Reburning Technologies for the Control of Nitrogen

Oxides Emissions from Coal-Fired Boilers

TOPICAL REPORT NUMBER 14 MAY 1999
TOPICAL REPORT NUMBER 14

A report on three projects conducted under

separate cooperative agreements between:

The U.S. Department of Energy and

 • The Babcock & Wilcox Company

 • Energy and Environmental Research Corporation

 • New York State Electric & Gas Corporation

MAY 1999

Reburning Technologies

for the Control of Nitrogen

Oxides Emissions

from Coal-Fired Boilers
Cover image: Schematic of reburning technology

Source: Energy and Environmental Research Corporation
Reburning Technologies

for the Control of Nitrogen

Oxides Emissions

from Coal-Fired Boilers

Executive Summary.................................................................................................. 5

Background............................................................................................................... 6

NOx Emissions Standards ........................................................................................ 6

NOx Control Technologies....................................................................................... 9

The Reburning Process ........................................................................................... 10

Clean Coal Technology Reburning Demonstration Projects.................................. 11

Demonstration of Coal Reburning for Cyclone Boiler NOx Control................... 13

Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler .... 17

Micronized Coal Reburning Demonstration for NOx Control ............................. 20

Conclusions ............................................................................................................ 24

Bibliography ........................................................................................................... 27

Contacts for CCT Projects and U.S. DOE CCT Program ...................................... 31

List of Acronyms and Abbreviations ..................................................................... 32
Executive Summary

The Clean Coal Technology (CCT)

Demonstration Program is a government

and industry co-funded effort to demonstrate a new generation of innovative

coal utilization processes in a series

of “showcase” facilities built across the

country. These projects are carried out

on a scale sufficiently large to demonstrate commercial worthiness and to

generate data for design, construction,

operation, and technical/economic

evaluation of full-scale commercial

applications.

The goal of the CCT Program is

to furnish the U.S. energy marketplace

with a number of advanced, more efficient coal-based technologies meeting

strict environmental standards. These

technologies will mitigate the economic

and environmental impediments that

limit the full utilization of coal as a continuing viable energy resource.

To achieve this goal, beginning in

1985, a multiphased effort consisting of

five separate solicitations was administered by the U.S. Department of Energy’s

(DOE) Federal Energy Technology Center (FETC). Projects selected through

these solicitations have demonstrated

technology options with the potential

to meet the needs of energy markets

while satisfying relevant environmental

requirements.

Part of this program is the demonstration of reburning technologies on

existing coal-fired utility boilers to reduce emissions of nitrogen oxides

(NOx). NOx is an acid rain precursor

and a contributor to the formation of

ground-level ozone, which is a health

hazard and a major component of smog.

NOx emissions are regulated under the

provisions of the 1990 Clean Air Act

Amendments (CAAA).

In applying reburning to a coal-fired

boiler, the furnace is subdivided into

three zones: (1) the primary combustion zone, where the bulk of the coal

is burned with relatively low levels of

excess air (NOx is formed in this zone);

(2) the reburn zone, where 10% to 30%

of the total heat is provided as reburn

fuel and where, under reducing conditions, NOx is converted to molecular nitrogen; and (3) the burnout zone, where

overfire air is injected to complete burnout of the remaining combustibles.

This report discusses three CCT

reburning projects:

• Coal Reburning for Cyclone Boiler NOx

Control was tested by The Babcock &

Wilcox Company on a 110-MWe (gross)

cyclone boiler at Wisconsin Power &

Light Company’s Nelson Dewey plant

in Cassville, Wisconsin. The objective

was to demonstrate 50% or greater

NOx reduction. This goal was achieved,

using both bituminous and subbituminous coals. The technology was

effective at turndown ratios of 66%

and 63%, respectively. Process flexibility was excellent.

• Gas Reburning-Low-NOx Burners

(GR-LNB) was tested by Energy and

Environmental Research Corporation

on a 158-MWe (net) wall-fired boiler

at Public Service Company of

Colorado’s Cherokee Station near

Denver, Colorado. The objective was

to attain 70% reduction of NOx emissions. Low-NOx burners (LNBs) alone

reduced NOx emissions by only 37%,

which was less than the target level of

45%. As a result, the GR-LNB combination, which achieved 66% NOx

reduction, fell slightly short of the

target. However, the 70% target reduction was achieved in short-term testing.

No significant adverse impacts on boiler

performance were found. A turndown

ratio of 50% was achieved.

• Micronized Coal Reburning was tested

by New York State Electric & Gas

Corporation (NYSEG) on a 50-MWe

equivalent industrial cyclone boiler at

the Kodak Park steam plant, Rochester,

New York, and at a 150-MWe (net)

tangentially fired boiler at NYSEG’s

Milliken Station in Lansing, New York.

This project was aimed at improving

coal reburning by further size reduction

of the reburn coal. The project achieved

57% NOx emissions reduction at Kodak

Park and 28% reduction in conjunction

with LNBs at Milliken.

For a 110-MWe cyclone boiler, the

estimated capital cost of coal reburning

is $66/kW, and the levelized cost is

$1,075/ton of NOx removed. For GR-LNB

installed on a 300-MWe wall-fired boiler

with 12.5% natural gas reburn heat input,

the estimated capital cost is $26/kW, and

the levelized cost is $1,187/ton, assuming that natural gas is available on-site.

Cost estimates for micronized coal

reburning are not yet available. The economics presented in this report have been

provided by the technology suppliers and

are not on the same basis, such as plant

capacity and financial parameters. Therefore, they cannot be directly compared.

A number of reburn retrofits have

been demonstrated or are operating on

a commercial scale on coal-fired boilers

in the U.S., and several others are on

order. In light of increasingly stringent

environmental regulations, the potential

U.S. market for reburning appears to

be significant, particularly in combination with other NOx emissions

control technologies.
Reburning Technologies

for the Control of Nitrogen

Oxides Emissions from

Coal-Fired Boilers

Background

The Clean Coal Technology (CCT)

Demonstration Program, sponsored by

the U.S. Department of Energy (DOE),

is a government and industry co-funded

technology development effort conducted since 1985 to demonstrate a new

generation of innovative coal-utilization

processes.

The CCT Program involves a series

of “showcase” projects, conducted on

a scale sufficiently large to demonstrate

commercial worthiness and generate data

for design, construction, operation, and

economic/technical evaluation of fullscale commercial applications. The goal

of the CCT Program is to furnish the

U.S. energy marketplace with advanced,

more efficient coal-based technologies

meeting strict environmental standards.

These technologies will mitigate some of

the economic and environmental impediments that inhibit the full utilization

of coal as an energy source.

Concurrent with the development of

the CCT Program by DOE, the U.S. Environmental Protection Agency (EPA) has

promulgated regulations, under the 1990

Clean Air Act Amendments (CAAA), controlling emissions from a variety of stationary sources, including coal-fired boilers.

The CCT Program has opened a channel to policy-making bodies by providing

data from cutting-edge technologies to aid

in formulating regulatory decisions. For example, results from several CCT projects

have been provided to EPA to help establish achievable nitrogen oxides (NO and

NO2, collectively referred to as NOx)

emissions targets for coal-fired boilers

subject to CAAA.

