EPA-650/2-75-057-k
October 1975 Environmental Protection Technology Series
OF FLUE GAS
DESULFURIZATION SYSTEMS
MOHAVE STATION, SOUTHERN CALIFORNIA EDISON CO.
UJ
O
U.S. Environmental Protection Agency
Office of Research ,ind Development
Washington, D.C. 20460
-------
EPA-650/2-75-057-k
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
MOHAVE STATION, SOUTHERN CALIFORNIA EDISON CO.
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 6k
ROAP No. 21AXC-130
Program Element No. 1AB013
EPA Project Officer: Norman Kaplan
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development .
Washington, D. C. 20460
October 1975
-------
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection
Agency and approved for publication. Approval does not signify that
the contents necessarily reflect the views and policies of the Environ-
mental Protection Agency, nor does mention of trade names or commer-
cial 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
This report has been assigned 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-k
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.
Mr. Wade H. Ponder, former EPA Project Officer, had
primary responsibility within EPA for this project report.
Information and data on plant operation was provided by Dr.
Alexander Weir, Jr., Southern California Edison Company,
during and subsequent to the survey visit. 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 ill
LIST OF FIGURES vi
LIST OF TABLES vi
SUMMARY vii
1.0 INTRODUCTION 1-1
2.0 FACILITY DESCRIPTION 2-1
3.0 FLUE GAS DESULFURIZATION SYSTEMS 3-1
3.1 Process Description 3-1
3.2 Installation Schedule 3-6
3.3 Cost Data 3-8
4.0 FGD SYSTEMS OPERATING HISTORY 4-1
4.1 Performance Test Run 4-1
APPENDIX A PLANT SURVEY FORM A-l
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LIST OF FIGURES
Figure
3-1
3-2
4-1
A Simplified Sketch of the Vertical TCA
Type FGD System Which is Installed
on Mohave 1
A Simplified Side View of the Horizontal
FGD Module Installed on Mohave 2
SO? Removal vs L/G Ratio-170 MW Horizontal
Module
Page
3-3
3-5
4-5
Table
2-1
3-1
4-1
4-2
LIST OF TABLES
Pertinent Data on Plant Design, Operation
and Atmospheric Emissions
Summary of Pertinent Data for the S0~
Absorber Modules
Comparison of Operating Time Parameters
Vertical Module - Mohave - SCE
Comparison of Operating Time Parameters
Horizontal Module - Mohave - SCE
Page
2-3
3-7
4-3
4-5
VI
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SUMMARY
Two prototype sulfur dioxide absorber modules were
installed in 1973 at the Mohave Generating Station of
Southern California Edison Company. A vertical module rated
at 170 MW was installed to treat a 450,000 scfm portion of
the flue gas from Unit 1 and a horizontal module, also rated
at 170 MW, was installed to treat a similar flue gas portion
from Unit 2. Units 1 and 2 are identical boilers each
having a maximum net continuous generating capacity of 790
MW. Each unit burns 390 ton/hr of pulverized coal at full
load. The heat content of the coal is about 11,500 BTU/lb.
The ash and sulfur content are approximately 10 and 0.4
percent, respectively.
The vertical absorber was in the process of starting up
when it was damaged by a fire on January 24, 1974. The unit
was subsequently rebuilt and was restarted for test opera-
tions which were conducted from November 2, 1974, to April
1975. The unit was modified for additional tests which were
completed July 2, 1975.
The horizontal module was operated from November 1,
1973, to January 16, 1974, for shakedown purposes. During a
test program from January 16, 1974 to February 9, 1975, the
vii
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unit operated for 5927 hours in various test modes. This
module has been dismantled and removed from the station.
Particulate and SO- removal efficiencies varied with
the tests that were run. The emission regulation for this
plant is 0.15 Ib/MM BTU for sulfur dioxide. Both absorbers
are preceded by electrostatic precipitators operating at
98.2 percent efficiency, but designed at 97.2 percent
efficiency.
The spent limestone slurry from the vertical absorber
is thickened in a clarifier, vacuum filtered or centrifuged,
and converted to aggregate at an on-site IU Conversion
Systems, Inc. plant. The filtrate water is returned to the
absorber.
The spent lime slurry from the horizontal module was
thickened in a clarifier and pumped to a disposal pond.
Calcilox, a sludge stabilizer manufactured by the Dravo
Corporation, was mixed into the thickened slurry before it
entered the disposal pond. Supernatant liquor was pumped
back from the pond to the absorber. This system operated in
a closed water loop. Estimates of capital and annual operating
costs have not been published.
Pertinent facility and FGD operational data are sum-
marized in the following table.
