Clean Coal Technology

Demonstration Program

Program Update 1996-97

October 1997

U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

DOE/FE-0364
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Clean Coal Technology

Demonstration Program

Program Update 1996-97

October 1997

U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

DOE/FE-0364
Program Update 1996-97 iii

Contents

Executive Summary: The Clean Coal

Technology Demonstration

Program—Responding to a Need

Introduction ES-1

Evolution of the Coal Technology Portfolio ES-2

Performance Results ES-2

Technology Successes ES-3

Model Government/Industry Partnership for Technology Advancement ES-9

Continuing the Mission ES-10

Introduction 1-1

Coal Technologies Respond to Need 1-1

Coal Technologies for Environmental Performance 1-3

Acid Rain Mitigation 1-3

Air Toxics 1-7

Global Climate Change Protection 1-8

Value-Added Solid Waste 1-9

Coal Technologies for Competitive Performance 1-9

Coal Technologies to Keep America Secure 1-12

Coal Technology for the Future 1-13

Introduction 2-1

Implementation Principles 2-1

Implementation Process 2-2

Commitment to Commercial Realization 2-4

Solicitation Results 2-5

Future Implementation Direction 2-12

Issue 1: Role of CCTs in the Evolving Domestic Electricity Market 2-13

Issue 2: International Markets—Seizing the Opportunity 2-13

Issue 3: Environmental Issues Affecting CCT Deployment 2-14

Issue 4: CCT Deployment—From Today into the Next Millennium 2-14

Section 1: Role of the CCT Program

Section 2: Program Implementation
iv Program Update 1996-97

Summary 3-1

Program Funding 3-1

Availability of Funding 3-2

Use of Appropriated Funds 3-2

Project Funding, Costs, and Schedules 3-4

Cost-Sharing 3-4

Recovery of Government Outlays (Recoupment) 3-8

Introduction 4-1

Marketplace Commitment 4-1

Environmental Control Devices 4-2

Advanced Electric Power Generation 4-5

Coal Processing for Clean Fuels 4-6

Industrial Applications 4-7

Understanding the Domestic Market 4-9

An Emerging International Market 4-10

Market Communications 4-12

Summary 5-1

Environmental Control Devices 5-8

SO2 Control Technology 5-8

NOx Control Technology 5-30

Combined SO2/NOx Control Technology 5-56

Advanced Electric Power Generation Technology 5-82

Fluidized-Bed Combustion 5-82

Integrated Gasification Combined Cycle 5-83

Integrated Gasification Fuel Cell 5-83

Coal-Fired Diesel 5-83

Slagging Combustor 5-84

Status of Projects 5-84

Section 3: Funding and Costs

Section 4: CCT Program Accomplishments

Section 5: CCT Projects
Program Update 1996-97 v

Coal Processing for Clean Fuels Technology 5-114

Industrial Applications Technology 5-128

Historical Perspective A-1

Legislative History A-2

Solicitation History B-1

Selection and Negotiation History B-1

Introduction C-1

Role of NEPA in the CCT Program C-1

Compliance with NEPA C-1

Categorical Exclusions C-2

Memoranda-to-File C-2

Environmental Assessments C-2

Environmental Impact Statements C-5

NEPA Actions in Progress C-5

Environmental Monitoring C-5

Air Toxics C-6

CCT Project Contacts D-1

Acronyms E-1

Abbreviations E-2

Index F-1

Section 5: CCT Projects (continued)

Appendix A: Historical Perspective and

Relevant Legislation

Appendix B: Program History

Appendix C: Environmental Aspects

Appendix E: Acronyms and Abbreviations

Appendix D: CCT Project Contacts

Index
vi Program Update 1996-97

Exhibits

ES-1 Completed Projects by Application Category ES-3

ES-2 Summary of Results of Completed CCT Projects ES-4

ES-3 Award-Winning CCT Projects ES-11

1-1 Phase I SO2 Compliance Methods 1-3

1-2 CAAA NOx Emission Limits 1-5

1-3 Comparison of Energy Projections 1-11

2-1 CCT Program Selection Process Summary 2-5

2-2 Clean Coal Technology Demonstration Projects, by Solicitation 2-6

2-3 Geographic Location of CCT Projects—Environmental Control Devices 2-8

2-4 Geographic Location of CCT Projects—Advanced Electric Power Generation 2-9

2-5 Geographic Location of CCT Projects—Coal Processing for Clean Fuels 2-10

2-6 Geographic Location of CCT Projects—Industrial Processes 2-11

3-1 CCT Project Costs and Cost-Sharing 3-1

3-2 Relationship between Appropriations and Subprogram Budgets for the CCT Program 3-2

3-3 Annual CCT Program Funding, by Appropriations and Subprogram Budgets 3-3

3-4 CCT Financial Projections as of June 30, 1997 3-4

3-5 Financial Status of the CCT Program as of June 30, 1997 3-5

3-6 CCT Project Schedules and Funding, by Application Category 3-6

4-1 Commercial Successes—SO2

 Control Technology 4-3

4-2 Commercial Successes—NOx Control Technology 4-4

4-3 Commercial Successes—Combined SO2/NOx Control Technology 4-5

4-4 Commercial Successes—Advanced Electric Power Generation 4-7

4-5 Commercial Successes—Coal Processing for Clean Fuels 4-8

4-6 Commercial Successes—Industrial Applications 4-9

4-7 How to Obtain Updated CCT Program Information 4-14

Section 2: Program Implementation

Executive Summary: The Clean Coal

Technology Demonstration Program—

Responding to a Need

Section 1: Role of the CCT Program

Section 3: Funding and Costs

Section 4: CCT Program Accomplishments
Program Update 1996-97 vii

5-1 Project Fact Sheet, by Application Category and Participant 5-3

5-2 CCT Projects that Completed Operational Testing by June 30, 1997 5-7

5-3 CCT Program SO2

 Control Technology Characteristics 5-9

5-4 Variables and Levels Used in GSA Factorial Testing 5-12

5-5 GSA Factorial Testing Results 5-12

5-6 SO2 Removal Performance 5-24

5-7 Estimated Costs for an AFGD System 5-25

5-8 Flue Gas Desulfurization Economics 5-25

5-9 Operation of CT-121 Scrubber 5-28

5-10 SO2 Removal Efficiency 5-28

5-11 Particulate Capture Performance 5-28

5-12 CT-121 Air Toxics Removal 5-29

5-13 Group 1 and 2 Boiler Statistics and Phase II NOx Emission Limits 5-30

5-14 CCT Program NOx

 Control Technology Characteristics 5-31

5-15 Coal Reburn Test Results 5-34

5-16 Coal Reburn Economics 5-35

5-17 NOx Data from Cherokee Station, Unit 3 5-42

5-18 Catalysts Tested 5-50

5-19 Avg SO2

 Oxidation Rate 5-50

5-20 Design Criteria 5-51

5-21 LNCFSTM Configurations 5-54

5-22 Concentric Firing Concept 5-54

5-23 Unit Performance Impacts Based on Long-Term Testing 5-55

5-24 Average Annual NOx

 Emissions and % Reduction 5-55

5-25 CCT Program Combined SO2/NOx Control Technology Characteristics 5-57

5-26 LIMB SO2

 Removal Efficiencies 5-64

5-27 Capital Cost Comparison 5-65

5-28 Annual Levelized Cost Comparison 5-65

5-29 CCT Program Advanced Electric Power Generation Technology Characteristics 5-85

Section 5: CCT Projects
viii Program Update 1996-97

Section 5: CCT Projects (continued) 5-30 Effect of Bed Temperature on Ca/S Requirement 5-98

5-31 Calcium Requirements and Sulfur Retentions for Various Fuels 5-98

5-32 CCT Program Coal Processing for Clean Fuels Technology Characteristics 5-115

5-33 CQETM Stand-Alone System Requirements 5-118

5-34 CCT Program Industrial Applications Technology Characteristics 5-129

5-35 Summary of Emissions and Removal Efficiencies 5-140

A-1 CCT Program Legislative History A-4

C-1 NEPA Reviews Completed through June 30, 1997 C-2

C-2 Memoranda-to-File Completed C-3

C-3 Environmental Assessments Completed C-4

C-4 Environmental Impact Statements Completed C-5

C-5 NEPA Reviews in Progress C-6

C-6 Status of Environmental Monitoring Plans for CCT Projects C-6

C-7 CCT Projects Monitoring Hazardous Air Pollutants C-10

Appendix A: Historical Perspective and

Relevant Legislation

Appendix C: Environmental Aspects
Program Update 1996-97 ES-1

Executive Summary: The Clean Coal Technology

Demonstration Program—Responding to a Need

Introduction

The Clean Coal Technology Demonstration Program (known as the CCT Program) reached a significant milestone in 1996 with the completion of 20 of the

39 active projects. This milestone showed that this

cooperative government/industry cost-shared program

has yielded technologies that (1) are capable of meeting

the environmental performance requirements established in current and emerging environmental standards

and (2) will be capable of meeting the operational and

economic performance necessary to compete in the era

of deregulation and competition.

The CCT Program is responding to a need to

demonstrate and deploy a portfolio of technologies that

will assure the U.S. recoverable coal reserves of 297

billion tons could continue to supply the nation’s

energy needs economically and in a manner that meets

the nation’s environmental objectives. This portfolio of

technologies includes environmental control devices

that contributed to meeting the accords on transboundary air pollution recommended by the Special Envoys

on Acid Rain in 1986. Operational, technical, environmental, and economic performance information and

data are now flowing from highly efficient, low-emission, advanced power generation technologies that will

enable coal to retain its prominent role into the next

millennium. Further, advanced technologies are emerging that will enhance the competitive use of coal in the

industrial sector, such as in steelmaking. Coal processing technologies will enable the entire coal resource

base to be used while complying with environmental

requirements. These technologies are producing products used by utilities and industrial processes. The

capability to coproduce products, such as liquid and

solid fuels, electricity, and chemicals, is being demonstrated at a commercial scale by projects in the CCT

Program. In summary, this portfolio of technologies is

satisfying the national need to maintain a multifuel

energy mix in which coal is a key component because

of its low-cost, availability, and abundant supply within

the nation’s borders.

The international opportunities for coal technology

exports are enormous. It is estimated that the worldwide demand for energy will reach 542 quadrillion

British thermal units (Btu) annually by 2015, 1.6 times

the current level. Coal is expected to account for about

25 percent of this demand. The worldwide powergeneration equipment market could be as high as $1

trillion by 2015. Capturing just 20 percent of this

market would bring in revenues of $200 billion and

support more than 100,000 jobs over three decades in

the domestic power equipment industry alone. There

are opportunities for U.S. technology suppliers, developers, architect/engineers, and other firms to capitalize

on the knowledge and experience gained through

participation in the CCT Program. Tampa Electric Integrated Gasification Combined-Cycle

Project (Tampa Electric Company)—1997 Powerplant

Award presented by Power magazine.

Tidd PFBC Demonstration Project (The Ohio Power

Company)—1991 Powerplant Award presented by Power

magazine.
ES-2 Program Update 1996-97

control devices had their operating experience documented by the end of 1996.

The five projects in the coal processing for clean

fuels application category, valued at more than

$519 million, represent a diversified portfolio of

technologies. Three projects involve the production of

high-energy-density solid compliance fuels for utility

or industrial boilers; one of these projects also produces a liquid for use as a chemical feedstock. One

project is demonstrating a new methanol production

process. The other project developed an expert computer software system that enables a utility to predict

operating performance of coals being considered but

not previously burned in the utility’s boiler.

The four projects in the industrial applications

category have a combined value of nearly $1.3 billion.

Projects encompass the substitution of coal for 40 percent of the coke used in iron making, integration of a

direct iron-making process with the production of

electricity, reduction of cement kiln emissions and

solid waste generation, and the demonstration of an

efficient industrial-scale combustor.

Performance Results

The CCT Program has extended the technical,

economic, and environmental performance envelope of

a broad portfolio of advanced coal technologies. As of

June 30, 1997, 20 projects—50 percent of the total

number—have completed operation, 11 are in operation, 1 project is in construction, 3 are in design, and 4

are being restructured. Exhibit ES-1 shows the number

of completed projects by application category. Exhibit

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company

Services, Inc.)—1994 Powerplant Award presented by

Power magazine.

stration of advanced electric power generation systems.

Over 900 megawatts (MWe) of new capacity and over

800 MWe of repowered capacity are represented by 11

advanced electric power generation projects. Projects

include 4 integrated gasification combined-cycle

systems, 5 fluidized-bed combustion systems, and 2

advanced combustion/heat engine systems. These

projects will provide environmentally sound, more

efficient, and less costly electric power generation in

the late-1990s and also will provide the demonstrated

technology base necessary to meet new capacity requirements in the 21st century.

There are 19 environmental control devices

projects valued at more than $704 million. These

projects include 7 nitrogen oxide (NOx

) emissions

control systems installed on over 1,700 MWe of utility

generating capacity, 5 SO2 emissions control systems

installed on about 770 MWe, and 7 combined

SO2/NOx emissions control systems installed on about

700 MWe of capacity. Most of these environmental

Evolution of the Coal Technology

Portfolio

The CCT Program has been implemented through

a series of five nationwide competitive solicitations

conducted over a 9-year period. 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 were aimed primarily at the 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 situations with sulfur

dioxide (SO2) emissions capped under the Clean Air

Act Amendments of 1990 (CAAA), increased need for

electric power, and the need to alleviate concerns over

global climate change—a situation that translates into a

need for technologies with very high efficiencies and

extremely low emissions.

The technologies are categorized in four market

sectors:

• Advanced electric power generation

• Environmental control devices

• Coal processing for clean fuels

• Industrial applications

Approximately 56 percent, or about $3.2 billion, of

the total CCT Program costs are directed toward

enhancing efficiency, environmental performance, and

reliability of electric power production by the demon-
Program Update 1996-97 ES-3

ES-2 provides a summary of the key technical and

environmental results from the 20 completed demonstration projects and the capital cost, where available.

(See Appendix E for explanations of acronyms and

abbreviations.)

Technology Successes

The CCT Program is establishing marketplace

credibility as the demonstrated technologies are entering commercial use. Today, technologies used to

reduce NOx emissions are being retrofitted on a significant percentage (i.e., over 25 percent) of the nation’s

coal-fired capacity and provide the capability of

achieving not only existing regulated levels, but those

proposed by the Environmental Protection Agency

(EPA) for 2000. In fact, EPA has used the results

from the NOx technology demonstrations to guide its

efforts in establishing NOx control regulations. The

CCT Program has also shown that several advanced

technologies have led to significant improvements in

the economic and environmental performance of SO2

controls. Circulating fluidized-bed technology has

become a commercial success in the utility sector

worldwide due largely to the data generated from a

CCT project that was one of the first utility-scale

circulating fluidized-bed projects in the world. The

electric power generation technologies for the next

century are being demonstrated in the form of the

pressurized fluidized-bed combustion (PFBC) systems

and integrated gasification

combined-cycle (IGCC) systems. Further, technologies are

being used to transform lowrank and non-compliance coals

to useful, environmentally

superior coal-based fuels for use

by domestic utility and industrial coal users and are being

considered for major projects

abroad. Finally, coal-based

industrial processes are benefiting environmentally and economically from the demonstration of advanced coal

technologies.

Market credibility has been

enhanced by the following

project successes:

• Successful testing of the AirPol technology

resulted in the city of Hamilton, Ohio, receiving a $5-million grant from the Ohio Coal

Development Office to install the gas suspension absorption technology to control SO2

emissions from a 50-MWe coal-fired boiler at

the municipal power plant. This project has an

estimated employment impact of 70 personyears. Additional sales have been made to the

U.S. Army for hazardous waste disposal, to

Sweden for an iron ore sinter plant, and to

Taiwan and India.

• Pure Air on the Lake, L.P., will continue to

operate the advanced flue gas desulfurization

unit at the Northern Indiana Public Service

Company’s Bailly Generating Station for

17 years beyond the 3-year demonstration,

which was completed in 1995. In April 1994,

Pure Air of Manatee, L.P., entered into a

contract to provide 1,600 MWe of SO2

Advanced Flue Gas Desulfurization Demonstration

Project (Pure Air on the Lake, L.P.)—1993 Powerplant

Award presented by Power magazine.

Exhibit ES-1

Completed Projects by Application Category

Number of Projects

Application Category Completed

Environmental Control Devices

NOx control technology 5

SO2

 control technology 5

Combined SO2

/NOx control technology 5

Advanced Electric Power Generation

Atmospheric fluidized-bed combustion 1

Pressurized fluidized-bed combustion 1

Coal Processing for Clean Fuels 1

Industrial Applications

Industrial cyclone combustor 1

Cement kiln flue gas recovery scrubber 1
ES-4 Program Update 1996-97

Project and Participant

Exhibit ES-2

Summary of Results of Completed CCT Projects

Key Results Capital Cost

Environmental Control Devices

SO2

 Control Technology

10-MWe Demonstration of Gas Suspension Absorption

(AirPol, Inc.)

Confined Zone Dispersion Flue Gas Desulfurization

Demonstration (Bechtel Corporation)

LIFAC Sorbent Injection Desulfurization Demonstration

Project (LIFAC–North America)

Advanced Flue Gas Desulfurization Project

(Pure Air on the Lake, L.P.)

Demonstration of Innovative Applications of Technology

for the CT-121 FGD Process (Southern Company

Services, Inc.)

Gas suspension absorption (GSA)/electrostatic precipitator (ESP)—SO2

 removal efficiency of 90% at Ca/S of

1.4, 18 oF approach to saturation, and 0.12% chloride

GSA/pulse jet baghouse—SO2

 removal efficiency 3–5%

greater than GSA/ESP (3.0% sulfur bituminous coal)

SO2 reduction of 50% (1.2–2.5% sulfur bituminous coal)

SO2 removal efficiency of 70% at 2.0 Ca/S ratio

(2.0–2.8% sulfur bituminous coal)

SO2

 removal efficiency of 95% or more at availabilities

of 99.5% when operating on 2.0–4.5% sulfur bituminous

coal

Maximum SO2 removal efficiency of 98%

Over 3-year demonstration, 237,000 tons of SO2

removed while producing 210,000 tons of gypsum

Gypsum purity––97.2%

Power consumption—5,275 kW (61% of expected)

Water consumption—1,560 gal/min (52% of expected)

SO2

 removal efficiency of over 90% at SO2 inlet

concentrations of 1,000–3,500 ppm

Particulate removal efficiency of 97.7–99.3% at inlet

mass loadings of 0.303–1.392 lb/106

 Btu

Produced wallboard-grade gypsum as a by-product

Fiberglass-reinforced-plastic equipment—chemically and

structurally durable

$149/kW for GSA ($216/kW for conventional wet

limestone forced oxidation) (1990$)

Less than $30/kW at 500 MWe

$66/kW for two reactors (300 MWe); $76/kW for one

reactor (150 MWe); $99/kW for one reactor (65 MWe)

$210/kW at 100 MWe; $121/kW at 300 MWe;

$94/kW at 500 MWe (3.0% sulfur coal)

Not yet available
Program Update 1996-97 ES-5

Project and Participant

Exhibit ES-2 (continued)

Summary of Results of Completed CCT Projects

Key Results Capital Cost

NOx Control Technology

Demonstration of Coal Reburning for Cyclone Boiler

NOx Control (The Babcock & Wilcox Company)

Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit (The Babcock & Wilcox Company)

Evaluation of Gas Reburning and Low-NOx Burners on a

Wall-Fired Boiler (Energy and Environmental Research

Corporation)

Demonstration of Selective Catalytic Reduction

Technology for Control of NOx Emissions from HighSulfur-Coal-Fired Boilers (Southern Company

Services, Inc.)

180-MWe Demonstration of Advanced Tangentially Fired

Combustion Techniques for Reduction of NOx

 Emissions

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

Combined SO2

/NOx Control Technology

SNOXTM Flue Gas Cleaning Demonstration Project

(ABB Environmental Systems)

LIMB Demonstration Project Extension and Coolside

Demonstration (The Babcock & Wilcox Company)

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration

Project (The Babcock & Wilcox Company)

NOx reductions of 52% using bituminous coal and 55%

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

and 53%, respectively, at 60 MWe

NOx reductions of 54–58% using bituminous coal at full

load (605 MWe); 48% at 350 MWe

LNB alone (second generation)—37% NOx

 reduction;

GR–LNB (second generation)—64% NOx reduction

(13% gas heat input)

NOx reductions of over 80% at ammonia slip well under

5 ppm

NOx reductions of 37% for LNCFSTM I and II, and 45%

for LNCFSTM III, which includes both separated overfire

air and close-coupled overfire air

NOx

 reduction with SCR over 94% at inlet concentrations of 500–700 ppm

SO2 removal efficiency over 95% at inlet concentrations

of 2,000 ppm

Produced salable sulfuric acid by-product

SO2

 removal efficiency (3.8% sulfur coal, Ca/S of 2.0):

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

Coolside—70% for hydrated lime

NOx reduction of 40–50%

SO2 reductions of 80–90% using 3–4% sulfur bituminous

coal, depending on sorbent and conditions

NOx

 reduction of 90% with 0.9 NH3/NOx ratio

$66/kW at 110 MWe; $43/kW at 605 MWe

$9/kW at 600 MWe

Approximately $15/kW for gas reburning, plus gas

pipeline cost

Levelized cost at 80% NOx

 reduction—

2.79 mills/kWh or $2,036/ton of NOx removed

LNCFS I—$5–15/kW

LNCFS II/III—$15–25/kW

$305/kW at 500 MWe (3.2% sulfur coal)

LIMB—$31–102/kW (100–500 MWe)

Coolside—$69–160/kW (100–500 MWe)

$233/kW at 250 MWe (3.5% sulfur coal and inlet

NOx

 level of 1.2 lb/106 Btu)
ES-6 Program Update 1996-97

Exhibit ES-2 (continued)

Summary of Results of Completed CCT Projects

Project and Participant Key Results Capital Cost

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection (Energy and Environmental Research

Corporation)

Integrated Dry NOx

/SO2 Emissions Control System

(Public Service Company of Colorado)

Advanced Electric Power Generation

Tidd PFBC Demonstration Project (The Ohio Power

Company)

Hennepin—NOx

 reduction of 67% avg with 18% gas

input; SO2 removal efficiency of 53% at 1.75 Ca/S ratio

Lakeside—NOx

 reduction of 66% avg and SO2 reductions

of 58% during extended continuous combined (GR–SI)

runs at 29 MWe, about 22% gas input, and 1.8 Ca/S ratio

NOx

 reduction of 67% avg during long-term testing of gas

reburning only

NOx reduction of 62–69% with low-NOx burners and

maximum overfire air (50–110 MWe)

NOx reduction of 63% with low-NOx burners and

minimum overfire air; steady state conditions

NOx

 reduction decreased by 10–25% under load following

SNCR obtained NOx reduction of 30–50%, thereby

increasing total NOx control system reduction to more

than 80%

SO2

 removal efficiency of 70% with sodium bicarbonate

at normalized stoichiometric ratio of 1.0

Sorbent injection reduced ammonia slip

SO2

 reduction of 90–95% (Ohio bituminous coal, 2–4%

sulfur) at 1.1–1.5 Ca/S ratio

NOx

 emissions of 0.15–0.33 lb/106 Btu

Particulate emissions of 0.02 lb/106

 Btu

Heat rate—10,280 Btu/kWh

Combustion efficiency—99.6%

Commercially viable design

Gas turbine operable in PFBC environment

$15/kW for gas reburning, plus gas pipeline cost

$50/kW for sorbent injection

Not yet available

Not yet available
Program Update 1996-97 ES-7

Exhibit ES-2 (continued)

Summary of Results of Completed CCT Projects

Project and Participant Key Results Capital Cost

SO2 reduction of 70–95% (up to 1.8% sulfur coal),

depending on Ca/S ratio

NOx

 emissions of 0.18 lb/106 Btu avg

Particulate emissions of 0.0072–0.0125 lb/106 Btu avg

Heat rate—11,600 Btu/kWh

Combustion efficiency—96.9–98.9%

Commercial viability established

CQETM features:

Fuel evaluator—performs system-, plant-, and/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, and

predicts associated costs

SO2

 reduction of over 80% with sorbent injection; 58%

maximum with limestone injection at 2.0 Ca/S ratio

NOx

 emissions of 160–184 ppm (75% reduction)

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

SO2

 reduction of 90–95% (2.5–3% sulfur bituminous

coal); 98% maximum reduction

NOx reduction of 18.8% avg

Particulate emissions of 0.005–0.007 gr/std ft3

 with

loading of 0.04 gr/std ft3

Approximately $1,123/net kW (repower cost)

CQETM package sells for between $75,000 and

$100,000

Not available

$10 million for 450,000 ton/yr wet-process plant

Nucla CFB Demonstration Project (Tri-State Generation

and Transmission Association, Inc.)

Coal Processing for Clean Fuels

Development of the Coal Quality ExpertTM (ABB

Combustion Engineering, Inc., and CQ Inc.)

Industrial Applications

Advanced Cyclone Combustor with Internal Sulfur,

Nitrogen, and Ash Control (Coal Tech Corporation)

Cement Kiln Flue Gas Recovery Scrubber

(Passamaquoddy Tribe)
ES-8 Program Update 1996-97

scrubbing capacity at Florida Power & Light’s

Manatee power plant. The estimated value of

the sale is $200 million with an estimated

employment benefit of 1,400 person-years.

• Georgia Power is retaining the CT-121 flue gas

desulfurization system at its Plant Yates, Unit

No. 1, for use in commercial operation. In

1994, a tar sands oil extraction facility in

Murray, Canada, purchased a CT-121 scrubber.

Sales of 1,200 MWe of flue gas desulfurization

capacity were made to the Czech Republic and

Korea.

• Richland Power & Light is retaining the LIFAC

technology for commercial use at Whitewater

Valley Station, Unit No. 2. Ten commercial

units are in operation or under construction in

Canada, China, Finland, Russia, and the United

States.

• NOx

 control testing was conducted on the four

major boiler types (wall-, tangential-, cyclonefired, and cell-burner boilers) representing over

90 percent of the pre-New Source Performance

Standards boilers.

• The demonstration of low-NOx burners on a

500-MWe wall-fired boiler was supplemented

with the demonstration of the Generic NOx

Control Intelligence System (GNOCIS), a

neural-network design to aid digital boiler

controls, enhance NOx

 reduction, and improve

boiler efficiency. Six systems have been sold,

with 11 more sales projected.

• The Low-NOx Concentric Firing System

(LNCFSTM) supplied by ABB Combustion

Engineering, Inc., is being retained by Gulf

Power at its Plant Lansing Smith. The technology also is being used at a number of other

utilities, including Tennessee Valley Authority,

Illinois Power, Public Service Company of

Colorado, Indianapolis Power and Light,

Cincinnati Gas and Electric, Virginia Power,

Union Electric, and New York State Electric &

Gas Corporation.

• The Babcock & Wilcox DRB-XCL® low-NOx

burner demonstrated in Public Service Company of Colorado’s Integrated Dry

NOx/SO2 Emissions Control System has been a

commercial success. Sales have involved

1,829 burners, or approximately 23,664 MWe

of capacity, at an estimated value of over

$240 million, and an employment benefit of

over 1,670 person-years. A derivative of the

selective noncatalytic reduction (SNCR)

system has been sold to Pennsylvania Electric

Company and Mitsubishi Heavy Industries of

America.

Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit (The Babcock & Wilcox Company)—1994 R&D

100 Award presented by R&D magazine.

Wabash River Coal Gasification Repowering Project

(Wabash River Coal Gasification Repowering Project Joint

Venture)—1996 Powerplant Award presented by Power

magazine.

• Ohio Edison is retaining the SNOXTM technology as a permanent part of the emissions

control system at Niles Station to help the

utility meet its overall SO2 and NOx reduction

goals. Commercial SNOXTM plants are

operational in Denmark and Sicily, Italy.

• A software package developed as part of the

Milliken project to assist the utility in optimizing project operation has become a commercial

product. The Plant Emission Optimization

Advisor (PEOATM) has been sold to City

Public Service in San Antonio, Texas; three

bids are outstanding in Korea and one in Israel.

• The Tidd demonstration was the first utilityscale PFBC system in the United States and

confirmed that the system could be applied to

electric power generation. The plant represented a 13:1 scale-up from the pilot facility
Program Update 1996-97 ES-9

• The Self-Scrubbing CoalTM demonstration has

resulted in (1) a proposed agreement with

domestic coal-marketing companies to purchase

1 million tons of compliance coal annually, (2)

a proposed agreement with China to build a

coal-cleaning plant, together with a 500-mile

underground slurry pipeline and port facility, at

an estimated value of $450 million, (3) signed

letters of intent from two Polish power plants

that wish to produce 5.0 million tons per year of

cleaned coal, with an estimated value of $50

million, and (4) a letter of intent for three

additional pipelines in China, with an estimated

value of $3 billion.

• Rosebud SynCoal Partnership is working on a

potential semi-commercial stand-alone

minemouth project located in Wyoming.

and led to significant refinements and understanding of the technology. The unit accumulated over 11,400 hours of operation and

established the commercial viability of the

design.

• As a result of the Tri-State Generation and

Transmission Association’s Nucla CFB

Demonstration Project, Pyropower Corporation

was able to save almost 3 years in establishing a

commercial line of atmospheric circulating

fluidized-bed units.

• Three IGCC units are in various stages of

operation at three separate utilities. PSI

Energy’s 262-MWe Wabash River Generating

Station Unit 1 has produced over 360,000 MWh

of electricity using coal-derived syngas. Tampa

Electric Company’s 250-MWe Polk Power

Station Unit 1 began operation in July 1996 and

was placed into commercial service in September. Sierra Pacific Power Company’s 99-MWe

Tracy Station System initiated startup activities

during 1996 and will begin commercial service

in mid-1997.

• The first commercial sale of the Coal Quality

ExpertTM (CQETM) Acid Rain Advisor software

package, developed as part of CQETM to assist

utilities in making CAAA compliance decisions,

was made in 1993. The final CQETM software

was released in December 1995 and is being

offered commercially. Over 40 U.S. and 1 U.K.

utilities have access to CQETM through their

membership in the Electric Power Research

Institute.

• The ENCOAL® Mild Coal Gasification project

has operated successfully for 5 years. Fifteen

unit trains of process-derived fuel has been

shipped to five utilities. Additionally, 3 million gallons of coal-derived liquids has been

shipped to industrial clients. ENCOAL®

Corporation’s newly formed company, NuCoal,

L.L.C., signed a contract with Mitsubishi

International Corporation to construct a $460-

million, 15,000-metric-ton-per-day commercial

plant in Wyoming. Feasibility studies were

completed for two Indonesian projects and a

Russian project.

• Granular-coal injection technology developer,

British Steel, has granted exclusive worldwide

marketing rights to codeveloper CPCMacawber. A commercial sale was made to

United States Steel Corporation.

Model Government/Industry

Partnership for Technology

Advancement

The successful implementation of the CCT Program over the past 10 years is based on a number of

principles that evolved as a result of the dedicated

effort of industry and DOE to cement a partnership to

advance clean coal technologies. Highlights of some

of these principles follow:

• Strong and stable financial commitments for the

life of the project were put into place by

Congress.

Development of the Coal Quality ExpertTM (ABB

Combustion Engineering, Inc., and CQ Inc.)—1996

recognized by Secretary of Energy and EPRI as one of best

cost-shared utility projects.
ES-10 Program Update 1996-97

• Multiple solicitations spread over a number of

years enabled the program to address a broad

range of national needs with a portfolio of

evolving technologies.

• The technology agenda was determined by

industry, not government.

• Demonstrations were conducted at commercial

scale in actual user environments.

• The respective roles of government and

industry were clearly defined.

• At least 50 percent cost sharing was required

through all project phases.

• Allowance for cost growth, but with a statutory

limit, provided an important check-and-balance

feature of the program.

• Repayment of funds to the government was

required of successful industrial participants.

• Real and intellectual property rights were

retained by industry.

• Technology developed is made available on a

nondiscriminatory basis to all U.S. companies

that seek, under reasonable terms and conditions, to use the technology.

These principles, in large measure, led to wide

private industry and non-federal government participation in the program. Non-DOE funds of nearly

$3.8 billion have come from a wide variety of sources.

Approximately 55 investor-owned utilities, nonutility

power generators, municipals, and cooperatives have

invested over $2.3 billion into projects. These electric

power generators represent approximately 50 percent

of the coal-fired capacity in the United States and

almost 70 percent of the units affected by Phase I under

Title IV of the CAAA of 1990. Further, over 50

industry participants, including technology owners and

equipment vendors, have committed over $1.3 billion

of cost sharing to the projects. Finally, seven state

agencies and eight industry and academic research and

development organizations have provided over $200

million as their portion of cost sharing.

This broad-based cost-shared participation in the

program has translated into jobs in many trades and

professions. For example, each emissions control

project provides 100–200 jobs and each advanced

power generating project provides over 1,000 construction jobs.

In addition, the excellent quality and importance of

the CCT projects are well recognized by the business,

environmental, and technical communities. Numerous

industry and environmental awards for excellence and

outstanding achievement have been presented to CCT

projects since 1991. These award-winning projects

and honors received are highlighted in Exhibit ES-3.

In summary, the joint effort between industry and

the government in the CCT Program is a success. The

number of complex, capital-intensive projects put into

place by the CCT Program partnership is unprecedented, as is the degree of cost sharing. The partnership is

important not only for the end objectives it is achieving, but for the benefits, tangible and intangible, created by continuing association of the partners. The CCT

Program has shown that, with the government serving

as a risk-sharing partner, industry funding can be

leveraged to improve the environment, reduce the cost

of electricity, create jobs, and assure technology is

available to enable coal to continue as the major

contributor to the nation’s and the world’s energy

future.

Continuing the Mission

DOE has structured an integrated Coal and Power

Systems Research, Development, and Demonstration

(RD&D) Program with the mission to foster the development and deployment of advanced clean, affordable

fossil-based power systems and alternate fuels through

the clean utilization of coal. The CCT Program is an

integral part of the Coal and Power Systems RD&D

Program and is being implemented in three primary

product lines:

• Advanced power generation systems

• Environmental systems

• Coal fuels and industrial systems

During 1997, the following three projects, currently in the operational phase, should be completed:

• Demonstration of Advanced Combustion

Techniques for a Wall-Fired Boiler

• Self-Scrubbing CoalTM: An Integrated

Approach to Clean Air

• ENCOAL® Mild Coal Gasification Project

Further, the following four projects should begin

their operational phase:

• Micronized Coal Reburning Demonstration for

NOx Control

• Piñon Pine IGCC Power Project
Program Update 1996-97 ES-11

Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit (The Babcock & Wilcox Company)

Evaluation of Gas Reburning and Low-NOx

 Burners

on a Wall-Fired Boiler; Enhancing the Use of Coals by

Gas Reburning and Sorbent Injection (Energy and

Environmental Research Corporation)

Advanced Flue Gas Desulfurization Demonstration

Project (Pure Air on the Lake, L.P.)

Demonstration of Innovative Applications of

Technology for the CT-121 FGD Process

(Southern Company Services, Inc.)

Tidd PFBC Demonstration Project (The Ohio Power

Company)

Tampa Electric Integrated Gasification CombinedCycle Project (Tampa Electric Company)

Wabash River Coal Gasification Repowering Project

(Wabash River Coal Gasification Repowering Project

Joint Venture)

Development of the Coal Quality ExpertTM (ABB

Combustion Engineering, Inc., and CQ Inc.)

Exhibit ES-3

Award-Winning CCT Projects

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

cell burner.

1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management Association to the U.S. Department of

Energy, Gas Research Institute, and U.S. Environmental Protection Agency for the development and commercialization of

gas-reburning technology.

1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service Company’s Bailly Generating

Station.

1992 Outstanding Engineering Achievement Award presented by the National Society of Professional Engineers.

1995 Design Award presented by the Society of Plastics Industries in recognition of the mist eliminator.

1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. Co-recipient was the U.S.

Department of Energy.

1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and Waste Management Association.

1993 Environmental Award presented by the Georgia Chamber of Commerce.

1992 National Energy Resource Organization award for demonstration of energy-efficient technology.

1991 Powerplant Award presented by Power magazine to American Electric Power Company’s Tidd project. Co-recipient

was The Babcock & Wilcox Company.

1997 Powerplant Award presented by Power magazine to Tampa Electric’s Polk Power Station.

1996 Association of Builders and Contractors Award presented to Tampa Electric for quality of construction.

1993 Ecological Society of America Corporate Award presented to Tampa Electric for its innovative siting process.

1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of Florida for the innovative

siting process.

1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innovative siting process.

1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc.

1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 1996 American Consulting

Engineers Council competition.

In 1996 recognized by then Secretary of Energy Hazel O’Leary and EPRI President Richard Balzhiser as the best of nine

DOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Program.

Project and Participant Award
ES-12 Program Update 1996-97

• Healy Clean Coal Project

• Commercial-Scale Demonstration of LiquidPhase Methanol (LPMEOHTM) Project

Assessments will be made of the impacts that

evolving and anticipated domestic and international

environmental rulings will have on the commercial

deployment of the technologies demonstrated under the

CCT Program. The environmental performance data

from completed projects will be analyzed, documented,

and distributed to potential users of the technology as

well as environmental and regulatory stakeholders.

This information and data would be available and can

be considered during the deliberations on new standards for the reduction of acid rain percursors, hazardous air pollutants, and greenhouse gas emissions, with

the purpose of assuring that new standards will be

reasonable and achievable in a cost-effective manner.

Technical and economic performance data from

the completed projects will be reviewed and analyzed

to identify opportunities to improve the competitiveness of the clean coal technologies. Opportunities

could lead to benefits such as reduced capital costs,

increased efficiencies, increased fuel flexibility, or

reduced cost of electricity to the customer by offsetting

production costs through coproduct profits. Timely

identification of opportunities to improve the competitive position of clean coal technologies is essential to

achieving these objectives as the utility sector moves

into the era of deregulation and competition. These

opportunities could be acted on by program stakeholders, such as technology suppliers and federal, state, and

industry RD&D organizations.

The CCT Program will continue to refine the

effectiveness of the outreach program in reaching and

informing all customers and stakeholders about the

program and its projects and improving the perception

of coal as a low-cost, environmentally acceptable fuel.

In order to accomplish this objective, participation of

the CCT Program stakeholders/customers will be

pursued vigorously with a view toward establishing

cooperative activities to advance compatible agendas.

These activities could involve CCT project site visits

by interested stakeholders/customers, expansion of the

audience in attendance at the Annual Clean Coal

Technology Conference, expanded support for international technology conferences, and increased level of

support for state-level education programs.
Program Update 1996-97 1-1

1. Role of the CCT Program

Introduction

Over the past quarter century, the nation’s energy

picture has been one of dynamic change. The oil

embargoes of the 1970s, the environmental debates of

the 1980s, the implementation of controls for acid rain

precursers, the beginning of electric utility deregulation, and the concerns about global warming in the

1990s have been forces that shaped the nation’s

energy policy, the private sector’s response in the

domestic and international marketplace, and the

capability of technology. Since 1985, a joint effort

between government and industry, known as the Clean

Coal Technology Demonstration Program (CCT

Program), has responded to the challenges represented

by these dynamic changes. The number of complex,

capital-intensive projects put into place by the CCT

Program is unprecedented, as is the magnitude of

participation by the industrial participants as represented by the level of cost and risk sharing. More

than $5.7 billion is being expended, with industry

investing two dollars for every government dollar

applied to the program. With half of the projects

completed, the technological successes have become

evident. New technologies to reduce the emissions of

acid rain processors, namely sulfur dioxide (SO2

) and

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

are being used by electric power producers and in

industrial applications. Advanced electric power

generation systems that can generate electricity with

greater efficiency and less environmental intrusion are

now operating, utilizing the nation’s most plentiful

fossil energy resource, coal. Coal, which accounts for

nearly 94 percent of the proven fossil energy reserves

in the United States, supplies the bulk of the low-cost,

reliable electricity vital to the nation’s economy and

global competitiveness. According to the Energy

Information Administration (EIA), coal was used by

electric utilities and nonutility generators to produce

over 1,670 billion kilowatt-hours or 54 percent of the

nation’s electricity in 1995. EIA projects that coal

will continue to dominate electric power production at

least through 2015 (the end of the forecast period)

when coal will be used to generate over 2,050 billion

kilowatt-hours or nearly

50 percent of all electricity generated.

The ability of coal and coal technologies to

respond to the nation’s need for low-cost, reliable

electricity hinges on the ability to meet two central

requirements: (1) the capability to meet the environmental performance requirements established in

current and emerging environmental regulations and

(2) the ability of the technologies to achieve the

operational and economic performance required to

compete in the era of utility deregulation and competition. The CCT Program is responding to these needs

and will produce a portfolio of advanced coal-based

technologies that will enable coal to retain its prominent role in the nation’s power generation future.

Further, advanced technologies emerging from the

CCT Program will also enhance coal’s competitive

position in the industrial sector. Technology advances

in steelmaking will reduce the cost of production

while greatly improving environmental performance.

The technologies for the coproduction of products,

such as liquid and solid fuels, electricity and chemicals, and industrial cogeneration, could enable coal to

increase market share in the industrial sector.

While the technologies emerging from the CCT

Program are vital to the nation’s ability to use coal

competitively and with environmental acceptability in

the next millennium, these technologies also establish

the basis for an export industry needed to meet the

global demand for energy. With coal as the fuel of

necessity for many economies, these technologies,

known as clean coal technologies worldwide, allow

U.S. industry to capitalize on the advances and knowledge base established through the CCT Program’s

government/industry partnership.

Coal Technologies Respond to

Need

The environmental and competitive performance

of coal technologies has evolved over 25 years of

industry and government research, development, and

demonstration programs. The programs were pursued

to assure that the U.S. recoverable coal reserves of

297 billion tons could securely supply the nation’s

energy needs economically and in an environmentally

acceptable manner.
1-2 Program Update 1996-97

During the 1970s and early 1980s, many of the

government-sponsored technology demonstrations

focused on the synthetic fuels production technology.

In 1980, the Synthetic Fuels Corporation (SFC) was

established under the Energy Security Act to reduce

the U.S. vulnerability to disruptions of crude oil

imports. It was to be accomplished by encouraging

the private sector to build and operate synthetic fuels

production facilities that would use abundant domestic

energy resources, primarily coal and oil shale. The

strategy was for the SFC to be primarily a financier of

pioneer commercial- and near-commercial-scale

facilities.

The goal of the SFC was to achieve production

capacities of 500,000 barrels per day by 1987 and

2 million barrels per day by 1992, at an estimated cost

of $8.8 billion. By 1985, it became apparent that the

need for synthetic fuels had changed, as oil prices

declined, world oil supplies stabilized, and a shortterm supply buffer was provided by the Strategic

Petroleum Reserve.

Congress observed the decline of private-sector

interest in the production of synthetic fuels in light of

unfavorable market conditions. Public Law 99-190,

Department of the Interior and Related Agencies

Appropriations Act for Fiscal Year 1986, abolished

the SFC and transferred project management to the

Treasury Department. Public Law 98-473, Joint

Resolution Making Continuing Appropriation for

Fiscal Year 1985 and Other Purposes, provided

$750 million from the Energy Security Reserve to be

deposited in a separate account in the U.S. Treasury

entitled The Clean Coal Technology Reserve. The

nation moved from an energy policy based on synthetic fuels production to a more balanced policy, which

established that the nation should have an adequate

supply of energy, maintained at a reasonable cost and

consistent with environmental, health, and safety

objectives. Energy stability, security, and strength

were the foundations for this policy. It was recognized that coal would be a major contribution to

meeting this goal for the foreseeable future because of

the following factors:

1. The location, magnitude, and characteristics of

the coal resource base were well understood.

2. The technology and skilled labor base of

nearly 1.1 million workers were available to

safely and economically extract, transport, and

use coal.

3. A multi-billion dollar infrastructure was in

place to gather, transport, and deliver this

valuable energy commodity to serve the

domestic and international marketplace.

4. Coal was used to produce over 54 percent of

the nation’s electric power in 1995 and was

vital to industrial processes, such as steel and

cement production as well as industrial power.

5. The most abundant fossil energy resource was

secure within the nation’s borders and relatively invulnerable to disruptions because of

the coal industry’s production responsiveness

and stockpiling capability.

6. Coal was the fuel of necessity in many lesser

developed economies.

It was recognized that the continued viability of

coal as a source of energy was dependent on the

demonstration and commercial application of a new

generation of advanced coal-based technologies

characterized by enhanced technical, economic, and

environmental performance.

With these factors very evident, the CCT Program was established to demonstrate the commercial

feasibility of clean coal technology application. In

1986, the first solicitation (CCT-I) for clean coal

technology projects was issued to be responsive to this

need, and the solicitation resulted in a broad range of

projects being selected in four major product markets—environmental control devices, advanced

electric power generation, coal processing for clean

fuels, and industrial applications.

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

the 1986 Joint Report of the Special Envoys on Acid

Rain, which included a 5-year, $5-billion U.S. effort

to curb precursors of acid rain formation—SO2

 and

NOx

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

February 1988, provided for the demonstration of

technologies that were capable of achieving significant reductions in SO2

 and/or NOx emissions from

existing power plants. These technologies were to be

more cost-effective than current technologies and

capable of commercial deployment in the 1990s when

the Clean Air Act Amendments were to become

effective. In May 1989 a third solicitation (CCT-III)

was issued with essentially the same objective as the

second, but encouraging technologies that would

produce clean fuels from run-of-mine coal.

The next two solicitations recognized evolving

energy and environmental issues and were thus focused on seeking highly efficient, economically

competitive, low-emission technologies. Specifically,

the fourth solicitation (CCT-IV), released in January
Program Update 1996-97 1-3

1991, had as its objective the demonstration of energy

efficient, economically competitive technologies

capable of retrofitting, repowering, or replacing

existing facilities while achieving significant reductions in SO2 and NOx

 emissions. In July 1992, the

fifth and final solicitation (CCT-V) was issued to

provide for demonstration projects that significantly

advanced the efficiency and environmental performance of technologies applicable to new or existing

facilities.

As a result of these five solicitations, a total of 50

government/industry cost-shared projects were negotiated, of which 39 valued at more than

$5.7 billion have been completed or remain active in

the CCT Program.

The success of the government/industry CCT

Program is directly attributable to its responsiveness

to public and private sector needs to reduce environmental emissions and maximize economic and efficient energy production. This will strengthen the

economy, enhance energy security, and reduce the

vulnerability of the economy to global energy market

shocks.

Coal Technologies for

Environmental Performance

Acid Rain Mitigation

During the late 1980s, work began on drafting

what was to become the Clean Air Act Amendments

of 1990 (CAAA) and on November 15, 1990, Congress enacted the CAAA. Title IV, Acid Deposition

Control, established emissions reduction targets for

SO2, capped SO2 emissions in the post-2000 timeframe, and directed the establishment of allowable

emission limitations for NOx

. Title IV represented the

first large-scale approach to regulating overall emissions levels by using marketable allowances. The

utilities could adopt a control strategy that was most

cost-effective for their given systems and plants rather

than having to apply a “command-and-control” approach wherein the emission-reduction technique is

specified.

The emission reduction requirements for SO2

were to be met in two phases. Phase I, which provided for the initial increment of SO2

 reduction, began on

January 1, 1995, and the second increment implemented through Phase II will begin on January 1, 2000.

Title IV identified 261 generating units (designated

affected units) that

were required to

comply with

Phase I. Most of

these units are coalfired with fairly

high emissions. An

additional 174 units

are participating in

Phase I based on

Environmental

Protection Agency

(EPA) rules, which

allow a utility to

designate substitution or compensating units as part of

Phase I compliance

strategies. Therefore, 435 units are considered Phase I units. Under

Phase II, more than 2,000 units will be affected.

Exhibit 1-1 summarizes the compliance methods used

by the 261 affected units listed in Title IV to satisfy

Phase I requirements.

By the end of 1995, the Phase I units had significantly reduced SO2

 emissions compared to previous

years. In 1990 the Phase I units emitted 9.7 million

tons of SO2

; in 1995 emissions were down to

5.3 million tons, a 45 percent reduction. This is

contrasted to non-Phase-I units whose emissions were

12 percent higher (6.6 million tons) than their 1990

emissions of 5.9 million tons.

The following projects within the CCT Program

were designated affected units and were required to

achieve compliance with Phase I requirements:

Exhibit 1-1

Phase I SO2 Compliance Methods

% SO2

No. of % of Reduction from % of Total

Method Units Units 1985 Baseline SO2 Reduction

Fuel switching/blending 136 52 60 59

Additional SO2 allowances 83 32 16 9a

Scrubbers 27 10 83 28

Retirements 7 3 100 2

Otherb 8 3 86 2

Total 261 100 100

a Includes reduced coal consumption of 2.5 million tons and 16% reduction in sulfur content.

b

 Includes 1 repowered unit, 2 switched to natural gas, and 5 switched to No. 6 fuel oil.

Source: The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities:

An Update, Energy Information Administration, March 1997.
1-4 Program Update 1996-97

• Northern Indiana Public Services’ Bailly

Generating Station, 528-MWe Units 7 and 8;

advanced flue gas desulfurization unit

• Georgia Power Company’s Plant Yates,

100-MWe Unit 1; Chiyoda Thoroughbred-121

advanced flue gas desulfurization

• New York State Gas & Electric’s Milliken

Station, 300-MWe Units 1 and 2; S-H-U

formic-acid-enhanced, wet limestone scrubber

• PSI Energy’s Wabash River Station,

262-MWe repowered integrated gasification

combined-cycle unit

EIA estimates the annualized Phase I compliance

cost to be $836 million (1995 dollars). The cost

ranged from $113 per ton of SO2

 removed for fuel

switching to $322 per ton of SO2

 removed for flue gas

desulfurization.

One of the more significant effects of compliance

with Phase I requirements was the change in coal use.

As shown in Exhibit 1-1, the fuel switching and/or

blending compliance strategy was selected by 52

percent of the affected units. This switch to lower

sulfur coal affected regional coal distribution. Between 1990 and 1995, the following changes in coal

sales resulted:

• Powder River Basin coal—increased

78 million tons

• Central Appalachian coal—increased

15 million tons

• Rocky Mountain coal—increased 10 million

tons

• Northern Appalachian coal—

decreased 29 million tons

• Illinois Basin coal—decreased

40 million tons

In Phase II, beginning in 2000,

emissions are limited to 1.2 pounds of

SO2 per million Btu at the consumption rate established in the 1985–1987

timeframe. Most utilities have not

finalized their compliance strategies

because the industry is faced with

major changes in the way it is structured and does business under the

requirements of the Energy Policy Act

(EPAct) of 1992, the Federal Energy

Regulatory Commission (FERC)

Orders No. 888 and 889, and state-level utility restructuring legislation. Under the previous regulatory

environments, state regulators would allow the utilities

to pass on pollution control costs to consumers.

However, in a restructured, competitive environment,

the added cost of capital-intensive environmental

controls could put a utility at a disadvantage to those

utilities that can achieve compliance with lower cost

alternatives, such as fuel switching and/or blending.

EIA projects that fuel switching and/or blending will

be the predominant strategy used, with allowance

acquisition being the second choice. However, it is

expected that allowance prices will increase after

2000, and thus the scrubbing option will become more

cost competitive so that by 2010 about 23 gigawatts of

coal-fired capacity will be retrofitted. This could

provide an opportunity to deploy SO2

 or combined

SO2/NOx environmental control device technologies

demonstrated under the CCT Program. Another

option available to utilities is to repower with a clean

coal technology. Under this option a 4-year extension

(to December 31, 2003) is available to comply with

the Phase II requirements.

Title IV of the CAAA required EPA to establish

annual allowable emissions limitations for NOx

 in two

phases. Phase I required NOx

 reductions from tangentially fired and dry-bottom wall-fired boilers. These

are referred to as Group 1 boilers. In March 1994,

EPA promulgated a rule establishing emission limitations of 0.45 pound per million Btu for tangentially

fired units and 0.50 pound per million Btu for wallfired units. However, in November 1994 after a

challenge from utility groups, the U.S. Court of

Appeals found that the definition of low-NOx burner

technology contained in the March rule exceeded

EPA’s statutory authority and vacated the rule. In

April 1995, after agreement with environmental and

New York State Electric & Gas Corporation’s Milliken Station used the SH-U scrubber to achieve Phase I SO2

 compliance.
Program Update 1996-97 1-5

utility organizations, EPA issued a final rule revising

the definition of low-NOx burner technology. Further,

the rule extended the compliance date to January 1,

1996.

On August 3, 1995, EPA issued a proposed

regulation that included a provision for “open market”

trading, somewhat similar to SO2

 allowance trading.

Under this rule, utilities would not need state and

federal approval for transactions of NOx and volatile

organic carbon (VOCs) credit trading. Instead,

utilities would be able to comply with various air

pollution mandates by buying and using an appropriate number of tons of “discrete emissions reductions,”

or DERs. Utilities would be able to generate emission

reduction credits for smog precursors by voluntarily

reducing NOx and VOCs and bank, use, or sell the

credits under the open market emissions trading

proposal. (In addition to trading VOCs and NOx

under the program, the utilities also would be able to

trade water pollution credits.) The DERs will not

require certification by regulators until they are used,

either by the utility that generates them for later use or

by a second utility that purchases the DERs from the

first utility.

On December 19, 1996, EPA issued a rule to

implement Phase II by establishing NOx

 emissions

limitations for additional coal-fired

boilers (Group 2) and

reducing the NOx

emissions limitations

on Group 1 units.

The types of Group 1

and 2 units and the

Phase I and II NOx

emission limits are

shown in Exhibit 1-2.

In response to the

need to formulate

NOx emission reductions that were realistic and achievable,

EPA was able to use

the database developed during the

Southern Company

Services evaluation of

NOx

 control on wallfired and tangentially

fired boilers. Further, the technical, environmental,

and economic data on NOx controls were developed

under the CCT Program for the four major boiler

types (wall-fired, tangential-fired, cyclone-fired, and

cell-burner), which constitute over 90 percent of the

pre-New Source Performance Standard boiler types.

In addition, low-NOx

 burners were installed on a

vertically fired boiler and tested. Other alternative

NOx-control technologies were demonstrated, including coal and gas reburning, selective noncatalytic

reduction (SNCR), and selective catalytic reduction

(SCR). This portfolio of NOx controls will not only

Chiyoda’s CT-121 system allowed Georgia Power’s

Plant Yates to meet Phase I SO2

 requirements.

Exhibit 1-2

CAAA NOx Emission Limits

Group 1 Group 2 Phase I NOx Phase II NOx

Unit Type Unit Type Emission Limitsa Emission Limitsa

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

Tangentially fired 0.45 0.40

boilers

Dry-bottom wall- 0.50 0.46

fired boilersb

Cell-burner 0.68

boilers

Cyclone boilers 0.86

>155 MWe

Wet-bottom 0.84

wall-fired boilers

>65 MWe

Vertically fired 0.80

boilers

a Emission limits are lb/106

 Btu of heat input on an annual average basis.

b Other than units applying cell-burner technology
1-6 Program Update 1996-97

assure Phase I and II emission reductions are achievable, but will provide the technology base necessary to

achieve even deeper NOx

 reductions that may be

necessary to meet CAAA Title I requirements for

ozone in nonattainment areas.

The EPA is in the process of considering and

issuing new rules that go beyond the acid rain provisions contained in the CAAA. Some of these rules are

in the discussion phase; other rules have been proposed or finalized and will need to be considered in

the research, development, and deployment of clean

coal technologies. The following initiatives are

included:

• Clean Air Power Initiative (CAPI). CAPI

was established by EPA to combine the rule

making for SO2, NOx, and fine particulates into

one rulemaking effort. CAPI would consider

the cap-and-trade approach to pollutant

reductions rather than the traditional command-and-control approach. The proposed

emission rates for NOx would be 0.15–0.25

pound per million Btu for utility sources and a

50–60 percent reduction in SO2

 beyond the

Title IV CAAA requirements. These would

take place in 2005 or 2010. EPA would

provide long-term relief from additional

regulations.

• Attainment of Ozone Standards (Title I).

CAAA Title I established the Ozone Transport

Commission (OTC) to address regional

transport of pollutants that contributes to

ozone nonattainment in the Northeast. The

Northeast Ozone Transport Commission

approved a Memorandum of Understanding in

September 1994 to reduce power plant

emissions of NOx by as much as 70 percent.

Reductions are to be accomplished in 1999

and 2003. The Ozone Transport Assessment

Group (OTAG) was a voluntary collaborative

effort by 37 states, begun in June 1995, to

address the issue of ozone transportation. On

June 19, 1997, the OTAG Policy Group issued

its recommendations, which called for utilities

in a number of affected states to control NOx at

a level between the CAAA level and the less

stringent 85% reduction from the 1990 rate or

0.15 pound per million Btu. Control levels are

to be determined and implemented through

statewide tonnage budgets established by EPA

with control measures determined and implemented by the states. Through State Implementation Plans (SIPs), the SIP process is

scheduled to be implemented on September 1,

Scaffolding and cell-burner penetration into the boiler

wall are viewed from inside of a boiler.

Selective catalytic reduction technology achieves deep

NOx

 reductions.
Program Update 1996-97 1-7

1997, with EPA establishing the emissions

budgets. Final approval of the SIPs is scheduled for March 2001. Further, OTAG approved a recommendation that would allow

states to sell or trade credits to exceed the

budget.

• Soot and Smog. On June 25, 1997, EPA

recommended new National Ambient Air

Quality Standards (NAAQS) for particulate

matter and ozone (commonly referred to as

soot and smog), with standards becoming final

in July 1997. The standard for coarse particles

remains essentially unchanged, while a new

standard for fine particles—those measuring

2.5 micrometers in diameter and smaller

(instead of the previous 10 microns)—was set

at an annual limit of 15 micrograms per cubic

meter, with a 24-hour limit of 65 micrograms

per cubic meter. For ozone, the recommended

final standard was tightened from 0.12 parts

per million (or 120 parts per billion) of ozone

measured over 1 hour to a new standard of

0.08 parts per million (or 80 parts per billion)

measured over 8 hours, with the average fourth

highest concentration over a 3-year period

determining whether an area is out of compliance. EPA also will issue an implementation

package and work from the regional plan

developed by OTAG to address long-distance

transport of ozone.

• NOx

 Emissions Standards (Title IV). EPA

proposed revised New Source Performance

Standards (NSPS) for NOx on July 9, 1997.

The proposed changes reduce limits of NOx

emissions from utilities to 1.35 pound per

megawatt-hour (net energy output) regardless

of fuel type. Compliance is determined on a

30-day rolling average basis. An alternate

standard of 0.15 pound per million Btu (heat

input) has also been proposed.

Air Toxics

Under Title III of the CAAA, EPA is responsible

for determining the hazards to public health posed by

189 hazardous air pollutants (HAPs) and is required to

perform a study of HAPs to determine the public

health roles that are likely to occur as a result of

power plant emissions. DOE recognized the importance of detecting and measuring HAPs in stack gases.

A program was implemented with industry to monitor

HAPs emissions at CCT projects sites, under both

baseline and demonstration operating conditions.

Two objectives of the HAPs monitoring, which have

been met, were to improve the

quality of HAPs data being gathered and to monitor a broader

range of plant configurations and

emissions control equipment. As

a result, 24 CCT projects are

monitoring HAPs, with 10 having

been completed by the end of

1996 (see Appendix C,

Exhibit C-7).

In another effort begun in

January 1993, EPA, with the

participation of the U.S. Department of Energy (DOE) under the

Coal R&D Program, the Electric

Power Research Institute (EPRI),

and the Utility Air Regulatory Group (UARG), began

an emissions data collection program using state-ofthe-art sampling and analysis techniques. Emissions

data were collected from eight utilities representing

nine process configurations, several of which were

sites for CCT projects. These utilities represented

different coal types, process configurations, furnace

types, and pollution control methods. The report, A

Comprehensive Assessment of Toxic Emissions from

Coal-Fired Power Plants: Phase I Results from the

U.S. Department of Energy Study, was released in

September 1996 and provided the raw data from the

emissions testing. In another effort, HAPs data were

collected from 16 power plants. A report released in

July 1996, Summary of Air Toxics Emissions Testing

at Sixteen Utility Plants, provides an assessment of

HAPs measured in the coal, across the major pollution

control devices, and the HAPs emitted from the stack.

Hazardous air pollutants will be measured at the Wabash River IGCC unit.
1-8 Program Update 1996-97

The second phase of the DOE/EPRI effort currently in progress will conduct sampling at other sites,

including the CCT Program’s Wabash River integrated gasification combined-cycle (IGCC) project.

Further, the results from the first phase will be used to

determine what configuration and coal types require

further assessment.

In October 1996, EPA submitted to Congress an

interim version of its technical assessment of toxic air

pollutant emissions from power plants, Study of

Hazardous Air Pollutant Emissions from Electric

Utility Steam Generating Units, Interim Final Report.

EPA plans to continue evaluating the potential exposures and potential public health concerns from

mercury emissions from utilities. In addition, the

agency will evaluate information on various potential

control technologies for mercury. If EPA decides that

HAPs pose a risk, then it must propose air toxic

emissions controls by November 15, 1998, and make

them final 2 years later.

However, the results of the HAPs program have

significantly mitigated concerns about HAPs emission

from coal-fired power generation and focused attention on but a few flue gas constituents. The results

have the potential to make the forthcoming EPA

regulations less strict, which could avoid unnecessary

control costs and thus save consumers money on

electricity bills.

Global Climate Change Protection

The CCT Program had its roots in the reduction

of acid rain precursors and was responsive to the U.S.

and Canadian Special Envoys’ recommendations. Ten

years later, the future of coal and clean coal technology may rest on the outcome of international concerns

and negotiations on emissions of greenhouse gases

(GHG), particularly carbon dioxide (CO2

).

In 1992, the United States became a signatory to

the Framework Convention on Climate Change

(FCCC). The FCCC directed Annex I parties (developed countries) to implement programs and actions

aimed at returning GHG emissions to 1990 levels by

2000. As a result, the Climate Change Action Plan,

published in October 1993, initiates a number of

voluntary mitigation actions. In 1995, the first meeting

of the Conference of Parties (COP-I) to the FCCC was

held in Berlin. The purpose of this conference was to

determine whether the non-binding FCCC was adequate. It was determined that most parties at COP-I

were not meeting the previously agreed to goals. As a

result, the Berlin Mandate was adopted. The Berlin

Mandate calls for negotiation of a protocol to enhance

the commitments of Annex I parties for the period

beyond 2000. An Ad Hoc Group on the Berlin Mandate is charged with (1) setting quantified emissions

limitations and reduction objectives within specified

time frames; (2) establishing a joint implementation

pilot program that would reduce, avoid, or sequester

greenhouse gases; and (3) not introducing any new

commitments from non-Annex-I parties. A draft

negotiating text of the protocol has been circulated for

comment. The Ad Hoc Group is scheduled to meet

during July-August 1997 and in October 1997 to

continue efforts to build concensus and finalize the

protocol document.

COP-II, held in Geneva, Switzerland, in July

1996, resulted in the Geneva Declaration calling for

Annex I parties to adopt legally binding commitments

by COP-III scheduled for Kyoto, Japan, in December

1997. The U.S. position supported verifiable mediumterm targets that are realistic and achievable, with

maximum flexibility (including joint implementation

and emissions trading among nations).

The responsiveness and role of clean coal technologies in meeting GHG reduction goals of U.S.

utilities is found in the Climate Change Action Plan’s

Climate Challenge Program. The basis of the program

is described in the April 20, 1994, Memorandum of

Understanding between DOE and representatives of

the nation’s electric utility industry:

• Edison Electric Institute

• American Public Power Association

• National Rural Electric Cooperative Association

• Large Public Power Council

• Tennessee Valley Authority

The program consists of voluntary commitments

by electric utilities to undertake actions to reduce,

avoid, offset, or sequester GHG emissions. These

commitments are formalized in individual utility

Participation Accords for large utilities and in Letters

of Participation for small utilities. DOE provides

technical information and support, reports on the

progress of the program, and provides public recognition to utility participants. The types of commitments

are broad enough so that any utility can participate,

regardless of size, type, or amount of genera- tion,

resource mix, or load growth.

Clean coal technologies can play an important

role in implementation of these Participation Accords.

Improvements in generation technology, how generation is operated and maintained, and where on the grid

it is located can have measurable beneficial effects on
Program Update 1996-97 1-9

both GHG emissions and operating costs. Utilities are

pursuing three broad strategies for reducing GHG

emissions through more efficient power generation:

(1) improving the efficiency of existing capacity, (2)

repowering or replacing generation with more efficient generation, and (3) repowering or replacing

generation with generation that uses lower-carbon

fuels.

More than half of the Participation Accords

include fossil-related activities; many of the remaining

accords are from utilities not having fossil-fired

generating capacity. Fossil-related GHG reduction

commitments total about 7.4 million metric tons of

carbon equivalent in the year 2000, approximately

one-sixth of all Climate Challenge Program tonnage

commitments.

As part of its accord, CINergy has installed clean

coal technology at the Wabash River Generating

Station, which is owned by its subsidiary, PSI Energy.

In a fully commercial setting, PSI Energy and its

partner, Destec Energy, are demonstrating coal gasification repowering of an existing unit. Where there

was an aging, inefficient, little-utilized unit, there is

now a very clean and highly efficient unit that will

generate power at high load well into the next century.

The original plant capacity was 100 MWe, but is now

262 MWe (net); and the original heat rate of 11,000

Btu per kilowatt-hour is now under 9,000, one of the

lowest for commercial coal plants in the United States.

Because the heat rate is so much lower, the rate of

CO2

 emissions is decreased by about 20 percent.

Additionally, emissions of SO2, NOx, and particulate

matter (PM) are reduced by at least 90 percent.

The 250-MWe Tampa Electric compound integrated gasification combined-cycle project began

operations in 1996. With a heat rate of 8,600 Btu per

kilowatt-hour (40 percent efficiency), it will result in a

GHG emission reduction of over 20 percent, compared

to conventional technology. Sierra Pacific Power

Company’s Piñon Pine integrated gasification combined-cycle project (99 MWe) scheduled to begin

operation in mid-1997 will result in similar reductions.

