EPA-650/2-75-057-Q
June 1975 Environmental Protection Technology Series
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
CHOUA POWER GENERATING STATION,
ARIZONA PUBLIC SERVICE COMPANY
I
55
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U.S. Environmental Protection Agency
Office of Research and Development
Washington, D. C. 20460
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EPA-650/2-75-057.Q
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
CHOLLA POWER GENERATING STATION,
ARIZONA PUBLIC SERVICE COMPANY
by
Gerald A. Isaacs and Fouad K. Zada
PEDCo-Environmental Specialists, Inc.
Suite 13
Atkinson Square
Cincinnati, Ohio 45246
Contract No. 68-02-1321, Task 6a
ROAP No. 21ACX-130
Program Element No. 1AB013
EPA Project Officer: Wade H. Ponder
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, N. C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON, D.C. 20460
June 1975
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EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center -Research Triangle Park , Office of Research and Development.
LPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office .of Research and Development , U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These 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
9. MISCELLANEOUS
™™ been assi8ned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/2-75-057-a
11
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ACKNOWLEDGMENT
This report was prepared under the direction of Mr.
Timothy W. Devitt. Principal authors were Dr. Gerald A.
Isaacs and Mr. Fouad K. Zada.
Project Officer for the U.S. Environmental Protection
Agency was Mr. Wade H. Ponder. Information and data on
plant operation were provided during and subsequent to the
survey visit by Messrs. Cleo Walker and Gilbert Gutierrez,
Arizona Public Service Company, and by Messrs. James E.
McCarthy and Joseph Stites, Research-Cottrell, Inc. Mr.
Charles D. Fleming was responsible for editorial review of
this report.
The authors appreciate the efforts and cooperation of
everyone who participated in the preparation of this report.
111
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TABLE OF CONTENTS
Page
ACKNOWLEDGMENT iii
LIST OF FIGURES v
LIST OF TABLES v
SUMMARY vi
1.0 INTRODUCTION 1-1
2.0 FACILITY DESCRIPTION 2-1
2.1 Plant Location 2-1
2.2 Boiler Data 2-1
2.3 Pollution Controls 2-1
3.0 FLUE GAS DESULFURIZATION SYSTEM 3-1
3.1 Process Description 3-1
3.2 Limestone Milling Facilities 3-5
3.3 Process Instrumentation 3-5
3.4 Design Parameters 3-6
3.5 Installation Schedule 3-7
3.6 Cost Data 3-7
4.0 FGD SYSTEM PERFORMANCE 4-1
4.1 Performance Test Run 4-1
4.2 Start-up Problems, Solutions and Cost 4-3
4.3 Process Modifications for Future 4-7
Installations
APPENDIX A PLANT SURVEY FORM A-l
APPENDIX B PLANT PHOTOGRAPHS B-l
APPENDIX C OPERATING DATA C-l
iv
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LIST OF FIGURES
Figure
3.1
3.2
4.1
4.2
Process Flow Diagram of the FGD System at
the Cholla Power Plant
Basic Components of Research-Cottrell's
FGD system: Variable-Throat Flooded-Disc
Particulate Scrubber (foreground) and
SO2 Scrubber Tower (background)
Scale Buildup in the Flooded-Disc Scrubber
Reheater Corrosion Problem
Page
3-2
3-3
4-4
4-6
Table
2.1
3.1
3.2
3.3
LIST OF TABLES
Pertinent Data on Plant Design, Operation,
and Atmospheric Emissions
Data Summary: Particulate and SO- Scrubbers
Data Summary: FGD System Hold Tanks
Typical Pressure Drop Across Components of
Particulate Scrubber and FGD System
Page
2-3
3-8
3-8
3-9
v
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SUMMARY
A wet limestone system was designed and installed by
Research-Cottrell for desulfurization of flue gas on Unit 1
of the Cholla Power Generating Station of Arizona Public
Service Company. This is a base-load unit with a maximum
continuous net generating capacity of 115 MW. The boiler
burns 54 tons per hour of pulverized coal at capacity. The
typical gross heat content of the coal, as-received, is
10,290 BTU per pound; typical ash and sulfur contents are
10.4 and 0.55 percent, respectively.
The flue gas desulfurization system consists of two
parallel scrubbing train modules, each designed to accom-
modate 50 percent of the flue gas. Module A of the system
includes an adjustable flooded-disc scrubber for particulate
control followed by a packed tower which utilizes a lime-
stone slurry for SO- removal. Module B also incorporates a
flooded-disc scrubber for particulate control. Its second
stage absorber shell is similar to that for Module A, but it
contains no packing, and limestone slurry is not circulated
through it. SO2 removal efficiency for Module B is estimated
by Arizona Public Service to be 25 percent.
Testing of the system started on October 2, 1973, and
continued until a scheduled shutdown on October 21. Research-
VI
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Cottrell reported that Module A collection efficiencies for particu-
lates and SO2 during that test run were 99.7 percent and 92
percent, respectively. System availability was reported to
exceed 92 percent. Official acceptance tests for the
system have not been performed by Arizona Public Service, as
of April 30, 1975.
After minor modifications the system was officially
started on December 14th and operated with a 92.6 percent
availability factor until April 15th when it was again
brought down for scheduled modifications of the expansion
joints. Repair crews, supplied by Research-Cottrell, were
available during most of the first half of 1974. Their
attention to the maintenance of the units partly accounted
for the high availability that was demonstrated during this
shakedown effort. Modifications were completed by the end
of April, and the system has continued to operate with high
reliability since that time.
The system operates in an open-loop mode, since there
is no recycling of liquor from the fly ash pond. Approxi-
mately 386 gallons of make-up water are required per pound-
mole of SO~ removed.
Installed cost for the flue gas desulfurization system
is reported to be about $6.5 million, or $57 per KW.
Annualized 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
charges.
VI1
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On December 25, 1974, Research-Cottrell was awarded a
contract for the installation of a similar system on Cholla
Unit 2, where the boiler is under construction. When this
unit is completed, the plant will have 365 MW of capacity
with SC>2 controls.
Pertinent data on Unit 1 and on the system operation
are summarized in the following table.
Vlll
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SUMMARY OF FGD DATA, CHOLLA UNIT NO. 1
Unit rating (net), MW
115
Fuel
Gross heating value,
BTU/lb (typ)
Ash, percent (typ)
Sulfur, percent (typ)
FGD vendor
Process
New or retrofit
Start-up date
FGD modules
Efficiency, percent
Particulates
SO,,
Water make-up,
gallons/lb-mole SO2
Sludge disposal
Unit cost, 1973 dollars
Coal
10,290
10.4
0.55
Research-Cottrell, Inc.
Wet limestone scrubbing
Retrofit
October 1973
2 - Only one has packing and
limestone circulation
99.7 - vendor data
92 - Module A - (vendor data)
25 - Module B - (utility estimate)
386a
Unstabilized sludge disposal in
unlined pond. Temporary solution
only.