Vlll
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SUMMARY OF FGD DATA - MOHAVE
Identification
Vertical
module
UOP
Horizontal
module
SCE
Module rating, MW (net)
Fuel
Gross heating value, BTU/lb
Ash, percent
Sulfur, percent
Process
New or retrofit
Start-up date
Start of test program
Efficiency, %
Particulates
so2
Water make-up, gpm/MW (net)
Sludge disposal
170
Coal
11,500
10
0.4
Wet limestone
(lime alternate)
Retrofit
January 1, 1974
November 2, 1974
Not available
Not available
Not available
Converted to
aggregate
170
Coal
11,500
10
0.4
Wet lime
(limestone
alternate)
Retrofit
November 1, 1973
January 16, 1974
Not available
75 - 98
Not available
Stabilized in
sludge pond
IX
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1.0 INTRODUCTION
The Control Systems Laboratory of the U.S. Environ-
mental Protection Agency has initiated a study to evaluate
the performance characteristics and degree of reliability of
flue gas desulfurization (FGD) systems on coal-fired utility
boilers in the United States. This report on the Mohave
Generating Station of the Southern California Edison Company
is one of a series of reports on such systems.
This report is based on information obtained during and
subsequent to a plant survey visit on July 24, 1974.
Section 2.0 presents pertinent data on facility design
and operation including allowable SO- emission rates.
Section 3.0 describes the flue gas desulfurization system
and Section 4.0 analyzes FGD system operating history.
1-1
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2.0 FACILITY DESCRIPTION
The Mohave Generating Station, operated by Southern
California Edison Company (SCE), is located in Clark County,
Nevada, about ten miles north of the southern tip of Nevada.
The plant is situated in a sparsely populated 'desert area.
The Lake Mead National Recreational Area lies 20 miles north
of the plant', and the Fort Mohave Indian Reservation is 10
miles to the south. The plant is jointly owned by the City
of Los Angeles Department of Water and Power, Nevada Power
Company, the Salt River Project Agricultural Improvement and
Power District and Southern California Edison Company.
The station consists of two coal-fired generating
units, each rated at 790 MW (net). The boilers are Combus-
tion Engineering, dry-bottom, pulverized-coal-fired units.
Unit 1 was placed in service in 1970; Unit 2 in 1971.
Low-sulfur coal is transported to the station from the
Black Mesa Mine via a 285-mile slurry pipeline. Average
coal characteristics are 11,500 BTU/lb, 10 percent ash and
0.4 percent sulfur. The maximum fuel s.ulfur content anti-
cipated for this station is about 0.60 percent,, correspond-
ing to a furnace outlet SO^ concentration of about 1.0
SO-/MM BTU. The maximum S00 emissions allowed under the
2-1
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a
Clark County Regulation is 0.15 Ib SO2/MM BTU input to the
boiler.
Research-Cottrell electrostatic precipitators (ESP),
operating with an efficiency of 98.2 percent, provides
primary particulate emission control for each boiler.
The installation of five FGD modules on each boiler at
this station would be necessary to comply with the existing
Clark County regulations. Module selection will be based on
the results obtained from the operation of the two experi-
mental test modules described in this report.
Table 2.1 presents pertinent data on plant design,
operation and atmospheric emissions.
a On May 20, 1975 a new Nevada law became effective which
prohibits the enforcement of the Clark County Air Pollu-
tion Control regulations on the Mohave Generating Station
until July 1, 1977 and requires the State of Nevada En-
vironmental Commission to hold hearings prior to July 1,
1976 for the purpose of reviewing all contaminant emis-
sion standards applicable to fossil-fuel-fired steam
generating facilities.
2-2
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Table 2.1 PERTINENT DATA ON PLANT DESIGN,
OPERATION AND ATMOSPHERIC EMISSIONS
Boiler identification number
Rated generating capacity, MW (net)
Average capacity factor, 1973
Served by stack no.
Boiler manufacturer
Year placed in service
Maximum coal consumption, ton/hr
Maximum heat input, MM BTU/hr
Stack height above grade, ft.
Flue gas rate - maximum, scfm @ 60°F
Flue gas temperature, °F
Emission controls:
Particulate
SO,
(treats 450,000 scfm of
each unit only)
S0_ emission rate:
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
1
790
2
790
1
CE
1970
390
10,000
500
1
CE
1971
390
10,000
500
2,100,000 2,100,000
270 270
electrostatic
precipitator
Vertical
absorber
module
Horizontal
absorber
module
0.15 0.15
Not available
2-3
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3.0 FLUE GAS DESULFURIZATION SYSTEMS
3.1 PROCESS DESCRIPTION
In 0,971 and 1972 eight different pilot plant FGD
systems were tested at the Mohave Station. At the con-
clusion of these tests SCE decided that two prototype FGD
modules should be installed at Mohave, each sized to handle
one-fifth of the gas flow from one of the generators.
