&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research EPA-600/7-79-199c
Laboratory August 1979
Research Triangle Park NC 27711
Survey of Flue Gas
Desulfurization Systems:
Cane Run Station,
Louisville Gas and
Electric 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-
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The nine series are:
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3. Ecological Research
4. Environmental Monitoring
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This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
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This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-79-199c
August 1979
Survey of Flue Gas
Desulfurization Systems:
Cane Run Station,
Louisville Gas and Electric Co.
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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ABSTRACT
The report gives results of a survey of operational flue gas desulfur-
ization (FGD) systems on coal-fired utility boilers in the U.S. The FGD
systems installed on Units 4,5, and 6 at the Cane Run Station are described
in terms of design and performance. The Cane Run No. 4 FGD system is a two-
nodule (packed tower) carbide lime scrubber, retrofitted on a 178 MW (net)
coal-fired boiler. The system, supplied by American Air Filter, commenced
initial operation in August 1976. The Cane Run No. 5 FGD system is a two-
module (spray tower) carbide lime scrubber, retrofitted on a 183 MW (net)
coal-fired boiler. The system, supplied by Combustion Engineering, commenced
initial operation in December 1977. The Cane Run Unit 6 FGD system is a two-
module (tray tower) dual alkali (sodium carbonate/lime) scrubber, retrofitted
on a 278 MW (net) coal-fired boiler. The system, supplied by A.D. Little/
Combustion Equipment Associates, commenced initial operation in December 1978.
ii
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CONTENTS
List of Figures iii
List of Tables iv
Acknowledgment vi
Summary vii
1. Introduction 1
2. Facility Description 2
3. Flue Gas Desulfurization System 7
Background Information 7
Process Description 23
Process Design 32
Process Chemistry: Principal Reactions 50
4. Flue Gas Desulfurization System Performance 54
Operating History and Performance 54
Problems and Solutions 57
Removal Efficiency 63
Future Operations 69
5. FGD Economics 77
Introduction 77
Approach 77
Description of Cost Elements 78
Results 79
Appendix A. Plant Survey Form A-l
Appendix B. Plant Survey Form B-l
Appendix C. Plant Survey Form C-l
Appendix D. Operational FGD System Cost Data Form D-l
Appendix E. Operational FGD System Cost Data Form E-l
Appendix F. Plant Photographs F~l
iii
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FIGURES
Number Page
1 Simplified Process Flow Diagram of Paddy's
Run 6 FGD System 12
2 Simplified Process Flow Diagram of Can Run 4
FGD System 24
3 Simplified Process Flow Diagram of Can Run 5
FGD System 29
4 Cane Run 4 Mobile Bed Contactor Absorber and
Sphere Path Jb
5 Cane Run 5 Mist Eliminator Design 39
6 Arrangement of the Cane Run 5 Reaction Tank 45
7 Cane Run 5 In-Tank Strainer Arrangement 46
8 Simplified Process Flow Diagram of Cane Run 6
FGD System 71
iv
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TABLES
Number Page
1 Facility and FGD System Data for Cane Run 4 xii
2 Facility and FGD System Data for Cane Run 5 xiii
3 Facility and FGD System Data for Cane Run 6 xiv
4 Summary of the Cane Run Power-Generating Units 3
5 Design, Operation, and Emission Data: Cane
Run 4, 5, and 6 6
6 Summary of Kreisinger Test Programs: 1971 to
1972 9
7 Summary of Data: Scrubber Modules 13
8 Summary of Data: Mist Eliminators 14
9 Summary of Data: Reheaters 15
10 Summary of Data: Tanks 16
11 Summary of Data: Thickener 17
12 Summary of Data: Vacuum Filters 17
13 Summary of Data: Major Pumps 18
14 Specifications of Cane Run Performance Coal 34
15 Design Criteria of Cane Run FGD Systems 35
16 Design Parameters and Operating Conditions of
Cane Run Scrubber Modules 37
17 Design Parameters and Operating Conditions of
Cane Run Mist Eliminators 40
18 Design Parameters and Operating Conditions of
Cane Run Reheaters 41
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TABLE (continued)
Number Page
19 Design Parameters and Operating Conditions of
Cane Run 4 Pumps 42
20 Design Parameters and Operating Conditions of
Cane Run 5 Pumps 43
21 Design Parameters and Operating Conditions of
Cane Run Reaction Tanks 47
22 Design Parameters and Operating Conditions of
Cane Run Thickeners 48
23 Chemical Composition of Cane Run Carbide Lime 51
24 Cane Run 4 FGD System Performance Summary:
August 1976 to September 1979 56
25 Cane Run 5 FGD System Performance Summary:
December 1977 to September 1979 58
26 Summary of Cane Run 4 Sulfur Dioxide Continuous
Monitoring Data: July 21 to December 23, 1977 66
27 Summary of Cane Run 5 Particulate Emission
Tests: May 19 to June 7, 1978 67
28 Summary of Cane Run 5 Sulfur Dioxide Emission
Tests: July 10 to 14, 1978 68
29 Cane Run 6 FGD System Design Basis 73
30 Cane Run 6 FGD System Design Operating
Parameters 74
31 Cane Run 6 FGD System Guarantees 75
32 Cane Run 4 and 5 Reported and Adjusted Capital
Costs 80
• 33 Cane Run 4 and 5 Adjusted Annual Costs 80
34 Estimated Capital Costs for Cane Run 6 FGD
System 82
35 Estimated Annual Costs for Cane Run 6 FGD
System 83
vl
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ACKNOWLEDGMENT
This report was prepared under the direction of Mr. Timothy
W. Devitt. The principal author was Mr. Bernard A. Laseke.
Mr. Norman Kaplan, EPA Project Officer, had primary respon-
sibility within EPA for this project report. Mr. Robert Van
Ness, Manager of Environmental Affairs, Louisville Gas and
Electric Company, provided information on plant design and opera-
tion.
vii
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SUMMARY
The Cane Run Power Station is an existing coal-fired facil-
ity owned and operated by the Louisville Gas and Electric Company
(LG&E). It is situated along the Ohio River in an industrialized
area of Louisville, Kentucky. The station's combined net gen-
erating capacity of 1007 MW is provided by six coal-fired power-
generating units. Each unit is equipped with its own steam
generator, turbine generator, emission controls, and stack.
A high sulfur, bituminous-grade, Kentucky coal is burned at
the station. This coal has an average heating value of 25,600
J/g (11,000 Btu/lb) and average ash, sulfur, and chloride con-
tents of 14.1, 4.1, and 0.07 percent, respectively.
All of the Cane Run units are equipped with electrostatic
precipitators (ESP's) for the control of fly ash. In addition,
Cane Run 4, 5, and 6 are equipped with flue gas desulfurization
(FGD) systems for the control of sulfur dioxide. The decision to
equip these boilers with FGD systems was made after a number of
discussions were held with the U.S. Environmental Protection
Agency, the Air Pollution Control District of Jefferson County,
and the Kentucky State Division of Air Pollution in 1974 and
1975. The intent of these discussions was to establish a com-
pliance plan for sulfur dioxide control at all of LG&E's facili-
ties in Jefferson County. The final result of these discussions
was the signing of a consent decree on December 10, 1975, which
mandated the installation of sulfur dioxide removal equipment on
various boilers at LG&E's Cane Run and Mill Creek stations. This
enforcement order specifically required sulfur dioxide removal
systems for Cane Run 4, 5, and 6 and Mill Creek 1 and 2.
viii
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As a result of the consent decree, LG&E awarded a contract
to American Air Filter on April 19, 1974, to supply an FGD system
which would be retrofitted on Cane Run 4. This FGD system, which
consists of two parallel wet scrubbing modules utilizing carbide
lime slurry as the absorbent, is designed to remove 85 percent of
the sulfur dioxide in the flue gas. Construction of the system
commenced on October 15, 1974, and initial system startup oc-
curred on August 3f 1976. The system was declared commercial
approximately one year later when it successfully completed
compliance and guarantee testing.
During the interim period between initial startup and
commercial startup, a number of major operating problems were en-
countered which required numerous modifications and ultimately
necessitated a basic redesign of the FGD system. The major
problems encountered during this phase of operation included
excessive system pressure drop, poor gas flow distribution, mal-
function of the spray nozzles and spray pumps, mist eliminator
inefficiency, failure of the lining materials on the outlet duct-
work and stack, and inadequate slurry recirculation rates to the
absorption zone of the scrubber modules. As a result, the FGD
system produced sulfur dioxide removal efficiencies of 70 to 80
percent (well below the 85 percent design guarantee for 4 percent
sulfur coal) and the operation of the boiler was limited to a
maximum capacity of 150 to 155 MW (well below the maximum net
generating capacity of 178 MW).
During the course of a scheduled unit shutdown, which ex-
tended from mid-April to mid-July 1977, all repairs and modifi-
cations were performed. This included relining of the stack and
outlet ductwork; replacing the mist eliminators and pH meters;
installing reheaters, turning vanes, and additional spray headers;
and increasing the recirculation pump capacity.
These modifications were completed in July 1977. Early in
August, the system was tested for compliance with Jefferson
County and Federal sulfur dioxide air emission regulations. The
IX
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modifications enabled the system to meet the Jefferson County
removal requirement of 85 percent and the Federal standard of 516
ng/J (1.2 lb/10 Btu). The testing was handled by EPA personnel
and a sulfur dioxide removal efficiency of 86 to 89 percent was
attained for coal containing 3.3 to 3.4 percent sulfur. This
efficiency is equivalent to an outlet emission value of 344 ng/J
(0.8 lb/106 Btu).
With respect to system dependability, the Cane Run 4 FGD
system achieved high operability* values for operation during and
subsequent to initial startup. For the first 6 months following
initial startup, the system performed at an operability of 92
percent. During the subsequent 6 months, however, the system
remained out of service for virtually the entire period because
of winter weather conditions which hampered lime deliveries to
the plant, and because of the extensive system repairs and
modifications required to achieve design performance. Following
the successful completion of acceptance testing and initiation of
commercial operation in August 1977, the FGD system has performed
at an operability of approximately 90 percent for the period
extending through September 1979. The only periods of system
inactivity that occurred during this time resulted primarily from
external conditions such as severe winter weather conditions, the
coal miners' strike of 1978, boiler and turbine repairs, and
scheduled annual unit overhauls.
LG&E was also mandated by the consent decree to retrofit
sulfur dioxide controls on Cane Run 5. On April 21, 1975, a
contract was awarded to Combustion Engineering to supply an FGD
system for Cane Run 5. This FGD system is similar to the Cane
Run 4 system in that the boiler is equipped with two parallel
scrubbing modules designed to remove 85 percent of the sulfur
dioxide from 100 percent of the boiler flue gas from the 192-
MW (net) unit. Carbide lime is also used as the sulfur dioxide
absorbent.
*
Operability: the number of hours the FGD system is in operation
divided by the number of hours the boiler is in operation for a
period, expressed as a percentage.
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Construction of the Cane Run 5 FGD system commenced on
October 1, 1975, and initial system startup occurred on December
29, 1977. Operation of the system during the months subsequent
to initial startup was sporadic primarily because of activities
related to construction completion, the coal miners' strike which
eventually forced the unit out of service for approximately 2
months, and a variety of minor FGD-related problems which are
normally encountered during system startup. The FGD system was
returned to service on March 24, 1978. During the months that
followed (mid-May to mid-July 1978) , a series of performance
tests were conducted in order to demonstrate contractual guaran-
tees and compliance with air emission regulations. The results
of the emission tests indicated that the FGD system was able to
remove better than 90 percent of the inlet sulfur dioxide as well
as provide a high degree of secondary particulate control. Fol-
lowing the successful completion of these tests, the system was
certified commercial. Performance of the system subsequent to
commercial startup has been characterized by a high degree of
system dependability with an average operability index of approx-
imately 80 percent. Periods of system activity during commercial
operation have been caused by severe winter weather conditioning
and FGD-related problems in the form of reheater tube failures.
The FGD process selected for Cane Run 6 was a sodium car-
bonate/carbide lime dual alkali system. This process was de-
veloped by Combustion Equipment Associates and A.D. Little and
the system was installed on Cane Run 6 as part of an EPA-funded
demonstration program. Similar to the Cane Run 4 and 5 FGD
systems, this system also consists of two parallel scrubber
modules designed to treat 100 percent of the boiler flue gas from
the 277-MW (net) unit. However, unlike the other systems, this
system uses a clear liquor of soluble sodium salts to absorb the
sulfur dioxide and a slurry of carbide lime to regenerate the
spent sodium scrubbing liquor and produce calcium sulfite and
sulfate waste solids. In addition, the system is designed to
xi
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remove as much as 95 percent of the inlet sulfur dioxide when
coal with a maximum sulfur content of 5 percent is burned in the
boiler.
Construction of the dual alkali system commenced in the
spring of 1977 and initial system startup occurred in early April
1979. Acceptance testing has not yet been performed to certify
the system ready for commercial service.
LG&E has reported the total capital and annual costs asso-
ciated with the Cane Run 4 and 5 FGD systems. Total installed
capital costs for these systems are $66.6/kW and $62.4/kW,
respectively. These values are expressed in terms of the gross
unit capacity and represent all direct and indirect capital
expenditures made prior to startup. The annual costs for both of
these systems amount to 2.5 to 3.0 mills/kWh and represent
estimated operating and maintenance costs incurred during 1977
and expressed in terms of net unit capacity.
Although the Cane Run 6 FGD system has not yet been declared
commercial, estimated capital and annual costs have been prepared
by the demonstration project participants. The estimated capital
costs amount to $57.9/kW and include all direct and indirect
costs expressed in terms of gross peak generating capacity. The
estimated annual costs amount to 3.2 mills/kWh and include all
variable and fixed costs expressed in terms of gross peak gener-
ating capacity.
Tables 1, 2, and 3 summarize data on the facilities and FGD
systems for Cane Run 4, 5, and 6, respectively.
xii
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TABLE 1. FACILITY AND FGD SYSTEM DATA FOR CANE RUN 4
Unit rating (gross), MW
(net), MW
Fuel
Average fuel characteristics:
Heating value, J/g (Btu/lb)
Ash, percent
Moisture, percent
Sulfur, percent
Chloride, percent
FGD process
FGD system supplier
Application
Status
Startup date:
Initial
Commercial
Design removal efficiency:
Particulate, percent
Sulfur dioxide, percent
Actual removal efficiency:
Particulate, percent
Sulfur dioxide, percent
Sludge disposal
Economics:
Capital, $/kW (gross)
Annual, mills/kWh
190
182
Coal
25,600 (11,000)
14.1
9.6
4.1
0.07
Lime (carbide)
American Air Filter
Retrofit
Operational
August 1976
August 1977
99. Oc
85.0
99.0
86-89°
Stabilized sludge disposed in
an on-site pond
66.6f
2.751
aProvided by upstream ESP's.
DResults of acceptance tests.
cEstimate of operating and maintenance costs for 1977.
xiii
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TABLE 2. FACILITY AND FGD SYSTEM DATA FOR CANE RUN 5
Unit rating (gross), MW
(net), MW
Fuel
Average fuel characteristics:
Heating value, J/g (Btu/lb)
Ash, %
Moisture, %
Sulfur, %
Chloride, %
FGD process
FGD system supplier
Application
Status
Startup date:
Initial
Commercial
Design removal efficiency:
Parti oil ate, %
Sulfur dioxide, %
Actual removal efficiency:
Particulate, %
Sulfur dioxide, %
Sludge disposal
Economics:
Capital, $/kW (gross)
Annual, mills/kWh (net)
200
192
Coal
25,600 (11,000)
14.1
9.6
4.1
0.07
Lime (carbide)
Combustion Engineering
Refrofi t
Operational
December 1977
July 1978
99.0°
85.0
99.0
91b
Stabilized sludge disposed in
on-site pond
$62.4
2.75C
aProvided by upstream ESP's.
b
Results of acceptance tests.
cEstimate of operating and maintenance costs for 1977.
xlv
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TABLE 3. FACILITY AND FGD SYSTEM DATA FOR CANE RUN 6
Unit rating (gross), MW
(net), MW
Fuel
Average fuel characteristics:
Heating value, J/g (Btu/lb)
Ash, %
Moisture, %
Sulfur, %
Chloride, %
FGD process
FGD system supplier
Application
Status
Startup date:
Initial
Commercial
Design removal efficiency:
Particulate, %
Sulfur dioxide, %
Actual removal efficiency:
Particulate, %
Sulfur dioxide, %
Sludge disposal
Economics:
Capital, $/kW (gross)
Annual, mills/kWh
299
277
Coal
25,600 (11,000)
14.1
9.6
4.1
0.07
Dual alkali
Combustion Equipment Associates/
A.D. Little
Retrofit
Operational
April 1979
99.0
95. O
99.0
Not available
Stabilized sludge disposed in
on-site pond
57.9
3.24
Provided by upstream ESP's.
DMaximum efficiency for coal sulfur contents of 5 percent and greater.
"Estimated values.
XV
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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
Cane Run Power Station of the Louisville Gas and Electric Company
(LG&E). It includes pertinent process design and operating data,
a description of major startup and operating problems and solu-
tions, atmospheric emissions data, and capital and annual cost
data.
This report is based on information obtained during and
after plant inspections conducted for PEDCo Environmental per-
sonnel on February 22, 1978, and September 11, 1979, by LG&E.
The information presented in this report is current as of September
1979.
Section 2 provides information and data on facility design
and operation; Section 3 provides background information and a
detailed description of the FGD processes; Section 4 describes
and analyzes the operation and performance of the FGD systems;
and Section 5 provides capital and annual cost data of the FGD
systems. Appendices A through F contain details of plant and
system operation, economic data, and photos of the installation.
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SECTION 2
FACILITY DESCRIPTION
The Cane Run Power Station is an existing coal-fired power-
generating station owned and operated by LG&E. Located in
Jefferson County, Kentucky, the plant is situated along the Ohio
River in a moderately industrialized area of Lousiville (popula-
tion: 333,000).
The station contains six coal-fired steam electric genera-
tors which are capable of producing a maximum net generating
capacity of 1007 MW. Cane Run 1, 2, and 3, which are the older
units at the station, are rated 106, 109, and 141 MW (net),
respectively. Cane Run 4, 5, and 6, which have been in service
for 19, 16, and 12 years, respectively, are rated 182, 192, and
277 MW (net), respectively. The station capacity factor for
operation in 1977 was approximately 50 percent. Table 4 provides
a summary of the Cane Run units, including gross and net generat-
ing capacities, heat rates, and capacity factors.
A high sulfur bituminous grade Kentucky coal is burned at
the station. This coal originates primarily from the Star Mine
which is owned by the Peabody Coal Company and located in the
western part of the state. This coal has an average heating
value of 25,600 J/g (11,000 Btu/lb) and average ash, moisture,
sulfur, and chloride contents of 14.1, 9.6, 4.1, and 0.07 per-
cent, respectively. Approximately 900 Mg (2 million tons) of
this coal are burned annually at this station.
In order to meet air emission regulations of the Air Pollu-
tion Control District of Jefferson County, the Kentucky State
Division of Air Pollution, and the U.S. EPA, each unit at Cane
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TABLE 4. SUMMARY OF THE CANE RUN POWER-GENERATING UNITS
Unit
1
2
3
4
5
6
Total
(average)
Capacity, MW
Gross
110
113
147
190
200
299
1059
Net
106
109
141
182
192
277
1007
Heat rate,
J/net kWh
(Btu/net kWh)
11,426
(10,830)
11,035
(10,460)
10,772
(10,210)
10,740
(10,180)
10,529
(9,980)
10,508
(9,960)
Capacity
factor,
percent
N.A.a
a
N.A.a
N.A.a
55
60
60
L.
(50)b
Individual unit capacity factors are not available. The combined
capacity factor for Units 1, 2, and 3 was approximately 34
percent for 1977.
Station capacity factor for 1977.
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Run is equipped with an emission control system. Cane Run 1
through 6 are equipped with electrostatic precipitators (ESP's)
for the control of fly ash. In addition, Cane Run 4, 5, and 6
are equipped with flue gas desulfurization (FGD) systems for the
control of sulfur dioxide. The FGD systems provided for each
unit consist of two parallel scrubber modules designed to treat
100 percent of the boiler flue gas for each unit at full load.
The Cane Run 4 and 5 FGD systems use a slurry of carbide lime for
removal of sulfur dioxide and the sulfur-bearing calcium waste
solids produced are disposed on the plant site. The Cane Run 6
FGD system uses a clear solution of soluble sodium salts for
removal of sulfur dioxide and carbide lime slurry to regenerate
the spent scrubbing solution and produce sulfur-bearing calcium
waste solids. The Cane 4 and 5 FGD systems are supplied by
American Air Filter (AAF) and Combustion Engineering (C-E),
respectively. Initial and commercial startup dates for these
systems are August 3, 1976, and August 7, 1977, respectively, for
Cane 4; and December 29, 1977, and July 14, 1978, respectively,
for Cane Run 5. The Cane Run 6 FGD system is supplied by Combus-
tion Equipment Associates and A.D. Little (CEA/ADL). Initial
startup of this system occurred in early April 1979. Acceptance
testing has not yet been completed for commercial certification
of this FGD system.
For Cane Run 4, 5, and 6, maximum particulate emissions
allowable under regulations of the Air Pollution Control District
of Jefferson County, the Kentucky State Division of Air Pollu-
tion, and the U.S. EPA are 43 ng/J (0.1 lb/10 Btu) of heat input
to the boiler. Maximum allowable sulfur dioxide emissions are
limited by a continuous removal requirement of 85 percent and a
weight limitation of 516 ng/J (1.2 lb/10 Btu) of heat input to
the boiler. Actual sulfur dioxide emissions, as measured by EPA
personnel during compliance testing for Cane Run 4, were 344 ng/J
(0.8 lb/10 Btu), which was equivalent to an 86 to 89 percent
sulfur dioxide removal efficiency for coal containing 3.3 to 3.4
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percent sulfur. For Cane Run 5, sulfur dioxide emissions mea-
sured during performance testing were 211 to 249 ng/J (0.49 to
0.58 lb/10 Btu) , which was equivalent to a 91 percent sulfur
dioxide removal efficiency.
Table 5 summarizes data on plant design and operation.
