U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

DOE/FE-0369

Clean Coal Technology

Demonstration Program

Project Fact Sheets 1997

February 1998
U.S. Department of Energy

Assistant Secretary for Fossil Energy

Washington, DC 20585

Clean Coal Technology

Demonstration Program

Project Fact Sheets 1997

February 1998

DOE/FE-0369
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.
Project Fact Sheets 1997 iii

Contents

The Clean Coal Technology Demonstration

Program

Introduction 1

Evolution of the Coal Technology Portfolio 2

Performance Results 2

Technology Successes 3

Project Fact Sheets 3

SO2 Control Technology 8

NOx Control Technology 30

Combined SO2

/NOx Control Technology 56

Fluidized-Bed Combustion 82

Integrated Gasification Combined Cycle 83

Integrated Gasification Fuel Cell 83

Coal-Fired Diesel 84

Slagging Combustor 84

Status of Projects 84

Introduction 112

Introduction 126

CCT Project Contacts A-1

Acronyms and Abbreviations B-2

Environmental Control Devices

Advanced Electric Power Generation

Technology

Coal Processing for Clean Fuels Technology

Industrial Applications Technology

Appendix A

Appendix B
iv Project Facts Sheets 1997

Exhibits

1 Completed Projects by Application Category 3

2 Project Schedules and Funding by Application Category 4

3 Project Fact Sheets: Clean Coal Technology Demonstration Program 6

4 CCT Program SO2 Control Technology Characteristics 9

5 Variables and Levels Used in GSA Factorial Testing 12

6 GSA Factorial Testing Results 12

7 SO2 Removal Performance 24

8 Estimated Costs for an AFGD System 25

9 Flue Gas Desulfurization Economics 25

10 Operation of CT-121 Scrubber 28

11 SO2

 Removal Efficiency 28

12 Particulate Capture Performance 28

13 CT-121 Air Toxics Removal 29

14 Group 1 and 2 Boiler Statistics and Phase II NOx Emission Limits 30

15 CCT Program NOx Control Technology Characteristics 31

16 Coal Reburn Test Results 34

17 Coal Reburn Economics 35

18 NOx Data from Cherokee Station, Unit 3 42

19 Catalysts Tested 50

20 Avg SO2 Oxidation Rate 50

21 Design Criteria 51

22 LNCFSTM Configurations 54

23 Concentric Firing Concept 54

24 Unit Performance Impacts Based on Long-Term Testing 55

25 Average Annual NOx

 Emissions and % Reduction 55

Environmental Control Devices

NOx Control Technology

The Clean Coal Technology Demonstration

Program

SO2 Control Technology
Project Fact Sheets 1997 v

26 CCT Program Combined SO2/NOx Control Technology Characteristics 57

27 LIMB SO2

 Removal Efficiencies 64

28 Capital Cost Comparison 65

29 Annual Levelized Cost Comparison 65

30 CCT Program Advanced Electric Power Generation Technology Characteristics 85

31 Effect of Bed Temperature on Ca/S Requirement 98

32 Calcium Requirements and Sulfur Retentions for Various Fuels 98

33 CCT Program Coal Processing for Clean Fuels Technology Characteristics 113

34 CQETM Stand-Alone System Requirements 116

35 CCT Program Industrial Applications Technology Characteristics 127

36 Summary of Emissions and Removal Efficiencies 138

Combined SO2

/NOx Control Technology

Advanced Electric Power Generation

Technology

Coal Processing for Clean Fuels Technology

Industrial Applications Technology
Project Fact Sheets 1997 1

The Clean Coal Technology Demonstration

Program

Introduction

The Clean Coal Technology Demonstration Program (known as the CCT Program) reached a significant milestone in 1997 with the completion of 21 of the

39 active projects. This milestone showed that this

cooperative government/industry cost-shared program

has yielded technologies that (1) are capable of meeting

the environmental performance requirements established in current and emerging environmental standards

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

economic performance necessary to compete in the era

of deregulation and competition.

The CCT Program is responding to a need to

demonstrate and deploy a portfolio of technologies that

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

billion tons could continue to supply the nation’s

energy needs economically and in a manner that meets

the nation’s environmental objectives. This portfolio of

technologies includes environmental control devices

that contribute to meeting the accords on transboundary

air pollution recommended by the Special Envoys on

Acid Rain in 1986 and the requirements of the Clean

Air Act Amendments of 1990 (CAAA). Operational,

technical, environmental, and economic performance

information and data are now flowing from highly

efficient, low-emission, advanced power generation

technologies that will enable coal to retain its promiTampa 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.

nent role into the next millennium. Further, advanced

technologies are emerging that will enhance the competitive use of coal in the industrial sector, such as in

steelmaking. Coal processing technologies will enable

the entire coal resource base to be used while complying with environmental requirements. These technologies are producing products used by utilities and

industrial processes. The capability to coproduce

products, such as liquid and solid fuels, electricity, and

chemicals, is being demonstrated at a commercial scale

by projects in the CCT Program. In summary, this

portfolio of technologies is satisfying the national need

to maintain a multifuel energy mix in which coal is a

key component because of its low-cost, availability,

and abundant supply within the nation’s borders.

The international opportunities for coal technology

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

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

the current level. Coal is expected to account for about

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

$1 trillion by 2015. Capturing just 20 percent of this

market would bring in revenues of $200 billion and

support more than 100,000 jobs over three decades in

the domestic power equipment industry alone. There

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

on the knowledge and experience gained through

participation in the CCT Program.
2 Project Fact Sheets 1997

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

Services, Inc.)—1994 Powerplant Award presented by

Power magazine.

Evolution of the Coal Technology

Portfolio

The CCT Program has been implemented through

a series of five nationwide competitive solicitations

conducted over a 10-year period. The first solicitation

was directed towards demonstrating the feasibility of

future commercial application of clean coal technology, which would balance the goals of expanding coal

use and minimizing environmental impact. The next

two solicitations were aimed primarily at the technologies that could mitigate the potential impacts of acid

rain from existing coal-fired power plants in response

to the recommendations of the Special Envoys on Acid

Rain. The fourth and fifth solicitations addressed the

post-2000 energy supply and demand situations with

sulfur dioxide (SO2) emissions capped under the

CAAA, increased need for electric power, and the need

to alleviate concerns over global climate change—a

situation that translates into a need for technologies

with very high efficiencies and extremely low emissions.

The technologies are categorized in four market

sectors:

• Environmental control devices

• Advanced electric power generation

• Coal processing for clean fuels

• Industrial applications

Approximately 56 percent, or about $3.2 billion,

of the total CCT Program costs are directed toward

enhancing efficiency, environmental performance, and

reliability of electric power production by the demonstration of advanced electric power generation systems.

Over 900 megawatts (MWe) of new capacity and

over 800 MWe of repowered capacity are represented

by 11 advanced electric power generation projects.

Projects include 4 integrated gasification combinedcycle systems, 5 fluidized-bed combustion systems,

and 2 advanced combustion/heat engine systems.

These projects will provide environmentally sound,

more efficient, and less costly electric power generation in the late-1990s and also will provide the demonstrated technology base necessary to meet new capacity

requirements in the 21st century.

There are 19 environmental control devices

projects valued at more than $700 million. These

projects include 7 nitrogen oxide (NOx) emissions

control systems installed on over 1,700 MWe of utility

generating capacity, 5 SO2

 emissions control systems

installed on about 770 MWe, and 7 combined SO2

/

NOx emissions control systems installed on about 700

MWe of capacity. Most of these environmental control

devices had their operating experience documented by

the end of 1997.

The five projects in the coal processing for clean

fuels category, valued at nearly $520 million, represent a diversified portfolio of technologies. Three

projects involve the production of high-energy-density

solid compliance fuels for utility or industrial boilers;

one project is demonstrating a new methanol production process; and the other project developed an expert

computer software system that enables a utility to

predict operating performance of coals being considered but not previously burned in the utility’s boiler.

The four projects in the industrial applications

category have a combined value of nearly $1.3 billion.

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

direct iron-making process with the production of

electricity, reduction of cement kiln emissions and

solid waste generation, and the demonstration of an

efficient industrial-scale combustor.

Performance Results

The CCT Program has extended the technical,

economic, and environmental performance envelope of

a broad portfolio of advanced coal technologies. As of

December 31, 1997, a total 21 CCT demonstration

projects have completed operation, 10 are in operation,

1 project is in construction, 5 are in design, and 2 are

being restructured. Exhibit 1 shows the number of

completed projects by application category. Exhibit 2

provides a schedule for the 39 projects as of

December 31, 1997.
Project Fact Sheets 1997 3

Advanced Flue Gas Desulfurization Demonstration

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

Award presented by Power magazine.

Exhibit 1

Completed Projects by

Application Category

Projects

Application Category Completed

Environmental Control Devices

NOx control technology 5

SO2

 control technology 5

Combined SO2

/NOx control technology 5

Advanced Electric Power Generation

Atmospheric fluidized-bed combustion 1

Pressurized fluidized-bed combustion 1

Coal Processing for Clean Fuels

Coal preparation technologies 1

Mild gasification 1

Industrial Applications

Industrial cyclone combustor 1

Cement kiln flue gas recovery scrubber 1

Technology Successes

The CCT Program is establishing marketplace

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

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

coal-fired capacity and provide the capability of

achieving not only existing regulated levels, but those

proposed by the Environmental Protection Agency

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

the NOx

 technology demonstrations to guide its efforts

in establishing NOx control regulations. The CCT

Program has also shown that several advanced technologies have led to significant improvements in the

economic and environmental performance of SO2

controls. Circulating fluidized-bed technology has

become a commercial success in the utility sector

worldwide due largely to the data generated from a

CCT project that was one of the first utility-scale

circulating fluidized-bed projects in the world. The

electric power generation technologies for the next

century are being demonstrated in the form of the

pressurized fluidized-bed combustion (PFBC)

systems and integrated gasification combined-cycle

(IGCC) systems. Further, technologies are being

used to transform low-rank and non-compliance

coals to useful, environmentally superior coal-based

fuels for use by domestic utility and industrial coal

users and are being considered for major projects

abroad. Finally, coal-based industrial processes are

benefiting environmentally and economically from

the demonstration of advanced coal technologies.

Project Fact Sheets

The remainder of this report contains fact

sheets for all 39 projects. Exhibit 3 provides an

index to the fact sheets. The information provided

in each fact sheet includes the project participant,

team members, location, process flow diagram,

significant project features, project objectives,

process description and performance attributes,

progress and accomplishments, commercial applications, major milestones, and references. For completed

projects, the results of operational testing are summarized. To prevent the release of project-specific information of a proprietary nature, process flow diagrams

contained in 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.

Project contacts are listed in Appendix A. A key

to acronyms and abbreviations is provided in

Appendix B.
4 Project Fact Sheets 1997

Exhibit 2

Project Schedules and Funding by Application Category

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

Year

B&W--LIMB Environmental Control Devices 7,

SCS--Wall-Fired 6,

EER--GR/SI 18,

SCS--Tangentially Fired 4,

Bechtel -- CZD 5,

B&W--Coal Reburning 6,

B&W--LNCB 5,

ABB ES--SNOX 15,

B&W--SNRB 6,

Pure Air on the Lake 63,

LIFAC 10,

PSC of Colorado 13,

AirPol -- GSA 2,

EER--GR-LNB 8,

SCS--CT-121 21,

SCS--SCR 9,

NYSEG -- Milliken 45,

NYSEG -- Micronized 2,

NOXSO Corporation Schedule being revised 41,

 - Preaward - Design and Construction - Operation and Reporting
Project Fact Sheets 1997 5

Exhibit 2 (continued)

Project Schedules and Funding by Application Category

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

Year

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

Ohio Power 66,

Wabash River 219,

Tampa Electric 150,

Sierra Pacific 167,

AIDEA 117,

ADL--Coal Diesel 23,

McIntosh 4A 93,

Jacksonville 74,

McIntosh 4B 109,

Clean Energy Schedule being revised 183,

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

Rosebud SynCoal 43,

ENCOAL 45,

Custom Coals Schedule being revised 37,

Air Products -- LPMEOH 92,

Coal Tech Industrial Applications 

Passamaquoddy 5,

Bethlehem Steel 31,

CPICOR 149,
6 Project Fact Sheets 1997

Exhibit 3

Project Fact Sheets: Clean Coal Technology Demonstration Program

Project Participant Page

Environmental Control Devices

SO2 Control Technologies

10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. 10

Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation 14

LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC–North America 18

Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. 22

Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Southern Company Services, Inc. 26

NOx

 Control Technologies

Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control The Babcock & Wilcox Company 32

Full-Scale Demonstration of Low-NOx Cell Burner Retrofit The Babcock & Wilcox Company 36

Evaluation of Gas Reburning and Low-NOx

 Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation 40

Micronized Coal Reburning Demonstration for NOx Control New York State Electric & Gas Corporation 44

Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. 46

Demonstration of Selective Catalytic Reduction Technology for the Control of NOx Emissions Southern Company Services, Inc. 48

from High-Sulfur-Coal-Fired Boilers

180-MWe Demonstration of Advanced Tangentially Fired Combustion Techniques Southern Company Services, Inc. 52

for the Reduction of NOx Emissions from Coal-Fired Boilers

Combined SO2

/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration Project ABB Environmental Systems 58

LIMB Demonstration Project Extension and Coolside Demonstration The Babcock & Wilcox Company 62

SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company 66

Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation 70

Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation 74

Commercial Demonstration of the NOXSO SO2

/NOx Removal Flue Gas Cleanup System NOXSO Corporation 76

Integrated Dry NOx/SO2 Emissions Control System Public Service Company of Colorado 78
Project Fact Sheets 1997 7

Exhibit 3 (continued)

Project Fact Sheets: Clean Coal Technology Demonstration Program

Project Participant Page

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project City of Lakeland, Department of Electric & Water Utilities 86

McIntosh Unit 4B Topped PCFB Demonstration Project City of Lakeland, Department of Electric & Water Utilities 88

Tidd PFBC Demonstration Project The Ohio Power Company 90

Jacksonville Electric Authority Large-Scale CFB Combustion Demonstration Project Jacksonville Electric Authority 94

Nucla CFB Demonstration Project Tri-State Generation and Transmission Association, Inc. 96

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project Clean Energy Partners Limited Partnership 100

Piñon Pine IGCC Power Project Sierra Pacific Power Company 102

Tampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company 104

Wabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering Project Joint Venture 106

Advanced Combustion/Heat Engines

Healy Clean Coal Project Alaska Industrial Development and Export Authority 108

Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. 110

Coal Processing for Clean Fuels

Coal Preparation Technologies

Development of the Coal Quality ExpertTM ABB Combustion Engineering, Inc., and CQ Inc. 114

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Custom Coals International 118

Advanced Coal Conversion Process Demonstration Rosebud SynCoal Partnership 120

Mild Gasification

ENCOAL® Mild Coal Gasification Project ENCOAL® Corporation 122

Indirect Liquefaction

Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOHTM) Process Air Products Liquid Phase Conversion Company, L.P. 124

Industrial Applications

Blast Furnace Granulated-Coal Injection System Demonstration Project Bethlehem Steel Corporation 128

Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Coal Tech Corporation 130

Clean Power from Integrated Coal/Ore Reduction (CPICORTM) CPICORTM Management Company, L.L.C. 134

Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe 136
8 Project Fact Sheets 1997 Environmental Control Devices

Environmental control devices are those technologies applied (retrofitted) to existing or new facilities

for the purpose of controlling SO2 and NOx emissions.

Although boilers may be modified and combustion

affected, the basic boiler configuration and function

remains unchanged in retrofitting these technologies.

SO2 Control Technology

Sulfur dioxide (SO2 ) is an acid gas formed during

coal combustion, which oxidizes the inorganic, pyritic

sulfur (Fe2

S), and organically bound sulfur in the coal.

Identified as a precursor to formation of acid rain, SO2

was targeted in Title IV of the Clean Air Act Amendments of 1990 (CAAA). Phase I of Title IV, effective

in 1995, affected 261 coal-fired units nationwide. The

required SO2

 reduction was moderate and largely met

by switching to low-sulfur fuels. In year 2000, Phase II

of Title IV will come into effect, impacting all fossilfuel-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. But, the CAAA provides utilities flexibility in

control strategies through SO2 allowance trading. This

permits a range of control options to be applied by a

utility, as well as allowance purchasing. Recognizing

this, the CCT Program has sought to provide a portfolio of SO2

 control technologies.

SO2 control devices embody those technologies

that condition and act upon the flue gas resulting from

combustion, not the combustion itself, for the purpose

of removing only SO2. Three basic approaches

evolved, driven primarily by different conditions that

exist within the pre-NSPS boiler population impacted

by the CAAA. There is a tremendous range in critical

factors, such as size, type, age, and space availability.

On one end of the spectrum are the smaller, older

boilers with limited space for adding equipment. For

these, sorbent injection techniques hold promise.

Sorbent is injected into the boiler or the ductwork, and

humidification is incorporated in some fashion to

properly condition the flue gas for efficient SO2

capture. Equipment size and complexity are held to a

minimum to keep capital costs and space requirements

low. Both limestone and lime sorbents are used.

Limestone costs are about one-third that of hydrated

lime; but limestone must be conditioned (calcined), and

even then it is less effective in SO2 capture (under

simple sorbent injection conditions) than hydrated

lime. Where limestone is used, it is injected in the

boiler to produce calcium oxide, which reacts with SO2

to form solid compounds of calcium sulfite and

calcium sulfate. Both limestone and lime injection

require the presence of water (humidification) and a

calcium-to-sulfur molar ratio (Ca/S) of about 2.0 for

sulfur capture efficiencies of 50–70 percent.

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

MWe boilers less than 30 years old and somewhat

space constrained. For many of these, an increase in

front-end control cost is justified by enhanced performance. The approach involves introduction of a reactor

vessel in the flue gas stream to create conditions to

enhance SO2 capture beyond that achievable with the

simpler sorbent injection systems. Lime, as opposed to

limestone, is used and sulfur capture efficiencies up to

90 percent can be achieved at a Ca/S of 1.3–2.0. This

category of control device is called a spray dryer

(because the solid by-product from the reaction is dry).

At the other end of the spectrum are the larger

(300-MWe and more) boilers with some latitude in

space availability, as well as new capacity additions.

For these, advanced flue gas desulfurization (AFGD)

wet scrubbers, with higher capital cost, but higher

sulfur capture efficiency than other approaches,

become cost effective. These systems apply larger and

somewhat more complex reactors that drive up the

capital cost. However, the sorbent is limestone and SO2

removal efficiencies greater than 90 percent are

achieved at a Ca/S of about 1.0, making operating costs

significantly lower than those of the other two approaches. Furthermore, although the initial AFGD solid

by-product is in slurry form, it is dewatered to produce

gypsum—a salable product.

Under the CCT Program, two sorbent injection systems, one spray dryer, and two AFGD processes were

successfully demonstrated. All have completed testing.

Exhibit 4 briefly summarizes the characteristics and performance of the technologies that are described in more

detail in the project fact sheets.

Environmental Control Devices
Environmental Control Devices Project Fact Sheets 1997 9

Exhibit 4

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% 14

Desulfurization Demonstration

LIFAC Sorbent Injection Desulfurization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0–2.9% 70% 18

Demonstration Project humidification vessel and sorbent recycle

10-MWe Demonstration of Gas Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7–3.5% 60–90% 10

Absorption particulate recycle (lime sorbent)

Advanced Flue Gas Desulfurization AFGD—co-current flow, integrated quench absorber tower and reaction 2.25–4.7% 94% 22

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

Demonstration of Innovative Applications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2–3% 90+% 26

of Technology for the CT-121 FGD Process Reactor®) for combined SO2

 and particulate capture (gypsum by-product)

This side view of Pure Air’s advanced flue gas desulfurization absorber module

shows air inlet ducts and sorbent injection piping.

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

Air absorber module.
10 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

10-MWe Demonstration of Gas

Suspension Absorption

Project completed.

Participant

AirPol, Inc.

Additional Team Members

FLS miljo a/s (parent company of AirPol, Inc.)—

technology owner

Tennessee Valley Authority—cofunder and site owner

Location

West Paducah, McCracken County, KY

Technology

FLS miljo a/s’ Gas Suspension Absorption (GSA) system

for flue gas desulfurization (FGD)

Plant Capacity/Production

10-MWe equivalent slipstream of flue gas from a

175-MWe wall-fired boiler

Coals

Western Kentucky bituminous—

Peabody Martwick, 3.05% sulfur

Emerald Energy, 2.61% sulfur

Andalax, 3.06% sulfur

Warrior Basin, 3.5% sulfur (used intermittently)

Project Funding

Total project cost $7,717,189 100%

DOE 2,315,259 30

Participant 5,401,930 70

Project Objective

To demonstrate the applicability of Gas Suspension Absorption as an economic option for achieving Phase II

CAAA SO2

 compliance on pulverized-coal-fired boilers

using high-sulfur coal.

Technology/Project Description

The GSA system consists of a vertical reactor in which

flue gas comes into contact with suspended solids consisting of lime, reaction products, and fly ash. About 99% of

the solids are recycled to the reactor via a cyclone while

the exit gas stream passes through an electrostatic precipitator (ESP) or pulse jet baghouse (PJBH) before being

released to the atmosphere. The lime slurry, prepared

from hydrated lime, is injected through a spray nozzle at

the bottom of the reactor. The volume of lime slurry is

regulated with a variable-speed pump controlled by the

measurement of the acid content in the inlet and outlet

gas streams. The dilution water added to the lime slurry

is controlled by on-line measurements of the flue gas exit

temperature.

A test program was structured to (1) optimize design

of the GSA reactor for reduction of SO2

 emissions from

boilers using high-sulfur coal and (2) evaluate the environmental control capability, economic potential, and

mechanical performance of GSA. A statistically designed

parametric (factorial) test plan was developed involving

six variables. Beyond evaluation of the basic GSA unit to

control SO2

, air toxic control tests were conducted, and

the effectiveness of a GSA/ESP and GSA/PJBH to control both SO2

 and particulate were tested. Factorial tests

were followed by continuous runs to verify consistency of

performance over time.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 11

Results Summary

Environmental

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

followed closely by chloride content.

• GSA/ESP achieved

– 90% sulfur capture at a Ca/S of 1.3 with 8 oF approach-to-saturation and 0.04% chloride,

– 90% sulfur capture at a Ca/S of 1.4 with 18 oF

approach-to-saturation and 0.12% chloride, and

– 99.9+% average particulate removal efficiency.

• GSA/PJBH achieved

– 96% sulfur capture at a Ca/S of 1.4 with 18 oF

approach-to-saturation and 0.12% chloride,

– 3–5% increase in SO2

 reduction relative to

GSA/ESP, and

– 99.99+% average particulate removal efficiency.

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

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

cadmium, artimony, mercury, and selenium.

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

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

Operational

• GSA/ESP lime utilization averaged 66.1% and

GSA/PJBH averaged 70.5%.

• The reactor achieved the same performance as a conventional spray dryer, but at 1

/4–1/3 the size.

• GSA generated lower particulate loading than a spray

dryer, enabling compliance with a lower ESP efficiency.

• Special steels were not required in construction, and

only a single spray nozzle is needed.

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

simple design.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

Ground breaking/construction started 5/92

Preaward

12/89 10/90 10/92

Design and Construction

DOE selected project

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

Environmental monitoring plan completed 10/2/92

Design completed 12/91

Cooperative agreement awarded 10/11/90

NEPA process completed (MTF) 9/21/90

Preoperational tests initiated 9/92

Construction completed 9/92

6/95

Project completed/final report issued 6/95

Operation completed 3/94

Economic

• Capital and levelized (15-year) costs for GSA installed

in a 300-MWe plant using 2.6% sulfur coal are compared below to costs for a wet limestone scrubber with

forced oxidation (WLFO scrubber). EPRI’s cost methodology was employed. Based on EPRI cost studies

of FGD processes, the capital cost (1990$) for a conventional spray dryer was $172/kW.

Capital Cost Levelized Cost

(1990$/kW) (mills/kWh)

GSA—3 units at $149 10.35

50% capacity

WLFO $216 13.04
12 Project Fact Sheets 1997 Environmental Control Devices

Project Summary

The GSA capability of suspending a high concentration

of solids, effectively drying the solids, and recirculating

the solids at a high rate with precise control results in SO2

control comparable to that of wet scrubbers and high lime

utilization. The high concentration of solids provides the sorbent/SO2

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

chloride usage. The rapid, precise, integral recycle

system sustains the high solids concentration. The

high lime utilization mitigates the largest operating

cost (lime) and further reduces costs by reducing the

amount of by-product generated. The GSA is distinguished from the average spray dryer by its modest

size, simple means of introducing reagent to the

reactor, direct means of recirculating unused lime,

and low reagent consumption. Also, injected slurry

coats recycled solids, not the walls, avoiding corrosion and enabling use of carbon steel in fabrication.

Environmental Performance

Exhibit 5 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 6 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

Exhibit 5

GSA Factorial Testing Results

Exhibit 5

Variables and Levels Used in

GSA Factorial Testing

Variable Level

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

Ca/S (moles Ca(OH)2

/mole inlet SO2) 1.00 and 1.30

Flyash loading (gr/ft3

, actual) 0.50 and 2.0

Coal chloride level (%) 0.04 and 0.12

Flue gas flow rate (103

 std ft3/min) 14 and 20

Recycle screw speed (rpm) 30 and 45

*

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

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

the overall SO2

 removal efficiency averaged slightly more

than 90%, very close to the set point of 91%, at an average Ca/S ratio of 1.40–1.45 moles Ca(OH)2

/mole inlet

SO2

. The system was able to adjust rapidly to the surge in

inlet SO2

 caused by switching to 3.5% sulfur Warrior

Basin coal for a week. Lime utilization averaged 66.1%.

The particulate removal efficiency averaged 99.9+% and

emission rates were maintained below 0.015 lb/106

 Btu.

The 14-day run on the GSA/PJBH system showed that the

SO2

 removal efficiency averaged more than 96% at an

average Ca/S ratio of 1.34–1.43 moles Ca(OH)2

/mole

inlet SO2

. Lime utilization averaged 70.5%. The particulate removal efficiency averaged 99.99+% and emission

rates ranged from 0.001 to 0.003 lb/106 Btu.

All air toxic tests were conducted with 2.7% sulfur,

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

temperature and a high flyash loading of 2.0 gr/ft3 (actual). The GSA/ESP arrangement indicated average removal efficiencies of greater than 99% for arsenic,

barium, chromium, lead, and vanadium; somewhat less

for manganese; and less than 99% for antimony, cadmium, mercury, and selenium. The GSA/PJBH configuration showed 99+% removal efficiencies for arsenic,

barium, chromium, lead, manganese, selenium, and vanadium; with cadmium removal much lower and mercury

removal lower than that of the GSA/ESP system. The

removal of HCl and HF was dependent upon the utilization of lime slurry and was relatively independent of

particulate control configuration. 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).

subsequent 14-day continuous run to evaluate the GSA/

PJBH configuration was performed under the same conditions as those of the 28-day run, except for adjustments in

flyash injection rate from 1.5 to 1.0 gr/ft3

 (actual).
Environmental Control Devices Project Fact Sheets 1997 13

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.

Commercial Applications

The low capital cost, moderate operating cost, and high

SO2

 capture efficiency make the GSA system particularly

attractive as a CAAA compliance option for boilers in

the 50–250-MWe range. Other major advantages include

the modest space requirements comparable to duct injection systems, high availability/reliability owing to design

simplicity, and low dust loading, minimizing particulate

upgrade costs.

GSA market entry was significantly enhanced with

the sale of a 50-MWe unit, worth $10 million, to the city

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

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

system has been sold to a Swedish iron ore sinter plant.

Sales to Taiwan and India have a combined value of

$5.5 million.

Contacts

Frank E. Hsu, Vice President, Operations, (201) 490-6400

AirPol, Inc.

3 Century Drive

Parsippany, NJ 07054-4610

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

Sharon K. Marchant, FETC, (412) 892-6008

References

• 10-MWe Demonstration of Gas Suspension Absorption

Final Project Performance and Economics Report.

Report No. DOE/PC/90542-T9. AirPol, Inc. June

1995. (Available from NTIS as DE95016681.)

• 10-MW Demonstration of the Gas Suspension Absorption Final Public Design Report. Report No. DOE/

PC/90542-T10. AirPol, Inc. June 1995. (Available

from NTIS as DE960003270.)

• SO2

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

Energy and AirPol, Inc. April 1995.

AirPol successfully demonstrated the GSA system at

TVA’s Center for Emissions Research.
14 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

Confined Zone Dispersion

Flue Gas Desulfurization

Demonstration

Project completed.

Participant

Bechtel Corporation

Additional Team Members

Pennsylvania Electric Company—cofunder and host

Pennsylvania Energy Development Authority—cofunder

New York State Electric & Gas Corporation—cofunder

Rockwell Lime Company—cofunder

Location

Seward, Indiana County, PA (Pennsylvania Electric

Company’s Seward Station, Unit No. 5)

Technology

Bechtel Corporation’s in-duct, confined zone dispersion

flue gas desulfurization (CZD/FGD) process

Plant Capacity/Production

73.5 MWe

Coal

Pennsylvania bituminous, 1.2–2.5% sulfur

Project Funding

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

DOE 5,205,800 50

Participant 5,205,800 50

Project Objective

To demonstrate SO2

 removal capabilities of in-duct

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

CZD/FGD’s operability, reliability, and cost-effectiveness

during long-term testing and its impact on downstream

operations and emissions.

Technology/Project Description

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

of reactive lime is sprayed into the flue gas stream between the boiler air heater and the electrostatic precipitator (ESP). The lime slurry is injected into the center of

the duct by spray nozzles designed to produce a cone of

fine spray. As the spray moves downstream and expands,

the gas within the cone cools and the SO2

 is quickly

absorbed in the liquid droplets. The droplets mix with

the hot flue gas, and the water evaporates rapidly. Fast

drying precludes wet particle buildup in the duct and aids

the flue gas in carrying the dry reaction products and the

unreacted lime to the ESP.

 This project included injection of different types of

sorbents (dolomitic and calcitic limes) with several atomizer designs using low- and high-sulfur coals to verify the

effects on SO2

 removal and the capability of the ESP to

control particulates. The demonstration was conducted at

Pennsylvania Electric Company’s Seward Station in

Seward, PA. One-half of the flue gas capacity of the

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

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

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

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

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 15

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
16 Project Fact Sheets 1997 Environmental Control Devices

Project Summary

The principle of the CZD/FGD is to form a

wet zone of slurry droplets in the middle of a

duct confined in an envelope of hot gas between the wet zone and the hot gas. The lime

slurry reacts with part of the SO2

 in the gas

and the reaction products dry to form solid

particles. An ESP, downstream from the

point of injection, captures the reaction products along with the fly ash entrained in the

flue gas.

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

Use of the commercially available Type S

pressure-hydrated dolomitic lime reduced

residence time requirements for CZD/FGD

and enhanced sorbent utilization. The increased humidity of CZD/FGD processed flue

gas enhanced ESP performance, eliminating the need for

upgrades to handle the increased particulate load.

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

for the CZD process in July 1991, with the first

12 months of the test program consisting primarily of

parametric testing and the last 6 months consisting of

continuous operational testing. During the continuous

operational test period, the system was operated under

fully automatic control by the host utility boiler operators.

The new atomizing nozzles were thoroughly tested both

outside and inside the duct prior to testing. The SO2

removal parametric test program, which began in October

1991, was completed in August 1992.

Specific objectives were as follows:

• Achieve projected SO2

 removal of 50%

• Realize SO2

 removal costs of less than $300/ton

• Eliminate negative effects on normal boiler operations

without increasing particulate emissions and opacity

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

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

 from the flue

gas but require different feed concentrations of lime

slurry for the same percentage of SO2

 removed. The most

efficient removals and easiest to operate system were

obtained using pressure-hydrated dolomitic lime.

Environmental Performance

Sorbent injection rate proved to be the most influential

factor on SO2

 capture. The rate of injection possible was

limited by the flue gas temperature. This impacted a

portion of the demonstration when air leakage caused flue

gas temperature to drop from 300–310 oF to 260–280 oF.

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

possible and SO2

 reductions greater than 50% were

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

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

SO2

 removal efficiency. Slurry concentration for a given

sorbent did not increase SO2

 removal efficiency beyond a

certain threshold concentration. For example, with pressure-hydrated dolomitic lime, slurry concentrations above

9% did not increase SO2

 capture efficiency.

Parametric tests indicated that SO2

 removals above

50% are possible under the following conditions: flue

gas temperature of 300–310 oF; boiler load of 145–147

MWe; residence time in the duct of 2 seconds; and lime

slurry injection rate of 52–57 gal/min.

Operational Performance

The percentage of lime utilization in the CZD/FGD significantly affected the total cost of SO2

 removal. An

analysis of the continuous operational data indicated that

the percentage of lime utilization was directly dependent

on two key factors:

• Percentage of SO2

 removed

• Lime slurry feed concentration

For operating conditions at Seward Station, data

indicated that for 40–50% SO2

 removal, a 6–8% lime or

dolomitic lime slurry concentration, and a stoichiometric

ratio of 2–2.5 resulted in a 40–50% lime utilization rate.

That is, 2–2.5 moles of CaO or CaO•MgO were required

for every mole of SO2

 removed; or assuming 92% lime

purity, 1.9–2.4 tons of lime were required for every ton of

SO2

 removed. In summary, the demonstration showed the

following results:

• A 50% SO2

 removal efficiency with CZD/FGD was

possible.

• Drying and SO2

 absorption required a residence time

of 2 seconds, which required a long and straight horizontal gas duct of about 100 feet.

• The fully automated system integrated with the power

plant operation demonstrated that the CZD/FGD process responded well to automated control operation.

However, modifications to the CZD/FGD were required to assure consistent SO2

 removal and avoid

deposition of solids within the gas duct during upsets.

• Availability of the system was very good.

Bechtel’s demonstration showed that 50% SO2 removal efficiency was

possible using CZD/FGD technology. The extended duct into which lime

slurry was injected is in the foreground.
Environmental Control Devices Project Fact Sheets 1997 17

• At Seward Station, stack opacity was not detrimentally

affected by the CZD/FGD system.

Economic Performance

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

SO2

 removed when operating a 500-MWe unit burning

4% sulfur coal. Based on a 500-MWe plant retrofitted

with CZD/FGD for 50% SO2

 removal, the total capital

cost is estimated to be less than $30/kW.

Commercial Applications

After the conclusion of the DOE-funded CZD/FGD demonstration project at Seward Station, the CZD/FGD system was modified to improve SO2 removal during continuous operation while following daily load cycles.

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

additional year. Results showed that CZD/FGD operation

at SO2

 removal rates lower than 50% could be sustained

over long periods without significant process problems.

CZD/FGD can be used for retrofit of existing plants

and installation in new utility boiler flue gas facilities to

remove SO2

 from a wide variety of sulfur-containing

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

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

installed capacity, or approximately one-fourth the cost of

building a conventional wet scrubber. In addition to low

capital cost, other advantages include small space requirements, ease of retrofit, low energy requirements, fully

automated operation, and production of only nontoxic,

disposable waste. The CZD/FGD technology is particularly well suited for retrofitting existing boilers, independent of type, age, or size. The CZD/FGD installation

does not require major power station alterations and can

be easily and economically integrated into existing power

plants.

Contacts

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

Bechtel Corporation

P.O. Box 193965

San Francisco, CA 94119-3965

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

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

This photo shows the CZD/FGD lime slurry injector control system.

References

• Confined Zone Dispersion Project: Final Technical

Report. Bechtel Corporation. June 1994.

• Confined Zone Dispersion Project: Public Design

Report. Bechtel Corporation. October 1993.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Confined Zone Dispersion Flue

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

of Energy. September 1990. (Available from NTIS as

DE91002564.)
18 Project Fact Sheets 1997 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

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 19

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Design and Construction Operation

Original design completed 7/91

Cooperative agreement awarded 11/20/90

NEPA process completed (MTF) 10/2/90

Ground breaking/construction started 5/29/91

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

Preoperational tests initiated 7/92

Environmental monitoring plan

completed 6/12/92

Construction completed 6/92

Operation completed 6/94

Operation initiated 9/92

12/89 11/90 9/92

Results Summary

Environmental

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

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

minus 325 mesh.

• SO2

 removal efficiency with limestone fineness of

80% minus 200 mesh was 15% lower at a Ca/S of 2.0

and 7–12 oF approach to saturation.

• The four parameters having the greatest influence on

sulfur removal efficiency were limestone quality, Ca/S

molar ratio, approach-to-saturation temperature, and

ESP ash recycle rate.

• ESP ash recycle rate was limited in the demonstration

system configuration. Increasing the recycle rate and

sustaining a 5 oF approach-to-saturation temperature

was projected to increase SO2

 removal efficiency to

85% at a Ca/S of 2.0 (fine limestone).

• ESP efficiency and operating levels were essentially

unaffected by LIFAC operation during steady-state

operation.

• Fly and bottom ash were dry and readily disposed of

at a local landfill. The quantity of additional solid

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

1.0 ton of SO2

.

Operational

• When operating with fine limestone (80% minus

325 mesh), the soot-blowing cycle had to be reduced

from 6.0 to 4.5 hours.

• Automated programmable logic and simple design

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

shutdown, or normal duty cycles.

• The amount of bottom ash increased slightly, but there

was no negative impact on the ash-handling system.

Economic

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

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

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

(65 MWe).

• Operating cost—$65/ton of SO2

 removal, assuming

75% SO2

 capture, Ca/S of 2.0, limestone composed of

95% CaCO3

, and $15/ton.

4/98

Project completed/final

report issued 4/98*
20 Project Fact Sheets 1997 Environmental Control Devices

The LIFAC system successfully demonstrated at

Whitewater Valley Station Unit No. 2 is being retained by

Richmond Power & Light for commercial use with highsulfur coal. There are 10 full-scale LIFAC units in Canada,

China, Finland, Russia, and the United States.

Project Summary

The LIFAC technology was designed to enhance the

effectiveness of dry sorbent injection systems for SO2

control and to maintain the desirable aspects of low

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

cost of lime) and a sorbent recycle system was incorporated to reduce operating costs.

The process evaluation test plan was composed of

five distinct phases each having its own objectives.

These tests were as follows:

• Baseline tests characterized the operation of the host

boiler and associated subsystems prior to LIFAC

operations.

• Parametric tests were designed to evaluate the many

possible combinations of LIFAC process parameters

and their effect on SO2

 removal.

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

the LIFAC process over short, continuous operating

periods.

• Long-term tests were performed to demonstrate

LIFAC’s performance under commercial operating

conditions.

• Post-LIFAC tests involved repeating the baseline test

to identify any changes caused by the LIFAC system.

The coals used during the demonstration varied in

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

testing was conducted with the higher sulfur coals

(2.0–2.8% sulfur).

Environmental Performance

During the parametric testing phase, the numerous

LIFAC process values and their effects on sulfur removal

efficiency were evaluated. The four major parameters

having the greatest influence on sulfur removal efficiency

were limestone quality, Ca/S molar ratio, reactor bottom

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

 capture was about 15% better when

injecting fine limestone (80% minus 325 mesh) than it

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

While injecting the fine limestone, the soot blowing

frequency had to be increased from 6- to 4.5-hour cycle

periods. The coarse-quality limestone did not affect soot

blowing but was found to be more abrasive on the feed

and transport hoses.

