CD A U.S. Environmental Protection Agency Industrial Environmental Research     EPA-600/7-78-048D
t* • f^ Office of Research and Development  Laboratory              _ _  . ^ QTQ
                      Research Triangle Park, North Carolina 27711 MBfCn iSf/O
           SURVEY OF FLUE GAS
           DESULFURIZATION SYSTEMS:
           WILL COUNTY STATION,
           COMMONWEALTH EDISON CO
            Interagency
            Energy-Environment
            Research and Development
            Program Report

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                  RESEARCH REPORTING SERIES


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. 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-600/7-78-048b
                                             March 1978
SURVEY OF FLUE GAS DESULFURIZATION
     SYSTEMS: WILL COUNTY STATION,
       COMMONWEALTH EDISON CO.
                            by

                       Bernard A. Laseke, Jr.

                     PEDCo Environmental, Inc.
                       11499 Chester Road
                       Cincinnati, Ohio 45246
                      Contract No. 68-01-4147
                          Task3
                    Program Element No. EHE624
                   EPA Project Officer: Norman Kaplan

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

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

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                         ACKNOWLEDGMENT

     This report was prepared under the direction of Mr. Timothy
W. Devitt and Dr. Gerald A. Isaacs.  The principal author was Mr.
Bernard A. Laseke.
     Mr. Norman Kaplan, EPA Project Officer, had primary respon-
sibility within EPA for this project report.  Information on
plant design and operation was provided by Mr. Rudy Kunshek,
Environmental Affairs Department, Commonwealth Edison Company,
Bruce R. Mansfield, General Environmental Engineer, Commonwealth
Edison Company, and Michael L. Poole, Operating Engineer SO-
Scrubber, Will County Station, Commonwealth Edison Company.
                               ii

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                            CONTENTS
Acknowledgment

Figures and Tables
Summary

     1.

     2.

     3.
Appendix

     A.
Introduction

Facility Description

Flue Gas Desulfurization System

     Process Description
     Process Chemistry:  Principal Reactions
     Process Control

FGD System Performance

     Performance Test Programs
     Summary of System Performance
     Problems, Solutions, and System
       Modifications
     System Economics
     Future Operation
Plant Survey Form
Page

  ii

  iv

  vi

   1

   2

   5

   5
  16
  17

  20

  20
  24

  29
  34
  34



  39
                               iii

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                              FIGURES
No.                                                          Page

1     Limestone Handling and Milling Facilities,
      Will  County Station                                      6

2     Flow  Diagram of Will County Boiler 1 and FGD System       8

3     Sludge  Stabilization and Disposal Facilities,
      Will  County FGD System                                  11

4"    Instrumentation and Control Diagram, Will County
      FGD Modules                                             18
                              TABLES

No.                                                         Page

1    Summary  Data,  Will County Unit 1 FGD System             ix

2    Characteristics of Coal Fired in Will County,
     Boiler 1                                                3

3    Design,  Operation,  and Emissions,  Will County  1          4

4    Summary  of  Design Data,  Scrubbing Trains                12

5    Summary  of  Design and  Operating Data,
     Mist Eliminators                                       13

6    Summary  of  Design and  Operating Data,  Reheaters         14

7    Summary  of  Design Data,  Recirculation  and Makeup
     Tanks                                                   15

8    Design Pressure  Drop for Each Scrubbing Train           15

9    preliminary Test  Data, A-Side Scrubbing Train
     May 18 to 23, 1972                                      21
                               iv

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                       TABLES  (Continued)

No.                                                         Page

10   Preliminary Test Data, A-Side Scrubbing Train,
     July 25 to August 7, 1972.                              22

11   Preliminary Test Data, A-Side Scrubbing Train,
     August 8 to 12, 1972.                                   23

12   Summmary of FGD System Performance, Will County
     FGD System:  1975, 1976, and 1977  (July)                25

13   Estimated Capital Investment Costs of Will
     County Unit 1 FGD System                                35

14   Approximate 1975 Cost to Own and Operate Will
     County Unit 1 Wet Scrubber                              36

15   Summary of FGD Data, Powerton Station Unit 5,
     Boiler 51                                               38

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                            SUMMARY

     The Commonwealth Edison Company owns and operates the Will
County Station on .the Chicago Sanitary and Ship Canal, near
Romeoville, Illinois.  The station consists of four electric
power generating units having a total rated capacity of 1147 MW
(gross).
     Early in11970 the utility began investigating sulfur removal
technology, and the Bechtel Corporation was contracted to assist.
The investigation dealt with those processes which, at that time,
were sufficiently developed for full-scale installation. Common-
wealth Edison consequently decided on a wet scrubbing system
using lime or limestone absorbent.  Bid Specifications were
prepared and bids were received from seven system suppliers.
Following a detailed study, a contract for the installation of a
limestone scrubbing system on Will County Boiler 1 was awarded to
the Babcock and Wilcox Company (B&W).
     Boiler 1 is a wet-bottom, coal-fired, radiant cyclone boiler
rated at 167 MW  (gross).   It was manufactured by B&W and went
into service in 1955.  This unit burns primarily low-sulfur
western grade coal (approximately 0.4 percent sulfur); a high-
sulfur Illinois grade  (approximately 4.0 percent sulfur); or a
combination of the two.  Design of the Will County scrubber
system began in September 1970 and construction started in May
1971.  It was completed by February 1972.  The main problems were
the necessity for a substantial cantilever to backfit the scrub-
ber between the boiler house and service building and the need to
complete the job by December 31, 1971.
     The system consists of two parallel trains (A-side, B-side),
each designed to treat half the boiler flue gas.  At present each
train contains the following components:  two recirculation

                                vi

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tanks, three recirculation pumps, a venturi scrubber, sump, two-
stage sieve tray absorber tower, mist eliminator, reheater, and
induced draft (I.D.) booster fan.  A series of by-pass dampers
allows flue gas to be routed around either one or both scrubbing
trains while the boiler is in service.
     The B-side initially went into service on February 23, 1972,
and the A-side on April 7, 1972.  Shortly after start-up and
during debugging, both modules were plagued with problems.  As a
result, in May 1973 Commonwealth Edison shut down the B-side,
which originally incorporated a turbulent contact absorber (TCA)
tower, to concentrate on solving the problems of the A-side,
which uses the counter-current tray absorber.
     When improved system performance of the A-side was achieved
                                                               i"*1
(69 percent operability* for 1974), the utility modified the B-
side, incorporating all changes made to the A-side.  Major modi-
fications included:  removal of the TCA mobile bed packing and
its replacement with two stages of sieve trays; a double-stage
reinforced mist eliminator in place of the original single-stage
unit; and replacement of the reheat tubes in the reheat bundles
from 304 stainless steel and corten steel components to 316L
stainless steel and carbon steel components.  The B-side went
back into service May 20, 1975.
     In 1976, Commonwealth Edison considered converting the A-
side sieve tray absorber to a TCA tower in an effort to improve
system operations at Will County while gaining experience for the
design, erection, and operation of a 450-MW TCA scrubbing system
being supplied by Universal Oil Products and scheduled for opera-
tion on Powerton Unit 5, Boiler 51, in December 1979.  The short-
age of time for data acquisition before the scheduled start-up of
the Powerton FGD system prevented this modification from being
made.
     In July 1977, Commonwealth Edison officially concluded
* Operabilitfy index: The number of hours the FGD system is in
  operation for a given period, divided by the number of boiler
  hours in the period, expressed as a percentage.
                                vii

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sulfur dioxide removal operations at the Will County No. 1 lime-
stone scrubbing system.  Compliance with existing sulfur dioxide
emission regulations is being achieved by burning exclusively
low-sulfur western coal.  Scrubbing operations are continuing in
the particulate removal mode, by means of which fly ash is
scrubbed from the flue gas with a dilute limestone slurry.  The
limestone is used for pH control only, preventing potential
excursions of the solution into the low pH range, which could
cause severe acid corrosion damage.  Since the scrubbing solution
retains some alkalinity as a result of the addition of limestone,
sulfur dioxide removal still occurs, though at a diminished
level.  Actual removal values have not yet been determined.
     The estimated capital and 1975 annual operating costs for
the FGD system on Will County Unit 1 are equivalent to $113/kW
 (including $5/kW for sludge treatment) and 13.06 mills/kWh
respectively.  These figures represent the cost of a difficult
retrofit application, where scrubbers were installed in an
extremely congested space and under a construction schedule that
required large overtime expenditures.  Operating costs are based
on a 1975 capacity factor of 49.5 percent.
     Summary data on the Will County FGD system are given in
Table 1.
                               viii

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                     Table 1.  SUMMARY DATA,

                  WILL COUNTY UNIT 1 FGD SYSTEM
Unit rating, MW, gross

Unit rating, MW, net


Fuel

Annual average  (1975)

  Heating value, kJ/kg  (Btu/lb)

  Sulfur, percent

  Ash, percent

FGD system supplier

FGD process

FGD trains

Start-up date

  A-side

  B-side

Design guaranteed removal
  efficiency, percent

  Particulates

  Sulfur dioxide

Makeup water

Sludge disposal


Economics

  Capital cost  (1975)

  Annual cost (1975)
        167

        144


       Coal



       22,260 (9,570)

        1.5

        7.4

  Babcock & Wilcox

  Wet limestone scrubbing

         2



   February 1972

   April 1972




        98

        76

   Not available

Stabilized sludge hauled
to off-site landfill



  S113/kW (net)

  13 mills/kWh
                                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 of the performance characteristics and reliability of flue
gas desulfurization (FGD) systems operating on coal-fired utility
boilers in the United States.
     This report, one of a series dealing with such systems,
describes a wet limestone scrubbing process developed by Babcock
& Wilcox (B&W) and installed at the Will County Station of the
Commonwealth Edison Company.  It addresses key process design and
operating parameters, major start-up and operational problems en-
countered at the facility and measures taken to alleviate them,
and the total installed and annual operating costs.  The report
is based on information obtained during plant visits on June 28,
1974; June 22, 1976; and June 1, 1977.  The information is cur-
rent as of November 1977.
     Section 2 presents data and information on the plant en-
virons and plant facilities.  Section 3 provides a detailed
description of the FGD system, including process design and
process chemistry features.  Section 4 analyzes the performance
of the FGD system since start-up in 1972.  It documents sulfur
dioxide and particulate matter removal efficiencies, system
dependability, mechanical and chemical problems and solutions,
and system economics.  Appendix A is the completed plant survey
form.

