United States      Industrial Environmental Research  EPA-600 7-79-199a
Environmental Protection  Laboratory          August 1979
Agency        Research Triangle Park NC 27711
Survey of  Flue Gas
Desulfurization  Systems:
Duck Creek Station,
Central Illinois Light Co.

Interagency
Energy/Environment
R&D  Program Report

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                 RESEARCH REPORTING SERIES


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination  of  traditional  grouping  was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:

    1. Environmental Health Effects Research

    2. Environmental Protection Technology

    3. Ecological Research

    4. Environmental Monitoring

    5. Socioeconomic Environmental Studies

    6. Scientific and Technical Assessment Reports  (STAR)

    7. Interagency Energy-Environment Research and Development

    8. "Special" Reports

    9. Miscellaneous Reports

This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND  DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal  Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the  Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport  of energy-related pollutants and their health and ecological
effects;  assessments of, and  development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.



                        EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products  constitute endorsement or recommendation for use.

This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.

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                              EPA-600/7-79-199a

                                      August 197S
    Survey  of  Flue Gas
Desulfurization Systems
    Duck  Creek  Station,
 Central  Illinois Light Co.
                  by

            Bernard A. Laseke, Jr.

           PEDCo Environmental, Inc.
             11499 Chester Road
            Cincinnati. Ohio 45246
           Contract No. 68-02-2603
               Task No. 24
         Program Element No. EHE624
        EPA Project Officer: Norman Kaplan

     Industrial Environmental Research Laboratory
       Office of Energy, Minerals, and Industry
        Research Triangle Park, NC 27711
               Prepared for

     U.S. ENVIRONMENTAL PROTECTION AGENCY
        Office of Research and Development
           Washington, DC 20460

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                        TABLE OF CONTENTS
Figures

Tables
  c
Acknowledgment

Summary

1.  Introduction

2.  Facility Description

3.  Flue Gas Desulfurization System

       Background Information
       Process Description
       Process Design
       Process Chemistry:  Principal Reactions
       Process Control

4.  FGD System Performance

       Background Information
       Operating History and Performance
       Problems and Solutions
       Removal Efficiency
       System Economics

Appendix A,  Plant Survey Form

Appendix B.  Plant Photographs
Page

 iii

  iv

  vi

 vii

   1

   2

  10

  10
  14
  23
  36
  40

  44

  44
  45
  46
  50
  51

 A-l

 B-l
                              11

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                         LIST OF FIGURES
No.                                                         Paqe
 1   Overview of Duck Creek Plant Including All Major
     Facilities, Accesses, and Waterways                      3

 2   Major Components of the Coal/Limestone Handling
     Network at the Duck Creek Plant                          6

 3   Simplified Process Flow Diagram of Duck Creek 1
     Power Plant and Emission Control System                  8

 4   Duck Creek 1 FGD Limestone Storage and
     Preparation Facility                                    15

 5   Duck Creek 1 FGD System Scrubbing Circuit               17

 6   Cutaway View of a Duck Creek 1 FGD Scrubber Module      19

 7   Duck Creek 1 Duct Work and Damper Arrangement           22

 8   Duck Creek 1 Waste Disposal and Water Return Loop       24
                               111

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                         LIST OF TABLES


No.                                                          Page

 1   Data Summary:  Duck Creek 1                              ix

 2   Characteristics of Coal Fired at Duck Creek               4

 3   Design, Operation, and Emission Data:  Duck Creek 1       9

 4   Duck Creek 1 FGD System Bench-scale Test Results         12

 5   Results of the E.D. Edwards Pilot Plant Test Program     13

 6   Specifications and Consumption Rates of Duck Creek
     Performance Coal                                         25

 7   Design Parameters of Duck Creek 1 ESP                    26

 8   Design Parameters of Duck Creek 1 FGD System             27

 9   Design Parameters and Operating Conditions of Duck
     Creek 1 Scrubbers                                        29

10   Design Parameters and Operating Conditions of
     Duck Creek 1 Mist Eliminators                            30

11   Design Parameters and Operating Conditions of Duck
     Creek 1 Dampers                                          31

12   Design Parameters and Operating Conditions of Duck
     Creek 1 Induced-draft Fans                               33

13   Design Parameters and Operating Conditions of Duck
     Creek 1 Pumps                                            34

14   Design Parameters and Operating Conditions of Duck
     Creek 1 Tanks                                            34

15   Design Parameters and Operating Conditions of Duck
     Creek 1 Limestone Storage Facilities                     36



(continued)

                               iv

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                   LIST OF TABLES (continued)
No.                                                          Page
16   Design Parameters and Operating Conditions of Duck
     Creek 1 Limestone Preparation Facility                   37

17   Design Parameters and Operating Conditions of Duck
     Creek 1 Waste Disposal System                            38

18   Duck Creek 1 D-scrubber Module Performance History       47

19   Results of the D-scrubber Module Test                    50
                                v

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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.  Larry Haynes,
Environmental Manager, Central Illinois Light Company, provided
information on plant design and operation.
                               VI

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                             SUMMARY

     The Duck Creek plant is a new coal-fired power-generating
station owned and operated by the Central Illinois Light Company
(CILCo).  It is situated in an unreclaimed strip-mining area near
Canton, Illinois.  The current capacity of the plant with one
coal-fired power-generating unit is 416 MW (gross).  Duck Creek
1, the existing unit, was placed in commercial service on June 1,
1976.  Duck Creek 2, 3, and 4 are three planned additional units
of similar capacity scheduled for commercial operation in 1982,
1989, and 1992, respectively.  This will bring the total station
capacity to approximately 2000 MW.
     Duck Creek 1 fires a high-sulfur, bituminous-grade, Illinois
coal having maximum sulfur and ash contents of 4.0 and 18.0
percent.  To enable the unit to meet Federal New Source Per-
formance Standards, it is equipped with an emission control
system for particulate and sulfur dioxide control.
     Primary particulate control is provided by two parallel
electrostatic precipitators  (ESP's) with a design removal effi-
ciency of 99.8 percent.  The ESP's are supplied by Pollution
Control-Walther.  Primary sulfur dioxide control is provided by a
limestone flue gas desulfurization (FGD) system consisting of
four parallel 25 percent-capacity scrubbing modules with a total
removal efficiency of 85 percent.  The FGD system is supplied by
Riley Stoker/Environeering.
     The utility originally planned to install only one 25 per-
cent capacity (100-MW equivalent) scrubbing module to conduct a
thorough high sulfur coal test program.  The data obtained was to
have been used to design the remaining three modules.  Approval
of this plan, which was originally granted at the State level,
                               Vll

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was later revoked by the U.S. EPA, which required the entire
plant to comply with New Source Performance Standards.  A consent
decree granted CILCo by the EPA gave the utility a variance to
burn high sulfur coal from July 1, 1976, to April 1, 1977.
During this period, one scrubber module (completed by June 1976)
would remain in the gas path and remove sulfur dioxide from 25
percent of the boiler flue gas.  The timetable for the installa-
tion of the remaining modules was accelerated to August 1978.
During the interim period between the end of the variance and the
completion of the remaining modules, low sulfur coal would be
burned in the boiler in order to comply with standards.
     The first scrubbing module was placed in service on July 1,
1976, and operated intermittently throughout the remainder of the
year and for approximately one month in early 1977.  Several
problems, including plugging, scaling, corrosion, and materials
failure, were encountered during this period.  As a result of
this initial operating experience, CILCo and Riley Stoker/Envi-
roneering made some design changes to both the existing and
planned scrubbing modules during the April 1977 to August 1978
period when low sulfur coal was burned.  On July 23, 1978, the
three remaining scrubbing modules were completed and all four
modules were placed in the gas path for treatment of high sulfur
coal flue gas.
     Central Illinois Light Company reported the total capital
cost of the system to be $37,540,000, including $33,740,000 for
the system and all ancillary equipment and $3,800,000 for the
sludge disposal pond.  Based on a unit gross generating capacity
of 416 MW, this amounts to $90.2/kW.  Actual annual cost figures
are not yet available; however, based on the limited operation of
one module, CILCo estimates that total annual cost will be
$13,921,000, including $7,539,000 for variable charges and
$6,382,000 for fixed charges.  Based on a net unit rating of 400
MW and a capacity factor of 65 percent, this amounts to 6.11
mills/kWh.
     Table 1 summarizes data on the facility and the FGD system.

                             viii

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            TABLE 1.   DATA SUMMARY:   DUCK CREEK 1
Gross rating, MW
Net rating, MW
Fuel
Average fuel characteristics:
     Heating value, kJ/kg (Btu/lb)
     Ash, percent
     Moisture, percent
     Sulfur, percent
     Chloride, percent
FGD process
FGD system supplier

Application
Status
Startup dates:
     Initial5
     Commercial
Design removal efficiency, percent
     Particulate
     Sulfur dioxide
Makeup water, liters/min per MW  (gal'/min per MW)
Economics
     Capital, $/kW (gross)
     Annual, mills/kWh (net)
416
400
Coal

24,523 (10,543)
 9.12
18.0
 3.30
 0.03
Limestone
Riley Stoker/
 Environeering
New
Operational

July 1976
August 1978

99.8
85.3
 5.65 (1.49)

90.2
 6.11
  Design fuel specifications for high sulfur Illinois coal.
  Boiler and ESP commenced operation in June 1976.   One FGD  module
  commenced operation in July 1976.  Full commercial operation with
  all four FGD modules commenced in August 1978.
  Particulate removal provided by ESP's.
  Design makeup water requirements.
                                 IX

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                            SECTION 1
                          INTRODUCTION

     The Industrial Environmental Research Laboratory (IERL)  of
the U.S. Environmental Protection Agency (EPA) has initiated a
study 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
Duck Creek plant of the Central Illinois Light Company (CILCo).
It includes pertinent process design and operating data,  a de-
scription of major startup and operational problems and solu-
tions, atmospheric emissions data, and capital and annual cost
information.
     This report is based on information obtained during and
after a plant inspection conducted for PEDCo Environmental per-
sonnel on June 9, 1977, by CILCo.  The information presented in
this report is current as of October 1978.
     Section 2 provides information and data on facility design
and operation; Section 3 provides background information and a
detailed description of the FGD process; Section 4 describes and
analyzes the operation and performance of the FGD system.
Appendices A and B contain details of plant and system operation,
economic data, and photos of the installation.

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                            SECTION 2
                      FACILITY DESCRIPTION

     The Duck Creek plant is a new coal-fired power-generating
station owned and operated by CILCo.  Located in Fulton County,
Illinois, approximately 65 km (40 mi) southwest of Peoria, the
plant site consists largely of unreclaimed strip-mining land
situated in a relatively flat, rural area.  There are no other
major industrial facilities within the immediate area.  The
nearest population center is Canton  (a town of about 14,000
people), which is approximately 8 km (5 mi) southwest of the
plant.
                                                                2
     The plant site proper covers an area of approximately 36 km
(9000 acres), approximately 4 km (2.5 mi) from the Illinois
River.  Duck Creek, an intermittent stream carrying only the
runoff from the immediate watershed, runs through the site.  The
plant's cooling pond was created by constructing an earthen dam
across this creek.  The dam, which is a zoned earthwork structure
with a crest length of 520 meters (1700 ft) and a maximum height
of 37 meters (120 ft), forms a reservoir covering an area of
                     2
approximately 7.36 km  (1820 acres).  The powerhouse is located
in an unmined section that is capable of withstanding the heavy
loads associated with the powerplant equipment and foundations.
At the present time two coal mines on the site remain active.  A
general overview of the Duck Creek plant site, including all
major facilities, accesses, and waterways, is provided in Figure
1.
     Duck Creek 1 is equipped with its own steam generator and
turbine.  The dry-bottom, pulverized-coal-fired steam generator
is a balanced-draft, front-fired, single reheat unit supplied

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'.
ILLINOIS RIVER
                                                                       \    EXISTING ROAD  '
                                                                         SECONDARY PLANT ACCESS)
                                                                   \ rUNIT 4(FUTURE) /LIMESTONE STORAGE         ^
                                                                   ^ rUNIT 3(FUTURE/	_-'r _.
                                                                      IrUNI
UNIT 2(FUTURE)
                                                                                  ASTE STORAG
                                                                                   (UNIT 1)
                                                                                               OrtTH FOUR UNITS
                                                                                               OPERATING)  ,
                                                                                                       V"
                                                                         DROP STRUCTURE
                                                                           HATER CONTROL STRUCTURE(FUTURE\Jfc
                   Figure  1.   Overview of Duck Creek plant,  including all major
                                     facilities,  accesses,  and  waterways.