6.5 x 10 (no limestone grinding
or sludge treatment facilities exist)
Calculated value assuming overall SO- removal efficiency
of (92 + 25)/2 = 58.5% *
IX
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1.0 INTRODUCTION
The Control Systems Laboratory of the U.S. Environ-
mental Protection Agency (EPA) has initiated a study to
evaluate the status of selected flue gas desulfurization
(FGD) systems on coal-fired boilers in the United States.
This report on the Cholla Power Generating Station of Arizona
Public Service Company (APS) is one of a series of reports
on such systems. It presents values of key process design
and operating parameters, describes the major start-up and
operational problems encountered at the facility and the
measures taken to alleviate such problems, and identifies
the total installed capital costs and annualized costs.
This report is based upon information obtained during a
plant inspection on April 2, 1974, and on data provided by
personnel of APS and Research-Cottrell, Inc. (R-C).
Section 2.0 presents pertinent data on facility design
and operation, including actual and allowable particulate
and SO2 emission rates. Section 3.0 describes the FGD
system and Section 4.0 analyzes FGD system performance.
Appendices present details of plant and system operation and
photographs of the installation.
1-1
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2.0 FACILITY DESCRIPTION
2.1 PLANT LOCATION
The Cholla Power Generating Station of APS is located
near Joseph City, in Navajo County, Arizona. The terrain
around the Cholla Station is relatively flat and practically
arid; there is no major industry in the area. The nearest
sizable populated area is the town of Holbrook, about 10
miles east of the plant.
2.2 BOILER DATA
At present Cholla operates only Unit 1, having a dry-
bottom, pulverized-coal-fired boiler with a net 115 MW
generating capacity. The boiler was designed by Combustion
Engineering, Inc. (CE). Plant capacity will increase to 365
MW upon completion of Cholla Unit 2, a 250 MW unit that is
under construction.
The coal now being burned has typical fuel values, as-
received, of 10,290 BTU/lb, 10.4 percent ash and 0.55 per-
cent sulfur.
2.3 POLLUTION CONTROLS
A R-C multicyclone-type collector, operating with an
efficiency of about 75 percent, provides primary control of
particulate emissions. Design particulate loading at the
2-1
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outlet of the multicyclones is approximately 2.0 grains per
standard cubic foot (gr/scf).
The maximum particulate emission allowed under Arizona
State Department of Health Regulation No. 7-1-3.5 is 0.196
Ib/MM BTU of heat input to the boiler. The present atmo-
spheric emission of particulate from Cholla's FGD system is
reported by APS to be 0.026 Ib/MM BTU.
Atmospheric emission of sulfur dioxide is limited by
Regulation No. 7-1-4.2 to 1.0 Ib/MM BTU heat input to the
boiler. The present SO2 emission rate from Cholla Unit 1,
based on a combined 58.5 percent removal efficiency in the
FGD system, is estimated to be 0.36 Ib/MM BTU.
APS plans to install an FGD system on Cholla Unit 2,
presently under construction. APS recently signed a contract
with R-C to purchase a particulate scrubber and an FGD
system for that boiler similar to the system on Unit 1. R-C
is preparing preliminary engineering designs and plans to
use two modules to treat the flue gases from that boiler.
Table 2.1 presents pertinent data on plant design,
operation, and atmospheric emissions.
2-2
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Table 2.1 PERTINENT DATA ON PLANT DESIGN,
OPERATION, AND ATMOSPERIC EMISSIONS
Boiler Data
Rated generating capacity, MW
Average capacity factor (1973)
Served by stack No.
Boiler manufacturer
Year placed in service
Max. coal consumption, T/hr
Max. heat input, MM BTU/hr
Stack height, ft above grade
Flue gas rate-max., acfm
Flue gas temperature, °F
Emission controls
Particulate
so2
Particulate emission rate
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
SO. emission rate
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
115
1
CE
1962
54
1,112
250
520,000
276
multicylones
venturi scrubber
venturi scrubber
absorber tower
0.196
0.026
1.0
0.5 (est.)
250
CE
0.167
0.8
a Boiler under construction. Contract signed with Research-Cottrell
to install a particulate control and FGD system.
2-3
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3.0 FLUE GAS DESULFURIZATION SYSTEM
3.1 PROCESS DESCRIPTION
The FGD system consists of two scrubbing trains, labeled
A and B as shown in Figure 3.1, each with a venturi scrubber
for particulate emission control and an absorber tower for
SO2 control. However, the absorber B-side tower is not
packed and limestone slurry is not circulated through it.
Each train treats about half of the total flue gas from the
coal-fired boiler or about 260,000 acfm at 276°F. Flue gas
from the boiler induced-draft fans is pressurized by two
booster fans to a static pressure of about 25 in. H-O. The
flue gas then enters the flooded-disc particulate scrubber
and flows downward through the scrubber throat. Limestone
slurry flowing out over the disc is atomized as it is sheared
by the gas stream at the edge of the disc. Limestone slurry
is also injected tangentially through nozzles located on the
inside wall of the scrubber shell near the tapered throat.
The gas pressure drop and the resulting scrubbing efficiency
are regulated by raising or lowering the flooded disc to
vary the throat opening. Scrubber components are illustrated
in Figure 3.2.
Gas from the particulate scrubber enters the SO2
absorber near the base of the tower and comes in contact
3-1
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LIMESTONE SLURRY MAKEUP
SO; SCRUBBER
OEMISTER
PARTICULATE
SCRUBBER
MODULE (B)
ASH-LADEN
WATER
PURGE TANKJ [SURGE TANK)
FLUE
CAS
BOOSTER
FAN
TO SlUDCE POND
Figure 3.1 Process flow diagram of the FGD system
at the Cholla Power Plant.
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Figure 3.2 Basic components of Research-Cottrell's
FGD system: variable-throat flooded-disc particulate
scrubber (foreground) and SO,, absorber tower (background)
3-3
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with limestone slurry on the surface of a two-foot-thick
fixed packing. The packing is made of corrugated sheets of
polypropylene joined in a honeycomb pattern. Only Module A
is equipped with this packing. The scrubbed gas then passes
through two plastic one-foot-thick demisters, sections of
which are washed intermittently with fresh water.
The cleaned flue gas is reheated from 121° to about
165°F as it passes across two bundles of shell-and-tube
heat exchangers. The source of heat is high-pressure steam
from the boiler steam drum, which is reduced from 1900 psig
to 250 psig. The reheated gas then exits through a
brick-lined concrete stack, which is common to both trains.
The two trains also share a common S0_ absorber tower recir-
culation tank.
The rate of limestone addition to the FGD system is
about 110 percent of the stoichiometric rate for reaction
with the sulfur dioxide in the stack gas. Part of the
circulated liquor in the S02 absorber is diverted to the
flooded-disc scrubber tank (common to both trains) to main-
tain the pH between 6 and 7 in the particulate control
system. The liquid level in this tank is maintained by
pumping the excess spent liquor to one of two surge tanks
before it is discharged to the fly ash pond.
