Clean Coal Technology

Demonstration Program

Program Update 1998

March 1999

U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

DOE/FE-0387
This report has been reproduced directly from the best available copy.

Available to DOE and DOE contractors from the Office of Scientific and Technical Information,

P.O. Box 62, Oak Ridge, TN 37831; prices available from (615) 576-8401.

Available to the public from the National Technical Information Service, U.S. Department of

Commerce, 5285 Port Royal Rd., Springfield, VA 22161.
Clean Coal Technology

Demonstration Program

Program Update 1998

March 1999

U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

DOE/FE-0387
Program Update 1998 iii

Contents

Executive Summary: The CCT

Program Update 1998

Introduction ES-1

Role of the CCT Program ES-1

Program Implementation ES-3

Funding and Costs ES-4

CCT Program Accomplishments ES-5

CCT Projects ES-13

Introduction 1-1

Coal Technologies Respond to Need 1-1

Coal Technologies for Environmental Performance 1-3

Acid Rain Mitigation 1-3

New Rules 1-5

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 Sustain Economic Growth 1-11

Coal Technology for the Future 1-13

Vision 21 1-13

Vision 21 Core Technologies 1-13

Vision 21 Enabling Technologies 1-14

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

Section 1: Role of the CCT Program

Section 2: Program Implementation
iv Program Update 1998

Introduction 3-1

Program Funding 3-1

General Provisions 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 4-7

Industrial Applications 4-10

Market Communications—Outreach 4-10

Information Sources 4-11

Publications Issued in FY1998 4-12

Information Access Updates for FY1998 4-12

Information Dissemination and Feedback 4-13

Sixth Annual Clean Coal Technology Conference: What Will It Take? 4-13

Conferences and Workshops Held in FY1998 4-15

Trade Mission Activities in FY1998 4-16

Introduction 5-1

Technology Overview 5-2

Environmental Control Devices 5-2

Advanced Electric Power Generation Technology 5-8

Coal Processing for Clean Fuels Technology 5-12

Industrial Applications Technology 5-14

Section 3: Funding and Costs

Section 4: CCT Program Accomplishments

Section 5: CCT Projects
Program Update 1998 v

Project Fact Sheets 5-16

Environmental Control Devices 5-21

SO2

 Control Technology 5-21

NOx Control Technology 5-43

Combined SO2

/NOx Control Technology 5-71

Advanced Electric Power Generation 5-99

Fluidized-Bed Combustion 5-99

Integrated Gasification Combined-Cycle 5-115

Advanvced Combustion/Heat Engines 5-125

Coal Processing for Clean Fuels 5-131

Industrial Applications 5-147

Historical Perspective A-1

Legislative History A-2

Solicitation History B-1

Selection and Negotiation History B-1

Introduction C-1

The 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

Section 5: CCT Projects (continued)

Appendix A: Historical Perspective and

Legislative History

Appendix B: Program History

Appendix C: Environmental Aspects
vi Program Update 1998

Project Contacts D-1

Environmental Control Devices D-1

Advanced Electric Power Generation D-4

Coal Processing for Clean Fuels D-6

Industrial Applications D-7

Acronyms, Abbreviations, and Symbols E-1

State Abbreviations E-3

Index Index-1

Appendix E: Acronyms, Abbreviations,

Symbols

Index

Appendix D: CCT Project Contacts
Program Update 1998 vii

Exhibits

Completed Projects by Application Category ES-5

Summary of Results of Completed Environmental Control Technology Projects ES-7

Commercial Successes–Environmental Control Technologies ES-10

Summary of Results of Completed Advanced Electric Power Generation Projects ES-12

Commercial Successes–Advanced Electric Power Generation ES-13

Summary of Results of Coal Processing for Clean Fuels ES-14

Commercial Successes–Coal Processing for Clean Fuels ES-15

Summary of Results of Industrial Application Projects ES-16

Commercial Successes–Industrial Applications ES-16

Projects by Application Category ES-17

Award-Winning CCT Projects ES-19

Phase I SO2 Compliance Methods 1-3

CAAA NOx

 Emission Limits 1-5

Comparison of Energy Projections 1-11

Vision 21 PowerPlex 1-13

CCT Program Selection Process Summary 2-5

Clean Coal Technology Demonstration Projects by Solicitation 2-6

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

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

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

Geographic Location of CCT Projects—Industrial Applications 2-11

CCT Project Costs and Cost-Sharing 3-1

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

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

CCT Financial Projections as of September 30, 1998 3-4

Section 2: Program Implementation

Executive Summary: The CCT Program

Update 1998

Section 1: Role of the CCT Program

Section 3: Funding and Costs
viii Program Update 1998

Financial Status of the CCT Program as of September 30, 1998 3-5

CCT Project Schedules and Funding by Application Category 3-6

Commercial Successes—SO2

 Control Technology 4-3

Commercial Successes—NOx Control Technology 4-4

Commercial Successes—Combined SO2

/NOx Control Technology 4-5

Commercial Successes—Advanced Electric Power Generation 4-8

Commercial Successes—Coal Processing for Clean Fuels 4-9

Commercial Successes—Industrial Applications 4-10

How to Obtain Updated CCT Program Information 4-11

CCT Program SO2

 Control Technology Characteristics 5-3

Group 1 and 2 Boiler Statistics and Phase II NOx

 Emission Limits 5-4

CCT Program NOx Control Technology Characteristics 5-5

CCT Program Combined SO2/NOx Control Technology Characteristics 5-7

CCT Program Advanced Electric Power Generation Technology Characteristics 5-11

CCT Program Coal Processing for Clean Fuels Technology Characteristics 5-13

CCT Program Industrial Applications Technology Characteristics 5-15

Project Fact Sheet by Application Category 5-17

CCT Project Fact Sheets by Participant 5-19

Variables and Levels Used in GSA Factorial Testing 5-24

GSA Factorial Testing Results 5-24

SO2

 Removal Performance 5-36

Estimated Costs for an AFGD System 5-37

Flue Gas Desulfurization Economics 5-37

Operation of CT-121 Scrubber 5-40

SO2 Removal Efficiency 5-40

Particulate Capture Performance 5-40

CT-121 Air Toxics Removal 5-41

Coal Reburn Test Results 5-48

Coal Reburn Economics 5-49

NOx

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

Section 5: CCT Projects

Section 4: CCT Program Accomplishments

Section 3: Funding and Costs (continued)
Program Update 1998 ix

Section 5: CCT Projects (continued) Catalysts Tested 5-60

Average SO2

 Oxidation Rate 5-60

Design Criteria 5-61

LNCFSTM Configurations 5-64

Concentric Firing Concept 5-64

Unit Performance Impacts Based on Long-Term Testing 5-65

Average Annual NOx Emissions and Percent Reduction 5-65

NOx

 vs. LOI Tests—All Sensivities 5-68

Typical Trade-Offs in Boiler Optimization 5-68

Major Elements of GNOCIS 5-68

Performance Test Results 5-69

Effect of Limestone Grind 5-74

Pressure Drop vs. Countercurrent Headers 5-75

LIMB SO2 Removal Efficiencies 5-84

Capital Cost Comparison 5-85

Annual Levelized Cost Comparison 5-85

Effect of Bed Temperature on Ca/S Requirement 5-112

Calcium Requirements and Sulfur Retentions for Various Fuels 5-112

CQETM Stand-Alone System Requirements 5-140

ENCOAL Production 5-144

Summary of Emissions and Removal Efficiencies 5-158

CCT Program Legislative History A-4

NEPA Reviews Completed through September 30, 1998 C-2

Memoranda-to-File Completed C-3

Environmental Assessments Completed C-4

Environmental Impact Statements Completed C-5

NEPA Reviews in Progress C-6

Status of Environmental Monitoring Plans for CCT Projects C-8

CCT Projects Monitoring Hazardous Air Pollutants C-10

Appendix A: Historical Perspective and

Relevant Legislation

Appendix C: Environmental Aspects
Program Update 1998 ES-1

Executive Summary: CCT Program Update 1998

Introduction

The Clean Coal Technology Demonstration Program (CCT Program), a model of government and

industry cooperation, responds to the Department of

Energy’s (DOE) mission to foster a secure and reliable

energy system that is environmentally and economically sustainable. With 23 of the 40 active projects having

completed operations, the CCT Program has yielded

clean coal technologies (CCTs) that are capable of

meeting existing and emerging environmental regulations and competing in a deregulated electric power

marketplace.

The CCT Program is providing a portfolio of

technologies that will assure the U.S. recoverable coal

reserves of 274 billion tons can continue to supply the

nation’s energy needs economically and in an environmentally sound manner. As the new millennium approaches, many of the clean coal technologies have

realized commercial application. Industry stands ready

to respond to the energy and environmental demands of

the 21st century, both domestically and internationally.

For existing power plants, there are cost effective

environmental control devices to control sulfur dioxide

(SO2), nitrogen oxides (NOx), and particulate matter

(PM). Also ready are a new generation of technologies

that can produce electricity and other commodities,

such as steam and synthetic gas, and provide the efficiencies and environmental performance responsive to

global climate change. The CCT Program took a

pollution prevention approach as well, demonstrating

technologies that produce clean coal-based solid and

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.

liquid fuels by removing pollutants or their precursors.

Lastly, new technologies were introduced into the

major coal-using industries to enhance environmental

performance. Thanks in part to the CCT Program,

coal—abundant, secure, and economical—can continue

in its role as a key component in the U.S. and world

energy markets.

Role of the CCT Program

Coal Technologies Respond to Need. Coal

accounts for over 94 percent of the proven fossil

energy reserves in the United States and supplies the

bulk of the low-cost reliable electricity vital to the

nation’s economy and global competitiveness. In

1996, over half of the nation’s electricity was produced

with coal and projections by the Energy Information

Agency (EIA) predict that coal will continue to dominate electric power production well into the first

quarter of the 21st century. However, there is also a

need to use U.S. coal resources in an environmentally

responsible manner. The CCT Program responds to

both of these needs.

The CCT Program was established to demonstrate

the commercial feasibility of CCTs to respond to a

growing demand for a new generation of advanced

coal-based technologies characterized by enhanced

operational, economic, and environmental performance. The first solicitation (CCT-I) for clean coal

projects resulted in a broad range of projects being

selected in four major product markets–environmental
ES-2 Program Update 1998

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

Company Services, Inc.)—1994 Powerplant Award

presented by Power magazine.

control devices, advanced electric power generation,

coal processing for clean fuels, and industrial

applications.

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

Envoys on Acid Rain (1986). The goal was to demonstrate technologies that could achieve significant

reductions in the emissions of precursors of acid rain,

namely SO2

 and NOx. The third round of solicitations

(CCT-III) furthered the goal of CCT-II and added

technologies that could produce clean fuel from run-ofmine coal.

The fourth and fifth solicitations (CCT-IV and

CCT-V, respectively) recognized emerging energy and

environmental issues, such as global climate change

and capping SO2 emissions, and thus focused on

technologies that were capable of addressing these

issues. CCT-IV called for energy efficient economically competitive technologies capable of retrofitting,

repowering, or replacing existing facilities, while at the

same time significantly reducing SO2

 and NOx emissions. CCT-V focused on technologies applicable to

new or existing facilities that could significantly improve efficiency and environmental performance.

Coal Technologies for Environmental Performance. Even before enactment of the Clean Air Act

Amendments of 1990 (CAAA), the CCT Program was

cognizant of the changes in electric power generation

that would likely be caused by the statute. Several

projects in the CCT Program were implemented at

units designated as Phase I units in Title IV of the

CAAA, which were required to meet SO2

 reductions by

January 1, 1995. The CCT Program projects at Phase I

units successfully reduced SO2

 emissions using advanced flue gas desulfurization (AFGD) and repowering with integrated gasification combined cycle

(IGCC). With a January 1, 2000 deadline quickly

approaching for Phase II of Title IV, the CCT Program

has developed a portfolio of technologies that will help

industry meet the more stringent SO2

 emission limits.

Unit operators now have several options for meeting

SO2 limitations or exceeding them to generate SO2

credits that can be sold in the emissions credit market.

Furthermore, these SO2 reduction technologies may be

important in meeting new requirements for PM2.5

(particulate matter 2.5 microns and smaller in diameter) because some sulfur species are also PM2.5.

In addition to SO2

 reductions, Title IV also called

for reductions in NOx emissions. Phase I of the NOx

provisions of Title IV requires reductions from the socalled Group 1 boilers–tangentially-fired and drybottom wall-fired boilers. The Environmental Protection Agency (EPA) used data developed during the

CCT Program in establishing the NOx

 emission standards. Under Phase II, EPA established NOx

 emission

limitations for Group 2 boilers and reduced the emission limits for Group 1 boilers. Group 2 boilers include cell-burner, cyclone, wet-bottom wall-fired, and

vertically-fired boilers. The CCT Program has demonstrated NOx

 emission techniques that are applicable to

all of these boiler types. Furthermore, these technologies are not only applicable to Phase I and II NOx

emission reductions, but can be used in ozone nonattainment areas to make deeper cuts in NOx

, which is a

precursor to ozone.

The issue of ozone nonattainment has recently

taken on new proportions as EPA has issued a “SIP

Call” to 22 states and the District of Columbia to take

action to reduce regional transport of pollutants that

contribute to ozone nonattainment in the Northeast.

The SIP Call requires the 23 affected jurisdictions to

revise their state implementation plans (SIP) to reduce

NOx emissions 85 percent below 1990 rates or achieve

a 0.15 lb/106 Btu emission rate by May 2003. In

addition, EPA has tightened the New Source Performance Standard (NSPS) for electric and industrial

boilers built or modified after July 9, 1997. The CCT

Program has demonstrated several advanced electric

power generation technologies that can be used to meet

the new requirements or exceed the requirements to

produce NOx

 credits that could be sold to unit operators unable to meet the requirements. Furthermore, an

environmental controls database has been developed

that provides a foundation for meeting the increasingly

stringent standards for existing units.

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

Title I of the CAAA, EPA is responsible for determining the hazards to public health posed by 189 identified

hazardous air pollutants (HAPs). The CCT Program

made a significant contribution to a better understanding of potential HAPs from power plant emissions by
Program Update 1998 ES-3

Advanced Flue Gas Desulfurization Demonstration

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

Award presented by Power magazine.

monitoring HAPs from CCT Program project sites.

The results of these and other studies have significantly

mitigated concerns about HAP emissions from coalfired power plants and focused attention on only a few

flue gas constituents.

The CCT Program is also cognizant of concerns

about global climate change. Clean coal technology,

such as IGCC, being demonstrated in the CCT Program

offers utilities an option to reduce greenhouse gases

(GHG) by as much as 25 percent with first generation

systems through enhanced efficiency. Commercialization of atmospheric fluidized-bed combustion (AFBC)

and pressurized fluidized-bed combustion (PFBC) will

also serve to reduce GHGs.

Coal Technologies for Competitive Performance. As the electric generation market moves from

a regulated industry to a free market, the CCT Program

has kept pace with the changes. Whether the changes

are brought about by the federal government through

existing or new legislation or by state governments, the

CCT Program is demonstrating the first generation of

many technologies that will be needed in a competitive

power generation market. These new technologies will

be far more efficient than existing plants and environmentally benign.

Coal Technologies to Sustain Economic

Growth. It is in the nation’s interest to maintain a

diverse energy mix to sustain domestic economic

growth. The CCT Program is contributing to this

interest by developing and deploying a technology

portfolio that enhances the efficient use of the United

States’ abundant natural resource while simultaneously

achieving important environmental goals. The advancements in use of coal resulting from the CCT

Program will reduce dependance on foreign energy

resources and create an international market for these

new technologies.

Coal Technology for the Future. The Department of Energy’s Office of Coal and Power Systems

(OC&PS) Research, Development, and Demonstration

(RD&D) Program is building on the CCT Program to

develop a “Vision 21 PowerPlex.” This Vision 21

PowerPlex is a modular facility using a multiplicity of

fuels to produce a variety of commodities (electricity,

steam, fuels, and chemicals) at efficiencies exceeding

60 percent and with near zero emissions. Vision 21

PowerPlex systems will build upon the clean coal

technologies and attendant databases developed in the

CCT Program in meeting the goals established for the

21st century.

Program Implementation

Implementation Principles. There are 10 guiding

principles that have been instrumental in the success of

the CCT Program. These are:

• strong and stable financial commitment for the

life of the project, including full funding of the

government’s share of the costs;

• multiple solicitations spread over a number of

years, enabling the CCT Program to address a

broad range of national needs with a portfolio

of evolving technologies;

• demonstrations conducted at commercial scale

in actual user environments, allowing clear

assessment of the technology’s commercial

potential;

• a technical agenda established by industry, not

the government, enhancing commercialization

potential;

• clearly defined roles of government and

industry, reflecting the degree of cost sharing

required;

• a requirement for at least 50 percent cost

sharing throughout all project phases, enhancing participant’s commitment;

• an allowance for cost growth, but with a ceiling

and cost-sharing, recognizing demonstration

risk and providing an important check-andbalance to the program;

• industry retains real and intellectual property

rights, enhancing commercialization potential;

• a requirement for industry to commit to

commercialize the technology, reflecting

commercialization goals; and

• a requirement for repayment up to the

government’s cost share upon successful

commercialization of the technology being

demonstrated, reflecting DOE policy.
ES-4 Program Update 1998

Implementation Process. Public and private

sector involvement is integral to the CCT Program

process and was crucial to the program’s success.

Environmental concerns are publicly addressed

through the process instituted under the National

Environmental Policy Act (NEPA). Through programmatic environmental assessments (PEAs), environmental impact statements (EISs), project specific Environmental Assessments (EAs) and EISs, and other NEPA

documents, the public is able to comment and have

their comments addressed before the projects proceed

to implementation. In addition, environmental monitoring programs are required for all projects to address

non-regulated pollutant emissions.

As to the solicitation process, Congress set the

goals for each solicitation. The Department of Energy

translated the congressional guidance into performance-based criteria and developed approaches to

address “lessons learned” from previous solicitations.

The criteria and solicitation procedures were offered

for public comment and presented at pre-proposal

conferences. The solicitations were objectively evaluated against the pre-established criteria.

Projects are managed by the participants, not the

government. However, to protect the public interest,

safeguards are implemented to track and monitor

project progress and direction. The Department of

Energy interacts with the project at key negotiated

decision points (budget periods) to approve or disapprove continuance of the project. Also, any changes to

cost or other major project changes require DOE

approval. In addition to formal project reporting

requirements, an outreach program was instituted to

make project information available to customers and

stakeholders. This Program Update 1998 is only one

of the many public reports made available through the

outreach program.

Commitment to Commercial Realization. The

CCT Program has focused on achieving commercial

realization since the program’s inception. All five

solicitations required the potential participant to address the commercial plans and approaches to be used

by the participant to achieve full commercialization of

the proposed technology. The cooperative agreement

contained balanced provisions that provide protection

for intellectual property but required the participant to

make the technology available under license on a

nondiscriminatory basis.

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 defined. The procurements followed

specific statutory requirements that would eventually

lead to a cooperative agreement between DOE and the

participant. The result was a broad spectrum of technologies involving customers and stakeholders from all

market segments. In sum, 211 proposals were submitted and 60 of those were selected. As of September

1998, a total of 40 projects have been completed or are

currently active. These 40 projects are spread across

the nation in 18 states.

Future Implementation Direction. The future

direction of the CCT Program focuses on completing

the existing projects as promptly as possible and

assuring the collection, analyses, and reporting of the

operational, economic, and environmental performance

results that are needed to affect commercialization. In

FY1999, the Clean Coal Diesel Demonstration project

is scheduled to begin operations. Five projects are

scheduled to complete operations in FY1999.

The body of knowledge obtained as a result of the

CCT Program is being used in decisionmaking relative

to regulatory compliance, forging plans for meeting

future energy and environmental demands, and developing the next generation of technologies responsive to

ever increasing demands on environmental performance at competitive costs. Three major drivers will

affect implementation of the CCT Program—environmental concerns, utility restructuring, and the international market—because of their impact on market entry

and deployment of clean coal technologies.

Environmental concerns include regional NOx

transport impacting ozone nonattainment areas, PM2..5,

and global climate change. Utility restructuring from a

regulated industry to a market-based industry will

require new clean coal technologies to be cost effective

and have a technological risk comparable to conventional technologies. The international market shows

the greatest near-term market potential for clean coal

technologies. With more than 50 percent future demand for new generation between now and 2010

coming from Asia, there is a tremendous market potential for clean coal technologies that can use indigenous

fuels.

Funding and Costs

Program Funding. Congress has appropriated a

federal budget of $2.3 billion for the CCT Program.

For the 40 completed and active projects, the participants have contributed $3.7 billion dollars for a combined commitment of more than $5.6 billion. By law,

DOE’s contribution can not exceed 50 percent of the

total cost of any project. However, industry has

stepped forward and cost shared an unprecedented 66

percent of the project funding.
Program Update 1998 ES-5

Congress has provided CCT Program funding for

all five solicitations through appropriation acts and

adjustments. Additional activities funded by the CCT

Program are the Small Business Innovation Research

Program and the Small Business Technology Transfer

Program. Funding is also provided for administration

and management of the CCT Program. Use of appropriated funds are controlled and monitored using a

variety of financial management techniques. 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 by budget period. This procedure reduces the

government’s financial exposure and assures that DOE

fully participates in the decision to proceed with each

major phase of project implementation.

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

project. This cost sharing is required for all phases of

the project. The federal government may share in

project cost growth (which, by its very nature, is likely

to happen for any demonstration project) up to 25

percent of the original project cost. The participant’s

contributions must occur as expenses are incurred and

can not be delayed based on forecasted revenues,

proceeds, or royalties. Also, prior investments in

facilities by participants can not count towards the

participant’s share.

Recovery of Government Outlays (Recoupment). The policy objective of DOE is to recover an

amount up the federal government’s financial contribution to each project when a technology is successfully

commercialized. Participants are required to submit a

plan outlining a proposed schedule for recoupment.

Each of the five solicitations have featured different

sets of recoupment rules because of lessons learned

from prior solicitations.

CCT Program

Accomplishments

Marketplace Commitment. The success of the

CCT program ultimately will be measured by the

contribution the technologies make to the resolution of

energy, economic, and environmental issues. These

contributions can only be achieved if the public and

private sectors understand that clean coal technologies

can increase the efficiency of energy use and enhance

environmental performance at costs that are competitive with alternative energy

options. The CCT Program

is organized from a market

perspective with projects

placed in four major product

lines—environmental control

devices, advanced electric

power generation, coal

processing for clean fuels,

and industrial applications. A

summary of the number of

projects having completed

operations by category is

shown in Exhibit ES-1.

The first major product

line, environmental control

devices, is subdivided into

three groups—SO2

 control

technologies, NOx control

technologies, and combined

SO2/NOx control technologies. Both wet and dry lime- and limestone-based

systems were demonstrated to achieve a range of SO2

capture efficiencies of 50 to 99 percent. All five of the

SO2

 control technology demonstrations have successfully completed operations.

For NOx

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

using low NOx burners and reburning systems, and (2)

post-combustion techniques using selective catalytic

reduction (SCR) and selective non-catalytic reduction

(SNCR) systems. These NOx control techniques were

applied in a variety of combinations on a variety of

boilers, which are representative of 90 percent of the

pre-NSPS boilers, i.e., those boilers built before NSPS

were imposed by the Clean Air Act of 1970. The result

of the NOx control technology demonstrations is a

Exhibit ES-1

Completed Projects by Application Category

Number of Projects

Application Category Completed Total

Operations

Environmental Control Devices

SO2 Control Technology 5 5

NOx Control Technology 6 7

Combined SO2

/NOx Control Technology 6 7

Advanced Electric Power Generation

Fluidized-Bed Combustion 2 5

Integrated Gasification Combined Cycle 0 4

Advanced Combustion/Heat Engines 0 2

Coal Processing for Clean Fuels 2 5

Industrial Applications 2 5

Total 23 40
ES-6 Program Update 1998

portfolio of technologies that can be used to address

today’s pressing environmental concerns, e.g., ozone.

Six of the seven NOx

 control technology demonstrations have successfully completed operations.

Six of the seven combined SO2/NOx control

technology demonstrations have successfully completed operations. The demonstrations tested a multiplicity of complementary and synergistic control methods

to achieve cost-effective SO2 and NOx emission reductions. A summary of the results of the completed

environmental control device projects can be found in

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

The second major product line, advanced electric

power generation, is subdivided into three groups–(1)

fluidized-bed combustion, (2) integrated gasification

combined-cycle, and (3) advanced combustion/heat

engines. These technologies can be used for repowering existing generation and new generation.

For fluidized-bed combustion, two approaches

were used: atmospheric fluidized-bed combustion

(AFBC) and pressurized fluidized-bed combustion

(PFBC). The two AFBC projects demonstrated in the

CCT Program used a circulating-bed, as opposed to a

bubbling-bed, operating at atmospheric pressure to

generate steam for electricity production. One project

is complete and the other project is ongoing. There are

three PFBC projects in the CCT Program. One PFBC

project used a bubbling-bed operating at 16 atmospheres to generate steam and drive a gas turbine in a

combined-cycle mode. Two ongoing interrelated

PFBC projects will use a circulating-bed operating at

13 atmospheres, also in a combined-cycle mode.

Three of the four integrated gasification combined

cycle demonstration projects are in various stages of

operation. A fourth project is in the design stage. The

IGCC projects represent a diversity of gasifier types,

cleanup systems, and applications.

Two projects are demonstrating advanced combustion/heat engine technology. One uses an entrained

(slagging) combustor and the other uses a heavy duty

diesel fired on a coal-water fuel. Both of these projects

are ongoing.

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

in Exhibit ES-4. The commercial successes of these

projects can be seen in Exhibit ES-5.

For the third major product line, coal processing

for clean fuels, there are five projects. Three projects

are using chemical and physical processes to transform

raw coal into an environmentally compliant fuel.

Another project is using coal to produce methanol from

coal-derived synthesis gas. A fifth project in this

product line is a software program used to assess the

environmental and operational performance and deterFull-Scale Demonstration of Low-NOx

 Cell Burner

Retrofit Project (The Babcock & Wilcox Company)—1994

R&D 100 Award presented by R&D magazine.

Wabash River Coal Gasification Repowering Project

(Wabash River Coal Gasification Repowering Project Joint

Venture)—1996 Powerplant Award presented by Power

magazine.

mine the least-cost option for available coals. Two of

the five coal processing for clean fuels projects are

complete.

A summary of the results of the completed coal

processing for clean fuels projects can be found in

Development of the Coal Quality ExpertTM Project

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

recognized by Secretary of Energy and EPRI as one of best

cost-shared utility projects.
Program Update 1998 ES-7

Project and Participant

Exhibit ES-2

Summary of Results of Completed Environmental Control Technology Projects

Key Results Capital Cost

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 molar

ratio 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 molar 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; eliminating the need for a flue gas

prescrubber and reheat

$149/kW for GSA, (2-6% sulfur coal) ($216/kW for

conventional wet limestone forced oxidation) (1990$)

Less than $30/kW at 500 MWe (4% sulfur coal)

$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;

$94/kW at 500 MWe (3.0% sulfur coal) (1995$)

Not yet available
ES-8 Program Update 1998

Project and Participant

Exhibit ES-2 (continued)

Summary of Results of Completed Environmental Control Technology 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.)

Demonstration of Advanced Combustion Techniques for

a Wall-Fired Boiler (Southern Company Services, Inc.)

Combined SO2

/NOx Control Technology

SNOXTM Flue Gas Cleaning Demonstration Project

(ABB Environmental Systems)

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

Using LNB alone, NOx emissions were 0.65 lb/106 Btu at

full load, representing a 48% reduction from baseline

conditions (1.24 lb/106 Btu)

Using AOFA only, NOx reductions of 24% below

baseline conditions were achieved under normal longterm operation, depending upon load

Using LNB/AOFA, full load NOx

 emissions were

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

reduction from baseline conditions

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

$66/kW at 110 MWe; $43/kW at 605 MWe (1990$)

$9/kW at 600 MWe (1994$)

Approximately $15/kW for gas reburning, plus gas

pipeline cost (1996$)

Levelized cost at 80% NOx

 reduction—

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

 removed (1996$)

LNCFS I—$5–15/kW (1993$)

LNCFS II/III—$15–25/kW (1993$)

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

for AOFA alone, $10.0/kW for LNB alone, and

$0.5/kW GNOCIS

Estimated cost of NOx

 removal is $86/ton

$305/kW at 500 MWe (3.2% sulfur coal) (1995$)
Program Update 1998 ES-9

Exhibit ES-2 (continued)

Summary of Results of Completed Environmental Control Technology Projects

Project and Participant Key Results Capital Cost

LIMB Demonstration Project Extension and Coolside

Demonstration (The Babcock & Wilcox Company)

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration

Project (The Babcock & Wilcox Company)

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection (Energy and Environmental Research

Corporation)

Milliken Clean Coal Technology Demonstration Project

(New York State Electric & Gas Corporation)

Integrated Dry NOx

/SO2 Emissions Control System

(Public Service Company of Colorado)

SO2

 removal efficiency (3.8% sulfur coal, Ca/S molar ratio

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

Hennepin—NOx

 reduction of 67% avg with 18% gas input;

SO2 removal efficiency of 53% at 1.75 Ca/S molar 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 molar

ratio

The maximum SO2

 removal demonstrated has been 98%

with all seven recycle pumps operating and using formic

acid. The maximum SO2 removal without formic acid has

been 95%

Testing of the LNCFSTM III indicated NOx

 emissions of

0.39 lb/106 Btu (compared to 0.61 lb/106 Btu for the

original burners)

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

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) (1994$)

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

$50/kW for sorbent injection

Not yet available

Not yet available
ES-10 Program Update 1998

Exhibit ES-3

Commercial Successes—Environmental Control Technologies

Project and Participant Commercialization Progress

LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC–North America) Technology retained for commercial use at host site

First high-sulfur coal application

10 commercial units in operation or construction (Canada, China, Finland, Russia, and

U.S.)

10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) Sale of 50-MWe unit to city of Hamilton, OH

– Value—$10 million

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

Sale of technical assistance and proprietary equipment to Taiwan

– Value—$1 million

Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Technology retained for commercial use at host site; first scrubber to comply with CAAA

installed; Wallboard manufacturer using all gypsum produced

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Technology retained for commercial use at host site

(Southern Company Services, Inc.) Since the CCT Program demonstration, over 8,200 MWe equivalent of CT-121 FGD

capacity has been sold to 16 customers in seven countries

Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control (The Babcock & Wilcox Technology retained for commercial use at host site

Company)

Full-Scale Demonstration of Low-NOx

 Cell Burner Retrofit (The Babcock & Wilcox Technology retained for commercial use at host site

Company) Seven commercial contracts awarded for 144 burners

– Value—$27 million

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler (Energy and Technology retained for commercial use at host site

Environmental Research Corporation)

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Technology retained for commercial use at host site

Company Services, Inc.) Foster Wheeler has equipped 86 boilers with low NOx technology (51 domestic and 35

international)

– Quantity—1,800 burners for over 30,000 MWe capacity

19 GNOCIS neural-network control projects underway

Expect another 17 GNOCIS projects in 1999

Organizations selected to market GNOCIS in U.S. and abroad
Program Update 1998 ES-11

Exhibit ES-3 (continued)

Commercial Successes—Environmental Control Technologies

Project and Participant Commercialization Progress

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques Technology retained for commercial use at host site

(Southern Company Services, Inc.) ABB Combustion Engineering has modified 116 coal-fired tangentially-fired boilers,

representing over 25,000 MWe, with LNCFSTM and TFS 2000TM

SNOXTM Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) Technology retained for commercial use at host site

305-MWe unit operating in Denmark on coal

30-MWe unit operating in Sicily on petroleum coke

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

(The Babcock & Wilcox Company)

Enhancing the Use of Coals by Gas Reburning Sorbent Injection (Energy and Illinois Power and City Water, Light & Power retained gas reburning for commercial use

Environmental Research Corporation)

Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Four sales of DHR Technologies’ Plant Emission Optimization Advisor

Corporation)

More than 20 NOx

 OUT® or NOx OUT® derivative units sold in U.S, Taiwan, and

Korea

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

Actively pursuing AFGD bid for Pennsylvania site (will include S-H-U process,

Stebbins absorber module, and heat-pipe air preheater)

Integrated Dry NOx/SO2 Emissions Control System (Public Service Company Technology retained for commercial use at host site

of Colorado) Sales of Babcock & Wilcox DRB-XCL® low-NOx burners (which are components

of the technology demonstrated)

– Quantity—2,428 burners for 31,467 MWe capacity

– Value—$320 million

Exhibit ES-6. The commercial successes of the coal

processing for clean fuels projects can be seen in

Exhibit ES-7.

The fourth and final major product line is industrial applications. This product line is addressing the

environmental issues and barriers associated with coal

use in industry. There are five diverse projects in this

category; two are completed and three are ongoing. A

summary of the results of the completed industrial

application projects can be found in Exhibit ES-8. The

commercial successes of these projects can be seen in

Exhibit ES-9.

Market Communications–Outreach. Outreach

has been a hallmark of the CCT Program since it’s

inception. Commercialization of new technologies

requires acceptance by a wide range of interests–

customers, manufacturers, suppliers, financiers, government, and public interest groups. The CCT Program

has aggressively sought to disseminate key information

to this full range of customers and stakeholders and to

obtain feedback on changing needs. This dissemination of information takes the form of printed media,

exhibits, and electronic media. Printed media takes the

form of newsletters, proceedings, technical papers, fact

sheets, program updates, and bibliographies. The CCT

Program currently uses four traveling exhibits of

varying sizes and complexity that can be updated and

tailored to specific forums. Electronic media is available through fax-on-demand, computer bulletin board

system, and the World Wide Web. As the 21st century
ES-12 Program Update 1998

Exhibit ES-4

Summary of Results of Completed Advanced Electric Power Generation Projects

Project and Participant Key Results Capital Cost

Tidd PFBC Demonstration Project (The Ohio Power

Company)

Nucla CFB Demonstration Project (Tri-State Generation

and Transmission Association, Inc.)

SO2

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

sulfur) at 1.1–1.5 Ca/S molar 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

SO2

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

depending on Ca/S molar 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

$1,263/kW at 360 MWe (1997$)

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

approaches, DOE is making more information available via the World Wide Web.

Feedback is another important part of the outreach

program. From public meetings during the PON

process to open houses at demonstration sites, the CCT

Program stays in contact with customers and stakeholders. Executive seminars, stakeholder meetings, conferences, workshops, and trade missions are used by the

CCT Program to disseminate information and obtain

feedback. The premier CCT Program outreach events

are the annual clean coal technology conferences. The

Sixth Annual Clean Coal Technology Conference was

held in Reno, Nevada from April 28 to May 1, 1998.

The conference focused on “What will it take?” to

realize the full commercial potential of clean coal

technologies.

Panel discussions at the conference identified two

basic issues that currently drive future technology

decisions in the domestic market—environmental

concerns and utility restructuring. With regard to

environmental concerns, the CCT Program has provided a portfolio of technologies to effectively deal with

acid rain concerns. Challenges remain, however, in

achieving ozone standards (a NOx

 control issue), PM2.5

control, and CO2 emission reductions. With regard to

utility restructuring, some 40 percent of the states are

sponsoring conceptually and functionally different

legislation driven by different rate structures, fuel

mixes, stranded cost implications, and environmental

policies. Thus, some argue that federal legislation is

needed to provide some consistency in what might

otherwise become an unnavigable maze of implementing mechanisms. Whatever the outcome of restructuring, it will have an impact–positive or negative–on the

future of clean coal technologies.

An International Business Forum was held at the

conference to identify emerging opportunities for clean

coal technologies worldwide. The consensus is that the

international market for clean coal technologies has

tremendous near-term potential. To capitalize on this

market potential requires action to mitigate the higher
Program Update 1998 ES-13

Exhibit ES-5

Commercial Successes—Advanced Electric Power Generation

Project and Participant Commercialization Progress

Tidd PFBC Demonstration Project (The Ohio Power Company) First utility-scale PFBC in U.S.

– Laid foundation for commercialization of PFBC

The first 360-MWe ABB Carbon P800 PFBC plant is being built in Japan

A second generation ABB Carbon P200 PFBC is under construction in Germany

Other ABB Carbon PFBC projects are under consideration in China, South Korea,

the United Kingdom, Italy, and Israel

Nucla CFB Demonstration Project (Tri-State Generation and Technology retained for commercial use at host site

Transmission Association, Inc.) – World’s first large utility-scale ACFB

Demonstration commercialized utility-scale ACFB

– Quantity—29 CFB units larger than 100-MWe planned, in construction, or in operation

 worldwide

– Estimated capacity—greater than 6,200 MWe

– Estimated value—almost $6 billion

Tampa Electric Integrated Gasification Combined-Cycle Project First greenfield IGCC unit in commercial service

(Tampa Electric Company) Texaco, Inc., and ASEA Brown Boveri signed an agreement forming an

alliance to market IGCC technology in Europe

Wabash River Coal Gasification Repowering Project First repowered IGCC unit in commercial service

(Wabash River Coal Gasification Repowering Project Joint Venture) – World’s largest single train IGCC in commercial service

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

 system because of high efficiency

Piñon Pine IGCC Power Project (Sierra Pacific Power Company) Unit in operation

Healy Clean Coal Project (Alaska Industrial Development and Export Authority) TRW offering licensing of combustor worldwide (China agreement in place)

risk and cost of clean coal technologies. Trading

mechanisms for CO2 such as the 161-nation “Global

Environmental Facility” and others proposed under

the Kyoto Protocol hold promise for reducing the

incremental costs for clean coal technologies, assuming CO2

 reduction requirements or incentives are

formalized. Fluidized-bed combustion and IGCC

technologies have begun to penetrate the market.

In addition to the Sixth Annual Clean Coal

Technology Conference, several other conferences

and workshops were held in fiscal year 1998. The

forums for the conferences varied from China to West

Virginia to Ukraine. Trade missions during fiscal year

1998 included China, Korea, Uruguay, Brazil, Japan,

and the Philippines. All of these conferences and trade

missions were used to endorse and promote the technologies demonstrated in the CCT Program.

CCT Projects

Technology Overview. The 40 CCT Program

projects provide a portfolio of technologies that 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.
ES-14 Program Update 1998

Exhibit ES-6

Summary of Results of Coal Processing for Clean Fuels

Project and Participant Key Results Capital Cost

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

The liquid (CDL®) and solid (PDF®) product fuels have

been used economically in commercial boilers and

furnaces and have reduced SO2 and NOx emissions

significantly at utility and industrial facilities currently

burning high-sulfur bituminous coal or fuel oils

Almost five years of operating data have been collected

for use as a basis for the evaluation and design of a

commercial plant

As of July 1997, about 260,000 tons of coal had been

processed into 120,000 tons of PDF® and 5,101,000

gallons of CDL®

CQETM package sells for between $75,000 and

$100,000

A commercial plant designed to process 15,000-metricton/day would cost $475 million (2001$) to construct

with annual operating and maintenance costs of $52

million per year

Development of the Coal Quality ExpertTM

(ABB Combustion Engineering, Inc., and CQ Inc.)

ENCOAL® Mild Gasification Project (ENCOAL

Corporation)

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

types. The 19 environmental control device projects

are valued at more than $704 million. These include

seven NOx

 emission control systems installed in more

than 1,750 MWe of utility generating capacity, five

SO2 emissions systems installed on approximately 770

MWe, and seven combined SO2

/NOx emission control

systems installed or planned for installation on more

than 665 MWe of capacity.

Advanced Electric Power Generation. To

respond to load growth, as well as growing environmental concerns, the CCT 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 NSPS; and salable solid and liquid

by-products in lieu of solid wastes. Over 1,800 MWe

of capacity are represented by 11 projects valued at

more than $3.1 billion. These projects 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.
Program Update 1998 ES-15

Exhibit ES-7

Commercial Successes—Coal Processing for Clean Fuels

Project and Participant Commercialization Progress

Development of the Coal Quality ExpertTM CQ Inc. and Black & Veatch working collaboratively to commercialize CQETM worldwide

(ABB Combustion Engineering, Inc. and CQ Inc.) CQE’s Acid Rain Advisor licensed to two U.S. users

30 U.S. and 1 U.K. utilities acquired CQETM through EPRI membership

Other foreign and domestic utilities pursuing access to CQETM

CQE technology saves U.S. utilities $26 million

CQETM Home Page posted on World Wide Web (http://www.fuels.bv.com:80/cqe/cqe.htm)

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

(Custom Coals International) Proposed agreement with China to build a coal-cleaning plant, slurry pipeline, and port facility

– Value—$450 million

Letter of intent for three 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 Demonstration Total sales of SynCoal® product exceeds 1,400,000 tons

(Rosebud SynCoal Partnership) Agreement in place to provide SynCoal® to fuel Montana Power’s 330 MWe Colstrip No. 2

A commercial project being developed

– Stand-alone minemouth design in Wyoming

ENCOAL® Mild Gasification Project (ENCOAL Corporation) Over 83,500 tons of solid fuel delivered to seven major utilities and metallurgical customers

Over 200 tank cars of liquid fuel delivered to eight industrial users

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

– Value—$460 million

Completed five feasibility studies—two Indonesian, one Russian, and two U.S. projects

Commercial-Scale Demonstration of the Liquid-Phase Methanol Nominal 80,000 gallon/day methanol production being used by Eastman Chemical Company

(LPMEOHTM) Process (Air Products Liquid-Phase Conversion Company, L.P.)

Coal Processing for Clean Fuels. Also addressed

are approaches to converting run-of-mine coals to highenergy-density, low-sulfur products. These products

have application domestically for compliance with the

CAAA. Internationally, both the products and processes have excellent market potential. Valued at more than

$51 million, the five projects in the coal processing for

clean fuels category represent a diversified portfolio of

technologies.

Industrial Processes. Projects were undertaken

as well to address pollution problems associated with

coal use in the industrial sector. The problems addressed include dependence of the steel industry on

coke and the inherent pollutant emissions in cokemaking; reliance of the cement industry on low-cost

indigenous, and often high-sulfur, coal fuels; and the

need for many industrial boiler operators to consider

switching to coal fuels to reduce operating costs. The

five industrial applications projects have a combined

value of nearly $1.3 billion. The projects encompass

substitution of coal for 40 percent of coke in ironmaking, integration of a direct iron-making process

with the production of electricity; reduction of cement

kiln emissions and solid waste generation; demonstration of an industrial-scale slagging combustor; and

demonstration of a pulse combustor system.

Project Fact Sheets. The core of this Program

Update 1998 is the project fact sheets. Two types of

fact sheets are provided: (1) a brief two-page overview
ES-16 Program Update 1998

Exhibit ES-9

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

Exhibit ES-8

Summary of Results of Industrial Application Projects

Project and Participant Key Results Capital Cost

SO2 reduction of over 80% with sorbent injection; 58%

maximum with limestone injection at 2.0 Ca/S molar 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

Not available

$10 million for 450,000 ton/yr wet-process plant (1990$)

Advanced Cyclone Combustor with Internal Sulfur,

Nitrogen, and Ash Control (Coal Tech Corporation)

Cement Kiln Flue Gas Recovery Scrubber

(Passamaquoddy Tribe)

for ongoing projects or (2) an expanded four-page

summary for projects that have successfully completed

operational testing. The latter contain a summary of

the major results from the demonstrations, as well as

sources for obtaining further information. Technology

descriptions, costs, and schedules are provided for all

projects. A list of the project fact sheets with the

participant, solicitation, and status is shown in Exhibit

ES-10. A list of the award winning CCT Program

projects is shown in Exhibit ES-11.
Program Update 1998 ES-17

Project Participant Solicitation/Status

Environmental Control Devices

SO2

 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/completed 3/94

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93

LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCT-III/completed 6/94

Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95

Demonstration of Innovative Applications of Technology for the Southern Company Services, Inc. CCT-II/completed 12/94

 CT-121 FGD Process

NOx

 Control Technologies

Micronized Coal Reburning Demonstration for NOx

 Control New York State Electric & Gas Corporation CCT-IV/operational

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

Full-Scale Demonstration of Low-NOx

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

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 1/95

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95

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 12/92

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

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/completed 5/98

Combined SO2

/NOx Control Technologies

Commercial Demonstration of the NOXSO SO2

/NOx Removal Flue NOXSO Corporation CCT-III/design

Gas Cleanup System

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/completed 12/94

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/completed 8/91

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5/93

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 10/94

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/completed 6/98

Integrated Dry NOx

/SO2 Emissions Control System Public Service Company of Colorado CCT-III/completed 12/96

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-III/design

McIntosh Unit 4B Topped PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-V/design

JEA Large Scale CFB Combustion Demonstration Project JEA CCT-I/design

Exhibit ES-10

Projects by Application Category

Shaded area indicates projects having completed operations.
ES-18 Program Update 1998

Exhibit ES-10 (continued)

Projects by Application Category

Tidd PFBC Demonstration Project The Ohio Power Company CCT-I/completed 3/95

Nucla CFB Demonstration Project Tri-State Generation and Transmission Association, Inc. CCT-I/completed 1/91

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project Clean Energy Partners Limited Partnership CCT-V/design

Piñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/operational

Tampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/operational

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

Advanced Combustion/Heat Engines

Healy Clean Coal Project Alaska Industrial Development and Export Authority CCT-III/operational

Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/construction

Coal Processing for Clean Fuels

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

(LPMEOHTM) Process

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Custom Coals International CCT-IV/design

Advanced Coal Conversion Process Demonstration Rosebud SynCoal Partnership CCT-I/operational

Development of the Coal Quality ExpertTM ABB Combustion Engineering, Inc., and CQ Inc. CCT-I/completed 12/95

ENCOAL Mild Coal Gasification Project ENCOAL Corporation CCT-III/completed 7/97

Industrial Applications

Blast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/operational

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) CPICORTM Management Company, L.L.C. CCT-V/design

Pulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/design

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

Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/completed 9/93

Project Participant Solicitation/Status

Shaded area indicates projects having completed operations.
Program Update 1998 ES-19

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-11

Award-Winning CCT Projects

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

cell burner.

1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management Association to the U.S. Department 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
Program Update 1998 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 nation’s

energy policy has responded to the oil embargoes of

the 1970s and the environmental debates of the 1980s.

The 1990s have brought about more changes in

response to required emission reductions for acid rain

precursors, initiation of more stringent NOx standards

for ozone nonattainment areas, the beginning of

electric utility restructuring, and concern about global

warming. These changes have also reshaped the

private sector’s response in the domestic and international marketplace.

Since 1985, a joint effort between government

and industry, known as the Clean Coal Technology

Demonstration Program (CCT Program), has responded to the challenges resulting from these dynamic

changes. The magnitude of the projects and extent of

industry participation in the CCT Program is unprecedented. More than $5.6 billion is being expended,

with industry and state governments investing two

dollars for every federal government dollar invested.

With 57 percent of the projects having completed

operations by the end of fiscal year 1998, the technological successes have manifested themselves in the

marketplace. New technologies to reduce the emissions of acid rain precursors, namely sulfur dioxide

(SO2

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

marketplace and are being used by electric power

producers and heavy industry. Advanced electric

power generation systems that generate electricity

with greater efficiency and fewer environmental

consequences are now operating with the nation’s

most plentiful fossil energy resource—coal. Coal,

which accounts for over 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 U.S. Department of Energy’s (DOE)

Energy Information Administration (EIA), coal was

used to produce over 1,797 billion kilowatt-hours or

52 percent of the nation’s electricity in 1996. EIA

projections count on coal continuing to dominate

electric power production, at least through 2020 (the

end of the forecast period), when coal will generate an

estimated 2,304 billion kilowatt-hours or nearly

49 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) environmental performance requirements established in current and emerging laws and

regulations and (2) operational and economic performance requirements to compete in the era of utility

restructuring and competition. The CCT Program is

responding to these requirements by producing a

portfolio of advanced coal-based technologies that

will enable coal to retain its prominent role in the

nation’s power generation future. Furthermore,

advanced technologies emerging from the CCT

Program will also enhance coal’s competitive position

in the industrial sector. For example, technology

advances in steelmaking, involving direct use of coal,

will reduce the cost of production while greatly

improving environmental performance. Coal could

increase its market share in the industrial sector

through cogeneration (steam and electricity) and

coproduction of products (clean fuels and chemicals).

While the CCT Program responds to domestic

needs for competitive and clean coal-based technology, it also positions U.S. industry to compete in a

burgeoning power market abroad. Coal is the fuel of

necessity for many foreign economies. Through the

CCT Program, U.S. industry has obtained the knowledge base needed to replicate clean coal technologies

both domestically and abroad.

Coal Technologies Respond

to Need

The environmental and competitive performance

of modern coal technologies has evolved through

many years of industry and government research,

development, and demonstration (RD&D). The

programs were pursued to assure that the U.S. recoverable coal reserves of 274 billion tons, which represent a secure energy source, could supply the nation’s

energy needs economically and in an environmentally

acceptable manner.

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

government-sponsored technology demonstrations

focused on synthetic fuels production technology.

Under the Energy Security Act of 1980, the Synthetic

Fuels Corporation (SFC) was established for the

purpose of reducing the U.S. vulnerability to disrup-
1-2 Program Update 1998

tions of crude oil imports. The SFC’s purpose was

accomplished by encouraging the private sector to

build and operate synthetic fuel 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 of synthetic fuels

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 short-term supply buffer was provided by the

Strategic Petroleum Reserve. In 1986, Congress

responded to the decline of private-sector interest in

the production of synthetic fuels in light of these

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.

The CCT Program was initiated in October, 1984.

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. Coal was recognized as an essential element

in this energy policy for the foreseeable future because of the following:

1. The location, magnitude, and characteristics of

the coal resource base are well understood.

2. The technology and skilled labor base to safely

and economically extract, transport, and use

coal are available.

3. A multi-billion dollar infrastructure is in place

to gather, transport, and deliver this valuable

energy commodity to serve the domestic and

international marketplace.

4. Coal is used to produce over half of the

nation’s electric power and is vital to industrial

processes, such as steel and cement production, as well as industrial power.

5. This abundant fossil energy resource is secure

within the nation’s borders and relatively

invulnerable to disruptions because of the coal

industry’s production responsiveness and

stockpiling capability.

6. Coal is the fuel of necessity in many lesser

developed economies, which provides export

opportunities for U.S. developed coal-based

technologies.

Congress 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 operational, economic, and

environmental performance. The CCT Program was

established to demonstrate the commercial feasibility

of clean coal technology applications in response to

that need. In 1986, the first solicitation (CCT-I) for

clean coal technology projects was issued. The CCT-I

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 Joint Report of the Special Envoys on Acid Rain

(1986). A presidential initiative launched a five-year,

$5-billion U.S. industry/government 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 emission reductions in SO2

, NOx, or both, from

existing power plants. These technologies were to be

more cost-effective than current technologies and

capable of commercial deployment in the 1990s. In

May 1989, a third solicitation (CCT-III) was issued

with essentially the same objective as the second, but

additionally encouraged technologies that would

produce clean fuels from run-of-mine coal.

The next two solicitations recognized emerging

energy and environmental issues, such as global

climate change and capping of SO2

 emissions, and

thus focused on seeking highly efficient, economically

competitive, and low-emission technologies. Specifically, the fourth solicitation (CCT-IV), released in

January 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
Program Update 1998 1-3

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 60 government/industry cost-shared projects were

selected, of which 40 valued at more than $5.6 billion

have either been successfully completed or remain

active in the CCT Program.

The success of the government/industry CCT

Program is directly attributable to the CCT Program’s

responsiveness to public and private sector needs to

reduce environmental emissions and maximize economic and efficient energy production. The CCT

Program 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

SO2 Control. During the late 1980s, work began

on drafting what was to become the CAAA. On

November 15, 1990, Congress enacted Public Law

101-549, the Clean Air Act Amendments of 1990.

Title IV, Acid Deposition Control, established emissions reduction targets for SO2

, capped SO2 emission

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 “commandand-control” approach wherein the emission-reduction

method 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. The second increment implemented

through Phase II will begin on January 1, 2000. Title

IV identified 261 generating units (designated as

“affected units”) that were required to comply with

Phase I. Most of these units are coal-fired with fairly

high emission rates. Exhibit 1-1 summarizes the

compliance methods used by the 261 affected units

listed in Title IV to satisfy Phase I requirements. An

additional 174 units are participating in Phase I based

on U.S. Environmental Protection Agency (EPA)

rules that 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.

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.

On the other hand, non-Phase I unit emissions were 12

percent higher (6.6 million tons) than their 1990

emissions of 5.9 million tons.

Several projects within the CCT Program, listed

below, were designated affected units and were

required to achieve compliance with Phase I requirements:

• Northern Indiana Public Services Company’s

Bailly Generating Station, 528-MWe Unit

Nos. 7 and 8 (Pure Air advanced flue gas

desulfurization scrubber);

• Georgia Power Company’s Plant Yates,

100-MWe Unit No. 1 (Chiyoda Thoroughbred-121 advanced flue gas desulfurization

scrubber);

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 261 100 345 100

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 1998

• New York State Electric & Gas Corporation’s

Milliken Station, 300-MWe Unit Nos. 1 and 2

(S-H-U formic-acid-enhanced wet limestone

scrubber); and

• PSI Energy’s Wabash River Station,

262-MWe Unit No. 1 (repowered with Destec

integrated gasification combined-cycle unit).

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/blending

compliance strategy was selected for 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, and

• Illinois Basin coal—decreased 40 million tons.

In Phase II, beginning January 1, 2000, annual

SO2

 tonnage emission limitations will be determined

based on a 1.20 lb/106 Btu emission rate and 1985-87

baseline fuel consumption. Most utilities have still

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 Federal Energy Regulatory Commission

(FERC) Order Nos. 888 and 889 and state-level utility

restructuring legislation. Under the previous regulatory environment, state regulators would

allow utilities to pass on pollution

control costs to consumers. In a

restructured competitive environment,

the added cost of capital-intensive

environmental controls could put a

utility at a disadvantage relative to

those utilities that can achieve compliance with lower cost alternatives, such

as fuel switching and blending. The

EIA projects that fuel switching and

blending will be the predominant

strategy used, with emission allowance purchases being the second

choice. However, allowance prices

are increasing and are expected to

increase significantly after 2000,

making the scrubbing option more cost competitive.

The EIA projects that by 2010 about 23 gigawatts of

coal-fired capacity will be retrofitted with scrubbers.

The technologies applied will have their roots in the

CCT Program, which redefined the state-of-thetechnology in scrubbers and essentially halved the

cost relative to conventional scrubbers of the time.

Another option available to utilities is to repower with

a clean coal technology. Under the repowering

option, a four-year extension (to December 31, 2003)

is available to comply with the Phase II requirements

with advanced electric power generation technology.

NOx

 Control. In Title IV of the CAAA, Congress also required the EPA to establish annual allowable emissions limitations for NOx

 in two phases.

Phase I required NOx reductions from tangentiallyfired and dry-bottom wall-fired boilers. These boilers

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

EPA promulgated a rule establishing NOx emission

limitations of 0.45 lb/106 Btu for tangentially-fired

units and 0.50 lb/106

 Btu for wall-fired 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 utility organizations, EPA

issued a final rule revising the definition of low-NOx

burner technology. Furthermore, 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 federal and

state approval for transactions of NOx and volatile

organic compounds (VOCs) credit trading. Instead,

utilities would be able to comply with various air

pollution mandates by buying and using an appropriNew York State Electric & Gas Corporation’s Milliken Station used the

S-H-U scrubber to achieve 98 percent SO2

 removal and compliance with Phases

I & II of the CAAA.
Program Update 1998 1-5

ate number of tons of “discrete emissions reductions”

(DERs). Utilities would be able to generate emission

reduction credits for smog precursors by voluntarily

reducing NOx

 and VOCs and then 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. The rule established NOx emission limitations for additional coal-fired boilers

(Group 2) and reduced the NOx emissions limitations

on Group 1 boilers. The types of Group 1 and 2

boilers 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 for

Group 1, EPA was able to use data developed during

the Southern Company Services’ evaluation of NOx

control on wall-fired and tangentially-fired boilers.

Furthermore, operational, environmental, and economic data on NOx

 controls were developed under the

CCT Program for all four major boiler types (wallfired, tangentially-fired, cyclone-fired, and cellburner), which constitute over 90 percent

of the pre-New

Source Performance

Standard (NSPS)

boiler types. In

addition, low-NOx

burners were installed

and tested on a

vertically-fired boiler.

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 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 or new National Ambient Air Quality

Standards (NAAQS) for ozone.

New Rules

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 proChiyoda’s CT-121 system demonstrated at Georgia

Power’s Plant Yates achieved high SO2

 capture efficiencies

and enhanced capture of particulate matter.

Exhibit 1-2

CAAA NOx Emission Limits

Group 1 Group 2 Phase I NOx Phase II NOx

Boiler Type Boiler 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 1998

posed or finalized and will need to be considered in

the research, development, and deployment of clean

coal technologies. The following rules are illustrative.

Attainment of Ozone Standards (Title I).

CAAA Title I established an ozone transport commission to address regional transport of pollutants that

contribute to ozone nonattainment in the Northeast.

The Northeast Ozone Transport Commission approved a Memorandum of Understanding in September 1994 stipulating intent to reduce power plant

emissions of NOx (a precursor to ozone formation) by

as much as 70 percent by 2003. The Ozone Transport

Assessment Group (OTAG), a collaborative effort by

37 states and the District of Columbia, was established

in June 1995 to address the issue of ozone transportation. In response to recommendations issued in June

1997 by the OTAG Policy Group, EPA issued a “SIP

Call” to 22 states and the District of Columbia. The

SIP Call (effective December 28, 1998, as EPA’s

ozone-transport rule) requires these 23 jurisdictions to

submit emission reduction plans by December 30,

1999 on how to cut NOx emissions 85 percent below

1990 rates or achieve a 0.15 lb/106 Btu emission rate

by May 2003.

