EPA-650/2-75-057-1
October 1975
Environmental Protection Technology Series
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
WILL COUNTY STATION, COMMONWEALTH EDISON CO.
U.S. Environmental Protection Agency
Office of Research and Development
Washington, D. C.204fiO
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EPA-650/2-75-057-1
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
WILL COUNTY STATION, COMMONWEALTH EDISON CO.
by
Gerald A. Isaacs and Fouad K. Zada
PEDCo-Environmental Specialists, Inc .
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
Contract No. 68-02-1321, Task 6i
ROAP No. 21ACX-130
Program Element No. 1AB013
EPA Project Officer: Norman Kaplan
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, North Carolina 27711
Prepared for
U. S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D. C. 20460
October 1975
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EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection
Agency and approved for publication. Approval does not signify that
the contents necessarily reflect the views and policies of the Environ-
mental Protection Agency, nor does mention of trade names or commer-
cial products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/ 2-75-057-i
11
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ACKNOWLEDGMENT
This report was prepared under the direction of Mr.
Timothy W. Devitt. Principal authors were Dr. Gerald A.
Isaacs and Mr. Fouad K. Zada.
Mr. Wade H. Ponder, former EPA Project Officer, had
primary responsibility within EPA for this project report.
Information and data on plant operation were provided by Mr.
Mike Trykoski, Commonwealth Edison Company, and by Mr. Jack
Stewart, Babcock and Wilcox Company during and subsequent to
the survey visit. Mr. Charles D. Fleming was responsible
for editorial review of this report.
The authors appreciate the efforts and cooperation of
everyone who participated in the preparation of this report.
111
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TABLE OF CONTENTS
Page
ACKNOWLEDGMENT ill
LIST OF FIGURES vi
LIST OF TABLES vi
SUMMARY Vii
1.0 INTRODUCTION 1-1
2.0 FACILITY DESCRIPTION 2-1
3.0 FLUE GAS DESULFURIZATION SYSTEM 3-1
3.1 Process Description 3-1
3.1.1 Limestone Milling Facility 3-3
3.1.2 Particulate and SO2 Scrubber Modules 3-3
3.1.3 Sludge Disposal System 3-9
3.2 Installation Schedules 3-10
3.3 Cost Data 3-11
4.0 FGD SYSTEM PERFORMANCE 4-1
4.1 Performance Test Runs 4-1
4.2 Start-Up and Operating Problems and Solutions 4-3
APPENDIX A PLANT SURVEY FORM A-l
APPENDIX B PLANT PHOTOGRAPHS B-l
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LIST OF FIGURES
Figure
3.1
3.2
3.3
General Flow Diagram of the FGD System on
Will County Unit 1
Flow Diagram of a Typical FGD Module
Limestone Sludge Stabilization Facilities
Page
3-2
3-4
3-9
LIST OF TABLES
Table
2.1 Pertinent Data on Plant Design, Operation
and Atmospheric Emissions - Will County
Station
3.1 Summary of Data: Particulate and SO2
Scrubbers
3.2 Summary of Data: FGD System Hold Tanks
3.3 Typical Pressure Drop Across Components of
FGD Module
3.4 Estimated Capital Investment Costs of Will
County Unit 1 Wet Scrubber
3.5 Estimated Annual Operating Costs of Will
County Unit 1 Wet Scrubber
4.1 Will County Unit 1 Wet Scrubber Module A
Preliminary Test Data - May 18-23, 1972
4.2 Will County Unit 1 Wet Scrubber Module A
Preliminary Test Data - July and August 1972
4.3 Will County Unit 1 Wet Scrubber Module A
Preliminary Test Data - August 8-12, 1972
4.4 FGD System Availability Factors
Page
2-3
3-7
3-7
3-8
3-12
3-13
4-2
4-4
4-5
4-6
VI
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SUMMARY
Boiler 1 at the Will County Station of Commonwealth
Edison is a wet-bottom coal-fired boiler rated at 146 MW
capacity (net). The boiler was manufactured by Babcock and
Wilcox (B&W) and was installed in 1955. In 1973, the
boiler burned coal with a gross heating value of 9463 BTU/lb
and ash and sulfur contents of 10 percent and 2.1 percent,
respectively. The wet limestone-base flue gas desulfurization
(FGD) system on the boiler was also designed and installed
by B&W. The FGD process is based on contacting the sulfur
dioxide in the flue gas with a limestone-base slurry in the
FGD modules. The FGD system, placed in service on February
23, 1972, consists of two FGD modules, limestone handling
and milling facilities and a sludge treatment and stabilization
unit. Each module consists of a venturi scrubber followed
by a two-stage absorption tower.
Shortly after start-up and during the initial debugging
stage, both modules were plagued with numerous problems. As
a result, in May 1973, Commonwealth Edison shut down Module
B, which was a turbulent contact absorber (TCA), to concen-
trate on solving the problems of Module A, which uses the
countercurrent tray absorber. The performance of this
-------
module has steadily improved, and its availability has
increased since its initial start-up. Operating problems
have been mainly confined to the demister and reheater
units. Additional spray nozzles have been installed to keep
the demister free of slurry deposits. Until an outage in
November 1973, the reheater bundle slowly deteriorated as a
result of pitting corrosion which occurred during down
periods when steam was not maintained in the coils. Modifi-
cations to Module B included the replacement of the two TCA
beds with two perforated trays and new moisture separators.
The estimated capital cost for the FGD system on Will
County Unit 1 is $115/KW (net), including $13/KW for sludge
treatment. Annualized operating cost is estimated to be 12
mills/KWH. These figures represent the cost of a difficult
retrofit application, where the scrubbers were installed in
an extremely congested space and under a construction
schedule which required large overtime expenditures. These
operating costs are based on an assumed boiler capacity
factor of 35 percent.
Pertinent plant and FGD operational data are summarized
in the following table.
Vlll
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SURVEY OF FGD DATA - WILL COUNTY STATION
Unit rating, MW (net)
Fuel
BTU/lb
Ash, %
Sulfur, %
FGD vendor
Process
New or retrofit
Start-up date
FGD modules
Efficiency, %
Particulates
so2
Make-up water
gpm/MW (net)
Sludge disposal
Unit cost
146
Coal
9463 (10,293 design)
10
2.14 (4 design)
B&W
Wet limestone
Retrofit
February 1972
Two
99.7 (99 design)
82 - 90 (83 design)
2.08
2.08
Stabilized sludge disposed of
in on-site, clay-lined
temporary disposal basin
Capital estimate: $16,800,000
Annualized estimate: $5,214,000
ix
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1.0 INTRODUCTION
The Industrial Environmental Research Laboratory,
(formerly the Control Systems Laboratory) of the U.S. Environ-
mental Protection Agency (EPA) has initiated a study to
evaluate the performance characteristics and degree of
reliability of FGD systems on coal-fired utility boilers in
the United States. This report on the Will County Station
of Commonwealth Edison is one of a series of reports on such
systems. It presents values of key process design and
operating parameters, describes the major start-up and
operational problems encountered at the facility and the
measures taken to alleviate such problems, and identifies
the total installed and annualized operating costs.
This report is based upon information obtained during a
plant inspection on June 28, 1974 and on subsequent data
provided by Commonwealth Edison personnel.
Section 2.0 presents pertinent data on facility design
and operation including actual and allowable particulate and
S02 emission rates. Section 3.0 describes the FGD system
and Section 4.0 analyzes FGD system performance.