The plant has no equipment for sludge treatment or
fixation. Because of light rainfall and a high evaporation
rate in this area no liquor is recirculated from the pond.
3-4
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The B-side train can be bypassed in conjunction with A-
side operation, or both trains can be bypassed simultaneously,
However, it is not possible to bypass the A-side train
alone, except for short periods of time. This is because
limestone enters the system via the A-side absorber and is
used to control the operating pH of the entire particulate
scrubber system. The inlets to both trains from the booster
fans are interconnected through a common suction header,
which makes it possible to equalize the gas load to the two
trains.
3.2 LIMESTONE MILLING FACILITIES
Ground limestone for the FGD system is purchased from
two suppliers, both located in Arizona. The APS limestone
specification calls for material that is at least 75 percent
by weight less than 200 mesh. Specified minimum CaO is 52.5
percent; specified maximum MgO is 2 percent.
Because the plant has no limestone milling facility,
the finely ground limestone is stored in a silo. A small
limestone slurry mixing tank is provided at the base of the
tower. Limestone milling facilities may be installed after
installation of the FGD system on Unit 2.
3.3 PROCESS INSTRUMENTATION
Instrumentation of the FGD installation is housed in
two separate areas. Most of the recording instruments are
mounted on a panel located in the electrical switch gear
building adjacent to the FGD structure. The remaining
instruments, primarily for remote control of process op-
3-5
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erations, are housed in the main boiler control room and are
monitored by the boiler control operator.
3.4 DESIGN PARAMETERS
The FGD system at the Cholla Station was designed by
R-C to process 480,000 acfm of flue gas at 276°F. The
actual total flow to both FGD trains, at 115 MW generating
capacity is 400,000 acfm, with about 17,000 acfm of bypass
leakage around the FGD system.
Each flooded-disc particulate scrubber operates with a
liquid recirculation rate of about 2170 gpm at full load.
This represents a liquid-to-gas ratio (L/G) of 10.1 gallons
of water per 1000 actual cubic feet (acf) of gas at 122°F.
Two-thirds of this liquid is introduced into the scrubber
through the hollow shaft of the flooded disc and the remainder
is sprayed through tangential nozzles on the vessel wall.
The sulfur dioxide absorber tower operates with an L/G
of about 49 gallons/1000 acf. The design gas velocity
through the tower is 7.7 feet per second.
Each tower demister is divided into four sections.
Each section is sprayed sequentially with process water for
12 seconds every 8 minutes. Flow rate of the process water
spray is about 240 gpm.
The shell-and-tube reheater on each train consists of
two bundles. The reheater duty is about 8 MM BTU/hr. Six
steam operated soot blowers for cleaning of the reheater
tubes are operated for 5 minutes during each 8-hour shift.
3-6
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Tables 3.1, 3.2, and 3.3 summarize operating design
parameters and specifications for major components of the
FGD system.
3.3 INSTALLATION SCHEDULE
Work on the FGD system at the Cholla Station was initiated
in January 1971. R-C, who already had a pilot plant in
operation at the Cholla Station and was treating a slip
stream from Boiler 1, made a preliminary design and submitted
a proposal for the FGD system in April 1971. APS awarded
the contract to R-C in July 1971. Construction and initial
testing of the system were completed on December 3, 1973,
and commercial operation began December 14, 1973.
System installation was delayed for several reasons,
including engineering design changes, material specification
changes, equipment delivery delays, adverse weather conditions,
and system shakedown problems.
3.6 COST DATA
The installed cost of this FGD system to APS was about
$6.5 million (equivalent to $57/net KW). This figure,
however, does not include the cost of such items as limestone
storage and milling facilities and sludge disposal (the
present ash pond is used). Additional costs incurred by R-C
have not been reported.
Cost of the ground limestone is $19.20 to $23.50 per
ton, delivered; transportation cost is $7.07 to $15.58 per
ton, ranging from 37 to 66 percent of the delivered lime-
stone cost.
3-7
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Table 3.1 DATA SUMMARY: PARTICULATE AND SO2 SCRUBBERS
Flooded-disc
scrubber
SO_ absorber
tower
L/C ratio,
gallons/1000 acf
Superficial gas
velocity, ft/sec
Equipment sizes
Equipment internals
10.1
6 ft dia. x 45 ft
adjustable disc
48.9
Design 7.7/Actual 6.9
22 ft dia. x 70 fta
2 ft fixed
matrix packing
Estimated
Table 3.2 DATA SUMMARY: FGD SYSTEM HOLD TANKS
Total number of
tanks
Tank sizes
Retention time at
full load
Temperature, °F
PH
Solids concentra-
tion, %
Specific gravity
Flooded disc
scrubber
holdup
tank
1
12 ft 6 in.
dia. x 14 ft
6 in.
7 min.
121
5.2
15.5
1.102
S0_ absorber
towers
holdup
tank
1 (common)
27 ft 4 in.
dia. x 28 ft
5 min.
121
6.5
8.3
1.049
FGD system
sludge
holdup
tank
2
18 ft 6 in.
dia. x 27 ft
14 hr ea.
121
5.2
25
Limestone
slurry
makeup
tank
1
_
90
20
3-8
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Table 3.3 TYPICAL PRESSURE DROP ACROSS
COMPONENTS OF PARTICULATE SCRUBBER AND FGD SYSTEM
Equipment Pressure drop,
inches W.G.
Flooded-disc scrubber 10
SO2 scrubber tower 0.5
Demister 0.5
Reheater 3.3
Ductwork 4.35
Total system (particulate & SO2 removal) 20
3-9
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Annualized cost for the system is 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 charges.
3-10
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4.0 FGD SYSTEM PERFORMANCE
4.1 PERFORMANCE TEST RUN
Initial testing of the FGD system began on October 2,
1973. The system operated until the scheduled shutdown date
of October 21. During the 3-week test period, particulate
and SO, removal efficiencies, mist carryover from the towers,
maximum process gas flow rates, and bypass gas leakage rates
were determined.
Module A consists of a flooded-disc scrubber followed
by a packed tower. Vendor data indicated an SO2 removal
efficiency of 92 percent with average inlet and outlet SO2
concentrations of 417 and 34 ppm, respectively. APS estimates
that the S02 removal efficiency for Module B is 25 percent.
Thus the estimated combined SO2 efficiency for the two
modules is 58.5 percent.
Mist carryover from Modules A and B was nil. The
solids carryover, detected as calcium ion, averaged 0.005
gr/scf from Module A. The appearance of the demisters at
shutdown on October 21, 1973, and the carryover tests
indicated very little entrainment of slurry. Pressure drop
buildup across the demister was less than 0.7 in. H2O over
a 4-month period of operation.