The EPA is also formulating a plan for utilities

and industries to trade allowances for NOx emissions.

The “cap and trade” program would apply to the 23

jurisdictions affected by the SIP Call. The EPA states

that most areas will be able to meet air quality standards without additional air controls. Under the plan,

the affected jurisdictions would establish a cap on

NOx emissions and then give power plants and industries the flexibility to cut NOx

 emissions in the most

cost-effective manner. Power plants and industries

that cut NOx

 emissions below the caps could sell

credits to facilities that could not cut emissions as

quickly or cost-effectively.

The NOx trading program, similar to the SO2

trading program, allows sources to pursue various

compliance strategies; such as fuel switching; installing pollution control devices, like the devices demonstrated in the CCT Program; or buying allowances

from sources that over-complied.

The EPA has tightened its NOx

 emission standards for new electric utility boilers and has changed

its rules so that all generation fuels are treated equally. Under the revised new source performance standard, electric utility and industrial steam generating

units built or modified after July 9, 1997, must meet

an emission limit of 1.6 lb/MWh regardless of fuel

type. For existing sources that become subject to new

standards, the NOx limit is now 0.15 lb/106 Btu. By

basing the standard on electricity output, there is an

economic incentive to use more efficient systems.

Soot and Smog. In 1997, EPA set new NAAQS

provisions for particulate matter (PM) and ozone

(commonly referred to as soot and smog). The

standard for inhalable particles (PM10) remains essentially unchanged, while a new standard for respirable

particles (PM2.5)—those measuring 2.5 micrometers in

diameter and smaller—was established at an annual

limit of 15 micrograms per cubic meter, with a 24-

hour limit of 65 micrograms per cubic meter.

The proposed revisions to NAAQS for PM 2.5 also

might require additional SO2

 control because many

NOx emissions at Georgia Power’s Plant Hammond

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

burners, shown here, and advanced overfire air.

Eight SCR catalysts with various shapes and

compositions were evaluated side-by-side at Gulf Power’s

Plant Crist using high sulfur coal. NOx

 reductions of 80

percent were achieved.
Program Update 1998 1-7

sulfur species are in this size range. Establishing

reliable relationship between fine sulfate emissions and

ambient PM 2.5 concentrations could have serious

repercussions for coal burning facilities.

For ozone, the standard was tightened from 0.12

parts per million (or 120 parts per billion) of ozone

measured over one-hour to a new standard of 0.08

parts per million (or 80 parts per billion) measured

over eight-hours, with the average fourth highest

concentration over a three-year period determining

whether an area is out of compliance.

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 risks that are likely to occur as a result of power

plant emissions. The Department of Energy (DOE)

recognizes the importance of detecting and measuring

HAPs in stack gases and has implemented a program

with industry to monitor HAPs emissions at CCT

Program project sites. Two objectives of the HAPs

monitoring are to (1) improve the quality of HAPs data

being gathered and (2) monitor a broader range of

plant configurations and emissions control equipment.

As a result of this program, 21 CCT projects are

monitoring HAPs, with 11 having been completed by

September 1998 (see Appendix C Exhibit C-7).

In another effort begun in January 1993, EPA,

with the participation of DOE under the Coal Research and Development Program, the Electric Power

Research Institute (EPRI), and the Utility Air Regulatory Group (UARG), began an emissions data collection program using state-of-the-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. The second phase of the DOE/EPRI effort

involves sampling at other sites, including the CCT

Program’s Wabash River, Tampa Electric, and Sierra

Pacific integrated gasification combined-cycle (IGCC)

projects.

In another DOE study, HAPs data were collected

from 16 power plants and reported in Summary of Air

Toxics Emissions Testing at Sixteen Utility Plants.

The report, issued in July 1996, provides an assessment of HAPs measured in the coal, across the major

pollution control devices, and emitted from the stack.

Following up on the October

1996 EPA report to Congress,

Study of Hazardous Air Pollutant

Emissions from Electric Utility

Steam Generating Units, Interim

Final Report, a new report has

been released by EPA focusing on

Mercury emissions. The December

1997 report, Mercury Study Report

to Congress, estimates that the U.S.

industrial sources were responsible

for releasing 158 tons of Mercury

into the atmosphere in 1994 and

1995. The EPA estimates that 87

percent of those emissions originate from combustion sources such

as waste and fossil fuel facilities, 10 percent from

manufacturing facilities, 2 percent from area sources,

and 1 percent from other sources. The EPA also

identified four specific categories that account for

about 80 percent of the total anthropogenic sources:

coal-fired power plants, 33 percent; municipal waste

incinerators, 18 percent; commercial and industrial

boilers, 18 percent; and medical waste incinerators, 10

percent. The next step for EPA is to assess the need

for enhanced research on health effects and new

pollution control technologies, community “right-toknow” approaches, and regulatory actions.

The results of the HAPs program have significantly mitigated concerns about HAPs emission from

coal-fired power generation and focused attention on 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.

Hazardous air pollutants are being measured at the Wabash River IGCC unit.
1-8 Program Update 1998

Global Climate Change Protection

The CCT Program had its roots in the reduction

of acid rain precursors and was responsive to the

recommendations contained in the Joint Report of the

Special Envoys on Acid Rain as discussed earlier.

Twelve 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 May 1992, the United States became a signatory to the U.N. Framework Convention on Climate

Change (FCCC), which was ratified by Congress in

October 1997. 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, recommended a number of voluntary mitigation actions. In 1995,

the first meeting of the Conference of Parties (COP-1)

to the FCCC was held in Berlin, Germany. The

purpose of this conference was to determine whether

the non-binding FCCC was adequate. The conclusion

was that most parties at COP-1 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. The

second meeting of the Conference of Parties (COP-2)

held in Geneva, Switzerland, in July 1996, resulted in

the Geneva Declaration calling for Annex I parties to

adopt legally binding commitments by the Third

Conference of Parties (COP-3) scheduled for Kyoto,

Japan, in December 1997. At Kyoto, the following

agreements were reached:

• A multi-year timeframe (2008-2012) for

emission reductions;

• Five year averaging of emissions reductions;

• Differentiated targets for key industrial nations

ranging from 6 to 8 percent below baseline

levels (1990 and 1995), with the United States

agreeing to a 7 percent reduction below a 1990

baseline;

• Allowance for certain activities, such as

planting trees, that absorb carbon dioxide—

called “sinks”—to be offset against emissions

targets; and

• Inclusion of all six significant greenhouse gases

(CO2

, methane, nitrous oxide, ozone, water

vapor, and hydrofluorcarbons).

The agreement also includes flexible market

mechanisms to allow countries to reach their targets,

rather than “policies and measures,” such as carbon

taxes. Companies and countries will be able to trade

emissions permits. However, the Kyoto agreement

failed to meet U.S. demands for participation by

developing countries.

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; and the Tennessee Valley

Authority.

The Climate Challenge 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. The 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 generation; resource mix; or load growth.

Clean coal technologies can play an important

role in implementation of these Participation Accords.

Improvements in generation technology, knowledge of

how generation is operated and maintained, and

optimal location of generation on the grid can have

measurable beneficial effects on 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. 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, Dynergy, are demonstrating coal gasification
Program Update 1998 1-9

repowering of an existing unit. Where there was an

aging, inefficient, little-used unit, there is now a very

clean and highly efficient unit that will generate power

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 relative to a conventional plant of the

same size. Additionally, emissions of SO2

, NOx, and

particulate matter are reduced by at least 90 percent.

The 250-MWe Tampa Electric Company’s

integrated gasification combined-cycle project began

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

kilowatt-hour (40 percent efficiency), the plant’s

operation will result in a GHG emission reduction of

over 20 percent when compared to conventional

technology. Sierra Pacific Power Company’s Piñon

Pine integrated gasification combined-cycle (IGCC)

project (99 MWe), which began operation in 1998,

will result in similar reductions. Technologies such as

pressurized fluidized-bed combustion and integrated

gasification fuel cell, also being demonstrated under

the CCT Program, represent other high-efficiency

technology options for significant reduction of CO2

.

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 Research and Development 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. This program also serves as

a source of independent expert data for policy makers,

industry, and the public on coal technologies to

address global climate concerns.

The IEA/GHG is conducting studies of a number

of technologies, including many clean coal technologies. For example, completed studies address IGCC,

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 also addresses solid waste

considerations. For example, two projects redefined

the state-of-the-technology in wet flue gas desulfurization. Included in this significant technology improvement was production of commercial-grade gypsum in

lieu of the scrubber sludge associated with conventional scrubbers of the early 1990s. Scrubber sludge

had been projected to require over 4,500 acres per

year for disposal by 2015. Advances under the CCT

Program precluded that need. The balance of technologies in the CCT Program also address solid waste

concerns by producing salable byproducts instead of

wastes (e.g., sulfur, sulfuric acid, or fertilizer) or dry

environmentally benign materials. These dry materials

can either be used as construction materials (e.g., for

use in soil and road bed stabilization, or as a cement

ingredient), agricultural supplements, means to mitigate mine subsidence and acid mine drainage, or

readily disposed of in landfills.

Coal Technologies for

Competitive Performance

When the CCT Program started in 1986, the

electric utility industry was highly regulated. The

major uncertainty was the breadth and depth of environmental regulatory requirements that would be

imposed on the industry. Even this uncertainty was

mitigated by the fact that 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. Most industry observers 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 was 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 and thus a competitive production

cost edge.
1-10 Program Update 1998

• The Public Utility Regulatory Policies Act of

1978 (PURPA) and the Energy Policy Act of

1992 (EPAct) were two major legislative

factors. 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

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

about 10 percent of the utility generation in

1995. The EPAct, in amending the Public

Utility Holding Company Act of 1935

(PUHCA) and the Federal Power Act of 1935

(FPA) lifted more of the constraints on the

development of nonutility generation as well

as some of the restrictions on competition in

wholesale electricity markets.

• The EPAct created a new class of producer

called the exempt wholesale generator (EWG),

which is defined as “any person determined by

the Federal Energy Regulatory Commission to

be engaged directly through one or more

affiliates—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. The EPAct

specifically allowed both registered and

prohibited from ordering retail wheeling.)

Under the 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 the end of

Fiscal Year 1998, twelve states have enacted

legislation to allow competition in the retail

electricity market in one form or another. In

six other states, there have been comprehensive regulatory orders issued. Legislation or

regulatory action is pending in another six

states. Twenty-four states and the District of

Columbia are currently investigating deregulation options. Only in two states is there no

significant deregulation activity. 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

electricity cheaper than can be achieved using

conventional fossil steam or nuclear generators. The new technologies are often more

efficient, less environmentally obtrusive, and

can be installed in a very short period of time

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 utility company

from purchasing wholesale energy from an

EWG that was one of its affiliates. Unlike

PURPA, the PUHCA reforms did not guarantee EWGs a market for their power, thereby

requiring that the EWGs compete with power

from other sources in the wholesale power

market.

• The 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. Furthermore,

anyone may petition the FERC for access to

the transmission grid. On April 14, 1996, the

FERC issued two closely related orders, Order

Nos. 888 and 889, detailing rules to assure

nondiscriminatory open access to interstate

electricity transmission and recovery of the

utilities’ prudently incurred costs. Order Nos.

888-A, 888-B, 889-A, and 889-B were

subsequently issued clarifying and modifying

positions in the original orders. The orders are

currently being appealed.

• 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
Program Update 1998 1-11

in capacity modules closely matching the load

growth curves.

• Also, federal legislation on utility restructuring

seems imminent as a number of bills are being

debated.

These factors have had a pronounced effect on

the utility market for coal and clean coal technology.

A comparison of 1985 and 1997 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 49 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

power generation. Nuclear power’s contribution to

the nation’s electric power generation in 2010 has

dropped by 28 percent between the 1985 and 1997

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. Contributing to increased capacity factors is a

projected drop in generating capacity not only from nuclear plant

retirements but capacity losses

where stranded costs are not recovered. The EIA has projected that

the capacity factor for coal-fired

power plants will increase from 66

percent in 1996 to 80 percent in 2020. The EIA

projects natural gas-fired generation to grow from

over 462 billion kilowatt-hours in 1996 to 1,583

billion in 2020, most of that using combined-cycle

technology. EIA further predicts that no net coal-fired

capacity additions will be made until 2010, when

rising natural gas costs and nuclear and coal retirements are projected to cause increasing demand for

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. Also, cogeneration and coproduction systems

will be available, which allow the consumer’s cost of

electricity 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. The CCT Program is also demonstrating

technologies to produce clean fuels. Processes to

remove precursors to acid rain and HAPs represent a

pollution prevention approach that is an integral part

of efforts to develop advanced coal-based power for

the future.

Coal Technologies to

Sustain Economic Growth

It is in the national interest to maintain a multifuel energy mix to sustain national economic growth.

Coal is a key component of national energy security

because of its affordability, availability, and abundanExhibit 1-3

Comparison of Energy Projections

Electricity Sales Coal Consumption Gas Consumptiona Oil Consumptiona

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

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

1995 3,018 3,026 0.3 924 958 3.7 3.0 3.37 12 0.2 0.30 50

2000 3,384 3,318 -2.0 1,059 1,058 -0.1 2.7 4.05 50 0.6 0.24 -60

2010 4,176 3,877 -7.2 1,355 1,162 -14.2 1.7 7.22 325 0.4 0.16 -60

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

B Annual Energy Outlook 1998 with Projections to 2020, Energy Information Agency, December 1997.

% dif = percent difference between the two projections.

a Consumptions by electric generators excluding cogenerators.
1-12 Program Update 1998

cy within the nation’s borders. The CCT Program’s

strategy leads to the development and deployment of a

technology portfolio that enhances the efficient use of

this coal resource while assuring national and global

environmental goals are achieved. The domestic coal

resources are large enough to supply U.S. needs for

more than 250 years at current rates of production.

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. In 1996, net petroleum

imports were 8.5 million barrels per day, or 46 percent

of domestic consumption. In its latest projections for

2020, EIA expects imports to range from 13.8 to

18.4 million barrels per day depending on oil price.

The EIA reference case for 2020 calls for net imports

of 16.0 million barrels per day, which is equivalent to

over 66 percent of consumption. Also, natural gas

imports are expected to grow from 12.4 percent of

total gas consumption in 1996 to 15.3 percent in 2020.

These imports are primarily from Canada, which does

not represent a supply stability problem, but does

represent a drain on balance of payments.

United States 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. The CCT Program will provide

the technologies that will enable coal 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 1996

coal production approaches $23.2 billion in the U.S.

economy. Coal related jobs are dispersed through the

mining, transportation, manufacturing, utility, and

supporting industries.

A U.S. coal conversion industry could directly

reduce the nation’s dependency on imported oil. The

economic impact of adding to domestic oil production

or reducing the cost of imported oil is very significant.

The CCT Program is responding to this opportunity

through development and demonstration of mild

gasification and liquid-phase methanol production

technologies.

In 1996, the U.S. exported 90 million tons of coal

to more than 40 nations. Coal exports to foreign

destinations contributed $3.39 billion to the U.S.

balance of payments in 1997. Worldwide demand for

energy is expected to reach 639 quadrillion Btu by

2020, over 1.7 times the current level. According to

the EIA, worldwide coal use in 1995 accounted for

about 25 percent of total energy consumption and 36

percent of the energy consumed worldwide for electricity generation. Those market shares are not projected to change substantially through 2020. Exports

of U.S. coal are projected to increase to over 128 million tons by 2020.

The worldwide market for power generation

technologies could be as high as $2.3 trillion between

1995 and 2010. Roughly two-thirds of the investment

will be in developing countries. This market provides

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

the CCT Program. However, aggressive action is

needed as other governments are recognizing the

enormous economic benefits that their economies can

enjoy if their manufacturers capture a greater share of

this market.

Beyond the CCT Program, DOE activities are

aimed at creating a favorable export climate for U.S.

coal and coal technology. These efforts 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.

National energy security is enhanced by coal

liquefaction technology being demonstrated at the Eastman

Chemical Company in Kingsport, TN. Air Products and

Chemical’s liquid phase methanol process is producing

80,000 gallons per day of methanol from eastern highsulfur bituminous coal.
Program Update 1998 1-13

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. The R&D Program is designed to assure an ample, secure, clean, low-cost

domestic electricity and domestic fuel supply through

viable technical options. Contributions of the RD&D

Program toward achieving national energy policy

goals include:

• Improving the efficiency of the energy system,

• Ensuring against energy disruptions,

• Promoting energy production and use in ways

that respect health and environments,

• Expanding future energy choices, and

• Cooperating internationally on energy issues.

Vision 21

Vision 21 PowerPlex. DOE’s Fossil Energy

RD&D program builds on the CCT Program toward

realizing a “Vision 21 PowerPlex”—a modular facility capable of using a multiplicity of fuels (such as

coal, biomass, gas, petroleum coke, and municipal

waste) to competitively produce a number of commodities (such as electricity, steam, fuels, and chemicals) at efficiencies greater than 60 percent and with

near zero pollutant emissions.

A Vision 21 PowerPlex represents a suite of

technology modules that can be interconnected in

different configurations to produce selected products.

When coupled with CO2

 capture and recycling or

sequestration, Vision 21 systems would create no

environmental impact outside of their physical “footprint.”

Exhibit 1-4 graphically illustrates the Vision 21

concept. Core technology and enabling technology

thrusts are outlined below.

Vision 21 Core Technologies

Fuel-Flexible Gasification. Gasification is a key

core technology because the syngas produced from

carbon-based feedstocks can be used as fuel for a gas

turbine in an integrated gasification combined-cycle

electric power generation mode, a source of hydrogen

for a fuel cell, feedstock for production of chemicals,

or a fuel gas for industrial applications. RD&D will

address how best to gasify fuel mixtures such as coal

and biomass.

High-Performance Combustion. Combustion

remains a primary energy conversion process that can

be used in conjunction with other approaches such as

gasification. The RD&D challenge will be to significantly improve on efficiency and pollutant control

through combustion modification and integration of

other process technologies such as gasification and

high temperature heat exchangers, particulate filtration, and advanced gas turbines.

Fuel Cell/Turbine Hybrids. Fuel cells and gas

turbines represent important energy supply technologies historically on two separate development paths.

Under Vision 21, concepts will be pursued to integrate the two technologies and adapt them to operate

on a multiplicity of fuels.

Exhibit 1-4

Vision 21 PowerPlex
1-14 Program Update 1998

Gas Separation Technologies. Advanced

membrane technology shows promise for separating

two key elements used in energy supply technologies—oxygen and hydrogen—from air and process

streams. Membrane RD&D will be pursued because it

has the potential to significantly reduce the cost of the

existing energy intensive methods—cryogenic air

separation is currently used to produce oxygen for

gasification and natural gas reforming is used to

produce hydrogen for fuel cells.

Vision 21 Enabling Technologies

Materials. The drive to higher efficiency requires operation at ever increasing temperatures and

pressures in corrosive environments. To realize

efficiency goals, materials will be developed with the

requisite strength and resistance to corrosion and hightemperature.

Catalysts and Sorbents. Improved catalysts

offer the means to reduce the energy needed to affect

conversion in such areas as coal to liquid fuels or

chemicals. Sorbents that can operate effectively at

high temperatures mitigate heat losses associated with

lowering process temperatures to accommodate

conventional sorbents. Progress in catalyst and

sorbent performance will be pursued because of the

direct efficiency gains possible.

Instrumentation. The flexibility desired in

Vision 21 plants to adjust to changing feedstocks and

production requirements necessitates new control

systems. RD&D will link artificial intelligence with

sensors for key parameters to measure, process, and

resolve the myriad of inputs necessary to affect optimum performance.

“Virtual” Plants. Scarce resources dictate less

reliance on hardware testing and more reliance on

RD&D assures that clean, affordable coal technologies

will be available in the future. Air Product’s LaPorte coal

liquefaction test facility (above) and Southern Company

Services’ Wilsonville power system development facility

(right) contribute to RD&D efforts.

predictive models in developing new technologies.

Vision 21 efforts will increasingly rely on new computer simulation technologies to test processes and

verify engineering performance, requiring development of advanced computation techniques similar to

those used today to design commercial airplanes or to

simulate nuclear explosions.

Carbon Sequestration. The means to capture

and either recycle or permanently store CO2

 will also

be sought. In conjunction with Vision 21, carbon

sequestration would close the carbon cycle for fossil

energy-based systems and eliminate the threat of

global climate change.
Program Update 1998 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 60 government/

industry cost-shared projects were selected, of which

40 valued at more than $5.6 billion have either been

completed or remain active at the end of Fiscal Year

1998. For the 40 projects, the industry cost-share is an

unprecedented 66 percent. Over 57 percent of the

projects (23) have reached successfully completed

operations. The balance are moving forward, with

operational testing under way for eight projects

Over the nine-year period of soliciting and awarding projects, the thrust of the environmental concerns

relative to coal use changed. Nevertheless, 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 result 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 the operational, environmental, and

economic performance of a technology can be projected for commercial applications. Decision-makers must

have a sufficient database to project performance and

assess associated risk for commercial introduction and

deployment of new technologies. This measure was a

driving force in establishing the principles that created

the foundation for the implementation process. The

government role is non-traditional, moving away from a

command-and-control approach to a performancebased 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 approach encourages technology

innovation and cost-sharing. Industry and the public

play major roles in the 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 66 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

in response to the objectives and criteria. DOE
2-2 Program Update 1998

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 the 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 strengthened.

• 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-a-kind

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 the

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 using

its expertise and getting the technology into the marketplace.

Implementation Process

Significant public and private sector involvement

was integral to the process leading to 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 the environmental impacts. 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). The Department of Energy translated the

congressional guidance and direction into performance-based criteria and developed approaches to

address lessons learned from previous solicitations.

Before proceeding with a solicitation, however, an

outline of the impending solicitation and attendant

issues and options was presented in a series of regional

public meetings to obtain feedback. The public meetings were structured along the lines of workshops to

facilitate discussion and obtain comments from the
Program Update 1998 2-3

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

of the solicitation 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. The

National Environmental Policy Act 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 (FONSI).

During the EIS process, public meetings are held for

the purpose of disclosing the intended project activities, with emphasis on potential environmental, health,

safety, socioeconomic impacts, and planned mitigating

measures. Comments are sought and must be resolved

before the project can proceed. This process 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 cost-sharing 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

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 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

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 1998

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., the Electric

Power Research Institute and Gas Research Institute).

This was accompanied by executive seminars designed

to enhance communications with 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. Furthermore, an annual CCT

Conference was instituted to serve as a forum for

updating progress and results and discussing issues

effecting the outcome of the CCT Program. And, an

outreach program 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. These activities are discussed in further

detail in Section 4.

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. To document lesson learned, 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, operational, and economic benefits of

the technologies being demonstrated in the program

will be realized when 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

operational, economic, and environmental data and the

experience gained during the demonstration are vital to

efforts to commercialize the technology. The government’s role is to capture, assess, and transfer operational, economic, and environmental information to a broad

spectrum of the private sector and international community. The information must be sufficient to allow

potential commercial users to confidently screen the

technologies and to identify those meeting operational

requirements. The importance of commercial 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; and

• 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.
Program Update 1998 2-5

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. These three mechanisms are:

• The commercialization clause requires the

technology owner to meet U.S. market demands

for the technology on a nondiscriminatory basis

(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; and

• The patent clause affords protection for new

inventions developed in the project.

In addition to ensuring the implementation of the

above project-specific mechanisms, the government

role also includes disseminating the operational, envibut 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 a Comprehensive Report to Congress issued after each solicitation.

Exhibit 2-1 summarizes the results of solicitations.

Exhibit 2-2 identifies the projects currently in the CCT

Program and the solicitation under which the projects

were selected. Appendix B provides a 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. More than 55 individual electric

generators serving 33 states have participated in the

program. These utilities generate more than 178,000

ronmental, and economic performance information on

the technologies to potential customers and stakeholders. To carry out this role, a CCT Outreach Program

was established to perform the following functions:

• Make the public and local, state, and federal

government policy makers aware of the CCTs

and their operational, economic and environmental benefits;

• Provide potential domestic and foreign users of

the technologies with the information needed

for decision making;

• Inform financial institutions and insurance

underwriters about the advancements in

technology and associated risk mitigation to

increase confidence; and

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

information requirements.

Specific accomplishments of the CCT Outreach

Program are discussed in Section 4 under Market

Communications–Outreach.

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

Publications keep stakeholders informed of CCT

Program contributions.

Exhibit 2-1

CCT Program Selection Process Summary

Projects in

Proposals Projects CCT Program as

Solicitation PON Issued Submitted Selected of Sept. 30, 1998

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 6

CCT-V July 6, 1992 24 5 4

211 60 40
2-6 Program Update 1998

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

JEA Large Scale CFB Combustion Demonstration Project Jacksonville, FL

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 1998 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, Lakeland Electric) 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

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

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) To be determined

CCT-IV

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

Pulse Combustor Design Qualification Test (ThermoChem, Inc.) Baltimore, MD

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

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

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) Carbondale, IL

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

Project and Participant Location

Exhibit 2-2 (continued)

Clean Coal Technology Demonstration Projects by Solicitation
2-8 Program Update 1998

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

NOXSO Corporation

To be determined
Program Update 1998 2-9

Alaska Industrial

Development and

Export Authority

Healy, AK

Clean Energy Partners Limited Partnership

Carbondale, IL

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,

Lakeland, FL

Arthur D. Little, Inc.

Fairbanks, AK

JEA

Jacksonville, FL
2-10 Program Update 1998

Rosebud SynCoal

Partnership

Colstrip, MT

ENCOAL Corporation

Gillette, WY

ABB Combustion

Engineering, Inc., and CQ Inc.

Homer City, PA

Air Products Liquid

Phase Conversion

Company, L.P.

Kingsport, TN

Exhibit 2-5

Geographic Locations of CCT Projects—Coal Processing for Clean Fuels

Custom Coals International

Central City, PA
Program Update 1998 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

ThermoChem, Inc.

Baltimore, MD
2-12 Program Update 1998

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. These contributions include:

• Completing demonstration and proving

commercial viability of a suite of cost-effective

SO2

 and NOx control options capable of

achieving moderate (50 percent) to deep

emission reduction (70–95 percent) for the full

range of coal-fired boiler types;

• Providing the data base and operating experience requisite to making atmospheric fluidizedbed combustion a commercial technology at

utility scale;

• Completing demonstration of a number of coal

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

of coal types;

• Laying the foundation for the next generation of

technologies to meet the energy and environmental demands of the 21st century—three

IGCC plants in operation at three separate

utilities; and demonstration of pressurized

fluidized-bed combustion at 70 MWe successfully completed and two larger scale demonstrations in progress; and

• Demonstrating significant efficiency and

pollutant emission reduction enhancements in

steelmaking, advanced combustion for combined SO2

/NOx/PM control for industrial and

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 operational, economic,

and environmental performance results that are needed

to affect commercialization.

In FY1999, the Clean Coal Diesel Demonstration

Project is scheduled to begin operation and the following projects are forecasted to complete operations:

• Micronized Coal Reburning Demonstration for

NOx

 Control;

• Healy Clean Coal Project;

• Wabash River Coal Gasification Repowering

Project;

• Advanced Coal Conversion Process Demonstration; and

• Blast Furnace Granular-Coal Injection System

Demonstration.

The body of knowledge obtained as a result of the

CCT Program demonstrations is being used in immediate decisionmaking relative to regulatory compliance,

forging plans for meeting future energy and environmental demands, and developing the next generation of

technology responsive to ever increasing demands on

environmental performance at competitive costs. An

expanded portfolio of information will be forthcoming

to make it easier for stakeholders and customers to sift

through the already enormous amount of data resulting

from the demonstrations.

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

Toward that end, as needs change, forums will be

sought to obtain feedback particularly in view of utility

restructuring, continued environmental concerns, and a

burgeoning foreign market. Objectives are to ensure

that CCT Program efforts are fully leveraged and that

follow-on efforts under the Office of Coal and Power

Systems (OC&PS) RD&D Program are appropriate.

Three major drivers will affect implementation of

the CCT Program because of the impact on market

entry and deployment of the CCTs—environmental

concerns, utility restructuring, and burgeoning demands

for power in developing countries.

Environmental concerns. Perhaps the most

immediate environmental concern relates to relieving

seasonal ozone emissions in “ozone nonattainment

areas.” To do so, EPA issued an ozone transport rule

that requires major cuts in NOx emissions in 22 states

and the District of Columbia by 2003 (see page 1-6).

Technologies and the associated databases developed

under the CCT Program will play a role in responding

to this requirement.

Increasing concerns over airborne particulate

matter (PM) in the respirable range resulted in standards for particles 2.5 microns or less in size. Previous

standards addressed airborne particles in the inhalable

size range of 10 microns (about the size of bacteria) or

less. But it is the respirable particles, PM2.5, that can

lodge in the lungs. PM2.5 standards will not only

require high PM capture efficiency, but also may put

further pressure on SO2 emission reduction. Sulfur
Program Update 1998 2-13

compounds in the PM2.5 range can be precipitated by

SO2 in stack gases.

Reduction of CO2 in response to concerns over

global climate change has been a major driver for the

CCT Program. However, mandated CO2 reduction as

proposed in the Kyoto Protocol could impede coalbased power as an option for meeting new domestic

demands for increased electric power generation for

the foreseeable future. Provisions for trading CO2

emissions between the United States and developing

countries would mitigate pressure on domestic coalbased power. But such provisions were not a part of the

Kyoto Protocol and remain in negotiation. Trading

CO2 emissions between the United States and developing countries would also provide a needed incentive for

incremental investments for the more efficient CCTs in

developing countries. Continued pressure to reduce

CO2 emissions has resulted in a new surge of research

and development into CO2

 capture and sequestration.

Advanced electric power generation technologies such

as IGCC lend themselves to CO2

 capture. Therefore,

progress in CO2 capture and sequestration would serve

to enhance IGCC marketability.

Utility Restructuring. Restructuring of the retail

electric power generation portion of the utility sector

from a regulated industry to a market-based industry

has significant ramifications for CCTs domestically. It

places pressure on the new technologies to not only

have competitive costs but to have acceptable risk. No

longer will risk and cost be born by the ratepayer.

Under restructuring, the ratepayer becomes a conventional consumer looking for the best deal. Market

niches may be found domestically, e.g., where multiple

commodities are required and disadvantaged fuels can

be used (e.g., IGCC using petroleum coke or biomass

to produce electricity and fuels or chemicals). But the

primary market for CCTs at least through 2005 will be

developing countries, and more specifically, the Asian

market. It is in the foreign markets where CCTs will

realize significant commercialization and the associated reduction in cost and risk.

International Market. The market for CCTs in

other parts of the world has tremendous near-term

potential. For many countries, coal is the primary

indigenous fuel and jobs and mitigation of poverty

override the stigma attached to coal because of global

climate change concerns. The total world power

market between now and 2010 is estimated to be 950

GW. Of that total 50 percent resides in Asia, 30

percent in Europe, and 20 percent in the Americas.

Within Asia, China alone has 16 percent of the total

market, Japan/Indonesia/Korea have 17 percent and

India alone 6 percent. These numbers plus reliance on

coal in the Asian market make it the primary target for

CCTs.

Realizing market potential for CCTs requires

action to mitigate the higher risk and cost of CCTs.

Project developers can seek cost saving measures such

as use of disadvantaged fuels, production of multiple

commodities, and firm definition of projects to reduce

contingencies. Trading mechanisms for CO2

 such as

the 161-nation “Global Environmental Facility” and

others proposed hold promise for obtaining the

incremental cost decreases for CCTs, assuming CO2

reduction requirements or incentives are formalized.

Fluidized-bed combustion technology, the most

mature CCT power system technology, has made

inroads into foreign markets because of its tremendous

fuel flexibility and proven track record. IGCC is

realizing market penetration through use of disadvantaged fuels and production of multiple commodities.

There are some 20 known IGCC projects worldwide,

10 already in place and 10 more in the planning stage.
Program Update 1998 3-1

3. Funding and Costs

plan for the federal government to recoup up to the

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 coal resources.

The project participant has primary responsibility

for the project. The federal government monitors

project activities, provides technical advice, and

assesses progress by periodically reviewing project

Introduction

Congress has appropriated a federal budget of

$2.3 billion for the CCT Program. These funds have

been committed to demonstration projects selected

through five competitive solicitations. As of September 30, 1998, the program consisted of 40 active or

completed projects.

These 40 projects have resulted in a combined

commitment by the federal government and the

private sector of more than $5.6 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 $3.7 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

General Provisions

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

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 730,920 13 239,645 491,275 33 67

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 1,037,815 18 477,058 560,757 46 54

CCT-V 2,174,173 38 466,196 1,707,977 21 79

Totala 5,671,472 100 1,941,365 3,730,106 34 66

Application Category

Advanced Electric Power 3,159,911 56 1,224,078 1,935,832 39 61

Generation

Environmental Control Devices 704,862 12 295,191 409,670 42 58

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

Industrial Applications 1,287,503 23 192,072 1,095,431 15 85

Totala 5,671,472 100 1,941,365 3,730,106 34 66

a Totals may not add due to rounding.

b DOE share does not include $52,512,231 obligated for withdrawn, terminated, and concluded projects.
3-2 Program Update 1998

Availability of Funding

Although all funds necessary to implement the

entire CCT Program were appropriated by Congress

prior to FY1990, 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. 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 is described below.

• 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.

• 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

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 72,467 303,231

P.L. 100-202 CCT-II 473,997 6,781 32,512 434,704

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 2,306,595 31,081 177,527 2,097,987

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, 105-18, 105-83, and 105-277.

(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 CCT program direction budget provides for

the management and administrative costs of the

program and includes federal employees’ salaries,

benefits and travel, site support services, and services

provided by national laboratories and private firms.

performance with the participant. The federal government also 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. Additional activities funded by CCT Program appropriations

are the Small Business Innovation Research (SBIR)

Program, the Small Business Technology Transfer
Program Update 1998 3-3

Exhibit 3-3

Annual CCT Program Funding by Appropriations and Subprogram Budgets

(Dollars in Thousands)

Fiscal Year 1986–90 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000-02e Totald

Adjusted Appropriationsa

P.L. 99-190 397,600 (17,000) 380,600

P.L. 100-202 375,000 199,997 (101,000) (40,000) 40,000 473,997

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 1,191,600 390,995 415,000 0 225,000 37,121 150,000 (2,121) (101,000) (40,000) 40,000 2,306,595

Subprogram Budgets

CCT-I Projects 387,231 (18,000) (18,000) (33,000) (15,000) (14,900) 288,331

CCT-II Projects 338,207 197,497 (101,000) (40,000) 40,000 434,704

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 1,116,934 361,420 385,125 0 221,513 18,341 128,775 (18,121) (116,000) (54,900) 40,000 2,083,087

Program Direction 60,527 25,000 25,000 18,000 18,000 16,000 15,000 14,900 192,427

Fossil Energy Subtotal 1,177,461 386,420 410,125 0 221,513 36,341 146,775 (2,121) (101,000) (40,000) 40,000 2,275,514

SBIR & STTRc 14,139 4,575 4,875 0 3,487 779 3,225 31,081

DOE Totald 1,191,600 390,995 415,000 0 225,000 37,121 150,000 (2,121) (101,000) (40,000) 40,000 2,306,595

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, 105-18, 105-83, and 105-277.

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

d Totals may not appear to add due to rounding.

e P.L. 105-277 deferred the availability of $40 million in FY1999. Availability of the funds are to be restored in FY2000 through FY2002 in increments of $10, $15, and $15 million.
3-4 Program Update 1998

(200,000)

(100,000)

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

Dollars x 1,000

Budget Authority Costs Obligations

fiscal years 1998 and 1999 result from rescission of

$101 million in FY1998 and the deferral of $40

million in FY1999.

The financial status of the program through

September 30, 1998, 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 Law 105-277. These values represent

the amount of budget authority available for the CCT

Program.

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.

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

actual performance for FY1986 through FY1998 and

DOE estimates for FY1999 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 negative

Budget Authority values shown in Exhibit 3-4 for

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. 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;

Exhibit 3-4

CCT Financial Projections as of September 30, 1998

Fiscal Year
Program Update 1998 3-5

 Appropriations

 Allocated to Apportioned Committed Obligated Cost

Subprogram Subprogramb to Datec 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

1998 (101,000) 2,306,595

1999 (40,000) 2,266,595

2000 10,000 2,276,595

2001 15,000 2,291,595

2002 15,000 2,306,595

CCT-I 303,231 303,231 257,157 257,157 183,885

CCT-II 434,704 394,704 171,489 172,317 165,499

CCT-III 545,544 545,544 618,947 618,684 451,201

CCT-IV 394,935 394,935 477,889 477,889 457,621

CCT-V 419,573 419,573 468,396 148,331 10,169

Projects Subtotal 2,097,987 2,057,987 1,993,878 1,674,378 1,268,375

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

Program Direction 177,527 177,527 177,527 174,584 171,336

Total 2,306,595 2,266,595 2,202,486 1,880,043 1,470,792

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.

c Reflects $40 million deferral required by P.L. 105-277.

Exhibit 3-5

Financial Status of the CCT Program as of September 30, 1998

(Dollars in Thousands)

As previously discussed, Exhibit 3-1 summarizes

the cost-sharing status by subprogram and by application category for the 40 active or completed projects.

In the advanced electric power generation category,

which accounts for 56 percent of total project costs,

participants are contributing 61 percent of the funds.

Cost-sharing by participants for environmental control

devices, coal processing for clean fuels, and industrial

• 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; and

• Investment in existing facilities, equipment, or

previously expended R&D funds are not

allowed for the purpose of cost-sharing.

• 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;
3-6 Program Update 1998

Exhibit 3-6

CCT Project Schedules and Funding, by Application Category

Calendar 86 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2

Year 3412341234123412341234123412341234123412341234123412341234123412341234123412341

B&W--LIMB Environmental Control Devices

SCS--Wall-Fired

EER--GR/SI

SCS--Tangentially Fired

Bechtel -- CZD

B&W--Coal Reburning

B&W--LNCB

ABB ES--SNOX

B&W--SNRB

Pure Air on the Lake

LIFAC

PSC of Colorado

AirPol -- GSA

EER--GR-LNB

SCS--CT-121

SCS--SCR

NYSEG -- Milliken

NYSEG -- Micronized

NOXSO Corporation Schedule being revised

 - Preaward - Design and Construction - Operation and Reporting
Program Update 1998 3-7

Exhibit 3-6 (continued)

CCT Project Schedules and Funding, by Application Category

Calendar 86 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 20

Year 3412341234123412341234123412341234123412341234123412341234123412341234123412341 2

Tri-State--Nucla Advanced Electric Power Generation 

Ohio Power

Wabash River

Tampa Electric

Sierra Pacific

AIDEA

ADL--Coal Diesel

JEA

McIntosh 4A

Clean Energy

McIntosh 4B

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

Rosebud SynCoal

ENCOAL

Custom Coals Schedule being revised

Air Products -- LPMEOH

Coal Tech Industrial Applications 

Passamaquoddy

Bethlehem Steel

ThermoChem

CPICOR

 - Preaward - Design and Construction - Operation and Reporting
3-8 Program Update 1998

applications categories is 58 percent, 56 percent, and

85 percent, respectively. For the overall program,

participants are contributing 66 percent of the total

funding, or $1.79 billion more than the federal

government.

Recovery of Government

Outlays (Recoupment)

The policy objective of DOE 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

0.5 percent of equipment sales and 5 percent of

royalties. Limited grace periods were allowed on a

project-by-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 September 30, 1998, 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.).

In September 1997, the CCT Program office

issued a report entitled Recoupment Lessons LearnedClean Coal Technology Demonstration Program.

The report: (1) reviewed the lessons learned on

“recoupment” during the implementation of the CCT

Program; (2) addressed recommended actions set

forth in General Accounting Office (GAO) Report

RCED-92-17, GAO Report RCED-96-141, and

Inspector General Audit Report IG-0391 relative to

“recoupment;” and (3) provided input into DOE

deliberations on “recoupment” policy.
Program Update 1998 4-1

4. CCT Program Accomplishments

Introduction

The success of the CCT Program ultimately will

be measured by the contribution the technologies make

to the resolution of energy, economic, and environmental issues. These contributions can only be achieved if

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 requires a continuing dialogue with electric

utility executives, public utility commissioners, and

financial institutions. Also required are analyses of the

effect that regional electric capacity requirements,

environmental compliance strategies, and electric

utility restructuring have on the demand for clean coal

technologies. Internationally, activities include participating in international conferences and workshops,

furnishing information on clean coal technologies, and

providing technical support to trade agencies, trade

missions, and financial organizations.

The following projects completed operation during

fiscal year 1998:

• Demonstration of Advanced Combustion

Techniques for a Wall-Fired Boiler; and

 • Milliken Clean Coal Technology Demonstration Project.

Throughout the 1998 fiscal year, the CCT Program staff participated in over 15 domestic and international events involving users and vendors of clean

coal technologies, regulators, financiers, environmental groups, and other public and private institutions.

Included was the Sixth Annual Clean Coal Technology

Conference, held in Reno, Nevada and attended by

340 participants from 22 countries. Four issues of the

Clean Coal Today newsletter were published in the

same period, along with the third annual edition of the

Clean Coal Today Index, which cross-references all

articles published in the newsletter. Publication of the

second Clean Coal Technology Program Bibliography

of Publications, Papers, and Presentations highlighted

efforts to document the progress and results of the

demonstration projects. The DOE also continued

expanded coverage of the program by publishing the

Clean Coal Technology Demonstration Program:

Update 1996-97, and the mid-year update of project

factsheets, Clean Coal Technology Demonstration

Program: Project Fact Sheets 1997.

Marketplace Commitment

Reflecting CCT Program commercialization

goals, the majority of the projects involve demonstrations at commercial scale, providing the opportunity

for the participants to continue operation of the demonstrated technologies as part of their strategy to

comply with the CAAA.

With government serving as a risk-sharing partner,

industry funding has been leveraged to:

• Create jobs,

• Improve the environment,

• Reduce the cost of compliance with environmental regulations,

• Reduce the cost of electricity generation,

• Improve power generation efficiencies, and

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

Reflecting the marketplace commitment, the CCT

projects are organized within four major product

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 of the

Program Update highlights

some of the

program and

project accomplishments to date along

with commercialization successes by

market sector.
4-2 Program Update 1998

Environmental Control Devices

Control of SO2 and NOx emissions from existing

coal-fired boilers was the initial thrust of the program;

thus, 17 of the 19 environmental control device

projects have now completed operations. The completed demonstrations proved commercial viability of a

suite of cost-effective SO2

 and NOx control options for

the full range of coal-fired boiler types. Risk was

significantly mitigated in successfully applying the

technologies commercially because of 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 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

technology suppliers have realized commercial sales.

SO2

 Control Technologies. All five SO2 control

technology demonstrations have completed operations,

evaluating three basic approaches to address the diverse coal-fired boiler population:

• Two low-capital cost sorbent injection

systems, sponsored by LIFAC–North America

and Bechtel Corporation, demonstrated SO2

capture efficiencies in the range of 50 to 70

percent. These systems hold particular promise

for the older, smaller units, particularly those

with space constraints.

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

demonstrated SO2

 capture efficiencies in the

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

The AFGD demonstration by Southern Company

Services using Chiyoda CT-121 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, owns, and

operates scrubbers as a contracted service to a utility.

The arrangement relieves utilities of the burden of

ownership and operation and has proven to be an

attractive approach.

Commercialization successes to date for the SO2

control technologies are summarized in Exhibit 4-1.

NOx Control Technology. Six of the seven NOx

control technology demonstrations have successfully

completed operations. Testing was conducted on the

four major boiler types (wall-fired, tangentially-fired,

cyclone-fired, and cell-burner boilers), representing

over 90 percent of the coal-fired boiler population;

however, applicability extends to all boiler types.

Typically, NOx emission reductions achieved for

the various approaches were:

range of 60 to 90 percent. The system has

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

• Two advanced flue gas desulfurization

(AFGD) systems, sponsored by Pure Air on the

Lake, L.P. and Southern Company Services,

having somewhat higher capital costs than the

other approaches, demonstrated SO2

 capture

efficiencies in the range of 90 to 95 percent.

These systems are primarily applicable to the

larger, newer units that have space available.

The AFGD projects redefined the state-of-the

technology by proving that a single absorber module of

advanced design could process large volumes of flue

gas and provide the required availability and reliability. This single module design, without the usual spares,

combined with integration of functions within the

absorber module and use of high throughput designs,

significantly reduced capital cost and space requirements. The AFGD testing also established that wallboard-grade gypsum could be produced in lieu of solid

waste; wastewater discharge could be eliminated; and,

by mitigating corrosion, fiberglass-reinforced-plastic

SO2 control technologies: AirPol (left),

Pure Air (center), and LIFAC (right).
Program Update 1998 4-3

• Low NOx burners: 45 to 63 percent

• Reburning systems: 50 to 67 percent

• SNCR systems: 30 to 50 percent

• SCR systems: 80 to 90+ percent

• Advanced controls: 10 to 15 percent

The database developed during Southern Company

Services’ evaluation of NOx

 control on wall-fired and

tangentially-fired boilers at Plant Smith and Plant

Hammond, respectively, was used by the Environmental Protection Agency (EPA) in formulating NOx

provisions under the CAAA. 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.

The Babcock & Wilcox Company’s low NOx cell

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

 control system for cell-burner boilers, which are

known for their inherently high NOx emissions.

Integration of neural-network systems into digital

boiler controls, such as the Generic NOx Control

Intelligence System (GNOCIS) installed at Plant

Hammond, demonstrated effective optimization of

parameters for NOx

 control and boiler performance

under load-following operations.

The Babcock & Wilcox Company’s coal reburning

technology proved not only to be an effective way to

control NOx

 on cyclone boilers, but a means to avoid

derating cyclone boilers when switching to low-sulfur,

low-rank western coals. Energy and Environmental

Research Corporation’s use of gas reburning, applicable to all boiler types, introduced an alternative to SCR

for high NOx emission reduction particularly when used

with low NOx burners.

In another project, comparative analyses were

conducted on a range of SCR catalysts operated on

high-sulfur U.S. coals, providing needed insight on the

environmental and economic performance potential of

SCR. Other SCR systems and selective non-catalytic 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

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

Sale of technical assistance and proprietary equipment to Taiwan

– Value—$1 million

Advanced Flue Gas Desulfurization Technology retained for commercial use at host site; first scrubber to

Demonstration Project (Pure Air on the comply with CAAA installed; Wallboard manufacturer using all

Lake, L.P.) gypsum produced

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

of Technology for the CT-121 FGD Process Since the CCT Program demonstration, over 8,200 MWe equivalent of

(Southern Company Services, Inc.) CT-121 FGD capacity has been sold to 16 customers in seven countries

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 1998

reduction (SNCR) systems were demonstrated on

combined SO2/NOx control technologies.

Commercialization successes to date for the NOx

control technologies are summarized in Exhibit 4-2.

Combined SO2/NOx Control Technologies. Six

of the seven combined SO2/NOx control technology

demonstrations have successfully completed operations. The demonstrations tested 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. The process also

demonstrated excellent particulate control, while

producing a salable by-product in lieu of solid waste.

In a project sponsored by Public Service Company

of Colorado, complementary use of low NOx burners

with SNCR resulted in NOx

 emission reductions of

greater than 80 percent. 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.

New York State Electric and Gas (NYSEG)

evaluated an advanced flue gas desulfurization system,

the S-H-U scrubber process. The S-H-U process is an

advanced formic acid-enhanced wet limestone scrubbing process that removes 98 percent of the SO2

 in the

flue gas. In conjunction with the S-H-U- process,

NYSEG also evaluated micronized coal as a reburn

fuel using close coupled reburning techniques and deep

staging over ABB Combustion Engineering, Inc.’s low

NOx

 burners. DHR Technologies supplied a plant

optimization control system known as the Plant Emission Optimization Advisor or PEOATM, which has been

sold to a number of users in the power industry.

& Wilcox DRB-XCL® advanced low NOx

 burners

reduced NOx emissions by 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.

Furthermore, SO2 removal of over 55 percent was

achieved by using special sorbents.

NOXSO Corporation’s demonstration of a dry,

regenerable flue gas cleanup process is predicted to

remove 98 percent of the SO2 and 75 percent of the

NOx from a coal-fired boiler’s flue gas.

The Babcock & Wilcox Company’s SOx

-NOx-Rox

BoxTM, an integration of a newly developed hightemperature fabric-filter bag (for baghouse installation)

with SCR and sorbent injection, proved to be an easily

installed, highly efficient control system for SO2

, NOx,

and particulates. Typical performance was 80 percent

SO2 removal, 90 percent NOx removal, and 99.9

percent particulate removal.

Limestone injection multistage burner (LIMB) and

Coolside (duct injection of lime sorbents) demonstrations proved that sorbent injection methods could

achieve up to 70 percent SO2

 reduction. The Babcock

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

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 Foster Wheeler has equipped 86 boilers with low NOx

Company Services, Inc.) technology (51 domestic and 35 international)

– Quantity—1,800 burners for over 30,000 MWe capacity

19 GNOCIS neural-network control projects underway

Expect another 17 GNOCIS projects in 1999

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 ABB Combustion Engineering has modified 116 coal-fired

(Southern Company Services, Inc.) tangentially-fired boilers, representing over 25,000 MWe,

with LNCFSTM and TFS 2000TM
Program Update 1998 4-5

As the CCT Program unfolded, a number of

energy and environmental issues combined to change

the emphasis toward seeking highly-efficient, very lowemission power generation technologies for both

repowering and new power generation. This emphasis

was deemed requisite to coal fulfilling its projected

contribution to the nation’s energy mix well into the

21st century. Environmental issues included a growing

concern over greenhouse gas emissions. In addition,

SO2

 emissions had been capped under the CAAA; NOx

continued to receive increased attention in ozone

nonattainment areas; and fine particulate emissions

(respirable dust) were identified as a particular health

threat. These issues prompted follow-on projects in

PFBC, initiation of projects in integrated gasification

combined cycle (IGCC), and projects in advanced

combustion and heat engines.

Fluidized-Bed Combustion. The Tri-State

Generation and Transmission Association, Inc. Nucla

Station repowering project provided the database and

operating experience requisite to making ACFB a

commercial technology option at utility scale. At 110

Commercialization successes to date for the

combined SO2 and NOx control technologies are

summarized in Exhibit 4-3.

Advanced Electric Power Generation

Pollution control was the early priority in the CCT

Program. But, technologies also were sought that

could effectively repower aging plants faced with the

need to install pollution controls and respond to growing power demands. Contributing to this search was the

recognition that existing power generation sites had

significant value and warranted investment, given the

permitting problems associated with siting new plants.

This recognition led to award early on of three key

repowering projects—two atmospheric fluidized-bed

combustion (ACFB) projects and a pressurized fluidized-bed combustion (PFBC) project.

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 gas reburning for

Environmental Research Corporation) commercial use

Milliken Clean Coal Technology Demonstration Four sales of DHR Technologies’ Plant Emission Optimization

Project (New York State Electric & Gas Advisor

Corporation) More than 20 NOx

 OUT® or NOx OUT® derivative units sold in

U.S, Taiwan, and Korea

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

Actively pursuing AFGD bid for Pennsylvania site (will include

S-H-U process, Stebbins absorber module, and heat-pipe

air preheater)

Integrated Dry NOx

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

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

 burners (which

are components of the technology demonstrated)

– Quantity—2,428 burners for 31,467 MWe capacity

– Value—$320 million
4-6 Program Update 1998

MWe, the Nucla ACFB unit was more than 40 percent

larger than any other ACFB at that time. Up to 95

percent SO2

 removal was achieved during the 15,700

hours of demonstration and NOx

 emissions averaged a

very low 0.18 lb/106 Btu. The thrust of this effort was

to fully evaluate the environmental, operational, and

economic performance of ACFB. As a result, the most

comprehensive database on ACFB technology available to date was developed. From this knowledge,

commercial units were offered and built.

While the Nucla project established commercial

acceptance of ACFB at moderate utility capacities, a

second CCT demonstration project, located in Jacksonville, Florida, is carrying on where Nucla left off. JEA

will build a 300 MWe plant, which will have the

distinction of being the largest ACFB in the world, as

well as one of the cleanest.

Today, every major U.S. boiler manufacturer

offers an ACFB in its product line. There are now

more than 170 fluidized-bed combustion boilers of

varying capacities operating in the U.S. and the technology has made significant market penetration abroad.

Through the Ohio Power Company’s 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 was 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 (calcium-to-sulfur molar ratio of 1.5) and

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

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

Others were built and operated in Sweden, Spain, and

Japan. ABB Carbon, the technology supplier, uses a

“bubbling” fluidized-bed design, which is characterized by low fluidization velocities and use of an in-bed

heat exchanger. The first 360-MWe P800 PFBC is

being built in Japan and is scheduled for operation in

1999. And, a “second generation” P200 PFBC, with

freeboard-firing is under construction in Cottbus,

Germany. A number of other ABB Carbon PFBC

projects are under consideration in China, South

Korea, the United Kingdom, Italy and Israel.

Two ongoing interrelated projects, McIntosh 4A

and McIntosh 4B, will demonstrate pressurized circulating fluidized-bed technology (PCFB) at utility scale.

PCFB uses a higher fluidization velocity than bubbling-bed systems, which entrains the bed material.

Bed material is separated from the flue gas by cyclones

and recirculated to the combustor. The economizer,

which captures heat from the flue gas, is downstream of

the cyclones. McIntosh 4A will evaluate a 145-MWe

first generation PCFB configuration using Foster

Wheeler technology. McIntosh 4B will demonstrate a

second generation system by integrating a small coal

gasifier (pyrolyzer) to fuel the gas turbine “topping

cycle” (adding 93 MWe capacity). The second generation PCFB has the potential to significantly improve

the efficiency of pressurized fluidized-bed systems by

increasing power generation from the gas turbine,

which is more efficient than the steam bottom cycle.

Integrated Gasification Combined Cycle. Three

of four IGCC projects are in various stages of operation under the CCT Program. They represent a diversity of gasifier types, cleanup systems, and applications.

PSI Energy’s 262-MWe Wabash River Coal Gasification Repowering Project began operation in November

1995 and continues in its third year of commercial

service. The utility dispatches the unit over other coalfired units because of its high efficiency. The unit,

which is the world’s largest single train IGCC, has

produced approximately 1.6 million megawatt hours of

electricity on syngas through early 1998 and in March

1998 alone generated a record one trillion Btus of

syngas.

The 250-MWe Tampa Electric Integrated Gasification Combined-Cycle Project began commercial

operation in September 1996 and continues to accumulate run time. Availability steadily increased over time,

reaching 70 percent for the past 12 months. The

gasifier has accumulated over 10,000 hours of operaThree IGCC plants are in various stages of operation:

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

River (lower right).
Program Update 1998 4-7

sorbent recycle. Operations commenced in January

1998. Preliminary results have showed very low

emissions—0.25 lb/106

 Btu for NOx and

0.08 lb/106

 Btu for SO2. Permit levels are

0.35 lb/106 Btu for NOx and 0.10 lb/106 Btu for SO2

because of the plant’s proximity to a national park.

NSPS allows 1.2 lb/106

 Btu for SO2.

The Clean Coal Diesel Demonstration Project is

based on the demonstration of a heavy duty diesel

engine to operate on a low-rank coal-water fuel. The

demonstration plant is expected to achieve 41 percent

efficiency and future commercial designs are expected

to reach 48 percent efficiency. Operation is expected

to begin in 1999.

Commercialization successes for the advanced

electric power generation systems to date are summarized in Exhibit 4-4.

Coal Processing for Clean Fuels

Physical and chemical processes can be used on

the abundant U.S. coal reserves to transform raw coal

to an economic, environmental compliant fuel for at

least a portion of the existing coal-fired boilers. The

solid products from coal processing are easily transportable fuels; high in energy density; and low in

sulfur, ash, and moisture. In addition, coal processing

creates the capability to generate liquid fuels from coal

that can replace petroleum and petroleum-based fuels

in a wide range of applications, thereby enhancing the

nation’s energy security. The liquid products are

suitable as transportation and stationary power generation fuels, or as chemical feedstocks. Both solid and

liquid products, and the processes that produce them,

have substantial market potential both domestically and

internationally.

The ENCOAL and Rosebud SynCoal Partnership

projects are breaking down the barrier to using the

nation’s vast low-sulfur, but low-energy-density

western coal resources. The resultant fuels have

particular application domestically for CAAA compliance and internationally for Pacific Rim energy markets.

ENCOAL’s solid fuel product has an energy

density of about 11,000 Btu per pound and the sulfur

content averages 0.36 percent. ENCOAL’s liquid fuel

product can substitute for No. 6 fuel oil or serve as a

chemical feedstock. During the demonstration, over

83,500 tons of solid fuel was shipped to seven customers in six states, as well as 203 tank cars of liquid

product to eight customers in seven states. Five commercial feasibility studies have been completed — two

for Indonesia, one for Russia, and two for U.S.

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

The Rosebud SynCoal® project is demonstrating

another route to producing high-quality fuel from lowrank coals. The advanced coal conversion process

(ACCP) upgrades low-rank coal to produce a lowtion and produced over 2,000,000 MWh of electricity

on syngas. Tests have included evaluation of various

coal types on system performance.

The Sierra Pacific Power Company (SPPC)

readies for sustained operation of its IGCC system on

syngas. The 99-MWe Piñon Pine IGCC Project at

SPPC’s Tracy Station began operation on natural gas

in November 1996. The GE Frame 6FA, the first of its

kind in the world, performed well. The plant has

undergone shakedown and design modifications have

been made. The system routinely achieved steady state

gasifier operation for short periods through September

1998.