Under the CCT Program, the three

projects discussed in this report were

undertaken to evaluate the performance

and economics of reburning technologies

for reducing NOx emissions from coalfired boilers.
Milliken Station (left); Nelson Dewey Station (top);

Cherokee Station (right).

NOx Emissions

Standards

History

The Clean Air Act of 1970 established

a major role for the federal government in

regulating air quality. The act was further

extended by amendments in 1977 and,

most recently, in 1990. The 1990 CAAA

is one of the most complex and comprehensive pieces of environmental legislation ever written. It authorizes EPA to

establish standards for a number of atmospheric pollutants, including sulfur dioxide

(SO2) and NOx.

Two major portions of the CAAA relevant to NOx control are Title I and Title

IV. Title I establishes National Ambient

Air Quality Standards (NAAQS) for six

criteria pollutants, including ozone, while

Title IV addresses controls for specific

types of boilers, including stationary coalfired utility power plants. Title IV is often

referred to as the Acid Rain Program.

Title IV uses a two-phase NOx control

strategy. Effective January 1, 1996, Phase

I established regulations for Group 1

boilers: dry-bottom, wall-fired boilers

and tangentially fired (T-fired) boilers.

In Phase II, which begins on January 1,

2000, lower emissions limits are set for

certain Group 1 boilers, and regulations

are established for Group 2 boilers,

which include cell-burner, cyclone,

wet-bottom wall-fired, and other types

of coal-fired boilers.
NOx emissions are generated

primarily from transportation, electric

utility, and other industrial sources.

NOx is reported to contribute to a

variety of environmental problems,

including acid rain and acidification

of aquatic systems, ground-level

ozone and smog formation, and

visibility degradation. For these reasons, NOx emissions are regulated

by various levels of government

throughout the country.

Ozone Nonattainment

Title I of the CAAA requires the

states to apply the same requirements to major stationary sources of

NOx as are applied to major stationary sources of volatile organic compounds (VOCs). In general, these

new NOx provisions require: (1) existing major stationary sources to

apply reasonably available control

technologies (RACT); (2) new or

modified major stationary sources to

offset their new emissions and install

Coal-Fired Boiler NOx Emissions Limits (Title IV), lb/million Btu

Phase I Phase II

Implementation Date Jan. 1, 1996 Jan. 1, 2000

Group 1 Boilers

Dry-Bottom, Wall-Fired 0.50 0.46

Tangentially Fired 0.45 0.40

Group 2 Boilers

Wet-Bottom, Wall-Fired

(>65 MWe) NA 0.84

Cyclone-Fired (>155 MWe) NA 0.86

Vertically Fired NA 0.80

Cell Burner NA 0.68

Fluidized Bed NA Exempt

Stoker NA Exempt

controls representing the lowest

achievable emissions rate (LAER);

and (3) each state with an ozone

nonattainment region to develop a

State Implementation Plan (SIP) that,

in most cases, includes reductions in

stationary source NOx emissions beyond those required by the RACT provisions of Title I.

More recently, EPA has attributed

part of the problem with nonattainment

to long range transport of ozone and its

precursors, NOx and VOCs. To address these transported pollutants,

EPA has adopted a regional approach

by promulgating an Ozone Transport

Rule that requires 22 states and the

District of Columbia to amend their

SIPs under CAAA to lower NOx emissions levels during the “summer” (May

through September) ozone season.

EPA’s rule sets statewide NOx

emissions budgets, which include budget components for the electric power

industry and certain industrial stationary sources. These sources are required to make large NOx emissions reductions to decrease the

movement of significant amounts

of ozone from one region of the

country to another. The target NOx

emissions limit for utility boilers is

0.15 lb/million Btu.

Acid Rain

Title IV of the CAAA focuses

on a particular set of NOx-emitting

sources–coal-fired electric utility

plants–and uses a two-phase strategy to reduce emissions. Phase I

of the program has reduced NOx

emissions in the United States by

over 400,000 tons/year. These

reductions were achieved by the

installation of low-NOx burner

technology on dry-bottom, wallfired boilers and tangentially fired

(T-fired) boilers (Group 1).

In Phase II, which begins in the

year 2000, EPA has established

lower emissions limits for Group 1

boilers and established limits for

Group 2 boilers. Group 2 boilers

include those applying cell-burner

technology, cyclone boilers, wetbottom boilers, and other types of

coal-fired boilers.

The statute requires that emissions control costs for Group 2

boilers be comparable to costs for

Phase I, Group 1 boilers. The regulations allow for emissions averaging in which the emissions levels

established by EPA are applied to

an entire group of boilers owned or

operated by a single company. It is

projected that the more stringent

Phase II limits will result in an additional NOx reduction of 820,000

tons/year.

Stationary Source NOx Regulations Under CAAA
Ozone Formation

When NOx and volatile organic compounds

(VOCs) enter the atmosphere, they react in the

presence of sunlight to form ground-level

ozone, which is a major ingredient of smog.

The revised NAAQS for ozone is 0.08 ppm

(eight-hour average). Many urban areas do not

meet this standard and are classified as

nonattainment, and a large number of power

plants are situated within these nonattainment

areas. Nonattainment status is attributable not

only to locally released NOx emissions but also

to significant amounts of ozone and ozone precursors (NOx and VOCs) transported by wind

over a wide geographical region.

To address regional pollutant transport,

EPA has issued a rule under Title I of the

CAAA governing NOx emissions from electric

power plants and other large stationary boilers

in an area consisting of 22 Eastern states and the

District of Columbia. To meet the ground-level

ozone NAAQS in that area, EPA projects an

average NOx emissions rate for electric power

plants of 0.15 lb/million Btu during the fivemonth (May through September) “summer”

ozone season.

NOx Control Technologies

Techniques for reducing NOx emissions

from fossil-fuel-fired boilers can be classified

into two fundamentally different categories:

combustion controls and post-combustion controls. Combustion controls reduce NOx formation during the combustion process, while

post-combustion controls reduce NOx after it

has been formed.

Combustion controls include low-NOx burners (LNBs), reburning, overfire air (OFA), flue

gas recirculation (FGR), and operational modifications. Post-combustion controls include selective catalytic reduction (SCR) and selective

noncatalytic reduction (SNCR). The primary

technology currently used for NOx reduction to

meet Title IV standards is combustion modification using LNBs, often in combination with OFA.

How NOx Is Formed in a Boiler

Most of the NOx formed during the combustion process is the

result of two oxidation mechanisms: (1) reaction of nitrogen in the

combustion air with excess oxygen at elevated temperatures, referred

to as thermal NOx; and (2) oxidation of nitrogen that is chemically

bound in the coal, referred to as fuel NOx. In addition, minor amounts

of NOx, referred to as prompt NOx, are formed early in the combustion process through complex interactions of molecular nitrogen with

hydrocarbon free radicals to form reduced nitrogen species that are

then oxidized to NOx.

