U.S. Environmental Protection Agency Industrial Environmental Research     EPA-600/7-78-048d
Office of Research and Development  Laboratory                    *%^*»
                Research Triangle Park. North Carolina 27711 MaTCn 1978
      SURVEY OF FLUE GAS
      DESULFURIZATION SYSTEMS:
      CHOLLA STATION, ARIZONA
      PUBLIC SERVICE CO.
      Interagency
      Energy-Environment
      Research and Development
      Program Report
                           ~ZL

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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-
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This report has been reviewed by the participating Federal Agencies, and approved
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tion Service, Springfield, Virginia 22161.

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                                     EPA-600/7-78-0488
                                           March 1978
SURVEY OF FLUE GAS DESULFURIZATION
  SYSTEMS: CHOLLA STATION, ARIZONA
              PUBLIC SERVICE CO.
                         by

                    Bernard A. Laseke, Jr.

                   PEDCo Environmental, Inc.
                     11499 Chester Road
                    Cincinnati. Ohio 45246
                    Contract No. 68-01-4147
                        TaskS
                  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, O.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. Ed. L. Lewis,
Manager, Administration and Technical Services, Arizona Public
Service; Mr. Coe Suydam, Mechanical Engineering Department,
Arizona Public Service; Mr. Gil Gutierrez, Plant Engineering
Department, Arizona Public Service; Milton D. Johnson, Results
Engineer, Cholla Steam Electric Station, Arizona Public Service;
Aubry Parsons, Assistant Superintendant, Cholla Steam Electric
Station, Arizona Public Service; and John Vayda, Utility Gas
Cleaning Division, Research-Cottrell.
                                ii

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                            CONTENTS


                                                            Page

Acknowledgment                                                ii

List of Figures and Tables                                    iv

Summary                                                      7

     1.   Introduction                                        1

     2.   Facility Description                                2

     3.   Flue Gas Desulfurization System                     6

               Process Description                            6
               Design Parameters                             11
               Limestone Milling Facilities                  14
               Process Chemistry:  Principal Reactions       14
               Process Control                               20

     4.   FGD System Performance                             22

               Performance Test Run                          22
               Operation History:  Problems and Solutions    23
               Design and Operation Modifications            29
               Economics                                     29

Appendices

     A.   Plant Survey Form                                  35
     B.   Plant Photographs                                  56
                               iii

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                         LIST OP FIGURES


No.                                                         Page

 1   Simplified process flow diagram, Cholla 1 FGD system     7

 2   Simplified process flow diagram, Module A, Cholla 1
     FGD system                                               8

 3   Basic components of flooded-disc FGD system venturi
     scrubber and cyclonic separator, Cholla FGD system      10

 4   Gas flow and damper arrangement, Cholla FGD system      12


                         LIST OF TABLES


No.                                                         Page

 1   Data Summary:  Cholla Unit 1                             ix

2A   Average Monthly Analyses of Coal Burned in 1975           3

2B   Design, Operation, and Emission Data, Cholla Boiler 1     5

 3   Data Summary:  Particulate and SO- Scrubbers             15

 4   Data Summary:  FGD System Hold Tanks                     15

 5   Data Summary:  FGD System Mist Eliminators               16

 6   Data Summary:  FGD System Reheaters                      17

 7   Typical Pressure Drop Across Components of Particulate
     Scrubber and Packed Tower                                18

 8   Results of FGD System Performance Test Runs,
     October 2 to October 21,1973                            24

 9   Chemical Analysis of Cholla Station Service Water        28

10   Performance Data for Cholla 1 FGD System:  October
     1973 to December 1977                                    30


                               iv

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                             SUMMARY

     The wet limestone flue gas desulfurization  (FGD) system on
Boiler 1 at the Cholla Steam Electric Station of the Arizona
Public Service Company (APS) was designed and installed by
Research-Cottrell  (R-C).
     Research-Cottrell had previously conducted pilot plant
operations at the Cholla Station  (treating a flue gas slip
stream from Boiler 1), but their work on a full-scale FGD system
did not begin until January 1971.  They prepared preliminary
design and submitted a proposal to APS in April 1971 and were
awarded the contract in July.
     Construction and initial testing were not completed until
December 3, 1973.  Construction was delayed for several reasons:
changes in engineering design and material specifications, equip-
ment delivery delays, adverse weather conditions, system shake-
down problems, and problems with the FGD system at APS's Four
Corners Station.
     Commercial operation of the FGD system commenced on December
14, 1973, and has proceeded on a continuous basis since that
time.  Cholla Boiler 1 is a base-load unit with a maximum, con-
tinuous, net generating capacity of 115 MW when the unit is tied
into the FGD system.  At full load it consumes pulverized coal at
a rate of approximately 49 Mg (54 tons) per hour.  The fuel
burned in this unit is a low-sulfur, New Mexico coal with the
following average characteristics:  23.6 MJ/kg  (10,150 Btu/lb)
heat content; 0.5 percent sulfur; and 13.45 percent ash.
     The FGD system consists of two parallel modules  (A and B),
each designed to accomodate 50 percent of the boiler flue gas.
Module A includes a variable-throat, flooded-disc scrubber for
particulate control, followed by a packed tower that uses a
                                v

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limestone slurry for sulfur dioxide removal.  The limestone
absorbent is purchased primarily from the Superior Company in
Phoenix, Arizona.
     Module B differs from Module A only in that the absorber
tower is not packed and limestone slurry is not circulated
through it.  Module A is designed for 92 percent sulfur dioxide
removal efficiency and Module B for 25 percent.  This yields a
combined sulfur dioxide removal efficiency of 58.5 percent.  This
efficiency is based on an inlet sulfur dioxide concentration of
approximately 400 to 500 ppm.  Either or both modules can be
bypassed.  Gas leakage around each module is approximately 4.5
percent of the volume of the gas being treated.
     The Munters packing in the Module A tower is 0.6 m (2 ft)
thick and constructed of polypropylene corrugated sheets joined
together in a crisscross pattern similar to a honeycomb.  The
mist eliminators are also constructed of polypropylene.  The
three bundles of shell-and-tube steam reheaters are 316L stain-
less steel.
     The Cholla Steam Electric Station does not have a sludge
treatment or fixation system.  The sludge and fly ash are pumped
to an unlined, pre-existing fly ash pond in a common pipeline.
The FGD system operates on an open-water-loop basis that does not
require the recycling of water from the pond.  Fresh makeup water
required to maintain the water balance in the scrubbing system is
0.07 liters/sec per MW (1.04 gpm/MW).
     According to Research-Cottrell, the particulate and S02
collection efficiencies of Module A were 99.7 and 92 percent
during a test run.  As of December 1977, APS had not conducted an
official acceptance test on the system.
     Minor modifications were made as a result of initial test-
ing, and the system was officially placed in service on December
14, 1973.  It operated with a 92.6 percent reliability factor
until April 15, 1974, when the system was shut down for approxi-
mately 2 weeks for scheduled modifications of the expansion
joints.  Research-Cottrell repair crews were available during
                                vi

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most of the first half of 1974, and it is believed that their
attention to maintenance was partly responsible for the high
system reliability demonstrated during the shakedown period.
     The performance of the system from the completion o'f final
modifications in October 1973 through December 1977 indicates a
high degree of mechanical reliability.  Shutdowns have occurred
primarily during scheduled turbine, boiler, and FGD system over-
hauls.  The average reliability indexes for the total FGD system
in 1974, 1975, 1976, and 1977 were 91, 88, 88, and 95 percent,
respectively.  Reliability indexes for Module A in the same years
were 94, 91, 89, and 93 percent, and for Module B, 88, 85, 89,
and 97 percent.
     Total installed capital cost of the Cholla FGD system to
date is approximately $6.5 million or $57/kW  (1973 dollars).
This cost figure is not final because final performance tests
have not been conducted and APS has not yet accepted the system.
The capital cost figure includes engineering costs, site prepara-
tion, erection, electrical service, limestone handling facili-
ties, and pilot plant engineering.
     Annual operating costs are estimated to be 2.2 mills/kWh.
This figure includes a 23 percent charge on capital investment to
account for interest, depreciation, taxes, and other fixed char-
ges.  Also included are labor costs of 0.09 mills/kWh  (one full-
time auxiliary operator); utility costs of 0.2 mills/kWh  (2.8
MW/hr electricity and 18,000 Ib/hr of steam); and material costs
of 0.15 mills/kWh  (limestone).  Maintenance and sludge disposal
costs are not included.
     Arizona Public Service is now in the process of increasing
the station's power generating capacity from 115 to 1315 MW.
Units 2 and 3, now under construction, are scheduled for com-
mercial start-up in June 1978 and June 1979.  Each is rated at
250 MW.  Units 4 and 5, now in the planning stage, are scheduled
for commercial start-up in June 1980 and June 1983.  Each of
these units is rated at 350 MW.  Current emission control reg-
ulations require that three of the additional units (2, 4, and

                               vii

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5) have FGD-equipped boilers.  Research-Cottrell has been awarded
two separate contracts to provide additional FGD systems for
Units 2 and 4.* Although Unit 5 is still in the preliminary
design stage, it is expected to include an FGD system.  No FGD
system is required on Unit 3; it will have only an electrostatic
precipitator (ESP)  for particulate control.
     Table 1 summarizes general data on Cholla Unit 1.
                               viii

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             Table 1.  DATA SUMMARY:  CHOLLA UNIT 1
Unit rating  (net)

Fuel

Average fuel characteristics'

  Heating value

  Ash

  Sulfur

FGD system supplier

Process

New or retrofit

Start-up date

Modules

Efficiency

  Particulates

  Sulfur dioxide

Water makeup


Sludge disposal



Unit cost

  Capital

  Annual
    115 MW

    Coal



    23.6 MJ/kg  (10,150 Btu/lb)

    13.45 %

    0.52 %

    Research-Cottre11

    Limestone slurry

    Retrofit

    October 1973

    Twob



    99.7 %°

    58.5 %d

    0.07 liters/sec per MW
    (1.04 gpm/MW)

    Unstabilized sludge disposed
    of on site in pre-existing
    ash disposal pond.



