRECIPITATOR
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

**Years omitted

1 2

Program Update 1999 2-31

1990 1991 1992 1993 1994 1996 1998 1999 2001

6/90

Design and Construction

erative agreement awarded 12/20/89

Design completed 3/90

Construction started, AOFA 4/90

Construction completed, AOFA 5/90

Operation initiated, AOFA 6/90

Environmental monitoring plan completed 9/14/90

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

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

Operation completed, LNB 1/92

Operation initiated, LNB/AOFA 5/93

Operation and Reporting

Operation completed, LNB/AOFA 8/93

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

NOx emissions were

a 48% reduction from

06 Btu).

 NOx emissions were

a 24% reduction from

m NOx emissions were

a 68% reduction from

howed no evidence of

resulting from the com

d for NO

x

 control. Trace

ercury and selenium,

ctrostatic precipitator

Operational• AOFA accounted for an incremental NO

x

 reduction

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

• GNOCIS achieved a boiler efficiency gain of 0.5

percentage points, a reduction in fly ash loss-on-ignition (LOI) levels of 1–3 percentage points, and a reduction in NO

x

 emissions of 10–15% at full load.

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

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

1 2

Final report

(Phase 1-3B)

issued 1/98

**

GNOCIS testinginitiated 2/96

Final report(Phase 4)issued 9/98

Project completed/

final report issued 3/01*

3/01

**

Cooperative agreement

resigned 9/15/99

**

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

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

• Estimated cost of NO

x removal is $79/ton using

LNB/AOFA in a base load dispatch scenario experienced at Plant Hammond.
Environmental Control Devices

Exhibit 2-15

Typical Trade-Offs in Boiler Optimization

Increase Excess O2

Open Outer Reg.

Arrow indicates direction of increasingoperating parameter or burner adjustment

Extend Tip

More Fuel to Open Upper Mills Inner Reg. Sliding Tip Mill Bias Inner Register

Excess O2

Outer Register

LOI (Percent)

NOx (lb/MBtu)

Exhibit 2-14

NOx vs. LOI Tests—All Sensitivities

t 2-13

e Test Results

acterization of the unit

August 1989 to April

ted from August 1990

ation of the LNBs in

NBs were tested from

ding a three-month

ed capacity. Post-LNB

th increases in combus

oading to the electro

y affected the unit’s

LNB/AOFA testing

2 to August 1993, ex

 outage and for por

essive particulate emis

e gas conditioning

P performance, which

load, and allowed

 LNB, and LNB/

it 2-13, despite im

e replacement of the

mills. Increased LOI was a concern not onlybecause of the associated efficiency loss, butalso due to a potential loss of fly ash sales.The increased carbon in the fly ash rendersthe material unsuitable for use in makingconcrete.

During October 1992, SCS conducted

parametric testing to determine the relationship between NOx and LOI emissions. The

parameters tested were: excess oxygen, millcoal flow bias, burner sliding tip position,burner outer register position, and burnerinner register position. Nitrogen oxide emissions and LOI levels varied from 0.44–0.57lb/106 Btu and 3–10%, respectively. As

expected, excess oxygen levels had considerable effect on both NOx and LOI. The results showed

that there is some flexibility in selecting the 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. Thiscan be more clearly seen in Exhibit 2-14 in which allsensitivities are plotted. This exhibit shows that, for

excess oxygen, mill bias, inner register, andsliding tip, any adjustments to reduce NOx emissions are at the expense of increased fly ash LOI.

In contrast, the slope of the outer register adjustment suggests that improvement in both NOx emissions

and LOI can be achieved byadjustment of this damper.However, due to the relatively small impact of theouter register adjustment onboth NOx and LOI, it is

likely the positive NOx/LOI

slope is an artifact of process noise.

A subsidiary goal of the project was to evaluate

advanced instrumentation and controls (I&C) as appliedto combustion control. The need for more sophisticatedI&C equipment is illustrated in Exhibit 2-15. There aretrade-offs in boiler operation, e.g., as excess air increases, NOx increases, LOI decreases, and boiler losses

increase. The goal is to find and maintain an optimaloperating condition. The I&C systems tested includedGNOCIS and carbon-in-ash analyzers.

The GNOCIS software applies an optimizing procedure to identify the best set points for the plant, which are

Baseline

LNB

LNB

+AOFA

+Other

AOFA

Load, MW

LOI, Percent

100 200 300 400 500 600

02

4

6

8

10

12
Project Fact Sheets 2-33

2-16

 of GNOCIS

out operator intervention

 plant operators for

e major elements of

-16. The GNOCIS sys

d NOx emissions by 10–

g the heat rate or reduc

age points.

e

hat the AOFA, LNBs,

d NOx reductions of 24,

ough the long-term LNB/

% reduction from base

of the incremental

n the LNB and the LNB/

lt of operational changes

OFA.

 phase a total of 63 days

s data was collected.

ad, long-term NOx emis

h was consistent with

er long-term testing had

4 lb/106 Btu for AOFA

B only, respectively.

Chemical emissions testing showed no evidence of

organic compound emissions resulting from the combustion modifications installed for NOx control. Trace element control, except for mercury and selenium, proved to

be a function of electrostatic precipitator (ESP) performance. Only a small portion of the mercury and selenium, which adopt a vapor phase, and none of the vaporphase chlorine (as hydrochloric acid) and fluorine (ashydrofluoric acid) were captured.Economic Performance

Estimated capital costs for a commercial 500-MWe

wall-fired installation are: AOFA—$8.8/kW, LNB—$10.0/kW, LNB/AOFA—$18.8/kW, and GNOCIS—$0.5/kW. Annual O&M costs and NOx reductions depend on the assumed load profile. Based on the actual

load profile observed in the testing, the estimated annual

O&M cost increase 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 ofNO

x removed is $79/ton for the Hammond base load

dispatch scenario.

The addition of GNOCIS to the LNB/AOFA, using

the actual load profile observed in the testing, results in arange of costs depending on whether the unit is operatedto maximize NOx removal efficiency, or LOI. For the

maximum NOx removal case, the efficiency is improved

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

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

due to increased efficiency).Project Extension

On September 15, 1999, the cooperative agreement

was extended and work began on the design and installation of an overall unit optimization system. The workwill be carried out as part of Phase 4 of the project. Theoverall goal of Phase 4 is to demonstrate on-line optimization techniques for power plant processes and for the unit as a whole. The major tasks include unit optimiza- tion, boiler optimization, automated sootblowing, and precipitator modeling/optimization. To date, the total plant optimization study is complete and the designs for the optimization packages are in progress. The real-time heat rate monitor is being tested by the participant. Commercial Applications The technology is applicable to the 411 existing pre- NSPS dry-bottom wall-fired boilers in the United States, which burn a variety of coals. The GNOCIS technology is applicable to all fossil fuel-fired boilers, including units fired with natural gas and units cofiring coal and natural gas. The host has retained the technologies for commer- cial use. Foster Wheeler has equipped 86 boilers with low-NOx burner technology (51 domestic and 35 interna- tional)—1,800 burners for over 30,000 MWe capacity. Contacts John N. Sorge, (205) 257-7426 Research Engineer Southern Company Services, Inc. P.O. Box 2641 Birmingham, AL 35291-8195 jnsorge@southernco.com Lawrence Saroff, DOE/HQ, (301) 903-9483 James R. Longanbach, NETL, (304) 285-4659 References

• 500-MW Demonstration of Advanced Wall-Fired

Combustion Techniques for the Reduction of Nitrogen Oxide (NOx) Emissions from Coal-Fired Boilers.

Phase 4—Digital Control System and Optimization.Southern Company Services, Inc. September 1998.

• 500-MW Demonstration of Advanced Wall-Fired

Combustion Techniques for the Reduction of Nitrogen Oxide (NOx) Emissions from Coal-Fired Boilers.

Phases 1-3B, Final Report. Southern CompanyServices, Inc. January 1998.
Environmental Control Devices

Coal

lone Boiler

any—cofunder and

coal handling

—cofunder

ergy and Natural

ler operators)—

onsin Power and Light

 Unit No. 2)

s Coal Reburning Sys

1.15% sulfur,

minous, 0.27% sulfur,

609 100%

788 46

821 54

Project Objective

To demonstrate the technical and economic feasibility of Coal Reburning to achieve greater than 50% reduction in NO

x emissions with no serious impact on cyclone

combustor operation, boiler performance, or other emission streams.Technology/Project Description

Babcock & Wilcox Coal Reburning reduces NOx in

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

x formed in the cyclone burners reacts

with the resultant reducing flue gas and is converted intonitrogen in this zone. Completion of the combustionprocess occurs in the third zone, called the burnout zone,where the balance of the combustion air is introduced.

Coal Reburning can be applied with the cyclone

burners operating within their normal, noncorrosive,oxidizing conditions, thereby minimizing any adverseeffects of reburning on the cyclone combustor and boilerperformance.

This project involved retrofitting an existing

100-MWe cyclone boiler that is representative of a largepopulation of cyclone units.

COAL REBURNINGBURNERS
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 2-35

ater than 50% NOx reduc

ituminous and PRB sub

y had the greatest effect

maintaining reburning

viding necessary burner

d mixing.

ic precipitator (ESP)

d by Coal Reburning with

 input was 29–30% at full

oderate 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 efficiency loss ranged from zero at full load to 0.3 percentage points at 60-MWe.

• Superior flame stability was realized with PRB coal,

contributing to better NOx control than with Lamar coal.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction

nt

90

4/90 12/91

Operation and Reporting

3/94

Project completed/final report issued 3/94

Operationcompleted 12/92 Operation initiated 12/91

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

• 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-year busbar power costs for a

110-MWe plant were 2.4 and 2.3 mills/kWh, respectively (constant 1990$).

• Levelized 10- and 30-year busbar power costs for a

605-MWe plant were 1.6 and 1.5 mills/kWh, respectively (constant 1990$).
Environmental Control Devices

Boiler Load

110 MWe 82 MWe 60 MWe

0.39/52 0.36/50 0.44/36

0.1 0.25 1.5

0.34/55 0.31/52 0.30/53

0.0 0.2 0.3

hibit 2-17

rn Test Results

Wisconsin Power and Light Company’s Nelson Dewey

Station hosted the successful demonstration of Coal Reburn.

resent only 8.5% of the

pacity, they contribute

PS coal-fired units.

tor’s inherent turbulent,

ess. However, at the

was no cost-effective

 for cyclone boiler NOx

urning offers an eco

ponse to the environ

logy avoids cyclone

iated performance

ernative to

ns, such as SCR, which

 operating costs.

as performed firing

mar), because it is

tilities operating cy

tests were performed to

ng on reburning opera

s strategy to meet

Wisconsin’s sulfur emission limitations as of January 1,1993, was to fire low-sulfur coal.Environmental Performance

Three sequential tests of Coal Reburning used Lamar

coal. 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 2-17 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

coals indicated that variation of reburning-zone stoichiometry was the most critical factor in changing NOx

emissions levels. The reburning-zone stoichiometry canbe varied by alternating the air flow quantities (oxygenavailability) to the reburning burners, the percent reburning heat input, the gas recirculation flow rate, or thecyclone stoichiometry.

Hazardous air pollutant (HAP) testing was performed using Lamar test coal. HAP emissions were

generally well within expected levels,and emissions with Coal Reburningwere comparable to baseline operation.No major effect of reburning on tracemetals partitioning was discernible.None of the 16 targeted polynucleararomatic semi-volatile organics (controlled under Title III of CAAA) werepresent in detectable concentrations, ata detection limit of 1.2 parts per billion.Operational Performance

For Lamar coal, the full-, medium-,

and low-load efficiency losses due tounburned carbon were higher than thebaseline by 0.1, 0.25, and 1.5 percentage points, respectively. Full-, medium-, and low-load efficiency losses with PRB coal were 0.0, 0.2, and 0.3 percentage points, respectively. Coal Reburning burner flame stability improved with PRB coal. During Coal Reburning operation with Lamar coal, the operators continually monitored boiler internals for increased ash deposition and the on-line performance monitoring system for heat transfer changes. At no time throughout the system optimization or long-term opera- tion period were any slagging or fouling problems ob- served. In fact, during scheduled outages, internal boiler inspections revealed that boiler cleanliness had actually improved. Extensive ultrasonic thickness measurements were taken of the furnace wall tubes. No observable decrease in wall tube thickness was measured. Another significant finding was that Coal Reburning minimizes and possibly eliminates a 0–25% derating normally associated with switching to subbituminous coal in a cyclone unit. This derating results from using a lower Btu fuel in a cyclone combustor, which has a lim- ited coal feed capacity. Coal Reburning transferred about 30% of the coal feed out of the cyclone to the reburning burners, bringing the cyclone feed rate down to a man-
Project Fact Sheets 2-37

Babcock & Wilcox Coal

retained by Wisconsin

 control at the Nelson

Exhibit 2-18

Coal Reburn Economics

(1990 Constant Dollars)

Plant Size

Costs 110 MWe 605 MWeTotal capital cost ($/kW) 66 43Levelized busbar powercost (mills/kWh)

10-year life 2.4 1.630-year life 2.3 1.5

Annualized cost ($/ton of NOx removed)

10-year life 1,075 40830-year life 692 263

full-load heat input to the

al capital and levelized

cted using the “Electric

mic Premises” for retrofit

addition, annualized

ere developed for 110-

0 and 30 years. The

wn in Exhibit 2-18.

rofit conditions and did

not take into account any fuel savings from use of lowrank coal. The pulverizers and associated coal handlingwere taken into account. Site-specific parameters that cansignificantly impact these retrofit costs included the stateof the existing control system, availability of flue gasrecirculation, space for coal pulverizers, space for reburnburners and overfire air ports within the boiler, scope ofcoal-handling modification, sootblowing capacity, ESPcapacity, steam temperature control capacity, and boilercirculation considerations.Commercial Applications

Coal Reburning is a retrofit technology applicable to

a wide 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 Wisconsin Power and Light for commercial use.

ContactsDot K. Johnson, (330) 829-7395

McDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601(330) 821-7801 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483John C. McDowell, NETL, (412) 386-6175References• Demonstration of Coal Reburning for Cyclone Boiler

NO

x

 Control: Final Project Report. Report No. DOE/

PC/89659-T16. The Babcock & Wilcox Company.February 1994. (Available from NTIS as DE94013052,Appendix 1 as DE94013053, Appendix 2 asDE94013054.)

• Public Design Report: Coal Reburning for Cyclone

Boiler NO

x

 Control. The Babcock & Wilcox Company.

August 1991. (Available from NTIS as DE92012554.)

• Comprehensive Report to Congress on the Clean Coal

Program: Demonstration of Coal Reburning for Cyclone Boiler NO

x

 Control. Report No. DOE/FE-0157.

U.S. Department of Energy. February 1990. (Availablefrom NTIS as DE90008111.)
Environmental Control Devices

stration of

ner Retrofit

mpany—cofunder and

—cofunder

cofunder

under

ofunder

der

ofunder

yton Power and Light

No. 4)

s low-NOx cell-burner

392 100%

800 48

592 52

cally required for complete combustion through the lowerburner and the balance of the air through the secondaryair port (NOx port).

The demonstration was conducted on a Babcock &

Wilcox-designed, supercritical once-through boilerequipped with an electrostatic precipitator (ESP). Thisunit, which is typical of cell-burner boilers, contained 24two-nozzle cell burners arranged in an opposed-firingconfiguration. Twelve burners (arranged in two rows ofsix burners each) were mounted on each of two opposingwalls of the boiler. All 24 standard cell burners wereremoved and 24 new LNCBs® were installed. Alternate

LNCBs® on the bottom rows were inverted, with the air

port then being on the bottom to ensure complete combustion in the lower furnace.

Project Objective

To demonstrate, through the first commercial-scale

full burner retrofit, the cost-effective reduction of NOx

from a large baseload coal-fired utility boiler withLNCB® technology; to achieve at least a 50% NOx reduction without degradation of boiler performance at less

cost than that of conventional low-NO

x

 burners.

Technology/Project Description

The LNCB® technology replaces the upper coal

nozzle of the standard two-nozzle cell burner with asecondary air port. The lower burner coal nozzle is enlarged to the same fuel input capacity as the two standardcoal nozzles. The LNCB® operates on the principle of

staged combustion to reduce NOx emissions. Combustion

is staged by providing only about 58% of the air theoreti

bcock & Wilcox Company.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 2-39

ng (all mills in service)

 range of 53.0–55.5%,

 at loads of 605 MWe,

spectively.

 (all mills in service)

ction of 58% (over

 (one mill out of service)

ction of 60% (over

sions averaged 28–55

 in service.

rformance remained

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

was offset by a decrease in dry gas loss due 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 NOx emission rate and 65% capacity factor, was $9/kW (1994$).

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

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

x removed (constant 1994$).

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operationinitiated 12/91

10/90

Operation and Reporting

Design and

reaward Construction

12/91

 8/10/90

Project completed/final report issued 12/95

12/95

Operation completed 4/93

Construction completed 11/91Preoperational tests initiated 11/91

e agreement

ed 10/11/90

pleted 10/90

Environmental monitoring plancompleted 8/9/91

Ground breaking/construction started 9/91
Environmental Control Devices

cell burners currently

4,000-MWe of pre

ty. Cell burners are

and air. The tight

minimize flame size

 rate and unit effi

good, but the rapid heat

uantities of NOx

.

 LNCB® has been

nd combustion air. A

shing delayed fuel-air

oiler walls. The plug

 costs and outage time

ompared to installing

w-NOx burners, thereby

to address NOx reduc

ion resulted in exces

ugh modeling, a revised

rting alternate burners

ed the problem without

 The modification

es.

to establish optimal

ization tests were con

vironmental and opera

measurements were

and the other by an

data accuracy. Conse

ge reflecting the two

eduction achieved at

anged from 53.0–

ce at full load, the

m 53.3–54.5%. Aver

load (about 460 MWe)

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

NOx emissions were monitored over the long-term at full

load for all mills in service and one mill out of service.Each test spanned an 8-month period. The NOx emission

reductions realized were 58% for all mills in service andabout 60% for one mill out of service.

Complications arose in assessing CO emissions

relative to baseline because baseline calibration was notsufficiently refined. However, accurate measurementswere made with LNCB® in service. Carbon monoxide

emissions were corrected for 3.0% O2 and measured at

full, intermediate, and low loads. The range of CO emissions at full load with all mills in service was 28–55 ppm,and 20–38 ppm with one mill out of service. At intermediate loads (about 460 MWe), CO emissions were 28–45ppm, and at low loads (about 350 MWe), 5–27 ppm.

Particulate emissions were minimally impacted. The

LNCB® had little effect on fly ash resistivity, largely due

to SO3 injection, and therefore ESP removal efficiency

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

99.43%, 99.12%, and 99.35%, respectively.Operational Performance

Furnace exit gas temperature, initially decreased by

100 oF, but eventually rose to within 10 oF of baselineconditions. The UBCL increased by approximately 28%for all tests. The most significant increase from baselinedata occurred for a test with one mill out of service. A52% increase in UBCL resulted in an efficiency loss of0.69%.

Boiler efficiency showed very little change from

baseline. The average for all mills in service increased by0.16%. The higher post-retrofit efficiency was attributed

to a decrease in dry gas loss with lower economizer gasoutlet temperature (and subsequent lower air heater gasoutlet temperature), offsetting UBCL and CO emissionlosses. Also, increased coal fineness mitigated UBCL.

Because sulfidation is the primary corrosion mechanism in substoichiometric combustion of sulfur-containing coal, H2S levels were monitored in the boiler. After

optimizing LNCB® operation, levels were largely at the

lower detection limit. There were some higher localreadings, but corrosion panel tests established that corrosion rates with LNCB® were roughly equivalent to preretrofit rates.

Ash sample analyses indicated that ash deposition

would not be a problem. The LNCB® ash differed little

from baseline ash. Furthermore, the small variationsobserved in furnace exit gas temperature between baseSingle LNCB® Retrofit.
Project Fact Sheets 2-41

tal cost was $9/kW (1994$). The 15-yearlevelized cost of electricity was estimated at0.284 mills/kWh, or $96.48/ton of NOxremoved in constant 1994 dollars.Commercial Applications

The low cost and short outage time for

retrofit make the LNCB® design the most

cost-effective NO

x control technology available today for cell-burner boilers. The

LNCB® system can be installed at about halfthe cost and time of other commercial lowNO

x

 burners.

Dayton Power & Light has retained the

LNCB® for use in commercial service.

Seven commercial contracts have beenawarded for 172 burners, valued at $24million. LNCBs® have already been installed on more

than 4,900 MWe of capacity.

The demonstration project received R&D magazine’s

1994 R&D Award.ContactsDot K. Johnson, (330) 829-7395

McDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601(330) 821-7801 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• Final Report: Full-Scale Demonstration of Low-NOx

CellTM Burner Retrofit. Report No. DOE/PC/90545-T2. The Babcock & Wilcox Company Research andDevelopment Division. December 1995. (Availablefrom NTIS as DE96003766.)

• Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit: Public Design Report. Report No. DOE/PC/90545-T4. The Babcock & Wilcox Company Energy

The connections to the LNCB® are viewed from outside the boiler.

hange in furnace slag

he unit were unaffected

e performed for a 600-

cal location in the

m-sulfur, medium-vola

as the typical fuel. For a

.2 lb/106 Btu, 65% capac

arget, the estimated capi

within the boiler. Services Division. August 1991. (Available from NTIS as DE92009768.) • Comprehensive Report to Congress on the Clean Coal Technology Program: Full-Scale Demonstration of Low-NOx Cell Burner Retrofit. The Babcock & Wil- cox Company. Report No. DOE/FE-0197P. U.S. Department of Energy. July 1990. (Available from NTIS as DE90018026.)
Environmental Control Devices

Reburning

ers on a

h Corporation

ado—cofunder and host

—cofunder

—cofunder

chnology supplier

c Service Company of

No. 3)

h Corporation’s gas

Wheeler Energy Corp.’s

, 10% ash

258 100%

790 50

468 50

e in NOx emissions from

 firing low-sulfur coal

NOx burners (GR-LNB);

B on boiler performance.

70%. Gas reburning was demonstrated with and withoutthe use of recirculated flue gas.

A series of parametric tests was performed on the gas

reburning system, varying operational control parametersand assessing the effect on boiler emissions, completeness of combustion (carbon-in-ash or loss-on-ignition),thermal efficiency, and heat rate. A one-year long-termtesting program was performed in order to judge theconsistency of system outputs, assess the impact of longterm operation on the boiler equipment, gain experiencein operating GR-LNB in a normal load-following environment, and develop a database for use in subsequentGR-LNB applications. Both first- and second-generationgas reburning tests were performed.

Technology/Project Description

Gas reburning involves injecting natural gas (up to

25% of total heat input) above the main coal combustionzone in a boiler. This upper-level injection and partialcombustion by limiting available oxygen creates a fuelrich zone. NO

x moving upward from coal combustion in

the lower furnace is stripped of oxygen as the reburn fuelis partially combusted in the reburn zone and converted tomolecular nitrogen. Overfire air ports above the reburnzone provide for complete combustion in a relativelycooler region of the boiler. Reburning allows the lowNO

x burners to operate at excess air levels far below that

needed for complete combustion, thus enhancing theireffectiveness. The synergistic effect of adding a reburning stage to wall-fired boilers equipped with low-NOx

burners was intended to lower NO

x emissions by up to
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

**Years omitted

1 2

Program Update 1999 2-43

sions from a pre-con

06 Btu to 0.46 lb/106 Btu

uction.

ncorporated flue gas

with LNB, reduced NOx

lb/106 Btu (at 3.25% O2),

% gas heat input rate.

ut flue gas recirculation

, reduced NOx emissions

 a 64% NOx reduction

ut.

tion GR with LNB were

sions by up to 70%

average was approxi

1990 1991 1992 1993 1994 1995 1996 1998 1999

eaward Operation and Reporting

Design and Construction

10/90 11/92

 selected project (CCT-III) 12/19/89

Environmental monitoring plan completed 7/26/90

NEPA process completed (MTF) 9/6/90

Cooperative agreement awarded 10/13/90

Ground breaking/construction started 6/91

Design completed 8/91

Constructioncompleted 11/92Operation initiated 11/92

• After modifying the overfire air system to enhance

penetration and turbulence (as part of second-generation GR), CO emissions were controlled to acceptablelevels at low gas heat input rates.

• SO2 emissions and particulate loadings were reduced

by the percentage heat input supplied by GR.

Operational• Boiler efficiency decreased < 1.0%.

• There was no measurable boiler tube wear and only a

small amount of slagging.

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

alone.

Long-term operations started 4/93

Operation completed 1/95

Restorationcompleted 11/95

10/98

Project completed/final

report issued 10/98

**

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

is $26.01/kW (1996$) plus the gas pipeline cost, if notalready existing ($12.14/kW for GR only and $13.87/kW for LNB only).

• Operating costs were related to the gas/coal cost differential and the value of SO2 emission allowances because

GR reduces SO2 emissions when displacing coal.
Environmental Control Devices

GR GenerationFirst Second

Baseline (lb/106 Btu) 0.73 0.73

Avg NOx reduction (%)

LNB 37 44GR-LNB 66 64

Avg gas heat input (%) 18 12.5

Exhibit 2-19

NO

x

 Data from Cherokee

Station, Unit No. 3

ring for the Foster

n the boiler wall.

d that GR-LNB offers a

 reductions on wall

ol performance ap

 reduction (SCR), but

mportance of cost

 reductions is that it

in ozone nonattainment

jected in Title IV of the

s with ozone

 driving force for deep

the country.

nd evaluated on a 172-

Babcock & Wilcox

balanced-draft pulverized coal-fired unit. The GR system, including an overfire air system, was designed andinstalled by Energy and Environmental Research Corporation. The LNBs were designed and installed by FosterWheeler Energy Corp.

Parametric testing began in October 1992 and was

completed in April 1993. The parametric tests examinedthe effect of process variables (such as zone stoichiometric ratio, 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 Performance

At a constant load (150 MWe) and a constant oxygen level at the boiler exit, NOx emissions were reduced

with increasing gas heat input. At gas heat inputs greaterthan 10%, NOx emissions were reduced marginally as gas

heat input increased. Natural gas also reduced SO2 emissions in proportion to the gas heat input. At the 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 testwere to obtain operating data over an extended periodwhen the unit was under routine commercial service,determine the effect of GR-LNB operation on the unit,and obtain incremental maintenance and operating costswith GR. During long-term testing, it was determinedthat flue gas recirculation had minimal effect on NOxemissions.

 A second series of tests was added to the demonstration to evaluate a modified or second-generation system.

Modifications included the following:

• The flue gas recirculation system, originally designed to

provide momentum to the natural gas, was removed.(This change significantly reduced capital costs.)

• Natural gas injection was optimized at 10% gas heat

input compared to the initial design value of 18%.Removal of the flue gas recirculation system requiredinstallation of high-velocity injectors, which madegreater use of available natural gas pressure. (Thismodification reduced natural gas usage and thus operating costs.)

• Overfire air ports were modified to provide higher jet

momentum, particularly at low total flows.

Over 4,000 hours of operation were achieved, with

the results shown in Exhibit 2-19. Although the 37%NO

x reduction performance of LNB was less than the

expected 45%, the overall objectives of the demonstrationwere met. Boiler efficiency decreased by only 1% duringgas reburning due to increased moisture in the fuel resulting from natural gas use. Further, there was no measurable tube wear, and only small amounts of slagging occurred during the GR-LNB demonstration. However,with LNB alone, carbon-in-ash and CO could not bemaintained at acceptable levels.
Project Fact Sheets 2-45

logy in which the eco

 the following site-spe

d

.

 GR-LNB is expected to

ction with a gas heat

 estimate for a 300-MWe

kW (1996$), plus gas

cost includes both equip

 15% contingency. The

s can be easily separated

re independent systems.

m only is estimated at

pital cost is $13.87/kW.

ntirely related to the

d coal and reduced by

edits received due to

uel differential of $1.00/

sts more than coal on a

ency was estimated to

s decline was calculated

.67/106 Btu. Overfire air

 loads will be partially

erizers. No additional

here is an increase in

also were made for over

d on these assumptions

wance of $95/ton (Feb.

$2.14 million per year

6/ton (constant 1996$).

Commercial Applications

The technology can be used in retrofit, repowering,

or greenfield installations of wall-fired boilers. There isno known limit to the size or scope of the application ofthis technology combination. GR-LNB is expected to beless capital intensive, or less costly, than selective catalytic reduction. GR-LNB functions equally well with anykind 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, arestoration was required to remove the flue gas recirculation system.

Energy and Environmental Research Corporation has

been awarded two contracts to provide gas-reburningsystems for five cyclone coal-fired boilers: TVA’s AllenUnit No. 1, with options for Unit Nos. 2 and 3 (identical330 MWe units); and Baltimore Gas & Electric’s C.P.Crane, Unit No. 2, with an option for Unit No. 1 (similar200 MWe units). Use of the technology also extends tooverseas markets. One of the first installations of thetechnology took place at the Ladyzkin State Power Station in Ladyzkin, Ukraine.

This demonstration project was one of two that received the Air and Waste Management Association’s

1997 J. Deanne Sensenbaugh Award.ContactsBlair A. Folsom, Sr. V.P., (949) 859-8851, ext. 140

General Electric Energy and Environmental ResearchCorporation18 MasonIrvine CA 92618(949) 859-3194 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483Jerry L. Hebb, NETL, (412) 386-6079

References• Evaluation of Gas Reburning and Low-NOx Burners on

a Wall-Fired Boiler: Performance and EconomicsReport, Gas Reburning—Low-NOx Burner System,

Cherokee Station Unit No. 3, Public Service Companyof 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 and Environmental Research Corporation. June1995. (Available from NTIS as DE95017755.)

• Evaluation of Gas Reburning and Low-NOx Burners on

a Wall-Fired Boiler (Optimization Testing, November1992–April 1993). Report No. DOE/PC/90547-T19.Energy and Environmental Research Corporation. June1995. (Available from NTIS as DE95017754.)
Environmental Control Devices

eburning

 NO

x

 Control

rporation

nd cofunder

n Coal Company)—

plier

ch Corporation

r

and Development

arch Corporation—

New York State Elec

ken Station, Unit No. 1)

Eastman Kodak

 Plant, Unit No. 15)

 Station) and

Kodak) technologies for

ntially fired boiler

er

mpany.

n Engineering, Inc.

CoalPittsburgh seam bituminous, medium- to high-sulfur (3.2%sulfur and 1.5% nitrogen at Milliken and 2.2% sulfur and1.6% nitrogen at Kodak Park)Project FundingTotal project cost $9,096,486 100%DOE 2,701,011 30Participant 6,395,475 70Project Objective

To achieve at least 50% NO

x

 reduction with micronized coal reburning technology on a cyclone boiler; to

achieve 25–35% NO

x

 reduction with micronized coal

reburning technology in conjunction with low-NOx burners

on a tangentially fired boiler; and to determine the effectsof coal micronization on electrostatic precipitator (EPS)performance.

Technology/Project Description

The reburn coal, which can constitute up to 30% of

the total fuel, is micronized (pulverized to achieve 85%below 325 mesh) and injected into a pulverized coal-firedfurnace above the primary combustion zone. At theMilliken tangentially fired boiler site, NOx control is

achieved by: (1) close-coupled overfire air (CCOFA)reburning in which the top coal injector of the LNCFSIIITM burner is used for injecting the micronized coal, andthe separated overfire air system completes combustion;and (2) the remaining burners and air ports are adjusted fordeep stage combustion by re-aiming them to create a fuelrich inner zone and fuel-lean outer zone providing combustion air. At the Kodak Park cyclone boiler site, the FullerMicroMillTM is used to produce the micronized coal,reburn fuel is introduced above the cyclone combustor, andoverfire air is employed to complete the combustion.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 2-47

3/97

1993 1994 1995 1996 1997 1998 1999 2000 2001

Design and Construction Operation and Reporting

12/99

Operation completed (Lansing) 4/99

Operation completed (Rochester) 10/98

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

Design completed (Rochester) 9/96

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

ess completed

92

agreement awarded 7/28/92

Preoperational tests initiated (Rochester) 1/97

Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

Project completed 12/99

Operation initiated (Rochester) 4/97

Environmental monitoring plan completed (Lansing) 8/97Environmental monitoring plan completed (Rochester) 8/97

Construction completed (Lansing) 1/97

Operation initiated (Lansing) 3/97

Project relocated to Lansing and Rochester 12/95

 input on the Milliken

ired) boiler resulted in a

106 Btu, which represents

d above the 39% NO

x

NCFS IIITM burner.

 input on the Kodak Park

Ox emission rate of 0.60

a 59% NOx reduction.

at Milliken Station

lso referred to as loss

intained under 4%,

maximum LOI for mar

– Excess air is the single most important parameter

that affects NO

x emissions;

– Increasing coal fineness only marginally improved

NO

x emissions; and

– Increasing the percent of reburn fuel slightly decreased NO

x, but increased LOI.

