EPA-650/2-75-057-e
September 1975
Environmental Protection Technology Series
OF FLUE AS
AS
ATION, KANSAS
CO.
ua
0
PRO'
-------
EPA-650/2-75-057-e
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
LAWRENCE POWER STATION, KANSAS POWER AND LIGHT 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 6e
ROAP No. 21ACX-130
Program Element No. 1AB013
EPA Project Officer: Norman Kaplan
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D. C. 20460
September 1975
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EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection
Agency and approved for publication. Approval does not signify that
the contents necessarily reflect the views and policies of the Environ-
mental Protection Agency, nor does mention of trade names or commer-
cial products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/2-75-057-e
11
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ACKNOWLEDGMENT
This report was prepared under -the direction of Mr.
Timothy W. Devitt. Principal authors were Dr. Gerald A.
Isaacs and Mr. Fouad K. Zada.
Project Officer for the U.S. Environmental Protection
Agency during the survey visit was Mr. Wade H. Ponder.
Information and data on plant operation were provided by Mr.
Kelly Green, Kansas Power and Light Company and by Mr. Jim
Jonakin, Combustion Engineering, Inc., during and subsequent
to the survey visit. Mr. Charles D. Fleming was responsible
for editorial review of this report.
The authors appreciate the efforts and cooperation of
everyone who participated in the preparation of this report.
iii
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TABLE OF CONTENTS
Page
ACKNOWLEDGMENT iii
LIST OF FIGURES vi
LIST OF TABLES vi
SUMMARY vii
1.0 INTRODUCTION 1-1
2.0 FACILITY DESCRIPTION 2-1
3.0 FLUE GAS DESULFURIZATION SYSTEM 3-1
3.1 Process Description 3-1
3.2 Design Parameters 3-4
3.3 Installation Schedule 3-6
3.4 Cost Data 3-7
4.0 FGD SYSTEM PERFORMANCE 4-1
4.1 General Discussion 4-1
4.2 Start-up Problems and Solutions 4-1
4.3 Future Modifications 4-6
APPENDIX A PLANT SURVEY FORM A-l
APPENDIX B PLANT PHOTOGRAPHS B-l
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LIST OF FIGURES
Figure
3.1
4.1
4.2
4.3
4.4
Sketch of a Typical FGD Module at the
Lawrence Power Station
Flow Diagram - December 1968
Flow Diagram - October 1969
Flow Diagram - October 1970
Flow Diagram - October 1972
Page
3-2
4-3
4-3
4-3
4-3
Table
2.1
3.1
3.2
3.3
LIST OF TABLES
Pertinent Data on Plant Design, Operation
and Atmospheric Emissions - Lawrence Station,
KP&L (Wyoming Coal)
Summary of Data: Particulate and SO- Scrubbers
Summary of Data: FGD System Recycle Tanks
Typical Pressure Drop Across Components of
FGD Module
Page
2-4
3-5
3-5
3-6
vi
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SUMMARY
The flue gas desulfurization (FGD) systems on Boilers
4 and 5 at the Lawrence Power Station of Kansas Power and
Light Company (KP&L) were designed and installed by Combustion
Engineering, Inc. (C-E). The process used is based on
injection of pulverized limestone in the furnace followed by
tail-end wet scrubbing.
Unit 4 has a net capacity of 102 MW when burning Wyoming
coal and with the FGD system operating. The unit is equipped
with two FGD modules which were placed in service in November
1968. These modules have undergone several major modifications
since that time in order to improve system performance and
availability. The experience gained was later incorporated
in the design and construction of the FGD system on Unit 5
which has a net generating capacity of 320 MW. This system
consists of eight modules and was installed concurrently
with and as an integral part of that boiler. Boiler 5 and
its SO, pollution controls both started up in November 1971.
The performance of the FGD units on Boilers 4 and 5 has
steadily improved, and their availability has increased with
operating experience. Availability figures for both units
have been recently reported to be close to 100 percent.
-------
However, these figures are somewhat misleading because of
the particular load cycle for this plant. Both boilers
operate only at half-load at night. Half of the modules are
shut down for cleaning or repair on a daily basis. Thus,
forced outages are infrequent because the scrubber demand
factor is fairly low.
Present outstanding problems for both boilers include
localized corrosion in some equipment, unsatisfactory damper
operation, demister fouling, expansion joint failures and
rapid wear of slurry recirculating pumps. In addition to
the above, Boiler 5 is plagued with poor flue gas distri-
bution to the eight FGD modules which, unlike the modules on
Boiler 4, are all interconnected to one common stack.
The spent lime/limestone slurry from both FGD units is
sent to three interconnected unlined sludge disposal ponds.
About 500 gal./min of make-up water to the system is supplied
from the cooling tower blowdown line. This make-up water is
pumped to the last pond. The clarified water from this pond
is recycled to FGD Units 4 and 5. The remainder of the
cooling tower blowdown is returned to the river.
Since the spent slurry contains fly ash and unreacted
lime, ingredients considered effective sludge stabilizers,
the sludge in the unlined ponds is not further treated and
is reported to solidify in the ponds.
Data are not available at the present time on capital
and operating costs of FGD Units 4 and 5. However, the
Vlll
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initial capital cost to KP&L in 1968 for the installation of
FGD Units 4 and 5 was reported to be about 3.5 million
dollars. The cost of subsequent modifications to these
units was borne by C-E.
Further modifications to the FGD systems are planned.
