vvEPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-79-l99e
August 1979
Survey of Flue Gas
Desulfurization Systems:
Bruce Mansfield Station,
Pennsylvania Power Co.
Interagency
Energy/Environment
R&D 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 ENVIRONMENTAL PROTECTION TECH-
NOLOGY series. This series describes research performed to develop and dem-
onstrate instrumentation, equipment, and methodology to repair or prevent en-
vironmental degradation from point and non-point sources of pollution. This work
provides the new or improved technology required for the control and treatment
of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, 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-600/7-79-199e
August 1979
Survey of Flue Gas
Desulfurization Systems:
Bruce Mansfield Station,
Pennsylvania Power Co.
by
Bernard A. Laseke, Jr.
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-02-2603
Task No. 24
Program Element No. EHE624
EPA Project Officer: Norman Kaplan
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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TABLE OF CONTENTS
Page
Acknowledgment vi
Summary vii
1. Introduction 1
2. Facility Description 2
3. Flue Gas Desulfurization System 10
Background Information 1.0
Process Description 12
Process Design 22
Process Chemistry: Principal Reactions 39
Process Control 42
4. FGD System Performance 44
Background Information 44
Operating History and Performance 45
Problems and Solutions 48
5. FGD Economics 54
Introduction 54
Approach 54
Description of Cost Elements 56
Results 56
Appendix A. Plant Survey Form A-l
Appendix B. Plant Photographs B-l
Appendix C. Operational FGD System Cost Data C-l
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LIST OF FIGURES
No. Page
1 General Geographical Map Showing Power Plants and 3
Related Facilities and Population Centers in the
Vicinity of Shippingport, Pennsylvania
2 Major Components of the Mansfield Plant Coal-handling 6
System
3 Simplified Process Flow Diagrams of Bruce Mansfield 8
Air Quality and Waste Disposal Systems
4 Schematic of the Process Lines and Major Components 14
of the Bruce Mansfield Air Quality and Waste Disposal
System
5 Simplified Diagram of the Bruce Mansfield Venturi 17
Scrubber
6 Simplified Diagram of the Bruce Mansfield Venturi 18
Absorber'
7 Simplified Diagram of the Bruce Mansfield Scrubbing 19
Train, Duct Work, and Reheater
8 Simplified Process Diagram of the Bruce Mansfield 23
Waste Treatment System
9 Cross-sectional View of the Little Blue Run Ravine 24
Embankment
10 Overview of the Little Blue Run Sludge Disposal 25
Reservoir
111
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LIST OF TABLES
No. Page
1 Data Summary: Bruce Mansfield 1 and 2 xi
2 Characteristics of Coal Fired at Bruce Mansfield 5
3 Design, Operation, and Emission Data: Bruce Mansfield 9
1, 2, and 3
4 Specifications and Consumption Rate of Performance 22
Coal
5 Inlet Gas Conditions and System Removal Efficiency 27
6 Venturi Scrubber Design Parameters and Operating 28
Conditions
7 Venturi Absorber Design Parameters and Operating 29
Conditions
8 Mist Eliminator Design Parameters and Operating 30
Conditions
9 Reheater Design Parameters and Operating Conditions 32
10 Induced-draft Fan Design Parameters and Operating 33
Conditions
11 Pump Design Parameters and Operating Conditions 34
12 Lime Storage and Preparation Facility Design 35
Parameters and Operating Conditions
13 Additive Treatment Design Parameters and Operating 36
Conditions
14 Slurry Transportation Design Parameters and Operating 37
Conditions
IV
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LIST OF TABLES (continued)
No
15 Embankment Design Parameters 38
16 Reservoir Design Parameters 38
17 Mansfield 1 Boiler and Scrubbing System Performance 46
18 Mansfield 2 Boiler and Scrubbing System Performance 47
19 Summary of Mansfield 3 Emission-control System 53
20 Mansfield 1 and 2 Reported Capital Costs 57
21 Mansfield 1 and 2 Reported 1977 Annual Variable Costs 58
22 Mansfield 1 and 2 Adjusted Capital Costs 59
23 Mansfield 1 and 2 Adjusted 1977 Annual Costs 60
v
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ACKNOWLEDGMENT
This report was prepared under the direction of Mr. Timothy
Devitt. The principal author was Mr. Bernard Laseke.
Mr. Norman Kaplan, EPA Project Officer, had primary responsi-
bility within EPA for this project report. Information on plant
design and operation was provided by the following members of the
Pennsylvania Power Company: Mr. Russell Forsythe, Engineer; Mr.
C. E. Brown, General Coordinator of Operations; Mr. Dale Billheimer,
Production Engineer; Mr. T. O. Flora, Associate Engineer A; and Mr.
W. F. Reehef, Vice-president of Power Production.
VI
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SUMMARY
The Bruce Mansfield plant is a three-unit, 2751-MW (gross),
coal-fired power generating station, located on the Ohio River in
the Borough of Shippingport, Pennsylvania. The plant is owned by
the Central Area Power Coordination Group (CAPCO), made up of the
Ohio Edison Company, Pennsylvania Power Company, Cleveland Electric
Illuminating Company, Duquesne Light Company, and Toledo Edison
Company. The plant is being constructed and operated by the Penn-
sylvania Power Company, a subsidiary of the Ohio Edison Company.
Bruce Mansfield 1 and 2 are currently operational. Bruce Mansfield
1 was placed in service on December 11, 1975, and was placed in
full commercial operation on June 1, 1976. Bruce Mansfield 2 was
placed in commercial service on October 1, 1977. Bruce Mansfield
3, currently under construction, is expected to begin commercial
operation in April 1980.
Bruce Mansfield 1 and 2, each rated 917 MW (gross), fire a
high-sulfur, eastern, bituminous coal having a maximum sulfur
content of 4.75 percent and an ash content of 19.7 percent. To
meet emission regulations promulgated by the Commonwealth of
Pennsylvania, each unit is fitted with a wet lime scrubbing system
for the control of particulate and sulfur dioxide.
The wet lime scrubbing systems for Bruce Mansfield 1 and 2
were designed and supplied by Chemico. Each system consists of six
parallel, two-stage, scrubbing trains. Each train includes a
variable-throat venturi scrubber, a wet induced-draft fan, and a
fixed-throat venturi absorber. The scrubbing trains are arranged
in two groups of three. Flue gas from the three trains in each
group flows together into an oil-fired reheat chamber and tl^rn is
discharged to the atmosphere through a 950-ft chimney. The chimney,
which serves both operating units, contains four carbon steel flues
VI1
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with polyester flaked glass coating for receipt of the discharge
gases from the four oil-fired reheat chambers. The chimney was not
within Chemico's scope of supply.
The lime used in the scrubbing operations is a proprietary
reagent, known as Thiosorbic lime, supplied by the Dravo Corpora-
tion. This lime, which contains 2 to 6 percent magnesium oxide,
offers the advantage of increased sulfur dioxide removal efficiency
and allows a subsaturated mode of operation.
The flue gas cleaning wastes produced by the scrubbing systems
are treated and disposed of in an environmentally acceptable manner
in a waste disposal system designed and built by the Dravo Cor-
poration. The waste disposal system is a three-part process con-
sisting of a pumping and treatment facility, a transportation
facility, and a containment area. In the pumping and treatment
j^
facility a cementitious stabilizing agent, Calcilox, is added to
the scrubber thickener underflow. This mixture is then pumped via
pipeline to a disposal area approximately 7 miles west of the power
plant. The disposal area is a ravine with an earthen dam at one
end, creating a reservoir into which the waste slurry is pumped and
deposited on the valley floor under a covering of water.
Bruce Mansfield 1 commenced commercial operation on June 1,
1976. Although the performance of the scrubbing system was char-
acterized by an adequate degree of availability* during the balance
of 1976 and the first quarter of 1977 (approximately 80 percent ),
several major problems were encountered that have since limited the
availability and operation of the entire scrubbing system. Speci-
fically, the major areas of concern have been the performance of
the scrubber mist eliminators, excessive water entrainment and
carryover out of the chimney, pH measurement and control, water
balance, reheat burner performance, excessive maintenance asso-
ciated with the wet induced-draft fan housings, and chimney flue
*Avaxlability: 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.
Includes downtime due to chimney coating failures.
viii
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liner failures. The last three problems have been the primary
causes of the reduced system availability and unit operation.
Bruce Mansfield 2 commenced commercial operation on October
1, 1977. This unit is identical to Bruce Mansfield 1 in design,
and the performance of its scrubbing system has been nearly
identical. As in the case of Bruce Mansfield 1, scrubbing system
availability and unit operation have been limited primarily by
problems with the reheaters, induced-draft fan housings, and
chimney flue liners.
Pennsylvania Power Company has reported the total capital
cost of the emission control systems for Bruce Mansfield 1 and 2,
including the air quality control and waste disposal systems, to
be $221,278,000. Of this total, $137,607,000 covers direct and
indirect capital costs of the air quality control system, and
$83,671,000 covers direct and indirect capital costs of the waste
disposal system. Based on a gross generating capacity of 1834 MW,
this amounts to approximately $120.65/kW. The total annual cost
of the scrubbing system, including the air quality control system
and waste disposal system, was reported to be $54,560,047. This
includes $21,589,625 in variable charges and $32,970,422 in fixed
charges. Based on a station capacity factor of 40.09 percent for
1977, giving a total net power production of approximately 3.621
9
x 10 kWh, this amounts to approximately 15.07 mills/kWh in total
annual costs.
Bruce Mansfield 3, which is currently being erected along-
side Bruce Mansfield 1 and 2, will have an air quality control
system supplied by Pullman Kellogg. The emission control strategy
for Bruce Mansfield 3 will be somewhat different from Bruce
Mansfield 1 and 2, in that primary particulate control will be by
electrostatic precipitators (ESP's) installed upstream of the
sulfur dioxide control system. Sulfur dioxide will be removed in
a wet lime horizontal spray chamber system, and the resulting
wastes will be stabilized and disposed of in the existing waste
disposal system. The cost of the entire air quality control
system, including the ESP's, fans, ash handling, absorbers and
IX
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related equipment, thickener, and chimney, is reported to be
$232/net kW.
Table 1 summarizes data on the facility and FGD system.
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TABLE 1. DATA SUMMARY: BRUCE MANSFIELD 1 and 2
Units
Gross rating, MW
Net rating, MW
Fuel
Average fuel characteristics:
Heating value, kJ/kg (Btu/lb)
Ash, percent
Moisture, percent
Sulfur, percent
FGD process
FGD system supplier
Application
Status
Startup dates:
Initial
Commercial
Design removal efficiency:
Particulate, percent
Sulfur dioxide, percent
Water loop
Sludge disposal
Economics (reported):
Capital, $/kW (gross)
Annual, mills/kWh (net)
1 and 2
1834
1650
Coal
27,593 (11,863)
15.11
5.53
2.44
Lime
Chemico
New
Operational
Dec. 1975 (Unit 1)
June 1976 (Unit 1);
Oct. 1977 (Unit 2)
99.8
92.1
Opena
Stabilized sludge dis-
posed in an offsite
dammed reservior
120.65
15.07
The system is designed for closed loop operation; however, it
operates in an open loop because of excess water inputs from
improper set points of seal water flow rate to recycle pumps,
failure of fly ash slurry pumps necessitating the use of river
water to remove fly ash from boiler hoppers to the thickeners,
leakage of river water past emergency water values, and other
sources.
XI
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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 to evaluate 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 on such systems, covers the
Bruce Mansfield plant of the Pennsylvania Power Company. It
includes pertinent process design and operating data, a descrip-
tion of major startup and operational problems and solutions,
atmospheric emission data, and capital and annual cost informa-
tion.
This report is based on information obtained during and
after plant inspections conducted for PEDCo Environmental person-
nel on July 7, 1976, and March 22, 1978, by the Pennsylvania
Power Company. The information presented in this report is
current as of August 1978.
Section 2 provides information and data on facility design
and operation; Section 3 provides background information and a
detailed description of the air quality and waste disposal sys-
tems; Section 4 describes and analyzes the operation and perfor-
mance of the air quality and waste disposal systems; and Section
5 provides a detailed review of capital and annual costs, in-
cluding utility-reported and PEDCo-adjusted values. Appendices
A, B, and C contain details of plant and system operation,
reported and adjusted capital and annual cost data, and photos of
the installation.
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SECTION 2
FACILITY DESCRIPTION
The Bruce Mansfield plant is a new 1650-MW (net), coal-
fired, power generating station located in the Borough of
Shippingport, Beaver County, Pennsylvania. It is situated in
the southwest corner of the State, approximately 56 km (35
miles) downstream of Pittsburgh and 13 km (8 miles) east of the
West Virginia-Pennsylvania State line. The area is highly
industrialized and includes a number of chemical manufacturing
plants and smelters. Another major power station, Beaver
Valley, occupies a site approximately 1.6 km (1 mile) down-
stream of Bruce Mansfield. A general geographical map of the
area, including the power stations, related facilities, and
various population centers, is provided in Figure 1.
The Bruce Mansfield plant site runs more than 2.4 km (1.5
miles) along the Ohio River shore line. It occupies approximately
2
2 km (500 acres), which is considered sufficient for ultimate
expansion to include four coal-fired, power generating units.
Plant grade is at an elevation of 222 m (730 ft), which is 20 m
(65.5 ft) above normal pool elevation of the Ohio River and 10
m (33 ft) above the 100-yr design flood level. The boilerhouses
and turbine rooms, one set for Bruce Mansfield 1 and 2 and one
set for Bruce Mansfield 3 (now being erected), occupy an area
approximately 89 m (292 ft) above grade.
Each unit is equipped with its own steam generator and
turbine. The supercritical, pulverized-coal-fired steam gene-
rator is a once-through, balanced-draft, single reheat unit
supplied by Foster Wheeler. Each unit produces 2910 Mg (6,415,000
Ib) per hour of superheat steam at 540°C (1005°F) and 26.2 MPa
(3785 psig) and 2360 Mg (5,200,000 Ib) per hour of reheat steam
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OHIO
WASTE
DISPOSAL
PIPELINE
WASTE DISPOSAL RESERVOIR
HANCOCK COUNTY
WEST VIRGINIA
BRUCE MANSFIELD
STATION
2751 MW (GROSS)
1980 CAPACITY
5
V
BOROUGH OF SHIPPINGPORT
Figure 1. General geographical map showing power plants and related facilities and
population centers in the vicinity of Shippingport, Pennsylvania.