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                            SECTION 2
                      FACILITY DESCRIPTION

     Will County Station of the Commonwealth Edison Company is on
the Chicago Sanitary and Ship Canal in Will County, near the town
of Romeoville, (1970 population: 12,674*) Illinois.  The area
contains many large refineries and chemical plants.  Canal traf-
fic consists mainly of bulk cargo barges, and it is by this means
that coal and limestone are delivered to the Will County Station.
     Will County Station has four electric power generating units
with a total rated capacity of 1147 MW.  Only Boiler 1, a wet-
bottom, coal-fired boiler rated at 167 MW, is retrofitted with an
FGD system.  It was manufactured by B&W and installed in 1955.
     Boiler 1 burned a low-sulfur Montana coal, a high-sulfur
Illinois coal, or combinations of both during the Will County FGD
demonstration program.  The average characteristics of these
coals are given in Table 2.
     The boiler is fitted with an electrostatic precipitator
(ESP) manufactured by the Western Precipitation Division of the
Joy Manufacturing Company.  The ESP has a design particulate
collection efficiency of 90 percent and a 79 percent actual
particulate collection efficiency on high-sulfur Illinois coal.^"
It provides primary particulate removal and is currently operated
on a full-time basis, independent of FGD operation.
*
  State of Illinois Official Road Map  (1970 Census) lists
  15,336.  Rand-McNally Road Map lists 12,674  (1970 est.).
  Collection efficiency of the precipitator depends on fuel
  supply.  The 79 percent efficiency is based  on tests con-
  ducted June 3, 1975, iand June 4, 1975, with  coal averaging
  3.98 percent in sulfur.

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 Table 2.  CHARACTERISTICS OF COAL FIRED IN WILL COUNTY BOILER 1
Source
Montana


Illinois


Characteristics
Heating value, kJ/k2
Btu/lb
Sulfur, percent
Ash, percent
Heating value, kJ/kg
Btu/lb
Sulfur, percent
Ash, percent
Value
21,167 -
9,100 -
0.3 -
3.0 -
22,097 -
9,500 -
3.5 -
12.0 -
22,330
9,600
0.6
6.0
24,423
10,500
4.5
16.0
     The maximum particulate emission allowed under Illinois
Pollution Control Board Regulation No. 203 (g) (1) (C), effective
May 30, 1975, is 86 ng/J  (0.2 Ib/million Btu).*  Using high-
sulfur Illinois coal, particulate emission rate  from the FGD
system is equivalent to 34.4 ng/J  (0.08 Ib/million Btu).
     Sulfur dioxide emissions are limited by Illinois Pollution
Control Board Regulation No. 204 (C) (1) (A)- *  Under this regula-
tion, effective May 30, 1975, the maximum allowable sulfur diox-
ide emission rate is 774 ng/J (1.8 Ib/million Btu).  The present
sulfur dioxide emission rate, based on 89.2 percent removal
efficiency and coal with a sulfur content of 3.8 percent, was
measured at 300 ng/J  (0.7 Ib/million Btu).
plant and emission rate data.
                                          tt
                                           Table  3 presents
tt
IPCB Regulations 203(g)(l)(C) and 204(C)(1)(A) were  invali-
dated by Illinois Supreme Court January 20, 1976.
Rate based on tests conducted June 3, 1975, and June  4,  1975,
with coal averaging 3.98 percent sulfur.
Rate based on tests conducted September 28, 1976.

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           Table 3.  DESIGN, OPERATION, AND EMISSIONS,

                       WILL COUNTY UNIT 1
Total rated generating capacity, MW
Boiler manufacturer
Year placed in service
Unit heat rate,  (1975) kJ/net kWh
                       (Btu/net kWh)
Unit capacity factor, percent  (1975)
Maximum coal consumption rate,
     kg/sec (short tons/hr)
Maximum heat input,
     GJ/hr  (106 Btu/hr)
Served by stack No.
Stack height above grade,
     meters (feet)
Design maximum flue gas rate,
     m3/Sec @ 179°C  (acfm  @ 355°F)
Emission controls:
     Particulate

     Sulfur dioxide
Particulate emission rates:
     Allowable, ng/J  (lb/106 Btu)
     Actual, ng/J  (lb/106 Btu)
Sulfur dioxide emission rates:
     Allowable, ng/J  (lb/106 Btu)
     Actual, ng/J  (lb/106 Btu)
       167
Babcock & Wilcox
      1955
      11,835
     (11,217)
      49.5

      21.4 (85)

 1,688 (1,600)
      1

     107  (350)

 363 (770,000)

 ESP and venturi
   scrubbers
 Venturi scrubbers
 and sieve tray
 absorbers

 86.0 (0.2)a
 34.4 (0.08)b

 774 (1.8)a
 300 (0.7)c
  IPCB regulations  203(g)(l)(C)  and  204(C)(1)(A) were invalidated
  by Illinois Supreme Court January  20,  1976.
•L
  Based on tests conducted June  3, 1975  and June 4,  1975.

c Based on tested FGD removal efficiency of 89.2 percent
  for coal with a sulfur content of  3.8  percent  (tests conducted
  September 28, 1976).

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                            SECTION 3
                 FLUE GAS DESULFURIZATION SYSTEM

PROCESS DESCRIPTION
     The wet limestone scrubbing system designed and installed by
B&W on Will County Boiler 1 is guaranteed to remove 98 percent of
particulate matter and 76 percent of sulfur dioxide.  Removal
efficiency values are based on inlet loading conditions of 3.1
g/m   (1.355 gr/scf) at 21°C (70°F) while burning Illinois coal,
with a sulfur content of 4 percent.
     The wet limestone scrubbing system backfitted on the boiler
includes a limestone handling and milling system, a sludge dis-
posal system, and two parallel scrubber-absorber trains, each
designed to treat half the boiler flue gas.  The B-side scrubbing
train went into commercial service February 23, 1972, and the A-
side scrubbing train on April 7, 1972.  Many problems were en-
countered, which resulted in numerous system modifications.
These are discussed in detail in Section 4.  The Will County wet
scrubber system is described in terms of three basic operations:
(1) limestone handling and milling, (2) wet scrubber and absorber
trains, and  (3) sludge handling and disposal.
Limestone Handling and Milling
     Figure 1 depicts the limestone handling and milling facility
at Will County Station.  It handles limestone used for both
scrubbing trains and includes a rock conveyor, two storage silos,
two wet ball mills, one slurry storage tank, and two slurry feed
pumps.
     The limestone,.a coarse-ground form about 2 cm  (0.75 in.) or
less in diameter, is purchased from Rigsby and Barnum Company,
and arrives by river barge.   It is unloaded at Will County by

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      RECLAIM HOPPER
                                            RECYCLE TANK
                                              AND PUMPS
                                                                                 SLURRY
                                                                                 STORAGE
                                                                                  TANK
                                                                                SLURRY
                                                                                TRANSFER
                                                                                PUMPS
TO WET SCRUBBER
Figure 1.   Limestone handling and  milling facilities, Will County Station,

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coal-handling equipment and transferred by conveyor to two 236-Mg
(260-ton) silos.  The storage capacity of the silos meets the
limestone requirements of FGD operation at full load.
     Each storage silo discharges onto a gravimetric feeder that
supplies one of two full-size wet ball mill and classification
systems.  Each system can grind limestone at a rate of 3 kg/sec
(12 ton/hr) to a fineness of 95 percent minus 325 mesh.  The
chemical specifications required allow a minimum calcium car-
bonate content of 97 percent and magnesium and silica contents of
less than 1.0 and 0.5 percent respectively.
     The wet ball mills discharge a limestone slurry containing
25 to 30 percent solids to a storage tank.  This tank, which has
a liquid capacity of 236,588 1  (62,500 gal.), is agitated contin-
uously.  It was designed to retain the slurry 4 hours before it
is pumped to the scrubbing system.  The entire limestone milling
facility was designed so that one wet ball mill could supply
limestone slurry for both scrubbing trains at full-load flue gas
capacity.
Wet Scrubber and Absorber Trains
     The wet scrubber-absorber system is composed of two identi-
cal parallel scrubbing trains, referred to above as the A-side
and the B-side.  Each train was designed to treat approximately
50 percent of the flue gas, or 182 m /sec  (385,000 cfm) at 179°C
(355°F).  The flow of flue gas and solutions through the scrub-
bing system is illustrated in Figure 2 and described below.
     Flue gas emerges from the boiler and passes through an
existing ESP (Western, 90 percent design removal efficiency)
where primary particulate removal takes place.  A by-pass damper,
installed downstream from the ESP, permits the gas to by-pass
either scrubbing train, or both.  The flue gas then enters the
scrubbing system through a venturi, where it is contacted with
jets of scrubbing s-lurry sprayed countercurrently from high-
pressure nozzles on each side of the rectangular venturi throat.
Flue gas velocity and particulate removal are maintained at

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      COAL FEED
oo
                              EXISTING
                          INDUCED-DRAFT FAN
                    BOILER
                                  BYPASS
                                  DAMPER
                                   ESP
                                         TO SLUDGE
                                         WASTE  POND
                                            VENTURI
                                             PUMPS
                                                               INDUCED-DRAFT
                                                               BOOSTER FAN
                                                                           SUMP
                                                              VENTURI
                                                           RECIRCULATION
                                                               TANK
   \
                                                                                          ABSORBER
  ABSORBER
RECIRCULATION
    TANK
                                                                                                        FROM MILL
                                                                                                          SYSTEM
                     ABSORBER
                      PUMPS
                    Figure  2.   Flow diagram  of  Will County Boiler 1  and FGD system.