Other technologies, such as the pressurized fluidizedbed combustion and integrated gasification fuel cell,

being demonstrated under the CCT Program offer a

major opportunity to contribute to this international

environmental issue.

Finally, in an effort to increase the awareness of

the role that clean coal technologies can have in meeting global climate concerns, the United States is

participating in the International Energy Agency

Greenhouse Gas R&D Program (IEA/GHG). The

work conducted by the program focuses on technical

and economic assessments and collaborative research

on technology to address global concerns due to

possible climate change resulting from atmospheric

buildup of greenhouse gases. The IEA/GHG investigates and evaluates technical ways of reducing greenhouse gas emissions through improved fossil fuel

technologies and by capture and sequestration of

greenhouse gases. Participation in the IEA/GHG

collaboration leverages the funding by the United

States. This program also serves as a source of independent expert data on coal technologies to address

global climate concerns for policy makers, industry,

and the public.

The IEA/GHG is conducting studies of a number

of technologies, including many clean coal technologies. For example, completed studies include integrated coal gasification combined cycles, advanced

pulverized coal cycles, ocean sequestration of CO2

,

and chemical utilization of CO2. Examples of ongoing

studies include integrated gasification fuel cells and

IGCC using Orimulsion.

Value-Added Solid Waste

The CCT Program addressed the issue of trading

off air emissions at the expense of solid waste. For

example, conventional SO2 emissions control technologies generate a scrubber sludge that must be carefully handled and disposed of in sludge ponds. Estimates

are that by 2015 over 4,500 acres per year would be

required to dispose of FGD sludge if wet FGD systems were used. Most of technologies being demonstrated under the CCT Program produce dry solid

wastes that significantly reduce the disposal problem.

Nine projects produce dry, solid compounds or composites that can be used as building materials, agriculture supplements, neutralizing agents for use with acid

mine drainage, and for other purposes; five CCT

projects produce commercial-grade gypsum; and eight

projects produce a salable by-product in the form of

commercial-grade sulfur or sulfuric acid. One project,

the Passamaquoddy Technology Recovery ScrubberTM

produced fertilizer and distilled water.

Coal Technologies for

Competitive Performance

In 1986 when the CCT Program was begun, the

electric utility industry was highly regulated. The

major uncertainty was the breadth and depth of environmental regulatory requirements that would be
1-10 Program Update 1996-97

imposed on the industry. Even this uncertainty was

mitigated by the fact that most of the environmental

control costs could be passed through to the consumer

if approved by the state regulatory commission. As

long as the utility made prudent investments in plant

and equipment, their economic future was fairly stable

and predictable. It was assumed that coal and nuclear

energy would carry the burden of baseload generation,

oil would be phased out, and natural gas would be

used for meeting peak load requirements.

By mid-1997, the picture was entirely different:

the utility industry is in the midst of a major restructuring to accommodate a competitive marketplace.

This restructuring was driven by legislative, consumer, and technology factors as follows:

• Consumers became a major factor in pushing

for competition and regulatory reform even

though regulators provide the oversight

necessary to assure consumers were paying a

fair price. However, the price differential

among the states and regions of the country

meant that large industrial users of electricity

in some areas were burdened with high

electricity prices, while their competitors in

other areas had access to much lower cost

electricity costs and thus a competitive

production cost edge.

• The Public Utility Regulatory Policies Act of

1978 (PURPA) and the Energy Policy Act of

1992 (EPAct) were two major legislative

drivers. Under PURPA, utilities were required

to purchase electricity from certain “qualified

facilities” (QFs) at a price equal to the utility’s

estimated avoided cost. As a result, the

amount of electricity generated by these

utility company from purchasing wholesale

energy from an EWG that was one of its

affiliates. Unlike PURPA, PUHCA reforms

did not guarantee EWGs a market for their

power, thereby requiring that it compete with

power from other sources in the wholesale

power market.

• EPAct further promoted wholesale competition by mandating that transmission facility

owners must provide open access to the grid

by wheeling power to wholesale customers at

cost-based rates (Subtitle B of the Electricity

Title VII). Further, anyone may petition

FERC for access to the transmission grid. On

April 14, 1996, FERC issued two closely

related orders, Orders No. 888 and 889,

detailing rules to assure nondiscriminatory

open access to interstate electricity transmission and recovery of the utilities’ prudently

incurred costs.

• Consumer pressures for access to lower priced

power have been successful in bringing about

competition in retail as well as wholesale

power markets. Deregulation of retail markets

is occurring at the state level. (FERC is

prohibited from ordering retail wheeling.)

Under EPAct, states continue to have responsibility for regulating (1) any electric company

operating within its jurisdiction, (2) any EWG

selling electricity wholesale to such a utility,

and (3) any holding company that was an

associate or affiliate of an EWG selling power

to a regulated utility. By early 1997, three

states—California, Pennsylvania, and Rhode

Island—had enacted legislation to allow

nonutility power producers increased dramatically to over 280 billion kilowatt-hours or

about 10 percent of the utility generation in

1995. EPAct, in amending the Public Utility

Holding Company Act of 1935 (PUHCA),

lifted more of the constraints on the development of nonutility generation as well as some

of the restrictions on competition in wholesale

electricity markets.

• EPAct created a new class of producer called

the exempt wholesale generator (EWG), which

was defined as “any person determined by the

Federal Energy Regulatory Commission to be

engaged directly through one or more

affilliates—and exclusively in the business of

owning or operating—all or part of one or

more eligible facilities and selling electric

energy at wholesale.” This amendment to

PUHCA provided that nonutility companies

could develop EWGs without coming under

the provisions of PUHCA and exempt holding

companies could also develop EWGs without

losing their exemption from PUHCA. Any

EWG also in the retail utility’s rate base had to

receive state regulatory approval before it

could be exempted from PUHCA. EPAct

(Section 711) specifically allowed both

registered and exempt holding companies to

own, acquire, and operate EWGs. The law

also allowed for so-called “hybrid plants,”

which have ownership divided between utility

companies, whose portion is included in the

rate base, and EWGs, whose portion is

exempt. The act sought to limit the abuse of

affiliate transactions by prohibiting an electric
Program Update 1996-97 1-11

competition in the retail electricity market. In

38 other states, retail deregulation is either

planned or under discussion, with 10 of these

states having a proposed time schedule for

deregulation. Pilot projects are ongoing in

Massachusetts, New Hampshire, New York,

Illinois, Idaho, and Washington and have been

proposed in five other states. Under retail

deregulation, end users are not required to

purchase power from their local utility

company, but instead may purchase power

from generators or marketers located in other

states and regions of the country. In this

competitive market environment, power is

priced according to market conditions, not

necessarily according to generation costs.

• Advances in the technology of electricity

production are another factor that has had an

impact on restructuring. Nonutility generators

have taken advantage of

these advances, such as

aero-derived gas turbines,

to generate cheaper

electricity than can be

achieved using conventional

fossil steam and/or nuclear

generators. The new

technologies are often more

efficient and less environmentally obtrusive and can

be installed in a very short

period of time in capacity

modules closely matching

the load growth curves.

These factors have had a pronounced effect on

the utility market for coal and clean coal technology.

A comparison of 1985 and 1996 energy projections

for coal, natural gas, and oil shown in Exhibit 1-3

illustrates the magnitude of the change that restructuring is playing, as well as environmental regulation

discussed previously. Coal is projected to maintain its

lead in the production of electricity in 2010 at

50 percent; however, that is down from 60 percent

when the CCT Program started. The differential has

been, for the most part, made up by the growth in

natural-gas-fueled power generation. Nuclear power’s

contribution to the nation’s electric power generation

in 2010 is about the same in both projections.

Industry restructuring and competition will

impact coal and coal technologies for the foreseeable

future. Utilities are expected to improve their operating efficiencies by using existing plants at higher

capacity factors. EIA has projected that the capacity

factor for coal-fired power plants will increase from

63 percent in 1995 to 74 percent in 2015. Between

1995 and 2010, the most economical choice for new

power generation is natural-gas-fired capacity. EIA

projects gas-fired generation to grow from over

330 billion kilowatt-hours in 1995 to 1,184 billion in

2015, most of that using combined-cycle technology.

EIA further predicts that no net coal-fired capacity

additions will be made until after 2010, when rising

natural gas costs and nuclear retirements are projected

to cause increasing demand for coal-fired baseload

capacity. At that time, new, highly efficient, lowemissions power systems will enter the power production markets. New concepts to reduce delivered

electricity prices will likely be employed. Examples

include minemouth plants that reduce or eliminate the

coal transportation cost component in power production and electric power and coproduct production

systems, which allow the consumer’s cost of electriciExhibit 1-3

Comparison of Energy Projections

Electricity Sales Coal Gas Oil

(109 kWh) (106 tons) (1012 ft3) (106 barrels)

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

1995 3,018 3,008 0 924 959 4 3.0 3.5 17 0.2 0.3 50

2000 3,384 3,290 -3 1,059 1,017 -4 2.7 4.3 60 0.6 0.2 -66

2010 4,176 3,784 -9 1,355 1,099 -19 1.7 6.9 305 0.4 0.3 -25

% dif = % difference between the two projections.

A National Energy Policy Plan Projections to 2010, U.S. Department of Energy, December 1985.

B Annual Energy Outlook 1997 with Projections to 2015, Energy Information Agency, December 1996.
1-12 Program Update 1996-97

ty to be offset by the profitability of coproducts. The

CCT Program is demonstrating the first commercial

versions of the advanced high-efficiency coal systems

that will be needed when older plants are retired and

new capacity additions are needed to assure continued

low-cost, reliable electric power service.

Coal Technologies to Keep

America Secure

It is in the national interest to maintain a multi-fuel

energy mix to sustain national economic growth. Coal

is a key component of national energy security because

of its low cost, availability, and abundant supplies

within the nation’s borders. The CCT Program pursues a strategy that leads to the development and

deployment of a technology portfolio that enhances the

efficient use of this coal resource base while assuring

national and global environmental goals are achieved.

The domestic coal resources are large enough to meet

demand for almost 270 years at current rates of consumption.

The United States is increasingly dependent on

imported oil as low prices have resulted in decreased

domestic oil production for 13 years. That trend was

broken in 1995 by an oil production capacity increase

of 0.4 million barrels per day. However in 1995, net

petroleum imports were 7.9 million barrels per day, or

45 percent of domestic consumption. In its latest

projections for 2015, EIA expects imports to range

from 10.8 to 15.9 million barrels per day depending on

oil price. The EIA reference case for 2015 calls for net

imports of 13.5 million barrels per day, which is

equivalent to over 60 percent of

consumption. Also, natural gas

imports are expected to grow

from 12.4 percent of total gas

consumption in 1995 to

14.0 percent in 2015. These

imports are primarily from

Canada, which does not represent a supply stability problem

but does represent a drain on

balance of payments.

U.S. coal consumption is

equivalent to approximately 10

million barrels of oil per day and

represents a reduction in balance

of payments of over $50 billion

per year. Clean coal technologies will provide the utilization and conversion technologies that will enable the coal fuel cycle to continue as a major component in the nation’s economy

while achieving the environmental quality that society

demands. The domestic and export value of 1995

coal production approaches $25 billion in the U.S.

economy. There are over 1.1 million workers whose

jobs directly depend on the coal industry. These jobs

are dispersed through the mining, transportation,

manufacturing, utility, and supporting industries.

A U.S. coal conversion industry could also

directly reduce the nation’s dependency on imported

oil. The economic impact of adding to domestic oil

production or reducing the cost of imported oil is very

significant. For example, in 2015, if the cost per

barrel of oil is reduced by one dollar, the overall

savings to the economy would be over $8 billion. If

domestic production of liquid fuels could be increased

by one million barrels per day, the U.S. balance of

payments could be reduced by nearly

$150 billion over the period 2015–2030. The CCT

Program is responding to this opportunity through

development and demonstration of mild gasification

and liquid-phase methanol production technology.

U.S. coal is exported to more than 40 nations and

amounted to 89 million tons in 1995. Coal exports to

foreign destinations contributed $3.5 billion to the

U.S. balance of payments in 1995. Worldwide demand for energy is expected to reach 542 quadrillion

Btu by 2015, 1.6 times the current level. According to

EIA, worldwide coal use is expected to account for

about 25 percent of total energy consumption. Exports of U.S. coal are projected to increase during this

period to over 120 million tons.

The worldwide market for power generation

technologies could be as high as $1 trillion by 2015.

National energy security is enhanced by coal cleaning technology being

demonstrated at this Custom Coals facility.
Program Update 1996-97 1-13

Capturing just 20 percent of this market would bring

in revenues of $200 billion and support more than

100,000 jobs over three decades in the U.S. power

equipment industry alone. This market provides

opportunities for U.S. technology suppliers, developers, architect/engineers, and other U.S. firms to capitalize on the advantages gained through experiences in

the CCT Program. However, other governments are

recognizing the enormous economic benefits that their

economies can enjoy if their manufacturers capture a

greater share of this market.

Other DOE activities are aimed at creating a

favorable export climate for U.S. coal and coal technology. These efforts will (1) improve the visibility of

U.S. firms and their products by establishing an

information clearinghouse and closer liaison with U.S.

representatives in other countries, (2) strengthen

interagency coordination of federal programs

pertinent to these exports, and (3) improve current

programs and policies for facilitating the financing

of coal-related projects abroad.

Coal Technology for the Future

DOE has structured an integrated Coal and

Power Systems Research, Development, and

Demonstration (RD&D) Program with the mission

to foster the development and deployment of

advanced, clean, affordable power systems and

technologies for the clean utilization of coal.

Pursuit of this mission is to assure an ample, secure, clean, low-cost domestic electricity and

domestic fuel supply through viable technical

options. This mission has a key role in achieving

the national energy policy goals of sustainable development. Sustainable development involves a simultaneous commitment to economic prosperity, social

equity, and ecological integrity.

The technology strategy followed in the integrated coal and power systems program is to (1) build on

past R&D successes and experience, (2) build a

portfolio of technologies including advanced, revolutionary and “leap frog” technologies, (3) provide

timely and effective dissemination of technology

results, and (4) use analyses as a guiding tool in

RD&D direction.

The role of the Coal and Power Systems RD&D

Program in advancing clean coal technology’s future

is shaped by a number of realities:

• Utility deregulation and the promotion of

competition is having a profound effect on the

utility sector’s approach to R&D, resulting in

sharply reduced private R&D funding and

shifting the emphasis to projects with immediate or near-term payoffs.

• The era of flat or slowly rising oil prices has

resulted in nearly total abandonment of

liquefaction technologies RD&D funding by

the private sector, as the time horizon is too

long to achieve the required near-term payback.

• Increased pressure on Coal and Power Systems

RD&D budgets for deficit reduction will likely

continue for the foreseeable future, thus

RD&D assures that clean, affordable coal technologies will be

available in the future. Air Product’s LaPorte coal liquefaction test

facility (left) and Southern Company Services’ Wilsonville power system

development facility (right) contribute to RD&D efforts.
1-14 Program Update 1996-97

requiring innovative approaches for leveraging

public-sector funds with private-sector

resources in order to achieve the mission

objectives.

• Industry and government support for RD&D

of a broad portfolio of technologies is necessary if the domestic and global environmental

challenges are to be met efficiently and

economically and if U.S. industry is to

maintain its position of leadership in world

trade of coal and power systems technologies.

Under the Coal and Power Systems Program,

RD&D are pursued in three primary product lines:

• Advanced power generation systems

• Environmental systems

• Coal fuels and industrial systems

The advanced power systems program will pursue

the completion of the 10 remaining CCT Program advanced power systems projects and the dissemination

of the technical, economic, and environmental results

into the domestic and international marketplace. Further, advances will be pursued in the product line portfolio, including low-emission boiler systems, pressurized fluidized bed combustion, integrated gasification

combined-cycle systems, indirect-fired cycles, gasification-fuel cell combinations, advanced gas turbines,

fuel cells, and hybrid fuel-cell-turbine cycles. The potential performance efficiencies of these systems range

from mid-40 percent up to 70 percent. The goal is to

achieve these performance levels while reducing cost

of electricity by 10–20 percent and emissions by 70–

90 percent over current standards.

The environmental control technology portfolio

includes super-clean emission control devices for the

removal of SO2

 and NOx from power plant flue gases,

hazardous air pollutant controls, innovative technologies for CO2

 management leading to near-zero emissions, and solid waste reduction, disposal, and use approaches. Specific goals are to develop new, advanced environmental control technologies by 2015,

primarily to meet existing and pending regulations on

gas-phase HAPs and NOx. The target is to attain

70–90 percent reduction in NOx at 25–50 percent of

current costs and to achieve 90 percent reduction in

HAPs at one-half the cost of current alternative technologies. Further, the remaining four CCT Program

environmental control device projects will be completed and the technical, environmental, and economic

results disseminated. The results from the 24 CCT

Program HAPs monitoring projects will be analyzed

and disseminated.

The coal fuels and industrial systems product line

program is to develop an RD&D portfolio in liquid

fuels technology that could be used for the conversion

of coal, natural gas, oil shale, biomass, and other

carbonaceous resources on a cost-competitive basis.

Further, the coproduction of liquids and power is

being pursued. Coal preparation technologies will

emphasize advanced methods for removing inorganic

matter that causes air toxics and other air pollutants.

Industrial systems technologies will assure that industrial steam coal users and other users, such as the steel

industry, will have advanced, high-efficiency and lowemission technologies available that will keep the

energy contribution to the final product cost low and

the product cost-competitive in the global marketplace. Further the program includes the completion of

the CCT Program’s two industrial applications

projects and the four coal processing for clean fuels

projects. Once completed the technical, economic,

and environmental results will be disseminated to the

domestic and international marketplace.

The above product line programs are undergirded

by advanced research that provides the fundamental

science and engineering basis for future fossil energy

concepts. The specific strategy is to

(1) develop by 2005 key and critical evolutionary

technologies that will improve performance and

reduce costs of advanced power, environmental

control, and fuels production systems while creating

derivatives that will have immediate high-value

applications; (2) develop by 2010 revolutionary

technologies and processes with the potential for

substantial improvements and advances in product

line systems; and (3) develop by 2015 a series of

“leap frog” technologies, such as advanced CO2

management schemes, advanced hybrid process and

cycles, smart systems, and others to address the

significant issues of the early 21st century. These

issues relate to achieving net-zero emissions and

closing the fossil-fuel cycle to use fossil energy

resources more effectively as part of sustainable

development.
Program Update 1996-97 2-1

2. Program Implementation

Introduction

The CCT Program founding principles and

implementing process resulted in one of the most

successful cost-shared government/industry partnerships forged to date to respond to critical national

needs. Through five nationwide competitions, a total

of 39 projects, valued at nearly $6 billion, were

implemented. Of this total, the industry cost-share is

an unprecedented 66 percent. Half the projects have

reached successful completion. The balance are

moving forward, with operational testing under way

for 10 projects

Over the 9-year period of soliciting and awarding

projects, the thrust of the environmental concerns

relative to coal use changed. But the adopted implementing process allowed the program to remain

responsive to the changing needs. The result is a

portfolio of technologies and a data base that will

enable coal to remain a major contributor to the U.S.

energy mix without being a threat to the environment.

This will ensure secure, low-cost energy requisite to a

healthy economy well into the 21st century.

Success of the CCT Program is measured by the

degree to which demonstrated technologies are placed

into commercial service. This was a driving force in

establishing the principles that created the foundation

for the implementation process. The government role

is non-traditional, moving away from a command-andcontrol approach to a performance-based approach,

where the government sets performance objectives and

industry responds with its ideas and is allowed broad

latitude in technical management of the projects. This

encourages technology innovation and cost-sharing.

The implementing process also provides for public

participation. Industry and the public play major roles

in this process, reflecting their respective roles in

moving technologies into the marketplace.

Implementation Principles

The principles underlying the CCT Program were

developed after much study of previous government

demonstration programs, those meeting with both

positive and negative results. Together, the principles

represent a composite of incentives and checks and

balances that allows all participants to best apply their

expertise and resources. These guiding principles are

outlined below.

• A strong and stable financial commitment

exists for the life of the projects. Full funding

for the government’s share of selected projects

was appropriated by Congress at the outset of

the program. This up-front commitment has

been vital to getting industry’s response in

terms of quantity and quality of proposals

received and the achievement of

65 percent cost-sharing.

• Multiple solicitations spread over a number

of years enabled the program to address a

broad range of national needs with a

portfolio of evolving technologies. Allowing

time between solicitations enabled Congress to

adjust the goals of the program to meet

changing national needs, provided DOE time

to revise the implementation process based on

lessons learned in prior solicitations, and

provided industry the opportunity to develop

better projects and more confidently propose

evolving technologies.

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

Typically a technology is constructed at

commercial scale with full system integration,

reflective of its intended commercial configuration, and operated as a commercial facility

or installed on an existing commercial facility.

This enables the technology’s performance

potential to be judged in the intended commercial environment.

• The technical agenda is determined by

industry, not the government. Based on

goals established by Congress and policy

guidance received, DOE set definitive performance objectives and performance-based

evaluation criteria against which proposals

would be judged. Industry was given the

flexibility to use their expertise and innovation

to define the technology and proposed project
2-2 Program Update 1996-97

in response to the objectives and criteria. DOE

selected the projects based on those that best

met the evaluation criteria.

• Roles of the government and industry are

clearly defined and reflect the degree of costsharing required. The government plays a

significant role up front in structuring the

cooperative agreements to protect public

interests. This includes negotiating definitive

performance milestones and decision points

throughout the project. Once the project

begins, the industrial participant is responsible

for technical management, while the government oversees the project through aggressive

monitoring and engages in implementation only

at decision points. Continued government

support is assured as long as project milestones

and terms and conditions of the original

cooperative agreement continue to be met.

• At least 50 percent cost-sharing is required

throughout all project phases. Industry’s

cost-share was required to be tangible and

directly related to the project, with no credit for

previous work. By sharing essentially in each

dollar expended along the way, on at least an

equal basis, industry’s commitment to fulfilling

project objectives was ensured.

• Allowance for cost growth provides an

important check-and-balance feature to the

program. Statutory provisions allow for

additional financial assistance beyond the

original agreement in an amount up to 25 percent of DOE’s original contribution. Such

financial assistance, if provided, must be costshared by the industrial participant at no less

than the cost-share ratio of the original

cooperative agreement. This statutory provision recognizes the risk involved in first-of-akind demonstrations by allowing for cost

growth. At the same time, it recognizes the

need for the industrial participant’s commitment to share cost growth and limits the

government’s exposure.

• Industry retains real and intellectual

property rights. The level of cost-sharing

warrants the industrial participant retaining

intellectual and real property rights and

removes potential constraints to commercialization. Industry would otherwise be reluctant

to come forward with technologies they have

developed to the point of demonstration,

relinquishing their competitive position.

• Industry must make a commitment to

commercialize the technology. Consistent

with program goals, the industrial participant is

required to make the technology available on a

nondiscriminatory basis to all U.S. companies

that seek, under reasonable terms and conditions, to use the technology. While the

technology owner is not forced to divulge

know-how to a competitor, the technology

must be made available to potential domestic

users on reasonable commercial terms.

• Upon successful commercialization of the

technology, repayment up to the government’s cost-share is required. The repayment obligation occurs only upon successful

commercialization of the technology. It is

limited to the government’s level of costsharing and the 20-year period following

demonstration.

In summary, there are built-in checks and balances

to ensure that the industry and government roles are

appropriate and that the government serves as a risksharing partner without impeding industry from utilizing its expertise and getting the technology into the

marketplace.

Implementation Process

Significant public and private sector involvement

was integral to the process leading to technology

demonstration and critical to program success. Even

before engaging in a solicitation, a public process was

instituted under the National Environmental Policy Act

(NEPA) to review whether the planned course of action

was prudent. A programmatic environmental impact

assessment (PEIA), followed by a programmatic

environmental impact statement (PEIS), was prepared

prior to initiating solicitations. Public comment and

resolution of comments were required prior to proceeding with the program.

As to the solicitation process, Congress set the

goals for each solicitation in the enabling legislation

and report language (see Appendix A for legislative

history and Appendix B for program implementation

history). DOE translated the congressional guidance

and direction into performance-based criteria and

developed approaches to address lessons learned from

previous rounds. Before proceeding with a solicitation, however, an outline of the impending solicitation
Program Update 1996-97 2-3

and attendant issues and options was presented in a

series of regional public meetings to obtain input. The

public meetings were structured along the lines of

workshops to facilitate discussion and obtain comments

from the broadest range of interests. Comments from

the public meetings were then used in preparing a draft

solicitation, which in turn was issued for public comment. Comments received were formally resolved

prior to solicitation issuance.

To aid proposers, preproposal conferences were

held for the purpose of clarifying any aspects of the

solicitation. Further, every attempt was made in the

solicitation to impart a clear understanding of what was

being sought, how it would be evaluated, and what contractual terms and conditions would apply. A section

was devoted to helping potential proposers determine

technology eligibility, and numerical quantification of

the evaluation criteria was provided. The solicitation

also contained a model cooperative agreement with the

key relevant contractual terms and conditions.

Project selection and negotiation leading to award

were conducted under stringent rules carrying

criminal penalties for non-compliance. Proposals were evaluated and projects negotiated

strictly against and within the criteria and terms

and conditions established in the solicitation. In

the spirit of NEPA, information required and

evaluated included project-specific environmental, health, safety, and socioeconomic

aspects of project implementation.

Upon project award, another public process

was engaged to ensure that all site-specific

environmental concerns were addressed. NEPA

requires that a rigorous environmental assessment be conducted to address all potential

environmental, health, safety, and socioeconomic

impacts associated with the project. The findings can

precipitate a more formal environmental impact

statement (EIS) process, or the findings can remain as

an environmental assessment (EA) along with a

finding of no significant impact. Under an EIS, public

meetings are held for the purpose of disclosing the

intended project activities, with emphasis on potential

environmental, health, safety, and socioeconomic

impacts and planned mitigating measures. Comments

are sought and must be resolved before the project can

proceed. This has led to additional actions taken by

the industrial participant beyond the original project

scope. To facilitate the NEPA process, DOE encouraged environmental data collection through costsharing during the negotiation period contingent upon

project award.

Because of the environmental nature of the CCT

Program, DOE took a proactive posture in carrying

out the principles of NEPA. Environmental concerns

were aggressively addressed and the public engaged

prior to major expenditure of public funds. Furthermore, DOE required that an in-depth environmental

monitoring plan (EMP) be prepared, fully assessing

potential pollutant emissions, both regulated and

unregulated, and defining the data to be collected and

the methodology for collection. All cooperative

agreements required preparation of environmental

monitoring reports that provide results of the monitoring activities. As discussed previously, as environmental issues emerged, every effort was made to address

them directly with the understanding that commercial

technology acceptance hinged on satisfying users and

the public as to acceptable environmental performance.

Appendix C reviews the proactive environmental

stance taken by the program, further delineates the

NEPA process, and provides the status of key actions.

Projects are managed by the participant, not the

government. However, public interests are protected

by requiring defined periods of performance referred to

as budget periods, throughout the project. Budget

periods are keyed to major decision points. A set

amount of funds are allotted to each budget

period, along with performance criteria to be

met before receiving funds for the next budget

period. These criteria are contained in project

evaluation plans (PEPs). Progress reports and

meetings during budget periods serve to keep

the government informed. At the decision

points, progress against PEPs is formally

evaluated, as is the PEP for the next budget

period. Financial data is also examined to

ensure the participant’s capability to continue

required cost-sharing. Failure to perform as

expected results in greater government involvement in the decision-making process.

Proposal of major project changes precipitates

The NEPA process assured environmental acceptability of the Healy

Clean Coal Project on the border of Denali National Park in Alaska.
2-4 Program Update 1996-97

not only in-depth programmatic assessment, but legal

and procurement review as well. Decisions regarding

continuance into succeeding budget periods, any

increase in funding, or major project changes require

the approval of the Assistant Secretary with program

responsibility.

Beyond the formal process associated with the

solicitations, parallel efforts were conducted to inform

stakeholders of ongoing events, results, and issues, and

to engage them in discussion on matters pertinent to

ensuring that the program remained responsive to

needs. A continuing dialog was facilitated by direct

involvement in the projects of a large number of

utilities, technology suppliers, and states as well as key

industry-based research organizations (e.g., EPRI and

GRI). This was accompanied by executive seminars

designed to fill communications gaps in the utility,

independent power production, regulatory, and financial sectors. The approach was to identify those sectors where inputs were missing and then structure

seminars to provide information on the program and

obtain the executives’ perspectives and suggestions for

enhancing program performance. An annual CCT

conference was instituted to serve as a forum for

updating progress and results and discussing issues. A

CCT outreach program (discussed in Section 4) was

put in place to ensure that needed information was

prepared and disseminated in the most efficient manner, leveraging a variety of domestic and international

conferences, symposia, and workshops.

During implementation of the CCT Program, many

precedent-setting actions were taken and many innovations were used by both the public and private sectors

to overcome procedural problems, create new management systems and controls, and move toward accomplishment of shared objectives. The experience

developed in dealing with complex business arrangements of multi-million-dollar CCT projects is a significant asset that has contributed greatly to the CCT

Program’s success—an asset of value to other programs seeking to forge government/industry partnerships. Because of this, The Clean Coal Technology

Program Lessons Learned was published in July 1994.

This report documents the knowledge acquired over

the course of the CCT Program through the completion

of five solicitations. The report was based on the

belief that it is of mutual advantage to the private and

public sectors to identify those factors thought to

contribute to the program’s success and to point out

pitfalls encountered and corrective actions taken.

Commitment to Commercial

Realization

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

environmental, efficiency, and economic benefits of

the technologies being demonstrated in the program

will be realized only if the technologies achieve

widespread commercial success. The importance

attached to commercial realization of clean coal

technologies is highlighted in Senate Report 99-82,

which contains the following recommendation for

project evaluation criteria: “The project must demonstrate commercial feasibility of the technology or

process and be of commercial scale of such size as to

permit rapid commercial scale-up.”

The commitment to commercial realization

recognizes the complementary but distinctive roles of

the technology owner and the government. It is the

technology owner’s role to retain and use the information and experience gained during the demonstration

and to promote the utilization of the technology in the

domestic and international marketplace. The detailed

technical, economic, and environmental data and

experience gained during the demonstration are vital to

efforts to commercialize the technology. The government’s role is to capture, assess, and transfer sufficient

technical, economic, and environmental information to

a broad spectrum of the private sector and international

community to allow potential commercial users to

confidently screen the technologies and to identify

those meeting operational requirements. The importance of commercial realization is confirmed by the

requirement in the solicitations and cooperative agreements that the project participant must pursue commercialization of the technology after successful demonstration.

Each of the five solicitations contained requirements for the project proposals to include a discussion

of the commercialization plans and approaches to be

used by the participants. The proposer was required to

discuss the following topics:

• The critical factors required to achieve commercial deployment, such as financing, licensing, engineering, manufacturing, and marketing

• A timetable identifying major commercialization goals and schedule for completion

• Additional requirements for demonstration of

the technology at other operational scales as

well as significant planned parallel efforts to the

demonstration project that may affect the

commercialization approach or schedule
Program Update 1996-97 2-5

Exhibit 2-1

CCT Program Selection Process Summary

Projects in

Proposals Projects CCT Program as

Solicitation PON Issued Submitted Selected of June 30, 1997

CCT-I February 17, 1986 51 17 8

CCT-II February 22, 1988 55 16 9

CCT-III May 1, 1989 48 13 13

CCT-IV January 17, 1991 33 9 5

CCT-V July 6, 1992 24 5 4

211 60 39

• The priority placed by senior management on

accomplishing the commercialization effort and

how the project fits into the various

corporation’s business, marketing, or energy

utilization strategies

The cooperative agreement contains three mechanisms to ensure that the demonstrated technology can

be replicated by responsible firms while protecting the

proprietary commercial position of the technology

owner:

• The commercialization clause requires the

technology owner to meet U.S. market demand

for the technology on a nondiscriminatory

basis. Further, this clause “flows down” from

the project participant to the project team

members and contractors.

• The clauses concerning rights to technical data

deal with the treatment of data developed

jointly in the project as well as data brought

into the project.

• The patent clause affords protection for new

inventions developed in the project.

In addition to ensuring implementation of the

above project-specific mechanisms, the government

role also includes the following functions:

• Developing and disseminating the technical,

economic, and environmental knowledge base

necessary for federal, state, and local governments to make sound policy and regulatory decisions regarding commercial CCT deployment

• Improving the regulatory and institutional

climate for deployment of demonstrated clean

summary of the procurement history and a chronology

of project selection, negotiation, restructuring, and

completion or termination. Project sites are mapped in

Exhibits 2-3 through 2-6, which indicate the geographic locations of projects by application category.

The resultant projects have achieved broad-based

industry involvement. Some 55 individual electric

generators serving 33 states have participated in the

program. These utilities generate more than 178,000

MWe, approximately 25 percent of U.S. capacity, and

consume about 36 percent of the coal produced domestically. Also participating were over 50 companies

supplying technology and 30 providing engineering,

construction, and consulting services.

The contributions of the selected projects to

domestic and international energy and environmental

needs are significant:

• Completed demonstration and proved commercial viability of a suite of cost-effective SO2

and NOx control options to achieve moderate

(50 percent) to deep emission reduction

coal technologies at a pace consistent with

domestic and international free market decision-making

• Informing the public of the increased efficiency, enhanced environmental quality, and

improved energy security benefits that can be

achieved through commercial use of CCTs

Solicitation Results

Each solicitation was issued as a Program Opportunity Notice (PON)—a solicitation mechanism for

cooperative agreements where the program goals and

objectives are defined but the technology is not. Proposals for demonstration projects consistent with the

objectives of the PON were submitted to DOE by

specific deadlines. DOE evaluated, selected, and

negotiated projects strictly within the bounds of the

PON provisions. Award was made only after Congress

was allowed 30 in-session

days to consider the projects

as outlined in Comprehensive Reports to Congress.

Exhibit 2-1 summarizes the

results of solicitations.

Exhibit 2-2 identifies the

projects currently in the

CCT Program (including

two projects that were

concluded in 1997) and the

solicitation under which the

projects were selected.

Appendix B provides a
2-6 Program Update 1996-97

Project and Participant Location

CCT-I

Development of the Coal Quality ExpertTM (ABB Combustion Engineering, Inc., and CQ Inc.) Homer City, PA

LIMB Demonstration Project Extension and Coolside Demonstration (The Babcock & Wilcox Company) Lorain, OH

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

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Hennepin and Springfield, IL

Tidd PFBC Demonstration Project (The Ohio Power Company) Brilliant, OH

Advanced Coal Conversion Process Demonstration (Rosebud SynCoal Partnership) Colstrip, MT

Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) Nucla, CO

ACFB Demonstration Project (York County Energy Partners, L.P.) To be determined

CCT-II

SNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) Niles, OH

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

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Dilles Bottom, OH

Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) Thomaston, ME

Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Chesterton, IN

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Coosa, GA

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

Demonstration of Selective Catalytic Reduction Technology for the Control of NOx

 Emissions from High-Sulfur-Coal-Fired Boilers Pensacola, FL

(Southern Company Services, Inc.)

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of NOx

 Emissions from Coal-Fired Lynn Haven, FL

 Boilers (Southern Company Services, Inc.)

CCT-III

Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Kingsport, TN

Company, L.P.)

10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) West Paducah, KY

Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Healy, AK

Full-Scale Demonstration of Low-NOx

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

Exhibit 2-2

Clean Coal Technology Demonstration Projects, by Solicitation
Program Update 1996-97 2-7

CCT-III (continued)

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) Seward, PA

Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) Burns Harbor, IN

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Department of Electric & Water Utilities) Lakeland, FL

ENCOAL® Mild Coal Gasification Project (ENCOAL® Corporation) Gillette, WY

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

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) Richmond, IN

Commercial Demonstration of the NOXSO SO2

/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) NOXSO site under negotiation

Charleston, TN

Integrated Dry NOx

/SO2 Emissions Control System (Public Service Company of Colorado) Denver, CO

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

CCT-IV

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air (Custom Coals International) Central City and Lower Mt. Bethel, PA

Richmond, IN

Ashtabula, OH

Micronized Coal Reburning Demonstration for NOx

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

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) Lansing, NY

Piñon Pine IGCC Power Project (Sierra Pacific Power Company) Reno, NV

Demonstration of Pulse Combustion in an Application for Steam Gasification of Coal (ThermoChem, Inc.) (project concluded) Not applicable

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

CCT-V

Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) Fairbanks, AK

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

Clean Energy Demonstration Project (Clean Energy Partners Limited Partnership) East coast site

McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, Department of Electric & Water Utilities) Lakeland, FL

Externally Fired Combined-Cycle Demonstration Project (Pennsylvania Electric Company) (project concluded) Not applicable

Project and Participant Location

Exhibit 2-2 (continued)

Clean Coal Technology Demonstration Projects, by Solicitation
2-8 Program Update 1996-97

Southern Company Services, Inc.

Coosa, GA

Public Service Company

of Colorado

Denver, CO

Energy and Environmental

Research Corporation

Denver, CO

Energy and Environmental

Research Corporation

Hennepin and

Springfield, IL

Exhibit 2-3

Geographic Locations of CCT Projects—Environmental Control Devices

AirPol, Inc.

West Paducah, KY

The Babcock & Wilcox

Company

Cassville, WI

Pure Air

on the Lake, L.P.

Chesterton, IN

New York State Electric & Gas Corporation

Lansing and Rochester, NY

The Babcock & Wilcox

Company

Lorain, OH

New York State

Electric & Gas Corporation

Lansing, NY

ABB Environmental Systems

Niles, OH

Bechtel Corporation

Seward, PA

The Babcock & Wilcox Company

Dilles Bottom, OH

The Babcock & Wilcox Company

Aberdeen, OH

LIFAC–North America

Richmond, IN

Southern Company Services, Inc.

Newnan, GA

Southern Company Services, Inc.

Pensacola, FL

Southern Company Services, Inc.

Lynn Haven, FL

Site under negotiation:

NOXSO Corporation
Program Update 1996-97 2-9

Alaska Industrial

Development and

Export Authority

Healy, AK

Sites under negotiation:

Clean Energy Partners Limited Partnership

York County Energy Partners, L.P.

Project concluded:

Pennsylvania Electric Company

Wabash River Coal Gasification

Repowering Project Joint Venture

West Terre Haute, IN

The Ohio Power

Company

Brilliant, OH

Exhibit 2-4

Geographic Locations of CCT Projects—Advanced Electric Power Generation

Sierra Pacific

Power Company

Reno, NV

Tampa Electric Company

Mulberry, FL

Tri-State Generation

and Transmission

Association, Inc.

Nucla, CO

City of Lakeland,

Department of Electric & Water Utilities

Lakeland, FL

Arthur D. Little, Inc.

Fairbanks, AK
2-10 Program Update 1996-97

Rosebud SynCoal

Partnership

Colstrip, MT

ENCOAL® Corporation

Gillette, WY

Custom Coals International

Central City, PA

Lower Mt. Bethel, PA

Richmond, IN

Ashtabula, OH

ABB Combustion

Engineering, Inc., and

CQ Inc.

Homer City, PA

Air Products Liquid

Phase Conversion

Company, L.P.

Kingsport, TN

Exhibit 2-5

Geographic Locations of CCT Projects—Coal Processing for Clean Fuels
Program Update 1996-97 2-11

CPICORTM Management

Company, L.L.C.

Vineyard, UT

Bethlehem Steel Corporation

Burns Harbor, IN

Exhibit 2-6

Geographic Locations of CCT Projects—Industrial Applications

Passamaquoddy Tribe

Thomaston, ME

Coal Tech Corporation

Williamsport, PA

Project concluded:

ThermoChem, Inc.
2-12 Program Update 1996-97

environmental rulings will have on the commercial

deployment of technologies demonstrated under the

CCT Program. The environmental performance data

from completed projects will be analyzed, documented, and distributed to potential users of the technology

as well as to environmental and regulatory stakeholders. This information and data can be considered

during the deliberations on new standards for the

reduction of acid rain precursors, hazardous air pollutants, and greenhouse gas emissions with the purpose of

assuring that new standards will be reasonable and

achievable in a cost-effective manner.

Technical and economic performance data from

the completed projects will be reviewed and analyzed

to identify opportunities to improve the competitiveness of the clean coal technologies. Opportunities

could lead to such benefits as reduced capital costs,

increased efficiencies, increased fuel flexibility, or

reduced cost of electricity to the customer by offsetting

production costs through co-product profits. Timely

identification of opportunities to improve the competitive position of clean coal technologies is essential to

achieving these objectives as the utility sector moves

into the era of deregulation and competition. These

opportunities could be acted on by program stakeholders such as technology suppliers, and federal, state, and

industry RD&D organizations.

The CCT Program will continue to refine the

effectiveness of the outreach program in reaching and

informing all customers and stakeholders about the

program and its projects and improving the perception

of coal as a low-cost, environmentally acceptable fuel.

In order to accomplish this objective, participation of

the CCT Program stakeholders/customers will be

pursued vigorously with a view toward establishing

(70–95 percent) for the full range of coal-fired

boiler types

• Provided the data base and operating experience requisite to making AFBC a commercial

technology at utility scale

• Completing demonstration of a number of coal

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

of coal types

• Currently laying the foundation for the next

generation of technologies to meet the energy

and environmental demands of the 21st century:

- Three IGCC plants in operation at three

separate utilities

- Demonstration of PFBC at 70 MWe successfully completed and two larger scale demonstrations in progress

• Demonstrating significant efficiency and

pollutant emission reduction enhancements in

Publications keep stakeholders informed of CCT

Program contributions.

steelmaking; advanced combustion for combined SO2

, NOx, and particulate control for

industrial/small utility boilers; and innovative

SO2

 control for waste elimination in cement

production

Future Implementation Direction

The future implementation direction of the CCT

Program focuses on completing the existing projects as

promptly as possible and assuring the collection,

analyses, and reporting of the technical, economic, and

environmental performance data necessary to support

subsequent commercialization activity. During 1997,

the following projects are expected to complete operational testing:

• Demonstration of Advanced Combustion

Techniques for a Wall-Fired Boiler

• Self-Scrubbing CoalTM: An Integrated Approach to Clean Air

• ENCOAL® Mild Coal Gasification Project

Further, the following projects are scheduled to

begin their operational phase:

• Micronized Coal Reburning Demonstration for

NOx Control

• Piñon Pine IGCC Power Project

• Commercial-Scale Demonstration of Liquid

Phase Methanol (LPMEOHTM) Project

Assessments will be made of the impacts that

evolving and anticipated domestic and international
Program Update 1996-97 2-13

Issue 2: International Markets—Seizing the

Opportunity

The following initiatives were identified to address

international market opportunities for CCTs:

• In view of the growing evidence that a number

of countries have been confused by the conflicting information and advice received about

CCTs and with evidence that a number of U.S.

senior energy company executives are unaware

of the breadth of the CCT Program, increased

efforts in education should be undertaken.

• Efforts should be focused and concentrated on a

few key growth areas, such as China and India.

• A consensus needs to be developed as to what

are the main barriers to technology deployment

within individual countries. Further, a strategy

should be developed to collectively overcome

these barriers.

• Private sector/government cooperation on

efforts to disseminate technical and economic

information about CCTs is important. Further,

a recommendation was made that the distribution of this data be accomplished under the

auspices of the International Energy Agency as

part of the World Bank’s clean coal initiative.

• The next Annual Clean Coal Technology

Conference should contain a session during

which progress on overseas demonstration

projects would be reported, and increased

efforts should be made to invite representatives—decision makers as well as technical and

financial advisors—from key market areas to

cooperative activities to advance

compatible agendas. These activities could involve CCT project site

visits by interested stakeholders/

customers, expansion of the audience in attendance at the Annual

Clean Coal Technology Conference, expanded support for international technology conferences, and

increased support for state-level

education programs.

The Fifth Annual Clean Coal

Technology Conference provided

an opportunity to elicit recommendations for the future direction of

the CCT Program from nearly 300

stakeholders by addressing four

key issues facing the program as it

moves into the next millennium.

Issue 1: Role of CCTs in the Evolving Domestic

Electricity Market

A number of initiatives were suggested to enhance

the entry of CCTs into the marketplace.

• Private sector initiatives could focus on

(1) coproduction (including tri-generation of

electricity, heat, and chemicals) in order to

bring the price of electricity down; (2) cofiring

with lower grade fuels; (3) development of

standardized plants and modular production to

lower capital costs; and (4) development of

integrated projects (e.g., minemouth plants)

within the coal sector to improve the competitive position of coal with respect to natural gas.

Clean coal technology conferences provide a forum for public input for future

program direction.

• Public sector (including federal and state)

initiatives conceived were (1) identification of

new approaches to support “favored technologies” while transitioning to deregulation, such

as a nonbypassable “wire” charge to collect

funds to support favored technology RD&D;

(2) the implementation of a portfolio standard

that requires sellers to obtain a certain percentage of their power from favored technologies,

and the introduction of regulatory requirements

favorable to certain technologies; (3) incentives

for overseas deployment of CCTs in order to

demonstrate the technologies adequately by the

time they are needed domestically; and (4)

recognition of the benefits of fuel diversity

represented by the continued use of coal.
2-14 Program Update 1996-97

identify what information they require to

enhance the “market pull” of CCTs.

Issue 3: Environmental Issues Affecting CCT

Deployment

The environmental issues that affect clean coal

technology deployment and power development were

found to be both international and domestic in nature.

• Environmental guidelines and requirements

facing developers of international projects are

promulgated by various entities, including

multi-national, regional, or national development banks, private banks, finance companies,

the host country, or other organizations. These

guidelines may be procedural or operational in

nature, and they constitute a confusing matrix

for the developer. It was recommended that the

World Bank expedite the finalization of its

guidelines. Further, it was noted that developers should work with all entities that might

affect the project. Giving attention during early

project definition to the environmental aspects

of site selection, baseline data and monitoring

requirements, and public perception could

reduce environmental compliance uncertainties.

• Domestically, it was believed that the cap-andtrade approach outlined in CAPI would result in

cost savings over the command-and-control

approach and should be encouraged. Further,

EPA was encouraged to explore peak-shaving

approaches to some problems, such as ozone

attainment, as cost-effective measures. With

respect to CO2

, it was recommended that any

agreements on emission targets should be multiyear, involve a time horizon that is long enough

to allow normal rather than premature turnover

of capital stock, and allow for emissions trading

and joint implementation. It also was recognized that electro-technologies could lead to

total emissions reductions when electricity is

substituted for direct fossil-fuel combustion.

Finally, the importance of educating congressional members as well as the public on CCTs

was recognized.

Issue 4: CCT Deployment—From Today into

the Next Millennium

A number of uncertainties that are creating barriers

and hurdles for the deployment of CCTs were identified. These barriers included the restructuring of the

electric utility industry and the subsequent associated

postponement of the installation of coal-fired capacity;

increased competition from cheap natural gas and

maturing advanced natural gas power generation

technologies; CCTs being perceived as high-cost,

unproven technologies; and uncertainty of environmental regulations with the potential that plant upgrading

and retrofits will trigger revised NSPS.

The following initiatives were suggested to overcome some of these barriers:

• Utility restructuring legislation should emphasize use of domestic resources and contain

environmental and reliability provisions to

encourage the use of retrofit technologies.

• Technical initiatives should include standardization of facilities, recognition that some

technologies are commercial and no longer in

the demonstration phase, reduction of operating

expenses through the use of smart systems,

encouragement of dual-fuel generating capacity, the use of technologies capable of multiproduct production, and/or the use of multiple

feedstocks.

• Government incentives should include expedited permitting, local tax incentives, targeted

export assistance, and expanded state/federal

coordination.

• Other near-term actions might include developing a comprehensive document listing state and

local incentives (i.e., update ICTAP’s

1989 Report to the Secretary of Energy

Concerning Commercialization Incentives);

conducting an international conference on

IGCC that would explore integration with other

processes, products, and feedstocks; initiating a

program to offer federal and state regulators

tours of CCT project sites; and making Congress aware of the need to increase the use of

domestic resources and to encourage dual-fuel

standards to assure electric system reliability.

Finally, the need was recognized for a vigorous

outreach and education program that would

promote awareness of the CCT Program and its

projects and erase the perceived stigma of coal

in general.
Program Update 1996-97 3-1

3. Funding and Costs

full amount of the federal government’s contribution.

This approach enables taxpayers to benefit from

commercially successful projects. This is in addition

to the benefits derived from the demonstration and

commercial deployment of technologies that improve

environmental quality and promote the efficient use of

the nation’s energy sources.

The participant has primary responsibility for the

project. The federal government monitors project

activities, provides technical advice, assesses progress

Summary

Congress has appropriated a federal budget of

nearly $2.41 billion for the CCT Program. These

funds have been committed to demonstration projects

selected through five competitive solicitations. As of

June 30, 1997, the program consisted of 39 active or

completed projects.

These 39 projects have resulted in a combined

commitment by the federal government and the

private sector of more than $5.7 billion. DOE’s costshare for these projects exceeds $1.9 billion, or

approximately 34 percent of the total. The project

participants (i.e., the non-federal-government participants) are providing the remaining $3.8 billion, or

66 percent of the total. Exhibit 3-1 summarizes the

total costs of CCT projects as well as cost-sharing by

DOE and project participants.

Program Funding

In the CCT Program, the federal government’s

contribution can not exceed 50 percent of the total

cost of any individual project. The federal governments funding commitments and other terms of federal assistance are represented in a cooperative agreement negotiated for each project in the program.

Terms of the cooperative agreement also include a

plan for the federal government to recoup up to the

Exhibit 3-1

CCT Project Costs and Cost-Sharing

(Dollars in Thousands)

Total Cost-Share Percent

Project Costs % DOEb Participants DOE Participants

Subprogram

CCT-I 801,469 14 239,645 561,824 30 70

CCT-II 319,177 6 139,520 179,657 44 56

CCT-III 1,409,387 25 618,947 790,440 44 56

CCT-IV 1,029,203 18 472,752 556,451 46 54

CCT-V 2,163,952 37 461,128 1,702,824 21 79

Totala 5,723,188 100 1,931,992 3,791,196 34 66

Application Category

Advanced Electric Power 3,220,239 56 1,219,011 2,001,228 38 62

Generation

Environmental Control Devices 704,862 12 295,191 409,671 42 58

Coal Processing for Clean Fuels 519,196 9 230,024 289,172 44 56

Industrial Applications 1,278,891 23 187,766 1,091,125 15 85

Totala 5,723,188 100 1,931,992 3,791,196 34 66

a Totals may not appear to add due to rounding.

b DOE share does not include $53,712,000 obligated for withdrawn and terminated projects.
3-2 Program Update 1996-97

and includes federal employees’ salaries, benefits and

travel, site support services, and services provided by

national laboratories and private firms.

Availability of Funding

Although all funds necessary to implement the

entire CCT Program were appropriated by Congress

prior to FY 1990, the legislation also directed that

these funds be made available (i.e., apportioned) to

DOE on a time-phased basis. Exhibit 3-3 depicts this

apportionment of funding to DOE from FY 1986,

when the program was initiated, through FY 1997,

when the final increment of funding became available

to DOE. Exhibit 3-3 also shows the program’s yearly

funding profile by appropriations act and by subprogram. Funds can be transferred among subprogram

budgets to meet project and program needs.

Use of Appropriated Funds

There are five key financial terms used by the

government to track the status and use of appropriated

funds: (1) budget authority, (2) commitments, (3) obligations, (4) costs, and (5) expenditures. The definition of each of these terms follows:

• Budget Authority. This is the legal authorization created by legislation (i.e., an appropriations act) that permits the federal government to obligate funds.

• Commitments. Within the context of the CCT

Program, a commitment is established when

DOE selects a project for negotiation. The

commitment amount is equal to DOE’s share of

the project costs contained in the cooperative

agreement.

Exhibit 3-2

Relationship between Appropriations and Subprogram Budgets

for the CCT Program

(Dollars in Thousands)

SBIR Program

Appropriation Adjusted & STTR Direction Projects

Enacted Subprogram Appropriations Budgetsa Budget Budget

P.L. 99-190 CCT-I 380,600 4,902 318,231 318,231

P.L. 100-202 CCT-II 574,997 6,781 32,512 535,704

P.L. 100-446 CCT-III 574,998 6,906 22,548 545,544

P.L. 101-121b CCT-IV 427,000 7,065 25,000 394,935

P.L. 101-121b CCT-V 450,000 5,427 25,000 419,573

Total 2,407,595 31,081 162,527 2,213,987

a Small Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs.

b P.L. 101-121 was revised by P.L. 101-512, 102-154, 102-381, 103-138, 103-332, 104-6, 104-208, and 105-18.

CCT-III, CCT-IV, and CCT-V. Additional activities

funded by CCT Program appropriations are the Small

Business Innovation Research (SBIR) Program, the

Small Business Technology Transfer (STTR) Program, and CCT program direction.

The SBIR Program implements the Small Business Innovation Development Act of 1982 and provides a role for small, innovative firms in selected

research and development (R&D) areas.

The STTR Program implements the Small Business Technology Transfer Act of 1992 that establishes

a pilot program and funding for small business concerns performing cooperative R&D efforts.

The program direction budget provides for the

management and administrative costs of the program

by periodically reviewing project performance with

the participant, and participates in decision making at

major project junctures negotiated into the cooperative agreement. Through these activities, the federal

government ensures the efficient use of public funds in

the achievement of individual project and overall

program objectives.

Congress has provided program funding through

appropriation acts and adjustments. (See Appendix A

for legislative history and excerpts from the relevant

funding legislation.)

Exhibit 3-2 presents the allocation of appropriated CCT Program funds (after adjustment) and the

amount available for each CCT solicitation. The five

CCT solicitations are referred to as CCT-I, CCT-II,
Program Update 1996-97 3-3

Exhibit 3-3

Annual CCT Program Funding, by Appropriations and Subprogram Budgets

(Dollars in Thousands)

Fiscal Year 1986–87 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 Totald

Adjusted Appropriationsa

P.L. 99-190 248,500 149,100 (17,000) 380,600

P.L. 100-202 50,000 190,000 135,000 199,997 574,997

P.L. 100-446 419,000 155,998 574,998

P.L. 101-121b 35,000 315,000 0 100,000 18,000 50,000 (91,000) 427,000

P.L. 101-121b 100,000 0 125,000 19,121 100,000 105,879 450,000

Total 248,500 199,100 190,000 554,000 390,995 415,000 0 225,000 37,121 150,000 (2,121) 2,407,595

Subprogram Budgets

CCT-I Projects 241,958 145,273 (18,000) (18,000) (33,000) 318,231

CCT-II Projects 31,094 173,800 133,313 197,497 535,704

CCT-III Projects 391,496 154,048 545,544

CCT-IV Projects 9,875 311,063 0 98,450 17,622 48,925 (91,000) 394,935

CCT-V Projects 74,062 0 123,063 18,719 97,850 105,879 419,573

Projects Subtotal 241,958 176,367 173,800 524,809 361,420 385,125 0 221,513 18,341 128,775 (18,121) 2,213,987

Program Direction 3,479 20,500 14,000 22,548 25,000 25,000 18,000 18,000 16,000 162,527

Fossil Energy Subtotal 245,437 196,867 187,800 547,357 386,420 410,125 0 221,513 36,341 146,775 (2,121) 2,376,514

SBIR & STTRc 3,063 2,233 2,200 6,643 4,575 4,875 0 3,487 779 3,225 0 31,081

DOE Totald 248,500 199,100 190,000 554,000 390,995 415,000 0 225,000 37,121 150,000 (2,121) 2,407,595

a Shown are appropriations less amounts sequestered under the Gramm-Rudman-Hollings Deficit Reduction Act.

b Shown is the fiscal year apportionment schedule of P.L. 101-121 as revised by P.L. 101-512, 102-154, 102-381, 103-138, 103-332, 104-6, 104-208, and 105-18.

c Small Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs.

d Totals may not appear to add due to rounding.
3-4 Program Update 1996-97

0

100,000

200,000

300,000

400,000

500,000

600,000

86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06

Budget Authority

Obligations

Costs

Expenditures

actual performance

for FY 1986

through FY 1996

and DOE estimates

for FY 1997

through program

completion. Excluded from the

graph are SBIR and

STTR funds, as

these are used and

tracked separately

from the CCT

Program. The

financial projections

presented in Exhibit

3-4 are based on

individual project

schedules and

budget periods as

defined in the

cooperative agreements and modifications. The projections reflect

approved modifications to the cooperative agreements.

The financial status of the program through

June 30, 1997, is presented by subprogram in

Exhibit 3-5. SBIR and STTR funds are included in

this exhibit to account for all funding. Exhibit 3-5

also indicates the apportionment sequence as modified by Public Laws 104-208 and 105-18. These

values represent the amount of budget authority

available for the CCT Program.

• Obligations. The cooperative agreement for

each project establishes funding increments,

referred to as budget periods. The cooperative

agreement defines the tasks to be performed in

each budget period. An obligation occurs in the

beginning of each budget period and establishes

the incremental amount of federal funds

available to the participant for use in performing

tasks as defined in the cooperative agreement.

• Costs. A request for payment submitted by

the project participant to the federal government for reimbursement of tasks performed

under the terms of the cooperative agreement

is considered a cost. Costs are equivalent to a

bill for payment or invoice.

• Expenditures. Expenditures represent payment

amounts to the project participant from checks

drawn upon the U.S. Treasury.

The full government cost-share specified in the

cooperative agreement is considered committed to

each project. However, DOE obligates funds for the

project in increments. Most projects are subdivided

into several time and funding intervals, or budget

periods. The number of budget periods is determined

during negotiations and is incorporated into the

cooperative agreement. DOE obligates sufficient

funds at the beginning of each budget period to cover

the government’s cost-share for that period. This

procedure limits the government’s financial exposure

and assures that DOE fully participates in the decision

to proceed with each major phase of project implementation.

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

Project Funding, Costs, and Schedules

Information for individual CCT projects, including

funding and the status of key milestones, is provided in

Section 5. An overview of project schedules and funding is presented in Exhibit 3-6.

Cost-Sharing

A characteristic feature of the CCT Program is the

cooperative funding agreement between the participant

and the federal government referred to as cost-sharing.

Exhibit 3-4

CCT Financial Projections as of June 30, 1997

(Dollars in Thousands)

Fiscal Year
Program Update 1996-97 3-5

 Appropriations

 Allocated to Apportioned Committed Obligated Cost

Subprogram Subprogramb to Date to Date to Date to Date

1986 99,400 99,400

1987 149,100 248,500

1988 199,100 447,600

1989 190,000 637,600

1990 554,000 1,191,600

1991 390,995 1,582,595

1992 415,000 1,997,595

1993 0 1,997,595

1994 225,000 2,222,595

1995 37,121 2,259,716

1996 150,000 2,409,716

1997 (2,121) 2,407,595

CCT-I 318,231 318,231 257,157 251,967 188,787

CCT-II 535,704 535,704 171,488 172,317 165,216

CCT-III 545,544 545,544 618,947 523,489 416,951

CCT-IV 394,935 394,935 474,784 475,598 407,467

CCT-V 419,573 419,573 463,328 30,978 5,830

Projects Subtotal 2,213,987 2,213,987 1,985,704 1,454,349 1,184,251

SBIR & STTRa 31,081 31,081 31,081 31,081 31,081

Program Direction 162,527 162,527 162,527 150,732 143,928

Total 2,407,595 2,407,595 2,179,312 1,636,162 1,359,260

Apportionment Sequence

FY Annual Cumulative

a Small Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs

b Totals may not appear to add due to rounding.

Exhibit 3-5

Financial Status of the CCT Program as of June 30, 1997

(Dollars in Thousands)

• Investment in existing facilities, equipment, or

previously expended R&D funds are not

allowed for the purpose of cost-sharing.

Exhibit 3-1 summarizes the cost-sharing status by

subprogram and by application category for the 39

active or completed projects. In the advanced electric

power generation category, which accounts for 56 percent of total project costs, participants are contributing

62 percent of the funds. For the overall program,

participants are contributing 66 percent of the total

funding, or over $1.8 billion more than the federal

government.

• Cost-sharing by the project participants is

required throughout the project (design,

construction, and operation).

• The federal government may share in project

cost growth (within the scope of work defined

in the original cooperative agreement) up to

25 percent of the originally negotiated

government share of the project.

• The participant’s cost-sharing contribution must

occur as project expenses are incurred and

cannot be offset or delayed based on prospective

project revenues, proceeds, or royalties.

This cost-sharing approach, as implemented in the

CCT Program, was introduced in Public Law 99-190,

An Act Making Appropriations for the Department of

the Interior and Related Agencies for the Fiscal Year

Ending September 30, 1986, and for Other Purposes.

General concepts and requirements of the cost-sharing

principle as applied to the CCT Program include the

following elements:

• The federal government may not finance more

than 50 percent of the total costs of a project.
3-6 Program Update 1996-97

Exhibit 3-6

CCT Project Schedules and Funding, by Application Category

Calendar 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 DO

Year

B&W--LIMB Environmental Control Devices 7,5

SCS--Wall-Fired 6,5

EER--GR/SI 18,7

SCS--Tangentially Fired 4,4

Bechtel -- CZD 5,2

B&W--Coal Reburning 6,3

B&W--LNCB 5,4

ABB ES--SNOX 15,7

B&W--SNRB 6,0

Pure Air on the Lake 63,9

LIFAC 10,6

PSC of Colorado 13,7

AirPol -- GSA 2,3

EER--GR-LNB 8,8

SCS--CT-121 21,0

SCS--SCR 9,4

NYSEG -- Milliken 45,0

NYSEG -- Micronized 2,7

NOXSO Corporation Schedule being revised 41,4

 - Preaward - Design and Construction - Operation and Reporting
Program Update 1996-97 3-7

Exhibit 3-6 (continued)

CCT Project Schedules and Funding, by Application Category

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 DO

Year

Tri-State--Nucla Advanced Electric Power Generation 17,1

Ohio Power 66,9

Wabash River 219,1

Tampa Electric 150,8

Sierra Pacific 167,9

AIDEA 117,3

McIntosh 4A 93,2

McIntosh 4B 109,2

ACFB Schedule being revised 74,7

ADL--Coal Diesel Schedule being revised 19,1

Clean Energy Schedule being revised 183,3

ABB CE & CQ Inc. -- CQE Coal Processing for Clean Fuels 10,8

Rosebud SynCoal 43,1

ENCOAL 45,3

Custom Coals 37,9

Air Products -- LPMEOH 92,7

Coal Tech Industrial Applications 4

Passamaquoddy 5,9

Bethlehem Steel 31,8

CPICOR 149,4
3-8 Program Update 1996-97

Recovery of Government Outlays

(Recoupment)

DOE’s policy objective is to recover an amount

up to the government’s financial contribution to each

project. Participants are required to submit a plan

outlining a proposed schedule for recovering the

government’s financial contribution. The solicitations

have featured different sets of recoupment rules.

Under the first solicitation, repayment was derived from revenue streams that include net revenue

from operation of the demonstration plant beyond the

demonstration phase and the commercial sale, lease,

manufacture, licensing, or use of the demonstrated

technology. In CCT-II, repayment was limited to

revenues realized from the future commercialization

of the demonstrated technology. The government’s

share would be 2 percent of gross equipment sales and

3 percent of the royalties realized on the technology

subsequent to the demonstration.

The CCT-III repayment formula was adjusted to

1⁄2 percent of equipment sales and 5 percent of royalties. Limited grace periods were allowed on a projectby-project basis. A waiver on repayment may be

sought from the Secretary of Energy if the project

participant determines that a competitive disadvantage

would result in either the domestic or international

marketplace.

The recoupment provisions for CCT-IV and

CCT-V were identical to those in CCT-III.

As of June 30, 1997, five projects have made

repayments to the federal government: Nucla CFB

Demonstration Project (Tri-State Generation and

Transmission Association, Inc.); Full-Scale Demonstration of Low-NOx

 Cell Burner Retrofit (The Babcock & Wilcox Company); Development of the Coal

Quality ExpertTM (ABB Combustion Engineering,

Inc., and CQ Inc.); 10-MWe Demonstration of Gas

Suspension Absorption (AirPol, Inc.); and the Advanced Flue Gas Desulfurization Demonstration

Project (Pure Air on the Lake, L.P.).
Program Update 1996-97 4-1

4. CCT Program Accomplishments

Introduction

The success of the CCT Program ultimately will

be measured by the degree to which the technologies

are commercialized and by the contribution the technologies make to the resolution of energy, economic,

and environmental issues. This contribution can only

be achieved if those in the public and private sectors

understand that clean coal technologies can increase

the efficiency of energy use and enhance environmental

quality at costs that are competitive with alternative

energy options.

The CCT Program has continued efforts to define

and understand the potential domestic and international

markets for clean coal technologies. Domestically this

activity involved interviews with electric utility executives, public utility commissioners, and financiers.

Analyses were made of regional electric capacity

requirements, environmental compliance strategies, and

the effects of electric utility restructuring on the demand for clean coal technologies. International activities continued, providing information on clean coal

technologies and technical support to trade agencies,

trade missions, and financial organizations.

A highlight of the continuing CCT Program

outreach effort was the Fifth Annual Clean Coal Technology Conference, held in Tampa, Florida, and attended by almost 400 people, including 70 representatives

from 16 countries. This conference focused on strategies and approaches that will enable clean coal technologies to resolve the competing, interrelated demands

for power and economic viability in the face of environmental constraints to coal use in the post-2000 era.

The program addressed the dynamic changes that will

result from utility competition and industry restructuring, while considering the potential of evolving

foreign markets.

Throughout the year, the CCT Program staff

participated in over 15 domestic and international

events involving users and vendors of technologies,

regulators, financiers, environmental groups, and

other public and private institutions. Five issues of

the Clean Coal Today newsletter were published in

1996 and early 1997, along with the second annual

edition of the Clean Coal

Today Index, which crossreferences all articles published in the newsletter.

Publication of the first Clean

Coal Technology Program

Bibliography of Publications,

Papers, and Presentations

highlighted efforts to document demonstration projects

over the past 10 years. DOE

also continued expanded

coverage of the program by

publishing the 10th Anniversary issue of the annual report,

Clean Coal Technology

Demonstration Program:

Program Update 1995, and the second mid-year

update of project fact sheets, Clean Coal Technology

Demonstration Program: Project Fact Sheets.