1-1
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2.0 FACILITY DESCRIPTION
The Will County Station of Commonwealth Edison Company
is located on the Chicago Sanitary and Ship Canal near the
town of Romeovilie, in Will County, Illinois. The area is
heavily developed with many large refineries and chemical
plants. Canal traffic consists mainly of barges carrying
bulk cargo. Coal and limestone are delivered to the Will
County Station by barges using this canal.
The Will County Station has four electric power generating
units with a total rated capacity of 1147 MW. Only Unit I,
a wet-bottom coal-fired boiler is retrofitted with an FGD
system. The capacity ratings for Unit 1 are 167 MW (gross),
153 MW (net, without FGD), and 146 MW (net, with FGD system
operating). The boiler was manufactured by Babcock and
Wilcox and installed in 1955.
The coal presently being burned has an average gross
heating value of 9463 BTU/lb. The ash and sulfur contents
are 10 and 2.1 percent, respectively.
The boiler is fitted with an electrostatic precipitator
(ESP) manufactured by Joy Western Precipitation Division.
The ESP has a 79 percent actual particulate collection
efficiency and is generally used only when the FGD system is
out of service.
2-1
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The maximum particulate emission allowed under Illinois
Regulation No. 2-2.11 is 0.6 Ib/MM BTU of heat input to the
boiler. The maximum emission allowed under the Illinois
Public Commission Board Regulation No. 203(G)(1)C effective
May 30, 1975, is 0.2 Ib/MM BTU. The present particulate
emission rate from the FGD system is equivalent to 0.06
Ib/MM BTU.
Sulfur dioxide emissions are limited by the Illinois
Public Commission Board Regulation No. 204(C)(1)A. Under
this regulation, effective May 30, 1975, the maximum allowable
SO- emission rate will be 1.8 Ib/MM BTU. The present S02
emission rate, based on 82 percent removal efficiency and a
maximum coal sulfur content of 4 percent, is equivalent to
1.5 Ib/MM BTU. Table 2.1 presents pertinent plant and
emission rate data.
2-2
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Table 2.1 PERTINENT DATA ON PLANT DESIGN, OPERATION
AND ATMOSPHERIC EMISSIONS - WILL COUNTY STATION
Boiler data
Item
Rated generating capacity, MW (net)
Average capacity factor (1973), %
Served by stack No.
Boiler manufacturer
Year placed in service
Maximum coal consumption, ton/hr
Maximum heat input, MM BTU/hr
Stack height above grade, ft
Flue gas rate - maximum, acfm
Flue gas temperature, °F
Emission controls:
Particulate
so2
Particulate emission rates:
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
SO- emission rates:
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
146
52.8
1
Babcock & Wilcox
1955
85
1600
350
770,000
355
Venturi scrubber
Venturi scrubber
and countercurrent
tray absorber
0.2a
0.06
1.8a
1.5b
Applicable emission rates by May 30, 1975.
Based on 82 percent FGD efficiency and maximum coal sulfur
content of 4 percent.
2-3
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3.0 FLUE GAS DESULFURIZATION SYSTEM
3.1 PROCESS DESCRIPTION
The wet limestone FGD system at the Will County Station
was placed in service on February 23, 1972. As illustrated
in Figure 3.1 the system includes two FGD modules. Limestone
handling and milling facilities and a sludge treatment and
stabilization unit also are part of the FGD facility, but
are not shown in Figure 3.1. Each module originally included
a venturi scrubber followed by an absorber tower and a
booster fan. Upon start-up several operational problems
were encountered in both modules. In May 1973, Module B was
shut down and so the concentrated efforts could be exerted
on Module A to solve the problems. A principal difference
between the two modules is that Module B was originally
equipped with a moving plastic ball turbulent contact
absorber (TCA) whereas Module A was equipped with a B&W
perforated tray absorber. Module B has subsequently been
modified by B&W to the perforated tray configuration.
The limestone milling system, the particulate and S0~
scrubbing and absorbing modules, and the sludge treatment
and disposal facilities are described in the following
sections.
3-1
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LIMESTONE
BUNKER
CO
I
to
ABSORBER
RECIRCULATION
PUMPS
RECYCLE AND
MAKE-UP WATER
SETTLING
POND
Figure 3.1 General flow diagram of the FGD system on will County Unit 1.
(Courtesy of Commonwealth Edison Company)
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3.1.1 Limestone Milling Facility
The limestone milling system consists of a limestone
rock conveyor, two 260-ton capacity limestone bunkers, two
wet ball mills, and a slurry storage tank. The total storage
capacity of the limestone bunkers is equivalent to the lime-
stone required for 48 hours of FGD system operation at full
load. The limestone is 97.5 percent calcium carbonate and
contains 0.99 percent magnesium carbonate and 0.48 percent
silica. It is received in coarse ground form (about 1/2
inch or less) and is finely ground to 95 percent through 325
mesh in two wet ball mills; each ball mill is rated at 12
tons per hour. A limestone slurry containing 20 to 35
percent solids is discharged from the mills. The slurry is
piped to a 4-hour capacity (62,500 gallon) storage tank,
which supplies the limestone slurry to the FGD modules.
3.1.2 Particulate and SC^ Removal Modules
Each module was designed for 385,000 acfm throughput at
355°F and handles 50 percent of the total boiler exhaust gas
flow. The liquid and gas flow patterns through a typical
module are shown in Figure 3.2. Flue gas passes through the
existing ESP, and enters the venturi scrubber. In the
venturi, the flue gas is contacted with jets of slurry
sprayed from high-pressure nozzles located on each side of
the rectangular venturi throat. Particulate removal efficiency
is maintained by regulating the pressure drop across the
adjustable venturi throat. Pressure drop across the venturi
3-3
-------
to
I
TO SLUDGE
WASTE
POND
VENTURI
PUMPS
FLUE GAS
VENTURI
VENTURI
RECIRClkATION
TANK
CLEAN GAS TO
DEMISTER AND REHEATER
SUMP
u
ABSORBER
ABSORBER
RECIRCULATION
TANK
FROM MILL
SYSTEM
ABSORBER
PUMPS
Figure 3.2 Flow diagram of a typical FGD module,
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is maintained at about 9 inches of water. Gas velocity
through the venturi is about 135 ft/sec.
The quenched flue gas and slurry droplets pass through
the sump where the large gas velocity reduction causes the
slurry droplets to drop out of the flue gas stream. The gas
then flows upward through the SO- absorber tower and passes
through two perforated trays. The trays are wetted with
limestone slurry sprays located above the trays. The trays
provide an extended wetted surface for absorption of SO- by
the circulated slurry. Superficial velocity through the
absorber is 12.2 ft/sec. Pressure drop through the two
trays is six inches of water. Total system pressure drop is
25 inches of water.
The cleaned flue gas passes upward through a two-stage
Z-shape demister. Fine mist droplets coalesce on the surface
of the demister vanes and drip back into the tower. The
demister is equipped with two sets of wash water headers.
The lower demister is washed continuously from below by 125
gpm of fresh water. It is also washed intermittently from
above by 1000 gpm of pond water for 90 seconds every two
hours. The gas then enters the reheater unit, where its
temperature is raised from 128°F to about 165°F. Reheat is
necessary to prevent condensation in the fans, ducts and the
existing brick-lined stack. The reheat also imparts plume
buoyancy to suppress plume visibility.
3-5
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The bare tube reheater has nine sections. The bottom
three sections are made of 304 stainless steel (316L
stainless steel - Module B); the other six sections are made
of Corten steel. Each reheater has four soot blowers. Heat
is supplied by saturated steam at 350 psig from Unit 1.
Condensate from the reheater is returned to the steam circuit
at the deaerator heater.
To compensate for the draft loss across each module, a
booster fan was installed at the suction side of the existing
boiler I.D. fan.