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TABLE 5. DESIGN,
CANE
OPERATION, AND EMISSION DATA:
RUN 4, 5, AND 6
Description
Generating capacity, MW
Gross
Net without FGD
Net with FGD
Maximum coal consumption,
Mg/h (tons/h)
Maximum heat input
GJ/h (106 Btu/h)
Maximum flue gas rate
m3/s (103 acfm)
Flue gas temperature, °C (°F)
Unit heat rate,
kJ/net kWh (Btu/net kWh)
Unit capacity factor,
percent (1977)
Emission controls:
Partial late
Sulfur dioxide
Particulate emission rate:
Allowable, ng/J
(lb/106 Btu)
Actual. ng/J
(lb/10o Btu)
Sulfur dioxide emission rate:
Allowable, ng/J
(lb/106 Btu)
Actual, ng/J
(lb/106 Btu)
Cane Run 4
190
185
182
76 (84)
1,955 (1,852)
346 (734)
163 (325)
10,740 (10,180)
55
ESP
Packed tower
absorbers
43
(0.1)
43
(0.1)
516
(1.2)
344
(0.8)
Cane Run 5
200
195
192
79 (87)
2,022 (1,916)
307 (650)
163 (325)
10,529 (9,980)
60
ESP
Spray tower
absorbers
43
(0.1)
15-26
(0.04 - 0.06)
516
(1.2)
211 - 249
(0.49 - 0.58)
Cane Run 6
299
280
211
113 (125)
2,911 (2,756)
503 (1,065)
149 (300)
10,508 (9,960)
60
ESP
Tray tower
absorbers
43
(0.1)
43
(0-1)
516
(1.2)
N.A.a
Not available; acceptance testing has not yet been performed.
6
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SECTION 3
FLUE GAS DESULFURIZATION SYSTEM
BACKGROUND INFORMATION
Process Development
In 1970, LG&E was faced with the dilemma of imminent strin-
gent ambient air standards for sulfur dioxide emissions from
their coal-fired plants and a contractural commitment to a long-
term supply of high sulfur coal. As such, LG&E requested Com-
bustion Engineering (C-E) to evaluate their marble-bed scrubber
design for application in a lime slurry FGD system on a coal-
fired boiler at their Paddy's Run Power Station. This evaluation
was based on the development of a process design that was com-
patible with carbide lime as the absorbent. Carbide lime is a
by-product of the manufacture of acetylene and is mainly composed
of calcium hydroxide and calcium carbonate. The request to
develop a process that could use carbide lime stemmed from LG&E's
easy access to supplies of this by-product from a local acetylene
manufacturing plant operated by Airco.
In early 1971, a laboratory pilot plant program was con-
ducted at C-E's Kreisinger Laboratory. A 34-m /min (1200-acfm)
pilot plant scrubber was used to establish the feasibility of
removing 80 percent of the inlet sulfur dioxide from a flue gas
stream containing 2000 ppm sulfur dioxide. Using carbide lime
lime as the absorbent, an optimum scrubber design was developed
which was capable of achieving design removal efficiency without
scaling while operating in an open water loop.
In June 1971, a prototype plant program was conducted at
Kreisinger to verify the results of the laboratory pilot plant
-------
program. A 340-m /min (12,000-acfm) prototype plant scrubber was
operated through a 100-h test program to verify and refine system
design parameters. The prototype plant test program essentially
verified the results obtained from the laboratory pilot plant
test program.
In early 1972, another prototype plant test program was
again conducted at Kreisinger [340 m /min (12,000 acfm)] to
demonstrate the feasibility of achieving these results while
operating in a closed water loop. For two months the prototype
plant demonstrated closed water loop operation with no decline in
overall performance. The results of the various pilot and
prototype plant test programs conducted at Kreisinger are sum-
marized in Table 6.
As a result of these successful test programs, LG&E author-
ized C-E to proceed with the design and installation of a demon-
stration-scale FGD system on Paddy's Run 6, a 65-MW (net) coal-
fired unit. This unit was selected for the demonstration because
of space available for retrofit. The intent of this demonstra-
tion was to determine the design and performance capabilities of
a carbide lime slurry FGD system on a full-size, high sulfur,
coal-fired unit. Based on the outcome of this demonstration
program, LG&E was required to develop a sulfur dioxide control
program for its coal-fired generating stations in order to comply
with ambient air standards.
On-site construction of the Paddy's Run FGD system commenced
in June 1972 and was completed in April 1973. Initial startup
occurred on April 5, 1973, and system shakedown was completed by
the following July.
Process Design
The Paddy"s Run FGD system consists of two identical scrub-
ber modules arranged in parallel. Each scrubber module is
designed to treat 50 percent of the boiler flue gas at full load,
which is equivalent to 82.6 m /s (175,000 acfm) of flue gas at
-------
TABLE 6. SUMMARY OF KREISINGER TEST PROGRAMS: 1971 to 1972
Test unit
Test duration, h (mo)
Capacity, m^/s (acfm)
Design
Absorbent
Stoichiometric ratio4
Slurry pHb
Liquid/gas ratio, Iiters/m3 (gal/1000 acf)c
Slurry recycle, percent
Water loop
Liquid blowdown, Iiters/m3 (gal/1000 acf)
Sulfur dioxide concentration, ppm
Sulfur dioxide removal efficiency;
Design, percent
Actual , percent
Pilot
34 (1200)
Double marble bed
Carbide lime
1.0
9 - 10
2.6 (20)
45
Open
2000
80
75-80
Prototype
75
340 (12,000)
Double marble bed
Carbide lime
1.0
10
2.6 (20)
45
Open
0.6 (5)
2000
80
80
Prototype
20
340 (12,000)
Double marble bed
Carbide lime
1.0
10
3.3 (25)
90
Open
0.6 (5)
2000
80
90
Prototype
(2)
340 (12,000)
Double marble bed
Carbide lime
1.0
<10
2.6 (20)
90
Closed
None
2000
80
87
Moles of absorbent (CaO) per mole of sulfur dioxide removed.
Control level of slurry feed to underbed streams.
Per bed.
The protion of scrubber effluent slurry recycled to the scrubber through the reaction tank.
-------
177°C (350°F). Each scrubber module is equipped with two marble
beds which facilitate intimate mixing of the gas and scrubbing
slurry. Each marble bed contains a 7.6-cm (3-in.) layer of 2.5-
cm (1.0-in.) diameter glass spheres. Each scrubber is also
equipped with a two-stage mist eliminator which removes entrained
droplets carried over in the gas from the scrubbing zone. The
discharge duct of each scrubber module is equipped with two
natural gas burners designed to raise the temperature of the
saturated gas stream 22°C (40°F) prior to passage through a
booster fan [1100 kW (1500 hp)] to the existing stack.
Carbide lime scrubbing slurry is sprayed cocurrently with
the gas stream to the underside of each marble bed at a rate of
256 liters/s (4050 gpm). This is equivalent to a liquid to gas
ratio (L/G) of approximately 2.1 liters/m (16 gal/1000 acf) per
bed. The carbide lime slurry is delivered to each scrubber
module by a battery of 3 spray pumps, 2 of which are required for
operation at full load. Spent scrubbing slurry is collected by
overflow pots located on the top side of each marble bed and re-
turned via gravity feed to a series of external reaction tanks.
Each scrubber module is also equipped with a divided internal
hold tank which collects slurry not carried away by the overflow
pots. A sloping screen segregates the internal hold tank into
two parts, a bottom half and top half, each of which is equipped
with an agitator. The screen collects large particles and purges
them along with spent scrubbing slurry collected in the top half
via an effluent bleed pump (one per scrubber module) to a thick-
ener. The slurry collected in the bottom half of the divided
hold tank is transferred by a drain pump (one operational and one
common spare per scrubber module) to the external reaction tanks.
The spent slurry is collected in the primary reaction tank
which is an agitated, 750,000-liter (210,000 gal) capacity reac-
tor. Fresh carbide lime slurry is fed to the primary reactor as
well as thickener overflow, fresh makeup water, and vacuum fil-
trate. The carbide lime is added to this tank along with the
10
-------
scrubber internal hold tank bottoms in a small cylindrical mixing
well in order to insure intimate mixing and completion of chem-
ical reactions. This tank provides a 20-minute retention time.
A secondary reaction tank (surge tank) downstream from the pri-
mary reactor provides additional slurry holdup in order to ensure
completion of chemical reactions. Slurry is then pumped back to
the marble beds in the scrubber modules by the slurry spray
pumps.
A 10 percent solids stream is bled from the slurry recir-
culation loop to the thickener in order to remove the reaction
products which accumulate in the scrubbing slurry. The thickener
has a diameter of 15.2 m (50 ft) and a liquid capacity of 777,900
liters (205,500 gal). The waste slurry is concentrated to a 25
percent solids sludge in the thickener and the underflow is sent
to a rotary drum vacuum filter for further concentrating. Two
rotary drum vacuum filters are provided for final dewatering, one
of which is a spare. Each filter has an effective filtering area
2 2
of 14 m (150 ft ) and is designed to produce 9 Mg/h (10 tons/hr)
of 45 percent solids filter cake. During the dewatering process,
lime and dry fly ash are added to the waste slurry in order to
stabilize the sludge product for disposal in an off-site land-
fill.
A simplified process flow diagram of the Paddy's Run FGD
system is provided in Figure 1. Design conditions and operating
parameters for the Paddy's Run FGD system are provided in Tables
7, 8, 9, 10, 11, 12, and 13.
System Performance
On April 6, 1973, initial operation of the FGD system was
achieved with one scrubber module placed in the flue gas path.
From April 6 to early October 1973, the FGD system operated
approximately 1000 h on an intermittent basis. During this
period, the system was checked out and modifications were made to
the thickener, lime feed system, mist eliminator wash system, and
system controls. On October 26, 1973, an extended 30-day test
11
-------
GAS TO STACK
GAi REHEATERS
MIST ELIMINATOR
DRV CA(OH)2
ADDITIVE SYSTEM
pH ELECTRODE _ STRAINERS
ASSEMBLY
MIXERO-—| ,'
COMM1NUTOR
GAS INLET
^
XT
GA5 Wit / - ±rr--
STEAM BLOytRS |
LADDER VANE SPRAY J
Figure 1. Simplified process flow diagram of Paddy's Run 6 FGD system.
-------
TABLE 7. SUMMARY OF DATA: SCRUBBER MODULES
Number of modules
Type
Dimensions, m (ft)
Capacity, m-^/s (acfm)
Superficial gas velocity, m/s (ft/s)
Liquid/gas ratio, liters/m3 (gal/1000 acf)
Equipment internals:
Number of beds
Bed packing thickness, cm (in)
Marble sphere diameter
Materials of construction:
Shell
Lining
Plates
Supports
Drain pots
Marble bed
5.2 (17), 5.5 (18), 15.2 (50)
82.6 (175,000)
3.0 (10)
2.1 (16)
2
7.6 (3)
2.5 (1)
Carbon steel
Flake glass polyester
316L stainless steel
316L stainless steel
316L stainless steel
13
-------
TABLE 8. SUMMARY OF DATA: MIST ELIMINATORS
Number
Number per module
Type
Configuration (relative to gas flow)
Shape
Number of stages
Number of passes
Distance between stages, m (ft)
Distance between vanes, cm (in.)
Freeboard distance, m (ft)
Pressure drop, kPa (in. ^0)
Materials of construction
Wash system:
Water source
Wash duration, min/h
Wash rate, liters/s (gpm)
Wash pressure, kPa (psig)
2
1
Chevron
Horizontal
Z-shape, 120-degree bends
2
3
1.2 (4)
3.8-5.1 (1.5-2.0)
1.5 (5)
0.25 (1.0)
FRP
River water
10-15/8
5.0-12.6 (80-200)
377-550 (40-65)
14
-------
TABLE 9. SUMMARY OF DATA: REHEATERS
Number
Number per module
Type
Fuel
Fuel rate, nrVmin (scfh)
Heat input, GJ/h (106 Btu/h)
Excess combustion air
AT, °C (°F)
4
2
Direct combustion
Natural gas
9.4 (20,000)
17 - 19 (16 - 18)
6-9
22 (40)
15
-------
TABLE 10. SUMMARY OF DATA: TANKS
(Ti
Category
Number
Dimensions, m (ft)
Capacity, liter (gal)
Retention time, min
Temperature
PH
Solids
Specific gravity
Agitators:
Number
Rating, kW (hp)
Materials of construction:
Shell
Lining
Primary reaction
tank
1
14.6 x 5.2
(48 x 17)
795,000
(210,000)
20
52 (125)
8
10
1.1
2
10 (15) & 40 (50)
Carbon
steel
Secondary
reaction
tank
(surge)
1
6.1 x 4.6
(20 x 15)
133,250 .
(35,200)
3
52 (125)
8
10
1.1
1
10 (15)
Carbon
steel
Scrubber
internal
hold
tank
2
4.6 x 5.2 x 4.9
(15 x 17 x 16)
61,700
(16,300)
3
52 (126)
4.6-5.3
10
1.1
2
8 (10)
Carbon
steel
Flake glass
polyester
Carbide
lime
slurry
tank
1
2.4 x 5.2
(8x 17)
24.230
(6,400)
150
Ambient
12.6
10
1.1
1
4 (5)
Carbon
steel
-------
TABLE 11. SUMMARY OF DATA: THICKENER
Number
Dimensions, m (ft)
Capacity, liters (gal)
Solids concentration:
Inlet, percent
Outlet, percent
Retention time, hra
Materials of construction
aAt full load.
1
15.2 x 4.3 (50 x 14)
777,900 (205,500)
10
25
4.3
Carbon steel
TABLE 12. SUMMARY OF DATA: VACUUM FILTERS
Number
Operating schedule
Cloth area/filter, m2 (ft2)
Feed stream characteristics:
Liters/s (gpm)
Solids, percent
Product characteristics:
Solids, percent
Wet filter cake, Mg/h (ton/h)
Dry solids, Mg/h (ton/h)
1 operational/I spare
14 (150)
5 (80)
25
45
9 (10)
3.7 (4.1)
17
-------
TABLE 13. SUMMARY OF DATA: MAJOR PUMPS
00
Number
6
Z
2
2
Service
Slurry
redrculatlon
Slurry feed
Thickener
overflow
Thickener
underflow
Manu-
facturer
AlHs
Chalmers
Worthing ton
AlHs
Chalmers
Allen
Shermanhoff
Model
ER-3729-
2-1/2R091
912
AA-6-5
Performance
Materials of
construction
N1-Hard
Cast Iron
(casing and
Impeller)
Rubber- lined
(casing and
Impeller)
Rubber- lined
(casing and
Impeller)
Motor
kW (hp)
335 (450)
3.7 (5)
22 (30)
3.7 (5)
Capacity.
I1ters/s
(9P"i)
380 (6000)
6.3 (100)
19 (300)
9.5 (150)
Speed,
rpm
1000
1800
1800
1800
Solids,
percent
10
25
<1
25
Head
m (ft)
36 (140)
18 (60)
36 (120)
36 (120)
Operation
4 operational,
2 spare
2 operational
1 operational,
1 spare
1 operational ,
1 spare
-------
run was initiated to demonstrate system reliability. The operat-
ing criteria for the test required one scrubber module remain in
service while the other module would float with system load
demand. This test was completed on November 30, 1973, after 854 h
of continuous operation. During the test, measurements indicated
that the FGD system's sulfur dioxide removal efficiency exceeded
design (85 percent) and the outlet particulate loadings were 68.6
to 91.5 mg/m3 (0.030 to 0.040 gr/dscf).
By the end of 1973, module A had logged 1318 hours of oper-
ation and module B had logged 2425 hours of operation. This
translates into annual operability* factors of 39 and 71 percent
for modules A and B, respectively.
The FGD system was returned to service in July 1974 to meet
LG&E's summer peak generating demand. During this period of
operation, the unit and FGD system were operated on an 8-to-5,
Monday-through-Friday schedule. Module A logged 417 h of opera-
tion and Module B 517 h, which are equivalent to operability
factors of 67 and 83 percent, respectively. The operation of the
FGD system during this period was significant because of varia-
tions in the carbide lime additive. The magnesium oxide content
ranged to a maximum of 2.2 percent (up from previous levels of
0.1 percent) and the concentration of a soluble oxidation inhi-
bitor dropped off to low or nonexistent levels. As such, the
following effects on system performance were noted:
(1) Sulfur dioxide removal increased on the average 3 or 4
percent to the 90 percent level.
(2) Sulfur dioxide emission levels decreased from approxi-
mately 140 ppm to 60 ppm.
(3) Magnesium ion concentrations in the scrubbing slurry
increased from approximately 100 to 1500 ppm.
(4) Dissolved solids levels in the scrubbing slurry in-
creased to 7000 to 8000 ppm.
Operability: the number of hours the FGD system (or individual
modules) is in operation divided by the number of hours the
boilers in operation for a period, expressed as a percentage.
19
-------
(5) Oxidation increased to the 10 percent level on a molar
basis.
The FGD system was again returned to service late in the
summer of 1975 when the unit was pressed into service to meet
summer peak demand. During the remainder of the year, the unit
and PGD system were operated intermittently, on an 8-to-5, Mon-
day- through-Friday schedule. During this period of operation,
no major problems were encountered and system operability was
approximately 98 percent for both modules. High sulfur dioxide
removal efficiencies, on the order of 98 percent, were recorded
during this period of operation.
The FGD system continued to operate intermittently in 1976
through peak demand periods. During the course of the year,
preparations were made to conduct an EPA-subsidized scrubber and
sludge evaluation study. This study, which commenced on October
25, 1976, consisted of four phases: carbide lime characteriza-
tion and sludge mixing, commercial lime testing and sludge
mixing, hold tank modifications, and magnesium and chloride ion
addition testing. Testing was conducted on one of the system's
two modules.
The first phase of operation was completed in December 1976.
Basically, this phase of testing was devoted to characterizing
the FGD system as it normally operated. The second phase of
operation, commercial lime testing, commenced in mid-March 1977.
With commercial lime as the scrubbing reagent, the system oper-
ated at elevated gypsum saturation levels (1.1 to 1.6) and
oxidation levels (13 to 15 percent), and varying amounts of
gypsum scale were formed in the system. Carbide lime slurry was
reintroduced into the system in order to clean up the scale
condition in the scrubber. A form of carbide lime ("black lime")
was used that contained high concentrations of magnesium (as high
as 2.2 percent), providing slurry concentrations in the range of
1000 to 1600 ppm. After a few days of operation with carbide
lime, the scale formed in the system dissolved and subsaturated
conditions were reestablished.
20
-------
From June 18 to August 31, 1977, the last phases of the test
program were completed. The most interesting results obtained
during this period involved the magnesium and chloride addition
testing. With respect to magnesium addition, the system was
operated with a commercial grade lime promoted with a 55 percent
slurry of magnesium hydroxide which yielded an effective mag-
nesium ion concentration of 4000 ppm. During the course of the
test, the magnesium ion concentration was gradually lowered to
2000 ppm. Sulfur dioxide removals of 99.7 to 99.9 percent were
achieved with inlet sulfur dioxide loadings of 2150 to 2230 ppm
and outlet loadings of 1 to 5 ppm. These removal efficiencies
were accompanied by calcium sulfate relative saturations ap-
proaching zero. Maintaining the effective magnesium ion concen-
tration in the 2400 to 3000 ppm range provided the best control
for maintaining high sulfur dioxide removals and low calcium
sulfate relative saturation levels.
With respect the chloride addition, calcium chloride was
added to the scrubbing slurry in order to produce chloride levels
of 3000 ppm, a concentration normally associated with a high
chloride coal. Magnesium ion concentrations were increased to
3500 ppm in order to compensate for the increased chloride ion
concentration levels. Results indicated that high sulfur dioxide
removals (99 percent) and low gypsum relative saturation levels
were achieved with no operational problems.
With respect to the sludge mix program, various samples of
carbide lime and commercial lime sludges were mixed with fixa-
tives in order to obtain data on permeability, unconfined com-
pressive strengths, and leachates. Conditions evaluated during
the course of the program included disposal method (lined pond,
unlined pit), sludge solids (24 to 65 percent), fixatives (car-
bide lime, portland cement), and fixative-to-solid ratios (0:1 to
1.5:1). Preliminary results indicated that the carbide lime and
commercial lime sludges achieved similar levels with respect to
permeability, unconfined compressive strength, and leachates.
21
-------
Following the completion of the scrubber and sludge test
program, the unit and FGD system remained inactive during the
balance of 1977 and operated only briefly in 1978. FGD opera-
tions in 1978 were confined to peak load periods (April and June)
and one test program which involved the evaluation of a new floc-
culant for use at other LG&E FGD systems. The FGD system did not
operate during the first 9 months of 1979 because of insufficient
demand to operate the unit.
Process Selection for Future Installations
During the course of the Paddy's Run FGD demonstration pro-
gram, discussions were being held with the U.S. EPA, Air Pollu-
tion Control District of Jefferson County, and the Kentucky State
Division of Air Pollution regarding the reduction of sulfur
dioxide emissions at LG&E*s coal-fired installations. The
success of the Paddy's Run FGD demonstration program, coupled
with LG&E's long-term commitment to high sulfur coal for their
entire system, resulted in the signing of a consent decree on
December 10, 1975, with the following conditions:
(1) All the Paddy's Run units will be phased out of service
by 1985 with Paddy's Run 1, 2, and 3 retired by the end
of 1979 and the remaining units by 1985.
(2) Cane Run 1, 2, and 3 will be phased out of service by
1985. Cane Run 4, 5, and 6 will be equipped with FGD
systems.
(3) Mill Creek 1 and 2 will be equipped with FGD systems.
Mill Creek 3 and 4 are new units which will require FGD
systems to achieve compliance with sulfur dioxide new
source performance standards (NSPS).
(4) LG&E will have the capability to use the units phased
out of service on an emergency basis which is defined
as power requirements during shutdown of the FGD-
equipped units.
Based on the requirements of the consent decree, LG&E
awarded a contract to AAF for a carbide lime slurry FGD system
22
-------
for Cane Run 4. Initial startup of this system occurred on
August 3, 1976. Subsequent contracts for commercial FGD systems
were awarded to C-E for Cane Run 5 (carbide lime slurry) and to
CEA/ADL for Cane Run 6 (dual alkali). These systems became
operational on December 29, 1977, and early April 1979, respec-
tively. Because the majority of LG&E's FGD commercial operating
experience has been with Cane Run 4 and 5, the remainder of this
report will be devoted to the design and performance aspects of
these particular units. The Cane Run 6 FGD system will be
briefly summarized with respect to design and performance charac-
teristics.