Marketplace Commitment

The true measure of the CCT Program’s success

will be the degree to which the clean coal technologies

are adopted in the marketplace. The majority of the

projects involve demonstrations at full commercial

scale, providing the opportunity for the participants to

leave the technologies in place and continue operation

as part of their strategy to comply

with the Clean Air Act Amendments of 1990.

The number of complex,

capital-intensive projects put in

place is unprecedented, as is the

degree of cost-sharing achieved in

this cooperative government and

private sector technology development program. With government

serving as the risk-sharing partner,

industry funding has been leveraged to achieve the following

goals:

• Create jobs

• Improve the environment
4-2 Program Update 1996-97

• Reduce the cost of compliance with environmental regulations

• Reduce the cost of electricity generation

• Improve power generation efficiencies

• Position U.S.-based industry to export innovative services and equipment

Underlining the premise that success of the CCT

Program depends on adoption of the technologies in

the energy marketplace, project information is organized within four major product markets—environmental control devices, advanced electric power

generation, coal processing for clean fuels, and industrial applications. Thus, the CCT Program can be

viewed from a market perspective. This section highlights some of the program and project accomplishments to date along with commercialization successes

by market sector.

Environmental Control Devices

Because control of SO2 and NOx emissions from

existing coal-fired boilers was the initial thrust of the

program, 15 of the 19 environmental control device

projects, those dealing with retrofit of existing facilities, are completed. The completed demonstrations

proved commercial viability of a suite of cost-effective

SO2 and NOx control options for the full range of coalfired boiler types. Risk in successfully applying the

technologies commercially was significantly mitigated

by the extensive databases and attendant predictive

models developed through the demonstrations. Also,

projects were leveraged to provide input in formulating

NOx

 control requirements under the CAAA and to

evaluate the impact of emerging issues, such as air

toxics on the existing boiler population and control

• Advanced flue gas desulfurization (AFGD)

systems, sponsored by Pure Air and Southern

Company Services and having somewhat higher

capital costs than the other two approaches,

demonstrated SO2

 capture efficiencies in the

range of 90–95 percent. These systems are

primarily applicable to the larger, newer preNSPS units that have some latitude in space

availability.

The AFGD projects 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. This,

combined with integration of functions within the

absorber module and use of high throughput designs,

significantly reduced capital cost and space requirements. AFGD testing also established that wallboardgrade gypsum could be produced in lieu of solid waste;

wastewater discharge could be eliminated; and, by

mitigating corrosion, fiberglass-reinforced-plastic

fabrication could eliminate process steps (e.g., prequenching for chloride removal and flue gas reheat).

options. Extensive air toxics testing was performed in

conjunction with 10 of the environmental control

projects. To a great extent, the technologies were

retained for commercial service at the demonstration

sites and many have realized commercial sales.

SO2

 Control Technologies. All five SO2 control

technology demonstrations have been completed,

evaluating three basic approaches to address the

diverse pre-NSPS boiler population:

• Low-capital-cost sorbent injection systems,

sponsored by LIFAC–North America and

Bechtel Corporation, demonstrated SO2 capture

efficiencies in the range of 50–70 percent.

These systems hold particular promise for the

older, smaller pre-NSPS units, particularly

those with space constraints.

• A moderate-capital-cost gas-suspensionabsorption system, sponsored by AirPol, Inc.,

demonstrated SO2

 capture efficiencies in the

range of 60–90 percent. The system has

particular applicability to the small to midrange pre-NSPS units with some space limitations.

 SO2 control technologies: AirPol (left),

Pure Air (center), and LIFAC (right).
Program Update 1996-97 4-3

The Chiyoda CT-121 AFGD demonstration by

Southern Company Services showed that the system

could significantly enhance particulate control.

Pure Air on the Lake, L.P., introduced an innovative business concept whereby the company builds,

retains ownership, and operates scrubbers as a contracted service to a utility. Relieving utilities of the

burden of ownership and operation has proven to be an

attractive approach.

Commercialization successes to date are summarized in Exhibit 4-1.

NOx

 Control Technology. Five of the seven NOx

control technology demonstrations have been successfully completed. Actual testing was conducted on the

four major boiler types (wall-, tangential-, cyclonefired, and cell-burner boilers), representing over

90 percent of the pre-NSPS boiler population. Applicability extends to all boiler types.

The database developed during Southern Company

Services’ evaluation of NOx

 control on wall- and

tangential-fired boilers at Plant Smith and Plant Hammond was used by the Environmental Protection

Agency in formulating CAAA NOx

 provisions. Babcock & Wilcox’s low-NOx

 burner systems, ABB

Combustion Engineering’s LNCFSTM for tangentially

fired boilers, and Foster Wheeler’s low-NOx burner

system for wall-fired boilers have realized commercial

acceptance.

Integration of artificial intelligence, neural-network systems into digital boiler controls, such as the

Generic NOx Control Intelligence System (GNOCIS)

installed at Plant Hammond, demonstrated effective

optimization of parameters for NOx

 control and boiler

performance under load-following operations.

Exhibit 4-1

Commercial Successes—SO2 Control Technology

Project and Participant Commercialization Progress

LIFAC Sorbent Injection Desulfurization Technology retained for commercial use at host site

Demonstration Project (LIFAC–North First high-sulfur coal application

America) 10 commercial units in operation or construction (Canada, China,

Finland, Russia, and U.S.)

10-MWe Demonstration of Gas Suspension Sale of 50-MWe unit to city of Hamilton, OH

Absorption (AirPol, Inc.) – Value—$10 million

– Employment benefit—70 person-years

Sale to U.S. Army for hazardous waste disposal

– Value—$1.3 million

Sale to Sweden for iron ore sinter plant (no value available)

Sales to Taiwan and India

– Combined value—$33 million

– Employment benefit—10 person-years

Advanced Flue Gas Desulfurization Technology retained for commercial use at host site

Demonstration Project (Pure Air on the First scrubber installed to comply with CAAA

Lake, L.P.) Wallboard manufacturer using all gypsum produced

Sale of 1,600 MWe of AFGD capacity to Florida Power & Light

– Value—$200 million

– Employment benefit—1,400 person-years

Demonstration of Innovative Applications Technology retained for commercial use at host site

of Technology for the CT-121 FGD Process Sale to Canada for tar sands extraction facility

(Southern Company Services, Inc.) Sales of 1,200 MWe of FGD capacity to Czech Republic and Korea

Low-NOx burner technologies: Foster Wheeler’s low-NOx

burner for wall-fired boilers (top left), ABB Combustion

Engineering’s LNCFSTM for tangentially fired boilers (right),

Babcock & Wilcox’s LNCB® for cell-burner boilers (center),

and Babcock & Wilcox’s DRB-XCL® for down-fired boilers

(bottom).
4-4 Program Update 1996-97

The Babcock & Wilcox Company’s coal reburning technology proved not only to be an effective way

to control NOx

 on cyclone boilers, but a means to

avoid derating cyclone boilers when switching to lowsulfur, low-rank western coals.

The Babcock & Wilcox Company’s low-NOx cell

burner, LNCBTM, provided an effective, low-cost plugin NOx

 control system for cell-burner boilers known

for their inherently high NOx emissions.

Energy and Environmental Research Corporation’s use of gas reburning with low-NOx

 burners

introduced an alternative SCR for high NOx emission

reduction.

Comparative analyses conducted on a range of

SCR catalysts operated on high-sulfur U.S. coals

provided needed insight as to the environmental and

economic performance potential of the approach and

the various options tested under U.S. conditions.

Commercialization successes to date are summarized in Exhibit 4-2.

Combined SO2/NOx Control Technologies.

Five of seven combined SO2/NOx control technology

demonstrations have been successfully completed,

testing a multiplicity of complementary and synergistic

control methods to achieve cost-effective SO2 and NOx

emissions reductions.

SNOXTM, a catalytic process developed by Haldor

Topsoe a/s, consistently achieved 95 and 94 percent

SO2 and NOx control, respectively, as well as excellent

particulate control, while producing a salable byproduct in lieu of solid waste.

In a project sponsored by Public Service Company of Colorado, complementary use of low-NOx

burners with SNCR was shown to increase NOx emission reduction to greater than 80 percent (comparable

LIMB and Coolside demonstrations proved that

sorbent injection methods could achieve up to

70 percent SO2

 reduction while Babcock & Wilcox

DRB-XCL® advanced low-NOx

 burners alone could

maintain NOx emission reductions of 45 percent.

Energy and Environmental Research Corporation’s

demonstration of gas reburning and sorbent injection

showed that NOx reductions greater than 60 percent

could be achieved with only 13 percent gas heat input

and SO2 removal could be greatly enhanced by use of

special sorbents.

to SCR). SNCR interacted synergistically with sorbent

injection to reduce ammonia slip and NO2 emissions.

Sodium-based sorbent injection achieved 70 percent

SO2

 removal at high sorbent utilization rates.

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

BoxTM, integration of a newly developed high-temperature fabric-filter bag (for baghouse installation) with

SCR and sorbent injection, proved to be an easily

installed, high-efficiency control system for SO2, NOx,

and particulates.

Exhibit 4-2

Commercial Successes—NOx Control Technology

Project and Participant Commercialization Progress

Demonstration of Coal Reburning for Cyclone Technology retained for commercial use at host site

Boiler NOx Control (The Babcock & Wilcox

Company)

Full-Scale Demonstration of Low-NOx

 Cell Technology retained for commercial use at host site

Burner Retrofit (The Babcock & Wilcox Seven commercial contracts awarded for 144 burners

Company) – Value—$27 million

– Employment benefit—27 person-years

Evaluation of Gas Reburning and Low-NOx Technology retained for commercial use at host site

Burners on a Wall-Fired Boiler (Energy and

Environmental Research Corporation)

Demonstration of Advanced Combustion Technology retained for commercial use at host site

Techniques for a Wall-Fired Boiler (Southern Sales of Foster Wheeler’s low-NOx

 burners

Company Services, Inc.) – Value—$20 million

– Employment benefit—140 person-years

Sales of 6 GNOCIS neural-network controls

Projected 11 additional GNOCIS sales by end of 1997

Organizations selected to market GNOCIS in U.S. and abroad

180-MWe Demonstration of Advanced Technology retained for commercial use at host site

Tangentially Fired Combustion Techniques Sales of 10 ABB Combustion Engineering LNCFSTM systems to

(Southern Company Services, Inc.) 8 utilities
Program Update 1996-97 4-5

the emphasis toward seeking very high-efficiency, very

low-emission power generation technologies both for

repowering and new power generation. This was

deemed requisite to coal fulfilling its projected contribution to the nation’s energy mix well into the 21st

century. Key to this was the growing concern over

greenhouse gas emissions. In addition, SO2

 emissions

had been capped under the CAAA at year 2000 levels;

NOx

 continued to receive increased attention in ozone

nonattainment areas; and particulate emissions were

identified as carriers of air toxics. This prompted

follow-on projects in PFBC, initiation of projects in

integrated gasification combined cycle (IGCC), and

projects in advanced combustion and heat engines.

The Tri-State Generation and Transmission

Association, Inc., repowering project provided the

database and operating experience requisite to making

AFBC a commercial technology option at utility scale.

At 110 MWe, the Nucla circulating fluidized-bed

(CFB) unit was more than 40 percent larger than any

other AFBC at that time. The thrust of the effort was to

fully evaluate the environmental, operational, and

Commercialization successes to date are summarized in Exhibit 4-3.

Advanced Electric Power Generation

Early in the CCT Program, technologies were

sought that could effectively repower those plants that

were aging and faced with both the need to install

pollutant controls and respond to growing power

demands. Contributing to this approach was recognition that existing power generation sites had significant

value and warranted investment given the permitting

problems associated with siting new plants. This led to

award of two key repowering projects, now completed—an atmospheric fluidized-bed combustion (AFBC)

project and a pressurized fluidized-bed combustion

(PFBC) project.

As the CCT Program unfolded, a number of

energy and environmental issues combined to change

Nucla Station, repowered with a circulating fluidizedbed boiler, was the world’s first utility-scale AFBC unit in

commercial service.

Exhibit 4-3

Commercial Successes—Combined SO2/NOx Control Technology

Project and Participant Commercialization Progress

SNOXTM Flue Gas Cleaning Demonstration Technology retained for commercial use at host site

Project (ABB Environmental Systems) 305-MWe unit operating in Denmark on coal

30-MWe unit operating in Sicily on petroleum coke

LIMB Demonstration Project Extension and Sale of LIMB to independent power project in Canada

Coolside Demonstration (The Babcock &

Wilcox Company)

Enhancing the Use of Coals by Gas Reburning Illinois Power retained gas reburning for commercial use

Sorbent Injection (Energy and City Water, Light & Power retained full technology for

Environmental Research Corporation) commercial use

Milliken Clean Coal Technology Demonstration One sale of DHR Technologies’ Plant Emission Optimization

Project (New York State Electric & Gas Advisor (PEOATM) and another 4 bids pending

Corporation) Derivative of SNCR system sold to Pennsylvania Electric

Company and Mitsubishi Heavy Industries of America

– Value—$1.9 million

U.S. company, SHN, established to market scrubber

Integrated Dry NOx

/SO2 Emissions Control Technology retained for commercial use at host site

System (Public Service Company of Colorado) Sale of Babcock & Wilcox DRB-XCL® low-NOx

 burners for

101 boilers (55 domestic and 46 international)

– Quantity—1,829 burners for 23,664 MWe capacity

– Value—$240 million

– Employment—1,670 person-years
4-6 Program Update 1996-97

Coal processing technologies remove barriers to the

use of low-energy-density western coal resources:

Rosebud (top) and ENCOAL® (bottom).

economic performance potential of AFBC. As a result,

the most comprehensive database on AFBC technology

available to date was developed. From this knowledge,

commercial units were offered and built. Up to

95 percent SO2

 removal was achieved during the

15,700 hours of demonstration and NOx emissions

averaged a very low 0.18 pound per million Btu.

Under the Ohio Power Company repowering of the

Tidd Plant (70 MWe), the potential of PFBC as a

highly efficient, very low pollutant emission technology was established and the foundation laid for commercialization. The PFBC system constructed was the first

utility-scale system in the United States. Efforts were

focused on fully evaluating the performance potential.

Over 11,444 hours of operation, the technology successfully demonstrated SO2

 removal efficiencies up to

95 percent with very high sorbent utilization (calciumto-sulfur molar ratio of 1.5) and NOx

 emissions in the

range of 0.15–0.33 pound per million Btu. Two ongoing interrelated projects, McIntosh 4A and McIntosh

4B, will take PFBC to a larger scale than the Tidd

Plant and introduce second-generation PFBC.

By the end of 1996, three IGCC units were in

various stages of operation at three separate utilities.

PSI Energy’s 262-MWe Wabash River Generating

Station Unit 1 IGCC system began operation in November 1995 and by year-end 1996 had produced over

360,000 MWh of electricity using coal-derived syngas.

The Tampa Electric Company’s 250-MWe Polk Power

Station Unit 1 IGCC system began operation in July

1996 and was placed into commercial service in September. Sierra Pacific Power Company’s 99-MWe

Tracy Station IGCC system initiated startup activities

during 1996, and the project began its operational

phase in February 1997.

Commercial configurations resulting from the

current IGCC and PFBC demonstrations will typically

(1) have efficiencies at least 20 percent greater than

conventional coal-fired systems (with like CO2 emission

reductions), (2) remove 95–99 percent of the SO2,

(3) reduce NOx emissions to levels equivalent to 90 percent reduction, (4) reduce particulate emissions to

1/3 to 1/10 that currently allowed under the CAAA, and

(5) produce salable by-products as opposed to waste

from solid residues.

Commercialization successes to date are summarized in Exhibit 4-4.

Coal Processing for Clean Fuels

Physical and chemical processes can be applied to

abundant U.S. coal reserves to transform them to an

economic energy-option fuel for at least a portion of the

existing coal-fired boilers, enabling them to comply

with the CAAA. In addition, coal processing creates the

capability to generate substitute liquid fuels from coal

that can replace petroleum and petroleum-based fuels

in a wide range of applications, enhancing the nation’s

energy security. The solid products are easily transportable fuels, high in energy density and low in sulfur, ash,

and moisture. The liquid fuels are low in sulfur and

suitable for the transportation sector, stationary power

generation, or as chemical feedstocks. Both the prodThree IGCC plants are in various stages of operation:

Tampa Electric (top), Piñon Pine (lower left), and Wabash

River (lower right).
Program Update 1996-97 4-7

ucts and the processes have a great deal of market

potential both domestically and internationally.

The barrier to using the nation’s vast low-sulfur,

low-energy-density western coal resource is being

addressed through projects sponsored by ENCOAL®

and the Rosebud SynCoal Partnership. The resultant

fuels, undergoing test burns, have particular application

domestically for CAAA compliance and internationally

for Pacific Rim Energy markets. Energy density for the

solid fuels averages 12,000 Btu per pound, and sulfur

content averages 1.0 percent. ENCOAL®’s liquid fuel

product is the equivalent of No. 6 fuel oil. Total sales

of Rosebud’s SynCoal® product have exceeded

900,000 tons, with 130,000 tons delivered over an

extended period to industrial users. ENCOAL® has

delivered 15 unit trains of solid fuel to 5 utilities and 3

million gallons of liquid fuel to 8 industrial users.

Many high-energy-density, high-sulfur eastern/

midwestern bituminous coals are amenable to significant sulfur removal using an advanced separation

process being demonstrated by Custom Coals International. The process can remove up to 90 percent of the

inorganic sulfur, which is an integral part of the ash.

For coals in which the organically bound sulfur content

is low, the process can produce a fuel that enables

users to comply with CAAA SO2 requirements. Addition of a sorbent and other additives to coals less

amenable to sulfur extraction also produces a compliance fuel. Products are undergoing test burns.

ABB Combustion Engineering, Inc., and CQ Inc.

developed PC-based software, CQETM, to assist utilities in assessing environmental and operational performance of their systems for the range of coal fuels

available to determine the least-cost option. The

CQETM software has been distributed to 41 utility

members of EPRI and is being marketed commercially

worldwide. Two U.S. utilities also have been licensed

to use copies of CQETM’s stand-alone Acid Rain

Advisor.

Commercialization successes to date are summarized in Exhibit 4-5.

Industrial Applications

There are significant environmental issues and

barriers associated with coal use in industrial applications. Production of steel has been dependent upon

coke. However, coke making is an inherently large

producer of not only SO2

 and NOx, but hazardous air

pollutants. Cement production often relies on coal fuel

because production costs are largely driven by fuel

costs, precipitating the need for effective SO2 control

measures. Because of its low, stable price, coal is an

Exhibit 4-4

Commercial Successes—Advanced Electric Power Generation

Project and Participant Commercialization Progress

Tidd PFBC Demonstration Project First utility-scale PFBC in U.S.

(The Ohio Power Company) – Laid foundation for commercialization of PFBC

Nucla CFB Demonstration Project Technology retained for commercial use at host site

(Tri-State Generation and – World’s first large utility-scale AFBC

Transmission Association, Inc.) Demonstration commercialized utility-scale AFBC

– Quantity—22 AFBC units larger than 100 MWe planned, in construction,

or in operation worldwide

– Estimated capacity—3,800 MWe

– Estimated value—$5 billion

Tampa Electric Integrated First greenfield IGCC unit in commercial service

Gasification Combined-Cycle 400-MWe minemouth project proposed by Britain’s RJB Mining Plc.

Project (Tampa Electric Company) and Texaco, Inc.

Texaco, Inc., and ASEA Brown Boveri signed an agreement forming an

alliance to market IGCC technology in Europe

Wabash River Coal Gasification First repowered IGCC unit in commercial service

Repowering Project (Wabash – World’s largest single train IGCC in commercial service

River Coal Gasification – Preferentially dispatched over other coal-fired units in PSI Energy’s

Repowering Project Joint Venture) system because of high efficiency

Piñon Pine IGCC Power Project Technology to be engaged in commercial service in 1997

(Sierra Pacific Power Company)

Healy Clean Coal Project (Alaska Technology to be engaged in commercial service in 1998

Industrial Development and TRW offering licensing of combustor worldwide (China agreement in place)

Export Authority)
4-8 Program Update 1996-97

Exhibit 4-5

Commercial Successes—Coal Processing for Clean Fuels

Project and Participant Commercialization Progress

Development of the Coal CQ Inc. and Black & Veatch working collaboratively to commercialize

Quality ExpertTM (ABB Combustion CQETM worldwide

Engineering, Inc., and CQ Inc.) CQE’s Acid Rain Advisor licensed to 2 U.S. users

40 U.S. and 1 U.K. utilities have CQETM through EPRI membership

Other foreign and domestic utilities pursuing access to CQETM

CQETM Home Page posted on World Wide Web

(http://www.fuels.bv.com:80/cqe/cqe.htm)

Self-Scrubbing CoalTM: An Integrated Proposed agreement to purchase 1 million tons/yr in U.S.

Approach to Clean Air (Custom Coals Proposed agreement with China to build a coal-cleaning plant, slurry

International) pipeline, and port facility

– Value—$450 million

Letter of intent for 3 additional pipelines in China

– Value—$3 billion

Letters of intent from Polish utilities for 5 million tons/yr

– Value—$50 million

Advanced Coal Conversion Process Total sales of SynCoal® product exceeds 900,000 tons

Demonstration (Rosebud SynCoal – 130,000 tons delivered over extended period to industrial users

Partnership) A semi-commercial project being developed

– Stand-alone minemouth design in Wyoming

ENCOAL® Mild Gasification Project 75,000 tons of solid fuel delivered to 5 major utilities and metallurgical

(ENCOAL® Corporation) customers

3 million gallons of liquid fuel delivered to 8 industrial users

ENCOAL Corporation’s newly formed company, NuCoal, L.L.C.,

signed a contract with Mitsubishi International Corporation for

construction of 15,000-metric-ton/day commercial plant in Wyoming

– Value—$460 million

Completed feasibility studies for two Indonesian projects

Completed first phase of feasibility study for Russian coal group

SO2 emissions from this cement kiln are controlled by

the Passamaquoddy Technology Recovery ScrubberTM.

attractive substitute for oil and gas in industrial boilers,

but concerns over increased SO2 and NOx emissions

and boiler tube fouling have impeded coal use.

Under a project with Bethlehem Steel Corporation,

British Steel’s blast furnace granular-coal injection

technology demonstrated that 40 percent of the coke

can be replaced with coal injected directly into a blast

furnace where emissions from coal combustion/processing are effectively controlled.

The Passamaquoddy Tribe successfully demonstrated a unique recovery scrubber that uses cement

kiln dust otherwise disposed of as waste, to remove

90 percent of the SO2

, produce fertilizer and distilled

water, and convert the kiln dust to feedstock. (No waste

was generated.)

Coal Tech Corporation moved closer to commercializing a combustor for industrial boilers that slags

the ash in the combustor to prevent boiler tube fouling,

controls NOx (70–80 percent reduction) through staged

combustion, and controls SO2 (90 percent) with sorbent

injection.

Commercialization successes to date are summarized in Exhibit 4-6.

Understanding the Domestic

Market

Since the beginning of the program in 1985, there

have been a number of activities aimed at developing

an understanding of the commercial market for the

technologies and enhancing their entry into the commercial marketplace. As a part of the response to the
Program Update 1996-97 4-9

recommendations of the Special Envoys on Acid Rain,

the President directed the Secretary of Energy in April

1987 to establish a panel to advise him on innovative

clean coal technology activities. This panel was the

Innovative Control Technology Advisory Panel. As a

part of the panel’s activities, the state and federal

incentive subcommittee prepared a report (Report to

the Secretary of Energy Concerning Commercialization Incentives) on the actions that states could take to

provide incentives for demonstrating and deploying

clean coal technologies and their eventual commercial

successes and determined that demonstration and

deployment should be managed through both state and

federal initiatives.

In the same time frame, the Vice President’s Task

Force on Regulatory Relief (later referred to as the

Presidential Task Force on Regulatory Relief) was

established. Among other things, the task force was

asked to examine incentives and disincentives to the

commercial realization of new clean coal technologies

and other cost-effective emissions reduction measures

that might be inhibited by various federal, state, and

local regulations. An outgrowth of this activity was the

recommendation that preference be given to projects

located in states that offer certain regulatory incentives

to encourage such technologies. This recommendation

was accepted and became part of the project selection

considerations beginning with

CCT-II.

An effort has been under way since 1992 to gain

greater understanding of the potential domestic market

for clean coal technologies and the organization and

factors that will influence what and when facilities get

built as well as the technologies that are used.

DOE has been conducting a series of Executive

Seminars with leaders in the utility, independent power

production, regulatory, and financial communities.

The objective of the Executive Seminar series is to

establish and maintain a dialogue with corporate

officials and key decisionmakers to determine how

DOE can enhance the climate wherein clean coal

technologies and other advanced technologies will be

given serious consideration in electric power generation planning and implementation. The Executive

Seminars seek to enlist the views of the key decisionmakers on a number of issues relevant to the CCT

Program and the Coal RD&D Program, including

(1) perspectives on the pending changes in the utility

industry and new opportunities for integrated advanced

technologies; (2) risk assessments and risk mitigation,

including the adoption of advanced technologies;

(3) potential incentives that could be implemented by

the government to accelerate commercial acceptance of

advanced technologies; and (4) potential impacts of

reduced R&D funding resulting from growing competition. Through 1996, three Executive Seminar series

had been initiated, with two completed and a total of

60 seminars conducted with utilities, independent

power producers, power marketers, state regulators,

financial institutions/investment bankers, equipment

manufacturers, insurance carriers, and associations.

The focus of the current seminar series is on the impacts of utility industry restructuring and its effect on

clean coal technology deployment, the opportunities

for advanced technologies in international markets, and

the outlook for environment compliance, particularly

with respect to global climate change issues. Priorities

for participation in the seminars are (1) utilities with

significant coal utilization, projected load growth, and

25 percent of their coal plants at least 30 years old or

older and (2) nonutility generators utilizing coal-based

technologies and plants up to 300 MWe of capacity.

Representatives of states where coal is a major resource, growth is projected for electric power generation, or advanced regulatory issues predominate are

also participants in the seminars.

Additionally, a series of regional studies of key

utilities and utility systems is under way. The purpose

of these studies is to gain a better understanding of the

domestic markets for clean coal technologies and the

regional and state factors that have a bearing on comExhibit 4-6

Commercial Successes—Industrial Applications

Project and Participant Commercialization Progress

Blast Furnace Granular-Coal Injection British Steel granted exclusive marketing rights to technology

System Demonstration Project co-developer, CPC-Macawber

(Bethlehem Steel Corporation) Commercial sale of technology to United States Steel Corporation

Cement Kiln Flue Gas Recovery Scrubber Technology retained for commercial use at host site

(Passamaquoddy Tribe) Completed feasibility study for Taiwanese cement plant
4-10 Program Update 1996-97

mercial deployment. Regions selected for study account for most of the U.S. coal-fired generating capacity. The regional, utility-specific, state, and other data

are collected and analyzed for insights into environmental compliance strategies, capacity planning,

industry restructuring, deregulation and competition,

and other stakeholder issues affecting the domestic

power generation market and the deployment of clean

coal technologies.

Studies for three regions have been completed:

• Region 3—Mid-Atlantic, encompassing

Pennsylvania, Delaware, Maryland, Virginia,

and West Virginia; published.

• Region 4—South Atlantic, encompassing

Kentucky, Tennessee, North Carolina, South

Carolina, Georgia, Alabama, Mississippi, and

Florida; published.

• Region 5—Midwest, encompassing Ohio,

Illinois, Indiana, Michigan, Minnesota, and

Wisconsin; updated in 1996.

Two studies are in progress:

• Region 6—Southeast, encompassing Texas,

Louisiana, Oklahoma, and Arkansas.

• Regions 1 and 2—Northeast, encompassing

Maine, Vermont, New Hampshire, Massachusetts, Rhode Island, Connecticut, New York,

and New Jersey.

Also completed in 1996 was an assessment of the

impact of environmental compliance on coal-fired

power plants. The assessment addressed various

CAAA requirements, National Ambient Air Quality

Standards (NAAQS), Prevention of Significant Deterioration (PSD), New Source Performance Standards

(NSPS), the Acid Rain Program, and the air toxics

control program, as well as efforts to control global

warming by reducing emissions of greenhouse gases.

Emission trends, proposed regulations, and options for

attaining regulatory compliance were considered for

the major air pollutants: SO2, NOx, particulate matter,

CO2, and the various air toxics defined as hazardous air

pollutants. The report, U.S. Coal-Fired Plants and

Environmental Compliance, also identifies the technologies for controlling SO2

, NOx, and particulate matter

that have been installed at each U.S. coal-fired power

plant.

The insights contributed by these efforts identify

many significant factors and trends affecting domestic

markets for CCTs and relating to the contributions of

CCT demonstration projects to these markets, such as

issues associated with restructuring the electric industry

and new limits on environmental emissions.

An Emerging International

Market

Internationally, clean coal technologies represent a

major opportunity for U.S. industries to improve their

position in world exports. Worldwide, the market for

power generation technologies could reach $1 trillion

by 2015. Capturing just 20 percent of this market

would bring in revenues of $200 billion and support

more than 100,000 jobs over three decades in the U.S.

power equipment industry alone. Aggressive action by

U.S. companies to capture this market share with

technologies proven under the CCT Program would

lead to a significant reduction in the U.S. balance-oftrade deficit.

Further, the export of coal amounted to 89 million

tons in 1995 and contributed $3.5 billion to the U.S.

balance of payments. By 2015, the Energy Information

Administration has projected that U.S. coal exports will

increase to more than 120 million tons. Thus, there is

enormous incentive to expand U.S. clean coal technology exports so that U.S. industry and the world markets it

serves can take advantage of the technical, environmental, efficiency, and economic benefits of these coalbased technologies.

During 1996, clean coal technologies gained

recognition as having an important role in enhancing

“environmental security.” This term describes a federal

interagency policy initiative to coordinate the resources

of the Departments of Defense and Energy and the

Environmental Protection Agency to focus on selected

acute international environmental problems that, by

their serious nature, threaten to impact the local health

and welfare and hence may destabilize the political or

social structure to the detriment of American interests.

Because coal is available worldwide, clean coal technologies are now viewed as essential to affordable and

reliable electrification that leads directly to sustainable

development and enhanced quality of life.

Activities in the Pacific Rim have been in support

of the deployment of clean coal technology in this

region. The Pacific Rim represents the largest regional

user of coal and the largest market for power generation

and other coal use technologies. Correspondingly, coal

use is the major source of the air and water pollution of

the region, and the Pacific Rim is rapidly becoming the

largest source of pollution in the world. DOE’s Office

of Fossil Energy has developed a program to address
Program Update 1996-97 4-11

the needs of the region. The program was developed

in conjunction with the governments and multilateral

organizations active in the Pacific Rim. Activities in

the region have had three purposes: (1) education and

training in the performance and cost of clean coal

technologies as well as the issues pertaining to obtaining commercial financing for projects using these

technologies, (2) where possible to support the activities of U.S. developers for projects using clean coal

technologies, and (3) when requested, to assist governments with the development of responsible energy and

related environmental policy and practices.

DOE’s Office of Fossil Energy continued its long

relationship with China by supporting the Ministry of

Electric Power with an assessment of IGCC projects in

China. China issued a plan for sustainable development and identified IGCC and PFBC technologies as

the top priorities for the future. China has shown a

keen interest in the U.S. clean coal technologies as a

means to reduce SO2

. At the Conference on Energy

and Sustainable Development held in Beijing, China

characterized its environmental issues as follows:

pollution from coal use and heavy transport in urban

areas; serious acid rain in South China; and high

overall CO2

 emissions. The importance of clean coal

technologies in addressing these issues is illustrated by

the fact that SO2

 emissions from China constitute 70

percent of the SO2

 emissions in Asia and 90 percent of

these emissions are related to those from coal. A

similar situation exists for NOx

: emissions from China

represent over 60 percent of the NOx

 emissions in Asia

with 70 percent of the Chinese emissions being related

to coal use. The introduction of clean coal technologies, which have a minimum power plant efficiency of

33–35 percent as compared to the current China average of 25–30 percent, could reduce emissions by 20

percent by taking advantage of the more efficient

power generation inherent in these advanced systems.

The main barrier to the introduction of clean coal

technologies is capital costs. Through the efforts of

DOE’s Office of Fossil Energy, the Asian Development Bank has become a participant in the development and the ultimate financing of the first projects in

China.

A second round of the U.S.-India Bilateral Energy

Consultations was held in New Delhi in August 1996

and resulted in the creation of a Coal Advisory Group

that will serve as a sounding board, problem identifier,

and coordinating mechanism relating to coal and coal

technology, including coal cleaning, power plant

efficiency improvement, and other technical issues. A

unique feature of these bilateral talks was the private

sector input. A business roundtable was held prior to

the talks and developed recommendations for the

government of India for reforms in the electric power

sector intended to streamline the energy permitting

process, improve financing mechanisms, and restructure state electricity boards to operate more independently and speed privatization. In a related activity,

DOE’s Office of Fossil Energy and the Electric Power

Research Institute cosponsored the Workshop on U.S.

Clean Coal Technologies at the Energy Summit ‘96

Conference and Exhibition in Madras, India, in September. Technical sessions were conducted on advanced power generation and advanced industrial and

clean fuels technologies. The sessions focused on

describing how U.S. coal and clean coal technologies

could contribute to economically meeting India’s

energy needs while addressing environmental issues.

Following the Energy Summit, DOE showcased the

latest CCT Program information through an exhibit,

technical session, and paper presented at the PowerGen Asia Conference and Exhibition in New Delhi.

DOE’s Office of Fossil Energy participated in a

number of other workshops and missions in 1996. A

fact-finding mission to Australia was conducted to

investigate opportunities and obstacles to U.S. exports

of clean coal technologies and to explore opportunities

for cooperation on R&D. The goal was to develop a

strategy for a government/industry partnership to

develop the Australian market for U.S. clean coal

technologies. The Office of Fossil Energy cosponsored

a workshop with the United States Energy Association

at the Independent Power Production Conference in

Rio de Janeiro, Brazil. This workshop dealt with the

roles, responsibilities, and regulatory functions of state

utility commissions. Further, the Office of Fossil

Energy continued to participate in a leadership capacity

in the Asia Pacific Economic Cooperation Expert

Working Group on Clean Coal Technology, which has

as its objective the development of multilateral policies

U.S. International Technical Assistance Program

identifies opportunities for clean coal technologies in Brazil.
4-12 Program Update 1996-97

for the development and implementation of clean coal

technologies.

A Clean Coal Technology Finance Seminar was

held in 1996 with the purpose of receiving views and

advice from the U.S. clean coal technology industry on

the international marketplace, as well as gaining better

insight and understanding on how to strengthen the

relationship between the coal industry and the financial

community on technologies, markets, and projects.

Market Communications

Public involvement has been a hallmark of the

CCT Program since its inception. Programmatic

interest was evaluated, first at the direction of Congress, in two informational solicitations preceding the

CCT-I and CCT-II solicitations. Strong and broad

industry interest covering a wide range of clean coal

technologies was found to exist. Numerous public

meetings were held prior to issuing each of the CCT-II

through CCT-V project solicitations. The 12 public

meetings that were held helped to sharpen the solicitation objectives and procedures, enabling industry to

propose a technical agenda that met each of the solicitations’ broad objectives.

The clean coal technology outreach program

continued to build a broad constituency for the CCT

Program and to identify the needs of that constituency

for information and data. The support of outreach was

reemphasized in the National Energy Strategy in 1991.

As a result, a formal outreach program was established

with DOE’s Office of Fossil Energy.

The purpose of the outreach program is to impart

an understanding that clean coal technologies can

increase the efficiency of coal use and enhance environmental quality at competitive costs. Further, the

outreach program underscores the commitment to

commercial realization of the technologies. Specific

objectives of the outreach program follow:

• Achieve public and government awareness of

advanced coal-using technologies as viable

energy options

• Provide potential technology users with

information that is timely and relevant to their

decision-making process

• Provide policy makers and regulators with

information about the advantages of clean coal

technologies

• Increase the confidence of financial institutions

that these technologies are viable options

A vigorous outreach program continues to be

pursued in the form of dissemination of program

information, publication of materials (including quarterly newsletters and annual program reports), cosponsorship of the Annual Clean Coal Technology Conference, attendance at trade shows and other highvisibility events, conduct of executive seminars, and

providing electronic access to project information via

the Internet as well as a fax-on-demand system and a

computer bulletin board. The outreach program has

been expanded into the international arena through

sponsorship and participation in trade missions and

overview conferences and more specifically as part of

the Asia Pacific Economic Cooperation initiative.

The outreach activities conducted by DOE have

been directed toward reaching targeted audiences,

including users and vendors of the technology, regulators, public educators, environmental organizations,

and export markets. Currently, the CCT Program has

more than 4,000 priority stakeholders/customers.

Stakeholders represent about 275 organizations that

are participating in the CCT Program, about 15 of

which provide independent and objective program

assessments and guidance and/or provide cosponsorship and inputs to the formulation and planning of

outreach materials and the annual conferences. Support of this outreach program also comes from well

established relationships with major organizations

representing the coal industry (e.g., Center for Energy

& Economic Development, Council of Industrial

Boiler Owners, Clean Coal Technology Coalition,

Electric Power Research Institute, and National

Mining Association).

The CCT Program mails newsletters, annual

program updates, and a variety of other outreach

materials to almost 4,000 stakeholders/customers,

80 percent of whom have indicated overall satisfaction

with the information and data received from the

program. These mailings are made on a periodic basis

(quarterly or annually) and as special publications

become available. The outreach program has participated in over 185 technical conferences, professional

meetings, and trade missions since 1991.

DOE’s outreach program has been implemented

through the following mechanisms: publications,

annual clean coal technology conferences, presentations and exhibits, and international trade missions.

Additionally, project participants have been holding

open houses, providing tours of demonstration facilities, and publicizing projects through groundbreaking

ceremonies. They also have been presenting technical

papers at professional and industry conferences to
Program Update 1996-97 4-13

report progress and results to potential users.

Outreach assets include four traveling exhibits,

interactive videos, broadcast videos, printed publications, an extensive photographic library, and a mailing

list of stakeholders/customers.

DOE has been disseminating information through

the distribution of published material about the program

and the projects. These reports include the annual

Program Update, Comprehensive Reports to Congress

for each solicitation and successfully negotiated

projects, the New Coal Era, the Investment Pays Off,

and a series of project-specific topical reports to highlight project events or to capture progress at particular

points driven by project-specific considerations. The

following key publications were prepared and disseminated:

• Reducing Emissions of Nitrogen Oxides via

Low-NOx

 Burner Technology (Topical Report

Number 5) discusses CCT demonstration

projects that reduce NOx emissions by combustion modifications using low-NOx

 burners.

• The Tampa Electric Integrated Gasification

Combined-Cycle Project (Topical Report

Number 6) describes the greenfield IGCC unit

at Polk Power Plant.

• The Wabash River Coal Gasification Repowering Project (Topical Report Number 7) describes the world’s largest single-train IGCC

power plant.

• The Piñon Pine Power Project (Topical Report

Number 8) describes Sierra Pacific Power

Company’s IGCC unit at Tracy Power Station.

Fossil Energy TechLine is a 24-hour fax-ondemand system that can provide a wide variety of

information on DOE’s fossil energy programs including the CCT Program. The TechLine system offers

news announcements on clean coal projects, fact sheets

for individual projects, and monthly updated status

reports. A computer bulletin board also provides

updates.

DOE continued to expand its computer network,

accessible through the Internet, which provides information on federal fossil energy programs and serves as

a “gateway” to other related information throughout the

United States and the world. Once into the network,

• Clean Coal Technology Demonstration

Program: Program Update 1995, which marks

the program’s 10-year anniversary, provides a

thorough review of the status of the program as

well as updates on each project.

• Clean Coal Technology Demonstration

Program: Project Fact Sheets provides a midyear update on each project.

• CCT Program Bibliography of Publications,

Papers and Presentations identifies the

material published during the 10 years of the

CCT Program.

• Fifth Annual Clean Coal Technology Conference: Powering the Next Millennium; Technical Papers contains the technical papers

submitted in advance of the conference.

• Fifth Annual Clean Coal Technology Conference: Powering the Next Millennium; Proceedings contains the papers presented during

plenary and panel sessions as well as the

luncheon addresses.

Five issues of the Clean Coal Today newsletter

were published in 1996 and early 1997, along with the

second annual edition of the Clean Coal Today Index,

which cross-references all articles published in the

newsletter to date by both project title and participant.

The newsletter is distributed to approximately 4,000

domestic and international readers. In 1996, the

newsletter was re-designed and coverage expanded to

include regular features on international activities,

commercialization briefs, and information on state

activities relating to clean coal technologies.

The CCT Program reports progress and accomplishments through several publications distributed to almost

4,000 stakeholders.
4-14 Program Update 1996-97

users can obtain general information and follow links

to increasingly detailed information, ultimately accessing specific data on individual projects and facilities.

Internet electronic links allow users to move seamlessly between headquarters and field sites. Users can also

access technical abstracts and reports maintained by

DOE’s Office of Scientific and Technical Information

at Oak Ridge, Tennessee. The gateways link to more

than a hundred energy-related computer servers and

networks operated by private companies, trade associations, and other agencies worldwide. Exhibit 4-7

provides instructions on how to obtain updates on the

CCT Program.

The Fifth Annual Clean Coal Technology Conference was held in Tampa, Florida, in January 1997, and

was cosponsored by the Center for Energy & Economic Development, Council of Industrial Boiler Owners,

Electric Power Research Institute, and National Mining

Association. There were almost 400 participants,

including 70 representatives from 16 countries. The

NOx

 control. This project is unique also in that it

recovered and converted some 1,500 acres of phosphate mining spoils to usable wetlands and uplands for

native plants and animals.

A tour also was given of Tampa Electric Company’s Electric Technology Resource Center, which is

the only full-service demonstration facility displaying

interactive testing centers in advanced technology,

lighting display, and food service.

The conference program was designed to develop

sequentially four key conference issues: (1) International Markets for CCTs, which focused on the opportunities and obstacles for CCTs to compete in the

international marketplace; (2) Role of CCTs in the

Evolving Domestic Electricity Market, which addressed the need to understand and follow the power

production industry as it moves into an era of deregulation and competition; (3) Environmental Issues Affecting CCT Deployment, which explored both domestic

and international requirements to broaden the understanding of how clean coal technologies can be used to

theme, “Powering the Next Millennium,” focused on

presenting strategies and approaches that will enable

clean coal technologies to resolve the competing,

interrelated demands for power, economic viability,

and environmental constraints associated with the use

of coal in the post-2000 era. The conference provided

a forum to review the status of CCT projects here and

abroad and provided an opportunity to evaluate CCT

Program directions.

The conference was launched at an International

Business Forum Brunch, which provided an opportunity to meet and network with the international delegations. This was followed by a panel on options for

financing projects and feasibility studies. That afternoon featured a tour of Tampa Electric Company’s

250-MWe IGCC project located near Mulberry,

Florida, which started operations in October 1996.

The project is using a Texaco pressurized, oxygenblown, entrained-flow gasifier, hot-gas and conventional cold-gas cleanup, and an advanced gas turbine

with nitrogen injection for power augmentation and

The Fifth Annual Clean Coal Technology Conference,

held in Tampa, FL, focused on issues affecting clean coal

deployment into the 21st century.

Exhibit 4-7

How to Obtain Updated CCT Program Information

Media Description and Action

Clean Coal Today Subscription to quarterly newsletter: Send name and address to U.S.

Department of Energy, FE-22, Washington, DC 20585.

Fossil Energy TechLine Fax-on-demand system for news announcements and status reports:

Call (202) 586-4300 from a tone phone and follow voice instructions.

(Call 202-586-6503 for additional TechLine information.)

Computer Bulletin Board Dial 202-586-6495 via modem.

Fossil Energy Home Page Primary gateway to extensive information on DOE’s Fossil Energy

Program and to relevant Web links: On the Internet, access

http://www.fe.doe.gov and use menu and/or search options.
Program Update 1996-97 4-15

ensure that solutions are available to accomplish

environmental goals while achieving benefits that

outweigh the costs; and (4) Deployment—From Today

into the Next Millennium, which focused on the opportunities and obstacles to clean coal technology deployment as well as strategies and approaches to enhance

deployment.

The four conference issues were developed

through three steps over the course of three conference

days. First, the issues were identified and articulated

in the opening plenary session. The next day consisted

of panel sessions during which the key issues were

expanded and explored, and resolutions were formulated. During this day, technical papers also were presented on the clean coal projects. On the final day,

during the closing plenary session, the issues were

summarized, and where possible, conclusions were

drawn.

Several parallel themes emerged from the panels.

To encourage clean coal technologies internationally, it

was recommended that businesses focus on a few key

regions, rather than over the entire globe. Greater

attention must be paid to understanding countryspecific barriers, be they economic, environmental,

political, or social; then strategies must be developed to

overcome these barriers. On the domestic front,

electric utility restructuring continues to pose great

uncertainties. However, coal is still seen as a major

energy provider, and clean coal technologies, such as

washing and beneficiation, can provide less variable

fuel suitable for standard power plant design. Blending

coal with other fuels to mitigate the environmental

impact of coal and use of IGCC technology were other

options emphasized at the conference.

The closing plenary session was followed by a

featured speaker, The Honorable Ralph Regula, who

chairs the House Appropriations

Subcommittee on Interior and

Related Agencies and is one of the

original supporters of the CCT

Program. Representative Regula

(and other speakers) emphasized the

need for continued and greater

outreach efforts, interacting with

legislators to convince them of the

beneficial effects of CCT development on jobs, economic growth, and

U.S. competitiveness, and broadening the reach of information dissemination on clean coal technologies.

Another conference highlight

was a featured appearance by departing Secretary of Energy Hazel

Then Energy Secretary Hazel O’Leary and Representative Ralph Regula

dedicate Tampa Electric’s 250-MWe IGCC plant following the Fifth Annual

Clean Coal Technology Conference.

Exhibits communicate the progress of the CCT

Program at worldwide conferences and trade shows.

O’Leary, who praised the CCT Program as the most

successful government/industry partnership—one that

has become a model for government/industry cooperation that even GAO applauds. She noted that the

program has succeeded because it is environmentally

beneficial, industry-driven in terms of portfolio and

performance standards, and awarded on the basis of

competition.

From January 1996 through June 1997, DOE made

use of exhibits and presentations as a means to highlight the activities and benefits of the CCT Program.

The exhibits were used in 20 domestic and international events: World Coal Conference, Coal Utilization and

Fuel Systems Conference and Exhibition (1996 and
4-16 Program Update 1996-97

1997), Annual American Power Conference (1996 and

1997), Power-Gen Asia ’96, Energy Summit ’96

Conference and Exhibition, Air & Waste Management

Association Annual Conference and Exhibition (1996

and 1997), ASME International Joint Power Generation Conference and Exhibition, Power-Gen International ’96, Association of Energy Engineers Competitive Power Congress, Virginia Coal Council

Conference & Exposition (1996 and 1977), NASA

Technology 2006, Fifth Annual Clean Coal Technology Conference, Pacific Coal Forum, Power Projects in

Central and Eastern Europe Conference, NECA Power

Markets of the Future: Risks and Rewards Conference,

and U.S. DOE American Energy Month.
Program Update 1996-97 5-1

5. CCT Projects

Summary

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, 15

of 19 projects have been completed that address SO2

and NOx control for coal-fired boilers. The resultant

technologies provide a suite of cost-effective 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 in more than 1,700

MWe of utility generating capacity, five SO2 emissions systems installed on approximately

770 MWe, and seven combined SO2/NOx emission

control systems installed on approximately 800 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 particulate emissions far below New Source

Performance Standards (NSPS); and salable solid and

liquid by-products in lieu of solid wastes. Nearly

900 MWe of new capacity and more than 800 MWe

of repowered capacity are represented by 11 projects

valued at more than $3.2 billion. These projects

include five fluidized-bed combustion (FBC) systems,

four integrated gasification combined-cycle (IGCC)

systems, and two advanced combustion/heat engine

systems. (In addition, a fact sheet for a twelfth project,

the externally fired combined-cycle demonstration

project is included in this section even though the

project was concluded on May 31, 1997.) These

projects will not only provide environmentally sound

electric generation in the mid- to late 1990s, 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. 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 complementary effort to the process demonstrations has provided 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 as well to address

pollution problems associated with coal use in the

industrial sector. These 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 highsulfur, coal fuels; and the need for many industrial

boiler operators to consider switching to coal fuels to

reduce operating costs. The four 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 iron-making process with the production of

electricity, reduction of cement kiln emissions and

solid waste generation, and demonstration of an

industrial-scale slagging combustor. (A fifth industrial project fact sheet, the pulse combustor/gasifier

project, is included in this section even though it was

concluded on March 3, 1997.

Section 5 contains a discussion of the technologies being demonstrated and fact sheets for each
5-2 Program Update 1996-97

project. Two types of facts sheets are provided: (1) a

brief, two-page overview for ongoing (or concluded)

projects and (2) an expanded four-page summary for

projects that have successfully completed operational

testing. The expanded fact sheets for completed

projects contain a summary of the major results from

the demonstration as well as sources for obtaining

further information, specifically, contact persons and

key references. Information provided in the fact

sheets includes the project participant and team

members, project objectives, significant project

features, process description, major milestones,

progress (if ongoing) or summary of results (if

completed), and commercial applications. A key to

interpreting the milestone charts is provided on the

right. To prevent the release of project-specific

information of a proprietary nature, process flow

diagrams contained in the fact sheets are highly

simplified and presented only as illustrations of the

concepts involved in the demonstrations. The portion

of the process or facility central to the demonstration

is demarcated by the shaded area.

An index to project fact sheets is provided in

Exhibit 5-1. Projects are listed by application

category and alphabetically by participant, and the

page numbers for each fact sheet are provided. In

addition, Exhibit 5-1 indicates the solicitation under

which the project was selected; its status as of

June 30, 1997; and the geographic location of the

demonstration. Exhibit 5-2 highlights those projects

that have successfully completed operational testing

and for which expanded, four-page fact sheets,

including a summary of results, are provided.

Key to Milestone Charts in Fact Sheets

Each fact sheet contains a bar chart that highlights

major milestones—past and planned. The bar chart

shows a project’s duration and indicates the time period

for three general categories of project activities—

preaward, design and construction, and operation. The

key provided below explains what is included in each of

these categories.

Preaward

Includes preaward briefings, negotiations,

and other activities conducted during the

period between DOE’s selection of the

project and award of the cooperative

agreement.

Design and Construction

Includes the NEPA process, permitting,

design, procurement, construction, preoperational testing, and other activities conducted prior to the beginning of operation

of the demonstration.

MTF Memo-to-file

CX Categorical exclusion

EA Environmental assessment

EIS Environmental impact statement

Operation

Begins with start-up of operation and includes operational testing, data collection,

analysis, evaluation, reporting, and other

activities to complete the demonstration

project.
Program Update 1996-97 5-3

Project Participant Solicitation/Status Page

Environmental Control Devices

SO2

 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/completed 5-10

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/completed 5-14

LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCT-III/completed 5-18

Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 5-22

Demonstration of Innovative Applications of Technology for the Southern Company Services, Inc. CCT-II/completed 5-26

CT-121 FGD Process

NOx

 Control Technologies

Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control The Babcock & Wilcox Company CCT-II/completed 5-32

Full-Scale Demonstration of Low-NOx

 Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 5-36

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 5-40

Micronized Coal Reburning Demonstration for NOx

 Control New York State Electric & Gas Corporation CCT-IV/operational 5-44

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/operational 5-46

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCT-II/completed 5-48

for the Control of NOx Emissions from High-Sulfur-Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion Southern Company Services, Inc. CCT-II/completed 5-52

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

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/completed 5-58

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/completed 5-62

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5-66

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 5-70

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/operational 5-74

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue NOXSO Corporation CCT-III/restructuring 5-76

Gas Cleanup System

Integrated Dry NOx

/SO2 Emissions Control System Public Service Company of Colorado CCT-III/completed 5-78

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project City of Lakeland, Department of Electric & Water Utilities CCT-III/design 5-86

McIntosh Unit 4B Topped PCFB Demonstration Project City of Lakeland, Department of Electric & Water Utilities CCT-V/design 5-88

Tidd PFBC Demonstration Project The Ohio Power Company CCT-I/completed 5-90

ACFB Demonstration Project York County Energy Partners, L.P. CCT-I/restructuring 5-94

Nucla CFB Demonstration Project Tri-State Generation and Transmission Association, Inc. CCT-I/completed 5-96

Exhibit 5-1

Project Fact Sheets, by Application Category and Participant
5-4 Program Update 1996-97

Exhibit 5-1 (continued)

Project Fact Sheets, by Application Category and Participant

Project Participant Solicitation/Status Page

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project Clean Energy Partners Limited Partnership CCT-V/restructuring 5-100

Piñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/operational 5-102

Tampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/operational 5-104

Wabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering Project CCT-IV/operational 5-106

Joint Venture

Advanced Combustion/Heat Engines

Healy Clean Coal Project Alaska Industrial Development and Export Authority CCT-III/construction 5-108

Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/restructuring 5-110

Externally Fired Combined-Cycle Demonstration Project Pennsylvania Electric Company CCT-V/concluded 5-112

Coal Processing for Clean Fuels

Coal Preparation Technologies

Development of the Coal Quality ExpertTM ABB Combustion Engineering, Inc., and CQ Inc. CCT-I/completed 5-116

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Custom Coals International CCT-IV/operational 5-120

Advanced Coal Conversion Process Demonstration Rosebud SynCoal Partnership CCT-I/operational 5-122

Mild Gasification

ENCOAL® Mild Coal Gasification Project ENCOAL® Corporation CCT-III/operational 5-124

Indirect Liquefaction

Commercial-Scale Demonstration of the Liquid-Phase Methanol Air Products Liquid Phase Conversion Company, L.P. CCT-III/operational 5-126

(LPMEOHTM) Process

Industrial Applications

Blast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/operational 5-130

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/completed 5-132

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) CPICORTM Management Company, L.L.C. CCT-V/design 5-136

Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/completed 5-138

Demonstration of Pulse Combustion in an Application for Steam ThermoChem, Inc. CCT-IV/concluded 5-142

Gasification of Coal
Program Update 1996-97 5-5

Exhibit 5-1 (continued)

Project Fact Sheets, by Application Category and Participant

Participant Project Location Page

ABB Combustion Engineering, Inc., and CQ Inc. Development of the Coal Quality ExpertTM Homer City, PA 5-116

ABB Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project Niles, OH 5-58

Air Products Liquid Phase Conversion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Kingsport, TN 5-126

Process

AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption West Paducah, KY 5-10

Alaska Industrial Development and Export Authority Healy Clean Coal Project Healy, AK 5-108

Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project Fairbanks, AK 5-110

The Babcock & Wilcox Company Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control Cassville, WI 5-32

The Babcock & Wilcox Company Full-Scale Demonstration of Low-NOx

 Cell Burner Retrofit Aberdeen, OH 5-36

The Babcock & Wilcox Company LIMB Demonstration Project Extension and Coolside Demonstration Lorain, OH 5-62

The Babcock & Wilcox Company SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project Dilles Bottom, OH 5-66

Bechtel Corporation Confined Zone Dispersion Flue Gas Desulfurization Demonstration Seward, PA 5-14

Bethlehem Steel Corporation Blast Furnace Granular-Coal Injection System Demonstration Project Burns Harbor, IN 5-130

City of Lakeland, Department of Electric & Water Utilities McIntosh Unit 4A PCFB Demonstration Project Lakeland, FL 5-86

City of Lakeland, Department of Electric & Water Utilities McIntosh Unit 4B Topped PCFB Demonstration Project Lakeland, FL 5-88

Clean Energy Partners Limited Partnership Clean Energy Demonstration Project East coast site 5-100

Coal Tech Corporation Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Williamsport, PA 5-132

CPICORTM Management Company, L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICORTM) Vineyard, UT 5-136

Custom Coals International Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Central City, PA 5-120

Lower Mt. Bethel, PA

Richmond, IN

Astabula, OH

ENCOAL® Corporation ENCOAL® Mild Coal Gasification Project Gillette, WY 5-124

Energy and Environmental Research Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Hennepin, IL 5-70

Springfield, IL

Energy and Environmental Research Corporation Evaluation of Gas Reburning and Low-NOx

 Burners on a Wall-Fired Boiler Denver, CO 5-40

LIFAC–North America LIFAC Sorbent Injection Desulfurization Demonstration Project Richmond, IN 5-18

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

 Control Lansing, NY 5-44
5-6 Program Update 1996-97

Exhibit 5-1 (continued)

Project Fact Sheets, by Application Category and Participant

Participant Project Location Page

New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project Lansing, NY 5-74

NOXSO Corporation Commercial Demonstration of the NOXSO SO2/NOx

 Removal Flue Gas NOXSO site under 5-76

Cleanup System negotiation

Charleston, TN

The Ohio Power Company Tidd PFBC Demonstration Project Brilliant, OH 5-90

Passamaquoddy Tribe Cement Kiln Flue Gas Recovery Scrubber Thomaston, ME 5-138

Pennsylvania Electric Company Externally Fired Combined-Cycle Demonstration Project Not applicable 5-112

Public Service Company of Colorado Integrated Dry NOx /SO2

 Emissions Control System Denver, CO 5-78

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Chesterton, IN 5-22

Rosebud SynCoal Partnership Advanced Coal Conversion Process Demonstration Colstrip, MT 5-122

Sierra Pacific Power Company Piñon Pine IGCC Power Project Reno, NV 5-102

Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coosa, GA 5-46

Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newnan, GA 5-26

Process

Southern Company Services, Inc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensacola, FL 5-48

NOx

 Emissions from High-Sulfur-Coal-Fired Boilers

Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Combustion Lynn Haven, FL 5-52

Techniques for the Reduction of NOx

 Emissions from Coal-Fired Boilers

Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project Mulberry, FL 5-104

ThermoChem, Inc. Demonstration of Pulse Combustion in an Application for Steam Gasification Not applicable 5-142

of Coal

Tri-State Generation and Transmission Association, Inc. Nucla CFB Demonstration Project Nucla, CO 5-96

Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project West Terre Haute, IN 5-106

Project Joint Venture

York County Energy Partners, L.P. ACFB Demonstration Project To be determined 5-94
Program Update 1996-97 5-7

Project Participant End Date Solicitation Page

Environmental Control Devices

SO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. 3/94 CCT-III 5-10

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation 6/93 CCT-III 5-14

LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America 6/94 CCT-III 5-18

Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. 6/95 CCT-II 5-22

Demonstration of Innovative Applications of Technology for the Southern Company Services, Inc. 12/94 CCT-II 5-26

CT-121 FGD Process

NOx

 Control Technologies

Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control The Babcock & Wilcox Company 12/92 CCT-II 5-32

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit The Babcock & Wilcox Company 4/93 CCT-III 5-36

Evaluation of Gas Reburning and Low-NOx

 Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation 1/95 CCT-III 5-40

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. 7/95 CCT-II 5-48

for the Control of NOx

 Emissions from High-Sulfur-Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion Southern Company Services, Inc. 12/92 CCT-II 5-52

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

Combined SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems 12/94 CCT-II 5-58

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company 8/91 CCT-I 5-62

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company 5/93 CCT-II 5-66

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation 10/94 CCT-I 5-70

Integrated Dry NOx

/SO2 Emissions Control System Public Service Company of Colorado 12/96 CCT-III 5-78

Advanced Electric Power Generation

Fluidized-Bed Combustion

Tidd PFBC Demonstration Project The Ohio Power Company 3/95 CCT-I 5-90

Nucla CFB Demonstration Project Tri-State Generation and Transmission Association, Inc. 1/91 CCT-I 5-96

Coal Processing for Clean Fuels

Coal Preparation Technologies

Development of the Coal Quality ExpertTM ABB Combustion Engineering, Inc., and CQ Inc. 12/95 CCT-I 5-116

Industrial Applications

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation 5/90 CCT-I 5-132

Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe 9/93 CCT-I 5-138

Exhibit 5-2

CCT Projects that Completed Operational Testing by June 30, 1997
5-8 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

Environmental control devices are those technologies applied (retrofitted) to existing or new facilities

for the purpose of controlling SO2

 and NOx emissions.

Although boilers may be modified and combustion

affected, the basic boiler configuration and function

remains unchanged in retrofitting these technologies.

SO2 Control Technology

Sulfur dioxide (SO2 ) is an acid gas formed

during coal combustion, which oxidizes the inorganic, pyritic sulfur (Fe2

S), and organically bound sulfur

in the coal. Identified as a precursor to formation of

acid rain, SO2 was targeted in Title IV of the Clean

Air Act Amendments of 1990 (CAAA). Phase I of

Title IV, effective in 1995, affected 261 coal-fired

units nationwide. The required SO2 reduction was

moderate and largely met by switching to low-sulfur

fuels. In year 2000, Phase II of Title IV will come

into effect, impacting all fossil-fuel-fired units, but

most of all, the approximately 900 pre-NSPS coalfired units. Under the stricter Phase II requirements,

compliance by fuel switching alone is unlikely. But,

the CAAA provides utilities flexibility in control

strategies through SO2 allowance trading. This

permits a range of control options to be applied by a

utility, as well as allowance purchasing. Recognizing

this, the CCT Program has sought to provide a

portfolio of SO2 control technologies.

SO2

 control devices embody those technologies

that condition and act upon the flue gas resulting from

combustion, not the combustion itself, for the purpose

of removing only SO2

. Three basic approaches

evolved, driven primarily by different conditions that

exist within the pre-NSPS boiler population impacted

by the CAAA. There is a tremendous range in critical

factors, such as size, type, age, and space availability.

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

capture. Equipment size and complexity are held to a

minimum to keep capital costs and space requirements

low. Both limestone and lime sorbents are used.

Limestone 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

calcium sulfate. Both limestone and lime injection

require the presence of water (humidification) and a

calcium-to-sulfur molar ratio (Ca/S) of about 2.0 for

sulfur capture efficiencies of 50–70 percent.

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

MWe boilers less than 30 years old and somewhat

space constrained. For many of these, an increase in

front-end control cost is justified by enhanced

performance. 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 of 1.3–2.0. 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, 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 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 dewatered to

produce gypsum—a salable product.

Under the CCT Program, two sorbent injection

systems, one spray dryer, and two AFGD processes were

successfully demonstrated. All have completed testing.

Exhibit 5-3 briefly summarizes the characteristics and

performance of the technologies that are described in

more detail in the project fact sheets.
Environmental Control Devices Program Update 1996-97 5-9

Exhibit 5-3

CCT Program SO2 Control Technology Characteristics

Coal Sulfur SO2 Fact

Project Process Content Reduction Sheet

Confined Zone Dispersion Flue Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.5–2.5% 50% 5-14

Desulfurization Demonstration

LIFAC Sorbent Injection Desulfurization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% 70% 5-18

Demonstration Project humidification vessel and sorbent recycle

10-MWe Demonstration of Gas Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7–3.5% 60–90% 5-10

Absorption particulate recycle (lime sorbent)

Advanced Flue Gas Desulfurization AFGD—co-current flow, integrated quench absorber tower and reaction 2.25–4.7% 94% 5-22

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

Demonstration of Innovative Applications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2–3% 90+% 5-26

of Technology for the CT-121 FGD Process Reactor®) for combined SO2

 and particulate capture (gypsum by-product)

This side view of Pure Air’s advanced flue gas desulfurization absorber module

shows air inlet ducts and sorbent injection piping.

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

Air absorber module.
5-10 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

10-MWe Demonstration of Gas

Suspension Absorption

Project completed.

Participant

AirPol, Inc.

Additional Team Members

FLS miljo a/s (parent company of AirPol, Inc.)—

technology owner

Tennessee Valley Authority—cofunder and site owner

Location

West Paducah, McCracken County, KY (Tennessee Valley

Authority’s Center for Emissions Research)

Technology

FLS miljo a/s’ 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

Coals

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 variable-speed 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 on-line 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 time.
Environmental Control Devices Program Update 1996-97 5-11

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

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 of 1.3 with 8 oF approach-to-saturation and 0.04% chloride,

– 90% sulfur capture at a Ca/S 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 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, artimony, 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 1

/4–1/3 the size.

• GSA generated lower particulate loading than a spray

dryer, enabling compliance with a lower ESP efficiency.

• Special steels were not required in construction, and

only a single spray nozzle is needed

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

simple design.

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

Economic

• Capital and levelized (15-year) costs for GSA installed

in a 300-MWe plant using 2.6% sulfur coal are compared below to costs for a wet limestone scrubber with

forced oxidation (WLFO scrubber). EPRI’s cost methodology was employed. Based on EPRI cost studies

of FGD processes, the capital cost (1990$) for a conventional spray dryer was $172/kW.

Capital Cost Levelized Cost

(1990$/kW) (mills/kWh)

GSA—3 units at $149 10.35

50% capacity

WLFO $216 13.04
5-12 Program Update 1996-97 Environmental Control Devices

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 5-4 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 approach-to-saturation temperature was chosen for the

higher 0.12% coal chloride level. Exhibit 5-5 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,

0.12%, 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 to 1.0 gr/ft3

 (actual).

Exhibit 5-5

GSA Factorial Testing Results

Exhibit 5-4

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

 std ft3/min) 14 and 20

Recycle screw speed (rpm) 30 and 45

*

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

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 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 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 to

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

system. The removal of HCl and HF was dependent upon

the utilization of lime slurry and was relatively independent

of particulate control configuration. The removal efficiencies were greater than 98% and 96% for HCl and HF, respectively.

Operational Performance

Because the GSA system has suspended recycle solids to

provide a contact area for SO2

 capture, multiple high-pressure atomizer nozzles or high-speed rotary nozzles to

achieve uniform, fine droplet size are not required. Also,

recycle of solids is direct and avoids recycling material in
Environmental Control Devices Program Update 1996-97 5-13

1 2 3 4 1 2 3 4 1 2 3 4 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 the feed slurry, which necessitates expensive abrasionresistant 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—

1

⁄4 to 1⁄3 the size. This makes retrofit feasible for spaceconfined 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 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 byproduct 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 30–35

other FGD processes, economics were estimated for a

moderately difficult retrofit of a 300-MWe boiler burning

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 and

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 to the city of Hamilton, OH,

subsidized by the Ohio Coal Development Office. This

will enable AirPol, Inc., to refine the commercial design

and provide a solid design base for a 100-MWe unit,

which will be the module size for larger plants. In addition to positioning GSA for market penetration into larger

plant sizes, the experience at the first commercial site will

increase utility sector confidence in the GSA system. This

should be further bolstered by an award to FLS miljo of a

major project in Sweden for a high-performance GSA

system to remove 90–95% sulfur from the flue gas of a

4-million-ton/yr iron ore sinter plant.