There are two slurry tanks for each module; the ab-
sorber recirculation tank to which fresh limestone is added
and the venturi tank. Spent limestone slurry (sludge) is
discharged from the venturi pump loop. These two tanks are
interconnected by a common tie in such a way that the spent
liquor from the absorber recirculation tank flows into the
venturi circulation tank. Each tank is fitted with an agitator
and pumps. The slurry recirculation rate in the absorber is
about 11,000 gal./min for a liquid-to-gas ratio (L/G) of 35
gal./lOOO ft of gas at 120°F. The recirculation rate
through the venturi is 5800 gal./min for an L/G of approxi-
mately 20 gal./lOOO ft3 of gas at 125°F. Tables 3.1, 3.2
and 3.3 summarize pertinent operating and design parameter
values, plus design specifications for major process equip-
ment.
3-6
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Table 3.1 SUMMARY DATA:
PARTICULATE AND S02 SCRUBBERS
Item
Venturi scrubber
SO. absorber
tower
L/G ratio,
gallons/1000 acf
Superficial gas
velocity, ft/sec
Equipment sizes, ft
Equipment internals
Material of con-
struction
Shell
Internals
14.5
120
8 x 26 x 16 high
(throat 21 x 1.8)
adjustable rectangular
throat blocks
carbon steel coated
with plasite
Kaocrete
35.5
12.2
16 x 24 x
60 high
two perforated
trays
corten steel,
rubber lined
316L SS
Table 3.2 SUMMARY DATA: FGD SYSTEM HOLD TANKS
Item
Total number
of tanks
Retention time
at full load
Temperature, °F
pH
Solids concen-
tration, %
Specific gravity
Material of
construction
Venturi
scrubber
recirculation
tank
2
8 min ea.
128
5.9
8
1.102
rubber- lined
carbon steel
SO- absorber
towers
recirculation
tank
2
4 min ea.
128
5.8
8
1.049
rubber- lined
carbon steel
FGD system
sludge
tank
100
5.9
35-40
Limestone
slurry
make-up
tank
1
48 hrs.
Ambient
7
35
3-7
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Table 3.3 TYPICAL PRESSURE DROP ACROSS
COMPONENTS OF FGD MODULE
Equipment
Venturi scrubber
S02 scrubber tower
Demister
Reheater
Ductwork
Total FGD system
Pressure drop,
inches, W.G.
9
6
1
6
3
25
3.1.3 Sludge Disposal System
Figure 3.3 is a flow diagram of the present sludge
treatment and disposal system used at the Will County Station.
The spent slurry from the two venturi loops is discharged to
a 65-ft-diameter thickener. During emergencies and when the
thickener is down, the slurry can be discharged directly to
the pond. The overflow from the thickener is returned to
the pond, but the underflow is stabilized by mixing it with
lime and fly ash. About 200 Ibs of lime and 400 Ibs of fly
ash are used per ton of dry solids of sludge. The fixed
sludge is transported by concrete mixing trucks to a small
on-site clay-lined basin for solidification. The stabilized
sludge solidifies in about one week, depending on weather
conditions.
3-8
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(jO
i
HOPPER
TO ON-SITE
DISPOSAL BASIN
RECYCLED THICKENER
OVERFLOW AND POND
SUPERNATANT TO MODULE
SCRUBBER SLUDGE POND
THICKENER UNDERFLOW
Figure 3.3 Limestone sludge stabilization facilities
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3.2 INSTALLATION SCHEDULES
Retrofitting the boiler presented several physical
construction problems as well as work scheduling problems.
The physical problems were due to space limitation and
resulted in the sandwiching of the scrubbers between the
boiler house and the service building with a substantial
cantilever. Complex ductwork was also required.
B&W was authorized to begin the detailed engineering on
September 3, 1970. To meet the project schedule, purchase
orders were placed immediately for such long delivery items
as fans, pumps, scrubbers, limestone mills and Corten steel
plates. By July 1971, the bulk of the major equipment was
on-site.
Equipment erection was scheduled to begin April 1,
1971, but was not underway until May 17, 1971 because of
foundation problems. Soil core samples between the service
building and the boiler house indicated that a slab-type
foundation would be inadequate to support the FGD system column
loads. Seven caissons had to be installed ranging in depth
from 33 to 102 feet. Even with the late start, the equipment
erection was substantially completed by the end of February
1972. Initial start-up (Module B) took place on February 23,
1972.
A detailed project construction schedule is shown in
Appendix A, page A-5.
3-10
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3.3 COST DATA
The estimated capital costs for the FGD system at Will
County Station are presented in Table 3.4. It should be
pointed out that this system is a full-size prototype
demonstration unit erected under an accelerated overtime
schedule and backfitted on a unit with little available
space.
Estimated annual operating costs for the FGD system on
Will County Unit 1 are presented in Table 3.5. A 35 percent
capacity factor was used in determining the annualized costs
of 10.43 mills/KWH.
3-11
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Table 3.4 ESTIMATED CAPITAL INVESTMENT COSTS OF
WILL COUNTY UNIT 1 FGD SYSTEM
Gas Cleaning System
B&W venturi/absorber
Equipment erection
Electrical equipment and
erection
Foundations
Limestone handling system
Professional engineering
Mill and SO. buildings
Structural steel
Miscellaneous equipment
Sludge Treatment System
Thickener, pumps and truck
loading station
Temporary disposal basin
Uncommitted
Total cost
Cost per kilowatt, without
sludge treatment
Cost per kilowatt, with
sludge treatment
Direct cost
$ 2,928,000
5,556,000
1,210,000
923,000
204,000
965,000
193,000
375,000
946,000
$13,300,000
$ 432,000
141,000
1,127,000
$ 1,700,000
$15,000,000
$ 91
$ 103
Indirect 'cost
$ 1,600,000
$ 200,000
$ 1,800,000
$ 11
$ 12
Total cost
$14,900,000
$ 1,900,000
$16,800,000
$ 102
$ 115
Notes:
(1) The cost per kilowatt is based on 146 MW net capability (167 MW -14 MW
aux. power - 7 MW scrubber power = 146 MW net).
(2) This investment represents the cost of a unit retrofitted with an FGD
system in an extremely congested space on a construction schedule
requiring large overtime expenditures.
(3) Indirect cost is 12% of direct cost and includes such items as: certain
professional services, interest during construction, payroll taxes,
state use taxes, employee pensions and benefits, and administrative and
legal expenses.
3-12
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Table 3.5 ESTIMATED ANNUAL OPERATING COSTS OF
WILL COUNTY UNIT 1 FGD SYSTEM
(capacity factor 35%)
Gas Cleaning System
Carrying charge on
$14,900,000
Property tax on
$14,900,000
Limestone @ $5.00/ton
Labor
Auxiliary power
Reheat Steam
Maintenance
Sludge Treatment
Carrying charge on
$1,900,000
Property tax on
$1,900,000
Sludge treatment
@ $17.10/ton
Total Cost
Annual cost
$ 2,280,000
298,000
230,000
88,000
454,000
82,000
447,000
$ 3,879,000
$ 291,000
38,000
1,006,000
$ 1,335,000
$ 5,214,000
$/ton of coal
8.40
1.10
0.85
0.32
1.67
0.30
1.65
14.29
1.07
0.14
3.70
4.91
19.20
«/MM BTU
54.0
5.6
4.3
1.6
8.6
1.5
8.4
73. OC
5.5
0.7
19.0
25.2$
98.2*
Mills/KWB
(net)
5.09
0.67
0.51
0.20
1.01
0.18
1.00
8.67
0.65
0.08
2.25
2.98
11.65
Notes:
Assumed life for system - 14 years.