    $57/kW

    2.2 mills/kWh
a Average values of coal burned during 1975 operation.
  Only one module  (A) is equipped with packing and limestone
  slurry circulation for sulfur dioxide removal.
c Total particulate removal efficiency provided by mechanical
  collectors and venturi scrubbers.
d Total system removal efficiency.  Module A efficiency is 92
  percent; Module B, 25 percent.
  1973 dollars.
ix

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                            SECTION 1
                          INTRODUCTION

     The Industrial Environmental Research  (IERL) Laboratory of
the U.S. Environmental Protection Agency  (EPA) has initiated a
study to evaluate the performance characteristics and reliability
of flue gas desulfurization  (FGD) systems operating on coal-fired
utility boilers in the United States.
     This report, one of a series on such systems, covers the
Cholla Steam Electric Station of Arizona Public Service Company
(APS).  It includes pertinent process design and operating data,
a description of major start-up and operational problems and
solutions, atmospheric emission data, and capital and annual cost
information.
     This report is an update of a previous report based on
observations made during an April 2, 1974, plant inspection and
on data provided by the utility and the system supplier during
that visit.  This update report is based on a second plant visit
on April 8, 1976, and data obtained since that visit.  Informa-
tion presented is current as of December 1977-
     Section 2 presents pertinent facility design and operation
data and actual and allowable particulate and sulfur dioxide
emission rates; Section 3 describes the FGD system; and Section
4 analyzes FGD system performance.  Appendices A and B contain
details of plant and system operation and photos of the installa-
tion.

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                            SECTION 2
                      FACILITY DESCRIPTION

     The Cholla Steam Electric Station of APS is in an arid
desert region in Navajo County, Arizona, near Joseph City.  The
terrain surrounding the station is relatively flat and sparsely
populated.  There is no other major industry in the area.
     Cholla now operates only one steam turbine generating unit
(Boiler 1).  This Combustion Engineering (CE) boiler is a dry-
bottom, pulverized-coal-fired unit with a net generating capacity
of 115 MW.  It was put in commercial service in May 1962.
     Arizona Public Service is in the process of increasing the
Station's capacity from 115 to 1315 MW.  Units 2 and 3, now under
construction, are scheduled for commercial start-up in June 1978
and June 1979.  Each is rated at 250 MW.  Units 4 and 5, now in
the planning stage, are scheduled for commercial start-up in June
1980 and June 1983.  Each of these units is rated at 350 MW.  All
are CE pulverized-coal-fired units.
     The plant burns low-sulfur subbituminous coal from the
McKinley mine near Gallup, New Mexico.  It is shipped in by rail.
A typical analysis of this coal gives the following values:
heating value, 10,400 Btu/lb;  sulfur content, 0.5 percent;
chloride content, 0.025 percent;  ash content, 13.5 percent; and
moisture content, 15 percent.   Table 2A shows monthly average
analyses of the coal burned.
     Boiler 1 is equipped with mechanical collectors upstream
from the FGD system.  These R-C multicyclones are designed to
remove 80 percent of the inlet particulate. matter.  If design
efficiency is achieved, loading at the outlet of the mechanical
collectors should be approximately 2.2 g/m3  (2.0 gr/scf).

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Table -2A.  AVERAGE MONTHLY ANALYSES OP COAL BURNED  IN  1975




               CHOLLA STEAM ELECTRIC STATION
Month
Jan.
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
Oct.
Nov.
Dec.
Average
Sulfur,
%
0.56
0.55
0.51
0.52
0.51
0.56
0.55
0.51
0.54
0.49
0.48
0.46
0.52
Chloride
(range) , %
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
0.01-0.04
Ash,
%
13.51
14.15
22.49
17.69
11.26
12.33
9.76
11.46
9.88
12.40
14.60
11.89
13.45
Heating value,
MJ/kg
23.5
22.6
20.9
22.5
23.4
24.1
24.6
23.3
23.7
23.7
23.1
23.7
23.1
(Btu/lb)
(10,093)
(9.750)
(9,970)
(9,671)
(10,053)
(10,352)
(10,578)
(10,001)
(10,199)
(9,956)
(9,946)
(10,178)
(10,150)
Average
moisture, %
15
15
15
15
15
15
15
15
15
15
15
15
15

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     Arizona State Department of Health Regulation No. 7-1-3.5
limits particulate emissions to 84.27 ng/J  (0.196 lb/106 Btu) of
heat input to the boiler.  Arizona Public Service reports present
particulate emissions at Cholla are 11.18 ng/J  (0.026 lb/106
Btu).
     Regulation No. 7-1-4.2 limits SO2 emissions to 430 ng/J  (1.0
lb/106 Btu) of heat input to the boiler.  The present emission
rate, based on a combined PGD removal efficiency of 58.5 percent,
is estimated to be 185 ng/J (0.43 lb/106 Btu).
     Based on limits imposed by current emission regulations,
three of the four additional units (2, 4, and 5) planned for this
station must be equipped with FGD systems.  Arizona Public Ser-
vice has already awarded two separate contracts to R-C for
limestone slurry TGD systems on Units 2 and 4.  "Each system will
consist of four modules for the control of particulates and
sulfur dioxide.  Both PGD systems will have 100 percent capacity,
and both are scheduled to go on line simultaneously with the
boilers (Unit 2 in June 1978 and Unit 4 in June 1980).  Unit 3
will include only an ESP for the control of particulate emis-
sions.  The emission control strategy for Unit 5 has not yet been
determined.
     Table 2B presents pertinent plant design, operation, and
emission data.

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         Table 2B. DESIGN, OPERATION, AND EMISSION DATA,

                         CHOLLA BOILER 1
Total rated generating capacity

Boiler manufacturer

Year placed in service

Unit heat rate


Coal consumption


Maximum heat input


Stack height above grade


Design maximum flue gas rate


Flue gas temperature


Emission controls:

  Particulate


  Sulfur dioxide


Paritculate emission rates:

  Allowable

  Actual

Sulfur dioxide emission rates:

  Allowable

  Actual
115 MW

Combustion Engineering

1962

10,199 kJ/net kWh
(9,670 Btu/net kWh)

49 Mg/hr
(54 tons/hr

1156 GJ/hr
(1096 106 Btu/hr)

76 m
(256 ft)

227 m3/sec
(480,000 acfm)

136°C
(276°F)
Mechanical collectors and
venturi scrubbers

Venturi scrubber and
packed-bed absorber
84.27 ng/J (0.196 lb/10  Btu)

11.18 ng/J (0.026 lb/106 Btu)
430 ng/J (1.0 lb/10  Btu)

185 ng/J (0.43 lb/106 Btu)

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                            SECTION 3
                 FLUE GAS DESULFURIZATION SYSTEM

PROCESS DESCRIPTION
     The FGD system consists of two modules, A and B.  Each
module includes a flooded-disc venturi scrubber, a cyclonic mist
eliminator, an absorber tower, and a final mist eliminator.  The
absorber on Module A includes packing for removal of the sulfur
dioxide with circulating limestone slurry.  The absorber tower in
Module B is a hollow spray tower, and limestone slurry is not
circulated through it.  Each module treats approximately one-half
of the total boiler flue gas.  A simplified process flow diagram
of the entire FGD system is shown in Figure 1.  A simplified
process flow diagram of Module A, which provides the primary sul-
fur dioxide control, is shown in Figure 2.
Gas Circuit
     Flue gas from the boiler induced-draft (ID) fans is pres-
surized by two booster fans to a static pressure of approximately
6.2 kPa (25 in. H~O), then flows downward through the throat of
the venturi-type, flooded-disc particulate scrubber.  Limestone
slurry flows out over the disc and is atomized as it is sheared
by the gas stream at the edge of the disc.  Slurry is also
injected tangentially through nbzzles on the inside wall of the
venturi scrubber shell above the tapered throat.  The orifice is
formed by the annular space between the circumference of the
horizontal disc and the wall of the tapered duct section in the
throat area.  The disc is adjusted in the vertical plane within
the tapered duct to increase or decrease the area of the orifice.
In this manner gas pressure drop and the resulting particulate
scrubbing efficiency are controlled.  The saturated, scrubbed
flue gas then passes through a cyclonic mist eliminator, where

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                             iuvn
                                                      r	,        *
                                                      [tUKi TAH« |    I  «!»SI TAM ]
                                                                       TO CVA»MATIC!<

                                                                         KKO
Figure 1.  Simplified  process  flow diagram, Cholla 1 FGD system.

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  INLET GAS
FROM MECHANICAL
  COLLECTORS
BOOSTER
FAN
BYPASS
DAMPER
                   FLOODED DISC
                     SCRUBBER
                                       H   K*
           \7
                         a
                          SLUDGE
                          HOLDUP
                          TANKS
     1CYLCONIC
       MIST
     ELIMINATOR
                REHEATER
   IMPINGEMENT
  MIST ELIMINATORS
 *-	MAKEUP HATER
             (FROM WELL)
b-	
                                               PACKING
                                               CONICAL SLURRY
                                                SEPARATOR
                                             FDS
                                           DISCHARGE
        PRE-EXISTING
        ASH DISPOSAL
          POND
                                    FDS SLURRY TANK
                                                    LIMESTONE
                                        MAKEUP WATER
                                       "(FROH UELL)
                                                                              EXIT GAS
                                                                              TO STACK
                                                             fr-
                                                                   TOWER TANK
          Figure  2.   Simplified  process  flow  diagram  of