Parametric tests indicated that a 70% SO2

 reduction

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

containing unspent sorbent and fly ash was recycled

from the ESP hoppers back into the reactor inlet duct

work. Ash recycling is essential for efficient SO2

 capture. The large quantity of ash removed from the LIFAC

reactor bottom and the small size of the ESP hoppers

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

amount of material recycled from the ESP was approximately 70% less than had been anticipated. However,

this low recycling rate was found to affect SO2

 capture.

During a brief test, it was found that increasing the recycle rate by 50% resulted in a 5% increase in SO2

 removal efficiency. It was estimated that if the reactor

bottom ash is recycled along with ESP ash, while sustaining a reactor temperature of 5 oF above saturation

temperature, an SO2

 reduction of 85% could be maintained.

Operational Performance

Optimization testing began in March 1994 and was

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

was operated at an average load of 60 MWe during longterm 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
Environmental Control Devices Project Fact Sheets 1997 21

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.

Economic Performance

The economic evaluation indicated that the capital cost

of a LIFAC installation is lower than for either a spray

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

reactors needed:

• $99/kW for one LIFAC reactor at Whitewater Valley

Station (65 MWe)

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

(150 MWe)

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

(300 MWe)

Crushed limestone accounts for about one half of

LIFAC’s operating costs. LIFAC requires 4.3 tons of

limestone to remove 1 ton of SO2

, assuming 75% SO2

capture, a Ca/S ratio of 2.0, and limestone containing

95% CaCO3

. Assuming limestone costs of $15/ton,

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

 removed.

Commercial Applications

There are 10 full-scale LIFAC units in operation in

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

The LIFAC system at Richmond Power & Light is the

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

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

Richmond Power & Light at Whitewater Valley Station,

Unit No. 2. The other LIFAC installations on power

plants are using bituminous and lignite coals having

lower sulfur contents (0.6–1.5%).

Contacts

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

ICF Kaiser Engineers, Inc.

Gateway View Plaza

1600 West Carson Street

Pittsburgh, PA 15219-1031

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

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

References

• LIFAC Sorbent Injection Desulfurization Demonstration Project. Final Report, Vol. II: Project Performance and Economics. LIFAC–North America.

June 1996. (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.)

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.
22 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

Advanced Flue Gas

Desulfurization Demonstration

Project

Project completed.

Participant

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

Air, which is a general partnership between Air Products

and Chemicals, Inc., and Mitsubishi Heavy Industries

America, Inc.)

Additional Team Members

Northern Indiana Public Service Company—cofunder and

host

Mitsubishi Heavy Industries, Ltd.—process designer

United Engineers and Constructors (Stearns-Roger

Division)—facility designer

Air Products and Chemicals, Inc.—constructor and

operator

Location

Chesterton, Porter County, IN (Northern Indiana Public

Service Company’s Bailly Generating Station, Units 7

and 8)

Technology

Pure Air’s advanced flue gas desulfurization (AFGD)

process

Plant Capacity/Production

528 MWe

Coal

Bituminous, 2.0–4.5% sulfur

Project Funding

Total project cost $151,707,898 100%

DOE 63,913,200 42

Participant 87,794,698 58

Project Objective

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

create no new waste streams.

Technology/Project Description

Pure Air built a single SO2

 absorber for a 528-MWe

power plant. Although the largest capacity absorber

module of its time in the United States, space requirements were modest because no spare or backup absorber

modules were required. The absorber performed three

functions in a single vessel: prequenching, absorbering,

and oxidation of sludge to gypsum. Additionally, the

absorber was of a co-current design, in which the flue gas

and scrubbing slurry move in the same direction and at a

relatively high velocity compared to that in conventional

scrubbers. These features all combined to yield a 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 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 Project Fact Sheets 1997 23

Results Summary

Environmental

• AFGD design enabled a single 600-MWe absorber

module without spares to remove 95% or more SO2

 at

availabilities of 99.5% when operating with highsulfur coals.

• Wallboard-grade gypsum was produced in lieu of solid

waste, and all gypsum produced was sold commercially.

• The wastewater evaporation system (WES) mitigated

expected increases in wastewater generation associated

with gypsum production and showed the potential for

achieving zero wastewater discharge (only a partialcapacity WES was installed).

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

product with the handling characteristics of natural

rock gypsum.

• Air toxics testing established that all acid gases were

effectively captured and neutralized by the AFGD.

Trace elements largely became constituents of the

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

Some boron, selenium, and mercury passed to the

stack gas in a vapor state.

Operational

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

proved to be highly efficient, reliable (to the exclusion

of requiring a spare module), and compact. The compactness, combined with no need for a spare module,

significantly reduced space requirements.

• The own-and-operate contractual arrangement

whereby Pure Air took on the turnkey, financing,

operating and maintenance risks through performance

guarantees was successful.

Economic

• Capital costs and space requirements for AFGD were

about half those of contemporary systems.

Project Summary

The project proved that single absorber modules of advanced design could process large volumes of flue gas

and provide the required availability and reliability without the usual spares. The major performance objectives

were met.

Over the 3-year demonstration, the AFGD unit accumulated 26,280 hours of operation with an availability of

99.5%. Approximately 237,000 tons of SO2

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

over 210,000 tons of salable gypsum were produced. The

AFGD continues commercial service, which includes sale

of all by-product gypsum to U.S. Gypsum’s East Chicago,

IN, wallboard production plant.

Environmental Performance

Testing over the 3-year period clearly established that

AFGD operating within its design parameters (without

additives) could consistently achieve 95% SO2

 reduction

or more with 2.0–4.5% sulfur coals. The design range

for the calcium-to-sulfur stoichiometric ratio was

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Design and Construction Operation

9/88

Project completed/final report issued 6/96

DOE selected project

(CCT-II) 9/28/88

Cooperative agreement awarded 12/20/89

Preoperational tests initiated 3/92

Operation initiated 6/92

Design completed 9/92

Construction completed 9/92

Operation completed 6/95

12/89 6/92

NEPA process completed (EA) 4/16/90

Ground breaking/construction started 4/20/90

Environmental monitoring plan completed 1/31/91

6/96
24 Project Fact Sheets 1997 Environmental Control Devices

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

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

in the gypsum). Another key control parameter was the

ratio (L/G) of the amount of reagent slurry injected into

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

design L/G range was 50–128 gal/103

 ft3. The lower end

was determined by solids settling rates in the slurry and

the requirement for full wetting of the grid packing. The

high end was determined by where performance leveled

out.

Five coals with differing sulfur contents were selected for parametric testing to examine SO2

 removal

efficiency as a function of load, sulfur content, stoichiometric ratio, and L/G. Loads tested were 33%, 67%, and

100%. High removal efficiencies, well above 95%, at

loads of 33% and 67% were possible with low to moderate stoichiometric ratio and L/G settings, even for 4.5%

sulfur coal. Exhibit 7 summarizes the results of parametric testing at full load.

In the AFGD process, chlorides that would have

been released to the air are captured and potentially become a wastewater problem. This was mitigated by the

addition of the WES which takes a portion of the wastewater stream with high chloride and sulfate levels and

injects it into the ductwork upstream of the ESP. The hot

flue gas evaporated the water and the dissolved solids

were captured in the ESP. Problems were experienced

early on, with the WES nozzles failing to provide adequate atomization and plugging as well. This was resolved by replacing the original single-fluid nozzles with

dual fluid systems employing air as the second fluid.

Commercial-grade gypsum quality (95.6–99.7%) was

maintained throughout testing, even at the lower sulfur

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

importance of producing a commercial-grade gypsum is

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

dependent upon whether users are in range of economic

transport and whether they can handle the gypsum byproduct. For these reasons, PowerChip® technology was

demonstrated as part of the project. This technology uses

a compression mill to convert the highly cohesive AFGD

gypsum cake into a flaked product with handling characteristics equivalent to natural rock gypsum. The process

avoids use of binders, pre-drying or pre-calcining normally associated with briquetting and is 30–55% cheaper

at $2.50–$4.10/ton.

Air toxics testing established that all acid gases are

effectively captured and neutralized by the AFGD. Trace

elements largely become constituents of the solids

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

boron, selenium, and mercury pass to the stack gas in a

vapor state.

Operational Performance

Availability over the 3-year operating period averaged

99.5% while maintaining an average SO2

 removal efficiency of 94%. This was

attributable to the simple,

effective design and an effective operating/maintenance

philosophy. Modifications

were also made to the AFGD

system. An example was the

implementation of new alloy

technology, C-276 alloy over

carbon steel clad material, to

replace alloy wallpaper construction within the absorber

tower wet/dry interface. Also,

use of co-current rather than

conventional counter-current

flow resulted in lower pressure drops across the absorber

and afforded the flexibility to

increase gas flow without an

abrupt drop in removal efficiency. AFGD SO2

 capture efficiency with limestone was

comparable to that in wet scrubbers using lime, which is

far more expensive. Twenty-four-hour power consumption

was 5,275 kW, or 61% of expected consumption, and

water consumption was 1,560 gal/min, or 52% of expected

consumption.

Economic Performance

Exhibit 8 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 9 depicts the relative

costs of a hypothetical 500-MWe generating unit in the

Exhibit 7

 SO2 Removal Performance

(100% Boiler Load)
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 25

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

with Florida Power & Light Company to process 1,600

MWe of flue gas with two 800-MWe AFGD modules and

incorporate WES and PowerChip®. The Manatee project

has a value of $200 million.

The project received Power magazine’s 1993

Powerplant Award and the National Society of Professional Engineer’s 1992 Outstanding Engineering

Achievement Award.

Contacts

Don Vymazal, Manager, Contract Administration

(601) 481-3687

Pure Air on the Lake, L.P.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

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

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

References

• Advanced Flue Gas Desulfurization (AFGD) Demonstration Project. Final Technical Report, 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.

Midwest burning

4.3% sulfur coal with

a base case conventional FGD system

and four incremental

cases. The horizontal lines in

Exhibit 9 show the

range of costs for a

fuel-switching option. The lower bar is

the cost of fuel delivered to the hypothetical Midwest unit and

the upper bar allows

for some plant modifications to accommodate the compliance fuel.

Commercial Applications

AFGD is positioned well to compete in

the pollution control arena of year 2000

and beyond. AFGD has markedly reduced cost and demonstrated the ability

to compete with fuel switching under

certain circumstances even with a firstgeneration 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. High-SO2

-capture

efficiency places an AFGD user in the

possible position of trading allowances

or applying credits to other units within

the utility. WES and PowerChip® mitigate or eliminate otherwise serious

environmental concerns. AFGD effectively deals with hazardous air pollutants.

Exhibit 8

Estimated Costs for an AFGD System

Cases: 1 2 3 456789

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

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

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

Levelized cost ($/ton SO2

)

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

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

Levelized cost (mills/kWh)

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

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

Exhibit 9

Flue Gas Desulfurization Economics

0

50

100

150

200

250

300

350

400

0

0.2

0.4

0.6

0.8

1

1.2

$/Ton SO2 $/106

 Btu

A B C D E

Plant Modifications

Delivered Fuel

500-MWe plant, 30-yr levelized costs, allowance value of $300/ton

Incremental cases:

A—Conventional FGD (EPRI model)

B—AFGD, own-and-operate arrangement

C—Adds gypsum sales

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

 removal

E—Increases SO2

 removal to 95%
26 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

SO2

 Control Technologies

Demonstration of Innovative

Applications of Technology for

the CT-121 FGD Process

Project completed.

Participant

Southern Company Services, Inc.

Additional Team Members

Georgia Power Company—host

Electric Power Research Institute—cofunder

Radian Corporation—environmental and analytical

consultant

Ershigs, Inc.—fiberglass fabricator

Composite Construction and Equipment—fiberglass

sustainment consultant

Acentech—flow modeling consultant

Ardaman—gypsum stacking consultant

University of Georgia Research Foundation—

by-product utilization studies consultant

Location

Newnan, Coweta County, GA (Georgia Power

Company’s Plant Yates, Unit No. 1)

Technology

Chiyoda Corporation’s Chiyoda Thoroughbred-121

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

process

Plant Capacity/Production

100 MWe

Coals

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

Compliance, 1.2% sulfur

Project Funding

Total project cost $43,074,996 100%

DOE 21,085,211 49

Participant 21,989,785 51

Project Objective

To demonstrate 90% SO2

 control at high reliability with

and without simultaneous particulate control; to evaluate

use of fiberglass-reinforced-plastic (FRP) vessels to

eliminate flue gas reheat and spare absorber modules; and

to evaluate use of gypsum to reduce waste management

costs.

Technology/Project Description

The project demonstrated the CT-121 FGD process,

which uses a unique absorber design known as the Jet

Bubbling Reactor® (JBR). The process combines limestone FGD reaction, forced oxidation, and gypsum crystallization in one process vessel. The process is mechanically and chemically simpler than conventional FGD

processes and can be expected to exhibit lower cost

characteristics.

The flue gas enters underneath the scrubbing solution in the Jet Bubbling Reactor®. The SO2

 in the flue

gas is absorbed and forms calcium sulfite (CaSO3

). Air is

bubbled into the bottom of the solution to oxidize the

calcium sulfite to form gypsum. The slurry is dewatered

in a gypsum stack, which involves filling a dyked area

with gypsum slurry. Gypsum solids settle in the dyked

area by gravity, and clear water flows to a retention pond.

The clear water from the pond is returned to the process.

Jet Bubbling Reactor is a registered trademark of the Chiyoda

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

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 27

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

4/90

Preaward Design and Construction Operation

9/88 10/92

DOE selected project

(CCT-II) 9/28/88

Cooperative agreement awarded 4/2/90

NEPA process

completed (EA) 8/10/90

Ground breaking/construction

started 8/23/90

Environmental monitoring

plan completed 12/18/90

Preoperational tests initiated 5/92

Design completed 9/92

Operation initiated 10/92

Construction completed 10/92

Results Summary

Environmental

• Over 90% SO2 removal efficiency was achieved at SO2

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

• JBR achieved particulate removal efficiencies of

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

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

• Capture efficiency was a function of particle size:

– >10 microns—99% capture

– 1–10 microns—90% capture

– 0.5–1 micron—negligible capture

– <0.5 micron—90% capture

• Hazardous air pollutant (HAP) testing showed greater

than 95% capture of hydrogen chloride (HCl) and

fluoride (HF) gases, 80–98% capture of most trace

metals, less than 50% capture of mercury and cadmium, and less than 70% capture of selenium.

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

Operational

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

gas prescrubber and reheat.

• FRP construction combined with simplicity of design

resulted in 97% availability at low ash loadings and

95% at high ash loadings, precluding the need for a

spare reactor module.

• Simultaneous SO2

 and particulate control were

achieved at flyash loadings reflective of an ESP with

marginal performance.

Economic

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

spare module requirement should result in capital

requirements far below those of conventional FGD

systems.

2/98

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 10 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 2/98*
28 Project Fact Sheets 1997 Environmental Control Devices

five different inlet concentrations with coals averaging

2.4% and ranging 1.2– 4.3% sulfur (as burned).

Operating Performance

Use of FRP construction proved very successful. Because

their large size precluded shipment, the JBR and limestone slurry storage tanks were constructed on site. Except for some erosion experienced at the JBR inlet transition duct, the FRP-fabricated equipment proved to be

durable both structurally and chemically. Because of the

high corrosion resistance, the need for a flue gas prescrubber to remove chlorides was eliminated. Similarly,

the FRP-constructed chimney proved resistant to the

corrosive condensates in wet flue gas, precluding the need

for flue gas reheat.

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

elevated ash-loading conditions due largely to sparger

tube plugging problems precipitated by flyash agglomeration on the sparger tube walls during high ash loading

when the ESP was deenergized. The high reliability

demonstrated verified that a spare JBR is not required in

a commercial design offering.

Environmental Performance

Exhibit 11 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 12.

Analysis indicated that a large percentage of the

outlet particulate matter is sulfate, likely a result of acid

mist and gypsum carryover. This reduces the estimate of

ash mass loading at the outlet to approximately 70% of

the measured outlet particulates.

Low-Ash Elevated-Ash Cumulative

Phase Phase for Project

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

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

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

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

Reliabilitya 0.98 0.95 0.96

Availabilityb 0.97 0.95 0.97

Utilizationc 0.73 0.72 0.75

a

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

b

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

c

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

Exhibit 10

Operation of CT-121 Scrubber

Exhibit 11

SO2 Removal Efficiency

Exhibit 12

Particulate Capture Performance

(ESP Marginally Operating)

JBR Pressure Boiler Inlet Mass Outlet Mass Removal

Change (inches of Load Loading Loading* Efficiency

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

18 100 1.288 0.02 97.7

10 100 1.392 0.010 99.3

18 50 0.325 0.005 98.5

10 50 0.303 0.006 98.0

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

permit limit is 0.24 lb/106

 Btu as an existing unit.
Environmental Control Devices Project Fact Sheets 1997 29

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 13.

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

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. A 350-MWE unit has been sold to a Canadian tar sands refinery; the sale is worth $100 million. A

total of 1,200 MWe of FGD capacity has been sold to the

Czech Republic and Korea.

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

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 13

CT-121 Air Toxics Removal

(JBR Components Only)

0

20

40

60

80

100

Chloride Fluoride Arsenic Cadmium Mercury Selenium Vanadium

Removal Efficiency (%)

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
30 Project Fact Sheets 1997 Environmental Control Devices

NOx Control Technology

Nitrogen oxides (NOx) are formed from oxidation

of nitrogen contained within the coal (fuel-bound

nitrogen) and oxidation of the nitrogen in the air at

high temperatures of combustion (thermal NOx). Rapid

formation of NOx

 at the flame front can occur; but

usually, this reaction of hydrocarbon fragments with

atmospheric nitrogen represents a small fraction of

total NOx emissions. To control fuel-NOx formation, it

is important to limit oxygen at the early stages of

combustion. To control thermal NOx

,it is important to

limit peak temperatures.

NOx

 was identified both as a precursor to acid

rain, targeted under Title IV of the CAAA, and as a

contributor to ozone formation, targeted under Title I.

Phase I of Title IV, effective in 1995, required some

169 wall- and tangentially fired coal units to reduce

emissions to 0.50 and 0.45 pound per million Btu,

respectively. In 2000, Phase II of Title IV will come

into effect, impacting all fossil-fueled units, but most of

all, the balance of the 900 pre-NSPS coal-fired units

(see Exhibit 14). The proposed new NSPS for NOx

emissions reduces the limit for new or modified utility

units to 1.35 pounds per megawatt-hour, regardless of

fuel type, or as an alternate, 0.15 pounds per million

Btu. In 1998, the largest sources of NOx in 13 eastern

states will be required to monitor and

report their NOx emissions during

ozone season, and additional rules

pertaining to ozone transport are

expected. Further, final revisions to

NAAQS for ozone drop the limit to

80 parts per billion over 8 hours. In

anticipation of these stricter NOx

limits, the CCT Program has sought to

provide a number of NOx control

options to cover the range of boiler

types and emission reduction requirements.

Control of NOx

 emissions can be

accomplished by either modifying the

combustion process or acting upon

the products of combustion (or

combinations thereof). Combustion

modification technologies include

low-NOx burners (LNBs), advanced

overfire air (AOFA), and reburning

Exhibit 14

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.

processes using either gas or coal. Processes used to

act upon flue gas include selective catalytic reduction

(SCR) and selective noncatalytic reduction (SNCR).

LNBs regulate the initial fuel-air mixture, velocities, and turbulence to create a fuel-rich flame core and

control the rate at which additional air required to

complete combustion is mixed. This staging of

combustion avoids a highly oxidized environment and

hot spots conducive to fuel-NOx and thermal-NOx

formation. LNBs alone typically can achieve 40–50

percent NOx

 reduction. But no LNBs have been

developed for cyclone-fired boilers.

AOFA involves injection of air above the primary

combustion zone to allow the primary combustion to

occur without the amount of oxygen needed for

complete combustion. This oxygen deficiency miti-
Environmental Control Devices Project Fact Sheets 1997 31

Exhibit 15

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% 32

Boiler NOx Control

Evaluation of Gas Reburning and Low-NOx

 Burners LNB/gas reburning/AOFA—13–18% gas heat input 172 MWe/wall 37–65% 40

on a Wall-Fired Boiler

Micronized Coal Reburning Demonstration Coal reburning—30% heat input 148 MWe/tangential 50–60% (goal) 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% 36

Retrofit

Demonstration of Advanced Combustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500 MWe/wall 50% (goal) 46

for a Wall-Fired Boiler and artificial intelligence controls

180-MWe Demonstration of Advanced Tangentially LNB/AOFA—advanced LNB with close-coupled 180 MWe/tangential 37–45% 52

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

Emissions from Coal-Fired Boilers

Demonstration of Selective Catalytic Reduction SCR—eight catalysts with different shapes and 8.7 MWe/various 80% 48

Technology for the Control of NOx

 Emissions chemical compositions

from High-Sulfur-Coal-Fired Boilers

gates 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 10–25 percent NOx

 emission reductions.

LNB/AOFA systems generally can achieve NOx

emission reductions of 60–67 percent.

In reburning, a percentage of the fuel input to the

boiler is diverted to injection ports above the primary

combustion zone. Either gas or coal is typically used as

the reburning fuel to provide 10–30 percent of the heat

input to the boiler. The reburning fuel is injected to

create a fuel-rich zone deficient in oxygen (a reducing

rather than oxidizing zone). NOx entering this zone is

stripped of oxygen, forming elemental nitrogen.

Combustion is completed in a burnout zone where air

is injected by an AOFA system. Reburning has

application to all boiler types, including cyclone

boilers, and can achieve NOx

 emission reductions of

50–67 percent.

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

use ammonia or urea in a reducing reaction with NOx

to form elemental nitrogen and water. SNCR can only

be used at high temperatures (1,600–2,200 oF) where a

catalyst is not needed. SCR is typically applied at

temperatures between 600–800 oF. Generally, SNCR

and SCR systems alone can achieve NOx emission

reductions of 30–50 percent and 80–90+ percent,

respectively.

Under the CCT Program, seven NOx control

technologies were addressed, encompassing LNBs,

AOFA, reburning, SNCR, SCR, and combinations

thereof. Five of the projects have been completed, one

is nearing completion, and one is in construction.

Exhibit 15 briefly summarizes the characteristics and

performance of the technologies that are described in

more detail in the project fact sheets.
32 Project Fact Sheets 1997 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.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 33

Results Summary

Environmental

• Coal Reburn achieved greater than 50% NOx

 reduction

at full load with Lamar bituminous and PRB subbituminous coals.

• Reburn-zone stoichiometry had the greatest effect on

NOx

 control.

• Gas recirculation was vital to maintaining reburn-zone

stoichometry while providing necessary burner cooling, flame penetration, and mixing.

• Opacity levels and electrostatic precipitator (ESP)

performance were not affected by Coal Reburn with

either coal tested.

• Optimal Coal Reburn heat input was 29–30% at full

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

Operational

• No major boiler performance problems were experienced with Coal Reburn operations.

• Boiler turndown capability was 66%, exceeding the

50% goal.

• ESP efficiency improved slightly during Lamar coal

testing and did not change with PRB coal.

• Coal fineness levels above the nominal 90% through

200 mesh were maintained, reducing unburned carbon

losses (UBCL).

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

loads of 110-, 82-, and 60-MWe, respectively, when

using Lamar coal. With PRB coal, the efficiency loss

ranged from zero at full load to 0.3% at 60 MWe.

• Superior flame stability was realized with PRB coal,

contributing to better NOx

 control than with Lamar

coal.

• Expanded volumetric fuel delivery with reburn burners

enabled switching to PRB low-rank coal without

boiler derating.

Economic

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

$66/kW and $43/kW, respectively. Levelized 10- and

30-year busbar power costs for a 110-MWe plant were

2.4 and 2.3 mills/kWh, respectively. Levelized 10-

and 30-year busbar power costs for a 605-MWe plant

were 1.6 and 1.5 mills/kWh, respectively.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Design and Construction

9/88

Preaward

DOE selected project

(CCT-II) 9/28/88

Cooperative agreement

awarded 4/2/90

4/90 12/91

Operation

3/94

Project completed/final report issued 3/94

Operation

completed 12/92 Operation

initiated 12/91

Construction completed 11/91

Preoperational tests initiated 11/91

Environmental monitoring plan completed 11/18/91

NEPA process completed (EA) 2/12/91

Design completed 6/91

Ground breaking/construction started 11/90
34 Project Fact Sheets 1997 Environmental Control Devices

During Coal Reburn operation with Lamar coal, the

operators continually monitored boiler internals for increased ash deposition and the on-line performance monitoring system for heat transfer changes. At no time

throughout the system optimization or long-term operation period were any slagging or fouling problems observed. In fact, during scheduled outages, internal boiler

inspections revealed that boiler cleanliness had actually improved. Extensive

ultrasonic thickness measurements

were taken of the furnace wall tubes.

No observable decrease in wall tube

thickness was measured.

Another significant finding was

that Coal Reburn minimizes and possibly eliminated a 0–25% derating normally associated with switching to

subbituminous coal in a cyclone unit.

This derating was a result of using a

lower Btu fuel in a cyclone with a

limited coal feed capacity. The reburn

system transferred about 30% of the

coal feed out of the cyclone to the

Project Summary

Although cyclone boilers represent only 15% of the preNSPS coal-fired generating capacity, they contribute 21%

of the NOx

 formed by pre-NSPS coal-fired units. This is

due to the cyclone combustor’s inherent turbulent, hightemperature combustion process. Consequently, cyclone

boilers are targeted for NOx

 reduction under the CAAA

and state implementation plans. However, at the time of

this demonstration, there was no cost-effective combustor

modification available for NOx

 control.

Babcock & Wilcox Coal Reburn offers an economic

and operationally sound response to the environmental

impetus. This technology avoids cyclone combustor

modification and associated performance complications

and provides an alternative to other cyclone boiler NOx

-

control options having relatively higher capital and/or

operating costs.

The majority of the testing was performed firing

Illinois Basin bituminous coal (Lamar), as it is typical of

the coal used by many utilities operating cyclones. Subbituminous PRB coal tests were performed to evaluate the

effect of coal switching on reburn operation. Wisconsin

Power and Light’s strategy to meet Wisconsin’s sulfur

emission limitations as of January 1, 1993, was to fire

low-sulfur coal.

Environmental Performance

Three sequences of testing of Coal Reburn used Lamar

coal. Parametric optimization testing was used to set up

the automatic controls. Performance testing was run with

the unit in full automatic control at set load points. Longterm testing was performed with reburn in operation

while the unit followed system load demand requirements. PRB coal was tested by parametric optimization

and performance modes. Exhibit 16 shows changes in

NOx

 emissions and boiler efficiency using the reburn

system for various load conditions and coal types.

Coal Reburn tests on both the Lamar and PRB coals

indicated that variation of reburn-zone stoichiometry was

Boiler Load

110 MWe 82 MWe 60 MWe

Lamar coal

NOx

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

Boiler efficiency losses due to 0.1 0.25 1.5

unburned carbon (%)

Powder River Basin coal

NOx (lb/106 Btu/% reduction) 0.34/55 0.31/52 0.30/53

Boiler efficiency losses due 0.0 0.2 0.3

to unburned carbon (%)

Exhibit 16

Coal Reburn Test Results

the most critical factor in changing NOx emissions levels.

The reburn-zone stoichiometry can be varied by alternating the air flow quantities (oxygen availability) to the

reburn burners, the percent reburn heat input, the gas

recirculation flow rate, or the cyclone stoichiometry.

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

generally well within expected levels, and emissions with

Coal Reburn were comparable to baseline operation. No

major effect of reburn on trace-metals partitioning was

discernible. None of the 16 targeted polynuclear aromatic

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.

Wisconsin Power and Light Company’s Nelson Dewey

Station hosted the successful demonstration of Coal Reburn.
Environmental Control Devices Project Fact Sheets 1997 35

reburn burners, bringing the cyclone feed rate down to a

manageable level, while maintaining full-load heat input

to the unit.

Economic Performance

An economic analysis of total capital and levelized revenue requirements was conducted using the “Electric

Power Research Institute Economic Premises” for retrofit

of 110- and 605-MWe plants. In addition, annualized

costs per ton of NOx

 removed were developed for 110-

and 605-MWe plants over both 10 and 30 years. The

results of these analyses are shown in Exhibit 17. These

values assumed typical retrofit conditions and did not

take into account any fuel savings from use of low-rank

coal. The pulverizers and associated coal handling were

taken into account. Site-specific parameters that can

significantly impact these retrofit costs included the state

of the existing control system, availability of flue gas

recirculation, space for coal pulverizers, space for reburn

burners and overfire air ports within the boiler, scope of

coal-handling modification, sootblowing capacity, ESP

capacity, steam temperature control capacity, and boiler

circulation considerations.

Commercial Applications

Coal Reburn is a retrofit technology applicable to a wide

range of utility and industrial cyclone boilers. The current U.S. Coal Reburn market is estimated to be approximately 26,000 MWe and to consist of about 120 units

ranging from 100 to 1,750 MWe with most in the

100–300-MWe range.

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

Contacts

Tony Yagiela, (330) 829-7403

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

John C. McDowell, FETC, (412) 892-6237

References

• Demonstration of Coal Reburning for Cyclone Boiler

NOx

 Control: Final Project Report. Report No. DOE/

PC/89659-T16. The Babcock & Wilcox Company.

February 1994. (Available from NTIS as

DE94013052, Appendix 1 as DE94013053,

Appendix 2 as DE94013054.)

• Public Design Report: Coal Reburning for Cyclone

Boiler NOx

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

DE92012554.)

The coal pulverizer is part of Babcock & Wilcox Coal

Reburn. This system has been retained by Wisconsin Power

and Light for NOx

 emission control at the Nelson Dewey

Station.

Exhibit 17

Coal Reburn Economics

Plant Size

Costs 110 MWe 605 MWe

Total capital cost ($/kW) 66 43

Levelized busbar power

cost (mills/kWh)

10-year life 2.4 1.6

30-year life 2.3 1.5

Annualized cost

 ($/ton of NOx

 removed)

10-year life 1,075 408

30-year life 692 263

• Comprehensive Report to Congress on the Clean Coal

Program: Demonstration of Coal Reburning for Cyclone Boiler NOx

 Control. (The Babcock & Wilcox

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

NTIS as DE90008111.)
36 Project Fact Sheets 1997 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.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 37

Results Summary

Environmental

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

showed NOx reductions in the range of 53.0–55.5%,

52.5–54.7%, and 46.9–47.9% at loads of 605 MWe,

460 MWe, and 350 MWe, respectively.

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

showed an average NOx

 reduction of 58% (over

8 months).

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

showed an average NOx

 reduction of 60% (over

8 months).

• CO emissions averaged 28–55 ppm at full load with

LNCB® in service.

• Fly ash increased, but ESP performance remained

virtually unchanged.

Operational

• Unit efficiency remained essentially unchanged.

• Unburned carbon losses (UBCL) increased by approximately 28% for all tests, but boiler efficiency loss

was offset by a decrease in dry gas loss due to a lower

boiler economizer outlet gas temperature.

• Boiler corrosion with LNCB® was roughly equivalent

to boiler corrosion rates prior to retrofit.

Economic

• Capital cost for a 600-MWe plant was $9/kW (1994$).

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

0.284 mills/kWh and $96.48/ton of NOx

 removed.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

initiated 12/91

10/90

Operation

Design and

Preaward Construction

12/91

NEPA process completed (MTF) 8/10/90

DOE selected project

(CCT-III) 12/19/89

Project completed/final report issued 12/95

Project Summary

Utility boilers equipped with cell burners currently comprise 13% or approximately 23,000 MWe of pre-NSPS

coal-fired generating capacity. Cell burners are designed

for rapid mixing of the fuel and air. The tight burner

spacing and rapid mixing minimize the flame size while

maximizing the heat release rate and unit efficiency.

Combustion efficiency is good, but the rapid heat release

produces relatively large quantities of NOx

.

To reduce NOx

 emissions, the LNCB® has been

designed to stage mixing of the fuel and combustion air.

A key design criterion was accomplishing delayed fuel-air

mixing with no modifications to waterwall panels. A

plug-in design reduces material costs and outage time

required to complete the retrofit, compared to installing

conventional, internally staged low-NOx

 burners. LNCB®

provides a lower cost alternative to address NOx reduction

requirements for cell burners.

12/95

Operation completed 4/93

12/89

Construction completed 11/91

Preoperational tests initiated 11/91

Cooperative agreement

awarded 10/11/90

Design completed 10/90

Environmental monitoring plan

completed 8/9/91

Ground breaking/construction started 9/91
38 Project Fact Sheets 1997 Environmental Control Devices

Average NOx reduction at

intermediate load (about

460 MWe) ranged from 52.5% to

54.7%. At low loads (about

350 MWe), average NOx

 reduction

ranged from 46.9% to 47.9%.

NOx

 emissions were monitored over the long-term at full

load for all mills in service and

one mill out of service. Each test

spanned an 8-month period. NOx

emission reductions realized were

58% for all mills in service and

about 60% for one mill out of

service.

Complications arose in assessing CO emissions relative to

baseline because baseline calibration was not refined enough.

However, accurate measurements

were made with LNCB® in service. CO emissions were corrected to 3.0% O2

 and measured at full, intermediate, and low loads. The range of

CO emissions at full load with all mills in service was

28–55 ppm and 20-38 ppm with one mill out of service.

At intermediate loads (about 460 MWe), CO emissions

were 28–45 ppm and at low loads (about 350 MWe),

5–27 ppm.

Particulate emissions were minimally impacted. The

LNCB® had little effect on flyash resistivity, largely due

to SO3

 injection, and therefore ESP removal efficiency

remained very high. Baseline ESP collection efficiencies

for full load with all mills in service, full load with one

mill in service, and intermediate load with one mill out of

service were 99.5%, 99.49%, and 99.81%, respectively.

For the same conditions, in the same sequence with

LNCB® in operation, ESP collection efficiencies were

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

Operational Performance

Furnace exit gas temperature, or secondary superheater

inlet temperature, initially decreased by 100 oF but eventually rose to within 10 oF of baseline conditions.

The UBCL increased by approximately 28% for all

tests. The most significant increase from baseline data

occurred for a test with one mill out of service. A 52%

increase in UBCL resulted in an efficiency loss of 0.69%.

Boiler efficiency showed very little change from

baseline. The average for all mills in service increased by

0.16%. The higher post-retrofit efficiency was attributed

Dayton Power and Light Company’s J.M. Stuart Plant hosted the successful

demonstration of LNCB® technology.

The LNCB® is viewed from within the boiler.

Environmental Performance

The initial LNCB® configuration resulted in excessive CO

and H2

S emissions. Through modeling, a revised configuration was developed to address the problem without

compromising boiler performance. The modification was

incorporated and validated model capabilities.

Following parametric testing to establish optimal

operating modes, a series of optimization tests were conducted on the LNCB® to assess environmental and operational performance. Two sets of measurements were

taken, one by Babcock & Wilcox and the other by an

independent company, to validate data accuracy. Consequently, the data provided is a range reflecting the two

measurements.

The average NOx

 emissions reduction achieved at

full load with all mills in service ranged from 53.0% to

55.5%. With one mill out of service at full load, the

average NOx

 reduction ranged from 53.3% to 54.5%.
Environmental Control Devices Project Fact Sheets 1997 39

to a decrease in dry gas loss with lower economizer gas

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

Tony Yagiela, (330) 829-7403

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

John C. McDowell, FETC, (412) 892-6237

References

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

Cell Burner Retrofit. Report No. DOE/PC/90545-T2.

The Babcock & Wilcox Company. December 1995.

(Available from NTIS as DE96003766.)

• Public Design Report: Full-Scale Demonstration of

Low-NOx

 Cell Burner Retrofit. Report No. DOE/PC/

90545-T4. The Babcock & Wilcox Company. August

1991. (Available from NTIS as DE92009768.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Full-Scale Demonstration of

Low-NOx

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

Department of Energy. July 1990. (Available from

NTIS as DE90018026.)

The connections to the LNCB® are viewed from outside the boiler.
40 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Evaluation of Gas Reburning

and Low-NO

x

 Burners on a

Wall-Fired Boiler

Project completed.

Participant

Energy and Environmental Research Corporation

Additional Team Members

Public Service Company of Colorado—cofunder and host

Gas Research Institute—cofunder

Colorado Interstate Gas Company—cofunder

Electric Power Research Institute—cofunder

Foster Wheeler Energy Corp.—technology supplier

Location

Denver, Adams County, CO (Public Service Company of

Colorado’s Cherokee Station, Unit No. 3)

Technology

Energy and Environmental Research Corporation’s

gas-reburning (GR) system

Foster Wheeler Energy Corp.’s low-NOx

 burners (LNB)

Plant Capacity/Production

172 MWe

Coal

Western bituminous, 0.35–0.66% sulfur

Project Funding

Total project cost $17,807,258 100%

DOE 8,895,790 50

Participant 8,911,468 50

Project Objective

To attain up to a 70% decrease in the emissions of NOx

from an existing wall-fired utility boiler firing low-sulfur

coal using both gas reburning and low-NOx

 burners

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 1-year long-term testing program

was performed in order to judge the consistency of system outputs, assess the impact of long-term operation on

the boiler equipment, gain experience in operating GR–

LNB in a normal load-following environment, and develop a database for use in subsequent GR–LNB applications. Both first- and second-generation gas-reburning

tests were performed.

(GR–LNB); and to assess the impact of GR–LNB on

boiler performance.

Technology/Project Description

Gas reburning involves firing natural gas (up to 25% of

total heat input) above the main coal combustion zone in

a boiler. This upper-level firing creates a slightly fuelrich zone. NOx

 drifting upward from the lower region of

the furnace is “reburned” in this zone and converted to

molecular nitrogen. Low-NOx

 burners positioned in the

coal combustion zone retard the production of NOx

 by

staging the burning process so that the coal-air mixture

can be carefully controlled at each stage. The synergistic

effect of adding a reburning stage to wall-fired boilers

equipped with low-NOx

 burners was intended to lower

NOx

 emissions by up to 70%. Gas reburning was demon-
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 41

Results Summary

Environmental

• LNB alone achieved a 37% NOx

 reduction.

• First-generation GR, which incorporated flue gas

recirculation, in combination with LNB achieved a

65% NOx

 reduction at an 18% gas heat input rate.

• Second-generation GR, without flue gas recirculation,

in combination with LNB achieved 64% NOx

 reduction at 13% gas heat input.

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

capable of reducing NOx

 emissions by up to 70%.

• After modifying the overfire air system to enhance

penetration and turbulence (as part of second-generation GR), CO emissions were controlled to acceptable

levels at low gas heat input rates (5–10%).

• SO2

 emissions and particulate loadings were reduced

by the percentage heat input supplied by GR.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Operation

12/89

Design and Construction

10/90 10/92

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

Environmental monitoring plan completed 7/26/90

NEPA process completed (MTF) 9/6/90

Cooperative agreement awarded 10/13/90

Ground breaking/construction started 6/91

Design completed 8/91

Preoperational tests initiated 6/92

Construction completed 6/92

Operation initiated 10/92

Operational

• Boiler efficiency decreased by approximately 1.0%.

• There was no measurable boiler tube wear and only a

small amount of slagging.

Economic

• Capital cost for GR was approximately $15/kW

(1993$) plus the gas pipeline cost, if not in place, for

100-MWe plants or larger.

