United States
Environmental Protection
Agency
Industrial Environmental Research -
Laboratory
Research Triangle Park NC 27711 "'fW x"
Research and Development
EPA-600/S9-81-019 Oct. 1981
Project Summary
Proceedings: Symposium on
Flue Gas Desulfurization
Houston, October 1980
Franklin A. Ayer
These proceedings for the sympo-
sium on flue gas desulfurization FGD
constitute the final report submitted
to the Industrial Environmental Re-
search Laboratory, U.S. Environmen-
tal Protection Agency, Research Tri-
angle Park, NC. The symposium was
conducted in Houston, TX, October
28-31, 1980.
This symposium provided a forum
for the exchange of information,
including recent technological and
regulatory developments, on the
application of FGD to utility and
industrial boilers. The program in-
cluded a Keynote Address on the
approaches for control of acid rain,
forecasts of energy and environmental
technologies and economics for the
1980's, and sessions on the impact of
recent legislation and regulations,
research and development plans,
utility applications, by-product utiliza-
tion, dry scrubbing, and industrial
applications. Participants represented
electric utilities, equipment and
process suppliers, state environmental
agencies, coal and petroleum sup-
pliers, EPA, and other Federal agencies.
This Project Summary was devel-
oped by EPA's Industrial Environmen-
tal Research Laboratory, Research
Triangle Park. NC. to announce key
findings of the research project that is
fully documented in a separate report
of the same title (see Project Report
ordering information at back).
Proceedings: Symposium on
Flue Gas Desulfurization
Houston, October 1980
This report summarizes the proceed-
ings of the Symposium on Flue Gas
Desulfurization (FGD), held on October
28-31, 1980, in Houston, TX. The
symposium brought together repre-
sentatives of the Federal government,
state and local governments, oil and
chemical companies, electric utilities,
architecture/engineering companies,
process suppliers, equipment suppliers,
academia, research firms, and associa-
tions for the purpose of providing a
forum for the exchange of information
including recent technological and
regulatory developments, on the ap-
plication of FGD to utility and industrial
boilers. The symposium was sponsored
by EPA's Industrial Environmental
Research Laboratory in Research Tri-
angle Park, NC (IERL-RTP).
Michael A. Maxwell, Chief, Emis-
sions/Effluent Technology Branch,
EPA, IERL-RTP, welcomed the partici-
pants and outlined the purpose of the
meeting. The keynote speaker was
Stephen J. Gage, Assistant Adminis-
trator for Research and Development,
EPA, Washington, DC, who gave a
presentation on the approaches for
control of acid rain. Gage said that one
new control technology that shows
promise would simultaneously control
both of the major components of acid
rain—nitrogen oxides (NO,) and sulfur
-------
dioxide (SO2). This new control tech-
nology can be retrofitted to many
existing coal-fired boilers with only
minor modifications: the limestone
injection/multistage burner, or LIMB.
Frank T. Princiotta, Director of EPA's
Energy Process Division, discussed the
nation's future with a focus on synthetic
fuels. Projections indicate that coal,
nuclear energy, and oil shale will
become increasingly important as we
minimize oil imports through adjust-
ments in static oil and gas production.
Gerald McGlamery, Chief, Pilot Plant
Design and Construction, Tennessee
Valley Authority (TVA), discussed the
economics of FGD systems. Jumpei
Ando, Chuo University of Japan, covered
S02 and NOX abatement for coal-fired
boilers in his country. FGD systems are
performing reliably and effectively in
improving the air quality in Japan.
Walter C. Barber, Deputy Assistant
Administrator for Air Quality Planning
and Standards, EPA, chaired a panel on
the impact of recent legislation/regula-
tions under the Clean Air Act (CAA), the
Clean Water Act (CWA), and the
Resource Conservation and Recovery
Act (RCRA) on FGD systems. Other
panel members included John Lum,
Senior Project Officer, Office of Water
Planning and Standards, EPA, and
Penelope Hansen, Program Manager of
the Minerals and Energy Program,
Office of Solid Waste, EPA.
FGD research and development plans
were discussed by three speakers: B.A.
Laseke, Project Director, PEDCo Envi-
ronmental, Inc., on recent trends in
utility flue gas desulfurization; Edward
Trexler, Program Manager for Demon-
stration, Department of Energy (DOE),
on DOE's FGD research and develop-
ment program; and Stuart Dalton,
Program Manager, Desulfurization
Processes, Electric Power Research
Institute (EPRI), on EPRI research
results in FGD—1979-1980.
Utility applications of FGD systems
were discussed by several speakers:
Dewey Burbank, Project Manager,
Shawnee Program, Bechtel National,
Inc., test results on adipic-acid-enhanced
limestone scrubbing at the EPA Shawnee
Test Facility; William Wells, TVA,
cocurrent scrubber and DOWA process
testing—Shawnee Test Facility; Dale
Hicks, City Utilities, Springfield, MO,
FGD experiences at Southwest Unit 1;
Thomas Morasky, Project Manager,
EPRI, results of the Chiyoda Thorough-
bred-121 prototype evaluation; R.A.
Runyan, Project Manager, TVA, forced
oxidation of limestone scrubber sludge
at TVA's Widows Creek Unit 8 Steam
Plant; Richard Spring, Superintendent
Air Quality Control, La Cygne Station,
Kansas City Power & Light Company, La
Cygne Station Unit 1 wet scrubber
operating experience; Royce Hutcheson,
Plant Superintendent of Environmental
Results, Alabama Electric Cooperative,
Inc., one-button operation: start-up and
operation of the Alabama Electric
Cooperative FGD System; Robert Hewitt,
Mechanical Engineer, Texas Utilities,
operation and maintenance experience
of the world's largest spray tower S02
scrubbers; Robert Van Ness, Manager,
Environmental Affairs, Louisville Gas &
Electric Company, operating and main-
tenance experience with the dual alkali
system on Louisville Gas & Electric
Company's Cane Run Unit No. 6; James
Van Meter, Director of Power Produc-
tion and Procurement, Southern Indiana
Gas and Electric Company, operating
experience on the FMC double alkali
system; Earl Mann, Executive Manager,
Electric Production, Northern Indiana
Public Service Company, status report
on the Wellman-Lord/Allied Chemical
FGD plant at Northern Indiana Public
Service Company's Dean H. Mitchell
Station; and Landon Fox, Staff Specialist,
TVA, magnesium FGD at TVA: pilot and
full scale.
An overview of FGD by-product
disposal and utilization was presented
by session chairman Jerome Rossoff,
Director, Fossil Energy Technology, The
Aerospace Corporation. Other speakers
who followed Rossoff were: Chakra
Santhanam, Management Staff, A.D.
