CD A U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-78-048D
t* • f^ Office of Research and Development Laboratory _ _ . ^ QTQ
Research Triangle Park, North Carolina 27711 MBfCn iSf/O
SURVEY OF FLUE GAS
DESULFURIZATION SYSTEMS:
WILL COUNTY STATION,
COMMONWEALTH EDISON CO
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine 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 (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-048b
March 1978
SURVEY OF FLUE GAS DESULFURIZATION
SYSTEMS: WILL COUNTY STATION,
COMMONWEALTH EDISON CO.
by
Bernard A. Laseke, Jr.
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-01-4147
Task3
Program Element No. EHE624
EPA Project Officer: Norman Kaplan
Industrial Environmental Research Laboratory
Office of Energy, Minerals and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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ACKNOWLEDGMENT
This report was prepared under the direction of Mr. Timothy
W. Devitt and Dr. Gerald A. Isaacs. The principal author was Mr.
Bernard A. Laseke.
Mr. Norman Kaplan, EPA Project Officer, had primary respon-
sibility within EPA for this project report. Information on
plant design and operation was provided by Mr. Rudy Kunshek,
Environmental Affairs Department, Commonwealth Edison Company,
Bruce R. Mansfield, General Environmental Engineer, Commonwealth
Edison Company, and Michael L. Poole, Operating Engineer SO-
Scrubber, Will County Station, Commonwealth Edison Company.
ii
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CONTENTS
Acknowledgment
Figures and Tables
Summary
1.
2.
3.
Appendix
A.
Introduction
Facility Description
Flue Gas Desulfurization System
Process Description
Process Chemistry: Principal Reactions
Process Control
FGD System Performance
Performance Test Programs
Summary of System Performance
Problems, Solutions, and System
Modifications
System Economics
Future Operation
Plant Survey Form
Page
ii
iv
vi
1
2
5
5
16
17
20
20
24
29
34
34
39
iii
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FIGURES
No. Page
1 Limestone Handling and Milling Facilities,
Will County Station 6
2 Flow Diagram of Will County Boiler 1 and FGD System 8
3 Sludge Stabilization and Disposal Facilities,
Will County FGD System 11
4" Instrumentation and Control Diagram, Will County
FGD Modules 18
TABLES
No. Page
1 Summary Data, Will County Unit 1 FGD System ix
2 Characteristics of Coal Fired in Will County,
Boiler 1 3
3 Design, Operation, and Emissions, Will County 1 4
4 Summary of Design Data, Scrubbing Trains 12
5 Summary of Design and Operating Data,
Mist Eliminators 13
6 Summary of Design and Operating Data, Reheaters 14
7 Summary of Design Data, Recirculation and Makeup
Tanks 15
8 Design Pressure Drop for Each Scrubbing Train 15
9 preliminary Test Data, A-Side Scrubbing Train
May 18 to 23, 1972 21
iv
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TABLES (Continued)
No. Page
10 Preliminary Test Data, A-Side Scrubbing Train,
July 25 to August 7, 1972. 22
11 Preliminary Test Data, A-Side Scrubbing Train,
August 8 to 12, 1972. 23
12 Summmary of FGD System Performance, Will County
FGD System: 1975, 1976, and 1977 (July) 25
13 Estimated Capital Investment Costs of Will
County Unit 1 FGD System 35
14 Approximate 1975 Cost to Own and Operate Will
County Unit 1 Wet Scrubber 36
15 Summary of FGD Data, Powerton Station Unit 5,
Boiler 51 38
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SUMMARY
The Commonwealth Edison Company owns and operates the Will
County Station on .the Chicago Sanitary and Ship Canal, near
Romeoville, Illinois. The station consists of four electric
power generating units having a total rated capacity of 1147 MW
(gross).
Early in11970 the utility began investigating sulfur removal
technology, and the Bechtel Corporation was contracted to assist.
The investigation dealt with those processes which, at that time,
were sufficiently developed for full-scale installation. Common-
wealth Edison consequently decided on a wet scrubbing system
using lime or limestone absorbent. Bid Specifications were
prepared and bids were received from seven system suppliers.
Following a detailed study, a contract for the installation of a
limestone scrubbing system on Will County Boiler 1 was awarded to
the Babcock and Wilcox Company (B&W).
Boiler 1 is a wet-bottom, coal-fired, radiant cyclone boiler
rated at 167 MW (gross). It was manufactured by B&W and went
into service in 1955. This unit burns primarily low-sulfur
western grade coal (approximately 0.4 percent sulfur); a high-
sulfur Illinois grade (approximately 4.0 percent sulfur); or a
combination of the two. Design of the Will County scrubber
system began in September 1970 and construction started in May
1971. It was completed by February 1972. The main problems were
the necessity for a substantial cantilever to backfit the scrub-
ber between the boiler house and service building and the need to
complete the job by December 31, 1971.
The system consists of two parallel trains (A-side, B-side),
each designed to treat half the boiler flue gas. At present each
train contains the following components: two recirculation
vi
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tanks, three recirculation pumps, a venturi scrubber, sump, two-
stage sieve tray absorber tower, mist eliminator, reheater, and
induced draft (I.D.) booster fan. A series of by-pass dampers
allows flue gas to be routed around either one or both scrubbing
trains while the boiler is in service.
The B-side initially went into service on February 23, 1972,
and the A-side on April 7, 1972. Shortly after start-up and
during debugging, both modules were plagued with problems. As a
result, in May 1973 Commonwealth Edison shut down the B-side,
which originally incorporated a turbulent contact absorber (TCA)
tower, to concentrate on solving the problems of the A-side,
which uses the counter-current tray absorber.
When improved system performance of the A-side was achieved
i"*1
(69 percent operability* for 1974), the utility modified the B-
side, incorporating all changes made to the A-side. Major modi-
fications included: removal of the TCA mobile bed packing and
its replacement with two stages of sieve trays; a double-stage
reinforced mist eliminator in place of the original single-stage
unit; and replacement of the reheat tubes in the reheat bundles
from 304 stainless steel and corten steel components to 316L
stainless steel and carbon steel components. The B-side went
back into service May 20, 1975.
In 1976, Commonwealth Edison considered converting the A-
side sieve tray absorber to a TCA tower in an effort to improve
system operations at Will County while gaining experience for the
design, erection, and operation of a 450-MW TCA scrubbing system
being supplied by Universal Oil Products and scheduled for opera-
tion on Powerton Unit 5, Boiler 51, in December 1979. The short-
age of time for data acquisition before the scheduled start-up of
the Powerton FGD system prevented this modification from being
made.
In July 1977, Commonwealth Edison officially concluded
* Operabilitfy index: The number of hours the FGD system is in
operation for a given period, divided by the number of boiler
hours in the period, expressed as a percentage.
vii
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sulfur dioxide removal operations at the Will County No. 1 lime-
stone scrubbing system. Compliance with existing sulfur dioxide
emission regulations is being achieved by burning exclusively
low-sulfur western coal. Scrubbing operations are continuing in
the particulate removal mode, by means of which fly ash is
scrubbed from the flue gas with a dilute limestone slurry. The
limestone is used for pH control only, preventing potential
excursions of the solution into the low pH range, which could
cause severe acid corrosion damage. Since the scrubbing solution
retains some alkalinity as a result of the addition of limestone,
sulfur dioxide removal still occurs, though at a diminished
level. Actual removal values have not yet been determined.
The estimated capital and 1975 annual operating costs for
the FGD system on Will County Unit 1 are equivalent to $113/kW
(including $5/kW for sludge treatment) and 13.06 mills/kWh
respectively. These figures represent the cost of a difficult
retrofit application, where scrubbers were installed in an
extremely congested space and under a construction schedule that
required large overtime expenditures. Operating costs are based
on a 1975 capacity factor of 49.5 percent.
Summary data on the Will County FGD system are given in
Table 1.
viii
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Table 1. SUMMARY DATA,
WILL COUNTY UNIT 1 FGD SYSTEM
Unit rating, MW, gross
Unit rating, MW, net
Fuel
Annual average (1975)
Heating value, kJ/kg (Btu/lb)
Sulfur, percent
Ash, percent
FGD system supplier
FGD process
FGD trains
Start-up date
A-side
B-side
Design guaranteed removal
efficiency, percent
Particulates
Sulfur dioxide
Makeup water
Sludge disposal
Economics
Capital cost (1975)
Annual cost (1975)
167
144
Coal
22,260 (9,570)
1.5
7.4
Babcock & Wilcox
Wet limestone scrubbing
2
February 1972
April 1972
98
76
Not available
Stabilized sludge hauled
to off-site landfill
S113/kW (net)
13 mills/kWh
ix
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SECTION 1
INTRODUCTION
The Industrial Environmental Research Laboratory (IERL) of
the U.S. Environmental Protection Agency (EPA) has initiated a
study of the performance characteristics and reliability of flue
gas desulfurization (FGD) systems operating on coal-fired utility
boilers in the United States.
This report, one of a series dealing with such systems,
describes a wet limestone scrubbing process developed by Babcock
& Wilcox (B&W) and installed at the Will County Station of the
Commonwealth Edison Company. It addresses key process design and
operating parameters, major start-up and operational problems en-
countered at the facility and measures taken to alleviate them,
and the total installed and annual operating costs. The report
is based on information obtained during plant visits on June 28,
1974; June 22, 1976; and June 1, 1977. The information is cur-
rent as of November 1977.