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at 540°C (1005°F) and 4.0 MPa (570 psig). The turbine generator
is a 917-MW (gross), 26.1-MPa (3675-psig), 538°C/538°C (1000°F/
1000°F), 5.1-kPa (1.5-in.-Hg), 3600-rpn\ unit supplied by General
Electric. The station also contains three auxiliary oil-fired
boilers, which are used for plant startups. These auxiliary
boilers are all shop-assembled units that fire No. 2 fuel oil.
Each produces 79.4 Mg (175,00 Ib) of steam per hour at 299°C
(570°F) and 2.3 MPa (325 psig).
The units burn an eastern, high-sulfur bituminous coal
supplied primarily by several mines in Belmont and Monroe Coun-
ties in Ohio. In addition to obtaining coal from these con-
tracted sources, the utility spot-purchases coal from mines in
Maryland, Pennsylvania, and West Virginia. Table 2 presents the
average characteristics of the coal burned at the plant.
Because of the large quantities of coal required at Mans-
field—301 Mg (332 tons) per hour per unit, or 21.7 Gg (24,000
tons) per day, for all three units at full load—a highly flexible
coal handling system was developed to accommodate coal deliveries
by barge or truck; but virtually all of the coal delivered to
Mansfield arrives by barge. Half of the plant harbor, one of the
largest inland docking facilities in the United States, can
accommodate up to 21 full jumbo barges. Coal can be unloaded
from the barges at a maximum rate of 4.5 Gg (5000 tons) per hour
and transferred via conveyor at a maximum rate of 2.7 Gg (3000
tons) per hour to the crusher house. The delivered coal is
crushed to a maximum size of 3.2 cm (1.25 in.), then conveyed
either to the plant for firing or to yard coal storage piles.
Figure 2 illustrates the major components of the coal-handling
system.
To meet air emission regulations promulgated by the Common-
wealth of Pennsylvania for the Beaver Valley air basin, each unit
includes a wet lime scrubbing system. These systems were supplied
by Chemico for Bruce Mansfield 1 and 2 and by Pullman Kellogg for
Bruce Mansfield 3 as an integral part of the power generating
facilities, and duct work is arranged so that flue gas cannot
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TABLE 2. CHARACTERISTICS OF COAL FIRED AT BRUCE MANSFIELD
Characteristic
Heating value, kJ/kg
(Btu/lb)
Ash, percent
Moisture, percent
Sulfur, percent
Range
25,600-27,800
(11,000-11,950)
11.5 - 13.5
5.5 - 8.5
1.75 - 3.75
Average
26,700
(11,500)
12.5
7.0
3.0
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FULL BARGE HARBOR
CONVEYOR
BARGE UNLOADER
RAIL
FACILITIES
TRANSFER
HOUSE 3
PLANT FEED CONVEYORS
'AS-RECEIVED ^ TRANSFER
SAMPLING MAGNETIC HOUSE
SEPARATOR
SHUTTLE /
CONVEYORS
TRANSFER
CONVEYORS
CONVEYOR EMPTY BARGE O
HARBOR
COAL STORAGE
STACKER/RECLAIMER
EMERGENCY RECLAIM HOPPERS
Figure 2. Major components of the Mansfield plant coal-handling system.
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bypass the scrubbing modules. The concrete chimney with four
coated carbon steel flues is not within Chemico's scope of
supply.
A waste disposal system is provided along with the air
quality control systems for disposal of flue gas cleaning (FGC)
wastes in an environmentally acceptable manner. The wastes
disposal system consists of a stabilization plant, which stabi-
lizes the FGC wastes, and a dammed ravine, which provides a final
disposal site for the treated wastes.
Chapter 123.11 of the Pennsylvania regulations governing the
Bruce Mansfield units limits particulate emissions to 43 ng/J
(0.1 lb/10 Btu) of heat input to the boiler and sulfur dioxide
emissions to 258 ng/J (0.6 lb/10 Btu) of heat input to the
boiler. Actual particulate emissions, as measured by the utility
during performance tests, are 13 ng/J (0.03 lb/10 Btu) below the
standard. Actual measured sulfur dioxide emissions showed that
the sulfur dioxide removal efficiencies of the control equipment
varied widely during initial operating .stages. Specifically, the
removal efficiency on Bruce Mansfield 1 varied from 60 to 94
percent over the course of several performance tests. This was
attributed primarily to pH control problems.
Figure 3 provides a simplified process flow diagram of the
Bruce Mansfield uriits, including the air quality and waste dis-
posal systems. Table 3 presents data on plant design, operation,
and atmospheric emissions.
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CLEAN GAS
POWER
PLANT
BOILER
FLUE
GASES __
SCRUBBING
TRAIN
SPENT SLURRY
AND FLY ASH
TACI
THICKENER
THICKENED SLUDGE
TREATED SlUDGE
MAIN
SLURRY
PUMP
SUPERNATANT
RETURN
SUCTION
BOOSTER PUMP
DISCHARGE ._.
1
Vn • " n
RESERVOIR
H
BACKUP LINE
BACKUP LINE
PIPELINES TO RESERVOIR
TO SCRUBBERS
FOR MAKEUP
WATER
Figure 3. Simplified process flow diagrams of Bruce Mansfield air quality and waste
disposal systems.
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TABLE 3. DESIGN, OPERATION, AND EMISSION DATA:
BRUCE MANSFIELD 1, 2, and 3
Description
Generating capacity, MW:
Gross
Net without scrubbing
Net with scrubbing
Maximum coal consumption,
Mg/h
(tons/h)
Maximum heat input, GJ/h
(106 Btu/h)
Maximum flue gas rate, m /s
(103 acfm)
Flue gas temperature, °C
(°F)
Unit heat rate, kJ/net kwh
(Btu/net kWh)
Unit capacity factor,
percent (1977)
Emission controls:
Particulate and
Sulfur dioxide
Sulfur dioxide
Particulate emission rate: ,
Allowable, ng/J (lb/10b
(Btu) ,
Actual, ng/J (lb/10°Btu)
Sulfur dioxide emission rate:
Allowable, ng/J
(lb/106 Btu) ,
Actual, ng/J (lb/10 Btu)
Unit 1
917
880h
825b
301
(332)
8,498
(8,055)
1,580
(3,350)
140
(285)
13,190
(12,500)
40.09a
Variable-
throat
venturi
scrubbers
Fixed-
throat
venturi
absorbers
H
15(0.035)°
13(0.03)
258(0.6)
65(0. 15)e
Unit 2
917
880b
825b
301
(332)
8,498
(8,055)
1,580
(3,350)
140
(285)
13,190
(12,500)
40.093
Variable-
throat
, venturi
scrubbers
Fixed-
throat
venturi
absorbers
A
15(0.035)°
13(0.03)
258(0.6)
65(0. 15)°
Unit 3
917
880h
825b
301
(332)
8,498
(8,055)
1,560
(3,308)
140
(285)
N/A°
N/A
N/A
ESP's and
spray
chamber
absorbers
Spray
chember
absorbers
32(0.075)
N/A
258(0.6)
NA
Net rating including plant auxiliary power requirement.
Net rating including plant auxiliary power requirement, scrubbing
system power requirement, and cooling tower power requirement.
£
N/A- Not applicable; unit under construction.
Based upon maximum inlet fly ash loading of 6.9 g/MJ (16 lb/10
Btu) and a maximum rate of 0.019 g/m3 (0.0175 gr/scf).
Results of emission tests performed by Pennsylvania Depart-
ment of Environmental Resources and an independent test
firm hired by the utility.
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SECTION 3
FLUE GAS DESULFURIZATION SYSTEM
BACKGROUND INFORMATION
On September 10, 1969, the CAPCO consortium announced the
construction of the Bruce Mansfield plant. The plant was to
contain two units, each having a net generating capacity of 880
MW. These units would fire high-sulfur, eastern bituminous coal
obtained from local mines. Pennsylvania Power, a subsidiary of
the Ohio Edison Company and a member company of the CAPCO consor-
tium, was responsible for design, construction, and operation of
the plant.
Engineering design was begun in late 1969. Plans for air
quality control were developed in early 1970. Because Pennsyl-
vania had no .statewide standard applicable to sulfur oxide emis-
sions at that time, the original air quality control plans con-
sidered only electrostatic precipitators for control of particu-
late emissions.
In November 1970, the Pennsylvania Department of Environ-
mental Resources (DER) advised Pennsylvania Power that it was
doubtful that a construction permit would be granted because no
sulfur dioxide controls were included in the preliminary design
of the plant. This precipitated an intensive investigation of
applicable sulfur dioxide removal systems by Pennsylvania Power
Company. Approximately 31 potential sulfur dioxide control
systems, offered by both domestic and foreign suppliers, were
evaluated. Fourteen were rejected immediately because they were
in the early developmental stage or because the guaranteed re-
moval efficiency was too low. Thirteen of the remaining 17
systems were rejected because they had not been developed to the
point of reliable application to 800-MW generating units and/or
10
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they could not achieve the anticipated Pennsylvania statewide
sulfur dioxide emission standard.
This elimination process left four systems for closer
examination, three regenerable (i.e., the sulfur dioxide is
recovered in a usable, marketable form) and one nonregenerable:
0 Regenerable magnesium oxide process.
0 Nonregenerable lime slurry process.
0 Regenerable catalytic oxidation process.
0 Regenerable electrolytic cell process.
The three regenerable processes were rejected because of lack of
commercial experience. Only the Chemico venturi lime slurry wet
scrubbing process was given serious consideration for two reasons:
(1) it was the only system that had been used commercially for
particulate control at an electric utility station (Arizona
Public Service, Four Corners 1, 2, and 3); and (2) Chemico had
design experience in sulfur dioxide removal from exhaust gases in
the chemical industry to make its system the most promising
candidate to meet the Pennsylvania statewide sulfur dioxide
emission standard.
Because further investigations revealed that the technology
associated with sulfur dioxide control had not reached the level
of development necessary for reliable full-scale application,
Pennsylvania Power proposed that a single module be built to
treat part of the flue gas (20 to 25 percent of the total gas
flow) from Bruce Mansfield 1. This module was to be an experi-
mental prototype that would provide key design data and operating
information in the areas of chemical, mechanical, and disposal
problems. A 290-m (950-ft) stack was to be constructed to
prevent ground-level concentrations from exceeding ambient air
quality standards. This proposal was rejected by DER and the
U.S. EPA.
In July 1972, Pennsylvania Power resubmitted its application
for a construction permit to DER and included a lime flue gas
scrubbing system for the control of particulate and sulfur dioxide
11
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in accordance with air emission regulations (Chapters 123.21,
123.22). A construction permit was granted in October 1972. In
January 1973, Chemico was authorized to proceed with detailed
design and engineering work for the installation of two full-
scale venturi lime slurry scrubbing systems. During this design
3
period a 0.7-m /s (1500-acfm) pilot plant was installed at Ohio
Edison's R. E. Burger plant. Pilot plant testing was conducted
from February to May 1973 and from August to September 1973.
Flue gases of composition similar to those of the Mansfield plant
were passed through the pilot unit, and various limes were tested
to determine what type would be best suited for the high removal
efficiencies required (99.8 percent for particulate and 92.1
percent for sulfur dioxide). Parameters for closed-water-loop
operation were determined, as were the means of disposing of
waste products from the flue gas cleaning system. As a result of
the pilot programs, the Dravo Corporation was awarded contracts
(1) to design and install a waste disposal system that used their
proprietary additive, Calcilox, and (2) to supply the lime re-
agent, Thiosorbic lime, also a proprietary material.
PROCESS DESCRIPTION
The lime slurry scrubbing systems on Bruce Mansfield 1 and 2
were supplied by Chemico. Each consists of six scrubbing trains
designed to treat the total boiler flue gas stream of 1580 m /s
(3.35 x 106 acfm) at 140°C (285°F). The design efficiencies of
the systems are 99.8 percent removal of the inlet particulate
matter and 92.1 percent removal of the inlet sulfur dioxide when
the boiler fires coal with sulfur and ash contents as high as
4.75 and 19.7 percent. The flue gas cleaning system was in-
stalled as an integral part of the power-generating facilities.
Duct work is arranged so that flue gases cannot bypass the scrub-
bing trains.
12
-------
The flue gas cleaning wastes produced by the scrubbing
systems are discharged from the air quality control plants as
thickener underflow at approximately 8.2 Mg (9000 tons) per
unit per day. The thickener underflow, which contains 25 to 35
percent solids, is pumped to an onsite sludge treatment facility,
where a stabilization material (Calcilox) is added before the
mixture is pumped 11 km (7 mi) to an offsite containment area
for final disposal.
Because of the size and complexity of the air quality and
waste disposal systems, each is described in a separate sub-
section. The air quality control system can be described in
terms of three basic operations: (1) lime handling and pre-
paration, (2) gas treatment, and (3) solids/ liquid separation.
The waste disposal system can be described in terms of four
basic operations: (1) additive handling and preparation, (2)
pumping and treatment, (3) transportation, and (4) containment.
A schematic of the Bruce Mansfield air quality and waste dis-
posal system, including all major components and process lines,
is provided in Figure 4.
Air Quality Control System
Lime Handling and Preparation—
Lime for the scrubbing operation is supplied by Dravo
Corporation under a long-term contract with Pennsylvania Power.
This reagent, known as Thiosorbic lime, contains 2 to 6 weight
percent magnesium oxide. The lime comes from a deep mine and
preparation plant operated by Dravo in Maysville, Kentucky. A
captive fleet of three towboats and numerous covered barges
transports the reagent upriver to the Bruce Mansfield plant.
The lime is unloaded from the barges by a clamshell-type
unloader. A conveying system transports the lime either into
30-day, 14,500-Mg (16,000-ton) bulk storage silos or two 3-day,
2270-Mg (2500-ton) storage silos. The 3-day silos are arranged
so that lime can be discharged directly by belt, scale-type,
weigh feeders into the lime slakers. One feeder and one slaker
is provided for each 3-day storage silo.
13
-------
t«u« MB Mil
MOWMB tarn*
US FILIU IKOMSII
«— Dun on tcnwra ef
<— MIUI OU> IIIH
«- fUSK-THMI OMI>
FLUSH
U1IH H.IK «* DISPOSAL MM
RIVES DISCHMGt PWVS (2)
Figure 4. Bruce Mansfield flow diagram.
