TOPICAL REPORT NUMBER 9 JULY 1997

Control of Nitrogen Oxide Emissions:

Selective Catalytic Reduction (SCR)
TOPICAL REPORT NUMBER 9

A report on a project conducted jointly under

a cooperative agreement between:

The U.S. Department of Energy and Southern Company Services, Inc.

JULY 1997

Control of Nitrogen

Oxide Emissions:

Selective Catalytic

Reduction (SCR)
Cover image: Photo of SCR Project

at Plant Crist.

Preparation and printing of this document conforms

to the general funding provisions of a cooperative

agreement between Southern Company Services

and the U.S. Department of Energy. The funding

contribution of the industrial participant permitted

inclusion of multicolored artwork and photographs at

no additional expense to the U.S. Government.
Control of Nitrogen Oxide Emissions:

Selective Catalytic Reduction (SCR)

Introduction and Executive Summary ............................................................... 1

Background ....................................................................................................... 2

NOx Emissions Standards.................................................................................. 3

NOx Control Technologies ................................................................................ 6

The SCR Process ............................................................................................... 6

Clean Coal Technology SCR Demonstration Project ....................................... 8

Long Term Testing of Catalyst Deactivation .................................................. 12

Parametric Studies ........................................................................................... 13

Significance of Test Results ............................................................................ 14

Commercial Applications of SCR Technology ............................................... 15

Future Work..................................................................................................... 15

Market Analysis............................................................................................... 16

Economics ....................................................................................................... 17

Conclusions ..................................................................................................... 19

Bibliography .................................................................................................... 20
1

Introduction and

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 on a scale

sufficiently large to demonstrate commercial worthiness and to generate data

for design, construction, operation, and

technical/economic evaluation of fullscale commercial applications.

The goal of the CCT program is to

furnish the U.S. energy marketplace

with a number of advanced, more efficient, and environmentally responsible

coal-utilizing technologies. 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, a multi-phased

effort consisting of five separate

solicitations was administered by the

U.S. Department of Energy (DOE).

Projects selected through these solicitations have demonstrated technology

options with the potential to meet the

needs of energy markets and respond

to relevant environmental requirements.

Part of this program is the demonstration of technologies designed to

reduce emissions of oxides of nitrogen

(NOx) from existing coal-fired utility

boilers. NOx is an acid rain precursor

and a contributor to atmospheric ozone

formation, which is a health hazard and

is also related to smog formation. NOx

emissions are regulated under the

provisions of the Clean Air Act and

particularly the Clean Air Act Amendments (CAAA) of 1990.

This report discusses a CCT project

which demonstrated selective catalytic

reduction (SCR) technology for the control of NOx emissions from high-sulfur,

coal-fired boilers. The project was conducted by Southern Company Services,

which served as a cofunder and as the

host at Gulf Power Company’s Plant

Crist near Pensacola, Florida. Other

participants and cofunders were the

Electric Power Research Institute (EPRI)

and Ontario Hydro. DOE provided 40%

of the total project cost of $23 million.

The project was administered for

DOE by its Federal Energy Technology

Center (FETC).

The SCR process consists of injecting ammonia (NH3) into boiler flue gas

and passing the flue gas through a catalyst bed where the NOx and NH3 react

to form nitrogen and water vapor. The

objectives of the demonstration project

were to investigate:

• Performance of a wide variety of

SCR catalyst compositions, geometries, and manufacturing methods

at typical U.S. high-sulfur coalfired utility operating conditions.

• Catalyst resistance to poisoning by

trace metal species present in U.S.

coals that may not be present in

fuels from other countries.

• Effects on the balance-of-plant

equipment from sulfur compounds

formed by reactions between sulfur

dioxide (SO2), sulfur trioxide

(SO3), and NH3, such as plugging

and corrosion of downstream

equipment.

The catalysts were tested over a twoyear period, during which they were

exposed to flue gas from a coal-fired

boiler at Plant Crist, under conditions

identical to those experienced in commercial installations. Catalyst suppliers

(two U.S., two European, and two

Japanese) provided eight different

catalysts. All catalysts performed well,

giving NOx removal rates of 80% or

better with acceptable NH3 slip. The

results demonstrated the applicability

of SCR under both high dust and low

dust conditions.

Economics were estimated for an

SCR unit installed in a new 250 MWe

power plant, using a projected process

design that incorporates improvements

based on experience gained from the

SCR demonstration project. The boiler

is assumed to be either a wall-fired or

a tangentially fired unit, equipped with

low-NOx burners and burning 2.5 wt%

sulfur coal. Design NOx concentration at

the reactor inlet is 0.35 lb/106 Btu. NOx

reduction is assumed to be 60%, giving

an outlet concentration of 0.14 lb/106

Btu, with a design NH3 slip of 5 ppm.

The capital cost is $54/kW. For a 30-

year project life, the levelized cost on

a current dollar basis is 2.6 mills/kWh.

This is equivalent to $2500/ton of NOx

removed. At the same plant capacity

and 90% removal, the capital cost

increases to $66/kW but the levelized

cost decreases to $1260/ton.

The demonstration project at Plant

Crist contributed significantly to the

body of knowledge regarding the application of SCR on U.S. coals. Currently,

six commercial SCR units have been

installed and are operating on low- and

medium-sulfur U.S. coals. Because SCR

is applicable to almost any kind of

boiler, a significant market for SCR

exists in the United States, especially

in light of increasingly stringent limitations on NOx emissions.
2

Control of Nitrogen

Oxide Emissions:

Selective Catalytic

Reduction (SCR)

technical/economic evaluation of full-scale

commercial applications. The goal of the

CCT Program is to furnish the U.S. energy

marketplace with advanced, more efficient,

and environmentally responsible coalutilizing technologies. These technologies

will mitigate some of the economic and

environmental impediments that inhibit

utilization of coal as an energy source.

The CCT Program also has opened a

channel to policy-making bodies by providing data from cutting-edge technologies

to aid in formulating regulatory decisions.

DOE and participants in several CCT projects have provided the EPA with data to

help establish NOx emissions targets for

coal-fired power plants subject to compliance under the CAAA.

A major issue of concern is emissions

of nitrogen oxides (NO and NO2, collectively referred to as NOx). Under the CCT

Program, a project was undertaken to

evaluate the performance and economics

of the selective catalytic reduction (SCR)

Background

The Clean Coal Technology (CCT)

Demonstration Program, which is 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. At the same time, the U.S.