Little, Inc., characterization and envi-
ronmental monitoring of full-scale
utility waste disposal sites—a status
report; Val Weaver, Program Manager
for Waste Management, DOE, assess-
ment of the economic impact of RCRA
on the electric utility industry; Dean
Golden, Project Manager, EPRI, FGD
sludge disposal demonstration and site
monitoring projects at EPRI; Gerald
Groenwold, Geologist, North Dakota
Geological Survey, potential effects on
ground water of fly ash and FGD waste
disposal in lignite surface mine pits in
North Dakota; Iver Duedall, Professor,
Marine Sciences Research Center,
State University of New York, at Stony
Brook, environmental compatibility, and
engineering feasibility for utilization of
FGD waste in artificial fishing reef
construction; and Penelope Hansen,
Office of Solid Waste, EPA, government
procurement of cement and concrete
containing fly ash.
At the symposium an evening session
was held on the subject of dry scrubbing.
Speakers and their topics were: Gerald
McGlamery, Chief, Pilot Plant Design
and Construction, TVA, spray dryer
FGD: technical review and economic
assessment; Marvin Drabkin, Senior
Systems Engineer, Mitre Corporation,
spray dryer FGD capital and operating
cost estimates for a northeastern utility;
Mary E. Kelly, Chemical Engineer,
Radian Corporation, current status of
dry FGD systems; Nicholas Stevens,
Manager, Chemical Process Develop-
ment, Research-Cottrell, Inc., dry S02
scrubbing pilot test results; Edward
Parsons, Engineering Consultant in
Product Design, Envirotech Corporation,
SO2 removal by dry FGD; and Thomas
Hurst, Babcock & Wilcox Company, dry
scrubber demonstration plant operating
results.
Industrial applications of FGD systems
were discussed by several speakers:
James Dickerman, Program Manager,
Radian Corporation, applicability of FGQ
systems to industrial boilers; Charles
Sedman, Environmental Engineer-Air,
Office of Air Quality Planning and
Standards (OAQPS), EPA, SO2 emission
data and status of the new development
of industrial boiler new source per-
formance standards; Avi Patkar, Project
Manager, PEDCo Environmental, Inc.
applicability of FGD systems to oilfielc
steamers and sodium waste dispose
options; Theodore Brna, Manager
Abatement Engineering, EPA, perform
ance evaluation of an industrial spra^
dryer for SO2 control; and Rober
Giammar, Associate Manager of Fuel;
and Combustion, Battelle Columbus
Laboratories, application of the coal/
limestone pellet process to stoker-coal
fired boilers.
In closing, Michael Maxwell, Chief
Emissions/Effluent Technology, EPA
indicated that the symposium provide)
the necessary foru m for the excha nge o
information, including the recent tech
nological and regulatory development
on the application of FGD to utility am
industrial boilers.
Summaries or abstracts of thi
speakers' remarks follow: I
-------
Michael A. Maxwell, Chief,
Emissions/Effluent
Technology Branch, EPA,
IERL-RTP
Maxwell welcomed the participants
and outlined the scope of the sympo-
sium. He stressed the need for exchang-
ing information on FGD technology
developments, including the techno-
logical and regulatory aspects, on the
application of FGD to utility and industrial
boilers.
Stephen J. Gage, Assistant
Administrator for Research
and Development,
EPA - Washington
Gage, in his keynote address, stressed
the need to move away from our
dependence on foreign oil to greater
reliance on coal where the U.S. has one
of the greatest known reserves existing
anywhere in the world. The President
and the Congress have mandated this
conversion to coal as part of the overall
National Energy Plan. The energy
supply structure emphasizes the con-
servation and use of domestic coal, oil
shale, unconventional natural gas, and
heavy oil (rather than the predominantly
oil-based structure).
He explained that this means mining
and burning "dirtier" fuels which could
cause a growing air pollution problem.
He pointed out that we must maintain
air quality as the production of pollutants
from burning fossil fuels rapidly expands.
New source performance standards
and those forthcoming are examples of
recent environmental protection efforts
to continue R & D of environmental
control technologies.
Gage stated that FGD systems are
performing reliably and effectively both
here and abroad. The growing use of
FGD means that the amount of SOX
emitted to the atmosphere is expected
to remain constant or decrease slightly
by the turn of the century.
According to Gage, EPA has been
aggressively pursuing an air emissions
program to control SOX, NOX and
particulates—all released from the
burning of coal and all contributors to
the growing problem of acid rain.
Gage's concern is that acid rain may
become one of the most significant
environmental problems of the coming
decade. EPA must first solve the
perplexing mechanism by which acid
rain is formed in order to minimize
Lcostly investments for control. In
addition to EPA's efforts, many gov-
ernment agencies as well as private
industry are participating in these
efforts.
Besides generating information on
acid rain that can be used to develop air
quality control strategies and options.
Gage said that another fundamental
task was to communicate to Congress
and the public the effects of acid rain.
One tool to accomplish this is the
development of an "acid deposition
document" that will attempt to quantify
and qualify the entire range of pol-
lutants involved in acid rain creation.
A new technology discussed by Gage
to control acid rain's major components,
SC>2 and NOX, which-shows promise and
which may be retrofitted to many coal-
fired boilers, was the limestone injec-
tion/multistage burners, or LIMB. LIMB
in the U.S. is at the bench/pilot scale
stage of development while Germany is
currently operating a 60-MW electric
boiler using the technology.
Gage concluded by emphasizing the
need for government and industry
working together to support the national
energy policy to expand the use of coal,
and he was sensitive to the fact that the
economy cannot regain its vital growth
without the aid of a vigorous industrial
base.
Frank T. Princiotta, Director,
Energy Processes Division.
EPA - Washington
Projections indicate that coal, nuclear
energy, and oil shale will become
increasingly important as we adjust for
static domestic oil and gas production
and minimization of oil imports. Envi-
ronmental problems can be quite severe
for each of these fuel cycles. A massive
synthetic fuel industry based on coal, oil
shale, and biomass is emerging with
monumental potential for environmen-
tal damage. The Environmental Protec-
tion Agency (EPA) has designed a
regulatory program aimed at mitigating
environmental damage while allowing
for birth and nurturing of this critical
industry.
Gerald G. McGlamery, Chief,
Pilot Plant Design and
Construction Branch, Energy,
Demonstration and
Technology Division,
Tennessee Valley Authority
This paper reviews recent results
from EPA-sponsored flue gas desulfuri-
zation and byproduct/waste disposal
economic evaluations prepared by TVA.
Included are a summary of comparative
capital investments and annual revenue
requirements from a three-phase effort
to evaluate the leading FGD processes,
and similar results from three phases of
sludge disposal studies. Data from a
1985 projection of FGD byproduct
sulfur/sulfuric acid marketing potential
are given.