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by Riley Stoker.  It produces 1360 Mg (3,000,000 Ibj per hour of
superheat steam at 540°C (1005°F) and 18 MPa  (2600 psig), and
1110 Mg (2,450,000 Ib) per hour of reheat steam at 540°C (1005°F)
and 3.3 MPa (481 psig).  The turbine generator is a 416-MW
(gross), 17-MPa (2400 psig), 538°C (1000°F), 3.4-kPa (1.0 in.
Hg), 3600-rpm unit supplied by General Electric.  The station
also contains one auxiliary boiler, which is used for plant
startups or for powering a house turbine generator.  The auxilary
boiler, a shop-assembled unit supplied by Riley Stoker, fires No.
2 fuel oil and produces 23 Mg (50,000 Ib) per hour of steam at
1.8 MPa (250 psig).
     The plant burns high sulfur Illinois coal and low sulfur
Colorado coal.  Originally, the plant was designed to burn only
a high sulfur bituminous grade of Illinois coal.  This coal is
supplied primarily by United Freeman's Crown and Buckheart mines
in Fulton County, near the plant site.  The plant also burns a
low sulfur bituminous grade of coal obtained on a spot-purchase
basis from several Colorado mines.  It was necessary to find a
low sulfur coal supply source to enable the plant to meet Federal
New Source Performance Standards regarding sulfur dioxide emis-
sions during the interim period between the end of the variance
(April 1, 1977) and commercial operation of the entire FGD system
(August 1, 1978).  Table 2 presents average characteristics of
these coals.
      TABLE 2.  CHARACTERISTICS OF QOAL FIRED AT DUCK CREEK
Source
Characteristics
Value (average)
Illinois
Colorado
Heating value, kJ/kg (Btu/lb)
Ash, percent
Moisture, percent
Sulfur, percent
Chloride, percent
Heating value, kJ/kg(Btu/lb)
Ash, percent
Sulfur, percent
24,523 (10,543)
   9.12
  18.0
   3.3
   0.03
24,750 (10,640)
   6.97
   0.41

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     A highly flexible coal-handling system capable both of pro-
viding for the ultimate plant capacity of 2000 MW (net) and of
transporting limestone for the FGD system was developed for Duck
Creek.  The flexibility of the coal-handling system was provided
by extending the stacker/reclaimer's travel some 90 m  (300 ft),
thereby allowing additional space for limestone storage.  A
series of interlocks is included in the system to minimize the
possibility of accidently conveying coal to the limestone area or
limestone to the coal area.
     The coal/limestone handling system is designed to accommo-
date deliveries by rail, but it also includes provisions for
truck shipments because of the potential for barge unloading on
the Illinois River.  Coal or limestone can be conveyed from the
unloading area to the yard storage area or directly to the plant
at a maximum rate of 1.8 Gg (2000 tons) per hour.  Coal or lime-
stone diverted to yard storage is deposited in either live or
dead storage piles.  Coal or limestone going directly to the
plant is transported by separate conveyors after passing through
a switch house.  Limestone is conveyed on a single 1.8-Gg (2000-
ton) belt to the crushing and milling building, whereas the coal
is transferred to the breaker house and sample house before being
burned in the boiler.  Figure 2 illustrates the major components
of the Duck Creek coal/limestone handling network.
     To meet Federal New Source Performance Standards, Duck Creek
1 is equipped with an emission control system that includes
electrostatic precipitators (ESP's) and an FGD system.  Primary
particulate control is provided by two parallel, cold-side ESP's
supplied by Pollution Control-Walther and designed to remove 99.8
percent of the inlet particulate matter.  Primary sulfur dioxide
control is provided by four parallel, wet-limestone, rod-deck
(Ventri-Sorber) scrubber modules supplied by Riley Stoker/En-
vironeering and designed to remove 85 percent of the inlet sulfur
dioxide.  All or part of the flue gas can be bypassed around the
scrubber modules by manipulating bypass dampers and module

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(Ti
LIMESTONE SUPPLY FOR   I
UNITS 3 AND 4(FUTURE)  ,
                                                              DEAD STORAGE
                                                                (FUTURE)
UNIT 4(FUTUR£)]  |l     ] ^    /CONVEYOR
            j—ffl	.HOUSE
UNIT 3(FUTURE)|  ||      j    \   *"•  BREAKER
                                    HOUSE
         UNIT 1

      UNIT 2(FUTURE)
                                                           EMERGENCY RECLAIM
                                                           DEAD COAL STORAGE
                                                                                            DEAD LIMESTONE STORAGE
                                                           CONVEYOR
                  'TRIPPER CONVEYORS
                 PLANT-SUPPLY CONVEYORS—^
        \  LIMESTONE CONVEYOR
        \
          \
                                                         \IMIIIIIIIIII
                                                               STACKER/RECLAIMER

 TRUCK RECEIVING
•TRAIN POSITIONER

  I I II I I I I I
                                                           ROTARY CAR DUMPER
                                                       LIVE LIMESTONE STORAGE
                                                               1  I  I  I I I I  I I I  I  I  I  I  I  I  I  II  I  N
                    Figure  2.   Major  components of  the  coal/limestone handling
                                      network  at  the Duck Creek plant.

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isolation dampers.  The bottom ash, fly ash, and scrubbing wastes
are disposed of in an onsite 65-acre sludge pond lined with a
natural impermeable material.
     The Federal Clean Air Act of 1972 limits particulate and
sulfur dioxide emissions to 43 ng/J (0.1 lb/10  Btu)  and 516 ng/J
(1.2 lb/10  Btu) of heat input to the boiler.  Actual particulate
emissions, as measured by the utility during performance tests,
ranged from 47.6 mg/m3 (0.0208 gr/scf) to 191.5 mg/m3 (0.0837
gr/scf).*  Actual sulfur dioxide emissions, as measured by the
utility during performance tests, were approximately 252 ppm.
Based on an inlet concentration of 3000 ppm from the combustion
of 3.3 percent sulfur coal, this translates into an FGD system
removal efficiency of 91.6 percent, which is above the 85.3
percent design removal efficiency for 4.0 percent sulfur coal.
     Figure 3 provides a process 'flow diagram of Duck Creek 1,
including the power plant, emission control system, reagent
preparation facility, and sludge disposal area.  Table 3 presents
data on plant design, operation, and atmospheric emissions.
  All measurements are expressed on dry basis.
  Performed during single module operation conducted from July
  1976 to April 1, 1977.

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00
                                                                               I	1
                                                                                    cuusirm
FEED
ira
H J
\s


_j



V

kjs ;

y
A
*n

                      Figure 3.  Simplified process flow diagram of  Duck  Creek 1
                               power plant  and emission control system.

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     TABLE  3.   DESIGN,  OPERATION,  AND EMISSION  DATA:
                            DUCK  CREEK 1
Generating capacity, MW:
     Gross
     Net without FGD
     Net with FGD
Maximum coal consumption,  Mg/h (tons/h)
Maximum heat input, GJ/h (10  Btu/h)
Maximum flue gas rate, m /s (acfm)
Flue gas temperature, °C (°F)
Unit heat rate, kJ/net kWh (Btu/net kWh}
Unit capacity factor, percent  (1977)
Emission controls:
     Particulate

     Sulfur dioxide
Particulate emission rate:
     Limit, ng/J (lb/106 Btu)
     Actual,mg/m3 (gr/scf)

Sulfur dioxide emission rate:
                      ,6
     Limit, ng/J (lb/10
     Actual, ppm
Btu)
                             416
                             410
                             400
                             174  (192)
                             4,265  (4,040)
                             668  (1,415,610)
                             135  (275)
                             10,380  (9,840)
                             55 - 60

                             Electrostatic
                              precipitators
                             Rod-deck scrubbers
                              43  (0.1)
                              47.6 -  191.5
                              (0.0208-0.0837)
516 (1.2)
252 a
  Measurement obtained during single module operation conducted  from
  July 1976 to April 1, 1977.

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                            SECTION 3
                 FLUE GAS DESULFURIZATION SYSTEM

BACKGROUND INFORMATION
     Because environmental constraints prevented expansion of
their existing plants, in the late 1960's CILCo began searching
for locations that were capable of ultimately supporting 2000 MW
of coal-fired capacity and included an onsite pond-treatment
facility for cooling purposes.  By early 1970 the search was
narrowed to three possible sites.  After determining the Duck
Creek site to be the best of the three, CILCo officials commis-
sioned a thorough feasibility study to determine representative
cost estimates for plant construction, including the use of a
cooling pond.  This feasibility study indicated that the Duck
Creek site could support the ultimate plant capacity and that the
use of a cooling pond offered substantial capital and annual cost
savings over mechanical- and natural-draft cooling towers.
     Compliance with New Source Performance Standards governing
sulfur dioxide and particulate emissions was also considered at
this stage of development.  Investigations revealed that com-
pliance with particulate emission regulations could readily be
achieved with the use of ESP's or scrubbers.  Compliance with
sulfur dioxide emission regulations, however, would be more
difficult.  Two basic alternatives were considered:  burning low
sulfur western coal or burning high sulfur coal and installing
FGD equipment.  The former alternative was rejected for several
reasons, including the premium paid for low sulfur coal; higher
transportion costs; the presence of abundant supplies of cheap,
high sulfur coal in mines near the plant site; and the adverse
effect of low sulfur coal on ESP performance.

                              10

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     Two emission control strategies were evaluated for high
sulfur coal application:  two-stage particulate and sulfur
dioxide wet scrubbing and an ESP-FGD combination for separate
collection of particulate and sulfur dioxide.  The ESP-FGD alter-
native was given primary consideration because it would (1)
result in a capital cost saving of $2,000,000, (2) reduce aux-
iliary power requirements by 10 MW, (3) reduce total annual cost,
(4) offer greater mechanical reliability, and (5) make it pos-
sible to bypass the FGD modules during forced outages without
reducing the boiler load.
     In 1972 and 1973 CILCo and Riley Stoker  (the boiler supplier
for Duck Creek 1) initiated an intensive program to evaluate
various FGD processes and designs that could be used in conjunc-
tion with an ESP for high sulfur coal service.  In late 1972 a
bench-scale program employing a 0.7-m /s (1500-acfm)* laboratory
test unit was conducted.  This program involved the use of a new,
patented scrubber design developed by Environeering (formerly
National Dust Collector), a firm later acquired by Riley Stoker.
Originally, Environeering held patents (which expired in early
1972) on a marble-bed design (Marble Bed hydro-filter).  Prior to
the expiration of these patents, however, Environeering had
developed a new, patented design using rod-decks in a vertical,
countercurrent spray tower  (Ventri-Sorber scrubber).  The bench-
scale results (summarized in Table 4) were very encouraging.
Using limestone slurry, this spray tower achieved sulfur dioxide
removal efficiencies in the 80 to 88 percent range on inlet
concentration levels of 2000 to 3000 ppm at pressure drops of 2.1
kPa  (8.5 in. H20).
  0.5 MW equivalent electrical capacity.
                              11

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   TABLE 4.  DUCK CREEK 1 FGD SYSTEM BENCH-SCALE TEST RESULTS
Parameters
Gas flow rate, m /min (acfm)
Liquid flow rate, liter s/s
(gal/min)
Pressure drop, kPa (in. H?O)
Liquid/gas ratio, liter s/m^
(gal/103 acf)
Sulfur dioxide inlet concentra-
tion, ppm
Sulfur dioxide outlet concentra-
tion, ppm
Sulfur dioxide removal effi-
ciency, percent
Test conditions
Block 1
48 (1700)
5.4 (85)
2.1 (8.5)
6.7 (50)

2000

238

88.1
Block 2
48 (1700)
5.4 (85)
2.1 (8.5)
6.7 (50)

3000

555

81.5
     As a result of this successful bench-scale test program, a
     3
185 m /min (6500 cfm)  limestone pilot plant costing over $1
million was installed and operated from March 1973 to December
1973 at CILCo's E.D. Edwards Station.  The pilot plant included a
rod-deck scrubber and all the related equipment, which was tied
into the duct work of Edwards 3, a coal-fired unit that included
an ESP for primary particulate control.  During the course of
this 9-month test program, the pilot operated over 5100 hours on
boiler flue gas and achieved sulfur dioxide removal efficiencies
above 90 percent on 2 to 3 percent sulfur coal.  The most signif-
icant information gained from this plant concerned construction
materials.  Originally, the pilot scrubber, including all inter-
nals and rods, was constructed of unlined carbon steel.  Wide-
spread corrosion and ultimate failure of the carbon steel shortly
after the outset of the program necessitated replacement of the
internals and rods with Hastelloy G and 316L stainless steel.
The results of the Edwards pilot plant program are summarized in
Table 5.
                              12

