U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-78-Q48
Office of Research and Development Laboratory 4r>^«
Research Triangle Park. North Carolina 27711 MaCCf! I 978
SURVEY OF FLUE GAS
DESULFURIZATION SYSTEMS:
ST. CLAIR STATION, DETROIT
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. Ehrninatiori of traditional grouping was consciously
planned to foster technology transfer and a rnaximuni 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-600/7-78-048C
March 1978
SURVEY OF FLUE GAS DESULFURIZATION
SYSTEMS: ST. CLAIR STATION,
DETROIT 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. James E. Meyers,
SO 2 Program Manager, Detroit Edison Co.; Mr. Thomas Morasky,
Senior Project Engineer, Detroit Edison Co.; and Mr. Canton A.
Johnson, Project Manager, Peabody Engineered Systems.
ii
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CONTENTS
Page
Acknowledgment ii
Figures and Tables 1V
Summary V
1. Introduction 1
.2. Facility Description 2
3. Flue Gas Desulfurization System 7
Background Information 7
Process Description 8
Design Parameters 10
Process Chemistry: Principal Reactions 14
Process Control 20
4. FGD System Performance 25
Background Information 25
Operating History and Performance 25
Operating Problems and Solutions 27
System Economics 32
Future Operations 32
Appendix
A. Plant Survey Form 35
111
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LIST OF FIGURES
No. Page
1 Operational and planned plants near Belle River,
Michigan 3
2 Simplified process flow diagram, St. Clair
FGD system 11
3 Simplified cross—sectional view of the scrubber-
absorber, St. Clair FGD system 12
4 Simplified diagram of the process network, St. Clair
FGD system 24
LIST OF TABLES
No. Page
1 Summary Data, St. Clair Unit 6 FGD System vii
2 Characteristics of Low—sulfur Western Coal Fired
at the St. Clair Facility 4
3 Design, Operation, and Emissions, St. Clair Unit 6
4 Design Coal Analysis (Weight Percentj 10
5 Design Parameters, St. Clair FGD System 13
6 Design Parameters, Peabody—Lurgi Venturi Scrubber 13
7 Design Parameters, High-velocity Spray Tower 15
8 Limestone Preparation and Storage Facilities 16
9 Design Parameters, Slurry Recirculation System 17
10 Design Features, St. Clair Sludge Disposal System 18
11 Summary of St. Clair FGD Technology Development
Program, Detroit Edison Co. 28—30
12 St. Clair Demonstration FGD System: Total Installed
Capital Costs 33
‘V
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SUMMARY
A full-scale flue gas desulfurization demonstration system
utilizing a calcium-based limestone slurry process for removal of
sulfur dioxide from boiler flue gas was backfitted onto one-half
of Unit 6 (325 MW) at the St. Clair Power Plant of the Detroit
Edison Company. The system consists of two identical parallel
scrubbing trains with a common recirculation tank, induced—draft
fan, and oil-fired, hot-air-injection reheater. Each scrubbing
train includes a Peabody—Lurgi radial-flow venturi scrubber for
particulate removal followed by a high-velocity spray tower for
sulfur dioxide removal.
The system was designed and installed by Peabody Engineered
Systems in cooperation with the Detroit Edison Company. Develop-
ment of the system resulted directly from a 1-MW pilot plant
program conducted by Detroit Edison and Peabody from 1971 to
1973. Upon successful completion of this program, installation
of the full-scale demonstration system began in February 1974.
Construction was completed by December 1974. Shakedown and
debugging operations conducted during 1975 included a cold gas
run followed by four separate hot flue gas runs. The hot flue
gas operations, which totalled more than 637 hours, revealed a
number of problems, primarily mechanical. Following the nec-
essary modifications, a 30-day system supplier qualification run
and a week—long series of final acceptance tests were success-
fully completed by May 29, 1976.
On October 14, 1976, the utility initiated an in-house
demonstration program in an effort to accumulate operating data
and experience with the flue gas desulfurization equipment. The
system operated continuously for 10 days, after which operation
was interrupted for cleaning of a scrubber booster fan.
V
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Operations were resumed on November 7 and continued without
interruption during the remainder of the month. System availa-
bility* in the period was 80 percent. Reduction of system
availability to 51 percent in December was caused by minor mech-
anical difficulties. On December 31, 1976, sulfur dioxide
removal operations were completed. The scrubber system was shut
down, and flue gas was bypassed around the system. The boiler
remained in service and was operated in compliance with emission
regulations by firing of low—sulfur (0.3 percent) western coal.
During the following months the system was modified to operate in
the particulate removal mode. Continuing to fire low—sulfur
western coal, the utility resumed operation of the scrubber on
October 13, 1977; the system removes primarily particulate matter
and also some sulfur dioxide from the flue gas.
The design particulate and sulfur dioxide removal effi-
ciencies for the scrubbing system are 99.7 and 90 percent,
respectively. These values are based upon a design coal with the
following characteristics: heat content, 26.3 MJ/kg (11,300
Btu/lb); ash content, 16 percent; sulfur and moisture contents,
4.0 and 5.9 percent, respectively.
The total direct cost of the scrubbing system, including
installation, was reported to be $8,151,000 (1975). Indirect
costs amounted to $4,937,000. Thus, the total installed capital
costs are $13,088,000. On the basis of a net generating capacity
of 163 MW, this cost is equivalent to approximately $80.5/kW.
Pertinent data on the facility and scrubbing system are
summarized in Table 1.
*Avajlability: The number of hours the system is available,
whether operated or not, divided by the number
of hours in the period, expressed as a per-
centage.
vi
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Table 1. SUMMARY DATA, ST. CLAIR UNIT 6 FGD SYSTEM
Unit rating, MW (net) 325
Fuel Pulverized coal
Average characteristics (design):
Heating value, MJ/kg (Btu/lb) 26.3 (11,300)
Ash, percent 16.0
Sulfur, percent 4.0
Moisture, percent 5.9
FGD system rating, MWa 163
FGD system supplier Peabody Engineered System
Process Limestone
Type Retrofit
Status Terminatedb
Start-up date May 1976
FGD modules Two
Removal efficiency, percent
Particulate (design) 99.7
Sulfur dioxide (design) 90.0
Makeup water, 1/mm per MW 4.05
gal/mm per MW (1.07)
System capital cost, $/kW (net) 80.5
a Unit No. 6 is powered by a two—stage superheater incorporating
two boiler furnaces. The north boiler is retrofitted with
the scrubbing system.
b removal operations were concluded on Deäember 31, 1976.
The scrubbing system resumed operation2 on October 13, 1977,
removing primarily particulate and some SO 2 from low-sulfur
western coal flue gas.
vii
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SECTION 1
INTRODUCTION
The Industrial Environmental Research Laboratory of the
U.S. Environmental Protection Agency 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 Peabody
Engineered Systems, Inc., in cooperation with the Detroit Edison
Company, and installed at the utility’s St. Clair Power Plant.
The report is based on information obtained during and after a
plant inspection conducted for PEDC0 Environmental on March 26,
1976, by Detroit Edison and Peabody personnel. The information
is current as of December 1977.
Section 2 presents information and data on facility design
and operation. Section 3 provides a detailed description of
the FGD system. Section 4 analyzes the performance of the FGD
system, the major operational problems, and the capital and
annualized operating costs. Appendix A provides additional
detailed design and operating data on the St. Clair Unit 6
facility.
1
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SECTION 2
FACILITY DESCRIPTION
The St. Clair power plant of the Detroit Edison Company is
located on the west bank of the St. Clair River in Belle River,
Michigan, approximately 72 km (45 miles) northeast of downtown
Detroit. The highly industrialized area includes another power-
generating facility, the Lambton Generating Station, owned and
operated by Ontario Hydro. A third power station now in the
planning stages, Belle River, will consist of two coal—fired 676—
MW power-generating units. The three stations will be located
within 3.2 km (2 miles) of each other. Figure 1 shows the loca-
tions of the plants and their power-generating capacities.
The St. Clair power plant includes seven fossil-fuel-fired
boilers, each coupled to its own turbine generator unit. The
total combined net generating capacity is 1798 MW. The boilers
for Units 1 through 5 were manufactured and installed by the
Babcock and Wilcox Company. The boilers for Units 6 and 7 were
manufactured and installed by Combustion Engineering, Inc.,
(C-E). Each boiler is served by a separate stack, the heights
above grade ranging from 76 m (250 ft) to 183 in (600 ft).