Section 2 presents data and information on the plant en-
virons and plant facilities. Section 3 provides a detailed
description of the FGD system, including process design and
process chemistry features. Section 4 analyzes the performance
of the FGD system since start-up in 1972. It documents sulfur
dioxide and particulate matter removal efficiencies, system
dependability, mechanical and chemical problems and solutions,
and system economics. Appendix A is the completed plant survey
form.
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SECTION 2
FACILITY DESCRIPTION
Will County Station of the Commonwealth Edison Company is on
the Chicago Sanitary and Ship Canal in Will County, near the town
of Romeoville, (1970 population: 12,674*) Illinois. The area
contains many large refineries and chemical plants. Canal traf-
fic consists mainly of bulk cargo barges, and it is by this means
that coal and limestone are delivered to the Will County Station.
Will County Station has four electric power generating units
with a total rated capacity of 1147 MW. Only Boiler 1, a wet-
bottom, coal-fired boiler rated at 167 MW, is retrofitted with an
FGD system. It was manufactured by B&W and installed in 1955.
Boiler 1 burned a low-sulfur Montana coal, a high-sulfur
Illinois coal, or combinations of both during the Will County FGD
demonstration program. The average characteristics of these
coals are given in Table 2.
The boiler is fitted with an electrostatic precipitator
(ESP) manufactured by the Western Precipitation Division of the
Joy Manufacturing Company. The ESP has a design particulate
collection efficiency of 90 percent and a 79 percent actual
particulate collection efficiency on high-sulfur Illinois coal.^"
It provides primary particulate removal and is currently operated
on a full-time basis, independent of FGD operation.
*
State of Illinois Official Road Map (1970 Census) lists
15,336. Rand-McNally Road Map lists 12,674 (1970 est.).
Collection efficiency of the precipitator depends on fuel
supply. The 79 percent efficiency is based on tests con-
ducted June 3, 1975, iand June 4, 1975, with coal averaging
3.98 percent in sulfur.
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Table 2. CHARACTERISTICS OF COAL FIRED IN WILL COUNTY BOILER 1
Source
Montana
Illinois
Characteristics
Heating value, kJ/k2
Btu/lb
Sulfur, percent
Ash, percent
Heating value, kJ/kg
Btu/lb
Sulfur, percent
Ash, percent
Value
21,167 -
9,100 -
0.3 -
3.0 -
22,097 -
9,500 -
3.5 -
12.0 -
22,330
9,600
0.6
6.0
24,423
10,500
4.5
16.0
The maximum particulate emission allowed under Illinois
Pollution Control Board Regulation No. 203 (g) (1) (C), effective
May 30, 1975, is 86 ng/J (0.2 Ib/million Btu).* Using high-
sulfur Illinois coal, particulate emission rate from the FGD
system is equivalent to 34.4 ng/J (0.08 Ib/million Btu).
Sulfur dioxide emissions are limited by Illinois Pollution
Control Board Regulation No. 204 (C) (1) (A)- * Under this regula-
tion, effective May 30, 1975, the maximum allowable sulfur diox-
ide emission rate is 774 ng/J (1.8 Ib/million Btu). The present
sulfur dioxide emission rate, based on 89.2 percent removal
efficiency and coal with a sulfur content of 3.8 percent, was
measured at 300 ng/J (0.7 Ib/million Btu).
plant and emission rate data.
tt
Table 3 presents
tt
IPCB Regulations 203(g)(l)(C) and 204(C)(1)(A) were invali-
dated by Illinois Supreme Court January 20, 1976.
Rate based on tests conducted June 3, 1975, and June 4, 1975,
with coal averaging 3.98 percent sulfur.
Rate based on tests conducted September 28, 1976.
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Table 3. DESIGN, OPERATION, AND EMISSIONS,
WILL COUNTY UNIT 1
Total rated generating capacity, MW
Boiler manufacturer
Year placed in service
Unit heat rate, (1975) kJ/net kWh
(Btu/net kWh)
Unit capacity factor, percent (1975)
Maximum coal consumption rate,
kg/sec (short tons/hr)
Maximum heat input,
GJ/hr (106 Btu/hr)
Served by stack No.
Stack height above grade,
meters (feet)
Design maximum flue gas rate,
m3/Sec @ 179°C (acfm @ 355°F)
Emission controls:
Particulate
Sulfur dioxide
Particulate emission rates:
Allowable, ng/J (lb/106 Btu)
Actual, ng/J (lb/106 Btu)
Sulfur dioxide emission rates:
Allowable, ng/J (lb/106 Btu)
Actual, ng/J (lb/106 Btu)
167
Babcock & Wilcox
1955
11,835
(11,217)
49.5
21.4 (85)
1,688 (1,600)
1
107 (350)
363 (770,000)
ESP and venturi
scrubbers
Venturi scrubbers
and sieve tray
absorbers
86.0 (0.2)a
34.4 (0.08)b
774 (1.8)a
300 (0.7)c
IPCB regulations 203(g)(l)(C) and 204(C)(1)(A) were invalidated
by Illinois Supreme Court January 20, 1976.
•L
Based on tests conducted June 3, 1975 and June 4, 1975.
c Based on tested FGD removal efficiency of 89.2 percent
for coal with a sulfur content of 3.8 percent (tests conducted
September 28, 1976).
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SECTION 3
FLUE GAS DESULFURIZATION SYSTEM
PROCESS DESCRIPTION
The wet limestone scrubbing system designed and installed by
B&W on Will County Boiler 1 is guaranteed to remove 98 percent of
particulate matter and 76 percent of sulfur dioxide. Removal
efficiency values are based on inlet loading conditions of 3.1
g/m (1.355 gr/scf) at 21°C (70°F) while burning Illinois coal,
with a sulfur content of 4 percent.
The wet limestone scrubbing system backfitted on the boiler
includes a limestone handling and milling system, a sludge dis-
posal system, and two parallel scrubber-absorber trains, each
designed to treat half the boiler flue gas. The B-side scrubbing
train went into commercial service February 23, 1972, and the A-
side scrubbing train on April 7, 1972. Many problems were en-
countered, which resulted in numerous system modifications.
These are discussed in detail in Section 4. The Will County wet
scrubber system is described in terms of three basic operations:
(1) limestone handling and milling, (2) wet scrubber and absorber
trains, and (3) sludge handling and disposal.
Limestone Handling and Milling
Figure 1 depicts the limestone handling and milling facility
at Will County Station. It handles limestone used for both
scrubbing trains and includes a rock conveyor, two storage silos,
two wet ball mills, one slurry storage tank, and two slurry feed
pumps.
The limestone,.a coarse-ground form about 2 cm (0.75 in.) or
less in diameter, is purchased from Rigsby and Barnum Company,
and arrives by river barge. It is unloaded at Will County by
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RECLAIM HOPPER
RECYCLE TANK
AND PUMPS
SLURRY
STORAGE
TANK
SLURRY
TRANSFER
PUMPS
TO WET SCRUBBER
Figure 1. Limestone handling and milling facilities, Will County Station,
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coal-handling equipment and transferred by conveyor to two 236-Mg
(260-ton) silos. The storage capacity of the silos meets the
limestone requirements of FGD operation at full load.
Each storage silo discharges onto a gravimetric feeder that
supplies one of two full-size wet ball mill and classification
systems. Each system can grind limestone at a rate of 3 kg/sec
(12 ton/hr) to a fineness of 95 percent minus 325 mesh. The
chemical specifications required allow a minimum calcium car-
bonate content of 97 percent and magnesium and silica contents of
less than 1.0 and 0.5 percent respectively.
The wet ball mills discharge a limestone slurry containing
25 to 30 percent solids to a storage tank. This tank, which has
a liquid capacity of 236,588 1 (62,500 gal.), is agitated contin-
uously. It was designed to retain the slurry 4 hours before it
is pumped to the scrubbing system. The entire limestone milling
facility was designed so that one wet ball mill could supply
limestone slurry for both scrubbing trains at full-load flue gas
capacity.
Wet Scrubber and Absorber Trains
The wet scrubber-absorber system is composed of two identi-
cal parallel scrubbing trains, referred to above as the A-side
and the B-side. Each train was designed to treat approximately
50 percent of the flue gas, or 182 m /sec (385,000 cfm) at 179°C
(355°F). The flow of flue gas and solutions through the scrub-
bing system is illustrated in Figure 2 and described below.
Flue gas emerges from the boiler and passes through an
existing ESP (Western, 90 percent design removal efficiency)
where primary particulate removal takes place. A by-pass damper,
installed downstream from the ESP, permits the gas to by-pass
either scrubbing train, or both. The flue gas then enters the
scrubbing system through a venturi, where it is contacted with
jets of scrubbing s-lurry sprayed countercurrently from high-
pressure nozzles on each side of the rectangular venturi throat.
Flue gas velocity and particulate removal are maintained at
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COAL FEED
oo
EXISTING
INDUCED-DRAFT FAN
BOILER
BYPASS
DAMPER
ESP
TO SLUDGE
WASTE POND
VENTURI
PUMPS
INDUCED-DRAFT
BOOSTER FAN
SUMP
VENTURI
RECIRCULATION
TANK
\
ABSORBER
ABSORBER
RECIRCULATION
TANK
FROM MILL
SYSTEM
ABSORBER
PUMPS
Figure 2. Flow diagram of Will County Boiler 1 and FGD system.
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37 m/sec (120 ft/sec) and 94.3 percent respectively, by regula-
ting the pressure drop across the throat at 2.2 kPa (9 in. H20).