• Testing on the cyclone boiler at Kodak Park showed:

– Increasing reburn fuel rates resulted in lower NOx

emissions;

– NO

x

 emission reductions on micronized coal were

comparable to NOx reductions achieved with gas

reburning;

– LOI increased with the reburn system in operation—LOI was 35–45% during full load (compared

to a baseline of 10–12% without reburning); and

– Stoichiometric ratios needed in the primary combustion zone and the reburn zone were 1.05–1.15

and 0.9, respectively.

Economic• The estimated capital cost for retrofitting micronized

coal reburning on a generic 300-MWe tangentiallyfired boiler is $4.3 million, or approximately $14/kW(1999$).

• The estimated O&M costs are $0.30 million per year

(1999$) for a 300 MWe unit.

• The total 15-year levelized cost of micronized coal

reburning is $1,329/ton of NOx removed (current

1999$) or $1,023 (constant 1999$).

Final report issued 10/99
Environmental Control Devices

cronized coal reburning

ed and cyclone-fired

YSEG’s Milliken Sta

T Program demonstra

cyclone-fired boiler was

k Park Power Plant, 50-

reburning demonstra

bustion of the reburn

t-residence-time reburn

hout detrimentally

n the ash, i.e., loss-on

f this two-site project

s in coal reburning for

g the particle size of the

n, the coal was finely

nd injected into the

stion zone. The result

rons compared to 60

al particles. This

a ninefold. With this

neness (micronized coal

s of atomized oil)

in milliseconds and

.

xisting ABB Low-NOx

FS-III), which includes

overfire air (OFA) ports,

tion. Four D.B. Riley

sifiers provided the

 there are four levels of

reburning application,

s fed micronized coal to

is demonstration. The

were biased to carry

uired for full load, with

the top injector supplying the remaining fuel. The speedof the dynamic classifier serving the mill feeding the topburners was increased to produce the micronized coal.

At Kodak Park, EER designed the micronized coal

reburn system using a combination of analytical andempirical techniques. The reburn fuel and OFA injectioncomponents were designed with a high degree of flexibility to allow for field optimization to accommodate thecomplex furnace flow patterns in the cyclone boiler. AFuller MicroMillTM produced the micronized coal reburnfuel with a particle size of about 20 microns. To maximize NO

x reduction, the reburn fuel was injected with

flue gas rather than air. The flue gas was extracted downstream of the electrostatic precipitator and was boosted bya single fan.

Two Fuller MicroMillsTM were installed in parallel on

Kodak Park Unit 15 to provide the capacity necessary forhigh reburn rates, the second mill serving as a spare atlower reburn rates. Eight injectors, six on the rear wall andone on each of the side walls, introduced the micronizedcoal into the reburn zone. The optimization variablesincluded the number of injectors, swirl, and velocity. Fourinjectors on the front wall provided OFA using EER’ssecond-generation, dual-concentric OFA air design, whichhas variable injection velocity and swirl. A new boilercontrol system was also installed on Unit No. 15.

Some mechanical problems were encountered during

the demonstration, including plugging of the coal handling system that feeds the MicroMillTM, vibration andblade wear on the mills, erosion of the classifiers, andcorrosion due to low-temperature flue gas when the reburn system was out of service. These problems werecorrected and successful operation was achieved.Environmental Performance

At the Milliken Station, micronized coal reburning

with 14% reburn fuel reduced NO

x

 from 0.35 lb/106 Btu

baseline level to 0.25 lb/106 Btu, a 28% reduction, which

is within the target range of 25–35% reduction. This

reduction represents an addition to the 39% reductionachieved with the LNCFS IIITM low-NO

x

 burner.

A primary objective at Milliken was to determine the

minimum NO

x level attainable while maintaining marketable fly ash (fly ash having less than 4.5% carbon). Variables studied at Milliken included boiler load, reburn coal

fineness, oxygen level at the economizer, percent reburnfuel, main burner tilt, and OFA tilt. During the testing,NYSEG found that excess air was the single most important parameter that affects NOx emissions. As shown in

Exhibit 2-20, higher excess air results in higher NOx

emissions, but lower LOI. In the case of the top mill(feeding reburning level) adjusted for regular grind (80%through 200 mesh), an increase in measured O2 at the

economizer inlet from 2.5% to 3.75% yields an increasein NO

x

 emissions from 0.36 lb/106 Btu to 0.43 lb/106 Btu,

or about a 20% increase. When the top mill is adjustedfor fine grind (micronized), the NOx emissions are only

marginally better with the same O2 increase. Exhibit 2-20

also shows the dramatic impact of excess air on LOI.When the economizer O2 is varied from 2.5% to 3.5%, the

LOI will drop from 6.2% to 3.8% (39% reduction) for thecase of the top mill adjusted for regular grind. When thesame measurements are made while the top mill is micronizing, the reduction in LOI is less significant.

Results from other parametric testing at Milliken

revealed that increasing coal fineness improved NOx

emissions only marginally, but lowered LOI. Other results showed that increasing the percent reburn fuelslightly decreased NOx, but substantially increased LOI.

At Kodak Park, micronized coal reburning with 17%

reburn fuel reduced NO

x

 emissions to 0.60 lb/106 Btu

from a baseline of 1.45 lb/106 Btu, a 59% reduction. At

greater reburn rates, further NOx reduction was achieved

to a degree comparable with gas reburning systems. Asexpected, LOI increased with the reburn system in operation. At full load LOI was 35–45%, compared to abaseline level of 10–12%.
Project Fact Sheets 2-49

erential cost of gas over

the cost of NOx reduc

en micronized coal is

r, the capital cost of coal

as reburning due to the

 coal milling system and

r retrofitting micronized

-MWe tangentially fired

stimated at $4.3 million

kW. The operating costs

per year (1999$). Costs

were levelized both on a current dollar and constantdollar basis. The 15-year levelized costs for the 300-MWe unit is $1,329/ton of NOx removed on a current

dollar basis, and $1,023/ton of NOx removed on a constant dollar basis.

Commercial Applications

Micronized coal reburning technology can be applied to existing and greenfield cyclone-fired, wall-fired,

and tangentially fired pulverized coal units. The technology reduces NOx emissions by 20–59% with minimal

furnace modifications for existing units.

The availability of a coal-reburning fuel, as an additional fuel to the furnace, enables switching to lower

heating-value coals without boiler derating. Reburnburners also can serve as low-load burners, and commercial units can achieve a turndown of 8:1 on nights andweekends without consuming expensive auxiliary fuel.ContactsJim Harvilla, (607) 762-8630

New York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224(607) 762-8457 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• New York State Electric & Gas Corporation and

CONSOL, Inc. Micronized Coal Reburning Demonstration for NOx Control. Final Report. October 1999.

• Reburning Technologies for the Control of Nitrogen

Oxides from Coal-Fired Boilers. (U.S. Department ofEnergy, Babcock & Wilcox, EER Corp., andNYSEG) Topical Report No. 14. May 1999.

• Savichky et al. “Micronized Coal Reburning Demonstration of NOx Control.” Sixth Clean Coal Technology Conference: Technical Papers. April-May 1998.

2-20

ing Results
Environmental Control Devices

Selective

n

e Control of

m High

Boilers

—cofunder

Gulf Power Company’s

We and six 0.2-MWe

729 100%

673 40

056 60

of commercially avail

to operating conditions

d utility boilers using

us operating conditions,

NOx removal.

Technology/Project Description

The SCR technology consists of injecting ammonia

into boiler flue gas and passing it through a catalyst bedwhere the NO

x and ammonia react to form nitrogen and

water vapor.

In this demonstration project, the SCR facility consisted of three 2.5-MWe equivalent SCR reactors, supplied by separate 5,000-scfm flue gas slipstreams, and six

0.20-MWe equivalent SCR reactors. These reactors werecalculated to be large enough to produce design data thatwill allow the SCR process to be scaled up to commercialsize. Catalyst suppliers (two U.S., two European, andtwo Japanese) provided eight catalysts with variousshapes and chemical compositions for evaluation ofprocess chemistry and economics of operation during thedemonstration.

The project demonstrated, at high- and low-dust

loadings of flue gas, the applicability of SCR technologyto provide a cost-effective means of reducing NOx emissions from power plants burning high-sulfur U.S. coal.

The demonstration plant, which was located at Gulf

Power Company’s Plant Crist near Pensacola, Florida,used flue gas from the burning of 2.7% sulfur coal.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 2-51

were achieved at an

5 ppm deemed accept

n.

d to 150% of design

nia slip design level of 5

ncreased above 700 oF,

the heat rate penalties.

sign of catalyst deactiva

pm to approximately

 hours of operation, thus

n coal-fired units was in

ce.

at SO2 oxidation was

mits necessary to protect

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction Operation and Reporting

6/90

ess

/89

Cooperative agreementawarded 6/14/90

Ground breaking/construction started 3/92

7/93

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

Construction completed 2/93

Design completed 12/92

11/96

Operation initiated 7/93

Operation completed 7/95

Project completed/finalreport issued 11/96

Operational• Fouling of catalysts was controlled by adequate sootblowing procedures.• Long-term testing showed that catalyst erosion was

not a problem.

• Air preheater performance was degraded because of

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

• The SCR process did not significantly affect the

results of Toxicity Characteristic Leaching Procedureanalysis of the fly ash.

Economic• Levelized costs on a 30-year basis for various NOx

removal levels for a 250-MWe unit at a 0.35 lb/106Btu NO

x

 emission rate follow:

40% 60% 80%

Constant 1996$levelized cost(mills/kWh) 2.39 2.57 2.79Constant 1996$levelized cost($/ton) 3,502 2,500 2,036
Environmental Control Devices

Exhibit 2-21

Catalysts Tested

Catalyst Reactor Size* Catalyst

Configuration

Nippon/Shokubai Large HoneycombSiemens AG Large PlateW.R. Grace/Noxeram Large HoneycombW.R. Grace/Synox Small HoneycombHaldor Topsoe Small PlateHitachi/Zosen Small PlateCormetech/High dust Small HoneycombCormetech/Low dust Small Honeycomb* Large = 2.5 MWe; 5,000 scfm Small = 0.2 MWe; 400 scfm

Exhibit 2-22

Average SO2 Oxidation Rate

(Baseline)

Average SO2 Oxidation (%)

NH3/NOx = 0.8, 700 oF, design flow

1.21.00.80.6

0.4

0.2

0

Noxeram

NSKK

Siemens

Synox

Corm. HD

Haldor

Hitachi

Corm. LD

baseline design value

High

AverageLow

 designed to address

tential catalyst deacti

metals species in U.S.

and effects on the bal

sence of high amounts

of the SCR catalyst

l-fired utility operating

e required to design the

mined reactor dimen

catalyst layers, and

e conditions:

m Baseline Maximum

700 750

0.8 1.0

100 150

5,000 7,500

400 600

in Exhibit 2-21. Cata

tude in providing the

tration.

g factor in the long-term

s usually <5 ppm be

siderations. Ammonia

osure time, flow rate,

, and NH3/NOx ratio

/NOx ratio and conse

roduced the most sig

The ammonia slip at

the detection limit of

reased above 80%,

emained at reasonable

%. Over 90%, the am

ically.

e effects on NOx reduc

al, flows could be

increased to 150% of design without the ammonia slipexceeding 5 ppm, at 80% NOx reduction and at the design

temperature. With respect to temperature, most catalystsexhibited fairly significant improvements in overall performance as temperatures increased from 620 °F to700 °F, but relatively little improvement as temperatureincreased from 700 °F to 750 °F. The conclusion wasthat the benefits of high-temperature operation probablydo not outweigh the heat rate penalties involved in operating SCR at the higher temperatures.

Catalyst deactivation was generally observed by an

increase in ammonia slip over time, assuming the NOx

reduction efficiency was held constant. Over the 12,000hours of the demonstration tests, the ammonia slip didincrease from less than 1 ppm to approximately 3 ppm.These results demonstrated the maturity of catalyst designand that deactivation was in line with prior worldwideexperience.

Experience has shown that the catalytic active species that result in NOx reduction often contributed to SO2

oxidation (i.e., SO3 formation), which can be detrimentalto downstream equipment. In general, NOx reduction can

be increased as the tolerance for SO3 is also increased.

The upper bound for SO2 oxidation for the demonstration

catalyst was set at 0.75% at baseline conditions. Theaverage SO2 oxidation rate for each of the catalysts is

shown in Exhibit 2-22. These data reflect baseline conditions over the life of the demonstration. All of the catalysts were within design limits, with most exhibitingoxidation rates below the design limit.

Other factors affecting SO2 oxidations were flow rate

and temperature. Most of the catalysts exhibited fairlyconstant SO2 oxidation with respect to flow rate (i.e.,

space velocity). In theory, SO2 oxidation should be inversely proportional to flow rate. Theoretically, the relationship between SO2 oxidation and temperature should

be exponential as temperature increases; however, measurements showed the relationship to be linear with littledifference in SO2 oxidation between 620 oF and 700 oF.

On the other hand, between 700 °F and 750 °F, the SO2

oxidation increased more significantly.

Other findings from the demonstration deal with

pressure drop, fouling, erosion, air preheater perfor-
Project Fact Sheets 2-53

and toxicity characteristic

ysis. Overall reactor

he catalyst geometry and

ive in determining which

ouling characteristics of

ng-term operation. Dur

ments showed a relatively

dicating that sootblowing

plate-type configurations

tial than did the honey

re acceptable. Catalyst

 a significant problem

attributed to aggressive

preheater performance,

he SCR process exacer

f the air preheaters

subsequent by-product

heaters outperformed

 in terms of both thermal

mmonia volatilized from

nt amount of water was

aused by formation of a

 high enough to convert

o gas-phase ammonia.

on fly ash samples. The

y affect the toxics leach

s performed for full-scale

to a new 250-MWe

d in a rural area with

fuel considered was high

key base case design

3.

apital, operating and

ed cost based on a 30-

sizes for an SCR system

f 60% showed:

125 MWe 250 MWe 700 MWe

Capital cost ($/kW) 61 54 45Operating cost ($) 580,000 1,045,000 2,667,000Constant 1996$ levelized costmills/kWh 2.89 2.57 2.22$/ton 2,811 2,500 2,165

Results of the economic analysis of capital, O&M, and

levelized cost for various NOx removal efficiencies for a

250-MWe unit with 0.35 lb/106 Btu of inlet NOx are:

40% 60% 80%

Capital cost ($/kW) 52 54 57Operating costs ($) 926,000 1,045,000 1,181,000

Constant 1996$ levelized costmills/kWh 2.39 2.57 2.79$/ton 3,502 2,500 2,036

For retrofit applications, the estimated capital costs

were $59–112/kW, depending on the size of the installation and the difficulty and scope of the retrofit. The

levelized costs for the retrofit applications were $1,850–5,100/ton (1996$).Commercial Applications

As a result of this demonstration, SCR technology

has been shown to be applicable to existing and newutility generating capacity for removal of NOx from the

flue gas of virtually any size boiler. There are over1,000 coal-fired utility boilers in active commercial service in the United States; these boilers represent a totalgenerating capacity of approximately 300,000 MWe.ContactsLarry Monroe, (205) 257-7772

Southern Company Services, Inc.P.O. Box 2641Birmingham, AL 35291-8195(205) 257-5367 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• Control of Nitrogen Oxide Emissions: Selective Catalytic Reduction (SCR). Topical Report No. 9. U.S.

Department of Energy and Southern Company Services, Inc. July 1997.

• Maxwell, J. D., et al. “Demonstration of SCR Technology for the Control of NOx Emissions from HighSulfur Coal-Fired Utility Boilers.” Fifth Annual Clean

Coal Technology Conference: Technical Papers,January 1997.

• Demonstration of SCR Technology for the Control of

NOx Emissions from High-Sulfur, Coal-Fired Utility

Boilers: Final Report. Vol. 1. Southern CompanyServices, Inc. October 1996. (Available from NTIS,Vol. 1 as DE97050873, Vol. 2: Appendixes A–N asDE97050874, and Vol. 3: Appendixes O–T asDE97050875.)

Exhibit 2-23

Design Criteria

Parameter SpecificationType of SCR Hot sideNumber of reactors OneReactor configuration 3 catalyst support layersInitial catalyst load 2 of 3 layers loadedRange of operation 35–100% boiler loadNOx inlet concentration 0.35 lb/106 Btu

Design NOx reduction 60%

Design ammonia slip 5 ppmCatalyst life 16,000 hrAmmonia cost $250/tonSCR cost $400/ft3
Environmental Control Devices

tration of

ially Fired

niques for

NOx

oal-Fired

and host

—cofunder

c.—cofunder and

f Power Company’s

ow-NOx Concentric

vanced overfire air

d offset air

665 100%

382 49

283 51

n Engineering, Inc.

in the LNCFSTM II system. This was an advanced overfire air system that incorporates back pressuring and flowmeasurement capabilities. CCOFA and SOFA were bothused in the LNCFSTM III tangential-firing approach.

Carefully controlled short-term tests were conducted

followed by long-term testing under normal load dispatchconditions. Long-term tests, which typically lasted 2–3months for each phase, best represent the true emissionscharacteristics of each technology. Results presented arebased on long-term test data.

Project Objective

To demonstrate in a stepwise fashion the short- and

long-term NOx reduction capabilities of LNCFSTM levels

I, II, and III on a single reference boiler.Technology/Project Description

Technologies demonstrated included LNCFSTM

levels I, II, and III. Each level of the LNCFSTM useddifferent combinations of overfire air and clustered coalnozzle positioning 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 featured
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Program Update 1999 2-55

ns using LNCFSTM I, II,

0.34 lb/106 Btu, respec

tions of 37, 37, and 45%

ere not sensitive to power

nd 200 MWe, but emis

below 100 MWe, reach

at 70 MWe.

ness at low loads,

as a compliance option

ased at full load.

FSTM to have no clear

 trace metals or acid

pounds (VOCs) appeared

ile 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 lowloads with LNCFSTM II and III.

Economic• The capital cost estimate for LNCFSTM I was

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

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

of NO

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

LNCFSTM III, $400/ton (1993$).

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation and Reporting

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

s

TF)

d 9/20/90

5/91
Environmental Control Devices

Exhibit 2-24

LNCFSTM Configurations

signed for tangentially

ge percentage of the

pacity. The technology

combustion in the

jectors, and horizon

 zones with offset air

ermine NOx emission

rformance under nor

ons over the long-term.

onstration provided

nalysis of the three

etric testing enabled

ngentially fired units by

n NOx emissions and

ion, specific NOx emis

lated under the CAAA.

e of this project pro

gulation development.

us LNCFSTM configu

mbustion. In addition to

rates other NOx-reduc

n process as shown in

o concentric circular

he majority of the coal

region. This region is

ntaining combustion

 of combustion air can

ir nozzles.

impacts of LNCFSTM

nd III reduced NOx

pectively. Exhibit 2-27

es obtained in the as

Ox emissions for three

Air toxics testing found LNCFSTM to have no clearcut effect on the emission of trace metals or acid gases.

The data provided marginal evidence for a decreasedemission of chromium. The effect on aldehydes/ketonescould not be assessed because baseline data were compromised. VOCs appeared to be reduced and semi-volatilecompounds increased. The increase in semi-volatilecompounds was deemed to be consistent with increases inthe amount of unburned carbon in the ash.Economic Performance

LNCFSTM II was the only complete retrofit

(LNCFSTM I and III were modifications of LNCFSTM II),and therefore capital cost estimates were based on theLansing Smith Unit No. 2 retrofit as well as other tangentially fired LNCFSTM retrofits. The capital cost ranges in1993 dollars follow:

• LNCFSTM I—$5–15/kW• LNCFSTM II—$15–25/kW• LNCFSTM III—$15–25/kW

Site-specific considerations have a significant effect

on capital costs; however, the above ranges reflect actualexperience and are planning estimates. The actual capitalcost for LNCFSTM II at Lansing Smith Unit No. 2 was $3million, or $17/kW, which falls within the projectedrange.

The cost effectiveness of the LNCFSTM technologies

is based on the capital and operating and maintenancecosts and the NO

x removal efficiency of the technologies.

The cost-effectiveness of the LNCFSTM technologiesfollows (based on a levelization factor of 0.144 in 1993constant dollars):• LNCFSTM I—$103/ton of NOx removed

• LNCFSTM II—$444/ton of NOx removed

• LNCFSTM III—$400/ton of NOx removed

Exhibit 2-25

Concentric Firing Concept
Project Fact Sheets 2-57

Exhibit 2-26

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

lower than baseline lower than baseline

Furnace slagging and Medium Medium Reduced slagging, Reduced slagging,

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

at low loads operate than other

systems

Boiler efficiency (%) 90 90.2 89.7 89.85

Efficiency change (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 2-27

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

otential commercial

U.S. pulverized coal,

These units range from

d fire a wide range of

ous through lignite.

d at the host site for

ion Engineering has

boilers with LNCFSTM

ers, representing over

Inc.

) 903-9483

6-5991

Advanced Tangentially

 for the

(NOx) Emissions from

port and Key Project

C/89653-T14. Southern

uary 1994. (Available

Advanced Tangentially

 for the Reduction of

ons from Coal-Fired

—Phase III and Final

rogram Report. Southern

ember 1993.
Environmental Control Devices
Project Fact Sheets 2-59

nvironmental Control Devices

ned SO2/NOx Control Technologies
Environmental Control Devices

Technology/Project Description

In the SNOXTM process, the stack gas leaving the

boiler is cleaned of fly ash in a high-efficiency fabricfilter baghouse to minimize the cleaning frequency of thesulfuric acid catalyst in the downstream SO2 converter.

The ash-free gas is reheated, and NOx is reacted with

small quantities of ammonia in the first of two catalyticreactors where the NO

x is converted to harmless nitrogen

and water vapor. The SO2 is oxidized to SO3 in a second

catalytic converter. The gas then passes through a novelglass-tube condenser that allows SO3 to hydrolyze to

concentrated sulfuric acid.

Because the SO2 catalyst follows the NOx catalyst,

any unreacted ammonia (slip) is oxidized in the SO2

catalyst largely to nitrogen and water vapor. Downstreamfouling by ammonia compounds is eliminated, permittingoperation at higher than normal stoichiometries. These

higher stoichiometries allow smaller catalyst volumes andhigh reduction efficiencies.

The technology was designed to remove 95% of the

SO2 and more than 90% of the NOx from flue gas, and

produce a salable sulfuric acid by-product using U.S.coals. This was accomplished without using sorbents andwithout creating waste streams.

The demonstration was conducted at Ohio Edison’s

Niles Station in Niles, Ohio. The demonstration unittreated a 35-MWe equivalent slipstream of flue gas fromthe 108-MWe Unit No. 2 boiler, which burned a 3.4%sulfur Ohio coal. The process steps were virtually thesame as for a full-scale commercial plant, and commercial-scale components were installed and operated.

chnology

Cleaning

oject

cofunder

 and host

for process technology,

and process designer

o Edison’s Niles Sta

c advanced flue gas

m a 108-MWe boiler

408 100%

200 50

208 50

hnology at an electric

r coals in which it will

nd more than 90% of

alable by-product of

.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Project Fact Sheets 2-61

• Absence of an alkali reagent contributed to elimination of secondary pollution streams and increases in

CO2 emissions.

• Presence of the SO2 catalyst virtually eliminated CO

and hydrocarbon emissions.

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

function more efficiently.

• Heat developed in the SNOXTM process was used to

enhance thermal efficiency.

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

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

and NO

x

 removed on a constant 1995 dollar basis.

ormally in excess of

averaging about 2,000

for inlet concentrations

y for the high-efficiency

NOXTM system was

 federal specifications for

h capture efficiency of

ghouse. A significant

st all of the mercury

nium and cadmium,

ectively captured in the

mpounds.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation and Reporting

Design and Construction

Operation initiated 3/92

3/92

PA process completed (MTF) 1/31/90

Construction completed 12/91Preoperational tests initiated 12/91

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

Design completed 8/91

Construction started 1/91

7/96

Project completed/final report issued 7/96

Operation completed 12/94
Environmental Control Devices

The bottom portion of the SO2 converter catalyst, with

the catalyst dust collector hopper mounted on steel rails(center), is shown.

he SO2 removal step

zed an oxidation cata

mately to sulfuric acid.

no other waste streams.

valuate the performance

operating data were

ducted to characterize

ystem operated for

oduced more than

ulfuric acid. Many of

were conducted at three

gn capacity.

e process were very low

istics of the SO2 cata

r (WSA Condenser).

d with a baghouse

This was not necessary

rather was needed to

equency for the SO2

, the SO2 catalyst re

entered the catalyst

e. Dust that passed

d in the WSA Con

ng particulate removal

tes as nuclei).

2 emissions by the

—the lack of a carbon

es CO2, and the fact

nal heat from the flue

quirements. Under

covery results in the

g the same or increas

process, and conse

generation.

ocarbons, the SO2 cata

ese 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, and a small amount of NOx. As a result, downstream fouling by ammonia compounds was eliminated,

and the SCR was operated at slightly higher than typicalammonia stoichiometries. These higher stoichiometriesallowed smaller SCR catalyst volumes and permitted theattainment of very high reduction efficiencies. Normaloperating stoichiometries for the SCR system were inthe range of 1.02–1.05, and system reduction efficiencies averaged 94% 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 the oxidation catalyst beds. The efficiency was controlled by twofactors—space velocity and bed temperature. Spacevelocity governed the amount of catalyst necessary atdesign flue gas flow conditions, and gas and bed temperature had to be high enough to activate the SO2 oxidation

reaction. During the test program, SO2 removal efficiency was normally in excess of 95% for inlet concentrations averaging about 2,000 ppm.

Sulfuric acid concentration and composition has met

or exceeded the requirements of the federal specificationsfor Class I acid. During the design and construction ofthe SNOXTM demonstration, arrangements were madewith a sulfuric acid supplier to purchase and distribute theacid from the plant. The acid has been sold to the agriculture industry for production of diammonium phosphate fertilizer and to the steel industry for pickling.Ohio Edison also has used a significant amount in boilerwater demineralizer systems throughout its plants.

Air toxics testing conducted at the Niles SNOXTM

plant measured the following substances:

• Five major and 16 trace elements including mercury,

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

• Acids and corresponding anions (hydrogen chloride,

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

• Ammonia and cyanide;• Elemental carbon;• Radionuclides;• Volatile organic compounds;
Project Fact Sheets 2-63

The SNOXTM demonstration at Ohio Edison’s Niles Station Unit No. 2

achieved SO2 removal efficiencies exceeding 95% and NOx reduction effectiveness

averaging 94%. Ohio Edison is retaining the SNOXTM technology as part of itsenvironmental control system.

luding polynuclear aro

aptured in the baghouse

gnificant portion of the

ury escaped to the stack;

mally a problem, were

rain, as were organic

shed by the SNOXTM

uration, it can be utilized

 The process generated

 All of the reactions that

nd SO2 removal were

mperature of the flue gas.

 heat added in the high

op, was recovered in the

om

on

of the

ed to

al

n

hat

 the

al

for a

r

e

n a

he

ant

and

Commercial Applications

The SNOXTM technology is applicable to all electric

power plants and industrial/institutional boilers firingcoal, oil, or gas. The high removal efficiency for NOx and

SO2 makes the process attractive in many applications.

Elimination of additional solid waste (except ash) enhances the marketability in urban and other areas wheresolid waste disposal is a significant problem.

The host utility, Ohio Edison, is retaining the

SNOXTM technology as a permanent part of the pollutioncontrol system at Niles Station to help Ohio Edisonmeet its overall SO2/NOx reduction goals.

Commercial SNOXTM plants also are operating in

Denmark and Sicily. In Denmark, a 305-MWe plant hasoperated since August 1991. The boiler at this plantburns coals from various suppliers around the world,including the United States; the coals contain 0.5–3.0%sulfur. The plant in Sicily, operating since March 1991,

has a capacity of about 30 MWe and fires petroleumcoke.ContactsPaul Yosick, Project Manager, (865) 693-7550

Alstom Power, Inc.1409 Center Port BoulevardKnoxville, TN 37932(865) 694-5213 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• Final Report Volume II: Project Performance and

Economics. July 1996. Report No. DE-FC22-90PC89C55.

• Final Report Volume I: Public Design. Report No.

DOE/PC/89655-T21. (Available from NTIS asDE96050312.)

• A Study of Toxic Emissions from a Coal-Fired Power

Plant Utilizing the SNOXTM Innovative Clean CoalTechnology Demonstration. Volume 1, Sampling/Results/Special Topics: Final Report. Report No.DOE/PC/93251-T3-Vol. 1. Battelle Columbus Operations. July 1994. (Available from NTIS asDE94018832.)

• A Study of Toxic Emissions from a Coal-Fired Power

Plant Utilizing the SNOXTM Innovative Clean CoalTechnology Demonstration. Volume 2, Appendices:Final Report. Report No. DOE/PC/93251-T3-Vol. 2.Battelle Columbus Operations. July 1994. (Availablefrom NTIS as DE94018833.)
Environmental Control Devices

Project Objective

To demonstrate, with a variety of coals and sorbents,

that the LIMB process can achieve up to 50% NOx and

SO2 reductions, and to demonstrate that the Coolside

process can achieve SO2 removal of up to 70%.

Technology/Project Description

The LIMB process reduces SO2 by injecting dry

sorbent into the boiler at a point above the burners. Thesorbent then travels through the boiler and is removedalong with fly ash in an electrostatic precipitator (ESP) orbaghouse. Humidification of the flue gas before it entersan ESP is necessary to maintain normal ESP operationand to enhance SO2 removal. Combinations of three

bituminous coals (1.6, 3.0, and 3.8% sulfur) and four

e Babcock & Wilcox Company. sorbents were tested. Other variables examined were

Research Institute.

stoichiometry, humidifier outlet temperature, and injection elevation level in the boiler.

In the Coolside process, dry sorbent is injected into

the flue gas downstream of the air preheater, followed byflue gas humidification. Humidification enhances ESPperformance and SO2 absorption. SO2 absorption is improved by dissolving sodium hydroxide (NaOH) or sodium carbonate (Na2CO3) in the humidification water.

The spent sorbent is collected with the fly ash, as in theLIMB process. Bituminous coal with 3.0% sulfur wasused in testing.

Babcock & Wilcox DRB-XCL® low-NO

x burners,

which control NO

x through staged combustion, were used

in demonstrating both LIMB and Coolside technologies.

chnology

on Project

olside

cofunder

funder and technology

Edison’s Edgewater

’s (B&W) limestone

) system; Babcock &

ners; Consolidation Coal

n of lime sorbents

% sulfur

033 100%

655 39

378 61
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

1 2

Project Fact Sheets 2-65

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

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

• Sorbent recycle tests demonstrated the potential to

improve sorbent utilization.

Operational• Humidification enhanced ESP performance, which

enabled opacity levels to be kept well within limits.

• LIMB availability was 95%. Coolside did not undergo

testing of sufficient length to establish availability.

• Humidifier performance indicated that operation in a

vertical rather than horizontal mode would be better.

1988 1989 1990 1991 1992 1993 1994 1995 1996

and Construction

11/92

Project completed/final report issued 11/92

LIMB operational tests completed 8/91

Coolside operational tests initiated 7/89

Construction completed 9/89

eaking/

n

87

itoring plan

d 10/19/88

es at a calcium-to-sulfur

 minimal humidification

r contents were 53–61%

lcitic lime, 45–52% for

for limestone ground to

5 mesh).

y increased to 32% using

nus 325 mesh, and in

when ground to 100% less

es were enhanced by

on down to 20 oF ap

ure was used.

abcock & Wilcox

, achieved 40–50% NOx

Operation and Reporting

LIMB operational testsinitiated 4/90

Coolside operational testscompleted 2/90

7/89

Economic• LIMB capital costs were $31–102/kW for plants

ranging from 100–500 MWe and coals with 1.5–3.5% sulfur, with a target SO2 reduction of 60%

(1992$). Annual levelized costs (15-year) for thisrange of conditions were $392–791/ton of SO2

removed.

• Coolside capital costs were $69–160/kW for plants

ranging from 100–500 MWe and coals with 1.5–3.5%sulfur, with a target SO2 reduction of 70% (1992$).