Coal is fired in all seven boilers. In 1975, the coal for
this facility came primarily from sources in Ohio and northern
West Virginia. The average heating value was 27.2 MJ/kg (11,700
Btu/lb); ash and sulfur contents were approximately 15 and 3,5
percent, respectively. In addition, 17 to 20 percent of the coal
supplied to the plant in 1975 came from the Decker, Montana,
area. This low—sulfur western coal is now burned in all of the
coal—fired units. Table 2 gives the average characteristics of
the Montana coal.
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OPERATIONAL FACILITY
PLANNED FACILITY
MICHIGAN
DETROIT EDISON CO.
BELLE RIVER
POWER PLANT
TOTAL PLANNED
GENERATING CAPACITY:1352 MW
(1984 CAPACITY)
DETROIT EDISON CO.
ST. CLAIR POWER PLANT
TOTAL OPERATIONAL
GENERATING CAPACITY:1798
(1977 CAPACITY)
z
ONTARIO HYDRO
LAMBTON GENERATING STATION
TOTAL OPERATIONAL
GENERATING CAPACITY:2100 MW
(1977 CAPACITY)
ONTARIO
3.2 (2)
Operational and planned plants near
Belle River, Michigan.
.
SCALE, km (MILES)
0 1.6(1)
Figure 1.
3
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Type
Heat content, MJ/kg (Btu/lb)
Volatile matter, wt. percent
Fixed carbon, wt. percent
Moisture, wt. percent
Ash, wt. percent
Sulfur, wt. percent
Grindability, Hardgrove index
Ash fusion temperature,
spherical softening, °C (°F)
Quantity, 1000 Mg (tons)/year
Coal
Decker, Montana
Dietz Mine No. 1
Subbituminous
22 (9600)
33.7
39.5
22.6
4.2
0.35
50
Table 2. CHARACTERISTICS OF LOW-SULFUR WESTERN COAL FIRED
AT THE ST. CLAIR FACILITY
Fuel
Source
1188
776
(2170)
(885)
4
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Unit 6 is a peak—load unit with a net power-generation
capacity of 325 MW. Steam is supplied to the generator from a
coal—fired, two-stage steam superheater, containing two separate
furnaces (the north and the south boilers). This unit was manu-
factured by C-E and placed in service in April 196L Particulate
controls installed on each furnace consist of mechanical col-
lectors and an electrostatic precipitator (ESP).
The north boiler has been backfitted with a wet limestone
scrubbing system for primary control of sulfur dioxide and
secondary removal of particulates. The FGD system can handle 100
percent of the flue gas from the north boiler, rated at 163 MW
(net). This capacity is equivalent to approximately 233 rn 3 /sec
(493,500 acfm) at 132°C (270°F).
Table 3 summarizes information concerning plant and FGD
system design, operation, and emissions.
The maximum allowable particulate and sulfur dioxide ernis—
sions for this unit, as covered by Michigan State Code P336.49,
are 86 ng/J (0.2 lb/million Etu heat input) for particulate
matter and 1.0 percent maximum sulfur content in fuel for sulfur
dioxide. This sulfur dioxide emission regulation value took
effect on January 1, 1978. The previous value, which covered the
1976 and 1977 operating period, was 1.5 percent maximum sulfur
content in the fuel.
5
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Table 3. DESIGN, OPERATION, AND EMISSIONS
ST. CLAIR UNIT 6
Unit No. 6
Total rated generating capacity, MW 325
Boiler manufacturer C—E
Year placed in service 1961
Unit heat rate, KJ/net kWh 9865
(Btu/net kWh) (9350)
Maximum coal consumption,
Mg/hr (Short tons/hr) 60.1 (66.3)
Maximum heat input
106 kg/hr (106 Btu/hr) 26.4 (1500)
Stack height above grade, m (ft) 130 (425)
Design maximum flue gas rate,
m 3 /sec @132°C 233
acfm @ 270°F 493,500
scfm @ 70°F 358,500
Emission controls:
Particulate Mechanical collectors,
ESP, and venturi scrubber
Sulfur dioxide Venturi scrubber and
spray tower absorber
Particulate emission rates:
Allowable, ng/J (lb/b 6 Btu) 86 (0.20)
Designa, ng/J (lb/b 6 Btu) 13 (0.03)
Sulfur dioxide emission rates:
Allowable, maximum sulfur
percent in fuel 1.0
Designa, ng/J (lb/b 6 Btu) 300 (0.7)
a Design values are based upon the outlet loadings achieved
with the emission control system in service.
6
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SECTION 3
FLUE GAS DESULFURIZATION SYSTEM
BACKGROUND INFORMATION
In 1971 the Detroit Edison Company initiated a program to
evaluate the applicability of limestone slurry scrubbing. In
cooperation with Peabody Engineered Systems, the utility de-
signed and installed a 1-Mw pilot plant at the River Rouge
Station. The pilot plant originally included a Peabody-Lurgi
venturi scrubber and a countercurrent tray tower absorber, along
with recycle tanks and four recirculation pumps. Initial
operation of the pilot unit on boiler flue gas revealed a
number of major problems, the more serious ones including forma-
tion of sulfite and sulfate scale on the tower trays and mist
eliminator; substantial increase in the slurry solids content,
causing accelerated wear and erosion of slurry-handling equipment;
and plugging of the radial-vane mist eliminator. Eventually it
became necessary to operate at 100 percent blowdown with no
water recirculation.
The severity of these problems prompted the utility and
system supplier to cease operations and reevaluate the system
design. Throughout 1972, the pilot plant was drastically
modified to prevent the scaling and plugging. The major modif i-
cations included replacement of the countercurrent tray tower
with a high-velocity countercurrent spray tower, inclusion of
larger recycle tanks and pumps, an automatic pH control system,
a slurry density control system, and a clear—water wash tray in
the absorber ahead of the mist eliminator. Following completion
of these modifications, the pilot plant was restarted in Febru-
ary 1973 and was operated continuously for about 500 hours
7
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without scaling or plugging. After additional successful test
runs, the utility authorized installation of a full-scale demon-
stration unit at the St. Clair power plant.
PROCESS DESCRIPTION
The demonstration FGD system was installed on the coal—
fired boiler of Unit 6. This boiler is a two—stage superheater
unit, consisting of two separate furnaces designated as the
north and south boilers. The demonstration FGD unit, installed
on the north boiler, was sized to handle half of the total flue
gas flow from Unit 6.
The scrubbing system consists of two identical parallel
scrubbing trains with a common recirculation tank, an induced—
draft fan, and an oil-fired, hot—air-injection reheating unit.
Each train contains a Peabody-Lurgi radial-flow venturi scrubber
followed by a high-velocity spray tower absorber. The scrubber
incorporates a variable-throat design with a plug-type throat
control regulated by a “wagon wheel” at the bottom of the scrub-
ber. Each scrubbing train includes a clear-water wash tray
located in the spray tower between the slurry spray section and
the radial—vane mist eliminator.
Before entering the scrubbing system, the flue gas passes
through mechanical collectors and an electrostatic precipitator
(Wheelabrator-Frye) for primary particulate removal. The hot
flue gas 132°C (270°F) then enters the scrubbing trains through
conical wetted—wall quench sections contained in the venturi
scrubbers. The gas is wetted with slurry from the recirculation
tank by cocurrent and crosscurrent sprays. The quenched gas and
slurry mixture then passes radially through the adjustable
throat section of the venturi scrubber which consists of two
opposing replaceable rings. The lower ring is contained in a
fixed cup and is adjusted by the wagon wheel to maintain a
designated pressure drop. Both the quench section and throat
are constructed of 3l6L stainless steel. The remainder of the
8
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scrubber is constructed of rubber-lined carbon steel. Following
passage through the throat, the gas continues through two 90-
degree turns (situated at the venturi outlet and the absorber
inlet in each scrubbing train), allowing maximum de—entrainment
of particulate and collection in the sump area of the scrubber.
The gas then passes upward through the high-velocity spray
tower, contacting the slurry countercurrently. The slurry is fed
from the recirculation tank and sprayed into the gas stream by
three pairs of spray banks. Each pair is equipped with a rubber—
lined recirculation pump and piping network. The spray units
incorporate large hollow—cone silicon carbide nozzles, which are
resistant to plugging and abrasion.