A new series of FGD process evalua-
tions is also previewed, including a set
of updated evaluation premises which
will be utilized in the early 1980's.
Examples of the effects of the revised
premises on limestone scrubbing eco-
nomics are shown. Finally, results are
provided from a recent evaluation of
limestone scrubbing in a spray tower
using adipic acid, forced oxidation, and
gypsum disposal by stacking.
Jumpei Ando, Professor,
Science and Engineering,
Chuo University
The total capacity of coal-fired utility
boilers in Japan, which was only 4,300
MW (3.7% of total utility power) in 1979,
is expected to increase to 10,000 MW
(5.6%) in 1985, and to 22,000 MW
(10.0%) in 1990. Most of the boilers will
apply FGD by the wet limestone-
gypsum process because of its reliability
and relatively low cost. To save energy
and water, FGD systems with a low
pressure drop and small water con-
sumption are preferred. Tests on FGD by
a dry carbon process are underway.
NOX concentrations in flue gases from
existing coal-fired boilers have been
lowered to 200-350 ppm by combustion
modification including staged combus-
tion and the use of Iow-N0x burners. For
further abatement, selective catalytic
reduction (SCR) has started to be
applied to several coal-fired boilers. The
first full-scale combination system of
SCR and FGD was put into operation in
April 1980. The plant cost for SCR is
about one-third that for FGD. A new
combustion technology has also been
developed in attempts to lower NOX
below 100 ppm.
B.A. Laseke. Jr.. Project
Director, PEDCo
Environmental, Inc.
PEDCo Environmental, Inc., under
contract to the Industrial Environmental
Research Laboratory-RTP and the Divi-
sion of Stationary Source Enforcement
of the U.S. Environmental Protection
-------
Agency, has been monitoring the status
of utility flue gas desulfurization (FGD)
technology since 1974. Information for
this program is obtained by visits to
plants having operational FGD systems
and through periodic contacts with
representatives of utility companies,
FGD system and equipment suppliers,
system designers, research organiza-
tions, and regulatory agencies.
This paper summarizes the status of
utility FGD technology as of the end of
August 1980 and indicates recent
trends in both the design and perform-
ance of the FGD systems. The discussion
of current status includes the number of
capacity of operational and planned
FGD systems, as well as identification of
the systems according to process type,
emission control strategy, S02 inlet
concentration levels, and removal ef-
ficiencies. Process design developments
and trends are summarized for the
major components and subsystems
associated with commercial FGD sys-
tems. In discussing FGD system per-
formance, composite graphs are in-
cluded presenting annual system
availability data (through June 1980}for
low-, medium-, and high-sulfur coal
FGD installations. A statistical analysis
of the data for the years 1978 and 1980
indicates overall trends in FGD system
dependability. Finally, capital and
annual cost data (both reported and
adjusted) are included for the opera-
tional FGD systems and cost model
comparisons are made.
The current data indicate that 203
FGD systems are either operational,
under construction, or planned (as of
August 1980), representing a total
controlled capacity of about 97,000
MW. Of the 203 systems, 73 are
operational, representing 27,155 MW
of controlled capacity. The dependability
analysis indicates that the overall
median availability for these operational
systems has increased 1.5%, 16.5%,
and 50.6% for low-, medium-, and high-
sulfur coal FGD installations, respec-
tively, between the years 1978 and
1980.
Edward C. Trexler, Program
Manager for Demonstration,
Office of Coal Utilization,
U.S. Department of Energy
The Department of Energy's flue gas
desulfurization (FGD) research and
development activities are conducted as
part of the Advanced Environmental
Control Technology Program (AECT)
which is managed within the organiza-
tion of the Assistant Secretary for Fossil
Energy. This new AECT program was
initiated in FY 1979 with a goal to
identify, research, develop, refine, and
demonstrate equipment that will clean
flue gas for compliance with existing
and anticipated environmental pollution
regulations, and equipment that will
remove the undesirable components
from coal-derived gas streams to ensure
reasonable life for utilization equipment
such as gas turbines and fuel cells. The
flue gas cleanup portion of the AECT
program budget amounted to $2.7
million in FY 1979 and $20.1 million in
FY 1980.
The FGD project is divided into two
parallel efforts identified by the scheduled
completion dates as very near-term (end
1983) and near-term (end 1986). The
very near-term effort aims at improving
the S02 removal efficiency and reducing
the waste disposal problems of conven-
tional lime/limestone scrubbers. This is
being done in coordination with EPRI
and EPA scrubber improvement pro-
grams, through private sector scrubber
instrumentation and analysis, by tests
at TVA and other utility prototype and
full-scale scrubber facilities, and by
transfer of process improvement in-
formation. The near-term effort is aimed
at supporting newer technology S02
removal processes that include non-
regenerable (throwaway) and regen-
erable systems that produce potentially
marketable by-products such as sulfur
and sulfuric acid. These technologies
are, or will, be under experimental test
at Fossil Energy Technology Centers,
under prototype testing by DOE and
EPRI at TVA and other sites, and under
initial commercial use evaluation by
DOE at power stations and industrial
plants. As these technologies mature,
private industry will be encouraged to
cost-share development with the Gov-
ernment. Information on progress will
be disseminated via reports, symposia,
plant visitations, demonstrations, and
workshops.
Stuart M. Dalton, Program
Manager, Desulfurization
Processes, Electric Power
Research Institute
EPRI has a research effort of about
$10 million/year in flue gas desulfuri-
zation covering engineering evaluations,
field testing, bench testing, pilot plants,
prototypes, and demonstrations. This
paper reports selected results from
projects on FGD water integration,
gypsum crystallization, limestone dis-
solution, wet stack operation, sulfur
production via RESOX, absorption/steam
stripping, cyclic reheat, and integrated
emission control. A brief review of
current demonstration plans and pro-
gram emphasis is also included.
Dewey A. Burbank. Project
Manager, Shawnee Program,
Bechtel National, Inc.
Adipic acid has been demonstrated as
a powerful scrubbing additive for en-
hancing SOa removal in lime and lime-
stone wet scrubbing tests both at the
EPA/IERL pilot plant at Research
Triangle Park, NC, and at the EPA-
sponsored Shawnee Test Facility near
Paducah, KY. Improved limestone
utilization and operating reliability have
also been demonstrated.