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 TABLE 5.  RESULTS OF THE E. D. EDWARDS PILOT PLANT TEST PROGRAM
Gas capacity
  Nominal, m /min  (ft /min)
            3        3
  Maximum, m /min  (ft /min)
Application
Period of performance
Total operation time, h
Coal sulfur, percent
Sulfur dixoide inlet concentra-
  tion, ppm
Pressure drop, kPa  (in.
H20)
Liquid recirculation rate,
  liters/s  (gal/min)
Liquid/gas ratio, liters/m
  (gal/1000 acf)
Sulfur dixoide outlet concentra-
  tion , ppm
Sulfur dioxide removal
  efficiency, percent
      185 (6500)
      193 (6800)
 Coal-fired flue gas
Mar. 1973 - Dec.  1973
        5100
     2.0 - 3.0

        2000
      2.1 (8.6)

      20.5 (325)

       6.7 (50)

         170

         91.5
     In November 1974, following the completion of the Edwards
pilot plant test program, CILCo awarded Riley Stoker/Environeer-
ing a contract to supply a limestone FGD system for Duck Creek 1
The contract originally specified that only one module having a
25 percent gas capacity  (100 MW) be installed for testing and
evaluation on high sulfur coal.  The remaining three modules
would be installed at a later date, and any design modifications
dictated by the module evaluation program would be incorporated.
This approach was eventually rejected by the U.S. EPA, and in
August 1976 CILCo awarded Riley Stoker/Environeering a contract
to supply the remaining three modules for operation by August 1,
1978.
                               13

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PROCESS DESCRIPTION
     The limestone slurry FGD system operating at Duck Creek was
designed, fabricated, and installed by Riley Stoker/Environeering
in accordance with specifications by Gilbert/Commonwealth Asso-
ciates for operating conditions and equipment requirements.  The
FGD system consists of four parallel rod-deck scrubber modules
designed to treat the entire boiler flue gas stream of 668 m /s
(1,415,600 acfm) at 135°C (275°F).  The FGD system includes
limestone storage, preparation, and handling equipment; a duct
work and damper arrangement; waste disposal and pond water return
equipment; and service water and compressed air equipment.
     The Duck Creek FGD system can be conveniently described in
terms of six basic operations:  (1) limestone preparation, (2)
limestone slurry handling,  (3) gas treatment, (4) mist elimina-
tion, (5) gas bypass, and (6) solids disposal and water return.
Limestone Preparation
     Limestone for FGD operations is supplied by the Columbia
Quarry Company in Valmeyer,  Illinois, approximately 320 km (200
mi) from the plant site.  The limestone is delivered to the plant
by rail as 1.9 cm x 0 cm  (3/4 in. x 0 in.) rock containing no
less than 95 percent calcium carbonate.  The limestone is stored
in a feed bin with a 24-h supply capacity and transferred to a
wet ball mill, where it is ground by a weigh feeder at a maximum
rate of 36 Mg (40 tons) per hour.  The limestone is ground to a
90 percent minus 200-mesh powder and the slurried effluent from
the mill is discharged to a mill slurry tank, which is a collec-
tion sump that serves as a reservoir for the slurry pumps.  The
slurry pumps discharge the milled limestone to a classifier at a
rate of 50 liters/s (800 gal/rain).  The oversize stone (exceeding
90 percent through 200 mesh) is returned to the front of the mill
for regrinding.  Overflow from the classifier returns to the mill
slurry tank.  The effluent from the milling system consists of a
35 to 40 percent solids limestone slurry.  Figure 4 is a simpli-
fied diagram of the Duck Creek limestone preparation system.
                               14

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       LIMESTONE
MAKEUP
HATER
LIMESTONE
  FEED
  BIN
        WEIGH
        FEEDER
                                                       TO SLURRY
                                                      STORAGE TANK
                          WET BALL MILL
                          1  OPERATIONAL
                          1  SPARE
              MILL SLURRY
                 TANK
              1  OPERATIONAL
              1  SPARE
                                                    MILL SLURRY
                                                       PUMP
                                                    1 OPERATIONAL
                                                    1 SPARE
     Figure  4.  Duck Creek 1 FGD  limestone  storage  and
                     preparation facility.
                               15

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Limestone Slurry Handling
     The ground limestone slurry (35 to 40 percent solids)  from
the milling operation is stored in a 301,000-liter (79f500-gal)
agitated storage tank.  Two agitators/ one operational and one
spare, maintain slurry suspension and prevent settling.  The
slurry is transferred from the storage tank to the pumphouse
through a continuous-feed supply manifold that feeds back to the
storage tank.  Taps off the return pipe provide a flow of slurry
to each recirculation tank for use in the scrubbing module or
back to the mill slurry tank.
     The limestone slurry tapped from the storage tank return
loop is added to the liquid scrubbing circuit of each module
through a recirculation tank, which'is an agitated, 606,000-liter
(160,000-gal) vessel that receives fresh limestone slurry from
the storage tank, spent solution from the scrubber module, and
return water from the pond.  Recirculation-tank slurry is contin-
uously pumped from the base of the recirculation tank through
three 51-cm  (20-in.) diameter lines to 12 spray heads located at
the top of each scrubber module.  Pumping capacity is provided by
two 497 liters/s (7875 gal/min) operational pumps  (one spare per
module).  Discharge from the spray heads flows down through the
scrubber module, contacting the gas flowing upward through the
rod decks.  Spent solution flows by gravity to the recirculation
tank, where chemical reactions are completed and reaction prod-
ucts and unused reagent are collected.  Spent slurry is bled from
the recycle tank by a line off the recirculation pump discharge
header.  Figure 5 shows a simplified diagram of the Duck Creek
FGD system liquid scrubbing circuit, including limestone slurry
handling, scrubbing, and recirculation.
Gas Treatment
     The flue gas exits the boiler at 1140 m3/s  (2,415,000 acfm)
and 446°C  (835°F) at full load, then passes through half-size air
preheaters before entering two Pollution Control-Walther ESP's
connected in parallel.  Each ESP treats 50 percent of the total
                                16

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                            MIST
                         ELIMINATION
                       SO? ABSORPTION
                           ZONE
                        ROD-DECK
                        SCRUBBER
                       4 OPERATIONAL
                         GAS INLET-
LIMESTONE
 SLURRY
                                                                                  MAKEUP
                                                                                  WATER
                                                          SPRAY
                                                          PUMPS
                                                          8 OPERATIONAL
                                                          4 SPARE
                                                        MIST ELIMINATOR
                                                         WASHDOWN TANK
                                                         4 OPERATIONAL
                                                            BLEED TO WASTE
                                                            COLLECTION TANK
                 STORAGE
                  TANK
              SCRUBBER
   SLURRY    RECIRCULATION
 TRANSFER      TANK
   PUMP     4 OPERATIONAL
1 OPERATIONAL
3 SPARE
RECIRCULATION
    PUMPS
8 OPERATIONAL
4 SPARE
         Figure  5.   Duck Creek  1  FGD  system  scrubbing circuit.
                                             17

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gas flow.  The ESP's are designed to remove 99.8 percent of the
inlet particulate when the inlet gas loading is 14.5 mg/m  (6.34
gr/scf).  The discharge gas from the ESP's enters a manifold
supplying four induced-draft fans.  These fans overcome draft
loss in the boiler as well as in the ESP's and FGD system.   They
are connected in parallel to a common duct that distributes the
gas to each scrubber module in the FGD system or to the bypass
duct.
     Flue gas enters the base of each scrubber module,  where it
is quenched to adiabatic saturation conditions.  The quenched gas
flows upward through nine successive stages of rod decks, where
it contacts the scrubbing slurry in a countercurrent fashion.
The scrubbing slurry sprayed from the top of each module flows
downward through the rod decks.  The rod decks provide  intimate
gas/slurry contacting sites that enhance mass transfer  of the
sulfur dioxide into the liquid phase, thus promoting sulfur
dioxide removal.
     The cleaned, saturated gas stream in each module then exits
the spray zone, turns 90 degrees, and passes through horizontal
mist eliminators, where entrained droplets of moisture  and slurry
are removed.  The discharge duct from each module feeds gas into
the breeching, through which it enters the stack approximately 20
m (65 ft) above grade.  Figure 6 provides a cutaway view of the
rod-deck scrubber and mist eliminator used in the Duck  Creek FGD
system.
     Scrubbed, saturated gas exits the FGD system and enters the
stack through the breeching section without benefit of  reheat.
The "wet stack" is a 150-m (500-ft) chimney with a Cor-Ten steel
flue lined with flake glass.  Four bottom hoppers are included in
the stack for collection of moisture and slurry droplets that
fall out of the flue gas because of a difference in the veloc-
ities of the droplets and the gas.
Gas Bypass
     The FGD system is equipped with a complex network  of ducts
and dampers that allows part or all of the flue gas to  bypass any
                              18

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                               HIST ELIMINATOR
    SLURRY
  SPRAY  HEADS
   QUENCH
                                      GAS  INLET
                                                        ROD DECKS  (8)
                                                       ROD DECK (1)
                        SPENT
                        SLURRY
Figure  6.   Cutaway view  of a Duck  Creek 1 FGD scrubber  module.

                                  19

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or all of the scrubber modules during outages or emergencies.
The major components are the bypass breeching, control damper,
bypass breeching damper, induced-draft fan isolation dampers, and
scrubber module isolation dampers.
Bypass Breeching—
     A breeching section, which can accommodate all or part of
the flue gas flow, is provided for FGD gas bypass.  It consists
of a straight duct run extending from the discharge side of the
induced-draft fans to the stack entry point.  Flue gas enters and
exits the FGD system via a common inlet and discharge duct, which
routes gas to and from each of the scrubber modules.  The common
inlet and discharge ducts exit the bypass breeching downstream of
the discharge side of the induced-draft fans and enter upstream
of the stack entry point.  During partial or full load bypass
situations the flue gas can pass directly from the induced-draft
fans to the stack for discharge to the atmosphere.
     Two important features of the breeching section are the
materials of construction and an emergency water spray.  The
bypass breeching is constructed of Hastelloy G.  This material
provides superior corrosion resistance under all gas conditions,
including the hot/dry environment associated with full bypass,
the warm/wet environment associated with partial bypass and
partial scrubbing, and the cool/saturated environment associated
with full scrubbing.  The emergency water spray is situated in
the breeching just prior to the stack entry point.  The purpose
of this system is twofold:  (1) to provide emergency cooling in
the event of a high temperature excursion [exceeding 175°C (350°F)],
which could severly damage the stack liner, and (2) to provide
continuous cooling of the gas bypassing the FGD system so that
the condition of the gas passing through the stack is nearly
constant, thus extending the life of the liner.
Control Damper—
     A control damper situated in the common duct downstream of
the discharge side of the induced-draft fans regulates gas flow

                               20

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to the stack so that a maximum of 25 percent of the design gas
flow of 648 m3/s  (1,415,600 acfm) at 135°C (275°F) enters each
scrubber.  Any gas flow in excess of the design value goes
directly to the stack.
Bypass Breeching Damper—
     The bypass breeching is equipped with a single-louver shut-"
off damper that seals off the breeching, permitting flue gas to
enter the FGD system.
Induced-draft Fan Isolation Dampers—
     Each of the four induced-draft fans is equipped with double-
inlet control dampers and a double-outlet damper so that any one
of the fans can be isolated from the flue gas path.  The outlet
dampers, which are located on the discharge side of the induced-
draft fans, are double-louver, seal-air units that operate in
parallel.  A seal-air fan pressurizes the area between the
dampers when they are in the closed position to prevent gas
leakage from the pressurized discharge duct back into the fan.
Scrubber Module Isolation Dampers—
     Each of the four scrubber modules is also equipped with a
set of inlet and outlet dampers, so that any one of the modules
can be isolated from the flue gas path.  The inlet dampers, which
are located in the inlet duct to each scrubber, are double-
louver, seal-air units that operate in parallel.  A seal-air fan
pressurizes the area between the dampers when they are in the
closed position and prevents gas leakage into the scrubber during
maintenance periods or while the boiler is in service.  The
outlet dampers, which are located in the outlet duct of each
scrubber, are double slide-gate dampers that operate in parallel.
Two seal-air fans are provided for each set of outlet dampers.
One operates continuously and pressurizes the damper drive mech-
anisms.  The other pressurizes the area between the dampers when
both slide gates are in the closed position.
     Figure 7 is a simplified diagram of the Duck Creek FGD
system duct work and damper arrangement.
                               21

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                       EMERGENCY OC
                        MATER
                        SPRAYS
         ID FAN OUTLET
          DAMPERS
          ID FAN INLET
            CONTROL
            DAMPERS
ISOLATION
 DAMPERS
Figure  7.   Duck  Creek 1  duct  work and damper  arrangement.
                                  22

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Solids Pisposajl and Water Return
     Spent scrubbing slurry is bled from the scrubber recircula-
tion lines as a 15 percent solids slurry containing reaction
products, unreacted limestone, and collected fly ash.  The spent
slurry is transferred to a waste collection tank, where it is
combined with liquid waste streams from plant sumps, and then
discharged to an onsite sludge disposal pond.  The pond, which is
lined with a natural impermeable material, covers approximately
         2
263,000 m  (65 acres).  Bottom ash and collected fly ash are also
stored here.  The waste solids present in the spent scrubbing
slurry settle out in the pond, and the supernatant is returned to
the plant for reuse.  Recycled water is used in the recycle tanks
to maintain liquid levels and for sluicing the bottom ash and fly
ash to the disposal pond.  Figure 8 is a simplified diagram of
the Duck Creek waste disposal and water return loop.