Quenched flue gas and slurry droplets pass through the sump,
where the large gas velocity reduction causes the droplets to
leave the flue gas stream. The gas then flows upward through the
sulfur dioxide absorber tower at the greatly reduced superficial
gas velocity of 3 m/sec (10 ft/sec). The A-side and Bside
absorber towers contain two sieve trays wetted by limestone
slurry sprays above the trays. The trays provide an extended
wetted surface for absorption of the sulfur dioxide from the flue
gas by circulated slurry. Pressure drop through the absorption
section of each module at full-load conditions is 2.5 kPa (10 in.
H20).
The cleaned flue gas then continues upward through a mist
eliminator (Z-shaped, two-stage, three-pass, chevron-type). Fine
mist droplets coalesce on the surface of the mist eliminator,
which is equipped with two sets of wash water headers. The lower
stage is washed continuously by an underspray of 7.9 I/sec (125
gal./min) of fresh water and intermittently by an overspray of
63.1 I/sec (1,000 gal./min) of pond water for 90 seconds every
hour. The scrubbed gas then enters the reheater unit, where its
temperature is raised from 53°C to 82°C (128°F to 180°F). Reheat
is necessary to prevent condensation in the fans, ducts, and the
existing brick-lined stack. The reheat also makes the plume
buoyant and thus reduces its visibility.
Each bare tube reheater has nine sections. The bottom three
sections of both the A-side and the B-side units are made of
316 L stainless steel, and the remaining six sections are of
carbon steel. Each reheater also has four soot blowers. Heat is
supplied by saturated steam from the boiler at 2,515 kPa (350
psig) and 252°C (485°F). Condensate from the reheater is re-
turned to the steam circuit at the deaerator heater. An ad-
ditional temperature boost of approximately 11°C (20°F) from 82°C
(180°F) to 93°C (200°F) is provided by the fans.
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To compensate for draft loss across the two scrubbing
trains, two 1,679-kW (2,250-hp) I.D. booster fans, one per train,
were installed at the suction side of the existing boiler I.D.
fans.
Both scrubbing trains have two recirculation tanks, each
with a capacity of 151 kl (40,000 gal.). One services the
venturi scrubber, the other the absorber. Spent scrubbing slurry
is discharged from the venturi recirculation loop. The two tanks
are tied together in such a way that spent liquor from the ab-
sorber recirculation tank flows into the venturi circulation
tank. All tanks are fitted with an agitator and pumps. The
slurry recirculation rate to the absorber is approximately 649
I/sec (11,000 gal./min), equalling a liquid-to-gas ratio (L/G) of
5 1/m3 (35 gal./I,000 ft3) of gas at 49°C (120°F). The liquid
recirculation rate to the venturi is 366 I/sec (5,800 gal./min),
3 3
an L/G of approximately 2.5 1/m (18 gal./I,000 ft ) of gas at
52°C (125°F).
Sludge Handling and Disposal
Figure 3 illustrates the present scrubbing wastes handling
and disposal system employed at the Will County Station. Wastes
are discharged from the A-side and B-side venturi recirculation
loops either to a 65-diameter thickener or directly to the sludge
waste pond. The latter mode is used only in emergencies, or when
the thickener is out of service. Clarified water is returned to
the process for use in the scrubbing and milling systems.
Thickener underflow or retrieved ponded sludge is stabilized
with fly ash and lime and hauled in concrete mixing trucks to an
off-site disposal area. Stabilization is achieved at a ratio of
181 kg (400 Ib) of fly ash and 91 kg (200 Ib) of lime per 0.9 Mg
(ton) of dry solids of sludge.
Tables 4 through 8 summarize operating data, design param-
eters, and design specifications for the major unit operations of
the Will County Boiler 1 FGD scrubbing system.
10
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X
RECYCLED THICKENER
OVERFLOW AND POND
SUPERNATANT TO MODULE
SCRUBBER SLUDGE POND
THICKENER UNDERFLOW
HOPPER
TO OFF-SITE
DISPOSAL AREA
Figure 3. Sludge stabilization and disposal facilities, Will County FGD system.
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Table 4. SUMMARY OF DESIGN DATA, SCRUBBING TRAINS
Item
Venturi scrubber
SC>2 absorber
tower
Number
3
L/G ratio, 1/m
(gal./lOOO acf)
Superficial gas
velocity, m/sec
(ft/sec)
Equipment size, m (ft]
Material of
construction
Shell
Internals
2.5
(18)
37
(120)
2.5 x 8 x 15
(8 x 26 x 16)
[throat 6.4 x 0.5
(21 x 1.8)1
Carbon steel
coated with
plasite
Kaocrete
5
(35)
3
(10)
5 x 7 x 18
(16 x 24 x 60)
Corten steel,
rubber lined
316L SS
12
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Table 5. SUMMARY OF DESIGN AND OPERATING DATA, MIST ELIMINATORS
Number
Type
Shape
Material of construction
Number of stages
Number of passes
Distance between stages, m (ft)
Spacing between vanes, cm (in.)
Pressure drop, kPa (in. H-O)
Configuration
Wash system:
Type
Duration
Rate
Chevron
Z-shape, 90° sharp-angle
bends
FRP (Hetron)
2
3
1.2 (4)
3.8 (1.5)
0.25 (1.0)
Horizontal
Fresh water underspray/
pond return overspray for
first stage; second stage
not washed.
Underspray - continuous;
overspray - intermittent
Underspray - 7 to 8 I/sec
(113 to 126 gal./min);
overspray - 63 I/sec
(1000 gal./min) for 40
sec for each module per
hour of operation.
13
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Table 6. SUMMARY OF DESIGN AND OPERATING DATA, REHEATERS
Number
Type
Flue gas reheat:
3
Flow rate, m /sec (acfm)
Temperature, °C (°-F)
SO,., Concentration, ppm (average)
Design:
Number of tube banks
Tube size
Material of construction
Soot blowing
Heating medium:
Pressure, kPa (psig)
Temperature, °C (°F)
Consumption rate, kg/sec (Ib/hr)
Outlet gas temperature, °C (°F)
Energy consumption, % of boiler
input
Steam in-line reheat
179 (380,000)
53 (128)
500
3, 9 rows per bank
1.6 cm (0.62 in.) O.D.,
bare tube
316L SS and carbon steel
Every 4 hours
2,515 (350)
252 (485)
6 (50,000)
71 (160)
3.2
14
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Table 7. SUMMARY OF DESIGN DATA, RECIRCULATION AND MAKEUP TANKS
Item
Total number of
tanks
Retention time
at full load
Temperature, °C
(°F)
PH
Solids content,
percent
Specific gravity
Material of
construction
Venturi
scrubber
recirculation
tank
2
Variable*
53
(128)
5.1-5.7
8
1.102
Rubber-lined
carbon steel
SO- absorber
tower
recirculation
tank
2
Variable1"
53
(128)
5.8
8
1.049
Rubber -lined
carbon steel
Limestone
slurry
makeup
tank
1
4 hr
Ambient
7.0
15-30
Carbon steel
Table 8. DESIGN PRESSURE DROP FOR EACH SCRUBBING TRAIN
[kPa (in. H20)]
Venturi scrubber
Sieve tray absorber
Mist eliminator
Reheater
Ductwork
Total FGD system
2.2 (9)
2.5 (10)
0.25 (1)
1.5 (6)
0.75 (3)
7.20 (29)
Design value is 8 minutes. Different rates were used on an
experimental basis during the course of the S02 program.
t Design value is 4 minutes. Different rates were used on an
experimental basis during the course of the S02 program.
15
-------
PROCESS CHEMISTRY: PRINCIPAL REACTIONS
The chemistry involved in the wet limestone scrubbing
process is complex, and a detailed account is beyond the scope of
this discussion. The principal steps involved in this process,
however, are discussed as follows:
Initially, the sulfur dioxide must diffuse from the gas
phase into the liquid phase
SO,, i < * S00 , v
2 2 (aq.)
The sulfur dioxide dissolved in the aqueous phase next undergoes
hydrolysis and ionization, yielding sulfurous acid, bisulfite,
sulfite, and hydrogen ions
S00 , v + H00 « » H.SO,
2 (aq. ) 2 23
In addition to the formation and subsequent ionization of sul-
furous acid, some of the sulfur dioxide reacts with oxygen in the
gas phase to yield sulfuric acid, bisulfate, sulfate, and hy-
drogen ions.
2S02 + + 02 t « ** 2S03 i
4
Analagous to the gas-phase oxidation steps discussed above, the
sulfite ion undergoes oxidation by dissolved oxygen present in
the scrubbing solution and forms a sulfate ion according to the
following reaction:
16
-------
The dissolution and ionization of the limestone additive
into an acidic medium yields the ionic species of calcium,
carbonate, bicarbonate, and calcium bicarbonate.
The calcium ions react with the sulfite and sulfate ions in the
aqueous phase, resulting in the formation and precipitation of
calcium sulfite and calcium sulfate salts.
Ca++ + SO3=^=±CaS03
CaS03 + 1/2 H20 < > CaS03-l/2 H2O +
Ca++ + S04=^=±:CaS04
CaSO. + 2 H-0 < * CaSO -2 H_0 4-
42 42
PROCESS CONTROL
Figure 4 is a diagram of the instrumentation and controls
for the scrubber- absorber train portion of the Will County FGD
system. The controls are designed to maintain optimum operating
efficiency by monitoring the following process variables: pres-
sure drop across the venturi throat, limestone feed, and scrub-
bing solution pH. Monitoring and control are performed automati-
cally from the scrubber control room panel in the boiler control
room.