The maximum average inlet gas rates during the 3-week
operation were 214,300 acfm to Module A and 204,600 acfm to
4-1
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Module B, with 18,400 acfm air leakage into the system
downstream of the flooded-disc scrubbers.
Chloride ion concentrations in the flooded-disc scrubber
recirculation and in tower slurries were 1600 and 575 ppm,
respectively. These levels are sufficient to cause pitting
corrosion in localized areas with temperatures greater than
140°F and pH less than 3.0. The chloride content of the
coal ranges between 0.01 to 0.04 percent (equivalent to 8 to
32 ppm by weight in the flue gas). The chloride ion concentra-
tion in the boiler water blowdown which is used as make-up
water to the FGD unit is 933 ppm. The chloride ion concen-
tration in the well water, used for boiler make-up water, is
144 ppm.
Additional vendor data on the 3-week initial operation
are presented in Appendix C.
The FGD system performed satisfactorily from December
15, 1973, to April 15, 1974. Although several upsets caused
shutdown of one or both modules for short periods, system
availability averaged 92.6 percent during that period.
The FGD units were shut down for short periods in April
to replace corroded' Corten steel expansion joints on the
reheater bundles. Module B was down from April 15 until
April 28; Module A was down from April 17 until April 27.
As of March 1, 1975 the FGD system has operated satisfac-
torily for 14 months with an average availability factor of
about 92 percent for each module.
4-2
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4.2 START-UP PROBLEMS, SOLUTIONS AND COST
An analysis of the problems encountered during start-up
indicates that nearly all were due to mechanical design
rather than to process chemistry. An account of the major
problems follows.
1. Scale deposits; Scale accumulated on top and
inside the cavity of the shaft's stuffing box in the flooded-
disc scrubber, as illustrated in Figure 4.1. These scale
deposits were discovered early enough to prevent binding of
the shaft. The problem was solved by modifying the assembly
of the stuffing box; it was disassembled, cleaned, and
reinstalled inverted so that the cavity is at the bottom and
cannot accumulate solids. 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.
2. Corrosion: The expansion joints above the reheaters
of Modules A and B were corroded by the weak sulfurous acid
condensate. Corrosion was also observed on the top row of
tubes near the tube sheet on Module B. The cause in all
cases was the accumulation of weak acid condensate in stagnant
pockets in the reheater and ductwork. To prevent recurrence
of this problem, the ductwork upstream of the reheaters on
Modules A and B was insulated and the Corten steel expansion
joints were replaced with rubber expansion joints. Also, to
prevent acid condensate from reaching the tubes, a trough
was installed to divert any condensate from the tube bun-
4-3
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TANGENTIAL
SPRAY NOZZLE
SCALE BUILDUP
CORROSION
AND
EROSION
EROSION
AND
LEAKS
PROBLEM: SCALE BUILDUP AROUND FDS SHAFT
STUFFING BOX. COULD FREEZE SHAFT
MOVEMENT.
SOLUTION: STUFFING BOX REINSTALLED IN
INVERTED POSITION.
Figure 4.1 Scale buildup, erosion and corrosion in
the flooded disc scrubber.
4-4
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dies. The corroded tube bundle was replaced. Figure 4.2
shows the site of the acid condensate corrosion attack. It
is important to note that corrosion of the reheater by
sulfurous acid occurred only in Module B (the module without
packing) which has low SO_ removal efficiency. Presumably
the higher S02 removal efficiency of the packed tower pre-
cludes significant formation of sulfurous acid. Evidence of
chloride attack was noted in the absorber tower shell. To
remedy this problem R-C coated the interior of the vessel
with an epoxy material. This material eroded away below the
scrubber disc. Alternate lining materials such as brick and
rubber are being considered. The spray distribution cap above
the flooded disc eroded and corroded completely off. The cap
is being redesigned by R-C. Additional chloride attack has
been observed on the B-side reheater tubes. It is believed
that the chlorides are being introduced in the well water
used in preparing make-up slurry. The chloride contents of
the coal and of the flue gas are extremely low.
3. Vibrations; Harmonic vibrations with deflections
of as much as 0.040 inch occurred in the reheaters. The
vibrations were attributed to inadequate transition of duct
size from the absorber outlet to the reheater shell, with a
resultant vortex effect. To remedy the situation, cross
baffles were installed at the entrance to the reheater.
Vibrations also occurred in the booster fan on Module
B. The vibration was caused by uneven buildup of scale on
the fan blades while the unit was idle. The blades were
sandblasted, cleaned, and rebalanced.
4-5
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DIRECTION
OF GAS FLOW
CORROSION OF
EXPANSION JOINT
DUE TO ACID
CONDENSATE
FROM SO,
4
SCRUBBER
I
CORROSION OF TUBES
DUE TO ACID CONDENSATE
TO STACK
PROBLEM: CORROSION DUE TO ACID CONDENSATE
SOLUTION: 1) REPLACEMENT OF CORTEN STEEL EXPANSION JOINTS
WITH RUBBER EXPANSION JOINTS.
2) INSULATION OF DUCTWORK UPSTREAM OF REHEATER.
3) INSTALLATION OF TROUGH SECTION ABOVE TUBES TO
DIVERT ACID AWAY FROM TUBE BUNDLE.
Figure 4.2 Reheater corrosion problem.
4-6
-------
4. Miscellaneous problems; Buildup of sediment
occurred several times in dead spaces in pipelines and
valves of idle pumps and also in process lines during
periods of reduced operating rate when slurry velocities in
the pipe were low. The solution to this problem was to
redesign some pipes to eliminate potential dead pockets. To
prevent freezing of valves due to sediment buildup, some
valves were repositioned and washout lines were installed.
Some pipe liners eroded. The erosion was due in some
cases to unsatisfactory liner materials and in other cases
to high velocities through pipes and fittings. Piping
modifications helped to reduce the erosion problem. Crack-
ing of the rubber lining in some pipes was due to defects in
fabrication.
In recent months while burning low-grade coal having
22 percent ash and 0.7 percent sulfur, some plugging of the
tower packing has occurred. It has not yet been verified
whether or not this plugging is due to the coal grade. If the
buildup of material in the packing continues, it appears that
the packing life will be reduced to about six months.
4.3 PROCESS MODIFICATIONS FOR FUTURE INSTALLATIONS
Research-Cottrell, Inc., designer of the wet limestone
FGD system at the Cholla Station, indicates no major changes
in the design of future installations. Because of reheater
tube failures at the Cholla Station however, reheater units
in future installations will be fabricated of Incoloy,
rather than stainless steel.
