TOPICAL REPORT NUMBER 4

SO2 Removal

Using Gas Suspension

Absorption Technology

A report on a project conducted jointly under a

cooperative agreement between:

The U.S. Department of Energy and AirPol Inc.

APRIL 1995
SO2 Removal

Using Gas Suspension

Absorption Technology

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

Definition of Technology ................................................................................2

Process Benefits ..............................................................................................3

The Demonstration Project at TVA’s Center

for Emissions Research ...................................................................................8

System Description ........................................................................................10

Demonstration Program .................................................................................13

Economic Evaluation .....................................................................................17

Operating and Maintenance Experience ........................................................18

Commercialization .........................................................................................18

Conclusions ....................................................................................................20

Bibliography ...................................................................................................21

To Receive Additional Information ...............................................................22

List of Acronyms and Abbreviations .............................................................23

Cover image: An illustration

of the GSA nozzle injecting

lime slurry into boiler flue gas

at the inlet to the reactor.

T E C H N O L O G Y
Introduction and

Executive Summary

The Clean Coal Technology (CCT)

Demonstration Program is a government

and industry co-funded technology development effort designed to demonstrate a new

generation of innovative coal utilization

processes in a series of full-scale, "showcase" facilities built across the country.

These demonstrations are on a scale sufficiently large to generate data for design,

construction, operation, technical/economic

evaluation, and future commercialization of

each process.

The goal of the program is to furnish the

U.S. energy marketplace with a number of

advanced, more efficient, and environmentally responsive coal-utilizing technologies.

These technologies will reduce and/or

eliminate the economic and environmental

impediments that limit the full utilization

of coal as a continuing viable future

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 considerations.

In response to the third of these solicitations, AirPol Inc., with the assistance of the

Tennessee Valley Authority (TVA), has

demonstrated the Gas Suspension Absorption (GSA) technology in a CCT project

titled "10 MW Demonstration of Gas Suspension Absorption." AirPol performed this

demonstration under a Cooperative Agreement awarded by DOE in October 1990.

The host site for this project was the

Center for Emissions Research (CER),

located at TVA’s Shawnee Fossil Power

Plant near Paducah, Kentucky. Over the

past 25 years, the CER has served as a test

ground for several different flue gas desulfurization (FGD) technologies. Before

the GSA demonstration program, two other

semi-dry processes, one of which was a 10

MWe spray dryer/electrostatic precipitator

(ESP), were tested at the facility. The GSA

system was retrofitted upstream of the

existing ESP and the test period began in

November 1992.

The GSA process was initially developed

as a calciner for limestone in cement production. It has been used successfully to clean

gases from commercial waste-to-energy

plants in Denmark, primarily to capture

chloride emissions. For FGD applications,

the GSA system removes sulfur dioxide

(SO2) by bringing coal combustion gases

into contact with a suspended mixture of

solids, including lime. After the lime reacts

with the SO2, most of the solids are separated from the flue gas in a cyclone and

recycled for additional SO2 absorption. The

flue gas, cleaned of the acid gas components, is sent through a dust collector for

particulate removal before being released

into the atmosphere.

The key to the system’s superior performance is the recirculation of solids back

to the reactor. Typically, a solid particle

will be recirculated about 100 times before

being discharged. Another advantage of the

GSA system is that it requires only a single,

simple, dual-fluid nozzle to inject fresh lime

slurry into the reactor.

The major objectives of the demonstration were successfully achieved:

• The GSA system removes greater

than 90 percent of the SO2 with a

low level of lime consumption.

• The GSA process operates with a

high degree of reliability.

• The capital cost for a GSA system is

about 30 percent less than that for a

comparable wet limestone FGD

system.

• The GSA process removes substantially all of the trace metals from the

flue gas.

The GSA FGD system is a promising

technology that will aid U.S. utilities and

other industries in achieving an effective,

economic, and space-efficient solution to

the SO2 emissions problem. The state of

Ohio, in conjunction with the Ohio Coal

Development Office, has awarded the city

of Hamilton a grant to install GSA technology in the city's municipal power plant.

This will allow the city to meet environmental regulations while using high-sulfur

Ohio coal for power generation.

Present commercialization activities for

GSA include installations at 1) an iron ore

sintering plant in Sweden having a flue gas

flow rate equivalent to that of a 135 MWe

power plant boiler, and 2) a cogeneration

project in Asia. For both of these applications, the success of the CCT demonstration

program at TVA was a major factor in the

decision to employ GSA technology.

I
Project Team Members

AirPol Inc.

Tennessee Valley Authority

U.S. Department of Energy

Contacts

Frank E. Hsu

Vice President of Operations

AirPol Inc.

32 Henry Street

Teterboro, NJ 07608

(201) 288-7070

Thomas A. Burnett

Project Specialist

Tennessee Valley Authority

1101 Market Street

Chattanooga, TN 37402

(615) 751-3938

C. Lowell Miller

Associate Deputy Assistant Secretary

 for Clean Coal Technology

U.S. Department of Energy

Washington, DC 20585

 (301) 903-9451

Sharon K. Marchant

DOE Project Manager

U.S. Department of Energy

Pittsburgh Energy Technology

Center

P.O. Box 10940

Pittsburgh, PA 15236

(412) 892-6008

SO2 Removal

Using Gas Suspension

Absorption Technology

Definition of

Technology

Combustion of coal results in the generation of flue gas containing sulfur dioxide

(SO2). Many U.S. coals have a sufficiently

high sulfur content to cause SO2 emissions

to exceed environmental standards. Thus,

some form of flue gas desulfurization

(FGD) is generally required. These FGD

processes are usually categorized as wet or

dry systems. In wet FGD systems, flue gas

is contacted with sufficient solution or

slurry consisting of a sorbent in an aqueous

medium, such that the flue gas is cooled to

the adiabatic saturation temperature. The

sorbent and the byproduct in the process are

in slurry form, with the byproduct slurry

subsequently being dewatered for disposal.