Gas loading
The modulation of the gas flow through the scrubbing system
is controlled as a function of boiler load variation. This is
accomplished automatically by a boiler load signal, which con-
trols the I.D. fan speed and booster fan dampers.
17
-------
oo
6140 g/sec
(48,700 Ib/hr)
VENTURI -
ABSORBER MODULES
ABSORBER
RECIRCULATION
FLOW
3697 g/sec
(29,340 Ib/hr
55 I/sec
(867 gal/min)
XvTTNTinn
RECIRCULATION
FLOW
733 l/»1n
(11,612 9*1/«1n)
1090 1/min
(17,280 gal/min)
Figure 4. Instrumentation and control diagram, Will County FGD Modules.
-------
Pressure drop across the venturi
Particulate removal efficiency and superficial gas velocity
in the scrubbing system are regulated by controlling the pressure
drop across the venturi throat. A constant value of 2.2 kPa (9
in. H_0) is maintained by a differential pressure controller and
pressure indicator network installed on the venturi throat. This
network is in turn connected to the throat-drive motor, which
expands or contracts the throat opening.
Limestone slurry feed
The limestone slurry feed to the scrubbing system is con-
trolled by monitoring the scrubbing solution pH at the venturi
inlet. The pH control range is variable. When the pH drops
below or exceeds the control range, the feed rate of fresh lime-
stone slurry is increased or decreased to the scrubbing system by
opening or closing the feed valves.
Spent slurry discharge
Spent scrubbing slurry is discharged from the scrubbing
system off the venturi recirculation line and transported to the
thickener. The amount of waste blowdown is regulated by' a level
controller. This controller works in conjunction with a flow
control valve, which is opened and closed as a function of the
liquid level in the venturi recirculation tank.
Sulfur dioxide level
The concentration of the sulfur dioxide species in the flue
gas is checked periodically by wet chemical techniques.
19
-------
SECTION 4
FGD SYSTEM PERFORMANCE
PERFORMANCE TEST PROGRAMS
Three performance test runs have been conducted on the Will
County FGD system. Babcock & Wilcox conducted a series of pre-
liminary performance tests in May, and during July and August,
1972, and the utility itself did tests during a high-sulfur coal
burn program in May 1975, and September 1976.
Table 9 summarizes the results of the May 1972 test program.
Outlet particulate loading during the test varied from 0.0167 to
0.0764 g/m3 (0.0073 to 0.0334 gr/scf). The design guarantee
value was 0.0568 g/m (0.0248 gr/scf). Sulfur dioxide removal
efficiency and resulting outlet values were not applicable to the
design guarantee because a varying blend of low-sulfur western
coal and high-sulfur Illinois coal was burned. During normal
operating conditions, sulfur dioxide removal efficiency was about
80 percent. It dropped to 67 percent when the limestone slurry
feed to the scrubbing system was deliberately reduced.
During the July-August 1972 test period, the system treated
flue gas from the combustion of high-sulfur Illinois coal (the
design coal). Outlet particulate loading varied from 0.0487 to
0.0636 g/m3 (0.0213 to 0.0278 gr/scf). Sulfur dioxide removal
efficiency varied from 67 to 94 percent. As in the May 1972 test
period, all the runs were made on the A-side with the ESP unit
de-energized. Tables 10 and 11 summarize the results.
A high-sulfur burn test program was initiated by the utility
in May 1975, during which sulfur dioxide removal, particulate
removal in the scrubber, and ESP removal efficiencies were mea-
sured and the process chemistry was monitored. Removal effi-
20
-------
Table 9. PRELIMINARY TEST DATA, A-SIDE SCRUBBING TRAIN
MAY 18 TO 23, 1972
Test number
Date
Load, MW
Gas flow, ra /sec
(acfm x 103)
Scrubber system,
pressure drop, kPa
(in. H20)
Dust inlet, g/m
(gr/dscf)
Dust outlet, g/m
(gr/dscf)
SO, inlet, ppm
S02 outlet, ppm
S0_ removal
efficiency, %
Absorber slurry solids
concentration, %
Absorber pH
1
5-18
113
158
(335)
6.1
(24.5)
0.0531
(0.0232)
1145
67
94
3.4
6.5
2
5-18
113
168
(355)
7.2
(29)
0.216
(0.0944)
0.0181
(0.0079)
1140
75
93
5.2
6.3
.3
5-19
114
158
(335)
5.2
(21)
0.330
(0.1440)
0.0167
(0.0073)
890
294
67
5.5
7.4
4
5-19
115
160
(340)
6.2
(25)
0.336
(0.1470)
0.0682
TO. 0298)
930
35
96
5.2
6.3
5
5-20
111
158
(335)
6.0
(24)
0.253
(0.1105)
0.0597
(0.0261)
1130
285
75
• 2.5
5.7
6'
5-20
112
151
(320)
6.3
(25.5)
0.410
(0.1790)
0.0584
(0.0255)
1000
118
88
4.3
5.8
7
5-21
113
149
(315)
5.6
(22.5)
640
18
97
5.0
7.2
8
5-21
115
146
(310)
5.5
(22.0)
910
45
95
5.7
9
5-22
110
149
(315)
5.8
(23.2)
0.700
(0.3060)
0-.0469
(0.0205)
1000
223
81
2.9
5.9
10
5-22
111
158
(335)
5.7
(23.0)
0.590
(0,2580)
0.0764
(0.0334)
545
180
67
2.2
5.4
11
5-23
97
(205)
4.0
(16.0)
1200
45
95
6.1
12
5-23
58
101
(215)
4.5
(18.0)
1150
50
96
1.5
6.1
-------
Table 10. PRELIMINARY TEST DATA, A-SIDE SCRUBBING TRAIN
JULY 25 TO AUGUST 7, 1972
to
NJ
Test number
Date
Load, MW
Gas flow, m /sec
(acfm x 103)
Scrubber system, pressure
drop, kPa (in. H20)
Dust inlet, (g/m )
(gr/dscf)
Dust outlet, g/m
(gr/dscf)
Absorber slurry solids
concentration, %
Absorber pH
1
7-25
102
154
(326)
5.0
(20)
0.996
(0.4354)
0.0487
(0.0213)
2
4.7
2
7-26
100
130
(276)
3.6
(14.5)
0.574
(0.2508)
0.0522
(0.0228)
2
5.7
3
7-27
112
172
(364)
5.8
(23.5)
0.424
(0.1855)
0.0502
(0.0220)
2
4
8-4
104
181
(383)
6.5
(26)
0.475
(0.2075)
0.0524
(0.0229)
2
6.0
5
8-4
103
181
(383)
6.7
(27)
0.231
(0.1008)
0.0508
(0.0222)
11
6.2
6
8-7
98
189
(400)
6.5
(26)
0.535
(0.2339)
0.0636
(0.0278)
11.8
6.2
-------
Table 11. PRELIMINARY TEST DATA, A-SIDE SCRUBBING TRAIN
AUGUST 8 TO 12, 1972
Test number
Date
Gas flow, ra /sec ,
(acfm x 10J)
Scrubber system, pressure
drop, kPa (in. H2O)
SO, inlet, ppm
SO- outlet, ppm
SO2 removal efficiency, %
Absorber, pH
1
8-8
76
(160)
6.6
(26.5)
2400
300
87.6
5.7
2
8-8
170
(360)
6.5
(26.0)
2860
960
66.4
5.9
3
8-9
107
(226)
5.2
(21.0)
2720
495
81.8
4.9
4
8-9
167
• (353)
7.2
(29.0)
2680
800
70.0
5.0
5
8-10
170
(360)
7.0
(28.0)
2700
185
93.2
5.5
6
8-10
167
(353)
6.7
(27.0)
1065
63
94.1
6.6
7
8-11
163
(345)
6.5
(26.0)
1600
280
82.5
6.4
' 8
9-11
221
(468)
7.0
(28.0)
2230
570
74.4
9
8-12
175
(370)
7.0
(28.0)
2260
520
77.0
10
8-12
175
(370)
7.3
(29.5)
2350
765
67.3
to
-------
ciency tests were conducted under full- and partial-load condi-
tions with the upstream ESP in and out of service. Sulfur diox-
ide removal efficiencies averaged 78.2 percent and 86.8 percent
for the A-side and B-side respectively. The average sulfur
dioxide inlet loading was 3573 ppm. The A-side value was lower
because only one of the two absorber recirculation pumps was in
service, resulting in a lower L/G. Slurry carryover in the
scrubber resulted in lower particulate removal efficiencies than
expected, and this caused high particulate loadings at the scrub-
ber outlet.
SUMMARY OF SYSTEM PERFORMANCE
The performance of the FGD system since start-up is de-
scribed below on a yearly basis. Details of the 1975, 1976, and
1977 (July), operations are summarized in Table 12.
1972 Operation
The B-side scrubbing train, which included a TCA absorber,
was first placed in service February 23, 1972. The A-side came
on-line April 7, 1972. To the end of 1972, the A-side was in
service a total of 1444 hours and the B-side, 1237 hours. The
average annual operability index values for the A- and B-sides
were 30 and 25 percent respectively. The longest period of con-
tinuous operation was 21 days, achieved by the A-side. Simul-
taneous operation of the scrubbing trains totalled 469 hours; the
longest continuous period was 6 days.
1973 Operation
In April 1973, the utility discontinued operation of the B-
side scrubbing train to concentrate on the A-side. The A-side
remained in service until November, when it was brought down for
repairs and modifications. By this time it had been in service a
total of 1726 hours, providing a 23 percent operability index for
the year.