PROCESS DESIGN
Fuel
     The Duck Creek 1 emission control system is designed to re-
move particulate and sulfur dioxide resulting from the combustion
of a high sulfur bituminous Illinois coal from nearby surface
mines.  Table 6 presents specifications and consumption rates of
the performance coal.
Particulate Removal
     Primary particulate control is provided by two half-size,
cold-side ESP's situated upstream of the FGD system.  These
Pollution Control-Walther ESP's are new units that were installed
as original power plant equipment.  Table 7 summarizes the design
parameters.
Sulfur Dioxide Removal
     Primary sulfur dioxide removal is provided by a four-module
limestone FGD system situated downstream of the ESP's.  Table 8
                               23

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to
                                 SPENT
                                 SLURRY
              FRESH
            LIMESTONE-
              SLURRY
                              RECIRCULATION
                                 TANKS (4)
                   PLANT SUNPS
RECYCLE
  TO
SCRUBBER
                                               RECIRCULATION
                                                 PUMPS (12)
                                        FLY ASH/BOTTOM ASH
                                                             WASTE
                                                           COLLECTION
                                                             TANK
                                                             (1)
                                                            WASTE TRANSFER
                                                               PUMPS (2)
                             L
                               WASTE DISPOSAL
                                 POND (1)
 f-\  POND WATER
7    RETURN PUMPS
                                                                                                           (2)
                  Figure 8.    Duck  Creek  1 waste  disposal  and water return  loop.

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      TABLE 6.  SPECIFICATIONS AND CONSUMPTION  RATES  OF
                 DUCK CREEK PERFORMANCE  COAL
Fuel
Grade
Source
Total raw coal  (maximum), kg/h  (Ib/h)
Sulfur  (maximum), kg/h  (Ib/h)
Hydrogen  (maximum), kg/h (Ib/h)
Ash  (maximum), kg/h  (lb/h)°
Moisture  (maximum), kg/h (Ib/h)
Volatile matter  (maximum), kg/h  (Ib/h)
                                    Q
Fixed carbon  (maximum),  kg/h  (Ib/h)
Heat input  (maximum), GJ/h  (10   Btu/h)
Pulverized coal
Bituminous
Illinois
173,839 (383,249)
7,058 (15,560)
10,430 (22,995)
31,291 (68,985)
39,983 (88,147)
60,844 (134,137)
78,227 (172,462)
4,260 (4,040)
  Moisture free.
  Moisture and ash  free.
  As received.
  Based on a coal heat  content  of 24,523 kJ/kg 10,543 (Btu/lb)
                              25

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      TABLE 7.   DESIGN PARAMETERS  OF DUCK CREEK  1 ESP
Number
Arrangement
Type
Supplier
Inlet gas conditions:
     Volume, m /s (acfra)
     Temperature, °C (°F)
     Weight, kg/h (Ib/h)
     Pressure, kPa (in.  H7O)
                     3   *
     Particulate, g/m  (gr/acf)
Outlet gas conditions:
     Volume, m /s (acfm)
     Temperature, ° C (•F)
     Weight, kg/h (Ib/h)
     Pressure, kPa (in.  H-O)
                      •>   *
     Particulate, mg/n  {gr/acf)
Removal efficiency,  percent
Two
Parallel
Cold side
Pollution Control-'-'alther

717 tl,520,000}
135 (275)
2,107,000 (4,646,000)
4.60 (18.4)
10.5 <4.57)

717 (1,520,000)
135 (275)
2,024,000 (4,463,100)
4.48 (17.9)
0.02 (0.009)a
99.Bb
  Maximum guaranteed particulate emission level.
  ESP maximum guaranteed removal efficiency based on a coal sulfur
  content of 2 percent.
                                 26

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TABLE  8.   DESIGN PARAMETERS OF DUCK CREEK 1  FGD SYSTEM3
  Inlet gas conditions:

       Volume,  m /s (acfm)

       Temperature, °C (°F)

       Weight,  kg/h (Ib/h)

       Pressure, kPa (in.  H20)

       Sulfur dioxide, kg/h  (lb/h)

       Particulate, kg/h (lb/h)

  Outlet gas conditions:

       Volume,  m /s (acfm)

       Temperature, °C (°F)

       Weight,  kg/h (lb/h)

       Pressure, kPa (in.  H_0)

       Sulfur dioxide, kg/h  (lb/h)

       Particulate, kg/h (lb/h)

  Sulfur dioxide removal efficiency,  percent
€68 (1,415,600)

135 (275)

2,107,000  (4,646,000)

2.5 (10)

14,115 (31,120)

51 (113)



572 (1,211,000)

53 (127)

2,172,000  (4,788,424)

0.5 (2)

2,074 (4,572)

60 (132)

85.3
    Maximum performance coal characteristics of  4 percent sulfur
    and 18 percent ash.
                                 27

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presents inlet and outlet gas conditions and design removal
efficiencies.
Rod-deck Scrubber
     The rod-deck scrubber is a proprietary, second-generation
design scrubbing vessel developed by Riley Stoker/Environeering
and marketed under the name Ventri-Sorber Scrubber.  The ver-
tical, multistage scrubber is a countercurrent gas-liquid flow
module which contains a series of rod decks arranged vertically
on staggered centers within the vessel.  The rods in each rod
deck are 2.5 cm (1 in.) in diameter and spaced 2.5 cm (1 in.)
apart.  Table 9 presents design parameters and operating con-
ditions of the scrubber module.  Figure 6 presents a cutaway view
of the module, showing the overall arrangement as well as the
internals.
Mist Eliminator
     Each scrubber module has a separate set of mist eliminators
arranged in a tilted-vertical position in the horizontal dis-
charge ducts.  The mist eliminators are equipped with a fresh-
water wash system which consists of a common wash-down tank and
spray pumps and piping for each mist eliminator.  The wash system
is capable of delivering 55 liters/s (885 gal/min) of freshwater
to each mist eliminator.  The water is sprayed on the second mist
eliminator, then collected in the wash-down tank and reused on
the first mist eliminator.  Table 10 presents design parameters
and operating conditions of the mist eliminators.
Gas Dampers
     The flue gas bypass network is comprised of several bypass
dampers, isolation dampers, and seal-air fans which enable the
gas to bypass any or all of the scrubber modules and induced-
draft fans during forced outages without having to shut down the
unit or reduce the load.  Table 11 presents design parameters and
operating conditions of the dampers.
                              28

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   TABLE  9.   DESIGN PARAMETERS AND OPERATING CONDITIONS
                     OF DUCK  CREEK 1  SCRUBBERS
Number of modules
Type
Configuration
Shape
Flow pattern
Dimensions
     Length, m  (ft)
     Width, m  (ft)
     Height, m  (ft)
Number of stages
Number of spray heads
Arrangement of internals:
     Number of rod decks
     Geometry

     Rod diameter  (outer), cm  (in.)
     Rod spacing, cm (in.)
Materials of construction:
     Shell
     Internals
     Rods
Inlet flue gas volume,  m /s (acfm)
Inlet flue gas temperature, °C (°F)
Flue gas velocity, m/s (ft/s)
Pressure drop, kPa (in. H_O)
Liquid recirculation rate, liters/s (gal/min)
Liquid to gas (L/G) ratio, liters/m
 (gal/103 acf)
Outlet flue gas volume, m/s (acfm)
Outlet flue gas temperature,  °C (°F)
Maximum slurry feed rate, kg/min  (Ib/h)
Rod deck
Vertical
Rectangular, inverted L
Countercurrent

12 (40)
1.5 (5)
12 (40)
9
12
Vertical, staggered
 off center
2.5 (1)
2.5 (1)
Carbon steel
Hastelloy G
316L stainless steel
167 (353,900)
135 (275)
3.9 (13)
2 (8)
994 (15,750)

6.8 (50)a
143 (302,750)
53 (127)
345 (45,600)
a
  Approximate L/G value at saturated gas conditions.
                                  29

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 TABLE  10.
DESIGN  PARAMETERS AND  OPERATINGv.CONDITIONS
OF  DUCK CREEK  1 MIST ELIMINATORS
Number

Number per module

Type

Configuration



Shape

Number of stages

Number of passes

Distance between stages, m (ft)

Distance between vanes, cm (in.)

Materials of  construction

Wash system:

     Hater source



     Point of addition/collection

     Hash direction


     Frequency

     Rate
     Pressure
                        4

                        1

                        Chevron

                        Vertical-tilted 35
                         degrees fron vertical
                         plane

                        Z-shape,  90-deqree bends

                        2

                        3

                        1.2  (4)

                        6.4  (2.5)

                        Hastellov G
                        Fresh (2nd stage);  spent wash
                         from 2nd stage collected
                         and used for 1st stage

                        Hash-down tank

                        1st stage - front and back
                        2nd stage - front

                        Continuous

                        1st stage - 56 liters/s
                         <885 qal/min)

                        2nd stage - .49 liters/s
                         (775 gal/min)a

                        Low
  Approximately 850 liters (225 gal)  per min of wash water is lost to
  gas stream as entrained moisture droplets.  Each stage contributes
  half of  this water loss.  Approximately  2500 liters  (660 gal) per
  minute of spent wash water from both  stages is drained from the
  wash-down tank to each recirculation  tank.
                              30

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 TABLE 11.  DESIGN PARAMETERS AND  OPERATING CONDITIONS OF DUCK CREEK 1 DAMPERS
Description
Induced-
draft fan
inlet
Induced-
draft fan
outlet
Bypass
breeching
inlet
Scrubber
module
inlet
Scrubber
module
outlet
Number
8
4
1
4
8
Type

Double-
louver
Single-
louver
Double-
louver
Double-
plate
slide-
gate
Manufacturer
Buffalo Forge
American
Warning
and Ventila-
ting
American
Warming
and Ventila-
ting
American
Warning
and Ventila-
ting
Environmental
Elements
Modulation

Open/closed
Open/closed
Open/closed
Open/closed
Seal air
Flow,
mVs(acfm)
Non
1.9S
(4,150)
t'one
1.95
(4.150)
0.57
(1200)
Pressure ,
kPaUn. H20)
e
5.5
(22.0)

5.5
(22.0)
\.
2.5
(10.0)
Service con-
ditions,
°C(»F)/min

370/30
(700)
232/30
(450)
232/30
(450)
232/30
(450)
Torque ,
raPa (psi)

113(16,500)*
276(40,000)
83.6(12,125)*

Comments
Inlet-control
dampers
Isolation dampers
Inlet-control
dampers
Isolation
dampers
Isolation dampers
Per side.