                     Module  A,  Choila  1 FGD  system.
                                          8

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solids from  collected  fly ash,  limestone  slurry,  and  reaction
products are separated from the gas  stream before it  enters  the
absorber.  A diagram of a Cholla flooded-disc  venturi and  cyclon-
ic mist eliminator  is  provided  in Figure  3.
     Gas from the cyclonic mist eliminator enters the absorber
tower near the base.   In Module A only, it contacts the  limestone
slurry on the surface  of the wetted-film  Munters  packing,  which
is 0.6 m  (2  ft)  thick.
     The packed  tower  section is separated from the cyclonic mist
eliminator by a  plate  containing a conical hat.   This arrangement
permits the  flue gas to leave the cyclonic mist eliminator and
enter the packed spray section  and yet prevents the spent  lime-
stone slurry in  the packed spray section  from  combining  with the
spent scrubbing  solution from the flooded-disc venturi (see
Figure 2).   Thus, fly  ash cannot enter the absorber tower.
     The scrubbed gas  then passes through a set of mist  elimina-
tors  (one set per absorber)  and is reheated before it is dis-
charged to the atmosphere through the main stack. The mist
eliminators  are  slat (special baffle design) impingement type,
constructed  of polypropylene and arranged horizontally (vertical
gas flow) in two stages.   Reheat is  provided by a set of steam-
heated, shell-and-tube heat exchangers  (one set per module).
Each set of  reheaters  contains  two bundles of  tubes,  which raise
the temperature  of  the saturated gas stream from  49 °C (120°F) to
71°C  (160°F)  before it passes through a duct to the brick-lined,
concrete stack.
     Limestone is added to Module A  of the FGD system at a rate
of approximately 110 percent of the  stoichiometric requirement
for reaction with the  sulfur dioxide in the flue  gas.  Part  of
the circulated liquor  in  the sulfur  dioxide absorber  is  diverted
to the flooded-disc  scrubber tank (common to both modules) to
maintain the pH  between 4  and 5 in the particulate control system
(flooded-disc venturi).   The liquid  level in this tank is  main-
tained by pumping the  excess spent liquor to one  of two  surge
tanks (sludge holdup-tanks)  before it is  discharged to a pre-

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 LIMESTONE
  SLURRY
      FLOODED-DISC
       SCRUBBER
   HORIZONTAL DISC
    ORIFICE AREA
       LIMESTONE
        SLURRY
                                           CYCLONIC MIST
                                            ELIMINATOR
                                 SPENT SOLUTION
                                   DISCHARGE
Figure  3.   Basic components of  the variable-throat,

    flooded-disc venturi scrubber and cyclonic

            separator,  Cholla FGD system.

                         10

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existing pond.   The plant  site  has  no  facilities  for  sludge
storage or  fixation.   Because of  the area's  light rainfall and  a
high evaporation rate,  wastewater discharge  into  receiving
waters is not  a  problem.   Therefore no liquor  is  recirculated
back to the process.
     Dampers in  the FGD system  are  arranged  so that only Module
B can be bypassed, or  both Modules  A and  B can be bypassed simul-
taneously.  Module A alone can  only be bypassed for short periods
of time, however,  because limestone,  which  enters the  system in
the Module  A absorber  tower  tank, is used to control  the opera-
ting pH of  the entire  particulate scrubber system to  a  range of 4
to 6.  The  inlets to both  modules from the booster fans are
interconnected through a common suction header.   Flue gas flow
control to  both  modules is maintained  by  balancing the  module
fans via amperage control.   Figure  4 presents  a diagram of the
Cholla FGD  system damper arrangement.
DESIGN PARAMETERS
     The R-C FGD system at Cholla is designed  to  treat  227 m /sec
(480,000 acfm) of flue gas at 136°C (276°F).   Actual  boiler flue
gas flow to both modules (at 115-MW generating capacity) measures
approximately  189 m /sec (400,000 acfm).  In addition,  bypass
leakage around the FGD system amounts  to  8 m3/sec (17,000 acfm).
     The flooded-disc  particulate scrubbers  are constructed of
316L stainless steel and are 1.8 m  (6  ft) in diameter by 13.7 m
(45 ft) high.  Pressure drops on  each  is  2.5 kPa  (15  in. H2O).
Each scrubber  operates  with  a liquid recirculattion rate of about
137 liters/sec (2170 gpm)  at full load, which  is  equal  to a
liquid-to-gas  (L/G) ratio  of 1.4  liters/m3 (10.1  gal/1000 ft3)  at
50°C (l22°F).  Two-thirds of the scrubbing solution used in the
flooded-disc scrubbers  is  introduced through the  hollow shaft of
the flooded disc; the remainder is  sprayed through tangential
nozzles on the vessel wall.
     The absorber towers are constructed of  316L  stainless steel
and are 6.7 m  (22 ft) in diameter by 21.3 m  (70 ft) high.  The

                               11

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INLET
LOUVER
DAMPER
                          REHEATER
                            SYSTEM
                          GUILLOTINE
                            DAMPER
 REHEATER
  STACK
GUILLOTINE
  DAMPER
F6D
BOOSTER
FAN
1
R
R
Mt
""
1
1
t
U-
1






1- -



MANUAL J-
GUILLOTINE
DAMPER
1
t
4

!
1
	 *\ -•""". j+ 	
~V_^~
CROSSOVER DAMPER
I GUILLOTINE

_^
17000 ACFM
1 STACK
BYPASS LOUVER
DAMPERS
BOILER
ID
FAN

1
1
                                                  BOILER
                                                    ID
                                                   FAN
                                                              MANUAL
                                                             GUILLOTINE
                                                              DAMPER
            Figure 4.   Gas flow and damper arrangement,

                           Cholla 1  FGD  system.

                                      12

-------
sulfur dioxide absorber  in Module A  includes  a  fixed plate and
conical hat separator and packing.   The  fixed plate and conical
hat separator are also constructed of  316L  stainless steel.  The
Munters packing, which consists of a fixed  matrix of rigid sheets
of polypropylene, has a  high  specific  surface area and low pres-
sure drop  [0.12 kPa  (0.5 in.  H2O)].  The superficial gas velocity
of the sulfur dioxide absorber is  2.1  m/sec (6.9 ft/sec), and
the L/G ratio is 6.5 liters/m3  (48.9 gal/1000 ft3).
     The mist eliminators in  each absorber  tower are arranged
horizontally in two stages.   The first stage  is a Chevron-type,
two-pass, polypropylene  mist  eliminator,  and  in the S02 absorber
is approximately 3.7 to  4.6 m (12 to 15  ft) above the packing.
The design configuration of the second-stage, four-pass, poly-
propylene mist eliminator differs only slightly from that of the
first stage.  The distance between stages is  approximately 1.2 m
(4 ft).  Vane spacing is 3.8  cm  (1.5 in.) in  the first stage and
18.1 cm  (8.1 in.) in the second stage.   On  each tower, both
stages of the mist eliminator are washed on timed cycle with
makeup water from plant  wells.  A quadrant  of each mist elimin-
ator stage is sprayed sequentially for 45 seconds every 30 min-
utes with 520 kPa  (60 psig) makeup water.   Flow rate of the
makeup water to the mist eliminator  is approximately 15 liters/
sec (240 gpm).
     The set of shell-and-tube heat  exchangers  on each module
raises the temperature of the gas from 50°C (122°F) to 72°C
(162°F) before it is discharged to the atmosphere.  Each reheater
consists of two bundles  of 316L stainless steel bare tubes with
an outside diameter of 2.5 cm (1.0 in.).  The heating medium is
high-pressure steam extracted from the boiler steam drum, which
is reduced in pressure from 13.2 MPa (1900  psig) to 1.8 MPa (250
psig).  The reheater rating is approximately  84 GJ/hr (8 million
Btu/hr).  Reheater steam power requirements are equivalent to
approximately 2 MW of electrical capacity.   [Six steam soot
blowers are operated 5 minutes during  each  8-hour period (once
per shift) to clean the  tubes.]

                               13

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     The reheated, scrubbed gases are discharge'1, through carbon
steel ducts to the main stack.  The ducts fum each module enter
the stack at points directly opposite each other (see Figure 4).
The stack shell is constructed of brick-lined concrete.
     Tables 3 through 7 summarize design and operating parameters
for the major components of the Cholla FGD system.
LIMESTONE MILLING FACILITIES
     Most of the ground limestone for the FGD system is supplied
by the Superior Company in Phoenix, Arizona.  The grade supplied,
known as "red wall" limestone, meets size specifications of at
least 75 percent by weight less than 200 mesh.  Chemical composi-
tion specifications call for a minimum calcium oxide content of
52.5 percent, a guaranteed minimum calcium carbonate content of
95 percent, and maximum magnesium carbonate and silica contents
of 0.5 and 1.0 percent.
     The finely ground limestone is stored in a silo on the plant
grounds, from which it is discharged at a rate of 9 kg/min (20
Ib/min) into a slurry preparation tank at the base of the silo.
The fresh limestone slurry is introduced into the FGD system
through the sulfur dioxide absorber recirculation tank.
     Arizona Public Service is in the process of installing a
limestone grinding facility on the plant grounds.  This facility
will be able to meet present (Unit 1)  and future (Unit 2} lime-
stone requirements.  It will consists of a ball mill capable of
grinding 0.6 cm (0.25 in.) limestone rock delivered to the plant
by rail to the specified size of 75 percent minus 200 mesh.
PROCESS CHEMISTRY:  PRINCIPAL REACTIONS
     The chemical reactions involved in the Cholla wet limestone
scrubbing process are highly complex.   Although details are
beyond the scope of this discussion, the principal chemical
mechanisms are described below.
     The first and most important step in the wet-phase absorp-
tion of sulfur dioxide from the flue gas stream is diffusion from
                               14

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     Table 3.  DATA SUMMARY:  PARTICULATE AND SO2 SCRUBBERS
                            Flooded-disc
                              scrubber
                         SO_ absorber
                             tower
L/G ratio, liters/m
 (gallons/1000 acf)

Superficial gas
 velocity, m/sec  (ft/sec)
   1.35  (10.1)
Equipment sizes


Equipment internals
1.8 m (6 ft) dia. x
   13.7 m (45 ft)

Adjustable disc
   6.5 (48.9)
                         2.1   (6.9)
6.7 m (22 ft)  dia.  x
 21.3 (70 ft)

0.6 m (2 ft) fixed
   matrix packing
         Table 4.  DATA SUMMARY:  FGD  SYSTEM HOLD TANKS