Accordingly, a Universal Oil Products Company (UOP) tur-
bulent contact absorber (TCA) vertical module was installed
on Unit 1 to operate using limestone, and a Southern Cali-
fornia Edison four-stage, countercurrent, horizontal unit
was installed on Unit 2 to use a lime slurry. Results of
the operational test programs for these two units will be
used to determine the type of full-scale system that would
be suitable for the station. These results will also be
used to specify equipment for installation at the Navajo
Station to be constructed by the Salt River Project Agri-
cultural Improvement and Power District and possibly for the
Kaiparowitz Station of SCE.
Vertical Module
Flue gas from the ESP on Unit 1 passes through a 5,500
horsepower booster fan before it enters the vertical module
3-1
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shown in Figure 3.1. The UOP unit is designed to treat
450,000 scfm of exhaust gas. The liquid-to-gas contacting
ratio (L/G) for the unit is 83 gallons of limestone slurry
per 1000 scf of flue gas. The design gas velocity through
the unit is 12.6 ft/sec. In its original configuration,
this unit was a four-stage turbulent contact absorber
(TCA). The unit has-subsequently been modified for further
testing. Electric power consumption for the TCA system
amounts to about 3 percent of the total generating capacity
of the station, whereas for the horizontal spray chamber
installation on Unit 2 the electric power consumption is
only about one-half as high (1.5%).
As shown in Figure 3.1, exhaust gas from the Unit 1
boiler passes through an electrostatic precipitator and a
forced draft fan before it enters the TCA. The gas flows
upward through the absorber, passes through a demister which
is washed continuously, and is reheated from 120° to about
175°F by a direct heat exchanger located in the exit duct.
The boiler supplies the steam for this heater.
The rate of limestone addition to the FGD system is
equivalent to about 130 percent of the stoichiometric rate
required for reaction with sulfur dioxide in the gas. Part
of the slurry from the circulation tank is diverted to a
clarifier for thickening. The thickened sludge can be
dewatered either by a vacuum filter or by a centrifuge. The
filtrate is returned to the hold tank, and the dewatered
3-2
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I
u>
MOHAVE GENERATING STATION
160 MW VERTICAL SCRUBBER SYSTEM
Figure 3.1 A simplified sketch of the vertical TCA type
FGD system which is installed on Mohave 1.
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sludge is hauled by truck to an on-site IU Conversion
Systems plant where it is made into aggregate.
Limestone for the FGD system is purchased in ground
form from La Habra Products in Lucerne Valley, California.
There are no limestone milling facilities on-site at
the present time. Instead, finely-ground limestone is
stored in a 300 ton silo. A slurry tank is provided for the
scrubbing system.
Separate control rooms are provided for the horizontal
and vertical absorbers.
Horizontal Module
Flue gas from Unit 2 passes through the ESP and through
a 1750 horsepower booster fan before it enters the hori-
zontal module shown in Figure 3.2. The booster fan require-
ments for this module are less than for the vertical module
due to a decreased pressure drop through the absorber. The
module, designed by SCE, was scaled up from a 1 MW pilot
unit previously tested by SCE. Lime slurry is sprayed from
nozzles in the top of the scrubber perpendicular to the gas
flow. There is no packing in this spray chamber module.
The module consists of four countercurrent stages with fresh
slurry contacting the gas having the lowest SO2 concentra-
tion. The unit operates with an L/G of 20-40 gallons of
slurry per 1000 scf of flue gas. The liquid recirculation
rate can be adjusted over a wide range. The horizontal
module was designed to treat 450,000 scfm of flue gas. The
3-4
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Ul
01
FOUR SCRUBBER STAGES
HOT AIR
INJECTION
BOOSTER FAN
MIST ELIMINATOR
Figure 3.2 A simplified side view of the horizontal
FGD module installed on Mohave 2.
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design gas velocity through the unit is 21.6 ft/sec. Cleaned
flue gas passes through a demister which is washed inter-
mittently on both sides. The gas is then reheated from 120°
to about 175°F by indirect heat exchange with hot air.
Ambient air is preheated to about 400°F and is mixed with
the cleaned gases as they exit from the module. This
causes a 15 to 20 percent dilution of the flue gases. The
boiler supplies the steam for this heater.
The rate of lime addition to the FGD system is about
equivalent to the stoichiometric rate required for reaction
with sulfur dioxide in the gas. Part of the slurry from the
circulation tanks is pumped to a thickener and the underflow
is then pumped to a lined pond, fixed with Calcilox supplied
by Dravo, and allowed to settle. Supernatant water from the
pond is recirculated to the horizontal module. The unit
operates on a closed water loop; the only water leaving the
system consists of water in the exit flue gas, water of
hydration in the gypsum product, and a small amount of water
(3% of total water leaving) evaporated in the sludge pond.
The present goal is to produce a sludge that will
achieve a hardness sufficient to support a load of 2-4 tons
per square foot within three months. Table 3.1 summarizes
operating design parameters and specifications for the two
FGD modules.
