United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/S9-87/004 May 1 987
SEPA Project Summary
Proceedings:
Tenth Symposium on
Flue Gas Desulfurization,
Atlanta, Georgia,
November 1986
B. B. Emmel, Compiler
The Tenth Symposium on Flue Gas
Desulfurization (FGD) was held in
Atlanta. GA. November 17-21, 1986.
This Symposium, jointly sponsored by
EPRI and EPA, had as its objective the
exchange of technical information re-
garding FGD systems and processes
applicable to utility and industrial
boilers.
Thirty-nine papers and 17 posters
were presented by EPA and EPRI staff
members, representatives of utility
companies, equipment manufacturers,
research and development companies,
and university researchers. Topics dis-
cussed in symposium presentations
included Federal and State clean coal
programs, the commercial status of
FGD (in the U.S., Europe, and Japan),
FGD economics, acid deposition issues,
industrial applications of FGD, wet FGD
additives, wet FGD operations and reli-
ability, spray dryer FGD, dry FGD tech-
nologies, and FGD by-product disposal
and utilization. Participants in a poster
session presented information on a
variety of topics including computer
applications, FGD chemistry, and
materials failure causes.
The proceedings are in two volumes.
Volume 1 contains papers from:
Session 1: Opening Session/
Clean Coal Programs
Session 2: Status of FGD
Sessions 3A/3B: FGD Econom-
ics: General/
Acid Deposition
Retrofit Applica-
tions
Session 4: Acid Deposition Issues
Session 5: Industrial Applications
Session 6: Wet FGD: Additives
Session 7: Poster Session
Volume 2 contains papers from:
Session 8: Wet FGD: Operations
and Reliability
Sessions 9A/9B: Spray Dryer
FGD/Dry FGD
Technologies
Session 10: FGD By-Product Dis-
posal/Utilization
This Project Summary was deve-
loped by EPA's Air and Energy Engi-
neering Research Laboratory. Research
Triangle Park. NC. to announce key
findings of the research project that is
fully documented in two separate
volumes of the same title (see Project
Report ordering information at back).
Introduction
This summary contains abstracts of 38
(of the 39} papers given at the Tenth
Symposium on Flue Gas Desulfurization.
Also included is title and author informa-
tion for 17 poster presentations.
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Volume 1
Session 1: Opening Session/
Clean Coal Programs
The Federal Clean Coal
Technology Demonstration
Program
C. L Miller,
U.S. Department of Energy,
Washington, DC
"Clean Coal Technology" (CCT) is a
generic term encompassing a variety of
techniques for reducing SO2, NOX, and/or
particulates. The technology may be de-
signed to be retrofitted on older boilers
without modification or be primarily in-
tended for new powerplant construction.
The technology may be able to achieve
new source performance standards
(NSPS) for one or more pollutants or
achieve a more significant reduction in
pollutant emissions. The technology may
be projected to provide either a modest
cost saving over current technology or a
substantial saving. The technology may
require several more years of develop-
ment or it may be ready for demonstration
now In the context of these numerous
technical and economic parameters,
virtually all of the Department of Energy's
(DOE) Coal R&D programs could be con-
sidered as constituting the Federal Clean
Coal Program This program in par-
ticular the "acid ram related research,"
costing over half a billion dollars during
the last 6 years (1982-1987) has
focused on new innovative technologies
that have the potential to remove SOX,
NOX, and particulate matter in greater
amounts, more cost effectively, and in a
more environmentally acceptable manner
than today's coal technology.
Ohio's Clean Coal Technology
David A. Berger,
Ohio Coal Development Office,
Columbus, OH
Ohio has one of the nation's largest
clean coal technology programs with more
than $600 million in total projects under-
way or in negotiation. In support of this
activity, the State of Ohio seeks to capi-
talize on its vast reserves of coal and its
coal-dedicated electric utility plant that
consumes in excess of 50 million tons/
year Accordingly, clean coal technologies
hold promise for improving market
demand for Ohio high sulfur coal and
reducing Ohio's SO2/NOX emissions. The
program's foremost priority is in ad-
vancing clean coal retrofit technologies
for application to existing coal-fired
boilers. Ohio coal's existing and principal
future market will continue to be in the
utility sector. However, retaining and ex-
panding Ohio coal's share of this market
depends directly on the pace at which
sulfur emission reduction technologies
are applied to existing coal-fired facilities.
Ohio's approach keys on competitively
solicited projects advanced by private
firms and research institutions. We
specifically seek "at risk" financial par-
ticipation by sponsors and encourage
technology demonstrations in "real
world" settings such as utility plants and
industrial power houses. Two types of
financial support are available from the
Office. Direct grant or loan support may
be awarded to projects from the $100
million State bond issue authorized for
this activity. Current policy restricts OCDO
support to a 30% share of demonstration
projects and a 50% share for pilot-scale
facilities. Additionally, Ohio utilities may
also submit projects for rapid expense
treatment by the Ohio Public Utilities
Commission. In this case, projects ap-
proved by the Office may be entitled to
cost recovery treatment in filings made to
the Commission every 6 months.
Illinois Coal Development
Program
John Mead,
Illinois Coal Development Program,
Springfield, IL
No written material furnished.
Session 2: Status of FGD
Evolution of FGD Technology
Alexander Weir, Jr.,
Southern California Edison
Company,
Rosemead, CA
In 1970, the National Academy of
Engineering (NAE) advised "there is an
urgent need for commercial demonstra-
tion: of FGD systems and established a
criteria of 'satisfactory operation on a
100 MW or larger unit for more than 1
year' as the definition of 'proven in-
dustrial-scale reliability' " The evolution
of technology from the "Large-Scale
Development Failures in Sulfur Oxides
Emission Control" (NAE) to the highly
efficient and reliable scrubbers of today
will be described.
Trends In Commercial
Applications of FGD
Michael T. Melia, R. S. McKibben,
and F. M. Jones,
PEI Associates, Inc.,
Cincinnati, OH; and
James L. Kelley,
U.S. Department of Energy,
Washington, DC
PEI Associates, Inc., has been reporting
on the status of utility flue gas desul-
furization (FGD) technology since 1974.
From 1974 to 1982, this effort was sup-
ported by the U.S. Environmental Protec-
tion Agency (EPA) under the direction of
the Air and Energy Engineering Research
Laboratory. In 1983 and 1984, it was
jointly sponsored by EPA and the Electric
Power Research Institute. Since January
1985, the program has been sponsored
by the U.S. Department of Energy (DOE),
Office of Environmental Analysis.
Information for this program is obtained
through regular contacts with owner/
operator utilities who are currently
operating (or planning to install) FGD
systems. Supplemental information is also
solicited from FGD system and equipment
suppliers, design/engineering firms,
research organizations, and regulatory
agencies.
The information collected is stored in
the Flue Gas Desulfunzation Information
System (FGDIS). This data base contains
computerized files of descriptive, design,
performance, and cost data on all the
FGD systems identified in the FGDIS. In
addition to being used to generate periodic
survey reports, the FGDIS is also available
for immediate access via remote terminal.
This latter feature allows private and
government users to access the FGDIS
directly at any time to conduct custom-
designed data analyses, to examine de-
tailed data that may be too specific for
convenient inclusion in the survey report,
or to review information that has been
loaded into the system but not yet pub-
lished in the semiannual report.
