EPA-650/2-75-057-B
July 1975
Environmental Protection Technology Series
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
LA CY6NE STATION, KANSAS CITY POWER AND LIGHT CO.
AND KANSAS GAS AND ELECTRIC CO.
U.S. Environmental Protection Agency
Office of Research and Development
Washington, D. C. 20460
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EPA-650/2-75-057-B
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
LA CYGNE STATION, KANSAS CITY POWER AND LIGHT CO,
AND KANSAS GAS AND ELECTRIC 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 6b
ROAP No. 21ACX-130
Program Element No. 1AB013
EPA Project Officer: Norman Kaplan
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON, D.C. 20460
July 1975
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EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center - Research Triangle Park, Office of Research and Development,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
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
Lo 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-b
11
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TABLE OF CONTENTS
Page
LEST OF FIGURES iv
LIST OF TABLES iv
ACKNOWLEDGMENT v
SUMMARY Vi
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 Design Parameters 3-5
3.3 Installation Schedule 3-8
3.4 Cost Data 3-8
4.0 FGD SYSTEM PERFORMANCE ANALYSIS 4-1
4.1 General Discussion 4-1
4.2 Start-up Problems, Solutions and Cost 4-4
4.3 Process Modifications for Future 4-8
Installations
APPENDIX A PLANT SURVEY FORM A-l
APPENDIX B PLANT PHOTOGRAPHS B-l
APPENDIX C OPERATING DATA C-l
11]
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LIST OF FIGURES
Figure Page
3.1 Flow Diagram of One of the Seven FGD Modules 3-2
LIST OF TABLES
Table Page
2.1 Pertinent Data on Plant Design, Operation 2-3
and Atmospheric Emissions
3.1 Summary of Data: Particulate and S02 3-6
Scrubbers
3.2 Summary of Data: FGD System Hold Tanks 3-7
3.3 Typical Pressure Drop Across Components 3-7
of FGD Train
4.1 Availability Summary - La Cygne, 1974 4-3
IV
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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.
Initial project officer for the U.S. Environmental Protection
Agency was Mr. Wade H. Ponder. Information and data on
plant operation were provided during and subsequent to the
survey visit by Mr. Cliff McDaniel, Kansas City Power &
Light Company, and by Mr. Jack Stewart, Babcock and Wilcox,
Incorporated. 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.
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SUMMARY
The wet limestone flue gas desulfurization system at
the La Cygne Power Station of the Kansas City Power and
Light Company was designed and installed by The Babcock and
Wilcox Company. It was built as an integral part of the
electric power generating facility.
The system consists of seven particulate and SO-
scrubbing modules, with on-site limestone grinding and
storage facilities. All flue gases are treated, and the
ductwork does not provide for the bypassing of flue gas
around the modules.
Since the system was first placed in service in February
1973, several modifications have been made to alleviate the
many operating problems associated with an undertaking of
this magnitude. At the present time, a particulate efficiency
of 97 to 99 percent is being attained. The SO- removal
efficiency ranges between 70 and 83 percent.
The spent limestone slurry is discharged to a 160-acre
pond. Water from the pond is recycled for use in the
process.
The initial installed capital cost of the flue gas
desulfurization system was $34 million, or $41/KW (based on
a net rated capacity of 820 MW). Subsequent equipment modi-
-------
fications have increased the cost to about $45 million or
$55/KW. The estimated cost for maintenance and operation of
the system, including limestone, is 1.79 mills/KWH. This
figure does not include any capital charge to account for
amortization, interest or taxes.
Pertinent data on the facility and the FGD system are
presented below.
SUMMARY OF FGD DATA, LA CYGNE POWER STATION
Unit rating, MW (net)
Fuelr
BTU/lb
Ash, percent
Sulfur, percent
FGD vendor
Process
New or retrofit
Start-up date
FGD modules
Efficiency, percent:
Particulates
so2
Sludge disposal
Unit cost
820
Coal
8,200 to 10,200
20-30
5-6
Babcock and Wilcox
Wet limestone scrubbing
New
February 1973
7
97-99
70-83
Unstabilized sludge
disposed in unlined pond.
Capital, $55/KW; operating
cost estimated at 1.79 mills/
KWH, not including amortization,
taxes, and insurance.
VI3.
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1.0 INTRODUCTION
The Control Systems Laboratory of the U.S. Environ-
mental Protection Agency (EPA) has initiated a study to
evaluate the performance characteristics and degree of
reliability of flue gas desulfurization (FGD) systems on
coal-fired boilers in the United States. This report on the
La Cygne Power Station of Kansas City Power and Light Company
(KCP&L) is one of a series of reports on such systems, which
presents values of key process design and operating parameters,
describes the major start-up and operational problems encountered
at the facility and the measures taken to alleviate such
problems, and identifies the total installed and annualized
operating costs.
This report is based upon information obtained during a
plant inspection on June 5, 1974, and on data provided by
KCP&L and Babcock and Wilcox (B&W) personnel during that
visit and subsequent to it.
Section 2.0 presents pertinent data on facility design
and operation, including actual and allowable particulate
and SO_ emission rates. Section 3.0 describes the FGD
system, and Section 4.0 analyzes FGD system performance.
Appendices present details of plant and system operation and
photos of the installation.
1-1
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2.0 FACILITY DESCRIPTION
The La Cygne Power Station of KCP&L is a new station.
It is located about 55 miles south of Kansas City, in Linn
County, Kansas. The terrain around the station is relatively
flat pasture land, and there is no other major industry in
the area. The nearest populated area is the town of La Cygne,
about 6 miles west of the station. The boiler was first
fired in December, 1972. The power generating facilities
were placed in service on May 31, 1973.
The electric power generating facilities consist of one
6,200,000 Ib steam/hr, coal-fired, base-load boiler with
associated 820 MW (net) steam turbine and electric generator.
The plant also has three oil-fired boilers, used primarily
for start-up of the large unit, but also to supply steam to
a 22 MW house turbine generator.
The boiler at La Cygne, designed by B&W is a wet-
bottom, cyclone-fired unit. The pollution control equipment
on this boiler, which consists of seven scrubbing modules,
was also built by B&W as an integral part of the power
generating facilities. Bypassing of the boiler's flue gas
around the FGD system is not possible. The La Cygne Power
Station uses about 50 MW from its gross generating capacity
of 870 MW to operate the station equipment including the FGD
system.
2-1
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The coal now being burned ranges in gross heating value
(as-received) between 8200 and 10,200 BTU per pound. Ash
and sulfur range 20-30 percent and 5-6 percent, respectively.
The maximum particulate emission allowed under the
Kansas State Department of Health and Environment Regulation
No. 28-19-31-A is 0.13 Ib/MM BTU of heat input to the
boiler. The present atmospheric emission of particulates
from the FGD system is equivalent to 0.15 Ib/MM BTU.
Atmospheric emissions of sulfur dioxide are limited by
Regulation No. 28-19-31-C, under which the maximum allowable
emission of sulfur dioxide is 1.5 Ib/MM BTU of heat input to
the boiler. The present S02 emission rate from the La Cygne
station, based on 80 percent removal efficiency in the FGD
system, is equivalent to about 2 Ib/MM BTU. This figure is
based on 95 percent conversion of sulfur to sulfur dioxide.
Table 2.1 presents pertinent data on plant design,
operation, and atmospheric emissions.
2-2
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Table 2.1 PERTINENT DATA ON PLANT DESIGN, OPERATION
AND ATMOSPHERIC EMISSIONS
Maximum generating capacity, MW (net)
Boiler capacity factor (1974), %
Served by stack No.
Boiler manufacturer
Year placed in service
Maximum coal consumption, ton/hr
Maximum heat input, MM BTU/hr
Unit heat rate, BTU/KWH
Stack height above grade, ft.
Flue gas rate-maximum, acfm
Flue gas temperature, °F
Emission controls:
Particulate
S02
Particulate emission rate:
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
SO- emission rate:
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
820
21
1
B&W
1973
404
7676
9360
700
2,760,000
285
Venturi scrubber
Venturi scrubber
and countercurrent
tray absorber tower
0.13
0.15
1.5
2
2-3
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3.0 FLUE GAS DESULFURIZATION SYSTEM
3.1 PROCESS DESCRIPTION
The FGD system consists of seven identical scrubbing
modules (one is shown in Figure 3.1) with a venturi scrubber
for particulate emission control and an absorber tower for S02
emission control. Each module treats about one-seventh of
the total flue gas from the coal-fired boiler, or about
394,300 acfm. As the hot flue gas enters the venturi, it is
subjected to jets of limestone slurry injected through
nozzles on the walls of the vessel. The liquid-gas stream
flows downward through the venturi throat restriction, where
the gas molecules contact the atomized liquid droplets. The
scrubbing efficiency is regulated by adjusting the venturi
throat gap. As the gas exits from the venturi and enters
the disengagement chamber, its velocity decreases from about
130 ft/sec (at the throat) to about 15 ft/sec. This reduction
in velocity separates the limestone slurry droplets from the
quenched gas. The slurry drains into the recirculation
tank. The gas enters the S02 absorber tower at the base and
moves upward through two sieve trays in series. As the gas
passes through the 1 3/8-inch-diameter holes of the sieve
trays, it contacts a shower of limestone slurry, which is
sprayed in the path of the rising gas. The scrubbed gas
3-1
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IU
FLUE GAS FROM
AIR HEATER STEAM r
394,300 acfm
AT 285°F
HYDROCLONE
800 gpm
SLUDGE
TO POND
V7
REHEATER
r HOT AIR FROM (NOT USED IN
f \ AIR HEATER »D" MODULE)
t I
1 IJ— DEMISTER
WM$>$\ 2100 gpm (INTERMITTENT)
DEHISTER
\lf
\
VENTURI
J. J. -L J_ J. _1
^
S02 ABSORBER
SCREEN
5000 gpm
--T'
VENT
D-HD
140 gpm (CONTINUOUS)
KWATER WASH
STAGE
CH-Q
RECIRCULATION
TANK pH 5.8
WATER FROM POND
9000 gpm
LLIMESTONE SLURRY
WATER MAKE UP
Figure 3.1 Flow diagram of one of the seven
FGD modules.
3-2
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then passes through a third sieve tray which collects slurry
carryover and reduces the load on the demister. The gas
then passes through a 10-inch high "Z" shape demister where
the remaining fine droplets coalesce and drip back down
through the gas stream into the recirculation tank. Two of
the seven modules also incorporate a second stage demister.
The flue gas is then reheated from about 121° to 175°F.
Reheating is accomplished primarily by means of steam coils,
with additional heat provided by injecting hot air from the
boiler combustion air heater. This latter practice, which
was not included in the original design of the system, has
reduced the net generating capacity of the unit by approximately
30 to 60 MW. The additional reheat was found to be necessary
to prevent deterioration of the reheat steam coils. Finally
the reheated gas enters a plenum common to all modules and
is discharged to the stack through induced-draft fans.