3-6
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Table 3.1 SUMMARY OF PERTINENT DATA
FOR THE SO2 ABSORBER MODULES
Vertical
module
Horizontal
module
L/G ratio, gal./lOOO scfm
Superficial gas velocity,
ft/sec
Equipment sizes, ft.
Equipment internals
Material of construction
Shell
Internals
83
12.6
18 x 40
x 90 high
4 stages of
ping pong
balls
rubber lined
polypropylene/
inconel
20 to 40 for
each of four
stages
21.6
15 x 30
x 60 long
sprays
various linings
none
3-7
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3.2 INSTALLATION SCHEDULE
Work on the horizontal and vertical modules of the FGD
system at the Mohave Power Plant was initiated in December
1972, and ground was broken in February 1973. Start-up of
the horizontal unit was achieved on schedule November 1,
1973, but a major malfunction of the generating unit oc-
curred on November 9, so that the start of the test program
was delayed until January 16, 1974. Start-up of the ver-
tical unit was January, 1974. However during the last phase
of construction and start-up, on January 24, 1974, a fire
inside the module caused appreciable damage to the internal
rubber lining and other internals, and delayed start of the
test program on that unit until October 31, 1974.
3.3 COST DATA
Data on the capital and annual operating costs of the
FGD installations at the Mohave Plant have not been re-
leased.
3-8
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4.0 FGD SYSTEMS OPERATING HISTORY
4.1 PERFORMANCE TEST PROGRAM
The initial start-up for the vertical module occurred
on schedule on January 1, 1974. However, on January 24,
1974, the module sustained substantial damage from a fire of
undetermined origin. The following repairs were made.
1. All internal structural members were replaced.
2. Deformed shell stiffeners were reinforced.
3. . Distorted wall plates were replaced.
4. Internal piping was repaired or replaced.
5. Damaged internals, including demister and grid
sections, were repaired or replaced.
6. Structural distortions were corrected.
7. Access door flanges were straightened or replaced.
8. Structural reinforcement was added.
9. Reheater supports were added.
10. Shell was sandblasted and relined with neoprene,
replacing chlorobutyl rubber that had been used
originally.
11. Distorted gratings and walkways were repaired or
replaced.
12. Reheater shell was replaced.
Repair costs were estimated to be $1.6 million. Start of
the test program was delayed until October 31, 1974.
4-1
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Preliminary tests preceded start-up, and a formal test
program was initiated on November 2, 1974. The program was
concluded on April 30, 1975 with 2342 hours of operation,
after which the system was shut down for modifications to a
grid packed tower for additional tests. The overall operating
time ratio for the system defined as the time the module
operated as a percentage of the boiler operating time, was
measured to be 60 percent during the first four months.
Operating time data for-the first four months of the test
program appear in Table 4.1. The reliability of the system
was lower in the first two months of the program than in the
second two months, mainly because of migration of plastic
spheres between adjacent grid compartments in the module, so
that the unit had to be shut down for redistribution of the
spheres and modification of the barrier grids. Other
problems included pump failures, plugged spray nozzles,
deposits on the demister and at the absorber inlet.
SCE operated the horizontal module in a short series of
start-up tests that ended on January 16, 1974, when a formal
test program was initiated to assess the performance and
reliability characteristics of the system. The test program
was concluded on February 9, 1975 after 5927 hours of operation.
Subsequently the module has been dismantled and is being
installed for tests at the Four Corners Plant operated by
Arizona Public Service Company in Farmington, New Mexico.
4-2
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Table 4.1 COMPARISON OF OPERATING TIME PARAMETERS
VERTICAL MODULE - MOHAVE - SCE
Month
11/74
12/74
1/75
2/75
Overall
Operating
time ratio3
46
39
78
84
60
Reliability
50
51
85
84
67
Availability0
39
51
80
88
64
Una vail 5
ability0
34.5
30.8
9.9
11.8
21.8
FGD system actual operating time as a percentage of
Unit 1 operating time.
Actual FGD system operating time as a percentage of the
time that the system was called upon to operate.
Time FGD system was available to operate (whether or
not operated) as a percentage of calendar time.
Time FGD system was unavailable to operate when called
upon to operate as a percentage of calendar time.
4-3
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During the one-year program ten separate test blocks
were conducted to obtain performance and operating data.
Both lime and limestone reagents were tested. SO- spiking
tests were also used to simulate the conditions with higher
percent sulfur -in the coal. Details of the SO- and particulate
removal performance for this system were presented at the
Atlanta symposium held by EPA in November, 1974. SO-
removal efficiency as a function of the L/G ratio, shown in
Figure 4.1, ranged between 76 and 98 percent.
The overall operating time ratio for the system, defined
as the time the FGD system operated as a percentage of the
boiler operating time, was measured to be 73.5 percent
during the one-year operation test. Month-by-month operating
time data, as published by SCE, appear in Table 4.2.
