tment of Energy

or Fossil Energy

gton, DC 20585

Clean Coal TechnologyDemonstration ProgramProject Fact SheetsStatus as of March 31, 1999June 1999

DOE/FE-0402
tment of Energy

or Fossil Energy

gton, DC 20585

Clean Coal TechnologyDemonstration ProgramProject Fact SheetsStatus as of March 31, 1999
This report has been reproduced directly from the best available copy.

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

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

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) 903-6434 (fax)gene.kight@hq.doe.gov
Project Fact Sheets i

y Demonstration

Introduction 1Evolution of the Coal Technology Portfolio 2

Program Status 3

Program Accomplishments 6Technology Overview 7Project Fact Sheets 21

Environmental Control Devices 27

SO2 Control Technology 27NO

x Control Technology 49

Combined SO2/NOx Control Technologies 77

Advanced Electric Power Generation 105

Fluidized-Bed Combustion 106Integrated Gasification Combined Cycle 121Advanced Combustion/Heat Engines 131

Coal Processing for Clean Fuels 137Industrial Applications 153CCT Project Contacts A-1Acronyms and Abbreviations B-1

vices

Generation

 Fuels Technology

chnology

ojects
1 Completed Projects by Application Category 32 Project Schedules and Funding by Application Category 43 CCT Program SO2 Control Technology Characteristics 84 Group 1 and 2 Boiler Statistics and Phase II NOx Emission Limits 95 CCT Program NOx Control Technology Characteristics 10

6 CCT Program Combined SO2/NOx Control Technology Characteristics 12

7 CCT Program Advanced Electric Power Generation Technology Characteristics 168 CCT Program Coal Processing for Clean Fuels Technology Characteristics 189 CCT Program Industrial Applications Technology Characteristics 2010 Project Fact Sheets by Application Category 2211 Project Fact Sheets by Participant 2412 Variables and Levels Used in GSA Factorial Testing 3013 GSA Factorial Testing Results 3014 SO2 Removal Performance 4215 Estimated Costs for an AFGD System 4316 Flue Gas Desulfurization Economics 4317 Operation of CT-121 Scrubber 4618 SO2 Removal Efficiency 4619 Particulate Capture Performance 4620 CT-121 Air Toxics Removal 4721 Coal Reburn Test Results 5422 Coal Reburn Economics 5523 NO

x Data from Cherokee Station, Unit 3 62

24 Catalysts Tested 6625 Average SO2 Oxidation Rate 66

ces

 Demonstration
Project Fact Sheets iii

26 Design Criteria 6727 LNCFSTM Configurations 7028 Concentric Firing Concept 7029 Unit Performance Impacts Based on Long-Term Testing 7130 Average Annual NOx Emissions and Percent Reduction 71

31 LOI Performance Test Results 7432 NO

x

 vs. LOI Tests–All Sensitivities 74

33 Typical Trade-Offs in Boiler Optimization 7434 Major Elements for GNOCIS 7535 Effect of Limestone Grind 8036 Pressure Drop vs. Countercurrent Headers 8137 LIMB SO2 Removal Efficiencies 9038 Capital Cost Comparison 9139 Annual Levelized Cost Comparison 9140 Effect of Bed Temperature on Ca/S Requirement 11841 Calcium Requirements and Sulfur Retentions for Various Fuels 11842 CQETM Stand-Alone System Requirements 14643 ENCOAL® Production 150

44 Summary of Emissions and Removal Efficiencies 164

l Technology

Generation

 Fuels Technology

chnology
Project Fact Sheets 1



 

n Coal Technology Demonstration

y Demonstration Pro

of government and

to the Department of

ter a secure and reliable

entally and economical

am represents an invest

vanced coal-based

tate governments pro

cent of the funding.

ts having completed

as yielded clean coal

pable of meeting

mental regulations and

ctric power marketplace.

ding a portfolio of

e U.S. recoverable coal

 continue to supply the

cally and in an environ

 new millennium ap

al technologies have

n. Industry stands ready

vironmental demands of

ally and internationally.

e are cost effective

o control sulfur dioxide

nd particulate matter

neration of technologies

that can produce electricity and other commodities,such as steam and synthetic gas, and provide theefficiencies and environmental performance responsiveto global climate change concerns. The CCT Programtook a pollution prevention approach as well, demonstrating technologies that remove pollutants or theirprecursors from coal-based fuels before combustion.Lastly, new technologies were introduced into themajor coal-using industries, such as steel production, toenhance environmental performance. Thanks in part tothe CCT Program, coal—abundant, secure, and economical—can continue in its role as a key componentin the U.S. and world energy markets.

The CCT Program also has global importance in

providing clean, efficient coal-based technology to aburgeoning energy market in developing countries,largely dependent on coal. World energy consumptionis expected to increase 63 percent by 2020, with almosthalf of the energy increment occurring in developingAsia (including China and India). By 2020, energyconsumption in developing Asia is projected to surpassconsumption in North America. The energy formcontributing most to the growth is electricity, as developing Asia establishes its energy infrastructure. Coal,the predominant indigenous fuel, will be the fuel ofchoice in electricity production. CCTs offer a means tomitigate potential environmental problems associatedwith unprecedented energy growth and to enhance theU.S. economy through equipment sales and engineering services.

World Energy Consumption by Fuel Type, 1996 and

2020.

1996 – 376 Quads2020 – 612 Quads

Source: IEO99, Tables A1 and A2.
2 Project Fact Sheets

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

achieved SO2

 removal efficiencies exceeding 95% and NOx reduction

effectiveness averaging 94%. Ohio Edison is retaining the SNOXTM technology

as part of its environmental control system.

Evolution of the Coal

Technology Portfolio

The CCT Program has been implemented through

a series of five nationwide competitive solicitations.

The first solicitation was directed towards demonstrating the feasibility of future commercial application of

clean coal technology, which would balance the goals

of expanding coal use and minimizing environmental

impact. The next two solicitations sought technologies

that could mitigate the potential impacts of acid rain

from existing coal-fired power plants in response to the

recommendations of the Special Envoys on Acid Rain.

The fourth and fifth solicitations addressed the post2000 energy supply and demand situation with SO2

emissions capped under the CAAA, increased need for

electric power, and the need to alleviate concerns over

global climate change—a situation

requiring technologies with very

high efficiencies and extremely low

emissions.

CCT Program demonstrations

provide a portfolio of technologies

that will enable coal to continue to

provide low-cost, secure energy vital

to the nation’s economy while

satisfying energy and environmental

goals well into the 21st century. This

is being carried out by addressing

four basic market sectors: (1) environmental control devices for

existing and new power plants, (2)

advanced electric power generation

for repowering existing facilities and

providing new generating capacity,

(3) coal processing for clean fuels to convert the

nation’s vast coal resources to clean fuels, and (4)

industrial applications dependent upon coal use.

In response to the initial thrust of the program,

operations have been completed for 17 of 19 projects

that address SO2

 and NOx control for coal-fired boilers.

The resultant technologies provide a suite of costeffective control options for the full range of boiler

types. The 19 environmental control device projects

are valued at more than $704 million. These include

seven NOx emission control systems installed on more

than 1,750 MWe of utility generating capacity, five

SO2 emissions systems installed on approximately 770

MWe, of capacity and seven combined SO2/NOx

emission control systems installed or planned on more

than 665 MWe of capacity.

To respond to load growth as well as growing

environmental concerns, the program provides a range

of advanced electric power generation options for both

repowering and new power generation. These advanced options offer greater than 20 percent reductions

in greenhouse gas emissions; SO2, NOx, and PM

emissions far below New Source Performance Standards (NSPS); and salable solid and liquid by-products

in lieu of solid wastes. Over 1,800 MWe of capacity

are represented by 11 projects valued at more than $3.1

billion. These projects include five fluidized-bed

combustion (FBC) systems, four integrated gasification

combined-cycle (IGCC) systems, and two advanced

combustion/heat engine systems. These projects will

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 coals to high-energy-density, low-sulfur

products. These products have application domestically

for compliance with the Clean Air Act Amendments of

1990 (CAAA). Internationally, both the products and

processes have excellent market potential. Valued at

more than $519 million, the five projects in the coal

processing for clean fuels category represent a diversified portfolio of technologies. Three projects involve

the production of high-energy-density solid fuels, one

of which also produces a liquid product equivalent to

No. 6 fuel oil. A fourth project is demonstrating a new

methanol production process. A fifth effort complements the process demonstrations by providing an

expert computer software system that enables a utility

to assess the environmental, operational, and cost

impact of utilizing coals not previously burned at a

facility, including upgraded coals and coal blends.

Projects were undertaken to address pollution

problems associated with coal use in the industrial
Project Fact Sheets 3

NOx emissions at Georgia Power’s Plant Hammond

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

burners, shown here, and advanced overfire air.

Exhibit 1

Completed Projects by Application Category

Number of Projects

Application Category Completed Total

Operations

Environmental Control Devices

SO2 Control Technology 5 5

NOx Control Technology 6 7

Combined SO2/NOx Control Technology 6 7

Advanced Electric Power Generation

Fluidized-Bed Combustion 2 5

Integrated Gasification Combined Cycle 0 4

Advanced Combustion/Heat Engines 0 2

Coal Processing for Clean Fuels 2 5

Industrial Applications 2 5

Total 23 40

sector. These problems included dependence of the

steel industry on coke and the inherent pollutant

emissions in coke-making; reliance of the cement

industry on low-cost indigenous, and often high-sulfur,

coal fuels; and the need for many industrial boiler

operators to consider switching to coal fuels to reduce

operating costs. The five industrial applications

projects have a combined value of nearly $1.3 billion.

Projects encompass substitution of coal for 40 percent

of coke in iron-making, integration of a direct ironmaking process with the production of electricity,

reduction of cement kiln emissions and solid waste

generation, and demonstrations of an industrial-scale

slagging combustor and a pulse combustor system.

Program Status

The CCT Program has extended the technical,

economic, and environmental performance envelope of

a broad portfolio of advanced coal technologies. As of

March 31, 1999, a total of 23 CCT demonstration

projects have completed operation, 9 are in operation,

2 projects are in construction, and 6 are in design.

Exhibit 1 shows the number of projects having completed operations by application category. Exhibit 2

provides a schedule for the 40 projects as of

March 31, 1999.

Golden Valley Electric Association is adding capacity to its 25 MWe Healy

Unit No. 1 with a 50-MWe slagging combustor unit using 65 percent waste coal.
plishments

ts of the CCT Program

ogy (CCT) Program

ry to respond cost

ve of NOx control

NOx burners) and has

ustry to respond to NOx

he 21st century. The

ded valuable input to

 furnishing real-time

e, over one-third of

capacity in the United

ers, worth a value

so provided a portfolio

es that enable utilities

y to year 2000 CAAA

gies are available for

m old space-con

ely-new large boilers.

ue gas desulfurization

d under the CCT

ate-of-the-art for

by: (1) halving

ficantly reducing

ng by-products instead

ng plant efficiency

re-efficiency devices.

strumental in com

 circulating fluidized

technology through

and Transmission

Association, Inc. project in Nucla, Colorado.An industry consortium joined with DOE tofully evaluate the potential of the technologyfor utility application. The results and theattendant comprehensive database served toestablish ACFB as a commercial offering, withan estimated 9.5 gigawatts of capacity installation worldwide.

• Pressurized Fluidized-bed Combustion (PFBC)

technology is also beginning to make marketpenetration as a result of work performed atThe Ohio Power Company’s Tidd Plant. TheCCT Program demonstration and associateddevelopment work have resulted in severalcommercial sales, including a 360 MW unit inJapan and a 220 MW unit in Germany. Thetechnology represents a new generation ofadvanced power systems, with efficiencies farhigher than conventional coal-fired systems andpollutant emissions far below new sourceperformance standards, without the need ofadd-on emission controls. The work at Tiddalso provided the basis for second generationPFBC demonstrations to be conducted inLakeland, Florida.

• Four IGCC demonstration projects, representing a diversity of gasifier types and cleanup

systems, are pioneering the introduction of anew approach to power generation. Two of thetechnologies are currently operating in acommercial dispatch mode, providing valuableperformance data. The units are attractingworldwide interest because of their potential tosignificantly improve efficiency, reducepollutant emissions, and serve as buildingblocks for even more advanced systems.

• ENCOAL has completed the successful

demonstration of a coal processing technologythat produces a high-energy-density solid fueland a liquid product from low-rank coal. Thesolid fuel is low enough in sulfur to be considered a compliance fuel, i.e., capable of meetingCAAA standards for 2000. Also, the solidproduct has demonstrated combustion characteristics that enable reduced NOx emissions.

The liquid product has most potential as achemical feedstock and can be used as a lowsulfur boiler fuel.

• The Liquid Phase Methanol process

(LPMEOH

TM) at the Eastman Chemical Company in Kingsport, Tennessee is demonstrating

a cost effective means of coproducing electricity and methanol. Continued stable productionof methanol at or beyond design rates fromhigh-sulfur bituminous coal suggests that IGCCwith LPMEOH

TM offers a very clean, highly

efficient means of using high-sulfur coal inchemical and electricity production.

• Demonstration of granular-coal injection at

Bethlehem Steel’s Burns Harbor blast furnaceoperations is proving that coal can replace up to40 percent of the coke requirement inironmaking. This has significant environmentaland cost ramifications because of the magnitudeand extent of pollutant emissions from cokeproduction. Emissions from granular-coalinjection are controlled in the blast furnace.
4 Project Fact Sheets

Exhibit 2

Project Schedules and Funding by Application Category

Calendar 86 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2

Year 

Tri-State--Nucla Advanced Electric Power Generation Ohio Power Wabash River Tampa Electric Sierra Pacific AIDEA ADL--Coal Diesel JEA McIntosh 4A Clean Energy McIntosh 4B ABB CE & CQ Inc. -- CQE Coal Processing for Clean Fuels Rosebud SynCoal ENCOAL Custom Coals Schedule being revised Air Products -- LPMEOH Coal Tech Industrial Applications Passamaquoddy Bethlehem Steel ThermoChem CPICOR 

 - Preaward - Design and Construction - Operation and Reporting (1) - comple
Exhibit 2 (continued)

Project Schedules and Funding by Application Category

Calendar 86 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 200

Year 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 

B&W--LIMB Environmental Control Devices SCS--Wall-Fired EER--GR/SI SCS--Tangentially Fired Bechtel -- CZD B&W--Coal Reburning B&W--LNCB ABB ES--SNOX B&W--SNRB Pure Air on the Lake LIFAC PSC of Colorado AirPol -- GSA EER--GR-LNB SCS--CT-121 SCS--SCR NYSEG -- Milliken NYSEG -- Micronized NOXSO Corporation Schedule being revised 

 - Preaward - Design and Construction - Operation and Reporting
Project Fact Sheets 7

rview

ol Devices

ices are those technolo

ties or installed on new

trolling SO2 and NOx

y be modified and

boiler configuration and

th these technologies.

Sulfur dioxide is an

mbustion, which oxidiz

Fe2S), and organically

fied as a precursor to

 targeted in Title IV of

 effective in 1995,

tionwide. The required

d largely met by switch

2000, Phase II of Title

ting all fossil-fuel-fired

ximately 900 pre-NSPS

ter Phase II require

ching alone is unlikely.

exibility in control

ce trading. This permits

 applied by a utility, as

Recognizing this, the

ovide a portfolio of SO2

ces embody those

 act upon the flue gas

the combustion itself,

ly SO2. Three basic

marily by different

pre-NSPS boiler population impacted by the CAAA. There is a tremendous range in critical factors, e.g., size, type, age, and space availability. On one end of the spectrum are the smaller, older boilers with limited space for adding equipment. For these, sorbent injection techniques hold promise. Sorbent is injected into the boiler or the ductwork, and humidification is incorporated in some fashion to properly condition the flue gas for efficient SO2 cap- ture. Equipment size and complexity are held to a minimum to keep capital costs and space requirements low. Both limestone and lime sorbents are used. Lime- stone costs are about one-third that of hydrated lime; but, limestone must be conditioned (calcined), and even then, it is less effective in SO2 capture (under simple sorbent injection conditions) than hydrated lime. Where limestone is used, it is injected in the boiler to produce calcium oxide, which reacts with SO2 to form solid compounds of calcium sulfite and calci- um sulfate. Both limestone and lime injection require the presence of water (humidification) and a calcium- to-sulfur (Ca/S) molar ratio of about 2.0 for sulfur capture efficiencies of 50 to 70 percent. In the mid-range of the spectrum are 100 to 300 MWe boilers less than 30 years old and somewhat space constrained. For many of these, an increase in higher equipment cost is justified by enhanced perfor- mance. The approach involves introduction of a reactor vessel in the flue gas stream to create conditions to enhance SO2 capture beyond that achievable with the simpler sorbent injection systems. Lime, as opposed to limestone, is used and sulfur capture efficiencies up to 90 percent can be achieved at a Ca/S molar ratio of 1.3 to 2.0. This category of control device is called a spray dryer (because the solid by-product from the reaction is dry). At the other end of the spectrum are the larger (300 MWe and more) boilers with some latitude in space availability, as well as new capacity additions. For these boilers, advanced flue gas desulfurization (AFGD) wet scrubbers, with higher capital cost, but higher sulfur capture efficiency than other approaches, become cost effective. These systems apply larger and somewhat more complex reactors that drive up the capital cost. However, the sorbent is limestone and SO2 removal efficiencies greater than 90 percent are achieved at a Ca/S molar ratio of about 1.0, making operating costs significantly lower than those of the other two approaches. Furthermore, although the initial AFGD solid by-product is in slurry form, it is dewa- tered to produce gypsum—a salable product. Under the CCT Program, two sorbent injection systems, one spray dryer, and two AFGD processes were successfully demonstrated. All have completed testing. Exhibit 3 briefly summarizes the characteristics and performance of the technologies that are described in more detail in the project fact sheets. Unique CT-121 SO2 scrubber at Plant Yates combined a number of functions and eliminated process steps.
Exhibit 3

CCT Program SO2 Control Technology Characteristics

Coal Sulfur SO2 Fact

Process Content Reduction Sheet

Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.5–2.5% 50% 32

urization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% 70% 36

humidification vessel and sorbent recycle

Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7–3.5% 60–90% 28

particulate recycle (lime sorbent)

on AFGD—co-current flow, integrated quench absorber tower and reaction 2.25–4.7% 94% 40

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

plications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2–3% 90+% 44

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

vanced flue gas desulfurization absorber module

ection piping.

This view shows the sorbent (top) and water (bottom) inlet connections to the Pure

Air absorber module.
Project Fact Sheets 9

 Nitrogen oxides (NOx

)

trogen contained within

oxidation of the nitro

res of combustion

n of NOx at the flame

s reaction of hydrocar

c nitrogen represents a

ssions. To control fuel

ortant to limit oxygen at

To control thermal

k temperatures.

tified both as a precur

Title IV of the CAAA)

rmation (targeted under

fective in 1995, required

169 wall- and tangentially-fired coal units to reduceemissions to 0.50 and 0.45 lb/106 Btu, respectively. In

2000, Phase II of Title IV will come into effect,impacting all fossil-fueled units, but most of all, thebalance of the pre-NSPS coal-fired units (seeExhibit 4). Ozone nonattainment prompted the U.S.Environmental Protection Agency (EPA) to issue aNO

x transport State Implementation Plan (SIP) call for

22 states and the District of Columbia to cut NOx

emissions 85 percent below 1990 rates or achieve a0.15 lb/106 Btu emission rate by May 2003.

 The CCT Program has sought to provide a

number of NOx control options to cover the range of

boiler types and emission reduction requirements.

Control of NOx emissions can be accomplished by

either modifying the combustionprocess or acting upon the products ofcombustion (or combinations thereof).Combustion modification technologies include low-NOx burners (LNBs),advanced overfire air (AOFA), andreburning processes using either gasor coal. Processes used to act uponflue gas include selective catalyticreduction (SCR) and selectivenoncatalytic reduction (SNCR).

LNBs regulate the initial fuel-air

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

AOFA involves injection of air above the primary

combustion zone to allow the primary combustion tooccur without the amount of oxygen needed forcomplete combustion. This oxygen deficiency mitigates fuel-bound NOx formation. AOFA injected at

high velocity creates turbulent mixing to complete thecombustion in a gradual fashion at lower temperaturesto mitigate thermal NOx formation. Usually, AOFA isused in combination with LNBs; but alone, AOFA canachieve 10 to 25 percent NOx emission reductions.

The LNB/AOFA systems generally can achieve NOxemission reductions of 60 to 67 percent.

Advanced control systems using artificial intelligence are also becoming an integral part of NOx

control systems. These systems can handle thenumerous parameters and optimize performance toreduce NOx while enhancing boiler performance.

Exhibit 4

 2 Boiler Statistics

NOx Emission Limits

Phase II

No. of NOx Emission Limits

Boilers (lb/106 Btu)

299 0.40

308 0.46

36 0.68

55 0.86

We 26 0.84

28 0.80

Agency, Nitrogen Oxides Emission Reduction

Group 1 and Group 2 Boilers (downloaded from

noxfs3.html).

A portion of ABB Combustion Engineering’s Low-NOx

Concentric Firing System (LNCFSTM) is shown beinginstalled on a tangentially-fired boiler.
f the fuel input to the

ts above the primary

oal is typically used as

to 30 percent of the

rning fuel is injected

nt in oxygen (a

one). NOx entering this

ing in elemental

ed in a burnout zone

A system. Reburning

, including cyclone

ission reductions of 50

Exhibit 5

CCT Program NOx Control Technology Characteristics

Boiler Size/ NO

x

Fact

Process Type Reduction Sheet

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

Low-NOx Burners LNB/gas reburning/AOFA—13–18% gas heat input 172-MWe/wall 37–65% 60

onstration Coal reburning—30% heat input 148-MWe/tangential 50–60% (goal) 50

50-MWe/cyclone

-NO

x Cell Burner LNB—separation of coal and air ports on plug-in unit 605-MWe/cell burner 48–58% 56

bustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500-MWe/wall 68% 72

and artificial intelligence controls

nced Tangentially- LNB/AOFA—advanced LNB with close-coupled 180-MWe/tangential 37–45% 68

 the Reduction of NOx and separated overfire air

s

ytic Reduction SCR—eight catalysts with different shapes and 8.7-MWe/various 80% 64

Ox Emissions chemical compositions

lers

SCR and SNCR can be used alone or in combination with combustion modification. These processes

use ammonia or urea in a reducing reaction with NOxto form elemental nitrogen and water. SNCR can onlybe used at high temperatures (1,600 to 2,200 oF) wherea catalyst is not needed. SCR is typically applied attemperatures between 600 to 800 oF. Generally, SNCRand SCR systems alone can achieve NOx emission

reductions of 30 to 50 percent and 80 to 90+ percent,respectively.

Under the CCT Program, seven NOx control

technologies were assessed encompassing LNBs,AOFA, reburning, SNCR, SCR, and combinationsthereof. Six of the projects have completed operations

and the remaining project is in the operations phase.Exhibit 5 briefly summarizes the characteristics andperformance of the technologies that are described inmore detail in the project fact sheets.

Combined SO2/NOx Control Technology.

Combined SO2/NOx control systems encompass thosetechnologies that combine previously described controlmethods and those that apply other, synergistictechniques. Three of the projects combine either LNBsor gas reburning with sorbent injection. In one of these,SNCR is used with LNBs to enhance performance.Another project combines a number of techniques toimprove overall system performance, such as LNBswith SNCR, unique space-saving and durable wet-
Project Fact Sheets 11

New York State Electric & Gas Corporation’s Milliken Station is hosting the demonstration of a combination of unique

SO2 and NOx control technologies.

ve, and artificial

ce of the seven projects

viously described.

porates an SCR

ilter bag for NOx

ction for SO2 control.

, operated in a standard

he SCR catalyst, allows

ol temperatures, forms a

nhance SO2 capture,

articulate capture.

ed by catalytic oxida

sation of the SO3 in the

lfuric acid. Following

ation allows the SCR to

ncentration without

nia passing to the second

ater vapor, nitrogen, and

rmore, most particu

am baghouse are

ndensing unit. The

.

enerable adsorber

gnated with sodium

and NOx. The adsorber

ieve effective mixing

 is then processed

 release the NOx and

ed bed. The flue gas

move particulates.

SO2/NOx control

leted operations and

and design phase.

e characteristics and

s that are described in

heets.
Exhibit 6

CT Program Combined SO2/NOx Control Technology Characteristics

Coal Sulfur SO2/NOx Fact

Process Content Reduction Sheet

tension and LNB/sorbent injection—furnace and duct injection, calcium-based 1.6–3.8% 60–70%/40–50% 88

sorbents

ns LNB/SNCR/sorbent injection—calcium- and sodium-based 0.4% 70%/62–80% 100

sorbents used in duct injection

as Reburning Gas reburning/sorbent injection—calcium-based sorbents used in 3.0% 50–60%/67% 96

duct injection

 Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5–4.0% 98%/53–58% 78

durable scrubber design

leanup SCR/high temperature baghouse/sorbent injection—SCR in high- 3.4% 80–90%/90% 92

temperature filter bag and calcium-based sorbent injection

monstration SCR/oxidation catalyst/sulfuric acid condenser—synergistic 3.4% 95%/94% 84

catalyst effect and no solid waste

e NOXSO Regenerable adsorbent—spherical alumina beads impregnated 3.4% 98% (goal)/75% (goal) 82

nup System with sodium carbonate in fluidized-bed adsorber (planned)
Project Fact Sheets 13

Tri-State Generation and Transmission Association’s

Nucla Station was host to demonstration of the world’s firstutility-scale AFBC.

wer Generation

eneration technologies

mentally superior

dvanced electric power

der the CCT Program

xpansion needs requi

nd, off setting nuclear

ent CAAA emission

technologies are charac

cy, very low pollutant

ons, few solid waste

mics. Advanced electric

may be deployed in

truction to better match

smaller capacity require

onutility generators.

anced electric power

strated in the CCT

 these five technologies

fic projects and technol

ail in the fact sheets.

on. Fluidized-bed

ssions of SO2 and NOx

meters and by injecting

stone) into the combus

al. Pulverized coal

dized on jets of air in

r released from the coal

nt in the bed to form a

 removed with the ash.

nign solid that can be

ricultural and construc

 percent of the SO2 can

At combustion temperatures of 1,400 to 1,600 oF,

the fluidized mixing of the fuel and sorbent enhancesboth combustion and sulfur capture. The operatingtemperature range is about half that of a conventionalpulverized-coal boiler and below the temperature atwhich thermal NO

x is formed. In fact, fluidized-bed NOx

emissions are about 70 to 80 percent lower than those forconventional pulverized-coal boilers. Thus, fluidized-bedcombustors substantially reduce both SO2 and NOxemissions. Also, fluidized-bed combustion has thecapability of using high-ash coal, whereas conventionalpulverized-coal units must limit ash content in the coal torelatively low levels.

Two parallel paths were pursued in fluidized-bed

development—bubbling and circulating beds. Bubblingbeds use a dense fluid bed and low fluidization velocityto effect good heat transfer and mitigate erosion of an inbed heat exchanger. Circulating fluidized beds use a relatively high fluidization velocity, which entrains the bed material, in conjunction with hot cyclones to separate and recirculate the bed material from the flue gas before it passes to a heat exchanger. Hybrid systems have also evolved from these two basic approaches. Fluidized-bed combustion can be either atmo- spheric (AFBC) or pressurized (PFBC). AFBC oper- ates at atmospheric pressure while PFBC operates at pressure 6 to 16 times higher. PFBC offers potentially higher efficiency, and consequently, reduced operating costs and waste relative to AFBC, as well as smaller size per unit of power output. Second-generation PFBC integrates the combustor with a pyrolyzer (coal gasifier) to fuel a gas turbine (topping cycle), the waste heat from which is used to generate steam for a steam turbine (bottoming cycle).

The inherent efficiency of the gas turbine and wasteheat recovery in this combined-cycle mode significantly increases overall efficiency. Such advanced PFBCsystems have the potential for efficiencies over50 percent.

Of the five fluidized-bed combustion projects, two

have successfully completed demonstration (one PFBCand one AFBC), and the other three are in the projectdefinition and design phase.

Integrated Gasification Combined Cycle. The

integrated coal gasification combined-cycle processhas four basic steps: (1) fuel gas is generated from coalreacting with high-temperature steam and an oxidant(oxygen or air) in a reducing atmosphere; (2) the fuelgas is either passed directly to a hot-gas cleanup systemto remove particulates, sulfur, and nitrogen compoundsor first cooled to produce steam and then cleanedconventionally; (3) the clean fuel gas is combusted in agas turbine generator to produce electricity; and (4) the
Tampa Electric Company’s Polk Power Station Unit 1,

a 250-MWe IGCC greenfield installation, is currently inoperation. It is one of the world’s cleanest and mostadvanced coal power plants.

as from the gas turbine

eam generator, and

tional electricity in a

ined-cycle systems are

cient of the emerging

itrogen compounds,

ore the fuel is burned

combustion air is

much lower volume of

mbustion scrubber.

 gas requires that the

high degree, not only

protect downstream

ine, from erosion and

in the coal is released

H2S) rather than as

ch of the sulfur

orbent injected into the

en commercial hydro

hich remove up to

uire the fuel to be

nalty. Therefore, hot

ng demonstrated. In

al gas is passed

ticles, such as zinc

lfur contaminants at

F, and the compound

ith little loss of effec

generation stage are

lfur-containing com

uce useful by-prod

f removing more than

gas stream. With hot

 the potential for

High levels of nitrogen removal are also possible.

Some of the coal’s nitrogen is converted to ammonia,which can be almost totally removed by commerciallyavailable chemical processes. NOx formed in the gasturbine can be held to well within allowable levels bystaged combustion in the gas turbine or by addingmoisture to control flame temperature.

Integrated Gasification Fuel Cell. A typical fuel

cell system using coal as fuel includes a coal gasifierwith a gas cleanup system, a fuel cell to use the coalgas to generate electricity (direct current) and heat, aninverter to convert direct current to alternating current,and a heat-recovery system. The heat-recovery systemwould be used to produce additional electric power in abottoming steam cycle.

Energy conversion in fuel cells is more efficient

(up to 60 percent, depending on fuel and type of fuelcell) than traditional energy conversion devices. Fuelcells directly transform the chemical energy of a fueland an oxidant (air or oxygen) into electrical energyinstead of going through an intermediate step, i.e.,burner, boiler, turbines, and generators. Each fuel cellincludes an anode and a cathode separated by anelectrolyte layer. In a coal gasification/fuel cellapplication, coal gas is supplied to the anode and air issupplied to the cathode to produce electricity and heat.

Of the four IGCC projects, three are in operation

and one is in the project definition and design phase.

Coal-Fired Diesel. Coal-fired diesels use either a

coal-oil or coal-water slurry fuel drive an electricgeneration system. The hot exhaust from the dieselengine is routed through a heat-recovery unit to produce steam for a steam-turbine electric generatingsystem (combined cycle). Environmental controlsystems for SO2, NOx, and particulate removal treat thecooled exhaust before release to the atmosphere. Thediesel system is expected to achieve 41 to 48 percentthermal efficiencies. The 5–20 MWe capacity range ofthe technology would be most amenable to distributedpower applications. The CCT coal-fired diesel projectis in construction.

Slagging Combustor. Many new coal-burning

technologies are designed to remove the coal ash asmolten slag in the combustor rather than the furnace.Most of these slagging combustors are based on acyclone combustor concept. In a cyclone combustor,coal is burned in a separate chamber outside the furnace cavity. The hot combustion gases then pass intothe boiler where the actual heat exchange takes place.
Project Fact Sheets 15

e combustor is that the

vity where it could

er heat transfer efficien

wn into the furnace, the

 so hot that mineral

hence the name slagging

 cyclone) forces the slag

stor where it can be

y positioning air injec

sted in stages, NOx

0 to 80 percent. Injecting

chamber has the poten

by 90 percent in combi

ber. Advanced slagging

red units in both utility

e used to retrofit older,

The CCT advanced

n operation.

process characteristics

c power generating

 detail in the project

SPPC’s Piñon Pine project demonstrates air-blown, fluidized-bed IGCC technology using hot gas cleanup, and evaluates

a low-Btu gas combustion turbine.
Exhibit 7

ogram Advanced Electric Power Generation Technology Characteristics

Process Size Fact Sheet

nstration Project Pressurized circulating fluidized-bed combustion 137-MWe (net) 106

McIntosh 4A with pyrolyzer and topping combustor 157-MWe + 103-MWe (net) 108

ct Pressurized bubbling fluidized-bed combustion 70-MWe (net) 112

Atmospheric circulating fluidized-bed combustion 297.5-MWe (gross); 110

ect 265-MWe (net)

ct Atmospheric circulating fluidized-bed combustion 100-MWe (net) 116

mbined Cycle

oject Oxygen-blown, slagging fixed-bed gasifier with 477-MWe (net); 122

cold gas cleanup 1.25 MWe MCFC

Air-blown, fluidized-bed gasifier with hot gas cleanup 107 MWe (gross); 124

99-MWe (net)

cation Oxygen-blown, entrained-flow gasifier with hot and 313 MWe (gross); 126

cold gas cleanup 250-MWe (net)Oxygen-blown, two-stage entrained-flow gasifier with 296-MWe (gross); 128

cold gas cleanup 262-MWe (net)

t Engines

Advanced slagging combustor, spray dryer with sorbent 50-MWe (nominal) 132

recycle

n Project Coal-fueled diesel engine 6.4-MWe (net) 134
Project Fact Sheets 17

Clean Fuels

ory includes a range of

ce high-energy-density,

d fuels, as well as

ating impacts of coal

Coals International

ning techniques are

 an already high Btu

h contains sulfur in the

n compound. A dense

zed magnetite effective

yritic sulfur. But,

ot remove the organi

um-cyclone processed

ompliance coals

ents) if the organic

 processed compliance

For coals with signifi

bents and other addi

he sulfur released upon

nto compliance. This

crubbing CoalTM.

resolution of

nership’s advanced

 mostly physical

ow-sulfur subbituminous

sture and secondarily to

 enhance the energy

r coal. Some conver

al is required, however,

ontaneous combustion)

e process, coal with

5,500 to 9,000 Btu/lb, 25 to 40 percent moisturecontent, and 0.5 to 1.5 percent sulfur is converted to a12,000 Btu/lb product with 1.0 percent moisture and aslow as 0.3 percent sulfur. The SynCoal® product isused at utility and industrial facilities.

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

convert low-Btu, low-sulfur subbituminous coal to ahigh-energy-density, low-sulfur solid product and aclean liquid fuel comparable to No. 6 fuel oil. Mildgasification is a pyrolysis process (heating in theabsence of oxygen) performed at moderate temperatures and pressures. It produces condensable volatilehydrocarbons in addition to solids and gas. Thecondensable fraction is drawn off as a liquid product.Most of the gas is used to provide on-site energyrequirements. The process solid is significantlybeneficiated to produce a 11,000-Btu/lb low-sulfursolid fuel. The demonstration plant processed 500 tonsper day of subbituminous coal and produced 250 tonsper day of solid Process-Derived Fuel (PDF®) and 250barrels per day of Coal-Derived Liquids (CDL®). Boththe solid and liquid fuels have undergone test burns atutility and industrial sites. The project was successfully completed.

The liquid-phase methanol (LPMEOHTM) process

being demonstrated is an 80,000 gallon/day indirectliquefaction process using synthesis gas from a coalgasifier. The unique aspect of the process is the use ofan inert liquid to suspend the conversion catalyst. Thisremoves the heat of reaction and eliminates the needfor an intermediate water-gas shift conversion. Alsoaddressed in the project are the load-following capability of the process by simulating application in an IGCCsystem and fuel characteristics of the unrefinedproduct. Plant operations began in April 1997.

CQ Inc. has developed a personal computer

software package that will serve as a predictive tool toassist utilities in selecting optimal quality coal for aspecific boiler based on operational efficiency, cost,and environmental considerations. Algorithms weredeveloped and verified through comparative testing atbench, pilot, and utility scale. Six large-scale field testswere conducted at five separate utilities. The softwarehas been released for use.

Exhibit 8 summarizes the process characteristics

and size of the coal processing for clean fuels technologies presented in more detail in the project fact sheets.
Exhibit 8

Program Coal Processing for Clean Fuels Technology Characteristics

Process Size Fact Sheet

 ExpertTM Coal Quality ExpertTM computer software Tested at 250–880-MWe 144

ess Demonstration Advanced coal conversion process for upgrading 45 tons/hr 142

low-rank coals

on Project Liquids-from-coal (LFC®) mild gasification to 1,000 tons/day* 148

produce solid and liquid fuels

n of the Liquid-Phase Methanol Liquid phase process for 80,000 gal/day 138

methanol production from coal-derived syngas

rated Approach to Clean Air Dense-medium cyclones with finely sized magnetic and 500 tons/hr 140

sorbent addition for bituminous coals

The LPMEOHTM process produces over 80,000 gal/day

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

The ENCOALmild gasification plant near Gillette, WY,

has operated 12,800 hours and processed approximately260,000 tons of raw coal and produced over 120,000 tons ofPDF® and 121,000 barrels of CDL®.

s advanced coal

 MT, has produced over

ts.
Project Fact Sheets 19

Shown here is the granular-coal injection system.Shown here is the completed Bethlehem Steel Corporation facility to

demonstrate the injection of granulated coal directly into two blast furnaces atBurns Harbor, IN.

ns Technology

 the industrial sector

tal issues and barriers

ustrial processes. These

h continued coal

e in various

mental concerns has to

ulting from producing

making. Two approaches

blem are being demon

t of the coke is dis

of granular coal into a

s essentially burned in

utant emissions are

o first coking the coal).

the need for coke

making process. In this

 into a reactor to pro

a unique reduction

xcess reducing gas is

r for electric

are largely driven by

of choice in cement

d to control SO2 emis

ng solid waste manage

ored the demonstration

The successfully dem

nology Recovery

ust, otherwise discarded

ons, convert the sulfur

izer, return the solid by

ck, and produce distilled

rated and cement kiln

dust waste is converted to feedstock.This technology also has applicationfor controlling pollutant emissions inpaper production and waste-to-energyapplications.

In many industrial boiler applications, the relatively low, stable price of

coal makes it an attractive substitute foroil and gas feedstock. However, drawbacks to conversion of oil- and gasfired units to coal include addition ofSO2 and NOx controls, tube fouling,

and the need for a coolant water circuitfor the combustor. Oil- and gas-firedunits are not high SO2 or NOx emitters,

use relatively tight tube spacing in theabsence of the potential for ash fouling, and the flow of oil or gas cools thecombustor, precluding the need forwater cooling. For these reasons, theCCT Program demonstrated an advanced air-cooled, slagging combustorthat could avoid these potential problems. The cyclone combustor stagesintroduction of air to control NOx

,

injects sorbent to control SO2, slagsthe ash in the combustor to preventtube fouling, and uses air cooling topreclude the need for water circuitry.

A pulse combustor being demonstrated by ThermoChem has a wide

range of applications. The technologycan be used in many coal processes,including coal gasification and wasteto-energy applications.
Exhibit 9

CCT Program Industrial Applications Technology Characteristics

Process Size Fact Sheet

ction System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of hot 154

metal/furnace per day

ith Internal Advanced slagging combustor with staged combustion and sorbent 23 x 106 Btu/hr 158

ol injection

al/Ore Direct reduction iron-making process to eliminate coke; 170-MWe 156

combined-cycle power generation 3,300 tons/day of hot metal

Scrubber Cement kiln dust used to capture SO2; dust converted to feedstock; 1,450 tons/day of cement 162

and fertilizer and distilled water produced

cation Test Advanced combustion using Manufacturing and Technology To be determined 166

Conversion International’s pulse combustor/gasifier

g combustor projects

nstrating granular

e is in operation. The

projects are in the

se and construction

ss characteristics and

s technologies pre

ct fact sheets.
Project Fact Sheets 21

eets

ment contains fact

types of facts sheets are

overview for ongoing

ur page summary for

completed operational

ets for completed

he 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

ng the milestone charts

event the release of

a proprietary nature,

d in the fact sheets are

 only as illustrations of

monstrations. The

y central to the demon

aded area.

eets is provided in

by application category.

ory appear first fol

leted operations. A

cts having completed

ts. Within these

breakdowns, projects are listed alphabetically byparticipant. In addition, Exhibit 10 indicates thesolicitation under which the project was selected; itsstatus as of March 31, 1999; and the page number foreach Fact Sheet. Exhibit 11 lists the projects alphabetically by participant and provides project location andpage numbers.

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.

n Coal Technology Projects

Key to Milestone Charts in Fact Sheets

Each fact sheet contains a bar chart that highlightsmajor milestones—past and planned. The bar chartshows a project’s duration and indicates the time periodfor three general categories of project activities—preaward, design and construction, and operation. Thekey provided below explains what is included in each ofthese categories.

PreawardIncludes preaward briefings, negotiations,and other activities conducted during theperiod between DOE’s selection of theproject and award of the cooperativeagreement.Design and ConstructionIncludes the NEPA process, permitting,design, procurement, construction, preoperational testing, and other activities conducted prior to the beginning of operationof the demonstration.MTF Memo-to-fileCX Categorical exclusionEA Environmental assessmentEIS Environmental impact statementOperationBegins with start-up of operation and includes operational testing, data collection,analysis, evaluation, reporting, and otheractivities to complete the demonstrationproject.
Participant Solicitation/Status Page

ces

Suspension Absorption AirPol, Inc. CCT-III/completed 3/94 28

Gas Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93 32

urization Demonstration Project LIFAC–North America CCT-III/completed 6/94 36

ion Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95 40

plications of Technology for the Southern Company Services, Inc. CCT-II/completed 12/94 44

monstration for NOx Control New York State Electric & Gas Corporation CCT-IV/operational 50

g for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/completed 12/92 52

w-NO

x

 Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 4/93 56

d Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 1/95 60

ytic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95 64

ions from High-Sulfur, Coal-Fired Boilers

vanced Tangentially-Fired Combustion Southern Company Services, Inc. CCT-II/completed 12/92 68

 of NOx Emissions from Coal-Fired Boilers

mbustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/completed 5/98 72

chnologies

e NOXSO SO2/NOx Removal Flue NOXSO Corporation CCT-III/design 82

monstration Project ABB Environmental Systems CCT-II/completed 12/94 84

tension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/completed 8/91 88

leanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5/93 92

Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 10/94 96

 Demonstration Project New York State Electric & Gas Corporation CCT-IV/completed 6/98 78

ns Control System Public Service Company of Colorado CCT-III/completed 12/96 100

eneration

stration Project City of Lakeland, Lakeland Electric CCT-III/design 106

 Demonstration Project City of Lakeland, Lakeland Electric CCT-V/design 108

on Demonstration Project JEA CCT-I/design 110

Exhibit 10

Project Fact Sheets by Application Category

ects having completed operations.
Project Fact Sheets 23

Exhibit 10 (continued)

Project Fact Sheets by Application Category

ect The Ohio Power Company CCT-I/completed 3/95 112

ect Tri-State Generation and Transmission Association, Inc. CCT-I/completed 1/91 116

ined Cycle

roject Clean Energy Partners Limited Partnership CCT-V/design 122

t Sierra Pacific Power Company CCT-IV/operational 124

fication Combined-Cycle Project Tampa Electric Company CCT-III/operational 126

n Repowering Project Wabash River Coal Gasification Repowering Project CCT-IV/operational 128

Joint Venture

Engines

Alaska Industrial Development and Export Authority CCT-III/operational 132

on Project Arthur D. Little, Inc. CCT-V/construction 134

 Fuels

on of the Liquid-Phase Methanol Air Products Liquid Phase Conversion Company, L.P. CCT-III/operational 138

egrated Approach to Clean Air Custom Coals International CCT-IV/operational 140

ocess Demonstration Rosebud SynCoal Partnership CCT-I/operational 142

ty ExpertTM ABB Combustion Engineering, Inc., and CQ Inc. CCT-I/completed 12/95 144

tion Project ENCOAL Corporation CCT-III/completed 7/97 148

jection System Demonstration Project Bethlehem Steel Corporation CCT-III/operational 154

oal/Ore Reduction (CPICORTM) CPICORTM Management Company, L.L.C. CCT-V/design 156

fication Test ThermoChem, Inc. CCT-IV/construction 166

with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/completed 5/90 158

y Scrubber Passamaquoddy Tribe CCT-II/completed 9/93 162

Participant Solicitation/Status Page

ojects having completed operations.
Exhibit 11

Project Fact Sheets by Participant

Project Location Page

nc., and CQ Inc. Development of the Coal Quality ExpertTM Homer City, PA 144

SNOXTM Flue Gas Cleaning Demonstration Project Niles, OH 84

ersion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Kingsport, TN 138

Process

10-MWe Demonstration of Gas Suspension Absorption West Paducah, KY 28

nd Export Authority Healy Clean Coal Project Healy, AK 132

Clean Coal Diesel Demonstration Project Fairbanks, AK 134

y Demonstration of Coal Reburning for Cyclone Boiler NOx Control Cassville, WI 52

y Full-Scale Demonstration of Low-NOx Cell Burner Retrofit Aberdeen, OH 56

y LIMB Demonstration Project Extension and Coolside Demonstration Lorain, OH 88y SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project Dilles Bottom, OH 92

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Seward, PA 32

Blast Furnace Granular-Coal Injection System Demonstration Project Burns Harbor, IN 154

ric McIntosh Unit 4A PCFB Demonstration Project Lakeland, FL 106

ric McIntosh Unit 4B Topped PCFB Demonstration Project Lakeland, FL 108

artnership Clean Energy Demonstration Project Grand Tower, IL 122

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Williamsport, PA 158

ny, L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICORTM) Vineyard, UT 156

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Central City, PA 140

ENCOAL® Mild Coal Gasification Project Gillette, WY 148

arch Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Hennepin, IL 96

Springfield, IL

arch Corporation Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Denver, CO 60

JEA Large-Scale CFB Combustion Demonstration Project Jacksonville, FL 110

LIFAC Sorbent Injection Desulfurization Demonstration Project Richmond, IN 36

Corporation Micronized Coal Reburning Demonstration for NOx Control Lansing, NY 50
Project Fact Sheets 25

Exhibit 11 (continued)

Project Fact Sheets by Participant

Project Location Page

 Corporation Milliken Clean Coal Technology Demonstration Project Lansing, NY 78

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas To be determined 82

Cleanup SystemTidd PFBC Demonstration Project Brilliant, OH 112

Cement Kiln Flue Gas Recovery Scrubber Thomaston, ME 162

lorado Integrated Dry NOx /SO2 Emissions Control System Denver, CO 100

Advanced Flue Gas Desulfurization Demonstration Project Chesterton, IN 40

Advanced Coal Conversion Process Demonstration Colstrip, MT 142

Piñon Pine IGCC Power Project Reno, NV 124

nc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coosa, GA 72

nc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newnan, GA 44

Process

nc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensacola, FL 64

NO

x Emissions from High-Sulfur, Coal-Fired Boilers

nc. 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Lynn Haven, FL 68

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

Tampa Electric Integrated Gasification Combined-Cycle Project Mulberry, FL 126

Pulse Combustor Design Qualification Test Baltimore, MD 166

mission Association, Inc. Nucla CFB Demonstration Project Nucla, CO 116

n Repowering Wabash River Coal Gasification Repowering Project West Terre Haute, IN 128
Environmental Control Devices Project Fact Sheets 27

Environmental Control Devices

SO2 Control Technology
28 Project Fact Sheets Environmental Control Devices

Environmental Control Devices

SO2

 Control Technology

10-MWe Demonstration of Gas

Suspension Absorption

Project completed.