PROCESS DESCRIPTION
Cane Run 4
The carbide lime slurry FGD system operating at Cane Run 4
was supplied by AAF in accordance with specifications prepared by
LG&E's engineer, Fluor-Pioneer. The FGD system installed on Cane
Run 4 is a pressurized, tail-end, wet scrubbing system which
consists of two parallel scrubber modules designed to treat 346
m3/s (734,000 acfm) of flue gas at 163°C (325°F) when the unit is
operating at full load. The FGD system includes gas handling and
treating equipment, slurry handling equipment, solids concen-
trating equipment, waste disposal and pond water return equip-
ment, and lime preparation and handling equipment. A description
of these various elements of system operation is provided in the
following paragraphs. A simplified diagram of the Cane Run 4 FGD
system is provided in Figure 2.
Gas Handling and Treating Equipment—
The flue gas exits the boiler and passes through existing
ESP's at 346 m3/s (734,000 acfm) and 163°C (325°F). Flue gas
from existing induced-draft fans discharge through induced-draft
booster fans into the FGD system. The ductwork and damper net-
work provided with the FGD system allows gas to partially or
23
-------
QUENCHER
MIST
ELIMINATOR
(CHEVRON)
ELECTROSTATIC
PRECIPITATOR
BOILER
FLUE
GAS
CONTACTOR
SCRUBBER
•* MODULE
CONTACTOR
SCRUBBER
MODULE
MIST
ELIMINATOR
(CHEVRON)
FLOCCULANT
ADDITION
THICKENER
SURGE
TANK
_T~\ Ly—i—
\SETTLING /
\ POND /
POND WATER RETURN
Figure 2. Simplified process flow diagram of Cane Run 4 FGD system.
-------
totally bypass the scrubber modules. Guillotine isolation damp-
ers installed at the inlet of each booster fan, at the outlet of
each scrubber module, and in the bypass breeching enables gas to
bypass one or both scrubber modules during boiler operation.
Following passage through the booster fans, the gas enters
the scrubber modules. Eac scrubber module consists of a verticle
absorber tower preceded by a quencher and flooded elbow. Each
quencher is a wetted-wall conical frustrum section in the duct.
A series of nozzles in the quencher inject lime scrubbing slurry
into the gas stream to insure thorough wetting of the gases prior
to passage through the absorber. Immediately below each quencher
is a flooded elbow. This section serves as a catch basin for the
spent quencher slurry and complete the saturation of the. gas
stream. Some removal of sulfur dioxide occurs in the quencher
and flooded elbow since part of the lime slurry recycle stream is
diverted to these sections for wetting and saturation.
The quenched flue gas enters the base of each absorber tower
at 138 m3/s (291,500 acfm) and 53°C (127°F). Each absorber tower
is a single stage mobile bed contactor. The mobile bed contactor
contains a fluid bed packing of solid spheres which serve to
break up the gas stream and provide pockets for intimate mixing
of the flue gases and scrubbing slurry. The flue gas passes
upward through the packing where it contacts the scrubbing slurry
sprayed into the gas stream countercurrently through large, low
pressure, slurry sprays.
Entrained droplets of moisture and slurry picked up by the
gas stream due to the turbulent mixing of slurry and gas in
absorption zone are removed by mist eliminators. Each absorber
is equipped with a two-stage, two-pass, chevron-type mist elim-
inator located in the top portion of each tower. Each mist
eliminator is equipped with its own set of water sprays to retard
the accumulation of solids which buildup on the chevron blades.
Following passage through the mist eliminators, the cool,
saturated gas stream is reheated by oil-fired burners located in
25
-------
the discharge ducts entering the stack. The direct oil-fired
reheaters boost the temperature of the gas stream approximately
22° to 28°C (40° to 50°F) prior to discharge to the existing
stack.
Slurry Handling System—
Each scrubber module is equipped with its own compartment-
alized reaction tank, recirculation pumps, and recirculation line
for contacting the flue gas with scrubbing slurry. Three recir-
culation pumps deliver 1112 liters/s (17,625 gpm) of 10 percent
solids scrubbing slurry to each scrubber module. Of this amount,
112 liters/s (1,760 gpm) is provided to the quencher and 1000
liters/s (15,865 gpm) is provided to the absorber. This slurry,
as well as 5 liters/s (80 gpm) of mist eliminator wash water,
drains to a cone-shaped reservior located at the base of each
absorber. The spent slurry and wash water then drains through a
main pipe line to the return section of the reaction tank.
The reaction tank is the heart of the slurry recirculation
system. Each reaction tank is a rectangular, reinforced concrete
tank which contains two partitions dividing the tank into three
compartments. Each compartment represents a separate reaction
area and is equipped with its own agitator, pH monitors, and
level controls. Slurry flows from one compartment to the next
through an opening in the bottom of the partitioning wall.
During emergencies, this flow may occur over weirs placed at the
top of each compartment wall.
The three compartments comprised by the reaction tank are
the return section, middle section, and feed section. The return
section collects the spent scrubbing slurry discharged from the
cone-shaped reservoir located in the base of the absorber. Fresh
carbide lime slurry is added to this section as well as thickener
overflow. The fresh carbide lime slurry reacts with the spent
scrubbing slurry, neutralizing the reaction products and pre-
cipitating the waste solids which are ultimately removed from the
recirculation loop. Water from the thickener overflow return
tank maintains proper liquid levels in the reaction tank.
26
-------
The middle section of the reaction tank allows the control
of recycle slurry pH and the continuation of the chemical re-
actions started in the return section.
The feed section of the reaction tank allows the completion
of chemical reactions and triming of the pH of the recycle slur-
ry. Solids which have precipitated in the reaction tank are
removed from the bottom of the feed section by effluent bleed
pumps. The recycle slurry is then returned to the quencher and
absorber by the recirculation pumps.
Solids Concentrating—
The effluent bleed pumps discharge the waste solids accumu-
lated in the slurry loop to the thickener. Approximately 14
liters/s (220 gpm) of slurry is discharged from the feed section
of each reaction tank. The thickener concentrates the waste
solids from approximately 10 to 25 percent. In order to aid the
thickening process, a polyelectrolyte feeding system is provided
to enhance precipitation within the thickener. This feeding
system prepares, mixes, and ages a 0.5 percent flocculant solu-
tion which is transferred directly to the thickener on a con-
tinuous basis. The 5 to 7 ppm concentration of flocculant which
results in the thickener enhances the settling characteristics of
waste solids produced by the scrubbing system.
Sludge is removed from the bottom of the thickener to an on-
site pond for final disposal. Clarified overflow from the
thickener gravity flows to the thickener overflow return tank for
return to the reaction tank return sections. Supernatant from
the sludge pond is added to the thickener overflow return tank to
maintain system liquid levels. In addition, the thickener
overflow return tank is also equipped with an emergency overflow
which can empty water directly to the pond during emergency
liquid surges.
27
-------
Lime Preparation and Handling Equipment—
Carbide lime is delivered to the plant as a 30 percent
solids slurry. This absorbent is added to a crusher-disinte-
grator at a rate of 12.6 liters/s (200 gpm) at full load. The
crusher-disintegrator supplies lime of the proper consistency to
the reactant supply tank. Any tramp solids or other foreign
matter in the carbide lime slurry are removed by the crusher-
disintegrator. The reactant supply tank is an agitated hold tank
from which slurry is transferred to the return section of each
reaction tank. The flow of slurry from the crusher-disintegrator
to the reactant supply tank is controlled by liquid levels in the
tank. The flow of slurry from the reactant supply tank to the
reaction tank is controlled recycle slurry pH levels.
Cane Run 5
The carbide lime slurry FGD system operating at Cane Run 5
was supplied by C-E in accordance with specifications prepared by
Fluor-Pioneer. This system is similar to Cane Run 4 in process
design and gas treating capacity. As such, this system is
described in the same manner as that used above for Cane Run 4 .
A simplified process flow diagram of the Cane Run 5 FGD system is
provided in Figure 3.
Gas Handling—
Flue gas exits the boiler and passes through existing ESP's
to the FGD system. The FGD system consists of two 50 percent
capacity scrubber modules designed to treat 307 m /s (650,000
acfm) of flue gas at 163 °C (325°F) . Each scrubber module con-
tains a horizontal approach duct which enters the base of a
vertical spray tower absorber. The flue gas enters the base of
each scrubber at a velocity of 7.6 m/s (25 ft/s). As the gas
enters the base of the spray tower it is decelerated to a veloc-
ity of 2.1 m/s (7 ft/s) and turned 90 degrees with the aid of
ladder-type turning vanes. In this zone of the tower the gas is
rapidly quenched to a temperature of 52°C (126°F). The gas then
28
-------
N)
IN LINE REHEATER (STEAM)
I.D. BOOSTER FANS
TO STACK
FROM-*
ESP'S
-BYPASS
SPRAY PUMPS
•MIST ELIMINATOR
MIST ELIMINATOR WASH
— BULK ENTRAPMENT
SEPARATOR
-SPRAY TOWER ABSORBERS
CRUSHER-
DISINTEGRATOR
D
FROM LIME
IN-TANK STRAINER
^
UNFR-J
REACTION TANK
LIME O
FEED PUMPS
STORAGE TANK
LIME FEEDTANK
MAKEUP
WATER
TO DISPOSAL*
DUNDERFLOW PUMPS
RECYCLE RECYCLE
PUMPS RETC;NCKLE
M.E.WASH
PUMP
Figure 3. Simplified process flow diagram of Cane Run 5 FGD system.
-------
flows upward through each vertical spray tower at a rate of 133
m /s (261,000 acfm). Slurry is sprayed countercurrent to the
flue gas flow from three levels of spray nozzles. The saturated,
scrubbed gas stream then passes through a mist eliminator section
situated at the top of each spray tower. Each mist eliminator
consists of two stages of chevrons preceded by a bulk entrainment
separator. Entrained droplets of moisture and slurry picked up
by the gas stream as it passes through the spray towers are
removed in the mist eliminator section.
Following passage through the mist eliminators, the cool,
saturated gas stream exits the tower and turns 90 degrees and
passes through in-line steam reheaters. Each module is equipped
with four vertical rows of tubes which use steam to raise the
temperature of the scrubbed gas stream approximately 22°C (40°F)
above the water dewpoint as it leaves the spray tower. The
treated gas stream then exits each spray tower at 142 m /s
(300,000 acfm) and 74°C (166°F) and passes through an induced-
draft booster fan. Each fan is provided to overcome the gas-side
pressure drop encountered through the scrubber module and asso-
ciated ductwork, which amounts to 1.4 kPa (5.5 in. H2O). The
reheated, scrubbed gas stream is then discharged to the atmos-
phere through the existing stack.
The ductwork and dampers provided with the FGD system allow
gas to partially or totally bypass the scrubber modules. Seal-
air louver dampers are installed at the inlet of each scrubber
module and its associated bypass duct, and at the suction and
discharge sides of each booster fan.
Slurry Handling—
Scrubbing slurry is delivered to each spray tower by one
1135 liter/s (18,000 gpm) spray pump. Spent scrubbing slurry
falls by gravity to the bottom of each spray tower and drains to
a common reaction tank with a liquid capacity of 1,779,000 liters
(475,000 gal). The reaction tank is equipped with two top-entry
agitators located at tank quarter points which keep the slurry
30
-------
solids in suspension. Mounted inside the tank is a perforated
plate strainer located upstream of the spray pump suction lines.
The strainer is equipped with an automatic back washer that
prevents plugging and facilitates removal of the over-sized
particles via the effluent bleed.
Fresh carbide lime slurry and makeup water are added direct-
ly to the reaction tank in order to maintain system chemistry and
liquid inventory. The fresh carbide lime slurry regenerates the
sulfur dioxide absorbent and precipitates waste solids which are
removed from the slurry loop. The fresh makeup water added to
the reaction tank is thickener overflow liquor supplemented by
filtered river water. The waste solids which are precipitated in
the reaction tank are removed by an effluent bleed line which
gravity feeds to a thickener. The effluent bleed is operated so
that a 10 percent solids slurry is continuously maintained in the
reaction tank.
Solids Concentrating—
The effluent from the reaction tank is bled by gravity to
the center well of a 34-m (110-ft) diameter thickener. At design
operating conditions, 36 liters/s (568 gpm) of waste slurry is
discharged to the thickener as a 10 percent solids stream. The
thickener concentrates the waste slurry to a 25 percent solids
sludge which is pumped from the bottom of the thickener to an on-
site disposal pond. In order to aid the thickening process, a
polyelectrolyte feeding system is provided to enhance precipita-
tion within the thickener. This feeding system is similar to
that provided for Cane Run 4 in that a flocculant is prepared,
mixed, and aged and transferred directly to the thickener as a
0.5 percent solution. The 5 to 7 ppm concentration of flocculant
which results in the thickener enhances the settling character-
istics of the waste solids produced by the FGD system.
Clarified overflow from the thickener is transferred by
gravity feed to a recycle tank (thickener overflow return tank)
at a rate of 12 liters/s (196 gpm). Supernatant from the sludge
31
-------
disposal pond and fresh makeup water are also added to the
recycle tank at a rate of 39 liters/s (420 gpm). This liquor is
returned to the FGD system for use as mist eliminator wash water
and to maintain system liquid inventory.
Lime Preparation and Handling Equipment—
The equipment provided for carbide lime slurry preparation
is similar to that previously described for the Cane Run 4 FGD
system. The carbide lime inventories are owned by LG&E and
located on Airco, Inc.'s property five miles up river from the
Cane Run plant. The absorbent is slurried to a 30 percent solids
concentration and shipped by barge to the plant. The slurry is
then transferred from the barges to the plant's main lime addi-
tive storage tanks by pumps. These tanks serve as storage ves-
sels for the carbide- lime slurry supplies required by all three
FGD systems operating at the plant. The absorbent is then
transferred to a crusher-disintegrator which supplies lime of
proper consistency to the additive feed tank. The crusher-
disintegrator removes any tramp solids or other foreign matter
present in the slurry. The additive feed tank is an agitated
hold tank with a 12-h retention time. This tank is located along
side the reaction tank. Slurry is transferred from the additive
feed tank to the reaction tank by centrifugal pumps through a
recirculating circuit. At design conditions, 7.8 liters/s (124
gpm) of carbide lime is fed to the reaction tank as a 30 percent
solids slurry. The flow of slurry from the additive feed tank to
the reaction tank is controlled by slurry pH, outlet sulfur
dioxide concentrations, and boiler load.
PROCESS DESIGN
Fuel
The Cane Run 4 and 5 FGD systems were designed to process
flue gas resulting from the combustion of pulverized coal in the
32
-------
boilers. The coal is a high sulfur, bituminous grade which
originates from the Star Mine of the Peabody Coal Company. Table
14 presents fuel specifications of the performance coal.
FGD Design Criteria
The design criteria of the Cane Run 4 and 5 FGD systems,
including inlet and outlet gas conditions and removal efficien-
cies, are summarized in Table 15.
Scrubber Modules
The FGD systems installed on Cane Run 4 and 5 are each
equipped with two modules. The Cane Run 4 scrubber module design
consists of a vertical absorber tower preceded by a quencher and
flooded elbow. The absorber tower is a single-stage mobile bed
contactor which contains a fluid bed packing of solid spheres.
The spheres are directed vertically through a circular path in
the mobile bed contactor in order to maximize slurry contact
surface area and remove the reaction products which build up on
the spheres. Figure 4 presents a cutaway view of the mobile bed
contactor, showing the arrangement of the internals and illus-
trating the actual sphere path.
The Cane Run 5 scrubber module design consists of a vertical
spray tower absorber. Slurry is sprayed countercurrently to the
flue gas flow from three levels of ceramic spray nozzles. Each
elevation of sprays is composed of a grid of 28 nozzles uniformly
spaced throughout the tower cross sections. The spray tower has
a total contact zone of 5.5 m (18 ft) which provides a gas
residence time of 2.25 seconds for sulfur dioxide removal.
Table 16 summarizes the design parameters and operating
conditions of the Cane Run 4 and 5 scrubber modules.
Mist Eliminators
Each scrubber module is equipped with its own separate mist
eliminator which is situated in the top portion of the absorber
tower horizontal to the gas flow. For both systems, a chevron-
type mist eliminator design is used. Originally, Cane Run 4 was
33
-------
TABLE 14. SPECIFICATIONS OF CANE RUN PERFORMANCE COAL
Cane
Run
4
Cane
Run
5
Fuel
Grade
Source
Maximum consumption, Mg/h (tons/h)
Higher heating value, J/g (Btu/lb):
Maximum
Average
Minimum
Ultimate analysis, percent by weight:
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Chlorine
Ash
Moisture
Coal
Bituminous
I
Kentucky
76 (84)
27,700
25,600
24,900
79 (87)
(11,900)
(11,000)
(10,700)
62.93
4.18
5.84
1.37
4.14
0.07
14.10
9.59
I
34
-------
TABLE 15. DESIGN CRITERIA OF CANE RUN FGD SYSTEMS
Category
Volume, m^/s (acfm)
Temperature, °C (°F)
Weight, Mg/h (Ib/h)
Density, kg/m3 (lb/ft3)
Sulfur dioxide, kg/h (Ib/h),
ng/J (lb/106 Btu)
Particulate matter, Mg/J (lb/106 Btu)
Sulfur dioxide removal efficiency,
percent
Particulate matter removal efficiency,
percent
Inlet gas conditions
Cane Run 4
346 (734,000)
163 (325)
980.2
(2,161,000)
0.787 (0.491)
6,309 (13,910)
2,885 (6.71)
43 (0.1)
Cane Run 5
307 (650,000)
163 (325)
959.3
(2,115,000)
0.868 (0.054)
5,652 (12,460)
2,885 (6.71)
43 (0.1)
85
0
Outlet gas conditions3
Cane Run 4
275 (583,000)
53 (127)
1,023
(2,256,000)
1.030 (0.065)
947 (2,087)
434 (1.01)
43 (0.1)
Cane Run 5
265 (562,000)
52 (126)
1,003
(2,212,000)
1.052 (0.066)
844 (1,860)
434 (1.01)
43 (0.1)
85
0
U)
en
All values for outlet gas conditions given prior to reheat.
-------
SCRUBBED GAS
u>
SPRAY
HEADER
MOBILE BED COMPARTMENT
ACTUAL SPHERE PATH
FLUE GAS
Figure 4. Cane Run 4 mobile bed contactor absorber and sphere path.
-------
TABLE 16. DESIGN PARAMETERS AND OPERATING CONDITIONS
OF CANE RUN SCRUBBER MODULES
Number
Type Qu
Cane Run 4
2
Cane Run 5
2
encher, flooded elbow, Spray tower
and mobile bed contactor
Configuration
Dimensions, m (ft)
Number of spray zones
Number of spray heads
Materials of construction:
Quencher
Flooded elbow
Absorber
o
Inlet flue gas volume, m /s (acfm)
Inlet flue gas temperature, °C (°F)
Flue gas velocity, m/s (ft/s)
Pressure drop, kPa (in. ^0)
Liquid recirculation rate,
liters/s (grm)
L/G, liters/m3
(gal/103 acf)
Outlet flue gas volume,
m3/s (acfm)
Outlet flue gas temperature,
°C (°F)
Vertical
6.1 x 6.1 x 8.4
(20 x 20 x 27.5)
2
5
Lined carbon steel
Lined carbon steel
Lined carbon steel
173 (367,000)
163 (325)
3-4 (10-13)
2.3 (9)
1112 (17,625)
8.6 (65)
138 (291,500)
53 (127)
Vertical
8.1 x 9.4
(26.5 x 31)
3
3
N/A
N/A
31 6L stainless
steel
154 (325,000)
163 (325)
2.1 (7)
0.12 (0.5)
1135 (18,000)
7.4 (55)
133 (281,000)
52 (126)
37
-------
equipped with open-type centrifugal mist eliminators. These were
replaced because of design and performance deficiencies. A
proprietary mist eliminator design is used in Cane Run 5. This
design consists of two stages of chevrons preceded by a pre-
collector (bulk entrainment separator), as illustrated in Figure
5. Table 17 presents design conditions and operating parameters
of the Cane Run 4 and 5 mist eliminators.
Reheaters
Each FGD system is equipped with its own set of reheaters
which raise the temperature of the scrubbed gas stream above its
dewpoint prior to discharge to the stack. Cane Run 4 is equipped
with direct oil-fired reheaters situated in the discharge ducts
at the base of the stack. Cane Run 5 is equipped with in-line
carbon steel reheaters which use extraction steam as the heating
medium. The Cane Run 4 reheaters were not installed as original
equipment. They had to be added soon after system startup be-
cause of severe corrosion which occurred in the discharge ducts
and stack. The Cane Run 5 reheaters are staggered vertical rows
of finned-tubes situated in the horizontal discharge duct of each
absorber. Table 18 summarizes the design parameters and operat-
ing conditions of the Cane Run 4 and 5 reheaters.
Pumps
Each FGD system is equipped with pumps which encompass the
liquid circuit battery limits from lime preparation to waste
solids disposal. Tables 19 and 20 summarize the design param-
eters and operating conditions of the major pumps installed on
Cane Run 4 and 5, respectively.
Reaction Tanks
The Cane Run 4 and 5 FGD systems are equipped with external
reaction tanks which provide slurry holdup to facilitate comple-
tion of chemical reactions, bleed of waste solids, and collection
of fresh slurry and return water streams. Cane Run 4 is equipped
38
-------
CHEVRON VANES
SECOND
STAGE
FIRST
STAGE
WASHER
LANCE
BULK ENTRAPMENT
SEPARATOR
Figure 5. Cane Run 5 mist eliminator design.
39
-------
TABLE 17. DESIGN PARAMETERS AND OPERATING
CONDITIONS OF CANE RUN MIST ELIMINATORS
Category
Total number
Number per module
Type
Configuration3
Shape
Number of stages
Number of passes per stage
Freeboard distance, m (ft)c
Distance between stages, m (ft)
Distance between vanes, cm (in.)
Materials of construction
Wash system:
Water source
Point of collection
Wash direction
Wash frequency
Wash rate, liters/s (gpm)
Wash pressure, MPa (psig)
Superficial gas velocity, m/s (ft/s)
Pressure drop, kPa (in. H20)
Cane Run 4
2
1
Chevron
Horizontal
Z-shape,
120-degree bends
2
3
1.8 (6.0)
NA
2.5-3.8 (1.0-1.5)
31 6L stainless
steel
River water
Makeup water tank
Overspray and
underspray
Intermittent-
2 min every 5 min
5.0 (80)
5.9 (70)
3.0 (10)
0.12-0.30
(0.5-1.2)
Cane Run 5
2
1
Chevron
Horizontal
A-frame
3b
2
NAd
NA
NA
FRP
Blended water
(river, pond
supernanant, and
thickener overflov
Recycle tank
Overspray and
underspray6
Intermittent-
once
every 24 hr.