Total number of
tanks
Tank sizes
Retention tine at
full load
Temperature
PH
Solids concentra-
tion, percent
Specific gravity
Flooded disc
scrubber
holdup tank
One
3.8 ra (12.5 ft)
dia. x 4.3 m (14 ft)
7 min
49°C (121°F)
5.2
15.5
1.102
SO, absorber
towers
holdup tank
One (common)
8.3 ra (27.3 ft)
dia. x 8.5 m (28 ft)
5 min
49°C (121°F)
6.5
8.3
1.049
FGD system
sludge
holdup tank
Two
5.6 m (18.5 ft)
dia. x 8.2 m (27 ft)
14 hr
49«C (121'F)
5.2
25

Limestone
slurry
makeup tank
Two


32°C (90°F)

20

                                15

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      Table 5.  DATA SUMMARY:  FGD SYSTEM MIST ELIMINATORS
Number

Materials of construction

Type


Number of stages

Passes/stage


Distance between stages

Vane spacing


Distance between last absorber
 stage and mist eliminator

Wash system:

  Water

  Frequency


  Pressure

  Capacity
Two

Polypropylene

Chevron  (1st stage)
Special design  (2nd stage)

Two

Two (1st stage)
Four (2nd stage)

1.2 m (4 ft)

3.8 cm (1.5 in.)  (1st stage)
18.1 cm  (7.1 in.)  (2nd stage)


3.7 to 4.6 m (12 to 15 ft)
Plant well

Intermittent  (45 seconds every
30 min per quadrant)

520 kPa  (60 psig)

15 liters/sec  (240 gpm)
                               16

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          Table 6.  DATA SUMMARY:  FGD SYSTEM REHEATERS
Number

Type

Heating medium

Number of tubes per exchanger

Tube size, outside diameter

Material of construction

Heating medium characteristics:

  Source

  Pressure

  Temperature

  Consumption

Rating

Soot blowers:

  Medium

  Number

  Frequency

Energy requirement, percent of
 unit output
Two

Shell-and-tube

Steam

Two

2.5 cm (1.0 in.)

316L stainless steel



Boiler steam drum

1.8 MPa (250 psig)

Saturated

9,100 kg/hr (20,000 Ib/hr)

84 GJ/hr (8 million Btu/hr)



Steam

Six

5 min/8-hr period
                                17

-------
      Table 7.  TYPICAL PRESSURE DROP ACROSS




COMPONENTS OF PARTICULATE SCRUBBER AND PACKED TOWER

Flooded-disc scrubber
Sulfur dioxide absorber
Mist eliminator
Reheater
Ductwork
Total
Pressure drop,
kPa (in. H2O)
2.5 (10.0)
0.1 (0.5)
0.1 (0.5)
0.5 (2.0)
1.3 (5.0)
4.5 (18.0)
                        18

-------
the gas to the liquid phase.  Sulfur dioxide  is  an  acidic anhy-
dride that reacts readily to  form  an acidic species in the pre-
sence of water
          S02 J —>• S02(aq.)
          SO2(aq.) + H2O —*• H-SO^
In addition, some sulfur trioxide is  formed  from further  oxida-
tion of the sulfur dioxide in the flue  gas stream.
                   1-+- 2SO.
                          '3
Because conditions are thermodynamically  (but  not  kinetically)
favorable, only small amounts of  sulfur trioxide are  formed.
This species, like sulfur dioxide,  is  an  acidic anhydride that
reacts readily to form an acid  in the  presence of  water
     so3
     SO  (aq.) + H,0  -^-*- H-SO.
       .3         ^       A   TI
     The sulfurous and sulfuric acid compounds are polyprotic
species; the sulfurous species  is weak and the sulfuric  species
is strong.  Their dissociation  into ionic species  occurs as  fol-
lows:
     HSO3
               H+ + HS03
               H+ + HS04
     HS04" ±=^ H+ + S04
     Analogous to the oxidation of  sulfur dioxide to  form  sulfur
trioxide, oxidation of sulfite ion  by dissolved oxygen in
the scrubbing slurry is limited.
    ' 2S03= + 02(aq.) ^ 2S04=
                               19

-------
     The limestone absorbent, which is a minimum of 95 percent
calcium carbonate by weight, enters the scrubbing system as a
slurry with wate*.  It is insoluble in water, and solubility
                                                n
increases only slightly as the temperature increases.  When
introduced into the scrubbing system, the slurry dissolves and
ionizes into an acidic aqueous medium, yielding the ionic pro-
ducts of calcium, carbonate, bicarbonate, and hydrogen.
     CaCO,   — >• CaCO- (ag. )
     CaCO3(aq.)  ^ Ca++
     Ca++ + H+ + CO3= ^v CaHCO3+
     CaHC03+ ^ Ca++ + HC03~
     The chemical absorption of sulfur dioxide occurs in the
venturi scrubber and spray tower and is completed in the external
recirculation tank.  The reaction products precipitate as calcium
salts and the scrubbing solution is recycled.  The following are
the principal reaction mechanisms for product formation and pre-
cipitation.
Ca +
CaS03
_ ++
Ca +
CaSO,
SO3 — >- CaSO-
+ 1/2H2O ^CaSi
S04~ ^ CaS04
+ 2H-O — *- CaSO
The hydrated calcium sulfite and calcium sulfate reaction pro-
ducts, along with the collected fly ash and unreacted limestone,
are transferred to the disposal pond.  The supernatant is re-
cycled to the process.

PROCESS CONTROL

     The chemistry of the PGD system is maintained by controlling
two important parameters of the scrubbing solution, the pH and
solids concentration levels.  The pH is monitored manually by
sampling the scrubbing solution in the tower recirculation tank

                               20

-------
once per shift.  The solids concentration in the scrubbing loop
is controlled by the use of nuclear density meters in the FGD
recirculation tank.
     The scrubbing solution pH is maintained at a minimum value
of 5.0.  Control at this level prevents major pH changes in the
scrubber, which may change salt saturation levels and cause
solids deposition and scale formation on the scrubber internals.
The quantity of limestone used in this pH range is approximately
110 percent stoichiometric, resulting in a limestone utilization
rate of 90 percent and a sulfur dioxide removal efficiency of
approximately 90 percent in the Module A absorber.
     The desired solids concentration level in the scrubber
circulation loop is 8 to 15 percent.  The solids are composed
primarily of fly ash, calcium sulfite, calcium sulfate, and cal-
cium carbonate.
     Flue gas loadings and sulfur dioxide concentrations are also
monitored and controlled in the scrubbing system.  The flue gas
that flows into the scrubbing trains is controlled using motor
amperage monitoring to balance the ID fans.  The measurement of
the mass flow of the sulfur dioxide into the scrubbing system is
performed by two continuous sulfur dioxide monitors.
     The FGD system instrumentation is housed in two separate
areas.  Most of the recording instruments are mounted on a panel
in a building housing electrical switch gear, adjacent to the FGD
structure.  The remaining instruments, primarily for remote
control of process operations, are housed in the main boiler con-
trol room and are monitored by the boiler control operator.
                               21

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                            SECTION 4
                     FGD SYSTEM PERFORMANCE

PERFORMANCE TEST RUN
     Initial testing of the FGD system began on October 2, 1973,
as most of the construction had been completed by that time.  The
system was operated until a scheduled shutdown on October 21.
This 3-week test period was used to determine particulate and
sulfur dioxide removal efficiencies, mist carryover from the
towers, maximum process gas flow rates, and the amount of bypass
gas leakage.
     Module A, which has the packed tower, achieved a sulfur
dioxide removal efficiency of 92 percent with average inlet and
outlet sulfur dioxide concentrations of 417 and 34 ppm.  Arizona
Public Service estimates that Module B, which has an empty tower,
is capable of removing 25 percent of the inlet sulfur dioxide.
Therefore, the combined sulfur dioxide removal efficiency for the
two modules was determined to be 58.5 percent [(92 + 25)/2].
     No mist carryover from the scrubbing trains was detectable.
Solids carryover in Module A were analyzed for calcium ion and
showed an average of 0.177 g/m^ (0.05 gr/scf).  The appearance of
the mist eliminators at the end of the test period, together with
the carryover tests, indicated very little entrainment of slurry.
Pressure drop buildup across the mist eliminator was less than
0.2 kPa  (0.7 in. H2O).
     The maximum average inlet gas rates during the 3-week opera-
tion were 101 m^/sec  (214,300 acfm) to Module A and 97 m3/sec
(204,600 acfm) to Module B.  Air leakage into the system was 9
m3/sec  (18,400 acfm) downstream of the flooded-disc scrubbers.
     Chloride ion concentrations were 1600 ppm in the flooded-
disc scrubber recirculation and 575 ppm and in the tower slur-

                              22

-------
ries.  These levels are sufficient to cause pitting corrosion  in

localized areas when temperatures are greater than 60°C  (140°F)

and pH is less than 3.0.  The chloride content of the coal ranged

between 0.01 and 0.04 percent  (equivalent to 8 to 32 ppm by

weight in the flue gas).  The chloride ion concentration was 933

ppm in the boiler water blowdown, which is used as makeup water

to the FGD unit.  The chloride ion concentration was 144 ppm in

the well water, which is used for boiler makeup water and FGD
fresh water makeup.

     Table 8 presents detailed information and data gathered dur-
ing the preliminary performance test run.

OPERATION HISTORY:  PROBLEMS AND SOLUTIONS

     Start-up and operation of the Choila FGD system have been

accompanied by many problems.  An analysis of these problems

reveals that most were related to process design rather than

process chemistry.  The utility operators and the FGD system

designer have conceived and implemented solutions to many of

these problems.  The major problems and solutions are discussed

in the following paragraphs.
     0    Scale accumulated on top of and inside the cavity of
          the shaft's stuffing box in the flooded-disc scrubber.
          These scale deposits were discovered early enough to
          prevent binding of the shaft.  Modifying the assembly
          of the stuffing box and reinstalling it in an inverted
          position (the cavity at the bottom so it cannot accumu-
          late solids) delayed binding.  Eventually, however, the
          shaft did freeze and had to be cleaned out.  Other
          minor scale accumulations on top of the shaft dome and
          around the tangential nozzles of the flooded-disc
          scrubber did not obstruct the flow of limestone slurry
          or flue gas through the scrubber.