Dry FGD systems usually involve injecting

a solid sorbent into the furnace or flue gas

duct, and the byproduct solids are collected

in a dry form along with the fly ash from the

boiler.

Several wet FGD systems have been

developed and are in commercial use, including a variety of scrubbing processes

involving lime or limestone slurries. Sulfur

dioxide removal efficiency is high, generally 90 percent or greater. Dry FGD

systems include a number of spray drying

or sorbent injection processes using lime,

limestone, or sodium-based sorbents. The

dry FGD, systems based on lime also can

achieve high SO2 removals. However,

some of these dry FGD systems that use

limestone exhibit lower SO2 removal

efficiencies, about 50 percent, because of

the lower reactivity of the limestone and the

short contact time between the flue gas and

the sorbent.

Gas Suspension Absorption (GSA) is an

innovative semi-dry FGD technology based

on lime sorbent. Flue gas is contacted with

an atomized slurry containing fresh lime,

resulting in absorption of the SO2. Major

products of this reaction are calcium sulfite

and calcium sulfate.

A key feature of the GSA process is the

recirculation of large amounts of dry solids,

2
The GSA system.

which are coated with lime slurry in the

reactor and act as the reaction medium.

The resulting heat and mass transfer characteristics of the system are superior to

those in conventional semi-dry technology

where lime slurry is sprayed directly into

a duct or spray dryer.

A more detailed process description is

given subsequently in the section titled

System Description.

Process Benefits

SO

2 Removal

As discussed above, GSA is a semi-dry

FGD process in which the flue gas is contacted with a lime slurry. Essentially all of

the water evaporates in the process, leaving

a "dry" solid byproduct. The SO

2 removal

efficiency of the GSA process is 90 percent or greater, roughly equivalent to that

achieved by wet scrubbing. Two main

factors account for the superior performance of GSA:

3
The Clean Coal GSA Demonstration Site at Paducah, Kentucky.

The GSA Reaction Chemistry

Ca(OH)2 + SO2 -- CaSO3 • 1⁄2 H2O + 1⁄2 H2O

CaSO3 + 1⁄2 O2 CaSO4

1. The GSA process operates successfully

very close to the flue gas adiabatic

saturation temperature due to excellent

heat transfer characteristics. The injected

slurry dries very quickly, allowing short

retention time for the flue gas and

generating a dry byproduct.

2.

4

The GSA process takes advantage of

the large surface area of recycle particles on which the absorption of SO2

can take place. The lime slurry coats the

turbulent bed of dry solids, providing

enhanced mass transfer between the

lime slurry and the SO2 laden flue gas.

Operation Near Saturation

Temperature

Sulfur dioxide absorption and lime utilization efficiencies increase as the flue gas

temperature comes closer to its adiabatic

saturation temperature. A key variable is the

approach-to-saturation temperature (AST),

which is the difference between the temperature of the flue gas leaving the reactor

and its adiabatic saturation temperature. A

conventional spray dryer system cannot

normally operate at an AST below 10 to

11° C (18 to 20° F) without solids build-up

problems caused by high moisture levels in

the solids.

However, because of the enhanced heat

and mass transfer in the GSA reactor, the

lime slurry injected into the GSA system

dries completely, as evidenced by the fact

that the byproduct solids have less than 1

percent moisture, even when operating at

an AST as low as 4° C (8° F). Several tests

have demonstrated that the GSA system can

operate successfully at these low ASTs

when the chloride level in the system is low.

Thus, for a low-chloride coal application,

the GSA system can attain higher SO2

absorption efficiencies than a conventional

spray dryer system at the same lime

consumption.

Lime Consumption

The lime reagent ratio is expressed in

terms of moles of calcium per mole of SO2

in the flue gas entering the system. This

figure is also referred to as the calcium/

sulfur molar ratio. Since the GSA system

can operate at low ASTs, it can achieve

high SO2 removal efficiencies with a low

level of lime consumption.

Byproduct Generation

The byproduct generated in the GSA

system consists mainly of calcium sulfite

and calcium sulfate, in addition to fly ash

from the boiler. The moisture content is

surprisingly low, less than 1 percent. This
low moisture content explains why there is

little dust build-up on the system walls.

Conventional spray dryer systems avoid

this potential problem by operating at

higher ASTs, but as a consequence, the

SO

2 removal efficiencies are not as high as

those achieved by the GSA process.

Analysis of the solids from the GSA system supports the theory that the dry recycle

solids are coated with a thin layer of fresh

lime slurry on each pass through the reactor.

Cross-sectional photomicrographs of large

particles removed from the recycle stream

show a central core surrounded by a series

of rings similar to tree rings. Spectral

analysis of these layers determined that the

central core of this particle is fly ash,

while surrounding rings are composed of

calcium-sulfur compounds.

The amount of byproduct generated depends on the amount of acid gases entering

the system, the capture efficiency of these

acid gases, and the amount of lime used.