4-7
-------
APPENDIX A
PLANT SURVEY FORM
A-l
-------
PLANT SURVEY FORM3
NON-REGENERABLE FGD PROCESSES
A. COMPANY AND PLANT INFORMATION
1. COMPANY NAME Arizona Power Service Co.
2. MAIN OFFICE
3 . PLANT MANAGER Cleo Walker
4 . PLANT NAME _ Cholla Power .Generating Station
5. PLANT LOCATION Near Joseph City, Arizona
6 . PERSON TO CONTACT FOR i'URTHER INFORMATION
7. POSITION
8. TELEPHONE NUMBER
9. DATE INFORMATION GATHERED April 2, 1974
10. PARTICIPANTS IN MEETING AFFILIATION
James E.. McCarthy Research-Cottrell
George Wilcox Research-Cottrell
Wade H. Ponder EPA
Timothy W. Devitt PEDCo-Environmental
Fouad K. Zada PEDCo-Environmental
a These data were obtained from Research-Cotrell on April 2, 1974
Some of the data have been updated in the text of the report.
A-2 5/17/74
-------
B. PLANT DATA. (APPLIES TO ALL BOILERS AT THE PLANT).
CAPACITY, MW
SERVICE (BASE, PEAK)
FGD SYSTEM USED
BOILER NO.
1
115
Base
jimeston
2
Under Cc
>
3
nstructi
Dn
C. BOILER DATA. COMPLETE SECTIONS (C) THROUGH (R) FOR EACH
~~BOILER HAVING AN FGD SYSTEM.
1. BOILER IDENTIFICATION NO.
2. MAXIMUM CONTINUOUS HEAT INPUT
1112
124
3. MAXIMUM CONTINUOUS GENERATING CAPACITY
4. MAXIMUM CONTINUOUS FLUE GAS RATE. 520,000
5. BOILER MANUFACTURER Combustion Engineering
MM BTU/HR
MW
ACFM @ 276
6. YEAR BOILER PLACED IN SERVICE May 1962
7. BOILER SERVICE (BASE LOAD, PEAK, ETC.)
8. STACK HEIGHT
9. BOILER OPERATION HOURS/YEAR (197 )
10. BOILER CAPACITY FACTOR *
11. RATIO OF FLY ASH/BOTTOM ASH
Base
250 ft.
* DEFINED AS: KwH GENERATED IN YEAR
MAX. CONT. GENERATED CAPACITY IN KW x 8760 HR/YR
A-3
5/17/74
-------
D. FUEL DATA
1. COAL ANALYSIS (as received)
GHV (BTU/LB.)
S %
ASH %
Dry Basis Avg. as Rec'd.
MAX.
12146
0.52
12.3
AVG.
10290
0.44
10.4
2. FUEL OIL ANALYSIS (exclude start-up fuel)
GRADE
S %
ASH %
E. ATMOSPHERIC EMISSIONS
1. APPLICABLE EMISSION REGULATIONS
a) CURRENT REQUIREMENTS
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
MAX. ALLOWABLE EMISSIONS
LBS/MM BTU
b) FUTURE REQUIREMENTS,
COMPLIANCE DATE
REGULATION & SECTION NO.
MAXIMUM ALLOWABLE EMISSIONS
LBS/MM BTU
PARTICULATES
7-1-3.5
0.336
so2
7-1-4.2
1.0
2. PLANT PROGRAM FOR PARTICULATES COMPLIANCE
3. PLANT PROGRAM FOR SO2 COMPLIANCE
A-4
5/17/74
-------
p. PARTICULATE REMOVAL
1. TYPE
MANUFACTURER
EFFICIENCY: DESIGN/ACTUAL /75
MAX. EMISSION RATE* LB/HR
GR/SCF
LB/MMBTU
MECH.
(multiclones
Research— Cotti
/75
R
F 2.0
IT
E.S.P.
)
_
-
FGD
Wet limestone
qfl.fi/QQ ?
DESIGN BASIS, SULFUR CONTENT
G. DESULFURIZATION SYSTEM DATA
1. PROCESS NAME
2. LICENSOR/DESIGNER NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
wet flv ash/limestone scrubbing
Research-Cottrell
Box 750 Bound Brook
New Jersey 08805
James E. McCarthy.
3. ARCHITECTURAL/ENGINEERS, NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
4. PROJECT CONSTRUCTION SCHEDULE:
DATE
a) DATE OF PREPARATION OF BIDS SPECS. January 1971
b) DATE OF REQUEST FOR BIDS
C) DATE OF CONTRACT AWARD
d) DATE ON SITE CONSTRUCTION BEGAN
April 1971
July 1971
e) DATE ON SITE CONSTRUCTION COMPLETED December 3, 1973
f) DATE OF INITIAL STARTUP
g) DATE OF COMPLETION OF SHAKEDOWN
*At Max. Continuous Capacity
A-5
5/17/74
-------
5. LIST MAJOR DELAYS IN CONSTRUCTION SCHEDULE AND CAUSES:
Design changes because of difficulties at Four Corners Plant.
Late equipment deliveries
Material of construction changes
Sub-contract declining job after award
Weather conditions
Start up problems
AThas packing
6. NUMBER OF S02 SCRUBBER TRAINS USED two B. no packing
7. DESIGN THROUGHPUT PER TRAIN, ACFM @ 276°F 240.000
8. DRAWINGS: 1) PROCESS FLOW DIAGRAM AND MATERIAL BALANCE
2) EQUIPMENT LAYOUT
H. SO, SCRUBBING AGENT
^ limestone purchased in
1. TYPE ground form
a) U-S. limestone, Nelson
?
-------
-J
STRIAM NO.
RATE, tb/hr
ACFM
CPM
PflRTICULATES. Ib/hr
S02. Ib/hr
ItMPfRflTURE. °F
lOTflL SOUDS. -S
SPECIfrCCRftVITV.
•CO
210, nnn
2090
556
278
C21
147,500
102
120
C3)
183,400
102
47
160
CO
210, POO
2090
556
278
CO
,
147, 50C
102
120
CO
183.400
102
280
160
CO
(16
(2
CO
.900)
78}
CO
(jo)
40
C'i)
2350
120
7
' ..
Ciz)
C>3)
2400
STREAM NO.
RATE. Ib/hr
ACFM
CPM
PARTICUIATES. Ib/hr
S02 , Ib/hr
TEMPERATURE. °F
TOTAL SOUDS. °'°
SPECIFIC GRAVITY
CM)
..• .