-------
The slurry from the slakers is allowed to stabilize (com-
pletion of chemical slaking process) for approximately 30 minutes
in an 11-m (36-ft)-diameter transfer tank. It is then pumped
approximately 900 m (3000 ft) to a 3.7-m (12-ft)-diameter recycle
tank directly adjacent to the absorbers. The recycle tank feeds
a local recycle loop, which branches off into individual lines
feeding each separate scrubber and absorber module. The lime
feed, which is distributed equally between the scrubbers and
absorbers, is transferred directly into the bottom of each
scrubber and absorber for circulation through the vessel.
Gas Treatment—
Flue gas exits from the two air heaters of each boiler at
1580 m3/s (3.35 x 106 acfm) and approximately 140°C (285°F), then
enters a manifold that distributes it to six separate 4.6m (15-
ft)-diameter inlet ducts. Each duct serves one scrubbing train
consisting of a variable-throat venturi scrubber module, a 6700-kW
(9000-hp) induced-draft fan, and a fixed-throat venturi absorber
module. Six scrubbing trains are required on each unit for full
boiler load operation. They are arranged in two groups of three,
and the treated gas discharged from the three trains in each
group flows together into a 7.6-m (25-ft)-diameter, oil-fired
reheat chamber. The heated exhaust gas is then discharged to
the atmosphere through a 290-m (950-ft) stack. The stack, which
serves both units, contains four separate carbon steel flues,
each of which receives the reheated gas stream discharged from
one reheat chamber.
The flue gas first enters the top of the venturi scrubber,
then passes down and around the adjustable plumb bob and acceler-
ates to a velocity of approximately 61 m/s (200 ft/s) through the
throat area. The gas is contacted in a cocurrent fashion with
lime slurry that is recycled from the base (internal recycle
tank) of the scrubber. A tangential-feed arrangement of the
slurry feed nozzles atop each scrubber provides the primary
sprays that wet the plumb bob and throat area. The incoming gas
impacts upon this curtain of slurry spray, forming fine droplets,
15
-------
which intimately mix with the gas stream as they pass through the
throat area. The gas-slurry stream separates in the lower section
of the scrubber. The gas turns 180 degrees and passes upward
through mist eliminator. The spent slurry droplets from the
sprays are collected in the internal recycle tank for recir-
culation through the scrubbing circuit. The cleaned gases pass
through the single-stage mist eliminator and then flow through
the discharge duct to the induced-draft fan. Figure 5 provides a
simplified diagram of a Bruce Mansfield scrubber module.
The induced-draft fan, which overcomes draft losses in the
boiler and scrubbing system, receives the saturated gases from
the scrubber. The gases then enter the top of the venturi
absorber and pass down through the fixed-throat area. In a
manner similar to that described for the venturi scrubber, the
gas accelerates to a velocity of 30 m/s (100 ft/s) through the
throat area, where it is contacted with lime slurry in a co-
current fashion. The slurry, which is recycled from the ab-
sorber's internal recycle tank, is sprayed into the gas stream
through a tangential-feed arrangement of the slurry feed nozzles.
The nozzles spray slurry onto the convering throat area, gas
baffles, and center cone of the absorber. The gas-slurry stream
separates in the lower section of the absorber. The gas turns
180 degrees and passes upward through the mist eliminator. The
spent slurry droplets from the primary and secondary sprays are
collected in the internal recycle tank for recirculation through
the scrubbing circuit. The cleaned, saturated gases then pass
through another mist elimination stage, from which they are sent
to the reheat chamber for temperature elevation before discharge
to the atmosphere through the stack. Figure 6 provides a simpli-
fied diagram of a Bruce Mansfield absorber module.
Figure 7 provides a simplified diagram of a Mansfield
scrubbing train, including inlet and outlet ducting, fan, re-
heater, and stack.
16
-------
THROAT-
AREA
MIST
ELIMINATOR
SPRAY
SCRUBBER
BLEED TO t=
THICKENER
SCRUBBER
RECYCLE PUMPS
(2)
PLUMB
BOB
FRESH
1 LIME
SLURRY
ABSORBER
BLEED
Figure 5. Simplified diagram of the Bruce Mansfield venturi
scrubber.
17
-------
MIST
ELIMINATOR
SPRAY
ABSORBER
BLEED TO
SCRUBBER
ABSORBER
RECYCLE
PUMPS
(2)
CENTER CONE
FRESH
LIME
SLURRY
THROAT
AREA
Figure 6. Simplified diagram of the Bruce Mansfield venturi
absorber.
18
-------
VD
GAS IN FROM BOILER
Figure 7. Simplified diagram of the Bruce Mansfield scrubbing train, duct work,
and reheater.
-------
Solids/Liquid Separation—
The spent slurry from the venturi absorber is discharged as
a continuous bleed stream off the recycle line to the venturi
scrubber. The absorber bleed stream enters directly into the
internal recycle tank of the scrubber, where it is combined with
the scrubber recycle stream and then recirculated through the
scrubbing circuit. The spent slurry from the venturi scrubber is
also discharged as a continuous bleed stream off the recycle line
to a thickener. The spent slurry, which is 8 to 10 percent
solids, combines with fly ash slurry from the boiler and then
flows into a 61-m (200-ft)-diameter thickener.
The underflow from the thickener, which is 25 to 35 percent
solids, is then pumped to the waste disposal system for treatment
and ultimate disposal. The thickener overflow is used to main-
tain liquid levels in the scrubber and absorber vessels.
Waste Disposal System
Additive Handling and Preparation—
The additive (Calcilox) for the waste disposal system
operation is supplied to Pennsylvania Power by the Dravo Corpora-
tion under a long-term contract. This cementitious stabilizing
agent sets up the sludge to the strength of soil. Calcilox is
transported to the plant harbor in totally enclosed, self-unloading
barges. The stabilizer is unloaded pneumatically into four 4100-
Mg (4500-ton) concrete storage silos. The storage silos feed
pneumatically into two 91-Mg (100-ton) feed hoppers, which dis-
tribute Calcilox directly to two 666,000-liter (176,000-gal) mix
tanks.
Pumping and Treatment—
The thickener underflow is pumped to the mix tanks to be
mixed with the Calcilox. A 40-minute retention time and agitators
assure adequate mixing of the waste stream with the Calcilox.
The mixed sludge is discharged from the mix tanks and piped
through one of two pump suction manifolds that supply four cen-
trifugal booster pumps. The discharge from each booster pump
20
-------
feeds one of four 746-kW (1000-hp), positive-displacement, sludge
transport pumps. Each pump can discharge from 1500 to 4500
liters/s (400 to 1200 gpm). of sludge at 7.7 MPa (1100 psig).
Transportation—
The waste slurry is pumped approximately 12 km {7 mi)
downriver to the Little Blue Run ravine impoundment area. The
slurry pipeline network consists of four underground pipes
connecting the treatment plant and impoundment area. The pipe-
line network serves the dual function of transporting sludge to
the impoundment area and returning supernatant to the plant. The
four lines consist of two 20-cm (8-in.) and two 30-cm (12 in.)-
diameter pipes, which can accommodate waste slurry flows ranging
from 25 to 230 liters/s (400 to 3600 gpm).
The pipeline network is equipped with a high-pressure flush-
ing system and a series of vents and drain boxes situated at high
and low points of the pipe lines. The purpose of the flushing
system is to purge the pipeline of sludge in the event a shutdown
lasts longer than 24 hours, because the sludge will eventually
solidify and plug the pipe if not cleared. Two 1,460,000-liter
(385,000-gal) storage tanks, located next to the sludge mix
tanks, provide the water needed for flushing. Three flush pumps
[centrifugal type, 115 liter/s (1800 gpm) total capacity] direct
flush water to the selected pipeline (s). The discharge from the
flushing operation is routed to the impoundment area.
Containment—
The sludge disposal site is located in the Little Blue Run
Valley lying on the Pennsylvania/West Virginia State line approx-
imately 12 km (7 mi) west of the power plant. An earth and
rockfill dam with an impervious core was constructed across the
mouth of the valley, creating a reservoir for placement of the
sludge. The embankment is 128 m (420 ft) high, 67 m (2200 ft)
long at the crest, 518 m (1700 ft) thick at the base, and is
fi ^ T
composed of 6.5 x 10 m (8.5 million yd ) of fill.
21
-------
The impoundment area covers approximately 5.7 x 106 m2
(1400 acres) in area. The reservoir has a surface area of 3.6 x
10 m {890 acres) and a total storage volume of 90 x 106 m3
(118 million yd ). It extends more than 3.2 km (2 mi) from the
embankment and has over 22 km (13 mi) of shoreline.
The sludge transported through the pipelines is deposited in
the reservoir through a tremie system, which distributes the
sludge uniformly on the reservoir bottom. Supernatant is pumped
from the reservoir surface by pumps on floating rafts. Water can
either be returned to the plant or discharged to the Ohio River.
The water recycled to the plant is either stored in the flush
water storage tanks or routed to a transfer tank for use as
makeup, mist eliminator wash, or slurry water.
Figures 8, 9 and 10 provide several diagrams of the basic
operations of the waste disposal system. Figure 8 presents a
simplified process diagram of the waste treatment system, includ-
ing additive handling and storage. Figure 9 presents a cross-
sectional view of the embankment. Figure 10 presents an overview
of the Little Blue Run sludge disposal reservoir.
PROCESS DESIGN
Air Quality Control System
Fuel—
The scrubbing systems were designed to process flue gas
resulting from the combustion of pulverized coal in two super-
critical steam generators. Table 4 presents fuel specifications
and consumption rate of the performance coal.
TABLE 4. SPECIFICATIONS AND CONSUMPTION RATE OF PERFORMANCE COAL
Heating value, kJ/kg (Btu/lb)
Ash, percent
Moisture, percent
Sulfur, percent
Maximum firing rate, Mg/h per unit
(tons/h per unit)
27,700 (11,900)
12.5
8.0
4.3
301
(332)
22
-------
Ul
TRUCK
FEED
HOPPERS
PNEUMATIC
CONVEYOR
MIX
TANK
SUCTION
BOOSTER PUMP
TREATED SLUDGE
THICKENER
THICKENER
UNDERFLOW
MAIN
SLURRY
PUMP
TO
SCRUBBERS
FOR MAKEUP
WATER f~*"
| HANIFOLD
SUPERNATANT
RETURN
MANIFOLD
DISCHARGE
RESERVOIR
n
BACKUP LINE
BACKUP LINE
t
—• PIPELINES TO RESERVOIR
Figure 8. Simplified process diagram of the Bruce Mansfield waste
treatment system.
-------
to
NQNRESISTANT ROCK
TRANSITION - MATERIAL
FILTER BLANKE1
RESISTANT AND
SEMI RESISTANT ROCK
Figure 9. Cross-sectional view of the Little Blue Run
Ravine embankment.
-------
SLURRY DISPOSAL
IMPOUNDMENT
SLURRY DISCHARGE
TREMIES
SLURRY DISCHARGE
LINES
Figure 10- Overview of the Little Blue Run
sludge disposal reservoir.
25
-------
Inlet Gas Conditions and Removal Efficiency—
The inlet gas conditions to the scrubbing systems and design
particulate and sulfur dioxide removal efficiencies are summarized
in Table 5. The design values presented are based on the speci-
fications and consumption rate of the performance coal.
Venturi Scrubbers—
The venturi scrubbers in the scrubbing systems provide
primary particulate and sulfur dioxide control. Virtually all
the particulate and 70 percent of the inlet sulfur dioxide is
removed during this first venturi stage. Table 6 summarizes
design parameters and operating conditions.
Venturi Absorbers—
The absorbers in the scrubbing systems are second-stage
venturi modules designed to provide any additional particulate
removal required (virtually all of the inlet particulate is
removed in the venturi scrubber) and to remove an additional 70
percent of the inlet sulfur dioxide. The 70 percent sulfur
dioxide removal efficiency in each stage gives a combined removal
efficiency of appro ;.mately 92 percent, the level required to
meet the 258 ng/J (0.6 lb/10 Btu) emission standard when the
sulfur content of the coal is 4.75 percent (maximum). Table 7
summarizes the design parameters and operating conditions of the
venturi absorbers.
Mist Eliminators—
Each module has its own separate mist eliminator, which is
placed horizontal to the flue gas stream. Mist elimination is
aided by a 180-degree reversal of the direction of the gas-slurry
stream before it passes through the mist eliminator. This
direction change effects removal of many of the medium-to-large
liquid and solid particles before the stream reaches the mist
eliminator. Table 8 summarizes design parameters and operating
conditions. Figures 5 and 6, which provide simplified diagrams
of the venturi scrubber and absorber modules, also illustrate the
mist eliminator arrangements.
26
-------
TABLE 5. INLET GAS CONDITIONS AND SYSTEM REMOVAL EFFICIENCY
Parameter
Average
Maximum
Inlet gas: _ 3
Volume, m /s (10 acfm)
Temperature, °C (°F)
Particulate,
ug/J (lb/10b Btu)
c/m^ (gr/scf) (dry basis)
Sulfur dioxide,
yg/J (lb/106 Btu)
ppm
Outlet gas ^ -
Volume, m /s (10 acfm)
Temperature, °C (°F)
Particulate,
ng/J (lb/106 Btu)
mg/m (gr/scf)(dry basis)
Sulfur dioxide,
ng/J (lb/106 Btu)
ppm
Particulate removal efficiency,
percent
Sulfur dioxide removal efficiency,
percent I
1580 (3350)
140 (285)
6.9 (16)
10.27 (4.49)
3.1 (7.2)
2940
1210 (2560)
52 (125)
15 (0.035)
40 (0.0175)
258 (0.6)
242
99.8
92.1
28.93 (7.75)
3.4 (7.9)b
3090
Based on a maximum coal ash content of 19.7 percent.
Based on a maximum coal sulfur content of 4.75 percent.
27
-------
TABLE 6. VENTURI SCRUBBER DESIGN PARAMETERS AND
OPERATING CONDITIONS
Total number of modules
Number of modules per unit
Type
Dimensions:
Diameter, m(ft)
Height, m(ft)
Materials of construction
Plumb bob
Throat
Internals
Shell
Flue gas volume, m / . (acfm)
Flue gas temperature:
Maximum, °C (°F)
Design, °C (°F)
Flue gas velocity, m/s (ft/s)
Pressure drop:
Design, kPa (in. H^O)
Liquid recirculation rate,
liters/s (gpm)
Liquid-to-gas ratio (L/G),
liters/m* (gal/103 acf)
12
6
Variable-throat (plumb
bob) venturi scrubber
10.8 (35.5)
15.8 (52.0)
317 SS, flake-glass lining^
316 SS, flake-glass lining6
Carbon steel, flake-glass
lining3
Carbon steel
263 (558,300)
149 (300)
140 (285)
61 (200)
6 (23)
1,390 (22,000)
5.3 (40)
a The flake-glass lining used in the scrubbers was supplied
and applied by Heil; 80 mils of Rigiline 413GS and 410 was
used for stainless steel surfaces; 80 mils of Rigiline 4850
was used for carbon steel surfaces.