Mechanical problems occurred during the test period.
These problems included pump failures, a thickener underflow
drain obstructed by a hard hat, fan alignment problems,
scrubber spray nozzle failures, scrubber shell leaks and
demister blade warping. In addition, a boiler makers strike
occurred during the test period.
Weir, Alexander, Jr., et al, "The Horizontal Cross Flow
Scrubber", Proceedings: Symposium on Flue Gas Desulfurization
Atlanta, November 1974, EPA Publication No. EPA 650/2-74-126a,
pp 357-387.
4-4
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100
95
90
*« 85
*
o 80
CM
O
fcO
70
60
50
40
30
20 —
10 —
(Courtesy -Southern Californie Edison Co.)
1
0.38% SULFUR COAL
I 1
0 5 10 15 20
L/6, gpm/1000 scfm
Figure 4.1 S02 Removal vs L/G Ratio
170 MW Horizontal Module.
25
30
4-5
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Table 4.2 COMPARISON OF OPERATING TIME PARAMETERS
HORIZONTAL MODULE - MOHAVE - SCE
Month
1/74
2/74
3/74
4/74
5/74
6/74
7/74
8/74
9/74
10/74
11/74
12/74
1/75
2/75
Total
Operating
time ratio3
0.89
0.82
0.73
0.91
0.81
0.79
0.79
1.00
0.58
0.74
0.35
0.52
0.81
0.56
0.74
Reliability
89
82
85
99
92
79
79
100
100
74
40
98
87
56
87
Availability01
89
60
80
99
93
77
63
100
100
68
46
99
90
56
81
Unavail-
abilitya
11
13
12
1
7
20
17
0
0
19
52
1
10
44
13
FGD system actual operating time as a percentage of
Unit 2 operating time.
Actual FGD system operating time as a percentage of the
time that the scrubbing system was called upon to operate.
Time FGD system was available to operate (whether
or not operated) as a percentage of calendar time.
Time FGD system was unavailable to operate when called
upon to operate as a percentage of calendar time.
4-6
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APPENDIX A
PLANT SURVEY FORM
A-l
-------
PLANT SURVEY FORM
NON-REGENERABLE FGD PROCESSES
A. COMPANY AMD PLANT INFORMATION
1. COMPANY NAME Southern California Edison
2. MAIN OFFICE Rosemead, California
3 . PLANT MANAGER G.L. Fraser
4 . PLANT NAME Mohave Generating Station
5. PLANT LOCATION Laughlin, Nevada
6. PERSON TO CONTACT FOR FURTHER INFORMATION Dr. A. Weirf Jr.
Principal Scientist for
7. POSITION Air Quality
8. TELEPHONE NUMBER (213) 572-2785
1899 Johnson
9. DATE INFORMATION GATHERED
10. PARTICIPANTS IN MEETING AFFILIATION
Mr. John Johnson Southern California Edison
Mr. Dick Ynnng Southern California Edison
Environmental
Mr. Wade Ponder Protection Agency
Environmental
Mr. John Busik Protection Agency
Mr. Tim Devitt PEDCo-Environmental
Mr. Fouad Zada PEDCo-Environmental
Mr. Tom Ponder PEDCo-Environmental
NOTE: Data in body of report have been updated subsequent to
the collection of data for Appendix A.
A-2
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B. PLANT DATA. (APPLIES TO ALL BOILERS AT THE PLANT).
CAPACITY, MW
SERVICE (BASE, PEAK)
FGD SYSTEM USED
BOILER NO.
1
7Q0
Base
None
2
7QQ
Base
None
C. BOILER DATA. COMPLETE SECTIONS (C) THROUGH (R) FOR EACH
BOILER HAVING AN FGD SYSTEM.
1. BOILER IDENTIFICATION NO.
2. MAXIMUM CONTINUOUS HEAT INPUT
5
6
19066:22266
20,000
MAXIMUM CONTINUOUS GENERATING CAPACITY
790
MM BTU/HR
MW
4. MAXIMUM CONTINUOUS FLUE GAS RATE. 4.200.000 SCFM @ 60°F
BOILER MANUFACTURER Combustion Engineering
YEAR BOILER PLACED IN SERVICE 1970 & 1971
7. BOILER SERVICE (BASE LOAD, PEAK, ETC.) Base Load
8 . STACK HEIGHT 500'
9. BOILER OPERATION HOURS/YEAR (197 )
10. BOILER CAPACITY FACTOR * N/A
11. RATIO OF FLY ASH/BOTTOM ASH
Available
N/A
* 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 %
MAX.
12.000
MIN.
11.000
AVG.