This paper summarizes the status of
FGD technology as of December 1985. It
highlights the status of the electric utility
power industry, projected growth of coal-
fired power generation, and the current
status of (and future trends in) FGD
application. It also addresses the per-
formance of utility FGD technology with
respect to both mechanical reliability and
S02 removal efficiency in high- and low-
sulfur coal applications, based on the
design generation (age). Developments
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in system design, current operating ex-
perience, and operating and maintenance
practices are discussed, as are impacts of
the various regulatory classifications on
FGD system design and operation
Status of Acid Rain and SO2 and
NOX Abatement Technology In
Japan
Jumpei Ando,
Chuo University,
Tokyo, Japan; and
Charles B. Sedman,
Air and Energy Engineering
Research Laboratory,
U.S. Environmental Protection
Agency,
Research Triangle Park, NC
Yearly SO2 emissions in Japan were
reduced from 5 million tons in 1967 to
1 2 million tons in 1985, while NOX
emissions were reduced from 2 million
tons in 1973 to 1.3 million tons in 1985
by strenuous efforts including the con-
struction of about 1500 flue gas desul-
furization (FGD) plants and 200 plants for
selective catalytic reduction (SCR) of NOX.
The air quality has been remarkably
improved but an appreciable decline of
needle-leaf trees is still observed in
certain regions rich in oxidants and acid
deposition. Efforts are continuing for
further abatement of the pollutants
FGD and SCR technolgies have been
fairly well established, giving a high reli-
ability of plant operation more than
99% for FGD and virtually 100% for SCR.
Recent efforts are directed mainly toward
improving existing technologies, rather
than developing new processes. Improve-
ments in FGD are seen in simplification
and cost reduction, automatic control,
and gas reheating. The life of SCR catalyst
has proved to be 4-5 years for coal-, more
than 6 years for oil-, and more than 8
years for gas-fired flue gases.
Assessment ofSO2/NOx Emission
Control Technology in Europe
William Ellison,
Ellison Consultants,
Monrovia, MD; and
Charles B. Sedman,
Air and Energy Engineering
Research Laboratory,
U.S. Environmental Protection
Agency,
Research Triangle Park, NC
Updated details are presented of major
flue gas desulfunzation (FGD) and de-
nitrification (de-NOx) installations in West
Germany for coal-fired boilers. The status
of technology in other European countries
is also presented. The paper: provides
an understanding of the principal types
of control system designs that have been
applied, outlines technological advance-
ments that have been achieved, and
reviews operating experience gained to
date in expanded use of FGD and NO,,
removal facilities in Europe in the 1980s.
Significant difference from FGD service
and practice in the U.S. and Japan is
described, and information that may help
improve operation and reliability of new
and retrofit FGD installations in the U.S.
is offered Principal topics include. 1) A
presentation of governmental emission
control requirements in Europe for new
as well as existing coal-fired sources; 2)
An overview of West German FGD and
de-NOx installations and purchase com-
mitments, including details of generic
processes applied, operating history and
current performance, and trends and
developments in technology utilization;
3) Control of industrial boilers; 4) Man-
agement of solid and liquid waste by-
products; and 5) Substantial activities in
other European countries.
Session 3A: FGD Economics:
General
Increasing the Clarity of Pollution
Abatement Cost Estimates
Jane A. Leggett and Ian M. Torrens,
Organisation for Economic
Cooperation and Development,
Paris, France; and
Edward S. Rubin,
Carnegie-Mellon University,
Pittsburgh, PA
Estimates of the costs of seemingly
similar systems to reduce emissions of
sulphur and nitrogen oxides (SOX and
N0y) often differ markedly when produced
by different countries or organisations.
To understand such differences requires
provision of adequate supporting informa-
tion on the methods and assumptions
used to develop those estimates. The
OECD has undertaken work recently both
to summarise which data are most es-
sential to provide, as well as to use
examples of those data to analyse why
cost estimates may differ so much. Data
were supplied by the Umweltbundesamt
(UBA) in Germany, the Electric Power
Development Company (EPDC) in Japan,
and the Electric Power Research Institute
(EPRI) in the U.S.; they cover similar flue
gas desulphurisation (FGD) and selective
catalytic reduction (SCR) installations on
coal-fired power plants. Initially, these
cost estimates vaired by factors of up to
5. After identifying differences in the
scope of the estimates and the economic
assumptions used, the OECD made the
original figures more consistent with each
other. This reduced the variation to factors
of 2 or less. The findings suggest that
additional care in providing supporting
data when reporting cost estimates may
help to reduce controversy in current
debates over the cost burdens imposed
by environmental regulations, and may
point to ways by which emission abate-
ment may be made more cost-effective.
Economic Evaluation of
Twenty-Four FGD Systems
R. J. Keeth and P. A. Ireland,
Stearns Catalytic Corporation,
Denver, CO; and
R. E. Moser,
Electric Power Research Institute,
Palo Alto, CA
This paper presents estimated costs for
24 throwaway and regenerable FGD
systems based on December 1982 dollars
and 1982-1986 process technology In
addition to costs, these systems were
evaluated for operability, technical merit,
and conYlriercial availability Most of the
FGD systems were evaluated for applica-
tion to a 4% sulfur coal fired in a hypo-
thetical 1000 MW (two 500 MW units)
power plant in Kenosha, Wl. A reference
plant was selected to ensure consistent
comparisons, and to increase the relative
accuracy of the costs presented. Dry FGD
systems were evaluated for a low sulfur
coal-fired plant. A flow sheet, material
balance, equipment list, system descrip-
tion, and utility consumption list form the
basis of each FGD evaluation. In each
case, critical equipment has been spared,
including one spare absorber module
Reheat of the flue gas (10°C) by indirect
steam heating has been included in all
wet systems.
Session 3B: FGD Economics: Acid
Deposition Retrofit Applications
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Plant Specific Retrofit Factors For
Lime/Limestone FGD and Lime
Spray Drying FGD
Thomas E. Emmel,
Radian Corporation,
Research Triangle Park, NC; and
Julian W. Jones,
Air and Energy Engineering
Research Laboratory,
U.S. Environmental Protection
Agency,
Research Triangle Park, NC
A major factor affecting the cost and
performance of S02 and NOX controls for
coal-fired power plants is trie difficulty
associated with retrofitting controls at
existing boilers. This paper presents the
results of an ongoing program conducted
under the National Acid Precipitation
Assessment Program (NAPAP) by the U.S.
EPA's Air and Energy Engineering Re-
search Laboratory. The objective of this
research program is to significantly im-
prove engineering cost estimates cur-
rently being used to evaluate the eco-
nomic effects of applying S02 and NOX
controls to existing coal-fired utility
boilers
The retrofit cost procedures used for
lime/limestone wet flue gas desulfuriza-
tion (L/LS FGD} and lime spray dryer flue
gas desulfurization (LSD FGD) is from the
Electric Power Research Institute (EPRI)
report entitled "Retrofit FGD Cost Esti-
mating Guidelines" (CS-3690). The
procedures make two types of cost ad-
justments to new plant costs cost adders
and cost multipliers. Cost adders account
for items not normally included in new
FGD system costs such as demolition
and relocation of existing facilities Cost
multipliers account for location factors
such as labor productivity/cost and
general retrofit factors such as access/
congestion and underground obstructions
Retrofit capital costs developed using
the EPRI detailed procedures are pre-
sented here for one boiler. The retrofit
costs were developed using information
obtained from a 1 -day site visit Retrofit
factors increased the base cost of building
a new FGD unit by 69-90% for the two
L/LS FGD cases and by 62-107% for the
two LSD FGD cases. Access and conges-
tion factors had the greatest effect and
typically resulted in 50% of the increase
over new plant costs. Scope adjustments
such as new chimney and paniculate
control equipment and long flue gas duct
runs also significantly increase FGD costs.