The byproduct can be disposed of in the

same manner as the boiler fly ash. However,

converting the byproduct to a marketable

material is being considered. One possibility

is to convert it to pozzolanic cement, which

is a ready-mix product that can be used for

non-structural concrete applications, such as

sub-base for roadways.

This cement can be made from a mixture

of GSA byproduct, fly ash, water, and a

small amount of quicklime (pebble lime).

Properties of concrete made from pozzolanic cement are quite similar to those of

concrete made from Portland cement. The

pozzolanic cement has extremely low leachability. If landfilled, it would thus form its

own liner and prevent any leaching into the

ground. AirPol is studying possible uses of

the pozzolanic cement.

Cross-section of a large particle removed

from the GSA recycle stream.

Magnification x1000.

Power Consumption

The major power consumption in the

GSA system occurs in the induced draft fan

and in the compressor for atomization of

the lime slurry. The more significant of

these is the fan, which is required to overcome the pressure drop in the GSA system.

Although the flue gas pressure drop across

the GSA system is somewhat higher than in

a conventional spray dryer system, the total

power consumption is lower because the

power for atomization is much less than that

for either rotary atomizers or atomizing

nozzles used in spray dryer systems.

Solids Build-Up

GSA systems in commercial operation

were previously installed at municipal solid

waste (MSW) incinerators, primarily to

remove hydrogen chloride (HCI) from the

flue gases. The first MSW application started

operating in 1988. None of these GSA installations has experienced difficulties with

dust build-up. The approach temperature is

higher in MSW applications than in FGD

applications of GSA, but the chloride content is also much higher. The MSW byproduct has a very low moisture content,

5
The GSA nozzle—at left is

an engineering design of

the nozzle and at right is

an exploded view of the

actual nozzle.

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, 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

The Clean Coal Technology Program

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 45 projects located in 21

states with a capital investment

value of nearly $7 billion. DOE’S

share of the total project costs is

about $2.37 billion, or approximately

34 percent of the total. The projects’

industrial participants (i.e., the nonDOE participants) are providing the

remainder-nearly $4.60 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.

6
despite the high concentrations of chlorides.

It should be noted that incinerator applications are much more susceptible to scaling,

corrosion, and dust build-up than coal-fired

boilers due to the presence of chlorides.

This is the reason for the higher approach

temperatures for MSW applications.

Maintenance

Experience shows that the GSA system

has very low maintenance requirements.

This is due to the simple design with no

moving parts in contact with the flue gases.

The lime slurry spray nozzle is the only

part that is exposed to wear. The spray

nozzle assembly is routinely alternated

with a spare unit once per week, a procedure that takes less than 5 minutes and

is done while the GSA system is in full

operation. The orifice washer (a low-cost

item) is replaced and the assembly is

cleaned and made ready for the following

week’s replacement.

All components are constructed of

carbon steel, which has proven to be

corrosion-free in the GSA system.

Of the commercial installations, none

has a dedicated maintenance crew for the

GSA system. Most of them have no dedicated operator, with the incinerator personnel also operating the GSA system.

Availability and Reliability

Commercial GSA system installations

operate reliably around the clock, and

have demonstrated availability of close

to 100 percent.

The GSA nozzle is easily removed for inspection and service.

7
The host site for the GSA demonstration

is TVA’s Shawnee Fossil Power Plant

near Paducah, Kentucky. The Demonstration

Project at TVA’s Center

for Emissions Research

With the increased emphasis on SO2

emissions reduction by electric utility and

industrial plants as required by the Clean

Air Act Amendments of 1990 (CAAA),

there is a need for a simple and economical

FGD process, such as the GSA system, for

small to mid-size plants where a wet FGD

system may not be the least-cost option.

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

Clean Coal Technology (CCT) Demonstration Program, the third solicitation (issued

in 1989) targeted those technologies capable

of achieving significant reduction of SO2

and/or nitrogen oxides (NOX) emissions

from existing facilities. Reduction of these

emissions would minimize environmental

impacts—such as transboundary and interstate pollution—and/or provide for future

energy needs in an environmentally

acceptable manner.

In response to this solicitation, AirPol

Inc. submitted a proposal for the design,

installation, and testing of the GSA system.

This project is the first North American

demonstration of the GSA FGD system for

a coal-fired utility boiler. The purpose of

this project was to demonstrate the high

SO2 removal efficiency of the GSA system,

as well as its cost effectiveness. GSA is a

novel concept developed by FLS miljφ, a

wholly-owned subsidiary of FLS Industries

of Copenhagen, Denmark. The GSA

system is distinguished in the MSW market

by its high SO2 removal efficiency, low

capital cost, and low operating cost.

8
TVA’s Center for Emissions Research

The Center for Emissions

Research (CER) is located at TVA’s

coal-fired Shawnee Fossil Plant. A

10 MWe equivalent flue gas slipstream is pulled from the Unit 9

boiler, which is a 175 MWe (nameplate), Babcock and Wilcox, wallfired unit. Unit 9 is normally fired with

high-sulfur (1.7 to 2.2 kg SO2/GJ, or

4.0 to 5.0 lb SO2/Million Btu) western

Kentucky bituminous coal, under a

variance granted by the state of

Kentucky.

The CER had its origins in the

early 1970s as an experimental test

facility for evaluating alternative

technologies for controlling emissions

of SO2 from coal-fired boilers. Some

of the first work on dry limestone

injection as an FGD technology was

completed at this facility. Later, wet

limestone scrubbing FGD technology

was developed with cofunding support over the years from the Environmental Protection Agency (EPA), the

Electric Power Research Institute

(EPRI), and the DOE. All aspects of

wet limestone scrubbing FGD technology were evaluated, ranging from

process and equipment design and

operation to byproduct disposal

studies.