The venturi and the absorber tower of each module share
a common limestone slurry recirculation tank, in which the
pH is maintained between 5.5 and 6.0. The pH is monitored
by means of a cell located in the slurry feed to the venturi
nozzles. The limestone solids content of the slurry at this
point is about 10 percent. Bags of lime are stored nearby
for manual addition to the slurry if its acidity increases
because of low quality limestone.
For removal of large particles of scale from the re-
circulated liquor, a liquid cyclone has been installed on
each module. These liquid cyclones centrifugally separate
3-3
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the large particles of scale from the liquor and discharge
them to the recirculation tank through a screen. This helps
prevent plugging of nozzles and strainers and reduces erosion
in pumps, pipes, and nozzles.
The liquid level in the recirculation tank is maintained
by pumping excess liquor to the sludge disposal pond; this
plant requires no facilities for sludge treatment or fixation.
The 160-acre pond is estimated to be sufficient for four
years of production at rated boiler capacity.
Limestone is ground on site. A 60,000 ton supply of
limestone rocks is maintained near the coal storage area.
The limestone is transported intermittently to the mill by
the coal conveyor system. Two wet ball mills, each rated at
108 ton/hr are housed in a building that also contains two
limestone holding tanks. The seven scrubbing modules are
located inside a building between the boiler and the stack.
3.2 DESIGN PARAMETERS
The FGD installation was designed with venturi and
turbulent contact absorber (TCA) towers for fly ash and S02
removal. Many major modifications in the system have since
altered some of the original design parameters; the following
description represents current operating conditions.
The venturi scrubber operation was originally designed
for a liquid-to-gas ratio (L/G) of 18 gallons per 1000 cubic
feet of gas. Since installation of the hydroclone unit,
however, the pressure head of the recirculation pump has
increased so that the L/G is only about 12 gallons per 1000
3-4
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cubic feet of gas. The liquid recirculation rate is 4000
gpm. Gas velocity through the venturi throat is about 150
ft/sec with the throat wide open.
The SO- absorber tower is designed for an L/G of about
26.5 gallons per 1000 cubic feet of gas. Gas velocity
through the demister section of the tower is 8.4 ft/sec.
Liquid recirculation rate in the absorber tower was designed
for 9000 to 11,000 gpm.
The tower demisters are washed by underspray and over-
spray manifolds. Pond water is used for cleaning. Each
demister is washed continuously with 140 gpm of underspray
water. The overspray operates intermittently at 2100 gpm
for 1 minute during each 8-hour period.
The reheater tube bundles were originally made of 304
stainless steel units. The original design reheater exit
temperature was 147°F. As noted earlier, supplemental
direct heating with hot air injection is presently practiced
on six modules. The remaining module has 4 rows of reheater
bundles with plans calling for the addition of three or four
more to raise the temperature to 175°F.
Tables 3.1, 3.2 and 3.3 summarize operating and design
parameters and specifications for the major components of
the FGD system.
3-5
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Table 3.1 SUMMARY OF DATA:
PARTICIPATE AND SC>2 SCRUBBERS
Venturi scrubber
S02 scrubber
tower
L/G
gallons/1000 acf
Superficial gas
velocity, ft/sec
Dimensions
Equipment internals
Material of
cnnstuction
Shell
Internals
12
147
21-1/2' long x
22" wide
Adjustable throat
316L SS
Throat, Kaocrete
ceramic, venturi
throat blocks
26.5
8.4 (at demister)
32' x 161 x
65' high
Sieve trays (1 3/8-
inch-diameter holes)
316L SS (no liner)
316L SS
3-6
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Table 3.2 SUMMARY OF DATA: FGD SYSTEM HOLD TANKS
Recirculation
tank
Limestone slurry
make-up tank
Total number of tanks
Dimensions, ft
Retention time at
full load, minutes
Temperature, °F
PH
Limestone concentration, %
Total solids concentra-
tion, %
Specific gravity
Material of
construction
30 dia. x 24 high
8
121
5.5-6.0
8 to 10
14
Rubber-lined
carbon steel
36 dia. x 26 high
120
ambient
7.5
20
Rubber-lined
carbon steel
Table 3.3 TYPICAL PRESSURE DROP
ACROSS COMPONENTS OF FGD TRAIN
Equipment
Pressure drop,
inches W.G.
Venturi scrubber
SO- absorber trays
Water wash tray
Demister
Reheater
Ductwork
7
6
1.2
0.2
3.7
4
Total FGD system
22
3-7
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3.3 INSTALLATION SCHEDULE
Construction was started in April 1969 and reached the
halfway point in October 1971 with a construction force of
over 900 men. Unit No. 1 was nearly complete when the
boiler was first fired on December 26, 1972. Construction
was considered complete when the generating unit was declared
commercial on June 1, 1973. There were no major construction
delays. Construction was terminated on schedule.
3.4 COST DATA
The installed capital cost of the FGD system was
initially $34 million, or $41/KW (based on net rated capacity
of 820 MW). Subsequent equipment modifications are expected
to increase this cost to about $45 million or $55/KW. The
present annualized operating cost is about 1.79 mills/KWH.
This figure does not include amortization, interest or taxes.
About 51 people are required to man the scrubber operation
which includes the scrubbers, the induced-draft fans, and
the mill house. This number includes 27 operators and
cleanup men, 1 process attendant, 1 superintendent, 1 engineer
and 16 maintenance men. This is a research manpower situation.
The number of operating personnel may be reduced at a later
date.
3-8
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4.0 FGD SYSTEM PERFORMANCE
4.1 GENERAL DISCUSSION
The FGD installation on the La Cygne Boiler No. 1 has
been plagued with numerous problems since the first trial
operation of the boiler on December 26, 1972. Some of these
problems, such as the vibrations of the induced-draft fans
and their sensitivity to imbalance, appeared even before the
boiler was fired.
When these fabrication problems were corrected and
the FGD system was put in operation, other problems began
to appear. Some of these problems are associated with the
wet limestone process and have been encountered in similar
installations; they include plugging of the demister and
strainers, erosion of spray nozzles, and corrosion of reheater
tubes.
KCP&L recognizes that the high fly ash content of the
flue gas is responsible for a great percentage of these problems.
Operating personnel are now having increased success in minimiz-
ing the effects of fly ash deposits.
A portion of the he'ated boiler combustion air is drawn
from the air heater outlet and bled into the scrubber exhaust
stream ahead of the reheat tube bundles. Capital and operating
costs associated with this system have not been reported,
but the procedure reduces the capacity of the boiler by
4-1
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about 30 to 60 MW, based on a recent full load test. The
bleed in air has been necessary to protect the reheat tube
bundles from corrosion, but is being phased out by installing
reheat tubes of more acid and chloride ion resistant metals.
Because the FGD system includes no spare modules and
cannot be bypassed, output of the boiler is totally con-
trolled by the performance and availability of the FGD
modules. At the present time, each module is shut down
about once per week during off peak hours for cleaning. It is
hoped that the operating period can be extended to minimize
the impact of module shutdown on operation of the system.
The present goal is to reduce the frequency of shutdown to
once every 3 weeks, with all maintenance to be performed by
the night shift.
Availability data for 1974 appear in Table 4.1. For
the year the boiler was on-line 4578 hours, or 52 percent of
the time. Calculating availability as the percent ratio of
FGD module operating hours to boiler operating hours, the
monthly availabilities of individual modules ranged from 23
percent to 100 percent. Yearly module availabilities ranged
from 69 percent to 85 percent. The average module utilization
over the one-year period was 77 percent.
4.2 START-UP PROBLEMS AND SOLUTIONS
Analysis of problems encountered during and since
start-up reveals that nearly all were due to mechanical
design rather than to process chemistry. An account of the
major problems follows.
4-2
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Table 4.1 MODULE AVAILABILITY SUMMARY - LA CYGNE, 1974
Month
January
February
March
April
May
June
July
August
September
October
November
December
Total
Boiler
hours
364
364
332
500
480
313
571
606
662
386
4578
Module hours/availability (%}
Module A
179/49
239/66
222/67
344/69
441/92
236/75
514/90
417/69
472/71
347/90
3411/75
Module B
115/32
247/68
233/70
415/83
402/84
252/80
512/90
532/88
402/61
273/71
3383/74
Module C
161/44
213/59
249/75
390/78
400/83
256/80
415/73
444/73
391/59
230/60
3149/69
Module D
315/87
278/76
293/88
426/85
433/90
253/81
460/81
458/76
535/81
235/61
3686/81
Module E
83/23
189/52
245/74
389/78
393/82
266/85
463/81
503/83
520/79
324/84
3375/74
Module F
133/37
364/100
332/100
422/84
396/83
248/79
448/78
539/89
615/93
327/85
3824/84
Module G
295/81
237/65
291/88
399/80
418/87
241/77
507/99
518/86
588/89
323/84
3817/83
Average
availability3
50
69
—
80
80
86
80
85
81
76
76
—
77%
Does not include module reserve {or standby) time.
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1. Scrubber Modules; The process piping network is
all rubber-lined to protect the carbon steel base from the
abrasive slurry. In general, the rubber liners have performed
well, with only a few reported incidents of wear in the area
of the spent slurry valves. This wear was attributed to the
throttling action of the valve to modulate the flow of
slurry. The problem was solved by operating the valve only
in a completely open or completely closed position.
The venturi pumps on the circulation tanks are also
rubber lined; this lining has been damaged many times,
primarily because of plugging of the strainer at the suction
end of the pump. As the flow ceases or is drastically
reduced because of this plugging, the pump cavitates and the
liner is sucked into the path of the impeller and shred-
ded. The suction strainers plugged frequently. Since
they were located inside the recirculation tank, the tank
had to be drained for cleaning of the strainers. To extend
the life of the limestone slurry spray nozzles on the venturi
scrubber and to reduce wear and erosion in the slurry recircula-
tion loop, a hydroclone was installed in the recirculation
line of each module. This device separates the larger
particles of scale from the main slurry steam by means of
centrifugal action. This modification, made at a cost of
about $13,000 per module, allowed the removal of the strainer
and thereby corrected the pump problems.
In the past the demister trays and the gas reheater
tubes have plugged severely. The demister trays are made up
4-4
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of Z-shaped fiberglass boards. Droplets of slurry are
carried over with the flue gas and are deposited on the
demister trays. As the slurry builds up, the gas flow is
restricted and its velocity through the demister increases.
This leads to solids carryover and deposition on the reheater
tubes. The slurry carryover also reaches the induced-draft
fan and is deposited on its blades.
These interrelated problems of carryover to the demister,
the reheater, and the induced-draft fan have necessitated
many modifications and corrections of operating procedures.
Currently, intermittent heavy overspray and continuous
underspray have kept the demisters relatively clean. Steam
soot blower modifications have been reasonably successful in
maintaining the reheaters and fan washing has been greatly
reduced.
The original reheater tubes (304 SS) began to fail
prematurely because of attack by acid condensate. They are
now being replaced with 316L SS bundles. In order to prevent
acid condensation, hot air headers were installed upstream
of the reheater coils and a hot slip stream from the boiler's
air heater was used to provide the additional reheat capability
to raise the temperature to 190-200°F. It is expected that
the 316L SS reheaters will be able to withstand corrosion at
about 175°F so that the 'boiler air heater bleed requirement
can be reduced or eliminated.
