Advanced Technologies for the Control

of Sulfur Dioxide Emissions from Coal-Fired Boilers

TOPICAL REPORT NUMBER 12 JUNE 1999
TOPICAL REPORT NUMBER 12

A report on three projects conducted under separate

cooperative agreements between:

The U.S. Department of Energy and

 • Pure Air

 • Southern Company Services

 • New York State Electric & Gas Corporation

JUNE 1999

Advanced Technologies

for the Control of

Sulfur Dioxide Emissions

from Coal-Fired Boilers

Cover image: Plant Views of

Bailly, Yates, and Milliken Stations

Executive Summary........................................................................................... 1

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

Emission Standards ........................................................................................... 4

Clean Coal Technology Wet FGD Demonstration Projects .............................. 4

 Advanced Flue Gas Desulfurization (AFGD) Demonstration Project ........... 5

 Demonstration of Innovative Applications of Technology

 for the CT-121 FGD Process ..................................................................... 11

 Milliken Clean Coal Technology Demonstration Project ............................ 19

Conclusions ..................................................................................................... 23

Bibliography .................................................................................................... 24

Contacts ........................................................................................................... 26

List of Acronyms and Abbreviations ............................................................. 27

Advanced Technologies

for the Control of

Sulfur Dioxide Emissions

from Coal-Fired Boilers
Executive Summary

The Clean Coal Technology (CCT)

Program is a government and industry

cofunded 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 technologies, referred to as flue gas

desulfurization (FGD) processes, designed

to reduce sulfur dioxide (SO2) emissions

from coal-fired power plants. Emissions

of SO2, a precursor of acid rain, are regulated under the provisions of the 1990

Clean Air Act Amendments (CAAA).

This Topical Report discusses three completed CCT projects that successfully demonstrated SO2 emissions reductions via

innovative FGD processes. The goal of all

three projects was to achieve greater than

90% SO2 removal. This goal was achieved,

with SO2 removals as high as 98% being

demonstrated. High particulate removal

efficiencies were also achieved. In addition,

these processes demonstrated the capability of producing wallboard-quality gypsum,

a marketable by-product, thereby eliminating the need for FGD sludge disposal, a major problem for many conventional FGD

processes.

• Advanced Flue Gas Desulfurization

(AFGD) was demonstrated at Northern

Indiana Public Service Company’s Bailly

Station, near Gary, Indiana. The project

was conducted by Pure Air on the Lake,

L.P., a company formed by the process

developer, Pure Air, which is a partnership

between Air Products and Chemicals, Inc.

and Mitsubishi Heavy Industries America,

Inc. The scrubber was of unique design,

incorporating cocurrent flow of gas and

liquid. Coal sulfur content varied between

2.3% and 4.5%, typical of high-sulfur

bituminous coals. A total of 210,000 tons

of high-quality gypsum was produced

during the demonstration and sold to a

wallboard manufacturer.

• Innovative Applications for the

CT-121 FGD Process was demonstrated

at Georgia Power’s Plant Yates, Newnan,

Georgia, using a novel scrubber called

a jet bubbling reactor. This single process

vessel replaces the usual spray tower/

reaction tank/thickener arrangement.

The fiberglass-reinforced plastic used

as the construction material proved highly

corrosion resistant. Coal sulfur content

ranged from 1.2% to 4.3%. In addition

to SO2 removal, the system also was

highly efficient in removing hazardous

air pollutants from the flue gas.

• Milliken Clean Coal Technology

was demonstrated at New York State

Electric & Gas Corporation’s (NYSEG)

Milliken Station at Lansing, New York.

On May 14, 1999, NGE Generation, an

affiliate of NYSEG, completed the sale

of its coal-fired power plants in New York

State, including Milliken Station, to

The AES Corporation. The FGD technology demonstrated at Milliken uses

the Saarberg-Holter-Umwelttechnik

(S-H-U) process, which incorporates

a unique cocurrent/countercurrent flow

path plus formic acid for enhanced absorption of SO2. The Stebbins tile-lined, reinforced concrete absorber exhibited superior

corrosion and abrasion resistance. FGD

availability during the test period was

99.9%. Coal sulfur content averaged 3.2%.

The technologies described in this report

are capable of high levels of SO2 removal

and have proven to be very reliable. Through

the use of efficient, compact absorber equipment and the elimination of spare reactors,

these technologies offer costs significantly

lower than those of previous wet FGD

processes. As a result, higher standards for

FGD performance and economics have

been set. With increasingly stringent air

quality regulations, these innovative FGD

technologies should find numerous commercial applications.

Through these CCT demonstrations

and related projects, significant experience

has been gained by U.S. suppliers of FGD

systems and system components. This expertise includes operating techniques, equipment designs, and selection of materials

of construction. These CCT projects have

demonstrated advanced features, several

of which have been adopted by commercial FGD suppliers, thereby accruing substantial cost savings to U.S. electric utilities

and their customers. This has led to costeffective answers to design challenges for

equipment such as reaction vessels, pumps,

and a wide variety of other items.

1
Advanced Technologies

for the Control of

Sulfur Dioxide Emissions

from Coal-Fired Boilers

Background

History

The Clean Coal Technology (CCT)

Program, sponsored by the U.S. Department of Energy (DOE), is a government

and industry cofunded 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 full-scale

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.

Environmental Regulations

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-burning 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 (NOx)

emissions targets for coal-fired boilers

subject to CAAA compliance.

Control of SO2 Emissions

A major goal of the CCT Program is the

demonstration of technologies designed to

reduce emissions of sulfur dioxide (SO2)

from coal-fired utility boilers. Many U.S.

coals have a sufficiently high sulfur content to cause SO2 emissions to exceed air

quality regulations. For operators of boilers

2
Loading FGD by-product gypsum

burning such coals, three major compliance for transport to wallboard plant.

options are available:

• Switch fuels (low-sulfur coal or

natural gas)

• Purchase SO2 credits (allowances)

on the open market

• Employ flue gas desulfurization

(FGD) technologies.

Use of low-sulfur coals is quite common,

but may result in reduced boiler output,

since these fuels frequently have a lower

heat content. Natural gas is more expensive

than coal and may not be available at the site.

Since the price of SO2 allowances is rising,

FGD is becoming the choice for more and

more boiler owners.

Types of FGD Processes

FGD processes can be categorized as (a)

wet and (b) dry or semidry systems. In most

wet FGD systems, SO2 is removed from the

flue gas by reaction with a calcium-based sorbent in an aqueous solution or slurry. A relatively high degree of SO2 removal is usually

achieved, with a high level of sorbent utilization. In addition, wet FGD systems generally

achieve excellent particulate removal because

of intimate contact between the gas and liquid

phases.