The two existing modules on Unit 4 will be phased out and
replaced by two new modules. Each module will consist of a
venturi followed by a spray chamber. Also an electrostatic
precipitator (ESP) unit will be installed to handle the fly
ash. These main changes are scheduled for completion by
January 1977. Unit 5 will be converted to a tail-end wet
limestone scrubbing process by the fall of 1975.
Pertinent plant and FGD operational data are summarized
in the following table.
IX
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SUMMARY OF FGD DATA, BOILERS 4 AND 5
LAWRENCE POWER STATION
System data
Unit rating (net MW)a
Boiler 4
102b
Boiler 5
320b
Fuel charac-
teristics
FGD vendor
Process
New or retrofit
Start-up date
FGD modules
Efficiency, %
Particulates
so2
Water make-up
-pr.i/riw
Sludge disposal
Kansas Coal: 12% ash, 3.75% S,
12,000 BTU/lb
Wyoming Coal
9.8% ash, 0.6% S,
10,000 BTU/lb
Combustion Engineering
Limestone injection with tail-end
scrubbing
Retrofit
November 1968
2
99.3
65
New
November 1971
8
99.3
65
3-75
Stabilized sludge disposed in
unlined pond
With FGD system operating.
When burning Wyoming coal.
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1.0 INTRODUCTION
The Industrial Environmental Research Laboratory,
formerly the Control Systems Laboratory of the U.S. Environmental
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 utility boilers
in the United States. This report on the Lawrence Power Station
of Kansas Power and Light Company (KP&L) is one of a series of
reports on such systems. It presents values of key process
design and operating parameters, describes the major start-up
and operational problems encountered at the facility and the
measures taken to alleviate such problems, and identifies the
total installed and annualized operating costs as made available
by the user and/or vendor.
This report is based upon information obtained during a
plant inspection on August 13, 197*1 and on data provided by
KP&L personnel.
Section 2.0 presents pertinent data on facility design
and operation, including actual and allowable particulate
and SOp emission rates. Section 3-0 describes the PGD system,
and Section 4.0 analyses PGD 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 Lawrence Power Station of Kansas Power and Light
Company is located in a lightly industralized area on the
outskirts of Lawrence, Kansas.
The plant operates two steam boilers which are equipped
to burn coal, natural gas supplemented with oil or a com-
bination of these three fuels. Boiler 4 is the older of the
two units. It was first placed in service in 1959 and
operated as a cyclic load boiler. The maximum electric
generating capacity of this unit varies with the type of
fuel being burned; when burning natural gas the unit's
output can be as high as 143 MW, and decreases to 125 MW
when burning coal plus natural gas. The retrofitting of
this boiler with an FGD system in 1968 has introduced
additional pressure drop in the flue gas system and further
reduced the boiler capacity to 115 MW.
The second unit at the plant is Boiler 5. Its rated
capacity, when burning coal plus natural gas, is 400 MW.
The unit, together with the FGD system, was placed in
service in November 1971. Similar to Boiler 4, it is also
classified as a cyclic load unit.
Both boilers at the Lawrence Power Station were built
2-1
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by C-E, which also designed and installed the FGD systems on
these boilers. These FGD systems consist of limestone
furnace injection with flue gas wet scrubbing.
Until recently the grade of coal burned at the Lawrence
Power Station had a gross heat content of 12,000 BTU/lb.
Its average ash and sulfur contents were 12 and 3.75 percent,
respectively. The company has now switched from this high-
sulfur Kansas coal to Wyoming coal which contains from 0.4
to 0.8 percent sulfur and 10 percent ash. The coal has a
gross heating value of 10,000 BTU/lb. This change was
necessitated by the curtailment of strip-mining operations
at the Kansas coal supply site.
As mentioned earlier, coal, gas and oil can be burned
in this boiler. Oil is used as a supplementary fuel. Thus,
S02 emissions can vary widely.
Both Boilers 4 and 5 burn some natural gas in the
summer, when the demand for home heating is low. In 1969-
70, approximately 65 percent of the plant's generating
capacity was from the combustion of natural gas. It is
estimated that gas usage will be phased out completely at
the Lawrence Power Station by 1981.
The maximum particulate emissions allowed under the
State of Kansas Regulation 28-19-31A are 0.19 Ib/MM BTU of
heat input to Unit 4 and 0.16 Ib/MM BTU of heat input to
Unit 5. The calculated maximum particulate emissions
from Units 4 and 5 are equivalent to 0.09 Ib/MM BTU of heat
2-2
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input to each boiler.
Atmospheric emissions of sulfur dioxide are limited by
the State of Kansas Regulation 28-19-31C. This regulation
limits the SO- emissions from Units 4 and 5 to 1.5 Ib/MM BTU
of heat input to the boilers. The calculated S02 emissions,
based on an FGD S02 removal efficiency of 65 percent, while
burning Wyoming coal, is 0.43 Ib/MM BTU of heat input to
each boiler. Therefore, the SO- emission limit can be met
by burning Wyoming coal, even without the use of an FGD
system. Nevertheless, KP&L is proceeding to replace the FGD
system on Unit 4 for several reasons:
1. It was not anticipated that low sulfur fuel would
be burned at the station when the replacement FGD
system was planned and engineered.
2. C-E has committed to provide an operable FGD
system on Unit 4. The existing system is in such
a state of deterioration that it cannot be repaired
for that purpose.
3. Low sulfur coal has reduced the efficiency of the
existing ESP, and there is insufficient space for
the installation of an adequately sized ESP. A
particulate scrubbing system is therefore necessary,
and an FGD system can conveniently be operated in
conjunction with the particulate system. Pertinent
data on Units 4 and 5 are given in Table 2.1.