Earlier test results using adipic acid,
July 1978 - October 1979, were
reported at the Fifth Symposium on Flue
Gas Desulfurization in Las Vegas, NV,
March 5-8, 1979, and at EPA's Fifth
Industry Briefing in Raleigh, NC,
December 5, 1979. This is the third
report on the recent adipic acid test
results at the Shawnee Test Facility i
from October 1979 through May 1980. '
The recent tests with adipic acid were
conducted only on the venturi/spray
tower system. All tests were made with
limestone slurry, including: (1) partial
factorial tests to characterize the effects
of pH, adipic acid concentration, and
other operating parameters on S02
removal; (2) single-loop (one-tank) tests
without forced oxidation at low pH and
high (4000 ppm) adipic acid concentra-
tion; (3) tests with a venturi only to
determine the limits of SO2 removal; (4)
single-loop forced oxidation tests, with
both one and two tanks; and (5) bleed
stream oxidation tests at low pH and
high (4000 ppm) adipic acid concentra-
tion.
Major efforts during the recent tests
were directed toward investigation of
the effect of pH on the degradation of
adipic acid. Adipic acid degradation was
found to be minimized when the
scrubber is operated at low (below 5.0-
5.1) inlet pH. Forced oxidation and poor
limestone utilization tend to increase
the degradation.
William L Wells, Program
Manager, Tennessee Valley
Authority
Prototype cocurrent limestone scrubbei
-------
tests were performed at the Shawnee
Test Facility. The initial cocurrent
prototype tests consistently achieved
greater than 90% S02 removal while
operating with inlet flue gas SO2
concentrations ranging from 1500 ppm
to 3000 ppm. Although the prototype
scrubber tower was reliable, total
system reliability was not achieved
during the initial tests at 27 ft/sec
superficial scrubber gas velocity, pri-
marily because of solids deposits in the
mist eliminator and the inline, indirect
steam reheater. At a 20 ft/sec super-
ficial gas velocity and with low fly ash
loading in the inlet flue gas, there were
no significant solids deposits in the mist
eliminator or reheater. Mist eliminator
operation was reliable during operation
with high fly ash loadings and a 20
ft/sec superficial gas velocity, but the
inline reheater continued to plug with
slurry solids. Forced-oxidation tests,
with a single scrubber hold tank and
multiple hold tanks, identified operating
conditions which consistently removed
greater than 90% of the S02 and
oxidized greater than 95% of the
calcium sulfite in the scrubber slurry to
gypsum.
William L. Wells, Program
Manager, Tennessee Valley
Authority
Dowa dual-alkali process tests at the
nawnee Test Facility were the first
application of the Dowa process with
flue gas from a coal-fired boiler. The
operating conditions were based on
operating experience at Dowa facilities
at smelter plants, sulfuric acid plants,
and oil-fired steam generator plants in
Japan.
The initial tests utilized the existing
Turbulent Contact Absorber (TCA) in the
Shawnee train 200. The maximum SCb
removal efficiency by the TCA was 85%
to 90%. During this TCA testing, prob-
lems with gas flow distribution in the
absorber were observed. Subsequently,
the mobile sphere packing in the TCA
was replaced with rigid packing to
improve gas flow distribution and
gas/liquor contact. A factorial absorp-
tion test series using the rigid packing
identified operating conditions which
will consistently achieve greater than
90% S02 removal efficiency.
The neutralization and gypsum de-
watering process steps were generally
satisfactory during the absorption tests.
Extensive reliability tests were not
conducted; however, no significant
reliability problems were identified
during the factorial absorption tests.
N. Dale Hicks, Superintendent,
Southwest Power Station,
Springfield City Utilities
City Utilities of Springfield, MO,
began commercial operation of this FGD
system in September 1977. Two
turbulent contact absorber modules are
arranged in parallel and utilize a
pulverized limestone slurry for S02
removal. The scrubbers serve a 195 MW
unit with a Riley Stoker boiler burning
3.5% sulfur coal. Station design was by
Burns & McDonnell, with the Air
Correction Division of UOP, Inc., re-
sponsible for the FGD system on this
new facility.
The absorber modules and various
support systems have experienced a
variety of problems since initial start-up.
The more severe problems encountered
have been: absorber and demister
pluggage; failure of absorber spheres;
pipe breakage; control and instrumenta-
tion malfunctions; and expansion joint,
damper, and duct corrosion. Past and
planned efforts to rectify these dif-
ficulties, and to improve FGD system
reliability, are discussed in detail.
A related problem area has been the
continuous monitoring systems for flue
gas opacity and SO2 emissions. Original
equipment has proven unsuccessful
and the investigation toward a solution,
with the aid of a consulting firm, is
described.
The station is to be the hostfacilityfor
an EPA-sponsored full-scale demon-
stration of adipic acid as an additive to
wet limestone FGD systems. Anticipated
results are enhanced efficiency and
improved operation of the pollution
control facility. Also involved in the
project are the Radian Corporation and
UOP, Inc.
Thomas M. Morasky, Project
Manager, Electric Power
Research Institute
A 10-month evaluation of the Chiyoda
Thoroughbred 121 Prototype Process
(CT-121) was conducted at the Scholz
Electric Generating Station of Gulf
Power Company. The 23-MW CT-121
prototype was modified from existing
CT-101 process equipment at Scholz by
Chiyoda International Corporation, a
subsidiary of Chiyoda Chemical Engi-
neering and Construction Company,
Ltd. Chiyoda operated the prototype, and
the Electric Power Research Institute and
Southern Company sponsored technical
evaluations of the prototype process
performance. This paper summarizes
the findings of these evaluations.
Detailed results of the gypsum stacking
evaluation are presented with the
Chiyoda Thoroughbred 121 presenta-
tion.
R.A. Puny an. Project Manager,
Environmental Control
Assessment Branch, Tennessee
Valley Authority
Tests on one module (140 MW) have
been carried out to demonstrate the
feasibility of forced oxidation of lime-
stone scrubber sludge to gypsum as a
viable technique for ultimate disposal of
these waste materials. Both one- and
two-tank oxidation experiments were
studied with data indicating that the
two-tank runs more closely met test
objectives. Equations to predict oxida-
tion were developed and expressed as a
function of mass transfer and chemical
kinetics. Air stoichiometries of between
1.75 and 2.0 Ib atoms 0/lb mole S02
absorbed will consistently produce
oxidation of —95%.
As a result of the Forced Oxidation
Test Program, this method is being
given consideration as one of the
alternative methods of scrubber sludge
disposal for Widows Creek Units 7 and
8. Additionally, Paradise Steam Plant
Units 1 and 2 scrubber trains are being
designed with a forced oxidation option
to produce a sulfate waste product.
Richard A. Spring,
Superintendent, Air Quality
Control, La Cygne Station,
Kansas City Power & Light
Company
In the late 1960's, Kansas City Power
& Light Company and Kansas Gas &
Electric Company entered into a joint
venture to construct an 800-MW coal-
fired generating unit. An east central
Kansas location was selected for its
ample coal reserves and adequate
water supply.