Annualized levelized costs (15-year) for this range ofconditions were $482–943/ton of SO2 removed.
Environmental Control Devices

Exhibit 2-28

LIMB SO2 Removal Efficiencies

(Percent)

Nominal Coal Sulfur Content

Sorbent 3.8% 3.0% 1.6%Ligno lime 61 63 53Commercial calcitic lime 58 55 51Dolomitic lime 52 48 45Limestone NT 25 22(80% <44 microns)

NT = Not testedTest conditions: injection at 181 ft, Ca/S molar ratio of 2.0,minimal humidification.

IMB technology was

n into the furnace

re. Use of limestone in

nsive lime would keep

wever, the demonstra

rinding of the limestone

nce with limestone was

 hydrated limes was

on, demonstrating

LIMB performance

fication to the point of

emperatures, perfor

midification.

nt upon deep humidifi

y and the use of hy

s downstream of the

ity was enhanced by

OH) or sodium carbon

 water.

Environmental Performance (LIMB)

LIMB tests were conducted over a range of Ca/

S molar ratios and humidification conditions whileburning Ohio coals with nominal sulfur contents of1.6, 3.0, and 3.8% by weight. Each of four differentsorbents was injected while burning each of the threedifferent coals. Other variables examined werestoichiometry, humidifier outlet temperature, andinjection elevation level in the boiler. Exhibit 2-28summarizes SO2 removal efficiencies for the range of

sorbents and coals tested.

While injecting commercial limestone with 80%

of the particles less than 44 microns in size, removalefficiencies of about 22% were obtained at a stoichiometry of 2.0 while burning 1.6% sulfur coal. However, removal efficiencies of about 32% wereachieved at a stoichiometry of 2.0 when using alimestone with a smaller particle size (i.e., all particles were less than 44 microns). A third limestone withessentially all particles less than 10 microns was used todetermine the removal efficiency limit. The removalefficiency for this very fine limestone was approximately5–7% higher than that obtained under similar conditionsfor limestone with particles all sized less than 44 microns.

During the design phase, it was expected that injection at the 181-foot plant elevation level inside the boiler

would permit the introduction of the limestone at close tothe optimum furnace temperature of 2,300 oF. Testingconfirmed that injection at this level, just above the noseof the boiler, yielded the highest SO2 removal. Injection

was also performed at the 187-foot level and similarremovals were observed. Removal efficiencies whileinjecting at these levels were about 5% higher than whileinjecting sorbent at the 191-foot level.

Removal efficiencies were enhanced by approximately 10% over the range of stoichiometries tested when

using humidification down to a 20 oF approach-to-saturation temperature. The continued use of the low-NOx

burners resulted in an overall average NOx emissions

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

Operational Performance (LIMB)

Long-term test data showed that the LIMB system

was available about 95% of the time it was called upon tooperate. Even with minimal humidification, ESP performance was adequately enhanced to keep opacity levelswell below the permitted limit. Opacity was generally inthe 2–5% range (limit was 20%).Environmental Performance (Coolside)

The Coolside process was tested while burning compliance (1.2–1.6% sulfur) and noncompliance (2.8–3.2%

sulfur) coals. Objectives of the full-scale test programwere to verify short-term process operability and to develop a design performance database to establish processeconomics for Coolside. Key process variables—Ca/Smolar ratio, Na/Ca molar ratio, and approach-to-saturation temperatures—were evaluated in short-term (6–8hour) parametric tests and longer term (1–11 day) processoperability tests.

ue gas, enhanced sulfur

ately 10% in the LIMB

uration was used.
Project Fact Sheets 2-67

ted that the Coolside

SO2 removal at design

o, 0.2 Na/Ca molar ratio,

 temperature using commercially available hydrated lime. Coolside SO2 removal depended on Ca/S molar ratio, Na/Ca molar ratio, approach-to-adiabatic-satu- ration, and the physical properties of the hydrated lime. Sorbent recycle showed significant poten- tial to improve sorbent utilization. The observed SO2 removal with recycled sorbent alone was 22% at 0.5 available Ca/S molar ratio and 18 oF approach-to-adiabatic-satu- ration. The observed SO2 removal with simultaneous recycle and fresh sorbent feed was 40% at 0.8 fresh Ca/S molar ratio, 0.2 fresh Na/Ca molar ratio, 0.5 available recycle, and 18 oF approach-to- adiabatic-saturation. Operational Performance (Coolside) Floor deposits experienced in the ductwork with the horizontal humidification led designers to consider a vertical unit in a com- mercial configuration. Short-term testing did not permit evaluation of Coolside system availability. Economic Performance (LIMB & Coolside) Economic comparisons were made between LIMB, Coolside, and a wet scrubber with limestone injection and forced oxidation (LSFO). Assumptions on performance were SO2 removal efficiencies of 60, 70, and 95% for LIMB, Coolside, and LSFO, respectively. The EPRI TAGTM methods were used for the economics, which are summarized in Exhibits 2-29 and 2-30. Exhibit 2-29 

al Cost Comparison (1992 $/kW) 

de LSFO LIMB Coolside LSFO 

150 MWe 

413 66 116 312 421 71 122 316 

425 73 127 324 

500 MWe 

228 31 69 163 

235 36 76 169 240 40 81 174 Exhibit 2-30 

velized Cost Comparison 

Ton of SO2 Removed) 

side LSFO LIMB Coolside LSFO 

150 MWe 

1418 653 797 1098 

895 520 624 692 665 461 570 527 

500 MWe 

831 480 589 623 539 416 502 411 Commercial Application Both LIMB and Coolside technologies are applicable to most utility and industrial coal-fired units, and provide alternatives to conventional wet flue gas desulfurization processes. LIMB and Coolside can be retrofitted with modest capital investment and downtime, and their space requirements are substantially less than for conventional flue gas desulfurization processes. LIMB has been sold to an independent power plant in Canada. Babcock & Wilcox has signed 124 contracts for DLB-XCL® low-NOx burners, representing 2,428 burners for 31,467 MWe of capacity. Contacts Paul Nolan, (330) 860-1074 The Babcock & Wilcox Company 20 South Van Buren Avenue P.O. Box 351 Barberton, OH 44203-0351 (330) 860-2045 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 John C. McDowell, NETL, (412) 386-6175 References

• T.R. Goots, M.J. DePero, and P.S. Nolan. LIMB

Demonstration Project Extension and Coolside Demonstration: Final Report. Report No. DOE/PC/79798-T27. The Babcock & Wilcox Company. November1992. (Available from NTIS as DE93005979.)

• D.C. McCoy et al. The Edgewater Coolside Process

Demonstration: A Topical Report. Report No. DOE/PC/79798-T26. CONSOL, Inc. February 1992.(Available from NTIS as DE93001722.)

• Coolside and LIMB: Sorbent Injection Demonstrations Nearing Completion. Topical Report No. 2.

U.S. Department of Energy and The Babcock & Wilcox Company. September 1990.
Environmental Control Devices

9/95

Project Objective

To achieve greater than 70% SO2 removal and 90%

or higher reduction in NOx emissions while maintaining

particulate emissions below 0.03 lb/106 Btu.

Technology/Project Description

The SNRBTM process combines the removal of SO2,

NO

x, and particulates in one unit—a high-temperature

baghouse. SO2 removal is accomplished using either

calcium- or sodium-based sorbent injected into the fluegas. NOx removal is accomplished by injecting ammonia

(NH3) to selectively reduce NOx in the presence of a

selective catalytic reduction (SCR) catalyst. Particulateremoval is accomplished by high-temperature fiberbag filters.

The 5-MWe SNRBTM demonstration unit is large

enough to demonstrate commercial-scale componentswhile minimizing the demonstration cost. Operation atthis scale also permitted cost-effective control of the fluegas temperature, which allowed for evaluation of performance over a wide range of sorbent injection and baghouse operating temperatures. Thus, several differentarrangements for potential commercial installations couldbe simulated.

chnology

TM Flue Gas

ration

 and host

cofunder

—cofunder

SCR catalyst supplier

r bag supplier

tion—cofunder and

OH (Ohio Edison

it No. 5)

’s SOx-NOx-Rox BoxTM

m a 156-MWe boiler

ur average

620 100%

402 46

218 54

ks of The Babcock & Wilcox
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Project Fact Sheets 2-69

% was achieved with

alcium-to-sulfur (Ca/S)

ature of 800–850 oF.

% was achieved with

nate hydrated lime at a

mperature of

% was achieved with

m-to-sulfur (Na2/S)

ature of 425 oF.

o less than 1.2 lb/106 Btu

 Ca/S molar ratio as low

f 1.0.

rbents directly upstream

F resulted in higher over

 further upstream at

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design completed 8/91

perative agreement

ded 12/20/89

ocess completed (MTF) 9/22/89

Ground breaking/construction started 5/9/91

5/92

Design and Construction Operation and Reporting

Preoperational tests initiated 11/91• NO

x

 reduction of 90% was achieved with an NH3/NOx

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

• Air toxics removal efficiency was comparable to that

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

Operational• Calcium utilization was 40–45% for SO2 removals of

85–90%.

• Norton Company’s NC-300 zeolite SCR catalyst

showed no appreciable physical degradation or changein catalyst activity over the course of the demonstration.

• No excessive wear or failures occurred with the filter

bags tested: 3M’s Nextel ceramic fiber filter bag andOwens Corning Fiberglas’ S-Glass filter bag.

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

Operationinitiated 5/92 Operation completed 5/93 Project completed/final report issued 9/95

9/95

Economic• Capital cost in 1994 dollars for a 150-MWe retrofit

was $253/kW, assuming 3.5% sulfur coal, baselineNO

x

 emissions of 1.2 lb/106 Btu, 65% capacity factor,

and 85% SO2 and 90% NOx removal.

• Levelized cost over 15 years in constant 1994 dollars

was $553/ton of SO2 and NOx removed.
Environmental Control Devices

ccessful technology

inct advantages over

emperature filter bags

elopments enabled

gle component with a

As a postcombustion

ate. The high-tempera

mperature environment

eration, and a surface

(creates a sorbent cake

ested for SO2 capture.

commercial grade hy

and lignosulfonate

m bicarbonate was

jecting the sorbent into

ream of the baghouse.

by the sorbent in the

ags (along with fly

above 830 oF, injection

e at Ca/S molar ratios

emovals of over 80%.

rmance of the sugar

hydrated lime increased

, for overall removal of

 of 85–90% was ob

he range of 40–45%.

bents directly upstream

ulted in higher overall

 upstream at tempera

m bicarbonate was

0 and 98% at an Na2/S

ly reduced baghouse

emissions while burning a 3–4% sulfur coal were reduced to less than 1.2 lb/ 106 Btu with a Ca/S molar ratio as low as 1.5 and Na2/S molar ratio less than 1.0. To capture NOx, ammonia was injected between the sorbent injection point and the baghouse. The ammonia and NOx reacted to form nitrogen and water in the pres- ence of Norton Company’s NC-300 series zeolite SCR catalyst. With the catalyst being located inside the filter bags, it was well protected from potential particulate erosion or fouling. The sorbent reaction products, unre- acted lime, and fly ash were collected on the filter bags and thus removed from the flue gas. A NOx emission reduction of 90% was readily achieved with ammonia slip limited to less than 5 ppm. This performance reduced NOx emissions to less than 0.10 lb/106 Btu. NOx reduction was insensitive to tem- peratures over the catalyst design temperature range of 700–900 oF. Catalyst space velocity (volumetric gas flow/catalyst volume) had a minimal effect on NOx re- moval over the range evaluated. Turndown capability for tailoring the degree of NOx reduction by varying the rate of ammonia injection was demonstrated for a range of 50–95% NOx reduction. No appreciable physical degradation or change in the catalyst activity was observed over the duration of the test pro- gram. The degree of oxidation of SO2 to SO3 over the zeolite catalyst appeared to be less than 0.5%. (SO2 oxidation is a concern for SCR catalysts containing vana- dium.) Leach potential analysis of the catalyst after completion of the field test showed that the catalyst re- mained nonhazardous for disposal. Particulate emissions were consistently below NSPS standards of 0.03 lb/106 Btu, with an average of 0.018 lb/ 106 Btu, which corresponds to a collective efficiency of 99.89%. Hydrated lime injection increased the baghouse inlet particulate loading from 5.6 to 16.5 lb/106 Btu. Emissions testing with and without the SCR catalyst installed revealed no apparent differences in collection efficiency. On-line cleaning with a pulse air pressure of 30–40 lb/in2 was sufficient for cleaning the bag/catalyst assemblies. Typically, one of five baghouse modules in service was cleaned every 30–150 minutes. A comprehensive air toxics emissions monitoring test was performed at the end of the SNRBTM demonstra- tion test program. The targeted emissions monitored included trace metals, volatile organic compounds, semi- volatile organic compounds, aldehydes, halides, and radionuclides. These species were a subset of the 189 hazardous substances identified in the CAAA. Measure- The demonstration baghouse is installed on the back side of the power plant. Workers stand by the catalyst holder tube prior to lifting it into the penthouse.
Project Fact Sheets 2-71

Workers lower one of the catalyst holder tubes into a

mounting plate in the penthouse of the high-temperaturebaghouse.

xins, and furans were

am. The emissions con

ious air toxics by the

comparable to those of

er plant. However, the

by an average of 95%

of 84%, whereas the

ituents.

emonstration resulted in

830 tons of fly ash and

n of potential uses for the

rial might be used for

. Also, the solids poten

ement replacement to

 of three fabric filters

c Development Test

lorado in December

bserved. All of the

ted using the 3M Com

bags or the Owens Corn

 No excessive wear or

ours of elevated tempera

 with 3.5% sulfur coal

Btu, 65% capacity factor,

oval, the projected capital

oximately $253/kW

ology and project contin

 fabric filter, SCR, and

arable emissions control

kW. Variable operating

of the SO2 sorbent for a

2 removal. Fixed operat

tem operating labor and

he hot baghouse and

ash-handling systems. Levelized costs over 15 years inconstant 1994 dollars are estimated at $553/ton of SO2

and NOx removed.

Commercial Applications

Commercialization of the technology is expected to

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

combined emissions to meet current performance requirements while providing flexibility to address future needs.ContactsDot K. Johnson, (330) 829-7395

McDermott Technology1562 Beeson StreetAlliance, OH 44601(330) 829-7801 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, NETL, (412) 386-5991References• SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration

Final Report. Report No. DOE/PC/89656-T1. TheBabcock & Wilcox Company. September 1995.(Available from NTIS as DE96003839.)

• 5-MWe SNRB

TM Demonstration Facility: Detailed

Design Report. The Babcock & Wilcox Company.November 1992.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: SOx-NOx-Rox BoxTM Flue Gas

Cleanup Demonstration Project. The Babcock &Wilcox Company. Report No. DOE/FE-0145. U.S.Department of Energy. November 1989. (Availablefrom NTIS as DE90004458.)
Environmental Control Devices

chnology

e of Coals by

d Sorbent

ch Corporation

mmerce & Community

st

nois Power Company’s

 (City Water, Light and

 No. 7)

ch Corporation’s gas

R-SI) process

We (gross), 71 MWe (net)

gross), 33 MWe (net)

955 100%

816 50

139 50

Project Objective

To demonstrate 60% NO

x reduction with gas reburning and at least 50% SO2 removal with sorbent injection

on two different boiler configurations—tangentially firedand cyclone-fired—while burning high-sulfur midwesterncoal.Technology/Project Description

In this process, 80–85% of the fuel as coal is supplied to the main combustion zone. The remaining 15–

20% of the fuel, provided by natural gas, bypasses themain combustion zone and is injected above the mainburners to form a reducing (reburning) zone in whichNO

x is converted to nitrogen. A calcium compound

(sorbent) is injected in the form of dry, fine particulatesabove the reburning zone in the boiler. Hydrated lime(Ca(OH)2) serves as the baseline sorbent.

This project demonstrated the GR-SI process on

two separate boilers representing two different firingconfigurations—a tangentially fired, 80-MWe (gross)boiler at Illinois Power Company’s Hennepin Plant inHennepin, Illinois, and a cyclone-fired, 40-MWe (gross)boiler at City Water, Light and Power’s Lakeside Station in Springfield, Illinois. Illinois bituminous coalcontaining 3% sulfur was the test coal for bothHennepin and Lakeside.

A comprehensive test program was conducted at

each of the two sites, operating the equipment over awide range of boiler conditions. Over 1,500 hours ofoperation was achieved, enabling a substantial amount ofdata to be obtained. Intensive measurements were takento quantify the reductions in NOx and SO2 emissions, the

impact on boiler equipment and operability, and all factors influencing costs. 

Environmental Research 
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

**Years omitted

1 2

Project Fact Sheets 2-73

er, GR-SI NOx reductions

and an average 67%

verage gas heat input of

y on the tangentially fired

drated lime at a calcium

f 1.75 (corresponding to

GR-SI NOx reductions of

d an average 66% reduc

e gas heat input of 22%.

 on the cyclone-fired

rated lime at a Ca/S molar

a sorbent utilization of

ot a problem on either

on, but humidification

had to be introduced at Hennepin to enhance ESPperformance.

• Three advanced sorbents tested achieved higher

SO2 capture efficiencies than the baseline Linwood

hydrated lime. PromiSORBTM A achieved 53%SO2 capture efficiency and 31% utilization withoutGR at a Ca/S molar ratio of 1.75. Under the sameconditions, 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.

Design and Construction

1988 1989 1990 1991 1992 1993 1994 1995 1998

1/91

Operation initiated,Lakeside 5/93

Operation completed,Hennepin 1/93

Construction completed, Hennepin 8/91

Operation initiated, Hennepin 1/91

Construction started, Lakeside 6/90

Environmental monitoring plan completed,Lakeside 11/15/89

nvironmental monitoring plan

mpleted, Hennepin 10/15/89

akeside (EA) 6/25/89

mpleted, both sites 5/89

started, Hennepin 5/89

NEPAprocesscompleted,Hennepin(MTF) 5/9/88

Construction completed, Lakeside 5/92

Restoration completed,Hennepin 12/93

9/98

Project completed/

final report issued 9/98

Operation completed,Lakeside 10/94

Operation and Reporting

Restoration completed,

Lakeside 12/95

Economic• Capital cost for gas reburning (GR) was approximately

$15/kW plus the gas pipeline cost, if not in place(1996$).

• Operating costs for GR were related to the gas/coal

cost differential and the value of SO2 emission allowances (because GR replaces some coal with gas, it also

reduces SO2 emissions).

• Capital cost for sorbent injection (SI) was approximately $50/kW.• Operating costs for SI were dominated by the cost of

sorbent and sorbent/ash disposal costs. SI was estimated to be competitive at $300/ton of SO2 removed.

**

3 4
Environmental Control Devices

The flexible lime-sorbent distribution lines lead from

the sorbent splitter to the top of the cyclone-fired boiler atLakeside Station.

ted the success of gas

chnologies in reducing

ess design conducted

 the vast amount of

eated a database en

-specific utility or

Hennepin)

g throughout 1991, the

sts spanned 1992. The

s and with the system

ith the system under

a wide range from 40-

We. Over the long

erage gross power

testing, the average

67%. The average SO2

at a Ca/S molar ratio of

s used throughout these

Marblehead lime was

50 ppm in most cases

at low load.

2 was also realized.

nt of coal with natural

ogen ratio. This cofir

in a theoretical CO2

from the coal-fired

idification, electrostatic

encies greater than

ess than 0.025 lb/106

ncrease in inlet particu

 injection. These lev

e emissions of 0.035

ncy greater than 99.5%.

ong-term tests, three

ested. Two were manufactured by the participant and contained proprietary additives to increase their reactivity toward SO2, and were referred to as PromiSORBTM A and B. The Illinois Geo- logical Survey developed the other sorbent—high-sur- face-area hydrated lime—in which alcohol is used to form a material that gives rise to a much higher surface area 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 hydrated lime, and 42% for Linwood lime. At a 2.6 Ca/S molar ratio, 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 optimiza- tion tests. A total of 100 GR parametric tests were con- ducted at boiler loads of 33, 25, and 20 MWe. Gas heat input varied from 5–26%. The GR parametric tests achieved a NOx reduction of approximately 60% at a gas heat input of 22–23%. Additional flow modeling and computer modeling studies indicated that smaller reburn- ing fuel jet nozzles could increase reburning fuel mixing and thus improve the NOx reduction performance. A total of 25 SI parametric tests were conducted to isolate the 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 sulfation reaction. At a Ca/S molar ratio of 2.0, 44% SO2 reduction was achieved at full load (33 MWe); 38% SO2 reduction was achieved at mid load (25 MWe); and 32% SO2 reduction was achieved at low load (20 MWe). In the GR-SI optimization tests, the two technologies were integrated. Modifications were made to the reburn- ing fuel injection nozzles based on the results of the initial GR parametric tests and flow modeling studies. The total cross-sectional area of the reburning jets was decreased by 32% to increase the reburning jet’s penetra- tion characteristics. The decrease in nozzle diameter increased NOx reduction by an additional 3–5% compared to the initial parametric tests. With GR-SI, total SO2 reductions resulted from partial replacement of coal with natural gas and sorbent injection. At a gas heat input of 22% and Ca/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%.
Project Fact Sheets 2-75

ennepin/Lakeside)

the frequency of soot

ersely affect boiler effi

e. Gas reburning de

oximately 1.0% because

d with combustion of

boiler before and after

ange in tube wear or

duled life of the boiler

mmodated the changes in

he presence of sorbent in

the ash. No adverse conditions were found to exist. Butas 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 installation, a 15% gas heat input will achieve 60% NOx reduction. The capital cost for such a GR installation was

estimated 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. Operating costs for SI were dominated by the cost of the

sorbent and sorbent/ash disposal costs. SI was projectedto be cost competitive at $300/ton of SO2 removed.

Commercial Applications

The GR-SI process is a unique combination of two

separate technologies. The commercial applications forthese technologies, both separately and combined, extendto both utility companies and industry in the UnitedStates and abroad. In the United States alone, these twotechnologies can be applied to more than 900 pre-NSPSutility boilers. The technologies also can be applied tonew utility boilers. With NOx and SO2 removal exceeding 60% and 50%, respectively, these technologies have

the potential to extend the life of a boiler or power plantand also provide a way to use higher sulfur coals.

Illinois Power has retained the gas-reburning system

and City Water, Light & Power has retained the fulltechnology for commercial use. The project was one oftwo receiving the Air and Waste ManagementAssociation’s 1997 J. Deanne Sensenbaugh Award.

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

General Electric Energy and Environmental ResearchCorporation18 MasonIrvine, CA 92618(949) 859-3194 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483Jerry L. Hebb, NETL, (412) 386-6079References• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 1–Program Overview.February 1997.

• Enhancing the Use of Coals by Gas Reburning–Sorbent Injection: Volume 4: Gas Reburning Sorbent

Injection at Lakeside Unit 7, City Water, Light andPower, Springfield, Illinois. Final Report. Energyand Environmental Research Corporation. March1996. Report No. DOE/PC/79796-T48-Vol.4. (Available from NTIS as DE96011869.)

• Enhancing the Use of Coals by Gas Reburning–Sorbent Injection; Long Term Testing Period, September

1, 1991–January 15, 1993. Report No. DOE/PC/79796-T40. Energy and Environmental ResearchCorporation. February 1995. (Available from NTISas DE95011481.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 2: Gas Reburning–SorbentInjection at Hennepin Unit 1, Illinois Power Company. Report No. DOE/PC/79796-T38-Vol. 2. Energy and Environmental Research Corporation. October 1994. (Available from NTIS as DE95009448.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 3: Gas Reburning–SorbentInjection at Edwards Unit 1, Central Illinois LightCompany. Report No. DOE/PC/79796-T38-Vol. 3.Energy and Environmental Research Corporation.October 1994. (Available from NTIS as DE95009447.)

nstalled on the corner of

ed boiler.
Environmental Control Devices

Plant Capacity/Production300 MWeCoalPittsburgh, Freeport, and Kittanning Coals; 1.5, 2.9 and4.0% sulfur, respectively.Project FundingTotal project cost $158,607,807 100%DOE 45,000,000 28Participant 113,607,807 72Project Objective

To demonstrate high sulfur capture efficiency and

NO

x and particulate control at minimum power require

chnology 

al 

nstration 

orporation 

and Development 

arch Corporation— 

chnical consultant 

GmbH (S-H-U)—tech- 

nufacturing Com- 

ogy supplier 

operator of advisor 

New York State Elec- 

 Station, Unit Nos. 1 

mic-acid-enhanced, wet 

BB Combustion 

ic Firing System 

le-lined split-module 

at-pipe air preheater; 

em.

n Engineering, Inc.

s, Inc.

ments, zero waste water discharge, and the production ofby-products in lieu of wastes.Technology/Project Description

The formic acid enhanced S-H-U process is designed

to remove up to 98% SO2 at high sorbent utilization rates.

The Stebbins tile-lined, split-module reinforced concreteabsorber vessel provides superior corrosion and abrasionresistance. Placement below the stack saves space andprovides operational flexibility. NOx emissions are controlled by LNCFS IIITMlow-NOx burners and by micronized coal reburning. A heat-pipe air preheater is integrated to increase boiler efficiency by reducing both air

leakage and the air preheater’s flue gas exit temperature.To enhance boiler efficiency and emissions reductions,DHR’s Plant Emission Optimization Advisor (PEOATM)
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Project Fact Sheets 2-77

1993 1994 1995 1996 1997 1998 1999 2000 2001

Operation and Reporting

tive agreement awarded 10/20/92

Design completed 4/93Ground breaking/construction started 4/93

NEPA process completed(EA) 8/18/93

10/99

Operation completed 6/98

Project completed/final reportissued 10/99

Operation initiated on Unit 2 1/95

6/95

Design and Construction

Environmental

monitoring

plan completed

12/1/94 Construction completed 6/95

Fully integrated operation of Units 1 and 2 initiated 6/95

-intelligence-based

perating parameters.

emonstrated was 98%

operating and using

O2 removal without

l between the two lime

–325 mesh and 90%–170

 coal was an average of

was greater than the de

h velocity test of the

p to a liquid-to-gas ratio

0 actual cubic feet of gas.

• At full load, LNCFSTM III lowered NOx emissions to

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

original burners)—a 39% reduction.

• During diagnostic tests, LOI was above 4% at full

boiler load. During the validation tests (when overfireair limitations were relaxed), the LOI dropped by 0.7to 1.7 percentage points, with a minor effect on NOx

emissions.

Operational• The co-current pumps had no measurable effect on

pressure drop, whereas the countercurrent pumpssignificantly increased the scrubber pressure drop.The average effect of each countercurrent header wasto increase pressure drop by 0.45 inches water column(WC) in the design flow tests and 0.64 inches WC inthe high velocity tests.

• Performance of a modified ESP with wider plate spacing and reduced plate area exceeded that of the original ESPs at lower power consumption.• Boiler efficiency was 88.3–88.5% for LNCFSTM III,

compared to a baseline of 89.3–89.6%.

• Air infiltration was low for both heat pipes. Some

unaccounted for air leakage occurred at full load,ranging between 2.0–2.4%.

• The flue gas side pressure loss for both heat pipes was

less than the design maximum of 3.65 inches WC. Theprimary side pressure drops for both heat pipes wereless than the design maximum of 3.6 inches WC. Thesecondary air side pressure drops for both heat pipeswere less than the design maximum of 5.35 inches WC.

Economic• The capital cost (1998$) of the FGD system is estimated at $300 /kW for a 300 MWe unit with a 65%
Environmental Control Devices

Exhibit 2-31

of Limestone Grind

al, and 95% sulfur

timated at $4.62 million

zed cost is estimated at

stant 1998$).

o cover all of the new

n addition to the tech

strated that existing

nction with new pro

ucts. Supplemental

 and performance data

ocesses under a variety

, each test program was

ests: diagnostic, perfor

(See Micronized Coal

Reburning Demonstration for NOx Control for another

CCT Program project at this unit.)Environmental Performance

The S-H-U FGD system was tested over a 36-month

period. Typical evaluations included SO2 removal efficiency, power consumption, process economics, loadfollowing capability, reagent utilization, by-product quality, and additive effects. Parametric testing includedformic acid concentration, L/G ratio, mass transfer, coalsulfur content, and flue gas velocity. The maximum SO2

removal demonstrated was 98% with all seven recyclepumps operating and using formic acid, and the maximum SO2 removal without formic acid was 95%. The

difference in SO2 removal between the two limestone

grind sizes tested (90%–325 mesh and 90%–170 mesh),while using low-sulfur coal was an average of 2.6 percentage points as shown in Exhibit 2-31. The SO2 removal efficiency was greater than the design efficiency

during the high velocity testof the cocurrent scrubbersection up to a liquid-to-gasratio of 110. The cocurrentpumps had no measurableeffect on pressure drop,whereas the countercurrentpumps significantly increased the scrubber pressure drop. As seen in Exhibit 2-32, the averageeffect of each countercurrent header was to increasepressure drop by 0.45inches water column (W.C.)in the design flow tests, and0.64 inches W.C. in thehigh velocity tests.

Performance of a

modified ESP with wider

plate spacing, reduced plate area, and reduced powerconsumption exceeded that of the original ESP. Theaverage particulate matter penetration before the ESPmodification was 0.22% and decreased to 0.12% after themodifications.

At full boiler load (145–150 MWe) and 3.0–3.5%

economizer O2, the LNCFSTM III lowered NOx emissions

from a baseline of 0.64 lb/106 Btu to 0.39 lb/106 Btu

(39% reduction). At 80- to 90-MWe boiler load and 4.3–5.0% economizer O2, the LNCFSTM III lowered NOx

emissions from a baseline of 0.58 lb/106 Btu to 0.41 lb/

106 Btu (29% reduction). With LNCFSTM III, LOI was

maintained below 4% and CO emissions did not increase.

Exhibit 2-32

Pressure Drop vs.

Countercurrent Headers

High Gas Velocity

Design Gas Velocity

Number of Countercurrent Headers

Scrubber Pressure Drop, inches W.C.
Project Fact Sheets 2-79

formance goal of 98%

eved. Similarly, the

ble gypsum by-product

ved. The test results

ed can be maintained at a

 a chloride level less than

producing a marketable

he FGD blowdown

availability for the test

rmed better than the

e. The total voltage

 directly proportional to

e modified ESP required

he original ESPs. The

t footprint with fewer

tal internal plate area is

inal ESPs, tending to

88.5% for LNCFSTM III,

9.6%. The lower effi

ost-retrofit flue gas ex

tack temperatures which

fit.

accordance with ASME

 4.3. Air infiltration was

unted for air leakage

ween 2.0–2.4%. The

e pressure loss for both

gn maximum of 3.65

essure drops for both

ign maximum of 3.6

de pressure drops for

e design maximum of

Economic Performance

The capital cost of the total FGD system in 1998

dollars is estimated at $300/kW for a 300 MWe unit witha 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.Commercial Applications

The S-H-U process, Stebbins absorber module, and

heat-pipe air preheater are applicable to virtually allpower plants. The space-saving design features of thetechnologies, combined with the production of marketable byproducts, offer significant incentives to generatingstations with limited space. Six modules of DHR Technologies’ PEOATM system have been sold, with an estimated value of $210,000.ContactsJim Harvilla, Project Manager, (607) 762-8630

New York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991References• Milliken Clean Coal Technology Demonstration

Project: Project Performance and Economics Report,Final Report Volumes I & II. New York State Electric& Gas Corporation. October 1999.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Milliken Coal TechnologyDemonstration Project. New York State Electric &Gas Corporation. Report No. DOE/FE-0265P. U.S.Department of Energy. September 1992. (Availablefrom NTIS as DE93001756.)

• Harvilla, James et al. “Milliken Clean Coal Technology Demonstration Project.” Sixth Clean Coal Technology Conference: Clean Coal for the 21st Century—

What Will It Take? Volume II - Technical Papers.CONF-980410—VOL II. April 28–May 1, 1998.
Environmental Control Devices

chnology

/SO2 

 System

ado

—cofunder

orp.—engineer

—burner developer

on—operational tester

sh evaluator

h-scale engineering

em provider

lic Service Company of

t No. 4)

y’s DRB-XCL® low

ction, and furnace

st), 0.35% sulfur

306 100%

653 50

653 50

Project Objective

To demonstrate the integration of five technologies

to achieve up to 70% reduction in NOx and SO2 emissions; more specifically, to assess the integration of a

down-fired low-NO

x burner with in-furnace urea injection

for additional NO

x removal and dry sorbent in-duct injection with humidification for SO2 removal.