2. Induced-Draft Fans; Since the time these fans were
first balanced in September 1972 they have been a constant
source of trouble. One problem was severe vibration in the
4-5
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fan housing. The fans were initially sensitive to imbalance,
and it was found that the operating speed was close to the
critical speed. The vibrations caused cracks to appear in
the inlet cones, requiring additional stiffeners to strengthen
the housing.
Another problem was the high running temperature of the
thrust collars on the fan bearings. Temperatures reached
the 180°F alarm set point within a short time after the fans
were started. Examination of the bearings revealed that the
thrust collars were not stable. The movement attributed to
air turbulence in the inlet ductwork caused the rotor to
shift from side to side. Several aerodynamic configurations
were tried to eliminate air turbulence. A splitter foil and
directional vanes were installed in the duct and in the fan
inlet box, but the thrust collar continued to overheat and
to move during operation. The temperature increase was
finally controlled by cutting oil grooves in the thrust
collar and installing forced-lubrication systems on all the
fans. These modifications caused the thrust collar temperature
to drop into a range from 140°F to 160°F. Movement of the
thrust collar was checked by installing split backup collars
designed to give an interference fit.
Problems with the induced-draft fans occurred as soon
as the boiler was fired. As mentioned earlier, fly ash and
slurry were carried over from the scrubber and deposited on
the blades of the impeller, aggravating the tendency for the
fan to be out of balance.
4-6
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Fan sensitivity to imbalance was complicated by the fly
ash eroding the fan blades. One blade was found to be nearly
destroyed by erosion. Examination of all the blades by magnaflux
revealed several cracks indicating the need for reinforcment.
By June 1974 all I.D. fan rotors had been exchanged with
units of heavier design. Shaft diameter was increased from
20" to 24". The wheels radial tip blades and side plates
are 5/8" thick instead of 1/4". The thick center plate was
scalloped to hold down the weight and the critical frequency
was moved farther away from the operating speed to reduce
the tendency to vibrate. The leading edge of each blade was
covered with a stainless steel clip to deter erosion. Fly
ash carryover still requires the fans to be washed on an
intermittent basis but the cleaning frequency is being
steadily reduced.
The inlet and outlet dampers of the induced-draft fans
have also suffered erosion from fly ash carryover. Metal on
the dampers has been rewelded or replaced several times.
When deposits have interferred with operation, the dampers
have bound and pins have sheared as a result. Seal air has
been provided to keep the bearings clean.
3. Limestone Conveying System; Limestone rocks and
coal are stored in two separate piles adjacent to each
other. Both materials are transported to the boiler by a
single conveying system, used on a time sharing basis.
Problems created by this arrangement are chiefly logistic,
except delivery chutes are clogged by the fines of proper
4-7
-------
size 3/4" x 0" necessitating the delivery of 2" x 1/8".
This creates other problems because larger steel balls must
be used in the mills; consequently limestone slurry with impro-
per fineness occurs and a greater challenge to good chemistry
results. The addition of a separate limestone delivery system
this fall will alleviate these problems.
4.3 PROCESS MODIFICATIONS FOR FUTURE INSTALLATIONS
B&W personnel who designed the wet limestone FGD
system at the La Cygne power plant, are generally satisfied
with the modifications that have been made to remedy opera-
tional problems. Present plans call for the use of more
reheater tube bundles to raise the temperature of cleaned
gas to the desired level thereby eliminating the hot combustion
air bleed.
Considerable variations in operability, in terms of pH
control, have been observed, with the use of various grades
of limestone. The key factor or ingredient making some
limestones more suitable than others has not yet been completely
identified, but maintaining specified parameters definitely
has minimized the problems of chemistry.
4-8
-------
APPENDIX A
PLANT SURVEY FORMS
A-l
-------
PLANT SURVEY FORM3
NON-REGENERABLE FGD PROCESSES
A. COMPANY AND PLANT INFORMATION
1. COMPANY NAME Kansas City Power and Light
2. MAIN OFFICE Kansas City. Mo.
3. PLANT MANAGER Charles Ryan
4. FGD MANAGER Cliff McDaniel
5. PLANT LOCATION La Cygne, Kansas
6. PERSON TO CONTACT FOR FURTHER INFORMATION Terry Eaton
7. POSITION Results Superintendent
8. TELEPHONE NUMBER
9. DATE INFORMATION GATHERED 6/5/74
10. PARTICIPANTS IN MEETING AFFILIATION
Terry Eaton KCPL (Results Supdt.)
Cliff McDaniel KCPL (FGD Plant Supdt.)
Wade Ponder EPA
John Busik EPA
Tim Devitt PEDCo Environmental
Larry Yerino PEDCo Environmental
Fouad Zada PEDCo Environmental
Dallas Wade (part-time) B&W
aThese data -were obtained on June 5, 1974. Some of the data have been
updated in the text of the report.
A-2
5/17/74
-------
B. PLANT DATA. (APPLIES TO ALL BOILERS AT THE PLANT).
C.
CAPACITY, MW (net)
SERVICE (BASE, PEAK)
FGD SYSTEM USED
BOILER NO.
1
820
Base
Yes
BOILER DATA. COMPLETE SECTIONS (C) THROUGH (R) FOR EACH
BOILER HAVING AN FGD SYSTEM.
1. BOILER IDENTIFICATION NO.
2. MAXIMUM CONTINUOUS HEAT INPUT
La Cygne 1
7676
3. MAXIMUM CONTINUOUS GENERATING CAPACITY
MM BTU/HR
820 MW (net)
4. MAXIMUM CONTINUOUS FLUE GAS RATE. 2,765,000 ACFM @ 285°F
5. BOILER MANUFACTURER B & W
6. YEAR BOILER PLACED IN SERVICE February 1973
7. BOILER SERVICE (BASE LOAD, PEAK, ETC.) Base
8. STACK HEIGHT 700 ft.
9. BOILER OPERATION HOURS/YEAR (1974) 4578
10. BOILER CAPACITY FACTOR * 23%
11. RATIO OF FLY ASH/BOTTOM ASH
30/70
* DEFINED AS: Kwl^ 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 %
2. FUEL OIL ANALYSIS (exclude start-up fuel)
GRADE —
s % --
ASH %
MAX.
—
—
MIN.
AVG.
9500
5.3
25
E. ATMOSPHERIC EMISSIONS
1. APPLICABLE EMISSION REGULATIONS
a) CURRENT REQUIREMENTS
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
MAX. ALLOWABLE EMISSIONS
LBS/MM BTU
b) FUTURE REQUIREMENTS,
COMPLIANCE DATE
REGULATION & SECTION NO.
MAXIMUM ALLOWABLE EMISSIONS
LBS/MM BTU
PARTICULATES
III
Control Reg
0.128
SO-
28-19-31
Kansas Air Pollution Emission
ilation
PLANT PROGRAM FOR PARTICULATES COMPLIANCE
Compliance through refinements of existing FGD system.
3. PLANT PROGRAM FOR S02 COMPLIANCE
Compliance through refinements of existing FGD systems
A-4
5/17/74
-------
F. PARTICULATE REMOVAL
1. TYPE
MANUFACTURER
EFFICIENCY: DESIGN/ACTUAL
MAX. EMISSION RATE* LB/HR
GR/SCF
LB/MMBTU
MECH.
„
E.S.P.
— — ^
FGD
Wet-Limestone
B & W
.If per
1000# gas
DESIGN BASIS, SULFUR CONTENT
G. DESULFURIZATION SYSTEM DATA
1. PROCESS NAME
2. LICENSOR/DESIGNER NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
B & W Wet I. imp stone
B & W
Barberton, Ohio
Carl Hamilton
(216) 753-4511
3. ARCHITECTURAL/ENGINEERS, NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
Same
4. PROJECT CONSTRUCTION SCHEDULE: DATE
a) DATE OF PREPARATION OF BIDS SPECS.
b) DATE OF REQUEST FOR BIDS
c) DATE OF CONTRACT AWARD
d) DATE ON SITE CONSTRUCTION BEGAN April 1969
e) DATE ON SITE CONSTRUCTION COMPLETED _
f) DATE OF INITIAL STARTUP Feb. 1973
g) DATE OF COMPLETION OF SHAKEDOWN June 1, 1973
*At Max. Continuous Capacity
A-5
5/17/74
-------
5. LIST MAJOR DELAYS IN CONSTRUCTION SCHEDULE AND CAUSES:
Construction was on schedule
6.
7.
8.
NUMBER OF S02 SCRUBBER TRAINS USED
DESIGN THROUGHPUT PER TRAIN, ACFM @ 122 °F
340.000
DRAWINGS: 1) PROCESS FLOW DIAGRAM AND MATERIAL BALANCE
2) EQUIPMENT LAYOUT
H. S02 SCRUBBING AGENT
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
Limestone
Local - 2 miles
5 to 7
85% min to 93%
2.5% max
1.7
Wet ball mill -
Recirculation tank
Slurry into Recircula-
tion tank of each module
A-6
5/17/74
-------
S).-
>
I
"|FROM TRAINS
~J
CLEAN CSS TO STACK
z;
*'''2
yi
^
^
0
^ (^2j
WATER MAKEUP
Uo TRAINS
r >-?
" j-TO TRAINS
*-J
®
LIME/LIMESIONE SLURRY
STREAM NO.
RATE. Ib/hr
ACFM
CPM
PAFniCULAUS. Ib/hr
S02- IJ)/hr
TEMPERATURE, °F
TOTAL SOLIOS. %
SPECIFIC GRAVITY,
CO
60,000
80,000
284 °F
C2)
CO
CO
346,000
CO
420fOOC
CO
- , -
... .
CO
CO
CO
(10]
;
1
C1!)
(I?)
~^~
260
20
1
STREAM NO.
RftTE, Ib/hr
ACFM
GPM
PARTICIPATES, Ib/hr
S02 , Ib/hr
TEMPERATURE, °F
IOTAL SOLIDS, %
SPECIFIC GRAVITY
[14)
1750.
20
C'5)
9000
14
(16)
4000
C»i)
Cis)
8QO
14
(J9)
(20]
(21)
(22)
(23)
(24)
(25)
(26)
I. Representative flow rates based on operating data at maximum continuous load
5/17/'
-------
J. SCRUBBER TRAIN SPECIFICATIONS
1. SCRUBBER NO. 1
midpoint on sump
TYPE OF LINING None
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.) m
NUMBER OF STAGES ^
TYPE AND SIZE OF PACKING MATERIAL "
PACKING THICKNESS PER STAGE (t>)
MATERIAL OF CONSTRUCTION, PACKING: «
SUPPORTS: II
2. SCRUBBER NO. 2 (a)
TYPE (TOWER/VENTURI) Tower
LIQUID/GAS RATIO, G/MCF @ 121°F 26. 5
GAS VELOCITY THROUGH SCRUBBER, FT/SEC 8.4
MATERIAL OF CONSTRUCTION ** 316L SS
TYPE OF LINING None
INTERNALS: 30% air pass
1-3/8" holes
TYPE (FLOATING BED, MARBLE BED, ETC.) Perforated tray
All modules:
NUMBER OF STAGES two travs. One water
wash tray
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.