In the 1980s, after the successful

commercialization of wet limestone

scrubbing FGD technology, the CER

began evaluating other new FGD

technologies. One of the innovative

FGD technologies being developedat the time was the spray dryer

system, which was beginning to be

commercialized for low-sulfur coal

and MSW applications. TVA began

evaluating the potential of this spray

dryer FGD technology for higher

sulfur coal applications with the

installation of two small, 1 MWe pilot

plants at the CER.

Later, in cooperation with EPRI

and Ontario Hydro, TVA constructed

and operated a 10 MWe spray dryer

pilot plant using an ESP for particulate removal.

Because of the apparent advantages of GSA technology, TVA agreed

to act as the host site for this CCT

demonstration program. The CER

operated and maintained the system,

developed the test plan, analyzed

the test data, and acted as a true

partner in the project, including provision of substantial cofunding. In

addition, TVA is continuing to test

the GSA process at the CER to

further expand the database.

Dedication of the completed GSA facility at the Center for Emissions Research.

9
At the Center for Emissions Research

(CER), the flue gas bypassed the existing

spray dryer that had previously been

installed as a test unit. The experience

gained in designing, manufacturing, and

constructing the GSA system for this

project will be used for future commercialization of the technology. Results of

the operation and experimental testing will

be used to further improve the GSA design.

The objectives of the GSA demonstration project were to:

Coal Composition

The sulfur content of the western

Kentucky coal burned during the

demonstration ranged from 1.7 to

2.2 kg SO2/GJ (4 to 5 lb/million Btu),

or about 2.6 to 3.0 percent sulfur by

weight. Three different coals were

burned separately during the test

program. Typical compositions

for these coals are shown in the

table below.

Ultimate Analyses Peabody Martwick Emerald Energy Andalex

Carbon 72.99 76.26 69.42

Hydrogen 4.92 5.72 5.03

Oxygen 7.65 6.83 9.91

Nitrogen 1.65 1.26 1.39

Sulfur 3.05 2.61 3.06

Chlorine 0.02 0.04 0.04

Ash 9.72 7.28 11.15

Total 100.00 100.00 100.00

Heating Value, MJ/kg

Wet 29.7 30.0 27.5

Dry 30.5 31.2 28.5

Heating Value, Btu/lb

Wet 12,800 12,910 12,420

Dry 13,117 13,420 12,870

Analyses: Percent on a dry basis

Composition of coals used in the test program.

10

• Demonstrate SO2 removal in excess

 of 90 percent using high-sulfur U.S.

 bituminous coal.

• Optimize recycle and design param-

 eters to achieve maximum efficiencies

 of lime utilization and SO2 removal.

• Compare removal efficiency and cost

 with existing FGD technologies.

• Determine the air toxics removal

 performance.

• Compare the SO2, particulates, and

 air toxics removal performance

 between a GSA system with an

 electrostatic precipitator and a GSA

 system with a fabric filter.

System Description

The GSA FGD system tested at the

CER is composed of:

• An absorption reactor with an

injection nozzle for lime slurry.

• A cyclone for separating and

recycling material to the reactor.

• A slurry preparation system which

converts pebble lime (also referred

to as quicklime) to slaked lime

needed in the reactor.

 • A dust collector which removes fly

 ash and reaction products from the

 flue gas stream.

The flue gas from the boiler air preheater enters the bottom of the reactor,

where it contacts a suspended bed of

recycle solids coated with lime. Fresh lime

slurry is fed into the reactor by way of a

single, dual-fluid nozzle located in the

center of the reactor, and atomized by compressed air. The heat in the flue gas causes

the moisture in the slurry to evaporate

while an absorption reaction between the

lime and the SO2 in the flue gas takes place.
Slurry droplets impact and coat the dry

solids, thereby preventing slurry from

hitting the wall of the reactor and causing

a build-up of solids. Recycle solids

further minimize scaling due to a scouring

effect on the reactor walls. The solids are

suspended in the reactor by the velocity of

the flue gas stream flowing up through the

reactor. The resulting turbulence provides

intimate contact, allowing SO2 to be absorbed into the lime slurry, which exists as

a thin layer coating the solid particles.

The cleaned flue gas and the suspended

reaction particles travel upward in the

reactor and continue to the cyclone, where

most of the solids, containing the calcium

salts, fly ash, and unreacted lime, are

removed. About 99 percent of the solids

are collected in the cyclone and recycled

to the reactor. Thus, most of the unreacted

lime is available to absorb additional SO2

from the flue gas, thereby minimizing the

consumption of lime.

The remaining 1 percent of the solids

entering the cyclone leaves the system with

the flue gas. The flue gas leaving the

cyclone proceeds to a dust collector for final

particulate collection. The cleaned flue gas

is released to the atmosphere.

The dust collector can be either an electrostatic precipitator (ESP) or a fabric filter;

at the CER, both an ESP and a fabric filter

are available for testing. The fabric filter

used at the CER is a small, 1 MWe pulse-jet

baghouse that treats a slipstream of flue gas.

Flow diagram of the GSA

demonstration system.

11
Control scheme for the GSA system.

The CCT GSA test program was

composed of five parts. The first

part was the preliminary tests, which

were conducted in November and

December 1992. The second part

was the factorial tests, performed

between January and August 1993.