32 (500)
6.6 (80)
2.1 (7)
0.12
(0.5)
Relative to gas flow.
Includes bulk entrainment separator.
c Distance between absorption zone and mist elimination section.
d Not available.
e Four water sprays (retractable soot blowers) are located between the bulk
entrainment separator and first stage of cheverons. The blower lances rotate
360 degrees while traversing.
40
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TABLE 18. DESIGN PARAMETERS AND OPERATING CONDITIONS
OF CANE RUN REHEATERS
Cane Run 4
Cane Run 5
Total number
Number per module
Type
Location
Heating medium
Temperature elevation, °C (°F)
Heat exchangers:
Number of rows
Number of tube circuits
Configuration
Tube size, cm (in.)
Materials of construction
2
1
Indirect, in-line
Discharge ducta
Steam
22 (40)
4
34
Vertical, staggered,
spiral-finned tubes
4.44 (1.75)
Carbon steel
2
1
Direct combustion
Discharge duct
No. 2 fuel oil
28 (50)
N/AC
a Located in ducts as they enter the base of the stack.
b Located in ducts at the top of the absorber towers.
c Not applicable.
41
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TABLE 19. DESIGN PARAMETERS AND OPERATING CONDITIONS OF CANE RUN 4 PUMPS
Service
Slurry
reclrculatlon
Slurry feed
Slurry bleed
Thickener
underflow
Thickener
overflow
Number
6
2
4
2
2
Manufacturer
Denver
Denver
Robbing
Meyers
Goulds
Morris
Model
2XNG 12H-CDR
3196
Materials
Casing
Rubber- lined
Cast Iron
Rubber-lined
Rubber-lined
(neoprene)
Rubber- lined
Impeller
Rubber- lined
Cast Iron
Rubber-lined
H1-A alloy
Rubber- lined
Drive
Belt
Belt
Variable
Variable
Direct
Performance*
Motor,
kH (hp)
244 (300)
7.5 (10)
5.6 (7.5)
15 (20)
18.7 (25)
Capacity,
11ters/s (gpm)
371 (5875)
12.6 (200)
13.9 (220)
12.6 (200)
38 (600)
5 peed,
rpin
1000
1800
NAb
1800
1800
Head,
m (ft)
36.6 (120)
22.9 (75)
18.3 (60)
35.1 (115)
30 (100)
Solids.
percent
10
30
10
25
0
Operation
6 operational,
no spares
1 operational,
1 spare
2 operational,
2 spares
1 operational,
1 spare
1 operational,
1 spare
"Per pump.
bNot available.
-------
TABLE 20. DESIGN PARAMETERS AND OPERATING CONDITIONS OF CANE RUN 5 PUMPS
Service
Slurry
recirculation
Slurry feed
Thickener
underflow
Recycle water
Number
2
2
2
2
Type
Centrifugal
Centrifugal,
constant speed
Positive displacement,
variable speed
NA
Materials of
construction
Rubber-lined
NAa
NA
NA
Performance
Capacity,
liters/s (gpm)
1,100
(18,000)
7.8
(124)
15.6
(248)
38.9
(616)
Solids,
percent
10
30
25
0
PH
9-10
11-12
9-10
8-10
Operation
2 operational ,
no spares
2 operational ,
no spares
1 operational ,
1 spare
1 operational,
1 spare
CO
Not available.
-------
with one rectangular reaction tank structure. This structure is
divided into two discrete and separate reaction tanks by a
partition running lengthwise through the tank structure. Each
separate reaction tank services only one of the two scrubber
modules. Further, each separate reaction tank is subdivided into
three compartments by two partitions. Each compartment repre-
sents a separate reaction area and is equipped with its own top-
entry agitator, pH monitor, and level control. Each separate
reaction tank has a liquid capacity of approximately 1,703,000
liters (450,000 gal) which provides a retention time of approxi-
mately 25 minutes (a little more than 8 minutes per compartment).
A simplified diagram of the Cane Run 4 reaction tank arrangement
is provided in Figure 6.
Cane Run 5 is equipped with a single 1,779,000 liter (470,000
gal) reaction tank which is common to the scrubber modules. This
capacity provides a slurry retention time of approximately 10
minutes. Two top-entry agitators located at tank quarter points
keep the slurry solids in suspension. A strainer is mounted
inside the reaction tank upstream of the spray pump suction
lines. This in-tank strainer is essentially a perforated plate
which protects the spray nozzles from plugging. An automatic
back washer prevents the strainer from plugging. A simplified
diagram of the in-tank strainer arrangement in the reaction tank
is provided in Figure 7. Table 21 provides a summary of the
design parameters and operating conditions of the Cane Run reac-
tion tanks.
Thickeners
Each FGD system is equipped with a thickener which concen-
trates the solids in the spent slurry from 10 to 25 percent by
weight prior to final disposal. Both thickening processes rely
on flocculants to enhance solids settling characteristics. The
liquor recovered by the thickeners is collected in surge tanks
and returned to each system's respective reaction tank. Table 22
provides a summary of the design parameters and operating condi-
tions of the Cane Run thickeners.
44
-------
30 m
(100 ft )
15 m
( 50 ft )
MODULE A
REACTION TANK
U1
-RETURN
SECTION
7.4 m
( 24.25 ft )
FEED SECTION
•MODULE B
REACTION TANK
Figure 6. Arrangement of the Cane Run 4 reaction tank.
-------
OSCILLATING AND
RETRACTING
WASH LANCE MECHANISM
WASH WATER
PERFORATED PLATE
50% OPEN AREA
SOLID PLATE
SPRAY PUMP
SUCTION
Figure 7. Cane Run 5 in-tank strainer arrangement.
46
-------
TABLE 21. DESIGN PARAMETERS AND OPERATING CONDITIONS
OF CANE RUN REACTION TANKS
Cane Run 4
Cane Run 5
Number
Capacity, liters (gal)
Retention time, minutes
Materials of construction
Agitators:
Number
Position
Motor, kW (hp)
1,703,000 (450,000)
25
Reinforced concrete
Top entry
37 (50)
1
1,779,000 (470,000)
10
Rubber-lined
carbon steel
Top entry
56 (75)
47
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TABLE 22. DESIGN PARAMETERS AND OPERATING CONDITIONS
OF CANE RUN THICKENERS
Number
Dimensions:
Depth, m (ft)
Diameter, m (ft)
Materials of construction
Feed stream conditions:
Thickener inlet:
Flow, liters/s (gpm)
Solids, percent
PH
Thickener outlet:
Flow, liters/s (gpm)
Solids, percent
PH
Thickener overflow:
Flow, liters/s (gpm)
Solids, percent
pH
Cane Run 4
1
4.3 (14)
25.9 (85)
Rubber- lined
carbon steel
30 (475)
10
9-10
18.0 (285)
25
9-10
11.6 (185)
0
9-10
Cane Run 5
1
NAa
33.5 (110)
Rubber-lined
carbon steel
' 28. (450)
10
9-10
15.6 (248)
25
9-10
12.4 (196)
0
9-10
Not available.
48
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Process Control
Both Cane Run FGD systems are equipped with indicators, con-
trols, and alarms which automatically monitor and control the
operating conditions of the processes. Included are sulfur
dioxide gas analyzers and temperature indicators for all gas in-
let and outlet streams, magnetic flow meters for all liquid
slurry streams, level indicators for all tanks, and pH and den-
sity meters for all reaction tanks.
Process chemistry is maintained and controlled primarily by
monitoring slurry pH in the reaction tank and regulating the flow
of additive to the tank as a function of this reading. For Cane
Run 4, pH is measured in each section (compartment) of the reac-
tion tank and automatically maintained at the control level. In
the return section of the reaction tank, slurry pH is normally
maintained between 4 and 6 as spent slurry from the scrubber is
mixed and reacts with fresh carbide lime slurry. In the middle
section of the reaction tank, slurry pH stabilizes as reactions
started in the return section go to completion. Slurry pH is
normally maintained between 8 and 9 in this section. In the feed
section, all chemical reactions are completed and the slurry pH
is trimmed to provide a pH level of 9.0 for slurry recirculated
to the scrubber module. The pH levels measured in the reaction
tank sections are characterized through a function generator.
The function generator compares the output signals from the pH
probes and corrects for any deviations in order to maintain a
recycle slurry pH of 9.0 + 0.1.
For Cane Run 5, pH is measured in the common reaction tank
by one of two pH probes. Each probe is equipped with an ultra-
sonic cleaning device in order to assure dependable operation.
An absorbent flow signal is provided by the pH probe which
regulates the operation of a slurry control valve (C-E Invalco
slurry control valve). This signal, along with the outlet
sulfur dioxide and boiler load signals, regulates the flow of
absorbent into the reaction tank in order to maintain a pH of 9
to 10 in the recycle slurry.
49
-------
Carbide Lime
The additive requirements for both FGD systems are met
through the use of carbide lime, a waste product from the manu-
facture of acetylene. The carbide lime inventories are obtained
from Airco , Inc . , an acetylene manufacturing firm located approx-
imately 8 km (5 miles) up river from the Cane Run station. Table
23 provides a summary of the chemical composition of the carbide
lime used at Cane Run.
PROCESS CHEMISTRY: PRINCIPAL REACTIONS
The chemical reactions involved in the Cane Run carbide lime
PGD systems are highly complex. Although details are beyond the
scope of this discussion, the principal chemical reactions are
described in the paragraphs that follow.
The overall reactions involved in lime scrubbing can be
expressed as:
CaO + SO2 - +• CaSO3
CaO + SO2 + 1/2 02 - *- CaS04
The various chemical steps involved in these overall reactions
include absorption, neutralization, regeneration, oxidation, and
precipitation .
The sulfur dioxide (SO2) in the flue gas diffuses from the
gas phase to the liquid phase. The absorbed sulfur dioxide
to form s
SO2 (aq.)
reacts with water to form sulfurous acid (H2SO_) .
(aq.)
In addition, carbon dioxide (CO-) present in the flue gas is also
absorbed into the liquid phase, forming carbonic acid (H
C02 i < * C02 (aq.)
(aq.)
50
-------
TABLE 23. CHEMICAL COMPOSITION OF CANE RUN CARBIDE LIMEC
Compound
Ca(OH)2
CaOb
CaC03
Si02
A1203
MgO
S
P
CC
Undetermined
Percent by weight
92.50
70.01
1.85
1.50
1.40
0.20
0.07
0.15
0.01
0.25
2.07
Source: Airco catalog (1969).
^Available calcium oxide.
"Free carbon.
51
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The sulfurous acid formed during absorption in the scrubber is
neutralized by dissolved alkali [sulfite (SO3~) and bicarbonate
(HCO~) ions] present in the scrubbing slurry.
S03 * - 5 2HS03
H SO + HC03
During the absorption and neutralization steps, some oxidation
occurs in the system which results in the presence of sulfate ion
(SO =) in the scrubbing liquor. This also occurs to a lesser
extent by gas phase oxidation of sulfur dioxide and its sub-
sequent ionization in the scrubbing liquor.
2
2 S03 i +=^ 2S03 (aq.)
2
2
However, the liquid-phase oxidation of sulfite and bisulfite
(HSO ~) accounts for the majority of sulfate formed in the
.
+ 2H+
The spent scrubbing slurry, which contains primarily soluble
bisulfite, is discharged to the reaction tank where fresh carbide
lime slurry [Ca(OH) ] reacts and neutralizes the reaction pro-
ducts formed in the scrubber.
++
Ca(OH)2 + 2HS03 - > Ca
Ca(OH)2 + 2H2C03-« - ^ Ca++ + 2HCO3~ + H2O
The dissolution of carbide lime in the reaction tank results in
alkali regeneration and the precipitation of reaction products.
This latter step occurs as a result of an increase in scrubbing
liquor pH and calcium ion (Ca++) concentration caused by carbide
52
-------
lime dissolution. The reaction product formed in the scrubbing
process is a mixed crystal of calcium sulfite and calcium sul-
fate.
Ca++ + (1-X)S03= + (X)S04= + 1/2 H20 < >
[(1-X) CaS03 - (X) CaSO4l -1/2 H20 4-
The calcium sulfite/calcium sulfate formed is a solid solution in
which the value of X (the ratio of sulfate to total sulfur in the
solution) is about 0.16. Thus, any sulfate formed in the scrub-
bing process is removed in the coprecipitate. This will occur as
long as the maximum sulfite oxidation in the process is 16 per-
cent. Levels of oxidation well below the maximum limit have been
experienced at Cane Run (and Paddy's Run) because of the presence
of oxidation inhibitors in the carbide lime.
53
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SECTION 4
FGD SYSTEM PERFORMANCE
OPERATING HISTORY AND PERFORMANCE
Cane Run 4
The Cane Run 4 FGD system was first placed in service on
August I, 1976. After approximately 2 weeks of operation a
number of major operating problems were encountered which limited
system capacity, service time, and removal efficiency. The major
initial problem involved excessive pressure drop across the
system. This limited the system's maximum gas treating capacity
to approximately 150 MW of equivalent electrical generating
capacity. This problem, in addition to problems encountered with
the system's spray nozzles and recirculation pumps, resulted in a
number of various modifications which commenced in early Sep-
tember 1976 and continued intermittently throughout the remainder
of the year. These modifications enabled the system to operate
at full load conditions and achieve an operability of 90 percent
for the August to December 1976 period. Sulfur dioxide removals,
however, remained below the design level of 85 percent.
From early January until early March 1977, the system was
operated intermittently because of curtailment of carbide lime
supplies. This occurred because of the severe winter weather
conditions which caused the Ohio River to freeze, thus suspending
all barge deliveries of carbide lime to the station. During this
period, the system was operated in a slurry-recycling mode (with-
out flue gas) to prevent freeze-ups in the associated piping. At
two week intervals flue gas was passed through the system in
order to warm-up the recycling slurry.
54
-------
Lime slurry supplies were reestablished in early March and
the system was returned to service from mid-March to mid-April
1977 (operability of approximately 90 percent). During the
period, the system was operated in various test modes in antici-
pation of a basic redesign of the system. System redesign was
required because of unsatisfactory sulfur dioxide removals, in-
efficient mist elimination, and lining failures in the outlet
ducts and stack. From April 18, 1977, to July 17, 1977, major
modifications were made in order to improve system performance
with respect to the problem areas mentioned above. Following its
return to service, the system successfully completed compliance
testing on August 3 and 4, 1977. Since the completion of these
major modifications,, system operability has averaged approxi-
mately 90 percent for the past two years. Periods of system
inactivity have resulted primarily from external conditions such
as severe winter conditions, a coal strike, boiler and turbine
repairs, and scheduled annual unit overhauls.
A summary of the performance of the Cane Run 4 FGD system is
provided in Table 24.
Cane Run 5
The Cane Run 5 FGD system was first placed in service on
December 28, 1977. Immediately following initial startup, the
FGD system was taken out of service in order to complete con-
struction and correct some problems encountered during startup.
On March 24, 1978, the FGD system was returned to service.
During the course of the months that followed, various perform-
ance tests were conducted in order to demonstrate contractual
guarantees and compliance with air emission regulations. These
tests were successfully completed by mid-July 1978.
The operability of the FGD system averaged approximately 83
percent for the period of April through December 1978. During
the first 9 months of 1979, the FGD system's operability has
averaged approximately 80 percent. Although some downtime can be
attributed to severe winter weather conditions which caused
55
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TABLE 24. CANE RUN 4 FGD SYSTEM PERFORMANCE SUMMARY:
AUGUST 1976 TO SEPTEMBER 1979
tate
Aug. 1976
Sep. 1976
Oct. 1976
Nov. 1976
Dec. 1976
Jan. 1977
Feb. 1977
Mar. 1977
Apr. 1977
May 1977
June T977
July 1977
Aug. 1977
Sep. 1977
Oct. 1977
Nov. 1977
Dec. 1977
Jan. 1978
Feb. 1978
Mar. 1978
Apr. 1978
May 1978
June 1978
July 1978
Aug. 1978
Sep. 1978
Oct. 1978
Nov. 1978
Dec. 1978
Jan. 1979
Feb. 1979
Mar. 1979
Apr. 1979
Hay 1979
June 1979
July 1979
Aug. 1979
Sep. 1979
Period
hours
744
720
744
720
744
744
672
744
720
744
720
744
744
720
744
720
744
744
672
744
720
744
720
744
744
720
744
720
744
744
672
744
720
744
720
744
744
720
Boiler
hours
740
720
600
FGD
hours
666
650
540
OperablHty
90.0
90.0
90.0
95.0
90.0
Utilization
90.0
90.0
73.0
Shut down because of severe winter weather conditions
Shut down because of severe winter weather conditions
432
358
83.0
48.1
Shut down because of FGD system modifications
Shut down because of FGD system modifications
Shut down because of FGD system modifications
360
657
529
677
483
715
742
324
588
524
662
453
60S
494
90.0
94.0
99.0
98.0
94.0
85.0
67.0
43.6
93.0
99.0
89.0
63.0
82.0
67.0
Shut down because of coal shortage due to strike
264
303
352
720
687
744
136
249
303
115
715
678
701
138
94.0
100.0
35.0
99.0
99.0
94.0
100.0
Shut down because of boiler tube repairs
432
420
97.0
34.0
47.0
12.0
99.0
91.0
94.0
19.0
58.0
Shut down because of turbine and boiler tube repairs
Shut down because of turbine and boiler tube repairs
Shut down because of turbine and boiler tube repairs
Shut down because of turbine and boiler tube repairs
Shut down because of turbine and boiler tube repairs
Shut down because of turbine and boiler tube repairs
266
701
744
123
692
664
46.2
99.0
89.0
Shut down because of boiler tube repairs
17.1
92.0
89.0
56
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interruptions of lime deliveries to the plant, the majority of
FGD system inactivity has been caused by reheater tube failures.
A summary of the performance of the Cane Run 5 FGD system is
provided in Table 25.
PROBLEMS AND SOLUTIONS
Problems were encountered with both FGD systems during and
subsequent to their initial startup. In the case of Cane Run 4,
the problems were so severe as to require a 4-month shutdown for
a basic redesign of the FGD system. The major operating problems
encountered by both FGD systems, as well as solutions and system
modifications, are described for each system in the paragraphs
that follow.
Cane Run 4
As previously mentioned, the Cane Run 4 FGD system encoun-
tered a number of major operating problems shortly after initial
startup. Pressure drops in excess of design were encountered
which limited the system's maximum gas treating capacity to
approximately 150 MW of equivalent electrical generating capac-
ity. This was attributed to gas flow distribution problems in
the ducts and mist eliminators. As such, gas turning vanes were
installed in the quenchers, flooded elbows, just below the mobile
bed contactors, just above the mist eliminators, and at the base
of the stack. Sections of the original radial vane mist elimi-
nators were cut out and removed.
These modifications remedied the excessive pressure drop
problem. However, subsequent problems were soon encountered with
solids carryover from the scrubbers because of the reduction in
mist elimination efficiency. In addition, sulfur dioxide removal
efficiencies well below guarantee levels were measured at full
load. With respect to sulfur dioxide removals, values of 90 to
92 percent were achieved for boiler loads up to 100 MW. However,
as boiler load increased the sulfur dioxide removals decreased to
82 to 85 percent for 120 MW and 70 percent for full load.
57
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TABLE 25. CANE RUN 5 F6D SYSTEM PERFORMANCE SUMMARY: DECEMBER 1977 TO SEPTEMBER 1979
Date
Dec. 1977
Jan. 1978
Feb. 1978
Mar. 1978
Apr. 1978
May 1978
June 1978
July 1978
Aug. 1978
Sep. 1978
Oct. 1978
Nov. 1978
Dec. 1978
Jan. 1979
Feb. 1979
Mar. 1979
Apr. 1979
May 1979
June 1979
July 1979
Aug. 1979
Sep. 1979
Period
hours
744
744
672
744
720
744
720
744
744
720
744
720
744
744
672
744
720
744
720
744
744
720
Boiler
hours
F6D
hours
Shut down for c<
Operabllity
Dmpletion of constri
Utilization
iction
Shut down for completion of construction
Shut down for completion of construction
Shut down for completion of construction
699
432
685
632
540
609
530
253
654
693
477
596
360
433
544
583
613
469
648
364
590
506
464
485
509
238
302
467
337
428
357
365
419
420
540
392
97.0
84.0
86.0
80,0
86.0
80.0
96.0
94.0
46.2
67.4
70.6
71.8
99.2
84.3
77.0
72.0
88.0
84.0
90.0
49.0
82.0
68.0
62.0
67.0
71.0
33.0
40.6
62.8
50.1
57.5
49.6
49.1
58.2
56.0
73.0
54.0
oo
-------
In analyzing the sulfur dioxide removal problem, LG&E and
AAF determined that the system's original design L/G ratio of 5.2
liters/m (39 gal/1000 acf) was insufficient. In an attempt to
increase L/G, the spare recirculation pump provided for each
scrubber module was placed in service. By coupling the spare
pump into the slurry circuit of each scrubber, the L/G should
have increased to approximately 8.6 liters/m (65 gal/1000 acf).
Although each recirculation pump has a rated capacity of approx-
imately 370 liters/s (5875 gpm), a total flow increase of only 31
to 38 liters/s (500 to 600 gpm) was realized. This occurred
because of excessive pressure drops across the spray headers. To
correct this problem, the original plastic spinner-vane spray
nozzles were replaced with a different nozzle design constructed
of ceramic. This modification decreased pressure drop, permit-
ting the slurry flow rate to increase to a level which approached
an equivalent L/G of approximately 8 liters/m (60 gal/1000 acf) .
Although sulfur dioxide removal levels improved, they still re-
mained below satisfactory levels when the unit was operated at
full load.
Because of these continuing problems, LG&E and AAF performed
a number of major modifications to the system's design during a
4-month outage in the spring and summer of 1977. These modifi-
cations essentially amounted to a basic redesign of the system in
order to increase sulfur dioxide removal, improve mist eliminator
efficiency, and correct a number of material failures with the
coatings applied to the outlet ducts and stack. These modifica-
tions are briefly summarized in the following:
1. A new spray header system was installed above the
original mobile bed contactor spray headers. Underbed
sprays were also added just below the mobile bed con-
tactor. These changes improved the distribution of gas
flowing through the mobile bed, improved the circula-
tion of the balls through the mobile bed contactor
compartments, and increased the L/G of the system to
approximately 8.6 liters/m3 (65 gal/1000 acf). This
has provided a superior slurry/gas contacting mechanism
which has contributed to improved sulfur dioxide re-
moval efficiency.