Participant

AirPol, Inc.

Additional Team Members

FLS miljo, Inc. (FLS) —technology owner

Tennessee Valley Authority—cofunder and site owner

Location

West Paducah, McCracken County, KY

Technology

FLS’ Gas Suspension Absorption (GSA) system for

flue gas desulfurization (FGD)

Plant Capacity/Production

10-MWe equivalent slipstream of flue gas from a

175-MWe wall-fired boiler

Coal

Western Kentucky bituminous—

Peabody Martwick, 3.05% sulfur

Emerald Energy, 2.61% sulfur

Andalax, 3.06% sulfur

Warrior Basin, 3.5% sulfur (used intermittently)

Project Funding

Total project cost $7,717,189 100%

DOE 2,315,259 30

Participant 5,401,930 70

Project Objective

To demonstrate the applicability of Gas Suspension

Absorption as an economic option for achieving Phase

II CAAA SO2

 compliance on pulverized coal-fired boilers using high-sulfur coal.

Technology/Project Description

The GSA system consists of a vertical reactor in which

flue gas comes into contact with suspended solids

consisting of lime, reaction products, and fly ash.

About 99% of the solids are recycled to the reactor via

a cyclone while the exit gas stream passes through an

electrostatic precipitator (ESP) or pulse jet baghouse

(PJBH) before being released to the atmosphere. The

lime slurry, prepared from hydrated lime, is injected

through a spray nozzle at the bottom of the reactor.

The volume of lime slurry is regulated with a variablespeed pump controlled by the measurement of the acid

content in the inlet and outlet gas streams. The dilution water added to the lime slurry is controlled by online measurements of the flue gas 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, and mechanical performance of GSA. A statistically designed parametric (factorial) test plan was

developed involving six variables. Beyond evaluation

of the basic GSA unit to control SO2

, air toxic control

tests were conducted, and the effectiveness of a GSA/

ESP and GSA/PJBH to control both SO2

 and particulate

were tested. Factorial tests were followed by continuous runs to verify consistency of performance over
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 29

time.

Results Summary

Environmental

• Ca/S molar ratio had the greatest effect on SO2

 removal, with approach-to-saturation temperature

next, followed closely by chloride content.

• GSA/ESP achieved

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

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

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

with 18 oF approach-to-saturation and 0.12%

chloride, and

– 99.9+% average particulate removal efficiency.

• GSA/PJBH achieved

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

with 18 oF approach-to-saturation and 0.12%

chloride,

– 3–5% increase in SO2

 reduction relative to

GSA/ESP, and

– 99.99+% average particulate removal efficiency.

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

(HF), and 99% on more of most trace metals, except

cadmium, antimony, mercury, and selenium.

(GSA/PJBH removed 99+% of the selenium.)

• The solid by-product was usable as low-grade cement.

Operational

• GSA/ESP lime utilization averaged 66.1% and

GSA/PJBH averaged 70.5%.

• The reactor achieved the same performance as a

conventional spray dryer, but at one-quarter to onethird the size.

• GSA generated lower particulate loading than a

conventional spray dryer, enabling compliance with

a lower ESP efficiency.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

Ground breaking/construction started 5/92

Preaward

12/89 10/90 10/92

Design and Construction

DOE selected project

(CCT-III) 12/19/89 Operation initiated 10/92

Environmental monitoring plan completed 10/2/

92

Design completed 12/91

Cooperative agreement awarded 10/11/90

NEPA process completed (MTF) 9/21/

90

Preoperational tests initiated 9/92

Construction completed 9/92

6/95

Project completed/final report issued 6/95

Operation completed 3/94

• Special steels were not required in construction, and

only a single spray nozzle is needed.

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

simple design.

Economic

• Capital and levelized (15-year) costs for GSA inCapital Cost Levelized Cost

(1990 $/kW) (mills/kWh)

GSA—3 units at 149 10.35

50% capacity

WLFO 216 13.04
30 Project Fact Sheets Environmental Control Devices

Exhibit 13

GSA Factorial Testing Results

Exhibit 12

Variables and Levels Used in

GSA Factorial Testing

Variable Level

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

Ca/S (moles Ca(OH)2

/mole inlet SO2) 1.00 and 1.30

Flyash loading (gr/ft3

, actual) 0.50 and 2.0

Coal chloride level (%) 0.04 and 0.12

Flue 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.

stalled in a 300-MWe plant using 2.6% sulfur coal

are compared below to costs for a wet limestone

scrubber with forced oxidation (WLFO scrubber).

EPRI’s TAGTM cost method was used. Based on

EPRI cost studies of FGD processes, the capital cost

(1990$) for a conventional spray dryer was

$172/kW.

Project Summary

The GSA capability of suspending a high concentration of solids, effectively drying the solids, and

recirculating the solids at a high rate with precise

control results in SO2

 control comparable to that

of wet scrubbers and high lime utilization. The

high concentration of solids provides the sorbent/

SO2

 contact area. The drying enables low approach-to-saturation temperature and chloride

usage. The rapid, precise, integral recycle system

sustains the high solids concentration. The high

lime utilization mitigates the largest operating cost

(lime) and further reduces costs by reducing the

amount of by-product generated. The GSA is

distinguished from the average spray dryer by its

modest size, simple means of introducing reagent

to the reactor, direct means of recirculating unused lime, and low reagent consumption. Also,

injected slurry coats recycled solids, not the

walls, avoiding corrosion and enabling use of

carbon steel in fabrication.

Environmental Performance

Exhibit 12 lists the six variables used in the factorial tests and the levels at which they were applied. Inlet flue gas temperature was held constant

at

320 oF. Factorial testing showed that lime stoichiometry had the greatest effect on SO2

 removal.

Approach-to-saturation temperature was the next

most important factor, followed closely by chloride levels. Although an approach-to-saturation

temperature of 8 oF was achieved without plugging the

system, the test was conducted at a very low chloride

level (0.04%). Because water evaporation rates decrease as chloride levels increase, an 18 oF approachto-saturation temperature was chosen for the higher

0.12% coal chloride level. Exhibit 13 summarizes key

results from factorial testing.

A 28-day continuous run to evaluate the

GSA/ESP configuration was made with bituminous

coals averaging 2.7% sulfur, 0.12% chloride levels, and

18 oF approach-to-saturation temperature. A subsequent

14-day continuous run to evaluate the GSA/PJBH configuration was performed under the same conditions as

those of the 28-day run, except for adjustments in flyash

injection rate from 1.5–1.0 gr/ft3

 (actual).

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

that the overall SO2

 removal efficiency averaged

slightly more than 90%, very close to the set point of

91%, at an average Ca/S molar ratio of 1.40–1.45 moles

Ca(OH)2

/mole inlet SO2. The system was able to adjust

rapidly to the surge in inlet SO2

 caused by switching to

3.5% sulfur Warrior Basin coal for a week. Lime utilization averaged 66.1%. The particulate removal efficiency

averaged 99.9+% and emission rates were maintained

below 0.015 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 efficiency

averaged 99.99+% and emission rates ranged from

0.001–0.003

lb/106 Btu.

All air toxic tests were conducted with 2.7% sulfur,

low-chloride coal with a 12 oF approach-to-saturation

temperature and a high flyash loading of 2.0 gr/ft3 (actual). The GSA/ESP arrangement indicated average

removal efficiencies of greater than 99% for arsenic,

barium, chromium, lead, and vanadium; somewhat less

for 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

mercury removal lower than that of the GSA/ESP sys-
Environmental Control Devices Project Fact Sheets 31

ing 2.6% sulfur coal. The design SO2 removal efficiency

was 90% at a lime feed rate equivalent to 1.30 moles of

Ca/mole inlet SO2

. Lime was assumed to be 2.8 times

the cost of limestone. It was determined that (1) capital

cost (1990$) was $149/kW with three units at 50% capacity and (2) levelized cost (15-year) was 10.35 mills/

kWh with three units at 50% capacity.

A cost comparison run for a WLFO scrubber

showed the capital and levelized costs to be $216/kW

AirPol, Inc. successfully demonstrated the GSA

system at TVA’s Center for Emissions Research.

tem. The removal of HCl and HF was dependent upon

the utilization of lime slurry and was relatively independent of particulate control configuration. Removal

efficiencies were 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 highpressure atomizer nozzles or high-speed rotary nozzles

to achieve uniform, fine droplet size are not required.

Also, recycle of solids is direct and avoids recycling

material in the feed slurry, which would necessitate

expensive abrasion-resistant materials in the

atomizer(s).

The high heat and mass transfer characteristics of

the GSA enable the GSA system to be significantly

smaller than a conventional spray dryer for the same

capacity—one-quarter to one-third the size. This makes

retrofit feasible for space-confined plants and reduces

installation cost. The GSA system slurry is sprayed on

the recycled solids, not the reactor walls, avoiding

direct wall contact and the need for corrosion-resistant

alloy steels. Furthermore, the high concentration of

rapidly moving solids scours the reactor walls and

mitigates scaling. The GSA system generates a significantly lower grain loading than a conventional spray

dryer—2–5 gr/ft3

 for GSA versus 6–10 gr/ft3 for a spray

dryer—enabling compliance even with lower ESP particulate removal efficiency. The GSA system produces

a solid by-product containing very low moisture. This

material contains both fly ash and unreacted lime. With

the addition of water, the by-product undergoes a

pozzolanic reaction, essentially providing the characteristics of a low-grade cement.

Economic Performance

Using the EPRI costing methodology applied to 30 to

35 other FGD processes, economics were estimated for

a moderately difficult retrofit of a 300-MWe boiler burnand 13.04 mills/kWh, respectively. The capital cost

listed in EPRI cost tables for a conventional spray

dryer at 300-MWe and 2.6% sulfur coal was $172/kW

(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

particularly attractive as a CAAA compliance option

for boilers in the 50–250-MWe range. Other major advantages 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 city

of Hamilton, OH, subsidized by the Ohio Coal Development Office. A sale worth $1.3 million has been made to

the U.S. Army for hazardous waste disposal. A GSA

system has been sold to a Swedish iron ore sinter

plant. Sales to Taiwan and India have a combined

value of

$5.5 million.

Contacts

Niels H. Kastrup, (281) 539-3400

FLS Miljo, Inc.

100 Glennborough

Houston, TX 77067

(281) 539-3411 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483

James U. Watts, FETC, (412) 892-5991

References

• 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 the Gas Suspension Absorption

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

90542-T10. AirPol, Inc. June 1995. (Available from
32 Project Fact Sheets Environmental Control Devices

Environmental Control Devices

SO2

 Control Technology

Confined Zone Dispersion

Flue Gas Desulfurization

Demonstration

Project completed.

Participant

Bechtel Corporation

Additional Team Members

Pennsylvania Electric Company—cofunder and host

Pennsylvania Energy Development Authority—

cofunder

New York State Electric & Gas Corporation—cofunder

Rockwell Lime Company—cofunder

Location

Seward, Indiana County, PA (Pennsylvania Electric

Company’s Seward Station, Unit No. 5)

Technology

Bechtel Corporation’s in-duct, confined zone

dispersion flue gas desulfurization (CZD/FGD) process

Plant Capacity/Production

73.5-MWe equivalent

Coal

Pennsylvania bituminous, 1.2–2.5% sulfur

Project Funding

Total project cost* $10,411,600 100%

DOE 5,205,800 50

Participant 5,205,800 50

Project Objective

To demonstrate SO2

 removal capabilities of in-duct

CZD/FGD technology; specifically, to define the optimum process operating parameters and to 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 stream

between the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the

center of the duct by spray nozzles designed to produce a cone of fine spray. As the spray moves downstream and expands, the gas within the cone cools and

the SO2

 is quickly absorbed in the liquid droplets. The

droplets mix 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 reaction products 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

verify the effects on SO2

 removal and the capability of

the ESP to control particulates. The demonstration

was conducted at Pennsylvania Electric Company’s

Seward Station in Seward, PA. One-half of the flue gas

*Additional project overrun costs were funded 100% by the participant

for a final total project cost of $12,173,000.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 33

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

capacity of the

147-MWe Unit No. 5 was routed through a modified,

longer duct between the first- and second-stage ESPs.

Results Summary

Environmental

• Pressure-hydrated dolomitic lime proved to be a

more effective sorbent than either dry hydrated

calcitic lime or freshly slaked calcitic lime.

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

the limiting factor on injection rate. For SO2 capture

efficiency of 50% or more, a flue gas temperature of

300 oF or more was needed.

• Slurry concentration for a given sorbent did not

increase SO2

 removal efficiency beyond a certain

threshold concentration.

• Testing indicated that SO2

 removal efficiencies of

50% or more were achievable with flue gas temperatures of 300–310 oF (full load), sorbent injection rate

of 52–57 gal/min, residence time of 2 seconds, and a

pressure-hydrated dolomitic-lime concentration of

about 9%.

• For operating conditions at Seward Station, data

indicated that for 40–50% SO2

 removal, a 6–8% lime

or dolomitic lime slurry concentration, and a stoichiometric ratio of 2–2.5 resulted in a 40–50% lime

utilization rate. That is, 2–2.5 moles of CaO or

CaO•MgO were required for every mole of SO2

 removed.

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

required for every ton of SO2

 removed.

Operational

• About 100 ft of straight duct was required to assure

the 2-second residence time needed for effective

CZD/FGD operation.

• At Seward Station, stack opacity was not detrimentally affected by CZD/FGD.

• Availability of CZD/FGD was very good.

• Some CZD/FGD modification will be necessary to

assure consistent SO2

 removal and avoid deposition

of solids within the ductwork during upsets.

Economic

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

Preaward Operation

19/89

12/89 10/90

DOE selected

project (CCT-III) 12/

Design start 6/90

NEPA process completed (MTF) 9/90

Cooperative agreement awarded 10/

90

Design completed 10/90

Ground breaking/construction started 3/91

Construction completed 6/91

Environmental monitoring plan 6/12/91

Preoperational tests initiated 7/91

Operation initiated 7/91

Design and Construction

Operation completed 6/93

7/91

Project completed/final report issued 6/

94

6/94
34 Project Fact Sheets Environmental Control Devices

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.

sulfur coal and achieving 50% SO2 reduction was estimated at less than $30/kW

and operating cost at $300/ton of SO2

removed (1994$).

Project Summary

The principle of the CZD/FGD is to form a

wet zone of slurry droplets in the middle of a

duct confined in an envelope of hot gas

between the wet zone and the hot gas. The

lime slurry reacts with part of the SO2

 in the

gas and the reaction products dry to form

solid particles. An ESP, downstream from the

point of injection, captures the reaction

products along with the fly ash entrained in

the flue gas.

CZD/FGD did not require a special reactor, simply a modification to the ductwork.

Use of the commercially available Type S pressurehydrated dolomitic lime reduced residence time requirements for CZD/FGD and enhanced sorbent utilization.

The increased humidity of CZD/FGD processed flue

gas enhanced ESP performance, eliminating the need

for upgrades to handle the increased

particulate load.

Bechtel began its 18-month, two-part test program

for the CZD process in July 1991, with the first

12 months of the test program consisting primarily of

parametric testing and the last 6 months consisting of

continuous operational testing. During the continuous

operational test period, the system was operated under

fully automatic control by the host utility boiler operators. The new atomizing nozzles were thoroughly

tested both outside and inside the duct prior to testing.

The SO2

 removal parametric test program, which began

in October 1991, was completed in August 1992.

Specific objectives were as follows:

• Achieve projected SO2

 removal of 50%

• Realize SO2

 removal costs of less than $300/ton

• Eliminate negative effects on normal boiler operations without increasing particulate emissions 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

lime slurry for the same percentage of SO2

 removed.

The most efficient removals and easiest to operate

system were obtained using 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

a portion of the demonstration when air leakage caused

flue gas temperature to drop from 300–310 oF to 260–

280 oF. At 300–310 oF, injection rates of 52–57 gal/min

were possible and SO2

 reductions greater than 50%

were achieved. At 260–280 oF, injection rates had to be

dropped to 30–40 gal/min, resulting in a 15–30% drop

in SO2

 removal efficiency. Slurry concentration for a

given sorbent did not 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:

• Percentage of SO2

 removed

• 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

horizontal gas duct of about 100 feet.

• The fully automated system integrated with the
Environmental Control Devices Project Fact Sheets 35

This photo shows the CZD/FGD lime slurry injector control

system.

power plant operation demonstrated that the CZD/

FGD process responded well to automated control

operation. However, modifications to the CZD/FGD

were required 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.

Economic Performance

The CZD/FGD process can achieve costs of $300/ton

of SO2

 removed when operating a 500-MWe unit burning 4% sulfur coal. Based on a 500-MWe plant retrofitted with CZD/FGD for 50% SO2

 removal, the total capital cost is estimated to be less than $30/kW (1994$).

Commercial Applications

After the conclusion of the DOE-funded CZD/FGD

demonstration project at Seward Station, the CZD/FGD

system was modified to improve SO2 removal during

continuous operation while following daily load cycles.

Bechtel and the host utility, Pennsylvania Electric Company, continued the CZD/FGD demonstration for an

additional year. Results showed that CZD/FGD operation at SO2

 removal rates lower than 50% could be

sustained over long periods without significant process problems.

CZD/FGD can be used for retrofit of existing plants

and installation in new utility boiler flue gas facilities to

remove SO2

 from a wide variety of sulfur-containing

coals. A CZD/FGD system can be added to a utility

boiler with a capital investment of about $25–50/kW of

installed capacity, or approximately one-fourth the cost

of building a conventional wet scrubber. In addition to

low capital cost, other advantages include small space

requirements, ease of retrofit, low energy requirements,

fully automated 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

installation does not require major power station alterations and can be easily and economically integrated

into existing

power plants.

Contacts

Joseph T. Newman, Project Manager, (415) 768-1189

Bechtel Corporation

P.O. Box 193965

San Francisco, CA 94119-3965

(415) 768-5420 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483

James U. Watts, FETC, (412) 892-5991

References

• Confined Zone Dispersion Project: Final Technical Report. Bechtel Corporation. June 1994.

• Confined Zone Dispersion Project: Public Design Report.

Bechtel Corporation. October 1993.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Confined Zone Dispersion Flue

Gas Desulfurization Demonstration. Bechtel Corporation. Report No. DOE/FE-0203P. U.S. Department of

Energy. September 1990. (Available from NTIS as

DE91002564.)
36 Project Fact Sheets Environmental Control Devices

Environmental Control Devices

SO2

 Control Technology

LIFAC Sorbent Injection

Desulfurization Demonstration

Project

Project completed.

Participant

LIFAC–North America (a joint venture partnership

between Tampella Power Corporation and ICF Kaiser

Engineers, Inc.)

Additional Team Members

ICF Kaiser Engineers, Inc.—cofunder and project

manager

Tampella Power Corporation—cofunder

Tampella, Ltd.—technology owner

Richmond Power and Light—cofunder and host utility

Electric Power Research Institute—cofunder

Black Beauty Coal Company—cofunder

State of Indiana—cofunder

Location

Richmond, Wayne County, IN (Richmond Power &

Light’s Whitewater Valley Station, Unit No. 2)

Technology

LIFAC’s sorbent injection process with sulfur capture

in a unique, patented vertical activation reactor

Plant Capacity/Production

60-MWe

Coal

Bituminous, 2.0–2.8% sulfur

Project Funding

Total project cost $21,393,772 100%

DOE 10,636,864 50

Participants 10,756,908 50

Project Objective

To demonstrate that electric power plants—especially

those with space limitations and burning high-sulfur

coals—can be retrofitted successfully with the LIFAC

limestone injection process to remove 75–85% of the

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 it

absorbs some of the SO2

 in the boiler flue gas. The

limestone is calcined into calcium oxide and is available

for capture of additional SO2

 downstream in the activation, or humidification, reactor. In the vertical chamber,

water sprays 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 ash in the electrostatic precipitator (ESP). The

sorbent material from the reactor and electrostatic precipitator are recirculated back through the reactor for

increased efficiency. The waste is dry, making it easier

to handle than the wet scrubber sludge produced by

conventional wet limestone scrubber systems.

The technology enables power plants with space

limitations to use high-sulfur midwestern coals by

providing an injection process that removes 75–85% of

the SO2

 from flue gas and produces a dry solid waste

product suitable for disposal in a landfill.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

3 4 1 2

Environmental Control Devices Project Fact Sheets 37

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Design and Construction Operation

Original design completed 7/91

Cooperative agreement awarded 11/20/90

NEPA process completed (MTF) 10/2/90

Ground breaking/construction started 5/29/91

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

Preoperational tests initiated 7/92

Environmental monitoring plan

completed 6/12/92

Construction completed 6/92

Operation completed 6/94

Operation initiated 9/92

12/89 11/90 9/92

Results Summary

Environmental

• SO2 removal efficiency was 70% at a calcium-tosulfur (Ca/S) molar ratio of 2.0, approach-to-saturation temperature of 7–12 oF, and limestone fineness

of 80% minus 325 mesh.

• SO2

 removal efficiency with limestone fineness of

80% minus 200 mesh was 15% lower at a Ca/S molar

ratio of 2.0 and 7–12 oF approach to saturation.

• The four parameters having the greatest influence

on sulfur removal efficiency were limestone fineness,

Ca/S molar ratio, approach-to-saturation temperature, and ESP ash recycle rate.

• ESP ash recycle rate was limited in the demonstration system configuration. Increasing the recycle

rate and sustaining a 5 oF approach-to-saturation

temperature was projected to increase SO2

 removal

efficiency to 85% at a Ca/S molar ratio of 2.0 (fine

limestone).

• ESP efficiency and operating levels were essentially

unaffected by LIFAC operation during steady-state

operation.

• Fly and bottom ash were dry and readily disposed

of at a local landfill. The quantity of additional solid

waste can be determined by assuming that approximately 4.3 tons of limestone is required to remove

1.0 ton of SO2

.

Operational

• When operating with fine limestone (80% minus

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

• Automated programmable logic and simple design

make the LIFAC system easy to operate in start-up,

shutdown, or normal duty cycles.

• The amount of bottom ash increased slightly, but

there was no negative impact on the ash-handling

system.

Economic

• Capital cost—$66/kW for two LIFAC reactors

(300-MWe); $76/kW for one LIFAC reactor

(150-MWe); $99/kW for one LIFAC reactor

(65-MWe) (1994$).

4/98

Project completed/final

report issued 4/98
38 Project Fact Sheets Environmental Control Devices

The LIFAC system successfully demonstrated at

Whitewater Valley Station Unit No. 2 is being retained

by Richmond Power & Light for commercial use with

high-sulfur coal. There are 10 full-scale LIFAC units in

Canada, China, Finland, Russia, and the United States.

• Operating cost—$65/ton of SO2 removal, assuming

75% SO2

 capture, Ca/S molar ratio of 2.0, limestone

composed of 95% CaCO3

, and $15/ton.

Project Summary

The LIFAC technology was designed to enhance the

effectiveness of dry sorbent injection systems for SO2

control and to maintain the desirable aspects of low

capital cost and compactness for ease of retrofit. Furthermore, limestone was used as the sorbent (about 1/3

of the cost of lime) and a sorbent recycle system was

incorporated to reduce operating costs.

The process evaluation test plan was composed of

five distinct phases each having its own objectives.

These tests were as follows:

• Baseline tests characterized the operation of the

host boiler and associated subsystems prior to

LIFAC operations.

• Parametric tests were designed to evaluate the many

possible combinations of LIFAC process parameters

and their effect on SO2

 removal.

• Optimization tests were performed after the parametric tests to evaluate the reliability and operability of

the LIFAC process over short, continuous operating

periods.

• Long-term tests were performed to demonstrate

LIFAC’s performance under commercial operating

conditions.

• Post-LIFAC tests involved repeating the baseline

test to identify any changes caused by the LIFAC

system.

The coals used during the demonstration varied in

sulfur content from 1.4–2.8%. However, most of the

testing was conducted with the higher sulfur coals

(2.0–2.8% sulfur).

Environmental Performance

During the parametric testing phase, the numerous

LIFAC process values and their effects on sulfur removal efficiency were evaluated. The four major parameters having the greatest influence on sulfur removal efficiency were limestone fineness Ca/S molar

ratio, reactor bottom temperature (approach-to-saturation), and ESP ash recycling rate. Total SO2

 capture

was about 15% better when injecting fine limestone

(80% minus 325 mesh) than it was with coarse limestone (80% minus 200 mesh).

While injecting the fine limestone, the soot blowing frequency had to be increased from 6-hour to 4.5-

hour cycle periods. The coarse-quality limestone did

not affect soot blowing but was found to be more abrasive on the feed and transport hoses.

Parametric tests indicated that a 70% SO2

 reduction was achievable with a Ca/S molar ratio of 2.0. ESP

ash containing unspent sorbent and fly ash was recycled from the ESP hoppers back into the reactor inlet

duct work. Ash recycling is essential for efficient SO2

capture. The large quantity of ash removed from the

LIFAC reactor bottom and the small size of the ESP

hoppers limited the ESP ash recycling rate. As a result,

the amount of material recycled from the ESP was approximately 70% less than had been anticipated. However, this low recycling rate was found to affect SO2

capture. During a brief test, it was found that increasing the recycle rate by 50% resulted in a 5% increase in

SO2

 removal efficiency. It was estimated that if the

reactor bottom ash is recycled along with ESP ash,

while sustaining a reactor temperature of 5 oF above

saturation temperature, an SO2

 reduction of 85% could

be maintained.

Operational Performance

Optimization testing began in March 1994 and was

followed by long-term testing in June 1994. The boiler

was operated at an average load of 60-MWe during

long-term testing, although it fluctuated according to

power demand. The LIFAC process automatically

adjusted to boiler 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.

Atomized water 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-
Environmental Control Devices Project Fact Sheets 39

content limestone, and recycle of spent sorbent from

the ESP.

Long-term testing showed that SO2

 reductions of

70% or more can be maintained under normal boiler

operating ranges. Stack opacity was low (about 10%)

and ESP efficiency was high (99.2%). The amount of

boiler bottom ash increased slightly during testing, but

there was no negative impact on the power plant’s

The top of the LIFAC reactor is shown being lifted

into place. During 2,800 hours of operation, long-term

testing showed that SO2

 reductions of 70% or more

could be sustained under normal boiler operation.

bottom and flyash removal system. The solid waste

generated was a mixture of fly ash and calcium compounds and was readily disposed of at a local landfill.

The LIFAC system proved to be highly operable

because it has few moving parts and is simple to operate. The process can be easily shut down and restarted. The process is automated by a programmable

logic system, which regulates process control loops,

interlocking, start-up, shutdowns, and data collection.

The entire LIFAC process was easily managed via two

personal computers located 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 a spray

dryer or wet scrubber. Capital costs for LIFAC technology vary, depending on unit size and the quantity of

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)

• $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 of

limestone to remove 1.0 ton of SO2

, assuming 75% SO2

capture, a Ca/S molar ratio of 2.0, and limestone containing 95% CaCO3

. Assuming limestone costs of $15/

ton, LIFAC’s operating cost would be $65/ton of SO2

removed.

Commercial 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 the

first to be applied to a power plant using high-sulfur

(2.0–2.9%) coal. The LIFAC system is being retained

by Richmond Power & Light at Whitewater Valley

Station, Unit No. 2. The other LIFAC installations on

power plants are using bituminous and lignite coals

having lower sulfur contents (0.6–1.5%).

Contacts

Jim Hervol, Project Manager, (412) 497-2235

ICF Kaiser Engineers, Inc.

Gateway View Plaza

1600 West Carson Street

Pittsburgh, PA 15219-1031

(412) 497-2235 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483

James U. Watts, FETC, (412) 892-5991

References

• 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.” Third

Annual Clean Coal Technology Conference: Technical

Papers. September 1994.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: LIFAC Sorbent Injection

Desulfurization Demonstration Project. LIFAC–North

America. Report No. DOE/FE-0207P. U.S. Department of Energy, October 1990. (Available from NTIS

as DE91001077.)
40 Project Fact Sheets Environmental Control Devices

Environmental Control Devices

SO2

 Control Technology

Advanced Flue Gas

Desulfurization Demonstration

Project

Project completed.

Participant

Pure Air on the Lake, L.P. (a project company of Pure

Air, which is a general partnership between Air Products and Chemicals, Inc., and Mitsubishi Heavy Industries America, Inc.)

Additional Team Members

Northern Indiana Public Service Company—cofunder

and host

Mitsubishi Heavy Industries, Ltd.—process designer

United Engineers and Constructors (Stearns-Roger

Division)—facility designer

Air Products and Chemicals, Inc.—constructor and

operator

Location

Chesterton, Porter County, IN (Northern Indiana Public

Service Company’s Bailly Generating Station, Unit Nos.

7 and 8)

Technology

Pure Air’s advanced flue gas desulfurization (AFGD)

process

Plant Capacity/Production

528-MWe

Coal

Bituminous, 2.0–4.5% sulfur

Project Funding

Total project cost $151,707,898 100%

DOE 63,913,200 42

Participant 87,794,698 58

Project Objective

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

technology, significantly reduce space requirements,

and create no new waste streams.

Technology/Project Description

Pure Air built a single SO2

 absorber for a 528-MWe

power plant. Although the largest capacity absorber

module of its time in the United States, space requirements were modest because no spare or backup absorber modules were required. The absorber performed

three functions in a single vessel: prequenching,

absorbering, and oxidation of sludge to gypsum. Additionally, the absorber was of a co-current design, in

which the flue gas and scrubbing slurry move in the

same direction and at a relatively high velocity compared to that in conventional scrubbers. These features all combined to yield a state-of-the-art SO2

 absorber that was more compact and less expensive than

contemporary conventional scrubbers.

Other technical features included the injection of

pulverized limestone directly into the absorber, a device

called an air rotary sparger located within the base of

the absorber, and a novel wastewater evaporation

system. The air rotary sparger combined the functions

of agitation and air distribution into one piece of equipment to facilitate the oxidation of calcium sulfite to

gypsum.

Pure Air also demonstrated a unique gypsum

agglomeration process, PowerChip®, to significantly

enhance handling characteristics of adsorbed flue gas

PowerChip is a registered trademark of Pure Air on the Lake, L.P.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 41

desulfurization (AFGD)-derived gypsum.

Results Summary

Environmental

• AFGD design enabled a single 600-MWe absorber

module without spares to remove 95% or more SO2

at availabilities of 99.5% when operating with highsulfur coals.

• Wallboard-grade gypsum was produced in lieu of

solid waste, and all gypsum produced was sold

commercially.

• The wastewater evaporation system (WES) mitigated expected increases in wastewater generation

associated with gypsum production and showed the

potential for achieving zero wastewater discharge

(only a partial- capacity WES was installed).

• PowerChip® increased the market potential for

AFGD- derived gypsum by cost effectively converting it to a product with the handling characteristics

of natural rock gypsum.

• Air toxics testing established that all acid gases

were effectively captured and neutralized by the

AFGD. Trace elements largely became constituents

of the solids streams (bottom ash, fly ash, gypsum

product). Some boron, selenium, and mercury

passed to the 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 exclusion of requiring a spare module), and compact. The

compactness, combined with no need for a spare

module, significantly reduced space requirements.

• The own-and-operate contractual arrangement

whereby Pure Air took on the turnkey, financing,

operating and maintenance risks through performance guarantees was successful.

Economic

• Capital costs and space requirements for AFGD

were about half those of contemporary systems.

Project Summary

The project proved that single absorber modules of

advanced design could process large volumes of flue

gas and provide the required availability and reliability

without the usual spares. The major performance objectives were met.

Over the 3-year demonstration, the AFGD unit

accumulated 26,280 hours of operation with an availability of 99.5%. Approximately 237,000 tons of SO2

were removed, with capture efficiencies of 95% or more,

and over 210,000 tons of salable gypsum were produced. The AFGD continues commercial service, which

includes sale of all by-product gypsum to U.S.

Gypsum’s East Chicago, IN, wallboard production

plant.

Environmental Performance

Testing over the 3-year period clearly established that

AFGD operating within its design parameters (without

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Design and Construction Operation

9/88

Operation completed 6/95

Project completed/final report issued 6/96

DOE selected

project (CCT-II) 9/

28/88

Cooperative agreement awarded 12/20/89

Operation initiated 6/92

Design completed 9/92

Construction completed 9/92

Preoperational tests initiated 3/92

12/89 6/92

NEPA process completed (EA) 4/16/90

Ground breaking/construction started 4/20/90

Environmental monitoring plan completed 1/31/

91

6/96
42 Project Fact Sheets Environmental Control Devices

Exhibit 14

 SO2 Removal Performance

(100% Boiler Load)

additives) could consistently achieve 95% SO2 reduction or more with 2.0–4.5% sulfur coals. The design

range

for the calcium-to-sulfur stoichiometric ratio was

1.01–1.07, with the upper value set by gypsum purity

requirements (i.e., amount of unreacted reagent allowed

in the gypsum). Another key control parameter was the

ratio L/G, which is the amount of reagent slurry injected

into the absorber grid (L) to the volume of flue gas (G).

The design L/G range was 50–128 gal/103

 ft3. The lower

end was determined by solids settling rates in the

slurry and the requirement for full wetting of the grid

packing. The high end was determined by where performance leveled out.

Five coals with differing sulfur contents were

selected for parametric testing to examine SO2

 removal

efficiency as a function of load, sulfur content, stoichiometric ratio, and L/G. Loads tested were 33%,

67%, and 100%. High removal efficiencies, well above

95%, at loads of 33% and 67% were possible with low

to moderate stoichiometric ratio and L/G settings, even

for 4.5% sulfur coal. Exhibit 14 summarizes the results

of parametric testing at full load.

In the AFGD process, chlorides that would have

been released to the air are captured and potentially

become a wastewater problem. This was mitigated by

the addition of the WES which takes a portion of the

wastewater stream with high chloride and sulfate levels

and injects it into the ductwork upstream of the ESP.

The hot flue gas evaporated the water and the dissolved solids were captured in the ESP. Problems were

experienced early on, with the WES nozzles failing to

provide adequate atomization and plugging as well.

This was resolved by replacing the original single-fluid

nozzles with dual fluid systems employing air as the

second fluid.

Commercial-grade gypsum quality (95.6–99.7%)

was maintained throughout testing, even at the lower

sulfur concentrations where the ratio of fly ash to gypsum increases due to lower sulfate availability. The

primary importance of producing a commercial-grade

gypsum is avoidance of the environmental and economic consequences of disposal. The marketability of

the gypsum is dependent upon whether users are in

range of economic transport and whether they can

handle the gypsum by-product. For these reasons,

PowerChip® technology was demonstrated as part of

the project. This technology uses a compression mill to

convert the highly cohesive AFGD gypsum cake into a

flaked product with handling characteristics equivalent

to natural rock gypsum. The process avoids use of

binders, pre-drying or pre-calcining normally associated with briquetting and is 30–55% cheaper at $2.50–

$4.10/ton.

Air toxics testing established that all acid gases

are effectively captured and neutralized by the AFGD.

Trace elements largely become constituents of the

solids streams (bottom ash, fly ash, gypsum product).

Some boron, selenium, and

mercury pass to the stack

gas in a vapor 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/maintenance philosophy. Modifications were also made to

the AFGD system. An

example was the implementation of new alloy technology, C-276 alloy over carbon steel clad material, to replace alloy wallpaper construction within the absorber tower wet/dry interface.

Also, use of co-current rather than conventional

counter-current flow resulted in lower pressure drops

across the absorber and afforded the flexibility to increase gas flow without an abrupt drop in removal

efficiency. AFGD SO2

 capture efficiency with limestone

was comparable to that in wet scrubbers using lime,

which is far more expensive. Twenty-four-hour power

consumption was 5,275 kW, or 61% of expected consumption, and water consumption was 1,560 gal/min, or

52% of expected consumption.

Economic Performance

Exhibit 15 summarizes capital and levelized current

dollar cost estimates for nine cases with varying plant

capacity and coal sulfur content. A capacity factor of

65% and a sulfur removal efficiency of 90% were assumed. The calculation of levelized cost followed

guidelines established in the Electric Power Research
Environmental Control Devices Project Fact Sheets 43

Institute’s Technical Assessment Guide.

The incremental benefits of the own-and-operate

arrangement, by-product utilization, and emission allowances were also evaluated. Exhibit 16 depicts the

relative costs of a hypothetical 500-MWe generating

unit in the Midwest burning 4.3% sulfur coal with a

base case conventional FGD system and four incremental cases. The horizontal lines in Exhibit 16 show

the range of costs for a fuel-switching option. The

lower bar is the cost of fuel delivered to the hypothetical midwest unit and the upper bar allows for some

plant modifications to accommodate the compliance

fuel.

Commercial Applications

AFGD is positioned well to compete in the pollution

control arena of 2000 and beyond. AFGD has markedly

reduced cost and demonstrated the ability to compete

with fuel switching under certain circumstances even

with a first-generation system. Advances in technology, e.g., in materials and components, should improve

James U. Watts, FETC, (412) 892-5991

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 as

DE96050313.)

• Advanced Flue Gas Desulfurization Project: Public Design Report. Pure Air on the Lake, L.P. March 1990.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Advanced Flue Gas Desulfurization

(AFGD) Demonstration Project. (Pure Air on the Lake,

L.P.) DOE/FE Report No. 0150. U.S. Department of

Energy. November 1989. (Available from NTIS as

DE90004460.)

costs for AFGD. The own-and-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 possible position of trading allowances or applying credits to other units within the

utility. WES and PowerChip® mitigate or eliminate otherwise serious environmental concerns. AFGD effectively

deals with hazardous air pollutants.

The project received Power magazine’s 1993 Powerplant Award and the National Society of Professional

Engineer’s 1992 Outstanding Engineering Achievement

Award.

Contacts

Tim Roth, (610) 481-6257

Pure Air on the Lake, L.P.

c/o Air Products and Chemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

(610) 481-5820 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483

Exhibit 15

Estimated Costs for an AFGD System

(1995 Current Dollars)

Cases: 1 2 3 456789

Plant size (MWe) 100 100 100 300 300 300 500 500 500

Coal sulfur content (%) 1.5 3.0 4.5 1.5 3.0 4.5 1.5 3.0 4.5

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

Levelized cost ($/ton SO2

)

15-year life 1,518 840 603 720 401 294 536 302 223

20-year life 1,527 846 607 716 399 294 531 300 223

Levelized cost (mills/kWh)

15-year life 16.39 18.15 19.55 7.78 8.65 9.54 5.79 6.52 7.24

20-year life 16.49 18.28 19.68 7.73 8.62 9.52 5.74 6.48 7.21

Exhibit 16

Flue Gas Desulfurization

Economics

0

50

100

150

200

250

300

350

400

0

0.2

0.4

0.6

0.8

1

1.2

$/Ton SO2 $/106 Btu

A B C D E

Plant Modifications

Delivered Fuel

500-MWe plant, 30-yr levelized costs, allowance value of

$300/ton

Incremental cases:

A—Conventional FGD (EPRI model)

B—AFGD, own-and-operate arrangement

C—Adds gypsum sales

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

removal

E—Increases SO2

 removal to 95%
44 Project Fact Sheets Environmental Control Devices

Environmental Control Devices

SO2

 Control Technology

Demonstration of Innovative

Applications of Technology for

the CT-121 FGD Process

Project completed.

Participant

Southern Company Services, Inc.

Additional Team Members

Georgia Power Company—host

Electric Power Research Institute—cofunder

Radian Corporation—environmental and analytical

consultant

Ershigs, Inc.—fiberglass fabricator

Composite Construction and Equipment—fiberglass

sustainment consultant

Acentech—flow modeling consultant

Ardaman—gypsum stacking consultant

University of Georgia Research Foundation—

by-product utilization studies consultant

Location

Newnan, Coweta County, GA (Georgia Power

Company’s Plant Yates, Unit No. 1)

Technology

Chiyoda Corporation’s Chiyoda Thoroughbred-121

(CT-121) advanced flue gas desulfurization (FGD)

process

Plant Capacity/Production

100-MWe

Coal

Illinois No. 5 & No. 6 blend, 2.4% sulfur

Compliance, 1.2% sulfur

Project Funding

Total project cost $43,074,996 100%

DOE 21,085,211 49

Participant 21,989,785 51

Project Objective

To demonstrate 90% SO2

 control at high reliability with

and without simultaneous particulate control; to evaluate use of fiberglass-reinforced-plastic (FRP) vessels to

eliminate flue gas reheat and spare absorber modules;

and to evaluate use of gypsum to reduce waste management costs.

Technology/Project Description

The project demonstrated the CT-121 FGD process,

which uses a unique absorber design known as the Jet

Bubbling Reactor® (JBR). The process combines limestone FGD reaction, forced oxidation, and gypsum

crystallization in one process vessel. The process is

mechanically and chemically simpler than conventional

FGD processes and can be expected to exhibit lower

cost characteristics.

The flue gas enters underneath the scrubbing

solution in the Jet Bubbling Reactor®. The SO2

 in the

flue gas is absorbed and forms calcium sulfite (CaSO3

).

Air is bubbled into the bottom of the solution to oxidize

the calcium sulfite to form gypsum. The slurry is dewatered in a gypsum stack, which involves filling a diked

area with gypsum slurry. Gypsum solids settle in the

diked area by gravity, and clear water flows to a retention pond. The clear water from the pond is returned to

the process. Jet Bubbling Reactor is a registered trademark of the Chiyoda
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

** Years omitted

3 4 1 2

Environmental Control Devices Project Fact Sheets 45

1988 1989 1990 1991 1992 1993 1994 1995 1996 1998 1999

4/90

Preaward Design and Construction Operation

9/88 10/92

DOE selected project

(CCT-II) 9/28/88

Cooperative agreement awarded 4/2/90

NEPA process

completed (EA) 8/10/90

Ground breaking/construction

started 8/23/90

Environmental monitoring

plan completed 12/18/90

Preoperational tests initiated 5/92

Design completed 9/92

Operation initiated 10/92

Construction completed 10/92

Results Summary

Environmental

• Over 90% SO2 removal efficiency was achieved at

SO2

 inlet concentrations of 1,000–3,500 ppm with

limestone utilization over 97%.