11.500
0.38
10.03
2. FUEL OIL ANALYSIS (exclude start-up fuel)
GRADE
S %
ASH %
E. ATMOSPHERIC EMISSIONS
1. APPLICABLE EMISSION REGULATIONS
a) CURRENT REQUIREMENTS
AQCR PRIORITY CLASSIFICATION
CLARK COUNTY APCD
REGULATION & SECTION NO.
MAX. ALLOWABLE EMISSIONS
LBS/MM BTU (County)
b) FUTURE REQUIREMENTS,
COMPLIANCE DATE
REGULATION & SECTION NO.
MAXIMUM ALLOWABLE EMISSIONS
LBS/MM BTU
PARTICULATES
SO-
26-2A, B, C
0.064
26-2D
0.15
June 30, 1977
June 30, 1977
June 30, 1977
June 30, 1977
June 30, 1977
June 30, 1977
PLANT PROGRAM FOR PARTICULATES COMPLIANCE
Test Modules Program then install Production Scrubbers,
See EPA Order - See July 9, 1974 Clark County Order
3. PLANT PROGRAM FOR SO2 COMPLIANCE
A-4
5/17/74
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F. PARTICULATE REMOVAL
1. TYPE
MANUFACTURER
EFFICIENCY: DESIGN/ACTUAL
MAX. EMISSION RATE* LB/HR
GR/SCF
LB/MMBTU
MECH.
E.S.P.
Research
Cot'tr^ll
97.2/98.2
FGD
DESIGN BASIS, SULFUR CONTENT
0.5
G. DESULFURIZATION SYSTEM DATA
1. PROCESS NAME
2. LICENSOR/DESIGNER NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
To Be Determined
3. ARCHITECTURAL/ENGINEERS, NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
4. PROJECT CONSTRUCTION SCHEDULE:
a) DATE CF PREPARATION OF BIDS SPECS.
b) DATE OF REQUEST FOR BIDS
c) DATE OF CONTRACT AWARD
d) DATE ON SITE CONSTRUCTION BEGAN
e) DATE ON SITE CONSTRUCTION COMPLETED
f) DATE OF INITIAL STARTUP
g) DATE OF COMPLETION OF SHAKEDOWN
*At Max. Continuous Capacity
A-5
DATE
5/17/74
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5. LIST MAJOR DELAYS IN CONSTRUCTION SCHEDULE AND CAUSES:
6. NUMBER OF SO2 SCRUBBER TRAINS USED
7. DESIGN THROUGHPUT PER TRAIN, ACFM @ °F
8. DRAWINGS: 1) PROCESS FLOW DIAGRAM AND MATERIAL BALANCE
2) EQUIPMENT LAYOUT
H. SO2 SCRUBBING AGENT - To be Determined
1. TYPE
2. SOURCES OF SUPPLY
3. CHEMICAL COMPOSITION (for each source)
SILICATES
SILICA
CALCIUM CARBONATE
MAGNESIUM CARBONATE
4. EXCESS SCRUBBING AGENT USED ABOVE
STOICHIOMETRIC REQUIREMENTS
5. MAKE-UP WATER POINT OF ADDITION
6. MAKE-UP ALKALI POINT OF ADDITION
A-6 5/17/74
-------
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ST.-
TO TS3IKS
FROM TRAINS
SOj SCRUBBIR1 ' 1 fi>, T
fcyys.-s?h^1
f V 5r^' — -'• <^^^^
r-J
FVFROM TR
1 e
SLUDGE TO
DISPOSAL SITE
CIEAH CAS 10 STACK
ff)
WATER MAKEUP
@
TO TRAINS
TO TRAINS
LIME/LIMESTONE SLURRY
STREAM NO.
RATE. Ib/hr
flCFM
CPM
PARTICIPATES. Ib/hr
S02. Ib/hr
TEMPERATURE. °F
TOTAL SOLIDS. =o
SPECIFIC GRAVITY.
CO
CO
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CO
-
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,
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CO
CO
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CO
f
C"D
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STREAM NO.
RATE. Ib/hr
ACFM
CPM
PARTICIPATES. Ib/hr
S02 . Ib/hr
TEMPERATURE. °F
TOTAL SQLIOS . %
SPECIFIC GRAVITY
CM)
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I. Representative flow rates based on operating data at maximum continuous load
5/17/7.
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J. SCRUBBER TRAIN SPECIFICATIONS - To be determined
1. SCRUBBER NO. 1
TYPE (TOWER/VENTURI)
LIQUID/GAS RATIO, G/MCF @
'GAS VELOCITY THROUGH SCRUBBER, FT/SEC
MATERIAL OF CONSTRUCTION
TYPE OF LINING
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.).