Located between the slurry spray zone and the radial—vane
mist eliminator is an impingement—type, clear—water wash tray,
which is constantly supplied with fresh makeup water. This tray
provides an interface between the slurry spray zone and the mist
eliminator, minimizing the potential for scale, corrosion, and
erosion of the mist eliminator.
The cleaned gas is fed into a duct common to both scrubber
trains and leading to a wet, induced-draft booster fan. Follow-
ing passage through the fan, the gas is reheated. The combustion
chamber of the oil—fired reheater is located outside the gas
duct. The unit burns No. 6 fuel oil to heat ambient air, which
is then injected into the gas stream through a diffuser. The
reheat system is designed to raise the temperature of the flue
gas stream from 52°C (125°F) to 135°C (275°F).
The flue gas cleaning wastes are discharged from both the
venturi scrubber and spray tower absorber into a single recycle
tank that serves both scrubbing trains. This tank, equipped with
four separate agitators, allows completion of the chemical
absorption reactions, addition of fresh alkali, discharge of
spent alkali, and recirculation of the scrubbing solution to the
scrubber and absorber towers.
The spent scrubbing slurry and collected fly ash solution
are discharged from the recycle tank through an overflow nozzle
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into a collection sump and then are pumped to a clay-lined
settling pond. The pond water is recycled for use in limestone
preparation and in maintaining the water balance in the scrubber
recirculation tank.
A simplified process flow diagram of the St. Clair FGD
system is presented in Figure 2. A cross-sectional view of the
scrubber—absorber train is provided in Figure 3.
DESIGN PARAMETERS
Fuel
The FGD system was designed to process flue gas resulting
from combustion of coal in the Unit 6 north boiler, which has a
net rating of 163 MW. Fuel characteristics of the coal on which
the design was based are given in Table 4.
Table 4. DESIGN COAL ANALYSIS
(Weight percent)
Carbon
64.10
Hydrogen
4.12
Nitrogen
1.07
Sulfur
.
4.00
Oxygen
4.00
Ash
16.00
Moisture
5.90
FGD System
Table 5 summarizes the design parameters of the St. Clair
FGD system. The values are based on the design coal charac-
teristics given in Table 3 and on upstream particulate control by
mechanical collectors and an ESP.
Particulate Removal
Primary particulate removal is in the Peabody-Lurgi radial—
f low venturi scrubbers. Design parameters are summarized in
Table 6.
Sulfur Dioxide Removal
Although the venturi scrubber removes an estimated 35 to 50
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F — — — — — — — — — — — — — — — — — — — — — — — — — — — —
MAKEUP WATER FRESH
SPRAY WATER PUMP
ABSORBER LURGI RECYCLE WASTE SLURRY
RECYCLE PUMPS pun s SUMP
Figure 2. Simplified process flow diagram, St. Clair FGD system.
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I.D. BOOSTER FAN
Figure 3.
Simplified cross-sectional view of the scrubber-
absorber, St. Clair FGD system.
WASHWATER
RECIRCULATION
TANK
12
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Table 5.
DESIGN PARAMETERS, ST. CLP .IR FGD SYSTEM
(270)
(493,500)
(18, 804)
(3.6)
(10,600)
000
48 (118)
203 (403,000)
6 (48)
0.23 (0.1)
134 ( 1,060)
300
99.7
90
Table 6. DESIGN PARAMETERS, PEABODYLURGI VENTURI SCRUBBER
Materials of construction:
Quench section
Throat
Internals
Shell
Flue gas volume, m 3 /sec (acfm)
Flue gas temperature, °C (°F)
Flue gas velocity, rn/sec (ft/see)
Pressure drop, kPa (in. H 2 0)
Liquid recirculation rate 1/sec
(gal. /min)
Maximum continuous liquid-to-gas ratio
(L/G) 1/rn 3 (gal./100 0 acf)
316L SS
316L SS
Rubber- lined carbon
steel
316L SS
116 (246,750)
132 (270)
28 (93)
3.5 (14)
279
(4420)
2.4 (20)
132
233
2274
8.2
1336
3
Flue gas inlet:
Temperature, C (°F)
Volume, m 3 /sec (acfrn)
Particulate, g/sec (lb/hr)
rng/dm 3 (gr/dscf)
Sulfur dioxide, g/sec (lb/hr)
ppm
Flue gas outlet:
Temperature, °C (°F)
Volume, m 3 /sec (acfm)
Particulate, g/sec (lb/hr)
ing/dm 3 (gr/dscf)
Sulfur dioxide, g/sec (lb/hr)
ppm
Particulate removal efficiency, percent
Sulfur dioxide removal efficiency, percent
13
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percent of the sulfur dioxide from the flue gas, primary sulfur
dioxide removal is in the spray tower. Table 7 summarizes the
design parameters of the countercurrent spray-tower absorber
unit.
Limestone Preparation and Solution Recirculation
Tables 8 and 9 summarize the design features of the lime-
stone preparation facilities and the scrubbing solution recircu-
lation system.
Sludge Disposal
The scrubbing wastes created by chemical absorption of
sulfur dioxide from the flue gas are discharged from the system
through the recirculation tank. The waste solution overflows
into a collection sump and is discharged to a clay-lined, on-site
disposal pond. Table 10 presents design features of the sludge
disposal facility.
PROCESS CHEMISTRY: PRINCIPAL REACTIONS
The chemical reactions involved in the St. Clair wet lime-
stone scrubbing process are highly complex. Although details are
beyond the scope of this discussion, the principal chemical
mechanisms are described below.
The first and most important step in the wet-phase absorp-
tion of sulfur dioxide from the flue gas stream is diffusion
from the gas to the liquid phase. Sulfur dioxide is an acidic
anhydride that reacts readily to form an acidic species in the
presence of water.
SO 2 + . SO2(aq.)
SO2(aq.) + H 2 0 H 2 S0 3
In addition, some sulfur trioxide is formed from further oxida-
tion of the sulfur dioxide in the flue gas stream.
2S0 2 + 4 - ( . 2S0 3 +
Because conditions are thermodynamically but not kinetically
favorable, only small amounts of sulfur trioxide are formed.
14
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Table 7.
DESIGN PARAMETERS, HIGH-VELOCITY SPRAY TOWER
Materials of construction:
Spray bank nozzles
Clear-water wash tray
Radial—vane mist eliminator
Absorber shell
Flue gas volume, m 3 /sec (acfm)
Flue gas temperature, °C (°F)
Flue gas velocity, rn/sec (ft/sec)
Pressure drop, kPa (in. H 2 0)
Maximum recirculation rate,
1/sec (gal./min)
Maximum L/G, 1/rn 3 (gal./l000 acf)
Silicon carbide
316L SS
316L SS
316L SS
101 (215,000)
48 (118)
2.9 (9.5)
2.5 (10)
1117
11
(17,700)
(80)
15
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Table 8. LIMESTONE PREPARATION AND STORAGE FACILITIES
Preparation equipment
Storage capacity, Mg (ton)
Limestone feed rate, Mg/hr (ton/hr)
Stoichiometric addition, percent
Limestone slurry storage, l(gal.)
Limestone slurry, percent solids
Slurry feed pumps
Flow rate/pump, 1/sec (gal./min)
Point of addition
None - the limestone
is received, pre-
pared, ground to
90% minus 200 mesh
680 (750)
10 (11)
130
567,817 (150,000)
35. 0
2
14 (215)
Recircu].ation tank
16
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‘Table 9. DESIGN PARAMETERS, SLURRY RECIRCULATION SYSTEN
Recirculation tank
Dimens ions:
Diameter, m (ft)
Height, m (ft)
Materials of coristr’uctiori:
She 11
Lining
Retention time, minutes
Recirculation pumps:
Venturi scrubber
Capacity, 1/sec (gal./min)
Service
Spray tower absorber
Capacity, 1/sec (qal./min)
1
15 (48)
12 (38)
C rhon steei
Cci icote
10
9
3
279 (4420)
2 operational/i spare
6
372 (5900)
S operational/i spare
Service
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Table 10. DESIGN FEATURES, ST. CLAIR SLUDGE
DISPOSAL SYSTEM
Disposal pond 1
Type Diked, clay-lined
Distance from FGD system, in (ft) 488 (1600)
Transportation method Pipeline
Dimensions:
Area, m 2 (acres) 43706 (10.8)
Depth, m (ft) 3 (10)
Capacity, Mg (tons) 96,606 (106,490)
Lifetime, years 1
Maximum discharge rate,
kg/sec (ton/hr) (dry) 318 (21)
Water content, percent 92
Chemical composition of sludge:
Calcium carbonate, percent 15.3
Calcium sulfite herrtihydrate,
percent 21.7
Calcium sulfate dihydrate,
percent 58.9
Fly ash 4.1
Pond water return points Limestone slurry pre-
paration, slurry recycle
tank
Pond water purge rate,
1/sec (gal./min) 11 (175)
18
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This species, like sulfur dioxide, is an acidic anhydride that
reacts readily to form an acid in the presence of water.