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37 m/sec  (120 ft/sec) and 94.3 percent respectively, by regula-
ting the pressure drop across the throat at 2.2 kPa  (9 in. H20).
     Quenched flue gas and slurry droplets pass through the sump,
where the large gas velocity reduction causes the droplets to
leave the flue gas stream.  The gas then flows upward through the
sulfur dioxide absorber tower at the greatly reduced superficial
gas velocity of 3 m/sec (10 ft/sec).  The A-side and Bside
absorber towers contain two sieve trays wetted by limestone
slurry sprays above the trays.  The trays provide an extended
wetted surface for absorption of the sulfur dioxide from the flue
gas by circulated slurry.  Pressure drop through the absorption
section of each module at full-load conditions is 2.5 kPa (10 in.
H20).
     The cleaned flue gas then continues upward through a mist
eliminator (Z-shaped, two-stage, three-pass, chevron-type).  Fine
mist droplets coalesce on the surface of the mist eliminator,
which is equipped with two sets of wash water headers.  The lower
stage is washed continuously by an underspray of 7.9 I/sec (125
gal./min) of fresh water and intermittently by an overspray of
63.1 I/sec (1,000 gal./min) of pond water for 90 seconds every
hour.  The scrubbed gas then enters the reheater unit, where its
temperature is raised from 53°C to 82°C (128°F to 180°F).  Reheat
is necessary to prevent condensation in the fans, ducts, and the
existing brick-lined stack.  The reheat also makes the plume
buoyant and thus reduces its visibility.
     Each bare tube reheater has nine sections.  The bottom three
sections of both the A-side and the B-side units are made of
316 L stainless steel, and the remaining six sections are of
carbon steel.  Each reheater also has four soot blowers.  Heat is
supplied by saturated steam from the boiler at 2,515 kPa  (350
psig) and 252°C (485°F).  Condensate from the reheater is re-
turned to the steam circuit at the deaerator heater.  An ad-
ditional temperature boost of approximately 11°C (20°F) from 82°C
(180°F)  to 93°C (200°F) is provided by the fans.

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     To compensate for draft loss across the two scrubbing
trains, two 1,679-kW  (2,250-hp) I.D. booster fans, one per train,
were installed at the suction side of the existing boiler I.D.
fans.
     Both scrubbing trains have two recirculation tanks, each
with a capacity of 151 kl (40,000 gal.).  One services the
venturi scrubber, the other the absorber.  Spent scrubbing slurry
is discharged from the venturi recirculation loop.  The two tanks
are tied together in such a way that spent liquor from the ab-
sorber recirculation tank flows into the venturi circulation
tank.  All tanks are fitted with an agitator and pumps.  The
slurry recirculation rate to the absorber is approximately 649
I/sec  (11,000 gal./min), equalling a liquid-to-gas ratio  (L/G) of
5 1/m3  (35 gal./I,000 ft3) of gas at 49°C (120°F).  The liquid
recirculation rate to the venturi is 366 I/sec  (5,800 gal./min),
                               3                  3
an L/G of approximately 2.5 1/m   (18 gal./I,000 ft ) of gas at
52°C  (125°F).
Sludge Handling and Disposal
     Figure  3 illustrates the present scrubbing wastes handling
and disposal system employed at the Will County Station.  Wastes
are discharged from the A-side and B-side venturi recirculation
loops either to a 65-diameter thickener or directly to the sludge
waste pond.  The latter mode is used only in emergencies, or when
the thickener is out of service.  Clarified water is returned to
the process  for use in the scrubbing and milling systems.
     Thickener underflow or retrieved ponded sludge is stabilized
with fly ash and lime and hauled in concrete mixing trucks to an
off-site disposal area.  Stabilization is achieved at a ratio of
181 kg  (400  Ib) of fly ash and 91 kg (200 Ib) of lime per 0.9 Mg
(ton) of dry solids of sludge.
     Tables 4 through 8 summarize operating data, design param-
eters, and design specifications for the major  unit operations of
the Will County Boiler 1 FGD scrubbing system.
                               10

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                                                    X
                                                                RECYCLED THICKENER
                                                                 OVERFLOW AND POND
                                                               SUPERNATANT TO MODULE
                                                            SCRUBBER SLUDGE POND
                                        THICKENER UNDERFLOW
HOPPER
                                TO OFF-SITE
                               DISPOSAL AREA
 Figure  3.   Sludge stabilization and disposal  facilities,  Will  County FGD  system.

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      Table 4.  SUMMARY OF DESIGN DATA,  SCRUBBING TRAINS
      Item
Venturi  scrubber
  SC>2  absorber
     tower
Number
              3
L/G ratio, 1/m
     (gal./lOOO acf)

 Superficial gas
 velocity, m/sec
           (ft/sec)

Equipment  size, m  (ft]
Material of
 construction

     Shell
     Internals
       2.5
      (18)
       37
     (120)

  2.5  x 8  x 15
  (8 x 26  x 16)
[throat 6.4 x 0.5
   (21 x 1.8)1
  Carbon steel
   coated with
     plasite

    Kaocrete
       5
     (35)
       3
     (10)

  5  x 7 x 18
(16  x 24 x 60)
 Corten steel,
 rubber lined
    316L SS
                               12

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Table 5.  SUMMARY OF DESIGN AND OPERATING DATA, MIST ELIMINATORS
     Number

     Type

     Shape


     Material of construction

     Number of stages

     Number of passes

     Distance between stages, m  (ft)

     Spacing between vanes, cm  (in.)

     Pressure drop, kPa  (in. H-O)

     Configuration

     Wash system:

          Type




          Duration


          Rate
  Chevron

Z-shape, 90° sharp-angle
     bends

FRP (Hetron)

     2

     3

1.2 (4)

3.8 (1.5)

0.25 (1.0)

Horizontal
Fresh water underspray/
pond return overspray for
first stage; second stage
not washed.

Underspray - continuous;
overspray - intermittent

Underspray - 7 to 8 I/sec
(113 to 126 gal./min);
overspray - 63 I/sec
(1000 gal./min) for 40
sec for each module per
hour of operation.
                               13

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    Table 6.  SUMMARY OF DESIGN AND OPERATING DATA,  REHEATERS
Number


Type


Flue gas reheat:

              3
  Flow rate, m /sec  (acfm)


  Temperature, °C  (°-F)


  SO,., Concentration, ppm  (average)


Design:


  Number of tube banks


  Tube size



  Material of construction


  Soot blowing


Heating medium:


  Pressure, kPa  (psig)


  Temperature, °C  (°F)


  Consumption rate, kg/sec  (Ib/hr)


Outlet gas temperature, °C  (°F)


Energy consumption, % of boiler
               input
Steam in-line reheat





179  (380,000)


 53  (128)


     500




3, 9 rows per bank


1.6 cm  (0.62 in.) O.D.,
     bare tube


316L SS and carbon steel


Every 4 hours




2,515 (350)


252  (485)


6 (50,000)


 71  (160)



      3.2
                               14

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 Table 7.  SUMMARY OF DESIGN DATA, RECIRCULATION AND MAKEUP TANKS
Item
Total number of
tanks
Retention time
at full load
Temperature, °C
(°F)
PH
Solids content,
percent
Specific gravity
Material of
construction
Venturi
scrubber
recirculation
tank
2

Variable*

53
(128)
5.1-5.7
8

1.102
Rubber-lined
carbon steel
SO- absorber
tower
recirculation
tank
2

Variable1"

53
(128)
5.8
8

1.049
Rubber -lined
carbon steel
Limestone
slurry
makeup
tank
1

4 hr

Ambient
7.0
15-30


Carbon steel

    Table 8.  DESIGN PRESSURE DROP FOR EACH SCRUBBING TRAIN

                         [kPa  (in. H20)]
     Venturi scrubber

     Sieve tray absorber

     Mist eliminator

     Reheater

     Ductwork
     Total FGD system
2.2 (9)

2.5 (10)

0.25 (1)

1.5 (6)

0.75 (3)
7.20 (29)
  Design value is 8 minutes.  Different rates were used on an
  experimental basis during the course of the S02 program.

t Design value is 4 minutes.  Different rates were used on an
  experimental basis during the course of the S02 program.

                               15

-------
PROCESS CHEMISTRY:  PRINCIPAL REACTIONS
     The chemistry involved in the wet limestone  scrubbing
process is complex, and a detailed account is beyond  the  scope  of
this discussion.  The principal steps involved  in this  process,
however, are discussed as follows:
     Initially, the sulfur dioxide must diffuse from  the  gas
phase into the liquid phase
               SO,, i <  * S00  ,   v
                 2         2  (aq.)
The sulfur dioxide dissolved  in the aqueous phase next  undergoes
hydrolysis and ionization, yielding sulfurous acid, bisulfite,
sulfite, and hydrogen ions
               S00  ,   v + H00 «   » H.SO,
                 2  (aq. )    2        23
In addition to the formation and subsequent ionization of  sul-
furous acid, some of the sulfur dioxide reacts with  oxygen in the
gas phase to yield sulfuric acid, bisulfate, sulfate, and  hy-
drogen ions.
               2S02 + + 02 t «    ** 2S03 i
                                4
Analagous to the gas-phase oxidation steps discussed  above,  the
sulfite ion undergoes oxidation by dissolved oxygen present  in
the scrubbing solution and forms a sulfate ion according  to  the
following reaction:
                               16

-------
     The dissolution and ionization of the limestone additive
into an acidic medium yields the ionic species of calcium,
carbonate, bicarbonate, and calcium bicarbonate.
The calcium ions react with the sulfite and sulfate ions in the
aqueous phase, resulting in the formation and precipitation of
calcium sulfite and calcium sulfate salts.
       Ca++ + SO3=^=±CaS03
       CaS03 + 1/2 H20 <    > CaS03-l/2 H2O +
       Ca++ + S04=^=±:CaS04
       CaSO. + 2 H-0 <      * CaSO -2 H_0 4-
           42               42

PROCESS CONTROL
     Figure 4 is a diagram of the instrumentation and controls
for the scrubber- absorber train portion of the Will County FGD
system.  The controls are designed to maintain optimum operating
efficiency by monitoring the following process variables:  pres-
sure drop across the venturi throat, limestone feed, and scrub-
bing solution pH.  Monitoring and control are performed automati-
cally from the scrubber control room panel in the boiler control
room.
Gas loading
     The modulation of the gas flow through the scrubbing system
is controlled as a function of boiler load variation.  This is
accomplished automatically by a boiler load signal, which con-
trols the I.D. fan speed and booster fan dampers.
                               17

-------
oo
                                                                                                    6140 g/sec
                                                                                                  (48,700 Ib/hr)
                                                                  VENTURI -
                                                              ABSORBER MODULES
                                                                                                     ABSORBER
                                                                                                   RECIRCULATION
                                                                                                       FLOW
        3697 g/sec
      (29,340 Ib/hr
           55 I/sec
          (867 gal/min)
   XvTTNTinn
RECIRCULATION
    FLOW
                                                  733 l/»1n
                                                (11,612 9*1/«1n)
                                                                                                    1090 1/min
                                                                                                   (17,280 gal/min)
           Figure 4.    Instrumentation  and  control diagram,  Will County  FGD  Modules.