Dry and semidry FGD systems involve injecting a solid sorbent (dry), usually limestone,

or a sorbent slurry (semidry), usually lime, into

the furnace or flue gas duct; the by-product

solids are collected in a dry form along with

the flyash from the boiler in the existing particulate removal equipment. Compared with

wet FGD systems, SO2 removal efficiency

and sorbent utilization are usually lower.

This report reviews the results of demonstrations of three innovative wet FGD processes conducted under the auspices of the

CCT Program.

3
Emissions Standards

The Clean Air Act was originally passed

in 1970. It was amended in 1977 and most

recently in 1990. The CAAA authorized EPA

to establish new standards for a number of

atmospheric pollutants, including SO2 and

NOx. Periodic review of the emissions

standards every five years is mandated.

SO2 Emissions Standards

Under Phase II of Title IV, the CAAA

impose significant reductions in SO2 emissions from existing boilers by 2000 and

place an annual cap on emissions beyond

2000. The Phase II allowable SO2 emissions rate is 1.2 lb/million Btu input, down

from 2.5 lb/million Btu in Phase I.

The CAAA provide for SO2 emissions

allowances (each allowance permits the

emission of 1 ton of SO2). As part of a

trading program, allowances can be bought

and sold on the open market. To date,

allowance prices have been relatively low,

with the result that many utilities have

opted to purchase allowances instead

of installing FGD systems. However, SO2

allowance prices have been increasing recently, thereby providing the potential for

development of a large-scale retrofit market for FGD technologies.

To meet forthcoming emissions regulations, especially when burning high-sulfur

coals, it is essential to achieve high levels

of SO2 removal, usually 90% or higher.

Even higher levels of SO2 removal can be

beneficial, since this is a way to generate

emissions allowance credits.

Clean Coal Technology

Wet FGD

Demonstration Projects

This report discusses three CCT

projects involving innovative wet FGD

technologies:

• Advanced Flue Gas Desulfurization

(AFGD) Demonstration Project

• Demonstration of Innovative Applications of Technology for the CT-121

FGD Process

• Milliken Clean Coal Technology

Demonstration Project

Each of the technologies demonstrated

uses limestone (CaCO3) as a sorbent and is

capable of producing wallboard-grade gypsum as a by-product. A major goal of these

projects was to demonstrate greater than

90% SO2 removal at a cost substantially

lower than that of conventional wet FGD

processes.

Sorbent recirculation

system at Bailly Station.

4
Advanced Flue Gas

Desulfurization (AFGD)

Demonstration Project

Project Description

This project was selected during

Round II of DOE’s CCT Program. In

December 1989, Pure Air on the Lake,

L.P. entered into an agreement to conduct

this demonstration project. Pure Air on

the Lake is a company formed to carry

out this project by Pure Air, a general

partnership between Air Products and

Chemicals, Inc. and Mitsubishi Heavy

Industries America, Inc.

The host site was the Bailly Generating

Station of Northern Indiana Public Service

Company (NIPSCO), located about 12 miles

northeast of Gary, Indiana. The site is immediately adjacent to the Indiana Dunes

National Lakeshore, along the southern edge

of Lake Michigan. The demonstration was

conducted between June 1992 and June

1995, treating the combined flue gases from

two boilers (Units No. 7 and 8) having

a total nameplate capacity of 616 MWe.

Total project cost was $152 million, of

which DOE provided $64 million, or 42%.

The project consisted of installing a

scrubber of unique design involving cocurrent flow of gas and liquid, an air rotary

sparger (ARS) located within the base of

the absorber, and a novel wastewater

evaporation system (WES). The project

also included a gypsum agglomeration

process known as PowerChip®, which

enhances the handling and transportability

characteristics of the by-product gypsum.

The result is a stable, densely agglomerated, semidry flake with handling properties equivalent to natural gypsum rock.

Adding PowerChip® technology expands the potential market for the gypsum

by-product. Gypsum made at the Bailly

Station is sold to United States Gypsum

Company for wallboard manufacture at its

East Chicago, Indiana, plant. The East Chicago plant is the first facility in North

America to produce wallboard from 100%

FGD gypsum.

Process Description

The AFGD process accomplishes SO2

removal in a single absorber which performs three functions: prequenching the

flue gas, absorption of SO2, and oxidation

of the resulting calcium sulfite to wallboard-grade gypsum.

Night view of Bailly Generation Station.

5
Description of the

Advanced Flue Gas Desulfurization (AFGD)

Demonstration Unit at Bailly Station

Hot

Flue

Gas

Stack

Wastewater

Evaporator Electrostatic

Precipitator

Mist

Eliminator

Water

Water

Air

Air Rotary

Sparger

Dry Limestone

Injection

Gypsum

Centrifuge

System

Slaked Lime

Polymer

Grid

Packing

Gypsum

To

Disposal

or Sales

Absorber

Recirculation

Disengagement

Zone

Slurry

Reservoir

Absorber

Wastewater

Incoming flue gas is cooled and humidified with process water sprays before passing to the absorber. In

the absorber, two tiers of fountain-like sprays distribute

reagent slurry over polymer grid packing that provides

a large surface area for gas/liquid contact. The gas then

enters a large gas/liquid disengagement zone above the

slurry reservoir in the bottom of the absorber and exits

through a horizontal mist eliminator.

After contacting the flue gas, slurry falls into the slurry

reservoir where any unreacted acids are neutralized by

limestone injected in dry powder form into the reservoir.

The primary reaction product, calcium sulfite, is oxidized

to gypsum by the air rotary spargers, which both mix

the slurry in the reservoir and inject air into it. Fixed air

spargers assist in completing the oxidation. Slurry from

the reservoir is circulated to the absorber grid.

A slurry stream is drawn from the tank, dewatered,

and washed to remove chlorides and produce wallboard quality gypsum. The resultant gypsum cake

contains less than 10% water and 20 ppm chlorides.

The clarified liquid is returned to the reservoir, with

a slipstream being withdrawn and sent to the wastewater evaporation system for injection into the hot flue

gas ahead of the electrostatic precipitator. Water evaporates and dissolved solids are collected along with the

flyash for disposal or sale.