SO 3 4 ‘ ). SO q
SO3(aq.) + H 2 0 H 2 SO
The sulfurous and sulfuric acid compounds are polyprotic
species; the sulfurous species is weak and the sulfuric species,
strong. Their dissociation into ionic species occurs as follows:
H 2 S0 3 4 . H + HSO 3
HSO 3 + so 3
H + HSO 4
HSO 4 ‘ . H++ SO 4
Analogous to the oxidation of sulfur dioxide to form sulfur
trioxide, oxidation of sulfite ion by dissolved oxygen (DO) in
the scrubbing slurry is limited.
2S0 3 + 0 2(aq.) 2SO
This reaction occurs in the aqueous phase like the gas-phase
oxidation of sulfur dioxide; conditions are favorable thermo-
dynamically and unfavorable kinetically. Formation of sulfate is
a second—order reaction that is directly proportional to the
concentrations of DO and sulfite ion. Since the DO content of
the scrubbing solution should be relatively constant because of
the excess oxygen in the flue gas, the formation of sulfate ion
in the aqueous phase depends primarily on sulfite ion concentra-
tion. Since sulfite solubility increases as pH decreases, sul-
fate ion production occurs more readily in the acidic pH range.
The limestone absorbent, which is approximately 85 to 95
percent calcium carbonate by weight, enters the scrubbing system
as a slurry with water. It is insoluble in water, and solubility
increases only slightly as the temperature increases. When
19
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introduced into the scrubbing system, the slurry dissolves and
ionizes into an acidic aqueous medium, yielding the ionic prod-
ucts of calcium, carbonate, bicarbonate, and hydrogen.
CaCO 3 + CaCO3(aq.)
caco 3 (aq.) — Ca + CO 3
Ca + + C0 3 CaHCO 3
CaHCO 3 . Ca + HCO 3
The chemical absorption of sulfur dioxide occurs in the
venturi scrubber and spray tower and is completed in the external
recirculation tank. The reaction products precipitate as calcium
salts and the scrubbing solution is recycled. Following are the
principal reaction mechanisms for product formation and precipi-
tation.
Ca + SO 3 CaSO
CaSO 3 + l/2H 2 0 CaSO 3 •l/2H 2 0
— 4 t-’
a - - . ... a
CaSO 4 + 2H 2 0 CaSO 4 •2H 2 0
The hydrated calcium sulfite and calcium sulfate reaction prod-
ucts, along with the collected fly ash and unreacted limestone,
are transferred to the disposal pond. The supernatant is re-
cycled to the system.
PROCESS CONTROL
The process control system for the St. Clair FGD facility
was designed by Peabody and Detroit Edison to maintain optimum
scrubber operations with 0.5 man. Following are the principal
design features.
All key process variables are monitored and controlled
automatically.
20
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The absence of check valves in the primary recircula-
tion lines eliminates the possibility of their erosion
and failure because of abrasive slurry service. System
modulation is achieved by stepwise operation of recir-
culation pumps.
o The inlet scrubber ductwork contains no gas flow
dampers. The design of the ductwork permits proper gas
flow distribution at 0, 40, and 100 percent boiler
loads.
O The flow of flue gas to the scrubbing trains is main-
tained externally by regulation of the boiler draft and
combustion control system.
o Continuous flow loops are tapped, when needed, to
control key process variables.
o The variables that are amenable to monitoring and
control are pH and solids content of the scrubbing
solution.
Following is detailed information concerning the regulation
of pH and solids content.
pH Control
The addition of fresh limestone slurry to the system is
regulated by monitoring the pH of the scrubbing solution in the
common recirculation tank. The control for pH regulation is
maintained in the slightly acidic range, 5.8 to 6.0. This range
optimizes system performance as a function of sulfur dioxide
removal, limestone utilization, and mechanical reliability.
Fresh makeup limestone slurry is pumped continuously through
a piping loop connected to the slurry preparation tank. This
loop is tapped by a flow control valve (gate valve), which is
connected to a p1-i sensor, a Cambridge-supplied dip-type unit
located in the common recirculation tank. When an excursion of
the pH control range occurs, the sensor signals the flow control
valve, which regulates the flow of slurry into the tank to com-
pensate for the direction of the excursion (i.e., when pH drops
below 5.8, flow of slurry is increased; when pH exceeds 6.0, flow
is decreased). The effects of extended pH excursions on system
operations are summarized as follows;
21
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1. Low pH causes rapid formation of hard gypsum scale on
the scrubber internals. This results from the cumula-
tive effect of increasing calcium sulfite solubility
and decreasing calcium sulfate solubility as the pH
level decreases. Even when pH control is reestab—
lished, the hard gypsum scale remains, requiring shut-
down and cleanout before optimum operation can be
resumed.
2. High pH causes poor limestone utilization and rapid
plugging and fouling of the scrubber internals.
Plugging, also called soft scale, is defined as the
deposition of soft solids. As with hard scale, soft
scale forms rapidly during the pH excursion. The
chemical basis of soft scale formation is calcium
sulfite solubility, which decreases rapidly as the pH
increases and enters the alkaline range. The sulfite
formations deposited on the scrubber internals are
large, leaf—like masses, which are very soft. At high
pH conditions, these soft solids provide deposition
sites for excess calcium carbonate and fly ash in the
scrubbing solution. Accumulations of calcium sulfite,
calcium carbonate, inert silicon, and fly ash cause
fouling of various scrubber internals. Unlike hard
scale, soft scale is easily altered mechanically and
thus maintenance of equipment requires less effort
during shutdowns for cleanout. Also, when the pH of
the solution is restored to the slightly acidic level,
the soft scale film disappears because of the high
solubility of calcium sulfite and calcium carbonate in
lower pH environments.
Solids Content Control
The addition of supernatant to the system is regulated by
monitoring the solids content of the scrubbing solution in the
recirculation tank. The control level for the suspended solids
concentration is maintained at a maximum of 15 percent by weight.
When this level is exceeded, the system automatically compensates
by discharging the spent slurry and bringing in pond supernatant.
The disposal pond supernatant is pumped continuously through
a piping loop. This loop is tapped by a flow control valve (gate
valve), which is connected to an Ohmart nuclear density meter in
the common recirculation tank. When the sensor indicates that
the control level has been exceeded, the meter signals the flow
control valve and supernant is supplied directly to the recircu-
22
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lation tank. The quantity of supernatant added to the system
is the amount needed to bring the suspended solids content below
15 percent. This results in a temporary water imbalance, which
is automatically compensated for by gravity overflow into the
waste slurry surnp and pumping to the disposal pond. The con-
tinuous liquid flow between the sump and the disposal pond en-
sures a constant velocity of flow through the pipe under all load
Conditions. This minimizes the possibility that solids will
settle out in the pipe, causing flow restrictions that could
necessitate shutdown for cleanout.
Prolonged high solids content in the scrubbing solution
leads to excessive wear and premature failure of slurry handling
equipment, problems with system chemistry, and reduction of
sulfur dioxide removal efficiency. Figure 4 presents a sim-
plified diagram of the St. Clair process control network.
23
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WATER
VENTURI SCRUBBER
AND SPRAY TOWER
SPENT SCRUBBING
SOLUTI ON
COMMON RECIRCULATION TANK
L j
I
Figure 4.
Simplified diagram of the process control network, St. Clair FGD system.
-------
SECTION 4
FGD SYSTEM PERFORMANCE
BACKGROUND INFORMATION
The St. Clair FGD system is an experimental unit designed
to provide engineering and operating data for future full—scale
installations. Currently, however, the utility does not need
full—scale FGD systems for the St. Clair coal—fired units, nor is
such a need imminent. The utility has a long-term agreement with
the Decker Coal Company for the supply of low-sulfur ubbit-
uminous coal from the Dietz mine in southern Montana. They are
now burning this low-sulfur coal (0.3 to 0.4 percent sulfur) in
all of the St. Clair coal-fired units and can comply with
emission regulations without sulfur dioxide removal equipment.