     0    Dilute sulfurous acid condensate caused corrosion in
          the expansion joints above the reheaters of both FGD
          modules and on the top row of tubes near the tube sheet
          on Module B.  This corrosion was caused by the accumu-
          lation of dilute sulfurous acid condensate in stagnant
          pockets in the reheater and ductwork.  To prevent
          recurrence of this corrosion problem, the carbon steel
          ductwork upstream of the reheaters in the Modules A
          and B was insulated with a flake-glass liner (Ceilcote)
                               23

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to
*»
                   Table 8.  RESULTS OF FGD SYSTEM  PERFORMANCE TEST RUNS,


                                    OCTOBER 2 to  21,  1973

Participate concentration inlet,
g/m3 (gr/scf d)
Particulate concentration outlet,
gr/scfd
S02 concentration outlet, ppm
S02 concentration inlet
Configuration
2 removal, percent
Particulate removal efficiency, percent
Gas inlet to PDS, m3/sec -(acfm)
Theoretical inlet gas to fOS, m /sec (acfm)
Apparent bypass leakage, m /sec (acfm)
FDS L/G ratio, liters/m3 (gal./lOOO acf)
Tower L/G ratio, liters/m3 (gal./lOOO acf)
Gas velocity through tower, m/sec (ft/sec)
Hist entrainment from tower, g/m (gr/scf )
Solids entrainment from tower slurry,
g/m3 (gr/scf)
Pressure drop FOS, kPa (in. H2Q)
Pressure drop tower demisters, kPa (in. H2O)
Pressure drop reheater, kPa (in. HjO)
NA -.Not applicable.
A-side
4.569 (1.99S)
0.0190 (0.0083)
34
417
Packed
92.4
99.7
16.9 (214,300)
(198,800)

1.35 (10.1)
6.5 (48.9)
2.10 (6.9)
0.000
0.011 (0.005)
3.7 (14.8)
0.0
1.3 (5.15)
B-side
5.810 (2.537)
0.0231 (0.0101)
357
409
Hollow
14.4
99.8
96.6 (204,600)
93.8 (198,800)
7.98 ( 16,900)
1.42 (10.6)

2.05 (6.6)
0.000
NA
3.9 (15.7)
0.0
0.6 (2.30)
Stack

0.2631 (0.1149)
236

B-side hollow
9.2
99.7
96.4 (204,300)


0.78 (5.8)

2.35 (7.7)
NA
NA
3.4 (13.5)


                (Continued)

-------
                                    Table  8.   (continued)
to
Ul

Temperature tower outlet °C ("Fl
AT reheafcer °C <«F)
Miat eliminator wash water rate,
litera/aec (gpm)
Blurry flow to PDS, -litera/aec (gpm)
Blurry flow from FOB, liters/sec (gpra)
Limestone feed rate, kg/rain (Ib/min)
Blurry flow from tower tank to FDS tank,
liter a/a (gpm)
Blurry flow from PDS tank to eludge holdup
tank, litera/aeo (gpm)
fewer tank makeup water, litera/aeo (gpra)
FOB tank makeup water, liters/sec (gpm)
Specific gravity (percent solids tower tank)
Speoifie gravity (percent solids FOB tank)
Percent aolida PDS tank
Tower tank pH
FDS tank pH
Coal consumption, mg/hr (tona/ht)
Coal heating value, MJ/kg (Btu/lb)
Atmospheric) pressure, kPa (in. Hg)
A-side
49 (121)
36 (65)
0.8 (12.5)
137 (2170)
83 (1317)













B-aide
with
packing
49 (121)
33 (60)
0.9 (14.0)
137 (2177)
94 (I486)
7.5 (16.6)
2.1 (32.5)
4.0 (64.0)
0
NA
1.049 (8.3)
1.102 (14.8)
IS. 5
6.5
5.2
49 (54)
23.9 (10,293)
65.4 (25.3)
B-side
without
packing
49 (121)
33 (60)
0.8 (14.0)
88 (1100)
NA














-------
and the Corten steel expansion joints were replaced
with rubber expansion joints.  The corroded tube bundle
was replaced, and to prevent acid condensate from
reaching the new tubes, a trough was installed to
divert any condensate away from the tube bundles.  It
is important to note that corrosion of the reheater by
sulfurous acid occurred only in Module B  (the module
without packing), which has a low sulfur dioxide re-
moval efficiency.  Presumably, the higher sulfur dioxide
removal efficiency of Module A (the packed tower)
prevents significant formation of sulfurous acid con-
densation.

Evidence of chloride attack was noted in the liquid-gas
centrifugal separator shell below the absorber.  To
remedy this problem, R-C coated the interior of the
vessel with an epoxy material, which later eroded in
spots and had to be repaired.  The epoxy material also
eroded and disbonded below the scrubber disc.  Acid
resistant brick was installed in this lower section of
the absorber and has held up for more than six months.

Evidence of additional chloride attack has been noted
on Module B reheater tubes, probably as a result of the
chlorides that are introduced in the well water used to
prepare makeup slurry.  Table 9 presents the results of
a March 1976 chemical analysis of the well water.  The
spray distribution deflector above the flooded disc
failed because of stress-corrosion cracking.  The
deflector was redesigned by R-C,  and the new design is
holding up.

Recently extensive corrosion has occurred in the duct-
work leading from the Module B absorber tower exhaust
elbow to the reheat tube bundle.   The utility has
recoated the elbow several times with a Ceilcote liner.
An application problem caused repeated failure of the
liner.  This problem has still not been fully resolved.

Harmonic vibrations with deflections of as much as 0.1
cm (0.040 in.) occurred in the reheaters.  The vibra-
tions were attributed to the vortex effect of an
inadequate transition of duct size from the absorber
outlet to the reheater shell.  To remedy the situation,
cross baffles were installed at the reheater entrance.
Vibrations also occurred in the Module B booster fan as
a result of uneven scale buildup on the fan blades when
the unit was idle.  The blades were sandblasted,
cleaned, and rebalanced to eliminate these vibrations.
                     26

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     0    Sediment built up several times in dead spaces in
          pipelines and valves of idle pumps and also in process
          lines.  This occured when slurry velocities in the pipe
          were low  (during periods of reduced operating rate).
          This problem was resolved by redesigning some pipes to
          eliminate potential dead pockets.  To prevent valve
          freezing due to sediment buildup, some valves were
          repositioned and flush-out lines were installed.
     0    Some pipe liners eroded  (e.g., in the absorber tower
          pump inlet piping).  The erosion was sometimes caused
          by unsatisfactory liner materials and sometimes by high
          flow velocities through pipes and fittings.  The rubber
          lining in some pipes cracked, primarily because of
          defects in fabrication.  Piping modifications helped to
          reduce the erosion problem.
     Burning a lower grade of coal  (22 percent ash and 0.7 percent
sulfur) in the boiler has been accompanied by some plugging in
the mist eliminator and tower packing in Module A.  Arizona
Public Service has not yet verified whether or not this plugging
is related to the lower grade of coal.  If this buildup of mater-
ial continues, it appears that the life span of the packing and
the mist eliminator may be reduced as much as 50 percent.
     The FGD system is capable of accommodating the boiler down
to a 50-MW load level without the system's operation being
seriously affected or major problems being encountered.  Constant
flow is maintained in the liquid circuit to prevent solids depo-
sition in the pipelines.  A turndown below 50 MW, however,
requires that liquid flow be modulated accordingly, and increases
the probability_of solids accumulating in the pipelines as a
result of the reduced liquid flow velocity.
     A number of additional minor problems, typical of FGD opera-
tions, have been encountered and resolved by normal maintenance
and engineering practices.  Among these are pump failures; vessel
lining failures  (requiring recoating); malfunction of solenoid
valves in mist eliminator wash system, preventing adequate
washing; reheater steam leaks; gas damper adjustments; localized
corrosion, erosion, and scaling; liquid leaks in tanks, valves,
and pipelines; and expansion joint failures.

                               27

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Table 9.  CHEMICAL ANALYSIS OF CHOLLA SERVICE WATER
Component
Calcium ion
Magnesium ion
Bicarbonate ion
Sulfate ion
Chloride ion
Sodium ion
Total dissolved solids
PH
Temperature, °C (°F)
Concentration, ppm
Well No. 1 Well No. 2
126.4
40.0
219.6
132.0
147.0
0
665.0
7.55
18(65)
120.0
34.2
202.5
68.0
127.0
0
551.7
7.50
18(65)
                        28

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     Table 10 summarizes the perforraace of the FGD system since
start-up.
DESIGN AND OPERATION MODIFICATIONS
     From start-up to the present, FGD operating procedures have
been modified somewhat.  The most important changes have occurred
in the process control area.  The continuous pH sensors were
eliminated and manual wet techniques were adopted on a once-per-
shift basis.  The original density meters were replaced with
nuclear units.  The utility has adopted the practice of water
purging of plugged sensing lines.  The mist eliminator wash
system, originally designed to spray each quadrant with service
water for 12 seconds every 8 minutes, has been changed to spray
each quadrant 45 seconds every 30 minutes.
     The only major change in the scrubbing system's design that
will be incorporated into the Cholla No. 2 scrubbing system, is
the use of Inconel 625 in the fabrication of the reheater tubes
(316L stainless steel used in Cholla 1).
ECONOMICS
     In 1973 dollars, the Cholla 1 FGD system cost APS approxi-
mately $6.5 million  (or $57/net kW).  This figure does not
include the cost of such items as limestone storage and milling
facilities and sludge disposal  {a pre-existing ash pond is
used).  The figure also does not include additional costs in-
curred by the system supplier.
     Cost of the ground limestone is $19.20 to $23.50 per ton,
delivered.   (Transportation costs included in these figures are
$7.07 'to $15.58 per ton, or 37 to 66 percent of the delivered
cost.)
     The annual cost of the system is estimated to be 2.2 mills/
kWh.  This figure includes a 23 percent charge on capital in-
vestment to account for interest, depreciation, taxes, and other
fixed charges.  The 1975 and 1976 annual costs of maintenance,
including labor and materials, were $183,871 and $216,024.
Arizona Public Service believes these maintenance costs are high,
                               29

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                        Table 10.  PERFORMANCE DATA FOR CHOLLA FGD


                          SYSTEM:  OCTOBER  1973  TO DECEMBER 1977


Period
Oct.