5/17/74
A-8
-------
11 gauae 1-3/8" holes 316LSS
PACKING THICKNESS PER STAGE
MATERIAL OF CONSTRUCTION,
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 Fiberglass (Hetron 197)
METHOD OF CLEANING
SOURCE OF WATER AND PRESSURE
Chevron
Two
2"
Horizontal
Underspray and overspray
water lanes
Recirc. Pond Water
Overspray: 2100 gpm
FLOW RATE DURING CLEANINGS, GPM Underspray: 130 gpm
Overspray: 1 min. per 8 hr,
FREQUENCY AND DURATION OF CLEANINGUnderspray: continuous
REMARKS
5. REHEATER
TYPE (DIRECT, INDIRECT)
6 modules: Indirect steam &
suppl. direct heat
1 module: Indirect steam
Water leakage through mechanical seals of venturi and tower
circulation pumps is about 10 gpm per pump,
5/17/74
A-9
-------
DUTY, MMBTU/HR
HEAT TRANSFER SURFACE AREA SQ.FT
TEMPERATURE OF GAS: IN 171°F
HEATING MEDIUM SOURCE
TEMPERATURE & PRESSURE
FLOW RATE
REHEATER TUBES, TYPE AND
MATERIAL OF CONSTRUCTION
OUT
190°F
Steam & Suppl. Hot Air
690°F - 140 psiq
7600
.LB/HR
304 SS (original)
316L SS (Replacement)
REHEATER LOCATION WITH RESPECT TO DEMISTER
Immediately on top of demister
METHOD OF CLEANING Steam soot blowers, IK
FREQUENCY AND DURATION OF CLEANING Once/4 hrs - 5 min.
FLOW RATE OF CLEANING MEDIUM LB/HR
REMARKS
6. SCRUBBER TRAIN PRESSURE DROP DATA
PARTICULATE SCRUBBER
S02 SCRUBBER
CLEAR WATER TRAY
DEMISTER
REHEATER
DUCTWORK
TOTAL FGD SYSTEM
INCHES OF WATER
6- 9
1.2
0.2
3.6
21- 24
A-10
5/17/74
-------
7. FRESH WATER MAKE UP FLOW RATES AND POINTS OF ADDITION
TO: DEMISTER
Intermittent - 2100 qpm (8 hours)
130 gpm - continuous
QUENCH CHAMBER 37 qpm throat flush
ALKALI SLURRYING 200 per module + 177 make-up
PUMP SEALS 10 apm x 2 (module)
OTHER
TOTAL
FRESH WATER ADDED PER MOLE OF SULFUR REMOVED
IlPASo SYSTEM
CAN FLUE GAS BE BYPASSED AROUND FGD SYSTEMS
GAS LEAKAGE THROUGH BYPASS VALVE, ACFM
No
K. SLURRY DATA
LIME/LIMESTONE SLURRY MAKEUP TANK 7.5
PARTICULATE SCRUBBER EFFLUENT
HOLD TANK (a) . one
S02 SCRUBBER EFFLUENT HOLD
TANK (a)
Common
Tank
PH
7.5
5.5
-6.0
>n
Solids
20
8-10
_ _
Capacity
(gal)
w ^
Hold up
time
_
(a) Carbon steel, rubber-lined
LIMESTONE MILLING AND CALCINING FACILITIES: INDICATE BOILERS
SERVED BY THIS SYSTEM.
TYPE OF MILL (WET CYCLONE, ETC.) Wet ball mill
NUMBER OF MILLS two
CAPACITY PER MILL 108
• . --
RAW MATERIAL MESH SIZE 2" x 1/8" (3/4" x 0" - Specs)
PRODUCT MESH SIZE 95% minus 200 mesh
. T/HR
A-ll
5/17/74
-------
M.
SLURRY CONCENTRATION IN MILL
CALCINING AND/OR SLAKING FACILITIES
SOURCE OF WATER FOR SLURRY MAKE UP OR
SLAKING TANK
DISPOSAL OF SPENT LIQUOR
66%
None
Recycle from settling pond
1. SCHEMATICS OF SLUDGE & FLY ASH DISPOSAL METHOD
(IDENTIFY QUANTITIES OR SCHEMATIC)
2. CLARIFIERS (THICKENERS)
NUMBER None
DIMENSIONS —
4.
CONCENTRATION OF SOLIDS IN UNDERFLOW —
3. ROTARY VACUUM FILTER
NUMBER OF FILTERS None r
CLOTH AREA/FILTER —
CAPACITY TON/HR (WET CAKE)
CONCENTRATION OF SOLIDS IN CAKE
PRECOAT (TYPE, QUANTITY, THICKNESS)
REMARKS ^____
SLUDGE FIXATION
POINT OF ADDITIVES INJECTION
FIXATION MATERIAL COMPOSITION
FIXATION PROCESS (NAME)
None
FIXATION MATERIAL REQUIREMENT/TONS OF DRY SOLIDS OF SLUDGE
A-12
5/17/74
-------
ESTIMATED POND LIFE, YRS. 4 years
CONCENTRATION OF SOLIDS IN FIXED SLUDGE 10%
METHOD OF DISPOSAL OF FIXED SLUDGE On site Ponding
INITIAL SOLIDIFICATION TIME OF FIXED SLUDGE —
SLUDGE QUANTITY DATA
POND/LANDFILL SIZE REQUIREMENTS, ACRE-FT/YR 400
IS POND/LANDFILL ON OR OFFSITE On site
TYPE OF LINER None
IF OFFSITE, DISTANCE AND COST OF TRANSPORT
POND/LANDFILL DIMENSIONS AREA IN ACRES 16°
DEPTH IN FEET 10 to 12
DISPOSAL PLANS; SHORT AND LONG TERM
Develop market for fly ash fill-gypsum.
Evaluate filling nearby quarry
N. COST DATA Initially: 32.5 million dollars
1. TOTAL INSTALLED CAPITAL COST projected final cost; 45-50 mill
dollars
2. ANNUALIZED OPERATING COST 1 ,870, (100
1.79 mils/KW hr
A-13
5/17/74
-------
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
n n
CD EH
n o
i i
i i i
cm n
en n
i i
i i
n n
ESTIMATED AMOUNT
OR % OF TOTAL
INSTALLED CAPITAL
COST
19,310,192
4,878,598
3,225,289
261,218
82,136
1,610,000
1.219,000
4,088,522
10 years
242,000
A.
B.
A-14
5/17/74
-------
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.)
1. S02 SCRUBBER, CIRCULATION TANK AND PUMPS.
a.
PROBLEM/SOLUTION.
2.
DEMISTER
PROBLEM/SOLUTION_J
h.HIH ,.p
water to recirculated pond water (probably can get by
with less fresh water) . Z-shape demisters are 1/P1'
thick.
REHEATER
PROBLEM/SOLUTION 304 SS reheater - Cl. Stress corrosion and
sulfurous acid. Chlorides are from oond^ water.
Replacing with 316L SS.
5/17/74
A-15
-------
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
A-16 5/17/74
-------
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.
Automatic pH, 303 index and gas flow to proportion feed
slurry.
A"17 5/17/74
-------
R.
COMPUTATION OF FGD SYSTEM AVAILABILITY FACTOR
BOILER RATING OR MAXIMUM CONTINUOUS CAPACITY, MW
i
M
oo
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)
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 '_*_(b * c)110° = %
5/17/74
-------
APPENDIX B
PLANT PHOTOGRAPHS
B-l
-------
Photo No. 1 General view of the La Cygne Power Station. The
building, which houses the flue gas desulfurization modules, is
shown between the boiler structure and the stack.
Photo No. t c-tose-up view of the FGD building showing the flue
gas ductwork to and from the building.
B-2
-------
Photo No. 3 Close-up view of the high pressure (60" W.G.) I.D.
fans which are the prime movers of gas through both the boiler
and the FGD system.
Photo No. 4 Picture of one of the seven Hydroclones (liquid cyclones)
inside the FGD building. The function of these units is to remove
scale particles from the recirculated slurry to the venturi scrubbers.
B-3
-------
Photo No. 5 Close-up view of a venturi scrubber throat, showing
the motor operated mechanism for varying the gap at the throat.
Photo No. 6 View of the battery of recirculation pumpu wliich serve
the venturi scrubbers.
to these.
The S02 scrubber pumps are similar in design
B-4
-------
Photo No. 7 Partial view of one of the S02 scrubber towers taken
at the demister level.
Photo No. 8 Picture taken during the arrival of some of the new
316L SS reheater bundles shown here being unloaded. One of the
high pressure I.D. fans is shown in the upper right corner.
B-5
-------
.
Photo No. 9 View of the I.D. fans area indicating the large size
of these units. One fan is shown here being taken down for repair,
Photo Ho. 10 View of the limestone rock storage piles which are
located near the coal storage area. The limestone is intermittently
transported to the mill using the coal conveying system.
B-6
-------
Photo No. 11 View of the twin limestone storage silos located on
top of the limestone milling building. The small chimney of the
three oil fired auxiliary boilers is shown to the right of the
silos.
Photo No. 12 View inside the limestone milling building showing
the limestone feeding and weighing equipment. The cone shown is
the bottom of one of the two limestone storage silos.
B-7
-------
Photo No. 13 View of one of the two limestone ball mills showing
the feed chute to the rotating mill drum.
Photo No. 14 View of the discharge end of one of the two limestone
mills. These mills (each rated at 110 ton/hr capacity) are driven
by 2000 hp motors.
B-8
-------
Photo No. 15 View near the top of one of the two limestone slurry
storage holdings tanks. These tanks are located inside the lime-
stone milling building, a short distance from the mill.
Photo No. 16 View of the pipes, some of which carry the ash and
limestone sludge from the FGD system to the pond, while the others
transport back the recycled pond water as well as fresh make-up
water from the lake.
B-9
-------
Photo No. 17 Partial view of the 160 acre ash-limestone sludge
pond. The coal storage pile is shown in the background.
Photo No. 18 This pumping station, located near the pond (not
shown), provides the energy for recycling the clarified pond
water as well as pumping fresh water from the lake canal (partly
shown).
B-10
-------
Photo No. 19 General view of the La Cygne Power Station taken
near the water pumping station.
Photo No. 20 View of the three oil fired auxiliary boilers at the
La Cygne Power Station. They are primarily used to start up the
large coal fired boilers.
B-ll
-------
Photo No. 21 View of the foundation of the second boiler under
construction.
Photo No. 22 Partial view of the schematic instrument control
panel which is located in the main boiler control room. There are
seven scrubber modules identified from A to G.
B-12
-------
APPENDIX C
PLANT OPERATING RECORD
C-l
-------
Availability Factor
for
The FGD System on La Cygne No. 1
The following calculations of availability factor are based
on record of outages data presented in a paper by A. E. Schnake.
The paper, titled "Start-Up of the La Cygne Unit No. 1", was
presented at the 1974 Engineering Conference of the Missouri
Valley Electric Association at Kansas City, Missouri on April 17,
1974.