The St. Clair experimental sulfur dioxide scrubbing program
can be surrunarized as follows:
0 Completion of all equipment installation, mechanical
debugging, and prestart-up testing.
o Completion of system supplier qualification and accep-
tance tests.
o Completion of a demonstration program conducted by the
St. Clair plant personnel.
o Termination of the sulfur dioxide removal operations.
Continuation of operation in the particulate removal
mode.
OPERATING HISTORY AND PERFORMANCE
Peabody Engineering and Detroit Edison undertook the devel-
oprnent of limestone scrubbing technology with a 1-MW pilot plant
at the River Rouge Station in Detroit, Michigan. Intermittent
25
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operation from 1971 to 1973 led to a large—scale system inodifi-
cation program, which included abandoning the tray—tower system
design. Modified pilot plant operations began in February 1973
and continued through the year. Successful periods of continuous
operation, lasting up to 21 days, ultimately resulted in author-
ization in February 1974 of a full—scale installation at the St.
Clair plant.
Construction was virtually complete by December 1974.
Mechanical checkout of auxiliary equipment, including pumps and
the induced-draft fan, was complete by early 1975. A cold run
with gas and water was successfully conducted on March 22 and 23,
1975. During this run, several minor system modifications were
completed and preparations were made for test runs with hot flue
gas. Four runs with hot flue gas and limestone slurry were
conducted in June, August, October, and December 1975; these
operations lasted 22 hours, 27 hours, 41 hours, and 547 hours,
respectively. As the duration of successful operations increased
with each run, the utility initiated and completed a 30-day
qualification run and a week-long series of final acceptance
tests by May 29, 1976. System operations in the qualification
run were conducted exclusively by plant personnel. The system
operability index* for the qualification run was 100 percent.
Results of the 6—day final acceptance run indicated that sulfur
dioxide removal efficiency was 90.9 percent with low-sulfur coal,
exceeding the design guarantee for use with high-sulfur coal.
The in—house scrubber demonstration program was initiated on
October 14, 1976. The system remained in continuous service for
10 days before operation was interrupted by fan balancing pro-
blems caused by excessive solids carry—over from the mist
eliminator and wash water tray. Sulfur dioxide scrubbing reswned
on November 7 and continued into December. Outages during
* Operability index: The number of hours the scrubbing system
operated divided by the number of hours
the boiler operated, expressed as a
percentage.
26
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the operating period are attributed primarily to mechanical
problems. System availability values for November and December
1976 were 80 and 51 percent, respectively. The sulfur dioxide
scrubbing program was completed on December 31, 1976.
Upon completion of the sulfur dioxide removal program, the
scrubber system was removed from the flue gas path and Unit 6
remained in service firing low-sulfur western coal. The scrubber
plant was shut down from January 1, 1977, through October 12,
1977. During this period the system was inspected and a number
of design modifications were made. Scrubbing operations resumed
on October 13, 1977, for removal of particulate only. In this
mode of operation, the venturi scrubbers and spray tower absorb-
ers remain in the flue gas stream. Scrubbing solution is circulated
through the venturi scrubber and clear water is circulated
through the wash water tray. No solution is circulated through
the spray zone of the absorber towers. The scrubbers remove the
fly ash not collected by the upstream mechanical collectors and
electrostatic precipitator. They also remove some sulfur dioxide
(approximately 35 to 50 percent) because of the alkalinity of the
fly ash and the use of limestone in the scrubbing solution to.
prevent low p 1 -I swings and subsequent actd corrosion of the scrub-
ber internals.
Table 11 summarizes Detroit Edison’s development of scrub-
bing technology from initial operation of the River Rouge pilot
plant to the present.
OPERATING PROBLEMS AND SOLUTIONS
The problems with scrubber operations to date are summarized
in the comments section of Table 11. Most of the problems en-
countered during the system’s relatively short operation have
been mechanical and design-related. Although some problems
relate to system chemistry, these are attributed to mechanical
and design inadequacies. For example, development of scale in
the induced—draft booster fan assembly resulted from carry-over
27
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Table 11. SUMNARY OF ST. CLAIR FGD TECHNOLOGY DEVELOPMENT PROGR N,
DETROIT EDISON CO.
1—MW pilot plant development program was initiated by Detroit Edison and
Peabody. Widespread scaling and plugging problems resulted in intermittent
operations and ultimately led to shutdown for major modifications.
Contract awarded to Peabody for the development of a full—scale demonstration
system.
The tray—type absorber was replaced by a countercurrent high-velocity spray
tower. Restart occui ed in February 1973, and continued on a controlled
intermittent basis throughout the year. Maximum continuous operation period
of 21 days was logged.
The utility authorized scale-up of the pilot unit for installation at the
St. Clair Power Plant, Unit 6, one—half of the total flue gas capacity.
Installation of the St. Clair Unit was virtually completed. A faulty
instrument panel was returned to the manufacturer. Water and air testing of
all auxiliary equipment (pumps, fan) was completed.
An air/water run was successfully conducted on March 22 and March 23. During
this period all rubber-lined recycle pumps were repaired, and the limestone
preparation and feed system were calibrated.
The first hot flue gas run was conducted on June 22 for 22 hours. During this
run the scrubber was purposely tripped off at loads of 40 to 80 percent
to observe any possible detrimental effects on steam generation operations.
None were detected. Following this run the following components were re-
paired: Lurgi throat, ph control system, target flow meters, and pump seal
water flow indicators.
A second hot flue gas run begun on August 6 lasted 27 hours. Termination of
system operations resulted from a reheater thermocouple failure. Inspection
of the unit internally and analysis of operating data revealed no drastic
abnormalities or malfunctions. Operating problems included: high solids
content in the wash tray recycle tank, indicating excessive solids carry-
over through the mist eliminator and wash tray; plugging of the fresh water
inlet boxes to the wash trays with solids; scale and slurry solids on
deniisters and wash trays; plugging of the wash tray underspray nozzles with
sludge and slurry; failure of the pH controller; unequal distribution of
gas flow between the two trains; duct vibrations; and SO 2 analyzer failures.
Period
Operations
Comments
1971
1972
Aug. 72
Feb. 73
Feb. 74
Dec. 74
Jan. 75
Feb. 75
Mar. 75
Apr. 75
May 75
June 75
Aug. 75
River Rouge Pilot Plant
Modified River Rouge Pilot
Plant
St. Clair Demonstration Unit
St. Clair air/water run
St. Clair hot flue gas run
St. Clair hot flue gas run
On t j flu ed)
-------
Table 11 (continued).
Period
Operations
Comments
Sept. 75 St. Clair hot flue gas run A third hot flue gas run of 41 hours was completed on October 9.
Oct. 75 The primary objective was to evaluate the effects on solids carry-over of
increased fresh water wash and increased underspray to the wash system.
The test run was terminated prematurely because loss of a boiler feed pump
resulted in a reduced boiler load, causing subsequent weeping of the wash
trey because of reduced flue gas velocity. Solids carry-over was significantly
reduced. Process changes were implemented to provide sufficient wash
Nov. 75 water and tray undersprsy while preventing carry-over in a closed-water-loop
mode.
Dec. 75 St. Clair hot flue gas run Detroit Edison completed a fourth hot flue gas run from December 5 to
December 29. Two interruptions occurred because of boiler shutdown for
maintenanca and interruption of the fuel oil supply to the rehester. A total
of 547 hours of oparstion was logged during this period. The test run was
terminated prematurely because of excessive vibration of the I.D. booster
fan. During the test run the unit operated at approximately 89% of design
capacity (design capacity is 163 MW . Inlet 502 concentrations ranged from
1000 ppm to 2500 ppm. 502 removal efficiencies were approximately 90 to 93%.
Particulate loading at the scrubber outlet was 1 g/lOO kg (0.01 lb/lOGO lb)
of flue gas (below the current standards of 15 g/l00 kg (0.15 lb/bOO lb) of
flue gas]. Sulfur content of the coal ranged from 1.0 to 3.5%. calculated
average stoichiometry for the test run based on 502 removed was 1.2.