Contacts

Frank E. Hsu, Vice President, Operations, (201) 490-6400

AirPol, Inc.

3 Century Drive

Parssippany, NJ 07054-4610

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

Sharon K. Marchant, FETC, (412) 892-6008

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 NTIS as DE960003270.)

• SO2

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

Energy and AirPol, Inc. April 1995.

AirPol successfully demonstrated the GSA system at

TVA’s Center for Emissions Research.
5-14 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

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

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 capacity of the

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

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

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

for a final total project cost of $12,173,000.
Environmental Control Devices Program Update 1996-97 5-15

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Calendar Year

*Projected date

3 4 1 2

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

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%

sulfur coal and achieving 50% SO2

 reduction was

estimated at less than $30/kW and operating cost at

$300/ton of SO2

 removed.

Preaward Operation

12/89 10/90

DOE selected project

(CCT-III) 12/19/89

Design start 6/90

NEPA process completed (MTF) 9/90

Cooperative agreement awarded 10/90

Design completed 10/90

Ground breaking/construction started 3/91

Construction completed 6/91

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
5-16 Program Update 1996-97 Environmental Control Devices

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

pressure-hydrated 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 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.

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.
Environmental Control Devices Program Update 1996-97 5-17

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

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

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

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

This photo shows the CZD/FGD lime slurry injector control system.

References

• Confined Zone Dispersion Project: Final Technical

Report. Bechtel Corporation. June 1994.

• Confined Zone Dispersion Project: Public Design

Report. Bechtel Corporation. October 1993.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Confined Zone Dispersion Flue

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

Energy. September 1990. (Available from NTIS as

DE91002564.)
5-18 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

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.
Environmental Control Devices Program Update 1996-97 5-19

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

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-to-sulfur

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

minus 325 mesh.

• SO2

 removal efficiency with limestone fineness of

80% minus 200 mesh was 15% lower at a Ca/S of 2.0

and 7–12 oF approach to saturation.

• The four parameters having the greatest influence on

sulfur removal efficiency were limestone quality, 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 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).

• Operating cost—$65/ton of SO2

 removal, assuming

75% SO2

 capture, Ca/S of 2.0, limestone composed of

95% CaCO3

, and $15/ton.

9/97

Project completed/final

report issued 9/97*
5-20 Program Update 1996-97 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 highsulfur coal. There are 10 full-scale LIFAC units in Canada,

China, Finland, Russia, and the United States.

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% to 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 quality, 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- 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-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 bottom and
Environmental Control Devices Program Update 1996-97 5-21

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

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, startup, 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)

• $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 ton of SO2

, assuming 75% SO2

capture, a Ca/S 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 or under

construction 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

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

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

References

• “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.)

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.
5-22 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

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, Units 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 AFGD-derived gypsum.

PowerChip is a registered trademark of Pure Air on the Lake, L.P.
Environmental Control Devices Program Update 1996-97 5-23

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

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 partialcapacity WES was installed).

• PowerChip® increased the market potential for AFGDderived 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

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

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Design and Construction Operation

9/88

Project completed/final report issued 6/96

DOE selected project

(CCT-II) 9/28/88

Cooperative agreement awarded 12/20/89

Preoperational tests initiated 3/92

Operation initiated 6/92

Design completed 9/92

Construction completed 9/92

Operation completed 6/95

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
5-24 Program Update 1996-97 Environmental Control Devices

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) of 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 5-6 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 byproduct. 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 5-7 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 Institute’s

Technical Assessment Guide.

The incremental benefits of the own-and-operate

arrangement, by-product utilization, and emission allowances were also evaluated. Exhibit 5-8 depicts the relaExhibit 5-6

 SO2 Removal Performance

(100% Boiler Load)
Environmental Control Devices Program Update 1996-97 5-25

1 2 3 4 1 2 3 4 1 2 3 4 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 Pure Air of Manatee, L.P., entered into a contract

with Florida Power & Light Company to process 1,600

MWe of flue gas with two 800-MWe AFGD modules and

incorporate WES.

Contacts

Don Vymazal, Manager, Contract Administration

(601) 481-3687

Pure Air on the Lake, L.P.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

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

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

References

• Advanced Flue Gas Desulfurization (AFGD) Demonstration Project: Final Technical Report. Pure Air on

the Lake, L.P. April 1996.

• 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.)

• Summary of Air Toxics Emissions Testing at Sixteen

Utility Power Plants. Prepared by Burns and Roe

Services Corporation for U.S. Department of Energy,

Pittsburgh Energy Technology Center. July 1996.

tive 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 5-8 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 year 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 costs for AFGD. The own-andoperate 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.

Exhibit 5-7

Estimated Costs for an AFGD System

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 5-8

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%
5-26 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

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

Coals

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 dyked area

with gypsum slurry. Gypsum solids settle in the dyked

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

Corporation.
Environmental Control Devices Program Update 1996-97 5-27

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

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

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

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 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 conventional FGD

systems.

9/97

Operation completed 12/94

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 5-9 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 boiler

with a marginally performing particulate collection

device. The SO2

 removal efficiency was measured under

Project completed/final

report issued 9/97*
5-28 Program Update 1996-97 Environmental Control Devices

five different inlet concentrations with coals averaging

2.4% and ranging 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%. It 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 5-10 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 5-11.

Analysis indicated that a large percentage of the

outlet particulate matter is sulfate, 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.

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 5-9

Operation of CT-121 Scrubber

Exhibit 5-10

SO2 Removal Efficiency

Exhibit 5-11

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.
Environmental Control Devices Program Update 1996-97 5-29

1 2 3 4 1 2 3 4 1 2 3 4 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 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 5-12.

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 predominant cause

of the initial high 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.),

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.

Contacts

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

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

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

References

• Final technical, economic, and public design reports

are expected to be available by September 1997.

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

Plant Utilizing an ESP while Demonstrating the CCT

CT-121 FGD Project. Final Report. Report No.

DOE/PC/93253-T1. Radian Corporation. June 1994.

(Available from NTIS as DE94016053.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Demonstration of 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 5-12

CT-121 Air Toxics Removal

(JBR Components Only)

0

20

40

60

80

100

Chloride Fluoride Arsenic Cadmium Mercury Selenium Vanadium

Removal Efficiency (%)

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
5-30 Program Update 1996-97 Environmental Control Devices

NOx Control Technology

Nitrogen oxides (NOx) are formed from oxidation

of nitrogen contained within the coal (fuel-bound

nitrogen) and oxidation of the nitrogen in the air at

high temperatures of combustion (thermal NOx).

Rapid formation of NOx

 at the flame front can occur;

but usually, this reaction of hydrocarbon fragments

with atmospheric nitrogen represents a small fraction

of total NOx emissions. To control fuel-NOx formation, it is important to limit oxygen at the early stages

of combustion. To control thermal NOx

,it is important

to limit peak temperatures.

NOx was identified both as a precursor to acid

rain, targeted under Title IV of the CAAA, and as a

contributor to ozone formation, targeted under Title

I. Phase I of Title IV, effective in 1995, required

some 169 wall- and tangentially fired coal units to

reduce emissions to 0.50 and 0.45 pound per million

Btu, respectively. In 2000, Phase II of Title IV will

come into effect, impacting all fossil-fueled units, but

most of all, the balance of the 900 pre-NSPS coalfired units (see Exhibit 5-13). The proposed new

NSPS for NOx

 emissions reduces the limit for new or

modified utility units to 1.35 pounds per megawatthour, regardless of fuel type, or as an alternate, 0.15

pounds per million Btu. In 1998, the largest sources

of NOx in 13 eastern states will be

required to monitor and report their

NOx emissions during ozone season,

and additional rules pertaining to

ozone transport are expected.

Further, final revisions to NAAQS

for ozone drop the limit to 80 parts

per billion over 8 hours. In anticipation of these stricter NOx

 limits, 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 combustion process or acting

upon the products of combustion (or

combinations thereof). Combustion

modification technologies include

low-NOx

 burners (LNBs), advanced

overfire air (AOFA), and reburning

Exhibit 5-13

Group I and 2 Boiler Statistics

and Phase II NOx Emission Limits

Phase II

No. of NOx Emission Limits

Boiler Types Boilers (lb/106 Btu)

Group 1

Tangentially fired 299 0.40

Dry-bottom, wall-fired 308 0.46

Group 2

Cell burner 36 0.68

Cyclone >155 MWe 55 0.86

Wet-bottom, wall-fired >65 MWe 26 0.84

Vertically fired 28 0.80

Source: Environmental Protection Agency, Nitrogen Oxides Emission Reduction

Program, Final Rule for Phase II, Group 1 and Group 2 Boilers (downloaded from

http://www.epa.gov/docs/acidrain/noxfs3.html).

A portion of ABB Combustion Engineering’s LowNOx

 Concentric Firing System (LNCFSTM) is shown being

installed on a tangentially fired boiler.

processes using either gas or coal. Processes used to

act upon flue gas include selective catalytic reduction

(SCR) and selective noncatalytic reduction (SNCR).

LNBs regulate the initial fuel-air mixture,

velocities, and turbulence to create a fuel-rich flame

core and control the rate at which additional air

required to complete combustion is mixed. This

staging of combustion avoids a highly oxidized

environment and hot spots conducive to fuel-NOx and

thermal-NOx formation. LNBs alone typically can

achieve 40–50 percent NOx

 reduction. But no LNBs

have been developed for cyclone-fired boilers.

AOFA involves injection of air above the primary

combustion zone to allow the primary combustion to

occur without the amount of oxygen needed for

complete combustion. This oxygen deficiency

mitigates fuel-NOx

 formation. AOFA injected at high
Environmental Control Devices Program Update 1996-97 5-31

Exhibit 5-14

CCT Program NOx Control Technology Characteristics

Boiler Size/ NOx Fact

Project Process Type Reduction Sheet

Demonstration of Coal Reburning for Cyclone Coal reburning—30% heat input 100 MWe/cyclone 52–62% 5-32

Boiler NOx Control

Evaluation of Gas Reburning and Low-NOx

 Burners LNB/gas reburning/AOFA—13–18% gas heat input 172 MWe/wall 37–65% 5-40

on a Wall-Fired Boiler

Micronized Coal Reburning Demonstration Coal reburning—30% heat input 148 MWe/tangential 50–60% (goal) 5-44

for NOx Control 50 MWe/cyclone

Full-Scale Demonstration of Low-NOx Cell Burner LNB—separation of coal and air ports on plug-in unit 605 MWe/cell burner 48–58% 5-36

Retrofit

Demonstration of Advanced Combustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500 MWe/wall 50% (goal) 5-46

for a Wall-Fired Boiler and artificial intelligence controls

180-MWe Demonstration of Advanced Tangentially LNB/AOFA—advanced LNB with close-coupled 180 MWe/tangential 37–45% 5-52

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

Emissions from Coal-Fired Boilers

Demonstration of Selective Catalytic Reduction SCR—eight catalysts with different shapes and 8.7 MWe/various 80% 5-48

Technology for the Control of NOx

 Emissions chemical compositions

from High-Sulfur-Coal-Fired Boilers

velocity creates turbulent mixing to complete the

combustion in a gradual fashion at lower temperatures

to mitigate thermal-NOx formation. Usually, AOFA is

used in combination with LNBs, but alone, AOFA can

achieve 10–25 percent NOx

 emission reductions.

LNB/AOFA systems generally can achieve NOx

emission reductions of 60–67 percent.

In reburning, a percentage of the fuel input to the

boiler is diverted to injection ports above the primary

combustion zone. Either gas or coal is typically used as

the reburning fuel to provide 10–30 percent of the heat

input to the boiler. The reburning fuel is injected to

create a fuel-rich zone deficient in oxygen (a reducing

rather than oxidizing zone). NOx entering this zone is

stripped of oxygen, forming elemental nitrogen.

Combustion is completed in a burnout zone where air

is injected by an AOFA system. Reburning has

application to all boiler types, including cyclone

boilers, and can achieve NOx emission reductions of

50–67 percent.

SCR and SNCR can be used alone or in combination with combustion modification. These processes use ammonia or urea in a reducing reaction with

NOx

 to form elemental nitrogen and water. SNCR

can only be used at high temperatures (1,600–2,200 oF)

where a catalyst is not needed. SCR is typically

applied at temperatures between 600–800 oF. Generally, SNCR and SCR systems alone can achieve NOx

emission reductions of 30–50 percent and 80–90+

percent, respectively.

Under the CCT Program, seven NOx

 control

technologies were addressed, encompassing LNBs,

AOFA, reburning, SNCR, SCR, and combinations

thereof. Five of the projects have been completed, one

is nearing completion, and one is in construction.

Exhibit 5-14 briefly summarizes the characteristics

and performance of the technologies that are described in more detail in the project fact sheets.
5-32 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Demonstration of Coal

Reburning for Cyclone Boiler

NO

x

 Control

Project completed.

Participant

The Babcock & Wilcox Company

Additional Team Members

Wisconsin Power and Light Company—cofunder and

host

Sargent and Lundy—engineer for coal handler

Electric Power Research Institute—cofunder

State of Illinois, Department of Energy and Natural

Resources—cofunder

Utility companies (14 cyclone boiler operators)—

cofunders

Location

Cassville, Grant County, WI (Wisconsin Power and Light

Company’s Nelson Dewey Station, Unit No. 2)

Technology

The Babcock & Wilcox Company’s coal-reburning

system, Coal Reburn

Plant Capacity/Production

100 MWe

Coals

Illinois Basin bituminous (Lamar), 1.15% sulfur,

1.24% nitrogen

Powder River Basin (PRB) subbituminous, 0.27% sulfur,

0.55% nitrogen

Project Funding

Total project cost $13,646,609 100%

DOE 6,340,788 46

Participant 7,305,821 54

Project Objective

To demonstrate the technical and economic feasibility of

achieving greater than 50% reduction in NOx

 emissions

with no serious impact on cyclone combustor operation,

boiler performance, or other emission streams.

Technology/Project Description

Babcock & Wilcox Coal Reburn reduces NOx

 in the furnace through the use of multiple combustion zones. The

main combustion zone uses 70–80% of the total heatequivalent fuel input to the boiler and slightly less than

normal combustion air input. The balance of the coal

(20–30%), along with significantly less than the theoretically determined requirement of air, is fed to the reburning

zone above the cyclones to create an oxygen-deficient

condition. The NOx

 formed in the cyclone burners reacts

with the resultant reducing flue gas and is converted into

nitrogen in this zone. The completion of the combustion

process occurs in the third zone, called the burnout zone,

where the balance of the combustion air is introduced.

Coal Reburn can be applied with the cyclone burners

operating within their normal, noncorrosive, oxidizing

conditions, thereby minimizing any adverse effects of

reburn on the cyclone combustor and boiler performance.

This project involved retrofitting an existing

100-MWe cyclone boiler that is representative of a large

population of cyclone units.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-33

Results Summary

Environmental

• Coal Reburn achieved greater than 50% NOx

 reduction

at full load with Lamar bituminous and PRB subbituminous coals.

• Reburn-zone stoichiometry had the greatest effect on

NOx

 control.

• Gas recirculation was vital to maintaining reburn-zone

stoichometry while providing necessary burner cooling, flame penetration, and mixing.

• Opacity levels and electrostatic precipitator (ESP)

performance were not affected by Coal Reburn with

either coal tested.

• Optimal Coal Reburn heat input was 29–30% at full

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

Operational

• No major boiler performance problems were experienced with Coal Reburn operations.

• Boiler turndown capability was 66%, exceeding the

50% goal.

• ESP efficiency improved slightly during Lamar coal

testing and did not change with PRB coal.

• Coal fineness levels above the nominal 90% through

200 mesh were maintained, reducing unburned carbon

losses (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

using Lamar coal. With PRB coal, the efficiency loss

ranged from 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 without

boiler derating.

Economic

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

$66/kW and $43/kW, respectively. Levelized 10- and

30-year busbar power costs for a 110-MWe plant were

2.4 and 2.3 mills/kWh, respectively. Levelized 10-

and 30-year busbar power costs for a 605-MWe plant

were 1.6 and 1.5 mills/kWh, respectively.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction

9/88

Preaward

DOE selected project

(CCT-II) 9/28/88

Cooperative agreement

awarded 4/2/90

4/90 12/91

Operation

3/94

Project completed/final report issued 3/94

Operation

completed 12/92 Operation

initiated 12/91

Construction completed 11/91

Preoperational tests initiated 11/91

Environmental monitoring plan completed 11/18/91

NEPA process completed (EA) 2/12/91

Design completed 6/91

Ground breaking/construction started 11/90
5-34 Program Update 1996-97 Environmental Control Devices

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 or long-term operation period were any slagging or fouling problems observed. In fact, during scheduled outages, internal boiler inspections revealed that boiler cleanliness had actually improved. Extensive ultrasonic

thickness measurements were taken of

the furnace wall tubes. No observable

decrease in wall tube thickness was

measured.

Another significant finding was

that Coal Reburn minimizes and possibly eliminated a 0–25% derating normally associated with switching to

subbituminous coal in a cyclone unit.

This derating was a result of using a

lower Btu fuel in a cyclone with a

limited coal feed capacity. The reburn

system transferred about 30% of the

Project Summary

Although cyclone boilers represent only 15% of the preNSPS coal-fired generating capacity, they contribute 21%

of the NOx

 formed by pre-NSPS coal-fired units. This is

due to the cyclone combustor’s inherent turbulent, hightemperature combustion process. Consequently, cyclone

boilers are targeted for NOx

 reduction under the CAAA

and state implementation plans. However, at the time of

this demonstration, there was no cost-effective combustor

modification available for NOx

 control.

Babcock & Wilcox Coal Reburn offers an economic

and operationally sound response to the environmental

impetus. This technology avoids cyclone combustor

modification and associated performance complications

and provides an alternative to other cyclone boiler NOx

-

control options having relatively higher capital and/or

operating costs.

The majority of the testing was performed firing

Illinois Basin bituminous coal (Lamar), as it is typical of

the coal used by many utilities operating cyclones. Subbituminous PRB coal tests were performed to evaluate the

effect of coal switching on reburn operation. Wisconsin

Power and Light’s strategy to meet Wisconsin’s sulfur

emission limitations as of January 1, 1993, was to fire

low-sulfur coal.

Environmental Performance

Three sequences of testing of Coal Reburn used Lamar

coal. Parametric optimization testing was used to set up

the automatic controls. Performance testing was run with

the unit in full automatic control at set load points. Longterm testing was performed with reburn in operation

while the unit followed system load demand requirements. PRB coal was tested by parametric optimization

and performance modes. Exhibit 5-15 shows changes in

NOx

 emissions and boiler efficiency using the reburn

system for various load conditions and coal types.

Coal Reburn tests on both the Lamar and PRB coals

indicated that variation of reburn-zone stoichiometry was

Boiler Load

110 MWe 82 MWe 60 MWe

Lamar coal

NOx

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

Boiler efficiency losses due to 0.1 0.25 1.5

unburned carbon (%)

Powder River Basin coal

NOx (lb/106 Btu/% reduction) 0.34/55 0.31/52 0.30/53

Boiler efficiency losses due 0.0 0.2 0.3

to unburned carbon (%)

Exhibit 5-15

Coal Reburn Test Results

the most critical factor in changing NOx emissions levels.

The reburn-zone stoichiometry can be varied by alternating the air flow quantities (oxygen availability) to the

reburn burners, the percent reburn heat input, the gas

recirculation flow rate, or the cyclone stoichiometry.

Hazardous air pollutant (HAP) testing was performed

using Lamar test coal. HAP emissions were generally

well within expected levels, and emissions with Coal

Reburn were comparable to baseline operation. No major

effect of reburn on trace-metals partitioning was discernible. None of the 16 targeted polynuclear aromatic semivolatile organics (controlled under Title III of CAAA) was

present in detectable concentrations, at a detection limit of

1.2 parts per billion.

Operational Performance

For Lamar coal, the full-, medium-, and low-load UBCL

were 0.1%, 0.25%, and 1.5% higher, respectively, than the

baseline. Full-, medium-, and low-load UBCL with PRB

coal were 0.0%, 0.2%, and 0.3% higher, respectively, than

the baseline. Coal Reburn burner flame stability improved with PRB coal.

Wisconsin Power and Light Company’s Nelson Dewey

Station hosted the successful demonstration of Coal Reburn.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-35

coal feed out of the cyclone to the reburn burners, bringing the cyclone feed rate down to a manageable level,

while maintaining full-load heat input to the unit.

Economic Performance

An economic analysis of total capital and levelized revenue requirements was conducted using the “Electric

Power Research Institute Economic Premises” for retrofit

of 110- and 605-MWe plants. In addition, annualized

costs per ton of NOx

 removed were developed for 110-

and 605-MWe plants over both 10 and 30 years. The

results of these analyses are shown in Exhibit 5-16. These

values assumed typical retrofit conditions and did not

take into account any fuel savings from use of low-rank

coal. The pulverizers and associated coal handling were

taken into account. Site-specific parameters that can

significantly impact these retrofit costs included the state

of the existing control system, availability of flue gas

recirculation, space for coal pulverizers, space for reburn

burners and overfire air ports within the boiler, scope of

coal-handling modification, sootblowing capacity, ESP

capacity, steam temperature control capacity, and boiler

circulation considerations.

Commercial Applications

Coal Reburn is a retrofit technology applicable to a wide

range 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 units

ranging from 100 to 1,750 MWe with most in the

100–300-MWe range.

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

Contacts

Tony Yagiela, (216) 829-7403

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

John C. McDowell, FETC, (412) 892-6237

References

• Demonstration of Coal Reburning for Cyclone Boiler

NOx

 Control: Final Project Report. Report No. DOE/

PC/89659-T16. The Babcock & Wilcox Company.

February 1994. (Available from NTIS as

DE94013052, Appendix 1 as DE94013053,

Appendix 2 as DE94013054.)

• Public Design Report: Coal Reburning for Cyclone

Boiler NOx

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

DE92012554.)

The coal pulverizer is part of Babcock & Wilcox Coal

Reburn. This system has been retained by Wisconsin Power

and Light for NOx

 emission control at the Nelson Dewey

Station.

Exhibit 5-16

Coal Reburn Economics

Plant Size

Costs 110 MWe 605 MWe

Total capital cost ($/kW) 66 43

Levelized busbar power

cost (mills/kWh)

10-year life 2.4 1.6

30-year life 2.3 1.5

Annualized cost

 ($/ton of NOx

 removed)

10-year life 1,075 408

30-year life 692 263

• Comprehensive Report to Congress on the Clean Coal

Program: Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control. (The Babcock & Wilcox

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

NTIS as DE90008111.)
5-36 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Full-Scale Demonstration of

Low-NO

x

 Cell Burner Retrofit

Project completed.

Participant

The Babcock & Wilcox Company

Additional Team Members

The Dayton Power and Light Company—cofunder and

host

Electric Power Research Institute—cofunder

Ohio Coal Development Office—cofunder

Tennessee Valley Authority—cofunder

New England Power Company—cofunder

Duke Power Company—cofunder

Allegheny Power System—cofunder

Centerior Energy Corporation—cofunder

Location

Aberdeen, Adams County, OH (Dayton Power and Light

Company’s J.M. Stuart Plant, Unit No. 4)

Technology

The Babcock & Wilcox Company’s low-NOx

 cell burner

(LNCB®) system

Plant Capacity/Production

605 MWe

Coal

Bituminous, medium sulfur

Project Funding

Total project cost $11,233,392 100%

DOE 5,442,800 48

Participant 5,790,592 52

Project Objective

To demonstrate, through the first commercial-scale full

burner retrofit, the cost-effective reduction of NOx

 from a

gen compounds are converted to nitrogen gas, and the

reduced flame temperature minimizes the formation of

thermal NOx

.

The demonstration was conducted on a Babcock &

Wilcox-designed, supercritical, once-through boiler

equipped with an electrostatic precipitator (ESP). This

unit, which is typical of cell burner boilers, contained 24

two-nozzle cell burners arranged in an opposed-firing

configuration. Twelve burners (arranged in two rows of

six burners each) were mounted on each of two opposing

walls of the boiler. All 24 standard cell burners were

removed, 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.

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 of

conventional low-NOx

 burners.

Technology/Project Description

The LNCB® technology replaces the upper coal nozzle of

the standard two-nozzle cell burner with a secondary air

port. The lower burner coal nozzle is enlarged to the

same fuel input capacity as the two standard coal nozzles.

The LNCB® operates on the principle of staged combustion to reduce NOx

 emissions. Approximately 70% of the

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

through or around the coal-feed nozzle. The remainder

of the air is directed to the upper port of each cell to

complete the combustion process. The fuel-bound nitroLNCB is a registered trademark of The Babcock & Wilcox Company.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-37

Results Summary

Environmental

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

showed NOx reductions in the range of 53.0–55.5%,

52.5–54.7%, and 46.9–47.9% at loads of 605 MWe,

460 MWe, and 350 MWe, respectively.

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

showed an average NOx

 reduction of 58% (over

8 months).

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

showed an average NOx

 reduction of 60% (over

8 months).

• CO emissions averaged 28–55 ppm at full load with

LNCB® in service.

• Fly ash increased, but ESP performance remained

virtually unchanged.

Operational

• Unit efficiency remained essentially unchanged.

• Unburned carbon losses (UBCL) increased by approximately 28% for all tests, but boiler efficiency loss was

offset by a decrease in dry gas loss due to a lower

boiler economizer outlet gas temperature.

• Boiler corrosion with LNCB® was roughly equivalent

to boiler corrosion rates prior to retrofit.

Economic

• Capital cost for a 600-MWe plant was $9/kW (1994$).

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

0.284 mills/kWh and $96.48/ton of NOx

 removed.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

initiated 12/91

10/90

Operation

Design and

Preaward Construction

12/91

NEPA process completed (MTF) 8/10/90

DOE selected project

(CCT-III) 12/19/89

Project completed/final report issued 12/95

Project Summary

Utility boilers equipped with cell burners currently comprise 13% or approximately 23,000 MWe of pre-NSPS

coal-fired generating capacity. Cell burners are designed

for rapid mixing of the fuel and air. The tight burner

spacing and rapid mixing minimize the flame size while

maximizing the heat release rate and unit efficiency.

Combustion efficiency is good, but the rapid heat release

produces relatively large quantities of NOx

.

To reduce NOx

 emissions, the LNCB® has been

designed to stage mixing of the fuel and combustion air.

A key design criterion was accomplishing delayed fuel-air

mixing with no modifications to waterwall panels. A

plug-in design reduces material costs and outage time

required to complete the retrofit, compared to installing

conventional, internally staged low-NOx

 burners. LNCB®

provides a lower cost alternative to address NOx reduction

requirements for cell burners.

12/95

Operation completed 4/93

12/89

Construction completed 11/91

Preoperational tests initiated 11/91

Cooperative agreement

awarded 10/11/90

Design completed 10/90

Environmental monitoring plan

completed 8/9/91

Ground breaking/construction started 9/91
5-38 Program Update 1996-97 Environmental Control Devices

Average NOx reduction at

intermediate load (about

460 MWe) ranged from 52.5% to

54.7%. At low loads (about

350 MWe), average NOx

 reduction

ranged from 46.9% to 47.9%.

NOx

 emissions were monitored over the long-term at full

load for all mills in service and

one mill out of service. Each test

spanned an 8-month period. NOx

emission reductions realized were

58% for all mills in service and

about 60% for one mill out of

service.

Complications arose in assessing CO emissions relative to

baseline because baseline calibration was not refined enough.

However, accurate measurements

were made with LNCB® in service. CO emissions were corrected to 3.0% O2

 and measured at full, intermediate, and low loads. The range of

CO emissions at full load with all mills in service was

28–55 ppm and 20-38 ppm with one mill out of service.

At intermediate loads (about 460 MWe), CO emissions

were 28–45 ppm and at low loads (about 350 MWe),

5–27 ppm.

Particulate emissions were minimally impacted. The

LNCB® had little effect on flyash resistivity, largely due

to SO3

 injection, and therefore ESP removal efficiency

remained very high. Baseline ESP collection efficiencies

for full load with all mills in service, full load with one

mill in service, and intermediate load with one mill out of

service were 99.5%, 99.49%, and 99.81%, respectively.

For the same conditions, in the same sequence with

LNCB® in operation, ESP collection efficiencies were

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

Operational Performance

Furnace exit gas temperature, or secondary superheater

inlet temperature, initially decreased by 100 oF but eventually rose to within 10 oF of baseline conditions.

The UBCL increased by approximately 28% for all

tests. The most significant increase from baseline data

occurred for a test with one mill out of service. A 52%

increase in UBCL resulted in an efficiency loss of 0.69%.

Boiler efficiency showed very little change from

baseline. The average for all mills in service increased by

0.16%. The higher post-retrofit efficiency was attributed

to a decrease in dry gas loss with lower economizer gas

Dayton Power and Light Company’s J.M. Stuart Plant hosted the successful

demonstration of LNCB® technology.

The LNCB® is viewed from within the boiler.

Environmental Performance

The initial LNCB® configuration resulted in excessive CO

and H2

S emissions. Through modeling, a revised configuration was developed to address the problem without

compromising boiler performance. The modification was

incorporated and validated model capabilities.

Following parametric testing to establish optimal

operating modes, a series of optimization tests were conducted 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 data accuracy. Consequently, the data provided is a range reflecting the two

measurements.

The average NOx

 emissions reduction achieved at

full load with all mills in service ranged from 53.0% to

55.5%. With one mill out of service at full load, the

average NOx

 reduction ranged from 53.3% to 54.5%.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-39

outlet temperature (and subsequent lower air heater gas

outlet temperature), offsetting UBCL and CO emission

losses. Also, increased coal fineness mitigated UBCL.

Because sulfidation is the primary corrosion mechanism in substoichiometric combustion of sulfur-containing coal, H2

S levels were monitored in the boiler. After

optimizing LNCB® operation, levels were largely at the

lower detection limit. There were some higher local

readings, but corrosion panel tests established that corrosion rates with LNCB® were roughly equivalent to preretrofit rates.

Ash sample analyses indicated that ash deposition

would not be a problem. The LNCB® ash was little different from baseline ash. Furthermore, the small variations observed in furnace exit gas temperature between

baseline and LNCB® indicated little change in furnace

slagging. Start-up and turndown of the unit were unaffected by conversion to LNCB®.

Economic Performance

The economic analyses were performed for a 600-MWe

nominal unit size and typical location in the midwest

United States. A medium-sulfur, medium-volatile bituminous coal was chosen as the typical fuel. For a

baseline NOx

 emission level of 1.2 lb/106 Btu and a 50%

reduction target, the estimated capital cost was $9/kW

(1994$). The levelized cost of electricity was estimated

at 0.284 mills/kWh or $96.48/ton of NOx

 removed.

Commercial Applications

The low cost and short outage time for retrofit make the

LNCB® design the most cost-effective NOx

 control technology available today for cell burner boilers. The

LNCB® system can be installed at about half the cost and

time of other commercial low-NOx

 burners. Dayton

Power & Light has retained the LNCB® for use in commercial service. There have been eight commercial sales

of LNCB®.

Contacts

Tony Yagiela, (216) 829-7403

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

John C. McDowell, FETC, (412) 892-6237

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-NOx

 Cell Burner Retrofit. Report No. DOE/PC/

90545-T4. The Babcock & Wilcox Company. August

1991. (Available from NTIS as DE92009768.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Full-Scale Demonstration of

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

Department of Energy. July 1990. (Available from

NTIS as DE90018026.)

The connections to the LNCB® are viewed from outside the boiler.
5-40 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Evaluation of Gas Reburning

and Low-NO

x

 Burners on a

Wall-Fired Boiler

Project completed.

Participant

Energy and Environmental Research Corporation

Additional Team Members

Public Service Company of Colorado—cofunder and host

Gas Research Institute—cofunder

Colorado Interstate Gas Company—cofunder

Electric Power Research Institute—cofunder

Foster Wheeler Energy Corp.—technology supplier

Location

Denver, Adams County, CO (Public Service Company of

Colorado’s Cherokee Station, Unit No. 3)

Technology

Energy and Environmental Research Corporation’s

gas-reburning (GR) system

Foster Wheeler Energy Corp.’s low-NOx

 burners (LNB)

Plant Capacity/Production

172 MWe

Coal

Western bituminous, 0.35–0.66% sulfur

Project Funding

Total project cost $17,807,258 100%

DOE 8,895,790 50

Participant 8,911,468 50

Project Objective

To attain up to a 70% decrease in the emissions of NOx

from an existing wall-fired utility boiler firing low-sulfur

coal using both gas reburning and low-NOx

 burners

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 1-year long-term testing program

was performed in order to judge the consistency of system

outputs, assess the impact of long-term operation on the

boiler equipment, gain experience in operating GR–LNB

in a normal load-following environment, and develop a

database for use in subsequent GR–LNB applications.

Both first- and second-generation gas-reburning tests were

performed.

(GR–LNB); and to assess the impact of GR–LNB on

boiler performance.

Technology/Project Description

Gas reburning involves firing natural gas (up to 25% of

total heat input) above the main coal combustion zone in

a boiler. This upper-level firing creates a slightly fuelrich zone. NOx

 drifting upward from the lower region of

the furnace is “reburned” 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 a reburning stage to wall-fired boilers

equipped with low-NOx

 burners was intended to lower

NOx

 emissions by up to 70%. Gas reburning was demonstrated with and without the use of recirculated flue

gas and with optimized overfire air.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-41

Results Summary

Environmental

• LNB alone achieved a 37% NOx

 reduction.

• First-generation GR, which incorporated flue gas

recirculation, in combination with LNB achieved a

65% NOx

 reduction at an 18% gas heat input rate.

• Second-generation GR, without flue gas recirculation,

in combination with LNB achieved 64% NOx

 reduction at 13% gas heat input.

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

capable of reducing NOx

 emissions by up to 70%.

• After modifying the overfire air system to enhance

penetration and turbulence (as part of second-generation GR), CO emissions were controlled to acceptable

levels at low gas heat input rates (5–10%).

• SO2

 emissions and particulate loadings were reduced

by the percentage heat input supplied by GR.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Operation

12/89

Design and Construction

10/90 10/92

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

Environmental monitoring plan completed 7/26/90

NEPA process completed (MTF) 9/6/90

Cooperative agreement awarded 10/13/90

Ground breaking/construction started 6/91

Design completed 8/91

Preoperational tests initiated 6/92

Construction completed 6/92

Operation initiated 10/92

Operational

• Boiler efficiency decreased by approximately 1.0%.

• There was no measurable boiler tube wear and only a

small amount of slagging.

Economic

• Capital cost for GR was approximately $15/kW

(1993$) plus the gas pipeline cost, if not in place, for

100-MWe plants or larger.

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

 emission allowances

(because GR reduces SO2

 emissions when displacing

coal).

Long-term operations started 4/93

Operation completed 1/95

Restoration

completed 11/95

Project Summary

The demonstration established that GR–LNB offers a

cost-effective option for deep NOx

 reduction on wall-fired

boilers. GR–LNB NOx

 control performance approached

that of selective catalytic reduction (SCR) but at significantly lower cost. SCR typically achieves 70–80% NOx

reduction at capital costs in the range of $100–$150/kW

for retrofit applications. GR–LNB achieved 60–70% NOx

reduction at a capital cost of approximately $35–$45/kW

(derived from GR capital cost of $15/kW according to the

demonstration and $20–30/kW for low-NOx

 burners

according to the literature). The importance of costeffective technology for deep NOx

 reduction is reflected

in ongoing deliberations on the need for NOx

 reduction in

ozone nonattainment areas beyond what is currently projected in Title IV of the CAAA. Title I of the CAAA

deals with ozone nonattainment and is currently the driving force for deep NOx

 reduction in many regions of the

country.

8/97

Project completed/final

report issued 8/97*
5-42 Program Update 1996-97 Environmental Control Devices

Environmental Performance

At a constant load (150 MWe) and a constant oxygen

level at the boiler exit, both NOx

 and SO2 emissions decreased when natural gas was introduced in the GR operation. In general, the NOx

 emissions were reduced with

increasing gas heat input. At gas heat inputs greater than

10%, NOx

 emissions were reduced marginally as gas heat

input increased. Natural gas also reduced SO2 emissions

in proportion to the gas heat input. At Cherokee Station,

low-sulfur (0.35–0.66%) coal was used, and typical SO2

emissions were 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 test

were to obtain operating data over an extended period

when the unit was under routine commercial service,

determine the effect of GR–LNB operation on the unit,

and obtain incremental maintenance and operating costs

with GR.

During long-term testing, it was determined that flue

gas recirculation had minimal effect on NOx

 emissions.

A second series of tests were added to the project 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, which

made greater use of available natural gas pressure.

(This modification reduced natural gas usage and thus

operating costs.)

• Overfire air ports were modified to provide higher jet

momentum, especially at low total flows.

Over 4,000 hours of operation were achieved, with

the results as shown in Exhibit 5-17.

Although the NOx

 reduction performance of LNB

(37% NOx

 reduction) was less than the expected 45%, the

overall objectives of the demonstration were met. Boiler

efficiency decreased by only 1% during gas reburning due

to increased moisture in 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.

Economic Performance

GR–LNB is a retrofit technology in which the costs are

dependent on the following site-specific factors:

• Gas availability at the site

• Gas/coal cost differential

• SO2 removal requirements

• Value of SO2 emission credits

Based on the demonstration, GR–LNB is expected to

achieve at least 60% NOx

 control with a gas heat input of

10–15%. The capital cost estimate for a 100-MWe or

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

(gross) wall-fired boiler—a balanced-draft pulverizedcoal unit supplied by Babcock & Wilcox. The GR system, including an overfire air system, was designed and

installed by Energy and Environmental Research Corporation. The LNBs were designed and installed by Foster

Wheeler Energy Corp.

Parametric testing was begun in October 1992 and

completed in April 1993. The parametric tests were

conducted by changing the process variables (such as

zone stoichiometric ratio, percent gas heat input, percent

overfire air, and load) and the effects of these variables on

NOx

 reduction, SO2 reduction, CO emissions, carbon-inash, and heat rates were analyzed. The baseline condition

of the LNB was also established.

GR Generation

First Second

Baseline (lb/106

 Btu) 0.73 0.73

Avg NOx

 reduction (%)

LNB 37 37

GR–LNB 65 64

Avg gas heat input (%) 18 13

Exhibit 5-17

NOx Data from Cherokee

Station, Unit 3

A worker inspects the support ring for the Foster

Wheeler low-NOx

 burner installed in the boiler wall.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-43

larger installation was about $15/kW (1993$) plus gas

pipeline costs, if required. Operating costs were almost

entirely related to the differential cost of natural gas and

coal as reduced by the value of the SO2

 emission credits

received due to absence of sulfur in the gas.

Commercial Applications

Public Service Company of Colorado, the host utility,

decided to retain the low-NOx

 burners and the gasreburning system for immediate use; however, a restoration was required to remove the flue gas recirculation

system.

Current estimates indicate that about 35 existing

wall-fired utility installations, plus industrial boilers,

could make immediate use of this technology. The technology can be used in retrofit, repowering, or greenfield

installations. There is no known limit to the size or scope

of the application of this technology combination.

GR–LNB is expected to be less capital intensive, or

less costly, than a scrubber, selective catalytic reduction,

or other technologies. GR–LNB functions equally well

with any kind of coal.

Contacts

Blair A. Folsom, Senior Vice President, (714) 859-8851

Energy and Environmental Research Corporation

18 Mason

Irvine CA 92718

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

Jerry L. Hebb, FETC, (412) 892-6079

References

• Evaluation of Gas Reburning and Low NOx Burners on

a Wall-Fired Boiler (Long-Term Testing, April 1993–

January 1995). Report No. DOE/PC/90547-T20.

Energy and Environmental Research Corporation.

June 1995. (Available from NTIS as DE95017755.)

• 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.)

• Reduction of NOx and SO2

 Using Gas Reburning,

Sorbent Injection and Integrated Technologies. Topical Report No. 3, Revision 1. U.S. Department of

Energy and Energy and Environmental Research Corporation. September 1993. (Available from NTIS as

DE94007444.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Evaluation of Gas Reburning

and 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.)

The Public Service Company of Colorado has retained the

gas-reburning and low-NOx

 burner system for commercial use.
5-44 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Micronized Coal Reburning

Demonstration for NO

x

 Control

Participant

New York State Electric & Gas Corporation

Additional Team Members

Eastman Kodak Company—host and cofunder

Consolidation Coal Company— tester

D.B. Riley—technology supplier

Fuller Company—technology supplier

Energy and Environmental Research Corporation—reburn

system designer

ABB Combustion Engineering, Inc.—technology supplier

Locations

Lansing, Tompkins County, NY (New York State Electric

& Gas Corporation’s Milliken Station, Unit 1)

Rochester, Monroe County, NY (Eastman Kodak

Company’s Utility Power House, Unit 15)

Technology

ABB Combustion Engineering’s Low-NOx

 Concentric

Firing System (LNCFSTM)

D.B. Riley’s MPS mill (at Milliken Station)

Fuller’s MicroMillTM technologies for producing

micronized coal (at Eastman Kodak)

Plant Capacity/Production

Milliken Station: 148-MWe tangentially fired boiler

Eastman Kodak Company: 50-MWe cyclone boiler

Project Funding

Total project cost $9,096,486 100%

DOE 2,701,011 30

Participant 6,395,475 70

MicroMill is a trademark of the Fuller Company.

LNCFS is a trademark of ABB Combustion Engineering, Inc.

Project Objective

To reduce NOx

 emissions by 50–60% using micronized

coal as the reburning fuel combined with advanced coalreburning technology.

Technology/Project Description

The reburning coal, which can comprise up to 30% of the

total fuel, is micronized (80% below 325 mesh) and

injected into a pulverized-coal-fired furnace above the

main burner, the region where NOx

 formation occurs.

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 heat rate, carbon

loss, boiler efficiency, and NOx

 formation are affected by

coal fineness.

The combination of micronized coal, supplying 30%

of the total furnace fuel requirements, and advanced

reburning, utilizing that requirement in conjunction with

fuel/air staging, provides flexible options for significant

combustion operations and environmental improvements.

These options can prevent higher operating costs or furnace performance derating often associated with conventional environmental controls.

At the Milliken site, coal will be reburned for NOx

control using the following methods: (1) close-coupled

overfire air (CCOFA) reburning in which the top burner

of the existing LNCFSTM burners are used for burning the

micronized coal and the remaining burners are re-aimed,

(2) use of the burners in a deep stage combustion mode
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-45

3/97

Commercial Applications

Micronized-coal-reburning technology can be applied to

existing and greenfield cyclone-fired, wall-fired, and

tangential-fired pulverized coal units. The technology

reduces NOx

 emissions by 50–60% with minimal furnace

modifications for existing units. For greenfield units, the

technology can be designed as an integral part of the

system. Either way, the technology enhances boiler performance with the improved burning characteristics of

micronized coal. About 25% of the more than 1,000

existing units could benefit from use of this technology.

The availability of a coal-reburning fuel, as an

additional fuel to the furnace, solves several problems

concurrently. Existing units unable to switch fuels

because of limited mill and burner capacity would be able

to reach their maximum continuous rating. NOx

 emissions reductions will enable lost capacity to be restored,

creating a very economic source of generation. For both

retrofit and greenfield facilities, reburn burners also can

serve as low-load burners, and commercial units can

achieve a turndown of 8:1 on nights and weekends

without consuming expensive auxiliary fuel. Existing

pulverizers can be operated on a variety of coals with

improved performance. The combination of micronizedcoal-reburning fuel and better pulverizer performance will

increase overall pulverized-fuel surface area for better

carbon burnout.

This demonstration will provide methods for NOx

control at a low capital cost for utilities and industrial

users to meet the current and upcoming NOx regulations.

Utilities that install low-NOx burners to meet CAAA

Title I requirements and must also meet Title IV requirements will have a low-cost option. Industrial users being

pressured by states to reduce NOx also will be provided a

low-cost option, particularly cyclone boiler users who

have been without low-NOx burners.

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

9/91 7/92

DOE selected

project (CCT-IV)

9/12/91

Design and Construction Operation

4/99

Operation completed (Lansing) 11/98*

Operation completed (Rochester) 3/98*

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

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

Design completed (Rochester) 9/96

NEPA process completed

(CX) 8/13/92

Cooperative agreement awarded 7/28/92

Preoperational tests initiated (Rochester) 1/97

Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

and re-aiming them to create burn and reburn zones, and

(3) a more standard method using injectors to input micronized coal into the boiler. At the Eastman Kodak site,

the Fuller MicroMillTM will be used to produce the micronized coal, and injectors or burners, depending on

boiler characteristics, will be used for the reburning.

Overfire air also will be installed. Both the injectors/

burners and the overfire air will be installed at the optimal point downstream of the cyclone burners.

Project Status/Accomplishments

Construction at the Kodak site in Rochester continued

into 1997. Operational testing began in April 1997 and

will continue into March 1998.

Preoperational testing of the reburn system at

Milliken Station near Lansing began in March 1997. In

late 1997, testing of CCOFA reburning at Milliken will

be completed, and injector reburn testing will begin.

Reburn testing at Milliken is scheduled to be completed

in late 1998.

Project completed/final report issued 4/99*

Operation initiated (Rochester) 4/97

Environmental monitoring plan completed (Lansing) 8/97*

Environmental monitoring plan completed (Rochester) 8/97*

Construction completed (Lansing) 10/97*

Operation initiated (Lansing) 3/97
5-46 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Demonstration of Advanced

Combustion Techniques for a

Wall-Fired Boiler

Participant

Southern Company Services, Inc.

Additional Team Members

Electric Power Research Institute—cofunder

Foster Wheeler Energy Corporation—technology

supplier

Georgia Power Company—host

Location

Coosa, Floyd County, GA (Georgia Power Company’s

Plant Hammond, Unit No. 4)

Technology

Foster Wheeler’s low-NOx

 burner (LNB) with advanced

overfire air (AOFA)

EPRI’s Generic NOx

 Control Intelligence System

(GNOCIS) for plant optimization

Plant Capacity/Production

500 MWe

Project Funding

Total project cost $15,853,900 100%

DOE 6,553,526 41

Participant 9,300,374 59

(Of the total project cost, $523,680 is for toxics

testing.)

Project Objective

To achieve 50% NOx

 reduction with the AOFA/LNB

system; to determine the contributions of AOFA and the

LNB to NOx

 reduction and the parameters determining

optimal AOFA/LNB system performance; and to assess

the long-term effects of AOFA, LNB, and combined

AOFA/LNB and advanced digital controls on NOx reduction and boiler performance.

Technology/Project Description

AOFA involves (1) improving the mixing of overfire air

with the furnace gases to achieve complete combustion,

(2) depleting the air from the burner zone to minimize

NOx

 formation, and (3) supplying air over furnace wall

tube surfaces to prevent slagging and furnace corrosion.

The AOFA technique was expected to reduce NOx

 emissions by about 35%.

In an LNB, fuel and air mixing is controlled to

preclude the formation of NOx

. This is accomplished by

regulating the initial fuel-air mixture, velocities, and

turbulence to create a fuel-rich flame core and by controlling the rate at which additional air required to complete combustion is mixed with the flame solids and

gases so as to maintain a deficiency of oxygen. Typical

results for utilities indicate that LNB technology is capable of reducing NOx

 emissions by about 45%.

Based on earlier experience, the use of AOFA in

conjunction with LNB can reduce NOx

 emissions by as

much as 65% compared with conventional burners.

The demonstration is located at the Georgia Power

Company’s Plant Hammond, Unit No. 4. The boiler is a

nominal 500-MWe pulverized coal, opposed wall-fired

unit, which is representative of many existing pre-NSPS

wall-fired utility boilers in the United States. The project

also includes installation and testing of an advanced

digital control system that optimizes LNB/AOFA performance using artificial intelligence techniques. The

project is using bituminous coal containing 3% sulfur.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-47

Project Status/Accomplishments

Baseline, AOFA, LNB, and LNB/AOFA test segments

have been completed. Analysis of more than 80 days of

AOFA operating data has provided statistically reliable

results indicating that, depending upon load, NOx

 reductions of 24% are achievable under normal long-term operation. Analysis of the 94 days of LNB long-term data

collected show the full-load NOx

 emission levels to be

approximately 0.65 lb/106

 Btu. This NOx level represents

a 48% reduction when compared to the baseline, full-load

value of 1.23 lb/106

 Btu. These reductions were sustainable over the long-term test period and were consistent

over the entire load range. Full-load, flyash loss-onignition (LOI) values in the LNB configuration were near

8%, compared to 5% for baseline. Results from

LNB/AOFA testing indicate that full-load NOx

 emissions

were approximately 0.41 lb/106

 Btu with a corresponding

flyash loss-on-ignition value of nearly 8%. Full-load,

long-term NOx

 emission reductions in the LNB/AOFA

configuration were about 63%. However, analysis of

emissions data showed that the incremental NOx

 reduction

effectiveness of the AOFA system (beyond the use of the

LNB) was approximately 17% with additional reductions

resulting from other operational changes.

GNOCIS testing for optimizing NOx

 reduction and

boiler efficiency began in February 1996. Although narrow parameters were placed on the recommendations that

GNOCIS could provide, preliminary data analysis is encouraging, with an observed efficiency gain of 0.5%, a

reduction in LOI levels of 1–3%, and a reduction in NOx

emissions by 10–15% at full load. Short-term testing of

the GNOCIS, in both open- and closed-loop configurations, and long-term closed-loop testing were planned for

early fall 1996; however, low dispatch priority and problems with the unit have impacted GNOCIS testing. The

final project report and a report on testing of several online carbon-in-ash monitors are being prepared.

Pre-retrofit LNB air toxics testing was performed

to establish a baseline. Additional air toxics testing

with the combined LNB/AOFA configuration has been

completed. A report was issued in December 1993.

Commercial Applications

The technology is applicable to the 422 existing preNSPS wall-fired boilers; these boilers burn a variety of

coals. The GNOCIS technology is applicable to all fossilfuel-fired boilers.

Based on the success of GNOCIS at Georgia Power’s

Plant Hammond and the early demonstrations at

PowerGen’s Kingsnorth 1 and Alabama Power’s Gaston

4, Southern Company has installed GNOCIS software in

six other power plants, including several of its own units,

i.e., Georgia Power’s Branch 3 and Wansley 1 and Alabama Power’s Gaston 3. The three other installations

include Duquesne Light & Power’s Cheswick unit,

Entergy’s Nelson Unit 4, and PowerGen’s Kingsnorth 3.

Of the 9 current installations, 5 units burn coal; 1, gas;

2, a combination of coal and gas; and 1, a combination of

coal and oil. The units encompass a wide variety of

boiler types and all major U.S. vendors. A total of

20 installations is anticipated by year-end 1997, including

several in foreign countries.

Preaward

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

9/88 12/89 6/90

Design and Construction

DOE selected

project (CCT-II)

9/28/88

Cooperative agreement awarded 12/20/89

Design completed 3/90

Construction started, AOFA 4/90

Construction completed, AOFA 5/90

Operation initiated, AOFA 6/90

Environmental monitoring plan completed 9/14/90

Construction started, LNB 3/91

Operation completed, AOFA 3/91

Operation initiated, LNB 4/91

Construction completed, LNB 4/91

NEPA process

completed (MTF)

5/22/89 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

9/97

Project completed/final report

issued 9/97*

GNOCIS testing initiated 2/96
5-48 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Demonstration of Selective

Catalytic Reduction

Technology for the Control of

NO

x

 Emissions from HighSulfur-Coal-Fired Boilers

Project completed.

Participant

Southern Company Services, Inc.

Additional Team Members

Electric Power Research Institute—cofunder

Ontario Hydro—cofunder

Gulf Power Company—host

Location

Pensacola, Escambia County, FL (Gulf Power Company’s

Plant Crist, Unit 4)

Technology

Selective catalytic reduction (SCR)

Plant Capacity/Production

8.7-MWe equivalent (three 2.5-MWe and six 0.2-MWe

equivalent SCR reactor plants)

Coal

Illinois bituminous, 2.7% sulfur

Project Funding

Total project cost $23,229,729 100%

DOE 9,406,673 40

Participant 13,823,056 60

Project Objective

To evaluate the performance of commercially available

SCR catalysts when applied to operating conditions found

in U.S. pulverized coal-fired utility boilers using highsulfur U.S. coal under various operating conditions while

achieving as much as 80% NOx

 removal.

Technology/Project Description

The SCR technology consists of injecting ammonia into

boiler flue gas and passing it through a catalyst bed

where the NOx

 and ammonia react to form nitrogen and

water vapor.

In this demonstration project, the SCR facility consisted of three 2.5-MWe-equivalent SCR reactors, supplied by separate 5,000 std ft3

/min flue gas slipstreams,

and six 0.20-MWe-equivalent SCR reactors. These reactors were calculated to be large enough to produce design

data that will allow the SCR process to be scaled up to

commercial size. Catalyst suppliers (two U.S., two European, and two Japanese) provided eight catalysts with

various shapes and chemical compositions for evaluation

of process chemistry and economics of operation during

the demonstration.

The project demonstrated, at high- and low-dust

loadings of flue gas, the applicability of SCR technology

to 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, utilized

flue gas from the burning of 2.7% sulfur coal under various NOx

 and particulate levels.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-49

Results Summary

Environmental

• NOx

 reductions of over 80% were achieved at an ammonia slip well under the 5 ppm acceptable for commercial operation.

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

at 80% NOx

 reduction.

• While catalyst performance increased above 700 oF,

the benefit did not outweigh the heat rate penalties.

• The increase for ammonia slip, a sign of catalyst deactivation, went from less than 1 ppm to approximately

3 ppm over 12,000 hours of operation, thus demonstrating deactivation in coal-fired units was in line

with worldwide experience.

• SO2

 oxidation was within or below the design limits

necessary to protect downstream equipment.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward

9/88

Design and Construction Operation

6/90

DOE selected project

(CCT-II) 9/28/88

NEPA process

completed

(MTF) 8/16/89

Cooperative agreement

awarded 6/14/90

Ground breaking/construction started 3/92

7/93

Preoperational tests initiated 3/93

Environmental monitoring plan completed 3/11/93

Construction completed 2/93

Design completed 12/92

11/96

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, performance 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

baskets to match predetermined reactor dimensions, provide a maximum of four catalyst layers, and meet the

following reactor baseline conditions:

Operation initiated 7/93

Operation completed 7/95

Project completed/final

report issued 11/96

40% 60% 80%

1996 levelized cost (mills/kWh) 2.39 2.57 2.79

1996 levelized cost ($/ton) 3,502 2,500 2,036

Operational

• Fouling of catalysts was controlled by adequate

sootblowing procedures.

• Catalyst erosion was not considered to be a problem.

• Air preheater performance was degraded because of

ammonia slip and subsequent by-product formation;

however, problem solutions were identified.

• The SCR process does not significantly affect the

results 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: Parameter Minimum Baseline Maximum

Temperature (o

F) 620 700 750

NH3/NOx molar ratio 0.6 0.8 1.0

Space velocity

(1% design flow) 60 100 150

Flow rate (std ft3/min)

 Large reactor 3,000 5,000 7,500

 Small reactor 240 400 600
5-50 Program Update 1996-97 Environmental Control Devices

The catalysts tested are listed in Exhibit 5-18. Catalyst suppliers were given great latitude in providing the

amount of catalyst for this demonstration.

Environmental Results

Ammonia slip, the controlling factor in the long-term

operation of commercial SCR, was usually <5 ppm because of plant and operational considerations. Ammonia

slip was dependent on catalyst exposure time, flow rate,

temperature, NH3

/NOx distribution, and NH3/NOx ratio

(NOx

 reduction). Changes in NH3/NOx ratio and consequently NOx

 reduction generally produced the most significant changes in ammonia slip. The ammonia slip at

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

1 ppm. As NOx

 reduction was increased above 80%,

ammonia slip also increased and remained at reasonable

levels up to NOx reductions of 90%. Over 90%, the ammonia slip levels increased dramatically.

The flow rate and temperature effects on NOx

 reduction were also measured. In general, flows could be

increased to 150% of design without the ammonia slip

exceeding 5 ppm at 80% NOx

 reduction and design temperature. With respect to temperature, most catalysts

exhibited fairly significant improvements

in overall performance as temperatures

increased from 620 °F to 700 °F but relatively little improvement as temperature

increased from 700 °F to 750 °F. The

conclusion was that the benefits of hightemperature operation probably do not

outweigh the heat rate penalties involved

in operating SCR at the higher temperatures.

Catalyst deactivation was generally

observed by an increase in ammonia slip

over time, assuming the NOx

 reduction

efficiency was held constant. Over the

12,000 hours of the demonstration tests,

the ammonia slip did, in fact, increase from

less than 1 ppm to approximately 3 ppm.

These results demonstrated the maturity of

catalyst design and that deactivation was in line with prior

worldwide experience.

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 5-19. These data reflect baseline conditions over the life of the demonstration. All of the catalysts were within design limits, with most exhibiting

oxidation rates below the design limit. Other factors

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, measurements

showed the relationship to be linear with little difference in SO2 oxidation between 620 oF and 700 oF.

However, between 700 °F and 750 °F, the SO2

 oxidation increased more significantly.

Other Findings

• Pressure Drop. Overall reactor pressure drop was a

function of the catalyst geometry and volume, but tests

to determine which one was controlling were inconclusive.

• Fouling. The fouling characteristics of the catalyst

were important to long-term operation. During the

demonstration, measurements showed relatively level

pressure drop over time, indicating that sootblowing

procedures were effective. The plate-type configurations had somewhat less fouling potential than did the

honeycomb configuration, but both were acceptable

for application.

• Erosion. Catalyst erosion was not considered to be a

significant problem because most of the erosion was

Exhibit 5-18

Catalysts Tested

Catalyst Reactor Size* Catalyst Configuration

Nippon/Shokubai Large Honeycomb

Siemens AG Large Plate

W.R. Grace/Noxeram Large Honeycomb

W.R. Grace/Synox Small Honeycomb

Haldor Topsoe Small Plate

Hitachi/Zosen Small Plate

Cormetech/High dust Small Honeycomb

Cormetech/Low dust Small Honeycomb

* Large = 2.5 MWe; 5,000 std ft3/min Small = 0.2 MWe; 400 std ft3/min

Exhibit 5-19

Avg SO2 Oxidation Rate

(Baseline)

Average SO2 Oxidation (%)

NH3

/NOx = 0.8, 700 oF, design flow
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-51

attributed to aggressive sootblowing.

• Air Preheater Performance. The demonstration

showed that the SCR process exacerbated performance

degradation of the air preheaters mainly due to ammonia slip and subsequent by-product formation. Regenerator-type air heaters outperformed recuperators in

SCR applications in terms of both thermal performance and fouling.

• Ammonia Volatilization. The ammonia volatilized

from the SCR flyash when a significant amount of

water was absorbed by the ash. This was caused by

the formation of a moist layer on the ash with a pH

high enough to convert the ammonia compounds in the

ash to gas-phase ammonia.

• Toxicity-Characteristic-Leaching-Procedure

(TCLP) Analysis. TCLP analyses were performed on

flyash samples. The SCR process did not significantly

affect the toxics leachability of the fly ash.

Economic Results

An economic evaluation was performed for full-scale

applications of SCR technology to a new 250-MWe pulverized coal-fired plant located in a rural area with minimal space limitations. The fuel considered was highsulfur Illinois No. 6 coal. Other key base case design

criteria are shown in Exhibit 5-20.

Results of the economic analysis of capital, operating and maintenance (O&M), and levelized cost based on

a 30-year project life for various unit sizes for an SCR

system with a NOx

 removal efficiency 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 of inlet NOx

/106 Btu

follow:

For retrofit applications, the estimated capital costs

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

levelized costs for the retrofit applications were

$1,850–5,100/ton (current $).

Commercial Applications

As a result of this demonstration, SCR technology has

been shown to be applicable to existing and new utility

generating capacity for removal of NOx

 from the flue gas

of virtually any size boiler. There are approximately

1,041 coal-fired utility boilers in active commercial service in the United States; these boilers represent a total

generating capacity of 296,000 MWe.

Contacts

Robert R. Hardman, (205) 257-7772

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

Arthur L. Baldwin, FETC, (412) 892-6011

References

• 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 Company

Services. October 1996. (Appendixes in Vol. 2–3.)

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

125 MWe 250 MWe 700 MWe Services. September 1996.

Capital cost ($/kW) 61 54 45

Operating cost ($) 580,000 1,045,000 2,667,000

1996 levelized cost

mills/kWh 2.89 2.57 2.22

$/ton 2,811 2,500 2,165

Exhibit 5-20

Design Criteria

Parameter Specification

Type of SCR Hot side

Number of reactors One

Reactor configuration 3 catalyst support layers

Initial catalyst load 2 of 3 layers loaded

Range of operation 35–100% boiler load

NOx

 inlet concentration 0.35 lb/106 Btu

Design NOx

 reduction 60%

Design ammonia slip 5 ppm

Catalyst life 16,000 hr

Ammonia cost $250/ton

SCR cost $400/ft3

40% 60% 80%

Capital cost ($/kW) 52 54 57

Operating costs ($) 926,000 1,045,000 1,181,000

1996 levelized cost

mill/kWh 2.39 2.57 2.79

$/ton 3,502 2,500 2,036
5-52 Program Update 1996-97 Environmental Control Devices

Project Objective

To demonstrate in a stepwise fashion the short- and

long-term NOx

 reduction capabilities of Low-NOx Concentric Firing System levels I, II, and III on a single

reference boiler.

Technology/Project Description

Technologies demonstrated included the Low-NOx

 Concentric Firing System (LNCFSTM), levels I, II, and III.

Each level of the LNCFSTM used different combinations

of overfire air and clustered coal nozzle positioning to

achieve NOx

 reductions. With the LNCFSTM, primary air

and coal are surrounded by oxygen-rich secondary air

that blankets the outer regions of the combustion zone.

LNCFSTM I used a close-coupled overfire air (CCOFA)

system integrated directly into the windbox of the boiler.

A separated overfire air (SOFA) system located above

Environmental Control Devices

NOx Control Technologies

180-MWe Demonstration of

Advanced Tangentially Fired

Combustion Techniques for the

Reduction of NOx Emissions

from Coal-Fired Boilers

Project completed.

Participant

Southern Company Services, Inc.

Additional Team Members

Gulf Power Company—cofunder and host

Electric Power Research Institute—cofunder

ABB Combustion Engineering, Inc.—cofunder and technology supplier

Location

Lynn Haven, Bay County, FL (Gulf Power Company’s

Plant Lansing Smith, Unit No. 2)

Technology

ABB Combustion Engineering’s Low-NOx

 Concentric

Firing System (LNCFSTM) with advanced overfire air

(AOFA), clustered coal nozzles, and offset air

Plant Capacity/Production

180 MWe

Coal

Eastern bituminous, high reactivity

Project Funding

Total project cost $9,153,383 100%

DOE 4,440,184 49

Participant 4,713,199 51

LNCFS is a trademark of ABB Combustion Engineering, Inc.

the combustion zone was featured in the LNCFSTM II

system. This was an advanced overfire air system that

incorporates back pressuring and flow measurement

capabilities. CCOFA and SOFA were both used in the

LNCFSTM III tangential-firing approach.

Carefully controlled short-term tests were conducted

followed by long-term testing under normal load dispatch

conditions. Long-term tests, which typically lasted 2–3

months for each phase, best represent the true emissions

characteristics of each technology. Results presented are

based on long-term test data.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-53

Results Summary

Environmental

• At full load, the NOx

 emissions using LNCFSTM I, II,

and III were 0.39, 0.39, and 0.34 lb/106

 Btu, respectively, which represent reductions of 37%, 37%, and

45% from the baseline emissions.

• Emissions with LNCFSTM were not sensitive to power

outputs between 100- and 200-MWe, but emissions

increased significantly below 100 MWe, reaching

baseline emission levels at 70 MWe.

• Because of reduced effectiveness at low loads,

LNCFSTM proved marginal as a compliance option for

peaking load conditions.

• Average CO emissions increased at full load.

• Air toxics testing found LNCFSTM to have no clear-cut

effect on the emissions of trace metals or acid gases.

Volatile organic compounds (VOCs) appeared to be

reduced and semi-volatile compounds increased.

Operational

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

LNCFSTM retrofits but very sensitive to coal fineness.

• Furnace slagging was reduced but 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 low

loads with LNCFSTM II and III.

Economic

• The capital cost estimate for LNCFSTM I was

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

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

NOx

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

III, $400/ton.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Operation

9/88 9/90

Design and Construction

Project completed/final report issued 6/94

6/94

Environmental monitoring

plan completed 12/27/90

Ground breaking/construction started 11/90

Design completed 4/91

Operation initiated 5/91

Construction

completed 5/91 Operation completed 12/92

Project Summary

At the time of the demonstration, specific NOx emission

regulations were being formulated under the CAAA. The

data developed over the course of this project provided

needed real-time input to regulation development.

LNCFSTM technology was designed for tangentially

fired boilers, which represent a large percentage of the

pre-NSPS coal-fired generating capacity. The technology

reduces NOx

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

by creating fuel-rich and lean zones with offset air

nozzles. The objective was to determine NOx

 emission

reductions and impact on boiler performance over the

long-term under normal dispatch and operating conditions. By using the same boiler, the demonstration provided direct comparative performance analysis of the

three configurations. Short-term parametric testing enabled extrapolation of results to other tangentially fired

units by evaluating the relationship between NOx

 emissions and key operating parameters.