Period covered: February 23, 1973 to February 16, 1974.
Time during period: 8616 hours
Time scrubbers were down: 3887 hours approx.
Availability factor = (8616 - 3887 - 548) x 100 = 88%
8616 - 3887
It should be noted that this availability factor is conser-
vative, since it assumes that all seven scrubber modules were
down, which is not true. Therefore the availability of the FGD
is higher than 88 percent. Also it is assumed that during the
periods when the boiler was down, the scrubber modules were
available if needed.
Note that this availability factor applies only to the above
stated period when the boiler was down because of numerous
problems, and the modules were accessible for thorough cleaning
and repairs after short operating intervals. As down times of
the boiler become less frequent and shorter, down time of the
scrubber is likely to increase and the availability of the FGD
system will decrease.
C-2
-------
1974 ENGINEERING CONFERENCE
POWER GENERATION COMMITTEE
Missouri Valley Electric Association
Kansas City, Missouri — April 17, 1974
START- UP of
LA CYGNE UNIT No.l
KANSAS CITY POWER & LIGHT COMPANY and
KANSAS GAS AND ELECTRIC COMPANY
Presented Bv - A. E. SchnaKe iviamiKiiance engineer
Kansas City Power & Light Company
C-3
-------
DESCRIPTION
La Cygne Unit No. I is located about 55 miles south of downtown
Kansas City and two miles east of Highway U.S. 69. The plant is jointly
owned equally by Kansas City Power & Light and Kansas Gas & Electric
Company. The plant is manned exclusively by KCP&L employees with output
shared equally by the two companies.
Construction was started in April 1969, reaching the halfway point
in October of 1971, with a construction force of over 900 men. Unit No.
I was nearing completion when the boiler was first fired on December 26,
1972, and construction was considered complete when the unit was declared
commercial on June I, 1973.
An earthfill dam almost 7,000 feet lonq was constructed to form a
lake for cooling. The lake covers 2,600 acres at normal operating level •
with a volume of 40,000 acre-feet. The lake level is controlled with
two radial gates that are 44 feet wide. Make-up water to the lake can
be pumped with two 20,000 gpm pumps from the Mara is des Cygnes River
through a 48 inch underground pipe almost 5 miles long to the lake. The
pumps were used some in the initial filling of the lake. Rain and water-
shed have kept the lake at operating level since January, 1973.
The plant site was originally sized for two 800 mw generators. However,
construction has been started on Unit No. 2 and it will be approximately
600 mw. The plant was designed for black start capability. A 2200 kw,
480 volt diesel generator will provide power to light off an auxiliary boiler.
The auxiliary steam powers a 22 mw, 6,900 volt auxiliary turbine generator.
The auxiliary turbine generator will then provide power for the auxiliaries
to light off the No. I boiler and roll the generator.
A General Electric monitoring and information computer supplies infor-
mation to the following equipment located in the control room. Alarms are
shown on an alarm video (television screen) and typed out on an alarm type-
writer. Desired information can be displayed on an operators video, recorded
on three 4-point trend recorders or printed out on a trend typewriter. A
periodic log, which summarizes the operation of the boiler, turbine generator
and principal auxiliaries is printed out hourly on a log typewriter.
Coal is delivered to the mine mouth plant with off-the-road 120 ton
trucks from a strip mine operated by Pittsburg 4 Midway Coal Company.
30 in.X 0 R.O.M. size coal is conveyed from the receiving hoppers at a rate
of 2,000 tons per hour to two rotary breakers and reduced to 3 in. X 0 size.
The coal then passes to the primary crushers and is reduced to 3/4 in. X 0
size. It continues on to be stacked out in the storage area with the stacker-
reclaimer or a maximum of 1200 TPH may bypass the stacker-reclaimer going on
to the secondary crushers. Live storage area for the stacker-reclaimer is
198,000 tons of coal and 64,000 tons of limestone. The secondary crushers
reduce the coal size from 3/4 in. X 0 to I/4 in. X 0. The coal then continues
on to the bunkers sized for 10 hours with the unit at full load.
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Startup of the main boiler requires steam to drive the boiler feed
pump turbine and seal steam. Three auxiliary boilers rated at 200 psi^ and
200,000 Ibs. per hr flow provide the steam for startup. They were supplied
by Erie City with Forney fuel safety controls.
The boiler Is a supercritical once-through balanced draft Babcock &
Wilcox boiler with Bailey controls. Rating Is 6,200,000 pounds per hour,
I,OIO°F, 3,825 psig at superheat outlet and I,OIO°F at the reheater outlet.
Eighteen positive pressure cyclones (9 on the front and 9 on the rear) fed
with Stock Equipment gravimetric feeders and controlled with a Ballev 660
System provide fire for the boiler. A Bailey 820 System controls the rest
of the boiler functions. Firing rate and attemperator sprays control super-
heat temperature. Reheat temperature is controlled with gas recirculation
and attemperator sprays. Feed water flow is provided with 2 ha If -capacity
Pacific boiler feed pumps driven with Westinghouse turbines. Boiler clean-
ing is done with Diamond Power (IK) sootb lowers and (IR) wal (blowers. Boiler
air flow is provided with three one-third capacity forced draft fans equip-
ped with forced lubrication system and supplied by Green Fuel Economizer
Company. Six one-sixth capacity Induced draft fans, supplied by Sturtevant
control the furnace pressure. The ID and FD fans are powered with 7,000
horsepower Westinghouse motors. Boiler air Is heated with an air preheater
coll heating system before passing through a LJungstrom horizontal air pre-
heater.
United Conveyor supplied the ash handling equipment. Bottom ash flows
from the boiler as hot slag and is quenched in two slag tanks. Each slag
tank has 2 ash lines to convey the ash to a dewatering bin or to the ash-
pond. Economizer ash is drawn from five hoppers with vacuum hydroveyors
and conveyed to the slag tanks where it Is disposed of with the bottom ash.
Fly ash is removed with the Air Qual^Y Control (AQC) System.
Boiler gas is cleaned with 7 B&W limestone slurry scrubbers. The or-
iginal intent was to have seven one-seventh capacity modules, however, mod-
ifications have derated the modules. Each module has 2 sections, a venturi
section for fly ash removal and an absorber section for sulfur dioxide re-
mova I .
A milling system is required to make limestone slurry for the scrubbers.
Two Koppers limestone ball mills are designed to reduce the rock from 3/4 in. x 0
to slurry at a rate of 110 tons per hour. The slurry then passes through
Krebs cyclone classifiers and Is either rejected back to the mill or passed
on to the slurry storage tanks.
The turbine-generator was supplied by Westinghouse with an electro-
fi/draulic control. The hydrogen cooled generator is guaranteed to 800 mw
and will generate 870 mw at .90 power factor with 5% overpressure and 75
psig hydrogen pressure. The hydrogen cooled exciter consists of a permanent
magnet generator, an a-c generator, and a rectifier assembly mounted on a
common shaft. The turbine Is a four-casino, tandem-compound quadruple exhaust
condensing reheat turbine. Simply speaking, this is a double-flow high pres-
sure turbine, a double-flow Intermediate pressure turbine, and two double-flow
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low pressure turbines, all connected in series to turn 1he generator jij
exciter at 3600 rtPM. The turbine valves are operated with high pressure
fire resistant fluid (1600 to 1900 psig) supplied from the electro-hydraulic
control system.
The condenser, supplied by Southwestern Engineering Company, is a sinple
pass unit with I" stainless steel tubes. Three circulating water pumps, rated
at 166,000 gpm, supply cooling water for the condenser. The pumps are driven
with Westinghouse synchronous motors.
Lake water is cleaned up with a Belco water treatment plant to provide
make up for the boiler. A clarator and sand filters clean water up to a
turbidity of 2 ppm at a rate of 600 gpm. The water is then passed throjgh
carbon filters to remove chlorine before demineralizing. The 3-beJ make UP
demineraIizer with cation, an ion, and mixed bed is the final step i .1 pre-
paring boiler make up.
Condensate is passed through a mixed bed polishing deminera I i zer- in i t-s
flow to the boiler. The condensate polishing system has 4 high flow polish-
ing demineraIizers and a separate regeneration system with cation reoener^-
tion tank, anion regeneration tank, and resin storage tank.
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START-UP OPERATIONS
The start-up operations of La Cygne No. I started during the month
of January 1972 when the plant staff was brought up to 9 operators .ind °
supervisory personnel. One of the 345,000 volt transmission lines to the
plant was already energized. So it was possible for the start-up personnel
to energize the standby transformer, some 6,900 volt auxiliary busses, a
few of the 480 volt power centers and some 480 volt motor control centers.
The busses were energized to check out supply and tie breaker interlocks
and for bumping some of the small motors for rotation. However, i1 was
necessary to deenerglze the equipment every night since the operators
would not be working shifts till the end of February.
The month of February saw more activity with many more motors being
bumped. The instrument air compressor was placed in service and techni-
cians were preparing the instrumentation in the water treatment plant for
service. The power line from our substation to the coal company was also
placed in service.
The operators began working shifts in March and start-up operations
continued on a 24-hour basis. The primary water treatment equipment was
placed in service allowing us to make enough water to start flushing some
of the piping systems. The intake equipment was being checked out and
placed in service. The circulating water pumps were bumped for rotation
but starting problems would keep 2 of the 3 pumps unavailable till October.
April saw many more lines getting flushed and the bearing cooling
water system was placed in service. The make-up demineraIizer was placed
in service to fill the condensate storage tanks in preparation for a boil-
er hydro.
The boiler was hydrostatically tested to 6300 psig in May. The
stacker/reclaimer was also being checked out to receive coal. The feed-
water and boiler cycle piping was complete by June and temporary piping
was installed to prepare for a clearwater flush and chemical cleaning of
the boiler and preboiler cycle.
The local union started a 23-day strike on the 1st of July and it
was necessary to transfer most of the supervisory personnel to other
plants to maintain operations. However, the few that remained were able
to check rotation of FD fans and get the main turbine oil flush started.
The chemical cleaning and clearwater flush of the preboiler and boil-
er cycle was completed in August. The main turbine and boiler feed pump-
turbine hot oil flushes were also completed. Two of the auxilijry boil-
ers were fired up and made available for service.
All six ID fans were run and balanced in September. Plans were made
C-7
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to pull a vacuum on the condenser, but the vacuum pump bound up mechan-
ically after running only a short time. The first phase of the coal
handling system was operational and we started receiving coal.
The auxiliary boilers were used to provide steam for steam blowing
of the auxiliary steam piping in October. The main boiler piping was
air blown instead of steam blown to save time. The superheat section
required 35 air blows and the reheat section of the boiler was satisfac-
tory after 17 blows. The blow would start when air pressure reached
300 psig and would stop at about zero pslg. The vacuum pumps were re-
paired and placed in service and we were able to pull vacuum. The start-
ing problems were cleared up on the circulating water pumps and they were
made available for service.
November was a busy month and the operating force had increased from
the original 2 men per shift to 7 men per shift. The cold clean up cycle
of boiler flow was started, but shutdowns were common due to suction
strainers plugging up with dirt and scale. Both boiler feed pumps were
run and tested for overspeed trip. ID and FD fans were operated with the
air preheater coil system and the air preheaters in service. Cyclone
ignitors were checked out along with the coal feeders and the fuel safety
system.