Environmental Protection Agency (EPA)

is in the process of promulgating new

regulations, authorized by the 1990 Clean

Air Act Amendments (CAAA), concerning emissions from a variety of stationary

sources, including coal-burning power

plants.

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
3

Plant Crist, Pensacola FL

process for removing NOx from the flue

gas of boilers fired with U.S. high-sulfur

coals. A major advantage of SCR is that

the reaction products, nitrogen and water,

are innocuous compounds already present

in the air.

The SCR process was initially discovered in the United States. Although it is

widely used in Japan and Europe, including numerous installations on coal-burning

power plants, there were technical uncertainties associated with applying SCR to

plants burning U.S. high-sulfur coals, primarily involving the danger of forming

excessive amounts of ammonia-sulfur

compounds with attendant plugging and

corrosion of downstream equipment. There

was also concern over the presence of trace

metals such as arsenic, which can lead to

catalyst deactivation.

The SCR demonstration project, conducted at Gulf Power Company’s Plant

Crist near Pensacola, Florida, was designed to evaluate the performance and

cost of SCR technology under typical

boiler conditions in the United States.

Its successful completion would demonstrate a process capable of meeting

increasingly stringent NOx emission

regulations.

NOx Emissions

Standards

History

The Clean Air Act was originally

passed in 1967. It was amended in 1970,

1977, and most recently in 1990. The

CAAA authorized the EPA to establish

standards for a number of atmospheric

pollutants, including sulfur dioxide (SO2)

and NOx. The regulations establish New

Source Performance Standards (NSPS)

for these flue gas components. Updating

the emissions standards every five years

is mandated.
4

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 $6.0 billion. DOE’s share of the total project costs is about $2.0 billion,

or approximately 34 percent of the total. The projects’ industrial participants

(i.e., the non-DOE participants) are providing the remainder—nearly $4.0

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.

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

coal-fired 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 256

Group 1 boilers, namely dry-bottom,

wall-fired boilers and tangentially fired

(T-fired) boilers. In Phase II, which begins in 2000, lower emission limits are

set for Group 1 boilers, and initial limits

are set for 145 Group 2 boilers, which include cell-burners; cyclones; wet-bottom,

wall-fired boilers; and other types of

coal-fired boilers. In addition to the 256

Phase I, Group 1 boilers, there are another 607 wall-fired and T-fired boilers

that must meet the applicable limits in

Phase II.

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 current

NAAQS for ozone is 0.12 ppm (1 hour

average). At this level many large- and

medium-sized urban areas are classified

as nonattainment, and many power plants

are within these nonattainment areas.

Furthermore, the Northeast Ozone Transport Region (NOTR), consisting of 12

states and the District of Columbia, is

considered nonattainment with respect

to sources in that region.

A number of studies have indicated

that the current ambient standard for

ozone is inadequate to protect either

human health or the environment. For

this reason the EPA has proposed a more
5

NOx Regulations under the Clean Air Act Amendments of 1990

NOx emissions are generated primarily from transportation, utility, and other industrial sources. They

are reported to contribute to a variety of environmental problems, including acid rain and acidification

of aquatic systems, ground level ozone (smog), and

visibility degradation. For these reasons, NOx emissions are regulated in many ways by different levels

of government throughout the country.

Ozone Non-Attainment

Title I of the CAAA requires the states to apply the

same limits to major stationary sources of NOx as are

applied to major stationary sources of volatile organic

compounds. 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 controls representing

the lowest achievable emission rate, and (3) each state

with an ozone nonattainment region in it to develop a

State Implementation Plan (SIP) that, in most cases,

will include reductions in stationary source NOx emissions beyond those required by the RACT provisions

of Title I. These requirements apply in certain ozone

nonattainment areas and ozone transport regions.

Mobile Sources

Title II of the CAAA calls for reductions in motor

vehicle emissions. Emission limits for new vehicles

constitute the majority of reductions from vehicles.

Emission limits for various classes of vehicles will be

implemented throughout this decade.

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-part strategy to reduce emissions. The

first stage of the program is projected to reduce NOx

emissions in the United States by over 400,000 tons/yr

between 1996 and 1999 (Phase I). These reductions

are achieved by the installation of low-NOx burner

(LNB) technology on dry-bottom wall-fired boilers and

tangentially fired (T-fired) boilers (Group 1). In Phase II,

which begins in 2000, EPA may establish more stringent standards for Group 1 boilers and establish regulations for Group 2 boilers (boilers applying cell-burner

Coal-Fired Boiler NOx Emissions Limits,

lb/106 Btu (Title IV)

Phase I Phase II

Implementation Date 1996 2000+

Status of Regulations Promulgated Proposed*

Group 1 Boilers

Dry-Bottom Wall-Fired 0.50 0.46

Tangentially Fired 0.45 0.40

Group 2 Boilers

Wet-Bottom Wall-Fired NA 0.84

 >65 MWe

Cyclone-Fired NA 0.86

 >155 MWe

Vertically Fired NA 0.80

Cell Burner NA 0.68

Fluidized Bed NA Exempt

Stoker NA Exempt

____

NA = Not applicable

*Final ruling is anticipated by December 1997

technology, cyclone boilers, wet-bottom boilers, and other

types of coal-fired boilers). Currently EPA has proposed a

rule that would set lower Phase II, Group 1 emission limits

and establish limits for Group 2, resulting in an additional

projected reduction of 820,000 tons/yr.

Implementation

The emission limitations proposed by EPA under Title

IV for Phase II, Group 1 boilers are more stringent than

the Phase I standards. The statute requires that emission

control costs for Group 2 boilers be comparable to those

for Group 1 boilers.

EPA has the authority to set Title IV NOx limitations at

higher levels if a utility can demonstrate that a boiler could

not meet the standard by using LNB technology. The regulations also 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. Averaging is not limited geographically.
6

Schematic flow diagram of SCR process

Economizer

Bypass SCR Reactor

FD

Boiler Fan

ESP

Air

Heater

stringent NAAQS for ozone: 0.08 ppm

(8 hour average). An area would be considered nonattainment when the third highest

daily maximum 8-hour concentration, averaged over three years, is above 0.08 ppm.

EPA is also seeking comment on a standard

of 0.07 ppm.