59
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2. In conjunction with a new spray header arrangement, the
pH/slurry feed control system was significantly modi-
fied in order to improve chemical control and sulfur
dioxide removal. The pH meters, which are dip-type
probes situated in the reaction tank compartments, were
replaced with more reliable units. The original meters
tended to drift 3 minutes after calibration. The con-
trol level of the pH of the scrubbing slurry was in-
creased from approximately 8.5 to 9.0.
3. Each scrubber module was originally equipped with an
open-type centrifugal mist eliminator which was located
in the top of the absorber tower downstream of the
mobile bed contactor compartments. These mist elimina-
tors consisted of stationary, widely-spaced, curved
vanes which directed the slurry droplets against the
mist eliminator shell. The flue gases then entered a
"necked-out" open cylindrical area where a reduction in
flue gas velocity caused the remaining droplets present
in the gas stream to drop out and drain downward along
the mist eliminator shell through a drain box and into
the drain lines of each absorber tower. Problems
associated with excessive pressure drop across these
mist eliminators required sections of the radial-vane
assembly to be removed. This subsequently decreased
mist eliminator efficiency and caused an increase in
the slurry solids carried over in the scrubbed gas
stream. The radial vane assembly was then removed
entirely from each absorber tower by cutting 4-cm (18-
in.) holes into the top of the assembly and replacing
it with 2 stages of 3-pass chevron mist eliminators.
The wash water spray system associated with the centri-
fugal design was also replaced with a system compatible
with the chevron design. Since these changes were
completed, mist eliminator efficiency has improved and
the chevrons have operated without any buildup of
solids on the vanes.
4. Direct oil-fired reheat burners were installed in the
exit ductwork as it enters the stack. These burners
fire No. 2 fuel oil and the combustion products are
mixed with the scrubbed gas stream to raise its tem-
perature a maximum of 28°C (50°F). Originally, reheat
was not included in this system. However, this "wet
stack" approach, coupled with the initial problems
associated with low sulfur dioxide removal and mist
elimination inefficiency, ultimately contributed to the
lining failures which occurred in the mist eliminator
shells, discharge ducts, and stack.
60
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5. As indicated above, the linings used in the mist elim-
inators, discharge ducts, and stack were severely
corroded and required replacement. A Carboline liner
was originally used on the mist eliminator shells and
discharge ducts. This material was severely blistered
and was replaced with Plasite 4005. Acid brick was
originally used to line the concrete shell of the
unit's existing stack. Failure of this material re-
quired all the brickwork in this 76-m (250-ft) stack to
be replaced with Precrete G-8 spray-applied to wire
mesh.
These major modifications were originally projected to re-
quire only 2 months for completion during the annual unit over-
haul. However, the lengthy installation of the new lining
materials, especially the Plasite 4005, required a 2-month ex-
tension for completion of this work.
On July 17, 1977, the FGD system was returned to service.
On August 3 and 4, 1977, the system successfully completed a
series of performance tests conducted by EPA. Since that time,
the FGD system has operated at a high level of mechanical reli-
ability and has been continuously in compliance. The only
problem of any major proportion which has been encountered since
restart involves the operation of the guillotine dampers which
are situated at the inlet, cutlet, and bypass ducts of each
scrubber module. The problem with the operation of these dampers
involves their inability to track smoothly without excessive
sticking during raisings and lowerings. Minor modifications to
the guillotine gate assemblies have since corrected this problem.
Cane Run 5
The initial and subsequent operation of the Cane Run 5 FGD
system was also accompanied by problems. However, unlike Cane
Run 4, most of these problems were of a minor variety normally
encountered during FGD system startup. Some of the problems and
solutions worth noting are discussed in the paragraphs that
follow.
61
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During startup, operating difficulties with the louver
dampers were encountered which at first were attributed to under-
sized drives. Subsequent analysis revealed, however, that the
difficulties were related to a combination of linkage adjustment,
sealing strip alignment, and lubrication deficiencies. During
periods when one or both scrubber modules were bypassed, a small
amount of gas leakage occurred that limited access to the mod-
ules. This was caused by a low positive flue gas pressure of
approximately 0.1 kPa (0.5 in H2O) or less which was produced at
the base of the stack.
In order to correct this problem, adjustments were made to
the linkages, sealing strips, and lubrication systems. In
addition, a damper seal air system was added which provides seal
air to each louver damper in the system. This insured 100 per-
cent flue gas sealing during bypass and permitted safe access to
the scrubber modules for inspection and maintenance.
The recirculation pumps encountered some minor difficulties
in the form of scoring of the shaft sleeves shortly after start-
up. These failures were the result of low seal water flow to the
packing glands. The original glands were designed for low flows
during low load operations in order to minimize the dilution of
slurry solids by the fresh water used for pump seals. This
design, however, was sensitive to minor flow variations caused by
the straining of river water for use as pump seal water. Becuase
of these problems the following remedial action was taken: (1)
the scored shaft sleeves were replaced and (2) the original
glands were replaced with standard glands of higher flow rates in
order to accommodate the flow variations. This modification
improved component reliability and did not present any problems
with respect to solids control in the recycled scrubbing slurry.
The reagent feed/pH control system has performed as designed
with the exception of reliable measurement of reaction tank pH.
The pH of the recirculated slurry as it entered the absorber
spray headers was higher than measured by the pH probe in the
62
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reaction tank. As such, excessive absorbent feed rates resulted
in a higher reagent consumption and lower reagent utilization
than had been designed. Although stable control of slurry pH was
maintained, the probe was relocated in order to more accurately
reflect the pH of the scrubbing slurry as it entered the ab-
sorbers, thus preventing excessive feed of absorbent to the
system.
The most significant problem encountered by the system to
date has involved the operation of the reheaters. These re-
heaters are in-line, spiral-finned, carbon steel heat exchangers
which use extraction steam as the heating medium. Leaks in both
bundles were detected shortly after startup and were repaired on
an individual basis. Analysis of these failures revealed de-
fective welds in the unfinned tubing at the tube return bends.
Although repairs were successfully completed on an individual
basis, a complete rework of the affected shop welds was performed
to insure no weak spots remained.
Other minor problems which were encountered during startup
included hardware malfunctions, incorrect instrument calibration,
and plugging from construction debris. The startup of the
auxiliary equipment such as pumps, agitators, booster fans, and
the thickener went routinely.
REMOVAL EFFICIENCIES
As previously mentioned, both FGD systems successfully com-
pleted performance testing to demonstrate contractual guarantees
and compliance with sulfur dioixde air emission regulations.
Both systems are designed to remove 85 percent of the inlet
sulfur dioxde and comply with the Federal new source performance
standard (NSPS) of 516 ng/J (1.2 lb/106 Btu)* when 4 percent
sulfur coal is burned in the boilers. The results of these
*The Federal NSPS of the Clean Air Act of 1971
63
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performance tests, as well as other emission test results and
continuous monitoring data, are summarized in the following
paragraphs.
Cane Run 4
As previously mentioned, the FGD system was not able to
achieve design sulfur dioxide removal efficiencies when operating
at full load during initial startup. Prior to the major modifi-
cation and basic system redesign work which commenced in April
1977, a 7- to 10-day test run was completed (commenced on March
14, 1977) in which "black lime"* was used as the absorbent.
During this test, sulfur dioxide removals averaged approximately
95 percent.
On August 3 and 4, 1977, the FGD system underwent and
successfully completed performance testing. The testing, which
was performed by EPA personnel, indicated that sulfur dioxide
removal efficiencies were in the 86 to 89 percent range when coal
of 3.3 to 3.4 percent sulfur was burned in the boiler at full
load. This corresponded to an outlet emission level of approxi-
mately 334 ng/J (0.8 lb/10 Btu). These tests were repeated one
month later and confirmed that the unit was in compliance.
From mid-1977 to early 1978, the Emissions Standards and
Engineering Division of the Office of Air Quality Planning and
Standards of the U.S. EPA conducted a program to acquire sulfur
dioxide monitoring data in support of revisions to the NSPS for
fossil-fuel-fired steam-electric generators. Data from five
different utility FGD-equipped boilers were obtained at this
time. The results were reduced and published by EPA in two
2 3
volumes in August 1978. '
One of the five sites from which data were obtained was Cane
Run 4. Sulfur dioxide and oxygen gas concentrations were con-
tinuously monitored by gas analyzers placed upstream (between the
A form of carbide lime from the carbide slag operation which
contains 2 to 4 percent magnesium oxide.
64
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ESP's and booster fans) and downstream (between the reheaters and
stack) of the scrubber modules. Gas samples were taken every 15
minutes and this data was statistically analyzed for consecutive
1-hour, 3-hour, 8-hour, and 24-hour averages. After each 30-day
period of average interval data, a statistical summary was pre-
pared. Using these 30-day statistical summaries, an overall
summary of the sulfur dioxide monitoring data for the period of
July 21, 1977, to December 23, 1977, .was assembled by PEDCo
Environmental and is presented in Table 26.
As indicated by the data in this table, the total system
sulfur dioxide removal efficiencies averaged 83.2 to 83.3 percent
for Cane Run 4 for the four different averaging periods analyzed
during this program. These values compare with the system's
design sulfur dioxide removal efficiency of 85 percent.
Cane Run 5
From mid-May to mid-July 1978, a series of performance tests
were conducted in order to demonstrate contractual guarantees and
compliance with air emission regulations. In mid-May and early
June, particulate and sulfur dioxide emission measurements were
completed. However, because of procedural and data analysis
errors, the sulfur dioxide emission measurements had to be re-
peated in mid-July. A summary of the particulate and sulfur
dioxide emission tests are provided in Tables 27 and 28.
The particulate emissions were measured simultaneously at
the outlet of the ESP (scrubber inlet) and at the inlet of the
stack (scrubber outlet) in accordance with EPA Reference Method
5. The tests were run at or near full load conditions and
during some of the tests high inlet particulate loadings were
created (for test purposes only) by de-energizing the final field
of the ESP's. The results summarized in Table 27 indicate that
the scrubbers were able to provide substantial secondary particu-
late control. For example, with the unit operating at full load
and the ESP fully energized (test results for May 22 and June 1,
65
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TABLE 26. SUMMARY OF CANE RUN 4 SULFUR DIOXIDE CONTINUOUS MONITORING DATA:
JULY 21 TO DECEMBER 23, 1977*
Averaging
period,
hours
1
3
8
24
Sulfur dioxide concentration
Inlet
ng/J (lb/106 Btu)
2452
(5.702)
2455
(5.709)
2447
(5.691)
2434
(5.669)
Outlet
ng/J (lb/106 Btu)
413
(0.960)
413
(0.960)
410
(0.954)
410
(0.955)
Total system
removal efficiency,
percent
83.2
83.2
83.3
83.2
a The data which appears in this table represents a summary prepared by PEDCo
Environmental of the individual monthly statistical summaries prepared and
published by EPA.
66
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TABLE 27. SUMMARY OF CANE RUN 5 PARTICULATE EMISSION TESTS:
MAY 19 TO JUNE 7, 1978
Date
May 19, 1978
May 27, 1978
June 1, 1978
June 7, 1978
June 7, 1978
Unit load,
MW (net)
173
194
188
188
188
Particulate loading,
ng/J (lb/106 Btu)
Inlet
104.5 (0.243)
53.32 (0.124)
38.27 (0.089)
117.8 (0.274)
143.2 (0.333)
Outlet
26.23 (0.061)
21.50 (0.050)
19.35 (0.045)
15.05 (0.035)
17.63 (0.041)
Removal
efficiency, %
74.9
59.7
49.4
87.2
87.7
67
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TABLE 28. SUMMARY OF CANE RUN 5 SULFUR DIOXIDE EMISSION TESTS:
JULY 10 TO 14, 1978
Date
July 10, 1979
July 11, 1979
July 14, 1979
Unit load,
MM (net)
166-186
106-176
190
Sulfur dioxide,
ng/J (15/106 Btu)
Inlet
2481.1
(5.77)
2730.5
(6.35)
2777.8
(6.46)
Outlet
210.7
(0.49)
245.4
(0.58)
516.0
(1.20)
Removal
efficiency, %
91.5
90.9
81.4
68
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1978), the spray towers removed approximately 50 to 60 percent of
the inlet particulate. With the ESP partially de-energized,
these removals increased to approximately 75 to 88 percent. As
expected, the collection efficiency of the spray towers increased
as the loadings of the inlet particulate increased.
The sulfur dioxide emissions were measured in accordance
with EPA Reference Method 5. The results presented in Table 28
for data obtained on July 10 and 11 show average sulfur dioxide
removal efficiencies exceeding 90 percent over a unit load range
of 106 to 186 MW (net). Data obtained on July 14 indicates that
the system's sulfur dioxide removal efficiency dropped appre-
ciably (81.4 percent) as the unit's net output began to appre-
ciably exceed maximum continuous operating capacity and approach
maximum peak load. However, subsequent to the testing of July
14, it was discovered that a malfunction of the sulfur dioxide
continuous gas analyzer resulted in a reduction of the feed rate
of fresh carbide lime slurry to the system. Although slurry pH
provides primary control of lime slurry feed rate to the system,
flue gas sulfur dioxide provides a "trim" to the amount of slurry
entering the system. As such, the gas analyzer malfunction
caused an abnormally low spray liquor pH which resulted in a
decreased sulfur dioxide removal efficiency.
Based on the results of the sulfur dioxide emission tests,
it was concluded that the FGD system met all contractual guar-
antees and compliance requirements. The system demonstrated that
an average outlet sulfur dioxide concentration of 516 ng/J (1.2
lb/106 Btu) can be achieved and that the system can remove 85
percent of the inlet sulfur dioxide over the entire unit load
range.
FUTURE OPERATIONS
in addition to Cane Run 4 and 5, LG&E has recently started
up the FGD system installed on Cane Run 6. This FGD system is
part of a demonstration project sponsored by EPA in order to
69
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demonstrate the soda ash/lime dual alkali FGD process on a
commercial-sized coal-fired utility boiler. The system, which is
supplied by CEA/ADL, comprises two parallel absorber towers, soda
ash and carbide lime storage and preparation equipment, a thick-
ener and rotary drum vacuum filters, and a series of absorbent
regeneration reactors. Sulfur dioxide absorption is accomplished
by a clear liquor of soluble sodium salts containing sodium
hydroxide, sodium carbonate, sodium sulfite, and sodium sulfate.
A continuous bleed stream of spent scrubbing liquor is drawn from
the absorber recirculation loop and is sent to the absorbent
regeneration reactors. A reactor train of two reactor stages
receives the spent scrubbing liquor. Hydrated carbide lime is
added to the reactor in order to neutralize the bisulfite acidity
in the bleed stream and react with the sodium sulfite and sulfate
present in the liquor to produce sodium hydroxide. These reac-
tions precipitate mixed calcium sulfite and sulfate solids which
are concentrated in the thickener and vacuum filters to a 55 to
70 percent insoluble solids filter cake and disposed in an on-
site sludge pond.
Construction of the FGD system was completed in early 1979
and initial startup occurred in April 1979. To date, the FGD
system is still in its shakedown and debugging phase of opera-
tion. Performance testing to demonstrate contractual guarantees
and compliance with air pollution regulations has not as yet been
performed. Following the successful completion of these tests,
the system will operate through a 1-year test program to demon-
strate overall performance with respect to sulfur dioxide re-
moval, reagent consumption, power consumption, water balance,
chemical- and mechanical-related problems, waste solids prop-
erties, availability and reliability, and capital and annual
costs.
A simplified process flow diagram of the Cane Run 6 dual
alkali FGD system is presented in Figure 8. The design basis,
operating conditions, and performance guarantees for the FGD
70
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COMBUSTION AIR
EXISTING
, PRECIPITATOR i
REACTANT
(LINE SLURRY)
FEED TANK
TO ABSORBER
A-Z01
Figure 8. Simplified process flow diagram of
Cane Run 6 FGD system.
71
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system are summarized in Tables 29, 30, and 31, respectively.
Additional information regarding this full-scale dual alkali
demonstration project is available in a project manual prepared
4
by the project participants and published by EPA.
In addition to Cane Run 6, LG&E is also operating or plan-
ning four FGD systems at their Mill Creek station and two FGD
systems for two new units planned for their Trimble County
station. These facilities are briefly described in the following
paragraphs.
Mill Creek is a planned 4-unit, coal-fired, power-generating
station with 3 units currently in service. Mill Creek 1 and 2
are existing units rated at 358 MW (gross) and 350 MW (gross) ,
respectively. In accordance with consent decrees with the U.S.
EPA, Air Pollution Control District of Jefferson County, and the
Kentucky State Division of Air Pollution, LG&E has agreed to
retrofit FGD systems on both these units. Contracts were awarded
to C-E to provide FGD systems which will use either carbide lime
or commercial limestone and be in service by April 1981 and April
1982 for Mill Creek 1 and 2, respectively. These FGD systems are
currently under construction.
Mill Creek 3 and 4 are new units which must comply with
Federal NSPS. These units are rated at 442 MW (gross) and 495 MW
(gross), respectively. Mill Creek 3, which was initially placed
in service in August 1978, is equipped with a carbide lime
slurry FGD system supplied by AAF. This system contains 4
parallel scrubber modules designed to treat 100 percent of the
boiler flue gas resulting from the combustion of the same high
sulfur bituminous coal burned at LG&E's other stations. The
scrubber module design is similar to Cane Run 4 in that mobile-
bed contactors are used as the absorber towers. The system's
design sulfur dioxide removal efficiency is 85 percent. The FGD
system was initially placed in service with the boiler in August
1978 and was certified commercial in March 1979 following the
successful completion of performance testing.
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TABLE 29. CANE RUN 6 FGD SYSTEM DESIGN BASIS
Unit rating, MW:
Gross
Net
Coal (dry basis):
Sulfur, percent
Chloride, percent
Heat content, J/g (Btu/lb)
Inlet gas conditions:
Volume, nvVs (acfm)
Weight, Mg/h (Ib/h)
Temperature, °C (°F)
Sulfur dioxide, ppm
Oxygen, percent
Particulate, ng/J (lb/106 Btu)
Outlet gas conditions:
Sulfur dioxide, ppm
Particulate, ng/J (Ib/KP Btu)
Sulfur dioxide removal
efficiency, percent
300
277
5.0
0.04
25,600 (11,000)
503 (1,065,000)
1530 (3,372,000)
149 (300)
3471
5.7
< 43 (0.1)
< 200
^43 (0.1)
95
73
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TABLE 30. CANE RUN 6 FGD SYSTEM DESIGN OPERATING PARAMETERS
Normal inlet gas operating temperature, °C (°F)
Maximum inlet gas operating temperature, °C (°F)a
Normal inlet gas operating pressure, kPa (in. H20)
Inlet gas density, kg/m3 (Ib/ft^)
System pressure drop, kPa (in. H20)
Absorber flue gas velocity, m/s (ft/s)
Liquor feed to absorbers, liters/s (gpm)
L/G ratio, liters/m3 (gpm)b
Liquor active sodium concentration, M
Saturated gas flow, nrVs (acfm)
Saturated gas temperature, °C (°F)
Reheated gas flow, m3/s (acfm)
Reheated gas temperature, °C (°F)
Makeup soda ash, kg/min (lb/min)c
Lime consumption, kg/min (Ib/min)
Fuel oil consumption, liters/s (gpm)
Water consumption, liter/s (gpm)
Waste solids production, kg/m (Ib/min)
149 (300)
316 (600)
-0.3 to +0.5 (-1 to +2)
1.25 (0.078)
2.4 (9.5)
2.7 (9.0)
5.43 (8,600)
1.3 (9.9)
0.45
412 (873,000)
52 (126)
460 (974,000)
80 (176)
6.2 (13.7)
209 (460)
23 (6)
20.5 (325)
565 (1,246)
Up to 5 minutes.
At saturated gas conditions.
Makeup for sodium salts lost in filter cake.
CaO available in carbide lime is 92.5 percent.
74
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TABLE 31. CANE- RUN 6 FGO SYSTEM GUARANTEES
Sulfur dioxide emission
Particulate emission
Lime consumption
Sodium carbonate makeup
Power consumption
Waste solids properties
System availability
A sulfur dioxide emission of 200 ppm for coal
sulfur less than 5 percent and a system removal
efficiency of at least 95 percent for coal
sulfur greater than 5 percent.
No particulate emissions will be added to the
flue gas as received from the ESP.
Lime consumption will not exceed 1.05 moles
calcium oxide per moles of sulfur dioxide re-
moved from the flue gas.
Soda ash makeup will not exceed 0.045 moles of
sodium carbonate per mole of sulfur dioxide re-
moved from the flue gas at an average coal
chloride of 0.06 percent. If the average coal
chloride exceeds 0.06 percent, then additional
sodium carbonate consumption will be allowed
at a rate of 0.5 moles per mole of chloride in
the flue gas in excess of 0.06 percent coal
chloride.
1.1 percent of unit output at peak load (300 MW)
A minimum of 55 percent insoluble solids con-
tained in the filter cake.
A minimum availability of 90 percent for the
demonstration period.
75
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Mill Greek 4 is presently under construction and is sched-
uled for operation in July 1981. This unit is similar to Mill
Creek 3 in that it is approximately the same capacity, will burn
the same coal, and will use the same emission control stragegy
for particulate (ESP's) and sulfur dioxide (carbide lime FGD
system supplied by AAF).
LG&E is currently planning a new, coal-fired, power-gen-
erating facility located in Bedford, Kentucky. This new station,
known as Trimble County, will consist of 4 coal-fired units each
nominally rated at 575 MW. Startup dates for these units are
currently scheduled for July 1984, July 1986, 1988, and 1990, for
Trimble County 1, 2, 3, and 4, respectively. With respect to
Trimble County 1 and 2, LG&E currently plans to fire high
sulfur bituminous coal and control emissions with ESP's and FGD
systems. The FGD systems currently being considered are wet
scrubbers which will remove 90 percent of the inlet sulfur
dioxide and produce a nonrecoverable waste material. Neither a
process nor a system supplier have yet been selected for these
FGD systems.