10,QQQ
120
7.5
(is)
del
f
10T520
2350
120
16
(I?) 1 118)
1
2400
0
(19)
20
' • :•."•., \
120
[2$
32.5
120
7
(21)
-
64
3976 ,
785
16
(22)
0
(23)
(64)
3976
785
16
@
C25)
l
4
|
-
-
^
C26)
I. Representative flow rates based on operating data at maximum continuous load.
-------
J. SCRUBBER TRAIN SPECIFICATIONS
1. SCRUBBER NO. 1
(a)
TYPE (TOWER/VENTURI) Flooded disc 2:1 split disc to
nozzle
LIQUID/GAS RATIO, G/MCP @ 121 °F 10.1
GAS VELOCITY THROUGH SCRUBBER, FT/SEC
MATERIAL OF CONSTRUCTION
TYPE OF LINING
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.) flooded disc
NUMBER OF STAGES
TYPE AND SIZE OF PACKING MATERIAL
No lining
PACKING THICKNESS PER STAGE
(b)
MATERIAL OF CONSTRUCTION, PACKING:
SUPPORTS:
2. SCRUBBER NO. 2 ^
TYPE (TOWER/VENTURI)
LIQUID/GAS RATIO, G/MCF @ 121°F
GAS VELOCITY THROUGH SCRUBBER, FT/SEC
MATERIAL OF CONSTRUCTION
TYPE OF LINING
INTERNALS:
Munters T2-81 Euroform
TYPE (FLOATING BED, MARBLE BED, ETC.) fixed Honeycomb
Packed Tower, fixed
matrix in (A) train,
no packing in (B) train
48.9
Design 7.7/actual 6.9
316L SS
None
NUMBER OF STAGES
TYPE AND SIZE OF PACKING MATERIAL
Fixed Matrix
a) Scrubber No. 1 is the scrubber that the flue gases first
enter. Scrubber 2 (if applicable) follows Scrubber No. 1.
b) For floating bed, packing thickness at rest.
A-8
5/17/74
-------
PACKING THICKNESS PER STAGE
(b)
2' thick
MATERIAL OF CONSTRUCTION, PACKINGt Polypropylene
SUPPORTS; 316L SS
CLEAR WATER TRAY (AT TOP OF SCRUBBER)
TYPE None
L/G RATIO
SOURCE OF WATER
DEMISTER
TYPE (CHEVRON, ETC.)
NUMBER OF PASSES (STAGES)
SPACE BETWEEN VANES
ANGLE OF VANES
TOTAL DEPTH OF DEMISTER
DIAMETER OF DEMISTER
DISTANCE BETWEEN TOP OF PACKING
AND BOTTOM OF DEMISTER
POSITION (HORIZONTAL, VERTICAL)
MATERIAL OF CONSTRUCTION
METHOD OF CLEANING
SOURCE OF WATER AND PRESSURE
FLOW RATE DURING CLEANINGS, GPM
Plastic polypropylene
Primarv demister T-271
Secondary dpmi gt-^v T-41
Primary 1"
two I1 sections Secondary
1/2"
Horizontal
Polypropylene
Sprav top and bottom
each quadrant
Process water. 60 osig
120
FREQUENCY AND DURATION OF CLEANING
REMARKS
5. REHEATER
TYPE (DIRECT, INDIRECT)
Shell and tubes
b) For floating bed, packing thickness at rest.
A-9
5/17/74
-------
DUTY, MMBTU/HR
HEAT TRANSFER SURFACE AREA SO,FT 3 bundles
TEMPERATURE OF GAS: IN 122°F OUT 182°F
HEATING MEDIUM SOURCE
TEMPERATURE & PRESSURE
FLOW RATE
Stepped down and desuper-
heated 1900 psia steam from
steam drum
2500 psig saturated
LB/HR
REHEATER TUBES, TYPE AND
MATERIAL OF CONSTRUCTION
31fiT. ss
REHEATER LOCATION WITH RESPECT TO DEMISTER 30 ft. horizonta
METHOD OF CLEANING
6 steam soot blowers
FREQUENCY AND DURATION OF CLEANING 5 min. every 8 hrs.
FLOW RATE OF CLEANING MEDIUM LB/HR
REMARKS
6. SCRUBBER TRAIN PRESSURE DROP DATA
PARTICULATE SCRUBBER
SO2 SCRUBBER
CLEAR WATER TRAY
DEMISTER
REHEATER
DUCTWORK
TOTAL FGD SYSTEM
Modules
A B
INCHES OF WATER
14.75
0.5
0.5
3.3
4.35
23.4
15
0.5
3.0
4.75
23.25
A-10
S/17/74
-------
7. FRESH WATER MAKE UP FLOW RATES AND POINTS OF ADDITION
TO: DEMISTER
QUENCH CHAMBER
ALKALI SLURRYING
PUMP SEALS
OTHER
TOTAL
FRESH WATER ADDED PER MOLE OF SULFUR REMOVED
8. BYPASS SYSTEM
CAN FLUE GAS BE BYPASSED AROUND FGD SYSTEMS
GAS LEAKAGE THROUGH BYPASS VALVE, ACFM
K. SLURRY DATA
LIME/LIMESTONE SLURRY MAKEUP TANK
PARTICULATE SCRUBBER EFFLUENT
HOLD TANK (a)
SO2 SCRUBBER EFFLUENT HOLD
TANK (a)
PH
5.2
6.5
%
Solids
varies
15
8
Size
2'jzJ x 4'
12 '6" $ x
14 '2"
27'4" jzJ x
28'
Hold up
time
7 min.
5 min.
L. LIMESTONE MILLING AND CALCINING FACILITIES: INDICATE BOILERS
SERVED BY THIS SYSTEM.
TYPE OF MILL (WET CYCLONE, ETC.)
NUMBER OF MILLS
CAPACITY PER MILL
RAW MATERIAL MESH SIZE
PRODUCT MESH SIZE
none
T/HR
Received as powder
Note: cost of limestone $18/ton of which $7.74 for transportation
A-ll
V17/74
-------
SLURRY CONCENTRATION IN MILL
CALCINING AND/OR SLAKING FACILITIES
SOURCE OF WATER FOR SLURRY MAKE UP OR
SLAKING TANK
M. DISPOSAL OF SPENT LIQUOR
1. SCHEMATICS OF SLUDGE & FLY ASH DISPOSAL METHOD
(IDENTIFY QUANTITIES OR SCHEMATIC)
2. CLARIFIERS (THICKENERS)
NUMBER Tw°
DIMENSIONS 18'-6" * * 27'
CONCENTRATION OF SOLIDS IN UNDERFLOW
3. ROTARY VACUUM FILTER
NUMBER OF FILTERS None
CLOTH AREA/FILTER
CAPACITY TON/HR (WET CAKE)
CONCENTRATION OF SOLIDS IN CAKE
PRECOAT (TYPE, QUANTITY, THICKNESS)
REMARKS
4. SLUDGE FIXATION
POINT OF ADDITIVES INJECTION Hone
FIXATION MATERIAL COMPOSITION
FIXATION PROCESS (NAME)
FIXATION MATERIAL REQUIREMENT/TONS OF DRY SOLIDS OF SLUDGE
A-12 5/17/74
-------
ESTIMATED POND LIFE, YRS.