Sludge treatment cost does not include hauling to an off-site disposal
site nor the disposal site fee
Assumes that the FGD system availability equals boiler-turbine availability.
Capacity factor of 35% assumed for above calculations.
Total Costs Assuming Alternative Capacity Factors
Mills/KWH
Annual cost $/ton of coal C/MM BTU (net)
e 50% capacity factor 5,838,000 15.05 77.0 9.13
8 65% capacity factor 6,463,000 12.81 65.2 7.77
3-13
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4.0 FGD SYSTEM PERFORMANCE
4.1 PERFORMANCE TEST RUNS
During May and August 1972, preliminary performance
tests were made by B&W. The outlet dust loading, during the
May test, varied from 0.0073 to 0.0334 grains per standard
cubic foot (gr/scf) of gas. The guaranteed outlet dust
loading was 0.0248 gr/scf. The outlet sulfur dioxide values
are not applicable to the guarantee because a varying blend
of western low-sulfur coal and Illinois high-sulfur coal was
being burned. The SO2 removal efficiency was 90 percent
under normal conditions, and 67 percent under conditions
when limestone feed to the unit was intentionally reduced.
A partial summary of the test data is presented in Table
4.1.
During the August test runs, the outlet dust loading
varied from 0.0213 to 0.0278 gr/scf. These results were
obtained while burning Illinois high-sulfur coal. A partial
summary of the test data appears in Table 4.2. SO, removal
efficiencies are comparable with the May test results. Some
S02 removal efficiency data are presented in Table 4.3.
All test runs were made on Module A with the existing
ESP deenergized.
4-1
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Table 4.1 WILL COUNTY UNIT 1 WET SCRUBBER MODULE A
PRELIMINARY TEST DATA - MAY 18 - 23, 1972
Test number
Date
Load, MW
Gas flow, acfm x 10
Scrubber system, pressure
difference, inches H.O
Dust inlet, gr/DSCF
Dust outlet, gr/DSCF
SO. inlet, ppm
SO, outlet, ppm
SO. removal efficiency, %
Absorber slurry solids
concentration, %
Absorber pH
1
5-18
113
335
24.5
0.0232
1145
67
94
3.4
6.5
2
5-18
113
355
29
0.0944
0.0079
1140
75
93
5.2
6.3
3
5-19
114
335
21
0.1440
0.0073
B90
294
67
5.5
7.4 .
4
5-19
115
340
25
0.1470
0.0298
930
35
96
5.2
6.3
5
5-20
111
335
24
0.1105
0.0261
1130
285
75
2.5
5.7
6
5-20
112
320
25.5
0.1790
0.0255
1000
118
88
4.3
5.8
7
5-21
113
315
22.5
640
18
97
5.0
7.2
8
5-21
115
310'
22.0
910
45
95
5.7
9
5-22
110
315
23.2
0.3060
0.0205
1000
223
81
2.9
5.9
10
5-22
111
335
23.0
6.2580
0.0334
545
180
67
2.2
5.4
11
5-23
205
16.0
1200
45
96
6.1
12
5-23
58
215
18.0
1150
50
96
1.5
6.1
I
NJ
-------
4.2 START-UP AND OPERATING PROBLEMS AND SOLUTIONS
As mentioned earlier, numerous problems have occurred
since start-up of the FGD system in February 1972. Many
problems have been completely solved; substantial progress
has been made on others. The FGD system availability for
Module A has improved consistently throughout 1974. It is
expected that when Module B is modified, its performance and
availability will be comparable to that of Module A. Monthly
availability data factors for each module are presented in
Table 4.4.
The major problems encountered and their solutions are
discussed below.
1972 - Demister plugging was a constant problem, mainly
because of heavy limestone slurry accumulations on the
bottom of the demister. This problem kept Modules A and B
out of service for several days per month during March,
April, June and July 1972. The modules were also out of
service from September 26 to November 21, 1972, because the
boiler was down during that period.
Because of heavy demister plugging the demister washer
nozzles were relocated to spray upward onto the bottom
(upstream side) of the demister. The spray modifications
improved the demister washing operation considerably.
Starting on March 12, a 15-day run with Module A was
completed with only three minor outages totaling ten hours.
One outage was an operating error trip. Two were attributed
4-3
-------
Table 4.2 WILL COUNTY UNIT 1 WET-SCRUBBER MODULE A
PRELIMINARY TEST DATA - JULY AND AUGUST 1972
Test nujnber
Date
Load', MW
Gas flow, acfm x 10
Scrubber system, pressure
difference, inches H_0
Dust inlet, gr/DSCF
Dust outlet, gr/DSCF
Absorber slurry solids
concentration, %
Absorber pH
1
7-25
102
326
20
0.4354
0.0213
2
4.7
2
7-26
100
276
14.5
0.2508
0.0228
2
5.7
3
7-27
112
364
23.5
0.1855
0.0220
2
4
8-4
104
383
26
0.2075
0.0229
2
6.0
5
8-4
103
383
27
0.1008
0.0222
11
6.2
6
8-7
98
400
26
0.2339
0.0278
11.8
6.2
-------
Table 4.3 WILL COUNTY UNIT 1 MODULE A
PRELIMINARY TEST DATA - AUGUST 8-12, 1972
Test number
Date
Gas flow, acfm x 10~
Scrubber system,
pressure difference,
inches H20
SO- inlet, ppm
SO- outlet, ppm
SO- removal effi-
ciency, %
Absorber, pH
1
8-8
360
26.5
2400
300
87.5
5.7
2
8-8
360
26.0
2860
960
66.4
5.9
3
8-9
226
21.0
2720
495
81.8
4.9
4
8-9
353
29.0
2680
800
70.0
5.0
5
8-10
6
8-10
I
360 ' 353
28.0
2700
185
93.2
5.5
27.0
1065
63
94.1
6.6
7
8-11
345
26.0
1600
280
82.5
6.4
8
8-11
468
28.0
2230
570
74.4
9
8-12
370
28.0
2260
520
77.0
10
8-12
370
29.5
2350
765
67.3
I
in
-------
Table 4.4 FGD SYSTEM AVAILABILITY FACTORS
Period
Month/year
March, 1972
April
May
June
July
August
September
October
November
December
January 1973
February
March
Availability, %
Module A
0
34
69
79
0
0
0
22
0
22
65
Module B
35
14
32
21
29
0
0
30
0
24
11
Period
Month/year
April
May
June
July
August
September
October
November
December
January 1974
February
March
April
May
June
Availability, %
Module A
6
0
1
51
19
0
32
51
0
0
0
21
72
93
54
Module B
13
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Period
Month/year
July
August
September
October
November
December
January 1975
February
March
Availability, %
Module A
96
91
85
94
97
99
99
99
99
Module B
0
0
0
0
0
0
0
0
0
-------
to "limestone blinding", a reported unexplained phenomenon
characterized by a sudden drop in SO- removal efficiency and
a pH reduction that cannot be readjusted by the addition of
limestone.3 In this case the odor of sulfur dioxide was
very strong over the recirculation tanks. When the phenom-
enon occurred several months earlier, proper operation was
recovered without isolating the scrubber from the boiler by
lowering the recirculating tank level and refilling with
fresh limestone slurry. During these two later occurrences
it was necessary to remove the scrubber from service.
During high gas flow rates, the reheater of Module B
vibrated excessively. Therefore, Module B was taken out of
service in April 1972 to carry out reheater modifications.
These modifications included rebracing the reheater tubes
and installing a baffle plate to reduce the vibrations.
Other reasons for module outages included erosion and
plugging of spray nozzles, internal and external buildup of
deposits on venturi nozzles, corrosion cracking and fan
vibrations.