Evaluation of Flue Gas
Desulfurization As An Acid Rain
Control Strategy For Utility
Coal-Fired Boilers In The
State of Ohio
B. A. Laseke,
PEI Associates, Inc.,
Cincinnati, OH;
H. J. Johnson,
Ohio Environmental Protection
Agency,
Columbus, OH; and
D. A. Berger,
Ohio Coal Development Office,
Columbus, OH
The electric utility industry of the State
of Ohio was the subject of an integrated
research program sponsored by the U.S
Environmental Protection Agency and the
State of Ohio to evaluate air emission
control techniques for acid ram precursors
emitted by existing coal-fired utility
boilers. The Ohio utility industry was
selected for this investigation because of
its heavy reliance on coal as a primary
energy source, the relatively large num-
ber and associated generating capacity of
existing coal-fired plants, the wide variety
of plant design and operating configura-
tions, the emission of acid rain precursors
relative to national levels, and the
potentially significant impact of the ap-
plication of emission controls on the pro-
duction and cost of electrical power
Two general categories of emission
control techniques were considered
"active" (i.e., methods which involve the
addition of control equipment or systems)
and "passive" (i e , methods which do
not require the addition of control equip-
ment or systems) A variety of emission
control techniques are contained in each
category A number were identified as
being potentially suitable to Ohio boilers,
including lime/limestone flue gas desul-
furization (FGD), lime spray drying, duct
sorbent injection, limestone injection
multistage burner, fluidized-bed combus-
tion repowering, Iow-N0x combustion,
selective catalytic reduction, natural gas
reburning, physical coal cleaning, and
coal substitution.
Site-specific boiler, fuel quality, and
emission control system data were col-
lected for all the coal-fired utility boilers
in Ohio Data collection was facilitated by
selective site visits to plants representing
the larger boiler population in Ohio
Detailed boiler and plant data were col-
lected to estimate the technical feasibility,
cost, and anticipated performance of FGI
technology. The applicability of FGD fc
the Ohio utility boiler population wa
determined in terms of specific boile
costs, total cost, emission reduction, ani
overall cost effectiveness
The Tennessee Sfafe Acid Rain
(STAR) Project
William S. Bain,
Tennessee Valley Authority,
Chattanooga, TN
As a part of the STAR program ad
ministered by the Environmental Protec
tion Agency (EPA), the State of Tennessee
proposed that the Tennessee Valley
Authority (TVA) be used as a model tc
determine the effects of implementing
acid ram controls on a large multistate
utility
Four strategies for implementing S0:
reductions on the TVA system wert
analyzed a cap on emissions for the TV/!
system as a whole, statewide emission;
caps on TVA plants m the three state;
where TVA plants are located, mdividua
plantwide caps, and a plant emission-
rate strategy National reduction goals ol
5, 10, and 12 million tons (1 ton - 0 907
metric ton) of S02 from utilities only were
analyzed for high and low load electrical
growth projections in the TVA region.
Estimates were made of additional plant
capital investments, annual operating
costs, and percent increase in total
revenue requirements for each case
Session 4: Acid Deposition Issues
Status of the Acid Rain Debate
Brian J. McLean,
U.S. Environmental Protection
Agency,
Washington, DC
Acid ram is both an issue (subject to
considerable debate in many forums) and
a problem (subject to intensive research
and analysis) We have found it useful
to make the distinction between acid rain
(the issue) and acid rain (the problem)
because it helps one think through and
respond to what is clearly a very complex
subject.
The acid ram problem is characterized
by deposition of acidic compounds which
can damage aquatic systems and may be
damaging forests and materials Through
the National Acid Precipitation Assess-
ment Program (NAPAP) and other re-
search efforts we are trying to learn the
-------
extent of this damage, the mechanisms
that cause it, and the prognosis for future
damage We will then be in a position to
formulate a solution to the problem.
Status of the National Acid
Precipitation Assessment
Program
Patricia M. Irving,
National Acid Precipitation
Assessment Program,
Washington, DC
The Acid Precipitation Act of 1980 (Title
VII of the Energy Security Act of 1980,
Public Law 96-924) established the Inter-
agency Task Force on Acid Precipitation
to implement a national program to
increase the understanding of the causes
and effects of acidic deposition The
National Acid Precipitation Assessment
Program (NAPAP) was thus established
to manage research efforts to reduce
uncertainties for policymakers in the
assessment of acidic precipitation effects.
The program includes research within six
federal agencies and is grouped in seven
categories 1) Emissions and Controls, 2)
Atmospheric Chemistry, 3) Atmospheric
Transport and Modeling, 4) Air Quality
and Deposition, 5) Terrestrial Effects, 6)
Aquatics Effects, and 7) Materials.
The major research efforts of the pro-
gram include investigations to reduce the
uncertainties associated with the rela-
tionship between emissions and deposi-
tion and the relationship between deposi-
tion and effects Major areas of research
include comprehensive inventories of
emissions, atmospheric chemistry, atmo-
spheric modeling, and deposition and air
quality monitoring and effects on agri-
cultural crops, plantation and natural
forests, watersheds, and materials
Session 5: Industrial Applications
A Review of Proposed Industrial
Boiler SO2 NSPS: Engineering
Analyses of FGD Technology
Dale A. Pahl and
Charles B. Sedman,
Air and Energy Engineering
Research Laboratory,
U.S. Environmental Protection
Agency,
Research Triangle Park, NC; and
Edward F. Aul, Jr.,
Radian Corporation,
Research Triangle Park, NC
The United States Environmental Pro-
tection Agency recently proposed new
source performance standards (NSPS) to
control air emissions of sulfur dioxide
(SO2) from new industrial boilers The
major provisions of these standards would
require compliance with both a percent
reduction requirement and an emission
limit Boilers subject to the standards
would be required to reduce SO2 emis-
sions by 90%. Boilers firing coal would be
required to meet an emission limit of 1 2
Ib S02/106 Btu* of heat input, boilers
firing oil would be required to meet a
limit of 0.8 Ib S02/106 Btu of heat input
A significant portion of the standard
development process for this NSPS in-
cluded engineering analyses of FGD
systems This paper reviews selected
results of these analyses, including the
performance, cost, and reliability of FGD
systems and the secondary environmental
impacts that may be associated with their
use (*) 1 lb/106 Btu = 429 95 ng/J
Session 6: Wet FGD: Additives
Three Years of Organic Acid Use
at San Miguel
Robert Cmiel,
San Miguel Electric Cooperative,
Inc.,
Jourdanton, TX; and
Daniel Seeman (Consultant),
Charlotte, NC
This paper summarizes scrubber results
since commercial plant operation in 1982.