The air toxics testing, which was

conducted between mid-September

and mid-October 1993, was the third

part. The next part was the 28-day

GSA/ESP demonstration run, executed in late October and November

1993. The final part was the 14-day

Time Schedule

fabric filter demonstration run, which

was conducted from late February to

mid-March 1994. Over the span of

the project, the GSA unit operated a

total of 7700 hours.

The Peabody Martwick coal was

burned during January and February

1993; the Emerald Energy coal was

burned during the period of February

to July 1993; and the Andalex coal

was burned from early September

1993 to the end of the test program

in March 1994.

12

The GSA system is automatically controlled to maintain the required level of

acid gas emissions while keeping the lime

consumption at a minimum. The system

is comprised of three control loops.

1. Material Recycle. A sensor in the

reactor inlet measures the dynamic

pressure and converts it to gas velocity

(flow). Based upon the flow, the controller adjusts the speed of the metering

screws in the feeder box, thereby controlling the recycle flow of material to

the reactor in direct proportion to the

gas flow.

2. Flue Gas Temperature. A temperature

sensor, located between the cyclone

and dust collector, controls the speed

of the pump directing cooling water

to the spray nozzle.
3. SO2 Emissions. An SO2 emissions

monitor in the stack controls the speed

of the pump injecting lime slurry into

the reactor.

SO2 Removal Efficiency

The metering screws in the feeder box,

the cooling water pump, and the lime slurry

pump are all driven by electric motors

provided with variable frequency drives

for precise speed control. The pumps are

positive displacement hose-type pumps.

Unlike a centrifugal pump, where the flow

changes with the pressure, the hose pump

maintains constant pressure at different

flow rates. This is necessary to maintain a

constant pressure at the spray nozzle in the

reactor.

For more precise and faster response of

the acid gas emissions control, especially

when the flue gas has large and rapid fluctuations in acid concentration, an additional

acid gas sensor is installed in the reactor

inlet. This permits control of the lime

slurry injection rate by a feed forward/

feedback system.

Demonstration Program

Preliminary Testing

After installation of the GSA equipment,

preliminary tests were performed to establish the operating ranges attainable and

confirm the influence of different operating

parameters. The test results established that

SO2 removal efficiency has a close relationship to the AST.

The tests showed that the GSA system

can operate successfully without dust buildup at an AST as low as 3–6° C (5–10° F).

The tests also showed, as expected, that the

addition of small amounts of calcium

chloride to the recycle dramatically

increases the SO2 removal rate.

ESP = Electrostatic Precipitator

FF = fabric filter

Comparison Of SO2 removal efficiencies with GSA/ESP and GSA/FF options.

A model created from data collected during the test program shows higher

SO2 removal efficiencies for GSA/FF than for GSA/ESP.

13

Ca/S Molar Ratio

Dust loading 2.0 gr/acf.

No chloride addition.

Overall system SO2 removal efficiency. A model created from data collected during

factorial testing demonstrates that SO2 removal efficiency increases as the calcium/

sulfur molar ratio increases and as the AST decreases.

SO2 Removal Efficiency

GSA/ESP vs. GSA/FF

Ca/S Molar Ratio
Effect of Chloride on SO2 Removal

AST = 24 °F

Ca/S Molar Ratio

Effect of chloride on SO2 removal. A model based on data collected during factorial

testing with injection of calcium chloride demonstrates that SO2 removal efficiency

increases as chloride content increases. The chloride additions are expressed as

percent of lime feed. Note: The natural chloride content in the Peabody Martwick

coal corresponds to 0.5 percent of the lime feed and thus represents the baseline

in this graph.

Trace Metal Removal Efficiency

14

Removal rates for trace metals for the test program GSA/ESP system.

Factorial Testing

Upon completion of the preliminary

tests, a statistically designed factorial test

program was conducted. The purpose of

this factorial testing was to determine the

effect of process variables on the operation

and SO2 removal efficiency in the reactor/

cyclone and in the subsequent ESP or alternate fabric filter in order to optimize GSA

system performance.

Reducing the AST results in a substantial

boost in the overall system SO2 removal

efficiency. Sulfur dioxide removal efficiency also increases as the calcium/sulfur

molar ratio increases.

The overall system SO2 removal efficiencies for the factorial tests ranged from

61 to 99 percent, depending on the specific

test conditions. Most of the SO2 removal

occurred in the reactor/cyclone. The SO2

removal efficiency in the ESP was very

low, ranging from 1 to 7 percentage points

based on the inlet SO2 concentration to the

reactor.

The SO2 removal efficiency in the GSA/

fabric filter system was typically about

3 to 5 percentage points higher than that

achieved in the GSA/ESP system at the same

test conditions. This higher SO2 removal

efficiency in the GSA/fabric filter system is

due to the intimate contact between the

residual SO2 and the still reactive solids in

the filter cake on the bags.

One of the important parameters established during the factorial tests was the

influence of chlorides. The test results

showed that SO2 removal efficiency

improves as chloride content in the system

increases.

A surprising result of this testing was

the ability of the GSA system to operate

close to saturation temperature without

incurring any operating problems, while

still achieving high SO2 removal. This is

even more impressive given the low flue

gas residence time in the reactor/cyclone

(3 to 5 seconds).

Test results based on an average of three measurements.
Air Toxics Testing

The potential impacts of Title III of the

CAAA have resulted in increased emphasis

by electric utilities on the measurement of

air toxics, especially for CCT demonstrations. Air toxics tests, which followed the

factorial tests, were conducted to determine

the capability of the GSA system to remove

hydrogen fluoride (HF), HCI, and trace

metals.