1973 - Demister plugging continued to be a problem.
Furthermore, the demister on Module B broke loose from its
mountings and the resultant carryover wash water plugged the
reheater. The reheater also began to leak from chloride
corrosion. Module A was down from April 24 to May 24, 1973,
a
EPA has reported only one isolated case of the occurrence of
blinding several years ago at TVA's Colbert Station. The
phenomenon was not confirmed in tests at Shawnee where
the pH was intentionally lowered. When the limestone feed
was restored, the pH recovered and the system resumed normal,
satisfactory operation.
4-7
-------
and Module B has been inoperative since April. The FGD
system was not operated between August 27 and September 26,
1973.
To solve the existing demister and reheater problems, a
constant underspray and an intermittent overspray were used
to wash all the demister compartments of Module A. Extra
nozzles were added and a clean water supply was maintained.
The failed reheaters were retubed using the best tubes from
both modules.
1974 - Only Module A was operated in 1974. The demister
operated satisfactorily; manual cleaning of demister,
reheater and absorber trays was not required. Operating
problems included damaged piping, sump pumps and instrumentation
due to freezing weather, and steam piping leaks. Fan balance
problems were reported, but the fans were not cleaned during
1974.
1975 - Module A performed with high reliability through
May. Most outages through then were either for inspection
purposes or else were due to the lack of demand for power.
Reheater leaks and plugged demister wash nozzles have occurred.
The module was shut down in June and remained out of service
throughout July. A new replacement demister was being
installed in July, and the reheater has been removed. A new
reheater has been ordered. The module will remain out of
service until the new demister and the replacement reheater
have been installed.
4-8
-------
Module B was placed in service on May 20, 1975. Early
outages have been related to booster fan deposits and vibra-
tions. Reheater leaks have occurred after 1000 hours of
operation and appear to be due to vibration fatigue.
4-9
-------
APPENDIX A
PLANT SURVEY FORM
A-l
-------
PLANT SURVEY FORM
NON-REGENERABLE FGD PROCESSES
A. COMPANY AND PLANT INFORMATION
1. COMPANY NAME Commonwealth Edison Company
2. MAIN OFFICE P.O. Box 767 - Chicago. Illinois 60690
3. PLANT MANAGER James R. Gilbert
4. PLANT NAME Will County Station
5. PLANT LOCATION Romeoville, Illinois
6. PERSON TO CONTACT FOR FURTHER INFORMATION Mr. J.P. McCluskey5
7. POSITION Director - Environmental Affairs
8. TELEPHONE NUMBER 312/294-2921
9 . DATE INFORMATION GATHERED 6/28/74
10. PARTICIPANTS IN MEETING AFFILIATION
a These data were reported on 6/28/74. Some of the data
have been updated in the text of the report.
A_2 5/17/74
-------
B. PLANT DATA. (APPLIES TO ALL BOILERS AT THE PLANT).
C.
Gross/
CAPACITY, MW Net
SERVICE (BASE, PEAK)
FGD SYSTEM USED
BOILER NO.
1
L67/144
Cycling
Wet
limes ton
2
167/154
Cycling
2 None
3
278/262
Base
None
4
545/523
Base
None
BOILER DATA. COMPLETE SECTIONS (C) THROUGH (R) FOR EACH
BOILER HAVING AN FGD SYSTEM.
1. BOILER IDENTIFICATION NO.
* 2. MAXIMUM CONTINUOUS HEAT INPUT
1
1600
3. MAXIMUM CONTINUOUS GENERATING CAPACITY
167
4. MAXIMUM CONTINUOUS FLUE GAS RATE. 770.000
5. BOILER MANUFACTURER Babcock and Wilcox
6. YEAR BOILER PLACED IN SERVICE
MM BTU/HR
MW (GROSS)
ACFM (33550F
1955
7. BOILER SERVICE (BASE LOAD, PEAK, ETC.) Cycling
8. STACK HEIGHT 350'
9. BOILER OPERATION HOURS/YEAR (197 ) 7632
10. BOILER CAPACITY FACTOR * 52.8%
11. RATIO OF FLY ASH/BOTTOM ASH
20/80
(Industry accepted values for cyclone-fired boiler)
* DEFINED AS: KWH GENERATED IN YEAR
MAX. CONT. GENERATED CAPACITY IN KW X 8760 HR/YR
A-3
5/17/74
-------
D. FUEL DATA (1973) - One year average
1. COAL ANALYSIS (as received)
GHV (BTU/LB.)
S %
ASH %
MAX.
9903
3.01
12.50
MIN.
8963
0.61
5.11
AVG.
9463
2.14
9.99
2. FUEL OIL ANALYSIS (exclude start-up fuel)(NONE)
GRADE
S %
ASH %
E. ATMOSPHERIC EMISSIONS
1. APPLICABLE EMISSION REGULATIONS
a) CURRENT REQUIREMENTS
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
MAX. ALLOWABLE EMISSIONS
LBS/MM BTU
b) FUTURE REQUIREMENTS,
COMPLIANCE DATE
REGULATION & SECTION NO.
MAXIMUM ALLOWABLE EMISSIONS
LBS/MM BTU
PARTICULATES
SO-
111. Rules & Regs, governing
the control of air poll.
rule 2-2.11
0.6
5/30/75
5/30/75
IPCB Air Pollution Regs.
203CG) (1) C ,204(C) (1) A
0.2
1.8
2. PLANT PROGRAM FOR PARTICULATES COMPLIANCE
All units presently in compliance with 1975 standards.
3. PLANT PROGRAM FOR S02 COMPLIANCE
All units presently in compliance with 1975 standards,
A-4
5/17/74
-------
* ESP Normally not used, except when scrubber is out of service.
F. PARTICULATE REMOVAL
1. TYPE
MANUFACTURER
EFFICIENCY: DESIGN/ACTUAL
MAX. EMISSION RATE* LB/HR
GR/SCF
LB/MMBTU
MECH.
(70°F)
* E.S.P.
Western
90/79
845
0.29
0.55
FGD
B&W
99/98
99.2
0.024
0.06
DESIGN BASIS, SULFUR CONTENT
4.0%
G. DESULFURI2ATION SYSTEM DATA
1. PROCESS NAME
2. LICENSOR/DESIGNER NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
Wet limestone scrubbing
Babcock and Wilcox
Barberton. Ohio
Mr. Thomas Hurst
216/753-4511
3. ARCHITECTURAL/ENGINEERS, NAME: Bechtel Power Corp.
Fifty Beale Street
ADDRESS: San Francisco, California
PERSON TO CONTACT:
TELEPHONE NO.:
Mr. J. J. Smortchevsky
415/764-6262
4. PROJECT CONSTRUCTION SCHEDULE:
DATE
a) DATE OF PREPARATION OF BIDS SPECS. June, 1970
b) DATE OF REQUEST FOR BIDS
c) DATE OF CONTRACT AWARD
d) DATE ON SITE CONSTRUCTION BEGAN
August, 1970
September 28, 1970
May 17. 1971
e) DATE ON SITE CONSTRUCTION COMPLETED April. 1972
f) DATE OF INITIAL STARTUP('B' Module February 23, 1972
only)
g) DATE OF COMPLETION OF SHAKEDOWN Still in Progress
*At Max. Continuous Capacity
A-5
5/17/74
-------
5. LIST MAJOR DELAYS IN CONSTRUCTION SCHEDULE AND CAUSES:
Ref; Will County Unit 1 Limestone Wet Scrubber
Description and Operating Experience, by D.C. Gifford,
Commonwealth Edison Company, Chicago, Illinois,
November 30. 1973.