The organic acid mechanism has his-
torically been called a buffer The authors
believe that this mechanism can be more
easily understood and accepted if pre-
sented as a mass transfer catalyst
Maintenance dollars continue to be
spent on linings The absorber's natural
rubber has blistered, and organic acid
has been detected in the extracted blister
fluid Work m progress is investigating
possible improvements in linings, process
chemistry, organic acid consumption, and
day-to-day procedures
The scrubber at San Miguel has been
operated with organic acid since Novem-
ber 1983 Average consumption is about
14 Ib organic acid per ton* SO2 The
actual to theoretical consumption ratio is
about 7 The initial skepticism of a
chemical fix in a traditional mechanical
power plant is gone In 1986, scrubber
operation with organic acid continues as
routine (*) 1 Ib = 0 454 kg, 1 ton = 907.2
kg
Enhancement of Wet Limestone
Flue Gas Desulfurization By
Organic Acid/Salt Additives
John C.S. Chang,
Acurex Corporation,
Research Triangle Park, NC; and
Theodore G. Brna,
U.S. Environmental Protection
Agency,
Air and Energy Engineering
Research Laboratory,
Research Triangle Park, NC
Experimental data from recent pilot
plant tests of organic acids/salts as
additives to enhance the performance of
wet limestone flue gas desulfunzation
processes are presented The technical
and economical feasibilities of five dif-
ferent organic acids and salts were
assessed by comparing new data with
previous data Sodium formate appeared
to be a promising alternative for natural
oxidation when compared with adipic acid
and dibasic acids However, unsatisfactory
solids dewatermg properties were ob-
tained with sodium formate in forced
oxidation when the system pH was main-
tained above 5 35
Comparison of the Effectiveness
of FGD Additives For SO2
Removal Enhancement and
Additive Consumption
James B. Jarvis,
David R. Owens, and
Dorothy A. Stewart,
Radian Corporation,
Austin, TX
This paper presents the results of an
FGD organic acid additive test program
using EPRI's 5 cfm* bench-scale FGD
system The objective of the tests was to
compare the effectiveness of organic
additives with respect to S02 removal
and additive consumption Additives were
selected which were either in, or showed
the potential for, commercial use The
tested additives included adipic acid, a
waste solid containing adipic acid, two
waste streams containing a mixture of
dibasic acids (DBA), a waste stream con-
taining maleic acid, and formic acid In
addition, two components of DBA, glutanc
and succmic acid, were also tested. (*) 1
cfm = 0.00047 mVs
Most of the tests were performed under
natural oxidation conditions (30-40%
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oxidation) with limestone reagent Two
additional tests were performed with the
DBA mixtures to evaluate the effect of
forced oxidation and slurry temperature
on additive consumption
Results are presented showing OS2
removal as a function of additive con-
centrations, and additive consumption as
a function of acid type and the process
variables tested The consumption data
include measurements of both chemical
degradation and solids coprecipitation or
occlusion Based on the test data, the
DBA and adipic acid consumption rates
for full-scale systems have been esti-
mated. These estimates are compared to
measured consumption data from four
full-scale systems and two pilot systems.
Thiosulfate Additives for
Lime/Limestone Scrubbing
Gary T. Rochelle,
Y. Joseph Lee, and
Rosa N. Ruiz-Alsop,
The University of Texas at Austin,
Austin, TX;
John C.S. Chang,
Acurex Corporation,
Research Triangle Park, NC; and
Theodore G. Brna,
U.S. Environmental Protection
Agency,
Air and Energy Engineering
Research Laboratory,
Research Triangle Park, NC
Powdered sulfur, ammonium thiosul-
fate, and sodium polysulfide have been
tested as alternatives to sodium thiosul-
fate for inhibiting sulfite oxidation in
limestone slurry scrubbing In bench-
scale experiments, powdered sulfur re-
acted with calcium sulfite at rates
adequate to permit in situ synthesis of
thiosulfate Use of powdered sulfur would
be 15-25% the cost of sodium thiosulfate
solution In pilot plant tests, ammonium
thiosulfate and sodium polysulfide were
effective at 25 and 50% the cost of sodium
thiosulfate, respectively Odor is caused
by the release of hydrogen sulfide from
sodium polysulfide
Session 7: Poster Session
The Integrated Air Pollution
Control System Design and Cost-
Estimating Model (Version II)
P. J. Palmisano and B. A. Laseke,
PEI Associates, Inc.,
Cincinnati, OH; and
N. Kaplan,
U.S. Environmental Protection
Agency,
Air and Energy Engineering
Research Laboratory,
Research Triangle Park, NC
FGD Cost-Estimating Computer
Model
R. J. Keeth,
P. A. Ireland, and
K. S. Van Winkle,
Stearns Catalytic Corporation,
Denver, CO; and
R. E. Moser,
Electric Power Research Institute,
Palo Alto, CA
Computer Programs For FGD
Data Management and Operation
Mark J. Hebets,
Craig A. Berry,
Robert W. Donaldson,
M. Timothy Johnston, and
Dorothy A. Stewart,
Radian Corporation,
Austin, TX
Simulation of Spray Dryer
Absorber For Removal of SO2
From Flue Gases
Matthew M. Maibodi,
Thomas L. Pearson,
Robert M. Counce, and
Wayne T. Davis,
The University of Tennessee,
Knoxville, TN
Interpretation of Gads Data
Carl V. Weilert,
Douglas B. Hammontree, and
Paul N. Dyer,
Burns & McDonnell Engineering
Company,
Kansas City, MO
Leaning Brick Stack Liners
H. S. Rosenberg and C. W. Kistler,
Battelle Columbus Division,
Columbus, OH;
E. R. Dille,
Burns & McDonnell,
Kansas City, MO; and
R. E. Moser,
Electric Power Research Institute,
Palo Alto, CA
100+ MW Demonstration of Dry
Sodium Injection Flue Gas
Desulfurization
David W. Ablin,
FMC Corporation,
Schaumburg, IL;
Joseph J. Hammond,
Dale B. Watts, and
Ronald L. Ostop,
Colorado Springs (Colorado) Dept.
of Utilities; and
Richard G. Hooper,
Electric Power Research Institute,
Palo Alto, CA
Operating Experience of a
Retrofitted Dry Scrubber at an
Industrial Steam Plant
Roy Baldwin,
Rockwell International,
Columbus, OH;
John Buschmann, Flakt, Inc.,
Knoxville, TN; and
Rodger Goffredi,
Stone & Webster Engineering
Corporation,
Denver, CO
Planning Maintenance For Flue
Gas Desulfurization Systems
L. N Davidson,
G. P. Miller, and
C. P. Wedig,
Stone & Webster Engineering
Corporation,
Boston, MA; and
R. E. Moser,
Electric Power Research Institute,
Palo Alto, CA
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SOz/NOx Removal By Ca(OH)2 FGD Materials Failure Causes
Paul Chu and Gary T. Rochelle,
The University of Texas at Austin,
Austin, TX
Combined SOz/NOx Removal
From Flue Gas By Electron Beam
Dennis J. Helfritch,
Cottrell Environmental Sciences,
Somerville, NJ
Removal of SOZ and NOX From
Stack Gases By Electron Beam
Irradiation
David 0. Ham and
James C. Person,
Physical Sciences, Inc.,
Andover, MA
Description and Mechanism of
Limestone FGD Operating
Problems Due to Aluminum/
Fluoride Chemistry
James B. Jarvis,
Robert W. Farmer, and
Dorothy A. Stewart,
Radian Corporation,
Austin, TX
Enhancing Double-Alkali and
Lime/Limestone Flue-Gas-
Desulfurization Chemistries To
Promote Nox Removal
John B.L Harkness,
Richard D. Doctor, and
C. David Livengood,
Argonne National Laboratory,
Argonne, IL
A Review of Methods For
Increasing Limestone Reagent
Fineness For Flue Gas
Desulfurization
Roland K. Seward and
Kenneth A. Brame,
Kennedy Van Saun Corporation,
Danville, PA
Peter F. Ellis II,
Radian Corporation,
Austin, TX; and
Robert E. Moser,
Electric Power Research Institute,
Palo Alto, CA
Shawnee 10-MW Spray Dryer/
Electrostatic Precipitator Pilot
Plant
Richard A. Runyan,
Joe B. Barkley,
James G. Patterson, Jr., TVA,
Chattanooga, TIM;
L. Jack Henson, TVA,
Muscle Shoals, AL, and
Steve F. Newton, TVA,
West Paducah, KY
Volume 2
Session 8A: Wet FGD: Operations
and Reliability (Part 1)
Advanced Computer Control
System With On-Line FGD
Process Simulator
Ken Kondo,
Pure Air Corporation,
Philadelphia, PA; and
N. Shinoda,
S. Hagiwara,
S. Kouno,
Y. Watanabe, and
Y. Nonogaki,
Mitsubishi Heavy Industries, Ltd.,
Tokyo, Japan
A state-of-the-art computer control
system for FGD plants has been devel-
oped Operation of this system has
lowered FGD power consumption by as
much as 12% by optimizing the process
control under varying boiler loads
This system, the ASC-1000, controls
absorber slurry recirculation flow rate
and reagent feed rate in response to
boiler load and process chemistry status
estimated by a built-in process simulator.