NEPA process

completed (MTF)

7/21/89

DOE selected

project

(CCT-II)

9/28/88

Cooperative agreement awarded 9/20/90

5/91
5-54 Program Update 1996-97 Environmental Control Devices

 Exhibit 5-21 shows the various LNCFSTM configurations used to achieve staged combustion. In addition to

overfire air, as shown in Exhibit 5-22, the LNCFSTM

incorporates other NOx

-reducing techniques into the

combustion process. Using offset air, two concentric

circular combustion regions are formed. The majority of

the coal is contained in the fuel-rich inner region. This

region is surrounded by a fuel-lean zone containing combustion air. The size of this outer annulus of combustion

air can be varied using adjustable offset air nozzles.

Operational Performance

Exhibit 5-23 summarizes the impacts of LNCFSTM on

unit performance.

Economic Performance

LNCFSTM II was the only complete retrofit (LNCFSTM I

and III were modifications of LNCFSTM II), and therefore

capital cost estimates were based on the Lansing Smith

Unit No. 2 retrofit as well as other tangentially fired

LNCFSTM retrofits. The capital cost ranges 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 recent

experience and are planning estimates. The actual capital

cost for LNCFSTM II at Lansing Smith Unit No. 2 was $3

million, or $17/ kW, which falls within the projected

range.

The cost effectiveness of the LNCFSTM technologies

is based on the capital and operating and maintenance

costs and the NOx

 removal efficiency of the technologies.

The cost effectiveness of the LNCFSTM technologies is

listed below (based on a levilization factor of 0.144):

• LNCFSTM I—$103/ton of NOx

 removed

• LNCFSTM II—$444/ton of NOx

 removed

• LNCFSTM III—$400/ton of NOx

 removed

Commercial Applications

LNCFSTM technology has been adopted by eight other

utilities in eight separate retrofits over a range of capacities. Further, potential commercial applications of this

technology include nearly 600 U.S. pulverized coal, tangentially fired utility units. These units are 25–950 MWe

in size and fire a wide range of coals, from low-volatile

bituminous through lignite.

Exhibit 5-22

Concentric Firing Concept

Exhibit 5-21

LNCFSTM Configurations

Environmental Performance

At full load, LNCFSTM I, II, and III reduced NOx

 emissions by 37%, 37%, and 45%, respectively.

Exhibit 5-24 presents the NOx

 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 decreased

emission of chromium. The effect on aldehydes/ketones

could not be assessed because baseline data were compromised. VOCs appeared to be reduced and semi-volatile

compounds increased. The increase in semi-volatile

compounds was deemed to be consistent with increases in

the amount of unburned carbon in the ash.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-55

Contacts

Robert R. Hardman, Project Manager, (205) 877-7772

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

Scott M. Smouse, FETC, (412) 892-5725

References

• 180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx

) Emissions from Coal-Fired

Boilers: Final Report and Key Project Findings.

Report No. DOE/PC/89653-T14. Southern Company

Services, Inc. February 1994. (Available from NTIS

as DE94011174.)

• 180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx

) Emissions from Coal-Fired

Boilers—Plant Lansing Smith—Phase III and Final

Environmental Monitoring Program Report. Southern

Company Services, Inc. December 1993.

• 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 as

DE94005038.)

• 180-MW Demonstration of Advanced Tangentially

Fired 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.)

Exhibit 5-23

Unit Performance Impacts Based on Long-Term Testing

Baseline LNCFSTM I LNCFSTM II LNCFSTM III

Avg CO at full load (ppm) 10 12 22 33

Avg excess O2 at full load (%) 3.7 3.2 4.5 4.3

LOI at full load (%) 4.8 4.6 4.2 5.9

O2 (%) 4.0 3.9 5.3 4.7

Steam outlet conditions Satisfactory at full Full load: 5–10 o

F Same as baseline 160–200 MWe: OK

load; 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

Furnace slagging and Medium Medium Reduced slagging, Reduced slagging,

backpass fouling but increased fouling but increased fouling

Operating flexibility Normal Same as baseline More care required More difficult to

at low loads operate than other

systems

Boiler efficiency (%) 90 90.2 89.7 89.85

Efficiency change N/A +0.2 -0.3 -0.15

Turbine heat rate (Btu/kWh) 9,000 9,011 9,000 9,000

Unit net heat rate (Btu/kWh) 9,995 9,986 10,031 10,013

Change (%) N/A -0.1 +0.36 +0.18

Exhibit 5-24

Average Annual NOx Emissions and % Reduction

Boiler Duty Cycle Units Baseline LNCFSTM I LNCFSTM II LNCFSTM III

Baseload Avg NOx

 emissions (lb/106 Btu) 0.62 0.41 0.41 0.36

(161.8 MWe avg) Avg reduction (%) 38.7 38.7 42.2

Intermediate load Avg NOx emissions (lb/106 Btu) 0.62 0.40 0.41 0.34

(146.6 MWe avg) Avg reduction (%) 39.2 35.9 45.3

Peaking load Avg NOx emissions (lb/106 Btu) 0.59 0.45 0.47 0.43

(101.8 MWe avg) Avg reduction (%) 36.1 20.3 28.0
5-56 Program Update 1996-97 Environmental Control Devices

Combined SO2/NOx Control

Technology

Combined SO2/NOx control systems encompass

those technologies that combine previously described control methods and those that apply other,

synergistic techniques. Three of the projects

combine either LNBs or gas reburning with sorbent

injection. In one of these, SNCR is used with LNBs to

enhance performance. Another project combines a

number of techniques to improve overall system

performance, such as LNBs with SNCR, unique

space-saving and durable wet-scrubber design,

sorbent additive, and artificial intelligence controls.

The balance of the seven projects use synergistic

methods not previously described.

SOx-NOx-Rox BoxTM incorporates an SCR

catalyst in a high-temperature filter bag for NOx

control and applies sorbent injection for SO2 control.

The high-temperature filter bag, operated in a

standard pulsed jet baghouse, protects the SCR

catalyst, allows operation at optimal NOx control

temperatures, forms a sorbent cake on the surface to

enhance SO2 capture, and provides high-efficiency

particulate capture.

SNOXTM uses SCR followed by catalytic

oxidation of SO2 to SO3 with condensation of the SO3

in the presence of water to produce sulfuric acid.

Following the SCR with the catalytic oxidation allows

the SCR to operate at optimal ammonia concentration

without worry of ammonia slip (ammonia passing to

the second catalyst is broken down). Furthermore,

most particulates passing through the upstream

baghouse are captured in the sulfuric acid condensing unit. The system produces no solid waste.

NOXSO uses a single, regenerable adsorber

(spherical alumina beads impregnated with sodium

carbonate) to capture both SO2 and NOx. The adsorber

is used in a fluidized bed to achieve effective mixing

with the flue gas. The flue gas is then processed

through a regenerator system to release the NOx

 and

SO2 before return to the fluidized bed.

Five of the seven combined SO2/NOx control

technology projects have been completed, one is in

operation, and one is in the project definition and

design phase. Exhibit 5-25 briefly summarizes the

characteristics and performance of the technologies

that are described in more detail in the project fact

sheets.

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

SO2

 and NOx control technologies.
Environmental Control Devices Program Update 1996-97 5-57

Exhibit 5-25

CCT Program Combined SO2/NOx Control Technology Characteristics

Coal Sulfur SO2/NOx Fact

Project Process Content Reduction Sheet

LIMB Demonstration Project Extension and LNB/sorbent injection—furnace and duct injection, calcium-based 1.6–3.8% 60–70%/40–50% 5-62

Coolside Demonstration sorbents

Integrated Dry NOx

/SO2 Emissions LNB/SNCR/sorbent injection—calcium- and sodium-based 0.4% 70%/62–80% 5-78

Control System sorbents used in duct injection

Enhancing the Use of Coals by Gas Reburning Gas reburning/sorbent injection—calcium-based sorbents used in 3.0% 50–60%/67% 5-70

and Sorbent Injection duct injection

Milliken Clean Coal Technology Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5–4.0% 95%/53–58% (goal) 5-74

Project durable scrubber design

SOx

-NOx-Rox BoxTM Flue Gas Cleanup SCR/high temperature baghouse/sorbent injection—SCR in high- 3.4% 80–90%/90% 5-66

Demonstration Project temperature filter bag and calcium-based sorbent injection

SNOXTM Flue Gas Cleaning Demonstration SCR/oxidation catalyst/sulfuric acid condenser—synergistic 3.4% 95%/94% 5-58

Project catalyst effect and no solid waste

Commercial Demonstration of the NOXSO Regenerable adsorbent—spherical alumina beads impregnated 3.4% 98% (goal)/75% (goal) 5-76

SO2

/NOx Removal Flue Gas Cleanup System with sodium carbonate in fluidized-bed adsorber (planned)
5-58 Program Update 1996-97 Environmental Control Devices

Technology/Project Description

In the SNOXTM process, the stack gas leaving the boiler is

cleaned of fly ash in a high-efficiency fabric filter

baghouse 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 reactors

where the NOx

 is converted to harmless nitrogen and

water vapor. The SO2

 is oxidized to SO3 in a second

catalytic converter. The gas then passes through a novel

glass-tube condenser that allows SO3

 to hydrolyze to

concentrated sulfuric acid.

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

the NOx

 from flue gas and produce a salable sulfuric acid

by-product. This was accomplished without using sorbents and without creating waste by-products.

The demonstration was conducted at Ohio Edison’s

Niles Station in Niles, OH. The demonstration unit

treated a 35-MWe equivalent slipstream of flue gas from

the 108-MWe Unit No. 2 boiler, which burned a 3.4%

sulfur Ohio coal. The process steps were virtually the

same as for a commercial full-scale plant, and commercial-scale components were installed and operated.

Environmental Control Devices

Combined SO2 /NOx Control Technologies

SNOXTM Flue Gas Cleaning

Demonstration Project

Project completed.

Participant

ABB Environmental Systems

Additional Team Members

Ohio Coal Development Office—cofunder

Ohio Edison Company—cofunder and host

Haldor Topsoe a/s—patent owner for process technology,

catalysts, and WSA Tower

Snamprogetti, U.S.A.—cofunder and process designer

Location

Niles, Trumbull County, OH (Ohio Edison’s Niles

Station, Unit No. 2)

Technology

Haldor Topsoe’s SNOXTM catalytic advanced flue gas

cleanup system

Plant Capacity/Production

35-MWe equivalent slipstream from a 108-MWe boiler

Coal

Ohio bituminous, 3.4% sulfur

Project Funding

Total project cost $31,438,408 100%

DOE 15,719,200 50

Participant 15,719,208 50

Project Objective

To demonstrate at an electric power plant using U.S. coals

that SNOXTM technology will catalytically remove 95% of

SO2

 and more than 90% of NOx from flue gas and produce a salable by-product of concentrated sulfuric acid.

SNOX is a trademark of Haldor Topsoe a/s.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-59

• Absence of an alkali reagent contributed to having no

secondary pollution streams or increases in CO2

 emissions.

• SO2

 catalyst virtually eliminated CO and hydrocarbon

emissions.

Operational

• 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 levelized

incremental cost was estimated at 6.1 mills/kWh or

$21/ton of SO2

 removal on a constant dollar basis.

Comparable current dollar costs were 7.8 mills/kWh

and $284/ton of SO2

.

Results Summary

Environmental

• SO2

 removal efficiency was normally in excess of 95%

for inlet concentrations averaging about 2,000 ppm.

• NOx

 reduction averaged 94% for inlet concentrations

of approximately 500–700 ppm.

• Particulate removal efficiency for the high-efficiency

fabric filter baghouse with SNOXTM system was

greater than 99%.

• Sulfuric acid purity exceeded federal specifications for

Class I acid.

• Air toxics testing showed high capture efficiency of

most trace elements in the baghouse. A significant

portion of the boron and almost all of the mercury

escaped to the stack. But selenium and cadmium,

normally a problem, were effectively captured in the

acid drain, as were organic compounds.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

9/88

Preaward Design and Construction

Operation initiated 3/92

12/89 3/92

Cooperative agreement

awarded 12/20/89

NEPA process completed (MTF) 1/31/90

Construction completed 12/91

Preoperational tests initiated 12/91

Dedication ceremony held 10/17/91

Environmental monitoring plan completed 10/31/91

Design completed 8/91

Construction started 1/91

DOE selected

project (CCT-II)

9/28/88

7/96

Project completed/

final report issued 7/96

Operation completed 12/94

Project Summary

Because the SNOXTM process utilized an oxidation catalyst to convert SO2

 to SO3 and ultimately to sulfuric acid,

no reagent was required for the SO2 removal step. 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 were

collected and parametric tests conducted to characterize

the process and equipment. The system has operated for

approximately 8,000 hours and produced more than

5,600 tons of commercial-grade sulfuric acid. Many tests

for the SNOXTM system were conducted at three loads—

75%, 100%, and 110% of design capacity.

Environmental Performance

Particulate emissions from the process were very low

 (<1 mg/Nm3

) due to the characteristics of the SO2 catalyst and the sulfuric acid condenser (WSA Condenser).

Although the Niles SNOXTM plant was fitted with a

baghouse (rather than an ESP) on its inlet, this was not

necessary for low particulate emissions, but the baghouse
5-60 Program Update 1996-97 Environmental Control Devices

was needed to maintain an acceptable cleaning frequency

of the SO2

 catalyst. At operating temperature, the SO2

catalyst, because of its sticky surface, retained about

90% of the dust that entered the catalyst vessel. Dust that

passed through was subsequently removed in the WSA

Condenser, which acted as a condensing particulate removal device (utilizing the dust particulates as nuclei).

Minimal or no increase in CO2

 emissions by the

process was tied to two features—the lack of a carbonatebased alkali reagent that releases CO2

 and the fact that the

process recovered additional heat from the flue gas to

offset its parasitic energy requirements. This heat recovery, under most design conditions, results in the net heat

rate of the boiler being the same or better after addition of

the SNOXTM process, and consequently no increase in

CO2 generation per unit of power.

With respect to CO and hydrocarbons, the SO2

 catalyst acted to virtually eliminate these compounds as well.

This aspect also positively affected the interaction of the

NOx

 and SO2 catalysts. Because the SO2 catalyst followed the NOx

 catalyst, any unreacted ammonia (slip)

was oxidized in the SO2

 catalyst to nitrogen, water vapor,

and a small amount of NOx

. As a result, downstream

fouling by ammonia compounds was eliminated and the

SCR was operated at slightly higher than typical ammonia

stoichiometries. These higher stoichiometries allowed

smaller SCR catalyst volumes and permitted the attainment of very high reduction efficiencies (>95%).

Sulfur dioxide removal in the SNOXTM process was

controlled by the efficiency of the SO2

-to-SO3 oxidation,

which occurred as the flue gas passes through the oxidation catalyst beds. The efficiency was controlled by two

factors—space velocity and bed temperature. Space

velocity governed the amount of catalyst necessary at

design flue gas flow conditions, and gas and bed temperature had to be high enough to activate the SO2

 oxidation,

reaction. During the test program, SO2

 removal efficiency

was normally in excess of 95% for inlet concentrations

averaging about 2,000 ppm.

The SCR portion of the SNOXTM process was able to

operate at higher than typical ammonia stoichiometries

due to its location ahead of the SO2

 catalyst beds. Normal operating stoichiometries for the SCR system were in

the range of 1.02–1.05 and system reduction efficiencies

averaged 94% with inlet NOx

 levels of approximately

500–700 ppm.

Sulfuric acid concentration and composition has met

or exceeded the requirements of the federal specifications

for Class I acid. During the design and construction of

the SNOXTM demonstration, arrangements were made

with a sulfuric acid supplier to purchase and distribute the

acid 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 boiler

water 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 the

boron and almost all of the mercury escaped to the stack.

But selenium and cadmium, normally a problem, were

effectively captured in the acid drain, as were organic

compounds.

Operational Performance

Heat recovery was accomplished by the SNOXTM process.

In a commercial configuration, it can be utilized in the

thermal cycle of the boiler. The process generated recoverable heat in several ways. All of the reactions that took

place with respect to NOx

 and SO2 removal were exothermic and increased the temperature of the flue gas. This

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

WSA Condenser cooling air discharge for use in the

furnace as combustion air. Because the WSA Condenser

The bottom portion of the SO2 converter catalyst, with

the catalyst dust collector hopper mounted on steel rails

(center), is shown.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-61

lowered the temperature of the flue gas to about 210 oF,

compared to approximately 300 oF for a typical power

plant, additional thermal energy was recovered along with

that from the heats of reaction.

Economic Performance

The economic evaluation of the SNOXTM process showed

a capital cost of approximately $305/kW for a 500-MWe

unit firing 3.2% sulfur coal. The levelized incremental

cost was 6.1 mills/kWh on a constant dollar basis and

7.8 mills/kWh on a current dollar basis. The equivalent

costs per ton of SO2

 removed were $219/ton (constant

dollars) and $384 (current dollars).

Commercial Applications

The SNOXTM technology is applicable to all electric

power plants and industrial/institutional boilers firing

coal, oil, or gas. The high removal efficiency for NOx and

SO2

 makes the process attractive in many applications.

Elimination of additional solid waste (except ash) enhances the marketability in urban and other areas where

solid waste disposal is a significant problem.

The host utility, Ohio Edison, is retaining the

SNOXTM technology as a permanent part of the pollution control

system at Niles Station to help

Ohio Edison meet its overall SO2

/

NOx

 reduction goals.

Commercial SNOXTM plants

also are operating in Denmark and

Sicily. In Denmark, a 305-MWe

plant has operated since August

1991. The boiler at this plant

burns coals from various suppliers

around the world, including the

United States; the coals contain

0.5–3.0% sulfur. The plant in

Sicily, operating since March

1991, has a capacity of about 30

MWe and fires petroleum coke.

Contacts

Paul Yosick, Project Manager, (423) 653-7550

ABB Environmental Systems

1400 Center Port Boulevard

Knoxville, TN 37932

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

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

References

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

Plant Utilizing the SNOXTM Innovative Clean Coal

Technology 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 as

DE94018832.)

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

Plant Utilizing the SNOXTM Innovative Clean Coal

Technology Demonstration. Volume 2, Appendices:

Final Report. Report No. DOE/PC/93251-T3-Vol. 2.

Battelle Columbus Operations. July 1994. (Available

from NTIS as DE94018833.)

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

Plant: Niles Station Boiler No. 2. Volume 1, Sampling/Results/Special Topics: Final Report. Report

No. DOE/PC/93251-T1-Vol. 1. Battelle Columbus

Operations. July 1994. (Available from NTIS as

DE94016050.)

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

Plant: Niles Station Boiler No. 2. Volume 2, Appendices: Final Report. Report No. DOE/PC/93251-T1-

Vol. 2. Battelle Columbus Operations. July 1994.

(Available from NTIS as DE94016051.)

• 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 from

NTIS as DE90004461.)

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.
5-62 Program Update 1996-97 Environmental Control Devices

Project Objective

To demonstrate, with a variety of coals and sorbents, the

LIMB process as a retrofit system for simultaneous control of NOx

 and SO2 in the combustion process, and that

LIMB can achieve up to 70% NOx

 and SO2 reductions; to

test alternate sorbent and coal combinations using the

Coolside process; to demonstrate in-duct sorbent injection

upstream of the humidifier and precipitator; and to show

SO2

 removal of up to 70%.

Technology/Project Description

The LIMB process reduces SO2

 by injecting dry sorbent

into the boiler at a point above the burners. The sorbent

then travels through the boiler and is removed along with

fly ash in an electrostatic precipitator (ESP) or baghouse.

DRB-XCL is a registered trademark of The Babcock & Wilcox Company. Humidification of the flue gas before it enters an ESP is

TAG is a trademark of the Electric Power Research Institute.

necessary 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

were tested. Other variables examined were stoichiometry, humidifier outlet temperature, and injection level.

In the Coolside process, dry sorbent is injected into

the flue gas downstream of the air preheater, followed by

flue gas humidification. Humidification enhances ESP

performance and SO2

 absorption. SO2 absorption is improved by dissolving NaOH or Na2

CO3 in the humidification water. The spent sorbent is collected with the fly ash,

as in the LIMB process. Bituminous coal with 3.0%

sulfur was used in testing.

Babcock & Wilcox DRB-XCL® low-NOx

 burners,

which control NOx

 through staged combustion, were used

in demonstrating both LIMB and Coolside technologies.

Environmental Control Devices

Combined SO2 /NOx Control Technologies

LIMB Demonstration Project

Extension and Coolside

Demonstration

Project completed.

Participant

The Babcock & Wilcox Company

Additional Team Members

Ohio Coal Development Office—cofunder

Consolidation Coal Company—cofunder and technology

supplier

Ohio Edison Company—host

Location

Lorain, Lorain County, OH (Ohio Edison’s Edgewater

Station, Unit 4)

Technology

The Babcock & Wilcox Company’s (B&W) limestone

injection multistage burner (LIMB) system; Babcock &

Wilcox DRB-XCL® low-NOx

 burners

Consolidation Coal Company’s Coolside duct injection of

lime sorbents

Plant Capacity/Production

105 MWe

Coal

Ohio bituminous, 1.6%, 3.0%, and 3.8% sulfur

Project Funding

Total project cost $19,404,940 100%

DOE 7,597,026 39

Participant 11,807,914 61
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-63

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

molar ratio of 2.0, a sodium-to-calcium (Na/Ca) ratio

of 0.2, and 20 oF approach-to-adiabatic-saturation

temperature using commercial hydrated lime and

2.8–3.0% sulfur coal.

• Sorbent recycle tests demonstrated the potential to

improve sorbent utilization.

Operational

• Humidification enhanced ESP performance, which

enabled opacity levels to be kept well within limits.

• LIMB availability was 95%. Coolside did not undergo

testing of sufficient length to establish availability.

• Humidifier performance indicated that operation in a

vertical rather than horizontal mode would be better.

Economic

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

100–500 MWe and coals with 1.5–3.5% sulfur, with a

target SO2

 reduction of 60%. Annual levelized costs

(15-year) for this range of conditions were $392–791/

ton of SO2

 removed (1992$).

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

100–500 MWe and coals with 1.5–3.5% sulfur, with a

target SO2

 reduction of 70%. Annualized levelized

costs (15-year) for this range of conditions were

$482–943/ton of SO2

 removed (1992$).

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

Design and Construction

7/86

Preaward

11/92

Project completed/final report issued 11/92

LIMB operational tests completed 8/91

NEPA process

 completed (MTF)

6/2/87

Cooperative agreement

awarded 6/25/87

Coolside operational tests initiated 7/89

Construction completed 9/89

Ground breaking/

construction

started 8/87

Environmental monitoring plan

completed 10/19/88

Results Summary

Environmental

• LIMB SO2

 removal efficiencies at a calcium-to-sulfur

(Ca/S) molar ratio of 2.0 and minimal humidification

across the range of coal sulfur contents were 53–61%

for ligno lime, 51–58% for calcitic lime, 45–52% for

dolomitic lime, and 22–25% for limestone ground to

80% less than 44 microns (325 mesh).

• LIMB SO2

 removal efficiency increased to 32% using

limestone ground to 100% minus 325 mesh and increased an additional 5–7% when ground to 100%

less than 10 microns.

• LIMB SO2 removal efficiencies were enhanced by

about 10% when humidification down to 20 oF approach-to-saturation temperature was used.

• LIMB, which incorporated Babcock & Wilcox DRBXCL® low-NOx

 burners, achieved 40–50% NOx reduction.

Operation

6/87

LIMB operational tests

initiated 4/90

Coolside operational tests

completed 2/90

DOE selected

project (CCT-I)

7/24/86

7/89
5-64 Program Update 1996-97 Environmental Control Devices

Project Summary

The initial expectation with LIMB technology was that

limestone calcined by injection into the furnace would

achieve adequate SO2

 capture. Use of limestone in lieu of

the significantly more expensive lime would keep operating costs relatively low. However, the demonstration

showed that even with fine grinding of the limestone and

deep humidification, performance with limestone was

marginal. As a result, a variety of hydrated limes were

evaluated in the LIMB configuration, demonstrating

enhanced performance. Although LIMB performance

was enhanced by applying humidification to the point of

approaching adiabatic saturation temperatures, performance did not rely on this deep humidification.

Coolside design was dependent upon deep humidification to improve sorbent reactivity and use of hydrated

lime. Sorbent injection was downstream of the furnace.

In addition, sorbent activity was enhanced by dissolving

sodium hydroxide (NaOH) or sodium carbonate

(Na2

CO3) in the humidification water.

Environmental Performance (LIMB)

LIMB tests were conducted over a range of Ca/S and

humidification conditions while burning Ohio coals

with nominal sulfur contents of 1.6%, 3.0%, and

3.8% by weight. Each of four different sorbents was

injected while burning each of the three different

coals. Other variables examined were stoichiometry,

humidifier outlet temperature, and injection level.

Exhibit 5-26 summarizes SO2

 removal efficiencies

for the range of sorbents and coals tested.

While injecting commercial limestone with 80%

of the particles less than 44 microns in size, removal

efficiencies of about 22% were obtained at a stoichiometry of 2.0 while burning 1.6% sulfur coal. However, removal efficiencies of about 32% were

achieved at a stoichiometry of 2.0 when using a limestone

with a smaller particle size (i.e., all particles were less

than 44 microns). A third limestone with essentially all

particles less than 10 microns was used to determine

what might be the removal efficiency limit. The removal

efficiency for this very fine limestone was approximately

5–7% higher than that obtained at similar conditions for

limestone with particles all sized less than 44 microns.

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

would permit the introduction of the limestone at close

to the optimum furnace temperature of 2,300 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-ft level and similar removals were observed. Removal efficiencies while injecting

at these levels were about 5% higher than while injecting

sorbent at the 191-ft level.

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

when humidification down to a 20 oF approach-to-saturation temperature was used.

The continued use of the low-NOx

 burners resulted in

an overall average NOx

 emissions level of 0.43 lb/106

Btu, which is about a 45% reduction.

Operational Performance (LIMB)

Long-term test data showed that the LIMB system was

available about 95% of the time it was called upon to

operate. Even with minimal humidification, ESP performance was adequately enhanced to keep opacity levels

well below the permitted limit. Opacity was generally in

the 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 program

were to verify short-term process operability and to develop a design performance database to establish process

economics for Coolside. Key process variables—Ca/S,

Na/Ca, and approach-to-adiabatic-saturation—were

evaluated in short-term (6–8-hour) parametric tests and

longer term (1–11-day) process operability tests.

Exhibit 5-26

LIMB SO2 Removal Efficiencies

(Percent)

Nominal Coal Sulfur Content

Sorbent 3.8% 3.0% 1.6%

Ligno lime 61 63 53

Commercial calcitic lime 58 55 51

Dolomitic lime 52 48 45

Limestone NT 25 22

(80% <44 microns)

NT = Not tested

Test conditions: injection at 181 ft, Ca/S of 2.0, minimal

humidification.

Water mist sprayed into the flue gas enhanced sulfur

capture by the sorbent by approximately 10% in the LIMB

process when 20 oF approach-to-saturation was used.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-65

The test program demonstrated that the Coolside

process routinely achieved 70% SO2

 removal at design

conditions of 2.0 Ca/S, 0.2 Na/Ca, and 20 oF approach-toadiabatic-saturation temperature using commercially

available hydrated lime. Coolside

SO2

 removal depended on Ca/S,

Na/Ca, approach-to-adiabaticsaturation, and the physical properties of the hydrated lime. Sorbent recycle showed significant

potential to improve sorbent utilization. The observed SO2

 removal with recycled sorbent alone

was 22% at 0.5 available Ca/S

and 18 oF approach-to-adiabaticsaturation. The observed SO2

removal with simultaneous recycle and fresh sorbent feed was

40% at 0.8 fresh Ca/S, 0.2 fresh

Na/Ca, 0.5 available recycle, and

18 oF approach-to-adiabaticsaturation.

Operational Performance

(Coolside)

Floor deposits experienced in the

ductwork with the horizontal

humidification led designers to

consider a vertical unit in a commercial configuration. Short-term

testing did not permit evaluation

of Coolside system availability.

Economic Performance

(LIMB & Coolside)

Economic comparisons were

made between LIMB, Coolside,

and a wet scrubber with limestone

injection and forced oxidation

(LSFO). Assumptions on performance were SO2

 removal efficiencies of 60%, 70%, and

95% for LIMB, Coolside, and LSFO, respectively. EPRI

TAGTM methodology was used. Exhibits 5-27 and 5-28

summarize results.

Commercial Application

Both LIMB and Coolside technologies are applicable to

most utility and industrial coal-fired units and provide

alternatives to conventional wet flue gas desulfurization

processes. LIMB and Coolside can be retrofitted with

modest capital investment and downtime, and their space

requirements are substantially less than for conventional

flue gas sulfurization processes.

Contacts

Paul Nolan, (216) 860-1074

The Babcock & Wilcox Company

P.O. Box 351

Barberton, OH 44203-0351

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

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

References

• T.R. Goots, M.J. DePero, and P.S. Nolan. LIMB Demonstration Project Extension and Coolside Demonstration: Final Report. Report No. DOE/PC/79798-

T27. The Babcock & Wilcox Company. November

1992. (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. December

1988. (LIMB/Coolside demonstration.) (Available

from NTIS as DE92016131.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: LIMB Demonstration Project

Extension. The Babcock & Wilcox Company. Report

No. DOE/FE-0085. U.S. Department of Energy. April

1987. (Available from NTIS as DE87009793.)

Exhibit 5-27

Capital Cost Comparison

($/kW)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe

1.5 93 150 413 66 116 312

2.5 95 154 421 71 122 316

3.5 102 160 425 73 127 324

250 MWe 500 MWe

1.5 46 96 228 31 69 163

2.5 50 101 235 36 76 169

3.5 54 105 240 40 81 174

Exhibit 5-28

Annual Levelized Cost Comparison

($/Ton of SO2 Removed)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe

1.5 791 943 1418 653 797 1098

2.5 595 706 895 520 624 692

3.5 525 629 665 461 570 527

250 MWe 500 MWe

1.5 549 704 831 480 589 623

2.5 456 567 539 416 502 411

3.5 419 526 413 392 482 321
5-66 Program Update 1996-97 Environmental Control Devices

Technology/Project Description

The SNRBTM process combines the removal of SO2

,

NOx

, and particulates in one unit—a high-temperature

baghouse. SO2

 removal is accomplished using either

calcium- or sodium-based sorbent injected into the flue

gas. NOx

 removal is accomplished by injecting ammonia (NH3

) to selectively reduce NOx in the presence of a

selective catalytic reduction, or SCR, catalyst. Particulate removal is accomplished by high-temperature fiber

bag filters.

The 5-MWe SNRBTM demonstration unit is large

enough to demonstrate commercial-scale components

while minimizing the demonstration cost. Operation at

this scale also permitted cost-effective control of the flue

gas 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 approximately 2,300 hours. Through this effort, SNRBTM demonstrated the technical and economic feasibility of

achieving more than 80% SO2

 removal, more than 90%

NOx

 removal, and 99% particulate removal at lower

capital, 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, OH.

Environmental Control Devices

Combined SO2 /NOx Control Technologies

SOx-NOx-Rox BoxTM Flue Gas

Cleanup Demonstration

Project

Project completed.

Participant

The Babcock & Wilcox Company

Additional Team Members

Ohio Edison Company—cofunder and host

Ohio Coal Development Office—cofunder

Electric Power Research Institute—cofunder

Norton Company—cofunder and SCR catalyst supplier

3M Company—cofunder and filter bag supplier

Owens Corning Fiberglas Corporation—cofunder and

filter bag supplier

Location

Dilles Bottom, Belmont County, OH (Ohio Edison

Company’s R.E. Burger Plant, Unit No. 5)

Technology

The Babcock & Wilcox Company’s SOx

-NOx-Rox BoxTM

(SNRBTM) process

Plant Capacity/Production

5-MWe equivalent slipstream from a 156-MWe boiler

Coal

Bituminous coal blend, 3.7% sulfur avg

Project Funding

Total project cost $13,271,620 100%

DOE 6,078,402 46

Participant 7,193,218 54

Project Objective

To achieve greater 70% SO2

 removal and 90% or higher

reduction in NOx

 emissions while maintaining particulate

emissions below 0.03 lb/106

 Btu.

SOx-NOx-Rox Box and SNRB are trademarks of The Babcock &

Wilcox Company.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-67

Results Summary

Environmental

• SO2

 removal efficiency of 80% was achieved with

commercial-grade lime at a calcium-to-sulfur (Ca/S)

molar ratio of 2.0 and temperature of 800–850 oF.

• SO2

 removal efficiency of 90% was achieved with

sugar hydrated and lignosulfonate hydrated lime at a

Ca/S ratio of 2.0 and temperature of 800–850 oF.

• SO2

 removal efficiency of 80% was achieved with

sodium bicarbonate at a sodium-to-sulfur (Na2

/S)

molar ratio of 1.0 and temperature of 425 oF.

• SO2

 emissions were reduced to less than 1.2 lb/106 Btu

with 3–4% sulfur coal with a Ca/S molar ratio as low

as 1.5 and NA2

/S ratio of 1.0.

• Injection of calcium-based sorbents directly upstream

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

temperatures up to 1,200 oF.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

9/88

Preaward

12/89

Design completed 8/91

DOE selected

project (CCT-II)

9/28/88

Cooperative agreement

awarded 12/20/89

NEPA process completed (MTF) 9/22/89

Ground breaking/construction started 5/9/91

5/92

Design and Construction Operation

Preoperational tests initiated 11/91

• NOx reduction of 90% was achieved with an NH3/NOx

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 hydrogen

chloride (HCl) by 95%.

Operational

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

85–90%.

• Norton Company’s NC-300 zeolite SCR catalyst

showed no appreciable physical degradation or change

in catalyst activity over the course of the demonstration.

• No excessive wear or failures occurred with the filter

bags tested: 3M’s Nextel ceramic fiber filter bag and

Owens Corning Fiberglas’s S-Glass filter bag.

Economic

• Capital cost for a 250-MWe retrofit was $233/kW,

assuming 3.5% sulfur coal and baseline NOx

 generation of 1.2 lb/106

 Btu.

9/95

Construction completed 12/91

Environmental monitoring plan completed 12/31/91

Operation

initiated 5/92 Operation completed 5/93

Project completed/final report issued 9/95
5-68 Program Update 1996-97 Environmental Control Devices

Project Summary

SNRBTM incorporates two successful technology development efforts that offer distinct advantages over other

control technologies. High-temperature filter bags and

circular monolith catalyst developments enabled multiple

emission control in a single component with a low plantarea space requirement. As a postcombustion control

system, it is simple to operate. The high-temperature bag

provides a clean, high-temperature environment compatible with effective SCR operation and a surface for enhanced SO2

/sorbent contact (creates a sorbent cake on the

surface). Particulate control, which is receiving increasing attention, is typical of the superior performance offered by pulsed jet baghouses.

Environmental Performance

Four different sorbents were tested for SO2

 capture. Calcium-based sorbents included commercial-grade-hydrated

lime, sugar-hydrated lime, and lignosulfonate-hydrated

lime. In addition, sodium bicarbonate was tested. The

optimal location for injecting the sorbent into the flue gas

was immediately upstream of the baghouse. Effectively,

the SO2

 was captured by the sorbent in the form of a filter

cake on the filter bags (along with fly ash).

With the baghouse operating above 830 oF, injection

of commercial-grade hydrated lime at Ca/S molar ratio of

1.8 and above resulted in SO2

 removals of over 80%. At

a Ca/S of molar ratio of 2.0, performance of the sugarhydrated lime and lignosulfonate-hydrated lime increased

performance by approximately 8%, for overall removal of

approximately 90%. SO2

 removal of 85–90% was obtained with calcium utilization of 40–45%. Injection of

the calcium-based sorbents directly upstream of the

baghouse at 825–900 oF resulted in higher overall SO2

removal than injection further upstream at temperatures

up to 1,200 oF.

SO2

 removal using sodium bicarbonate was 80% at

an Na2

/S ratio of 1.0 and 98% at an Na2/S ratio of 2.0

at a significantly reduced baghouse temperature of

450–460 oF. SO2

 emissions while burning a 3–4% sulfur

coal were reduced to less than 1.2 lb/106

 Btu with a Ca/S

molar ratio as low as 1.5 and Na2

/S ratio less than 1.0.

To capture NOx

, ammonia was injected between the

sorbent injection point and the baghouse. The ammonia

and NOx

 reacted to form nitrogen and water in the presence of Norton Company’s NC-300 series zeolite SCR

catalyst. With the catalyst being located inside the filter

bags, 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.

NOx

 emissions reduction of 90% was readily

achieved with ammonia slip limited to less than 5 ppm.

This performance reduced NOx

 emissions to less than

0.10 lb/106

 Btu. NOx reduction was insensitive to temperatures over the catalyst design temperature range of

700–900 oF. Catalyst space velocity (volumetric 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 program. The degree of oxidation of SO2

 to SO3 over the

zeolite catalyst appeared to be less than 0.5%. (SO2

 oxidation is a concern for SCR catalysts containing vanadium.) Leach potential analysis of the catalyst after

completion of the field test showed that the catalyst remained 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 demonstration test program. The targeted emissions monitored

included trace metals, volatile organic compounds, semivolatile organic compounds, aldehydes, halides, and

radionuclides. These species were a subset of the 189

substances identified in the CAAA. Measurements of

mercury speciation, dioxins, and furans were unique

The demonstration baghouse is installed on the back side

of the power plant. Workers stand by the catalyst holder tube

prior to lifting it into the penthouse.
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-69

features of this test program. The emissions control efficiencies achieved for various air toxics by the SNRBTM

system were generally comparable to those of the conventional ESP at the power plant. However, the SNRBTM

system did reduce HCl by an average of 95% and HF

emissions by an average of 84%, whereas the ESP had no

effect on these constituents.

Operation of the SNRBTM demonstration resulted in

the production of approximately 830 tons of fly ash and

by-product solids. An evaluation of potential uses for the

by-product showed that the material might be used for

agricultural liming (if pelletized). Also, the solids potentially could be used as a partial cement replacement to

lower the cost of concrete.

Operational Performance

A 3,800-hour durability test of three fabric filters was

completed at the Filter Fabric Development Test Facility

in Colorado Springs in December 1992. No signs of

failure were observed. All of the demonstration tests

were conducted using the 3M Company Nextel ceramic

fiber filter bags or the Owens Corning Fiberglas S-Glass

filter bags. No excessive wear or failures occurred in

over 2,000 hours of elevated temperature operation.

Economic Performance

For a 250-MWe boiler fired with 3.5% sulfur coal and

NOx

 emissions of 1.2 lb/106 Btu, the projected capital

cost of an SNRBTM system is approximately $233/kW

including various technology and project contingency

factors. A combination of fabric filter, SCR, and wet

scrubber for achieving comparable emissions control has

been estimated at $360–400/kW. Variable operating costs

are dominated by the cost of the SO2

 sorbent for a system

designed for 85–90% SO2

 removal. Fixed operating costs

primarily consist of system operating labor and projected

labor and material for the hot baghouse and ash-handling

systems.

Commercial Applications

Commercialization of the technology is expected to

develop with an initial larger scale application equivalent

to 50–100 MWe. The focus of marketing efforts is being

tailored to match the specific needs of potential industrial, utility, and independent power producers for both

retrofit and new plant construction. SNRBTM is a flexible

technology that can be tailored to maximize control of

SO2

, NOx, or combined emissions to meet current performance requirements while providing flexibility to address

future needs.

Contacts

Kevin Redinger, (330) 829-7719

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

John C. McDowell, FETC, (412) 892-6237

References

• SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Final Report. Report No. DOE/PC/89656-T1.

The Babcock & Wilcox Company. September 1995.

(Available from NTIS as DE96003839.)

• 5 MWe SNRBTM Demonstration Facility: Detailed

Design Report. The Babcock & Wilcox Company.

November 1992.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: SOx

-NOx-Rox BoxTM Flue Gas

Cleanup Demonstration Project. The Babcock &

Wilcox Company. Report No. DOE/FE-0145. U.S.

Department of Energy. November 1989. (Available

from NTIS as DE90004458.)

Workers lower one of the catalyst holder tubes into a

mounting plate in the penthouse of the high-temperature

baghouse.
5-70 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

Combined SO2 /NOx Control Technologies

Enhancing the Use of Coals by

Gas Reburning and Sorbent

Injection

Project completed.

Participant

Energy and Environmental Research Corporation

Additional Team Members

Gas Research Institute—cofunder

State of Illinois, Department of Commerce & Community

Affairs—cofunder

Illinois Power Company—host

City Water, Light and Power—host

Locations

Hennepin, Putnam County, IL (Illinois Power Company’s

Hennepin Plant, Unit 1)

Springfield, Sangamon County, IL (City Water, Light and

Power’s Lakeside Station, Unit 7)

Technology

Energy and Environmental Research Corporation’s gas

reburning and sorbent injection (GR–SI) process

Plant Capacity/Production

Hennepin: tangential-fired 80 MWe (gross), 71 MWe (net)

Lakeside: cyclone-fired 40 MWe (gross), 33 MWe (net)

Coal

Illinois bituminous, 3.0% sulfur

Project Funding

Total project cost $37,588,955 100%

DOE 18,747,816 50

Participant 18,841,139 50

Project Objective

To demonstrate gas reburning to attain at least 60% NOx

reduction along with sorbent injection to capture at least

50% of the SO2

 on two different boiler configurations—

tangentially fired and cyclone-fired—while burning

high-sulfur midwestern coal.

Technology/Project Description

In this process, 80–85% of the fuel was coal and was

supplied to the main combustion zone. The remaining

15–20% of the fuel, provided by natural gas, bypassed

the main combustion zone and was injected above the

main burners to form a reducing (reburning) zone in

which NOx

 was converted to nitrogen. A calcium compound (sorbent) was injected in the form of dry, fine

particulates above the reburning zone in the boiler. The

calcium compound tested was Ca(OH)2

 (lime). This

project demonstrated the GR–SI process on two separate

boilers representing two different firing configurations—

a tangentially fired, 80-MWe (gross) boiler at Illinois

Power Company’s Hennepin Plant in Hennepin, IL, and a

cyclone-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 factors influencing costs.

PromiSORB is a trademark of Energy and Environmental Research

Corporation.
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 Program Update 1996-97 5-71

Results Summary

Environmental

• On the tangentially fired boiler, GR–SI NOx

 reductions

of up to 75% were achieved, and an average 67%

reduction was realized at an average gas heat input of

18%.

• GR–SI SO2

 removal efficiency on the tangentially fired

boiler averaged 53% with hydrated lime at a calciumto-sulfur (Ca/S) molar ratio of 1.75 (corresponding to a

sorbent utilization of 24%).

• On the cyclone-fired boiler, GR–SI NOx

 reductions of

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

• GR–SI SO2

 removal efficiency on the cyclone-fired

boiler averaged 58% with hydrated lime at a Ca/S

molar ratio of 1.8 (corresponding to a sorbent utilization of 24%).

• Particulate emissions were not a problem on either

unit undergoing demonstration, but humidification

had to be introduced at Hennepin to enhance ESP

performance.

• Three advanced sorbents tested achieved higher SO2

capture efficiencies than the baseline Linwood hydrated lime. PromiSORBTM A achieved 53% SO2

capture efficiency and 31% utilization without GR at

a Ca/S molar ratio of 1.75. Under the same conditions, PromiSORBTM B achieved 66% SO2 reduction

and 38% utilization, and High-Surface-Area Hydrated

Lime achieved 60% SO2

 reduction and 34% utilization.

Operational

• Boiler efficiency decreased by approximately 1% as a

result of increased moisture formed in combustion

from natural gas use.

• There was no change in boiler tube wastage, tube

metallurgy, or projected boiler life.

Preaward Design and Construction

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

7/86 1/91

DOE selected

project (CCT-I)

7/24/86

7/87

Operation initiated,

Lakeside 5/93

Operation completed,

Hennepin 1/93

Construction completed, Hennepin 8/91

Operation initiated, Hennepin 1/91

Construction started, Lakeside 6/90

Environmental monitoring plan completed,

Lakeside 11/15/89

Environmental monitoring plan

completed, Hennepin 10/15/89

NEPA process completed, Lakeside (EA) 6/25/89

Design completed, both sites 5/89

Construction started, Hennepin 5/89

NEPA

process

completed,

Hennepin

(MTF) 5/9/88

Cooperative

agreement

awarded

7/14/87

Construction completed, Lakeside 5/92

Restoration completed,

Hennepin 12/93

Economic

• Capital cost for gas reburning (GR) was approximately

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

• 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

8/97

Project completed/

final report issued 8/97*

Operation completed,

Lakeside 10/94

Operation

Restoration completed,

Lakeside 12/95
5-72 Program Update 1996-97 Environmental Control Devices

Project Summary

The GR–SI project demonstrated the success of gas

reburning and sorbent injection technologies in reducing

NOx

 and SO2 emissions. The process design conducted

early in the project combined with the vast amount of

data collected during the testing created a database capable of applying the technology to all major coal-firing

configurations (tangential-, cyclone-, and wall-fired) on

both utility and industrial units. The emissions control

and performance can be accurately projected as can the

capital and operating costs.

Environmental Performance (Hennepin)

Operational testing, which included optimization testing

and long-term testing, was conducted between January

1991 and January 1993. The GR–SI long-term demonstration tests were carried out from January 1992 to October 1992 to verify the system performance over an extended period. The unit was operated at constant loads

and with the system under dispatch operation where load

was varied to meet plant power output requirements.

With the system under dispatch, the load fluctuated over a

wide range from 40 MWe to a maximum load of 75 MWe.

Over the long-term demonstration period, the average

gross power output was 62 MWe.

For long-term demonstration testing, the average

NOx

 reduction was approximately 67%. The average SO2

removal efficiency was over 53% at a Ca/S molar ratio of

1.75. (Linwood hydrated lime was used throughout these

tests except for a few days when Marblehead lime was

used.) CO emissions were below 50 ppm in most cases

but were higher during operation at low load.

A significant reduction in CO2

 was also measured.

This was due to partial replacement of coal with natural

gas having a lower C/H ratio. This cofiring with 18%

natural gas resulted in a theoretical CO2

 emissions reduction of nearly 8% from the coal-fired baseline level. With

flue gas humidification, electrostatic precipitator (ESP)

collection efficiencies greater than 99.8% 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 of 0.035 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 were

manufactured by the participant and contained proprietary

additives to increase their reactivity toward SO2

 and were

referred to as PromiSORBTM A and B. The Illinois State

Geological Survey developed the other sorbent—HighSurface-Area Hydrated Lime in which alcohol is used to

form a material that gives rise to a much higher surface

area than that of conventionally hydrated limes.

The SO2

 capture without GR, at a nominal 1.75 Ca/S

molar ratio, was 53% for PromiSORBTMA, 66% for

PromiSORBTM B, 60% for High-Surface-Area Hydrated

Lime, and 42% for Linwood lime. At a 2.6 Ca/S molar

ratio, the PromiSORBTM B yielded 81% SO2

 removal

efficiency.

Environmental Performance (Lakeside)

Parametric tests were conducted in three series: GR

parametric tests, SI parametric tests, and GR–SI optimization tests. A total of 100 GR parametric tests were conducted at boiler loads of 33, 25, and 20 MWe. Gas heat

input varied from 5% to 26%. The GR parametric tests

achieved a NOx

 reduction of approximately 60% at a gas

heat input of 22–23%. Additional flow modeling and

computer modeling studies indicated that smaller reburning fuel jet nozzles could increase reburning fuel mixing

and thus improve the NOx

 reduction performance.

A total of 25 SI parametric tests were conducted to

isolate the effects of sorbent on boiler performance and

operability. Results showed that SO2

 reduction level

varied with load because of the effect of temperature on

the sulfation reaction. At a Ca/S 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 of

the initial GR parametric tests and flow modeling studies.

The total cross-sectional area of the reburning jets was

decreased by 32% to increase the reburning jet’s penetration characteristics. The decrease in nozzle diameter

increased NOx

 reduction by an additional 3–5% compared

to the initial parametric tests. With GR–SI, total SO2

reductions resulted from partial replacement of coal with

natural gas and sorbent injection. At a gas heat input of

22% and Ca/S molar ratio of 1.8, average NOx

 reduction

The flexible lime-sorbent distribution lines lead from

the sorbent splitter to the top of the cyclone-fired boiler at

Lakeside Station.
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 Program Update 1996-97 5-73

during the long-term testing of

GR–SI was 66% and the average

SO2

 reduction was 58%.

Operational Performance

(Hennepin/Lakeside)

Sorbent injection increased the

frequency of sootblower operation

but did not adversely affect boiler

efficiency or equipment performance. Gas reburning decreased

boiler efficiency by approximately

1.0% because of the increase in

moisture formed with combustion

of natural gas. Examination of the

boiler before and after testing

showed no measurable change in

tube wear or metallurgy. Essentially, the scheduled life of the

boiler was not compromised.

The ESPs adequately accommodated the changes in ash loading and resistivity with the presence of sorbent in the ash. No adverse conditions were

found to exist. But as mentioned, humidification had to

be added at Hennepin to achieve acceptable ESP performance with GR–SI.

Economic Performance (Hennepin/Lakeside)

Capital and operating costs depend largely on site-specific factors, such as gas availability at the site, coal/gas

cost differential, SO2

 removal requirements, and value of

SO2

 allowances. It was estimated that for most installation, a 15% gas heat input will achieve 60% NOx

 reduction. The capital cost for such a GR installation was

estimated at $15/kW for 100-MWe and larger plants plus

the cost of the gas pipeline (if required). Operating costs

were almost entirely related to the differential cost of the

gas over the coal as reduced by the value of SO2

 emission

allowances.

The capital cost estimate for

SI was $50/kW. Operating costs

for SI were dominated by the cost

of the sorbent and sorbent/ash

disposal costs. SI was projected to

be cost competitive at $300/ton of

SO2

 removed.

Commercial Applications

The GR–SI process is a unique

combination of two separate technologies. The commercial applications 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 preNSPS 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.

Contacts

Blair A. Folsom, Senior Vice President, (714) 859-8851

Energy and Environmental Research Corporation

18 Mason

Irvine, CA 92718

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

Jerry L. Hebb, FETC, (412) 892-6079

References

• 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 Research Corporation.

February 1995. (Available from NTIS as DE95011481.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 2: Gas Reburning–Sorbent

Injection at Hennepin Unit 1, Illinois Power Company.

Report No. DOE/PC/79796-T38-Vol. 2. Energy and

Environmental Research Corporation. October 1994.

(Available from NTIS as DE95009448.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 3: Gas Reburning–Sorbent

Injection at Edwards Unit 1, Central Illinois Light Company. Report No. DOE/PC/79796-T38-Vol. 3. Energy

and Environmental Research Corporation. October

1994. (Available from NTIS as DE95009447.)

• Clean Coal Technology: Reduction of NOx

 and SO2

Using Gas Reburning, Sorbent Injection, and Integrated

Technologies. Topical Report No. 3, Revision 1. U.S.

Department of Energy and Energy and Environmental

Research Corporation. September 1993. (Available

from NTIS as DE94007444.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Enhancing the Use of Coals by

Gas Reburning and Sorbent Injection. Energy and Environmental Research Corporation. Report No. DOE/FE0087. U.S. Department of Energy. May 1987. (Available from NTIS as DE87010815.)

The natural gas injector was installed

on the corner of Hennepin Station’s

tangentially fired boiler.
5-74 Program Update 1996-97 Environmental Control Devices

Project Funding

Total project cost $158,607,807 100%

DOE 45,000,000 28

Participant 113,607,807 72

Project Objective

To demonstrate at a 300-MWe utility-scale a combination

of cost-effective and innovative emission reduction and

efficiency improvement technologies, including the

S-H-U wet scrubber system enhanced with formic acid to

increase SO2

 removal in a Stebbins tile-lined scrubber,

low-NOx

 burner, urea injection for NOx removal, and a

heat-pipe air preheater.

Technology/Project Description

The S-H-U wet flue gas desulfurization process is a formic-acid-enhanced, wet limestone process, which results

in very high SO2

 removal with low energy consumption

and the production of commercial-grade gypsum.

The flue gas desulfurization absorber is a Stebbins

tile-lined split-module vessel, which has superior corrosion and abrasion resistance, leading to decreased lifecycle costs and reduced maintenance. The split-module

design is constructed below the stack to save space and

provide operational flexibility.

The Nalco Fuel Tech NOxOUT® system is used to

remove NOx

 by injecting urea into the boiler flue gas.

This facet of the project, in conjunction with other combustion modifications, including LNCFSTM Level III (lowNOx

 burner system), reduces NOx emissions and produces

marketable fly ash.

A heat-pipe air-heater system by ABB Air Preheater,

Inc., reduces both air leakage and the air heater’s flue gas

Environmental Control Devices

Combined SO2 /NOx Control Technologies

Milliken Clean Coal

Technology Demonstration

Project

Participant

New York State Electric & Gas Corporation

Additional Team Members

New York State Energy Research and Development

Administration—cofunder

Empire State Electric Energy Research Corporation—

cofunder

Consolidation Coal Company—technical consultant

Saarberg-Hölter-Umwelttechnik, GmbH—technology

supplier

The Stebbins Engineering and Manufacturing

Company—technology supplier

Nalco Fuel Tech—technology supplier

ABB Air Preheater, Inc.—technology supplier

DHR Technologies, Inc.—operator of advisor system

Location

Lansing, Tompkins County, NY (New York State Electric

& Gas Corporation’s Milliken Station, Units 1 and 2)

Technology

Flue gas cleanup using Saarberg-Hölter-Umwelttechnik’s

(S-H-U) formic-acid-enhanced, wet limestone scrubber

technology; ABB Combustion Engineering’s Low-NOx

Concentric Firing System (LNCFSTM) Level III; Nalco

Fuel Tech’s NOxOUT® urea injection system; Stebbins’

tile-lined split-module absorber; and ABB Air Preheater’s

heat-pipe air-heater system

Plant Capacity/Production

300 MWe

NOxOUTis a registered trademark of Nalco Fuel Tech.

LNCFS is a trademark of ABB Combustion Engineering, Inc.

PEOA is a trademark of DHR Technologies, Inc.
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 Program Update 1996-97 5-75

exit temperature. DHR Technologies, Inc., is providing a

state-of-the-art boiler and plant artificial-intelligencebased control system, PEOATM, to enhance emissions

reductions and boiler efficiencies.

The project has been designed for “total environmental and energy management,” a concept encompassing low emissions, low energy consumption, improved

combustion, upgraded boiler controls, and reduced solid

waste. The system has been designed to achieve at least a

95% SO2

 removal efficiency (or up to 98%) using limestone while burning high-sulfur coal. NOx

 reductions

have been achieved using selective noncatalytic reduction

technology and separate combustion modifications. NOx

emissions have been reduced from 0.65 to 0.40 lb/106 Btu

(38%) by retrofitting the two boilers with low-NOx

 burners. NOxOUT® is expected to reduce NOx

 emissions

from Unit 1 by an additional 15–20%. The system has

zero wastewater discharge and produces marketable byproducts (e.g., commercial-grade gypsum, calcium chloride, and fly ash), minimizing solid waste.

 Pittsburgh, Freeport, and Kittanning coals, with

sulfur contents of 1.5%, 2.9%, and 4.0%, are being used

in the demonstration.

Project Status/Accomplishments

The split module scrubber at Milliken Station began

scrubbing operations for Unit 2 in January 1995. Full

plant operation with Unit 1 incorporated into the splitmodule scrubber began in June 1995.

Heat pipe performance testing at various loads was

completed in July 1996. Further testing on a cleaned heat

pipe was completed in November 1996. Test data are

being compiled, and a report is being prepared.

Design coal FGD testing began in May 1996. However, the sulfur content of coal received was below design

specifications for the scrubber. Testing was halted in

September 1996 due to plugging of some slurry spray

nozzles. Milliken does not expect to receive any coal

with the design sulfur percentage until late summer 1997.

Testing has been delayed until design coal can be delivered, after which testing will continue for 6 months.

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Preaward Operation

9/91 10/92

DOE selected

project (CCT-IV)

9/12/91

Cooperative agreement awarded 10/20/92

Mist eliminator testing is complete; a report is expected to be issued in mid-1997.

Commercial Applications

The S-H-U SO2

 removal process, the Nalco NOxOUT®

noncatalytic reduction process, Stebbins’ tile-lined splitmodule absorber, and ABB Air Preheater’s heat-pipe airheater technology are applicable to virtually all power

plants, in both retrofit and greenfield applications, at any

size. The space-saving design features of the technologies, combined with the production of marketable byproducts, offer significant incentives to generating stations with limited space.

Wheelabrator is marketing NOxOUT® through a

license agreement with Nalco Fuel Tech. DHR Technologies’ Plant Emission Optimization Advisor (PEOATM) has

been sold to City Public Service in San Antonio, TX;

three bids are outstanding in Korea and one in Israel.

Ground breaking/construction started 4/93

Design completed 4/93

NEPA process completed

(EA) 8/18/93

8/98

Operation completed 7/98*

Project completed/final report issued 8/98*

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
5-76 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

Combined SO2 /NOx Control Technologies

Commercial Demonstration of

the NOXSO SO2/NOx Removal

Flue Gas Cleanup System

Participant

NOXSO Corporation

Additional Team Members

Olin Corporation—cofunder and host

Gas Research Institute—cofunder

Electric Power Research Institute—cofunder

W.R. Grace and Company—cofunder

Morrison Knudsen-Ferguson—engineer

Calabrian Corporation—burn-in-oxygen

technology supplier

Advanced Petrogas Systems—liquid SO2

 plant

fabrication

Location

NOXSO Plant: site under negotiation

SO2

 Plant: Charleston, Bradley County, TN (Olin

Corporation’s Chlor-alkali facility)

Technology

NOXSO Corporation’s dry, regenerable flue gas cleanup

process

Calabrian Corporation’s burn-in-oxygen technology for

production of liquid SO2

Plant Capacity/Production

NOXSO Plant: 50–100 MWe

SO2

 Plant: 45,000 tons/yr of liquid SO2

Project Funding

Total project cost $82,812,120 100%

DOE 41,406,060 50

Participant 41,406,060 50

Project Objective

To demonstrate removal of 98% of the SO2

 and 75% of

the NOx

 from a coal-fired boiler’s flue gas using the

NOXSO process.

Technology/Project Description

The NOXSO process is a dry, regenerable system capable

of removing both SO2

 and NOx in flue gas from coal-fired

utility boilers burning medium- to high-sulfur coals. In

the basic process, the flue gas passes through a fluidizedbed adsorber located downstream of the precipitator; SO2

and NOx are adsorbed by the sorbent, which consists of

spherical beads of high-surface-area alumina impregnated

with sodium carbonate. Cleaned flue gas then passes

through a baghouse to the stack.

The NOx

 is desorbed from the NOXSO sorbent when

heated by a stream of hot air. Hot air containing the desorbed NOx

 is recycled to the boiler where equilibrium

processes cause destruction of the NOx

. The adsorbed

sulfur is recovered from the sorbent in a regenerator

where it reacts with methane at high temperature to produce an offgas with high concentrations of SO2

 and hydrogen sulfide (H2

S). This offgas is processed to produce

elemental sulfur, which is further processed to produce

liquid SO2

, a higher valued by-product.

The process is expected to achieve SO2

 reductions of

98% and NOx

 reductions of 75%.

A full-scale design based on data from the proof-ofconcept facility at Ohio Edison’s Toronto power plant is

in preparation.

The project will also demonstrate a 45,000-ton/yr

liquid SO2

 plant at Olin Corporation’s Charleston, TN,

facility. The liquid SO2

 plant will use Calabrian’s burn-
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in-oxygen technology. This technology is a substantial

improvement over other existing technologies for producing liquid SO2

. By manufacturing liquid SO2 with oxygen rather than air, by-product streams are eliminated,

making the technology environmentally friendly. Storage

requirements are minimal because the product can be

made virtually on demand.

Project Status/Accomplishments

NOXSO is searching for a new host site to demonstrate

the NOXSO process. Alcoa Generating Corporation

chose to cancel the host site agreement when NOXSO

was unable to obtain full project financing by January 31,

1997, as specified in the agreement.

In June 1997, the court accepted NOXSO’s petition

for voluntary bankruptcy. NOXSO will continue the

process of selecting a new host site for demonstrating the

NOXSO technology.

Commercial Applications

The NOXSO process is applicable for retrofit or new

facilities. The process is suitable for utility and industrial

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

12/89 3/91

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

Preaward

Cooperative agreement

awarded 3/11/91

Design

coal-fired boilers of 50 MWe or larger. The process is

adaptable to coals with medium- to high-sulfur content.

The process produces one of the following as a salable by-product: elemental sulfur, sulfuric acid, or liquid

SO2

. A readily available market exists for these products.

The technology is expected to be especially attractive

to utilities that require high removal efficiencies for both

SO2

 and NOx, need to eliminate solid wastes, and/or have

inadequate water supply for a wet scrubber.

Alcoa Generating Corp. cancelled

host site agreement 2/97

Note: Milestone schedule pending

project restructuring

Novation of cooperative agreement with NOXSO Corp. 8/94

Selected new host site 8/94

Project definition phase completed 10/94

NEPA process completed (EA) 6/26/95

SO2 plant construction started 10/95

SO2 plant construction completed 9/96

SO2 plant operations initiated 12/96
5-78 Program Update 1996-97 Environmental Control Devices

Environmental Control Devices

Combined SO2 /NOx Control Technologies

Integrated Dry NOx/SO2

Emissions Control System

Project completed.

Participant

Public Service Company of Colorado

Additional Team Members

Electric Power Research Institute—cofunder

Stone and Webster Engineering Corp.—engineer

The Babcock & Wilcox Company—burner developer

Fossil Energy Research Corporation—operational 

tester

Western Research Institute—flyash evaluator

Colorado School of Mines—bench-scale engineering

researcher and tester

NOELL, Inc.—urea-injection system provider

Location

Denver, Denver County, CO (Public Service Company of

Colorado’s Arapahoe Station, Unit No. 4)

Technology

The Babcock & Wilcox Company’s DRB-XCL® low-NOx

burners, in-duct sorbent injection, and furnace (urea)

injection

Plant Capacity/Production

100 MWe

Coal

Colorado bituminous, 0.4% sulfur

Wyoming subbituminous (short test), 0.35% sulfur

Project Funding

Total project cost $27,411,462 100%

DOE 13,705,731 50

Participant 13,705,731 50

Project Objective

To demonstrate the integration of five technologies to

achieve up to 70% reduction in NOx

 and SO2 emissions;

more specifically, to assess the integration of a downfired low-NOx

 burner with in-furnace urea injection for

additional NOx

 removal and dry sorbent in-duct injection

with humidification for SO2

 removal.

Technology/Project Description

All of the testing used Babcock & Wilcox’s low-NOx

DRB-XCL® down-fired burners with overfire air. These

burners control NOx

 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

DRB-XCL is a registered trademark of The Babcock & Wilcox Company.

(SNCR) system was tested to determine how much additional NOx

 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 was injected upstream of the boiler

economizer or sodium downstream of the air heater.

Humidification downstream of the dry sorbent injection

was incorporated to aid 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.
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1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Operation Design and 8/92

Construction

12/89 3/91

NEPA process completed (MTF) 9/27/90

Design initiated 6/90

DOE selected project

(CCT-III) 12/19/89

Ground breaking/construction started 5/21/91

Design completed 3/92

Preoperational tests initiated 6/92

Operation initiated 8/92

Construction completed 8/92

Environmental

monitoring plan

completed

8/5/93

Results Summary

Environmental

• With maximum overfire air (24% of total combustion

air), a NOx

 reduction of 62–69% was achieved across

the 50–110-MWe load range.

• DRB-XCL® burners with minimum overfire air reduced NOx

 emissions by more than 63% under steady

state conditions.

• NOx

 reductions were decreased by 10–25% under

load-following conditions.

• The SNCR system, using both stationary and retractable injection lances in the furnace, provided NOx

removal of 30–50% at an ammonia (NH3) slip of

10 ppm, thus increasing performance of the total NOx

control system to greater than 80% NOx reduction.

• SO2 removal with calcium-based dry sodium injection

into the boiler at approximately 1,000 oF was less than

10%, and with injection into the fabric filter duct, SO2

removal was less than 40% at a Ca/S 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 sodium sesquicarbonate.

• Integrated SNCR and sodium dry 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 emissions

and 80% of the mercury.

Operational

• Arapahoe 4 operated more than 34,000 hours after

combustion modifications were complete.

• Availability factor was over 91%.

• Operational test objectives were met or exceeded.

• Control system modifications and additional operator

training may be necessary to improve NOx

 control

under load-following conditions.

• Buildup of a hard ash cake on the fabric filter occurred

during operation of dry sorbent injection of calcium

hydroxide with humidification.

• Temperature differential between the top and bottom

surfaces of the Advanced Retractable Injection Lances

(ARIL) caused the lances to bend downwards

12–18 inches. Alternative designs corrected the

problem.

• Concurrent operation of SNCR and the dry sodium

injection system caused an NH3

 odor problem around

the ash silo, which appeared to be related to the rapid

change in pH due to the sodium in the ash.

Economic

• Data not available.

12/97

Operation completed 12/96

Cooperative agreement awarded 3/11/91

Project completed/

final report issued

12/97*
5-80 Program Update 1996-97 Environmental Control Devices

Project Summary

The Integrated Dry NOx/SOx Emissions Control System

combines five major control technologies to form an

integrated system to control both NOx

 and SO2. The lowNOx

 combustion system consists of 12 Babcock & Wilcox DRB-XCL® low-NOx

 burners installed on the roof.

The low-NOx combustion system also incorporated three

Babcock & Wilcox dual-zone NOx ports added to each

side of the furnace approximately 20 ft below the boiler

roof. These ports injected up to 25% of the total combustion air through the furnace sidewalls.

Additional NOx

 control was achieved with the ureabased SNCR system. The SNCR when used with the

low-NOx

 combustion system would allow the goal of

70% NOx

 reduction to be reached. Further, the SNCR

system was an important part of the integrated system,

interacting synergistically with the dry sorbent injection

(DSI) system to reduce NO2

 formation and ammonia slip.

Initially the SNCR was designed and installed to

incorporate two levels of injectors with 10 injectors at

each level, with the exact location being based on temperature profiles that existed with the original combustion

system. However, the retrofit low-NOx

 combustion system resulted in a decrease in furnace exit gas temperature

by approximately 200 oF, thus moving one injector level

out of the temperature regime needed for effective SNCR

operation. With only one operational injector level, the

load-following performance was compromised.