• JBR achieved particulate removal efficiencies of

97.7–99.3% for inlet mass loadings of 0.303–1.392

lb/106 Btu over a load range of 50–100-MWe.

• Capture efficiency was a function of particle size:

– >10 microns—99% capture

– 1–10 microns—90% capture

– 0.5–1 micron—negligible capture

– <0.5 micron—90% capture

• Hazardous air pollutant (HAP) testing showed

greater than 95% capture of hydrogen chloride (HCl)

and hydrogen fluoride (HF) gases, 80–98% capture

of most trace metals, less than 50% capture of mercury and cadmium, and less than 70% capture of

selenium.

• Gypsum stacking proved effective for producing

wallboard/cement-grade gypsum.

Operational

• FRP-fabricated equipment proved durable both

structurally and chemically, eliminating the need for

a flue gas prescrubber and reheat.

• FRP construction combined with simplicity of design resulted in 97% availability at low ash loadings

and 95% at high ash loadings, precluding the need

for a spare reactor module.

• Simultaneous SO2

 and particulate control were

achieved at flyash loadings reflective of an electrostatic (ESP) with marginal performance.

Economic

• Final results are not yet available. However, elimination of the need for flue gas prescrubbing, reheat,

and spare module requirement should result in capital requirements far below those of contemporary

4/99

Operation completed 12/94

conventional FGD systems.

Project Summary

The CT-121 process differs from the more common

spray tower type of flue gas desulfurization systems in

that a single process vessel is used in place of the

usual spray tower/reaction tank/thickener arrangement.

Pumping of reacted slurry to a gypsum transfer tank is

intermittent. This allows crystal growth to proceed

essentially uninterrupted resulting in large, easily dewatered gypsum crystals (conventional systems employ large centrifugal pumps to move reacted slurry

causing crystal attrition and secondary nucleation).

The demonstration spanned 27 months, including

start-up and shakedown, during which approximately

19,000 hours were logged. Exhibit 17 summarizes operating statistics. Elevated particulate loading included a

short test with the electrostatic precipitator (ESP) completely deenergized, but the long-term testing was

conducted with the ESP partially deenergized to simulate a more realistic scenario, i.e., a CT-121 retrofit to a

Project completed/final

report issued 4/99*

**
46 Project Fact Sheets Environmental Control Devices

Low-Ash Elevated-Ash Cumulative

Phase Phase for Project

Total test period (hr) 11,750 7,250 19,000

Scrubber available (hr) 11,430 6,310 18,340

Scrubber operating (hr) 8,600 5,210 13,810

Scrubber called upon (hr) 8,800 5,490 14,290

Reliabilitya 0.98 0.95 0.96

Availabilityb 0.97 0.95 0.97

Utilizationc 0.73 0.72 0.75

a

 Reliability = hours scrubber operated divided by the hours called upon to operate

b

 Availability = hours scrubber available divided by the total hours in the period

c

 Utilization = hours scrubber operated divided by the total hours in the period

Exhibit 17

Operation of CT-121 Scrubber

Exhibit 18

SO2 Removal Efficiency

Exhibit 19

Particulate Capture Performance

(ESP Marginally Operating)

JBR Pressure Boiler Inlet Mass Outlet Mass Removal

Change (inches of Load Loading Loading* Efficiency

water column) (MWe) (lb/106 Btu) (lb/106 Btu) (%)

18 100 1.288 0.02 97.7

10 100 1.392 0.010 99.3

18 50 0.325 0.005 98.5

10 50 0.303 0.006 98.0

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

Yates permit limit is 0.24 lb/106

 Btu as an existing unit.

boiler with a marginally performing particulate collection device. The SO2

 removal efficiency was measured

under five different inlet concentrations with coals

averaging 2.4% sulfur and ranging from 1.2– 4.3%

sulfur

(as burned).

Operating Performance

Use of FRP construction proved very successful. Because their large size precluded shipment, the JBR and

limestone slurry storage tanks were constructed on

site. Except for some erosion experienced at the JBR

inlet transition duct, the FRP-fabricated equipment

proved to be durable both structurally and chemically.

Because of the high corrosion resistance, the need for

a flue gas prescrubber to remove chlorides was eliminated. Similarly, the FRP-constructed chimney proved

resistant to the corrosive condensates in wet flue gas,

precluding the need for flue gas reheat.

Availability of the CT-121 scrubber during the lowash test phase was 97%. Availability dropped to 95%

under the elevated ash-loading conditions due largely

to sparger tube plugging problems precipitated by

flyash agglomeration on the sparger tube walls during

high ash loading when the ESP was deenergized. The

high reliability demonstrated verified that a spare JBR

is not required in a commercial design offering.

Environmental Performance

Exhibit 18 shows SO2

 removal efficiency as a function

of pressure drop across the JBR for five different inlet

concentrations. The greater the pressure drop, the

greater the depth of slurry traversed by the flue gas.

As the SO2

 concentration increased, removal efficiency

decreased, but adjustments in JBR fluid level could

maintain the efficiency above 90% and, at lower SO2

concentration levels, above 98%. Limestone utilization

remained above 97% throughout the demonstration.

Long-term particulate capture performance was

tested with a partially deenergized ESP (approximately

90% efficiency) and is summarized in Exhibit 19.

Analysis indicated that a large percentage of the

outlet particulate matter is sulfate,
Environmental Control Devices Project Fact Sheets 47

likely a result of acid mist and gypsum carryover. This

reduces the estimate of ash mass loading at the outlet

to approximately 70% of the 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%. Between 0.5

and 1 micron, the particulate removal

dropped at times to negligible values possibly due to acid mist carryover entraining

particulates in this size range. Below 0.5

micron, the capture efficiency increased to

over 90%. Calculated HAP removals

across the CT-121 JBR, based on the measurements taken during the demonstration,

are shown in Exhibit 20.

As to solids handling, the gypsum

stacking method proved effective in the

long term. Although chloride content was

initially high in the stack due to the closed

loop nature of the process (with concentrations often exceeding 35,000 ppm), a year

later the chloride concentration in the gypsum

dropped to less than 50 ppm, suitable for wallboard and cement applications. The reduction in

chloride content was attributed to rainwater

washing the stack.

Economic Performance

Although the final economic analyses are not yet

available, it appears as though CT-121 technology offers significant economic advantages.

FRP construction eliminates the need for

prescrubbing and reheating flue gas. High system availability eliminates the need for a spare

absorber module. Particulate removal capability

precludes the need for expensive (capital-intensive) ESP upgrades to meet increasingly tough

environmental regulations.

Commercial Applications

Involvement of Southern Company (which owns

Southern Company Services, Inc.), with more than

20,000-MWe of coal-fired generating capacity, is expected to enhance confidence in the CT-121 process

among other large high-sulfur-coal boiler users. This

process will be applicable 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 10,500,000

tons/yr of potential SO2

 control.

Plant Yates continues to operate with the CT-121

scrubber as an integral part of the site’s CAAA compliance strategy. Since the CCT Program demonstration,

over 8,200 MWe equivalent of CT-121 FGD Capacity

has been sold to 16 customers in seven countries.

The project received Power magazine’s 1994 Powerplant Award. Other awards include the Society of

Plastics Industries’ 1995 Design Award for the mist

eliminator, the Georgia Chapter of the Air and Waste

Management Association’s 1994 Outstanding

Achievement Award, and the Georgia Chamber of

Commerce’s 1993 Environmental Award.

Contacts

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

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

(205) 992-7535 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483

James U. Watts, DOE/FETC, (412) 892-5991

References

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

Plant Utilizing an ESP while Demonstrating the CCT CT121 FGD Project. Final Report. Report No. DOE/PC/

93253-T1. Radian Corporation. June 1994. (Available from NTIS as DE94016053.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Demonstration of Innovative Applications of Technology for the CT-121 FGD Process.

Southern Company Services, Inc. Report No. DOE/

FE-0158. U.S. Department of Energy. February 1990.

(Available from NTIS as DE9008110.)

The unique Jet Bubbling Reactor® (center) was

constructed from fiberglass-reinforced plastic.

Exhibit 20

CT-121 Air Toxics Removal

(JBR Components Only)

0

20

40

60

80

100

Chloride Fluoride Arsenic Cadmium Mercury Selenium Vanadium

Removal Efficiency (%)
Project Fact Sheets 49

nvironmental Control Devices

NO

x Control Technology
Environmental Control Devices

eburning

 NOx Control

orporation

nd cofunder

ster

plier

ch Corporation—

and Development

arch Corporation—

New York State Electric

Station, Unit No. 1)

astman Kodak

Plant, Unit No. 15)

n Station) and

Kodak) technologies

ntially-fired boiler

We cyclone boiler

um- to high-sulfur

pany.

Project FundingTotal project cost $9,096,486 100%DOE 2,701,011 30Participant 6,395,475 70Project ObjectiveTo achieve at least 50% NO

x

 reduction with micronized

coal reburning technology on a cyclone boiler; to achieve25-35% NO

x reduction with micronized coal reburning

technology in conjunction with low-NOx burners on a

tangentially-fired boiler; and to determine the effects ofcoal micronization on electrostatic precipitator (EPS)performance.Technology/Project DescriptionThe reburning coal, which can comprise up to 30% of thetotal fuel, is micronized (pulverized to achieve 80% below 325 mesh) and injected into a pulverized-coal-fired furnace above the primary combustion zone. Typical particle size generated in micronization is 20 microns, whereas normal pulverized coal particles are about 60 microns. This similar size increases surface area by nine fold.Micronized coal has the surface area and combustion characteristics of an atomized oil flame, which allows carbon conversion within milliseconds and release of volatiles at a more even rate. This uniform, compact combustion envelope allows for complete combustion of the coal/air mixture in a smaller furnace volume than conventional pulverized coal because of the coal fineness. The combination of micronized coal, supplying up to 30% of the total furnace fuel requirements, advanced reburning, and fuel/air staging provides flexible options
2 3 4 1 2 3 4 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 51

3/97

flow biasing, and soot blowing frequency) and boileroutputs. The parametric testing established the range ofcontrol settings for optimum performance that were thenused for long-term testing. Testing showed that the targetNO

x

 emission rate of 0.60 lb/106 Btu was achieved with

as low as 17% reburn fuel heat input, which represented a59% NO

x

 reduction. Stoichiometric ratios needed in the

reburn zone and cyclone burner zone to achieve the targeted NOx reduction were 0.9 and 1.05–1.15, respectively. The test program at the Kodak site is complete and

data are being evaluated in preparation for issuance of thefinal technical report.

Parametric testing at the Milliken site examined

conditions that will achieve NO

x

 emissions without exceeding 4.5% loss-on-ignition (LOI) to maintain marketability of the fly ash. Burner tilt, reburn fuel fineness,

reburn fuel flow rate, and primary air flow showed littleimpact on NOx emissions, but significant impact on LOI.

Only excess air had a significant impact on both NOx

emissions and LOI. Long-term testing ensued, exploringoptimum conditions for sustained NOx control at low

LOI. Data are being evaluated in preparation for issuance of the final technical report.Commercial ApplicationsMicronized-coal-reburning technology can be applied toexisting and greenfield cyclone-fired, wall-fired, andtangential-fired pulverized coal units. The technologyreduces NO

x emissions by 50–60% 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.

1993 1994 1995 1996 1997 1998 1999 2000 2001

Design and Construction Operation

6/99

Operation completed (Lansing) 4/99*

Operation completed (Rochester) 10/98

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

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

Design completed (Rochester) 9/96

ess completed

92

agreement awarded 7/28/92

Preoperational tests initiated (Rochester) 1/97

Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

fication and environmen

s can prevent higher

mance derating often

ronmental controls.

reburned for NOx control

) close-coupled overfire

 the top burner of the

r burning the micronized

re re-aimed and (2) ad

s for deep stage combus

e primary combustion and

odak site, the Fuller

he micronized coal,

he cyclone combustor,

omplete the combustion.

ments

he Kodak site examined

en controlling param

coal fineness, flue gas

erfire air flow rate, coal

Project completed/final reportissued 6/99*

Operation initiated (Rochester) 4/97

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

Construction completed (Lansing) 10/97

Operation initiated (Lansing) 3/97

Project relocated to Lansing and Rochester 12/95
Environmental Control Devices

Coal

lone Boiler

any—cofunder and

coal handling

—cofunder

ergy and Natural

er operators)—

consin Power and Light

, Unit No. 2)

s coal-reburning sys

 1.15% sulfur,

uminous, 0.27% sulfur,

609 100%

788 46

821 54

Project ObjectiveTo demonstrate the technical and economic feasibility ofachieving greater than 50% reduction in NOx emissions

with no serious impact on cyclone combustor operation,boiler performance, or other emission streams.Technology/Project DescriptionBabcock & Wilcox Coal Reburn reduces NO

x

 in the

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

x formed in the cyclone

burners reacts with the resultant reducing flue gas and isconverted into nitrogen in this zone. The completion ofthe combustion process occurs in the third zone, calledthe burnout zone, where the balance of the combustion airis introduced.

Coal Reburn can be applied with the cyclone burners

operating within their normal, noncorrosive, oxidizingconditions, thereby minimizing any adverse effects ofreburn on the cyclone combustor and boiler performance.

This project involved retrofitting an existing

100-MWe cyclone boiler that is representative of a largepopulation of cyclone units.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

1 2

Project Fact Sheets 53

 than 50% NOx reduction

inous and PRB subbitu

ad the greatest effect on

maintaining reburn-zone

 necessary burner cool

ixing.

ic precipitator (ESP)

d by Coal Reburn with

put was 29–30% at full

oderate loads.

problems were experi

ations.

• Boiler turndown capability was 66%, exceeding the

50% goal.

• ESP efficiency improved slightly during Lamar coal

testing and did not change with PRB coal.

• Coal fineness levels above the nominal 90% through

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

• UBCL was the only major contributor to boiler efficiency loss, which was 0.1, 0.25, and 1.5% at loads of

110-, 82-, and 60-MWe, respectively, when usingLamar coal. With PRB coal, the efficiency loss rangedfrom zero at full load to 0.3% at 60-MWe.

• Superior flame stability was realized with PRB coal,

contributing to better NOx control than with Lamar

coal.

• Expanded volumetric fuel delivery with reburn burners

enabled switching to PRB low-rank coal withoutboiler derating.

Economic• Capital costs for 110- and 605-MWe plants were

$66/kW and $43/kW, respectively.

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

110-MWe plant were 2.4 and 2.3 mills/kWh, respectively.

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

605-MWe plant were 1.6 and 1.5 mills/kWh, respectively. (Costs are in 1990 constant dollars.)

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction

nt

90

4/90 12/91

Operation

3/94

Project completed/final report issued 3/94

Operationcompleted 12/92 Operation initiated 12/91

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

NEPA process completed (EA) 2/12/91

Design completed 6/91

Ground breaking/construction started 11/90
Environmental Control Devices

Boiler Load110-MWe 82-MWe 60-MWe

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

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

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

Exhibit 21

Coal Reburn Test Results

Wisconsin Power and Light Company’s Nelson Dewey

Station hosted the successful demonstration of Coal Reburn.

t only 15% of the pre

ty, they contribute 21%

oal-fired units. This is

herent turbulent, high

Consequently, cyclone

ion under the CAAA

owever, at the time

o cost-effective com

cyclone boiler

urn offers an economic

to the environmental

yclone combustor

rmance complications

-combustion NOx con

relatively higher capital

as performed firing

mar), as it is typical of

rating cyclones. Sub

erformed to evaluate the

operation. Wisconsin

t Wisconsin’s sulfur

1, 1993, was to fire

 Reburn used Lamar

ing was used to set up

ce testing was run with

t set load points. Long

eburn in operation

d demand require

rametric optimization

21 shows changes in

cy using the reburn

 and coal types.

 Lamar and PRB coals

zone stoichiometry was

the most critical factor in changing NOx emissions

levels. The reburn-zone stoichiometry can be variedby alternating the air flow quantities (oxygen availability) to the reburn burners, the percent reburn heatinput, the gas recirculation flow rate, or the cyclonestoichiometry.

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

generally well within expected levels, and emissionswith Coal Reburn were comparable to baseline operation. No major effect of reburn on trace-metals partitioning was discernible. None of the 16 targetedpolynuclear aromatic semi-volatile organics (controlled under Title III of CAAA) was present in detectable concentrations, at a detection limit of 1.2parts per billion.Operational PerformanceFor Lamar coal, the full-, medium-, and low-load efficiency losses, due to unburned carbon, were 0.1, 0.25,and 1.5% higher, respectively, than the baseline. Full-,medium-, and low-load efficiency losses with PRB coal

were 0.0, 0.2, and 0.3%, respectively. Coal Reburnburner flame stability improved with PRB coal.

During Coal Reburn 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 orlong-term operation period were anyslagging or fouling problems observed.In fact, during scheduled outages,internal boiler inspections revealed thatboiler cleanliness had actually improved. Extensive ultrasonic thicknessmeasurements were taken of the furnace wall tubes. No observable decrease in wall tube thickness was measured.

Another significant finding was

that Coal Reburn minimizes and possibly eliminated a 0–25% derating normally associated with switching tosubbituminous coal in a cyclone unit.
Project Fact Sheets 55

Babcock & Wilcox Coal

ined by Wisconsin Power

l at the Nelson Dewey

Exhibit 22

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

a lower Btu fuel in a

imited coal feed capac

nsferred about 30% of

o the reburn burners,

wn to a manageable

d heat input to the unit.

pital and levelized rev

d using the “Electric

mic Premises” for retrofit

addition, annualized

costs per ton of NOx removed were developed for 110-

and 605-MWe plants over both 10 and 30 years. Theresults of these analyses are shown in Exhibit 22. Thesevalues assumed typical retrofit conditions and did nottake into account any fuel savings from use of low-rankcoal. The pulverizers and associated coal handling weretaken 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 ApplicationsCoal Reburn is a retrofit technology applicable to a widerange of utility and industrial cyclone boilers. The current U.S. Coal Reburn market is estimated to be approximately 26,000-MWe and to consist of about 120 unitsranging from 100- to 1,150-MWe with most in the100–300-MWe range.

The project technology has been retained by Wisconsin Power and Light for commercial use.

ContactsDot K. Johnson, (330) 829-7395

McDermott Technologies, Inc.1562 Beeson StreetAlliance, OH 44601(330) 821-7801 (fax)dot.k.johnson@mcdermott.com

Lawrence Saroff, DOE/HQ, (301) 903-9483John C. McDowell, FETC, (412) 892-6237

References• Demonstration of Coal Reburning for Cyclone Boiler

NO

x

 Control: Final Project Report. Report No. DOE/

PC/89659-T16. The Babcock & Wilcox Company.February 1994. (Available from NTIS asDE94013052, Appendix 1 as DE94013053,Appendix 2 as DE94013054.)

• Public Design Report: Coal Reburning for Cyclone

Boiler NO

x

 Control. The Babcock & Wilcox Company. August 1991. (Available from NTIS as

DE92012554.)

• Comprehensive Report to Congress on the Clean Coal

Program: Demonstration of Coal Reburning forCyclone Boiler NOx Control. (The Babcock & Wilcox

Company). Report No. DOE/FE-0157. U.S. Department of Energy. February 1990. (Available fromNTIS as DE90008111.)
Environmental Control Devices

stration of

ner Retrofit

pany—cofunder and

—cofunder

cofunder

nder

ofunder

er

funder

ayton Power and Light

 No. 4)

s low-NOx cell burner

392 100%

800 48

592 52

the air is directed to the upper port of each cell to complete the combustion process. The fuel-bound nitrogencompounds are converted to nitrogen gas, and the reduced flame temperature minimizes the formation ofthermal NO

x

.

The demonstration was conducted on a Babcock &

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

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

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

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

large baseload coal-fired utility boiler with LNCB® technology; to achieve at least a 50% NOx reduction without

degradation of boiler performance at less cost than that ofconventional low-NO

x

 burners.

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

the standard two-nozzle cell burner with a secondary airport. The lower burner coal nozzle is enlarged to thesame fuel input capacity as the two standard coal nozzles.The LNCB® operates on the principle of staged combustion to reduce NO

x emissions. Approximately 70% of the

total air (primary, secondary, and excess air) is supplied

bcock & Wilcox Company. through or around the coal-feed nozzle. The remainder 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 57

ng (all mills in service)

 range of 53.0–55.5%,

 at loads of 605-MWe,

pectively.

 (all mills in service)

ction of 58% (over

 (one mill out of service)

ction of 60% (over

5 ppm at full load with

rformance remained

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

was offset by a decrease in dry gas loss due 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 was $9/kW

(1994$).

• Levelized cost for a 600-MWe plant was estimated at

0.284 mills/kWh and $96.48/ton of NOx removed.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Operationinitiated 12/91

10/90

Operation

Design and

reaward Construction

12/91

 8/10/90

Project completed/final report issued 12/95

12/95

Operation completed 4/93

Construction completed 11/91Preoperational tests initiated 11/91

e agreement

ed 10/11/90

pleted 10/90

Environmental monitoring plancompleted 8/9/91

Ground breaking/construction started 9/91
Environmental Control Devices

any’s J.M. Stuart Plant hosted the successful

.

The LNCB® is viewed from within the boiler.

burners currently com

0-MWe of pre-NSPS

ll burners are designed

r. The tight burner

e the flame size while

nd unit efficiency.

t the rapid heat release

s of NOx.

 LNCB® has been

el and combustion air.

plishing delayed fuel-air

aterwall panels. A

sts and outage time

ompared to installing

w-NOx burners. LNCB®

o address NOx reduction

Environmental PerformanceThe initial LNCB® configuration

resulted in excessive CO and H2S

emissions. Through modeling, arevised configuration was developedto address the problem withoutcompromising boiler performance.The modification was incorporatedand validated model capabilities.

Following parametric testing to

establish optimal operating modes, aseries of optimization tests wereconducted on the LNCB® to assess

environmental and operational performance. Two sets of measurements were taken, one by Babcock& Wilcox and the other by an independent company, to validate dataaccuracy. Consequently, the dataprovided is a range reflecting thetwo measurements.

The average NOx emissions reduction achieved at

full load with all mills in service ranged from 53.0–55.5%. With one mill out of service at full load, theaverage NOx reduction ranged from 53.3–54.5%. Average NOx reduction at intermediate load (about 460-MWe)

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

NO

x 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. 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 notrefined enough. However, accurate measurements weremade with LNCB® in service. Carbon monoxide emissions were corrected for 3.0% O2 and measured at full,

intermediate, and low loads. The range of CO emissionsat full load with all mills in service was 28–55 ppm and20-38 ppm with one mill out of service. At intermediateloads (about 460-MWe), CO emissions were 28–45 ppmand at low loads (about 350-MWe), 5–27 ppm.

Particulate emissions were minimally impacted. The

LNCB® had little effect on flyash resistivity, largely due

to SO3 injection, and therefore ESP removal efficiency

remained very high. Baseline ESP collection 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. Forthe same conditions, in the same sequence with LNCB®
Project Fact Sheets 59

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

ciencies were 99.43,

secondary superheater

sed by 100 oF but even

eline conditions.

proximately 28% for all

ase from baseline data

out of service. A 52%

efficiency loss of 0.69%.

ry little change from

ls in service increased by

efficiency was attributed

 lower economizer gas

nt lower air heater gas

BCL and CO emission

ness mitigated UBCL.

imary corrosion mecha

ustion of sulfur-contain

red in the boiler. After

vels were largely at the

e some higher local

ts established that corro

ghly equivalent to pre

ed that ash deposition

NCB® ash was little dif

rmore, the small varia

s temperature between

ttle change in furnace

 of the unit were unaf

formed for a 600-MWe

ation in the midwest

 medium-volatile bitumi

cal fuel. For a baseline

Btu and a 50% reduction

target, the estimated capital costwas $9/kW (1994 $). Thelevelized cost of electricity wasestimated at 0.284 mills/kWh or$96.48/ton of NOx removed.

Commercial ApplicationsThe low cost and short outagetime for retrofit make theLNCB® design the most costeffective NO

x control technology

available today for cell burnerboilers. The LNCB® system can

be installed at about half the costand time of other commerciallow-NO

x

 burners.

Dayton Power & Light has

retained the LNCB® for use in

commercial service. Seven commercial contracts havebeen awarded for 172 burners, valued at $24 million.LNCB® have already been installed on more than 4,600-MWe of capacity.

The demonstration project received R&D magazine’s

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

McDermott Technologies, Inc.1562 Beeson StreetAlliance, OH 44601(330) 821-7801 (fax)dot.k.johnson@mcdermott.com

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, FETC, (412) 892-5991

References• Final Report: Full-Scale Demonstration of Low-NOx

Cell Burner Retrofit. Report No. DOE/PC/90545-T2.The Babcock & Wilcox Company. December 1995.(Available from NTIS as DE96003766.)

• Public Design Report: Full-Scale Demonstration of

Low-NO

x Cell Burner Retrofit. Report No. DOE/PC/

90545-T4. The Babcock & Wilcox Company. August1991. (Available from NTIS as DE92009768.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Full-Scale Demonstration ofLow-NO

x Cell-Burner Retrofit. The Babcock & Wilcox Company. Report No. DOE/FE-0197P. U.S.

Department of Energy. July 1990. (Available fromNTIS as DE90018026.)
Environmental Control Devices

Reburning

ers on a 

ch Corporation

ado—cofunder and host

—cofunder

—cofunder

hnology supplier

ic Service Company of

 No. 3)

ch Corporation’s

w-NOx burners (LNB)

r, 10% ash

258 100%

790 50

468 50

he emissions of NOx

boiler firing low-sulfur

low-NOx burners

out the use of recirculated flue gas and with optimizedoverfire air.

A series of parametric tests were performed on the

gas reburning system, varying operational control parameters, and assessing the effect on boiler emissions, completeness of combustion (carbon-in-ash), thermal efficiency, and heat rate. A one-year, long-term testing program was performed in order to judge the consistency ofsystem outputs, assess the impact of long-term operationon the boiler equipment, gain experience in operatingGR–LNB in a normal load-following environment, anddevelop a database for use in subsequent GR–LNB applications. Both first- and second-generation gas-reburningtests were performed.

(GR–LNB); and to assess the impact of GR–LNB onboiler performance.Technology/Project DescriptionGas reburning involves firing natural gas (up to 25% oftotal heat input) above the main coal combustion zone ina boiler. This upper-level firing creates a slightly fuelrich zone. NO

x drifting upward from the lower region of

the furnace is stripped of oxygen as the reburn fuel iscombusted in this zone and converted to molecular nitrogen. Low-NOx burners positioned in the coal combustion

zone retard the production of NOx by staging the burning

process so that the coal-air mixture can be carefully controlled at each stage. The synergistic effect of adding areburning stage to wall-fired boilers equipped with lowNO

x

 burners was intended to lower NO

x emissions by up

to 70%. Gas reburning was demonstrated with and with-
2 3 4 1 2 3 4 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 61

sions from a pre-con

06 Btu to 0.46 lb/106 Btu

uction.

corporated flue gas

with LNB, reduced NOx

lb/106 Btu (at 3.25% O2),

% gas heat input rate.

ut flue gas recirculation,

uced NO

x

 emissions to

64% NOx reduction with

tion GR with LNB were

sions by up to 70%

average was approxi

1990 1991 1992 1993 1994 1995 1996 1998 1999

eaward Operation

Design and Construction

10/90 11/92

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

Environmental monitoring plan completed 7/26/90

NEPA process completed (MTF) 9/6/90

Cooperative agreement awarded 10/13/90

Ground breaking/construction started 6/91

Design completed 8/91

Operation initiated 11/92Constructioncompleted 11/92

• After modifying the overfire air system to enhance

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

• SO2 emissions and particulate loadings were reduced

by the percentage heat input supplied by GR.

Operational• Boiler efficiency decreased < 1.0%.

• There was no measurable boiler tube wear and only a

small amount of slagging.

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

LNB alone.

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

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

Long-term operations started 4/93

Operation completed 1/95

Restorationcompleted 11/95

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

because GR reduces SO2 emissions whendisplacing coal.

Project SummaryThe demonstration established that GR–LNB offers acost-effective option for deep NOx reduction on wall-fired

boilers. GR–LNB NO

x control performance approached

that of selective catalytic reduction (SCR) but at significantly lower cost. The importance of cost-effectivetechnology for deep NOx reduction is the need for NOx

reduction in ozone nonattainment areas beyond what iscurrently projected in Title IV of the CAAA. Title I ofthe CAAA deals with ozone nonattainment and is currently the driving force for deep NOx reduction in many

regions of the country.

The GR–LNB was installed and evaluated on a 172-

MWe (gross) wall-fired boiler—a Babcock & Wilcoxbalanced-draft pulverized-coal unit. The GR system,including an overfire air system, was designed and in10/98 Project completed/final report issued 10/98

**
Environmental Control Devices

GR GenerationFirst Second

Baseline (lb/106 Btu) 0.73 0.73Avg NOx reduction (%)

LNB 37 44GR–LNB 66 64

Avg gas heat input (%) 18 12.5

Exhibit 23

NOx Data from Cherokee

Station, Unit No. 3

ing for the Foster

n the boiler wall.

tal Research Corpora

d installed by Foster

ctober 1992 and was

ametric tests examined

h as zone stoichiomet

rcent overfire air, and

tion, CO emissions,

 baseline performance

 a constant oxygen

ons were reduced with

heat inputs greater than

10%, NOx emissions were reduced marginally as gas heat

input increased. Natural gas also reduced SO2 emissions

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

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

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

The CO2 emissions were also reduced as a result of

using natural gas because it has a lower carbon-to-hydrogen ratio 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 were added to the demonstration to evaluate a modified or second-generation

system. Modifications are summarized below.• 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%.The removal of the flue gas recirculation system required installation of high-velocity injectors, whichmade greater use of available natural gas pressure.(This modification reduced natural gas usage and thusoperating costs.)

• Overfire air ports were modified to provide higher jet

momentum, especially at low total flows.

Over 4,000 hours of operation were achieved, with

the results as shown in Exhibit 23. Although the 37%NO

x reduction performance of LNB was less than the

expected 45%, the overall objectives of the demonstration

were met. Boiler efficiency decreased by only 1% 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.Economic PerformanceGR–LNB is a retrofit technology in which the economicbenefits are dependent on the following site-specificfactors:• Gas availability at the site• Gas/coal cost differential• Boiler efficiency• SO2 removal requirements

• Value of SO2 emission credits

Based on the demonstration, GR–LNB is expected to

achieve at least a 64% NO

x reduction with a gas heat

input of 12.5%. The capital cost estimate for a 300-MWewall-fired installation is $26.01/kW (1996 $) plus gaspipeline costs, if required. This cost includes both equipment and installation costs and a 15% contingency. The
Project Fact Sheets 63

The Public Service Company of Colorado has retained

the gas-reburning and low-NOx burner system for

commercial use.

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. Over-fire

ary loads will be par

e pulverizers. No addi

, but there is an increase

es were also made for

Based on these assump

 allowance of $95/ton

st is $2.14 million per

 $786/ton (constant

bout 35 existing wall

dustrial boilers, could

nology. The technology

ng, or greenfield installa

o the size or scope of the

mbination.

ess capital intensive, or

c reduction. GR–LNB

kind of coal.

Colorado, the host util

x burners and the gas

use; however, a

ve the flue gas recircula

Research Corporation has

rovide gas-reburning

ed boilers: TVA’s Allen

Unit No. 1, with options for Unit Nos. 2 and 3 (identical330-MWe Units); Baltimore Gas & Electric’s C.P. Crane,Unit No. 2, with an option for Unit No. 1 (similar 200-MWe Units). Use of the technology also extends to overseas markets. One of the first installations of the technology took place at the Ladyzkin State Power Station inLadyzkin, Ukraine.

This demonstration project was one of two that

received the Air and Waste Management Association’s1997 J. Deanne Sensenbaugh Award.ContactsBlair A. Folsom, Sr. V.P., (949) 859-8851, ext. 140

Energy and Environmental Research Corporation18 MasonIrvine CA 92618(949) 859-3194 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483Jerry L. Hebb, FETC, (412) 892-6079References• 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, April1993–January 1995). Report No. DOE/PC/90547-T20. Energy and Environmental Research Corporation. June 1995. (Available from NTIS asDE95017755.)

• Evaluation of Gas Reburning and Low NOx Burners

on a Wall-Fired Boiler (Optimization Testing, November 1992–April 1993). Report No. DOE/PC/90547-T19. Energy and Environmental Research Corporation. June 1995. (Available from NTIS as DE95017754.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Evaluation of Gas Reburningand Low-NOx Burners on a Wall-Fired Boiler. Energy

and Environmental Research Corporation. Report No.DOE/FE-0204P. U.S. Department of Energy. September 1990. (Available from NTIS as DE9100253.)
Environmental Control Devices

Selective

n

e Control of

m High

Boilers

—cofunder

Gulf Power Company’s

)

We and six 0.2-MWe

729 100%

673 40

056 60

mmercially available

erating conditions found

y boilers using high

rating conditions while

moval.

Technology/Project DescriptionThe SCR technology consists of injecting ammonia intoboiler flue gas and passing it through a catalyst bedwhere the NO

x and ammonia react to form nitrogen and

water vapor.

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

0.20-MWe equivalent SCR reactors. These reactors werecalculated to be large enough to produce design data thatwill allow the SCR process to be scaled up to commercialsize. Catalyst suppliers (two U.S., two European, andtwo Japanese) provided eight catalysts with variousshapes and chemical compositions for evaluation 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, FL, usedflue gas from the burning of 2.7% sulfur coal.

Results SummaryEnvironmental• NO

x

 reductions of over 80% were achieved at an

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

• Flow rates could be increased to 150% of design without exceeding the ammonia slip design level of 5 ppm

at 80% NO

x

 reduction.
2 3 4 1 2 3 4 1 2 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 65

ncreased above 700 oF,

he heat rate penalties.

ign of catalyst deactiva

m to approximately

 hours of operation, thus

 coal-fired units was in

ce.

t SO2 oxidation was

mits necessary to protect

olled by adequate

t catalyst erosion was not

as degraded because of

 by-product formation;

ified.

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction Operation

6/90

ess

/89

Cooperative agreementawarded 6/14/90

Ground breaking/construction started 3/92

7/93

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

Construction completed 2/93

Design completed 12/92

11/96

baskets to match predetermined reactor dimensions, provide a maximum of four catalyst layers, and meet thefollowing reactor baseline conditions:

The catalysts tested are listed in Exhibit 24. Catalyst

suppliers were given great latitude in providing theamount of catalyst for this demonstration.Environmental ResultsAmmonia slip, the controlling factor in the long-termoperation of commercial SCR, was usually <5 ppm beOperation initiated 7/93 Operation completed 7/95Project completed/final report issued 11/96 Parameter Minimum Baseline Maximum Temperature (oF) 620 700 750 NH3/NOx molar ratio 0.6 0.8 1.0 Space velocity (1% design flow) 60 100 150 Flow rate (scfm) Large reactor 3,000 5,000 7,500 Small reactor 240 400 600 • The SCR process did not significantly affect the re- sults of Toxicity Characteristic Leaching Procedure analysis of the fly ash. Economic Levelized costs for various NOx removal levels for a 250-MWe unit at 0.35 lb/106 Btu inlet follow: Project Summary The demonstration tests were designed to address several uncertainties, including potential catalyst deactivation due to poisoning by trace metals species in U.S. coals, perfor- mance of technology and effects on the balance-of-plant equipment in the presence of high amounts of SO2 and SO3, and performance of the SCR catalyst under typical U.S. high-sulfur coal-fired utility operating conditions. Catalyst suppliers were required to design the catalyst 40% 60% 80% 1996 levelized cost (mills/kWh) 2.39 2.57 2.79 1996 levelized cost ($/ton) 3,502 2,500 2,036
Environmental Control Devices

hibit 24

sts Tested

r Size* Catalyst Configuration

Honeycomb

Plate

Honeycomb

Honeycomb

Plate

Plate

HoneycombHoneycomb

mall = 0.2-MWe; 400 scfm

Exhibit 25

Average SO2 Oxidation Rate

(Baseline)

Average SO2 Oxidation (%)

NH3/NOx = 0.8, 700 oF, design flow

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

ut the ammonia slip

uction and design tem

ure, most catalysts

ements in overall per

d from 620 °F to

ment as temperature

The conclusion was that

peration probably do

not outweigh the heat rate penalties involved in operating SCR at the highertemperatures.

Catalyst deactivation was generally

observed by an increase in ammonia slipover time, assuming the NOx reduction

efficiency was held constant. Over the12,000 hours of the demonstration tests,the ammonia slip did, in fact, increase fromless than 1 ppm to approximately 3 ppm.These results demonstrated the maturity ofcatalyst design and that deactivation was inline with prior worldwide experience.

It has been observed that the catalytic

active species that results in NOx reduction

often contributed to SO2 oxidation (i.e.,

SO3 formation), which can be detrimental

to downstream equipment. In general, NOx

reduction can be increased as the tolerance for SO3 is also

increased. The upper bound for SO2 oxidation for the

demonstration catalyst was set at 0.75% at baseline conditions. The average SO2 oxidation rate for each of the

catalysts is shown in Exhibit 25. These data reflectbaseline conditions over the life of the demonstration.All of the catalysts were within design limits, with mostexhibiting oxidation rates below the design limit. Otherfactors affecting SO2 oxidations are listed below:

• Flow Rate. Most of the catalysts exhibited fairly

constant SO2 oxidation with respect to flow rate (i.e.,space velocity). In theory, SO2 oxidation should be

inversely proportional to flow rate.

• Temperature. Theoretically, the relationship between

SO2 oxidation and temperature should be exponential

as temperature increases; however, measurementsshowed the relationship to be linear with little difference 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 can be summarized as follows:

• Pressure Drop. Overall reactor pressure drop was a

function of the catalyst geometry and volume, but teststo determine which one was controlling were inconclusive.

• Fouling. The fouling characteristics of the catalyst

were important to long-term operation. During thedemonstration, measurements showed relatively levelpressure drop over time, indicating that sootblowingprocedures were effective. The plate-type configurations had somewhat less fouling potential than did thehoneycomb configuration, but both were acceptablefor application.

• Erosion. Catalyst erosion was not considered to be a

significant problem because most of the erosion wasattributed to aggressive sootblowing.

• Air Preheater Performance. The demonstration

showed that the SCR process exacerbated performancedegradation of the air preheaters mainly due to ammo-
Project Fact Sheets 67

Exhibit 26

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

40% 60% 80%

Capital cost ($/kW) 52 54 57Operating costs ($) 926,000 1,045,000 1,181,0001996 levelized costmill/kWh 2.39 2.57 2.79$/ton 3,502 2,500 2,036

oduct formation. Regen

ormed recuperators in

both thermal perfor

he ammonia volatilized

ignificant amount of

h. This was caused by

 on the ash with a pH

mmonia compounds in

.

ching Procedure

alyses were performed on

cess did not significantly

of the fly ash.

formed for full-scale

to a new 250-MWe pul

n a rural area with mini

considered was high

key base case design

lysis of capital, operating

velized cost based on a

nit sizes for an SCR

iency of 60% follow:

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/106Btu of inlet NOx are

as follows:

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. Thelevelized costs for the retrofit applications were$1,850–5,100/ton (current 1996 $).

Commercial ApplicationsAs a result of this demonstration, SCR technology hasbeen shown to be applicable to existing and new utilitygenerating capacity for removal of NOx from the flue gas

of virtually any size boiler. There are over 1,000 coalfired utility boilers in active commercial service in theUnited States; these boilers represent a total generatingcapacity of approximately 300,000-MWe.ContactsLarry Monroe, (205) 257-7772

Southern Company Services, Inc.P.O. Box 2625Birmingham, AL 35202-2625(205) 257-5367 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, FETC, (412) 892-5991References• 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.)

• Economic Evaluation of Commercial-Scale SCR Applications for Utility Boilers. Southern Company

Services, Inc. September 1996. (Available from NTISas DE97051156.)

e 250-MWe 700-MWe

54 45

1,045,000 2,667,000

2.57 2.22

2,500 2,165
Environmental Control Devices

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

x reduction capabilities of LNCFSTM levels I, II,

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

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

tration of

ially-Fired

iques for the

Emissions

oilers

and host

—cofunder

c.—cofunder and tech

f Power Company’s

ow-NOx Concentric

vanced overfire air

nd offset air

y

383 100%

184 49

199 51

n Engineering, Inc.

in the LNCFSTM II system. This was an advancedoverfire air system that incorporates back pressuring andflow measurement capabilities. CCOFA and SOFA wereboth used 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.
2 3 4 1 2 3 4 1 2 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 69

ns using LNCFSTM I, II,

.34 lb/106 Btu, respec

ions of 37, 37, and 45%

re not sensitive to power

0-MWe, but emissions

100-MWe, reaching

-MWe.

ness at low loads,

s a compliance option for

sed at full load.

FSTM to have no clear-cut

ce metals or acid gases.

VOCs) appeared to be

mpounds increased.

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

LNCFSTM retrofits but very sensitive to coal fineness.

• Furnace slagging was reduced but back-pass 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

9/90

Design and Construction

Project completed/final report issued 6/94

6/94

Environmental monitoringplan completed 12/27/90

Ground breaking/construction started 11/90

Design completed 4/91

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

Project SummaryAt the time of the demonstration, specific NOx emission

regulations were being formulated under the CAAA. Thedata developed over the course of this project providedneeded real-time input to regulation development.

LNCFSTM technology was designed for tangentiallyfired boilers, which represent a large percentage of the

pre-NSPS coal-fired generating capacity. The technologyreduces NO

x by staging combustion in the boiler vertically by separating coal and air injectors and horizontally

by creating fuel-rich and lean zones with offset airnozzles. The objective was to determine NOx emission

reductions and impact on boiler performance over thelong-term under normal dispatch and operating conditions. By using the same boiler, the demonstration provided direct comparative performance analysis of thethree configurations. Short-term parametric testing enabled extrapolation of results to other tangentially-firedunits by evaluating the relationship between NOx emissions and key operating parameters.

s

TF)

ed 9/20/90

5/91
Environmental Control Devices

27

gurations

Exhibit 28

Concentric Firing Concept

 LNCFSTM configura

ustion. In addition to

8, the LNCFSTM incor

ques into the combusconcentric circular

he majority of the coal

region. This region is

ntaining combustion air.

ombustion air can be

ozzles.

s of LNCFSTM on unit

Environmental PerformanceAt full load, LNCFSTM I, II, and III reduced NOx emissions by 37, 37, and 45%, respectively. Exhibit 30 presents the NO

x

 emission estimates obtained in the assessment of the average annual NOx emissions for three dispatch scenarios.

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

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

Economic PerformanceLNCFSTM II was the only complete retrofit (LNCFSTM Iand III were modifications of LNCFSTM II), and thereforecapital cost estimates were based on the Lansing SmithUnit No. 2 retrofit as well as other tangentially-firedLNCFSTM retrofits. The capital cost ranges in 1993 constant dollars follow:• LNCFSTM I—$5–15/kW• LNCFSTM II—$15–25/kW• LNCFSTM III—$15–25/kW

Site-specific considerations have a significant effect

on capital costs; however, the above 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 technologies islisted below (based on a levelization factor of 0.144 in

1993 constant dollars):• LNCFSTM I—$103/ton of NOx removed

• LNCFSTM II—$444/ton of NOx removed

• LNCFSTM III—$400/ton of NOx removed

Commercial ApplicationsLNCFSTM technology has potential commercial application to all the nearly 600 U.S. pulverized coal, tangentially-fired utility units. These units range from 25-MWeto 950-MWe in size and fire a wide range of coals, fromlow-volatile bituminous through lignite.

LNCFSTM has been retained at the host site for commercial use. ABB Combustion Engineering has modified

116 tangentially-fired boilers, representing over 25,000MWe, with LNCFSTM and derivative TFS 2000TM burners.
Project Fact Sheets 71

Exhibit 29

mance Impacts Based on Long-Term Testing

Baseline LNCFSTM I LNCFSTM II LNCFSTM III

10 12 22 33

3.7 3.2 4.5 4.3

4.8 4.6 4.2 5.9

4.0 3.9 5.3 4.7

Satisfactory at full Full load: 5–10 oF Same as baseline 160–200-MWe: OK

oad; low temper- lower than baseline 80-MWe: 15–35 oF

patures at low loads Low loads: 10–30 oF lower than baseline

lower than baseline

Medium Medium Reduced slagging, Reduced slagging,

but increased fouling but increased fouling

Normal Same as baseline More care required More difficult to

at low loads operate than other

systems

90 90.2 89.7 89.85

N/A +0.2 -0.3 -0.15

9,000 9,011 9,000 9,000

9,995 9,986 10,031 10,013

N/A -0.1 +0.36 +0.18

Exhibit 30

nual NOx Emissions and Percent Reduction

Baseline LNCFSTM I LNCFSTM II LNCFSTM III

Ox emissions (lb/106 Btu) 0.62 0.41 0.41 0.36

uction (%) 38.7 38.7 42.2

Ox emissions (lb/106 Btu) 0.62 0.40 0.41 0.34

uction (%) 39.2 35.9 45.3

Ox emissions (lb/106 Btu) 0.59 0.45 0.47 0.43

uction (%) 36.1 20.3 28.0

ContactsLarry Monroe, (205) 257-7772

Southern Company Services, Inc.P.O. Box 2625Birmingham, AL 35202-2625(205) 257-5367 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, FETC, (412) 892-5991References• 180-MWe Demonstration of Advanced TangentiallyFired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx) Emissions from Coal-Fired

Boilers: Final Report and Key Project Findings. Report No. DOE/PC/89653-T14. Southern CompanyServices, Inc. February 1994. (Available from NTISas DE94011174.)