NOx Control

Technologies

The primary technology currently used

in utility boilers for NOx reduction is combustion modification using low-NOx burners

(LNBs), frequently combined with overfire

air (OFA). This technology has generally

proven adequate to meet Title IV emissions

requirements. In fact, field experience with

combustion modification technologies demonstrated in the CCT Program substantiated

the validity of the current regulations. Utilities subject to the most stringent requirements may be forced to use post-combustion

technologies such as SCR, either alone or

in combination with LNBs.

The SCR Process

History

Selective catalytic reduction of NOx

using ammonia (NH3) as the reducing gas

was patented in the U.S. by Englehard

Corporation in 1957. The original catalysts, employing platinum or platinum

group metals, were unsatisfactory because

of the need to operate in a temperature

range in which explosive ammonium

nitrate forms. Other base metal catalysts

were found to have low activity. Research

done in Japan in response to severe environmental regulations in that country led

to the development of vanadium/titanium

catalysts which have proved successful.

This combination forms the basis of current

SCR catalyst technology.

In addition to Japan, several countries

in Western Europe have enacted stringent

NOx emission regulations which essentially mandate the installation of SCR, and

extensive catalyst development work has

been done, especially in Germany. As a

result, SCR has been applied on numerous

boilers in Europe. Encouraged in part by

the initial success of the SCR test program

at Plant Crist, there are now six commercial installations of SCR on coal-burning

power plants in the U.S.

Process Description

NOx, which consists primarily of NO

with lesser amounts of NO2, is converted

to nitrogen by reaction with NH3 over a

catalyst in the presence of oxygen. A small

fraction of the SO2, produced in the boiler

by oxidation of sulfur in the coal, is oxidized to sulfur trioxide (SO3) over the SCR

catalyst. In addition, side reactions may

produce undesirable by-products: ammonium sulfate, (NH4)2SO4, and ammonium

bisulfate, NH4HSO4. There are complex

relationships governing the formation of
7

4NO + 4NH3 + O2 —> 4N2 + 6H2O

2NO2 + 4NH3 + O2 —> 3N2 + 6H2O

SO2 + 1/2 O2 —> SO3

2NH3 + SO3 + H2O —> (NH4)2SO4

NH3 + SO3 + H2O —> NH4HSO4

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. For coal-fired units, thermal NOx generally

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

In addition, minor amounts of NOx are formed through complex interaction of molecular nitrogen with hydrocarbons in an early phase of the

flame front; this is referred to as prompt NOx.

The quantity of NOx formed depends primarily on the “three t’s”:

temperature, time, and turbulence. In other words, flame temperature

and the residence time of the fuel/air mixture, 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.

How NOx Is Formed in a Boiler

Side Reactions

Chemistry of the SCR Process

these by-products, but they can be minimized by appropriate control of process

conditions.

Ammonia Slip

Unreacted NH3 in the flue gas downstream of the SCR reactor is referred to as

NH3 slip. It is essential to hold NH3 slip

to below 5 ppm, preferably 2-3 ppm, to

minimize formation of (NH4)2SO4 and

NH4HSO4, which can cause plugging and

corrosion of downstream equipment. This

is a greater problem with high-sulfur coals,

caused by higher SO3 levels resulting

from both higher initial SO3 levels due to

fuel sulfur content and oxidation of SO2

in the SCR reactor.

Operating Temperature

Catalyst cost constitutes 15-20% of the

capital cost of an SCR unit; therefore it is

essential to operate at as high a temperature as possible to maximize space velocity

and thus minimize catalyst volume. At the

same time, it is necessary to minimize the

rate of oxidation of SO2 to SO3, which is

more temperature sensitive than the SCR

reaction. The optimum operating temperature for the SCR process using titanium and vanadium oxide catalysts is

about 650-750°F. Most installations use

an economizer bypass to provide flue gas

to the reactors at the desired temperature

during periods when flue gas temperatures

are low, such as low load operation.

Reactor Placement

SCR systems can be installed at any

of three locations in a power plant:

In the Plant Crist tests, which operated on a slip stream

from the power plant flue gas, each reactor was located

upstream of the APH; thus these were hot side installations.

Seven of the eight reactors were also high dust installations.

In commercial practice, most SCR reactors are hot side

installations. This location is preferred because it obviates

the need to reheat the flue gas to reaction temperature,

thereby minimizing loss of thermal efficiency.

(1) upstream of the air preheater (APH)

and electrostatic precipitator (ESP)

[referred to as hot side, high dust]

(2) upstream of the APH and downstream of the ESP [hot side, low dust]

(3) downstream of the APH and ESP

[cold side, low dust].
8

Diagram of demonstration unit at Plant Crist

Plant Crist SCR unit under construction

Large

SCR Reactor

(1 of 3) Small

SCR Reactors

(3 of 6)

Power

Plant

Duct

To

Cold Side

ESP Inlet

Ash

Cyclone

Catalyst

Layers

Dummy

Layer

High Dust/Hot Side ESP Inlet Flue Gas

Slip Stream

Low Dust/Hot Side

ESP Outlet Bypass

Bypass

Cooler

Fan

NH3/Air

Air

Heater

Heater

NH3/Air

Power

Plant

Duct Venturi

Dummy

Layer

Ash Ash

Catalysts

SCR catalysts are made of a ceramic

material that is a mixture of carrier (titanium oxide) and active components (oxides

of vanadium and, in some cases, tungsten).

The two leading shapes of SCR catalyst

used today are honeycomb and plate. The

honeycomb form usually is an extruded

ceramic with the catalyst either incorporated throughout the structure (homogeneous) or coated on the substrate. In the

plate geometry, the support material is generally coated with catalyst. When processing flue gas containing dust, the reactors

are typically vertical, with downflow of

flue gas. The catalyst is typically arranged

in a series of two to four beds, or layers.

For better catalyst utilization, it is common

to use three or four layers, with provisions

for an additional layer which is not initially

installed.

As the catalyst activity declines, additional catalyst is installed in the available

spaces in the reactor. As deactivation

continues, the catalyst is replaced on a

rotating basis, one layer at a time, starting

with the top. This strategy results in maximum catalyst utilization. The catalyst is

subjected to periodic sootblowing to remove

deposits, using steam as the cleaning agent.

Clean Coal Technology

SCR Demonstration

Project

Goals and Objectives

The goal of the demonstration project

at Plant Crist was to evaluate SCR retrofit

technology for reducing NOx emissions

from utility boilers burning high-sulfur

U.S. coals. The project was designed to

confirm pilot plant results and to develop

scale-up procedures necessary for commercial application of the technology, as well

as to resolve those technical issues that

could not be adequately addressed in an

engineering study.