The main objective in December was to prepare for the first boiler
fire. All available equipment was operated as much as possible to expose
start-up problems, and familiarize the operators with the equipment. The
boiler was first fired on December 26, 1972 for about 24 hours. An aux-
iliary boiler had to be taken off because of a split allowing smoke to
blow out of the fire box. It vras needed to power the boiler feed pump
turbine, so was necessary to stop firing the main boiler and have the aux-
iliary repaired. Other problems also surfaced and it was January 24th
before the boiler was fired again. One of the problems that surfaced was
the energy crisis, and we experienced difficulty keeping a sufficient
supply of light oil.
A steam line to the boiler feed pump turbine was installed during the
outage. It allowed steam generated by the main boiler and normally dump-
ed to the condenser to be used to run the B.F.P. turbine. The new steam
line allowed us to reduce the auxiliary boiler loading much quicker than
originally planned.
The turbine-generator was rolled with steam for the first time on
January 25, 1973. The turbine roll history section of this paper starts
on this date with the first turbine roll.
During the period of trial operations, we encountered many problems
such as; boiler slagging, boiler leaks, balance weight changes on the
generator, and I.D. fan problems. This slowed down operations considerably.
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Quite often it was necessary to extend the outages to repair equipment
that hadn't forced the outage. Some of the problems with the equipment
and systems will be covered in the next section.
The start-up of La Cygne No. I was not right on schedule but it wasn't
far off. Trial operation was originally scheduled to start on October I, 1972,
The first boiler fire on December 26, 1972 was just 12 weeks behind the
scheduled date. The unit was scheduled to go commercial on May I, 1973
and was declared commercial only four weeks late on June 1st. The peak
load for the unit was 832 mw and was reached on June 2, 1973. The major
factor limiting unit load has been the number of AQC modules available.
C-9
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EQUIPMENT PROBLEMS
This section of the paper will be devoted to some of the problems
that were encountered in the start up of various equipment.
AUXILIARY BOILERS
The "B" auxiliary boiler exploded several months afler being placed
in service. The boiler was shut down and purged for approximately five
minutes. It then exploded about five minutes after shultinq down the
fan. The source of the fuel for the explosion or how it was ignited
io not known at this time. Repair of the boiler was started immediate-
ly and it was back in service in about a week. The boiler was fired
almost continuously for about five weeks before it had to be shut down
again. This was the first time for the rear end of the boiler to burn
out. The rear ends of all three boilers have burned out frequentU.
The boiler skin breaks at the rear corners and the slightly positive
furnace pressure allows fire to shoot out and enlarge the holes. The
insulation in the rear corners of the boiler was increased on the last
repair. This was done to try to stop the holes that jppear.
The fuel safety system has given us some problems. The problems
usually surface during boiler light off. Houses were built around the
boiler front last summer and this seems to have increased the reliabil-
ity of the system.
CIRCULATING WATER PUMPS
The major problems encountered with the circulating water pumps
was that the motor would trip right after starting, usually on "timed
overload". The motors were 6,900 volt, 1750 hp, 300 rpm synchronous
motors. Apparently the motor reached synchronous speed too fast for
the starting circuit to apply the field. The motor would maintain start-
ing current, overspeed and trip off. The field was also generatino 3
high enough voltage to turn off a thyristor. The thyristor had to turn
on to apply the field, so a blocking diode was installed. The one motor
that would start apparently had a faulty thyristor that the inverse volt-
age did not turn off. The problem was solved with the installation of
the blocking diode. The motors have given us very few problems since
that time other than the replacement of diodes and thyr ir,tor.-.
TURBINE GENERATOR
The biggest problem with this unit has been the qenerjtor oil se^ls,
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The anti-rotation pins have failed several times, a I low i no the se.i I rm^
to rotate. This breaks the hydrogen seal and allows hydrogen to leak.
The seal oil system has a drain receiving tank with a float valve
to control the tank level. The float valve sticks shut occasionally
and must be jacked open and adjusted to get it regulating. The valve
usually creates a problem when the seal oil to hydrogen differential
pressure is increased.
The electro-hydraulic control system has been reliable jnd provides
good control of the turbine-generator. A problem did occur with the
EHC system that has not been solved. The problem was that the generator
load would increase 150 mw and then decrease 150 mw when either one of
the two ID fans were started. The load would eventually level, but if
the generator load was less than 450 mw, the unit would trip off. The
problem did disappear after some apparently unrelafed wiring cnjncies
were made.
BOILER
The boiler has had about 32 leaks since the generat-or wtis first
synchronized. Tube leaks have forced an outage three timor.. The rest
of the , ,-aks didn't force an outage or were found by hydrostatic test
when the unit was down for some other reason. The boiler bypass system
has forced a few outages due to piping leaks.
COMPUTER
The computer has been in service most of the time. Recently a pre-
fabricated cable was found to have faulty terminations in the connector
and was responsible for several outages. Other than this, the computer
has been reliable.
PREFABRICATED CABLE
A great deal of the plant wiring was done with preimbricated cables.
Many of the cables were too long. The excess length was looped in cjble
trays and manholes, overloading the trays and crowding the manholes.
The connectors are not completely weatherproof and we have had some trouble
with the terminations in the connectors.
DC BATTERY CHARGER
The battery charger has been very reliable. A bad card was found
one time and it was apparently caused by dirt falling from overhead work-
ers.
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ELECTRICAL BREAKERS
The 6900 volt breakers have proven quite reliable. One problem
however, that the operators must continually watch for is a linkage rod
in the breaker cubicle that operates the auxiliary contacts. It must
be aligned with an operating arm on the breaker. The arm occasionally
is misaligned when the breaker is rolled into the cubicle.
The auxiliary contact fingers on the 480 volt power center breakers
broke on several of the breakers. This problem hasn't appeared since
the first few months of operation. One power center breaker did explode,
but it apparently was caused by foreign material on the breaker stabs.
The 480 volt motor control center breakers have been very reliable.
BOILER FEEL) PUMP AND TURBINE
We experienced several problems on the turbine with the speed sens-
ing system. This difficulty was solved by the manufacturer soon after
it was placed in service. The turbine has proven very reliable since
that time.
The head gaskets on the boiler feed pumps have failed three times
and the thrust bearing on "A" pump has failed once. A sudden increase
in feedwater flow could have caused the thrust bearing failure. However,
the flow didn't increase to an excessive amount and the bearing should
not have failed for that reason.
ASH SLUICE PUMPS
The bearings on the ash sluice pumps have failed quite a few times
and the rotor has been replaced on all three of the pumps. Both problems
seem to be caused by vibration. The manufacturer has recommended chang-
ing the suction piping to remove a suction strainer. The bearing fail-
ures have also been caused by water leaking from the pump packing into
the bearing housing. Mechanical seals have been ordered to correct this
problem.
The pump motor has also given us a problem. Two of the motors have
failed. One motor had to be rewound because a piece of metal stuck in
the rotor and tore up the winding. The other motor had to be completely
replacea. A flat spot was worn into the length of the rotor.
VACUUM PUMPS
Both vacuum pumps failed when they were initially started. One
ran for a short time and then failed. The other failed the first lime
it was started. The clearance from the thrust end of the rotor to- the
C-12
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end plate was too much. Something fell between the two surfaces and
the rotor bound up. Both the surfaces of the rotor and the end plate
had to be remachined. The timing gears were adjusted when the pump was
put back together and both pumps have operated since then. One small
annoyance is a float valve that controls the level in the seal water
reservoir. The valve occasionally sticks open and overflows the reservoir.
INDUCED DRAFT FANS
We have had many problems related to the ID fans and have worked
almost continuously on them since they were first balanced in September '7^
Ine fans were initially sensitive to imbalance and it was found that the
operating speed was close to the critical speed. However, they were
balanced and we attempted to run the fans to get some operating time
on them. The fan housing had quite a bit of vibration though, and after
finding cracks in the inlet cones, it was decided additional stiffen-
ing was needed to strengthen the housing. We proceeded to get more run-
ning time on the fans but found the thrust collars on the fan bearing
were getting too hot. Thermocouples were originally hooked up to inboard
and outboard fan and motor bearing. So, by the time a high temperature
was indicated on the inboard fan bearing, the thrust collar had already
been wiped. Thermocouples were hooked up to monitor the thrust collar
temperature. They indicated thrust temperatures were increasing to the
alarm set point of I80°F within a short time after the fan was started.
jo the inboard bearings were opened up and it was found that the thrust
collars were moving. The next thought was that air turbulence in the
inlet duct work was causing the rotor to shift from side fo side. Several
different aerodynamic configurations were tried to eliminate air turbu-
lence. A splitter foil was installed and directional vanes were instal-
led in the duct and in the fan inlet box; but the thrust collar was still
getting hot and moving. The next step was to install set screws in the
thrust col lar and cut oi.l grooves to keep the thrust face cooler. The
collar still moved but it did run cooler.
There was apparently only one way to control the thrust bearing
temperature prior to cutting the oil grooves. The temperature would
increase very gradually if the fan was loaded to full load motor amps
right after it was started. It was possible to vary the fan load some
after the oil grooves were cut. If was necessary thouqh to continually
monitor bearing temperature and increase the fan load if the temperal-ure
increased. The operating guide for the thrust temperature would shut
•tne fan down if, the temperature was increasing gradually and reached
2IO°F, or any time the temperature went straight up. Affer many trials,
we found we could get to 240°F if the temperature was gradually increas-
i ng.
The thrust temperature was eventually controlled by installing forced
Ijbrication systems on all the fans. The lube sets allowed the temper-
ature to drop into a I40°F to I60°F temperature range.
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The set screws installed in the thrust collar didn't stop the col-
lar from moving, and the next step was to install pins through the col-
ar into holes drilled into the shaft. It was impossible to make a field
installation within specified tolerances and we gave up on installing
pins. The next effort at stopping thrust collar movement was to install
split back up collars that were designed to give an interference fit.
These were successful and were installed on all six ID fans.
The thrust collar movement and high temperature problems were solved
but another problem appeared as soon as we started firinq the boiler.
Slurry was carrying over from the scrubber and coating out on the fans.
The buildup would throw the fans out of balance. A high pressure water
washer was finally settled on to wash the fans after trying several dif-
ferent methods. The most destructive characteristic of the slurry was
erosion to the fan blades. A blade was discovered almost torn in half
so a I I the blades were magnafluxed. The magnaflux revealed several cracks
and it became apparent the blades needed to be reinforced. Testing in-
dicated that a plate added across the leading edge of each blade would
allow the blades to withstand the stresses they were being subjected to.
Go each fan blade on a I I fans was modified after being checked for cracks.