For most coal-fired units, thermal NOx typically represents about

25% and fuel NOx about 75% of the total NOx formed. However,

for cyclones and other boilers that operate at very high temperatures,

the ratio is different, and thermal NOx can be considerably higher

than fuel NOx.

The quantity of thermal NOx formed depends primarily on the

“three t’s” of combustion: temperature, time, and turbulence. In other

words, flame temperature, the residence time at temperature, and the

degree of fuel/air mixing, along with the nitrogen content of the coal

and the quantity of excess air used for combustion, determine NOx

levels in the flue gas. Combustion modifications delay the mixing

of fuel and air, thereby reducing temperature and initial turbulence,

which minimizes NOx formation.
Reburn

Fuel

Overfire

Air

Coal and

 Combustion Air

Primary

Combustion

Zone

Reburn

Zone

Burnout

Zone

The Reburning Process

History

Reburning, or the staged introduction of

fuel into a combustion device, is based on

laboratory-scale studies in the early 1970’s

by Wendt and Sternling of Shell Development Company. The first commercial-scale

application of this technology to control

NOx emissions was installed in Japan during the same decade.

Subsequently, commercial-scale testing

was conducted in the U.S. and Europe,

mainly on electric utility boilers, but also

to some extent on municipal waste incinerators. At present, natural gas, coal, and fuel

oil (in Italy) reburning applications are in

operation. The majority of the commercial

installations in the U.S. use natural gas as

the reburn fuel, but either natural gas, oil,

or coal can achieve about 50-60% NOx

reduction without adversely affecting

boiler operations.

Process Description

Reburning involves the staged addition

of fuel into two combustion zones: (1) the

primary combustion zone where coal is

fired; and (2) the reburn zone where additional fuel (the reburn fuel) is added to create a reducing (oxygen deficient) condition

to convert the NOx produced in the primary

zone to molecular nitrogen (N2) and water.

Above the reburn zone is a burnout zone in

which OFA is added to complete the combustion. Each zone has a unique stoichiometric air ratio (the ratio of the air used

to that theoretically required for complete

combustion) as determined by the flows

of primary fuel, burner air, reburn fuel,

and OFA.

Primary Combustion Zone

Coal is fired under normal to low excess

air conditions at a rate corresponding to 70-

Schematic of reburning technology.
90% of the total heat input. The amount

of NOx created in this zone is reduced

by about 10% because less coal is

fired (lower production of fuel NOx),

the heat release rate is lower (lower

production of thermal NOx) and, generally, the excess air level to the burners is reduced (a lower oxygen

concentration results in lower NOx).

Reburn Zone

Reburn fuel injection creates a reducing region within which the reburn

fuel molecules break down to hydrocarbon fragments (CH, CH2, etc.)

that react with NOx, producing reduced

nitrogen species (mainly N2). The optimum reburn zone stoichiometric ratio

is 0.85-0.95. This is achieved by injecting reburn fuel at a rate corresponding to 10-30% of the total heat input,

depending on the primary zone excess

air level. The lower the primary combustion zone excess air, the lower

the reburn fuel requirement. Introduction of FGR through the reburn fuel

injectors may also be employed to increase the momentum of the injected

reburn fuel to improve furnace penetration and mixing. Because recirculated flue gas has a low oxygen

content, FGR has only a minor impact

on the reburn zone fuel requirement

and the burnout zone air rate.

Burnout Zone

OFA is injected downstream of the

reburn zone to complete combustion.

OFA is typically 20% of the total air

flow with an overall excess air level

of 15-25% being usual. The OFA injection rate is optimized for each specific application to minimize carbon

monoxide emissions and unburned

carbon in the fly ash. Thermal NOx

formation in the burnout zone is small

because of the lower temperature.

Depending on the nature of the reburn

fuel used, various boiler retrofits are required. In all cases, the boiler needs to be

equipped with fuel injection in the reburn

zone, and FGR may also be added. OFA

ports are also needed for the burnout

zone. If natural gas is used as the reburn

fuel, a pipeline extension to the site may

be required.

If the reburn fuel is coal, additional

coal handling and pulverizing equipment

may have to be installed. For example,

cyclone boilers are fired with coarse

crushed coal, which needs to be reduced

to smaller particle sizes to be an effective reburn fuel. Similarly, micronized

coal, which was tested as the reburn

fuel in one of the CCT projects described

in this report, requires special size-reduction equipment.

Comparison of Reburning with

Post-Combustion Control

Technologies

Reburning involves combustion

modification. Competing technologies

for coal-fired boiler NOx control are

post-combustion processes such as SCR

and SNCR. SNCR operates in a fashion

that has some of the characteristics of

reburning. In SNCR, instead of generating the NOx-reducing species from

the decomposition of fuel, as is done in

reburning, the reducing agent (typically

ammonia or urea) is injected into the furnace above the combustion zone, where

it reduces the NOx to nitrogen and water.

NOx reduction efficiency for SNCR may

be in the same range as that for reburning,

but efficiency varies with boiler capacity,

furnace configuration, etc.

 SCR, in which the NOx reduction is

carried out over a catalyst, has the capability of greater NOx reduction but is more

expensive than SNCR. SCR, like reburning, is applicable to virtually any type

of power generation or industrial boiler.

Clean Coal Technology

Reburning

Demonstration

Projects

This report discusses three

CCT demonstration projects:

• Demonstration of Coal

Reburning for Cyclone Boiler

NOx Control

• Evaluation of Gas Reburning

and Low-NOx Burners on a

Wall-Fired Boiler

• Micronized Coal Reburning

Demonstration for NOx

Control

All three of these projects involve reburning for reducing NOx

emissions from utility boilers. The

goal of these projects was to demonstrate the technical feasibility

and evaluate the economic potential of reburning under three different boiler configurations.

These projects were designed

to confirm pilot plant results and to

generate the data necessary for

scale-up of the technology to commercial applications, as well as to

resolve those technical issues that

could not be adequately addressed by engineering studies.

The work reported here has helped

establish reburning as a viable

technology for NOx control.
NOx reduction technologies can be grouped into two

broad categories: combustion modifications and postcombustion processes. Some of the more important NOx

control approaches are briefly discussed below.

Combustion Modifications

Low-NOx Burners – LNBs are designed to control the

mixing of fuel and air so as to achieve staged combustion. This results in a lower maximum flame temperature

and a reduced oxygen concentration during some phases

of combustion, thus resulting in both lower thermal NOx

and lower fuel NOx production.

Overfire Air – Overfire air (OFA) is air that is injected

into the furnace above the normal combustion zone. OFA

is generally used in conjunction with operating the burners at a lower-than-normal air-to-fuel ratio, which reduces

NOx formation. The OFA is then added to achieve complete combustion. OFA is frequently used in conjunction

with LNBs.

Reburning – With reburning, part of the boiler heat

input (typically 10-30%) is added in a separate reburn

zone, where fuel-rich conditions lead to the reduction

of NOx formed in the normal combustion zone. OFA is

injected above the reburn zone to complete combustion.