In order to achieve the desirable NOx

 reduction at

low loads, two alternatives were explored. First, it was

shown that ammonia was more effective than urea at low

loads. An on-line urea-to-ammonia conversion system

was installed and resulted in improved low-load performance, but the improvement was not as large as desired

for the lowest load (60 MWe). The second approach was

to install injectors in the higher temperature regions of the

furnace. This was achieved by installing two NOELL

ARIL lances into the furnace through two unused

sootblower ports. Each lance was nominally 4 inches in

diameter and approximately 20 ft in length with a single

 84 I-Jet nozzles that can inject up to 80 gal/min into the

flue gas duct work.

Environmental Performance

The combined DRB-XCL® burner and minimum overfire

air reduced NOx

 emissions by over 63% under steadystate conditions and with carefully supervised operations.

Under load-following conditions, NOx

 emissions were

about 10–25% higher. At maximum overfire air (4% of

total combustion air), the low-NOx

 combustion system

reduced NOx

 emissions by 62–69% across the load range

(50–110 MWe). The results indicated 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 injectors

was in a region where the flue gas temperature was too

low for effective operation. At full load, the original

design achieved NOx

 reduction of 45%. However, the

performance decreased significantly as load decreased; at

60 MWe, NOx

 removal was limited to about 11% with an

ammonia slip of 10 ppm. The addition of the retractable

lances improved low-load performance of the urea-based

SNCR injection system. The ability to follow the temperature window by rotating the ARIL lances proved to

be an important feature in optimizing performance. As

a result, the SNCR system obtained NOx

 removal of

30–50%, at a NH3

 slip limited to 10 ppm at the fabric

filter inlet, thus increasing the total NOx

 control system

reduction to greater than 80%, significantly exceeding the

goal of 70%.

Testing of calcium hydroxide injection at the economizer without humidification resulted in SO2

 removal in

the range of 5–8% at a Ca/S molar ratio of 2.0. Higher

SO2

 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 approachto-saturation temperature of 20–30 oF. Sodium-based

reagents were found to be much more effective than

calcium-based sorbents and achieved significantly higher

SO2

 removals during dry injection. Sodium bicarbonate

Public Service Company of Colorado demonstrated lowNOx

 burners, induct injection, and SNCR at Arapahoe Station

near Denver.

row of nine injection nozzles. Each injection nozzle

consisted of a fixed air orifice and a replaceable liquid

orifice. The ability to change orifices allowed not only

for removal and cleaning but adjustment of the injection

pattern along the length of the lance in order to compensate for any significant maldistributions of flue gas velocity, temperature, or baseline NOx

 concentration. One of

the key features of the ARIL system was its ability to

rotate, thus providing a high degree of flexibility in optimizing SNCR performance.

The SO2

 control system was a DSI system that could

inject either calcium- or sodium-based reagents into the

flue gas upstream of the fabric filter. Sorbent was injected into three locations: (1) air heater exit where the

temperature was approximately 260 oF, (2) entrance of the

air heater where the temperature was approximately 600

oF, or (3) the boiler economizer region where the flue gas

temperature was approximately 1,000 oF. To improve SO2

removal with calcium hydroxide, a humidification system

capable of achieving 20 oF approach-to-saturation was

installed approximately 100 ft ahead of the fabric filter.

The system designed by Babcock & Wilcox included
1 2 3 4 1 2 3 4 1 2 3 4 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

Environmental Control Devices

*Projected date

3 4 1 2

 Program Update 1996-97 5-81

injection before the air heater demonstrated short-time

SO2

 removals of 80%. Long-term reductions of 70%

were achieved with an NSR of 1.0. Sodium sesquicarbonate achieved 70% removal at an NSR of 2.0 when

injected ahead of the fabric filter. A disadvantage of the

sodium-based process was that it converted some existing

NO to NO2

. Even though 5–10% of the NOx was reduced

during the conversion process, the net NO2

 exiting at the

stack was increased. While NO is colorless, small quantities of brown/orange NO2

 caused a visible plume.

A major objective was the demonstration of the

integrated performance of the NOx

 emissions control

systems and the SO2

 removal technologies. The results

showed that a synergistic benefit occurred during the

simultaneous operation of the SNCR and the sodium DSI

system in that the NH3

 slip from the SNCR process suppressed the NO2

 emissions associated with NO to NO2

oxidation by dry sodium injection.

Four series of air toxic tests were completed. Results

indicated that the fabric filter successfully removed nearly

all trace metal emissions and nearly 80% of the mercury

emissions. Radionuclides, semi-volatile organic compounds, and dioxins/furans were below or very near their

detectable limits.

Operating Performance

Construction began in July 1991 and was completed in

August 1992. The test program began in August 1992

and was scheduled for completion in June 1994. However, the addition of the new SNCR injection location and

alternative lance design tests extended the test program

through December 1996. The Arapahoe Unit 4 operated

more than 34,000 hours after combustion modifications

were completed. The availability factor during the period

was over 91%.

The operational test objectives were met or exceeded. However, there were operational lessons learned

during the demonstration that will be useful in future

deployment of the technologies. These “lessons” are

summarized below.

It was found that control system modifications and

additional operator training may be necessary to more

accurately control NOx

 reductions using low-NOx burners

under load-following conditions.

During the operation of the duct injection of calcium

hydroxide and humidification under 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 approach-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 Babcock & Wilcox) was tested and found to have less bending due to evaporative cooling, even though its NOx

 reduction and NH3

 slip performance were slightly less than

for the ARIL lance.

When the SNCR and dry sodium systems were operated concurrently, an NH3 odor problem was encountered

around the ash silo. Reducing the NH3

 slip set points to

the range of 4–5 ppm reduced the ammonia 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 handling. 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 Control 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) 571-1113

Public Service Company of Colorado

550 15th Street, Suite 880

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.” Fifth Annual Clean Coal Technology Conference: Technical

Papers. January 1997.

• 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 NTIS

as DE91008624.)
5-82 Program Update 1996-97 Advanced Electric Power Generation

Advanced Electric Power

Generation Technology

Advanced electric power generating systems

employ the technologies that enable the efficient and

environmentally superior generation of electric power.

The advanced electric power generation projects

selected under the CCT Program are responsive to the

long-term capacity expansion needs requisite to

meeting long-term demand and offseting nuclear

retirements and to the stringent CAAA emission

limits effective in 2000. These technologies are

characterized by high thermal efficiency, very low

pollutant emissions, reduced CO2

 emissions, few

solid waste problems, and enhanced economics.

Advanced electric power generation systems may be

deployed in modules, allowing phased construction to

match demand growth more predictably and to meet

the requirements of smaller municipal, rural, and

nonutility generators.

There are five generic technology approaches

being used to demonstrate advanced electric power

generation systems under the CCT Program. The

characteristics of these five technologies are outlined

here, and the specific projects and technologies are

presented in more detail in the fact sheets. A sixth

generic technology project, externally fired combined-cycle, was selected as part of the CCT-V

solicitation. Even though this project ended in May

1997, its fact sheet is included for completeness.

Fluidized-Bed Combustion

Fluidized-bed combustion (FBC) reduces

emissions of SO2 and NOx by controlling combustion

parameters and by injecting a sorbent (such as

crushed limestone) into the combustion chamber

along with the coal. Pulverized coal mixed with the

limestone is fluidized on jets of air in the combustion

chamber. Sulfur released from the coal as SO2

 is

captured by the sorbent in the bed to form a solid

calcium compound that is removed with the ash. The

resultant waste is a dry, benign solid that can be

disposed of easily or used in agricultural or construction applications. More than 90 percent of the SO2

released can be captured this way.

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

the fluidized mixing of the fuel and sorbent enhances

both combustion and sulfur capture. The operating

temperature range is about half that of a conventional

boiler and below the temperature which thermally

induced NOx

 is formed. In fact, fluidized-bed NOx

emissions are about 70–80 percent lower than those

for at conventional pulverized coal boilers. Thus,

fluidized-bed combustors substantially reduce both

SO2

 and NOx emissions. Also, fluidized-bed combustion has the capability of utilizing high-ash coal,

whereas conventional pulverized coal units must

limit ash content to relatively low levels.

Two parallel paths were pursued in fluidized-bed

development—bubbling and circulating beds.

Bubbling beds use a dense fluid bed and low fluidization velocity to effect good heat transfer and mitigate

erosion of an in-bed heat exchanger. Circulating

fluidized beds use a relatively high fluidization

velocity (entrained bed) in conjunction with hot

cyclones to separate and recirculate the particulate

from the flue gas before it passes to a heat exchanger.

Hybrid systems have since evolved from these two

basic approaches.

Fluidized-bed combustion can be either atmospheric (AFBC) or pressurized (PFBC). AFBC

operates at atmospheric pressure while PFBC

operates at pressure 6–16 times higher. PFBC offers

potentially higher efficiency and, consequently,

reduced operating costs and waste relative to AFBC.

Second-generation PFBC integrates the combustor with a pyrolyzer (coal gasifier) to fuel a gas

turbine (topping cycle), the waste heat from which is

used to generate steam for a steam turbine (bottoming cycle). The inherent efficiency of the gas turbine

and waste heat recovery in this combined-cycle mode

significantly increases overall efficiency. Such

advanced PFBC systems have the potential for

efficiencies of over 50 percent. Tri-State Generation and Transmission Association’s

Nucla Station was host to demonstration of the world’s first

utility-scale AFBC.
Advanced Electric Power Generation Program Update 1996-97 5-83

Integrated Gasification Combined Cycle

The integratd coal gasification combined-cycle

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

by coal reacting with high-temperature steam and an

oxidant (oxygen or air) in a reducing atmosphere;

(2) gas is either passed directly to a hot-gas cleanup

system to remove particulates and sulfur and nitrogen

compounds or first cooled to produce steam and then

cleaned conventionally; (3) clean fuel gas is combusted in a gas turbine generator to produce electricity;

and (4) residual heat in the hot exhaust gas from the

turbine is recovered in a heat recovery steam generator, and the steam is used to produce additional

electricity in a steam turbine generator.

Integrated gasification combined-cycle (IGCC)

systems are among the cleanest and most efficient of

the emerging clean coal technologies. Sulfur,

nitrogen compounds, and particulates are removed

before the fuel is burned in the gas turbine, that is,

before combustion air is added. For this reason, there

is a much lower volume of gas to be treated than in a

postcombustion scrubber.

The gas stream must be cleaned to a high degree,

not only to achieve low emissions, but to protect

downstream components, such as the gas turbine, from

erosion and corrosion. In a coal gasifier, the sulfur in

the coal is released in the form of hydrogen sulfide

rather than as SO2

, which is the case in coal combustion. In some IGCC systems, much of the sulfurcontaining gas is captured by a sorbent injected into

the gasifier. Others use existing commercial hydrogen

sulfide removal processes, which remove up to

99 percent of the sulfur but require the fuel to be

cooled, with some efficiency penalty. Therefore, hotgas cleanup systems are being demonstrated. In these

cleanup systems, the hot coal gas is passed through a

bed of metal oxide particles, such as supported zinc

oxides. Zinc oxide can absorb sulfur contaminants at

temperatures in excess of 1,000 oF, and the compound can be regenerated and reused with little loss

of effectiveness. Produced during the regeneration

stage are salable sulfur, sulfuric acid, or sulfurcontaining solid waste, which may be used to produce

useful by-products, such as gypsum. The technique is

capable of removing more than 99.9 percent of the

sulfur in the gas stream. With hot-gas cleanup, IGCC

systems have the potential for efficiencies of over

50 percent.

High levels of nitrogen removal are also possible. Some of the coal’s nitrogen is converted to

ammonia, which can be almost totally removed by

commercially available chemical processes. NOx

formed by the combustion air can be held to well

within allowable levels by staged combustion in the

turbine or by adding moisture to hold down flame

temperature.

Integrated Gasification Fuel Cell

A typical fuel cell system using coal as fuel

includes a coal gasifier with a gas cleanup system, a

fuel cell to use the coal gas to generate electricity

(direct current) and heat, an inverter to convert direct

current to alternating current, and a heat-recovery

system. The heat-recovery system would be used to

produce additional electric power in a bottoming

steam cycle.

Energy conversion in fuel cells is potentially

more efficient (up to 60 percent, depending on fuel

and type of fuel cell) than traditional energy conversion devices. Fuel cells directly transform the

chemical energy of a fuel and an oxidant (air or

oxygen) into electrical energy instead of going

through an intermediate step (i.e., burner, boiler,

turbines, and generators). Each fuel cell includes an

anode and a cathode separated by an electrolyte layer.

In a typical fuel cell, coal gas is supplied to the anode

and air is supplied to the cathode to produce electricity and heat.

Coal-Fired Diesel

The diesel-engine-driven electric generation

system is fueled with a coal-oil or coal-water slurry.

The hot exhaust from the diesel engine is routed

Tampa Electric Company’s Polk Power Station Unit 1,

a 250-MWe IGCC greenfield installation, is currently in

operation. It is one of the world’s cleanest and most

advanced coal power plants.
5-84 Program Update 1996-97 Advanced Electric Power Generation

through a heat-recovery unit to produce steam for a

steam-turbine electric generating system (combined

cycle). Environmental control systems for SO2

, NOx,

and particulate removal treat the cooled exhaust

before release to the atmosphere. The diesel system is

expected to achieve 45–48 percent thermal efficiencies. The 10–100-MWe capacity range of the technology would be most applicable to small utilities

(municipalities and rural cooperatives) and industrial

cogeneration.

Slagging Combustor

Many new coal-burning technologies are designed to remove the coal ash as molten slag in the

combustor rather than the furnace. Most of these

slagging combustors are based on a cyclone combustor concept. In a cyclone combustor, coal is burned in

a separate chamber outside the furnace cavity. The

hot combustion gases then pass into the boiler where

the actual heat exchange takes place.

The advantage of a cyclone combustor is that the

ash is kept out of the furnace cavity where it could

collect on boiler tubes and lower heat transfer

efficiency. To keep ash from being blown into the

furnace, the combustion temperature is kept so hot

that mineral impurities melt and form slag, hence the

name slagging combustor. A vortex of air (the

cyclone) forces the slag to the outer walls of the

combustor where it can be removed as waste. Because

ash removal efficiency is high, there is no degradation

of boiler tube surfaces to reduce boiler efficiency over

time.

Results to date show that by positioning air

injection ports so that coal is combusted in stages,

NOx

 emissions can be reduced by 70–80 percent.

Injecting limestone into the combustion chamber has

the potential to reduce sulfur emissions by 90 percent

in combination with a spray-dryer absorber. Advanced

slagging combustors could replace oil-fired units in

both utility and industrial applications or be used to

retrofit older, conventional cyclone boilers.

Status of Projects

There are 11 advanced electric power generating

projects in the CCT Program of which five are

fluidized-bed combustion systems, four are IGCCs,

and two are advanced combustion/heat engine

systems (coal diesel and advanced slagging combustor). Of the five fluidized-bed combustion projects,

two have successfully completed demonstration (one

PFBC and one AFBC), and the other three are in the

project definition and design phase. Of the four

IGCC projects, three are in operation and one is in

the project definition and design phase. Of the two

remaining advanced combustion/heat engine

projects, the advanced slagging combustor project is

in the last stages of construction, and the coal diesel

project is in the project definition and design phase.

Exhibit 5-29 summarizes the process characteristics and size of the advanced electric power

generating technologies presented in more detail in

the project fact sheets.

Golden Valley Electric Association is adding capacity to

its Healy Plant with a 50-MWe slagging combustor unit

using 65% waste coal.
Advanced Electric Power Generation Program Update 1996-97 5-85

Exhibit 5-29

CCT Program Advanced Electric Power Generation Technology Characteristics

Project Process Size Fact Sheet

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project Pressurized circulating fluidized-bed combustion 157 MWe 5-86

McIntosh Unit 4B Topped PCFB McIntosh 4A with pyrolyzer and topping combustor 157 MWe + 12 MWe 5-88

Demonstration Project

Tidd PFBC Demonstration Project Pressurized bubbling fluidized-bed combustion 70 MWe 5-90

ACFB Demonstration Project Atmospheric circulating fluidized-bed combustion 250 MWe 5-94

Nucla CFB Demonstration Project Atmospheric circulating fluidized-bed combustion 100 MWe 5-96

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project Oxygen-blown, slagging fixed-bed gasifier with cold 477 MWe 5-100

gas cleanup, fuel cell slipstream

Piñon Pine IGCC Power Project Air-blown, fluidized-bed gasifier with hot gas cleanup 99 MWe 5-102

Tampa Electric Integrated Gasification Oxygen-blown, entrained-flow gasifier with hot and 250 MWe 5-104

Combined-Cycle Project cold gas cleanup

Wabash River Coal Gasification Oxygen-blown, two-stage entrained-flow gasifier with 262 MWe 5-106

Repowering Project cold gas cleanup

Advanced Combustion/Heat Engines

Healy Clean Coal Project Advanced slagging combustor, spray dryer with sorbent 50 MWe 5-108

recycle

Clean Coal Diesel Demonstration Project Coal-fueled diesel engine 4.2 MWe 5-110

Externally Fired Combined-Cycle Externally fired combined-cycle system 5.0 MWe 5-112

Demonstration Project (slipstream)
5-86 Program Update 1996-97 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB

Demonstration Project

Participant

City of Lakeland, Department of Electric & Water

Utilities

Additional Team Members

Foster Wheeler Energy Corp.—supplier of hightemperature combustor and heat exchanger; engineer

Westinghouse Electric Corporation—supplier of PCFB,

hot gas filter, gas turbine, and steam turbine

Location

Lakeland, Polk County, FL (Lakeland’s McIntosh Power

Station, Unit 4)

Technology

Foster Wheeler’s PCFB technology integrated with

Westinghouse’s hot gas filter and power generation

technologies

Plant Capacity/Production

157 MWe (net)

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 Westinghouse’s hot gas filter 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. The project’s pressurized fluidized-bed

combustor will also serve for demonstrating the integration of a gasifier and topping combustor (topping cycle)

with the PCFB technology. This integration will be demonstrated in the McIntosh Unit 4B Topped PCFB Demonstration Project.

Coal and limestone are mixed with water to form a

paste, which is pumped into the combustion chamber by

piston pumps commonly used in the cement industry.

Combustion takes place at approximately 1,560–1,600 °F

at a pressure of about 200 psig. The resulting flue gas

and fly ash leaving the combustor pass through a cyclone

and hot gas filter where the particulates are removed. The

hot gas leaving the filter is expanded through a gas turbine, which is based on a standard Westinghouse 251B12,

single-shaft, cold-end-drive industrial machine. The gas

inlet temperature of less than 1,650 °F allows for a simplified turbine shaft and blade-cooling system. The hot

gas leaving the gas turbine passes through a heat recovery

unit used to generate steam. Heat recovered from both

the combustor and heat recovery unit is used to generate

steam to power a reheat steam turbine. Approximately

15% of the gross power is derived from the gas turbine,

with the steam turbine contributing the remaining 85%.

The unit is being designed to burn a range of coals,

including the current Eastern Kentucky coal burned in

Unit 3 and high-ash, high-sulfur coals that are expected to

be available at a lower cost. Limestone will be purchased

from nearby Florida quarries. Ash will be disposed of in

landfills or sold to others.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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 Program Update 1996-97 5-87

Project Status/Accomplishments

Approval by all participants of the transfer of the cooperative agreement to the City of Lakeland, Department of

Electric & Water Utilities, is expected to be completed in

late fiscal year 1997. The project schedule anticipates the

start of commercial operation of the PCFB (McIntosh 4A)

in the winter of 2001. In parallel with the first 2 years of

operation of the PCFB will be the design, fabrication, and

construction of the topped PCFB technology (McIntosh

4B), with a planned start of operation in late 2003.

Commercial Applications

The project serves as a stepping stone to move the PCFB

technology to readiness for widespread commercial deployment in the post-2000 time frame. The project will

include the first commercial applications of hot-gas particulate cleanup and one of the first to use a nonruggedized 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 bubbling-bed PCFB

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 match load growth

and/or to repower plants using existing coal- and wastehandling 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 8,100 Btu/kWh (based on HHV), which equates to

over 42% efficiency.

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.

1991 1999 2000 1997 1998 2001 2002 2003 2004 2005 2006

12/89

DOE selected project

(CCT-III) 12/19/89

Cooperative agreement

awarded 8/1/91

11/01 11/03

**

**Years omitted

Design and Construction

Design initiated 11/97*

Operation

Groundbreaking/construction

started 9/99*

Design completed 9/99*

NEPA process completed

(EIS) 10/99*

Environmental monitoring plan

completed 8/01*

8/91

Operation initiated 11/01*

Preoperational tests initiated 11/01*

Construction completed 11/01* Project completed/

final report issued 11/03*

Operation completed 11/03*

Novation to Lakeland approved

10/97*

Preaward
5-88 Program Update 1996-97 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4B Topped PCFB

Demonstration Project

Participant

City of Lakeland, Department of Electric & Water

Utilities

Additional Team Members

Foster Wheeler Energy Corp.—supplier of carbonizer;

engineer

Westinghouse Electric Corporation—supplier of topping

combustor and high-temperature filter

Location

Lakeland, Polk County, FL (Lakeland’s McIntosh Power

Station, Unit 4)

Technology

Fully integrated second-generation PCFB technology with

the addition of a carbonizer island that includes

Westinghouse’s multi-annular swirl-burner (MASB)

topping combustor

Plant Capacity/Production

12 MWe (net) addition to the 157 MWe (net) McIntosh

4A project

Project Funding

Total project cost $218,741,300 100%

DOE 109,204,000 50

Participant 109,537,300 50

Project Objective

To demonstrate topped PCFB technology in a fully commercial power generating setting, thereby advancing the

technology for future plants that will operate at higher gas

turbine inlet temperatures and that 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 gasifier and topping combustor

(topping cycle) with the PCFB technology. By utilizing a

segmented approach, Lakeland will be able to demonstrate both PCFB (McIntosh 4A) and topped PCFB

(McIntosh 4B) technologies.

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 together with part of the gas

turbine discharge air. The coal is partially gasified at

about 1,700 °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 filter.

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 2,000 °F. The gas is expanded through the turbine, cooled in a heat recovery

unit, and exhausted to the stack. The net impact of the

addition of the topping cycle is an increase in power

output of 12 MWe and an associated improvement in

plant heat rate of approximately 600 Btu/kWh. 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

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*Projected date

Advanced Electric Power Generation Program Update 1996-97 5-89

ate 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. Other

environmental attributes 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 dry,

readily disposable, and potentially usable material.

1994 1999 2000 1997 1998 2001 2002 2003 2004 2005 2006

5/93

DOE selected project

(CCT-V) 5/4/93

Cooperative agreement

awarded 7/28/94; effective

8/1/94

Design and Construction

11/03 11/05

Project completed/

final report issued 11/05*

Novation to Lakeland approved 10/97* Operation completed 11/05*

**

**Years omitted

Operation

NEPA process completed (EIS) 10/99*

Design initiated 11/01*

Groundbreaking/construction started 9/02*

Design completed 9/02*

Operation initiated 11/03*

Preoperational tests initiated 11/03*

Construction completed 11/03*

Environmental monitoring plan completed 8/03*

8/94

Preaward

Project Status/Accomplishments

Approval by all participants of the transfer of the cooperative agreement to the City of Lakeland, Department of

Electric & Water Utilities, is expected to be completed in

late fiscal year 1997. The project schedule anticipates the

start of commercial operation of the PCFB (McIntosh 4A)

in the winter of 2001. In parallel with the first 2 years of

operation of the PCFB will be the design, fabrication, and

construction of the topped PCFB technology

(McIntosh 4B), with a planned start of operation in late

2003.

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, based

on 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 emission limits that are half those allowed by NSPS, (3) oper-
5-90 Program Update 1996-97 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 1)

Technology

The Babcock & Wilcox Company’s pressurized fluidizedbed combustion (PFBC) system (under license from ABB

Carbon)

Plant Capacity/Production

70 MWe

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 and one of only five worldwide. The boiler, cyclones, bed reinjection vessels, and

associated hardware were encapsulated in a pressure

vessel 45 ft in diameter and 70 ft high. The facility was

designed so that one-seventh of the hot gases produced

could be routed to a slipstream to test advanced filtration

devices.

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 coal-water

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 by-product.

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.
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Advanced Electric Power Generation Program Update 1996-97 5-91

Results Summary

Environmental

• SO2 removal efficiency of 90% was achieved at full

load with a calcium-to-sulfur molar ratio (Ca/S) of 1.1

and temperature of 1,580 oF.

• SO2

 removal efficiency of 95% was achieved at full

load with a Ca/S 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 was 99.6%.

• Heat rate was 10,280 Btu/kWh based on higher heating value of the fuel and gross electrical output, or

33.2% efficiency, because of the small-scale retrofit

application.

• High-temperature particulate filtration system, 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

Because the Tidd plant was a comparatively small-scale

facility, economic performance would not be representative of a larger utility-scale plant using PFBC technology.

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

feed lines, supplied from two lock hoppers. An alterna1986 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
5-92 Program Update 1996-97 Advanced Electric Power Generation

tive sorbent feed system was added in 1993, which provided the capability of injecting sorbent of various sizes

directly into the coal-water paste feed system. The system

provided the means to assess a wet-feed sorbent system

while providing the opportunity to better control sorbent

size.

In 1992, a 10-MWe advanced hot gas cleanup system

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

cyclones that was normally used for final gas cleanup.

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 1.1 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

proved ineffective as a sorbent, 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).

Sintering of fluidized-bed 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, post-bed combustion and

sintering were effectively eliminated.

The process demonstrated NOx emissions in the range of 0.15–0.33 lb/106

 Btu.

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

main- tenance. While the tube bundle was in good condition, a significant amount of erosion on each of the four

water walls was observed. While no operational failure

occurred during the demonstration, remedial action, such

as the use of refractory coatings utilized successfully on

two commercial PFBC units, was deemed to be warranted.

The gas turbine experienced both structural and

erosion 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 problems. The Tidd demonstration showed that a gas turbine

The PFBC demonstration at the repowered 70-MWe unit at Ohio

Power’s Tidd Plant led to significant refinements and understanding of the

technology.

could operate in a PFBC flue gas environment, and it was

concluded that erosion was manageable with a scheduled

maintenance program.

The efficiency of the PFBC combustion process was

calculated during the testing from the amount of unburned carbon in the cyclone ash and bed ash together

with the measurements of the amount of carbon monoxide in the flue gas. Tests showed combustion efficiencies

of 99.6%, 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
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Advanced Electric Power Generation Program Update 1996-97 5-93

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 PFBC Demonstration Project

showed that the PFBC system could be applied to electric

power generation. Further, the demonstration project led

to significant refinements and understanding of the technology in the areas of turbine erosion, sorbent utilization,

sintering, post-bed combustion, and boiler materials.

Testing of advanced ceramic candle filtration elements on a slipstream of one-seventh of the exhaust gases

for over 5,800 hours of coal-fired operation showed that

the design of the particulate filter was structurally adequate. However, results also showed that clay-bonded

silicon carbide lost 50% of its strength after 1,000–2,000

hours of exposure and that a buildup of ash in the filter

vessel caused breakage of the candles. The filter operated

at a pressure drop on the order of 100 inches of water

column and a filtration efficiency (mass basis) of 99.99%.

Economic Performance

Because the Tidd plant was a comparatively small-scale

facility, economic performance would not be representative of a larger utility-scale plant using PFBC technology.

Commercial Applications

Combined-cycle PFBC permits use of a wide range of

coals, including high-sulfur coals. Bubbling PFBC technology, along with other advanced technologies, will

compete with circulating PFBC systems to repower or

replace conventional power plants. 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. 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 environmental attributes of a mature system

include in-situ sulfur removal of 95% and NOx

 emission

levels less than 0.1 lb/106

 Btu. Although the system

generates slightly more solid waste compared to conventional systems, the dry material is either readily disposable or potentially usable.

Contacts

Mario Marrocco, (614) 223-2460

American Electric Power Service Corporation

1 Riverside Plaza

Columbus, OH 43215

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.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Tidd PFBC Demonstration

Project. The Ohio Power Company. Report No.

DOE/FE-0078. U.S. Department of Energy. February

1987. (Available from NTIS as DE87005803.)

Coal and sorbent conveyors can be seen just after

entering the Tidd Plant.
5-94 Program Update 1996-97 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

ACFB Demonstration Project

Participant

York County Energy Partners, L.P.

Additional Team Member

Foster Wheeler Energy Corp.—technology supplier

Location

To be determined

Technology

Foster Wheeler’s atmospheric circulating fluidized-bed

(ACFB) combustor

Plant Capacity/Production

235 MWe (net)

Project Funding

Total project cost $379,645,000 100%

DOE 74,733,833 20

Participant 304,911,167 80

Project Objective

To demonstrate ACFB at 235 MWe, representing a scaleup from previously constructed facilities; to verify expectations of the technology’s economic, environmental,

and technical performance to provide utility and

nonutility power producers 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.

placed downstream of the cyclone particulate separator to

protect against erosion. The steam is then used to produce power in a conventional steam cycle.

The heat rate for this cogeneration plant is expected

to be 9,200 Btu/kWh (37% efficiency). SO2

 emissions

are expected to be below 0.24 lb/106

 Btu. This technology operates at lower temperatures than conventional

boilers, thus reducing NOx

 formation.

Technology/Project Description

In this project, the circulating fluidized-bed combustor

operates at atmospheric pressure. Coal and coal-refuse

fuels, primary air, and a solid sorbent, such as limestone,

are introduced into the lower portion of the combustor

where initial combustion occurs. As coal particles decrease in size due to combustion and breakage, they are

carried higher in the combustor to an area where 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 particle

separator, and recycled to the lower portion of the combustor. The sorbent in the bed removes sulfur during the

combustion process, eliminating the need for scrubbers.

Steam is generated in tubes placed along the

combustor’s walls and superheated in tube bundles
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Advanced Electric Power Generation Program Update 1996-97 5-95

Project Status/Accomplishments

All activities have been put on hold while resiting of the

project is considered. On September 26, 1995, York

County Energy Partners and Metropolitan Edison Company announced their joint decision to restructure the

power-purchase agreement, thus removing York County

as a site for this project.

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 coal-fired boiler 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 1996 1997 1998 1999 2000

Preaward

6/89

Design

11/90

2001 ** **

Cooperative agreement

awarded 11/30/90

Project restructured 6/92

Project resited

(York) 6/93

**Years omitted

DOE selected

project (CCT-I)

6/23/89

NEPA process completed (EIS; York site) 8/11/95

Note: Milestone schedule pending project restructuring

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.
5-96 Program Update 1996-97 Advanced Electric Power Generation

baghouse where the particulate matter is removed. The

steam generated in the ACFB is used to generate 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.

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

 gases 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 sorbent 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. The flue gas passes through a

Advanced 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 Corp.—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)

Coals

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

Project Objective

To demonstrate the feasibility of ACFB technology at

utility scale and to evaluate the economic environmental,

and operational performance at that scale.
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Advanced Electric Power Generation Program Update 1996-97 5-97

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 varied between 70 and 140 ppmv.

• Particulate emissions ranged from 0.0072 to 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.

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

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

 generation

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 bed, which

dictates a low-fluidization velocity, ACFB uses a relatively high fluidization velocity, creating a more turbulent

bed. 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) in the project involved

evaluating ACFB potential for broad utility application

through a comprehensive test program. Over a 21

/2-year

Operation

completed 1/91

Operation test program initiated 8/88

Cooperative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92
5-98 Program Update 1996-97 Advanced Electric Power Generation

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 overcome. During the last 3 months of the demonstration,

average availability was 97% and the capacity factor,

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 5-30 shows the effect of bed temperatures on the Ca/S requirement for 70% sulfur retention. Ca/S 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 of about 1.5

was sufficient to achieve 70% sulfur retention in the

1,500 °F to 1,620 °F range, the Ca/S requirement

jumped to 5.0 or more at 1,700 °F or greater.

Exhibit 5-31 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 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 °F to

240 ppmv (0.34 lb/106

 Btu) at 1,700 °F.

Limestone feed rate was also identified as a

variable affecting NOx

 emissions, i.e., somewhat higher NOx

 emissions resulted from

increasing calcium-to-nitrogen (Ca/N) ratios.

The mechanism was believed to be oxidation

Exhibit 5-30

 Effect of Bed Temperature

on Ca/S Requirement

Exhibit 5-31

Calcium Requirements and

Sulfur Retentions for Various Fuels
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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

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Advanced Electric Power Generation Program Update 1996-97 5-99

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.

Economic Performance

The final capital costs associated with

the engineering, construction, and

start-up of the Nucla ACFB system were $112.3 million.

This represents a cost of $1,123/net kW. 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%), nonfuel expenses (6.8%), and maintenance expenses (5.5%).

Commercial Applications

ACFB could play a role in near-term electric power generation markets, in which the Energy Information Administration estimates that 4 GWe of new coal-based capacity

will be needed between 1996 and 2000 to replace retiring

utility units. In the post-2000 time frame, ACFB will be

well positioned to compete for the estimated 32 GWe of

additional coal-based power generation and cogeneration

needed between 2000 and 2015. The international power

generation market is expected to substantially overshadow the domestic market, particularly in the nearterm, and the attributes of ACFB make it particularly

suitable for worldwide deployment.

Contacts

Marshall L. Pendergrass, Assistant General Manager

(303) 249-4501

Tri-State Generation and Transmission Association,

Inc.

P.O. Box 1149

Montrose, CO 81402

George Lynch, DOE/HQ, (301) 903-9434

Nelson F. Rekos, FETC, (304) 285-4066

References

• “Field Study of Wastes from Fluidized Bed Combustion Technologies.” Andrew Weinberg, Larry

Holcomb, and Ray Butler. 1991 11th International

Conference on Fluidized Bed Combustion—Volume 2,

page 865. Available from American Society of Mechanical Engineers.

• 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.)

• Clean Coal Reference Plants: Atmospheric CFB (Topical Report, Task 1). Report No. DOE/MC/25177-3307.

Gilbert/Commonwealth, Inc. June 1992. (Available

from NTIS as DE93000251.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Nucla CFB Demonstration

Project. (Colorado-Ute Electric Association, Inc.).

Report No. DOE/FE-0106. U.S. Department of Energy. July 1988.

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.
5-100 Program Update 1996-97 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.; Makowski Clean Energy

Investors, Inc.; British Gas Americas, Inc.; and an affiliate of the General Electric Company)

Additional Team Members

Duke Engineering & Services, Inc.—engineer and

constructor

General Electric Company—power island designer and

supplier

British Gas Americas, Inc., affiliate in conjunction with

Lurgi Energie and Umwelt GmbH—gasification

island designer

Fuel Cell Engineering Corporation—molten carbonate

fuel cell designer and supplier; cofunder

Electric Power Research Institute—cofunder

National Rural Electric Cooperative Association—

cofunder

Deutsche Aerospace AG—cofunder

Location

An east coast site

Technology

Integrated gasification combined-cycle (IGCC) using

British Gas/Lurgi (BG/L) slagging fixed-bed gasification

system coupled with Fuel Cell Engineering’s molten

carbonate fuel cell (MCFC)

Plant Capacity/Production

477-MWe (net) IGCC; 1.25-MWe MCFC

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 highsulfur bituminous coal in an oxygen-blown, fixed-bed,

slagging gasifier and the operability of a molten carbonate fuel cell fueled by coal gas, by an independent power

producer under commercial terms and conditions.

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 to produce a raw coal gas rich in hydrogen and

carbon monoxide. Raw coal gas exiting the gasifier is

washed and cooled. Hydrogen sulfide and other sulfur

compounds are removed. Elemental sulfur is reclaimed

and disposed of as a by-product. Tars, oils, and dust are

recycled to the gasifier. The resulting clean, medium-Btu

fuel gas is used to fuel the gas turbine in the IGCC power

island. A small portion of the clean 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 gas) and

steam are fed continuously 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

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Advanced Electric Power Generation Program Update 1996-97 5-101

1993 1996 1997 1994 1995 1998 1999 2000 2001 2002 2003

Preaward

5/93

DOE selected project

(CCT-V) 5/4/93

The project is demonstrating the use of eastern U.S.

bituminous coal in a commercial-scale IGCC system and

integrated MMCFC module.

Project Status/Accomplishments

The cooperative agreement was awarded December 2,

1994. The participant is looking for an east coast site.

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

of the system are competitive with or superior to other

fossil-fuel-fired power generation technologies.

12/94

Cooperative agreement

awarded 12/2/94

Design

Note: Milestone schedule pending project restructuring

The heat rate of the IGCC demonstration facility is

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.
5-102 Program Update 1996-97 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

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

99 MWe (net)

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

long-term 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

a pressurized, air-blown, fluidized-bed gasifier. Crushed

limestone is used to capture a portion of the sulfur and to

inhibit conversion of fuel nitrogen to ammonia. 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.

Hot, 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 metal oxide sorbent in

a transport reactor.

The hot, cleaned gas then enters the GE Model

MS6001FA combustion turbine, which is coupled to a

generator designed to produce 61 MWe (gross). Exhaust

gas is used to produce steam in a heat recovery steam

generator. Superheated high-pressure steam drives a

condensing steam turbine-generator designed to produce

about 46 MWe (gross).

Due to the relatively low operating temperature of the

gasifier and the injection of steam into the combustion

fuel stream, the NOx

 emissions are 0.069 lb/106 Btu (94%

reduction). Due to the combination of in-bed sulfur capture and hot gas cleanup, SO2

 emissions are 0.069 lb/106

Btu (90% reduction).
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

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Advanced Electric Power Generation Program Update 1996-97 5-103

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

Commercial Applications

The Piñon Pine IGCC system concept is suitable for new

power generation, repowering needs, and cogeneration

applications. The net effective heat rate for a proposed

greenfield plant using this technology is projected to be

7,800 Btu/kWh (43.7% efficiency), representing a 20%

increase in thermal efficiency as compared to a conventional pulverized coal plant with a scrubber and a comparable reduction in CO2

 emissions. The compactness of a

IGCC system reduces space requirements per unit of

energy generated relative to other coal-based power

generation systems, and the advantages provided by

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 and high-swelling coals, as well as bio- or refuse-derived waste, with

minimal environmental impact. This versatility provides

numerous economic advantages for the depressed mineral extraction and cleanup industries. There are no

In the demonstration project, 880 tons/day of coal are

converted into 107 MWe (gross), or 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 integrated gasification system is located at Sierra Pacific Power Company’s

Tracy Station, near Reno, NV.

Project Status/Accomplishments

Construction activities, which began in early 1995, were

completed in February 1997. Start-up efforts began during the second half of 1996 and continued through June

1997. The GE Frame 6FA (Model MS6001FA) combustion turbine at the unit is the first of its kind in the world

and was successfully fired for the first time on August 15,

1996, using natural gas. The combined-cycle part of the

plant began commercial operation on natural gas in November 1996.

Environmental monitoring plan

completed 10/31/96

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.

Preoperational tests initiated 12/96

2/97

Operation initiated 2/97

Construction completed 2/97
5-104 Program Update 1996-97 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 Company—combined-cycle technology

supplier

G.E. Environmental Systems—hot-gas cleanup

technology supplier

TECO Power Services, Inc.—project manager and

marketer

Bechtel Power Corporation—architect and engineer

Location

Mulberry, Polk County, FL (Tampa Electric Company’s

Polk Power Station, Unit 1)

Technology

Integrated gasification combined-cycle (IGCC) system

using Texaco’s pressurized, oxygen-blown, entrainedflow gasifier technology and incorporating both conventional, low-temperature acid-gas removal and hot-gas

moving-bed desulfurization

Plant Capacity/Production

250 MWe (net)

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. Coal/

water slurry and oxygen are reacted at high temperature

and pressure to produce a high-temperature syngas.

Molten coal-ash flows out of the bottom of the vessel

and into a water-filled quench tank where it is turned

into a solid slag. The syngas from the gasifier moves to

a high-temperature heat-recovery unit which cools the

gases.

The cooled gases flow to a particulate-removal

section before entering gas-cleanup trains. A portion of

the syngas is passed through a moving bed of metal

oxide absorbent to remove sulfur. The remaining syngas

is further cooled through a series of 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. A GE MS 7001F gas turbine

generates about 192 MWe (gross). Thermally generated

NOx

 is controlled to below 0.27 lb/106 Btu by injecting
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

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Advanced Electric Power Generation Program Update 1996-97 5-105

nitrogen as a dilutent in the turbine’s combustion section.

A heat-recovery steam-generator uses heat from the gasturbine exhaust to produce high-pressure steam. This

steam, along with the steam generated in the gasification

process, is routed to the steam turbine to generate an

additional 121 MWe (gross). The 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. Being used in the demonstration are Illinois 6 and Pittsburgh 8 bituminous coals having sulfur

contents ranging 2.5–3.5%.

By-products from the process—sulfuric acid and

slag—can be sold commercially. Sulfuric acid by-products can be used as a raw material to make agricultural

fertilizer and the nonleachable slag used in roofing

shingles and asphalt roads and as a structural fill in construction projects.

1988 1989 1990 1991 1994 1995 1996 1997 1998 1999 2000

Preaward Design and Construction

12/89 3/91

Project Status/Accomplishments

The first syngas was produced on July 19, 1996. The

first gasifier run lasted 21.5 hours, which set the longevity record for first fire on a solid-fuel Texaco gasifier.

Ten gasifier runs totalling 174 hours were completed by

the end of September. All plant systems had been successfully commissioned, so Unit 1 was placed in commercial operation on September 30, 1996.

Another 10 gasifier runs totaling 701 hours were

made in October and November 1996, prior to a planned

outage, which began December 5 for routine maintenance, inspection, and some minor improvements. In the

30 days preceding the outage, the gasifier was on-line

67% of the time and the gas turbine was on 100% syngas

fuel 59% of the time, exceeding target expectations for

this period. Efforts in late 1996 were geared toward

keeping the unit on line as much as possible to obtain

operating experience. During December 1996 and January 1997, the combined-cycle system operated for 40 out

of 45 days, while achieving a maximum load of

310 MWe (gross) on clean syngas. Efforts in 1997 are

**

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 10/96

10/96

*Projected date

**Years omitted

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

focusing on improving the unit’s reliability, reducing

operating costs, improving heat rate, commissioning the

hot gas cleanup system, and beginning alternate coal

testing. The unit was dedicated on January 10, 1997.

The project was presented the 1997 Powerplant Award by

Power magazine.

Commercial Applications

The IGCC system being demonstrated in this project is

suitable for new electric power generation, repowering

needs, and cogeneration applications. The net effective

heat rate for the Texaco-based IGCC is expected to be

below 8,500 Btu/kWh, which makes it very attractive for

baseload applications. Commercial IGCCs should

achieve better than 98% SO2

 capture with a NOx emissions reduction of 90%.

The Texaco-based system has already been proven

capable of handling both subbituminous and bituminous

coals. This demonstration project is scaling up the technology from a 100-MWe pilot unit (Cool Water plant)

tested without full system integration.
5-106 Program Update 1996-97 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 Destec Energy, Inc., and

PSI Energy, Inc.)

Additional Team Members

PSI Energy, Inc.—host

Destec Energy, Inc.*—engineer, gas plant operator, and

technology supplier

Location

West Terre Haute, Vigo County, IN (PSI Energy’s

Wabash River Generating Station, Unit 1)

Technology

Integrated gasification combined-cycle (IGCC) using

Destec’s two-stage, entrained-flow gasification system

Plant Capacity/Production

262 MWe (net)

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,

oxygen-blown IGCC system, including advancements in

the technology relevant to the use of high-sulfur bituminous coal; and to assess long-term reliability, availability,

and maintainability of the system at a fully commercial

scale.

Technology/Project Description

Coal is ground, slurried with water, and gasified in a

pressurized, two-stage (slagging first stage and nonslagging entrained-flow second stage), oxygen-blown,

gasifier. The product gas is cooled through heat exchangers and passed through a conventional cold gas

cleanup system which removes particulates, ammonia,

and sulfur. The clean, medium-Btu gas is then reheated

and burned in an advanced 192-MWe (gross) GE 7FA

gas turbine. Hot exhaust from the gas turbine is passed

through a heat recovery steam generator to produce highpressure steam. High-pressure steam is also produced

from the gasification plant and superheated in the heat

recovery steam generator. The combined high-pressure

steam flow is supplied to an existing, refurbished

104-MWe (gross) steam turbine.

The process has the following subsystems: a coalgrinding and slurry system, an entrained-flow coal gasifier,

a syngas heat recovery system, a cold gas cleanup system

that produces a marketable sulfur by-product,

a combustion turbine capable of using coal-derived fuel

gas, a heat recovery steam generator, and a repowered

steam turbine.

One of six units at Wabash River Generating Station

was repowered. The demonstration unit generates

262 MWe (net) using 2,544 tons/day of high-sulfur

(2.3–5.9% sulfur) Illinois Basin bituminous coal. The

anticipated heat rate for the repowered unit is approximately 9,000 Btu/kWh (38% efficiency). Using highsulfur bituminous coal, SO2

 emissions are expected to be

less than 0.1 lb/106 Btu (98% reduction). NOx

 emissions

are expected to be less than 0.1 lb/106

 Btu 90% reduction). *Destec Energy, Inc., merger with NGC is expected to be completed in

August 1997.
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Advanced Electric Power Generation Program Update 1996-97 5-107

The project represents the world’s largest single-train

IGCC plant currently in operation.

Project Status/Accomplishments

The plant is in its second year of operation, which began

in November 1995. Through June 30, 1997, the plant has

operated for about 3,500 hours on syngas in combinedcycle mode and has produced about 700,000 MWh of

electricity using syngas. The combustion turbine has

demonstrated 192 MWe (100% of nameplate) and the

gasifier has demonstrated 1,825 million Btu/hr, HHV

(103% of nameplate). The gasifier has operated about

4,000 hours on coal and produced over 6 trillion Btu (dry)

of syngas by processing over 350,000 tons of coal. Gasifier operation has attained over 74% cold gas efficiency.

The project has completed the first 11⁄2 years of a

three-year demonstration period. Early operation has

demonstrated the ability to run at full-load capability

while meeting the environmental requirements for sulfur

and NOx

 emissions. CINergy, PSI’s post-merger parent

company, dispatches the project second behind its hydro

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 2/99

Demonstration completed 11/98*

Operation initiated 11/95

Construction completed 11/95

facilities on the basis of environmental emissions and

efficiency, with a demonstrated heat rate of better than

9,000 Btu/kWh (HHV). CINergy Corp./PSI Energy, Inc.,

received the 1996 Powerplant Award from Power magazine.

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

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.

Given the advantages of modularity, rapid and staged

on-line generation capability, high efficiency, fuel flexibility, environmental controllability, and reduced land

and natural resource needs, the IGCC system is also a

strong contender for new electric power generating facilities. Commercial offerings of the technology will be

based on a 300-MWe train, which is ideally suited to

utility-scale power generation applications. 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-coalfired plant with flue gas desulfurization. The improved

system efficiency also results in a similar decrease in

CO2 emissions.

Project completed/final report issued 2/99*
5-108 Program Update 1996-97 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

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 #1)

Technology

TRW’s advanced entrained (slagging) combustor

Babcock & Wilcox’s spray-dryer absorber with sorbent

recycle

Plant Capacity/Production

50 MWe (nominal electric output)

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.

TRW slagging combustors are bottom-mounted on the

boiler hopper. 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 watercooled 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 is to be a nominal 50-MWe facility consisting

of two pulverized-coal-fired combustor systems. Emissions of SO2

 and NOx will be controlled using TRW’s

slagging combustion systems with staged fuel and air, a

boiler that controls fuel- and thermal-related conditions,

and limestone injection. Additional SO2

 will be 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

performance testing of coal consists of 35% run-of-mine

and 65% waste coal, with the waste coal having a lower

heating value and significantly more ash.

A coal-fired precombustor increases the air inlet

temperature for optimum slagging performance. The
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Advanced Electric Power Generation Program Update 1996-97 5-109

Pulverized limestone (CaCO3) for SO2 control is fed

into the combustor where most is flash calcined. The

mixture of this lime (CaO) and the ash not slagged, called

flash-calcined material, is removed in the fabric filter

(baghouse) system. A small part of the flash-calcined

material is disposed of, but most is conveyed to a mixing

tank where water is added to form a 45% flash-calcinedmaterial solids slurry. The slurry leaving the mixing tank

is pumped to a grinding mill where it is mechanically

activated by abrasive grinding. Feed slurry is pumped

from the feed tank to the spray-dryer absorber where the

slurry is atomized using Babcock & Wilcox’s dry scrubbing technology. 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

#1 near Healy, AK, and to the Usibelli coal mine. Power

will go to the Golden Valley Electric Association

(GVEA). The plant will use a nominal 900 tons/day of

subbituminous coal, containing a nominal 0.2% sulfur,

and waste coal. The project will collect performance

data for 31⁄2 years, with 2 years of data being provided at

no cost to DOE. A hazardous air pollutant 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 #1 so that the combined emissions from the two

units will be only slightly greater than those currently

emitted from Unit #1 alone. Total site emissions will be

further reduced to current levels if necessary to protect

the park.

Project Status/Accomplishments

By June 30, 1997, engineering efforts were complete and

construction was 91% complete. The erection of structural steel and on-site fabrication and installation of all

major equipment was complete, and startup and commissioning of individual plant systems was under way. The

retrofit of Unit No. 1 (low-NOx

 burners with overfire air)

and its performance testing was completed. Construction

is on schedule for completion in September 1997.

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, lowsulfur, low-ash-fusion-temperature coal that cyclone

boilers require. The commercial availability of costeffective 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 of 1990 requirements.

TRW is offering licensing of its technology worldwide and already has a licensing agreement in place in

China.

1990 1991 1993 1994 1995 1996 1997 1998 1999 2000 2001

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 6/99

**

Project completed/final

report issued 6/99*

DOE cost-shared operation

completed 6/99*

2 yrs of operational

data provided at no

additional cost

6/01*

6/01

*Projected date

**Years omitted

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 9/97*
5-110 Program Update 1996-97 Advanced Electric Power Generation

Technology/Project Description

The project is based on the demonstration of a 12-cylinder, heavy duty engine (4.2 MWe) modified to operate on

Alaskan subbituminous. The clean coal diesel technology, which uses a coal slurry (specifically, low-rank coalwater fuel), is expected to have very low NOx

 and SOx

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

 compared to conventional coal-fired plants.

The low-rank coal-water fuel 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 coal-water-fuel processing plant

that will utilize local coal brought by truck from

Usibelli’s mine in Healy, Alaska. In addition to its use in

the coal-fueled diesel engine, the low-rank coal-water

fuel is expected to be an alternative to fuel oil in conventional oil-fired industrial boilers.

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

R.W. Beck—architect/engineer, designer, and constructor

Usibelli Coal Mine, Inc.—coal supplier

Proposed Team Members

Alaskan Science & Technology Foundation—cofunder

Coltec—diesel engine technology vendor

EERC—fuel preparation technology vendor

Location

Fairbanks, AK (University of Alaska facility)

Technology

Coal-fueled diesel engine

Plant Capacity/Production

4.2 MWe (net)

Project Funding

Total project cost $38,309,516 100%

DOE 19,154,758 50

Participant 19,154,758 50

Project Objective

To prove the design, operability, and durability of the coal

diesel engine during 6,000 hours of operation and verify

the design and operation of an advanced drying/slurrying

process for subbituminous Alaskan coals and for testing

the coal slurry in the diesel and a retrofitted oil-fired

boiler.
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Advanced Electric Power Generation Program Update 1996-97 5-111

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

Project Status/Accomplishments

Easton Utilities, the original host, withdrew from the

project after reevaluating its long-term need for power.

DOE has approved the participant’s plans to resite the

project at the University of Alaska in Fairbanks, where

the engine will operate on subbituminous Alaskan coals.

An extension until September 30, 1997, has been granted

to complete restructuring activities, obtain firm financial

commitments, and establish the schedule and milestones

for the project.

Project definition and design activities are ongoing.

NEPA requirements have been satisfied by an environmental assessment, which was completed June 2, 1997.

Commercial Applications

The coal-fueled diesel engine is particularly suited for

nonutility new capacity, small utility repowering, and

exports to 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. EnviNEPA process completed (EA) 6/2/97

Note: Milestone schedule pending project restructuring

ronmental 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.
5-112 Program Update 1996-97 Advanced Electric Power Generation

Advanced Electric Power Generation

Advanced Combustion/Heat Engines

Externally Fired CombinedCycle Demonstration Project

Project concluded.

Participant

Pennsylvania Electric Company

Additional Team Members

Hague International—technology developer and supplier

Black & Veatch—engineer and construction manager

Location

Site under negotiation

Technology

Hague International’s externally fired combined-cycle

(EFCC) system using a novel, high-temperature, ceramic

gas-to-air heat exchanger

Plant Capacity/Production

5 MWe slipstream

Project Funding

Total project cost $146,832,000 100%

DOE 73,416,000 50

Participant 73,416,000 50

Project Objective

To demonstrate an externally fired combined-cycle system through the use of a novel ceramic heat exchanger

and to assess the system’s environmental and economic

performance for meeting future energy needs.

duce electricity. The product gas is finally passed through

a gas cleanup system consisting of a flue gas desulfurizer

and a fabric filter before exiting to the atmosphere

through the stack. The hot air from the CerHx® is passed

through a gas turbine to produce additional electricity

before being fed to the combustor.

The attractiveness of the EFCC lies in its ability to

eliminate the need for a hot gas cleanup system to protect

the costly gas turbine gas-path components from the

corrosive and abrasive elements in the combustion product gas. Instead, the gas turbine operates on indirectly

heated clean air and the gas path is never exposed to the

corrosive elements in the fuel or product gas. The

CerHx® raises the temperature of the air to the turbine

inlet conditions using tube elements that are manufactured

CerHx is a registered trademark of Hague International. from corrosion-resistant, toughened, ceramic materials.

Technology/Project Description

In this project, an existing coal-fueled steam plant is

being repowered by adding an externally fired gas turbine

to form a combined-cycle system. The central feature of

the EFCC is a ceramic air heater or heat exchanger

(CerHx®) and an atmospheric combustor, which together

replace a conventional combustion system in an opencycle gas turbine.

Coal is first combusted in a staged combustor for

NOx

 control. Particulate-laden gases exit the combustor

and enter the slag screen where all particles larger than

about 10 microns are collected. Air from the turbine

compressor is heated by exchange with the hot product

gas in the CerHx®. The product gas is then passed

through a heat recovery steam generator, where more heat

is extracted to drive a steam turbine generator and pro-
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Advanced Electric Power Generation Program Update 1996-97 5-113

1993 1996 1997 1994 1995 1998 1999 2000 2001 2002 2003

Preaward

5/93 8/94

DOE selected project (CCT-V) 5/4/93

Cooperative agreement awarded 8/1/94

Design

NEPA process completed (EA; Warren Station site) 5/18/95

Commercial Applications

The EFCC system concept is suitable for new electric

power generation, repowering needs, and cogeneration

applications. The potential commercial market for EFCC

systems is expected to be about 24 GWe by 2010. The

net effective heat rate for a 300-MWe greenfield plant

using this technology is projected to be 7,790 Btu/kWh.

This represents a 20% increase in thermal efficiency

compared to a conventional pulverized coal plant with a

scrubber.

SO2

 emissions are expected to be less than 0.081

lb/106

 Btu, which is a reduction of more than 90% for

most coals. NOx emissions are expected to be less than

0.15 lb/106 Btu, and particulate emissions are expected to

be less than 0.015 lb/106 Btu.

Project concluded 5/31/97

Potential SOx release is reduced by more than 90%

through capture in the flue gas desulfurization system.

NOx

 emissions are expected to be less than 0.13 lb/106

Btu.

Project Status/Accomplishments

In May 1995, Pennsylvania Electric stopped all project

activity due to lack of progress in resolving technical

issues relating to the ceramic heat exchanger. In June

1996, the utility announced it would not pursue the fullscale EFCC at Warren Station. The utility did propose a

demonstration of a scaled down EFCC in a 5-MWe

slipstream at Seward Station. However, Hague International did not complete developmental testing of the

ceramic heat exchanger at the Kennebunk facility. Because a successful 50-hour coal-fired test at the pilotplant

was not completed, the project was concluded on

May 31, 1997.

5/97
5-114 Program Update 1996-97 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Technology

This category includes a range of technologies

designed to produce high-energy-density, low-sulfur

solid and clean liquid fuels, as well as systems to

assist users in evaluating impacts of coal quality on

boiler performance.

In the case of the Customs Coals International

project, advanced physical-cleaning techniques are

applied to bituminous coal with an already high Btu

content to remove the ash, which contains sulfur in

the form of pyrite, an inorganic iron compound. A

dense-medium cyclone using finely sized magnetite

effectively separates 90 percent of the pyritic sulfur.

But, because physical methods cannot remove the

organically bound sulfur, dense-medium-cyclone

processed coals can only be considered compliance

coals (meeting CAAA SO2

 requirements) if the

organic sulfur content is very low. This processed

compliance coal is called Carefree CoalTM. For coals

with significant organic sulfur content, sorbents and

other additives must be added to capture the sulfur

released upon combustion and bring the coal into

compliance. This second product is called SelfScrubbing CoalTM.

The Rosebud SynCoal Partnership’s advanced

coal conversion project applies mostly physicalcleaning methods to low-Btu, low-sulfur subbituminous coals, primarily to remove moisture and secondarily to remove ash. The objective is to enhance the

energy density of the already low-sulfur coal. Some

conversion of the surface properties of the coal is

required, however, to provide stability (prevent

spontaneous combustion) in transport and handling.

In the process, coal with 5,500–9,000 Btu per pound,

25–40 percent moisture content, and 0.5–1.5 percent

sulfur is converted to a 12,000-Btu-per-pound product

with 1.0 percent moisture and as low as 0.3 percent

sulfur. Test burning of processed coal at utilities is

continuing.

The ENCOAL® project uses mild gasification to

convert low-Btu, low-sulfur-content subbituminous

coal to a high-energy-density, low-sulfur solid

product and a clean liquid fuel comparable to No. 6

fuel oil. Mild gasification is a pyrolysis process

(heating in the absence of oxygen) performed at

moderate temperatures and pressures. It produces

condensable volatile hydrocarbons in addition to

solids and gas. The condensable fraction is drawn off

as a liquid product. Most of the gas is used to provide

on-site energy requirements. The process solid is

significantly beneficiated to produce a 12,000-Btuper-pound low-sulfur solid fuel. The demonstration

plant is processing 500 tons per day of subbituminous

coal and producing 250 tons per day of solid processderived fuel (PDFTM) and 250 barrels per day of coalderived liquids (CDLTM). Both the solid and liquid

fuels are undergoing test burns at utility and industrial

sites.

The liquid-phase methanol (LPMEOHTM) process

being demonstrated is an indirect liquefaction process

using synthesis gas from a coal gasifier. The unique

aspect of the process is the use of an inert liquid to

suspend the conversion catalyst. This removes the

heat of reaction and precludes the need for an

intermediate water-gas shift conversion. Also

addressed in the project are the load-following

capability of the process by simulating application in

an IGCC system and fuel characteristics of the

unrefined product. Construction on the project was

completed in January 1997. Operation began in April

1997. The LPMEOHTM demonstration unit logged

over 500 hours of stable operation in the first month

on stream—an availability of over 90 percent.

CQ Inc. has developed a personal computer

software package that will serve as a predictive tool

to assist utilities in selecting optimal quality coal for

a specific boiler based on operational efficiency, cost,

and environmental considerations. Algorithms were

developed and verified through comparative testing

at bench, pilot, and utility scale. Six large-scale field

tests were conducted at five separate utilities. The

software has been released for use.

Exhibit 5-32 summarizes the process characteristics and size of the coal processing for clean fuels

technologies presented in more detail in the project

fact sheets.
Coal Processing for Clean Fuels Program Update 1996-97 5-115

Exhibit 5-32

CCT Program Coal Processing for Clean Fuels Technology Characteristics

Project Process Size Fact Sheet

Development of the Coal Quality ExpertTM Coal Quality ExpertTM computer software Tested at 250–880 MWe 5-116

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Dense-medium cyclones with finely sized magnetite and 500 tons/hr 5-120

sorbent addition for bituminous coals

Advanced Coal Conversion Process Demonstration Advanced coal conversion process for upgrading 45 tons/hr 5-122

low-rank coals

ENCOAL® Mild Gasification Project Liquids-from-coal (LFCTM) mild gasification to 1,000 tons/day 5-124

produce solid and liquid fuels

Commercial-Scale Demonstration of the Liquid-Phase Methanol Liquid-phase methanol (LPMEOHTM) process for 80,000 gal/day 5-126

(LPMEOHTM) Process methanol production from coal syngas

Custom Coals International’s advanced coal-cleaning

plant in Central City, PA, can process 500 tons/hr of raw

coal.

The ENCOAL® mild gasification plant near Gillette,

WY, has operated more than 13,000 hours and processed

more than 210,000 tons of raw coal.

Rosebud SynCoal Partnership’s advanced coal

conversion process plant in Colstrip, MT has produced over

a million tons of SynCoal® products.
5-116 Program Update 1996-97 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Coal Preparation Technologies

Development of the Coal

Quality ExpertTM

Project completed.

Participants

ABB Combustion Engineering, Inc.

CQ Inc.

Additional Team Members

Black & Veatch—cofunder and software

developer

Electric Power Research Institute—cofunder

The Babcock & Wilcox Company—cofunder and

pilot-scale tester

Electric Power Technologies, Inc.—field tester

University of North Dakota, Energy and Environmental

Research Center—bench-scale tester

Alabama Power Company—host

Mississippi Power Company—host

New England Power Company—host

Northern States Power Company—host

Public Service Company of Oklahoma—host

Locations

Grand 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 5)

Gulfport, Harrison County, MS (Watson, Unit 4)

Somerset, Bristol County, MA (Brayton Point,

Units 2 and 3)

Bayport, Washington County, MN (King Station)

Oologah, Rogers County, OK (Northeastern, Unit 4)

Technology

CQ Inc.’s EPRI Coal Quality ExpertTM (CQETM) computer software

Plant Capacity/Production

Full-scale testing took place at six utility sites ranging in

size from 250 to 880 MWe.

Project Funding

Total project cost $21,746,004 100%

DOE 10,863,911 50

Participants 10,882,093 50

Project Objective

The objective of the project was to provide the utility

industry with a PC software program to confidently and

inexpensively evaluate the potential for coal-cleaning,

blending, and switching options to reduce emissions

while producing the lowest cost electricity. Specifically

the project was to (1) enhance the existing Coal Quality

Information System (CQISTM) database and Coal Quality

Impact Model (CQIMTM) to allow assessment of the

effects of coal-cleaning on specific boiler costs and performance and (2) develop and validate CQETM, a methodology that allows accurate and detailed prediction of coal

quality impacts on total power plant operating cost and

performance.

Technology/Project Description

The CQETM is a software tool that brings a new level of

sophistication to fuel decisions by integrating the systemwide effects of fuel purchase decisions on power plant

performance, emissions, and power generation costs.

CQETM can be used on a stand-alone computer or as a

network application for utilities, coal producers, and

Coal Quality Expert, CQE, CQIS, and CQIM are trademarks of the

Electric Power Research Institute.
Coal Processing for Clean Fuels

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Calendar Year

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 Program Update 1996-97 5-117

*Projected date

equipment manufacturers to perform detailed analyses of

the impacts of coal quality, capital improvements, operational changes, and/or environmental compliance alternatives on power plant emissions, performance, and production costs. CQETM can be used as an organized methodology for systematically evaluating all such impacts or it

may be used in modules with some default data to perform more strategic or comparative studies.

Project Summary

Background

CQETM began with EPRI’s Coal Quality Impact Model

(CQIMTM), developed for EPRI by Black & Veatch and

introduced in 1989. CQIMTM was endowed with a variety

of capabilities, including evaluating Clean Air Act compliance strategies, evaluating bids on coal contracts, conducting test-burn planning and analysis, and providing

techno-economic analyses of plant operating strategies.

CQETM, which combines CQIMTM with other existing

software and databases, extends the art of model-based

fuel evaluation established by CQIMTM in three dimensions: new flexibility and application, advanced technical

models and performance correlations, and advanced user

interface and network awareness.

Algorithm Development

Data derived from bench-, pilot-, and full-scale testing

were used to develop the CQETM algorithms. Bench-scale

testing was performed at ABB Combustion Engineering’s

facilities in Windsor, CT, and the University of North

Dakota’s Energy and Environmental Research Center in

Grand Forks, ND; pilot-scale testing was performed at

ABB Combustion Engineering’s facilities in Windsor, CT,

and Alliance, OH. The six field test sites were Alabama

Power’s Gatson, Unit 5 (880 MWe), Wilsonville, AL;

Mississippi Power’s Watson, Unit 4 (250 MWe), Gulfport,

MS; New England Power’s Brayton Point, Unit 2

(285 MWe) and Unit 3 (615 MWe), Somerset, MA; Northern States Power’s King Station (560 MWe), Bayport, MN;

and Public Service Company of Oklahoma’s Northeastern,

Unit 4 (445 MWe), Oologah, OK.

The six large-scale field tests consisted of burning a

baseline coal and an alternate coal over a 2-month period.

The baseline coal was used to characterize the operating

performance of the boiler. The alternate coal, a blended

or cleaned coal of improved quality, was burned in the

boiler for the remaining test period.

The baseline and alternate coals for each test site also

were burned in bench- and pilot-scale facilities under

similar conditions. The alternate coal was cleaned at CQ

Inc. to determine what quality levels of clean coal can be

produced economically and then transported to the

bench- and pilot-scale facilities for testing. All data from

bench-, pilot-, and full-scale facilities were evaluated and

correlated to formulate algorithms used to develop the

model.

CQETM Capability

The PC-based program evaluates coal quality, transportation system options, performance issues, and alternative

emissions control strategies for utility power plants.