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

 emission allowances

(because GR reduces SO2

 emissions when displacing

coal).

Project Summary

The demonstration established that GR–LNB offers a

cost-effective option for deep NOx

 reduction on wall-fired

boilers. GR–LNB NOx

 control performance approached

that of selective catalytic reduction (SCR) but at significantly lower cost. SCR typically achieves 70–80% NOx

reduction at capital costs in the range of $100–$150/kW

Long-term operations started 4/93

Operation completed 1/95

Restoration

completed 11/95

for retrofit applications. GR–LNB achieved 60–70%

NOx

 reduction at a capital cost of approximately

$35–$45/kW (derived from GR capital cost of $15/kW

according to the demonstration and $20–30/kW for lowNOx

 burners according to the literature). 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.

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

(gross) wall-fired boiler—a balanced-draft pulverizedcoal unit supplied by Babcock & Wilcox. The GR system, including an overfire air system, was designed and

installed by Energy and Environmental Research Corporation. The LNBs were designed and installed by Foster

Wheeler Energy Corp.

4/98

Project completed/final

report issued 4/98*
42 Project Fact Sheets 1997 Environmental Control Devices

10%, NOx emissions were reduced marginally as gas heat

input increased. Natural gas also reduced SO2 emissions

in proportion to the gas heat input. At Cherokee Station,

low-sulfur (0.35–0.66%) coal was used, and typical SO2

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

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

 Btu.

The CO2 emissions were also reduced as a result of

using natural gas because it has a lower carbon-to-hydrogen ratio than coal. At a gas heat input of 20%, the CO2

emissions were reduced by 8%.

Long-term testing was initiated in April 1993 and

completed in January 1995. The objectives of the test

were to obtain operating data over an extended period

when the unit was under routine commercial service,

determine the effect of GR–LNB operation on the unit,

and obtain incremental maintenance and operating costs

with GR.

During long-term testing, it was determined that flue

gas recirculation had minimal effect on NOx

 emissions.

A second series of tests were added to the project to

evaluate a modified or second-generation system. Modifications are summarized below:

• The flue gas recirculation system, originally designed

to provide momentum to the natural gas, was removed.

(This change significantly reduced capital costs.)

• Natural gas injection was optimized at 10% gas heat

input compared to the initial design value of 18%.

The removal of the flue gas recirculation system required installation of high-velocity injectors, which

made greater use of available natural gas pressure.

(This modification reduced natural gas usage and thus

operating costs.)

• Overfire air ports were modified to provide higher jet

momentum, especially at low total flows.

Over 4,000 hours of operation were achieved, with

the results as shown in Exhibit 18.

Although the NOx

 reduction performance of LNB

(37% NOx

 reduction) was less than the expected 45%, the

overall objectives of the demonstration were met. Boiler

efficiency decreased by only 1% during gas reburning due

to increased moisture in the fuel resulting from natural

gas use. Further, there was no measurable tube wear, and

only small amounts of slagging occurred during the

GR–LNB demonstration.

Economic Performance

GR–LNB is a retrofit technology in which the costs are

dependent on the following site-specific factors:

• Gas availability at the site

• Gas/coal cost differential

• SO2 removal requirements

• Value of SO2 emission credits

Based on the demonstration, GR–LNB is expected to

achieve at least 60% NOx

 control with a gas heat input of

10–15%. The capital cost estimate for a 100-MWe or

larger installation was about $15/kW (1993$) plus gas

pipeline costs, if required. Operating costs were almost

entirely related to the differential cost of natural gas and

coal as reduced by the value of the SO2

 emission credits

received due to absence of sulfur in the gas.

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

GR Generation

First Second

Baseline (lb/106

 Btu) 0.73 0.73

Avg NOx

 reduction (%)

LNB 37 37

GR–LNB 65 64

Avg gas heat input (%) 18 13

Exhibit 18

NOx Data from Cherokee

Station, Unit 3

A worker inspects the support ring for the Foster

Wheeler low-NOx

 burner installed in the boiler wall.
Environmental Control Devices Project Fact Sheets 1997 43

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 1, with options for Units 2 and 3, (identical 330-

MWe Units); Baltimore Gas & Electric’s C.P. Crane, Unit

2, with an option for Unit 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, Senior Vice President, (714) 859-8851

Energy and Environmental Research Corporation

18 Mason

Irvine CA 92718

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

Jerry L. Hebb, FETC, (412) 892-6079

References

• Evaluation of Gas Reburning and Low NOx Burners

on a Wall-Fired Boiler (Long-Term Testing, April

1993–January 1995). Report No. DOE/PC/90547-

T20. Energy and Environmental Research Corporation. June 1995. (Available from NTIS as

DE95017755.)

• Evaluation of Gas Reburning and Low NOx

 Burners

on a Wall-Fired Boiler (Optimization Testing, November 1992–April 1993). Report No. DOE/PC/90547-

T19. Energy and Environmental Research Corporation. June 1995. (Available from NTIS as

DE95017754.)

• Reduction of NOx and SO2

 Using Gas Reburning,

Sorbent Injection and Integrated Technologies. Topical Report No. 3, Revision 1. U.S. Department of

Energy and Energy and Environmental Research Corporation. September 1993. (Available from NTIS as

DE94007444.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Evaluation of Gas Reburning

and Low-NOx

 Burners on a Wall-Fired Boiler. Energy

and Environmental Research Corporation. Report No.

DOE/FE-0204P. U.S. Department of Energy. September 1990. (Available from NTIS as DE9100253.) The Public Service Company of Colorado has retained

the gas-reburning and low-NOx

 burner system for

commercial use.
44 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Micronized Coal Reburning

Demonstration for NO

x

 Control

Participant

New York State Electric & Gas Corporation

Additional Team Members

Eastman Kodak Company—host and cofunder

Consolidation Coal Company— tester

D.B. Riley—technology supplier

Fuller Company—technology supplier

Energy and Environmental Research Corporation—

reburn system designer

ABB Combustion Engineering, Inc.—technology supplier

New York State Energy Research and Development

Authority

Locations

Lansing, Tompkins County, NY (New York State Electric

& Gas Corporation’s Milliken Station, Unit 1)

Rochester, Monroe County, NY (Eastman Kodak

Company’s Utility Power House, Unit 15)

Technology

ABB Combustion Engineering’s Low-NOx

 Concentric

Firing System (LNCFSTM)

D.B. Riley’s MPS mill (at Milliken Station)

Fuller’s MicroMillTM technologies for producing

micronized coal (at Eastman Kodak)

Plant Capacity/Production

Milliken Station: 148-MWe tangentially fired boiler

Eastman Kodak Company: 50-MWe cyclone boiler

Project Funding

Total project cost $9,096,486 100%

DOE 2,701,011 30

Participant 6,395,475 70

MicroMill is a trademark of the Fuller Company.

LNCFS is a trademark of ABB Combustion Engineering, Inc.

Project Objective

To reduce NOx

 emissions by 50–60% using micronized

coal as the reburning fuel combined with advanced coalreburning technology.

Technology/Project Description

The reburning coal, which can comprise up to 30% of the

total fuel, is micronized (80% below 325 mesh) and

injected into a pulverized-coal-fired furnace above the

main burner, the region where NOx

 formation occurs.

Micronized coal has the surface area and combustion

characteristics of an atomized oil flame, which allows

carbon conversion within milliseconds and release of

volatiles at a more even rate. This uniform, compact

combustion envelope allows for complete combustion of

the coal/air mixture in a smaller furnace volume than

conventional pulverized coal because heat rate, carbon

loss, boiler efficiency, and NOx

 formation are affected by

coal fineness.

The combination of micronized coal, supplying 30%

of the total furnace fuel requirements, and advanced

reburning, utilizing that requirement in conjunction with

fuel/air staging, provides flexible options for significant

combustion operations and environmental improvements.

These options can prevent higher operating costs or furnace performance derating often associated with conventional environmental controls.

At the Milliken site, coal will be reburned for NOx

control using the following methods: (1) close-coupled

overfire air (CCOFA) reburning in which the top burner

of the existing LNCFSTM burners are used for burning the

micronized coal and the remaining burners are re-aimed,

(2) use of the burners in a deep stage combustion mode
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 45

3/97

in preparation. Reburn testing at Milliken is scheduled to

be completed in late 1998.

Commercial Applications

Micronized-coal-reburning technology can be applied to

existing and greenfield cyclone-fired, wall-fired, and

tangential-fired pulverized coal units. The technology

reduces NOx

 emissions by 50–60% with minimal furnace

modifications for existing units. For greenfield units, the

technology can be designed as an integral part of the

system. Either way, the technology enhances boiler performance with the improved burning characteristics of

micronized coal. About 25% of the more than 1,000

existing units could benefit from use of this technology.

The availability of a coal-reburning fuel, as an additional fuel to the furnace, solves several problems concurrently. Existing units unable to switch fuels because of

limited mill and burner capacity would be able to reach

their maximum continuous rating. NOx

 emissions reductions will enable lost capacity to be restored, creating a

very economic source of generation. For both retrofit and

greenfield facilities, reburn burners also can serve as 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.

This demonstration will provide methods for NOx

control at a low capital cost for utilities and industrial

users to meet the current and upcoming NOx regulations.

Utilities that install low-NOx burners to meet CAAA

Title I requirements and must also meet Title IV requirements will have a low-cost option. Industrial users being

pressured by states to reduce NOx also will be provided a

low-cost option, particularly cyclone boiler users who

have been without low-NOx burners.

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

9/91 7/92

DOE selected

project (CCT-IV)

9/12/91

Design and Construction Operation

4/99

Operation completed (Lansing) 11/98*

Operation completed (Rochester) 8/98*

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

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

Design completed (Rochester) 9/96

NEPA process completed

(CX) 8/13/92

Cooperative agreement awarded 7/28/92

Preoperational tests initiated (Rochester) 1/97

Construction completed (Rochester) 1/97

Preoperational tests initiated (Lansing) 1/97

and re-aiming them to create burn and reburn zones, and

(3) a more standard method using injectors to input micronized coal into the boiler. At the Eastman Kodak site,

the Fuller MicroMillTM will be used to produce the micronized coal, and injectors or burners, depending on

boiler characteristics, will be used for the reburning.

Overfire air also will be installed. Both the injectors/

burners and the overfire air will be installed at the optimal

point downstream of the cyclone burners.

Project Status/Accomplishments

Operational testing at the Kodak site in Rochester began

in April 1997 and will continue into March 1998. Initial

readings show performance may be better than projected.

Minor problems with flue gas leakage and opacity are

being addressed.

Preoperational testing of the reburn system at

Milliken Station near Lansing began in March 1997.

Sieve testing and analysis involved 49 samples. Sieve

test results have been forwarded to ABB Combustion

Engineering and CONSOL for analysis. A draft report is

Project completed/final report issued 4/99*

Operation initiated (Rochester) 4/97

Environmental monitoring plan completed (Lansing) 8/97

Environmental monitoring plan completed (Rochester) 8/97

Construction completed (Lansing) 10/97

Operation initiated (Lansing) 3/97
46 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

NOx Control Technologies

Demonstration of Advanced

Combustion Techniques for a

Wall-Fired Boiler

Participant

Southern Company Services, Inc.

Additional Team Members

Electric Power Research Institute—cofunder

Foster Wheeler Energy Corporation—technology supplier

Georgia Power Company—host

Location

Coosa, Floyd County, GA (Georgia Power Company’s

Plant Hammond, Unit No. 4)

Technology

Foster Wheeler’s low-NOx

 burner (LNB) with advanced

overfire air (AOFA)

EPRI’s Generic NOx

 Control Intelligent System

(GNOCIS) for plant optimization

Plant Capacity/Production

500 MWe

Project Funding

Total project cost $15,853,900 100%

DOE 6,553,526 41

Participant 9,300,374 59

(Of the total project cost, $523,680 is for toxics

testing.)

Project Objective

To achieve 50% NOx

 reduction with the AOFA/LNB

system; to determine the contributions of AOFA and the

LNB to NOx

 reduction and the parameters determining

optimal AOFA/LNB system performance; and to assess

the long-term effects of AOFA, LNB, and combined

AOFA/LNB and advanced digital controls on NOx reduction and boiler performance.

Technology/Project Description

AOFA involves (1) improving the mixing of overfire air

with the furnace gases to achieve complete combustion,

(2) depleting the air from the burner zone to minimize

NOx

 formation, and (3) supplying air over furnace wall

tube surfaces to prevent slagging and furnace corrosion.

The AOFA technique was expected to reduce NOx

 emissions by about 35%.

In an LNB, fuel and air mixing is controlled to preclude the formation of NOx

. This is accomplished by

regulating the initial fuel-air mixture, velocities, and

turbulence to create a fuel-rich flame core and by controlling the rate at which additional air required to complete

combustion is mixed with the flame solids and gases so as

to maintain a deficiency of oxygen. Typical results for

utilities indicate that LNB technology is capable of reducing NOx

 emissions by about 45%.

Based on earlier experience, the use of AOFA in

conjunction with LNB can reduce NOx

 emissions by as

much as 65% compared with conventional burners.

The demonstration is located at the Georgia Power

Company’s Plant Hammond, Unit No. 4. The boiler is a

nominal 500-MWe pulverized coal, opposed wall-fired

unit, which is representative of many existing pre-NSPS

wall-fired utility boilers in the United States. The project

also includes installation and testing of an advanced

digital control system that optimizes LNB/AOFA performance using artificial intelligence techniques.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 47

Project Status/Accomplishments

Baseline, AOFA, LNB, and LNB/AOFA test segments

have been completed. Analysis of more than 80 days of

AOFA operating data has provided statistically reliable

results indicating that, depending upon load, NOx

 reductions of 24% are achievable under normal long-term operation. Analysis of the 94 days of LNB long-term data

collected show the full-load NOx

 emission levels to be

approximately 0.65 lb/106

 Btu. This NOx level represents

a 48% reduction when compared to the baseline, full-load

value of 1.23 lb/106

 Btu. These reductions were sustainable over the long-term test period and were consistent

over the entire load range. Full-load, flyash loss-onignition (LOI) values in the LNB configuration were near

8%, compared to 5% for baseline. Results from

LNB/AOFA testing indicate that full-load NOx

 emissions

were approximately 0.41 lb/106

 Btu with a corresponding

flyash LOI value of nearly 8%. Full-load, long-term NOx

emission reductions in the LNB/AOFA configuration

were about 63%. However, analysis of emissions data

showed that the incremental NOx

 reduction effectiveness

of the AOFA system (beyond the use of the LNB) was

approximately 17% with additional reductions resulting

from other operational changes.

GNOCIS testing for optimizing NOx

 reduction and

boiler efficiency began in February 1996. GNOCIS is

fully operational and testing has achieved an efficiency

gain of 0.5 percentage points, a reduction in LOI levels of

1–3 percentage points, and a reduction in NOx

 emissions

by 10–15% at full load.

Remaining modeling and testing is in progress to

evaluate the applicability of postcombustion NOx

 control

(SNCR) on large, coal-fired boilers, including an evaluation of GNOCIS. A final report on the baseline, AOFA,

LNB, and LNB-AOFA tests has been drafted and reviewed. A report on the on-line carbon-in-ash monitors

evaluated in the project has been prepared.

A report on air toxic testing was issued in December

1993.

Commercial Applications

The technology is applicable to the 422 existing preNSPS U.S. wall-fired boilers 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 retained the technologies for commercial

use. GNOCIS software has been installed in eight other

units: Georgia Power’s Branch Unit 3 and Wansley Unit

1, Alabama Power’s Gaston Units 3 and 4, Duquesne

Light & Power’s Cheswick Unit 1, TVA’s Kingston Unit

4, and PowerGen’s Kingsnorth Units 3 and 4. Feasibility

studies are under way at a number of utilities in England.

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

2/98

Project completed/final report

issued 2/98*

GNOCIS testing initiated 2/96
48 Project Fact Sheets 1997 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 4)

Technology

Selective catalytic reduction (SCR)

Plant Capacity/Production

8.7-MWe equivalent (three 2.5-MWe and six 0.2-MWe

equivalent SCR reactor plants)

Coal

Illinois bituminous, 2.7% sulfur

Project Funding

Total project cost $23,229,729 100%

DOE 9,406,673 40

Participant 13,823,056 60

Project Objective

To evaluate the performance of commercially available

SCR catalysts when applied to operating conditions found

in U.S. pulverized coal-fired utility boilers using highsulfur U.S. coal under various operating conditions while

achieving as much as 80% NOx

 removal.

Technology/Project Description

The SCR technology consists of injecting ammonia into

boiler flue gas and passing it through a catalyst bed

where the NOx

 and ammonia react to form nitrogen and

water vapor.

In this demonstration project, the SCR facility consisted of three 2.5-MWe-equivalent SCR reactors, supplied by separate 5,000 std ft3

/min flue gas slipstreams,

and six 0.20-MWe-equivalent SCR reactors. These reactors were calculated to be large enough to produce design

data that will allow the SCR process to be scaled up to

commercial size. Catalyst suppliers (two U.S., two European, and two Japanese) provided eight catalysts with

various shapes and chemical compositions for evaluation

of process chemistry and economics of operation during

the demonstration.

The project demonstrated, at high- and low-dust

loadings of flue gas, the applicability of SCR technology

to provide a cost-effective means of reducing NOx emissions from power plants burning high-sulfur U.S. coal.

The demonstration plant, which was located at Gulf

Power Company’s Plant Crist near Pensacola, FL, utilized

flue gas from the burning of 2.7% sulfur coal under various NOx

 and particulate levels.

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

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 49

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

at 80% NOx

 reduction.

• While catalyst performance increased above 700 oF,

the benefit did not outweigh the heat rate penalties.

• The increase for ammonia slip, a sign of catalyst deactivation, went from less than 1 ppm to approximately

3 ppm over 12,000 hours of operation, thus demonstrating deactivation in coal-fired units was in line

with worldwide experience.

• SO2

 oxidation was within or below the design limits

necessary to protect downstream equipment.

Operational

• Fouling of catalysts was controlled by adequate

sootblowing procedures.

• Catalyst erosion was not considered to be a problem.

• Air preheater performance was degraded because of

ammonia slip and subsequent by-product formation;

however, problem solutions were identified.

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

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 19. Catalyst

suppliers were given great latitude in providing the

amount of catalyst for this demonstration.

40% 60% 80%

1996 levelized cost (mills/kWh) 2.39 2.57 2.79

1996 levelized cost ($/ton) 3,502 2,500 2,036

Operation initiated 7/93

Operation completed 7/95

Project completed/final

report issued 11/96

Parameter Minimum Baseline Maximum

Temperature (o

F) 620 700 750

NH3/NOx molar ratio 0.6 0.8 1.0

Space velocity

(1% design flow) 60 100 150

Flow rate (std ft3/min)

 Large reactor 3,000 5,000 7,500

 Small reactor 240 400 600

• The SCR process does not significantly affect the

results of toxicity-characteristic-leaching-procedure

analysis of the fly ash.

Economic

Levelized costs for various NOx

 removal levels for a

250-MWe unit at 0.35 lb/106

 Btu inlet follow:

Project Summary

The demonstration tests were designed to address several

uncertainties, including potential catalyst deactivation due

to poisoning by trace metals species in U.S. coals, performance of technology and effects on the balance-of-plant

equipment in the presence of high amounts of SO2

 and
50 Project Fact Sheets 1997 Environmental Control Devices

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 20.

These data reflect baseline conditions over the life of the

demonstration. All of the catalysts were within design

limits, with most exhibiting oxidation rates below the

design limit. Other factors affecting SO2

 oxidations are

listed below:

• Flow Rate. Most of the catalysts exhibited fairly

constant SO2

 oxidation with respect to flow rate (i.e.,

space velocity). In theory, SO2

 oxidation should be

inversely proportional to flow rate.

• Temperature. Theoretically the relationship between

SO2

 oxidation and temperature should be exponential

as temperature increases; however, measurements

showed the relationship to be linear with little difference in SO2 oxidation between 620 oF and 700 oF.

However, between 700 °F and 750 °F, the SO2

 oxidation increased more significantly.

Other Findings

• Pressure Drop. Overall reactor pressure drop was a

function of the catalyst geometry and volume, but tests

to determine which one was controlling were inconclusive.

• Fouling. The fouling characteristics of the catalyst

were important to long-term operation. During the

demonstration, measurements showed relatively level

pressure drop over time, indicating that sootblowing

procedures were effective. The plate-type configurations had somewhat less fouling potential than did the

honeycomb configuration, but both were acceptable

for application.

• Erosion. Catalyst erosion was not considered to be a

significant problem because most of the erosion was

attributed to aggressive sootblowing.

Exhibit 19

Catalysts Tested

Catalyst Reactor Size* Catalyst Configuration

Nippon/Shokubai Large Honeycomb

Siemens AG Large Plate

W.R. Grace/Noxeram Large Honeycomb

W.R. Grace/Synox Small Honeycomb

Haldor Topsoe Small Plate

Hitachi/Zosen Small Plate

Cormetech/High dust Small Honeycomb

Cormetech/Low dust Small Honeycomb

* Large = 2.5 MWe; 5,000 std ft3/min Small = 0.2 MWe; 400 std ft3/min

Exhibit 20

Avg SO2 Oxidation Rate

(Baseline)

Average SO2 Oxidation (%)

NH3

/NOx = 0.8, 700 oF, design flow
Environmental Control Devices Project Fact Sheets 1997 51

• 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 21.

Results of the economic analysis of capital, operating

and maintenance (O&M), and levelized cost based on a

30-year project life for various unit sizes for an SCR

system with a NOx

 removal efficiency of 60% follow:

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

and levelized cost for various NOx

 removal efficiencies

for a 250-MWe unit with 0.35 lb of inlet NOx

/106 Btu

follow:

For retrofit applications, the estimated capital costs

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

levelized costs for the retrofit applications were

$1,850–5,100/ton (current $).

Commercial Applications

As a result of this demonstration, SCR technology has

been shown to be applicable to existing and new utility

generating capacity for removal of NOx

 from the flue gas

of virtually any size boiler. There are approximately

1,041 coal-fired utility boilers in active commercial service in the United States; these boilers represent a total

generating capacity of 296,000 MWe.

Contacts

Robert R. Hardman, Project Manager, (205) 257-7772

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

Arthur L. Baldwin, FETC, (412) 892-6011

References

• 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. 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. 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

Exhibit 21

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
52 Project Fact Sheets 1997 Environmental Control Devices

Project Objective

To demonstrate in a stepwise fashion the short- and longterm NOx

 reduction capabilities of Low-NOx Concentric

Firing System levels I, II, and III on a single reference

boiler.

Technology/Project Description

Technologies demonstrated included the Low-NOx

 Concentric Firing System (LNCFSTM), levels I, II, and III.

Each level of the LNCFSTM used different combinations

of overfire air and clustered coal nozzle positioning to

achieve NOx

 reductions. With the LNCFSTM, primary air

and coal are surrounded by oxygen-rich secondary air that

blankets the outer regions of the combustion zone.

LNCFSTM I used a close-coupled overfire air (CCOFA)

system integrated directly into the windbox of the boiler.

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.

A separated overfire air (SOFA) 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.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 53

Results Summary

Environmental

• At full load, the NOx

 emissions using LNCFSTM I, II,

and III were 0.39, 0.39, and 0.34 lb/106

 Btu, respectively, which represent reductions of 37%, 37%, and

45% from the baseline emissions.

• Emissions with LNCFSTM were not sensitive to power

outputs between 100- and 200-MWe, but emissions

increased significantly below 100 MWe, reaching

baseline emission levels at 70 MWe.

• Because of reduced effectiveness at low loads,

LNCFSTM proved marginal as a compliance option for

peaking load conditions.

• Average CO emissions increased at full load.

• Air toxics testing found LNCFSTM to have no clear-cut

effect on the emissions of trace metals or acid gases.

Volatile organic compounds (VOCs) appeared to be

reduced and semi-volatile compounds increased.

Operational

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

LNCFSTM retrofits but very sensitive to coal fineness.

• Furnace slagging was reduced but back-pass fouling

was increased for LNCFSTM II and III.

• Boiler efficiency and unit heat rate were impacted

minimally.

• Unit operation was not significantly affected, but

operating flexibility of the unit was reduced at low

loads with LNCFSTM II and III.

Economic

• The capital cost estimate for LNCFSTM I was

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

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

NOx

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

III, $400/ton.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Operation

9/88 9/90

Design and Construction

Project completed/final report issued 6/94

6/94

Environmental monitoring

plan completed 12/27/90

Ground breaking/construction started 11/90

Design completed 4/91

Operation initiated 5/91

Construction

completed 5/91 Operation completed 12/92

Project Summary

At the time of the demonstration, specific NOx emission

regulations were being formulated under the CAAA. The

data developed over the course of this project provided

needed real-time input to regulation development.

LNCFSTM technology was designed for tangentially

fired boilers, which represent a large percentage of the

pre-NSPS coal-fired generating capacity. The technology

reduces NOx

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

by creating fuel-rich and lean zones with offset air

nozzles. The objective was to determine NOx

 emission

reductions and impact on boiler performance over the

long-term under normal dispatch and operating conditions. By using the same boiler, the demonstration provided direct comparative performance analysis of the

three configurations. Short-term parametric testing enabled extrapolation of results to other tangentially fired

units by evaluating the relationship between NOx

 emissions and key operating parameters.

NEPA process

completed (MTF)

7/21/89

DOE selected

project

(CCT-II)

9/28/88

Cooperative agreement awarded 9/20/90

5/91
54 Project Fact Sheets 1997 Environmental Control Devices

 Exhibit 22 shows the various LNCFSTM configurations used to achieve staged combustion. In addition to

overfire air, as shown in Exhibit 23, 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 24 summarizes the impacts of LNCFSTM on unit

performance.

Economic Performance

LNCFSTM II was the only complete retrofit (LNCFSTM I

and III were modifications of LNCFSTM II), and therefore

capital cost estimates were based on the Lansing Smith

Unit No. 2 retrofit as well as other tangentially fired

LNCFSTM retrofits. The capital cost ranges follow:

• LNCFSTM I—$5–15/kW

• LNCFSTM II—$15–25/kW

• LNCFSTM III—$15–25/kW

Site-specific considerations have a significant effect

on capital costs; however, the above ranges reflect recent

experience and are planning estimates. The actual capital

cost for LNCFSTM II at Lansing Smith Unit No. 2 was $3

million, or $17/ kW, which falls within the projected

range.

The cost effectiveness of the LNCFSTM technologies

is based on the capital and operating and maintenance

costs and the NOx

 removal efficiency of the technologies.

The cost effectiveness of the LNCFSTM technologies is

listed below (based on a levilization factor of 0.144):

• LNCFSTM I—$103/ton of NOx

 removed

• LNCFSTM II—$444/ton of NOx removed

• LNCFSTM III—$400/ton of NOx

 removed

Commercial Applications

LNCFSTM technology has been adopted by eight other

utilities in eight separate retrofits over a range of capacities. Further, potential commercial applications of this

technology include nearly 600 U.S. pulverized coal,

tangentially fired utility units. These units are 25–950

MWe in size and fire a wide range of coals, from lowvolatile bituminous through lignite.

LNCFSTM has been retained at the host site for commercial use.

Environmental Performance

At full load, LNCFSTM I, II, and III reduced NOx

 emissions by 37%, 37%, and 45%, respectively.

Exhibit 25 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.

Exhibit 22

LNCFSTM Configurations

Exhibit 23

Concentric Firing Concept
Environmental Control Devices Project Fact Sheets 1997 55

Contacts

Robert R. Hardman, Project Manager, (205) 257-7772

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

Scott M. Smouse, FETC, (412) 892-5725

References

• 180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx

) Emissions from Coal-Fired

Boilers: Final Report and Key Project Findings.

Report No. DOE/PC/89653-T14. Southern Company

Services, Inc. February 1994. (Available from NTIS

as DE94011174.)

• 180-MWe Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx

) Emissions from Coal-Fired

Boilers—Plant Lansing Smith—Phase III and Final

Environmental Monitoring Program Report. Southern

Company Services, Inc. December 1993.

• Measurement of Chemical Emissions under the Influence of Low-NOx

 Combustion Modifications. Report

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

DE94005038.)

• 180-MW Demonstration of Advanced Tangentially

Fired Combustion Techniques for the Reduction of

Nitrogen Oxide (NOx

) Emissions from Coal-Fired

Boilers: Public Design Report. Report No. DOE/PC/

89652-T13. Southern Company Services, Inc. September 1993. (Available from NTIS as DE94000218.)

Exhibit 24

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 25

Average Annual NOx Emissions and % Reduction

Boiler Duty Cycle Units Baseline LNCFSTM I LNCFSTM II LNCFSTM III

Baseload Avg NOx

 emissions (lb/106 Btu) 0.62 0.41 0.41 0.36

(161.8 MWe avg) Avg reduction (%) 38.7 38.7 42.2

Intermediate load Avg NOx emissions (lb/106 Btu) 0.62 0.40 0.41 0.34

(146.6 MWe avg) Avg reduction (%) 39.2 35.9 45.3

Peaking load Avg NOx emissions (lb/106 Btu) 0.59 0.45 0.47 0.43

(101.8 MWe avg) Avg reduction (%) 36.1 20.3 28.0
56 Project Fact Sheets 1997 Environmental Control Devices

Combined SO2/NOx Control

Technology

Combined SO2/NOx control systems encompass

those technologies that combine previously described

control methods and those that apply other, synergistic

techniques. Three of the projects combine either

LNBs or gas reburning with sorbent injection. In one

of these, SNCR is used with LNBs to enhance

performance. Another project combines a number of

techniques to improve overall system performance,

such as LNBs with SNCR, unique space-saving and

durable wet-scrubber design, sorbent additive, and

artificial intelligence controls. The balance of the

seven projects use synergistic methods not previously

described.

SOx-NOx-Rox BoxTM incorporates an SCR

catalyst in a high-temperature filter bag for NOx

control and applies sorbent injection for SO2 control.

The high-temperature filter bag, operated in a standard

pulsed jet baghouse, protects the SCR catalyst, allows

operation at optimal NOx control temperatures, forms

a sorbent cake on the surface to enhance SO2 capture,

and provides high-efficiency particulate capture.

SNOXTM uses SCR followed by catalytic oxidation of SO2

 to SO3 with condensation of the SO3 in the

presence of water to produce sulfuric acid. Following

the SCR with the catalytic oxidation allows the SCR to

operate at optimal ammonia concentration without

worry of ammonia slip (ammonia passing to the

second catalyst is broken down). Furthermore, most

particulates passing through the upstream baghouse

are captured in the sulfuric acid condensing unit. The

system produces no solid waste.

NOXSO uses a single, regenerable adsorber

(spherical alumina beads impregnated with sodium

carbonate) to capture both SO2 and NOx. The adsorber

is used in a fluidized bed to achieve effective mixing

with the flue gas. The flue gas is then processed

through a regenerator system to release the NOx and

SO2 before return to the fluidized bed.

Five of the seven combined SO2

/NOx control

technology projects have been completed, one is in

operation, and one is in the project definition and

design phase. Exhibit 26 briefly summarizes the

characteristics and performance of the technologies

that are described in more detail in the project fact

sheets.

New York State Electric & Gas Corporation’s Milliken

Station is hosting the demonstration of a combination of

unique SO2

 and NOx control technologies.
Environmental Control Devices Project Fact Sheets 1997 57

Exhibit 26

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% 62

Coolside Demonstration sorbents

Integrated Dry NOx

/SO2 Emissions LNB/SNCR/sorbent injection—calcium- and sodium-based 0.4% 70%/62–80% 78

Control System sorbents used in duct injection

Enhancing the Use of Coals by Gas Reburning Gas reburning/sorbent injection—calcium-based sorbents used in 3.0% 50–60%/67% 70

and Sorbent Injection duct injection

Milliken Clean Coal Technology Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5–4.0% 95%/53–58% (goal) 74

Project durable scrubber design

SOx

-NOx-Rox BoxTM Flue Gas Cleanup SCR/high temperature baghouse/sorbent injection—SCR in high- 3.4% 80–90%/90% 66

Demonstration Project temperature filter bag and calcium-based sorbent injection

SNOXTM Flue Gas Cleaning Demonstration SCR/oxidation catalyst/sulfuric acid condenser—synergistic 3.4% 95%/94% 58

Project catalyst effect and no solid waste

Commercial Demonstration of the NOXSO Regenerable adsorbent—spherical alumina beads impregnated 3.4% 98% (goal)/75% (goal) 76

SO2

/NOx Removal Flue Gas Cleanup System with sodium carbonate in fluidized-bed adsorber (planned)
58 Project Fact Sheets 1997 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

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 59

• Absence of an alkali reagent contributed to having no

secondary pollution streams or increases in CO2

 emissions.

• SO2

 catalyst virtually eliminated CO and hydrocarbon

emissions.

Operational

• SO2

 catalyst downstream of the NOx catalyst eliminated ammonia slip and allowed the SCR to function

more efficiently.

• Heat developed in the SNOXTM process was used to

enhance thermal efficiency.

Economic

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

500-MWe unit firing 3.2% sulfur coal. The levelized

incremental cost was estimated at 6.1 mills/kWh or

$21/ton of SO2

 removal on a constant dollar basis.

Comparable current dollar costs were 7.8 mills/kWh

and $284/ton of SO2

.

Results Summary

Environmental

• SO2

 removal efficiency was normally in excess of 95%

for inlet concentrations averaging about 2,000 ppm.

• NOx

 reduction averaged 94% for inlet concentrations

of approximately 500–700 ppm.

• Particulate removal efficiency for the high-efficiency

fabric filter baghouse with SNOXTM system was

greater than 99%.

• Sulfuric acid purity exceeded federal specifications for

Class I acid.

• Air toxics testing showed high capture efficiency of

most trace elements in the baghouse. A significant

portion of the boron and almost all of the mercury

escaped to the stack. But selenium and cadmium,

normally a problem, were effectively captured in the

acid drain, as were organic compounds.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Operation

9/88

Preaward Design and Construction

Operation initiated 3/92

12/89 3/92

Cooperative agreement

awarded 12/20/89

NEPA process completed (MTF) 1/31/90

Construction completed 12/91

Preoperational tests initiated 12/91

Dedication ceremony held 10/17/91

Environmental monitoring plan completed 10/31/91

Design completed 8/91

Construction started 1/91

DOE selected

project (CCT-II)

9/28/88

7/96

Project completed/

final report issued 7/96

Operation completed 12/94

Project Summary

Because the SNOXTM process utilized an oxidation catalyst to convert SO2

 to SO3 and ultimately to sulfuric acid,

no reagent was required for the SO2 removal step. As a

result, the process produced no other waste streams.

In order to demonstrate and evaluate the performance

of the SNOXTM process, general operating data were

collected and parametric tests conducted to characterize

the process and equipment. The system has operated for

approximately 8,000 hours and produced more than

5,600 tons of commercial-grade sulfuric acid. Many tests

for the SNOXTM system were conducted at three loads—

75%, 100%, and 110% of design capacity.

Environmental Performance

Particulate emissions from the process were very low

 (<1 mg/Nm3

) due to the characteristics of the SO2 catalyst and the sulfuric acid condenser (WSA Condenser).

Although the Niles SNOXTM plant was fitted with a

baghouse (rather than an ESP) on its inlet, this was not

necessary for low particulate emissions, but the baghouse
60 Project Fact Sheets 1997 Environmental Control Devices

was needed to maintain an acceptable cleaning frequency

of the SO2

 catalyst. At operating temperature, the SO2

catalyst, because of its sticky surface, retained about

90% of the dust that entered the catalyst vessel. Dust that

passed through was subsequently removed in the WSA

Condenser, which acted as a condensing particulate removal device (utilizing the dust particulates as nuclei).

Minimal or no increase in CO2

 emissions by the

process was tied to two features—the lack of a carbonatebased alkali reagent that releases CO2

 and the fact that the

process recovered additional heat from the flue gas to

offset its parasitic energy requirements. This heat recovery, under most design conditions, results in the net heat

rate of the boiler being the same or better after addition of

the SNOXTM process, and consequently no increase in

CO2 generation per unit of power.

With respect to CO and hydrocarbons, the SO2

 catalyst acted to virtually eliminate these compounds as well.

This aspect also positively affected the interaction of the

NOx

 and SO2 catalysts. Because the SO2 catalyst followed the NOx

 catalyst, any unreacted ammonia (slip)

was oxidized in the SO2

 catalyst to nitrogen, water vapor,

and a small amount of NOx

. As a result, downstream

fouling by ammonia compounds was eliminated and the

SCR was operated at slightly higher than typical ammonia

stoichiometries. These higher stoichiometries allowed

smaller SCR catalyst volumes and permitted the attainment of very high reduction efficiencies (>95%).

Sulfur dioxide removal in the SNOXTM process was

controlled by the efficiency of the SO2

-to-SO3 oxidation,

which occurred as the flue gas passes through the oxidation catalyst beds. The efficiency was controlled by two

factors—space velocity and bed temperature. Space

velocity governed the amount of catalyst necessary at

design flue gas flow conditions, and gas and bed temperature had to be high enough to activate the SO2

 oxidation,

reaction. During the test program, SO2

 removal efficiency

was normally in excess of 95% for inlet concentrations

averaging about 2,000 ppm.

The SCR portion of the SNOXTM process was able to

operate at higher than typical ammonia stoichiometries

due to its location ahead of the SO2

 catalyst beds. Normal

operating stoichiometries for the SCR system were in the

range of 1.02–1.05 and system reduction efficiencies

averaged 94% with inlet NOx

 levels of approximately

500–700 ppm.

Sulfuric acid concentration and composition has met

or exceeded the requirements of the federal specifications

for Class I acid. During the design and construction of

the SNOXTM demonstration, arrangements were made

with a sulfuric acid supplier to purchase and distribute the

acid from the plant. The acid has been sold to the agriculture industry for the production of diammonium phosphate fertilizer and to the steel industry for pickling.

Ohio Edison has also used a significant amount in boiler

water demineralizer systems throughout its plants.

Air toxic testing conducted at the Niles SNOXTM

plant measured the following substances:

• Five major and 16 trace elements including mercury,

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

• Acids and corresponding anions (hydrogen chloride,

hydrogen fluoride, chloride, fluoride, phosphate, sulfate)

• Ammonia and cyanide

• Elemental carbon

• Radionuclides

• Volatile organic compounds

• Semi-volatile compounds including polynuclear aromatic hydrocarbons

• Aldehydes

Most trace elements were captured in the baghouse

along with the particulate. A significant portion of the

boron and almost all of the mercury escaped to the stack.

But selenium and cadmium, normally a problem, were

effectively captured in the acid drain, as were organic

compounds.

Operational Performance

Heat recovery was accomplished by the SNOXTM process.

In a commercial configuration, it can be utilized in the

thermal cycle of the boiler. The process generated recoverable heat in several ways. All of the reactions that took

place with respect to NOx

 and SO2 removal were exothermic and increased the temperature of the flue gas. This

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

WSA Condenser cooling air discharge for use in the

The bottom portion of the SO2 converter catalyst, with

the catalyst dust collector hopper mounted on steel rails

(center), is shown.
Environmental Control Devices Project Fact Sheets 1997 61

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

dollars) and $384 (current dollars).

Commercial Applications

The SNOXTM technology is applicable to all electric

power plants and industrial/institutional boilers firing

coal, oil, or gas. The high removal efficiency for NOx and

SO2

 makes the process attractive in many applications.