28
-------
TABLE 7. VENTURI ABSORBER DESIGN PARAMETERS AND
OPERATING CONDITIONS
Total number of modules,
Number of modules per unit
Type
Dimensions:
Diameter, m(ft)
Height, m(ft)
Materials of construction:
Center cone
Throat
Internals
Shell
•3
Flue gas volume, m /s (acfm)
Flue gas temperature:
Maximum, °C (°F)
Design, °C (°F)
Flue gas velocity, m/s (ft/s)
Pressure drop:
Maximum, kPa (in. H20)
Design, kPa (in. H20)
Liquid recirculation rate,
liters/s (gpm)
L/G,a liters/m3 (gal/103 acf)
12
6
Fixed-throat venturi
10.4 (34)
15.7 (51.5)
316 SS, flake-glass lining
316 SS, flake-glass lining
Carbon steel, flake-glass
lining
Carbon steel
201 (426,600)
66 (150)
53 (127)
30 (100)
4 (16)
2 (8)
1220 (19,400)
5.3 (40)b
Liquid-to-gas ratio.
T *3
Actual operating L/G ratio is 2.6 liters/m (20 aal/10 acf).
29
-------
TABLE 8. MIST ELIMINATOR DESIGN PARAMETERS AND OPERATING
Total number
Number per module
Type
Configuration
Materials of construction
Number of stages
Number of passes per stage
Shape
Spacing between lanes, cm (in.)
Mist carryover, g/m (gr/acf)
Wash system:
Water source
Wash direction
Frequency
Duration
Rate
Pressure
24
1
Chevron
Horizontal,
Fiber-reinforced plastic
1
4
Chemico open chevron design
7.6 (3.0)
2.3 (1.0)a
Transfer water
Overspray/underspray
Overspray - once per shift;
Underspray - continuous
sequence spray on each
quadrant.
Overspray - 1 h/shift
Underspray - continuous
Overspray - 7.9 liters/s
(125 gpm);
Underspray - 4 liters/s
(63.5 gpm)
Overspray - 379 kPa (40 psig)
Underspray - 241 kPa (20 psig)
Actual measured value is 1.2 g/m (0.5 gr/acf).
30
-------
Reheaters—
Each scrubbing system is equipped with two oil-fired,
direct-combustion reheaters. These reheaters were intended to
elevate the discharge gas temperature to avoid downstream
condensation and corrosion, suppress plume visibility, and
enhance plume rise and dispersion of pollutants. Because
experience has shown that the reheaters are incapable of operating
at temperatures high enough to reheat the flue gas sufficiently
and they require extensive maintenance, they will not be used.
Table 9 summarizes reheater design and operating parameters.
Fans—
In each scrubbing train, a wet-type, induced-draft fan is
situated between the venturi scrubber and venturi absorber.
These fans are designed to operate in tandem with the boiler
forced-draft fans and overcome the draft losses in the boiler
and scrubbing system. Table 10 summarizes the design and
operating parameters.
Pumps--
Each air quality control system has approximately 35
pumps, within the liquid circuit battery limits from the lime
slurry feed to the thickener underflow discharge. Table 11
summarizes pump design parameters and operating conditions.
Lime Storage and Preparation—
One lime storage and preparation facility meets the reagent
needs for scrubbing systems. Table 12 summarizes design
parameters and operating conditions.
Waste Disposal System
The four basic operations of the waste disposal system are
additive handling and preparation, pumping and treatment,
transportation, and containment. Tables 13 and 14 summarize
the design parameters and operating conditions for additive
treatment and slurry transportation, Tables 15 and 16 list the
embankment and reservoir design parameters.
31
-------
TABLE 9. REHEATER DESIGN PARAMETERS AND OPERATING CONDITIONS
Total number
Number per scrubbing system
Type
Manufacturer
Combustion chamber location
Combustion chamber type
Number of burners per chamber
Fuel
Heating value, t. /liter
(103 Btu/gal)
Sulfur content, percent
Combustion rate per chamber,
liters/s (gpm)
Heat input, GJ/h (Btu/h)
Gas temperature, °C (°F)
Reheated gas temperature, °C (°F)
4
2
Direct combustion
Thermal research and
engineering
In-line
Vortex type, mechanical
atomization
No. 2 fuel oil
39 (140)
0.3
0.5 (7.9)
29.5 (28.0)
1650 (3000)
74 (165)
32
-------
TABLE 10. INDUCED-DRAFT FAN DESIGN PARAMETERS
AND OPERATING CONDITIONS
Total number
Number per scrubbing train
Manufacturer
Service
Specifications:
Type
Rating, kW(hp) and rpm
Pressure drop:
Design, kPa (in. H20)
Maximum continuous, kPa
(in. H^O)
Motor, kv o 3
Capacity, m /s (ft /min)
Gas temperature, °C (°F) 3
Gas density, kg/m3 (ib/ft )
Materials of construction:
Housing
Scrolls
Blades
Shaft
12
1
Green Fan Company
Wet
Radial tip, inlet damper
control
6700 (9000) and 1300
19 (75)
16 (63)
13.2
263 (558)
48 (118)
0.913 (0.057)
Rubber-lined carbon steel*
Inconel 625
Inconel 625
Carbon steel clad with
Carpenter 20
* The rubber-lined carbon steel has been extremely unsatisfactory
and is being replaced with housing fabricated from Inconel 625.
33
-------
TABLE 11. PUMP DESIGN PARAMETERS AND OPERATING CONDITIONS
U)
24
24
4
4
4
4
St'i ubber
recycla
Absorber
recycla
Thickener
undcrf luw
Thickener
tran&f er
Limi* slurry
transfer
Lime slurry
recycle
M leti-Shaman-Hof f
Allen-Sherman-Hof f
Joy/Denver
Goulds
Joy/Denver
Joy/Denver
Cent i I f u.ia 1 ,
sirji|l o- slagi- ,
V-belt
Ccntr 1 1 u*i j 1 ,
BlIKlle-Std^jC,
V-belt
Centr i f Uijal ,
sin«jlp-sta9«,
V-belt
Cc-nt r i f ut|ti 1 ,
Binqle- stage,
V-bttl t
CP nt r i f u'jd t ,
single- stage.
V-belt
Ccntri f uqal ,
• inql e- s ta
-------
TABLE 12. LIME STORAGE AND PREPARATION FACILITY DESIGN
PARAMETERS AND OPERATING CONDITIONS
Lime storage:
Bulk storage silos:
Number 3
Capacity, Gg(10 ton)
Retention time, days
Short term storage silos:
Number ^
Capacity, Gg(10 ton)
Retention time, days
Lime preparation:
Slakers:
Number
Manufacturer
Capacity, Mg/h (tons/h)
Feed rate, liters/s (gpm)
Solids, percent
Stoichiometric, percent
Point of addition
Maximum feed rate,
liters/s (gpm)
14.5 (16)
30
2.3 (2.5)
2
Dorr-Oliver
20 (22)
63 (1000)
9
130
Recycle tank
125 (2000)
a One common recycle tank is provided for each scrubbing system.
The recycle tank, which is situated adjacent to the absorbers,
receives the lime slurry stream and feeds a local recycle loop
that has individual branches feeding the internal recircula-
tion tank of each module.
Per scrubbing system.
35
-------
TABLE 13. ADDITIVE TREATMENT DESIGN PARAMETERS AND
OPERATING CONDITIONS
Thickener underflow characteristics:
Solids, percent (wt.)
Temperature, °C (°F)
Specific gravity
Particle size
PH
25 to 35
38 to 52 (100 to 125)
1.2 to 1.29
250
10.5 to 11.0
Treatment processing rates:
12.5 percent station load factor,
Mg/h (tons/h)
25 percent station load factor,
Mg/h (tons/h)
50 percent station load factor,
Mg/h (tons/h)
75 percent station load factor,
Mg/h (tons/h)
100 percent station load factor,
Mg/h (tons/h)
Additive requiremen^ "?:
Calcilox, kg/s (l^/min)
Lime grits, kg/s (Ib/min)
Additive feed rates:
Normal:
Calcilox, percent of total flow
Maximum:
Calcilox, percent, on dry basis
of material being pumped
Retention time, minutes
45 (50)
91 (100)
180 (200)
270 (300)
360 (400)
5.3 (700)
0.7 (93)
10
40
36
-------
TABLE 14. SLURRY TRANSPORTATION DESIGN PARAMETERS AND
OPERATING CONDITIONS
Slurry pumping characteristics
20-cm
(8-in) pipe
30-cm
(12-in) pipe
25 percent solids and 1.2 specific gravityi
Minimum conditions:
Velocity, m/s (ft/s)
Plow rate, liters/s (gpmi
Total capacity, Mg/h
1.22 (3.99)
39 (619)
168 (IBS)
2.41 (7.92)
78.1 (1238)
336 (371)
0.97 (3.20)
31.5 (500)
140 (155)
1.95 (6.41)
63.1 (1000)
281 (309)
O.BO (2,63)
26.1 (415)
121 (133)
1.59 (5.21)
52.4 (830)
242 (268)
1.08 (3.54}
78.1 (1238)
336 (371]
3.10 (10.18)
226 £3590)
976 (1076)
0.87 (2.85)
63.1 (1000)
281 (309)
2.50 (8.20)
183 (2904)
816 (390)
0.73 (2.38)
52.4 (830)
242 (268)
2.07 (6.78)
152 (2410)
705 (777)
37
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TABLE 15. EMBANKMENT DESIGN PARAMETERS
Height, m (ft)
Crest length, m (ft)
Base thickness, m (ft)
Composition, 106 m3 (106 yd3)
128 (420)
670 (2200)
472 (1550)
6.5 (8.5)
TABLE 16. RESERVOIR DESIGN PARAMETERS
6 2
Total area, 10 m (acre)
6 2
Surface area, 10 m (acre)
Depth, m (ft)
Shoreline, km (mi)
Total storage volume, 10 m
(106 yd3)
5.7 (1400)
3.6 (890)
110 (350)
21 (13)
90 (118)
38
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PROCESS CHEMISTRY: PRINCIPAL REACTIONS
The chemical reactions involved in the Bruce Mansfield wet
lime scrubbing processes are highly complex. Although details of
these processes 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 .
(1)
S°2(aq.) + H2°« " H2S03
In addition, some sulfur trioxide is formed from further oxida-
tion of the sulfur dioxide in the flue gas stream.
(3) 2S02 t
Because conditions are thermodynamically but not kinetically
favorable, only small amounts of sulfur trioxide are formed.
This species, like sulfur dioxide, is an acidic anhydride that
reacts readily to form an acid in the presence of water.
(4) S0 t « -£S0
S°
3(aq.) + H2°
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:
39
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(6) H2S03 «, —^ H+ +
(7) HS03~ < * H+ + SO3"
-*• rr+ .
(8) H2S04 «. H
(9) HSO4~ t *~ H + S04 =
Analogous to the oxidation of sulfur dioxide to form sulfur
trioxide, oxidation of sulfite ion by dissolved oxygen (no) in
the scrubbing slurry is limited.
(10) 2SO_ + 00(aq.) „ *
J Z. 1
This reaction occurs in the aqueous phase like the gas-phase
oxidation of sulfur dioxide. Formation of sulfate is a second-
order reaction that is directly proportional to the concentra-
tions of DO and sulfite ion. Since the DO content of the scrub-
bing 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 concentration.
Since sulfite solubility increases as pH decreases, sulfate ion
production occurs more readily in the acidic pH range.
The Thiosorbic lime reagent supplied by Dravo is burned lime
containing primarily calcium oxide (94 to 98 percent) and a small
quantity of magnesium oxide (2 to 6 percent). When slaked with
water, the calcium and magnesium oxides are converted to hy-
droxides.
(11) CaO + H2O + * Ca(OH)2
(12) MgO + H2O « *Mg(OH)2
The calcium and magnesium hydroxides produced during the slaking
process are soluble to different extents in the aqueous phase.
40
-------
(13) r-a (nn) *• r* + 2OH
(14) Mg(OH) - » Mg++ + 2OH~
Because of the superior solubility of the magnesium, this species
dominates in the absorption step, whereas calcium dominates in
the regeneration step. This chemical behavior, similar in nature
to double-alkali chemistry that utilizes a soluble medium (e.g. ,
sodium) for absorption and calcium (lime or limestone) for re-
generation in a reactor outside the scrubbing loop, has given
rise to the phrase "dirty double alkali" for describing magnesium-
lime scrubbing chemistry.
During absorption the magnesium cations react with the pre-
dominate sulfur dioxide anions of sulfite and bisulfite in the
following manner:
(15) Mg++ + S03= « *" MgS0
(16) Mg++ + 2HS0" +- " M
3
The magnesium sulfite formed in reaction (15) is a highly soluble
ion pair, which is capable of further reacting with sulfur dioxide
ions in the following manner:
(17) MgS03 + E + HS03
Thus, the predominate species formed during absorption is magnesium
bisulfite. The spent absorbing medium is collected at the base
of the venturi modules in the internal recirculation tank. Fresh
slaked lime is added to the internal recirculation tank, result-
ing in regeneration of the absorbing medium and formation of the
waste products.
(18) Mg(HS03)2 + Ca(OH)2
(19) Mg(HS03)2 + Mg(OH)2
41
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The calcium sulfite precipitates ^-rL as a hemihydrate crystal.
(20) CaS03 + 1/2 H20^===^: CaS03-l/2 H2O 4
Sulfate ions formed by reactions (9) and (10) also constitute a
waste product, which is purged from the system as either a
soluble component of the sludge liquor or an insoluble calcium
sulfate dihydrate {gypsum) .
(21) CaSO4 + 2 H2O «
The gypsum formed in the system is present in small quantities
because of the subsaturated mode provided by the magnesium
species.
The waste products collected in the scrubbing system, which
include fly ash, calcium sulfite, and calcium sulfate, as well as
some unused reagent, are discharged to the thickener for separa-
tion and disposal.
