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-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-0488
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.
-------
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-
-------
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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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.
-------
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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