NUMBER OF STAGES
TYPE AND SIZE OF PACKING MATERIAL
PACKING THICKNESS PER STAGED
MATERIAL OF CONSTRUCTION, 'PACKING:
SUPPORTS:
SCRUBBER NO. 2 - Same as Scrubber No. 1
TYPE (TOWER/VENTURI)
LIQUID/GAS RATIO, G/MCF @ °F
GAS VELOCITY THROUGH SCRUBBER, FT/SEC
MATERIAL OF CONSTRUCTION
TYPE OF LINING
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.)
NUMBER OF STAGES
TYPE AND SIZE OF PACKING MATERIAL
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.
5/17/74
A-8
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PACKING THICKNESS PER STAGE (b)
MATERIAL OF CONSTRUCTION, PACKING:.
SUPPORTS:.
3. CLEAR WATER TRAY (AT TOP OF SCRUBBER)
TYPE
L/G RATIO
SOURCE OF WATER
4. 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
FREQUENCY AND DURATION OF CLEANING
REMARKS
5. REHEATER
TYPE (DIRECT, INDIRECT)
b) For floating bed, packing thickness at rest.
5/17/74
A-9
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DUTY, MMBTU/HR
HEAT TRANSFER SURFACE AREA SQ.FT..
TEMPERATURE OF GAS: IN OUT
HEATING MEDIUM SOURCE
TEMPERATURE & PRESSURE
FLOW RATE LB/HR
REHEATER TUBES, TYPE AND
MATERIAL OF CONSTRUCTION
REHEATER LOCATION WITH RESPECT TO DEMISTER.
METHOD OF CLEANING
FREQUENCY AND DURATION OF CLEANING __
FLOW RATE OF CLEANING MEDIUM LB/HR
REMARKS
SCRUBBER TRAIN PRESSURE DROP DATA INCHES OF WATER
PARTICULATE SCRUBBER
S02 SCRUBBER
CLEAR WATER TRAY
DEMISTER
REHEATER
DUCTWORK
TOTAL FGD SYSTEM
A-10 5/17/74
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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 - TO Be Determined
LIME/LIMESTONE SLURRY MAKEUP TANK
PARTICULATE SCRUBBER EFFLUENT
HOLD TANK (a)
SO2 SCRUBBER EFFLUENT HOLD
TANK (a)
pH
%
Solids
Capacity
(gal)
Hold up
time
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
T/HR
A-ll
5/17/74
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SLURRY CONCENTRATION IN MILL
CALCINING AND/OR SLAKING FACILITIES
SOURCE OF WATER FOR SLURRY MAKE UP OR
SLAKING TANK
M. DISPOSAL OF SPENT LIQUOR _ To Be Determined
1. SCHEMATICS OF SLUDGE & FLY ASH DISPOSAL METHOD
(IDENTIFY QUANTITIES OR SCHEMATIC)
2. CLARIFIERS (THICKENERS)
NUMBER
DIMENSIONS
CONCENTRATION OF SOLIDS IN UNDERFLOW
3. ROTARY VACUUM FILTER
NUMBER OF FILTERS
CLOTH AREA/FILTER
CAPACITY TON/HR (WET CAKK)
CONCENTRATION OF SOLID'S IN CAKE
PRECOAT (TYPE, QUANTITY, THICKNESS)
REMARKS
4. SLUDGE FIXATION
POINT OF ADDITIVES INJECTION
FIXATION MATERIAL COMPOSITION
FIXATION PROCESS (NAME)
FIXATION MATERIAL REQUIREMENT/TONS OF DRY SOLIDS OF SLUDGE
5/17/74
A-12
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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 - To Be Determined
POND/LANDFILL SIZE REQUIREMENTS, ACRE-FT/YR
IS POND/LANDFILL ON OR OFFSITI3
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 - To Be Determined
1. TOTAL INSTALLED CAPITAL COST
2. ANNUALIZED OPERATING COST
5/17/74
A-13
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3.
COST BREAKDOWN
COST ELEMENTS
CAPITAL COSTS
SO- SCRUBBER TRAINS
2
LIMESTONE MILLING
FACILITIES
SLUDGE TREATMENT &
DISPOSAL POND
SITE IMPROVEMENTS
LAND, ROADS, TRACKS,
SUBSTATION
ENGINEERING COSTS
CONTRACTORS FEE
INTEREST ON CAPITAL-
DURING CONSTRUCTION
ANNUALIZED OPERATING COST
FIXED COSTS
INTEREST ON CAPITAL
DEPRECIATION
INSURANCE & TAXES
LABOR COST
INCLUDING OVERHEAD
VARIABLE COSTS
RAW MATERIAL
UTILITIES
MAINTENANCE
INCLUDED IN
ABOVE COST
ESTIMATE
YES NO
EH EH
EH o
EH EU
1 1
EH EH
ED EH
EH EH
EH EH
EH EH
EH EH
EH EH
EH EH
IH EH
EH EH
ESTIMATED AMOUNT
OR % OF TOTAL
INSTALLED CAPITAL
COST
A.