76
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SECTION 5
FGD ECONOMICS
INTRODUCTION
In an effort to improve the comparability of the capital and
annual costs associated with utility FGD systems, PEDCo Environ-
mental has been conducting an on-going program for the U.S. EPA
which involves the acquisition of reported capital and annual
costs for the operational FGD systems and then adjusting this
data to a common basis. The intent of performing such a program
stems from the difficulty of comparing the costs that are re-
ported by the owning/operating utilities. Many of the capital
and operating costs reported for the operational FGD systems are
site-sensitive and involve different FGD battery limits and
expenditures made in different years. To accommodate these
differences, the cost data for the systems were analyzed and
adjusted to produce accurate and comparable data for the sulfur
dioxide portion of the emission control system.
APPROACH
The sole intent of the adjusting procedure was to establish
accurate costs of FGD systems on a common basis, not to critique
the design or reasonableness of the costs reported by the util-
ity. 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 (MW).
77
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Gross unit capacity was used to express all FGD capital
expenditures because the capital requirements of an FGD
system depends on actual boiler size before derating
for auxiliary and air quality control power require-
ments.
Particulate control costs were deducted in an effort to
estimate the incremental cost of sulfur dioxide con-
trol.
Capital costs associated with the modification or in-
stallation of equipment that is not part of the FGD
system but is needed for its proper functioning were
included (e.g., stack lining, modification to existing
ductwork or fans).
Indirect charges were adjusted to provide adequate
funds for engineering, field expenses, legal expenses,
insurance, interest during construction, allowance for
startup, taxes, and contingencies.
Annual costs, represented in mills/kilowatt-hour
(mills/kWh), were expressed in terms of net megawatts
(MW) .
Net unit capacity was used to express all FGD annual
expenditures because the annual cost requirement of an
FGD system depends on the actual amount of kilowatt-
hours (kWh) produced by the unit after derating for
auxiliary and air quality control power requirements.
Annual costs were adjusted to a common capacity factor
(65 percent).
Replacement power costs were not included.
Sludge disposal costs were adjusted to reflect the
costs of sulfur dioxide waste disposal only (i.e.,
excluding fly ash disposal).
A 30-year life was assumed for all process and economic
considerations for new units. A 20-year life was
assumed for retrofit units.
DESCRIPTION OF COST ELEMENTS
Capital costs consist of direct, indirect, contingency, and
other capital costs. Direct costs include the "bought-out" cost
of the equipment, installation, and site development. Indirect
78
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costs include interest during construction, contractor's fees and
expenses, engineering, legal expenses, taxes, insurance, allow-
ance for startup and shakedown, and spares. Contingency costs
include those resulting from malfunctions, equipment alterations,
and similar unforeseen sources. Other capital costs include the
nondepreciable items of land and working capital.
Annual costs consist of direct, fixed, and overhead costs.
Direct costs include the cost of raw materials, utilities,
operating labor and supervision, and maintenance and repair.
Fixed costs include depreciation, interim replacement, insurance,
taxes, and interest on borrowed capital. Overhead costs include
those of plant and payroll expenses.
RESULTS
The reported and adjusted capital and annual costs associ-
ated with the Cane Run 4 and 5 FGD systems are presented in
Appendices D and E of this report. The estimated capital and
annual costs associated with the Cane Run 6 FGD system were
prepared and published in the demonstration project manual. The
results of this cost analysis for the Cane Run FGD systems are
summarized in the following paragraphs.
Reported and Adjusted Capital and Annual Costs
The reported and adjusted capital and annual costs provided
by LG&E for Cane Run 4 and 5 are summarized in Tables 32 and 33.
The total capital costs reported by LG&E were $12,467,000 for
Cane Run 4 and $12,481,000 for Cane Run 5. Based on gross unit
capacity, these costs are equivalent to $66.6/kW and $62.2/kW,
respectively. The total annual cost reported by the utility for
Cane Run 4 was an estimate of 2.5 to 3.0 mills/kwh (net). No
annual costs were reported for Cane Run 5 at the time of data
collection because of the FGD system's recent operating status.
79
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TABLE 32. CANE RUN 4 AND 5 REPORTED AND ADJUSTED CAPITAL COSTS
Adjustments
Total reported capital cost
Additional waste disposal capacity
adjustment
Conversion to July 1, 1977, dollars
Total adjusted capital cost
Costs, 106 $ ($/gross kW)
Cane Run 4
12.647
(66.5)
0.900
1.774
15.321
(80.6)
Cane Run 5
12.481
(62.4)
0.900
0.125
13.506
(67.5)
TABLE 33. CANE RUN 4 AND 5 ADJUSTED ANNUAL COSTS
Costs, 106 $ (mills/net kWh)
Category
Variable charges
Overhead
Fixed charges
Total annual
Cane Run 4
3.355 (3.24)
0.403 (0.39)
2.234 (2.15)
5.992 (5.78)
Cane Run 5
3.287 (3.01)
0.503 (0.46)
2.276 (2.09)
6.066 (5.56)
80
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The adjusted capital and annual costs calculated for Cane
Run 4 and 5 were $15,321,000 or $80.6/kW (gross) and $5,992,000
or 5.8 mills/kWh (net) for Cane Run 4- and $13,506,000 or $67.5/kW
(gross) and $6,087,000 or 5.6 mills/kWh (net) for Cane Run 5.
With respect to Cane Run 6, the estimated capital and annual
costs published in the project manual for the dual alkali demon-
stration system are summarized in Tables 34 and 35. These costs
are already adjusted in that all the elements required for de-
termining the total capital and annual costs are included.
Further, these values are represented in common dollars. The
capital investment of $17,379,000 are roughly equivalent to
September 1977 dollars. The annual cost of $5,101,400 represents
an estimate for operations during 1979. These costs are equiva-
lent to 57.9/kW (gross) and 3.24 mills/kWh (net). These costs
compare favorably well with those reported by LG&E for Cane Run
4 and 5.
81
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TABLE 34. ESTIMATED CAPITAL COSTS FOR CANE RUN 6 FGD SYSTEM
Cateogry
Cost, $ ($/gross kW)
Materials:
Major equipment cost
Other materials cost
Sludge disposal equipment
Additive slurry system
Total materials cost
Erection:
Direct labor
Field supervision
Total erection cost
Engineering:
System supplier engineering
L6&E engineering
Consulting engineering
Total engineering cost
Spare parts
Working capital
Total capital
7,037,000
2,525,000
900,000
700,000
11,162,000
3,034,000
273,000
3,307,000
1,323,000
303,000
852,000
2,478,000
232,000
200,000
17,379,000 (57.9)
82
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TABLE 35. ESTIMATED ANNUAL COSTS FOR CANE RUN 6 FGD SYSTEM
Category
Direct costs:
Carbide lime
Soda ash
Fuel oil
Electricity
Water
Sludge Removal
Maintenance materials
Labor
Operation
Maintenance
Analysis
Supervision
Total direct costs
Indirect costs:
Overhead
Interest
Depreciation
Total indirect costs
Total annual costs
Cost, $ (mills/net
780,500
150,400
775,200
161,900
6,300
372,400
279,000
215,000
217,600
20,800
40,000
3,019,000
293,000
1,064,500
724,700
2,082,300
5,101,400 (3.
kWh)
24)
Based on the unit's gross peak generating capacity of 300 MW
and a capacity factor of 60 percent.
83
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REFERENCES
1. Holcombe, L.J., and K.W. Luke. Characterization of Carbide
Lime to Identify Sulfite Oxidation Inhibitors. Prepared for
the U.S. Environmental Agency under Contract No. 68-02-2608,
Task No. 21. EPA-600/7-78-176, September 1978.
2. Kelly, W.E., and C. Sedman. Air Pollution Emission Test,
Volume I: First Interim Report - Continuous Sulfur Dioxide
Monitoring at Steam Generators. Prepared by the U.S. En-
vironmental Protection Agency under Contract No. 68-02-2818,
Work Assignment 2. EMB Report No. 77SPP23A, August 1978.
3. Kelly, W.E., and C. Sedman. Air Pollution Emission Test,
Volume II: Data Listings, Averages and Statistical Sum-
maries - Continuous Sulfur Dioxide Monitoring at Steam
Generators. Prepared by the U.S. Environmental Protection
Agency under Contract No. 68-02-2818, Work Assignment 2.
EMB Report No. 77SPP23A, August 1978.
4. VanNess, R.P., et al. Project Manual for Full-Scale Dual
Alkali Demonstration at Louisville Gas and Electric Co. -
Preliminary Design and Cost Estimate. Prepared for the U.S.
Environmental Protection Agency under Contract No. 68-02-2189
EPA-600/7-78-010, January 1978.
5. Ibid.
84
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APPENDIX A
PLANT SURVEY FORM
A. Company and Plant Information
1. Company name: Louisville Gas and Electric (LG&E)
2. Main office; 311 West Chestnut Street
3. Plant name: Cane Run
4. Plant location; Lousiville. Kentucky
5. Responsible officer; R.L. Rover
6. Plant manager; S.J. Lindauer
7. Plant contact: Robert Van Ness
8. Position; Manager. Environmental Affairs
9. Telephone number; (502) 566-4216
10. Date information gathered: 2/22/78 and 9/11/7Q
Participants in meeting Affiliation
R. Van Ness LG&E
B. Statnick U.S. EPA
M. Maxwell U.S. EPA
B. Laseke PEDCo Environmental
M. Smith PEDCo Environmental
M. Melia PEDCo Environmental
N. Kaplan U.S. FPA
A-l
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B. Plant and Site Data
1. UTM coordinates:
Sea Level elevation:
3. Plant site plot plan (Yes, No):_j
(include drawing or aerial overviews)
4. FGD system plan (Yes, No): .
5. General description of plant environs; Situated along
the Ohio River in a moderately industrialized area
6. Coal shipment mode(s); Barge and truck
FGD Vendor/Designer Background
1. Process: Carbide lime slurry
2. Developer/licensor; American Air Filter Co.
3. Address: 215 Central Avenue:
Louisville, Kentucky 40201
4. Company offering process:
Company; Amerclan Air Filter Co.
Address: 215 Central Avenue
A-2
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Location: Louisville, Kentucky 40201
Company contact; J- Onnen
Position: S02 Product Manager
Telephone number; 502/588-9125
5. Architectural/engineer:
Company: Fluor-Pioneer
Address: 200 West Monroe
Location: Chicago, Illinois 60606
Company contact:
Position:
Telephone number; (3i2)/3fia-37nn
D. Boiler Data
1. Boiler: Cane Run 4
2. Boiler manufacturer; Combustion Engineering
3. Boiler service (base, intermediate, cycling, peak)
Base Load
4. Year placed in service; 1962
5. Total hours operation (date)::_
6. Remaining life of unit; 18 yr.
7. Boiler type; Pulverized coal
8. Served by stack no.:4
9. Stack height; 76.2 m (250 ft)
10. Stack top inner diameter:
11. Unit ratings (MW):
Gross unit rating; 190
Net unit rating without FGD; 185
A-3
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Net unit rating with FGD; 182
Name plate rating:
12. Unit heat rate:
Heat rate without FGD:
10, 740, W/net kWh
Heat rate with FGD: (in ] 80 Rtu/netkWhL
13. Boiler capacity factor, (1977): 55_
14. Fuel type: Coal
15. Flue gas flow rate:
Maximum: 346 m3/s (734,000 acfm)
Temperature:_J63°C (325°F)
16. Total excess air:
17. Boiler efficiency:
Coal Data
1. Coal supplier(s):
Name (s); Peabody Coal Company
Location(s): Star Mine
Mine location (s); Western Kentucky
County, State;
Seam:
2. Gross heating value; 27,700 J/g (T1.500 Btu/lb) (maximum)
3. Ash (maximum) : 14.0%
4. Moisture; 12.0% (maximum)
5. Sulfur (maximum): 4.0%
6. Chloride; Q.07% (maximum)
7. Ash composition (See Table Al)
A-4
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Table Al
Constituent Percent weight
Silica, SiO™
Alumina, A120.,
Titania, TiO-
Ferric oxide, Fe~Q3
Calcium oxide, CaO
Magnesium oxide, MgO Not available
Sodium oxide, Na20
Potassium oxide, K_0
Phosphorous pentoxide, P2°5
Sulfur trioxide, SO3
Other
Undetermined
F. Atmospheric Emission Regulations
1. Applicable particulate emission regulation
a) Current requirement: 43 ng/J (0.1 Ib/MM Btu)
Regulation and section:
b) Future requirement:
Regulation and section:
2. Applicable SO- emission regulation
a) Current requirement; 516 nq/J (1.2 Ib/MM Btu)
Jefferson County KRS Chapter
Regulation and section No. ; 77 and KRS Chapter 224
b) Future requirement:
Regulation and section:
A-5
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Chemical Additives; (Includes all reagent additives -
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)
1. Trade name: Carbide lime
Principal ingredient; Ca(OH)? 92.5%
Function: SO? Absorbent
Source/manufacturer: Airco. Inc.
Quantity employed; 107 Gg (118,000 ton/yr) (estimate)*
Point of addition: Recycle tank
2. Trade name; Betv Polvfloc 1100
Principal ingredient:
Function: Flocculant
Source/manufacturer; Betz
Quantity employed; Q.5% solution (continuous feed)
Point of addition: Thickener
3. Trade name: Not applicable (N/A)
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
Trade name: N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
* PEDCo Environmental estimate
A-6
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5. Trade name: N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
H. Equipment Specifications
1. Electrostatic precipitator(s)
Number; Two (2}
Manufacturer:
99%
Design removal efficiency:
Outlet temperature; 163°C (325°F)
Pressure drop:
2. Mechanical collector(s) N/A
Number:
Type;
Size:
Manufacturer:
Design removal efficiency:
Pressure drop:
3. Particulate scrubber (s) N/A (Quencher and flooded elbow)*
Number; Two (2)
Type: Wetted-wall conical frustum section (quench)
Manufacturer: American Air Filter (AAF) ,
Dimensions :
Material, shell; Carbon steel
^Absorber preceded by quencher and flooded elbow
A-7
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Material, shell lining:
Material, internals:
No. of modules per train; One
No. of stages per module; twn (2) (quench and flooded elbow)
No. of nozzles or sprays; Tangpntial and cocurrent -
Nozzle tVPe: jn^prtnr's nozzles - - -
Nozzle size: _ __ __ , __
Boiler load capacity;
(Parh module) _ .
173 m-Vs (367,000 acfm)
Gas flow and temperature: Ifi3°r. (325°F)
Liquid recirculation rate; 112 liter/s (1760 qpm)
Modulation: .
L/G ratio; 0.6 liter/in3 (4.8 nal/103 acf)
Pressure drop; 1.25 kPa (5.0 in H?0)
Modulation:
Superficial gas velocity:
Particulate removal efficiency (design/actual):
Inlet loading:
Outlet loading:
SO- removal efficiency (design/actual):
Inlet concentration:
Outlet concentration:
4. S02 absorber(s)
Number: Two (2)
Type: Mobile bed contactor
Manufacturer: AAF
Dimensions; 6.1 m x 6.1 m x 8.4 m (20 ft y ?0 ft v ?7
A-8
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Material, shell: Carbon steel
Material, shell lining: Precrete and Plasite 4005
Material, internals; Polyurethane balls, ceramic nozzles
No. of modules per train; One (1)
No. of stages per module: One (1)
Packing/tray type; 3.2-cm (1.25-in.) diameter polyurethane balls
Packing/tray dimensions:
No. of nozzles or sprays:
Nozzle type:
Nozzle size:
Boiler load capacity; 50% ^_^
138 m^/s (291,500 acfm)
Gas flow and temperature; 53°C(127°F)
Liquid recirculation rate: 1000 liter/s (15.865 qpm)
Modulation:
L/G ratio: 8 1/m3 (60.0 gal/IOOP acf)
Pressure drop; 1.0 kPa (4.0 in. H?0)
Modulation:
Superficial gas velocity: 3 to 4 m/s (10 to 13 ft/s)
Particulate removal efficiency (design/actual):
Inlet loading: __
Outlet loading:
S00 removal efficiency (design/actual); 85 %/86-89%*
2800 ng/J (6.5 1b/106 Btu)'
. r*\ t~\ f\ r\ i ^ i ^ r- ii»^rtlJrv. \ *
Inlet concentration:
Outlet concentration: 344 ng/J (0.8 1b/106 Btu)*
Wash water tray(s) N/A
Number : __ .
* Results of acceptance test.
Estimate.
A-9
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Type:_
Materials of construction:
Liquid recirculation rate:
Source of water:
6. Mist eliminator(s)
Number: Two (2)
Type; Chevron
Materials of ™n«*metion; SS and Plasite 4005 (duct area)
Manufacturer: __—-—
Configuration (horizontal/vertical); Horizontal
Number of stages: 2 _
Number of passes per stage :__3_
Mist eliminator depth:
Vane spacing; 2.5 - 3.8 cm (1-1.5 in.)
Vane angles:_ ;
Type and location of wash system: Fresh water over and
undersprays . .—
Superficial gas velocity; 3.1 m/s (TO fps) .
Freeboard distance: 1.8 m (6 ft._)_
Pressure drop; 1.2 - 3.0 kPa (0.5 - 1.2 in. H20)
Comments: Intermittent wash sprayed 2 min. every 5 min. at 2.5
liter/s (40 qpm) and 483 kPa (70 psig)
7. Reheater (s): Two (2) .—
Type (check appropriate category) :
A-10
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in-line
indirect hot air
direct combustion
bypass
exit gas recirculation
waste heat recovery
other
Gas conditions for reheat:
Flow rate: 275 m3/s (583.000 acfm)
Temperature: 53°C (127°F)
SO- concentration:
350 ppm (dry) (approximate)
Heating medium: Combustion gases
Combustion fuel; No. 2 fuel oil
Percent of gas bypassed for reheat: None
Temperature boost (AT) ; 28°C (50°F)
Energy required:
Comments; Reheat burners added to discharge ducts during initial
operations; originally, no reheat was included in system ( wet stack)
8. Fan(s)
Number : Two (2)
Type: Forced-draft booster fan
Materials of construction: Carbon steel
Manufacturer; Buffalo Forge/American Standard fluid drives
Location: Between ESP and FGD system
Rating:
930 kW (1250 hp) and 720 rpm
Pressure drop:
A-ll
-------
Recirculation tank(s):
Number: Two
Materials of construction; Reinforced concrete _
Function : Slurry reclrculation, reaction, and bleed
Configuration/dimensions; Rectangular, 3 compartments
Capacity; 1,703,000 liters (450.000 gal) _
Retention time; 25 minutes (8 min/coropartment) _
Covered (yes /no) ; No. __ __._ _
Agitator : Six (6) - I/ compartment _
10, Recirculat ion/slurry pump (s) :
Number : Six (6) _ _______ _
Type; Rectrculation (quencher. Jtbsorber) _
Manufacturer ; Denver _
Materials of construction
Head : 30 m (TOO ft)
Rubber-lined
Capaci ty: 37T ]/s (5875
11. Thickener(s)/clarifier(s)
Number: One (1)
Type: Type B
Manufacturer: Eimco
Materials of construction: Rubber-lined carbon steel*
Configuration; Circular
Diameter: 26 m (85 ft)
Depth: 4.2 m 04 .ft)
Rake speed:
Retention time:
12. Vacuum filter(s) N/A
* All submerged parts are rubber covered.
A-12
-------
Number:
Type:
Manufacturer:
Materials of construction:
Belt cloth material:
Design capacity:
Filter area:
13. Centrifuge(s) N/A
Number:
Type:
Manufacturer:
Materials of construction:
Size/dimensions:
Capacity:
14. Interim sludge pond(s) N/A
Number:
Description;
Area:
Depth:
Liner type:
Location:
Service Life:
Typical operating schedule:
Ground water/surface water monitors:
15. Final disposal site(s)
A-13
-------
Number: One (1)
Description: Lined pond
Area:
Depth:
Location: On-site
Transportation mode; Pipeline
Service life:
Typical operating schedule; Continuous: 68 kg/h (151 1b/h)
of dry sludge^produced per 0.9 Mg (ton) of coal burned (design)
16. Raw materials production N/A
Number:
Type:
Manufacturer;
Capacity:
Product characteristics:
I. Equipment Operation, Maintenance, and Overhaul Schedule
1. Scrubber(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
2. Absorber(s)
A-U
-------
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
3. Reheater(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
4. Fan(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
5. Mist eliminator(s)
Design life:
Elapsed operation time:
A-15
-------
Cleanout method: Wash water sprays
Cleanout frequency; 2 min. every 5 min.
Cleanout duration:
Other preventive maintenance procedures:
6. Purap(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
7. Vacuum filter(s)/centrifuge(s) N/A
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
Sludge disposal pond(s)
Design life:
Elapsed operation time:
Capacity consumed:
Remaining capacity:
A-16
-------
Cleanout procedures:
J. Instrumentation See text of report (Section 3, Process Control)
A brief description of the control mechanism or method of
measurement for each of the following process parameters:
Reagent addition:
Liquor solids content:
Liquor dissolved solids content:
0 Liquor ion concentrations
Chloride:
Calcium:
Magnesium:
Sodium:
Sulfite:
Sulfate:
Carbonate:
Other (specify):
A-17
-------
Liquor alkalinity:
Liquor pH:
Liquor flow:
0 Pollutant (SO-, particulate, NO ) concentration in
£* a
flue gas:
0 Gas flow:
0 Waste water
0 Waste solids:
Provide a diagram or drawing of the scrubber/absorber train
that illustrates the function and location of the components
of the scrubber/absorber control system.