The Clean Energy Demonstration Project, which is

in the design stage, will offer yet another gasifier

design and include the testing of a fuel cell operated on

syngas from the coal gasifier. This will provide valuable data for design of an integrated gasification fuel

cell (IGFC) system. IGFC has the potential to achieve

efficiencies greater than 60 percent.

Commercial configurations resulting from the

current IGCC and PFBC demonstrations will typically:

have efficiencies at least 20 percent greater than

conventional coal-fired systems (with like CO2

 emission reductions), remove 95 to 99 percent of the SO2

,

reduce NOx emissions to levels equivalent to a 90

percent reduction, reduce particulate emissions by 1/3

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

produce salable by-products from solid residues as

opposed to waste.

Advanced Combustion/Heat Engines. Two

projects are demonstrating advanced combustion/heat

engine technology.

The Healy Clean Coal Project is demonstrating

TRW’s entrained (slagging) combustor combined with

Babcock & Wilcox’s spray-dryer absorber using

Pielstick diesel engine block being cleaned prior to

assembly in Beliot, Wisconsin.
4-8 Program Update 1998

sulfur (as low as 0.3 percent sulfur) SynCoal® product

having a heating value of about 12,000 Btu per pound.

By the end of September 1998, more than 1.4 million

tons of SynCoal® had been produced. Nearly 1.3

million tons has been supplied to industrial applications and utilities. The Rosebud SynCoal® Partnership

has signed a letter of agreement to supply fuel to

Montana Power’s 330-MWe Colstrip Unit No. 2.

Advanced physical coal-cleaning technology

developed by Custom Coals International uses highsulfur bituminous feedstocks to produce two types of

compliance coal—Carefree CoalTM and Self-Scrubbing

CoalTM.

Air Products Liquid Phase Conversion Company,

L.P., is demonstrating the LPMEOHTM process to

produce methanol from coal-derived synthesis gas.

The LPMEOHTM process has been developed to enhance integrated gasification combined-cycle power

generation facilities by coproducing a clean-burning

storable liquid fuel from coal-derived synthesis gas.

The production of dimethyl ether (DME) as a mixed

coproduct with methanol will also be demonstrated.

Methanol and DME may be used as a low-SO2, lowNOx

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

The first stable operation of the LPMEOHTM unit

at nameplate capacity of 80,000 gallons per day was

achieved in April 1997, only four days after start-up.

A test period at methanol production rates over 92,000

gallons per day has demonstrated the potential for this

new technology.

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

The first 360-MWe ABB Carbon P800 PFBC plant is being built in Japan

A second generation ABB Carbon P200 PFBC is under construction in

Germany

Other ABB Carbon PFBC projects are under consideration in China,

South Korea, the United Kingdom, Italy, and Israel

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

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

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

– Quantity—29 CFB units larger than 100 MWe planned, in

 construction, or in operation worldwide

– Estimated capacity—greater than 6,200 MWe

– Estimated value—almost $6 billion

Tampa Electric Integrated First greenfield IGCC unit in commercial service

Gasification Combined-Cycle Texaco, Inc., and ASEA Brown Boveri signed an agreement forming an

Project (Tampa Electric Company) 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 Unit in initial operation preparatory to commercial service

(Sierra Pacific Power Company)

Healy Clean Coal Project (Alaska TRW offering licensing of combustor worldwide (China agreement in place)

Industrial Development and

Export Authority)

Coal processing technologies remove barriers to the use

of low-energy-density western coal resources: Rosebud

(top) and ENCOAL (bottom).
Program Update 1998 4-9

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 two U.S. users

30 U.S. and 1 U.K. utilities acquired CQETM through EPRI membership

Other foreign and domestic utilities pursuing access to CQETM

CQE technology saves U.S. utilities $26 million

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 three 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 1,400,000 tons

Demonstration (Rosebud SynCoal A commercial project being developed

Partnership) – Stand-alone minemouth design in Wyoming

ENCOAL® Mild Gasification Project Over 83,500 tons of solid fuel delivered to seven major utilities and

(ENCOAL Corporation) metallurgical customers

Over 200 tank cars of liquid fuel delivered to eight industrial users

Permitting of a 15,000 metric-ton/day commercial plant in Wyoming is

nearly complete

– Value—$460 million

Completed five feasibility studies—two Indonesian, one Russian, and two

U.S. projects

Commercial-Scale Demonstration of the Nominal 80,000 gallon/day methanol production being

Liquid Phase Methanol (LPMEOHTM) used by Eastman Chemical Company

Process (Air Products Liquid Phase

Conversion Company , L.P.)

Since start-up, the LPMEOHTM demonstration unit

has produced over 25 million gallons of methanol, all

of which was accepted by Eastman for use in downstream chemical processing. Since restart of the unit

with fresh catalyst in December 1997, availability of

the unit has been greater than 99 percent and catalyst

activity decline has been less than 0.4 percent.

ABB Combustion Engineering, Inc., and CQ Inc.

developed PC-based software, CQETM, to assist utilities in assessing the environmental and operational

performance of their systems for the available range of

coal fuels to determine the least-cost option. The

CQETM software has been distributed to over 30 utility

members of EPRI and is being marketed commercially

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

to use copies of the CQETM stand-alone Acid Rain

Advisor.

Commercialization successes for the coal processing technologies to date are summarized in Exhibit 4-5.

The LPMEOHTM demonstration unit at Eastman’s vast

chemicals-from-coal complex in Kingsport, TN.
4-10 Program Update 1998

Industrial Applications

The CCT Program is addressing the environmental

issues and barriers associated with coal use in industrial applications. Historically, production of steel has

been dependent upon coke. Coke making, however, is

an inherently large producer of SO2, NOx, and hazardous air pollutants. Also, cement production often relies

on coal fuel because production costs are largely

driven by fuel costs. Because of its low stable price,

coal is an 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 are

effectively controlled in the process.

CPICORTM is in the design stage of demonstrating

a direct iron ore reduction and smelting of iron oxides

using coal in lieu of coke. This would eliminate the

need for coke.

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 with no

waste 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 to 80 percent reduction) through

staged combustion, and controls SO2 (90 percent) with

sorbent injection.

ThermoChem, Inc. has completed restructuring of

its project and will be demonstrating a multiple resonance tube pulse combustor design.

Commercialization successes for the industrial

applications technologies to date are summarized in

Exhibit 4-6.

Market Communications–

Outreach

Outreach has been a hallmark of the CCT Program

since its inception. It was recognized early on that

commercialization of technology requires acceptance

by a range of interests including: technology users;

equipment manufactures; suppliers and users of raw

materials and products; financial institutions and

insurance underwriters; government policy makers,

legislators, and regulators; and public interest groups.

Requisite to acceptance is an outreach program to

provide these customers and stakeholders with both

program and project information and to seek, on a

continuing basis, feedback on program direction and

information requirements. An ongoing outreach

program has aggressively sought to disseminate key

information to the full range of customers and stakeholders and to obtain feedback on changing needs. The

effort has recognized the need to highlight environmental, operational, and economic performance characteristics of clean coal technologies and to redesign information packages as customers and stakeholders, and their

respective needs, change with the market. Specific

objectives of the outreach program include the following:

• Achieving public and government awareness of

advanced coal-using technologies as viable

energy options;

• Providing potential technology users, both

foreign and domestic, with information that is

timely and relevant to their decision making

process;

• Providing policy makers, legislators, and

regulators with information about the advantages of clean coal technologies;

• Increasing the confidence of financial institutions and insurance underwriters that clean coal

technologies are viable options; and

Exhibit 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
Program Update 1998 4-11

• Providing forums and opportunities for

feedback on program direction and information

requirements.

Information Sources

A portfolio of publications and information access

media exist and are being improved upon as program

and marketplace events unfold. Information is currently distributed to over 4,000 customers and stakeholders, 275 of which are CCT project participants. The

following provides a brief synopsis of the publications

and information transfer mechanisms currently in place

or soon to be introduced:

Clean Coal Technology Demonstration Program:

Annual Program Update provides an annual summary

of program and project progress, accomplishments, and

financial status along with an historical backdrop and

program role relative to current policy.

Annual Clean Coal Technology Conference

Proceedings serves as an annual update on issues

impacting the program, feedback on program direction,

and a yearly snapshot of how each of the active

projects is progressing with some degree of technical

depth.

Clean Coal Technology Demonstration Program:

Project Fact Sheets provides a mid-year update on

each project.

Clean Coal Today Newsletter offers the readership

a quarterly look at the program, highlighting key

events, updating project status, and listing the latest

publications and upcoming events.

Topical Reports capture projects at critical junctures and highlight particular technological advantages,

project plans, and expected outcomes.

National Technical Information Service (NTIS)

serves as the Federal government’s central source for

the sale of scientific, technical, engineering, and related

business information produced by or for the U.S.

government. NTIS has most of CCT Program technical reports.

CCT Program Bibliography of Publications,

Papers, and Presentations periodically updates the key

materials available on the technologies demonstrated

under the CCT Program.

The Investment Pays Off periodically takes a

market-based view of the success of the CCT Program

by virtue of commercial sales and relevance of ongoing

activities to projected market need.

CCT Program - Lessons Learned documents the

lessons learned in soliciting, selecting, and awarding

projects and implementing the program.

CCT Compendium provides an electronic database

incorporating the CCT Program publications that can

be accessed on the Internet (http://www.lanl.gov/

projects/cctc/).

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

program messages at a variety of forums and serve as

focal points for distribution of literature and discussion

of the program and information needs. (There are

currently four exhibits of varying sizes and complexity

that are updated and modified, as necessary, to convey

the appropriate message for specific forums.)

Fossil Energy Techline offers fax-on-demand for

news announcements and status reports on projects

(202-586-6503).

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-24, 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

or 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.

CCT Compendium On the Internet, access http://www.lanl.gov/projects/cctc/.

CCT Program Update and Send name and address to U.S. Department of Energy, FE-20,

other publications Washington, DC 20585.

National Technical Information U.S. Department of Commerce, 5285 Port Royal Road,

Service (NTIS) Springfield, VA 22161 (703-487-4600).
4-12 Program Update 1998

Computer Bulletin Board offers a modem

accessed bulletin board of noteworthy items on

the CCT Program (202-586-6495).

Fossil Energy Home Page provides the

primary Internet gateway to extensive information on DOE’s Fossil Energy Program and to

relevant World Wide Web links (http://

www.fe.doe.gov).

Exhibit 4-7 summarizes how the above

publications can be obtained and information

sources can be accessed.

Publications Issued in FY1998

The following publications were issued in

Fiscal Year 1998 by the CCT Program. Similar publications can be expected in Fiscal Year 1999.

CCT Program Bibliography of Publications,

Papers, and Presentations

Sixth Annual Clean Coal Technology Conference:

What Will It Take?; Technical Papers

Sixth Annual Clean Coal Technology Conference:

What Will It Take?; Proceedings

Clean Coal Technology Demonstration Program:

Program Update 1996-97

Clean Coal Technology Demonstration Program:

Project Fact Sheets 1997

Clean Coal Today: Winter 1997, Spring 1998,

Summer 1998, Fall 1998

Clean Coal Today Index

Information Access Updates for FY1998

The Department of Energy continued to expand its

website, accessible through the Internet that 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 DOE website, users can obtain general information

and follow links to increasingly detailed information,

ultimately accessing specific data on individual

projects and facilities. Hyperlinks 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 websites

operated by private companies, trade associations, and

other agencies worldwide.

Furthermore, the Fossil Energy International

Activities site on the World Wide Web has been

expanded with the addition of new country pages in the

Western Hemisphere region (Guatemala, Honduras,

Nicaragua, Paraguay, Trinidad & Tobago, and Uruguay) and the Russia/NIS region (Armenia, Georgia,

and Moldova). Many of the existing country pages

have also been upgraded, with new hyperlinks to

business- or energy-related information sources. An

innovation at the Fossil Energy International Activities

web site is a series of newly created Country Energy

Overviews. Each overview, individualized for a

particular country, includes a status summary of that

country’s energy infrastructure, energy and environmental policies, and privatization efforts. Seven

country pages in the Eastern Europe region now

include these overviews; Western Hemisphere country

pages will be next to receive these upgrades. The

Uniform Resource Locator (URL) for the Fossil

Energy International main page is http://

www.fe.doe.gov/international and can be accessed via

the “International” hyperlink in the Fossil Energy

Home Page (http://www.fe.doe.gov).

In February 1998, DOE established a new information resource on the Internet. The Clean Coal

Technology Compendium, sponsored by the Office of

Fossil Energy and the Federal Energy Technology

One of four clean coal technology exhibits, shown here, was

used at the Sixth Annual CCT conference to convey a technical

message.

The CCT Program reports progress and

accomplishments through several publications distributed to

almost 4,000 customers and stakeholders.
Program Update 1998 4-13

Center (FETC), is dedicated to making the maximum

use of information derived from the CCT Program.

The compendium designers anticipate that the compendium will become the principal source of information

for stakeholders interested in implementation of clean

coal technologies. The compendium is designed to

emphasize ease of use, and contains a broad collection

of different types of data and information, making it

applicable to the needs of both managers and engineers. For example, by selecting the CCT Program

menu option, one can access the latest CCT Demonstration Program Annual Program Update, and Topical

Reports published periodically on individual CCT

projects. The Compendium is accessible via the

Internet at http://www.lanl.gov/projects/cctc/.

Information Dissemination and Feedback

A number of mechanisms are used to disseminate

program information to customers and stakeholders

and obtain feedback from them on specific issues,

program direction, and information requirements. The

following provides a brief outline of the mechanisms.

Public Meetings were routinely held over the

course of the acquisition phase of the CCT Program to

solicit input on procurement actions. Subsequently,

project participants have been holding open houses for

the public, providing tours of demonstration facilities,

and publicizing projects through groundbreaking and

dedication ceremonies.

Executive Seminars involve program officials

meeting with key industry officials at their places of

business to facilitate discussion. Discussions seek to:

obtain a better understanding of the dynamics of the

decision making process for adopting new power

generating technologies, determine how the program

could best support the process and achieve a positive

outcome, and gain insights on the future direction of the

power industry. Over 50 meetings have been held since

1992 with influential leaders in the utility, independent

power, regulatory, and financial communities.

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

programs, where appropriate, and discussing pertinent

issues and implementation strategies to address the

issues, and outreach needs. Such stakeholder organizations include the Electric Power Research Institute

(EPRI), Gas Research Institute (GRI), Coal Utilization

Research Council, Center for Energy & Economic

Development (CEED), Council of Industrial Boiler

Owners (CIBO), Clean Coal Technology Coalition, and

National Mining Association (NMA).

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

document discussions and findings, and provide recommendations, as appropriate. Trade Missions are a

subset of these and differ only in that the thrust is

international in character with the purpose of promoting

the export of U.S. services and technology. The

outreach program has participated in over 200 technical conferences, workshops, and trade missions since

1991.

Sixth Annual Clean Coal Technology

Conference: What Will It Take?

Some 340 attendees from 22 countries participated

in the Sixth Annual Clean Coal Technology Conference held in Reno, Nevada from April 28 to May 1,

1998. Cosponsors included the CEED, NMA, EPRI,

CIBO, and DOE. Sierra Pacific Power Company

hosted the conference and a site visit to its Tracy

Station which employs IGCC technology.

The Conference provided an annual update on the

CCT Program, the issues driving technology decisions,

and suggested courses of action to affect technology

deployment.

The Department of Energy Assistant Secretary for

Fossil Energy set the stage for the Conference by

recognizing CCT Program accomplishments and

challenging participants to define what it will take to

finish the job—deploy CCTs on a large scale into U.S.

and global energy markets. Participants were encouraged to find ways: to leverage the investment in CCTs

and the attendant databases; to work with international

organizations toward increased use of CCTs in nearterm overseas markets; and to develop innovative

incentives and financial mechanisms for CCTs, aside

from subsidies.

The Assistant Secretary also outlined DOE’s

efforts to build on the CCT experience toward achieving “Vision 21,” where power-plexes would squeeze

every available Btu out of coal, and produce multiple

products in lieu of pollutant emissions and waste. But

it was recognized that Vision 21 efficiency improveThe CCT Program exhibit serves as a focal point for

distribution of literature and discussion of the program.
4-14 Program Update 1998

ments alone may not be enough, which has prompted

exploration of CO2 sequestration options.

Domestic Market. Panel discussions identified

two basic issues that currently drive technology decisions in the domestic market—environmental concerns

and utility restructuring. Discussion of environmental

concerns focused on the most significant challenges.

Utility restructuring discussions addressed potential

implications for power generators. The following

highlights some of the findings.

Environmental Concerns. The CCT Program has

provided a portfolio of technologies to effectively deal

with acid rain concerns. Challenges remain, however,

in achieving ozone standards (a NOx

 control issue),

fine particulate control (PM2.5), and CO2 emission

reduction.

Ozone nonattainment prompted the EPA to issue

a NOx transport SIP Call for 22 states to meet the

following:

Date NOx Emissions

May 1999 0.2 lb/106 Btu

2003 1.5 lb/106 Btu

2007 Cap emissions

Utilities have expressed concern that the proposed

compliance schedule does not allow sufficient time to

develop a cost effective response. Selective Catalytic

Reduction represents the only option currently available, and little experience exists with U.S. high-sulfur

coals. Capping NOx emissions in 2007 may push

technology beyond the capability of SCR.

Evaluation of PM2.5 fine particulate emissions may

lead to a requirement for additional SO2 reductions

associated with sulfate formation from stack gases.

However, even complete particulate emission control

cannot prevent compounds precipitated from post-stack

chemical reactions.

CO2

 reduction per the Kyoto Protocol may spell

disaster for coal-based power generation in the absence

of trading between developed and developing countries

under a proposed Clean Development Mechanism

(CDM) and/or sequestration.

Utility Restructuring. Utility restructuring is

moving rapidly forward with some 40 percent of the

states sponsoring conceptually and functionally different legislation. Some argue that federal legislation is

needed to provide some consistency in what they

consider will be a “crazy quilt” of implementing

mechanisms. State legislation is driven by different

rate structures, fuel mixes, stranded cost implications,

and environmental policies. Federal legislation is being

deliberated.

The electric power industry embraces the concept

of open competition, but some speakers expressed

concern that legislation is skewing the market away

from market-based outcomes by establishing “Renewable Portfolio Standards,” which would require sellers

to include an increasing proportion of above-market

cost renewable generation in their annual sales over

time.

Competition will spur generators to increase

capacity factors on existing plants to meet increased

demand and also upgrade existing plants where there is

significant potential to increase both efficiency and

capacity. Existing coal-fired plant upgrades might lead

to efficiency improvements of 2 to 4 percent and

capacity increases of 10 to 13 percent.

Restructuring has the potential to remove barriers

to distributed power systems. Distributed power can

produce significant efficiency improvements relative to

central power generation because there are no line

losses and heat, steam, and other byproducts can be

readily utilized.

Competition will drive a paradigm shift for power

generators to a commodity viewpoint with the commodities being electricity, heat, steam, and chemical

byproducts. Providing a multiplicity of commodities

enhances market potential and reduces risk.

In a market-based utility industry, coal-based

technologies must meet the challenge of $800/kW

capital cost (at acceptable risk) while complying with

all environmental standards and without guarantee of

cost recovery. The Coal Utilization Research Council

shows 30-year levelized cost of electricity for advanced

coal-based systems (7,000 Btu/kWh heat rate) to be

competitive with natural gas-fired systems by 2020 at

$800/kW, and year 2000 coal and gas prices of $1.30/

106

 Btu and $2.25/106 Btu respectively. To achieve

$800/kW, more CCTs must be installed and designs

refined to mitigate risk and cost. The importance is

underscored by the fact that financing will be more

difficult in a deregulated environment, where customers are no longer required to cover capital investments

in the rate base.

Employing IGCC to co-produce power and syngas-derived products may provide an avenue for this

technology to enter the marketplace. The key initially

is to find low-cost disadvantaged fuels such as heavy

petroleum liquids or petroleum coke. For some applications, syngas conversion alone may be the best

option. These applications will serve to reduce the risk

and cost of IGCC technology. There is some movement domestically toward installing gasification-based

systems for co-production.

International Market. An International Business

Forum was held at the conference to identify emerging

opportunities for CCTs worldwide. The following

presents some of the key points made during the forum.
Program Update 1998 4-15

Market Definition. While the near-term domestic

market for CCTs is not promising, the international

market for CCTs has tremendous near-term potential.

Basic elements exist in many developing countries for

CCTs to play a major role in meeting energy demands.

For many, coal is the primary indigenous fuel, and the

need for jobs and mitigation of poverty may reduce the

stigma global climate change associates with coal.

The total world power market between now and

2010 is estimated to be 950 GW. Of that total 50

percent resides in Asia, 30 percent in Europe, and 20

percent in the Americas. Within Asia, China alone has

16 percent of the total market, Japan/Indonesia/Korea

have 17 percent, and India alone has 6 percent. These

numbers, plus reliance on coal in the Asian market,

make it the primary target for CCTs.

Realizing Market Potential. Realizing market

potential for CCTs requires action to mitigate the

higher risk and cost of CCTs. Environmentally superior performance of CCTs serves as an incentive, but

costs must be competitive with other options. Cost

saving measures can be taken, such as using disadvantaged fuels, producing multiple commodities, and

firmly defining projects to reduce contingencies.

Trading mechanisms for CO2

, such as the 161-nation

“Global Environmental Facility” and others proposed

under the Kyoto Protocol, hold promise for obtaining

incremental cost decreases for CCTs, assuming CO2

reduction requirements or incentives are formalized.

Fluidized-bed combustion technology, the most

mature CCT power system technology, has made

inroads into foreign markets because of its tremendous

fuel flexibility and proven track record. This demonstrates the possibilities for the more advanced systems.

IGCC is already making progress through use of

disadvantaged fuels and production of multiple commodities. There are some 20 known IGCC projects

worldwide, 10 already in place, and 10 more in the

planning stage.

Conferences and Workshops Held in FY1998

Fifth Annual Technical Seminar of AsiaPacific Economic Cooperation (APEC) Expert’s

Group on Clean Fossil Energy. The Office of Fossil

Energy participated in the APEC technical seminar.

This seminar, held in Reno, Nevada, in October 1997,

brought together senior energy policy officials from

around the globe. It followed a series of four previous

meetings of the Expert’s Group held in Thailand,

Indonesia, South Korea, and the People’s Republic of

China.

Historically, APEC nations have been able to gain

insight into the plans and actions of all member countries while at the same time being afforded an opportunity to participate in the formulation of policies, procedures, trade regulations, and other issues that impact

individual economies. Of interest to members are

environmental and economic factors and functions. In

particular, APEC has provided a forum for encouraging

coal use in the Pacific Rim, and has expended a great

deal of effort to make coal a high-profile fuel. Australia and the United States share the lead responsibility

for the energy and environment activity, which emphasizes coal and clean coal technology. The goal of this

activity is to assist APEC members in reducing their

dependency on imported oil by using more coal,

increasing efficiency of energy use in the region, and

promoting U.S. energy exports.

Executive Committee Meeting of the IEA Clean

Coal Center. In October 1997, representatives from

the Office of Fossil Energy participated in the Executive Committee meeting of the International Energy

Agency’s (IEA) Clean Coal Center, the International

Energy Agency’s coal research activity. The Committee agreed to initiate studies in the following areas:

blast furnace coal injection; management of coal

stockpiles; opportunities for coal preparation to lower

emissions; particulate emissions from coal combustion

(PM10, PM2.5); computers and air pollution control; a

NOx control systems database; coal-fired power stations and water quality; and coal-fired power generation and air pollution control in South Asia.

International Symposium on Clean Coal Technology. A team from the Office of Fossil Energy

participated in the symposium, co-sponsored by DOE,

China’s Ministry of Coal Industry (MOCI), and the

European Commission Directorate of Energy. The

conference took place in Xiamen, Fuijan, China, on

November 17-21, 1997. In parallel with the conference was a workshop sponsored by the Fuijan Coal

An interactive exhibit at the Sixth Annual Clean Coal

Technology Conference.
4-16 Program Update 1998

Industry Administration of MOCI, a group heavily

involved in a variety of coal-related projects. The

workshop was targeted toward specific clean coal

projects and opportunities in Fuijan.

Ukraine/U.S. Joint Conference on Ukraine

Clean Coal Power Plant Upgrade Opportunities.

On April 21-22 , 1998, some 160 attendees (30 from

the U.S.) participated in the conference held in Kiev.

The conference was co-sponsored by U.S. DOE, U.S.

Agency for International Development, and the Ukrainian Ministry of Energy and Electrification. The

conference was held to report on the recently finished

study on upgrading the anthracite-fired Lugansk Power

Station in eastern Ukraine with the goal of obtaining

World Bank financing, and to provide a forum for

exchange of information among Ukrainian government

and power sector officials and western companies

interested in rebuilding that country’s aging coal-fired

power sector.

Advanced Coal-Based Power and Environmental Systems ‘98 Conference. The Department of

Energy hosted the July 21-23, 1998, conference in

Morgantown, West Virginia. About 300 persons

attended the conference representing every region of

the United States and several other countries.

The conference provided a forum for industry

representatives, government regulators, scientists,

engineers, and other interested parties to: (1) share the

results of FE-sponsored research and development

projects related to advanced power generation and

environmental systems; (2) learn about cooperative

industrial-government research and development

opportunities (CRADAs) with FETC; and (3) discuss

the direction of future research and development for a

competitive energy market in the coming millennium.

Industrial and academic researchers and developers, along with FETC scientists and engineers, presented research results at sessions for Advanced Power

Systems; IGCC Gas Cleaning, Recovery, Separation,

and Advanced Gasification; Particulate Control; ByProduct Utilization; Environment Control Technology;

and Global Climate Change. Two poster sessions were

also held for Combustion and Environmental Control,

and Hot Gas Cleanup.

Trade Mission Activities in FY1998

Brazil. Following over a years’s effort, during

which the Office of Fossil Energy provided significant

guidance, support, and advice, the U.S. Trade Development Agency (TDA) announced a grant of $470,000

for a feasibility study for a new coal-fired power plant

in Brazil. The grant will be awarded to Copelmi

Mineracao, S.A., one of Brazil’s largest coal producers. The new coal-fired power plant is to be located

near the Seival coal mine in Rio Grande do Sul. The

area is Brazil’s third most populous and industrialized

state, and is experiencing rapid industrial growth.

Average energy consumption for the state is at approximately 3,000 MWe while it only produces 700 MWe.

Total cost of the new mine-mouth plant is estimated at

$400 million. When the project is finally approved,

engineering, new generation equipment, instrumentation, controls, construction, and management services

will all be open for bidding to U.S. firms. TDA also

recently approved another grant in the amount of

$140,000, cost-shared with mine owner Copelmi

Mineracao, to study Seival coal mine development

options.

During FY1998, U.S. DOE’s Office of Import and

Export and the Southern States Energy Board cosponsored a Conference in Atlanta, Georgia to promote

the many business opportunities involved in the multimillion dollar projects planned in Brazil.

China. The 14th International Pittsburgh Coal

Conference, held in Taiyuan, China September 23-25,

1997, was attended by over 300 delegates representing

18 countries and over 200 major international corporations, government agencies, research organizations, and

educational institutions. In addition to the University

of Pittsburgh, co-sponsors of the event included the

Shanxi Energy Research Society (China), the Institute

of Coal Chemistry, Chinese Academy of Sciences

(China), and the U.S. DOE Federal Energy Technology

Center (FETC). One of the highlights of the conference

was the International Coal Forum. Distinguished

panelists included key industrial leaders and policy

makers from Babcock & Wilcox Power Generation

Group, the Chinese National Power Corporation, the

East-West Center, Hawaii, and the Atmospheric Environment Institute, China. Presentations emphasized the

collaborative spirit in which the conference was organized, and set the tone for the exchange of technical

information between the international and Chinese

participants.

Governor of West Virginia and Brazilian industrialists

confer on coal investment opportunities at Atlanta

conference.
Program Update 1998 4-17

A major feature of the 14th International Pittsburgh

Coal Conference Agenda was the U.S. sponsored twoday Clean Coal Technology and Coal Utilization

Workshop, held on September 26-27, 1997, in

Taiyuan, China. The workshop focused on economics

and commercialization of demonstrated innovative and

conventional technologies potentially applicable to

markets in China and the Pacific Rim countries.

More than 120 technologists from China, the U.S.,

and sixteen other countries attended the workshop.

Over 40 presentations were made by various representatives of the U.S. and Chinese industrial firms, with

each presentation delivered to an audience of 25 to 50

attendees from the international community. Some 24

of the presentations represented U.S. clean coal technologies and coal utilization technologies. The remainder of the presentations represented Chinese use of

clean coal and utilization technologies, and China’s

potential need for more and better applications. The

format of the workshop encouraged discussions and the

exchange of information.

On November 15, 1997, the Tsinghua University

in Beijing, China held a commencement ceremony of

the U.S.-China Energy and Environmental Technology

Center (EETC). The EETC represents a significant

step for the two countries in demonstrating a long-term

relationship that builds on trust, mutual benefits, and

good will.

EETC was created and made possible under joint

DOE and EPA funding. Its mission is to enhance the

competitiveness and adoption of U.S. clean and environmentally superior technologies in China by focusing

on education and training, promoting the use and

profitability of U.S. technology, and supporting policy

development in China to encourage the responsible use

of coal. The EETC activities are jointly implemented

by the U.S. and the Chinese governments: U.S. DOE

and EPA, China’s State Science and Technology

Commission (SSTC), Tulane University in New Orleans, and Tsinghua University. The Chinese government is cost-sharing part of EETC’s activities. A binational core team composed of members from a

number of U.S. and Chinese organizations is overseeing and implementing EETC’s work.

Although the opening ceremony was held in

November 1997, an EETC office has been operational

at the Tsinghua University for nearly a year. The

following are some of its accomplishments.

• Establishment of a web site and home page at

http://www.tulane.edu/~uschina to support an

Internet-based energy and environmental

information system. The site includes a

database of more than 1,000 U.S. firms with

energy and environmental technology and

equipment that can serve the Chinese market.

• The conduct of joint expert studies on coal

liquefaction, IGCC for retrofit and repowering,

coal preparation, and superfine coal applications, with plans to investigate applications for

molten carbonate fuels cells. Studies include

analysis of technology readiness, need for the

technology in China, and barriers to technology

introduction. Some assessments are generic

while others are site-specific.

• Development of a model cogeneration contract

for joint venture projects.

Korea. The Office Fossil Energy and the U.S.

Department of Commerce co-sponsored the highly

successful 12th Korea-U.S. Joint Workshop on Energy

and Environment, in Taejon, Korea October 6-11,

1997. This year’s workshop was combined with a

trade mission so that the U.S. delegation included 36

representatives from 16 firms specializing in advanced

power generation, air pollution control, and waste

management, who met with potential Korean partners

at on-the-spot appointments. On the Korean side, the

FETC Director moderates International Coal Forum at the 14th International Pittsburgh Coal Conference in Taiyuen,

China.
4-18 Program Update 1998

workshop was organized by the Korea Institute of

Energy Research and sponsored by the Ministry of

Trade, Industry and Energy, with participation by the

Korea Electric Power Corporation. Also participating

were 124 Korean industry representatives. The workshop, which included a 2-day technical conference and

site visits, achieved its major goal of introducing a

broad range of U.S. energy and environmental companies to Korea and provided an effective forum for

information exchange on energy and environmental

technologies, for which there is a large Korean market.

Uruguay. The Office of Fossil Energy’s Office of

Coal and Power Systems sponsored the “Roundtable on

the Deployment of Clean Power Systems for Power

Generation Technologies” at the September 1997

“Meeting on Natural Gas and Electric Power Integration in the Southern Cone” held in Uruguay. The

Government of Uruguay was overall conference host,

and co-sponsored the workshop with the DOE, the

Department of State, the Department of Commerce,

and the U.S. Trade and Development Agency. Over

200 government officials and industry executives from

the U.S., Argentina, Bolivia, Brazil, Chile, Paraguay,

and Uruguay attended. The Roundtable consisted of

sessions on Alternative Advanced Clean Energy Technologies, and Financing of Clean Energy Projects.

U.S. representatives made presentations on IGCC,

FBC, and fuel cells. Participants discussed potential

areas of collaboration, opportunities for U.S. companies

in Latin America, and barriers to business opportunities.

Japan. Office of Fossil Energy representatives

participated in the 10th Annual FETC/Japanese Technical Meeting on Coal Liquefaction and Materials for

Coal Liquefaction, held in Tokyo in October. The

meeting provided an excellent opportunity for exchange of technical information. Participants also had

the opportunity to tour Japan’s 150 ton/day direct coal

liquefaction demonstration plant outside of Tokyo.

The demonstration plant, which went on-line in November 1996, is the largest in existence and will

operate for three years to obtain scale-up data for a

commercial plant and to evaluate the economic

feasibility of the project.

Philippines. The Office of Fossil Energy sent a

representative to the Philippines in the summer of 1998

to discuss potential application of clean coal technologies to the Palawan Province, an environmentally

pristine area where all generation is currently oil-fired

and 70 percent of the near-one million population live

in isolated communities without power. Meetings

have been conducted under the auspices of the Philippine Center for Sustainable Development, which was

funded by the U.S.-Asian Environmental Partnership (a

U.S. State Department program). The Center is a

collaborative international institute started in 1997 by a

California-based consortium led by California State

University in Hayward and the Philippines’ De La

Salle University in Manila. The initial effort in Palawan, largely supported by local funding, will be a pilot

program of modeling on and economic analysis of the

role of advanced clean technologies, including clean

coal, in the energy mix.

The Center’s team comprises representatives from

the Office of Fossil Energy, De La Salle University,

California State University, Lawrence Livermore

National Laboratory, and the University of California

at Santa Barbara and at Davis. If the Palawan effort is

successful, a national model would be developed with

the Philippines’ Ministry of Energy for other rural

communities. Funding for that effort would be expected to come from a variety of international and local

sources. The model also may be applicable to other

Asian countries that are seeking a mix of energy generation to cope with growing economic demand while

addressing climate change concerns.

Some 20 percent of Philippine power generation

is coal-fired, with the remainder oil-fired. Oil is expected

to be phased out, with new generation coming from

natural gas and a combination of clean coal and renewables.

Switzerland. DOE co-sponsored the Fourth

International Conference on Greenhouse Gas Control

Technologies in Interlaken, Switzerland August 30–

September 1998. The conference provided a forum for

the discussion of the latest advances in the field of

greenhouse gas control technologies, including capture,

storage, and utilization. Also addressed were other

mitigation options such as efficiency increase and use

of renewables, as well as economic issues. An underlying objective of the conference was to promote international research and development collaborations and to

encourage an exchange of ideas on future directions in

this field. DOE participated by outlining its Vision 21

program and attendant carbon sequestration efforts,

using an exhibit and handouts to underscore the message.

Unveiling of a plaque at the dedication of the EETC.
Program Update 1998 5-1

The CCT projects are spread across the nation in 18

states, indicated in white.

5. CCT Projects

Introduction

CCT Program demonstrations provide a portfolio

of technologies that will enable coal to continue to

provide low-cost, secure energy vital to the nation’s

economy while satisfying energy and environmental

goals well into the 21st century. This is being carried

out by addressing four basic market sectors: (1) environmental control devices for existing and new power

plants, (2) advanced electric power generation for

repowering existing facilities and providing new

generating capacity, (3) coal processing for clean fuels

to convert the nation’s vast coal resources to clean

fuels, and (4) industrial applications dependent upon

coal use.

In response to the initial thrust of the program,

operations have been completed for 17 of 19 projects

that address SO2

 and NOx control for coal-fired boilers.

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

types. The 19 environmental control device projects

are valued at more than $704 million. These include

seven NOx emission control systems installed in more

than 1,750 MWe of utility generating capacity, five

SO2 emissions systems installed on approximately 770

MWe, and seven combined SO2/NOx emission control

systems installed or planned on more than 665 MWe of

capacity.

To respond to load growth as well as growing

environmental concerns, the program provides a range

of advanced electric power generation options for both

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

in greenhouse gas emissions; SO2

, NOx, and particulate

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

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

are represented by 11 projects valued at more than $3.1

billion. These projects include five fluidized-bed

combustion (FBC) systems, four integrated gasification

combined-cycle (IGCC) systems, and two advanced

combustion/heat engine systems. These projects will

not only provide environmentally sound electric

generation in the 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 (CAAA). Internationally, both the products and

processes have excellent market potential. Valued at

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

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

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

of which also produces a liquid product equivalent to

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

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

expert computer software system that enables a utility

to assess the environmental, operational, and cost

impact of utilizing coals not previously burned at a

facility, including upgraded coals and coal blends.

Projects were undertaken 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 high-sulfur,

coal fuels; and the need for many industrial boiler

operators to consider switching to coal fuels to reduce

operating costs. The five industrial applications

projects have a combined value of nearly $1.3 billion.

Projects encompass substitution of coal for 40 percent

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

reduction of cement kiln emissions and solid waste

generation, and demonstrations of an industrial-scale

slagging combustor and a pulse combustor system.

Section 5 contains a discussion of the technologies

being demonstrated and fact sheets for each project.
5-2 Program Update 1998

Unique CT-121 SO2 scrubber at Plant Yates combined a

number of functions and eliminated process steps.

Technology Overview

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 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 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

coal-fired units. Under the stricter Phase II requirements, compliance by fuel switching alone is unlikely.

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.

Sulfur dioxide 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, e.g., size, type, age, and space

availability.

On one end of the spectrum are the smaller, older

boilers with limited space for adding equipment. For

these, sorbent injection techniques hold promise.

Sorbent is injected into the boiler or the ductwork, and

humidification is incorporated in some fashion to

properly condition the flue gas for efficient SO2

 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 calciumto-sulfur (Ca/S) molar ratio of about 2.0 for sulfur

capture efficiencies of 50 to 70 percent.

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

MWe boilers less than 30 years old and somewhat

space constrained. For many of these, an increase in

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 molar ratio of 1.3

to 2.0. This category of control device is called a spray

dryer (because the solid by-product from the reaction is

dry).

At the other end of the spectrum are the larger

(300 MWe and more) boilers with some latitude in

space availability, as well as new capacity additions.

For these boilers, advanced flue gas desulfurization

(AFGD) wet scrubbers, with higher capital cost, but

higher sulfur capture efficiency than other approaches,

become cost effective. These systems apply larger and

somewhat more complex reactors that drive up the

capital cost. However, the sorbent is limestone and SO2

removal efficiencies greater than 90 percent are

achieved at a Ca/S molar ratio of about 1.0, making

operating costs significantly lower than those of the

other two approaches. Furthermore, although the initial

AFGD solid by-product is in slurry form, it is 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 5-1 briefly summarizes the characteristics and performance of the technologies that are

described in more detail in the project fact sheets.
Program Update 1998 5-3

Exhibit 5-1

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% 5-26

Desulfurization Demonstration

LIFAC Sorbent Injection Desulfurization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% 70% 5-30

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% 5-22

Absorption particulate recycle (lime sorbent)

Advanced Flue Gas Desulfurization AFGD—co-current flow, integrated quench absorber tower and reaction 2.25–4.7% 94% 5-34

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+% 5-38

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.
5-4 Program Update 1998

Exhibit 5-2

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 Low-NOx

Concentric Firing System (LNCFSTM) is shown being

installed on a tangentially fired boiler.

NOx Control Technology. Nitrogen oxides (NOx)

are formed from oxidation of nitrogen contained within

the coal (fuel-bound NOx

) 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 fuelbound NOx

 formation, it is important to limit oxygen at

the early stages of combustion. To control thermalNOx

,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 lb/106 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 pre-NSPS coal-fired units (see Exhibit

5-2). Ozone nonattainment prompted the U.S.

Environmental Protection Agency to issue a NOx

transport State Implementation Plan (SIP) call for 22

states and the District of Columbia to cut NOx emissions 85 percent below 1990 rates or achieve a 0.15 lb/

106 Btu emission rate by May 2003.

 The CCT Program has sought to provide a

number of NOx control options to cover the range of

boiler types and emission reduction requirements.

Control of NOx

 emissions can be accomplished by

either modifying the 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 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 to 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

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 to 25 percent NOx

 emission reductions.

LNB/AOFA systems generally can achieve NOx

emission reductions of 60 to 67 percent.

In reburning, a percentage of the fuel input to the

boiler is diverted to injection ports above the primary
Program Update 1998 5-5

Exhibit 5-3

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% 5-46

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% 5-54

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% 5-50

Retrofit

Demonstration of Advanced Combustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500-MWe/wall 68% 5-66

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% 5-62

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% 5-58

Technology for the Control of NOx Emissions chemical compositions

from High-Sulfur-Coal-Fired Boilers

combustion zone. Either gas or coal is typically used as

the reburning fuel to provide 10 to 30 percent of the

heat input to the boiler. The reburning fuel is injected

to create a fuel-rich zone deficient in oxygen (a

reducing rather than oxidizing zone). 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

to 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 to 2,200 oF) where

a catalyst is not needed. SCR is typically applied at

temperatures between 600 to 800 oF. Generally, SNCR

and SCR systems alone can achieve NOx emission

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

respectively.

Under the CCT Program, seven NOx control

technologies were addressed, encompassing LNBs,

AOFA, reburning, SNCR, SCR, and combinations

thereof. Six of the projects have completed operations

and the remaining one is in the operations phase.

Exhibit 5-3 briefly summarizes the characteristics and

performance of the technologies that are described in

more detail in the project fact sheets.

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 wetscrubber design, sorbent additive, and artificial

intelligence controls. The balance of the seven projects

use synergistic methods not previously described.
5-6 Program Update 1998

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

SO2

 and NOx control technologies.

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 hightemperature 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.

Six of the seven combined SO2/NOx control

technology projects have completed operations and one

is in the project definition and design phase. Exhibit 5-

4 briefly summarizes the characteristics and performance of the technologies that are described in more

detail in the project fact sheets.
Program Update 1998 5-7

Exhibit 5-4

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% 5-82

Coolside Demonstration sorbents

Integrated Dry NOx

/SO2 Emissions LNB/SNCR/sorbent injection—calcium- and sodium-based 0.4% 70%/62–80% 5-94

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% 5-90

and Sorbent Injection duct injection

Milliken Clean Coal Technology Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5–4.0% 98%/53–58% 5-72

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% 5-86

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% 5-78

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)
5-8 Program Update 1998

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

Technology

Advanced electric power generation technologies

enable the efficient and environmentally superior

generation of electricity. The advanced electric power

generation projects selected under the CCT Program

are responsive to the capacity expansion needs requisite to meeting long-term demand, offsetting nuclear

retirements, and meeting 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 technologies may be deployed in

modules, allowing phased construction to better match

demand growth, and to meet the smaller capacity requirements of municipal, rural, and nonutility generators.

There are five generic advanced electric power

generation technologies demonstrated in 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.

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 and construction applications. More than 90 percent of the SO2

 can

be captured this way.

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

the fluidized mixing of the fuel and sorbent enhances

both combustion and sulfur capture. The operating

temperature range is about half that of a conventional

pulverized-coal boiler and below the temperature at

which thermal NOx

 is formed. In fact, fluidized-bed NOx

emissions are about 70 to 80 percent lower than those for

conventional pulverized-coal boilers. Thus, fluidized-bed

combustors substantially reduce both SO2

 and NOx

emissions. Also, fluidized-bed combustion has the

capability of using high-ash coal, whereas conventional

pulverized-coal units must limit ash content in the coal to

relatively low levels.

Two parallel paths were pursued in fluidized-bed

development—bubbling and circulating beds. Bubbling

beds use a dense fluid bed and low fluidization velocity

to effect good heat transfer and mitigate erosion of an inbed heat exchanger. Circulating fluidized beds use a

relatively high fluidization velocity, which entrains the

bed material, in conjunction with hot cyclones to separate

and recirculate the bed material from the flue gas before

it passes to a heat exchanger. Hybrid systems have also

evolved from these two basic approaches.

Fluidized-bed combustion can be either atmospheric (AFBC) or pressurized (PFBC). AFBC operates at atmospheric pressure while PFBC operates at

pressure 6 to 16 times higher. PFBC offers potentially

higher efficiency, and consequently, reduced operating

costs and waste relative to AFBC.

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 over 50

percent.

Integrated Gasification Combined Cycle. The

integrated coal gasification combined-cycle process

has four basic steps: (1) fuel gas is generated from coal

reacting with high-temperature steam and an oxidant

(oxygen or air) in a reducing atmosphere; (2) the fuel

gas is either passed directly to a hot-gas cleanup system

to remove particulates, sulfur, and nitrogen compounds

or first cooled to produce steam and then cleaned

conventionally; (3) the clean fuel gas is combusted in a

gas turbine generator to produce electricity; and (4) the

residual heat in the hot exhaust gas from the gas turbine

is recovered in a heat recovery steam generator, and

the steam is used to produce additional electricity in a

steam turbine generator.
Program Update 1998 5-9

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.

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 chemical composition of the gas

requires that 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 (H2

S) rather than as

SO2, which is the case in conventional pulverized-coal

combustion. In some IGCC systems, much of the

sulfur-containing gas is captured by a sorbent injected

into the gasifier. Others use existing proven commercial hydrogen sulfide removal processes, which remove

up to 99+ percent of the sulfur, but require the fuel to

be cooled, which is an efficiency penalty. Therefore,

hot-gas cleanup systems are now 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 sulfur-containing 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 in the gas

turbine can be held to well within allowable levels by

staged combustion in the gas turbine or by adding

moisture to control 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. Either a coal-oil or coal-water

slurry fuels a diesel-engine, which drives an electric

generation system. The hot exhaust from the diesel

engine is routed 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 to 48 percent

thermal efficiencies. The 10 to 100 MWe capacity

range of the technology would be most applicable to

small utilities, municipalities, 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
5-10 Program Update 1998

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 to 80 percent. Injecting

limestone into the combustion chamber has the potential to reduce sulfur emissions by 90 percent in combination with a spray-dryer absorber. Advanced slagging

combustors could replace oil-fired units in 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, one is a coal diesel, and one is an 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 projects, operation was initiated in January

1998 on the advanced slagging combustor project, and

the coal diesel project is in the project definition and

design phase.

Exhibit 5-5 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 25 MWe Healy

Unit No. 1 with a 50-MWe slagging combustor unit using 65 percent waste coal.
Program Update 1998 5-11

Exhibit 5-5

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 145-MWe 5-100

McIntosh Unit 4B Topped PCFB McIntosh 4A with pyrolyzer and topping combustor 145-MWe + 93-MWe 5-102

Demonstration Project

Tidd PFBC Demonstration Project Pressurized bubbling fluidized-bed combustion 70-MWe 5-106

JEA Large-Scale CFB Atmospheric circulating fluidized-bed combustion 297.5-MWe 5-104

Combustion Demonstration Project

Nucla CFB Demonstration Project Atmospheric circulating fluidized-bed combustion 100-MWe 5-110

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project Oxygen-blown, slagging fixed-bed gasifier with cold 477-MWe 5-116

gas cleanup, fuel cell slipstream

Piñon Pine IGCC Power Project Air-blown, fluidized-bed gasifier with hot gas cleanup 99-MWe 5-118

Tampa Electric Integrated Gasification Oxygen-blown, entrained-flow gasifier with hot and 250-MWe 5-120

Combined-Cycle Project cold gas cleanup

Wabash River Coal Gasification Oxygen-blown, two-stage entrained-flow gasifier with 262-MWe 5-122

Repowering Project cold gas cleanup

Advanced Combustion/Heat Engines

Healy Clean Coal Project Advanced slagging combustor, spray dryer with sorbent 50-MWe 5-126

recycle

Clean Coal Diesel Demonstration Project Coal-fueled diesel engine 6.4-MWe 5-128
5-12 Program Update 1998

Coal Processing for Clean Fuels

Technology

The coal processing 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 densemedium 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 Self-Scrubbing CoalTM. The

project is on hold pending resolution of financial

matters.

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 to 9,000 Btu/lb, 25 to 40 percent

moisture content, and 0.5 to 1.5 percent sulfur is

converted to a 12,000 Btu/lb 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, which completed operational testing in July 1997, has used mild gasification

to convert low-Btu, low-sulfur 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 11,000-Btu/lb low-sulfur

solid fuel. The demonstration plant processed 500 tons

per day of subbituminous coal and produced 250 tons

per day of solid Process-Derived Fuel (PDF®) and 250

barrels per day of Coal-Derived Liquids (CDL®). Both

the solid and liquid fuels have undergone test burns at

utility and industrial sites. The project was successfully completed in December 1997.

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.

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 5-6 summarizes the process characteristics

and size of the coal processing for clean fuels technologies presented in more detail in the project fact sheets.
Program Update 1998 5-13

Exhibit 5-6

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 5-138

Advanced Coal Conversion Process Demonstration Advanced coal conversion process for upgrading 45 tons/hr 5-136

low-rank coals

ENCOAL® Mild Gasification Project Liquids-from-coal (LFC®) mild gasification to 1,000 tons/day 5-142

produce solid and liquid fuels

Commercial-Scale Demonstration of the Liquid-Phase Methanol Liquid phase process for 80,000 gal/day 5-132

(LPMEOHTM) Process methanol production from coal-derived syngas

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Dense-medium cyclones with finely sized magnetic and 500 tons/hr 5-134

sorbent addition for bituminous coals

The LPMEOHTM process produces over 80,000 gal/day

of methanol, all of which is used by the Eastman Chemical

Company.

The ENCOAL® mild gasification plant near Gillette,

WY, has operated 12,800 hours and processed approximately

247,000 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.
5-14 Program Update 1998

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, HIsmelt®. In

this process, raw coal is introduced into a meltergasifier 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 boiler 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 byproduct 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- and gasfired units to coal include addition of

SO2

 and NOx controls, tube fouling,

and the need for a coolant water circuit

for the combustor. Oil- and 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 fouling, and uses air cooling to

preclude the need for water circuitry.

A pulse combustor being demonstrated by ThermoChem has a wide

range of applications. The technology

can be used in many coal processes,

including coal gasification, as well as

waste-to-energy applications.

The cement kiln and slagging

combustor projects are completed. The

project demonstrating granular-coal

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.
Program Update 1998 5-15

Exhibit 5-7

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 5-148

Demonstration Project metal/furnace per day

Advanced Cyclone Combustor with Internal Advanced slagging combustor with staged combustion and sorbent 23 x 106

 Btu/hr 5-152

Sulfur, Nitrogen, and Ash Control injection

Clean Power from Integrated Coal/Ore HIsmelt® direct reduction iron-making process to eliminate coke; 195-MWe 5-150

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 5-156

and fertilizer and distilled water produced

Pulse Combustor Design Qualification Test Advanced combustion using Manufacturing and Technology To be determined 5-160

Conversion International’s pulse combustor/gasifier

injection into a blast furnace is in operation. Demonstration of the HIsmelt® direct iron-making process and

the ThermoChem project are in the project definition

and design phase.

Exhibit 5-7 summarizes process characteristics and

size for the industrial applications technologies presented in more detail in the project fact sheets.
5-16 Program Update 1998

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.

Project Fact Sheets

The remainder of this section contains fact sheets

for all 40 projects. Two types of facts sheets are

provided: (1) a brief, two page overview for ongoing

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 5-8. Projects are listed by application category. Ongoing projects in each category appear first

followed by projects having completed operations. A

shaded area distinguishes projects having completed

operations from ongoing projects. Within these

breakdowns, projects are listed alphabetically by

participant. In addition, Exhibit 5-8 indicates the

solicitation under which the project was selected; its

status as of September 30, 1998; and the page number

for each Fact Sheet. Exhibit 5-9 lists the projects

alphabetically by participant and provides project

location and page numbers.
Program Update 1998 5-17

Project Participant Solicitation/Status Page

Environmental Control Devices

SO2

 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/completed 3/94 5-22

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93 5-26

LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America CCT-III/completed 6/94 5-30

Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95 5-34

Demonstration of Innovative Applications of Technology for the Southern Company Services, Inc. CCT-II/completed 12/94 5-38

CT-121 FGD Process

NOx

 Control Technologies

Micronized Coal Reburning Demonstration for NOx

 Control New York State Electric & Gas Corporation CCT-IV/operational 5-44

Demonstration of Coal Reburning for Cyclone Boiler NOx Control The Babcock & Wilcox Company CCT-II/completed 12/92 5-46

Full-Scale Demonstration of Low-NOx

 Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 4/93 5-50

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 1/95 5-54

Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95 5-58

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 12/92 5-62

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

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/completed 5/98 5-66

Combined SO2

/NOx Control Technologies

Commercial Demonstration of the NOXSO SO2

/NOx Removal Flue NOXSO Corporation CCT-III/design 5-76

Gas Cleanup System

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/completed 12/94 5-78

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company CCT-I/completed 8/91 5-82

SOx-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-II/completed 5/93 5-86

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 10/94 5-90

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/completed 6/98 5-72

Integrated Dry NOx

/SO2 Emissions Control System Public Service Company of Colorado CCT-III/completed 12/96 5-94

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-III/design 5-100

McIntosh Unit 4B Topped PCFB Demonstration Project City of Lakeland, Lakeland Electric CCT-V/design 5-102

JEA Large Scale CFB Combustion Demonstration Project JEA CCT-I/design 5-104

Exhibit 5-8

Project Fact Sheets by Application Category

Shaded area indicates projects having completed operations.
5-18 Program Update 1998

Exhibit 5-8 (continued)

Project Fact Sheets by Application Category

Tidd PFBC Demonstration Project The Ohio Power Company CCT-I/completed 3/95 5-106

Nucla CFB Demonstration Project Tri-State Generation and Transmission Association, Inc. CCT-I/completed 1/91 5-110

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project Clean Energy Partners Limited Partnership CCT-V/design 5-116

Piñon Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/operational 5-118

Tampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-III/operational 5-120

Wabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering Project CCT-IV/operational 5-122

Joint Venture

Advanced Combustion/Heat Engines

Healy Clean Coal Project Alaska Industrial Development and Export Authority CCT-III/operational 5-126

Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/construction 5-128

Coal Processing for Clean Fuels

Commercial-Scale Demonstration of the Liquid-Phase Methanol Air Products Liquid Phase Conversion Company, L.P. CCT-III/operational 5-132

(LPMEOHTM) Process

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Custom Coals International CCT-IV/design 5-134

Advanced Coal Conversion Process Demonstration Rosebud SynCoal Partnership CCT-I/operational 5-136

Development of the Coal Quality ExpertTM ABB Combustion Engineering, Inc., and CQ Inc. CCT-I/completed 12/95 5-138

ENCOAL Mild Coal Gasification Project ENCOAL® Corporation CCT-III/completed 7/97 5-142

Industrial Applications

Blast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/operational 5-148

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) CPICORTM Management Company, L.L.C. CCT-V/design 5-150

Pulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/design 5-160

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation CCT-I/completed 5/90 5-152

Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/completed 9/93 5-156

Project Participant Solicitation/Status Page

Shaded area indicates projects having completed operations.
Program Update 1998 5-19

Exhibit 5-9

Project Fact Sheets by Participant

Participant Project Location Page

ABB Combustion Engineering, Inc., and CQ Inc. Development of the Coal Quality ExpertTM Homer City, PA 5-138

ABB Environmental Systems SNOXTM Flue Gas Cleaning Demonstration Project Niles, OH 5-78

Air Products Liquid Phase Conversion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Kingsport, TN 5-132

Process

AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption West Paducah, KY 5-22

Alaska Industrial Development and Export Authority Healy Clean Coal Project Healy, AK 5-126

Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project Fairbanks, AK 5-128

The Babcock & Wilcox Company Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control Cassville, WI 5-46

The Babcock & Wilcox Company Full-Scale Demonstration of Low-NOx

 Cell Burner Retrofit Aberdeen, OH 5-50

The Babcock & Wilcox Company LIMB Demonstration Project Extension and Coolside Demonstration Lorain, OH 5-82

The Babcock & Wilcox Company SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project Dilles Bottom, OH 5-86

Bechtel Corporation Confined Zone Dispersion Flue Gas Desulfurization Demonstration Seward, PA 5-26

Bethlehem Steel Corporation Blast Furnace Granular-Coal Injection System Demonstration Project Burns Harbor, IN 5-148

City of Lakeland, Lakeland Electric McIntosh Unit 4A PCFB Demonstration Project Lakeland, FL 5-100

City of Lakeland, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project Lakeland, FL 5-102

Clean Energy Partners Limited Partnership Clean Energy Demonstration Project Grand Tower, IL 5-116

Coal Tech Corporation Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Williamsport, PA 5-152

CPICORTM Management Company, L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICORTM) Vineyard, UT 5-150

Custom Coals International Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Central City, PA 5-134

ENCOAL® Corporation ENCOAL® Mild Coal Gasification Project Gillette, WY 5-142

Energy and Environmental Research Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Hennepin, IL 5-90

Springfield, IL

Energy and Environmental Research Corporation Evaluation of Gas Reburning and Low-NOx

 Burners on a Wall-Fired Boiler Denver, CO 5-54

JEA JEA Large-Scale CFB Combustion Demonstration Project Jacksonville, FL 5-104

LIFAC–North America LIFAC Sorbent Injection Desulfurization Demonstration Project Richmond, IN 5-30

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

 Control Lansing, NY 5-44
5-20 Program Update 1998

Exhibit 5-9 (continued)

Project Fact Sheets by Participant

Participant Project Location Page

New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project Lansing, NY 5-72

NOXSO Corporation Commercial Demonstration of the NOXSO SO2/NOx

 Removal Flue Gas To be determined 5-76

Cleanup System

The Ohio Power Company Tidd PFBC Demonstration Project Brilliant, OH 5-106

Passamaquoddy Tribe Cement Kiln Flue Gas Recovery Scrubber Thomaston, ME 5-156

Public Service Company of Colorado Integrated Dry NOx /SO2

 Emissions Control System Denver, CO 5-94

Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Chesterton, IN 5-30

Rosebud SynCoal Partnership Advanced Coal Conversion Process Demonstration Colstrip, MT 5-136

Sierra Pacific Power Company Piñon Pine IGCC Power Project Reno, NV 5-118

Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coosa, GA 5-66

Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newnan, GA 5-38

Process

Southern Company Services, Inc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensacola, FL 5-58

NOx

 Emissions from High-Sulfur-Coal-Fired Boilers

Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially Fired Combustion Lynn Haven, FL 5-62

Techniques for the Reduction of NOx

 Emissions from Coal-Fired Boilers

Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project Mulberry, FL 5-150

ThermoChem, Inc. Pulse Combustor Design Qualification Test Baltimore, MD 5-160

Tri-State Generation and Transmission Association, Inc. Nucla CFB Demonstration Project Nucla, CO 5-110

Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project West Terre Haute, IN 5-122

Project Joint Venture
Environmental Control Devices

SO2 Control Technology
5-22 Program Update 1998 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, Inc. (FLS) —technology owner

Tennessee Valley Authority—cofunder and site owner

Location

West Paducah, McCracken County, KY

Technology

FLS’ Gas Suspension Absorption (GSA) system for flue

gas desulfurization (FGD)

Plant Capacity/Production

10-MWe equivalent slipstream of flue gas from a

175-MWe wall-fired boiler

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

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Program Update 1998 5-23

Results Summary

Environmental

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

followed closely by chloride content.