6. NUMBER OF S02 SCRUBBER TRAINS USED
7. DESIGN THROUGHPUT PER TRAIN, ACFM @ 355°F 385.000
8. DRAWINGS: 1) PROCESS FLOW DIAGRAM AND MATERIAL BALANCE
I
2) EQUIPMENT LAYOUT (See attach 1)
H. SO2 SCRUBBING AGENT
1. TYPE Limestone
2. SOURCES OF SUPPLY Marblehead lime
Office in Chicago -
3. CHEMICAL COMPOSITION (for each source) quarry around St. Louis
or Quincy
SILICATES
SILICA 0.48%
CALCIUM CARBONATE 91.5%
MAGNESIUM CARBONATE 0.99%
EXCESS SCRUBBING AGENT USED ABOVE
STOICHIOMETRIC REQUIREMENTS J0 ~ 50%
Absorber Recirc. Tank and
5. MAKE-UP WATER POINT OF ADDITION demister underspray
6. MAKE-UP ALKALI POINT OF ADDITION Absorber Recirc. Tank
A-6
-------
FROM TRAINS
CD
@
FLUE GAS
TO TRAINS
1
SLU3CE STABILIZER
©
SLUDGE TO
DISPOSAL SITE
Based on 4% sulfur
Contract design Number 1
RATE, Ib/hr
ACFM
CPM
PARTICULATES, Ib/hr
S02. Ib/hr
TEMPERATURE, °F
TOTAL SOLIDS. %
SPECIFIC GRAVITY
CO
770,000
4960
12,360
355
(?)
385,000
2480
6180
355
C3J
385. OOC
2480
6180
355
0
31 5, OOC
49.6
4120
128
[ ;
C5)
354.000
49.6
1135
200
V)
354.000
49.6
i:
-35
200
7
7 Q8. 000
99
9
2270
200
1
CO
280
80
C9)
140
80
(10)
140
80
GD
o
(12)
60
80
35
1.3
(ji)
-
60
QA
35
1.3
RATE, Ib/hr
ACFM
GPM
PARTICULATES, Ib/hr
S02 . Ib/hr
TEMPERATURE. °F
TOTAL SOLIDS, %
SPECIFIC GRAVITY
(14)
120 ...
80
35
1.3
(is)
? 1,200
120
10%
1.07
(is)
5600
120
10%
1.07
' ($
?sn
120
10
1.07
(18)
?50
120
10
1.07
© 1 ^5)
500
120
10
1.07
120
100
40
1.33
| (21)
330
100
0
1.0
(22)
_
_
_
(23)
330
100
0
1.0
(24)
9700
-
C2!
90 522
80
46%
1.4
(26) .
I. Representative flow rates based on operating data at maximum continuous load
5/17/74
-------
J. SCRUBBER TRAIN SPECIFICATIONS
1. SCRUBBER NO. 1 (Particulate Removal)
TYPE (TOWER/VENTURI) Venturi
LIQUID/GAS RATIO, G/MCF @ 355°F 14.5 - full load
GAS VELOCITY THROUGH SCRUBBER, FT/SEC 120
MATERIAL OF CONSTRUCTION Carbon Steel
Plastic and
TYPE OF LINING two inch Kaocrete
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.)Moveable Throat Block
NUMBER OF STAGES One
TYPE AND SIZE OF PACKING MATERIAL N/A
(b)
PACKING THICKNESS PER STAGE
MATERIAL OF CONSTRUCTION, PACKING:
N/A
SUPPORTS: N/A
SCRUBBER NO. 2 (a) (S02 Removal)
TYPE (TOWER/VENTUR!) Tower
LIQUID/GAS RATIO, G/MCF @ 120°F 35.5 - full load
GAS VELOCITY THROUGH SCRUBBER, FT/SEC 10
MATERIAL OF CONSTRUCTION Corten Steel
TYPE OF LINING Rubber
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.) Perforated Plates
NUMBER OF STAGES _2
TYPE AND SIZE OF PACKING MATERIAL None
a) Scrubber No. 1 is the scrubber that the flue gases first
enter. Scrubber 2 (if applicable) follows Scrubber No. 1.
b) For floating bed, packing thickness at rest.
A-8 5/17/74
-------
PACKING THICKNESS PER STAGE
(b)
N/A
MATERIAL OF CONSTRUCTION, PACKING: N/A_
SUPPORTS:N/A
CLEAR WATER TRAY (AT TOP OF SCRUBBER)
TYPE
L/G RATIO
SOURCE OF WATER N/A
DEMISTER
TYPE (CHEVRON, ETC.)
NUMBER OF PASSES (STAGES)
SPACE BETWEEN VANES
ANGLE OF VANES
TOTAL DEPTH OF DEMISTER
DIAMETER OF DEMISTER
DISTANCE BETWEEN TOP OF PACKING
AND BOTTOM OF DEMISTER
POSITION (HORIZONTAL, VERTICAL)
MATERIAL OF CONSTRUCTION
METHOD OF CLEANING
SOURCE OF WATER AND PRESSURE
Chevron
2-separated by
space
1-3/4"
45(
7"
Rectangular Shape
Horizontal
FRP
Water Spray, Bottom - Constant
Top - Intermittent
Bottom - Fresh (15 psig)
Top - Pond (30 psig)
Bottom - 120 gpm/module
FLOW RATE DURING CLEANINGS, GPM TOP - lOOOcmm/compartment(3)
Bottom - Constant
FREQUENCY AND DURATION OF CLEANING Top - 30 sec, every 2 hour
REMARKS 2nd demister installed end of March. 1974
5. REHEATER
TYPE (DIRECT, INDIRECT)
Indirect Steam
b) For floating bed, packing thickness at rest.
A-9
5/17/74
-------
DUTY, MMBTU/HR 55
HEAT TRANSFER SURFACE AREA SQ.FT 6096 (total)
TEMPERATURE OF GAS: IN 128 OUT 200°F
HEATING MEDIUM SOURCE Steam from boiler
TEMPERATURE & PRESSURE 485°F, 350 psig
FLOW RATE 55,000 LB/HR
REHEATER TUBES, TYPE AND
MATERIAL OF CONSTRUCTION 5/8" - 304 SS and Corten
Steel
REHEATER LOCATION WITH RESPECT TO DEMISTER
After demister
METHOD OF CLEANING Sootblowers (8)
FREQUENCY AND DURATION OF CLEANING Every 4 hours
FLOW RATE OF CLEANING MEDIUM Unknown LB/HR
REMARKS
6. SCRUBBER TRAIN PRESSURE DROP DATA INCHES OF WATER
PARTICULATE SCRUBBER 2
S02 SCRUBBER 6
CLEAR WATER TRAY
DEMISTER
REHEATER
DUCTWORK
TOTAL FGD SYSTEM 25
A-10 5/17/74
-------
7. FRESH WATER MAKE UP FLOW RATES AND POINTS OF ADDITION
(Total for Both Modules)
TO: DEMISTER 240 gpm
QUENCH CHAMBER
ALKALI SLURRYING
PUMP SEALS
OTHER
60 gpm
8.
TOTAL
300 gpm
FRESH WATER ADDED PER MOLE OF SULFUR REMOVED 880*Ib. H?O/lb.
Mole S02 Removed
BYPASS SYSTEM
Yes
CAN FLUE GAS BE BYPASSED AROUND FGD SYSTEMS
GAS LEAKAGE THROUGH BYPASS VALVE, ACFM Unknown
K. SLURRY DATA
LIME/LIMESTONE SLURRY MAKEUP TANK 7.0
PARTICULATE SCRUBBER EFFLUENT
HOLD TANK (a)
S02 SCRUBBER EFFLUENT HOLD
TANK (a)
PH
7.0
5.9
5.8
%
Solids
35
8
8
Capacity
(gal)
60,000
40,000
40,000
Hold up
time
N/A
8 min.