Elimination of additional solid waste (except ash) enhances the marketability in urban and other areas where

solid waste disposal is a significant problem.

The host utility, Ohio Edison,

is retaining the SNOXTM technology as a permanent part of the

pollution control system at Niles

Station to help Ohio Edison meet

its overall SO2

/NOx reduction

goals.

Commercial SNOXTM plants

also are operating in Denmark and

Sicily. In Denmark, a 305-MWe

plant has operated since August

1991. The boiler at this plant

burns coals from various suppliers

around the world, including the

United States; the coals contain

0.5–3.0% sulfur. The plant in

Sicily, operating since March

1991, has a capacity of about 30 MWe and fires petroleum coke.

Contacts

Paul Yosick, Project Manager, (423) 653-7550

ABB Environmental Systems

1400 Center Port Boulevard

Knoxville, TN 37932

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

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

References

• 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.)

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

Plant: Niles Station Boiler No. 2. Volume 1, Sampling/Results/Special Topics: Final Report. Report

No. DOE/PC/93251-T1-Vol. 1. Battelle Columbus

Operations. July 1994. (Available from NTIS as

DE94016050.)

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

Plant: Niles Station Boiler No. 2. Volume 2, Appendices: Final Report. Report No. DOE/PC/93251-T1-

Vol. 2. Battelle Columbus Operations. July 1994.

(Available from NTIS as DE94016051.)

• Comprehensive Report to Congress on the Clean Coal

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

NTIS as DE90004461.)

The SNOXTM demonstration at Ohio Edison’s Niles

Station Unit No. 2 achieved SO2 removal efficiencies

exceeding 95% and NOx reduction effectiveness averaging

94%. Ohio Edison is retaining the SNOXTM technology as

part of its environmental control system.
62 Project Fact Sheets 1997 Environmental Control Devices

Project Objective

To demonstrate, with a variety of coals and sorbents, the

LIMB process as a retrofit system for simultaneous control of NOx

 and SO2 in the combustion process, and that

LIMB can achieve up to 70% NOx

 and SO2 reductions; to

test alternate sorbent and coal combinations using the

Coolside process; to demonstrate in-duct sorbent injection

upstream of the humidifier and precipitator; and to show

SO2

 removal of up to 70%.

Technology/Project Description

The LIMB process reduces SO2

 by injecting dry sorbent

into the boiler at a point above the burners. The sorbent

then travels through the boiler and is removed along with

fly ash in an electrostatic precipitator (ESP) or baghouse.

DRB-XCL is a registered trademark of The Babcock & Wilcox Company. Humidification of the flue gas before it enters an ESP is

TAG is a trademark of the Electric Power Research Institute.

necessary to maintain normal ESP operation and to enhance SO2

 removal. Combinations of three bituminous

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

were tested. Other variables examined were stoichiometry, humidifier outlet temperature, and injection level.

In the Coolside process, dry sorbent is injected into

the flue gas downstream of the air preheater, followed by

flue gas humidification. Humidification enhances ESP

performance and SO2

 absorption. SO2 absorption is improved by dissolving NaOH or Na2

CO3 in the humidification water. The spent sorbent is collected with the fly ash,

as in the LIMB process. Bituminous coal with 3.0%

sulfur was used in testing.

Babcock & Wilcox DRB-XCL® low-NOx

 burners,

which control NOx

 through staged combustion, were used

in demonstrating both LIMB and Coolside technologies.

Environmental Control Devices

Combined SO2 /NOx Control Technologies

LIMB Demonstration Project

Extension and Coolside

Demonstration

Project completed.

Participant

The Babcock & Wilcox Company

Additional Team Members

Ohio Coal Development Office—cofunder

Consolidation Coal Company—cofunder and technology

supplier

Ohio Edison Company—host

Location

Lorain, Lorain County, OH (Ohio Edison’s Edgewater

Station, Unit 4)

Technology

The Babcock & Wilcox Company’s (B&W) limestone

injection multistage burner (LIMB) system; Babcock &

Wilcox DRB-XCL® low-NOx

 burners

Consolidation Coal Company’s Coolside duct injection of

lime sorbents

Plant Capacity/Production

105 MWe

Coal

Ohio bituminous, 1.6%, 3.0%, and 3.8% sulfur

Project Funding

Total project cost $19,404,940 100%

DOE 7,597,026 39

Participant 11,807,914 61
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 63

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

molar ratio of 2.0, a sodium-to-calcium (Na/Ca) ratio

of 0.2, and 20 oF approach-to-adiabatic-saturation

temperature using commercial hydrated lime and

2.8–3.0% sulfur coal.

• Sorbent recycle tests demonstrated the potential to

improve sorbent utilization.

Operational

• Humidification enhanced ESP performance, which

enabled opacity levels to be kept well within limits.

• LIMB availability was 95%. Coolside did not undergo

testing of sufficient length to establish availability.

• Humidifier performance indicated that operation in a

vertical rather than horizontal mode would be better.

Economic

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

100–500 MWe and coals with 1.5–3.5% sulfur, with a

target SO2

 reduction of 60%. Annual levelized costs

(15-year) for this range of conditions were $392–791/

ton of SO2

 removed (1992$).

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

100–500 MWe and coals with 1.5–3.5% sulfur, with a

target SO2

 reduction of 70%. Annualized levelized

costs (15-year) for this range of conditions were

$482–943/ton of SO2

 removed (1992$).

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

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
64 Project Fact Sheets 1997 Environmental Control Devices

evaluated in the LIMB configuration, demonstrating

enhanced performance. Although LIMB performance

was enhanced by applying humidification to the point of

approaching adiabatic saturation temperatures, performance did not rely on this deep humidification.

Coolside design was dependent upon deep humidification to improve sorbent reactivity and use of hydrated

lime. Sorbent injection was downstream of the furnace.

In addition, sorbent activity was enhanced by dissolving

sodium hydroxide (NaOH) or sodium carbonate (Na2

CO3)

in the humidification water.

Environmental Performance (LIMB)

LIMB tests were conducted over a range of Ca/S and

humidification conditions while burning Ohio coals with

nominal sulfur contents of 1.6%, 3.0%, and 3.8% by

weight. Each of four different sorbents was injected

while burning each of the three different coals. Other

variables examined were stoichiometry, humidifier outlet

temperature, and injection level. Exhibit 27 summarizes SO2

 removal efficiencies for the range of sorbents and coals tested.

While injecting commercial limestone with 80%

of the particles less than 44 microns in size, removal

efficiencies of about 22% were obtained at a stoichiometry of 2.0 while burning 1.6% sulfur coal. However, removal efficiencies of about 32% were

achieved at a stoichiometry of 2.0 when using a

limestone with a smaller particle size (i.e., all particles were less than 44 microns). A third limestone

with essentially all particles less than 10 microns was

used to determine what might be the removal efficiency limit. The removal efficiency for this very

fine limestone was approximately 5–7% higher than

that obtained at similar conditions for limestone with

particles all sized less than 44 microns.

During the design phase, it was expected that

injection at the 181-ft plant elevation level inside the

boiler would permit the introduction of the limestone at

close to the optimum furnace temperature of 2,300 oF.

Testing confirmed that injection at this level, just above

the nose of the boiler, yielded the highest SO2

 removal.

Injection was also performed at the 187-ft level and

similar removals were observed. Removal efficiencies

while injecting at these levels were about 5% higher than

while injecting sorbent at the 191-ft level.

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

when humidification down to a 20 oF approach-to-saturation temperature was used.

The continued use of the low-NOx

 burners resulted

in an overall average NOx

 emissions level of 0.43 lb/106

Btu, which is about a 45% reduction.

Operational Performance (LIMB)

Long-term test data showed that the LIMB system was

available about 95% of the time it was called upon to

operate. Even with minimal humidification, ESP performance was adequately enhanced to keep opacity levels

well below the permitted limit. Opacity was generally in

the 2–5% range while the limit was 20%.

Environmental Performance (Coolside)

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

sulfur) coals. Objectives of the full-scale test program

were to verify short-term process operability and to develop a design performance database to establish process

economics for Coolside. Key process variables—Ca/S,

Na/Ca, and approach-to-adiabatic-saturation—were

evaluated in short-term (6–8-hour) parametric tests and

longer term (1–11-day) process operability tests.

The test program demonstrated that the Coolside

process routinely achieved 70% SO2

 removal at design

conditions of 2.0 Ca/S, 0.2 Na/Ca, and 20 oF approach-toadiabatic-saturation temperature using commercially

available hydrated lime. Coolside SO2

 removal depended

on Ca/S, Na/Ca, approach-to-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

Exhibit 27

LIMB SO2 Removal Efficiencies

(Percent)

Nominal Coal Sulfur Content

Sorbent 3.8% 3.0% 1.6%

Ligno lime 61 63 53

Commercial calcitic lime 58 55 51

Dolomitic lime 52 48 45

Limestone NT 25 22

(80% <44 microns)

NT = Not tested

Test conditions: injection at 181 ft, Ca/S of 2.0, minimal

humidification.

Water mist, sprayed into the flue gas, enhanced sulfur

capture by the sorbent by approximately 10% in the LIMB

process when 20 oF approach-to-saturation was used.
Environmental Control Devices Project Fact Sheets 1997 65

alone was 22% at 0.5 available Ca/S and 18 oF approachto-adiabatic-saturation. The observed SO2

 removal with

simultaneous recycle and fresh sorbent feed was 40% at

0.8 fresh Ca/S, 0.2 fresh Na/Ca, 0.5 available recycle, and

18 oF approach-to-adiabatic-saturation.

Operational Performance

(Coolside)

Floor deposits experienced in the

ductwork with the horizontal humidification led designers to consider a vertical unit in a commercial

configuration. Short-term testing

did not permit evaluation of

Coolside system availability.

Economic Performance

(LIMB & Coolside)

Economic comparisons were made

between LIMB, Coolside, and a wet

scrubber with limestone injection

and forced oxidation (LSFO). Assumptions on performance were SO2

removal efficiencies of 60%, 70%,

and 95% for LIMB, Coolside, and

LSFO, respectively. EPRI TAGTM

methodology was used. Exhibits

28 and 29 summarize results.

Commercial Application

Both LIMB and Coolside technologies are applicable to most utility

and industrial coal-fired units and

provide alternatives to conventional

wet flue gas desulfurization processes. LIMB and Coolside can be

retrofitted with modest capital

investment and downtime, and their

space requirements are substantially

less than for conventional flue gas

sulfurization processes.

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, (216) 860-1074

The Babcock & Wilcox Company

P.O. Box 351

Barberton, OH 44203-0351

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

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

References

• T.R. Goots, M.J. DePero, and P.S. Nolan. LIMB Demonstration Project Extension and Coolside Demonstration:

Final Report. Report No. DOE/PC/79798-T27. The

Babcock & Wilcox Company. November 1992. (Available from NTIS as DE93005979.)

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

Demonstration: A Topical Report. Report No. DOE/PC/

79798-T26. CONSOL, Inc. February 1992. (Available

from NTIS as DE93001722.)

• Coolside and LIMB: Sorbent Injection Demonstrations

Nearing Completion. Topical Report No. 2. U.S. Department of Energy and The Babcock & Wilcox Company. September 1990.

• Public Design Report. Report No. DOE/PC/79798-T2.

The Babcock & Wilcox Company. December 1988.

(LIMB/Coolside demonstration.) (Available from NTIS

as DE92016131.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: LIMB Demonstration Project

Extension. The Babcock & Wilcox Company. Report

No. DOE/FE-0085. U.S. Department of Energy. April

1987. (Available from NTIS as DE87009793.)

Exhibit 28

Capital Cost Comparison

($/kW)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe

1.5 93 150 413 66 116 312

2.5 95 154 421 71 122 316

3.5 102 160 425 73 127 324

250 MWe 500 MWe

1.5 46 96 228 31 69 163

2.5 50 101 235 36 76 169

3.5 54 105 240 40 81 174

Exhibit 29

Annual Levelized Cost Comparison

($/Ton of SO2 Removed)

Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO

100 MWe 150 MWe

1.5 791 943 1418 653 797 1098

2.5 595 706 895 520 624 692

3.5 525 629 665 461 570 527

250 MWe 500 MWe

1.5 549 704 831 480 589 623

2.5 456 567 539 416 502 411

3.5 419 526 413 392 482 321
66 Project Fact Sheets 1997 Environmental Control Devices

Technology/Project Description

The SNRBTM process combines the removal of SO2

, NOx,

and particulates in one unit—a high-temperature

baghouse. SO2

 removal is accomplished using either

calcium- or sodium-based sorbent injected into the flue

gas. NOx

 removal is accomplished by injecting ammonia

(NH3

) to selectively reduce NOx in the presence of a

selective catalytic reduction, or SCR, catalyst. Particulate

removal is accomplished by high-temperature fiber bag

filters.

The 5-MWe SNRBTM demonstration unit is large

enough to demonstrate commercial-scale components

while minimizing the demonstration cost. Operation at

this scale also permitted cost-effective control of the flue

gas temperature, which allowed for evaluation of performance over a wide range of sorbent injection and

baghouse operating temperatures. Thus several different

arrangements for potential commercial installations could

be simulated.

The SNRBTM process was operated for approximately 2,300 hours. Through this effort, SNRBTM demonstrated the technical and economic feasibility of

achieving more than 80% SO2

 removal, more than 90%

NOx

 removal, and 99% particulate removal at lower

capital, operating, and maintenance costs than those for a

combination of conventional systems. The demonstration was conducted at Ohio Edison Company’s R.E.

Burger Plant, Unit No. 5, in Dilles Bottom, OH.

Environmental Control Devices

Combined SO2 /NOx Control Technologies

SOx-NOx-Rox BoxTM Flue Gas

Cleanup Demonstration

Project

Project completed.

Participant

The Babcock & Wilcox Company

Additional Team Members

Ohio Edison Company—cofunder and host

Ohio Coal Development Office—cofunder

Electric Power Research Institute—cofunder

Norton Company—cofunder and SCR catalyst supplier

3M Company—cofunder and filter bag supplier

Owens Corning Fiberglas Corporation—cofunder and

filter bag supplier

Location

Dilles Bottom, Belmont County, OH (Ohio Edison

Company’s R.E. Burger Plant, Unit No. 5)

Technology

The Babcock & Wilcox Company’s SOx

-NOx-Rox BoxTM

(SNRBTM) process

Plant Capacity/Production

5-MWe equivalent slipstream from a 156-MWe boiler

Coal

Bituminous coal blend, 3.7% sulfur avg

Project Funding

Total project cost $13,271,620 100%

DOE 6,078,402 46

Participant 7,193,218 54

Project Objective

To achieve greater 70% SO2

 removal and 90% or higher

reduction in NOx

 emissions while maintaining particulate

emissions below 0.03 lb/106

 Btu.

SOx-NOx-Rox Box and SNRB are trademarks of The Babcock & Wilcox

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

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 67

Results Summary

Environmental

• SO2

 removal efficiency of 80% was achieved with

commercial-grade lime at a calcium-to-sulfur (Ca/S)

molar ratio of 2.0 and temperature of 800–850 oF.

• SO2

 removal efficiency of 90% was achieved with

sugar hydrated and lignosulfonate hydrated lime at a

Ca/S ratio of 2.0 and temperature of 800–850 oF.

• SO2

 removal efficiency of 80% was achieved with

sodium bicarbonate at a sodium-to-sulfur (Na2

/S)

molar ratio of 1.0 and temperature of 425 oF.

• SO2

 emissions were reduced to less than 1.2 lb/106 Btu

with 3–4% sulfur coal with a Ca/S molar ratio as low

as 1.5 and NA2

/S ratio of 1.0.

• Injection of calcium-based sorbents directly upstream

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

temperatures up to 1,200 oF.

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

9/88

Preaward

12/89

Design completed 8/91

DOE selected

project (CCT-II)

9/28/88

Cooperative agreement

awarded 12/20/89

NEPA process completed (MTF) 9/22/89

Ground breaking/construction started 5/9/91

5/92

Design and Construction Operation

Preoperational tests initiated 11/91

• NOx reduction of 90% was achieved with an NH3/NOx

ratio of 0.9 and temperature of 800–850 oF.

• Air toxic removal efficiency was comparable to that of

an electrostatic precipitator (ESP), except that hydrogen fluoride (HF) was reduced by 84% and hydrogen

chloride (HCl) by 95%.

Operational

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

85–90%.

• Norton Company’s NC-300 zeolite SCR catalyst

showed no appreciable physical degradation or change

in catalyst activity over the course of the demonstration.

• No excessive wear or failures occurred with the filter

bags tested: 3M’s Nextel ceramic fiber filter bag and

Owens Corning Fiberglas’s S-Glass filter bag.

9/95

Construction completed 12/91

Environmental monitoring plan completed 12/31/91

Operation

initiated 5/92 Operation completed 5/93

Project completed/final report issued 9/95

Economic

• Capital cost for a 250-MWe retrofit was $233/kW,

assuming 3.5% sulfur coal and baseline NOx

 generation of 1.2 lb/106

 Btu.
68 Project Fact Sheets 1997 Environmental Control Devices

Project Summary

SNRBTM incorporates two successful technology development efforts that offer distinct advantages over other

control technologies. High-temperature filter bags and

circular monolith catalyst developments enabled multiple

emission control in a single component with a low plantarea space requirement. As a postcombustion control

system, it is simple to operate. The high-temperature bag

provides a clean, high-temperature environment compatible with effective SCR operation and a surface for enhanced SO2

/sorbent contact (creates a sorbent cake on the

surface). Particulate control, which is receiving increasing attention, is typical of the superior performance offered by pulsed jet baghouses.

Environmental Performance

Four different sorbents were tested for SO2

 capture. Calcium-based sorbents included commercial-grade-hydrated lime, sugar-hydrated lime, and lignosulfonatehydrated lime. In addition, sodium bicarbonate was

tested. The optimal location for injecting the sorbent into

the flue gas was immediately upstream of the baghouse.

Effectively, the SO2

 was captured by the sorbent in the

form of a filter cake on the filter bags (along with fly

ash).

With the baghouse operating above 830 oF, injection

of commercial-grade hydrated lime at Ca/S molar ratio of

1.8 and above resulted in SO2

 removals of over 80%. At

a Ca/S of molar ratio of 2.0, performance of the sugarhydrated lime and lignosulfonate-hydrated lime increased

performance by approximately 8%, for overall removal of

approximately 90%. SO2

 removal of 85–90% was obtained with calcium utilization of 40–45%. Injection of

the calcium-based sorbents directly upstream of the

baghouse at 825–900 oF resulted in higher overall SO2

removal than injection further upstream at temperatures

up to 1,200 oF.

SO2

 removal using sodium bicarbonate was 80% at

an Na2

/S ratio of 1.0 and 98% at an Na2/S ratio of 2.0

at a significantly reduced baghouse temperature of

450–460 oF. SO2

 emissions while burning a 3–4% sulfur

coal were reduced to less than 1.2 lb/106

 Btu with a Ca/S

molar ratio as low as 1.5 and Na2

/S ratio less than 1.0.

To capture NOx

, ammonia was injected between the

sorbent injection point and the baghouse. The ammonia

and NOx

 reacted to form nitrogen and water in the presence of Norton Company’s NC-300 series zeolite SCR

catalyst. With the catalyst being located inside the filter

bags, it was well protected from potential particulate

erosion or fouling. The sorbent reaction products,

unreacted lime, and fly ash were collected on the filter

bags and thus removed from the flue gas.

NOx

 emissions reduction of 90% was readily

achieved with ammonia slip limited to less than 5 ppm.

This performance reduced NOx

 emissions to less than

0.10 lb/106

 Btu. NOx reduction was insensitive to temperatures over the catalyst design temperature range of

700–900 oF. Catalyst space velocity (volumetric gas flow/

catalyst volume) had a minimal effect on NOx

 removal

over the range evaluated.

Turndown capability for tailoring the degree of NOx

reduction by varying the rate of ammonia injection was

demonstrated for a range of 50–95% NOx

 reduction. No

appreciable physical degradation or change in the catalyst

activity was observed over the duration of the test program. The degree of oxidation of SO2

 to SO3 over the

zeolite catalyst appeared to be less than 0.5%. (SO2

 oxidation is a concern for SCR catalysts containing vanadium.) Leach potential analysis of the catalyst after

completion of the field test showed that the catalyst remained nonhazardous for disposal.

Particulate emissions were consistently below NSPS

standards of 0.03 lb/106

 Btu, with an average over 30

baghouse particulate emission measurements of

0.018 lb/106

 Btu, which corresponds to a collective efficiency of 99.89%. Hydrated lime injection increased the

baghouse inlet particulate loading from 5.6 to 16.5 lb/106

Btu. Emissions testing with and without the SCR catalyst

installed revealed no apparent differences in collection

efficiency. On-line cleaning with a pulse air pressure of

30–40 lb/in2

 was sufficient for cleaning the bag/catalyst

assemblies. Typically, one of five baghouse modules in

service was cleaned every 30–150 minutes.

A comprehensive air toxics emissions monitoring

test was performed at the end of the SNRBTM demonstration test program. The targeted emissions monitored

included trace metals, volatile organic compounds, semivolatile organic compounds, aldehydes, halides, and

radionuclides. These species were a subset of the 189

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 Control Devices Project Fact Sheets 1997 69

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.

Operational Performance

A 3,800-hour durability test of three fabric filters was

completed at the Filter Fabric Development Test Facility

in Colorado Springs in December 1992. No signs of

failure were observed. All of the demonstration tests

were conducted using the 3M Company Nextel ceramic

fiber filter bags or the Owens Corning Fiberglas S-Glass

filter bags. No excessive wear or failures occurred in

over 2,000 hours of elevated temperature operation.

Economic Performance

For a 250-MWe boiler fired with 3.5% sulfur coal and

NOx

 emissions of 1.2 lb/106 Btu, the projected capital

cost of an SNRBTM system is approximately $233/kW

including various technology and project contingency

factors. A combination of fabric filter, SCR, and wet

scrubber for achieving comparable emissions control has

been estimated at $360–400/kW. Variable operating costs

are dominated by the cost of the SO2

 sorbent for a system

designed for 85–90% SO2

 removal. Fixed operating costs

primarily consist of system operating labor and projected

labor and material for the hot baghouse and ash-handling

systems.

Commercial Applications

Commercialization of the technology is expected to develop with an initial larger scale application equivalent to

50–100 MWe. The focus of marketing efforts is being

tailored to match the specific needs of potential industrial, utility, and independent power producers for both

retrofit and new plant construction. SNRBTM is a flexible

technology that can be tailored to maximize control of

SO2

, NOx, or combined emissions to meet current performance requirements while providing flexibility to address

future needs.

Contacts

Kevin Redinger, (330) 829-7719

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

John C. McDowell, FETC, (412) 892-6237

References

• SOx

-NOx-Rox BoxTM Flue Gas Cleanup Demonstration

Final Report. Report No. DOE/PC/89656-T1. The

Babcock & Wilcox Company. September 1995.

(Available from NTIS as DE96003839.)

• 5 MWe SNRBTM Demonstration Facility: Detailed

Design Report. The Babcock & Wilcox Company.

November 1992.

• Comprehensive Report to Congress on the Clean Coal

Technology Program: SOx

-NOx-Rox BoxTM Flue Gas

Cleanup Demonstration Project. The Babcock &

Wilcox Company. Report No. DOE/FE-0145. U.S.

Department of Energy. November 1989. (Available

from NTIS as DE90004458.)

Workers lower one of the catalyst holder tubes into a

mounting plate in the penthouse of the high-temperature

baghouse.
70 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

Combined SO2 /NOx Control Technologies

Enhancing the Use of Coals by

Gas Reburning and Sorbent

Injection

Project completed.

Participant

Energy and Environmental Research Corporation

Additional Team Members

Gas Research Institute—cofunder

State of Illinois, Department of Commerce & Community

Affairs—cofunder

Illinois Power Company—host

City Water, Light and Power—host

Locations

Hennepin, Putnam County, IL (Illinois Power Company’s

Hennepin Plant, Unit 1)

Springfield, Sangamon County, IL (City Water, Light and

Power’s Lakeside Station, Unit 7)

Technology

Energy and Environmental Research Corporation’s gas

reburning and sorbent injection (GR–SI) process

Plant Capacity/Production

Hennepin: tangential-fired 80 MWe (gross), 71 MWe (net)

Lakeside: cyclone-fired 40 MWe (gross), 33 MWe (net)

Coal

Illinois bituminous, 3.0% sulfur

Project Funding

Total project cost $37,588,955 100%

DOE 18,747,816 50

Participant 18,841,139 50

Project Objective

To demonstrate gas reburning to attain at least 60% NOx

reduction along with sorbent injection to capture at least

50% of the SO2

 on two different boiler configurations—

tangentially fired and cyclone-fired—while burning 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. The calcium

compound tested was Ca(OH)2

 (lime). This project demonstrated the GR–SI process on two separate boilers

representing two different firing configurations—a tangentially fired, 80-MWe (gross) boiler at Illinois Power

Company’s Hennepin Plant in Hennepin, IL, and a cyclone-fired, 40-MWe (gross) boiler at City Water, Light

and Power’s Lakeside Station in Springfield, IL. Illinois

bituminous coal containing 3% sulfur was the test coal

for both Hennepin and Lakeside.

A comprehensive test program was conducted at

each of the two sites, operating the equipment over a wide

range of boiler conditions. Over 1,500 hours of operation

was achieved, enabling a substantial amount of data to be

obtained. Intensive measurements were taken to quantify

the reductions in NOx

 and SO2 emissions, the impact on

boiler equipment and operability, and all factors influencing costs.

PromiSORB is a trademark of Energy and Environmental Research

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

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 71

Results Summary

Environmental

• On the tangentially fired boiler, GR–SI NOx

 reductions

of up to 75% were achieved, and an average 67%

reduction was realized at an average gas heat input of

18%.

• GR–SI SO2

 removal efficiency on the tangentially

fired boiler averaged 53% with hydrated lime at a

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.

• There was no change in boiler tube wastage, tube

metallurgy, or projected boiler life.

Preaward Design and Construction

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

7/86 1/91

DOE selected

project (CCT-I)

7/24/86

7/87

Operation initiated,

Lakeside 5/93

Operation completed,

Hennepin 1/93

Construction completed, Hennepin 8/91

Operation initiated, Hennepin 1/91

Construction started, Lakeside 6/90

Environmental monitoring plan completed,

Lakeside 11/15/89

Environmental monitoring plan

completed, Hennepin 10/15/89

NEPA process completed, Lakeside (EA) 6/25/89

Design completed, both sites 5/89

Construction started, Hennepin 5/89

NEPA

process

completed,

Hennepin

(MTF) 5/9/88

Cooperative

agreement

awarded

7/14/87

Construction completed, Lakeside 5/92

Restoration completed,

Hennepin 12/93

Economic

• Capital cost for gas reburning (GR) was approximately

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

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

cost differential and the value of SO2

 emission allowances (because GR replaces some coal with gas, it also

reduces SO2

 emissions).

• Capital cost for sorbent injection (SI) was approximately $50/kW.

• Operating costs for SI were dominated by the cost of

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

 removed.

Project Summary

The GR–SI project demonstrated the success of gas

reburning and sorbent injection technologies in reducing

NOx

 and SO2 emissions. The process design conducted

early in the project combined with the vast amount of

data collected during the testing created a database capable of applying the technology to all major coal-firing

3 4

4/98

Project completed/

final report issued 4/98*

Operation completed,

Lakeside 10/94

Operation

Restoration completed,

Lakeside 12/95
72 Project Fact Sheets 1997 Environmental Control Devices

configurations (tangential-, cyclone-, and wall-fired) on

both utility and industrial units. The emissions control

and performance can be accurately projected as can the

capital and operating costs.

Environmental Performance (Hennepin)

Operational testing, which included optimization testing

and long-term testing, was conducted between January

1991 and January 1993. The GR–SI long-term demonstration tests were carried out from January 1992 to October 1992 to verify the system performance over an extended period. The unit was operated at constant loads

and with the system under dispatch operation where load

was varied to meet plant power output requirements.

With the system under dispatch, the load fluctuated over a

wide range from 40 MWe to a maximum load of 75 MWe.

Over the long-term demonstration period, the average

gross power output was 62 MWe.

For long-term demonstration testing, the average

NOx

 reduction was approximately 67%. The average SO2

removal efficiency was over 53% at a Ca/S molar ratio of

1.75. (Linwood hydrated lime was used throughout these

tests except for a few days when Marblehead lime was

used.) CO emissions were below 50 ppm in most cases

but were higher during operation at low load.

A significant reduction in CO2

 was also measured.

This was due to partial replacement of coal with natural

gas having a lower C/H ratio. This cofiring with 18%

natural gas resulted in a theoretical CO2

 emissions reduction of nearly 8% from the coal-fired baseline level. With

flue gas humidification, electrostatic precipitator (ESP)

collection efficiencies greater than 99.8% and particulate

emissions less than 0.025 lb/106

 Btu were measured even

with an increase in inlet particulate loading resulting from

sorbent injection. These levels were comparable to measured baseline emissions of 0.035 lb/106

 Btu and a collection efficiency greater than 99.5%.

Following the completion of the long-term tests,

three specially prepared sorbents were tested. Two were

manufactured by the participant and contained proprietary

additives to increase their reactivity toward SO2

 and were

referred to as PromiSORBTM A and B. The Illinois State

Geological Survey developed the other sorbent—HighSurface-Area Hydrated Lime in which alcohol is used to

form a material that gives rise to a much higher surface

area than that of conventionally hydrated limes.

The SO2

 capture without GR, at a nominal 1.75 Ca/S

molar ratio, was 53% for PromiSORBTMA, 66% for

PromiSORBTM B, 60% for High-Surface-Area Hydrated

Lime, and 42% for Linwood lime. At a 2.6 Ca/S molar

ratio, the PromiSORBTM B yielded 81% SO2

 removal

efficiency.

Environmental Performance (Lakeside)

Parametric tests were conducted in three series: GR

parametric tests, SI parametric tests, and GR–SI optimization tests. A total of 100 GR parametric tests were conducted at boiler loads of 33, 25, and 20 MWe. Gas heat

input varied from 5% to 26%. The GR parametric tests

achieved a NOx

 reduction of approximately 60% at a gas

heat input of 22–23%. Additional flow modeling and

computer modeling studies indicated that smaller reburning fuel jet nozzles could increase reburning fuel mixing

and thus improve the NOx

 reduction performance.

A total of 25 SI parametric tests were conducted to

isolate the effects of sorbent on boiler performance and

operability. Results showed that SO2

 reduction level

varied with load because of the effect of temperature on

the sulfation reaction. At a Ca/S of 2.0, 44% SO2

 reduction was achieved at full load (33 MWe); 38% SO2

 reduction was achieved at mid-load (25 MWe); and 32% SO2

reduction was achieved at low load (20 MWe).

In the GR–SI optimization tests, the two technologies were integrated. Modifications were made to the

reburning fuel injection nozzles based on the results of

the initial GR parametric tests and flow modeling studies.

The total cross-sectional area of the reburning jets was

decreased by 32% to increase the reburning jet’s penetration characteristics. The decrease in nozzle diameter

increased NOx

 reduction by an additional 3–5% compared

to the initial parametric tests. With GR–SI, total SO2

reductions resulted from partial replacement of coal with

natural gas and sorbent injection. At a gas heat input of

22% and Ca/S molar ratio of 1.8, average NOx

 reduction

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

The flexible lime-sorbent distribution lines lead from

the sorbent splitter to the top of the cyclone-fired boiler at

Lakeside Station.
Environmental Control Devices Project Fact Sheets 1997 73

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 pre-NSPS utility boilers;

the technologies also can be applied

to new utility boilers. With NOx

 and

SO2

 removal exceeding 60% and

50%, respectively, these technologies have the potential to extend the

life of a boiler or power plant and

also provide a way to use higher

sulfur coals.

Illinois Power has retained the

gas-reburning system and City Water, Light & Power has retained the full 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, Senior Vice President, (714) 859-8851

Energy and Environmental Research Corporation

18 Mason

Irvine, CA 92718

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

Jerry L. Hebb, FETC, (412) 892-6079

References

• Enhancing the Use of Coals by Gas Reburning–

Sorbent Injection; Long Term Testing Period, September 1, 1991–January 15, 1993. Report No. DOE/PC/

79796-T40. Energy and Environmental Research

Corporation. February 1995. (Available from NTIS as

DE95011481.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 2: Gas Reburning–Sorbent

Injection at Hennepin Unit 1, Illinois Power Company.

Report No. DOE/PC/79796-T38-Vol. 2. Energy and

Environmental Research Corporation. October 1994.

(Available from NTIS as DE95009448.)

• Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection; Volume 3: Gas Reburning–Sorbent

Injection at Edwards Unit 1, Central Illinois Light

Company. Report No. DOE/PC/79796-T38-Vol. 3.

Energy and Environmental Research Corporation.

October 1994. (Available from NTIS as

DE95009447.)

• Clean Coal Technology: Reduction of NOx

 and SO2

Using Gas Reburning, Sorbent Injection, and Integrated Technologies. Topical Report No. 3, Revision

1. U.S. Department of Energy and Energy and Environmental Research Corporation. September 1993.

(Available from NTIS as DE94007444.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Enhancing the Use of Coals by

Gas Reburning and Sorbent Injection. Energy and

Environmental Research Corporation. Report No.

DOE/FE-0087. U.S. Department of Energy. May

1987. (Available from NTIS as DE87010815.)

The natural gas injector was installed

on the corner of Hennepin Station’s

tangentially fired boiler.
74 Project Fact Sheets 1997 Environmental Control Devices

Plant Capacity/Production

300 MWe

Project Funding

Total project cost $158,607,807 100%

DOE 45,000,000 28

Participant 113,607,807 72

Project Objective

To demonstrate at a 300-MWe utility-scale a combination

of cost-effective and innovative emission reduction and

efficiency improvement technologies, including the

S-H-U wet scrubber system enhanced with formic acid to

increase SO2 removal in a Stebbins tile-lined scrubber,

low-NOx

 burner, urea injection for NOx removal, and a

heat-pipe air preheater.

Technology/Project Description

The S-H-U wet flue gas desulfurization process is a formic-acid-enhanced, wet limestone process, which results

in very high SO2

 removal with low energy consumption

and the production of commercial-grade gypsum.

The flue gas desulfurization absorber is a Stebbins

tile-lined split-module vessel, which has superior corrosion and abrasion resistance, leading to decreased lifecycle costs and reduced maintenance. The split-module

design is constructed below the stack to save space and

provide operational flexibility.

The Nalco Fuel Tech NOxOUT® system is used to

remove NOx

 by injecting urea into the boiler flue gas.

This facet of the project, in conjunction with other combustion modifications, including LNCFSTM Level III

(low-NOx

 burner system), reduces NOx emissions and

produces marketable fly ash.

Environmental Control Devices

Combined SO2 /NOx Control Technologies

Milliken Clean Coal

Technology Demonstration

Project

Participant

New York State Electric & Gas Corporation

Additional Team Members

New York State Energy Research and Development

Authority—cofunder

Empire State Electric Energy Research Corporation—

cofunder

Consolidation Coal Company—technical consultant

Saarberg-Hölter-Umwelttechnik, GmbH—technology

supplier

The Stebbins Engineering and Manufacturing

Company—technology supplier

Nalco Fuel Tech—technology supplier

ABB Air Preheater, Inc.—technology supplier

DHR Technologies, Inc.—operator of advisor system

Location

Lansing, Tompkins County, NY (New York State Electric

& Gas Corporation’s Milliken Station, Units 1 and 2)

Technology

Flue gas cleanup using Saarberg-Hölter-Umwelttechnik’s

(S-H-U) formic-acid-enhanced, wet limestone scrubber

technology; ABB Combustion Engineering’s Low-NOx

Concentric Firing System (LNCFSTM) Level III; Nalco

Fuel Tech’s NOxOUT® urea injection system; Stebbins’

tile-lined split-module absorber; and ABB Air Preheater’s

heat-pipe air-heater system

NOxOUTis a registered trademark of Nalco Fuel Tech.

LNCFS is a trademark of ABB Combustion Engineering, Inc.

PEOA is a trademark of DHR Technologies, Inc.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 75

A heat-pipe air-heater system by ABB Air Preheater,

Inc., reduces both air leakage and the air heater’s flue gas

exit temperature. DHR Technologies, Inc., is providing a

state-of-the-art boiler and plant artificial-intelligencebased control system, Plant Emission Optimization Advisor (PEOATM), to enhance emissions reductions and

boiler efficiencies.

The project has been designed for “total environmental and energy management,” a concept encompassing

low emissions, low energy consumption, improved combustion, upgraded boiler controls, and reduced solid

waste. The system has been designed to achieve at least a

95% SO2

 removal efficiency (or up to 98%) using limestone while burning high-sulfur coal. NOx

 reductions

have been achieved using selective noncatalytic reduction

technology and separate combustion modifications. NOx

emissions have been reduced from 0.65 to 0.40 lb/106 Btu

(38%) by retrofitting the two boilers with low-NOx

 burners. NOxOUT® is expected to reduce NOx

 emissions

from Unit 1 by an additional 15–20%. The system has

zero wastewater discharge and produces marketable byproducts (e.g., commercial-grade gypsum, calcium chloride, and fly ash), minimizing solid waste.

 Pittsburgh, Freeport, and Kittanning coals, with

sulfur contents of 1.5%, 2.9%, and 4.0%, are being used

in the demonstration.

Project Status/Accomplishments

The split module scrubber at Milliken Station began

scrubbing operations for Unit 2 in January 1995. Full

plant operation with Unit 1 incorporated into the splitmodule scrubber began in June 1995.

Heat pipe performance testing at various loads was

completed in July 1996. Further testing on a cleaned heat

pipe was completed in November 1996. Test data are

being compiled, and a report is in final review.

Design coal FGD testing began in May 1996. Testing was delayed due to the sulfur content of coal received

being below design specifications for the scrubber. Testing resumed in November 1997 and will continue until

summer of 1998.

Mist eliminator testing is complete; a report is expected to be issued in first quarter 1998.

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

Commercial Applications

The S-H-U SO2

 removal process, the Nalco NOxOUT®

noncatalytic reduction process, Stebbins’ tile-lined splitmodule absorber, and ABB Air Preheater’s heat-pipe airheater technology are applicable to virtually all power

plants, in both retrofit and greenfield applications, at any

size. The space-saving design features of the technologies, combined with the production of marketable byproducts, offer significant incentives to generating stations with limited space.

Four sales of NOxOUT®, worth more than $3 million, have been made. PEOATM has been sold to one

utility; several bids are pending. S-H-U has formed a

U.S. company, SHN, to market the scrubber; several bids

are pending.

Ground breaking/construction started 4/93

Design completed 4/93

NEPA process completed

(EA) 8/18/93

12/98

Operation completed 7/98*

Project completed/final report issued 12/98*

Operation initiated on Unit 2 1/95

6/95

Design and Construction

Environmental

monitoring

plan completed

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

Construction completed 6/95
76 Project Fact Sheets 1997 Environmental Control Devices

Environmental Control Devices

Combined SO2 /NOx Control Technologies

Commercial Demonstration of

the NOXSO SO2/NOx Removal

Flue Gas Cleanup System

Participant

NOXSO Corporation

Additional Team Members

Olin Corporation—cofunder and host

Gas Research Institute—cofunder

Electric Power Research Institute—cofunder

W.R. Grace and Company—cofunder

Morrison Knudsen-Ferguson—engineer

Location

Site under negotiation

Technology

NOXSO Corporation’s dry, regenerable flue gas cleanup

process

Plant Capacity/Production

30 MWe

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%.