-------
Pressure drop across the venturi
     Particulate removal efficiency and superficial gas velocity
in the scrubbing system are regulated by controlling the pressure
drop across the venturi throat.  A constant value of 2.2 kPa  (9
in. H_0) is maintained by a differential pressure controller and
pressure indicator network installed on the venturi throat.  This
network is in turn connected to the throat-drive motor, which
expands or contracts the throat opening.
Limestone slurry feed
     The limestone slurry feed to the scrubbing system is con-
trolled by monitoring the scrubbing solution pH at the venturi
inlet.  The pH control range is variable.  When the pH drops
below or exceeds the control range, the feed rate of fresh lime-
stone slurry is increased or decreased to the scrubbing system by
opening or closing the feed valves.
Spent slurry discharge
     Spent scrubbing slurry is discharged from the scrubbing
system off the venturi recirculation line and transported to the
thickener.  The amount of waste blowdown is regulated by' a level
controller.  This controller works in conjunction with a flow
control valve, which is opened and closed as a function of the
liquid level in the venturi recirculation tank.
Sulfur dioxide level
     The concentration of the sulfur dioxide species in the flue
gas is checked periodically by wet chemical techniques.
                               19

-------
                            SECTION 4
                     FGD SYSTEM PERFORMANCE

PERFORMANCE TEST PROGRAMS
     Three performance test runs have been conducted on the Will
County FGD system.   Babcock & Wilcox conducted a series of pre-
liminary performance tests in May,  and during July and August,
1972, and the utility itself did tests during a high-sulfur coal
burn program in May 1975, and September 1976.
     Table 9 summarizes the results of the May 1972 test program.
Outlet particulate loading during the test varied from 0.0167 to
0.0764 g/m3 (0.0073 to 0.0334 gr/scf).  The design guarantee
value was 0.0568 g/m  (0.0248 gr/scf).  Sulfur dioxide removal
efficiency and resulting outlet values were not applicable to the
design guarantee because a varying blend of low-sulfur western
coal and high-sulfur Illinois coal was burned.  During normal
operating conditions, sulfur dioxide removal efficiency was about
80 percent.  It dropped to 67 percent when the limestone slurry
feed to the scrubbing system was deliberately reduced.
     During the July-August 1972 test period, the system treated
flue gas from the combustion of high-sulfur Illinois coal  (the
design coal).  Outlet particulate loading varied from 0.0487 to
0.0636 g/m3 (0.0213 to 0.0278 gr/scf).  Sulfur dioxide removal
efficiency varied from 67 to 94 percent.  As in the May 1972 test
period, all the runs were made on the A-side with the ESP unit
de-energized.  Tables 10 and 11 summarize the results.
     A high-sulfur burn test program was initiated by the utility
in May 1975, during which sulfur dioxide removal, particulate
removal in the scrubber, and ESP removal efficiencies were mea-
sured and the process chemistry was monitored.  Removal effi-

                               20

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Table 9.  PRELIMINARY TEST DATA, A-SIDE SCRUBBING TRAIN




                  MAY 18 TO 23, 1972
Test number
Date
Load, MW
Gas flow, ra /sec
(acfm x 103)
Scrubber system,
pressure drop, kPa
(in. H20)
Dust inlet, g/m
(gr/dscf)
Dust outlet, g/m
(gr/dscf)
SO, inlet, ppm
S02 outlet, ppm
S0_ removal
efficiency, %
Absorber slurry solids
concentration, %
Absorber pH
1
5-18
113
158
(335)
6.1
(24.5)

0.0531
(0.0232)
1145
67
94
3.4
6.5
2
5-18
113
168
(355)
7.2
(29)
0.216
(0.0944)
0.0181
(0.0079)
1140
75
93
5.2
6.3
.3
5-19
114
158
(335)
5.2
(21)
0.330
(0.1440)
0.0167
(0.0073)
890
294
67
5.5
7.4
4
5-19
115
160
(340)
6.2
(25)
0.336
(0.1470)
0.0682
TO. 0298)
930
35
96
5.2
6.3
5
5-20
111
158
(335)
6.0
(24)
0.253
(0.1105)
0.0597
(0.0261)
1130
285
75
• 2.5
5.7
6'
5-20
112
151
(320)
6.3
(25.5)
0.410
(0.1790)
0.0584
(0.0255)
1000
118
88
4.3
5.8
7
5-21
113
149
(315)
5.6
(22.5)


640
18
97
5.0
7.2
8
5-21
115
146
(310)
5.5
(22.0)


910
45
95

5.7
9
5-22
110
149
(315)
5.8
(23.2)
0.700
(0.3060)
0-.0469
(0.0205)
1000
223
81
2.9
5.9
10
5-22
111
158
(335)
5.7
(23.0)
0.590
(0,2580)
0.0764
(0.0334)
545
180
67
2.2
5.4
11
5-23

97
(205)
4.0
(16.0)


1200
45
95

6.1
12
5-23
58
101
(215)
4.5
(18.0)


1150
50
96
1.5
6.1

-------
                   Table 10.  PRELIMINARY  TEST DATA,  A-SIDE SCRUBBING TRAIN


                                   JULY  25 TO  AUGUST  7,  1972
to
NJ
Test number
Date
Load, MW
Gas flow, m /sec
(acfm x 103)
Scrubber system, pressure
drop, kPa (in. H20)
Dust inlet, (g/m )
(gr/dscf)
Dust outlet, g/m
(gr/dscf)
Absorber slurry solids
concentration, %
Absorber pH
1
7-25
102
154
(326)
5.0
(20)
0.996
(0.4354)
0.0487
(0.0213)
2
4.7
2
7-26
100
130
(276)
3.6
(14.5)
0.574
(0.2508)
0.0522
(0.0228)
2
5.7
3
7-27
112
172
(364)
5.8
(23.5)
0.424
(0.1855)
0.0502
(0.0220)
2

4
8-4
104
181
(383)
6.5
(26)
0.475
(0.2075)
0.0524
(0.0229)
2
6.0
5
8-4
103
181
(383)
6.7
(27)
0.231
(0.1008)
0.0508
(0.0222)
11
6.2
6
8-7
98
189
(400)
6.5
(26)
0.535
(0.2339)
0.0636
(0.0278)
11.8
6.2

-------
                 Table 11.   PRELIMINARY TEST DATA,  A-SIDE SCRUBBING TRAIN




                                  AUGUST 8 TO 12, 1972
Test number
Date
Gas flow, ra /sec ,
(acfm x 10J)
Scrubber system, pressure
drop, kPa (in. H2O)
SO, inlet, ppm
SO- outlet, ppm
SO2 removal efficiency, %
Absorber, pH
1
8-8
76
(160)
6.6
(26.5)
2400
300
87.6
5.7
2
8-8
170
(360)
6.5
(26.0)
2860
960
66.4
5.9
3
8-9
107
(226)
5.2
(21.0)
2720
495
81.8
4.9
4
8-9
167
• (353)
7.2
(29.0)
2680
800
70.0
5.0
5
8-10
170
(360)
7.0
(28.0)
2700
185
93.2
5.5
6
8-10
167
(353)
6.7
(27.0)
1065
63
94.1
6.6
7
8-11
163
(345)
6.5
(26.0)
1600
280
82.5
6.4
' 8
9-11
221
(468)
7.0
(28.0)
2230
570
74.4

9
8-12
175
(370)
7.0
(28.0)
2260
520
77.0

10
8-12
175
(370)
7.3
(29.5)
2350
765
67.3

to

-------
ciency tests were conducted under full- and partial-load condi-
tions with the upstream ESP in and out of service.  Sulfur diox-
ide removal efficiencies averaged 78.2 percent and 86.8 percent
for the A-side and B-side respectively.  The average sulfur
dioxide inlet loading was 3573 ppm.  The A-side value was lower
because only one of the two absorber recirculation pumps was in
service, resulting in a lower L/G.  Slurry carryover in the
scrubber resulted in lower particulate removal efficiencies than
expected, and this caused high particulate loadings at the scrub-
ber outlet.

SUMMARY OF SYSTEM PERFORMANCE
     The performance of the FGD system since start-up is de-
scribed below on a yearly basis.   Details of the 1975, 1976, and
1977  (July), operations are summarized in Table 12.
1972 Operation
     The B-side scrubbing train,  which included a TCA absorber,
was first placed in service February 23, 1972.  The A-side came
on-line April 7, 1972.  To the end of 1972, the A-side was in
service a total of 1444 hours and the B-side, 1237 hours.  The
average annual operability index values for the A- and B-sides
were 30 and 25 percent respectively.  The longest period of con-
tinuous operation was 21 days, achieved by the A-side.  Simul-
taneous operation of the scrubbing trains totalled 469 hours; the
longest continuous period was 6 days.
1973 Operation
     In April 1973, the utility discontinued operation of the B-
side scrubbing train to concentrate on the A-side.  The A-side
remained in service until November, when it was brought down for
repairs and modifications.  By this time it had been in service a
total of 1726 hours, providing a 23 percent operability index for
the year.
                               24

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          Table 12.  SUMMARY OF FGD SYSTEM  PERFORMANCE, WILL COUNTY FGD  SYSTEM:

                                1975, 1976, AND 1977 (JULY)
NJ
Ul
Period
Jan. 75
Feb. 75
Mar. 75
Apr. 75
May 75

June 75

July 75
Aug. 75
Sept. 75
Oct. 75d
Nov. 75
Dec. 75
Total

Hours
744
672
744
720
744

720

744
744
720
744
720
744
8760

Unit
hours
685
666
609
638
744

642

689
565
720
195
Module
A
A
A
A
A
B
A
B
B
B
B
B
Hours
676
662
605
253
629
276
390
543
547
568
452 •
195
Scheduled overhaul of
Scheduled ove
6153

A
B
rhaul of
3123
2580
System performance factors, percent
Availability3
99
'99
94
37
84
37
64
85
79
94
63
32
boiler, turbine
boiler, turbine
40
34
Operability
99
99
99
40
84
37
61
85
79
100
63
100
, and scrubbe
, and scrubbe
52
42
Reliability
91
99
86
95
100
100
84
88
93
82
100
81
rs
rs
38
31
Q
Utilization
91
99
81
35
84
37
54
75
74
76
63
26


37
29
               (Continued)

-------
                                           Table 12  (Continued).
CT\
Period
Jan. 76
Feb. 76
Mar. 76