Inspection after shutdown revesled no significant buildup of scale or sludge
in the Lurgi venturi scrubbers or the spray tower absorbers. Very slight
deposits on the periphery of the interface trays and demisters did not affect
system operation. Vibration of the 1.0. booster fan was apparently caused
by damage to the fan blades by loose fan spray nozzles.
Jan. 76 St. Clair qualification run The 30—day aystem supplier qualification run and figal acceptance test pro-
Feb. 76 and final acceptance tests grams were completed by May 29. The system supplier qualification run was
Mar. 76 conducted using plant personnel exclusively. The final acceptance test pro-
Apr. 76 gram lasted one week, consisting of 502 and particulate removal at various
May 76 boiler loads. All design guarantees were exceeded on high-aulfur coal
application (SD 2 removal efficiency was 90.9% and outlet particulate emis-
sions were measured at 2 g/lOO kg (0.02 lb/l000 lb) of flue gas).
(continued)
-------
The in—house scrubber demonstration program began on October 14 end continued
for 10 days until excessive vibration and imbalance in the I.D. booster fan
assembly forced a scrubber outage. This was caused by sludge and scale carry-
over from the wash tray and mist eliminator. The I.D. fan was cleaned out,
rebalaflCed, and its spray system modified for greater capacities.
System availability index for November was 80%. Outage time was primarily
attributed to procuring sand blasting services for removal of the particulate
buildup on the I.D. booster fan blades. The sand blasting Operation required
only 8 hours.
The availability index for December was 51%. Four forced scrubber outages
were caused by malfunction of the dense slurry traverse pump, plugging of the
pH sample line, and malfunction of the dense slurry storage tank agitators.
so 2 removal operations are being conducted on flue gases resulting from the
burning of low—sulfur western coal.
The 502 removal program was concluded on December 31, 1976. The system was
removed from the flue gas path for modifications prior to restart in the fall.
Modifications will allow operation to remove particulate matter only. Com-
pliance with S02 regulations will be achieved by burning low—sulfur western
coal. For particulate removal, the trains will remain intact and no solution
will be circulated through the spray Zone of spray towers. Limestone require-
ments will be reduced to levels required for pH control only. Some SO 2
removal (30—50%) will occur because of the fly ash alkalinity and that im-
parted to the scrubbing solution by the limestone.
Scrubbing operations were resumed on October 13, 1977.
Table 11
(continued).
Period
Operations
Cousnents
June 76
July 76
Aug. 76
Sept. 76
Oct. 76
NOv. 76
Dec. 76
Jan. 77
Feb. 77
Mar. 77
May 77
June 77
July 77
Aug. 77
Sept. 77
Oct. 77
St. Clair SO 2 demonstration
program
Shutdown for modifications
St. Clair particulate
scrubbing
-------
of solids from the wash tray because of inefficient operation of
the mist eliminator.
The major problems with the St. Clair scrubbing system are
highlighted below.
Process Control Network
The pH probes originally specified for service were an in-
line type supplied by Foxboro. The failure rate was high because
of plugging and blowouts. Conversion to a dip—type probe manu-
factured by Cambridge has considerably reduced pH monitor prob-
lems and maintenance requirements.
The design premise of the system’s control network appears
faulty. When pH of the solution in the recirculation tank drops
below the control range (5.8 to 6.0), the sensor signals the
control valve for addition of fresh alkali slurry (limestone, 35
percent solids) to the tank. When the solids content of the
solution apparently exceeds 15 percent, however, the sensor
signals the control valve for addition of fresh water to the
tank. The result is a temporary water imbalance, corrected by
overflow into the slurry sump. Because this overflow contains
large amounts of unused calcium carbonate, the operation becomes
uneconomical and inefficient.
Gas Flow Balance
Balancing the flow of flue gas to the two scrubbing trains
has presented problems. No gas flow meters were included in the
flue gas ducts to determine the actual gas flow. In operation
the design values of gas flow and pressure drop were maintained
in one scrubber train, and the remaining gas flowed through the
second scrubber train. The resulting imbalance caused a drastic
decline in system performance. The utility rectified the problem
by installing a flow-balancing “black box” device of their own
design.
Fan Vibration
Excessive fan vibration and resulting problems with fan
31
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balance have occurred often, usually followed by cleanout and
rebalancing. The utility plans to modify the fan’s wash system
to provide greater water flow and thus increase efficiency of
the wash system.
Scale Formation and Plugging
As mentioned earlier, scale formation and plugging have
occurred because of control system inadequacies and the ineffi-
ciency of various internal components. The most susceptible
components have been the booster fan assembly, mist eliminator,
and wash water tray.
SYSTEM ECONOMICS
Table 12 summarizes the total installed capital costs of
the St. Clair Unit 6 FGD system. The total cost, $13,088,000
(in 1975 dollars), includes $8,151,000 for direct costs and
$4,927,000 for indirect costs. Based on the net generating
capacity (163 Mw) of the boiler equipped with the scrubbing
system, this cost equals approximately $80.5/kw. The total
includes the particulate removal equipment and sludge disposal
capacity for 1 year of operation. Although the utility has
provided operating cost estimates, these figures are not included
because they do not accurately reflect the demonstration basis
upon which this system was operated.
FUTURE OPERATIONS
Sulfur dioxide removal was terminated following completion
of the internal demonstration program. The utility is continuing
to operate the scrubbing system in the particulate removal mode.
Some limestone must be added to the scrubbing solution to pre-
vent low pH swings and subsequent corrosion of internal compo-
nents. The limestone addition, coupled with the alkalinity of
the collected fly ash, should result in some sulfur dioxide
removal, in the range of 35 to 50 percent. No tests have been
conducted to determine the actual removal efficiency.
32
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Raw material handling
, reheater
Solids disposaiC
Solids disposal trans-
port system
Utilities and services
Structures, yard facili-
ties, electrical ducts
insulation, start-up
Direct cost — subtotal
Indirect cost
Interest (8.4%) and
property tax
Allowance for start-up
Contingency
Indirect cost - subtotal
Total capital cost
Table 12. ST. CLAIR DEMONSTRATION FGD SYSTEM:
TOTAL INSTALLED CAPITAL COSTSa
Items
Direct cost
Costs $ (1975)
Equipment
213,000
3,188,000
162,800
212,520
56,000
867,000
4, 699 , 320
Installation
271,000
1,528,000
207,200
270,480
72,000
1,103,000
3,451,680
Engineering
Construction field
expense
Total
484,000
4,716,000
370 ,000
483,000
127,000
1,970,000
8,151,000
2,822,000
435,000
1 , 100 , 000
500,000
80,000
4,927,000
13,088,000
$ / kwb
50. 2
30.3
80 . 5 d
a All figures are 1975 dollars.
b Based upon the net generating capacity of one-half of the No. 6
unit, 162.5 MW.
One year capacity.
d Particulate removal equipment included.
33
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Currently, the utility plans to operate the scrubbing
system for 3 to 4 years in the particulate removal mode. The
scrubbers will then be shut down and dismantled and eventually
replaced with a full-load high-efficiency electrostatic pre-
cipitator.
34
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APPENDIX A
PLANT SURVEY FORM
A. Company and Plant Information
1. Company name: Detroit Edison Company
2. Main office: 2000 Second Ave., Detroit, Michigan
3. Plant name: St. Clair Power Plant
4. Plant location: Belle River, Michigan
5. Responsible officer: B.H. Schneider
6. Plant manager: R.W. Berta
7. Plant contact: James E. Meyers
B. Position: Program Director. St. Clair FGD Demonstration
Program
9. Telephone number: ( 313)/237—9284
10. Date information gathered: 3/26/76
Participants in meeting Affiliation
James E. Meyers Detroit Edison
Thomas Morasky Detroit Edison
Charles Dene Detroit Edison
Gregory Truchan Detroit Edison
George Gordon Peabody Engineered Systems , Inc.
Canton Johnson Peabody Engineered Systems , Inc.
H.A. Ohigren PEDC0
G.A. Isaacs PEDC0
B.A. Laseke PEDC0
R.I. Smolin PEDC0
35
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B. Plant and Site Data
1. UTM coordinates: _______________________________________
2. Sea level elevation: Sea level (pla:t i iocated
beside the St. CiLair River)
3. Plant site plot plant (Yes, No): No
(include drawing or aerial overviews)
4. FGD system plan (yes, No): No
5. General description of plant environs: Highly
industrialized. ___________________________ ____
6. Coal shipment mode: Decker ccal leaves tiicjn ne i .
Burlington—Northern trains and arrives at the Suporior
Wisconsin, coal storage terminal, where it is transferred
o two 39,463—Mg (43,500—ton) coal barges and transported
through Lakes Superior and Huron to St. Clair, Michigan.