CONCENTRATION OF SOLIDS IN FIXED SLUDGE
METHOD OF DISPOSAL OF FIXED SLUDGE
INITIAL SOLIDIFICATION TIME OF FIXED SLUDGE
5. SLUDGE QUANTITY DATA
POND/LANDFILL SIZE REQUIREMENTS, ACRE-FT/YR
IS POND/LANDFILL ON OR OFFSITE On-site
TYPE OF LINER
IF OFFSITE, DISTANCE AND COST OF TRANSPORT
POND/LANDFILL DIMENSIONS AREA IN ACRES
DEPTH IN FEET
DISPOSAL PLANS; SHORT AND LONG TERM
N. COST DATA
1. TOTAL INSTALLED CAPITAL COST
2. ANNUALIZED OPERATING COST
A'13 5/17/74
-------
4. COST FACTORS
a. ELECTRICITY
b. WATER
C. STEAM (OR FUEL FOR REHEATING)
d. FIXATION COST ___ $/TON OF DRY SLUDGE
(pulverized limestone)
e. RAW MATERIAL PURCHASING COST 18 $/TON OF DRY SLUDGE
f. LABOR: SUPERVISOR JHOURS/WEEK WAGE
OPERATOR
OPERATOR HELPER -
MAINTENANCE • •• •"
MAJOR PROBLEM AREAS: (CORROSION, PLUGGING, ETC.)
1. SO2 SCRUBBER, CIRCULATION TANK AND PUMPS.
a. PROBLEM/SOLUTION 1) erosion of 2" fibercast T at pump
discharge. 2) flow control valve liner supposed to be
teflon, but instead was carbon impregnated plastic, also
rubber on rubber-lined pipes cracked/ 1 modified pipes,
replaced T by 90° elbow and lowered velocity 2. rubber-
lined piping changed and replaced control valve (butterfly)
with teflon-lined valve. Cracking of rubber lining
2. DEMISTERattributed to mfg.defects.
PROBLEM/SOLUTION Essential! ly none
AP build up about 0.5" - 0.7" H-O in
i
4 month period (12/15 - 4/2/74)
3. REHEATER
PROBLEM/SOLUTION D vibration due to size of duct vs. size of
reheater transition duct, which caused harmonic vibrations
(-40 mills deflection) 2) tube bundle leaking to acid
condensation in uninsulated duct/ 1 installed baffles to
break harmonics 2 replaced one tube bundle(out of 3)due to
corrosion and installed diverted baffle to draw off acid
alia™ Cheater tubes, duct upsteam of
5/17/74
A-l 4
-------
VENTURI SCRUBBER, CIRCULATION TANKS AND PUMPS
PROBLEM/SOLUTION 1 ) Scaling on disc, buildup on shaft, hasn' t
caused a problem yet but might eventually bind shaft so it
can't move, buildup in stuffing gland flange and on top of
spray dome. T] piuggage ot some small lines particularly when
i nr nn -roHuced rat~.es 1 nw^y •Flou wol nr-i- / also
settling in stand by pumps/ 1 reversed packing gland position
upside down, also removed one half of packing gland, didn't
need that much. _
5. I.D. BOOSTER FAN AND DUCT WORK
PROBLEM/SOLUTION 1) vibration problems due to accumulation
of scale buildup while fan was idle / 1 cleaned fan and _
sandblasted it.
6. LIMESTONE MILLING SYSTEM OR LIME SLAKING
PROBLEM/SOLUTION N/A
7. SLUDGE TREATMENT AND DISPOSAL
PROBLEM/SOLUTION No problem
A"15 5/17/74
-------
8. MISCELLANEOUS AREA INCLUDING BYPASS SYSTEM
PROBLEM/SOLUTION Vertically mounted valves (stem horizontal!
scale and sediment buildup in dead space. Modified valve
position to horizontal piping and installed wash out lines.
Have 20 Hilton valves. They were the only ones that caused
problems in vertical position.
P. DESCRIBE FACTORS WHICH MAY NOT MAKE THIS A REPRESENTATIVE
INSTALLATION treatment of sludge is understood not to be required due
to high rate of evaporation in Arizona. Method presumed acceptable to
Local EPA. ]) Lack of limestone milling facilities (APS plans to
install such system when other two boilers are in operation and FGD
system installed 2) Absence of sludqe treatment & fixation may not
Q. DESCRIBE METHODS OF SCRUBBER CONTROT, UNDER FLUCTUATING be acceptable
LOAD. IDENTIFY PROBLEMS WITH THIS METHOD AND SOLUTIONS, in other
IDENTIFY METHOD OF pH CONTROL AND LOCATION OF pH PROBES. locals.
R. CLASriFY WATER LOOP MODE OF OPERATION
Since no water is recycled to tfre FQQ system f^Qifl the pnnd
the installation is considered to be operating under
open water loop conditions.
A-16
5/17/74
-------
APPENDIX B
PLANT PHOTOGRAPHS
B-l
-------
Photo No. 1 General view of the flue gas desulfurization
facilities at the Cholla Power Station. The facilities consist
of two parallel SO2 scrubbing trains (shown on left) with a
common slurry circulation tank (center). The pulverized lime-
stone is stored in the tall silo shown to the right of the
slurry circulation tank. Part of one of the two sludge holding
tanks can be seen behind the limestone silo. The electrical
switch gear and part of the control instruments are housed
inside the building shown in the center.
Photo No. 2 Back view of SO2 scrubbing train A, showing flue
gas ductwork to the boiler I.D. fan and the booster I.D. (to
the right) as well as the flooded-disc scrubber and the SO,,
absorber tower (at extreme right). The path of flue gas
through equipment is indicated by arrows.
B-2
-------
Photo No. 3 Close up view of the flooded-disc scrubber. The
cluster of pipes around the throat of the scrubber distribute
the limestone slurry to nozzles located in the walls of the
scrubber vessel near the entrance to the throat. Limestone
slurry also enters at the base through the scrubber shaft to
the flooded disc near the throat.
B-3
-------
Photo No. 4 Inside view at the base of the limestone silo. The
limestone vibrating hopper is on top of the structure and feeds
controlled quantities of limestone to the slurry mix tank below.
B-4
-------
Photo No. 5 View looking south towards upper half of the lime-
stone silo showinq the pneumatic charging line. The vertical
limestone dust trap is on the top of the silo.
B-5
-------
Photo No. 6 View from top of the boiler structure looking
towards S02 scrubbing train A. The picture shows the insulated
duct from top of the absorber tower to the reheater unit. Part
Of the concrete stack appears to the left.
B-6
-------
Photo No. 7 View from top of the boiler structure looking
towards S02 scrubbing train B. The equipment layout of this
train is a mirror image of that of train A.
B-7
-------
Photo No. 8
View from top of the boiler structure looking
The reheaters
towards the area between the two SO- trains.
of both trains are shown on opposite sides of the common
concrete stack. In the center of the picture is the common
suction ductwork for both booster fans. A motorized bypass
sliding vane-type of valve is shown center-left portion of
the picture.
B-8
-------
Photo No. 9 Top view of the common slurry circulation tank
which serves both trains. The return piping from both absorber
towers can be seen on opposite sides of the tank. The tank
agitator motor and gear are in the center.