The results of the air toxics testing show

that the GSA process is capable of removing these components from the flue gas.

The removal rate across the GSA system

reactor and cyclone appears to be 100 percent for HCI and 99 percent for HF. The

GSA/ESP system removal rates for trace

metals are surprisingly high, exceeding 98

percent for most metals.

Demonstration Runs

Upon completion of the factorial tests

and the air toxics tests, the GSA system

was tested in a 28-day continuous demonstration run with the ESP and separately in

a 14-day demonstration run with the fabric

filter. The demonstration runs began with

the boiler burning the high-sulfur, lowchloride Andalex coal and the following

test conditions:

Gas

Flow Rate .....570 Nm3

/min (20,000 scfm)

Inlet Gas

Temperature ....................160° C (320° F)

Fly Ash

Loading .................... 4.6 g/m3

 (2.0 gr/acf)

Simulated Coal

Chloride Level ................................ 0.12%

AST .....................................10° C (18° F)

The cyclone is being moved to the layout area for insulation prior to installation.

The insulated GSA reactor

is being lifted into place

during construction.

15
History of GSA Development

The GSA process is an innovative

concept for FGD that was developed

by AirPol’s parent company, FLS

miljφ in Copenhagen, Denmark. The

process was initially developed as a

cyclone preheater system for cement

kiln raw meal (limestone and clay).

This system provided both capital

and energy savings by reducing the

required length of the rotary kiln and

lowering the fuel consumption. The

GSA system also showed superior

heat and mass transfer characteristics and was subsequently used in

conjunction with the calcination of

limestone, alumina, and dolomite.

The GSA process for FGD applications was developed later by injecting lime slurry and recycled solids

into the reactor for acid gas removal.

In 1985, a GSA system pilot

plant was built to establish design

parameters for SO2 absorption in

flue gas from an electric utility

power boiler (Stignaes Station of

SEAS) in Copenhagen. The power

station subsequently managed to

meet the emissions code for SO2

without an FGD system, and thus

had no further interest in installing

a GSA system.

At the same time, the code

requirements for SO2 and HCI for

MSW incinerators were tightened

and the pilot unit was moved to an

incinerator plant. The first commercial GSA system unit was installed

at the KARA Waste-to-Energy Plant

at Roskilde, Denmark, in 1988.

The CCT demonstration project

was the first U.S. commercial scale

test of the GSA process for removing

SO2 from power plant stack gas. It

was conducted at TVA’s Shawnee

Fossil Power Plant, using high-sulfur

coal as feed.

The SO2 control mode was engaged for

this run with an overall System SO2 removal

efficiency goal of 91 percent. Due to some

problems encountered in obtaining the

chosen coal, a switch was made to burning

Warrior coal, a higher sulfur (3.5 percent)

coal, for about 1 week. The lime consumption averaged 1.40 – 1.45 moles of calcium

per mole of SO2 in the inlet gas.

The following results were achieved in

the demonstration program:

• During the 28-day run of the GSA/

ESP system, SO2 removal efficiency

exceeded 90 percent, even when the

boiler was switched to a higher sulfur

coal. This switch to the higher sulfur

coal, which necessitated an increase

in lime consumption, demonstrated

the flexibility of the GSA system

over a range of coal sulfur levels.

16

• The particulate removal efficiency

averaged 99.9+ percent. The emissions rate with the ESP remained well

below the New Source Performance

Standards (NSPS) for particulates

(12.9 g/GJ, or 0.03 lb/million Btu)

throughout the 28-day run. The

particulate emissions were about

6.5 g/GJ (0.015 lb/million Btu), i.e.,

one-half the NSPS level.

 • The GSA system demonstrated its

reliability by remaining on-line for

the entire 28-day period.

 • The 14-day fabric filter demonstration run showed that the GSA/fabric

filter system can achieve very high

SO2 and particulate removal efficiencies. Sulfur dioxide removal levels

reached as high as 96+ percent.

Particulate Collection

Performance with Electrostatic

Precipitator

The ESP used during the demonstration

program is a relatively modern, four-field

unit with a specific collection area of about

1.44 m2

/m3/min (440 ft2/1000 acfm). This is

a size similar to several full-scale ESPs

installed on the TVA power system. The

most important result of this demonstration

was that the emissions rate from the ESP

was well below the NSPS for particulates

at all of the test conditions, with a particulate removal efficiency above 99.9+ percent

for most of the tests.

Performance with Fabric Filter

The fabric filter was tested in two

modes: treating flue gas from either the

GSA system outlet or the ESP outlet during

separate phases of the factorial testing.

The bags used in this testing were made

of polyphenylene sulfide needle felt, having

a weight of 542 g/m2

 (16 oz/yd2). Based on

the factorial tests, the SO2 removal

efficiency in the GSA/fabric filter system
was typically about 3 to 5 percentage points

higher than that achieved in the GSA/ESP

system at the same test conditions. This

enhanced performance in the fabric filter

system was not unexpected given the

intimate contact between the SO2 in the

flue gas and the alkaline material collected

on the bags.

The particulate removal efficiency in

the fabric filter was 99.9+ percent for all

of the tests completed with the full dust

loading from the GSA system reactor/

cyclone. The emissions rate was typically in

the range of 4.3 g/GJ (0.01 lb/million Btu),

which is well below the NSPS for particulates. The filter cake on the bags was relatively easy to dislodge and no problems

were encountered in cleaning the bags.