The water is navigable only B or 9 months of the year .
C. FGD Vendor/Designer Background
1. Process name: fi1L eStCnC scrubbing
2. Developer/licensor name: Peabody Engineered Systems
3. Address: 39 Maple Tree Avenue
Stamford, Connecticut
4. Company offering process:
Company name: Peabody Engineered Systems
Address: 39 Maple Tree Avenue
36
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Location: Stamford, Connecticut
Company contact: Canton A. Johnson
Position: Manager of Process Engineering
Telephone number: ( 203)/327-700
5. Architectural/engineers name: Bechtel
Address: _______________________________________________
Location: Ann Arbor, Michigan
Company contact: _______________________________________
Position: _______________________________________________
Telephone number: ______________________________________
D. Boiler Data
1. Boiler: Unit No. 6
2. Boiler manufacturer: Combustion Engineering
3. Boiler service (base, standby, floating, peak):
Peak load service
4. Year boiler placed in service: 1961
5. Total hours operation: Approximately 85,000
6. Remaining life of unit: Approximately 15 years
7. Boiler type: Two-stage superheater unit containing two
boiler boxes
8. Served by stack no.: 6
9. Stack height: 130 m (425 ft )
10. Stack top inner diameter: _____________________________
11. Unit ratings (MW):
Gross unit rating: 325 MW total; 50% to scrubber
Net unit rating without FGD: 163 MW
37
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Net unit rating with FGD: 6.6 MW lost on No. 6
Name plate rating: 350 MW
12. Unit heat rate: 9918 kJ/net kWh (9400 Btu/net kWh )
Heat rate without FGD: _________________________________
Heat rate with FGD: 9400 (net )
13. Boiler capacity factor, (1974): 73.5%
14. Fuel type (coal or oil): Coal
15. Flue gas flow: 466 m 3 /sec (987,000 acfm )
Maximum: 466 m 3 /sec (987,000 acfm )
Temperature: 132°C (270°F )
16. Total excess air: 15-20
17. Boiler efficiency: _____________________________________
6. Coal Data
1. Coal supplier:
Name: Decker Coal Company
Location: Montana
Mine location: Dietz Mine
County, State: Southern portion of Montana
Seam: No. 1
2. Gross heating value: 15,513 Mg/wk (17,100 ton/wk )
(1974 consumption)
3. Ash (dry basis): 3.0 to 4.0
4. Sulfur (dry basis): 0.3 to 0.4
5. Total moisture: 22.0 to 24.0
6. Chloride: N/A ___________________________________
7. Ash composition (See Table Al) N/A
Not Available
38
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Table Al
F.
*
Constituent
Silica, Si0 2
Alumina, A1 2 0 3
Titania, Ti0 2
Ferric oxide, Fe 2 0 3
Calcium oxide, CaO
Magnesium oxide, MgO
Sodium oxide, Na 2 0
Potassium oxide, K 2 0
Phosphorous pentoxide, P 2 0 5
Sulfur trioxide, SO 3
Other
Undetermined
Percent weight
N/A
Atmospheric Emission Regulations
Applicable particulate emission regulation
1.
2.
1978
a) Current requirement: 86 mg/J (0.20 lb/b 6 Btu)
AQCR priority classification:
Regulation and section No.: MI/R 336.49
b) Future requirement (Date: ):
Regulation and section No.:
Applicable SO 2 emission regulation
*a) Current requirement: 1.0% sulfur fuel content
AQCR Priority Classification:
Regulation and section No.:
b) Future requirement (Date:
State emission limitation.
39
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Regulation and section No.: MI/R 336.49
C. Chemical Additives : (Includes all reagent additives -
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)
1. Trade name: Limestone
Principal ingredient: CaCO 3 ; 1% MgO
Function: SO? Absorbent
Source/manufacturer: Levy Co., Jefferson—Marine Terminal ,
Rogers City, Michigan
Quantity employed: 26,308 Mg (29,000 ton)/year based on
1.6% sulfur coal
Point of addition: Recirculatjon tank
2. Trade name: Not applicable
Principal ingredient: ___________________________________
Function:
Source/manufacturer:
Quantity employed: _____________________________________
Point of addition:
3. Trade name: Not applicable
Principal ingredient: ___________________________________
Function:
Source/manufacturer:
Quantity employed: ____________________________________
Point of addition:_____________________________________
4. Trade name: Not applicable
Principal ingredient: ___________________________________
Function: ________________________________________________
Source/manufacturer: _______________________________________
Quantity employed: ____________________________________
40
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-
Point of addition: ___________
5. Trade name: Not applicable
Principal ingredient: ________
Function: _____________________
Source/manufacturer: __________
Quantity employed: ___________
Point of addition:__________
H. Equipment Specifications
1. Electrostatic precipitator(s)
Nu mber: Two
Manufacturer:• Whee1ebrator-Frv .
Particulate removal efficiency: 90
Outlet temperature: 132°C (270°F
Pressure drop:
2. Mechanical collector(s)
Number
Type:
Size:
Manufacturer:
Particulate removal efficiency:
Pressure drop:
3. Particulate scrubber(s
Number: Two , one per scrubbinq train
Type: Radian Flow Venturi
Manufacturer: Peabody-Lurgi
Dimensions: ______________
(yes)
)
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Material, shell: 316L SS
Material, shell lining: Rubber
Material, internals: 316L SS (quench and orifice sections )
No. of modules: One
No. of stages: One
Nozzle type: Bull nozzle
Nozzle size: ____________________________________________
No. of nozzles: ________________________________________
Boiler load: 50% (total boiler gas flow )
Scrubber gas flow: 117 m 3 /secl32°C (247,000 acfm, 230°F )
Liquid recirculation rate: 279 1/sec (4420 gal./min )
Modulation: Stepwise shutdown of recirculation pumps
L/G ratio: 2.4 1/rn 3 (20 gal./1000 acf )
Scrubber pressure drop: 3.5 kPa (14 in. H 2 0 )
Modulation: None
Superficial gas velocity: 28 rn/sec (93 ft/sec )
Particulate removal efficiency: 99.7% overall
Inlet loading: 8.2 Q/m 3 (3.6 qr/scf )
Outlet loading: ______________________________________
removal efficiency: 35—50%
Inlet concentration: 3000 ppm (maximum )
Outlet concentration: 1500-2000 ppm
4. SO 2 absorber(s)
Number: Two, one per scrubbing train
Type: High-velocity countercurrent spray tower
Manufacturer: Peabody Engineered Systems
42
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Dimensions:
Material, shell: 316L SS
Material, shell lining: None
Material, internals: None
No. of modules: One
No. of stages: One
Packing type: None
Packing thickness/stage: None
Nozzle type: Silicon carbide hollow cone
Nozzle size:
No. of nozzles: 6 banks of nozzles/tower
Boiler load: 50% (total boiler gas flow )
Absorber gas flow: 101 m 3 /sec, 48°C (215,000 acfrn, 118°F )
Liquid recirculation rate: 372 1/sec (5900 gal/mm )
Modulation: Stepwise shutdown of recirculation pumps
L/G ratio: 11 1/rn 3 (80 gal/1000 acf )
Absorber pressure drop: 2.5 kPa (10 in. H 2 0 )
Modulation: None
Superficial gas velocity: 2.9 rn/sec (9.5 ft/sec )
Particulate removal efficiency: 99.7% overall
Inlet loading: _____________________________________
• Outlet loading: 0.02 g/m 3 (0.01 gr/scf )
SO 2 removal efficiency: 90%
Inlet concentration: 1500-2000 ppm
Outlet concentration: 300 (max.) ppm
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5. Clear water tray(s)
Number: Two, one per absorber
Type: Impingement wash tray
Materials of construction: 316L ss
L/G ratio:
Source of water: Wash water recycle tank
6. Mist eliminator(s)
Number: Two, one per absorber
Type: Radial baffle - curved vane
Materials of construction: 316L ss
Manufacturer: Peabody
Configuration (horizontal/vertical): Horizontal
Distance between scrubber bed and mist eliminator: _____
1.4 m (4.5 ft)
Mist eliminator depth: __________________________________
Vane spacing: 20 cm (8 in) at top center; 30 cm (12 in. )
at bottom rim.