• GSA/ESP achieved

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

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

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

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

and

– 99.9+% average particulate removal efficiency.

• GSA/PJBH achieved

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

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

– 3–5% increase in SO2

 reduction relative to

GSA/ESP, and

– 99.99+% average particulate removal efficiency.

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

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

cadmium, 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 TAGTM

cost method was used. Based on EPRI cost studies of

FGD processes, the capital cost (1990$) for a conventional spray dryer was $172/kW.

Capital Cost Levelized Cost

(1990 $/kW) (mills/kWh)

GSA—3 units at 149 10.35

50% capacity

WLFO 216 13.04
5-24 Program Update 1998 Environmental Control Devices

Exhibit 5-11

GSA Factorial Testing Results

Exhibit 5-10

Variables and Levels Used in

GSA Factorial Testing

Variable Level

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

Ca/S (moles Ca(OH)2

/mole inlet SO2) 1.00 and 1.30

Flyash loading (gr/ft3

, actual) 0.50 and 2.0

Coal chloride level (%) 0.04 and 0.12

Flue gas flow rate (103

 scfm) 14 and 20

Recycle screw speed (rpm) 30 and 45

*

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

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 5-10 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 5-11 summarizes key results from factorial testing.

A 28-day continuous run to evaluate the

GSA/ESP configuration was made with bituminous

coals averaging 2.7% sulfur, 0.12% chloride levels,

and 18 oF approach-to-saturation temperature. A

subsequent 14-day continuous run to evaluate the GSA/

PJBH configuration was performed under the same conditions as those of the 28-day run, except for adjustments in

flyash injection rate from 1.5–1.0 gr/ft3

 (actual).

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

the overall SO2

 removal efficiency averaged slightly more

than 90%, very close to the set point of 91%, at an average Ca/S molar ratio of 1.40–1.45 moles Ca(OH)2

/mole

inlet SO2

. The system was able to adjust rapidly to the

surge in inlet SO2

 caused by switching to 3.5% sulfur

Warrior Basin coal for a week. Lime utilization averaged

66.1%. The particulate removal efficiency averaged

99.9+% and emission rates were maintained below 0.015

lb/106

 Btu. The 14-day run on the GSA/PJBH system

showed that the SO2

 removal efficiency averaged more

than 96% at an average Ca/S molar ratio of 1.34–1.43

moles Ca(OH)2

/mole inlet SO2. Lime utilization averaged

70.5%. The particulate removal efficiency averaged

99.99+% and emission rates ranged from 0.001–0.003 lb/

106 Btu.

All air toxic tests were conducted with 2.7% sulfur,

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

temperature and a high flyash loading of 2.0 gr/ft3 (actual). The GSA/ESP arrangement indicated average removal efficiencies of greater than 99% for arsenic,

barium, chromium, lead, and vanadium; somewhat less

for manganese; and less than 99% for antimony, cadmium, mercury, and selenium. The GSA/PJBH configuration showed 99+% removal efficiencies for arsenic,

barium, chromium, lead, manganese, selenium, and vanadium; with cadmium removal much lower and mercury

removal lower than that of the GSA/ESP system. The

removal of HCl and HF was dependent upon the utilization of lime slurry and was relatively independent of

particulate control configuration. Removal efficiencies

were greater than 98% for HCl and 96% for HF.

Operational Performance

Because the GSA system has suspended recycle solids to

provide a contact area for SO2

 capture, multiple highpressure atomizer nozzles or high-speed rotary nozzles to

achieve uniform, fine droplet size are not required. Also,

recycle of solids is direct and avoids recycling material in

the feed slurry, which necessitates expensive abrasionresistant materials in the atomizer(s).
Environmental Control Devices Program Update 1998 5-25

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.

AirPol, Inc. successfully demonstrated the GSA system

at TVA’s Center for Emissions Research.

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 space-confined plants and reduces installation cost. The GSA system slurry is sprayed on the recycled solids, not the reactor walls, avoiding direct wall contact and the need for

corrosion-resistant alloy steels. Furthermore, the high

concentration of rapidly moving solids scours the reactor

walls and mitigates scaling. The GSA system generates a

significantly lower grain loading than a 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.

GSA market entry was significantly enhanced with

the sale of a 50-MWe unit, worth $10 million, to the city

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

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

system has been sold to a Swedish iron ore sinter plant.

Sales to Taiwan and India have a combined value of

$5.5 million.

Contacts

Niels H. Kastrup, (281) 539-3400

FLS Miljo, Inc.

1000 Glennborough

Houston, TX 77067

(281) 539-3411 (fax)

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

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

References

• 10-MWe Demonstration of Gas Suspension Absorption

Final Project Performance and Economics Report.

Report No. DOE/PC/90542-T9. AirPol, Inc. June

1995. (Available from NTIS as DE95016681.)

• 10-MW Demonstration of the Gas Suspension Absorption Final Public Design Report. Report No. DOE/PC/

90542-T10. AirPol, Inc. June 1995. (Available from

NTIS as DE960003270.)

• SO2

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

Energy and AirPol, Inc. April 1995.

• 10-MWe Demonstration of the Gas Suspension Absorption Process at TVA’s Center for Emissions Research:

Final Report. Report No. DOE/PC/90542-T10. Tennessee Valley Authority. March 1995. (Available from

NTIS as DE96000327.)
5-26 Program Update 1998 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 equivalent

Coal

Pennsylvania bituminous, 1.2–2.5% sulfur

Project Funding

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

DOE 5,205,800 50

Participant 5,205,800 50

Project Objective

To demonstrate SO2

 removal capabilities of in-duct

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

CZD/FGD’s operability, reliability, and cost-effectiveness

during long-term testing and its impact on downstream

operations and emissions.

Technology/Project Description

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

of reactive lime is sprayed into the flue gas stream between the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the center of

the duct by spray nozzles designed to produce a cone of

fine spray. As the spray moves downstream and expands,

the gas within the cone cools and the SO2

 is quickly

absorbed in the liquid droplets. The droplets mix with

the hot flue gas, and the water evaporates rapidly. Fast

drying precludes wet particle buildup in the duct and aids

the flue gas in carrying the dry reaction products and the

unreacted lime to the ESP.

 This project included injection of different types of

sorbents (dolomitic and calcitic limes) with several atomizer designs using low- and high-sulfur coals to verify the

effects on SO2

 removal and the capability of the ESP to

control particulates. The demonstration was conducted at

Pennsylvania Electric Company’s Seward Station in

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

WATER

SORBENT

SLURRY

DOLOMITIC CALCITIC LIME

AIR

SOLID WASTE

SOLID WASTE TO DISPOSAL

1st STAGE 

ELECTROSTATIC

PRECIPITATOR

AIR 

PREHEATER

BOILER

AIR

PULVERIZED

COAL

2d STAGE

ELECTROSTATIC

PRECIPITATOR

STACK
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Program Update 1998 5-27

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
5-28 Program Update 1998 Environmental Control Devices

Bechtel’s demonstration showed that 50% SO2 removal efficiency

was possible using CZD/FGD technology. The extended duct into which

lime slurry was injected is in the foreground.

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.
Environmental Control Devices Program Update 1998 5-29

This photo shows the CZD/FGD lime slurry injector control system.

Economic Performance

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

SO2

 removed when operating a 500-MWe unit burning

4% sulfur coal. Based on a 500-MWe plant retrofitted

with CZD/FGD for 50% SO2

 removal, the total capital

cost is estimated to be less than $30/kW.

Commercial Applications

After the conclusion of the DOE-funded CZD/FGD demonstration project at Seward Station, the CZD/FGD system was modified to improve SO2 removal during continuous operation while following daily load cycles.

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

additional year. Results showed that CZD/FGD operation

at SO2

 removal rates lower than 50% could be sustained

over long periods without significant process problems.

CZD/FGD can be used for retrofit of existing plants

and installation in new utility boiler flue gas facilities to

remove SO2

 from a wide variety of sulfur-containing

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

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

installed capacity, or approximately one-fourth the cost of

building a conventional wet scrubber. In addition to low

capital cost, other advantages include small space requirements, ease of retrofit, low energy requirements, fully

automated operation, and production of only nontoxic,

disposable waste. The CZD/FGD technology is particularly well suited for retrofitting existing boilers, independent of type, age, or size. The CZD/FGD installation

does not require major power station alterations and can

be easily and economically integrated into existing power

plants.

Contacts

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

Bechtel Corporation

P.O. Box 193965

San Francisco, CA 94119-3965

(415) 768-5420 (fax)

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

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

References

• Confined Zone Dispersion Project: Final Technical

Report. Bechtel Corporation. June 1994.

• Confined Zone Dispersion Project: Public Design

Report. Bechtel Corporation. October 1993.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Confined Zone Dispersion Flue

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

of Energy. September 1990. (Available from NTIS as

DE91002564.)
5-30 Program Update 1998 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.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

3 4 1 2

Environmental Control Devices Program Update 1998 5-31

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 molar

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

• The four parameters having the greatest influence on

sulfur removal efficiency were limestone 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 molar ratio of 2.0 (fine limestone).

• ESP efficiency and operating levels were essentially

unaffected by LIFAC operation during steady-state

operation.

• Fly and bottom ash were dry and readily disposed of

at a local landfill. The quantity of additional solid

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

1.0 ton of SO2

.

Operational

• When operating with fine limestone (80% minus

325 mesh), the soot-blowing cycle had to be reduced

from 6.0 to 4.5 hours.

• Automated programmable logic and simple design

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

shutdown, or normal duty cycles.

• The amount of bottom ash increased slightly, but there

was no negative impact on the ash-handling system.

Economic

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

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

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

(65-MWe).

• Operating cost—$65/ton of SO2

 removal, assuming

75% SO2

 capture, Ca/S molar ratio of 2.0, limestone

composed of 95% CaCO3

, and $15/ton.

Project Summary

The LIFAC technology was designed to enhance the

effectiveness of dry sorbent injection systems for SO2

control and to maintain the desirable aspects of low capital cost and compactness for ease of retrofit. Furthermore, limestone was used as the sorbent (about 1/3 of the

cost of lime) and a sorbent recycle system was incorporated to reduce operating costs.

The process evaluation test plan was composed of

five distinct phases each having its own objectives.

These tests were as follows:

4/98

Project completed/final

report issued 4/98
5-32 Program Update 1998 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.

• Baseline tests characterized the operation of the host

boiler and associated subsystems prior to LIFAC operations.

• Parametric tests were designed to evaluate the many

possible combinations of LIFAC process parameters

and their effect on SO2

 removal.

• Optimization tests were performed after the parametric

tests to evaluate the reliability and operability of the

LIFAC process over short, continuous operating periods.

• Long-term tests were performed to demonstrate

LIFAC’s performance under commercial operating

conditions.

• Post-LIFAC tests involved repeating the baseline test

to identify any changes caused by the LIFAC system.

The coals used during the demonstration varied in

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

testing was conducted with the higher sulfur coals

(2.0–2.8% sulfur).

Environmental Performance

During the parametric testing phase, the numerous LIFAC

process values and their effects on sulfur removal efficiency were evaluated. The four major parameters having

the greatest influence on sulfur removal efficiency were

limestone 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-hour to 4.5-hour

cycle periods. The coarse-quality limestone did not affect

soot blowing but was found to be more abrasive on the

feed and transport hoses.

Parametric tests indicated that a 70% SO2

 reduction

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

containing unspent sorbent and fly ash was recycled from

the ESP hoppers back into the reactor inlet duct work.

Ash recycling is essential for efficient SO2

 capture. The

large quantity of ash removed from the LIFAC reactor

bottom and the small size of the ESP hoppers limited the

ESP ash recycling rate. As a result, the amount of material recycled from the ESP was approximately 70% less

than had been anticipated. However, this low recycling

rate was found to affect SO2

 capture. During a brief test,

it was found that increasing the recycle rate by 50% resulted in a 5% increase in SO2

 removal efficiency. It was

estimated that if the reactor bottom ash is recycled along

with ESP ash, while sustaining a reactor temperature of 5

oF above saturation temperature, an SO2

 reduction of 85%

could be maintained.

Operational Performance

Optimization testing began in March 1994 and was followed by long-term testing in June 1994. The boiler was

operated at an average load of 60-MWe during long-term

testing, although it fluctuated according to power demand. The LIFAC process automatically adjusted to

boiler load changes. A Ca/S molar ratio of 2.0 was selected to attain SO2

 reductions above 70%. Reactor bottom temperature was about 5 oF higher than optimum to

avoid ash buildup on the steam reheaters. Atomized

water droplet size was smaller than optimum for the same

reason. Other key process parameters held constant during the long-term tests included the degree of humidification, grind size of the high-calcium-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

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.
Environmental Control Devices Program Update 1998 5-33

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)

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.

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

(150-MWe)

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

(300-MWe)

Crushed limestone accounts for about one half of

LIFAC’s operating costs. LIFAC requires 4.3 tons of

limestone to remove 1.0 ton of SO2

, assuming 75% SO2

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

. Assuming limestone costs of $15/ton,

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

 removed.

Commercial Applications

There are 10 full-scale LIFAC units in operation in

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

The LIFAC system at Richmond Power & Light is the

first to be applied to a power plant using high-sulfur (2.0–

2.9%) coal. The LIFAC system is being retained by Richmond Power & Light at Whitewater Valley Station, Unit

No. 2. The other LIFAC installations on power plants are

using bituminous and lignite coals having lower sulfur

contents (0.6–1.5%).

Contacts

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

ICF Kaiser Engineers, Inc.

Gateway View Plaza

1600 West Carson Street

Pittsburgh, PA 15219-1031

(412) 497-2235 (fax)

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

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

References

• LIFAC Sorbent Injection Desulfurization Demonstration Project. Final Report, Vol. II: Project Performance and Economics. LIFAC–North America. February 1998. (Available from NTIS as DE96004421.)

• “LIFAC Nearing Marketability.” Clean Coal Today.

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

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

Sorbent Injection Process in North America.” Third

Annual Clean Coal Technology Conference: Technical Papers. September 1994.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: LIFAC Sorbent Injection

Desulfurization Demonstration Project. LIFAC–North

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

as DE91001077.)
5-34 Program Update 1998 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, Unit Nos.

7 and 8)

Technology

Pure Air’s advanced flue gas desulfurization (AFGD)

process

Plant Capacity/Production

528-MWe

Coal

Bituminous, 2.0–4.5% sulfur

Project Funding

Total project cost $151,707,898 100%

DOE 63,913,200 42

Participant 87,794,698 58

Project Objective

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

create no new waste streams.

Technology/Project Description

Pure Air built a single SO2

 absorber for a 528-MWe

power plant. Although the largest capacity absorber

module of its time in the United States, space requirements were modest because no spare or backup absorber

modules were required. The absorber performed three

functions in a single vessel: prequenching, absorbering,

and oxidation of sludge to gypsum. Additionally, the

absorber was of a co-current design, in which the flue gas

and scrubbing slurry move in the same direction and at a

relatively high velocity compared to that in conventional

scrubbers. These features all combined to yield a stateof-the-art SO2

 absorber that was more compact and less

expensive than contemporary conventional scrubbers.

Other technical features included the injection of

pulverized limestone directly into the absorber, a device

called an air rotary sparger located within the base of the

absorber, and a novel wastewater evaporation system.

The air rotary sparger combined the functions of agitation

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

Pure Air also demonstrated a unique gypsum agglomeration process, PowerChip®, to significantly enhance handling characteristics of adsorbed flue gas desulfurization (AFGD)-derived gypsum.

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

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Program Update 1998 5-35

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 1.01–

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
5-36 Program Update 1998 Environmental Control Devices

Exhibit 5-12

 SO2 Removal Performance

(100% Boiler Load)

1.07, with the upper value set by gypsum purity requirements (i.e., amount of unreacted reagent allowed in the

gypsum). Another key control parameter was the ratio L/

G, which is the amount of reagent slurry injected into the

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

design L/G range was 50–128 gal/103

 ft3. The lower end

was determined by solids settling rates in the slurry and

the requirement for full wetting of the grid packing. The

high end was determined by where performance leveled

out.

Five coals with differing sulfur contents were selected for parametric testing to examine SO2

 removal

efficiency as a function of load, sulfur content, stoichiometric ratio, and L/G. Loads tested were 33%, 67%, and

100%. High removal efficiencies, well above 95%, at

loads of 33% and 67% were possible with low to moderate stoichiometric ratio and L/G settings, even for 4.5%

sulfur coal. Exhibit 5-12 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 cocurrent 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 5-13 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 5-14 depicts the relative costs of a hypothetical 500-MWe generating unit in

the Midwest burning 4.3% sulfur coal with a base case

conventional FGD system and four incremental cases.
Environmental Control Devices Program Update 1998 5-37

Exhibit 5-13

Estimated Costs for an AFGD System

(1995 Current Dollars)

Cases: 1 2 3 456789

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

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

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

Levelized cost ($/ton SO2

)

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

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

Levelized cost (mills/kWh)

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

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

The horizontal lines in Exhibit 5-15 show the range of

costs for a fuel-switching option. The lower bar is the

cost of fuel delivered to the hypothetical midwest unit

and the upper bar allows for some plant modifications to

accommodate the compliance fuel.

Commercial Applications

AFGD is positioned well to compete in the pollution

control arena of 2000 and beyond. AFGD has markedly

reduced cost and demonstrated the ability to compete

with fuel switching under certain circumstances even with

a first-generation system. Advances in technology, e.g., in

materials and components, should improve costs for

AFGD. The own-and-operate business approach has done

much to mitigate risk on the part of prospective users.

References

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

Project Performance and Economics. Pure Air on the

Lake, L.P. April 1996. (Available from NTIS as

DE96050313.)

• Advanced Flue Gas Desulfurization Project: Public

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

1990.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Advanced Flue Gas Desulfurization (AFGD) Demonstration Project. (Pure Air on

the Lake, L.P.) DOE/FE Report No. 0150. U.S.

Department of Energy. November 1989. (Available

from NTIS as DE90004460.)

• 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.

High SO2

-capture efficiency places an AFGD user in the

possible position of trading allowances or applying credits to other units within the utility. WES and PowerChip®

mitigate or eliminate otherwise serious environmental

concerns. AFGD effectively deals with hazardous air pollutants.

The project received Power magazine’s 1993

Powerplant Award and the National Society of Professional Engineer’s 1992 Outstanding Engineering

Achievement Award.

Contacts

Tim Roth, (610) 481-6257

Pure Air on the Lake, L.P.

c/o Air Products and Chemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

(610) 481-5820 (fax)

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

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

Exhibit 5-14

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
5-38 Program Update 1998 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

FAN

FLUE

GAS

AIR

MOTOR

AIR

SPARGER A GITATO R

GYPSUM STAC K COLLECTION

POND

LOWER 

DECK

BOILER

AIR

P R EC IPITATO R

FLY

ASH

QUENCH

DUCT

COAL

ASH

UPPER

DECK

WATER

REACTION

ZONE

JET

BU BBLING

ZONE

RISER

CLEAN

GAS TO

STACK

SPARGER

PIPE

LIM ESTONE

SLURRY
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

** Years omitted

3 4 1 2

Environmental Control Devices Program Update 1998 5-39

1988 1989 1990 1991 1992 1993 1994 1995 1996 1998 1999

4/90

Preaward Design and Construction Operation

9/88 10/92

DOE selected project

(CCT-II) 9/28/88

Cooperative agreement awarded 4/2/90

NEPA process

completed (EA) 8/10/90

Ground breaking/construction

started 8/23/90

Environmental monitoring

plan completed 12/18/90

Preoperational tests initiated 5/92

Design completed 9/92

Operation initiated 10/92

Construction completed 10/92

Results Summary

Environmental

• Over 90% SO2 removal efficiency was achieved at SO2

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

• JBR achieved particulate removal efficiencies of

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

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

• Capture efficiency was a function of particle size:

– >10 microns—99% capture

– 1–10 microns—90% capture

– 0.5–1 micron—negligible capture

– <0.5 micron—90% capture

• Hazardous air pollutant (HAP) testing showed greater

than 95% capture of hydrogen chloride (HCl) and

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.

2/99

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 5-15 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 2/99*

**
5-40 Program Update 1998 Environmental Control Devices

Low-Ash Elevated-Ash Cumulative

Phase Phase for Project

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

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

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

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

Reliabilitya 0.98 0.95 0.96

Availabilityb 0.97 0.95 0.97

Utilizationc 0.73 0.72 0.75

a

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

b

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

c

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

Exhibit 5-15

Operation of CT-121 Scrubber

Exhibit 5-16

SO2 Removal Efficiency

Exhibit 5-17

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.

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 5-16 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 5-17.

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.
Environmental Control Devices Program Update 1998 5-41

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 5-18.

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.), with more than

20,000-MWe of coal-fired generating capacity, is

expected to enhance confidence in the CT-121

process among other large high-sulfur-coal boiler

users. This process will be applicable to 370,000-MWe

of new and existing generating capacity by the year 2010.

A 90% reduction in SO2

 emissions from only the retrofit

portion of this capacity represents more than 10,500,000

tons/yr of potential SO2

 control.

Plant Yates continues to operate with the CT-121

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

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

been sold to 16 customers in seven countries.

The project received Power magazine’s 1994

Powerplant Award. Other awards include the Society of

Plastics Industries’ 1995 Design Award for the mist

eliminator, the Georgia Chapter of the Air and Waste

Management Association’s 1994 Outstanding Achievement Award, and the Georgia Chamber of Commerce’s

1993 Environmental Award.

Contacts

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

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

(205) 992-7535 (fax)

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

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

References

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

Plant Utilizing an ESP while Demonstrating the CCT

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 5-18

CT-121 Air Toxics Removal

(JBR Components Only)

0

20

40

60

80

100

Chloride Fluoride Arsenic Cadmium Mercury Selenium Vanadium

Removal Efficiency (%)
5-42 Program Update 1998 Environmental Control Devices
Environmental Control Devices

NO

x

 Control Technology
5-44 Program Update 1998 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

New York State Energy Research and Development

Authority—cofunder

Empire State Electric Energy Research Corporation—

cofunder

Locations

Lansing, Tompkins County, NY (New York State Electric

& Gas Corporation’s Milliken Station, Unit No. 1)

Rochester, Monroe County, NY (Eastman Kodak

Company’s Kodak Park Site Power Plant, Unit No. 15)

Technology

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 20%

of the total furnace fuel requirements, and advanced

reburning, 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 LNCFS IIITM burners are used for burning the

micronized coal and the remaining burners are re-aimed

and (2) use of the burners in a deep stage combustion

BOILER BURNOUT ZONE–

NORMAL EXCESS AIR

REBURNING ZONE–

SLIG HTLY FUEL RICH–

NO REDUCED TO N X 2

PR IMARY COM BUSTION ZONE—

REDUCED FIRING RATE

COAL

EXISTIN G COAL

HOPPER

MICR OFINE BURN ERS

MICR OFUEL

SYSTEM

FAN

AIR

EXISTIN G 

PU LVE RIZERS

OVERFIRE AIR

SYSTEM

BAGHOUSE

ASH TO DISPOSAL

ASH TO DISPOSAL

STACK
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Program Update 1998 5-45

3/97

impact on NOx emissions, but significant impact on LOI.

Only excess air had a significant impact on both NOx

emissions and LOI. Ongoing tests are exploring optimum

conditions for sustained NOx

 control at low LOI.

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. 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 lowload 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 micronized-coal-reburning

fuel and better pulverizer performance will increase

overall pulverized-fuel surface area for better carbon

burnout.

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

6/99

Operation completed (Lansing) 4/99*

Operation completed (Rochester) 10/98

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

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

Design completed (Rochester) 9/96

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

mode and re-aiming them to create primary combustion

and reburn zones. At the Eastman Kodak site, the Fuller

MicroMillTM is 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.

Project Status/Accomplishments

Parametric testing at the Kodak site is complete. Tests

showed that the target NOx

 emission level of 0.60 lb/106

Btu could be met with a reburn fuel heat input as low as

18.5%, representing a 56% reduction from baseline emissions. Long-term testing at optimum conditions established in the parametric tests is complete. The project is

now focused on system and component reliability.

Parametric testing at the Milliken site is finished as

well. The primary objective was to determine conditions

that will achieve minimum NOx

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

reburn fuel flow rate, and primary air flow showed little

Project completed/final report

issued 6/99*

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

Project relocated to Lansing and Rochester 12/95
5-46 Program Update 1998 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 oxygendeficient 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.

BOILER

BURNOUT

ZONE

REBURN

ZONE

SECONDARY

AIR

COAL REBURN

BURNERS

AIR

PU LVE RIZED

COAL

AIR

MAIN

COMBUSTION

ZONE

M O LTEN SLA G

WATER

AIR

PR EHEATER
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

3 4 1 2

Environmental Control Devices Program Update 1998 5-47

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. (Costs are

in 1990 constant dollars.)

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

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
5-48 Program Update 1998 Environmental Control Devices

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 5-19

Coal Reburn Test Results

Wisconsin Power and Light Company’s Nelson Dewey

Station hosted the successful demonstration of Coal Reburn.

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 5-19 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

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

semi-volatile 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.

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

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
Environmental Control Devices Program Update 1998 5-49

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 5-20

Coal Reburn Economics

(1990 Constant Dollars)

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

results of these analyses are shown in Exhibit 5-20.

These values assumed typical retrofit conditions and did

not take into account any fuel savings from use of lowrank 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

Dot K. Johnson, (330) 829-7395

McDermott Technologies, Inc.

1562 Beeson Street

Alliance, OH 44601

(330) 821-7801 (fax)

dot.k.johnson@mcdermott.com

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.)

• 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.)
5-50 Program Update 1998 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

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 nitrogen

LNCB is a registered trademark of The Babcock & Wilcox Company.

BOILER

W INDBOX

ASH x

SECONDARY

AIR PORT

COAL

AND 

AIR

SECONDARY

AIR PORT

LOW-NO

CELL BURNER

SYSTEM

COAL

AND 

AIR

FLY A SH TO DISP O SAL

ELECTRO STATIC

PR EC IP ITATO R

STACK

BOTTOM ASH

LOW-NO

CELL BURNER

SYSTEM

x
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

3 4 1 2

Environmental Control Devices Program Update 1998 5-51

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
5-52 Program Update 1998 Environmental Control Devices

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–

55.5%. With one mill out of service at full load, the

average NOx

 reduction ranged from 53.3–54.5%.

Average NOx

 reduction at

intermediate load (about

460-MWe) ranged from 52.5–

54.7%. At low loads (about

350-MWe), average NOx

 reduction

ranged from 46.9–47.9%.

NOx

 emissions were monitored over the long-term at full

load for all mills in service and

one mill out of service. Each test

spanned an 8-month period. 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
Environmental Control Devices Program Update 1998 5-53

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

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. Seven commercial contracts

have been awarded for 172 burners, valued at $27 million. LNCB® have already been installed on more than

4,600-MWe of capacity.

The project received R&D magazine’s 1994 R&D

Award.

Contacts

Dot K. Johnson, (330) 829-7395

McDermott Technologies, Inc.

1562 Beeson Street

Alliance, OH 44601

(330) 821-7801 (fax)

dot.k.johnson@mcdermott.com

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

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

References

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

Cell Burner Retrofit. Report No. DOE/PC/90545-T2.

The Babcock & Wilcox Company. December 1995.

(Available from NTIS as DE96003766.)

• Public Design Report: Full-Scale Demonstration of

Low-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.)
5-54 Program Update 1998 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 (gross), 158-MWe (net)

Coal

Colorado bituminous, 0.40% 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

strated with and without the use of recirculated flue gas

and with optimized overfire air.

A series of parametric tests were performed on the

gas reburning system, varying operational control parameters, and assessing the effect on boiler emissions, completeness of combustion (carbon-in-ash), thermal efficiency, and heat rate. A one-year long-term testing program was performed in order to judge the consistency 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 demonTO DISPOSAL

ECONOMIZER

BOILER

REBURN ZONE

PRIMARY 

COMBUSTION 

ZONE

BURNOUT ZONE

OVERFIRE AIR

NATURAL GAS

RECIRCULATED

FLUE GAS

WINDBOX

COAL

AIR

LOW-NO

BURNERS

X

ASH

BAGHOUSE

STACK

AIR

PREHEATER
1 2 3 4 1 2 3 4 1 2 3 4 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

**Years omitted

3 4 1 2

Environmental Control Devices Program Update 1998 5-55

Results Summary

Environmental

• LNB alone reduced NOx

 emissions from a pre-construction baseline of 0.73 lb/106

 Btu to 0.48 lb/106

Btu, a 37% NOx reduction.

• First-generation GR, which incorporated flue gas

recirculation, in combination with LNB, reduced NOx

emissions to 0.25 lb/106 Btu, a 66% NOx reduction at

an 18% gas heat input rate.

• Second-generation GR, without flue gas recirculation,

in combination with LNB reduced NOx

 emissions to

0.26 lb/106

 Btu, a 64% NOx reduction with only 12.5%

gas heat input.

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

capable of reducing NOx

 emissions by up to 70% for

short periods of time, the average was 65%.

• After modifying the overfire air system to enhance

penetration and turbulence (as part of second-genera1988 1989 1990 1991 1992 1993 1994 1995 1996 1998 1999

Preaward Operation

12/89

Design and Construction

10/90 11/92

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

Operation initiated 11/92

Construction

completed 11/92

tion 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.

Operational

• Boiler efficiency decreased by approximately 1.0%.

• There was no measurable boiler tube wear and only a

small amount of slagging.

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

alone.

Economic

• Capital cost for GR–LNB retrofit is $26.01/kW

(1996$) plus the gas pipeline cost, if not in place, for

300-MWe plant ($12.14/kW for GR only and

$13.87/kW for LNB only)

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

 emission allowances

Long-term operations started 4/93

Operation completed 1/95

Restoration

completed 11/95

(because GR reduces SO2 emissions when displacing

coal).

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. The importance of cost-effective

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.

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

MWe (gross) wall-fired boiler—a balanced-draft pulverized-coal 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

10/98

Project completed/final

report issued 10/98

**
5-56 Program Update 1998 Environmental Control Devices

GR Generation

First Second

Baseline (lb/106

 Btu) 0.73 0.73

Avg NOx

 reduction (%)

LNB 37 44

GR–LNB 65 64

Avg gas heat input (%) 18 12.5

Exhibit 5-21

NOx Data from Cherokee

Station, Unit No. 3

A worker inspects the support ring for the Foster

Wheeler low-NOx

 burner installed in the boiler wall.

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.

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 (0.40%) 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 5-21.

Although the 37% NOx

 reduction performance of

LNB was less than the expected 45%, the overall objectives of the demonstration were met. Boiler efficiency

decreased by only 1% during gas reburning due to increased moisture in the fuel resulting from natural gas

use. Further, there was no measurable tube wear, and only

small amounts of slagging occurred during the

GR–LNB demonstration. However, with LNB alone,

carbon-in-ash and CO could not be maintained at acceptable levels.

Economic Performance

GR–LNB is a retrofit technology in which the economic

benefits are dependent on the following site-specific

factors:

• Gas availability at the site

• Gas/coal cost differential

• Boiler efficiency

• SO2 removal requirements

• Value of SO2

 emission credits

Based on the demonstration, GR–LNB is expected to

achieve at least 64% NOx

 control with a gas heat input of

12.5%. The capital cost estimate for a 300-MWe wallfired installation is $26.01/kW (1996 $) plus gas pipeline
Environmental Control Devices Program Update 1998 5-57

The Public Service Company of Colorado has retained

the gas-reburning and low-NOx

 burner system for

commercial use.

costs, if required. This cost includes both equipment and

installation costs and a 15% contingency. The GR and

LNB system capital costs can be easily separated from

one another because they are independent systems. The

capital cost for the GR system only is estimated at

$12.14/kW. The LNB system capital cost is $13.87/kW.

Operating costs are almost entirely related to the

differential cost of natural gas and coal and reduced by

the value of the SO2

 emission credits received due to

absence of sulfur in the gas. Gas costs more than coal on

a $/Btu basis, so a differential cost of $1.00/106

 Btu was

used. Boiler efficiency was estimated to decline by

0.80%; the cost of this decline was calculated using a

composite fuel cost of $1.67/106

 Btu. Over-fire air

boaster and cooling fans auxiliary loads will be partially

offset by lower loads on the pulverizers. No additional

operating labor is required, but there is an increase in

maitenance costs. Allowances were also made for overhead, taxes, and insurance. Based on these assumptions

and assuming an SO2

 credit allowance of $95/ton (Feb.

1996), the net operating cost is $2.14 million per year.

Commercial Applications

Current estimates indicate that about 35 existing wallfired 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.

Public Service Company of Colorado, the host utility, decided to retain the low-NOx

 burners and the gasreburning system for immediate use; however, a restoration was required to remove the flue gas recirculation

system.

Energy and Environmental Research Corporation has

been awarded two contracts to provide gas-reburning

systems for five cyclone coal-fired boilers: TVA’s Allen

Unit No. 1, with options for Unit Nos. 2 and 3, (identical

330-MWe Units); Baltimore Gas & Electric’s C.P. Crane,

Unit No. 2, with an option for Unit No. 1, (similar 200-

MWe Units). Start-up of the first two units is planned for

mid-1998.

This project was one of two that received the Air and

Waste Management Association’s 1997 J. Deanne

Sensenbaugh Award.

Contacts

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

Energy and Environmental Research Corporation

18 Mason

Irvine CA 92618

(949) 859-3194 (fax)

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: Performance and Economics

Report, Gas Reburning-Low NOx

 Burner System,

Cherokee Station Unit No. 3, Public Service Company

of Colorado. Final Report. July 1998.

• Guideline Manual: Gas Reburning—Low NOx

 Burner

System, Cherokee Station Unit No. 3, Public Service

Company of Colorado. Final Report. July 1998.

• Evaluation of Gas Reburning and Low NOx Burners

on a Wall-Fired Boiler (Long-Term Testing, April

1993–January 1995). Report No. DOE/PC/90547-

T20. Energy and Environmental Research Corporation. 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.)

• 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.)
5-58 Program Update 1998 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Demonstration of Selective

Catalytic Reduction

Technology for the Control of

NOx 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 No. 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 scfm 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, used

flue gas from the burning of 2.7% sulfur coal under various NOx

 and particulate levels.

Results Summary

Environmental

• NOx reductions of over 80% were achieved at an

ammonia slip well under the 5 ppm acceptable for

commercial operation.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

3 4 1 2

Environmental Control Devices Program Update 1998 5-59

• 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 the nearly 12,000 hours of operation, thus

demonstrating deactivation in coal-fired units was in

line with worldwide experience.

• Long-term testing showed that SO2

 oxidation was

within or below the design limits necessary to protect

downstream equipment.

Operational

• Fouling of catalysts was controlled by adequate

sootblowing procedures.

• Long-term testing showed that catalyst erosion was not

a problem.

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

mance of technology and effects on the balance-of-plant

equipment in the presence of high amounts of SO2

 and

SO3

, and performance of the SCR catalyst under typical

U.S. high-sulfur coal-fired utility operating conditions.

Catalyst suppliers were required to design the catalyst

baskets to match predetermined reactor dimensions, provide a maximum of four catalyst layers, and meet the

following reactor baseline conditions:

The catalysts tested are listed in Exhibit 5-22. Catalyst suppliers were given great latitude in providing the

amount of catalyst for this demonstration.

Operation initiated 7/93

Operation completed 7/95

Project completed/final

report issued 11/96

• Air preheater performance was degraded because of

ammonia slip and subsequent by-product formation;

however, solutions were identified.

• The SCR process did not significantly affect the results of Toxicity Characteristic Leaching Procedure

analysis of the fly ash.

Economic

Levelized costs for various NOx

 removal levels for a

250-MWe unit at 0.35 lb/106

 Btu inlet follow:

Project Summary

The demonstration tests were designed to address several

uncertainties, including potential catalyst deactivation due

to poisoning by trace metals species in U.S. coals, perfor40% 60% 80%

1996 levelized cost (mills/kWh) 2.39 2.57 2.79

1996 levelized cost ($/ton) 3,502 2,500 2,036

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 (scfm)

 Large reactor 3,000 5,000 7,500

 Small reactor 240 400 600
5-60 Program Update 1998 Environmental Control Devices

Exhibit 5-22

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 scfm Small = 0.2-MWe; 400 scfm

Exhibit 5-23

Average SO2 Oxidation Rate

(Baseline)

Average SO2 Oxidation (%)

NH3

/NOx = 0.8, 700 oF, design flow

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-

23. 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. On

the other hand, 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

attributed to aggressive sootblowing.
Environmental Control Devices Program Update 1998 5-61

Exhibit 5-24

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

• 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 5-24.

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/106 Btu of inlet NOx

 are

as follows:

For retrofit applications, the estimated capital costs

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

levelized costs for the retrofit applications were

$1,850–5,100/ton (current 1996 $).

Commercial Applications

As a result of this demonstration, SCR technology has

been shown to be applicable to existing and new utility

generating capacity for removal of NOx

 from the flue gas

of virtually any size boiler. There are 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

Larry Monroe, (205) 257-7772

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

(205) 257-5367 (fax)

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

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

References

• Control of Nitrogen Oxide Emissions: Selective Catalytic Reduction (SCR). Topical Report No. 9. U.S.

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

• Maxwell, J. D., et al. “Demonstration of SCR Technology for the Control of NOx

 Emissions from HighSulfur Coal-Fired Utility Boilers.” Fifth Annual Clean

Coal Technology Conference: Technical Papers,

January 1997.

• Demonstration of SCR Technology for the Control of

NOx

 Emissions from High-Sulfur Coal-Fired Utility

Boilers: Final Report. Vol. 1. Southern Company

Services, Inc. October 1996. (Available from NTIS,

Vol. 1 as DE97050873, Vol. 2: Appendixes A–N as

DE97050874, and Vol. 3: Appendixes O–T as

DE97050875.)

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

Services, Inc. September 1996. (Available from NTIS

as DE97051156.)

125-MWe 250-MWe 700-MWe

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
5-62 Program Update 1998 Environmental Control Devices

Project Objective

To demonstrate in a stepwise fashion the short- and longterm NOx

 reduction capabilities of Low-NOx Concentric

Firing System (LNCFSTM) levels I, II, and III on a single

reference boiler.

Technology/Project Description

Technologies demonstrated included the 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)

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.

system located above 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.

PU LVE RIZED

COAL

COMBUSTION

AIR

AD VANCED 

OVERFIRE AIR

PORTS

BOILER

AOFA PORTS

W INDBOX

PU LVE RIZED

COAL

CO NCENTRIC

FIRING SYSTEM

ELECTRO STATIC

PR EC IP ITATO R

AIR

PREHEATER

ELECTRO STATIC

PR EC IP ITATO R
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

3 4 1 2

Environmental Control Devices Program Update 1998 5-63

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

(1993$).

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

NOx

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

III, $400/ton (1993$).

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 tangentiallyfired 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
5-64 Program Update 1998 Environmental Control Devices

Exhibit 5-25

LNCFSTM Configurations

Exhibit 5-26

Concentric Firing Concept

 Exhibit 5-25 shows the various LNCFSTM configurations used to achieve staged combustion. In addition to

overfire air, as shown in Exhibit 5-26, 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 5-27 summarizes the impacts of LNCFSTM on

unit performance.

Environmental Performance

At full load, LNCFSTM I, II, and III reduced NOx

 emissions by 37, 37, and 45%, respectively.

Exhibit 5-28 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.

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 in 1993 constant dollars follow:

• LNCFSTM I—$5–15/kW

• LNCFSTM II—$15–25/kW

• LNCFSTM III—$15–25/kW

Site-specific considerations have a significant effect

on capital costs; however, the above ranges reflect 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 in

1993 constant dollars):

• LNCFSTM I—$103/ton of NOx

 removed

• LNCFSTM II—$444/ton of NOx

 removed

• LNCFSTM III—$400/ton of NOx removed

Commercial 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 range from 25-

MWe to 950-MWe in size and fire a wide range of coals,

from low-volatile bituminous through lignite.

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

116 tangentially-fired boilers, representing over 25,000

MWe, with LNCFSTM and derivative TFS 2000TM burners.
Environmental Control Devices Program Update 1998 5-65

Exhibit 5-27

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 oF Same as baseline 160–200-MWe: OK

load; low temper- lower than baseline 80-MWe: 15–35 o

F

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 5-28

Average Annual NOx Emissions and Percent 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

Contacts

Larry Monroe, (205) 257-7772

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

(205) 257-5367 (fax)

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

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

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.)
5-66 Program Update 1998 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Demonstration of Advanced

Combustion Techniques for a

Wall-Fired Boiler

Project completed.

Participant

Southern Company Services, Inc. (SCS)

Additional Team Members

Electric Power Research Institute (EPRI)—cofunder

Foster Wheeler Energy Corporation (Foster Wheeler)—

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)

Coal

Eastern bituminous coals, 1.7% sulfur

Plant Capacity/Production

500-MWe

Project Funding

Total project cost $15,853,900 100%

DOE 6,553,526 41

Participant 9,300,374 59

Project Objective

To achieve 50% NOx

 reduction with the LNB/AOFA

system; to determine the contributions of AOFA and LNB

to NOx

 reduction and the parameters for optimal LNB/

AOFA performance; and to assess the long-term effects of

LNB, AOFA, combined LNB/AOFA, and the Generic

NOx

 Control Intelligence System (GNOCIS) advanced

digital controls on NOx

 reduction and boiler performance.

Technology/Project Description

In a LNB, fuel and air mixing is controlled to mitigate the

formation of NOx

 by regulating the primary air-fuel mixture, velocity, and turbulence to create a fuel-rich flame

core. Furthermore, by controlling the rate that secondary

air, which is required to complete combustion, is mixed

with flame solids and gases, an oxygen deficient atmosphere is created that reduces thermal-NOx

 formation.

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 thermal-NOx

 formation, and (3) supplying air over

furnace wall tube surfaces to prevent slagging and furnace corrosion. Plant Hammond Unit No. 4 is a nominal

500-MWe pulverized coal opposed wall-fired unit, which

typifies many existing pre-NSPS wall-fired utility boilers

in the United States.

Results Summary

Operational

• At full load, fly ash loss-on-ignition (LOI) was near

8% (compared to a baseline of 5%) for LNB alone and

LNB/AOFA combined.

• AOFA accounted for an incremental NOx

 reduction

beyond the use of LNB of approximately 17%, with

additional reductions resulting from other operational

changes.

AIR

W INDBOX WINDBOX

BOILER

EC ONOMIZER

AD VANCED

OVERFIRE AIR

PORTS

COMBUSTION

AIR

PU LVE RIZED

COAL

LOW-NO

BURNERS

X

ASH

BOUNDARY AIR PORTS

LOW-NO

BURNERS

X

DRY WASTE TO DISPOSAL

PU LVE RIZED

COAL

AOFA

PORTS

AIR

AIR

PR EHEATER STACK

ELECTRO STATIC

PR EC IP ITATO R
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

**Years omitted

3 4 1 2

Environmental Control Devices Program Update 1998 5-67

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

12/98

GNOCIS testing initiated 2/96

• GNOCIS achieved boiler efficiency gain of 0.5 percentage points, a reduction in fly ash LOI levels of 1-3

percentage points, and a reduction in NOx

 emissions of

10-15 % at full load.

Environmental

• Using LNB alone, NOx

 emissions were 0.65 lb/106 Btu

at full load, representing a 48% reduction from

baseline conditions (1.24 lb/106

 Btu).

• Using AOFA only, NOx

 reductions of 24% below

baseline conditions were achieved under normal longterm operation, depending upon load.

• Using LNB/AOFA, full load NOx

 emissions were

approximately 0.40 lb/106

 Btu, which represents a

68% reduction from baseline conditions.

• There was not a significant difference in emissions of

trace metals, acid gases, and volatile organic compounds between AOFA and LNB/AOFA operations.

Economic

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

for AOFA alone, $10.0/kW for LNB alone, and $0.5/

kW for GNOCIS.

• Estimated cost of NOx

 removal is $86/ton.

Project Summary

Operational

SCS conducted baseline characterization of the unit in an

“as-found” condition from August 1989 to April 1990.

The AOFA system was tested from August 1990 to March

1991. Following installation of the LNBs in the second

quarter of 1991, the LNBs were tested from July 1991 to

January 1992, excluding a three-month delay when the

plant ran at reduced capacity. Post-LNB increases in fly

ash LOI, along with increases in combustion air requirements and fly ash loading to the electrostatic precipitator

(ESP), adversely affected the unit’s stack particulate

emissions. The LNB/AOFA testing was conducted from

January 1992 to August 1993, excluding downtime for a

scheduled outage and for portions of the test period due

to excessive particulate emissions. However, an ammonia

flue gas conditioning system was added to improve ESP

performance, which enabled the unit to operate at full

load and testing to continue.

LOI increased significantly for the AOFA, LNB, and

LNB/AOFA phases despite improved mill performance

due to the replacement of the mills.

Increased LOI was a concern not only because of the

associated efficiency loss, but a potential loss of fly ash

sales. The increased carbon in the fly ash can render the

material unsuitable for use in making concrete.

During October 1992, SCS conducted parametric

testing to determine the relationship between NOx

 and

LOI emissions. The parameters tested were: excess oxygen, mill coal flow bias, burner sliding tip position,

burner outer register position, and burner inner register

position. Nitrogen oxide emissions and LOI levels varied

from 0.44–0.57 lb/106

 Btu and 3–10%, respectively. As

3 4

Project completed 12/98*

Final report issued 6/98

**
5-68 Program Update 1998 Environmental Control Devices

Exhibit 5-31

Major Elements of GNOCIS

expected, excess oxygen level had considerable effect on

both NOx

 and LOI. The results showed that there is some

flexibility in selecting the optimum operating point and

making tradeoffs between NOx

 emissions and fly ash

LOI; however, much of the variation was the result of

changes in excess oxygen. This can be more clearly seen

in Exhibit 5-29 in which all sensitivities are plotted. This

exhibit shows that for excess oxygen, mill bias, inner

register, and sliding tip, any adjustments to reduce NOx

emissions are at the expense of increased fly ash LOI. In

contrast, the slope of the outer register characteristic

suggests improvement in both NOx

 emissions and LOI

can be achieved by adjustment of this damper. However,

due to the relatively small impact of the outer register

adjustment on both NOx

 and LOI, it is likely the positive

NOx

/LOI slope is an artifact of process noise.

A subsidiary goal of the project was to evaluate

advanced instrumentation and controls (I&C) as applied

to combustion control. The need for more sophisticated

I&C equipment is illustrated in Exhibit 5-30. There are

tradeoffs in boiler operation, e.g., as excess air increases,

NOx

 increases, LOI decreases, and boiler losses increase.

The goal is to find and maintain an

optimal operating condition. However,

what is optimal at full load is not optimal at part load. The I&C systems

tested at Plant Hammond included

GNOCIS and carbon-in-ash analyzers.

The GNOCIS software applies an

optimizing procedure to identify the best

set points for the plant, which are implemented automatically without operator

intervention (closed-loop), or conveyed

to the plant operators for implementation (open-loop). The major elements of

GNOCIS are shown in Exhibit 5-31.

SCS has employed GNOCIS in both open-loop

advisory and closed-loop supervisory modes. The system

has provided advice that reduced NOx

 emissions by 10-

15% at full load. GNOCIS provided advice that reduced

fly ash LOI by 1-3 percentage points and improved boiler

efficiency by 0.5 percentage points.

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

and Clyde-Sturtevant SEKAM. The monitors

seemed to represent LOI trends well

by responding in the correct direction and provided important and

timely information on combustion

performance.

Environmental

As shown in Exhibit 5-32, the

AOFA, LNBs, and LNB/AOFA

provide a long-term full load NOx

reduction of 24, 48, and 68%, respectively. The load-weighted

average of NOx

 emission reductions

was 14, 48, and 63%, respectively,

for AOFA, LNB, LNB/AOFA. Although the LNB/AOFA NOx

 level

represents a 68% reduction from

baseline levels, a substantial portion of the incremental

change in NOx

 emissions between the LNB and the LNB/

AOFA configurations is the result of operational changes

and is not the result of adding AOFA.

A total of 63 days of valid long-term NOx

 emissions

data were collected during the LNB/AOFA test phase.

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

 emissions are approximately 0.40 lb/106

 Btu, which was consistent with earlier short-term test data.

Air toxic testing was conducted for AOFA and LNB/

AOFA operation. There was not a significant difference Exhibit 5-29

NOx vs. LOI Tests–All Sensitivities

Exhibit 5-30

Typical Trade-Offs in Boiler Optimization
Environmental Control Devices Program Update 1998 5-69

in emissions of trace metals, acid gases, and volatile

organic compounds for the two tests. There was a slight

downward trend, however, in emissions during LNB/

AOFA operation. For elements associated with particulate matter, ten (barium, beryllium, chromium, cobalt,

copper, lead, manganese, nickel, phosphorus, and vanadium) show lower mean emissions during LNB/AOFA

operation; only two (arsenic and cadmium) show higher

mean emissions during LNB/AOFA operation. Total

particulate matter emissions were also lower during LNB/

AOFA operation; however, this was more an indication of

ESP performance rather than burner configuration.

Economic

Estimated capital costs for a commercial 500 MWe wallfired installation are: AOFA—$8.8/kW, LNB—$10.0/

kW, and GNOCIS—$0.5/kW. Annual O&M costs and

NOx

 reductions depend on the assumed load profile.

Based on the actual load profile observed in the testing,

the estimated annual O&M cost increase for LNB and

AOFA is $333,351. Efficiency is decreased by 1.3 percent, and the NOx

 reduction is 68 percent of baseline, or

11,615 tons/year. The capital cost is $8,300,000 and the

calculated cost of NOx removed is $86/ton.

The addition of GNOCIS to the same unit, using the

actual load profile observed in the testing, results in a

range of costs depending on whether the unit is operated

to maximize NOx

 removal, efficiency, or LOI. For the

maximum NOx

 removal case, the efficiency is improved

by 0.6 percent, the annual O&M cost is decreased by

$228,058, the incremental NOx

 reduction is 11 percent

(834 tons/year), and the capital cost is $250,000. The

calculated cost per ton of NOx

 removed is -$299.

Commercial Applications

The technology is applicable to the 422 existing preNSPS wall-fired boilers in the United States, which burn

a variety of coals. The GNOCIS technology is applicable

to all fossil fuel-fired boilers, including units fired with

natural gas and units co-firing coal and natural gas.

The host has retained the technologies for

commercial use. Foster Wheeler has equipped 86

boilers with low-NOx

 burner technology (51

domestic and 35 international)—1,800 burners

for over 30,000 MWe capacity. Some 19

GNOCIS neural-network control projects are

underway and another 17 projects are expected in

1999.

Contacts

John N. Sorge, (205) 257-7426

ICCT Project Manager

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

jnsorge@southernco.com

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

lawrence.saroff@hq.doe.gov

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

jlonga@fetc.doe.gov

References

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

Oxide (NOx

) Emissions from Coal-Fired Boilers–

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

May 24, 1996.

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

Oxide Emissions from Coal-Fired Boilers [Advanced

Digital Control/Optimization Phase]. Report No.

DOE/PC/89651-T22. Southern Company Services,

Inc. January 1995. (Available from NTIS as

DE95017742.)

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

Oxide (NOx

) Emissions from Coal-Fired Boilers; Field

Exhibit 5-32

Performance Test Results

Chemical Emissions Monitoring; Overfire Air and

Overfire Air/Low-NOx

 Burner Operation: Final Report. Report No. DOE/PC/89651-T16. Southern

Company Services, Inc. January 1993. (Available

from NTIS as DE95006352.)

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

Oxide (NOx

) Emissions from Coal-Fired Boilers–

Phase 2 Overfire Air Tests. Southern Company Services, Inc. and Energy Technology Consultants. Submitted to DOE on August 27, 1992.

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

Oxide (NOx

) Emissions from Coal-Fired Boilers–

Phase I Baseline Tests Report. Southern Company

Services, Inc. and Energy Technology Consultants.

Submitted to DOE on September 9, 1991.

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

Oxide (NOx

) Emissions from Coal-Fired Boilers–

Phases 4—Digital Control System and Optimization.

Southern Company Services, Inc. September 1998.
5-70 Program Update 1998 Environmental Control Devices
Environmental Control Devices

Combined SO2/NO

x

Control Technologies
5-72 Program Update 1998 Environmental Control Devices

Coals

Pittsburgh, Freeport, and Kittanning Coals; 1.5, 2.9 and

4.0% sulfur, respectively.

Project Funding

Total project cost $158,607,807 100%

DOE 45,000,000 28

Participant 113,607,807 72

Project Objective

To demonstrate high sulfur capture efficiency and NOx

and particulate control at minimum power requirements,

zero waste water discharge, and the production of

byproducts in lieu of wastes.

Technology/Project Description

The formic acid enhanced S-H-U process is designed to

remove up to 98% SO2

 at high sorbent utilization rates.

Environmental Control Devices

Combined SO2 /NOx Control Technologies

Milliken Clean Coal

Technology Demonstration

Project

Project completed.

Participant

New York State Electric & Gas Corporation

Additional Team Members

New York State Energy Research and Development

Authority—cofunder

Empire State Electric Energy Research Corporation—

cofunder

Consolidation Coal Company—technical consultant

Saarberg-Hölter-Umwelttechnik, GmbH (S-H-U)—technology supplier

The Stebbins Engineering and Manufacturing

Company—technology supplier

ABB Air Preheater, Inc.—technology supplier

DHR Technologies, Inc. (DHR)—operator of advisor

system

Location

Lansing, Tompkins County, NY (New York State Electric

& Gas Corporation’s Milliken Station, Unit Nos. 1 and 2)

Technology

Flue gas cleanup using S-H-U formic-acid-enhanced, wet

limestone scrubber technology; ABB Combustion

Engineering’s Low-NOx

 Concentric Firing System

(LNCFSTM) Level III; Stebbins’ tile-lined split-module

absorber; ABB Air Preheater’s heat-pipe air preheater;

and DHR’s PEOATM Control System.

Plant Capacity/Production

300-MWe

LNCFS is a trademark of ABB Combustion Engineering, Inc.

PEOA is a trademark of DHR Technologies, Inc.

The Stebbins tile-line, split-module reinforced concrete

absorber vessel provides superior corrosion and abrasion

resistance. Placement below the stack saves space and

provides operational flexibility.

NOx

 emissions are controlled by LNCFS IIITMlowNOx

 burners and by micronized coal reburning. The

LNCFS IIITM low-NOx

 burners are integrated into the

Milliken units. See Micronized Coal Reburning Demonstration for NOx

 Control for another CCT Program project

at this unit.

A heat-pipe air preheater is integrated to increase

boiler efficiency by reducing both air leakage and the air

preheater’s flue gas exit temperature. To enhance boiler

efficiency and emissions reductions, DHR’s Plant Emission Optimization Advisor (PEOATM) provides state-ofthe-art artificial-intelligence-based control of key boiler

and plant operating parameters.

AIR

COAL

SOLID

WASTE

ASH TO DISPOSAL

ELETR OSTATIC

PRECIPITATO R

ASH TO DISPOSAL

ASH

COMMERCIAL-GRADE

CALCIUM C HLORIDE

ELECTRO STATIC

PR EC IP ITATO R

COAL

ASH

AIR

UNIT #2

BOILER

HOT FLUE

GAS INLET

COOL FLUE

GAS OUTLET

HEAT-PIPE

AIR-HEATER SYSTEM

HOT 

COMBUSTION

AIR OUTLET

UNIT #1

BOILER

AIR

PREHEATER

(REFURBISHED)

ELECTRO STATIC

PR EC IP ITATO R

COLD COMBUSTION

AIR INLET

FGD BLOWDOWN

TREATMENT

& RECYCLE

COMMERCIAL-GRADE

GYPSUM

LIM ESTONE

PR EPARATIO N

AND

HANDLING

SPLIT

MODULE

ABSORBER

BELOW STACK

FLUE GAS

OUT

OF STACK

FLUE

GAS

GYPSUM

DEWATERING /

HANDLING

CCOFA REBURNING

OF MICRONIZED

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

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Program Update 1998 5-73

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

Ground breaking/construction started 4/93

Design completed 4/93

NEPA process completed

(EA) 8/18/93

3/99

Operation completed 6/98

Project completed/final report issued 3/99*

Operation initiated on Unit 2 1/95

6/95

Design and Construction

Environmental

monitoring

plan completed

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

Construction completed 6/95

Results Summary

Environmental

• The maximum SO2 removal demonstrated has been

98% with all seven recycle pumps operating and using

formic acid. The maximum SO2

 removal without

formic acid has been 95%.