2-3
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Table 2.1 PERTINENT DATA ON PLANT DESIGN,
OPERATION AND ATMOSPHERIC EMISSIONS -
LAWRENCE STATION, KP&L (Wyoming Coal)
Boiler Data
Maximum continuous generating
capacity (MW, net)
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
Maximum flue gas rate, acfm @ 290°F
Emission controls
Particulate
so2
Particulate emission rate
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
SO_ emission rate
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
Unit 4
102
4A, 4B
C-E
1959
63
1260
11,667
120
367,000a
FGD scrubber
FGD scrubber
0.19
0.09b
1.5
0.43°
Unit 5
320
5
C-E
1971
178
3560
11,125
375
l,036,000a
FGD scrubber
FGD scrubber
0.16
0.09b
1.5
0.43C
Calculated, 22% excess air.
Calculated, assuming 99% scrubber particulate efficiency.
Calculated, assuming 65% S02 removal efficiency.
2-4
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3.0 FLUE GAS DESULFURIZATION SYSTEM
3.1 PROCESS DESCRIPTION
The FGD systems on Boilers 4 and 5 are identical in
basic design and operation. The FGD system on Boiler 4
underwent several major modifications since its start-up in
November 1968. Many of these modifications were later
incorporated in the design of the FGD system on Boiler 5.
The present FGD system for each boiler includes facilities
for pulverizing and injecting finely ground limestone rock
into the boilers' furnace chamber where the bulk of it is
calcined. This calcined limestone, along with the fly ash,
is transported by the flue gas to the tail-end wet scrubber
modules, where the SO- in the gas reacts with the scrubbed
lime/limestone in the recirculated slurry and is substantially
removed, along with the fly ash, from the gas stream. The
cleaned gas is then demisted and reheated (to prevent con-
densation in the downstream equipment) and finally discharged
from the stack by the I.D. fans.
There are two FGD modules on Boiler 4 and eight FGD
modules on Boiler 5. They are all identical in size and
each is designed to handle approximately 150,000 scfm of
flue gas. A typical module is shown in Figure 3.1. It
3-1
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FROM
AIR-£»
HEATER
• SOOT BLOWER AIR
WATER WASH LANCE
LAWRENCE N? 4
CE-APCS
OCTOBER 1972
SCRUBBERS (?'.
( ENLARGED DEPTH - 4' )
RECYCLE TANK (
IENLARGEDI
DRAIN TANK
CLARIFIED
FROM
POND
TO
^. SOL ID
DISPOSAL
(J) POND
Figure 3.1 Sketch of a typical FGD module at the
Lawrence Power Station.
Source: Kansas Power and Light Company
3-2
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consists of a single stage of 3/4" glass marbles. The bed
is about 3 to 4 inches thick and is fitted with overflow
pots to collect and drain the liquor from the top of the
bed. The scrubbing liquor is sprayed through nozzles located
below the bed.
Chevron demistars are located about 4 1/2 feet above
the marble bed (7 1/2 feet in six of the eight modules of
Boiler 5). There are two layers of demisters each 6 inches
thick spaced 12 inches apart. They are cleaned once a day
for one hour by 150 psig pond water sprayed from retractable
wash lances.
The present reheater bundles are made of carbon steel
tubes and each is rated at 10 MM BTU/hr. The heating medium
is boiler feed water which is available at 260°F. The tube
bundles are located about 6 1/2 feet directly above the
demisters. They are cleaned six times a day for 3 minutes
each time by high pressure compressed air blown from lances
located under the tubes.
Each one of the two modules on Boiler 4 is connected
(through an I.D. fan) to a separate 120 ft stack, while the
gases from all eight modules on Boiler 5 are discharged
through a common stack, 375 feet tall.
Originally, all modules were fitted with bypass ducts
and hydraulic seal dampers. However, because of extensive
corrosion and plugging problems with the systems on the two
modules of Boiler 4, the bypass ducts on these modules were
removed.
3-3
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The spent liquor from the scrubber tower drains into a
recycle tank. The 30-40 minute retention time of this tank
ensures complete conversion of the scrubbed SO- to calcium
sulfite and calcium sulfate. The spent liquor from this
tank overflows to a drain tank from which it is pumped to
the sludge disposal ponds.
Presently there are three unlined sludge ponds on site,
4 acres, 16 acres, and 28 acres. The sludge first enters
the 16-acre pond and overflows into the 4- and 28-acre
ponds. Approximately 800 gpm of sludge containing 9 percent
solids, are fed to the unlined ponds. Because of the presence
of unreacted lime as well as fly ash in the sludge (ingredients
which are usually added to stabilize limestone sludge) the
sludge sets up very hard like concrete, without any addi-
tives. Including an additional 30-acre on-site location,
for future sludge ponds, it is anticipated that sludge can
be stored on-site for about 20 more years.
3.2 DESIGN PARAMETERS
As noted earlier, and further discussed under Section
4.1, the FGD modules of Boiler 4 have undergone several
major modifications since they were originally designed and
installed. Therefore, the figures presented in Tables 3.1,
3.2, and 3.3 refer to present operating conditions instead
of original design parameters. These data (except where
noted) also apply to the FGD system of Boiler 5, since many
of the modifications on Unit 4 were incorporated in the
design of the FGD system on Boiler 5.