The objectives of this project were to

investigate:

• Performance of a wide variety of

SCR catalyst compositions, geometries, and manufacturing methods

at typical U.S. utility operating conditions.

• Catalyst resistance to poisoning by

trace metal species present in highsulfur U.S. coals but not present, or

present at much lower concentrations,

in fuels from other countries.

• Effects on the balance-of-plant equipment from sulfur compounds formed

by reactions between SO2, SO3, and

NH3 (e.g., plugging and corrosion of

downstream equipment).

Project Description

The demonstration project was conducted at Gulf Power’s Plant Crist, located

near Pensacola, Florida. Plant Crist consists
9

Clean catalyst installed in one of the SCR reactors

Plugging that may occur during normal operations of an SCR facility

Damage caused by erosion in the catalyst bed

of seven fossil-fuel burning generating

units. Units 1, 2, and 3 are small gas- and

oil-fired boilers, while Units 4 through 7

are coal-fired. The SCR test facility was

built in and around the ductwork on Unit 5.

This unit is a tangentially fired, dry-bottom

boiler, rated at 75 MWe (gross), built by

Combustion Engineering and placed into

operation in 1961. The unit is equipped

with hot side and cold side ESPs for particulate control.

The individual SCR reactors operated

on a slip stream taken from the flue gas of

Unit 5. There were three 2.5-MWe equivalent reactors and six 0.20 MWe equivalent

reactors, each containing a different catalyst for side-by-side performance comparisons. Eight of the nine reactors were

designed to treat flue gas containing the

full particulate loading (high dust), extracted from the inlet duct of the hot side

ESP, while one small reactor was designed

to treat flue gas extracted from the hot side

ESP outlet (low dust). Because of design

problems, it was not possible to fully

evaluate the differences in performance

between the single low dust reactor and

the high dust units.

Each reactor train was equipped with

an electric duct heater to independently

control flue gas temperature and a venturi

meter to measure the flue gas flow rate.

An economizer bypass line maintained a

minimum flue gas temperature of 620°F

to the high dust reactors. Anhydrous NH3

was independently metered to a stream

of heated dilution air and was injected via

nozzles into the flue gas upstream of each

SCR reactor. The flue gas, containing NH3,

passed through the reactors, each of which

had the capacity to contain up to four catalyst layers.

For each of the larger reactor trains,

the flue gas exiting the reactor entered a

specially modified pilot-scale APH, each

of different design. The modified APHs

were used to better simulate full-scale APHs

for improved extrapolation of results to
10

Vertical-flow fixed-bed type reactor chamber

Hopper

Mono-Rail

Electric

Hoist

Catalyst

Module

Gas Flow

Frame

Catalyst

Element

Gas

Flow

Reactor

Chamber

Sootblower

Inlet Gas Duct

Gas

Flow

Trolley

source: Southern Company 1995

The test facility examined the performance of eight SCR catalysts (one reactor

was idled due to the withdrawal of a

project participant), differing in chemical

makeup and physical form. Each catalyst

supplier was given great latitude in designing its catalyst offering provided it met the

following requirements:

• Catalyst baskets that match predetermined reactor dimensions

• A maximum of four catalyst layers

• A minimum 80% NOx reduction at

baseline conditions

• A maximum baseline NH3 slip

of 5 ppm

• A maximum baseline SO2 oxidation

rate of 0.75%

• A 2-yr life while meeting the above

performance criteria

It was determined that full-scale demonstration of SCR technology was not required. The major issues to be addressed

were questions of chemistry which could

be adequately investigated using a slip

stream facility and, in general, the performance of fixed-bed catalytic reactors can

readily be scaled up. A full-scale facility

would have been unnecessarily expensive

while providing little additional in the way

of technical information. However, the

catalyst modules used in the larger reactors

were full-scale versions of the catalysts

used commercially in Europe and Japan.

The test units were designed to ensure that

the flue gas slip streams were fully representative in terms of gaseous and solid

species and that the catalyst modules were

exposed to flue gas conditions identical

to those experienced in full-scale

installations.

The tests were conducted on flue gas

 derived primarily from burning Illinois

No. 6 coal, a typical midwestern highsulfur (2.3% sulfur) coal widely used

for power generation.

commercial scale. The APHs were incorporated in the project to evaluate the effects

of SCR on APH deposit formation and

the effects of the deposits on APH performance and operation.

All reactor trains except the low dust

train had a cyclone downstream of the

SCR reactor to protect the induced draft

fans from particulates. The exhausts from

all of the SCR reactors were combined into

a single manifold and reinjected into the

host boiler’s flue gas stream ahead of the

cold side ESP. The preheated air streams

from the APHs on the larger reactors were

also combined into a single manifold and

returned to the host boiler draft system at

the existing host APH outlet. All particulate matter removed from the test facility

was combined with ash from the host unit’s

ESP and sent to ash disposal.
11

Catalyst Reactor Dust Catalyst

Reactor Supplier Size Level Composition Configuration

A W.R. Grace (Noxeram) Large High V-W/Ti Honeycomb

B Nippon Shokubai K.K. Large High V-W/Ti-Si Honeycomb

C Siemens AG Large High V/Ti Plate

D W.R. Grace (Synox) Small High V/Ti-Si Honeycomb

E Cormetech Small High V-W/Ti Honeycomb

F Haldor Topsoe Small High V/Ti Plate

G Hitachi Zosen Small High V/Ti Plate

J Cormetech Small Low V-W/Ti Honeycomb

SCR Catalysts Tested at Plant Crist

Properties of Coal Used in Plant Crist Tests

Coal Source: Illinois No. 6 Bituminous

Proximate Analysis, wt% (as received)

Fixed Carbon 47.65

Volatile Matter 34.16

Moisture 9.80

Ash 8.39

Total 100.00

HHV, Btu/lb 12,500

Ultimate Analysis, wt% (as received)

Carbon 67.48

Hydrogen 4.51

Nitrogen 1.43

Sulfur 2.33

Chlorine 0.14

Oxygen 5.92

Ash 8.39

Water 9.80

Total 100.00

Performance

The catalysts were tested over a twoyear period (16,000 hours), including

parametric testing every four to six months.

Catalysts were provided by three U.S. suppliers (Englehard, Grace, and Cormetech),

two European suppliers (Haldor Topsoe

and Siemens), and two Japanese suppliers

(Hitachi Zosen and Nippon Shokubai).