24
-------
Table 12. SUMMARY OF FGD SYSTEM PERFORMANCE, WILL COUNTY FGD SYSTEM:
1975, 1976, AND 1977 (JULY)
NJ
Ul
Period
Jan. 75
Feb. 75
Mar. 75
Apr. 75
May 75
June 75
July 75
Aug. 75
Sept. 75
Oct. 75d
Nov. 75
Dec. 75
Total
Hours
744
672
744
720
744
720
744
744
720
744
720
744
8760
Unit
hours
685
666
609
638
744
642
689
565
720
195
Module
A
A
A
A
A
B
A
B
B
B
B
B
Hours
676
662
605
253
629
276
390
543
547
568
452 •
195
Scheduled overhaul of
Scheduled ove
6153
A
B
rhaul of
3123
2580
System performance factors, percent
Availability3
99
'99
94
37
84
37
64
85
79
94
63
32
boiler, turbine
boiler, turbine
40
34
Operability
99
99
99
40
84
37
61
85
79
100
63
100
, and scrubbe
, and scrubbe
52
42
Reliability
91
99
86
95
100
100
84
88
93
82
100
81
rs
rs
38
31
Q
Utilization
91
99
81
35
84
37
54
75
74
76
63
26
37
29
(Continued)
-------
Table 12 (Continued).
CT\
Period
Jan. 76
Feb. 76
Mar. 76
Apr. 76
May 76
June 76
July 76
Aug. 76
Sept. 76
Oct. 76
Nov. 76
Dec. 76
Total
Hours
744
696
Unit
hours
Sche
Module
Juled ovei
Hours
"haul of
|
Scheduled overhaul of
744 ; 309'
720
744
720
744
744
720
744
720
744
8760
690
665
612
598
495
566
726
569
692
5920
A
B
A
B
B
A
B
A
B
A
B
A
B
A
B
A
B
A
B
A
B
140
63
138
340
567
271
517
0
538
285
304
163
431
208
408
145
394
334
357
1684
3919
System performance factors, percent
Availability3
boiler, turbine
boiler, turbine
30
9
23
Operability | Reliability1'
and scrubbe
and scrubbe
45
20
20
51 49
87
52
72
20
84
98
65
42
79
30
76
20
72
45
53
27
56
85
44
85
0
90
57
61
29
76
29
56
26
70
48
52
28
66
rs
rs
62
97
83
93
88
72
83
0
84
96
54
28
74
28
70
20
66
45
51
22
50
Utilization0
19
8
19
47
76
38
72
0
72
38
41
42
60
28
55
20
55
45
48
19
44
(Continued)
-------
Table 12 (Continued).
Period
Jan. 77
Feb. 77
Mar. 77
Apr. 77
May 77
June 77
July 77
Total
Hours
744
672
744
720
744
720
744
5080
Unit
hours
722
613
727
650
691
566
377
4347
Module
A
B
A
B
A
B
A
B
A
B
A
B
A
B
A
B
Hours
713
8
261
280
478
550
441
196
15
352
76
529
201
201
1923
2071
System performance factors, percent
Availability
98
14
39
72
97
81
86
45
89
98
32
93
27
70
72
67
Operability
99
1
42
45
66
75
68
30
2
51
13
93
53
41
44
48
Reliability
98
1
81
33
16
96
13
92
27
41
58
55
Utilization
96
1
39
41
64
73
61
21
2
47
10
73
27
21
38
41
Availability index: The number of hours the FGD system is available for operation (whether
operated or not), divided by the number of hours in the period, expressed
as a percentage.
Reliability index: The number of hours the FGD system is in operation for a given period,
divided by the number of hours the FGD system is called upon to operate in
the period, expressed as a percentage.
c Utilization index: The number of hours the FGD system is in operation for a given period,
divided by the number of hours in the period, expressed as a percentage
21-week scheduled turbine, boiler and scrubber outage began Oct. 11.
-------
1974 Operation
The A-side scrubbing train remained in service throughout
the year, accumulating 5468 hours of operation. The train was
available 6025 hours and the boiler was operational 7924 hours.
These figures represent a 69 percent operability and availability
index for the year.
1975 Operation
Operations in 1975 commenced in much the same manner as in
1974. The A-side was operational, the B-side still out of ser-
vice. The A-side remained in service until mid-June, when it was
taken out for extensive repairs and modifications. The average
operability index for the A-side, through June 20, was 80 per-
cent. The A-side remained out of service throughout the year.
Modifications to the B-side (the TCA absorber was converted to a
sieve tray unit) were completed and it was returned to service
May 20. The B-side operated almost without incident until
October 11, when Unit 1 was shut down for a scheduled boiler,
turbine, and scrubber overhaul. During the year, the generating
unit was in service 6152 hours; the A-side and B-side scrubbing
trains were available 3463 and 2969 hours, respectively, and
actually operated 3213 and 2580 hours respectively. Based on
these service hours, the following index values were calculated
for 1975 operations: A-side availability, operability, reliabil-
ity, and utilization were 40, 52, 38, and 37 percent, respective-
ly; B-side values for the same parameters were 34, 42, 31, and 29
percent respectively- The average sulfur content of the coal
burned in Unit 1 during the year was 1.5 percent.
1976 Operation
Unit 1 was returned to service in March following the 4-
month overhaul. The A-side and B-side were returned to service
March 22 and 29 respectively. During the year, the generating
unit was available for service 6450 hours and was operated 5920
hours. The A-side and B-side scrubbing trains were available
28
-------
2634 and 4883 hours respectively, and were operated 1684 and 3919
hours respectively. Based on these service hours, the following
index values were calculated for 1976 operations: the generating
unit was 73 percent available; A-side availability, operability,
reliability, and utilization were 27, 28, 22, and 19 percent
respectively. B-side values for the same parameters were 56, 66,
50, and 44 percent respectively. The average sulfur content of
coal burned in Unit 1 during the year was sightly over 1 percent.
1977 Operation
In July 1977, Commonwealth Edison officially concluded the
Will County sulfur dioxide scrubbing program. The scrubbers are
still in service, removing primarily fly ash and some sulfur
dioxide from the flue gas. Low-sulfur western coal is burned.
From January to July 1977, several test programs were conducted
by the utility, including the evaluation of continuous sulfur
dioxide analyzers; high-sulfur coal sludge evaluations; magnesium
oxide beneficiation of the limestone slurry; and forced oxidation
testing. Virtually all operations were conducted on low-sulfur
western coal. During this period, the generating unit was avail-
able for service 4394 hours and operated 4347 hours. The A-side
and B-side scrubbing trains were available 3689 and 3436 hours
respectively, and were operated 1923 and 2071 hours respectively.
Based on these service hours, the following index values were
calculated for operations from January to July 1977: generating
unit availability was 86 percent; A-side availability, operabil-
ity, reliability, and utilization were 72, 44, 58, and 38 percent
respectively; B-side values for the same parameters were 67, 48,
55, and 41 percent respectively.
PROBLEMS, SOLUTIONS, AND SYSTEM MODIFICATIONS
The Will County FGD system has been beset with numerous
problems since commercial operation began in February 1972. The
major problems, solutions, modifications, and experiments per-
formed on the scrubbing system are described below.
29
-------
Scrubbing modules
By April 1972, the two scrubbing trains had been placed in
the flue gas path: both encountered more problems than had been
expected. This resulted in the utility's discontinuing operation
of the B-side to concentrate on achieving satisfactory operation
of the A-side. By 1974 performance of the A-side had improved to
the point where the utility decided to use the B-side again. The
B-side was therefore modified to be identical with the A-side.
The major change was the removal of the mobile-bed packing in the
absorber and its replacement with two stages of sieve trays.
Following completion of conversion to a tray tower, both
scrubber-absorber vessels experienced -major problems in the form
of scale and erosion. Massive gypsum scaling developed in the
sump areas of the scrubbing trains. The scale film was reported
to be over 1.3 cm (0.5 in.) thick in some places. The scale was
removed by shutting the system down and chipping gypsum off the
various scrubber internals. Erosion of the scrubber vessel
• occurred in the horizontal plate above the venturi inlet wash
box. A number of holes developed, allowing slurry to seep
through and over the outer shell of the venturi. This problem
was corrected by fitting each wall wash nozzle with a deflector
to redirect the path of the slurry.
Mist eliminators
Fouling and scaling of the mist eliminators in both scrub-
bing trains has been a persistent problem from the outset of
commercial operation. Fouling occurred primarily because of the
accumulation of the heavy limestone slurry on the lower sections
of the mist eliminators. To rectify this, the wash system was
modified so that the nozzles sprayed upward onto the bottom
sections of the mist eliminators. Plugging continued to be a
problem, however, requiring the addition of extra spray nozzles
and the use of a continuous fresh makeup water underspray and an
intermittent pond return overspray, which uses a water deluge
wash system. The increased amount of fresh makeup water re-
30
-------
quired, however, upset the system's water balance to the extent
that the underspray system had to be modified to an intermittent
wash system that alternated on a 5-minutes on/5-minutes off
basis.
In May 1975, during the high-sulfur coal burn program, the
mist eliminator wash system was again modified. Because use of
saturated pond return water caused additional scale development
and minor plugging in the mist eliminators, the underspray was
converted back to a continuous spray.
Reheaters
The flue gas reheaters have also been the site of numerous
problems since initial commercial operation. The major problems
included plugging, scaling, stress corrosion cracks in the 304
stainless steel tubes, and eventual failure of the corten tubes.