The coal reserves proved to be a low
grade with an average of 5.25 percent
sulfur and 24 percent ash. To make this
coal an acceptable boiler fuel a large
scale air quality control system was
required. After considerable pilot test-
ing on a smaller generating unit burning
similar coal, a venturi-absorber scrubber
using limestone as the scrubbing agent
was selected. Construction of the La
-------
Cygne Station Unit 1 started in April
1969; commercial operation began in
June 1973.
This paper reviews the operating
experiences, operation and maintenance
(O & M) cost trends, availabilities,
modifications, manpower, and other
supportive data relating to this limestone
scrubber system.
Royce Hutcheson, Plant
Supervisor, Environmental
Results, Tombigbee Power
Plant, Alabama Electric
Cooperative, Inc.
Alabama Electric Cooperative's
Tombigbee Power Station is on the
Tombigbee River about 70 miles north
of Mobile, AL. The most recent expan-
sion at this site was the addition of Units
2 and 3. Each unit has a rated capacity of
255 MW and is designed to burn
Alabama and Kentucky coals with a
maximum sulfur content of 1.8%. To
meet the emission standard of 1.2 Ib
S02 per million Btu, flue gas desul-
furization was required. In September
1975 Peabody Process systems was
awarded a contract to furnish a lime-
stone FGD System for both units.
Robert A. Hewitt, Mechanical
Engineer, Texas Utilities
Services, Inc.
The 750-MW Monticello boiler 3 of
Texas Utilities Services, firing lignite
coal, is equipped with three large spray
towers, designed by Chemico Air Pollu-
tion Control Corporation. Each spray
tower is sized to handle over 1 million
ftVmin of flue gas. This flue gas
desulfurization system uses pulverized
limestone slurry for scrubbing and
includes a flue gas bypass as well as an
external steam flue gas reheat system.
The FGD system went into operation in
mid-1978 and has since consistently
logged very high availability as well as
high S02 removal efficiency. The extreme
simplicity of the spray tower system has
resulted in only a modest increase in the
power plant's operating and mainte-
nance staff. A recent inspection of the
system revealed no major problem with
the tower and duct liners or the tower
internals. A few isolated spots on the
internal slurry pipes showed wear due
to close proximity to the sprays. Failure
of the rubber lining on the side-mounted
agitators and slurry recycle pumps has
been the primary source of problems
with the system. The experience with
this system in general has been very
satisfactory and Texas Utilities has
purchased two essentially duplicate
systems for the Twin Oak Power
Station.
Robert P. Van Ness, Manager,
Environmental Affairs,
Louisville Gas & Electric
Company
This pa per discusses the results of the
recently performed acceptance test on
the dual alkali system serving Louisville
Gas and Electric Company's Cane Run
Unit 6 boiler. The acceptance test was
conducted to measure the system
performance with respect to the guar-
antees offered Louisville Gas and
Electric by Combustion Equipment
Associates. The results of the testing
were:
• SOa removal averaged 94% and
143 ppm outlet concentration.
• Soda ash consumption averaged
0.042 mole soda ash per mole S02
removed.
• Lime consumption averaged 1.04
mole CaO per mole SOa removed.
• Power consumption averaged
1.05% of generation.
• Filter cake solids averaged 52.2 wt
% insoluble solids.
• There was no net particulate
addition.
Various problems attributable to the
boiler, the FGD system, and the quality
and quantity of the carbide lime supplied
to the system delayed the acceptance
testing until July 1980. The year-long
demonstration period started officially
in May 1980. The nature of the prob-
lems experienced and their solutions
are discussed.
James A. Van Meter, Director
of Power Production and
Procurement, Southern
Indiana Gas and Electric
Company
This paper reviews the design and
initial operating experience with the
flue gas desulfurization system at
Southern Indiana Gas and Electric
Company's (SIGECO's) A.B. Brown
Station Unit 1, a 265-MW steam electric
station burning up to 4.5% sulfur coal in
a pressurized, pulverized coal boiler.
After initial checkout in the spring and
summer of 1979, the FGD system began
routine continuous operation. Overall
operating results are presented for SO?
collection, chemical consumption,
availability, maintenance requirements,
and operating costs. The problem areas
that contributed significantly to main-
tenance requirements or nonavailability
of the system are discussed in detail.
Not counting the scheduled outage, the
system has enjoyed a 96% availability
overall in its first year of operation on a
high sulfur coal application. SOa removal
of over 90% has been routinely demon-
strated. Overall operating costs on an
annual revenue requirements basis are
close to the original projections.
Earl L. Mann, Executive
Manager, Electric Production,
Northern Indiana Public
Service Company
The Northern Indiana Public Service
Company and the U.S. Environmental
Protection Agency entered into a cost-
shared contract in June 1972 for the
design, construction, and operation of a
regenerable flue gas desulfurization
(FGD) demonstration plant. The system
selected for the project was a combina-
tion of the Wellman-Lord SOa Recovery
Process and the Allied Chemical SOa
Reduction Process. The FGD plant was
to be retrofitted to NIPSCO's 115-MW
pulvenzed-coal-fired Unit 11 at the
Dean H. Mitchell Station in Gary, IN. j
NIPSCO entered into contracts with.
Davy Powergas, Inc., for the design an4(
construction of the FGD plant, and
Allied Chemical Corporation for opera-
tion of the piant.
The FGD plant acceptance test was
successfully completed on September
14, 1977. The plant completed a 2-year
demonstration test period during which
information was collected and reported
regarding pollution control performance,
secondary effects, economics, and
reliability of the system. TRW, Inc. was
the independent evaluator for the EPA
through October 1979. A follow-on
EPA/NIPSCO contract of 7-V2 months
has recently been completed. Operation
of the plant continues.
Landon D. Fox, Staff
Specialist, Tennessee Valley
Authority
This paper discusses pilot and full-
scale magnesium flue gas desulfuriza-
tion (FGD) designs by TVA.
The full-scale (600-MW equivalent)
magnesium FGD design is for operation
at high and low load factors for a high
sulfur coal. After a process and system
chemistry (magnesium sulf ite/bisulf ite)
description, the paper describes th
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FGD equipment and system operation
which includes an onsite acid plant. The
second part of the paper discusses
information on a test program and
schedule of a pilot plant being con-
sidered by TVA to verify the magnesium
FGD design.
Chakra J. Santhanam,
Management Staff, Arthur
D. Little, Inc.
This paper presents a status report on
the EPA project, "Characterization and
Environmental Monitoring of Full-Scale
Utility Waste Disposal Sites" (EPA
Contract 68-02-3167). Arthur D. Little,
Inc. is the prime contractor on this
project which involves the character-
ization, environmental monitoring, and
engineering/economic assessment of
coal ash and FGD waste disposal at 12
full-scale waste disposal sites. The
project is designed to obtain technical
background data and information so
that EPA can determine the degree to
which disposal of these wastes (from
coal-fired power plants) needs to be
managed in order to protect human
health and the environment. This effort
will fulfill some of EPA's responsibilities
under RCRA.