• 180-MWe Demonstration of Advanced TangentiallyFired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx) Emissions from Coal-Fired

Boilers—Plant Lansing Smith—Phase III and FinalEnvironmental Monitoring Program Report. SouthernCompany Services, Inc. December 1993.

• Measurement of Chemical Emissions under the Influence of Low-NOx Combustion Modifications. Report

No. DOE/PC/89653-T12. Southern Company Services, Inc. October 1993. (Available from NTIS asDE94005038.)

• 180-MW Demonstration of Advanced TangentiallyFired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx) Emissions from Coal-Fired

Boilers: Public Design Report. Report No. DOE/PC/89652-T13. Southern Company Services, Inc. September 1993. (Available from NTIS as DE94000218.)
Environmental Control Devices

Advanced

iques for a

(SCS)

(EPRI)—cofunder

n (Foster Wheeler)—

a Power Company’s

(LNB) with advanced

eneric NOx Control

mputer software.

lfur

$15,853,900 100%

6,553,526 41

9,300,374 59

th the LNB/AOFA

ions of AOFA and LNB

rs for optimal LNB/

the long-term effects of

LNB, AOFA, combined LNB/AOFA, and the GenericNO

x Control Intelligence System advanced digital controls on NO

x reduction and boiler performance.

Technology/Project DescriptionAOFA involves (1) improving overfire air (OFA) mixingto lower overall stoichiometry (less total excess air) whilestill avoiding high unburned combustible losses, (2)allowing deeper staging (sub-stoichiometric conditions inthe flame zone, i.e., reducing atmosphere) without increasing combustible losses, and (3) introducing “boundary air” at the boiler walls to prevent corrosion caused bythe reducing atmosphere.

In the Foster Wheeler Controlled Flow/Split Flame

(CFSF) LNB, fuel and air mixing (staged combustion) iscontrolled for localized, individual burner flames, ratherthan on a gross furnace-wide basis, by regulating the

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 airnecessary 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 2800 °F). The

final excess air can then be allowed to mix with the unburned products so that combustion is completed at arelatively low temperature.

The demonstration was conducted at Plant

Hammond Unit No. 4, which is a nominal 500-MWeFoster Wheeler pulverized coal opposed wall-fired unitthat typifies many existing pre-NSPS wall-fired boilers inthe United States. To accomplish the project objective,
2 3 4 1 2 3 4 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 73

1990 1991 1992 1993 1994 1996 1997 1998 1999

6/90

Design and Construction

erative agreement awarded 12/20/89

Design completed 3/90

Construction started, AOFA 4/90

Construction completed, AOFA 5/90

Operation initiated, AOFA 6/90

Environmental monitoring plan completed 9/14/90

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

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

Operation completed, LNB 1/92

Operation initiated, LNB/AOFA 5/93

Operation

Operation completed, LNB/AOFA 8/93

Operation initiated,LNB/AOFA with digital control system 6/94

he following test phases:

NB, (3B) LNB/AOFA,

volved three distinct

acterization (diagnostic,

sion tests), long-term

us days), and short-term

xics testing was con

A and a demonstration

s was conducted during

gnition (LOI) was near

f 5%) for LNB alone and

mental NO

x

 reduction

proximately 17%, with

g from other operational

• GNOCIS achieved a boiler efficiency gain of 0.5

percentage points, a reduction in fly ash LOI levels of1-3 percentage points, and a reduction in NOx emissions of 10-15% at full load.

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

lb/106 Btu, representing a 48% reduction from

baseline conditions (1.24 lb/106 Btu).

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

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

conditions.

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

0.40 lb/106 Btu, which represents a 68% reduction

from baseline conditions.

• There was not a significant difference in emissions of

trace metals, acid gases, and volatile organic compounds between AOFA and LNB operations. But,there was a slight downward trend in emissions duringLNB/AOFA operation.

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 $86/ton using

LNB/AOFA.

Project SummaryOperationalSCS conducted baseline characterization of the unit in an“as-found” condition from August 1989 to April 1990.The AOFA system was tested from August 1990 to March1991. Following installation of the LNBs in the secondquarter of 1991, the LNBs were tested from July 1991 toJanuary 1992, excluding a three-month delay when theplant ran at reduced capacity. Post-LNB increases in flyash LOI, along with increases in combustion air requirements and fly ash loading to the electrostatic precipitator(ESP), adversely affected the unit’s stack particulateemissions. The LNB/AOFA testing was conducted from

1 2

Final report (Phase 1-3B)

issued 1/98

**

GNOCIS testing initiated 2/96

Final report (Phase 4) issued 9/98

Project extension 4/99*

4/99
Environmental Control Devices

luding downtime for a

of the test period due

 However, an ammonia

added to improve ESP

nit to operate at full

r the AOFA, LNB, and

ibit 31, despite im

e replacement of the

rn not only because of

a potential loss of fly

 the fly ash renders the

ing concrete.

onducted parametric

p between NOx and

sted were: excess oxy

ding tip position,

burner inner register

s and LOI levels varied

0%, respectively. As

 considerable effect on

owed that there is some

m operating point and

making tradeoffs between NOx emissions and

fly ash LOI; however, much of the variationwas the result of changes in excess oxygen.This can be more clearly seen in Exhibit 32 inwhich all sensitivities are plotted. This exhibit shows that for excess oxygen, mill bias,inner register, and sliding tip, any adjustmentsto reduce NO

x emissions are at the expense of

increased fly ash LOI. In contrast, the slopeof the outer register characteristic suggestsimprovement in both NOx emissions and LOI

can be achieved by adjustment of this damper.However, due to the relatively small impact ofthe outer register adjustment on both 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 33. There aretradeoffs in boiler operation, e.g., as excess air increases,NO

x increases, LOI decreases, and boiler losses increase.

The goal is to find and maintain an optimal operating

condition. The I&C systems tested includedGNOCIS and carbon-in-ash analyzers.

The GNOCIS software applies an optimizing

procedure to identify thebest set points for the plant,which are implementedautomatically without operator intervention (closedloop), or conveyed to theplant operators for implementation (open-loop). Themajor elements of GNOCISare shown in Exhibit 34.The GNOCIS system hasprovided advice that reduced NO

x emissions by 10-

15% at full load, reduced fly ash LOI by 1-3 percentagepoints, and improved boiler efficiency by 0.5 percentagepoints.

Three carbon-in-ash monitors were installed: Applied Synergistics FOCUS, CAMRAC Corporation CAM,

and Clyde-Sturtevant SEKAM. The monitors seemed torepresent LOI trends well by responding in the correctdirection and provided important and timely informationon combustion performance.

it 31

ce Test Results

Exhibit 33

Typical Trade-Offs in Boiler Optimization

Exhibit 32

NOx vs. LOI Tests–All Sensitivities
Project Fact Sheets 75

e AOFA, LNBs, and

Ox reductions of 24, 48,

-weighted average of

4, 48, and 63%, respec

OFA. Although the long

esents a 68% reduction

al portion of the incre

 between the LNB and

s the result of operational

dding AOFA.

ong-term NOx emissions

NB/AOFA test phase.

ad, long-term NOx emis

h was consistent with

er long-term testing had

4 lb/106 Btu and 0.65

NB only, respectively.

e testing revealed an

b/106 Btu.

cted for AOFA and LNB/

 a significant difference

d gases, and volatile

ests. There was a slight

issions during LNB/

associated with particu

m, chromium, cobalt,

 phosphorus, and vana

ns during LNB/AOFA

cadmium) show higher

FA operation. Total

e also lower during LNB/

was more an indication of

ner configuration.

mercial 500 MWe wall

8/kW, LNB—$10.0/kW,

OCIS—$0.5/kW. Annual

depend on the assumed

load profile. Based on the actual load profileobserved in the testing, the estimated annualO&M cost increase for LNB and 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. The capital costis $8,300,000 and the calculated cost of NOx

removed is $86/ton.

The addition of GNOCIS to the LNB/

AOFA, using the actual load profile observed inthe testing, results in a range of costs dependingon whether the unit is operated to maximizeNOx removal efficiency, or LOI. For the maximum NOx removal case, the efficiency is improved by 0.6 percent, the annual O&M cost is

decreased by $228,058, the incremental NOx

reduction is 11 percent (834 tons/year), and the capitalcost is $250,000. The calculated cost per ton of NOxremoved is -$299 (net gain due to increased efficiency).Commercial ApplicationsThe technology is applicable to the 422 existing preNSPS wall-fired boilers in the United States, which burna variety of coals. The GNOCIS technology is applicableto all fossil fuel-fired boilers, including units fired withnatural gas and units co-firing coal and natural gas.

The host has retained the technologies for commercial use. Foster Wheeler has equipped 86 boilers with

low-NOx burner technology (51 domestic and 35 international)—1,800 burners for over 30,000 MWe capacity.

Some 19 GNOCIS neural-network control projects areunderway and another 17 projects are expected in 1999.ContactsJohn N. Sorge, (205) 257-7426

ICCT Project ManagerSouthern Company Services, Inc.P.O. Box 2625Birmingham, AL 35202-2625jnsorge@southernco.com

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James R. Longanbach, FETC, (304) 285-4659

jlonga@fetc.doe.gov

References• 500 MW Demonstration of Advanced Wall-Fired Combustion Techniques for the Reduction of Nitrogen

Oxide (NOx) Emissions from Coal-Fired Boilers–

Phases 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–FinalReport—Phases 1-3. Southern Company Services,Inc. January 1998.

• 500 MW Demonstration of Advanced Wall-Fired

Combustion Techniques for the Reduction of NitrogenOxide (NOx) Emissions from Coal-Fired Boilers–

Public Design Report (Preliminary and Final). Southern Company Services, Inc. Submitted to DOE onMay 24, 1996.

Exhibit 34

Major Elements of GNOCIS
 Project Fact Sheets 77

nvironmental Control Devices

ined SO2/NOx Control Technology
Environmental Control Devices

CoalPittsburgh, Freeport, and Kittanning Coals; 1.5, 2.9 and4.0% sulfur, respectively.Project FundingTotal project cost $158,607,807 100%DOE 45,000,000 28Participant 113,607,807 72Project ObjectiveTo demonstrate high sulfur capture efficiency and NOxand particulate control at minimum power requirements,zero waste water discharge, and the production of byproducts in lieu of wastes.Technology/Project DescriptionThe formic acid enhanced S-H-U process is designed toremove up to 98% SO2 at high sorbent utilization rates.

chnology

al

nstration

orporation

and Development

arch Corporation—

chnical consultant

GmbH (S-H-U)—tech

nufacturing

r

ogy supplier

operator of advisor

New York State Electric

ion, Unit Nos. 1 and 2)

mic-acid-enhanced, wet

BB Combustion

c Firing System

e-lined split-module

at-pipe air preheater;

em.

n Engineering, Inc.

, Inc.

The Stebbins tile-line, split-module reinforced concreteabsorber vessel provides superior corrosion and abrasionresistance. Placement below the stack saves space andprovides operational flexibility.

NO

x emissions are controlled by LNCFS IIITMlowNO

x burners and by micronized coal reburning. The

LNCFS IIITM low-NO

x burners are integrated into the

Milliken units. (See Micronized Coal Reburning Demonstration for NO

x Control for another CCT Program project

at this unit.)

A heat-pipe air preheater is integrated to increase

boiler efficiency by reducing both air leakage and the airpreheater’s flue gas exit temperature. To enhance boilerefficiency and emissions reductions, DHR’s Plant Emission Optimization Advisor (PEOATM) provides state-ofthe-art artificial-intelligence-based control of key boilerand plant operating parameters.

AIR

COAL

SOLID

WASTE

ASH TO DISPOSAL

ELETR OSTATIC

PRECIPITATO R

ASH TO DISPOSAL

ASH

COMMERCIAL-GRADE

CALCIUM C HLORIDE

ELECTRO STATIC

PR EC IP ITATO R

COAL

ASH

AIR

UNIT #2

BOILER

HOT FLUE

GAS INLET

COOL FLUE

GAS OUTLET

HEAT-PIPE

AIR-HEATER SYSTEM

HOT 

COMBUSTION

AIR OUTLET

UNIT #1BOILER

AIR

PREHEATER

(REFURBISHED )

ELECTRO STATIC

PR EC IP ITATO R

COLD COMBUSTION

AIR INLET

FGD BLOWDOWN

TREATMENT

& RECYCLE

COMMERCIAL-GRADE

GYPSUM

LIM ESTONE

PR EPARATIO N

AND

HANDLING

SPLIT

MODULE

ABSORBER

BELOW STACK

FLUE GAS

OUT

OF STACK

FLUE

GAS

GYPSUM

DEWATERING /

HANDLING

CCOFA REBURNING

OF MICRONIZED

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

*Projected date

1 2

 Project Fact Sheets 79

1993 1994 1995 1996 1997 1998 1999 2000 2001

Operation

tive agreement awarded 10/20/92

Ground breaking/construction started 4/93Design completed 4/93

NEPA process completed(EA) 8/18/93

5/99

Operation completed 6/98

Project completed/final report issued 5/99*

Operation initiated on Unit 2 1/95

6/95

Design and Construction

Environmental

monitoring

plan completed

12/1/94 Fully integrated operation of Units 1 and 2 initiated 6/95

Construction completed 6/95

emonstrated has been

umps operating and using

O2 removal without

l between the two lime

–325 mesh and 90%–170

coal was a minimum of

was greater than the de

h velocity test of the

 to a liquid-to-gas ratio

0 actual cubic feet of gas.

measurable effect on

untercurrent pumps

ubber pressure drop.

untercurrent header was

.45 inches water column

(WC) in the design flow tests and 0.64 inches WC inthe high velocity tests.

• At full load, LNCFSTM III lowered NOx emissions to

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

original burners).

• During diagnostic tests, LOI was above 4% at full

boiler load. During the validation tests (when overfireair limitations were relaxed), the LOI dropped by 0.7to 1.7 percentage points, with a minor effect on NOx

emissions.

Operational• Performance of a modified ESP with wider plate spacing and reduced plate area exceeded that of the original ESPs at lower power consumption.• Boiler efficiency was 88.3–88.5% for LNCFSTM III,

compared to a baseline of 89.3–89.6%.

• Air infiltration is low for both heat pipes. Some unaccounted for air leakage occurred at full load, ranging

between 2.0–2.4%.

• The flue gas side pressure loss for both heat pipes was

less than the design maximum of 3.65 inches WC.The primary side pressure drops for both heat pipeswere less than the design maximum of 3.6 inches WC.The secondary air side pressure drops for both heatpipes were less than the design maximum of 5.35inches WC.

Economic• Economic data is not yet available.
Environmental Control Devices

ver all of the new tech

dition to the technolo

ed that existing tech

n with new processes to

pplemental monitoring

mance data illustrating

er a variety of operating

ogram was divided into

tic, performance, long

d over a 36 month pe

SO2 removal efficiency,

omics, load following

product quality, and

g included formic acid

concentration, L/G ratio, mass transfer, coal sulfur content, and flue gas velocity. The maximum SO2 removal

demonstrated was 98% with all seven recycle pumpsoperating and using formic acid and the maximum SO2

removal without formic acid was 95%. The difference inSO2 removal between the two limestone grind sizes tested

(90%–325 mesh and 90%–170 mesh), while using lowsulfur coal was a minimum of 2.6 percentage points asshown in Exhibit 35. The SO2 removal efficiency was

greater than the design efficiency during the high velocitytest of the cocurrent scrubber section up to a liquid-to-gasratio of 110. The cocurrent pumps had no measurableeffect on pressure drop, whereas the countercurrentpumps significantly increased the scrubber pressure drop.As seen in Exhibit 36, the average effect of each countercurrent header was to increase pressure drop by 0.45inches water column (WC) in the design flow tests and0.64 inches WC in the high velocity tests.

Performance of modified ESP with wider plate

spacing and reduced platearea exceeded that of theoriginal ESPs at lowerpower consumption. Theaverage particulate matterpenetration before the ESPmodification was 0.22%and decreased to 0.12%after the modifications.

At full boiler load

(145–150 MWe) and 3.0–3.5% economizer O2, the

LNCFSTM III lowered NOx

emissions from a baselineof 0.64 lb/106 Btu to 0.39

lb/106 Btu (39% reduction).

At 80-90 MWe boiler loadand 4.3–5.0% economizerO2, 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. Operational Performance The S-H-U FGD system performance goal of 98% SO2 removal efficiency was achieved. Similarly, the objective of producing a marketable gypsum by-product from the FGD system was achieved. The test results indicate that the gypsum produced can be maintained at a purity level exceeding 95% with a chloride level less than 100 ppm. However, the goal of producing a marketable calcium chloride solution from the FGD blowdown stream was not achieved. FGD availability for the test period was 99.9%. The modified ESP has performed better than the original ESP at a lower power use. The total voltage• current product (V•I) for ESPs is directly proportional to the total power requirement. The modified ESP 75% of the V•I demand of the original ESPs. The modified ESP has a smaller plant footprint with fewer internals and a smaller SCA. Total internal plate area is less than one- half that of the original ESPs, tending to lower capital costs.Boiler efficiency was 88.3–88.5% for LNCFSTM III, compared to a baseline of 89.3–89.6%. The lower effi- ciency was attributed to higher post retrofit flue gas O2 and higher stack temperatures which accompanied the air heater retrofit. When LNCFSTM III and baseline condi- tions are compared, boiler efficiency with LNCFSTM III was 0.2 percentage points higher than baseline. The heat pipe were tested in accordance with ASME Power Test Code for Air Heaters 4.3. Air infiltration is low for both heat pipes. Unaccounted for air leakage occurred at full load, ranging between 2.0–2.4%. The tests showed that the flue gas side pressure loss for both heat pipes was less than the design maximum of 3.65 inches WC. The primary side pressure drops for both heat pipes were less than the design maximum of 3.6 Exhibit 35 

of Limestone Grind
 Project Fact Sheets 81

de pressure drops for

e design maximum of

le.

orber module and heat

to virtually all power

features of the technolo

on of marketable

entives to generating

re have been four com

tem.

ContactsJames Harvilla, Project Manager, (607) 729-8630

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, FETC, (412) 892-5991References• Comprehensive Report to Congress on the Clean Coal

Technology Program: Milliken coal Technology Demonstration Project. New York State Electric & Gas

Corporation. Report No. DOE/FE-0265P. U.S. Department of Energy. September 1992. (Available fromNTIS as DE93001756.)

• Milliken Clean Coal Technology Demonstration

Project. Harvilla, James et al. 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.

t 36

Drop vs.

nt Headers
Environmental Control Devices

chnology

nstration of

Ox Removal

System

—cofunder

der

—host

rable flue gas cleanup

120 100%

060 50

060 50

f the SO2 and 75% of

flue gas using the

on

nerable system capable

flue gas from coal-fired

utility boilers burning medium- to high-sulfur coals. Inthe basic process, the flue gas passes through a fluidizedbed adsorber located downstream of the precipitator; SO2

and NO

x are adsorbed by the sorbent, which consists of

spherical beads of high-surface-area alumina impregnatedwith sodium carbonate. Cleaned flue gas then passesthrough a baghouse to the stack.

The NO

x

 is desorbed from the NOXSO sorbent when

heated by a stream of hot air. Hot air containing thedesorbed NO

x is recycled to the boiler where equilibrium

processes cause destruction of the NOx. The adsorbed

sulfur is recovered from the sorbent in a regeneratorwhere it reacts with methane at high temperature to produce an offgas with high concentrations of SO2 and hydrogen sulfide (H2S). This offgas is processed to produce

elemental sulfur, which can be further processed to produce liquid SO2, a higher valued by-product.

The process is expected to achieve SO2 reductions of

98% and NO

x

 reductions of 75%.

Project Status/AccomplishmentsAlcoa Generating Corporation chose to cancel a host siteagreement when NOXSO was unable to obtain fullproject financing by January 31, 1997, as specified in theagreement. NOXSO signed a conditional Host SiteAgreement with RP&L in January 1998.

NOXSO filed for bankruptcy under Chapter 11 -

Reorganization. The Chapter 11 plan was approved bythe Bankruptcy Court on September 2, 1998, but NOXSOwas unable to raise sufficient funds. NOXSO closed itsoffice in October 1998. An auction of NOXSO’s assets isscheduled for May 27, 1999.
2 3 4 1 2 3 4 1 2 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 83

le to existing or new

e for utility and industrial

s adaptable to coals with

f the following as a sal

r, sulfuric acid, or liquid

exists for these products.

to be especially attractive

val efficiencies for both

solid wastes, and/or have

t scrubber.

1991 1992 1993 1994 1995 1996 1997 1998 1999

91

CT-III) 12/19/89

Cooperative agreementawarded 3/11/91

Design

Alcoa Generating Corp. cancelledhost site agreement 2/97

Novation of cooperative agreement with NOXSO Corp. 8/94

Selected Alcoa host site 8/94

Project definition phase completed 10/94

NEPA process completed, Alcoa (EA) 6/26/95

Identified conditional host site,RP&L 1/98

Schedule pending actionin bankruptcy court

On Hold
Environmental Control Devices

Technology/Project DescriptionIn the SNOXTM process, the stack gas leaving the boiler iscleaned of fly ash in a high-efficiency fabric filterbaghouse to minimize the cleaning frequency of the sulfuric 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 catalytic reactorswhere the NO

x is converted to harmless nitrogen and

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

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

concentrated sulfuric acid.

The technology, while using U.S. coals, was designed to remove 95% of the SO2 and more than 90% of

the NO

x from flue gas and produce a salable sulfuric acid

by-product. This was accomplished without using sorbents and without 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 commercial full-scale plant, and commercial-scale components were installed and operated.

echnology

Cleaning

oject

cofunder

 and host

for process technology,

and process designer

o Edison’s Niles

c advanced flue gas

m a 108-MWe boiler

408 100%

200 50

208 50

er plant using U.S.

hnology will catalyti

e than 90% of NOx

e by-product of con2 3 4 1 2 3 4 1 2 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 85

• Absence of an alkali reagent contributed to having no

secondary pollution streams or 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 levelizedincremental cost was estimated at 6.1 mills/kWh or$219/ton of SO2 removal on a constant 1995 dollar

basis. Comparable current dollar costs were 7.8 mills/kWh and $284/ton of SO2.

ormally in excess of 95%

ging about 2,000 ppm.

for inlet concentrations

m.

 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

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

Project SummaryNo reagent was required for the SO2 removal step because

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

result, the process produced no other waste streams.

In order to demonstrate and evaluate the performance

of the SNOXTM process, general operating data werecollected and parametric tests conducted to characterizethe process and equipment. The system operated forapproximately 8,000 hours and produced more than5,600 tons of commercial-grade sulfuric acid. Many ofthe tests for the SNOXTM system were conducted at threeloads—75, 100, and 110% of design capacity.Environmental PerformanceParticulate emissions from the process were very low (<1 mg/Nm3) due to the characteristics of the SO2 catalyst and the sulfuric acid condenser (WSA Condenser).

The Niles SNOXTM plant was fitted with a baghouse(rather than an ESP) on its inlet. This was not necessaryfor low particulate emissions, but rather was needed to
Environmental Control Devices

The bottom portion of the SO2 converter catalyst, with

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

equency for the SO2

, the SO2 catalyst,

ned about

atalyst vessel. Dust that

removed in the WSA

ensing particulate re

rticulates as nuclei).

2 emissions by the

the lack of a carbonate

CO2 and the fact that the

from the flue gas to

ments. This heat recov

 results in the net heat

r better after addition of

ently no increase in

carbons, the SO2 cata

se compounds as well.

d the interaction of the

he SO2 catalyst fol

cted ammonia (slip)

 nitrogen, water vapor,

result, downstream

was eliminated and the

er than typical ammonia

chiometries allowed

 permitted the attain

encies (>95%).

 SNOXTM process was

SO2-to-SO3 oxidation,

ses through the oxida

was controlled by two

mperature. Space

atalyst necessary at

nd gas and bed tempera

vate the SO2 oxidation,

 SO2 removal effi

95% for inlet concentra

The SCR portion of the SNOXTM process was able to

operate at higher than typical ammonia stoichiometriesdue to its location ahead of the SO2 catalyst beds. Normal

operating stoichiometries for the SCR system were in therange of 1.02–1.05 and system reduction efficienciesaveraged 94% with inlet NOx levels of approximately

500–700 ppm.

Sulfuric acid concentration and composition has met

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

Air toxic 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• Semi-volatile compounds including polynuclear aromatic hydrocarbons• Aldehydes

Most trace elements were captured in the baghouse

along with the particulate. A significant portion of theboron and almost all of the mercury escaped to the stack.

But selenium and cadmium, normally a problem, wereeffectively captured in the acid drain, as were organiccompounds.Operational PerformanceHeat recovery was accomplished by the SNOXTM process.In a commercial configuration, it can be utilized in thethermal cycle of the boiler. The process generated recoverable heat in several ways. All of the reactions that tookplace with respect to NOx and SO2 removal were exothermic and increased the temperature of the flue gas. This
 Project Fact Sheets 87

The SNOXTM demonstration at Ohio Edison’s Niles

Station Unit No. 2 achieved SO2 removal efficienciesexceeding 95% and NOx reduction effectiveness averaging94%. Ohio Edison is retaining the SNOXTM technology aspart of its environmental control system.

added in the high-tem

was recovered in the

harge for use in the

use the WSA Condenser

ue gas to about 210 oF,

oF for a typical power

was recovered along with

SNOXTM process showed

305/kW for a 500-MWe

 levelized incremental

stant 1995 dollar basis

ollar basis. The equiva

d were $219/ton (con

rrent dollars).

icable to all electric

utional boilers firing

al efficiency for NOx and

 in many applications.

aste (except ash) en

n

e

n,



s

nd

burns 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, (423) 693-7550

ABB Environmental Systems1409 Center Port BoulevardKnoxville, TN 37932(423) 694-5213 (fax)

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, FETC, (412) 892-5991References• 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.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: WSA-SNOXTM Flue Gas Cleaning Demonstration Project. ABB Combustion Engineering, Inc. Report No. DOE/FE-0151. U.S. Department of Energy. November 1989. (Available fromNTIS as DE90004461.)
Environmental Control Devices

Project ObjectiveTo demonstrate, with a variety of coals and sorbents, thatthe LIMB process can achieve up to 50% NOx and SO2reductions and to demonstrate that the Coolside processcan achieve SO2 removal up to 70%.

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

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

coals (1.6, 3.0, and 3.8% sulfur) and four sorbents weretested. Other variables examined were stoichiometry, 

 Babcock & Wilcox Company. 

Research Institute.

humidifier outlet temperature, and injection level in theboiler.

In the Coolside process, dry sorbent is injected into

the flue gas downstream of the air preheater, followed byflue gas humidification. Humidification enhances ESPperformance and SO2 absorption. SO2 absorption is

improved by dissolving sodium hydroxide (NaOH) orsodium carbonate (Na2CO3) in the humidification water.

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

Babcock & Wilcox DRB-XCL® low-NO

x burners,

which control NO

x through staged combustion, were used

in demonstrating both LIMB and Coolside technologies.

chnology

on Project

olside

cofunder

funder and technology

Edison’s Edgewater

s (B&W) limestone

MB) system; Babcock &

urners

oolside duct injection of

% sulfur

940 100%

026 39

914 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

1 2

 Project Fact Sheets 89

• 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-adiabatic-saturationtemperature using commercial hydrated lime and2.8–3.0% sulfur coal.

• Sorbent recycle tests demonstrated the potential to

improve sorbent utilization.

Operational• Humidification enhanced ESP performance, which

enabled opacity levels to be kept well within limits.

• LIMB availability was 95%. Coolside did not undergo

testing of sufficient length to establish availability.

• Humidifier performance indicated that operation in a

vertical rather than horizontal mode would be better.

Economic• LIMB capital costs were $31–102/kW for plants ranging from 100–500-MWe and coals with 1.5–3.5%

sulfur, with a target SO2 reduction of 60% (1992$).

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

toring plan

 10/19/88

es at a calcium-to-sulfur

minimal humidification

r contents were 53–61%

lcitic lime, 45–52% for

for limestone ground to

5 mesh).

y increased to 32% using

nus 325 mesh and in

when ground to 100% less

es were enhanced by

on down to 20 oF ap

ure was used.

abcock & Wilcox

, achieved 40–50% NOx

Operation

LIMB operational testsinitiated 4/90

Coolside operational testscompleted 2/90

7/89

Annual levelized costs (15-year) for this range ofconditions 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.

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

the significantly more expensive lime would keep operating costs relatively low. However, the demonstrationshowed that even with fine grinding of the limestone anddeep humidification, performance with limestone wasmarginal. As a result, a variety of hydrated limes wereevaluated in the LIMB configuration, demonstratingenhanced performance. Although LIMB performancewas enhanced by applying humidification to the point of
Environmental Control Devices

Exhibit 37

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.

e gas, enhanced sulfur

tely 10% in the LIMB

uration was used.

emperatures, perfor

midification.

nt upon deep humidifi

y and use of hydrated

stream of the furnace.

nhanced by dissolving

um carbonate (Na2CO3

)

LIMB)

 range of Ca/S molar

ns while burning Ohio

 of 1.6, 3.0, and 3.8%

sorbents was injected

fferent coals. Other

metry, humidifier outlet

 the boiler. Exhibit 37

ies for the range of

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 limestonewith essentially all particles less than 10 microns wasused to determine what might be the removal efficiency limit. The removal efficiency for this veryfine limestone was approximately 5–7% higher thanthat obtained at similar conditions for limestone withparticles all sized less than 44 microns.

During the design phase, it was expected that

injection at the 181-foot plant elevation level insidethe boiler would permit the introduction of the limestone at close to the optimum furnace temperature of2,300 oF. Testing confirmed that injection at this level,just above the nose of the boiler, yielded the highest SO2

removal. Injection was also performed at the 187-footlevel and similar removals were observed. Removalefficiencies while injecting at these levels were about 5%higher than while injecting sorbent at the 191-foot level.

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

humidification down to a 20 oF approach-to-saturationtemperature was used. The continued use of the low-NOxburners resulted in an overall average NOx emissions

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

Operational Performance (LIMB)Long-term test data showed that the LIMB system wasavailable about 95% of the time it was called upon tooperate. Even with minimal humidification, ESP performance was adequately enhanced to keep opacity levelswell below the permitted limit. Opacity was generally inthe 2–5% range while the limit was 20%.

Environmental Performance (Coolside)The Coolside process was tested while burning compliance (1.2–1.6% sulfur) and noncompliance (2.8–3.2%sulfur) coals. Objectives of the full-scale test programwere to verify short-term process operability and to develop a design performance database to establish processeconomics for Coolside. Key process variables—Ca/Smolar ratio, Na/Ca molar ratio, and approach-to-adiabatic-saturation—were evaluated in short-term (6–8 hour)parametric tests and longer term (1–11 day) process operability tests.

The test program demonstrated that the Coolside

process routinely achieved 70% SO2 removal at design

conditions of 2.0 Ca/S molar ratio, 0.2 Na/Ca molar ratio,and 20 oF approach-to-adiabatic-saturation temperatureusing commercially available hydrated lime. CoolsideSO2 removal depended on Ca/S molar ratio, Na/Ca molar

ratio, approach-to-adiabatic-saturation, and the physicalproperties of the hydrated lime. Sorbent recycle showedsignificant potential to improve sorbent utilization. Theobserved SO2 removal with recycled sorbent alone was
 Project Fact Sheets 91

Exhibit 38

Cost Comparison

(1992 $/kW)

de LSFO LIMB Coolside LSFO

150-MWe

413 66 116 312421 71 122 316

425 73 127 324

500-MWe

228 31 69 163

235 36 76 169240 40 81 174

Exhibit 39

ized Cost Comparison

Ton of SO2 Removed)

side LSFO LIMB Coolside LSFO

150-MWe

1418 653 797 1098

895 520 624 692665 461 570 527

500-MWe

831 480 589 623539 416 502 411413 392 482 321

molar ratio, 0.5 available recycle,and 18 oF approach-to-adiabaticsaturation.Operational Performance(Coolside)Floor deposits experienced in theductwork with the horizontalhumidification led designers toconsider a vertical unit in a commercial configuration. Short-termtesting did not permit evaluationof Coolside system availability.Economic Performance(LIMB & Coolside)Economic comparisons were made

between LIMB, Coolside, and awet scrubber with limestoneinjection and forced oxidation(LSFO). Assumptions on performance were SO2 removal efficiencies of 60, 70, and 95% for

LIMB, Coolside, and LSFO,respectively. The EPRI TAGTMmethods were used for the economics, which are summarized inExhibits 38 and 39.Commercial ApplicationBoth LIMB and Coolside technologies are applicable to mostutility and industrial coal-firedunits and provide alternatives toconventional wet flue gas desulfurization processes. LIMB andCoolside can be retrofitted with

modest capital investment and downtime, and their spacerequirements are substantially less than for conventionalflue gas desulfurization processes.

LIMB has been sold to an independent power plant

in Canada. Babcock & Wilcox has signed 85 contracts(61 domestic, 24 foreign) for DLB-XCL® low-NOx burners,

representing 1,515 burners for 20,396-MWe of capacity.ContactsPaul Nolan, (330) 860-1074

The Babcock & Wilcox Company20 S. Van Buren AvenueP.O. Box 351Barberton, OH 44203-0351

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, FETC, (412) 892-5991References• 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.

• Public Design Report. Report No. DOE/PC/79798-

T2. The Babcock & Wilcox Company. December1988. (LIMB/Coolside demonstration.) (Availablefrom NTIS as DE92016131.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: LIMB Demonstration ProjectExtension. The Babcock & Wilcox Company. ReportNo. DOE/FE-0085. U.S. Department of Energy. April1987. (Available from NTIS as DE87009793.)

ratio and 18 oF ap

The observed SO2 re

 and fresh sorbent feed

 ratio, 0.2 fresh Na/Ca
Environmental Control Devices

9/95

Technology/Project DescriptionThe SNRBTM process combines the removal of SO2, NOx,

and particulates in one unit—a high-temperaturebaghouse. 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 different arrangements for potential commercial installations could be simulated. The SNRBTM process was operated for approxi- mately 2,300 hours. Through this effort, SNRBTM dem- onstrated the technical and economic feasibility of achieving more than 80% SO2 removal, more than 90% NOx removal, and 99% particulate removal at lower capi- tal, operating, and maintenance costs than those for a combination of conventional systems. The demonstration was conducted at Ohio Edison Company’s R.E. Burger Plant, Unit No. 5, in Dilles Bottom, Ohio.

chnology

TM Flue Gas

ration

 and host

cofunder

—cofunder

SCR catalyst supplier

r bag supplier

tion—cofunder and

OH (Ohio Edison

t No. 5)

s SOx-NOx-Rox BoxTM

m a 156-MWe boiler

ur average

620 100%

402 46

218 54

emoval and 90% or

 while maintaining

b/106 Btu.

SO

x

-NO

x

-Rox Box and SNRB are trademarks of The Babcock & 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

 Project Fact Sheets 93

% 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

of 1.0.

rbents directly upstream

F resulted in higher over

 further upstream at

1990 1991 1992 1993 1994 1995 1996 1997 1998

Design completed 8/91

perative agreement

ded 12/20/89

ocess completed (MTF) 9/22/89

Ground breaking/construction started 5/9/91

5/92

Design and Construction Operation

Preoperational tests initiated 11/91

• NO

x

 reduction of 90% was achieved with an NH3/NOx

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

• Air toxic removal efficiency was comparable to that of

an electrostatic precipitator (ESP), except that hydrogen fluoride (HF) was reduced by 84% and hydrogenchloride (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 thedemonstration.

• No excessive wear or failures occurred with the filter

bags tested: 3M’s Nextel ceramic fiber filter bag andOwens Corning Fiberglas’s 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

Economic• Capital cost in 1994 constant dollars for a 250-MWe

retrofit was $233/kW, assuming 3.5% sulfur coal andbaseline NO

x

 emissions of 1.2 lb/106 Btu.

9/95
Environmental Control Devices

The demonstration baghouse is installed on the back

side of the power plant. Workers stand by the catalyst holdertube prior to lifting it into the penthouse.

ful technology devel

dvantages over other

rature filter bags and

ments enabled multiple

onent with a low plan

combustion control

e high-temperature bag

 environment compat

and a surface for en

es a sorbent cake on the

h is receiving increas

rior performance of

d for SO2 capture. Cal

mercial grade hydrated

nosulfonate-hydrated

nate was tested. The

orbent into the flue gas

baghouse. Essentially,

nt in the form of a filter

 fly ash).

above 830 oF, injection

e at Ca/S molar ratios

emovals of over 80%.

rmance of the sugar

hydrated lime increased

, for overall removal of

 of 85–90% was ob

he of 40–45%. Injec

 directly upstream of

ed in higher overall SO2

ream at temperatures

carbonate was 80% at

% at an Na2/S molar

ed baghouse temperature of 450–460 oF. SO2 emissions while burning a 3–4% sulfur coal were reduced to less than 1.2 lb/106 Btu with a Ca/S molar ratio as low as 1.5 and Na2/S molar ratio less than 1.0. To capture NOx, ammonia was injected between the sorbent injection point and the baghouse. The ammonia and NOx reacted to form nitrogen and water in the pres- ence of Norton Company’s NC-300 series zeolite SCR catalyst. With the catalyst being located inside the filter bags, it was well protected from potential particulate erosion or fouling. The sorbent reaction products, unreacted lime, and fly ash were collected on the filter bags and thus removed from the flue gas. A NOx emission reduction of 90% was readily achieved with ammonia slip limited to less than 5 ppm. This performance reduced NOx emissions to less than 0.10 lb/106 Btu. NOx reduction was insensitive to tem- peratures over the catalyst design temperature range of 700–900 oF. Catalyst space velocity (volumetric gas flow/ catalyst volume) had a minimal effect on NOx removal over the range evaluated. Turndown capability for tailoring the degree of NOx reduction by varying the rate of ammonia injection was demonstrated for a range of 50–95% NOx reduction. No appreciable physical degradation or change in the catalyst activity was observed over the duration of the test pro- gram. The degree of oxidation of SO2 to SO3 over the zeolite catalyst appeared to be less than 0.5%. (SO2 oxi- dation is a concern for SCR catalysts containing vana- dium.) Leach potential analysis of the catalyst after completion of the field test showed that the catalyst re- mained nonhazardous for disposal. Particulate emissions were consistently below NSPS standards of 0.03 lb/106 Btu, with an average over 30 baghouse particulate emission measurements of 0.018 lb/ 106 Btu, which corresponds to a collective 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
 Project Fact Sheets 95

Workers lower one of the catalyst holder tubes into a

mounting plate in the penthouse of the high-temperaturebaghouse.

n the CAAA. Measure

xins, and furans were

am. The emissions con

ous air toxics by the

comparable to those of

er plant. However, the

by an average of 95%

of 84%, whereas the

ituents.

emonstration resulted in

830 tons of fly ash and

n of potential uses for the

rial might be used for

. Also, the solids poten

ement replacement to

hree fabric filters was

velopment Test Facility

r 1992. No signs of

e demonstration tests

mpany Nextel ceramic

rning Fiberglas S-Glass

r failures occurred in

perature operation.

 3.5% sulfur coal and

 the projected capital

oximately $233/kW

ology and project contin

 fabric filter, SCR, and

arable emissions control

kW. Variable operating

of the SO2 sorbent for a

2 removal. Fixed operat

tem operating labor and

he hot baghouse and

Commercial ApplicationsCommercialization of the technology is expected to develop with an initial larger scale application equivalent to50–100-MWe. The focus of marketing efforts is beingtailored to match the specific needs of potential industrial,utility, and independent power producers for both retrofitand new plant construction. SNRBTM is a flexible technology that can be tailored to maximize control of SO2,

NO

x, or combined emissions to meet current performance

requirements while providing flexibility to addressfuture needs.ContactsDot K. Johnson, (330) 829-7395

The Babcock & Wilcox Company20 South Van Buren AvenueBarberton, OH 44203(330) 829-7801 (fax)dot.k.johnson@mcdermott.com

Lawrence Saroff, DOE/HQ, (301) 903-9483James U. Watts, FETC, (412) 892-5991References• SO

x

-NO

x

-Rox BoxTM Flue Gas Cleanup Demonstration

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

• 5 MWe SNRBTM Demonstration Facility: Detailed

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

• Comprehensive Report to Congress on the Clean Coal

Technology Program: SOx-NOx-Rox BoxTM Flue Gas

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

chnology

e of Coals by

d Sorbent

ch Corporation

mmerce & Community

t

nois Power Company’s

 (City Water, Light and

 No. 7)

ch Corporation’s gas

R–SI) process

We (gross), 71-MWe

gross), 33-MWe (net)

955 100%

816 50

139 50

Project ObjectiveTo demonstrate gas reburning to attain at least 60% NOx

reduction along with sorbent injection to capture at least50% of the SO2 on two different boiler configurations—

tangentially-fired and cyclone-fired—while burning highsulfur midwestern coal.Technology/Project DescriptionIn this process, 80–85% of the fuel was coal and wassupplied to the main combustion zone. The remaining15–20% of the fuel, provided by natural gas, bypassed themain combustion zone and was injected above the mainburners to form a reducing (reburning) zone in whichNO

x was converted to nitrogen. A calcium compound

(sorbent) was injected in the form of dry, fine particulatesabove the reburning zone in the boiler. Lime (Ca(OH)2)

was the sorbent tested at both sites. This project demonstrated the GR–SI process on two separate boilers repre- senting two different firing configurations—a tangen- tially-fired, 80-MWe (gross) boiler at Illinois Power Company’s Hennepin Plant in Hennepin, IL, and a cy- clone-fired, 40-MWe (gross) boiler at City Water, Light and Power’s Lakeside Station in Springfield, IL. Illinois bituminous coal containing 3% sulfur was the test coal for both Hennepin and Lakeside. A comprehensive test program was conducted at each of the two sites, operating the equipment over a wide range of boiler conditions. Over 1,500 hours of operation was achieved, enabling a substantial amount of data to be obtained. Intensive measurements were taken to quantify the reductions in NOx and SO2 emissions, the impact on boiler equipment and operability, and all fac- 

Environmental Research tors influencing costs. 
2 3 4 1 2 3 4 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 97

er, GR–SI NOx reduc

ved, and an average 67%

verage gas heat input of

y on the tangentially

h hydrated lime at a

ar ratio of 1.75 (corre

on of 24%).

GR–SI NOx reductions of

d an average 66% reduc

e gas heat input of 22%.

y on the cyclone-fired

drated lime at a Ca/S

ding to a sorbent utiliza

• Particulate emissions were not a problem on either

unit undergoing demonstration, but humidificationhad to be introduced at Hennepin to enhance ESPperformance.

• Three advanced sorbents tested achieved higher SO2

capture efficiencies than the baseline Linwood hydrated lime. PromiSORBTM A achieved 53% SO2capture efficiency and 31% utilization without GR ata Ca/S molar ratio of 1.75. Under the same conditions, PromiSORBTM B achieved 66% SO2 reductionand 38% utilization, and High-Surface-Area HydratedLime achieved 60% SO2 reduction and 34%

utilization.

Operational• Boiler efficiency decreased by approximately 1% as a

result of increased moisture formed in combustionfrom natural gas use.

• There was no change in boiler tube wastage, tube

metallurgy, or projected boiler life.

Design and Construction

1988 1989 1990 1991 1992 1993 1994 1995 1998

1/91

Operation initiated,Lakeside 5/93

Operation completed,Hennepin 1/93

Construction completed, Hennepin 8/91

Operation initiated, Hennepin 1/91

Construction started, Lakeside 6/90

Environmental monitoring plan completed,Lakeside 11/15/89

nvironmental monitoring plan

mpleted, Hennepin 10/15/89

akeside (EA) 6/25/89

mpleted, both sites 5/89

started, Hennepin 5/89

NEPAprocesscompleted,Hennepin(MTF) 5/9/88

Construction completed, Lakeside 5/92

Restoration completed,Hennepin 12/93

9/98

Project completed/

final report issued 9/98

Operation completed,Lakeside 10/94

Operation

Restoration completed,

Lakeside 12/95

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

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

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

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

reduces SO2 emissions).