6
SO2 removal performance at Bailly Station (76% of design liquid-to-gas flow ratio).

Important features of the AFGD project

technology are:

• The use of cocurrent flow to permit

high flue gas velocities (up to 20 feet

per second) and compact design

• A non-pressurized slurry distribution

system that requires approximately

30% less recirculation pump power

than conventional countercurrent

scrubbers

• Fountain-like flow that doesn’t generate a fine mist, thereby reducing mist

eliminator loading by as much as 95%

compared to countercurrent designs

• Use of a dry pulverized limestone direct injection system, eliminating the

need for ball mills, tanks, pumps, and

other equipment associated with onsite wet grinding systems

• Use of an ARS, combining agitation

and oxidation, that significantly enhances scrubber performance

• Incorporation of WES to control

chlorides without creating a new

waste stream

• Use of the PowerChip® system,

incorporating a compression mill

operating at an optimum compacting

pressure and cure time/temperature

relationship to change the physical

structure of the gypsum

Results

The AFGD unit successfully achieved

the target of removing more than 90% of

the SO2 from the flue gas. Five Midwestern bituminous coals, having sulfur contents between 2.25% and 4.5%, were

burned during this demonstration. SO2

removal efficiency averaged 94%, with

a maximum of over 98%. The facility

was operated for 26,300 hours during the

demonstration, with system availability

of 99.5%. High availability eliminates

the need for a spare absorber.

Variables studied in the test program

included the sulfur content of the coal,

the slurry recirculation rate, the ratio of

calcium injected to SO2 in the flue gas,

and the liquid-to-gas ratio in the absorber.

U.S. Gypsum has taken the entire byproduct gypsum output from the Bailly

AFGD unit. During the three-year demonstration, gypsum production exceeded

210,000 tons, with an average purity

of 97.2%.

Business Arrangement

An important innovation with the AFGD

project was a business arrangement whereby Pure Air owns and operates the FGD

system on behalf of NIPSCO, thus relieving the utility of day-to-day operating and

maintenance responsibilities.

100

95

90

85

1.01

SO

2 Removal Efficiency, %

80

Stoichiometric Ratio,

moles calcium/mole SO2 removed

1.04 1.07 1.10

Inlet SO2

1000 ppm

2500 ppm

3500 ppm

Coal Sulfur

Content, %

2.25

4.0

4.5

7
Emissions Standards

History

The Clean Air Act of 1970 established a major air regulatory role for

the federal government. The Act was

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).

SO2 Emissions Standards

SO2 is formed through the combustion of sulfur contained in coal. Burning typical medium- and high-sulfur

coals produces SO2 emissions that

exceed the allowable limits under the

CAAA. Two major portions of the

CAAA relevant to SO2 control are

Title I and Title IV. Title I establishes

National Ambient Air Quality Standards (NAAQS) for six criteria pollutants, including SO2. The 24-hour

average ambient air standard for

SO2 under Title I is 0.14 ppm.

Title IV addresses controls for specific types of stationary boilers, including those found in coal-fired power

plants. Title IV is often referred to as

the Acid Rain Program. The overall

goal of Title IV is to achieve environmental and public health benefits

through reductions in emissions of SO2

as well as reduced nitrogen oxides

(NOx) and particulates emissions.

Title IV uses a two-phase SO2 control strategy. Phase I began in 1995

and affects 263 units at 110 mostly

coal-burning electric utility plants

located in 21 Eastern and Midwestern

states. An additional 182 units joined

the program as substitution or compensating units, bringing the total of Phase

I affected units to 445.

Phase II, which begins January 1,

2000, tightens annual emissions limits

and also sets restrictions on smaller

plants fired by coal, oil, and gas.

The Title IV Phase I SO2 emissions

limit is 2.5 lb/million Btu of heat input

to the boiler. This decreases to 1.2 lb/

million Btu in Phase II.

Title IV allows sources to select their

own compliance strategies. To reduce

SO2 emissions an affected source may

repower, use cleaner burning fuel, reassign some of its energy production

from dirtier to cleaner units, or reduce

fuel consumption by improving efficiency. In general, no prior approval

is required, allowing sources to respond quickly to market conditions.

The SO2 Trading Allowance Program

The Acid Rain Program represents

a dramatic departure from traditional

regulatory methods that establish specific, inflexible, emissions limits with

which all affected sources must comply. Instead, the program introduces

an allowance trading system that harnesses the incentives of the free market to reduce pollution. Affected utility

units have been allocated allowances

based on their historic fuel consumption. Each allowance permits a unit

to emit one ton of SO2; for each

ton of SO2 emitted, one allowance

is retired.

Allowances may be bought, sold,

or banked. Anyone may acquire allowances and participate in the trading

system. However, regardless of the

number of allowances held, a source

may not emit pollutants at levels

that would violate federal or state

limits set under Title I of the CAAA

to protect public health.

In Phase II, the CAAA set a permanent ceiling (or cap) of 8.95 million annual allowances allocated

to utilities. This cap firmly restricts

SO2 emissions and ensures that

environmental benefits will be

achieved and maintained.

The allowance trading system

contains an inherent incentive for

utilities to reduce pollution, since

for each ton of SO2 that a utility

avoids emitting, one fewer allowance

must be retired. Utilities that reduce

emissions below their allowance

allocation are able to sell, transfer,

or bank their surplus allowances.

Title IV includes an optional program involving voluntary reduction

of SO2 emissions. This program

allows sources not regulated under

Title IV the opportunity to participate

on a voluntary basis, reducing their

emissions and, thereby, receiving

SO2 allowances.

EPA invited broad input into the

development of Title IV by consulting with representatives from various

stakeholder groups and is maintaining this open-door policy as it implements the program. The Acid Rain

Program is viewed as a prototype for

tackling emerging environmental issues. The allowance trading system

capitalizes on the power of the marketplace to reduce SO2 emissions

in the most cost effective manner.

8
Costs

Pure Air developed cost estimates for

commercial implementation of the AFGD

technology, covering a range of plant capacities and coal sulfur contents. For a 500-

MWe power plant firing a 3% sulfur coal

and operating at 90% SO2 emissions reduction, the capital cost is estimated at $94/kW.

For a 15-year project life, the levelized cost

on a current dollar basis is 6.5 mills/kWh,

which is equivalent to $302/ton of SO2

removed. These costs are about one-half

those of a conventional wet FGD process.

The advanced design features of the AFGD

technology result in a comparatively smaller scrubber, one that requires less plot area,

less material to construct, and has much

lower capital and operating costs than conventional scrubbers.

Awards

The Bailly AFGD project received a 1992

Outstanding Engineering Achievement Award

from the National Society of Professional

Engineers and Power magazine’s 1993

Powerplant Award.

Conclusions

This project shows that a single absorber

can provide flue gas desulfurization for a

power plant of at least 600-MWe capacity

and that no spare absorber is required. It also

shows that pulverized limestone can be successfully injected directly into an absorber.