After Englehard withdrew from the

project, its low dust catalyst was replaced

by one of Cormetech’s low dust catalysts.

All of the catalysts performed well in

both parametric (short tests varying operating conditions) and long term (baseline)

testing, achieving at least 80% NOx removal with maximum NH3 slip of 5 ppm.

Although the catalysts varied somewhat

in operating characteristics such as activity and pressure drop, no one catalyst

was found superior.

Catalyst deactivation proceeded as expected based on European and Japanese

experience, with an average decrease in

activity of 20% over the two-year period.

No unusual deactivation effects could be

attributed to the use of high-sulfur U.S.

coals, and no detrimental effects of trace

metals such as arsenic were detected.
12

SCR Process Conditions

Kinetics of the SCR Reaction

Temperature, °F 700 620-750

Flow, SCFM 5000 (large reactors) 60% to 150%

400 (small reactors) of Design

NH3/NOx Molar Ratio ~0.81 0.6 to 1.0

k/SV = -ln(1-x/r) + ln[(1-x)/(1-x/r)]/KNo(1-r),

where K = adsorption coefficient of NOx on the catalyst.

k/SV = -ln(1-x/r)

s = (r-x)No or r = x + s/No,

where k = rate constant

SV = space velocity

x = fractional conversion of NOx

r = molar ratio of NH3 to NOx at reactor inlet

s = NH3 slip

No = NOx concentration at reactor inlet.

More recent work has shown that the process can be better represented by a modified Langmuir-Hinshelwood relationship, as follows:

In some of the earlier literature on the kinetics of the SCR process,

the rate constant is defined in the following equations, which assume

that the reaction is first order with respect to NOx or NH3:

The latter relationship more accurately predicts space velocity (and

hence catalyst volume) required to both remove NOx and minimize NH3

slip, especially at higher conversion levels.

Design Basis Parametric

for 80% Conversion Tests

Both plate and honeycomb catalysts

performed satisfactorily. A major difference between these catalyst configurations

is pressure drop, which must be taken into

account in designing commercial SCR

installations. Other differences include

geometric surface area, resistance to

poisoning, and conversion of SO2 to SO3.

No serious plugging of the catalysts

was experienced, indicating that the

sootblowing procedures used in the test

program were satisfactory. Performance

comparisons between high dust and low

dust reactor configurations were inconclusive because of problems associated with

the design of the test facility.

There was significant variation in the

rate of oxidation of SO2 to SO3 among

the catalysts tested, but the amounts of

(NH4)2SO4 and NH4HSO4 were minor.

However, there was some corrosion of

the APHs downstream of the SCR reactors.

Appropriate materials of construction for

APHs need to be chosen for commercial

SCR installations.

 The environmental impacts of the technology studied in the test program are significant. SCR has been shown to provide

high levels of NOx removal with minimal

NH3 slip. Widespread use is anticipated

in the future, providing a major reduction

in NOx emissions from coal-fired power

plants in the United States.

Long Term Testing of

Catalyst Deactivation

The results of the long term catalyst

tests are expressed in terms of the decrease

in activity over time, as measured by the

rate constant, k. From a practical standpoint, the precise kinetic relationship is of

little concern. What is important is the

ratio k/ko, where k is the rate constant at a

given time in the deactivation cycle and ko
13

Catalyst activity (k/ko) vs. time

Typical SCR performance

80

60

40

20

0

100

0 0.2 0.4 0.6 0.8 1.0 1.2 1.4

NH3/NOx

NO

x Reduction (%)

NH3 Slip (ppm)

80

60

40

20

0

100

1.00

0.90

0.80

0.60

0 2000 4000 6000 8000 10000 12000 14000

0.70

0.50

16000

Operating Time (hours)

Relative Activity, (k/k

o)

is the initial rate constant with fresh catalyst. For this project this ratio, and thus

catalytic activity, was determined by

dividing the fractional NOx conversion

at a given time by the conversion at time

zero, based on assuming first order kinetics. For the SCR test program at Plant

Crist, the relative activity began at 1.0

at time zero and decreased to an average

of about 0.8 at 12,000 hours.

Parametric Studies

The parametric studies investigated the

effects of reactor operating temperature,

NH3/NOx molar ratio, and space velocity

on catalyst performance.

The tests covered the range of 620°F

 to 750°F, with the design operating temperature being 700°F. As temperature was

increased while maintaining a constant 0.8

NH3/NOx ratio, NH3 slip remained fairly

constant at less than 5 ppm. The parametric tests covered the range of 0.6 to 1.0,

with the design NH3/NOx molar ratio

being 0.8. NH3 slip generally remained

constant at about 2 ppm at low levels of

NH3/NOx ratio, increasing significantly

above a ratio of about 0.9.

At an operating temperature of 700°F

and an NH3/NOx ratio of 0.8, increasing

the gas flow rate (and hence the space velocity) from 100% to 150% of the design

value resulted in a fairly constant NH3

slip of less than 5 ppm for three of the

catalysts. NH3 slip increased to significantly greater than 5 ppm for the other

three catalysts studied in this part of the

test program.

As the temperature was increased, the

rate of SO2 oxidation was fairly constant

at less than 0.2% for two of the catalysts,

while increasing to varying degrees for

the other catalysts.
14

Significance of Test

Results

The test data show that the SCR process

can achieve high (up to 90%) NOx reduction while meeting acceptable NH3 slip

levels over an extended period of operation

(at least two years). In practice, SCR reactors are designed not just to meet specified

NOx levels at startup, but sufficient catalyst volume is provided to allow for catalyst deactivation.