It also possesses substantial operation
and maintenance management software
designed to minimize operator errors,
reduce staff requirements, and enhance
the quality of component equipment
maintenance
This system has been retrofitted on
four operating scrubbers at the Nakoso
Power Station, Joban Joint Power Com-
pany, Ltd After 1 year of successful
operation, the following results were
obtained:
Under a boiler load change rate of
5% per minute, the control system
maintained stable desulfunzation
performance.
This high degree of desulfunzation
control enabled more flexibility in
adjustments to the absorber slurry
recirculation flow rate Power sav-
ings of 26 MWh per day resulted for
each 600 MW unit retrofitted and,
additionally, reagent savings of 5%
were achieved
Materials of Construction
Overview
G. H. Koch,
Battelle Columbus Division,
Columbus, OH
An overview of the materials of con-
struction presently used m flue gas
desulfunzation (FGD) systems is pre
sented Initially, the construction matenais
which are commonly used m the various
scrubber components are reviewed Then,
utility experience with several construc-
tion materials m significant scrubber
components is discussed The compo-
nents of interest are prescrubbers,
absorbers, outlet ducts, and stacks Based
on the discussion of the materials of
construction in these components, it is
concluded that a wide variety of materials
can be used throughout an FGD system
ranging from low cost organic linings in
absorbers to ceramic linings or highly
alloyed metal in ventun scrubbers and
outlet ducts Cost effective materials can
be selected by carefully considering
scrubber operating conditions and the
environments in the various components
Design and Operation of A Wet
Process Based Flue Gas
Desulfurization System Without
Reheat
John E. Smigelski,
New York State Gas and Electric
Corporation,
Binghamton, NY; and
Lewis A. Maroti,
Dynatech Scientific, Inc.,
Cambridge, MA
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In 1977, EPRI published "Stack Gas
Reheat for Wet Flue Gas Desulfurization
Systems " It gave three categories of
reasons for stack gas reheat (1) to
enhance plume rise and dispersion of
pollutions, (2) to avoid a visible plume,
and (3) to avoid downstream condensation
and corrosion. Included in Category 3 is
"rainout," acid mist fallout, or stack liquid
discharge in the vicinity of the stack It
was reported that at that time nearly all
operating systems included a reheat
system utilizing between 045 and 5.7%
of the boiler system energy input There
was only a limited amount of experience
without reheat, primarily on small units.
There are now approximately 130 in-
dividual FGD systems, 104 of which use
stack gas reheat. The median temperature
rise for reheated flue gas is about 2°C.
While bypass reheat is the most popular
form of reheat, 75 units employ an
installed external source of reheat Of the
26 FGD systems that are designed to
operate without reheat, 16 have the
capability to bypass flue gas. The know-
ledge gained through a decade of FGD
operating experience has enabled many
wet FGD systems to operate without the
expense and problems of an installed
reheat system There is a strong economic
incentive for operating without an in-
stalled reheat system This paper provides
an overview of the design process and
the decision to operate a wet stack noting
some of the new knowledge of the last
decade The methodology of a modeling
investigation to develop the design of a
wet duct/stack system for Somerset
Station is discussed along with imple-
mentation and the history of the operation
without reheat
Session 8B. Wet FGD: Operations
and Reliability (Part 2)
Improvements In FGD System
Reliability at Springfield IL City
Water, Light, and Power's
Dallman Station
0. W. (Buddy) Hargrove,
David DeKraker, and
Dorothy A. Stewart,
Radian Corporation,
Austin, TX; and
Ed Riordan,
Brad Buecker, and
Don Myers,
City Water, Light, and Power,
Springfield, IL
Dallman Unit 3 is equipped with a wet-
limestone double-loop FGD system Since
its start-up in 1980, this FGD system has
experienced problems associated with
solids buildup in the absorber and mist
eliminator packing. In past operation, this
pluggage eventually restricted gas flow
and unit load.
In 1984, CWL&P and EPRI began a
program to improve the reliability of the
Dallman system. Changes have been
made in the limestone preparation area,
limestone reagent control strategy, and
the process chemistry of the upper
absorber loop The effects of these
changes are reported and compared with
results from a similar system at Texas
Utilities Generating Company's Martin
Lake Steam Electric Station
Investigation of Mist Eliminator
Reliability Problems at Utah
Power and Light's Hunter Station
G. Betenson,
Utah Power and Light Company,
Salt Lake City, UT; and
0. W. Hargrove, Jr.,
C. A. Brown,
D. P. DeKraker, and
Dorothy A. Stewart,
Radian Corporation,
Austin, TX
Utah Power and Light (UP&L) has been
experiencing mist eliminator reliability
problems at Hunter Units 1 and 2 The
FGD systems on these units are lime-
based with vertical flow mist eliminators
in the top of the vertical towers These
mist eliminators plug with slurry which
requires extensive cleaning or replace-
ment of the mist eliminators during each
annual outage In addition, slurry buildup
on the outlet ducts and in the stack is
severe.
UP&L and EPRI have begun a program
to improve the reliability of the mist
eliminator system at Hunter 1 and 2 The
changes made in the wash system involve
wash water quality and wash duration
and frequency. Changes have also been
made in the lime slaking area and in low-
load operating philosophy to reduce water
consumption in the FGD system Water
consumption at Hunter is extremely
important since the plant must operate at
zero discharge
Session 9A: Spray Dryer FGD
Limestone Spray Drying
Absorption For SO2 Control
Ebbe Joens,
Karsten Felsvang, and
Raman Madhok,
A/S Niro Atomizer,
Copenhagen, Denmark
Flue gas desulphunzation by spray
drying absorption is now a well estab-
lished technology worldwide with more
than 12,000 MWe contracted for
Spray dryer absorption or dry scrubbing
has attracted much attention during the
last 8-9 years due to its simplicity, cost
effectiveness, and dry end-product
Lime, which is the preferred reagent
for spray dryer adsorption systems in
operation, can, however, be a major
operating cost disadvantage of spray dryer
absorber systems
This paper describes pilot plant test
work carried out to develop the use of
limestone instead of lime in new as well
as in existing spray dryer absorption
systems
Niro Atomizer and other research or-
ganizations have, over the last 3-4 years,
tried to use finely divided limestone as
absorbent in the spray dryer absorber
process The major problems preventing
the successful use of limestone have
been the lack of sufficient SO? removal
and difficult transport and handling pro-
perties of finely divided limestone These
handling and transport properties have
virtually eliminated limestone from use
in a spray dryer absorber system
This paper identifies the problems with
limestone handling and discusses pilot
plant tests that have led to a successful
solution of the problems mentioned
At current development status, at least
75-80% S02 removal can be achieved for
a medium sulphur coal (1500 ppm S02)
with a limestone stoichiometry of 1 5
Comparison of Dry Scrubbing
Operation of Laramie River and
Craig Stations
J. B. Doyle,
B. J. Jankura, and
R. C Veterrick,
Babcock & Wilcox Company,
Alliance, OH
This paper provides an overview and
comparison of the operation of the first
two commercial dry sulfur removal (DSR)
-------
systems designed, built, and installed by
The Babcock & Wilcox Company (B&W).