A full-scale design based on data from the proof-ofconcept facility at Ohio Edison’s Toronto power plant is

in preparation.
1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

*Projected date

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 77

Project Status/Accomplishments

NOXSO is searching for a new host site to demonstrate

the NOXSO process. Alcoa Generating Corporation

chose to cancel the host site agreement when NOXSO

was unable to obtain full project financing by January 31,

1997, as specified in the agreement.

In June 1997, the court accepted NOXSO’s petition

for voluntary bankruptcy. NOXSO will continue the

process of selecting a new host site for demonstrating the

NOXSO technology.

Commercial Applications

The NOXSO process is applicable for retrofit or new

facilities. The process is suitable for utility and industrial

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.

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

Note: Milestone schedule

pending project restructuring

Novation of cooperative agreement with NOXSO Corp. 8/94

Selected new host site, Alcoa 8/94

Project definition phase completed 10/94

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

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.
78 Project Fact Sheets 1997 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 (SNCR) sysDRB-XCL is a registered trademark of The Babcock & Wilcox Company.

tem 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

3 4 1 2

Environmental Control Devices Project Fact Sheets 1997 79

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Preaward Operation Design and 8/92

Construction

12/89 3/91

NEPA process completed (MTF) 9/27/90

Design initiated 6/90

DOE selected project

(CCT-III) 12/19/89

Ground breaking/construction started 5/21/91

Design completed 3/92

Preoperational tests initiated 6/92

Operation initiated 8/92

Construction completed 8/92

Environmental

monitoring plan

completed

8/5/93

Results Summary

Environmental

• With maximum overfire air (24% of total combustion

air), a NOx

 reduction of 62–69% was achieved across

the 50–110-MWe load range.

• DRB-XCL® burners with minimum overfire air reduced NOx

 emissions by more than 63% under steady

state conditions.

• NOx

 reductions were decreased by 10–25% under

load-following conditions.

• The SNCR system, using both stationary and retractable injection lances in the furnace, provided NOx

removal of 30–50% at an ammonia (NH3) slip of

10 ppm, thus increasing performance of the total NOx

control system to greater than 80% NOx reduction.

• SO2 removal with calcium-based dry sodium injection

into the boiler at approximately 1,000 oF was less than

10%, and with injection into the fabric filter duct, SO2

removal was less than 40% at a Ca/S ratio of 2.0.

• Sodium bicarbonate injection before the air heater

demonstrated a long-term SO2

 removal of approximately 70% at a normalized stoichiometric ratio (NSR)

of 1.0.

• Sodium sesquicarbonate injection ahead of the fabric

filter achieved 70% SO2

 removal at an NSR of 2.0.

• NO2 emissions were generally higher when using

sodium biocarbonate than when using sodium sesquicarbonate.

• Integrated SNCR and sodium dry sorbent injection

tests showed reduced NH3

 and NO2 emissions.

• During four series of air toxics tests, the fabric filter

successfully removed nearly all trace metal emissions

and 80% of the mercury.

Operational

• Arapahoe 4 operated more than 34,000 hours after

combustion modifications were complete.

• Availability factor was over 91%.

• Operational test objectives were met or exceeded.

• Control system modifications and additional operator

training may be necessary to improve NOx

 control

under load-following conditions.

• Buildup of a hard ash cake on the fabric filter occurred

during operation of dry sorbent injection of calcium

hydroxide with humidification.

• Temperature differential between the top and bottom

surfaces of the Advanced Retractable Injection Lances

(ARIL) caused the lances to bend downwards

12–18 inches. Alternative designs corrected the

problem.

• Concurrent operation of SNCR and the dry sodium

injection system caused an NH3

 odor problem around

the ash silo, which appeared to be related to the rapid

change in pH due to the sodium in the ash.

Economic

• Data not available.

1/98

Operation completed 12/96

Cooperative agreement awarded 3/11/91

Project completed/

final report issued

1/98*
80 Project Fact Sheets 1997 Environmental Control Devices

Project Summary

The Integrated Dry NOx/SOx Emissions Control System

combines five major control technologies to form an

integrated system to control both NOx

 and SO2. The lowNOx

 combustion system consists of 12 Babcock & Wilcox DRB-XCL® low-NOx

 burners installed on the roof.

The low-NOx combustion system also incorporated three

Babcock & Wilcox dual-zone NOx ports added to each

side of the furnace approximately 20 ft below the boiler

roof. These ports injected up to 25% of the total combustion air through the furnace sidewalls.

Additional NOx

 control was achieved with the ureabased SNCR system. The SNCR when used with the

low-NOx

 combustion system would allow the goal of

70% NOx

 reduction to be reached. Further, the SNCR

system was an important part of the integrated system,

interacting synergistically with the dry sorbent injection

(DSI) system to reduce NO2

 formation and ammonia slip.

Initially the SNCR was designed and installed to

incorporate two levels of injectors with 10 injectors at

each level, with the exact location being based on temperature profiles that existed with the original combustion

system. However, the retrofit low-NOx

 combustion system resulted in a decrease in furnace exit gas temperature

by approximately 200 oF, thus moving one injector level

out of the temperature regime needed for effective SNCR

operation. With only one operational injector level, the

load-following performance was compromised.

In order to achieve the desirable NOx

 reduction at

low loads, two alternatives were explored. First, it was

shown that ammonia was more effective than urea at low

loads. An on-line urea-to-ammonia conversion system

was installed and resulted in improved low-load performance, but the improvement was not as large as desired

for the lowest load (60 MWe). The second approach was

to install injectors in the higher temperature regions of the

furnace. This was achieved by installing two NOELL

ARIL lances into the furnace through two unused

sootblower ports. Each lance was nominally 4 inches in

was installed approximately 100 ft 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

(50–110 MWe). The results indicated that the low-NOx

burners were responsible for most of the NOx reduction.

The original design of two rows of injector nozzles

proved relatively ineffective because one row of injectors

was in a region where the flue gas temperature was too

low for effective operation. At full load, the original

design achieved NOx

 reduction of 45%. However, the

performance decreased significantly as load decreased; at

60 MWe, NOx

 removal was limited to about 11% with an

ammonia slip of 10 ppm. The addition of the retractable

lances improved low-load performance of the urea-based

SNCR injection system. The ability to follow the temperature window by rotating the ARIL lances proved to

be an important feature in optimizing performance. As

a result, the SNCR system obtained NOx

 removal of

30–50%, at a NH3

 slip limited to 10 ppm at the fabric

filter inlet, thus increasing the total NOx

 control system

reduction to greater than 80%, significantly exceeding the

goal of 70%.

Testing of calcium hydroxide injection at the economizer without humidification resulted in SO2

 removal in

the range of 5–8% at a Ca/S molar ratio of 2.0. Higher

SO2

 removal was achieved with duct injection of calcium

hydroxide and humidification, with SO2

 removals approaching 40% at a Ca/S molar ratio of 2.0 and approachto-saturation temperature of 20–30 oF. Sodium-based

reagents were found to be much more effective than

Public Service Company of Colorado demonstrated lowNOx

 burners, induct injection, and SNCR at Arapahoe Station

near Denver.

diameter and approximately 20 ft 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 DSI system that could

inject either calcium- or sodium-based reagents into the

flue gas upstream of the fabric filter. Sorbent was injected into three locations: (1) air heater exit where the

temperature was approximately 260 oF, (2) 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
Environmental Control Devices Project Fact Sheets 1997 81

calcium-based sorbents and achieved significantly higher

SO2

 removals during dry injection. Sodium bicarbonate

injection before the air heater demonstrated short-time

SO2

 removals of 80%. Long-term reductions of 70%

were achieved with an NSR of 1.0. Sodium sesquicarbonate achieved 70% removal at an NSR of 2.0 when

injected ahead of the fabric filter. A disadvantage of the

sodium-based process was that it converted some existing

NO to NO2

. Even though 5–10% of the NOx was reduced

during the conversion process, the net NO2

 exiting at the

stack was increased. While NO is colorless, small quantities of brown/orange NO2

 caused a visible plume.

A major objective was the demonstration of the

integrated performance of the NOx

 emissions control

systems and the SO2

 removal technologies. The results

showed that a synergistic benefit occurred during the

simultaneous operation of the SNCR and the sodium DSI

system in that the NH3

 slip from the SNCR process suppressed the NO2

 emissions associated with NO to NO2

oxidation by dry sodium injection.

Four series of air toxic tests were completed. Results

indicated that the fabric filter successfully removed nearly

all trace metal emissions and nearly 80% of the mercury

emissions. Radionuclides, semi-volatile organic compounds, and dioxins/furans were below or very near their

detectable limits.

Operating Performance

Construction began in July 1991 and was completed in

August 1992. The test program began in August 1992

and was scheduled for completion in June 1994. However, the addition of the new SNCR injection location and

alternative lance design tests extended the test program

through December 1996. The Arapahoe Unit 4 operated

more than 34,000 hours after combustion modifications

were completed. The availability factor during the period

was over 91%.

The operational test objectives were met or exceeded. However, there were operational lessons learned

during the demonstration that will be useful in future

deployment of the technologies. These “lessons” are

summarized below.

It was found that control system modifications and

additional operator training may be necessary to more

accurately control NOx

 reductions using low-NOx burners

under load-following conditions.

During the operation of the duct injection of calcium

hydroxide and humidification under load-following conditions, fabric filter pressure-drop significantly increased.

This was caused by the buildup of a hard ash cake on the

fabric filter bags that could not be cleaned under normal

reverse-air cleaning. The heavy ash cake was caused by

the humidification system, but it was not determined

whether the problem was due to operation at 30 oF approach-to-saturation temperature or an excursion caused

by a rapid decrease in load.

The performance of the ARIL lances in NOx

 removal

was good; however, the location created some operational

problems. A large differential heating pattern between

the top and bottom of the lance caused a significant

amount of thermal expansion along the upper surface of

the lance. This caused the lance to bend downwards

approximately 12–18 inches after 30 minutes of exposure.

Eventually the lances become permanently bent, thus

making insertion and retraction difficult. The problem

was partially resolved by adding cooling slots at the end

of the lance. An alternative lance design provided by

Diamond Power Specialty Company (a division of Babcock & Wilcox) was tested and found to have less bending due to evaporative cooling, even though its NOx

 reduction and NH3

 slip performance were slightly less than

for the ARIL lance.

When the SNCR and dry sodium systems were operated concurrently, an NH3 odor problem was encountered

around the ash silo. Reducing the NH3

 slip set points to

the range of 4–5 ppm reduced the ammonia concentration

in the fly ash to the 100–200 ppm range but the odor

persisted. It was found that the problem was related to

the rapid change in pH due to the presence of sodium in

the ash. The rapid development of the high pH level and

the attendant release of the ammonia vapor appear to be

related to the wetting of the fly ash necessary to minimize

fugitive dust emissions during transportation and handling. Handling ash in dry transport trucks solved this

problem.

Economic Performance

Economic analysis is under way.

Commercial Applications

Either the entire Integrated Dry NOx

/SO2 Emissions Control System or the individual technologies are applicable

to most utility and industrial coal-fired units and provide

lower capital-cost alternatives to conventional wet flue

gas desulfurization processes. They can be retrofitted

with modest capital investment and downtime, and their

space requirements are substantially less. They can be

applied to any unit size but are mostly applicable to the

older, small- to mid-size units.

Contacts

Terry Hunt, Project Manager, (303) 571-7113

Public Service Company of Colorado

550 15th Street, Suite 880

Denver, CO 80202

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

Jerry L. Hebb, FETC, (412) 892-6079

References

• Hunt, Terry, et al. “Integrated Dry NOx

/SO2 Emissions

Control System: Performance Summary.” Fifth Annual Clean Coal Technology Conference: Technical

Papers. January 1997.
82 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced electric power generating systems

employ the technologies that enable the efficient and

environmentally superior generation of electric power.

The advanced electric power generation projects

selected under the CCT Program are responsive to the

long-term capacity expansion needs requisite to meeting long-term demand and offsetting nuclear retirements and to the stringent CAAA emission limits

effective in 2000. These technologies are characterized

by high thermal efficiency, very low pollutant emissions, reduced CO2

 emissions, few solid waste problems, and enhanced economics. Advanced electric

power generation systems may be deployed in modules, allowing phased construction to match demand

growth more predictably and to meet the requirements

of smaller municipal, rural, and nonutility generators.

There are five generic technology approaches

being used to demonstrate advanced electric power

generation systems under the CCT Program. The

characteristics of these five technologies are outlined

here, and the specific projects and technologies are

presented in more detail in the fact sheets.

Fluidized-Bed Combustion

Fluidized-bed combustion (FBC) reduces emissions of SO2

 and NOx by controlling combustion

parameters and by injecting a sorbent (such as crushed

limestone) into the combustion chamber along with the

coal. Pulverized coal mixed with the limestone is

fluidized on jets of air in the combustion chamber.

Sulfur released from the coal as SO2 is captured by the

sorbent in the bed to form a solid calcium compound

that is removed with the ash. The resultant waste is a

dry, benign solid that can be disposed of easily or used

in agricultural or construction applications. More than

90 percent of the SO2 released can be captured this

way.

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

the fluidized mixing of the fuel and sorbent enhances

both combustion and sulfur capture. The operating

temperature range is about half that of a conventional

boiler and below the temperature at which thermally

induced NOx is formed. In fact, fluidized-bed NOx

emissions are about 70–80 percent lower than those for

conventional pulverized coal boilers. Thus, fluidizedbed combustors substantially reduce both SO2

 and NOx

emissions. Also, fluidized-bed combustion has the

capability of utilizing high-ash coal, whereas conventional pulverized coal units must limit ash content to

relatively low levels.

Two parallel paths were pursued in fluidized-bed

development—bubbling and circulating beds. Bubbling

beds use a dense fluid bed and low fluidization velocity

to effect good heat transfer and mitigate erosion of an

in-bed heat exchanger. Circulating fluidized beds use a

relatively high fluidization velocity (entrained bed) in

conjunction with hot cyclones to separate and recirculate the particulate from the flue gas before it passes to

a heat exchanger. Hybrid systems have since evolved

from these two basic approaches.

Fluidized-bed combustion can be either atmospheric (AFBC) or pressurized (PFBC). AFBC operates at atmospheric pressure while PFBC operates at

pressure 6–16 times higher. PFBC offers potentially

higher efficiency and, consequently, reduced operating

costs and waste relative to AFBC.

Second-generation PFBC integrates the combustor

with a pyrolyzer (coal gasifier) to fuel a gas turbine

(topping cycle), the waste heat from which is used to

generate steam for a steam turbine (bottoming cycle).

The inherent efficiency of the gas turbine and waste

heat recovery in this combined-cycle mode significantly increases overall efficiency. Such advanced PFBC

systems have the potential for efficiencies of over 50

percent.

Tri-State Generation and Transmission Association’s

Nucla Station was host to demonstration of the world’s first

utility-scale AFBC.

Advanced Electric Power Generation Technology
Advanced Electric Power Generation Project Fact Sheets 1997 83

Integrated Gasification Combined

Cycle

The integrated coal gasification combined-cycle

process has four basic steps: (1) fuel gas is generated

by coal reacting with high-temperature steam and an

oxidant (oxygen or air) in a reducing atmosphere;

(2) gas is either passed directly to a hot-gas cleanup

system to remove particulates and sulfur and nitrogen

compounds or first cooled to produce steam and then

cleaned conventionally; (3) clean fuel gas is combusted

in a gas turbine generator to produce electricity; and

(4) residual heat in the hot exhaust gas from the turbine

is recovered in a heat recovery steam generator, and

the steam is used to produce additional electricity in a

steam turbine generator.

Integrated gasification combined-cycle (IGCC)

systems are among the cleanest and most efficient of

the emerging clean coal technologies. Sulfur, nitrogen

compounds, and particulates are removed before the

fuel is burned in the gas turbine, that is, before combustion air is added. For this reason, there is a much

lower volume of gas to be treated than in a postcombustion scrubber.

The gas stream must be cleaned to a high degree,

not only to achieve low emissions, but to protect

downstream components, such as the gas turbine, from

erosion and corrosion. In a coal gasifier, the sulfur in

the coal is released in the form of hydrogen sulfide

rather than as SO2

, which is the case in coal combustion. In some IGCC systems, much of the sulfurcontaining gas is captured by a sorbent injected into the

gasifier. Others use existing commercial hydrogen

sulfide removal processes, which remove up to

99 percent of the sulfur but require the fuel to be

cooled, with some efficiency penalty. Therefore, hotgas cleanup systems are being demonstrated. In these

cleanup systems, the hot coal gas is passed through a

bed of metal oxide particles, such as supported zinc

oxides. Zinc oxide can absorb sulfur contaminants at

temperatures in excess of 1,000 oF, and the compound

can be regenerated and reused with little loss of effectiveness. Produced during the regeneration stage are

salable sulfur, sulfuric acid, or 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 by the

combustion air can be held to well within allowable

levels by staged combustion in the turbine or by adding

moisture to hold down flame temperature.

Integrated Gasification Fuel Cell

A typical fuel cell system using coal as fuel includes a coal gasifier with a gas cleanup system, a fuel

cell to use the coal gas to generate electricity (direct

current) and heat, an inverter to convert direct current

to alternating current, and a heat-recovery system. The

heat-recovery system would be used to produce additional electric power in a bottoming steam cycle.

Energy conversion in fuel cells is potentially more

efficient (up to 60 percent, depending on fuel and type

of fuel cell) than traditional energy conversion devices.

Fuel cells directly transform the chemical energy of a

fuel and an oxidant (air or oxygen) into electrical

energy instead of going through an intermediate step

(i.e., burner, boiler, turbines, and generators). Each

fuel cell includes an anode and a cathode separated by

an electrolyte layer. In a typical fuel cell, coal gas is

supplied to the anode and air is supplied to the cathode

to produce electricity and heat.

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.
84 Project Fact Sheets 1997 Advanced Electric Power Generation

Golden Valley Electric Association is adding capacity to

its Healy Plant with a 50-MWe slagging combustor unit using

65% waste coal.

Coal-Fired Diesel

The diesel-engine-driven electric generation

system is fueled with a coal-oil or coal-water slurry.

The hot exhaust from the diesel engine is routed

through a heat-recovery unit to produce steam for a

steam-turbine electric generating system (combined

cycle). Environmental control systems for SO2

, NOx,

and particulate removal treat the cooled exhaust before

release to the atmosphere. The diesel system is expected to achieve 45–48 percent thermal efficiencies. The

10–100-MWe capacity range of the technology would

be most applicable to small utilities (municipalities and

rural cooperatives) and industrial cogeneration.

Slagging Combustor

Many new coal-burning technologies are designed

to remove the coal ash as molten slag in the combustor

rather than the furnace. Most of these slagging combustors are based on a cyclone combustor concept. In a

cyclone combustor, coal is burned in a separate chamber outside the furnace cavity. The hot combustion

gases then pass into the boiler where the actual heat

exchange takes place.

The advantage of a cyclone combustor is that the

ash is kept out of the furnace cavity where it could

collect on boiler tubes and lower heat transfer efficiency. To keep ash from being blown into the furnace, the

combustion temperature is kept so hot that mineral

impurities melt and form slag, hence the name slagging

combustor. A vortex of air (the cyclone) forces the slag

to the outer walls of the combustor where it can be

removed as waste. Because ash removal efficiency is

high, there is no degradation of boiler tube surfaces to

reduce boiler efficiency over time.

Results to date show that by positioning air injection ports so that coal is combusted in stages, NOx

emissions can be reduced by 70–80 percent. Injecting

limestone into the combustion chamber has the potential to reduce sulfur emissions by 90 percent in combination with a spray-dryer absorber. Advanced slagging

combustors could replace oil-fired units in both utility

and industrial applications or be used to retrofit older,

conventional cyclone boilers.

Status of Projects

There are 11 advanced electric power generating

projects in the CCT Program of which five are fluidized-bed combustion systems, four are IGCCs, and two

are advanced combustion/heat engine systems (coal

diesel and advanced slagging combustor). Of the five

fluidized-bed combustion projects, two have successfully completed demonstration (one PFBC and one

AFBC), and the other three are in the project definition

and design phase. Of the four IGCC projects, three are

in operation and one is in the project definition and

design phase. Of the two remaining advanced combustion/heat engine projects, construction was completed

in November 1997 on the advanced slagging combustor project, and the coal diesel project is in the project

definition and design phase.

Exhibit 30 summarizes the process characteristics

and size of the advanced electric power generating

technologies presented in more detail in the project fact

sheets.
Advanced Electric Power Generation Project Fact Sheets 1997 85

Exhibit 30

CCT Program Advanced Electric Power Generation Technology Characteristics

Project Process Size Fact Sheet

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project Pressurized circulating fluidized-bed combustion 157 MWe 86

McIntosh Unit 4B Topped PCFB McIntosh 4A with pyrolyzer and topping combustor 157 MWe + 12 MWe 88

Demonstration Project

Tidd PFBC Demonstration Project Pressurized bubbling fluidized-bed combustion 70 MWe 90

Jacksonville Electric Authority Large-Scale CFB Atmospheric circulating fluidized-bed combustion 265 MWe 94

Combustion Demonstration Project

Nucla CFB Demonstration Project Atmospheric circulating fluidized-bed combustion 100 MWe 96

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project Oxygen-blown, slagging fixed-bed gasifier with cold 477 MWe 100

gas cleanup, fuel cell slipstream

Piñon Pine IGCC Power Project Air-blown, fluidized-bed gasifier with hot gas cleanup 99 MWe 102

Tampa Electric Integrated Gasification Oxygen-blown, entrained-flow gasifier with hot and 250 MWe 104

Combined-Cycle Project cold gas cleanup

Wabash River Coal Gasification Oxygen-blown, two-stage entrained-flow gasifier with 262 MWe 106

Repowering Project cold gas cleanup

Advanced Combustion/Heat Engines

Healy Clean Coal Project Advanced slagging combustor, spray dryer with sorbent 50 MWe 108

recycle

Clean Coal Diesel Demonstration Project Coal-fueled diesel engine 6.4 MWe 110
86 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB

Demonstration Project

Participant

City of Lakeland, Department of Electric & Water

Utilities

Additional Team Members

Foster Wheeler Energy Corp.—supplier of hightemperature combustor and heat exchanger; engineer

Westinghouse Electric Corporation—supplier of PCFB,

hot gas filter, gas turbine, and steam turbine

Location

Lakeland, Polk County, FL (Lakeland’s McIntosh Power

Station, Unit 4)

Technology

Foster Wheeler’s PCFB technology integrated with

Westinghouse’s hot gas filter and power generation

technologies

Plant Capacity/Production

157 MWe (net)

Project Funding

Total project cost $186,588,000 100%

DOE 93,252,864 50

Participant 93,335,136 50

Project Objective

To demonstrate Foster Wheeler’s PCFB technology

coupled with Westinghouse’s hot gas filter and power

generation technologies, which represent a cost-effective,

high-efficiency, low-emissions means of adding generating capacity at greenfield sites or in repowering applications.

Technology/Project Description

The project resulted from a restructuring of the DMEC-1

PCFB Demonstration Project awarded under the third

solicitation. In the first of the two Lakeland projects,

McIntosh Unit 4 is being repowered with a PCFB combustor. 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 with water to form a

paste, which is pumped into the combustion chamber by

piston pumps commonly used in the cement industry.

Combustion takes place at approximately 1,560–1,600 °F

at a pressure of about 200 psig. The resulting flue gas

and fly ash leaving the combustor pass through a cyclone

and hot gas filter where the particulates are removed. The

hot gas leaving the filter is expanded through a gas turbine, which is based on a standard Westinghouse

251B12, single-shaft, cold-end-drive industrial machine.

The gas inlet temperature of less than 1,650 °F allows

for a simplified turbine shaft and blade-cooling system.

The hot gas leaving the gas turbine passes through a heat

recovery unit used to generate steam. Heat recovered

from both the combustor and heat recovery unit is used

to generate steam to power a reheat steam turbine. Approximately 15% of the gross power is derived from the

gas turbine, with the steam turbine contributing the

remaining 85%.

The repowered unit is being designed to burn a

range of coals, including the current Eastern Kentucky

coal burned in Unit 3 and high-ash, high-sulfur coals that

are expected to be available at a lower cost. Limestone
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Project Fact Sheets 1997 87

will be purchased from nearby Florida quarries. Ash will

be disposed of in landfills or sold to others.

Project Status/Accomplishments

Negotiations are in progress with all participants to transfer the cooperative agreement to the City of Lakeland,

Department of Electric & Water Utilities. The project

schedule anticipates the start of commercial operation of

the PCFB (McIntosh 4A) in the winter of 2001. In parallel with the first 2 years of operation of the PCFB will be

the design, fabrication, and construction of the topped

PCFB technology (McIntosh 4B), with a planned start of

operation in late 2003.

The Lakeland City Council gave approval for the 10-

year plan of Lakeland’s Department of Electric & Water

Utilities in September 1997. The plan included this clean

coal project.

Commercial Applications

The project serves as a stepping stone to move the PCFB

technology to readiness for widespread commercial deployment in the post-2000 time frame. The project will

include the first commercial applications of hot-gas particulate cleanup and one of the first to use a nonruggedized gas turbine in a pressurized fluidized-bed

application.

The combined-cycle PCFB system permits the combustion of a wide range of coals, including high-sulfur

coals, and would compete with the bubbling-bed PCFB

system. PCFB can be used to repower or replace conventional power plants. Because of modular construction

capability, PCFB generating plants permit utilities to add

economical increments of capacity to match load growth

and/or to repower plants using existing coal- and wastehandling equipment and steam turbines. Another advantage for repowering applications is the compactness of

the process due to pressurized operation, which reduces

space requirements per unit of energy generated.

The projected net heat rate for the system is approximately 8,100 Btu/kWh (based on HHV), which equates

to over 42% efficiency.

Environmental attributes include in-situ sulfur removal of 95%, NOx

 emissions less than 0.3 lb/106 Btu,

1991 1999 2000 1996 1997 2001 2002 2003 2004 2005 2006

12/89

DOE selected project

(CCT-III) 12/19/89

Cooperative agreement

awarded 8/1/91

11/01 11/03

**

**Years omitted

Design and Construction Operation

Design completed 9/99*

Groundbreaking/construction

started 10/99*

NEPA process completed (EIS)

10/99*

Environmental monitoring plan

completed 8/01*

8/91

Operation initiated 11/01*

Preoperational tests initiated 11/01*

Construction completed 11/01* Project completed/

final report issued 11/03*

Operation completed 11/03*

Site change approved

(Lakeland) 10/29/96

Preaward

**

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.
88 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

McIntosh Unit 4B Topped PCFB

Demonstration Project

Participant

City of Lakeland, Department of Electric & Water

Utilities

Additional Team Members

Foster Wheeler Energy Corp.—supplier of carbonizer;

engineer

Westinghouse Electric Corporation—supplier of topping

combustor and high-temperature filter

Location

Lakeland, Polk County, FL (Lakeland’s McIntosh Power

Station, Unit 4)

Technology

Fully integrated second-generation PCFB technology with

the addition of a carbonizer island that includes

Westinghouse’s multi-annular swirl-burner (MASB)

topping combustor

Plant Capacity/Production

12 MWe (net) addition to the 157 MWe (net) McIntosh

4A project

Project Funding

Total project cost $218,741,300 100%

DOE 109,204,000 50

Participant 109,537,300 50

Project Objective

To demonstrate topped PCFB technology in a fully commercial power generating setting, thereby advancing the

technology for future plants that will operate at higher gas

turbine inlet temperatures and that are expected to achieve

cycle efficiencies in excess of 45%.

Technology/Project Description

The project resulted from a restructuring of the Four

Rivers Energy Modernization Project awarded under the

fifth solicitation. The Four Rivers project was to demonstrate the integration of a gasifier and topping combustor

(topping cycle) with the PCFB technology. By utilizing a

segmented approach, Lakeland will be able to demonstrate both PCFB (McIntosh 4A) and topped PCFB

(McIntosh 4B) technologies 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 2,000 °F. The

gas is expanded through the turbine, cooled in a heat

recovery unit, and exhausted to the stack. The net impact of the addition of the topping cycle is an increase in

power output of 12 MWe and an associated improvement

in plant heat rate of approximately 600 Btu/kWh. The

coal and limestone used in McIntosh 4B are the same as

those used in McIntosh 4A.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Project Fact Sheets 1997 89

1996 1997

coal-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 discharge of approximately 0.03 lb/106

 Btu. Although the

system will generate a slight increase in solid waste as

compared to conventional systems, the material is dry,

readily disposable, and potentially usable material.

1994 1999 2000 2001 2002 2003 2004 2005 2006

5/93

DOE selected project

(CCT-V) 5/4/93

Cooperative agreement

awarded 7/28/94; effective

8/1/94

Design and Construction

11/03 11/05

Project completed/

final report issued 11/05*

Site change approved (Lakeland) 10/29/96 Operation completed 11/05*

**

**Years omitted

Operation

NEPA process completed (EIS) 10/99*

Design initiated 11/01*

Groundbreaking/construction started 9/02*

Design completed 9/02*

Operation initiated 11/03*

Preoperational tests initiated 11/03*

Construction completed 11/03*

Environmental monitoring plan completed 8/03*

8/94

Preaward

Project Status/Accomplishments

Negotiations are in progress with all participants to transfer of the cooperative agreement to the City of Lakeland,

Department of Electric & Water Utilities. The project

schedule anticipates the start of commercial operation of

the PCFB (McIntosh 4A) in the winter of 2001. In parallel with the first 2 years of operation of the PCFB will be

the design, fabrication, and construction of the topped

PCFB technology (McIntosh 4B), with a planned start of

operation in late 2003.

The Lakeland City Council has approved the utility

department’s 10-year plan, which includes this project.

Commercial Applications

The commercial version of the topped PCFB technology

will have a greenfield net plant efficiency of 45% (which

equates to a heat rate approaching 7,500 Btu/kWh, based

on HHV). In addition to higher plant efficiencies, the

plant will (1) have a cost of electricity that is projected to

be 20% lower than that of a conventional pulverized-

**
90 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

Tidd PFBC Demonstration

Project

Project completed.

Participant

The Ohio Power Company

Additional Team Members

American Electric Power Service Corporation—

designer, constructor, and manager

The Babcock & Wilcox Company—technology supplier

Ohio Coal Development Office—cofunder

Location

Brilliant, Jefferson County, OH (Ohio Power

Company’s Tidd Plant, Unit 1)

Technology

The Babcock & Wilcox Company’s pressurized fluidizedbed combustion (PFBC) system (under license from ABB

Carbon)

Plant Capacity/Production

70 MWe

Coal

Ohio bituminous, 2–4% sulfur

Project Funding

Total project cost $189,886,339 100%

DOE 66,956,993 35

Participant 122,929,346 65

Project Objective

To verify expectations of PFBC economic, environmental, and technical performance in a combined-cycle

repowering application at utility scale; and to accomplish

greater than 90% SO2

 removal and NOx emission level of

0.2 lb/106

 Btu at full load.

Technology/Project Description

Tidd was the first large-scale operational demonstration

of PFBC in the United States and one of only five worldwide. The 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 ft in diameter and 70 ft high. The facility was

designed so that one-seventh of the hot gases produced

could be routed to a slipstream to test advanced filtration

devices.

The Tidd facility is a bubbling fluidized-bed combustion process operating at 12 atm (175 psi). Pressurized combustion air is supplied by the turbine compressor

to fluidize the bed material, which consists of a coalwater fuel paste, coal ash, and a dolomite or limestone

sorbent. Dolomite or limestone in the bed reacts with

sulfur to form calcium sulfate, a dry, granular bed-ash

material, which is easily disposed of or is usable as a byproduct. A low bed-temperature of about 1,600 oF limits

NOx

 formation.

The hot combustion gases exit the bed vessel with

entrained ash particles, 98% of which are removed when

the gases pass through cyclones. The cleaned gases are

then expanded through a 15-MWe gas turbine. Heat

from the gases exiting the turbine, combined with heat

from a tube bundle in the fluid bed, generates steam to

drive an existing 55-MWe steam turbine.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Project Fact Sheets 1997 91

Results Summary

Environmental

• SO2 removal efficiency of 90% was achieved at full

load with a calcium-to-sulfur molar ratio (Ca/S) of 1.1

and temperature of 1,580 oF.

• SO2

 removal efficiency of 95% was achieved at full

load with a Ca/S of 1.5 and temperature of 1,580 oF.

• NOx

 emissions were 0.15–0.33 lb/106 Btu.

• CO emissions were less than 0.01 lb/106

 Btu.

• Particulate emissions were less than 0.02 lb/106

 Btu.

Operational

• Combustion efficiency was 99.6%.

• Heat rate was 10,280 Btu/kWh based on higher heating value of the fuel and gross electrical output, or

33.2% efficiency, because of the small-scale retrofit

application.

• High-temperature particulate filtration system, a silicon carbide candle filter array, achieved 99.99% filtration efficiency on a mass basis.

• PFBC boiler demonstrated commercial readiness.

• ASEA Stal GT-35P gas turbine proved capable of

operating commercially in a PFBC flue gas environment.

Economic

Because the Tidd plant was a comparatively small-scale

facility, economic performance would not be representative of a larger utility-scale plant using PFBC technology.

Project Summary

The Tidd PFBC technology is a bubbling fluidized-bed

combustion process operating at 12 atmospheres

(175 psi). Fluidized combustion is inherently efficient.

A pressurized environment further enhances combustion

efficiency, allowing very low temperatures that mitigate

thermal NOx

 generation, flue gas/sorbent reactions that

increase sorbent utilization, and flue gas energy that is

used to drive a gas turbine. The latter contributed significantly to system efficiency because of the high efficiency

of gas turbines and the availability of gas turbine exhaust

heat that can be applied to the steam cycle. A bed design

temperature of 1,580 oF was established because it was

the maximum allowable temperature at the gas turbine

inlet and was well below temperatures for coal ash fusion, thermal NOx

 formation, and alkali vaporization.

Coal crushed to 1⁄4 inch or less was injected into the

combustor as a coal/water paste containing 25% water by

weight. Crushed sorbent, either dolomite or limestone,

was injected into the fluidized bed via two pneumatic

feed lines, supplied from two lock hoppers. An alternative sorbent feed system was added in 1993; it injected

sorbent of various sizes directly into the coal-water paste

feed system. The system provided the means to assess a

wet-feed sorbent system while providing the opportunity

to better control sorbent size.

In 1992, a 10-MWe advanced hot gas cleanup system

was installed and commissioned as part of a research and

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
92 Project Fact Sheets 1997 Advanced Electric Power Generation

development program and not part of the CCT demonstration. This system used ceramic candle filters to clean

one-seventh of the exhaust gases from the PFBC system.

The hot gas cleanup system unit replaced one of the seven

cyclones that was normally used for final gas cleanup.

The Tidd PFBC demonstration plant accumulated

11,444 hours of coal-fired operations during its 54

months of operation. The unit completed 95 parametric

tests, including continuous coal-fired runs of 28, 29, 30,

31, and 45 days. Ohio bituminous coals having sulfur

contents of 2–4% were used in the demonstration.

Environmental Performance

Testing showed that 90% SO2

 capture was achievable

with a Ca/S molar ratio of 1.1 and that 95% SO2

 capture

was possible with a Ca/S molar ratio of 1.5, provided the

size gradation of the sorbent being utilized was optimized. This sulfur retention was achieved at a bed temperature of 1,580 oF and full bed height. Limestone

proved ineffective as a sorbent, and as a result, testing

focused on dolomite. The testing showed that sulfur

capture as well as sintering was sensitive to the fineness

of the dolomite sorbent (Plum Run Greenfield dolomite).

Sintering of fluidized-bed materials, a fusing of the materials rather than effective reaction, had become a serious

problem that required operation at bed temperatures below the optimum for effective boiler operation. Tests

were conducted with sorbent size reduced from minus 6

mesh to a minus 12 mesh. The result with the finer material was a major, positive impact on process performance

without the expected excessive elutriation of sorbent.

The finer material increased the fluidization activity as

evidenced by a 10% improvement in heat transfer rate

and an approximately 30% increase in sorbent utilization.

In addition, the process was much more stable as indicated by reductions in temperature variations in both the

bed and the evaporator tubes. Further, post-bed combustion and sintering were effectively eliminated.

The process demonstrated NOx emissions in the

range of 0.15–0.33 lb/106

 Btu. These emissions were

inherent to the process, which was operating at approximately 1,580 oF. No NOx

control enhancements, such as ammonia

injection, were required. Emissions of

carbon monoxide and particulates were less

than 0.01 and 0.02 lb/106

 Btu, respectively.

Operational Performance

Except for localized erosion of the in-bed

tube bundle and the more general erosion

of the water walls, the Tidd boiler performed extremely well and was considered

a commercially viable design. The in-bed

tube bundle experienced no widespread

erosion that would require significant

main- tenance. While the tube bundle was

in good condition, a significant amount of

erosion on each of the four water walls was

observed. While no operational failure

occurred during the demonstration, remedial action, such as the use of refractory

coatings utilized successfully on two commercial PFBC units, was deemed to be

warranted.

The gas turbine experienced both

structural and erosion problems and was

the leading cause of unit unavailability during the first 3

years of operation. However, design changes instituted

over the course of the demonstration proved effective in

addressing the problems. The Tidd demonstration

showed that a gas turbine could operate in a PFBC flue

gas environment, and it was concluded that erosion was

manageable with a scheduled maintenance program.

Efficiency of the PFBC combustion process was

calculated during testing from the amount of unburned

carbon in cyclone and bed ash, together with measurements of the amount of carbon monoxide in the flue gas.

Tests showed combustion efficiencies of 99.6%, surpassing the design or expected efficiency of 99.0%.

Using data for typical full-load operation, a heat rate

of 10,280 Btu/kWh (HHV basis) was calculated. This

corresponds to a cycle thermodynamic efficiency of

33.2% at a point where the cycle produced 70 MWe of

gross electrical power while burning Pittsburgh No. 8

coal. Because the Tidd plant was a repowering application at a comparatively small scale, the measured efficiency does not represent what would be expected for a

larger utility-scale plant using Tidd technology. Studies

conducted under the PFBC Utility Demonstration Project

showed that efficiencies of over 40% are likely for a

larger utility-scale PFBC plant.

In summary, the Tidd project showed that the PFBC

system could be applied to electric power generation.

The PFBC demonstration at the repowered 70-MWe unit at Ohio

Power’s Tidd Plant led to significant refinements and understanding of the

technology.
Advanced Electric Power Generation Project Fact Sheets 1997 93

Further, the demonstration project led to significant refinements and understanding of the technology in the

areas of turbine erosion, sorbent utilization, sintering,

post-bed combustion, and boiler materials.

Testing of advanced ceramic candle filtration elements on a slipstream of one-seventh of the exhaust gases

for over 5,800 hours of coal-fired operation showed that

the design of the particulate filter was structurally adequate. However, results also showed that clay-bonded

silicon carbide lost 50% of its strength after 1,000–2,000

hours of exposure and that a buildup of ash in the filter

vessel caused breakage of the candles. The filter operated

at a pressure drop on the order of 100 inches of water

column and a filtration efficiency (mass basis) of 99.99%.