Nov.
Dec.

Jan.
Feb.
Mar.
Apr.




Hay
June
July
Aug.
sept
Oct.
Nov.
Dec.
1974
Jan.
Feb.
73


73
73

74
74
74
74




74
74
74
74
. 74
74
74
74
Avg.
75
75
Reliability, percent
Module A
Module B
System avg.
Initial operation and testing


initial operation and testing
Commercial operation

97
100
100
66




98
100
97
97
95
83
100
100
94
98
96

90
94
66
57




99
100
92
97
99
68
98
100
88
99
99

94
97
83
62




98
100
97
97
97
76
99
10T)
91
98
98
Comments
Initial operation and testing of the system
and continued for 3 weeks. Particulate and
encies, mist carryover, gas flows, and gas

The construction and initial testing of the
December 3 . Commercial operation began on



System performance from December 15, 1973,
started on October 2, 1973,
sulfur dioxide removal effici-
leakage rates wore determined.

system were completed on
December 14 .



to April 15, 1974, was satis-
factory. The scrubbing trains were shut down intermittently for replace-
ment of corroded Corten steel expansion joints on the reheater bundles .
Module B was out of service from April 15 to 28; Module A was out from
April 17 to 27.











The system was shut down for an annual boiler and FGD system overhaul.










10
o
       (Continued)

-------
                                  Table  10.   (continued)
Period
Har. 75
Apr. 75
Hay 75
June 75
July 75
Aug. 75
Sept. 75
Oct. 75
Nov. 75
Dec. 75
1975 Avg.
Jan. 76
Feb. 76
Har. 76
Apr. 76
May 76
June 76
Reliability, percent
Module A

88
48
100
97
95
98
84
100
100
91
99


99
76
64
Module B

65
40
100
98
100
97
55
80
100
85
99


98
100
39
System avg.

76
44
100
98
98
98
70
90
100
88
99


98
88
52
Comments


Both nodules were out of service most of the month for scheduled repairs
and cleaning.
A substantial amount of plugging was observed in the Module A absorber
tower packing. Some plugging was also noted in the mist eliminators.
One forced FGD system outage resulted from flow restrictions in the FDS
reciroulation lines because they needed to be cleaned out.

Problems recurred with FDS recirculation lines, requiring additional
cleanouts .
Overhauling of FGD equipment and recoating of vessels accounted for most
of the scrubber outage time.

Minor problems encountered during this period included recycle pump
failure and malfunctioning of the Module B reheater coil.

Module A was in service 715 hours, Module B, 654 hours. Some minor
valve and plugging was encountered during the period.


The FGD system experienced coating failures in the elbow of the
exhaust duct leading to the stack.
During the month Module A experienced corrosion problems in the
reheater tubes. The FDS recirculation lines continued to plug up.
The utility shut down the FGD system for inspection, maintenance,
and repairs.
Ul
        (Continued)

-------
                                    Table 10.  (continued)
Period
July 76
Aug. 76
Sept. 76
Oct. 76
Nov. 76
Dec. 76
1976 Avg.
Jan, 77
Feb. 77
Mar. 77
Apr. 77
Hay 77
June 77
Reliability, percent
Module A
100
100
100
56
96
98
89
72
99
72
100
87
100
Module B
98
100
100
56
98
100
89
93
99
93
100
87
100
System avg.
99
100
100
56
97
99
89
83
99
83
100
87
100
Comments
The utility completed repairs to the coating in the elbow scrubber
exhaust duct.

The boiler was in service the entire month. Module A and Module B
service times were 720 and 679 hours.
Boiler, Module A, and Module B service times were 417, 415, and 277
hours respectively.
Boiler, Module A, and Module B service times were 720, 682, and 556
hours, respectively. Minor outages were caused by a reheater steam leak
and inlet gas damper adjustments.
Boiler, Module A, and Module B service times were 744, 742, and 498
hours, respectively. Additional adjustments were made to the Module A
inlet gas dampers.

Boiler, Module A, and Module B service times were 744, 532, and 684
hours, respectively.
Boiler, Module A, and Module B service times were 672, 648, and 591
hours, respectively. The Hunters packing in the Module A absorber was
replaced. Minor problems included module vessel plugging, corrosion,
liquid piping and gas by-pass dampers.
Boiler, Module A, and Module B service times were 744, 532, and 684
hours, respectively.
Boiler, Module A, and Module B service times were 638, 635, and 629
hours, respectively.
Boiler, Module A, and Nodule B service times were 645, 645, and 645
hours, respectively. The unit was shut down by APS for mid-year
inspection, overhaul, and repairs. R-C Initiated a forced oxidation
teat program on the system by forcing air into the FDS scrubber tank
and converting all the sulfite to sulfate.
Boiler, Module A, and Module B service times were 720 hours.
to
NJ
        (Continued)

-------
                                   Table 10.   (continued)
U)
U)
Period
July 77
Aug. 77
Sept. 77
Oct. 77
Nov. 77
Dec. 77
1977 Avg.
Reliability, percent
Module A
97 '
97
100
100
100
97
93
Module B
99
99
100
100
96
91
97
System avg.
98
98
100
100
99
94
95
Comments
Boiler, Module A, and Module B service times were 744, 724, and 734
hours, respectively. Leaks were encountered in the limestone slurry
tank and the Module B return line. R-C continued forced oxidation
testing .
Boiler, Module A, and Module B service times were 744, 723, and 734
hours, respectively.
Boiler, Module A, and Module B service times were 720, 718, and 716
hours, respectively. Problems with leaks in the limestone slurry tank
and return line to the FDS tank continued to plague the system.
Boiler, Module A, and Module B service times were 744, 743, and 743
hours, respectively.
Boiler, Module A, and Module B service times were 169, 169, and 142
hours, respectively. Boiler was overhauled during the last half of the
month. Minor problems with FGD included venturi leaks and a pump
expansion joint failure.



-------
and they also believe that the high removal efficiencies and
reliabilities listed in the report are the result of considerable
financial investment on their part.
                              34

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                            APPENDIX A
                        PLANT SURVEY FORM

A.   Company and Plant Information
     1.   Company name:   Arizona Public Service Co.  (APS)
     2.   Main office;  Phoenix, Arizona	
     3.   Plant name;   Cholla Steam Electric Station
     4.   Plant location;  Joseph City. Arizona	
     5.   Responsible officer;    L. K. Mundth	
     6.   Plant manager:  Cleo Walker
     7.   Plant contact;  Aubrv Parsons
     8.   Position;    Assistant Plant Manager
     9.   Telephone number;    (602) 288-3357
    10.   Date information gathered:	April 8, 1976
     Participants in meeting                 Affiliation
      Aubrv Parsons	   	APS	
      Milton Johnson	   	APS
      H.  A. Ohlgren	   	PEDCo Environmental
      G. 'A. Isaacs	   	PEDCo Environmental
      B.  A. Laseke	   	PEDCo Environmental

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B.   Plant and Site Data
     1.   UTM coordinates:
                  T
     2.   Sea Level elevation: 	Sea level
     3.   Plant site plot plant  (Yes, No) :^	
          (include drawing or aerial overviews)
     4.   FGD system plan (yes. No):	yes
     5.   General description of plant environs;   Flat and	
           arid desert region,  sparsely populated	
     6.   Coal shipment mode;  coal is shipped to the plant by
           rail from the Gallup, New Mexico, area [165 km (100
           miles)  east of the plant] and the window Rock, Arizona,
           area [145 km (88 miles)  northeast of the plant] .	
     FGD Vendor/Designer Background
     1.   Process name:   Limestone slurry	
     2.   Developer/licensor name;  Research-Cottrell, Inc.
     3.   Address:   Box 750. Bound Brook, New Jersey  08805

     4.   Company offering process:
          Company name:   Research-Cottrell. Inc.	
          Address:   P.O. Box 750	
                                 36

-------
          Location: Bound  Brook. NPW Jersey
          Company contact: James  E. McCarthy
          Position; Manager,  Sales  Development
          Telephone number;  201/885-7101
     5.   Architectural/engineers name: Ebasco.  Inc.



          Address:  2  Rector  Street
          Location: New York. N.Y.   10006
          Company contact:



          Position:
          Telephone number;  212/785-2200



D.   Boiler Data



     1.   Boiler:  1
     2.   Boiler manufacturer:  Combustion  Engineering



     3.   Boiler service  (base, standby, floating, peak):



          Base	








     4.   Year boiler placed in service: 1962	
     5.   Total hours operation; Approximately  100,000



     6.   Remaining life of unit: Approximately 16 years



     7.   Boiler type: Pulverized-coal-fired, wet-bottom



     8.   Served by stack no.:  1	
     9.   Stack height;  76 m  (250  ft)
    10.   Stack top inner diameter:



    11.   Unit ratings:	
          Gross unit rating:  124 MW
          Net unit rating without FGD:  119.5 MW
                                 37

-------
          Net unit rating with FGD; 114.3 MW

          Name plate rating:	
     12.   Unit heat, rate: 10,202 kJ/net kWh  (9670 Btu/net  kWh)

          Heat rate without FGD:	 	

          Heat rate with FGD:
     13.   Boiler capacity factor, (1974); 85%

     14.   Fuel type (coal or oil): Coal	

     15.   Flue gas flow:	
                        o
          Maximum: 227 m /sec (480,000 acfm)
          Temperature:  136°C (276°F)
     16.   Total excess air; 18 to 20%  (3% 02 in flue gas)

     17.   Boiler efficiency; 86%	

E.   Coal Data

     1.    Coal supplier:

          Name: McKinley Mine	
          Location:  Gallup, N.M., and Window Rock, Arizona	




          Mine location;  Gallup, N.M., and Window Rock, Arizona

          County,  State:  McKinley, N.M., and Apache, Arizona

          Seam:	

     2.    Gross heating value: 23.6 MJ/kq (10,150 Btu/lb)	

     3.    Ash (dry basis):  13.45 avg.	
     4.   Sulfur (dry basis): 0.52 avq.
     5.    Total moisture; 14.77 avq.
     6.   Chloride:  0.01 to 0.04
          Ash composition (See Table A-l)
                                 38