Apr. 76

May 76
June 76

July 76

Aug. 76

Sept. 76

Oct. 76

Nov. 76

Dec. 76

Total

Hours
744
696
Unit
hours
Sche
Module
Juled ovei
Hours
"haul of
|
Scheduled overhaul of
744 ; 309'

720

744
720

744

744

720

744

720

744

8760

690

665
612

598

495

566

726

569

692

5920

A
B
A
B
B
A
B
A
B
A
B
A
B
A
B
A
B
A
B
A
B
140
63
138
340
567
271
517
0
538
285
304
163
431
208
408
145
394
334
357
1684
3919
System performance factors, percent
Availability3
boiler, turbine
boiler, turbine
30
9
23
Operability | Reliability1'
and scrubbe
and scrubbe
45
20
20
51 49
87
52
72
20
84
98
65
42
79
30
76
20
72
45
53
27
56
85
44
85
0
90
57
61
29
76
29
56
26
70
48
52
28
66
rs
rs
62
97
83
93
88
72
83
0
84
96
54
28
74
28
70
20
66
45
51
22
50
Utilization0


19
8
19
47
76
38
72
0
72
38
41
42
60
28
55
20
55
45
48
19
44
                    (Continued)

-------
                              Table 12  (Continued).
Period
Jan. 77

Feb. 77

Mar. 77

Apr. 77

May 77

June 77

July 77

Total

Hours
744

672

744

720

744

720

744

5080

Unit
hours
722

613

727

650

691

566

377

4347

Module
A
B
A
B
A
B
A
B
A
B
A
B
A
B
A
B
Hours
713
8
261
280
478
550
441
196
15
352
76
529
201
201
1923
2071
System performance factors, percent
Availability
98
14
39
72
97
81
86
45
89
98
32
93
27
70
72
67
Operability
99
1
42
45
66
75
68
30
2
51
13
93
53
41
44
48
Reliability
98
1




81
33
16
96
13
92
27
41
58
55
Utilization
96
1
39
41
64
73
61
21
2
47
10
73
27
21
38
41
  Availability  index: The number of hours the  FGD  system is available for operation  (whether
                     operated or not),  divided by the number of hours in the  period, expressed
                     as a percentage.
  Reliability index:  The number of hours the  FGD  system is in operation for a given period,
                     divided by the number of hours the FGD system is called  upon to operate in
                     the period, expressed as a percentage.
c Utilization index:  The number of hours the  FGD  system is in operation for a given period,
                     divided by the number of hours in the period, expressed  as  a percentage

  21-week scheduled turbine, boiler and scrubber outage began Oct. 11.

-------
1974 Operation
     The A-side scrubbing train remained in service throughout
the year, accumulating 5468 hours of operation.  The train was
available 6025 hours and the boiler was operational 7924 hours.
These figures represent a 69 percent operability and availability
index for the year.
1975 Operation
     Operations in 1975 commenced in much the same manner as in
1974.  The A-side was operational, the B-side still out of ser-
vice.  The A-side remained in service until mid-June, when it was
taken out for extensive repairs and modifications.  The average
operability index for the A-side, through June 20, was 80 per-
cent.  The A-side remained out of service throughout the year.
Modifications to the B-side  (the TCA absorber was converted to a
sieve tray unit) were completed and it was returned to service
May 20.  The B-side operated almost without  incident until
October  11, when Unit 1 was shut down for a  scheduled boiler,
turbine, and scrubber overhaul.  During the  year, the generating
unit was in service 6152 hours; the A-side and B-side scrubbing
trains were available 3463 and 2969 hours, respectively, and
actually operated 3213 and 2580 hours respectively.  Based on
these service hours, the following index values were calculated
for 1975 operations:  A-side availability, operability,  reliabil-
ity, and utilization were 40, 52, 38,  and 37 percent, respective-
ly; B-side values for the same parameters were 34, 42, 31, and 29
percent  respectively-   The average sulfur content of the coal
burned in Unit 1 during the year was 1.5 percent.
1976 Operation
     Unit 1 was returned to service in March following the 4-
month overhaul.  The A-side and B-side were returned to service
March 22 and 29 respectively.  During the year, the generating
unit was available for service 6450 hours and was operated 5920
hours.   The A-side and B-side scrubbing trains were available

                               28

-------
2634 and 4883 hours respectively, and were operated 1684 and 3919
hours respectively.  Based on these service hours, the following
index values were calculated for 1976 operations:  the generating
unit was 73 percent available; A-side availability, operability,
reliability, and utilization were 27, 28, 22, and 19 percent
respectively.  B-side values for the same parameters were 56, 66,
50, and 44 percent respectively.  The average sulfur content of
coal burned in Unit 1 during the year was sightly over 1 percent.
1977 Operation
     In July 1977, Commonwealth Edison officially concluded the
Will County sulfur dioxide scrubbing program.  The scrubbers are
still in service, removing primarily fly ash and some sulfur
dioxide from the flue gas.  Low-sulfur western coal is burned.
From January to July 1977, several test programs were conducted
by the utility, including the evaluation of continuous sulfur
dioxide analyzers; high-sulfur coal sludge evaluations; magnesium
oxide beneficiation of the limestone slurry; and forced oxidation
testing.  Virtually all operations were conducted on low-sulfur
western coal.  During this period, the generating unit was avail-
able for service 4394 hours and operated 4347 hours.  The A-side
and B-side scrubbing trains were available 3689 and 3436 hours
respectively, and were operated 1923 and 2071 hours respectively.
Based on these service hours, the following index values were
calculated for operations from January to July 1977:  generating
unit availability was 86 percent; A-side availability, operabil-
ity, reliability, and utilization were 72, 44, 58, and 38 percent
respectively; B-side values for the same parameters were 67, 48,
55, and 41 percent respectively.

PROBLEMS, SOLUTIONS, AND SYSTEM MODIFICATIONS
     The Will County FGD system has been beset with numerous
problems since commercial operation began in February 1972.  The
major problems, solutions, modifications, and experiments per-
formed on the scrubbing system are described below.

                               29

-------
 Scrubbing modules
      By  April 1972,  the  two  scrubbing  trains had been placed in
 the  flue gas  path:   both encountered more problems  than had been
 expected.   This  resulted in  the  utility's discontinuing operation
 of the B-side to concentrate on  achieving satisfactory operation
 of the A-side.   By  1974  performance  of the A-side had improved to
 the  point where  the utility  decided  to use the B-side again.  The
 B-side was  therefore modified to be  identical with  the A-side.
 The  major change was the removal of  the mobile-bed  packing in the
 absorber and  its replacement with two  stages of sieve trays.
      Following completion of conversion to a tray tower, both
 scrubber-absorber vessels experienced  -major problems in the form
 of scale and  erosion.  Massive gypsum  scaling developed in the
 sump areas  of the scrubbing  trains.  The scale film was reported
 to be over  1.3 cm  (0.5 in.)  thick in some places.  The scale was
 removed  by  shutting the  system down  and chipping gypsum off the
 various  scrubber internals.   Erosion of the scrubber vessel
• occurred in the  horizontal plate above the venturi  inlet wash
 box.  A  number of holes  developed,  allowing slurry  to seep
 through  and over the outer shell of  the venturi. This problem
 was  corrected by fitting each wall wash nozzle with a deflector
 to redirect the  path of  the  slurry.
 Mist eliminators
      Fouling  and scaling of  the  mist eliminators in both scrub-
 bing trains has  been a persistent problem from the  outset of
 commercial  operation.   Fouling occurred primarily because of the
 accumulation  of  the heavy limestone  slurry on the lower sections
 of the mist eliminators.  To rectify this, the wash system was
 modified so that the nozzles sprayed upward onto the bottom
 sections of the  mist eliminators.  Plugging continued to be a
 problem, however, requiring  the  addition of extra spray nozzles
 and  the  use of a continuous  fresh makeup water underspray and an
 intermittent  pond return overspray,  which uses a water deluge
 wash system.   The increased  amount of  fresh makeup  water re-
                               30

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quired, however, upset the system's water balance to the extent
that the underspray system had to be modified to an intermittent
wash system that alternated on a 5-minutes on/5-minutes off
basis.
     In May 1975, during the high-sulfur coal burn program, the
mist eliminator wash system was again modified.  Because use of
saturated pond return water caused additional scale development
and minor plugging in the mist eliminators, the underspray was
converted back to a continuous spray.
Reheaters
     The flue gas reheaters have also been the site of numerous
problems since initial commercial operation.  The major problems
included plugging, scaling, stress corrosion cracks in the 304
stainless steel tubes, and eventual failure of the corten tubes.
Plugging and scaling in the reheat section are a direct function
of the performance of the upstream mist eliminators.
     Each bare tube reheater includes a total of nine sections
and four sootblowers.  The bottom three sections were originally
constructed of 304 stainless steel, the top six of corten.  These
bundles have been replaced by 316L stainless steel tubes in the
lower three banks and by carbon steel tubes in the upper six
banks.  By 1975, six of the 12 new carbon steel bundles had
developed peripheral cracks.  All of the failures occurred be-
cause the tube supports had worked loose, permitting excessive
vibration.  The coil manufacturer repaired and modified all the
tube bundles by redesigning the tube supports and installing an
additional support.
Recirculation
     The design retention times of the venturi scrubber and
absorber recirculation tanks are 4 minutes and 8 minutes respec-
tively.  The utility has determined, however, that 50 percent of
the flow into the tank system is immediately recycled to the
scrubbing system with little or no retention time.  Half the
                               31

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scrubbing solution therefore lacks sufficient time for chemical
reactions to be completed before recirculation to the scrubbing
system.
Pumps
     Three 100 percent capacity venturi recirculation pumps, each
rated at 315 I/sec (5000 gal./min) ,  and four 60 percent capacity
absorber recirculation pumps,  each rated at 331 I/sec (5250
gal./min), were provided for both scrubbing trains.  Problems
with these pumps have been minimal.   One of the absorber recircu-
lation pumps was damaged when a check valve failed in the dis-
charge piping and parts fell into the pump, damaging the impel-
ler and destroying the rubber lining.  It was determined that the
rubber lining in the check valve had eroded, allowing the base
material to corrode and eventually fail.  The system supplier
reviewed the need for check valves in the pump discharges, recom-
mending that they be removed and the spool pieces re lined with
rubber.
Sludge treatment
     Thickener underflow or retrieved ponded sludge is treated in
mixing trucks together with lime and fly ash and hauled to an
offsite disposal area.  Until September 1975, the treated mate-
rial was initially disposed of in an on-site, clay-lined disposal
basin where the material would set up.  Operation of this inter-
mediate hold basin has since been discontinued, and a local firm
is now transporting treated sludge from the plant directly to the
off-site disposal area.
     The utility has purchased a belt-type vacuum filter, which
went into service in late 1976.  This filter had the advantage of
changing the sludge handling method and reducing treatment costs.
The additional water recovery, however, has affected the system's
water balance, making it more difficult to approach closed loop
operations.
                               32