Economic Performance

Because the Tidd plant was a comparatively small-scale

facility, economic performance would not be representative of a larger utility-scale plant using PFBC technology.

Commercial Applications

Combined-cycle PFBC permits use of a wide range of

coals, including high-sulfur coals. Bubbling PFBC technology, along with other advanced technologies, will

compete with circulating PFBC systems to repower or

replace conventional power plants. PFBC technology

appears to be best suited for applications of 50-MWe or

larger. Capable of being constructed modularly, PFBC

generating plants permit utilities to add increments of

capacity economically to match load growth. Plant life

can be extended by repowering with PFBC using the

existing plant area, coal- and waste-handling equipment,

and steam turbine equipment. Another advantage for

repowering applications is the compactness of the process

due to pressurized operation, which reduces space requirements per unit of energy generated.

The environmental attributes of a mature system

include in-situ sulfur removal of 95% and NOx

 emission

levels less than 0.1 lb/106

 Btu. Although the system

generates slightly more solid waste compared to conventional systems, the dry material is either readily disposable or potentially usable.

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

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.) Coal and sorbent conveyors can be seen just after

entering the Tidd Plant.

• 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.)
94 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Fluidized-Bed Combustion

Jacksonville Electric Authority

Large-Scale CFB Combustion

Demonstration Project

Participant

Jacksonville Electric Authority

Additional Team Member

Foster Wheeler Energy Corp.—co-owner and technology

supplier

Location

Jacksonville, Duval County, FL (Jacksonville Electric

Authority’s Northside Station, Unit 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 utility and nonutility power producers with the

data necessary for evaluating a large-scale ACFB as a

commercial alternative to accomplish greater than 90%

SO2

 removal and to reduce NOx emissions by 60% when

compared with conventional technology.

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 million lb/hr of main steam at about 2,400 psig and

1,005 oF and 1.73 million 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). SO2

emissions from the common stack for Units 1 and 2

would be on the order of 0.17 lb/106

 Btu. (Unit 1 is a

275-MWe oil-fired unit similar to Unit 2.)

Technology/Project Description

A circulating fluidized-bed combustor, operating at atmospheric pressure, will be retrofitted into Unit 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

Advanced Electric Power Generation Project Fact Sheets 1997 95

Preoperational tests started 6/01*

Environmental monitoring plan

completed 6/01*

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 and repayment agreement with Jacksonville Electric Authority to cost-share

refurbishment of the first (Unit 2) of two units at

Northside Generating Station.

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.

In its commercial configuration, ACFB technology

offers several potential benefits when compared to conventional pulverized coal-fired systems: lower capital

costs; reduced SO2

 and NOx emissions at lower costs;

higher combustion efficiency; and dry, granular solid

material that is easily disposed of or potentially salable.

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

NEPA process completed (EIS; Jacksonville site) 2/99*

9/97

*Projected date

**Years omitted

Project restructured and resited

(Jacksonville) 8/26/97

** **

4/02 4/04

Design and Construction

NEPA process completed

(EIS; York site) 8/11/95

Cooperative agreement modified 9/29/97

Operation initiated 4/02*

Project completed/final report issued 4/04*

Operation completed 4/04*

Design completed

11/00*

Construction

completed 3/02*

Groundbreaking/

construction started 3/99*
96 Project Fact Sheets 1997 Advanced Electric Power Generation

late 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.

Technology/Project Description

Nucla’s circulating fluidized-bed system operates at atmospheric pressure. In the combustion chamber, a stream

of air fluidizes and entrains a bed of coal, coal ash, and

sorbent (e.g., limestone). Relatively low combustion

temperatures limit NOx

 formation. Calcium in the sorbent

combines with SO2

 gases to form calcium sulfite and

sulfate solids, and solids exit the combustion chamber

and flow into a hot cyclone. The cyclone separates the

solids from the gases, and the solids are recycled for

combustor temperature control. Continuous circulation of

coal and sorbent improves mixing and extends the contact

time of solids and gases, thus promoting high utilization

of the coal and high-sulfur-capture efficiency. Heat in the

flue gas exiting the hot cyclone is recovered in the economizer. Flue gas passes through a baghouse where particuAdvanced Electric Power Generation

Fluidized-Bed Combustion

Nucla CFB Demonstration

Project

Project completed.

Participant

Tri-State Generation and Transmission Association, Inc.

(formerly Colorado-Ute Electric Association, Inc.)

Additional Team Members

Foster Wheeler Energy Corp.*—technology supplier

Technical Advisory Group (potential users)—cofunder

Electric Power Research Institute—technical consultant

Location

Nucla, Montrose County, CO (Nucla Station)

Technology

Foster Wheeler’s atmospheric circulating fluidized-bed

(ACFB) combustion system

Plant Capacity/Production

100 MWe (net)

Coals

Western bituminous—

Salt Creek, 0.5% sulfur, 17% ash

Peabody, 0.7% sulfur, 18% ash

Dorchester, 1.5% sulfur, 23% ash

Project Funding

Total project cost $46,512,678 100%

DOE 17,130,411 37

Participant 29,382,267 63

Project Objective

To demonstrate the feasibility of ACFB technology at

utility scale and to evaluate the economic environmental,

and operational performance at that scale.

*Pyropower Corporation, the original technology developer and

supplier, was acquired by Foster Wheeler Energy Corp.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Project Fact Sheets 1997 97

Results Summary

Environmental

• Bed temperature had the greatest effect on pollutant

emissions and boiler efficiency.

• At bed temperatures below 1,620 oF, sulfur capture

efficiencies of 70 and 95% were achieved at calciumto-sulfur (Ca/S) molar ratios of 1.5 and 4.0, respectively.

• During all tests, NOx

 emissions averaged 0.18 lb/106

Btu and did not exceed 0.34 lb/106 Btu.

• CO emissions varied between 70 and 140 ppmv.

• Particulate emissions ranged from 0.0072 to 0.0125

lb/106

 Btu, corresponding to a removal efficiency of

99.9%.

• Solid waste was essentially benign and showed potential as an agricultural soil amendment, soil/road bed

stabilizer, or landfill cap.

Operational

• Boiler efficiency ranged from 85.6–88.6% and combustion efficiency ranged from 96.9–98.9%.

• A 3:1 boiler turndown capability was demonstrated.

• Heat rate at full load was 11,600 Btu/kWh and was

12,400 Btu/kWh at half load.

Economic

• Capital cost for the Nucla retrofit was $1,123/kW and

a normalized power production cost was 64 mills/

kWh.

Project Summary

Fluidized-bed combustion evolved from efforts to find a

combustion process conducive to controlling pollutant

emissions without external controls. Fluidized-bed

combustion enables efficient combustion at temperatures

of 1,400–1,700 oF, well below the thermal NOx

 generation temperature (2,500 oF), and high SO2

-capture efficiency through effective sorbent/flue gas contact. ACFB

differs from the more traditional fluid-bed combustion.

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, creating a more turbulent bed. Hot cyclones capture and return the solids

emerging from the turbulent bed to control temperature

and extend the gas/solid contact time and to protect a

downstream heat exchanger.

Interest and participation of the Department of Energy, Electric Power Research Institute, and Technical

Advisory Group (potential users) in the project involved

evaluating ACFB potential for broad utility application

through a comprehensive test program. Over a 21

/2-year

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

Operation

completed 1/91

Operation test program initiated 8/88

Cooperative agreement awarded 10/3/88

4/92

Project completed/final report issued 4/92
98 Project Fact Sheets 1997 Advanced Electric Power Generation

Exhibit 31

 Effect of Bed Temperature

on Ca/S Requirement

Exhibit 32

Calcium Requirements and

Sulfur Retentions for Various Fuels

demonstration, most of the technical problems had been

overcome. During the last 3 months of the demonstration, average availability was 97% and the capacity factor,

66.5%.

Over the range of operating temperature at which

testing was performed, bed temperature was found to be

the most influential operating parameter. With the exception of coal-fired configuration and excess air at elevated

temperatures, bed temperature was the only parameter

that had a measurable impact on emissions and efficiency.

Combustion efficiency, a measure of the quantity of

carbon that is fully oxidized to CO2

, ranged from

96.9–98.9%. Of the four exit sources of incompletely

burned carbon, the largest was carbon contained in the fly

ash (93%). The next largest (5%) was carbon contained

in the bottom ash stream, and the remaining feed-carbon

loss (2% ) was incompletely oxidized CO in the flue gas.

The fourth possible source, hydrocarbons in the flue gas,

was measured and found to be negligible.

Boiler efficiencies for 68 performance tests varied

from 85.6–88.6%. The contributions to boiler heat loss

were identified as unburned carbon, sensible heat in dry

flue gas, fuel and sorbent moisture, latent heat in burning

hydrogen, sorbent calcination, radiation and convection,

and bottom-ash cooling water. Net plant heat rate decreased with increasing boiler load, from 12,400 Btu/

kWh at 50% of full load to 11,600 Btu/kWh at full load.

The lowest value achieved during a full-load steady-state

test was 10,980 Btu/kWh. These values were affected by

the absence of reheat, the presence of the three older

12.5-MWe turbines in the overall steam cycle, the number

of unit restarts, and part-load testing.

Environmental Performance

As indicated above, bed temperature had the greatest

impact on ACFB performance, including pollutant emissions. Exhibit 31 shows the effect of bed temperatures on

the Ca/S requirement for 70% sulfur retention. Ca/S

ratios were calculated based on the calcium content of the

sorbent only and do not account for the calcium content

of the coal. While a Ca/S of about 1.5 was sufficient to

achieve 70% sulfur retention in the 1,500–1,620 °F

range, the Ca/S requirement jumped to 5.0 or more at

1,700 °F or greater.

Exhibit 32 shows the effect of Ca/S molar ratio on

sulfur retention at average bed temperatures below

1,620 oF. Salt Creek and Peabody coals contain 0.5%

and 0.7% sulfur, respectively. To achieve 70% SO2

reduction, or the 0.4 lb/106 Btu emission rate required

by the licensing agreement, a Ca/S molar ratio of approximately 1.5 is required. To achieve an SO2

 reduction of 95%, a Ca/S molar ratio of approximately 4.0 is

necessary. Dorchester coal, averaging 1.5% sulfur

content, required a somewhat lower Ca/S for a given

retention.

NOx

 emissions measured throughout the demonstration were less than 0.34 lb/106

 Btu, which is well

below the regulated value of 0.5 lb/106

 Btu. The average level of NOx

 emissions for all tests was 0.18 lb/106

Btu. NOx emissions indicate a relatively

strong correlation with temperature, increasing from 40 ppmv (0.06 lb/106

 Btu) at

1,425 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)

ratios. The mechanism was believed to be

oxidation of volatile nitrogen in the form of

ammonia (NH3

) catalyzed by calcium oxide.

CO emissions decrease as temperature

increases, from 140 ppmv at 1,425 oF to 70

ppmv at 1,700 oF.

At full load, the hot cyclones removed

99.8% of the particulates. With the addition

of baghouses, removal efficiencies achieved

on Peabody and Salt Creek Coals were

99.905% and 99.959%, respectively. This
Advanced Electric Power Generation Project Fact Sheets 1997 99

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.

equated to emission levels of 0.0125 lb/

106

 Btu for Peabody coal and 0.0072

lb/106

 Btu for Salt Creek coal, well

below the required 0.03 lb/106

 Btu.

Economic Performance

The final capital costs associated with

the engineering, construction, and startup of the Nucla ACFB system were

$112.3 million. This represents a cost

of $1,123/net kW. Total power costs

associated with plant operations between September 1988 and January

1991 were approximately $54.7 million, resulting in a normalized cost of

power production of 64 mills/kWh.

The average monthly operating cost

over this period was about $1,888,000.

Fixed costs represent about 62% of the

total and include interest (47%), taxes

(4.8%), depreciation (6.9%), and insurance (2.7%). Variable costs represent

more than 38% of the power production costs and include fuel expenses (26.2%), non-fuel

expenses (6.8%), and maintenance expenses (5.5%).

Commercial Applications

ACFB could play a role in near-term electric power generation markets, in which the Energy Information Administration estimates that 4 GWe of new coal-based capacity

will be needed between 1996 and 2000 to replace retiring

utility units. In the post-2000 time frame, ACFB will be

well positioned to compete for the estimated 32 GWe of

additional coal-based power generation and cogeneration

needed between 2000 and 2015. The international power

generation market is expected to substantially overshadow the domestic market, particularly in the nearterm, and the attributes of ACFB make it particularly

suitable for worldwide deployment.

The Nucla ACFB project prompted wide dissemination of the technical progress of ACFB technology and

showed the viability of scaling up. When the Nucla

ACFB boiler was sold, it was 44% larger than any other

U.S. ACFB unit and 41% larger than any other ACFB

boiler sold anywhere in the world. It was not until after

the Nucla unit was built and the first coal firing occurred

that another ACFB boiler of comparable size was sold.

The project enabled Pyropower (now owned by Foster

Wheeler) to save almost 3 years in establishing a commercial line of ACFB units. A total of 22 ACFB units

larger than 100 MWe, representing 3,800 MWe of capacity and worth more than $5 billion are being planned,

engineered, built, or operated; 11 are in the United

States.

Contacts

Marshall L. Pendergrass, Assistant General Manager

(303) 249-4501

Tri-State Generation and Transmission Association,

Inc.

P.O. Box 1149

Montrose, CO 81402

George Lynch, DOE/HQ, (301) 903-9434

Nelson F. Rekos, FETC, (304) 285-4066

References

• Colorado-Ute Nucla Station Circulating FluidizedBed (CFB) Demonstration—Volume 2: Test Program

Results. EPRI Report No. GS-7483. October 1991.

• Demonstration Program Performance Test: Summary

Reports. Report No. DOE/MC/25137-3104. ColoradoUte Electric Association, Inc. March 1992. (Available

from NTIS as DE92001299.)

• Economic Evaluation Report: Topical Report. Report

No. DOE/MC/25137-3127. Colorado-Ute Electric

Association, Inc., March 1992. (Available from NTIS

as DE93000212.)

• Nucla CFB Demonstration Project: Detailed Public

Design Report. Report No. DOE/MC/25137-2999.

Colorado-Ute Electric Association, Inc., December

1990. (Available from NTIS as DE91002081.)

• Clean Coal Reference Plants: Atmospheric CFB (Topical Report, Task 1). Report No. DOE/MC/25177-

3307. Gilbert/Commonwealth, Inc. June 1992. (Available from NTIS as DE93000251.)

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Nucla CFB Demonstration

Project. (Colorado-Ute Electric Association, Inc.).

Report No. DOE/FE-0106. U.S. Department of Energy. July 1988.
100 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Clean Energy Demonstration

Project

Participant

Clean Energy Partners Limited Partnership (a limited

partnership consisting of Clean Energy Genco, Inc., an

affiliate of Duke Energy Corp.; Makowski Clean Energy

Investors, Inc.; British Gas Americas, Inc.; and an affiliate of the General Electric Company)

Additional Team Members

Duke Engineering & Services, Inc.—engineer and

constructor

General Electric Company—power island designer and

supplier

British Gas Americas, Inc., affiliate in conjunction with

Lurgi Energie and Umwelt GmbH—gasification

island designer

Fuel Cell Engineering Corporation—molten carbonate

fuel cell designer and supplier; cofunder

Electric Power Research Institute—cofunder

Deutsche Aerospace AG—cofunder

National Rural Electric Cooperative Association—

cofunder

Location

Evaluating site locations.

Technology

Integrated gasification combined-cycle (IGCC) using

British Gas/Lurgi (BG/L) slagging fixed-bed gasification

system coupled with Fuel Cell Engineering’s molten

carbonate fuel cell (MCFC)

Plant Capacity/Production

477-MWe (net) IGCC; 1.25-MWe MCFC

Project Funding

Total project cost $841,096,189 100%

DOE 183,300,000 22

Participant 657,796,189 78

Project Objective

To demonstrate and assess the reliability, availability, and

maintainability of a utility-scale IGCC system using

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 to produce a raw coal gas rich in hydrogen

and carbon monoxide. Raw coal gas exiting the gasifier

is washed and cooled. Hydrogen sulfide and other sulfur

compounds are removed. Elemental sulfur is reclaimed

and disposed of as a by-product. Tars, oils, and dust are

recycled to the gasifier. The resulting clean, mediumBtu fuel gas fires the gas turbine. A small portion of the

clean gas is used for the MCFC.

The MCFC is composed of a molten carbonate

electrolyte sandwiched between porous anode and cathode plates. Fuel (desulfurized, heated medium-Btu gas)

and steam are fed continuously into the cathode. Electrical reactions produce direct electric current, which is

converted to alternating power in an inverter.

Eastern bituminous coal will be used.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

 1 2

*Projected date

Advanced Electric Power Generation Project Fact Sheets 1997 101

1993 1996 1997 1994 1995 1998 1999 2000 2001 2002 2003

Preaward

5/93

DOE selected project

(CCT-V) 5/4/93

Project Status/Accomplishments

The cooperative agreement was awarded December 2,

1994. The participant is evaluating sites.

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.

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

12/94

Cooperative agreement

awarded 12/2/94

Design

Note: Milestone schedule pending project restructuring

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.
102 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Piñon Pine IGCC Power

Project

Participant

Sierra Pacific Power Company

Additional Team Members

Foster Wheeler USA Corporation—architect, engineer,

and constructor

The M.W. Kellogg Company—technology supplier

Location

Reno, Storey County, NV (Sierra Pacific Power

Company’s Tracy Station)

Technology

Integrated gasification combined-cycle (IGCC) using the

KRW air-blown pressurized fluidized-bed coal

gasification system

Plant Capacity/Production

99 MWe (net)

Project Funding

Total project cost $335,913,000 100%

DOE 167,956,500 50

Participant 167,956,500 50

Project Objective

To demonstrate air-blown, pressurized, fluidized-bed

IGCC technology incorporating hot gas cleanup; to

evaluate a low-Btu gas combustion turbine; and to assess

long-term reliability, availability, maintainability, and

environmental performance at a scale sufficient to determine commercial potential.

Technology/Project Description

Dried and crushed coal and limestone are introduced into

a pressurized, air-blown, fluidized-bed gasifier. Crushed

limestone is used to capture a portion of the sulfur and to

inhibit conversion of fuel nitrogen to ammonia. The

sulfur reacts with the limestone to form calcium sulfide

which, after oxidation, exits as calcium sulfate along

with the coal ash in the form of agglomerated particles

suitable for landfill.

Hot, low-Btu coal gas leaving the gasifier passes

through cyclones, which return most of the entrained

particulate matter to the gasifier. The gas, which leaves

the gasifier at about 1,700 oF, is cooled to about 1,100 oF

before entering the hot gas cleanup system. During

cleanup, virtually all of the remaining particulates are

removed by ceramic candle filters, and final traces of

sulfur are removed by reaction with metal oxide sorbent

in a transport reactor.

The hot, cleaned gas then enters the GE Model

MS6001FA combustion turbine, which is coupled to a

generator designed to produce 61 MWe (gross). Exhaust

gas is used to produce steam in a heat recovery steam

generator. Superheated high-pressure steam drives a

condensing steam turbine-generator designed to produce

about 46 MWe (gross).

Due to the relatively low operating temperature of

the gasifier and the injection of steam into the combustion fuel stream, the NOx

 emissions are 0.069 lb/106 Btu

(94% reduction). Due to the combination of in-bed

sulfur capture and hot gas cleanup, SO2

 emissions are

0.069 lb/106

 Btu (90% reduction).

In the demonstration project, 880 tons/day of coal

are converted into 107 MWe (gross), or 99 MWe (net),
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Calendar Year

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*Projected date

Advanced Electric Power Generation Project Fact Sheets 1997 103

Preaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Design and Construction Operation

9/91 8/92 7/00

DOE selected

project (CCT-IV)

9/12/91

Cooperative agreement awarded 8/1/92

Project completed/final report issued 7/00*

Operation completed 7/00*

Ground breaking/construction started 2/95

NEPA process completed (EIS) 11/8/94

Design completed 8/95

of the coal-gasification combined cycle continued

through 1997 with syngas produced in January 1998.

Additional shakedown testing is planned with test-plan

operations scheduled to begin in April 1998.

Commercial Applications

The Piñon Pine IGCC system concept is suitable for new

power generation, repowering needs, and cogeneration

applications. The net effective heat rate for a proposed

greenfield plant using this technology is projected to be

7,800 Btu/kWh (43.7% efficiency), representing a 20%

increase in thermal efficiency as compared to a conventional pulverized coal plant with a scrubber and a comparable reduction in CO2

 emissions. The compactness of a

IGCC system reduces space requirements per unit of

energy generated relative to other coal-based power

generation systems, and the advantages provided by

modular construction reduce the financial risk associated

with new capacity additions.

The KRW IGCC technology is capable of gasifying

all types of coals, including high-sulfur, high-ash, lowfor export to the grid. Southern Utah bituminous coal

(0.5–0.9% sulfur) is the design coal; tests using

midwestern or eastern high-sulfur bituminous coal

(2–3% sulfur) also are planned. The integrated gasification system is located at Sierra Pacific Power Company’s

Tracy Station, near Reno, NV.

Project Status/Accomplishments

Construction activities, which began in early 1995, were

completed in February 1997. Start-up efforts, which

began during the second half of 1996, are continuing,

and final commissioning is in progress. However, plant

start-up is proceeding slower than planned due to problems encountered during equipment commissioning and

the need to relocate the flare.

The GE Frame 6FA (Model MS6001FA) combustion turbine at the unit is the first of its kind in the world

and was successfully fired for the first time on August

15, 1996, using natural gas. The combined-cycle part of

the plant began commercial operation on natural gas in

November 1996. Preoperational testing and shakedown

Environmental monitoring plan

completed 10/31/96

rank, and high-swelling coals, as well as bio- or refusederived waste, with minimal environmental impact. This

versatility provides numerous economic advantages for

the depressed mineral extraction and cleanup industries.

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.

Preoperational tests initiated 11/96

1/98

Operation initiated 1/98*

Construction completed 2/97
104 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Tampa Electric Integrated

Gasification Combined-Cycle

Project

Participant

Tampa Electric Company

Additional Team Members

Texaco Development Corporation—gasification

technology supplier

General Electric Company—combined-cycle technology

supplier

G.E. Environmental Systems—hot-gas cleanup

technology supplier

TECO Power Services, Inc.—project manager and

marketer

Bechtel Power Corporation—architect and engineer

Location

Mulberry, Polk County, FL (Tampa Electric Company’s

Polk Power Station, Unit 1)

Technology

Integrated gasification combined-cycle (IGCC) system

using Texaco’s pressurized, oxygen-blown, entrainedflow gasifier technology and incorporating both conventional, low-temperature acid-gas removal and hot-gas

moving-bed desulfurization

Plant Capacity/Production

250 MWe (net)

Project Funding

Total project cost $303,288,446 100%

DOE 150,894,223 49

Participant 152,394,223 51

Project Objective

To demonstrate IGCC technology in a greenfield, commercial, electric utility application at the 250-MWe size

with a Texaco gasifier. To demonstrate the integrated

performance of a metal oxide hot-gas cleanup system,

conventional cold-gas cleanup, and an advanced gas

turbine with nitrogen injection (from the air separation

plant) for power augmentation and NOx

 control.

Technology/Project Description

Texaco’s pressurized, oxygen-blown, entrained-flow

gasifier is used to produce a medium-Btu fuel gas. Coal/

water slurry and oxygen are reacted at high temperature

and pressure to produce a high-temperature syngas. Molten coal-ash flows out of the vessel’s bottom and into a

water-filled quench tank where it is forms a solid slag.

The syngas from the gasifier moves to a high-temperature

heat-recovery unit, which cools the gases.

The cooled gases flow to a particulate-removal section before entering gas-cleanup trains. A portion of the

syngas is passed through a moving bed of metal oxide

absorbent to remove sulfur. The remaining syngas is

further cooled through a series of heat exchangers before

entering a conventional gas-cleanup train where sulfur is

removed by an acid-gas removal system. Combined,

these cleanup systems are expected to maintain sulfur

levels below 0.21 lb/106

 Btu (96% capture). The cleaned

gases are then routed to a combined-cycle system for

power generation. Sulfuric acid and slag are salable byproducts.

A GE MS 7001F gas turbine generates about 192

MWe (gross). Thermally generated NOx

 is controlled to

below 0.27 lb/106

 Btu by injecting nitrogen as a dilutent

in the turbine’s combustion section. A heat-recovery
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Calendar Year

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Advanced Electric Power Generation Project Fact Sheets 1997 105

steam-generator produces an additional 121 MWe (gross).

Polk’s IGCC heat rate for this demonstration is expected

to be approximately 8,600 Btu/kWh (40% efficient). The

demonstration project involves only the first 250 MWe

(net) of the planned 1,150-MWe Polk Power Station.

Illinois 6 and Pittsburgh 8 bituminous coals (2.5–3.5%

sulfur) are being used.

Project Status/Accomplishments

The first syngas was produced on July 19, 1996. The first

gasifier run lasted 21.5 hours, which set the longevity

record for first fire on a solid-fuel Texaco gasifier. Ten

gasifier runs totalling 174 hours were completed by the

end of September. All plant systems had been successfully commissioned, so Unit 1 was placed in commercial

operation on September 30, 1996.

Efforts in late 1996 were geared toward keeping the

unit on line as much as possible to obtain operating experience. During December 1996 and January 1997, the

combined-cycle system operated for 40 out of 45 days,

while achieving a maximum load of 310 MWe (gross) on

1988 1989 1990 1991 1994 1995 1996 1997 1998 1999 2000

Preaward Design and Construction

12/89 3/91

clean syngas. Efforts in 1997 are focusing on improving

the unit’s reliability, reducing operating costs, improving

heat rate, commissioning the hot gas cleanup system, and

beginning alternate coal testing. In July 1997, the plant

operated continuously for 20 days; plant efficiency improved, with a heat rate of 9,250 Btu/kWh. The plant

operated at full load for most of August. However, the

plant was brought off-line on August 26 to repair a gas

leak in the radiant syngas cooler and then restarted in

September on Illinois 6 coal.

The unit was dedicated on January 10, 1997.

Commercial Applications

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%.

Texaco and RJB Mining have proposed a 400-MWe

IGCC minemouth unit in West Yorkshire (U.K.) Texaco

and ASEA Brown Boveri have signed an agreement

**

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

Cooperative agreement awarded 3/11/91

Preoperational tests initiated 6/96

Construction completed 8/96

Operation initiated 10/96

10/96

*Projected date

**Years omitted

Design completed 8/94

NEPA process completed (EIS) 8/17/94

Construction started 8/94

Project completed/final report

issued 10/01*

Operation completed 10/01*

10/01

Operation

Environmental monitoring plan completed 5/96

forming an alliance to market IGCC technology in Europe. This demonstration project is scaling up the technology from a 100-MWe pilot unit (Cool Water plant)

tested without full system integration.

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

Conflict Resolution Award from the state of Florida, and

the 1991 Florida Audubon Society Corporate Award.
106 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Integrated Gasification Combined Cycle

Wabash River Coal

Gasification Repowering

Project

Participant

Wabash River Coal Gasification Repowering Project Joint

Venture (a joint venture of Destec Energy, Inc., and PSI

Energy, Inc.)

Additional Team Members

PSI Energy, Inc.—host

Destec Energy, Inc.*—engineer, gas plant operator, and

technology supplier

Location

West Terre Haute, Vigo County, IN (PSI Energy’s Wabash

River Generating Station, Unit 1)

Technology

Integrated gasification combined-cycle (IGCC) using

Destec’s two-stage, entrained-flow gasification system

Plant Capacity/Production

262 MWe (net)

Project Funding

Total project cost $438,200,000 100%

DOE 219,100,000 50

Participant 219,100,000 50

Project Objective

To demonstrate utility repowering with a two-stage, oxygen-blown IGCC system, including advancements in the

technology relevant to the use of high-sulfur bituminous

coal; and to assess long-term reliability, availability, and

maintainability of the system at a fully commercial scale.

Technology/Project Description

Coal is ground, slurried with water, and gasified in a

pressurized, two-stage (slagging first stage and nonslagging entrained-flow second stage), oxygen-blown,

gasifier. The product gas is cooled through heat exchangers and passed through a conventional cold gas cleanup

system which removes particulates, ammonia, and sulfur.

The clean, medium-Btu gas is then reheated and burned

in an advanced 192-MWe (gross) GE 7FA gas turbine.

Hot exhaust from the gas turbine is passed through a heat

recovery steam generator to produce high-pressure steam.

High-pressure steam is also produced from the gasification plant and superheated in the heat recovery steam

generator. The combined high-pressure steam flow is

supplied to an existing, refurbished 104-MWe (gross)

steam turbine.

The process has the following subsystems: a coalgrinding and slurry system, an entrained-flow coal gasifier, a syngas heat recovery system, a cold gas cleanup

system that produces a marketable sulfur by-product, a

combustion turbine capable of using coal-derived fuel

gas, a heat recovery steam generator, and a repowered

steam turbine.

One of six units at Wabash River Generating Station

was repowered. The demonstration unit generates

262 MWe (net) using 2,544 tons/day of high-sulfur

(2.3–5.9% sulfur) Illinois Basin bituminous coal. The

anticipated heat rate for the repowered unit is approximately 9,000 Btu/kWh (38% efficiency). Using highsulfur bituminous coal, SO2

 emissions are expected to be

less than 0.1 lb/106 Btu (98% reduction). NOx

 emissions

are expected to be less than 0.1 lb/106

 Btu (90% reduc-

*Destec Energy has been acquired by NGC Corporation and will

operate as a subsidiary, retaining the same name.
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*Projected date

Advanced Electric Power Generation Project Fact Sheets 1997 107

tion). The project represents the world’s largest singletrain IGCC plant currently in operation.

Project Status/Accomplishments

The plant is in its second year of operation, which began

in November 1995. Through September 30, 1997, the

plant has operated for about 4,000 hours on syngas in

combined-cycle mode and has produced about 1 million

MWh of electricity using syngas. The combustion turbine has demonstrated 192 MWe (100% of nameplate)

and the gasifier has demonstrated 1,825 million Btu/hr,

HHV (103% of nameplate). The gasifier has operated

about 4,500 hours on coal and produced over 7 trillion

Btu (dry) of syngas by processing over 400,000 tons of

coal. Gasifier operation has attained over 74% cold gas

efficiency.

The project has completed the first 2 years of a

3-year demonstration period. Early operation has demonstrated the ability to run at full-load capability while

meeting the environmental requirements for sulfur and

NOx

 emissions. CINergy, PSI’s post-merger parent comPreaward

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Operation

DOE selected

project (CCT-IV)

9/12/91

Design and Construction

9/91 7/92

NEPA process completed (EA) 5/28/93

Design completed 5/94

Cooperative agreement awarded 7/28/92

Environmental monitoring plan completed 7/9/93

Groundbreaking ceremony 7/7/93

Preoperational tests initiated 8/95

11/95 2/99

Demonstration completed 11/98*

Operation initiated 11/95

Construction completed 11/95

pany, dispatches the project 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).

Commercial Applications

Throughout the United States, particularly in the Midwest

and East, there are more than 95,000 MWe of existing

coal-fired utility boilers over 30 years old. Many of these

aging plants are without air pollution controls and are

candidates for repowering with IGCC technology. Repowering these plants with IGCC systems will improve

plant efficiencies and reduce SO2

, NOx, and CO2 emissions. The modularity of the gasifier technology will

permit a range of units to be considered for repowering,

and the relatively short construction schedule for the

technology will allow utilities greater flexibility in

designing strategies to meet load requirements. Also, the

high degree of fuel flexibility inherent in the gasifier

design will provide utilities with more choice in selecting

fuel supplies to meet increasingly stringent air quality

regulations.

Given the advantages of modularity, rapid and staged

on-line generation capability, high efficiency, fuel flexibility, environmental controllability, and reduced land

and natural resource needs, the IGCC system is also a

strong contender for new electric power generating facilities. Commercial offerings of the technology will be

based on a 300-MWe train, which is ideally suited to

utility-scale power generation applications. The system

heat rate for a new power plant based on this technology

is expected to realize at least a 20% improvement in

efficiency compared to a conventional pulverized-coalfired plant with flue gas desulfurization. The improved

system efficiency also results in a similar decrease in

CO2 emissions.

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.

Project completed/final report issued 2/99*
108 Project Fact Sheets 1997 Advanced Electric Power Generation

Advanced Electric Power Generation

Advanced Combustion/Heat Engines

Healy Clean Coal Project

Participant

Alaska Industrial Development and Export Authority

Additional Team Members

Golden Valley Electric Association—host

Stone and Webster Engineering Corp.—engineer

TRW Inc., Space & Technology Division—combustor

technology supplier

The Babcock & Wilcox Company (which has acquired

assets of Joy Environmental Technologies, Inc.)—

spray-dryer absorber technology supplier

Usibelli Coal Mine, Inc.—coal supplier

Location

Healy, Denali Borough, AK (adjacent to Healy Unit #1)

Technology

TRW’s advanced entrained (slagging) combustor

Babcock & Wilcox’s spray-dryer absorber with sorbent

recycle

Plant Capacity/Production

50 MWe (nominal electric output)

Project Funding

Total project cost $242,058,000 100%

DOE 117,327,000 48

Participant 124,731,000 52

Project Objective

To demonstrate an innovative new power plant design

featuring integration of an advanced combustor and heat

recovery system coupled with both high- and low-temperature emissions control processes.

TRW slagging combustors are bottom-mounted on the

boiler hopper. The main slagging combustor consists of a

water-cooled cylinder that slopes toward a slag opening.

The precombustor burns 25–40% of the total coal input.

The remaining coal is injected axially into the combustor,

rapidly entrained by the swirling precombustor gases

and additional air flow, and burned under substoichiometric (fuel-rich) conditions for NOx

 control. The ash

forms molten slag, which accumulates on the watercooled walls and is driven by aerodynamic and gravitational forces through a slot into the slag recovery section.

About 70–80% of the coal’s ash is removed as molten

slag. The hot gas is then ducted to the furnace where, to

ensure complete combustion, additional air is supplied

from the tertiary air windbox to NOx

 ports and to final

overfire air ports.

Technology/Project Description

The project is to be a nominal 50-MWe facility consisting

of two pulverized-coal-fired combustor systems. Emissions of SO2

 and NOx will be controlled using TRW’s

slagging combustion systems with staged fuel and air, a

boiler that controls fuel- and thermal-related conditions,

and limestone injection. Additional SO2

 will be removed

using Babcock & Wilcox’s activated recycle spray-dryer

absorber system. Performance goals are NOx

 emissions

of less than 0.2 lb/106

 Btu, particulate emissions of 0.015

lb/106

 Btu, and SO2 removal greater than 90%. The

performance testing of coal consists of 35% run-of-mine

and 65% waste coal, with the waste coal having a lower

heating value and significantly more ash.

A coal-fired precombustor increases the air inlet

temperature for optimum slagging performance. The
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Advanced Electric Power Generation Project Fact Sheets 1997 109

Pulverized limestone (CaCO3) for SO2 control is fed

into the combustor where most is flash calcined. The

mixture of this lime (CaO) and the ash not slagged, called

flash-calcined material, is removed in the fabric filter

(baghouse) system. A small part of the flash-calcined

material is disposed of, but most is conveyed to a mixing

tank where water is added to form a 45% flash-calcinedmaterial solids slurry. The slurry leaving the mixing tank

is pumped to a grinding mill where it is mechanically

activated by abrasive grinding. Feed slurry is pumped

from the feed tank to the spray-dryer absorber where the

slurry is atomized using Babcock & Wilcox’s dry scrubbing technology. SO2

 in the flue gas reacts with the slurry

droplets as water is simultaneously evaporated. SO2

 is

further removed from the flue gas by reacting with the dry

flash-calcined material on the baghouse filter bags.

The project site is adjacent to the existing Healy Unit

#1 near Healy, AK, and to the Usibelli coal mine. Power

will go to the Golden Valley Electric Association

(GVEA). The plant will use a nominal 900 tons/day of

subbituminous coal, containing a nominal 0.2% sulfur,

and waste coal. The project will collect performance

data for 31⁄2 years, with 2 years of data being provided at

no cost to DOE. A hazardous air pollutant monitoring

program will also be implemented.

To address concerns about potential impact to the

nearby Denali National Park and Preserve, DOE, the

National Park Service, GVEA, and the project participant

entered into an agreement to reduce the emissions from

Unit #1 so that the combined emissions from the two

units will be only slightly greater than those currently

emitted from Unit #1 alone. Total site emissions will be

further reduced to current levels if necessary to protect

the park.

Project Status/Accomplishments

Construction was completed on November 15, 1997, and

startup and commissioning is under way. In July 1997,

the boiler was fired on oil, and the turbine was loaded to

produce 5 MW of electricity. Initial firing of the slagging

combustiors on coal is scheduled for January 1998 when

demonstration operations are initiated. The retrofit of

Unit No. 1 (low-NOx

 burners with overfire air) was completed, and its performance testing is expected early in

1998.

Commercial Applications

This technology has a wide range of applications. It is

appropriate for any size utility or industrial boiler in new

and retrofit uses. It can be used in coal-fired boilers as

well as in oil- and gas-fired boilers because of its high

ash-removal capability. However, cyclone boilers may be

the most amenable type to retrofit with the slagging combustor because of the limited supply of high-Btu, lowsulfur, low-ash-fusion-temperature coal that cyclone

boilers require. The commercial availability of costeffective and reliable systems for SO2

, NOx, and particulate control is important to potential users planning new

capacity, repowering, or retrofits to existing capacity in

order to comply with CAAA of 1990 requirements.

TRW is offering licensing of its technology worldwide and already has a licensing agreement in place in

China.

1990 1991 1993 1994 1995 1996 1997 1998 1999 2000 2001

Preaward Design and Construction

Design

started 7/90

4/91

Cooperative

agreement

awarded 4/11/91

DOE selected project

(CCT-III) 12/19/89

Operation

12/89 1/98 6/99

**

Project completed/final

report issued 6/99*

DOE cost-shared operation

completed 6/99*

2 yrs of operational

data provided at no

additional cost

6/01*

6/01

*Projected date

**Years omitted

Operation initiated 1/98*

Preoperational tests initiated 8/97 NEPA process completed (EIS) 3/10/94

Design completed 10/93

Ground breaking/construction

started 5/30/95

No-Cost Data Collection

Environmental monitoring

plan completed 4/11/97

Construction completed 11/97
110 Project Fact Sheets 1997 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. The clean coal diesel technology, which uses a coal slurry (specifically, low-rank coalwater fuel), 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 low-rank coal-water fuel is prepared using an

advanced coal drying process that allows dried coal to be

slurried in water. The University of Alaska will assemble

and operate a 5-ton/hr coal-water-fuel processing plant

that will utilize local coal brought by truck from

Usibelli’s mine in Healy, AK. In addition to its use in the

coal-fueled diesel engine, the low-rank coal-water fuel is

expected to be an alternative to fuel oil in conventional

oil-fired industrial boilers.

Advanced Electric Power Generation

Advanced Combustion/Heat Engines

Clean Coal Diesel

Demonstration Project

Participant

Arthur D. Little, Inc.