The fans' sensitivhy to imbalance was complicated even more by
the slurry eroding the fan blades. The leading edge was now protected
but the trailing edge and the rest of the blade was still susceptible
to erosion. The blades slowly eroded and it was necessary to have the
fans rebalanced periodically. The blades on "C" ID fan were eroded to
a knife edge thickness and the fan was removed from service with less
than a year of service. A new rotor, quite different from the original
one, was installed. The shaft size was increased from 20 to 24 inches
in diameter and the weight of the wheel was decreased. Both changes
helped to increase the critical speed and move it further away from the
operating speed. Although the total wheel weight was decreased, the
blade thickness of the new rotor was more than doubled as it was in-
creased from 0.25 inches to 0.625 inches. The new rotor has proven very
reliable after several months of service. The new rotor qives more hours
running time between washings and it has not eroded enough yet to re-
quire rebalancing.
The ID fan inlet and outlet dampers have also suffered from erosion
by the slurry carryover. The dampers have had metal replaced several
times. Slurry has worked into the bearings; binding the dampers, and,
pins have been sheared.
SCRUBBER
Tho scrubber is more commonly called the A.Q.C. system (Air Quality
Control) by the plant personnel. The boiler gas is passed through seven
scrubber modules for removal of fly ash and sulfur dioxide. Each module
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may be isolated from the gas path with inlet and outlet dampers. The
seven modules were originally designed for full boiler load. The boiler
load is thus limited whenever a module is removed from service.
The biggest problem with the scrubber is pluggage in the various
sections and piping.
The piping systems are all rubber lined to protect the piping from
the abrasive qualities of the slurry. We have had some holes wear through
the piping in the area of the spent slurry valves. This is the only
area holes have appeared and we haven't had any more holes since we stop-
ped modulating with the valve and operating with it either wide open or
fully closed.
The venturi section has no internals to plug up, and, except for
some coating on the walls in the spray nozzle area, stays very clean.
The fjas flows through the sump area next making a 180 degree turn, al-
lowing the slurry soaked fly ash to drop out on the sump floor. The
slurry then drains through screens into a recirculation tank. The screens
set at a 45 degree angle to vertical on the sump floor. The slurrv set-
tles on the sump floor and eventually the level becomes high enough to
cover most of the sump screen. The sump floor must be cleaned off when
•Q module is removed from service for cleaning and occasionally there are
holes in the sump screens to be repaired.
The venturi pump takes suction from the recirculation tank and spravs
the slurry through nozzles into the venturi throat. The pump is rubber
lined and we have had some trouble tearing rubber liners. The suction
strainer for the pump gets plugged up and the pump cavitates. The pump
liner is sucked into the impeller when the pump cavitates and the rub-
bing tears the liner. The suction strainers have plugged up frequently
and since they are located in the recirculation tank, the tank must be
drained before cleaning the strainer. The venturi spray and wall wash
nozzles have also plugged up several times. The nozzles are connected
iO the piping with rubber hoses about 3 feet long. The nozzles and rub-
ber hoses must be removed and cleaned whenever they plug up. Then the
hoses are put back on and the piping is flushed with clearwater to re-
move the rest of the solidified slurry. The nozzles are then reinstal-
led and the system is ready to put back in service.
The absorber section of the A.Q.C. module has two parts that pliuT
up frequently. The aemister trays are comprised of z-shaped fiberglass
boards. The gas flows up from the sump carrying slurry jnd the slurry
coats out on the trays restricting gas flow. The module is shut down
to clean the trays when they get dirty.
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The reheater section of the absorber also plugs up frequently.
The reheater Is made up of bundles of steam colls. The gas flows through
the col Is and is supposed to be heated back up to a minimum of I75°F
before passing on to the ID fans. The gas velocity through the demisters
is too high for the demisters to remove moisture when the demisters start
plugging and slurry carries up to the reheat coils. The coils bake on
slurry as It passes through them and can plug up very quickly.
The problems discussed were some of the more Involved and time con-
suming that we confronted. Many repairs and some design changes have been
made to the scrubber during the first year turbine inspection. We expect
the changes to give us a much more reliable and maintenance free operation.
Start up problems are always expected and we believe our first year of oper-
ation has given us the experience to maintain a reliable operation while
contending with any other problems that may appear.
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There have been 112 outages since the generator was first synchioni:o.i
to the sysfem ori February 23, 1973. Cumulative availability VMS -18$ from
June I, 1973 (start of commercial service) to January 31, 1974. Since the
generator was first synchronized to the system on February 23, 1973 there have
been I 12 outages; 71 less than 24 hours long and 9 longer than one week. A
list of outages follows this section of the paper. The "Comments" column
gives the type of trip that brought the unit off and additional information
concerning the trip or work performed on that outage. The 9 outages longer
than 7 days are analyzed as follows:
I outage - First year turbine inspection
I " - Scrubber
4 outages - Slag Problems
3 " - Generator Problems
SLAG PROBLEMS:
There are 4 monkey holes spaced across the center of the boiler floor
that allow molten slag to run into the slag tanks. The boiler must be brought
up to one-rhird load fairly quickly to get the furnace hot enough for the slaq
•tc run properly. B&W recommended that vent lines be installed from the SIJUT
tank to the suction of the gas recirculation fans for the purpose ot put lino
not gas fhrough the slag taps. The vent would then help the slag to stay
hot and run even at low load. The slag tank manufacturer felt that t'he vent
lines might cause problems with the slag tank and didn't encourage the in-
stallation of the vent lines. Several attempts were made to fire the boilor
fast enough to get the slag to run, but we were not successful and decided
to install the vent lines after deslagging the boiler floor 4 times. We
have since encountered no serious problems with the vent and have been forced
down to deslag twice. The 2 times we were forced down was caused by receiv-
ing fire clay with a very high running temperature, and we had to empty the
coal bunkers before firing back up.
GENERATOR PROBLEMS:
The generator has forced a short outage 10 times for balance weicjht
changes. Three of Hie four oulages forced for repair were longer than a
week. The generator and exciter seal oil seal rings were repaired on all
three of these outages and on the first year outage. During outage No. 78
the generator was also reshimmed to distribute the weight of rhe generator
frame so that the foundation would absorb more of the vibration.
SCRUBBER PROBLEMS:
The absorber section of the scrubber contains demlster trays and re-
heater coils which plug up with slurry carried over from the venturi sec-
tion. We usually have at least one module cut out of service to cl-ean up,
but when outage No. 76 came, we were unable to keep up and had to shut* down
until we could clean enough modules to return to service.
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TURBINE ROLL HISTORY
Roll
No. Date Comments on Turbine Rolls From: First Roll Off Turning Gear With Steam
To: First Time Generator Was Synchronized
1 1-25-73 Turbine rolled to 500+ RPM, tripped on false vibration No. 4. bearing.
2 1-25-73 Turbine rolled to 900 RPM for Generator air test, speed was increased to 1200 RPM
for test. Turbine was taken off for baffle change in Generator.
3 1-30-73 Turbine rolled to 900 RPM for Generator air test, speed was increased to 1200 RPM
for test. Turbine off, leak in boiler and oil pipe change on main pump section.
4, 2-08-73 Rolled off turning gear to 2250 RPM, for 10 hour stretchout run. Tripped due to
noise in exciter. Broke the shaft on the permanent magnet generator.
5 2-08-73 Rolled main turbine to 2400 RPM. Tripped turbine because of differential expansion,
i governor end.
M
00
6 2-09-73 Rolled to 2400 for 1 hour, continued 3600 for sync, checks. Turbine tripped due to
loss of all flame.
7 2-09-73 Turbine rolled off T.G., Unit brought to speed for synchronizing checkout. Unable
to synchronize because of wrong ratio on potential transformers.
8 2-22-73 Turbine rolled for 2 minutes and tripped.
9 2-22-73 Unit rolled off turning gear to 1900 RPM, tripped while changing Boiler feed pumps.
10 2-23-73 Unit rolled off turning gear to 1900 RPM. At 5:54 AM La Cygne No. 1 synchronized
to system 1st time 6:00 AM. Turbine tripped due to differential expansion, gover-
nor end.
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OUTAGE RECORD
Outage Date
No. Started Length Type of Trip - Reason for Trip
1 2-23 19-11 Outage #1 follows Turbine Roll No. 10
2 2-24 292-54 Controlled - Ran four hour test run at 80 mw load and 2 overspeed trip
tests. Shut down to deslag boiler.
3 3-8 25-40 MFT "Loss of All Flame" - Couldn't keep cyclones on.
4 3-9 5-37 " "
5 3-10 225-25 Controlled - Shutdown to deslag boiler.
6 3-20 14-48 Turbine trip "Differential Expansion" -
7 3-21 5-51 MFT "Loss of All Flame". Lost all cyclones when technician shorted a
circuit.
8 3-21 40-43 MFT "High Furnace Draft" - "Rotor differential" sensing line on ID fan
tore loose and fell into the fan rotor.
9 3-23 8-54 Operator Trip - Fuel oil line broke, no isolation valves, so had to
shut down.
10 3-24 0-37 Operator Trip - Superheat temperature dropped, uncontrolled.
11 3-24 2-9 MFT "High Furnace Pressure" - Technician working on scrubber module,
dampers went closed.
12 3-24 192-7 Controlled - Unable to keep cyclones on due to wet coal. Boiler needed
to be deslagged.
13 4-1 28-52 Controlled - Change balance weights on IP/LP couplings.
-------
Outage
No.
14
15
16
17
18
n
i
NJ
o
19
20
21
22
23
Date
Started
4-3
4-4
4-4
4-4
4-6
4-6
4-7
4-10
4-11
4-13
Length
short
20-18
14-44
short
23-27
14-59
19-11
13-09
42-48
91-30
Type of Trip - Reason for Trip
MFT - Trip was caused by closed gas recirculation dampers.
Operator Trip - Tripped turbine on temperature differential which in-
dicated water detection.
Generator Lockout Relay "Reverse Power" - Tripped right after synchroni-
zation.
current relay.
" - Changed setting on reverse
Lockout Relay "Auxiliary Transformer "B" Phase Differential" - Trans-
former was inspected and found a wiring error in "C" phase current
transformer.
Operator Trip - Front generator bearing had 6-mils vibration caused by
varying the hydrogen temperature.
Operator Trip - Relief valve failed on steam supply header to boiler
feed pump turbines.
Operator Trip - Lost cyclones, caused uncontrolled steam temperature
drop of more than 150° F.
Controlled - Boiler tube leaks.
MFT "Feedwater Flow Unsafe" - Lost the boiler feed pump. Didn':t make
a transfer quick enough on the boiler feed pump turbine steam supply.
24
4-18 103-25
MFT "High Furnace Pressure" - Had to repair furnace wall damaged by
high pressure.
-------
Outage Date
No. Started Length Type of Trip - Reason for Trip
25 4-23 94-40 Controlled - Slag tanks full of ash and unable to pull ash.
26 4-27 1-51 MFT "High Furnace Pressure"
27 4-27 1-53 Turbine tripped interceptor valve closed.
28 4-28 0-57 Turbine tripped. Reason unknown.
29 4-28 0-58 4 trips MFT "High Furnace Pressure" - Caused by plugged air preheaters.
30 4-28 25-46
n 31 4-29 1-35
i
£2 32 4-30 68-55 Shut down to wash the air preheaters.