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

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

**

3 4
Environmental Control Devices

The flexible lime-sorbent distribution lines lead from

the sorbent splitter to the top of the cyclone-fired boiler atLakeside Station.

he success of gas

chnologies in reducing

ess design conducted

 the vast amount of

eated a database ca

o all major coal-firing

e-, and wall-fired) on

he emissions control

y projected as can the

Hennepin)

d optimization testing

ted between January

SI long-term demon

m January 1992 to Octo

ormance over an ex

ated at constant loads

h operation where load

tput requirements.

e load fluctuated over a

ximum load of 75-

stration period, the

2-MWe.

testing, the average

67%. The average SO2

at a Ca/S molar ratio of

s used throughout these

Marblehead lime was

50 ppm in most cases

t low load.

2 was also realized.

nt of coal with natural

ogen ratio. This

lted in a theoretical

 8% from the coal-fired

dification, electrostatic

encies greater than

99.8% and particulate emissions less than 0.025 lb/106

Btu were measured even with an increase in inlet particulate loading resulting from sorbent injection. These levels were comparable to measured baseline emissions of0.035 lb/106 Btu and a collection efficiency greater

than 99.5%.

Following the completion of the long-term tests,

three specially prepared sorbents were tested. Two weremanufactured by the participant and contained proprietaryadditives to increase their reactivity toward SO2 and were

referred to as PromiSORBTM A and B. The Illinois StateGeological Survey developed the other sorbent—HighSurface-Area Hydrated Lime in which alcohol is used toform a material that gives rise to a much higher surfacearea than that of conventionally hydrated limes.

The SO2 capture without GR, at a nominal 1.75 Ca/S

molar ratio, was 53% for PromiSORBTMA, 66% for

PromiSORBTM B, 60% for High-Surface-Area HydratedLime, and 42% for Linwood lime. At a 2.6 Ca/S molarratio, the PromiSORBTM B yielded 81% SO2 removal

efficiency.Environmental Performance (Lakeside)Parametric tests were conducted in three series: GRparametric tests, SI parametric tests, and GR–SI optimization tests. A total of 100 GR parametric tests were conducted at boiler loads of 33-, 25-, and 20-MWe. Gas heatinput varied from 5-26%. The GR parametric testsachieved a NOx reduction of approximately 60% at a gas

heat input of 22–23%. Additional flow modeling andcomputer modeling studies indicated that smaller reburning fuel jet nozzles could increase reburning fuel mixingand thus improve the NOx reduction performance.

A total of 25 SI parametric tests were conducted to

isolate the effects of sorbent on boiler performance andoperability. Results showed that SO2 reduction level

varied with load because of the effect of temperature onthe sulfation reaction. At a Ca/S molar ratio of 2.0, 44%SO2 reduction was achieved at full load (33-MWe); 38%

SO2 reduction was achieved at mid load (25-MWe); 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

reburning fuel injection nozzles based on the results ofthe initial GR parametric tests and flow modeling studies.The total cross-sectional area of the reburning jets wasdecreased by 32% to increase the reburning jet’s penetration characteristics. The decrease in nozzle diameterincreased NOx reduction by an additional 3–5% compared

to the initial parametric tests. With GR–SI, total SO2

reductions resulted from partial replacement of coal with
 Project Fact Sheets 99

The natural gas injector was installed

on the corner of Hennepin Station’stangentially-fired boiler.

Ca/S

he

on

r

y

n

he

modated the changes in

he presence of sorbent in

were found to exist. But

d to be added at

ESP performance with

nnepin/Lakeside)

nd largely on site-spe

lity at the site, coal/gas

quirements, and value of

d that for most installa

chieve 60% NOx reduc

GR installation was

We and larger plants plus

quired) (1996$). Operating costs were almost entirely related to the differential cost of the gas over the coal as reduced by the value of SO2 emission allow- ances.The capital cost estimate for SI was $50/kW. Operating costs for SI were dominated by the cost of the sorbent and sorbent/ash dis- posal costs. SI was projected to be cost competitive at $300/ton of SO2 removed. Commercial Applications The GR–SI process is a unique combination of two separate tech- nologies. The commercial applica- tions for these technologies, both separately and combined, extend to both utility companies and industry in the United States and abroad. In the United States alone, these two technologies can be applied to more than 900 pre-NSPS utility boilers; the technologies also can be applied to new 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 plant and 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 full tech- nology for commercial use. The project was one of two receiving the Air and Waste Management Association’s 1997 J. Deanne Sensenbaugh Award. Contacts Blair A. Folsom, Sr. V.P., (949) 859-8851, ext. 140 Energy and Environmental Research Corporation 18 Mason Irvine, CA 92618 Lawrence Saroff, DOE/HQ, (301) 903-9483 Jerry L. Hebb, FETC, (412) 892-6079 References

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 1–Program Overview.February 1997.

• Enhancing the Use of Coals by Gas Reburning–Sorbent Injection: Volume 4: Gas Reburning Sorbent

Injection at Lakeside Unit 7, City Water, Light andPower, Springfield, Illinois. Final Report. Energy andEnvironmental Research Corporation. March 1996.Report No. DOE/PC/79796-T48-Vol.4. (Availablefrom NTIS as DE96011869.

• Enhancing the Use of Coals by Gas Reburning–

Sorbent Injection; Long Term Testing Period, September 1, 1991–January 15, 1993. Report No. DOE/PC/79796-T40. Energy and Environmental ResearchCorporation. February 1995. (Available from NTIS asDE95011481.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 2: Gas Reburning–SorbentInjection at Hennepin Unit 1, Illinois Power Company.Report No. DOE/PC/79796-T38-Vol. 2. Energy andEnvironmental Research Corporation. October 1994.(Available from NTIS as DE95009448.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 3: Gas Reburning–SorbentInjection at Edwards Unit 1, Central Illinois LightCompany. Report No. DOE/PC/79796-T38-Vol. 3.Energy and Environmental Research Corporation.October 1994. (Available from NTIS asDE95009447.)
Environmental Control Devices

chnology

x/SO2

 System

ado

—cofunder

orp.—engineer

—burner developer

on—operational 

h evaluator

h-scale engineering

em provider

ic Service Company of

t No. 4)

s DRB-XCL® low-NOx

and furnace (urea)

st), 0.35% sulfur

462 100%

731 50

731 50

Project ObjectiveTo demonstrate the integration of five technologies toachieve up to 70% reduction in NOx and SO2 emissions;

more specifically, to assess the integration of a downfired low-NO

x burner with in-furnace urea injection for

additional NO

x removal and dry sorbent in-duct injection

with humidification for SO2 removal.

Technology/Project DescriptionAll of the testing used Babcock & Wilcox’s low-NOx

DRB-XCL® down-fired burners with overfire air. These

burners control NO

x by injecting the coal and the combustion air in an oxygen-deficient environment. Additional air was introduced via overfire air ports to complete

the combustion process and further enhance NOx removal. A urea-based selective noncatalytic reduction

 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 gas

flow before entering the fabric filter dust collector.

The systems were installed on Public Service Company of Colorado’s Arapahoe Station Unit No. 4, a

100-MWe down-fired, pulverized-coal boiler with roofmounted burners.
2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

*Projected date

** Years omitted

3 4

 Project Fact Sheets 101

1990 1991 1992 1993 1994 1995 1996 1997 1999

Preaward Operation Design and 8/92 Construction 

3/91

) 9/27/90

 6/90

Ground breaking/construction started 5/21/91

Design completed 3/92

Preoperational tests initiated 6/92

Operation initiated 8/92Construction completed 8/92

Environmentalmonitoring plancompleted8/5/93

imum overfire air re

e than 63% under steady

24% of total combustion

9% was achieved across

eased by 10–25% under

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

duct, SO2 removal was less than 40% at a calcium/

sulfur (Ca/S) molar ratio of 2.0.

• Sodium bicarbonate injection before the air heater

demonstrated a long-term SO2 removal of approximately 70% at a normalized stoichiometric ratio

(NSR) of 1.0.

• Sodium sesquicarbonate injection ahead of the fabric

filter achieved 70% SO2 removal at an NSR of 2.0.

• NO2 emissions were generally higher when using

sodium biocarbonate 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%.

9/99

Operation completed 12/96

Cooperative agreement awarded 3/11/91

Project completed/

final report issued

9/99*

• Control system modifications and additional operator

training may be necessary to improve NOx controlunder load-following conditions.

• Buildup of a hard ash cake on the fabric filter occurred

during operation with injection of calcium hydroxideand use of humidification.

• Temperature differential between the top and bottom

surfaces of the Advanced Retractable Injection Lances(ARIL) caused the lances to bend downwards12–18 inches. Alternative designs corrected theproblem.

• Concurrent operation of SNCR and the dry sodiumbased sorbent injection system caused an NH3 odor

problem around the ash silo, which appeared to berelated to the rapid change in pH due to the sodium inthe ash.

Economic• Economic data is not yet available.

**
Environmental Control Devices

sootblower ports. Each lance was nominally 4 inches indiameter and approximately 20 feet in length with asingle row of nine injection nozzles. Each injectionnozzle consisted of a fixed air orifice and a replaceableliquid orifice. The ability to change orifices allowed notonly for removal and cleaning but adjustment of theinjection pattern along the length of the lance in order tocompensate for any significant maldistributions of fluegas velocity, temperature, or baseline NOx concentration.

One of the key features of the ARIL system was its abilityto rotate, thus providing a high degree of flexibility inoptimizing SNCR performance.

The SO2 control system was a direct sorbent injection system that could inject either calcium- or sodiumbased reagents into the flue gas upstream of the fabric

filter. Sorbent was injected into three locations: (1) airheater exit where the temperature was approximately260 oF, (2) air heater entrance where the temperature wasapproximately 600 oF, or (3) the boiler economizer regionwhere the flue gas temperature was approximately1,000 oF. To improve SO2 removal with calcium hydroxide, a humidification system capable of achieving 20 oF

approach-to-saturation was installed approximately 100feet ahead of the fabric filter. The system designed by

Babcock & Wilcox included 84 I-Jet nozzles that caninject up to 80 gal/min into the flue gas duct work.Environmental PerformanceThe combined DRB-XCL® burner and minimum overfire

air reduced NOx emissions by over 63% under steadystate conditions and with carefully supervised operations.

Under load-following conditions, NOx emissions were

about 10–25% higher. At maximum overfire air (4% oftotal combustion air), the low-NOx combustion system

reduced NOx emissions by 62–69% across the load range

(60–110-MWe). The results verified that the low-NOx

burners were responsible for most of the NOx reduction.

The original design of two rows of injector nozzles

proved relatively ineffective because one row of injectorswas in a region where the flue gas temperature was toolow for effective operation. At full load, the original

design achieved NOx reduction of 45%. However, the

performance decreased significantly as load decreased; at60-MWe, NOx removal was limited to about 11% with an

ammonia slip of 10 ppm. The addition of the retractablelances improved low-load performance of the urea-basedSNCR injection system. The ability to follow the temperature window by rotating the ARIL lances proved tobe an important feature in optimizing performance. Asa result, the SNCR system achieved NOx removal in therange of 30–50%, (at a NH3 slip limited to 10 ppm at the

fabric filter inlet), increasing total NOx reduction to

greater than 80%, significantly exceeding the goalof 70%.

Testing of calcium hydroxide injection at the economizer without humidification resulted in SO2 removal in

the range of 5–8% at a Ca/S molar ratio of 2.0. HigherSO2 removal was achieved with duct injection of calcium

hydroxide and humidification, with SO2 removals approaching 40% at a Ca/S molar ratio of 2.0 and within

20–30 oF approach-to-saturation. Sodium-based reagentswere found to be much more effective than calcium-basedsorbents and achieved significantly higher SO2 removals

during dry injection. Sodium bicarbonate injection be

sions Control System 

ologies to form an 

NOx and SO2. The low- 

f 12 Babcock & Wil- 

installed on the boiler 

stem also incorporates 

e NOx ports added to 

ately 20 feet below the 

to 25% of the total 

e sidewalls. 

chieved with the urea- 

when used with the 

wed the goal of 

 Further, the SNCR 

e integrated system, 

 dry sorbent injection 

tion and 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 Public Service Company of Colorado demonstrated low-NOx burners, in-duct sorbent injection, and SNCR at Arapahoe Station near Denver.
 Project Fact Sheets 103

short-time SO2 removals

f 70% were achieved

quicarbonate achieved

when injected ahead of

of the sodium-based

me existing NO to NO2

.

was reduced during the

exiting at the stack was

s, small quantities of

ble plume.

emonstration of the

Ox emissions control

hnologies. The results

 occurred during the

NCR and the sodium DSI

the SNCR process sup

iated with NO to NO2

n.

were completed. Results

cessfully removed nearly

rly 80% of the mercury

volatile organic com

below or very near their

ed more than 34,000

fications in place. The

od was over 91%.

ves were met or ex

erational lessons learned

ll be useful in future

These “lessons learned”

tem modifications and

be necessary to more

s using low-NOx burners

duct injection of calcium

der load-following conditions, fabric filter pressure-drop significantly increased. This was caused by the buildup of a hard ash cake on the fabric filter bags that could not be cleaned under normal reverse-air cleaning. The heavy ash cake was caused by the humidification system, but it was not determined whether the problem was due to operation at 30 oF ap- proach-to-saturation temperature or an excursion caused by a rapid decrease in load. The performance of the ARIL lances in NOx removal was good; however, the location created some operational problems. A large differential heating pattern between the top and bottom of the lance caused a significant amount of thermal expansion along the upper surface of the lance. This caused the lance to bend downwards approximately 12–18 inches after 30 minutes of exposure. Eventually the lances become permanently bent, thus making insertion and retraction difficult. The problem was partially resolved by adding cooling slots at the end of the lance. An alternative lance design provided by Diamond Power Specialty Company (a division of Bab- cock & Wilcox) was tested and found to have less bend- ing due to evaporative cooling, even though its NOx reduction and NH3 slip performance were slightly less than for the ARIL lance. When the SNCR and dry sodium systems were oper- ated 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 concentration in the fly ash to the 100–200 ppm range but the odor persisted. It was found that the problem was related to the rapid change in pH due to the presence of sodium in the ash. The rapid development of the high pH level and the attendant release of the ammonia vapor appear to be related to the wetting of the fly ash necessary to minimize fugitive dust emissions during transportation and han- dling. Handling ash in dry transport trucks solved this problem. Economic Performance Economic analysis is under way. Commercial Applications Either the entire Integrated Dry NOx/SO2 Emissions Con- trol System or the individual technologies are applicable to most utility and industrial coal-fired units and provide lower capital-cost alternatives to conventional wet flue gas desulfurization processes. They can be retrofitted with modest capital investment and downtime, and their space requirements are substantially less. They can be applied to any unit size but are mostly applicable to the older, small- to mid-size units. Contacts Terry Hunt, Project Manager, (303) 571-7113 Utility Engineering 550 15th Street, Suite 800 Denver, CO 80202 Lawrence Saroff, DOE/HQ, (301) 903-9483 Jerry L. Hebb, FETC, (412) 892-6079 References

• Hunt, Terry, et al. “Integrated Dry NOx/SO2 Emissions

Control System: Performance Summary.” FifthAnnual Clean Coal Technology Conference: Technical Papers. January 1997.

• Integrated Dry NOx/SO2 Emissions Control System

Calcium-Based Dry Sorbent Injection: Test Report,April 30–November 2, 1993. Report No. DOE/PC/90550-T14. Fossil Energy Research Corporation andPublic Service Company of Colorado. December1994. (Available from NTIS as DE95007932.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Integrated Dry NOx/SO2 Emission Control System. Public Service Company of

Colorado. Report No. DOE/FE-0212P. U.S. Department of Energy. January 1991. (Available from NTISas DE91008624.)
Advanced Electric Power Generation Project Fact Sheets 105

Advanced Electric Power Generation

Fluidized-Bed Combustion
106 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB

Demonstration Project

Participant

City of Lakeland, Lakeland Electric

Additional Team Members

Foster Wheeler Corporation—supplier of pressurized

circulating fluidized-bed (PCFB) combustor and heat

exchanger and engineer

Siemens Westinghouse Power Corporation—supplier of

hot gas filter, gas turbine, and steam turbine

Location

Lakeland, Polk County, FL (Lakeland Electric’s McIntosh

Power Station, Unit No. 4)

Technology

Foster Wheeler’s PCFB technology integrated with

Siemens Westinghouse’s hot gas particulate filter system

(HGPFS) and power generation technologies

Plant Capacity/Production

137-MWe (net)

Coal

Eastern Kentucky and high ash, high sulfur bituminous

coals

Project Funding

Total project cost $186,588,000 100%

DOE 93,252,864 50

Participant 93,335,136 50

Project Objective

To demonstrate Foster Wheeler’s PCFB technology

coupled with Siemens Westinghouse’s ceramic candle

type HGPFS and power generation technologies, which

represent a cost-effective, high-efficiency, low-emissions

means of adding generating capacity at greenfield sites or

in repowering applications.

Technology/Project Description

The project resulted from a restructuring of the DMEC-1

PCFB Demonstration Project awarded under the third

solicitation. In the first of the two Lakeland Electric

projects, McIntosh Unit No. 4A is being constructed with

a PCFB combustor adjacent to the existing Unit No. 3

(see also McIntosh Unit 4B Topped PCFB Demonstration

Project).

Coal and limestone are mixed and fed into the combustion chamber. Combustion takes place at a temperature of approximately 1,560–1,600 °F and a pressure of

about 200 psig. The resulting flue gas and fly ash leaving

the combustor pass through a cyclone and ceramic candle

type HGPFS where the particulates are removed. The hot

gas leaving the HGPFS is expanded through a Siemens

V64.3 gas turbine. The gas inlet temperature of less than

1,650 °F allows for a simplified turbine shaft and bladecooling system. The hot gas leaving the gas turbine

passes through a heat recovery steam generator (HRSG).

Heat recovered from both the combustor and HRSG is

used to generate steam to power a reheat steam turbine.

Approximately 5–10% of the gross power is derived from

the gas turbine, with the steam turbine contributing

the balance.

The project also includes an atmospheric fluidizedbed unit that can be fired on coal or char from the

carbonizer and will replace the PCFB unit during times of

PCFB unavailability, allowing various modes of

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

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Project Fact Sheets 107

Project Status/Accomplishments

On December 19, 1997, a Cooperative Agreement modification was signed implementing the project restructuring from DMEC-1 to the City of Lakeland. The Lakeland

City Council gave approval for the 10 year plan of Lakeland Electric (formerly Department of Electric & Water

Utilities), which included this project, in April 1998. The

project schedule anticipates the start of commercial operation of the PCFB (McIntosh 4A) in 2003. In parallel

with the first two years of operation of the PCFB, the

design, fabrication, and construction of the topped PCFB

technology (McIntosh 4B) will occur, with a planned start

of operation in 2005.

Negotiations continue between Lakeland and Foster

Wheeler on the Engineer-Procure-Construct (EPC) proposal for the technology island.

 Recent efforts focused on testing of the HGPFS,

which is critical to system performance. Silicon carbide

candle filters proved effective under conditions simulating those of the demonstration unit. At both 1,550 oF and

1,400 oF, the candle filters performed for over 1,000

hours at design levels without evidence of ash bridging

or structural failure. Three new oxide-based candle

filters showed promise as well and will undergo further

testing because of the potential for reduced cost and

operation at higher temperatures.

Commercial Applications

The project serves to demonstrate the PCFB technology

to readiness for widespread commercial deployment in

post-2000. The project 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 high-sulfur

coals, and would compete with the pressurized bubblingbed fluidized-bed system. PCFB can be used to repower

or replace conventional power plants. Because of modular construction capability, PCFB generating plants permit utilities to add economical increments of capacity to

1991 2000 2001 1996 1997 2002 2003 2004 2005 2006 2007

12/89

DOE selected project

(CCT-III) 12/19/89

Cooperative Agreement

awarded 8/1/91

7/03 7/05

**

**Years omitted

Design and Construction Operation

Design completed 9/00*

NEPA process completed (EIS)

10/00*

Environmental monitoring

plan completed 4/03*

8/91

Operation initiated 7/03*

Preoperational tests initiated 7/03*

Construction completed 7/03* Project completed/

final report issued 7/05*

Operation completed 7/05*

Site change approved

(Lakeland) 10/29/96

Preaward

match load growth or to repower plants using existing

coal- and waste-handling equipment and steam turbines.

Another advantage for repowering applications is the

compactness of the process due to pressurized operation,

which reduces space requirements per unit of energy

generated.

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 is

readily disposable or potentially usable.

Cooperative Agreement

signed 12/19/97

**

Groundbreaking/

construction

started 7/01*
108 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4B Topped PCFB

Demonstration Project

Participant

City of Lakeland, Lakeland Electric

Additional Team Members

Foster Wheeler Corporation—supplier of carbonizer;

engineer

Siemens Westinghouse Power Corporation—supplier of

topping combustor and high-temperature filter

Location

Lakeland, Polk County, FL (Lakeland Electric’s McIntosh

Power Station, Unit No. 4)

Technology

Fully integrated second-generation PCFB technology with

the addition of a carbonizer island that includes Siemens

Westinghouse’s multi-annular swirl-burner (MASB)

topping combustor

Plant Capacity/Production

103-MWe (net) addition to the 137-MWe (net) McIntosh

4A project

Coal

Eastern Kentucky and high ash, high sulfur bituminous

coals

Project Funding

Total project cost $219,635,546 100%

DOE 109,608,507 50

Participant 110,027,039 50

Project Objective

To demonstrate topped PCFB technology in a fully commercial power generation setting, thereby advancing the

technology for future plants that will operate at higher gas

turbine inlet temperatures and are expected to achieve

cycle efficiencies in excess of 45%.

Technology/Project Description

The project resulted from a restructuring of the Four

Rivers Energy Modernization Project awarded under the

fifth solicitation. The Four Rivers project was to demonstrate the integration of a carbonizer (gasifier) and topping combustor (topping cycle) with the PCFB technology. By using a phased approach, Lakeland Electric will

be able to demonstrate both PCFB (McIntosh 4A) and

topped PCFB (McIntosh 4B) technologies at one

plant site.

The project involves the addition of a carbonizer

island to the PCFB demonstrated in the McIntosh 4A

project. Dried coal and limestone are fed via a lock hopper system to the carbonizer with part of the gas turbine

discharge air. The coal is partially gasified at about

1,750–1,800 °F to produce syngas and char solids

streams. The limestone is used to absorb sulfur compounds generated during the mild gasification process.

After cooling the syngas to about 1,200 °F, the char and

limestone entrained with the syngas are removed by a hot

gas particulate filter system (HGPFS). The char and

limestone are then transferred to the PCFB combustor for

complete carbon combustion and limestone utilization.

The hot, cleaned, filtered syngas is then fired in the

MASB 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

generator, 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.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

**Years omitted

Advanced Electric Power Generation Project Fact Sheets 109

1996 1998

on the Engineer-Procure-Construct (EPC) proposal for the

technology island.

 Recent efforts focused on testing of the HGPFS,

which is critical to system performance. Silicon carbide

and alumina/mullite candle filters proved effective under

conditions simulating those of the demonstration unit. At

both 1,550 oF and 1,400 oF, the candle filters performed

for over 1,000 hours at design levels without evidence of

ash bridging or structural failure. Three new oxide-based

candle filters showed promise as well. These will undergo

further testing because of the potential for reduced cost and

operation at higher temperatures.

Commercial Applications

The commercial version of the topped PCFB technology

will have a greenfield net plant efficiency of 45% (which

equates to a heat rate approaching 7,500 Btu/kWh,

HHV). In addition to higher plant efficiencies, the plant

will (1) have a cost of electricity that is projected to be

20% lower than that of a conventional pulverized-coalfired plant with flue gas desulfurization, (2) meet emis1994 2000 2001 2003 2004 2005 2006 2007 2008

5/93

DOE selected project

(CCT-V) 5/4/93

Cooperative agreement

awarded 7/28/94; effective

8/1/94

Design and Construction

7/05 7/07

Project completed/

final report issued 7/07*

Site change approved Operation completed 7/07*

(Lakeland) 10/29/96

**

Operation

NEPA process

completed (EIS) 10/00*

Design initiated 7/03*

Groundbreaking/construction started 5/04*

Design completed 5/04*

Operation initiated 7/05*

Preoperational tests initiated 7/05*

Construction completed 7/05*

Environmental monitoring plan completed 4/05*

8/94

Preaward

The 240-MWe (net) plant is expected to have a heat

rate of 8,776 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 turbine will produce 207-MWe, while plant auxiliaries will

consume about 25 MWe.

Project Status/Accomplishments

On January 29, 1998, a Cooperative Agreement modification was signed implementing the project restructuring

from Four Rivers Energy Partners to the City of Lakeland.

The Lakeland City Council gave approval for the 10 year

plan of Lakeland Electric (formerly Department of Electric & Water Utilities), which included this project, in

April 1998. In parallel with the first two years of operation of the PCFB (McIntosh 4A), the design, fabrication,

and construction of the topped PCFB technology will take

place. Start of operation is planned for late 2005. Negotiations continue between Lakeland and Foster Wheeler

**

Cooperative Agreement signed

1/29/98

sion limits that are half those allowed by New Source

Performance Standard (NSPS), (3) operate economically

on a wide range of coals, and (4) be amenable to shop

fabrication. The benefits of improved efficiency include

reduced cost for fuels and a reduction in CO2

 emissions.

The commercial version of the topped PCFB technology has other environmental attributes, which include

in-situ sulfur retention that can meet 95% removal, NOx

emission that will be lower than 0.3 lb/106 Btu, and particulate matter discharge of approximately 0.03 lb/106

Btu. Although the system will generate a slight increase

in solid waste as compared to conventional systems, the

material is a dry, readily disposable, and potentially usable material.

** **
110 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

JEA Large-Scale CFB

Combustion Demonstration

Project

Participant

JEA (formerly Jacksonville Electric Authority)

Additional Team Member

Foster Wheeler Energy Corporation—co-owner and technology supplier

Location

Jacksonville, Duval County, FL (JEA’s Northside Station,

Unit No. 2)

Technology

Foster Wheeler’s atmospheric circulating fluidized-bed

(ACFB) combustor

Plant Capacity/Production

297.5-MWe (gross), 265-MWe (net)

Coal

Eastern bituminous, 0.7% sulfur (design)

Project Funding

Total project cost $309,096,512 100%

DOE 74,733,633 24

Participant 234,362,679 76

Project Objective

To demonstrate ACFB at 297.5-MWe gross (265-MWe

net) representing a scale-up from previously constructed

facilities; to verify expectations of the technology’s economic, environmental, and technical performance to

provide potential users with the data necessary for evaluating a large-scale ACFB as a commercial alternative; to

accomplish greater than 90% SO2

 removal; and to reduce

NOx

 emissions by 60% when compared with conventional technology.

through the use of a polishing scrubber to be installed

ahead of the particulate control equipment.

Steam is generated in tubes placed along the

combustor’s walls and superheated in tube bundles

placed downstream of the particulate separator to protect

against erosion. The system will produce approximately

2 x106

 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 existing

297.5-MWe (nameplate) steam turbine. The heat rate for

the retrofit plant is expected to be approximately 9,950

Btu/kWh (34% efficiency; HHV).

Technology/Project Description

A circulating fluidized-bed combustor, operating at atmospheric pressure, will be retrofitted into Unit No. 2 of

the Northside Station. Coal or the secondary fuel (petroleum coke), primary air, and a solid sorbent (such as

limestone), are introduced into the lower part of the

combustor where initial combustion occurs. As the coal

particles decrease in size due to combustion, they are

carried higher in the combustor when secondary air is

introduced. As the coal particles continue to be reduced

in 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 the

bed. However, additional SO2

 capture is achieved
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

**Years omitted

Advanced Electric Power Generation Project Fact Sheets 111

Preoperational tests started 7/01*

Environmental monitoring plan

completed 7/01*

Project Status/Accomplishments

The project was successfully resited to Jacksonville,

Florida after York County Energy partners and Metropolitan Edison Company terminated activities on the ACFB

in September 1996. On August 26, 1997, DOE approved

the transfer of the ACFB clean coal project from York,

Pennsylvania, to Jacksonville. On September 29, 1997,

DOE signed a modified cooperative agreement with JEA

to cost-share refurbishment of the first (Unit No. 2) of

two units at Northside Generating Station.

A Public Scoping Meeting on the Environmental

Impact Statement (EIS) was held on December 3, 1997 at

the Northside Station. The draft EIS is being prepared

and was submitted for review in March 1999.

The project, currently in design, moves atmospheric

fluidized-bed combustion technology to the larger sizes of

utility boilers typically considered in capacity additions

and replacements. The nominal 300-MWe demonstration

unit in the JEA project will be more than double the size

of the Nucla unit (110-MWe). Features include an integrated recycle heat exchanger (INTREXTM) in the furnace, steam-cooled cyclones, a parallel pass reheat control, an SO2

 polishing scrubber, and a fabric filter for

particulate control. Expected environmental performance

is 0.17 lb/106

 Btu for SO2 (98% reduction), 0.11 lb/106

Btu for NOx, and 0.017 lb/106 Btu for total particulates

(0.013 lb/106

 Btu for PM10).

Commercial Applications

ACFB technology has good potential for application in

both the industrial and utility sectors, whether for use in

repowering existing plants or in new facilities. ACFB is

attractive for both baseload and dispatchable power

applications because it can be efficiently turned down to

25% of full load. Coal of any sulfur or ash content can

be used, and any type or size of a unit can be repowered.

In repowering applications, an existing plant area is used,

and coal- and waste-handling equipment as well as steam

turbine equipment are retained, thereby extending the life

of a plant.

1989 1990 1992 1993 1995 1997 1999 2000 2001 2002

Preaward

6/89

Project Restructuring Operation

11/90

DOE selected

project (CCT-I)

6/23/89

2003

** **

Cooperative agreement

awarded 11/30/90

Project restructured 6/92

Project resited

(York) 6/93

9/97

Project restructured and resited

(Jacksonville) 8/26/97

** **

5/02 5/04

Design and Construction

NEPA process completed

(EIS York site) 8/11/95

Cooperative agreement modified 9/29/97

Operation initiated

5/02*

Project completed/final report issued 5/04*

Operation completed 5/04*

Design completed

11/00*

Groundbreaking/

construction started 10/99*

NEPA process completed

(EIS Jacksonville site) 10/99*

In its commercial configuration, ACFB technology

offers several potential benefits when compared to conventional pulverized coal-fired systems: lower capital

costs; reduced SO2

 and NOx emissions at lower costs;

higher combustion efficiency; and dry, granular solid

material that is easily disposed of or potentially salable.

Construction completed

3/02*
112 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

Tidd PFBC Demonstration

Project

Project completed.

Participant

The Ohio Power Company

Additional Team Members

American Electric Power Service Corporation—

designer, constructor, and manager

The Babcock & Wilcox Company—technology supplier

Ohio Coal Development Office—cofunder

Location

Brilliant, Jefferson County, OH (Ohio Power Company’s

Tidd Plant, Unit No. 1)

Technology

The Babcock & Wilcox Company’s pressurized fluidizedbed combustion (PFBC) system (under license from ABB

Carbon)

Plant Capacity/Production

70-MWe (net)

Coal

Ohio bituminous, 2–4% sulfur

Project Funding

Total project cost $189,886,339 100%

DOE 66,956,993 35

Participant 122,929,346 65

Project Objective

To verify expectations of PFBC economic, environmental, and technical performance in a combined-cycle

repowering application at utility scale; and to accomplish

greater than 90% SO2

 removal and NOx emission level of

0.2 lb/106

 Btu at full load.

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 pressure

vessel 45 feet in diameter and 70 feet high. The facility

was designed so that one-seventh of the hot gases produced could be routed to an Advanced Particulate

Filter (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 with

sulfur to form calcium sulfate, a dry, granular bed-ash

material, which is easily disposed of or is usable as a byproduct. A low bed-temperature of about 1,600 oF limits

NOx

 formation.

The hot combustion gases exit the bed vessel with

entrained ash particles, 98% of which are removed when

the gases pass through cyclones. The cleaned gases are

then expanded through a 15-MWe gas turbine. Heat

from the gases exiting the turbine, combined with heat

from a tube bundle in the fluid bed, generates steam to

drive an existing 55-MWe steam turbine.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Project Fact Sheets 113

Results Summary

Environmental

• Sorbent size had the greatest effect on SO2 removal

efficiency as well as stabilization and heat transfer

characteristics of the fluidized-bed.

• SO2

 removal efficiency of 90% was achieved at full

load with a calcium-to-sulfur (Ca/S) molar ratio of

1.14 and temperature of 1,580 oF.

• SO2

 removal efficiency of 95% was achieved at full

load with a Ca/S molar ratio of 1.5 and temperature of

1,580 oF.

• NOx

 emissions were 0.15–0.33 lb/106 Btu.

• CO emissions were less than 0.01 lb/106

 Btu.

• Particulate emissions were less than 0.02 lb/106 Btu.

Operational

• Combustion efficiency ranged from an average 99.3%

at low bed levels to an average 99.5% at moderate to

full bed levels.

• Heat rate was 10,280 Btu/kWh (HHV-gross output)

(33.2% efficiency) because the unit was small and no

attempt was made to optimize heat recovery.

• An Advanced Particulate Filter (APF), using a silicon

carbide candle filter array, achieved 99.99% filtration

efficiency on a mass basis.

• PFBC boiler demonstrated commercial readiness.

• ASEA Stal GT-35P gas turbine proved capable of

operating commercially in a PFBC flue gas

environment.

Economic

• The Tidd plant was a relatively small-scale facility, as

such, detailed economics were not prepared as part of

this project.

• A recent cost estimate performed on Japan’s 360-MWe

PFBC Karita Plant, due to commence operation in

1999, projected a capital cost of $1,263/kW (1997$).

Project Summary

The Tidd PFBC technology is a bubbling fluidized-bed

combustion process operating at 12 atmospheres

(175 psi). Fluidized combustion is inherently efficient.

A pressurized environment further enhances combustion

efficiency, allowing very low temperatures that mitigate

thermal NOx

 generation, flue gas/sorbent reactions that

increase sorbent utilization, and flue gas energy that is

used to drive a gas turbine. The latter contributed significantly to system efficiency because of the high efficiency

of gas turbines and the availability of gas turbine exhaust

heat that can be applied to the steam cycle. A bed design

temperature of 1,580 oF was established because it was

the maximum allowable temperature at the gas turbine

inlet and was well below temperatures for coal ash fusion, thermal NOx

 formation, and alkali vaporization.

Coal crushed to 1⁄4 inch or less was injected into the

combustor as a coal/water paste containing 25% water by

weight. Crushed sorbent, either dolomite or limestone,

was injected into the fluidized bed via two pneumatic

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

Design and Construction Operation

3/87

Cooperative agreement awarded 3/20/87

NEPA process completed (MTF) 3/5/87

Environmental monitoring

plan completed 5/25/88

Groundbreaking ceremony 4/6/88

Construction started 12/9/87

Operation initiated 3/91

Preoperational tests started 12/90

Construction completed 12/90

Design completed 12/90

3/91

DOE selected project (CCT-I) 7/24/86

7/86

Preaward

12/95

Project

completed/

final report

issued 12/95

Operation completed 3/95
114 Project Fact Sheets Advanced Electric Power Generation

full bed heights, surpassing the design or expected efficiency of 99.0%.

Using data for typical full-load operation, a heat rate

of 10,280 Btu/kWh (HHV basis) was calculated. This

corresponds to a cycle thermodynamic efficiency of

33.2% at a point where the cycle produced 70-MWe of

gross electrical power while burning Pittsburgh No. 8

coal. Because the Tidd plant was a repowering application at a comparatively small scale, the measured efficiency does not represent what would be expected for a

larger utility-scale plant using Tidd technology. Studies

conducted under the PFBC Utility Demonstration Project

showed that efficiencies of over 40% are likely for a

larger utility-scale PFBC plant.

In summary, the Tidd project showed that the PFBC

system could be applied to electric power generation.

Further, the demonstration project led to significant reThe PFBC demonstration at the repowered 70-MWe unit at Ohio

Power’s Tidd Plant led to significant refinements and understanding of

the technology.

feed lines, supplied from two lock hoppers. The sorbent

feed system initially used two injector nozzles but

was modified to add two more for nozzles to

enhance distribution.

In 1992, a 10-MWe equivalent APF was installed

and commissioned as part of a research and development

program and not part of the CCT demonstration. This

system used ceramic candle filters to clean one-seventh of

the exhaust gases from the PFBC system. The hot gas

cleanup system unit replaced one of the seven

secondary cyclones.

The Tidd PFBC demonstration plant accumulated

11,444 hours of coal-fired operations during its 54

months of operation. The unit completed 95 parametric

tests, including continuous coal-fired runs of 28, 29, 30,

31, and 45 days. Ohio bituminous coals having sulfur

contents of 2–4% were used in the demonstration.

Environmental Performance

Testing showed that 90% SO2

 capture was achievable

with a Ca/S molar ratio of 1.14 and that 95% SO2

 capture

was possible with a Ca/S molar ratio of 1.5, provided the

size gradation of the sorbent being utilized was optimized. This sulfur retention was achieved at a bed temperature of 1,580 oF and full bed height. Limestone induced deterioration of the fluidized-bed, and as a result,

testing focused on dolomite. The testing showed that

sulfur capture as well as sintering was sensitive to the

fineness of the dolomite sorbent (Plum Run Greenfield

dolomite was the design sorbent). Sintering of fluidizedbed materials, a fusing of the materials rather than effective reaction, had become a serious problem that required

operation at bed temperatures below the optimum for

effective boiler operation. Tests were conducted with

sorbent size reduced from minus 6 mesh to a minus 12

mesh. The result with the finer material was a major,

positive impact on process performance without the expected excessive elutriation of sorbent. The finer material

increased the fluidization activity as evidenced by a 10%

improvement in heat transfer rate and an approximately

30% increase in sorbent utilization. In addition, the process was much more stable as

indicated by reductions in temperature variations in both the bed and the evaporator tubes.

Further, sintering was effectively eliminated.

NOx emissions ranged from 0.15–0.33

lb/106

 Btu, but were typically 0.2 lb/106 Btu

during the demonstration. These emissions

were inherent to the process, which was operating at approximately 1,580 oF. No NOx

 control

enhancements, such as ammonia injection,

were required. Emissions of carbon monoxide

and particulates were less than 0.01 and 0.02

lb/106

 Btu, respectively.

Operational Performance

Except for localized erosion of the in-bed tube

bundle and the more general erosion of the

water walls, the Tidd boiler performed extremely well and was considered a commercially viable design. The in-bed tube bundle

experienced no widespread erosion that would

require significant maintenance. While the

tube bundle experienced little wear, a significant amount of erosion on each of the four water walls

was observed. This erosion posed no problem, however,

because the area affected is not critical to heat transfer

and could be protected by refractory.

The prototype gas turbine experienced structural

problems and was the leading cause of unit unavailability

during the first 3 years of operation. However, design

changes instituted over the course of the demonstration

proved effective in addressing the problem. The Tidd

demonstration showed that a gas turbine could operate in

a PFBC flue gas environment.

Efficiency of the PFBC combustion process was

calculated during testing from the amount of unburned

carbon in cyclone and bed ash, together with measurements of the amount of carbon monoxide in the flue gas.

Combustion efficiencies averaged 99.5% at moderate to
Advanced Electric Power Generation Project Fact Sheets 115

finements and understanding of the technology in the

areas of turbine design, sorbent utilization, sintering,

post-bed combustion, ash removal, and boiler materials.

Testing of the APF for over 5,800 hours of coal-fired

operation showed that the APF vessel was structurally

adequate; the clay-bonded silicon carbide candle filters

were structurally adequate unless subjected to side loads

from ash bridging or build-up in the vessel; bridging was

precluded with larger particulates included in the particulate matter; and filtration efficiency (mass basis)

was 99.99%.

Economic Performance

The Tidd plant was a relatively small-scale demonstration

facility, so detailed economics were not prepared as part

of this project. However, a recent cost estimate performed on Japan’s 360-MWe PFBC Karita Plant, due to

commence operation in 1999, projected a capital cost of

$1,263/kW (1997$).

Commercial Applications

Combined-cycle PFBC permits use of a wide range of

coals, including high-sulfur coals. The compactness of

bubbling-bed PFBC technology allows utilities to significantly increase capacity at existing sites. Compactness of

the process due to pressurized operation reduces space

requirements per unit of energy generated. PFBC technology appears to be best suited for applications of 50-

MWe or larger. Capable of being constructed modularly,

PFBC generating plants permit utilities to add increments

of capacity economically to match load growth. Plant life

can be extended by repowering with PFBC using the

existing plant area, coal- and waste-handling equipment,

and steam turbine equipment.

The 360-MWe Karita Plant in Japan, which will use

ABB Carbon P800 technology, represents a major move

toward commercialization of PFBC bubbling-bed technology. A second generation P200 PFBC is under construction in Germany. Other PFBC projects are under

consideration 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 the

National Energy Resource Organization award for demonstrating energy-efficient technology.

Contacts

Mario Marrocco, (614) 223-2460

American Electric Power Service Corporation

1 Riverside Plaza

Columbus, OH 43215,

(614) 223-3204 (fax)

George Lynch, DOE/HQ, (301) 903-9434

Donald W. Geiling, FETC, (304) 285-4784

References

• Tidd PFBC Hot Gas Clean Up Program Final Report.

Report No. DOE/MC/26042-5130. The Ohio Power

Company. October 1995. (Available from NTIS as

DE96000650.)

• Tidd PFBC Demonstration Project Final Report,

Including Fourth Year of Operation. The Ohio Power

Company. August 1995. (Available from DOE

Library/Morgantown, 1-800-432-8330, ext. 4184 as

DE96000623.)

• Tidd PFBC Demonstration Project Final Report,

March 1, 1994–March 30, 1995. Report No. DOE/

MC/24132-T8. The Ohio Power Company. August

1995. (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 and

DE96003781 for vol. 2.)

• A Study of Hazardous Air Pollutants at the Tidd PFBC

Demonstration Plant. Report No. DOE/MC/26042-

4083. American Electric Power Service Corporation.

October 1994. (Available from NTIS as DE95009729.)

• Tidd PFBC Demonstration Project Topical Report—

First Eighteen Months of Operation. Report No.

DOE/MC/24132-3746. The Ohio Power Company.

March 1994. (Available from NTIS as DE94004120.)

• Tidd PFBC Demonstration Project: Public Final

Design Report. Report No. DOE/MC/24132-3195.

The Ohio Power Company. October 1992. (Available

from NTIS as DE93000234.)

Coal and sorbent conveyors can be seen just after

entering the Tidd Plant.
116 Project Fact Sheets Advanced Electric Power Generation

bent improves mixing and extends the contact time of

solids and gases, thus promoting high utilization of the

coal and high-sulfur-capture efficiency. Heat in the flue

gas exiting the hot cyclone is recovered in the economizer. Flue gas passes through a baghouse where particulate matter is removed. Steam generated in the

ACFB 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 ACFB

steam generator capable of driving a new 74-MWe turbine generator. Extraction steam from this turbine generator powers three existing turbine generators

 (12-MWe each).

In 1992, Colorado-Ute Electric Association, Inc.,

the owner of Nucla Station, was purchased by Tri-State

Generation and Transmission Association, Inc.

Project Objective

To demonstrate the feasibility of ACFB technology at

utility scale and to evaluate the economic, environmental,

and operational performance at that scale.

Technology/Project Description

Nucla’s circulating fluidized-bed system operates at atmospheric pressure. In the combustion chamber, a stream

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 flow

into a hot cyclone. The cyclone separates the solids from

the gases, and the solids are recycled for combustor temperature control. Continuous circulation of coal and sorAdvanced Electric Power Generation

Fluidized-Bed Combustion

Nucla CFB Demonstration

Project

Project completed.

Participant

Tri-State Generation and Transmission Association, Inc.

(formerly Colorado-Ute Electric Association, Inc.)

Additional Team Members

Foster Wheeler Energy Corporation*—technology supplier

Technical Advisory Group (potential users)—cofunder

Electric Power Research Institute—technical consultant

Location

Nucla, Montrose County, CO (Nucla Station)

Technology

Foster Wheeler’s atmospheric circulating fluidized-bed

(ACFB) combustion system

Plant Capacity/Production

100-MWe (net)

Coal

Western bituminous—

Salt Creek, 0.5% sulfur, 17% ash

Peabody, 0.7% sulfur, 18% ash

Dorchester, 1.5% sulfur, 23% ash

Project Funding

Total project cost $46,512,678 100%

DOE 17,130,411 37

Participant 29,382,267 63

*Pyropower Corporation, the original technology developer and

supplier, was acquired by Foster Wheeler Energy Corp.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Project Fact Sheets 117

Results Summary

Environmental

• Bed temperature had the greatest effect on pollutant

emissions and boiler efficiency.