Wastewater evaporation in the flue gas

duct eliminates the need for liquid waste disposal, and use of the gypsum by-product for

wallboard manufacture eliminates the need

to dispose of solid waste.

A unique own-and-operate business

arrangement successfully handles the

processing of flue gas, relieving the host

utility of these responsibilities. The Bailly

AFGD scrubber continues to operate

commercially under a long-term agreement between NIPSCO and Pure Air.

Limestone and lime silos for AFGD Demonstration

Project, adjacent to Indiana Dunes National Lakeshore.

9
The Indiana Dunes

Adjacent to the Pure Air project

site, only about 300 feet away, are

the Indiana Dunes National Lakeshore and the Indiana Dunes State

Park. The State Park was established in 1926, followed by establishment of the adjacent National

Lakeshore in 1996. Together, these

two parks span about 20 miles

along the southern shore of Lake

Michigan.

The Indiana Dunes consist of

large sand dunes at the lake’s

edge, behind which is an area

of dunes whose plant cover has

evolved to mature forests. With

1,445 native plant species present,

the area is a botanist’s dream with

variety exceeded in the United

States only by the Grand Canyon

and Great Smoky Mountains National Parks. Overlapping ranges

of plant species converge at the

dunes, where plants usually found

in warmer climates (orchids, cacti,

and carnivorous plants) grow

alongside species more typical

of Canadian forests and the tundra (Arctic bayberry, jack pine,

and northern rose).

This unusual diversity of plant

life serves to attract a wide variety

of wildlife to the area. For example,

nearly 350 species of birds have

been sighted in the dunes, ranging from waterfowl (geese, ducks,

and swans) to raptors (hawks,

falcons, and eagles). The National

Lakeshore staff even manages a

nearby heron rookery.

From 1895 to 1934, the Indiana Dunes served as the laboratory for Henry C. Cowles, a professor at the University of

Chicago who was eulogized as

being America’s first professional

ecologist. At the Indiana Dunes,

Dr. Cowles studied the effects

of geological formations on plant

communities and the transformation of habitat by those communities.

Amidst the kaleidoscope of

plant communities found at the

dunes, Cowles recognized some

patterns. As the habitat changed,

proceeding inland from beachfront to forested dunes, he observed a succession of plant

communities—ranging from

grasses that colonize the beachfront dunes to increasingly complex cottonwood, pine, oak, and

beech-maple forests. This principle of ecological succession is

important enough that when ten

European botanists were asked

what sites they wanted to see

on their trip to America in 1913,

they responded, “The Grand

Canyon, Yosemite, and the Indiana Dunes.” Scientific investigations are still performed at the

Indiana Dunes, largely under

the auspices of a staff of scientists at the National Lakeshore.

It is fitting that the AFGD

demonstration project is located

in the midst of this environmentally sensitive area. In addition

to such features as reduced SO2

emissions, production of commercial gypsum instead of sludge,

and wastewater evaporation, the

project includes extensive environmental monitoring.

10
Demonstration of

Innovative Applications

of Technology for the

CT-121 FGD Process

Project Description

In April 1990, Southern Company Services entered into an agreement with DOE

to conduct this project, which was selected

during Round II of DOE’s CCT Program.

The demonstration was hosted at Georgia

Power Company’s Plant Yates, Unit 1,

located at Newnan, Georgia. This unit is a

100-MWe (net) pulverized-coal fired boiler.

Total project cost was $43 million, of which

DOE provided $21 million, or 49%.

The project involved installation of the

Chiyoda CT-121 FGD process, that includes

a specially designed absorber known as a

Jet Bubbling Reactor® (JBR), made of

fiberglass-reinforced plastic (FRP). A primary objective was to demonstrate reliable, long-term operation of the JBR. Coal

sulfur content ranged from 1.2% to 4.3%.

Process Description

A major innovative feature of the CT-121

process is the use of a single absorber vessel — Chiyoda’s patented JBR — in place

of the spray tower/reaction tank/thickener

arrangement used in conventional FGD systems. The JBR combines SO2 absorption in

a limestone slurry, oxidation of sulfite to sulfate, and gypsum crystallization.

Much of the undesirable crystal attrition

and secondary nucleation associated with the

large centrifugal pumps used for slurry recirculation in conventional FGD systems is eliminated in the CT-121 design. The result is that

large, easily dewatered, gypsum crystals are

consistently produced. The CT-121 design also

significantly reduces the potential for gypsum scale growth, a problem that frequently

occurs in conventional FGD systems.

The gypsum storage area at Plant Yates

has three separate cells: a “clean” gypsum

stack area, a gypsum/flyash stack area, and

a recycle water pond. The stacks are used

to store and dewater the solids, with clear,

decanted process water being collected in

the common pond area and returned to the

process. Aerial view of Yates

Electric Station.

11
Overview

Most SO2 control technologies

involve the addition of a calciumbased sorbent to the system. Under

the proper conditions, this material

reacts with SO2 to form calcium sulfite (CaSO3), which is then oxidized

to calcium sulfate (CaSO4). Because of their low cost, limestone

and lime are the most frequently

used sorbents.

In the majority of applications,

the sorbent is dissolved in, or slurried with, water; flue gas contacts

the solution or slurry in a scrubber.

Alternatively, the sorbent is injected directly into the furnace or flue

gas duct.

Historical Note

The notion of scrubbing SO2 from

coal-derived flue gas dates back to

the 1920s and 30s, when the first

scrubbers were built in Great Britain. These facilities were shut down

during World War II so that the British power plants would not be detected by aircraft that could follow

the vapor plumes. Interestingly, even

these first scrubbers were capable

of removing 90% of the SO2. Scrubber technology continued to evolve

through the 1960s, with installations

in Europe, Japan, and the United

States. However, widespread application in the United States did not occur

until enactment of the Clean Air Act

of 1970.

In the United States, a number of

coal-fired power plants were equipped

with scrubbers during the 1970s and

early 1980s. These scrubbers were,

for the most part, installed at newly

constructed power plants, because

existing plants were exempt under

the law. When domestic power plant

construction decreased in the 1980s,

the market for scrubber technology

moved overseas, where improvements

were made. With the advent of acid

rain controls for older units under

the 1990 Clean Air Act Amendments

(CAAA), a new market for scrubber

technology began to emerge in the

United States. Technology developments continue to improve performance and reduce costs.