B.
A-14
5/17/74
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4. COST FACTORS
a. ELECTRICITY
b. WATER
C. STEAM (OR FUEL FOR REHEATING)
d. FIXATION COST
e. RAW MATERIAL PURCHASING COST
f. LABOR: SUPERVISOR
OPERATOR
OPERATOR HELPER _.
MAINTENANCE
$/TON OF DRY SLUDGE
$/TON OF DRY SLUDGE
_ HOURS/WEEK WAGE
O. MAJOR PROBLEM AREAS: (CORROSION, PLUGGING, ETC.)
To Be Determined
1. S02 SCRUBBER, CIRCULATION TANK AND PUMPS.
a.
PROBLEM/SOLUTION.
2. DEMISTER
PROBLEM/SOLUTION.
3. REHEATER
PROBLEM/SOLUTION.
A-15
5/17/74
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4. VENTURI SCRUBBER, CIRCULATION TANKS AND PUMPS
PROBLEM/SOLUTION
5. I.D. BOOSTER FAN AND DUCT WORK
PROBLEM/SOLUTION
6. LIMESTONE MILLING SYSTEM OR LIME SLAKING
PROBLEM/SOLUTION
7. SLUDGE TREATMENT AND DISPOSAL
PROBLEM/SOLUTION
5/17/74
A-16
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8. MISCELLANEOUS AREA INCLUDING BYPASS SYSTEM
PROBLEM/SOLUTION
P. DESCRIBE FACTORS WHICH MAY NOT MAKE THIS A REPRESENTATIVE
INSTALLATION
Q. DESCRIBE METHODS OF SCRUBBER CONTROL UNDER FLUCTUATING
LOAD. IDENTIFY PROBLEMS WITH THIS METHOD AND SOLUTIONS.
IDENTIFY METHOD OF pH CONTROL AND LOCATION OF pH PROBES.
A-17 5/l7/74
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R. COMPUTATION OF FGD SYSTEM AVAILABILITY FACTOR
BOILER RATING OR MAXIMUM CONTINUOUS CAPACITY, MW
PERIOD
MONTH/YEAR
FLUE GAS DESULFURIZATION MODULES
MODULE A
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE B
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE C
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE D
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
CO
Availability factor computation: 1.
Divide boiler capacity by the number of modules
and obtain MW/module = x
Multiply boiler capacity by number of hours
during period = a
Add all down times due to module trouble for all modules
during period = b
Add all down times due to boiler trouble or reduction
in electricity demand for all modules during period = c
Availability factor = [a " X_(b+c)]100 = %
ci ~ ]t C
5/17/74
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TECHNICAL REPORT
(Please read Instructions on the reverse
DATA
before completing)
1 REPORT NO.
EPA-650/2-75-057-k
3 RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Survey of Flue Gas Desulfurization Systems
Mohave Station, Southern California Edison Co.
5 REPORT DATE
October 1975
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)
Gerald A. Isaacs and Fouad K. Zada
I. 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 6k
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
Task Final: 7/74-9/75
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT Tne report givcs results of a survey of the flue gas desulfurization (FGD)
systems at Southern California Edison's Mohave Generating Station. Two prototype
170 MW SO2 absorber systems were installed: a vertical module treated a portion of
the flue gas from boiler unit 1; and a horizontal module treated a similar flue gas
portion from unit 2. Each unit has a maximum net generating capacity of 790 MW,
burning coal with a heat content of about 11,500 Btu/lb. Ash and sulfur contents of
the coal are about 10 and 0.4 percent, respectively. The vertical absorber was
damaged by fire during startup on January 24, 1974. After repairs, test operations
were conducted from November 2, 1974, to April 1975. The unit was then modified
for additional tests which were completed on July 2, 1975. The horizontal module,
after operating for 5927 hours in various test modes from January 16, 1974, to
February 9, 1975, was dismantled and removed from the Station. Particulate and
SO2 removal efficiencies varied with the tests that were run. Emission regulation
for this plant is 0.15 Ib/MM Btu for SO2. Both absorbers are preceded by electro-
static precipitators. Spent slurry from each absorber was dewatered and
stabilized, and the water was returned to the FGD system. Estimates of capital and
operating costs have not been published.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution Coal
Flue Gases Combustion
Desulfurization Electrostatic Precip-
Sulfur Dioxide itators
Absorbers (Equipment)
Columns (Process
E ngineering)
Air Pollution Control
Stationary Sources
Particulate
Horizontal Absorber
Vertical Absorber
13B
21B
07A,07D
07B
2 ID
13. DISTRIBUTION STATEMENT
Unlimited
19 SECURITY CLASS (This Report)
Unclassified
21. NO OF PAGES
46
20 SECURITY CLASS (Thispage)
Unclassified
22 PRICE
EPA Form 2220-1 (9-73)
A-19
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