The particulate emission rates with the

fabric filter pulling flue gas from the ESP

outlet were extremely low, about 0.9 g/GJ

(0.002 lb/million Btu), which is more than

an order of magnitude below the NSPS for

particulates. If extremely high removal

efficiencies are required, then the most

effective arrangement may be to install a

fabric filter downstream of the GSA unit

and the ESP.

Comparative capital cost estimates for

the conventional wet limestone, forcedoxidation scrubbing system and the GSA

system show that the total capital requirement for the GSA process is substantially

lower ($149/kW vs. $216/kW). The lower

capital requirement for GSA is primarily

due to lower costs in the SO2 removal

area. The capital cost for the GSA system

is also lower than that for a conventional

spray dryer system.

Economic Evaluation

As part of the DOE CCT Demonstration

Program, an economic evaluation of the

GSA process was conducted using the same

design and economic premises that were

used to evaluate a number of other FGD

processes. Economics were estimated for

a moderately difficult retrofit 300 MWe

boiler burning 2.6 percent sulfur coal. The

design SO2 removal efficiency was

90 percent at a lime feed rate equivalent

to 1.30 moles of calcium per mole of SO2

in the gas inlet stream.

Capital Cost Comparison

GSA vs. Wet Limestone Forced Oxidation (WLFO)

300 MWe, 2.6% Sulfur Coal

Area

$/kW (1990 dollars)

GSA WLFO

Reagent Feed 25 37

SO2 Removal 38 71

Flue Gas Handling 18 24

Solids Handling 5 7

General Support 1 2

Additional Equipment 4 4

Total Process Capital 91 145

Total Capital Requirement* 149 216

* Includes general facilities, engineering and home office fees, contingencies,

 pre-production costs, etc.

Capital cost comparison, GSA versus WLF0. The total capital requirement for GSA is about 30% lower than that for WLFO.

17
Operating and

Maintenance

Experience

The GSA system tested at TVA’s CER

was remarkably trouble free, and there were

no major problems encountered during the

entire program. All equipment and control

instruments operated as anticipated without

extra attention. The GSA system has demonstrated the following advantages:

Legislative and Marketplace Incentives

Title IV of the 1990 revisions to

the Clean Air Act is intended to

reduce SO2 emissions in order to

mitigate acid rain. The 100 largest

SO2 sources are required to reduce

SO2 emissions and implement controls in Phase 1, starting in January

1995. In Phase 11, starting in January 2000, all sources are required

to meet more stringent SO2 control

standards.

Title IV controls SO2 via a system of emission allowances. Each

allowance authorizes the utility to

emit one ton of SO2 per year. The

EPA will distribute the allowances

based on the plant’s total annual

heat input in the mid-1980s multiplied by an emissions factor, which

is 1.1 kg/GJ (2.5 lb/million Btu) for

Phase I and 0.52 kg/GJ (1.2 lb/ million Btu) for Phase II. New plants

receive no allowances. The SO2

emission allowances may be bought

or sold. Decisions will be made to

install SO2 controls or to buy allowances based on the relative costs

in $/ton Of SO2 emitted.

SO2 control systems installed will

make additional allowances available, which may be sold at the

current market price.

Some companies now burn

compliance coals, i.e., coals that

generate SO2 emissions which are

in compliance with emissions limits.

These are low-sulfur coals with

either a higher delivered price than

high-sulfur coals or characteristics

which require significant boiler

changes. Thus, utilities must consider the trade-offs between the

cost of lower sulfur in the coal feed

versus the cost of removing SO2

from the stack gas.

18

• The system is a very simple design

 and is easy to operate and maintain.

• The spray nozzle assembly can be

 replaced without interrupting the

 operation.

• None of the systems in operation has

 had dust buildup requiring shutdown.

• Dedicated maintenance personnel are

 not required.

• GSA yields a byproduct with less than

 1 percent moisture, that can be easily

 disposed of or converted to a low

 grade cement.

• There has been no apparent corrosion

 or erosion after seven years of opera-

 tion in MSW service.

• All GSA systems in operation show

 very close to 100 percent availability.

Commercialization

The GSA system is a low-cost alternative

to wet scrubbers and other semi-dry FGD

systems, with SO2 removal efficiencies

higher than those for other semi-dry systems.

The GSA system meets NSPS requirements

for SO2 and provides significant removal of

air toxics.

The patented GSA technology is considered a viable and cost-effective process

for controlling air pollution emissions from

medium-size boilers fueled with mediumto high-sulfur coal. Particulate control in

GSA systems can be achieved by either an

ESP or a fabric filter. The ground space

requirements for the primary equipment

are very small. The GSA system, therefore,

lends itself well to retrofit installations,

where in many cases an existing ESP can

be utilized.
The potential market for GSA includes

new coal-fired utility boilers and cogeneration boilers up to 500 MWe. Additionally,

in those cases where boilers are fired with

compliance coal, use of GSA would permit

switching to lower-cost high-sulfur coals.

One of the goals of this demonstration

project was to design, fabricate, construct,

and operate a GSA system that can be commercialized for the benefit of U.S. electric

utilities and industries. GSA technology is

now ready to be used to comply with Phase

II of the Clean Air Act Amendments.