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Induced-draft Fans
     Four centrifugal induced-draft fans are connected in par-
allel to a common duct with internal baffling promote even gas
flow distribution to the scrubbers and/or bypass breeching.
These fans are designed to operate in tandem with the boiler
forced-draft fans to overcome draft loss in the boiler side and
emission-control side.  Each fan is equipped with a water-cooled
oil-lubrication system,  complete with pumps and coolers.  Table
12 presents the design parameters and operating conditions of the
fans.
Pumps
     The FGD system is equipped with 34  pumps covering the liquid
circuit battery limits from limestone preparation to waste solids
disposal.  Table 13 presents design parameters and operating
conditions of the pumps.
Tanks
     The liquid circuit of the FGD system is equipped with 11
major tanks for storage,  transfer,  recirculation and collection
of slurry, and addition of makeup water.  Table 14 presents
design parameters and operating conditions of the tanks.
Wet Stack
     The FGD system has no stack gas reheat system.  It is
designed so that the scrubbed gas stream exits the system at
approximately 53°C (127°F) .  The bypass  duct and stack also
handle the warm and hot flue gas streams associated with partial
and total FGD bypass.  The wide variety  of operating conditions
has necessitated the incorporation of a  number of design fea-
tures, which are summarized as follows:
     0    The bypass breeching and discharge ducts are constructed
          of Hastelloy G,  an exotic, corrosion-resistant alloy.
                              32

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TABLE  12.   DESIGN  PARAMETERS  AND  OPERATING CONDITIONS
             OF DUCK  CREEK 1  INDUCED-DRAFT  FANS
 Number

 Manufacturer

 Arrangement

 Service

 Specifications:

      Type



      Rating, kW  (hp), and rpm

      Lube system


      Bearings

      •Rotation

 Performance:

      Gas capacity, m /s  (ft /min)

      Gas temperature, °C  (°F)

      Gas density, kg/m3  (lb/ft3)

      Pressure drop,  kPa  (in. H-0)

 Materials of construction
Buffalo Forge

Parallel

Dry
Centrifugal,  double
 width,  double  inlet,
 radial  tip

2,960 (4,000),  900

Water-cooled, circulating
 oil

Self-aligning sleeve type

2 CW8, 2
205 (435,000)

149 (300)

0.785 (0.049)

9.5 (38.0)

Carbon steel
   CW = clockwise.
   CCW * counter  clockwise.
                                 33

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             TABLE 13.   DESIGN PARAMETERS AND OPERATING CONDITIONS OF DUCK CREEK 1 PUMPS
U)
Number
2
4
12
12
2
2
Service
Mill sump
Slurry
transfer and
return
Slurry re-
circulation
Hist elimi-
nator spray
Waste col-
lection
underflow
Fond water
return
Manufacturer
Galigher
Worthing ton
Worthington
Worthington
Barret
Worthington
Tytw
Centrifugal.
•lurry
Centrifugal
•lurry
Centrifugal
slurry
Centrifugal
Centrifugal
slurry
Centrifugal
Materials.
of construction
Rubber-lined
Rubber-lined
Rubber- lined
Rubber- lined
Rubber- lined
Rubber-lined
• Performance
Motor,
Jew (top)


215(290)
26435)
89(120)

Capacity,
liters/a
(gal/min)
50(800)
45(105)
497(7875)
66(1050)
100(1600)
50(800)
Speed,
rpm
1800
1800
770
1800
985
1800
Solids,
percent
55
40-50
15
0
15
0
Operation
1 operational,
1 spare
1 operational,
3 spare
8 operational,
4 spare
8 operational,
4 spare
1 operational,
1 spare
1 operational,
1 spare
                      TABLE 14.   DESIGN PARAMETERS AND OPERATING CONDITIONS
                                      OF DUCK CREEK 1 TANKS
Service
description
Slurry recir-
culation
Slurry
storage
Mist elimi-
nator wash
down
Mill slurry
Number
4
1
4

2
Dimensions,
m {ft)
11 dia. x 6. 7
(37 dia. ,x 22)
7.9 dia. x 6.1
(26 dia. x 20)
1.5 dia. x 3.0
[5 dia. x 10)


Capacity,
liters (gal)
606,000
(160,000)
303,000
(80,000)
11,400
(3,000)


Retention
time, min
10
100
3.5


Agitator
Yes
Yes
No

Yes
Materials of
construction
Rubber- lined
carbon steel
Rubber-lined
carbon steel
Rubber-lined
carbon steel

Concrete
Comments
1 per scrubber
Common
1 per scrubber

1 operational,
1 spare

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     0    Emergency water sprays are located in the discharge
          duct just prior to the stack entry point.  The water
          sprays provide emergency cooling for stack liner
          protection in the event of a high temperature excur-
          sion.  The water sprays also provide continuous cooling
          of the gas bypassing the FGD system so that a constant
          gas environment is created within the stack, thereby
          extending stack liner life.

     0    The 152-m (500-ft) stack is a reinforced-concrete
          shell.  Its Cor-Ten flue is coated with a sprayed-on
          flake-glass liner (Ceilcote 151) for protection from
          acid corrosion attack.  A venturi throat placed approx-
          imately two-thirds of the way up the stack gives the
          gas a mechanical boost before it is discharged to the
          atmosphere.  This boost causes a difference in the
          velocity of the gas and the entrained droplets, allow-
          ing the latter to fall out of the gas stream and be
          collected in four hoppers situated at the base of the
          stack.

Limestone Storage and Preparation

     Limestone arriving at the plant is either delivered to a

dead storage or live storage area or is transferred directly to

the limestone grinder building.  The dead storage area holds 90

days supply and the live storage area, 3 days.  Limestone deliv-

ered to the grinder building is stored in a feed bin having a 24-h

storage capacity.

     The limestone delivered to the storage bin is 1.9 cm (3/4

in.) and must be ground to a particle size of 90 percent minus

200 mesh.  Grinding takes place at 10 kg/s (40 tons/h) in one of

two (one operational, one spare) wet ball mills to which the

stone is supplied by a weigh feeder.  Fresh makeup water is fed

to the ball mill at 14 liters/s (220 gal/min) under maximum

conditions (100% boiler load,  4% sulfur coal).  The milled lime-

stone is discharged to a slurry tank for collection, then pumped

to a slurry storage tank via a classifier that insures a 90

percent minus 200 mesh product.  The effluent from the mill

system, which is a 40 percent solids slurry,  is retained in the

slurry storage tank for 100 minutes before it is added to the

liquid scrubbing circuit via the scrubber recirculation tanks.


                               35

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Tables 15 and 16 present design parameters and operating condi-
tions of the Duck Creek limestone storage and preparation opera-
tions .

      TABLE 15.  DESIGN PARAMETERS AND OPERATING CONDITIONS
          OF DUCK CREEK 1 LIMESTONE STORAGE FACILITIES
Description
Dead storage
Live storage
Feed bin
Number
1
1
1
Capacity, Gg (tons)
39.2 (86,400)
1.30 (2,880)
0.4 (960)
Storage, days
90
3
1
Waste Solids Disposal and Pond-water Return
     The spent scrubbing slurry from the recirculation lines of
each module is discharged to a waste collection tank where it is
combined with liquid waste streams from plant sumps and dis-
charged to an onsite sludge disposal pond.  The waste collection
tank is situated in a sludge building located approximately half
way between the plant and pond.  The sludge disposal pond, which
also accommodates bottom ash and fly ash disposal, has a 3- to 5-
yr service life.  It is lined with a natural impermeable material
to prevent contamination of water streams.  The inlet waste
stream to the disposal pond consists of a 15 percent solids
slurry containing reaction products, fly ash, bottom ash, and
unreacted limestone.  The waste solids settle out in the pond,
and supernatant is returned to the recirculation tanks to main-
tain liquid balance in the FGD system.  Table 17 presents design
parameters and operating conditions of the waste disposal system.

PROCESS CHEMISTRY:  PRINCIPAL REACTIONS
     The chemical reactions involved in the Duck Creek wet lime-
stone scrubbing process are highly complex.  Although details are.
beyond the scope of this discussion, the principal chemical
mechanisms are described below.
                              36

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TABLE 16.   DESIGN PARAMETERS AND OPERATING CONDITIONS  OF
         DUCK  CREEK 1  LIMESTONE  PREPARATION  FACILITY
Weigh feeder:
     Number
     Manufacturer
     Capacity
One
Merrick
45 Mg (50 tons)/h of
 1.3 cm (0.5 in.) stone
 at 1.5 to 1.8 Mg/m3  (95
 to 110 Ib/ft3), 65°C
 (150°F), and 15.5 m/min
 (50.95 ft/min)
Ball mill:
     Number

     Manufacturer
     Motor drive
     Mill speed, rpm
     Bearings
     Ball charge,  Mg (Ib)
     Capacity,  Mg/h (tons/h)
     Slurry solids, percent
Two (one operational, one
 spare)
Kennedy Van Saun
Falk/General Electric
18.36
Oil lubricated
67 (148,000)
36 (40)
65
Classifier:
     Number
     Manufacturer
     Dimensions, m (ft)
     Lining
     Rating
     Overflow,  Mg/h (tons/h)
     Underflow, Mg/h (tons/h)
     Inlet flow, liters/s  (gal/min)
     AP,  kPa (psig)
     Slurry solids,  percent
One
Krebs
0.3 x 1.3 (1.0  x 4.2)
Rubber
90 percent minus 200 mesh
36 (40)
72 (80)
17.7 (281)
245 (20.5)
40
                                  37

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TABLE  17.   DESIGN  PARAMETERS AND OPERATING  CONDITIONS
          OF DUCK CREEK 1 WASTE DISPOSAL  SYSTEM
Method
Number
Type

Location
Area dimensions, m  (acre)
Distance from plant, km (mil
Transportation mode
Pond permeability, cm/s (in./s)
Annual  storage capacity:
     Ash, Gg (tons)
     Reaction products, Gg '(tons)
     Volumer a  (acre-feet)
Service life, yr
Pond water return rate, liters/s (gal/min)
Pond water return points
Ponding
One
Clay-lined settling
 pond
Plant site
263,000 (65)
0,8 (Q.S)
Pipeline
10
  -8
no'10,
218 (240,000)
816 (900,000]
328,700 (266.5)
3 to 5
46.6 (738)
Recirculation  tanks
                                 38

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     The first and most important step in the wet-phase absorp-
tion of sulfur dioxide from the flue gas stream is diffusion from
the gas to the liquid phase.  Sulfur dioxide is an acidic an-
hydride that reacts readily to form an acidic species in the
presence of water.

     S°2  •          S°2(aq.)
     S°2(aq.) +H2° ^=*  H2S°3
In addition, some sulfur trioxide is formed from further oxida-
tion of the sulfur dioxide in the flue gas stream.
     2SO2   +  02 *       ».   2S03
This species, like sulfur dioxide, is an acidic anhydride that
reacts readily to form an acid in the presence of water.

     S03  «           S°3(aq.)
     S03(ag.) + H2°  *        H2S°4
     The sulfurous and sulfuric acid compounds are polyprotic
species; the sulfurous species is weak and the sulfuric species,
strong.  Their dissociation into ionic species occurs as follows:
           <     *  H+ +     ~
                     +
     H_SO. <        H  + HSO
      24                  4
           <        H  + SO4
     Analogous to the oxidation of sulfur dioxide to form sulfur
trioxide, oxidation of sulfite ion by dissolved oxygen (DO)  in
the scrubbing slurry is limited.

     2S03= +°2(aq.)  ^^   2S04=
     The limestone absorbent, which is 95 percent calcium car-
bonate by weight, is introduced into the scrubbing system as a
slurry with water.  At Duck Creek limestone is added to the  FGD
system at a stoichiometric rate of 1.5 moles per mole of sulfur

                               39

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dioxide removed.  Limestone is largely insoluble in water, and
solubility increases only slightly as the temperature increases.
In the scrubbing system,  the slurry dissolves and ionizes into an
acidic aqueous medium,  yielding the ionic products of calcium,
carbonate, bicarbonate, and hydrogen.

     CaC03 «           CaC03(aq.)
     Ca++ + H+ + C03~ <     »   CaHC03+
     CaHCO* •<   *  Ca++ +  HCO3~
     The chemical absorption of sulfur dioxide occurs in the
scrubber modules and is completed in the external recirculation
tanks .
     Ca++ + SO3= <      *" CaSO3
     Ca++ + SO,= «     * CaSO,
              4              4
The calcium sulfite and calcium sulfate reaction products, along
with the collected  fly ash and  unreacted limestone, are trans-
ferred to the  disposal pond.  After the sulfur dioxide reaction
products precipitate as hydrated calcium salts and settle out
with the other waste solids,  the supernatant is returned to the
recirculation  tanks for reuse.
     CaS03 + 1/2H20 •
     CaS04 + 2H2O <      *

PROCESS CONTROL
     The Duck Creek FGD system operations are monitored and con-
trolled from a control panel  situated in a cubicle in the lime-
stone grinder building.  The  control cubicle contains the analog
and digital control elements  for automatic monitoring and control
of the FGD process inlet and  outlet streams.  The principal con-
cerns of this control network are flue gas flow, reagent feed,
and slurry solids.