• At bed temperatures below 1,620 oF, sulfur capture

efficiencies of 70 and 95% were achieved at calciumto-sulfur (Ca/S) molar ratios of 1.5 and 4.0,

respectively.

• During all tests, NOx

 emissions averaged 0.18 lb/106

Btu and did not exceed 0.34 lb/106 Btu.

• CO emissions ranged from 70–140 ppmv.

• Particulate emissions ranged from 0.0072–0.0125

lb/106

 Btu, corresponding to a removal efficiency

of 99.9%.

• Solid waste was essentially benign and showed potential as an agricultural soil amendment, soil/road bed

stabilizer, or landfill cap.

Operational

• Boiler efficiency ranged from 85.6–88.6% and combustion efficiency ranged from 96.9–98.9%.

• A 3:1 boiler turndown capability was demonstrated.

• Heat rate at full load was 11,600 Btu/kWh and was

12,400 Btu/kWh at half load.

Economic

• Capital cost for the Nucla retrofit was $1,123/kW and a

normalized power production cost was 64 mills/kWh.

Project Summary

Fluidized-bed combustion evolved from efforts to find a

combustion process conducive to controlling pollutant

emissions without external controls. Fluidized-bed

combustion enables efficient combustion at temperatures

of 1,400–1,700 oF, well below the thermal-NOx

 formation temperature (2,500 oF), and high SO2

-capture efficiency through effective sorbent/flue gas contact. ACFB

differs from the more traditional fluid-bed combustion.

Rather than submerging a heat exchanger in the fluid

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

Preaward Operation

1997

10/87 10/88

DOE selected

project (CCT-I)

10/7/87

Environmental monitoring

plan completed 2/27/88

NEPA process completed (MTF) 4/18/88

bed, which dictates a low-fluidization velocity, ACFB

uses a relatively high fluidization velocity, which entrains

the bed material. Hot cyclones capture and return the

solids emerging from the turbulent bed to control temperature and extend the gas/solid contact time and to

protect a downstream heat exchanger.

Interest and participation of the Department of Energy, Electric Power Research Institute, and Technical

Advisory Group (potential users) resulted in the evaluation of ACFB potential for broad utility application

through a comprehensive test program. Over a 21

/2-year

period, 72 steady-state performance tests were conducted

and 15,700 hours logged. The result was a database that

remains the most comprehensive, available resource on

ACFB technology.

Operational Performance

Between July 1988 and January 1991, the plant operated

with an average availability of 58% and an average capacity factor of 40%. However, toward the end of the demonstration, most of the technical problems had been overOperation

completed 1/91

Operation test program initiated 8/88

Cooperative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92
118 Project Fact Sheets Advanced Electric Power Generation

Exhibit 40

 Effect of Bed Temperature

on Ca/S Requirement

Exhibit 41

Calcium Requirements and

Sulfur Retentions for Various Fuels

come. During the last three months of the demonstration,

average availability was 97% and the capacity factor

was 66.5%.

Over the range of operating temperature at which

testing was performed, bed temperature was found to be

the most influential operating parameter. With the exception of coal-fired configuration and excess air at elevated

temperatures, bed temperature was the only parameter

that had a measurable impact on emissions and efficiency.

Combustion efficiency, a measure of the quantity of

carbon that is fully oxidized to CO2

, ranged from

96.9–98.9%. Of the four exit sources of incompletely

burned carbon, the largest was carbon contained in the fly

ash (93%). The next largest (5%) was carbon contained

in the bottom ash stream, and the remaining feed-carbon

loss (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 loss

were identified as unburned carbon, sensible heat in dry

flue gas, fuel and sorbent moisture, latent heat in burning

hydrogen, sorbent calcination, radiation and convection,

and bottom-ash cooling water. Net plant heat rate decreased with increasing boiler load, from 12,400 Btu/kWh

at 50% of full load to 11,600 Btu/kWh at full load. The

lowest value achieved during a full-load steady-state test

was 10,980 Btu/kWh. These values were affected by the

absence of reheat, the presence of the three older

12.5-MWe turbines in the overall steam cycle, the number

of unit restarts, and part-load testing.

Environmental Performance

As indicated above, bed temperature had the greatest

impact on ACFB performance, including pollutant emissions. Exhibit 40 shows the effect of bed temperatures on

the Ca/S molar ratio requirement for 70% sulfur retention. The Ca/S molar ratios were calculated based on the

calcium content of the sorbent only and do not account

for the calcium content of the coal. While a Ca/S molar

ratio of about 1.5 was sufficient to achieve 70% sulfur

retention in the 1,500–1,620 °F range, the Ca/S molar

ratio requirement jumped to 5.0 or more at 1,700 °F

or greater.

Exhibit 41 shows the effect of Ca/S molar ratio on

sulfur retention at average bed temperatures below

1,620 oF. Salt Creek and Peabody coals contain 0.5%

and 0.7% sulfur, respectively. To achieve 70% SO2

reduction, or the 0.4 lb/106 Btu emission rate required

by the licensing agreement, a Ca/S molar ratio of approximately 1.5 is required. To achieve an SO2

 reduction of 95%, a Ca/S molar ratio of approximately 4.0 is

necessary. Dorchester coal, averaging 1.5% sulfur

content, required a somewhat lower Ca/S molar ratio

for a given retention.

NOx

 emissions measured throughout the demonstration were less than 0.34 lb/106

 Btu, which is well

below the regulated value of 0.5 lb/106

 Btu. The average level of NOx

 emissions for all tests was 0.18 lb/106

Btu. NOx emissions indicate a relatively strong correlation with temperature, increasing from 40 ppmv (0.06

lb/106

 Btu) at 1,425 oF to 240 ppmv (0.34 lb/

106

 Btu) at 1,700 °F. Limestone feed rate was

also identified as a variable affecting NOx

emissions, i.e., somewhat higher NOx emissions resulted from increasing calcium-tonitrogen (Ca/N) molar ratios. The mechanism

was believed to be oxidation of volatile nitrogen in the form of ammonia (NH3

) catalyzed

by calcium oxide. CO emissions decrease as

temperature increases, 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.
Advanced Electric Power Generation Project Fact Sheets 119

The 110-MWe Nucla ACFB demonstration enabled Pyropower Corporation

(now owned by Foster Wheeler) to save almost 3 years in establishing a

commercial line of ACFB units.

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). Total power costs

associated with plant operations between September 1988 and January

1991 were approximately $54.7 million, resulting in a normalized cost of

power production of 64 mills/kWh.

The average monthly operating cost

over this period was about $1,888,000.

Fixed costs represent about 62% of 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 effectiveness 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 commercial service.

Today, every major boiler manufacturer offers an

ACFB system in its product line. There are now more

than 120 fluidized-bed combustion boilers of 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

George Lynch, DOE/HQ, (301) 903-9434

Nelson F. Rekos, FETC, (304) 285-4066

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. ColoradoUte Electric Association, Inc. March 1992. (Available

from NTIS as DE92001299.)

• Economic Evaluation Report: Topical Report. Report

No. DOE/MC/25137-3127. Colorado-Ute Electric

Association, Inc., March 1992. (Available from NTIS

as DE93000212.)

• Nucla CFB Demonstration Project: Detailed Public

Design Report. Report No. DOE/MC/25137-2999.

Colorado-Ute Electric Association, Inc., December

1990. (Available from NTIS as DE91002081.)
120 Project Fact Sheets Advanced Electric Power Generation
Advanced Electric Power Generation Project Fact Sheets 121

Advanced Electric Power Generation

Integrated Gasification Combined Cycle
122 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Clean Energy Demonstration

Project

Participant

Clean Energy Partners Limited Partnership (a limited

partnership consisting of Clean Energy Genco, Inc., an

affiliate of Duke Energy Corp.; AMEREN Corporation;

and Energy Research Corporation)

Additional Team Members

Duke Engineering & Services, Inc.—engineer and

constructor

General Electric Company—power island designer and

supplier

British Gas Americas, Inc., in conjunction with Lurgi

Energie and Umwelt GmbH—gasification island designer

Energy Research Corporation—molten carbonate fuel cell

designer and supplier; cofunder

AMEREN Corporation—cofunder

Location

Carbondale, Jackson County, IL (Central Illinois Public

Service Company’s Grand Tower Station)

Technology

Integrated gasification combined-cycle (IGCC) using

British Gas/Lurgi (BG/L) slagging fixed-bed gasification

system coupled with Energy Research Corporation’s molten carbonate fuel cell (MCFC)

Plant Capacity/Production

477-MWe (net) IGCC; 1.25-MWe MCFC

Coal

Illinois basin bituminous coal

Project Funding

Total project cost $841,096,189 100%

DOE 183,300,000 22

Participant 657,796,189 78

Project Objective

To demonstrate and assess the reliability, availability, and

maintainability of a utility-scale IGCC system using

high-sulfur bituminous coal in an oxygen-blown, fixedbed, slagging gasifier and the operability of a molten

carbonate fuel cell fueled by coal gas.

Technology/Project Description

The BG/L gasifier is supplied with steam, oxygen, limestone flux, and coals having a high fines content. During

gasification, the oxygen and steam react with the coal

and limestone flux to produce a raw coal-derived fuel

gas rich in hydrogen and carbon monoxide. Raw fuel

gas exiting the gasifier is washed and cooled. Hydrogen

sulfide 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 the gas turbine. A small portion of the clean fuel gas is used for

the MCFC.

The MCFC is composed of a molten carbonate

electrolyte sandwiched between porous anode and cathode plates. Fuel (desulfurized, heated medium-Btu fuel

gas) and steam are fed continuously into the anode;

carbon dioxide enriched air is fed into the cathode. Electrical reactions produce direct electric current, which is

converted to alternating power in an inverter.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

**Years omitted

Advanced Electric Power Generation Project Fact Sheets 123

1993 1998 1999 1994 1995 2000 2001 2003 2004 2005 2006

Preaward

5/93

DOE selected project

(CCT-V) 5/4/93

Project Status/Accomplishments

The cooperative agreement was awarded December 2,

1994. Subsequent to award, a new site had to be found.

The Central Illinois Public Service Company’s Grand

Tower Station was proposed by the Participant and approved by DOE on November 10, 1998. The initial

scoping meeting for the NEPA process was held in

January 1999.

Commercial Applications

The IGCC system being demonstrated in this project is

suitable for both repowering applications and new power

plants. The technology is expected to be adaptable to a

wide variety of potential market applications because of

several factors. First, the BG/L gasification technology

has successfully used a wide variety of U.S. coals. Also,

the highly modular approach to system design makes the

BG/L-based IGCC and molten carbonate fuel cell competitive in a wide range of plant sizes. In addition, the

high efficiency and excellent environmental performance

Cooperative Agreement

awarded 12/2/94

Design and Construction

of the system are competitive with or superior to other

fossil-fuel-fired power generation technologies.

The heat rate of the IGCC demonstration facility is

projected to be 8,560 Btu/kWh (40% efficiency) and the

commercial embodiment of the system has a projected

heat rate of 8,035 Btu/kWh (42.5% efficiency). The

commercial version of the molten carbonate fuel cell

fueled by a BG/L gasifier is anticipated to have a heat rate

of 7,379 Btu/kWh (46.2% efficiency). These efficiencies

represent greater than 20% reduction in emissions of CO2

when compared to a conventional pulverized coal plant

equipped with a scrubber. SO2

 emissions from the IGCC

system are expected to be less than 0.1 lb/106

 Btu

(99% reduction); 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.

12/94 12/03 12/05

Operation

Operation Initiated 12/03*

Final report issued/project

completed 12/05*

**

New site approved 11/98

**
124 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Piñon Pine IGCC Power

Project

Participant

Sierra Pacific Power Company

Additional Team Members

Foster Wheeler USA Corporation—architect, engineer,

and constructor

The M.W. Kellogg Company—technology supplier

Bechtel Corporation—startup engineer

Location

Reno, Storey County, NV (Sierra Pacific Power

Company’s Tracy Station)

Technology

Integrated gasification combined-cycle (IGCC) using the

KRW air-blown pressurized fluidized-bed coal

gasification system

Plant Capacity/Production

107-MWe (gross), 99-MWe (net)

Coal

Southern Utah bituminous, 0.5–0.9% sulfur (design coal);

eastern bituminous, 2–3% sulfur (planned test)

Project Funding

Total project cost $335,913,000 100%

DOE 167,956,500 50

Participant 167,956,500 50

Project Objective

To demonstrate air-blown pressurized fluidized-bed

IGCC technology incorporating hot gas cleanup; to evaluate a low-Btu gas combustion turbine; and to assess longterm reliability, availability, maintainability, and environmental performance at a scale sufficient to determine

commercial potential.

Technology/Project Description

Dried and crushed coal and limestone are introduced into

an air-blown pressurized fluidized-bed gasifier. Crushed

limestone is used to capture a portion of the sulfur. The

sulfur reacts with the limestone to form calcium sulfide

which, after oxidation, exits as calcium sulfate along

with the coal ash in the form of agglomerated particles

suitable for landfill.

Low-Btu coal gas leaving the gasifier passes

through cyclones, which return most of the entrained

particulate matter to the gasifier. The gas, which leaves

the gasifier at about 1,700 oF, is cooled to about 1,100 oF

before entering the hot gas cleanup system. During

cleanup, virtually all of the remaining particulates are

removed by ceramic candle filters, and final traces of

sulfur are removed by reaction with a metal oxide sorbent in a transport reactor.

The cleaned gas then enters the General Electric

MS6001FA (Frame 6FA) combustion turbine, which is

coupled to a generator designed to produce 61-MWe

(gross). Exhaust gas from the combustion turbine is

used to produce steam in a heat recovery steam generator

(HRSG). Superheated high-pressure steam 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 temperature

of 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

IGCC will produce 20% less CO2

 (a greenhouse gas)

than conventional plants.
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Calendar Year

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Advanced Electric Power Generation Project Fact Sheets 125

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Design and Construction Operation

9/91 8/92 7/00

DOE selected

project (CCT-IV)

9/12/91

Cooperative agreement awarded 8/1/92

Project completed/final report issued 7/00*

Operation completed 7/00*

Ground breaking/construction started 2/95

NEPA process completed (EIS) 11/8/94

Design completed 8/95

improve performance, including the start-up logic for the

gasifier and the sorbent used for the transport desulfurizer.

This project continues to make progress achieving

integrated operation of all systems. Some earlier problems (related to measuring solids levels) in the fines

handling system have been resolved; however, other nongasifier problems, such as fines bridging in vessels, have

occurred that prevent feeding coal for more than 6-8

hours continuously. The gasifier continues to operate

smoothly through numerous startup-turndown cycles,

with reproducible production of specification-quality

syngas. Sierra Pacific continues to operate the plant on

natural gas in the combined cycle mode.

Commercial Applications

The Piñon Pine IGCC system concept is suitable for new

power generation, repowering needs, and cogeneration

applications. The net heat rate for a proposed greenfield

plant using this technology is projected to be 7,800 Btu/

kWh (43.7% efficiency), representing a 20% increase in

In the demonstration project, 880 tons/day of coal

are converted into 99 MWe (net) for export to the grid.

Southern Utah bituminous coal (0.5–0.9% sulfur) is the

design coal; tests using midwestern or eastern high-sulfur

bituminous coal (2–3% sulfur) also are planned. The

IGCC system is located at Sierra Pacific Power

Company’s Tracy Station, near Reno, NV.

Project Status/Accomplishments

The system has initiated test-plan operations and continues to experience start-up problems. The station began

operation on natural gas in November 1996. Pre-operational testing and shakedown of the coal gasification

combined-cycle system continued through 1997 with

syngas produced in January 1998. The plant was dedicated in April 1998.

The GE Frame 6FA combustion turbine, the first of

its kind in the world, has performed well since commencing operation in August 1996 on natural gas. Other portions of the plant have undergone design modification to

Environmental monitoring plan

completed 10/31/96

Preoperational tests initiated 11/96

1/98

Operation initiated 1/98

Construction completed 2/97

thermal efficiency as 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 energy

generated relative to other coal-based power generation

systems. The advantages provided by phased modular

construction reduce the financial risk associated with new

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 bio- or refusederived waste, with minimal environmental impact. There

are no significant process waste streams that require

remediation. The only solid waste from the plant is a

mixture of ash and calcium sulfate, a nonhazardous waste.
126 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Tampa Electric Integrated

Gasification Combined-Cycle

Project

Participant

Tampa Electric Company

Additional Team Members

Texaco Development Corporation—gasification

technology supplier

General Electric Corporation—combined-cycle

technology supplier

GE Environmental Services, Inc.—hot-gas cleanup

technology supplier

TECO Power Services Corporation—project manager and

marketer

Bechtel Power Corporation—architect and engineer

Location

Mulberry, Polk County, FL (Tampa Electric Company’s

Polk Power Station, Unit No. 1)

Technology

Integrated gasification combined-cycle (IGCC) system

using Texaco’s pressurized oxygen-blown entrained-flow

gasifier technology and incorporating both conventional

low-temperature acid-gas removal and hot-gas movingbed desulfurization

Plant Capacity/Production

313-MWe (gross), 250-MWe (net)

Coal

Illinois #6, Pittsburgh #8, and Kentucky #11; 2.5–3.5%

sulfur

Project Funding

Total project cost $303,288,446 100%

DOE 150,894,223 49

Participant 152,394,223 51

Project Objective

To demonstrate IGCC technology in a greenfield, commercial, electric utility application at the 250-MWe size

with a Texaco gasifier; to demonstrate the integrated

performance of a metal oxide hot-gas cleanup system,

conventional cold-gas cleanup, and an advanced gas

turbine with nitrogen injection (from the air separation

plant) for power augmentation and NOx

 control.

Technology/Project Description

Texaco’s pressurized, oxygen-blown, entrained-flow

gasifier is used to produce a medium-Btu fuel gas. A

coal/water slurry and oxygen are reacted at high temperature and pressure to produce a high-temperature syngas.

The syngas moves from the gasifier to a high-temperature

heat-recovery unit, which cools the gases. Molten coalash flows out of the bottom of the gasifier vessel and into

a water-filled quench tank where it is forms a solid slag.

The cooled gases flow to a particulate-removal section before entering gas-cleanup trains. A portion of the

syngas (10%) is passed through a moving bed of metal

oxide absorbent to remove sulfur. The remaining syngas

is further cooled through a series of convective heat exchangers before entering a conventional gas-cleanup train

where sulfur is removed by an acid-gas removal system.

Combined, these cleanup systems are expected to maintain sulfur levels below 0.21 lb/106

 Btu (96% capture).

The cleaned gases are then routed to a combined-cycle

system for power generation. Sulfuric acid and slag are

salable by-products.

A GE MS 7001F combustion turbine generates about

192 MWe (gross). Thermal-NOx

 is controlled to below
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Calendar Year

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**Years omitted

Advanced Electric Power Generation Project Fact Sheets 127

0.27 lb/106 Btu by injecting nitrogen as a dilutent in the

turbine’s combustion section. A steam turbine, which

uses steam produced by the heat recovery steam-generator, produces an additional 121-MWe (gross). Polk’s

IGCC heat rate for this demonstration is expected to be

approximately 8,600 Btu/kWh (40% efficient). The

demonstration project involves only the first 250-MWe

(net) of the planned 1,150-MWe Polk Power Station.

Illinois #6, Pittsburgh #8, and Kentucky #11 bituminous

coals (2.5–3.5% sulfur) are being used.

Project Status/Accomplishments

The plant began commercial operation in September 1996

and continues to successfully accumulate run time. IGCC

operation had exceeded 11,000 hours by December 1998.

The unit has produced over 2,944,278 MWh on syngas.

The gasifier on-stream factor was over 70% for 1998.

Overall combined-cycle availability has remained above

90% since the second quarter of 1997. Improved gasifier

availability was largely due to removal of the raw gas/

clean gas heat exchanger, a source of particulate contami1988 1989 1990 1991 1994 1995 1996 1997 1998 1999 2001

Preaward Design and Construction

12/89 3/91

nation, and installation of a larger filter to prevent leakage

of particulate matter to the turbine. Also contributing to

improved availability are new operating procedures to

deal with radiant syngas cooler dome seal leaks and hot

restarts of the gasifier.

Tests included evaluation of various coal types on

system performance. Kentucky #11, Illinois #6, and three

Pittsburgh #8 coals were tested for their: (1) ability to be

processed into a high concentration slurry, (2) carbon

conversion efficiency, (3) aggressiveness of the slag in

regard to refractory wear, and (4) tendency toward fouling

of the syngas coolers. Kentucky #11 coal proved to have

the best overall characteristics and supplanted Pittsburgh

#8 as the base coal. Illinois #6 placed second and

prompted further testing because of some promising

aspects of its performance. The unit is currently running

on a blend of Ohio #11/Powder River Basin coals. The

gasifier and combustion turbine set continuous operating

records of over 49 and 51 days, respectively.

**

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

Cooperative agreement awarded 3/11/91

Preoperational tests initiated 6/96

Construction completed 8/96

Operation initiated 9/96

9/96

Design completed 8/94

NEPA process completed (EIS) 8/17/94

Construction started 8/94

Project completed/final report issued 10/01*

Operation completed 10/01*

10/01

Operation

Environmental monitoring plan completed 5/96

Commercial Applications

This demonstration project is scaling up the technology

from Cool Water demonstration unit (100-MWe) tested

without full system integration. The Texaco-based IGCC

is suitable for new electric power generation, repowering

needs, and cogeneration applications. Commercial

IGCCs should achieve better than 98% SO2

 capture with

a NOx

 emissions reduction of 90% relative to a conventional pulverized coal-fired plant.

Texaco and ASEA Brown Boveri have signed an

agreement forming an alliance to market IGCC technology in Europe.

The project was presented the 1997 Powerplant

Award by Power magazine. In 1996 the project received

the Association of Builders and Contractors Award for

construction quality. Several awards were presented for

using an innovative siting process: 1993 Ecological

Society of America Corporate Award and 1993 Timer

Powers Conflict Resolution Award from the State of

Florida, and the 1991 Florida Audubon Society

Corporate Award.

**

3 4
128 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Wabash River Coal

Gasification Repowering

Project

Participant

Wabash River Coal Gasification Repowering Project Joint

Venture (a joint venture of Dynegy and PSI Energy, Inc.)

Additional Team Members

PSI Energy, Inc.—host

Dynegy (formerly Destec Energy, Inc.; a subsidiary of

Natural Gas Clearinghouse)—engineer, gas plant

operator, and technology supplier

Location

West Terre Haute, Vigo County, IN (PSI Energy’s Wabash

River Generating Station, Unit No. 1)

Technology

Integrated gasification combined-cycle (IGCC) using

Destec’s two-stage pressurized oxygen-blown entrainedflow gasification system

Plant Capacity/Production

296-MWe (gross), 262-MWe (net)

Coal

Illinois Basin bituminous

Project Funding

Total project cost $438,200,000 100%

DOE 219,100,000 50

Participant 219,100,000 50

Project Objective

To demonstrate utility repowering with a two-stage pressurized oxygen-blown entrained-flow IGCC system,

including advancements in the technology relevant to the

use of high-sulfur bituminous coal and to assess longterm reliability, availability, and maintainability of the

system at a fully commercial scale.

Technology/Project Description

The Destec coal gasification process features an oxygenblown, continuous-slagging, two-stage, entrained flow

gasifier. Coal is slurried, combined with oxygen in mixer

nozzles, and injected into the first stage of the gasifier,

which operates at 2600 °F and 400 psig. Oxygen of 95%

purity is supplied by an Air Liquide 2,060-ton/day lowpressure cryogenic distillation facility (Air Separation

Unit or ASU), which is owned and operated by Destec.

In the first stage, the coal slurry undergoes 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 additional coal slurry is

injected. This coal is pyrolyzed in an endothermic reaction with the hot syngas to enhance syngas heating value

and to improve overall efficiency. A Claus unit is used to

produce elemental sulfur as a salable by-product.

The syngas then flows to the high-temperature heatrecovery unit (HTHRU), essentially a firetube steam generator, to produce high-pressure saturated steam. After

cooling in the HTHRU, particulates in the syngas 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 (COS) into hydrogen sulfide. Hydrogen sulfide is

removed in the acid gas removal system using MDEAbased absorber/stripper columns. The “sweet” gas is then

moisturized, preheated, and piped to the power block.
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Calendar Year

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Advanced Electric Power Generation Project Fact Sheets 129

The power block consists of a single 192-MWe

General Electric MS 7001FA combustion turbine/generator (CT), a Foster Wheeler single-drum heat recovery

steam generator with reheat, and a 1952 vintage

Westinghouse reheat steam turbine. Steam injection is

used for NOx

 control in the CT, but the steam flow is

minimal because the syngas is moisturized in the gasification process. Existing coal handling facilities, interconnections, and other auxiliaries were reused.

Project Status/Accomplishments

The project began operations in December 1995 and

continues in its fourth year of commercial service.

CINergy, PSI’s post-merger parent company, preferentially dispatches the unit second behind its hydroelectric

facilities on the basis of environmental emissions and

efficiency, with a demonstrated heat rate of better than

9,000 Btu/kWh (HHV). In 1998, the facility operated for

5,281 hours processing over 560,000 tons of coal and

producing over 8.8 trillion Btus of syngas. Since beginning operation, the facility has operated on coal for over

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Operation

DOE selected

project (CCT-IV)

9/12/91

Design and Construction

9/91 7/92

NEPA process completed (EA) 5/28/93

Design completed 5/94

Cooperative agreement awarded 7/28/92

Environmental monitoring plan completed 7/9/93

Groundbreaking ceremony 7/7/93

Preoperational tests initiated 8/95

11/95 11/99

Demonstration completed 9/99*

Operation initiated 11/95

Construction completed 11/95

10,000 hours and processed more than one million tons

of coal. The unit has achieved monthly production levels

of one trillion Btus on four occasions. The 1998 operating data show a capacity factor of 68% and an availability of over 72%. Refinements to the design are continuing, including replacement of ceramic candle particulate

filters with a metallic filter (operating temperature

800 oF) and installation of a chloride scrubber and new

COS hydrolysis catalyst for SO2

 control.

Commercial Applications

Throughout the United States, particularly in the Midwest

and East, there are more than 95,000-MWe of existing

coal-fired utility boilers over 30 years old. Many of these

aging plants are without air pollution controls and are

candidates for repowering with IGCC technology. Repowering these plants with IGCC systems will improve

plant efficiencies and reduce SO2

, NOx, and CO2 emissions. The modularity of the gasifier technology will

permit a range of units to be considered for repowering,

and the relatively short construction schedule for the

Project completed/final report

issued 11/99*

technology will allow utilities greater flexibility in

designing strategies to meet load requirements. Also, the

high degree of fuel flexibility inherent in the gasifier

design will provide utilities with more choice in selecting

fuel supplies to meet increasingly stringent air quality

regulations.

The system heat rate for a new power plant based on

this technology is expected to realize at least a 20% improvement in efficiency compared to a conventional

pulverized coal-fired plant with flue gas desulfurization.

The improved system efficiency also results in a similar

decrease in CO2 emissions.

Destec Energy and CINergy Corp./PSI Energy received the 1996 Powerplant Award from Power magazine. Sargent & Lundy, engineer for the combined-cycle

facility, won the American Consulting Engineers

Council’s 1996 Engineering Excellence Award.
130 Project Fact Sheets Advanced Electric Power Generation
Advanced Electric Power Generation Project Fact Sheets 131

Advanced Electric Power Generation

Advanced Combustion/Heat Engines
132 Project Fact Sheets Advanced Electric Power Generation

Advanced Electric Power Generation

Advanced Combustion/Heat Engines

Healy Clean Coal Project

Participant

Alaska Industrial Development and Export Authority

Additional Team Members

Golden Valley Electric Association—host and operator

Stone and Webster Engineering Corp.—engineer

TRW Inc., Space & Technology Division—combustor

technology supplier

The Babcock & Wilcox Company (which has acquired

assets of Joy Environmental Technologies, Inc.)—

spray-dryer absorber technology supplier

Usibelli Coal Mine, Inc.—coal supplier

Location

Healy, Denali Borough, AK (adjacent to Healy Unit

No. 1)

Technology

TRW’s advanced entrained (slagging) combustor

Babcock & Wilcox’s spray-dryer absorber with sorbent

recycle

Plant Capacity/Production

50-MWe (nominal)

Coal

Usibelli subbituminous 35% run-of-mine (ROM) (0.2%

sulfur) and 65% waste coal (design)

Project Funding

Total project cost $242,058,000 100%

DOE 117,327,000 48

Participant 124,731,000 52

Project Objective

To demonstrate an innovative new power plant design

featuring integration of an advanced combustor and heat

recovery system coupled with both high- and low-temperature emissions control processes.

the combustion products vertically into the boiler. The

main slagging combustor consists of a water-cooled cylinder that slopes toward a slag opening. The precombustor

burns 25–40% of the total coal input. The remaining coal

is injected axially into the combustor, rapidly entrained by

the swirling precombustor gases and additional air flow,

and burned under substoichiometric (fuel-rich) conditions

for NOx

 control. The ash forms molten slag, which accumulates on the water-cooled walls and is driven by aerodynamic and gravitational forces through a slot into the

slag recovery section. About 70–80% of the coal’s ash is

removed as molten slag. The hot gas is then ducted to the

furnace where, to ensure complete combustion, additional

air is supplied from the tertiary air windbox to NOx

 ports

and to final overfire air ports.

Technology/Project Description

The project involves two unique slagging combustors

generating a nominal 50 MWe. Emissions of SO2

 and

NOx

 are controlled using TRW’s slagging combustion

systems with staged fuel and air, a boiler that controls

NOx

 related conditions, and limestone injection. Additional SO2

 is removed using Babcock & Wilcox’s activated recycle spray-dryer absorber system. Performance

goals are NOx

 emissions of less than 0.2 lb/106 Btu,

particulate emissions of 0.015 lb/106

 Btu, and SO2 removal greater than 90%. The design fuel blend performance testing of coal consists of 35% ROM and 65%

waste coal.

A coal-fired precombustor increases the air inlet

temperature for optimum slagging performance. The

TRW slagging combustors are side mounted, injecting
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Calendar Year

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*Projected date

**Years omitted

Advanced Electric Power Generation Project Fact Sheets 133

Pulverized limestone (CaCO3) for SO2 control is fed into

the combustor where it is flash calcined (converting CaCO3

 to

CaO). The mixture of this lime (CaO) and ash not slagged,

called flash-calcined material, is removed in the fabric filter

(baghouse) system. Most of the flash-calcined material is used

to form a 45% flash-calcined-material solids slurry. SO2

 in the

flue gas reacts with the slurry droplets as water is simultaneously evaporated. SO2

 is further removed from the flue gas

by reacting with the dry flash-calcined material on the baghouse

filter bags.

The project site is adjacent to the existing Healy Unit No.

1 near Healy, Alaska, and to the Usibelli coal mine. Power will

go to the Golden Valley Electric Association (GVEA). The

plant will use 900 tons/day of subbituminous and waste coal.

Following the completion of cost-shared demonstration operations, the project will collect an additional 2 years of performance data being provided at no cost to DOE. A HAP monitoring program will also be implemented.

To address concerns about potential impact to the nearby

Denali National Park and Preserve, DOE, the National Park

Service, GVEA, and the project participant entered into an

agreement to reduce the emissions from Unit No. 1 so that the

combined emissions from the two units will be only slightly

greater than those currently emitted from Unit No. 1 alone.

Total site emissions will be further reduced to current levels if

necessary to protect the park.

Project Status/Accomplishments

The initial firing of the entrained slagging combustion system

on coal began in January 1998. During a record-setting 18-day

period of continuous operation, initial NOx

 and SO2 environmental compliance testing was completed. The preliminary

results showed that NOx

 emissions of 0.25 lb/106 Btu and SO2

emissions of 0.08 lb/106 Btu were achieved. The permit requires emissions to be less than 0.35 lb/106

 Btu for NOx and

less than 0.10 lb/106

 Btu for SO2. The stringent SO2 emission

level required by the permit is significantly lower than the 1.2

lb/106

 Btu NSPS limit. By the end of the first year of operation, the plant had logged over 4,900 hours of operation and

converted 156,000 tons of coal/waste coal blend into 231

gigawatts of electricity (average capacity factor 44%). The

following minor modifications were made on Combustor “A”

during a routine outage completed in January 1999: combustor

improvements to minimize slag buildup in the precombustor/

combustor, acoustical silencer added to the ID fan area, and a

flow distribution device was inserted prior to the baghouse to

minimize bag wear. Operations are currently focused on blending ROM coal with up to 65% waste coal. In March 1999,

compliance particulate emissions tests were conducted.

Commercial Applications

This technology has a wide range of applications. It is appropriate for any size utility or industrial boiler in new and retrofit

uses. It can be used in coal-fired boilers as well as in oil- and

gas-fired boilers because of its high ash-removal capability.

However, cyclone boilers may be the most amenable type to

retrofit with the slagging combustor because of the limited

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 particulate

control is important to potential users planning new capacity,

repowering, or retrofits to existing capacity in order to comply

with CAAA requirements.

The combustion technology supplier, TRW, is offering

licensing of its technology worldwide and already has a licensing agreement in place in China.

1990 1991 1993 1994 1995 1997 1998 1999 2000 2001 2002

Preaward Design and Construction

Design

started 7/90

4/91

Cooperative

agreement

awarded 4/11/91

DOE selected project

(CCT-III) 12/19/89

Operation

12/89 1/98 11/99

**

DOE cost-shared operation

completed 11/99*

2 yrs of operational data

provided at no additional

cost 11/01*

11/01

Operation initiated 1/98

Preoperational tests

initiated 8/97

NEPA process completed (EIS) 3/10/94

Design completed 10/93

Ground breaking/

construction

started 5/30/95

No-Cost Data Collection

Environmental monitoring

plan completed 4/11/97

Construction

completed 11/97

Project completed/final report

issued 6/00*

**
134 Project Fact Sheets 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 diesel technology, which uses a low-rank coal-water-fuel (LRCWF),

is expected to have very low NOx

 and SO2 emission levels

(50–70% below current New Source Performance Standards). In addition, the demonstration plant is expected

to achieve 41% efficiency, while future plant designs are

expected to reach 48% efficiency. This will result in a

25% reduction in CO2

 emissions compared to conventional coal-fired plants.

The LRCWF is prepared using an advanced coal

drying process that allows dried coal to be slurried in

water. The University of Alaska will assemble and operate a 5-ton/hr LRCWF processing plant that will use local

coal brought by truck from Usibelli’s mine in Healy,

Alaska. In addition to its use in the coal-fueled diesel

engine, the LRCWF is expected to be an alternative to

fuel oil in conventional oil-fired industrial boilers.

Project Status/Accomplishments

The project has passed several milestones. A 95% design

review was conducted in January 1999 at the University

of Alaska, Fairbanks (UAF). Representatives from

Coltec, A.D. Little, UAF, DOE, and GHEMM (construction contractor) were in attendance. The latest design

eliminates the need for a sorbent injection system because

Usibelli was able to locate a very clean coal seam with

less than 0.2% sulfur in the ash. The sorbent injection

system originally proposed for the coal diesel was designed for use with bituminous coals with greater than

Advanced Electric Power Generation

Advanced Combustion/Heat Engines

Clean Coal Diesel

Demonstration Project

Participant

Arthur D. Little, Inc.

Additional Team Members

University of Alaska at Fairbanks—host and cofunder

Alaskan Science & Technology Foundation—cofunder

Coltec Industries Inc.—diesel engine technology vendor

Energy and Environmental Research Center, University

of North Dakota—fuel preparation technology vendor

R.W. Beck, Inc.—architect/engineer, designer,

constructor

Usibelli Coal Mine, Inc.—coal supplier

Location

Fairbanks, AK (University of Alaska facility)

Technology

Coltec’s coal-fueled diesel engine

Plant Capacity/Production

6.4-MWe (net)

Coal

Usibelli Alaskan subbituminous

Project Funding

Total project cost $47,636,000 100%

DOE 23,818,000 50

Participant 23,818,000 50

Project Objective

To prove the design, operability, and durability of the

coal diesel engine during 6,000 hours of operation; verify

the design and operation of an advanced drying/slurrying

process for subbituminous Alaskan coals; and test the

coal slurry in the diesel and a retrofitted oil-fired boiler.
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Advanced Electric Power Generation Project Fact Sheets 135

1993 1996 1997 1994 1995 1998 1999 2000 2001 2002 2003

Preaward

5/93 7/94

DOE selected project

(CCT-V) 5/4/93

Cooperative agreement awarded 7/12/94

Design and Construction

2.0% sulfur levels. Coltec worked with the diesel engine

manufacturer to design new injectors with sapphire orifices sized for the volume of LRCWF required to operate

the engine at full load. Earlier designs were based on

higher energy density bituminous coals.

The 18-cylinder diesel engine arrived in January

1999, but extremely cold weather prevented movement

into facilities building until the end of February 1999.

Construction activities, which started at the Fairbanks site

on June 15, 1998, are over 60% complete.

Samples of the Usibelli coal were sent to CQ Inc.,

for washability tests; to ADL for wear tests; and to EERC

for preliminary hot water drying tests and bench wear

tests. Several plant design changes were made in order to

keep the project within budget. Notably, only a small oilfired boiler will be converted for coal slurry tests instead

of a utility-scale boiler, and several of the slurry holding

tanks will be located closer to the diesel engine to reduce

underground piping.

NEPA process completed (EA) 6/2/97

Final design of the low-rank coal-water-fuel

(LRCWF) processing plant has been delayed. Construction of the LRCWF is not expected to start until May

2000. A revised schedule for the demonstration test of

the diesel or coal is being developed.

Commercial Applications

The U.S. diesel market is projected to exceed 60,000-

MWe (over 7,000 engines) through 2020. The worldwide

market is 70 times the U.S. market. The technology is

particularly applicable to dispersed power generation in

the 5–20-MWe range, using indigenous coal in developing countries.

The net effective heat rate for the mature diesel

system is expected to be 6,830 Btu/kWh (48%), which

makes it very competitive with similarly sized coal- and

fuel oil-fired installations. Environmental emissions from

commercial diesel systems should be reduced to levels

between 50% and 70% below NSPS. The estimated

installation cost of a mature commercial unit is approximately $1,300/kW.

Construction started 6/98

Environmental monitoring plan completed 2/99

Operation initiated 9/00*

Preoperational tests initiated 9/00*

Construction completed 9/00*

9/00 4/03

Project completed/final

report issued 4/03*

Operation

completed 1/03*

Operation

Project restructured 8/96

Design completed 1/99
136 Project Fact Sheets Advanced Electric Power Generation
Coal Processing for Clean Fuels 

Coal Processing for Clean Fu
138 Project Fact Sheets 

Coal Processing for Clean Fuels

Indirect Liquefaction

Commercial-ScaleDemonstration of the LiquidPhase Methanol (LPMEOHTM)ProcessParticipantAir Products Liquid Phase Conversion Company, L.P.(a limited partnership between Air Products andChemicals, Inc., the general partner, and EastmanChemical Company)Additional Team MembersAir Products and Chemicals, Inc.—technology supplier

and cofunder

Eastman Chemical Company—host, operator, synthesis

gas and services provider

ARCADIS Geraghty & Miller—fuel methanol tester and

cofunder

Electric Power Research Institute—utility advisorLocationKingsport, Sullivan County, TN (Eastman ChemicalCompany’s Integrated Coal Gasification Facility)TechnologyAir Products and Chemicals’ liquid phase methanol(LPMEOHTM) processPlant Capacity/Production80,000 gallons/day of methanol (nominal)CoalEastern high-sulfur bituminous, 3–5% sulfurProject FundingTotal project cost $213,700,000 100%DOE 92,708,370 43Participant 120,991,630 57

nol processes. The liquid catalyst but functions as aheat of reaction away from feature permits the direct feed to the reactor withoushift conversion.

Methanol fuel testing 

stationary and mobile appbuses, and distributed eleverification testing for the coproduct with methanol planned for Fall 1999, andemonstrate will be madenous coal (Mason seam) cmum) and 10% ash is bei

Project ObjectiveTo demonstrate on a commercial scale the production ofmethanol from coal-derived synthesis gas using theLPMEOHTMprocess; to determine the suitability of methanol produced during this demonstration for use as a

chemical feedstock or as a low-SO

x emitting, low-NOx

emitting alternative fuel in stationary and transportationapplications; and to demonstrate, if practical, the production of dimethyl ether (DME) as a mixed coproductwith methanol.Technology/Project DescriptionThis project is demonstrating, at commercial scale, theLPMEOHTM process to produce methanol from coalderived synthesis gas. The combined reactor and heatremoval system is different from other commercial metha- LPMEOHTM is a trademark of Air Products and Chemicals, Inc.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels Project Status/AccomplishmentsConstruction was completed in January of 1997. Following commissioning and shakedown activities, the firstproduction of methanol from the 80,000 gal/day unitoccurred on April 2, 1997. The first stable operation ofthe process demonstration unit at nameplate capacityoccurred on April 6, 1998. A stable test period at over92,000 gal/day revealed no system limitations. Thestartup also proceeded without injury orenvironmental incidents.

The hydrogen to carbon monoxide (H2/CO) ratio in

the reactor feed stream was varied from 0.4 to 5.6 with nonegative effects on catalyst performance. The operationof the demonstration unit confirmed the engineeringmethods used in the design of the LPMEOHTM Reactor,and several parameters (such as the overall heat transfercoefficient of the internal heat exchanger) were demonstrated at greater than 115% of design levels.

Operation during 1998 has resulted in significant

accomplishments. During 1998, the demonstration unit

operated at an availability of over 99%. Since operationsbegan in April 1997, the unit has had an availability ofover 96% as of the end of 1998. The design catalystloading in the LPMEOHTM Reactor has been exceeded toover 150% without indications of mass transfer limitations. Catalyst life has met or exceeded the design targetfor operation in the environment of trace poisons presentin coal-derived synthesis gas. Process variable studies tomaximize the reactor volumetric productivity and determine the long-term catalyst performance are on-going. Acode inspection of all pressure vessels in the LPMEOHTMDemonstration unit was completed in March 1999. Allvessels inspected showed no evidence of erosion, pitting,or fouling. Since startup, the demonstration facility hasproduced over 35 million gallons of methanol, all ofwhich has been accepted by Eastman Chemical Companyfor use in downstream chemical processes.Commercial ApplicationsThe LPMEOHTM process has been developed to enhanceintegrated gasification combined-cycle (IGCC) power

generation by producing fuel—methanol—from also has a broad range obe substituted for convemobile combustion applfor utility peaking unitshas exceptionally low-N

Methanol can be producIGCC facility.

DME has several c

blend with methanol, thfuel in IGCC electric poof methanol and DME cfeedstock for the synthefuel additives. Pure DMaerosol for personal pro

Typical commercia

expected to range in sizmethanol produced wheIGCC power generation 

Design and Construction Operation

1992 1995 1993 1994 1996 1997 1998 1999 

Preaward

1991

12/89 10/92

DOE selectedproject (CCT-III)12/19/89

Cooperative agreement awarded 10/16/92

Project c

NEPA process completed (EA) 6/30/95

Construction started 10/95

Design completed 6/96

Environmental monitoring plan completed 8/29/96

4/97

Operation initiated 4/97

Preoperational tests initiated 1/97Construction completed 1/97

Project transferred to Air Products

Liquid Phase Conversion

Company, L.P. 9/94
140 Project Fact Sheets 

Project FundingTotal project cost $87,386,102 100%DOE 37,994,437 43Participant 49,391,665 57Project ObjectiveTo demonstrate advanced coal-cleaning unit processes toproduce low-cost compliance coals that can meet therequirements for commercial-scale utility power plants tosatisfy provisions of the CAAA.Technology/Project DescriptionAn advanced coal-cleaning plant has been designed,blending existing and new processes, to produce twotypes of compliance coals—Carefree CoalTM and SelfScrubbing CoalTM from high-sulfur bituminousfeedstocks.