Dry and Semidry Sorbent Injection

A reactive calcium- or sodium-based

sorbent is injected into the economizer

or flue gas duct, where the particles

react with SO2 and are subsequently

removed along with flyash by the

boiler’s particulate control device. The

two most common calcium-based sorbents are limestone, CaCO3, and slaked lime, Ca(OH)2. Limestone, which

generally requires a higher reaction

temperature, is usually injected as a

dry powder. Lime, on the other hand,

is usually handled as a slurry that

dries as soon as it is injected into

the hot flue gas.

This is referred to as semidry

scrubbing, which dominates the sorbent injection market. All commercial semidry systems in the U.S.

use lime and recycled fly ash as

sorbent. These systems account for

8-10% of the installed FGD capacity

in the U.S.

Sulfuric Acid Production

Although less commonly used,

another approach is to oxidize the

SO2 to SO3 over a catalyst and absorb it in water to form sulfuric acid,

which can be sold for a variety of

uses, such as metals pickling.

Conventional Wet FGD

Technology

Conventional wet FGD systems

are typically designed for SO2 removal efficiencies of about 90%,

a level required to meet air quality

standards when burning high-sulfur

coals.

The processing scheme for most

wet FGD systems is essentially as

follows. Flue gas from the particulate

SO2 Emissions Control Technologies

12
collector flows to the SO2 absorber,

the energy necessary to overcome

the FGD system pressure drop

being provided by the boiler induced

draft (ID) fans. In the absorber, a

variety of technology specific devices achieve intimate contact of

the flue gas with the sorbent slurry.

Gas flow per unit cross sectional

area, which determines scrubber

diameter, must be low enough to

minimize entrainment. Mass transfer

characteristics of the system determine absorber height. Absorber vessels tend to be quite large in practice.

Following contact with the slurry,

the scrubbed flue gas passes through

mist eliminators, which remove entrained slurry droplets. Periodic washing using fresh water keeps the mist

eliminators clean and provides makeup water to the FGD system.

In the absorber, SO2 reacts with

limestone, forming calcium sulfite.

Limestone is supplied either as a

dry solid or a slurry. The sulfite is

subsequently oxidized in a separate

reaction tank to form calcium sulfate, which crystallizes as gypsum

(CaSO4 • 2H2O). The residence time

of solids in the reaction tank is generally in the range of 15 to 25 hours.

This extended residence time, coupled with proper reaction tank design

and operation, provides an environment conducive to gypsum crystal

growth.

In some processes, pumps recirculate slurry from the reaction tank to

the scrubber to provide the volume of

slurry necessary to maintain good gas/

slurry contact and ensure high SO2 removal efficiency. The slurry in the recycle tank is agitated to maintain the

solids in suspension and prevent solids buildup on the tank bottom.

A small slipstream of slurry is sent

to a primary dewatering system,

which recovers solids (gypsum and

flyash). The dewatering system is

designed to concentrate the gypsum

crystals to an ultimate solids content

of 85% to 90% (dewatered gypsum

has the consistency of wet sand). The

gypsum is conveyed to an on-site

waste disposal landfill or shipped to

a processing facility where the byproduct gypsum is utilized for wallboard or cement manufacture.

Recovered process water is returned to the absorption and reagent

preparation systems.

Over its life, a 500-MWe coal-fired

power plant with a conventional wet

scrubber produces enough sludge to

fill a 500-acre disposal pond 40 feet

deep. Early scrubbers were plagued

by poor reliability, often requiring the

installation of spare modules as

back-up to ensure continuous flue

gas cleanup.

Innovative Wet FGD Technology

The innovative scrubbers described in this report are a significant improvement over 1970s wet

scrubber technology, featuring

state-of-the-art designs and materials of construction. Highly efficient,

compact, and less expensive to

construct and operate, these scrubbers eliminate waste disposal problems by incorporating oxidation of

the calcium sulfite sludge to wallboard-grade gypsum. Because of

high process reliability, spare scrubber modules are not required.

Advanced features developed

in these CCT projects have been

widely adopted by scrubber vendors and, more importantly, the

U.S. electric utility industry. These

demonstration projects have resulted in increased competition,

pointing the scrubber market toward fewer but larger absorber

vessels, salable by-products, and

better equipment guarantees. The

resultant savings to U.S. electricity

customers amount to billions of

dollars in reduced costs for

CAAA compliance.

13
Description of the CT-121 Process Demonstration Unit at Plant Yates

Flue gas enters the scrubber inlet gas

cooling section downstream of the boiler’s

ID fan, which also serves as the scrubber’s

booster fan. In the gas cooling section,

the flue gas is cooled and saturated

using diluted Jet Bubbling ReactorTM

(JBR) slurry. From the gas cooling section, the flue gas enters an enclosed plenum chamber in the JBR, formed by the

upper and lower deck plates.

Sparger tubes mounted in the floor of

the inlet plenum conduct the flue gas below the level of the slurry reservoir in the

jet bubbling zone (froth zone) of the JBR.

After bubbling through the slurry, the gas

flows upward through large gas riser

tubes that bypass the inlet plenum.

The cleaned gas enters a second plenum above the upper deck plate, where,

because of a large decrease in velocity,

entrained liquor is disengaged. The cleaned gas passes to a two-stage, chevronstyle, horizontal-flow mist eliminator, then

on to a wet fiberglass-reinforced plastic

chimney.

A closed-circuit, wet ball mill limestone

preparation system is used to grind raw

(≤ 3/4") limestone to a particle size small

enough (90% through a 200-mesh screen)

to ensure rapid reaction and minimize the

amount of unreacted limestone in the JBR.

The JBR slurry reservoir provides about

36 hours of solid-phase residence time,

depending on the SO2 absorption rate.

For JBR slurry level and density control,

slurry from the JBR is pumped intermittently to a gypsum slurry transfer tank. It

is then diluted for pumping to a Hypalon®-

lined gypsum (or gypsum/ash) stacking

area for gravity dewatering and storage.

Gypsum stacking involves filling a

lined, diked area with slurry for gravity

sedimentation. Over time, this area fills

with settled solids. The filled area is then

partially excavated, with the excavated

material used to increase the height of

the containment dikes. The repetitive

cycle of sedimentation, excavation, and

raising of perimeter dikes continues on

a regular basis during the active life of

the stack. Process water is decanted,

stored in a surge pond and then returned

to the CT-121 process.

The amount of SO2 removed from the

flue gas is controlled by varying the slurry

pH or the depth of submergence of the

flue gas spargers in the JBR. Higher liquid levels result in increased SO2 removal

because of increased contact time between the flue gas and the slurry.