Thus, with reburn there are three zones in the furnace:

(1) a combustion zone with a normal to slightly below normal air-to-fuel ratio; (2) a reburn zone, where added fuel

results in a fuel-rich, reducing condition; and (3) a burnout

zone, where OFA leads to completion of combustion.

Coal, oil, and gas can all be used as the reburn fuel.

Flue Gas Recirculation – FGR, in which part of the

flue gas is recirculated to the furnace, can be used to

modify conditions in the combustion zone (lowering the

temperature and reducing the oxygen concentration) to

reduce NOx formation. Another use for FGR is as a carrier to inject fuel into the reburn zone to increase penetration and mixing.

NOx Reduction Technologies

Operational Modifications – These involve changing

certain boiler operational parameters to create conditions in the furnace that will lower NOx production. Examples are burners-out-of-service (BOOS), low excess

air (LEA), and biased firing (BF). In BOOS, selected

burners are removed from service by stopping fuel flow,

but air flow is maintained to create staged combustion

in the furnace. LEA involves operating at the lowest

possible excess air level while maintaining good combustion, and BF involves injecting more fuel to some

burners (typically the lower burners) while reducing fuel

to other burners (typically the upper burners) to create

staged combustion conditions in the furnace.

Post-Combustion Processes

Selective Noncatalytic Reduction – In SNCR a reducing agent (typically ammonia or urea) is injected into

the furnace above the combustion zone, where it reacts

with NOx to form nitrogen gas and water vapor, thus reducing NOx emissions. The critical factors in applying

SNCR are sufficient residence time in the appropriate

temperature range and even distribution and mixing of

the reducing agent across the full furnace cross section.

Selective Catalytic Reduction – In SCR a catalyst

vessel is installed downstream of the furnace. Ammonia is injected into the flue gas before it passes over the

fixed-bed catalyst. The catalyst promotes a reaction

between NOx and ammonia to form nitrogen and water.

NOx reductions as high as 90% are achievable, but

careful design and operation are necessary to keep

ammonia emissions (referred to as ammonia slip) to

a concentration of a few ppm.

Hybrid Process – SNCR and SCR can be used in

conjunction with each other with some synergistic benefits. Also, both processes can be used in conjunction

with LNBs.
Aerial view of Nelson Dewey Station.

Demonstration of Coal

Reburning for Cyclone

Boiler NOx Control

Project Description

Coal reburning for cyclone boiler NOx

control was selected during Round II of

DOE’s CCT Program. In April 1990, The

Babcock & Wilcox Company (B&W) entered into an agreement with DOE to conduct this project. The project site was

Wisconsin Power & Light’s (WP&L) 110-

MWe (gross) cyclone-fired Nelson Dewey

Unit 2 (Cassville, Wisconsin). WP&L

served as co-funder and host. The tests

were conducted by B&W. Sargent and

Lundy engineered the coal handling

equipment. Additional team members

and co-funders were the Electric Power

Research Institute (EPRI), the Illinois

Department of Energy and Natural Resources, and 14 electric utility owner/

operators of cyclone boilers. DOE provided 46% of the total project cost of

$13.6 million.

The project goal was to achieve

50% or greater NOx reduction at full

load by reburning with the same coal

as the primary fuel, with no substantial adverse impact on other emissions

or on boiler reliability, operability, and

steam production rate. Adding coal

reburning to Unit 2 required the installation of four B&W S-type reburn burners, four B&W dual zone OFA ports, and

a B&W MPS-67 pulverizer and primary

air fan plus the necessary ducting, dampers, and monitors. Modifications were also

made to the control system. Coals burned

during the test were Illinois Basin (Lamar)

bituminous (1.15% sulfur, 1.24% nitrogen) and Powder River Basin (PRB) subbituminous (0.27% sulfur, 0.55%

nitrogen).

When reburning is being used, the

cyclone burners operate within their normal, noncorrosive, oxidizing conditions,

thereby minimizing any adverse effects

on combustor and boiler performance.

The 110-MWe boiler is a size that is representative of a significant fraction of the

population of cyclone units.
Flow diagram of coal reburning on a cyclone boiler.

Reburn

Zone

Economizer Boiler

Electrostatic

Precipitator

Hot Air

to Boiler

Crushed Coal

Primary

Air

Secondary

Air

Dry Waste

to Disposal

Stack

Molten Slag Water

Main

Combustion

Zone

Pulverized

Coal

Coal Reburn

Burners

Air

Slag to Disposal

Cyclone

Burner

Air

Overfire

Air

Burnout

Zone

Air Preheater

Results

At Nelson Dewey Unit 2, NOx emissions reductions exceeding 50% were

achieved using both Lamar bituminous

and PRB subbituminous coals. Switching

part of the load from the cyclone burners

to the reburn burners eliminated the need

for derating the boiler, normally required

for boilers feeding lower heat content

subbituminous coal and having limited

coal feed capacity.

Excellent process flexibility was demonstrated. The boiler operated successfully

at load levels as low as 37 MWe (a turndown ratio of 66%) with bituminous coal

and 41 MWe (a turndown ratio of 63%)

with subbituminous coal. It was found

that accurate and responsive control of

both fuel and air flow rates into the different operating zones of the boiler was

required.

For optimum NOx control, effective

in-furnace mixing of the gases from the

cyclone and reburning burners is essential. This was predicted by mathematical modeling, which proved to be an

extremely useful process design tool.

Measured NOx emissions with bitumi-
nous coal at full load were reduced from

the baseline level of 0.82 lb/million Btu

to 0.39 lb/million Btu, a reduction of

52%. Percentage reductions were somewhat poorer at reduced load levels, and

slightly better emissions reductions were

achieved with the subbituminous coal.

The two most important operating variables for effective NOx control were found

to be the stoichiometric ratio in the reburn

zone (optimum was in the range of 0.85-

0.95) and the use of FGR. The use of FGR

was vital to providing necessary burner

cooling, flame penetration, and mixing,

while maintaining the reburn zone stoichiometric ratio.

No significant adverse boiler impacts

were found. Only a slight reduction in

boiler efficiency (<1.5%) resulted from

coal reburning compared with baseline

operation, and the furnace exit flue gas

temperature was not compromised by

reburning. Under long-term reburn operating conditions, there was no impact on

slagging, fouling, tube wall corrosion rate,

surface cleanliness, or spray flow requirements for superheat and reheat steam temperature control. Particulate collection

efficiency remained the same with subbituminous coal and actually improved

slightly with bituminous coal.

Costs

Cost estimates by B&W for commercial

implementation of coal reburning technology are based on two sizes of cyclone boilers, with 50% NOx reduction for each size.

For a 110-MWe (gross) power plant, the

same size as Nelson Dewey Unit 2, total

capital is $66/kW. This figure decreases to

$43/kW at a capacity of 605 MWe. Tenyear levelized costs (current dollars) are 2.4

mills/kWh at 110 MWe and 1.6 mills/kWh

at 605 MWe. The corresponding costs are

$1,075/ton of NOx removed at 110 MWe

and $408/ton at 605 MWe. Site-specific

factors, such as the type of boiler, will affect

the economics.

Coal pulverizer with

associated feed and

distribution piping.