                               40

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Flue Gas Flow
     Gas flow through the scrubber modules is monitored and
controlled to prevent overloading and loss of chemical control.
Control is accomplished by maintaining a constant pressure drop
across the system.  Each scrubber module has differential pres-
sure sensors in the inlet and outlet gas ducts.  These sensors
relay signals through a differential pressure transmitter to a
controller in the boiler control room.  The controller maintains
a constant pressure drop of 2 kPa (8 in. H20) across each module
by adjusting the bypass damper in the bypass breeching through
modulation of an electric drive.  This single-louver shutoff
damper can be modulated to any position between fully open and
fully closed to maintain proper gas flow distribution and con-
stant pressure drop.
     Another important aspect of this control network is the
operation of isolation dampers.  Each scrubber module is equipped
with one double-louver, seal-air damper on the inlet and two
slide-gate, seal-air dampers on the outlet.  Each damper is
powered by an electric drive and controlled automatically or
manually from the control cubicle.  The automatic control network
is actuated by differential pressure and liquid flow sensors in
the mist eliminator and scrubber recirculation liquid loops.
When below normal values are registered in either of these loops,
the dampers are automatically closed and seal-air fans are
activated to insure complete seal-off.*  The dampers reopen when
readings return to normal in both loops.  Each damper can be
operated manually from the control cubicle during periods of
reduced load or outages.  During manual operation the dampers can
be moved to a closed or intermediate position and reopened only
when readings return to normal.
Reagent Feed
     Fresh limestone slurry is continuously added to the FGD
scrubber recirculation tanks to compensate for reagent consumed
  One set of seal-air fans operates continuously, pressurizing
  the damper drive mechanisms for the outlet slide-gate dampers
  of each scrubber module.
                               41

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in scrubbing operations/  thereby maintaining sulfur dioxide
removal efficiency and chemical  integrity.   The flow of fresh
limestone slurry into the scrubbing circuit is controlled in an
automatic feed-forward/feedback  manner.   Primary control is
provided by the feed-forward network,  which utilizes the inlet
gas stream's sulfur dioxide concentration and flow rate.  Fine
control or "trim" is provided by the feedback network,  which
utilizes slurry pH and inlet slurry flow rate.  The following
paragraphs summarize the  specifics of these control networks.
     The flow of sulfur dioxide  and boiler gas is measured by
sulfur dioxide gas monitors and  boiler load signals originating
in the boiler control room.  Sulfur dioxide is measured by six
continuous gas monitors situated at the system inlet duct, at the
system outlet duct, and at each  scrubber module outlet.  The
signals from all these monitors  are recorded and transferred to
an analyzer, which transmits a signal to a computer, indicating
the inlet sulfur dioxide  concentration.   The boiler load signal
is also transmitted to the computer, indicating the proportional
amount of limestone slurry needed for sulfur dioxide removal.
This output signal enters another computer, which produces four
separate signals that then enter a flow controller.  The flow
controller is connected to an actuator that regulates the posi-
tion of a butterfly control valve.  Each of these signals can be
biased in relation to the individual scrubber module gas flow.
     The flow controller  also receives two input signals from pH
monitors situated in the  recirculation tanks and from another
computer, which transmits an output signal proportional to slurry
flow rate into the recirculation tanks.   The input signals for
this computer are provided by a  magnetic flow meter and density
meter located in the storage tank slurry loop and the storage
tank itself.
     These three signals  (inlet  gas flow/sulfur dioxide concen-
tration, slurry pH, and slurry flow) provide the input to the
flow controller that actuates the flow control valves located in
                               42

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each of the four tap lines, which draw off fresh slurry from the
storage tank return loop.  The slurry pH control point is set at
5.5 to 6.0.
Slurry Solids
     The solids content of the slurry in the scrubbing circuit is
controlled at the 15 percent level by monitoring the liquid level
of the recirculation tank, the slurry density, the fresh slurry
flow rate, and the spent slurry flow rate.  A recirculation
tank level controller and a slurry discharge controller are used
in conjunction with a computer to operate a slurry discharge
flow control valve for each scrubber.  Input signals to the
computer and controllers are sent from differential pressure
level transmitters and density meters in the recirculation tanks
and from flow meters in the slurry feed and discharge lines.
Using these signals, the controllers maintain a set ratio between
incoming and outgoing slurry to the recirculation tanks and the
overflow spent wash water from the mist eliminator wash-down
tanks to maintain a 15 percent solids level in the slurry scrub-
bing circuit.
                              43

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                            SECTION 4
                     FGD SYSTEM PERFORMANCE

BACKGROUND INFORMATION
     Originally CILCo intended to install one scrubber for the
control of sulfur dioxide emissions at Duck Creek 1, and to
evaluate its effectiveness on high sulfur coal before proceeding
with the design, installation,  and operation of the remaining
scrubber modules.  It was believed that such a modular approach
would produce sufficient operating data on the scrubbing of flue
gas produced by high sulfur coal so that any drastic design
changes might be made without large capital investments or unit
load reductions.
     In 1974 the Illinois EPA approved the modular approach for
the Duck Creek 1 FGD system.   Permission was granted for CILCo to
build and operate only one 100-MW equivalent scrubber module
initially, and to build the remaining three modules after this
module had been tested sufficiently.   As a result of this ruling,
CILCo awarded a contract to Riley Stoker/Environeering (in
November 1974)  for the design and construction of an FGD system
that included only one scrubber module to treat 25 percent of the
total boiler flue gas flow.
     In October 1975, the U.S.  EPA served a notice of violation,
requiring the entire plant to comply with New Source Performance
Standards governing sulfur dioxide emissions.  The utility
obtained a consent decree and elected to move up the expected
completion date of the remaining scrubber modules to August 1,
1978, and on August 26, 1976, awarded Riley Stoker/Environeering
a contract to supply these modules.  The utility was also granted
a variance to fire high sulfur coal in the boiler from July 1,
                               44

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1976, to April 1, 1977, for test purposes.  The unit could be
operated at full load during this period with both ESP's and one
scrubber module in the gas path.
     The first scrubber module  (D-scrubber) was completed in June
1976, placed in service on July 1, 1976, and operated intermit-
tently throughout the fall and winter and for approximately 1
month in the spring of 1977.  The purpose of this operation was
to verify process chemistry and design.  During this brief period
of service, several problems became apparent, making subsequent
design modifications necessary.  The modifications were made and
the remaining modules were installed between April 1977 and July
1978.  During this time the utility burned low sulfur coal in
order to meet the sulfur dioxide emission standard of 516 ng/J
(1.2 lb/10  Btu).  Initial startup of the entire FGD system
commenced on July 23, 1978.
     Because the Duck Creek 1 FGD system has only recently
attained commercial operating status, operating data are limited.
However, the data obtained during the D-scrubber test (removal
efficiencies, problems, solutions, and necessary design modifi-
cations) are discussed in the remainder of this section.

OPERATING HISTORY AND PERFORMANCE
     Duck Creek 1 commenced commercial operation on June 1, 1976,
and the D-scrubber module was initially placed in the flue gas
path on July 1, 1976.  The limited operation during the balance
of July and August was due primarily to construction deficien-
cies, such as bad welds, faulty pipe hangers, and slurry leaks
in the scrubber.  The D-scrubber was taken out of the gas path to
resolve these problems and put back in on September 9.  It
operated  (intermittently) for approximately 360 hours during the
balance of the month, 385 hours in October, and 24 hours in
November.  During these periods a number of major operating
problems were encountered, including massive mist eliminator
scale, spray nozzle and pipe plugging, and materials failure.
                               45

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The module remained out of service from December through February
because of a scheduled 3-month boiler/turbine overhaul.   During
this outage a number of modifications were made to the scrubber
in order to correct the major operating problems encountered.
The unit was placed back in service in mid-March, and the D-
scrubber operated almost continuously for 350 hours during the
balance of the month.   During April and May,  testing was to
concentrate on operating the automatic control loops; however,
the testing was terminated prematurely because of installation
difficulties, and the  D-scrubber was taken out of service.  The
unit remained in service with the boiler firing low sulfur
Colorado coal.  The ESP's also remained in service, and with the
aid of sulfur trioxide gas injection, removed particulate from
the flue gas generated by the burning of low sulfur coal.  The D-
scrubber was placed back in the flue gas path on July 23, 1978,
along with the other scrubber modules.  Table 18 summarizes the
performance of the D-scrubber during the July 1976 to April 1977
test period.

PROBLEMS AND SOLUTIONS
     The interim testing of the D-scrubber module revealed
several chemical, mechanical,  and design-related problems and
prompted a number of modifications to the system.  All of the
problems were not directly related to design deficiencies how-
ever; some were caused by operating the scrubber before it was
completely installed.   These items are discussed briefly in the
paragraphs that follow.
Chemical Problems
     Many of the chemical problems that beset the D-scrubber
module and ancillary equipment were caused or aggravated by an
incomplete instrumentation/control network.  The sophisticated
automatic control system could not be put in service during this
early stage of operation.
                              46

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TABLE 18.  DUCK CREEK 1 D-SCRUBBER MODULE PERFORMANCE HISTORY
Period
Jul. 1976
Aug. 1976
Sept. 1976
Oct. 1976
Nov. 1976
Dec. 1976
Jan. 1977
Feb. 1977
Mar. 1977







Apr. 1977-
Jun. 1978
Jul. 1978
Module, Service
8 h
18 h
360 h
385 h
24 h


350 h









Comments
Initial operation of the D-scrubber module for shakedown and debugging
purposes occurred during the month. Limited service time resulted from
bad welds, faulty pipe hangers, and slurry leaks in the module.
Limited operations continued because of continued startup and construction
problems. The module was taken out of the gas path to concentrate on
resolving these problems.
Module restart occurred on September 9. Operation continued throughout
the remainder of the month on an intermittent basis. Major problems
included pipe breaking, pump liner failures, plugging and sealing of mist
eliminators, and some boiler-related problems. The module remained in
service for approximately 15 days of noncontinuous operation.
Total operation time during the month amounted to approximately 16 days
(noncontinuous). The major problem was the continuation of massive scale
development on the mist eliminators, resulting in plugging of the piping
and nozzles to the components spray system.
Sporadic operation resulted from continued scaling problems in the mist
eliminator section. Riley and CILCo initiated modifications to the design
of the module. Specifically, a rod deck was changed in the absorber,
pressure drop across the absorber was increased, piping and pump liner
materials were modified/replaced, and. a freshwater wash system was installed
for the mist eliminator.
The module remained out of service the entire month. During this time, the
boiler fired low sulfur (0.6%) Kentucky coal.
Duck Creek 1 was down throughout the entire period for turbine/boiler over-
haul. During the outage, a number of modifications were made to the scrubber.
Duck Creek 1 returned to service in mid-March. The D-scrubber was placed in
service to test the following modifications made during the preceding outage:
• The mist eliminator spray wash system piping was changed from PVC to FRP
materials, and another spray header was added.
• The slurry circulation system was revamped.
• The original natural rubber liners were replaced with neoprene liners.
Flush/drain systems have been included to minimize solids build up.
• Piping valves were moved closer to the recycle tank.
" Slurry storage tanks were equipped with flush/drain systems.
• Additional mixers were added for greater agitation to promote process
chemistry.
Except for a few minor boiler outages, the module remained in service on a
continual basis during the last part of March.
The firing of Colorado low sulfur coal commenced on April 1 and continued
until July 1978.
Operation of the FGD system with all four scrubber modules in the flue gas
path commenced on July 23, 1978.

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     Primary difficulties involved frequent scaling and plugging
of the mist eliminators.  Although these problems were attributed
primarily to the lack of automatic controls, the wash system was
modified to provide more efficient washing.  Specifically, the
polyvinyl chloride materials used in the wash water piping that
feeds water from the wash-down tank to the spray nozzles for each
mist eliminator stage were replaced with fiberglass-reinforced
plastic.  Also, an additional spray header was added to the wash
system to provide more thorough rinsing.
     Another chemical problem was the widespread corrosion of the
Ceilcote 151 flake-glass liner that was sprayed on the Cor-Ten
steel stack flue to a thickness of 0.5 mm (20 mils).  Inspection
of the liner following the D-scrubber test program revealed
blistering and acid corrosion as well as subsequent widespread
corrosion of the flue.  The major factor contributing to this
problem seemed to be the intermittent and partial scrubbing load.
This caused the gas conditions to vary widely when passing
through the stack, resulting in premature failure of the liner
because operating conditions exceeded the design conditions
specified for the materials.  Two other factors may have contri-
buted to liner failure:  the liner material itself  (it is no
longer offered by the supplier for stack lining applications) and
the absence of a stack gas reheat system.
     The utility has since repaired areas where cracked and
peeled liner exposed bare metal surface, but information on the
success of these repairs is not available.  Other U.S. utility
FGD systems using this wet stack approach have met with the same
fate—widespread corrosion of liner, flue, and/or stack, which
ultimately required extended outages for repair and/or modifica-
tion.