To date, major accomplishments of
the project include:
• Evaluation of available data on
coal-fired power plants in the U.S.
to develop a list of candidate and
backup sites.
• Preparation of procedures manuals.
• Progress in securing utility involve-
ment and cooperation.
Val E. Weaver, Program
Manager for Waste
Management, U.S. Department
of Energy
This paper presents "interim" findings
of a continuing evaluation of the
impacts on coal-fired electric generating
facilities in the utility sector deriving
from Proposed Rules issued by EPA for
implementing Sections 3001, 3002,
and 3004 of RCRA Subtitle C (December
18, 1978) and Proposed Guidelines
under Section 4004 (February 6, 1979)
and Section 1008 (March 26, 1979).
Cost analyses were made on direct
costs only and presented in 1979
dollars.
The primary purpose for undertaking
this study was to assess RCRA's
impacts on coal-fired utilities as a
means to understanding the implica-
tions of RCRA regulations on the
National Energy Plan (NEP), the Power-
plant and Industrial Fuel Use Act of
1978 (PIFUA), which gives DOE authority
to enforce coal conversion actions, and
on utilities. Ultimately, this information
can be used to understand and deter-
mine RCRA's implications on DOE's
Fossil Energy mission objectives of
developing programs and supporting
advanced technologies which will
promote greater utilization of coal in an
environmentally acceptable manner.
Cost and other impact considerations
were developed through a survey of
available information from 29 significant
coal producing and/or using states and
by in-depth case studies of operating
conditions and engineering and design
requirements for RCRA compliance at 6
operating and 16 theoretical base-case
coal-fired power generating plants. The
six plants were selected to encompass a
broad cross-section of industry operating
factors. Solid waste disposal costs were
developed for three scenarios structured
to bracket the probable cost impacts of
the proposed RCRA regulations on the
utility sector. Cost curves and mathe-
matical models of capital and operation
and maintenance (O&M) costs asso-
ciated with each disposal scenario were
developed as a function of waste
generation rates. In all instances the
"least cost of compliance" rather than
"worst case" data were employed.
Preliminary national costs for waste
disposal, based on direct costs alone,
reflected an increase in disposal costs of
over "4 times" for nonhazardous and
over "13 times" for hazardous disposal.
This results in a cost increase of from
1.09 to 3.2 mills per kWh of power
generated (in terms of 1979 dollars).
Dean M. Golden, Project
Manager, Electric Power
Research Institute
The increasingly stringent air quality
requirements on power plants necessi-
tated the cleanup of flue gas stack
emissions, resulting in ever-increasing
quantities of solid wastes from the
combustion of coal. Presently, the most
used type of FGD scrubber is the wet
scrubber. This kind of scrubber is
expected to dominate the industry into
the 1990's. The waste produced by wet
scrubbing is a sludge composed of the
scrubbing liquor, calcium sulfite/sulfate
solids, and varying quantities of fly ash.
EPRI has a number of research projects
recently completed or underway explor-
ing new options for disposal of the FGD
sludges. This paper summarizes the
results of two projects, one evaluating
the stacking method for gypsum dis-
posal, and the other a site monitoring
investigation to assess the acceptability
of sludge/ash fixation.
The results of the FGD gypsum
stacking demonstration indicate that
this oxidized FGD sludge has settling,
dewatering, and structured character-
istics similar to and, in some cases,
superior to phosphate gypsum, making
this a viable option for disposal.
The results of the site monitoring of
the first full-scale fixed sludge disposal
system are still inconclusive. Well
monitoring indicates some impact on
groundwater quality in the vicinity of the
disposal facilities. Field permeabilities
of the fixed sludge samples were found
to be higher than laboratory test results.
Gerald H. Groenewold,
Geologist, North Dakota
Geological Survey
Increased reliance on coal-burning
power plants is resulting in the genera-
tion of large quantities of waste
products. Fly ash and FGD waste
constitute the two major by-products of
coal-burning power plants in the U.S. At
mine-mouth power stations a common
method of disposal of these wastes is by
emplacement in surface mine pits.
In this study, initially funded by EPA
and presently by DOE, the potential
impacts of surface mine pit disposal of
fly ash and FGD waste at the Center
Mine near Center, ND, are being
evaluated. The FGD waste at Center is
generated by using the highly alkaline
fly ash as the SO2 sorbent. The research
involves field studies, laboratory studies,
and computational geochemical studies
to determine the potential for FGD
waste and fly ash to affect groundwater
quality.
FGD waste from North Dakota lignite,
when placed in contact with water in
various types of laboratory experiments,
produces leach fluids with high SO*,
Mg, and Na concentrations and pH
values in the range of 7.0 to 8.5. Toxic
metal and nonmetal concentrations are
generally not significantly in excess of
drinking water standards. The concen-
trations of S04 and Ca are limited by the
solubility of gypsum in conjunction with
the degree of ion pairing between the
major cations and sulfate. Highest total
dissolved solids occur when Na and Mg
are present as soluble sulfate salts.
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Iver W. Duedall, Professor,
Marine Sciences Research
Center, State University of
New York at Stony Brook
A multidisciplinary team at the State
University of New York at Stony Brook,
in collaboration with ID Conversion
Systems, Inc. (Horsham, PA), is assessing
the feasibility of using blocks of waste
materials from coal-fired power plants
for underwater construction of artificial
fishing reefs. Experiments conducted
over the past 3 years in the laboratory
and in the sea have suggested that coal
waste blocks are environmentally
acceptable in the ocean.
On September 12, 1980, a 500 ton
reef was constructed in the Atlantic,
south of Long Island, from 18,000 solid
blocks 8 in. x 8 in. x 16 in. of stabilized fly
ash and FGD sludge obtained from coal
burning power plants in Ohio and
Indiana. The reef blocks were fabricated
at a commercial concrete block plant in
Pennsylvania using automatic block
making equipment. The ratio (dry
weight) of fly ash to FGD sludge was
1.5:1 and 3:1.
In preparation for fabrication of the
500 tons of reef blocks, a combination of
different coal waste mixes, stabilization
additives, and curing procedures were
screened to develop candidate mix
designs. Experiments were made at the
research facilities of the Besser Com-
pany in Alpena, Ml, to develop methods
by which coal wastes could successfully
be formed into blocks by block making
machines.
The demonstration disposal reef will
be monitored for 3 to 4 years to assess
environmental impacts which may
occur and to measure the development
of the biological communities which will
be associated with the reef.