• The difference in SO2

 removal between the two limestone grind sizes tested (90%–325 mesh and 90%–170

mesh) while using low sulfur coal was a minimum of

2.6 percentage points.

• The SO2

 removal efficiency was greater than the design during the high velocity test of the cocurrent

scrubber section up to a liquid-to-gas ratio of 110.

• The cocurrent pumps had no measurable effect on

pressure drop, whereas the countercurrent pumps

significantly increased the scrubber pressure drop.

The average effect of each countercurrent header was

to increase pressure drop by 0.45 inches water column

(WC) in the design flow tests and 0.64 inches WC in

the high velocity tests.

• Testing of the LNCFSTM III indicated NOx

 emissions

of 0.39 lb/106

 Btu (compared to 0.61 lb/106 Btu for the

original burners).

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

boiler load, during the validation tests (when overfire

air limitations were relaxed) the LOI dropped by 0.7 to

1.7 percentage points, with a minor effect on NOx

emissions.

• The NOxOUT technology at Seward Station successfully demonstrated a 42% reduction NOx

 emission

reduction from a baseline of 0.78 lb/106

 Btu to 0.45 lb/

106

 Btu.

Operational

• Performance of the modified ESP exceeded that of the

original ESPs at lower power consumption.

• Boiler efficiency was 88.3–88.5% for LNCFSTM III,

compared to a baseline of 89.3–89.6%.

• Air filtration is low for both heat pipes. The unaccounted for air leakage rates at full load ranged between 2.0–2.4%.

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

less than the design maximum of 3.65 inches WC.

The primary side pressure drops for both heat pipes

were less than the design maximum of 3.6 inches WC.

The secondary air side pressure drops for both heat

pipes were less than the design maximum of 5.35

inches WC.

Economic

• No economic data available.

Project Summary

The test plan was developed to cover all of the new technologies used in the project. In addition to the technologies tested, the project demonstrated that existing technologies can be used in conjunction with new processes

to produce saleable by-products. Supplemental monitoring has provided operation and performance data illustrat-
5-74 Program Update 1998 Environmental Control Devices

ing the success of these processes under a variety of operating conditions. Generally, each test program was divided

into four independent subtest: diagnostic, performance,

long-term, and validation.

Environmental Performance

The S-H-U FGD system was tested over a 36 month period. Typical evaluations included SO2

 removal efficiency,

power consumption, process economics, load following

capability, reagent utilization, by-product quality, and

additive effects. Parametric testing included formic acid

concentration, L/G ratio, mass transfer, coal sulfur content, and flue gas velocity. Not all test results are currently available. The maximum SO2

 removal demonstrated was 98% with all seven recycle pumps operating

and using formic acid and the maximum SO2

 removal

without formic acid was 95%. The difference in SO2

removal between the two limestone grind sizes tested

(90%–325 mesh and 90%–170 mesh while using low

sulfur coal) was a minimum of 2.6 percentage points as

shown in Exhibit 5-33. The SO2

 removal efficiency was

greater than the design during the high velocity test of the

cocurrent scrubber section up to a liquid-to-gas ratio of

110. The cocurrent pumps had no measurable effect on

pressure drop, whereas the countercurrent pumps significantly increased the scrubber pressure drop. As seen in

Exhibit 5-34, the average effect of each countercurrent

header was to increase pressure drop by 0.45 inches water

column (WC) in the design flow tests and 0.64 inches

WC in the high velocity tests.

Performance of the modified ESP exceeded that of

the original ESPs at lower power consumption. The

average penetration before the ESP modification was

0.22% and decreased to 0.12% after the modifications.

At full boiler load (145–150 MWe) and 3.0–3.5%

economizer O2

, the

LNCFSTM III lowered NOx

emissions from a baseline

of .064 lb/106

 Btu to 0.39

lb/106

 Btu (39% reduction).

At 80-90 MWe boiler load

and 4.3–5.0% economizer

O2

, the LNCFSTM III lowered NOx

 emissions from a

baseline of 0.58 lb/106

 Btu

to 0.41 lb/106

 Btu (29%

reduction). With LNCFSTM

III, LOI was maintained

below 4% and CO emissions did not increase.

Operational

Performance

The S-H-U FGD system

performance goal of 98%

SO2

 removal efficiency was

achieved. Similarly, the

objective of producing a

marketable gypsum by-product from the FGD system was

achieved. The test results indicate the gypsum produced

can be maintained at a purity level exceeding 95% with a

chloride level less than 100 ppm. However, the goal of

producing a marketable calcium chloride solution from

the FGD blowdown stream was not achieved. FGD availability for the test period was 99.9%.

The modified ESP performed better than the original

ESP at a lower power use. The total voltage•current

product (V•I) for ESPs is directly proportional to the total

power requirement. The modified ESP 75% of the V•I

demand of the original ESPs. The modified ESP has a

smaller plant footprint with fewer internals and a smaller

SCA. Total internal plate area is less than one-half that of

the original ESPs, tending to lower capital costs.

Boiler efficiency was 88.3–88.5% for LNCFSTM III,

compared to a baseline of 89.3–89.6%. The lower efficiency was attributed to higher post retrofit flue gas O2

and higher stack temperatures which accompanied the air

heater retrofit. When LNCFSTM III and baseline conditions are compared, boiler efficiency with LNCFSTM III

was 0.2 percentage points higher than baseline.

The heat pipe were tested in accordance with ASME

Power test Code for Air Heaters 4.3. Air filtration is low

for both heat pipes. The unaccounted for air leakage rates

at full load ranged between 2.0–2.4%. The tests showed

that the flue gas side pressure loss for both heat pipes was

less than the design maximum of 3.65 inches WC. The

primary side pressure drops for both heat pipes were less

than the design maximum of 3.6 inches WC. The secondary air side pressure drops for both heat pipes were less

than the design maximum of 5.35 inches WC.

The main problem with the NOx

OUT technology was

with ammonia slip, which is a byproduct of the urea

injected into the boiler. The ammonia reacts with sulfur

trioxide in the flue gas to form ammonium bisulfate in the

air heaters. If the ammonia slip is not consistently maintained below 2 ppm significant pluggage of the air heater

can result in a short period of time.

Exhibit 5-33

Effect of Limestone Grind
Environmental Control Devices Program Update 1998 5-75

Economic Performance

Economic data is not yet available.

Commercial Applications

The S-H-U process, stebbins absorber module, NOx

OUT®

system, and heat-pipe air preheater are applicable to

virtually all power plants. The space-saving design features of the technologies, combined with the production

of marketable byproducts, offer significant incentives to

generating stations with limited space.

There have been four commercial sales of the

PEOATM system. Commercial sales of the NOx

OUT®

system have been made to at least a dozen companies and

a licensing agreement has been signed with Wheelabrator.

More than 20 units have been sold in the United States,

Taiwan, and Korea. Several of these sales are for a derivative reduction system. Applications span industrial

and utility boilers, municipal solid waste incinerators,

wood-waste-fired furnaces, and steel production.

Contacts

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

New York State Electric & Gas Corporation

Corporate Drive — Kirkwood Industrial Park

P.O. Box 5224

Binghamton, NY 13902-5224

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

lawrence.saroff@hq.doe.gov

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

References

• Comprehensive Report to Congress on the Clean Coal

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

Corporation. Report No. DOE/FE-0265P. U.S. Department of Energy. September 1992. (Available from

NTIS as DE93001756.)

• Milliken Clean Coal Technology Demonstration

Project. Harvilla, James et al. Sixth Clean Coal Technology Conference: Clean Coal for the 21st Century —

What Will It Take? Volume II - Technical Papers.

CONF-980410— VOL II. April 28-May 1, 1998.

Exhibit 5-34

Pressure Drop vs.

Countercurrent Headers
5-76 Program Update 1998 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

Gas Research Institute—cofunder

Electric Power Research Institute—cofunder

W.R. Grace and Company—cofunder

Morrison Knudsen-Ferguson—engineer

Richmond Power & Light (RP&L)—host

Location

Not applicable

Technology

NOXSO Corporation’s dry, regenerable flue gas cleanup

process

Plant Capacity/Production

Not applicable

Coal

Medium- to high-sulfur coals

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 can be 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%.

Project Status/Accomplishments

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. NOXSO signed a conditional Host Site

Agreement with RP&L in January 1998.

On September 22, 1998 NOXSO issued a press

release stating that they have requested the bankruptcy

court to change their filing from a Chapter 11 - Reorganization to Chapter 7 - Liquidation. This change was

prompted by an inability to raise funding for their cost
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

3 4 1 2

Environmental Control Devices Program Update 1998 5-77

share of a continued project. However, the unsecured

creditor committee requested the court keep NOXSO in

Chapter 11.

Commercial Applications

The NOXSO process is applicable for retrofit or new

facilities. The process is suitable for utility and industrial

coal-fired boilers. 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.

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

Alcoa Generating Corp. cancelled

host site agreement 2/97

Novation of cooperative agreement with NOXSO Corp. 8/94

Selected Alcoa host site 8/94

Project definition phase completed 10/94

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

Identified conditional host site,

RP&L 1/98

Schedule pending action

in bankruptcy court
5-78 Program Update 1998 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

3 4 1 2

Environmental Control Devices Program Update 1998 5-79

• 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

$219/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
5-80 Program Update 1998 Environmental Control Devices

The bottom portion of the SO2 converter catalyst, with

the catalyst dust collector hopper mounted on steel rails

(center), is shown.

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
Environmental Control Devices Program Update 1998 5-81

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.

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

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

1995 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) 693-7550

ABB Environmental Systems

1409 Center Port Boulevard

Knoxville, TN 37932

(423) 694-5213 (fax)

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

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

References

• Final Report Volume II: Project Performance and

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

90PC89C55.

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

DOE/PC/89655-T21. (Available from NTIS as

DE96050312.)

• 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.)

• 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.)
5-82 Program Update 1998 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.

Humidification of the flue gas before it enters an ESP is DRB-XCL is a registered trademark of The Babcock & Wilcox Company.

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

humidifica-tion 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 No. 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

3 4 1 2

Environmental Control Devices Program Update 1998 5-83

• 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% (1992 $). Annual

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

DRB-XCL® 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

levelized costs (15-year) for this range of conditions

were $392–791/ton of SO2

 removed.

• 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% (1992 $). Annualized

levelized costs (15-year) for this range of conditions

were $482–943/ton of SO2

 removed.

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
5-84 Program Update 1998 Environmental Control Devices

Exhibit 5-35

LIMB SO2 Removal Efficiencies

(Percent)

Nominal Coal Sulfur Content

Sorbent 3.8% 3.0% 1.6%

Ligno lime 61 63 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 molar ratio 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.

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 molar

ratio 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 5-35 summarizes SO2

 removal efficiencies for the range of sorbents

and coals tested.

While injecting commercial limestone with 80%

of the particles less than 44 microns in size, 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-feet 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-feet

level and similar removals were observed. Removal

efficiencies while injecting at these levels were about 5%

higher than while injecting sorbent at the 191-feet 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

molar ratio, Na/Ca molar ratio, and approach-to-adiabatic-saturation—were evaluated in short-term (6–8-hour)

parametric tests and longer term (1–11-day) process operability tests.

The test program demonstrated that the Coolside

process routinely achieved 70% SO2

 removal at design

conditions of 2.0 Ca/S molar ratio, 0.2 Na/Ca molar ratio,

and 20 oF approach-to-adiabatic-saturation temperature

using commercially available hydrated lime. Coolside

SO2

 removal depended on Ca/S molar ratio, Na/Ca molar

ratio, approach-to-adiabatic-saturation, 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
Environmental Control Devices Program Update 1998 5-85

Exhibit 5-36

Capital Cost Comparison

(1992 $/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 5-37

Annual Levelized Cost Comparison

(1992 $/Ton of SO2 Removed)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100-MWe 150-MWe

1.5 791 943 1418 653 797 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

molar ratio, 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

method was used. Exhibits 5-36

and 5-37 summarize the 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.

LIMB has been sold to an independent power plant

in Canada. Babcock & Wilcox has signed 85 contracts

(61 domestic, 24 foreign) for DLB-XCL® low-NOx

 burners,

representing 1,515 burners for 20,396-MWe of capacity.

Contacts

Paul Nolan, (330) 860-1074

The Babcock & Wilcox Company

20 S. Van Buren Avenue

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.) 22% at 0.5 available Ca/S molar ratio and 18 oF approach-to-adiabatic-saturation. The observed SO2

 removal with simultaneous recycle and fresh sorbent feed

was 40% at 0.8 fresh Ca/S molar ratio, 0.2 fresh Na/Ca
5-86 Program Update 1998 Environmental Control Devices

9/95

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 (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 average

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

3 4 1 2

Environmental Control Devices Program Update 1998 5-87

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 molar 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 molar ratio of 1.0.

• Injection of calcium-based sorbents directly upstream

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

temperatures up to 1,200 oF.

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

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

• Air toxic removal efficiency was comparable to that of

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

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

Economic

• Capital cost in 1994 constant dollars for a 250-MWe

retrofit was $233/kW, assuming 3.5% sulfur coal and

baseline NOx

 generation of 1.2 lb/106 Btu.

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.

9/95
5-88 Program Update 1998 Environmental Control Devices

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.

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

ratio of 2.0 at a significantly reduced baghouse temperature of 450–460 oF. SO2

 emissions while burning a 3–4%

sulfur coal were reduced to less than 1.2 lb/106

 Btu with

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

/S molar ratio

less than 1.0.

To capture NOx

, ammonia was injected between the

sorbent injection point and the baghouse. The ammonia

and NOx

 reacted to form nitrogen and water in the presence of Norton Company’s NC-300 series zeolite SCR

catalyst. With the catalyst being located inside the filter

bags, 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

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.
Environmental Control Devices Program Update 1998 5-89

Workers lower one of the catalyst holder tubes into a

mounting plate in the penthouse of the high-temperature

baghouse.

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

(1994 constant dollars), 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

Dot K. Johnson, (330) 829-7395

The Babcock & Wilcox Company

20 South Van Buren Avenue

Barberton, OH 44203

(330) 829-7801 (fax)

dot.k.johnson@mcdermott.com

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

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

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.)
5-90 Program Update 1998 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 No. 1)

Springfield, Sangamon County, IL (City Water, Light and

Power’s Lakeside Station, Unit No. 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 highsulfur 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. Lime (Ca(OH)2

)

was the sorbent tested at both sites. 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

PromiSORB is a trademark of Energy and Environmental Research
1 2 3 4 1 2 3 4 1 2 3 4 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

** Years omitted

3 4 1 2

Environmental Control Devices Program Update 1998 5-91

to quantify the reductions in NOx and SO2 emissions, the

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

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

calcium-to-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.

Preaward Design and Construction

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1998

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

9/98

Project completed/

final report issued 9/98

Operation completed,

Lakeside 10/94

Operation

Restoration completed,

Lakeside 12/95

• There was no change in boiler tube wastage, tube

metallurgy, or projected boiler life.

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.

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

**

3 4
5-92 Program Update 1998 Environmental Control Devices

The flexible lime-sorbent distribution lines lead from

the sorbent splitter to the top of the cyclone-fired boiler at

Lakeside Station.

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 carbon-to-hydrogen 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 5-26%. 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 molar ratio of 2.0, 44%

SO2

 reduction was achieved at full load (33-MWe); 38%

SO2

 reduction was achieved at mid-load (25-MWe); and

32% SO2

 reduction was achieved at low load (20-MWe).

In the GR–SI optimization tests, the two technologies were integrated. Modifications were made to the

reburning fuel injection nozzles based on the results 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

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
Environmental Control Devices Program Update 1998 5-93

The natural gas injector was installed

on the corner of Hennepin Station’s

tangentially fired boiler.

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.

Illinois Power has retained the gas-reburning

system and City Water, Light & Power has retained the full technology for commercial use.

The project was one of two receiving the Air and

Waste Management Association’s 1997 J. Deanne

Sensenbaugh Award.

Contacts

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

Energy and Environmental Research Corporation

18 Mason

Irvine, CA 92618

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

Jerry L. Hebb, FETC, (412) 892-6079

References

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 1–Program Overview.

February 1997.

• Enhancing the Use of Coals by Gas Reburning–Sorbent Injection: Volume 4: Gas Reburning Sorbent

Injection at Lakeside Unit 7, City Water, Light and

Power, Springfield, Illinois. Final Report. Energy and

Environmental Research Corporation. March 1996.

Report No. DOE/PC/79796-T48-Vol.4. (Available

from NTIS as DE96011869.

• Enhancing the Use of Coals by Gas Reburning–

Sorbent Injection; Long Term Testing Period, September 1, 1991–January 15, 1993. Report No. DOE/PC/

79796-T40. Energy and Environmental 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/FE-0087. U.S. Department of Energy. May

1987. (Available from NTIS as DE87010815.)
5-94 Program Update 1998 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.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

** Years omitted

3 4 1 2

Environmental Control Devices Program Update 1998 5-95

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1999

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 molar ratio of

2.0.

• Sodium bicarbonate injection before the air heater

demonstrated a long-term SO2

 removal of approximately 70% at a normalized stoichiometric ratio

(NSR) of 1.0.

• Sodium sesquicarbonate injection ahead of the fabric

filter achieved 70% SO2

 removal at an NSR of 2.0.

• NO2

 emissions were generally higher when using

sodium biocarbonate than when using 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 Unit No. 4 operated more than 34,000 hours

after combustion modifications were complete.

2/99

Operation completed 12/96

Cooperative agreement awarded 3/11/91

Project completed/

final report issued

2/99*

• 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.

**
5-96 Program Update 1998 Environmental Control Devices

sootblower ports. Each lance was nominally 4 inches in

diameter and approximately 20 feet in length with a

single row of nine injection nozzles. Each injection

nozzle consisted of a fixed air orifice and a replaceable

liquid orifice. The ability to change orifices allowed not

only for removal and cleaning but adjustment of the

injection pattern along the length of the lance in order to

compensate for any significant mal distributions of flue

gas velocity, temperature, or baseline NOx

 concentration.

One of the key features of the ARIL system was its ability

to rotate, thus providing a high degree of flexibility in

optimizing SNCR performance.

The SO2

 control system was a direct sorbent injection system that could inject either calcium- or sodiumbased reagents into the flue gas upstream of the fabric

filter. Sorbent was injected into three locations: (1) air

heater exit where the temperature was approximately

260 oF, (2) air heater entrance where the temperature was

approximately 600 oF, or (3) the boiler economizer region

where the flue gas temperature was approximately

1,000 oF. To improve SO2

 removal with calcium hydroxide, a humidification system capable of achieving 20 oF

approach-to-saturation was installed approximately 100

feet ahead of the fabric filter. The system designed by

Babcock & Wilcox included 84 I-Jet nozzles that 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

(60–110-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

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 boiler

roof. The low-NOx combustion system also incorporated

three Babcock & Wilcox dual-zone NOx ports added to

each side of the furnace approximately 20 feet 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, loadfollowing performance was compromised.

In order to achieve the desirable NOx

 reduction at

low loads, two alternatives were explored. The first

approach was to substitute ammonia for urea. It was

shown that ammonia was more effective than urea at lowloads. 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

Public Service Company of Colorado demonstrated

low-NOx

 burners, in-duct sorbent injection, and SNCR at

Arapahoe Station near Denver.
Environmental Control Devices Program Update 1998 5-97

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

The Arapahoe Unit No. 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 learned”

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) 571-7113

Utility Engineering

550 15th Street, Suite 800

Denver, CO 80202

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

Jerry L. Hebb, FETC, (412) 892-6079

References

• Hunt, Terry, et al. “Integrated Dry NOx

/SO2 Emissions

Control System: Performance Summary.” Fifth

Annual Clean Coal Technology Conference: Technical Papers. January 1997.

• Integrated Dry NOx

/SO2 Emissions Control System

Calcium-Based Dry Sorbent Injection: Test Report,

April 30–November 2, 1993. Report No. DOE/PC/

90550-T14. Fossil Energy Research Corporation and

Public Service Company of Colorado. December

1994. (Available from NTIS as DE95007932.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Integrated Dry NOx

/SO2 Emission Control System. Public Service Company of

Colorado. Report No. DOE/FE-0212P. U.S. Department of Energy. January 1991. (Available from NTIS

as DE91008624.)
5-98 Program Update 1998 Environmental Control Devices
Advanced Electric Power Generation

Fluidized-Bed Combustion
5-100 Program Update 1998 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB

Demonstration Project

Participant

City of Lakeland, Lakeland Electric

Additional Team Members

Foster Wheeler Energy Corporation—supplier of pressurized circulating fluidized-bed (PCFB) combustor and

heat exchanger and engineer

Siemens Westinghouse Power Corporation—supplier of

hot gas filter, gas turbine, and steam turbine

Location

Lakeland, Polk County, FL (Lakeland’s McIntosh Power

Station, Unit No. 4)

Technology

Foster Wheeler’s PCFB technology integrated with

Siemens Westinghouse’s hot gas particulate filter system

(HGPFS) and power generation technologies

Plant Capacity/Production

145-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 Siemans Westinghouse’s ceramic candle

type hot gas filter and power generation technologies,

which represent a cost-effective, high-efficiency, lowemissions means of adding generating capacity at

greenfield sites or in repowering applications.

Technology/Project Description

The project resulted from a restructuring of the DMEC-1

PCFB Demonstration Project awarded under the third

solicitation. In the first of the two Lakeland projects,

McIntosh Unit No. 4 is being constructed with a PCFB

combustor adjacent to the existing Unit No. 3. In the

second project, the integration of a gasifier and topping

combustor (topping cycle) with the PCFB technology will

be demonstrated (see McIntosh Unit 4B Topped PCFB

Demonstration Project).

Coal and limestone are mixed and fed into the combustion chamber. 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 ceramic candle type HGPFS

where the particulates are removed. The hot gas leaving

the HGPFS is expanded through a gas turbine, which is

based on a Siemens V64.3 gas turbine. 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

5–10% of the gross power is derived from the gas turbine, with the steam turbine contributing the balance.

The unit is being designed to burn a range of coals,

including the current Eastern Kentucky coal burned in

Unit No. 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.

The project also includes a 104-MWe spare atmospheric fluidized-bed unit that can be fired on coal or

char from the carbonizer and will replace the PCFB unit
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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 1998 5-101

during times of PCFB unavailability, allowing various

modes of operation.

Project Status/Accomplishments

On December 19, 1997, a Cooperative Agreement modification was signed implementing the project restructuring from DMEC-1 to the City of Lakeland. The Lakeland

City Council gave approval for the 10 year plan of Lakeland Electric (formerly Department of Electric & Water

Utilities), which included this project, in September 1997.

The project schedule anticipates the start of commercial

operation of the PCFB (McIntosh 4A) in the winter of

2002. In parallel with the first two 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 2004.

Negotiations continue between Lakeland and Foster

Wheeler on the Engineer-Procure-Construct (EPC) proposal for the technology island.

 Recent efforts focused on testing of the HGPFS,

which is critical to system performance. Silicon carbide

candle filters proved effective under conditions simulating those of the demonstration unit. At both 1,550 oF and

1,400 oF, the candle filters performed for over 1,000

hours at design levels without evidence of ash bridging

or structural failure. Three new oxide-based candle

filters showed promise as well. These will undergo further testing because of the potential for reduced cost and

operation at higher temperatures.

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 pressurized bubblingbed fluidized-bed system. PCFB can be used to repower

1991 2000 2001 1996 1997 2002 2003 2004 2005 2006 2007

12/89

DOE selected project

(CCT-III) 12/19/89

Cooperative Agreement

awarded 8/1/91

11/02 11/04

**

**Years omitted

Design and Construction Operation

Design completed 9/00*

Groundbreaking/construction

started 10/00*

NEPA process completed (EIS)

10/00*

Environmental monitoring plan

completed 8/02*

8/91

Operation initiated 11/02*

Preoperational tests initiated 11/02*

Construction completed 11/02* Project completed/

final report issued 11/04*

Operation completed 11/04*

Site change approved

(Lakeland) 10/29/96

Preaward

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 or to repower plants using existing

coal- and waste-handling equipment and steam turbines.

Another advantage for repowering applications is the

compactness of the process due to pressurized operation,

which reduces space requirements per unit of energy

generated.

The projected net heat rate for the system is approximately 9,511 Btu/kWh (based on HHV), which equates to

over 35% 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.

Cooperative Agreement

signed 12/19/97

**
5-102 Program Update 1998 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4B Topped PCFB

Demonstration Project

Participant

City of Lakeland, Lakeland Electric

Additional Team Members

Foster Wheeler Energy Corporation—supplier of

carbonizer; engineer

Siemens Westinghouse Power Corporation—supplier of

topping combustor and high-temperature filter

Location

Lakeland, Polk County, FL (Lakeland’s McIntosh Power

Station, Unit No. 4)

Technology

Fully integrated second-generation PCFB technology with

the addition of a carbonizer island that includes Siemens

Westinghouse’s multi-annular swirl-burner (MASB)

topping combustor

Plant Capacity/Production

93-MWe (net) addition to the 145-MWe (net) McIntosh

4A project

Project Funding

Total project cost $219,635,546 100%

DOE 109,608,507 50

Participant 110,027,039 50

Project Objective

To demonstrate topped PCFB technology in a fully commercial power 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

using a phased approach, Lakeland will be able to

demonstrate both PCFB (McIntosh 4A) and topped

PCFB (McIntosh 4B) technologies in a repowering

application.

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

2,400 °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 93-MWe and

an associated improvement in plant heat rate of approximately 735 Btu/kWh. The coal and limestone

used in McIntosh 4B are the same as those used in

McIntosh 4A.

The 238-MWe plant is expected to have a heat rate
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

**Years omitted

Advanced Electric Power Generation Program Update 1998 5-103

1996 1998

Negotiations continue between Lakeland and

Foster Wheeler on the Engineer-Pressure-Construct

(EPC) proposal for the technology island.

 Recent efforts focused on testing of the HGPFS,

which is critical to system performance. Silicon carbide and alumina/mullite candle filters proved effective

under conditions simulating those of the demonstration unit. At both 1,550 oF and 1,400 oF, the candle

filters performed for over 1,000 hours at design levels

without evidence of ash bridging or structural failure.

Three new oxide-based candle filters showed promise

as well. These will undergo further testing because of

the potential for reduced cost and operation at higher

temperatures.

Commercial Applications

The commercial version of the topped PCFB technology

will have a greenfield net plant efficiency of 45% (which

equates to a heat rate approaching 7,500 Btu/kWh, based

on HHV). In addition to higher plant efficiencies, the

1994 2000 2001 2002 2003 2004 2005 2006 2007

5/93

DOE selected project

(CCT-V) 5/4/93

Cooperative agreement

awarded 7/28/94; effective

8/1/94

Design and Construction

11/04 11/06

Project completed/

final report issued 11/06*

Site change approved Operation completed 11/06*

(Lakeland) 10/29/96

**

Operation

NEPA process completed (EIS) 10/00*

Design initiated 11/02*

Groundbreaking/construction started 9/03*

Design completed 9/03*

Operation initiated 11/04*

Preoperational tests initiated 11/04*

Construction completed 11/04*

Environmental monitoring plan completed 8/04*

8/94

Preaward

of 8,776 Btu/kWh (38.9% efficiency-HHV). Sulfur dioxide capture efficiency rate is 95%. Particulate and NOx

emissions are expected to be 0.02 lb/106 Btu and 0.17 lb/

106

 Btu, respectively. In the final configuration, the gas

turbine will produce 57-MWe and the steam turbine will

produce 181-MWe

Project Status/Accomplishments

On January 29, 1998, a Cooperative Agreement modification was signed implementing the project restructuring

from Four Rivers Energy Partners to the City of Lakeland.

The Lakeland City Council gave approval for the 10 year

plan of Lakeland Electric (formerly Department of Electric & Water Utilities), which included this project, in

September 1997. The project schedule anticipates the

start of commercial operation of the PCFB (McIntosh 4A)

in the winter of 2002. In parallel with the first two 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 2004.

**

Cooperative Agreement signed

1/29/98

plant will (1) have a cost of electricity that is projected

to be 20% lower than that of a conventional pulverizedcoal-fired plant with flue gas desulfurization, (2) meet

emission limits that are half those allowed by NSPS,

(3) operate economically on a wide range of coals, and

(4) be amenable to shop fabrication.

The benefits of improved efficiency include reduced

cost for fuels and a reduction in CO2

 emissions. 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 dis-

**
5-104 Program Update 1998 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

JEA Large-Scale CFB

Combustion Demonstration

Project

Participant

JEA

Additional Team Member

Foster Wheeler Energy Corporation—co-owner and technology supplier

Location

Jacksonville, Duval County, FL (JEA’s Northside Station,

Unit No. 2)

Technology

Foster Wheeler’s atmospheric circulating fluidized-bed

(ACFB) combustor

Plant Capacity/Production

297.5-MWe (gross), 265-MWe (net)

Project Funding

Total project cost $309,096,512 100%

DOE 74,733,633 24

Participant 234,362,679 76

Project Objective

To demonstrate ACFB at 297.5-MWe gross (265-MWe

net) representing a scale-up from previously constructed

facilities; to verify expectations of the technology’s economic, environmental, and technical performance to

provide potential users with the data necessary for evaluating a large-scale ACFB as a commercial alternative; to

accomplish greater than 90% SO2

 removal; and to reduce

NOx

 emissions by 60% when compared with conventional technology.

through the use of a polishing scrubber to be installed

ahead of the particulate control equipment.

Steam is generated in tubes placed along the

combustor’s walls and superheated in tube bundles

placed downstream of the particulate separator to protect

against erosion. The system will produce approximately

2 x106

 lb/hr of main steam at about 2,400 psig and

1,005 oF and 1.73 x 106 lb/hr of reheat steam at 600 psig

and 1,005 oF. The steam will be used in an existing

297.5-MWe (nameplate) steam turbine and its generator.

The heat rate for the retrofit plant is expected to be approximately 9,950 Btu/kWh (34% efficiency).

Technology/Project Description

A circulating fluidized-bed combustor, operating at atmospheric pressure, will be retrofitted into Unit No. 2 of

the Northside Station. Coal or the secondary fuel, petroleum coke, primary air, and a solid sorbent, such as limestone, are introduced into the lower part of the combustor

where initial combustion occurs. As the coal particles

decrease in size due to combustion, they are carried

higher in the combustor when secondary air is introduced. As the coal particles continue to be reduced in

size, the coal, along with some of the sorbent, is carried

out of the combustor, collected in a particle separator,

and recycled to the lower portion of the combustor. Primary sulfur capture is achieved by limestone sorbent in

the bed. However, additional SO2

 capture is achieved
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

**Years omitted

Advanced Electric Power Generation Program Update 1998 5-105

Preoperational tests started 7/01*

Environmental monitoring plan

completed 7/01*

Project Status/Accomplishments

The project was successfully resited to Jacksonville after

York County Energy partners and Metropolitan Edison

Company terminated activities on the ACFB in September 1996. On August 26, 1997, DOE approved the transfer of the ACFB clean coal project from York, PA, to

Jacksonville, FL. On September 29, 1997, DOE signed a

modified cooperative agreement with JEA to cost-share

refurbishment of the first (Unit No. 2) of two units at

Northside Generating Station.

A Public Scoping Meeting on the Environmental

Impact Statement (EIS) was held on December 3, 1997 at

the Northside Station. The draft EIS is being prepared

and will be submitted for review in March 1999.

The project, currently in design, moves atmospheric

fluidized-bed combustion technology to the larger sizes of

utility boilers being considered in capacity additions and

replacements. The nominal 300-MWe demonstration unit

in the JEA project will be more than double the size of

the Nucla unit (110-MWe). Features include an integrated recycle heat exchanger (INTREXTM) in the furnace, steam-cooled cyclones, a parallel pass reheat

control, an SO2

 polishing scrubber, and a fabric filter

for particulate control. Expected environmental performance is 0.17 lb/106

 Btu SO2 (98% reduction), 0.011 lb/

106

 Btu NOx, and 0.017 lb/106 Btu particulates (0.013 lb/

106

 Btu PM10).

Commercial Applications

ACFB technology has good potential for application in

both the industrial and utility sectors, whether for use in

repowering existing plants or in new facilities. ACFB is

attractive for both baseload and dispatchable power

applications because it can be efficiently turned down to

25% of full load. Coal of any sulfur or ash content can

be used, and any type or size of a 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 1997 1999 2000 2001 2002

Preaward

6/89

Project Restructuring Operation

11/90

DOE selected

project (CCT-I)

6/23/89

2003

** **

Cooperative agreement

awarded 11/30/90

Project restructured 6/92

Project resited

(York) 6/93

9/97

Project restructured and resited

(Jacksonville) 8/26/97

** **

5/02 5/04

Design and Construction

NEPA process completed

(EIS York site) 8/11/95

Cooperative agreement modified 9/29/97

Operation initiated

5/02*

Project completed/final report issued 5/04*

Operation completed 5/04*

Design completed

11/00*

Groundbreaking/

construction started 10/99*

NEPA process completed

(EIS Jacksonville site) 10/99*

In its commercial configuration, ACFB technology

offers several potential benefits when compared to

conventional pulverized coal-fired systems: lower capital costs; reduced SO2

 and NOx emissions at lower

costs; higher combustion efficiency; and dry, granular

solid material that is easily disposed of or potentially

Construction completed

3/02*
5-106 Program Update 1998 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

Tidd PFBC Demonstration

Project

Project completed.

Participant

The Ohio Power Company

Additional Team Members

American Electric Power Service Corporation—

designer, constructor, and manager

The Babcock & Wilcox Company—technology supplier

Ohio Coal Development Office—cofunder

Location

Brilliant, Jefferson County, OH (Ohio Power Company’s

Tidd Plant, Unit No. 1)

Technology

The Babcock & Wilcox Company’s pressurized fluidizedbed combustion (PFBC) system (under license from ABB

Carbon)

Plant Capacity/Production

70-MWe

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 project represented a 13:1 scaleup from the

pilot facility.

The boiler, cyclones, bed reinjection vessels, and

associated hardware were encapsulated in a pressure

vessel 45 feet in diameter and 70 feet high. The facility

was designed so that one-seventh of the hot gases produced could be routed to an Advanced Particulate Filter

(APF).

The Tidd facility is a bubbling fluidized-bed combustion process operating at 12 atm (175 psi). Pressurized combustion air is supplied by the turbine compressor

to fluidize the bed material, which consists of a coalwater fuel paste, coal ash, and a dolomite or limestone

sorbent. Dolomite or limestone in the bed reacts with

sulfur to form calcium sulfate, a dry, granular bed-ash

material, which is easily disposed of or is usable as a byproduct. A low bed-temperature of about 1,600 oF limits

NOx

 formation.

The hot combustion gases exit the bed vessel with

entrained ash particles, 98% of which are removed when

the gases pass through cyclones. The cleaned gases are

then expanded through a 15-MWe gas turbine. Heat

from the gases exiting the turbine, combined with heat

from a tube bundle in the fluid bed, generates steam to

drive an existing 55-MWe steam turbine.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Program Update 1998 5-107

Results Summary

Environmental

• Sorbent size had the greatest effect on SO2 removal

efficiency as well as stabilization and heat transfer

characteristics of the fluidized-bed.

• SO2

 removal efficiency of 90% was achieved at full

load with a calcium-to-sulfur (Ca/S) molar ratio of

1.14 and temperature of 1,580 oF.

• SO2

 removal efficiency of 95% was achieved at full

load with a Ca/S molar ratio of 1.5 and temperature of

1,580 oF.

• NOx

 emissions were 0.15–0.33 lb/106 Btu.

• CO emissions were less than 0.01 lb/106

 Btu.

• Particulate emissions were less than 0.02 lb/106 Btu.

Operational

• Combustion efficiency ranged from an average 99.3%

at low bed levels to an average 99.5% at moderate to

full bed levels.

• Heat rate was 10,280 Btu/kWh (HHV-grass output)

(33.2% efficiency) because the unit was small and no

attempt was made to optimize heat recovery.

• An Advanced Particulate Filter (APF), using a silicon

carbide candle filter array, achieved 99.99% filtration

efficiency on a mass basis.

• PFBC boiler demonstrated commercial readiness.

• ASEA Stal GT-35P gas turbine proved capable of

operating commercially in a PFBC flue gas environment.

Economic

• The Tidd plant was a relatively small-scale facility, as

such, detailed economics were not prepared as part of

this project.

• A recent cost estimate performed on Japan’s 360-MWe

PFBC Karita Plant, due to commence operation in

1999, projected a capital cost of $1,263/kW (1997$).

Project Summary

The Tidd PFBC technology is a bubbling fluidized-bed

combustion process operating at 12 atmospheres

(175 psi). Fluidized combustion is inherently efficient.

A pressurized environment further enhances combustion

efficiency, allowing very low temperatures that mitigate

thermal NOx

 generation, flue gas/sorbent reactions that

increase sorbent utilization, and flue gas energy that is

used to drive a gas turbine. The latter contributed significantly to system efficiency because of the high efficiency

of gas turbines and the availability of gas turbine exhaust

heat that can be applied to the steam cycle. A bed design

temperature of 1,580 oF was established because it was

the maximum allowable temperature at the gas turbine

inlet and was well below temperatures for coal ash fusion, thermal NOx

 formation, and alkali vaporization.

Coal crushed to 1⁄4 inch or less was injected into the

combustor as a coal/water paste containing 25% water by

weight. Crushed sorbent, either dolomite or limestone,

was injected into the fluidized bed via two pneumatic

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

Design and Construction Operation

3/87

Cooperative agreement awarded 3/20/87

NEPA process completed (MTF) 3/5/87

Environmental monitoring

plan completed 5/25/88

Groundbreaking ceremony 4/6/88

Construction started 12/9/87

Operation initiated 3/91

Preoperational tests started 12/90

Construction completed 12/90

Design completed 12/90

3/91

DOE selected project (CCT-I) 7/24/86

7/86

Preaward

12/95

Project

completed/

final report

issued 12/95

Operation completed 3/95
5-108 Program Update 1998 Advanced Electric Power Generation

gas. Combustion efficiencies averaged 99.5% at moderate to full bed heights, surpassing the design or

expected efficiency of 99.0%.

Using data for typical full-load operation, a heat

rate of 10,280 Btu/kWh (HHV basis) was calculated.

This corresponds to a cycle thermodynamic efficiency

of 33.2% at a point where the cycle produced 70-MWe

of gross electrical power while burning Pittsburgh No.

8 coal. Because the Tidd plant was a repowering application at a comparatively small scale, the measured

efficiency does not represent what would be expected

for a larger utility-scale plant using Tidd technology.

Studies conducted under the PFBC Utility Demonstration Project showed that efficiencies of over 40% are

likely for a larger utility-scale PFBC plant.

The PFBC demonstration at the repowered 70-MWe unit at Ohio

Power’s Tidd Plant led to significant refinements and understanding of

the technology.

feed lines, supplied from two lock hoppers. The sorbent

feed system initially used two injector nozzles but was

modified to add two more for nozzles to enhance

distribution.

In 1992, a 10-MWe equivalent APF was installed

and commissioned as part of a research and development

program and not part of the CCT demonstration. This

system used ceramic candle filters to clean one-seventh of

the exhaust gases from the PFBC system. The hot gas

cleanup system unit replaced one of the seven secondary

cyclones.

The Tidd PFBC demonstration plant accumulated

11,444 hours of coal-fired operations during its 54

months of operation. The unit completed 95 parametric

tests, including continuous coal-fired runs of 28, 29, 30,

31, and 45 days. Ohio bituminous coals having sulfur

contents of 2–4% were used in the demonstration.

Environmental Performance

Testing showed that 90% SO2

 capture was achievable

with a Ca/S molar ratio of 1.14 and that 95% SO2

 capture

was possible with a Ca/S molar ratio of 1.5, provided the

size gradation of the sorbent being utilized was optimized. This sulfur retention was achieved at a bed temperature of 1,580 oF and full bed height. Limestone deterioration of the fluidized-bed, and as a result, testing

focused on dolomite. The testing showed that sulfur

capture as well as sintering was sensitive to the fineness

of the dolomite sorbent (Plum Run Greenfield dolomite

was the design sorbent). Sintering of fluidized-bed materials, a fusing of the materials rather than effective reaction, had become a serious problem that required operation at bed temperatures below the optimum for effective

boiler operation. Tests were conducted with sorbent size

reduced from minus 6 mesh to a minus 12 mesh. The

result with the finer material was a major, positive impact

on process performance without the expected excessive

elutriation of sorbent. The finer material increased the

fluidization activity as evidenced by a 10% improvement

in heat transfer rate and an approximately 30% increase in

sorbent utilization. In addition, the process

was much more stable as indicated by reductions in temperature variations in both the

bed and the evaporator tubes. Further, sintering was effectively eliminated.

NOx emissions ranged from 0.15–0.33 lb/

106

 Btu, but were typically 0.2 lb/106 Btu

during the demonstration. These emissions

were inherent to the process, which was

operating at approximately 1,580 oF. No NOx

control enhancements, such as ammonia

injection, were required. Emissions of carbon

monoxide and particulates were less than 0.01

and 0.02 lb/106

 Btu, respectively.

Operational Performance

Except for localized erosion of the in-bed

tube bundle and the more general erosion of

the water walls, the Tidd boiler performed

extremely well and was considered a commercially viable design. The in-bed tube bundle

experienced no widespread erosion that

would require significant maintenance.

While the tube bundle experienced little wear,

a significant amount of erosion on each of the four

water walls was observed. This erosion posed no

problem, however, because the area affected is not

critical to heat transfer and could be protected by refractory.

The prototype gas turbine experienced structural

problems and was the leading cause of unit unavailability

during the first 3 years of operation. However, design

changes instituted over the course of the demonstration

proved effective in addressing the problem. The Tidd

demonstration showed that a gas turbine could operate in

a PFBC flue gas environment.

Efficiency of the PFBC combustion process was

calculated during testing from the amount of unburned

carbon in cyclone and bed ash, together with measurements of the amount of carbon monoxide in the flue
Advanced Electric Power Generation Program Update 1998 5-109

In summary, the Tidd 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 design, sorbent utilization,

sintering, post-bed combustion, ash removal, and

boiler materials.

Testing of the APF for over 5,800 hours of coal-fired

operation showed that the APF vessel was structurally

adequate; the clay-bonded silicon carbide candle filters

were structurally adequate unless subjected to side loads

from ash bridging or build-up in the vessel; bridging was

precluded with larger particulates included in the particulate matter; and filtration efficiency (mass basis) was

99.99%.

Economic Performance

The Tidd plant was a relatively small-scale facility, detailed economics were not prepared as part of this project.

However, a recent cost estimate performed on Japan’s

360-MWe PFBC Karita Plant, due to commence operation in 1999, projected a capital cost of $1,263/kW

(1997$).

Commercial Applications

Combined-cycle PFBC permits use of a wide range of

coals, including high-sulfur coals. The compactness of

Bubbling PFBC technology allows utilities to significantly increase capacity at existing sites. 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 360-MWe Kapita Plant in Japan, which will

use ABB Carbon P800 technology, represents a major

move toward commercialization of PFBC bubbling-bed

technology. A second generation P200 PFBC is under

construction in Germany. Other PFBC projects are

under consideration in China, South Korea, the United

Kingdom, Italy, and Israel.

The Tidd project received Power magazine’s 1991

Powerplant Award. In 1992, the project received the

National Energy Resource Organization award for demonstrating energy-efficient technology.

Contacts

Mario Marrocco, (614) 223-2460

American Electric Power Service Corporation

1 Riverside Plaza

Columbus, OH 43215,

(614) 223-3204 (fax)

George Lynch, DOE/HQ, (301) 903-9434

Donald W. Geiling, FETC, (304) 285-4784

References

• Tidd PFBC Hot Gas Clean Up Program Final Report.

Report No. DOE/MC/26042-5130. The Ohio Power

Company. October 1995. (Available from NTIS as

DE96000650.)

• Tidd PFBC Demonstration Project Final Report,

Including Fourth Year of Operation. The Ohio Power

Company. August 1995. (Available from DOE

Library/Morgantown, 1-800-432-8330, ext. 4184 as

DE96000623.)

• Tidd PFBC Demonstration Project Final Report,

March 1, 1994–March 30, 1995. Report No. DOE/

MC/24132-T8. The Ohio Power Company. August

1995. (Available from NTIS as DE96004973.)

• Tidd PFBC Demonstration Project—First Three Years

of Operation. Report No. DOE/MC/24132-5037-vol.

1 and 2. The Ohio Power Company. April 1995.

(Available from NTIS as DE96000559 for vol. 1 and

DE96003781 for vol. 2.)

• A Study of Hazardous Air Pollutants at the Tidd

PFBC Demonstration Plant. Report No. DOE/MC/

26042-4083. American Electric Power Service Corporation. October 1994. (Available from NTIS as

DE95009729.)

• Tidd PFBC Demonstration Project Topical Report—First Eighteen Months of Operation. Report

No. DOE/MC/24132-3746. The Ohio Power Company. March 1994. (Available from NTIS as

DE94004120.)

• Tidd PFBC Demonstration Project: Public Final

Design Report. Report No. DOE/MC/24132-3195.

The Ohio Power Company. October 1992. (Available

from NTIS as DE93000234.)

• 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.
5-110 Program Update 1998 Advanced Electric Power Generation

bent improves mixing and extends the contact time of

solids and gases, thus promoting high utilization of the

coal and high-sulfur-capture efficiency. Heat in the flue

gas exiting the hot cyclone is recovered in the economizer. Flue gas passes through a baghouse where particulate matter is removed. Steam generated in the

ACFB is used to produce electric power.

Three small, coal-fired, stoker-type boilers at Nucla

Station were replaced with a new 925,000-lb/hr ACFB

steam generator capable of driving a new 74-MWe turbine generator. Extraction steam from this turbine generator powers three existing turbine generators (12-MWe

each).

In 1992, Colorado-Ute Electric Association, Inc.,

the owner of Nucla Station, was purchased by Tri-State

Generation and Transmission Association, Inc.

Project Objective

To demonstrate the feasibility of ACFB technology at

utility scale and to evaluate the economic environmental,

and operational performance at that scale.

Technology/Project Description

Nucla’s circulating fluidized-bed system operates at atmospheric pressure. In the combustion chamber, a stream

of air fluidizes and entrains a bed of coal, coal ash, and

sorbent (e.g., limestone). Relatively low combustion

temperatures limit NOx

 formation. Calcium in the sorbent

combines with SO2

 gas to form calcium sulfite and sulfate

solids, and solids exit the combustion chamber and flow

into a hot cyclone. The cyclone separates the solids from

the gases, and the solids are recycled for combustor temperature control. Continuous circulation of coal and sorAdvanced Electric Power Generation

Fluidized-Bed Combustion

Nucla CFB Demonstration

Project

Project completed.

Participant

Tri-State Generation and Transmission Association, Inc.

(formerly Colorado-Ute Electric Association, Inc.)

Additional Team Members

Foster Wheeler Energy Corporation*—technology supplier

Technical Advisory Group (potential users)—cofunder

Electric Power Research Institute—technical consultant

Location

Nucla, Montrose County, CO (Nucla Station)

Technology

Foster Wheeler’s atmospheric circulating fluidized-bed

(ACFB) combustion system

Plant Capacity/Production

100-MWe (net)

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

*Pyropower Corporation, the original technology developer and

supplier, was acquired by Foster Wheeler Energy Corp.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Program Update 1998 5-111

Results Summary

Environmental

• Bed temperature had the greatest effect on pollutant

emissions and boiler efficiency.

• At bed temperatures below 1,620 oF, sulfur capture

efficiencies of 70 and 95% were achieved at calciumto-sulfur (Ca/S) molar ratios of 1.5 and 4.0, respectively.

• During all tests, NOx

 emissions averaged 0.18 lb/106

Btu and did not exceed 0.34 lb/106 Btu.

• CO emissions ranged from 70–140 ppmv.

• Particulate emissions ranged from 0.0072–0.0125

lb/106

 Btu, corresponding to a removal efficiency of

99.9%.

• Solid waste was essentially benign and showed potential as an agricultural soil amendment, soil/road bed

stabilizer, or landfill cap.

Operational

• Boiler efficiency ranged from 85.6–88.6% and combustion efficiency ranged from 96.9–98.9%.

• A 3:1 boiler turndown capability was demonstrated.

• Heat rate at full load was 11,600 Btu/kWh and was

12,400 Btu/kWh at half load.

Economic

• Capital cost for the Nucla retrofit was $1,123/kW and

a normalized power production cost was 64 mills/

kWh.

Project Summary

Fluidized-bed combustion evolved from efforts to find a

combustion process conducive to controlling pollutant

emissions without external controls. Fluidized-bed

combustion enables efficient combustion at temperatures

of 1,400–1,700 oF, well below the thermal-NOx

 formation temperature (2,500 oF), and high SO2

-capture efficiency through effective sorbent/flue gas contact. ACFB

differs from the more traditional fluid-bed combustion.

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

Rather than submerging a heat exchanger in the fluid bed,

which dictates a low-fluidization velocity, ACFB uses a

relatively high fluidization velocity, which entrains the

bed material. Hot cyclones capture and return the solids

emerging from the turbulent bed to control temperature

and extend the gas/solid contact time and to protect a

downstream heat exchanger.

Interest and participation of the Department of Energy, Electric Power Research Institute, and Technical

Advisory Group (potential users) in the project involved

evaluating ACFB potential for broad utility application

through a comprehensive test program. Over a 21

/2-year

period, 72 steady-state performance tests were conducted

and 15,700 hours logged. The result was a database that

remains the most comprehensive, available resource on

ACFB technology.

Operational Performance

Between July 1988 and January 1991, the plant operated

with an average availability of 58% and an average capacity factor of 40%. However, toward the end of the demOperation

completed 1/91

Operation test program initiated 8/88

Cooperative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92
5-112 Program Update 1998 Advanced Electric Power Generation

Exhibit 5-38

 Effect of Bed Temperature

on Ca/S Requirement

Exhibit 5-39

Calcium Requirements and

Sulfur Retentions for Various Fuels

onstration, most of the technical problems had been overcome. During the last three 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 5-38 shows the effect of bed temperatures

on the Ca/S molar ratio requirement for 70% sulfur retention. Ca/S molar ratios were calculated based on the

calcium content of the sorbent only and do not account

for the calcium content of the coal. While a Ca/S molar

ratio of about 1.5 was sufficient to achieve 70% sulfur

retention in the 1,500–1,620 °F range, the Ca/S molar

ratio requirement jumped to 5.0 or more at 1,700 °F or

greater.

Exhibit 5-39 shows the effect of Ca/S molar ratio

on sulfur retention at average bed temperatures below

1,620 oF. Salt Creek and Peabody coals contain 0.5%

and 0.7% sulfur, respectively. To achieve 70% SO2

reduction, or the 0.4 lb/106 Btu emission rate required

by the licensing agreement, a Ca/S molar ratio of approximately 1.5 is required. To achieve an SO2

 reduction of 95%, a Ca/S molar ratio of approximately 4.0 is

necessary. Dorchester coal, averaging 1.5% sulfur

content, required a somewhat lower Ca/S molar ratio

for a given retention.

NOx

 emissions measured throughout the demonstration were less than 0.34 lb/106

 Btu, which is well

below the regulated value of 0.5 lb/106

 Btu. The average level of NOx

 emissions for all tests was

0.18 lb/106

 Btu. NOx emissions indicate a

relatively strong correlation with temperature,

increasing from 40 ppmv (0.06 lb/106

 Btu) at

1,425 oF to 240 ppmv (0.34 lb/106

 Btu) at

1,700 °F. Limestone feed rate was also identified as a variable affecting NOx

 emissions,

i.e., somewhat higher NOx

 emissions resulted

from increasing calcium-to-nitrogen (Ca/N)

molar ratios. The mechanism was believed to

be oxidation of volatile nitrogen in the form

of ammonia (NH3

) catalyzed by calcium

oxide.

CO emissions decrease as temperature

increases, from 140 ppmv at 1,425 oF to 70

ppmv at 1,700 oF.

At full load, the hot cyclones removed

99.8% of the particulates. With the addition

of baghouses, removal efficiencies achieved
Advanced Electric Power Generation Program Update 1998 5-113

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.

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/kW (net). Total power

costs associated with plant operations between September 1988 and

January 1991 were approximately $54.7

million, resulting in a normalized cost

of power production of 64 mills/kWh.

The average monthly operating cost

over this period was about $1,888,000.

Fixed costs represent about 62% of

the total and include interest (47%),

taxes (4.8%), depreciation (6.9%), and insurance (2.7%).

Variable costs represent more than 38% of the power

production costs and include fuel expenses (26.2%),

non-fuel expenses (6.8%), and maintenance expenses

(5.5%).

Commercial Applications

The Nucla project represented the first repowering of a

U.S. utility plant with ACFB technology and showed

the technology’s effectiveness to burn a wide variety

of coals cleanly and efficiently. The comprehensive

database resulting from the Nucla project enabled the

resultant technology to be replicated in numerous

commercial plants throughout the world. Nucla continues in commercial service.

Today, every major boiler manufacturer offers an

ACFB system in its product line. There are now more

than 170 fluidized-bed combustion boilers of varying

capacity operating in the U.S. and the technology has

made significant market penetration abroad. The fuel

flexibility and ease of operation make it a particularly

attractive power generation option for the burgeoning

power market in developing countries.

Contacts

Stuart Bush, (303) 452-6111

Tri-State Generation and Transmission Ass’n., Inc.

P.O. Box 33695

Denver, CO 80233

George Lynch, DOE/HQ, (301) 903-9434

Nelson F. Rekos, FETC, (304) 285-4066

References

• Colorado-Ute Nucla Station Circulating Fluidized-Bed (CFB) Demonstration—Volume 2: Test

Program Results. EPRI Report No. GS-7483. October

1991.

• Demonstration Program Performance Test: Summary Reports. Report No. DOE/MC/25137-3104.

Colorado-Ute Electric Association, Inc. March 1992.

(Available from NTIS as DE92001299.)

• Economic Evaluation Report: Topical Report.

Report No. DOE/MC/25137-3127. Colorado-Ute

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.
5-114 Program Update 1998 Advanced Electric Power Generation
Advanced Electric Power Generation

Integrated Gasification Combined-Cycle
5-116 Program Update 1998 Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Clean Energy Demonstration

Project

Participant

Clean Energy Partners Limited Partnership (a limited

partnership consisting of Clean Energy Genco, Inc., an

affiliate of Duke Energy Corp.; AMEREN Corporation

and Energy Research Corporation)

Additional Team Members

Duke Engineering & Services, Inc.—engineer and

constructor

General Electric Company—power island designer and

supplier

British Gas Americas, Inc., in conjunction with Lurgi

Energie and Umwelt GmbH—gasification island designer

Energy Research Corporation—molten carbonate fuel cell

designer and supplier; cofunder

AMEREN Corporation—cofunder

Location

Carbondale, Jackson County, IL (Central Illinois Public

Service Company’s Grand Tower Station)

Technology

Integrated gasification combined-cycle (IGCC) using

British Gas/Lurgi (BG/L) slagging fixed-bed gasification

system coupled with Energy Research Corporation’s molten carbonate fuel cell (MCFC)

Plant Capacity/Production

477-MWe (net) IGCC; 1.25-MWe MCFC

Coal

Illinois basin bituminous coal

Project Funding

Total project cost $841,096,189 100%

DOE 183,300,000 22

Participant 657,796,189 78

Project Objective

To demonstrate and assess the reliability, availability, and

maintainability of a utility-scale IGCC system using

high-sulfur bituminous coal in an oxygen-blown, fixedbed, slagging gasifier and the operability of a molten

carbonate fuel cell fueled by coal gas 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 flux to produce a raw coal-derived fuel

gas rich in hydrogen and carbon monoxide. Raw fuel

gas exiting the gasifier is washed and cooled. Hydrogen

sulfide and other sulfur compounds are removed. Elemental sulfur is reclaimed and disposed of as a byproduct. Tars, oils, and dust are recycled to the gasifier.

The resulting clean, medium-Btu fuel gas fires the gas

turbine. A small portion of the clean fuel gas is used for

the MCFC.

The MCFC is composed of a molten carbonate

electrolyte sandwiched between porous anode and cathode plates. Fuel (desulfurized, heated medium-Btu fuel

gas) and steam are fed continuously into the cathode.

Electrical reactions produce direct electric current, which

is converted to alternating power in an inverter.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

**Years omitted

Advanced Electric Power Generation Program Update 1998 5-117

1993 1998 1999 1994 1995 2000 2001 2003 2004 2005 2006

Preaward

5/93

DOE selected project

(CCT-V) 5/4/93

Project Status/Accomplishments

The cooperative agreement was awarded December 2,

1994. Subsequent to award, a new site had to be found.

The Central Illinois Public Service Company’s Grand

Tower Station was proposed by the Participant and approved by DOE on November 20, 1998.

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.

Cooperative Agreement

awarded 12/2/94

Design and Construction

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.