Mechanical Problems
     Many of the mechanical problems encountered involved pre-
mature pump lining failures and damper leakage.  Originally, all
the slurry recirculation and transfer pumps were lined with
                               48

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natural rubber, and pump cavitation, which occurred frequently,

caused the linings to be stripped from the casings.  To rectify

this, CILCo replaced the natural rubber linings in the slurry

recirculation pumps with neoprene linings and the linings in the

remaining slurry pumps with reinforced natural rubber.

     The utility also equipped all the slurry pumps with a flush-

out system.  Because the circulating fluid is a slurry (15%

solids in the recirculation and discharge lines and 40 to 55% in

the transfer lines), solids settle out when flow is stopped.  If

they settle out in the pump, the pump impeller and lining can be

damaged on startup.  Therefore, a flush system was installed to

purge the pump with freshwater whenever the system is not in

service.

Design-related Problems

     Several design deficiencies were observed either to have

caused or aggravated the chemical and mechanical problems just

discussed.  These deficiencies are summarized below.

     0    The ceramic spray nozzles in the scrubber spray heads
          were originally spinner-vane type.  Repeated plugging
          of these nozzles prompted replacement with orifices in
          the flow lines (open-pipe arrangement) and splash
          plates on the top rod deck.  The flow orifices reduced
          the liquid stream from 10 to 5 cm (2 to 4 in.), and the
          splash plates reduced the potential for erosion of the
          top rod deck and helped to achieve proper liquid dis-
          tribution .

     0    Much of the mist eliminator fouling was attributed to
          an unexpectedly high carryover of slurry solids in the
          gas stream.  These solids were eventually deposited on
          the mist eliminators, causing fouling, increased pres-
          sure drops across the mist eliminators, and ineffi-
          ciency of mist eliminator operation.  Eventually the
          scrubber module had to be shut down to clean the mist
          eliminators.  This problem was corrected by increasing
          the pressure drop across the scrubber by modifying the
          rod decks.  This modification reduced the entrainment
          of slurry solids in the gas stream and reduced fouling
          in the mist eliminator.
                               49

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          In addition to the slurry pumps,  freshwater flush and
          drain systems were added to all the slurry storage
          tanks, recirculation tanks, and pipe lines to purge
          them of solids that settle out during periods of
          inactivity.

          Erosion of piping valves in the scrubber recirculation
          lines was eliminated by moving the valves closer to the
          recirculation tanks.  Freshwater flush and drain
          systems have also helped to extend valve life.

          An improper gas velocity profile in the scrubber con-
          tributed to some of the problems.   Riley Stoker/
          Environeering is now attempting to determine the actual
          profile and necessary corrective action.

          Additional agitation was added to all the slurry tanks
          to maintain solids suspension in the slurry circuit,
          minimize solids settling, and promote reaction chemistry.
REMOVAL EFFICIENCY

     Because the FGD system has attained its commercial operating

status so recently,  sulfur dioxide removal efficiencies for full-

scale operations are not available;  however, sulfur dioxide

removal efficiency was measured on the D-scrubber module during

the interim test. The results (summarized in Table 19) indicate

that the removal efficiency was 91.6 percent, which exceeds the

design maximum guarantee value of 85.3 percent.*  This measure-

ment was taken for sulfur dioxide inlet concentrations of 3000

ppm.

        TABLE 19. RESULTS OF THE D-SCRUBBER MODULE TEST
Gas capacity, m /s (acfm)
Sulfur dioxide inlet concentration, ppm
Pressure drop, kPa (in. H,O)
3
Liquid/gas ratio, liters/m
(gal/103 acf)
Sulfur dioxide outlet concentration,
ppm
Sulfur dioxide removal efficiency,
percent
140 (300,000)
3000
2.2 (8.8)
6.8 (50)
252
91.6
  The efficiency guarantee applied to 4 percent sulfur coal.

                               50

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     Particulate removal efficiency measurements taken during the
D-scrubber test program also proved interesting in that the
scrubber was apparently removing as much as 70 percent of the
inlet particulate matter after it had passed through the upstream
ESP's even though scrubbers are not designed to provide any
additional particulate removal capability beyond that of the
emission control system.*  The utility and system supplier indi-
cate that this serendipitous phenomenon may be attributed to the
ionization and/or agglomeration of the small particles provided
by passage through the upstream ESP's, which would greatly en-
hance collection of these particles in the downsteam scrubber.

SYSTEM ECONOMICS
     The total capital cost of the FGD system reported by CILCo
is $37,540,000.  This includes $33,740,000 for the entire system
and all ancillary equipment and $3,800,000 for the sludge dis-
posal pond.  Based on a unit gross generating capacity of 416 MW,
this amounts to $90.2/kW.  Actual annual cost figures for the FGD
system are not available because of limited operation to date.
However, based on the limited operation of one module, the
utility estimates that the total annual cost of the flue gas
desulfurization system is $13,921,000.  This includes $7,539,000
for variable charges and $6,382,000 for fixed charges.  Based on
a net unit rating of 400 MW and a capacity factor of 65 percent,
this would amount to 6.11 mills/kWh in total annual cost.
  The FGD system is guaranteed not to add any particulate loading
  to the discharge gas stream as measured at the outlet of the
  ESP's.
                               51

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                           APPENDIX A



                        PLANT SURVEY FORM






A.   Company and Plant Information



     1.   Company name; Central Illinois Light Company	



     2.   Main office:  300 Liberty Street, Peoria, Illinois
     3.   Plant name:  Duck Creek
     4.   Plant location:   Canton, Illinois
     5.   Responsible officer:



     6.   Plant manager:	
     7.   Plant contact:  Larry Haynes
     8.   Position;  Manager, Environmental Affairs



     9.   Telephone number:  (309)/672-5221	
    10.   Date information gathered;  April 1977
     Participants in meeting                 Affiliation



     L. Haynes	   Central Illinois Light Company



     B. Laseke	   PEDCo Environmental, Inc.	



     J. Tuttle                     PEDCo Environmental, Inc*
                               A-l

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B.   Plant and Site Data
     1.   UTM coordinates:
     2.   Sea Level elevation:
     3.   Plant site plot plan (Yes, No): Yes
          (include drawing or aerial overviews)
     4.   FGD system plan (Yes, No); Yes	
     5.   General description of plant environs;  The plant  site
          occupies unreclaimed  strip-mined  land situated  in a
          flat,  rural area.	
     6.   Coal shipment mode(s);  Coal  is  delivered  to  the plant
          site  primarily  by  rail.   Provisions  have  been made to
          accommodate truck  shipments  because  of the capability
          for barge  unloading on  the Illinois  River.	
C.   FGD Vendor/Designer Background
     1.   Process:  Limestone	
     2.   Developer/licensor;   Riley  Stoker/Environeering	
     3.   Address;   P.O.  Box  547,  Wooster,  Massachusetts/  01613

     4.   Company offering process:
          Company:  Riley  Stoker/Environeering	
          Address: P.O.  Box 547,  Wooster,  Massachusetts,  01613
                                A-2

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          Location:
          Company contact;    Tom Robinson
          Position;  Design Engineer
          Telephone number:
     5.    Architectural/engineer:

          Company:    Gilbert/Commonwealth

          Address:
          Location:   Jackson, Michigan
          Company contact:   H. W. Sauer
          Position;   Project Manager
          Telephone number:	

D.   Boiler Data

     1.   Boiler:   Duck Creek 1
     2.   Boiler manufacturer:   Riley Stoker
     3.   Boiler service  (base, intermediate, cycling, peak):

          Base	



     4.   Year placed in service;   1976
                                         12,000
     5.   Total hours operation  (date):; .'Capproximate to 1Q/1/781

     6.   Remaining life of unit; 30-year life span	

     7.   Boiler type;  Pulverized-coal, balanced-draft, front-fired

     8.   Served by stack no. :  one	

     9.   Stack height;   152 m  (500 ft)	
    10.   Stack top  inner diameter:	

    11.   Unit ratings  (MW):

          Gross unit rating;   416 MW
          Net unit rating without  FGD;  410 MW
                                A-3

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     Net unit rating with FGD;   400 MW
     Name plate rating:  416 MW
12.   Unit heat rate:	
     Heat rate without FGD:  10,130 kJ  net/kWh  (9600  Btu/net kWh)
     Heat rate with FGD; 10/380 kJ/net  kWh (9840 Btu/net kWh)
13.  Boiler capacity factor, (1977);   55-60%	
14.  Fuel type:   Coal 	__
15.  Flue gas flow rate; 688 m3/s (1,415.600 acfm)	
     Maximum:  688 m3/s (1,415,600 acfm)	
     Temperature:  135°C (275°F)	
16.  Total excess air:	
17.  Boiler efficiency:	
Coal Data
1.   Coal supplier(s):
     Name(s}:  United Freeman
     Location(s);Mines are situated close to plant site in
     Fulton County near Canton, Illinois.	
     Mine location(s): Canton, Illinois	
     County, State; Fulton, Illinois
     Seam:
2.   Gross heating value: 25,523 kJ/kg  (10,543 Btu/lb)
3.   Ash  (dry basis):  9.12%	
4.   Moisture:  18.0%
5.   Sulfur  (dry basis);   3.3%
6.   Chloride:   0.03%     	
7.   Ash composition  (See Table Al) -  Not available.
                           A-4

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                       Table Al
F.
                                           Percent weight
                                           Not available
   Constituent



Silica, Si02



Alumina, Al_03



Titania, TiO2



Ferric oxide, Fe~G-3



Calcium oxide, CaO



Magnesium oxide, MgO



Sodium oxide, Na-0



Potassium oxide, K2O



Phosphorous pentoxide, PO^C



Sulfur trioxide, SO.,



Other



Undetermined





Atmospheric Emission Regulations



1.   Applicable particulate emission regulation



     a)   Current requirement:   43 ng/J  (0.1 lb/106 Btu)



          Regulation and section;  Federal NSPS _



     b)   Future requirement: _
          Regulation and section:
     Applicable SO- emission regulation



     a)   Current requirement: 516 ng/J  (1.2 lb/10  Btu)



          Regulation and section No.; Federal NSPS	



     b)   Future requirement:	
          Regulation and section:
                           A-5

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Chemical Additives:   (Includes all reagent additives -
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)

1.   Trade name:  Limestone	______
     Principal ingredient;  Calcium carbonate (95% minimum)

     Function:  Absorbent	

     Source/manufacturer: Columbia Quarry Company	

     Quantity employed; 152 Gg/yr (168,000 tons/yr)	

     Point of addition;  Scrubber recirculation tanks	

     Trade name;  Carbide lime	.	