Coal reburn burner on floor awaiting installation.
The following equations are not intended to be exact but only approximate representations of the complex,

free-radical reactions that occur during reburning.

Chemistry of the Reburning Process

Burnout Zone (Normal excess air; stoichiometric

ratio of 1.20-1.25) – The main function of the burnout zone is to complete combustion of the fuel.

However, any unreacted reduced nitrogen compounds may be reoxidized to NOx. This latter effect is normally small, and the overall result of

reburning is a reduction in NOx emissions.

Air + CHx + CO ––> CO2 + H2O

•CN + •NH2 + O2 ––> NOx + CO2 + H2O

Primary Combustion Zone (Low to normal excess air;

stoichiometric ratio of 1.1-1.2) – The major reactions

occurring in the primary combustion zone are fuel

combustion and NOx formation.

Main Fuel + O2 ––> CO2 + CO + H2O + Other Species

N(fuel) + O2 ––> NOx

N2(air) + O2 ––> NOx

Reburn Zone (Fuel rich; stoichiometric ratio of 0.85-0.95) –

The chemistry in the reburn zone is very complex. NOx reacts

with hydrocarbon free radicals to form reduced nitrogen species

which, in turn, react with additional NOx to form nitrogen gas.

Reburn Fuel ––> CHx + Other Species

CHx + NOx ––> •CN + •NH2 + H2O

NOx + •NH2 ––> N2 + H2O

NOx + •CN ––> N2 + CO

NOx + CO ––> N2 + CO2

Power plant control room.
Aerial view of Cherokee Station with

Denver skyline in background.

Evaluation of Gas

Reburning and LowNOx Burners on a

Wall-Fired Boiler

Project Description

This project was selected during Round

III of DOE’s CCT Program. In October

1990 Energy and Environmental Research

Corporation (EER) signed an agreement with

DOE to conduct this project. Gas reburning

coupled with low-NOx burners (GR-LNB)

was tested at Public Service Company of

Colorado’s (PSCo) 158-MWe (net) wallfired Cherokee Unit 3 near Denver, Colorado. PSCo served as co-funder and host.

EER and Foster Wheeler Energy Corporation were the technology suppliers, and

testing was conducted by EER. Additional

team members and co-funders were the

Gas Research Institute (GRI), Colorado

Interstate Gas Company, and EPRI. DOE

provided 50% of the total project cost of

$17.8 million.

The existing 16 burners on Unit 3 were

replaced by Foster Wheeler Controlled Flow/

Split Flame LNBs. These burners employ

dual combustion-air registers, allowing control of air distribution at the burner and providing independent control of the ignition

zone and flame shape. The gas reburning

system retrofit involved routing natural gas

to 16 boiler penetrations (eight on the front

wall and eight on the rear wall), installing a

flue gas recirculation fan, installing a multiclone dust collector to remove particulates

and protect the fan, and connecting the

equipment with the ductwork. The OFA

system involved installing an OFA fan and

ductwork from the secondary air system to

six front-wall injection nozzles. The control

system was also modified.

During the first test series, it was found

that FGR had little effect on NOx reduction.

Therefore, part way through the demonstration, the FGR system was removed. At the

same time, the natural gas injectors were

replaced by high-velocity injectors, which

made greater use of the available natural gas

pressure. Also, the OFA ports were modified to provide higher jet momentum, air

swirl capability, and velocity control. This

provided improved lateral coverage and turbulence in mixing with unburned fuel. After

these modifications, the system was referred

to as Second Generation GR-LNB.
Flow diagram of gas reburning-low-NOx

burners installation.

Reburn

Zone

Boiler

Baghouse

Dry Waste

to Disposal

Stack Burnout

Zone

Overfire Air

Natural Gas

Recirculated

Flue Gas

Windbox

Coal

Air

Low-NOx

Burners

Economizer

Ash to Disposal

Hot Air

to Boiler

Air Preheater

The project goal was to reduce NOx

emissions by 70% by the combined use

of LNBs and GR. Tests were performed

on the GR system by varying operational control parameters to assess the

effect on boiler emissions, completeness

of combustion, thermal efficiency, and

heat rate. A long-term testing program

was performed to evaluate the consistency of system operations, assess the

impact of long-term operation on the

boiler, gain experience in operating GRLNB in a normal load-following environment, and develop a database for use

in subsequent applications. The coal

burned during this demonstration was

a Western bituminous coal with a sulfur content of 0.45% and a nitrogen

content of 1.5%.

Results

The use of LNBs by themselves

(without GR) reduced NOx emissions

from the 0.73 lb/million Btu baseline

level to 0.46 lb/million Btu, a 37% reduction. This performance, however,

fell short of the targeted value of 45%

NOx reduction and had an adverse impact on the overall performance of the

combined GR-LNB technology. NOx

emissions for first-generation GRLNB, at 18% gas heat input, were

lowered to an average of 0.25 lb/million

Btu, an overall reduction of 65%,

slightly poorer than the targeted value.

Second-generation GR-LNB (no FGR)

achieved 64% NOx reduction at 13%

gas heat input. In short-term tests, both

first- and second-generation GR-LNB

were able to meet the target level of

70% reduction in NOx emissions.

The use of natural gas reduced SO2

and particulate emissions in direct proportion to the gas heat input. GR-LNB

had only a minor impact on the boiler.

Boiler efficiency decreased by about

1% during gas reburning because of

the increased moisture in the flue gas
View of low-NOx burners after installation.

resulting from natural gas combustion.

There was no measurable tube erosion,

and only small amounts of slagging

occurred. There was no reduction in

the efficiency of flyash collection at

the baghouse. After completion of the

GR-LNB project, the host site has continued to operate the LNB system. The

gas reburn system has been retained

by the host utility but is not operated

at present because current NOx emissions requirements can be met using

LNBs alone. Gas reburning can be used

in the future if needed to meet more

stringent regulations, although at somewhat higher operating cost.

Costs

Preliminary economics were developed by EER for a GR-LNB retrofit

to a hypothetical 300-MWe wall-fired

boiler burning 3.0 wt% sulfur coal with

a 10,000 Btu/kWh heat rate, a capacity

factor of 65%, and 12.5% of the heat

input by natural gas, which was assumed to be available on-site. The

capital cost is $26/kW, of which GR

contributes $12/kW and the LNBs contribute $14/kW.

The cost differential between gas

and coal is assumed to be $1.00/million Btu. The amount of fuel fired is

increased by 0.8%, compared with

baseline operation, to account for the

slight loss in overall boiler efficiency.

Based on these assumptions, the

levelized cost is $908/ton of NOx

removed (constant dollar basis). These

economics do not include an allowance for reduced SO2 emissions resulting from the substitution of natural

gas (containing no sulfur) for a portion of the coal feed. The reduction

in SO2 emissions may result in credits

on the SO2 emissions trading market,

which would lower the levelized cost

of NOx reduction.