3-4
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Table 3.1 SUMMARY OF DATA: SO2 SCRUBBER
Item
SO- scrubber
tower
L/6 ratio,
gallons/1000, acf
Superficial gas
velocity, ft/sec
Equipment size
Equipment internals
Material of construction
Shell
Internal supports
22
6.5
3.5-inch thick bed of
3/4-inch diameter marbles
C.S. lined with Ceilcote
epoxy with glass flakes
316 L SS
Table 3.2 SUMMARY OF DATA: FGD SYSTEM RECYCLE TANKS
Item
Recycle tank
on Boiler 4
Recycle tank
on Boiler 5
Total number of tanks
Tank size
Retention time at full
load , minutes
Temperature, °F
pH
Solids concentration, %
Specific gravity
Material of construction
40
290
9.5-10
8.5-9.5
30
9.5-10
8.5-9.5
3-5
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Table 3.3 TYPICAL PRESSURE DROP ACROSS
COMPONENTS OF FGD MODULE
Equipment
SO_ scrubber tower
Demister "^
Reheater ^
Ductwork J
Total FGD system
Pressure drop,
inches W.G.
6-8
1-1/2 - 2
10
3.3 INSTALLATION SCHEDULE
The decision to install an FGD system on Boilers 4 and
5 was made during 1967. The company had assumed that by
1971 there would be some ambient and/or emission regulations
in effect for particulate matter and sulfur dioxide.
Based on this assumption and the availability of coal
containing 3 to 4 percent sulfur and 12 percent ash, the
decision was made to install as original equipment, facilities
to remove the fly ash and SO- from the flue gas of Boiler 5
which was then in the planning stage. The FGD process was
based on C-E's limestone-furnace injection with tail-end wet
scrubbing.
In order to gain experience in the operation of such a
system, KP&L further decided to retrofit a similar FGD
system on the existing Boiler 4. Construction on this
FGD system began in March 1968 and the initial start-up of the
FGD system took place in November of the same year.
3-6
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Construction of Boiler 5 and its FGD system also began
in 1968, side by side with the work on retrofitting Boiler
4. The initial start-up of Boiler 5 and its pollution
control equipment began in March 1971. Shakedown and de-
bugging of the equipment was completed in November 1971.
Kansas State emission standards require that new in-
stallations utilize the latest available technology; KP&L
interprets this as a requirement for the installation of
scrubbers. Accordingly, the company has proceeded to in-
corporate scrubbers into the design of their Jeffery Energy
Center, a new power plant to be built at St. Mary's, Kansas,
about 30 miles west of Topeka. The new plant will consist
of four 700 MW units. The first two units are to be opera-
tional in 1978 and 1979, burning Wyoming coal containing 0.2
to 0.45 percent sulfur. ESP's will be used for particulate
control, and C-E scrubbers will be used to attain 50 to 60
percent SO2 control. The units will be designed to limit
SO- emissions to about 0.5 Ib/MM BTU, considerably lower
than the Federal New Source Performance Standard (NSPS) of
1.2 Ib/MM BTU.
3.4 COST DATA
Detailed data on the capital and operating costs of the
FGD installations at the Lawrence Power Station are not
available. In 1968, KP&L paid C-E a lump sum of about 3.5
million dollars (equivalent to $8.3/KW net) for retrofitting
Boilers 4 and 5 with FGD systems. Since that time the
3-7
-------
systems have not met performance specifications and there-
fore have not yet been accepted by KP&L. Consequently, the
expenses incurred in many subsequent modifications to the
systems were largely borne by C-E. Since these costs occur-
red over a period of many years, no meaningful conclusion
can be drawn as to the present cost of a comparable system.
It is significant to note that it was not necessary to
expand the size of the operating staff, nor to upgrade
operator qualification grades as a result of the scrubber
installations. However, maintenance requirements have
increased considerably as a result of the FGD installation.
3-8
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4.0 FGD SYSTEM PERFORMANCE
4.1 GENERAL DISCUSSION
The several major modifications completed by C-E and
KP&L on Unit 4 have significantly improved the units per-
formance and availability. Availabilities close to 100
percent were reported for July and August 1974. The S02
removal efficiency has been around 65 percent, which is
sufficient for the plant to comply with the applicable
pollution control regulations. SO- removal efficiencies as
high as 85 percent were achieved over a short period, but
only at the expense of an accelerated rate of scale formation
in the scrubbers, resulting in decreased FGD system availability.
Boiler 5 has recently been firing natural gas. When
the boiler is firing coal and the FGD system is in operation,
the problems experienced are similar to those encountered
with the modules on Boiler 4. However, the main outstanding
problem with Unit 5 is improper flue gas distribution to the
eight modules. Combustion Engineering is presently performing
some tests on Unit 5 to alleviate this problem.
4.2 START-UP PROBLEMS AND SOLUTIONS
Analysis of the problems encountered during and since
start-up reveals that nearly all were due to improper con-
4-1
-------
trol of process chemistry. In the limestone furnace in-
jection process, satisfactory control of the degree of
limestone calcination as well as the amount of lime/limestone
carried in the flue gas to the tail-end scrubbers, is difficult
to achieve. This situation is further aggravated when the
boiler is operating as a cyclic load boiler and is fired
with a variable combination of coal, natural gas and oil.
Figure 4.1 illustrates the configuration of each of the
two modules when the FGD system initially started operating
in 1968. This design presented many operating problems and
shortcomings. Among these were (1) scale buildup and
plugging of the hot gas inlet duct, (2) erosion of the
scrubber walls and corrosion of the scrubber internals, (3)
plugging and scaling of drain lines, tanks, pumps, marble
bed, demister, reheater and (4) scale buildup on I.D. fan
rotors, which resulted in fan imbalance and vibration.