Carefree CoalTM is p

ing run-of-mine coal and medium cyclones and fineto 90% of the pyritic sulfuCoalTM is designed to be a fuel that can be used withadditional capital expendiuse Carefree CoalTM to co

others cannot due to the htheir coal feedstocks. Whproduced by reducing pyrCoalTM can be produced t

Self-Scrubbing Coal

free CoalTM, with its redutent, and adding to it sorbSelf-Scrubbing CoalTM is 

Coal Processing for Clean Fuels

Coal Preparation Technologies

Self-Scrubbing CoalTM: AnIntegrated Approach to CleanAirParticipantCustom Coals InternationalAdditional Team MembersPennsylvania Power & Light Company—hostRichmond Power & Light—hostCenterior Service Company—hostLocationsCentral City, Somerset County, PA (advanced

coal-cleaning plant)

Lower Mt. Bethel Township, Northampton County, PA

(combustion tests at Pennsylvania Power & Light’sMartin’s Creek Power Station, Unit No. 2)

Richmond, Wayne County, IN (combustion tests at

Richmond Power & Light’s Whitewater ValleyGenerating Station, Unit No. 2)

Ashtabula, Trumbull County, OH (combustion tests at

Centerior Energy’s Ashtabula C)

TechnologyCoal preparation using Custom Coals’ advanced physicalcoal-cleaning and fine magnetite separation technologyplus sorbent addition technologyPlant Capacity/Production500 tons/hrCoalMedium and high-sulfur bituminous coals (LowerKittanning, Illinois No. 5, and Lower Freeport Seam)Self-Scrubbing Coal and Carefree Coal are trademarks of Custom CoalsInternational.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels 

A Carefree CoalTM test burn (cleaned Lower

Kittanning coal) at Martin’s Creek Power Station wasconducted in mid-November 1996. Although plant optimization was not completed, the overall product made forthe test was consistent with the current quality of theplant feed coal. The unit experienced some opacity problems due to the low sulfur in the coal and a marginalelectrostatic precipitator.

High organic sulfur in the raw coal created problems

with the ability to produce compliance quality clean coal.Further, difficulties with the plant resulted in an excessiveamount of material going to the refuse pond, and plantoperation was suspended in February 1997. Financialproblems ensued and, despite efforts to resolve the matter,the project was placed in Chapter 11. Due to CustomCoals inability to find a buyer for the facility, the CustomCoals Laurel facility was sold at auction on December 16,1998 to C.J. Betters Enterprises of Monaca, Pennsylvania.C.J. Betters has met with DOE to discuss continuation ofthe project.

with virtually any U.S. coal feedstock through in-boilerabsorption of SO2 emissions. The reduced ash content of

the Self-Scrubbing CoalTM permits addition of relativelylarge amounts of sorbent without exceeding ash specifications of boilers or overloading electrostatic precipitators.

Two medium- to high-sulfur coals—Illinois No. 5

(2.7% sulfur) and Lower Freeport (3.9% sulfur)—arebeing used to produce Self-Scrubbing CoalTM. CarefreeCoalTM is being made using Lower Kittanning (1.8%sulfur). Plans called for Lower Kittanning coal to betested at Martin’s Creek Power Station; Illinois No. 5 coalto be tested at Whitewater Valley Generating Station; andLower Freeport Seam coal to be tested at Ashtabula C.Project Status/AccomplishmentsStart-up began in late December 1995, and the first coalwas processed in February 1996. In May 1996, the facility reached its design capacity. Equipment and circuitoptimization testing began immediately thereafter andcontinued throughout 1996.

Commercial ApplicaCommercialization of Spotential of bringing inttons/yr of bituminous colimits through conventiosents more than 38% of 50-MWe or larger U.S. 

1991 1992 1993 1994 1995 1996 1997 1998 1999 

Preaward

9/91 10/92

DOE selectedproject (CCT-IV)9/12/91

Construction started 12/93

Cooperative agreement awarded 10/29/92

NEPA process completed (EA) 2/14/94

Design and Construction Operation

2/96

Design completed 12/94

Preoperational tests initiated 11/95Construction completed 11/95

Operation initiated 2/96

2/97

Project on hold
142 Project Fact Sheets 

Coal Processing for Clean Fuels

Coal Preparation Technologies

Advanced Coal ConversionProcess DemonstrationParticipantRosebud SynCoal Partnership (a partnership of WesternEnergy Company and Western SynCoal Company [asubsidiary of Montana Power Company’s Energy SupplyDivision])Additional Team MembersNoneLocationColstrip, Rosebud County, MT (adjacent to Western

Energy Company’s Rosebud Mine)

TechnologyRosebud SynCoal Partnership’s Advanced Coal Conversion Process for upgrading low-rank subbituminous andlignite coalsPlant Capacity/Production45 tons/hr of SynCoal® product

CoalPowder River Basin subbituminous (Rosebud Mine), 0.5-1.5% sulfur, plus tests of other subbituminous coals andlignitesProject FundingTotal project cost $105,700,000 100%DOE 43,125,000 41Participant 62,575,000 59Project ObjectiveTo demonstrate Rosebud SynCoal Partnership’s Advanced Coal Conversion Process (ACCP) to produceSynCoal®, a stable coal product having a moisture content

as low as 1%, sulfur content as low as 0.3%, and heatingvalue up to 12,000 Btu/lb.

SynCoal is a registered trademark of the Rosebud SynCoal Partnership.

Technology/Project DescriptionThe process demonstrated is an advanced thermal coalconversion process coupled with physical cleaning techniques to upgrade high-moisture, low-rank coals to produce a high-quality, low-sulfur fuel. The raw coal isscreened and fed to a vibratory fluidized-bed reactorwhere surface moisture is removed by heating with hotcombustion gas. Coal exists 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 cool

with an inert gas in a vibrcooled coal is sized and fair pressure and vibration ing much of the pyrite, froing the sulfur content of tgravity fractions are sent heavier fractions go to flutional ash removal.

The fines handling sy

that are produced throughfines are gathered by scredrag conveyors to a bulk fines are blended with the ton capacity bin until loadoff-site sales, or returned 
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels Project Status/AccomplishmentsThe ACCP facility was scheduled to complete demonstration operations in January 1999, but was granted a twoyear no-cost extension. The ACCP facility continues tooperate using a dedicated pneumatic feed system to supply SynCoal® to Montana Power’s 330 MWe Colstrip No.

2 under an 8-year contract. The ACCP facility has processed 2.0 million tons of raw coal to produce over 1.4million tons of SynCoal®. The SynCoal® is used by electric utilities and industrial facilities (primarily cement and

lime plants).

The demonstration unit can process 1,000 tons per

day of SynCoal® and is one-tenth the size of a commercial

facility. The ACCP facility takes advantage of existingmine infrastructure. Over a four-year period, 321,528 tonsof SynCoal® was burned at the 160-MWe J.E. Corette

plant in Billings, Montana. The testing involved bothhandling and combustion tests of dust stabilization enhancement (DSE; a dilute water-based suppressant)treated SynCoal® in a variety of blends. These blends

ranged from 15–85% SynCoal® with raw coal. Overall,

the results indicate that 50/50 blend of SynCoal®/raw coal

provides improved plant performance, including reducedSO2 emissions. The use of SynCoal® permitted

deslagging the boiler at full load, thereby eliminatingcostly ash shedding operations. The result was reducedgas flow resistance in the boiler and convection passage,which reduced fan horsepower and improved heat transferin the boiler, leading to a net increase in generation ofapproximately 3 MWe.

Three different feedstocks were tested at the ACCP

facility—North Dakota lignite, Knife River lignite, andAmax subbituminous coal. Approximately 190 tons ofthe SynCoal® product produced with the North Dakota

lignite was burned at the 250-MWe cyclone-fired MiltonR. Young Power Plant Unit No. 1 located near Center,North Dakota. This testing showed dramatic improvement in cyclone combustion, improved slag tapping, anda 13% reduction in boiler air flow requirement, whichreduced the auxiliary load from the forced draft and induced draft fans. In addition, boiler efficiency increasedfrom 82% to over 86% and the total gross heat rate improved by 123 Btu/kWh.

Commercial ApplicaWestern SynCoal Compand has exclusively licePartnership. The Rosebpartnership between Wesponsible for all activiti

The Rosebud SynC

potential to enhance the rank western subbituminmoisture, low-sulfur, higSynCoal® is a viable com

emission reduction requ

supplemental fuel for plrank coals because the Alow-sulfur raw coals wi

The ACCP has the 

low-sulfur, low-rank coareducing agents for manFurthermore, SynCoal® 

tion and provides a valu

Preaward Design and Construction Operation

1988 1989 1990 1991 1992 1993 1994 1999 2000 

12/88 9/90 6/92

Design completed 8/91

DOE selected project(CCT-I) 12/9/88

Cooperative agreement

awarded 9/21/90

Ground breaking/construction started 3/28/91NEPA process completed (EA) 3/27/91

Preoperational tests initiated 12/91

Construction completed 2/92

Environmental monitoring plan completed 4/7/92

Test operation initiated 6/92

**

Project compl

Operation completed 
144 Project Fact Sheets 

Coal Processing for Clean Fuels

Coal Preparation Technologies

Development of the CoalQuality ExpertTMProject completed.ParticipantsABB Combustion Engineering, Inc. andCQ Inc.Additional Team MembersBlack & Veatch—cofunder and software

developer

Electric Power Research Institute—cofunderThe Babcock & Wilcox Company—cofunder and

pilot-scale tester

Electric Power Technologies, Inc.—field testerUniversity of North Dakota, Energy and Environmental

Research Center—bench-scale tester

Alabama Power Company—hostMississippi Power Company—hostNew England Power Company—hostNorthern States Power Company—hostPublic Service Company of Oklahoma—hostLocationsGrand Forks, Grand Forks County, ND (bench tests)Windsor, Hartford County, CT (bench- and pilot-scale

tests)

Alliance, Columbiana County, OH (pilot-scale tests)Wilsonville, Shelby County, AL (Gatson, Unit No. 5)Gulfport, Harrison County, MS (Watson, Unit No. 4)Somerset, Bristol County, MA (Brayton Point,

Unit Nos. 2 and 3)

Bayport, Washington County, MN (King Station)Oologah, Rogers County, OK (Northeastern, Unit No. 4)

TechnologyCQ Inc.’s EPRI Coal Quality ExpertTM (CQETM) computer softwarePlant Capacity/ProductionFull-scale testing took place at six utility sites ranging insize from 250–880-MWe.CoalWide variety of coal blendsProject FundingTotal project cost $21,746,004 100%DOE 10,863,911 50Participants 10,882,093 50

Project ObjectiveThe objective of the projeindustry with a PC softwainexpensively evaluate thblending, and switching owhile producing the lowethe project was to (1) enhInformation System (CQIImpact Model (CQIMTM) effects of coal-cleaning oformance and (2) develop that allows accurate and dity impacts on total poweperformance.

Coal Quality Expert, CQE, CQIS, and CQIM are trademarks of theElectric Power Research Institute.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels Technology/Project DescriptionThe CQETM is a software tool that brings a new level ofsophistication to fuel decisions by integrating the systemwide impact of fuel purchase decisions on coal-firedpower plant performance, emissions, and power generation costs. CQETM can be used on a stand-alone computeror as a network application for utilities, coal producers,and equipment manufacturers to perform detailed coalimpact analyses. 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.Project SummaryBackgroundCQETM began with EPRI’s CQIMTM, developed for EPRIby Black & Veatch and introduced in 1989. CQIMTM was

endowed with a variety of capabilities, including evaluating Clean Air Act compliance strategies, evaluating bidson coal contracts, conducting test-burn planning andanalysis, and providing technical and economic analysesof plant operating strategies. CQETM, which combinesCQIMTM with other existing software and databases,extends the art of model-based fuel evaluation establishedby CQIMTM in three dimensions: new flexibility andapplication, advanced technical models and performancecorrelations, and advanced user interface and networkawareness.Algorithm DevelopmentData derived from bench-, pilot-, and full-scale testingwere used to develop the CQETM algorithms. Bench-scaletesting was performed at ABB Combustion Engineering’sfacilities in Windsor, Connecticut, and the University ofNorth Dakota’s Energy and Environmental ResearchCenter in Grand Forks, North Dakota. Pilot-scale testingwas performed at ABB Combustion Engineering’s facilities in Windsor, Connecticut, and Alliance, Ohio. The six

field test sites were Alab(880-MWe), WilsonvilleWatson, Unit No. 4 (250New England Power’s BMWe) and Unit No. 3 (6setts; Northern States PoBayport, Minnesota; and Oklahoma’s NortheasterOologah, Oklahoma.

The six large-scale 

baseline coal and an alteThe baseline coal was uperformance of the boileor cleaned coal of improboiler for the remaining 

The baseline and al

were burned in bench- asimilar conditions. The Inc. to determine what qproduced economically bench- and pilot-scale fa

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Operation

DOE selectedproject (CCT-I)12/9/88

12/88

Cooperative agreement awarded 6/14/90

NEPA process completed

(MTF) 4/27/90

Environmental monitoringplan completed 7/31/90

Operation initiated 8/90

Preaward

Development

6/90

Field testing completed 4/93

8/90

CQE R

CQE CD-ROM i
146 Project Fact Sheets 

bench-, pilot-, and full-scale facilities were evaluated andcorrelated to formulate algorithms used to developthe model.CQETM CapabilityThe PC-based program evaluates coal quality, transportation system options, performance issues, and alternativeemissions control strategies for utility power plants.CQETM is composed of technical tools to evaluateperformance issues, environmental models to evaluateemissions and regulatory issues, and economic models todetermine production cost components, including consumables (e.g., fuel, scrubber additives), waste disposal,operation and maintenance, replacement energy costs,and operational and maintenance costs for coal-cleaningprocesses, power production equipment, and emissionscontrol systems. CQETM has four main features:• Fuel Evaluator—Performs system-, plant-, or unitlevel fuel quality, economic, and technical assessments.

• Plant Engineer—Provides in-depth performance evaluations with a more focused scope than provided in the

Fuel Evaluator.

• Environmental Planner—Provides access to evaluation

and presentation capabilities of the Acid Rain Advisor.

• Coal-Cleaning Expert—Establishes the feasibility of

cleaning a coal, determines cleaning processes, andpredicts associated costs.

Software DescriptionCQETM includes more than 100 algorithms based on thedata generated in the six full-scale field test.

CQETM’s design philosophy underscores the importance of flexibility by modeling all important power plant

equipment and systems and their performance in realworld situations. This level of sophistication allows newapplications to be added by assembling a model of howobjects interact. Updated information records can bereadily shared among all affected users because CQETM isnetwork-aware, enabling users throughout an organizationto share data and results. The CQETM object-oriented

design, coupled withan object databasemanagement system,allows different viewsinto the same data.As a result, staff efficiency is enhancedwhen decisionsare made.

CQETM also can

be expanded withoutmajor revisions to thesystem. Object-oriented programmingallows new objects tobe added and oldobjects to be deletedor enhanced easily.

For example, if modeling respect to predicting boiland fouling), the internal provides these predictionOther objects affected by tion and disposal systemsneed to be altered; thus, tsystem is maintained.System RequirementsCQETM currently uses the developers are planning tplatform. CQETM can opsingle computer or on a nments for stand-alone ope42. Technical support is for licensed users.Commercial ApplicatiThe CQETM system is appgeneration plants and largthat burn pulverized coalsuppliers, environmental regulatory institutions, antional markets for CQETM Inc. and Black & Veatch.

EPRI owns the softw

EPRI members for their uers in the form of three tyand commercializer. CQ each signed commercializboth companies non-excluser’s licenses and to offeclude the use of CQETM sbeen licensed to use copiRain Advisor. Over 30 Uhave CQETM through theiare pending with several foreign utilities to license 

Item Minimum Preferred

Hardware speed 486 PC, 33 Mhz Pentium PC, market stockRAM 16 MB 32 MB

Disk space 200 MB 1 GBMonitor SVGA color SVGA colorGraphics card Capable of 1024x768 mode Capable of 1024x768 modeExternal drives 1.44 MB 3.5-inch; CD-ROM 1.44 MB 3.5-inch; CD-ROMMouse Required RequiredKeyboard Required Required

Printer Access to high-speed printer Access to laser printerOperating system OS/2 Version 2.0 OS/2 WARP (3.0)

Exhibit 42

CQETM Stand-Alone System Requirements
Coal Processing for Clean Fuels 

The CQETM team has a Home Page on the World

Wide Web (http://www.fuels.bv.com:80/cqe/cqe.htm) andthe EPRI Fuels Web Server to promote CQETM, facilitatecommunications between CQETM developers and users,and eventually allow software updates to be distributedover the Internet. It also was developed to provide an online updatable user’s manual. The Home Page also helpsattract the interest of international utilities andconsulting firms.

CQETM was recognized by former Energy Secretary

Hazel O’Leary and EPRI President Richard Balzhiser in1996 as the best of nine DOE/EPRI cost-shared utilityresearch and development projects under the “SustainableElectric Partnership” program.ContactsClark D. Harrison, President, (724) 479-3503

CQ Inc.160 Quality Center Rd.Homer City, PA 15748

Douglas Archer, DOE/HQ, (301) 903-9443Joseph B. Renk, FETC, (412) 892-6249References• 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. Departmentof Energy. May 1990. (Available from NTIS asDE90010381.)

CQETM, a PC-based software tool, can be used to determine the

complete costs of various fuel options by seamlessly integrating the effects offuel purchase decisions on power plant performance, emissions, and powergeneration costs. Portions of the CQETM User’s Manual are available on theInternet.
148 Project Fact Sheets 

Coal Processing for Clean Fuels

Mild Gasification

ENCOAL® Mild Coal

Gasification Project

Project completed.ParticipantENCOALCorporation (a wholly owned subsidiary of

Bluegrass Coal Development Company)

Additional Team MembersBluegrass Coal Development Company (a wholly owned

subsidiary of AEI Resources, Inc.)—cofunder

SGI International—technology developer, owner,

licensor

Triton Coal Company (a wholly owned subsidiary of

Vulcan Coal Company)— host

LocationNear Gillette, Campbell County, WY (Triton Coal

Company’s Buckskin Mine site)

TechnologySGI International’s Liquids-From-Coal (LFC®) process

CoalLow-sulfur Powder River Basin (PRB) subbituminouscoal, 0.45% sulfurPlant Capacity/Production1,000 tons/day of subbituminous coal feedProject FundingTotal project cost $90,664,000 100%DOE 45,332,000 50Participant 45,332,000 50Project ObjectiveTo demonstrate the integrated operation of a number ofnovel processing steps to produce two higher-value fuelforms from mild gasification of low-sulfur subbitumiENCOAL, LFC, CDL, and PDF are registered trademarks of SGI and

Bluegrass.

nous coal and to provide sufficient products for potentialend users to conduct burn tests.Technology/Project DescriptionCoal is fed into a rotary grate dryer where it is heated toreduce moisture. The temperature is controlled so that nosignificant amounts of methane, CO2, or CO are released.

The solids are then fed to the pyrolyzer, where the temperature is about 1,000 °F, and all remaining water isremoved. A chemical reaction releases the volatile gaseous material. Solids exiting the pyrolyzer are quenchedto stop the pyrolysis reactions.

In the original process, the quench table solids were

further cooled in a rotary cooler and transferred to a surgebin. A single 50% flow rate vibrating fluidized-bed(VFB) was added to stabilize the Process-Derived Fuel

(PDF®) with respect to oxpartially-cooled, pyrolyzecontaining a controlled amdative deactivation,” a reasites in the particles reducous ignition.

Following the VFB, 

atmospheric temperature where water is added to redust suppressant is added 

bin. The hot gas produced a cyclone for removal of in a quench column to stotions and to condense the 
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Coal Processing for Clean Fuels 

Design and Construction Operation

1988 1989 1990 1991 1992 1993 1994 1995 1996 

Cooperative agreement awarded 9/17/90

DOEselectedproject(CCT-III)12/19/89

NEPA process completed (EA) 8/1/90

Ground breaking/construction started 10/26/90

Operation initiated 7/92

Construction completed 6/92

Preoperational tests initiated 4/92

Design completed 7/91

Environmental monitoring plan completed 5/29/92

12/89 9/90 7/92

Preaward

Operation 

Results SummaryEnvironmental• The PDF® contains 0.36% sulfur with a heat content of

11,100 Btu/lb (compared to 0.45% sulfur and 8,300Btu/lb for the feed coal).

• The CDL® contains 0.6% sulfur and 140,000 Btu/gal

(compared to 0.8% sulfur and 150,000 Btu/gal for No.6 fuel oil).

• In utility applications, PDF® enabled reduction in SO2

emissions, reduction in NOx emissions (through flame

stabilization), and maintenance of boiler rated capacitywith fewer mills in service.

• LFC® products contained no toxins in concentrations

anywhere close to federal limits.

Operational• Steady state operation exceeding 90% availability was

achieved for extended periods for the entire plant(numerous runs exceeded 120 days duration).

• The LFC® process consistently produced 250 tons/day

of PDF® and 250 barrels/day of CDL® from 500 tons/

day of run-of-mine PRB coal.

• Integrated operation of the LFC® process components

over five years has provided a comprehensive databasefor evaluation and design of a commercial unit.

• Over 83,500 tons of PDF® were shipped via 17 unit

trains and one truck shipment to seven customers insix states. Shipments included 100% PDF® and blends

from 14–94% PDF®.

• PDF®, alone and in blends, demonstrated excellent

combustion characteristics in utility applications,providing heating values comparable to bituminouscoal, more reactivity than bituminous coal, and astable flame.

• The low-volatile PDF® also showed promise as a reductant in direct iron reducing testing and also as a

blast furnace injectant in place of coke.

• Nearly 5 million gallons of CDL® were produced and

shipped to eight customers in seven states.

• CDL® demonstrated 

sulfur No. 6 fuel oil lower sulfur content. content, however, ma

chemical feedstock.

Economic• A commercial plant 

ric-ton/day would co(2001 year dollars) to and maintenance cos
150 Project Fact Sheets 

Pre-VFB Post-VFB

1992 1993 1994 1995 1996 

Raw Coal Feed (tons) 5,200 12,400 67,500 65,800 68,000 PDF® Produced (tons) 2,200 4,900 31,700 28,600 33,300 

PDF® Sold (tons) 0 0 23,700 19,100 32,700 CDL® Produced (bbl) 2,600 6,600 28,000 31,700 32,500 Hours on Line 314 980 4,300 3,400 3,600 Average Length ofRuns (Days) 2 8 26 38 44 

Exhibit 43

ENCOAL Production

1Through June 1997.

Project SummaryOperational PerformanceThe LFC® facility operated for more than 15,000 hours

over a five year period. Steady-state operation was maintained for much of the demonstration with availabilitiesof 90 percent for extended periods. The length of operation and volume of production proved the soundness anddurability of the process.

Exhibit 43 summarizes ENCOAL’s production

history. By the end of the demonstration, over 83,500tons of PDF® were shipped via 17 unit trains and one

truck shipment to seven customers in six states. Shipments included 100% PDF® and blends from 14–94 percent PDF®. Over 5 million gallons of CDL® were produced and shipped to eight customers in seven states.

PDF® Product. As with most demonstrations, however, success required overcoming many challenges. The

most difficult challenge had to do with stability of thePDF® product, which had to be overcome to achieve

market acceptance.

In June 1993, efforts ceased in trying to correct persistent PDF® stability problems within the bounds of the

original plant design. The rotary cooler failed to providethe deactivation necessary to quell spontaneous ignitionof PDF®. It was concluded that a separate, sealed vessel

was needed for product deactivation. A search for asuitable design led to adoption of a vibrating fluidizedbed (VFB). A 500 ton/day VFB was installed betweenthe quench table and rotary cooler. (Installation of a second 500 ton/day VFB was planned but neverimplemented.)

Although the VFB enhanced deactivation, the PDF

still required “finishing” to achieve stabilization. Extensive study revealed that more oxygen was needed fordeactivation. Two courses of action were pursued: (1)development of interim measures to finish deactivationexternal to the plant, enabling immediate PDF® shipment

for test burns; and (2) development of an in-plant process

for finishing, eliminating product quality and labor penalties for external finishing.

“Pile layering” was the primary external PDF® finishing measure adopted. However, PDF® quality becomes

somewhat impaired by impacting size, moisture andash content.

Pursuit of a finishing process step resulted in establishment of a stabilization task force composed of private

sector and government engineers and scientists. Theoutcome was construction and testing of a Pilot Air Stabilization System (PASS) to complete the oxidative deactivation of PDF®. PASS controls temperature and humidity

during forced oxidation. The data obtained were used todevelop specifications and design requirements for a fullscale, 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 insta

The pour point ranged fropoint averaged 230 oF, boWater content was down tent was 2–4 percent. Imconsistent operation and lhigher pyrolysis flow ratewater seal.Environmental PerforPDF® Product. PDF® off

Powder River Basin coal In fact, the LFC® process 

sulfur, making the PDF® p

parent coal on a Btu basisin ash, PDF® ash levels re

ing, even though the ash lfrom one ton of ROM coa

Dust emissions were 

dust suppressant (MK) w

the surface as it leaves the 

narrower particle size dist
Coal Processing for Clean Fuels 

a larger fines content but fewer particles in the fugitivedust range than ROM coal.

ENCOAL’s test burn shipments became international

when Japan’s Electric Power Development Company(EPDC) evaluated six metric tons of PDF® in 1994. The

EPDC, which must approve all fuels being considered forelectric power generation in Japan, found PDF® acceptable for use in Japanese utility boilers.

In October 1996, instrumented combustion testing

was conducted at the Indiana-Kentucky ElectricCooperative’s (IKEC) Clifty Creek Station, Unit #3.Important findings included the following:• Full generating capacity using PDF® was possible with

one mill out of service, which was not possible on thebaseline fuel and a source of concern. Operation onPDF® afforded time to perform mill maintenance and

calibration without losing capacity or revenues, increasing capacity factor and availability and decreasing operating and maintenance costs.

• NOx emissions were reduced by 20 percent due to high

PDF® reactivity, resulting in almost immediate ignition

upon leaving the burner coal nozzle. Furthermore,PDF® sustained effective combustion (maintaining lowloss on ignition) with very low excess oxygen, whichis conducive to low NOx emissions.

• PDF® use precipitated increased ash deposits in the

convective pass that were wetter than those resultingfrom baseline coal use, requiring increasedsootblowing to control build-up.

CDL® Product. The CDL® liquid product is a low-sulfur,

highly aromatic, heavy liquid hydrocarbon. CDL® fuel

characteristics are similar to a low-sulfur No. 6 fuel oil,except that the sulfur content is significantly less. Itsmarket potential as a straight industrial residual fuel,however, appears limited. The market for CDL® as a fuel

never materialized and CDL® has limited application as a

blend for high sulfur residual fuels due to incompatibilityof the aromatic CDL® with many straight-chain hydrocarbon distillates.

A determination was made that a centrifuge was

needed to reduce solids retention (tests validated a 90percent removal capability); and an optimum slate ofupgraded products was identified. The upgraded productswere: (1) crude cresylic acid (2) pitch, (3) refinery feedstock (low-oxygen middle distillate), and (4) oxygenatedmiddle distillate (industrial fuel).EconomicThe “base case” for economics of a commercial plant isthe 15,000-metric-ton/day, three-unit North RochelleLFC® plant, the commercial scale plant proposed by

ENCOAL, with an independent 80-MW cogenerationunit, and no synthetic fuel tax credit (29c tax credit). It isassumed that the cogeneration unit is owned and operatedby an independent third-party. The capital cost for a fullscale three module LFC® plant is $475 million.

Economic benefits from an LFC® commercial plant

are derived from the margin in value between a raw,unprocessed coal and the upgraded products, making anLFC® plant dependent on the cost of feed coal. In fact,

this is the largest single operating cost item. The totalestimated operating cost is $9.00/ton of feed coal including the cost of feed coal, chemical supplies, maintenance,and labor.Commercial ApplicationsIn a commercial application, CDL® would be upgraded to

cresylic acid, pitch, refinery feedstock, and oxygenatedmiddle distillate. Oxygenated middle distillate, the lowest value byproduct, would be used in lieu of natural gasas a make-up fuel for the process (30 percent of the process 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 methodsand as a reductant in direct reduced iron processes.

Partners in the ENCOAL® project completed five

detailed commercial feasibility studies over the course of

the demonstration and ssian, one Russian, and thas received an Industriity Construction Permit.ContactsBrent A. Knottnerus, (3

ENCOAL CorporatioP.O. Box 3038Gillette, WY 82717(307) 682-7938 (fax)

Douglas Archer, DOE/HDouglas M. Jewell, FETReferences• ENCOAL® Mild Gas

Feasibility Study. Utember 1997. Reporfrom NTIS as DE980

• Final Design Modifi

of Energy. Septembe27339-5797. (Availa

• ENCOAL® Mild Gas

Project Final Report5798. U.S. Departm(Available from NTI

• Johnson, S.A., and K

PDF® Test Burn at C

ment of Energy Topic

• ENCOAL® Mild Coa

Project Public Desigport No. DOE/MC/2tion. December 1994DE95009711.)
Industrial Applications 

Industrial Applications
154 Project Fact Sheets 

Industrial ApplicationsBlast Furnace Granular-CoalInjection SystemDemonstration ProjectParticipantBethlehem Steel CorporationAdditional Team MembersBritish Steel Consultants Overseas Services, Inc.

(marketing arm of British Steel Corporation)—technology owner

CPC-Macawber, Ltd. (formerly named Simon-Macawber,

Ltd.)—equipment supplier (world rights to sublicensetechnology)

Fluor Daniel, Inc.—architect and engineerATSI, Inc.—injection equipment engineer (North

America technology licensee)

LocationBurns Harbor, Porter County, IN (Bethlehem Steel’sBurns Harbor Plant, Blast Furnace Units C and D)CoalEastern bituminous, 0.8–2.8% sulfur; andwestern subbituminous, 0.4–0.9% sulfurTechnologyBritish Steel and CPC-Macawber blast furnace granularcoal injection (BFGCI) processPlant Capacity/Production7,000 net tons of hot metal (NTHM)/day (each blastfurnace)Project FundingTotal project cost $194,301,790 100%DOE 31,824,118 16Participant 162,477,672 84Project ObjectiveTo demonstrate that existing iron-making blast furnacescan be retrofitted with blast furnace granular-coal injection technology; to demonstrate sustained operation with a variety of coal particle sizes, coal injection rates, and coal types; and to assess the interactive nature of these parameters. Technology/Project Description In the BFGCI process, either granular or pulverized coal is injected into the blast furnace in place of natural gas or oil as a blast furnace fuel supplement. The coal, along with heated air, is blown into the barrel-shaped section in the lower part of the blast furnace through passages called tuyeres, which creates swept zones in the furnace called raceways. The size of a raceway is important and is de- pendent upon many factors, including temperature. Low- ering 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 n

raceway temperatures. Igas, the coal injected thrthe primary blast furnace agent), on approximately BFGCI technology has spollutant emissions and tion because coke produsions of NOx, SO2, and a

to 40% of the coke requi

Emissions generate

remain virtually unchangexiting the blast furnace Sulfur from the coal is reand bound up in the slag
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Industrial Applications 

1989 1990 1991 1993 1994 1995 1996 1997 1998 

Two high-capacity blast furnaces, Units C and D at

Bethlehem Steel’s Burns Harbor Plant, were retrofittedwith BFGCI technology. Each unit has a productioncapacity of 7,000 NTHM/day. The two units use about2,800 tons/day of coal during full operation. Tests willinclude eastern bituminous coals with sulfur content of0.8–2.8% and a western subbituminous coal having0.4–0.9%.Project Status/AccomplishmentsEarly trials comparing high- and low-volatile coals asinjectant showed that low-volatile coal replaces morecoke and results in better blast furnace operation thanhigh-volatile coal. The replacement ratio was 0.96pounds of coke replaced for every pound of low-volatilecoal used. A major conclusion of the early trials was thatgranular-coal injection performs very well on large blastfurnaces. The low-volatile coals used were Buchanan andVirginia Pocahantas coals (different mines, but sameseam and similar properties).

Further trials were conducted on the effect of higher

coal ash content on the furnace operation. The baseline

coal was the Virginia Pocahantas coal with high carbonand relatively low ash content. Three trials were runvarying the ash content while keeping all otherparameters constant.

The high ash trials revealed that (1) furnace permeability was not changed and no deleterious effect was

experienced in the raceway, (2) furnace blast pressure andwind volume were maintained at the base conditionsduring the trial, (3) furnace production rates were up asdelay periods declined during the trial, and (4) hot metalsilicon and sulfur content and variability were about thesame during all three periods. Corrected coke rates calculated from the trial results reveal that there is a coke ratedisadvantage of 3 lb/NTHM for each 1% increase of ashin the injection coal at an injection rate of 260 lb/NTHM.

Western coal trials were completed using Colorado

Oxbow high-volatile granular and pulverized coal. Trialsvalidated that low-volatile coal replaces more coke thanhigh-volatile coal. The high-volatile coal required 31.4kWh/ton to pulverize and 19.6 kWh/ton to granulate,

Preaward

DOE selectedproject (CCT-III)12/19/89

12/89 11/90

Cooperative agreement awarded 11/26/90

Design and Construction Operation

Projec

showing a 40% reductioversus pulverization.Commercial ApplicaBFGCI technology can blast furnaces. The techany rank coal commercithat has a moisture contenvironmental impacts oprimarily indirect and coemissions resulting from quirements.

The BFGCI techno

British Steel and CPC-Mgranted exclusive rights worldwide to CPC-Macthe right to sublicense Btions through-out the woMacawber have recently Steel’s Fairfield blast fu

Operatio

**

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
156 Project Fact Sheets 

Technology/Project DescriptionThe HIsmelt® process is based on producing hot metal

and slag from iron ore fines and non-coking coals. Theheart of the process is producing sufficient heat and maintaining high heat transfer efficiency in the post combustion zone above the reaction zone to reduce and smeltiron oxides. Tests have consistently demonstrated 60%post-combustion levels (degree of post combustion attained) with 90% heat transfer efficiency.

The HIsmelt® process uses a vertical smelt reduction

reactor, which is a closed molten bath vessel, into whichiron ore fines, coal, and fluxes are injected. The coal,which can have a wide range of composition, is injectedinto the bath where carbon is rapidly dissolved. Thedissolved carbon reacts with oxygen (from the injectediron ore) to form CO and metallic iron. Injection gases

Industrial ApplicationsClean Power from IntegratedCoal/Ore Reduction(CPICORTM)ParticipantCPICORTM Management Company, L.L.C. (a limitedliability company composed of subsidiaries of the GenevaSteel Company)Additional Team MembersGeneva Steel Company—cofunder and host; constructor

and operator of unit

LocationVineyard, Utah County, UT (Geneva Steel Company’smill)TechnologyHIsmelt® direct ironmaking process

Plant Capacity/Production3,300 tons/day liquid iron productionCoalBituminous, 0.5% sulfurProject FundingTotal project cost $1,065,805,000 100%DOE 149,469,242 14Participant 916,335,758 86Project ObjectiveTo demonstrate the integration of a direct iron-makingprocess with the co-production of electricity using variousU.S. coals in an efficient and environmentallyresponsible manner.

HIsmelt is a registered trademark of HIsmelt Corporation Pty Limited.CPICOR is a trademark of the CPICORTM Management Company, L.L.C.

and evolved CO entrain amolten iron upward into t

The iron reduction re

endothermic; therefore, aand returned to the bath to and maintain an acceptabadditional heat is generateand hydrogen from the bablast entering through the absorbed by the metal and the bath as the droplets delets in contact with the gaabsorb heat, but are shroucending reducing gases (Ccarbon, prevent unaccepta
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Industrial Applications 

1993 1997 2000 1994 1996 2001 2002 2003 2004 

DOE selected project(CCT-V) 5/4/93

5/93

Preaward

Cooperative agreement awarded 10/11/96

NEPA process completed 12/00*

Construction started 12/00*

Design and Construction

Operation initiated 5/03*Construction completed 5/0

Operatio

re

The molten iron collects in the bottom of the bath

and is continuously tapped from the reactor through afore-hearth, which maintains a constant level of iron inthe reactor. Slag, which is periodically tapped through aconventional blast furnace-type tap hole, is used to coatand control the internal cooling system and reduce theheat loss.

Reacted gases, mainly N2, CO2, CO, H2, and water

vapor, exit the vessel. After scrubbing the reacted gases,the cleaned gases will be combusted to produce 170-MWeof power. The cleaned gases can also be used to pre-heatand partially reduce the incoming iron ore.Project Status/AccomplishmentsThe cooperative agreement was awarded on October 11,1996. CPICORTM analyzed the global assortment of newdirect ironmaking technologies to determine which technology would be most adaptable to western U.S. coalsand raw materials. Originally, the COREX® process

appeared suitable for using Geneva’s local raw materials;however, lack of COREX® plant data on 100% raw coals

and ores prevented its application in this demonstration.

Thus, CPICORTM chose to examine alternatives. Theprocesses evaluated included: AISI direct ironmaking,DIOS, Romelt, Tecnored, Cyclonic Smelter, andHIsmelt®. The HIsmelt® process appears to offer good

economic and operational potential, as well as the prospect of rapid commercialization. CPICORTM has completed testing of two U.S. coals at the HIsmelt® pilot plant

near Perth, Australia.

On February 1, 1999, Geneva Steel Company

(CPICORTM Management Company’s parent corporation)

filed a voluntary petition for bankruptcy under Chapter 11of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the District of Utah. Geneva Steel intends to emerge from Chapter 11 with a restructuredbalance sheet that will enable full participation in thisdemonstration project. Other developments include thefollowing: DOE is reviewing final drafts of license andmarketing agreements between HIsmelt® and CPICORTM;

DOE has established a NEPA Team to review the Environmental Information Volume and begin the NEPAscoping process; baseline air monitoring is in progress.

Commercial ApplicaThe HIsmelt® technolog

ing blast furnace and cotional potential to produOf the existing 79 coke of age or older and are drebuilds. There are abowhich have been operatsome originally installed 

represents a viable optioironmaking technology.

The HIsmelt® proce

Two pilot plants have beand one in Kwinana, Wetest work in Australia, thoperational control paracomplete computer modoped and proven. The gcommercial plant by ear

**

Environmental monitoring

plan completed 9/02*

5/03

**

10/96 
158 Project Fact Sheets 

combustor was designed ash and sorbent fed to the control, the combustor is combustion taking place ithe combustor is attached

limestone into the combuthe combustor forces the where it can be collected operating conditions, the tion of vitrified coal sulfution into the boiler providcapacity.

In Coal Tech’s demo

cooled, cyclone coal com23 x 106 Btu/hr, oil-desig

Tampella Power CorporatWilliamsport, Pennsylvan

Technology/Project DescriptionCoal Tech’s horizontal cyclone combustor is internallylined with an air-cooled ceramic that is air-cooled. Pulverized coal, air, and sorbent are injected tangentiallytoward the wall through tubes in the annular region of thecombustor to cause cyclonic action. In this manner, coalparticle combustion takes place in a swirling flame in aregion favorable to particle retention in the combustor.Secondary air is used to adjust the overall combustorstoichiometry. Tertiary air is injected at the combustor/boiler interface. The ceramic liner is cooled by the secondary air and maintained at a temperature high enoughto keep the slag in a liquid, free-flowing state. The secondary air is preheated by the combustor walls to attainefficient combustion of the coal particles in the fuel-richcombustor. Fine coal pulverization allows combustion ofmost of the coal particles near the cyclone wall. The

Industrial ApplicationsAdvanced CycloneCombustor with InternalSulfur, Nitrogen, and AshControlProject completed.ParticipantCoal Tech CorporationAdditional Team MembersCommonwealth of Pennsylvania, Energy Development

Authority—cofunder

Pennsylvania Power and Light Company—supplier of

test coals

Tampella Power Corporation—hostLocationWilliamsport, Lycoming County, PA (Tampella PowerCorporation’s boiler manufacturing plant)TechnologyCoal Tech’s advanced, air-cooled, slagging combustorPlant Capacity/Production23 x 106 Btu/hr of steam

CoalPennsylvania bituminous, 1.0–3.3% sulfurProject FundingTotal project cost $984,394 100%DOE 490,149 50Participant 494,245 50Project ObjectiveTo demonstrate that an advanced cyclone combustor canbe retrofitted to an industrial boiler and that it can simultaneously remove up to 90% of the SO2 and 90–95% of

the ash within the combustor and reduce NO

x

 to

100 ppm.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Industrial Applications 

1986 1989 1990 1987 1988 1991 1992 1993 1994 

Preaward Operation

7/86 3/87 11/87

Design and Construction

DOE selected project (CCT-I) 7/24/86

Design completed 7/87Ground breaking/construction started 7/87

Cooperative agreement awarded 3/20/87NEPA process completed (MTF) 3/26/87

Environmental monitoring plan completed 9/22/87

Construction completed 11/87Operation initiated 11/87

Operation

completed 5/90

Results SummaryEnvironmental• SO2 removal efficiencies of over 80% were achieved

with sorbent injection in the furnace at variouscalcium-to-sulfur (Ca/S) molar ratios.

• SO2 removal efficiencies up to 58% were achieved

with sorbent injection in the combustor at a Ca/Smolar ratio of 2.0.

• A maximum of 1/3 of the coal’s sulfur was retained in

the dry ash removed from the combustor (as slag) andfurnace hearth.

• At most, 11% of the coal’s sulfur was retained in the

slag rejected through the combustor’s slag tap.

• NO

x emissions were reduced to 184 ppm by the combustor and furnace and to 160 ppm with the addition

of a wet particulate scrubber.

• Combustor slag was essentially inert.

• Ash/sorbent retention in the combustor as slag averaged 72% and ranged from 55–90%. Under more 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 technolo

tion criteria, economdemonstration. Howthat incremental capicombustor in lieu of $100–$200/kW.

9/91

Project completed/final report issued 9/91
160 Project Fact Sheets 

The slagging combustor, associated piping, and control panel for

Coal Tech’s advanced ceramic-lined slagging combustor are shown.

Project SummaryThe novel features of Coal Tech’s patentedceramic-lined, slagging cyclone combustorincluded its air-cooled walls and environmental control of NOx, SO2, and solid waste emissions. Air cooling took place in a very compact combustor, which could be retrofitted to

a wide range of industrial and utility boilerdesigns without disturbing the boiler’s watersteam circuit. In this technology, NOx reduction was achieved by staged combustion, and

SO2 was captured by injection of limestone

into the combustor and/or boiler. Critical tocombustor performance was removal of ash,as slag, which would otherwise erode boilertubes. This was particularly important in oilfurnace retrofits where tube spacing is tight(made possible by the low-ash content of oilbased fuels).

The test effort consisted of 800 hours of operation,

including five individual tests, each of four days duration.An additional 100 hours of testing was performed as partof a separate ash vitrification test. Test results obtainedduring operation of the combustor indicated that CoalTech attained most of the objectives contained in thecooperative agreement. About eight different Pennsylvania bituminous coals with sulfur contents ranging from1.0–3.3% and volatile matter contents ranging from 19–37% were tested.Environmental PerformanceA maximum of over 80% SO2 reduction measured at the

boiler outlet stack was achieved using sorbent injection inthe furnace at various Ca/S molar ratios. A maximumSO2 reduction of 58% was measured at the stack with

limestone injection into the combustor at a Ca/S molarratio of 2. A maximum of 1/3 of the coal’s sulfur wasretained in the dry ash removed from the combustor andfurnace hearths, and as much as 11% of the coal’s sulfur

was retained in the slag rejected through the slag tap.Additional sulfur retention in the slag is possible by increasing the slag flow rate and further improving fuel-richcombustion and sorbent-gas mixing.

With fuel-rich operation of the combustor, a threefourths reduction in measured boiler outlet stack NOx was

obtained, corresponding to 184 ppm. An additional 5–10% reduction was obtained by the action of the wetparticulate scrubber, resulting in atmospheric NOx emissions as low as 160 ppm.

All the slag removed from the combustor produced

trace metal leachates well below EPA’s DrinkingWater Standard.

Total ash/sorbent retention as slag in the combustor

under efficient combustion operating conditions averaged72% and ranged from 55–90%. Under more fuel-leanconditions, the slag retention averaged 80%. In post-CCTproject tests on flyash vitrification in the combustor,modifications to the solids injection system and increasesin the slag flow rate produced substantial increases in theslag retention rate. To meet local stack particulate emission standards, a wet ven

installed at the boiler outlOperational PerformaCombustion efficiencies eating procedures were ach6 x 106 Btu/hr from a pea

turndown) was achieved. ing the tests was around 2

combustor was designed 

boiler was thermally rated 

situation resulted from fafor the boiler. In fact, ducooling, even 20 x 106 Bt

of the testing was conduc

Different sections of 

materials requirements. Stion were identified. Alsooperational procedures w

als durability. As an examprocedures, such as changperature, it was possible tfractory wall thickness wibustion rather than by addwalls.The combustor’s totaof the CCT project was abapproximately 100 hours vitrification tests projectsthird was with coal; abousumed. Developing proper cwas also an objective. Noproperly operating an air-but the entire operating dcomputer-controlled systeoperation.
Industrial Applications 

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 thconveyor, is essentially an inert glassy by-product with value in the construction industry aaggregate or in the manufacture of abrasives.

Commercial ApplicationsIn conclusion, the goal of this project was to validate theperformance of the air-cooled combustor at a commercialscale. While the combustor was not yet fully ready forsale with commercial guarantees, it was believed to havecommercial potential. Subsequent work was undertaken,which has brought the technology close to commercialintroduction.ContactsBert Zauderer, President, (610) 667-0442

Coal Tech Corp.P.O. Box 154Merion Station, PA 19066coaltechbz@compuserve.com

William E. Fernald, DOE/HQ, (301) 903-9448Arthur L. Baldwin, FETC, (412) 892-6011References• The Coal Tech Advanced Cyclone Combustor Demonstration Project—A DOE Assessment. Report No.