Installation of

low-NOx burner.
Micronized Coal

Reburning

Demonstration for NOx

Control

Project Description

The micronized coal reburning project

was selected during Round IV of DOE’s

CCT Program, and in August 1997, New

York State Electric & Gas Corporation

(NYSEG) entered into an agreement with

DOE to conduct the project. The project

was conducted at two sites: NYSEG’s

Milliken Unit 1 (Lansing, New York),

a 150-MWe (net) T-fired boiler, where

NYSEG was host and co-funder; and

Kodak Park Unit 15 (Rochester, New

York), a 50-MWe equivalent cyclone-fired

industrial boiler, where Eastman Kodak

Company was host and co-funder. Energy

and Environmental Research Corporation

provided the reburn system design. Consolidation Coal Company, now known as

CONSOL, provided coal sample testing,

and the New York State Electric Research

and Development Authority and the Empire State Electric Energy Research Corporation were co-funders. DOE provided

29% of the total project cost of $8.7 million.

With gas reburning, the differential cost

of gas over coal is the largest component

of the cost of NOx reduction. When coal

is used as the reburn fuel, this differential

is zero. Thus, coal reburning has the potential for significantly lower NOx control

cost than gas reburning. The challenge

with coal reburning is to achieve aequate

combustion of the reburn coal in the oxygen deficient, short residence time reburn

zone. This project demonstrates micronized coal reburning, where the reburn coal

is finely ground to 85% below 325 mesh.

The small coal particles have greatly

increased surface area which increases

the rate of combustion, allowing coal

1.0

0.8

0.7

0.4

0.2

0

2.0 3.0 4.0 5.0 6.0

GR-LNB

140-160 MWe (Net)

9-15% Gas

LNB

Baseline

NOx (lb/10

6 Btu)

Excess O2 (% dry)

NOx reduction data from Cherokee Station.

Kodak Park.
Milliken Station, located in the Finger

reburning to be applied in units with lim- Lakes Region of New York State.

ited reburn zone residence time.

The prime objective of this two-site

project was to demonstrate improvements

in coal reburning for NOx emissions control by further particle size reduction of

the reburn coal. The project goal was to

achieve 25-30% NOx reduction on the

T-fired unit and at least 50% reduction

on the cyclone unit. Testing at both sites

began in April 1997 and was completed

in 1998. Low-volatile Pittsburgh seam

coal (3.2% sulfur and 1.5% nitrogen at

Milliken, and 2.2% sulfur and 1.6% nitrogen at Kodak) was fired at both test sites.

Milliken Implementation and

Results

At Milliken, the existing ABB LowNOx Concentric Firing SystemTM

(LNCFS-III), which includes both close

coupled and separated OFA ports, was

used for the reburn project. Pulverized

coal is provided by four DB Riley MPS

150 mills with dynamic classifiers. With

LNCFS-III there are four levels of burners, and each mill serves one burner level.

When using reburning, the top-level burner

nozzles were used to feed the reburn fuel

into the upper part of the furnace. To simulate and test a reburn application, the lower

three coal elevations were biased to carry

approximately 80% of the fuel required

for full load, with the top burner supplying the remaining fuel. The speed of the

dynamic classifier serving the mill feeding

the top burners was increased to provide

the micronized fuel. It was decided that

full conversion to micronized coal would

not be cost effective.

A primary objective at Milliken was to

determine the minimum NOx level attainable while maintaining marketable fly ash

production (fly ash having less than 4.5%

carbon). Variables studied at Milliken include boiler load, reburn coal fineness,

oxygen level at the economizer, percent

reburn fuel, main burner tilt, and OFA tilt.

Micronized coal reburning with 14%

reburn fuel reduced NOx emissions from

the 0.35 lb/million Btu baseline level to

0.25 lb/million Btu, a 28% reduction,

which was within the target range. The unburned carbon-in-ash, also referred to as

loss-on-ignition (LOI), was maintained

under 4%. During testing, it was found that

excess air is the single most important parameter that affects NOx emissions, higher

excess air resulting in higher NOx, but

lower LOI. Increasing coal fineness improved NOx emissions only marginally,

but lowered LOI. Increasing the percent

reburn fuel slightly decreased NOx, but

increased LOI.
Reburn

Zone

Coal

Micronized

Coal Injectors

Overfire Air

System

Micronized Coal

System

Existing

Feeders

Flue Gas

Classifier

Existing

Coal

Hopper

Boiler

Baghouse

Dry Waste

to Disposal

Stack

Burnout

Zone

Ash to Disposal

Main Coal Feed

Economizer

Flow diagram of micronized coal installation.

Kodak Implementation and Results

At Kodak, the micronized reburn system

was designed by EER using a combination

of analytical and empirical techniques, augmented by EER’s extensive reburning database. The reburn fuel and overfire air (OFA)

injection components were designed with a

high degree of flexibility to allow for field

optimization to accommodate the complex

furnace flow patterns in the cyclone boiler.

The micronized coal reburn fuel was provided by a Fuller MicroMillTM system that

produces micronized coal with a particle

size of approximately 20 microns, about

one third the diameter of normal pulverized

coal. To maximize NOx reduction, the

reburn fuel was injected with flue gas as

the carrier instead of air. The flue gas was

extracted downstream of the electrostatic

precipitator (ESP) and boosted by

a single fan.

Two MicroMillsTM were installed in

parallel to provide the capacity necessary for high reburn rates, the second

mill serving as a spare at lower reburn

rates. The micronized coal was introduced into the reburn zone by means of

eight injectors, six on the rear wall and

one on each of the side walls. The optimization variables included the number

of injectors, swirl, and velocity. OFA

was injected through four injectors on

the front wall, utilizing EER’s second

generation, dual-concentric OFA design

which provided for variable injection

velocity and swirl. The optimization

tests showed that best performance was

achieved at conditions close to EER’s

design point. A new boiler control system was also installed.

The demonstration showed excellent

MicroMillTM NOx reduction performance. The target and classifier.
Location Owner/ Capacity, Reburn NOx Emissions, NOx

(Retrofit Date) Operator MWe Heat, % lb/million Btu Reduction,

Boiler Type (net) Uncon- Con- %

trolled trolled

Gas Reburning

Hennepin (1991) Illinois 71 18 0.75 0.25 67

Tangential Power

Lakeside (1993) Springfield 33 23 0.97 0.39 60

Cyclone Water, Light

& Power

Cherokee (1993) Public Service 158 18 0.73 0.27 63

Wall of Colorado (w/o LNB)

Greenidge (1996) New York State 100 10 0.50 0.25 50

Tangential Electric & Gas

Kodak Park (1995) Eastman 69 20 1.25 0.56 56

Cyclone Kodak (equiv)

Kodak Park (1998) Eastman 50 14 1.20 0.51 58

Cyclone Kodak (equiv)

Kodak Park (1999) Eastman 50 13 1.20 0.51 58

Cyclone Kodak (equiv)

Crane (1998) Baltimore 200 Not Not Not Not

Tangential Gas & Electric available available available available

Coal Reburning

Nelson Dewey Wisconsin 100 25-30 0.82 0.39 52

(1991) Cyclone Power & Light

Milliken (1997) New York State 150 14 0.35 0.25 28

Tangential Electric & Gas (with LNB)

Micronized Coal

Kodak Park Eastman 50 17 1.36 0.59 57

(1997) Cyclone Kodak (equiv)

Micronized Coal

Demonstration and/or Operating Reburn Installations

on Coal-Fired Boilers in the United States
Conclusions

The three projects described in this

report clearly show that reburning is an

effective NOx control option for coalfired boilers, either alone or in combination with other emissions control

technologies. This is reinforced by the

results of an earlier NOx control CCT

demonstration project, Enhancing the

Use of Coals by Gas Reburning and Sorbent Injection (GR-SI) at Illinois Power’s

Hennepin Plant (see CCT Topical Report

Number 3), as well as by commercial

projects involving reburning, both in the

U.S. and abroad.