Technology/Project Description

All of the testing used Babcock & Wilcox’s low-NOx

DRB-XCL® down-fired burners with overfire air. These

burners control NO

x by injecting the coal and the combustion air in an oxygen-deficient environment. Additional air is introduced via overfire air ports to complete

the combustion process and further enhance NOx removal. A urea-based selective noncatalytic reduction

e Babcock & Wilcox Company.

(SNCR) system was tested to determine how much additional NO

x can be removed from the combustion gas.

Two types of dry sorbents were injected into the

ductwork downstream of the boiler to reduce SO2 emissions. Either calcium-based sorbent was injected upstream of the boiler economizer, or sodium-based sorbent

downstream of the air heater. Humidification downstream of the dry sorbent injection was incorporated toaid SO2 capture and lower flue gas temperature and gasflow before entering the fabric filter dust collector.

The systems were installed on Public Service Company of Colorado’s Arapahoe Station Unit No. 4, a

100-MWe down-fired, pulverized-coal boiler with roofmounted burners.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

**Years omitted

1 2

Project Fact Sheets 2-81

1990 1991 1992 1993 1994 1995 1996 1999 2000

Preaward Operation Design and 8/92 Construction 

3/91

) 9/27/90

 6/90

Ground breaking/construction started 5/21/91

Design completed 3/92

Preoperational tests initiated 6/92

Construction completed 8/92Operation initiated 8/92

Environmental monitoring plancompleted 8/5/93

imum overfire air re

e than 63% under steady

24% of total combustion

9% was achieved across

ge.

h stationary and retract

rnace, provided NOx

monia (NH3) slip of

rmance of the total NOx

 80% NOx reduction.

m hydroxide injection into

oximately 1,000 oF was

tion into the fabric filter

an 40% at a calcium/

0.

• Sodium bicarbonate injection before the air heater

demonstrated a long-term SO2 removal of approximately 70% at a normalized stoichiometric ratio

(NSR) of 1.0.

• Sodium sesquicarbonate injection ahead of the fabric

filter achieved 70% SO2 removal at an NSR of 2.0.

• NO2 emissions were generally higher when using

sodium bicarbonate than when using sodiumsesquicarbonate.

• Integrated SNCR and dry sodium-based sorbent injection tests showed reduced NH3 and NO2 emissions.

• During four series of air toxics tests, the fabric filter

successfully removed nearly all trace metal emissionsand 80% of the mercury.

Operational• Arapahoe Unit No. 4 operated more than 34,000 hours

with the combustion modifications in place. Availability factor was over 91%.

2/00

Operation completed 12/96

Cooperative agreement awarded 3/11/91

Project completed/

final report issued

2/00

• Control system modifications and additional operator

training may be necessary to improve NOx control

under load-following conditions.

• Temperature differential between the top and bottom

surfaces of the Advanced Retractable Injection Lances(ARIL) initially caused the lances to bend downward12–18 inches. Alternative designs corrected theproblem.

Economic• When used on units burning low sulfur coal, the technology offers SO2 and NOx removals comparable to a

wet scrubber and SCR, but at a lower cost.

• Total capital costs for the technology ranges from

$125/kW to $281/kW for 300 MWe to 50 MWeplants, respectively. Levelized costs range from12.43–7.03 mills/kWh or 1746–987 $/ton of SO2 and

NO

x removed for 300 MWe to 50 MWe plants, respectively.

**
Environmental Control Devices

Public Service Company of Colorado demonstrated

low-NOx burners, in-duct sorbent injection, and SNCR at

Arapahoe Station near Denver, Colorado.

Emissions Control

ol technologies to form

h NOx and SO2. The

sts of 12 Babcock &

ers installed on the

tion system also incor

ual-zone NOx ports

pproximately 20 feet

 inject up to 24% of the

urnace sidewalls.

chieved using the urea

when used with the

wed the goal of 70%

her, the SNCR system

ated system, interact

rbent injection (DSI)

nd ammonia slip.

ned and installed to

 with 10 injectors at

ed by temperature

nal combustion system.

mbustion system re

 gas temperature by

g one injector level out

for effective SNCR

nal injector level, load

omised.

ble NOx reduction at

xplored. The first

ia for urea. It was

ective than urea at low

a conversion system

oved low-load perfor

not as large as desired

e second approach was

mperature regions of the

talling two NOELL

ugh two unused sootblower ports. Each lance was nominally 4 inches in diameter and approximately 20 feet in length with a single row of nine injection nozzles. Each injection nozzle consisted of a fixed air orifice and a replaceable liquid orifice. The ability to change orifices allowed not only for removal and cleaning but adjustment of the injection pattern along the length of the lance in order to compensate for any significant maldistributions of flue gas velocity, temperature, or baseline NOx concentration. One of the key features of the ARIL system was its ability to rotate, thus providing a high degree of flexibility in optimizing SNCR performance. The SO2 control system was a direct sorbent injec- tion system that could inject either calcium- or sodium- based reagents into the flue gas upstream of the fabric filter. Sorbent was injected into three locations: (1) air heater exit where the temperature was approximately 260 oF, (2) air heater entrance where the temperature was approximately 600 oF, or (3) the boiler economizer region where the flue gas temperature was approximately 1,000 oF. To improve SO2 removal with calcium hydrox- ide, a humidification system capable of achieving 20 oF approach-to-saturation was installed approximately 100

feet ahead of the fabric filter. The system designed byBabcock & Wilcox included 84 I-Jet nozzles that caninject up to 80 gal/min into the flue gas duct work.Environmental Performance

The combined DRB-XCL® burner and minimum

overfire air reduced NOx emissions by over 63% under

steady-state conditions and with carefully supervisedoperations. Under load-following conditions, NOx emissions were about 10–25% higher. At maximum overfire

air (24% of total combustion air), the low-NOx combustion system reduced NOx emissions by 62–69% across theload range (60- to 110-MWe). The results verified thatthe low-NOx burners were responsible for most of the

NOx reduction.

The original design of two rows of SNCR injector

nozzles proved relatively ineffective because one row ofinjectors was in a region where the flue gas temperaturewas too low for effective operation. At full load, theoriginal design achieved a NOx reduction of 45%. However, the performance decreased significantly as load

decreased; at 60-MWe, NOx removal was limited to about

11% with an ammonia slip of 10 ppm. The addition ofretractable lances improved low-load performance of theurea-based SNCR injection system. The ability to followthe temperature window by rotating the ARIL lancesproved to be an important feature in optimizing performance. As a result, the SNCR system achieved NOx

removals in the range of 30–50% (at a NH3 slip limited to

10 ppm at the fabric filter inlet), increasing total NOx

reduction to greater than 80%, significantly exceeding thegoal of 70%.

Testing of calcium hydroxide injection at the economizer without humidification resulted in SO2 removal in

the range of 5–8% at a Ca/S molar ratio of 2.0. HigherSO2 removal was achieved with duct injection of calcium

hydroxide and humidification, with SO2 removals approaching 40% at a Ca/S molar ratio of 2.0 and within

20–30 oF approach-to-saturation. Sodium-based reagentswere found to be much more effective than calcium-based
Project Fact Sheets 2-83

tly higher SO2 removals

carbonate injection be

short-time SO2 removals

of 70% were achieved

squicarbonate achieved

when injected ahead of

e of the sodium-based

me existing NO to NO2

.

 was reduced during the

 exiting at the stack was

ss, small quantities of

ble plume.

emonstration of the

Ox emissions control

hnologies. The results

 occurred during the

NCR and the sodium DSI

the SNCR process sup

iated with NO-to-NO2

n.

perated more than 34,000

fications in place. The

od was over 91%. The

met or exceeded. How

ons learned during the

 in future deployment of

duct injection of calcium

der load-following con

drop significantly in

 buildup of a hard ash

 could not be cleaned

g. The heavy ash cake

n system, but it was not

 was due to operation at

perature or an excursion

d.

The performance of the ARIL lances in NOx removal

was good; however, the location created some operationalproblems. A large differential heating pattern betweenthe top and bottom of the lance caused a significantamount of thermal expansion along the upper surface ofthe lance. This caused the lance to bend downward approximately 12–18 inches after 30 minutes of exposure.Eventually the lances become permanently bent, thusmaking insertion and retraction difficult. The problemwas partially resolved by adding cooling slots at the endof the lance. An alternative lance design provided byDiamond Power Specialty Company (a division of Babcock & Wilcox) was tested and found to have less bending due to evaporative cooling, even though its NOx

reduction and NH3 slip performance dropped relative to

the ARIL lance.

When the SNCR and dry sodium systems were operated concurrently, an NH3 odor problem was encountered

around the ash silo. Reducing the NH3 slip set points to

the range of 4–5 ppm reduced the ammonia concentrationin the fly ash to the 100–200 ppm range, but the odorpersisted. It was found that the problem was related tothe rapid change in pH due to the presence of sodium inthe ash. The rapid development of the high pH level andthe attendant release of the ammonia vapor appear to berelated to the wetting of the fly ash necessary to minimizefugitive dust emissions during transportation and handling. Handling ash in dry transport trucks solved thisproblem.Economic Performance

The technology is an economical method of obtaining SO2 and NOx reduction on low sulfur coal units.

Total estimated capital costs range from 125–281 $/kWfor capacities ranging from 300–50 MWe. Comparably,wet scrubber and SCR capital costs range from 270–474 $/kW for the same unit size ranges. On a levelizedcost basis, the demonstrated system costs vary from12.43–7.03 mills/kWh (1,746–987 $/ton of SO2 and NOx

removed) compared to wet scrubber and SCR levelizedcosts of 23.34–12.67 mills/kWh (4,974–2,701 $/ton ofSO2 and NOx removed) based on 0.4% sulfur coal. The

integrated system is most efficient on smaller low-sulfurcoal units. As size and sulfur content increases, the costadvantages decrease.Commercial Applications

Either the entire Integrated Dry NOx/SO2 Emissions

Control System or the individual technologies are applicable to most utility and industrial coal-fired units andprovide lower capital-cost alternatives to conventionalwet flue gas desulfurization processes. They can beretrofitted with modest capital investment and downtime,and their space requirements are substantially less. Theycan be applied to any unit size but are mostly applicableto the older, small- to mid-size units.ContactsTerry Hunt, Project Manager, (303) 571-7113

Utility Engineering550 15th Street, Suite 900

Denver, CO 80202-4256

Lawrence Saroff, DOE/HQ, (301) 903-9483Jerry L. Hebb, NETL, (412) 386-6079References• Public Service Company of Colorado. Integrated Dry

NOx/SO2 Emissions Control System. Final Report,

Volume 1: Public Design. November 1997.

• Public Service Company of Colorado. Integrated Dry

NOx/SO2 Emissions Control System. Final Report,

Volume 2: Project Performance and Economics.September 1999.
Environmental Control Devices
tion Project Fact Sheets 2-85

nced Electric Power Generation

Fluidized-Bed Combustion
Advanced Electric Power Generation

eration

PCFB

oject

c

plier of pressurized

B) combustor and heat

poration—supplier of

team turbine

and Electric’s McIntosh

y integrated with

articulate filter system

chnologies

gh-sulfur bituminous

000 100%

864 50

136 50

er’s PCFB technology

use’s ceramic candle

n technologies, which

iciency, low-emissions

ty at greenfield sites or

Technology/Project Description

In the first of the two Lakeland Electric projects,

McIntosh Unit No. 4A will be constructed with a PCFBcombustor adjacent to the existing Unit No. 3 (see alsoMcIntosh Unit 4B Topped PCFB Demonstration Project).

Coal and limestone are mixed and fed into the combustion chamber. Combustion takes place at a temperature of approximately 1,560–1,600 °F and a pressure of

about 200 psig. The resulting flue gas and fly ash leavingthe combustor pass through a cyclone and ceramic candletype HGPFS where the particulates are removed. The hotgas leaving the HGPFS is expanded through a SiemensV64.3 gas turbine. The gas inlet temperature of less than1,650 °F allows for a simplified turbine shaft and bladecooling system. The hot gas leaving the gas turbinepasses through a heat recovery steam generator (HRSG).

Heat recovered from both the combustor and HRSG isused to generate steam to power a reheat steam turbine.Approximately 5–10% of the power is derived from thegas turbine, with the steam turbine contributingthe balance. The project also includes an atmosphericfluidized-bed unit that can be fired on coal or char fromthe carbonizer and will replace the PCFB unit duringtimes of PCFB unavailability, allowing various modes ofoperation.

The projected net heat rate for the system is approximately 9,480 Btu/kWh (HHV), which equates to an efficiency greater than 36%. Environmental attributes include in-situ sulfur removal of 95%, NOx emissions less

than 0.3 lb/106 Btu, and particulate matter discharge less

than 0.03 lb/106 Btu. Solid waste will increase slightly as

compared to conventional systems, but the dry material isreadily disposable or potentially usable.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

tion Project Fact Sheets 2-87

ments

restructuring of the

Project awarded under

7, a Cooperative Agree

mplementing the project

he City of Lakeland. The

roval in April 1998 for

ctric (formerly Depart

s), which included this

on hold while technical

d.

n testing the HGPFS,

mance. Silicon carbide

s proved effective under

e demonstration unit. At

andle filters performed

vels without evidence of

 Three new oxide-based

 well and will undergo

ential for reduced cost

ures.

Commercial Applications

The project serves to demonstrate the PCFB technology for widespread commercial deployment and will

include the first commercial application of hot gas particulate cleanup and one of the first to use a non-ruggedized gas turbine in a pressurized fluidized-bed application.

The combined-cycle PCFB system permits the

combustion of a wide range of coals, including highsulfur coals, and would compete with the pressurizedbubbling-bed fluidized-bed system. The PCFB technology can be used to repower or replace conventionalpower plants. Because of modular construction capability, PCFB generating plants permit utilities to add economical increments of capacity to match load growth orto repower plants using existing coal- and waste-handling equipment and steam turbines. Another advantage for repowering applications is the compactness ofthe process due to pressurized operation, which reducesspace requirements per unit of energy generated.

1992 1993 

1991 1994 1995 1996 1997 1999 2000

Cooperative Agreementawarded 8/1/91

Design and Construction

8/91

Site change approved (Lakeland) 10/29/96

Cooperative Agreement

signed 12/19/97

NEPA process started 3/99

Project on Hold

**Years omitted

**
Advanced Electric Power Generation

eration

Topped PCFB

oject

c

plier of carbonizer;

poration—supplier of

mperature filter

and Electric’s McIntosh

 PCFB technology with

that includes Siemens

rl burner (MASB)

7-MWe (net) McIntosh

gh-sulfur bituminous

546 100%

507 50

039 50

 technology in a fully

ng, thereby advancing

at will operate at higher

will be expected to

s of 45%.

Technology/Project Description

The project involves the addition of a carbonizer

island to the PCFB demonstrated in the McIntosh 4Aproject. Dried coal and limestone are fed via a lock hopper system to the carbonizer with part of the gas turbinedischarge air. The coal is partially gasified at about1,750–1,800 oF to produce syngas and char solidsstreams. The limestone is used to absorb sulfur compounds generated during the mild gasification process.After cooling the syngas to about 1,200 oF, the char andlimestone entrained with the syngas are removed by a hotgas particulate filter system (HGPFS). The char andlimestone are then transferred to the PCFB combustor forcomplete carbon combustion and limestone utilization.The hot, cleaned, filtered syngas is then fired in theMASB topping combustor to raise the turbine inlet temperature to approximately 2,350 °F. The gas is expanded through the turbine, cooled in a heat recovery steam gen- erator, and exhausted to the stack. The net impact of the addition of the topping cycle is an increase in both power output and efficiency. The coal and limestone used in McIntosh 4B are the same as those used in McIntosh 4A. The 240-MWe (net) plant is expected to have a heat rate of 8,406 Btu/kWh (40.6% efficiency, HHV). The design SO2 capture efficiency rate is 95%. Particulate and NOx emissions are expected to be 0.02 lb/106 Btu and 0.17 lb/106 Btu, respectively. In the final configuration, the gas turbine will produce 58 MWe and the steam tur- bine will produce 207 MWe, while plant auxiliaries will consume about 25 MWe.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Project Fact Sheets 2-89

1995

conditions simulating those of the demonstration unit. Atboth 1,550 oF and 1,400 oF, the candle filters performedfor over 1,000 hours at design levels without evidence ofash bridging or structural failure. Three new oxide-basedcandle filters showed promise as well. These will undergofurther testing because of the potential for reduced costand operation at higher temperatures.Commercial Applications

The commercial version of the topped PCFB technology will have a greenfield net plant efficiency of 45%

(which equates to a heat rate approaching 7,500 Btu/kWh,HHV). In addition to higher plant efficiencies, the plantwill (1) have a cost of electricity that is projected to be20% lower than that of a conventional pulverized-coalfired plant with flue gas desulfurization, (2) meet emissionlimits allowed by New Source Performance Standard(NSPS), (3) operate economically on a wide range ofcoals, and (4) be amenable to shop fabrication. The benefits of improved efficiency include reduced cost for fuelsand a reduction in CO2 emissions.

1996 1997 1998 1999 2000 2001 2002 2003

agreement awarded 7/

ve 8/1/94

Design and Construction

Site change approved

(Lakeland) 10/29/96

Project on Hold

ments

estructuring of the Four

oject awarded under the

rs project was to demon

zer (gasifier) and topping

he PCFB technology. By

nd Electric will be able

ntosh 4A) and topped

es at one plant site.

operative Agreement

enting the project re

rgy Partners to the City

Council gave approval in

f Lakeland Electric (for

Water Utilities), which

he project is on hold

ues are resolved.

sting the HGPFS, which

 Silicon carbide and

ved effective under

Cooperative Agreementsigned 1/29/98

The commercial version of the topped PCFB technology has other environmental attributes, which include

in-situ sulfur retention that can meet 95% removal requirements, NOx emissions that will meet or exceed

NSPS, and particulate matter discharge of approximately0.03 lb/106 Btu. Although the system will generate a

slight increase in solid waste compared to conventionalsystems, the material is a dry, readily disposable, andpotentially usable material.

NEPA processstarted 3/99
Advanced Electric Power Generation

eration

CFB

onstration

c Authority)

n—technology supplier

EA’s Northside Station,

ulating fluidized-bed

t)

design)

512 100%

633 24

679 76

5-MWe gross (265-

rom previously con

ations of the

ental, and technical

sers with the data nec

ACFB as a commercial

han 90% SO2 removal;

0% when compared

through the use of a polishing scrubber to be installedahead of the particulate control equipment.

Steam is generated in tubes placed along the

combustor’s walls and superheated in tube bundlesplaced downstream of the particulate separator to protectagainst erosion. The system will produce approximately2 x 106 lb/hr of main steam at about 2,400 psig and

1,005 oF, and 1.73 x 106 lb/hr of reheat steam at 600 psig

and 1,005 oF. The steam will be used in an existing297.5-MWe (nameplate) steam turbine.

The heat rate for the retrofit plant is expected to be

approximately 9,950 Btu/kWh (34% efficiency; HHV).Expected environmental performance is 0.17 lb/106 Btu

for SO2 (98% reduction), 0.11 lb/106 Btu for NOx, and

0.017 lb/106 Btu for total particulates (0.013 lb/106 Btu

for PM10).

Technology/Project Description

A circulating fluidized-bed combustor, operating at

atmospheric pressure, will be retrofitted into Unit No. 2of the Northside Station. Coal or the secondary fuel(petroleum coke), primary air, and a solid sorbent (suchas limestone), are introduced into the lower part of thecombustor where initial combustion occurs. As the coalparticles decrease in size due to combustion, they arecarried higher in the combustor when secondary air isintroduced. As the coal particles continue to be reducedin size, the coal, along with some of the sorbent, is carried out of the combustor, collected in a cyclone separator, and recycled to the lower portion of the combustor.Primary sulfur capture is achieved by the sorbent in thebed. However, additional SO2 capture is achieved

nergy Corp.

CYCLONE

COAL/COKE LIMESTONE

AIR AIR

CONDENSER

INTREX

AIR

ECONOMIZER

FEEDWATER

H.P. STEAM

CIRCULATING

FLUIDIZED-BED BOILER

SECONDARY

AIR

HEATEXCHANGER

BOTTOM

ASH

TO BY-PRODUCT STORAGE

STEAM TURBINE

L.P. STEAM

L.P. STEAM

L.P. STEAM

AIR

PREHEATER

TO BY-PRODUCT STORAGE

GENERATOR

POLISHINGSCRUBBER PARTICULATES

HEATED AIR

TO BOILER

LIME

SLURRY

PARTICULATE

CONTROL

DEVICE

STACK
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Project Fact Sheets 2-91

Environmental monitoring plancompleted 7/01*Preoperational tests started 7/01*

ments

y resited to Jacksonville,

y Partners and Metropoli

activities on the ACFB

August 26, 1997, DOE

FB Clean Coal Project

sonville, Florida. On

d a modified cooperative

e refurbishment of the

Northside Generating

Statement (EIS) process

97 with the Public

 NEPA process of public

raft EIS was prepared and

orating comments and

IS was issued on June

s are addressed, the

d.

The project, currently in design, moves atmospheric

fluidized-bed combustion technology to the larger sizes ofutility boilers typically considered in capacity additionsand replacements. The nominal 300-MWe demonstrationunit in the JEA project will be more than double the sizeof the Nucla unit (110-MWe). Features include an integrated recycle heat exchanger (INTREXTM) in the furnace,steam-cooled cyclones, a parallel pass reheat control, anSO2 polishing scrubber, and a fabric filter for particulate

control.Commercial Applications

ACFB technology has good potential for application

in both the industrial and utility sectors, whether for usein repowering existing plants or in new facilities. ACFBis attractive for both baseload and dispatchable powerapplications because it can be efficiently turned down to25% of full load. Coal of any sulfur or ash content can beused, and any type or size unit can be repowered. Inrepowering applications, an existing plant area is used,and coal- and waste-handling equipment, as well as

1992 1993 1995 1997 1999 2000 2001 2002

Project Restructuring

Operation

and

Reporting

2004

**

ative agreement

d 11/30/90

Project restructured 6/92

Project sited

(York) 6/93

9/97

Project restructured and resited

(Jacksonville) 8/26/97

** **

5/02 5/04

Design and Construction

NEPA process completed

(EIS York site) 8/11/95

Cooperative agreement modified 9/29/97

Operation initiated5/02*

Operation completed 5/04*

Project completed/final report issued 5/04*

Design completed

11/00*

Pre-construction

started

8/99

steam turbine equipment are retained, thereby extendingthe life of a plant.

In its commercial configuration, ACFB technology

offers several potential benefits when compared to conventional pulverized coal-fired systems: lower capitalcosts; reduced SO2 and NOx emissions at lower costs;

higher combustion efficiency; a high degree of fuel flexibility (including use of renewable fuels); and dry, granular solid material that is easily disposed of or potentiallysalable.

Construction completed3/02*

NEPA process completed;

construction started

(EIS Jacksonville site) 8/00*

**
Advanced Electric Power Generation

eration

stration

Corporation—

ager

—technology supplier

ofunder

hio Power Company’s

s pressurized fluidized

nder license from ABB

339 100%

993 35

346 65

C economic, environ

 in a combined-cycle

ale; and to accomplish

 NOx emission level of

Technology/Project Description

Tidd was the first large-scale operational demonstration of PFBC in the United States. The project represented a 13:1 scaleup from the pilot facility.The boiler, cyclones, bed reinjection vessels, and

associated hardware were encapsulated in a pressurevessel 45 feet in diameter and 70 feet high. The facilitywas designed so that one-seventh of the hot gases produced could be routed to an advanced particulatefilter (APF).

The Tidd facility is a bubbling fluidized-bed combustion process operating at 12 atm (175 psi). Pressurized combustion air is supplied by the turbine compressor

to fluidize the bed material, which consists of a coalwater fuel paste, coal ash, and a dolomite or limestone

sorbent. Dolomite or limestone in the bed reacts withsulfur to form calcium sulfate, a dry, granular bed-ashmaterial, which is easily disposed of or is usable as a byproduct. A low bed temperature of about 1,600 oF limitsNO

x

 formation.

The hot combustion gases exit the bed vessel with

entrained ash particles, 98% of which are removed whenthe gases pass through cyclones. The cleaned gases arethen expanded through a 15-MWe gas turbine. Heatfrom the gases exiting the turbine, combined with heatfrom a tube bundle in the fluid bed, generates steam todrive an existing 55-MWe steam turbine.

PRESSURIZED

FLUIDIZED-BED BOILER

PRESSURE

VESSEL

DOLOMITE/

LIMESTONE

COMPRESSED

AIR

AIR

COMBUSTION

TURBINE GEN.

GEN.

BED

VESSEL

COAL

WATER

CLEAN

HOT GAS

STEAM

CYCLONES STEAM TURBINE

BED

PREHEATER CONDENSER

FEED

WATER

WASTE

HEAT

RECOVERY

ELECTROSTATIC

PRECIPITATOR

STACK

TO DISPOSAL

ASH

COOLER

CYCLONE

ASH

BED ASH

FEED WATER

INLET

FLY ASH
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

tion Project Fact Sheets 2-93

effect on SO2 removal

ion and heat transfer

-bed.

% was achieved at full

(Ca/S) molar ratio of

0 oF.

% was achieved at full

of 1.5 and temperature of

3 lb/106 Btu.

0.01 lb/106 Btu.

ss than 0.02 lb/106 Btu.

Operational• Combustion efficiency ranged from an average 99.3%

at low bed levels to an average 99.5% at moderate tofull bed levels.

• Heat rate was 10,280 Btu/kWh (HHV, gross output)

(33.2% efficiency) because the unit was small and noattempt was made to optimize heat recovery.

• An advanced particulate filter (APF), using a silicon

carbide candle filter array, achieved 99.99% filtrationefficiency on a mass basis.

• PFBC boiler demonstrated commercial readiness.• ASEA Stal GT-35P gas turbine proved capable of

operating commercially in a PFBC flue gasenvironment.

Economic• The Tidd plant was a relatively small-scale facility,

and as such, detailed economics were not prepared aspart of this project.

• A recent cost estimate performed on Japan’s 360-

MWe PFBC Karita Plant projected a capital cost of$1,263/kW (1997$).

1988 1989 1990 1991 1992 1993 1994 1995 1996

Design and Construction Operation and Reporting

ment awarded 3/20/87

pleted (MTF) 3/5/87

Environmental monitoringplan completed 5/25/88

Ground breaking ceremony 4/6/88

truction started 12/9/87

Operation initiated 3/91

Design completed 12/90Construction completed 12/90Preoperational tests started 12/90

3/91

/24/86

12/95

Projectcompleted/final reportissued 12/95

Operation completed 3/95
Advanced Electric Power Generation

experienced no widespread erosion that would requiresignificant maintenance. While the tube bundle experienced little wear, a significant amount of erosion on eachof the four water walls was observed. This erosion posedno problem, however, because the area affected is notcritical to heat transfer and could be protected byrefractory.

The prototype gas turbine experienced structural

problems and was the leading cause of unit unavailabilityduring the first 3 years of operation. However, designchanges instituted over the course of the demonstrationproved effective in addressing the problem. The Tidddemonstration showed that a gas turbine could operate ina PFBC flue gas environment.

Efficiency of the PFBC combustion process was

calculated during testing from the amount of unburnedcarbon in cyclone and bed ash, together with measurements of the amount of carbon monoxide in the flue gas.

The PFBC demonstration at the repowered 70-MWe

unit at Ohio Power’s Tidd Plant led to significantrefinements and understanding of the technology.

 a bubbling fluidized

at 12 atmospheres

on is inherently effi

onment enhances com

 temperatures that

promotes flue gas/

bent utilization, and

ed to drive a gas tur

cantly to system effi

cy of gas turbines and

ust heat that can be

design temperature of

t was the maximum

urbine inlet and was

sh fusion, thermal NOx

nch or less was injected

 paste containing 25%

t, either dolomite or

uidized bed via two

m two lock hoppers.

sed two injector nozzles

 nozzles to enhance

nt APF was installed

earch and development

Program demonstration.

ilters to clean one

the PFBC system. The

ed one of the seven

n plant accumulated

ns during its 54 months

95 parametric tests,

ns of 28, 29, 30, 31, and

ving sulfur contents of

ion.

Environmental Performance

Testing showed that 90% SO2 capture was achievable

with a Ca/S molar ratio of 1.14 and that 95% SO2 capture

was possible with a Ca/S molar ratio of 1.5, provided thesize gradation of the sorbent being utilized was optimized.This sulfur retention was achieved at a bed temperature of1,580 oF and full bed height. Limestone induced deterioration of the fluidized-bed, and as a result, testing focusedon dolomite. The testing showed that sulfur capture aswell as sintering was sensitive to the fineness of the dolomite sorbent (Plum Run Greenfield dolomite was thedesign sorbent). Sintering of fluidized-bed materials, afusing of the materials rather than effective reaction, hadbecome a serious problem that required operation at bedtemperatures below the optimum for effective boiler operation. Tests were conducted with sorbent size reducedfrom minus 6 mesh to a minus 12 mesh. The result withthe finer material was a major positive impact on processperformance without the expected excessive elutriation ofsorbent. The finer material increased the fluidizationactivity as evidenced by a 10% improvement in heattransfer rate and an approximately 30% increase in sorbent utilization. In addition, the process was much morestable as indicated by reductions in temperature variationsin both the bed and the evaporator tubes. Furthermore,sintering was effectively eliminated.

NO

x emissions ranged from 0.15–0.33 lb/106 Btu, but

were typically 0.2 lb/106 Btu during the demonstration.

These emissions were inherent in the process, which wasoperating at approximately 1,580 oF. No NOx control

enhancements, such as ammonia injection, were required.Emissions of carbon monoxide and particulates were lessthan 0.01 and 0.02 lb/106 Btu, respectively.

Operational Performance

Except for localized erosion of the in-bed tube bundle

and the more general erosion of the water walls, the Tiddboiler performed extremely well and was considered acommercially viable design. The in-bed tube bundle
tion Project Fact Sheets 2-95

d 99.5% at moderate to

esign or expected effi

oad operation, a heat rate

 was calculated. This

namic efficiency of 33.2%

ed 70-MWe of gross

ittsburgh No. 8 coal.

owering application at a

easured efficiency does

ected for a larger utility

y. Studies conducted

ration Project showed

 likely for a larger, util

t showed that the PFBC

ic power generation.

ct led to significant re

he technology in the

tilization, sintering, post

d boiler materials.

5,800 hours of coal-fired

essel was structurally

n carbide candle filters

 subjected to side loads

he vessel; bridging was

s included in the

efficiency (mass basis)

ely small-scale demon

omics were not prepared

a recent cost estimate

PFBC Karita Plant pro

W (1997$).

Commercial Applications

Combined-cycle PFBC permits use of a wide range

of coals, including high-sulfur coals. The compactness ofbubbling-bed PFBC technology allows utilities to significantly increase capacity at existing sites. Compactness ofthe process due to pressurized operation reduces spacerequirements per unit of energy generated. PFBC technology appears to be best suited for applications of 50 MWeor larger. Capable of being constructed modularly, PFBCgenerating plants permit utilities to add increments ofcapacity economically to match load growth. Plant lifecan be extended by repowering with PFBC using theexisting plant area, coal- and waste-handling equipment,and steam turbine equipment.

The 360-MWe Karita Plant in Japan, which uses

ABB Carbon P800 technology, represents a major movetoward commercialization of PFBC bubbling-bed technology. A second generation P200 PFBC is under construction in Germany. Other PFBC projects are under considCoal and sorbent conveyors can be seen just after

entering the Tidd plant.

eration in China, South Korea, the United Kingdom,Italy, and Israel.

The Tidd project received Power magazine’s 1991

Powerplant Award. In 1992, the project received theNational Energy Resource Organization award for demonstrating energy efficient technology.ContactsMichael J. Mudd, (614) 223-1585

American Electric Power Service Corporation1 Riverside PlazaColumbus, OH 43215(614) 223-2499 (fax)

George Lynch, DOE/HQ, (301) 903-9434Donald W. Geiling, NETL, (304) 285-4784References• Tidd PFBC Hot Gas Cleanup Program Final Report.

Report No. DOE/MC/26042-5130. The Ohio PowerCompany. October 1995. (Available from NTIS asDE96000650.)

• Tidd PFBC Demonstration Project Final Report,

Including Fourth Year of Operation. The Ohio PowerCompany. August 1995. (Available from DOE Library/Morgantown, 1-800-432-8330, ext. 4184 asDE96000623.)

• Tidd PFBC Demonstration Project Final Report,

March 1, 1994–March 30, 1995. Report No. DOE/MC/24132-T8. The Ohio Power Company. August1995. (Available from NTIS as DE96004973.)