Additional Team Members

University of Alaska at Fairbanks—host and cofunder

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)

Project Funding

Total project cost $38,309,516 100%

DOE 19,154,758 50

Participant 19,154,758 50

Project Objective

To prove the design, operability, and durability of the

coal diesel engine during 6,000 hours of operation and

verify the design and operation of an advanced drying/

slurrying process for subbituminous Alaskan coals and

for testing the coal slurry in the diesel and a retrofitted

oil-fired boiler.
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Advanced Electric Power Generation Project Fact Sheets 1997 111

1993 1996 1997 1994 1995 1998 1999 2000 2001 2002 2003

Preaward

5/93 7/94

DOE selected project

(CCT-V) 5/4/93

Cooperative agreement awarded 7/12/94

Design and Construction

Project Status/Accomplishments

Easton Utilities, the original host, withdrew from the

project after reevaluating its long-term need for power.

On August 21, 1997, DOE approved the participant’s

plans to resite the project at the University of Alaska in

Fairbanks, where the engine will operate on subbituminous Alaskan coals, and restructure the project.

Project definition and design activities are ongoing.

NEPA requirements have been satisfied by an environmental assessment, which was completed June 2, 1997.

Commercial Applications

The coal-fueled diesel engine is particularly suited for

nonutility new capacity, small utility repowering, and

exports to developing countries. The net effective heat

rate for the mature diesel system is expected to be 6,830

Btu/kWh (48%), which makes it very competitive with

similarly sized coal- and fuel-oil-fired installations. EnviNEPA process completed (EA) 6/2/97

ronmental emissions from commercial diesel systems

should be reduced to levels between 50% and 70% below

NSPS. The estimated installation cost of a mature commercial unit is approximately $1,300/kW.

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 indiginous coal in developing

countries.

The JGC Corporation of Japan, a coal-water mixture

and power supplier, has approached Coltec Industries

about using the clean coal diesel engine for a 10-MWe

power plant in Indonesia. JGC is processing Chinese coal

shipments to Indonesia and recently has been using the

same hot water drying/slurrying technique as in this CCT

project.

Groundbreaking/construction started 5/98*

Environmental monitoring plan completed 2/99*

Design completed 2/99*

Construction completed 2/99*

Preoperational tests initiated 3/99*

Operation initiated 8/99*

8/99 4/02

Project completed/final

report issued 4/02*

Operation completed 1/02*

Operation
112 Project Fact Sheets 1997 Coal Processing for Clean Fuels

Introduction

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 Rosebud SynCoal Partnership’s advanced

coal conversion project applies mostly physicalcleaning methods to low-Btu, low-sulfur subbituminous coals, primarily to remove moisture and secondarily to remove ash. The objective is to enhance the

energy density of the already low-sulfur coal. Some

conversion of the surface properties of the coal is

required, however, to provide stability (prevent

spontaneous combustion) in transport and handling. In

the process, coal with 5,500–9,000 Btu per pound,

25–40 percent moisture content, and 0.5–1.5 percent

sulfur is converted to a 12,000-Btu-per-pound product

with 1.0 percent moisture and as low as 0.3 percent

sulfur. Test burning of processed coal at utilities is

continuing.

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

convert low-Btu, low-sulfur-content subbituminous

coal to a high-energy-density, low-sulfur solid product

and a clean liquid fuel comparable to No. 6 fuel oil.

Mild gasification is a pyrolysis process (heating in the

absence of oxygen) performed at moderate temperatures and pressures. It produces condensable volatile

hydrocarbons in addition to solids and gas. The

condensable fraction is drawn off as a liquid product.

Most of the gas is used to provide on-site energy

requirements. The process solid is significantly

beneficiated to produce a 12,000-Btu-per-pound lowsulfur 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 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 33 summarizes the process characteristics

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

Coal Processing for Clean Fuels Technology
Coal Processing for Clean Fuels Project Fact Sheets 1997 113

Exhibit 33

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 114

Self-Scrubbing CoalTM: An Integrated Approach to Clean Air Dense-medium cyclones with finely sized magnetite and 500 tons/hr 118

sorbent addition for bituminous coals

Advanced Coal Conversion Process Demonstration Advanced coal conversion process for upgrading 45 tons/hr 120

low-rank coals

ENCOAL® Mild Gasification Project Liquids-from-coal (LFC®) mild gasification to 1,000 tons/day 122

produce solid and liquid fuels

Commercial-Scale Demonstration of the Liquid-Phase Methanol Liquid-phase methanol (LPMEOHTM) process for 80,000 gal/day 124

(LPMEOHTM) Process methanol production from coal syngas

Custom Coals International’s advanced coal-cleaning

plant in Central City, PA, can process 500 tons/hr of raw

coal.

The ENCOAL® mild gasification plant near Gillette,

WY, has operated 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.
114 Project Fact Sheets 1997 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Coal Preparation Technologies

Development of the Coal

Quality ExpertTM

Project completed.

Participants

ABB Combustion Engineering, Inc.

CQ Inc.

Additional Team Members

Black & Veatch—cofunder and software

developer

Electric Power Research Institute—cofunder

The Babcock & Wilcox Company—cofunder and

pilot-scale tester

Electric Power Technologies, Inc.—field tester

University of North Dakota, Energy and Environmental

Research Center—bench-scale tester

Alabama Power Company—host

Mississippi Power Company—host

New England Power Company—host

Northern States Power Company—host

Public Service Company of Oklahoma—host

Locations

Grand Forks, Grand Forks County, ND (bench tests)

Windsor, Hartford County, CT (bench- and pilot-scale

tests)

Alliance, Columbiana County, OH (pilot-scale tests)

Wilsonville, Shelby County, AL (Gatson, Unit 5)

Gulfport, Harrison County, MS (Watson, Unit 4)

Somerset, Bristol County, MA (Brayton Point,

Units 2 and 3)

Bayport, Washington County, MN (King Station)

Oologah, Rogers County, OK (Northeastern, Unit 4)

Technology

CQ Inc.’s EPRI Coal Quality ExpertTM (CQETM) computer software

Plant Capacity/Production

Full-scale testing took place at six utility sites ranging in

size from 250 to 880 MWe.

Project Funding

Total project cost $21,746,004 100%

DOE 10,863,911 50

Participants 10,882,093 50

Project Objective

The objective of the project was to provide the utility

industry with a PC software program to confidently and

inexpensively evaluate the potential for coal-cleaning,

blending, and switching options to reduce emissions

while producing the lowest cost electricity. Specifically

the project was to (1) enhance the existing Coal Quality

Information System (CQISTM) database and Coal Quality

Impact Model (CQIMTM) to allow assessment of the

effects of coal-cleaning on specific boiler costs and performance and (2) develop and validate CQETM, a methodology that allows accurate and detailed prediction of coal

quality impacts on total power plant operating cost and

performance.

Technology/Project Description

The CQETM is a software tool that brings a new level of

sophistication to fuel decisions by integrating the systemwide 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,

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

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*Projected date

Coal Processing for Clean Fuels Project Fact Sheets 1997 115

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

techno-economic analyses of plant operating strategies.

CQETM, which combines CQIMTM with other existing

software and databases, extends the art of model-based

fuel evaluation established by CQIMTM in three dimensions: new flexibility and application, advanced technical

models and performance correlations, and advanced user

interface and network awareness.

Algorithm Development

Data derived from bench-, pilot-, and full-scale testing

were used to develop the CQETM algorithms. Bench-scale

testing was performed at ABB Combustion Engineering’s

facilities in Windsor, CT, and the University of North

Dakota’s Energy and Environmental Research Center in

Grand Forks, ND; pilot-scale testing was performed at

ABB Combustion Engineering’s facilities in Windsor, CT,

and Alliance, OH. The six field test sites were Alabama

Power’s Gatson, Unit 5 (880 MWe), Wilsonville, AL;

Mississippi Power’s Watson, Unit 4 (250 MWe),

Gulfport, MS; New England Power’s Brayton Point, Unit

2 (285 MWe) and Unit 3 (615 MWe), Somerset, MA;

Northern States Power’s King Station (560 MWe),

Bayport, MN; and Public Service Company of

Oklahoma’s Northeastern, Unit 4 (445 MWe),

Oologah, OK.

The six large-scale field tests consisted of burning a

baseline coal and an alternate coal over a 2-month period.

The baseline coal was used to characterize the operating

performance of the boiler. The alternate coal, a blended

or cleaned coal of improved quality, was burned in the

boiler for the remaining test period.

The baseline and alternate coals for each test site also

were burned in bench- and pilot-scale facilities under

similar conditions. The alternate coal was cleaned at CQ

Inc. to determine what quality levels of clean coal can be

produced economically and then transported to the

bench- and pilot-scale facilities for testing. All data from

bench-, pilot-, and full-scale facilities were evaluated and

correlated to formulate algorithms used to develop the

model.

CQETM Capability

The PC-based program evaluates coal quality, transportation system options, performance issues, and alternative

emissions control strategies for utility power plants.

CQETM is composed of technical tools to evaluate

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 3/98*

3/98

CQE Release 1.2

issued 12/97
116 Project Fact Sheets 1997 Coal Processing for Clean Fuels

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-, and/or unitlevel fuel quality, economic, and technical assessments.

• Plant Engineer—Provides in-depth performance

evaluations with a more focused scope than provided

in the Fuel Evaluator.

• Environmental Planner—Provides access to evaluation and presentation capabilities of the Acid Rain

Advisor.

• Coal-Cleaning Expert—Establishes the feasibility of

cleaning a coal, determines cleaning processes, and

predicts associated costs.

Software Description

CQETM includes more than 100 algorithms based on the

data generated in the six full-scale field test.

CQETM’s design philosophy underscores the importance of flexibility by modeling all important power plant

equipment and systems and their performance in realworld situations. This level of sophistication allows new

applications to be added by assembling a model of how

objects interact. Updated information records can be

readily shared among all affected users because CQETM is

network-aware, enabling users throughout an organization to share data and results. The CQETM object-oriented design, coupled with an object database management system, allows different views into the same data.

As a result, staff efficiency is enhanced when decisions

are made.

CQETM also can be expanded without major revisions to the system. Object-oriented programming allows

new objects to be added and old objects to be deleted or

enhanced easily. For example, if modeling advancements

are made with respect to predicting boiler ash deposition

(i.e., slagging and fouling), the internal calculations of the

object that provides these predictions can be replaced or

augmented. Other objects affected by ash deposition

(e.g., ash collection and disposal systems, soot blower

systems) do not need to be altered; thus the integrity of

the underlying system is maintained.

System Requirements

CQETM currently uses the OS/2 operating system, but the

developers are planning to migrate to a Windows-based

platform. CQETM can operate in stand-alone mode on a

single computer or on a network. The system requirements for stand-alone operation are listed in Exhibit 34.

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 40 U.S. utilities and one U.K. utility have

CQETM through their EPRI membership. Proposals are

pending with several non-EPRI-member U.S. and foreign

utilities to license their software.

The CQETM team has a Home Page on the World

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

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 34

CQETM Stand-Alone System Requirements
Coal Processing for Clean Fuels Project Fact Sheets 1997 117

CQETM was recognized by then Energy Secretary

Hazel O’Leary and EPRI President Richard Balzhiser in

1996 as the best of nine DOE/EPRI cost-shared utility

research and development projects under the “Sustainable

Electric Partnership” program.

Contacts

Clark D. Harrison, President, (412) 479-6016

CQ Inc.

One Quality Center

P.O. Box 280

Homer City, PA 15748-0280

Douglas Archer, DOE/HQ, (301) 903-9443

Scott M. Smouse, FETC, (412) 892-5725

References

• Harrison, Clark D., et al. “Recent Experience with the

CQETM.” Fifth Annual Clean Coal Technology Conference: Technical Papers. January 1997.

• CQETM Users Manual, CQETM Home Page at

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

• Comprehensive Report to Congress on the Clean Coal

Technology Program: Development of the Coal Quality Expert. ABB Combustion Engineering, Inc., and

CQ Inc. Report No. DOE/FE-0174P. U.S. Department

of Energy. May 1990. (Available from NTIS as

DE90010381.)

CQETM, a PC-based software tool, can be used to determine the complete

costs of various fuel options by seamlessly integrating the effects of fuel purchase

decisions on power plant performance, emissions, and power generation costs.

Portions of the CQETM User’s Manual are available on the Internet.
118 Project Fact Sheets 1997 Coal Processing for Clean Fuels

Project Objective

To demonstrate advanced coal-cleaning unit processes to

produce low-cost compliance coals that can meet full

requirements for commercial-scale utility power plants to

satisfy provisions of the CAAA.

Technology/Project Description

An advanced coal-cleaning plant has been designed,

blending existing and new processes, to produce, from

high-sulfur bituminous feedstocks, two types of compliance coals—Carefree CoalTM and Self-Scrubbing CoalTM.

Carefree CoalTM is produced by breaking and

screening run-of-mine coal and by using innovative

dense-medium cyclones and finely sized magnetite to

remove up to 90% of the pyritic sulfur and most of the

ash. Carefree CoalTM is designed to be a competitively

priced, high-Btu fuel that can be used without major

plant modifications or additional capital expenditures.

While many utilities can use Carefree CoalTM to comply

with SO2

 emissions limits, others cannot due to the high

content of organic sulfur in their coal feedstocks. When

compliance coal cannot be produced by reducing pyritic

sulfur, Self-Scrubbing CoalTM can be produced to achieve

compliance.

Self-Scrubbing CoalTM is produced by taking Carefree CoalTM, with its reduced pyritic sulfur and ash content, and adding to it sorbents, promoters, and catalysts.

Self-Scrubbing CoalTM is expected to achieve compliance

with virtually any U.S. coal feedstock through in-boiler

absorption of SO2

 emissions. The reduced ash content of

the Self-Scrubbing CoalTM permits addition of relatively

large amounts of sorbent without exceeding ash specifications of boilers or overloading electrostatic precipitators.

Coal Processing for Clean Fuels

Coal Preparation Technologies

Self-Scrubbing CoalTM: An

Integrated Approach to Clean

Air

Participant

Custom Coals International (a joint venture between

Genesis Coals Limited Partnership and Genesis Research

Corporation)

Additional Team Members

Pennsylvania Power & Light Company—host

Richmond Power & Light—host

Centerior Service Company—host

Locations

Central City, Somerset County, PA (advanced

coal-cleaning plant)

Lower Mt. Bethel Township, Northampton County, PA

(combustion tests at Pennsylvania Power & Light’s

Martin’s Creek Power Station, Unit 2)

Richmond, Wayne County, IN (combustion tests at

Richmond Power & Light’s Whitewater Valley

Generating Station, Unit No. 2)

Ashtabula, Trumbull County, OH (combustion tests at

Centerior Energy’s Ashtabula C)

Technology

Coal preparation using Custom Coals’ advanced physical

coal-cleaning and fine magnetite separation technology

plus sorbent addition technology

Plant Capacity/Production

500 tons/hr

Project Funding

Total project cost $87,386,102 100%

DOE 37,994,437 43

Participant 49,391,665 57

Self-Scrubbing Coal and Carefree Coal are trademarks of Custom Coals

International.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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 Project Fact Sheets 1997 119

Commercial Applications

Commercialization of Self-Scrubbing CoalTM has the

potential of bringing into compliance about 164 million

tons/yr of bituminous coal that cannot meet emissions

limits through conventional coal-cleaning. This represents more than 38% of the bituminous coal burned in

50-MWe or larger U.S. generating stations.

The technology produces coal products that can be

used to reduce a utility or industrial power plant’s total

sulfur emissions by 80–90%.

Custom Coals has been aggressively marketing the

technology in Eastern Europe and has received letters of

intent from Polish utilities interested in producing 5 million tons/yr of cleaned coal.

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.

Due to the inability to run the plant, financial strains

have been placed on Custom Coals. On May 13, 1997,

Custom Coals filed for Chapter 11. Tanoma Coal Sales,

Inc., has made an offer to buy the site and continue the

project. On August 28, 1997, Custom Coals formally

accepted Tanoma’s offer. The Federal Bankruptcy Court

approved the sale in a hearing on September 30, 1997.

Tanoma is preparing a detailed proposal to DOE concerning project completion. A market analysis has been completed. A cost analysis has been prepared for the project.

DOE is evaluating Tanoma’s offer; DOE must approve

the proposal before the project can proceed.

Two medium- to high-sulfur coals—Illinois No. 5

(2.7% sulfur) and Lower Freeport (3.9% sulfur)—are

being used to produce Self-Scrubbing CoalTM. Carefree

CoalTM is being made using Lower Kittanning (1.8%

sulfur). Lower Kittanning coal is being tested at Martin’s

Creek Power Station; Illinois No. 5 coal is being tested at

Whitewater Valley Generating Station; and Lower

Freeport Seam coal is being tested at Ashtabula C.

Project Status/Accomplishments

Start-up began in late December 1995, and the first coal

was processed in February 1996. In May 1996, the facility reached its design capacity. Equipment and circuit

optimization testing began immediately thereafter and

continued throughout 1996.

The Carefree CoalTM test burn (cleaned Lower

Kittanning coal) at Martin’s Creek Power Station was

conducted in mid-November 1996. Although plant optimization was not completed, the overall product made for

the test was consistent with the current quality of the plant

feed coal. The unit experienced some opacity problems

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Preaward

9/91 10/92

DOE selected

project (CCT-IV)

9/12/91

Construction started 12/93

Cooperative agreement awarded 10/29/92

NEPA process completed (EA) 2/14/94

Design and Construction Operation

2/96

Design completed 12/94

Preoperational tests initiated 11/95

Construction completed 11/95

Operation initiated 2/96

Note: Milestone schedule pending project restructuring
120 Project Fact Sheets 1997 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)

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 demonstration facility continues reliable operation;

for example, for the month of September 1997, the plant

achieved a 91% capacity factor. It has processed more

than 1.8 million tons of coal, and on April 19, 1997, the

plant produced its one millionth ton of SynCoal®. Total

sales of SynCoal® product have reached nearly 2 million

tons.

 SynCoal® products totaling over 220,000 tons have

been delivered over an extended period of time to several

industrial customers, including Ash Grove Cement, Bentonite Corporation, Wyoming Lime, Continental Lime, SynCoal is a registered trademark of the Rosebud SynCoal Partnership.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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 Project Fact Sheets 1997 121

DOE’s coal gasification test program.

The main product issue continues to be the spontaneous combustion tendency of the SynCoal®. Efforts also

are continuing to reduce operational costs per ton.

Commercial Applications

Rosebud SynCoal’s advanced coal conversion process has

the potential to enhance the use of low-rank western

subbituminous and lignite coals. Many of the power

plants located throughout the upper Midwest have cyclone boilers, which burn low-ash-fusion-temperature

coals. Currently, most of these plants burn Illinois Basin

high-sulfur coal. SynCoal® is an ideal low-sulfur coal

substitute for these and other plants because it allows

operation under more restrictive emissions guidelines

without requiring derating of the units or the addition of

costly flue gas desulfurization systems. The advanced

coal conversion process produces SynCoal® that has a

consistently low moisture content, low sulfur content,

high heating value, and high volatile content. Because of

these characteristics, SynCoal® could have significant

impact on SO2

 reduction and provide a clean, economical

alternative fuel to many regional industrial facilities and

small utilities being forced to use fuel oil and natural gas.

Rosebud SynCoal’s process, therefore, will be attractive

to industry and utilities because the upgraded fuel will be

less costly to use than would the construction and use of

flue gas desulfurization equipment.

SynCoal® technology is being marketed actively

worldwide. The partnership has been working closely

with a Japanese equipment and technology company to

expand into Asian markets. Prospects also are being

pursued in Europe. In September 1997, Rosebud

SynCoal signed a non-exclusive technology license with

NRG Energy.

and Empire Sand and Gravel. In May 1997, tests were

performed on several petroleum coke/SynCoal® blends.

 A SynCoal® test burn was completed at Montana

Power’s J.E. Corette in April 1996. The test involved

both handling and combustion of SynCoal® in a variety of

blends ranging from 15% to 85% SynCoal®. Overall

results indicated that a 50% SynCoal®/raw coal blend

provides improved results. SO2

 emissions were reduced

by 21% overall, generation increased at normal operating

loads, and there was no noticeable impact on NOx

 emissions.

SynCoal® and a blend of regular SynCoal® and fines

are being sent to Montana Power’s Colstrip Project Units

1 and 2, where tests will provide information on boiler

efficiency, output, and air emissions. Feasibility testing

had been successful and showed that by properly blending the product with DSE (dust stabilization enhancement) dust was controlled, making it possible to deliver

the blend. In November 1996, 25 tons of specific-sized

1.7 sulfur SynCoal® was sent to Morgantown for use in

Preaward Design and Construction Operation

1988 1989 1990 1991 1992 1993 1994 1996 1997 1998 1999

12/88 9/90 6/92

Design completed 8/91

DOE selected project

(CCT-I) 12/9/88

Cooperative agreement

awarded 9/21/90

Ground breaking/construction started 3/28/91

NEPA process completed (EA) 3/27/91

Preoperational tests initiated 12/91

Construction completed 2/92

Environmental monitoring plan completed 4/7/92

Test operation initiated 6/92

12/98

**

Project completed/final report

issued 12/98*

** Year omitted

Operation completed 7/98*
122 Project Fact Sheets 1997 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Mild Gasification

ENCOAL® Mild Coal

Gasification Project

Project completed.

Participant

ENCOAL® Corporation (a subsidiary of Bluegrass Coal

Development Company, which is a unit of Zeigler Coal

Holding Company)

Additional Team Members

Bluegrass Coal Development Company (formerly named

SMC Mining Company)—cofunder

TEK-KOL (partnership between SGI International and a

subsidiary of Zeigler Coal Holding Company)—

technology owner, supplier, and licenser

SGI International—technology developer

Triton Coal Company—host and coal supplier

The M.W. Kellogg Company—engineer and

constructor

Location

Near Gillette, Campbell County, WY (Triton Coal

Company’s Buckskin Mine)

Technology

SGI International’s Liquids-From-Coal (LFC®) process

Plant Capacity/Production

1,000 tons/day of subbituminous coal feed

Project Funding

Total project cost $90,664,000 100%

DOE 45,332,000 50

Participant 45,332,000 50

time are controlled to achieve desired properties of the

fuel products. During processing in the pyrolyzer, all

remaining free water is removed, and a chemical reaction

occurs that results in the release of volatile gaseous material. Solids exiting the pyrolyzer are cooled and transferred to a Process-Derived Fuel (PDF®) storage bin.

The gas produced in the pyrolyzer is sent through a

cyclone for removal of the particulates and then cooled

to condense the liquid-fuel products, or Coal-Derived

Liquids (CDL®). Most of the gas from the condensation

unit is recycled to the pyrolyzer. The rest of the gas is

burned in combustors to provide heat for the pyrolyzer

and the dryer. NOx

 emissions are controlled by staged air

injection.

The offgas from the dryer is treated in a wet venturi

scrubber to remove particulates and a horizontal scrubber

Project Objective

To demonstrate the integrated operation of a number of

novel processing steps to produce two higher value fuel

forms from mild gasification of low-sulfur subbituminous coal; to provide sufficient products for potential end

users to conduct burn tests.

Technology/Project Description

The ENCOAL® mild coal gasification process involves

heating coal under carefully controlled conditions. Coal

is fed into a rotary grate dryer where it is heated by a hot

gas stream to reduce the coal’s moisture content. The

solid bulk temperature is controlled so that no significant

amounts of methane, CO, or CO2

 are released from the

coal. The solids from the dryer are conveyed to a pyrolyzer where the rate of heating of the solids and residence

ENCOAL, LFC, CDL, and PDF are registered trademarks of TEK-KOL.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 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 Project Fact Sheets 1997 123

to remove SO2, both using a sodium carbonate solution.

The treated gas is vented to a stack, and the spent solution is discharged into a pond for evaporation.

The ENCOAL® project is located within Campbell

County, WY, at Triton Coal Company’s Buckskin Mine,

10 miles north of Gillette. The plant has made use of the

present coal-handling facilities at the mine. Subbituminous coal with 0.4–0.9% sulfur content was used.

Project Status/Accomplishments

The project completed operational testing in July 1997.

During the 5-year operational demonstration, the plant

operated approximately 12,800 hours. The plant processed approximately 247,000 tons of coal, operating at a

coal feed rate of 500 tons/day, as constrained by the

capacity of the new vibrating fluid-bed subsystem, and

producing 250 tons/day of PDF® and 280 barrels/day of

CDL®. By project’s end, more than 83,000 tons of specification PDF® had been shipped to seven utility and

industrial customers in six states, and 203 tank cars of

CDL® had been shipped to light industrial customers in

seven states.

In addition to Buckskin coal, ENCOAL® tested two

other coals: 3,280 tons of North Rochelle mine subbituminous coal and 3,000 tons of Wyodak coal. Also, Alaskan subbituminous coal, North Dakota lignite, and Texas

lignites were laboratory tested.

Commercial Applications

The liquid products from mild coal gasification can be

used in existing markets in place of No. 6 fuel oil. The

solid product can be used in most industrial or utility

boilers and also shows promise for iron ore reduction

applications. The feedstock for mild gasification is being

limited to high-moisture, low-heating-value coals.

The potential benefits of this mild gasification technology in its commercial configuration are attributable to

the increased heating value (about 12,000 Btu/lb) and

lower sulfur content (per unit of fuel value) of the new

solid-fuel product compared to the low-rank coal feedstock, and the production of low-sulfur liquid products

requiring no further treatment for the fuel oil market. The

product fuels are expected to be used economically in

commercial boilers and furnaces and to reduce significantly SO2

 emissions at industrial and utility facilities

currently burning high-sulfur bituminous coals or fuel oils.

ENCOAL® is continuing plant operation as a commercial facility. Feasibility studies have been completed

for two Indonesian projects and one Russian project; a

follow-up study has been approved by the Russian government and private participants.

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
124 Project Fact Sheets 1997 Coal Processing for Clean Fuels

Coal Processing for Clean Fuels

Indirect Liquefaction

Commercial-Scale

Demonstration of the LiquidPhase Methanol (LPMEOHTM)

Process

Participant

Air Products Liquid Phase Conversion Company, L.P.

(a limited partnership between Air Products and

Chemicals, Inc., the general partner, and Eastman

Chemical Company)

Additional Team Members

Air Products and Chemicals, Inc.—technology supplier

and cofunder

Eastman Chemical Company—host; operator; synthesis

gas and services provider

Acurex Environmental Corporation—fuel methanol

tester and cofunder

Electric Power Research Institute—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)

Project Funding

Total project cost $213,700,000 100%

DOE 92,708,370 43

Participant 120,991,630 57

the heat of reaction away from the catalyst surface. This

feature permits the direct use of synthesis gas streams as

feed to the reactor without the need for phase-shift conversion.

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 Objective

To demonstrate on a commercial scale the production of

methanol from coal-derived synthesis gas using the

LPMEOHTMprocess; and to determine the suitability of

methanol produced during this demonstration for use as a

chemical feedstock or as a low-SOx

, low-NOx alternative

fuel in stationary and transportation applications. 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 LPMEOH is a trademark of Air Products and Chemicals, Inc.
 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Calendar Year

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*Projected date

Coal Processing for Clean Fuels Project Fact Sheets 1997 125

Project Status/Accomplishments

Construction was completed and commissioning and

start-up began in January 1997. Methanol production in

the LPMEOHTM process demonstration unit began on

April 2, 1997. The first stable operation of the

LPMEOHTM process demonstration unit at nameplate

capacity of 80,000 gal/day occurred on April 6, 1997.

Eastman accepted all 1.67 million gallons of product

methanol from the initial run for use in its onsite chemicals production.

The second operating period ended July 28, 1997

following 985 hours on stream with 100% unit availability. During August, a 12-day test using CO-rich, coalderived synthesis gas feed was completed; methanol

production rates averaged 58,500 gal/day (190 tons/day).

The third operating period ended on November 3,

1997, with the longest continuous period (31 days) of

operation. Catalyst concentration was increased to the

design condition of 40% (wt), and the reactor temperature

was increased from 482 oF (the design condition) to

500 oF. Overall unit availability from start-up has approached 90%.

Reactor performance has shown faster decline than

expected. Follow-up sampling has confirmed the presence of arsine at levels similar to those measured in 1994,

prior to installation of an arsine guard bed. Recently, the

arsine guard bed material and the aged reactor catalyst

were replaced in preparation for the resumption of demonstration operations. To assist in the restart, the Alternative Fuels Field Test Unit, a transportable laboratory

equipped with an autoclave and analytical equipment, was

set up at the Kingsport site. In addition, laboratory autoclave testing and catalyst evaluations continue at Air

Products’ Allentown facilities.

Commercial Applications

The LPMEOHTM process has been developed to enhance

integrated gasification combined-cycle (IGCC) power

generation by producing a clean burning, storable liquid

fuel—methanol—from the clean coal-derived gas.

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 to 300,000 gal/day

of methanol produced when associated with commercial

IGCC power generation trains of 200–500 MWe. Air

Products expects to market the technology through licensing, owning/operating, and tolling arrangements.

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*
126 Project Fact Sheet 1997 Industrial Applications

Introduction

Technologies applicable to the industrial sector

address significant environmental issues and barriers

associated with coal use in industrial processes. These

technologies are directed at both continued coal use

and introduction of coal use in various industrial

sectors.

One of the critical environmental concerns has to

do with pollutant emissions resulting from producing

coke from coal in steelmaking. Two approaches to

mitigate or eliminate this problem are being demonstrated. In one, about 40 percent of the coke is displaced through direct injection of granular coal into a

blast furnace system. The coal is essentially burned in

the blast furnace where the pollutant emissions are

readily controlled (as opposed to first coking the coal).

The other approach precludes the need for coke making by using a direct iron-making process, COREX®. In

this process, raw coal is introduced into a 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 gas turbine for

electric power generation.

Because production costs are largely driven by

fuel cost, coal is often the fuel of choice in cement

production. Faced with the need to control SO2

 emissions and also to address growing solid waste management problems, industry sponsored the demonstration

of an innovative SO2 scrubber. The successfully demonstrated Passamaquoddy Technology Recovery

ScrubberTM uses cement kiln dust,

otherwise discarded as waste, to

control SO2

 emissions, convert the

sulfur and chloride acid gases to

fertilizer, return the solid by-product

as cement kiln feedstock, and produce

distilled water. No new wastes are

generated and cement kiln dust waste

is converted to feedstock. This technology also has application for

controlling pollutant emissions in

paper production and waste-to-energy

applications.

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

of coal makes it an attractive substitute for oil and gas feedstock. However, drawbacks to conversion of oil/

gas-fired units to coal include addition

of SO2 and NOx controls, tube fouling,

and the need for a coolant water

circuit for the combustor. Oil/gasfired 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

Shown here is the granular-coal injection system.

Shown here is the completed Bethlehem Steel Corporation facility to

demonstrate the injection of granulated coal directly into two blast furnaces at

Burns Harbor, IN.

Industrial Applications Technology
Industrial Applications Project Fact Sheets 1997 127

Exhibit 35

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 128

Demonstration Project metal/furnace

Advanced Cyclone Combustor with Internal Advanced slagging combustor with staged combustion and sorbent 23 million Btu/hr 130

Sulfur, Nitrogen, and Ash Control injection

Clean Power from Integrated Coal/Ore COREX® direct reduction iron-making process to eliminate coke; 195 MWe 134

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 136

and fertilizer and distilled water produced

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.

The cement kiln and slagging combustor projects

are completed. The project demonstrating granularcoal injection into a blast furnace is in operation.

Demonstration of the COREX® direct iron-making

process is in the project definition and design phase.

Exhibit 35 summarizes process characteristics and

size for the industrial applications technologies presented in more detail in the project fact sheets.
128 Project Fact Sheets 1997 Industrial Applications

Industrial Applications

Blast Furnace Granular-Coal

Injection System

Demonstration Project

Participant

Bethlehem Steel Corporation

Additional Team Members

British Steel Consultants Overseas Services, Inc.

(marketing arm of British Steel Corporation)—BFGCI

technology owner

CPC-Macawber, Ltd. (formerly named Simon-Macawber,

Ltd.)—equipment supplier (world rights to sublicense

BFGCI)

Fluor Daniel, Inc.—architect and engineer

ATSI, Inc.—injection equipment engineer

(North America BFGCI licensee)

Location

Burns Harbor, Porter County, IN (Bethlehem Steel’s

Burns Harbor Plant, Blast Furnace Units C and D)

Technology

British Steel and CPC-Macawber blast furnace granularcoal injection (BFGCI) process

Plant Capacity/Production

7,000 net tons/day of hot metal (each blast furnace)

Project Funding

Total project cost $194,301,790 100%

DOE 31,824,118 16

Participant 162,477,672 84

Project Objective

To demonstrate that existing iron-making blast furnaces

can be retrofitted with blast furnace granular-coal injection technology; and to demonstrate sustained

operation with a variety of coal particle sizes, coal injection rates, and coal types, and to assess the interactive

nature of these parameters.

Technology/Project Description

In the BFGCI process, either granular or pulverized coal

is injected into the blast furnace in place of natural gas (or

oil) as a blast furnace fuel supplement. The coal along

with heated air is blown into the barrel-shaped section in

the lower part of the blast furnace through passages called

tuyeres, which creates swept zones in the furnace called

raceways. The size of a raceway is important and is dependent upon many factors including temperature. Lowering of a raceway temperature, which can occur with gas

injection, reduces blast furnace production rates. Coal,

with a lower hydrogen content than either gas or oil, does

not cause as severe a reduction in raceway temperatures.

In addition to displacing injected natural gas, the coal

injected through the tuyeres displaces coke, the primary

blast furnace fuel and reductant (reducing agent), on

approximately a pound-for-pound basis. Because coke

production results in significant emissions of NOx

, SO2,

and air toxics and coal could replace up to 40% of the

coke requirement, BFGCI technology has significant

potential to reduce pollutant emissions and enhance blast

furnace production.

Emissions generated by the blast furnace itself

remain virtually unchanged by the injected coal; the gas

exiting the blast furnace is clean, containing no measurable SO2

 or NOx. Sulfur from the coal is removed by the

limestone flux and bound up in the slag, which is a

salable by-product. In addition to the net pollutant emissions reduction realized by coke displacement, blast

furnace production is increased by maintaining high

raceway temperatures.

Two high-capacity blast furnaces, Units C and D at

Bethlehem Steel’s Burns Harbor Plant, were retrofitted

with BFGCI technology. Each unit has a production
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Industrial Applications Project Fact Sheets 1997 129

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

capacity of 7,000 net tons/day of hot metal. The two

units use about 2,800 tons/day of coal during full operation. Bituminous coals with sulfur content of 0.8–2.8%

from West Virginia, Pennsylvania, Illinois, and Kentucky

are being used. A western coal having 0.4–0.9% sulfur

will be tested also.

Project Status/Accomplishments

From July to September 1997, Furnace C was operated

with an average coal injection rate of 261–271 lb/net ton

of hot metal on low-volatile bituminous coal. With coal

injection, the furnace continued to operate with a coke

rate of approximately 663–674 lb/net ton of hot metal,

down from a reference point of 770 lb/net ton of hot

metal using natural gas.

During the same time frame, the injection rate on

Furnace D averaged 193–201 lb/net ton of hot metal and

a coke rate of 702–718 lb/net ton of hot metal.

A comparison of high- and low-volatile coals as

injectants showed that low-volatile coal replaces more

coke and results in better blast furnace operation than

high-volatile coal. The replacement ratio with low-volatile coal is 0.96 lb coke/lb coal. A major conclusion of

the work to date was that granular-coal injection performs

very well on large blast furnaces.

Operational testing of Furnace C on high ash, low

volatile coal has been completed and is being analyzed. It

appears that as ash increases, the coke rate begins to

increase.

Operating experience during the past year seems to

indicate that the coal injection rate can increase if the

overall furnace iron production rate is held constant or

slightly decreased. Coal injection rates much greater than

300 lb/net ton of hot metal may require major modifications in burden distribution practices.

Burden compositions and oxygen injection are still

being adjusted to increase permeability and improve

operation and yield of hot metal. Tuyere replacement rate

has been significantly reduced.

In further testing, injection rates will be increased

while maintaining stable, high iron production rates.

Modifications will continue on primary feed cyclones to

convert to all stainless steel. Further testing of different

Preaward

DOE selected

project (CCT-III)

12/19/89

12/89 11/90

NEPA process completed (EA) 6/8/93

Construction started 9/93

Design completed 12/93

Cooperative agreement awarded 11/26/90

11/95

Operation initiated 11/95

Design and Construction Operation

Environmental monitoring plan completed 12/23/94

Preoperational tests initiated 2/95

Construction completed 2/95

9/98

Project completed/final report

issued 9/98*

Operation completed 9/98*

coals will include a direct comparison of granular versus

pulverized coal injection.

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 (then named

Simon-Macawber). British Steel has granted exclusive

rights to market BFGCI technology worldwide to

CPC-Macawber. CPC-Macawber also has the right to

sublicense BFGCI rights to other organizations throughout the world. British Steel and CPC-Macawber have

recently installed a similar facility at United States Steel’s

Fairfield blast furnace.
130 Project Fact Sheets 1997 Industrial Applications

particles near the cyclone wall. The combustor was designed to retain as slag a high percentage of the ash and

sorbent fed to the combustor. For NOx

 control, the combustor is operated fuel rich, with final combustion taking

place in the boiler furnace to which the combustor is

attached. SO2

 is captured by injection of limestone into

the combustor. The cyclonic action inside the combustor

forces the coal ash and sorbent to the walls where it can

be collected as liquid slag. Under optimum operating

conditions, the slag contains a significant fraction of

vitrified coal sulfur. Downstream sorbent injection into

the boiler provides additional sulfur removal

capacity.

In Coal Tech’s demonstration, an advanced, aircooled, cyclone coal combustor was retrofitted to a

23-million-Btu/hr, oil-designed package boiler located at

Technology/Project Description

Coal Tech’s horizontal cyclone combustor is internally

lined with ceramic that is air-cooled. Pulverized coal, air,

and sorbent are injected tangentially toward the wall

through tubes in the annular region of the combustor to

cause cyclonic action. In this manner, coal-particle combustion takes place in a swirling flame in a region favorable to particle retention in the combustor. Secondary air

is used to adjust the overall combustor stoichiometry.

Tertiary air is injected at the combustor/boiler interface.

The ceramic liner is cooled by the secondary air and

maintained at a temperature high enough to keep the slag

in a liquid, free-flowing state. The secondary air is preheated by the combustor walls to attain efficient combustion of the coal particles in the fuel-rich combustor. Fine

coal pulverization allows combustion of most of the coal

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 million Btu/hr

Coal

Pennsylvania bituminous, 1.0–3.3% sulfur

Project Funding

Total project cost $984,394 100%

DOE 490,149 50

Participant 494,245 50

Project Objective

To demonstrate that an advanced cyclone combustor can

be retrofitted to an industrial boiler and that it can simultaneously remove up to 90% of the SO2

 and 90–95% of

the ash within the combustor and reduce NOx

 to

100 ppm.
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Calendar Year

*Projected date

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Industrial Applications Project Fact Sheets 1997 131

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

the 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 molar ratios (Ca/S).

• SO2

 removal efficiencies up to 58% were achieved

with sorbent injection in the combustor at a Ca/S of

2.0.

• A maximum of 1/3 of the coal’s sulfur was retained in

the dry ash removed from the combustor (as slag) and

furnace hearth.

• At most, 11% of the coal’s sulfur was retained in the

slag rejected through the combustor’s slag tap.