Reburning can reduce NOx emissions

from coal-fired boilers by up to 50-60%,

depending on various factors such as the

baseline emissions level, furnace characteristics, and the fraction of heat input

supplied by the reburn fuel. The most

important process variable is the stoichiometric ratio in the fuel-rich reburn zone.

The optimum value for this ratio is in the

range of 0.85-0.95, which is achieved by

10-30% reburn heat input.

 Long-term testing has shown only

minor impacts on boiler equipment and

operations. There is a small loss in boiler

efficiency, particularly when gas is used

as the reburn fuel, due to the increased

moisture content of the flue gas when

gas is fired.

With coal reburning, other emissions

are not significantly affected. With natu-

% NO

x Reduction

% Reburn Fuel

80

60

40

20

0 5

0

10 15 20 25 30

Performance of demonstration

and commercial reburning units.

was to reduce NOx to less than 0.60

lb/million Btu from a baseline of

1.25 lb/million Btu, a 52% reduction.

Although the actual baseline was

higher than expected (1.45 lb/million

Btu), the NOx emissions target of 0.60

lb/million Btu was achieved with 17%

reburn fuel, a 59% reduction. At

greater reburn fuel rates, NOx reduction was even greater. These results

are comparable to the NOx reduction

achieved with gas reburning systems.

As expected, LOI increased with the

reburn system in operation; LOI was

35 to 45% during full load, compared

with the baseline level of 10-12%.

Some mechanical problems were

encountered during the demonstration,

including plugging of the coal handling system feeding the MicroMillTM,

vibration and blade wear on the mills,

erosion of the classifiers, and corrosion due to low temperature flue gas

when the reburn system was out of

service. In spite of these problems,

successful operation was achieved.

Costs

The installed cost of a micronized coal

reburning system exceeds that of gas

reburning, principally due to the cost of

the coal milling system. However, since

there is no reburn fuel cost differential,

operating costs are much lower.
ral gas reburning, emissions of sulfur

oxides and particulates are reduced in

direct proportion to the fraction of heat

supplied by natural gas, and carbon dioxide emissions are somewhat reduced,

because of the higher hydrogen content

of natural gas compared to coal.

In terms of NOx reduction performance, natural gas and coal appear to be

about equally effective reburn fuels, and

the choice between them will be based

on relative capital and operating costs.

Market Potential

Reburning is applicable to all types

of coal-fired boilers, including the major

types of firing systems used in electric

power generation and industrial steam

production, specifically wall-fired, T-fired,

cyclone, and stoker units. A significant

feature of reburning is that it can be used

on cyclone boilers, whose design features

do not lend themselves to being retrofitted

with LNBs.

Reburning can be used as an alternative

to LNBs or in combination with LNBs to

meet Title IV NOx emissions regulations.

A large potential market for reburning is

the boilers subject to more stringent controls under Title I of the CAAA. Illustrative of this market are the boilers covered

under EPA’s September 1998 Rule for

Reducing Regional Transport of GroundLevel Ozone. As discussed previously,

this rule requires 22 states and DC to

submit revised State Implementation

Plans to ensure that emissions are sufficiently reduced to mitigate transport of

ozone and NOx across state boundaries

in the Eastern half of the United States.

All boilers in this region, as well as

those located in other ozone nonattainment areas across the U.S., are potential

candidates for retrofit reburning applications. While reburning alone cannot meet

the stringent NOx emissions requirements

associated with Title I, reburning can be

Canada geese feeding in shadow

of power plant stack.

used along with LNBs to reduce the

load on post-combustion technologies

such as SCR.

Economics

Whether natural gas or coal is used as

the reburn fuel is a decision based largely

on economics. Factors that affect the

comparison are: (a) the cost differential

between gas and coal; (b) the capital and

operating costs of pulverizers and other

coal-handling equipment required for coal

reburning; (c) the availability of natural

gas at the site; (d) the relative impacts

of coal and gas reburning on boiler efficiency; and (e) the possibility of generating credits from decreased emissions of

SO2 when burning natural gas.

Although a comparison between these

technologies is highly site specific, in

general the capital cost of coal reburning

is higher than that of gas reburning, primarily because of the cost of the pulverizers and ancillary equipment required for
coal reburning, particularly with cyclonefired boilers, which utilize coarse coal.

However, for some boilers firing pulverized coal, it may be possible to adjust

the existing pulverizers to achieve a sufficiently fine particle size for the reburn

coal. If natural gas is not available at the

site, the cost of installing a supply line

from the nearest pipeline to the power

plant may make the capital cost of gas reburning higher than that of coal reburning.

As opposed to capital costs, which

tend to be higher for coal reburning,

operating costs tend to be higher with

gas reburning because of the gas/coal

fuel price differential. At present, coal

is significantly cheaper than gas per unit

of heat content, and this price differential is expected to increase over the next

15 years.

FGR has been used in both coal and

gas reburning, primarily as a carrier for

the reburn fuel to improve its penetration

and mixing in the reburn zone. By redesigning the gas injectors, it was possible Farming country near

Nelson Dewey Station.

to eliminate the use of FGR in the GRLNB project. The need for FGR has

to be examined on a case-by-case basis,

and, if it can be avoided, costs will

be reduced.

Commercial Applications of

Reburning Technology

A number of owner/operator hosts

have continued to operate their reburn

facilities after the completion of the CCT

test programs at their plants. These installations on coal-fired boilers include the

GR retrofits at Hennepin and Lakeside

from the earlier GR-SI CCT project, and

the coal reburning retrofit at Nelson Dewey.

In addition, GR has been installed by

EER at NYSEG’s Greenidge Station, the

Tennessee Valley Authority’s (TVA)

Allen Plant, and at Baltimore Gas and

Electric (BG&E) Company’s Crane Station. GR has also been installed on an oil/

gas-fired boiler at Long Island Lighting

Company’s Barrett Station. Options with

EER to retrofit gas reburning installations on other units have been exercised

or are pending with BG&E and TVA.

B&W has installed gas reburn at Kodak’s

second power plant, with design co-funding provided by GRI. Internationally,

Scottish Power has installed gas reburning

at Longannet. At more than 600 MWe,

this is the largest installation to date.