Plugging and scaling in the reheat section are a direct function
of the performance of the upstream mist eliminators.
Each bare tube reheater includes a total of nine sections
and four sootblowers. The bottom three sections were originally
constructed of 304 stainless steel, the top six of corten. These
bundles have been replaced by 316L stainless steel tubes in the
lower three banks and by carbon steel tubes in the upper six
banks. By 1975, six of the 12 new carbon steel bundles had
developed peripheral cracks. All of the failures occurred be-
cause the tube supports had worked loose, permitting excessive
vibration. The coil manufacturer repaired and modified all the
tube bundles by redesigning the tube supports and installing an
additional support.
Recirculation
The design retention times of the venturi scrubber and
absorber recirculation tanks are 4 minutes and 8 minutes respec-
tively. The utility has determined, however, that 50 percent of
the flow into the tank system is immediately recycled to the
scrubbing system with little or no retention time. Half the
31
-------
scrubbing solution therefore lacks sufficient time for chemical
reactions to be completed before recirculation to the scrubbing
system.
Pumps
Three 100 percent capacity venturi recirculation pumps, each
rated at 315 I/sec (5000 gal./min) , and four 60 percent capacity
absorber recirculation pumps, each rated at 331 I/sec (5250
gal./min), were provided for both scrubbing trains. Problems
with these pumps have been minimal. One of the absorber recircu-
lation pumps was damaged when a check valve failed in the dis-
charge piping and parts fell into the pump, damaging the impel-
ler and destroying the rubber lining. It was determined that the
rubber lining in the check valve had eroded, allowing the base
material to corrode and eventually fail. The system supplier
reviewed the need for check valves in the pump discharges, recom-
mending that they be removed and the spool pieces re lined with
rubber.
Sludge treatment
Thickener underflow or retrieved ponded sludge is treated in
mixing trucks together with lime and fly ash and hauled to an
offsite disposal area. Until September 1975, the treated mate-
rial was initially disposed of in an on-site, clay-lined disposal
basin where the material would set up. Operation of this inter-
mediate hold basin has since been discontinued, and a local firm
is now transporting treated sludge from the plant directly to the
off-site disposal area.
The utility has purchased a belt-type vacuum filter, which
went into service in late 1976. This filter had the advantage of
changing the sludge handling method and reducing treatment costs.
The additional water recovery, however, has affected the system's
water balance, making it more difficult to approach closed loop
operations.
32
-------
ESP
After installation of the FGD system, the upstream ESP was
to operate only when the FGD unit was out of service. Neverthe-
less, it is now operated on a full-time basis. This allows
maximum particulate removal and minimizes the amount of fly ash
in the scrubbing system, thus alleviating a problem of high
solids content in the scrubbing liquor.
Instrumentation
Because of instrument failures and inaccurate readings,
pH and sulfur dioxide levels have, for the most part, been mea-
sured manually. During the period from January to July 1977,
Commonwealth Edison experimented with a number of continuous
monitors, including both ERT and Dupont sulfur dioxide analyzers.
The utility reported that the Dupont unit performed satisfactor-
ily; it operated with very little maintenance and gave readings
verified by grab samples.
Liners
Liners have failed in the duct between the absorber outlet
and reheater inlet and in the sump walls of the absorber. In
both areas Ceilcote Flakeline 103 coating had been used. The
liner flaked, peeled, or was eroded off, and the bare metal sur-
face soon corroded. This problem was corrected in the sump area
by applying a coating of Kaocrete refractory over the Flakeline
liner.
Chemistry
Process chemistry experimentation and testing focused pri-
marily on pH control, magnesium beneficiation, and forced oxida-
tion. In August 1976, the set point for controlling pH of the
scrubbing solution was reduced from 5.4 to 5.1, in an effort to
reduce scaling and plugging and to increase reagent utilization.
Loss of chemical control and formation of gypsum scale soon
resulted in the return to a pH control point of 5.4. In May
33
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1977, a magnesium oxide addition test was conducted. Although
sulfur dioxide removal efficiency was increased by approximately
10 percent, neither sludge production rate nor limestone utili-
zation was seriously affected. A forced oxidation test was
successfully conducted immediately before termination of sulfur
dioxide scrubbing operations. Using liquid oxygen, approximately
5.7 m3/min. (200 ft3/min.) of gaseous oxygen was fed into each
venturi scrubber downcomer. Oxidation of sulfite to sulfate was
increased from 35 to 90 percent.
SYSTEM ECONOMICS
Estimated capital and operating costs for the FGD system at
Will County Station are presented in Tables 13 and 14 and in
Appendix A. 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. The cost per kilowatt is based on a 137-MW net unit
rating with the FGD system in operation.
FUTURE OPERATION
As indicated previously, sulfur dioxide removal operations
at Will County were concluded in July 1977. Particulate removal
operations are continuing at the facility. Some sulfur dioxide
removal from low-sulfur western coal flue gas is occurring be-
cause of the alkalinity of the scrubbing solution; this is due to
limestone addition for pH control. Actual sulfur dioxide remov-
al efficiencies have not yet been determined. During the more
than 5 years that sulfur dioxide removal operations were con-
ducted at the plant, a vast amount of information was accumulated
on the design and operation of FGD systems. This information is
being used for the design, installation, and future operation of
a full-scale, limestone-based FGD system now under construction
at the utility's Powerton Station, Unit 5, Boiler 51. This sys-
tem, unlike the Will County system, is not designed for test
34
-------
U)
on
Table 13. 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 S02 buildings
Structural steel
Miscellaneous equipment
Sludge treatment
Total
$/kW (net)
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
573,000
$13,873,000
101
Indirect cost
$ 1,600,000
69,000
$ 1,669,000
12
Total cost
$14,900,000
642,000
$15,542,000
113
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Table 14. APPROXIMATE 1975 COST TO OWN AND OPERATE
WILL COUNTY UNIT 1 WET SCRUBBER
Scrubber system
Carrying charges on
$14,900,000
Labor (operating
and technical)
Maintenance (labor
and material)
Limestone
Auxiliary power
Reheat steam
Sludge treatment
Carrying charges
on $642,000
Sludge treatment
$ Annual Cost
2,280,000
81,709
256,656
62,726
586,875
72,595
3,340,561
98,000
546,217
644,217
Scrubber and sludge treatment total cos
3,984,778
$/Mg of coal
$/Ton of coal
13.82
(12.54)
0.50
(0.45)
1.55
(1.41)
.37
(0.34)
3.56
(3.23)
.44
(0.40)
20.24
(18.37)
0.60
(0.54)
3.31
(3.00)
3.91
(3.54)
t
24.15
(21.91)
C/GH
•^/Million Btu
64.89
(65.3)
2.18
(2.3) '
7.01
(7.4)
1.71
(1.8)
15.92
(16.8)
1.99
(2.1)
90.70
(95.7
•
2.65
(2.8)
14.88
15.7
17.53
(18.5)
108.23
(114.2
Notes:
Mills/kWh
7.47
0.27
0.84
0.21
1.92
0.24
10.95
0.32
1.79
2.11
13.06
1. Scrubber system has a 14-year life.
2. Sludge treatment cost includes haulinq to an off-site di
-------
purposes, but for compliance with emission regulations. Table 15
summarizes the Powerton No. 51 FGD system.
37
-------
Table 15. SUMMARY OF FGD DATA, POWERTON STATION UNIT 5,
BOILER 51
FGD unit capacity, MW
Design coal specifications:
Heat content, MJ/kg (Btu/lb)
Sulfur, percent
Ash, percent
Chloride, percent
Moisture, percent
Application (new/retrofit)
Process
Supplier
Absorber type
Number of modules
Exit flue gas capacity m /sec (acfm)
Exit flue gas termperature, °C (CF)
Design removal efficiency:
Particulate, percent
Sulfur dioxide, percent
L/G ratio, I/sec @ °C
(gal./lOOO acf @ °F)
Gas reheat AT, °C (°F)
Sludge disposal
S0_ emission regulation ng/J
(Ib/mi11ion Btu)
Gas bypass capability
FGD schedule milestones:
Contract awarded
Start of construction
Initial operation
'Commercial operation
FGD Economics:
Capital cost, $/kW
Operating cost, mills/kWh
450
24.4 (10,500)(avg.)
3.6 (avg.), 6.0 (max.)
8.3 (avg.), 16.0 (max.)
0 . 2 (max .)
17.3 (avg.)
Retrofit
Limestone
Universal Oil Products
Turbulent contact absorber
735 (1,556,217)
53 (128)
84
8 @ 53°C
(60@ 128)
14 (25)
Stabilized sludge disposed of
on plant grounds in a lined
pond 1.2 km (0.75 miles) from
generating -unit.
774
(1.8)
Yes
February 1976
March 1977
Late 1978
December 1979
117.65
8.70c
N/A - not applicable: ESP upstream of FGD system provides control
of particulate matter.
This is the maximum removal efficiency value based upon 100
percent conversion of 6 percent sulfur coal with a 24.4 MJ/kg
(10,500 Btu/lb) heating value.
Estimated value, which includes the following: 2.7 mills/kWh for
operation and maintenance; 6.0 mills/kWh for auxiliary power
requirements; FGD life span of 30 years.