Water

Upper

Deck Plate

Riser

Clean

Gas to

Stack

Motor

Lower

Deck

Plate

Limestone

Slurry

Air Agitator

Sparger

Air

Reaction

Zone

Jet

Bubbling

Zone

Quench

Duct

Fan

Flue

Gas

Fly

Ash

Boiler Precipitator

Ash

Air

Coal

Sparger

Tube

Collection

Pond

Gypsum

Stack

Jet Bubbling

Reactor

Slurry

Reservoir

Disengagement

Zone

14
Schematic of Chiyoda’s Jet Bubbling

Reactor with gas sparger action.

Absorption Zone

Reaction Zone

Air

Gypsum

By-product

Slurry

Limestone

Slurry

Clean Gas

Flue

Gas

Gas

Sparger

Tube

Lower Deck Plate

Flue Gas

in

Gas

Out

Gas

Out

Initial

Liquid Level

Submergence

Depth

Gas

Sparger

Tube

Jet

Bubbling

Zone

Limestone

and Gypsum

Particles

Detail of gas sparger tube.

15
Results

When high-sulfur coal was burned

at maximum boiler load at Plant Yates,

the CT-121 scrubber exceeded the target

90% SO2 removal efficiency and demonstrated excellent availability. Limestone utilization was greater than 97%.

Maximum SO2 removal was about 98%

when burning 2.2% sulfur coal, and

about 95% with 3.5% sulfur coal. Since

removal efficiency is controlled by adjusting the depth of submergence of the

flue gas spargers, it is relatively simple

to compensate for the higher sulfur content, thereby maintaining SO2 removal

efficiency.

Materials of Construction

As indicated previously, one of the

novel aspects of the CT-121 design is

the use of fiberglass-reinforced plastic

to avoid the corrosion damage associated with traditional closed-loop FGD

systems. Both the JBR and the inlet

transition duct, where flue gas is cooled

prior to contacting the sparger tubes,

are made completely of FRP. A distinct

advantage of this construction is that it

eliminates the need for a flue gas prescrubber, traditionally included in FGD

systems to remove chlorides that cause

serious corrosion in alloys.

Exposed surfaces at Plant Yates

were coated with homogeneous filler

materials (Duromar® and Duromix®)

to protect against erosion. The use of

FRP was very successful; this material

proved to be durable both structurally

and chemically. The chimney resisted

corrosion from condensates in the wet

flue gas, thereby precluding the need

for flue gas reheat. The high reliability

verified that a spare absorber is not

necessary.

SO2 Formation and Removal

Combustion

All coals contain sulfur. Some of this sulfur, known as organic sulfur, is intimately associated with the coal matrix. The rest of the sulfur, in the form of

pyrites or sulfates, is associated with the mineral matter. High-sulfur bituminous coals contain up to about 4% sulfur, whereas low-sulfur Western coals

may have a sulfur content below 1%.

Upon combustion, most of the sulfur is converted to SO2, with a small

amount being further oxidized to sulfur trioxide (SO3).

S(Coal) + O2 ----> SO2

SO2 + 1/2 O2 ----> SO3

Because, in the absence of a catalyst, the formation of SO3 is slow, over

98% of the combusted sulfur is in the form of SO2.

Effective January 1, 2000, the SO2 emissions limit for coal-fired power

plants is 1.2 lb/million Btu. To comply with this regulation without FGD, the

maximum sulfur content for a coal having a higher heating value of 12,000

Btu/lb is 0.72% by weight, assuming 100% conversion of sulfur to SO2.

Wet FGD

The major reactions occurring in wet FGD processes are shown by the following equations:

Absorption

SO2 + H2O ----> H2SO3

SO3 + H2O ----> H2SO4

Neutralization

CaCO3 + H2SO3 ----> CaSO3 + CO2 + H2O

CaCO3 + H2SO4 ----> CaSO4 + CO2 + H2O

Oxidation

CaSO3 + 1/2 O2 ----> CaSO4

Crystallization

CaSO4 + 2H2O ----> CaSO4 • 2H2O

16
SO2 removal performance at Plant Yates.

Particulate Removal

In 1993, the Yates CT-121 Project was

chosen by DOE as one of eight coal-fired

sites for a study of hazardous air pollutants

(HAPs) conducted on EPA’s behalf. The

project investigated the fate of HAPs at a

number of plants that utilize a variety of

air pollution control technologies.

At all tested conditions, the JBR exhibited excellent particulate removal efficiency,

ranging from 97.7% to 99.3%. The JBR

also removed from 40% to 95% of HAPs.

Since much of the HAPs of interest are

associated with the particulate phase, removal of particulates effectively removes

the HAPs. Additional testing in 1994 confirmed that the Chiyoda CT-121 JBR is

highly efficient at HAPs removal.

Gypsum Quality

The gypsum was of wallboard quality

except for high chloride content, which

would require washing for removal.

In 1996, Georgia Power received a Plant

Food Permit from the State of Georgia that

allows the unrestricted sale of ash-free

gypsum from the Yates project for agricultural purposes. This market exceeds 1 million tons/yr in Georgia alone.

Costs

Projected capital costs for commercial

implementation of the CT-121 process are

in the range of $80-$95/kW. Levelized cost

estimates are not available.

Awards

The Yates CT-121 project received Power

magazine’s 1994 Powerplant Award, the

Society of Plastic Industries’ 1995 Design

Award, and environmental awards from

the Air & Waste Management Association

and the Georgia Chamber of Commerce.

Hazardous Air Pollutants

Hazardous air pollutants (HAPs), also referred to as toxic air pollutants

or air toxics, are generally defined as atmospheric pollutants that are known

or suspected to cause serious health problems. HAPs are emitted by motor

vehicles and a variety of industrial sources and may exist as particulate matter or as gases. HAPs include metals and other particulates, gases adsorbed

on particulates, and certain vapors, such as benzene, from fuels and other

sources.

For coal-fired power plants, the HAPs of most concern are metals such

as arsenic, cadmium, mercury, selenium, and vanadium, present in trace

quantities in the mineral matter in coal. There is also concern over certain

other elements such as fluorine.

DOE conducted on EPA’s behalf a study to investigate the fate of HAPs

at a number of coal-fired plants utilizing a variety of air pollution control technologies. The objective was to see how effective these technologies are for

removing HAPs from flue gas. The CCT Program has made a significant

contribution to this study through the participation of a number of its projects.

100

90

80

70

6 8 10 12 14 16 18 20

Inlet SO2

1000 ppm

2500 ppm

3500 ppm

JBR Pressure Drop,

inches of water

Inlet SO2

1000 ppm

2500 ppm

3500 ppm

SO

2 Removal Efficiency, %

17
Gypsum stack impoundment at CT-121 Demonstration Unit.

Conveying by-product gypsum.