Award

EPA, GRI, and DOE were the recipients of the Air & Waste Management

Association’s 1997 J. Dean Sensenbaugh

Award for their collaborative work in

developing gas reburning into a viable

and commercial emissions control

option for utility and industrial power

generation boilers.
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B. Folsom, T.M. Sommer, D.A.

Engelhardt, D.T. O’Dea, S. Hunsicker,

and J.U. Watts, “Coal Reburning for CostEffective NOx Compliance,” Fifth Annual

Clean Coal Technology Conference

(Tampa FL), January 1997.

W. Savichky, G. Gaufillet, M.Mahlmeister, D. Engelhardt, J. Mereb,

and J. Watts, “Micronized Coal Reburning

Demonstration of NOx Control,” Sixth

Clean Coal Technology Conference

(Reno NV), April 1998.

Energy and Environmental Research Corporation, “Evaluation of Gas Reburning

and Low-NOx Burners on a Wall-Fired

Boiler,” Final Report, July 1998.

U.S. EPA, Finding of Significant Contribution and Rulemaking for Certain States in

the Ozone Transport Assessment Group

Region for Purposes of Reducing Regional

Transport of Ozone, 63 FR 90,

September 24, 1998.

Gas reburn installation on Cherokee Unit 3.
The Clean Coal Technology Program

The Clean Coal Technology (CCT)

Program is a unique partnership between the federal government and

industry that has as its primary goal

the successful introduction of new

clean coal utilization technologies into

the energy marketplace. With its roots

in the acid rain debate of the 1980s,

the program is on the verge of meeting

its early objective of broadening the

range of technological solutions available to eliminate acid rain concerns

associated with coal use. Moreover,

the program has evolved and has been

expanded to address the need for new,

high-efficiency power-generating technologies that will allow coal to continue to be a fuel option well into the

21st century.

Begun in 1985 and expanded in

1987 consistent with the recommendation of the U.S. and Canadian Special

Envoys on Acid Rain, the program has

been implemented through a series

of five nationwide competitive solicitations. Each solicitation has been

associated with specific government

funding and program objectives. After

five solicitations, the CCT Program

comprises a total of 40 projects

located in 18 states with a capital

investment value of nearly $6 billion.

DOE’s share of the total project costs

is about $2 billion, or approximately 34

percent of the total. The projects’ industrial participants (i.e., the non-DOE

participants) are providing the

remainder—nearly $4 billion.

Clean coal technologies being demonstrated under the CCT Program are

establishing a technology base that

will enable the nation to meet more

stringent energy and environmental

goals. Most of the demonstrations are

being conducted at commercial scale,

in actual user environments, and

under circumstances typical of commercial operations. These features

allow the potential of the technologies

to be evaluated in their intended commercial applications. Each application

addresses one of the following four

market sectors:

• Advanced electric power

generation

• Environmental control devices

• Coal processing for clean fuels

• Industrial applications

Given its programmatic success,

the CCT Program serves as a model

for other cooperative government/

industry programs aimed at introducing new technologies into the

commercial marketplace.

Coal unloading facility.
To be placed on the Department

of Energy’s distribution list for future

information on the Clean Coal

Technology Program, the demonstration projects it is financing, or

other Fossil Energy Programs,

please contact:

Participant Contacts

Dot K. Johnson

Program Development Manager

McDermott Technology, Inc.

1562 Beeson Street

Alliance OH 44601

(330) 829-7395

(330) 829-7801 fax

dot.k.johnson@mcdermott.com

Donald A. Engelhardt

Project Manager

Energy and Environmental

Research Corporation

1345 Main Street

P.O. Box 153

Orrville OH 44667

(330) 682-4007

(330) 684-2110 fax

dengelhardt@eercorp.com

U.S. Department of Energy Contacts

David J. Beecy

Director, Office of Environmental

Systems Technology

FE 23

Germantown MD 20874-1290

(301) 903-2787

(301) 903-8350 fax

david.beecy@hq.doe.gov

To Receive Additional

Information

Robert C. Porter, Director

Office of Communication

U.S. Department of Energy

FE-5

1000 Independence Ave SW

Washington DC 20585

(202) 586-6503

(202) 586-5146 fax

robert.porter@hq.doe.gov

Otis Mills

Public Information Office

U.S. Department of Energy

Federal Energy Technology

Center

P.O. Box 10940

Pittsburgh PA 15236-0940

(412) 892-5890

(412) 892-6195 fax

mills@fetc.doe.gov

Contacts for CCT Projects

and U.S. DOE CCT Program

This report is available on the Internet

at U.S. DOE, Office of Fossil Energy’s home page: www.fe.doe.gov

James Harvilla

Project Manager

New York State Electric & Gas

Corporation

Corporate Drive - Kirkwood

Industrial Park

P.O. Box 5224

Binghamton NY 13902-2551

(607) 762-8630

(607) 762-8457 fax

jharvila@spectra.net

James U. Watts

Project Manager

Federal Energy Technology Center

P.O. Box 10940

Pittsburgh PA 15236-0940

(412) 892-5991

(412) 892-4775 fax

watts@fetc.doe.gov
List of Acronyms and Abbreviations

ABB ...................................................... Asea Brown Boveri

BF .................................................................... Biased firing

BOOS .............................................. Burners-out-of-service

Btu ........................................................ British thermal unit

B&W .......................... The Babcock and Wilcox Company

BG&E ...................... Baltimore Gas and Electric Company

CAAA ........................ Clean Air Act Amendments of 1990

CCT ................................................ Clean Coal Technology

CO2 ...................................................................................Carbon dioxide

DOE .......................................... U.S. Department of Energy

EER ...... Energy and Environmental Research Corporation

EPA ....................... U.S. Environmental Protection Agency

EPRI ............................... Electric Power Research Institute

ESP ............................................... Electrostatic precipitator

FETC ........................... Federal Energy Technology Center

FGR ................................................... Flue gas recirculation

FWEC ......................... Foster Wheeler Energy Corporation

GR.................................................................. Gas reburning

GRI ................................................... Gas Research Institute

GR-LNB .......................... Gas reburning-low-NOx burners

GR-SI................................. Gas reburning-sorbent injection

kW ........................................................................... kilowatt

kWh ................................................................ kilowatt hour

LAER .............................. Lowest achievable emissions rate

LEA .............................................................. Low excess air

LNBs ...................................................... Low-NOx burners

LNCFS.................. Low-NOx Concentric Firing SystemTM

LOI ............................................................. Loss on ignition

MWe ....................................... Megawatts of electric power

NAAQS ...............National Ambient Air Quality Standards

NOx ............................................................ Nitrogen oxides

NYSEG ......... New York State Electric & Gas Corporation

OFA ................................................................... Overfire air

ppm ............................................................ parts per million

PRB ......................................................Powder River Basin

PSCo ........................ Public Service Company of Colorado

RACT ................. Reasonably available control technology

SCR ........................................ Selective catalytic reduction

SI............................................................... Sorbent injection

SIP ............................................. State Implementation Plan

SNCR ................................ Selective noncatalytic reduction

SO2 ...................................................................................... Sulfur dioxide

TVA ......................................... Tennessee Valley Authority

VOCs ...................................... Volatile organic compounds