38
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APPENDIX A
PLANT SURVEY FORM
A. Company and Plant Information
1. Company name: Commonwealth Edison Company
2. Main office: P.O. Box 767, Chicago, Illinois 60&90
3. Plant name; Will County Station
4. Plant location; Romeoville, Illinois
5. Responsible officer; Mr. J. P. McCluskey
6. Plant manager: James R. Gilbert
7. Plant contact: R. Kunshek
8. Position: Director - Environmental Affairs Dept.
9. Telephone number: (312) 294-2906
10. Date information gathered: 6/22/76 and 6/1/77
Participants in meeting Affiliation
G. A. Isaacs PEDCo Environmental, Inc.
B. A. Laseke PEDCo Environmental, Inc.
T. C. Ponder PEDCo Environmental, Inc.
R. Klier PEDCo Environmental, Inc.
H. M. Drake PEDCo Environmental, Inc.
B. Mansfield Commonwealth-Edison
M. Poole Commonwealth-Edison
39
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B. Plant and Site Data
1. UTM coordinates:
2. Sea Level elevation: Sea level
3. Plant site plot plant (Yes, No) : No
(include drawing or aerial overviews)
4. FGD system-plan (Yes, No): See diagram
5. General description of plant environs: A highly indus-
trialized area - many refineries and chemical plants
6. Coal shipment mode; Two types of coal were burned dur-
ing the course of the S02 scrubbing program, both
shipped in by barge. The western, low-sulfur coal,
which is the only coal burned in the boiler after the
SO2 program was completed, is shipped to Havana, Illi-
nois, from southern Montana via rail, unloaded, and
barged upriver.
FGD Vendor/Designer Background
1. Process name: Wet Limestone Scrubbing
2. Developer/licensor name: Babcock & Wilcox
3. Address: Power Generation Group, 20 S. Van Buren
Avenue, Barberton, Ohio
4. Company offering process:
Company name: Babcock & Wilcox
Address: 20 S. Van Buren Avenue
40
-------
Location: Barberton, Ohio
Company contact: Jack F. Stewart
Position; Sales Manager
Telephone number; (216) 753-4511
5. Architectural/engineers name; Bechtel Power Corp.
Address: 50 Beale Street
Location: San Francisco, California
Company contact; Mr. J. J. Smortchevsky
Position: Project Engineer
Telephone number: (415) 764-6262
D. Boiler Data
1. Boiler: Unit 1
2. Boiler manufacturer: Babcock & Wilcox
3. Boiler service (base, standby, floating, peak):
Cycling load service
4. Year boiler placed in service; 1955
5. Total hours operation; (1976) 5,920
6. Remaining life of unit:
7. Boiler type; Radiant cyclone boiler
8. Served by stack no.: One
9. Stack height; 107 m (350 ft)
10. Stack top inner diameter; 3.8 m (12.4 ft)
11. Unit ratings:
Gross unit rating; 167 MW
Net unit rating without FGD: 144 MW
41
-------
Net unit rating with FGD: 137 MW (4% of gross for FGD)
Name plate rating; 177 MW
12. Unit heat rate: 11.8 MJ/net kWh (11,217 Btu/net kWh)
Heat rate without FGD: 11.8 MJ/net kWh (11,217 Btu/net kWh)
Heat rate with FGD: 4 % energy penalty
13. Boiler capacity factor, (1975): 49.5%
14. Fuel type (.coal or oil) ; Coal
15. Flue gas flow:
Maximum: 363 m3/s (770,000 acfm)
Temperature: 179°C (355°F)
16. Total excess air; 4% 02 in flue gas stream
17. Boiler efficiency:
E. Coal Data (See General Comments, Section M, item 1)
1. Coal supplier:
Name: Decker Coal Company
Location: Montana
Mine location: Dietz No., 1
County, State; Montana (southern portion)
Seam: No. 1
2. Gross heating value: 21.2-22.3 MJ/kg (9100-9.600 Btu/lb)
3. Ash (dry basis) : 3.0 - 6.0 %
4. Sulfur (dry basis): 0.3 - 0.6 %
5. Total moisture: 22.0 - 25.0
6. Chloride: Not available
7. Ash composition (See Table Al) Not available
42
-------
Table Al
Constituent
Silica, SiO~
Alumina, A12
-------
Regulation and section No. :
G. Chemical Additives: (Includes all reagent additives -
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)
1. Trade name: Limestone
Principal ingredient: CaCO^ = 97.5%; MgCOT = 0.99%
Function: S02 absorbent
Source/manufacturer: Columbia
Quantity employed: 3 kg/sec (12 tons/hour)
Point of addition; Absorber recirculation tank
Trade name: Lime
Principal ingredient; CaO
Function: Sludge stabilizer
Source/manufacturer: Columbia
Quantity employed: 10 g/kg (200 Ib/ton) of sludge (dry)
Point of addition; Concrete mixing trucks
3. Trade name: Collected coal fly ash
Principal ingredient: Fly ash
Function: Sludge stabilizer
Source/manufacturer: Collected from other operating units
on plant premises.
Quantity employed; 200 g/kg (400 Ib/ton) of sludge (dry)
Point of addition; Concrete mixing trucks
Trade name: N/A*
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
* Not applicable
44
-------
Point of addition:
5. Trade name; N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
H. Equipment Specifications
1. Electrostatic precipitator(s)
Number: One
Manufacturer: Joy Manufacturing/Western Precip. Div.
Particulate removal efficiency; 90% design, 79% actual
Outlet temperature; 168°C (355°F)
Pressure drop:
Mechanical collector(s) N/A
Number:
Type:
Size:
Manufacturer:
Particulate removal efficiency:
Pressure drop:
Particulate scrubber (s)
Number: Two (A and B trains)
Type: Adjustable-throat venturi
Manufacturer: Babcock & Wilcox
Dimensions: 2.4 x 7.9 x 4.9 m (8 x 26 x 16 ft)
-------
Material, shell; Carbon steel
Material, shell lining: Plasite and Kaocrete
Material, internals; N/A
No. of modules: One per train
No. of stages: One per module
Nozzle type: Stainless steel
Nozzle size:
No. of nozzles: 48 venturi, 32 wall wash
Boiler load: 50%
Scrubber gas flow: 182 m3/sec, 179°C (335,000 acfm, 355°F)
Liquid recirculation rate: 366 I/sec (5800 gal./min)
Modulation:
L/G ratio: 2.4 1/m3 (18 gal./lOOO acf)
Scrubber pressure drop: 2240 Pa (9 in. H20)
Modulation:
Superficial gas velocity: 36.6 m/sec (120 ft/sec)
Particulate removal efficiency; 98% (design)
Inlet loading; 366 mg/m3 (0.16 gr/scf)*
Outlet loading: 92 mg/m3 (0.04 gr/scf)*
SO2 removal efficiency:
Inlet concentration:
Outlet concentration:
S02 absorber (s)
Number: Two (A and B trains)
Type: Countercurrent tray tower, two stage
Manufacturer: Babcock & Wilcox
* Based on tests conducted June 3-4, 1975, using high-sulfur
Illinois coal (3.98% sulfur).
46
-------
Dimensions: 4.9 x 7.3 x 18.3 m (16 x 25 x 60 ft)
Material, shell; Corten steel
Material, shell lining: Rubber
Material, internals; Two perforated trays^
No.'of modules: One per train
No. of stages: Two
Packing type: N/A .
Packing thickness/stage: N/A
Nozzle type: Stainless steel
Nozzle size:
No. of nozzles:
Boiler load: 50%
Absorber gas flow; 149 m3/sec, (315,000 acfm, 128°F)
Liquid recirculation rate; 694 I/sec (11,000 gal./min)
Modulation:
L/G ratio:
Absorber pressure drop:
Modulation:
Superficial gas velocity: 3.0 m/s (9 ft/s)
Particulate removal efficiency:
Inlet loading:
Outlet loading; 92 mq/m (0.04 qr/scf)
S02 removal efficiency: 76% (design)
Inlet concentration:
Outlet concentration:
47
-------
5. Clear water tray(s)
Number: N/A
Type:
Materials of construction:
L/G ratio:
Source of water:
6. Mist eliminator(s)
Number: Two (A and B trains)
Type: Chevron
Materials of construction: FRP (Hetron)
Manufacturer: Babcock & Wilcox
Configuration (horizontal/vertical) : Horizontal
Distance between scrubber bed and mist eliminator:
3.05 m (10 ft)
Mist eliminator depth:
Vane spacing: 3.8 cm (1.5 in)
Vane angles: 45'
Type and location of wash system; Continuous fresh
water underspray; deluge pond water overspray
Superficial gas velocity:
Pressure drop: 0.50 kPa (1.0 in. H2O)
Comments: Each mist eliminator is a 2-stage, 3-pass,
Z-shape, 90°, sharp-angle bend unit; 1.2 m (4 ft)
between stages; ___^
7. Reheater(s): Two (A and B trains)
Type (check appropriate category):
48
-------
|2L|' in-line
Q indirect hot air
O direct combustion
Q bypass
Q exit gas recirculation
Q waste heat recovery
EH other
Gas conditions for reheat:
Flow rate; 180 m3/sec (380,000 acfm)
Temperature: 53°C (128°F)
SC>2 concentration: Low and high-sulfur coal
Heating medium: Saturated steam
Combustion fuel: N/A
Percent of gas bypassed for reheat: N/A
Temperature boost (AT): 11°C (52°F)
Energy required; 3.2% of boiler input
Comments: Reheat steam pressure is 2515 kPa (350 psig)
steam temperature is 224°C (435°F) , consumption is
5.7 kg/sec (45,000 Ib/hr) .