CQETM is composed of technical tools to evaluate perfor1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

DOE selected

project (CCT-I)

12/9/88

12/88

Cooperative agreement awarded 6/14/90

NEPA process completed

(MTF) 4/27/90

Environmental monitoring

plan completed 7/31/90

Operation initiated 8/90

Preaward

Development

6/90

Field testing completed 4/93

8/90

CQE Release 1.1 beta issued 6/96

CQE CD-ROM issued 12/95

Project completed/final

report issued 8/97*

CQE Release 1.0

issued 8/97*

8/97
5-118 Program Update 1996-97 Coal Processing for Clean Fuels

mance issues, environmental models to evaluate emissions and regulatory issues, and economic models to

determine 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-cleaning

processes, power production equipment, and emissions

control systems. CQETM has four main features:

• Fuel Evaluator—Performs system-, plant-, and/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, and

predicts associated costs.

Software Description

CQETM includes more than 100 algorithms based on the

data 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 new

applications to be added by assembling a model of how

objects interact. Updated information records can be

readily shared among all affected users because CQETM is

network-aware, enabling users throughout an organization to share data and results. The CQETM object-oriented

design, coupled with an object database management

system, allows different views into the same data. As a

result, staff efficiency is enhanced when decisions are

made.

CQETM also can be expanded without major revisions to the system. Object-oriented programming allows

new objects to be added and old objects to be deleted or

enhanced easily. For example, if modeling advancements

are made with respect to predicting boiler ash deposition

(i.e., slagging and fouling), the internal calculations of the

object that provides these predictions can be replaced or

augmented. Other objects affected by ash deposition

(e.g., ash collection and disposal systems, soot blower

systems) do not need to be altered; thus the integrity of the

underlying system is maintained.

System Requirements

CQETM currently uses the OS/2 operating system, but the

developers are planning to migrate to a Windows-based

platform. CQETM can operate in stand-alone mode on a

single computer or on a network. The system requirements for stand-alone operation are listed in Exhibit 5-33.

Technical support is available from Black & Veatch by

sending an e-mail message to cqe@bv.com or phoning

(913) 458-9772, Monday through Friday, 8:00 a.m. to

5:00 p.m. (central time).

Commercial

Applications

The CQETM system is

applicable to all electric power generation

plants and large industrial/institutional

boilers that burn pulverized coal. Potential

users include fuel

suppliers, environmental organizations,

government and regulatory institutions, and

engineering firms.

International markets

for CQETM are being

explored by both CQ

Inc. and Black &

Veatch.

EPRI owns the software and distributes CQETM to

EPRI members for their use. CQETM is available to others in the form of three types of licenses: user, consultant,

and commercializer. CQ Inc. is EPRI’s licensing agent.

CQ Inc. and Black & Veatch have each signed commercialization agreements, which give both companies nonexclusive worldwide rights to sell user’s licenses and to

offer consulting services that include the use of CQETM

software. Two U.S. utilities have been licensed to use

copies of CQETM’s stand-alone Acid Rain Advisor. Over

40 U.S. utilities and one U.K. utility have CQETM through

their EPRI membership. Proposals are pending with

several non-EPRI-member U.S. and foreign utilities to

license their software.

The CQETM team has a Home Page on the World

Wide Web (http://www.fuels.bv.com:80/cqe/cqe.htm) to

promote CQETM, facilitate communications between

CQETM developers and users, and eventually allow software updates to be distributed over the Internet. It also

was developed to provide an on-line updatable user’s

Item Minimum Preferred

Hardware speed 486 PC, 33 Mhz Pentium PC, market stock

RAM 16 MB 32 MB

Disk space 200 MB 1 GB

Monitor SVGA color SVGA color

Graphics card Capable of 1024x768 mode Capable of 1024x768 mode

External drives 1.44 MB 3.5-inch; CD-ROM 1.44 MB 3.5-inch; CD-ROM

Mouse Required Required

Keyboard Required Required

Printer Access to high-speed printer Access to laser printer

Operating system OS/2 Version 2.0 WARP (3.0)

Exhibit 5-33

CQETM Stand-Alone System Requirements
Coal Processing for Clean Fuels

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Calendar Year

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 Program Update 1996-97 5-119

*Projected date

manual. The Home Page also helps attract the interest of

international utilities and consulting firms that are unable

to be reached by Black & Veatch and CQ Inc.

CQETM was recognized by then Energy Secretary

Hazel O’Leary and EPRI President Richard Balzhiser in

1996 as the best of nine DOE/EPRI cost-shared utility

research and development projects under the “Sustainable

Electric Partnership” program.

Contacts

Clark D. Harrison, President, (412) 479-6016

CQ Inc.

One Quality Center

P.O. Box 280

Homer City, PA 15748-0280

Douglas Archer, DOE/HQ, (301) 903-9443

Scott M. Smouse, FETC, (412) 892-5725

References

• 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., and

CQ Inc. Report No. DOE/FE-0174P. U.S. Department

of Energy. May 1990. (Available from NTIS as

DE90010381.)

CQETM, a PC-based software tool, can be used to determine the complete

costs of various fuel options by seamlessly integrating the effects of fuel purchase

decisions on power plant performance, emissions, and power generation costs.

Portions of the CQETM User’s Manual are available on the Internet.
5-120 Program Update 1996-97 Coal Processing for Clean Fuels

Project Objective

To demonstrate advanced coal-cleaning unit processes to

produce low-cost compliance coals that can meet full

requirements for commercial-scale utility power plants to

satisfy provisions of the CAAA.

Technology/Project Description

An advanced coal-cleaning plant has been designed,

blending existing and new processes, to produce, from

high-sulfur bituminous feedstocks, two types of compliance coals—Carefree CoalTM and Self-Scrubbing CoalTM.

Carefree CoalTM is produced by breaking and

screening run-of-mine coal and by using innovative

dense-medium cyclones and finely sized magnetite to

remove up to 90% of the pyritic sulfur and most of the

ash. Carefree CoalTM is designed to be a competitively

priced, high-Btu fuel that can be used without major plant

modifications or additional capital expenditures. While

many utilities can use Carefree CoalTM to comply with

SO2

 emissions limits, others cannot due to the high content of organic sulfur in their coal feedstocks. When

compliance coal cannot be produced by reducing pyritic

sulfur, Self-Scrubbing CoalTM can be produced to achieve

compliance.

Self-Scrubbing CoalTM is produced by taking Carefree CoalTM, with its reduced pyritic sulfur and ash content, and adding to it sorbents, promoters, and catalysts.

Self-Scrubbing CoalTM is expected to achieve compliance

with virtually any U.S. coal feedstock through in-boiler

absorption of SO2

 emissions. The reduced ash content of

the Self-Scrubbing CoalTM permits addition of relatively

Coal Processing for Clean Fuels

Coal Preparation Technologies

Self-Scrubbing CoalTM: An

Integrated Approach to Clean

Air

Participant

Custom Coals International (a joint venture between

Genesis Coals Limited Partnership and Genesis Research

Corporation)

Additional Team Members

Pennsylvania Power & Light Company—host

Richmond Power & Light—host

Centerior Service Company—host

Locations

Central City, Somerset County, PA (advanced

coal-cleaning plant)

Lower Mt. Bethel Township, Northampton County, PA

(combustion tests at Pennsylvania Power & Light’s

Martin’s Creek Power Station, Unit 2)

Richmond, Wayne County, IN (combustion tests at

Richmond Power & Light’s Whitewater Valley

Generating Station, Unit No. 2)

Ashtabula, Trumbull County, OH (combustion tests at

Centerior Energy’s Ashtabula C)

Technology

Coal preparation using Custom Coals’ advanced physical

coal-cleaning and fine magnetite separation technology

plus sorbent addition technology

Plant Capacity/Production

500 tons/hr

Project Funding

Total project cost $87,386,102 100%

DOE 37,994,437 43

Participant 49,391,665 57

Self-Scrubbing Coal and Carefree Coal are trademarks of Custom Coals

International.
Coal Processing for Clean Fuels

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

 Program Update 1996-97 5-121

*Projected date

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Preaward

9/91 10/92

DOE selected

project (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

sents more than 38% of the bituminous coal burned in

50-MWe or larger U.S. generating stations.

The technology produces coal products that can be

used to reduce a utility or industrial power plant’s total

sulfur emissions by 80–90%.

A U.S.-led consortium with Custom Coals as the

principal partner has signed a cooperative agreement

worth $450 million with China to build a coal-cleaning

plant, a 500-mile underground slurry pipeline, and port

facility. The pipeline will bring coal from the northwest

Shanxi province to the coastal province of Shandong. A

letter of intent for three additional pipelines in China was

signed in August 1996.

Custom Coals is aggressively marketing the technology in Eastern Europe and has received letters of intent

from Polish utilities interested in producing 5 million

tons/yr of cleaned coal. Custom Coals also has a proposed agreement with domestic coal-marketing companies for 1 million tons of compliance coal annually.

the test was consistent with the current quality of the plant

feed coal. The unit experienced some opacity problems

due to the low sulfur in the coal and a marginal electrostatic precipitator. Data analysis is under way.

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 excessive

amount of material going to the refuse pond, and plant

operation was suspended in February 1997. Activities

needed for the plant to resume operation have been delayed due to financial problems.

In June 1997, Custom Coals International accepted

an offer from a coal supplier to purchase the facility and

continue the demonstration project. DOE is evaluating

the offer to continue the demonstration.

Commercial Applications

Commercialization of Self-Scrubbing CoalTM has the

potential of bringing into compliance about 164 million

tons/yr of bituminous coal that cannot meet emissions

limits through conventional coal-cleaning. This reprelarge 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)—are

being used to produce Self-Scrubbing CoalTM. Carefree

CoalTM is being made using Lower Kittanning (1.8%

sulfur). Lower Kittanning coal is being tested at Martin’s

Creek Power Station; Illinois No. 5 coal is being tested at

Whitewater Valley Generating Station; and Lower

Freeport Seam coal is being tested at Ashtabula C.

Project Status/Accomplishments

Start-up began in late December 1995, and the first coal

was processed in February 1996. In May 1996, the facility reached its design capacity. Equipment and circuit

optimization testing began immediately thereafter and

continued throughout 1996.

The Carefree CoalTM test burn (cleaned Lower

Kittanning coal) at Martin’s Creek Power Station was

conducted in mid-November 1996. Although plant optimization was not completed, the overall product made for

Design completed 12/94

Preoperational tests initiated 11/95

Construction completed 11/95

Operation initiated 2/96

12/97

Project completed/final report issued 12/97*

Environmental monitoring plan completed 12/97*

Operation completed 12/97*
5-122 Program Update 1996-97 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Coal Preparation Technologies

Advanced Coal Conversion

Process Demonstration

Participant

Rosebud SynCoal Partnership (a partnership between

Western Energy Company and the NRG Group, a

nonregulated subsidiary of Northern States Power

Company)

Additional Team Member

None

Location

Colstrip, Rosebud County, MT (adjacent to Western

Energy Company’s Rosebud Mine)

Technology

Rosebud SynCoal Partnership’s advanced coal

conversion process for upgrading low-rank

subbituminous and lignite coals

Plant Capacity/Production

45 tons/hr of SynCoal® product (300,000 tons/yr)

Project Funding

Total project cost $105,700,000 100%

DOE 43,125,000 41

Participant 62,575,000 59

Project Objective

To demonstrate Rosebud SynCoal’s advanced coal conversion process to produce SynCoal®, a stable coal product having a moisture content as low as 1%, sulfur content as low as 0.3%, and heating value up to 12,000

Btu/lb.

Technology/Project Description

Being demonstrated is an advanced thermal coal conversion process coupled with physical cleaning techniques

to upgrade high-moisture, low-rank coals to produce a

high-quality, low-sulfur fuel. The coal is processed

through two fluidized-bed dryer/reactors that remove

loosely held water and then chemically bound water,

carboxyl groups, and volatile sulfur compounds. After

conversion, the coal is put through a deep-bed stratifier

cleaning process to effect separation of the ash.

The technology enhances low-rank western coals,

usually with a moisture content of 25–40%, sulfur content of 0.5–1.5%, and heating value of 5,500–9,000

Btu/lb, by producing an upgraded SynCoal® product with

a moisture content as low as 1%, sulfur content as low as

0.3%, and heating value up to 12,000 Btu/lb.

The 45-ton/hr unit is located adjacent to a unit train

loadout facility at Western Energy Company’s Rosebud

coal mine in Colstrip, MT. The demonstration plant is

one-tenth the size of a commercial facility. However, the

process equipment is at 1

/3–1/2 commercial scale because

a full-sized commercial plant will have multiple process

trains.

SynCoal is a registered trademark of the Rosebud SynCoal Partnership.
Coal Processing for Clean Fuels

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Calendar Year

 1 2

 Program Update 1996-97 5-123

*Projected date

Preaward Design and Construction Operation

1988 1989 1990 1991 1992 1993 1994 1996 1997 1998 1999

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 3/28/91

NEPA 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

12/98

sions. Also, SynCoal® is being sent to Montana Power’s

Colstrip Project Units 1 and 2, where tests will provide

information on boiler efficiency, output, and air emissions.

In November 1996, 25 tons of specific-sized uncleaned

SynCoal® was sent to Morgantown for use in DOE’s coal

gasification test program.

The main product issue continues to be the spontaneous combustion tendency of the SynCoal®. Efforts also

are continuing to reduce operational costs per ton.

Commercial Applications

Rosebud SynCoal’s advanced coal conversion process has

the potential to enhance the use of low-rank western

subbituminous and lignite coals. Many of the power

plants located throughout the upper Midwest have cyclone boilers, which burn low-ash-fusion-temperature

coals. Currently, most of these plants burn Illinois Basin

high-sulfur coal. SynCoal® is an ideal low-sulfur coal

substitute for these and other plants because it allows

operation under more restrictive emissions guidelines

without requiring derating of the units or the addition of

costly flue gas desulfurization systems. The advanced coal

conversion process produces SynCoal® that has a consistently low moisture content, low sulfur content, high

heating value, and high volatile content. Because of these

characteristics, SynCoal® could have significant impact on

SO2

 reduction and provide a clean, economical alternative

fuel to many regional industrial facilities and small utilities being forced to use fuel oil and natural gas. Rosebud

SynCoal’s process, therefore, will be attractive to industry

and utilities because the upgraded fuel will be less costly

to use than would the construction and use of flue gas

desulfurization equipment.

SynCoal® technology is being marketed actively

worldwide. The partnership has been working on a potential semi-commercial project located in Wyoming. The

partnership has been working closely with a Japanese

equipment and technology company to expand into Asian

markets. Prospects also are being pursued in Europe.

Project Status/Accomplishments

The demonstration facility continues reliable operation.

It has processed more than 1.5 million tons of coal, and

on April 19, 1997, the plant produced its one millionth

ton of SynCoal®. Total sales of SynCoal® product have

exceeded 900,000 tons.

 SynCoal® products totaling nearly 130,000 tons

have been delivered over an extended period of time to

several industrial customers, including Ash Grove Cement, Bentonite Corporation, Wyoming Lime, Continental Lime, and Empire Sand and Gravel. In May 1997,

tests were performed on several coke/SynCoal® blends.

 A SynCoal® test burn was completed at Montana

Power’s J.E. Corette in April 1996. The test involved

both handling and combustion of SynCoal® in a variety of

blends ranging from 15% to 85% SynCoal®. Overall

results indicated that a 50% SynCoal®/raw coal blend

provides improved results. SO2

 emissions were reduced

by 21% overall, generation increased at normal operating

loads, and there was no noticeable impact on NOx

 emis-

**

Project completed/final report

issued 12/98*

** Year omitted

Operation completed 7/98*
5-124 Program Update 1996-97 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Mild Gasification

ENCOAL® Mild Coal

Gasification Project

Participant

ENCOAL® Corporation (a subsidiary of Bluegrass Coal

Development Company, which is a unit of Zeigler Coal

Holding Company)

Additional Team Members

Bluegrass Coal Development Company (formerly named

SMC Mining Company)—cofunder

TEK-KOL (partnership between SGI International and a

subsidiary of Zeigler Coal Holding Company)—

technology owner, supplier, and licenser

SGI International—technology developer

Triton Coal Company—host and coal supplier

The M.W. Kellogg Company—engineer and

constructor

Location

Near Gillette, Campbell County, WY (Triton Coal

Company’s Buckskin Mine)

Technology

SGI International’s liquids-from-coal (LFCTM) process

Plant Capacity/Production

1,000 tons/day of subbituminous coal feed

Project Funding

Total project cost $90,664,000 100%

DOE 45,332,000 50

Participant 45,332,000 50

dence time are controlled to achieve desired properties of

the fuel products. During processing in the pyrolyzer, all

remaining free water is removed, and a chemical reaction

occurs that results in the release of volatile gaseous material. Solids exiting the pyrolyzer are cooled and transferred to a process-derived fuel (PDFTM) storage bin.

The gas produced in the pyrolyzer is sent through a

cyclone for removal of the particulates and then cooled

to condense the liquid-fuel products, or coal-derived

liquids (CDLTM). Most of the gas from the condensation

unit is recycled to the pyrolyzer. The rest of the gas is

burned in combustors to provide heat for the pyrolyzer

and the dryer. NOx

 emissions are controlled by staged air

injection.

The offgas from the dryer is treated in a wet venturi

scrubber to remove particulates and a horizontal scrubber

Project Objective

To demonstrate the integrated operation of a number of

novel processing steps to produce two higher value fuel

forms from mild gasification of low-sulfur subbituminous coal; to provide sufficient products for potential

end users to conduct burn tests.

Technology/Project Description

The ENCOAL® mild coal gasification process involves

heating coal under carefully controlled conditions. Coal

is fed into a rotary grate dryer where it is heated by a hot

gas stream to reduce the coal’s moisture content. The

solid bulk temperature is controlled so that no significant

amounts of methane, CO, or CO2

 are released from the

coal. The solids from the dryer are conveyed to a pyrolyzer where the rate of heating of the solids and resiLFC, CDL, and PDF are trademarks of TEK-KOL.

ENCOAL is a registered trademark of TEK-KOL.
Coal Processing for Clean Fuels

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

 Program Update 1996-97 5-125

*Projected date

to remove SO2, both using a sodium carbonate solution.

The treated gas is vented to a stack, and the spent solution is discharged into a pond for evaporation.

The ENCOAL® project is located within Campbell

County, WY, at Triton Coal Company’s Buckskin Mine,

10 miles north of Gillette. The plant makes use of the

present coal-handling facilities at the mine. Subbituminous coal with 0.4–0.9% sulfur content is being used.

Project Status/Accomplishments

The plant is processing 500 tons/day of coal and producing 250 tons/day of PDFTM and 250 barrels/day of

CDLTM. The plant has been in operation for 41⁄2 years

and has delivered 15 unit trains of PDFTM to five major

utilities. More than 3 million gallons of CDLTM has also

been delivered to seven industrial fuel users and one steel

mill blast furnace. By the end of June 1997, the plant

had operated nearly 13,000 hours and processed more

than 210,000 tons of raw coal.

In 1996, ENCOAL® began shipping unit trains containing 100% PDFTM for the first time. Several 100%

Design and Construction Operation

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Cooperative agreement awarded 9/17/90

DOE

selected

project

(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

PDFTM unit trains have been delivered to two separate

utilities for test burns. At Indiana-Kentucky Electric

Cooperative’s Clifty Creek Station, blends of 70–90%

PDFTM with Ohio high-sulfur coal indicated that unit

capacity was increased significantly relative to the base

blend, and there was at least a 20% NOx reduction because of a more stable flame. Several unit trains were

sent to Union Electric.

Commercial Applications

The liquid products from mild coal gasification can be

used in existing markets in place of No. 6 fuel oil. The

solid product can be used in most industrial or utility

boilers and also shows promise for iron ore reduction

applications. The feedstock for mild gasification is being

limited to high-moisture, low-heating-value coals.

The potential benefits of this mild gasification technology in its commercial configuration are attributable to

the increased heating value (about 12,000 Btu/lb) and

lower sulfur content (per unit of fuel value) of the new

solid-fuel product compared to the low-rank coal feedstock, and the production of low-sulfur liquid products

requiring no further treatment for the fuel oil market. The

product fuels are expected to be used economically in

commercial boilers and furnaces and to reduce significantly SO2

 emissions at industrial and utility facilities

currently burning high-sulfur bituminous coals or fuel oils.

ENCOAL® Corporation’s newly formed company,

NuCoal, L.L.C., has signed a contract with Mitsubishi

International Corporation to construct a $460-million,

15,000-metric-ton/day plant in Wyoming. Feasibility

studies also have been completed for two Indonesian

projects and one Russian project.

7/97

Project completed/final

report issued 7/97*

Operation completed 7/97*
5-126 Program Update 1996-97 Coal Processing for Clean Fuels

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.

(a limited partnership between Air Products and

Chemicals, Inc., the general partner, and Eastman

Chemical Company)

Additional Team Members

Air Products and Chemicals, Inc.—technology supplier

and cofunder

Eastman Chemical Company—host; operator; synthesis

gas and services provider

Acurex Environmental Corporation—fuel methanol

tester and cofunder

Electric Power Research Institute—fuel methanol test

advisor

Location

Kingsport, Sullivan County, TN (Eastman Chemical

Company’s Integrated Coal Gasification Facility)

Technology

Air Products and Chemicals’ liquid-phase methanol

(LPMEOHTM) process

Plant Capacity/Production

80,000 gallons/day of methanol (nominal)

Project Funding

Total project cost $213,700,000 100%

DOE 92,708,370 43

Participant 120,991,630 57

the catalyst but functions as an efficient means to remove the heat of reaction away from the catalyst surface. This feature permits the direct use of synthesis

gas streams as feed to the reactor without the need for

phase-shift conversion.

The Eastman Chemical Company’s integrated coal

gasification facility at Kingsport, TN, has operated

commercially since 1983. At this site, it will be possible to ramp up and down to demonstrate the unique

load-following flexibility of the LPMEOHTM unit for

application to coal-based electric power generation

facilities. Methanol fuel testing will be conducted in

off-site stationary and mobile applications, such as fuel

cells, buses, and distributed electric power generation.

Design verification testing for the production of DME

as a mixed coproduct with methanol for use as a storProject Objective

To demonstrate on a commercial scale the production of

methanol from coal-derived synthesis gas using the

LPMEOHTMprocess; and to determine the suitability of

methanol produced during this demonstration for use as a

chemical feedstock or as a low-SOx

, low-NOx alternative

fuel in stationary and transportation applications. If

practical, the production of dimethyl ether (DME) as a

mixed coproduct with methanol also will be demonstrated.

Technology/Project Description

This project is demonstrating, at commercial scale, the

LPMEOHTM process to produce methanol from coalderived synthesis gas. The combined reactor and heat

removal system is different from other commercial

methanol processes. The liquid phase not only suspends LPMEOH is a trademark of Air Products and Chemicals, Inc.
Coal Processing for Clean Fuels

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

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 Program Update 1996-97 5-127

*Projected date

able fuel is planned, and a decision on whether or not to

demonstrate will be made. Eastern high-sulfur bituminous coal (Mason seam) containing 3% sulfur (5% maximum) and 10% ash will be used.

Project Status/Accomplishments

Construction was completed and commissioning and

start-up began in January 1997. All utility and control

systems were commissioned, and a functional checkout

of the liquid-phase reactor system using coal-derived

synthesis gas at operating temperatures and pressures

was performed. Functional checkout of the methanol

distillation system and catalyst preparation areas was

also performed at normal operating temperatures and

pressures. Activation of the methanol catalyst was completed and methanol production in the LPMEOHTM

process demonstration unit began on April 2, 1997. The

first stable operation of the LPMEOHTM process demonstration unit at nameplate capacity of 80,000 gal/day

occurred on April 6, 1997. The initial operating period

continued until May 9, 1997; over 700 hours of stable

operation was logged. A continuous operating period of

over 351 hours was also achieved. Eastman has accepted

all of the 1.67 million gallons of product methanol from

the initial run for use in its onsite chemicals production.

A recent economic study of the LPMEOHTM process

as an add-on to an IGCC power plant indicates that costsavings are realized when utilities manufacture and sell

two products: electricity and methanol. Based on these

economics, a commercial-scale IGCC coproduction facility generating 426 MWe of electric power could also

manufacture 152,000 gal/day of methanol at a cost of

about 46.5 cents/gal. This compares favorably to new

world-scale (700,000–900,000 gal/day) chemical-grade

methanol plants having a U.S. Gulf Coast delivered cost

of 55–60 cents/gal.

Commercial Applications

The LPMEOHTM process has been developed to enhance

integrated gasification combined-cycle (IGCC) power

generation by producing a clean burning, storable liquid

fuel—methanol—from the clean coal-derived gas.

Design and Construction Operation

1992 1995 1993 1994 1996 1997 1998 1999 2000 2001

Preaward

1991

12/89 10/92

DOE selected

project (CCT-III)

12/19/89

Cooperative agreement awarded 10/16/92

12/01

Project completed/final report issued 12/01*

NEPA process completed (EA) 6/30/95

Construction started 10/95

Design completed 6/96

Environmental monitoring plan completed 8/29/96

4/97

Operation initiated 4/97

Preoperational tests initiated 1/97

Construction completed 1/97

Methanol also has a broad range of commercial applications, can be substituted for conventional fuels in stationary and mobile combustion applications, is an excellent

fuel for utility peaking units, contains no sulfur, and has

exceptionally low-NOx

 characteristics when burned.

Methanol can be produced from coal as a coproduct in an

IGCC facility.

DME has several commercial uses. In a storable

blend with methanol, the mixture can be used as peaking

fuel in IGCC electric power generating facilities. Blends

of methanol and DME can also be used as a chemical

feedstock for the synthesis of chemicals or new, oxygenate

fuel additives. Pure DME has been gaining acceptance as

an environmentally friendly aerosol in personal products.

Typical commercial-scale LPMEOHTM units are

expected to range in size from 50,000 to 300,000 gal/day

of methanol produced when associated with commercial

IGCC power generation trains of 200–500 MWe. Air

Products and Chemicals expects to market the

LPMEOHTM technology through licensing, owning/operating, and tolling arrangements.

Operation completed 3/01*
5-128 Program Update 1996-97 Industrial Applications

Industrial Applications

Technology

Technologies applicable to the industrial sector

address significant environmental issues and barriers

associated with coal use in industrial processes. These

technologies are directed at both continued coal use

and introduction of coal use in various industrial

sectors.

One of the critical environmental concerns has to

do with pollutant emissions resulting from producing

coke from coal in steelmaking. Two approaches to

mitigate or eliminate this problem are being demonstrated. In one, about 40 percent of the coke is

displaced through direct injection of granular coal

into a blast furnace system. The coal is essentially

burned in the blast furnace where the pollutant

emissions are readily controlled (as opposed to first

coking the coal). The other approach precludes the

need for coke making by using a direct iron-making

process, COREX®. In this process, raw coal is

introduced into a melter-gasifier to produce reducing

gas and heat for a unique reduction furnace; no coke

is required. Excess reducing gas is cleaned and used

to fuel a gas turbine for electric power generation.

Because production costs are largely driven by

fuel cost, coal is often the fuel of choice in cement

production. Faced with the need to control SO2

emissions and also to address growing solid waste

management problems, industry sponsored the

demonstration of an innovative SO2 scrubber. The

successfully demonstrated Passamaquoddy Technology Recovery ScrubberTM uses cement kiln dust,

otherwise discarded as waste, to control SO2

 emissions, convert the sulfur and chloride

acid gases to fertilizer, return the

solid by-product as cement kiln

feedstock, and produce distilled

water. No new wastes are generated

and cement kiln dust waste is

converted to feedstock. This technology also has application for controlling pollutant emissions in paper

production and waste-to-energy

applications.

In many industrial boiler

applications, the relatively low,

stable price of coal makes it an

attractive substitute for oil and gas

feedstock. However, drawbacks to

conversion of oil/gas-fired units to

coal include addition of SO2

 and NOx

controls, tube fouling, and the need

for a coolant water circuit for the

combustor. Oil/gas-fired units are not

high SO2

 or NOx emitters, use

relatively tight tube spacing in the

absence of the potential for ash

fouling, and the flow of oil or gas

cools the combustor, precluding the

need for water cooling. For these

reasons, the CCT Program demonstrated an advanced air-cooled,

slagging combustor that could avoid

these potential problems. The

cyclone combustor stages introduction of air to control NOx

, injects

sorbent to control SO2, slags the ash

in the combustor to prevent tube

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 at

Burns Harbor, IN.
Industrial Applications Program Update 1996-97 5-129

Exhibit 5-34

CCT Program Industrial Applications Technology Characteristics

Project Process Size Fact Sheet

Blast Furnace Granular-Coal Injection System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of hot 5-130

Demonstration Project metal/furnace

Advanced Cyclone Combustor with Internal Advanced slagging combustor with staged combustion and sorbent 23 million Btu/hr 5-132

Sulfur, Nitrogen, and Ash Control injection

Clean Power from Integrated Coal/Ore COREX® direct reduction iron-making process to eliminate coke; 195 MWe 5-136

Reduction (CPICORTM) combined-cycle power generation 3,300 tons/day of hot metal

Cement Kiln Flue Gas Recovery Scrubber Cement kiln dust used to capture SO2; dust converted to feedstock; 1,450 tons/day of cement 5-138

and fertilizer and distilled water produced

Demonstration of Pulse Combustion in an Advanced combustion using pulse combustor/gasifier 170 million Btu/hr of medium-Btu 5-142

Application for Steam Gasification of Coal fuel

10 tons/hr of low-sulfur char

4,500 lb/hr of hydrocarbon liquids

fouling, and uses air cooling to preclude the need for

water circuitry.

The cement kiln and slagging combustor projects

are completed. The project demonstrating granularcoal injection into a blast furnace is in operation.

Demonstration of the COREX® direct iron-making

process is in the project definition and design phase.

A fifth project to demonstrate a pulse combustor

in an application for steam gasification of coal was

concluded in March 1997, when the project was

unable to be restructured.

Exhibit 5-34 summarizes process characteristics

and size for the industrial applications technologies

presented in more detail in the project fact sheets.
5-130 Program Update 1996-97 Industrial Applications

Industrial Applications

Blast Furnace Granular-Coal

Injection System

Demonstration Project

Participant

Bethlehem Steel Corporation

Additional Team Members

British Steel Consultants Overseas Services, Inc.

(marketing arm of British Steel Corporation)—

BFGCI technology owner

CPC-Macawber, Ltd. (formerly named SimonMacawber, Ltd.)—equipment supplier (world rights

to sublicense BFGCI)

Fluor Daniel, Inc.—architect and engineer

ATSI, Inc.—injection equipment engineer

(North America BFGCI licensee)

Location

Burns Harbor, Porter County, IN (Bethlehem Steel’s

Burns Harbor Plant, Blast Furnace Units C and D)

Technology

British Steel and CPC-Macawber blast furnace granularcoal injection (BFGCI) process

Plant Capacity/Production

7,000 net tons/day of hot metal (each blast furnace)

Project Funding

Total project cost $194,301,790 100%

DOE 31,824,118 16

Participant 162,477,672 84

Project Objective

To demonstrate that existing iron-making blast furnaces

can be retrofitted with blast furnace granular-coal injection technology; and 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 dependent upon many factors including temperature. Lowering of a raceway temperature, which can

occur with gas injection, reduces blast furnace production rates. Coal, with a lower hydrogen content than

either gas or oil, does not cause as severe a reduction in

raceway temperatures. In addition to displacing injected

natural gas, the coal injected through the tuyeres displaces coke, the primary blast furnace fuel and reductant

(reducing agent), on approximately a pound-for-pound

basis. Because coke production results in significant

emissions of NOx

, SO2, and air toxics and coal could

replace up to 40% of the coke requirement, BFGCI

technology has significant potential to reduce pollutant

emissions and enhance blast furnace production.

Emissions generated by the blast furnace itself

remain virtually unchanged by the injected coal; the gas

exiting the blast furnace is clean, containing no measurable SO2

 or NOx. Sulfur from the coal is removed by the

limestone flux and bound up in the slag, which is a

salable by-product. In addition to the net pollutant emissions reduction realized by coke displacement, blast

furnace production is increased by maintaining high

raceway temperatures.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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

 1 2

Industrial Applications Program Update 1996-97 5-131

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Two high-capacity blast furnaces, Units C and D at

Bethlehem Steel’s Burns Harbor Plant, were retrofitted

with BFGCI technology. Each unit has a production

capacity of 7,000 net tons/day of hot metal. The two

units use about 2,800 tons/day of coal during full operation. Bituminous coals with sulfur content of 0.8–2.8%

from West Virginia, Pennsylvania, Illinois, and Kentucky

are being used. A western subbituminous coal having

0.4–0.9% sulfur is being tested also.

Project Status/Accomplishments

The plant is now fully operational in a commercial

mode. Furnace C has been operated with an average

coal injection rate of 264 lb/net ton of hot metal, using

low-volatile bituminous coals. Coal injection rates

reached 270 lb/ton by mid-1996 and 300 lb/ton for short

periods. Furnace C continued to operate with a coke rate

of approximately 660 lb/net ton of hot metal, down from

770 lb/net ton. Permeability was stabilized at 1.19 with

the addition of moisture to produce more hydrogen in

the bosh gas. Furnace D commonly has achieved coal

injection rates 10% above the design rate of 180 lb/net

ton and has operated at an average coke rate of 715 lb/

ton of hot metal.

A comparison of high- and low-volatile coals as

injectants showed that low-volatile coal replaces more

coke and results in better blast furnace operation than

high-volatile coal. The replacement ratio with lowvolatile coal is 0.96 lb coke/lb coal. A major conclusion

of the work to date was that granular-coal injection

performs very well on large blast furnaces.

Further testing of different coals will include a highash coal and a direct comparison of granular versus

pulverized coal injection. Bethlehem Steel plans to

increase substantially the coal feed rate through all

52 tuyeres for comparison with the baseline standard of

275 lb/net ton of hot metal on Furnace C.

Commercial Applications

BFGCI technology can be applied to essentially all U.S.

blast furnaces. The technology should be applicable to

any rank coal commercially available in the United

Preaward

DOE selected

project (CCT-III)

12/19/89

12/89 11/90

NEPA process completed (EA) 6/8/93

Construction started 9/93

Design completed 12/93

Cooperative agreement awarded 11/26/90

11/95

Operation initiated 11/95

Design and Construction Operation

Environmental monitoring plan completed 12/23/94

Preoperational tests initiated 2/95

Construction completed 2/95

9/98

Project completed/final report

issued 9/98*

Operation completed 9/98*

States that has a moisture content no higher than 12%.

The environmental impacts of commercial application

are primarily indirect and consist of a significant reduction of emissions resulting from diminished coke-making

requirements.

The BFGCI technology was developed jointly by

British Steel and CPC-Macawber (then named

Simon-Macawber). British Steel has granted exclusive

rights to market BFGCI technology worldwide to

CPC-Macawber. CPC-Macawber also has the right to

sublicense BFGCI rights to other organizations throughout the world. British Steel and CPC-Macawber have

recently installed a similar facility at a United States

Steel blast furnace.
5-132 Program Update 1996-97 Industrial Applications

tor was designed to retain as slag a high percentage of

the ash and sorbent fed to the combustor. For NOx

 control, the combustor is operated fuel rich, with final combustion taking place in the boiler furnace to which the

combustor is attached. SO2

 is captured by injection of

limestone into the combustor. The cyclonic action inside

the combustor forces the coal ash and sorbent to the

walls where it can be collected as liquid slag. Under

optimum operating conditions, the slag contains a significant fraction of vitrified coal sulfur. Downstream

sorbent injection into the boiler provides additional

sulfur removal

capacity.

In Coal Tech’s demonstration, an advanced, aircooled, cyclone coal combustor was retrofitted to a

23-million-Btu/hr, oil-designed package boiler located at

the Tampella Power Corporation boiler factory in

Technology/Project Description

Coal Tech’s horizontal cyclone combustor is internally

lined with ceramic that is air-cooled. Pulverized coal,

air, and sorbent are injected tangentially toward the wall

through tubes in the annular region of the combustor to

cause cyclonic action. In this manner, coal-particle

combustion takes place in a swirling flame in a region

favorable to particle retention in the combustor. Secondary air is used to adjust the overall combustor stoichiometry. Tertiary air is injected at the combustor/boiler

interface. The ceramic liner is cooled by the secondary

air and maintained at a temperature high enough to keep

the slag in a liquid, free-flowing state. The secondary air

is preheated by the combustor walls to attain efficient

combustion of the coal particles in the fuel-rich combustor. Fine coal pulverization allows combustion of most

of the coal particles near the cyclone wall. The combusIndustrial Applications

Advanced Cyclone Combustor

with Internal Sulfur, Nitrogen,

and Ash Control

Project completed.

Participant

Coal Tech Corporation

Additional Team Members

Commonwealth of Pennsylvania, Energy Development

Authority—cofunder

Pennsylvania Power and Light Company—supplier of

test coals

Tampella Power Corporation—host

Location

Williamsport, Lycoming County, PA (Tampella Power

Corporation’s boiler manufacturing plant)

Technology

Coal Tech’s advanced, air-cooled, slagging combustor

Plant Capacity/Production

23 million Btu/hr

Coal

Pennsylvania bituminous, 1.0–3.3% sulfur

Project Funding

Total project cost $984,394 100%

DOE 490,149 50

Participant 494,245 50

Project Objective

To demonstrate that an advanced cyclone combustor can

be 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 NOx

 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 4 1 2 3 4

Calendar Year

*Projected date

 1 2

Industrial Applications Program Update 1996-97 5-133

1986 1989 1990 1987 1988 1991 1992 1993 1994 1995 1996

Preaward Operation

7/86 3/87 11/87

Design and Construction

DOE selected project (CCT-I) 7/24/86

Design completed 7/87

Ground breaking/construction started 7/87

Cooperative agreement awarded 3/20/87

NEPA process completed (MTF) 3/26/87

Environmental monitoring plan completed 9/22/87

Construction completed 11/87

Operation initiated 11/87

Operation

completed 5/90

Williamsport, PA.

Results Summary

Environmental

• SO2

 removal efficiencies of over 80% were achieved

with sorbent injection in the furnace at various calcium-to-sulfur molar ratios (Ca/S).

• SO2

 removal efficiencies up to 58% were achieved

with sorbent injection in the combustor at a Ca/S 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)

and furnace hearth.

• At most, 11% of the coal’s sulfur was retained in the

slag rejected through the combustor’s slag tap.

• NOx

 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% to 90%. Under more

fuel lean conditions, retention averaged 80%.

• Meeting local particulate emissions standards required the addition of a wet venturi scrubber.

Operational

• Combustion efficiencies of over 99% were achieved.

• A 3-to-1 combustor turndown capability was demonstrated. Protection of combustor refractory with slag

was shown to be possible.

• A computer-controlled system for automatic combustor operation was developed and demonstrated.

Economic

• Because the technology failed to meet commercialization criteria, economics were not developed during

the demonstration. However, subsequent efforts

indicate that incremental capital costs for installing

the coal combustor in lieu of oil or gas systems are

$100–$200/kW.

Project Summary

The novel features of Coal Tech’s patented ceramic-lined,

slagging cyclone combustor included 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 boiler designs without disturbing the

boiler’s water-steam circuit. In this technology, NOx

reduction was achieved by staged combustion, and SO2

was captured by injection of limestone into the combustor and/or boiler. Critical to combustor performance was

removal of ash, as slag, which would otherwise erode

boiler tubes. This was particularly important in oil furnace retrofits where tube spacing is tight (made possible

by the low-ash content of oil-based fuels).

The test effort consisted of 800 hours of operation,

including five individual tests, each of 4 days duration.

An additional 100 hours of testing was performed as part

8/91

Project completed/final report issued 9/91
5-134 Program Update 1996-97 Industrial Applications

of a separate ash vitrification test. Test results obtained during operation of the combustor indicated that Coal Tech attained most

of the objectives contained in the cooperative

agreement. About eight different Pennsylvania bituminous coals with sulfur contents

ranging from 1.0% to 3.3% and volatile

matter contents ranging from 19% to 37%

were tested.

Environmental Performance

A maximum of over 80% SO2

 reduction

measured at the boiler outlet stack was

achieved using sorbent injection in the furnace at various Ca/S molar ratios. A maximum SO2

 reduction of 58% was measured at

the stack with limestone injection into the

combustor at a Ca/S of 2. A maximum of

one-third of the coal’s sulfur was retained in

the dry ash removed from the combustor and furnace

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-rich

combustion and sorbent-gas mixing.

With fuel-rich operation of the combustor, a threefourths reduction in measured boiler outlet stack NOx

was obtained, corresponding to 184 ppm. An additional

5–10% reduction was obtained by the action of the wet

particulate scrubber, resulting in atmospheric NOx

 emissions as low as 160 ppm.

All the slag removed from the combustor produced

trace metal leachates well below EPA’s Drinking Water

Standard.

Total ash/sorbent retention as slag in the combustor

under efficient combustion operating conditions averaged 72% and ranged from 55% to 90%. Under more

fuel-lean conditions, the slag retention averaged 80%.

In post-CCT-project tests on flyash vitrification in the

combustor, modifications to the solids injection system

and increases in the slag flow rate produced substantial

increases in the slag retention rate. To meet local stack

particulate emission standards, a wet venturi particulate

scrubber was installed at the boiler outlet.

Operational Performance

Combustion efficiencies exceeded 99% after proper

operating procedures were achieved. Combustor turndown to 6 million Btu/hr from a peak of 19 million

Btu/hr (or a 3-to-1 turndown) was achieved. The maximum heat input during the tests was around 20 million

Btu/hr, even though the combustor was designed for

30 million Btu/hr and the boiler was thermally rated at

around 25 million Btu/hr. This situation resulted from

facility limits on water availability for the boiler and for

cooling the combustor. In fact, due to the lack of sufficient water cooling, even 20 million Btu/hr was borderline, so that most of the testing was conducted at lower

rates.

Different sections of the combustor had different

materials requirements. Suitable materials for each

section were identified. Also, the test effort showed that

operational procedures were closely coupled with materials durability. As an example, by implementing certain

procedures, such as changing the combustor wall temperature, it was possible to replenish the combustor

refractory wall thickness with slag produced during

combustion rather than by adding ceramic to the combustor walls.

The combustor’s total operating time during the life

of the CCT project was about 900 hours. This included

approximately 100 hours of operation in two other flyash

vitrification tests projects. Of the total time, about onethird was with coal; about 125 tons of coal were consumed.

Developing proper combustor operating procedures

was also an objective. Not only were procedures for

properly operating an air-cooled combustor developed,

but the entire operating data base was incorporated into a

computer-controlled system for automatic combustor

operation.

Commercial Applications

In conclusion, the goal of this project was to validate the

performance of the air-cooled combustor at a commercial scale. While the combustor was not yet fully ready

for sale with commercial guarantees, it was believed to

have commercial potential. Subsequent work was undertaken, which has brought the technology close to

commercial introduction.

Contacts

Bert Zauderer, President, (215) 667-0442

Coal Tech Corporation

P.O. Box 154

The slagging combustor, associated piping, and control panel for

Coal Tech’s advanced ceramic-lined slagging combustor are shown.
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Calendar Year

*Projected date

 1 2

Industrial Applications Program Update 1996-97 5-135

Merion, PA 19066

William E. Fernald, DOE/HQ, (301) 903-9448

Arthur L. Baldwin, FETC, (412) 892-6011

References

• The Coal Tech Advanced Cyclone Combustor Demonstration Project—A DOE Assessment. Report No.

DOE/PC/79799-T1. U.S. Department of Energy.

May 1993.

• The Demonstration of an Advanced Cyclone Coal

Combustor, with Internal Sulfur, Nitrogen, and Ash

Control for the Conversion of a 23 MMBtu/Hour Oil

Fired Boiler to Pulverized Coal; Vol. 1: Final Technical Report; Vol. 2: Appendixes I–V; Vol. 3: Appendix

VI. Coal Tech Corporation. August 1991. (Available

from NTIS as DE92002587 and DE92002588.)

• Comprehensive Report to Congress on the Clean

Coal Technology Program: Advanced Cyclone Combustor with Integral Sulfur, Nitrogen, and Ash Control. Coal Tech Corporation. Report No. DOE/FE0077. U.S. Department of Energy. February 1987.

(Available from NTIS as DE87005804.)

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 the

conveyor, is essentially an inert glassy by-product with value in the construction industry as

aggregate or in the manufacture of abrasives.
5-136 Program Update 1996-97 Industrial Applications

Project Funding

Total project cost $1,065,805,000 100%

DOE 149,469,242 14

Participant 916,335,758 86

Project Objective

To demonstrate the integration of a direct iron-making

process (COREX®) with the co-production of electricity

using various U.S. coals in an efficient and environmentally responsible manner.

Technology/Project Description

The clean power from integrated coal/ore reduction

(CPICORTM) process integrates two historically distinct

processes—iron making and electric power generation.

COREX® is a novel iron-making technology that eliminates the need for coke production. The key innovative

Industrial Applications

Clean Power from Integrated

Coal/Ore Reduction

(CPICORTM)

Participant

CPICORTM Management Company, L.L.C. (a limited

liability company composed of subsidiaries of Centerior

Energy Corporation, Air Products and Chemicals, Inc.,

and the Geneva Steel Company)

Additional Team Members

Geneva Steel Company—cofunder and host; constructor

and operator of COREX® unit

Centerior Energy Corporation—cofunder

Air Products and Chemicals, Inc.—cofunder; designer,

engineer, constructor, and operator of air separation

and combined-cycle units

Deutsche Voest-Alpine Industrieanlagenbau GmbH—

COREX® developer/supplier; designer and engineer

of COREX® unit

Location

Vineyard, Utah County, UT (Geneva Steel Company’s

mill)

Technology

Integration of Deutsche Voest-Alpine

Industrieanlagenbau’s COREX® iron-making process

with a combined-cycle power generation system

Plant Capacity/Production

195 MWe (net) or 250 MWe (gross) and 3,300 tons/day

of hot metal (liquid iron)

features of the COREX® process include the reduction

shaft furnace, which is used to reduce the iron ore to

iron, and the melter-gasifier, located beneath the reduction furnace, which gasifies the coal and melts the iron.

The gasification process generates the reducing gas for

use in the reduction furnace as well as sufficient heat to

melt the resulting iron in the melter-gasifier.

Excess reducing gas exiting the reduction furnace is

cooled, cleaned, compressed, mixed with air, and burned

in a gas turbine generator system capable of combusting

low-Btu gas to make electric power. The hot exhaust

from the turbine is then delivered to a heat recovery

steam generator where process steam is made for utilization in a steam turbine generator system to produce

additional electric power.

COREX is a registered trademark of Deutsche Voest-Alpine

Industrieanlagenbau GmbH.

CPICOR is a trademark of the CPICOR Management Company, L.L.C.
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Calendar Year

*Projected date

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Industrial Applications Program Update 1996-97 5-137

1993 1996 1997 1994 1995 1998 1999 2000 2001 2002 2003

During the demonstration, the facility will utilize

approximately 3,400 tons/day of a western bituminous

coal blend containing about 0.5% sulfur. The project

will produce 3,300 tons/day of hot metal and 195 MWe.

Project Status/Accomplishments

The cooperative agreement was awarded on October 11,

1996. Permitting and project definition are under way.

Commercial Applications

The CPICORTM technology is a direct replacement for

existing blast furnace and coke-making facilities with the

additional benefit of combined-cycle power generation.

A full-scale commercial plant based on the CPICORTM

demonstration project will produce 195 MWe (net exportable) and 1,200,000 tons/yr of hot metal while expanding the type of coals that can be used to produce hot

metal into the much larger noncoking range.

All criteria pollutants, particularly SO2

 and NOx, are

reduced by more than 85%. This reduction is due largely

to the desulfurizing capability of the COREX® process,

DOE selected project

(CCT-V) 5/4/93

5/93

efficient control systems within the combined-cycle

power generation facility, and use of oxygen in place of

air. The COREX® process releases no air toxics from the

high-temperature gasifier into the environment, and most

trace elements are captured in the slag. The predominant

solid by-product of the COREX® process is a usable slag,

which is similar to blast furnace slag and can be sold as

construction balast.

The energy efficiency of the CPICORTM technology

is over 30% greater than the competing commercial

technology when considering only the effective production of hot metal and electric power. CPICORTM

technology’s higher efficiency is due to the more effective use of sensible heat and volatile matter than the

coke-making/blast furnace process. In addition, combined-cycle power generation achieves energy efficiencies of nearly 50%.

Of the existing 79 U.S. coke oven batteries, half

are 30 years of age or older and are due for replacement

or major rebuilds. There are about 60 U.S. blast furPreaward

Cooperative agreement awarded 10/11/96

NEPA process completed (EIS) 4/98*

Construction started 4/98*

Design and Construction

Operation initiated 9/00*

Environmental monitoring plan completed 9/00*

Construction completed 9/00*

9/00

Operation

10/96 1/03

Project completed/final report issued 1/03*

Operation completed 1/03*

naces, all of which have been operating for more than

10 years, with some originally installed up to 90 years

ago. Worldwide, more than 300 blast furnaces with

capacities of 0.3–1.2 million net tons/yr could be replaced by COREX®.

The CPICORTM project exceeds the individual production rates of 75% of domestic blast furnaces. Further,

a utility facility scale-up by only 150% would exceed

production rates of 90% of existing U.S. blast furnaces.
5-138 Program Update 1996-97 Industrial Applications

Industrial Applications

Cement Kiln Flue Gas

Recovery Scrubber

Project completed.

Participant

Passamaquoddy Tribe

Additional Team Members

Dragon Products Company—project manager and host

HPD, Incorporated—designer and fabricator of tanks

and heat exchanger

Cianbro Corporation—constructor

Location

Thomaston, Knox County, ME (Dragon Products

Company’s coal-fired cement kiln)

Technology

Passamaquoddy Technology Recovery ScrubberTM

Plant Capacity/Production

1,450 tons/day of cement; 250,000 std ft3

/min of kiln

gas; and up to 274 tons/day of coal

Coal

Pennsylvania bituminous, 2.5–3.0% sulfur

Project Funding

Total project cost $17,800,000 100%

DOE 5,982,592 34

Participant 11,817,408 66

Project Objective

To retrofit and demonstrate a full-scale industrial scrubber and waste recovery system for a coal-burning wet

process cement kiln using waste dust as the reagent to

accomplish 90–95% SO2

 reduction using high-sulfur

eastern coals; and to produce a commercial by-product,

potassium-based fertilizer.

Technology/Project Description

The Passamaquoddy Technology Recovery ScrubberTM

uses cement kiln dust (CKD), an alkaline-rich (potassium) waste, to react with the acidic flue gas. This CKD,

representing about 10% of the cement feedstock otherwise lost as waste, is formed into a water-based slurry

and mixed with the flue gas as the slurry passes over a

perforated tray that enables the flue gas to percolate

through the slurry. The SO2

 in the flue gas reacts with

the potassium to form potassium sulfate, which stays in

solution and remains in the liquid as the slurry undergoes

separation into liquid and solid fractions. The solid

fraction, in thickened slurry form and freed of the potassium and other alkali constituents, is returned to the kiln

as feedstock (it is the alkali content that makes the CKD

unusable as feedstock). No dewatering is necessary for

the wet process used at the Dragon Products Plant. The

liquid fraction is passed to a crystallizer that uses waste

heat in the flue gas to evaporate the water and recover

dissolved alkali metal salts. A recuperator lowers the

incoming flue gas temperature to prevent slurry evaporation, enables the use of low-cost fiberglass construction

material, and provides much of the process water

through condensation of exhaust gas moisture.

The Passamaquoddy Technology Recovery ScrubberTM was constructed at the Dragon Products

Company’s cement plant in Thomaston, ME, a plant that

can process approximately 450,000 tons/yr of cement.

The process was developed by the Passamaquoddy Indian Tribe while it was seeking ways to solve landfill

problems, which resulted from the need to dispose of

waste kiln dust from the cement-making process. Passamaquoddy Technology Recovery Scrubber is a trademark of the

Passamaquoddy Tribe.
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Industrial Applications Program Update 1996-97 5-139

Results Summary

Environmental

• The SO2 removal efficiency averaged 94.6% during

the last several months of operation and 89.2% for

the entire operating period.

• The NOx

 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. This

resulted in reducing the raw feedstock requirement by

10% and eliminating solid waste disposal costs.

• Particulate emission rates of 0.005–0.007 gr/std ft3

,

about 1/10 that allowed for cement kilns, were

achieved with dust loadings of approximately

0.04 gr/std ft3

.

• 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

alpha-pinene) 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 host

site downtime) steadily increased from 65% in April

1993 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

and interest costs, are generally offset by avoided

costs associated with fuel, feedstock, and waste disposal and with revenues from the sale of fertilizer.

1988 1991 1992 1989 1990 1993 1994 1995 1996 1997 1998

Preaward Design and Construction

9/88 8/91

Operation

DOE

selected

project

(CCT-II)

9/28/88

12/89

Design completed 4/90

Environmental monitoring plan

completed 3/26/90

Operation initiated 8/91

Construction completed 5/91

Preoperational tests initiated 5/91

NEPA process completed (EA) 2/16/90

Cooperative agreement awarded 12/20/89

Project Summary

The Passamaquoddy Technology Recovery ScrubberTM is

a unique process that achieves efficient acid gas and

particulate control through effective contact between

flue gas and a potassium-rich slurry composed of waste

kiln dust. Flue gas passes through the slurry as it moves

over a special sieve tray. This results in high SO2

 and

particulate capture, some NOx

 reduction, and sufficient

uptake of the potassium (an unwanted constituent in

cement) to allow the slurry to be recycled as feedstocks.

Waste cement kiln dust, exhaust gases (including waste

heat), and wastewater are the only inputs to the process.

Renovated cement kiln dust, potassium-based fertilizer,

scrubbed exhaust gas, and distilled water are the only

proven outputs. There is no waste.

The scrubber was evaluated over 3 basic operating

intervals dictated by winter shutdowns for maintenance

and inventory and 14 separate operating periods (within

these basic intervals) largely determined by unforeseen

host-plant maintenance and repairs and a depressed

2/94

Project completed/final report issued 2/94

Construction started 6/89

Operation

completed 9/93
5-140 Program Update 1996-97 Industrial Applications

cement market. Over the period August 1991 to September 1993, more than 5,300 hours was logged, 1,400

hours in the first operating interval, 1,300 hours in the

second interval, and 2,600 hours in the third interval.

Sulfur loadings varied significantly over the operating

periods due to variations in feedstock and operating

conditions.

Operational Performance

Several design problems were discovered and corrected

during start-up. No further problems were experienced in

these 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,

experienced plugging. Attempts to design a more efficient water spray for cleaning failed. However, replacement with a chevron-type mist eliminator prior to the

third operating interval was effective. Potassium sulfate

pelletization proved to be a more difficult problem. The

cause was eventually isolated and found to be excessive

water entrainment due to carry-over of gypsum and

syngenite. Hydroclones were installed in the crystallizer

circuit to separate the very fine gypsum and syngenite

crystals from the much coarser 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 into the third and final operating interval—April to September 1993. During this

interval, recovery scrubber availability (discounting host

site downtime) steadily increased from 65% in April to

99.5% in July.

Environmental Performance

An average 250 tons/day of CKD waste generated by the

Dragon Products plant was used as the sole reagent in

the recovery scrubber to treat approximately 250,000 std

ft3

/min of flue gas. All the CKD, or approximately

10 tons/hr, were renovated and returned to the plant as

feedstock and mixed with about 90 tons/hr of fresh feed

to make up the required 100 tons/hr. The alkali in the

CKD was converted to potassium-based fertilizer, eliminating all solid waste. Exhibit 5-35 lists the number of

hours per operating period, SO2

 and NOx inlet and outlet

readings in pounds per hour, and removal efficiency as a

percentage for each operating 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 the demonstration.

Aside from the operating period emissions data, an

assessment was made of inlet SO2 load impact on removal efficiency. For SO2

 inlet loads in the range of

100 lb/hr or less, recovery scrubber removal efficiency

averaged 82.0%. For SO2

 inlet loads in the range of

100–200 lb/hr, removal efficiency increased to 94.1%

and up to 98.5% for loads greater than 200 lb/hr.

In compliance testing for the state of Maine’s Department of Environmental Quality, the recovery scrubber was subjected to dust loadings of approximately

0.04 gr/std ft3

 and demonstrated particulate emission

rates of 0.005–0.007 gr/std ft3

—less than 1/10 the current allowable limit.

Exhibit 5-35

Summary of Emissions and Removal Efficiencies

Operating Operating Inlet (lb/hr) Outlet (lb/hr) % Removal Efficiency

Period Time (hr) SO2 NOx SO2 NOx SO2 NOx

1 211 73 320 10 279 87.0 12.8

2 476 71 284 11 260 84.6 08.6

3 464 87 292 13 251 85.4 14.0

4 259 131 252 16 165 87.6 34.5

5 304 245 293 28 243 88.7 17.1

6 379 222 265 28 208 87.4 21.3

7 328 281 345 28 244 90.1 29.3

8 301 124 278 10 188 91.8 32.4

9 314 47 240 7 194 85.7 19.0

10 402 41 244 6 218 86.1 10.5

11 460 36 315 6 267 83.4 15.0

12 549 57 333 2 291 95.9 12.4

13 464 86 288 4 223 95.0 22.6

14 405 124 274 9 199 92.4 27.4

Total 5,316

Weighted Avg 109 289 12 234 89.2 18.8
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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

 1 2

Industrial Applications Program Update 1996-97 5-141

Commercial Applications

Of the approximately 2,000 Portland cement kilns in the

world, about 250 are in the United States and Canada.

These 250 kilns emit an estimated 230,000 tons/yr of

SO2

 (only three plants have SO2 controls, one of which is

the Passamaquoddy Technology Recovery ScrubberTM).

The applicable market for SO2

 control is estimated at

75% of the 250 installations. If full penetration of this

estimated market were realized, approximately

150,000 tons/yr of SO2

 reduction could be achieved.

Contacts

Thomas N. Tureen, Project Manager, (207) 773-7166

Passamaquoddy Technology, L.P.

1 Monument Way

Portland, ME 04101

William E. Fernald, DOE/HQ, (301) 903-9448

John C. McDowell, FETC, (412) 892-6237

References

• Passamaquoddy Technology Recovery ScrubberTM:

Final Report. Volumes 1 and 2 (Appendices A–M. Passamaquoddy Tribe. February 1994. (Vol. 1 available from NTIS as

DE94011175, Vol. 2 as DE94011176.)

• Passamaquoddy Technology Recovery

ScrubberTM: Public Design Report. Report No. DOE/PC/89657-T2.

Passamaquoddy Tribe. October 1993.

(Available from NTIS as DE94008316.)

• Passamaquoddy Technology Recovery

ScrubberTM: Topical Report. Report No.

DOE/PC/89657-T1. Passamaquoddy

Tribe. March 1992. (Available from NTIS

as DE92019868.)

The Passamaquoddy Technology Recovery ScrubberTM became a

permanent part of the Dragon Products facility at the project’s end.

• Comprehensive Report to Congress on the Clean

Coal Technology Program: Cement Kiln Flue Gas

Recovery Scrubber. (Passamaquoddy Tribe). Report

No. DOE/FE-0152. U.S. Department of Energy.

November 1989. (Available from NTIS as

DE90004462.)

The Passamaquoddy Technology Recovery ScubberTM

was successfully demonstrated at Dragon Products

Company’s cement plant in Thomaston, ME.

Economic Performance

The estimated “as built” capital cost to reconstruct the

Dragon Products prototype, absent the modifications, is

$10,090,000 in 1990 dollars.

Annual operating and maintenance costs are estimated at $500,000. Long-term annual maintenance costs

are estimated at $150,000. Power costs, estimated at

$350,000/yr, are the only 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 as

3.1 years. In making this projection, $6,000,000 was

added to the “as built” capital costs to allow for contingency, design/permitting, construction interest, and licensing fees.
5-142 Program Update 1996-97 Industrial Applications

Industrial Applications

Demonstration of Pulse

Combustion in an Application

for Steam Gasification of Coal

Project concluded.

Participant

ThermoChem, Inc.

Additional Team Member

Manufacturing and Technology Conversion

International, Inc.—technology supplier

Location

Silver Bay, Lake County, MN (Northshore Mining

Company facility)

Technology

Advanced combustion using Manufacturing and

Technology Conversion International’s (MTCI) pulse

combustor/gasifier

Plant Capacity/Production

170 million Btu/hr of 280 Btu/std ft3

 medium-Btu fuel

gas plus 10 tons/hr of low-sulfur char and 4,500 lb/hr of

hydrocarbon liquids

Project Funding

Total project cost $37,333,474 100%

DOE 18,666,737 50

Participants 18,666,737 50

Project Objective

To demonstrate the MTCI pulse combustor in an application for steam gasification of coal to produce a mediumBtu fuel gas and char from subbituminous coal.

Technology/Project Description

The MTCI fluidized-bed gasifier incorporates an innovative indirect heating process for thermochemical steam

gasification of coal to produce hydrogen-rich, clean,

medium-Btu fuel gas without the need for an oxygen

plant. The indirect heat transfer is provided by MTCI’s

multiple resonance tube pulse combustor technology

with the resonance tubes comprising the heat exchanger

immersed in the fluidized-bed reactor. Heat transfer is

3–5 times greater than other indirectly heated gasifier

concepts, allowing the heat transfer surface to be

minimized.

The demonstration plant’s overall efficiency is

expected to be 72% or more. In major commercial applications, char combustion and heat recovery operations

can be included to enhance overall plant efficiency.

SO2

 emissions are controlled by scrubbing the product gas using commercially available processes. A market for the by-product sulfur is being sought, and disposal methods are being evaluated.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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

 1 2

Industrial Applications Program Update 1996-97 5-143

Project Status/Accomplishments

The cooperative agreement was awarded on October 27,

1992. Fabrication of the design-verification–scale

253-tube pulse combustor has been completed. On

October 26, 1994, ThermoChem, Inc., requested that

DOE consider relocating the project to Silver Bay, MN.

ThermoChem was unable to restructure the project at the

new site, and on March 3, 1997, the project was concluded.

Commercial Applications

The MTCI fluidized-bed gasifier is expected to provide

the exceptional environmental performance exhibited by

coal gasification in general. SO2

 emissions are controlled by removing hydrogen sulfide from the product

gas prior to combustion; removal efficiencies approaching 99% are possible. Particulate emissions are also

controlled in highly efficient scrubbers. Finally, the

MTCI pulse combustion technology that provides the

required gasifier heat is an inherently low-NOx

 combustion process, thereby assuring that NOx

 emissions are

substantially below acceptable limits.

Because of its potential for reducing emissions

while producing a clean-burning, hydrogen-rich fuel gas,

the MTCI fluidized-bed gasifier is expected to have

considerable commercial potential. Some of the early

industrial applications of this technology are expected to

be waste-to-energy or waste and coal cofired facilities

for power and steam generation. One of the more promising non-coal applications is processing of kraft black

liquor.

The processing of pulp results in the production of

about 88 million tons of by-product black liquor. The

current practice of using black liquor recovery boilers to

produce steam and electricity is inefficient. Replacing

these boilers with MTCI gasifiers would significantly

improve the conversion efficiency. The estimated market for MTCI gasifiers in this application alone is

28 units annually.

Another potential application for the technology is

1991 1992 1993 1994 1997 1998 1999 2000 2001

Preaward

1995 1996

9/91 10/92

DOE selected

project (CCT-IV)

9/12/91

Cooperative agreement

awarded 10/27/92

Project relocation

requested 10/26/94

Project concluded 3/3/97

3/97

Design

in industrial coal gasification because of its modularity

and ability to produce a medium-Btu gas without requiring an oxygen plant.
Program Update 1996-97 A-1

Appendix A: Historical Perspective and Relevant

Legislation

In The Process of Being Updated.
Program Update 1996-97 B-1

Appendix B: Program History

Solicitation History

The objective of the CCT-I solicitation, issued

February 17, 1986, was to seek cost-shared projects to

demonstrate the feasibility of clean coal technologies

for commercial applications. The Program Opportunity Notice (PON) elicited 51 proposals. Nine projects

were selected and 14 projects were placed on a list of

alternatives in the event negotiations on the original 9

projects were unsuccessful; 8 alternate projects were

eventually selected as replacement projects. Projects

were selected from the list of alternates on three

separate occasions.

The CCT-II PON, issued February 22, 1988,

solicited cost-shared, innovative clean coal technology

projects to demonstrate technologies that were capable

of being commercialized in the 1990s, more cost

effective than current technologies, and capable of

achieving significant reductions in SO2 and/or NOx

emissions from existing coal-burning facilities, particularly those that contribute to transboundary and

interstate air pollution. The CCT-II PON was the first

solicitation implementing the recommendations of the

U.S. and Canadian Special Envoys’ report on acid

rain. DOE received 55 proposals and selected 16 as

best furthering the goals and objectives of the PON

(no alternates were selected).

The objective of the CCT-III PON, issued May 1,

1989, was to solicit cost-shared clean coal technology

projects to demonstrate innovative, energy-efficient

technologies capable of being commercialized in the

1990s. These technologies were to be capable of (1)

achieving significant reductions in emissions of SO2

and/or NOx from existing facilities to minimize environmental impacts, such as transboundary and interstate air pollution, and/or (2) providing for future

energy needs in an environmentally acceptable manner. DOE received 48 proposals and selected 13

projects as best furthering the goals and objectives of

the PON.

The CCT-IV PON, issued January 17, 1991,

solicited proposals to conduct cost-shared clean coal

technology projects to demonstrate innovative, energy-efficient, economically competitive technologies.

These technologies were to be capable of (1) retrofitting, repowering, or replacing existing facilities while

achieving significant reductions in the emissions of

SO2

 and/or NOx and/or (2) providing for future energy

needs in an environmentally acceptable manner. A

total of 33 proposals were submitted in response to the

PON. Nine projects were selected; however, 3 have

been withdrawn.

The objective of the CCT-V PON, issued July 6,

1992, was to solicit proposals to conduct cost-shared

demonstration projects that significantly advance the

efficiency and environmental performance of coalusing technologies and are applicable to either new or

existing facilities. In response to the solicitation,

DOE received proposals for 24 projects and selected

5 projects.

Selection and Negotiation

History

July 1986

Nine projects were selected under CCT-I (14 alternate projects selected if negotiations for original

9 unsuccessful).