Benefits of U.S.

Experience in

SO2 Removal

The United States has the largest

number of FGD installations in the

world, with over 260 units installed

on coal-fired power plants having a

total capacity of over 85,000 MWe.

As a consequence of the extensive

work on CCT demonstrations and

other projects, vast experience has

been gained by U.S. suppliers of

FGD systems and system components, including expertise in operating techniques, equipment design,

and construction materials. Examples

include the use of Warman pumps,

made in Milwaukee, Wisconsin, for

circulating the slurry in the AFGD

Demonstration Unit, and the use of

Stebbins tile, made in Watertown,

New York, as a corrosion resistant

liner in the S-H-U absorber at

Milliken Station.

Taken together, these projects

have demonstrated advanced features, several of which have been

adopted by FGD suppliers, thereby

accruing substantial cost savings

to U.S. electric utilities and their

customers. This has led to costeffective answers to design challenges for equipment such as reaction vessels, pumps, and a wide

variety of other items.

When the CAAA were promulgated, many operators of high-sulfur

coal mines expressed concern that

their markets would be significantly

reduced. Development of innovative, economic FGD technologies

has provided new opportunities

for continued use of high-sulfur

Eastern coal.

Limestone unloading conveyor, slurry tank,

and hopper at CT-121 Demonstration Unit.

18
Milliken Clean Coal

Technology

Demonstration Project

This project was selected during Round

IV of DOE’s CCT Program. In October

1992, the New York State Electric & Gas

Corporation (NYSEG) entered into an agreement with DOE to conduct this demonstration. The project was hosted at NYSEG’s

Milliken Station, Units 1 and 2, located at

Lansing, New York. The plant is in an environmentally sensitive area on the shores

of one of the famous Finger Lakes. Units 1

and 2 are 150-MWe (net) pulverized-coal

fired units built in the 1950s by Combustion Engineering. Total cost of the CCT

project was $159 million, of which DOE

provided $45 million, or 28%.

The project involved installing a combination of technologies to control both SO2

and NOx emissions, including a wet limestone scrubber, low-NOx burners, and a

heat-pipe combustion air preheater.

Because low-NOx burners are, to a great

extent, developed technologies and are

covered in other Topical Reports, this report is limited to discussion of the innovative SO2 removal technology tested at

Milliken, namely the Saarberg-HolterUmwelttechnik (S-H-U) FGD process.

The project goals were to demonstrate SO2

emissions reduction of greater than 90%,

improved boiler efficiency, minimum solid

waste production through by-product utilization, and zero wastewater discharge.

The S-H-U process was installed on

both Units 1 and 2 at Milliken. A single

two-compartment absorber was used, providing separate absorber sections for each

unit within a single vessel. The Milliken

FGD system has been in operation since

1995. Performance testing was concluded

in 1998.

View of Milliken Station on

the shores of Cayuga Lake.

Process Description

In the S-H-U process, flue gas is

scrubbed with a limestone slurry in a

space-saving cocurrent/countercurrent

absorber vessel. The process is designed specifically to take advantage of the

benefits of organic acid enhanced absorption by utilizing a low concentration of formic acid additive in the

scrubbing liquid.

Formic acid acts as a buffer in the

absorber. Formic acid addition improves both the rate of limestone dissolution and the solubility of calcium in

the scrubbing liquid, thereby enhancing

SO2 absorption efficiency, reducing

limestone consumption, improving energy efficiency, improving by-product

gypsum quality, and reducing wastewater production.

19
Description of the FGD Demonstration Unit at Milliken Station

Flue gas from the boiler ID fans is

ducted to the top of the absorber and

flows cocurrently downward with scrubbing liquid sprayed into the flue gas

through an array of spray nozzles. The

sprayed liquid is collected in a reservoir at the bottom of the absorber,

while the partially scrubbed flue gas

makes a 180-degree turn and flows

upward through the countercurrent

stage of the absorber. Here, additional

scrubbing liquid is sprayed into the

flue gas to complete SO2 absorption.

Mist eliminators are mounted in the

roof of the vessel to remove entrained

liquid droplets before the flue gas is

discharged to the stack.

Spent scrubbing liquid from both

absorption stages collects in a common reservoir in the base of the absorber. Air blown into this reservoir

oxidizes calcium sulfite to gypsum.

Oxidation is enhanced by agitation

of the liquid, which also prevents

gypsum particles from settling to the

bottom of the reservoir. Reagent

limestone is added to the reservoir

along with makeup formic acid as required to maintain stable operation.

A slurry slipstream is pumped

from the reservoir to the gypsum

dewatering system, where solid

gypsum particles are recovered

before the liquid is returned to the

scrubbing vessel. A small liquid

bleed stream is removed from the

gypsum dewatering system to

control the chloride concentration

in the slurry.

Flue

Gas Mist

Eliminators

Formic Acid

Air

Limestone

Addition

Makeup Water

To Primary

Dewatering Filtrate

Return

20
Limestone ball mill at Milliken Station.

Hydrocyclone in gypsum dewatering system at Milliken Station.

Operation at low pH provides the

benefit of producing soluble calcium

bisulfite as a reaction product, rather

than the less soluble calcium sulfite.

This greatly increases the ease of

oxidation to gypsum and essentially eliminates the potential for

sulfite scaling within the absorber,

thus reducing maintenance costs.

The by-product gypsum is

trucked to a wallboard manufacturer located in Mississauga, Ontario.

Results

Operating variables studied include formic acid concentration,

coal sulfur content, limestone grind

size, and flue gas velocity within the

absorber vessel. In addition, FGD

efficiency was examined as the

number and location of operating

spray headers were varied. SO2

removal efficiency as high as 98%

was demonstrated, exceeding the

target value of 90%. A high degree

of reliability was achieved.

By-product gypsum storage prior

to wallboard manufacture.

21
Performance testing has demonstrated

the beneficial effect of formic acid enhanced operation. In one series of tests,

SO2 removal efficiency increased from

83% without formic acid to 95% with formic acid. At the same removal efficiency,

using formic acid results in a 75% reduction in energy required for circulating the

sorbent slurry.

Materials of Construction

Special consideration was given to the

materials of construction of the absorber

to minimize erosion and corrosion, which

have caused problems with some conventional FGD systems. The absorber shell is

constructed of reinforced concrete with an

integral, cast-in-place liner made of Stebbins

ceramic tile. This tile has superior abrasion

and corrosion resistance compared to rubber and alloy linings and is expected to last

for the life of the plant.