4 min.
L. LIMESTONE MILLING AND CALCINING FACILITIES: INDICATE BOILERS
SERVED BY THIS SYSTEM.
TYPE OF MILL (WET CYCLONE, ETC.)
NUMBER OF MILLS
CAPACITY PER MILL
RAW MATERIAL MESH SIZE
PRODUCT MESH SIZE
Wet Ball
12
0 X 1/2"
95% < 325
T/HR
A-ll
5/17/74
-------
SLURRY CONCENTRATION IN MILL 60%
CALCINING AND/OR SLAKING FACILITIES N/A
SOURCE OF WATER FOR SLURRY MAKE UP OR
SLAKING TANK Pond recycle
M. DISPOSAL OF SPENT LIQUOR
1. SCHEMATICS OF SLUDGE & FLY ASH DISPOSAL METHOD
(IDENTIFY QUANTITIES OR SCHEMATIC) See Page 6
2. CLARIFIERS (THICKENERS)
1
NUMBER
DIMENSIONS 65% dia. X 15' high
CONCENTRATION OF SOLIDS IN UNDERFLOW 35"40%
3. ROTARY VACUUM FILTER
NUMBER OF FILTERS
CLOTH AREA/FILTER
CAPACITY N/A TON/HR (WET CAKE)
CONCENTRATION OF SOLIDS IN CAKE N/A
PRECOAT (TYPE, QUANTITY, THICKNESS) N/A
REMARKS
4. SLUDGE FIXATION
POINT OF ADDITIVES INJECTION Thickener underflow
FIXATION MATERIAL COMPOSITION Lime and fly ash
FIXATION PROCESS (NAME) None
FIXATION MATERIAL REQUIREMENT/TONS OF DRY SOLIDS OF SLUDGE
0.1 ton lime and
0.2 ton fly ash
R-12 5/17/74
-------
ESTIMATED POND LIFE, YRS . 1/2 yr .
CONCENTRATION OF SOLIDS IN FIXED SLUDGE 46%
METHOD OF DISPOSAL OF FIXED SLUDGE Lined basin - claya ,
INITIAL SOLIDIFICATION TIME OF FIXED SLUDGE 1 week, but
varies with ambient
SLUDGE QUANTITY DATA
POND/LANDFILL SIZE REQUIREMENTS, ACRE-FT/YR 150
IS POND/LANDFILL ON OR OFFSITE On r
TYPE OF LINER Clay
IF OFFSITE, DISTANCE AND COST OF TRANSPORT N/A
POND/LANDFILL DIMENSIONS AREA IN ACRES Z_
DEPTH IN FEET 10
DISPOSAL PLANS; SHORT AND LONG TERM
Short term plans are to continue using present disposal
basin. Long term plans are to dispose of treated
sludge in a disposal site near the station. Awaiting
Illinois EPA approval of site.
N. COST DATA (See attach 1)
1. TOTAL INSTALLED CAPITAL COST
2. ANNUALIZED OPERATING COST
^
About 1 foot deep.
A-13
5/17/74
-------
3.
COST BREAKDOWN
A.
B.
COST ELEMENTS
CAPITAL COSTS
S02 SCRUBBER TRAINS
LIMESTONE MILLING
FACILITIES
SLUDGE TREATMENT &
DISPOSAL POND
SITE IMPROVEMENTS
LAND, ROADS, TRACKS,
SUBSTATION
ENGINEERING COSTS
CONTRACTORS FEE*
INTEREST ON CAPITAL
DURING CONSTRUCTION
ANNUALIZED OPERATING COST
FIXED COSTS
INTEREST ON CAPITAL
DEPRECIATION
INSURANCE & TAXES
LABOR COST
INCLUDING OVERHEAD
VARIABLE COSTS
RAW MATERIAL
UTILITIES
MAINTENANCE
INCLUDED IN
ABOVE COST
ESTIMATE
ESTIMATED AMOUNT
OR % OF TOTAL
INSTALLED CAPITAL
COST
YES
NO
**
n
)irect cost/Total cost =
Direct cost + Indirect
@ 12%
2,928,000/3.279.000
397.000/445.OOP
573,000/642.000
Appears in contractor's
fee
Appear in
contractor's fee
965.000/1.081.000
9.010.000/10.091.000
Not available
2.280.000
Included in
above figure
Not available
88.000
230.000
454.000
447.000
* Contractors Fee Includes: Equipment Erection, Electrical
Equipment & Erection, Foundations, Structural Steel and
Miscellaneous Equipment.
**
Estimated annual operating cost @ 35% boiler capacity factor.
A-14
5/17/74
-------
COST FACTORS
a.
ELECTRICITY $454,000/yr.
Pumping cost only -
b. WATER included in (a)
c. STEAM (OR FUEL FOR REHEATING) $ 82.000/vr.
*d. FIXATION COST 16.20 $/TON OF DRY SLUDGE
**e. RAW MATERIAL PURCHASING COST 7.55 $/TON OF DRY SLUDGE
f. LABOR: SUPERVISOR HOURS/WEEK WAGE
OPERATOR
OPERATOR HELPER
a Contract out thru B&W = 5 people
MAINTENANCE @ 40 hrs/wk @ $15/hr includes supervisor
O. MAJOR PROBLEM AREAS: (CORROSION, PLUGGING, ETC.)
1. S02 SCRUBBER, CIRCULATION TANK AND PUMPS.
a. PROBLEM/SOLUTION
Scaling on Absorber Plates.
Scale breaking of Venturi Throat and Venturi
Sumpwalls plugging Recirc. Tank Screen. —
Solutions unknown at present.
2. DEMISTER
PROBLEM/SOLUTION
Plugging — Improved washing systems have partially
alleviated the problem.
3. REHEATER
PROBLEM/SOLUTION Deposits — Improvement in Demister
Efficiency. Corrosion (Chloride) — Improvement in
Demister Efficiency has helped, but may require new
reheater tube alloy.
* Includes raw material(e) but not cost of disposal site.
** Limestone - $3.84, Lime - -$3.38, Fly ash - $0.33.
A"15 5/17/74
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VENTURI SCRUBBER, CIRCULATION TANKS AND PUMPS
PROBLEM/SOLUTION
Wet-dry interface deposit. Throat drive problems. Tank
screen scaling causing screen blockage and collapse —
Not solved yet.
5. I.D. BOOSTER FAN AND DUCT WORK
PROBLEM/SOLUTION
Corrosion of ductwork - not solved.
Booster fan swinging - control modification.
Inlet cone cracks - rewelded.
Acid deposits caused by low reheat temp. - raised temperature
Vibration - rebalanced fan.
6. LIMESTONE MILLING SYSTEM OR LIME SLAKING
PROBLEM/SOLUTION Limestone hangs up in silo — installing
air operated flow stimulators, hopefully this will solve
problem.
Chutes Plug -- Installed new reversible conveyor. Level
indication in tanks, throttling slurry flow due to valve
wear, pump inlet expansion joint failures — Not solved yet,
Pluggage of piping — Piping redesign has helped.
7. SLUDGE TREATMENT AND DISPOSAL
PROBLEM/SOLUTION
A~16 5/17/74
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8. MISCELLANEOUS AREA INCLUDING BYPASS SYSTEM
PROBLEM/SOLUTION Limestone blinding — More stringent
chemical control has apparently prevented recurrence.