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         Table A-l.   ASH COMPOSITION OF COAL AT CHOLLA 1


         Elemental
        Constituents                      Percent by weight

       Iron                                     8.10

       Aluminum                                12.24

       Calcium                                  3.54

       Magnesium                                2.28

       Sodium                                   0.40

       Manganese                                0.021

       Copper                                   0.007

       Lead                                     0.001

       Nickel                                   0.001

       Chromium                                 0.007

       Zinc                                     0.010

       Barium                                   0.22



F.   Atmo-spheric Emission Regulations

     1.   Applicable particulate emission regulation

          a)   Current requirement:  84.27 ng/J (Q.196  lb/106  Btu)

               AQCR priority classification:	
                                            Arizona  State Dept.  of
               Regulation and section No.;  Health Regulation  No. 7-1-3.5

          b)   Future requirement  (Date:     ) :	

               Regulation and section No.:	
          Applicable S0_ emission regulation

          a)   Current requirement; 429.9 ng/J  (1.0 lb/10  Btu)

               AQCR Priority Classification:	
                                           Arizona State Dept. of
               Regulation and section No.: Health Regulation 7-1-4.2

          b)   Future requirement (Date:      )	
                                  39

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

     1.   Trade name:     Limestone
          Principal ingredient:	CaCO^ (95% minimum)

          Function:  Scrubbing agent	
          Source/manufacturer.:  Superior Co., Phoenix, Arizona

          Quantity employed:   110% of stoichiometric	

          Point of addition;   Absorber recirculation tank	

          Trade name:   NA
          Principal ingredient:

          Function:
          Source/manufacturer:

          Quantity employed:	

          Point of addition:	

          Trade name:     NA
          Principal ingredient:

          Function:
          Source/manufacturer:

          Quantity employed:	

          Point of addition:	

     4.   Trade name:     NA
          Principal ingredient:

          Function:
          Source/manufacturer:

          Quantity employed:	

        NA - Not applicable
                                 40

-------
          Point of addition:
     5.   Trade name;   r
          Principal ingredient:
          Function:
          Source/manufacturer:
          Quantity employed:	
          Point of addition:
H.   Equipment Specifications
     1.   Electrostatic precipitator (s)
          Number:
          Manufacturer:
          Particulate removal efficiency:
          Outlet temperature:	
          Pressure drop:	
     2.   Mechanical collector(s)
          Number:
          Type:  Multicvclones  (multitube dust  collectors)	
          Size:	
          Manufacturer;    Research-Cottrell	
          Particulate removal efficiency;    75 to 80%	
          Pressure drop:	
     3.   Particulate scrubber(s)
          Number:    Two	
          Type:	Flooded-disc venturi	_
          Manufacturer:    Research-Cottrell	
          Dimensions:      1.8 m $ x 13.7 m (6  ft  t> x 45  ft  high)
                                  41

-------
     Material, shell:	316L stainless steel	


     Material, shell lining; Ceilcote flakeglass  (lower portion)


     Material, internals; None	
               i1

     No. of modules:  One per module	


     No. of stages;  One	


     Nozzle type; See item No. 1, Section M - General Comments


     Nozzle size: See item No. 1, Section M - General Comments


     No. of nozzles;  See item No. 1, Section M - General Comments


     Boiler load:    100%	


     Scrubber gas flow: 113 m3/sec  (240, OOP, acfm) @ 136°C  (276-°F)


     Liquid recirculation rate: 137 liters/sec  (2170 gpm)


       Modulation:   50% turndown (50 MW)	


     L/G ratio: 1.35 liters/m3 (10.1 gal./lOOO acf)	


     Scrubber pressure drop:  2.5 kPa (10 in.  H?O)	

                   Flooded-disc controls throat opening
       Modulation: and pressure drop	


     Superficial gas velocity:	
     Particulate removal efficiency;  99.2%
       Inlet loading:   70.6 g/m3 (2.0 gr/scf)


       Outlet loading:	
     SO- removal efficiency:


       Inlet concentration:_


       Outlet concentration:
4.    SO, absorber(s)


     Number:   Two (Module A,  packed.  Module B. hollow)


     Type:  Packed tower absorber (Module A)	


     Manufacturer:   Re search-Cottrel1
                            42

-------
Dimensions :  6.7 m  $ x  21.3 m  (22  ft  $  x  70  ft)
Material, shell:   316L  stainless  steel"
Material, shell lining: None
Material, internals: Munters Packing



No. of modules;  Qne	



No. of stages:
              Corrugated sheets of polypropylene joined

Packing type; jn a fixed matrix, honeycomh



Packing thickness/stage;  p.g m  (2 ft\
Nozzle type:	Spinner vane



Nozzle size:
No. of nozzles:



Boiler load:
Absorber gas flow; 113 m3/sec  @  136°C  (240,000  acfm  @  276°F)



Liquid recirculation rate; 567 liters/sec  (9000 gpm)



  Modulation:   None	



L/G ratio: 6.5 liters/m3  (48.9 cral./lOOO acf)	



Absorber pressure drop:   Q.i kPa  fO.5 in. H~0)	
                                            £


  Modulation:   None	



Superficial gas velocity; 2.1 m/sec  (6.9 ft/sec)	



Particulate removal efficiency:	



  Inlet loading;    	_^_____
  Outlet loading:    0.353 a/m3  (0.010 ar/scf)	



SOI removal efficiency: 92%  (Module A); 25%  (Module B)



  Inlet concentration; 420 pom  (Module A); 420 ppm  (Module B)



  Outlet concentration: 35 ppm  (Module AJ; 315 ppm  (Module B)
                        43

-------
5.   Clear water tray(s)
     Number:    None	
     Type:	
                t
     Materials of construction:
     L/G ratio:	
     Source of water:
6.   Mist eliminator(s)
     Number:   Two, one per
     Type: Chevron  (1st  stage)7  special  design (2nd stage)
     Materials of construction; Polypropylene (T-271 and T-41)
     Manufacturer:  Munters	
     Configuration  (horizontal/vertical):   Horizontal	
     Distance between scrubber bed and mist eliminator:	
     3.7 to 4.6 m  (12 to 15  ft)	
     Mist eliminator depth:  Q.3  m  (1.0 ft)  per stage	
                  First  stage  3.8  cm  (1.5  in.);
     Vane spacing; second stage 18.1 cm  (7.1 in.)	
     Vane angles:  45 degree	
     Type and location of wash system; .intermittent  over spray.
     15 liters/sec  (240 pgm);  45 sec every  30 min/guadrant
     Superficial gas velocity; 0.1 kPa  (0.5 in.  H?0)	
     Pressure drop:	
     Comments: Two  stages per  mist eliminator;  two  passes in
     first stage, four passes  in second  stage.   1.2 m (4 ft)
     between  stages.	
7.    Reheater(s):    TWO	
     Type (check appropriate category):	
                            44

-------
     [X]   in-line  (she11-and-tube  heat  exchanger,  two bundles
                   per  exchanger;  316L  SS  construction)
     [j   indirect hot  air
     (~)   direct combustion
     Q   bypass
     Q   exit gas recirculation
     Q   waste heat recovery
     D   other
     Gas conditions for reheat:
       Flow rate;   231 m /sec  (490,000  acfm)	
       Temperature: 50°C  (122°F)	
       SO2 concentration:  35 ppm  (Module A);  330 ppm (Module B)
     Heating medium:  Saturated steam	
     Combustion fuel: NA
     Percent of gas bypassed for reheat:  NA
     Temperature boost  (AT):   22°C  (40°F)
     Energy required:	2%	
     Comments ; Saturated  gteam extracted  from boiler  steam
     dyum at a  ressure  of  1.8 MPa  (250   si) ;  consumtion
     rate  is  9000  kg/min  (20.000  Ib/hr^; rating is 84 GJ/hr
      (8 x  106 Btu/hr) .
8.    Fan (s) Four: two  induced-draft boiler fans  and two
           forced-draft FGD  booster  fans
     Type : Forced-draft paddle wheel (FGD  booster fans) _
     Materials of construction:    Mild  steel ___
     Manufacturers  Westinghouse
     Legation:  Upstream of FGD,  suction  side of boiler  ID  fan s
     Fan/motor speed:	
     Motor/brake power:	
                            45

-------
9.
Variable speed drive:



Tank(s)

Total number of
tanks
Tank sizes

Retiontion time at
full load
Temperature
PH
Solids concentra-
tion, percent
Specific gravity
Flooded-disc
scrubber
holdup
tank

one
3.8 ra (12 ft) dia.
X4.3 m (14 ft)

7 min
49 °C (121 °F)
S.2

15.5
1.102
SO. absorber
towers
holdup
tank

one (common)
8.3 m (27 ft) dia.
xB.5 m (28 ft)

5 min
49°C (121"P)
6.5

8.3
1.049
FGD system
sludge
holdup
tank

two
5.6 m (18 ft) dia.
x (27 ft) 8.2 m

14 hr each
49°C (121CP)
5.2

25

Limestone
slurry
makeup
tank

one




32"C (90°P)


20

10.  Recirculation/slurry pump(s)
Number
3
3
Description
FDS recirculation
Absorber
recirculation
Manufacturer
Gould
Gould
Capacity .
liters/sec (gpm)
168 (2670)
587 (9300)
Materials
Rubber-lined
Rubber-lined
Service
Two operational/
one spare
Two operational/
one spare
11,
Thickener(s)/clarifier(s) NA



Number: None	



Type:	
     Manufacturer:
     Materials of construction:



     Configuration:	



     Diameter:	



     Depth:	
     Rake speed:
12.  Vacuum filter(s)  NA
                           46

-------
     Number:
     Type:
     Manufacturer:
     Materials of construction:
     Belt cloth material:	
     Design capacity:_	
     Filter area:
13.  Centrifuge(s)  NA
     Number:  None
     Type:	
     Manufacturer:
     Materials of construction:
     Size/dimensions:	
     Capacity:	
14.  Interim sludge pond(s)
     Number: One  (pre-existing  fly  ash  disposal pond)
     Description: Solar evaporation and fly ash disposal pond
     Area:  283,281 to 404>687 m2  (70 to 100 acres)	
     Depth: 1.8 m (6 ft) maximum	
     Liner type;  Unlined	
     Location: On plant site	
     Typical operating schedule;  Continuous discharge with no
     recurculation to FGD because of high evaporation rate
     Ground water/surface water monitors: NA	
15.  Final disposal site(s) : Pre-existing fly ash disposal pond
                           47

-------
     Number:  NA
     Description:

     Area:
     Depth:
     Location:
     Transportation mode:
     Typical operating schedule:
16.  Raw materials production: See item No. 2, Section M
                               General Comments
     Type:  None	
     Number:
     Manufacturer:

     Capacity:	
     Product characteristics: Delivered 75% < 200 mesh
Equipment Operation, Maintenance, and Overhaul Schedule

1.   Scrubber (s)

     Design life:	

     Elapsed operation time:	

     Cleanout method:
     Cleanout frequency: Scheduled every 6 months

     Cleanout duration:
     Other preventive maintenance procedures: Complete with

     each system shutdown	

2.   Absorber(s)
                            48

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

     Cleanout method:
     Cleanout frequency: Same as scrubbers

     Cleanout duration:
     Other preventive maintenance procedures:

      Same as scrubbers	

3.    Reheater(s)

     Design life:   	
     Elapsed operation time:	
                     Six steam-operated soot blowers run for
     Cleanout method;5 roin  each 8-hour shift.	