Vane angles: 30 to 450
Type and location of wash system: None, mist eliminators
preceded by fresh water wash trays
Superficial gas velocity: 5 rn/sec (10 ft/sec )
Pressure drop: 0.05 kPa (0.2 in. H O) 46.5 kPa (3.0 in . H 2 0)
for wash tray
Comments:
7. Reheater(s): One
Type (check appropriate category): _____________________
44
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O in-line
0 indirect hot air
direct combustion
bypass
0 exit gas recirculation
fl waste heat recovery
EJ other
Gas conditions for reheat:
Flow rate: 186 m 3 /sec (396,700 acfm )
Temperature: 50°C (122°F )
so 2 concentration: 200 ppm
Heating medium: Combustion gases
Combustion fuel: No 6 fuel oil
Percent of gas bypassed for reheat: None
Temperature boost (piT): 121-149°C (250—300°F )
Energy required: 4.4%
Comments: The reheater combustion chamber is located
outside the main duct. The combustion products are in-
lected into the main gas stream through a diffuser .
8. Fan(s)
Type: Wet
Materials of construction: 316L SS
Manufacturer: Peabody
Location: Between mist eliminator and reheater unit
Fan/motor speed: N/A
Motor/brake power: N/A
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Variable speed drive: N/A
9. Tank(s) One recirculatjon
Materials of construction: Carbon steel/ceilcote lining
Function: Liquid recirculation/alkali addition/waste disposal
Configuration/dimensions: Cylindrical 14.6 m x 11.6 m
(48 ft) x (38 ft)
Capacity: 1,949,487 1 (515,000 gal )
Retention times: 10 minutes
Covered (yes/no): No
Agitator description: 4 agitators
11. Thickener(s)/clarifier (s)
Number: Not applicable
Type
Manufacturer:
Materials of construction:
Configuration
Diameter
Depth
Rake speed: _____
12. Vacuum filter(s)
10. Recirculation/slurry pump: service description
No.
Manufacturer
Capacity
1/sec (gal/mm)
Operation
2
3
6
Slurry feed
Venturi
recycle
Absorber
recycle
Denver
Denver
Denver
14 (215)
279 (4,420)
372 (5,900)
Full time
One spare
One spare
46
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Number: Not applicable
Type:
Manufacturer: ___________________________________________
Materials of construction: ______________________________
Belt cloth material: __________________________________
Design capacity: _______________________________________
Filter area: ____________________________________________
13. centrifuge(s)
Number: Nr I- pp1i-ah1
Type:
• Manufacturer: ___________________________________________
Materials of construction: _____________________________
Size/dimensions:
Capacity:
14. Interim sludge pond(s)
Number: One
Description: Sludge disposal pond
Area: 43,706 m 2 (10.8 acres)
Depth: 3 in (10 feet)
Liner type: Diked settling pond, clay lined .
Location: 488 m (1600 ft) from plant
Typical operating schedule: 19 Mg/hr (21 tpns/hr) (dryL
142 Mg (156 tons) produced per ton of coal consumed (dry) .
Ground water/surface water monitors: None
15. Final disposal site(s)
47
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Number: See interim sludge ponds
Description: _______________________
Area: _______________________________
Depth: __________________________
Location: ______________________________
Transportation mode: ______________
Typical operating schedule: ______
16. Raw materials production
Type: Reagent received prepared
Number: 1 storage silo
Manufacturer: ________________________________________________
Capacity: 680 Mg (750 tons )
Product characteristics: Limestone slurry storage
capacity is 568,000 1 (150,000 gal.);
I. 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)
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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:____
49
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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: _______
50
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Cleanout procedures:
J. Cost Data
1. Total installed capital cost: $8,151,000
2. Annualized operating cost: Not available
3. Cost analysis (see breakdown: Table A2)
4. Unit costs
a. Electricity: _______________________________________
b. Water: _____________________________________________
C. Steam:__________________________________________
d. Fuel (reheating/FGb process): __________________
e. Fixation cost:___________________________________
f. Raw material: _____________________________________
g. Labor: ________________________________________
5. Comments A detailed capital cost analysis is provided
in the text of the report, Section 4 and Table A2
Annualized operating costs are not provided because of
their meaningless nature (i.e. the system was in ser-
vice only for a 2.5 month demonstration program) .
51
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Table A2. COST BREAKDOWN
Estimated amount
Included in
or % of
total
Cost elements
.
cost estimate
capital
cost
Yes
No
A. Capital Costs
Scrubber modules L_J
Reagent separation
facilities
Waste treatment and P J [ i
disposal pond
Byproduct handling and I I
storage
Site improvements I I _____
Land, roads, tracks, I I _____I
substation
Engineering costs
Contractors fee
Interest on capital
during construction
B. Annualized Operating
Cost
Fixed Costs
Interest on capital I I
Depreciation I _____
Insurance and taxes L I
Labor cost including I I 1
overhead
Variable costs
Raw material I I I
Utilities I I I I
Maintenance I I I I
52
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K. Instrumentation
A brief description of the control mechanism or method of
measurement for each of the following process parameters:
o Reagent addition: ___________________________________
0
0
0
Liquor solids content:_________________________________
Liquor dissolved solids content:______________________
Liquor ion concentrations
Chloride:
Calcium:
Magnesium:
Sodium:
Sulfite:
Sulfate:
Carbonate:
Other (specify):____________________________________
53
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Liquor alkalinity:
Liquor pH:
Liquor flow:
Pollutant (SO 2 ,
particulate,
NOR)
concentration
in
flue gas:
Gas flow:
Waste water
.
Waste solids:
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: Detailed information on the control system is
given in the report, Section 3, and Figure 4.
L. Discussion of Major Problem Areas:
1. Corrosion:
See text, Section 4 and
Table 10.
0
0
0
0
0
0
54
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2. Erosion:
3. Scaling:
4. Plugging:
5. Design problems: ___________
6. Waste water/solids disposal:
55
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7. Mechanical problems:
M. General comments:
56
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TECHNICAL REPORT DATA
(Please read lusifuc (ions on the reverse before completing)
1. IREPORT NO. )2.
EPA-600/7-78-048c
3. RECIPIENT’S ACCESSIOI*NO.
4. TITLE AND SUBTITLE Survey of Flue Gas Desulfurization
Systems: St. Clafr Station, Detroit Edison Co.
REPORT DATE
March 1978
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Bernard A. Laseke, Jr.
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING OROANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-01-4147, Task 3
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
Subtask Final; 1-6/77
14. SPONSORING AGENCY CODE
EPA/600/l3
15. SUPPLEMENTARY NOTES JERL .. ..RTP project officer is Norman Kaplan, Mail Drop 62, 919/
541-2556.
16. ABsTRAcTThe report gives results of a survey of the flue gas desullurization (FGD )
system retrofitted on Unit 6 of, Detroit Edison Co. t St. Clair Station. The experi-
mental FGD system, which operated through a 2-month (October 1976-January 1977)
demonstration program, utilized a limestone slurry to remove S02 in two parallel
scrubbing trains. Each train included a radial-flow venturi scrubber and a high-
velocity countercurrent spray tower absorber to control Fly ash and S02. Flue gas
cleaning wastes were discharged from a reaction tank to an on-site clay-lined
settling pond. Clear water was recycled from the pond to the FGD system for fur-
ther use. The FGD system was designed to remove S02 and fly ash from high sulfur
eastern coal. Actual operation was on low sulfur western coal. Following the demon-
stration, the FGD system was shut down and modified for resumption of particulate
scrubbing on low sulfur western coal in the fall of 1977. Some S02 is removed from
the flue gas during particulate removal because of the alkalinity of the collected
fly ash and the limestone additive used for pH control of the scrubbing solution.
I?. KEY WORDS AND DOCUMENT ANALYSIS
1. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
C. COSATI heldfGroup
Air Pollution Scrubbers
Flue Gases Coal
Desulfurization Combustion
Fly Ash Cost Engineering
Limestone Sulfur Dioxide
Slurries Dust Control
Ponds
Air Pollution Control
Stationary Sources
Wet Limestone
Particulate
13B
2lB 2 1D
07A , OlD
l4A
07B
hG
08H
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
64
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220.1 (9.73)
5.’
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