8. Fan(s) (Two, 1 per scrubbing train)
Type: Induced-draft boiler booster fan
Materials of construction:
Manufacturer:
Location: Suction side of existing boiler I.D. fan
Fan/motor speed:
Motor/brake power; 1680 W (2250 hp)
49
-------
11.
Variable speed drive:
9. Tank(s)
Item
Total number of
tanks
Retention time
at full load
Temperature, °C
<°F)
PH
Solids content,
percent
Specific gravity
Material of con-
struction
Venturi
scrubber
recirculation
tank
2
Variable
53
(128)
5.1-5.7
8
1.102
Rubber- lined
carbon steel
SO2 absorber
tower
recirculation
tank
2
Variable
53
(128)
5.8
8
1.049
Rubber- lined
carbon steel
Limestone
slurry
makeup
tank
1
4 hr
Ambient
7.0
15-30
Carbon steel
10. Recirculation/slurry pump(s)
Description
Venturi
Recir.
Absorber
Recir.
Mill Prod.
Pumps
Slurry
Transfer
Manufacturer
A-S-H
A-S-H
A-S-H
A-S-H
Materials
Rubber-
lined
Rubber-
lined
Rubber-
lined
Rubber-
lined
No.
3
4
4
2
Capacity
366 I/sec
(5800 gpm)
353" I/sec
(5600 gpm)
32 I/sec
(500 gpm)
20 I/sec
(312 gpm)
Service
100% capacity
2 oper./l spare
60% capacity
No spare
100% capacity
1 oper./l spare
•100% capacity
1 oper./l spare
Thickener(s)/clarifier (s)
Number: One
Type: Thickener
Manufacturer:
Materials of construction:
Configuration: Circular, sloped bottom
Diameter: 19.8 m (65 ft)
Depth: 4.6 m (15 ft)
Rake speed:
12. Vacuum filter (s)
50
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Number: One
Type: Belt-type vacuum filter
Manufacturer:
Materials of construction:
Belt cloth material:
Design capacity: 0.94 kg/sec (90 ton/day)
Filter area:
13. Centrifuge(s)
Number: Not applicable
Type:
Manufacturer:
Materials of construction:
Size/dimensions:
Capacity:
14. Interim sludge pond(s) N/A (See Section M - Comments,
Item 2)
Number:
Description:
Area:
Depth:
Liner type:
Location:
Typical operating schedule:
Ground water/surface water monitors:
15. Final disposal site(s) N/A (See Section M - Comments,
Item 2)
51
-------
Number:
Description:
Area:
Depth:
Location:
Transportation mode:
Typical operating schedule:
16. Raw materials production
Type: Wet ball mills
Number: Two
Manufacturer:
Capacity: 3 kg/sec (12 ton/hr)
Product characteristics: Mill product mesh size is
95% < 325 mesh
Equipment Operation, Maintenance, and Overhaul Schedule
1. Scrubber (s)
Design life: ____^__
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
2. Absorber(s)
52
-------
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
3. Reheater(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
4. Scrubber fan(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
5. Mist eliminator(s)
Design life:
Elapsed operation time:
53
-------
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
6. Pump(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
7. Vacuum filter(s)/centrifuge(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
8. Sludge disposal pond(s)
Design life:
Elapsed operation time:
Capacity consumed:
Remaining capacity:
54
-------
Cleanout procedures:
J. Cost Data
1. Total installed capital cost: $15,538,000
2. Annualized operating cost: $3,984,778
3. Cost analysis (see breakdown: Table A2)
4. Unit costs
a. Electricity; $586,875 (1.92 mills/kWh)
b. Water:
c. Steam; $72,595 (0.24 mills/kWh)
d. Fuel (reheating/FGD process): N/A
e. Fixation cost; $546,217
f. Raw material; $62,726 (0.21 mills/kWh) limestone
g. Labor; $81,709 (0.27 mills/kWh) for operating and
technical labor; maintenance labor not included
5. Comments ; Will County FGD system is a full-scale
demonstration unit erected on an accelerated overtime
schedule in a difficult retrofit application. The
capital cost figure reflects these constraints. The
annualized operating cost figure is provided for 1975
operations.
55
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Table A2. Cost Breakdown
Cost elements
A. Capital Costs
Scrubber modules
Reagent separation
facilities
Waste treatment and
disposal pond
Byproduct handling and
storage
Site improvements
Land, roads, tracks,
substation
Engineering costs
Contractors fee
Interest on capital
during construction
B. Annualized Operating
Cost
Fixed Costs
Interest on capital
Depreciation
Insurance and taxes
Labor cost including
overhead
Variable costs
Raw material
Utilities
Maintenance
Sludqe Treatment
Included in
cost estimate
Yes
1
No
EZJ
EZ]
CZ]
CZI
Estimated amount
or % of total
capital cost
Breakdown $
Direct Indirect
2,928,000 2,
397,000
Total
928,000
397,000
642,000
In contractors fee
In contractors fee
965,000
9,010,000 9,
965,000
010,000
13,300,0001,600,000* 14,
15,
2,280,000 98,000 2,
900,000
542,000
378,000
81,709
62,726
586,875 72,595
256,656
546.217
81,709
62,726
659,470
256,656
546 .217
* 12% of direct
3,984,778
56
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K. Instrumentation
A brief description of the control mechanism or method of
measurement for each of the following process parameters:
0 Reagent addition: See remarks (below)
Liquor solids content: See remarks (below)
Liquor dissolved solids content; See remarks (below)
Liquor ion concentrations See remarks (below)
Chloride:
Calcium:
Magnesium:
Sodium:
Sulfite:
Sulfate:
Carbonate:
Other (specify):
57
-------
0 Liquor alkalinity: See remarks (below)
Liquor pH; See remarks (below)
0 Liquor flow; See remarks (below)
0 Pollutant (S00, particulate, NO ) concentration in
^ -X
flue gas: See remarks (below)
Gas flow: See remarks (below)
Waste water See remarks (below)
0 ' Waste solids: See remarks
Provide a diagram or drawing of the scrubber/absorber train
that illustrates the function and location of the components
of the scrubber/absorber control system.
Remarks: Text of report provides a diagram (Figure 4) and
description of the scrubber/absorber control system.
L. Discussion of Major Problem Areas:
1. Corrosion: See text of report (Section 4 - Problems,
Solutions, and System Modifications)
58
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2. Erosion; See text of report (Section 4 - Problems.
Solutions, and System Modifications)
3. Scaling: See text of report (Section 4 - Problems,
Solutions, and System Modifications)
4. Plugging: See text of report (Section 4 - Problems,
Solutions, and System Modifications)
5. Design problems; See text of report (Section 4 - Prob-
lems, Solutions, and System Modifications)
6. Waste water/solids disposal: See text of report (Sec-
tion 4 - Problems. Solutions, and System Modifications)
59
-------
7. Mechanical problems: See text of report (Section 4 -
Problems, Solutions, and System Modifications)
M. General comments.:
1. Initial scrubbing operations were conducted on high-sul-
fur Illinois coal. A long-term contract for low-sulfur
western coal was made in 1975. Thereafter, scrubbing opera-
tions were conducted on high-sulfur coal, low-sulfur coal
and blends of both. Operation on low-sulfur coal only began
in July 1977.
2
2. A 0.03 km (7-acre) on-site clay-lined hold basin was
used for temporary sludge disposal prior to September 1975.
The thickener underflow is treated with fly i.ash and lime
and transported directly to an off-site landfill. During
overflow or equipment emergencies, the thickener is bypassed
and wastes are disposed in the interim pond. This material
is retrieved, treated, and hauled away to the off-site land-
fill during later reduced-load periods.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-048b
2.
3. RECIPIENT'S ACCESSION NO.
I. TITLE AND
SUBTITLE Survey of Flue Gas Desulfurization
ftif »-*A r V J VA J. JLUW «M*C4AJ J-S\sO •-* ]_' UJL AdUC
Systems: Will County Station, Commonwealth
Edison Co.
5. REPORT DATE
March 1978
6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
Bernard A. Laseke, Jr.
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-01-4147, TaskS
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 PERIOI
Subtask Final; 1-6/77
D COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES jERL-RTP project officer is Norman Kaplan, Mail Drop 61, 919/
541-2556. Report EPA-650/2-75-0571 gives first survey results.
16. ABSTRACT
The report gives results of a second survey of the flue gas desulfurization
(FGD) system on Unit 1 of Commonwealth Edison Co. 's Will County Station. The
FGD system, started up in February 1972, utilizes a limestone slurry in two para-
llel scrubbing trains. Each train includes a venturi scrubber, sump, and two-stage
sieve tray absorber for the control of fly ash and SO2. The flue gas cleaning wastes
are stabilized with lime and collected fly ash and hauled away to an off-site
disposal area. The FGD system operated as an SO2-removal unit from February
1972 to July 1977, treating flue gas from the combustion of low sulfur western coal,
high sulfur Illinois coal, and blends of both. Experimental SO2-removal operations
were concluded in July 1977. The scrubbing system remains in service removing
fly ash from low sulfur western coal flue gas. Some SO2 is removed from the flue
gas during particulate-removal operations because of the alkalinity of the collected
fly ash and the limestone additive used for pH control of the scrubbing solution.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Flue Gases
Des ulfur ization
Fly Ash
Limestone
Calcium Oxides
Slurries
Scrubbers
Coal
Combustion
Cost Engineering
Sulfur Dioxide
Dust Control
Air Pollution Control
Stationary Sources
Wet Limestone
Particulate
13B
2 IB
07A,07D
07B
11G
21D
14A
3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
70
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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