In addition to the above mentioned operating problems,
the SO2 removal was quite low due to the over burning of
limestone in the furnace and the dropout of the lime with
the ash in the bottom of the scrubbers.
After the first few months of operation, the scrubbers
were modified. These modifications, which are shown in
Figure 4.2, include (1) addition of soot blowers in the gas
inlet duct and under the reheater bundle, to minimize plugging
problems, (2) raising of the demister to reduce plugging from
solids carry-over, (3) directing the overflow liquor from
the pots to the pond, and the installation of a large recycle
4-2
-------
TO STACK
.TO STACK
WATER
SEAL ^ k^
Wl
v»
m
FROM
AIR -6
-Tir
-•=
HEATER
_ "x^
///////////////,
^»«?r-
<*h^*H
v T 7T
HOT
HjO
REHEAT
DEMISTER
MARBLE BED
LAWRENCE N* 4
CE-APCS
DECEMBER 1968
SCRUBBERS (2)
^ CLARIFIED FROM POND
1
SOLID DISPOSAL POND
Figure 4.1 Flow Diagram - December 1968
• SOOT BLOWER AIR
WATER
SEAL
I H pfWWWWW
HJ VvWWW»\
LAWRENCE
CE-APCS
OCTOBER 1969
SCRUBBERS I?)
CLARIFIED FROM PONC
MEATt*
TANK (I)
Figure 4.2 Flow Diagram - October 1969
I
OJ
TOST
LAWRENCE N«4
CE-APCS
OCTOBER I97O
SCRUBBERS
-
'
w*
DRAIN TANK
Figure 4.3 Flow Diagram - October 1970
, TO STACK
• SOOT BLOWER AIR
10 FAN ^ WATER WASH LANCE
LAWRENCE N* 4
CE-APCS
OCTOBER 1972
SCRUBBERS (2)
(ENLAR8EO OCPTH-4')
(?)
RECYCLE TANK (I)
(ENLAR6EO)
DRAIN TANK
Figure 4.4 Flow Diagram - October 1972
-------
tank and pump to catch and recirculate the highly alkaline
underflow back to the marble bed. Other modifications to
combat corrosion and plugging were the installation of a new
type of spray nozzle and lining the bottom section of the
scrubber tanks with gunite. Hydraulic variable speed drives
were installed on all the fans. It was found that a slight
readjustment of fan speed would often eliminate vibrations
caused by deposit buildup on the rotor. Thus, operation
could be continued without shutting down the fan for a
thorough cleaning.
Most of the problems were reduced but not eliminated by
these modifications. Furthermore, the new recirculation
system improved the SO2 removal efficiency.
To further minimize corrosion, erosion, scaling and
plugging problems, additional revisions were made during the
summer of 1970. The resulting scrubber configuration is shown
in Figure 4.3. The major revisions were:
1. Sandblasting and coating the interior of the
scrubbers with two coats of glass flake lining.
2. Replacement of all internal steel pipes with
plastic and fiberglass piping.
3. Replacement of the stainless steel demisters with
fiberglass demisters.
4. Addition of a ladder vane under the marble beds to
improve gas distribution.
5. Modification of the pot overflow drain piping to
allow the liquor to return to the recycle tank.
6. Removal and replacement of the original copper fin
tubes of the reheater coils with a carbon steel
fin tube coil. Because of the close spacing of
4-4
-------
the fins on the copper tubes, the reheaters
plugged easily. Also the fins were flattened by
the soot blower jets.
Demister plugging continued to create serious problems.
Manual washing was necessary every other night to maintain
the required unit output.
In the summer of 1972, the scrubbers (on Units 4 and
5) were modified to operate using a high solid slurry
crystallization process to control saturation and precipi-
tation of scale within the scrubber. These latest major
modifications, shown in Figure 4.4, included the enlargement
of the liquor recirculation tank as well as the replacement
of many components, such as piping, nozzles, pumps and
mixers. Also the demisters were replaced with a new two-
bank fiberglass unit fitted with high pressure wash water
lances.
Operation of the two FGD systems since the fall of 1973
has been the most successful to date. Some of the remaining
problems are:
a) Isolated corrosion areas
b) Expansion joint failure
c) Demister fouling
d) Rapid wear of slurry pumps
e) Valve failures
The load cycle at this station is such that the boilers
are cut to half-load every night. Therefore, half of the
modules are shut down nightly and can be cleaned or repaired
regularly. Thus forced outages are infrequent.
4-5
-------
The FGD system availability averaged 86 percent during
the first 11 months of 1974. Availability was 50 percent in
December due to outages for repairs on the modules.
4.3 FUTURE MODIFICATIONS
Future modifications to the FGD systems on each boiler
will be primarily concerned with alleviating the problems
which are inherent in the furnace injection of limestone.
Therefore, Unit 5 will be converted to a tail-end, wet lime-
stone scrubbing process by fall 1975. Beyond that the
future of Unit 5 is uncertain.
After six years and several major modifications, the
current plans for Unit 4 are as follows:
a) Engineering of two 2-stage scrubbers (ventri-rod
followed by spray) will be started. Foundation
work due to start Spring, 1975.
b) By September 1976, the two new scrubber modules
are to be operational. The present scrubbers will
be kept in service while the new scrubbers are
being built.
c) By September 1977, the present scrubbers will be
razed, and an ESP will be installed. It is
anticipated that the ESP/ventri-rod/spray flue gas
cleaning system will be operational by September
1977. The new system will have forced oxidation
of via aeration to produce calcium sulfate.