PROCESS CONTROL
The process con ol network of the Bruce Mansfield air
quality and waste disposal systems focuses on the regulation of
reagent feed, slurry solids, and water balance. The major vari-
ables measured for process control include solution pH, slurry
solids, liquid level, and liquid flow. The principal features of
the control network are described and summarized as follows:
Reagent Feed
Control signals are provided by pH sensors, which modulate
the flow of lime slurry to the scrubbing systems in a feedback
control mode. The sensor feeds a signal back to the controller,
and regulation is effected by correcting for any deviation
between the response valve and set point after the fact. Each
venturi scrubber and venturi absorber in these scrubbing systems
has lime slurry circulated through it. Therefore each module
regulates the amount of lime slurry fed to each scrubber and
42
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absorber by monitoring slurry pH in each recirculation line. A
short-coupled, flow-through system takes a sample at the fresh-
slurry injection point and returns the sample directly to the
scrubber vessel at a location directly above the liquid level.
The pH sensors are a Universal Uniloc model equipped with
ultrasonic cleaners that do not work and are being removed.
The signal is relayed to an air-operated, pinch-type, flow-
control valve installed in each individual feed line that
branches off the local recycle loop of the lime recycle tank.
The pH control range of the lime slurry feed is 7.0 +_ 0.2. As
the pH swings above or below this control bank, the amount of
fresh slurry is automatically reduced or increased to maintain
slurry pH within this bank. This permits optimum removal
efficiency while preventing loss of chemical control, which can
lead to scale formation or plugging.
Slurry Solids
The slurry solids content in the scrubbing solution is
manually controlled by maintaining a constant slurry solids
content in the purge stream to the thickener. The solids
content of this purge stream is 10 percent; it keeps the solids
content of the absorber purge that flows to the Venturis at 8
percent.
The solids content of the thickener underflow is also con-
trolled manually. Maintaining a slurry solids content of 30
percent in the underflow stream provides several benefits: (1)
plugging and erosion are minimized; (2) chemical control is
maintained; and (3) the waste disposal system operates more
efficiently.
Water balance
Water balance in the scrubbing system is monitored and
controlled by the use of diaphragm and static-head level indi-
cators situated in each scrubber and absorber internal recir-
culation tank and lime slurry transfer tank. Thickener overflow
is used to maintain liquid levels in these and other tanks in
the scrubbing systems. 43
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SECTION 4
FGD SYSTEM PERFORMANCE
BACKGROUND INFORMATION
Bruce Mansfield air quality and waste disposal systems
represent the largest and most sophisticated applications of
scrubbing and waste disposal technology in the world today. The
air quality control systems, which represent first-generation
design philosophy, are an integral part of the power production
systems. Because these systems provide primary control of both
sulfur dioxide and particulates, the duct work design does not
permit flue gas to bypass the system. At the time they were
designed, pilot-tested, and developed, flue gas desulfurization
(FGD) was still in the early stage of development. Much of the
design philosophy Oj. FGD technology at that stage was "borrowed"
from other fields and applications. Specifically, the ultimate
choice of a system supplier to design, fabricate, and supply the
scrubbing systems was based on their previous experience with a
fly ash scrubbing application at one utility station and sulfur
dioxide removal in the chemical industry. Many of the advances
in second- and third-generation design philosophies over the last
5 years are not evident in these two systems, but they are
reflected in the one now under construction for Bruce Mansfield
3. (This is discussed at length in the latter part of this
section.)
The operating history and. performance of the air quality and
waste disposal systems, including removal efficiencies, depend-
ability, and problems and solutions, are summarized in the follow-
ing paragraphs.
44
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OPERATING HISTORY AND PERFORMANCE
Air Quality Control System
Bruce Mansfield Unit 1 was first fired on November 3, 1975.
Initial operation of the unit began on December 11, 1975, and
commercial operation followed approximately 6 months later on
July 1, 1976. Initial operation of Bruce Mansfield 2 began in
July 1977, and commercial operation followed approximately 2
months later on October 1, 1977.
Many major design-, mechanical-, and chemical-related prob-
lems accompanied the initial and subsequent operation of the air
quality control systems. These included corrosion, scale, mist
eliminator inefficiency, reheater vibration, pH control failures,
stack liner failures, and induced-draft fan problems.
Although many of the problems plaguing the systems have been
resolved, problems with the chimney liners and induced-draft fans
have severely limited system availability. The former problem,
severe stack liner failures, has especially limited operations,
requiring each of the units to operate at half-load capacity for
1 year. The availability of the scrubbing trains that have been
kept in service, however, has been adequate. Tables 17 and 18
summarize the performance of the Bruce Mansfield boilers and
scrubbing systems.
Waste Disposal System
When Bruce Mansfield 1 was first fired, the waste disposal
system was completed to the extent that a minimum nanual system
was available to process waste slurry. This allowed a slurry
flow path to be maintained between the plant and reservoir while
the balance of the system was completed. This final phase of
construction, which involved the installation of backup elements
and all automatic controls, lasted approximately 18 months.
Halfway through this final construction phase the utility fully
45
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ABLE 17. MANSFIELD 1 BOILER AND SCRUBBING SYSTEM PERFORMANCE
Per iod
May 76
June 76
July 76
August 76
Sept. 76
Oct. 76
Nov. 76
Dec . 7 6
Year
Jan. 77
Feb. 77
March 77
April 77
May 77
June 77
July 77
Aug. 77
Sept. 77
Oct. 77
Nov. 77
Dec. 77
Year
Jan. 78
Feb. 78
Boiler
operating
hours
595
720
673
705
720
720
277
722
5,132
675
540
264d
0
121e
669
473
692
558
720
720
626
6,058
331
514
System dependability factors, percent
Total system
availability
80
100
90
95
100
99
100
100
96
90
80
88
Of
82f
93*
100r
70
66
93
95f
97f
80g
67f
74f
Total system
operability3
100
100
100
100
100
100
100
100
100
91
85
88
Of
70f
99*
1001
73
74
95
95*
98*
819
67f
93f
Total system
reliability*3
100
100
100
100
100
100
100
100
100
Total system
utilization0
80
100
90
95
100
99
100
97
95
83
69
of
39f
93*
65f
67
58
93
95*
86f
62g
39f
74f
Operability index: the number of hours the FGD system is operational
divided by the boiler operating hours, expressed as a percentage.
Reliability index: the number of hours the FGD system is. operational
divided by the number of hours the FGD system is called upon to operate,
expressed as a percentage.
Utilization index: the number of hours the FGD system is operational
divided by the number of hours in the period, expressed as a percentage.
The unit operated 12 days because of a scheduled 10-week turbine overhaul.
Repairs commenced on the stack flue liners.
e Unit started up on May 23, 1977, and remained in service at half load during
the remainder of the month.
A Dependability factors calculated for. operation of half the system.
^ Annual averages of dependability factors include monthly values when half
the system was in service.
46
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TABLE 18. MANSFIELD 2 BOILER AND SCRUBBING SYSTEM PERFORMANCE
Period
Oct. 77
Nov. 77
Dec. 77
Year
Jan. 78
Feb. 78
Boiler
operating
hours
595
581
469
1645
391
672
System dependability factors, percent
Total system
availability
80
72
93
82
97
. 89
Total system
operability
79
74
93
82
85
75
Total system
reliability
Total system
utilization
66
58
77
67
53
75
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assumed the responsibility of operating and maintaining the
system.
PROBLEMS AND SOLUTIONS
Startup and subsequent operation of the Bruce Mansfield
scrubbing and waste disposal systems have been accompanied by
several design-, mechanical-, and chemical-related problems,
especially in the scrubbing systems and related equipment. The
utility, in conjunction with system supplier, has conceived and
implemented solutions to many of these problems. The major
problems encountered with scrubbing and waste disposal systems
and their solutions are summarized and discussed by generic
type (design, mechanical, chemical) in the following paragraphs,
Air Quality Control System
Design-related Problems—
The scrubbing systems were orginally designed so that five
of the six scrubbing trains installed on each unit could handle
total boiler gas flow at a slightly reduced particulate and
sulfur dioxide col^ ction efficiency. Actual operation has
shown, however, that all six scrubbing trains are necessary
when the unit is operating at full load. This has eliminated
the option of servicing one train over a short period of time
without the necessity of load cutbacks.
The reheaters have never worked properly. At maximum
operating conditions a resonance pattern was created by the oil
burners, and severe duct vibration occurred. The shock wave
created by the oil injection nozzle matched the reasonance
frequency of the ducts. This vibration was so severe that, if
permitted to continue, it would have cracked the ducts and
shaken them loose. The oil injection nozzles were modified by
the manufacturer to eliminate this shock wave. Although this
modification was successful, the reheaters are only able to
operate at 80 percent capacity and provide a AT of 17 to 19°C
(30 to 35°F).
48
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Mist eliminator performance has been a major problem area in
system operation. The problems encountered resulted from a
complex combination of chemical-, mechanical-, design-related
factors, as well as from operating the mist eliminators above
design gas volume and from continuous use of thickener overflow
water or work water without intermittent use of fresh water.
Mist eliminator scaling was encountered very early, prompting
modification to the mist eliminator wash system. Moreover, tests
conducted in late 1976 indicated that mist carryover from the
mist eliminators was on the order of 7 g/m (3 gr/scf), higher
than the maximum design value by a factor of three. Pennsylvania
Power and Chemico experimented with second-stage vertical mist
eliminators. Duct diameter and spatial restrictions caused these
mist eliminators to experience high flow velocities, on the order
of 15 m/s (50 ft/s). One experimental vertical mist eliminator
was installed and collapsed because of structural failure.
Another vertical configuration was developed that would operate
at lower gas velocities. Concurrently with this research, model
studies performed by Chemico indicated that excessive carryover
resulted when pressure drops exceeding 3 kPa (0.75 in. HO)
developed across horizontal mist eliminators. No carryover was
evident when pressure drops were maintained at 2 kPa (0.5 in.
H^O) or less. Where the problem is not corrected and pressure
drop continues to rise, the module is taken out of service, and
the mist eliminator is manually cleaned.
Failure of chimney liners is also considered a design-
related problem. Failure of the original coating material
applied to the carbon steel (Cor-Ten) flues has resulted in half-
load operation for 1 year on both units. Originally, the two
flues on Unit 1 were coated with flake-glass. The first 61-m
(200-ft) section of each flue was coated with a troweled-on
flake-glass material approximately 60 mils thick. The remaining
213-m (700-ft) section was coated with a sprayed-on flake-glass
material approximately 20 mils thick. Widespread failure and
resulting corrosion were most severe in the top section. For
49
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want of other viable alternatives, the utility replaced the
sprayed-on coating with the troweled-on material. Several test
patches were also inserted in one of the flues of Bruce Mansfield
2. An inspection of the flues in the spring of 1978 revealed
that one of the flues for Bruce Mansfield 2 had developed a crack
approximately three-quarters of the way around because of coating
failure and acid corrosion attack. This crack had extended to 90
percent of the circumference by the time the utility repaired it
by applying metal cladding to the failed area. The utility
contracted Carnegie Mellon Institute to investigate this pro-
blem thoroughly. Their findings and the results of the test
patch program indicate that a completely suitable coating material
does not exist. Of all the material evaluated, CXL-2000, de-
veloped by Pullman Kellogg, holds the most promise for long-term
service. The utility may use this material when making future
repairs or coating.
Another design-related problem concerns the operation of
the wet induced-draft fans. Although these fans have been beset
by a number of prob1^ms that are a combination of chemical-,
mechanical-, and design-related factors, the major problem en-
countered has been failure of the construction materials. The pH
at this location has been measured at approximately 2.0. The fan
housings (constructed of rubber-lined carbon steel) and the
scrolls (constructed of rubber-lined carbon steel) have been
damaged extensively by corrosion and/or erosion. The utility is
now replacing many of these with components constructed of more
sophisticated alloys, such as Carpenter 20 or Inconel 625.
Chemical-related Problems—
Many of the chemical-related problems that beset the scrub-
bing system and related equipment were caused by a faulty pH
monitoring network during the early phases of operation. Primary
difficulties involved flow sampling location and glass probe
breakage, causing pH to be controlled manually during much of the
initial operation stage. This manual control in turn caused
50
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subsequent problems such as scale formation, plugging, and acid
corrosion. The pH monitors were relocated to a different posi-
tion in the recirculation circuit, and sampling procedures were
modified. The results have been excellent. The pH is controlled
within a very narrow band of 7.0 + 0.2. Magnesium ion concen-
tration is maintained at approximately 1500 ppm in the liquid
circuit. Sulfur dioxide removal efficiency levels are consist-
ently above the 92.1 percent design value. Finally, the modules
are operating without any substantial development of hard scale
(gypsum) or plugging, which often affected mist eliminator per-
formance .
Mechanical-related Problems—
Although the system has been plagued by a number of minor
problems such as pump and valve failures, they have caused very
little outage time.
Waste Disposal System
Generally, the operation of the waste disposal system has
proceeded without major incident; however, the problems that have
been encountered are summarized briefly in the following para-
graphs.
Closed loop operation has never been achieved; supernatant
from the reservoir is being discharged into the Ohio River. One
major reason is the greater requirement of fresh makeup water in
scrubbing operations (e.g., mist eliminator wash); another is the
quality of the supernatant resulting from the stabilization
process. The pH of the supernatant is approximately 9.0 to 9.2
instead of the design value of 8.0;. thus, less supernatant is
returned for slurrying and washing.
Core samplings of the stabilized waste material covering the
reservoir floor indicate different strata of material with vary-
ing physical characteristics. This resulted from not varying the
Calcilox feed rate with varying thickener underflow characteris-
tics, especially during the initial operation when stabilizer was
added on a manual control basis.
51
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Future Operations
Bruce Mansfield 3, a 917-MW (gross) coal-fired unit is
currently under construction alongside Units 1 and 2. Commercial
operation is scheduled for October 1980. The emission control
system for this unit, which is designed and supplied by Pullman
Kellogg, is different from those on Bruce Mansfield 1 and 2. In
many respects the design strategy for Bruce Mansfield 3 (compared
with that for Units 1 and 2) is representative of the change in
FGD design philosophy that has occurred over the past 5 years.
Most notably, electrostatic precipitators will provide particu-
late removal upstream of a lime-based, spray chamber FGD system.