Costs

Projected economics for commercial

implementation of the S-H-U process have

been prepared by NYSEG. For a 300-MWe

power plant burning 3.2% sulfur coal, the

total capital requirement for an S-H-U

retrofit with 95% SO2 removal is $300/

kW. Assuming a 15-year project life, the

levelized cost on a current dollar basis is

12.0 mills/kWh, which is equivalent to

$534/ton of SO2 removed.

Aerial view of Milliken Station.

22
Loading finished wallboard for

use in construction industry.

Conclusions

The demonstration phase for the projects

described in this report has been completed.

The AFGD, CT-121, and S-H-U facilities

continue to operate on a commercial basis,

attesting to the success of these demonstration projects and the technical and economic

viability of the technologies.

During the demonstrations, all of the

projects exceeded their goals with respect

to SO2 removal efficiency and proved to

be easily maintained and economical to

operate. As a result of these efforts, the

utility industry has several new technology

choices to enable continued use of coal,

our most abundant fuel, in an economical

and environmentally sound manner. In addition, because of high levels of particulate

removal, these technologies are very effective at removing HAPs.

The FGD processes demonstrated in

these CCT projects feature compact scrubbers which operate at high levels of reliability, thereby eliminating the need for

spare reactors. All three technologies offer high SO2 removal efficiency at costs

significantly lower than conventional wet

FGD. As a result of these projects, improved standards for FGD performance

and economics have been set.

Another important benefit of the innovative FGD systems demonstrated in the

CCT Program is the production of wallboard-quality gypsum, thus eliminating

the sludge disposal problem common to

conventional wet FGD processes. According to recent trade announcements,

several facilities for manufacture of wallboard from FGD gypsum waste are

planned or under construction. Because

of its uniform high quality, synthetic

gypsum, produced as an FGD by-product,

has become the preferred feedstock for

wallboard manufacture.

With implementation of increasingly

stringent air quality regulations, there

should be a significant market, both in the

United States and abroad, for innovative

wet FGD processes such as those presented in this report. In the past, many

utilities have chosen other options, including fuel switching and purchasing SO2 allowances, but these new wet FGD

technologies that offer lower costs, high

reliability, and low maintenance should

result in many more power producers

opting for FGD.

23
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Pure Air/AFGD

Comprehensive Report to Congress, Clean

Coal Technology Program, “Advanced

Flue Gas Desulfurization (AFGD) Demonstration Project,” proposed by Pure Air,

U.S. DOE, November 1989.

R.J. Keeth, P.J. Ireland, and P.T. Radcliffe,

“Economic Evaluation of 28 FGD Processes,” 1991 EPRI/EPA/DOE SO2 Control Symposium (Washington DC),

December 1991.

B. Wrobel and D.C. Vymazal, “Acid Rain

Compliance -- Advanced Co-Current Wet

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GA), September 1993.

J. Henderson, D.C. Vymazal, D.A. Stryf,

and T.A. Sarkus, “Two Years of Outstanding AFGD Performance -- Pure Air on the

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G.B. Manavizadeh, J.J. Lewnard, D.A.

Stryf, and T.A. Sarkus, “Bailly Station

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Final Report, “Volume 2, Project Performance and Economics,” Pure Air, April

1996.

Chiyoda CT-121

Comprehensive Report to Congress, Clean

Coal Technology Program, “Demonstration of Innovative Applications of Technology for the CT-121 FGD Process,”

proposed by Southern Company Services,

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Ritz, “Demonstration of Innovative Applications of Technology for the CT-121

FGD Process,” First Annual Clean Coal

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24
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 has met its

objective of broadening the range

of technological solutions available

to eliminate acid rain concerns

associated with coal use.

Moreover, the CCT Program

has evolved and been expanded

to address the need for new, highefficiency 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

CCT 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% of the total.

The projects’ industrial participants

(i.e., the non-DOE participants) are

providing the remainder — nearly

$4 billion.

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.

Yates CT-121 scrubber

in the early stages of fabrication.

25
This report is available on the Internet

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

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, 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

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) 386-5890

(412) 386-6195 fax

mills@fetc.doe.gov

Contacts for CCT Project

and U.S. DOE CCT Program

Southern Company Services, Inc.

Contact

David P. Burford

Project Manager

Southern Company Services, Inc.

P.O. Box 2625

Birmingham AL 35202-2625

(205) 992-6329

(205) 992-7535 fax

dpburfor@southernco.com

Pure Air on the Lake, L.P.

Contact

Tim Roth

Asset Manager

Pure Air on the Lake, L.P.

7201 Hamilton Blvd.

Allentown PA 18195-1501

(610) 481-6257

(610) 481-5444 fax

rothtj@apci.com

New York State Electric & Gas

Corporation

Contact

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

U.S. Department of Energy

Contacts

David J. Beecy

Director, Office of Environmental

 Systems Technology

FE 23, GTN, Room D-212

Germantown MD 20874-1290

(301) 903-2787

(301) 903-8350 fax

david.beecy@hq.doe.gov

James U. Watts

Project Manager

Federal Energy Technology Center

P.O. Box 10940

Pittsburgh PA 15236-0940

(412) 386-5991

(412) 386-4775 fax

watts@fetc.doe.gov

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List of Acronyms and Abbreviations

AFGD ........................................................................ Advanced Flue Gas Desulfurization

ARS ........................................................................................................ Air rotary sparger

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

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

CaCO3 ........................................................................................................... Calcium carbonate (limestone)

CaO ....................................................................................................Calcium oxide (lime)

Ca(OH)2 ...................................................................................................Calcium hydroxide (slaked lime)

CaSO3 .............................................................................................................................................Calcium sulfite

CaSO4 ............................................................................................................................................Calcium sulfate

CaSO4•2H2O .......................................................................................................... gypsum

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

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

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

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

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

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

FGD .............................................................................................. Flue gas desulfurization

FRP ........................................................................................ Fiberglass-reinforced plastic

HAPs ............................................................................................ Hazardous air pollutants

ID ....................................................................................................................Induced draft

JBR ................................................................................................. Jet Bubbling Reactor®

H2SO4 .................................................................................................................................................. Sulfuric acid

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

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

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

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

NIPSCO .......................................................... Northern Indiana Public Service Company

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

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

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

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

S-H-U .............................................................................. Saarberg-Holter-Umwelttechnik

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

SO3 .................................................................................................................................................... Sulfur trioxide

SR ........................................................................................................ Stoichiometric ratio

WES.................................................................................. Wastewater evaporation system

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