Remarks:
K. Discussion of Major Problem Areas:
1. Corrosion:
A-18
-------
2. Erosion:
3. Scaling:
4. Plugging:
5. Design problems:
6. Waste water/solids disposal
A-19
-------
7. Mechanical problems:
L. General comments:
A-20
-------
APPENDIX S
PLANT SURVEY FORM
A. Company and Plant Information
1. Company name; Louisville Gas and Electric (LG&El
2. Main office; 311 West Chestnut Street
3. Plant name: Cane Run
4. Plant location: Lousiville, Kentucky
5. Responsible officer; R.L. Rover
6. Plant manager: S.J. Lindauer
7. Plant contact; Robert Van Ness
8. Position; Manager, Environmental Affairs
9. Telephone number; (502) 566-4216
10. Date information gathered: 2/22/78 and 9/1177Q
Participants in meeting Affiliation
R. Van Ness LG&E
B. Statnick U.S. EPA
M. Maxwell U.S. EPA
B. Laseke PEDCo Environmental
M. Smith PEDCo Environmental
M. Melia PEDCo Environmental
N. Kaplan U.S. EPA
B-l
-------
B. Plant and Site Data
1. UTM coordinates:
2. Sea Level elevation:
3. Plant site plot plan (Yes, No):_^
(include drawing or aerial overviews)
4. PGD system plan (Yes, No); Yes
5. General description of plant environs; Situated along the
Ohio River in a moderately Industrail zed area
6. Coal shipment mode(s); Barge and truck
C. FGD Vendor/Designer Background
1. Process; Carbide lime slurry
2. Developer/licensor; Combustion Engineering
3. Address; 10QQ Prospect Hill Road
Windsor, Conn. 06095
4. Company offering process:
Company: Combustion Engineering
Address; 1QQQ Prospect Hill Road
B-2
-------
Location: Windsor, Conn. 06095
Company contact: A.J. Snider
Position: Manager, Environmental Control
Telephone number: (203)/688-1911
5. Architectural/engineer:
Company: Fluor-Pi'oneer
Address: 200 West Monroe
Location: Chicago, Illinois 60606
Company contact:
Position:
Telephone number; (312^/368-3700
D. Boiler Data
1. Boiler: Cane Run 5
2. Boiler manufacturer: Riley Stoker
3. Boiler service (base, intermediate, cycling, peak)
Base load
4. Year placed in service: 1966
5. Total hours operation (date)::
6. Remaining life of unit:
7. Boiler type; Pulverized coal
8. Served by stack no.; 5
9. Stack height; 76 m (250 ft)
10. Stack top inner diameter:
11. Unit ratings (MW):
Gross unit rating; 200
Net unit rating without FGD; 195
B-3
-------
Net unit rating with FGD; 192
Name plate rating:
12. Unit heat rate:
Heat rate without FGD:
Heat rate with FGD; 10,529 J/net kWh (9.980 Btu/net kWh)
13. Boiler capacity factor, (1977); 60%
14. Fuel type; Coal
15. Flue gas flow rate:
Maximum: 307 ni3/s (650,000 acftn)
Temperature; 163°C (325°F)
16. Total excess air:
17. Boiler efficiency:
E. Coal Data
1. Coal supplier(s):
Name (s); Peabody Coal Company
Location(s): Star Mine
Mine location (s); Western Kentucky
County, State:
Seam:
2. Gross heating value: 27,700 J/g (n,500 Btu/lb) (maximum)
3. Ash (maximum) : 14.0%
4. Moisture: 12.0% (maximum)
5. Sulfur (maximum) : 4.0%
6. Chloride: 0.07% (maximum)
7. Ash composition (See Table Al)
B-4
-------
Table Al
Constituent Percent weight
Silica,
Alumina,
Titania,
Ferric oxide, Fe-O^
Calcium oxide, CaO
Magnesium oxide, MgO Not available
Sodium oxide, Na20
Potassium oxide, K~0
Phosphorous pentoxide, P2°5
Sulfur trioxide, SO3
Other
Undetermined
F. Atmospheric Emission Regulations
1. Applicable particulate emission regulation
a) Current requirement:__« ng/J (0-1 lb/W Btu)
Regulation and section:
b) Future requirement;
Regulation and section:
Applicable SO- emission regulation
a) Current requirement; 516 nq/J (1.2 Ib/MM Btu)
Jefferson County KRS Chapter
Regulation and section No.; 77 and KRS Chapter 224
b) Future requirement:
Regulation and section:
B-5
-------
G. Chemical Additives; (Includes all reagent additives •
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)
1. Trade name: Carbide lime
Principal ingredient; Ca(OH)2 (92.5%)
Function: SO? Absorbent
Source/manufacturer: Airco« Inc.
Quantity employed; 124 Gq (137,000 ton/vr) (estimate)
Point of addition; Recycle tank
2. Trade name: Betz Polvfloc 1100
Principal ingredient:
Function: Flocculant
Source/manufacturer; Betz
Quantity employed; p.5% solution (continuous feed)
Point of addition; Thickener
3. Trade name; Not applicable (N/A)
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
Trade name:
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
*
PEDCo Environmental estimate.
B-6
-------
5. Trade name: N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
H. Equipment Specifications
1. Electrostatic precipitator(s)
Number: Two (2)
Manufacturer:
Design removal efficiency: 99.0%
Outlet temperature; 163°C (325°Fl
Pressure drop:_
2. Mechanical collector(s) N/A
Number:
Type:
Size:
Manufacturer:
Design removal efficiency:
Pressure drop:_
3. Particulate scrubber(s) N/A*
Number:
Type:
Manufacturer:
Dimensions:
Material, shell:
* Secondary particulate control provided by the spray tower absorbers,
B-7
-------
Material, shell lining:
Material, internals:
No. of modules per train:
No. of stages per module:
No. of nozzles or sprays:
Nozzle type:
Nozzle size:
Boiler load capacity:
Gas flow and temperature:
Liquid recirculation rate:
Modulation: :
L/G ratio:
Pressure drop:
Modulation:
Superficial gas velocity:
Particulate removal efficiency (design/actual)
Inlet loading:
Outlet loading:
SO- removal efficiency (design/actual):
Inlet concentration:
Outlet concentration:
S0~ absorber(s)
Number: Two (2)
Type; Spray tower
Manufacturer: Combustion Engineering
Dimensions; 8 m x 9.5 m (26 ft x 31 ft)
B-8
-------
Material, shell; Carbon steel
Material, shell lining; Precrete
Material, internals; Ceramic nozzles
No. of modules per train; One (1)
No. of stages per module: One (1)
Packing/tray type: None
Packing/tray dimensions; N/A
No. of nozzles or sprays; 84
Nozzle type; Ceramic
Nozzle size:
Boiler load capacity; 50% (per module)
Gas flow and t-ry—a+""^ 1™ ™3/<; & 163°C (325.000 acfm @ 325°F)
Liquid recirculation rate; 1135 liters/s (17,500 qpm)
Modulation: .
L/G ratio; 7.4 liters/m3 (55 gal/TO3 acf) .
Pressure drop: 0.5 kPa (2.0 in. H20)
Modulation; . .
Superficial gas velocity: 2.1 m/s (7.0 ft/s) -
Particulate removal efficiency (dBWUfr/actual) ; 50-88*
Inlet loading; 39-143 nq/J (0.089-0.333 1b/106 Btu)* -
Outlet loading; 15-26 nq/J (0.035- 0.061 1b/106 Btu)* -
SO removal efficiency (design/actual) ; 85.0%/91.0 --
Inlet ™P~»T.*T.a + ion-. 2431-2778 ng/J (5.77-6.46 WIO6 Btu)*
Outlet ~™^nr,«.raf inn: 211-249 na/J (Q.49-Q-5R
Wash water tray(s) N/A
Number : _ __ _____ - --- ;
* Results of acceptance test.
B-9
-------
Type:
Materials of construction:
Liquid recirculation rate:
Source of water:
6. Mist eliminator(s)
Number: Two (2)
Type: Chevron , A-frame
Materials of construction; FRP
Manufacturer:
Configuration (horizontal/vertical): Horizontal
Number of stages; 3
Number of passes per stage: 2_
Mist eliminator depth:
Vane spacing:
Vane angles:
Type and location of wash system; Blended water overspray
and underspray
Superficial gas velocity; 2.1 m/s (7.0 ft/s)
Freeboard distance:
Pressure drop; 0.12 kPa (0.5 In. HpO)
Comments: Intermittent wash frequency (once/24 h). 3 stages in-
cludes 2 stages of chevrons preceded by a precollector (bulk entrain-
ment separator)
7. Reheater (s) : Two (2)
Type (check appropriate category):
B-10
-------
in-line
indirect hot air
direct combustion
bypass
exit gas recirculation
waste heat recovery
other
Gas conditions for reheat:
Flow rate: 265 m3/s (562,000 acfm)
Temperature: 53°C (126°F)
SO- concentration:
250-300 pom SO?
Heating medium; Steam
Combustion fuel; N/A
Percent of gas bypassed for reheat; None
Temperature boost (AT) r 22°C (40°F)
Energy required:
Comments: Reheater tubes are circumferential finned tubes con-
structed of carbon steel and arranged vertically in horizontal dis-
charge ducts atop absorbers
8. Fan(s)
Number; Two (2)
Type: Induced-draft booster fan
Materials of construction; Carbon steel
Manufacturer:
Location: Between reheatersl_and_.stack
Rating:
Pressure drop:
B-ll
-------
Recirculation tank(s):
Number: One
Materials of construction; Carbon steel
Function: Slurry recycle
Configuration/dimensions; Rectangular
Capacity: 1,779.000 liters (470.000 gal)
Retention time: 10 min
Covered (yes/no); No
Agitator; Two (2) _
10. Recirculation/slurry pump(s):
Number: Two (2) [One per module]
Type; Centrifugal
Manufacturer:
Materials of construction; Rubber-lined
Head:
Capacity; 1140 1/s (18.000 qprn)
11. Thickener(s)/clarifier(s)
Number; One (1)
Type:
Manufacturer:
Materials of construction; Rubber-lined carbon steel
Configuration: Circular
Diameter: 33.5m (110 ft) .
Depth:
Rake speed:
Retention time:
12. Vacuum filter(s) N/A
B-12
-------
Number:
Type:
Manufacturer:
Materials of construction:
Belt cloth material:
Design capacity:
Filter area:
13. Centrifuge(s) N/A
Number:
Type:
Manufacturer:
Materials of construction:
Size/dimensions:
Capacity:
14. Interim sludge pond(s)
Number:
Description:
Area:
Depth:
Liner type:
Location:
Service Life:
Typical operating schedule:
Ground water/surface water monitors:
15. Final disposal site(s)
B-13
-------
Number: One (1)
Description: Lined pond
Area:
Depth:
Location: On-site
Transportation mode; Pipeline
Service life:
Typical operating schedule; Continuous: 163 kg (360 1b) of
dry sludge produced per 0.9 Mg (ton) of coal burned
16. Raw materials production N/A
Number: .__ .
Type:
Manufacturer:
Capac ity:
Product characteristics:
Equipment Operation, Maintenance, and Overhaul Schedule
1. Scrubber(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
2. Absorber(s)
B-14
-------
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
3. Reheater(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
4. Fan(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
5. Mist eliminator(s)
Design life:
Elapsed operation time:
B-15
-------
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
6. Pump(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:.
Other preventive maintenance procedures;
7. Vacuum filter(s)/centrifuge(s) N/A
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:
B-16
-------
Cleanout procedures:
J. Instrumentation See text of report (Section 3, Process Control)
A brief description of the control mechanism or method of
measurement for each of the following process parameters:
0 Reagent addition:
Liquor solids content:
0 Liquor dissolved solids content:
Liquor ion concentrations
Chloride:
Calcium:
Magnesium:
Sodium:
Sulfite:
Sulfate:
Carbonate:
Other (specify):
B-17
-------
0 Liquor alkalinity:
Liquor pH:
0 Liquor flow:
Pollutant (S00, particulate, NO ) concentration in
f, X
flue gas:
0 Gas flow:
Waste water
Waste solids:
Provide a diagram or drawing of the scrubber/absorber train
that illustrates the function and location of the components
of the scrubber/absorber control system.
Remarks:
X. Discussion of Major Problem Areas:
1. Corrosion:
B-18
-------
2. Erosion:
3. Scaling:
4. Plugging:
5. Design problems:
6. Waste water/solids disposal:
B-19
-------
7. Mechanical problems:
L. General comments:
B-20
-------
APPENDIX C
PLANT SURVEY FORM
A. Company and Plant Information
1. Company name; Louisville Gas and Electric (LG&E)
2. Main office: 311 West Chestnut Street
3. Plant name: Cane Run
4. Plant location; Louisville. Kentucky
5. Responsible officer; R.L. Royer
6. Plant manager; S.J. Lindauer
7. Plant contact: Robert Van Ness
8. Position; Manager, Environmental Affairs
9. Telephone number; (502) 566-4216
10. Date information gathered: 2/22/78 and 9/11/79
Participants in meeting Affiliation
R. Van Ness LG&E
B. Statnick U.S. EPA
M. Maxwell U.S. EPA
B. Laseke PEDCo Environmental
M. Smith PEDCo Environmental
M. Melia PEDCo Environmental
N. Kaplan __ U.S. EPA
C-l
-------
B. Plant and Site Data
1. UTM coordinates:
2. Sea Level elevation:
3. Plant site plot plan (Yes, No):_^
(include drawing or aerial overviews)
4. FGD system plan (Yes, No); Yes
5. General description of plant environs; Situated along the
Ohio River in 2 moderately industrialized areas.
6. Coal shipment mode(s); Barge and truck _____
C. FGD Vendor/Designer Background
1. Process: Dual alkali
2. Developer/licensor; ADL/CEA*
3. Address: Acorn Park
Cambridge. MA 02140
4. Company offering process:
Company: ADL/CEA
Address: 555 Madison Ave.
Arthur D. Little and Combustion Equipment Associates
C-2
-------
Location: New York. NY 10022
Company contact; T. Frank
Position:
Telephone number; 212/980-3700
5. Architectural/engineer:
Company: Fluor-Pioneer
Address: 200 West Monore
Location: Chicago, Illinois 60606
Company contact:
Position:
Telephone number; (312) 368-3700
D. Boiler Data
1. Boiler: Cane Run 6
2. Boiler manufacturer; Combustion Engineering
3. Boiler service (base, intermediate, cycling, peak)
Base load —.
4. Year placed in service; 1969
5. Total hours operation (date)::
6. Remaining life of unit:
7. Boiler type: Pulverized coal
8. Served by stack no.: 6_
9. Stack height: 15R pi (5T8 ft)
10. Stack top inner diameter; 4.8 n (16 ft)
11. Unit ratings (MW):
Gross unit rating; 299
Net unit rating without FGD; 280
C-3
-------
Net unit rating with F6D: 277
Name plate rating:
12. Unit heat rate:
Heat rate without FGD:
10,508 kJ/net kWh
Heat rate with FGD; fg.960 Btu/net kWh)
13. Boiler capacity factor, (1977); 60%
14. Fuel type: Coal
15. Flue gas flow rate:
Maximum: 503 m3/s (1.065,000 acfm)
Temperature; ]49°C (300°F)
16. Total excess air:. 25% (35%
17. Boiler efficiency:
E. Coal Data
1. Coal supplier(s):
Name(s) ; Peabodv Coal Company
Location (s): Star Mine
Mine location (s); Western Kentucky
County, State:
Seam:
2. Gross heating value; 27,700 J/g (11,500 Btu/lb) (maximum)
3. Ash (maximum) : 14.0%
4. Moisture; 12.0% (maximum)
5. Sulfur (maximum) : 4.0%
6. Chloride: 0.07% (maximum)
7. Ash composition (See Table Al)
C-4
-------
Table Al
Constituent Percent weight
Silica, Si02
Alumina, Al-03
Titania, TiO-
Ferric oxide, Fe-O.,
Calcium oxide, CaO
Magnesium oxide, MgO Not available
Sodium oxide, Na2O
Potassium oxide, K20
Phosphorous pentoxide, P2°5
Sulfur trioxide, SO3
Other
Undetermined
F. Atmospheric Emission Regulations
1. Applicable particulate emission regulation
a) Current requirement; 43 nq/J (0.1 Ib/MM Btu)
Regulation and section:
b) Future requirement:
Regulation and section:
Applicable SO- emission regulation
a) Current requirement; 516 nq/J (1.2 Ib/MM Btu)
Jefferson County KRS Chapter
Regulation and section No.: 77 and KRS Chapter 224
b) Future requirement:
Regulation and section:
C-5
-------
Chemical Additives; (Includes all reagent additives •
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)
1. Trade name: Soda ash
Principal ingredient; Sodium carbonate
Function: S02 absorbent
Source/manufacturer:
Quantity employed! 1.734 Mg/yr (1.912 ton/yr)
Point of addition: Thickener
Trade name: Carbide lime
Principal ingredient; Ca(OH)? (92.5%)
Function: Reagent regeneration
Source/manufacturer; Airco, Inc.
Quantity employed; 53,277 Mg/yr (58,728 ton/yr)
Point of addition; Primary reactor
3. Trade name; Not applicable (N/A)
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
4. Trade name; N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
C-6
-------
5. Trade name: N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
H. Equipment Specifications
1. Electrostatic precipitator(s)
Number: Two (2)
Manufacturer:
Design removal efficiency: 99.4%
Outlet temperature; 150°C (300°F)
Pressure drop:
2. Mechanical collector(s) N/A
Number:
Type:
Size:
Manufacturer:
Design removal efficiency:
Pressure drop:
3. Particulate scrubber(s)
Number:
Type:
Manufacturer:
Dimensions:
Material, shell:
C-7
-------
Material, shell lining:
Material, internals:
No. of modules per train:
No. of stages per module:
No. of nozzles or sprays:
Nozzle type;
Nozzle size:
Boiler load capacity:
Gas flow and temperature:
Liquid recirculation rate:
Modulation: :
L/G ratio:
Pressure drop:
Modulation:
Superficial gas velocity:_
Particulate removal efficiency (design/actual)
Inlet loading:
Outlet loading:
SO2 removal efficiency (design/actual):
Inlet concentration:
Outlet concentration:
4. SO2 absorber(s)
Number: Two (2)
Type; Tray tower
Manufacturer: CEA
Dimensions; 9.7 m x 13.7 m (32 ft x 45 ft)
C-8
-------
Material, shell: A-283 carbon steel
Material, shell lining; Flake reinforced polyester
Material, internals; 317L SS, 316 SS, FRP piping
No. of modules per train; One (1)
No. of stages per module; Two (2)
Packing/tray type:
Packing/tray dimensions:
No. of nozzles or sprays:
Nozzle type:
Nozzle size:
Boiler load capacity; 60% (per module)
Gas flow and temperature; 41? m3/s Q 52°C (436.500 acfm @ 126°F)
Liquid recirculation rate; 272 liters/s (4,318 qpm)
Modulation: ^
L/G ratio: 1.2 liters/m3 (9.9 gal/1000 acf)
Pressure drop: 2,4 kPa (9.5 in. H20)
Modulation; 6:1 turndown
Superficial gas velocity; 2.7 m/s (9.0 ft/s)
Particulate removal efficiency (design/actual):
Inlet loading; (<43 nq/J) (<0.1 1b/106 Btu)
Outlet loading: (<43 nq/J) (<0.1 1b/1()6 Btu)
S02 removal efficiency (design/actual); 94.2%
Inlet concentration: 3471 ppm (dry)
Outlet concentration; 200 ppm (dry)
5. Wash water tray(s) N/A
Number:
C-9
-------
Type:
Materials of construction:
Liquid recirculation rate:
Source of water:
6. Mist eliminator(s)
Number: Two (2)
Type: Chevron
Materials of construction: Polypropylene
Manufacturer: Hei 1
Configuration (horizontal/vertical): Horizontal
Number of stages; One (1)
Number of passes per stage; Four (4)
Mist eliminator depth:
Vane spacing:
Vane angles:
Type and location of wash system; N/A
Superficial gas velocity: 2.7 m/s (9.0 ft/s)
Freeboard distance:
Pressure drop; 0.25 kPa (1.0 in.
Comments:
7. Reheater(s); Two (2)
Type (check appropriate category)
C-10
-------
in-line
indirect hot air
direct combustion
bypass
exit gas recirculation
waste heat recovery
other
Gas conditions for reheat:
Flow rate: 206 m3/s (463,500 acfm)
Temperature: 52°C (125°F)
SO2 concentration; 200 ppm
Heating medium; Combustion products
Combustion fuel: No. 2 fuel oil
Percent of gas bypassed for reheat: N/A
Temperature boost (AT) ; 28°C (50°F)
Energy required; 28,386.000 kJ/h (26.914,000 Btu/hl
Comments; 10.8 liters/m (171 gal/h) of No. 2 fuel oil consumed
in each reheater at maximum design operating conditions.
8. Fan(s)
Number: Two (2)
Type; Forced-draft booster, centrifugal
Materials of construction: A 441 carbon steel (housing and
blades)
Manufacturer:
Location: Between boiler ID fan and scrubber
Rating: 720 rpm
Pressure drop; 2.1 kPa (8.5 in H?0)
C-ll
-------
Recirculation tank(s) : [Primary reaction tanks]
Number: Two (2)
Materials of construction: 316L SS
Function: Regeneration/precipitation
Configuration/dimensions; 3.4 m x 4.3 m (11 ft x 14 ft)
Capacity; 37.672 liters (9952 gal)
Retention time: 4.5
Covered (yes/no):
Agitator; TWO (2) turbine-type 45 rom units
10. Recirculation/slurry pump(s):
Number: Four (4) - Two (2) operating/two (2) spare
Type: Recycle
Manufacturer:
Materials of construction: Rubber-lined
Head: 40 m (130 ft)
Capacity: 290 liters/s (4600 aal)
11. Thickener(s)/clarifier(s)
Number: One (1)
Type; Flat bottom
Manufacturer:
Concrete shell carbon steel interior,
Materials of construction; flake reinforced lining
Configuration; Cylindrical
Diameter: 38.1 m (125 ft)
Depth: 7 m (23 ft)
Rake speed:
Retention time:
12. Vacuum filter(s)
C-12
-------
Number: Three (3) - Two (2) operating/One (1) spare
Type; Rotary-drum
Manufacturer:
Materials of construction: 316 SS (filter drum)
Belt cloth material; FRP
Design capacity; 2.7 kg/day (3 ton/day)
Filter area:
13. Centrifuge(s)
Number:
Type:
Manufacturer:
Materials of construction:
Size/dimensions:
Capacity:
14. Interim sludge pond(s) N/A
Number:
Description:
Area:
Depth:
Liner type:
Location:
Service Life:
Typical operating schedule:
Ground water/surface water monitors:
15. Final disposal site(s)
C-13
-------
Number: One (1)
Description: Lined pond
Area:
Depth:
Location: On-site
Transportation mode: Truck
Service life:
Typical operating schedule; Continuous hauling
16. Raw materials production N/A
Number:
Type:
Manufacturer:
Capacity:
Product characteristics:
I. Equipment Operation, Maintenance, and Overhaul Schedule
1. Scrubber(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
2. Absorber(s)
C-14
-------
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures;
3. Reheater(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
4. Fan(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
5. Mist eliminator(s)
Design life:
Elapsed operation time:
C-15
-------
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
6. Pump(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
7. Vacuum filter(s)/centrifuge(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
8. Sludge disposal pond(s)
Design life:
Elapsed operation time:
Capacity consumed:
Remaining capacity:
C-16
-------
Cleanout procedures:
J. Instrumentation
A brief description of the control mechanism or method of
measurement for each of the following process parameters:
0 Reagent addition:
0 Liquor solids content:
0 Liquor dissolved solids content
0 Liquor ion concentrations
Chloride:
Calcium:
Magnesium:
Sodium:
Sulfite:
Sulfate:
Carbonate:
Other (specify):
C-17
-------
0 Liquor alkalinity:
Liquor pH:
0 Liquor flow:
0 Pollutant (SO0, particulate, NO ) concentration in
£. Jt
flue gas:
0 Gas flow:
Waste water
Waste solids:
Provide a diagram or drawing of the scrubber/absorber train
that illustrates the function and location of the components
of the scrubber/absorber control system.