The first unit was installed at the
Missouri Basin Power Project, Laramie
River Station, and the second unit was
installed at the Colorado Lite Craig Station.
Both of these units are very similar in
regards to the basic design principles, but
there are a number of unique features
that have had a significant effect on the
operation of the systems. This paper
focuses on these differences and their
effects. The major area of discussion
centers on the chemical composition of
the fly ash and the type of particulate
collector used.
Dry Scrubber Operating
Experience at The North Valmy
Station
Lori Smith,
Sierra Pacific Power Company,
Reno, NV; and
Len Garrity and Rodger Goffredi,
Stone & Webster Engineering
Corporation,
Denver, Co
The North Valmy Station is a coal-fired
power plant in north-central Nevada. It is
owned by Sierra Pacific Power Company
and Idaho Power Company. Unit 2 at
North Valmy is a 267 MW unit that
utilizes a General Electric turbine, Foster
Wheeler boiler, Combustion Engineering
dry scrubber, and Flakt baghouse.
The dry scrubber system has been in
operation since March 1985. It has
achieved anticipated SO2 removal effici-
encies and lime consumption rates while
experiencing relatively few operating
problems. This paper reviews the equip-
ment design and explores in detail the
operating experience to date
Joy/Niro Utility Spray Dryer FGD
Operating Experience An
Update
J. R. Donnelly,
3. W. Tracy, and
Vl. T. Quach,
Joy Manufacturing Company,
_os Angeles, CA;
C S. Felsvang,
A/S Niro Atomizer,
Copenhagen, Denmark;
3. L Ericksen,
Basin Electric Power Cooperative,
Bismarck, ND; and
J. G. Eutizi,
Alamito Co.,
Springerville, AZ
Since the last FGD symposium in June
1985, four additional Joy/Niro utility
spray dryer absorption (SDA) FGD systems
have started up, bringing the number of
commercial operating units to eight,
representing a total of 2650 MWe of
generating capacity. Three of these units
have undergone compliance/perform-
ance testing: Springerville Generating
Station Unit 1, Antelope Valley Station
Unit 2, and VKG Kraftwerk Durnrohr Unit
1. The fourth unit, Wyodat Generating
Station Unit 1, is the first retrofit applica-
tion of an SDA system upstream of an
existing electrostatic precipitator (ESP)
and is currently in the initial performance
test phase.
Each of these units incorporates unique
design features. Antelope Valley Unit 2 is
the first multi-module SDA system de-
signed for -8°C approach to saturation
temperature operation. Durnrohr Unit 1
employs single-field ESPs for precollectmg
fly ash and four-field ESPs for final dust
removal. Springerville Unit 1 is designed
to operate at -8°C approach to saturation
temperature out of the SDA with reheat
prior to the reverse air bag filter
System descriptions and results from
tests of these units are presented. Start-
up problems are reviewed and solutions
discussed. Operation and availability data
of earlier started up units are updated
Session 9B: Dry FGD Technologies
Status of Calcium-Based Dry
Sorbent Injection SO2 Control
Richard Rhudy,
Mike McElroy, and
George Offen,
Electric Power Research Institute,
Palo Alto, CA
The various processes that use dry,
calcium-based sorbent injection for SO2
control are described and their current
status reviewed. There are five basic pro-
cesses, two associated with the furnace
(Furnace Sorbent Injection (FSI) and con-
vective pass injection), and three associ-
ated with injection into the ductwork
downstream of the air heater (in-duct dry
injection, in-duct spray drying, and Hybrid
Pollution Abatement System HYPAS).
Combinations of these processes are also
possible.
Pilot-Scale Studies ofSO2
Removal by the Addition of
Calcium-Based Sorbents
Upstream of a Particulate Control
Device
Gary Blythe,
Radian Corporation,
Austin, TX;
Verle Bland and Cameron Martin,
KVB, Incorporated,
Denver, CO; and
Michael McElroy and
Richard Rhudy,
Electric Power Research Institute,
Palo Alto, CA
EPRI is developing potentially low cost
FGD retrofit technologies that involve the
addition of calcium-based reagents to
humidified flue gas just upstream of a
particulate control device. Pilot-scale tests
have been conducted with both fabric
filter and ESP particulate collection
devices. Two methods of reagent addition
have been investigated: flue gas humidi-
fication with separate dry injection of
sorbents, and in-duct "spray drying"
where a lime-based slurry is sprayed
directly into hot (149°C) flue gas.
Results show the S02 removal potential
for dry sorbent injection for both particu-
late collector types, and for in-duct spray
drying upstream of the ESP Also pre-
sented are the effects of a number of
operating variables including approach to
adiabatic saturation, calcium-to-sulfur
molar ratio, solids recycle, reagent type,
performance additives, and steam/sor-
bent comjection. Finally, results are pre-
sented which indicate the effects of these
sorbent injection processes on particulate
collection efficiency
Results show that, when humidifying
the flue gas to within a -7°C approach to
adiabatic saturation, conventional hy-
drated lime injected upstream of a fabric
filter at a 2 1 Ca/S ratio can achieve 50-
55% S02 removal. Comjection of steam
with the lime increased the SO2 removal
to nearly 70%. For injection of hydrated
lime upstream of an ESP, S02 removal at
a -7°C approach to adiabatic saturation
and a 2:1 Ca/S ratio was 30-35%. Steam
coinjection increased S02 removal to 40-
45%. In-duct spray drying upstream of an
ESP achieved 50% S02 removal at a
16°C approach to adiabatic saturation
and a 1.6 1 Ca/S ratio.
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Current Status of In-Duct
Scrubbing Technology
Kenneth R. Murphy and
Eric A. Samuel,
General Electric Environmental
Services, Inc.,
Lebanon, PA; and
Henry W. Pennline,
U.S. Department of Energy,
Pittsburgh, PA
The promulgation of revised stack
height regulations and possible changes
under consideration in the National
Ambient Air Quality Standards could
require older power plants to develop
new compliance strategies and upgrade
emission control systems In such situa-
tions, a low cost, moderate removal ef-
ficiency, flue gas desulfunzation (FGD)
technology could maintain the cost ef-
fectiveness of these plants. Such a
technology was selected by the Depart-
ment of Energy for demonstration in its
Acid Rain Precursor Control Technology
Initiative. The process, identified as In-
Duct Scrubbing (IDS), applies the rotary
atomizer techniques developed for lime
based spray dryer FGD while utilizing
existing flue gas ductwork and particulate
collectors. IDS technology is anticipated
to result in a dry desulfurization process
of moderate removal efficiency (50%) for
high sulfur coal-fired boilers. The critical
elements for successful application are
(1) adequate mixing for efficient reactant
contact, (2) sufficient residence time to
produce a non-wetting product, and (3)
appropriate ductwork cross sectional area
to prevent deposition of wet reaction
products before particle drying is com-
plete. The ductwork in many older power
plants, previously modified to meet 1970
Clean Air Act requirements for particulate
control, usually meets these criteria.