33 5_3 4-39 MFT "Feedwater Flow Unsafe" - Steam pressure regulator to boiler feed
pump turbine malfunctioned and caused steam pressure to swing.
34 5-4 1-44 MFT "Loss of all Flame".
35 5-5 8-20 MFT - Trip was caused by gas recirculation - fan tripping off.
36 5-6 1-2 MFT "Gas Recirc Unsafe" - Cause unknown.
37 5-6 1-26 " " " - This trip was disconnected to have instru-
ments calibrated.
38 5-7 106-19 Controlled - Deslag boiler floor.
39 5-11 8-19 Operator trip - Technician working on control circuit for B&W 201
(pressure reducing) valve caused throttle press, swing.
-------
Outage Date
No. Started Length Type of Trip - Reason for Trip
40 5-13 0-59 Operator Trip - Lost cyclones. Turbine temperature differential in-
dicated water detection.
41 5-18 60-44 MFT "High Furnace Pressure" - "B" ID fan tripped off.
42 5-20 7-6 Operator Trip - Turbine vibration.
43 5-21 8-53 Generator Lockout Relay "Excessive Motoring" - Intercept valve went
closed.
44 5-21 2-12 Operator Trip - Slag tank full.
45 5-21 2-54 MFT "Feedwater Plow Unsafe" - Caused by intercept valves closing.
o
i 46 5-22 16-1 MFT " " " - Lost control of B&W 202 (Primary super-
M heat bypass) valves.
47 5-22 16-53 MFT "Loss of All Flame" - Flame scanner fans tripped off due to water
flooding.
48 5-24 18-28 MFT "High Furnace Press" - "A" ID fan tripped from overload.
49 5-25 18-47 MFT "Feedwater Flow Unsafe" - Auxiliary Boilers tripped so B.F.P.T.
lost steam pressure.
50 5-26 3-46 Operator Trip - Change balance weight on PMG.
51 5-26 3-16 " " " "
52 5-29 0-47 MFT "Feedwater Flow Unsafe" - Appeared that both Boiler Feed Booster
Pumps tripped.
-------
Outage Date
No. Started Length Type of Trip - Reason for Trip
53 5-31 1-34 MFT "High Furnace Pressure" - "F" ID fan tripped - cause unknown.
6-1 June 1, 1973 the Unit is declared available for commercial service.
54 6-3 3-16 Operator Trip - Low steam temp. - Caused by loss of cyclones while
burning out bunkers.
55 6-3 2-15 Operator Trip - Excessive water hammer in the flash tank drain header.
56 6-5 322-4 Scheduled Outage - Find cause of vibration in excitor and generator.
57 6-17 10-38 Controlled - Repair leak in 201.1 Pressure Reducing Valve
O
^ 58 6-17 2-23 Controlled - High vibration on PMG - Made balance weight change.
CO
59 6-18 1-25 MFT "Firing Rate above Reheat Protection Limit" and Diff. pressure sw.
across high pressure turbine operated.
60 6-18 0-21 Diff. press sw. above operated again. Disconnected switch.
61 6-19 19-45 Controlled - Unit removed to make a generator balance weight change,
attempting to eliminate a seal ring rub.
62 6-20 23-35 Controlled - Made a generator balance weight change.
63 6-25 2-0 MFT "Low Feedwater Flow" - Lost an auxiliary boiler that was supplying
Boiler Feed Pump steam.
64 6-27 14-22 Lockout Relay operated "Generator Ground" - "A" phase potential transformer
failed.
65 7-2 96-34 Main transformer lockout relay operated - "C"-phased differential - No
damage to transformer.
-------
Outage
No.
66
67
68
69
70
71
o
£ 72
73
74
75
76
77
78
79
Date
Started
7-10
7-11
7-13
7-17
7-18
8-2
8-13
8-23
8-27
8-31
9-3
9-16
9-17
10-7
Length
24-28
2-20
104-2
21-24
214-26
3-22
38-1
3-5
8-32
2-57
293-15
6-19
443-50
14-2
Type of Trip - Reason for Trip
Controlled - Hydrogen leak on the generator lead box.
" - Made a balance weight change on the PMG.
" - Slag accumulation on boiler floor - partially removed.
MFT "Feedwater Flow Unsafe" - B&W 202 (Primary Superheater Bypass)
valve control failed.
Controlled - Slag accumulation on boiler floor.
MFT "Lov Feedwater Flow".
MFT "High Furnace Draft" - Scrubber plugged up. Unable to maintain
adequate Boiler air flow.
MFT Feedwater Flow Unsafe - Electro-Hydraulic system malfunction.
MFT "High Furnace Draft" - Scrubber module dampers tripped shut.
Controlled - Unit was tripped to prevent an employee, who was inspect-
ing a scrubber module from being sucked into the ID fan. Caused by
faulty damper operation.
MFT - Scrubber and air preheaters plugged up.
MFT "High Furnace Pressure" - ID fan tripped due to lube oil system
trouble. Bad timer in control circuit.
Controlled - Generator hydrogen leak and slag problems.
" - Made a generator balance weight change.
-------
Outage Date
No. Started Length Type of Trip - Reason for Trip
80 10-7 18-36 Controlled - Made a generator balance weight change.
81 10-8 2-16 " - Made a PMG balance weight change.
82 10-9 1-1 MFT - "Total Flame Lost" - Lost fires due to electrician and technician
working on vital ac.
83 10-9 2-8 Electrical problems - Lost fire.
8 A 10-9 15-57 Seal oil problem.
85 10-26 115-35 Controlled - Plugged air preheater and scrubber.
86 10-30 4-7-57 MFT - Boiler control was placed in automatic with improper setting.
87 11-2 118-20 Controlled - High vibration on PMG and generator caused by hydrogen
temperature excursion.
88 11-6 23-27 MFT "Feedwater Flow Unsafe" - Auxiliary boiler tripped. Boiler feed
pump steam supply relief valve failed.
89 11-8 11-12 Controlled - Primary superheater tube leak.
90 11-17 25-49 Boiler feed pump tripped on "High Thrust" - No thrust bearing damage
was found.
91 11-19 16-11 MFT "Feedwater Flow Unsafe" - Boiler feed pump tripped from low deaerator
level.
92 11-20 38-47 Controlled - Air preheaters plugged up.
93 11-22 23-31 Operator trip - Indication of low throttle pressure.
-------
n
to
en
Outage
No.
94
95
96
97
98
99
100
101
102
103
104
105
Date
Started
12-2
12-6
12-17
12-24
1-3
1-7
1-9
1-10
1-12
1-18
1-26
1-31
Length
45-3
71-24
153-5
200-7
98-36
35-21
20-18
23-6
148-33
32-46
73-44
1-36
Type of Trip - Reason for Trip
Controlled - Air preheater plugged up.
MFT "Feedwater Plow Unsafe" - Pressure transmitter froze up and backed
down the boiler feed pump.
MFT "Feedwater Flow Unsafe" - Boiler feed pump tripped.
Controlled - Hydrogen seal ring failed.
MFT - Boiler Feed Booster Pump was tripped by a pressure switch mis-
operation.
Controlled - Had to replace broken bolts on B&W 207 (Secondary Super-
heat Bypass) valve.
Lockout Relay "Differential Expansion" - No expansion problem, a pick-up
coil failed on the expansion indicator.
Operator Trip - Indication of generator end differential expansion.
Controlled - Coal problems, cyclone feeder stoppage and unable to con-
vey coal.
Controlled - B&W 207 (Secondary Superheater Bypass) valve discharge
line leak. Also had to replace broken bolts on the impingment flange.
Controlled - Boiler tube leak at No. 2 slag tap. Caused by using a
jackhammer to open the tap hole.
Operator trip - Control of B&W 201 (Pressure Reducing) valve failed.
Caused uncontrolled steam temperature drop.
-------
Outage Date
No. Started Length Type of Trip - Reason for Trip
106 1-31 1-12 Operator Trip - Control of B&W 201 (Pressure Reducing) valve failed.
Caused uncontrolled steam temperature drop.
107 2-4. 6-38 MFT "Low Feedwater Flow" - Cold reheat steam supply to the boiler
feed pump turbine pressure regulating valve failed.
108 2-6 6-1 MFT "High Furnace Draft" - Scrubber plugged up, unable to maintain
adequate boiler air flow.
109 2-9 17-59 Same as above.
110 2-10 5-38 Operator Trip - Uncontrolled steam temperature drop caused by losing
cyclones.
O
to 111 2-10 1-24. Operator Trip - B&W 201 valve control failed. Caused uncontrolled
-3 steam temperature drop.
112 2-16 Controlled - First year turbine-generator outage.
-------
TECHNICAL REPORT DATA
f/'kasc read lasinicliuns an llic rciirse before completing)
1 RbPORTMO
EPA-650/2-75-057-b
4 TITLE AND SUBTITLE
Survey of Flue Gas Desulfurization Systems
La Cygne Station, Kansas City Power and Light Co.
and Kansas Gas and Electric Co.
3 RECIPIENT'S ACCESSIOI»NO
5 REPORT DATE
July 1975
6 PERFORMING ORGANIZATION CODE
7 AUTHORIS)
Gerald A. Isaacs and Fouad K. Zada
8 PERFORMING ORGANIZATION REPORT NO
9 PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
10 PROGRAM ELEMENT NO
1AB013; ROAP 21ACX-130
11 CONTRACT/GRANT NO.
68-02-1321, Task 6b
12 SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OK REPORT AND PERIOD COVERED
Subtask Final; 6/74 - 6/75
14 SPONSORING AGENCY CODE
15 SUPPLEMENTARY (MOTES
16 ABSTRACT
The report gives results of a survey of the wet limestone flue gas desulfurization
(FGD) system at the La Cygne Station of Kansas City Power and Light Co. and
Kansas Gas and Electric Co. The FGD system, designed and installed by the Babcock
and Wilcox Co. , was built integral with the electric power generating facility. The
system consists of seven modules for particulate and SO2 removal, with on-site
limestone grinding and storage facilities. Since there is no provision for bypassing
flue gas around the FGD modules, all flue gases are treated. Several modifications
have been made since system start-up in February 1973. A particulate removal
efficiency of 97-99% has been reported. SO2 removal efficiency ranges between 70 and
83%. The spent limestone slurry is discharged to a 160-acre pond, and water from
the pond is recycled. The initial installed capital cost of the FGD system was ?34
million or $41/KW (based on a net rated capacity of 820 MW) in 1973. Subsequent
modifications increased the cost to about $45 million or 555/KW. Estimated
operating and maintenance costs, including limestone, are 1.79 mills/KWH, not
including capital charges.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Air Pollution
Flue Gases
Desulfurization
Limestone
Scrubbers
Coal
Combustion
Cost Engineering
3 DISTRIBUTION STATEMENT
Unlimited
b IDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Wet Limestone
Particulate
19 SECURITY CLASS (Tins Report)
Unclassified
20 SECURITY CLASS (This page I
Unclassified
c COSATI I'icld/Croup
13B
21B 14A
07A, 07D
21D
21 NO OF PAGES
85
22 PRICE
EPA roirn 2220-1 (9-73)
C-28
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