Remarks:
K. Discussion of Major Problem Areas:
1. Corrosion:
C-18
-------
2. Erosion:
3. Scaling:
4. Plugging:
5. Design problems:
6. Waste water/solids disposal
C-19
-------
7. Mechanical problems;
General comments:
C-20
-------
APPENDIX D
OPERATIONAL FGD SYSTEM COST DATA
Date _ June 27. 197R
Utility Name Louisville Gas & Electric _
Address _ P.O. Box 32010. Louisville, KY 40232 _
Name of Contact - TitiP R- Van Ness, Mgr. Environmental Affairs
Phone No. ( 502) /566 - 4216
Station Cane Run _
Unit Identification
Unit Size. 190 _ gross MW. 734.000 acfm e 325
Net MW w/o Fftp 185
Net MW w/FGD _ 182
FGD System Size. 190 MW
Foot- 734,000 acfm e 325 «F
note
No. COST BREAKDOWN
I. CAPITAL COSTS OF FGD SYSTEM INSTALLATION
A. Year(s) to which estimates below apply; 1975
B. Year of greatest capital expenditure: 1975
C. Month and year estimates made: _J??[Li_I£Z§
D. Date FGD contract awarded; APr11 19» 1974
Date FGD construction began; October 15, 1974
Date of initial FGD system start-up: August 3, 1976
Date of commercial FGD system start-up: Sept. 1977
E. Expected FGD system life; 13 years
F. Cost adjustment made byt L- Yerlno
G. Cest adjustment checked by: M- Smith •
D-l
-------
Foot-
note
No.
H. Direct capital cost
Particulate collection
"Equipment cost
Installation cost
Total cost
Facilities for
reagent handling
and preparation
Equipment cost
Installation cost
Total cost
SC>2 absorber and re-
lated equipment
Equipment cost
Installation cost
Total cost
. Pans installed for FGD
Equipment cost
Installation cost
Total cost
Reheat
Equipment cost
Installation cost
Total cost
Included
in reported
total cost Capital
Yes No cost, $
496.000
4.7 MM
4.1 MM
8.8 MM
300,000
D-2
-------
Foot-
note
No.
6.
Included
in reported
total cost Capital
Yes No cost, $
Solids disposal: site
Equipment cost
Installation cost
Total cost
Location of interim and final disposal site(s)_anzsi±£_
X
X
X
1.101 MM
7.
When was site(s) acquired or year of expected acquisition
1945
Cost when acquired or at time of expected acquisition
Life span 10 years - can be expanded to 20 yrs. by increasing dike wall
Required site treatment (lining, surface preparation,
etc.) clay
Composition of disposed material (flyashJL_%, bottom
ash 24 %f SC>2 waste .22-%, unreacted reagent 3.%,
water_3_3_%) .
Solids disposal:
transport system
Contract cost
Equipment cost
Installation cost
Total cost
D-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, $
i—i
X
N/A
N/A
N/A - Not Applicable
D-4
-------
Foot-
note
No.
13,
10
14
15,
16,
17,
Stack requirements due
to FGD
Equipment cost
Installation cost
Total cost
Additional system
modifications
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 Capital
Yes No cost, $
iQQ.oon
D-5
-------
Foot-
note
No.
18. Other
Equipment cost
Installation cost
Total cost
9. Other
Equipment cost
Installation cost
Total cost
20. Other
Equipment cost
Installation cost
Total cost
Direct cost subtotal
Equipment cost
Installation cost
Total cost
I. Indirect Costs
1. Engineering
In-house
A-E
2. Construction expenses
In-house
Contractor
Included
in reported
total cost Capital
Yes No cost, $
10.847.000
D-6
-------
Foot-
note
No.
Included
in reported
13
3. Contractor fees
4. Subcontractor fees
5. Allowance for funds
used during construc-
tion
6. Allowance for start-up
7. Contingency
8. Escalation
9. Spares, offsite, taxes,
freight, etc.
10. Research and develop-
ment
11. Other
Indirect cost subtotal
J. Total Direct and Indirect Costs
$/kW (gross)
II. ANNUAL OPERATING COST
otal
Yes
X
X
X
X
X
X
12
66
<
,6
.5
:ost
No
X
X
X
»7,00
5
Capital
cost, $
1,800,000
0
A. Variable Costs
1. Particulate removal
a. Operating
(1) Labor
(2) Supervision
b. Electricity
c. Other utilities
(1) Water
Included
in reported
total cost
Yes No
Cost, $
D-7
-------
Foot-
note
No.
d. Maintenance
(1) Labor
(2) Supplies
Subtotal particulate
SC>2 absorber
a. Operating
(1) Labor
(2) Supervision
b. Electricity consumption
(1) Feed preparation
(2) Reheat
(3) Fans
(4) S(>2 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 cost
Yes No
X
X
X
X
X
X
X
X
X
X
X
_x_
X
Cost, $
D-8
-------
Foot-
note
No.
Included
in reported
total cost
Yes No
Cost, $
Subtotal absorber
Raw materials
a. Lime
b. Limestone
c. Fuel for process needs
d. Sodium hydroxide
e. Magnesium oxide
f. Sodium carbonate
g. 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
D-9
-------
Foot-
note
No.
14
g. Wastewater treatment
Subtotal disposal
5. Overhead
a. Plant
b. Administrative
Subtotal indirect
Total Variable Costs
B. Fixed Charges
1. Interest
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
1
2
.7
X
X
X
X
X
X
X
5
D-10
-------
FOOTNOTES
Line Page Comments
1 2 Reagent handling and preparation costs include barge
handling (carbide lime) and unloading facilities, pump-
ing system, day tank, lines and pumps and live storage
tank.
2 2 Modifications to the absorber by AAF are not included
as the costs were underwritten by the vendor.
3 2 Fan equipment includes two booster fans. These costs
are included in item 3. Total fan AP=12.8 in. HgO at
full load.
4 2 Reheat costs include two burners using No. 2 fuel oil
creating a temperature rise of 50°F. Also included
are two air injection fans. Total cost given in 1978 dollars,
5 3 Total sludge disposal site cost is $4 MM (units 4,5,6).
At a 10 yr. expected life the cost for unit 4 would be
$4 MM x 190/690 = $1.101 MM. To expand life span to
twenty years $900,000 must be added for additional dike
construction yielding a total of $2 MM.
6 4 Solids disposal system treatment costs are included in item
6.
7 4 Instrumentation and control costs are included in item 3.
8 4 Utilities and service costs are included in item 3.
9 5 The stack is lined with pre-crete attached to a wire
mesh.
10 5 Modification costs were absorbed by AAF. Major system
modifications included mist eliminator replacement, in-
creasing absorber L/G, installation of a reheat system,
duct and stack liner replacement and installation of
turning vanes.
11 6 Indirect cost breakdown was not available.
12 6 LG&E saved an estimated 2Q% on construction expenses by
using their own construction forces.
D-ll
-------
FOOTNOTES
Line Page Comments
13 7 NO annual operating cost breakdown was available. The
only reported annual cost was 2.5-3.0 mills/kWh (estimated.)
14 10 2.75 mills/kWh representing an average of the range
reported.
D-12
-------
APPENDIX D
COST ADJUSTMENTS
1. Total Reported Capital Cost Direct and Indirect $12,647,000
66.56 $/kW
2. Correct Expenditures to July 1, 1977;
1973
1974
1975
1976
1977
1Q78
Conversion
Factor to
July 1, 1977
1.417
1.234
1.12
1.062
1.00
.949
% of
Total
0.3
4.0
30.0
80.0
100.0
AAF
Expenditures
50,000
450,000
500,000
L.G&E
Expenditure
34,000
416,000
2,924,000
5,623,000
2,249,000
1 ,401 ,000
Corrected to
July 1, 1977
48,000
513,000
3,331,000
6,450,000
2,749,000
330,000
14,421,000
o Cost to increase waste disposal site life to 20 years = + 900.000
0 Total Adjusted Capital Expenditure $15,321,000
80.64 $/kW
3. Reported Annual Cost 2.75 mills/kWh
4. Adjusted Annual Cost (Pedco Estimates @ 65% cf);
Variable Costs
A) S02 Absorber
« Operating - manpower and respective costs shown are for units
4.5 & 6 with the operating subtotal being proportioned by m
for unit four only. Pedco estimated manpower cost @ $8.50/hr
used.
D-13
-------
APPENDIX D
COST ADJUSTMENTS
(1) Labor (@ 10 men per shift) 745,000
(2) Supervision (@ 1 man per shift) 74,000
(3) Labor: barge facilities, etc. (@ 5
men per shift) 372,000
Subtotal Operating (units 4,5 & 6)$1,191,000
° Total absorber operating labor cost (unit
four only) 1,191,000x190/690 = $ 328,000
o Electricity Consumption
(Estimation @ 12 mills/kWh) 234,000
o Fuel for reheat
(Estimation @ $13/barrel & 30 GPM) 3,172,000
o Maintenance
(1) Labor (estimated 0 4% of capital cost) 613,000
(2) Supplies (estimated @ 15% of labor) 92,000
B) Raw Materials
0 Lime (estimated @ $8/ton) 1,147,000
0 Lime handling cost 717,000
0 Flocculant (estimated @ $1.80/lb.) 13,000
C) Overhead
0 Plant (estimated e 50% 0+M) 360,000
0 lAdministrative (estimated 8 20% of 43,000
operating labor)
Total Variable Costs $6,719,000
D-14
-------
APPENDIX D
COST ADJUSTMENTS
Fixed Charges, %
0 Cost of Money 6.25
"Annual Depreciation 3.33
0 Insurance 0.30
o 7axes 4.00
0 Interim Replacement 0.70
14.58%
Total Fixed Cost = .1458 x 15,321,000 = $2,234,000
Variable 6,719,000
Fixed 2.234.000
Total Adjusted Annual Cost 8,953,000
Net kWh Generated
182 MW x 1000 kW/MW x 8760 hr/yr. x .65 cf = 1,036,308.000 kWh
f 036,308,000
2,234,0007 LQ36.308.000 = 1J56 mlls/kWh Fixed
8.640 mills/kWh Total
D-15
-------
APPENDIX E
OPERATIONAL FGD SYSTEM COST DATA
Date June 28. 1978
Utility Name Louisville Gas & Electric __
Address p-°- Box 32010. Louisville, KY 40232 _
Name of Contact - T^I*. R- V™ Ness» Manager of Environmental Affairs
Phone No. ( 502)7566-4216
Station Cane Run _ _
Unit Identification No. 5 ___
Unit Size,_2J)0 _ gross MW. 700.000 acfm P 310 °F
Net MW w/o FGD_J_95 _
Net MW M/Fftn 191.5
FGD System Size. 200
Foot- 700,000 acfm £ _!i°
note
No. COST BREAKDOWN
I. CAPITAL COSTS OF FGD SYSTEM INSTALLATION
A. Year(s) to which estimates below apply: 1975-1977
B. Year of greatest capital expenditure: 1977
C. Month and year estimates tnadg: March 1978
D. Date FGD contract awarded; April 21, 1975
Date FGD construction began; October 1» 1975
Date of initial FGD system start-up: December 1977
Date of commercial FGD system start-up: June 1, 1978
E. Expected FGD system life: 12 years
F. Cost adjustment made by; L- Ye^no
G. Cost adjustment checked by; B. A. Laseke, Jr.
E-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. SC>2 absorber and re-
lated equipment
Equipment cost
Installation cost
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, $
1 ,800,000
5,768,000
5,032,000
10,800,000
E-2
-------
Foot-
note
No.
6.
Included
in reported
total cost Capital
Yes No cost, $
Solids disposal: site
Equipment cost
Installation cost
Total cost
1 ,159,000
Location of interim and final disposal site(s)—PjL-site—
When was site(s) acquired or year of expected acquisition
1945
Cost when acquired or at time of expected acquisition
Life span 10 yrs. - ran hp pypanHoH tg ?{> years by incrgasin
dike wall
Required site treatment (lining, surface preparation,
etc.) clay _
Composition of disposed material (flyash_JL%, bottom
ash_24%, SO2 wasteJL2.%, unreacted reagent__3%,
water 33%) .
7. Solids disposal:
transport system
Contract cost
Equipment cost
Installation cost
Total cost
E-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, $
EDO
N/A
N/A
N/A - not applicable
E-4
-------
Foot-
note
No.
10
13,
14.
11
15
16,
17.
Stack requirements due
to FGD
Equipment cost
Installation cost
Total cost
Additional system
modifications
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 Capital
Yes No cost, $
x
X
E-5
-------
Foot-
note
No.
12
L8. Other
Equipment cost
Installation cost
Total cost
9. Other
Equipment cost
Installation cost
Total cost
. Other
Equipment cost
Installation cost
Total cost
Direct cost subtotal
Equipment cost
Installation cost
Total cost
I. Indirect Costs
1. Engineering
In-house
A-E
2. Construction expenses
In-house
Contractor
Included
in reported
total cost Capital
yes No cost, $
DG
X
X
X
1
Included in
E-6
-------
Foot-
note
No.
13
Included
in reported
total cost Capital
Yes No cost, $
3. Contractor fees
4. Subcontractor fees
5. Allowance for funds
used during construc-
tion
6. Allowance for start-up
7. Contingency
8. Escalation
9. Spares, offsite, taxes,
freight, etc.
0. Research and develop-
ment
1. Other
Indirect cost subtotal
J. Total Direct and Indirect Costs
$/kW (gross)
II. ANNUAL OPERATING COST
X
X
X
X
X
X
X
X
$
$
12
62
X
,481,
.4
ncluded in
tntal ranital
000
Included
in reported
total cost
Yes No
Cost, $
A. Variable Costs
1. Particulate removal
a. Operating
(1) Labor
(2) Supervision
b. Electricity
c. Other utilities
(1) Water
E-7
-------
Foot-
note
No.
Included
in reported
total cost
Yes No
Cost, $
d. Maintenance
(1) Labor
(2) Supplies
Subtotal particulate
2. SC»2 absorber
a. Operating
(1) Labor
(2) Supervision
b. Electricity consumption
(1) Feed preparation
(2) Reheat
(3) Fans
(4) SC>2 absorber
(5) Other
c. Fuel
(1) Reheat
(2) Other
d. Other Utilities
(1) Water
(2) Other
e. Maintenance
(1) Labor
(2) Supplies
E-8
-------
Foot-
note
No.
Included
in reported
total cost
Yes No
Cost, $
Subtotal absorber
Raw materials
a. Lime
b. Limestone
c. Fuel for process needs
d. Sodium hydroxide
e. Magnesium oxide
f. Sodium carbonate
g. 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
E-9
-------
Foot-
note
No.
Included
in reported
total cost
Yes No
Cost, $
g. Wastewater treatment
Subtotal disposal
5. Overhead
a. Plant
b. Administrative
Subtotal indirect
Total Variable Costs
B. Fixed Charges
1. Interest
2. Annual depreciation
3. Insurance
4. Taxes
5. Other, specify (Int. Repl .)
Total Fixed Costs
C. Total Variable and Fixed Costs
mills/kwh(net)
See
A
a
7.25%
8.33%
4.00%
0.30%
19.88%
dJustaent
E-10
-------
Line
FOOTNOTES
Comments
1 2 Reagent handling and preparation facility includes
barge handling (carbide lime) and unloading facility,
three separate pumping systems for units 4,5 and 6,
day tank, lines and pumps and live storage tank
(1MM gal.).
2 2 Besfgn S02 removal efficiency is 85%.
3 2 Approximate total FGD AP is 13 ;in H?0. Ductwork =
5 in, steam coils = 1-2 in, flooded elboW - 3 in,
tray = 1-5 in. Fan costs are included tn item 3.
4 2 Reheat type is finned coils - steam.
Estimated cost is $650,000 and is included
in item no. 3. AT = 40°F.
5 3 Total cost for solid disposal site is $4 MM for
units 4, 5, and 6. Cost breakdown for unit 5 is
($4 MM )x(200/690) = $1,159,000
6 3 Sol ids disposal transport system costs are
included in items 3 and 6.
7 4 Discharge from the thickener underflow will go
to the vacuum filter and then be mixed with
flyash and lime for all three units. IUCS system
treatment estimate is included in item 6.
8 4 Instrumentation costs are included in item 3
and other related areas. This includes SO^.an-
alyzer, Dupont 460A, measuring at two inlet and
two outlet points.
9 4 Utilities and service costs are included in item 3.
10 5 No stack modifications are required - reheat will
be operated when FGD system is in service.
11 5 This category includes change from original double
marble bed tower to spray tower with ability to insert
both marble beds and one common reaction tank.
cost is included in item 3.
12 6 Indirect costs are included in total capital cost
W» \S d U I J IIIUIUUCU III I I* C III **•
Indirect costs are included in total capital
figure.
E-ll
-------
FOOTNOTES
Coinments
No annual costs were reported because of
the system's recent operating status (initial
service in Dec. 1977; earnest operation of
the system actually commenced in Apr. 1978).
E-12
-------
APPENDIX E
COST ADJUSTMENTS
Total Annual Costs; 3,790,000 VARIABLE
2.276.000 FIXED
$6,066,000 TOTAL
Net kWh Generated;
191,500kW x 8760hr x .65C.F. = 1,090,401,000 kWh
' 5-562 mills/kwh TOTAL
= 3.475 mills/kWh VARIABLE
,
1 ,090,0 ,000
= 2.087 mills/kWh FIXED
, oo
1,090,401,000
3. Sunmary of Adjusted Costs
Capital $13,506,000 67.53 $/kW
Annual $ 6,087,000 5-562 mills/kWh
E-13
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APPENDIX E
COST ADJUSTMENTS
Capital Costs
Total reported direct and indirect cost $12,481,000
62.41 $/kW
Correct expenditures to July 1, 1977
% of Total Expenditure Corr. factor 1977 $
46,000
839,000
1974
1975
1976
1977
1978
0.3
6.3
32.3
72.0
100.0
37,000
749,000
3,245,000
4,955,000
3,495,000
1.234
1.12
1.063
1.0
.949
3,317.000
$12,606,000
Cost to increase solids disposal site life to 20 yrs. +900.000
$13,506,000
67.53 $/kW
2. Annual Costs
The following are PEDCo estimates based on a 65% load factor:
A) SO? absorber operating labor (supervision, labor at barge facility,
etc.) @ 8.50/hr. - $224,000
B) Electricity consumption @ 12 mills/kWh - $239,000
C) Reheat fuel @ $24/ton and 3344 Ib/hr coal - $229,000
D) Maintenance
Labor @ 4% of total capital expenditure - $545,000
Supplies S 15% of labor charge - $82,000
E) Raw materials and handling carbide lime $1,954,000 and flocculant
$14,000
F) Overhead
Plant: $428,000
Admini strati ve:$ 75.000
$3,790,000
G) Fixed costs:
0 Cost of money 7.25%
0 Depreciation 5.00%
0 Insurance 0.30%
Taxes 4.00%
0 Int. Replacement 0.30%
16.85%
(.1685) C$13,506,000) s $2,276,000
E-14
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APPENDIX F
PLANT PHOTOGRAPHS
F-l
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I
to
Photo No. 1. Full view of Cane Run Power Station. Units 1 to
6 are featured from left to right.
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Photo No. 2. Close-up view of the FGD-equipped units at Cane
Run. Cane Run 4, 5, and 6 are featured from left to right.
Each FGD system contains two parallel scrubber modules.
F-3
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TECHNICAL REPORT DATA
(Please read-Instructions on the reverse before completing)
. REPORT NO.
EPA-600/7-79-199c
2.
3. RECIPIENT'S ACCESSION1 NO.
AND SUBTITLE Survey of Flue Gas Desulfurization
Systems: Cane Run Station, Louisville Gas and Elec-
tric Co.
5. REPORT DATE
August 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Bernard A. Laseke, Jr.
8. PERFORMING ORGANIZATION REPORT NO.
PN 3470-1-C
. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
11499 Chester Road
incinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-02-2603, Task 24
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
EPORT AND PERIOD COVERED
13. TYPE OF REPORT AND PEI
Final; 7/78 - 12/78
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES JERL-RTP project officer is Norman Kaplan, Mail Drop 61, 919/
541-2556.
is. ABSTRACT rpne repOrt gives results of B. survey of operational Hue gas desuliurization
(FGD) systems on coal-fired utility boilers in the U.S. The FGD systems installed on
Units 4,5, and 6 at the Cane Run Station are described in terms of design and perfor
mance. The Cane Run No. 4 FGD system is a two-module (packed tower) carbide
lime scrubber, retrofitted on a 178 MW (net) coal-fired boiler. The system, supplied
>y American Air Filter, commenced initial operation in August 1976. The Cane Run
No. 5 FGD system is a two-module (spray tower) carbide lime scrubber, retrofitted
on a 183 MW (net) coal-fired boiler. The system, supplied by Combustion Engineer-
ing, commenced initial operation in December 1977. The Cane Run Unit 6 FGD system
is a two-module (tray tower) dual alkali (sodium carbonate/lime) scrubber, retrofit-
ted on a 278 MW (net) coal-fired boiler. The system, supplied by A.D. Little/Com-
>ustion Equipment Associates, commenced initial operation in December 1978.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
flue Gases
Desulfurization
Fly Ash
imestone
Slurries
Ponds
Scrubbers
Coal
Combustion
Cost Engineering
Sulfur Dioxide
Dust Control
Air Pollution Control
Stationary Sources
Wet Limestone
Particulate
13B
21B
07A,07D
11G
08H
21D
14A
07B
8. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
192
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
F-4
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