March 1987

DOE signed cooperative agreements with two CCT-I

participants, Coal Tech Corporation (Advanced

Cyclone Combustor with Internal Sulfur, Nitrogen,

and Ash Control) and The Ohio Power Company

(Tidd PFBC Demonstration Project).

June 1987

DOE signed a cooperative agreement with CCT-I

participant, The Babcock & Wilcox Company (LIMB

Demonstration Project Extension and Coolside

Demonstration).

July 1987

DOE signed a cooperative agreement with CCT-I

participant, Energy and Environmental Research

Corporation (Enhancing the Use of Coals by Gas

Reburning and Sorbent Injection).
B-2 Program Update 1997-97

September 1987

General Electric Company withdrew its proposal

(Integrated Coal Gasification Steam Injection Gas

Turbine Demonstration Plants with Hot Gas Cleanup).

October 1987

Weirton Steel Corporation withdrew its proposal,

Direct Iron Ore Reduction to Replace Coke Oven/

Blast Furnace for Steelmaking, from further

consideration.

Four more CCT-I projects were selected: ColoradoUte Electric Association, Inc. (Nucla CFB Demonstration Project); TRW, Inc. (Advanced Slagging Coal

Combustor Utility Demonstration Project); Minnesota

Department of Natural Resources (COREX

Ironmaking Demonstration Project); and Foster

Wheeler Power Systems, Inc. (Clean Energy IGCC

Demonstration Project).

December 1987

DOE signed cooperative agreements with two more

CCT-I participants, Ohio Ontario Clean Fuels, Inc.,

(Prototype Commercial Coal/Oil Coprocessing

Project) and Energy International, Inc. (Underground

Coal Gasification Demonstration Project).

January 1988

DOE signed a cooperative agreement with The

M.W. Kellogg Company and Bechtel Development

Company for a CCT-I project, The Appalachian

IGCC Demonstration Project.

September 1988

Sixteen projects were selected under CCT-II.

October 1988

DOE signed a cooperative agreement with CCT-I

participant, Colorado-Ute Electric Association, Inc.

(Nucla CFB Demonstration Project).

November 1988

DOE signed a cooperative agreement with CCT-I

participant, TRW, Inc. (Advanced Slagging Coal

Combustor Utility Demonstration Project).

December 1988

Negotiations were terminated with Minnesota Department of Natural Resources under CCT-I.

DOE selected three more CCT-I projects: ABB

Combustion Engineering, Inc., and CQ Inc.

(Development of the Coal Quality Expert); Western

Energy Company (Advanced Coal Conversion

Process Demonstration); and United Coal Company

(Coal Waste Recovery Advanced Technology

Demonstration).

June 1989

The City of Tallahassee CCT-I project, ACFB

Repowering, was selected from the alternate list.

The M.W. Kellogg Company and Bechtel Development Company withdrew their CCT-I project, Clean

Energy IGCC Demonstration Project.

September 1989

United Coal Company withdrew its CCT-I project,

Coal Waste Recovery Advanced Technology Demonstration.

November 1989

DOE signed a cooperative agreement with CCT-II

participant, Bethlehem Steel Corporation (Innovative

Coke Oven Gas Cleaning System for Retrofit Applications).

Combustion Engineering, Inc., (CCT-II) withdrew its

Postcombustion Sorbent Injection Demonstration

Project.

December 1989

Thirteen projects were selected under CCT-III.

DOE signed cooperative agreements with five CCT-II

participants: ABB Combustion Engineering, Inc.

(SNOXTM Flue Gas Cleaning Demonstration Project);

The Babcock & Wilcox Company

(SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project); Passamaquoddy Tribe (Cement Kiln

Flue Gas Recovery Scrubber); Pure Air on the Lake,

L.P. (Advanced Flue Gas Desulfurization Demonstration Project); and Southern Company Services, Inc.

(Demonstration of Advanced Combustion Techniques

for a Wall-Fired Boiler).

Energy International, Inc., withdrew its CCT-I project,

Underground Coal Gasification Demonstration

Project.
Program Update 1996-97 B-3

February 1990

Foster Wheeler Power Systems, Inc., withdrew its

CCT-I proposal, Clean Energy IGCC Demonstration

Project.

April 1990

DOE signed cooperative agreements with three CCTII participants: The Appalachian Power Company

(PFBC Utility Demonstration Project); The Babcock

& Wilcox Company (Demonstration of Coal

Reburning for Cyclone Boiler NOx

 Control); and

Southern Company Services, Inc. (Demonstration of

Innovative Applications of Technology for the

CT-121 FGD Process).

June 1990

DOE signed cooperative agreements with the coparticipants of one CCT-I project, ABB Combustion

Engineering, Inc., and CQ Inc., (Development of the

Coal Quality ExpertTM) and with two CCT-II participants: Southern Company Services, Inc. (Demonstration of Selective Catalytic Reduction Technology for

the Control of NOx

 Emissions from High-Sulfur-CoalFired Boilers) and TransAlta Resources Investment

Corporation (LNS Burner for Cyclone-Fired Boilers

Demonstration Project).

September 1990

DOE signed cooperative agreements with one CCT-I

participant, Rosebud SynCoal Partnership (formerly

Western Energy Company; Advanced Coal Conversion Process Demonstration); one CCT-II participant,

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

Techniques for the Reduction of NOx

 Emissions from

Coal-Fired Boilers); and one CCT-III participant,

ENCOAL® Corporation (ENCOAL® Mild Coal

Gasification Project).

Negotiations terminated with CCT-II participant,

Southwestern Public Service Company (Nichols CFB

Repowering Project).

October 1990

DOE signed cooperative agreements with four

CCT-III participants: AirPol, Inc. (10-MWe Demonstration of Gas Suspension Absorption); The Babcock

& Wilcox Company (Full-Scale Demonstration of

Low-NOx

 Cell Burner Retrofit); Bechtel Corporation

(Confined Zone Dispersion Flue Gas Desulfurization

Demonstration); and Energy and Environmental

Research Corporation (Evaluation of Gas Reburning

and Low-NOx Burners on a Wall-Fired Boiler).

November 1990

DOE signed cooperative agreements with one CCT-I

participant, The City of Tallahassee (Arvah B.

Hopkins Circulating Fluidized-Bed Repowering

Project); one CCT-II participant, ABB Combustion

Engineering, Inc. (Combustion Engineering IGCC

Repowering Project); and two CCT-III participants,

Bethlehem Steel Corporation (Blast Furnace Granular-Coal Injection System Demonstration Project) and

LIFAC–North America (LIFAC Sorbent Injection

Desulfurization Demonstration Project).

December 1990

Negotiations terminated with CCT-II participant,

Otisca Industries, Ltd. (Otisca Fuel Demonstration

Project).

March 1991

DOE signed cooperative agreements with three CCTIII participants: MK-Ferguson Company (Commercial

Demonstration of the NOXSO SO2/NOx Removal Flue

Gas Cleanup System); Public Service Company of

Colorado (Integrated Dry NOx/SO2 Emissions Control

System); and Tampa Electric Company (formerly

Clean Power Cogeneration Limited Partnership;

Tampa Electric Integrated Gasification CombinedCycle Project).

TRW, Inc., withdrew its CCT-I project (Advanced

Slagging Coal Combustion Utility Demonstration

Project).

April 1991

DOE signed a cooperative agreement with CCT-III

participant, Alaska Industrial Development and

Export Authority (Healy Clean Coal Project).

June 1991

DOE withdrew its sponsorship of the Ohio Ontario

Clean Fuels, Inc., CCT-I project, Prototype Commercial Coal/Oil Coprocessing Plant.
B-4 Program Update 1997-97

August 1991

DOE signed a cooperative agreement with CCT-III

participant, DMEC-1 Limited Partnership (formerly

Dairyland Power Cooperative; PCFB Demonstration

Project).

TransAlta Resources Investment Corporation withdrew its CCT-II project, LNS Burner for CycloneFired Boilers Demonstration Project.

September 1991

Nine projects were selected under CCT-IV.

Coal Tech Corporation’s CCT-I project, Advanced

Cyclone Combustor with Internal Sulfur, Nitrogen,

and Ash Control, was completed; final reports have

been issued.

April 1992

Tri-State Generation and Transmission Association,

Inc., (formerly Colorado-Ute Electric Association,

Inc.) completed its CCT-I project, Nucla CFB

Demonstration Project; final reports have been issued.

June 1992

The City of Tallahassee project (CCT-I) was restructured and transferred to York County Energy Partners,

L.P. (York County Energy Partners Cogeneration

Project).

Demonstration Project); and ThermoChem, Inc.

(Demonstration of Pulse Combustion in an Application for Steam Gasification of Coal).

November 1992

The Babcock & Wilcox Company’s CCT-I project,

LIMB Demonstration Project Extension and Coolside

Demonstration, was completed; final reports have

been issued.

May 1993

Five projects were selected under CCT-V: Four

Rivers Energy Partners, L.P. (Four Rivers Energy

Modernization Project; previously, Calvert City

Advanced Energy Project); Duke Energy Corp.

(Camden Clean Energy Demonstration Project);

Centerior Energy Corporation, on behalf of

CPICORTM Management Company L.L.C. (Clean

Power from Integrated Coal/Ore Reduction

[CPICORTM]); Arthur D. Little, Inc. (Clean Coal

Combined-Cycle Project; previously Demonstration

of Coal Diesel Technology at Easton Utilities); and

Pennsylvania Electric Company (Warren Station

Externally Fired Combined-Cycle Demonstration

Project).

July 1993

Union Carbide Chemicals and Plastics Company, Inc.,

withdrew its CCT-IV proposal, Demonstration of the

Union Carbide CANSOLVTM System at the Alcoa

Generating Corporation Warrick Power Plant.

July 1992

DOE signed cooperative agreements with two

CCT-IV participants: Tennessee Valley Authority

(Micronized Coal Reburning Demonstration for NOx

Control on a 175-MWe Wall-Fired Unit) and Wabash

River Coal Gasification Repowering Project Joint

Venture (Wabash River Coal Gasification Repowering

Project).

August 1992

DOE signed a cooperative agreement with CCT-IV

participant, Sierra Pacific Power Company (Piñon

Pine IGCC Power Project).

Cordero Mining Company withdrew from negotiations

its CCT-IV project, Cordero Coal-Upgrading Demonstration Project.

At the participant’s request, Union Carbide Chemicals

and Plastics Company Inc. (CCT-IV) was granted an

extension of 1 year to the DOE deadline for completing negotiations of its Demonstration of the Union

Carbide CANSOLVTM System at the Alcoa Generating Corporation Warrick Power Plant.

October 1992

DOE signed cooperative agreements with one CCT-III

participant, Air Products and Chemicals, Inc. (Commercial-Scale Demonstration of the Liquid-Phase

Methanol [LPMEOHTM] Process) and with four CCTIV participants: Custom Coals International (SelfScrubbing CoalTM: An Integrated Approach to Clean

Air); New York State Electric & Gas Corporation

(Milliken Clean Coal Technology Demonstration

Project); TAMCO Power Partners (Toms Creek IGCC
Program Update 1996-97 B-5

December 1993

The Babcock & Wilcox Company’s CCT-II project,

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project, was completed; final reports have been

issued.

The Babcock & Wilcox Company’s CCT-II project,

Demonstration of Coal Reburning for Cyclone Boiler

NOx Control, was completed; the final technical report

has been issued.

Bechtel Corporation’s CCT-III project, Confined

Zone Dispersion Flue Gas Desulfurization Demonstration, was completed; final reports have been issued.

February 1994

The Passamaquoddy Tribe’s CCT-III project, Cement

Kiln Flue Gas Recovery Scrubber, was completed;

final reports have been issued.

June 1994

DOE signed a cooperative agreement with CCT-V

participant, Arthur D. Little, Inc. (Coal Diesel

Combined-Cycle Project).

Southern Company Services’ CCT-III project,

180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reduction of

NOx

 Emissions from Coal-Fired Boilers, was completed; final reports have been issued.

August 1994

DOE signed cooperative agreements with two CCT-V

participants, Four Rivers Energy Partners, L.P. (Four

Rivers Energy Modernization Project); and Pennsylvania Electric Company (Warren Station Externally

Fired Combined-Cycle Demonstration Project).

The CCT-III project, Commercial Demonstration of

the NOXSO SO2

/NOx Removal Flue Gas Cleanup

System, was relocated and transferred to NOXSO

Corporation.

September 1994

The Air Products and Chemicals CCT-III project,

Commercial-Scale Demonstration of the Liquid-Phase

Methanol (LPMEOHTM) Process, was transferred to

Air Products Liquid Phase Conversion Company, L.P.

December 1994

DOE signed a cooperative agreement with CCT-V

participant, Clean Energy Partners Limited Partnership (formerly Duke Energy Corp.; Clean Energy

Demonstration Project).

The Babcock & Wilcox Company’s CCT-II project,

Full-Scale Demonstration of Low-NOx

 CellBurner

Retrofit, was completed (operational testing was

completed April 1993; project was extended to

complete the boiler water-wall corrosion examination

during the fall 1994 boiler outage); final reports have

been issued.

AirPol’s CCT-III project, 10-MWe Demonstration of

Gas Suspension Absorption, was completed; final

reports have been issued.

LIFAC–North America’s CCT-III project, LIFAC

Sorbent Injection Desulfurization Project, was

completed; final reports are in preparation.

ABB Environmental Systems’ CCT-II project,

SNOXTM Flue Gas Cleaning Demonstration Project,

was completed; final reports are in preparation.

Energy and Environmental Research Corporation’s

CCT-I project, Enhancing the Use of Coal by Gas

Reburning and Sorbent Injection, was completed; final

reports for Hennepin and Edwards have been issued

and the final report for Lakeside is in preparation.

Southern Company Services’ CCT-II project, Demonstration of Innovative Applications of Technology for

the CT-121 FGD Process, completed operational

testing; final reports are in preparation.

January 1995

Energy and Environmental Research Corporation’s

CCT-III project, Evaluation of Gas Reburning and

Low-NOx

 Burners on a Wall-Fired Boiler, completed

operational testing; final reports are in preparation.

March 1995

The Ohio Power Company’s CCT-I project, Tidd

PFBC Demonstration Project, completed operational

testing; final reports have been issued.

TAMCO Power Partner’s CCT-IV project, Toms

Creek IGCC Demonstration Project, was not granted a

further extension and the project was ended.

April 1995

Bethlehem Steel Corporation’s CCT-II project,
B-6 Program Update 1997-97

Innovative Coke Oven Gas Cleaning System for

Retrofit Applications, was terminated by mutual

agreement with DOE because coke production was

suspended at the demonstration facility.

June 1995

Pure Air on the Lake’s CCT-II project, Advanced

Flue Gas Desulfurization Project, completed operational testing; final reports have been issued.

July 1995

Southern Company Services’ CCT-II project, Demonstration of Selective Catalytic Reduction Technology

for the Control of NOx

 Emissions from High-Sulfur

Coal-Fired Boilers, completed operational testing;

final reports have been issued.

December 1995

The Tennessee Valley Authority and New York State

Electric & Gas Corporation finalized an agreement to

allow the project, Micronized Coal Reburning

Demonstration for NOx

 Control, to be conducted at

both Milliken Station in Lansing, NY, and Eastman

Kodak Company in Rochester, NY.

May 1996

The ABB Combustion Engineering, Inc., CCT-II

project, Combustion Engineering IGCC Repowering

Project, was ended.

August 1996

The Arthur D. Little, Inc., CCT-V project was

restructured and retitled as the Clean Coal Diesel

Demonstration Project.

September 1996

The Appalachia Power Company CCT-II project,

PFBC Utility Demonstration Project, was ended.

October 1996

DOE signed a cooperative agreement with CCT-V

participant, CPICORTM Management Company,

L.L.C. (Clean Power from Integrated Coal/Ore

Reduction [CPICORTM]).

The DMEC-1 Limited Partnership project (CCT-III)

was restructured and transferred to the City of

Lakeland, Department of Electric & Water Utilities

(McIntosh Unit 4A PCFB Demonstration Project).

The Four Rivers Energy Partners, L.P., project

(CCT-V) was restructured and transferred to the City

of Lakeland, Department of Electric & Water Utilities

(McIntosh Unit 4B Topped PCFB Demonstration

Project).

December 1996

The ABB Combustion Engineering, Inc., and CQ Inc.

CCT-I project, Development of the Coal Quality

ExpertTM, was completed; final reports are in preparation.

The Public Service Company of Colorado’s CCT-III

project, Integrated Dry NOx/SO2 Emissions Control

System, completed operational testing; final reports

are in preparation.

March 1997

The ThermoChem, Inc., CCT-IV project, Demonstration of Pulse Combustion in an Application for Steam

Gasification of Coal, was concluded.

May 1997

The Pennsylvania Electric Company CCT-V project,

Externally Fired Combined-Cycle Demonstration

Project, was concluded.
Program Update 1996-97 C-1

iii. alternatives to the proposed action,

iv. the relationship between local short-term uses of man’s

environment and the maintenance and enhancement of

long-term productivity, and

v. any irreversible and irretrievable commitments of

resources which would be involved in the proposed

action should it be implemented.

. . . (E) study, develop, and describe appropriate

alternatives to recommended courses of action in any

proposal which involves unresolved conflicts concerning alternative uses of available resources.

NEPA created the CEQ, which has promulgated

regulations that ensure compliance with the act.

Compliance with NEPA

In November 1989, a PEIS was completed for the

entire CCT Program. This PEIS addressed issues

such as potential global climatic modification and the

ecological and socioeconomic impacts of the CCT

Program. The PEIS evaluated the following two

alternatives:

• “No action,” which assumed that conventional

coal-fired technologies with conventional flue

gas desulfurization controls would continue to

be used

• “Proposed action,” which assumed that

successfully demonstrated clean coal technologies would undergo widespread commercialization by the year 2010

Appendix C: Environmental Aspects

for 1 project, MTFs for 17 projects, EAs for 18

projects and EISs for 4 proposed projects (actions

exceed 33 because of project terminations, withdrawals, and restructuring).

For each project cofunded by DOE under the

CCT Program, the industrial participant is required to

develop an environmental monitoring plan (EMP) that

will ensure operational compliance and that significant

technical and environmental data are collected and

disseminated. Data to be collected include compliance data to meet federal, state, and local requirements and performance data to aid in future commercialization of the technology.

The Role of NEPA in the CCT

Program

NEPA was initially enacted in 1969 as Public

Law 91-190 and has since been amended, most recently by Public Law 94-83 in 1975. The applicability of

NEPA to the CCT Program is encapsulated in the

following provision (Section 102):

[A]ll agencies of the Federal Government shall . . . (C)

include in every recommendation or report on proposals for

legislation and other major Federal actions significantly

affecting the quality of the human environment, a detailed

statement by the responsible official on—

i. the environmental impact of the proposed action,

ii. any adverse environmental effects which cannot be

avoided should the proposal be implemented,

Introduction

DOE employs a three-step process to ensure that

the CCT Program and its projects comply with the

environmental requirements of the National Environmental Policy Act (NEPA) and the regulations for

NEPA compliance promulgated by the Council on

Environmental Quality (CEQ) (40 CFR Parts 1500–

1508) and by DOE (10 CFR Part 1021). This process

includes (1) preparation in 1989 of a programmatic

environmental impact statement (PEIS); (2) preparation of preselection, project-specific environmental

reviews; and (3) preparation of postselection, sitespecific NEPA documentation. Several types of

NEPA documents have been used in the CCT Program, including memoranda-to-file (MTF; discontinued as of September 30, 1990), environmental assessments (EA), and environmental impact statements

(EIS). DOE’s NEPA regulations also provide for

categorical exclusions (CX) for certain classes of

actions.

Exhibit C-1 shows the progress made through

June 30, 1997, to complete NEPA reviews of projects

in the CCT Program. By June 30, 1997, NEPA

reviews were completed for 33 of the 39 CCT projects

remaining in the program (two NEPA reviews were

completed for one project, Enhancing the Use of

Coals by Gas Reburning and Sorbent Injection—an

MTF was completed for the Hennepin site and an EA

for the Lakeside site). From 1987 through June 30,

1997, NEPA requirements were satisfied with a CX
C-2 Program Update 1996-97

Upon selection, project participants are required

to prepare and submit additional environmental

information. This detailed site- and project-specific

information is used, along with independent information gathered by DOE, as the basis for site-specific

NEPA documents which are prepared by DOE for

each selected project. These NEPA documents are

prepared, considered, and published in full conformance with CEQ and DOE regulations for NEPA

compliance.

Categorical Exclusions

“Subpart D—Typical Classes of Actions” of the

DOE NEPA regulations provide for categorical

exclusions as a class of actions that DOE has determined do not individually or cumulatively have a

significant effect on the human environment. One

project, Micronized Coal Reburning Demonstration

for NOx Control, was covered by a categorical exclusion (NEPA review was completed August 13, 1992).

Memoranda-to-File

The MTF was established when DOE’s NEPA

guidelines were first issued in 1980. The MTF was

intended for circumstances when the expected impacts

of the proposed action were clearly insignificant, yet

the action had not been specified as a categorical

exclusion from NEPA documentation. The use of the

MTF was terminated as of September 30, 1990.

Exhibit C-2 lists the 17 projects for which an MTF

was prepared.

a Includes an MTF (1988) and an EA (1989)

required for one project

Memoranda-to-file

Environmental assessments

b Includes an EA for a project that was

withdrawn

Exhibit C-1

NEPA Reviews Completed through June 30, 1997

In preselection project-specific environmental

reviews, DOE evaluates the environmental aspects of

each proposed demonstration project. Reviews are

provided to the Source Selection Official for consideration in the project selection process. The sitespecific environmental, health, safety, and socioeconomic issues associated with each proposed project

are examined during the environmental review. As

part of the comprehensive evaluation prior to selecting projects, the strengths and weaknesses of each

proposal are compared with the environmental evaluation criteria. To the maximum extent possible, the

environmental impacts of each proposed project and

practical mitigating measures are considered. Also, a

list of necessary permits is prepared, to the extent

known; these are permits that would need to be

obtained in implementing the proposed project.

c Includes an EA for a

project that was terminated

Categorical exclusions

Environmental impact statements

Number of Projects
Program Update 1996-97 C-3

Project and Participant Completed

CCT-I

Development of the Coal Quality Expert (ABB Combustion Engineering, Inc., and CQ Inc.) 4/27/90

LIMB Demonstration Project Extension and Coolside Demonstration 6/2/87

(The Babcock & Wilcox Company)

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 3/26/87

(Coal Tech Corporation)

Nucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State 4/18/88

Generation and Transmission Association, Inc.)

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Hennepin site) 5/9/88

(Energy and Environmental Research Corporation)

Tidd PFBC Demonstration Project (The Ohio Power Company) 3/5/87

CCT-II

SNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) 1/31/90

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project 9/22/89

(The Babcock & Wilcox Company)

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler 5/22/89

(Southern Company Services, Inc.)

Demonstration of Selective Catalytic Reduction Technology for the Control of NOx 8/16/89

Emissions from High-Sulfur-Coal-Fired Boilers (Southern Company Services, Inc.)

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the 7/21/89

Reduction of NOx

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

CCT-III

10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) 9/21/90

Full-Scale Demonstration of Low-NOx

 Cell Burner Retrofit (The Babcock & Wilcox Company) 8/10/90

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) 9/25/90

Evaluation of Gas Reburning and Low-NOx

 Burners on a Wall-Fired Boiler (Energy and 9/6/90

Environmental Research Corporation)

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) 10/2/90

Integrated Dry NOx

/SO2 Emissions Control System (Public Service Company of Colorado) 9/27/90

Environmental Assessments

An EA has the following three functions:

1. To provide sufficient evidence and analysis for

determining whether a proposed action

requires preparation of an EIS or a finding of

no significant impact (FONSI)

2. To aid an agency’s compliance with NEPA

when no EIS is necessary, i.e., to provide an

interdisciplinary review of proposed actions,

assess potential impacts, and help identify

better alternatives and mitigation measures

3. To facilitate preparation of an EIS when one is

necessary

An EA’s contents are determined on a case-bycase basis and depend on the nature of the action. If

appropriate, a DOE EA also includes any floodplain

or wetlands assessment that has been prepared and

may include analyses needed for other environmental

determinations.

If an agency determines on the basis of an EA

that it is not necessary to prepare an EIS, a FONSI is

issued. CEQ regulations describe the FONSI as a

document that briefly presents the reasons why an

action will not have a significant effect on the human

environment and for which an EIS therefore will not

be prepared. The FONSI includes the EA, or a

summary of it, and notes any other related environmental documents. CEQ and DOE regulations also

provide for notification of the public that a FONSI has

been issued. Also, DOE provides copies of the EA

and FONSI to the public on request.

Exhibit C-3 lists the 18 projects for which an EA

has been prepared. The exhibit includes EAs for one

Exhibit C-2

Memoranda-to-File Completed
C-4 Program Update 1996-97

Project and Participant Completed

CCT-I

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Lakeside site) (Energy and Environmental Research Corporation) 6/25/89

Advanced Coal Conversion Process Demonstration (Rosebud SynCoal Partnership) 3/27/91

CCT-II

Combustion Engineering IGCC Repowering Project (ABB Combustion Engineering, Inc.) (project terminated) 3/27/92

Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control (The Babcock & Wilcox Company) 2/12/91

Innovative Coke Oven Gas Cleaning System for Retrofit Applications (Bethlehem Steel Corporation) (project terminated) 12/22/89

Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) 2/16/90

Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) 4/16/90

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) 8/10/90

Low-NOx

/SO2 Burner Retrofit for Utility Cyclone Boilers (TransAlta Resources Investment Corporation) (project withdrawn) 3/21/91

CCT-III

Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Company, L.P.) 6/30/95

Blast Furnace Granulated-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) 6/8/93

ENCOAL® Mild Coal Gasification Project (ENCOAL® Corporation) 8/1/90

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) (Warrick Power Plant site) 6/26/95

CCT-IV

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air (Custom Coals International) 2/14/94

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Company) 8/18/93

Warren Station Externally Fired Combined-Cycle Demonstration Project (Pennsylvania Electric Company) (Warren Station site) (project terminated) 5/18/95

Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) 5/28/93

CCT-V

Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) 6/2/97

Exhibit C-3

Environmental Assessments Completed
Program Update 1996-97 C-5

Project and Participant Completed*

CCT-I

York County Energy Partners Cogeneration Project (York County site) 8/11/95

(York County Energy Partners, L.P.)

CCT-III

Healy Clean Coal Project (Alaska Industrial Development and Export Authority) 3/10/94

Tampa Electric Company Integrated Gasification Combined-Cycle Project 8/17/94

(Tampa Electric Company)

CCT-IV

Piñon Pine IGCC Power Project (Sierra Pacific Power Company) 11/8/94

* Completion is the date DOE issued a record of decision.

project that was subsequently withdrawn from the

program—TransAlta Resources Investment Corporation’s Low-NOx

/SO2 Burner Retrofit for Utility Cyclone Boilers project—and three that were terminated—ABB Combustion Engineering’s Combustion

Engineering IGCC Repowering Project, Bethlehem

Steel Corporation’s Innovative Coke Oven Gas Cleaning System for Retrofit Applications, and Pennsylvania Electric’s Warren Station Externally Fired Combined-Cycle Demonstration Project.

The list of completed EAs includes one for the

original site of NOXSO Corporation’s project. However, relocation of the project will require a new

NEPA compliance document (see Exhibit C-4).

Environmental Impact Statements

The primary purpose of an EIS is to serve as an

action-forcing device to ensure that the policies and

goals defined in NEPA are infused into the programs

and actions of the federal government. An EIS contains a full and fair discussion of all significant environmental impacts. The EIS should inform decision

makers and the public of reasonable alternatives that

would avoid or minimize adverse impacts or enhance

the quality of the human environment.

The CEQ regulations state that an EIS is to be

more than a disclosure document; it is to be used by

federal officials in conjunction with other relevant

material to plan actions and make decisions. Analysis

of alternatives is to encompass those to be considered

by the ultimate decision-maker, including a complete

description of the proposed action. In short, the EIS is

a means of assessing the environmental impacts of a

proposed DOE action, rather than justifying decisions

already made, prior to making a decision to proceed

Environmental Monitoring

CCT project participants are required to develop

and implement an environmental monitoring plan

(EMP) which addresses both compliance and supplemental monitoring. Exhibit C-6 lists the status of

EMPs for all 39 projects in the CCT Program. The

EMP is intended to ensure collection and dissemination of the significant technology-, project-, and sitespecific environmental data necessary for evaluation

of impacts upon health, safety, and the environment.

Further, the data are used to characterize and quantify

the environmental performance of the technology in

order to evaluate its commercialization and

deployment potential. In addition to regulatory

Exhibit C-4

Environmental Impact Statements Completed

with the proposed action. Consequently, before a

record of decision is issued, DOE may not take any

action that would have an adverse environmental

effect or limit the choice of reasonable alternatives.

EISs for three projects were completed in 1994. In

1995, DOE issued a record of decision on the EIS

prepared for the York County Energy Partners project

located in York county, Pennsylvania. However,

because this project is being restructured, a new

NEPA compliance document will be required for the

new site. (See Exhibit C-4).

NEPA Actions in Progress

Exhibit C-5 lists the status of projects for which

the NEPA process has not yet been completed.
C-6 Program Update 1996-97

Project and Participant Status

CCT-I

ACFB Demonstration Project (York County Energy Partners, L.P.) (new site) To be determined

CCT-III

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, EIS planned (10/99)

Department of Electric & Water Utilities)

Commercial Demonstration of the NOXSO SO2

/NOx Removal Flue Gas To be determined

Cleanup System (NOXSO Corporation) (new site)

CCT-V

McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, EIS planned (10/99)

Department of Electric & Water Utilities)

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management EIS planned (4/98)

Company, L.L.C.)

Clean Energy Demonstration Project (Clean Energy Partners Limited Partnership) To be determined

Air Toxics

Title III of the CAAA of 1990 lists known hazardous air pollutants (HAPs) and, among other things,

calls for the Environmental Protection Agency (EPA)

to establish categories of sources that emit these

pollutants. Exploratory analyses suggest that HAPs

may be released by conventional coal-fired power

plants and, presumably, by plants utilizing clean coal

technologies. It is expected that emissions standards

will be proposed for the electric-power-productionsource categories. However, there are many uncertainties as to which HAPs will be regulated, their

prevalence in various types and sources of coal, and

their nature and fate as functions of combustion

characteristics and the particular clean coal technology utilized.

The CCT Program recognizes the importance of

monitoring HAPs in achieving widespread commercialization in the late 1990s and beyond. For all

projects with existing cooperative agreements, DOE

sought to include HAPs monitoring. A total of 24

projects contain provisions for monitoring HAPs.

The CCT-V PON acknowledged the importance

of HAPs throughout the solicitation, including them as

an aspect of proposal evaluation. The PON addressed

the control of air toxics as an environmental performance criterion. Also, in the instructions on proposal

preparation, the PON directed proposers as follows:

With respect to emission of air toxics, Proposers

should consider . . . the particular elements and compounds

[listed in Table 5-1 of the PON, “Specific Air Toxics to be

Monitored”]. Proposers should present any information

known concerning the reduction of emissions of these

toxics by [the proposed] technology. Some of the toxics for

Exhibit C-5

NEPA Reviews in Progress

compliance data, further monitoring is required to

fulfill the following:

• Ensure that emissions, ambient levels of

pollutants, and environmental impacts do not

exceed expectations projected in the NEPA

documents

• Identify any need for corrective action

• Verify the implementation of any mitigative

measure that may have been identified in a

mitigation action plan pursuant to the provisions of an EA or EIS

• Provide the essential data on the environmental performance of the technology needed to

evaluate the potential impact of future commercialization, including the ability of the

technology to meet requirements of the Clean

Air Act and the 1990 amendments

The objective of the CCT Program’s environmental monitoring efforts is to ensure that, when commercially available, clean coal technologies will be

capable of responding fully to air toxics regulations

that emerge from the CAAA of 1990, and, to the

extent possible, are in the vanguard of cost-effective

solutions to concerns about public health and safety

related to coal use.
Program Update 1996-97 C-7

which the proposed technology may offer control are likely

unregulated in the target market at present. The significance and importance of the additional control afforded by

the proposed technology for the continued use of coal

should be explained. An example of this kind would be one

or more particular air toxic compounds controlled by a

technology meant for use in power generation.

The CCT-V PON also stipulates that information

on air toxics be presented in the environmental information required by DOE. Exhibit C-7 lists the 23

projects that provide for HAPs monitoring. Ten of

these projects have completed the HAPs monitoring

requirements. The objective of the HAPs monitoring

program is to improve the quality of HAPs data being

gathered and to monitor a broader range of plant

configurations and emissions control equipment.

The CCT Program is coordinating with organizations such as the Electric Power Research Institute

(EPRI) and the Ohio Coal Development Office in

activities focused on HAPs monitoring and analysis.

Further, under the DOE Coal R&D Program, two

reports summarizing the source, distribution, and fate

of HAPs from coal-fired power plants were published

in 1996. A report released in July 1996, Summary of

Air Toxics Emissions Testing at Sixteen Utility Plants,

provided assessment of HAPs measured in the coal,

across the major pollution control devices, and the

HAPs emitted from the stack. A second report, A

Comprehensive Assessment of Toxics Emissions from

Coal-Fired Power Plants: Phase I Results from the

U.S. Department of Energy Study, was released in

September 1996 and provided the raw data from the

emissions testing. Emissions data were collected from

16 power plants, representing nine process configurations, operated by eight different utilities; several

power plants were sites for CCT projects. The power

plants represented a range of different coal types,

process configurations, furnace types, and pollution

control methods.

The second phase of the DOE/EPRI effort currently in progress will conduct sampling at other sites,

including the CCT Program’s Wabash River integrated gasification combined-cycle (IGCC) project.

Further, the results from the first phase will be used to

determine what configuration and coal types require

further assessment.

In October 1996, EPA submitted to Congress an

interim version of its technical assessment of toxic air

pollutant emissions from power plants, Study of

Hazardous Air Pollutant Emissions from Electric

Utility Steam Generating Units, Interim Final Report.

EPA plans to continue evaluating the potential exposures and potential public health concerns from

mercury emissions from utilities. In addition, the

agency will evaluate information on various potential

control technologies for mercury. If EPA decides that

HAPs pose a risk, then the agency must propose air

toxic emissions controls by November 15, 1998, and

make them final 2 years later.

However, the results of the HAPs program have

significantly mitigated concerns about HAPs emission

from coal-fired generation and focused attention on

but a few flue gas constituents. The results have the

potential to make the forthcoming EPA regulations

less strict, which could avoid unnecessary control

costs and thus save consumers money on electricity

bills.
C-8 Program Update 1996-97

Project and Participant Status

CCT-I

Development of the Coal Quality Expert (ABB Combustion Engineering, Inc., and CQ Inc.) Completed 7/31/90

LIMB Demonstration Project Extension and Coolside Demonstration (The Babcock & Wilcox Company) Completed 10/19/88

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) Completed 9/22/87

Nucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State Generation and Transmission Association, Inc.) Completed 2/27/88

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Completed 10/15/89 (Hennepin)

Completed 11/15/89 (Lakeside)

Tidd PFBC Demonstration Project (The Ohio Power Company) Completed 5/25/88

Advanced Coal Conversion Process Demonstration (Rosebud SynCoal Partnership) Completed 4/7/92

ACFB Demonstration Project (York County Energy Partners, L.P.) To be determined

CCT-II

SNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) Completed 10/31/91

Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control (The Babcock & Wilcox Company) Completed 11/18/91

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Completed 12/31/91

Innovative Coke Oven Gas Cleaning System for Retrofit Applications (Bethlehem Steel Corporation) (project terminated) Completed 7/5/91

Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) Completed 3/26/90

Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Completed 1/31/91

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Completed 9/14/90

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Completed 12/18/90

Demonstration of Selective Catalytic Reduction Technology for the Control of NOx

 Emissions from High-Sulfur-Coal-Fired Completed 3/11/93

Boilers (Southern Company Services, Inc.)

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques for the Reduction of NOx

 Emissions from Completed 12/27/90

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

Exhibit C-6

Status of Environmental Monitoring Plans for CCT Projects
Program Update 1996-97 C-9

Project and Participant Status

CCT-III

Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Process (Air Products Liquid Phase Conversion Company, L.P.) Completed 8/29/96

10-MW Demonstration of Gas Suspension Absorption (AirPol, Inc.) Completed 10/2/92

Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Completed 4/11/97

Full-Scale Demonstration of Low-NOx

 Cell Burner Retrofit (The Babcock & Wilcox Company) Completed 8/9/91

Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) Completed 6/12/91

Blast Furnace Granulated-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) Completed 12/23/94

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Department of Electric & Water Utilities) Projected 8/01

ENCOAL Mild Coal Gasification Project (ENCOAL Corporation) Completed 5/29/92

Evaluation of Gas Reburning and Low-NOx

 Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) Completed 7/26/90

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) Completed 6/12/92

Commercial Demonstration of the NOXSO SO2

/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) To be determined

Integrated Dry NOx

/SO2 Emissions Control System (Public Service Company of Colorado) Completed 8/5/93

Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Completed 5/96

CCT-IV

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air (Custom Coals International) Projected 12/97

Micronized Coal Reburning Demonstration for NOx

 Control (New York State Electric & Gas Corporation) Projected 8/97

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) Completed 12/1/94

Piñon Pine IGCC Power Project (Sierra Pacific Power Company) Completed 10/31/96

Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Completed 7/9/93

CCT-V

Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) To be determined

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management Company, L.L.C.) Projected 9/00

Clean Energy Demonstration Project (Clean Energy Partners Limited Partnership) To be determined

McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, Department of Electric & Water Utilities) Projected 8/03

Exhibit C-6 (continued)

Status of Environmental Monitoring Plans for CCT Projects
C-10 Program Update 1996-97

Coal Processing for

Clean Fuels

Application Category Participant Project Status

Alaska Industrial Development and Export Authority Healy Clean Coal Project Planned

Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project Planned

Clean Energy Partners Limited Partnership Clean Energy Demonstration Project Planned

City of Lakeland, Department of Electric & McIntosh Unit 4B Topped PFBC Demonstration Project Planned

Water Utilities

The Ohio Power Company Tidd PFBC Demonstration Project Completed

Sierra Pacific Power Company Piñon Pine IGCC Power Project Planned

Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project Planned

Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project In progress

Project Joint Venture

York County Energy Partners, L.P. ACFB Demonstration Project Planned

ABB Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project Completed

AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption Completed

The Babcock & Wilcox Company Demonstration of Coal Reburning for Cyclone Boiler NOx Control Completed

The Babcock & Wilcox Company SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project Completed

New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project In progress

Public Service Company of Colorado Integrated Dry NOx

/SO2 Emissions Control System Completed

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Completed

Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Completed

Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the Completed

CT-121 FGD Process

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

Techniques for the Reduction of NOx

 Emissions from Coal-Fired Boilers

Custom Coals International Self-Scrubbing CoalTM: An Integrated Approach to Clean Air In progress

ENCOAL® Corporation ENCOAL® Mild Coal Gasification Project In progress

CPICORTM Management Company, L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICORTM) Planned

Exhibit C-7

CCT Projects Monitoring Hazardous Air Pollutants

Advanced Electric

Power Generation

Industrial

Applications

Environmental

Control Devices
Program Update 1996-97 D-1

Appendix D: CCT Project Contacts

Confined Zone Dispersion Flue Gas

Desulfurization Demonstration

Participant:

Bechtel Corporation

Contacts:

Joseph T. Newman, Project Manager

(415) 768-1189

(415) 768-3580 (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:

Jim Hervol, Project Manager

(412) 497-2235

(412) 497-2298 (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:

Don C. Vymazal, Manager, Contract Administration

(610) 481-3687

Pure Air on the Lake, L.P.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

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 Innovative Applications of

Technology for the CT-121 FGD Process

Participant:

Southern Company Services, Inc.

Contacts:

David P. Burford, Project Manager

(205) 992-6329

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

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 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:

Frank E. Hsu,Vice President, Operations

(201) 490-6400

(201) 538-8066 (fax)

AirPol, Inc.

3 Century Drive

Parsippany, NJ 07054-4610

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

lawrence.saroff@hq.doe.gov

Sharon K. Marchant, FETC, (412) 892-6008

marchant@fetc.doe.gov
D-2 Program Update 1996-97

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

(714) 859-8851

(714) 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

Micronized Coal Reburning Demonstration of NOx

Control

Participant:

New York State Electric & Gas Corporation

Contacts:

Dennis O'Dea, Project Manager

(607) 729-2551

New York State Electric & Gas Corporation

120 Chenango Street

Binghamton, NY 13902

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 Advanced Combustion

Techniques for a Wall-Fired Boiler

Participant:

Southern Company Services, Inc.

Contacts:

John N. Sorge, ICCT Project Manager

(205) 877-7426

john.sorge@scsnet.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

Scott M. Smouse, FETC, (412) 892-5725

smouse@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:

Robert R. Hardman, Project Manager

(205) 257-7772

rob.hardman@scsnet.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

Arthur L. Baldwin, FETC, (412) 892-6011

baldwin@fetc.doe.gov

Environmental Control Devices—NOx

 Control

Technologies

Demonstration of Coal Reburning for Cyclone

Boiler NOx

 Control

Participant:

The Babcock & Wilcox Company

Contacts:

Tony Yagiela

(330) 829-7403

The Babcock & Wilcox Company

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

Full-Scale Demonstration of Low-NOx CellBurner

Retrofit

Participant:

The Babcock & Wilcox Company

Contacts:

Tony Yagiela

(330) 829-7403

The Babcock & Wilcox Company

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
Program Update 1996-97 D-3

LIMB Demonstration Project Extension and

Coolside Demonstration

Participant:

The Babcock & Wilcox Company

Contacts:

Paul Nolan

(216) 860-1074

(216) 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

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

watts@fetc.doe.gov

SOx

-NOx-Rox BoxTM Flue Gas Cleanup

Demonstration Project

Participant:

The Babcock & Wilcox Company

Contacts:

Kevin Redinger

(330) 829-7719

The Babcock & Wilcox Company

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.do.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

(714) 859-8851

(714) 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

Milliken Clean Coal Technology Demonstration

Project

Participant:

New York State Electric & Gas Corporation

Contacts:

Dennis O’Dea, Project Manager

(607) 729-2551

New York State Electric & Gas Corporation

120 Chenango Street

Binghamton, NY 13902

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:

Robert R. Hardman, Project Manager

(205) 257-7772

rob.hardman@scsnet.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

Scott M. Smouse, FETC, (412) 892-5725

smouse@fetc.doe.gov

Environmental Control Devices—Combined

SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration

Project

Participant:

ABB Environmental Systems

Contacts:

Paul Yosick, Project Manager

(423) 653-7550

ABB Environmental Systems

1400 Center Port 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
D-4 Program Update 1996-97

Commercial Demonstration of the NOXSO

SO2/NOx Removal Flue Gas Cleanup System

Participant:

NOXSO Corporation

Contacts:

James B. Black

(412) 854-12007

(412) 854-5729 (fax)

noxso@city-net.com

NOXSO Corporation

2414 Lytle Road

Bethel Park, PA 15102-2704

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

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

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@msp.psco.com

Public Service Company of Colorado

550 15th Street, Suite 880

Denver, CO 80202

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

lawrence.saroff@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

ACFB Demonstration Project

Participant:

York County Energy Partners, L.P.

Contacts:

Bradley F. Hahn, Project Manager

(610) 481-3955

(610) 481-2393 (fax)

York County Energy Partners, L.P.

25 South Main Street

Spring Grove, PA 17362

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Advanced Electric Power Generation—

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project

Participant:

City of Lakeland, Department of Electric & Water

Utilities

Contacts:

Alfred M. Dodd, Project Manager

(941) 499-6461

(941) 499-6344 (fax)

Lakeland Electric & Water Utilities

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, Department of Electric & Water

Utilities

Contacts:

Alfred M. Dodd, Project Manager

(941) 499-6461

(941) 499-6344 (fax)

Lakeland Electric & Water Utilities

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
Program Update 1996-97 D-5

Nucla CFB Demonstration Project

Participant:

Tri-State Generation and Transmission

Association, Inc.

Contacts:

Marshall L. Pendergrass, Assistant General Manager

(303) 249-4501

Tri-State Generation and Transmission

Association, Inc.

P.O. Box 1149

Montrose, CO 81402

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Advanced Electric Power Generation—

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project

Participant:

Clean Energy Partners Limited Partnership

Contacts:

Victor Shellhorse, Vice President

(704) 373-2474

(704) 382-9325 (fax)

Duke Energy Corp.

400 S. Tryon Street

Charlotte, NC 28202

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Gary A. Nelkin, FETC, (304) 285-4216

gnelki@fetc.doe.gov

Piñon Pine IGCC Power Project

Participant:

Sierra Pacific Power Company

Contacts:

Sherry Dawes, Project Manager

(702) 343-0816

(702) 343-0407 (fax)

sherry@sppco.sppco.com

Sierra Pacific Power Company

6100 Neil Road

Reno, NV 89520-0400

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@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) 228-1332

(813) 228-4802 (fax)

TECO Power Services, Inc.

P.O. Box 111

Tampa, FL 33601-0111

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Web Site:

http://www.teco.net/teco/TEPlkPwrStn.html

Wabash River Coal Gasification Repowering

Project

Participant:

Wabash River Coal Gasification Repowering Project

Joint Venture

Contacts:

Phil Amick

(713) 735-4178

(713) 735-4837 (fax)

amick@destec.attmail.com

Destec Energy, Inc.

2500 CityWest Boulevard, Suite 150

Houston, TX 77042

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Gary A. Nelkin, FETC, (304) 285-4216

gnelki@fetc.doe.gov
D-6 Program Update 1996-97

Advanced Electric Power Generation—

Advanced Combustion/Heat Engines

Healy Clean Coal Project

Participant:

Alaska Industrial Development and Export Authority

Contacts:

John B. Olson, Deputy Director (Development)

(907) 269-3000

(907) 269-3044 (fax)

jolson@aidea.alaska.net

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

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.

200 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

Externally Fired Combined-Cycle Demonstration

Project

Participant:

Pennsylvania Electric Company

Contacts:

Kenneth Gray, Project Manager

(814) 533-8044

(814) 533-8108 (fax)

Pennsylvania Electric Company

1001 Broad Street

Johnstown, PA 15907

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

Coal Processing for Clean Fuels—

Coal Preparation Technologies

Development of the Coal Quality ExpertTM

Participants:

ABB Combustion Engineering, Inc., and CQ Inc.

Contacts:

Clark D. Harrison, President

(412) 479-6016

CQ Inc.

One Quality Center

P.O. Box 280

Homer City, PA 15748-0280

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Scott M. Smouse, FETC, (412) 892-5725

smouse@fetc.doe.gov

Web Site:

http://www.fuels.bv.com:80/cqe/cqe.htm

Self-Scrubbing CoalTM: An Integrated Approach

to Clean Air

Participant:

Custom Coals International

Contacts:

Robin Godfrey, President and CEO

(412) 642-2625

Custom Coals International

100 First Avenue, Suite 500

Pittsburgh, PA 15222

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk, FETC, (412) 892-6249

renk@fetc.doe.gov

Advanced Coal Conversion Process Demonstration

Participant:

Rosebud SynCoal Partnership

Contacts:

Ray W. Sheldon, P.E., Director of Development

(406) 748-2366 or (406) 252-2277

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
Program Update 1996-97 D-7

Coal Processing for Clean Fuels—

Mild Gasification

ENCOAL® Mild Coal Gasification Project

Participant:

ENCOAL® Corporation

Contacts:

Brent A. Knottnerus, Project Manager

(307) 686-5486

(307) 682-7938 (fax)

bknottnerus@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

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 Cemicals, 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

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

Building C, Room 211

Bethlehem, PA 18016

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@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

(215) 667-0442

Coal Tech Corporation

P.O. Box 154

Merion, 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
D-8 Program Update 1996-97

Clean Power from Integrated Coal/Ore Reduction

(CPICORTM)

Participant:

CPICORTM Management Company, L.L.C.

Contacts:

Brian O’Neil

(610) 481-5683

(610) 481-2576 (fax)

Air Products and Chemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

William Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@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

Demonstration of Pulse Combustion in an

Application for Steam Gasification of Coal

Participant:

ThermoChem, Inc.

Contacts:

William Steedman, Project Manager

(410) 997-9671

ThermoChem, Inc.

5570 Sterrett Place, Suite 210

Columbia, MD 21044

William Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Douglas F. Gyorke, FETC, (412) 892-6173

gyorke@fetc.doe.gov
Program Update 1996-97 E-1

Appendix E: Acronyms and Abbreviations

Acronyms

ABB CE ABB Combustion Engineering, Inc.

ABB ES ABB Environmental Systems

ACFB atmospheric circulating fluidized bed

AFBC atmospheric fluidized-bed

combustion

AFGD advanced flue gas desulfurization

AIDEA Alaska Industrial Development and

Export Authority

AOFA advanced overfire air

AR&TD advanced research and technology

development

BFGCI blast furnace granular-coal injection

BG British Gas

BG/L British Gas/Lurgi

B&W The Babcock & Wilcox Company

CAAA Clean Air Act Amendments of 1990

CAPI Clean Air Power Initiative

CCOFA close-coupled overfire air

CCT clean coal technology

CCT Program Clean Coal Technology

Demonstration Program

CDL coal-derived liquid

CEQ Council on Environmental Quality

CFB circulating fluidized bed

CKD cement kiln dust

COP Conference of Parties

CT-121 Chiyoda Thoroughbred-121

CQE Coal Quality Expert

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

EA environmental assessment

EER Energy and Environmental Research

Corporation

EFCC externally fired combined cycle

EIA Energy Information Administration

EIS environmental impact statement

EMP environmental monitoring plan

EPA U.S. Environmental Protection

Agency

EPAct Energy Policy Act of 1992

EPRI Electric Power Research Institute

ESP electrostatic precipitator

EWG exempt wholesale generator

FBC fluidized-bed combustion

FCCC Framework Convention on Climate

Change

FERC Federal Energy Regulatory

Commission

FETC Federal Energy Technology Center

FGD flue gas desulfurization

FONSI finding of no significant impact

FRP fiberglass-reinforced plastic

FY fiscal year

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

HAP(s) hazardous air pollutant(s)

HHV high heating value

HRSG heat recovery steam generator

IEA International Energy Agency

IGCC integrated gasification combined

cycle

JBR Jet Bubbling Reactor®

LHV low heating value

LIMB limestone injection multistage

burner

LNB low-NOx

 burner

LNCFS Low-NOx

 Concentric-Firing System

LOI loss on ignition

LSFO limestone forced oxidation

MASB multi-annular swirl burner

MCFC molten carbonate fuel cell

MTCI Manufacturing and Technology

Conversion International

MTF memorandum (memoranda)-to-file

NAAQS National Ambient Air Quality

Standards

NEPA National Environmental Policy Act

NOPR Notice of Proposed Rulemaking

NSPS New Source Performance Standards
E-2 Program Update 1996-97

NTIS National Technical Information

Service

NYSEG New York State Electric & Gas

Corporation

O&M operating and maintenance

OTAG Ozone Transport Assessment

Group

OTC Ozone Transport Commission

PC personal computer

PCFB pressurized circulating fluidized bed

PDF process-derived fuel

PEIA programmatic environmental impact

assessment

PEIS programmatic environmental impact

statement

PEOA Plant Emission Optimization

Advisor

PEP progress evaluation plan

PFBC pressurized fluidized-bed

combustion

PJBH pulse jet baghouse

PM particulate matter

PON program opportunity notice

PRB Powder River Basin

PSCC Public Service Company of Colorado

PSD Prevention of Significant

Deterioration

PUHCA Public Utility Holding Company Act

of 1935

PURPA Public Utility Regulatory Policies

Act of 1978

QF qualified facilities

RAM random access memory

R&D research and development

RD&D research, development, and

demonstration

REA Rural Electrification Administration

SBIR Small Business Innovation Research

SCR selective catalytic reduction

SCS Southern Company Services, Inc.

SFC Synthetic Fuels Corporation

SI sorbent injection

SIP state implementation plan

SNCR selective noncatalytic reduction

SOFA separated overfire air

STTR Small Business Technology

Transfer Program

SVGA super video graphics adapter

TCLP toxicity-characteristics leaching

procedure

TVA Tennessee Valley Authority

UARG Utility Air Regulatory Group

UBCL unburned carbon boiler efficiency

losses

U.K. United Kingdom

U.S. United States

VOC volatile organic compound

WES wastewater evaporation system

WLFO wet limestone, forced oxidation

Abbreviations

States are abbreviated using two-letter postal codes.

atm atmosphere(s)

avg average

Btu British thermal unit(s)

C/H molar ratio of carbon to hydrogen

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 molar ratio of calcium to nitrogen

Ca/S molar ratio of calcium to sulfur

CaSO3 calcium sulfite

CaSO4 calcium sulfate

CO carbon monoxide

CO2 carbon dioxide

°F degrees Fahrenheit

ft, ft2

, ft3 foot (feet), square feet, cubic feet

gal gallon(s)

GB gigabyte(s)

GW gigawatt(s)

GWe gigawatt(s)-electric

H2S hydrogen sulfide

H2SO4 sulfuric acid

HCl hydrogen chloride

HF hydrogen fluoride

hr hour(s)

in, in2

, in3 inch(es), square inches, cubic

inches

KCl potassium chloride
Program Update 1996-97 E-3

K2SO

4 potassium sulfate

kW kilowatt(s)

kWh kilowatt-hour(s)

lb pound(s)

MB megabyte(s)

MgCO

3 magnesium carbonate

MgO magnesium oxide

Mhz megahertz

min minute(s)

mo month(s)

MW megawatt(s)

MWe megawatt(s)-electric

MWt megawatt(s)-thermal N2 atmospheric nitrogen

Na/Ca molar ratio of sodium to calcium

Na

2

/S molar ratio of sodium to sulfur

NaOH sodium hydroxide

Na2CO

3 sodium carbonate

NH

3 ammonia

NO

2 nitrogen dioxide

NO

x nitrogen oxides

O

2 oxygen

ppm parts per million (mass)

ppmv parts per million by volume

psi pound(s) per square inch

rpm revolutions per minute

S sulfur

SO

2 sulfur dioxide

SO

3 sulfur trioxide

std ft

3 standard cubic feet

yr year(s)
Program Update 1996-97 F-1

ABB Combustion Engineering, Inc.’s Combustion

Engineering IGCC Repowering Project B-3, B-6,

C-4, C-5

ABB Combustion Engineering, Inc.’s and CQ Inc.’s

Development of the Coal Quality ExpertTM ES-7,

ES-9, ES-11, 2-6, 3-7, 3-8, 4-7, 4-8, 5-4, 5-5, 5-7,

5-114, 5-115, 5-116–5-119, B-2, B-3, B-6, C-3, C-8,

D-6

ABB Environmental Systems’ SNOXTM Flue Gas

Cleaning Demonstration Project ES-5, ES-8, 2-6,

3-6, 4-4, 4-5, 5-3, 5-5, 5-7, 5-57, 5-58–5-61, B-2,

B-5, C-3, C-8, C-10, D-3

Air Products Liquid Phase Conversion Company,

L.P.’s Commercial-Scale Demonstration of the

Liquid-Phase Methanol (LPMEOHTM) Process

ES-12, 2-6, 2-12, 3-7, 5-4, 5-5, 5-114, 5-115,

5-126–5-127, B-5, C-4, C-9, D-7

AirPol, Inc.’s 10-MWe Demonstration of Gas

Suspension Absorption ES-3, ES-4, 2-6, 3-6, 3-8,

4-2, 4-3, 5-3, 5-5, 5-7, 5-9, 5-10–5-13, B-3, B-5, C-3,

C-9, C-10, D-1

Alaska Industrial Development and Export

Authority’s Healy Clean Coal Project ES-12, 2-3,

2-6, 3-7, 4-7, 5-4, 5-5, 5-84, 5-85, 5-108–5-109, B-3,

C-5, C-9, C-10, D-6

Bechtel Corporation’s Confined Zone Dispersion

Flue Gas Desulfurization Demonstration ES-4,

2-7, 3-6, 5-3, 5-5, 5-7, 5-9, 5-14–5-17, B-3, B-5, C-3,

C-9, D-1

Bethlehem Steel Corporation’s Blast Furnace

Granulatar-Coal Injection System Demonstration

Project ES-9, 2-7, 3-7, 4-8, 4-9, 5-4, 5-5, 5-128,

5-129, 5-130–5-131, B-3, C-4, C-9, D-7

City of Lakeland, Department of Electric & Water

Utilities’ McIntosh Unit 4A PCFB Demonstration

Project 2-7, 3-7, 4-6, 5-3, 5-5, 5-85, 5-86–5-87,

B-6, C-6, C-9, D-4

City of Lakeland, Department of Electric & Water

Utilities’ McIntosh Unit 4B Topped PCFB

Demonstration Project 2-7, 3-7, 4-6, 5-3, 5-5, 5-85,

5-88–5-89, B-6, C-6, C-9, C-10, D-4

Clean Energy Partners Limited Partnership’s Clean

Energy Demonstration Project 2-7, 3-7, 5-4, 5-5,

5-85, 5-100–5-101, B-5, C-6, C-9, C-10, D-5

Coal Tech Corporation’s Advanced Cyclone

Combustor with Internal Sulfur, Nitrogen, and Ash

Control ES-7, 2-6, 3-7, 4-8, 5-4, 5-5, 5-7, 5-129,

5-132–5-135, B-1, B-4, C-3, C-8, D-7

Colorado-Ute Electric Association, Inc. (see Tri-State

Generation and Transmission Association, Inc.)

Index of CCT Projects

The Appalachian Power Company's PFBC Utility

Demonstration Project B-3, B-6

Arthur D. Little, Inc.’s Clean Coal Diesel

Demonstration Project 2-7, 3-7, 5-4, 5-5, 5-85,

5-110–5-111, B-6, C-4, C-9, C-10, D-6

The Babcock & Wilcox Company’s Demonstration of

Coal Reburning for Cyclone Boiler NOx

 Control

ES-5, 2-6, 3-6, 4-4, 5-3, 5-5, 5-7, 5-31, 5-32–5-35,

B-3, B-5, C-4, C-8, C-10, D-2

The Babcock & Wilcox Company’s Full-Scale

Demonstration of Low-NOx Cell Burner Retrofit

ES-5, ES-8, ES-11, 2-6, 3-6, 3-8, 4-4, 5-3, 5-5, 5-7,

5-31, 5-36–5-39, B-3, B-5, C-3, C-9, D-2

The Babcock & Wilcox Company’s LIMB

Demonstration Project Extension and Coolside

Demonstration ES-5, 2-6, 3-6, 4-4, 4-5, 5-3, 5-5,

5-7, 5-57, 5-62–5-65, B-1, B-4, C-3, C-8, D-3

The Babcock & Wilcox Company’s SOx

-NOx-Rox

BoxTM Flue Gas Cleanup Demonstration Project

ES-5, 2-6, 3-6, 4-4, 5-3, 5-5, 5-7, 5-57, 5-66–5-69,

B-2, B-5, C-3, C-8, C-10, D-3
F-2 Program Update 1996-97

CPICORTM Management Company, L.L.C.’s Clean

Power from Integrated Coal/Ore Reduction

(CPICORTM) 2-7, 3-7, 5-4, 5-5, 5-129,

5-136–5-137, B-4, B-6, C-6, C-9, C-10, D-8

Custom Coals International’s Self-Scrubbing CoalTM:

An Integrated Approach to Clean Air ES-9,

ES-10, 1-12, 2-7, 2-12, 3-7, 4-8, 5-4, 5-5, 5-114,

5-115, 5-120–5-121, B-4, C-4, C-9, C-10, D-6

ENCOAL® Corporation’s ENCOAL® Mild Coal

Gasification Project ES-9, ES-10, 2-7, 2-12, 3-7,

4-6, 4-7, 4-8, 5-4, 5-5, 5-114, 5-115, 5-124–5-125,

B-3, C-4, C-9, C-10, D-7

Energy and Environmental Research Corporation’s

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection ES-6, 2-6, 3-6, 4-4, 4-5, 5-3,

5-5, 5-7, 5-57, 5-70–5-73, B-1, B-5, C-3, C-4, C-8,

D-3

Energy and Environmental Research Corporation’s

Evaluation of Gas Reburning and Low-NOx Burners

on a Wall-Fired Boiler ES-5, ES-11, 2-7, 3-6, 4-4,

5-3, 5-5, 5-7, 5-31, 5-40–5-43, B-3, B-5, C-3, C-9,

D-2

LIFAC–North America’s LIFAC Sorbent Injection

Desulfurization Demonstration Project ES-4,

ES-8, 2-7, 3-6, 4-2, 4-3, 5-5, 5-7, 5-9, 5-18–5-21,

B-3, B-5, C-3, C-9, D-1

New York State Electric & Gas Corporation’s

Micronized Coal Reburning Demonstration for NOx

Control ES-10, 2-7, 2-12, 3-6, 5-3, 5-5, 5-31,

5-44–5-45, B-6, C-2, C-9, D-2

New York State Electric & Gas Corporation’s

Milliken Clean Coal Technology Demonstration

Project ES-8, 1-4, 2-7, 3-6, 4-5, 5-3, 5-6, 5-56,

5-57, 5-74–5-75, B-4, C-4, C-9, C-10, D-3

NOXSO Corporation’s Commercial Demonstration

of the NOXSO SO2

/NOx Removal Flue Gas Cleanup

System 2-7, 3-6, 5-3, 5-6, 5-57, 5-76–5-77, B-5,

C-4, C-6, C-9, D-4

The Ohio Power Company’s Tidd PFBC

Demonstration Project ES-1, ES-6, ES-8, ES-11,

2-6, 3-7, 4-6, 4-7, 5-3, 5-6, 5-7, 5-85, 5-90–5-93,

B-1, B-5, C-3, C-8, C-10, D-4

Passamaquoddy Tribe’s Cement Kiln Flue Gas

Recovery Scrubber ES-7, 2-6, 3-7, 4-8, 4-9, 5-4,

5-6, 5-7, 5-128, 5-129, 5-138–5-141, B-2, B-5, C-4,

C-8, D-8

Pennsylvania Electric Company’s Externally Fired

Combined-Cycle Demonstration Project 2-7, 3-7,

5-4, 5-6, 5-85, 5-112–5-113, B-7, C-4, D-6

Public Service Company of Colorado’s Integrated

Dry NOx

/SO2 Emissions Control System ES-6,

ES-8, 2-7, 3-6, 4-4, 4-5, 5-3, 5-6, 5-7, 5-57, 5-78–81,

B-3, B-6, C-3, C-9, C10, D-4

Pure Air on the Lake, L.P.’s Advanced Flue Gas

Desulfurization Demonstration Project ES-3,

ES-4, ES-11, 1-4, 2-6, 3-6, 3-8, 4-2, 4-3, 5-3,

5-6, 5-7, 5-9, 5-22–5-25, B-2, B-6, C-4, C-8, C-10,

D-1

Rosebud SynCoal Partnership’s Advanced Coal

Conversion Process Demonstration ES-9, 2-6, 3-7,

4-6, 4-7, 4-8, 5-4, 5-6, 5-114, 5-115, 5-122–5-123,

B-3, C-4, C-8, D-6

Sierra Pacific Power Company’s Piñon Pine IGCC

Power Project ES-9, ES-10, 1-9, 2-7, 2-12, 3-7,

4-6, 4-7, 4-13, 5-4, 5-6, 5-85, 5-102–5-103, B-4, C-5,

C-9, C-10, D-5

Southern Company Services, Inc.’s Demonstration of

Advanced Combustion Techniques for a Wall-Fired

Boiler ES-10, 2-6, 2-12, 3-6, 4-4, 5-3, 5-6, 5-31,

5-46–5-47, B-2, C-3, C-8, C-10, D-2

Southern Company Services, Inc.’s Demonstration of

Innovative Applications of Technology for the

CT-121 FGD Process ES-2, ES-4, ES-8, ES-11,

1-4, 1-5, 2-6, 3-6, 4-3, 5-3, 5-6, 5-7, 5-9, 5-26–5-29,

B-3, B-5, C-4, C-8, C-10, D-1

Southern Company Services, Inc.’s Demonstration of

Selective Catalytic Reduction Technology for the

Control of NOx

 Emissions from High-Sulfur-CoalFired Boilers ES-5, 2-6, 3-6, 5-3, 5-6, 5-7, 5-31,

5-48–5-51, B-3, B-6, C-3, C-8, D-2

Southern Company Services, Inc.’s 180-MWe

Demonstration of Advanced Tangentially Fired

Combustion Techniques for the Reduction of NOx

Emissions from Coal-Fired Boilers ES-5, 2-6, 3-6,

4-4, 5-3, 5-6, 5-7, 5-31, 5-52–5-55, B-3, B-5, C-3,

C-8, C-10, D-3
Program Update 1996-97 F-3

Tampa Electric Company’s Tampa Electric

Integrated Gasification Combined-Cycle Project

ES-1, ES-9, ES-11, 1-9, 2-7, 3-7, 4-6, 4-7, 4-13,

4-14, 4-15, 5-4, 5-6, 5-83, 5-85, 5-104–5-105, B-3,

C-5, C-9, C-10, D-5

ThermoChem, Inc.’s Demonstration of Pulse

Combustion in an Application for Steam Gasification

of Coal 2-7, 3-7, 5-4, 5-6, 5-129, 5-142–5-143,

B-4, B-6, D-8

Tri-State Generation and Transmission Association,

Inc.’s Nucla CFB Demonstration Project ES-7,

ES-9, 2-6, 3-7, 3-8, 4-5, 4-7, 5-3, 5-6, 5-7, 5-82,

5-85, 5-96–5-99, B-2, B-4, C-3, C-8, D-5

Wabash River Coal Gasification Repowering Project

Joint Venture’s Wabash River Coal Gasification

Repowering Project ES-8, ES-9, ES-11, 1-4,

1-7, 1-8, 1-9, 2-7, 3-7, 4-6, 4-7, 4-13, 5-4, 5-6, 5-85,

5-106–5-107, B-4, C-4, C-9, C-10, D-5

York County Energy Partners, L.P.’s ACFB

Demonstration Project 2-6, 3-7, 5-3, 5-6, 5-85,

5-94–5-95, B-4, C-6, C-8, C-10, D-4