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ESP
     After installation of the FGD system, the upstream ESP was
to operate only when the FGD unit was out of service.  Neverthe-
less, it is now operated on a full-time basis.  This allows
maximum particulate removal and minimizes the amount of fly ash
in the scrubbing system, thus alleviating a problem of high
solids content in the scrubbing liquor.
Instrumentation
     Because of instrument failures and inaccurate readings,
pH and sulfur dioxide levels have, for the most part, been mea-
sured manually.  During the period from January to July 1977,
Commonwealth Edison experimented with a number of continuous
monitors, including both ERT and Dupont sulfur dioxide analyzers.
The utility reported that the Dupont unit performed satisfactor-
ily; it operated with very little maintenance and gave readings
verified by grab samples.
Liners
     Liners have failed in the duct between the absorber outlet
and reheater inlet and in the sump walls of the absorber.  In
both areas Ceilcote Flakeline 103 coating had been used.  The
liner flaked, peeled, or was eroded off, and the bare metal sur-
face soon corroded.  This problem was corrected in the sump area
by applying a coating of Kaocrete refractory over the Flakeline
liner.
Chemistry
     Process chemistry experimentation and testing focused pri-
marily on pH control, magnesium beneficiation, and forced oxida-
tion.  In August 1976, the set point for controlling pH of the
scrubbing solution was reduced from 5.4 to 5.1, in an effort to
reduce scaling and plugging and to increase reagent utilization.
Loss of chemical control and formation of gypsum scale soon
resulted in the return to a pH control point of 5.4.  In May

                               33

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1977,  a magnesium oxide addition test was conducted.  Although
sulfur dioxide removal efficiency was increased by approximately
10 percent,  neither sludge production rate nor limestone utili-
zation was seriously affected.   A forced oxidation test was
successfully conducted immediately before termination of sulfur
dioxide scrubbing operations.   Using liquid oxygen, approximately
5.7 m3/min.  (200 ft3/min.) of  gaseous oxygen was fed into each
venturi scrubber downcomer. Oxidation of sulfite to sulfate was
increased from 35 to 90 percent.

SYSTEM ECONOMICS
     Estimated capital and operating costs for the FGD system at
Will County Station are presented in Tables 13 and 14 and in
Appendix A.   It should be pointed out that this system is a full-
size, prototype demonstration  unit, erected under an accelerated
overtime schedule and backfitted on a unit with little available
space.  The cost per kilowatt  is based on a 137-MW net unit
rating with the FGD system in  operation.

FUTURE OPERATION
     As indicated previously,  sulfur dioxide removal operations
at Will County were concluded  in July 1977.  Particulate removal
operations are continuing at the facility.  Some sulfur dioxide
removal from low-sulfur western coal flue gas is occurring be-
cause of the alkalinity of the scrubbing solution; this is due to
limestone addition for pH control.  Actual sulfur dioxide remov-
al efficiencies have not yet been determined.  During the more
than 5 years that sulfur dioxide removal operations were con-
ducted at the plant, a vast amount of information was accumulated
on the design and operation of FGD systems.  This information is
being used for the design, installation, and future operation of
a full-scale,  limestone-based  FGD system now under construction
at the utility's Powerton Station, Unit 5, Boiler 51.  This sys-
tem, unlike  the Will County system, is not designed for test

                               34

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U)
on
                    Table 13.  ESTIMATED CAPITAL INVESTMENT COSTS OF


                              WILL COUNTY UNIT 1 FGD SYSTEM
Gas cleaning system
B&W venturi/absorber
Equipment erection
Electrical equipment and
erection
Foundations
Limestone handling system
Professional engineering
Mill and S02 buildings
Structural steel
Miscellaneous equipment
Sludge treatment
Total
$/kW (net)
Direct cost
$ 2,928,000
5,556,000
1,210,000
923,000
204,000
965,000
193,000
375,000
946,000
$13,300,000
573,000
$13,873,000
101
Indirect cost








$ 1,600,000
69,000
$ 1,669,000
12
Total cost








$14,900,000
642,000
$15,542,000
113

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Table 14.   APPROXIMATE 1975 COST TO  OWN  AND  OPERATE


            WILL COUNTY  UNIT  1 WET SCRUBBER

Scrubber system
Carrying charges on
$14,900,000
Labor (operating
and technical)
Maintenance (labor
and material)
Limestone

Auxiliary power

Reheat steam



Sludge treatment
Carrying charges
on $642,000
Sludge treatment




$ Annual Cost
2,280,000

81,709

256,656

62,726

586,875

72,595

3,340,561


98,000

546,217

644,217

Scrubber and sludge treatment total cos


3,984,778

$/Mg of coal
$/Ton of coal
13.82
(12.54)
0.50
(0.45)
1.55
(1.41)
.37
(0.34)
3.56
(3.23)
.44
(0.40)
20.24
(18.37)

0.60
(0.54)
3.31
(3.00)
3.91
(3.54)
t
24.15
(21.91)
C/GH
•^/Million Btu
64.89
(65.3)
2.18
(2.3) '
7.01
(7.4)
1.71
(1.8)
15.92
(16.8)
1.99
(2.1)
90.70
(95.7
•
2.65
(2.8)
14.88
15.7
17.53
(18.5)

108.23
(114.2
Notes:

Mills/kWh
7.47

0.27

0.84

0.21

1.92

0.24

10.95


0.32

1.79

2.11


13.06


1. Scrubber system has a 14-year life.
2. Sludge treatment cost includes haulinq to an off-site di
-------
purposes, but for compliance with emission regulations.  Table 15
summarizes the Powerton No. 51 FGD system.
                               37

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Table  15.   SUMMARY OF FGD DATA,  POWERTON STATION UNIT 5,

                               BOILER 51
  FGD unit capacity, MW

  Design coal specifications:
    Heat content, MJ/kg (Btu/lb)
    Sulfur, percent
    Ash, percent
    Chloride, percent
    Moisture, percent

  Application  (new/retrofit)

  Process

  Supplier

  Absorber type

  Number of modules

  Exit  flue gas capacity m /sec (acfm)
  Exit  flue gas termperature, °C (CF)

  Design removal efficiency:
    Particulate, percent
    Sulfur dioxide, percent

  L/G ratio, I/sec @ °C
     (gal./lOOO acf @ °F)

  Gas reheat AT, °C (°F)

  Sludge disposal
   S0_ emission regulation ng/J
               (Ib/mi11ion Btu)

   Gas bypass capability

   FGD schedule milestones:
    Contract awarded
    Start of construction
    Initial operation
    'Commercial operation

   FGD Economics:
    Capital cost, $/kW
    Operating cost, mills/kWh
 450


 24.4  (10,500)(avg.)
 3.6  (avg.),  6.0  (max.)
 8.3  (avg.),  16.0  (max.)
 0 . 2  (max .)
 17.3  (avg.)

 Retrofit

 Limestone

 Universal  Oil  Products

 Turbulent  contact  absorber
 735  (1,556,217)
 53  (128)
 84

 8  @  53°C
(60@  128)

 14  (25)

 Stabilized  sludge  disposed  of
 on plant grounds in  a  lined
 pond 1.2 km (0.75  miles)  from
 generating  -unit.

 774
(1.8)

 Yes
 February  1976
 March  1977
 Late  1978
 December  1979
 117.65
 8.70c
    N/A - not applicable:   ESP upstream of FGD system provides control
    of particulate matter.

    This is the maximum removal efficiency value based upon 100
    percent conversion of 6 percent sulfur coal with a 24.4 MJ/kg
    (10,500 Btu/lb) heating value.

    Estimated value, which includes the following:   2.7 mills/kWh for
    operation and maintenance; 6.0  mills/kWh for auxiliary power
    requirements; FGD life span of  30 years.
                                   38

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                           APPENDIX A




                        PLANT SURVEY FORM






A.    Company and Plant Information




     1.    Company name:  Commonwealth Edison Company	




     2.    Main office: P.O. Box 767, Chicago, Illinois  60&90




     3.    Plant name;  Will County Station             	
     4.    Plant location; Romeoville, Illinois	



     5.    Responsible officer; Mr. J. P. McCluskey



     6.    Plant manager:  James R. Gilbert	
     7.    Plant contact:  R. Kunshek
     8.    Position:  Director - Environmental Affairs Dept.



     9.    Telephone  number:  (312) 294-2906	
    10.    Date information gathered: 6/22/76 and 6/1/77	



     Participants in meeting                 Affiliation



     G.  A. Isaacs	       PEDCo Environmental, Inc.



     B.  A. Laseke	   	PEDCo Environmental, Inc.



     T.  C. Ponder	       PEDCo Environmental, Inc.



     R.  Klier	   	PEDCo Environmental, Inc.



     H.  M. Drake	       PEDCo Environmental, Inc.



     B.  Mansfield	       Commonwealth-Edison	




     M.  Poole                          Commonwealth-Edison   	
                                39

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B.    Plant and Site Data




     1.    UTM coordinates:
     2.   Sea Level elevation:  Sea  level
     3.   Plant site plot plant (Yes,  No) :   No
          (include drawing or aerial overviews)



     4.   FGD system-plan (Yes,  No):  See  diagram
     5.   General description of plant environs: A  highly indus-



           trialized area - many  refineries  and  chemical plants



     6.   Coal shipment mode; Two  types  of  coal were  burned dur-



           ing the course of  the  S02  scrubbing program,  both	



           shipped in  by barge.   The  western, low-sulfur coal,



           which  is the only  coal burned  in  the  boiler after the



           SO2 program was completed,  is  shipped to  Havana,  Illi-



           nois,  from  southern Montana via rail, unloaded, and



           barged upriver.
     FGD Vendor/Designer Background



     1.   Process name: Wet Limestone  Scrubbing	



     2.   Developer/licensor name:   Babcock  &  Wilcox	



     3.   Address: Power Generation Group,  20 S.  Van Buren



          	Avenue, Barberton,  Ohio	



     4.   Company offering  process:



          Company name: Babcock  &  Wilcox	



          Address: 20  S. Van Buren Avenue
                                40

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         Location:  Barberton,  Ohio
         Company contact:  Jack F.  Stewart
         Position;  Sales Manager
         Telephone number;  (216)  753-4511
     5.   Architectural/engineers  name;  Bechtel Power Corp.