• Tidd PFBC Demonstration Project—First Three Years

of Operation. Report No. DOE/MC/24132-5037-Vol.1 and 2. The Ohio Power Company. April 1995.(Available from NTIS as DE96000559 for Vol. 1 andDE96003781 for Vol. 2.)
Advanced Electric Power Generation

mizer. Flue gas passes through a baghouse where particulate matter is removed. Steam generated in theACFB is used to produce electric power.

Three small, coal-fired, stoker-type boilers at Nucla

Station were replaced with a new 925,000-lb/hr ACFBsteam generator capable of driving a new 74-MWeturbine generator. Extraction steam from this turbinegenerator powers three existing turbine generators (12-MWe each).

Technology/Project Description

Nucla’s circulating fluidized-bed system operates at

atmospheric pressure. In the combustion chamber, astream of air fluidizes and entrains a bed of coal, coal ash,and sorbent (e.g., limestone). Relatively low combustion

temperatures limit NOx formation. Calcium in the sorbent

combines with SO2 gas to form calcium sulfite and sulfate

solids, and solids exit the combustion chamber and flowinto a hot cyclone. The cyclone separates the solids fromthe gases, and the solids are recycled for combustor temperature control. Continuous circulation of coal and sorbent improves mixing and extends the contact time ofsolids and gases, thus promoting high utilization of thecoal and high-sulfur-capture efficiency. Heat in the fluegas exiting the hot cyclone is recovered in the econo

eration 

stration 

sion Association, Inc. 

n*—technology 

al users)—cofunder 

—technical consultant 

cla Station) 

ulating fluidized-bed 

sh 

sh 

949 100% 

411 11 

538 89 

 of ACFB technology 

economic, environmen- 

t that scale.

ology developer and supplier,

p.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

tion Project Fact Sheets 2-97

test effect on pollutant

y.

620 oF, sulfur capture

ere achieved at calcium

of 1.5 and 4.0,

ns averaged 0.18 lb/106

b/106 Btu.

0–140 ppmv.

from 0.0072–0.0125

 removal efficiency

enign and showed poten

endment, soil/roadbed

Operational• Boiler efficiency ranged from 85.6–88.6% and combustion efficiency ranged from 96.9–98.9%.• A 3:1 boiler turndown capability was demonstrated.• Heat rate at full load was 11,600 Btu/kWh and was

12,400 Btu/kWh at half load.

Economic• Capital cost for the Nucla retrofit was $1,123/kW

and a normalized power production cost was64 mills/kWh.

1989 1990 1991 1992 1993 1994 1995 1996

Operation and Reporting

1997

ing

88

mpleted (MTF) 4/18/88

Operationcompleted 1/91

est program initiated 8/88

ative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92
Advanced Electric Power Generation

Exhibit 2-33

 Effect of Bed Temperature

on Ca/S Requirement

olved from efforts to

ive to controlling pollut

ntrols. Fluidized-bed

bustion at temperatures

thermal NOx formation

s high SO2-capture

t/flue gas contact.

ional fluid-bed combus

at exchanger in the fluid

ion velocity, ACFB

velocity, which entrains

pture and return the

t bed to control tempera

act time and to protect a

DOE, EPRI, and the

ial users) resulted in the

road utility application

ram. Over a two-and-a

erformance tests were

d. The result was a

mprehensive available

ry 1991, the plant oper

f 58% and an average

toward the end of the

al problems had been

onths of the demonstra

 and the capacity factor

mperature at which

ature was found to be

meter. With the excep

d excess air at elevated

 the only parameter that

ions and efficiency.

Combustion efficiency, a measure of the quantity of

carbon that is fully oxidized to CO2, ranged from

96.9–98.9%. Of the four exit sources of incompletelyburned carbon, the largest was carbon contained in the flyash (93%). The next largest (5%) was carbon containedin the bottom ash stream, and the remaining feed-carbonloss (2%) was incompletely oxidized CO in the flue gas.The fourth possible source, hydrocarbons in the flue gas,was measured and found to be negligible.

Boiler efficiencies for 68 performance tests varied

from 85.6–88.6%. The contributions to boiler heat losswere identified as unburned carbon, sensible heat in dryflue gas, fuel and sorbent moisture, latent heat in burninghydrogen, sorbent calcination, radiation and convection,and bottom-ash cooling water. Net plant heat rate decreased with increasing boiler load, from 12,400 Btu/kWhat 50% of full load to 11,600 Btu/kWh at full load. Thelowest value achieved during a full-load steady-state testwas 10,980 Btu/kWh. These values were affected by the

Ca/S Molar Ratio

Mean Bed Temperature ( F)

1450 1500 1550 1600 1650 1700 1750

6.56.05.55.04.54.03.53.02.52.01.51.0

absence of reheat, the presence of the three older 12.5-MWe turbines in the overall steam cycle, the number ofunit restarts, and part-load testing.Environmental Performance

As indicated above, bed temperature had the greatest

impact on ACFB performance, including pollutant emissions. Exhibit 2-33 shows the effect of bed temperatureson the Ca/S molar ratio requirement for 70% sulfur retention. The Ca/S molar ratios were calculated based on thecalcium content of the sorbent only, and do not accountfor the calcium content of the coal. While a Ca/S molarratio of about 1.5 was sufficient to achieve 70% sulfurretention in the 1,500–1,620 °F range, the Ca/S molarratio requirement jumped to 5.0 or more at 1,700 °F orgreater.

Exhibit 2-34 shows the effect of Ca/S molar ratio on

sulfur retention at average bed temperatures below1,620 oF. Salt Creek and Peabody coals contain 0.5%and 0.7% sulfur, respectively. To achieve 70% SO2

Plant layout with coal and limestone feed locations.
tion Project Fact Sheets 2-99

mission rate required by

molar ratio of approxi

ve an SO2 reduction of

ximately 4.0 is neces

 1.5% sulfur content,

 molar ratio for a given

roughout the demonstra

tu, which is well below

Btu. The average level of

.18 lb/106 Btu. NOx

rong correlation with

ppmv (0.06 lb/106 Btu) at

06 Btu) at 1,700 °F.

ntified as a variable

mewhat higher NOx

ng calcium-to-nitrogen

nism was believed to be

he form of ammonia

e. CO emissions decreased as temperature increased, from 140 ppmv at 1,425 oF to 70 ppmv at 1,700 oF. At full load, the hot cyclones removed 99.8% of the particulates. With the addition of baghouses, removal efficiencies achieved on Peabody and Salt Creek coals were 99.905% and 99.959%, respectively. This equated to emission levels of 0.0125 lb/106 Btu for Peabody coal and 0.0072 lb/106 Btu for Salt Creek coal, well below the required 0.03 lb/106 Btu. Economic Performance The final capital costs associated with the engineering, construction, and startup of the Nucla ACFB system were $112.3 million. This represents a cost of $1,123/kW (net). The total power cost associated with plant operations between September 1988 and January 1991 was approximately $54.7 mil- lion, resulting in a normalized cost of power production of 64 mills/kWh. The average monthly operating cost over this period was about $1,888,000. Fixed costs rep- resent about 62% of the total and include interest (47%), taxes (4.8%), depreciation (6.9%), and insurance (2.7%). Variable costs represent more than 38% of the power production costs and include fuel expenses (26.2%), non- fuel expenses (6.8%), and maintenance expenses (5.5%). Commercial Applications The 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 enabled the resultant technology to be replicated in numerous commercial plants throughout the world. Nucla continues in com- mercial service. Today, every major boiler manufacturer offers an ACFB system in its product line. There are now more than 120 fluidized-bed combustion boilers of varying capacity operating in the U.S. and the technology has made significant market penetration abroad. The fuel flexibility and ease of operation make it a particularly attractive power generation option for the burgeoning power market in developing countries. Contacts Stuart Bush, (303) 452-6111 Tri-State Generation and Transmission Ass’n., Inc. P.O. Box 33695 Denver, CO 80233 (303) 254-6066 (fax) George Lynch, DOE/HQ, (301) 903-9434 Thomas Sarkus, NETL, (412) 386-5981 References

• Colorado-Ute Nucla Station Circulating FluidizedBed (CFB) Demonstration—Volume 2: Test Program

Results. EPRI Report No. GS-7483. October 1991.

• Demonstration Program Performance Test: Summary

Reports. Report No. DOE/MC/25137-3104. Colorado-Ute Electric Association, Inc. March 1992.(Available from NTIS as DE92001299.)

• Economic Evaluation Report: Topical Report. Report

No. DOE/MC/25137-3127. Colorado-Ute ElectricAssociation, Inc., March 1992. (Available from NTISas DE93000212.)

• Nucla CFB Demonstration Project: Detailed Public

Design Report. Report No. DOE/MC/25137-2999.Colorado-Ute Electric Association, Inc., December1990. (Available from NTIS as DE91002081.)

bit 2-34

quirements and

s for Various Fuels
Advanced Electric Power Generation
tion Project Fact Sheets 2-101

anced Electric Power Generation

ated Gasification Combined-Cycle
Advanced Electric Power Generation

eration

ed-Cycle

Energy IGCC

oject

nergy Research Corpora

designer and supplier,

ntucky Power

ycle (IGCC) using a

slagging fixed-bed

uel Cell Energy’s mol

MCFC

coal blended with mu

714 100%

357 18

225 82

e reliability, availability,

le IGCC system using a

unicipal solid waste

ed, slagging gasifier

bonate fuel cell fueled

Technology/Project Description

The BGL gasifier is supplied with steam, oxygen,

limestone flux, and a coal and municipal waste blend.During gasification, the oxygen and steam react with thecoal and limestone flux to produce a coal-derived fuel gasrich in hydrogen and carbon monoxide. Raw fuel gasexiting the gasifier is washed and cooled. Hydrogensulfide and other sulfur compounds are removed. Elemental sulfur is reclaimed and sold as a by-product.Tars, oils, and dust are recycled to the gasifier. The resulting clean, medium-Btu fuel gas fires a gas turbine. Asmall portion of the clean fuel gas is used for the MCFC.

The MCFC is composed of a molten carbonate

electrolyte sandwiched between porous anode and cathode plates. Fuel (desulfurized, heated medium-Btu fuelgas) and steam are fed continuously into the anode;

CO2-enriched air is fed into the cathode. Chemical

reactions produce direct electric current, which is converted to alternating power with an inverter.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Project Fact Sheets 2-103

1998 1999 

1994 2000 2001 2002 2003 2004 2005

award

ments

onditionally approved

ger of Union Electric Co.

ce Co.) as an equity part

 to completing specific

. The new project site to

eir Venice Station Plant

1999, Ameren Services

ect for economic and

y USA Limited (Global),

Energy, LLC (KPE),

e project and providing a

 Cooperative’s Smith

Subsequently, Global

ments with DOE and

P) to acquire the project.

ve agreement was no

ved.

ative Agreement

d 12/2/94

Design and Construction

The NEPA process was initiated with the public

scoping meeting on May 4, 2000. Comments from themeeting are being used in preparing the draft EIS, whichshould be released in late 2000.Commercial Applications

The IGCC system being demonstrated in this project

is suitable for both repowering applications and newpower plants. The technology is expected to be adaptableto a wide variety of potential market applications becauseof several factors. First, the BGL gasification technologyhas successfully used a wide variety of U.S. coals. Also,the highly modular approach to system design makes theBGL-based IGCC and MCFC competitive in a widerange of plant sizes. In addition, the high efficiency andexcellent environmental performance of the system arecompetitive with or superior to other fossil-fuel-firedpower generation technologies.

The heat rate of the IGCC demonstration facility is

projected to be 8,560 Btu/kWh (40% efficiency) and the

12/94 7/03 Operation and

Reporting

Operation initiated 7/03*

Final report issued/projectcompleted 7/04*

**

Novation of cooperativeagreement; New siteapproved 11/99 New site approved 5/98

commercial embodiment of the system has a projectedheat rate of 8,035 Btu/kWh (42.5% efficiency). Thecommercial version of the molten carbonate fuel cellfueled by a BGL gasifier is anticipated to have a heat rateof 7,379 Btu/kWh (46.2% efficiency). These efficienciesrepresent a greater than 20% reduction in emissions ofCO2 when compared to a conventional pulverized coalplant equipped with a scrubber. SO2 emissions from the

IGCC system are expected to be less than 0.1 lb/106 Btu

(99% reduction); and NOx emissions less than 0.15 lb/106

Btu (90% reduction).

Also, the slagging characteristic of the gasifier produces a nonleaching, glass-like slag that can be marketed

as a usable by-product.

7/04

Site withdrawn Construction started 2/01*

4/99

EIS processinitiated 5/00*
Advanced Electric Power Generation

eration

ed-Cycle

Power

—architect, engineer,

hnology supplier

ineer

Pacific Power

ycle (IGCC) using the

zed-bed coal gasifica

9% sulfur (design coal);

planned test)

000 100%

500 50

500 50

ssurized fluidized-bed

ot gas cleanup; to

n turbine; and to assess

maintainability, and

ale sufficient to deter

Technology/Project Description

Dried and crushed coal and limestone are introduced

into a KRW air-blown pressurized fluidized-bed gasifier.Crushed limestone is used to capture a portion of thesulfur. The sulfur reacts with the limestone to form calcium sulfide which, after oxidation, exits as calciumsulfate along with the coal ash in the form of agglomerated particles suitable for landfill.

Low-Btu coal gas leaving the gasifier passes

through cyclones, which return most of the entrainedparticulate matter to the gasifier. The gas, which leavesthe gasifier at about 1,700 oF, is cooled to about 1,100 oFbefore entering the hot gas cleanup system. Duringcleanup, virtually all of the remaining particulates areremoved by ceramic candle filters, and final traces ofsulfur are removed by reaction with a metal oxide sorbentin a transport reactor.

The cleaned gas then enters the GE MS6001FA

(Frame 6FA) combustion turbine, which is coupled to a61-MWe (gross) generator. Exhaust gas from the combustion turbine is used to produce steam in a heat recovery steam generator (HRSG). Superheated high-pressuresteam drives a condensing steam turbine-generator designed to produce about 46 MWe (gross).

The IGCC plant will remove 95+% of the sulfur in

the coal. Due to the relatively low operating temperatureof the gasifier and the injection of steam into the combustion fuel stream, the NOx emissions are expected to be

70% less than a conventional coal-fired plant. The IGCCwill produce 20% less CO2 than conventional plants.

COAL & LIMESTONE

HANDLING

SOLID WASTE

AGGLOMERATES

FLUIDIZED-BED

GASIFIER

CYCLONE

STEAM TO HRSG

GAS

COOLER

HOTGAS

CLEANUP

SULFUR

REMOVAL

AIR

AIR

STEAM

COMP.

COMBUSTION TURBINE

STEAM FROM

GAS COOLER

FEED

WATER STEAM

HOT GAS

STACK

HEAT RECOVERY

STEAM

GENERATOR

STEAM

GEN.

STEAM TURBINE

GEN.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

tion Project Fact Sheets 2-105

1993 1994 1995 1996 1997 1998 1999 2000 2001

Design and Construction Operation and Reporting

1/01

e agreement awarded 8/1/92

Project completed/final report issued 1/01*

Operation completed 1/01*

Ground breaking/construction started 2/95

NEPA process completed (EIS) 11/8/94

Design completed 8/95

provements include increasing the diameter to the annulus section of the gasifier to address the problem of hightemperatures of the limestone and ash leaving the gasifier. Also, the refractory in the gasifier grid area and 18feet into the fluid bed region will be replaced with asingle castable layer on a revised anchoring pattern, toprovide improved resistance to low cycle fatigue of therefractory lining. Sierra Pacific expects to restart theplant in August 2000.

Sierra Pacific’s 2000 performance goals include:

demonstrate a 90% combined-cycle availability;achieve stable, sustained production of syngas; demonstrate sustained operation on syngas; and successfullyrun the gas turbine on syngas.Commercial ApplicationsThe Piñon Pine IGCC system concept is suitable for newpower generation, repowering needs, and cogenerationapplications. The net heat rate for a proposed greenfieldplant using this technology is projected to be 7,800 Btu/kWh (43.7% efficiency), representing a 20% increase in

ments

monstration operations

ational difficulties. The

al gas in November 1996.

down of the coal gasifica

inued through 1997 with

8. The plant was dedi

ffer from a number of

ve been solved, but

een attributed to the

high scale-up factors on

 design and engineering

ra Pacific is confident

 preclude successful

ommercialization of the

Sierra Pacific began to

rovements so that sus

an be achieved. ImEnvironmental monitoring plan completed 10/31/96

Preoperational tests initiated 11/96

1/98

Operation initiated 1/98

Construction completed 2/97

thermal efficiency compared to a conventional pulverized coal plant with a scrubber and a comparable reduction in CO2 emissions. The compactness of an IGCC

system reduces space requirements per unit of energygenerated relative to other coal-based power generationsystems. The advantages provided by phased modularconstruction reduce the financial risk associated withnew capacity additions.

The KRW IGCC technology is capable of gasifying

all types of coals, including high-sulfur, high-ash, lowrank, and high-swelling coals, as well as biowaste orrefuse-derived waste, with minimal environmental impact. There are no significant process waste streams thatrequire remediation. The only solid waste from the plantis a mixture of ash and calcium sulfate, a nonhazardouswaste.
Advanced Electric Power Generation

eration

ed-Cycle

egrated

bined-Cycle

—gasification

mbined-cycle

—air separation unit

Inc.—sulfuric acid

n—project manager and

tect and engineer

a Electric Company’s

ombined-cycle (IGCC)

 oxygen-blown en

y # 11, and Kentucky

446 100%

223 49

223 51

Project Objective

To demonstrate IGCC technology in a greenfield

commercial electric utility application at the 250-MWesize using an 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 Description

Coal/water slurry and oxygen are reacted at high

temperature and pressure to produce a medium-Btu syngas in a Texaco gasifier. Molten ash flows out of thebottom of the gasifier into a water-filled sump where itforms a solid slag. The syngas moves from the gasifierto a high temperature heat-recovery unit, which cools thesyngas while generating high pressure steam. Thecooled gases flow to a water wash for particulate removal. Next, a COS hydrolysis reactor converts one of the sulfur species in the gas to a form which is more easily removed. The syngas is then further cooled before entering a conventional amine sulfur removal system. The amine system keeps SO2 emissions below 0.15 lb/ 106 Btu (97% capture). The cleaned gases are then re- heated and routed to a combined-cycle system for power generation. A GE MS 7001FA gas turbine generates 192 MWe. Thermal NOx is controlled to below 0.27 lb/ 106 Btu by injecting nitrogen. A steam turbine uses steam produced by cooling the syngas and superheated with the gas turbine exhaust gases in the HRSG to produce an additional 124-MWe. The plant heat rate is 9,350 Btu/ kWh (HHV).

- - - - Future
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Project Fact Sheets 2-107

1990 1991 1994 1995 1996 1997 1998 1999 2001

Preaward Design and Construction

3/91

**

selected project (CCT-III) 12/19/89

Cooperative agreement awarded 3/11/91

Preoperational tests initiated 6/96

Construction completed 8/96

Operation initiated 9/96

9/96

Design completed 8/94NEPA process completed (EIS) 8/17/94Construction started 8/94

Project completed/final report issued 10/01*

Operation completed 10/01*

10/01

Operation and Reporting

Environmental monitoring plan completed 5/96

**

3 4

ments

first gasifier run in July

ver 18,500 hours. The

llion MWh of electricity

 March 2000. During one

d an 83.5% on-stream

vailability was 94%.

e original design and

hieve the recent high

ving or modifying some

gh temperature heat

mpensating adjustments

resolve ash plugging

article erosion protec

to protect the machine

 restart procedures to

8 hours, (4) adding a

 to deal with increased

wer than expected car

erating procedures to

deal with high shell temperatures in the dome of theradiant syngas cooler, and (6) making various pipingchanges to correct for erosion and corrosion in theprocess and coal/water slurry systems. A COS hydrolysis unit was installed in 1999 to further reduceSO2 emissions, enabling the station to meet recent,

more stringent emissions restrictions.

In March and April 2000, Tampa Electric tested

several coal/petroleum coke blends. Preliminary testresults from 60/40 and 40/60 blends of Pittsburgh #8 andpetroleum coke (petcoke) looked promising. Both testswere successful and provide data that show continuedoperation on a blend of coal/petcoke is possible. Onefurther test is planned using a 20/80 blend.Commercial Applications

The project was presented the 1997 Powerplant

Award by Power magazine. In 1996 the project receivedthe Association of Builders and Contractors award forconstruction quality. Several awards were presented forusing an innovative siting process: 1993 Ecological

Society of America Corporate Award, 1993 Timer Powers Conflict Resolution Award from the State of Florida,and the 1991 Florida Audubon Society Corporate Award.

As a result of the Polk Power Station demonstration,

Texaco-based IGCC can be considered commercially andenvironmentally suitable for electric power generationutilizing a wide variety of feedstocks. Sulfur capture forthe project is greater than 98%, while NOx emissions

reductions are 90% those of a conventional pulverizedcoal-fired power plant. The integration and control approaches utilized at Polk can also be applied in IGCCprojects using different gasification technologies.

TECO Energy is not only actively working with

Texaco to commercialize the technology in the UnitedStates, but has been contacted by European power producers to discuss possible technical assistance on using thegasifier technology.
Advanced Electric Power Generation

eration

ed-Cycle

l

wering

epowering Project Joint

 and PSI Energy, Inc.)

Inc., a subsidiary of

engineer and gas plant

N (PSI Energy’s Wabash

. 1)

ycle (IGCC) using

ized, oxygen-blown,

—E-Gas TechnologyTM

000 100%

000 50

000 50

ring with a two-stage

ned-flow IGCC system,

hnology relevant to the

; and to assess longterm reliability, availability, and maintainability of the system at a fully commercial scale. Technology/Project Description The Destec process features an oxygen-blown, con- tinuous-slagging, two-stage, entrained flow gasifier. Coal is slurried, combined with 95% pure oxygen, and injected into the first stage of the gasifier, which operates at 2,600 °F/400 psig. In the first stage, the coal slurry un- dergoes a partial oxidation reaction 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 addi- tional 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 the syngas cooler, essen- tially a firetube steam generator, to produce high-pressure saturated steam. After cooling in the syngas cooler, par- ticulates are removed in a hot/dry filter and recycled to the gasifier. The syngas is further cooled in a series of heat exchangers. The syngas is water-scrubbed to remove chlorides and passed through a catalyst that hydrolyzes carbonyl sulfide into hydrogen sulfide. Hydrogen sulfide is removed in the acid gas removal system using MDEA- based absorber/stripper columns. A Claus unit is used to produce elemental sulfur as a salable by-product. The “sweet” gas is then moisturized, preheated, and piped to the power block. The power block consists of a single 192-MWe GE MS 7001FA (Frame 7 FA) gas turbine, a Foster Wheeler single-drum heat recovery steam generator with reheat, and a 1952 vintage Westinghouse reheat steam turbine.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

tion Project Fact Sheets 2-109

1993 1994 1995 1996 1997 1998 1999 2000 2001

Operation and Reporting

Design and Construction

NEPA process completed (EA) 5/28/93

Design completed 5/94

greement awarded 7/28/92

Environmental monitoring plan completed 7/9/93Groundbreaking ceremony 7/7/93

Preoperational tests initiated 8/95

11/95 9/00

Demonstration completed 12/99

Construction completed 11/95Operation initiated 11/95

Project completed/final reportissued 9/00*

eater than 99%, keeping

low 0.1 lb/106 Btu and

 Btu; and SO2 was trans

ur, a highly valued by

d by steam injection

ow-carbon vitreous slag,

alued as an aggregate in

asives and roofing mate

etroleum coke were also

ag.

ed included:

ube boiler inlet, which was

e flow path geometry;

- Particulate breakthrough in the hot gas filter, which

was largely solved by changing to improved metallic candle filters.

- Chloride and metals poisoning of the COS catalyst,

which was eliminated by installation of a wet chloride scrubber and a COS catalyst less prone topoisoning.

• The second year identified cracking in the gas turbine

combustion liners and tube leaks in the heat recoverysteam generator (HRSG). Resolution involved replacement of the gas turbine fuel nozzles and liners andmodifications to the HRSG to allow for more tubeexpansion.

• The third year was essentially trouble free and the

IGCC unit underwent fuel flexibility tests, whichshowed that the unit operated trouble free, withoutmodification, on a second coal feedstock, a blend oftwo different Illinois #6 coals, and petroleum coke.

• Overall thermal performance actually improved during

petroleum coke operation.

• In the fourth year, the gas turbine incurred damage to

rows 14 through 17 of the compressor causing a 3-month outage. But over the four years of operation,availability of the gasification plant steadily improvedreaching 79.1% in 1999.

Economic Performance• Overall cost of the gasification and power generation

facilities was $417 million, including engineering andenvironmental studies, equipment procurement, construction, pre-operations management, and start-up.

• Preliminary estimates for a future dual-train facility are

$1,200/kW. Costs could fall to under $1,000/kW for agreenfield plant with advances in turbine technology.
Advanced Electric Power Generation

fication Repowering

 pulverized coal-fired

a nominally 33% effi

y 40% efficient 262-

ent company, dis

th a demonstrated heat

ond only to their hydro

vironmental emissions

advanced gasification

d features contributed

e include: (1) hot/dry

leanup without heat

high temperature heat

gas turbine-connected

onditions for the steam

de (COS) hydrolysis

sulfur removal, (4)

carbon recovery, (5) use

r requirements for the

sturization to reduce

Ox control.

tion period starting in

ted approximately

ximately 1.5 million

1012 Btu of syngas. For

duction exceeded one

he final year of opera

262-MWe IGCC unit

nds equivalent of SO2

.

s plagued primarily by

at the inlet to the fire

rough in the hot gas

metals poisoning of the

e hot gas path flow

tion problem. Replacement of the ceramic candle filters with metallic candles proved to be largely successful. A follow-on metallic candle filter development effort ensued using a hot gas slipstream, which resulted in improved candle filter met- allurgy, blinding rates, and cleaning techniques. The combined effort all but eliminated downtime associated with the filter system by the close of 1998. Installation of a wet chloride scrubber eliminated the chloride problem by September 1996 and use of an alternate COS catalyst less prone to trace metal poisoning provided the final cure for the COS system by October 1997. The second year of operation identified cracking problems with the gas turbine combustion liners and tube leaks in the HRSG. Replacement of the fuel nozzles and liners solved the cracking problem. Resolu- tion 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 nuisance items such as instrumentation induced trips in the oxygen plant and high maintenance items such as replacement of high pressure slurry burners every 40–50 days. In the third year, the IGCC unit underwent fuel flexibility tests. The unit operated effectively, without modification or incident, on a second coal feedstock, a blend of two dif- ferent Illinois #6 coals, and petroleum coke (petcoke). These tests added to the fuel flexibility portfolio of the gasifier, which had previously processed both lignite and subbituminous coals during its earlier development. The overall thermal performance of the IGCC unit actually improved during petcoke operation. The unit processed over 18,000 tons of high sulfur petcoke and produced 350,000 x 106 Btu of syngas. There was a negligible amount of tar production and no problems were encoun- tered in removing the dry char particulate despite a higher dust loading. Exhibit 2-35 provides a summary of the thermal performance of the unit on both coal and petcoke. Exhibit 2-36 compares the coal and petcoke fuel charac- teristics and Exhibit 2-37 compares the syngas product. The fourth year of operation was marred by a 3- month outage due to damage incurred to rows 14 through 17 of the gas turbine air compressor. However, over the four years of operation, availability of the gasification plant steadily improved, reaching 79.1% in 1999. Environmental Performance The IGCC unit operates with an SO2 capture effi- ciency greater than 99%. As a result, SO2 emissions are consistently below 0.1 lb/106 Btu of coal input, reaching as low as 0.03 lb/106 Btu. Moreover, the process trans- forms the SO2 pollutant into 99.99% pure sulfur, a highly valued by-product, rather than a solid waste. Steam injection controls NOx emissions down to 0.15 lb/106 Btu. This is the emission limit being sought under the EPA SIP call related to ozone nonattainment areas. Also, particulate emissions are below detection limits.The ash component of the coal results in a low-car- bon vitreous slag, impervious to leaching and valued as an aggregate in construction or as grit for abrasives and roofing materials. Also, the trace metal constituents in the petcoke were effectively captured in the slag produced. Economic Performance The economic performance of the IGCC unit will be forthcoming in the Final Technical Report currently in preparation. Some preliminary information presented here was drawn from technical papers prepared over the course of the demonstration. The overall combined cost of the gasification and power generation facilities was $417 million at comple- tion. This cost includes engineering and environmental studies, equipment procurement, construction, pre-opera- tions management (including operator training), and start- up. Escalation during the project is included. Start-up includes the costs of construction and operations, exclud- ing coal and power, up to the date of commercial opera- tion in December 1995. Soft costs such as legal and fi- nancing fees and interest during construction are not

included.
tion Project Fact Sheets 2-111

future costs of $1,200/

lities, and greenfield

ances in turbine technol

tion in December 1999,

ynegy’s gasification

nergy plans to market the

as TechnologyTM.”

Gas TechnologyTM ap

 domestic applications

as petcoke can be used

forded such as bundled

cals, and electricity.

finery operations are

ology has application to

We of existing U.S. coal

nd new foreign and do

ns. Over time, the eco

chnology will continue

fferentials will increase,

n chemicals and fuels

rtance.

03-9434

386-5814

River in Its Fourth Year of

Clean Coal Technology

cal Papers. June 1999.

Exhibit 2-35

Wabash Thermal Performance Summary

Design Actual

Coal Coal Petcoke

Nominal Throughput, tons/day 2,550 2,450 2,000Syngas Capacity, 106 Btu/hr 1,780 1,690 1,690Combustion Turbine, MW 192 192 192Steam Turbine, MW 105 96 96Auxiliary Power, MW 35 36 36Net Generation, MW 262 261 261Plant Efficiency, % (HHV) 37.8 39.7 40.2Sulfur Removal Efficiency, % >98 >99 >99

Exhibit 2-36

Wabash Fuel Analysis

Typical Coal Petcoke

Moisture, % 15.2 7.0

Ash, % 12.0 0.3

Volatile, % 32.8 12.4

Fixed Carbon, % 39.9 80.4

Sulfur, % 1.9 5.2

Heating Value, as Rec’d, Btu/lb 10,536 14,282

Exhibit 2-37

Wabash Product Syngas Analysis

Typical Coal Petcoke

Nitrogen, vol % 1.9 1.9

Argon, vol % 0.6 0.6

Carbon Dioxide, vol % 15.8 15.4

Carbon Monoxide, vol % 45.3 48.6

Hydrogen, vol % 34.4 33.2

Methane, vol % 1.9 0.5

Total Sulfur, ppmv 68 69

Higher Heating Value, Btu/scf 277 268
Advanced Electric Power Generation
tion Project Fact Sheets 2-113

anced Electric Power Generation

anced Combustion/Heat Engines
Advanced Electric Power Generation

Technology/Project Description

The project is based on the demonstration of an 18-

cylinder, heavy duty engine (6.4-MWe) modified to operate on Alaskan subbituminous coal. The clean coal dieseltechnology, which uses a low-rank coal-water-fuel(LRCWF), is expected to have very low NOx and SO2emission levels (50–70% below current New SourcePerformance Standards). In addition, the demonstrationplant is expected to achieve 41% efficiency and futureplant designs are expected to reach 48% efficiency. Thiswill result in a 25% reduction in CO2 emissions comparedto conventional coal-fired plants.

eration

ngines

oject

—host and cofunder

undation—cofunder

ne technology vendor

ch Center, University of

eparation technology

er, designer, constructor

pplier

ka facility)

000 100%

000 50

000 50

ty, and durability of the

urs of operation and

SLURRY

PLANT

COAL

WATER

EXHAUST

GAS WASTE HEAT

BOILER

STEAM FOR

SPACE HEATING

FGD/

SCR

BAGHOUSE

STACK

GEN.