12/94 12/03 12/05

Operation

Operation Initiated 12/03*

Final report issued/project

completed 12/05*

**

New site selected

(tentative) 9/98

**
5-118 Program Update 1998 Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Piñon Pine IGCC Power

Project

Participant

Sierra Pacific Power Company

Additional Team Members

Foster Wheeler USA Corporation—architect, engineer,

and constructor

The M.W. Kellogg Company—technology supplier

Bechtel Corporation—startup engineer

Location

Reno, Storey County, NV (Sierra Pacific Power

Company’s Tracy Station)

Technology

Integrated gasification combined-cycle (IGCC) using the

KRW air-blown pressurized fluidized-bed coal

gasification system

Plant Capacity/Production

107-MWe (gross), 99-MWe (net)

Coal

Southern Utah bituminous, 0.5–0.9% sulfur (design coal);

eastern bituminous, 2–3% sulfur (planned test)

Project Funding

Total project cost $335,913,000 100%

DOE 167,956,500 50

Participant 167,956,500 50

Project Objective

To demonstrate air-blown pressurized fluidized-bed

IGCC technology incorporating hot gas cleanup; to evaluate a low-Btu gas combustion turbine; and to assess longterm reliability, availability, maintainability, and environmental performance at a scale sufficient to determine

commercial potential.

Technology/Project Description

Dried and crushed coal and limestone are introduced into

an air-blown pressurized fluidized-bed gasifier. Crushed

limestone is used to capture a portion of the sulfur 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.

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 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

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Program Update 1998 5-119

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

to improve performance, start-up logic for the gasifier

has been revised, and an alternate sorbent for the transport desulfurizer was installed and successfully tested.

Short periods of steady-state gasifier operation on

coal are routinely achieved. Sustained operation has

been inhibited by mechanical and control problems in the

hot gas filter system. Breakage of a significant number

of candle filters was experienced due to failure of the

fines combustor subsystem. Sierra Pacific also modified

the bottom of the gasifier to correct a shift in the air/coal

feed tube. While the gasifier was down for repair, Sierra

Pacific repaired an area of the gasifier refractory that was

eroded.

Commercial Applications

The Piñon Pine IGCC system concept is suitable for new

power generation, repowering needs, and cogeneration

applications. The net heat rate for a proposed greenfield

plant using this technology is projected to be 7,800 Btu/

kWh (43.7% efficiency), representing a 20% increase in

thermal efficiency as compared to a conventional pulverIn 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

The system has initiated test-plan operations and continues to experience start-up problems. The station began

operation on natural gas in November 1996. Pre-operational testing and shakedown of the coal gasification

combined-cycle continued through 1997 with syngas

produced in January 1998. The plant was dedicated in

April 1998.

The GE Frame 6FA combustion turbine, the first of

its kind in the world, has performed well since commencing operation in August 1996 on natural gas. Other

portions of the plant have undergone design modification

Environmental monitoring plan

completed 10/31/96

Preoperational tests initiated 11/96

1/98

Operation initiated 1/98

Construction completed 2/97

ized coal plant with a scrubber and a comparable reduction in CO2

 emissions. The compactness of an IGCC

system reduces space requirements per unit of energy

generated relative to other coal-based power generation

systems. The advantages provided by phased modular

construction reduce the financial risk associated with new

capacity additions.

The KRW IGCC technology is capable of gasifying

all types of coals, including high-sulfur, high-ash, lowrank, and high-swelling coals, as well as bio- or refusederived waste, with minimal environmental impact. There

are no significant process waste streams that require

remediation. The only solid waste from the plant is a

mixture of ash and calcium sulfate, a nonhazardous waste.
5-120 Program Update 1998 Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Tampa Electric Integrated

Gasification Combined-Cycle

Project

Participant

Tampa Electric Company

Additional Team Members

Texaco Development Corporation—gasification

technology supplier

General Electric Corporation—combined-cycle

technology supplier

GE Environmental Services, Inc.—hot-gas cleanup

technology supplier

TECO Power Services Corporation—project manager and

marketer

Bechtel Power Corporation—architect and engineer

Location

Mulberry, Polk County, FL (Tampa Electric Company’s

Polk Power Station, Unit No. 1)

Technology

Integrated gasification combined-cycle (IGCC) system

using Texaco’s pressurized oxygen-blown entrained-flow

gasifier technology and incorporating both conventional

low-temperature acid-gas removal and hot-gas movingbed desulfurization

Plant Capacity/Production

250-MWe (net)

Coal

Illinois #6, Pittsburgh #8, Kentucky #11, 2.5–3.5% sulfur

Project Funding

Total project cost $303,288,446 100%

DOE 150,894,223 49

Participant 152,394,223 51

Project Objective

To demonstrate IGCC technology in a greenfield, commercial, electric utility application at the 250-MWe size

with a Texaco gasifier; to demonstrate the integrated

performance of a metal oxide hot-gas cleanup system,

conventional cold-gas cleanup, and an advanced gas

turbine with nitrogen injection (from the air separation

plant) for power augmentation and NOx

 control.

Technology/Project Description

Texaco’s pressurized, oxygen-blown, entrained-flow

gasifier is used to produce a medium-Btu fuel gas. Coal/

water slurry and oxygen are reacted at high temperature

and pressure to produce a high-temperature syngas. The

syngas from the gasifier moves to a high-temperature

heat-recovery unit, which cools the gases. Molten coalash flows out of the bottom of the vessel and into a

water-filled quench tank where it is forms a solid slag.

The cooled gases flow to a particulate-removal section before entering gas-cleanup trains. A portion of the

syngas (10%) is passed through a moving bed of metal

oxide absorbent to remove sulfur. The remaining syngas

is further cooled through a series of convective heat exchangers before entering a conventional gas-cleanup train

where sulfur is removed by an acid-gas removal system.

Combined, these cleanup systems are expected to maintain sulfur levels below 0.21 lb/106

 Btu (96% capture).

The cleaned gases are then routed to a combined-cycle

system for power generation. Sulfuric acid and slag are

salable by-products.

A GE MS 7001F gas turbine generates about 192

MWe (gross). Thermal-NOx

 is controlled to below
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Calendar Year

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*Projected date

**Years omitted

Advanced Electric Power Generation Program Update 1998 5-121

0.27 lb/106 Btu by injecting nitrogen as a dilutent in the

turbine’s combustion section. A heat-recovery steamgenerator produces an additional 121-MWe (gross).

Polk’s IGCC heat rate for this demonstration is expected

to be approximately 8,600 Btu/kWh (40% efficient). The

demonstration project involves only the first 250-MWe

(net) of the planned 1,150-MWe Polk Power Station.

Illinois #6, and Pittsburgh #8, and Kentucky #11 bituminous coals (2.5–3.5% sulfur) are being used.

Project Status/Accomplishments

The plant began commercial operation in September 1996

and continues to successfully accumulate run time. Gasifier operation had exceeded 10,000 hours by October

1998. The gasifier on-stream factor steadily increases

over time, reaching 70% for the past 12 months. Combined-cycle availability has remained above 90% since

the second quarter of 1997. Improved gasifier availability

was largely due to removal of the raw gas/clean gas heat

exchanger, a source of particulate contamination, and

1988 1989 1990 1991 1994 1995 1996 1997 1998 1999 2001

Preaward Design and Construction

12/89 3/91

installation of a larger filter to prevent leakage of particulate matter to the turbine. Also contributing to

improved availability are new operating procedures to

deal with radiant syngas cooler dome seal leaks and

hot restarts of the gasifier.

Recent tests included evaluation of various coal

types on system performance. Kentucky #11, Illinois #6,

and three Pittsburgh #8 coals were tested for their:

(1) ability to be processed into a high concentration

slurry, (2) carbon conversion efficiency, (3) aggressiveness of the slag in regard to refractory wear, and (4) tendency toward fouling of the syngas coolers. Kentucky

#11 coal proved to have the best overall characteristics

and supplanted Pittsburgh #8 as the base coal. Illinois #6

placed second and prompted further testing because of

some promising aspects of its performance.

Commercial Applications

This demonstration project is scaling up the technology

from Cool Water demonstration unit (100-MWe) tested

**

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

Cooperative agreement awarded 3/11/91

Preoperational tests initiated 6/96

Construction completed 8/96

Operation initiated 9/96

9/96

Design completed 8/94

NEPA process completed (EIS) 8/17/94

Construction started 8/94

Project completed/final report issued 10/01*

Operation completed 10/01*

10/01

Operation

Environmental monitoring plan completed 5/96

without full system integration. The Texaco-based

IGCC is suitable for new electric power generation,

repowering needs, and cogeneration applications.

Commercial IGCCs should achieve better than 98% SO2

capture with a NOx emissions reduction of 90% relative

to a conventional pulverized coal-fired plant.

Texaco and ASEA Brown Boveri have signed an

agreement forming an alliance to market IGCC technology in Europe.

The project was presented the 1997 Powerplant

Award by Power magazine. In 1996 the project received

the Association of Builders and Contractors Award for

construction quality. Several awards were presented for

using an innovative siting process: 1993 Ecological

Society of America Corporate Award, 1993 Timer Powers

**

3 4
5-122 Program Update 1998 Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Wabash River Coal

Gasification Repowering

Project

Participant

Wabash River Coal Gasification Repowering Project Joint

Venture (a joint venture of Dynegy and PSI Energy, Inc.)

Additional Team Members

PSI Energy, Inc.—host

Dynegy (formerly Destec Energy, Inc.)—engineer, gas

plant operator, and technology supplier

Location

West Terre Haute, Vigo County, IN (PSI Energy’s Wabash

River Generating Station, Unit No. 1)

Technology

Integrated gasification combined-cycle (IGCC) using

Destec’s two-stage pressurized oxygen-blown entrainedflow gasification system

Plant Capacity/Production

296-MWe (gross), 262-MWe (net)

Coal

Illinois Basin bituminous

Project Funding

Total project cost $438,200,000 100%

DOE 219,100,000 50

Participant 219,100,000 50

Project Objective

To demonstrate utility repowering with a two-stage pressurized oxygen-blown entrained-flow IGCC system,

including advancements in the technology relevant to the

use of high-sulfur bituminous coal and to assess longterm reliability, availability, and maintainability of the

system at a fully commercial scale.

Technology/Project Description

Coal is ground in a rod mill slurried with water, and

gasified in a pressurized, two-stage (slagging first stage

and non-slagging entrained-flow second stage), oxygenblown, 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

(MS 7001) gas turbine. Hot exhaust from the gas turbine

is passed through a heat recovery steam generator to

produce high-pressure steam. High-pressure steam is also

produced from the gasification plant and superheated in

the heat recovery steam generator. The combined highpressure steam flow is supplied to an existing, refurbished

104-MWe (gross) steam turbine for a total output of 296

MWe (gross).

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
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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 1998 5-123

less than 0.1 lb/106 Btu (98% reduction). NOx emissions

are expected to be less than 0.1 lb/106

 Btu (90% reduction). The project represents the world’s largest singletrain IGCC plant currently in operation.

Project Status/Accomplishments

The project began operations in November 1995 and

continues in its third year of commercial service.

CINergy, PSI’s post-merger parent company, preferentially dispatches the unit second behind its hydro facilities

on the basis of environmental emissions and efficiency,

with a demonstrated heat rate of better than 9,000 Btu/

kWh (HHV). Late 1998 operating statistics showed an

annual availability of 77.2%. Since initiating operation in

1995, the unit has achieved monthly production levels of

one trillion Btus on four occasions. Refinements to the

design are continuing, including replacement of ceramic

candle particulate filters with a metallic filter (operating

temperature 800 oF) and installation of a chloride scrubber and new COS hydrolysis catalyst for SO2

 control.

Both the gasifier and combined-cycle plants have

demonstrated the ability to run at capacity and within

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 5/99

Demonstration completed 2/99*

Operation initiated 11/95

Construction completed 11/95

environmental compliance while using locally mined,

high sulfur coal. Early identification of availability limiting process problems within the gasification plant led to

aggressive implementation of improvements which have

nearly tripled production since operations began.

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

Project completed/final report issued 5/99*

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-coal-fired plant with flue gas

desulfurization. The improved system efficiency also

results in a similar decrease in CO2 emissions.

Destec Energy and CINergy Corp./PSI Energy received the 1996 Powerplant Award from Power magazine.

Sargent & Lundy, engineer for the combined-cycle facility,

won the American Consulting Engineers Council’s 1996

Engineering Excellence Award.
5-124 Program Update 1998 Advanced Electric Power Generation
Advanced Electric Power Generation

Advanced Combustion/Heat Engines
5-126 Program Update 1998 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—operator

Stone and Webster Engineering Corp.—engineer

TRW Inc., Space & Technology Division—combustor

technology supplier

The Babcock & Wilcox Company (which has acquired

assets of Joy Environmental Technologies, Inc.)—

spray-dryer absorber technology supplier

Usibelli Coal Mine, Inc.—coal supplier

Location

Healy, Denali Borough, AK (adjacent to Healy Unit

No. 1)

Technology

TRW’s advanced entrained (slagging) combustor

Babcock & Wilcox’s spray-dryer absorber with sorbent

recycle

Plant Capacity/Production

50-MWe (nominal)

Coal

Usibelli subbituminous 35% run-of-mine (0.2% sulfur)

and 65% waste coal (design)

Project Funding

Total project cost $242,058,000 100%

DOE 117,327,000 48

Participant 124,731,000 52

Project Objective

To demonstrate an innovative new power plant design

featuring integration of an advanced combustor and

heat recovery system coupled with both high- and lowtemperature for optimum slagging performance. The

TRW slagging combustors are side mounted, injecting

the combustion products vertically into the boiler. The

main slagging combustor consists of a water-cooled

cylinder that slopes toward a slag opening. The

precombustor burns 25–40% of the total coal input.

The remaining coal is injected axially into the combustor, rapidly entrained by the swirling precombustor

gases and additional air flow, and burned under

substoichio-metric (fuel-rich) conditions for NOx

 control. The ash forms molten slag, which accumulates on

the water-cooled walls and is driven by aerodynamic

and gravitational forces through a slot into the slag

recovery section. About 70–80% of the coal’s ash is

removed as molten slag. The hot gas is then ducted to

the furnace where, to ensure complete combustion,

temperature emissions control processes.

Technology/Project Description

The project involves two unique slagging combustors

generating a nominal 50-MWe. Emissions of SO2

 and

NOx

 are controlled using TRW’s slagging combustion

systems with staged fuel and air, a boiler that controls

fuel- and thermal-NOx

 related conditions, and limestone

injection. Additional SO2

 is removed using Babcock &

Wilcox’s activated recycle spray-dryer absorber system.

Performance goals are NOx

 emissions of less than 0.2 lb/

106

 Btu, particulate emissions of 0.015 lb/106 Btu, and

SO2

 removal greater than 90%. The design fuel blend

performance testing of coal consists of 35% run-of-mine

and 65% waste coal.

A coal-fired precombustor increases the air inlet
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Calendar Year

 1 2

*Projected date

**Years omitted

Advanced Electric Power Generation Program Update 1998 5-127

additional air is supplied from the tertiary air windbox

to NOx

 ports and to final overfire air ports.

Pulverized limestone (CaCO3

) for SO2 control is fed

into the combustor where it is flash calcined (converting CaCO3

 to CaO). The mixture of this lime (CaO) and

ash not slagged, called flash-calcined material, is removed in the fabric filter (baghouse) system. Most of

the flash-calcined material is used to form a 45% flashcalcined-material solids slurry. SO2

 in the flue gas

reacts with the slurry droplets as water is simultaneously evaporated. SO2

 is further removed from the

flue gas by reacting with the dry flash-calcined material

on the baghouse filter bags.

The project site is adjacent to the existing Healy Unit

No. 1 near Healy, AK, and to the Usibelli coal mine.

Power will go to the Golden Valley Electric Association

(GVEA). The plant will use 900 tons/day of subbituminous coal 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 No. 1 so that the combined emissions

from the two units will be only slightly greater than

those currently emitted from Unit No. 1 alone. Total

site emissions will be further reduced to current levels

if necessary to protect the park.

Project Status/Accomplishments

Start-up of the entrained slagging combustion system

began in January 1998. During a record-setting 18-day

period of continuous operation, initial NOx

 and SO2

environmental compliance testing was completed. The

preliminary results showed that NOx

 emissions of 0.25

lb/106

 Btu and SO2 emissions of 0.08 lb/106 Btu were

achieved. The permit requires emissions to be less than

0.35 lb/106

 Btu for NOx and less than 0.10 lb/106 Btu for

SO2

. The stringent SO2 emission level required by the

permit is significantly lower than the 1.2 lb/106

 Btu

NSPS limit. The environmental compliance testing was

witnessed by the U.S. EPA, Region X and the Alaska

Department of Environmental Conservation. The plant

was experiencing precombustor plugging when the

coal feed is changed to a 50/50 blend of run-of-mine

and waste coal. The main problem remaining is solid

particle erosion of the mill exhauster fans.

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

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

Operation initiated 1/98

Preoperational tests initiated 8/97 NEPA process completed (EIS) 3/10/94

Design completed 10/93

Ground breaking/construction

started 5/30/95

No-Cost Data Collection

Environmental monitoring

plan completed 4/11/97

Construction completed 11/97
5-128 Program Update 1998 Advanced Electric Power Generation

Technology/Project Description

The project is based on the demonstration of an 18-cylinder, heavy duty engine (6.4-MWe) modified to operate on

Alaskan subbituminous coal. The clean coal diesel technology, which uses a low-rank coal-water-fuel (LRCWF)

slurry, is expected to have very low NOx

 and SO2 emission levels (50–70% below current New Source Performance Standards). In addition, the demonstration plant is

expected to achieve 41% efficiency, while future plant

designs are expected to reach 48% efficiency. This will

result in a 25% reduction in CO2

 compared to conventional coal-fired plants.

The LRCWF is prepared using an advanced coal

drying process that allows dried coal to be slurried in

water. The University of Alaska will assemble and operate a 5-ton/hr LRCWF processing plant that will utilize

local coal brought by truck from Usibelli’s mine in Healy,

AK. In addition to its use in the coal-fueled diesel engine, the LRCWF is expected to be an alternative to fuel

oil in conventional oil-fired industrial boilers.

Project Status/Accomplishments

The project has passed several milestones. A 60%

design review was conducted in March 1998 at the University of Alaska, Fairbanks (UAF). Representatives

from Coltec, A.D. Little, UAF, DOE, and GHEMM (construction contractor) were in attendance. The new design

eliminates the sorbent injection system, since Usibelli

was able to locate a very clean coal seam with less than

0.2% sulfur in the ash. The sorbent injection system

originally proposed for the coal diesel was designed for

use with bituminous coals with greater than 2.0% sulfur

Advanced Electric Power Generation

Advanced Combustion/Heat Engines

Clean Coal Diesel

Demonstration Project

Participant

Arthur D. Little, Inc.

Additional Team Members

University of Alaska at Fairbanks—host and cofunder

Alaskan Science & Technology Foundation—cofunder

Coltec Industries Inc.—diesel engine technology vendor

Energy and Environmental Research Center, University

of North Dakota—fuel preparation technology vendor

R.W. Beck, Inc.—architect/engineer, designer,

constructor

Usibelli Coal Mine, Inc.—coal supplier

Location

Fairbanks, AK (University of Alaska facility)

Technology

Coltec’s coal-fueled diesel engine

Plant Capacity/Production

6.4-MWe (net)

Coal

Usibelli Alaskan subbituminous

Project Funding

Total project cost $47,636,000 100%

DOE 23,818,000 50

Participant 23,818,000 50

Project Objective

To prove the design, operability, and durability of the

coal diesel engine during 6,000 hours of operation; verify

the design and operation of an advanced drying/slurrying

process for subbituminous Alaskan coals; and test the

coal slurry in the diesel and a retrofitted oil-fired boiler.
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Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Program Update 1998 5-129

1993 1996 1997 1994 1995 1998 1999 2000 2001 2002 2003

Preaward

5/93 7/94

DOE selected project

(CCT-V) 5/4/93

Cooperative agreement awarded 7/12/94

Design and Construction

levels. Coltec worked with the diesel engine manufacturer to design new injectors with sapphire orifices sized

for the volume of LRCWF required to operate the engine

at full load. Earlier designs were based on higher energy

density bituminous coals.

Delivery of the 18-cylinder diesel engine has moved

to January 1999. Construction activities started at the

Fairbanks site on June 15, 1998 and construction is over

60% complete.

Samples of the Usibelli coal were sent to CQ Inc.,

for washability tests; ADL for wear tests; and to EERC

for preliminary hot water drying tests. Several plant

design changes were made in order to keep the project

within budget. Notably, only a small oil-fired boiler will

be converted for coal slurry tests instead of a utility-scale

boiler, and several of the slurry holding tanks will be

located closer to the diesel engine to reduce underground

piping.

NEPA process completed (EA) 6/2/97

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. Environmental emissions from commercial diesel systems

should be reduced to levels between 50% and 70% below

NSPS. The estimated installation cost of a mature commercial unit is approximately $1,300/kW.

The U.S. diesel market is projected to exceed

60,000-MWe (over 7,000 engines) through 2020. The

worldwide market is 70 times the U.S. market. The technology is particularly applicable to dispersed power generation in the 5–20-MWe range, using indigenous coal in

developing countries.

Construction started 6/98

Environmental monitoring plan completed 2/99*

Construction completed 3/99*

Preoperational tests initiated 5/99*

Operation initiated 8/99*

8/99 4/02

Project completed/final

report issued 4/02*

Operation completed 1/02*

Operation

Project restructured 8/96

Design completed 11/98*
5-130 Program Update 1998 Advanced Electric Power Generation
Coal Processing for Clean Fuels
5-132 Program Update 1998 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

ARCADIS Geraghty & Miller—fuel methanol tester and

cofunder

Electric Power Research Institute—utility 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)

Coal

Eastern high-sulfur bituminous, 3–5% sulfur

Project Funding

Total project cost $213,700,000 100%

DOE 92,708,370 43

Participant 120,991,630 57

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.

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 storable

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 in January of 1997. FolProject Objective

To demonstrate on a commercial scale the production of

methanol from coal-derived synthesis gas using the

LPMEOHTMprocess; 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; and to

demonstrate, if practical, the production of dimethyl ether

(DME) as a mixed coproduct with methanol.

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 the

catalyst but functions as an efficient means to remove the LPMEOHTM is a trademark of Air Products and Chemicals, Inc.
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Calendar Year

 1 2

* Projected date

**Years omitted

Coal Processing for Clean Fuels Program Update 1998 5-133

lowing commissioning and shakedown activities, the

first production of methanol from the 80,000 gal/day

unit occurred on April 2, 1997. The first stable operation of the process demonstration unit at nameplate

capacity occurred on April 6, 1998. A stable test period

at over 92,000 gal/day revealed no system limitations.

The startup also proceeded without injury or environmental incidents.

During calendar year 1997, availability of the process demonstration unit exceeded 92%. The hydrogen

to carbon monoxide (H2

/CO) ratio in the reactor feed

stream was varied from 0.4 to 5.6 with no negative

effects on catalyst performance. The operation of the

demonstration unit confirmed the engineering methods

used in the design of the LPMEOHTM Reactor, and

several parameters (such as the overall heat transfer

coefficient of the internal heat exchanger) were demonstrated at greater than 115% of design levels.

Operation during 1998 has resulted in significant

accomplishments. The design catalyst loading in the

LPMEOHTM Reactor has been exceeded without indications of mass transfer limitations. Since being restarted

with fresh catalyst in December of 1997, the demonstration facility has operated at greater than 99% availability,

and 67 days of what would be a 94-day period of continuous operation was in progress as of September 30, 1998.

Catalyst life has met or exceeded the design target for

operation in the environment of trace poisons present in

coal-derived synthesis gas. Process variable studies to

maximize the reactor volumetric productivity and determine the long-term catalyst performance are on-going.

Since startup, the demonstration facility has produced

over 25 million gallons of methanol, all of which has

been accepted by Eastman Chemical Company for use in

downstream chemical processes.

Commercial Applications

The LPMEOHTM process has been developed to enhance

integrated gasification combined-cycle (IGCC) power

generation by producing a clean burning, storable liquid

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

Operation completed 3/01*

fuel—methanol—from the clean coal-derived gas.

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 is an environmentally

friendly aerosol for personal products.

Typical commercial-scale LPMEOHTM units are

expected to range in size from 50,000–300,000 gal/day of

methanol produced when associated with commercial

IGCC power generation trains of 200–500 MWe. Air

 3 4

**

Project transferred to Air Products

Liquid Phase Conversion

Company, L.P. 9/94
5-134 Program Update 1998 Coal Processing for Clean Fuels

Project Objective

To demonstrate advanced coal-cleaning unit processes to

produce low-cost compliance coals that can meet the

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 two

types of compliance coals—Carefree CoalTM and SelfScrubbing CoalTM from high-sulfur bituminous feedstocks.

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

Coal Processing for Clean Fuels

Coal Preparation Technologies

Self-Scrubbing CoalTM: An

Integrated Approach to Clean

Air

Participant

Custom Coals International

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 No. 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

Coals

Medium and high-sulfur bituminous

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.
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Calendar Year

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Coal Processing for Clean Fuels Program Update 1998 5-135

mization was not completed, the overall product made for

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.

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.

Financial problems ensued and, despite efforts to

resolve the matter, the project was placed in Chapter 11.

Due to Custom Coals inability to find a buyer for the

facility, the Custom Coals Laurel facility was sold at

auction to C.J. Betters Company.

the Self-Scrubbing CoalTM permits addition of relatively

large 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.

A Carefree CoalTM test burn (cleaned Lower

Kittanning coal) at Martin’s Creek Power Station was

conducted in mid-November 1996. Although plant opti1991 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

Design completed 12/94

Preoperational tests initiated 11/95

Construction completed 11/95

Operation initiated 2/96

2/97

Commercial Applications

Commercialization of Self-Scrubbing CoalTM had the

potential of bringing into compliance about 164 million

tons/yr of bituminous coal that cannot meet emissions

limits through conventional coal-cleaning. This represents more than 38% of the bituminous coal burned in

50-MWe or larger U.S. generating stations.

Project on hold
5-136 Program Update 1998 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Coal Preparation Technologies

Advanced Coal Conversion

Process Demonstration

Participant

Rosebud SynCoal Partnership (a partnership of Western

Energy Company and Western SynCoal)

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)

Coal

Powder River Basin subbituminous (Rosebud mine)

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.

Project Status/Accomplishments

 The Advanced Coal Conversion Process (ACCP)

facility continues to process raw subbituminous coal,

producing over 1.4 million tons of SynCoal® product to

date. Nearly 1.3 million tons has been supplied to

industrial applications (primarily cement and lime

plants) and utilities. Rosebud SynCoal Partnership has

signed a letter agreement between Puget Sound Energy SynCoal is a registered trademark of the Rosebud SynCoal Partnership.
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Calendar Year

 1 2

* Projected date

**Years omitted

Coal Processing for Clean Fuels Program Update 1998 5-137

of Bellevue, Washington and Montana Power Company of Butte, Montana, to design, install, and commission a dedicated pneumatic feed system to supply

SynCoal® to Montana Power’s 330-MWe Colstrip No.

2. Construction is nearly complete for the Colstrip No.

2 Pneumatic SynCoal® Fuel Project. The plant is continuing to be “cycled,” filling the silos and shutting

down until Colstrip No. 2 pneumatic feed system is in

place (scheduled for January 1999).

 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. Sulfur dioxide emissions

were reduced by 21% overall, generation increased at

normal operating loads, and there was no noticeable

impact on NOx

 emissions.

In August 1998, Rosebud was granted a six-month

no-cost time extension.

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

6/99

**

Project completed/final report

issued 6/99*

Operation completed 1/99*

Commercial Application

The Rosebud SynCoal ACCP has the potential to enhance the utility and industrial use of low-rank western

subbituminous and lignite coals. SynCoal® is an ideal

supplement fuel for plants seeking to burn western lowrank coals because it allows a wider range of low-sulfur

raw coals to be used to meet more restrictive worldwide emissions guidelines without derating of the units

or the addition of costly flue gas desulfurization systems.

The ACCP has potential to convert inexpensive

low-sulfur, low-rank coals into valuable carbon-based

reducing agents for many metallurgical applications,

further helping to reduce world-wide emissions and

decrease the U.S. dependence on foreign energy

sources.

The ACCP produces a fuel which has a consistently low moisture content, low sulfur content, high

heating value, and high volatile content. Because of

these characteristics, SynCoal® could have significant
5-138 Program Update 1998 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 No. 5)

Gulfport, Harrison County, MS (Watson, Unit No. 4)

Somerset, Bristol County, MA (Brayton Point,

Unit Nos. 2 and 3)

Bayport, Washington County, MN (King Station)

Oologah, Rogers County, OK (Northeastern, Unit No. 4)

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 250-880-MWe.

Coal

Wide variety of coal blends

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 model

that allows accurate and detailed prediction of coal quality impacts on total power plant operating cost and

performance.

Coal Quality Expert, CQE, CQIS, and CQIM are trademarks of the

Electric Power Research Institute.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

**Years omitted

Coal Processing for Clean Fuels Program Update 1998 5-139

Technology/Project Description

The CQETM is a software tool that brings a new level of

sophistication to fuel decisions by integrating the systemwide impact of fuel purchase decisions on coal-fired

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 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

technical and economic analyses of plant operating strategies. CQETM, which combines CQIMTM with other existing software and databases, extends the art of modelbased 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 No. 5 (880-MWe), Wilsonville, AL;

Mississippi Power’s Watson, Unit No. 4 (250-MWe),

Gulfport, MS; New England Power’s Brayton Point, Unit

No. 2 (285-MWe) and Unit No. 3 (615-MWe), Somerset,

MA; Northern States Power’s King Station (560-MWe),

Bayport, MN; and Public Service Company of

Oklahoma’s Northeastern, Unit No. 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

1988 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 6/98

6/98

CQE Release 1.2

issued 12/97

 3 4

**
5-140 Program Update 1998 Coal Processing for Clean Fuels

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

performance 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-, 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 Windowsbased 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

5-40. Technical support is available from

Black & Veatch for

licensed users.

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. and Black & Veatch have

each signed commercialization agreements, which give

both companies non-exclusive 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 30 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.

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 OS/2 WARP (3.0)

Exhibit 5-40

CQETM Stand-Alone System Requirements
Coal Processing for Clean Fuels Program Update 1998 5-141

The CQETM team has a Home Page on the World

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

the EPRI Fuels Web Server 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 online updatable user’s manual. The Home Page also helps

attract the interest of international utilities and consulting

firms.

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, (724) 479-3503

CQ Inc.

160 Quality Center Rd.

Homer City, PA 15748

Douglas Archer, DOE/HQ, (301) 903-9443

Scott M. Smouse, FETC, (412) 892-5725

References

• Final Report: Development of a Coal Quality Expert.

June 20, 1998.

• Harrison, Clark D., et al. “Recent Experience with the

CQETM.” Fifth Annual Clean Coal Technology Conference: Technical Papers. January 1997.

• CQETM Users Manual, CQETM Home Page at

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

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Development of the Coal Quality Expert. ABB Combustion Engineering, Inc., 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.
5-142 Program Update 1998 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Mild Gasification

ENCOAL® Mild Coal

Gasification Project

Project completed.

Participant

ENCOALCorporation (a wholly owned subsidiary of

Bluegrass Coal Development Company)

Additional Team Members

Bluegrass Coal Development Company (a wholly owned

subsidiary of AEI Resources, Inc.)—cofunder

SGI International—technology developer, owner,

licensor

Triton Coal Company (a wholly owned subsidiary of

Vulcan Coal Company)— host and coal supplier

The M.W. Kellogg Company—engineer and constructor

Location

Near Gillette, Campbell County, WY (Triton Coal

Company’s Buckskin Mine site)

Technology

SGI International’s Liquids-From-Coal (LFC®) process

Coal

Low-sulfur subbituminous coals

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

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 subbitumiENCOAL, LFC, CDL, and PDF are registered trademarks of SGI and

Bluegrass.

nous coal and to provide sufficient products for potential end users to conduct burn tests.

Technology/Project Description

Coal is fed into a rotary grate dryer where it is heated to

reduce moisture. The temperature is controlled so that no

significant amounts of methane, CO2

, or CO are released.

The solids are then fed to the pyrolyzer, where the temperature is about 1,000 °F, and all remaining water is

removed. A chemical reaction releases the volatile gaseous material. Solids exiting the pyrolyzer are quenched

to stop the pyrolysis reactions.

In the original process, the quench table solids were

further cooled in a rotary cooler and transferred to a surge

bin. A single 50% flow rate vibrating fluidized-bed

(VFB) was added to stabilize the Process-Derived Fuel

(PDF®) with respect to oxygen and water. In the VFB,

the partially cooled, pyrolyzed solids contact a gas

stream containing a controlled amount of oxygen.

Termed “oxidative deactivation,” a reaction occurs at

active surface sites in the particles reducing the tendency for spontaneous ignition.

Following the VFB, the solids are cooled to near

atmospheric temperature in an indirect rotary cooler

where water is added to rehydrate the PDF®. A patented

dust suppressant is added as the PDF® leaves the surge

bin. The hot gas produced in the pyrolyzer is sent through

a cyclone for removal of the particulates and then cooled

in a quench column to stop any additional pyrolysis reactions and to condense the Coal-Derived liquid (CDL®).
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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

Coal Processing for Clean Fuels Program Update 1998 5-143

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

Project completed/final

report issued 12/97

Operation completed 7/97

12/97

Results Summary

Environmental

• The product fuels have been used economically in

commercial boilers and furnaces and have reduced

SO2

 and NOx emissions significantly at utility and

industrial facilities currently burning high-sulfur bituminous coal or fuel oils.

• One utility reported a 20% reduction in NOx

 emissions

due to a more stable flame when burning PDF®.

• The PDF® contains 0.36% sulfur with a heat content of

11,100 Btu/lb (compared to 0.45% sulfur and 8,300

Btu/lb for the feed coal).

• The CDL® contains 0.6% sulfur and 140,000 Btu/gal

(compared to 0.8% sulfur and 150,000 Btu/gal for No.

6 oil).

• No EPA listed toxins in concentrations anywhere

close to federal limits.

Operational

• Almost five years of operating data have been collected for use as a basis for the evaluation and design

of a commercial plant.

• Numerous runs exceeding 120 days operation at 90%

availability.

• As of July 1997, about 260,000 tons of coal had been

processed into 120,000 tons of PDF® and 5,101,000

gallons of CDL®.

• Over 83,500 tons of PDF® have been shipped via 17

unit trains and 1 truck shipment to seven customers in

six states. Blends have ranged from 20–100% PDF®.

• Over 200 tank cars of CDL® have been shipped to

eight customers in seven states. The largest customer

has purchased 101 tank cars and blended the CDL®

with its fuel and burned the mixture for process heat.

• PDF® has been tested as a reductant (combined with

iron ore) in the direct reduced iron process, and holds

promise as a blast furnace injectant.

Economic

• A commercial plant designed to process 15,000-metric-ton/day would cost $475 million (2001 $) to construct with annual operating and maintenance costs of

$52 million per year.

Project Summary

Operational

A summary of plant performance is contained in Exhibit

5-41. ENCOAL’s first 24-hour run took place in June

1992.

After startup, it became evident that additional processing of the PDF® was necessary. Initially, the PDF®

was “finished” by a short exposure to atmospheric conditions in a layered stockpile prior to be reclaimed and

shipped, or either blended with run-of-plant PDF®, ROM

coal, or the atmosphere stabilized PDF®, but there was a

Btu penalty. After considering several alternatives, the

VFB was added as part of the deactivation loop.
5-144 Program Update 1998 Coal Processing for Clean Fuels

The VFB was designed to handle only half the

ENCOAL plant’s designed capacity; when proven, a

second VFB was to be installed. Operations became

notably smoother and more productive. This was attributable not only to the VFB’s improved stabilization of the

PDF® and the subsequent increased ease of handling, but

also to the replacement of the pyrolyzer sand seal with a

water seal and the installation of the process water fines

handling system. All these improvements combined to

produce a major landmark when ENCOAL® shipped its

first train containing PDF® on September 17, 1994 to

Western Farmers Electric Cooperative in Hugo,

Oklahoma.

ENCOAL met all its goals for its first shipments of

PDF® in the Fall of 1994— to demonstrate its ability to

coordinate with the Buckskin Mine in loading and shipping consistent blends, to ship PDF® with dust generation

comparable to or less than run-of-mine (ROM) Buckskin

coal, and to ship PDF® blends that were stable with respect to self heating. Furthermore, ENCOAL demonstrated that PDF® could be transported and delivered to

customers using regular commercial equipment. With

respect to use, the goal was for customers to burn trial

amounts (1⁄2 unit train minimum) of PDF® blends with

minimal adjustment of equipment. ENCOAL’s test burn

shipments became international when Japan’s Electric

Power Development Company evaluated six metric tons

of PDF® in 1994. Early 1995 saw much increased plant

volume when 13,700 tons of raw coal were processed in a

one-month period. Plant availability reached 89%, with

downtime attributable to the replacement of the original

quench table heat exchanger with a new, high capacity

unit.

ENCOAL began shipping unit trains of 100 PDF®

for the first time in 1996. By the end of October, two 100

PDF® unit trains were delivered to two separate utilities

for test burns. The first was burned in Indiana-Kentucky

Electric Cooperative’s Clifty Creek Station, which is

jointly owned by American Electric Power. The PDF®

was blended with Ohio high-sulfur coal at the utility and

burned in the Babcock & Wilcox open-path, slag-tap

boiler with full instrumentation. Blends tested ranged

between 70 and 90% PDF®, and burn results indicated

that even with one pulverizer out of service, the unit

capacity was increased significantly relative to the base

blend. More importantly, there was at least a 20% NOx

reduction due to a more stable flame. Completion of this

test burn achieved a primary project milestone of testing

PDF® at a major U.S. utility. The remaining 100% PDF®

unit train was sent to Northern Indiana Public Service

Company and to Union Electric’s Sioux Plant near St.

Louis, Missouri.

The largest user of the CDL® was Dakota Gas, which

purchased 101 tank cars. Dakota Gas blended the CDL®

with its fuel and burned the mixture for process heat. A

thorough characterization of the CDL® was done by Dakota Gas, for ENCOAL. Tests with a centrifuge successfully removed much of the sediment in the CDL®.

By the end of July, 1997, about 260,000 tons of coal

had been processed into 120,000 tons of PDF® and

5,101,000 gallons of CDL®. Over 83,500 tons of PDF®

had been shipped to seven customers in six states, as well

as 203 tank cars of CDL® to eight customers in seven

states.

Stabilization of the PDF® presented challenges to the

engineers at ENCOAL. Over 20 different operating conditions were evaluated to enhance the amount of oxygen

absorbed in the VFB system. However, VFB deactivation

was not complete—stabilization still involved “finishing”

using pile layering as well as blending with ROM coal,

increased silo retention time, and higher rehydration. This

“pile layering” allows the PDF® to react with oxygen and

become stable, but is labor intensive and negatively impacts PDF® quality. A stabilization task force composed

of private and government engineers and scientists recommended the construction and testing of a Pilot Air Stabilization System (PASS) to complete the oxidative deactivation of PDF® without drying the product. The design and

installation of the PASS was completed in November

1995 and the unit operated successfully from November

1995 to January 1996. The PASS processed 1⁄2 to 1 ton of

solids per hour, 24 hours per day, for 21⁄2 months producPre-VFB Post-VFB

1992 1993 1994 1995 1996 19971 Sum

Raw Coal Feed (tons) 5,200 12,400 67,500 65,800 68,000 39,340 258,300

PDF Produced (tons) 2,200 4,900 31,700 28,600 33,300 19,300 120,500

PDF Sold (tons) 0 0 23,700 19,100 32,700 7,400 82,900

CDL Produced (bbl) 2,600 6,600 28,000 31,700 32,500 20,300 121,700

Hours on Line 314 980 4,300 3,400 3,600 2,603 15,197

Average Length of

Runs (Days) 2 8 26 38 44 75

Exhibit 5-41

ENCOAL Production

1

Through June 1997.
Coal Processing for Clean Fuels Program Update 1998 5-145

ing a stable PDF® that could be stored in uncompacted

piles without pile layering.

Environmental

Environmental compliance was an important goal

during the demonstration of the LFC® process. Five

significant environmental modifications were made at the

ENCOAL facility.

Extensive ambient air monitoring work revealed no

EPA listed toxins in concentrations anywhere close to

federal limits. It was decided, however, to install a vapor

recovery system on all process water holding vessels to

address an odor problem.

Economic

The “base case” for economics of a commercial plant is

the 15,000-metric-ton/day, three-unit North Rochelle

LFC® plant, the commercial scale plant proposed by

ENCOAL®, with an independent 80-MW cogeneration

unit, and no synthetic fuel tax credit (29c tax credit). It is

assumed that the cogeneration unit is owned and operated

by an independent third-party. The capital cost for a full

scale three module LFC® plant is $475 million.

Economic benefits from an LFC® commercial plant

are derived from the margin in value between a raw,

unprocessed coal and the upgraded products, making an

LFC® plant dependent on the cost of feed coal. In fact,

this is the largest single operating cost item. The total

estimated operating cost is $9.00/ton of feed coal including the cost of feed coal, chemical supplies, maintenance,

and labor.

A financial model was constructed using a spreadsheet to evaluate the project’s financial viability. The

unleveraged Internal Rate of Return (IRR) on the base

case of around 15% is encouraging given the project’s

upfront capital requirements, long construction period,

and 30-year project life. The project generates impressive

after-tax cash flows (ATCF’s) with payback on the base

case of less than nine years from plant startup and cumulative ATCF’s over 30 years, exceeding $2 billion.

The probability of reaching the 18–20% range for

IRR is good, given a combination of lower capital costs

and increased revenues. An increase in revenue of 10%

coupled with a decrease in capital cost of 10% would

provide an unleveraged IRR in excess of 18%.

A possible upside to the base case is use of the nonconventional fuel tax credit commonly referred to as 29c.

The addition of 29c to the base case evaluation adds over

15% to the unleveraged IRR, and more than doubles the

project net present value.

Commercial Applications

AEI Resources, a unit of Addington Enterprises of

Ashland, Kentucky, through its 1998 acquisition of

Zeigler Coal Holding Co., holds an undivided and equal

interest in the LFC® technology along with SGI International. AEI Resources is the administrative partner responsible for preparation of lease agreements and contracts. In order to determine the viability of potential

LFC® plants, five detailed commercial feasibility studies—two Indonesian, one Russian, and two U.S.

projects—have been completed. Permitting of a 15,000

metric-ton/day commercial plant in Wyoming is nearly

complete.

Contacts

J.P. Frederick, (307) 686-2720, ext. 29

ENCOAL® Corporation

P.O. Box 3038

Gillette, WY 82717

(307) 686-2720, ext. 27

(307) 686-2894 (fax)

jfrederick@vcn.com

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

References

• ENCOAL Mild Coal Gasification Project: Commercial Plant Feasibility Study. U.S. Department of

Energy. September 1997.

• ENCOAL Mild Gasification Project: Final Design

Modifications Report. U.S. Department of Energy.

September 1997.

• ENCOAL Mild Coal Gasification Project: ENCOAL

Project Final Report. U.S. Department of Energy.

September 1997.

• ENCOAL Mild Coal Gasification Plant: Commercial

Plant Feasibility Study. U.S. Department of Energy.

May 1997.
5-146 Program Update 1998 Coal Processing for Clean Fuels
Industrial Applications
5-148 Program Update 1998 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)—

technology owner

CPC-Macawber, Ltd. (formerly named Simon-Macawber,

Ltd.)—equipment supplier (world rights to sublicense

technology)

Fluor Daniel, Inc.—architect and engineer

ATSI, Inc.—injection equipment engineer

(North America technology licensee)

Location

Burns Harbor, Porter County, IN (Bethlehem Steel’s

Burns Harbor Plant, Blast Furnace Units C and D)

Coal

Eastern bituminous, 0.8–2.8% sulfur; and

western subbituminous, 0.4–0.9% sulfur

Technology

British Steel and CPC-Macawber blast furnace granularcoal injection (BFGCI) process

Plant Capacity/Production

7,000 net tons of hot metal (NTHM)/day (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; 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

natural gas injection, reduces blast furnace production

rates. Coal, with a lower hydrogen content than either

natural gas or oil, does not cause as severe a reduction in

raceway temperatures. In addition to 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. BFGCI technology has significant potential to

reduce pollutant emissions and enhance blast furnace

production because coke production results in significant emissions of NOx

, SO2, and air toxics. Coal could

replace up to 40% of the coke requirement.

Emissions generated by the blast furnace itself

remain virtually unchanged by the injected coal; the gas

exiting the blast furnace is cleaned and used in the mill.

Sulfur from the coal is removed by the limestone flux

and bound up in the slag, which is a salable by-product.

Two high-capacity blast furnaces, Units C and D at

Bethlehem Steel’s Burns Harbor Plant, were retrofitted
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

**Years omitted

 1 2

Industrial Applications Program Update 1998 5-149

1989 1990 1991 1993 1994 1995 1996 1997 1998 1999 2000

with BFGCI technology. Each unit has a production

capacity of 7,000 NTHM/day. The two units use about

2,800 tons/day of coal during full operation. Tests will

include eastern bituminous coals with sulfur content of

0.8–2.8% and a western subbituminous coal having 0.4–

0.9%.

Project Status/Accomplishments

Early trials comparing high- and low-volatile coals as

injectant showed that low-volatile coal replaces more

coke and results in better blast furnace operation than

high-volatile coal. The replacement ratio was 0.96

pounds of coke replaced for every pound of low-volatile

coal used. A major conclusion of the early trials was that

granular-coal injection performs very well on large blast

furnaces. The low-volatile coals used were Buchanan and

Virginia Pocahantas coals (different mines, but same

seam and similar properties).

Further trials were conducted on the effect of higher

coal ash content on the furnace operation. The baseline

coal was the Virginia Pocahantas coal with high carbon

and relatively low ash content—both characteristics provide high coke replacement. Three trials were run varying the ash content while keeping all other parameters

constant.

The high ash trials revealed that (1) furnace permeability was not changed and a higher ash coal did not

have a deleterious effect in the raceway, (2) furnace blast

pressure and wind volume were maintained at the base

conditions during the trial, (3) furnace production rates

were up as delay periods declined during the trial, and (4)

hot metal silicon and sulfur content and variability were

about the same during all three periods.

Trials were also conducted to determine the coke rate

penalty to the blast furnace that results from the use of

higher ash injection coal. Corrected coke rates calculated

from the trial results reveal that there is a coke rate disadvantage of 3 lb/NTHM for each 1% increase of ash in the

injection coal at an injection rate of 260 lb/NTHM.

Sanborn Creek Colorado “B” Seam Coal was selected for trials on western coal. Sufficient granular and

Preaward

DOE selected

project (CCT-III)

12/19/89

12/89 11/90

Cooperative agreement awarded 11/26/90

Design and Construction Operation

9/99

Project completed/final report

issued 9/99*

pulverized data has been collected on this coal. The data is

currently being analyzed.

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 States

that has a moisture content no higher than 10%. 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. 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 through- out the world. British Steel and CPCMacawber have recently installed a similar facility at U.S.

Steel’s Fairfield blast furnace.

Operation completed 6/99*

**

NEPA process completed (EA) 6/8/93

Construction started 9/93

Design completed 12/93

Environmental monitoring plan completed 12/23/94

Construction completed 1/95

Preoperational tests initiated 2/95

Operation initiated 11/95

11/95
5-150 Program Update 1998 Industrial Applications

Technology/Project Description

The HIsmelt® process is based on producing hot metal

and slag from iron ore fines and non-coking coals. The

heart of the process is creating suitable conditions in the

HIsmelt® vertical reactor where there is high post-combustion levels with high heat transfer efficiency. The goal

is to have sufficient energy input for the reduction and

smelting of iron oxides. Tests have consistently demonstrated 60% post-combustion levels with 90% heat transfer efficiency.

The HIsmelt® process uses a vertical smelt reduction

reactor, which is a closed molten bath vessel, into which

iron ore fines, coal, and fluxes are injected. The coal,

which can have a wide range of composition, is injected

into the bath where carbon is rapidly dissolved. The

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 the Geneva

Steel Company)

Additional Team Members

Geneva Steel Company—cofunder and host; constructor

and operator of unit

PacifiCorp—cofunder

Location

Vineyard, Utah County, UT (Geneva Steel Company’s

mill)

Technology

HIsmelt® direct ironmaking process

Plant Capacity/Production

3,300 tons/day liquid iron production

Coal

Bituminous, 0.5% sulfur

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 with the co-production of electricity using various

U.S. coals in an efficient and environmentally responsible

manner.

HIsmelt is a registered trademark of HIsmelt Corporation Pty Limited.

CPICOR is a trademark of the CPICORTM Management Company,

dissolved carbon reacts with oxygen (from the injected

iron ore) to form carbon monoxide (CO) and metallic

iron. Injection gases and evolved CO entrain and propel

droplets of slag and molten iron upward into the post

combustion zone.

The iron reduction reaction in the molten bath is

endothermic; therefore, additional heat must be generated

and returned to the bath to sustain the reduction process

and maintain an acceptable hot metal temperature. This

additional heat is generated by post-combusting the CO

and hydrogen (H2

) from the bath with oxygen-enriched

hot air blast entering through the central top lance. The

heat is absorbed by the metal and slag droplets and returned to the bath as the droplets descend under the gravity. Droplets in contact with the gas in the post-combus-
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

**Years omitted

 1 2

Industrial Applications Program Update 1998 5-151

1993 1997 2000 1994 1996 2001 2002 2003 2004 2005 2006

DOE selected project

(CCT-V) 5/4/93

5/93

Preaward

Cooperative agreement awarded 10/11/96

NEPA process completed 12/00*

Construction started 12/00*

Design and Construction

Operation initiated 5/03*

Construction completed 5/03*

Operation

Project

completed/final

report issued 10/05*

Operation

completed 10/05*

tion zone absorb heat, but are shrouded during the descent

by ascending reducing gases, which together with bath

CO, prevent unacceptable levels of slag (FeO).

The molten iron collects in the bottom of the bath

and is continuously tapped from the reactor through a

fore-hearth, which maintains a constant level of iron in

the reactor. Slag, which is periodically tapped through a

conventional blast furnace-type tap hole, is used to coat

and control the internal cooling system and reduce the

heat loss.

Reacted gases, mainly nitrogen (N2

), carbon dioxide

(CO2

), CO, H2, and water vapor (H2O), exit the vessel.

After scrubbing the reacted gases, the cleaned gases will

be combusted to produce 170-MWe of power. The

cleaned gases can also be used to pre-heat and partially

pre-reduce the incoming iron ore.

Project Status/Accomplishments

The cooperative agreement was awarded on October 11,

1996. Permitting and project definition are underway.

CPICORTM analyzed the global assortment of new

direct ironmaking technologies to determine which technology would be most adaptable to western U.S. coals

and raw materials. Originally, the COREX® process

appeared suitable for using Geneva’s local raw materials;

however, lack of COREX® plant data on 100% raw coals

and ores prevented its application in this demonstration.

Thus, CPICORTM chose to examine alternative direct

ironmaking processes. The processes evaluated included:

AISI direct ironmaking, DIOS, Romelt, Tecnored, Cyclonic Smelter, and HIsmelt®. The HIsmelt® process

appears to offer good economic and operational potential,

as well as the prospect of rapid commercialization.

CPICORTM has completed testing of two U.S. coals

at the HIsmelt® pilot plant near Perth, Australia.

Commercial Applications

The HIsmelt® technology is a direct replacement for existing blast furnace and coke-making facilities with additional potential to produce steam for power production.

Of the existing 79 coke oven batteries, half are 30 years

of age or older and are due for replacement or major

rebuilds. There are about 60 U.S. blast furnaces, all of

which have been operating for more than 10 years, with

some originally installed up to 90 years ago. HIsmelt®

represents a viable option as a substitute for conventional

ironmaking technology.

The HIsmelt® process is ready for demonstration.

Two pilot plants have been built, one in Germany in 1984

and one in Kwinana, Western Australia in 1991. Through

test work in Australia, the process has been proven—

operational control parameters have been identified and

**

Environmental monitoring

plan completed 9/02*

5/03

**

10/96 10/05
5-152 Program Update 1998 Industrial Applications

most of the coal particles near the cyclone wall. The

combustor was designed to retain a high percentage of the

ash and sorbent fed to the combustor as slag. For NOx

control, the combustor is operated fuel rich, with final

combustion taking place in the 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 x 106

 Btu/hr, oil-designed package boiler located at the

Technology/Project Description

Coal Tech’s horizontal cyclone combustor is internally

lined with an air-cooled 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, coalparticle 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

Industrial 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 x 106

 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 1998 5-153

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

Tampella Power Corporation boiler factory in

Williamsport, PA.

Results Summary

Environmental

• SO2

 removal efficiencies of over 80% were achieved

with sorbent injection in the furnace at various

calcium-to-sulfur (Ca/S) molar ratios.

• SO2

 removal efficiencies up to 58% were achieved

with sorbent injection in the combustor at a Ca/S

molar ratio of 2.0.

• A maximum of 1/3 of the coal’s sulfur was retained in

the dry ash removed from the combustor (as slag) 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 55–90%. 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 four days duration.

An additional 100 hours of testing was performed as part

9/91

Project completed/final report issued 9/91
5-154 Program Update 1998 Industrial Applications

The slagging combustor, associated piping, and control panel for

Coal Tech’s advanced ceramic-lined slagging combustor are shown.

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 1.0–3.3% and volatile matter contents

ranging from 19–37% 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 molar ratio of 2. A

maximum of 1/3 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 55–90%. 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 x 106

 Btu/hr from a peak of 19 x 106 Btu/hr (or a

3-to-1 turndown) was achieved. The maximum heat input

during the tests was around 20 x 106

 Btu/hr, even though

the combustor was designed for 30 x 106

 Btu/hr and the

boiler was thermally rated at around 25 x 106

 Btu/hr. This

situation resulted from facility limits on water availability

for the boiler and for cooling the combustor. In fact, due

to the lack of sufficient water cooling, even 20 x 106

 Btu/

hr was borderline, so that most of the testing was conducted at lower rates.

Different sections of the combustor had different

materials requirements. Suitable materials for 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, (610) 667-0442

Coal Tech Corp.

P.O. Box 154

Merion Station, PA 19066

coaltechbz@compuserve.com

William E. Fernald, DOE/HQ, (301) 903-9448

Arthur L. Baldwin, FETC, (412) 892-6011
Industrial Applications Program Update 1998 5-155

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.

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. (Available from NTIS as DE93017043.)

• 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 Internal Sulfur, Nitrogen, and Ash Control. Coal

Tech Corporation. Report No. DOE/FE-0077. U.S.

Department of Energy. February 1987. (Available

from NTIS as DE87005804.)
5-156 Program Update 1998 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 scfm 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, potassiumbased fertilizer byproducts.

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 CKD from the cement-making process. Passamaquoddy Technology Recovery Scrubber is a trademark of the

Passamaquoddy Tribe.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

 1 2

Industrial Applications Program Update 1998 5-157

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/scf, about

1/10 that allowed for cement kilns, were achieved with

dust loadings of approximately

0.04 gr/scf.

• Pilot testing conducted at U.S. Environmental Protection Agency laboratories under Passamaquoddy Technology, L.P. sponsorship showed 98% HCl removal.

• On three different runs, VOC (as represented by alphapinene) removal efficiencies of 72.3, 83.1, and 74.5%

were achieved.

• A reduction of approximately 2% in CO2

 emissions

was realized through recycling of the CKD.

Operational

• During the last operating interval, April to September

1993, recovery scrubber availability (discounting 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 three basic operating intervals dictated by winter shutdowns for maintenance and inventory and 14 separate operating periods

(within these basic intervals) largely determined by un2/94

Project completed/final report issued 2/94

Construction started 6/89

Operation

completed 9/93
5-158 Program Update 1998 Industrial Applications

Exhibit 5-42

Summary of Emissions and Removal Efficiencies

Operating Operating Inlet (lb/hr) Outlet (lb/hr) Removal Efficiency (%)

Period Time (hr) SO2 NOx SO2 NOx SO2 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 Average 109 289 12 234 89.2 18.8

foreseen host-plant maintenance and repairs and a depressed 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 scfm 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 5-42 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/scf and demonstrated particulate emission rates of

0.005–0.007 gr/scf—less than 1/10 the current allowable

limit.
Industrial Applications Program Update 1998 5-159

The Passamaquoddy Technology Recovery ScrubberTM became a

permanent part of the Dragon Products facility at the project’s end.

The Passamaquoddy Technology Recovery ScrubberTM

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.

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.

The scrubber became a permanent part of the cement

plant at the end of the demonstration. A feasibility study

has been completed for a Taiwanese cement plant.

Contacts

Thomas N. Tureen, Project Manager, (207) 773-7166

Passamaquoddy Technology, L.P.

1 Monument Way

Portland, ME 04101

(207) 773-7166

(207) 773-8832 (fax)

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.)

• 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.)
5-160 Program Update 1998 Industrial Applications

Industrial Applications

Pulse Combustor Design

Qualification Test

Participant

ThermoChem, Inc.

Additional Team Member

Manufacturing and Technology Conversion

International, Inc. (MTCI)—technology supplier

Location

Baltimore, MD (MTCI Test Facility)

Technology

MTCI’s PulsedEnhancedTM Steam Reforming using a

multiple resonance tube pulse combustor.

Plant Capacity/Production

13 million Btu/hr (steam reformer)

Coal

Powder River Basin subbituminous

Project Funding

Total project cost $8,612,054 100%

DOE 4,306,027 50

Participants 4,306,027 50

Project Objective

To demonstrate the operational/commercial viability of a

single 253-resonance-tube pulse combustor unit and

evaluate characteristics of coal-derived fuel gas generated by an existing Process Development Unit.