NOx reduction is controlled for the most

part by the NH3/NOx ratio. Therefore, even

with excess catalyst in the reactor, NOx

reduction remains essentially constant over

the life of the catalyst. Ammonia slip increases somewhat over time until it reaches

the design limit, at which point fresh catalyst is added. Although relatively high NH3

slip was observed in this study at high

levels of NOx reduction, this effect probably resulted from the difficulty in maintaining precise measurement and control

of NH3 flow while operating at NH3/NOx

ratios approaching 1.0. This effect could be

Plant Birchwood Stanton Carneys Logan Indiantown Merrimack 2

(Unit 2) Point

(2 Units)

Owner/ SEIa/ Orlando USGenb USGenb USGenb Public Service

Operator Cogentrix Utilities of NH

Commission

Location King George Orlando, Carneys Swedesboro, Indiantown, Concord,

County, VA FL Point, NJ NJ FL NH

Capacity, MWe (net) 220 425 260 225 330 330

Coal Sulfur, wt% 1.0 1.1-1.2 <2.0 <1.5 0.8 1.5

Boiler Type T-fired Wall-fired Wall-fired Wall-fired Wall-fired Wet-bottom

Burner Typec LNB/OFA LNB/OFA LNB/OFA LNB/OFA LNB/OFA Cyclone

Catalyst Supplier Siemens Siemens IHId Siemens Siemens Siemens

Inlet NOx, lb/106 Btu 0.17 0.32 0.32 0.35 0.25 2.66

Outlet NOx, lb/106 Btu 0.075 0.17 0.13 0.14 0.15 0.77

NOx Reduction, % 56 47 59 60 40 71

NH3 Slip, ppm <5 2 <5 <5 <5 <2

Date SCR Commercial 11/96 6/96 3/94 9/94 12/95 5/95

SCR Installation New New New New New Retrofit

a Southern Energy, Inc.

b U.S. Generating Company, a Pacific Gas and Electric Company/Bechtel partnership

c LNB = Low-NOx burners; OFA = overfire air

d Ishikawajima-Harima Heavy Industries

Commercial SCR Installations on

Coal-Fired Utility Boilers in the U.S.
15

Boiler Population in the OTAG Region

The poorly performing unit initially experienced frequent plugging of the air

preheater surfaces downstream of the

SCR reactor. This problem was remedied

by installation of additional catalyst,

bringing performance to the desired level.

In general, the plant staff and management at each facility are pleased with the

SCR operation.

Future Work

The demonstration project and the

subsequent commercial applications on

coal-fired boilers in the United States

have shown that SCR can achieve high

levels of NOx reduction at an acceptable

cost. This has been a major contributing

factor in EPA’s recent actions in proposing more stringent control of NOx emissions from coal-burning power plants.

It is expected that design improvements

will be made as operating experience

is gained.

The degree to which SCR will be incorporated in new or future retrofit applications will depend on the severity of NOx

control standards yet to be promulgated.

encountered in commercial units in cases

where the owner/operator attempts to

“stretch” the performance of the catalyst.

Commercial

Applications of

SCR Technology

With the completion of the SCR test

program at Plant Crist, the experimental

facility was dismantled. Supported in part

by the successful demonstration of SCR

technology at Plant Crist, several U.S.

companies have decided to use SCR on

coal-fired utility boilers.

At present, there are six such installations. One of these units, Birchwood, is

an independent power producer jointly

owned by Southern Energy Inc. (SEI) and

Cogentrix. SEI is a non-regulated subsidiary of Southern Company. The Birchwood

SCR design was based on data from the

test program at Plant Crist. Since all of the

U.S. installations are relatively new, there

has not been sufficient time to evaluate

long-term performance, particularly with

respect to catalyst deactivation. All of the

SCR units are hot side, high dust installations. Five of the SCR units are associated

with new plants and one is a retrofit. The

feed coals range in sulfur content from

about 0.8 to 2.0 wt%.

All of the U.S. SCR units are operating

successfully, with NOx reductions ranging

from 40 to 71% depending on the uncontrolled NOx concentration and the desired

level of NOx in the stack gas. With the exception of one unit which appears to have

initially contained insufficient catalyst

because of higher uncontrolled NOx than

the catalyst was designed for, there have

been no problems in meeting NH3 slip

requirements or with deposition of solids,

and catalyst deactivation has proceeded

as predicted from the Plant Crist test data.

SCR reactor cyclones at Plant Crist

Boiler Type Number of Units Generating Capacity, MWe

Wall-fired 315 94,327

Tangentially fired 315 112,000

Cyclone 77 22,329

Cell-fired 33 24,143

Wet-bottom 23 4,712

Roof-fired 29 3,111

Total 792 260,622
16

In fact, the success of the experimental work

at Plant Crist and the experience gained in

the subsequent commercial applications

in the U.S. have contributed significantly

to consideration of more stringent NOx

emissions criteria.

Market Analysis

The SCR process is applicable to all

types of boilers including stoker, cyclone,

wall-fired and tangentially fired boilers.

A potential market for SCR is in the Ozone

Transport Assessment Group (OTAG)

region.

OTAG, which was created under the

auspices of the EPA for the purpose of

developing recommendations for ozone

reduction, comprises the 37 contiguous

states except the 11 westernmost states.

All boilers in the OTAG region are potential candidates for SCR, although regulations are still being formulated and many

of these boilers may not be subject to NOx

emissions limits so stringent as to require

the use of SCR. In any given case the

economic viability of SCR will be highly

dependent upon retrofit difficulty and other

site specific factors.

The need for SCR will be dictated by

the power plant NOx emissions limits now

being considered, since LNBs (with or

without OFA) will not be able to meet the

lower NOx target levels. Utilities subject

to the most stringent requirements may be

forced to use SCR, either alone or in

conjunction with LNBs.

Economics of SCR Process

1996 Dollars

Greenfield Installation

Coal Properties Units Value

Higher heating value (HHV) Btu/lb 12,500

Power Plant Attributes With Controls

Plant capacity, net MWe 250

Power produced, net 109 kWh/yr 1.34

Capacity factor % 65

Coal fed 106 tons/yr 0.54

NOx Emissions Control Data

Removal efficiency % 60

Emissions without SCR lb/106 Btu 0.35

Emissions with SCR lb/106 Btu 0.14

NOx removed tons/yr 1,374

Total Capital Requirement $/kW 54

Levelization mills/ $/ton

Factor [a] kWh NOx removed

Levelized Cost, Current $

Capital charge 0.154 1.50 1464

Fixed O&M 1.362 0.32 310

Variable O&M 1.362 0.75 726

Total 2.57 2500

aLevelization based on 30-year project life, 38% tax rate, 3% inflation, and

the following capital structure: 50% debt @ 8.5% return, 15% preferred

stock @ 7.0% return, and 35% common stock @ 7.5% return, giving a

weighted cost of capital of 9.150% (including inflation).
17

Effect of NOx Removal Rate on SCR Economics

1996 Dollars

Greenfield Installation

Sensitivity Analysis of SCR Economics

1996 Dollars

Greenfield Installation

NOx Removal, % 50 60 70 80 90

Outlet NOx, lb/106 Btu 0.39 0.31 0.23 0.15 0.08

Capital, $/kW 55 57 59 62 66

$/ton NOx removed 1750 1540 1390 1290 1260

(current dollar basis)

Effect of Capacity

Capacity, MWe 125 250 700

NOx Removal, % 60 60 60

Inlet NOx, lb/106 Btu 0.35 0.35 0.35

Capital, $/kW 61 54 45

$/ton NOx removed 2811 2500 2165

(current dollar basis)

Effect of Inlet NOx

Capacity, MWe 250 250 250

NOx Removal, % 60 60 60

Inlet NOx, lb/106 Btu 0.45 0.35 0.25

Capital, $/kW 61 54 45

$/ton NOx removed 1977 2500 3446

(current dollar basis)

Economics

SCR Costs – Southern Company

Estimates

The Southern Company has prepared

economic estimates for the SCR process.