P. DESCRIBE FACTORS WHICH MAY NOT MAKE THIS A REPRESENTATIVE
INSTALLATION
DESCRIBE METHODS OF SCRUBBER CONTROL UNDER FLUCTUATING
LOAD. IDENTIFY PROBLEMS WITH THIS METHOD AND SOLUTIONS.
IDENTIFY METHOD OF pH CONTROL AND LOCATION OF pH PROBES.
As boiler load chanes, the air flow thru t-he>
automatically varied by means o-f controlling the
f an speed and booster fan dampers . To maintain a constant _
pressure drop across the venturi portion of the scrubber, the
venturi throat automatically opens and closes. To maintain _
constant gas outlet temperatures/ the steam flow to the reheater
is also automatically controlled. _
pH is manually sampled at two points, the recirculation line and
the venturi recirculation tank. An automatic pH sampling system
is being installed. Based on the pH readings, the operator _
manually adjusts the slurry mix. __
Mechanical - Misc. Minor. Chemical — Difficulty in maintaining
chemical balance with fluctuating boiler load and sulfur conditions
increases the potential for scaling. It is hoped that the automatic
chemical control to be installed in the near future will alleviate
this situation.
A'17 5/17/74
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R. COMPUTATION OF FGD SYSTEM AVAILABILITY FACTOR
BOILER RATING OR MAXIMUM CONTINUOUS CAPACITY, MW
CO
PERIOD
MONTH/YEAR
June 1973
July
August
September
October
November
December
January 1974
February
March
April
May
FLUE GAS DESULFURIZATION MODULES
MODULE A
DOWN DUE TO
BOILER
(HRS)
512
677
668
553
738
633
627
743
647
426
684
744
MODULE
(HRS)
106
324
110
6
355
201
0
0
0
110
447
693
MODULE B
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE C
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE D
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
Availability factor computation: 1,
Divide boiler capacity by the number of modules
and obtain MW/module = x
Multiply boiler capacity by number of hours
during period = a
Add all down times due to module trouble for all modules
during period = b
Add all down times due to boiler trouble or reduction
in electricity demand for all modules during period = c
Availability factor = [a ~ * (b * c)]1°° = %
cl "" X G
5/17/74
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APPENDIX B
PLANT PHOTOGRAPHS
B-l
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Photo No. 1 General view of the Will County power house
showing the coal conveyor (foreground) and the limestone
conveyor in the background.
B-2
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Photo No. 2 View from top of the boiler building looking
north towards the ship and sanitary canal. The FGD modules
are housed in the building shown behind the electrostatic
precipitator structure. The peak of the limestone storage
pile can be seen in the background.
B-3
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Photo No. 3 View inside the limestone grinding building
showing the bottom of the limestone storage silo.
B-4
-------
Photo No. 4 One of the two 12-tons/hr limestone ball mills
B-5
-------
Photo No. 5 Scale model revealing typical arrangements of
the module internals. The venturi scrubber on the left and
the two-stage scrubber towers to the right. The venturi and
scrubber circulation tanks are at ground level.
B-6
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Photo No. 6 Close-up view of a venturi throat showing the
motorized mechanism which drives the throat blocks in order
to vary the throat's gap. The slurry spray piping is shown
at the top.
B-7
-------
Photo No. 7 Partial view of the slurry circulation pumps.
There are three venturi circulation pumps and four scrubber
tower circulation pumps serving the modules.
B-8
-------
Photo No. 8 Close-up view of a dismantled reheater bundle,
B-9
-------
Photo No. 9 View of the booster fan on Module B. Its
internals are being examined through the inspection windows
B-10
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Photo No. 10 The FGD instrument panel which is located in
the boiler control room. Some of the important instruments
on this panel are the SO2 inlet and outlet concentrations,
pH meters and pump controls.
Photo No. 11 General view of the on-site sludge treatment
facilities. The Chicago Fly Ash Company, under contract
with Commonwealth Edison, installed and operated the equip-
ment.
B-ll
-------
Photo No. 12 Top view of the clarifier tank showing the
clarified water overflowing the weir to the collection
trough on the circumference of the tank.
B-12
-------
Photo No. 13 Side view of the clarifier tank showing the
overflow pipe discharging in the nearby pond. This water
is further clarified in the pond and recycled to the FGD
system. The underflow pipe is discharged to a holding
tank located near the clarifier tank.
B-13
-------
Photo No. 14 General view of the pond area. The accumulated
silt is periodically excavated and stabilized before it is
hauled to an on-site holding basin.
B-14
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Photo No. 15 View of the sludge stabilization operation.
Fly ash and lime stored in the two silos are mixed with the
sludge which is either conveyed on the inclined conveyor when
cleaning the pond or pumped from the thickener underflow. The
three ingredients are then fed to the cement truck. The
materials are mixed on the way to the on-site stabilized sludge
holding basin.
B-15
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Photo No. 16 Another view of the sludge stabilization
equipment during operation. About 200 pounds of lime and
400 pounds of fly ash are used to stabilize one ton of dry
sslids in the sludge.
Photo No. 17 The homogenized mixture of stabilized sludge
is poured into an on-site sludge holding basin for solidifi-
cation.
B-16
-------
Photo No. 18 The stabilized sludge which solidifies in about
one week depending on weather conditions is excavated and piled
as shown in this picture and hauled away for disposal in an
off-site sanitary landfill.
B-17
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TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
1 REPORT NO
EPA -650/2 -75-057-i
2.
3 RECIPIENT'S ACCESSION-NO.
4 TITLE AND SUBTITLE
Survey of Flue Gas Desulfurization Systems
Will County Station, Commonwealth Edison Co.
5 REPORT DATE
October 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
Gerald A. Isaacs and Fouad K. Zada
9. PERFORMING ORGANIZATION NAME ANO ADDRESS
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ACX-130
11. CONTRACT/GRANT NO.
68-02-1321, Task 6i
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research-and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 6/74-9/75
14. SPONSORING AGENCY CODE
15 SUPPLEMENTARY NOTES
16 ABSTRACT Tne repOr|. gives results of a. survey of the flue gas desulfurization (FGD)
system at Commonwealth Edison's Will County Station boiler No. 1. The 146 MW
(net) boiler was installed in 1955. In 1973 the boiler burned coal with a gross heating
value of 9463 Btu/lb and ash and sulfur contents of 10 and 2.1 percent, respectively.
The wet limestone FGD system was placed in service on February 23, 1972. It
consists of two FGD modules, limestone handling and milling facilities, and a
sludge treatment and stabilization unit. Each module consists of a venturi scrubber
followed by a two-stage absorption tower. Operating problems were encountered
with both modules soon after startup and during initial debugging. Module B was
shut down in May 1973 to concentrate on operating Module A. Operating problems
have been mainly confined to the demister and reheater units. Additional spray
nozzles were installed to keep the demister free of slurry deposits. Estimated
capital cost for the Unit 1 FGD system is SH5/KW (net), including SlS/KW for sludge
treatment. Annualized operating cost is estimated to be 12 mills/KWH, based on an
assumed boiler capacity factor of 35 percent.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Flue Gases
Desulfurization
Sulfur Dioxide
Limestone
Scrubbers
Absorbers (Kqm
Coal
Combustion
Sludge
De misters
Cost Effectiveness
Columns (Process
Air Pollution Control
Stationary Sources
Veriiuri S-"rubbers
13B 21D
21B
07A, 07D
07B ISA
08G 14A
8 DISTRIBUTION STATEMENT
Unlimited
19 SbCUfli . Y CLASS (ThisReport)
Unclassified
21 NO. OF PAGES
71
20 SECURITY CLASS (Thispage)
Unclassified
22 PRICE
EPA Form 2220-1 (9-73)
B-18
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