Penelope Hansen, Program
Manager of the Minerals and
Energy Program, Office of
Solid Waste, EPA-Washington
The Resource Conservation and
Recovery Act (RCRA) has two major
goals: 1) the protection of human health
and the environment, and 2) the
conservation of valuable material and
energy resources. EPA's efforts have
been concentrated on the first goal. This
paper, however, concentrates on re-
source recovery and reuse of waste
materials as outlined under RCRA
Section 6002.
Federal procuring agencies are man-
dated to purchase items containing the
maximum practical amount of recovered
materials. Recycled products are dis-
cussed from reasonable equivalents in
technical performance, price, levels of
competition, and product availability.
Criteria developed to aid in the pro-
curement process are discussed. The
scenario used is the application of
Federal procurement to either cement
or concrete which contains fly ash and
the guidelines proposed for their
procurement.
Gerald G. McGlamery, Chief,
Pilot Plant Design and
Construction Branch,
Tennessee Valley Authority
This paper summarizes the results of
an EPA-funded study of dry scrubbing
technology and economics. The relative
economics of a generic lime spray dryer
process and a limestone scrubbing
process were compared for three coal
applications: a low-sulfur western, and
low- and high-sulfur eastern coals. The
cost estimates are based on recently
updated TVA design and economic
premises and include all of the process-
ing required to meet the 1979 new
source performance standards (NSPS)
for both paniculate matter and S02 and
to dispose of the resulting FGD waste in
an environmentally acceptable manner.
The resulting preliminary economics
are included for all three coal appli-
cations for both the generic lime spray
dryer process and the limestone scrub-
bing process. Sensitivity of the resulting
annual revenue requirements to the
delivered raw material cost and the raw
material stoichiometry are also included.
Marvin Drabkin, Senior
Systems Engineer, The
Mitre Corporation
This paper responds to a request by
the EPA Office of Environmental Engi-
neering and Technology (OEET) to
develop investment and operating costs
for a spray dryer flue gas desulf urization
(FGD) system retrofitted on several
boilers in two power stations of a
northeastern utility. These power
stations are among 23 power plants
involved in DOE-proposed coal conver-
sion actions under the Fuel Use Act of
1978. Based on budget estimates
received from a number of FGD system
vendors, total installed cost of this
system (which would control SOX and
paniculate emissions to present un-
controlled levels produced by firing No.
6 oil, would range from $153.9 million
($89/kW) to $204.0 million ($118/kW)
for a generalized northeast location,
with a significantly higher cost of
$295.8 million ($171/kW) for a highly
urbanized location typified by the northern
New Jersey or southern New York area.
Based on projected oil costs, coal costs,
plant renovation costs, and annualized
operating costs of the emission controls,
potential savings by coal conversion
would be $187 million annually (19
mills/kWh). Problems of FGD waste
disposal as well as site-specific problems
are also considered in this paper.
Mary E. Kelly, Chemical
Engineer, Radian Corporation
Radian Corporation is currently
conducting a survey of the commercial
and developmental status of dry FGD
systems in the U.S. for the EPA. This
paper discusses the current commercial
status of these systems, the focus of
current research and development activ-
ities, the potential advantages of dry
scrubbing over conventional wet scrub-
bing, and possible technical and eco-
nomic limitations of dry FGD.
For this study, dry FGD is defined as
any FGD process producing a dry
product for disposal. Dry FGD systems
are grouped according to system type:
(1) spray dryer based systems with ESP
or fabric filter collectors; (2) dry injection
systems, primarily with baghouse
collectors; and (3) other systems, in-
cluding those where alkaline material is
added directly to the fuel prior to
combustion.
Of the three types, only spray dryer
systems have been commercially ap-
plied. Ten utility (low sulfur coal)
systems had been sold as of May 1980.
Two industrial spray dryer based systems
have been sold. Higher sulfur coal (2 to 3
percent) is fired at the industrial sites.
The dry injection/baghouse collection
systems have been the subject of
numerous past and ongoing bench and
pilot scale studies, but no commercial
systems have been sold to date. Tech-
nologies involving combustion of a
coal/alkaline fuel mixture are still in the
early stages of development. Two
processes are currently under study:
combustion of coal/limestone pellets
and firing of a pulverized coal/limestone
fuel mixture in a low-NO* burner. 4
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* Nicholas J. Stevens, Manager
Chemical Process
Development, Research-
Cottrell, Inc.
Dry SC>2 scrubbing has emerged as an
attractive technology for flue gas
desulfunzation to meet NSPS. Pilot
testing by Research-Cottrell and others
indicates that a spray dryer followed by
a particulate collection device is a viable
alternative to wet scrubbing for low
sulfur coals.
Research-Cottrell and its spray dryer
supplier, Komline-Sanderson, have
conducted several investigations in
Texas and Colorado employing spray
dryer/fabric filter technology. This
paper describes some of the results of
the Research-Cottrell/Komline-
Sanderson pilot test work performed for
its commercial interests as well as for
an EPA-funded program. Key process
parameters that affect SOa removal,
including stoichiometry, flue gas tem-
perature, inlet SOa concentration, and
recycle are discussed. Other related
variables and the limits of dry S02
scrubbing are also considered.
, Edward L. Parsons, Jr.,
Engineering Consultant in
Product Design, Envirotech
Corporation
This paper describes the removal of
SO2 from boiler flue gases using two dry
FGD technologies: spray absorption and
dry injection. These two dry FGD
methods were investigated in an EPA-
sponsored pilot test program, in co-
operation with the City of Colorado
Springs at its Martin Drake Station. Flue
gas from an 85-MW pulverized-coal-
fired boiler at rates up to 34,000 m3/hr
(20,000 acfm) could be handled by the
spray absorber; up to 10,000 mVhr
(6,000 acfm) was available to the dry
injection system.
A comprehensive series of parametric
optimization tests, just completed by
Envirotech and Anhydro A/S, investi-
gated many aspects of the spray
absorption equipment/process inter-
face, including the spray absorber,
sorbent preparation and delivery system,
fabric filter, controls, and instrumenta-
tion. Process feasibility/demonstration
tests were conducted using slaked lime
and trona as primary sorbents. Recycled
process off-product, consisting of fly
ash and reaction products, and lime-
L stone with adipic acid additive were
jested as supplementary alkalis for the
reduction of primary sorbent consump-
tion. Absorber inlet temperature and
SOa concentration, reactant stoichi-
ometry, and approach to saturation at
the absorber outlet were varied as
process parameters. Test results, with
SOa removal rates of up to 94 percent,
are discussed in relation to published
analytical models.
The use of dry injection of pulverized
sodium compounds as a means of SOa
removal in conjunction with a fabric
filter was evaluated in a separate test
program. The reactants used were:
nahcolite, a naturally occurring sodium
bicarbonate; crude lake bed trona ore;
and trona upgraded by mining methods
to 70 percent sodium bicarbonate
content. SOa removal by reaction with
the dry pulverized sorbents was eval-
uated as a function of reactant stoichi-
ometry, baghouse inlet temperature,
and air-to-cloth ratio. Removal per-
formance as a function of stoichiometry
is compared to spray absorption results.