The base case is a 250 MWe greenfield unit,

using a projected process design for the nth

plant which incorporates improvements

based on experience gained from the demonstration project. The boiler is either a wallfired or T-fired unit, equipped with LNBs.

The coal feed is assumed to contain 2.5 wt%

sulfur. Design NOx concentration at the reactor inlet is 0.35 lb/106 Btu. NOx reduction

is assumed to be 60%, giving an outlet concentration of 0.14 lb/106 Btu. Catalyst deactivation is assumed to be 20% at 16,000 hr;

that is, the k/ko ratio is 0.8 at that time.

The estimated capital cost is $54/kW.

For a 30-year project life, the levelized

cost on a current dollar basis is 2.57 mills/

kWh. This is equivalent to $2500/ton of

NOx removed.

The economics are highly dependent

on a number of variables including plant

capacity, degree of NOx removal, and inlet

NOx concentration. At a given plant capacity, levelized costs on a $/ton of NOx removed basis decrease with increasing NOx

removal rate and increasing initial NOx

concentration, such as would occur in situations where SCR is used on boilers with

the highest uncontrolled NOx levels and

without combustion modification. Longer

catalyst life and/or reduced catalyst prices

also reduce costs.
18

SCR Costs – Other Estimates

The above cost estimates, prepared by

Southern, assume the use of combustion

modification to reduce NOx in the flue gas

to 0.35 lb/106 Btu at the SCR reactor inlet,

with only 60% additional reduction in the

SCR unit required to achieve the target

NOx emissions level of 0.14 lb/106 Btu.

Alternatively, it is useful to consider situations where all of the NOx reduction is

achieved via SCR. The effects of inlet

NOx concentration, unit capacity, and NOx

removal rate on SCR economics were investigated in a DOE study. The base case is

assumed to have an inlet NOx concentration

of 500 ppm, or about 0.77 lb/106 Btu, representing a typical T-fired boiler. Boiler

capacity is 250 MWe, as in the Southern

study. Ammonia slip is 5 ppm and catalyst

life is 4 years.

It should be noted that as the NOx removal efficiency increases, the capital cost

increases but the levelized cost decreases

because of the larger number of tons/yr

of NOx removed.

The above costs are consistent with

figures obtained recently from a major

supplier of SCR catalyst, incorporating

detailed engineering estimates for six retrofit units ranging from 190 MWe to 570

MWe, with 85% NOx removal. Capital

costs were $55 to $84/kW, and levelized

costs were $950 to $1400/ton of NOx

removed.

An alternative approach to SCR commercialization involves the Build, Own,

Operate, and Maintain (BOOM) concept,

in which a third party provides the capital

for the SCR unit, eliminating the need for

a major expenditure on the part of the utility. The third party also operates and maintains the SCR unit, charging the utility an

agreed upon price for providing SCR

services. Preliminary proposals using

this concept show favorable economics

compared with conventional funding

approaches.

Comparison with Other

Technologies

The only other commercially available

technology capable of achieving NOx removal levels comparable to that of LNBs

is selective noncatalytic reduction (SNCR).

Since SNCR does not require use of a

catalyst, it may be considerably less expensive than SCR. However, typical NOx

removals for SNCR are 25-45%, whereas

U.S. commercial SCR installations are

achieving up to about 70% NOx removal.

In addition, some experience has shown

that SNCR applications are limited to

smaller boilers because of difficulties in

achieving uniform distribution of reagent

in the flue gas stream, and numerous

control problems have arisen especially

where loads fluctuate. Therefore, SCR

may be preferred over SNCR in some

situations. Hybrid processes, using SNCR

followed by SCR, have the potential for

operating flexibility at lower overall cost.

Such configurations need to be evaluated

on a case-by-case basis.

Worldwide Installations of SCR on

Coal-Fired Utility Boilers

1996 Data

Country/Region Capacity, MWe

Austria 1,200

Germany 33,000

Japan 7,700

Netherlands 1,000

Scandinavia 1,100

United States 2,000

Total 46,000
19

SCR demonstration facility at Plant Crist

Conclusions

The SCR demonstration project was

successful. All of the catalysts in the test

program met design specifications, providing at least 80% NOx removal at an NH3

slip of 5 ppm or less. Although the catalysts

varied somewhat in operating characteristics such as activity and pressure drop, no

one catalyst was found superior. Catalyst

deactivation proceeded as expected based

on European and Japanese experience,

with an average decrease in activity of

20% over a two-year period. No unusual

deactivation effects could be attributed to

the use of high-sulfur U.S. coals containing typical concentrations of metals such

as arsenic. Both plate and honeycomb

catalysts performed satisfactorily.

There was significant variation in the

rate of oxidation of SO2 to SO3 among

the catalysts tested, but the amount of

oxidation was minimal, and excessive

formation of (NH4)2SO4 and NH4HSO4

was avoided. Some corrosion of the air

preheaters was experienced, indicating

the need to specify appropriate materials

of construction in this service. No serious

plugging of the catalysts was found, indicating that the sootblowing procedures

used in the test program were satisfactory.

A commercial-scale SCR unit can be

installed for about $50-60/kW in a new

plant. Retrofit costs could be significantly

higher. Six commercial SCR units are operating successfully on low- and mediumsulfur coals in the United States. A significant market for SCR potentially exists,

especially in light of increasingly stringent

limitations on NOx emissions.
20

Coal barge unloading facility and storage area at Plant Crist

Bibliography

Comprehensive Report to Congress, Clean

Coal Technology Program, “Demonstration of Selective Catalytic Reduction

(SCR) Technology for the Control of Nitrogen Oxide (NOx) Emissions from HighSulfur, Coal-Fired Boilers,” proposed by

Southern Company Services, Inc., DOE,

April 1990.