     Cleanout frequency:	

     Cleanout duration:
     Other preventive maintenance procedures:
4.   Scrubber fan(s)

     Design life:	
     Elapsed operation time:

     Cleanout method:
     Cleanout frequency: scheduled every 6 months

     Cleanout duration:	
     Other preventive maintenance procedures:
5.   Mist eliminator(s)

     Design life:	
     Elapsed operation time:
                            49

-------
     Cleanout method:
     Cleanout frequency; Every 30 minutes
     Cleanout duration;  45  seconds,  15  liters/sec (240 gpm)
     Other preventive maintenance procedures:	
6.   Pump(s)
   .  Design life:
     Elapsed operation time:
     Cleanout method:
     Cleanout frequency!  Scheduled every 6  months
     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
     Elapsed operation time:
     Capacity consumed:	
     Remaining capacity:
                            50

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          Cleanout procedures:
J.   Cost Data

     1.   Total installed capital cost;  $6.5 million ($57/kW)a
     2.   Annualized operating cost;  2.2 mills/kwhb	
     3.   Cost analysis  (see breakdown:  Table A2)
     4.   Unit costs

          a.   Electricity;  p. 2 itiills/kWh (including steam)
          b.   Water:	

          c.   Steam:  0.2 mills/kWh (including electricity)
          d.   Fuel  (reheating/FGD process);    NA	
          e.   Fixation  cost:     NA
          f.   Raw material;  0.15 mills/kWh  (limestone)0
          g.   Labor:	
     5.   Comments
           a
            Capital cost figure given in 1973 dollars.  Additional
            capital cost expenditures by APS and R-C not included.
            Includes a 23% charge for capitalization to account for
            interest, depreciation, taxes, and other fixed charges.
            Annual 1975 and 1976 maintenance costs, including labor
            and materials, were $183,871 and $216,024.	
           CCost of limestone is $19.20 to $23.50 per ton.   This
            includes a transportation cost of $7.07 to $15.58 per

            ton.	.	
                                 51

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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. Annual ized Operating
Cost
Fixed Costs
Interest on capital
Depreciation
Insurance and taxes
Labor cost including
overhead
Variable costs
Raw material
Utilities
Maintenance
Included in
cost estimate
Yes
CZH
cm
Cm
Cm
CZD
No
dD
cu
CUD
cm
cm
a
cm
cm
cm
CZZI
cm
cm
cm
Estimated amount
or % of total
capital cost









23 percenl;
23 percent
23 percent

S19.20 - S23.5/tpn limestone
0.2 mills/kWh
5183,871 (1975), $216,024
	 U976)
          52

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K.   Instrumentation

     A brief description of the control mechanism or method of
     measurement for each of the following process parameters:
          Reagent addition:
          Liquor solids content:
          Liquor dissolved solids content:
     0    Liquor ion concentrations

            Chloride:
            Calcium:
            Magnesium:
            Sodium:
            Sulfite:
            Sulfate:
            Carbonate:
            Other (specify):.
                                 53

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          Liquor alkalinity:  See  remarks
          Liquor pH; See  remarks
          Liquor flow; See  remarks
     0    Pollutant (SO-, particulate, NO )  concentration in
                       **                 X

          flue gas: See  remarks	




     0    Gas flow; See  remarks	



     0    Waste water See remarks	




     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:  A thorough description of the instrumentation/ con-

      trol  loop is  provided under Process Description in Section 3

      of  the report.	  	
L.   Discussion of Major Problem Areas:

     1.   Corrosion:  See Operation Problems  and Solutions  in

          Section  4  of the report.	         	
                                   54

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2.   Erosion: See Operation Problems and Solutions in Section



     	4 of the report.
3.   Scaling; See Operation Problems and Solutions in Section



     	4 of the report.	
4.   Plugging; See Operation Problems and Solutions in Sec-



     	tion 4 of the report.	
5.   Design problems; See Operation Problems and Solutions



     	in Section 4 of the report.	
6.    Waste water/solids disposal: See Operation Problems and



     	Solutions  in Section 4 of the report
                             55

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     7.   Mechanical problems;   See Operation Problems and



             Solutions  in Section  4 of  the  report	
M.   General comments:
      1.  Two-thirds of  the  scrubbing  solution used  in  the  flooded-



     	disc  scrubbers is  introduced through the hollow shaft of



     	the flooded disc;  the  remainder  is  sprayed through	



     	tangential nozzles located on the vessel wall.	



      2.  Arizona Public Service is now installing a limestone



     	grinding  facility  on the plant grounds.  This facility



     	will  be able to meet the limestone  requirements of	



     	Cholla 1  and 2 (Cholla 2 will be put in service in June



         1978) .  It will consist of a ball mill capable of	



     	grinding  0.6 cm (0.25  in.) limestone rock  to  75 percent



     	minus 200-mesh product.	
                                56

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                     APPENDIX B

                  PLANT PHOTOGRAPHS
Photo No. 1.  General view of the FGD system and
boiler for the Cholla No. 1 unit.  The two parallel
scrubbing trains are featured in the foreground.
The boiler is featured in the background.  The B-side
absorber tower is featured closest to the viewer.
Photo No.  2.   Back view  of  the A-side  scrubbing
train.  Featured  in  the  photo are  the  induced draft
fans, flue gas ductwork,  flooded-disc  scrubber,
absorber  tower, and  tank.
                     57

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Photo No. 3.  Side view of scrubbing facilities.
Featured in the photo from left to right are the
coal conveyor, absorber tower, ductwork, slurry
recirculation tank, stack, and part of the lime-
stone storage silo.
Photo No. 4.  Closeup view of the scrubbing  train.
The flooded-disc scrubber, sump, and absorber  tower
are featured in the photo from  left to right.
                      58

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Photo No. 5.  Close up view of the base of the shaft
which is connected to the flooded-disc located in the
throat area of the scrubber.
Photo No.  6.   Side view of  the mechanical collectors and
the  scrubber  induced  draft  booster  fan.
                      59

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  Photo No.  7.
  draft fan.
Side view of the scrubber induced
Photo No. 8.  View of the battery of absorber tower
feed pumps.  A total of three are employed for service
to both scrubbing trains.
                      60

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Photo No. 9.  Side view of the twin sludge holding tanks
showing the discharge pumps and piping.
  Photo No. 10.  View of limestone silo and lake which
  provides fresh water to the plant.  A work shed is
  located in the foreground.

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Photo No. 11.  The Cholla station coal receiving, storage
and conveying facilities.
   Photo No. 12.  View of the boiler for Cholla No. 2
   This unit is currently under construction and is
   scheduled for start-up in June 1977.
                        62

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                                TECHNICAL REPORT DATA
                         (Please read Instructions on the reverse before completing)
  REPORT NO.
 EPA-600/7-78-048a
                           2.
                                                      3. RECIPIENT'S ACCESSION NO.
 ,T,TLE AND SUBTITLE Surv?y of Flue Gas Desulfurization
 Systems: Cholla Station, Arizona Public Service Co.
                                5. REPORT DATE
                                March 1978
                                                      6. PERFORMING ORGANIZATION CODE
7. 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 PERIOD COVERED
                                Subtask Final; 1-6/77	
                                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-650/2-75-057a 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 Arizona Public Service Co. 's Cholla Station.  The FGD
 system,  commercially available in December 1973, utilizes a limestone slurry in
 two parallel scrubbing modules to control SO2 and fly ash from the combustion of
 low sulfur western coal.  (The two-module FGD system is described.) The system's
 total SO2 removal efficiency is  58. 5% (92% for the SO2 removal module). Either or
 both modules can be bypassed.  The flue gas cleaning wastes are disposed of in an
 on-site unlined fly ash pond. No water is recycled from the pond to the FGD system.
 Following a number of modifications of the FGD system by the system supplier and
 the utility, the  system has exhibited a high degree of mechanical reliability while
 meeting required SO2 and particulate emission control levels.
17.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                          b.IDENTIFIERS/OPEN ENDED TERMS
                                                                  c. COSATI Field/Group
 Air Pollution   •
 Flue Gases
 Desulfurization
 Fly Ash
 Limestone
 Slurries
Scrubbers
Coal
Combustion
Cost Engineering
Sulfur Dioxide
Dust Control
Ponds	
Air Pollution Control
Stationary Sources
Wet Limestone
Particulate
13B
21B
07A,07D
                        11G
 21D

 14A
 07B

_Q8JL
13. DISTRIBUTION STATEMENT

 Unlimited
                    19. SECURITY CLASS (This Report)
                    Unclassified
                             72
                    20. SECURITY CLASS (Thispage)
                    Unclassified
                                            22. PRICE
EPA Farm 2220-1 (9-73)
                                        63

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