Technology/Project Description

MTCI’s PulsedEnhancedTM Steam Reforming process

incorporates an indirect heating process for thermochemical steam gasification of coal to produce hydrogen-rich, clean, medium-Btu content fuel gas without the

need for an oxygen plant. Indirect heat transfer is provided by the multiple resonance-tube pulse combustor by

immersing the combustor tubes in the fluidized-bed

steam gasification reactor. Pulse combustion increases

heat transfer rate by a factor of 3 to 5, thus greatly reducing the heat transfer area required in the gasifier.

The pulse combustor represents the core of the

PulsedEnhancedTM Steam Reforming process because it

provides a highly efficient and cost-effective heat source.

Demonstration of the combustor at the 253-resonancetube commercial scale is critical to market entry. The

253-resonance-tube unit represents a 3.5 scale-up from

previous tests. Testing will seek to verify scale-up criteria

and appropriateness of controls and instrumentation.

Also, an existing Process Development Unit (PDU) will

be used to gasify coal feedstock to provide fuel gas data,

including energy content, species concentration, and yield.

Char from the PDU will be evaluated as well.

The facility will also have a product gas cleanup train

that includes two stages of cyclones, a venturi scrubber

with a scrubber tank, and a gas quench column. An aircooled heat exchanger will be used to reject heat from the

condensation of excess steam (unreacted fluidization

steam) quenched in the venturi scrubber and gas quench

column. All project testing will be performed at the

MTCI test facility in Baltimore, Maryland.

Project Status/Accomplishments

On September 10, 1998, DOE approved revision of

ThermoChem, Inc.’s Cooperative Agreement for a scaleddown, 16-month project. The original project, awarded

in October, 1992, was a commercial demonstration facility that would employ 10 identical 253-resonance-tube

pulse combustor units. After fabrication of the first combustor unit, the project went through restructuring. The
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

Industrial Applications Program Update 1998 5-161

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

Design and Construction

*Projected Date

Revised Cooperative

Awarded 9/29/98

Operation

initiated 10/99*

Operation complete/final

report issued 2/00*

10/99 2/00

revised project will demonstrate a single 253-resonancetube pulse combustor. The first major milestone is

completion of design by early 1999. NEPA requirements

were satisfied on November 30, 1998 with a Categorical

Exclusion.

Commercial Applications

PulsedEnhancedTM Steam Reforming has application in

many different processes. Coal, with the world production

on the order of four billion tons per year, constitutes the

largest potential feed stock for steam reforming. Other

potential feedstocks include spent liquor from pulp and

paper mills, refused-derived fuel, municipal solid waste,

sewage sludge, biomass, and other wastes.

Although the project will demonstrate mild gasification only, the following coal-based applications are envisioned:

• Coal processing for combined-cycle power generation,

• Coal processing for fuel cell power generation,

• Coal pond waste and coal rejects processing to produce a hydrogen-rich gas from the steam reformer for

use in overfiring or reburning to reduce NOx emissions,

• Coal processing for production of gas or liquid fuel

and char for the steel industry,

• Coal processing for producing compliance fuels,

• Mild gasification of coal,

• Direct reduction steel production,

• Co-processing of coal and wastes, and

• Coal drying.

In addition, the technology has application for black

liquor processing and chemical recovery and for hazardous, low-level radioactive, and low-level mixed waste

volume reduction and destruction.
Program Update 1998 A-1

Appendix A: Historical Perspective and

Legislative History

Historical Perspective

There were a number of key events that prompted

creation of the CCT Program and impacted its focus

over the course of the five solicitations. The roots of

the CCT Program can be traced to the acid rain

debates of the early 1980s, culminating in U.S. and

Canadian envoys recommending a five year, $5 billion

U.S. effort to curb precursors to acid rain formation—

SO2

 and NOx. This recommendation was adopted and

became a presidential initiative in March 1987.

As a part of the response to the recommendations

of the Special Envoys on Acid Rain in April 1987, the

President directed the Secretary of Energy to establish

a panel to advise the President 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, that addressed actions that states could take to

provide incentives for demonstrating and deploying

clean coal technologies. The panel 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. The task force also examined cost-effective

emissions reduction measures that might be inhibited

by various federal, state, and local regulations. The

task force recommended 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.

Initial CCT Program emphasis was on controlling

SO2 and NOx emissions from existing coal-based

power generators. Approaches demonstrated through

the program were coal processing to produce clean

fuels, combustion modification to control emissions,

postcombustion cleanup of flue gas, and repowering

with advanced power generation systems. These early

efforts (projects resulting from the first three solicitations) produced a suite of cost-effective compliance

options available today to address acid rain concerns.

As the CCT Program evolved, work began on

drafting what was to become the Clean Air Act

Amendments of 1990. Through a dialog with EPA

and Congress, the program was able to remain responsive to shifts in environmental emphasis. Also,

projects in place enabled CAAA architects to have

access to real-time data on emission control capabilities while structuring proposed acid rain regulations

under Title IV of the CAAA. Aside from acid rain,

there was an emerging issue in the area of hazardous

air pollutants (HAPs), also referred to as air toxics.

Title III of the CAAA listed 189 airborne compounds

subject to control, including trace elements and

volatile and semi-volatile compounds. To assess the

impacts on coal-based power generation, CCT Program projects were leveraged to obtain data through

an integrated effort among DOE, EPA, EPRI, and the

Utility Air Regulatory Group. Through this effort,

concerns about HAPs relative to coal-based power

generation have been significantly mitigated, enabling

focus on but a few flue gas constituents. Also, because NOx

 is a precursor to ozone formation, the

presence of NOx

 in ozone nonattainment areas, even at

low levels, became an issue. This precipitated action

in the CCT Program to include technologies capable

of deep NOx

 reduction in the portfolio of technologies

sought.

In the course of the last two solicitations of the

CCT Program, a number of energy and environmental

considerations combined to change the emphasis

toward seeking high-efficiency, very-low-emission

power generation technology. Energy demand projections in the United States showed the need for continued reliance on coal-based power generation, with

significant growth required into the 21st century. The

CAAA, however, capped SO2

 emissions at year 2000

levels, and NOx

 continued to receive increased attention relative to ozone nonattainment. Furthermore,
A-2 Program Update 1998

particulate emissions were coming under increased

scrutiny because of correlations with lung disorders

and the tendency for toxic compounds to adhere to

particulate matter. Added to these concerns was the

growing concern over global warming, and more

specifically, the CO2

 produced from burning fossil

fuels. Coal became a primary target because of the

high carbon-to-hydrogen ratio relative to natural gas,

resulting in somewhat higher CO2 emissions per unit

of energy produced. However, coal is the fuel of

choice (if not necessity) for many developing countries where projected growth in electric power generation is the greatest. The path chosen to respond to

these considerations was to pursue advanced power

generation systems that could provide major enhancements in efficiency and control SO2

, NOx, and particulates without introducing external parasitic control

devices. (Increased efficiency translates to less coal

consumption per unit of energy produced.) As a result,

a number of advanced power generation projects were

undertaken, representing pioneer efforts recognized

throughout the world.

Legislative History

The legislation authorizing the CCT Program is

found in Public Law 98-473, Joint Resolution Making

Continuing Appropriations for Fiscal Year 1985 and

for Other Purposes. Title I set aside $750 million of

the congressionally rescinded $5.375 billion of the

Synthetic Fuels Corporation into a special U.S. Treasury account entitled the “Clean Coal Technology

Reserve.” This account was dedicated to “conducting

cost-shared clean coal technology projects for the

construction and operation of facilities to demonstrate

the feasibility of future commercial applications of

such technology.” Title III of this act directed the

Secretary of Energy to solicit statements of interest in

and proposals for clean coal projects. In keeping with

this mandate, DOE issued a program announcement,

which resulted in the receipt of 176 proposals representing both domestic and international projects with a

total estimated cost in excess of $8 billion.

After this significant initial expression of interest

in clean coal demonstration projects, Public Law

99-190, enacted December 1985, appropriated

$400 million to conduct cost-shared demonstration

projects. Of the total appropriated funds, approximately $387 million was made available for costshared projects to be selected through a competitive

solicitation, or Program Opportunity Notice (PON),

referred to as CCT-I. (The remaining funds were

required for program direction and the legislatively

mandated Small Business Innovation Research Program [SBIR] and Small Business Technology Transfer Program [STTR].)

In a manner similar to the initiation of CCT-I,

Congress again directed DOE to solicit information

from the private sector in the Department of the

Interior and Related Agencies Appropriations Act for

FY1987 (Public Law 99-591, enacted October 30,

1986). The information received was to be used to

establish the level of potential industrial interest in

another solicitation, this time involving clean coal

technologies capable of retrofitting, repowering, or

modernizing existing facilities. Projects were to be

cost-shared, with industry sharing at least 50 percent

of the cost. As a result of the solicitation, a total of

39 expressions of interest were received by DOE in

January 1987.

On March 18, 1987, the President announced the

endorsement of the recommendations of the Special

Envoys on Acid Rain, including a $2.5 billion government share of funding for industry/government demonstrations of innovative control technology over a

five year period. The Secretary of Energy stated that

the department would ask Congress for an additional

$350 million in FY1988 and an advanced appropriation of $500 million in FY1989. Additional appropriations of $500 million would be requested in fiscal

years 1990, 1991, and 1992. This request was made

by the President on April 4, 1987.

Public Law 100-202, enacted December 22, 1987,

as amended by Public Law 100-446, appropriated a

total of $575 million to conduct CCT-II. About

$536 million was for projects, with the remainder for

program direction and the SBIR and STTR Programs.

The Department of the Interior and Related

Agencies Appropriations Act for FY1989 (Public Law

100-446, enacted September 27, 1988) provided

$575 million for necessary expenses associated with

clean coal technology demonstrations in the CCT-III

solicitation. Of the total funding, about $546 million

was made available for cost-sharing projects, with the

remainder for program direction and the SBIR and

STTR Programs. The act continued the requirement

that proposals must demonstrate technologies capable

of retrofitting or repowering existing facilities. The

statute also authorized the use of Tennessee Valley

Authority power program funds as a source of nonfederal cost-sharing, except if provided by annual appropriations acts. In addition, funds borrowed by Rural

Electrification Administration )now Rural Utilities

Service) electric cooperatives from the Federal Financing Bank became eligible as cost-sharing in the

CCT-III solicitation, except if provided by annual

appropriations.
Program Update 1998 A-3

In the Department of the Interior and Related

Agencies Appropriations Act of 1990 (Public Law

101-121, enacted October 23, 1989), Congress

provided $600 million for the CCT-IV solicitation.

CCT-IV, according to the act, “shall demonstrate

technologies capable of replacing, retrofitting, or

repowering existing facilities and shall be subject to

all provisos contained under this head in Public Laws

99-190, 100-202 and 100-446 as amended by this

Act.” About $563 million was made available for

federal cofunding of projects selected in CCT-IV,

with the remainder for program direction and the

SBIR and STTR Programs.

In Public Law 101-121, enacted October 23,

1989, Congress also provided $600 million for the

CCT-V solicitation. CCT-V, according to the act,

“shall be subject to all provisos contained under this

head in Public Laws 99-190, 100-202 and 100-446 as

amended by this Act.” Approximately $568 million

was made available for federal cofunding of projects

to be selected in this solicitation, with the remainder

again for program direction and the SBIR and STTR

Programs.

Subsequent acts (Public Laws 101-164, 101-302,

101-512, and 102-154) modified the schedule for

issuing CCT-IV and/or CCT-V PONs and selecting

projects. In Public Law 101-512, Congress directed

DOE to issue the PON for CCT-IV not later than

February 1, 1991, with selections to be made within

8 months. In Public Law 102-154, Congress directed

DOE to issue CCT-V PON not later than July 6, 1992,

with selections to be made within 10 months. This

later act also directed that CCT-V proposals should

advance significantly the efficiency and environmental

performance of coal-using technologies and be applicable to either new or existing facilities.

Public Laws 101-164, 101-302, 101-512, 103-

138, and 103-332 adjusted the rate at which funds

were to be made available to the program.

CCT Program funds have been further adjusted

through sequestering requirements of the GrammRudman-Hollings Deficit Reduction Act as well as

rescissions. Sequestering reduced CCT Program

appropriations as follows:

• $2.4 million was sequestered from the $400

million appropriated by Public Law 99-190.

• $2,600 was sequestered from the $575 million

appropriated by Public Law 100-202, as

amended by Public Law 100-446.

• $2,028 was sequestered from the $575 million

appropriated by Public Law 100-446, as

amended by Public Law 101-164.

• $455 was sequestered from the $1.2 billion

appropriated by Public Law 101-121, as

amended by Public Laws 101-512, 102-154,

102-381, 103-138, 103-332, 104-6, 104-208,

and 105-18.

Rescissions have reduced CCT Program appropriations as follows:

• $200 million was rescinded by Public Law

104-6.

• $123 million was rescinded by Public Law

104-208.

• $17 million was rescinded by Public Law

105-18.

In 1998, $40 million of the CCT program funds

were deferred. Funds will be restored over a three

year period beginning October 1, 1999.

Exhibit A-1 lists all the key legislation relating to

the CCT Program and provides a summary of provisions relating to program funding as well as program

implementation. Following this exhibit are funding

provisions excerpted from appropriations and other

relevant funding-related acts.
A-4 Program Update 1998

Exhibit A-1

CCT Program Legislative History

Public Date

Law Enacted CCT Round Program Funding Implementation Provisions

98-473 10/12/84 Initiation of CCT

Program; informational

solicitation

99-88 8/15/85

99-190 12/19/85 CCT-I

99-591 10/30/86 Second informational

solicitation

100-202 12/22/87 CCT-II

Title III required publication of a notice soliciting

statements of interest in and proposals for projects

employing emerging CCTs. A report to Congress was

required no later than 4/15/85.

Conference Report (H. Rep. 99-236) concurred with

CCT project guidelines contained in Senate Report

99-82, with certain modifications.

Required a PON (CCT-I) to be issued and projects to be

selected no later than 8/1/86. Project cost-sharing

provisions were detailed.

Title II required publication of a notice soliciting

statements of interest in, and informational proposals for

projects employing emerging CCTs capable of retrofitting, repowering, or modernizing existing facilities. A

report to Congress was required no later than 3/6/87.

Required a request for proposals (CCT-II) to be issued

no later than 60 days following enactment, for emerging

CCTs capable of retrofitting or repowering existing

facilities. Extended project selection from 120 days to

160 days after receipt of proposals. Provided for costsharing of pre-award costs for preparation and submission of environmental data upon signing of the cooperative agreement. Conference Report (H. Rep. 100-498)

provided that project cost-sharing funds be made

available to nonutility as well as utility applications. No

funds were made available for new, stand-alone

applications. H. Rep. Report 100-171 and Senate

Report 100-165 outlined provisions for participant to

repay government contributions.

Rescinded $750 million of $5.375 billion from the Energy

Security Reserve (Synthetic Fuels Corporation) to be

deposited in a U.S. Treasury Department account entitled

“Clean Coal Technology Reserve” for conducting costshared CCT projects for the construction and operation of

facilities to demonstrate the feasibility for future commercial

application of such technology, without fiscal year limitation, subject to subsequent annual appropriation.

Deferred $1.6 million for obligation until 10/1/85.

Conference Report (H. Rep. 99-450) agreed to a

$400-million CCT Program as described under the U.S.

Treasury Department Energy Security Reserve, with the

request for proposals to be for the full $400 million.

(Contained no funding provisions for CCT Program)

Appropriated $50 million for FY beginning 10/1/87 until

expended and $525 million for FY beginning 10/1/88 until

expended.
Program Update 1998 A-5

Exhibit A-1 (continued)

CCT Program Legislative History

Public Date

Law Enacted CCT Round Program Funding Implementation Provisions

Made available $575 million on 10/1/89 until expended.

Pub. L. 100-202 was amended by striking $525 million and

inserting $190 million for FY beginning 10/1/88 until

expended, $135 million for fiscal year beginning 10/1/89

until expended, and $200 million for FY beginning 10/1/90

until expended, provided that outlays for FY89 resulting

from use of funds appropriated under Pub. L. 100-202, as

amended, did not exceed $15.5 million.

Funds appropriated for FY1989 were made available for a

third solicitation.

Made available $600 million on 10/1/90 until expended and

$600 million on 10/1/91 until expended. Pub. L. 100-446

was amended by striking $575 million and inserting

$450 million to be made available on 10/1/89 until

expended and $125 million to be made available on

10/1/90. Unobligated balances excess to the needs of the

procurement for which they originally were made available

may be applied to other procurements for which requests for

proposals had not yet been issued, except that no supplemental, backup, or contingent selection of projects could be

made over and above the projects originally selected.

Appropriation for FY1990 was amended by striking

$450 million and inserting $419 million and by striking

$125 million and inserting $156 million.

Obligation of funds previously appropriated for CCT-IV

and CCT-V was deferred until 9/1/91.

100-446 9/27/88 CCT-III

101-45 6/30/89 CCT-III

101-121 10/23/89 CCT-IV and CCT-V

101-164 11/21/89 CCT-IV and CCT-V

101-302 5/25/90 CCT-IV and CCT-V

Request for proposals (CCT-III) to be issued by 5/1/89

for emerging CCTs capable of retrofitting or repowering

existing facilities. Proposals were to be due 120 days

after issuance of the PON; projects were to be selected

no later than 120 days after receipt of proposals.

Funds borrowed by REA electric cooperatives from the

Federal Financing Bank were made eligible as costsharing. Funds derived by the Tennessee Valley

Authority from its power program were deemed

allowable as cost-sharing except if provided by annual

appropriations acts.

Project selections for the third solicitation were to be

made not later than 1/1/90.

Two solicitations (CCT-IV and CCT-V) to be issued,

one for each appropriation, to demonstrate technologies

capable of replacing, retrofitting, or repowering existing

facilities, subject to all provisos contained in Pub. L.

99-190, 100-202, and 100-446 as amended. The PON

(CCT-IV) using funds becoming available on 10/1/90

was to be issued by 6/1/90, with selections made by

2/1/91. The PON (CCT-V) using funds becoming

available on 10/1/91 was to be issued no later than

9/1/91, with selections made by 5/1/92.

Solicitations could not be conducted prior to ability to

obligate funds. Repayment provisions for CCT-IV and

CCT-V were to be the same as for CCT-III.
A-6 Program Update 1998

Exhibit A-1 (continued)

CCT Program Legislative History

Public Date

Law Enacted CCT Round Program Funding Implementation Provisions

Pub. L. 101-121 was amended by striking $600 million

made available on 10/1/90 until expended and $600 million

made available on 10/1/91 until expended and inserting

$600 million made available as follows: $35 million on

9/1/91, $315 million on 10/1/91, and $250 million on

10/1/92, all sums remaining until expended, for use in

conjunction with a separate general request for proposals,

and $600 million made available as follows: $150 million

on 10/1/91, $225 million on 10/1/92, and $225 million on

10/1/93, all sums remaining until expended, for use with a

separate general request for proposals.

Pub. L. 102-512 was amended by striking $150 million on

10/1/91 and $225 million on 10/1/92 and inserting

$100 million on 10/1/91 and $275 million on 10/1/92.

101-512 11/5/90 CCT-IV and CCT-V

102-154 11/13/91 CCT-V

The CCT-IV solicitation was to be issued not later than

2/1/91. The CCT-V PON was to be issued not later than

3/1/92. Project selections were to be made within eight

months of PON’s issuance. Repayment provisions were

to be the same as for CCT-III. Provisions were included

to provide protections for trade secrets and proprietary

information. Conference Report (H. Rep. 101-971)

recommends changes to program policy factors.

The CCT-V PON was delayed to not later than

7/6/92, with selection to be made within 10 months

(extended by two months). The PON was to be for

projects that advance significantly the efficiency and

environmental performance of coal-using technologies

and be applicable to either new or existing facilities.

Conference Report (H. Rep. 102-256) stated expectations that the CCT-V solicitation would be conducted

under the same general types of criteria as CCT-IV,

principally modified only to (1) include the wider range

of eligible technologies or applications; (2) adjust

technical criteria to consider allowable development

activities, strengthen criteria for nonutility demonstrations, and adjust commercial performance criteria for

additional facilities and technologies with regard to

aspects of general energy efficiency and environmental

performance; and (3) clarify and strengthen cost and

finance criteria, particularly with regard to development

activities.

Funding was allowed for project-specific development

activities for process performance definition, component

design verification, materials selection, and evaluation of

alternative designs on a cost-shared basis up to a limit of

10 percent of the government share of project cost.
Program Update 1998 A-7

Exhibit A-1 (continued)

CCT Program Legislative History

Public Date

Law Enacted CCT Round Program Funding Implementation Provisions

Pub. L. 101-512 was amended by striking $250 million on

10/1/92 and inserting $150 million on 10/1/93 and

$100 million on 10/1/94; and by striking $275 million on

10/1/92 and $225 million on 10/1/93 and inserting $250

million on 10/1/93 and $250 million on 10/1/94.

(Contained no funding provisions for CCT Program)

Pub. L. 101-512 was amended by striking $150 million on

10/1/93 and $100 million on 10/1/94 and inserting

$100 million on 10/1/93, $100 million on 10/1/94, and

$50 million on 10/1/95; and by striking $250 million on

10/1/93 and $250 million on 10/1/94 and inserting

$125 million on 10/1/93, $275 million on 10/1/94, and

$100 million on 10/1/95.

Pub. L. 101-512 was amended by striking $100 million on

10/1/94 and $50 million on 10/1/95 and inserting

$18 million on 10/1/94, $100 million on 10/1/95, and

$32 million on 10/1/96; and by striking $275 million on

10/1/94 and $100 million on 10/1/95 and inserting

$19.121 million on 10/1/94, $100 million on 10/1/95, and

$255.879 million on 10/1/96.

102-154

(continued)

102-381 10/5/92

102-486 10/24/92

103-138 11/11/93

103-332 9/30/94

Development activities eligible for cost-sharing included

limited modifications to existing facilities for projectrelated testing but not construction of new facilities.

Section 1301—Coal RD&D and Commercial Applications Programs (Title XIII; Subtitle A) authorized DOE

to conduct programs for RD&D and commercial

applications of coal-based technologies. Secretary of

Energy was directed to submit to Congress (1) a report

that included, among other things, recommendations

regarding the manner in which the cost-sharing demonstrations conducted pursuant to the Clean Coal Program

(Pub. L. 98-473) might be modified and extended in

order to ensure the timely demonstration of advanced

coal-based technologies and (2) periodic status reports

on the development of advanced coal-based technologies

and RD&D and commercial application attributes.

An amount not to exceed $18 million available in

FY1995 may be used for administrative oversight of the

CCT Program.
A-8 Program Update 1998

Exhibit A-1 (continued)

CCT Program Legislative History

Public Date

Law Enacted CCT Round Program Funding Implementation Provisions

Of funds available for obligation in FY1996, $50 million

was rescinded. Of the funds to be made available for

obligation in FY1997, $150 million was rescinded.

Conference Report (H. Rep. 104-863 to accompany

H.R. 3610) noted rescission of $123 million for FY1997 or

prior years.

Of funds made available for obligation in FY1997 or prior

years, $17 million was rescinded.

Of funds made available for obligation in FY1997 or priors,

$101 million was rescinded.

Of funds made available for obligation in prior years,

$40 million was deferred.

104-6 4/10/95

104-134a 4/26/96

104-208b 9/30/96

105-18 6/12/97

105-83 11/14/97

105-277 10/21/98

Conference Report (H. Rep. 104-402 to accompany H.R.

1977) allowed for the use of up to $18 million in CCT

Program funds for program administration.

House and Senate committees did not object to use of up

to $16 million in available funds for administration of

the CCT Program in FY1997 (H. Rep. 104-625 and

Senate 104-319 to accompany H.R. 3662).

Conference Report allowed $14.9 million in CCT

Program funds for program administration.

a H.R. 3019, which became Pub. L. 104-134, replaced H.R. 1977.

b H.R. 3610, which became Pub. L. 104-208, replaced H.R. 3662.
Program Update 1998 A-9

Public Law 99-190

Public Law 99-190, 99 Stat. 1251 (1985)

CLEAN COAL TECHNOLOGY

Within 60 days following enactment of this Act [Dec. 19, 1985] the Secretary of

Energy shall, pursuant to the Federal Nonnuclear Energy Research and Development

Act of 1974 (42 U.S.C. 5901, et seq.), issue a general request for proposals for clean

coal technology projects for which the Secretary of Energy upon review may provide

financial assistance awards. Proposals for clean coal technology projects under this

section shall be submitted to the Department of Energy within 60 days after issuance

of the general request for proposals. The Secretary of Energy shall make any project

selections no later than August 1, 1986: Provided, That the Secretary may vest fee title

or other property interests acquired under cost-shared clean coal technology agreements in any entity, including the United States: Provided further, That the Secretary

shall not finance more than 50 per centum of the total costs of a project as estimated

by the Secretary as of the date of award of financial assistance: Provided further, That

cost-sharing by project sponsors is required in each of the design, construction, and

operating phases proposed to be included in a project: Provided further, That financial

assistance for costs in excess of those estimated as of the date of award of original

financial assistance may not be provided in excess of the proportion of costs borne by

the Government in the original agreement and only up to 25 per centum of the original

financial assistance: Provided further, That revenues or royalties from prospective

operation of projects beyond the time considered in the award of financial assistance,

or proceeds from prospective sale of the assets of the project, or revenues or royalties

from replication of technology in future projects or plants are not cost-sharing for the

purposes of this appropriation: Provided further, That other appropriated Federal

funds are not cost-sharing for the purposes of this appropriation: Provided further,

That existing facilities, equipment, and supplies, or previously expended research or

development funds are not cost-sharing for the purposes of this appropriation, except

as amortized, depreciated, or expensed in normal business practice.

Conference Report (H.R. Conf. Rep. No. 450, 99th Cong., 1st Sess.

[1985])

CLEAN COAL TECHNOLOGY

The managers have agreed to a $400,000,000 Clean Coal Technology program

as described under the Department of the Treasury, Energy Security Reserve. Bill

language is included which provides for the selection of projects no later than August

1, 1986. Within that period, a general request for proposals must be issued within 60

days and proposals must be submitted to the Department within 60 days after issuance

of the general request for proposals. Language is also included allowing the Secretary

of Energy to vest title in interests acquired under agreements in any entity, including

the United States, and delineating cost-sharing requirements. Funds for these

activities and projects are made available to the Clean Coal Technology program in

the Energy Security program.

It is the intent of the managers that contributions in the form of facilities and

equipment be considered only to the extent that they would be amortized, depreciated

or expensed in normal business practice. Normal business practice shall be determined by the Secretary and is not necessarily the practice of any single proposer.

Property which has been fully depreciated would not receive nay cost-sharing value

except to the extent that it has been in continuous use by the proposer during the

calendar year immediately preceding the enactment of this Act. For this property, a

fair use value for the life of the project may be assigned. Property offered as a costshare by the proposer that is currently being depreciated would be limited in its costshare value to the depreciation claimed during the life of the demonstration project.

Furthermore, in determining normal business practice, the Secretary should not accept

valuation for property sold, transferred, exchanged, or otherwise manipulated to

acquire a new basis for depreciation purposes or to establish a rental value in

circumstances which would amount to a transaction for the mere purpose of participating in this program.

The managers agree that, with respect to cost-sharing, tax implications of

proposals and tax advantages available to individual proposers should not be considered in determining the percentage of Federal cost-sharing. This is consistent with

current and historical practices in Department of Energy procurements.

It is the intent of the managers that there be full and open competition and that the

solicitation be open to all markets utilizing the entire coal resource base. However,
A-10 Program Update 1998

projects should be limited to the use of United States mined coal as the feedstock and

demonstration sites should be located within the United States.

The managers agree that no more than $1,500,000 shall be available in FY1986

and $2,000,000 each year thereafter for contracting, travel and ancillary costs of the

program, and that manpower costs are to be funded under the fossil energy research

and development program.

The managers direct the Department, after projects are selected, to provide a

comprehensive report to the Congress on proposals received.

The managers also expect the request for proposals to be or the full

$400,000,000 program, and not only for the first $100,000,000 available in fiscal

year 1986.

Public Law 100-202

Public Law 100-202, 101 Stat. 1329-1 (1987)

CLEAN COAL TECHNOLOGY

For necessary expenses of, and associated with, Clean Coal Technology demonstrations pursuant to 42 U.S.C. 5901 et seq., $50,000,000 are appropriated for the

fiscal year beginning October 1, 1987, and shall remain available until expended, and

$525,000,000 are appropriated for the fiscal year beginning October 1, 1988, and shall

remain available until expended.

No later than sixty days following enactment of this Act, the Secretary of Energy

shall, pursuant to the Federal Nonnuclear Energy Research and Development Act of

1974 (42 U.S.C. 5901 et seq.), issue a general request for proposals for emerging clean

coal technologies which are capable of retrofitting or repowering existing facilities, for

which the Secretary of Energy upon review may provide financial assistance awards.

Proposals under this section shall be submitted to the Department of Energy no later

than ninety days after issuance of the general request for proposals required herein, and

the Secretary of Energy shall make any project selections no later than one hundred and

sixty days after receipt of proposal: Provided, That projects selected are subject to all

provisos contained under this head in Public Law 99-190: Provided further, That preaward costs incurred by project sponsors after selection and before signing an

agreement are allowable to the extent that they are related to (1) the preparation of

material requested by the Department of Energy and identified as required for the

negotiation; or (2) the preparation and submission of environmental data requested by

the Department of Energy to complete National Environmental Policy Act requirements for the projects: Provided further, That pre-award costs are to be reimbursed

only upon signing of the project agreement and only in the same ratio as the costsharing for the total project: Provided further, That reports on projects selected by the

Secretary of Energy pursuant to authority granted under the heading “Clean coal

technology” in the Department of the Interior and Related Agencies Appropriations

Act, 1986, as contained in Public Law 99-190, which are received by the Speaker of

the House of Representatives and the President of the Senate prior to the end of the first

session of the 100th Congress shall be deemed to have met the criteria in the third

proviso of the fourth paragraph under the heading “Administrative provision, Department of Energy” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190, upon expiration of 30 calendar

days from receipt of the report by the Speaker of the House of Representatives and the

President of the Senate.

Conference Report (H.R. Conf. Rep. No. 498, 100th Cong., 1st Sess.

[1987])

CLEAN COAL TECHNOLOGY

Appropriates $575,000,000 for clean coal technology instead of $350,000,000

as proposed by the House and $850,000,000 as proposed by the Senate. The

comparison by year is as follows:

House Senate Conference

Fiscal year:

1988 $50,000,000 $350,000,000 $50,000,000

1989 200,000,000 500,000,000 525,000,000

1990 100,000,000

Total 350,000,000 850,000,000 575,000,000
Program Update 1998 A-11

Bill language, proposed by the House, which would have prohibited using grants

has been deleted. The managers agree that project funding is expected to be based on

cooperative agreements, but that grants might be applicable to support work also

funded from this account.

The managers agree to deleted Senate language providing personnel floors for

Clean Coal Technology. The managers further agree that the budget estimates for

personnel and contract support are to be followed. The agreement included 58 new

positions above current employment floors for the fossil energy organization and 30

positions within the floors. Out of clean coal technology funds, up to $3,980,000 is

for fiscal year 1988 personnel-related costs and up to $16,520,000 is for all contract

costs needed to make project selections and complete negotiations for both clean coal

procurements. Contract costs necessary to monitor approved projects should be

requested in the fiscal year 1989 budget. Increases above to those amount are subject

to reprogramming procedures. No funds other than personnel related costs for the 30

positions included in the program direction are to be provided from the fossil energy

research and development account.

The length of time for selection of projects by the Secretary of Energy has been

extended from 120 days to 160 days based on experience from the original clean coal

procurement. Once projects have been selected the Secretary should establish project

milestones and guidelines for project negotiations in order to expedite the negotiation

process to the extent feasible.

The managers agree that the funds provided are available for non-utility applications as well as for utility applications.

The managers agree that no funds are provided for the demonstration of clean coal

technologies which are intended solely for new, stand alone, applications. The Senate

had proposed up to 25% of the funds be available for this purpose.

Bill language has been included which provides that reports on projects selected

in the first round of clean coal procurements that are received before the end of the first

session of the 100th Congress will satisfy reporting requirements 30 calendar days

after receipt by Congress. This provision applies to a maximum of two project reports.

Public Law 100-446

Public Law 100-446, 102 Stat. 1774 (1988)

CLEAN COAL TECHNOLOGY

For necessary expenses of, and associated with, Clean Coal Technology demonstrations pursuant to 42 U.S.C. 5901 et seq., $575,000,000 shall be made available on

October 1, 1989, and shall remain available until expended: Provided, That projects

selected pursuant to a general request for proposals issued pursuant to this appropriation shall demonstrate technologies capable of retrofitting or repowering existing

facilities and shall be subject to all provisions contained under this head in Public Laws

99-190 and 100-202 as amended by this Act.

The first paragraph under this head in Public Law 100-202 is amended by striking

“and $525,000,000 are appropriated for the fiscal year beginning October 1, 1988”

and inserting “$190,000,000 are appropriated for the fiscal year beginning October 1,

1988, and shall remain available until expended, $135,000,000 are appropriated for

the fiscal year beginning October 1, 1989, and shall remain available until expended,

and $200,000,000 are appropriated for the fiscal year beginning October 1, 1990”:

Provided, That outlays in fiscal year 1989 resulting from the use of funds appropriated

under this head in Public Law 100-202, as amended by this Act, may not exceed

$15,500,000: Provided further, That these actions are taken pursuant to section

202(b)(1) of Public law 100-119 (2 U.S.C. 909).

For the purposes of the sixth proviso under this head in Public Laws 99-190, funds

derived by the Tennessee Valley Authority from its power program are hereafter not

to be precluded from qualifying as all or part of any cost-sharing requirement, except

to the extent that such funds are provided by annual appropriations Acts: Provided,

That unexpended balances of funds made available in the “Energy Security Reserve”

account in the Treasury for the Clean Coal Technology Program by the Department

of the Interior and Related Agencies Appropriations Acts, 1986, as contained in

section 101(d) of Public Law 99-190, shall be merged with this account: Provided

further, That for the purposes of the sixth proviso in Public Law 99-190 under this

heading, funds provided under section 306 of Public Law 93-32 shall be considered

non-Federal: Provided further, That reports on projects selected by the Secretary of

Energy pursuant to authority granted under the heading “Clean coal technology” in the
A-12 Program Update 1998

Department of the Interior and Related Agencies Appropriations Act, 1986, as

contained in Public Law 99-190, which are received by the Speaker of the House of

Representatives and the President of the Senate prior to the end of the second session

of the 100th Congress shall be deemed to have met the criteria in the third proviso of

the fourth paragraph under the heading “Administrative provisions, Department

Energy” in the Department of the Interior and Related Agencies Appropriations Act,

1986, as contained in Public Law 99-190, upon expiration of 30 calendar days from

receipt of the report by the Speaker of the House of Representatives and the President

of the Senate.

Conference Report (H.R. Conf. Rep. No. 862, 100th Cong., 2nd Sess.

[1988])

CLEAN COAL TECHNOLOGY

Amendment No. 131: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the

Senate with an amendment as follows:

In lieu of the matter proposed by said amendment insert the following: For

necessary expenses of, and associated with, Clean Coal Technology demonstrations

pursuant to 42 U.S.C. 5901 et seq., $575,000,000 shall be made available on October

1, 1989, and shall remain available until expended: Provided, That projects selected

pursuant to a general request for proposals issued pursuant to this appropriation

shall demonstrate technologies capable of retrofitting or repowering existing facilities and shall be subject to all provisos contained under this head in Public Laws 99-

190 and 100-202 as amended by this Act.

The managers on the part of the Senate will move to concur in the amendment of

the House to the amendment of the Senate. The amendment provides $575,000,000

in fiscal year 1990 for a third Clean Coal Technology procurement as proposed by the

Senate, and clarifies that the procurement is for retrofit and repowering technologies

and is subject to the cost-sharing provisions of the previous two procurements.

The managers agree that a request for proposals should be issued by May 1, 1989,

with proposals due no later than 120 days after issuance of the request for proposals,

and that the Secretary of Energy should make project selections no later than 120 days

after receipt of proposals.

Amendment No. 132: Reported in technical disagreement. The managers on

the part of the House will offer a motion to recede and concur in the amendment of

the Senate with an amendment as follows:

Restore the matter stricken by said amendment, amended to read as follows: The

first paragraph under this head in Public Law 100-202 is amended by striking “and

$525,000,000 are appropriated for the fiscal year beginning October 1, 1988” and

inserting “$190,000,000 are appropriated for the fiscal year beginning October 1,

1988, and shall remain available until expended, $135,000,000 are appropriated for

the fiscal year beginning October 1, 1989, and shall remain available until expended,

and $200,000,000 are appropriated for the fiscal year beginning October 1, 1990”:

Provided, That outlays in fiscal year 1989 resulting from the use of funds appropriated under this head in Public Law 100-202, as amended by this Act, may not exceed

$15,500,000: Provided further, That these actions are taken pursuant to section

202(b)(1) of Public Law 100-119 (2 U.S.C. 909).

The managers on the part of the Senate will move to concur in the amendment of

the House to the amendment of the Senate. The amendment changes the availability

of $525,000,000 originally made available for fiscal year 1989 in Public Law 100-202

by making $190,000,000 available in 1989, $135,000,000 available in 1990, and

$200,000,000 available in 1991 and also provides an outlay ceiling in fiscal year 1989.

The House had proposed $100,000,000 in fiscal year 1989, $225,000,000 in fiscal

year 1990, and $200,000,000 in fiscal year 1989, $225,000,000 in fiscal year 1990,

and $200,000,000 in fiscal year 1991, and the Senate struck the House language.

Both of these changes are necessary because of budget allocation constraints, but

neither action has an effect on the execution of the Clean Coal program, or on the

Congress’ overall support for the program, as is evidenced by additional appropriations provided for a third procurement of technologies.

The managers agree that administrative contract expenses may be incurred up to

the budget level of $9,820,000, but caution that close control of such expenditures is

necessary to assure that the outlay ceiling provided will be sufficient to cover project

costs.

Amendment No. 133: Modifies public law citation as proposed by the Senate.

Amendment No. 134: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the

Senate which clarifies that funds borrowed by REA Electric Cooperatives from the

Federal Financing Bank are eligible as cost-sharing in the clean coal technology

program.
Program Update 1998 A-13

Amendment No. 135: Reported in technical disagreement. The managers on

the part of the House will offer a motion to recede and concur in the amendment of

the Senate which specifies clean coal projects may proceed 30 calendar days after

receipt by Congress of required reports, provided the reports are received prior to

the end of the 100th Congress.

Public Law 101-45

Public Law 101-45, 103 Stat. 97 (1989)

CLEAN COAL TECHNOLOGY

 Notwithstanding any other provision of law, funds originally appropriated

under this head in the Department of the Interior and Related Agencies Appropriations Act, 1989, shall be available for a third solicitation of clean coal technology

demonstration projects, which projects are to be selected by the Department not

later than January 1, 1990.

Public Law 101-121

Public Law 101-121, 103 Stat. 701 (1989)

CLEAN COAL TECHNOLOGY

 For necessary expenses of, and associated with, Clean Coal Technology demonstrations pursuant to 42 U.S.C. 5901 et seq., $600,000,000 shall be made available on

October 1, 1990, and shall remain available until expended, and $600,000,000 shall

be made available on October 1, 1991, and shall remain available until expended:

Provided, That projects selected pursuant to a separate general request for proposals

issued pursuant to each of these appropriations shall demonstrate technologies capable

of replacing, retrofitting or repowering existing facilities and shall be subject to all

provisos contained under this head in Public Laws 99-190, 100-202, and 100-446 as

amended by this Act: Provided further, That the general request for proposals using

funds becoming available on October 1, 1990, under this paragraph shall be issued no

later than June 1, 1990, and projects resulting from such a solicitation must be selected

no later than February 1, 1991: Provided further, That the general request for proposals

using funds becoming available on October 1, 1991, under this paragraph shall be

issued no later than September 1, 1991, and projects resulting from such a solicitation

must be selected no later than May 1, 1992.

The first paragraph under this head in Public Law 100-446 is amended by striking

“$575,000,000 shall be made available on October 1, 1989” and inserting “$450,000,000

shall be made available on October 1, 1989, and shall remain available until expended,

and $125,000,000 shall be made available on October 1, 1990”: Provided, That these

actions are taken pursuant to section 202(b)(1) of Public Law 100-119 (2 U.S.C. 909).

With regard to funds made available under this head in this and previous

appropriations Acts, unobligated balances excess to the needs of the procurement for

which they originally were made available may be applied to other procurements for

which requests for proposals have not yet been issued: Provided, That for all

procurements for which project selections have not been made as of the date of

enactment of this Act no supplemental, backup, or contingent selection of projects

shall be made over and above projects originally selected for negotiation and

utilization of available funds: Provided further, That reports on projects selected by

the Secretary of Energy pursuant to authority granted under this heading which are

received by the Speaker of the House of Representatives and the President of the

Senate less than 30 legislative days prior to the end of the first session of the 101st

Congress shall be deemed to have met the criteria in the third proviso of the fourth

paragraph under the heading “Administrative provisions, Department of Energy” in

the Department of the Interior and Related Agencies Appropriations Act, 1986, as

contained in Public Law 99-190, upon expiration of 30 calendar days from receipt of

the report by the Speaker of the House of Representatives and the President of the

Senate or at the end of the session, whichever occurs later.
A-14 Program Update 1998

Conference Report (H.R. Conf. Rep. No. 264, 101st Cong., 1st Sess.

[1987])

CLEAN COAL TECHNOLOGY

Amendment No. 112: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of he

Senate which adds the word “replacing” to the definition of clean coal technology. The

managers agree that the inclusion of “replacing” for clean coal IV and V is intended

to cover the complete replacement of an existing facility if because of design or site

specific limitations, repowering or retrofitting of the plant is not a desirable option.

Amendment No,. 113: Appropriates $450,000,000 for fiscal year 1990 for clean

coal technology instead of $500,000,000 as proposed by the House and $325,000,000

as proposed by he Senate. This appropriation along with $125,000,000 provided for

fiscal year 1991 in Amendment 114 fully funds the third round of clean coal technology

projects. The managers agree that additional manpower is required, particularly at the

Department’s Energy Technology Centers, in order to manage adequately the increased workload from the accumulation of active clean coal technology projects and

the inclusion of additional procurements in this bill. Although a legislative floor is not

included, the managers agree that at least eighty personnel will be required in addition

to the approximately thirty FTE’s now included in the fossil energy research and

development appropriation. The managers agree further that funds from the fossil

energy research and development appropriation should not be used to pay the cost of

more than the equivalent FTE’s paid under that account in fiscal year 1989.

Amendment No. 114: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the

Senate with an amendment as follows:

In lieu of the matter stricken and inserted by said amendment, insert: and shall

remain available until expended, and $125,0000,000

The managers on the part of the Senate will move to concur in the amendment of

the House to the amendment of the Senate. The amendment provides $125,000,000

in fiscal year 1991 for the third clean coal technology procurement instead of

$75,000,000 as proposed by the House and $100,000,000 as proposed by the Senate.

Amendment No 115: Deletes Senate proposed appropriation of $150,000,000 for

fiscal year 1992 for clean coal technology. The House proposed no such appropriation.

Amendment No. 116: Restores House language stricken by the Senate which

prohibits the use of supplemental, backup, or contingent project selections in clean

coal technology procurements.

Amendment No. 117: Restores the word “further” stricken by the Senate.

Public Law 101-164

Public Law 101-164, 103 Stat. 1069 (1989)

CLEAN COAL TECHNOLOGY

The second paragraph under this head contained in the Act making appropriations

for the Department of the Interior and Related Agencies for the fiscal year ending

September 30, 1990, is amended by striking “$450,000,000” and inserting

“$419,000,000” and by striking “$125,000,000” and inserting “$156,000,000”.

Conference Report (H.R. Conf. Rep. No. 315, 101st Cong., 1st Sess.

[1989])

The managers have agreed to reduce the funds appropriated by the Energy and

Water Development Appropriations Act for Fiscal Year 1990 (Public Law 101-101)

for the “Nuclear Waste Disposal Fund” by $46,000,000. This reduction will make

funds available for the drug prevention effort.

The managers have agreed to reductions to the Interior and Related Agencies

Appropriations Act for Fiscal Year 1990 (Public Law 101-121) in order to accommodate additional drug related appropriations.

The reductions are in three areas. The new budget authority for Clean Coal

Technology of $450,000,000 for fiscal year 1990 is reduced by $31,000,000 with this

same amount added to the advance appropriation for fiscal year 1991. With this

change the new amount for fiscal year 1990 is $419,000,000 while fiscal year 1991

increases to $156,000,000. The second area of change is the imposition of an outlay

ceiling on Strategic Petroleum Reserve oil acquisition. Outlays will be reduced from

an estimated $169,945,000 to $147,125,000 and will decrease the fill rate from

approximately 50,000 barrels per day to approximately 46,000 or 47,000 barrels per

day. The third reduction relates to the Pennsylvania Avenue Development Corporation. The borrowing authority is reduced from $5,000,000 to $100,000.
Program Update 1998 A-15

The conference agreement includes bill language reducing the amount of funds

transferred from trust funds to the Health Care Financing Administration Program

Management account by $32,000,000 from $1,917,172,000 to $18,851,712,000.

This reduction, along with the outlays reserved from the regular 1990 Labor, Health

and Human Services, and Education appropriations bill, will be sufficient to support

the Subcommittee’s share of the cost of anti-drug abuse funding. The conferees intend

that the reduction in trust fund transfers be associated with activities to implement

catastrophic health insurance, where funding needs may be diminished.

Public Law 101-302

Public Law 101-302, 104 Stat. 213 (1990)

CLEAN COAL TECHNOLOGY

Funds previously appropriated under this head for clean coal technology

solicitations to be issued no later than June 1, 1990, and no later than September 1,

1991, respectively, shall not be obligated until September 1, 1991: Provided, That

the aforementioned solicitations shall not be conducted prior to the ability to

obligate these funds: Provided further, That pursuant to section 202(b) of the

Balanced Budget and Emergency Deficit Control Reaffirmation Act of 1987, this

action is a necessary (but secondary) result of a significant policy change: Provided

further, That for the clean coal solicitations identified herein, provisions included

for the repayment of government contributions to individual projects shall be

identical to those included in the Program Opportunity Notice (PON) for Clean

Coal Technology III (CCT-III) Demonstration Projects (solicitation number DEPSO1-89 FE 61825), issued by the Department of Energy on May 1, 1989.

Conference Report (H.R. Conf. Rep. No. 493, 101st Cong., 2nd Sess.

[1990])

CLEAN COAL TECHNOLOGY

Amendment No. 89. Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the

senate with an amendment as follows:

In lieu of the matter proposed by said amendment insert:

DEPARTMENT OF ENERGY

CLEAN COAL TECHNOLOGY

Funds previously appropriated under this head for clean coal technology

solicitations to be issued no later than June 1, 1990, and no later than September 1,

1991, respectively, shall not be obligated until September 1, 1991: Provided, That the

aforementioned solicitations shall not be conducted prior to the ability to obligate

these funds: Provided further, That pursuant to section 202 (b) of the Balanced

Budget and Emergency Deficit Control reaffirmation /Act of 1987 this action is a

necessary (but secondary) result of a significant policy change: Provided further,

That for the clean coal solicitations identified herein, provisions included for the

repayment of government contributions to individual projects shall be identical to

those included in the Program Opportunity Notice (PON) for Clean Coal Technology

III (CCT-III) Demonstration Projects (solicitation number DE-PS01-89 FE 61825),

issued by the Department of Energy on May 1, 1989.

The managers on the part of the Senate will move to concur in the amendment of

the House to the amendment of the Senate.

The amendment delays the fourth and fifth clean coal technology solicitations as

proposed by the Senate and specifies that, when issued, these solicitations must use

repayment provisions used successfully in the third solicitation. This provision was

included in the House introduced bill (H.R. 4828) and modifies a Senate amendment

to the original Dire Emergency Supplemental.

The managers agree that changes to the clean air bill, proposed by a House

authorizing committee, that would modify the clean coal technology program must be

resolved before a reasonable solicitation can be issued. The proposed delay will allow

such resolution.
A-16 Program Update 1998

The managers have added language to ensure that provisions dealing with the

repayment of government provided funds will remain the same as the third round of

procurements. These provisions were developed over a four year period based on

experience of previous procurements and negotiations, and input from industrial

participants, Congress, and the managers of the program. They appear to be working

well.

Based on the long-term experience, and the clear fact that implementation of this

type of technology will become even more important with passage of clean air

legislation, the managers reject proposals put forth by the Department of Energy to

increase rates substantially. Such proposals, while they might increase the recovery

of government-provided funds over periods of up to 20 years, might also act as a

deterrent to industrial participation in the program, which is already over 50 percent

cost-shared by industry. The purpose of the program is to accelerate the introduction

of clean uses of coal in a more efficient manner in compliance with stringent new air

quality standards, not the provision of investment returns to the Government at the

expense of nascent markets.

Public Law 101-512

Public Law 101-512, 104 Stat. 1915 (1990)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-121 is amended by striking

“$600,000,000 shall be made available on October 1, 1990, and shall remain available

until expended, and $600,000,000 shall be made available on October 1, 1991, and

shall remain available until expended” and inserting “$600,000,000 shall be made

available as follows: $35,000,000 on September 1, 1991, $315,000,000 on October

1, 1991, and $250,000,000 on October 1, 1992, all such sums to remain available until

expended for use in conjunction with a separate general request for proposals, and

$600,000,000 shall be made available as follows: $150,000,000 on October 1, 1991,

$225,000,000 on October 1, 1992, and $225,000,000 on October 1, 1993, all such

sums to remain available until expended for use in conjunction with a separate general

request for proposals”: Provided, That these actions are taken pursuant to section

202(b)(1) of Public Law 100-119 (2 U.S.C. 909): Provided further, That a fourth

general request for proposals shall be issued not later than February 1, 1991, and a fifth

general request for proposals shall be issued not later than March 1, 1992: Provided

further, That project proposals resulting from such solicitations shall be selected not

later than eight months after the date of the general request for proposals: Provided

further, That for clean coal solicitations required herein, provisions included for the

repayment of government contributions to individual projects shall be identical to

those included in the Program Opportunity Notice (PON) for Clean Coal Technology

III (CCT-III) Demonstration Projects (solicitation number DE-PS01-89 FE 61825),

issued by the Department of Energy on May 1, 1989: Provided further, That funds

provided under this head in this or any other appropriations Act shall be expended only

in accordance with the provisions governing the use of such funds contained under this

head in this or any other appropriations Act.

With regard to funds made available under this head in this and previous

appropriations Acts, unobligated balances excess to the needs of the procurement for

which they originally were made available may be applied to other procurements for

use on projects for which cooperative agreements are in place, within the limitations

and proportions of Government financing increases currently allowed by law:

Provided, That the Department of Energy, for a period of up to five (5) years after

completion of the operations phase of a cooperative agreement may provide appropriate protections, including exemptions from subchapter II of chapter 5 of title 5, United

States Code, against the dissemination of information that results from demonstration

activities conducted under the Clean Coal Technology Program and that would be a

trade secret or commercial or financial information that is privileged or confidential

if the information had been obtained from and first produced by a non-Federal party

participating in a Clean Coal Technology project: Provided further, That, in addition

to the full-time permanent Federal employees specified in section 303 of Public Law

97-257, as amended, no less than 90 full-time Federal employees shall be assigned to

the Assistant Secretary for Fossil Energy for carrying out the programs under this head

using funds available under this head in this and any other appropriations Act and of

which 35 shall be for PETC and 30 shall be for METC: Provided further, That reports

on projects selected by the Secretary of Energy pursuant to authority granted under this

heading which are received by the Speaker of the House of Representatives and the

President of the Senate less than 30 legislative days prior to the end of the second

session of the 101st Congress shall be deemed to have met the criteria in the third

proviso of the fourth paragraph under the heading “Administrative provisions,
Program Update 1998 A-17

Department of Energy” in the Department of the Interior and Related Agencies

Appropriations Act, 1986, as contained in Public Law 99-190, upon expiration of 30

calendar days from receipt of the report by the Speaker of the House of Representatives

and the President of the Senate or at the end of the session, whichever occurs later.

Conference Report (H.R. Conf. Rep. No. 971, 101st Cong., 2nd Sess.

[1990])

CLEAN COAL TECHNOLOGY

Amendment No. 142: Provides $35,000,000 for clean coal technology on

September 1, 1991 as proposed by the House instead of $100,000,000 as proposed by

the Senate. This amendment and Amendment No. 143 shift the availability of

$65,000,000 from fiscal year 1991 to fiscal year 1992.

Amendment No. 143: Provides $315,000,000 for clean coal technology on

October 1, 1991 as proposed by the House instead of $250,000,000 as proposed by the

Senate. This amendment and Amendment No. 142 shift the availability of $65,000,000

from fiscal year 1991 to fiscal year 1992.

Amendment No. 144: Provides dates for two solicitations for clean coal

technology as proposed by the Senate. The date for CCT-IV is amended to February

1, 1991 from January 1, 1991. The date for CCT-V is not changed from the Senate date

of March 1, 1992.

The managers have agreed to a February 1, 1991 date for the next solicitation to

enable the Department to publish a draft solicitation for comment by interested parties.

It is expected that there will be changes to evaluation criteria and other factors that

make it imperative that potential proposers have an opportunity to comment on the

content of the solicitation.

The managers urge the Department to include potential benefits to remote,

import-dependent sites as a program policy factor in evaluating proposals. The

Department should also consider projects which can provide multiple fuel resource

options for regions which are more than seventy-five percent dependent on one fuel

form for total energy requirements.

Amendment No. 145: Requires selection of projects within eight months of the

requests for proposals required by Amendment No. 144 as proposed by the Senate.

The House had no such provision.

Amendment No. 146: Requires repayment of government contributions to

projects under conditions identical to the most recent clean coal solicitation as

proposed by the Senate. The House had no such provision.

Amendment No. 147: Provides that funds for clean coal technology may be

expended only under conditions contained in appropriations Acts. The Senate

language had prohibited geographic restrictions on the expenditure of funds. The

House had no such provision. The managers direct that no preferential consideration

be given to any project referenced explicitly or implicitly in other legislation.

The managers agree to delete bill language dealing with geographic restrictions

based on such restrictions being deleted from clean air legislation.

Amendment No. 148: Earmarks employees to two fossil energy technology

centers as proposed by the Senate. The House had no such provision. The managers

agree that the earmarks for PETC and METC are minimum levels and may be

increased as necessary.

The managers agree that no more than the current 30 full-time equivalent positions

from fossil energy research and development may be used in the clean coal program

in fiscal year 1991.

Public Law 102-154

Public Law 102-154, 105 Stat. 990 (1991)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-512 is amended by striking

the phrase “$150,000,000 on October 1, 1991, $225,000,000 on October 1, 1992” and

inserting “$100,000,000 on October 1, 1991, $275,000,000 on October 1, 1992”.

 Notwithstanding the issuance date for the fifth general request for proposals

under this head in Public Law 101-512, such request for proposals shall be issued not

later than July 6, 1992, and notwithstanding the proviso under this head in Public Law

101-512 regarding the time interval for selection of proposals resulting from such

solicitation, project proposals resulting from the fifth general request for proposals

shall be selected not later than ten months after the issuance date of the fifth general

request for proposals: Provided, That hereafter the fifth general request for proposals
A-18 Program Update 1998

shall be subject to all provisos contained under this head in previous appropriations

Acts unless amended by this Act.

 Notwithstanding the provisos under this head in previous appropriations Acts,

projects selected pursuant to the fifth general request for proposals shall advance

significantly the efficiency and environmental performance of coal-using technologies and be applicable to either new or existing facilities: Provided, That budget

periods may be used in lieu of design, construction, and operating phases for costsharing calculations: Provided further, That the Secretary shall not finance more than

50 per centum of the total costs of any budget period: Provided further, That project

specific development activities for process performance definition, component design

verification, materials selection, and evaluation of alternative designs may be funded

on a cost-shared basis up to a limit of 10 per centum of the Government’s share of

project cost: Provided further, That development activities eligible for cost-sharing

may include limited modifications to existing facilities for project related testing but

do not include construction of new facilities.

With regard to funds made available under this head in this and previous

appropriations Acts, unobligated balances excess to the needs of the procurement for

which they originally were made available may be applied to other procurements for

use on projects for which cooperative agreements are in place, within the limitations

and proportions of Government financing increases currently allowed by law: Provided, That hereafter, the Department of Energy, for a period of up to five years after

completion of the operations phase of a cooperative agreement may provide

appropriate protections, including exemptions from subchapter II of chapter 5 of title

5, United States Code, against the dissemination of information that results from

demonstration activities conducted under the Clean Coal Technology Program and

that would be a trade secret or commercial or financial information that is privileged

or confidential if the information had been obtained from and first produced by a nonFederal party participating in a Clean Coal Technology project: Provided further, That

hereafter, in addition to the full-time permanent Federal employees specified in

section 303 of Public Law 97-257, as amended, no less than 90 full-time Federal

employees shall be assigned to the Assistant Secretary for Fossil Energy for carrying

out the programs under this head using funds available under this head in this and any

other appropriations Act and of which not less than 35 shall be for PETC and not less

than 30 shall be for METC: Provided further, That hereafter reports on projects

selected by the Secretary of Energy pursuant to authority granted under this heading

which are received by the Speaker of the House of Representatives and the President

of the Senate less than 30 legislative days prior to the end of each session of Congress

shall be deemed to have met the criteria in the third proviso of the fourth paragraph

under the heading “Administrative provisions, Department of Energy” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in

Public Law 99-190, upon expiration of 30 calendar days from receipt of the report by

the Speaker of the House of Representatives and the President of the Senate or at the

end of the session, whichever occurs later.