DOE/PC/79799-T1. U.S. Department of Energy. May1993. (Available from NTIS as DE93017043.)

• The Demonstration of an Advanced Cyclone Coal

Combustor, with Internal Sulfur, Nitrogen, and AshControl for the Conversion of a 23 MMBtu/Hour OilFired Boiler to Pulverized Coal; Vol. 1: Final Technical Report; Vol. 2: Appendixes I–V; Vol. 3: AppendixVI. Coal Tech Corporation. August 1991. (Availablefrom NTIS as DE92002587 and DE92002588.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Advanced Cyclone Combustorwith Internal Sulfur, Nitrogen, and Ash Control. Coal

Tech Corporation. Report No. DOE/FE-0077. U.S.Department of Energy. February 1987. (Availablefrom NTIS as DE87005804.)
162 Project Fact Sheets 

Industrial ApplicationsCement Kiln Flue GasRecovery ScrubberProject completed.ParticipantPassamaquoddy TribeAdditional Team MembersDragon Products Company—project manager and hostHPD, Incorporated—designer and fabricator of tanks and

heat exchanger

Cianbro Corporation—constructorLocationThomaston, Knox County, ME (Dragon ProductsCompany’s coal-fired cement kiln)TechnologyPassamaquoddy Technology Recovery ScrubberTMPlant Capacity/Production1,450 tons/day of cement; 250,000 scfm of kiln gas; andup to 274 tons/day of coalCoalPennsylvania bituminous, 2.5–3.0% sulfurProject FundingTotal project cost $17,800,000 100%DOE 5,982,592 34Participant 11,817,408 66Project ObjectiveTo retrofit and demonstrate a full-scale industrial scrubberand waste recovery system for a coal-burning wet processcement kiln using waste dust as the reagent to accomplish90–95% SO2 reduction using high-sulfur eastern coals;

and to produce a commercial by-product, potassiumbased fertilizer by-products.

Technology/Project DescriptionThe Passamaquoddy Technology Recovery ScrubberTMuses cement kiln dust (CKD), an alkaline-rich (potassium)waste, to react with the acidic flue gas. This CKD, representing about 10% of the cement feedstock otherwise lostas waste, is formed into a water-based slurry and mixedwith the flue gas as the slurry passes over a perforatedtray that enables the flue gas to percolate through theslurry. The SO2 in the flue gas reacts with the potassium

to form potassium sulfate, which stays in solution andremains in the liquid as the slurry undergoes separationinto liquid and solid fractions. The solid fraction, in thickened slurry form and freed of the potassium and otheralkali constituents, is returned to the kiln as feedstock (itis the alkali content that makes the CKD unusable asfeedstock). No dewatering is necessary for the wet process used at the Dragon P

tion is passed to a crystallflue gas to evaporate the walkali metal salts. A recupgas temperature to prevenuse of low-cost fiberglass provides much of the proof exhaust gas moisture. The Passamaquoddy berTM was constructed at cement plant in Thomastoapproximately 450,000 towas developed by the Pasit was seeking ways to soresulted from the need to ment-making process. Passamaquoddy Technology Recovery Scrubber is a trademark of the Passamaquoddy Tribe.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Industrial Applications Results SummaryEnvironmental• The SO2 removal efficiency averaged 94.6% during

the last several months of operation and 89.2% for theentire operating period.

• The NO

x removal efficiency averaged nearly 25%

during the last several months of operation and 18.8%for the entire operating period.

• All of the 250-ton/day CKD waste produced by the

plant was renovated and reused as feedstock. Thisresulted in reducing the raw feedstock requirement by10% and eliminating solid waste disposal costs.

• Particulate emission rates of 0.005–0.007 gr/scf, about

1/10 that allowed for cement kilns, were achieved withdust loadings of approximately0.04 gr/scf.

• Pilot testing conducted at U.S. Environmental Protection Agency laboratories under Passamaquoddy Technology, L.P. sponsorship showed 98% HCl removal.

• On three different runs, VOC (as represented by alphapinene) removal efficiencies of 72.3, 83.1, and 74.5%

were achieved.

• A reduction of approximately 2% in CO2 emissions

was realized through recycling of the CKD.

Operational• During the last operating interval, April to September

1993, recovery scrubber availability (discounting hostsite downtime) steadily increased from 65% in April1993 to 99.5% in July 1993.

Economic• Capital costs are approximately $10,090,000 (1990 $)

for a recovery scrubberto control emissions from a

450,000-ton/yr wet process plant, with a simple payback estimated in 3.1 years. Operating and maintenance costs, estimated at $500,000/yr, plus capital andinterest costs, are generally offset by avoided costsassociated with fuel, feedstock, and waste disposal andwith revenues from the sale of fertilizer.

1988 1991 1992 1989 1990 1993 1994 1995 1996 

Preaward Design and Construction

9/88 8/91

Operation

DOEselectedproject(CCT-II)9/28/88

12/89

Design completed 4/90

Environmental monitoring plancompleted 3/26/90

Operation initiated 8/91

Construction completed 5/91Preoperational tests initiated 5/91

NEPA process completed (EA) 2/16/90

Cooperative agreement awarded 12/20/89

Project SummarThe Passamaquoddy Teca unique process that acparticulate control througas and a potassium-rich dust. Flue gas passes tha special sieve tray. Thi

late capture, some NOx 

the potassium (an unwaallow the slurry to be rement kiln dust, exhaust wastewater are the only cement kiln dust, potassexhaust gas, and distilleputs. There is no waste

The scrubber was e

ing intervals dictated by nance and inventory and (within these basic inter

2/94Project completed/final report issued 2/94 Construction started 6/89 Operation completed 9/93
164 Project Fact Sheets 

Exhibit 44

Summary of Emissions and Removal Eff

Operating Operating Inlet (lb/hr) Outlet (lb/hr) Period Time (hr) SO2 NOx SO2 NOx 1 211 73 320 10 279 2 476 71 284 11 260 3 464 87 292 13 251 4 259 131 252 16 165 5 304 245 293 28 243 6 379 222 265 28 208 7 328 281 345 28 244 8 301 124 278 10 188 9 314 47 240 7 194 10 402 41 244 6 218 11 460 36 315 6 267 12 549 57 333 2 291 13 464 86 288 4 223 14 405 124 274 9 199 Total operating time 5,316Weighted Average 109 289 12 234 

foreseen host-plant maintenance and repairs and a depressed cement market. Over the period August 1991 toSeptember 1993, more than 5,300 hours was logged,1,400 hours in the first operating interval, 1,300 hours inthe second interval, and 2,600 hours in the third interval.Sulfur loadings varied significantly over the operatingperiods due to variations in feedstock and operatingconditions.Operational PerformanceSeveral design problems were discovered and correctedduring start-up. No further problems were experienced inthese areas during actual operation.

Two problems persisted into the demonstration period. The mesh-type mist eliminator, which was installed

to prevent slurry entrainment in the flue gas, experiencedplugging. Attempts to design a more efficient water sprayfor cleaning failed. However, replacement with a chevron-type mist eliminator prior to the third operating interval was effective. Potassium sulfate pelletization provedto be a more difficult problem. The cause was eventuallyisolated and found to be excessive water entrainment dueto carry-over of gypsum and syngenite. Hydrocloneswere installed in the crystallizer circuit to separate thevery fine gypsum and syngenite crystals from the muchcoarser potassium sulfate crystals. Although the correction was made, it was not in time to realize pellet production during the demonstration period. After all modifications were completed, the recovery scrubber entered intothe third and final operating interval—April to September1993. During this interval, recovery scrubber availability(discounting host site downtime) steadily increased from65% in April to 99.5% in July.Environmental PerformanceAn average 250 tons/day of CKD waste generated by theDragon Products plant was used as the sole reagent in therecovery scrubber to treat approximately 250,000 scfm offlue gas. All the CKD, or approximately 10 tons/hr, wererenovated and returned to the plant as feedstock and

mixed with about 90 tons/hr of fresh feed to make up therequired 100 tons/hr. The alkali in the CKD was converted to potassium-based fertilizer, eliminating all solidwaste. Exhibit 44 lists the number of hours per operatingperiod, SO2 and NOx inlet and outlet readings in pounds

per hour, and removal efficiency as a percentage for eachoperating period.

Average removal efficiencies during the demonstration period were 89.2% for SO2 and 18.8% for NOx emissions. No definitive explanation for the NOx control

mechanics was available at the conclusion of thedemonstration.

Aside from the operating period emissions data, an

assessment was made of inlet SO2 load impact on removal

efficiency. For SO2 inlet 

less, recovery scrubber re82.0%. For SO2 inlet load

removal efficiency increafor loads greater than 200 

In compliance testing 

partment of Environmentwas subjected to dust load0.04 gr/scf and demonstra0.005–0.007 gr/scf—less allowable limit.
Industrial Applications 

The Passamaquoddy Technology 

permanent part of the Dragon Products 

The Passamaquoddy Technology Recovery ScrubberTM

was successfully demonstrated at Dragon ProductsCompany’s cement plant in Thomaston, ME.Economic PerformanceThe estimated “as-built” capital cost to reconstruct theDragon Products prototype, absent the modifications, is$10,090,000 in 1990 dollars.

Annual operating and maintenance costs are estimated at $500,000. Long-term annual maintenance costs

are estimated at $150,000. Power costs, estimated at$350,000/yr, are the only significant operating costs.There are no costs for reagents or disposal, and no dedicated staffing or maintenance equipment are required.

Considering various revenues and avoided costs that

may be realized by installing a recovery scrubbersimilar

in size to the one used at Dragon Products, simple payback on the investment is projected in as little as3.1 years. In making this projection, $6,000,000 wasadded to the “as-built” capital costs to allow for contingency, design/permitting, construction interest, and licensing fees.

Commercial ApplicationsOf the approximately 2,000 Portland cement kilns in theworld, about 250 are in the United States and Canada.These 250 kilns emit an estimated 230,000 tons/yr of SO2

(only three plants have SO2 controls, one of which is the

Passamaquoddy Technology Recovery ScrubberTM). Theapplicable market for SO2 control is estimated at 75% of

the 250 installations. If full penetration of this estimatedmarket were realized, approximately 150,000 tons/yr ofSO2 reduction could be achieved.

The scrubber became a permanent part of the cement

plant at the end of the demonstration. A feasibility studyhas been completed for a Taiwanese cement plant.ContactsThomas N. Tureen, Project Manager, (207) 773-7166

Passamaquoddy Technology, L.P.1 Monument WayPortland, ME 04101(207) 773-7166(207) 773-8832 (fax)

William E. Fernald, DOE/HQ, (301) 903-9448John C. McDowell, FETC, (412) 892-6237References• Passamaquoddy Technology Recovery

ScrubberTM: Final Report. Volumes 1 and2 (Appendices A–M. PassamaquoddyTribe. February 1994. (Vol. 1 availablefrom NTIS as DE94011175, Vol. 2 asDE94011176.)

• Passamaquoddy Technology Recovery

ScrubberTM: Public Design Report. Report No. DOE/PC/89657-T2.

Passamaquoddy Tribe. October 1993.(Available from NTIS as DE94008316.)

• Passamaquoddy Tech

Topical Report. RepPassamaquoddy TribNTIS as DE9201986

• Comprehensive Repo

Technology ProgramScrubber. (PassamaqFE-0152. U.S. Depa1989. (Available fro
166 Project Fact Sheets 

Industrial ApplicationsPulse Combustor DesignQualification TestParticipantThermoChem, Inc.Additional Team MemberManufacturing and Technology ConversionInternational, Inc. (MTCI)—technology supplierLocationBaltimore, MD (MTCI Test Facility)TechnologyMTCI’s Pulsed EnhancedTM Steam Reforming using amultiple resonance tube pulse combustor.Plant Capacity/Production30 million Btu/hr (steam reformer)CoalBlack Thunder (Powder River Basin) subbituminousProject FundingTotal project cost $8,612,054 100%DOE 4,306,027 50Participants 4,306,027 50Project ObjectiveTo demonstrate the operational/commercial viability of asingle 253-resonance-tube pulse combustor unit andevaluate characteristics of coal-derived fuel gas generated by an existing Process Development Unit.Technology/Project DescriptionMTCI’s PulsedEnhancedTM Steam Reforming processincorporates an indirect heating process for thermochemical steam gasification of coal to produce hydrogen-rich, clean, medium-Btu content fuel gas without theneed for an oxygen plant. Indirect heat transfer is provided by immersing multiple resonance-tube pulse combustors in a fluidized-bed steam gasification reactor.

Pulse combustion increases heat transfer rate by a factorof 3 to 5, thus greatly reducing the heat transfer area required in the gasifier.

The pulse combustor represents the core of the

PulsedEnhancedTM Steam Reforming process because itprovides a highly efficient and cost-effective heat source.Demonstration of the combustor at the 253-resonancetube commercial scale is critical to market entry. The253-resonance-tube unit represents a 3.5 scale-up fromprevious tests. Testing will seek to verify scale-up criteriaand appropriateness of controls and instrumentation.Also, an existing Process Development Unit (PDU) willbe used to gasify coal feedstock to provide fuel gas data,including energy content, species concentration, and yield.Char from the PDU will be evaluated as well.

The facility will also 

train that includes two staber with a scrubber tank, air-cooled heat exchangethe condensation of excessteam) quenched in the vcolumn. All project testiMTCI test facility in BaltProject Status/AccomOn September 10, 1998, ThermoChem, Inc.’s Coodown project. The origin1992, was a commercial dwould employ 10 identiccombustor units. After fa
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 

Calendar Year

Industrial Applications 

1991 1992 1993 1994 1997 1998 1999 

Preaward

1995 1996

9/91 10/92

DOE selectedproject (CCT-IV)9/12/91

Cooperative agreementawarded 10/27/92

Project relocationrequested 10/26/94

Design and Construction

Revised CooperativeAwarded 9/29/98

1

unit, the project went through restructuring. The revisedproject will demonstrate a single 253-resonance-tubepulse combustor. NEPA requirements were satisfied onNovember 30, 1998 with a Categorical Exclusion. Thefirst major milestone was completion of the design onFebruary 15, 1999.

The next major milestone is completion of the coal

mild gasification data in June 1999 using the existingPDU. Construction of the combustor unit is scheduled tobe completed in October or November 1999, with operations beginning in November 1999.Commercial ApplicationsPulsedEnhancedTM Steam Reforming has application inmany different processes. Coal, with the world productionon the order of four billion tons per year, constitutes thelargest potential feed stock for steam reforming. Otherpotential feedstocks include spent liquor from pulp andpaper mills, refused-derived fuel, municipal solid waste,sewage sludge, biomass, and other wastes.

Although the project will demonstrate mild gasification only, the following coal-based applications are

envisioned:• Coal processing for combined-cycle power generation,• Coal processing for fuel cell power generation,• Coal pond waste and coal rejects processing to produce a hydrogen-rich gas from the steam reformer for

use in overfiring or reburning to reduce NOx emissions,

• Coal processing for production of gas or liquid fuel

and char for the steel industry for use in direct reduction of iron ore,

• Coal processing for producing compliance fuels,• Mild gasification of coal,• Co-processing of coal and wastes, and• Coal drying.

In addition, the technology has application for black

liquor processing and chemical recovery and for hazardous, low-level radioactive, and low-level mixed wastevolume reduction and destruction.

PDU Gobtaine

Design comp

Restructuring complete

3/21/98
Project Fact Sheets A-1

Appendix A: CCT Project Contacts

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

Confined Zone Dispersion Flue Gas

Desulfurization Demonstration

Participant:

Bechtel Corporation

Contacts:

Joseph T. Newman, Project Manager

(415) 768-1189

(415) 768-5420 (fax)

Bechtel Corporation

P.O. Box 193965

San Francisco, CA 94119-3965

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

LIFAC Sorbent Injection Desulfurization

Demonstration Project

Participant:

LIFAC–North America

Contacts:

Dan Stap, Project Manager

(412) 497-2231

(412) 497-2212 (fax)

ICF Kaiser Engineers, Inc.

Gateway View Plaza

1600 West Carson Street

Pittsburgh, PA 15219-1031

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

Advanced Flue Gas Desulfurization Demonstration

Project

Participant:

Pure Air on the Lake, L.P.

Contacts:

Tim Roth

(610) 481-6257

(610) 481-2762 (fax)

Pure Air on the Lake, L.P.

c/o Air Products and Chemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Demonstration of Innovative Applications of

Technology for the CT-121 FGD Process

Participant:

Southern Company Services, Inc.

Contacts:

David P. Burford, Project Manager

(205) 992-6329

(205) 992-7535 (fax)

dpburfor@southernco.com

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

Project Contacts

Listed below are contacts for obtaining further

information about specific CCT Program

demonstration projects. Listed are the name, title,

phone number, fax number, mailing address, and

e-mail address, if available, for the participant’s

contact person. In those instances where the project

participant consists of more than one company, a

partnership, or joint venture, the mailing address listed

is that of the contact person. In addition, the names,

phone numbers, and e-mail addresses for contact

persons at DOE Headquarters and the Federal Energy

Technology Center are provided.

Environmental Control Devices

SO2 Control Technologies

10-MWe Demonstration of Gas Suspension

Absorption

Participant:

AirPol, Inc.

Contacts:

Niels H. Kastrup

(281) 539-3400

(281) 539-3411 (fax)

nhk@flsmiljous.com

FLS Miljo, Inc.

100 Glenborough Drive

Houston, TX 77067
A-2 Project Fact Sheets

Full-Scale Demonstration of Low-NOx CellBurner

Retrofit

Participant:

The Babcock & Wilcox Company

Contacts:

Dot K. Johnson

(330) 829-7395

(330) 829-7801 (fax)

dot.k.johnson@mcdermott.com

McDermott Technologies

1562 Beeson Street

Alliance, OH 44601

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

Evaluation of Gas Reburning and Low-NOx

Burners on a Wall-Fired Boiler

Participant:

Energy and Environmental Research Corporation

Contacts:

Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140

(949) 859-3194 (fax)

Energy and Environmental Research Corporation

18 Mason

Irvine, CA 92618

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx

 Emissions from

High-Sulfur-Coal-Fired Boilers

Participant:

Southern Company Services, Inc.

Contacts:

Larry Monroe

(205) 257-7772

(205) 257-5367 (fax)

Southern Company Services, Inc.

P.O. Box 2641

Birmingham, AL 35291-8195

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

180-MWe Demonstration of Advanced

Tangentially-Fired Combustion Techniques for the

Reduction of NOx Emissions from Coal-Fired

Boilers

Participant:

Southern Company Services, Inc.

Contacts:

Larry Monroe

(205) 257-7772

(205) 257-5367 (fax)

Southern Company Services, Inc.

P.O. Box 2641

Birmingham, AL 35291-8195

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

NOx Control Technologies

Micronized Coal Reburning Demonstration for NOx

Control

Participant:

New York State Electric & Gas Corporation

Contacts:

Jim Harvilla

(607) 729-8630

(607) 762-8457 (fax)

New York State Electric & Gas Corporation

Corporate Drive–Kirkwood Industrial Park

P.O. Box 5224

Binghamton, NY 13902-5224

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

Demonstration of Coal Reburning for Cyclone

Boiler NOx

 Control

Participant:

The Babcock & Wilcox Company

Contacts:

Dot K. Johnson

(330) 829-7395

(330) 829-7801 (fax)

dot.k.johnson@mcdermott.com

McDermott Technologies

1562 Beeson Street

Alliance, OH 44601

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell.fetc.doe.gov
Project Fact Sheets A-3

SNOXTM Flue Gas Cleaning Demonstration Project

Participant:

ABB Environmental Systems

Contacts:

Paul Yosick, Project Manager

(423) 693-7550

(423) 694-5203 (fax)

ABB Environmental Systems

1409 Center Point Boulevard

Knoxville, TN 37932

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

LIMB Demonstration Project Extension and

Coolside Demonstration

Participant:

The Babcock & Wilcox Company

Contacts:

Paul Nolan

(330) 860-1074

(330) 860-2045 (fax)

The Babcock & Wilcox Company

20 South Van Buren Avenue

P.O. Box 351

Barberton, OH 44203-0351

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell@fetc.do.gov

SOx

-NOx-Rox BoxTM Flue Gas Cleanup

Demonstration Project

Participant:

The Babcock & Wilcox Company

Contacts:

Dot K. Johnson

(330) 829-7395

(330) 829-7801 (fax)

dot.k.johnson@mcdermott.com

McDermott Technologies

1562 Beeson Street

Alliance, OH 44601

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection

Participant:

Energy and Environmental Research Corporation

Contacts:

Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140

(949) 859-3194 (fax)

Energy and Environmental Research

Corporation

18 Mason

Irvine, CA 92718

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Demonstration of Advanced Combustion Techniques

for a Wall-Fired Boiler

Participant:

Southern Company Services, Inc.

Contacts:

John N. Sorge, Research Engineer

(205) 257-7426

(205) 257-5367 (fax)

Southern Company Services, Inc.

P.O. Box 2641

Birmingham, AL 35291-8195

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James R. Longanbach, FETC, (304) 285-4659

jlonga@fetc.doe.gov

Combined SO2 /NOx Control Technologies

Milliken Clean Coal Technology Demonstration

Project

Participant:

New York State Electric & Gas Corporation

Contacts:

Jim Harvilla

(607) 729-8630

(607) 762-8457 (fax)

New York State Electric & Gas Corporation

Corporate Drive–Kirkwood Industrial Park

P.O. Box 5224

Binghamton, NY 13902-5224

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov
A-4 Project Fact Sheets

Integrated Dry NOx/SO2 Emissions Control System

Participant:

Public Service Company of Colorado

Contacts:

Terry Hunt, Project Manager

(303) 571-7113

(303) 571-7868 (fax)

thunt@ueplaza.com

Utility Engineering

550 15th Street, Suite 800

Denver, CO 80202-4256

Lawrence Saroff, DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Commercial Demonstration of the NOXSO SO2

/

NOx Removal Flue Gas Cleanup System

Participant:

NOXSO Corporation

Contacts:

Lawrence Saroff DOE/HQ, (301) 903-9483

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

JEA Large-Scale CFB Combustion Demonstration

Project

Participant:

JEA

Contacts:

Reece E. Comer, Jr. P.E.

(904) 665-6312

(904) 665-7263 (fax)

comere@jea.com

JEA

21 West Church Street, Tower 10

Jacksonville, FL 32202-3139

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Tidd PFBC Demonstration Project

Participant:

American Electric Power Service Corporation as

agent for The Ohio Power Company

Contacts:

Mario Marrocco

(614) 223-2460

(614) 223-3204 (fax)

American Electric Power Service Corporation

1 Riverside Plaza

Columbus, OH 43215

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

Advanced Electric Power

Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project

Participant:

City of Lakeland, Lakeland Electric

Contacts:

Alfred M. Dodd, Project Manager

(941) 499-6461

(941) 499-6344 (fax)

Lakeland Electric

501 E. Lemon Street

Lakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

McIntosh Unit 4B Topped PCFB Demonstration

Project

Participant:

City of Lakeland, Lakeland Electric

Contacts:

Alfred M. Dodd, Project Manager

(941) 499-6461

(941) 499-6344 (fax)

Lakeland Electric

501 E. Lemon Street

Lakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov
Project Fact Sheets A-5

Nucla CFB Demonstration Project

Participant:

Tri-State Generation and Transmission

Association, Inc.

Contacts:

Stuart Bush

(303) 452-6111

(303) 254-6066 (fax)

Tri-State Generation and Transmission

Association, Inc.

P.O. Box 33695

Denver, CO 80233

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project

Participant:

Clean Energy Partners Limited Partnership

Contacts:

Victor Shellhorse, Vice President

(704) 382-8064

(704) 373-4986 (fax)

Duke Energy Industrial Asset Development

400 S. Tryon Street, Suite 1700

Charlotte, NC 28202

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

Piñon Pine IGCC Power Project

Participant:

Sierra Pacific Power Company

Contacts:

Jeffrey W. Hill, Director Power Generation

(775) 834-5650

(775) 834-5704 (fax)

jhill@sppc.com

Sierra Pacific Power Company

P.O. Box 10100

Reno, NV 89520-0024

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

Web Site:

http://www.sierrapacific.com/utilserv/electric/pinon/

Tampa Electric Integrated Gasification CombinedCycle Project

Participant:

Tampa Electric Company

Contacts:

Donald E. Pless, Director, Advanced Technology

(813) 228-1111, ext. 46201

(813) 641-5300 (fax)

Tampa Electric Company

P.O. Box 111

Tampa, FL 33601-0111

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

James U. Watts, FETC, (412) 892-5991

watts@fetc.doe.gov

Web Site:

http://www.teco.net/teco/TEKPlkPwrStn.html

Wabash River Coal Gasification Repowering Project

Participant:

Wabash River Coal Gasification Repowering Project

Joint Venture

Contacts:

Phil Amick, Director of Gasification Development

(713) 767-8667

(713) 767-8515 (fax)

pram@dynergy.com

Dynergy Marketing and Trade

1000 Louisiana St., Suite 5800

Houston, TX 77002

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Leo E. Makovsky, FETC, (412) 892-5814

makovsky@fetc.doe.gov

Advanced Combustion/Heat Engines

Healy Clean Coal Project

Participant:

Alaska Industrial Development and Export Authority

Contacts:

Dennis V. McCrohan, Deputy Director, Project

Development and Operations

(907) 269-3025

(907) 269-3044 (fax)

dmccrohan@aidea.org

Alaska Industrial Development and Export

Authority

480 West Tudor Road

Anchorage, AK 99503-6690

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Robert M. Kornosky, FETC, (412) 892-4521

kornosky@fetc.doe.gov
A-6 Project Fact Sheets

Clean Coal Diesel Demonstration Project

Participant:

Arthur D. Little, Inc.

Contacts:

Robert P. Wilson, Vice President

(617) 498-5806

(617) 498-7206 (fax)

Arthur D. Little, Inc.

25 Acorn Park

Cambridge, MA 02140

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Coal Processing for Clean Fuels

Indirect Liquefaction

Commercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOHTM) Process

Participant:

Air Products Liquid Phase Conversion Company, L.P.

Contacts:

Edward C. Heydorn, Project Manager

(610) 481-7099

(610) 706-7299 (fax)

heydorec@apci.com

Air Products and Chemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

Edward Schmetz, DOE/HQ, (301) 903-3931

edward.schmetz@hq.doe.gov

Robert M. Kornosky, FETC, (412) 892-4521

kornosky@fetc.doe.gov

Coal Preparation Technologies

Advanced Coal Conversion Process Demonstration

Participant:

Rosebud SynCoal Partnership

Contacts:

Ray W. Sheldon, P.E., Director of Development

(406) 252-2277

(406) 252-2090 (fax)

Rosebud SynCoal Partnership

P.O. Box 7137

Billings, MT 59103-7137

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk, FETC, (412) 892-6249

renk@fetc.doe.gov

Development of the Coal Quality ExpertTM

Participants:

ABB Combustion Engineering, Inc., and CQ Inc.

Contacts:

Clark D. Harrison, President

(724) 479-3503

(724) 479-4181

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, FETC, (412) 892-6249

renk@fetc.doe.gov

Web Site:

http://www.fuels.bv.com:80/cqe/cqe.htm

Mild Gasification

ENCOAL® Mild Coal Gasification Project

Participant:

ENCOAL Corporation

Contacts:

James P. Frederick, Project Director

(307) 686-2720, ext. 27

(307) 686-2894 (fax)

jfrederick@vcn.com

ENCOAL Corporation

P.O. Box 3038

Gillette, WY 82717

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

Self-Scrubbing CoalTM”: An Integrated Approach

to Clean Air

Participant:

Custom Coals International

Contacts:

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk, FETC, (412) 892-6249

renk@fetc.doe.gov
Project Fact Sheets A-7

Industrial Applications

Blast Furnace Granular-Coal Injection System

Demonstration Project

Participant:

Bethlehem Steel Corporation

Contacts:

Robert W. Bouman, Project Director

(610) 694-6792

(610) 694-2981 (fax)

Bethlehem Steel Corporation

Homer Research Laboratory

Mountain Top Campus

Bethlehem, PA 18016

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Leo E. Makovsky, FETC, (412) 892-5814

makovsky@fetc.doe.gov

Clean Power from Integrated Coal/Ore Reduction

(CPICORTM)

Participant:

CPICORTM Management Company, L.L.C.

Contacts:

Reginal Wintrell, Project Director

(801) 227-9214

(801) 227-9198 (fax)

CPICORTM Management Company, L.L.C.

P.O. Box 2500

Provo, UT 84603

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

Advanced Cyclone Combustor with Internal

Sulfur, Nitrogen, and Ash Control

Participant:

Coal Tech Corporation

Contacts:

Bert Zauderer, President

(610) 667-0442

(610) 667-0576 (fax)

coaltechbz@compuserve.com

Coal Tech Corporation

P.O. Box 154

Merion Station, PA 19066

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Arthur L. Baldwin, FETC, (412) 892-6011

baldwin@fetc.doe.gov

Cement Kiln Flue Gas Recovery Scrubber

Participant:

Passamaquoddy Tribe

Contacts:

Thomas N. Tureen, Project Manager

(207) 773-7166

(207) 773-8832 (fax)

ttureen@gwi.com

Passamaquoddy Technology, L.P.

1 Monument Way

Portland, ME 04101

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell@fetc.doe.gov

Pulse Combustor Design Qualification Test

Participant:

ThermoChem, Inc.

Contacts:

William G. Steedman, Sr. Systems Engineer

(410) 354-9890

(410) 354-9894 (fax)

tcheminc@aol.com

ThermoChem, Inc.

6001 Chemical Road

Baltimore, MD 21226

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Gary E. Staats, FETC, (412) 892-5741

staats@fetc.doe.gov
Project Fact Sheets B-1

Appendix B: Acronyms, Abbreviations, and

Symbols

Acronyms, Abbreviations, and

Symbols

°C degrees Celsius

°F degrees Fahrenheit

$ dollars (U.S.)

$/kw dollars per kilowatt

$/ton dollars per ton

% percent

® registered trademark

TM trademark

ABB CE ABB Combustion Engineering, Inc.

ABB ES ABB Environmental Systems

ACFB atmospheric circulating fluidized-bed

ADL Arthur D. Little, Inc.

AFBC atmospheric fluidized-bed

combustion

AFGD advanced flue gas desulfurization

AIDEA Alaska Industrial Development and

Export Authority

AOFA advanced overfire air

APF advanced particulate filter

ASME American Society of Mechanical

Engineers

Ass’n. Association

ATCF after tax cash flows

atm atmosphere(s)

avg. average

BFGCI blast furnace granular-coal injection

BG British Gas

BG/L British Gas/Lurgi

Btu British thermal unit(s)

Btu/kWh British thermal units per kilowatthour

B&W The Babcock & Wilcox Company

CAAA Clean Air Act Amendments of 1990

CaCO3 calcium carbonate (calcitic

limestone)

CaO calcium oxide (lime)

Ca(OH)2 calcium hydroxide (calcitic

hydrated lime)

Ca(OH)2•MgO dolomitic hydrated lime

Ca/N calcium/nitrogen

CAPI Clean Air Power Initiative

Ca/S calcium/sulfur

CaSO3 calcium sulfite

CaSO4 calcium sulfate

CCOFA close-coupled overfire air

CCT clean coal technology

CCT I First CCT Program solicitation

CCT II Second CCT Program solicitation

CCT III Third CCT Program solicitation

CCT IV Fourth CCT Program solicitation

CCT V Fifth CCT Program solicitation

CCT Program Clean Coal Technology

Demonstration Program

CDL® Coal-Derived Liquid®

CEQ Council on Environmental Quality

CFB circulating fluidized bed

C/H carbon/hydrogen

CKD cement kiln dust

CO carbon monoxide

CO2 carbon dioxide

COP Conference of Parties

CT-121 Chiyoda Thoroughbred-121

CQETM Coal Quality ExpertTM

CQIMTM Coal Quality Impact ModelTM

CX categorical exclusion

CZD confined zone dispersion

DER discrete emissions reduction

DME dimethyl ether

DOE U.S. Department of Energy

DOE/HQ U.S. Department of Energy

Headquarters

DSE dust stabilization enhancement

DSI dry sorbent injection

EA environmental assessment

EER Energy and Environmental Research

Corporation

EFCC externally fired combined cycle

EIA Energy Information Administration

EIS environmental impact statement

EIV Environmental Information Volume

EMP environmental monitoring plan

EPA U.S. Environmental Protection

Agency

EPAct Energy Policy Act of 1992

EPRI Electric Power Research Institute

ESP electrostatic precipitator
B-2 Project Fact Sheets

EWG exempt wholesale generator

ext. extension

FBC fluidized-bed combustion

FCCC Framework Convention on Climate

Change

Fe2

S pyritic sulfur

FERC Federal Energy Regulatory

Commission

FETC Federal Energy Technology Center

FGD flue gas desulfurization

FONSI finding of no significant impact

FRP fiberglass-reinforced plastic

ft, ft2, ft3 foot (feet), square feet, cubic feet

FY fiscal year

gal. gallon(s)

gal/ft3 gallons per cubic feet

GB gigabyte(s)

GE General Electric

GHG greenhouse gases

GNOCIS Generic NOx Control Intelligence

System

gpm gallons per minute

GR gas reburning

GR–LNB gas reburning and low-NOx burner

GR–SI gas reburning and sorbent injection

GSA gas suspension absorption

GVEA Golden Valley Electric Association

GW gigawatt(s)

GWe gigawatt(s)-electric

H2S hydrogen sulfide

H2SO4 sulfuric acid

HAP hazardous air pollutant

HCl hydrogen chloride

HF hydrogen fluoride

HGPFS hot gas particulate filter system

HHV high heating value

hr. hour(s)

HRSG heat recovery steam generator

ID Induced Draft

IEA International Energy Agency

IGCC integrated gasification combined

cycle

in, in2

, in3 inch(es), square inches, cubic inches

JBR Jet Bubbling Reactor®

KCl potassium chloride

K2SO4 potassium sulfate

kW kilowatt(s)

kWh kilowatt-hour(s)

lb. pound(s)

L/G liqud to gas ratio

LHV low heating value

LIMB limestone injection multistage

burner

LNB low-NOx burner

LNCB® low-NOx cell burner

LNCFS Low-NOx Concentric-Firing System

LOI loss on ignition

LPMEOHTM Liquid phase methanolTM

LRCWF low-rank coal-water-fuel

LSFO limestone forced oxidation

MASB multi-annular swirl burner

MB megabyte(s)

MCFC molten carbonate fuel cell

MgCO3 magnesium carbonate

MgO magnesium oxide

Mhz megahertz

mills/kWh mills per kilowatt hour

min. minute(s)

mo. month(s)

MTCI Manufacturing and Technology

Conversion International

MTF memorandum (memoranda)-to-file

MW megawatt(s)

MWe megawatt(s)-electric

MWt megawatt(s)-thermal

N2 atmospheric nitrogen

Na/Ca sodium/calcium

Na2/S sodium/sulfur

NaOH sodium hydroxide

Na2

CO3 sodium carbonate

NAAQS National Ambient Air Quality

Standards

NEPA National Environmental Policy Act

NH3 ammonia

Nm3 Normal cubic meter

NO2 nitrogen dioxide

NOPR Notice of Proposed Rulemaking

NOx nitrogen oxides

NSPS New Source Performance Standards

NTHM net tons of hot metal

NTIS National Technical Information

Service

NYSEG New York State Electric & Gas

Corporation

OC&PS Office of Coal & Power Systems

O&M operating and maintenance

O2 oxygen

OTAG Ozone Transport Assessment Group

OTC Ozone Transport Commission

PC personal computer

PCAST Presidential Committee of Advisors

on Science and Technology

PCFB pressurized circulating fluidized bed

PDF® Process-Derived Fuel®

PEIA programmatic environmental impact

assessment

PEIS programmatic environmental impact

statement
Project Fact Sheets B-3

PEOATM Plant Emission Optimization

AdvisorTM

PENELEC Pennsylvania Electric Company

PEP progress evaluation plan

PFBC pressurized fluidized-bed

combustion

PJBH pulse jet baghouse

PM particulate matter

PM10 particulate matter less than 10

microns in diameter

PM2.5 particulate matter less than 2.5

microns in diameter

PON program opportunity notice

PRB Powder River Basin

ppm parts per million (mass)

ppmv parts per million by volume

PSCC Public Service Company of Colorado

PSD Prevention of Significant

Deterioration

psi pound(s) per square inch

PUHCA Public Utility Holding Company

Act of 1935

PURPA Public Utility Regulatory Policies

Act of 1978

QF qualifying facility

RAM random access memory

R&D research and development

RD&D research, development, and

demonstration

REA Rural Electrification Administration

RP&L Richmmond Power & Light

ROD Record of Decision

ROM run-of-mine

rpm revolutions per minute

RUS Rural Utility Service

S sulfur

SBIR Small Business Innovation Research

scf standard cubic feet

scfm standard cubic feet per minute

SCR selective catalytic reduction

SCS Southern Company Services, Inc.

SFC Synthetic Fuels Corporation

S-H-U Saarberg-Hölter-Umwelttechnik

SI sorbent injection

SIP state implementation plan

SM service mark

SNCR selective noncatalytic reduction

SNRBTM SOx

-NOx-Rox BoxTM

SO2 sulfur dioxide

SO3 sulfur trioxide

std ft3 standard cubic feet

SOFA separated overfire air

STTR Small Business Technology

Transfer Program

SVGA super video graphics adapter

TAGTM Technical Assessment GuideTM

TCLP toxicity characteristics leaching

procedure

TVA Tennessee Valley Authority

UAF University of Alaska, Fairbanks

UARG Utility Air Regulatory Group

UBCL unburned carbon

U.K. United Kingdom

U.S. United States

VFB vibrating fluidized-bed

VOC volatile organic compound

WC water column

WES wastewater evaporation system

WLFO wet limestone, forced oxidation

wt. weight

yr. year(s)

State Abbreviations

States within the United States are abbreviated using

two-letter postal codes.
Project Fact Sheets Index-1

Index of CCT Projects and Participants

#

10-MWe Demonstration of Gas Suspension

Absorption 9, 22, 24, 28, 31, A-1

180-MW Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reduction of

NOx Emissions from Coal-Fired Boilers 11, 22, 25, 68,

71, A-2

A

ABB Combustion Engineering Inc. 9, 23, 24, 68, 70,

78, 87, 144, 145, 147, A-6, B-1

ABB Environmental System 22, 24, 84, 87, A-3, B-1

Advanced Coal Conversion Process Demonstration

18, 23, 25, 142, A-6

Advanced Cyclone Combustor with Internal Sulfur

Nitrogen and Ash Control 20, 23, 24, 158, 161,

A-7

Advanced Flue Gas Desulfurization Demonstration

Project 9, 22, 25, 40, 43, A-1

Air Products Liquid Phase Conversion Company, L.P.

23, 24, 138, 139, A-6

AirPol Inc. 22, 24, 28, 31, A-1

Alaska Industrial Development and Export Authority

23, 24, 132, A-5, B-1

Arthur D. Little Inc. 23, 24, 134, A-6, B-1

B

The Babcock & Wilcox Company 22, 24, 52, 55, 56,

59, 88, 91, 92, 95, 100, 112, 132, 144, A-2, A-3, B-1

Bechtel Corporation 22, 24, 32, 35, 124, A-1

Bethlehem Steel Corporation 19, 23, 24, 154, A-7

Blast Furnace Granular-Coal Injection System

Demonstration Project 20, 23, 24, 154, A-7

C

Cement Kiln Flue Gas Recovery Scrubber 20, 23, 25,

162, 165, A-7

City of Lakeland, Lakeland Electric 22, 24, 106, 108,

109, A-4

Clean Coal Diesel Demonstration Project 16, 23, 24,

134, A-6

Clean Energy Demonstration Project 16, 23, 24, 122,

A-5

Clean Energy Partners Limited Partnership 23, 24,

122, A-5

Clean Power from Integrated Coal/Ore 20

Clean Power from Integrated Coal/Ore Reduction

(CPICORTM) 23, 24, 156, A-7

Coal Tech Corporation 23, 24, 158, 161, A-7

Commercial Demonstration of the NOXSO SO2

/NOx

Removal 22, 25, 82, A-4

Commercial-Scale Demonstration of the LiquidPhase 18, 23, 24, 138, A-6

Confined Zone Dispersion Flue Gas Desulfurization

2, 9, 22, 24, 32, 35, A-1

CPICORTM Management Company L.L.C. 23, 24, 156,

A-7

CQ Inc. 17, 23, 24, 135, 144, 145, 146, 147, A-6

Custom Coals International 17, 23, 24, 140, A-6

D

Demonstration of Advanced Combustion Techniques

for a Wall-Fired Boiler 11, 22, 25, 72, A-2

Demonstration of Coal Reburning for Cyclone Boiler

11, 22, 24, 52, 55, A-2

Demonstration of Innovative Applications of

Technology for the CT-121 FGD 9, 22, 25, 44, 47,

A-1

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx Emissions from

High-Sulfur-Coal-Fired Boilers 11, 22, 25, 64, A-2

Development of the Coal Quality Expert 147

Development of the Coal Quality ExpertTM 18, 23, 24,

144, 147, A-6

E

ENCOAL Corporation 23, 24, 148, 149, 150, 151, A-6

ENCOAL® Mild Coal Gasification Project 18, 23, 24,

148, 151, A-6

Energy and Environmental Research Corporation A-3

Energy and Environmental Research Corporation 22,

24, 50, 60, 62, 63, 96, 99, A-2, A-3, B-1
Index-2 Project Fact Sheets

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection 22, 24, 96, 99, A-3

Evaluation of Gas Reburning and Low NOx

 Burners

on a Wall-Fired Boiler 11, 22, 24, 60, 63, A-2

F

Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit 11, 22, 24, 56, 59, A-2

H

Healy Clean Coal Project 16, 23, 24, 132, A-5

I

Integrated Dry NOx/SO2 Emissions Control System

22, 25, 100, 102, 1 03, A-4

J

JEA 22, 24, 110, 111, A-4, B-2

JEA Large-Scale CFB Combustion Demonstration

Project 16, 22, 24, 110, A-4

L

LIFAC Sorbent Injection Desulfurization

Demonstration Project 9, 22, 24, 36, 39, A-1

LIFAC–North America 22, 24, 36, 39, A-1

LIMB Demonstration Project Extension and Coolside

22, 24, 88, 91, A-3

M

McIntosh Unit 4A PCFB Demonstration Project

16, 22, 24, 106, 107, 108, 109, A-4

McIntosh Unit 4B Topped PCFB Demonstration

Project 16, 22, 24, 106, 107, 108, A-4

Micronized Coal Reburning Demonstration for NOx

Control 11, 22, 24, 50, A-2

Milliken Clean Coal Technology Demonstration

Project 22, 25, 78, 81, A-3

N

New York State Electric & Gas Corporation 11, 22,

24, 25, 50, 78, 81, A-2, A-3, B-2

NOXSO Corporation 22, 25, 82, A-4

Nucla CFB Demonstration Project 16, 23, 25, 116, 119,

A-5

O

Ohio Power Company, The 6, 23, 25, 112, 115, A-4

P

Passamaquoddy Tribe 23, 25, 162, 165, A-7

Piñon Pine IGCC Power Project 16, 23, 25, 124,

A-5

Public Service Company of Colorado 22, 25, 63, 100,

102, 103, A-4

Pulse Combustor Design Qualification Test 20, 23,

25, 166, A-7

Pure Air on the Lake L.P. 22, 25, 40, 43, A-1

R

Rosebud SynCoal Partnership 17, 18, 23, 25, 142,

143, A-6

S

Self-Scrubbing CoalTM: An Integrated Approach to

Clean Air 18, 23, 24, 140, A-6

Sierra Pacific Power Company 23, 25, 124, 125, A-5

SNOXTM Flue Gas Cleaning Demonstration Project

22, 24, 84, A-3

Southern Company Services Inc. 22, 25, 44, 47, 64,

67, 68, 71, 72, 75, A-1, A-2, A-3, B-3

SOx-NOx-Rox BoxTM Flue Gas Cleanup

Demonstration Project 22, 24, 92, 95, A-3

T

Tampa Electric Company 14, 23, 25, 126, A-5

Tampa Electric Integrated Gasification CombinedCycle Project 16, 23, 25, 126, A-5

ThermoChem Inc. 19, 20, 23, 25, 166, A-7

Tidd PFBC Demonstration Project 16, 23, 25, 112,

115, A-4

Tri-State Generation and Transmission Association

13, 23, 25, 116, 119, A-5

W

Wabash River Coal Gasification Repowering Project

16, 23, 25, 128, A-5