4-6
-------
APPENDIX A
PLANT SURVEY FORM
A-l
-------
PLANT SURVEY FORM3
NON-REGENERABLE FGD PROCESSES
A. COMPANY AMD PLANT INFORMATION
1. COMPANY NAME Kansas Power and Light Company
2. MAIN OFFICE Topeka, Kansas
3. PLANT MANAGER Lee Brunton
4. PLANT NAME Lawrence Power Station
5. PLANT LOCATION Lawrence, Kansas
6 . PERSON TO CONTACT FOR FURTHER INFORMATION Kelly Green
7. POSITION Production Engineer
8. TELEPHONE NUMBER (913) 233-1351
9. DATE INFORMATION GATHERED 8-13-74
10. PARTICIPANTS IN MEETING AFFILIATION
Kelly Green KPL
Lee Brunton KPL
Wade Ponder EPA
John Busik EPA
Tim Devitt PEDCo
Fouad Zada PEDCo
a These data were obtained on August 13, 1974. Some of the data
may have been updated in the body of the report
A-2 5/17/74
-------
B. PLANT DATA. (APPLIES TO ALL BOILERS AT THE PLANT).
CAPACITY, MW
SERVICE (BASE, PEAK)
FGD SYSTEM USED
BOILER NO.
4
125
Cyclic
/
5
400
Cyclic
/
C. BOILER DATA. COMPLETE SECTIONS (C) THROUGH (R) FOR EACH
BOILER HAVING AN FGD SYSTEM.
1. BOILER IDENTIFICATION NO.
2. MAXIMUM CONTINUOUS HEAT INPUT
1000
MM BTU/HR
3. MAXIMUM CONTINUOUS GENERATING CAPACITY 102** MW
4. MAXIMUM CONTINUOUS FLUE GAS RATE. 165000/module ACFM @ 290 °F
5. BOILER MANUFACTURER Combustion Engineering
6. YEAR BOILER PLACED IN SERVICE 1959
7. BOILER SERVICE (BASE LOAD, PEAK, ETC.) Cyclic
(each module
120' has its own stack)
8. STACK HEIGHT
9. BOILER OPERATION HOURS/YEAR (1973)
10. BOILER CAPACITY FACTOR *
11. RATIO OF FLY ASH/BOTTOM ASH
8100
50*
85/15
* DEFINED AS: KwH GENERATED IN YEAR
MAX. CONT. GENERATED CAPACITY IN KW x 8760 HR/YR
** Net - Wyoming coal.
A-3
5/17/74
-------
D. FUEL DATA
1. COAL ANALYSIS (as received)
GHV (BTU/LB.)
S %
ASH %
2. WYOMING COAL ANALYSIS
GRADE
S %
ASH %
MAX.
4.00%
MIN.
3.5%
AVG.
12,000
3.75%
12%
0.8%
0.4%
10,000
0.53%
10%
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
3.
PARTICULATES
0.19
so2
1.5
PLANT PROGRAM FOR PARTICULATES COMPLIANCE
Test results 99.2% efficiency by York Co. tests.
Source is in compliance. All tests ranged between
98-99.3%
PLANT PROGRAM FOR SO2 COMPLIANCE
Removal efficiency is about 65%.
A-4
5/17/74
-------
F. PARTICULATE REMOVAL
1. TYPE
MANUFACTURER
EFFICIENCY: DESIGN/ACTUAL
MAX. EMISSION RATE* LB/HR
GR/SCF
LB/MMBTU
DESIGN BASIS, SULFUR CONTENT
MECH.
E.S.P.
•
FGD
C.E
99.0/98-99.3
G. DESULFURIZATION SYSTEM DATA
1. PROCESS NAME
2. LICENSOR/DESIGNER NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
3. ARCHITECTURAL/ENGINEERS, NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
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 3/68
e) DATE ON SITE CONSTRUCTION COMPLETED
f) DATE OF INITIAL STARTUP 11/68
g) DATE OF COMPLETION OF SHAKEDOWN
*At Max. Continuous Capacity
A-5
5/17/74
-------
5. LIST MAJOR DELAYS IN CONSTRUCTION SCHEDULE AND CAUSES:
6. NUMBER OF SO2 SCRUBBER TRAINS USED . .. Two
7. DESIGN THROUGHPUT PER TRAIN, ACFM @ °F 165000 SCFM
8. DRAWINGS: 1) PROCESS FLOW DIAGRAM AND MATERIAL BALANCE
2) EQUIPMENT LAYOUT
H. S02 SCRUBBING AGENT
1. TYPE Limestone
2. SOURCES OF SUPPLY N.R. Hamm Quarry
(local quarry)
3. CHEMICAL COMPOSITION (for each source)
SILICATES
SILICA _§*
CALCIUM CARBONATE 93%
MAGNESIUM CARBONATE 1%
EXCESS SCRUBBING AGENT USED ABOVE
STOICHIOMETRIC REQUIREMENTS 60-65% *
5. MAKE-UP WATER POINT OF ADDITION Recirculation Tank
6. MAKE-UP ALKALI POINT OF ADDITION Injection into furnace
* Rate adjusted to give 5.5 pH in marble bed.