     Principal ingredient:  Calcium hydroxide	

     Function:  Emergency pH control additive	

     Source/manufacturer;  AIRCo	
     Quantity employed;  Emergency pile maintained at plant

     Point of addition: Scrubber recirculation tanks	

3.   Trade name:  Not applicable	.	
     Principal ingredient:

     Function:
     Source/manufacturer:

     Quantity employed:	

     Point of addition:
     Trade name;  Not applicable
     Principal  ingredient:

     Function:
      Source/manufacturer:

      Quantity  employed:	

      Point  of  addition:
                           A-6

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     5.   Trade name:  Not applicable
          Principal ingredient:



          Function:
          Source/manufacturer:



          Quantity employed:	



          Point of addition:
H.   Equipment Specifications



     1.   Electrostatic precipitator(s)



          Number:  Two
          Manufacturer;  Pollution Control - Walther



          Design removal efficiency:  99.8	
          Outlet temperature;  135°C  (275°F)
          Pressure drop;  0.13 kPa  (0.5 in. H2O)



          Mechanical collector(s) - Not applicable



          Number:	,	



          Type:___	



          Size:                            	
          Manufacturer:
          Design removal efficiency:



          Pressure drop:	
     3.   Particulate scrubber(s) - Not applicable



          Number:	



          Type:	
          Manufacturer:



          Dimensions:
          Material, shell:
                               A-7

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     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:    Four
     Type;  Vertical,  rod-deck (Ventri-Sorber scrubber)	



     Manufacturer:    Riley Stoker/Environeering	



     Dimensions; 12 m x 12 m x 1.5 m (40 ft x 40 ft x 5 ft)
                           A-8

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     Material,  shell:   Carbon steel
     Material,  shell  lining;  Not applicable
     Material,  internals:  316L SS  (rods) and Hastelloy G

     No.  of  modules  per train:   1  gpray  zone,  9  rod  decks

     No.  of  stages per module:	
     Packing/tray type:  Rod deck
                              2.5 cm  (1 in.) rods spaced
     Packing/tray dimensions:  2.5 cm  Q in.) apart	

     No.  of  nozzles or sprays:	12 spray heads	

     Nozzle  type:  Open pipe arrangement	

     Nozzle  size;   5  cm  (2 in.) flow  orifices	

     Boiler  load capacity; 25%*	
     Gas flow and temperature: 167 m3/s  (353,900 acfm) *	

     Liquid recirculation rate:	994 liters/s  (15,.750 gal/min)

       Modulation:    50%	

     L/G ratio;  6.8 liters/m3 (50 gal/103  acf)	

     Pressure drop;    20  kPa  (8.0 in.  H?Q)	

       Modulation:	

     Superficial gas velocity; 3.9 m/s (13  ft/s)	

     Particulate removal efficiency (design/actual);  0/75

       Inlet loading:  Q.Q2 mq/m3 (0.009 qr/acf)  (design)

       Outlet loading; Q.Q2 mq/m  (0.009 qr/acf)  (design)

     SO- removal efficiency (design/actual):  85.3/91.6	
                            4123  ppm (max.  design)/
       Inlet concentration: 3000  ppm (actual)	
                             575  ppm (max.  design)/
       Outlet concentration; 252  ppm (actual)	

     Wash water tray(s) - Not applicable

     Number:                                     	
*
  Per scrubber module.
                           A-9

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     Type:	
     Materials of construction:
     Liquid recirculation rate:
     Source of water:
6.   Mist eliminator(s)
     Number:   Four, one per  module
     Type:   Chevron
     Materials of construction:  HasteHoy G
     Manufacturer;  Riley Stoker/Environeerinq	
     Configuration  (horizontal/vertical);  Vertical  - 35° tilt
     Number of stages;  TWO	
     Number of passes per stage; Three	
     Mist eliminator depth:	
     Vane spacing;  6.4  cm (2.5 in.)
     Vane angles; 90-degree sharp-angle bends	
     Type and location of wash system; Front and back spray
     (1st stage); front spray (2nd stage) .	
     Superficial gas velocity;  3.6 m/s (12 ft/s)	
     Freeboard distance:                               	
     Pressure drop;   0.25  kPa (1.0 in.  H?O)	
     Comments:  Mist eliminator wash-down tanks supply fresh-
     water and spent wash  water for cleaning;  1st stage -
     56 liters/s (885 qpm) and  2nd stage  - 49  liters/s	
                                             (775 gal/min)
7.    Reheater(s):  Not applicable - wet stack	
     Type (check appropriate category) :	
                           A-10.

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          in-line



          indirect hot air



          direct combustion



          bypass



          exit gas recirculation



          waste heat recovery



          other
     Gas conditions for reheat:  Not applicable



       Flow rate:
       Temperature:
       S0~ concentration:



     Heating medium:	
     Combustion fuel:
     Percent of gas bypassed for reheat:



     Temperature boost (AT):	



     Energy required:	
     Comments:  The system is not equipped with a stack-gas



     reheat system.  A wet stack is equipped with hoppers
     for collection of entrained droplets.	



8.    Fan(s)  - Service for boiler, ESP's, and FGD system.



     Number:  Four, induced-draft (with respect to boiler)



     Type: Centrifugal, double-width, double-inlet, radial tip



     Materials of construction; Carbon steel	



     Manufacturer; Buffalo Forge	



     Location: Dry, between ESP's and FGD system	



     Rating:  2960 kW (4000 hp)	
     Pressure drop; 9.5 kPa (38.0 in. H20)
                          A-11

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     Recirculation tank(s):

     Number:   Four
     Materials of construction:  Rubber-lined carbon  steel
     Function: Collection of spent  solution/limestone makeup
                               11 m dia.  x  6.7  m    addition.
     Configuration/dimensions; (37  ft dia.  x 22 ft)	
     Capacity:  606,000 liters  (160,000  gal)

     Retention time:  10 minutes         	
     Covered (yes/no):  No

     Ag itator:   Yes	
10.  Recirculation/slurry pump(s):
Service
Slurry
recirculation
Slurry
transfer
Number
12
4
Type
Centrifugal
slurry
Centrifugal
slurry
Manufacturer
Korthington
Worth ington
Capacity
497 liters/s
(7875 gal/min)
45 liters/s
(705 gal/min)
Operation
12 total
8 operational
4 spare
4 total
1 operational
3 spare
11.
Thickener(s)/clarifier (s) - Not applicable

Number:	

Type:	
     Manufacturer:
     Materials of construction:

     Conf iguration:	

     Diameter:	

     Depth:	
     Rake speed:
     Retention time:
12.  Vacuum filter(s) - Not applicable
                            A-12

-------
     Number:




     Type:
     Manufacturer:
     Materials of construction:



     Belt cloth material:	



     Design capacity:	



     Filter area:
13.  Centrifuge (s) - Not applicable



     Number:	



     Type:	
     Manufacturer:
     Materials of construction:



     Size/dimensions:	



     Capacity:	
14.  Interim sludge pond(s) - Not applicable



     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
          Description;  Clay-lined settling pond
          Area:  263,000 m2 (65 acres)	
          Depth:
          Location:   On site, 0.8 km (0.5 mi) from plant
          Transportation mode;  Pipeline	
          Service life:  3 to 5 years
          Typical operating schedule; Continuous flow from waste
          collection tank.	
     16.  Raw materials production - Limestone preparation
          Number: Two mills (one operational/one spare)	
          Type:  Wet ball mill, oil-lubricated
          Manufacturer:  Kennedy Van Saun	
          Capacity:    36 Mg/h (40 tons/h)	
          Product characteristics; Slurry - 65 percent solids
          stream, which is transferred to a mill slurry tank and
          then to a  storage tank for addition to recirculation tank.
I.   Equipment Operation, Maintenance, and Overhaul Schedule
     1.    Scrubber(s)  - Not applicable
          Design life:	
          Elapsed operation time:	
          Cleanout method:
          Cleanout frequency:
          Cleanout duration:
          Other preventive maintenance procedures:
     2.    Absorber(s)  - Not available
                               A-14

-------
     Design life:
     Elapsed operation time:



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures:
3.    Reheater(s)  - Not applicable



     Design life:	
     Elapsed operation time:



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures
4.   Fan(s) -  Not  available



     Design life:	
     Elapsed operation time:



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures







     Mist eliminator(s) -•  Not  available



     Design life:	



     Elapsed operation time:	









                          A-15

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     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures:
6.   Pump(s)- Not available



     Design life:	
     Elapsed operation time:



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures:
7.   Vacuum filter(s)/centrifuge(s)- Not available



     Design life:	



     Elapsed operation time:	



     Cleanout method:
     Cleanout frequency



     Cleanout duration:
     Other preventive maintenance procedures:
8.    Sludge disposal pond(s)



     Design life:   3 to 5 yr
     Elapsed operation time:



     Capacity consumed:	



     Remaining capacity:	
                          A-16

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          Cleanout procedures:
J.   Instrumentation - See text, Section 3, Process Control
                       subsection.
     A brief description of the control mechanism or method of
     measurement for each of the following process parameters:
          Reagent addition:
     0    Liquor solids content:
          Liquor dissolved solids content;
          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
                       £•                 X
          flue gas:
          Gas flow:
          Waste water
          Waste solids:
     Provide a diagram or drawing of the scrubber/absorber train
     that illustrates the function and location of the components
     of the scrubber/absorber control system.

     Remarks:  See text  of report concerning specific instrumenta-

     tion and process control network.	
K.   Discussion of Major Problem Areas:  See text of report con-
                                         cerning problem areas.
     1.   Corrosion:
                                A-18

-------
2.   Erosion:
3.   Scaling:
4.   Plugging:
5.   Design problems:
6.   Waste water/solids disposal:
                           A-19

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     7.   Mechanical problems
L.   General comments:
                               A-20

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   APPENDIX B




PLANT PHOTOGRAPHS
         B-l

-------
      View of Duck Creek Station.  Featured to the right of the
      stack are the boiler and turbine houses.
2.   View of Duck Creek dead coal storage area.  Featured are
     the stacker/reclaimer  (foreground) and waste disposal pond
     (background).   Limestone dead storage is maintained at the
     far end of the coal dead storage area.
                                 B-2

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3.    View of carbide lime supply kept at the plant site for use
     during emergency pH control excursions.
 4.   View of Duck Creek cooling pond.  Inverted weir featured
      at right allows water to be withdrawn from the deeper,
      cooler levels of the pond.
                              B-3

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5.    Discharge canal for cooling water return to cooling pond.
6.    View of waste disposal pond.   Featured at far end of pond
     are fly ash,  bottom ash,  and scrubbing wastes, which are
     discharged to pond for final disposal.
                            B-4

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7.   View of coal transfer houses and conveyor.  The coal
     transportation network is also capable of handling
     limestone.
8.    View of Duck Creek ESP.  Featured at the left is one of
     the four parallel double-inlet induced-draft fans.
                           B-5

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9.    Side view of Duck Creek D-scrubber module.  Featured
     from right to left are the ESP outlet duct, induced-
     draft fan, scrubber module and recirculation tank,
     bypass breeching, and stack.
                          .. -
    10.   Side view of Duck Creek  D-scrubber  module
                         B-6

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11.   View of induced-draft fans and discharge duct work.
     Double-louver seal-air dampers are featured in discharge
     duct near center of photo.
                           B-7

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12.    View of top portion of stack.   Featured is stack plume
      with unit operating at full load and ESP's in service
      during low-sulfur coal combustion.
                          B-8

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  13.    Close-up  view of D-scrubber  module  recirculation  tank
14.    Mist eliminator PVC wash piping showing solids deposition
      incurred during initial operation of D-scrubber module.
                              B-9

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                                   TECHNICAL REPORT DATA
                            (Please read Instruction* on tin irio«< bijon rr*»u/>/r/»u''
1. REPORT NO.
  EPA-600/7-79-lSga
4. T.TLE AND SUBTITLE
                         Qf
  Systems:  Duck Creek  Station,  Central Illinois
  Light Co.
                                                           3 RECIPIENT'S ACCESSION NO
                                   5. REPORT DATE
                                     August 1979
                                   6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)

  Bernard A. Laseke, Jr.
                                   B. PERFORMING ORGANIZATION REPORT NO

                                    PN 3470-1-C
9. PERFORMING ORGANIZATION NAME AND ADDRESS
  PEDCo Environmental,  Inc.
  11499 Chester Road  -
  Cincinnati, Ohio  45246
                                   10. PROGRAM ELEMENT NO.
                                   E HE 62 4
                                   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
                                   13. TYPE OF REPORT AND PERIOD COVERED
                                    Final; 7/78 - 12/78	
                                   14. SPONSORING AGENCY CODE
                                                            EPA/600/13
16.SUPPLEMENTARY NOTES ffiRL-RTP project officer is Norman Kaplan, Mail Drop 61, 919/
541-2556.
16. ABSTRACT
  The  report presents the results of a survey of operational  flue gas desulfurization
  (FGD)  systems on coal-fired utility boilers in the United States.   The FGD system
  installed on Unit 1 at the Duck Creek Station of Central  Illinois  Light Company
  is described in terms of design and performance.  The  system consists of four
  parallel, wet-limestone, rod-deck scrubber modules designed for 25% capacity
  each,  providing a total sulfur dioxide removal efficiency of 85%.   The bottom
  ash, fly ash, and scrubbing wastes are disposed of in  a  sludge pond lined with
  a natural impermeable material.  The first module of this four module FGD system
  was  placed in service on July 1, 1976, and operated intermittently throughout the
  remainder of the year and for approximately one month  in early 1977.  On July 23,
  1978,  the three remaining modules were completed and all  four modules were placed
  in the gas path for treatment of high sulfur flue gas.
17.
                               KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                              b.lDENTIFIERS/OPEN ENDED TERMS
                                                 c.  COSATI Field/Group
  Air Pollution
  Flue Gases
  Desulfurization
  Fly Ash
  Limestone
  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
18. DISTRIBUTION STATEMENT
                      19. SECURITY CLASS (This Report)
                       Unclassified
                                                                        21. NO. OF PAGES
                                                                             91
  Unlimited
                      2O. SECURITY CLASS (Thispage/

                       Unclassified
                                                                        22. PRICE
EPA Form 2220-1 (t-73)
                                           B-10

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