Dry type fans will be located upstream of the spray towers. A
high degree of component redundancy will increase overall system
reliability. Redundant components include one spare fan, one
spare precipitator, one spare spray chamber, and one spare stage
per spray chamber. The electrostatic precipitators are designed
for 95 percent particulate removal, and the spray chambers will
collect additional i~ Articulate simultaneously with the sulfur
dioxide. The lower-efficiency electrostatic precipitators offer
substantial capital savings and permit a simpler, more efficient
design. Another important feature of this system involves the
chimney liner. Currently, the utility is planning to use an
Inconel 625 alloy liner in the 183-m (600-ft) high chimney. This
choice of an exotic alloy stems from the nearly disastrous re-
sults encountered in Bruce Mansfield 1 and 2. The flue gas
cleaning wastes produced by this system will be disposed of in
the existing waste disposal system. Table 19 summarizes the
Bruce Mansfield 3 emission control system.
52
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TABLE 19. SUMMARY OF MANSFIELD 3 EMISSION CONTROL SYSTEM
Unit capacity, MW (gross)
Design coal specifications
Heating value, kJ/kg (Btu/lb)
Sulfur content, percent
Ash content, percent
Particulate emission rate,
ng/J (lb/106 Btu)
Sulfur dioxide emission rate,
ng/J (lb/106 Btu)
Emission controls:
Particulate
Sulfur dioxide
Process
Supplier
Absorber type
Number of absorbers
Number of ESP's
Gas capacity, m /s
Pressure drop, kPa (in. H_0)
Gas reheat:
Type
AT, °C (°F)
Gas bypass capability
Commercial startup date
Total capital cost, $/kW
917
27,700 (11,900)
2.6 - 4.75
9.5 - 19.7
32 (0.075)
258 (0.6)
Electrostatic precipitators
and spray tower absorbers
Spray tower absorbers
Lime
Pullman Kellogg
Spray tower
5 (1 spare)
4 (1 spare)
1110 (2355)
7.0 (28.0)
Oil-fired
22 (40)
No
October 1980
243a
Cost includes ash handling system, electrostatic precipitators,
spray tower absorbers, fans, stack, one-third of the waste
disposal system, and all necessary auxilliary equipment.
53
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SECTION 5
FGD ECONOMICS
INTRODUCTION
The cost of FGD systems for the control of sulfur dioxide
emissions is an area of intense interest and substantial contro-
versy. For this reason, reported and adjusted economic data have
been incorporated into this report.
The rationale for including adjusted costs stems primarily
from the incomparability of the reported costs. Many of the
reported cost figures for operational FGD systems, both capital
and operating, are largely site-sensitive and cannot be compared
accurately because they involve different FGD battery limits and
the expenditures were made in different years. To allow for
these differences, ie cost data for these systems were analyzed,
and adjustments were made so that cost data for the sulfur
dioxide portion of the emission control system would be accurate
and comparable.
APPROACH
PEDCo forwarded Pennsylvania Power a cost form containing
all available cost information in the PEDCo files with the
request that Pennsylvania Power verify the data and fill in any
missing information. PEDCo then arranged for a followup visit
to assist in data acquisition and to ensure completeness and
reliability of the information.
The sole intent of this adjusting procedure was to establish
accurate costs of FGD systems on a common basis, not to critique
54
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the design or reasonableness of the costs reported by the utility.
Adjustments focused primarily on the following items:
0 Capital costs were adjusted to July 1, 1977, dollars
using the Chemical Engineering Index. Capital costs,
represented in dollars/kilowatt ($/kW), were expressed
in terms of gross megawatts
-------
DESCRIPTION OF COST ELEMENTS
Capital costs consist of direct costs, indirect costs, con-
tingency costs, and other capital costs. Direct costs include
the "bought-out" cost of the equipment, the cost of installation,
and the cost of site development. Indirect costs include interest
during construction, contractor's fees and expenses, engineering,
legal expenses, taxes, insurance, allowance for startup and
shakedown, and spares. Contingency costs include those costs
resulting from malfunctions, equipment alterations, and similar
unforeseen sources. Other capital costs include the nondepre-
ciable items of land and working capital.
Annual costs consist of direct costs, fixed costs, and over-
head costs. Direct costs include the cost of raw materials,
utilities, operating labor and supervision, and maintenance and
repairs. Fixed costs include depreciation, interim replacement,
insurance, taxes, and interest on borrowed capital. Overhead
costs include those of plant and payroll expenses.
RESULTS
The complete results of the capital and annual cost analysis
for Bruce Mansfield 1 and 2 are presented in Appendix C of this
report. The reported and adjusted capital cost data are sum-
marized in the following paragraphs.
Reported and Adjusted Capital and Annual Costs
The reported capital and annual variable costs provided by
the utility are summarized in Tables 20 and 21. The total re-
ported capital cost of both systems is $221,278,000, which is
equivalent to $120.65/kW (gross). The annual cost of both
systems is $47,730,357, which is equivalent to 13.18 mills/kWh.
The adjusted capital and annual costs are summarized in
Tables 22 and 23. The total adjusted capital cost of both
systems is $187,417,900, which is equivalent to $102.19/kW
(gross). The annual adjusted cost of both systems is $83,250,212,
which is equivalent to 8.96 mills/kWh.
56
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TABLE 20. MANSFIELD 1 AND 2 REPORTED CAPITAL COSTS
(dollars)
Equipment
Air quality control systems:
Scrubbers and absorbers
Induced-draft fans
Flue-gas reheaters
Concrete chimney with coated steel flues
Duct work
Barge, truck, and rail lime unloading facilities
Lime slaking and lime slurry pumping and
recycling equipment and facilities
Thickeners
Pumping facilities for transporting thickened
wastes to the waste disposal system
Waste holding pond and reslurry pumps and piping
facilities
Water primps and associated piping and filtration
equipment
Instrumentation and control
Electric power supply equipment and cabling
Piping and pipe rack systems
Pump houses and electrical houses
Control rooms
Fuel-oil supply and storage for flue-gas
reheaters
Steam supply for lime slaking
Protective linings in the duct work and other
related equipment
Associated sumps and sump pumps
Subtotal 137,607,000
Waste disposal system:
Barge, truck, and rail unloading facilities for
additive
Additive transporting, handling, and storage
facilities
Waste and additive mixing equipment
Pumping equipment for pumping treated wastes to
the disposal area
Pipelines between pumping station and disposal
area .
Equipment
Waste disposal and dam pumping equipment
for supernatant return to plant
Instrumentation and control
Electric power supply equipment and cabling
Pump house building
Control room
Associated sumps and sump pumps
Subtotal 83,761,000
Total, air quality and waste disposal 221,278,000
57
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TABLE 21. MANSFIELD 1 AND 2 REPORTED 1977 ANNUAL VARIABLE COSTS
(dollars)
Category
Supervision and engineering
Fuel:
Reheater oil $ 535,255
Calcilox $ 699,122
Other $1,104,292
Total
Steam operating expenses:
Lime $6,819,411
Other $1,423,470
Total
Miscellaneous operatia expenses
Maintenance supervision and engineering
Maintenance of structures
Maintenance of boiler plant
Total air quality control system and
waste disposal system
operating and maintenance expenses
106,282
2,338,669
8,242,881
212,856
155,717
59,994
3,643,536
14,759,935
58
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TABLE 22. MANSFIELD 1 AND 2 ADJUSTED CAPITAL COSTS
(dollars)
Adjustments
Total reported capital
Particulate control deduction
Partial stack deduction
Particulate control waste disposal
Conversion to July 1, 1977, dollars
Total adjusted capital
221,278,000
-27,338,185
- 2,500,000
-37,651,950
+33,630,035
187,417,900
59
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TABLE 23. MANSFIELD 1 AND 2 ADJUSTED 1977 ANNUAL COSTS
(dollars)
Category
Operation and maintenance
Power
Fixed charges
Total annual
38,296,450
13,467,555
31,486,207
83,250,212
60
-------
APPENDIX A
PLANT SURVEY FORM
A. Company and Plant Information
1. Company name: Pennsylvania Power Co.
2. Main office; New Castle, Pennsylvania
3. Plant name: Bruce Mansfield
4. Plant location: Shippingport, Pennsylvania
5. Responsible officer; W.F. Reeher
6. Plant manager; K.H. Workman
7. Plant contact; R. Forsythe
8. Position: Engineer
9. Telephone number; (412) 652-5531
10. Date information gathered: July 7, 1976, and Mar. 22, 1978
Participants in meeting Affiliation
Russ Forsythe Pennsylvania Power
Dale Billheimer Pennsylvania Power
T.O. Flora Pennsylvania Power
B.A. Laseke, Jr. PEDCo Environmental
R.W. Gerstle PEDCo Environmental
M. Melia PEDCo Environmental
a Bruce Mansfield is owned by the Central Area Power Coordination
Group (CAPCO), a consortium consisting of five Pennsylvania and
Ohio power companies: Pennsylvania Power, Ohio Edison, Duquesne
Light, Cleveland Electric Illuminating, and Toledo Edison.
Pennsylvania Power has design, construction, and operation
responsibility.
A-l
-------
B. Plant and Site Data
1. UTM coordinates:
2. Sea Level elevation; Plant grade elevation is 730 ft.
Normal Ohio River pool elevation is 664.5 ft.
3. Plant site plot plan (Yes, No): Yes
(include drawing or aerial overviews)
4. FGD system plan (yes, No); Yes
5. General description of plant environs: Sparsely populated,
highly industrialized section of the Ohio River.
6. Coal shipment mode: Primary coal transportation is via
-jumbo and standard river barges to the plant barge
harbor. Truck is a secondary means, employed only
during emergencies.
C. FGD Vendor/Designer Background (Units 1 and 2)
1. Process name: Lime
2. Developer/licensor name; Chemico
3. Address: One Penn Plaza, New York, New York 10001
4. Company offering process:
Company name; Chemico
Address; One Penn Plaza
A-2
-------
Location: New York. New York
Company contact: Mr. Feller
Position; Managerf Bruce Mansfield Project
Telephone number; (212) 239-5100
5. Architectural/engineers name; Gilbert/Commonwealth Assoc.
Address: 209 E. Washington Avenue
Location: Jackson, Michigan 49201
Company contact: Mr. W.E. Richards
Position: Project Engineer
Telephone number; (517) 788-3580
D. Boiler Data
1. Boiler: Bruce Mansfield 1 and 2
2. Boiler manufacturer: Foster Wheeler
3. Boiler service (base, standby, floating, peak):
Base load
4. Year boiler placed in service; 4/1/76 (Unit 1), 10/1/77 (Unit 2)
5. Total hours operation; 4655 (Unit 1)
6. Remaining life of unit; 3Q-yr service life
7. Boiler type; Pulverized coal-fired
8. Served by stack no.: One chimney for both units
9. Stack height: 290 m (950 ft)
10. Stack top inner diameter:
11. Unit ratings (MW): Bruce Mansfield 1 and 2
Gross unit rating: 1834 MW
Net unit rating without FGD; 1760 MW
A-3
-------
Net unit rating with FGD: 1650 MW
Name plate rating: 1834 MW
12. Unit heat rate:
Heat rate without FGD:
Heat rate with FGD:
13. Boiler capacity factor, (1977): 40.09% (station)
14. Fuel type (coal or oil); Coal
15. Flue gas flow: 1570 m3/s (3,350,000 acfm)
Maximum: 1570 m3/s (3,350,000 acfm)
Temperature: 140°C (285°F)
16. Total excess air: 18-20%
17. Boiler efficiency: 92.5%
E. Coal Data (units 1 and 2)
1. Coal supplier: (Major supplier)
Name: North African Coal Co..
Location: Belmont County, Ohio
Mine location:
County, State: Belmont. Ohio
Seam:
2. Gross heating value; 26,700 kJ/kg (11,500 Btu/lb)
3. Ash (dry basis): 12.5%
4. Sulfur -(dry basis) ; 3.0%
5. Total moisture: 7.0%
6. Chloride: Not available
7. Ash composition (Se;e Table Al) Not available
A-4
-------
Table A-l
Constituent Percent weight
Silica, SiO2
Alumina, A120_
Titania, TiO~
Ferric oxide, Fe2°3
Calcium oxide, CaO
Magnesium oxide, MgO
Sodium oxide, Na20
Potassium oxide, K_0
Phosphorous pentoxide, P2°5
Sulfur trioxide, SO3
Other
Undetermined
F. Atmospheric Emission Regulations (Units 1 and 2)
1. Applicable particulate emission regulation
a) Current requirement; 43 ng/J (0.1 Ib. per 1Q6 Btu heat input)
AQCR priority classification:
Regulation and section No.: Pittsburgh Interstate
AQCR, Chap. 123.11
b) Future requirement {Date: ):
Regulation and section No.:
2. Applicable S02 emission, regulation
a) Current requirement; 263 ng/J (0.6 lb/10 Btu heat input)
AQCR Priority Classification:
Regulation and section No.: Pittsburgh Interstate
AQCR, Chap. 123.21,
b) Future requirement {Date: )
A-5
-------
Regulation and section No.:
G. Chemical Additives: (Includes all reagent additives -
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)
1. Trade name: Thiosorbic lime
Principal ingredient: Calcium oxide and magnesium oxide (2-6%)
Function: Absorbent
Source/manufacturer: Dravo Lime Co.
Quantity employed: 227 Ma/ .yr per unit (250.000/vr per unit)
Point of addition; Scrubber and absorber recircuLation
Trade name: Calcilox
Principal ingredient: Confidential
Function: Sludge stabilization agent
Source/manufacturer: Dravo Lime Co.
Quantity employed; 23.5 Mg/h (26 tons/h) (projected full
capacity, both units)
Point of addition; sludge treatment facility
3. Trade name:
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed; .