A-6
5/17/74
-------
\
0
(s)
VFKOM TKAI15
CLEAN CAS 10 STACK
WATER MAKEUP
)TO TRAINS
TO TRAINS
LIME/LIMESTONE SLURRY
STREAM NO
RATE. Ib/hr
ACFM
CPM
PARTICULATES. Ib/hr
SO;. Ib/hr
TEMPERflTURE.°F
TOTAL SOLIDS. %
SPECIFIC GRAVITY.
CO
CO
C3^
,
CO
CO
CO
CO
CO
CO
C'O)
OD
on
C'3)
STREAM NO
RATE. Ib/hr
ACFM
CPM
PARTICIPATES. Ib/hr
SOj, |b/hr
TEMPERATURE. *F
TOTAL SOLIDS. %
SPECIFIC GRAVITY
C.4)
OS)
Cl6) j (H)
Cl8)
0?)
•
•
C20)
Q.O
C22]
©
®
•
®
W
I. Representative flow rates based on operating data at maximum continuous load 5/17/74
-------
SCRUBBER TRAIN SPECIFICATIONS
1.
SCRUBBER NO. 1 (a)
TYPE (TOWER/VENTURI)
LIQUID/GAS RATIO, G/MCF @
Tower
22
GAS VELOCITY THROUGH SCRUBBER, FT/SEC
MATERIAL OF CONSTRUCTION
TYPE OF LINING
INTERNALS:
6-7 ft/sec
C.S.
Ceilcote epoxy
w/glass flakes
TYPE (FLOATING BED, MARBLE BED, ETC.) Marble bed
one
3/4" Pyrex glass
3-1/2"
glass
316 SS - Plates
304 SS - Support
NUMBER OF STAGES
TYPE AND SIZE OF PACKING MATERIAL
PACKING THICKNESS PER STAGE
-------
PACKING THICKNESS PER STAGED
MATERIAL OF CONSTRUCTION, PACKING:
SUPPORTS:
CLEAR WATER TRAY (AT TOP OF SCRUBBER)
TYPE None
L/G RATIO
SOURCE OF WATER
DEMISTER
TYPE (CHEVRON, ETC.)
NUMBER OF PASSES (STAGES)
SPACE BETWEEN VANES
ANGLE OF VANES
TOTAL DEPTH OF DEMISTER
DIAMETER OF DEMISTER
DISTANCE BETWEEN TOP OF PACKING
AND BOTTOM OF DEMISTER
POSITION (HORIZONTAL, VERTICAL)
MATERIAL OF CONSTRUCTION
METHOD OF CLEANING
SOURCE OF WATER AND PRESSURE
FLOW RATE DURING CLEANINGS, GPM
Chevron
Two
2"
45'
24" (6"/demister + 12"
space)
4 - 4-1/2 ft
Fiberglass
Pond water, 150 psig
FREQUENCY AND DURATION OF CLEANING Once every 24 hrs.
REMARKS One blower is turned on at a time
5. REHEATER
TYPE (DIRECT, INDIRECT)
Indirect
b) For floating bed, packing thickness at rest.
A-9
5/17/74
-------
DUTY, MMBTU/HR 21 (~ 10 per reheater)
HEAT TRANSFER SURFACE AREA SQ.FT
TEMPERATURE OF GAS: IN 120 OUT 150
HEATING MEDIUM SOURCE Boiler feed water
TEMPERATURE & PRESSURE 260°F
FLOW RATE 150 qpm/unit
REHEATER TUBES, TYPE AND
MATERIAL OF CONSTRUCTION C.S.
REHEATER LOCATION WITH RESPECT TO DEMISTER
6' to 7' directly above top if demister
METHOD OF CLEANING Compressed Air Blower
FREQUENCY AND DURATION OF CLEANING 6 times/day for 3 min.
FLOW RATE OF CLEANING MEDIUM LB/HR
REMARKS No cleaning problems
6. SCRUBBER TRAIN PRESSURE DROP DATA INCHES OF WATER
PARTICULATE SCRUBBER
S02 SCRUBBER 6" - 8"
CLEAR WATER TRAY N/A
DEMISTER
REHEATER l-l/2"-2"
DUCTWORK
TOTAL FGD SYSTEM 10" max.
A-10
5/17/74
-------
7.
8.
FRESH WATER MAKE UP FLOW RATES AND POINTS OF ADDITION
TO: DEMISTER
QUENCH CHAMBER
ALKALI SLURRYING
PUMP SEALS Pond Water
OTHER
TOTAL Evap. load 125 gpm. blowdown 175 qpm = 300 gpm
FRESH WATER ADDED PER MOLE OF SULFUR REMOVED
BYPASS SYSTEM
CAN FLUE GAS BE BYPASSED AROUND FGD SYSTEMS No
GAS LEAKAGE THROUGH BYPASS VALVE, ACFM ™
K. SLURRY DATA
LIME/LIMESTONE SLURRY MAKEUP TANK
PARTICULATE SCRUBBER EFFLUENT
HOLD TANK (a)
S02 SCRUBBER EFFLUENT HOLD
TANK (a)
PH
9.5
to
10
%
Solids
8.5
to
9.5
Capacity
(gal)
Hold up
time
40 min.
LIMESTONE MILLING AND CALCINING FACILITIES: INDICATE BOILERS
SERVED BY THIS SYSTEM.