The paper presents the IDS technology
and the status of the jointly sponsored
IDS pilot study which is to be tested on
the American Electric Power System.
Development and Pilot Plant
Evaluation of Silica-Enhanced
Lime Sorbents For Dry Flue Gas
Desulfurization
Wojciech Jozewicz,
Claus Jorgensen, and
John C.S. Chang,
Acurex Corporation,
Research Triangle Park, NC; and
Charles B. Sedman and
Theodore G. Brna,
U.S. Environmental Protection
Agency,
Air and Energy Engineering
Research Laboratory
Research Triangle Park, NC
EPA's efforts to develop low cost, retro-
fittable flue gas cleaning technology
include the development of highly reactive
sorbents Recent work addressing lime
enhancement and testing at the bench-
scale followed by evaluation of the more
promising sorbents in a pilot plant are
discussed here.
The conversion of Ca(OH)2 with S02
increased several-fold compared with
Ca(OH)2 alone when Ca(OH)2 was slurried
with fly ash first and later exposed to S02
in a laboratory packed bed reactor
Ca(OH)2 enhancement increased with the
increased flyash amount Diatomaceous
earths were very effective reactivity pro-
moters of lime-based sorbents Differen-
tial scanning calorimetry of the promoted
sorbents revealed the formation of a new
phase (calcium silicate hydrates after
hydration) which may be the basis for the
observed improved S02 capture.
Flyash/lime and diatomaceous earth/
lime sorbents were tested in a 100 mVh
(58 cfm) pilot facility incorporating a gas
humidifier, a sorbent duct injection sys-
tem, and a baghouse. The inlet SO2 con-
centration range was 1000-2500 ppm.
With once-through dry sorbent injection
into the humidified flue gas [approach to
saturation 10-20°C (18-36°F) in the
baghouse], the total S02 removal ranged
from 50 to 90% for a stoichiometric ratio
of 1 to 2. Recycling the collected solids
resulted in a total lime utilization ex-
ceeding 80-90%. Increased lime en-
hancement was also investigated by the
use of additives.
Dry/Semi-Dry Flue Gas
Desulfurization Using The Lurgi
Circulating Fluid Bed Absorption
Process
Rolf Graf,
Lurgi GmbH,
Frankfurt, West Germany; and
John D. Riley,
Lurgi Corporation,
River Edge, NJ
The dry/semi-dry process, the Cir-
culating Fluid Bed Absorption, is pre-
sented with its main characteristics and
process features This process is similar
to FGD with the well-known Spray Dry(
but has some additional advantages:
slurry atomizer is not necessary,
higher solid residence time in th
absorber,
higher mass transfer rate betwee
SO2 gas and lime feed,
capable of reducing any S02 leve
resulting from coals even with vei
high sulfur content to legislate
levels, and
a deduster type (baghouse or ESI
can be selected independent of ar
stipulated desulfurization rate.
Information on the planning, erectioi
and operation of the first four contracte
units, particularly of the first dry FG
plant which has been in operation sine
November 1984, is furnished.
Furthermore, the disposal routes avai
able to this process are outlined.
Session 10: FGD By-Product
Disposal/Utilization
Engineering and Design Aspecti
Disposal and By-Product
Utilization of FGD Residues
Richard W. Goodwin,
Environmental Consultants
Associates,
Upper Saddle River, NJ
This paper presents both the theoi
and application of engineering and mar
aging systems designed to dispose <
and/or recover residues from wet-lim«
and limestone-based FGD systems. Th
work described is based on investigation
conducted on pilot and operating FG
systems. The treatment of FGD sludg
involves both primary and seconder
dewatering; i e , thickening/settling an
filtration or centrifugation. Selection an
sizing of such equipment depends on th
physical characteristics of the incomin
FGD slurry. Of primary importance is th
particle size and distribution. Based o
work performed for both domestic an
foreign electric utilities, the relationshi
of particle size and distribution to optim;
dewatering is presented From a dispos;
consideration, achieving maximum de
watering is important to avoid thixotropi
conditions during transport Even whe
blended with fly ash, the resultant mixtur
may be thixotropic due to inadequat
solids content; this is particularly true fc
thiosorbic lime sludges A transportabiht
analysis technique is presented to detei
mine upset conditions When free lime i
10
-------
added to or present in the fly ash, the
probability for premature setup or poz-
zolanic behavior is increased due to lime
solubilization. Achieving maximum de-
watering prevents this condition while
ensuring a transportable mixture. Wall-
board manufacturers require a 90+%
solids content in the oxidized sludge
product. Achieving such a high degree of
dewatermg requires attaining both large
(i.e., > 50 /urn) particle size and a
normalized distribution Attaining just
large particle sizes is insufficient to ensure
satisfying end-user requirements. In addi-
tion to attaining the desired percent solids,
by-product utilization criteria include
minimizing: halogen salts (i.e , chlorides
and fluorides), unreacted limestone, and
inerts/acid insolubles. Attaining a nor-
malized distribution facilitates washing-
out these undesirable salts and prevents
accumulation of fines (i.e. unreacted
CaCO3 and inerts). The use of hydroclones
is presented as a means of achieving
such requirements. The use of a hydro-
clone is explained in both theory and
practice. A knowledge of the feedstock
characteristics enables utilization of such
fundamental relationships as the Tromp
Curve and practical computer application
(i.e., material balances) to predict both
the underflow characteristics to the
secondary dewatermg device and over-
flow quality to the FGD recycle The paper
presents a practical mathematical and
graphical concept to predict the resultant
in-situ geotechnical properties for both
oxidized and blended FGD sludge. The
particle size and S04/SO3 ratio are cor-
related to strength and permeability. At-
taining optimum moisture content to
achieve both maximum placement density
and to prevent premature pozzolanic
behavior is described. The relationships
indicate how to predict achieving the
desired pozzolanic reaction and resultant
properties while minimizing lime addition,
if required The paper discusses opera-
tional considerations for systems designed
to dispose of and to utilize FGD residues
A simple technique to monitor the degree
of oxidation is described which has been
incorporated into several utility operating
procedures This procedure is useful in
determining auto-oxidation of the FGD
slurry (i e , typical of low sulfur applica-
tions) facilitating equipment operational
modifications. The analysis of Free Avail-
able Lime provides the operator with a
forewarning of premature setup condi-
tions. Recommendations are made for
continuous monitoring to ensure product
quality. The use of on-line particle size
distribution devices is discussed.
Effect of Wet Lime FGD
Operating Conditions On
Improving Particle Size and
Dewatering of Sludge
Frank Baczek,
EIMCO Process Equipment
Company,
Salt Lake City, UT;
Lewis B. Benson,
Dravo Lime Company,
Pittsburgh, PA;
R. Mark Golightley,
Ohio Edison Company,
Akron, OH; and
Jim Wilhelm,
Codan Associates,
Sandy, UT
Lime is used extensively as reagent in
high-sulfur wet FGD systems. Magne-
sium-enhanced lime gives superior per-
formance in scrubbing S02 from high-
sulfur flue gases but sometimes results
in sludge which is difficult to dewater.