Only nahcolite produced performance
comparable to spray absorption, with
SOa removals of up to 90 percent.
Thomas B. Hurst, Manager,
Technology & Product
Development, Babcock &
Wilcox Co.
As part of a continuing development
program for dry scrubbing of SOa from
stack gases, Babcock & Wilcox designed
and constructed a 20 MW demonstration
unit at Pacific Power and Light
Company's Jim Bridger Station. The
objective in building this facility was to
demonstrate the operating capabilities
and performance of a dry scrubbing
system in large scale. Initial operation of
the dry scrubbing research (DSR) unit
commenced in late 1979 and is con-
tinuing. This paper deals with the
operating results learned to date from
this installation and from supporting
research activities.
James C. Dickerman, Program
Manager, Radian Corporation
The CAA Amendments of 1977
require EPA to coordinate and lead the
development and implementation of
regulations on air pollution. These
include standards of performance for
new and modified sources of pollution.
Specifically mentioned as a prioritized
pollution source in the August 21,1979,
Federal Register are industrial fossil-
fuel-fired steam generators. Accord-
ingly, the EPA has undertaken a series
of studies of industrial boilers and
pollution control systems with the
intent to promulgate standards of
performance based on the study results.
This paper presents the results of an
evaluation of the application of FGD
controls for industrial boilers. Factors
considered included development status,
environmental impacts, energy impacts,
and capital and operating costs of the
various FGD processes. The focus of
this paper is on the results of the
environmental, energy, and cost impact
analysis; it considers only those processes
that have been commercially applied.
Charles B. Sedman,
Environmental Engineer,
EPA-RTP
To support development of standards
of performance for new industrial
boilers, EPA initiated a test program on
industrial FGD applications to develop a
data base for SOa emissions control.
The program included continuous
monitoring of SOa, oxygen, and moisture
at both scrubber inlet and outlet.
Systems selected included sodium
scrubbing on oil and pulverized-coal
boilers, dual alkali systems on spreader-
stoker boilers, and a lime/limestone
application on spreader-stoker boilers.
All boilers fired relatively high (2.5 to 4.0
percent) sulfur fuels.
Performance of the industrial FGD
systems was generally superior to that
previously examined in the utility
sector, with respect to reliability and
mean SOa removal. Variability of
emissions from industrial FGD systems
was somewhat less than for utility
systems.
A vi N. Patkar, Project Manager,
PEDCo Environmental, Inc.
This paper summarizes the evaluation
of 12 commercial FGD processes for
their applicability to steam generators at
thermally enhanced oil recovery (TEOR)
sites in California. All the FGD processes
were compared on a' common design
basis with the sodium-throwaway
process currently used at the TEOR
sites. PEDCo concluded that the ammo-
nia, lime, limestone, double alkali, and
Chiyoda T-121 processes are very
competitive with the sodium-throwaway
process. The Department of Energy
(DOE) sponsored the study to assist the
oil companies in FGD process selection,
and DOE in planning future R&D
projects. The paper also presents the
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status of existing FGD systems in the
oilfields.
The primary concerns about the
sodium-throwaway process are the cost
of the alkali and waste disposal. The
paper reviews the current practices of
sodium-based waste disposal in indus-
trial applications which include disposal
to holding pond for evaporation, and
wastewater treatment and discharge to
city sewer, tailing pond, or waste wells.
The paper discusses two major options
for bleed stream treatment: oxidation
(oxidation/crystallization, or oxidation/
partial quenching of the flue gas) and
central regeneration (chemical or
thermal). The marketability of Na2S04,
gypsum, or sulfuric acid will determine
the applicability for a specific site.
Theodore G. Brna. Project
Manager Dry FGD,
EPA-RTP
Using methods specified by EPA for
compliance testing, the performance of
a dry S02 control system was evaluated.
The system tested treated flue gas from
the coal-fired boiler located at the
Amcelle Plant of the Celanese Fibers
Company in Cumberland, MD. This
system and its operation are described
briefly.
Results, based on 25 days of data
obtained over a 33-day period, showed
the mean S02 removal to be 69 percent,
with a range of 60 to 80 percent, except
for upsets, over the test period when the
sulfur content of the coal averaged 2
percent. Operating experience with the
spray-dryer/baghouse system is sum-
marized for the 5-month period ending
with the completion of testing on
September 30, 1980.
Robert D. Giammar, Associate
Manager Fuels and Combustion
Section, Battelle Columbus
Laboratories
This paper presents the results of a
three-phase program to evaluate emis-
sions and control technology for indus-
trial stoker boilers. The paper focuses on
the third phase "Limestone/Coal Pellet
Development," while summaries are
given of the first two phases, "Alternate
Fuels Evaluation" and "Control Tech-
nology Evaluation." Because SO2
appears to be the most troublesome
emission to control for stokers, a
limestone/high-sulfur-coal pellet was
developed and evaluated as a SO2.
control technique. Initially, this pellet
with a Ca/S molar ratio of 7 was
successfully fired in an 8-MW industrial
spreader-stoker boiler with S02 emis-
sions reduced by 75 percent. However,
from both an economical and opera-
tional standpoint, the amount of lime-
stone required had to be reduced to
correspond to a Ca/S molar ratio of 3 to
4. Furthermore, the mechanical proper-
ties of this pellet were inadequate to
withstand the severe stresses of an
industrial fuel-handling system. Ac-
cordingly, a research and development
effort was undertaken to refine the
pellet. A refined pellet, with a Ca/S
molar ratio of 3.5 , with appropriate
binders was produced that had similar
or improved physical characteristics of
raw coals. Additionally, economic
analysis indicates that this pellet can be
produced for approximately $15/ton
above the cost of high sulfur coal. This
refined pellet was fired in a 200-kW
laboratory spreader-stoker boiler,
achieving sulfur captures as high as 70
percent. However, when fired in the 8-
MW (25,000-lb steam/hr) stoker boiler,
sulfur captures on the order of 50
percent were achieved.
Franklin A. Ayer, compiler, is with Research Triangle Institute, Research Triangle
Park, NC 27709.
Julian W. Jones is the EPA Project Officer (see below).
The complete report, entitled "Proceedings: Symposium on Flue Gas Desulfu-
rization—Houston, October 1980."
Volume 1. (Order No. PB 81-243 156; Cost: $36.50, subject to change)
Volume 2. (Order No. PB 81-243 164; Cost: $38.00, subject to change)
will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
10
. S. GOVERNMENT PRINTING OFFICE: I98I/559-092/3323
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