Point of addition:
Trade name: Not applicable
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed;:
A-6
-------
Point of addition:
5. Trade name: Not applicable
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
H. Equipment Specifications (Units 1 and 2)
1. Electrostatic precipitator(s)
Number:
Manufacturer:
Particulate removal efficiency:
Outlet temperature:
Pressure drop:
2. Mechanical collector (s) Not applicable
Number:
Type: _
Size:
Manufacturer:
Particulate removal efficiency:
Pressure drop: _^
3. Particulate scrubber(s)
Number: 12, 6 per unit
Type : Adjustable-throat vertical venturi
Manufacturer: Chemico
Dimensions; 10.8 m d) x 15.8 m ht. (35.5 ft x 52.0 ft.ht)
A-7
-------
Material, shell: Carbon steel
Material, shell lining: Polyester flake glass
Material, internals: 316 ss (Plumb bob and throat area)
No. of modules: 1 per train, 6 per unit
No. of stages: Two
Nozzle type: Not available
Nozzle size; Not available
No. of nozzles; Four primary spray heads per module
Boiler load; 100% for all 6 modules/unit
Scrubber gas flow; 259 m3/s @ 140°C (558,300 acfm @ 285°F)
Liquid recirculation rate:1390 liters/s (22,000 gpm)
Modulation: 50%
L/G ratio; 5.3 liters/in3 (40 aal/103 acf)
Design: 167 kPa (67 in. H20)
Scrubber pressure drop;Actual: 6 kPa (23 in. H?O)
Modulation:
Superficial gas velocity; 61 m/s @ 14Q°C (200 ft/s @ 285 °F)
Particulate removal efficiency; 99.8% (design)
Inlet loading: 17.7 g/m (7.75 gr/scf) (dry, maximum)
Outlet loading: 0.0354 g/m (0.0155 gr/scf) (dry, maximum)
SO2 removal efficiency.:. 92.1% (design)
Inlet concentration: 3,090 ppm (maximum design)
Outlet concentration; 930 ppm (maximum design)
SO2 absorber(s)
Number: 12, 6 per unit
Type: Fixed-throat vertical venturi
Manufacturer: Chemico
A-8
-------
Dimensions: 10.4 m 4> x 15.7 m ht. (34 ft 4> x 51.5 ft ht)
Material, shell: _..__Car_bon_ steel
Material, shell lining: Polyester flake glass
Material, internals:316 SS (center cone and throat area)
No. of modules: 1 per train, 6 per unit
No. of stages: TWO
Packing type: None
Packing thickness/stage: Not applicable
Nozzle type: Not available
Nozzle size: Not available
No. of nozzles: Five primary spray heads per module
Boiler load;100% for all 6 modules/unit
Absorber gas flow;201 m3/s @ 52°C (426,000 acfm @ 127°F)
Liquid recirculation rate; 1,220 liters/s (19,400 gpm)
Modulation: 50%
L/G ratio; 6.1 liter/ra3 (45 gal/103 acf)
Absorber pressure drop; 2 kPa (8 in. H^O)
Modulation: None
Superficial gas velocity: 30 m/s (100 ft/s)
Particulate removal efficiency; 99.8% (scrubber & absorber design)
Inlet loading:
Outlet loading: Q.Q354 g/m (0.0155 qr/scf)(dry, maximum)
S02 removal efficiency; 92.1% (design)
Inlet concentration: 930 PPm (maximum design)
Outlet concentration: 240 ppm (maximum design)
A-9
-------
5. Clear water tray(s) None
Number:
Type:
Materials of construction:
L/G ratio:
Source of water:
6. Mist eliminator(s)
Number; 24, 1 per module
Type: Chevron
Materials of construction: FRP
Manufacturer: chemico
Configuration (horizontal/vertical) : Horizontal
Distance between scrubber bed and mist eliminator:
Not available
Mist eliminator depth; Not available
Vane spacing: 7.6 cm (3.0 in.)
Vane angles:
Type and location of wash system: Over spray/under spray;
intermittent overspray (once/shift) & continuous underspray
Superficial gas velocity: 3.1 m/s @ 52°C (10.0 ft/s @ 127°F)
Pressure drop; 1.2 kPa (0.3 in. IUO)
Comments; i-stage. 4-pass. Z-shape, 90-dea sharp-angle bend
n; 2nd vertical stage was installed and tested
i -H-pnhly
7. Reheater(s) : 4 reheat chambers, 2 per unit
Type (check appropriate category):
A-10
-------
D in-line Q
Q indirect hot air Q
[x] direct combustion Q
D bypass
Gas conditions for reheat:
Flow rate: 201 m3/s (426,000 acf)
exit gas recirculation
waste heat recovery
other
Temperature: 51°C (125°F)
SO- concentration: 240 ppm
Heating medium: Combustion products
Combustion fuel; No. 2 fuel oil
Percent of gas bypassed for reheat; None
Temperature boost (AT): 22°C (51 to 73) r40°F Q24 to 164)]
Energy required:
Comments;Three burners/reheat chamber. Each chamber is rato1
at (28 x IP** Btu/h, vortex type, mechanical atomization
injection. Total reheat fuel consumption per boiler is
1200 gph.
8. Fan(s)
Total number
Manufacturer
Service
Specifications:
Type
Rating, kW (hp) and rpra
Pressure drop:
Design, kPa (in. HjO)
Maximum continuous
Motor, kV , 3
Capacity, m /s (ft /min)
Gas temperature, °C (°F)
Gas density, kg/m3
Materials of construction:
Housing
Scrolls
Blades
Shaft
12
Green Fan Company
Wet
Radial-tip, inlet
damper control
6700 (9000) and 1300
19 (75)
16 (63)
13.2
263 (558)
48 (118)
0.913 (0.057)
Rubber-lined carbon steel
Inconel 625
Inconel 625
Carbon steel clad with
Carpenter 20
A-ll
-------
9. Tank(s) 24 internal recirculation tanks, one per module
Materials of construction: Carbon steel, flake glass lining
Function:Collection of spent solution/lime makeup addition
Configuration/dimensions: Contained in venturi modules
Capacity; 136fOOO liters (36,100 gal)
Retention times: 1.5 min
Covered (yes/no); Yes (internal)
Agitator description; None
10. Recirculation/slurry pump(s) (See Table A-2 on following
page.)
Type:
Manufacturer:
Materials of construction:
Head:
Capacity:
11. Thickener (s)/clarifier(s)
Number: TVTO, one per unit
Type: Rake drive
Manufacturer: Hoppers Co.
Materials of construction: Carbon steel and concrete
Configuration: Cylindrical
Diameter; 61 m (200 ft)
Depth: 3.7 m (12 ft)
Rake speed; Variable
12. Vacuum filter (s) Not applicable
A-12
-------
TABLE A-2. RECIRCULATION/SLURRY PUMPS
Number
24
24
4
4
4
4
Service
Scrubber
recycle
Absorber
recycle
Thickener
under f low
Thickener
transfer
Lime slurry
transfer
recycle
Manufacturer
Allen-Shermdn-Hoff
Al 1 en - Sherman- Ho f f
Joy/Denver
Goulds
Joy/Denver
Typo
Contr i f u.ul ,
si nql e-staqe.
V-belt
Cunt r i i uqj 1 ,
sin^l e-ata
-------
Number:
Type:
Manufacturer:
Materials of construction:
Belt cloth material:
Design capacity:__
Filter area:
13. Centrifuge (s) Not applicable
Number: None
Type:
Manufacturer:
Materials of construction:
Size/dimensions:
Capacity:
14.. Water balance system:
Number: 4 onsite storage ponds.
Description;Two low dissolved solids (LDS) ponds and two
high dissolved solids (HDS) ponds •
Capacity: 3R million liters (10 million gal> per.pond
Service: The' LDS ponds receive raw river water,
miscellaneous sump runoffs, coal storage area drainage;
LDS water is used for bottom ash transport, I.D. fan sprays,
scaling, moling, and slurry pipe.flushing. The HDS ponds,
receive acid, boiler cleaning wastes, seal-water return, sump
discharges, and emergency thickener underflow; HDS pond
supernatant is used as makeup water ^or the scrubbing
system. ^^
15. Final disposal site(s): Little Blue Run ravine landfill
A-14
-------
Number: One
Description; Earth and rgckfill embarkment area
Area : 5.7 km2 (1400 acres)
Depth : Maximum dam height is 128 m (420 ft)
Location: Approximately 11.3 km (7 mi) from plant site
Transportation mode ; 4 underground transport pipes
Typical operating schedule: Continuous, semiautomatic
l-insis; maximum fgpd caacity is 302 m /S (4800
of fixated slurry to the Little Blue Run
16. Raw materials production
Type : j
Number:Three bulk storage silos (30-day storage); Two
2-day silos per unit
Manufacturer; Dorr-Oliver
Capacity: 20 Mg/h (22 tons/h) maximum feed rate; 63 liters/s
(1000 gpm) maximum slurry output; two 14.9-kW (20-hp)
slaking mixers
I. Equipment Operation, Maintenance, and Overhaul Schedule
1. Scrubber(s)
Design life; 30 Vr
Elapsed operation time:
Cleanout method:
Cleanout frequency; Maintenance performed as needed
Cleanout. duration:
Other preventive maintenance procedures:
2. Absorber (s)
A-15
-------
Design life: 30
Elapsed operation time:
Cleanout method:
Cleanout frequency: Maintenance performed as needed
Cleanout duration:
Other preventive maintenance procedures:
3. Reheater (s)
Design life: 30 yr
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
4. Scrubber fan(s)
Design life: 30 yr
Elapsed operation time; Approximately 33, OOP h for all
six trains
Cleanout method:
Cleanout frequency; Maintenance performed as needed
Cleanout duration:
Other preventive maintenance procedures:
5. Mist eliminator (s)
Design life: 30 yr
Elapsed operation time:
A-16
-------
Cleanout method: Washwater sprays
Cleanout frequency: Continuous/intermittent
Cleanout duration: intermittent overspray once/shift
Other preventive maintenance procedures: clean out
when AP exceeds 1.2 kPa (0.3 in. H.?0)
6. Pump(s) Not determined
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
7. Vacuum filter(s)/centrifuge(s) Not applicable
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:
A-17
-------
Cleanout procedures:
J. Cost Data (see Appendix C)
1. Total installed capital cost:
2. Annualized operating cost:
3. Cost analysis
4. Unit costs
a. Electricity: •
b. Water:
c. Steam:
d. Fuel (reheating/FGD process):
e. Fixation cost:
f. Raw material:
g. Labor:
5. Comments
A-18
-------
K. Instrumentation See text of report, Section 3, Process
Control subsection
A brief description of the control mechanism or method of
measurement for each of the following process parameters:
0 Reagent addition:
e Liquor solids content:
Liquor dissolved solids content:
0 Liquor ion concentrations
Chloride:
Calcium:
Magnesium:
Sodium:
Sulfite:
Sulfate:
Carbonate:
Other (specify):
A-19
-------
Liquor alkalinity:
Liquor pH:
0 Liquor flow:
Pollutant (SO., particulate, NO ) concentration in
fc *»
flue gas:
0 Gas flow:
0 Waste water
Waste solids:
Provide a diagram or drawing of the scrubber/absorber train
that illustrates \e function and location of the components
of the scrubber/absorber control system.
Remarks; see text of report concerning specific instrumentation
information and the process control scenario-
L. Discussion of. Major Problem Areas:
1. Corrosion: See the main body of the report concerning
problem areas.
A-20
-------
2. Erosion; ,gee tne majn body of the report concerning
prnhlom
3. Scaling: See the main body of the report concerning
problem areas.
4. Plugging; See the main body of the report concerning
problem areas.
5. Design problems: See the main body of the report
concerning problem areas.
6. Waste water/solids -disposal; See the main body of the
report concerning problem areas.
A-21
-------
7. Mechanical problems: See the main body of the report
concerning problem areas.
M. General comments:
A-22
-------
APPENDIX B
PLANT PHOTOGRAPHS
Photo No. 1. View of Sherburne County generating station.
Featured are the boiler and turbine house, stack, mechanical
draft cooling towers, and fly ash pond.
B-l
-------
Photo No. 2. Upward view of stack as seen from its base,
B-2
-------
Photo No. 3. View of one of the rod sections u
in the ventur ubber.
Photo No, 4. Close-up view of the scissor jacking arrangement
used to control the oosition of the rod decks.
B-3
-------
Photo No. 5. Vlev; of a mn • i insidr: a nodule.
Featured are the overflow pots sui e glass sphere
packing (marbles).
Photo No. 6.
pots.
>f marble-1 aid overflow
-------
Photo No. 7. View of top section of second stage mist
eliminator. Top right-hand portion of photo features the
reheater inlet of the in-line, hot-water reheater.
-------
Photo No. 8. Side view of reheat tube bundles situated in
top portion of scrubber module.
B-6
-------
Photo No. 9. View of original duplex strainer situated in
the slurry spray discharge line.
Photo No. 10. View of one of the two nain thickeners used
for concentratinq the solids of the waste stream prior to
disposal.
-------
Photo No. 11. Side view of thickener water surface featuring
walkway and center well.
B-8
-------
Photo No. 12. Sherburne County generating station as viewed
from the fly ash pond. In the foreground are flue gas cleaning
wastes entering the fly ash pond.
B-9
-------
Photo No. 13. View of holding and recycle basins used for plant
water distribution, recycling, monitoring, and discharge.
B-10
-------
APPENDIX C
OPERATIONAL FGD SYSTEM COST DATA
Date Junp 26. 1Q7JL
Utility Name Pennsylvania Power Company
Address 1 East Washington Street, New Castle, Pa.
Name of Contact - Title Russ c- Forsythe - Engineer
Phone No. (412 )/652 ~ 5531
Station Bruce Mansfield
Unit Identification No. 1 and 2
Unit Size. 1834 gross MW. 6.7 MM acfm (a 285
Net MW w/o FGD 1760
Net MW w/FGD 1650
FGD System Size. 1834 MW
Foot- 6.7 MM acfm @ 285 °F
note
No. COST BREAKDOWN
I. CAPITAL COSTS OF FGD SYSTEM INSTALLATION
A. Year(s) to which estimates below apply; 1973-1977
B. Year of greatest capital expenditure: 1975
C. Month and year estimates made: April 1978
D. Date FGD contract awarded: October 1973
Date FGD construction began: April 1973
Dec. 1975 (Unit 1)
Date of initial FGD system start-up: Jul. 1977 (Unit 2)
June 1, 1976 (Unit 1)
Date of commercial FGD system start-up: Oct. 1, 1977 (Unit 2)
E. Expected FGD system life: 30 years .
F. Cost adjustment made by: B. A. Laseke. jr.
G. Cost adjustment checked by: B. A. Laseke, Jr.
C-l
-------
Foot-
note
No.
H.