Recent field tests on full-scale wet
lime FGD systems and other work suggest
that FGD operating conditions in addition
to liquor chemistry can cause improve-
ment or deterioration of sludge solids
particle size and dewatering. Lower slurry
solids concentration and shorter residence
time in the scrubber recycle tank where
crystallization takes place produced larger
sludge particles. An improvement in
thickener performance resulted when
larger particles were produced.
This paper discusses observations of
the effect of scrubber operating conditions
including slurry solids concentration and
liquor chemical composition on sludge
particle size and thickener performance
in two full-scale wet magnesium-en-
hanced lime FGD systems. Laboratory
data are also presented which relate
thickener capacity, filtration rates, filter
cake solids, and slurry viscosity to particle
size for three magnesium-enhanced lime
sludges. Included is discussion of factors
that affect FGD crystallization that relate
to these observations.
Design Considerations For FGD
Solids Disposal/Utilization At A
Power Plant With Limited Space
J. A. Hengel and R. G. Chapman,
Black & Veatch,
Kansas City, MO; and
D. W. Wilterdink,
Grand Haven Board of Light and
Power,
Grand Haven, Ml
This paper discusses the problem of
FGD solids disposal at Grand Haven's
J. B. Sims Unit 3, a plant with limited
space, and describes the disposal/utiliza-
tion options considered and decisions
made during the initial design stages.
Byproduct disposal options included
trucking fly ash and scrubber solids to an
offsite landfill, use of fly ash for roadbase
material, and use of scrubber solids for
wallboard manufacturing. Uncertain
market conditions for these byproducts
required that the new unit design include
provisions to use all of these options. A
summary is presented of the design
development and the current operating
practices, which include the production
and sale of wallboard quality gypsum as
a byproduct of the SO2 removal process.
Evaluation of Washing
Alternatives For FGD Byproduct
Gypsum Production
J. David Colley,
Sterling M. Gray, and
Dorothy A. Stewart,
Radian Corporation,
Austin, TX; and
James A. Wilhelm,
Codan Associates,
Sandy, UT
The results of an economic and technical
evaluation of four commercially available
alternatives for washing gypsum produced
from flue gas desulfurization (FGD) are
presented in this paper. Two types of
vacuum filtration were evaluated hori-
zontal belt and rotary drum. A horizontal
solid bowl continuous feed centrifuge
and a vertical bowl batch feed centrifuge
were tested also. The pilot-scale de-
watering devices were fed thickener
underflow from the Martin Lake Gen-
erating Station FGD system. The scrub-
bers at Martin Lake are forced oxidized
and routinely produce wallboard quality
gypsum. Chloride was spiked into the
thickener underflow slurry prior to being
fed to the dewatering machines to deter-
mine the washing efficiency of each. Test
variables included wash rate, chloride
concentration, cake thickness, and
throughput for the filters In addition to
these variables, RPM was also examined
for the centrifuges. Samples of the pro-
77
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duct were analyzed for chloride to mea-
sure the wash efficiency for each set of
conditions. An economic evaluation based
on the results of the testing was com-
pleted. The economic study compares the
capital and operating costs for three dif-
ferent types of dewatering systems for
producing wallboard quality gypsum
horizontal filter, rotary filter, and vertical
bowl centrifuge. The equipment is sized
to handle material from a 500 MW unit
firing a high sulfur bituminous coal.
Design of Waste Management
Systems For Calcium Spray
Dryer FGD Technology
Anthony P. Klimek,
Baker/TSA, Inc.,
Beaver, PA;
A. Gwen Eklund,
Radian Corporation,
Austin, TX;
Gaynor W. Dawson,
ICF Northwest,
Richland, WA; and
Dean M. Golden,
Electric Power Research Institute,
Palo Alto, CA
Calcium spray dryer FGD technology is
a viable SO2 control technology available
to the electric utility industry. This tech-
nology currently is utilized at utility gen-
erating stations burning lignite or low-
sulfur subbituminous coal. This paper
presents information concerning the
waste and waste management systems
associated with this technology. Informa-
tion concerning waste properties, waste
management systems at stations cur-
rently using (or planning to use) this
technology, and a brief assessment of
the federal, state, and local regulations
that control the management and dis-
posal of these wastes is presented. A
typical waste management system for a
full size generating station using calcium
spray dryer technology is described. This
system was developed based on typical
waste properties, experience at other
stations, and regulatory requirements.
This information will provide guidance
and assist utilities in assessing the
operational and economic impacts of
waste management when considering
calcium spray dryer FGD technology.
Influence of Particulate Control
On Waste Management:
Integrated Environmental Control
Pilot Plant Results
J. Edward Cichanowicz,
Electric Power Research Institute,
Palo Alto, CA; and
Patrick M. Maroney and
Steve A. Davidson,
Brown & Caldwell Engineers,
Denver, CO
Results with the EPRI 2.5 MW(e) In-
tegrated Environmental Control Pilot
Plant (IECPP) compare the influence of
paniculate penetration on scrubber waste
production and properties. Tests compared
a fabric filter/wet scrubber and ESP/wet
scrubber, the latter operated to simulate
1979 NSPS, 1971 NSPS, and pre-NSPS
units. Tests were conducted with low
sulfur coal at 400 ppm; flue gas spiking
could be used to increase S02 to 2000
ppm. Scrubber waste was dewatered in a
thickener and vacuum belt filter (to 55%
solids content), and fixed with fly ash.
Results show that scrubbers retrofit to
pre-NSPS ESPs and forced to operate in
zero-discharge could experience solid
waste handling problems and increased
operating costs. Specifically, particular
penetration above 0.10 lb/106 Btu* can
(a) reduce reagent utilization to 80%
causing waste handling/reliability prob
lems; (b) increase solid waste production
and (c) reduce SO2 removal. These results
are attributable to inhibited limestone
dissolution from an aluminum/fluorid*
compound. For both low sulfur and simu
lated high sulfur test conditions, allowing
waste water discharge to purge alumi
num/fluoride content restored perform
ance to design levels. (*) 1 lb/106 Btu :
429.95 ng/J.
Particulate control efficiency also af
fected solid waste physical properties
The fabric filter/wet scrubber producec
the lowest solid waste permeability (10"'
cm/sec). ESP operation at 1979 NSPE
and pre-1971 NSPS ESPs increased solic
waste permeability to 107 and 10'
cm/sec, respectively.
These results are most significant foi
scrubber retrofit to units with pre-NSPJ
ESPs. High sulfur coal scrubbers coulc
be affected depending on water cycles o
concentration and accumulation of alumi
num/fluoride compounds. This problerr
could become significant with the in
creasing trend to restricted wate
discharge.
Barbara B. Emmel is with Radian Corporation, Research Triangle Park, NC
27709.
Julian W. Jones is the EPA Project Officer (see below).
The complete report consists of two volumes entitled "Proceedings: Tenth
Symposium on Flue Gas Desulfurization, Atlanta, Georgia, November 1986:
"Volume 1," (Order No. PB 87-166 609/AS; Cost: $36.95. subject to change)
"Volume 2," (Order No. PB 87-166 617/AS; Cost: 36.95, subject to change)
The above reports will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
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