SHAFT

COAL-FUELED POWER

DIESEL ENGINE
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

tion Project Fact Sheets 2-115

1996 1997 

1994 1998 1999 2000 2002 2003 2004

7/94

ject

Cooperative agreementawarded 7/12/94

Design and Construction

ments

gn was completed in early

gine arrived on site at

ounted in the engine

er 1999, the engine, after

, was operated on diesel

coupled with the genera

tartup was attempted on

h system integration and

bus system were encoun

 corrected and system

mmence Fall 2000. Upon

the diesel engine will be

esign of the hardened

n and testing, and

SNCR system are in

m Easton, Maryland to

oal will now be used to

lli Coal Mine, Inc. will

NEPA processcompleted (EA)6/2/97

Construction started 6/98

Environmental monitoring

plan completed 2/99

Coal Diesel Operation initiated 6/02*

6/02 4/04

Project completed/final

report issued 4/04*

Operation

completed 1/04*

Operation

and Reporting

Project

restructured 8/96

Design completed 1/99

Coaltec two-cylinder engine

test on LRCWF 10/00*

supply the coal. Samples of the coal have been sent toCQ Inc. for analysis and washability tests. ADL andEERC will also perform various analyses on the coal.Upon completion of the tests, a design formula will bedevised to produce the LRCWF. The LRCWF will firstbe tested in Coltec two-cylinder test engine. Thesetests are scheduled for the Fall 2000. The tests on thetest engine will provide information and data on how tooptimize the operational settings, verify the coal fuelperformance, and finalize the requirements for hardenedcoatings for critical components.Commercial Applications

The U.S. diesel market is projected to exceed

60,000 MWe (over 7,000 engines) through 2020. Theworldwide market is 70 times the U.S. market. The technology is particularly applicable to distributed powergeneration in the 5- to 20-MWe range, using indigenouscoal in developing countries.

The net effective heat rate for the mature diesel

system is expected to be 6,830 Btu/kWh (48%), whichmakes it very competitive with similarly sized coal- andfuel oil-fired installations. Environmental emissionsfrom commercial diesel systems should be reduced tolevels between 50% and 70% below NSPS. The estimated installation cost of a mature commercial unit isapproximately $1,300/kW.

** **
Advanced Electric Power Generation

eration

ngines

Project

d Export Authority

n—host and operator

orp.—engineer

ivision—combustor

(B&W) (which has

mental Technologies,

hnology supplier

pplier

ent to Healy Unit No. 1)

bustor; Babcock &

A) with sorbent recycle

f-mine (ROM) and

)

000 100%

000 48

000 52

 new power plant de

vanced combustor and

h both high- and low

cesses.

water-cooled walls and is driven by aerodynamic andgravitational forces through a slot into the slag recoverysection. About 70–80% of the ash is removed as moltenslag. The hot gas is then ducted to the furnace where, toensure complete combustion, additional air is suppliedfrom a tertiary air windbox to NOx ports and to final overfire air ports. Pulverized limestone (CaCO3) for SO2

control is fed into the combustors where it is flash calcined (converting CaCO3 to lime (CaO). The mixture of

this CaO and ash that was not removed in the combustor,called flash-calcined material, is removed in the fabricfilter system. Most of the flash-calcined material is usedto form a 45% solids slurry, which is injected into thespray dryer. The SO2 in the flue gas reacts with the slurry

droplets as water is simultaneously evaporated. The SO2

is further removed from the flue gas by reacting with thedry flash-calcined-material on the baghouse filter bags.

Technology/Project Description

The project involves two unique slagging combustors.

Emissions are controlled using TRW’s slagging combustion systems 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. Theslagging combustors are bottom mounted, injecting thecombustion products into the boiler. The main slaggingcombustor consists of a water-cooled cylinder that slopestoward a slag opening. The precombustor burns 25–40%of the total coal input. The remaining coal is injectedaxially into the combustor, rapidly entrained by the swirling precombustor gases and additional air flow, andburned under substoichiometric conditions for NO

x

 control. The ash forms molten slag, which flows along the
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

**Years omitted

tion Project Fact Sheets 2-117

.208–0.278 lb/106 Btu,

5 lb/106 Btu on a 30-day

 below the permit limit

ng day average.

tly less than 0.09 lb/106

f 0.038 lb/106 Btu, which

0.10 lb/106 Btu (3-hour

s in excess of 90% were

 and Ca/S molar ratios of

ions were 0.0047 lb/106

permit limit of 0.02 lb/

130 ppm at 3.0% O2,

40 ppm at 3.0% O2,

it limit of 202 ppm at

1993 1994 1995 1997 1998 1999 2000 2001 2002

Design and Construction

Operation and Reporting

1/98

DOE cost-shared operationcompleted 12/99

Operation initiated 1/98

Preoperational testsinitiated 8/97

pleted (EIS) 3/10/94

leted 10/93

Ground breaking/

construction

started 5/30/95 Environmental monitoring

plan completed 4/11/97

Constructioncompleted 11/97

Project completed/final reportissued 12/00*

**

12/00

• Tests showed that the SDA system SO2 emissions, PM

emissions, and opacity were well within guarantees.

Operational• Carbon burnout contract goals were achieved—greater

than 99% carbon burnout at 100% maximum continuous rating (MCR) for the performance, ROM, and 55/45 blend of ROM/waste coal. The carbon burnout wastypically 99.7%.

• The contract goal for slag recovery greater than 70%

at 100% MCR for all coals was also achieved. Slagrecovery ranged from 78–87%, with a typical recoveryof 83%.

• During a 90-day test in the second half of 1999, the

plant availability was 97% at a capacity factor of 95%.

• The SDA pressure drops and power consumption were

well below guarantee levels.

Economic• Economic data are not yet available.
Advanced Electric Power Generation

t is the first utility-scale

ed entrained (slagging)

acent to the existing

ka and the Usibelli

e Golden Valley Elec

signed to minimize

on burnout, and remove

ue gas prior to the

 also the first step of a

SO2 by first converting

econd, the flash cal

boiler. Third, the

th B&W’s SDA sys

 lime and fly ash cap

ost of the coal ash is

ors, the recycled mate

ent that the SDA can be

ids, eliminating the

me for the back end

th combustion system

ts were performed to

he combustion system

ste coal blends, to map

stics over a broad range

are configurations, and

n and operating condi

oughout the testing

 and CO emission

 of short-term SO2 and

p and repairs. The

SPS requirements, are

A system conducted in

ogy performed well.

DA outlet, stack, limestone feed, coal feed, air preheater hopper ash, surge bin ash, electrical power consumption, and stack opacity, as well as normal plant data from the plant distributed con- trol system, showed that the technology exceeds the guar- antees. The results of the tests and the performance guar- antees are shown in Exhibit 2-39. Operational Performance The slagging stage of the combustor performed ex- tremely well and continuously demonstrated the capability to burn both ROM and ROM/waste coal blends over a broad range of operating conditions. The precombustor performed very well with ROM coal, but exhibited more variable performance, in terms of slagging behavior, dur- ing the initial tests with ROM/waste coal blends. Localized slag freezing was observed in the precom- bustor during early testing. A combination of hardware configuration and operational configuration changes were made that successfully minimized slag freezing. These changes included relocating the secondary air from the precombustor mix annulus to 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 the mixing of excess air down- stream of the precombustor chamber to minimize local slag freezing and increased the precombustor operating temperature in order to provide additional temperature margin. The mill air change had the added benefit of simplifying combustor operation by eliminating the need to monitor and control coal-laden mill air flow to the precombustor mill air ports during steady-state operation. Testing of the slagging combustor also showed that the contract goals were achieved, which included greater than 99% carbon burnout at 100% MCR for the perfor- mance, ROM, and 55/45 blend of ROM/waste coal and greater than 98% carbon burnout 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 the contract goal for slag recovery of greater than 70% at 100% MCR for all coals. The SDA system also performed well. During per- formance testing in June 1999, system pressure drops were well below the 13 in. W.G. guarantee. The range was 9.6–10.0 in. W.G. as can be seen in Exhibit 2-39. Power consumption was approximately 38–41% less than the guaranteed level. Based on these results, Stone & Webster concluded that the SDA system met all perfor- mance guarantees. Economic Performance Economic data are not yet available. Commercial Applications This technology is appropriate for any size utility or industrial boiler in new or retrofit uses. It can be used in coal-fired boilers as well as in oil- and gas-fired boilers because of its high ash-removal capability. However, cy- clone boilers may be the most amenable type to retrofit with the slagging combustor because of the limited supply of high-Btu, low-sulfur, low-ash-fusion-temperature coal that cyclone boilers require. The commercial availability of cost-effective and reliable systems for SO2, NOx, and par- ticulate control is important to potential users planning new capacity, repowering, or retrofits to existing capacity in order to comply with CAAA requirements. Contacts Arthur E. Copoulos, Project Manager, (907) 269-3029 Alaska Industrial Development and Export Authority 480 West Tudor Road Anchorage, AK 99503-6690 (907) 269-3044 (fax) George Lynch, DOE/HQ, (301) 903-9434 Robert M. Kornosky, NETL, (412) 386-4521 References • TRW, Inc. Healy Clean Coal Project (HCCP) Dem- onstration Program Topical Report: Combustion System Operation Final Report. March 31, 2000. • Stone & Webster Engineering Corporation. Spray Dryer Absorber System Performance Test Report:

June 7-11, 1999. February 2000.
tion Project Fact Sheets 2-119

with premature filter bag failures in the baghouse.

esting equipment failure.

 Exhibit 2-39

Healy SDA Performance Test Results and Performance Guarantees

Parameter Values

ntee Test 1 Test 3a Test 4 Test 5 Test 6 Test 7 Test 8 Test 9

/hr (max) <2.01 <2.07 <2.13 <2.15 <2.10 <2.13 <2.13 <2.15

b/106 Btu 0.0023 0.0042 0.0052 0.0040 0.0027 0.0030 0.0014 0.0034

pacity (3 minute 1.3–1.5 1.3–1.7 1.5–1.7 1.5–1.7 1.1–1.4 1.0–2.0 1.3–1.5 1.3–1.5

7% Opacity

minutes per hour

hes W.C. 10.0 10.5 9.6 9.7 9.8 9.9 9.8 9.9

kW 334 330 324 331 333 333 328 340

 Exhibit 2-38

Healy Performance Goals and Combustion System Characterization

Testing Results (June – December 1998)

Permit Goal Actual Range Actual Typical

efore 7/97) 0.350 lb/106 Btu (30 day rolling avg) <0.35 lb/106 Btu 0.208–0.278 lb/106 Btu 0.245 lb/106 Btu

(modified after 7/97) (30 day rolling avg) (30 day rolling avg)

new plant after 7/97)

d less than 1.2 0.086 lb/106 Btu (annual avg) 70% removal (min) <0.09 lb/106 Btu 0.038 lb/106 Btu (15 ppm @ 3% O2)

79.6 lb/hr max (<35 ppm @ 3% O2) 25 lb/hr

hen emissions 0.10 lb/106 Btu (3-hour avg)

u 65.8 lb/hr max (3-hour avg)

0.02 lb/106 Btu (hourly avg) 0.015 lb/106 Btu NA 0.0047 lb/106 Btua

minute avg) 20% Opacity (3 minute avg) 20% Opacity (3 <10% Opacity 2.3% Opacitya

27% Opacity (one 6 minute minute avg) (30 min avg.)period per hour)

mbient CO 0.20 lb/106 Btu (hourly avg) <200 ppm (dry basis) <130 ppm @ 30–40 ppm @ 3.0% O2

al region (202 ppm CO @ 3.0% O2) at 3.5% O2 (dry basis) 3.0% O2 0.036 lb/106 Btu

(<206 ppm CO @3.0% O2)
Advanced Electric Power Generation
Project Fact Sheets 2-121

oal Processing for Clean Fuels
Coal Processing for Clean Fuels

ls

the Liquid

LPMEOHTM)

sion Company, L.P.

 Products and

er, and Eastman

—technology supplier

st, operator, synthesis

uel methanol tester and

—utility advisor

Eastman Chemical

Complex)

s liquid phase metha

ominal)

–5% sulfur

000 100%

370 43

630 57

catalyst but functions as an efficient means to remove theheat of reaction away from the catalyst surface. Thisfeature permits the direct use of synthesis gas streams asfeed to the reactor without the need for water-gas shiftconversion.

Methanol fuel testing is being conducted in off-site

stationary and mobile applications, such as fuel cells,buses, and distributed electric power generation. Stabilized methanol from the project is being made available toseveral test locations to study the feasibility of using theproduct as a feedstock in transportation and power generation applications. Eastern high-sulfur bituminous coal(Mason seam) containing 3% sulfur (5% maximum) and10% ash is being used.

Project Objective

To demonstrate on a commercial scale the production

of methanol from coal-derived synthesis gas using theLPMEOHTMprocess; to determine the suitability of methanol produced during this demonstration for use as a

chemical feedstock or as a low-SO

x emitting, low-NOx

emitting alternative fuel in stationary and transportationapplications; and to demonstrate, if practical, the production of dimethyl ether (DME) as a mixed coproduct withmethanol.Technology/Project Description

This project is demonstrating, at commercial scale,

the LPMEOHTM process to produce methanol from coalderived synthesis gas. The combined reactor and heatremoval system is different from other commercial metha

nd Chemicals, Inc. nol processes. The liquid phase not only suspends the
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

* Projected date

**Years omitted

Project Fact Sheets 2-123

ments

hanol from the 80,000

, 1997 with the first

pacity occurring on

od at over 92,000 gal/

ons.

monstration unit contin

nt tests demonstrating

MEOHTM process demon

alyst deactivation with a

imilar to the catalyst

alanced feed gas that is

a test was also performed

bilities of the

lts of these tests, together

ests, have given increased

MEOH(tm) process for

7, about 60 million gal

uced and plant availability has exceeded 97%. Availability in 1998 and 1999 was in excess of 99.7%. As a result of the successes achieved, the demonstration operations were extended an additional 15 months (through June 30, 2002) to allow for the opportunity to perform new tests that are considered to be of significant commercial interest. Stabilized methanol from the project has been made available to a number of test locations to study its feasi- bility as a feedstock in transportation and power genera- tion applications. A total of five vehicles have been tested on fuel blends made from the stabilized methanol. In the tests, stabilized methanol was shown to provide the same environmental benefits as chemical-grade methanol with no penalty on performance or fuel economy. Four projects were selected to study the use of stabilized methanol in both central and distributed power generation systems. Initial results show that stabilized methanol can lower NOx emissions in gas turbines and diesel engines. Testing in a fuel cell is currently underway. Commercial Applications The LPMEOHTM process has been developed to enhance IGCC power generation by producing a clean- burning, storable-liquid fuel (methanol) from clean coal- derived gas. Methanol also has a broad range of commer- cial applications; it can be substituted for conventional fuels in stationary and mobile combustion applications and is an excellent fuel for utility peaking units. Metha- nol contains no sulfur and has exceptionally low NOx characteristics when burned. DME has several commercial uses. In a storable blend with methanol, the mixture can be used as peaking fuel in IGCC electric power generating facilities. Blends of methanol and DME also can be used as a chemical feedstock for the synthesis of chemicals or new oxygen- ate fuel additives. Pure DME is an environmentally friendly aerosol for personal products. Typical commercial-scale LPMEOHTM units are expected to range in size from 50,000–300,000 gal/day of methanol produced when associated with commercial

IGCC power generation trains of 200–500 MWe.

Design and Construction Operation and Reporting

1995 1993 1994 1996 1997 1998 2002 2003 2004

ive agreement awarded 10/16/92

3/03

NEPA process completed (EA) 6/30/95

Construction started 10/95

Design completed 6/96

Environmental monitoring plan completed 8/29/96

4/97

Operation initiated 4/97

Construction completed 1/97Preoperational tests initiated 1/97

Project completed/finalreport issued 3/03*

 3 4

Project transferred to Air Products

Liquid Phase Conversion

Company, L.P. 3/95

Project resited toKingsport, TN10/93

Operationcompleted6/02*

 **
Coal Processing for Clean Fuels

ls

onversion

ration

Rosebud SynCoal

na Power Company’s

djacent to Western

)

d Coal Conversion

bbituminous and lignite

s (Rosebud Mine),

r subbituminous coals

000 100%

000 41

000 59

Coal LLC’s Advanced

to produce SynCoal®, a

ure content as low as

 and heating value up

osebud SynCoal Partnership.

Technology/Project Description

The process demonstrated is an advanced thermal

coal conversion process coupled with physical cleaningtechniques to upgrade high-moisture, low-rank coals toproduce a high-quality, low-sulfur fuel. The raw coal isscreened and fed to a vibratory fluidized-bed reactorwhere surface moisture is removed by heating with hotcombustion gas. Coal exits this reactor at a temperatureslightly higher than that required to evaporate water andflows to a second vibratory reactor where the coal isheated to nearly 600 °F. This temperature is sufficient toremove chemically bound water, carboxyl groups, andvolatile sulfur compounds. In addition, a small amount oftar is released, partially sealing the dried product. Particleshrinkage causes fracturing, destroys moisture reactionsites, and liberates the ash-forming mineral matter.

The coal is then cooled to less than 150 °F by

contact with an inert gas in a vibrating fluidized-bedcooler. The cooled coal is sized and fed to deep bedstratifiers where air pressure and vibration separatemineral matter, including much of the pyrite, from thecoal, thereby reducing the sulfur content of the product. The low specific gravity fractions are sent to aproduct conveyor while heavier fractions go to fluidized-bed separators for additional ash removal.

The fines handling system consolidates the coal fines

that are produced throughout the ACCP facility. Thefines are gathered by screw conveyors and transported bydrag conveyors to a bulk cooling system. The cooledfines are blended with the coarse product, stored in a 250-ton capacity bin until loaded into pneumatic trucks foroff-site sales, or returned to the mine pit.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

* Projected date

**Years omitted

Project Fact Sheets 2-125

ments

duled to complete dem

1999 but was granted a

 ACCP facility has pro

aw coal to produce over

e SynCoal is used by

cilities (primarily cement

ility continues to supply

ing the 330-MWe

trucked to Colstrip Unit

 pulverizers using a

m.

al as a supplemental fuel

 1999. About 131,000

g 1999, or approximately

n an annual basis. On

supplemental fuel, Unit

%, or 10.5 MWe (net), of

unit heat rate for Unit No.

 firing SynCoal (auxiliary

9 MWe).

When the demonstration started, baseline testing

indicated that Unit No. 2 was typically producing 2.9MW (net) less than Unit No. 1, a sister unit of comparablecapacity. In late Spring 1999, Unit No. 1 was overhauled, resulting in an increase in its average output of 7MWe (net). With this increase in output, the overhauledUnit No. 1 would have produced 5.4 MWe more thanUnit No. 2. However, for the days that SynCoal wasused, Unit No. 2 out-produced the overhauled Unit No. 1by an average of 7.3 MWe—285.7 MWe versus 278.4MWe (net)—with 15.0% of the total heat input comingfrom SynCoal. Furthermore, SynCoal can be credited foractual 1999 SO2 emissions reductions for Unit No. 2 of

approximately 430 tons, or an 8% reduction, and NOx

emissions reductions of approximately 826 tons, or a 19%reduction, when compared to Unit No. 1 emissions.

Three different feedstocks were tested at the ACCP

facility—North Dakota lignite, Knife River lignite, andAmax subbituminous coal. Approximately 190 tons ofthe SynCoal® product produced with the North Dakota

lignite was burned at the 250-MWe cyclone-fired Milton

Design and Construction Operation and Reporting

1990 1991 1992 1993 1994 1999 2000 2001 2002

9/90 6/92

Design completed 8/91

agreement

d 9/21/90

Ground breaking/construction started 3/28/91NEPA process completed (EA) 3/27/91

Preoperational tests initiated 12/91

Construction completed 2/92

Environmental monitoring plan completed 4/7/92

Test operation initiated 6/92

6/01

**

Project completed/final report

issued 6/01*

Operation completed 1/01*

R. Young Power Plant Unit No. 1. Testing showeddramatic improvement in cyclone combustion, improvedslag tapping, and a 13% reduction in boiler air flowrequirements. In addition, boiler efficiency increasedfrom 82% to over 86% and the total gross heat rateimproved by 123 Btu/kWh.Commercial Applications

ACCP has the potential to enhance the use of lowrank western subbituminous and lignite coals. The SynCoal® is a viable compliance option for meeting SO2

emission reduction requirements. SynCoal® is an ideal

supplemental fuel for plants seeking to burn western lowrank coals because the ACCP allows a wider range oflow-sulfur raw coals without derating the units. Theparticipant has six long-term agreements in place to provide SynCoal® to industrial and utility customers.

The ACCP has the potential to convert inexpensive,

low-sulfur low-rank coals into valuable carbon-basedreducing agents for many metallurgical applications.Furthermore, SynCoal® enhances cement and lime production and provides a value-added bentonite product.
Coal Processing for Clean Fuels

ls

e Coal

c. and

ftware

—cofunder

—cofunder and pilot

—field tester

gy and Environmental

tester

, ND (bench tests)

ench- and pilot-scale

H (pilot-scale tests)

ertTM (CQETM) com

 utility sites ranging in

Project FundingTotal project cost $21,746,004 100%DOE 10,863,911 50Participants 10,882,093 50Project Objective

The objective of the project was to provide the

utility industry with a PC software program it could useto confidently and inexpensively evaluate the potentialfor coal-cleaning, blending, and switching options toreduce emissions while producing the lowest cost electricity. Specifically the project was to: (1) enhance theexisting Coal Quality Information System (CQISTM)database and Coal Quality Impact Model (CQIMTM) toallow assessment of the effects of coal-cleaning onspecific boiler costs and performance; and (2) develop

and validate CQETM, a model that allows accurate anddetailed prediction of coal quality impacts on totalpower plant operating cost and performance.Technology/Project Description

The CQETM is a software tool that brings a new level

of sophistication to fueling decisions by integrating thesystem-wide impact of fuel purchase decisions on coalfired power plant performance, emissions, and powergeneration costs. The impacts of coal quality; capitalimprovements; operational changes; and environmentalcompliance alternatives on power plant emissions, performance, and production costs can be evaluated usingCQETM. CQETM can be used to systematically evaluateall such impacts, or it may be used in modules with somedefault data to perform more strategic or comparativestudies.

M are trademarks of the

osoft Corporation.

SELECTED

COALS

SUBBITUMINOUS BITUMINOUS

LIGNITE

BENCH-SCALE

TESTING

FULL-SCALE

BOILER

WASTE

COMPUTER EXPERT

MODEL

ANTHRACITE

CLEAN COAL

DATA EVALUATION

AND CORRELATION

PILOT-SCALE

BOILER
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

Project Fact Sheets 2-127

aluate emission and

d-alone computer or as a

es, coal producers, and

erform detailed coal

CQETM program are:

d

te:

ons,

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation and Reporting

Cooperative agreement awarded 6/14/90

d

0

Environmental monitoringplan completed 7/31/90

Operation initiated 8/90

Development

6/90

Field testing completed 4/93

8/90

CQE Release 1.1 beta issued 6/96

CQE CD-ROM issued 12/95

Project completed/

final report issued 6/98

6/98

CQE Release 1.2

issued 12/97

– Performance issues, and– Alternative emissions control strategies.

• Operates on an OS/2 Warp® (Version 3 or later) operating system with preferred hardware requirements of

a Pentium®-equipped personal computer, 1 gigabyte

hard disk space, 32 megabytes RAM, 1024x768SVGA, and CD-ROM.

Economic• CQETM includes economic models to determine production cost components for coal-cleaning processes,

power production equipment, and emissions controlsystems.
Coal Processing for Clean Fuels

QIMTM, developed for

oduced in 1989.

ety of capabilities,

t compliance strategies,

conducting test-burn

ng technical and eco

strategies. CQETM,

her existing software

model-based fuel evalu

hree dimensions: (1)

) advanced technical

ons, and (3) advanced

ess.

ot-, and full-scale

QETM algorithms.

d at ABB Combustion

r, Connecticut and the

rgy and Environmental

North Dakota. Pilot

B Combustion

r, Connecticut and

 sites were:

 No. 5 (880 MWe),

Unit No. 4 (250 MWe),

 Point, Unit No. 2 (285

We), Somerset, Massa

Station (560 MWe),

lahoma’s Northeastern,

ah, Oklahoma.

The six large-scale field tests consisted of burning a

baseline coal and an alternate coal over a two monthperiod. The baseline coal was used to characterize theoperating performance of the boiler. The alternate coal, ablended or cleaned coal of improved quality, was burnedin the boiler for the remaining test period.

The baseline and alternate coals for each test site also

were burned in bench- and pilot-scale facilities undersimilar conditions. The alternate coal was cleaned at CQInc. to determine what quality levels of clean coal can beproduced economically and then transported to the benchand pilot-scale facilities for testing. All data from bench-,pilot-, and full-scale facilities were evaluated and correlated to formulate algorithms used to develop the model.CQE

TM Capability

The OS/2®-based program evaluates coal quality,

transportation system options, performance issues, andalternative emissions control strategies for utility powerplants. CQETM is composed of technical tools to evaluateperformance issues, environmental models to evaluateemissions and regulatory issues, and economic models todetermine production cost components, including consumables (e.g., fuel, scrubber additives), waste disposal,operation and maintenance, replacement energy costs,and operation and maintenance costs for coal-cleaningprocesses, power production equipment, and emissionscontrol systems. CQETM has four main features:• Fuel Evaluator—Performs system-, plant-, or unitlevel fuel quality, economic, and technical assessments.• Plant Engineer—Provides in-depth performance evaluations with a more focused scope than provided in the

Fuel Evaluator.

• Environmental Planner—Provides access to evaluation

and presentation capabilities of the Acid Rain Advisor.

• Coal-Cleaning Expert—Establishes the feasibility of

cleaning a coal, determines cleaning processes, andpredicts associated costs.

Software Description

The CQETM includes more than 100 algorithms

based on the data generated in the six full-scale field test.

The CQETM design philosophy underscores the importance of flexibility by modeling all important power

plant equipment and systems and their performance inreal-world situations. This level of sophistication allowsnew applications to be added by assembling a model ofhow objects interact. Updated information records can bereadily shared among all affected users because CQETM isnetwork-aware, enabling users throughout an organization to share data and results. The CQETM object-orienteddesign, coupled with an object database managementsystem, allows different views of the same data. As aresult, staff efficiency is enhanced when decisions aremade.

CQETM also can be expanded without major revisions to the system. Object-oriented programming allows

new objects to be added and old objects to be deleted orenhanced easily. For example, if modeling advancementsare made with respect to predicting boiler ash deposition(i.e., slagging and fouling), the internal calculations of the

object that provides these predictions can be replaced oraugmented. Other objects affected by ash deposition(e.g., ash collection and disposal systems, soot blower

systems) do not need to be altered; thus, the integrity ofthe underlying system is maintained.System Requirements

CQETM currently uses the OS/2® operating system,

but the developers are planning to migrate to a Windows®-based platform. CQETM can operate in stand-alone

mode on a single computer or on a network. Technicalsupport is available from Black & Veatch for licensedusers.
Project Fact Sheets 2-129

cable to all electric power

trial/institutional boilers

tial users include fuel

ations, government and

eering firms. Interna

ing explored by both CQ

d distributes CQETM to

QETM is available to

 of licenses: user, con

Q Inc. and Black &

ercialization agreements,

-exclusive worldwide

 to offer consulting

CQETM software. Two

 to use copies of

 Advisor. Over 30 U.S.

ve CQETM through their

ilities and coal compa

posals are pending with

and foreign utilities to

me Page on the World

com:80/cqe/cqe.htm) and

omote CQETM, facilitate

TM developers and users,

pdates to be distributed

veloped to provide an on

he Home Page also helps

al utilities and consulting

he Secretary of Energy

6 as the best of nine

search and development

Electric Partnership”

ContactsClark D. Harrison, President, (724) 479-3503

CQ Inc.160 Quality Center Rd.Homer City, PA 15748(724) 479-4181 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Joseph B. Renk, NETL, (412) 386-6406

New England Power

Five utilities acted as hosts for field tests of CQETM.

References• Final Report: Development of a Coal Quality Expert.

June 20, 1998.

• Harrison, Clark D. et al. “Recent Experience with the

CQETM.” Fifth Annual Clean Coal Technology Conference: Technical Papers. January 1997.

• CQETM Users Manual, CQETM Home Page at http://

www.fuels.bv.com:80/cqe/cqe.htm.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Development of the Coal Quality Expert. ABB Combustion Engineering, Inc., andCQ Inc. Report No. DOE/FE-0174P. U.S. Department of Energy. May 1990. (Available from NTIS asDE90010381.)
Coal Processing for Clean Fuels

ls

al

ct

wned subsidiary of

mpany)

mpany (a wholly owned

nc.)—cofunder

veloper, owner,

wned subsidiary of

WY (Triton Coal

Coal (LFC®) process

PRB) subbituminous

oal feed

000 100%

000 50

000 50

 operation of a num

oduce two higher

d gasification of low

red trademarks of SGI

ment Company.

sulfur subbituminous coal, and to provide sufficient products for potential end users to conduct burn tests.Technology/Project Description

Coal is fed into a rotary grate dryer where it is heated

to reduce moisture. The temperature is controlled so thatno significant amounts of methane, CO2, or CO are released. The solids are then fed to the pyrolyzer where the

temperature is about 1,000 °F, and all remaining water isremoved. A chemical reaction releases the volatile gaseous material. Solids exiting the pyrolyzer are quenchedto stop the pyrolysis reactions.

In the original process, the quench table solids were

further cooled in a rotary cooler and transferred to a surgebin. A single 50% flow rate vibrating fluidized bed(VFB) was added to stabilize the Process-Derived Fuel

(PDF®) with respect to oxygen and water. In the VFB,

the partially-cooled, pyrolyzed solids contact a gas streamcontaining a controlled amount of oxygen. Termed “oxidative deactivation,” a reaction occurs at active surfacesites on the particles, reducing the tendency for spontaneous ignition.

Following the VFB, the solids are cooled to near

atmospheric temperature in an indirect rotary coolerwhere water is added to rehydrate the PDF®. A patented

dust suppressant is added as the PDF® leaves the surge

bin. The hot gas produced in the pyrolyzer is sentthrough a cyclone for removal of the particulates, andthen cooled in a quench column to stop any additionalpyrolysis reactions and to condense the Coal-DerivedLiquid (CDL®).

RAW COAL

CYCLONE

PRODUCT

GAS

DRYER

ELECTROSTATIC

PRECIPITATORS

LIQUIDS

PROCESS GAS

TO PDF STORAGE

COALDERIVED

LIQUID

RECOVERY

DRYER GAS

PROCESS HEAT

PYROLYZER

BLOWER STACK

DRYER

GAS

CYCLONE

COAL

SCREEN

FINES TO

PROCESS-DERIVED

FUEL STORAGE

DRYER

FINES TO COMBUSTOR

PROCESS-DERIVED

FUEL STORAGE

PYROLYZER

COMBUSTOR

BLOWER

TO TRUCK AND RAIL LOADOUT

COAL-DERIVED

LIQUID STORAGE

QUENCH

DEACTIVATION

AIRFINISHER

COOLER

FLUE GAS

DESULFURIZATION
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

*Projected date

Project Fact Sheets 2-131

Design and Construction Operation and Reporting

1990 1991 1992 1993 1994 1995 1996 1997 1998

Cooperative agreement awarded 9/17/90

ted

ct

-III)

/89

NEPA process completed (EA) 8/1/90

Ground breaking/construction started 10/26/90

Operation initiated 7/92

Construction completed 6/92

Preoperational tests initiated 4/92

Design completed 7/91

Environmental monitoring plan completed 5/29/92

9/90 7/92

eaward

Project completed/final

report issued 12/97

Operation completed 7/97

12/97

fur with a heat content of

.45% sulfur and 8,300

fur and 140,000 Btu/gal

 150,000 Btu/gal for No.

enabled reduction in SO2

missions (through flame

ce of boiler rated capacity

oxins in concentrations

its.

ing 90% availability was

 for the entire plant

 days duration).

• The LFC® process consistently produced 250 tons/day

of PDF® and 250 barrels/day of CDL® from 500 tons/

day of run-of-mine PRB coal.

• Integrated operation of the LFC® process components

over five years has provided a comprehensive databasefor evaluation and design of a commercial unit.

• Over 83,500 tons of PDF® were shipped via 17 unit

trains and one truck shipment to seven customers insix states. Shipments included 100% PDF® and blends

from 14–94% PDF®.

• PDF®, alone and in blends, demonstrated excellent

combustion characteristics in utility applications,providing heating values comparable to bituminouscoal, more reactivity than bituminous coal, and astable flame.

• The low-volatile PDF® also showed promise as a

reductant in direct iron reducing testing and also as ablast furnace injectant in place of coke.

• Nearly 5 million gallons of CDL® were produced and

shipped to eight customers in seven states.

• CDL® demonstrated fuel properties similar to a lowsulfur No. 6 fuel oil but with the added benefit of

lower sulfur content. High aromatic hydrocarboncontent, however, may make CDL® more valuable as a

chemical feedstock.