Direct capital cost
1. Particulate collection
Equipment cost
Installation cost
Total cost
2. Facilities for
reagent handling
and preparation
Equipment cost
Installation cost
Total cost
3. SO2 absorber and re-
lated equipment
Equipment cost
Installation cosr
Total cost
4. Fans installed for FGD
Equipment cost
Installation cost
Total cost
5. Reheat
Equipment cost
Installation cost
Total cost
Included
in reported
total cost Capital
Yes No cost, $
X
X
X
Included
item 3
in
n.700.OOP
31.800.000
42.500.000
74.300.000
X
X
X
Included
item 3
in
X
X
X
Included
i tpm "3
in
02
-------
Foot-
note
No.
7.
Included
in reported
total cost
Yes No
Capital
cost, $
Solids disposal: site
Equipment cost
Installation cost
Total cost
40,000,000
Location of interim and final disposal site(s) 6.5 to , „
7 miles from the plant site.
When was site(s) acquired or year of expected acquisition
1973 and 1974
Cost when acquired or at time of expected acquisition
$2.700,000
Life span 30 yr .for all three Mansfield units. .
Required site treatment (lining, surface preparation,
420-ft high hydraulic dam
etc.) ._ —.
Composition of disposed material (flyashl£_%, bottom
ash_Q_%, SC-2 waste_L5%, unreacted reagent %, fixative 2.5%
water67.5%) .
Solids disposal:
transport system
Contract cost
Equipment cost
Installation cost
Total cost
34.858.465
C-3
-------
Foot-
note
No.
8
10,
11,
12,
Solids disposal:
treatment system
Equipment cost
Installation cost
Total cost
By-product recovery:
regenerative system
Equipment cost
Installation cost
Total cost
By-product recovery
plant
Equipment cost
Installation cost
Total cost
Instrumentation and
controls
Equipment cost
Installation cost
Total cost
Utilities and services
Equipment cost
Installation cost
Total cost
Included
in reported
total cost Capital
Yes No cost, $
8,812,530
N/A
N/A
Included in
items 3 and 7
N/A - Not Applicable.
C-4
-------
Foot-
note
NO.
13
10 !l!
i /
Stack requirements due
to FGD
Equipment cost
Installation cost
Total cost
Additional system
ir.odif ications
Equipment cost
Installation cost
Total cost
Other
Equipment cost
Installation cost
Total cost
Other
Equipment cost
Installation cost
Total cost
Other
Equipment cost
Installation cost
Total cost
Included
in reported
total cost
Yes No
X
X
X
X
X
X
X
X
X
cost, S
C-5
-------
Foot-
note
No.
11
12
18. Otu~-
Equipment cost
Installation cost
Total cost
Other
Equipment cost
Installation cost
Total cost
20. Other
Equipment cost
Installation cost
Total cost
Direct cost si ' otal
Equipment cost
Installation cost
Total cost
I. Indirect Costs
1. Engineering
In-house
A-E
2. Construction expenses
In-house
Contractor
Inc J udeo
in reported
total cost
Yes No
n m
I
y I I
LJLJ i-
Ci
Capital
cost, $
221,278,000
C-6
-------
Foot-
note
No.
Included
in reported
14
8
9.
10.
11.
3
4
5,
Contractor fees
Subcontractor fees
Allowance for funds
used during construc-
' tion
Allowance for start-up
Contingency
Escalation
Spares, offsite, taxes,
freight, etc.
Research and develop-
ment
Other
Indirect cost subtotal
J. Total Direct and Indirect Costs $??1 ,
:ota]
Yes
X
X
X
X
X
X
X
X
$221
«
cost
No
X
X
>7fi,n
Capital
cost, $
i n\, i uutu i n
direct cost
nn
$AW (gross) 120.fi5
II. ANNUAL OPERATING COST
See Attachment A: breakdown of all operation
and maintenance costs for B. Mansfield Included
1 and 2 scrubbing systems
A. Variable Costs
Particulate removal
a. Operating
(1) Labor
(2) Supervision
b. Electricity
c. Other utilities
(1) Water
in reported
total cost
Yes No
Cost, $
C-7
-------
Foot-
15
c. Maintenance
Labor
(2; Supplies
Sub-c^al partioulate
SO- absorber
a. Oper CTL.LI
(1: Labor
(2: Supervision
b. Electricity ccnsumptio:
(1"' Feed Dreoaratior.
(2'i Reheat
(3; Fans
(4) SO2 absorber
(5)•Other
c. Fuel
(1) Reheat
(2) Other
d. Other Utilities
(1) Water
(2) Other
e. Maintenance
(1) Labor
(2) Supplies
Included
in reported
total ccst
Yes No Cos-
i I !
i I [ j
L
mi
X
X
JLI l_.
L_ Du
LJL
x
Included 1r tot;
vsnable cost
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Foot-
note
No.
Included
in reported
total cost
Yes No
Subtotal absorber
Raw materials
a. Lime
b. Limestone
c. Fuel for process needs
d. Sodiuir. hydroxide
e. Magnesium oxide
f. Sodium carbonate
c. Flocculant
h. Other
Subtotal raw materials
Solid and liquid waste disposal
a. Operating
(1) Labor
(2) Supervision
b. Electricity consumption
c. Other utilities
(1) Water
(2) Other
d. Maintenance
(1) Labor
(2) Supplies
e. Other
f. Credit for by-product recovery
X
X
X
x
X
X
x
X
X
Cost, $
Included in total
variable cost
Included in total
variable cost
C-9
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Foot-
note
No.
c. Wa ' jwater treatment
Subtotal disposal
5. Overhead
a. Plant
b. Administrative
Subtotal
Total Variable Costs
16 | B. Fixed Charges
I
jl. Interest
i
| 2. Annual depreciation
3. Insurance
4. Taxes
5. Other, specify
Total Fixed Costs
C. Total Variable and Fixed Costs
mills/kwh(net)
Included
in reported
total cost
Yes No
Cost, $
X
X
X
X
X
X
X
X
X
X
X
51,
9;
X
Included in total
variable cost
Included in total
variable cost
14,759,935
17,923,518
6, 859, bib
2,212,780
10,178,788
37,174,704
54,639
14.34
C-10
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FOOTNOTES
Comments
Each unit is equipped with 6 parallel 2-stage
scrubbing trains for the wet phase removal of parti-
cipate and S02- Each train includes a variable-
throat venturi for participate and S0£ removal and a
fixed-throat venturi for primary SQ2 removal. The
cost of particulate control is included in the cost
of S02-removal equipment.
2 2 Included is the additional reagent preparation equip-
ment. Charges are not included in the original
contract with Chemico.
3 2 The cost of the contract for engineering and procure-
ment includes all 24 scrubbing vessels and related
equipment, including reagent handling, equalling
approximately $3,100,000 per module.
4 2 Twelve wet fans are provided for both units. Each
fan is a 9000-hp unit capable of overcoming a maximum
gas side pressure drop of 75 in. F^O (62 in. F^O on a
maximum continuous basis). The cost of the fans is
included in the scrubbing equipment and related com-
ponents (Item 3).
5 2 Four direct fuel-oil-fired reheat chambers boost the
gas discharge temperature 40°F. The cost of the
reheater is included in the scrubbing, and related
equipment (Item 3).,
6 3 The Little Blue Run ravine waste disposal area is
located approximately seven miles from the plant. A
manmade dam impounds a disposal area approximately
1460 acres in area.
7 3 169,500 lineal feet of 12-inch and 8-inch piping, 41
pumps, and supernatant return equipment are provided
to transport 18,000 tons/day of sludge to the waste
disposal area.
8 4 Dravo's Calcilox/Synearth stabilization process is
used. All associated transportation, mixing, stor-
age, and handling equipment is included.
9 5 950-ft. concrete-shell chimney contains four steel
(Corten) sleeves, two for each unit. Flake-qlass
coating (Heil Rigiflake) is included. (NOTE: the
cost of repair to failed coating and reapplication of
new materials is not included.)
C-ll
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FOOTNOTES (continued)
Line Page Comments
10 5 Included are the ductwork, thickeners, waste holding
ponds, piping and pipe racks, pump houses, electrical
houses, control rooms, fuel-oil storage and supply,
steam supply, protective liners, sumps, and sump
pumps.
11 6 The total direct capital cost includes $137,607,000
for air quality control and $83,671,000 for waste
solids disposal. These values also include all the
indirect capital costs.
12 6 Gilbert/Commonwealth Associates.
13 7 Eight percent interest rate on borrowed capital
during construction.
14 7 Eight percent/year for purchased and quoted material;
12 percent/year for estimated material; 5.5 percent/
year on labor through June 1, 1976; 8 percent/year on
labor after June 1, 1976.
15 8 No. 2 fuel oil used for direct reheat systems (140,000
Btu/qal at $2.282/106 Btu).
16 10 The fixed charges provided were computed using the
following rates: interest - 8.1 percent; annual
depreciation - 3.1 percent; insurance - 1.0 percent;
taxes - 4.6 percent; total fixed charge rate - 16.8
percent.
17 10 The station capacity factor for 1977, reported by the
utility, was 40.09 percent, equaling 3.62099 x 109
kWh. The station capacity factor was based on one
complete year of service from Unit 1 and approximately
one-half year from Unit 2. (Initial startup commenced
on July 1, 1977, and commercial startup commenced on
October 1, 1977.)
C-12
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Attachment A to Appendix C
Bruce Mansfield Plant
Units 1 and 2
Air Quality Control System
Operation and Maintenance Costs for 1977
Supervision and engineering S 106,282
Fuel:
Reheater oil $ 535,255
Calcilox $ 699,122
Other $1,104,292
Total $ 2,338,669
Steam operating expenses
Lime $6,819,411
Other $1,423,470
Total $ 8,242,881
Miscellaneous operating expenses S 212,856
Maintenance supervision and engineering $ 155,717
Maintenance of structures $ 59,994
Maintenance of boiler plant $ 3,643,536
Total air quality control system and
waste disposal system
operation and maintenance expenses $14,759,935
(Total net plant generation in 1977, at a capacity factor of 40.09 percent,
was 3,620,990 MWh.)
Total operating and maintenance costs for
Units 1 and 2 $62,911,541
Operating and maintenance costs in 1977, mills/net kWh:
Total operating and maintenance 17.37
Air quality control system and waste
disposal system oDeratinq and
maintenance 4.08
Estimated 1977 station power costs,
excluding air quality control system
and waste disposal system 1.89
C-13
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Attachment B to Appendix C
COST ADJUSTMENTS
1. Of the estimated $213,200,000, $74,300,000 was allocated for the
scrubber modules, reheaters, and fans. Of this total, $2,057,750
is assessed to the reheaters, leaving $72,242,430 for the modules
(24) and fans (12). The design premises of the scrubbing system call
for virtually all the particulate and 70 percent of the inlet S02 to be
removed in the first-stage venturi. The second-stage venturi removes
the remaining S02 (22.1 percent design efficienies). Thus, 1-(70/92.1)
or 24 percent of $72,242,430, or $27,338,185, is subtracted for parti-
culate control.
2. The entire 950-ft concrete-shell chimney, including four flake-glass-coated
carbon steel flues, was included in the scrubber capital costs. Because
a 600-ft stack was originally proposed and rejected, only a portion of
the top 350 ft can accurately be assessed against the scrubber. Thus,
c.2.^ ni 11 ion has been subtracted.
3. The total direct and indirect costs assessed against the air quality
control systems are as follows:
$137,607,000
- 17,338,185
- 2,500,000
$117,768,815 = $64.214/kW (gross)
4. With regard to the waste disposal system, approximately 45 percent of the
wastes disposed is collected fly ash (1 x 10° tons/year of fly ash; 1.2 x
106 tons/year of S02 waste). Therefore, 45 percent of the capital costs
assessed against the waste disposal system ($83,671,000), or ($37,651,950),
has been subtracted.
$ 83,671,000
- 37,651,950
$ 46,019,050 = $25.092/kW (gross)
5. Conversion to 1977 dollars is based upon the following assumptions:
a) Construction of the station commenced on 9/10/69.
b) Engineering design commenced in late 1969.
c) Plant construction began in May 1971.
d) Origninal AQCS plans (ESP and high stack) were drawn un in 1970.
C-14
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Attachment B to Appendix C (continued)
a) An intensive investigation of FGD processes was initiated in November
1970.
f) Plans for a full-scale FGD system were formulated in July 1972.
g) The plans were approved in October 1972.
h) Chemico was authorized to proceed with design engineering and fabri-
cation in January 1973.
i) Pilot plant testing was conducted between February and May 1973, and
August and September 1973.
j) B. Mansfield 1 started up initially December 11, 1975. Commercial
operation commenced June 1, 1976.
k) B. Mansfield 2 started up on July 1, 1977, and went commercial
October 1, 1977.
0 One percent of capital expenditures for the entire AQCS and sludge
disposal system occurred before January 1, 1973, or 0.5 percent in
1971 and 0.5 percent in 1972.
$1,637,880 x 50% = $818,940 x (1.488/0.964) = $1,264,090
51,637,880 x 50% = $818,940 x (1.488) = $1,218,580
0 Ten percent of the capital expenditures was made during the course
of 1973. This figure is derived by assuming that half of the
average monthly expenditures over the duration of the entire project
was made during this period because the pilot plant program needed
to verify process chemistry and process design.
516,774,135 x (1.488/1.05) = $23,771,350
0 Approximately 23 percent of the expenditures was made each year
in 1974, 1975, and 1976, and 19 percent in 1977. This translates
into the following actual costs:
$37,924,135 x (1.488/1.206) = $ 46,791,165
$37,924,135 x (1.488/1.329) = $ 42,461,335
$37,924,135 x (1.488/1.4) = $ 40,307,935
$31,603,445 x 1.00 - $ 31,603,445
$161,163,880 (1977 dollars)
Total adjusted capital: $187,417,900 (1977 dollars)
$102.19/kW (gross)
C-15
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Attachment B to Appendix C (continued)
6. Annual! zed charges: Assume 65 percent station capacity factor
(9,395,100,000 kWh).
a) Operation and maintenance costs:
$14,759,935 X (3*520*990 = $38>296>45° = 4-0?6 mills/kWh
b) Power costs:
= $13,467,555 = 1.433 Mills/kWh
c) Fixed charges: Using '16.8 percent, a total fixed charge of
$31,486,207 on a fixed investment of $187,417,900 is calculated,
which equals 3.35 mills/kWh.
:) Total annual charges: $83,250,212 = 8.96 mills/kWh
7. S.immary of adjusted costs:
Capital cost: $187,417,900 $102.19/KW (gross)
Annual cost: '33,250,212 8.96 mills/kWh (net)
C-16
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TECHNICAL REPORT DATA
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