&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-
gories were established to facilitate further development and application of en-
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    5. Socioeconomic Environmental Studies

    6. Scientific and Technical Assessment  Reports (STAR)

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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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                        EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
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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

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             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

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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.

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                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

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                 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

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                                                        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.

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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

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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

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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

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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

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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

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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

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            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

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                             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.

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                                                             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.

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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

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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

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                           CHEVRON  VANES
SECOND
STAGE
FIRST
STAGE
                                                                 WASHER
                                                                  LANCE
                                             BULK ENTRAPMENT
                                                SEPARATOR
             Figure 5.   Cane Run 5 mist eliminator design.
                                     39

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                   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.

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                  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

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                                                                    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.

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                            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

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             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

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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

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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

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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

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     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

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     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
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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.
                                72

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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

-------
                              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

-------
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

-------
          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

-------
      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

-------
                            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

-------
 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

-------
     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

-------
     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

-------
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

-------
     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

-------
          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

-------
                                   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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