Economic• A commercial plant designed to process 15,000 metric

tons per day would cost an estimated $475 million(2,001$) to construct, with annual operating and maintenance costs of $52 million per year.
Coal Processing for Clean Fuels

Pre-VFB Post-VFB

1992 1993 1994 1995 1996 19971 Sum

Raw Coal Feed (tons) 5,200 12,400 67,500 65,800 68,000 39,340 258,300PDF® Produced (tons) 2,200 4,900 31,700 28,600 33,300 19,300 120,500

PDF® Sold (tons) 0 0 23,700 19,100 32,700 7,400 82,900CDL® Produced (bbl) 2,600 6,600 28,000 31,700 32,500 20,300 121,700Hours on Line 314 980 4,300 3,400 3,600 2,603 15,197Average Length ofRuns (Days) 2 8 26 38 44 75 N/A

1Through June 1997.

Exhibit 2-40

ENCOAL Production

r more than 15,000

ady-state operation was

stration with availabili

The length of operation

the soundness and

COAL’s production

tration, over 83,500

unit trains and one

 in six states. Ship

lends from 14–94%

CDL® were produced

seven states.

t demonstrations, how

 many challenges. The

ving stability of the

olved in order to

n trying to correct

 within the bounds of

ry cooler failed to

 to quell spontaneous

luded that a separate,

uct deactivation. A

adoption of a VFB. A

tween the quench table

a second 500 ton/day

mented.)

deactivation, the PDF

e stabilization. Exten

gen was needed for

on were pursued:

res to finish deactiva

 immediate PDF® ship

pment of an in-plant

product quality and

ng.

“Pile layering” was the primary external PDF® finishing measure adopted. However, PDF® quality becomes somewhat impaired by impacting size, moisture,

and ash content.

Pursuit of a finishing process step resulted in establishment of a stabilization task force composed of private

sector and government engineers and scientists. Theoutcome was construction and testing of a Pilot Air Stabilization System (PASS) to complete the oxidative deactivation of PDF®. The PASS controls temperature and

humidity during forced oxidation. The data obtainedwere used to develop specifications and design requirements for a full-scale, in-plant PDF® finishing unit based

upon a commercial (Aeroglide) tower dryer design.

CDL® Product. The first shipment of ENCOAL’s

liquid product experienced unloading problems. The useof heat tracing and tank heating coils solved the unloading problems for subsequent customers. The CDL® also

contained more solids and water than had been hoped for,but was considered usable as a lower grade oil.

Following VFB installation, CDL® quality improved.

The pour point ranged from 75–95 oF, and the flash point

averaged 230 oF, both within the design range. Watercontent was down to 1–2%, and solids content was 2–4%.Improvements resulted from more consistent operationand lower pyrolysis temperatures and higher pyrolysisflow rates enabled by a new pyrolyzer water seal.Environmental PerformancePDF® Product. PDF® offers the advantages of lowsulfur Powder River Basin coal without a heating value

penalty. In fact, the LFC® process removes organicallybound sulfur, making the PDF® product lower in sulfur

than the parent coal on a Btu basis. Because the ROMcoal is low in ash, PDF® ash levels remain reasonable

after processing, even though the ash level is essentiallydoubled (ash from one ton of ROM coal goes into onehalf ton of PDF®).

Dust emissions were not a problem with PDF®. A

dust suppressant (MK) was sprayed on the PDF® to coat

the surface as it leaves the storage bin. Also, PDF® has a

narrower particle size distribution than ROM coal, havinga larger fines content but fewer particles in the fugitivedust range than ROM coal.
Project Fact Sheets 2-133

ents became international

velopment Company

s of PDF® in 1994. The

uels being considered for

n, found PDF® accept

oilers.

ted combustion testing

ntucky Electric Co

Station, Unit #3. Impor

ing:

g PDF® was possible with

 was not possible on the

DF® afforded time to

d calibration without

ncreasing capacity factor

ng operation and mainte

by 20% due to high

almost immediate igni

coal nozzle. Further

ve combustion (maintain

 very low excess oxygen,

Ox emissions.

ed ash deposits in the

ter than those resulting

ing increased sootblow

 liquid product is a low

quid hydrocarbon.

milar to a low-sulfur No.

content is significantly

 as a straight industrial

limited. The market for

ed and CDL® has limited

ulfur residual fuels due

ic CDL® with many

llates.

ENCOAL determined that a centrifuge was needed

to reduce solids retention and improve marketability ofCDL® (tests validated a 90% removal capability); and an

optimum slate of upgraded products was identified. Theupgraded products were: (1) crude cresylic acid, (2) pitch,(3) refinery feedstock (low-oxygen middle distillate), and(4) oxygenated middle distillate (industrial fuel).Economic

The “base case” for economics of a commercial plant

is the 15,000-metric-ton/day, three-unit North RochelleLFC® plant, the commercial-scale plant proposed by

ENCOAL, with an independent 80-MWe cogenerationunit, and no synthetic fuel tax credit (29c tax credit). It isassumed that the cogeneration unit is owned and operatedby an independent third party. The capital cost for a fullscale three module LFC® plant is $475 million.

Economic benefits from an LFC® commercial plant

are derived from the margin in value between a raw,unprocessed coal and the upgraded products, making anLFC® plant dependent on the cost of feed coal. In fact,

this is the largest single operating cost item. The totalestimated operating cost is $9.00/ton of feed coal including the cost of feed coal, chemical supplies, maintenance,and labor.Commercial Applications

In a commercial application, CDL® would be upgraded to cresylic acid, pitch, refinery feedstock, and

oxygenated middle distillate. Oxygenated middle distillate, the lowest value by-product, would be used in lieu ofnatural gas as a make-up fuel for the process (30% of theprocess heat input). PDF® would be marketed not only as

a boiler fuel but as a supplement or substitute for coke inthe steel industry. PDF® characteristics make it attractive

to the metallurgical market as a coke supplement in pulverized coal injection and granular coal injection methods, and as a reductant in direct reduced iron processes.

Partners in the ENCOAL® project completed five

detailed commercial feasibility studies over the course ofthe demonstration and shortly thereafter—two Indonesian, one Russian, and two U.S. projects. A U.S. projecthas received an Industrial Siting Permit and an Air Quality Construction Permit, but the project is on hold due tolack of funding.ContactsJames P. Frederick, (307) 686-2720, ext. 29

SGI International319 South Gillette Ave., Suite 260P.O. Box 3038Gillette, WY 82717(307) 686-2894 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Douglas M. Jewell, NETL, (304) 285-4720References• ENCOAL® Mild Gasification Plant Commercial Plant

Feasibility Study. U.S. Department of Energy. September 1997. Report No. DOE/MC/27339. (Available from NTIS as DE98002005.)

• Final Design Modifications Report. U.S. Department

of Energy. September 1997. Report No. DOE/MC/27339-5797. (Available from NTIS as DE98002006.)

• ENCOAL® Mild Gasification Project: ENCOAL

Project Final Report. Report No. DOE/MC/27339-5798. U.S. Department of Energy. September 1997.(Available from NTIS as DE98002007.)

• Johnson, S.A., and Knottnerus, B.A. “Results of the

PDF® Test Burn at Clifty Creek Station.” U.S. Department of Energy Topical Report. October 1996.

• ENCOAL® Mild Coal Gasification Demonstration

Project Public Design and Construction Report. Report No. DOE/MC/27339-4065. ENCOAL Corporation. December 1994. (Available from NTIS asDE95009711.)
Coal Processing for Clean Fuels
Project Fact Sheets 2-135

Industrial Applications
Industrial Applications

maintaining high heat transfer efficiency in the postcombustion zone above the reaction zone, to reduce andsmelt iron oxides. The HIsmelt® process uses a vertical

smelt reduction reactor, which is a closed molten bathvessel, into which iron ore fines, coal, and fluxes areinjected. The coal is injected into the bath where carbonis dissolved rapidly. The carbon reacts with oxygen (fromthe iron ore) to form CO and metallic iron. Injectiongases and evolved CO entrain and propel droplets of slagand molten iron upward into the post-combustion zone.

The iron reduction reaction in the molten bath is

endothermic; therefore, additional heat is needed to sustain the process and maintain hot metal temperature. Thisheat is generated by post-combusting the CO and hydrogen from the bath with an O2-enriched hot air blast from

the central top lance. The heat is absorbed by the slag

Integrated

n

y LLC (a limited liabil

ries of the Geneva Steel

r, constructor, host, and

va Steel Co.’s mill)

ess

ion

000 100%

242 14

758 86

n of direct iron making

y using various U.S.

entally responsible

on

ed on producing hot

and non-coking coals.

ng sufficient heat and

 Corporation Pty Limited.

Management Company, L.L.C.

and molten iron droplets and are returned to the bathby gravity. Droplets in contact with the gas in thepost-combustion zone absorb heat, but are shroudedduring the descent by ascending reducing gases (CO),which, together with bath carbon, prevent unacceptable levels of FeO in the slag. The molten iron collectsin the bottom of the bath and is continuously tappedfrom the reactor through a fore-hearth, which maintainsa constant level of iron in the reactor. Slag, which isperiodically tapped through a conventional blast furnace-type tap hole, is used to coat and control theinternal cooling system and reduce the heat loss. Reacted gases, mainly N2, CO2, CO, H2, and H2O, exit the

vessel. After scrubbing the reacted gases, the cleanedgases will be combusted to produce 170 MWe ofpower. The cleaned gases can also be used to pre-heatand partially reduce the incoming iron ore.

FUEL GAS

COLD BLAST

OXYGEN

GAS CLEANING

COAL,

IRON ORE,

AND FLUXES COAL,

IRON ORE,

AND FLUXES

POST-COMBUSTION

ZONE

REACTOR

VESSEL HOT METAL

SLAG

HOT BLAST

STOVES
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

**Years omitted

 1 2

Project Fact Sheets 2-137

1997 2000 

1996 2001 2002 2003 2004 2005 2006

Cooperative agreement awarded 10/11/96

NEPA process completed 12/00*

Construction started 12/00*

Design and Construction

Operation initiated 5/03*Construction completed 5/03*

Operation and Reporting

Project

completed/final

report issued 10/05*

Operation

completed 10/05*

ments

was awarded on October

he global assortment of

ies to determine which

able to western U.S. coals

e COREX® process

va’s local raw materials;

data on 100% raw coals

n in this demonstration.

ine alternatives. The

SI direct ironmaking,

nic Smelter, and

 appears to offer good

ial, as well as the pros

CPICORTM has com

t the HIsmelt® pilot plant

ry design, and environ

On July 28, 1999, DOE

re an Environmental

Impact Statement for the project. A NEPA publicscoping meeting was held in Provo, Utah on July 15,1999.

On February 1, 1999, Geneva Steel Company

(CPICORTM Management Company’s parent corporation) filed a voluntary petition for bankruptcy underChapter 11 of the United States Bankruptcy Code in theU.S. Bankruptcy Court for the District of Utah. GenevaSteel intends to emerge from Chapter 11 with a restructured balance sheet that will enable full participation inthis demonstration project.Commercial Applications

The HIsmelt® technology is a direct replacement for

existing blast furnace and coke-making facilities withadditional potential to produce steam for power production. Of the existing 79 coke oven batteries, half are 30years of age or older and are due for replacement ormajor rebuilds. There are about 60 U.S. blast furnaces,all of which have been operating for more than 10 years,

with some originally installed up to 90 years ago.HIsmelt® represents a viable option as a substitute for

conventional iron making technology.

The HIsmelt® process is ready for demonstration. Two

pilot plants have been built, one in Germany in 1984 andone in Kwinana, Western Australia in 1991. Through testwork in Australia, the process has been proven—operational control parameters have been identified and completecomputer models have been successfully developed andproven.

**

Environmental monitoring

plan completed 9/02*

5/03

10/96 10/05
Industrial Applications

Design

nversion International,

y)

m Reforming process

pulse combustor.

in) subbituminous

054 100%

027 50

027 50

l/commercial viability

se combustor unit and

ived fuel gas generated

tion

Steam Reforming pro

ng process for thermo

l to produce hydrogen

uel gas without the need

transfer is provided by

be pulse combustors

in a fluidized-bed steam gasification reactor. Pulsecombustion increases the heat transfer rate by a factorof 3 to 5, thus greatly reducing the heat transfer arearequired in the gasifier.

The pulse combustor represents the core of the

Pulsed EnhancedTM Steam Reforming process becauseit provides a highly efficient and cost-effective heatsource. Demonstration of the combustor at the 253-resonance-tube commercial-scale is critical to marketentry. The 253-resonance-tube unit represents a 3.5:1scale-up from previous tests. Testing will seek toverify scale-up criteria and appropriateness of controls and instrumentation. Also, an existing processdata unit will be used to gasify coal feedstock to provide fuel gas data, including energy content, speciesconcentration, and yield. Char from the process dataunit will be evaluated as well.

The facility will also have a product gas cleanup

train that includes two stages of cyclones, a venturiscrubber with a scrubber tank, and a gas quench column. An air-cooled heat exchanger will be used toreject heat from the condensation of excess steam(unreacted fluidization steam) quenched in the venturiscrubber and gas quench column. All project testingwill be performed at the MTCI test facility in Baltimore,Maryland.

AIR

FEED

WATER

FUEL

GAS

FLUE GAS

BOILER

(FOR START-UP)

AIR

FUEL GAS

STEAM

253-TUBE

PULSED

HEATER

STEAM

SUPER

HEATER

2-STAGE

CYCLONE

PUMP

VENTURI

STEAM

VENT STACK

GAS COOLINGCOLUMN

AIRCOOLER

PUMP
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

 1 2

Project Fact Sheets 2-139

1993 1994 1997 1998 1999 2000 2001

1995 1996

tive agreement

 10/27/92

Project relocationrequested 10/26/94

Design and Construction

*Projected Date

Revised Cooperative AgreementAwarded 9/29/98

Operation initiated10/00*

Operationcomplete11/00*

4/00 12/00

ments

OE approved revision of

e Agreement for a

nal project, awarded in

l demonstration facility

253-resonance-tube

brication of the first

 through restructuring.

trate a single 253-reso

EPA requirements were

, with a Categorical

stone was completion of

.

sonance-tube combus

n is expected to begin

ests of the process data

0. Following modifica

U tests with Black

e expected to be com

Commercial Applications

PulsedEnhancedTM Steam Reforming has application in many different processes. Coal, with the world

production on the order of four billion tons per year,constitutes the largest potential feedstock for steamreforming. Other potential feedstocks include spentliquor from pulp and paper mills, refuse-derived fuel,municipal solid waste, sewage sludge, biomass, andother wastes.

Although the project will demonstrate mild gasification only, the following coal-based applications are

envisioned:• Coal processing for combined-cycle power generation,• Coal processing for fuel cell power generation,• Coal pond waste and coal rejects processing to produce a hydrogen-rich gas from the steam reformer for

use in overfiring or reburning to reduce NOx emissions,

• Coal processing for production of gas or liquid fuel,

and char for the steel industry for use in direct reduction of iron ore,

Final report 12/00*

Design complete 2/15/99

Restructuring complete

3/21/98

• Coal processing for producing compliance fuels,• Mild gasification of coal,• Coprocessing of coal and wastes, and• Coal drying.

In addition, the technology has application for black

liquor processing and chemical recovery and for hazardous, low-level radioactive, and low-level mixed wastevolume reduction and destruction.

PDU Gasification data 9/00*

Operation

and

Reporting
Industrial Applications

nular-Coal

oject

 Services, Inc. (market

ation)—technology

med Simon-Macawber,

ngineer

ngineer (North

Bethlehem Steel’s

 Units C and D)

blast furnace granular

M)/day (each blast

fur

 sulfur

790 100%

118 16

672 84

Project Objective

To demonstrate that existing iron making blast

furnaces can be retrofitted with blast furnace granularcoal injection technology; to demonstrate sustainedoperation with a variety of coal types, particle sizes, andinjection rates; and to assess the interactive nature ofthese parameters.Technology/Project Description

In the BFGCI process, either granular or pulverized

coal is injected into the blast furnace in place of naturalgas or oil as a blast furnace fuel supplement. The coal,along with heated air, is blown into the barrel-shapedsection in the lower part of the blast furnace throughpassages called tuyeres, which creates swept zones in thefurnace called raceways. The size of a raceway is important and is dependent upon many factors, including temperature. Lowering of a raceway temperature, which can occur with natural gas injection, reduces blast furnace production rates. Coal, with a lower hydrogen content than either natural gas or oil, does not cause as severe a reduction in raceway temperatures. In addition to displac- ing natural gas, the coal injected through the tuyeres displaces coke, the primary blast furnace fuel and reduc- tant (reducing agent), on approximately a pound-for- pound basis up to 40% of total requirements. Emissions generated by the blast furnace itself remain virtually un- changed by the injected coal; the gas exiting the blast furnace is cleaned and used in the mill. Sulfur from the coal is removed by the limestone flux and bound up in the slag, which is a salable by-product. Two high-capacity blast furnaces, Units C and D at Bethlehem Steel’s Burns Harbor Plant, were retrofitted with BFGCI technology.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

**Years omitted

 1 2

Project Fact Sheets 2-141

1991 1993 1994 1995 1996 1997 1998 1999 2000

rative agreement awarded 11/26/90

Design and Construction Operation and Reporting

11/99

Final report issued 10/99

Operation completed 11/98

**

NEPA process completed (EA) 6/8/93

Construction started 9/93

Design completed 12/93

Environmental monitoring plan completed 12/23/94

Construction completed 1/95

Preoperational tests initiated 2/95

Operation initiated 11/95

11/95

coals are not as likely to stick to conveying pipes ifmoisture control is not adequately maintained.

• Any decrease in furnace permeability as a result of

coal injection can be minimized by increasing oxygenenrichment and raising moisture additions to the blastfurnace.

• Higher ash coal had no adverse effect on furnace

permeability.

• The productivity rate of the furnace was not affected

by the 2.4 percentage point increase in coal ash at aninjection rate of 260 lb/NTHM.

• There is a coke rate disadvantage of 3 lb/NTHM for

each 1 percentage point increase of ash in the coal atan injection rate of 260 lb/NTHM.

• Hot metal quality was not affected by the increased

ash content of the injection coal.

Economic• The capital cost for one complete injection system at

Burns Harbor was $15,073,106 (1990$) for the 7,200NTHM/day blast furnace.

• The total fixed costs (labor and repair costs) at Burns

Harbor were $6.25/ton of coal. The total variable costs(water, electricity, natural gas, and nitrogen) were$3.56/ton of coal. Coal costs were $50-60/ton.

• At a total cost of $60/ton and a natural gas cost of

$2.85/106 Btu, the iron cost savings would be about

$6.50/ton of iron produced.

• Based on the Burns Harbor production of 5.2 million

tons of iron per year, the annual savings is about$34 million/yr.

e potential to reduce

ally by displacing coke,

ts in significant emis

h-carbon coal provided a

enabled the operators to

ate of 661 lb/NTHM

40 lb/NTHM).

eability of the carbon

en column (a critical

cceptable operation

igh-carbon coal.

andle in pneumatic con

ed coal because granular

Project completed 11/99
Industrial Applications

ces, Units C and D at

lant, were retrofitted

t has a production

e two units use about

operation. This project

ce designed to deliver

us blast furnaces have

d (fine) coal. The

% scale-up from CPC

England where the

nology on large, high

em Steel conducted

oal to determine the

e. Tests included east

ontents of 0.8–2.8% and

ng 0.4–0.9% sulfur.

st program was to deter

oal type on blast furnace

determining the effects

n furnace performance.

been reported—a base

 coal and a trial period

chanan, a chemically

ut from a different

ng the entire month of

 blast furnace operated

ia Pocahontas. This

n coal provided a high

ase period test. The

8 lb/NTHM on a daily

264 lb/NTHM. The

od averaged 661 lb/

ed in C furnace was

he month.

The injected coal rate of 264 lb/NTHM is one of

the highest achieved since startup of the coal facility.Reliability of the coal system enabled the operators toreduce furnace coke to a low rate of 661 lb/NTHM.This low coke rate is not only economically beneficial,it is an indicator of the efficiency of furnace operationwith regard to displacing coke with injected coal.

Hot metal chemistry, particularly that of silicon and

sulfur content, is important in iron making. Specificsilicon and sulfur values with low variability are vital tomeeting steel-making specifications. The average values and standard deviations for silicon and sulfur canbe seen in Exhibit 2-41. These values are compared totypical operation data on natural gas collected in January 1995.

Exhibit 2-41 also shows the significant operating

changes that occur with the use of injected coal versusnatural gas. The wind volume on the furnace decreasedsignificantly with the use of coal. Oxygen enrichmentincreased from 24.4% to 27.3% with coal. The amount ofmoisture added to the furnace in the form of steam significantly increased from 3.7 grains/SCF to 19.8 grains/SCF.All of these variables were increased by operating personnel to maintain adequate burden material movement.These actions also increased the permeability of the furnace burden column, which is a function of the blast rateand the pressure drop through the furnace. The larger thepermeability value, the better the furnace burden movement and the better the reducing gas flow rate through thefurnace column. During the base period, the permeabilityindicated overall acceptable operation using low-ash,low-volatile, high-carbon coal.

The next series of tests involved using a higher

ash coal. In order to ensure that other variables didnot influence the test results, Buchanan coal was used,but the ash content was increased by eliminating oneof the usual coal cleaning steps. The ash content ofthe coal used for the high-ash trial was 7.70% compared with 5.30% for the base period trial and 4.72% forthe period immediately prior to the high-ash coal trial.

As during the base trial period, the granular coal wasabout 15% minus 200 mesh. To ensure comparableresults, Bethlehem Steel operators maintained operation consistent with the base period trials. A comparison of the high-ash trial to the base period is also contained in Exhibit 2-41. The amount of injected coal,general blast conditions, wind volume, blast pressure,top pressure, and moisture additions were comparableduring the two trials.

The primary change in operation, as expected, was

the increase in the blast furnace slag volume. With thehigher ash coal, the 461 lb/NTHM slag volume was 8.7%higher than the baseline period of 424 lb/NTHM. Thegeneral conclusion is that higher ash content in the injected coal can be adjusted by the furnace operators anddoes not adversely affect overall furnace operations.However, the results lead to the conclusion that a 2.4percentage point increase in injected coal ash results in a8 lb/NTHM increase in the furnace coke rate after correcting for other variables. This is the amount of coke carbonneeded to replace the lower carbon in the higher-ash coalwithout an additional process penalty.Environmental Summary

The greatest environmental benefit to the BFGCI is

displacement of coke in favor of coal. Coke is essentiallyreplaced on a pound-for-pound basis with granulated coal,up to 40% of the total requirements. The BFGCI technology has the potential to reduce pollutant emissions because coke production results in significant emissions ofair toxics.Economic Summary

Capital cost for one complete injection system at

Burns Harbor was approximately $15 million (1990$).This does not include infrastructure improvements, whichcost $87 million at Burns Harbor. The fixed operatingcost, which includes labor and repair costs, was $6.25/ton of coal. The variable operating cost, which includeswater, electricity, natural gas, and nitrogen, was $3.56/ton of coal. Coal costs were $50–60/ton. This brought
Project Fact Sheets 2-143

the total operating costs to $59.81–69.81/ton of coal.Using $60/ton of coal and a natural gas cost of $.88/106Btu, the cost savings would be about $6.50/ton of ironproduced. At Burns Harbor, which produces 5.2 milliontons of iron per year, the savings would be about $34million/yr. At Burns Harbor, the payback period is 3.44years using a simple rate of return calculation.Commercial Applications

BFGCI technology can be applied to essentially all

U.S. blast furnaces. The technology should be applicableto any rank coal commercially available in the U.S. thathas a moisture content no higher than 10%. The environmental impacts of commercial application are primarilyindirect and consist of a significant reduction of emissionsresulting from diminished coke-making requirements. TheBFGCI technology was developed jointly by British Steeland Simon-Macawber (now CPC-Macawber). BritishSteel has granted exclusive rights to market BFGCI technology worldwide to CPC-Macawber. CPC-Macawberalso has the right to sublicense BFGCI rights to otherorganizations throughout the world. CPC-Macawber hasalso installed a similar facility at United States SteelCorporation’s Fairfield blast furnace.ContactsRobert Bouman, Manager, (610) 694-6792

Bethlehem Steel CorporationBuilding C, Room 211Homer Research LaboratoryMountain Top CampusBethlehem, PA 18016(610) 694-2981 (fax)

Douglas Archer, DOE/HQ, (301) 903-9443Leo E. Makovsky, NETL, (412) 386-5814ReferencesHill, D.G. et al. “Blast Furnace Granular-Coal InjectionSystem Demonstration Project.” Sixth Clean Coal Conference Proceedings: Volume II - Technical Papers.April–May, 1998.

Exhibit 2-41

BFGCI Test Results

Pre-Demonstration Base High-Ash Test

January 1995 October 1996 May 28–June 23, 1997

7,436 6,943 7,437

740 661 674141 0 5.0

0 264 262

881 925 940

167,381 137,005 135,370

38.9 38.8 38.3

1.57 1.19 1.23

24.4 27.3 28.6

2,067 2,067 2,012

3.7 19.8 20.7

4.8 5.0 5.0

0.44 (0.091) 0.50 (0.128) 0.49 (0.97)

0.043 (0.012) 0.040 (0.014) 0.035 (0.012)

0.070 0.072 0.0730.40 0.43 0.46

2,745 2,734 2,733

38.02 36.54 36.21

8.82 9.63 9.91

37.28 39.03 39.40

12.02 11.62 11.32

0.45 0.46 0.45

0.85 1.39 1.40

1.05 1.10 1.10

1.30 1.39 1.40

394 424 461
Industrial Applications

signed so that a high percentage of the ash and sorbentfed to the combustor as slag. For NOx control, thecombustor is operated fuel rich, with final combustiontaking place in the boiler furnace to which the combustor is attached. SO2 is captured by injection of limestone into the combustor. The cyclonic action inside

the combustor forces the coal ash and sorbent to thewalls where it can be collected as liquid slag. Underoptimum operating conditions, the slag contains asignificant fraction of vitrified coal sulfur. Downstreamsorbent injection into the boiler provides additionalsulfur removal capacity.

In Coal Tech’s demonstration, an advanced, aircooled cyclone coal combustor was retrofitted to a 23 x

106 Btu/hr, oil-fired package boiler located at the

Tampella Power Corporation boiler factory inWilliamsport, Pennsylvania.

Technology/Project Description

Coal Tech’s horizontal cyclone combustor is lined

with an air-cooled ceramic. Pulverized coal, air, andsorbent are injected tangentially toward the wallthrough tubes in the annular region of the combustor tocause cyclonic action. In this manner, coal-particle combustion takes place in a swirling flame in a region favorable to particle retention in the combustor. Secondary airis used to adjust the overall combustor stoichiometry.Tertiary air is injected at the combustor/boiler interface.The ceramic liner is cooled by the secondary air and maintained at a temperature high enough to keep the slag in aliquid, free-flowing state. The secondary air is preheatedby the combustor walls to attain efficient combustion ofthe coal particles in the fuel-rich combustor. Fine coalpulverization allows combustion of most of the coal particles near the cyclone wall. The combustor was de

e Combustor 

r, Nitrogen, 

Energy Development 

ompany—supplier of 

t 

A (Tampella Power 

g plant) 

slagging combustor 

% sulfur 

394 100% 

149 50 

245 50 

ced cyclone combustor 

oiler and that it can 

of the SO2 and 90–95% 

d reduce NOx to 
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

 1 2

Project Fact Sheets 2-145

1989 1990 

1988 1991 1992 1993 1994 1995 1996

Operation and Reporting

Construction

/24/86

eted 7/87

king/construction started 7/87

ent awarded 3/20/87

leted (MTF) 3/26/87

ental monitoring plan completed 9/22/87

uction completed 11/87

tion initiated 11/87

Operation

completed 5/90

over 80% were achieved

urnace at various cal

atios.

o 58% were achieved

ombustor at a Ca/S mo

he coal’s sulfur was re

 from the combustor (as

lfur was retained in the

bustor’s slag tap.

to 184 ppm by the com

0 ppm with the addition

ly inert.

• Ash/sorbent retention in the combustor as slag

averaged 72% and ranged from 55–90%. Undermore fuel-lean conditions, retention averaged 80%.

• Meeting local particulate emissions standards required the addition of a wet venturi scrubber.Operational• Combustion efficiencies of over 99% were achieved.• A 3-to-1 combustor turndown capability was demonstrated. Protection of combustor refractory with

slag was shown to be possible.

• A computer-controlled system for automatic combustor operation was developed and demonstrated.

Economic• Because the technology failed to meet commercialization criteria, economics were not developed during the demonstration. However, subsequent efforts indicate that the incremental capital cost for

installing the coal combustor in lieu of oil or gassystems is $100–200/kW.

9/91

Project completed/final report issued 9/91
Industrial Applications

The slagging combustor, associated piping, and control panel for

Coal Tech’s advanced ceramic-lined slagging combustor are shown.

Tech’s pat

one com

s and envi

d solid

 place in a

uld be

trial and

rbing the

s technol

by staged

d by injec

or and/or

rmance was

ld other

particularly

here tube

the low-ash

800 hours of operation,

ch of four days dura

 testing was performed

tion test. Test results

 combustor indicated

he objectives con

ent. About eight

s coals with sulfur

and volatile matter

were tested.

2 reduction measured

hieved using sorbent

 Ca/S molar ratios. A

was measured at the

o the combustor at a

m of one-third of the

dry ash removed from

hs, and as much as

ned 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-rich combustion and sor- bent-gas mixing. With fuel-rich operation of the combustor, a three- fourths reduction in measured boiler outlet stack NOx was obtained, corresponding to 184 ppm. An additional 5– 10% reduction was obtained by the action of the wet particulate scrubber, resulting in atmospheric NOx emis- sions as low as 160 ppm. All the slag removed from the combustor produced trace metal leachates well below EPA’s Drinking Water Standard. Total ash/sorbent retention as slag in the combus- tor, under efficient combustion operating conditions, averaged 72% and ranged from 55–90%. Under more fuel-lean conditions, the slag retention averaged 80%. After the CCT project, tests on fly ash vitrification in the combustor, modifications to the solids injection system, and increases in the slag flow rate produced substantial increases in the slag retention rate. To meet

local stack particulate emission standards, a wet venturi particulate scrubber was installed at the boileroutlet.Operational Performance

Combustion efficiencies exceeded 99% after proper

operating procedures were achieved. Combustor turndown to 6 x 106 Btu/hr from a peak of 19 x 106 Btu/hr (or

a 3-to-1 turndown) was achieved. The maximum heatinput during the tests was around 20 x 106 Btu/hr, even

though the combustor was designed for 30 x 106 Btu/hr

and the boiler was thermally rated at around 25 x 106 Btu/

hr. This situation resulted from facility limits on wateravailability for the boiler. In fact, due to the lack of sufficient water cooling, even 20 x 106 Btu/hr was borderline,

so that most of the testing was conducted at lower rates.

Different sections of the combustor had different

materials requirements. Suitable materials for eachsection were identified. Also, the test effort showed thatoperational procedures were closely coupled with materials durability. As an example, by implementing certainprocedures, such as changing the combustor wall temperature, it was possible to replenish the combustor

refractory wall thickness with slag produced duringcombustion rather than by adding ceramic to the combustor walls.

The combustor’s total operating time during the life

of the CCT project was about 900 hours. This includedapproximately 100 hours of operation in two other flyash vitrification test projects. Of the total time, aboutone-third was with coal; about 125 tons of coal wereconsumed.

Developing proper combustor operating procedures

was also a project objective. Not only were proceduresfor properly operating an air-cooled combustor developed, but the entire operating database was incorporatedinto a computer-controlled system for automatic combustor operation.
Project Fact Sheets 2-147

Coal Tech’s slagging combustor demonstrated the capability to retain, as slag, a high

percentage of the non-fuel components injected into the combustor. The slag, shown on theconveyor, is essentially an inert, glassy by-product with value in the construction industry asan aggregate and in the manufacture of abrasives.

s to validate the perfor

or at a commercial scale.

t fully ready for sale

was believed to have

ent work was under

hnology close to com

67-0442

301) 903-9448

6-5991

lone Combustor Demon

essment. Report No.

partment of Energy. May

as DE93017043.)

vanced Cyclone Coal

fur, Nitrogen, and Ash

f a 23-MMBtu/Hour Oil

al; Vol. 1: Final Techni

s I–V; Vol. 3: Appendix

August 1991. (Available

nd DE92002588.)

ngress on the Clean Coal

ced Cyclone Combustor

, and Ash Control. Coal

. DOE/FE-0077. U.S.

ary 1987. (Available
Industrial Applications

Gas

er

ect manager and host

 fabricator of tanks and

ragon Products

very ScrubberTM

 scfm of kiln gas; and

% sulfur

000 100%

592 34

408 66

full-scale industrial

m for a coal-burning

te dust as the reagent to

n using high-sulfur

mmercial by-product,

ucts.