An effort has been made to standardize

the process design and equipment sizing so

that a commercial unit can be built and

installed in a relatively short time. Furthermore, equipment design has been simplified, resulting in reduced material and construction costs. A GSA unit which will

accommodate a 100 MWe boiler in a single

reactor has also been designed.

Efforts are now being concentrated on

the retrofit market. AirPol will supply a

GSA system for a 50 MWe municipal boiler

burning Ohio coal as its first commercial

utility installation in the U.S. The state of

Ohio, in conjunction with the Ohio Coal

Development Office, awarded the city of

Hamilton a grant to install a GSA system in

the city’s municipal power plant. To meet

requirements of the CAAA it has been

necessary to burn relatively expensive lowsulfur coal in this plant. After tests on the

GSA system are completed, the unit will

remain in place, allowing the city of

Hamilton to meet environmental regulations while using high-sulfur Ohio coal for

power generation.

The next step in development will be to

apply GSA to a 100-200 MWe boiler, a

conservative scale-up from the 50 MWe

system. Since the GSA system consists of

modular units, subsequent size increases

should be easily accommodated.

Capital Cost Comparison

Boiler Size (MWe)

Capital cost comparison, GSA vs spray dryer. Process capital cost for GSA

is lower than that for spray dryer.

Insulated cyclone separator

being elevated for placement

into the system.

Note: SDW = Spray Dryer, Wheel Type

 SDN = Spray Dryer, Nozzle Type

19
Conclusions

All of the major objectives of the GSA

demonstration were successfully achieved:

• The GSA system removes more than

 90 percent of the SO2 with a low

 level of lime consumption.

• The GSA unit operated without inter-

 ruption during the 28-day demonstra-

 tion period. The emissions from the

 ESP remained well below the NSPS

 for particulates.

Additional GSA Commercial Projects

As a result of the success of the

10 MWe GSA demonstration project,

FLS miljφ has won a major contract

for a high performance SO2 removal

GSA system. The $10 million contract, awarded by Swedish company

Luossavaara Kirunavaara AB (LKAB),

sets a landmark in the application of

the GSA process: with a gas volume

equivalent to a 135 MWe boiler

application, it will be the largest GSA

unit built to date.

The GSA unit will be used to

remove sulfur from the flue gas of a

four million ton per year iron ore

reduction plant. According to FLS

miljφ, the Swedish environmental

authority suddenly imposed more

stringent emissions standards, which

raised the required SO2 removal

efficiency from 90 percent to 95 percent at the final stage of contract

negotiations. The test results from

the GSA demonstration project at

TVA convinced LKAB that GSA is

capable of achieving such high SO2

removal efficiencies and led to

the contract.

In February 1995, AirPol was

awarded a contract for the supply of

a GSA system for a 12 MWe oil-fired

cogeneration plant in Asia. The GSA

system, which is scheduled to be

operational by the end of 1995, will

be the first GSA, and possibly the

first semi-dry scrubber, for an oilfired boiler application.

Based on their prior experience

with a wet scrubber on a similar

installation, and their preference for

a scrubber that generates dry waste,

the company selected a semi-dry

scrubber for this application. Among

competing technologies from worldwide suppliers, GSA was chosen

based on the excellent SO2 removal

performance and the extremely dry

characteristics of the GSA waste

product as demonstrated at the test

unit at TVA.

20

• The capital cost for a GSA system is

 about 30 percent less than that for a

 comparable wet limestone FGD system.

• The GSA process in conjunction with

 dust collection removes substantially

 all of the HCl, HF, and trace metals

 from the flue gas.

• The SO2 removal efficiency of the

 GSA system using a fabric filter for

 particulate removal is about three to

 five percentage points higher than

 that achieved in a GSA system using

 an ESP under comparable conditions.

As shown in the demonstration program,

the GSA process can be designed to take

into account existing site conditions, environmental impacts, and operational concerns,

as well as the goal of cost minimization.

The GSA process is a viable solution to

SO2 removal in coal-fired boiler plants,

and the technology for commercial application in order to meet the Phase II CAAA

compliance requirements. The results of

this demonstration project show that GSA

technology meets the goals of the CCT

Program. The GSA process offers a simple,

economical means of achieving a high

degree of SO2 removal from boilers burning

high-sulfur coals.
Bibliography

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To Receive Additional

Information

To be placed on the Department of Energy’s distribution list

for future information on the Clean

Coal Technology Program and

the demonstration projects it is

financing or on other Fossil

Energy Programs, please contact:

Jerry Pell

FE-222, Building 270

U.S. Department of Energy

19901 Germantown Road

Germantown, MD 20874-1290

(301) 903-9447

(301) 903-9438 fax

Patrice A. Leister

U.S. Department of Energy

Pittsburgh Energy

Technology Center

P.O. Box 10940

Pittsburgh, PA 15236

(412) 892-6126

(412) 892-6127 fax
List of Acronyms and Abbreviations

acf ...............................................................................................................actual cubic feet

AST ...............................................................................approach-to-saturation temperature

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

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

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

CER ......................................................................................Center for Emissions Research

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

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

FGD ............................................................................ ................... flue gas desulfurization

g .................................................................................. ................................................ gram

gr ................................................................................. ................................................ grain

GSA ...........................................................................................Gas Suspension Absorption

J .....................................................................................................................................joule

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

MSW .................................................................................................. municipal solid waste

MW, MWe ............................................................................................................ megawatt

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

scfm .......................................................................................standard cubic feet per minute

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

Preparation and printing of this document

conforms to the general funding provisions of

a cooperative agreement between AirPol Inc.

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.

23