         Address:  50 Beale Street	



         Location:  San Francisco, California	



         Company contact;  Mr.  J.  J.  Smortchevsky	



         Position:  Project Engineer	



         Telephone  number:  (415)  764-6262	



D.    Boiler Data



     1.   Boiler:  Unit 1
     2.   Boiler manufacturer:  Babcock & Wilcox
     3.   Boiler  service  (base,  standby,  floating, peak):



         Cycling load service	







     4.   Year boiler  placed  in  service;  1955	
     5.   Total hours operation;  (1976)  5,920
     6.    Remaining  life of  unit:
     7.    Boiler  type;  Radiant cyclone boiler



     8.    Served  by  stack  no.:  One	
     9.    Stack height;  107 m (350 ft)
    10.    Stack  top  inner  diameter;  3.8 m (12.4 ft)




    11.    Unit ratings:



          Gross  unit rating;  167 MW	
          Net  unit rating  without  FGD:  144 MW
                                41

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          Net  unit  rating with FGD:   137 MW  (4%  of  gross for FGD)



          Name plate  rating;   177 MW	
     12.   Unit  heat  rate:  11.8 MJ/net kWh  (11,217  Btu/net kWh)




          Heat  rate  without  FGD:  11.8 MJ/net  kWh (11,217 Btu/net kWh)




          Heat  rate  with FGD:  4 % energy penalty	




     13.   Boiler capacity factor,  (1975):   49.5%	




     14.   Fuel  type  (.coal or oil) ;  Coal	




     15.   Flue  gas flow:	




          Maximum:  363  m3/s  (770,000 acfm)	




          Temperature:   179°C  (355°F)	
     16.   Total excess air;   4% 02  in  flue  gas  stream



     17.   Boiler efficiency:	
E.    Coal Data (See General Comments,  Section M,  item 1)



     1.    Coal supplier:



          Name:  Decker Coal  Company
          Location:  Montana
          Mine location:  Dietz No., 1
          County,  State;  Montana (southern portion)



          Seam:  No. 1
     2.    Gross  heating value:  21.2-22.3 MJ/kg  (9100-9.600 Btu/lb)



     3.    Ash (dry basis) :  3.0 - 6.0 %	



     4.    Sulfur (dry  basis):  0.3 - 0.6 %
     5.    Total  moisture:  22.0 - 25.0
     6.    Chloride:  Not available
     7.   Ash  composition  (See  Table Al)  Not available
                                42

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                           Table Al
       Constituent
    Silica, SiO~

    Alumina, A12
-------
               Regulation and section No. :
G.   Chemical Additives:  (Includes all reagent additives -
     absorbents, precipitants,  flocculants, coagulants, pH
     adjusters, fixatives, catalysts, etc.)

     1.   Trade name: Limestone  	
          Principal ingredient: CaCO^ = 97.5%; MgCOT =  0.99%

          Function: S02 absorbent	

          Source/manufacturer:  Columbia	
          Quantity employed: 3 kg/sec  (12 tons/hour)	

          Point of addition; Absorber recirculation tank

          Trade name:  Lime                            	
          Principal ingredient; CaO
          Function: Sludge stabilizer
          Source/manufacturer:  Columbia
          Quantity employed: 10 g/kg  (200 Ib/ton) of sludge  (dry)

          Point of addition; Concrete mixing trucks	

     3.   Trade name: Collected coal fly ash	

          Principal ingredient: Fly ash	
          Function: Sludge stabilizer
          Source/manufacturer:  Collected from other operating units
                               on plant premises.
          Quantity employed; 200 g/kg  (400 Ib/ton) of sludge  (dry)

          Point of addition; Concrete mixing trucks	

          Trade name:  N/A*	

          Principal ingredient:	

          Function:
          Source/manufacturer:

          Quantity employed:	

     * Not applicable
                                44

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         Point of addition:



    5.   Trade name; N/A
         Principal ingredient:



         Function:
         Source/manufacturer:



         Quantity employed:	



         Point of addition:
H.   Equipment Specifications



    1.   Electrostatic precipitator(s)



         Number:  One
         Manufacturer:  Joy Manufacturing/Western Precip.  Div.



         Particulate removal efficiency;  90%  design,  79%  actual



         Outlet temperature;  168°C (355°F)	



         Pressure drop:	
         Mechanical collector(s)  N/A




         Number:	




         Type:	




         Size:
         Manufacturer:
         Particulate  removal  efficiency:



         Pressure drop:	
          Particulate  scrubber (s)



          Number:  Two  (A and B trains)
          Type:  Adjustable-throat venturi
         Manufacturer:  Babcock & Wilcox
          Dimensions:  2.4 x 7.9 x 4.9 m (8 x 26 x 16 ft)

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     Material,  shell;  Carbon steel
     Material,  shell lining:  Plasite and Kaocrete

     Material,  internals; N/A	
     No. of modules: One per train
     No. of stages: One per module
     Nozzle type: Stainless steel

     Nozzle size:
     No. of nozzles: 48 venturi,  32 wall wash

     Boiler load: 50%                  	
     Scrubber gas flow: 182 m3/sec, 179°C (335,000 acfm, 355°F)

     Liquid recirculation rate: 366 I/sec (5800 gal./min)

       Modulation:	

     L/G ratio: 2.4 1/m3 (18 gal./lOOO acf)	

     Scrubber pressure drop: 2240 Pa (9 in.  H20)	

       Modulation:	

     Superficial gas velocity:  36.6 m/sec (120 ft/sec)	

     Particulate removal efficiency; 98% (design)	

       Inlet loading; 366 mg/m3 (0.16 gr/scf)*	

       Outlet loading: 92 mg/m3 (0.04 gr/scf)*	

     SO2 removal efficiency:

       Inlet concentration:
       Outlet concentration:	

     S02 absorber (s)

     Number:  Two (A and B trains)
     Type:  Countercurrent tray tower, two stage

     Manufacturer: Babcock & Wilcox
* Based on tests conducted June 3-4, 1975, using high-sulfur
  Illinois coal (3.98% sulfur).


                           46

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Dimensions:  4.9  x  7.3  x  18.3  m (16  x 25  x  60  ft)



Material, shell; Corten  steel	



Material, shell lining:  Rubber
Material, internals;  Two  perforated  trays^



No.'of modules:  One per train	
No. of stages:  Two
Packing type: N/A  .
Packing thickness/stage:  N/A
Nozzle type:  Stainless steel



Nozzle size:
No. of nozzles:
Boiler load:  50%
Absorber gas flow;  149  m3/sec,  (315,000  acfm,  128°F)



Liquid recirculation rate;  694  I/sec  (11,000 gal./min)



  Modulation:	



L/G ratio:	
Absorber pressure drop:



  Modulation:
Superficial gas velocity:  3.0 m/s (9 ft/s)



Particulate removal efficiency:	



  Inlet loading:	
  Outlet loading;    92 mq/m   (0.04 qr/scf)



S02 removal efficiency:  76% (design)	



  Inlet concentration:
  Outlet concentration:
                       47

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5.    Clear water tray(s)




     Number:  N/A	




     Type:	
     Materials of construction:




     L/G ratio:	
     Source of water:
6.   Mist eliminator(s)



     Number:   Two  (A and  B  trains)
     Type:  Chevron
     Materials of construction:  FRP (Hetron)
     Manufacturer:  Babcock &  Wilcox
     Configuration (horizontal/vertical) :   Horizontal



     Distance between scrubber bed and mist eliminator:



      3.05 m (10  ft)
     Mist eliminator depth:
     Vane spacing:  3.8  cm (1.5  in)
     Vane angles:  45'
     Type and location of wash system;  Continuous fresh



     water  underspray;  deluge pond water overspray	



     Superficial gas velocity:	
     Pressure drop:  0.50  kPa (1.0  in.  H2O)	



     Comments:  Each mist  eliminator is a 2-stage, 3-pass,



      Z-shape, 90°,  sharp-angle bend unit;  1.2 m  (4 ft)



      between stages;	___^	



7.   Reheater(s):  Two  (A  and B trains)	



     Type (check appropriate category):
                           48

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     |2L|'   in-line



     Q    indirect hot air



     O    direct combustion



     Q    bypass




     Q    exit gas recirculation



     Q    waste heat recovery



     EH    other



     Gas conditions for reheat:



       Flow rate; 180 m3/sec (380,000 acfm)



       Temperature: 53°C (128°F)	
       SC>2 concentration:  Low and high-sulfur coal



     Heating medium:  Saturated steam
     Combustion fuel:  N/A
     Percent of gas bypassed for reheat:  N/A



     Temperature boost (AT): 11°C (52°F)	
     Energy required;  3.2% of boiler input	




     Comments:  Reheat  steam pressure is 2515 kPa (350 psig)



     steam temperature is 224°C (435°F) ,  consumption is	



     5.7  kg/sec (45,000 Ib/hr) .	