Technology/Project Description

The Passamaquoddy Technology Recovery ScrubberTM uses cement kiln dust (CKD), an alkaline-rich

(potassium) waste, to react with the acidic flue gas. ThisCKD, representing about 10% of the cement feedstockotherwise lost as waste, is formed into a water-basedslurry and mixed with the flue gas as the slurry passesover a perforated tray that enables the flue gas to percolatethrough the slurry. The SO2 in the flue gas reacts with the

potassium to form potassium sulfate, which stays in solution and remains in the liquid as the slurry undergoesseparation into liquid and solid fractions. The solid fraction, in thickened slurry form and freed of the potassiumand other alkali constituents, is returned to the kiln asfeedstock (it is the alkali content that makes the CKDunusable as feedstock). No dewatering is necessary for the

wet process used at the Dragon Products Companycement plant. The liquid fraction is passed to a crystallizer that uses waste heat in the flue gas to evaporatethe water and recover dissolved alkali metal salts. Arecuperator lowers the incoming flue gas temperatureto prevent slurry evaporation, enables the use of lowcost fiberglass construction material, and providesmuch of the process water through condensation ofexhaust gas moisture.

The Passamaquoddy Technology Recovery

ScrubberTM was constructed at the Dragon Productsplant in Thomaston, Maine, a plant that can processapproximately 450,000 ton/yr of cement. The processwas developed by the Passamaquoddy Indian Tribewhile it was seeking ways to solve landfill problems,which resulted from the need to dispose of CKD fromthe cement-making process.

bber is a trademark of the
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

 1 2

Project Fact Sheets 2-149

averaged 94.6% during

eration and 89.2% for

averaged nearly 25%

 of operation and 18.8%

.

waste produced by the

ed as feedstock, which

eedstock requirement by

aste disposal costs.

0.005–0.007 gr/scf, about

ment kilns, were achieved

mately 0.04 gr/scf.

S. Environmental Pro

 under Passamaquoddy

p showed 98% HCl

• On three different runs, VOC (as represented by

alpha-pinene) removal efficiencies of 72.3, 83.1, and74.5% 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

host site downtime) steadily increased from 65% inApril 1993 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 revenuesfrom the sale of fertilizer.

1991 1992 

1990 1993 1994 1995 1996 1997 1998

Design and Construction

8/91

Operation and Reporting

Design completed 4/90

Environmental monitoring plancompleted 3/26/90

Operation initiated 8/91

Construction completed 5/91Preoperational tests initiated 5/91

EPA process completed (EA) 2/16/90

erative agreement awarded 12/20/89

2/94

Project completed/final report issued 2/94

rted 6/89

Operation

completed 9/93
Industrial Applications

ology Recovery Scrub

eves efficient acid gas

ective contact between

y composed of waste

 the slurry as it moves

ults in high SO2 and

uction, and sufficient

wanted constituent in

 recycled as feedstock.

gases (including

the only inputs to the

 dust, potassium

 gas, and distilled

s. There is no waste.

 over three basic

winter shutdowns for

14 separate operating

vals) largely deter

maintenance and

market. Over the pe

993, more than 5,300

in the first operating

nd interval, and 2,600

r loadings varied

periods due to varia

g conditions.

 discovered and cor

roblems were experi

operation.

 the demonstration

inator, which was

ment in the flue gas,

to design a more

failed. However,

mist eliminator prior

s effective. Potassium

sulfate pelletization proved to be a more difficult problem. The cause was eventually isolated and found tobe excessive water entrainment due to carry-over ofgypsum and syngenite. Hydroclones were installed inthe crystallizer circuit to separate the very fine gypsumand syngenite crystals from the much coarser potassium sulfate crystals. Although the correction wasmade, it was not completed in time to realize pelletproduction during the demonstration period. After allmodifications were completed, the recovery scrubberentered into the third and final operating interval—April to September 1993. During this interval, recoveryscrubber availability (discounting host site downtime)steadily increased from 65% in April to 99.5% in July.

Environmental Performance

An average 250 ton/day of CKD waste generated

by the Dragon Products plant was used as the solereagent in the recovery scrubber to treat approximately250,000 scfm of flue gas. All the CKD, or approximately10 ton/hr, were renovated and returned to the plant asfeedstock and mixed with about 90 ton/hr of fresh feedto make up the required 100 ton/hr. The alkali in theCKD was converted to potassium-based fertilizer, eliminating all solid waste. Exhibit 2-42 lists the number ofhours per operating period, SO2 and NOx inlet and

outlet readings in pounds per hour, and removal efficiency as a percentage for each operating period.

Exhibit 2-42

Summary of Emissions and Removal Efficiencies

Operating Operating Inlet (lb/hr) Outlet (lb/hr) Removal Efficiency (%)Period Time (hr) SO2 NOx SO2 NOx SO2 NOx1 211 73 320 10 279 87.0 12.82 476 71 284 11 260 84.6 08.63 464 87 292 13 251 85.4 14.04 259 131 252 16 165 87.6 34.55 304 245 293 28 243 88.7 17.16 379 222 265 28 208 87.4 21.37 328 281 345 28 244 90.1 29.38 301 124 278 10 188 91.8 32.49 314 47 240 7 194 85.7 19.010 402 41 244 6 218 86.1 10.511 460 36 315 6 267 83.4 15.012 549 57 333 2 291 95.9 12.413 464 86 288 4 223 95.0 22.614 405 124 274 9 199 92.4 27.4Total operating time 5,316Weighted Average 109 289 12 234 89.2 18.8
Project Fact Sheets 2-151

ies during the demon

SO2 and 18.8% for NOx

nation for the NOx

e at the conclusion of

riod emissions data, an

O2 load impact on removal

 the range of 100 lb/hr or

fficiency averaged

 range of 100–200 lb/hr,

4.1% and up to 98.5%

aine’s Department of

ery scrubberwas sub

imately 0.04 gr/scf and

on rates of 0.005–0.007

current allowable limit.

Economic Performance

The estimated “as-built” capital cost to reconstruct the Dragon 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 significantoperating costs. There are no costs for reagents ordisposal, and no dedicated staffing or maintenanceequipment is required.

The simple payback on the investment is projected in as little as 3.1 years considering various

revenues and avoided costs that may be realized byinstalling a recovery scrubber similar in size to the

one used at Dragon Products. In making this projection, $6,000,000 was added to the “as-built” capitalcosts to allow for contingency, design/permitting,construction interest, and licensing fees.Commercial Applications

Of the approximately 2,000 Portland cement kilns in

the world, about 250 are in the United States andCanada. 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 RecoveryScrubberTM). The applicable market for SO2 control is

estimated at 75% of the 250 installations. If full penetration of this estimated market were realized, approximately 150,000 ton/yr of SO2 reduction could be

achieved.

The scrubber became a permanent part of the

cement plant at the end of the demonstration. A feasibility study has been completed for a Taiwanese ce- ment plant. Contacts Thomas N. Tureen, Project Manager, (207) 773-7166 Passamaquoddy Technology, L.P. 1 Monument Way, Suite 200 Portland, ME 04101 (207) 773-7166 (207) 773-8832 (fax) William E. Fernald, DOE/HQ, (301) 903-9448 John C. McDowell, NETL, (412) 386-6175 References • Passamaquoddy Technology Recovery ScrubberTM: Final Report. Volumes 1 and 2 (Appendices A–M. Passamaquoddy Tribe. February 1994. (Vol. 1 avail- able from NTIS 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 as DE94008316.) • Passamaquoddy Technology Recovery ScrubberTM: Topical Report. Report No. DOE/PC/89657-T1. Pas- samaquoddy Tribe. March 1992. (Available from NTIS as DE92019868.) • Comprehensive Report to Congress on the Clean Coal Technology Program: Cement Kiln Flue Gas Recov- ery Scrubber. Passamaquoddy Tribe. Report No. DOE/FE-0152. U.S. Department of Energy. Novem- ber 1989. (Available from NTIS as DE90004462.) 

logy Recovery ScrubberTM 

 Dragon Products 

maston, Maine.
Industrial Applications
Project Fact Sheets A-1

x A: CCT Project Contacts

Environmental Control DevicesSO2 Control Technologies10-MWe Demonstration of Gas SuspensionAbsorptionParticipant:AirPol, Inc.Contacts:Niels H. Kastrup

(281) 539-3400(281) 539-3411 (fax)nhk@flsmiljous.comFLS miljo, Inc.100 Glenborough DriveHouston, TX 77067

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Confined Zone Dispersion Flue GasDesulfurization DemonstrationParticipant:Bechtel CorporationContacts:Joseph T. Newman, Project Manager

(415) 768-1189(415) 768-2095 (fax)Bechtel CorporationP.O. Box 193965

San Francisco, CA 94119-3965

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

LIFAC Sorbent Injection DesulfurizationDemonstration ProjectParticipant:LIFAC-North AmericaContacts:Darryl Brogan

(412) 497-2144(412) 497-2212 (fax)Kaiser Engineers, Inc.Gateway View Plaza1600 West Carson StreetPittsburgh, PA 15219-1031

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

or obtaining further

Program demonstration

tle, phone number, fax

mail address, if avail

ontact person. In those

cipant consists of more

, or joint venture, the

he contact person. In

bers, and e-mail ad

OE Headquarters and

 Laboratory (NETL)
NOx Control TechnologiesMicronized Coal Reburning Demonstration forNOx ControlParticipant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)New York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Demonstration of Coal Reburning for CycloneBoiler NOx ControlParticipant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)dot.k.johnson@mcdermott.comMcDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

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

mcdowell@netl.doe.gov

Full-Scale Demonstration of Low-NOx CellBurnerRetrofitParticipant:The Babcock & Wilcox CompanyContacts:Dot K. Johnson

(330) 829-7395(330) 829-7801 (fax)dot.k.johnson@mcdermott.comMcDermott Technology, Inc.1562 Beeson StreetAlliance, OH 44601

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Evaluation of Gas Reburning and Low-NOx

Burners on a Wall-Fired BoilerParticipant:Energy and Environmental Research CorporationContacts:Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140(949) 859-3194 (fax)General Electric Energy and EnvironmentalResearch Corporation18 MasonIrvine, CA 92618

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

ation Demonstration

micals, Inc.

1

01) 903-9483

ov

386-5991

Applications of

D Process

nc.

ager

01) 903-9483

ov

386-5991
Project Fact Sheets A-3

Demonstration of Advanced CombustionTechniques for a Wall-Fired BoilerParticipant:Southern Company Services, Inc.Contacts:John N. Sorge, Research Engineer

(205) 257-7426(205) 257-5367 (fax)Southern Company Services, Inc.P.O. Box 2641Birmingham, AL 35291-8195

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James R. Longanbach, NETL, (304) 285-4659

jlonga@netl.doe.gov

Combined SO2 /NOx Control TechnologiesMilliken Clean Coal Technology DemonstrationProjectParticipant:New York State Electric & Gas CorporationContacts:Jim Harvilla

(607) 762-8630(607) 762-8457 (fax)New York State Electric & Gas CorporationCorporate Drive—Kirkwood Industrial ParkP.O. Box 5224Binghamton, NY 13902-5224

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

SNOXTM Flue Gas Cleaning DemonstrationProjectParticipant:ABB Environmental SystemsContacts:Paul Yosick, Project Manager

(865) 693-7550(865) 694-5213 (fax)Alstom Power, Inc.1409 Center Point BoulevardKnoxville, TN 37932

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

LIMB Demonstration Project Extension andCoolside DemonstrationParticipant:The Babcock & Wilcox CompanyContacts:Paul Nolan

(330) 860-1074(330) 860-2045 (fax)The Babcock & Wilcox Company20 South Van Buren AvenueP.O. Box 351Barberton, OH 44203-0351

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

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

mcdowell@netl.doe.gov

atalytic Reduction

f NOx Emissions from

ers

Inc.

ces, Inc.

8195

301) 903-9483

gov

 386-5991

v

Advanced

on Techniques for the

from Coal-Fired

Inc.

ces, Inc.

8195

301) 903-9483

gov

 386-5991

v
 Cleanup

any

.com

nc.

01) 903-9483

ov

386-5991

 Gas Reburning and

arch Corporation

esident

d Environmental

1) 903-9483

v

-6079

McIntosh Unit 4B Topped PCFB DemonstrationProjectParticipant:City of Lakeland, Lakeland ElectricContacts:Alfred M. Dodd, Project Manager

(863) 834-6461(863) 834-6344 (fax)Lakeland Electric501 E. Lemon StreetLakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald L. Bonk, NETL, (304) 285-4889

dbonk@netl.doe.gov

JEA Large-Scale CFB Combustion DemonstrationProjectParticipant:JEAContacts:Joey Duncan

(904) 714-4831(904) 714-4895 (fax)JEA4377 Heckscher Drive, NSRPCOJacksonville, FL 32256

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

Integrated Dry NOx/SO2 Emissions Control

SystemParticipant:Public Service Company of ColoradoContacts:Terry Hunt, Project Manager

(303) 571-7113(303) 571-7868 (fax)thunt@ueplaza.comUtility Engineering550 15th Street, Suite 900Denver, CO 80202-4256

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, NETL, (412) 386-6079

hebb@netl.doe.gov

Advanced Electric PowerGenerationFluidized-Bed CombustionMcIntosh Unit 4A PCFB Demonstration ProjectParticipant:City of Lakeland, Lakeland ElectricContacts:Alfred M. Dodd, Project Manager

(863) 834-6461(863) 834-6488 (fax)Lakeland Electric501 E. Lemon StreetLakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald L. Bonk, NETL, (304) 285-4889

dbonk@netl.doe.gov
Project Fact Sheets A-5

roject

ce Corporation as

 Company

Service Corporation

) 903-9434

04) 285-4784

roject

mission

Transmission

) 903-9434

86-5981

Integrated Gasification Combined-CycleKentucky Pioneer IGCC Demonstration ProjectParticipant:Kentucky Pioneer Energy, LLCContacts:H. H. Graves, President

(513) 621-0077(513) 621-5947 (fax)hhgraves@globalenergyinc.comKentucky Pioneer Energy, LLC312 Walnut Street, Suite 2000Cincinnati, OH 45202

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Douglas M. Jewell, NETL, (304) 285-4720

doug.jewell@netl.doe.gov

Piñon Pine IGCC Power ProjectParticipant:Sierra Pacific Power CompanyContacts:Jeffrey W. Hill, Director, Power Generation

(775) 834-5650(775) 834-4604 (fax)jhill@sppc.comSierra Pacific Power CompanyP.O. Box 10100Reno, NV 89520-0024

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, NETL, (304) 285-4784

dgeili@netl.doe.gov

Web Site:www.sierrapacific.com/utilserv/electric/pinon/

Tampa Electric Integrated GasificationCombined-Cycle ProjectParticipant:Tampa Electric CompanyContacts:Donald E. Pless, Director, Advanced Technology

(813) 228-1111, ext. 46201(813) 641-5300 (fax)TECO EnergyP.O. Box 111Tampa, FL 33601-0111

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Web Site:www.teco.net/teco/TEKPlkPwrStn.htmlWabash River Coal Gasification RepoweringProjectParticipant:Wabash River Coal Gasification Repowering Project

Joint Venture

Contacts:Phil Amick, Director of Gasification Development

(713) 374-7252(713) 374-7279 (fax)pramick@globalenergyinc.comGlobal Energy, Inc.1000 Louisiana St., Suite 1550Houston, TX 77002

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Leo E. Makovsky, NETL, (412) 386-5814

makovsky@netl.doe.gov
Engines

and Export Authority

nager II

ment and Export

0

903-9434

12) 386-4521

ov

ion Project

t

903-9434

86-5991

Coal Processing for Clean FuelsIndirect LiquefactionCommercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOHTM) ProcessParticipant:Air Products Liquid Phase Conversion Company,

L.P.

Contacts:Edward C. Heydorn, Project Manager

(610) 481-7099(610) 706-7299 (fax)heydorec@apci.comAir Products and Chemicals, Inc.7201 Hamilton BoulevardAllentown, PA 18195-1501

Edward Schmetz, DOE/HQ, (301) 903-3931

edward.schmetz@hq.doe.gov

Robert M. Kornosky, NETL, (412) 386-4521

robert.kornosky@netl.doe.gov

Coal Preparation TechnologiesAdvanced Coal Conversion ProcessDemonstrationParticipant:Western SynCoal LLCContacts:Ray W. Sheldon, P.E., Director of Development

(406) 252-2277, ext. 456(406) 252-2090 (fax)Western SynCoal LLCP.O. Box 7137Billings, MT 59103-7137

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk III, NETL, (412) 386-6406

joseph.renk@netl.doe.gov

Development of the Coal Quality ExpertTMParticipants:ABB Combustion Engineering, Inc. and CQ Inc.Contacts:Clark D. Harrison, President

(724) 479-3503(724) 479-4181 (fax)CQ Inc.160 Quality Center Rd.Homer City, PA 15748

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk III, NETL, (412) 386-6406

joseph.renk@netl.doe.gov

Web Site:www.fuels.bv.com:80/cqe/cqe.htm
Project Fact Sheets A-7

ation Project

rector

uite 260

01) 903-9443

ov

4) 285-4720

Industrial ApplicationsBlast Furnace Granular-Coal Injection SystemDemonstration ProjectParticipant:Bethlehem Steel CorporationContacts:Robert W. Bouman, Manager

(610) 694-6792(610) 694-2981 (fax)Bethlehem Steel CorporationBuilding C, Room 211Homer Research LaboratoryMountain Top CampusBethlehem, PA 18016

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Leo E. Makovsky, NETL, (412) 386-5814

makovsky@netl.doe.gov

Clean Power from Integrated Coal/Ore Reduction(CPICORTM)Participant:CPICORTM Management Company, LLCContacts:Reginald Wintrell, Project Director

(801) 227-9214(801) 227-9198 (fax)CPICORTM Management Company, LLCP.O. Box 2500Provo, UT 84603

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Douglas M. Jewell, NETL, (304) 285-4720

doug.jewell@netl.doe.gov

Advanced Cyclone Combustor with InternalSulfur, Nitrogen, and Ash ControlParticipant:Coal Tech CorporationContacts:Bert Zauderer, President

(610) 667-0442(610) 667-0576 (fax)coaltechbz@compuserve.comCoal Tech CorporationP.O. Box 154Merion Station, PA 19066

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

James U. Watts, NETL, (412) 386-5991

james.watts@netl.doe.gov

Cement Kiln Flue Gas Recovery ScrubberParticipant:Passamaquoddy TribeContacts:Thomas N. Tureen, Project Manager

(207) 773-7166(207) 773-8832 (fax)tntureen@gwi.comPassamaquoddy Technology, L.P.1 Monument Way, Suite 200Portland, ME 04101

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

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

mcdowell@netl.doe.gov
ification Test

ystems Engineer

301) 903-9448

v

12) 386-4521

ov
Project Fact Sheets B-1

x B: Acronyms, Abbreviations, and

viations, and

us

enheit

lowatt

n

demark

stion Engineering, Inc.

nmental Systems

circulating fluidized

tle, Inc.

gy Outlook 1999

gy Outlook 2000

gy Review 1998

fluidized-bed

e gas desulfurization

trial Development and

ority

erfire air

ticulate filter

etractable Injection

Lanes

ASME American Society of Mechanical

Engineers

Ass’n. AssociationATCF after tax cash flowsatm atmosphere(s)avg. averageBFGCI blast furnace granular-coal injectionBG British GasBtu British thermal unit(s)Btu/kWh British thermal units per kilowatthourB&W The Babcock & Wilcox CompanyCAAA Clean Air Act Amendments of 1990CaCO3 calcium carbonate (calcitic

limestone)

CaO calcium oxide (lime)Ca(OH)2 calcium hydroxide (calcitic

hydrated lime)

Ca(OH)2•MgO dolomitic hydrated limeCa/N calcium-to-nitrogenCAPI Clean Air Power InitiativeCa/S calcium-to-sulfurCaSO3 calcium sulfiteCaSO4 calcium sulfateCCOFA close-coupled overfire airCCT clean coal technologyCCTDP Clean Coal Technology

Demonstration Program

CCT I First CCT Program solicitationCCT II Second CCT Program solicitationCCT III Third CCT Program solicitationCCT IV Fourth CCT Program solicitationCCT V Fifth CCT Program solicitationCCT Program Clean Coal Technology

Demonstration Program

CD-ROM Compact disk-read only memoryCDL® Coal-Derived Liquid®CEQ Council on Environmental QualityCFB circulating fluidized-bedC/H carbon/hydrogenCKD cement kiln dustCO carbon monoxideCO2 carbon dioxideCOP Conference of PartiesCT-121 Chiyoda Thoroughbred-121CQETM Coal Quality ExpertTMCQIMTM Coal Quality Impact ModelTMCX categorical exclusionCZD confined zone dispersionDER discrete emissions reductionDME dimethyl etherDOE U.S. Department of EnergyDOE/HQ U.S. Department of Energy

Headquarters

DSE dust stabilization enhancementDSI dry sorbent injectionEA environmental assessment
vironmental

oration

vironmental

er, University of

d combined cycle

ation Administration

 impact statement

 Information Volume

 monitoring plan

mental Protection

Act of 1992

c Power

Company

 Research Institute

ecipitator

sale generator

combustion

onvention on Climate

y Regulatory

y Technology Center

urization

ignificant impact

forced plastic

are feet, cubic feet

bic feet

GE General ElectricGHG greenhouse gasesGNOCIS Generic NO

x Control Intelligent

System

gpm gallons per minutegr grainsGR gas reburningGR-LNB gas reburning and low-NOx burner

GR-SI gas reburning and sorbent injectionGSA gas suspension absorptionGVEA Golden Valley Electric AssociationGW gigawatt(s)GWe gigawatt(s)-electricH elemental hydrogenH2 molecular hydrogen

H2S hydrogen sulfide

H2SO4 sulfuric acid

HAP hazardous air pollutantHCl hydrogen chlorideHF hydrogen fluorideHGPFS hot gas particulate filter systemHHV higher heating valuehr. hour(s)HRSG heat recovery steam generatorID Induced DraftIEA International Energy AgencyIEO99 International Energy Outlook 1999IEO2000 International Energy Outlook 2000IGCC integrated gasification combinedcyclein, in2, in3 inch(es), square inches, cubic

inches

JBR Jet Bubbling Reactor®KCl potassium chlorideK2SO4 potassium sulfate

kW kilowatt(s)kWh kilowatt-hour(s)lb. pound(s)L/G liquid-to-gas ratioLHV lower heating valueLIMB limestone injection multistage

burner

LNB low-NO

x

 burner

LNCB® low-NO

x

 cell burner

LNCFS Low-NO

x Concentric-Firing System

LOI loss-on-ignitionLPMEOHTM Liquid phase methanolTMLRCWF low-rank coal-water-fuelLSFO limestone forced oxidationMASB multi-annular swirl burnerMB megabyte(s)MCFC molten carbonate fuel cellMCR Maximum Continuous RatingMDEA methyldiethanolamineMgCO3 magnesium carbonateMgO magnesium oxideMHz megahertzmills/kWh mills per kilowatt hourmin. minute(s)mo. month(s)MTCI Manufacturing and Technology

Conversion International

MTF memorandum (memoranda)-to-fileMW megawatt(s)MWe megawatt(s)-electricMWt megawatt(s)-thermalN elemental nitrogenN2 molecular nitrogenn.d. not datedN/A not applicable
Project Fact Sheets B-3

lcium

lfur

oxide

onate

bient Air Quality

ironmental Policy Act

rgy Technology

formerly FETC)

c meter

ide

posed Rulemaking

es

Performance Standards

toichiometric ratio

ot metal

hnical Information

ate Electric & Gas

ygen

ygen

d maintenance

al & Power Systems

port Assessment Group

port Commission

bilization System

puter

Committee of Advisors

nd Technology

irculating fluidized

ved Fuel®

c environmental

ment

PEIS programmatic environmental

impact statement

PEOATM Plant Emission Optimization

AdvisorTM

PENELEC Pennsylvania Electric CompanyPEP progress evaluation planPFBC pressurized fluidized-bed

combustion

PJBH pulse jet baghousePM particulate matterPM10 particulate matter less than 10

microns in diameter

PM2.5 particulate matter less than 2.5

microns in diameter

PON program opportunity noticePRB Powder River Basinppm parts per million (mass)ppmv parts per million by volumePSCC Public Service Company of

Colorado

PSD Prevention of Significant

Deterioration

psi pound(s) per square inchpsia pound(s) per square inch absolutepsig pound(s) per square inch gaugePUHCA Public Utility Holding Company

Act of 1935

PURPA Public Utility Regulatory Policies

Act of 1978

QF qualifying facilityRAM random access memoryR&D research and developmentRD&D research, development, and

demonstration

REA Rural Electrification AdministrationRP&L Richmond Power & Light

ROD Record of DecisionROM run-of-minerpm revolutions per minuteRUS Rural Utility ServiceS sulfurSBIR Small Business Innovation

Research

scf standard cubic feetscfm standard cubic feet per minuteSCR selective catalytic reductionSCS Southern Company Services, Inc.SDA spray dryer absorberSFC Synthetic Fuels CorporationS-H-U Saarberg-Hölter-UmwelttechnikSI sorbent injectionSIP state implementation planSM service markSNCR selective noncatalytic reductionSNRBTM SO

x

-NO

x

-Rox BoxTM

SO2 sulfur dioxide

SO3 sulfur trioxidestd ft3 standard cubic feetSOFA separated overfire airSTTR Small Business Technology

Transfer Program

SVGA super video graphics adapterTAGTM Technical Assessment GuideTMTCLP toxicity characteristics leaching

procedure

TVA Tennessee Valley AuthorityUAF University of Alaska, FairbanksUARG Utility Air Regulatory GroupUBCL unburned carbon lossesU.K. United KingdomUNESCO United Nations Educational,

Scientific and Cultural Organization
ized bed

c compound

aporation system

 forced oxidation

s

umbia

MI MichiganMN MinnesotaMO MissouriMS MississippiMT MontanaNC North CarolinaND North DakotaNE NebraskaNH New HampshireNJ New JerseyNM New MexicoNV NevadaNY New YorkOH OhioOK OklahomaOR OregonPA PennsylvaniaPR Puerto RicoRI Rhode IslandSC South CarolinaSD South DakotaTN TennesseeTX TexasUT UtahVA VirginiaVI Virgin IslandsVT VermontWA WashingtonWI WisconsinWV West VirginiaWY Wyoming

OtherSome companies have adopted an acronym as theircorporate names. The following corporate namesreflect the former name of the company.BGL British Gas LurgiJEA Jacksonville Electric AuthorityKRW Kellogg Rust Westinghouse
Project Fact Sheets Index-1

CCT Projects and Participants

s Suspension Absorp

A-1

dvanced Tangentially

ques for the Reduction

oal-Fired Boilers

3

, Inc. 1-2, 1-16,

76, 2-126, A-6, B-1

2-2, 2-4, 2-60,

ocess Demonstra

-5, 2-124, A-6

 with Internal Sulfur,

l 1-18, 2-3, 2-4,

ation Demonstration

2-5, 2-20, A-2

nversion Company,

-123, A-6

2-8, 2-11, A-1

t and Export Author

6, B-1

4, 2-114, A-6, B-1

The 1-2, 1-7,

64, 2-68, 2-80,

, A-3, A-4, B-1

Bechtel Corporation 2-2, 2-4, 2-12, 2-104, A-1Bethlehem Steel Corporation 1-6, 1-18, 2-3,

2-4, 2-140, A-7

Blast Furnace Granular-Coal Injection System

Demonstration Project 1-18, 2-3, 2-4,2-140, A-7

CCement Kiln Flue Gas Recovery Scrubber 1-18,

2-3, 2-5, 2-148, A-7

Clean Coal Diesel Demonstration Project 1-15,

2-3, 2-4, 2-114, A-6

Clean Power from Integrated Coal/Ore Reduction

(CPICORTM) 1-18, 2-3, 2-4, 2-136, A-7

Coal Tech Corporation 2-3, 2-4, 2-144, A-7Commercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOHTM) Process

2-3, 2-4, 2-122, A-6

Confined Zone Dispersion Flue Gas Desulfurization 1-8, 2-2, 2-4, 2-12, A-1CPICORTM Management Company LLC 2-3,

2-4, 2-136, A-7

CQ Inc. 1-16, 2-3, 2-4, 2-115, 2-126, 2-128,

2-129, A-6

DDemonstration of Advanced Combustion Techniques

for a Wall-Fired Boiler 1-10, 2-2, 2-5,2-30, A-3

Demonstration of Coal Reburning for Cyclone

Boiler 1-10, 2-2, 2-4, 2-34, A-2

Demonstration of Innovative Applications of

Technology for the CT-121 FGD Process2-2, 2-5, 2-24, A-2

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx Emissions

from High-Sulfur, Coal-Fired Boilers 1-10,2-2, 2-5, 2-50, A-3

Development of the Coal Quality ExpertTM

1-17, 2-3, 2-4, 2-126, A-6

EENCOAL Corporation 1-6, 1-17, 2-3, 2-4,

2-130, A-6

ENCOAL® Mild Coal Gasification Project

1-17, 2-3, 2-4, 2-130, A-6

Energy and Environmental Research Corporation 2-2, 2-4, 2-42, 2-44, 2-45, 2-46,

2-72, A-2, A-4, B-2

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection 1-12, 2-2, 2-4, 2-72, A-4

Evaluation of Gas Reburning and Low-NOx Burners

on a Wall-Fired Boiler 1-10, 2-2, 2-4,2-42, A-2

FFour Rivers Energy Modernization Project 2-89Four Rivers Energy Partners, L.P. 2-89Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit 1-10, 2-2, 2-4, 2-38, A-2

HHealy Clean Coal Project 2-3, 2-4, 2-116,

2-118, A-6
ons Control Sys

2-80, 2-82,

91, A-4, B-4

on Demonstration

2-90, A-4

 Demonstration

2-102, A-5

2-3, 2-4,

ctric 2-2, 2-4,

urization Demonstra

4, 2-16, A-1

-4, 2-16, A-1

xtension and Coolside

, 2-4, 2-64, A-3

nstration Project

B Demonstration

2-86, 2-88, A-4

monstration for NOx

2-46, 2-78, A-2

y Demonstration

2-76, A-3

NNew York State Electric & Gas Corporation

2-2, 2-4, 2-5, 2-12, 2-46, 2-76, A-2,A-3, B-3

Nucla CFB Demonstration Project 1-13, 1-15,

2-3, 2-5, 2-96, A-5

OOhio Power Company, The 1-6, 2-3, 2-5,

2-92, A-5

PPassamaquoddy Tribe 2-3, 2-5, 2-148, A-7Piñon Pine IGCC Power Project 1-15, 2-3, 2-5,

2-104, A-5

Public Service Company of Colorado 2-2, 2-5,

2-42, 2-45, 2-80, A-4, B-3

Pulse Combustor Design Qualification Test

1-18, 2-3, 2-5, 2-138, A-7

Pure Air on the Lake, L.P. 1-8, 2-2, 2-5, 2-20,

A-2

SSierra Pacific Power Company 2-3, 2-5,

2-104, A-5

SNOXTM Flue Gas Cleaning Demonstration

Project 1-12, 2-2, 2-4, 2-60, A-3

Southern Company Services, Inc. 1-10, 2-2,

2-5, 2-24, 2-27, 2-30, 2-50, 2-54, A-2,A-3, B-3

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project 1-12, 2-2, 2-4, 2-68, A-4TTampa Electric Company 2-3, 2-5, 2-106

Tampa Electric Integrated Gasification CombinedCycle Project 1-15, 2-3, 2-5, 2-106, A-5ThermoChem, Inc. 2-3, 2-5, 2-138, 2-139, A-7Tidd PFBC Demonstration Project 1-15, 2-3,

2-5, 2-92, A-5

Tri-State Generation and Transmission Association 1-3, 2-3, 2-5, 2-96, A-5

WWabash River Coal Gasification Repowering Joint

Venture 2-3, 2-5, 2-108, A-5

Wabash River Coal Gasification Repowering

Project 1-15, 2-3, 2-5, 2-108, 2-110, A-5

Western SynCoal LLC 1-14, 1-17, 2-3, 2-5,

2-124, A-6