Conference Report (H.R. Conf. Rep. No. 256, 102nd Cong., 1st Sess.

[1991])

CLEAN COAL TECHNOLOGY

Amendment No. 165: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the

Senate with an amendment as follows:

In lieu of the matter stricken and inserted by said amendment insert:

Notwithstanding the issuance date for the fifth general request for proposals

under this head in Public Law 101-512, such request for proposals shall be issued not

later than July 6, 1992, and notwithstanding the proviso under this head in Public Law

101-512 regarding the time interval for selection of proposals resulting from such

solicitation, project proposals resulting from the fifth general request for proposals

shall be selected not later than ten months after the issuance date of the fifth general

request for proposals: Provided, That hereafter the fifth general request for proposals

The managers on the part of the Senate will move to concur in the amendment of

the House to the amendment of the Senate.

The amendment changes the issuance date for the fifth general request for

proposals to July 6, 1992 instead of March 1, 1992 as proposed by the House and

August 10, 1992 as proposed by the Senate and the allowable length of time from

issuance of the request for proposals to selection of projects to ten months. The

amendment also deletes Senate proposed bill language pertaining to a sixth general

request for proposals as discussed below.

The managers agree that the additional two months in the procurement process for

the fifth round of proposals should include an additional month to allow for the

preparation of proposals by the private sector, and up to an additional month for

Department of Energy review and evaluation of proposals when compared to the

process for the fourth round.
Program Update 1998 A-19

The managers have agreed to delete bill language regarding a sixth round of

proposals, but agree that funding will be provided for a sixth round based on

unobligated and unneeded amounts that may become available from the first five

rounds. The report from the Secretary on available funds, which was originally in the

Senate amendment, is still a requirement and such report should be submitted to the

House and Senate Committees on Appropriations not later than May 1, 1994. Based

on that report, the funding, dates and conditions for the sixth round will be included

in the fiscal year 1995 appropriation.

The managers expect that the fifth solicitation will be conducted under the same

general types of criteria as the fourth solicitation principally modified only (1) to

include the wider range of eligible technologies or applications; (2) to adjust technical

criteria to consider allowable development activities, to strengthen criteria for nonutility demonstrations, and to adjust commercial performance criteria for additional

facilities and technologies with regard to aspects of general energy efficiency and

environmental performance; and (3) to clarify and strengthen cost and finance criteria

particularly with regard to development activities.

Amendment No. 166: Restores House language deleted by the Senate which

refers to a fifth general request for proposals. The Senate proposed language dealing

with both a fifth and a sixth round.

Amendment No. 167: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the

Senate which directs the Secretary of Energy to reobligate up to $44,000,000 from the

fourth round of Clean Coal Technology proposals to a proposal ranked highest in its

specific technology category by the Source Evaluation Board if other than the highest

ranking project in that category was selected originally by the Secretary, and if such

funds become unobligated and are sufficient to fund such projects. This amendment

would earmark such funds, if they become available, to a specific project not chosen

in the Department of Energy selection process for the fourth round of Clean Coal

Technology.

Amendment No. 168: Technical amendment which deletes House proposed

punctuation and numbering as proposed by the Senate.

Amendment No. 169: Deletes House proposed language which made unobligated

funds available for procurements for which requests for proposals have not been

issued.

Amendment No. 170: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the

Senate which adds “not less than” to employment floor language for PETC as proposed

by the Senate. The House had no such language.

Amendment No. 171: Reported in technical disagreement. The managers on the

part of the House will offer a motion to recede and concur in the amendment of the

Senate which adds “not less than” to employment floor language for METC as

proposed by the Senate. The House had no such language.

Public Law 102-381

Public Law 102-381, 106 Stat. 1374 (1992)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-512, as amended, is further

amended by striking the phrase “and $250,000,000 on October 1, 1992” and inserting

“$150,000,000 on October 1, 1993, and $100,000,000 on October 1, 1994” and by

striking the phrase “$275,000,000 on October 1, 1992, and $225,000,000 on October

1, 1993” and inserting “$250,000,000 on October 1, 1993, and $250,000,000 on

October 1, 1994”.
A-20 Program Update 1998

Public Law 103-138

Public Law 103-138, 107 Stat. 1379 (1993)

CLEAN COAL TECHNOLOGY

The first paragraph under this head in Public Law 101-512, as amended, is further

amended by striking the phrase “$150,000,000 on October 1, 1993, and $100,000,000

on October 1, 1994” and inserting “$100,000,000 on October 1, 1993, $100,000,000

on October 1, 1994, and $50,000,000 on October 1, 1995” and by striking the phrase

“$250,000,000 on October 1, 1993, and $250,000,000 on October 1, 1994” and

inserting “$125,000,000 on October 1, 1993, $275,000,000 on October 1, 1994, and

$100,000,000 on October 1, 1995”.

Public Law 103-332

Public Law 103-332, 108 Stat. 2499 (1994)

CLEAN COAL TECHNOLOGY

 The first paragraph under this head in Public Law 101-512, as amended, is

further amended by striking the phrase “$100,000,000 on October 1, 1994, and

$50,000,000 on October 1, 1995” and inserting “$18,000,000 on October 1, 1994,

$100,000,000 on October 1, 1995, and $32,000,000 on October 1, 1996”; and by

striking the phrase “$275,000,000 on October 1, 1994, and $100,000,000 on October

1, 1995” and inserting “$19,121,000 on October 1, 1994, $100,000,000 on October

1, 1995, and $255,879,000 on October 1, 1996”: Provided, That not to exceed

$18,000,000 available in fiscal year 1995 may be used for administrative oversight of

the Clean Coal Technology program.

Public Law 104-6

Public Law 104-6, 109 Stat. 73 (1995)

CLEAN COAL TECHNOLOGY

(RESCISSION)

 Of the funds made available under this heading for obligation in fiscal year

1996, $50,000,000 are rescinded and of the funds made available under this heading

for obligation in fiscal year 1997, $150,000,000 are rescinded: Provided, That funds

made available in previous appropriations Acts shall be available for any ongoing

project regardless of the separate request for proposal under which the project was

selected.

Public Law 104-134

Conference Report (H.R. Conf. Rep. No. 402, 104th Cong., 1st Sess.

[1995])

The managers do not object to the use of up to $18,000,000 in clean coal

technology program funds for administration of the clean coal program.
Program Update 1998 A-21

Public Law 104-208

Conference Report (H.R. Conf. Rep. No. 863, 104th Cong., 2nd Sess.,

[1996])

CLEAN COAL TECHNOLOGY

(RESCISSION)

Of the funds made available under this heading for obligation in fiscal year 1997

or prior years, $123,000,000 are rescinded: Provided, That funds made available in

previous appropriations Acts shall be available for any ongoing project regardless of

the separate request for proposal under which the project was selected.

Senate Report (S. Rep. No. 319, 104th Cong., 2nd Sess. [1996])

The Committee does not object to the use of up to $16,000,000 in available funds

for administration of the clean coal program in fiscal year 1997.

House Report (H.R. Rep. No. 625, 104th Cong., 2nd Sess. [1996])

The Committee does not object to the use of up to $16,000,000 in available funds

for administration of the clean coal program in fiscal year 1997.

Public Law 105-18

Public Law 105-18, 111 Stat. 158 (1997)

CLEAN COAL TECHNOLOGY

(RESCISSION)

Of the funds made available under this heading for obligation in fiscal year 1997

or prior years, $17,000,000 are rescinded: Provided, That funds made available in

previous appropriations Acts shall be available for any ongoing project regardless of

the separate request for proposal under which the project was selected.

Public Law 105-83

Public Law 105-83, 111 Stat. 37 (1997)

Of the funds made available under this heading for obligation in fiscal year 1997

or prior years, $101,000,000 are rescinded: Provided, That funds made available in

previous appropriations Acts shall be available for any ogoing project regardless of the

separate request for proposal under which the project was selected.

Public Law 105-277

Public Law 105-277, 112 Stat. 2681 (1998)

CLEAN COAL TECHNOLOGY

(DEFERRAL)

 Of the funds made available under this heading for obligation in prior

years, $10,000,000 of such funds shall not be available until October 1, 1999;

$15,000,000 shall not be available until October 1, 2000; and $15,000,000 shall

not be available until October 1, 2001: Provided, That funds made available in

previous appropriations Acts shall be available for any ongoing project regardless

of the separate request for proposal under which the project was selected.

Conference Report (H.R. Conf. Rep. No. 825, 105th Cong. 2nd Sess.

[1998])

CLEAN COAL TECHNOLOGY

The conference agreement provides for the deferral of $40,000,000 in previously appropriated funds for the clean coal technology program as proposed by the

Senate. The House did not propose to defer funding. The Committees agree that

$14,900,000 may be used for administration of the clean coal technology program.
Program Update 1998 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 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, NOx, or both 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.

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 to replace any selected projects if

negotiations were 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 1998

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.

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 (COREX Ironmaking

Demonstration Project) 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 (now Rosebud SynCoal Partnership;

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.

February 1990

Foster Wheeler Power Systems, Inc., withdrew its

CCT-I proposal, Clean Energy IGCC Demonstration

Project.
Program Update 1998 B-3

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 CT121 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, Western Energy Company (now Rosebud

SynCoal Partnership; 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 were terminated with CCT-II participant,

Southwestern Public Service Company (Nichols CFB

Repowering Project).

October 1990

DOE signed cooperative agreements with four CCTIII participants: AirPol, Inc. (10-MWe Demonstration

of Gas Suspension Absorption); The Babcock &

Wilcox Company (Full-Scale Demonstration of LowNOx

 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; now JEA); 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 (now

NOXSO Corporation; 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 Combined-Cycle 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.

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.
B-4 Program Update 1998

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, final reports issued and project

completed.

April 1992

Tri-State Generation and Transmission Association,

Inc.’s (formerly Colorado-Ute Electric Association,

Inc.) CCT-I project, Nucla CFB Demonstration

Project, final reports issued and project completed.

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).

July 1992

DOE signed cooperative agreements with two CCTIV participants: Tennessee Valley Authority (now

New York State Electric & Gas Corporation project;

Micronized Coal Reburning Demonstration for NOx

Control on a 175-MWe Wall-Fired Unit), and the

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

for 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 one year to the DOE deadline for

completing negotiations of its Demonstration of the

Union Carbide CANSOLVT 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

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, final reports issued and project

completed.

May 1993

Five projects were selected under CCT-V: Four

Rivers Energy Partners, L.P. (Four Rivers Energy

Modernization Project (formerly Calvert City Advanced Energy Project, now McIntosh Unit 4B

Topped PCFB Demonstration 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 CANSOLVT System at the Alcoa

Generating Corporation Warrick Power Plant.

February 1994

The Passamaquoddy Tribe’s CCT-III project, Cement

Kiln Flue Gas Recovery Scrubber, final reports issued

and project completed.

March 1994

The Babcock & Wilcox Company’s CCT-II project,

Demonstration of Coal Reburning for Cyclone Boiler

NOx

 Control, final reports issued and project completed.
Program Update 1998 B-5

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, final reports

issued and project completed.

Bechtel Corporation’s CCT-III project, Confined

Zone Dispersion Flue Gas Desulfurization Demonstration, final reports issued and project completed.

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).

March 1995

TAMCO Power Partner’s CCT-IV project, Toms

Creek IGCC Demonstration Project, was not granted a

further extension and the project was concluded.

April 1995

Bethlehem Steel Corporation’s CCT-II project,

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

AirPol, Inc.’s CCT-II project, 10-MWe Demonstration of Gas Suspension Absorption, final reports

issued and project completed.

September 1995

The Babcock & Wilcox Company’s CCT-II project,

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration

Project, final reports issued and project completed.

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.

The Babcock & Wilcox Company’s CCT-II project,

Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit, final reports issued and project completed.

The Ohio Power Company’s CCT-I project, Tidd

PFBC Demonstration Project, final reports issued and

project completed.

May 1996

The ABB Combustion Engineering, Inc., CCT-II

project, Combustion Engineering IGCC Repowering

Project, was concluded.

June 1996

Pure Air on the Lake’s CCT-II project, Advanced

Flue Gas Desulfurization Project, final reports issued

and project completed.

August 1996

The Arthur D. Little, Inc., CCT-V project was

restructured and retitled as the Clean Coal Diesel

Demonstration Project.
B-6 Program Update 1998

September 1996

The Appalachia Power Company CCT-II project,

PFBC Utility Demonstration Project, was concluded.

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]).

November 1996

Southern Company Services’ CCT-II project, Demonstration of Selective Catalytic Reduction Technology

for the Control of NOx

 Emissions from High-Sulfur

Coal-Fired Boilers, final reports issued and project

completed.

December 1996

ABB Environmental Systems’ CCT-II project,

SNOXTM Flue Gas Cleaning Demonstration Project,

final reports issued and project completed.

May 1997

The Pennsylvania Electric Company CCT-V project,

Externally Fired Combined-Cycle Demonstration

Project, was concluded.

September 1997

DOE modified the cooperative agreement for JEA’s

CCT-I project, JEA Large-Scale CFB Combustion

Project (formerly The City of Tallahassee project,

then the York County Energy Partners project).

December 1997

ENCOAL Corporation’s CCT-III project, ENCOAL®

Mild Coal Gasification Project, final reports issued

and project completed.

DOE signed a new cooperative agreement for the

restructured City of Lakeland’s CCT-III project,

McIntosh Unit 4A PCFB Demonstration Project

(formerly the DMEC-1 Limited Partnership project).

January 1998

DOE signed a new cooperative agreement for the

restructured City of Lakeland’s CCT-III project,

McIntosh Unit 4B Topped PCFB Demonstration

Project (formerly the Four Rivers Energy Partners,

L.P. project).

April 1998

LIFAC-North America’s CCT-III project, LIFAC

Sorbent Injection Desulfurization Project, final reports

issued and project completed.

June 1998

Southern Company Services, Inc.’s CCT-II project,

Demonstration of Advanced Combustion Techniques

for a Wall-Fired Boiler, final report issued and project

completed.

Southern Company Services’ CCT-II project, Demonstration of Innovative Applications of Technology for

the CT-121 FGD Process, final reports issued and

project completed.

The ABB Combustion Engineering, Inc., and CQ

Inc.’s CCT-I project, Development of the Coal

Quality ExpertTM, final reports issued and project

completed.

September 1998

Energy and Environmental Research Corporation’s

CCT-I project, Enhancing the Use of Coals by Gas

Reburning and Sorbent Injection, final reports issued

and project completed.

DOE signed a revised cooperative agreement with for

the restructured ThermoChem Inc.’s CCT IV project,

Pulse Combustion Design Qualification test.

October 1998

Energy and Environmental Research Corporation’s

CCT III project, Evaluation of Gas Reburning and

Low-NOx

 Burners on a Wall-Fired Boiler, final

reports issued and project completed.
Program Update 1998 C-1

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[.]

Through NEPA, Congress 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

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, and

• “Proposed action,” which assumed that

successfully demonstrated clean coal technologies would undergo widespread commercialization by the year 2010.

In preselection project-specific environmental

reviews, DOE evaluates the environmental aspects of

Appendix C: Environmental Aspects

projects, EAs for 18 projects and EISs for 4 projects

(actions exceed 33 because of project terminations,

withdrawals, and restructuring).

For each project cofunded by DOE under the

CCT Program, the industrial participant is 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 been amended from time-to-time

by Congress. 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,

iii. alternatives to the proposed action,

Introduction

The U.S. Department of Energy employs a threestep process to ensure that the CCT Program and its

projects comply with the procedural 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 of a

programmatic environmental impact statement (PEIS)

in 1989; (2) preparation of preselection, projectspecific environmental reviews; and (3) preparation of

postselection, site-specific 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). The Department of Energy’s

NEPA regulations also provide for categorical exclusions (CX) for certain classes of actions.

Exhibit C-1 shows the progress made through

September 30, 1998, to complete NEPA reviews of

projects in the CCT Program. By September 30,

1998, NEPA reviews were completed for 35 of the 40

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 September 30, 1998, NEPA requirements

were satisfied with a CX for 1 project, MTFs for 17
C-2 Program Update 1998

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.

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);

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 September 30, 1998

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 NEPA 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.

Upon selection, project participants are required

to prepare and submit additional environmental

information. This detailed site- and project-specific

c Includes an EA for a

project that was terminated

Categorical exclusions

Environmental impact statements

Number of Projects
Program Update 1998 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

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;

and

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. Council on Environmental Quality 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. The 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

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

Exhibit C-2

Memoranda-to-File Completed
C-4 Program Update 1998

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 Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) 6/8/93

ENCOAL® Mild Coal Gasification Project (ENCOALCorporation) 8/1/90

Commercial Demonstration of the NOXSO SO2/NOx Removal Flue Gas Cleanup System (NOXSO Corporation) 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 Corporation) 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 1998 C-5

Project and Participant Completed*

CCT-I

York County Energy Partners Cogeneration Project (York County, PA 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.

Cleaning System for Retrofit Applications and Pennsylvania Electric’s Warren Station Externally Fired

Combined-Cycle Demonstration Project.

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 alternatives 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 with the proposed action. Consequently,

before a record of decision (ROD) 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 ROD on the EIS prepared for the York County Energy Partners project

located in York County, Pennsylvania. However,

because this project has been restructured, a new

NEPA compliance document will be required for the

JEA project site. (See Exhibit C-4).

terize and quantify the environmental performance of

the technology in order to evaluate its commercialization and deployment potential. In addition to regulatory 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, and

Exhibit C-4

Environmental Impact Statements Completed

NEPA Actions in Progress

Exhibit C-5 lists the status of projects for which

the NEPA process has not yet been completed.

Environmental Monitoring

CCT project participants are required to develop

and implement an EMP which addresses both compliance and supplemental monitoring. Exhibit C-6 lists

the status of EMPs for all 40 projects in the CCT

Program. The EMP is intended to ensure collection

and dissemination of the significant technology-,

project-, and site-specific environmental data necessary for evaluation of impacts upon health, safety, and

the environment. Further, the data are used to charac-
C-6 Program Update 1998

Project and Participant Status

CCT-I

JEA Large-Scale CFB Combustion Demonstration Project EIS planned (10/99)

CCT-III

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland Electric) EIS planned (10/99)

CCT-V

McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, EIS planned (10/99)

Lakeland Electric)

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management EIS planned (12/00)

Company, L.L.C.)

Clean Energy Demonstration Project (Clean Energy Partners Limited Partnership) To be determined

cialization in the late 1990s and beyond. For all

projects with existing cooperative agreements, DOE

sought to include HAPs monitoring. A total of 21

projects contain provisions for monitoring HAPs.

The CCT-V Program Opportunity Notice (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

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 21

projects that provide for HAPs monitoring. Eleven 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

Exhibit C-5

NEPA Reviews in Progress

• 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, and to the maximum

extent possible, are in the vanguard of cost-effective

solutions to concerns about public health and safety

related to coal use.

Air Toxics

Title III of the CAAA lists known hazardous air

pollutants (HAPs) and, among other things, calls for

the 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 using clean

coal technologies. It is expected that emissions

standards will be proposed for the electric-powerproduction-source 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 used.

The CCT Program recognizes the importance of

monitoring HAPs in achieving widespread commer-
Program Update 1998 C-7

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 Program 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 is sampling at other sites, including

the CCT Program’s Wabash River 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 two years later.

Following up on the October 1996 report to

Congress, a report was released by EPA focusing on

Mercury emissions. The December 1997 report,

Mercury Study Report to Congress, estimates the U.S.

industrial sources were responsible for releasing 158

tons of Mercury into the atmosphere in 1994 and

1995. The EPA estimates that 87 percent of those

emissions originate from combustion sources such as

waste and fossil fuel facilities, 10 percent from manufacturing facilities, 2 percent from area sources, and 1

percent from other sources. The EPA also identified

four specific categories that account for about 80

percent of the total anthropogenic sources: coal-fired

power plants, 33 percent; municipal waste incinerators, 18 percent; commercial and industrial boilers, 18

percent; and medical waste incinerators, 10 percent.

The next step for EPA is to assess the need for enhanced research on health effects and on new pollution control technologies, community “right-to-know”

approaches, and regulatory actions.

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 1998

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

JEA Large-Scale CFB Combustion Demonstration Project Projected 6/01

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

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 1998 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 Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) Completed 12/23/94

McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland Electric) 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

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

Commercial Demonstration of NOXSO SO2

/ NOx Removal Flue Gas Cleanup System (NOXSO Corporation) To be determined

CCT-IV

Micronized Coal Reburning Demonstration for NOx

 Control (New York State Electric & Gas Corporation) Completed 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

Pulse Combustor Design Qualification Test To be determined

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air (Custom Coals International) To be determined

CCT-V

Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) Projected 2/99

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) (CPICORTM Management Company, L.L.C.) Projected 9/02

Clean Energy Demonstration Project (Clean Energy Partners Limited Partnership) To be determined

McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, Lakeland Electric) Projected 8/03

Exhibit C-6 (continued)

Status of Environmental Monitoring Plans for CCT Projects
C-10 Program Update 1998

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, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project Planned

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 In progress

Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project In progress

Project Joint Venture

JEA Large Scale CFB Combustion 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

ENCOAL Corporation ENCOAL® Mild Coal Gasification Project Completed

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 1998 D-1

Appendix D: CCT Project Contacts

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Confined Zone Dispersion Flue Gas

Desulfurization Demonstration

Participant:

Bechtel Corporation

Contacts:

Joseph T. Newman, Project Manager

(415) 768-1189

(415) 768-5420 (fax)

Bechtel Corporation

P.O. Box 193965

San Francisco, CA 94119-3965

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

lawrence.saroff@hq.doe.gov

Robert M. Koanosky, FETC, (412) 892-4521

kornosky@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:

Tim Roth

(610) 481-6257

(610) 481-5820 (fax)

Pure Air on the Lake, L.P.

c/o Air Products and Chemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

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

lawrence.saroff@hq.doe.gov

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

(205) 992-7535 (fax)

dpburfor@southernco.com

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Project Contacts

Listed below are contacts for obtaining further

information about specific CCT Program

demonstration projects. Listed are the name, title,

phone number, fax number, mailing address, and

e-mail address, if available, for the participant’s

contact person. In those instances where the project

participant consists of more than one company, a

partnership, or joint venture, the mailing address listed

is that of the contact person. In addition, the names,

phone numbers, and e-mail addresses for contact

persons at DOE Headquarters and the Federal Energy

Technology Center are provided.

Environmental Control Devices

SO2 Control Technologies

10-MWe Demonstration of Gas Suspension

Absorption

Participant:

AirPol, Inc.

Contacts:

Niels H. Kastrup

(281) 539-3400

(281) 539-3411 (fax)

nhk@flsmiljous.com

FLS Miljo, Inc.

100 Glenborough

Houston, TX 77067
D-2 Program Update 1998

Full-Scale Demonstration of Low-NOx CellBurner

Retrofit

Participant:

The Babcock & Wilcox Company

Contacts:

Dot K. Johnson

(330) 829-7395

(330) 821-7801 (fax)

dot.k.johnson@mcdermott.com

McDermott Technologies

1562 Beeson Street

Alliance, OH 44601

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Evaluation of Gas Reburning and Low-NOx

Burners on a Wall-Fired Boiler

Participant:

Energy and Environmental Research Corporation

Contacts:

Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140

(949) 859-3194 (fax)

Energy and Environmental Research Corporation

18 Mason

Irvine, CA 92718

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

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx

 Emissions from

High-Sulfur-Coal-Fired Boilers

Participant:

Southern Company Services, Inc.

Contacts:

Larry Monroe

(205) 257-7772

(205) 257-5367 (fax)

Southern Company Services, Inc.

P.O. Box 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

180-MWe Demonstration of Advanced

Tangentially-Fired Combustion Techniques for the

Reduction of NOx Emissions from Coal-Fired

Boilers

Participant:

Southern Company Services, Inc.

Contacts:

Larry Monroe

(205) 257-7772

(205) 257-5367 (fax)

Southern Company Services, Inc.

P.O. Box 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

NOx Control Technologies

Micronized Coal Reburning Demonstration for

NOx Control

Participant:

New York State Electric & Gas Corporation

Contacts:

Jim Harvilla

(607) 729-2551

(607) 762-8457 (fax)

New York State Electric & Gas Corporation

Corporate Drive–Kirkwood Industrial Park

P.O. Box 5224

Binghamton, NY 13902-5224

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Demonstration of Coal Reburning for Cyclone

Boiler NOx

 Control

Participant:

The Babcock & Wilcox Company

Contacts:

Dot K. Johnson

(330) 829-7395

(330) 821-7801 (fax)

dot.k.johnson@mcdermott.com

McDermott Technologies

1562 Beeson Street

Alliance, OH 44601

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

lawrence.saroff@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell.fetc.doe.gov
Program Update 1998 D-3

SNOXTM Flue Gas Cleaning Demonstration

Project

Participant:

ABB Environmental Systems

Contacts:

Paul Yosick, Project Manager

(423) 693-7550

(423) 694-5213 (fax)

ABB Environmental Systems

1409 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

LIMB Demonstration Project Extension and

Coolside Demonstration

Participant:

The Babcock & Wilcox Company

Contacts:

Paul Nolan

(330) 860-1074

(330) 860-2045 (fax)

The Babcock & Wilcox Company

20 South Van Buren Avenue

P.O. Box 351

Barberton, OH 44203-0351

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

lawrence.saroff@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell@fetc.do.gov

SOx

-NOx-Rox BoxTM Flue Gas Cleanup

Demonstration Project

Participant:

The Babcock & Wilcox Company

Contacts:

Dot K. Johnson

(330) 829-7395

(330) 829-7801 (fax)

dot.k.johnson@mcdermott.com

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection

Participant:

Energy and Environmental Research Corporation

Contacts:

Blair A. Folsom, Senior Vice President

(949) 859-8851, ext. 140

(949) 859-3194 (fax)

Energy and Environmental Research

Corporation

18 Mason

Irvine, CA 92718

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

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Demonstration of Advanced Combustion

Techniques for a Wall-Fired Boiler

Participant:

Southern Company Services, Inc.

Contacts:

John N. Sorge, Research Engineer

(205) 257-7426

(205) 257-5367 (fax)

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

lawrence.saroff@hq.doe.gov

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

jlonga@fetc.doe.gov

Combined SO2/NOx Control Technologies

Milliken Clean Coal Technology Demonstration

Project

Participant:

New York State Electric & Gas Corporation

Contacts:

Jim Harvilla

(607) 729-8630

(607) 762-8457 (fax)

New York State Electric & Gas Corporation

Corporate Drive–Kirkwood Industrial Park

P.O. Box 5224

Binghamton, NY 13902-5224

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov
D-4 Program Update 1998

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

Utility Engineering

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

Commercial Demonstration of the NOXSO SO2

/

NOx Removal Flue Gas Cleanup System

Participant:

NOXSO Corporation

Contacts:

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

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

JEA Large-Scale CFB Combustion Demonstration

Project

Participant:

JEA

Contacts:

Reece E. Comer, Jr. P.E.

(904) 665-6312

(904) 665-7263 (fax)

comere@jea.com

JEA

21 West Church Street, Tower 10

Jacksonville, FL 32202-3139

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Tidd PFBC Demonstration Project

Participant:

American Electric Power Service Corporation as

agent for The Ohio Power Company

Contacts:

Mario Marrocco

(614) 223-2460

(614) 223-3204 (fax)

American Electric Power Service Corporation

1 Riverside Plaza

Columbus, OH 43215

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

Advanced Electric Power

Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project

Participant:

City of Lakeland, Lakeland Electric

Contacts:

Alfred M. Dodd, Project Manager

(941) 499-6461

(941) 499-6344 (fax)

Lakeland Electric

501 E. Lemon Street

Lakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

McIntosh Unit 4B Topped PCFB Demonstration

Project

Participant:

City of Lakeland, Lakeland Electric

Contacts:

Alfred M. Dodd, Project Manager

(941) 499-6461

(941) 499-6344 (fax)

Lakeland Electric

501 E. Lemon Street

Lakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov
Program Update 1998 D-5

Nucla CFB Demonstration Project

Participant:

Tri-State Generation and Transmission

Association, Inc.

Contacts:

Stuart Bush

(303) 452-6111

(303) 254-6066 (fax)

Tri-State Generation and Transmission

Association, Inc.

P.O. Box 33695

Denver, CO 80233

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project

Participant:

Clean Energy Partners Limited Partnership

Contacts:

Victor Shellhorse, Vice President

(704) 382-8064

(704) 373-4986 (fax)

Duke Energy Industrial Asset Development

400 S. Tryon Street

Charlotte, NC 28202

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

Piñon Pine IGCC Power Project

Participant:

Sierra Pacific Power Company

Contacts:

Jeffrey W. Hill, Director Power Generation

(702) 834-5650

(702) 834-5704 (fax)

jhill@sppc.com

Sierra Pacific Power Company

P.O. Box 10100

Reno, NV 89520-0024

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

Web Site:

http://www.sierrapacific.com/utilserv/electric/pinon/

Tampa Electric Integrated Gasification CombinedCycle Project

Participant:

Tampa Electric Company

Contacts:

Donald E. Pless, Director, Advanced Technology

(813) 228-1111, ext. 46201

(813) 641-5300 (fax)

Tampa Electric Company

P.O. Box 111

Tampa, FL 33601-0111

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

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

watts@fetc.doe.gov

Web Site:

http://www.teco.net/teco/TEKPlkPwrStn.html

Wabash River Coal Gasification Repowering

Project

Participant:

Wabash River Coal Gasification Repowering Project

Joint Venture

Contacts:

Phil Amick, Director of Gasification Development

(713) 767-8667

(713) 767-8515 (fax)

pram@dynergy.com

Dynergy Power Corp.

1000 Louisiana St., Suite 5800

Houston, TX 77002

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Leo E. Makovski, FETC, (412) 892-5814

makovsky@fetc.doe.gov

Advanced Combustion/Heat Engines

Healy Clean Coal Project

Participant:

Alaska Industrial Development and Export Authority

Contacts:

Dennis V. McCrohan, Deputy Director, Project

Development and Operations

(907) 269-3025

(907) 269-3044 (fax)

dmccrohan@aidea.org

Alaska Industrial Development and Export

Authority

480 West Tudor Road

Anchorage, AK 99503-6690

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Robert M. Kornosky, FETC, (412) 892-4521

kornosky@fetc.doe.gov
D-6 Program Update 1998

Clean Coal Diesel Demonstration Project

Participant:

Arthur D. Little, Inc.

Contacts:

Robert P. Wilson, Vice President

(617) 498-5806

(617) 498-7206 (fax)

Arthur D. Little, Inc.

25 Acorn Park

Cambridge, MA 02140

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Coal Processing for Clean Fuels

Indirect Liquefaction

Commercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOHTM) Process

Participant:

Air Products Liquid Phase Conversion Company, L.P.

Contacts:

Edward C. Heydorn, Project Manager

(610) 481-7099

(610) 706-7299 (fax)

heydorec@apci.com

Air Products and Chemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

Edward Schmetz, DOE/HQ, (301) 903-3931

edward.schmetz@hq.doe.gov

Robert M. Kornosky, FETC, (412) 892-4521

kornosky@fetc.doe.gov

Coal Preparation Technologies

Advanced Coal Conversion Process Demonstration

Participant:

Rosebud SynCoal Partnership

Contacts:

Ray W. Sheldon, P.E., Director of Development

(406) 252-2277

(406) 252-2090 (fax)

Rosebud SynCoal Partnership

P.O. Box 7137

Billings, MT 59103-7137

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk, FETC, (412) 892-6249

renk@fetc.doe.gov

Development of the Coal Quality ExpertTM

Participants:

ABB Combustion Engineering, Inc., and CQ Inc.

Contacts:

Clark D. Harrison, President

(724) 479-3503

(724) 479-4181

CQ Inc.

160 Quality Center Rd.

P.O. Box 280

Homer City, PA 15748

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

Mild Gasification

ENCOAL® Mild Coal Gasification Project

Participant:

ENCOAL Corporation

Contacts:

Brent A. Knottnerus, Project Manager

(307) 686-2720, ext. 27

(307) 686-2894 (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

Self-Scrubbing CoalTM”: An Integrated Approach

to Clean Air

Participant:

Custom Coals International

Contacts:

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk, FETC, (412) 892-6249

renk@fetc.doe.gov
Program Update 1998 D-7

Industrial Applications

Blast Furnace Granular-Coal Injection System

Demonstration Project

Participant:

Bethlehem Steel Corporation

Contacts:

Robert W. Bouman, Project Director

(610) 694-6792

(610) 694-2981 (fax)

Bethlehem Steel Corporation

Homer Research Laboratory

Building C, Room 211

Bethlehem, PA 18016

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Leo E. Makovski, FETC, (412) 892-5814

makovsky@fetc.doe.gov

Clean Power from Integrated Coal/Ore Reduction

(CPICORTM)

Participant:

CPICORTM Management Company, L.L.C.

Contacts:

Reginal Wintrell, Project Director

(801) 227-9214

(801) 227-9198 (fax)

CPICOR Management Company, LLC

P.O. Box 2500

Provo, UT 84603

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

Advanced Cyclone Combustor with Internal

Sulfur, Nitrogen, and Ash Control

Participant:

Coal Tech Corporation

Contacts:

Bert Zauderer, President

(610) 667-0442

(610) 667-0576 (fax)

coaltechbz@compuserve.com

Coal Tech Corporation

P.O. Box 154

Merion, PA 19066

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Arthur L. Baldwin, FETC, (412) 892-6011

baldwin@fetc.doe.gov

Cement Kiln Flue Gas Recovery Scrubber

Participant:

Passamaquoddy Tribe

Contacts:

Thomas N. Tureen, Project Manager

(207) 773-7166

(207) 773-8832 (fax)

ttureen@gwi.com

Passamaquoddy Technology, L.P.

1 Monument Way

Portland, ME 04101

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell@fetc.doe.gov

Pulse Combustor Design Qualification Test

Participant:

ThermoChem, Inc.

Contacts:

William G. Steedman, Sr. Systems Engineer

(410) 354-9890

(410) 354-9894 (fax)

tcheminc@aol.com

ThermoChem, Inc.

6001 Chemical Road

Baltimore, MD 21226

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Gary E. Staats, FETC, (412) 892-5741

staats@fetc.doe.gov
Program Update 1998 E-1

Appendix E: Acronyms, Abbreviations, and

Symbols

Acronyms, Abbreviations, and

Symbols

°C degrees Celsius

°F degrees Fahrenheit

$ dollars (U.S.)

$/kw dollars per kilowatt

$/ton dollars per ton

% percent

® registered trademark

TM trademark

ABB CE ABB Combustion Engineering, Inc.

ABB ES ABB Environmental Systems

ACFB atmospheric circulating fluidized-bed

ADL Arthur D. Little, Inc.

AFBC atmospheric fluidized-bed

combustion

AFGD advanced flue gas desulfurization

AIDEA Alaska Industrial Development and

Export Authority

AOFA advanced overfire air

APF advanced particulate filter

ASME American Society of Mechanical

Engineers

Ass’n. Association

ATCF after tax cash flows

atm atmosphere(s)

avg. average

BFGCI blast furnace granular-coal injection

BG British Gas

BG/L British Gas/Lurgi

Btu British thermal unit(s)

Btu/kWh British thermal units per kilowatthour

B&W The Babcock & Wilcox Company

CAAA Clean Air Act Amendments of 1990

CaCO3 calcium carbonate (calcitic

limestone)

CaO calcium oxide (lime)

Ca(OH)2 calcium hydroxide (calcitic

hydrated lime)

Ca(OH)2•MgO dolomitic hydrated lime

Ca/N calcium/nitrogen

CAPI Clean Air Power Initiative

Ca/S calcium/sulfur

CaSO3 calcium sulfite

CaSO4 calcium sulfate

CCOFA close-coupled overfire air

CCT clean coal technology

CCT I First CCT Program solicitation

CCT II Second CCT Program solicitation

CCT III Third CCT Program solicitation

CCT IV Fourth CCT Program solicitation

CCT V Fifth CCT Program solicitation

CCT Program Clean Coal Technology

Demonstration Program

CDL® Coal-Derived Liquid®

CEQ Council on Environmental Quality

CFB circulating fluidized bed

C/H carbon/hydrogen

CKD cement kiln dust

CO carbon monoxide

CO2 carbon dioxide

COP Conference of Parties

CT-121 Chiyoda Thoroughbred-121

CQETM Coal Quality ExpertTM

CQIMTM Coal Quality Impact ModelTM

CX categorical exclusion

CZD confined zone dispersion

DER discrete emissions reduction

DME dimethyl ether

DOE U.S. Department of Energy

DOE/HQ U.S. Department of Energy

Headquarters

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

ext. extension

FBC fluidized-bed combustion
E-2 Program Update 1998

FCCC Framework Convention on Climate

Change

Fe2S pyritic sulfur

FERC Federal Energy Regulatory

Commission

FETC Federal Energy Technology Center

FGD flue gas desulfurization

FONSI finding of no significant impact

FRP fiberglass-reinforced plastic

ft, ft2

, ft3 foot (feet), square feet, cubic feet

FY fiscal year

gal. gallon(s)

gal/ft3 gallons per cubic feet

GB gigabyte(s)

GE General Electric

GHG greenhouse gases

GNOCIS Generic NOx Control Intelligence

System

gpm gallons per minute

GR gas reburning

GR–LNB gas reburning and low-NOx

 burner

GR–SI gas reburning and sorbent injection

GSA gas suspension absorption

GVEA Golden Valley Electric Association

GW gigawatt(s)

GWe gigawatt(s)-electric

H2

S hydrogen sulfide

H2SO4 sulfuric acid

HAP hazardous air pollutant

HCl hydrogen chloride

HF hydrogen fluoride

HGPFS hot gas particulate filter system

HHV high heating value

hr. hour(s)

HRSG heat recovery steam generator

IEA International Energy Agency

IGCC integrated gasification combined

cycle

in, in2

, in3 inch(es), square inches, cubic inches

JEA Jacksonville Electric Authority

JBR Jet Bubbling Reactor®

KCl potassium chloride

K2SO4 potassium sulfate

kW kilowatt(s)

kWh kilowatt-hour(s)

lb. pound(s)

L/G liqud to gas ratio

LHV low heating value

LIMB limestone injection multistage

burner

LNB low-NOx burner

LNCB® low-NOx cell burner

LNCFS Low-NOx Concentric-Firing System

LOI loss on ignition

LPMEOHTM Liquid phase methanolTM

LRCWF low-rank coal-water-fuel

LSFO limestone forced oxidation

MASB multi-annular swirl burner

MB megabyte(s)

MCFC molten carbonate fuel cell

MgCO3 magnesium carbonate

MgO magnesium oxide

Mhz megahertz

mills/kWh mills per kilowatt hour

min. minute(s)

mo. month(s)

MTCI Manufacturing and Technology

Conversion International

MTF memorandum (memoranda)-to-file

MW megawatt(s)

MWe megawatt(s)-electric

MWt megawatt(s)-thermal

N2 atmospheric nitrogen

Na/Ca sodium/calcium

Na2/S sodium/sulfur

NaOH sodium hydroxide

Na2

CO3 sodium carbonate

NAAQS National Ambient Air Quality

Standards

NEPA National Environmental Policy Act

NH3 ammonia

NO2 nitrogen dioxide

NOPR Notice of Proposed Rulemaking

NOx nitrogen oxides

NSPS New Source Performance Standards

NTHM net tons of hot metal

NTIS National Technical Information

Service

NYSEG New York State Electric & Gas

Corporation

OC&PS Office of Coal & Power Systems

O&M operating and maintenance

O2 oxygen

OTAG Ozone Transport Assessment Group

OTC Ozone Transport Commission

PC personal computer

PCAST Presidential Committee of Advisors

on Science and Technology

PCFB pressurized circulating fluidized bed

PDF® Process-Derived Fuel®

PEIA programmatic environmental impact

assessment

PEIS programmatic environmental impact

statement

PEOATM Plant Emission Optimization

AdvisorTM

PENELEC Pennsylvania Electric Company
Program Update 1998 E-3

PEP progress evaluation plan

PFBC pressurized fluidized-bed

combustion

PJBH pulse jet baghouse

PM particulate matter

PM10 particulate matter less than 10

microns in diameter

PM2.5 particulate matter less than 2.5

microns in diameter

PON program opportunity notice

PRB Powder River Basin

ppm parts per million (mass)

ppmv parts per million by volume

PSCC Public Service Company of Colorado

PSD Prevention of Significant

Deterioration

psi pound(s) per square inch

PUHCA Public Utility Holding Company

Act of 1935

PURPA Public Utility Regulatory Policies

Act of 1978

QF qualifying facility

RAM random access memory

R&D research and development

RD&D research, development, and

demonstration

REA Rural Electrification Administration

RP&L Richmmond Power & Light

ROD Record of Decision

rpm revolutions per minute

RUS Rural Utility Service

S sulfur

SBIR Small Business Innovation Research

scf standard cubic feet

scfm standard cubic feet per minute

SCR selective catalytic reduction

SCS Southern Company Services, Inc.

SFC Synthetic Fuels Corporation

S-H-U Saarberg-Hölter-Umwelttechnik

SI sorbent injection

SIP state implementation plan

SM service mark

SNCR selective noncatalytic reduction

SNRBTM SOx

-NOx-Rox BoxTM

SO2 sulfur dioxide

SO3 sulfur trioxide

std ft3 standard cubic feet

SOFA separated overfire air

STTR Small Business Technology

Transfer Program

SVGA super video graphics adapter

TAGTM Technical Assessment GuideTM

TCLP toxicity characteristics leaching

procedure

TVA Tennessee Valley Authority

UAF University of Alaska, Fairbanks

UARG Utility Air Regulatory Group

UBCL unburned carbon

U.K. United Kingdom

U.S. United States

VFB vibrating fluidized-bed

VOC volatile organic compound

WC water column

WES wastewater evaporation system

WLFO wet limestone, forced oxidation

wt. weight

yr. year(s)

State Abbreviations

States are abbreviated using two-letter postal codes.
Program Update 1998 Index-1

Index of CCT Projects and Participants

#

10-MWe Demonstration of Gas Suspension

Absorption ES-7, ES-10, ES-17, 2-6, 3-8,

4-3, 5-3, 5-17, 5-19, 5-22, 5-25, C-3, C-9, 

C-10, D-1

180-MWe Demonstration of Advanced

Tangentially Fired Combustion Techniques for the

Reduction of NOx Emissions from Coal-Fired

Boilers ES-8, ES-11, 2-6, 4-4, 5-5, 5-17,

5-20, 5-62, 5-65, B-3, C-3, C-8, C-10, D-2

A

ABB Combustion Engineering, Inc. ES-6,

ES-11, ES-14, ES-15, ES-18, ES-19, 2-6, 2-10,

3-8, 4-3, 4-4, 4-9, 5-18, 5-19, 5-44, 5-62, 5-64,

5-72, 5-81, 5-138, 5-141, B-2, B-3, B-5,

B-6, C-3, C-4, C-8, D-6, E-1

ABB Environmental Systems ES-8, ES-11,

ES-17, 2-6, 2-8, 4-5, 5-17, 5-19, 5-78, 5-81,

B-6, C-3, C-8, C-10, D-3, E-1

Advanced Coal Conversion Process

Demonstration ES-15, ES-18, 2-6, 5-13,

5-18, 5-20, 5-136, B-2, B-3, C-4, C-8, D-6

Advanced Cyclone Combustor with Internal Sulfur,

Nitrogen, and Ash Control ES-17, ES-18,

2-6, 5-15, 5-18, 5-19, 5-152, 5-155, B-1,

B-4, C-3, C-8, D-7

Advanced Flue Gas Desulfurization Demonstration

Project ES-3, ES-10, ES-17, ES-19, 2-6,

3-8, 4-3, 5-3, 5-17, 5-20, 5-34, B-2, C-4,

C-8, C-10, D-1

Air Products Liquid Phase Conversion Company,

L.P. ES-15, ES-18, 2-6, 2-10, 4-8, 4-9,

5-18, 5-19, 5-132, 5-133, B-5, C-4, C-9, D-6

AirPol, Inc. ES-7, ES-10, ES-17, 2-6, 2-8,

3-8, 4-2, 4-3, 5-17, 5-19, 5-22, 5-25, B-3,

B-5, C-3, C-9, C-10, D-1

Alaska Industrial Development and Export

Authority ES-13, ES-18, 2-6, 2-9, 5-18,

5-19, 5-126, B-3, C-5, C-9, C-10, D-5, E-1

Arthur D. Little, Inc. ES-18, 2-7, 5-18, 5-

19, 5-128, B-4, B-5, C-4, C-9, C-10, D-6, E-1

B

Babcock & Wilcox Company, The ES-6,

ES-8, ES-9, ES-10, ES-11, ES-17, ES-19,

2-6, 2-8, 3-8, 4-3, 4-5, 4-4, 4-7, 4-16, 5-17,

5-19, 5-46, 5-49, 5-50, 5-53, 5-82, 5-85,

5-86, 5-89, 5-94, B-1, B-2, B-3, B-4, B-5,

C-3, C-4, C-8, C-9, C-10, D-2, D-3, E-1

Bechtel Corporation ES-7, ES-17, 2-7, 2-8,

4-2, 5-17, 5-19, 5-26, 5-29, B-3, B-5, C-3,

C-9, D-1

Bethlehem Steel Corporation ES-17, ES-18,

2-7, 4-10, 4-11, 5-14, 5-18, 5-19, 5-148, B-2,

B-3, B-5, C-3, C-4, C-9, D-7

Blast Furnace Granular-Coal Injection System

Demonstration Project ES-17, ES-18, 2-7,

4-11, 5-15, 5-18, 5-19, 5-148, B-3, C-4,

C-9, D-7

C

Cement Kiln Flue Gas Recovery Scrubber

ES-17, ES-18, 2-6, 4-11, 5-15, 5-18, 5-20,

5-156, 5-159, B-2, B-4, C-4, C-8, D-7

City of Lakeland, Lakeland Electric ES-17,

2-7, 5-17, 5-19, 5-100, 5-102, C-6, C-9,

C-10, D-4

Clean Coal Diesel Demonstration Project

ES-18, 2-7, 5-11, 5-18, 5-19, 5-128, B-5,

C-4, C-9, C-10, D-6

Clean Energy Demonstration Project ES-18,

2-7, 5-11, 5-18, 5-19, 5-116, B-5, C-6, C9, C-10, D-5

Clean Energy Partners Limited Partnership

ES-18, 2-7, 2-9, 5-18, 5-19, 5-116, B-5,

C-6, C-9, C-10, D-5

Clean Power from Integrated Coal/Ore Reduction

(CPICORTM) ES-18, 2-7, 5-15, 5-18, 5-19,

5-150, B-4, B-6, C-6, C-9, C-10, D-7
Index-2 Program Update 1998

Coal Tech Corporation ES-17, ES-18, 2-6,

2-11, 4-10, 5-18, 5-19, 5-152, 5-155, B-1,

B-4, C-3, C-8, D-7

Commercial Demonstration of NOXSO SO2

/NOx

Removal Flue Gas Cleanup System ES-17, 2-7,

5-17, 5-20, 5-76, B-3, B-5, C-4, C-9, D-4

Commercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOHTM) Process

ES-15, ES-18, 2-6, 4-9, 5-13, 5-18, 5-19,

5-132, B-4, C-4, C-9, D-6

Confined Zone Dispersion Flue Gas

Desulfurization ES-7, ES-17, 2-7, 5-3, 5-17,

5-19, 5-26, 5-29, B-3, B-5, C-3, C-9, D-1

CPICORTM Management Company, L.L.C.

ES-18, 2-7, 2-11, 5-18, 5-19, 5-150, B-4, 

B-6, C-6, C-9, C-10, D-7

CQ Inc. ES-6, ES-14, ES-15, ES-18, ES-19,

2-6, 2-10, 3-8, 4-9, 5-12, 5-18, 5-19, 5-138,

5-139, 5-140, 5-141, B-2, B-3, B-6, C-3, C8, D-6

Custom Coals International ES-15, ES-18,

2-7, 2-10, 5-18, 5-19, 5-134, B-4, C-4, C-9,

D-6

D

Demonstration of Advanced Combustion

Techniques for a Wall-Fired Boiler ES-8,

ES-10, ES-17, 2-6, 4-4, 5-5, 5-17, 5-20,

5-66, B-2, B-6, C-3, C-8, C-10, D-3

Demonstration of Coal Reburning for Cyclone

Boiler NOx Control ES-8, ES-10, ES-17,

2-6, 4-4, 5-5, 5-17, 5-19, 5-46, 5-49, B-3,

B-4, C-4, C-8, C-10, D-2

Demonstration of Innovative Applications of

Technology for the CT-121 FGD ES-7, ES10, ES-17, ES-19, 2-6, 4-3, 5-3, 5-17, 5-20,

5-38, 5-41, B-3, C-4, C-8, C-10, D-1

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx

 Emissions from

High-Suflur-Coal-Fired Boilers ES-8, ES-17,

2-6, 5-5, 5-17, 5-20, 5-58, B-3, C-3, C-8, D-2

Development of the Coal Quality ExpertTM

ES-6, ES-14, ES-15, ES-18, ES-19, 2-6, 3-

8, 5-13, 5-18, 5-19, 5-138, 5-141, B-2, B-3,

C-3, C-8, D-6

E

ENCOAL Corporation ES-14, ES-15, ES-18,

2-7, 2-10, 4-9, 5-18, 5-19, 5-142, 5-145, 

B-3, B-6, C-4, C-9, C-10, D-6

ENCOAL® Mild Coal Gasification Project

2-7, 4-9, 5-13, 5-18, 5-19, 5-142, 5-145, B-3,

B-6, C-4, C-9, C-10, D-6

Energy and Environmental Research

Corporation ES-8, ES-9, ES-10, ES-17,

ES-19, 2-6, 2-7, 2-8, 4-3, 4-4, 4-5, 5-17,

5-19, 5-44, 5-54, 5-55, 5-57, 5-90, 5-93,

B-1, B-3, B-6, C-3, C-4, C-8, C-9, D-2,

D-3, E-1

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection ES-9, ES-17, ES-19, 2-6,

4-93, 5-17, 5-19, 5-90, 5-93, B-1, B-6, C-3,

C-4, C-8, D-3

Evaluation of Gas Reburning and Low-NOx

Burners on on a Wall-Fired Boiler ES-8,

ES-10, ES-17, ES-19, 2-7, 4-4, 5-5, 5-17,

5-19, 5-54, 5-57, B-3, B-6, C-3, C-9, D-2

F

Full-Scale Demonstration of Low-NOx Cell Burner

Retrofit ES-6, ES-8, ES-10, ES-17, ES-19,

2-6, 3-8, 4-4, 5-5, 5-17, 5-19, 5-50, 5-53, B3, B-5, C-3, C-9, D-2

H

Healy Clean Coal Project ES-13, ES-18, 2-6,

5-11, 5-18, 5-19, 5-126, B-3, C-5, C-9, C-10,

D-5

I

Integrated Dry NOx/SO2 Emissions Control

System ES-9, ES-11, ES-17, 2-7, 5-17,

5-20, 5-94, 5-96, 5-97, B-3, C-3, C-9, C-10,

D-4

J

JEA ES-17, 2-9, 4-6, 5-17, 5-19, 5-104,

5-105, B-3, B-6, C-5, D-4, E-2

JEA Large-Scale CFB Combustion Demonstration

Project ES-17, 2-6, 5-11, 5-17, 5-19, 5-104,

B-6, C-6, C-8, C-10, D-4
Program Update 1998 Index-3

L

LIFAC Sorbent Injection Desulfurization

Demonstration Project ES-7, ES-10, ES-17,

2-7, 4-3, 5-3, 5-17, 5-19, 5-30, 5-33, B-3, B-6,

C-3, C-9, D-1

LIFAC–North America ES-7, ES-10, ES-17,

2-7, 2-8, 4-2, 4-3, 5-17, 5-19, 5-30, 5-33, B-3,

B-6, C-3, C-9, D-1

LIMB Demonstration Project Extension and

Coolside Demonstration ES-9, ES-11,

ES-17, 2-6, 4-5, 5-17, 5-19, 5-82, 5-85,

B-1, B-4, C-3, C-8, D-3

M

McIntosh Unit 4A PCFB Demonstration

Project ES-17, 2-7, 5-11, 5-17, 5-19,

5-100, B-6, C-6, C-9, D-4

McIntosh Unit 4B Topped PCFB Demonstration

Project ES-17, 2-7, 5-11, 5-17, 5-19,

5-100, 5-102, B-4, B-6, C-6, C-9, C-10, D-4

Micronized Coal Reburning Demonstration for

NOx

 Control ES-17, 2-7, 5-5, 5-17, 5-19,

5-44, B-4, B-5, C-9, D-2

Milliken Clean Coal Technology Demonstration

Project ES-11, ES-17, 2-7, 4-5, 5-17, 5-20,

5-72, 5-75, B-4, C-4, C-9, C-10, D-3

N

New York State Electric & Gas Corporation

ES-9, ES-17, 1-4, 2-7, 2-8, 4-5, 5-6, 5-17,

5-19, 5-20, 5-44, 5-72, 5-75, B-4, B-5, C-4, 

C-9, C-10, D-2, D-3, E-2

NOXSO Corporation ES-17, 2-7, 2-8, 4-4,

5-17, 5-20, 5-76, B-3, B-5, C-4, C-9, D-4

Nucla CFB Demonstration Project ES-12,

ES-13, ES-18, 2-6, 3-8, 5-11, 5-18, 5-20,

5-110, 5-113, B-4, C-3, C-8, D-5

O

Ohio Power Company, The ES-1, ES-12,

ES-13, ES-18, ES-19, 2-6, 4-6, 4-8, 5-18,

5-20, 5-106, 5-109, B-1, B-5, C-3, C-8,

C-10, D-4

P

Passamaquoddy Tribe ES-17, ES-18, 2-6,

2-11, 4-10, 4-11, 5-18, 5-20, 5-156, 5-159,

B-2, B-4, C-4, C-8, D-7

Piñon Pine IGCC Power Project ES-13,

ES-18, 2-7, 4-7, 5-11, 5-18, 5-20, 5-118,

B-4, C-5, C-9, C-10, D-5

Public Service Company of Colorado ES-9,

ES-17, 2-7, 4-4, 4-5, 5-17, 5-20, 5-57,

5-94, 5-96, 5-97, B-3, C-3, C-9, C-10, D-4

Pulse Combustor Design Qualification Test

ES-18, 2-7, 5-15, 5-18, 5-20, 5-160, C-9, D-7

Pure Air on the Lake, L.P. ES-3, ES-7, ES-10,

ES-17, ES-19, 2-6, 3-8, 4-2, 4-3, 5-17, 5-20,

5-34, 5-37, B-2, C-4, C-8, C-10, D-1

R

Rosebud SynCoal Partnership ES-15, ES-18,

2-6, 4-7, 5-12, 5-13, 5-18, 5-20, 5-136,

B-2, B-3, C-4, C-8, D-6

S

Self-Scrubbing CoalTM: An Integrated Approach to

Clean Air ES-15, ES-18, 2-7, 5-13, 5-18,

5-19, 5-134, C-4, C-9, D-6

Sierra Pacific Power Company ES-13, ES-18,

1-9, 2-7, 4-7, 4-8, 4-13, 5-18, 5-20, 5-118,

B-4, C-5, C-9, C-10, D-5

SNOXTM Flue Gas Cleaning Demonstration

Project ES-8, ES-11, ES-17, 2-6, 4-5, 5-17,

5-19, 5-78, C-3, C-8, C-10, D-3

Southern Company Services, Inc. ES-2,

ES-7, ES-8, ES-10, ES-11, ES-17, ES-19,

2-6, 2-8, 4-2, 4-3, 4-4, 5-17, 5-20, 5-38,

5-41, 5-58, 5-61, 5-62, 5-65, 5-66, 5-69,

B-2, B-3, B-6, C-3, C-4, C-8, C-10, D-1,

D-2, D-3, E-3

SOx

-NOx-Rox BoxTM Flue Gas Cleanup

Demonstration Project ES-9, ES-17, 2-6,

5-17, 5-19, 5-86, 5-89, B-2, B-5, C-3, C-8,

C-10, D-3

T

Tampa Electric Company ES-1, ES-13,

ES-18, ES-19, 1-9, 2-7, 4-8, 5-9, 5-18,

5-20, 5-120, B-3, C-5, C-9, C-10, D-5
Index-4 Program Update 1998

Tampa Electric Integrated Gasification CombinedCycle Project ES-1, 2-7, 4-6, 5-11, 5-18,

5-20, 5-120, B-3, C-5, C-9, C-10, D-5

ThermoChem, Inc. ES-18, 2-7, 4-10, 5-18,

5-20, 5-160, B-4, D-7

Tidd PFBC Demonstration Project ES-1,

ES-12, ES-13, ES-18, ES-19, 2-6, 5-11, 5-18,

5-20, 5-106, 5-109, B-1, B-5, C-3, C-8,

C-10, D-4

Tri-State Generation and Transmission

Association ES-12, ES-18, 2-6, 3-8, 4-5, 5-8,

5-18, 5-20, 5-110, 5-113, B-4, C-3, C-8, D-5

W

Wabash River Coal Gasification Repowering

Project ES-6, ES-13, ES-18, ES-19, 2-7,

4-6, 5-10, 5-11, 5-18, 5-20, 5-122, B-4, C-4,

C-9, C-10, D-5