• NOx

 emissions were reduced to 184 ppm by the combustor and furnace and to 160 ppm with the addition

of a wet particulate scrubber.

• Combustor slag was essentially inert.

• Ash/sorbent retention in the combustor as slag averaged 72% and ranged from 55% to 90%. Under more

fuel lean conditions, retention averaged 80%.

• Meeting local particulate emissions standards required

the addition of a wet venturi scrubber.

Operational

• Combustion efficiencies of over 99% were achieved.

• A 3-to-1 combustor turndown capability was demonstrated. Protection of combustor refractory with slag

was shown to be possible.

• A computer-controlled system for automatic combustor operation was developed and demonstrated.

Economic

• Because the technology failed to meet commercialization criteria, economics were not developed during the

demonstration. However, subsequent efforts indicate

that incremental capital costs for installing the coal

combustor in lieu of oil or gas systems are

$100–$200/kW.

Project Summary

The novel features of Coal Tech’s patented ceramic-lined,

slagging cyclone combustor included its air-cooled walls

and environmental control of NOx

, SO2, and solid waste

emissions. Air cooling took place in a very compact

combustor, which could be retrofitted to a wide range of

industrial and utility boiler designs without disturbing the

boiler’s water-steam circuit. In this technology, NOx

reduction was achieved by staged combustion, and SO2

was captured by injection of limestone into the combustor and/or boiler. Critical to combustor performance was

removal of ash, as slag, which would otherwise erode

boiler tubes. This was particularly important in oil furnace retrofits where tube spacing is tight (made possible

by the low-ash content of oil-based fuels).

The test effort consisted of 800 hours of operation,

including five individual tests, each of 4 days duration.

An additional 100 hours of testing was performed as part

8/91

Project completed/final report issued 9/91
132 Project Fact Sheet 1997 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% to 3.3% and volatile matter contents ranging from 19% to 37% were tested.

Environmental Performance

A maximum of over 80% SO2

 reduction

measured at the boiler outlet stack was

achieved using sorbent injection in the furnace at various Ca/S molar ratios. A maximum SO2

 reduction of 58% was measured at

the stack with limestone injection into the

combustor at a Ca/S of 2. A maximum of

one-third of the coal’s sulfur was retained in

the dry ash removed from the combustor and

furnace hearths, and as much as 11% of the coal’s sulfur

was retained in the slag rejected through the slag tap.

Additional sulfur retention in the slag is possible by increasing the slag flow rate and further improving fuel-rich

combustion and sorbent-gas mixing.

With fuel-rich operation of the combustor, a threefourths reduction in measured boiler outlet stack NOx

 was

obtained, corresponding to 184 ppm. An additional 5–

10% reduction was obtained by the action of the wet

particulate scrubber, resulting in atmospheric NOx

 emissions as low as 160 ppm.

All the slag removed from the combustor produced

trace metal leachates well below EPA’s Drinking Water

Standard.

Total ash/sorbent retention as slag in the combustor

under efficient combustion operating conditions averaged

72% and ranged from 55% to 90%. Under more fuel-lean

conditions, the slag retention averaged 80%.

In post-CCT-project tests on flyash vitrification in the

combustor, modifications to the solids injection system

and increases in the slag flow rate produced substantial

increases in the slag retention rate. To meet local stack

particulate emission standards, a wet venturi particulate

scrubber was installed at the boiler outlet.

Operational Performance

Combustion efficiencies exceeded 99% after proper operating procedures were achieved. Combustor turndown to

6 million Btu/hr from a peak of 19 million Btu/hr (or a

3-to-1 turndown) was achieved. The maximum heat input

during the tests was around 20 million Btu/hr, even

though the combustor was designed for 30 million Btu/hr

and the boiler was thermally rated at around 25 million

Btu/hr. This situation resulted from facility limits on

water availability for the boiler and for cooling the combustor. In fact, due to the lack of sufficient water cooling,

even 20 million Btu/hr was borderline, so that most of the

testing was conducted at lower rates.

Different sections of the combustor had different

materials requirements. Suitable materials for each section were identified. Also, the test effort showed that

operational procedures were closely coupled with materials durability. As an example, by implementing certain

procedures, such as changing the combustor wall temperature, it was possible to replenish the combustor refractory wall thickness with slag produced during combustion rather than by adding ceramic to the combustor

walls.

The combustor’s total operating time during the life

of the CCT project was about 900 hours. This included

approximately 100 hours of operation in two other flyash

vitrification tests projects. Of the total time, about onethird was with coal; about 125 tons of coal were consumed.

Developing proper combustor operating procedures

was also an objective. Not only were procedures for

properly operating an air-cooled combustor developed,

but the entire operating data base was incorporated into a

computer-controlled system for automatic combustor

operation.

Commercial Applications

In conclusion, the goal of this project was to validate the

performance of the air-cooled combustor at a commercial

scale. While the combustor was not yet fully ready for

sale with commercial guarantees, it was believed to have

commercial potential. Subsequent work was undertaken,

which has brought the technology close to commercial

introduction.

Contacts

Bert Zauderer, President, (215) 667-0442

Coal Tech Corporation

P.O. Box 154

Merion, PA 19066

William E. Fernald, DOE/HQ, (301) 903-9448

Arthur L. Baldwin, FETC, (412) 892-6011
Industrial Applications Project Fact Sheets 1997 133

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 Integral 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.)
134 Project Fact Sheets 1997 Industrial Applications

Project Funding

Total project cost $1,065,805,000 100%

DOE 149,469,242 14

Participant 916,335,758 86

Project Objective

To demonstrate the integration of a direct iron-making

process with the co-production of electricity using various

U.S. coals in an efficient and environmentally responsible

manner.

Technology/Project Description

The clean power from integrated coal/ore reduction

(CPICORTM) process integrates two historically distinct

processes—iron making and electric power generation.

COREX® is a novel iron-making technology that elimiIndustrial Applications

Clean Power from Integrated

Coal/Ore Reduction

(CPICORTM)

Participant

CPICORTM Management Company, L.L.C. (a limited

liability company composed of subsidiaries of Centerior

Energy Corporation, Air Products and Chemicals, Inc.,

and the Geneva Steel Company)

Additional Team Members

Geneva Steel Company—cofunder and host; constructor

and operator of COREX® unit

Centerior Energy Corporation—cofunder

Air Products and Chemicals, Inc.—cofunder; designer,

engineer, constructor, and operator of air separation

and combined-cycle units

Deutsche Voest-Alpine Industrieanlagenbau GmbH—

COREX® developer/supplier; designer and engineer of

COREX® unit

Location

Vineyard, Utah County, UT (Geneva Steel Company’s

mill)

Technology

Integration of Deutsche Voest-Alpine

Industrieanlagenbau’s COREX® iron-making process with

a combined-cycle power generation system

Plant Capacity/Production

195 MWe (net) or 250 MWe (gross) and 3,300 tons/day of

hot metal (liquid iron)

nates the need for coke production. The key innovative

features of the COREX® process include the reduction

shaft furnace, which is used to reduce the iron ore to iron,

and the melter-gasifier, located beneath the reduction

furnace, which gasifies the coal and melts the iron. The

gasification process generates the reducing gas for use in

the reduction furnace as well as sufficient heat to melt the

resulting iron in the melter-gasifier.

Excess reducing gas exiting the reduction furnace is

cooled, cleaned, compressed, mixed with air, and burned

in a gas turbine generator system capable of combusting

low-Btu gas to make electric power. The hot exhaust

from the turbine is then delivered to a heat recovery steam

generator where process steam is made for utilization in a

steam turbine generator system to produce additional

electric power.

COREX is a registered trademark of Deutsche Voest-Alpine

Industrieanlagenbau GmbH.
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*Projected date

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Industrial Applications Project Fact Sheets 1997 135

1993 1996 1997 1994 1995 1998 1999 2000 2001 2002 2003

During the demonstration, the facility will utilize

approximately 3,400 tons/day of a western bituminous

coal blend containing about 0.5% sulfur. The project will

produce 3,300 tons/day of hot metal and 195 MWe.

Project Status/Accomplishments

The cooperative agreement was awarded on October 11,

1996. Permitting and project definition are under way.

Negotiations with the technology vendor are continuing.

Baseline air monitoring is in progress at the Geneva Steel

Plant. The participant is continuing discussions on economic modeling of export gas production and power

generating/marketing. Establishing acceptable technical

baseline is proceeding slower than planned.

Commercial Applications

The CPICORTM technology is a direct replacement for

existing blast furnace and coke-making facilities with the

additional benefit of combined-cycle power generation.

A full-scale commercial plant based on the CPICORTM

demonstration project will produce 195 MWe (net exportable) and 1,200,000 tons/yr of hot metal while expanding

DOE selected project

(CCT-V) 5/4/93

5/93

the type of coals that can be used to produce hot metal

into the much larger noncoking range.

All criteria pollutants, particularly SO2

 and NOx, are

reduced by more than 85%. This reduction is due largely

to the desulfurizing capability of the COREX® process,

efficient control systems within the combined-cycle

power generation facility, and use of oxygen in place of

air. The COREX® process releases no air toxics from the

high-temperature gasifier into the environment, and most

trace elements are captured in the slag. The predominant

solid by-product of the COREX® process is a usable slag,

which is similar to blast furnace slag and can be sold as

construction blast.

The energy efficiency of the CPICORTM technology

is over 30% greater than the competing commercial technology when considering only the effective production of

hot metal and electric power. CPICORTM technology’s

higher efficiency is due to the more effective use of sensible heat and volatile matter than the coke-making/blast

furnace process. In addition, combined-cycle power

generation achieves energy efficiencies of nearly 50%.

Preaward

Cooperative agreement awarded 10/11/96

NEPA process completed (EIS) 4/98*

Construction started 4/98*

Design and Construction

Operation initiated 9/00*

Environmental monitoring plan completed 9/00*

Construction completed 9/00*

9/00

Operation

10/96 1/03

Project completed/final report issued 1/03*

Operation completed 1/03*

Of the existing 79 U.S. coke oven batteries, half

are 30 years of age or older and are due for replacement

or major rebuilds. There are about 60 U.S. blast furnaces,

all of which have been operating for more than

10 years, with some originally installed up to 90 years

ago. Worldwide, more than 300 blast furnaces with capacities of 0.3–1.2 million net tons/yr could be replaced

by COREX®.

The CPICORTM project exceeds the individual production rates of 75% of domestic blast furnaces. Further,

a utility facility scale-up by only 150% would exceed

production rates of 90% of existing U.S. blast furnaces.
136 Project Fact Sheets 1997 Industrial Applications

Industrial Applications

Cement Kiln Flue Gas

Recovery Scrubber

Project completed.

Participant

Passamaquoddy Tribe

Additional Team Members

Dragon Products Company—project manager and host

HPD, Incorporated—designer and fabricator of tanks and

heat exchanger

Cianbro Corporation—constructor

Location

Thomaston, Knox County, ME (Dragon Products

Company’s coal-fired cement kiln)

Technology

Passamaquoddy Technology Recovery ScrubberTM

Plant Capacity/Production

1,450 tons/day of cement; 250,000 std ft3

/min of kiln gas;

and up to 274 tons/day of coal

Coal

Pennsylvania bituminous, 2.5–3.0% sulfur

Project Funding

Total project cost $17,800,000 100%

DOE 5,982,592 34

Participant 11,817,408 66

Project Objective

To retrofit and demonstrate a full-scale industrial scrubber

and waste recovery system for a coal-burning wet process

cement kiln using waste dust as the reagent to accomplish

90–95% SO2

 reduction using high-sulfur eastern coals;

and to produce a commercial by-product, potassiumbased fertilizer.

Technology/Project Description

The Passamaquoddy Technology Recovery ScrubberTM

uses cement kiln dust (CKD), an alkaline-rich (potassium)

waste, to react with the acidic flue gas. This CKD, representing about 10% of the cement feedstock otherwise lost

as waste, is formed into a water-based slurry and mixed

with the flue gas as the slurry passes over a perforated

tray that enables the flue gas to percolate through the

slurry. The SO2

 in the flue gas reacts with the potassium

to form potassium sulfate, which stays in solution and

remains in the liquid as the slurry undergoes separation

into liquid and solid fractions. The solid fraction, in thickened slurry form and freed of the potassium and other

alkali constituents, is returned to the kiln as feedstock (it

is the alkali content that makes the CKD unusable as

feedstock). No dewatering is necessary for the wet process used at the Dragon Products Plant. The liquid fraction is passed to a crystallizer that uses waste heat in the

flue gas to evaporate the water and recover dissolved

alkali metal salts. A recuperator lowers the incoming flue

gas temperature to prevent slurry evaporation, enables the

use of low-cost fiberglass construction material, and

provides much of the process water through condensation

of exhaust gas moisture.

The Passamaquoddy Technology Recovery ScrubberTM was constructed at the Dragon Products Company’s

cement plant in Thomaston, ME, a plant that can process

approximately 450,000 tons/yr of cement. The process

was developed by the Passamaquoddy Indian Tribe while

it was seeking ways to solve landfill problems, which

resulted from the need to dispose of waste kiln dust from

the cement-making process. Passamaquoddy Technology Recovery Scrubber is a trademark of the

Passamaquoddy Tribe.
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*Projected date

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Industrial Applications Project Fact Sheets 1997 137

Results Summary

Environmental

• The SO2 removal efficiency averaged 94.6% during

the last several months of operation and 89.2% for the

entire operating period.

• The NOx

 removal efficiency averaged nearly 25%

during the last several months of operation and 18.8%

for the entire operating period.

• All of the 250-ton/day CKD waste produced by the

plant was renovated and reused as feedstock. This

resulted in reducing the raw feedstock requirement by

10% and eliminating solid waste disposal costs.

• Particulate emission rates of 0.005–0.007 gr/std ft3

,

about 1/10 that allowed for cement kilns, were

achieved with dust loadings of approximately

0.04 gr/std ft3

.

• Pilot testing conducted at U.S. Environmental Protection Agency laboratories under Passamaquoddy Technology, L.P., sponsorship showed 98% HCl removal.

• On three different runs, VOC (as represented by 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 3 basic operating

intervals dictated by winter shutdowns for maintenance

and inventory and 14 separate operating periods (within

these basic intervals) largely determined by unforeseen

2/94

Project completed/final report issued 2/94

Construction started 6/89

Operation

completed 9/93
138 Project Fact Sheet 1997 Industrial Applications

Exhibit 36

Summary of Emissions and Removal Efficiencies

Operating Operating Inlet (lb/hr) Outlet (lb/hr) % Removal Efficiency

Period Time (hr) SO2 NOx SO2 NOx SO2 NOx

1 211 73 320 10 279 87.0 12.8

2 476 71 284 11 260 84.6 08.6

3 464 87 292 13 251 85.4 14.0

4 259 131 252 16 165 87.6 34.5

5 304 245 293 28 243 88.7 17.1

6 379 222 265 28 208 87.4 21.3

7 328 281 345 28 244 90.1 29.3

8 301 124 278 10 188 91.8 32.4

9 314 47 240 7 194 85.7 19.0

10 402 41 244 6 218 86.1 10.5

11 460 36 315 6 267 83.4 15.0

12 549 57 333 2 291 95.9 12.4

13 464 86 288 4 223 95.0 22.6

14 405 124 274 9 199 92.4 27.4

Total 5,316

Weighted Avg 109 289 12 234 89.2 18.8

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 std ft3

/

min of flue gas. All the CKD, or approximately

10 tons/hr, were renovated and returned to the plant as

feedstock and mixed with about 90 tons/hr of fresh feed

to make up the required 100 tons/hr. The alkali in the

CKD was converted to potassium-based fertilizer, eliminating all solid waste. Exhibit 36 lists the number of

hours per operating period, SO2

 and NOx inlet and outlet

readings in pounds per hour, and removal efficiency as a

percentage for each operating period.

Average removal efficiencies during the demonstration period were 89.2% for SO2

 and 18.8% for NOx emissions. No definitive explanation for the NOx

 control

mechanics was available at the conclusion of the demonstration.

Aside from the operating period emissions data, an

assessment was made of inlet SO2 load impact on removal

efficiency. For SO2

 inlet loads in the range of 100 lb/hr

or less, recovery scrubber removal efficiency averaged

82.0%. For SO2

 inlet loads in the range of 100–200 lb/hr,

removal efficiency increased to 94.1% and up to 98.5%

for loads greater than 200 lb/hr.

In compliance testing for the state of Maine’s Department of Environmental Quality, the recovery scrubber

was subjected to dust loadings of approximately

0.04 gr/std ft3

 and demonstrated particulate emission rates

of 0.005–0.007 gr/std ft3

—less than 1/10 the current

allowable limit.
Industrial Applications Project Fact Sheets 1997 139

The Passamaquoddy Technology Recovery ScrubberTM became a

permanent part of the Dragon Products facility at the project’s end.

The Passamaquoddy Technology Recovery ScubberTM

was successfully demonstrated at Dragon Products

Company’s cement plant in Thomaston, ME.

Economic Performance

The estimated “as built” capital cost to reconstruct the

Dragon Products prototype, absent the modifications, is

$10,090,000 in 1990 dollars.

Annual operating and maintenance costs are estimated at $500,000. Long-term annual maintenance costs

are estimated at $150,000. Power costs, estimated at

$350,000/yr, are the only significant operating costs.

There are no costs for reagents or disposal, and no dedicated staffing or maintenance equipment are required.

Considering various revenues and avoided costs that

may be realized by installing a recovery scrubbersimilar

in size to the one used at Dragon Products, simple payback on the investment is projected in as little as

3.1 years. In making this projection, $6,000,000 was

added to the “as built” capital costs to allow for contingency, design/permitting, construction interest, and licensing fees.

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

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.)
Project Fact Sheets 1997 A-1

Appendix A: CCT Project Contacts

Confined Zone Dispersion Flue Gas

Desulfurization Demonstration

Participant:

Bechtel Corporation

Contacts:

Joseph T. Newman, Project Manager

(415) 768-1189

(415) 768-3580 (fax)

Bechtel Corporation

P.O. Box 193965

San Francisco, CA 94119-3965

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

LIFAC Sorbent Injection Desulfurization

Demonstration Project

Participant:

LIFAC–North America

Contacts:

Jim Hervol, Project Manager

(412) 497-2235

(412) 497-2298 (fax)

ICF Kaiser Engineers, Inc.

Gateway View Plaza

1600 West Carson Street

Pittsburgh, PA 15219-1031

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Advanced Flue Gas Desulfurization Demonstration

Project

Participant:

Pure Air on the Lake, L.P.

Contacts:

Don C. Vymazal, Manager, Contract Administration

(610) 481-3687

Pure Air on the Lake, L.P.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Demonstration of Innovative Applications of

Technology for the CT-121 FGD Process

Participant:

Southern Company Services, Inc.

Contacts:

David P. Burford, Project Manager

(205) 992-6329

david.p.burford@scsnet.com

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Listed below are contacts for obtaining further

information about specific CCT Program

demonstration projects. Listed are the name, title,

phone number, fax number, mailing address, and

e-mail address for the participant’s contact person. In

those instances where the project participant consists

of more than one company, a partnership, or joint

venture, the mailing address listed is that of the

contact person. In addition, the names, phone

numbers, and e-mail addresses for contact persons at

DOE Headquarters and the Federal Energy

Technology Center are provided.

Environmental Control Devices—SO2 Control

Technologies

10-MWe Demonstration of Gas Suspension

Absorption

Participant:

AirPol, Inc.

Contacts:

Frank E. Hsu,Vice President, Operations

(201) 490-6400

(201) 538-8066 (fax)

AirPol, Inc.

3 Century Drive

Parsippany, NJ 07054-4610

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

lawrence.saroff@hq.doe.gov

Sharon K. Marchant, FETC, (412) 892-6008

marchant@fetc.doe.gov
A-2 Project Fact Sheets 1997

Evaluation of Gas Reburning and Low-NOx

Burners on a Wall-Fired Boiler

Participant:

Energy and Environmental Research Corporation

Contacts:

Blair A. Folsom, Senior Vice President

(714) 859-8851

(714) 859-3194 (fax)

Energy and Environmental Research

Corporation

18 Mason

Irvine, CA 92718

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

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Micronized Coal Reburning Demonstration of NOx

Control

Participant:

New York State Electric & Gas Corporation

Contacts:

Dennis O'Dea, Project Manager

(607) 729-2551

New York State Electric & Gas Corporation

120 Chenango Street

Binghamton, NY 13902

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

Demonstration of Advanced Combustion

Techniques for a Wall-Fired Boiler

Participant:

Southern Company Services, Inc.

Contacts:

John N. Sorge, Research Engineer

(205) 257-7426

(205) 257-5367

john.sorge@scsnet.com

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

lawrence.saroff@hq.doe.gov

Scott M. Smouse, FETC, (412) 892-5725

smouse@fetc.doe.gov

Demonstration of Selective Catalytic Reduction

Technology for the Control of NOx Emissions from

High-Sulfur-Coal-Fired Boilers

Participant:

Southern Company Services, Inc.

Contacts:

Robert R. Hardman, Project Manager

(205) 257-7772

rob.hardman@scsnet.com

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

lawrence.saroff@hq.doe.gov

Arthur L. Baldwin, FETC, (412) 892-6011

baldwin@fetc.doe.gov

Environmental Control Devices—NOx

 Control

Technologies

Demonstration of Coal Reburning for Cyclone

Boiler NOx

 Control

Participant:

The Babcock & Wilcox Company

Contacts:

Tony Yagiela

(330) 829-7403

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

lawrence.saroff@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell.fetc.doe.gov

Full-Scale Demonstration of Low-NOx CellBurner

Retrofit

Participant:

The Babcock & Wilcox Company

Contacts:

Tony Yagiela

(330) 829-7403

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

lawrence.saroff@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell@fetc.doe.gov
Project Fact Sheets 1997 A-3

LIMB Demonstration Project Extension and

Coolside Demonstration

Participant:

The Babcock & Wilcox Company

Contacts:

Paul Nolan

(216) 860-1074

(216) 860-2045 (fax)

The Babcock & Wilcox Company

20 South Van Buren Avenue

P.O. Box 351

Barberton, OH 44203-0351

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

SOx

-NOx-Rox BoxTM Flue Gas Cleanup

Demonstration Project

Participant:

The Babcock & Wilcox Company

Contacts:

Kevin Redinger

(330) 829-7719

The Babcock & Wilcox Company

1562 Beeson Street

Alliance, OH 44601

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

lawrence.saroff@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell@fetc.do.gov

Enhancing the Use of Coals by Gas Reburning and

Sorbent Injection

Participant:

Energy and Environmental Research Corporation

Contacts:

Blair A. Folsom, Senior Vice President

(714) 859-8851

(714) 859-3194 (fax)

Energy and Environmental Research

Corporation

18 Mason

Irvine, CA 92718

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

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Milliken Clean Coal Technology Demonstration

Project

Participant:

New York State Electric & Gas Corporation

Contacts:

Dennis O’Dea, Project Manager

(607) 729-2551

New York State Electric & Gas Corporation

120 Chenango Street

Binghamton, NY 13902

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov

180-MWe Demonstration of Advanced

Tangentially Fired Combustion Techniques for the

Reduction of NOx

 Emissions from Coal-Fired

Boilers

Participant:

Southern Company Services, Inc.

Contacts:

Robert R. Hardman, Project Manager

(205) 257-7772

rob.hardman@scsnet.com

Southern Company Services, Inc.

P.O. Box 2625

Birmingham, AL 35202-2625

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

lawrence.saroff@hq.doe.gov

Scott M. Smouse, FETC, (412) 892-5725

smouse@fetc.doe.gov

Environmental Control Devices—Combined

SO2/NOx Control Technologies

SNOXTM Flue Gas Cleaning Demonstration

Project

Participant:

ABB Environmental Systems

Contacts:

Paul Yosick, Project Manager

(423) 653-7550

ABB Environmental Systems

1400 Center Port Boulevard

Knoxville, TN 37932

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

lawrence.saroff@hq.doe.gov

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

watts@fetc.doe.gov
A-4 Project Fact Sheets 1997

Commercial Demonstration of the NOXSO

SO2/NOx Removal Flue Gas Cleanup System

Participant:

NOXSO Corporation

Contacts:

James B. Black

(412) 854-1200

(412) 854-5729 (fax)

noxso@city-net.com

NOXSO Corporation

2414 Lytle Road

Bethel Park, PA 15102-2704

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

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Integrated Dry NOx

/SO2 Emissions Control System

Participant:

Public Service Company of Colorado

Contacts:

Terry Hunt, Project Manager

(303) 571-7113

(303) 571-7868 (fax)

thunt@msp.psco.com

Public Service Company of Colorado

550 15th Street, Suite 880

Denver, CO 80202

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

lawrence.saroff@hq.doe.gov

Jerry L. Hebb, FETC, (412) 892-6079

hebb@fetc.doe.gov

Tidd PFBC Demonstration Project

Participant:

American Electric Power Service Corporation as

agent for The Ohio Power Company

Contacts:

Mario Marrocco

(614) 223-2460

(614) 223-3204 (fax)

American Electric Power Service Corporation

1 Riverside Plaza

Columbus, OH 43215

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

Jacksonville Electric Authority Large-Scale CFB

Combustion Demonstration Project

Participant:

Jacksonville Electric Authority

Contacts:

Reece E. Comer, Jr. P.E.

(904) 655-6312

comere@jea.com

Jacksonville Electric Authority

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

Advanced Electric Power Generation—

Fluidized-Bed Combustion

McIntosh Unit 4A PCFB Demonstration Project

Participant:

City of Lakeland, Department of Electric & Water

Utilities

Contacts:

Alfred M. Dodd, Project Manager

(941) 499-6461

(941) 499-6344 (fax)

Lakeland Electric & Water Utilities

501 E. Lemon Street

Lakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov

McIntosh Unit 4B Topped PCFB Demonstration

Project

Participant:

City of Lakeland, Department of Electric & Water

Utilities

Contacts:

Alfred M. Dodd, Project Manager

(941) 499-6461

(941) 499-6344 (fax)

Lakeland Electric & Water Utilities

501 E. Lemon Street

Lakeland, FL 33801-5079

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Donald W. Geiling, FETC, (304) 285-4784

dgeili@fetc.doe.gov
Project Fact Sheets 1997 A-5

Nucla CFB Demonstration Project

Participant:

Tri-State Generation and Transmission

Association, Inc.

Contacts:

Marshall L. Pendergrass, Assistant General Manager

(303) 249-4501

Tri-State Generation and Transmission

Association, Inc.

P.O. Box 1149

Montrose, CO 81402

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Advanced Electric Power Generation—

Integrated Gasification Combined Cycle

Clean Energy Demonstration Project

Participant:

Clean Energy Partners Limited Partnership

Contacts:

Victor Shellhorse, Vice President

(704) 373-2474

(704) 382-9325 (fax)

Duke Energy Corp.

400 S. Tryon Street

Charlotte, NC 28202

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Gary A. Nelkin, FETC, (304) 285-4216

gnelki@fetc.doe.gov

Piñon Pine IGCC Power Project

Participant:

Sierra Pacific Power Company

Contacts:

Sherry Dawes, Project Manager

(702) 343-0816

(702) 343-0407 (fax)

sherry@sppco.sppco.com

Sierra Pacific Power Company

6100 Neil Road

Reno, NV 89520-0400

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

Web Site:

http://www.sierrapacific.com/utilserv/electric/pinon

Tampa Electric Integrated Gasification CombinedCycle Project

Participant:

Tampa Electric Company

Contacts:

Donald E. Pless, Director, Advanced Technology

(813) 228-1332

(813) 228-4802 (fax)

TECO Power Services, Inc.

P.O. Box 111

Tampa, FL 33601-0111

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Web Site:

http://www.teco.net/teco/TEPlkPwrStn.html

Wabash River Coal Gasification Repowering

Project

Participant:

Wabash River Coal Gasification Repowering Project

Joint Venture

Contacts:

Phil Amick

(713) 735-4178

(713) 735-4837 (fax)

amick@destec.attmail.com

Destec Energy, Inc.

2500 CityWest Boulevard, Suite 150

Houston, TX 77042

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Gary A. Nelkin, FETC, (304) 285-4216

gnelki@fetc.doe.gov
A-6 Project Fact Sheets 1997

Advanced Electric Power Generation—

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.alaska.net

Alaska Industrial Development and Export

Authority

480 West Tudor Road

Anchorage, AK 99503-6690

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Robert M. Kornosky, FETC, (412) 892-4521

kornosky@fetc.doe.gov

Clean Coal Diesel Demonstration Project

Participant:

Arthur D. Little, Inc.

Contacts:

Robert P. Wilson, Vice President

(617) 498-5806

(617) 498-7206 (fax)

Arthur D. Little, Inc.

200 Acorn Park

Cambridge, MA 02140

George Lynch, DOE/HQ, (301) 903-9434

george.lynch@hq.doe.gov

Nelson F. Rekos, FETC, (304) 285-4066

nrekos@fetc.doe.gov

Coal Processing for Clean Fuels—

Coal Preparation Technologies

Development of the Coal Quality ExpertTM

Participants:

ABB Combustion Engineering, Inc., and CQ Inc.

Contacts:

Clark D. Harrison, President

(412) 479-6016

CQ Inc.

One Quality Center

P.O. Box 280

Homer City, PA 15748-0280

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Scott M. Smouse, FETC, (412) 892-5725

smouse@fetc.doe.gov

Web Site:

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

Self-Scrubbing CoalTM: An Integrated Approach

to Clean Air

Participant:

Custom Coals International

Contacts:

Robin Godfrey, President and CEO

(412) 642-2625

Custom Coals International

100 First Avenue, Suite 500

Pittsburgh, PA 15222

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk, FETC, (412) 892-6249

renk@fetc.doe.gov

Advanced Coal Conversion Process Demonstration

Participant:

Rosebud SynCoal Partnership

Contacts:

Ray W. Sheldon, P.E., Director of Development

(406) 748-2366 or (406) 252-2277

Rosebud SynCoal Partnership

P.O. Box 7137

Billings, MT 59103-7137

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Joseph B. Renk, FETC, (412) 892-6249

renk@fetc.doe.gov

Coal Processing for Clean Fuels—

Mild Gasification

ENCOAL® Mild Coal Gasification Project

Participant:

ENCOAL® Corporation

Contacts:

Brent A. Knottnerus, Project Manager

(307) 686-5486

(307) 682-7938 (fax)

bknottnerus@vcn.com

ENCOAL® Corporation

P.O. Box 3038

Gillette, WY 82717

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov
Project Fact Sheets 1997 A-7

Coal Processing for Clean Fuels—Indirect

Liquefaction

Commercial-Scale Demonstration of the LiquidPhase Methanol (LPMEOHTM) Process

Participant:

Air Products Liquid Phase Conversion Company, L.P.

Contacts:

Edward C. Heydorn, Project Manager

(610) 481-7099

(610) 706-7299 (fax)

heydorec@apci.com

Air Products and Cemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

Edward Schmetz, DOE/HQ, (301) 903-3931

edward.schmetz@hq.doe.gov

Robert M. Kornosky, FETC, (412) 892-4521

kornosky@fetc.doe.gov

Industrial Applications

Blast Furnace Granular-Coal Injection System

Demonstration Project

Participant:

Bethlehem Steel Corporation

Contacts:

Robert W. Bouman, Project Director

(610) 694-6792

(610) 694-2981 (fax)

Bethlehem Steel Corporation

Homer Research Laboratory

Building C, Room 211

Bethlehem, PA 18016

Douglas Archer, DOE/HQ, (301) 903-9443

douglas.archer@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

Advanced Cyclone Combustor with Internal

Sulfur, Nitrogen, and Ash Control

Participant:

Coal Tech Corporation

Contacts:

Bert Zauderer, President

(215) 667-0442

Coal Tech Corporation

P.O. Box 154

Merion, PA 19066

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Arthur L. Baldwin, FETC, (412) 892-6011

baldwin@fetc.doe.gov

Clean Power from Integrated Coal/Ore Reduction

(CPICORTM)

Participant:

CPICORTM Management Company, L.L.C.

Contacts:

Brian O’Neil

(610) 481-5683

(610) 481-2576 (fax)

Air Products and Chemicals, Inc.

7201 Hamilton Boulevard

Allentown, PA 18195-1501

William Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

Douglas M. Jewell, FETC, (304) 285-4720

djewel@fetc.doe.gov

Cement Kiln Flue Gas Recovery Scrubber

Participant:

Passamaquoddy Tribe

Contacts:

Thomas N. Tureen, Project Manager

(207) 773-7166

(207) 773-8832 (fax)

ttureen@gwi.com

Passamaquoddy Technology, L.P.

1 Monument Way

Portland, ME 04101

William E. Fernald, DOE/HQ, (301) 903-9448

william.fernald@hq.doe.gov

John C. McDowell, FETC, (412) 892-6237

mcdowell@fetc.doe.gov
A-8 Project Fact Sheets 1997
Project Fact Sheets 1997 B-1

Appendix B: Acronyms and Abbreviations

Acronyms

ABB CE ABB Combustion Engineering, Inc.

ABB ES ABB Environmental Systems

ACFB atmospheric circulating fluidized bed

AFBC atmospheric fluidized-bed

combustion

AFGD advanced flue gas desulfurization

AIDEA Alaska Industrial Development and

Export Authority

AOFA advanced overfire air

AR&TD advanced research and technology

development

BFGCI blast furnace granular-coal injection

BG British Gas

BG/L British Gas/Lurgi

B&W The Babcock & Wilcox Company

CAAA Clean Air Act Amendments of 1990

CAPI Clean Air Power Initiative

CCOFA close-coupled overfire air

CCT clean coal technology

CCT Program Clean Coal Technology

Demonstration Program

CDL coal-derived liquid

CEQ Council on Environmental Quality

CFB circulating fluidized bed

CKD cement kiln dust

COP Conference of Parties

CT-121 Chiyoda Thoroughbred-121

CQE Coal Quality Expert

CX categorical exclusion

CZD confined zone dispersion

DER discrete emissions reduction

DME dimethyl ether

DOE U.S. Department of Energy

DOE/HQ U.S. Department of Energy

Headquarters

EA environmental assessment

EER Energy and Environmental Research

Corporation

EFCC externally fired combined cycle

EIA Energy Information Administration

EIS environmental impact statement

EMP environmental monitoring plan

EPA U.S. Environmental Protection

Agency

EPAct Energy Policy Act of 1992

EPRI Electric Power Research Institute

ESP electrostatic precipitator

EWG exempt wholesale generator

FBC fluidized-bed combustion

FCCC Framework Convention on Climate

Change

FERC Federal Energy Regulatory

Commission

FETC Federal Energy Technology Center

FGD flue gas desulfurization

FONSI finding of no significant impact

FRP fiberglass-reinforced plastic

FY fiscal year

GE General Electric

GHG greenhouse gases

GNOCIS Generic NOx

 Control Intelligent

System

GPM gallons per minute

GR gas reburning

GR–LNB gas reburning and low-NOx burner

GR–SI gas reburning and sorbent injection

GSA gas suspension absorption

HAP(s) hazardous air pollutant(s)

HHV high heating value

HRSG heat recovery steam generator

IEA International Energy Agency

IGCC integrated gasification combined

cycle

JBR Jet Bubbling Reactor®

LHV low heating value

LIMB limestone injection multistage

burner

LNB low-NOx

 burner

LNCFS Low-NOx

 Concentric-Firing System

LOI loss on ignition

LSFO limestone forced oxidation

MASB multi-annular swirl burner

MCFC molten carbonate fuel cell

MTCI Manufacturing and Technology

Conversion International

MTF memorandum (memoranda)-to-file

NAAQS National Ambient Air Quality

Standards

NEPA National Environmental Policy Act

NOPR Notice of Proposed Rulemaking

NSPS New Source Performance Standards
B-2 Project Fact Sheets 1997

NTIS National Technical Information

Service

NYSEG New York State Electric & Gas

Corporation

O&M operating and maintenance

OTAG Ozone Transport Assessment Group

OTC Ozone Transport Commission

PC personal computer

PCFB pressurized circulating fluidized bed

PDF process-derived fuel

PEIA programmatic environmental impact

assessment

PEIS programmatic environmental impact

statement

PEOA Plant Emission Optimization

Advisor

PEP progress evaluation plan

PFBC pressurized fluidized-bed

combustion

PJBH pulse jet baghouse

PM particulate matter

PON program opportunity notice

PRB Powder River Basin

PSCC Public Service Company of Colorado

PSD Prevention of Significant

Deterioration

PUHCA Public Utility Holding Company

Act of 1935

PURPA Public Utility Regulatory Policies

Act of 1978

QF qualified facilities

RAM random access memory

R&D research and development

RD&D research, development, and

demonstration

REA Rural Electrification Administration

SBIR Small Business Innovation Research

SCR selective catalytic reduction

SCS Southern Company Services, Inc.

SFC Synthetic Fuels Corporation

SI sorbent injection

SIP state implementation plan

SNCR selective noncatalytic reduction

SOFA separated overfire air

STTR Small Business Technology

Transfer Program

SVGA super video graphics adapter

TCLP toxicity-characteristics leaching

procedure

TVA Tennessee Valley Authority

UARG Utility Air Regulatory Group

UBCL unburned carbon boiler efficiency

losses

U.K. United Kingdom

U.S. United States

VOC volatile organic compound

WES wastewater evaporation system

WLFO wet limestone, forced oxidation

Abbreviations

States are abbreviated using two-letter postal codes.

atm atmosphere(s)

avg average

Btu British thermal unit(s)

C/H molar ratio of carbon to hydrogen

CaCO3 calcium carbonate (calcitic

limestone)

CaO calcium oxide (lime)

Ca(OH)2 calcium hydroxide (calcitic

hydrated lime)

Ca(OH)2•MgO dolomitic hydrated lime

Ca/N molar ratio of calcium to nitrogen

Ca/S molar ratio of calcium to sulfur

CaSO3 calcium sulfite

CaSO4 calcium sulfate

CO carbon monoxide

CO2 carbon dioxide

°F degrees Fahrenheit

ft, ft2

, ft3 foot (feet), square feet, cubic feet

gal gallon(s)

GB gigabyte(s)

GW gigawatt(s)

GWe gigawatt(s)-electric

H2S hydrogen sulfide

H2SO4 sulfuric acid

HCl hydrogen chloride

HF hydrogen fluoride

hr hour(s)

in, in2

, in3 inch(es), square inches, cubic inches

KCl potassium chloride

K2SO4 potassium sulfate
Project Fact Sheets 1997 B-3

kW kilowatt(s)

kWh kilowatt-hour(s)

lb pound(s)

MB megabyte(s)

MgCO

3 magnesium carbonate

MgO magnesium oxide

Mhz megahertz

min minute(s)

mo month(s)

MW megawatt(s)

MWe megawatt(s)-electric

MWt megawatt(s)-thermal N2 atmospheric nitrogen

Na/Ca molar ratio of sodium to calcium

Na

2

/S molar ratio of sodium to sulfur

NaOH sodium hydroxide

Na

2

CO

3 sodium carbonate

NH

3 ammonia

NO

2 nitrogen dioxide

NO

x nitrogen oxides

O

2 oxygen

ppm parts per million (mass)

ppmv parts per million by volume

psi pound(s) per square inch

rpm revolutions per minute

S sulfur

SO

2 sulfur dioxide

SO

3 sulfur trioxide

std ft

3 standard cubic feet

yr year(s)
B-4 Project Fact Sheets 1997