Photo No. 10 Top view of the twin sludge holding tanks
showing the feed lines from both flooded-disc scrubbers to
each sludge tank. The discharge from the sludge tanks to the
disposal pond is intermittent and through pipes which are
also used for sluicing of fly ash to the pond.
B-9
-------
Photo No. 11 View of battery of ^>O~ absorber co./^r feed
pumps. There are three feed pumps: two are in operation
serving both towers through a common discharge header and
the third is a standby.
B-10
-------
Photo No. 12 View of the main instrument panel located in
the powerhouse main control room. The panel contains key
instruments and alarms for remote control of the flue gas
desulfurization equipment.
B-ll
-------
Photo No. 13 View of the auxiliary control panel located in
the electric switch gear building. The panel shows a sche-
matic flow diagram of the installation and contains mostly
recording instruments. DuPont's SO2 analyzer which records
the concentration of SO2 into and oQt of the FGD system is
shown to the right of tne instrument panel.
Photo No. 14 View from top of the boiler structure looking
south towards the transformers switchyard. The railroad
cars which deliver coal to the plant can be seen immediately
behind the switchyard.
B-12
-------
Photo No. 15 View from top of the boiler structure looking west
towards the structure of boilers 2 and 3, which are presently
under construction. The concrete structures to the left are the
concrete foundations for the steam turbines and generators for
each boiler-.
Photo No. 16 View from top of the boiler structure looking
southeast towards the sludge and fly ash disposal pond located
behind the railroad tracks. The lake shown in the foreground
provides fresh water to the plant. The slurry pipe can be
seen near the edge of the lake.
B-13
-------
APPENDIX C
OPERATING DATA
C-l
-------
Table C-l RESULTS OF FGD SYSTEM TEST RUNS
OF OCTOBER 1973a
Data
Particulate concentration inlet
(gr/SCFD)
Particulate concentration outlet
(gr/SCFD)
SO2 concentration outlet (PPM)
SO2 concentration inlet (PPM)
Data
SO. removal (percent)
Particulate removal efficiency
(percent)
Gas inlet to FDS (ACFM @ T=276°F,
P=27.3"Hg)
Theoretical inlet gas to FDS (ACFM)
Apparent bypass leakage (ACFM @
T=276°F, P=27.3"Hg)
FDS L/G ratio (gal./lOOO ft3)
Tower L/G ratio (gal./lOOO ft3)
Gas velocity through tower (ft/sec)
Mist entrainment from tower (gr/SCFD)
Solids entrainment from tower slurry
(gr/SCFD)
Pressure drop FDS (IWG)
Pressure drop tower demisters (IWG)
Pressure drop reheater (IWG)
Side A
1.995
0.0083
34
417
"A"
Side
92.4
99.7
214,300
198,800
16,
10.1
48.9
6.9
0.000
0.005
14.8
0.00
5.15
Side B
2.537
0.0101
357
409
11 B" Side
with Ring
14.4
99.8
204,600
198,800
900
10.6
0.0
6.6
0.000
N.A.
15.7
0.00
2.30
Stack
-
0.1149
236
—
11 B" Side
without Ring
9.2
99.7
240,300
-
-
5.8
0.0
7.7
N.A.
N.A.
13.5
-
-
Reported by Research-Cottrell.
C-2
-------
Table C-l RESULTS OF FGD SYSTEM TEST RUNS
OF OCTOBER 1973 (continued)
Data
Temperature tower outlet (°F)
AT reheater (°F)
Demister water rate (GPM)
Slurry flow to FDS (GPM)
Slurry flow from FDS (GPM)
Limestone feed rate (Ib/min)
Slurry flow from tower tank to FDS
tank (GPM)
Slurry flow from FDS tank to slurry
(GPM)
Tower tank makeup water (GPM)
FDS tank makeup water (GPM)
Specific gravity/percent solids
tower tank
Specific gravity /percent solids
FDS tank
Percent solids FDS tank (be
Dynatrol)
Tower tank pH
FDS tank pH
Coal consumption (tons/hr)
Coal heating value (BTU/lb)
Atmospheric pressure (in. Hg)
"A"
Side
121
65
12.2
2170
1317
"B" Side
with Ring
121
60
14.0
2177
1486
16.6
32.5 (es1
64.0
0
N.A.
1.049/8.3
1.102/14.8
15.5
6.5
5.2
54
10,293
25.3
"B" Side
without Ring
121
60
14.0
1400
N.A.
:.)
C-3
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before coin/ilcting)
1 REPORT NO
EPA-650/2-75-057-a
3 RECIPIENT'S ACCESSION NO
4 TITLE AND SUBTITLE
Survey of Flue Gas Desulfurization Systems
Cholla Power Generating Station, Arizona Public
Service Company
5 REPORT DATE
June 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Gerald A. Isaacs and Fouad K. Zada
8. PERFORMING ORGANIZATION REPORT NO
9 PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ACX-130
11 CONTRACT/GRANT NO.
68-02-1321, Task 6a
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research .and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Subtask Final: 4/74 - 5/75
14. SPONSORING AGENCY CODE
15 SUPPLEMENTARY NOTES
16. ABSTRACT
repOrt gives results of a survey of a wet limestone system for .desul-
furization of flue gas on Unit 1 of the Cholla Power Generating Station of Arizona
Public Service Company (APSCo). This base-load unit has a maximum continuous net
generating capacity of 115 MW. At capacity, the boiler burns 54 tons of pulverized
coal per hour. The typical gross heat content of the coal, as received, is 10,290 Btu
per pound; typical ash and sulfur contents are 10.4 and 0. 55 percent, respectively.
The system consists of two parallel scrubbing train modules, each accommodating
50 percent of the flue gas. Both modules include an adjustable flooded-disc scrubber
for particulate control, followed by a tower. The module A tower is packed, utilizing
a limestone slurry for SO2 removal. The module B tower contains no packing, and
limestone is not circulated through it. APSCo estimates module B SO2 removal
efficiency to be 25 percent. The system operates in an open- loop mode, since there is
no recycling of liquor from the fly ash pond. Approximately 386 gallons of make-up
water are required per pound-mole of SO2 removed. Installed cost for the system
is reported to be about ?6. 5 million, or $57 per KW. Annualized costs are estimated
to be 2.2 mills /KWHr, including a 23 percent charge on capital investment to account
for interest, depreciation, taxes, and other fixed charges.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Croup
Air Pollution
Flue Gases
Desulfurization
Limestone
Scrubbers
Coal
Combustion
Cost Engineering
Air Pollution Control
Stationary Sources
Wet Limestone
Particulate
13 B
21B 14A
07A, 07D
21D
8 DISTRIBUTION STATEMENT
Unlimited
19 SECURITY CLASS (This Report)
Unclassified
21 NO. OF PAGES
63
20 SECURITY CLASS (Thispage)
Unclassified
22 PRICE
EPA Form 2220-1 (9-73)
C-4
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