J.D. Maxwell (Southern Company Services) and A.L. Baldwin (DOE), “Demonstration of Selective Catalytic Reduction

(SCR) Technology for the Control of Nitrogen Oxide (NOx) Emissions from HighSulfur, Coal-Fired Boilers,” First Annual

Clean Coal Technology Conference

(Cleveland OH), September 1992.

W.S. Hinton, C.A. Powell, and J.D.

Maxwell (Southern Company Services),

“Demonstration of Selective Catalytic

Reduction Technology for the Control of

Nitrogen Oxide Emissions from HighSulfur, Coal-Fired Boilers,” Second Annual Clean Coal Technology Conference

(Atlanta GA), September 1993.

S.M. Cho (Foster Wheeler), “Properly

Apply Selective Catalytic Reduction for

NOx Removal,” Chemical Engineering

Progress, pp. 39-45, January 1994.

W.S. Hinton, C.A. Powell, and J.D.

Maxwell (Southern Company Services),

“Demonstration of Selective Catalytic Reduction (SCR) Technology for the Control

of Nitrogen Oxides (NOx) Emissions from

High-Sulfur, Coal-Fired Boilers at Plant

Crist SCR Test Facility,” Third Annual

Clean Coal Technology Conference

(Chicago IL), September 1994.
21

Plant Crist is only 5 miles from this pristine beach

S.N. Rao, H.G. McIlvried, and A.N. Mann

(Burns and Roe Services Corporation),

“Evaluation of NOx Removal Technologies,” Volume 1: Selective Catalytic Reduction (Revision 2), September 1994.

A.L. Baldwin and D.N. Smith (DOE) and

A.N. Mann, H.G. McIlvried, and S.N. Rao

(Burns and Roe Services Corporation),”Is

Selective Catalytic Reduction (SCR) an

Attractive Option for NOx Control in CoalFired Power Plants?” Air & Waste Management Association Conference (Tempe

AZ), January 1995.

W.S. Hinton, and J.D. Maxwell (Southern

Company Services), and A.L. Baldwin

(DOE), “Demonstration of Selective Catalytic Reduction (SCR) Technology for the

Control of Nitrogen Oxides (NOx) Emissions from High-Sulfur Coal-Fired Utility

Boilers at Plant Crist SCR Test Facility,”

Fourth Annual Clean Coal Technology

Conference (Denver CO), September 1995.

W.S. Hinton, J.D. Maxwell, E.C. Healy,

and R.R. Hardman (Southern Company

Services), “Demonstration of SCR Technology for the Control of NOx Emissions

from High-Sulfur Coal-Fired Utility Boilers,” EPRI Workshop (Cincinnati OH),

August 1996.

E.C. Healy, J.D. Maxwell and W.S.

Hinton, “Economic Evaluation of Commercial-Scale SCR Applications for Utility

Boilers,” Southern Company Services,

September 1996.

Final Report, “Plant Crist Environmental

Monitoring Program,” Radian Corporation, September 1996.

Final Report, “Demonstration of Selective

Catalytic Reduction (SCR) Technology

for the Control of Nitrogen Oxide (NOx)

Emissions from High-Sulfur Coal-Fired

Boilers,” Southern Company Services,

October 1996.

Draft Report, “Performance of Selective

Catalytic Reduction Technology at Electric Utility Boilers in the United States,

Germany and Sweden,” EPA Office of Air

and Radiation, Acid Rain Program, October 1996.

W.S. Hinton, J.D. Maxwell, E.C. Healy,

and R.R. Hardman (Southern Company

Services) and A.L. Baldwin (DOE),

“Demonstration of SCR Technology for

the Control of NOx Emissions from HighSulfur Coal-Fired Utility Boilers,” Fifth

Annual Clean Coal Technology Conference (Tampa FL), January 1997.

A.L. Baldwin and D.N. Smith (DOE) and

A.N. Mann, H.G. McIlvried, and D.L.

Russell (Burns and Roe Services Corporation), “The Role of the U.S. Clean Coal

Technology Program in Implementing the

Objectives of the Joint Canada-U.S. Acid

Rain Mitigation Initiative,” Air & Waste

Management Association Annual Meeting

(Toronto, Canada), June 1997.
22

To Receive Additional

Information

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:

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

Patrice A. Leister

Public Information Office

U.S. Department of Energy

Federal Energy Technology Center

P.O Box 10940-0940

Pittsburgh PA 15236

(412) 892-6126

(412) 892-6127 fax

SCR unit at Birchwood Power Plant
23

SCR unit at Merrimack Power Plant Unit 2

Contacts for CCT Projects

and U.S. DOE CCT Program

U.S. Department of Energy

Contacts

David J. Beecy

Director, Office of Environmental Systems

Technology

FE 72/270cc

Germantown MD 20874-1290

(301) 903-2787

(301) 903-8350 fax

david.beecy@hq.doe.gov

Charles Schmidt

Product Manager, Environmental

Federal Energy Technology Center

P.O. Box 10940

Pittsburgh PA 15236-0940

(412) 892-6290

(412) 892-4818 fax

schmidt@fetc.doe.gov

This Report is available on the Internet

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

Southern Company

Contact

Robert R. Hardman

Project Manager

Southern Company Services, Inc.

14N-8195

P.O. Box 2625

Birmingham AL 35202-2625

(205) 257-7772

(205) 257-5367 fax

robert.r.hardman@scsnet.com
24

List of Acronyms and Abbreviations

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

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

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

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

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

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

ESP ...................................................................................................................... electrostatic precipitator

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

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

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

LNB ..................................................................................................................... low-NOx burners

MWe .................................................................................................................... megawatts of electric power

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

NOx ............................................................................................................................................................ nitrogen oxides

NOTR .................................................................................................................. Northeast Ozone Transfer Region

NSPS.................................................................................................................... New Source Performance Standards

OFA ..................................................................................................................... overfire air

OTAG .................................................................................................................. Ozone Transport Assessment Group

RACT .................................................................................................................. Reasonably Available Control Technology

SCR...................................................................................................................... selective catalytic reduction

SNCR ................................................................................................................... selective noncatalytic reduction

VOCs ................................................................................................................... volatile organic compounds