8.    Fan(s)  (Two,  1 per scrubbing train)




     Type:  Induced-draft boiler booster fan	



     Materials  of  construction:	



     Manufacturer:	




     Location:  Suction side of existing boiler I.D. fan



     Fan/motor  speed:	




     Motor/brake power; 1680 W (2250 hp)	
                           49

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11.
     Variable speed drive:
9.    Tank(s)
Item
Total number of
tanks
Retention time
at full load
Temperature, °C
<°F)
PH
Solids content,
percent
Specific gravity
Material of con-
struction
Venturi
scrubber
recirculation
tank
2
Variable
53
(128)
5.1-5.7
8
1.102
Rubber- lined
carbon steel
SO2 absorber
tower
recirculation
tank
2
Variable
53
(128)
5.8
8
1.049
Rubber- lined
carbon steel
Limestone
slurry
makeup
tank
1
4 hr
Ambient
7.0
15-30

Carbon steel
10.  Recirculation/slurry pump(s)
Description
Venturi
Recir.
Absorber
Recir.
Mill Prod.
Pumps
Slurry
Transfer
Manufacturer
A-S-H
A-S-H
A-S-H
A-S-H
Materials
Rubber-
lined
Rubber-
lined
Rubber-
lined
Rubber-
lined
No.
3
4
4
2
Capacity
366 I/sec
(5800 gpm)
353" I/sec
(5600 gpm)
32 I/sec
(500 gpm)
20 I/sec
(312 gpm)
Service
100% capacity
2 oper./l spare
60% capacity
No spare
100% capacity
1 oper./l spare
•100% capacity
1 oper./l spare
Thickener(s)/clarifier (s)



Number: One
     Type: Thickener
     Manufacturer:
     Materials of construction:
     Configuration:  Circular,  sloped bottom



     Diameter: 19.8  m  (65  ft)	
     Depth: 4.6 m  (15  ft)
     Rake speed:
12.  Vacuum filter (s)
                           50

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     Number:  One
     Type:  Belt-type vacuum filter
     Manufacturer:
     Materials of construction:

     Belt cloth material:
     Design capacity:  0.94 kg/sec (90 ton/day)

     Filter area:
13.   Centrifuge(s)

     Number:  Not applicable

     Type:	
     Manufacturer:
     Materials of construction:

     Size/dimensions:	

     Capacity:	
14.   Interim sludge pond(s)  N/A (See Section M - Comments,
                                 Item 2)
     Number:
     Description:

     Area:
     Depth:
     Liner type:

     Location:
     Typical operating schedule:
     Ground water/surface water monitors:
15.  Final disposal site(s) N/A  (See Section M - Comments,

                                 Item 2)
                           51

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     Number:
     Description:



     Area:
     Depth:
     Location:
     Transportation mode:
     Typical operating schedule:
16.  Raw materials production




     Type: Wet ball mills
     Number:  Two
     Manufacturer:
     Capacity:  3 kg/sec  (12 ton/hr)
     Product characteristics: Mill product mesh  size is



     95% < 325 mesh	








Equipment Operation, Maintenance, and Overhaul Schedule



1.   Scrubber (s)



     Design life:	____^__	



     Elapsed operation time:	



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures:
2.    Absorber(s)
                           52

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     Design life:
     Elapsed operation time:



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures








3.    Reheater(s)



     Design life:	
     Elapsed operation time:



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures:








4.   Scrubber fan(s)



     Design life:	
     Elapsed operation time:



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures:








5.   Mist eliminator(s)



     Design life:	



     Elapsed operation time:             	
                           53

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     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures








6.    Pump(s)



     Design life:	
     Elapsed operation time:



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures:








7.   Vacuum filter(s)/centrifuge(s)



     Design life:	



     Elapsed operation time:	



     Cleanout method:
     Cleanout frequency:



     Cleanout duration:
     Other preventive maintenance procedures:








8.    Sludge disposal pond(s)



     Design life:	



     Elapsed operation time:



     Capacity consumed:	
     Remaining capacity:
                           54

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          Cleanout  procedures:
J.    Cost  Data




     1.    Total  installed  capital  cost:  $15,538,000
     2.   Annualized  operating  cost:  $3,984,778
     3.    Cost  analysis  (see  breakdown:   Table A2)



     4.    Unit  costs




          a.    Electricity;  $586,875 (1.92 mills/kWh)



          b.    Water:
          c.    Steam;  $72,595 (0.24 mills/kWh)



          d.    Fuel  (reheating/FGD  process):  N/A



          e.    Fixation  cost;  $546,217	
          f.    Raw material;  $62,726 (0.21 mills/kWh)  limestone



          g.    Labor;  $81,709 (0.27 mills/kWh)  for operating and



               technical labor;  maintenance labor not included








     5.    Comments ;  Will County  FGD system is a full-scale	




          demonstration unit erected on an accelerated overtime



          schedule  in a difficult retrofit application.  The	



          capital cost figure reflects these constraints.  The



          annualized operating cost figure is provided for 1975




          operations.	
                                55

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               Table A2.  Cost Breakdown
Cost elements
A. Capital Costs
Scrubber modules
Reagent separation
facilities
Waste treatment and
disposal pond
Byproduct handling and
storage
Site improvements
Land, roads, tracks,
substation
Engineering costs
Contractors fee
Interest on capital
during construction
B. Annualized Operating
Cost
Fixed Costs
Interest on capital
Depreciation
Insurance and taxes
Labor cost including
overhead
Variable costs
Raw material
Utilities
Maintenance
Sludqe Treatment
Included in
cost estimate
Yes
1
No
EZJ
EZ]
CZ]
CZI
Estimated amount
or % of total
capital cost
Breakdown $
Direct Indirect
2,928,000 2,
397,000
Total
928,000
397,000
642,000

In contractors fee
In contractors fee
965,000
9,010,000 9,
965,000
010,000

13,300,0001,600,000* 14,
15,
2,280,000 98,000 2,
900,000
542,000
378,000


81,709
62,726
586,875 72,595
256,656
546.217 	
81,709
62,726
659,470
256,656
546 .217
* 12% of direct
                                                     3,984,778
                           56

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K.    Instrumentation

     A  brief  description of the control mechanism or method  of
     measurement  for each of the following process parameters:

     0     Reagent addition: See remarks (below)
          Liquor solids content:  See remarks (below)	



          Liquor dissolved solids content;  See remarks (below)



          Liquor ion concentrations  See remarks (below)

            Chloride:	



            Calcium:	



            Magnesium:	
            Sodium:
            Sulfite:
            Sulfate:
            Carbonate:
            Other (specify):
                                57

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     0     Liquor  alkalinity:  See remarks (below)
          Liquor  pH;  See remarks (below)
     0     Liquor  flow;  See remarks (below)
     0     Pollutant (S00,  particulate,  NO )  concentration in
                       ^                  -X


          flue gas: See remarks (below)	
          Gas flow:  See remarks (below)
          Waste water  See remarks (below)
     0 '   Waste solids:  See remarks
     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:  Text of report provides a diagram (Figure 4) and



     description of the scrubber/absorber control system.  	
L.    Discussion of Major Problem Areas:



     1.    Corrosion:  See text of report (Section 4 - Problems,



          Solutions,  and System Modifications)	
                                58

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2.    Erosion; See text of report  (Section 4 - Problems.



     Solutions, and System Modifications)	
3.   Scaling: See text of report  (Section 4 - Problems,



     Solutions, and System Modifications)
4.   Plugging: See text of report  (Section 4 - Problems,



     Solutions, and System Modifications)	
5.   Design problems;  See  text of  report  (Section 4 - Prob-



     lems, Solutions,  and  System Modifications)	
6.   Waste water/solids disposal:  See  text of  report  (Sec-



      tion 4  -  Problems.  Solutions,  and System  Modifications)
                            59

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     7.    Mechanical problems:  See text of report (Section 4 -


          Problems,  Solutions,  and System Modifications)	
M.   General comments.:
     1.  Initial scrubbing operations were conducted on high-sul-



     fur Illinois coal.   A long-term contract for low-sulfur	



     western coal was made in 1975.   Thereafter,  scrubbing opera-



     tions were conducted on high-sulfur coal, low-sulfur coal



     and blends of both.  Operation on low-sulfur coal only began



     in July 1977.	

                  2
     2.  A 0.03 km  (7-acre) on-site clay-lined hold basin was


     used for temporary sludge disposal prior to September 1975.



     The thickener underflow is treated with fly i.ash and lime



     and transported directly to an off-site landfill.  During



     overflow or equipment emergencies, the thickener is bypassed



     and wastes are disposed in the interim pond.  This material



     is retrieved, treated, and hauled away to the off-site land-



     fill during later reduced-load periods.
                                60

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                                TECHNICAL REPORT DATA
                         (Please read Instructions on the reverse before completing)
 1. REPORT NO.
 EPA-600/7-78-048b
    2.
                                3. RECIPIENT'S ACCESSION NO.
 I. TITLE AND
         SUBTITLE Survey of Flue Gas Desulfurization
               ftif »-*A r V J VA J. JLUW «M*C4AJ J-S\sO •-* ]_' UJL AdUC
 Systems: Will County Station, Commonwealth
 Edison Co.
                                5. REPORT DATE
                                  March 1978
                               6. PERFORMING ORGANIZATION CODE
 . AUTHOR(S)

 Bernard A.  Laseke, Jr.
                               8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
 PEDCo Environmental, Inc.
 11499 Chester Road
 Cincinnati, Ohio  45246
                                10. PROGRAM ELEMENT NO.
                                EHE624
                                11. CONTRACT/GRANT NO.

                                68-01-4147,  TaskS
 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 PERIOI
                                Subtask Final; 1-6/77
                                                                          D COVERED
                                14. SPONSORING AGENCY CODE
                                 EPA/600/13
 15. SUPPLEMENTARY NOTES jERL-RTP project officer is Norman Kaplan, Mail Drop 61, 919/
 541-2556. Report EPA-650/2-75-0571 gives first survey results.
 16. ABSTRACT
         The report gives results of a second survey of the flue gas desulfurization
  (FGD) system on Unit 1 of Commonwealth Edison Co. 's Will County Station. The
  FGD system, started up in February 1972,  utilizes a limestone slurry in two para-
  llel scrubbing trains. Each train includes a venturi scrubber, sump, and two-stage
  sieve tray absorber for the control of fly ash and SO2. The flue gas cleaning wastes
  are stabilized with lime and collected fly ash and hauled away to an off-site
  disposal area.  The FGD system operated as an SO2-removal unit from February
  1972 to July 1977,  treating flue gas from the combustion of low sulfur western coal,
  high sulfur Illinois coal, and blends of both. Experimental SO2-removal operations
  were concluded in July  1977. The scrubbing system remains  in service  removing
  fly ash from low sulfur western coal flue gas. Some SO2 is removed from the flue
  gas during particulate-removal operations because of the alkalinity of the  collected
  fly ash and the limestone additive used for pH control of the scrubbing solution.
 7.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                          b.IDENTIFIERS/OPEN ENDED TERMS
                                            c. COSATI Field/Group
 Air Pollution
 Flue Gases
 Des ulfur ization
 Fly Ash
 Limestone
 Calcium Oxides
Slurries
Scrubbers
Coal
Combustion
Cost Engineering
Sulfur Dioxide
Dust Control
Air Pollution Control
Stationary Sources
Wet Limestone
Particulate
13B
2 IB
07A,07D


07B
11G

21D

14A
 3. DISTRIBUTION STATEMENT

 Unlimited
                    19. SECURITY CLASS (ThisReport)
                    Unclassified
                        21. NO. OF PAGES
                             70
                   20. SECURITY CLASS (Thispage)
                    Unclassified
                                            22. PRICE
EPA Form 2220-1 (9-73)
                  61

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