A-11
TYPE OF MILL (WET CYCLONE, ETC.) Old Coal Pulverizers
NUMBER OF MILLS One
CAPACITY PER MILL
RAW MATERIAL MESH SIZE
PRODUCT MESH SIZE
15
1-1/4"
5/17/74
T/HR
60% through 200 mesh
-------
SLURRY CONCENTRATION IN MILL
CALCINING In ftirnacg
SOURCE OF WATER FOR SLURRY MAKE UP OR
SLAKING TANK
M. DISPOSAL OF SPENT LIQUOR
1. SCHEMATICS OF SLUDGE & FLY ASH DISPOSAL METHOD
(IDENTIFY QUANTITIES OR SCHEMATIC)
2. CLARIFIERS (THICKENERS)
NUMBER
DIMENSIONS
CONCENTRATION OF SOLIDS IN UNDERFLOW
3. ROTARY VACUUM FILTER
NUMBER OF FILTERS
CLOTH AREA/FILTER
CAPACITY TON/HR (WET CAKE)
CONCENTRATION OF SOLIDS IN CAKE
PRECOAT (TYPE, QUANTITY, THICKNESS)
REMARKS ___
4. SLUDGE FIXATION
POINT OF ADDITIVES INJECTION None
FIXATION MATERIAL COMPOSITION
FIXATION PROCESS (NAME)
FIXATION MATERIAL REQUIREMENT/TONS OF DRY SOLIDS OF SLUDGE
A-12 5/17/74
-------
Plant has room for one more 30 acre x. 16" pond
ESTIMATED POND LIFE, YRS. ~ 20 years
CONCENTRATION OF SOLIDS IN FIXED SLUDGE
METHOD OF DISPOSAL OF FIXED SLUDGE
INITIAL SOLIDIFICATION TIME OF FIXED SLUDGE
5. SLUDGE QUANTITY DATA
POND/LANDFILL SIZE REQUIREMENTS, ACRE-FT/YR
IS POND/LANDFILL ON OR OFFSITE
TYPE OF LINER
IF OFFSITE, DISTANCE AND COST OF TRANSPORT
POND/LANDFILL DIMENSIONS AREA IN ACRES
DEPTH IN FEET
DISPOSAL PLANS; SHORT AND LONG TERM
N. COST DATA
1. TOTAL INSTALLED CAPITAL COST
2. ANNUALIZED OPERATING COST
A-13
5/17/74
-------
3.
COST BREAKDOWN
COST ELEMENTS
CAPITAL COSTS
SO_ SCRUBBER TRAINS
2.
LIMESTONE MILLING
FACILITIES
SLUDGE TREATMENT &
DISPOSAL POND
SITE IMPROVEMENTS
LAND, ROADS, TRACKS,
SUBSTATION
ENGINEERING COSTS
CONTRACTORS FEE
INTEREST ON CAPITAL
DURING CONSTRUCTION
ANNUALIZED OPERATING COST
FIXED COSTS
INTEREST ON CAPITAL
DEPRECIATION
INSURANCE & TAXES
LABOR COST
INCLUDING OVERHEAD
VARIABLE COSTS
RAW MATERIAL
UTILITIES
MAINTENANCE
INCLUDED IN
ABOVE .COST
ESTIMATE
YES NO
EH EH
EH EH
EH EH
EH
El EH
EH EH
EH EH
n EH
EH EH
EH EH
EH EH
CH O
CU EH
EH EH
ESTIMATED AMOUNT
OR % OF TOTAL
INSTALLED CAPITAL
COST
A.
B.
A-14
5/17/74
-------
4. COST FACTORS
a. ELECTRICITY
b. WATER
c. STEAM (OR FUEL FOR REHEATING)
d. FIXATION COST $/TON OF DRY SLUDGE
e. RAW MATERIAL PURCHASING COST $/TON OF DRY SLUDGE
f. LABOR: SUPERVISOR HOURS/WEEK WAGE
OPERATOR
OPERATOR HELPER
MAINTENANCE
0. MAJOR PROBLEM AREAS: (CORROSION, PLUGGING, ETC.)
1. SO2 SCRUBBER, CIRCULATION TANK AND PUMPS.
a. PROBLEM/SOLUTION
Numerous problems and modifications. Refer to
section 4.0 of the report for details.
2. DEMISTER
PROBLEM/SOLUTION Demisters vanes thin and fragile
would break easily as result of operators walking
on them or from high pressure of wash water.
Installed new deminsters of different design and
wall thickness.
3. REHEATER
PROBLEM/SOLUTION Original tubes had closely spaced
fins which caused buildup of solids between adjoining
fins over short periods. Replace reheater bundle
with one having widely spaced fins.
5/17/74
-------
4. VENTURI SCRUBBER, CIRCULATION TANKS AND PUMPS
PROBLEM/SOLUTION
5. I.D. BOOSTER FAN AND DUCT WORK
PROBLEM/SOLUTION No major problem, but have to sandblast
shaft and blades about twice/yr. Wished they had speed
regulator on fans so that they can be operated at
slower speed when they are slightly out of balance.
6. LIMESTONE MILLING SYSTEM OR LIME SLAKING
PROBLEM/SOLUTION Some problems (wear of internals)
on grinders but nothing serious.
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.
pH nf fjirculatied slurry controlled to predetermine
as load is changed.
5/17/74
-------
R. COMPUTATION OF FGD SYSTEM AVAILABILITY FACTOR
BOILER RATING OR MAXIMUM CONTINUOUS CAPACITY, MW
PERIOD
MONTH/YEAR
FLUE GAS DESULFURIZATION MODULES
MODULE A
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE B
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE C
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE D
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
t->
00
Availability factor computation: 1,
Divide boiler capacity by the number of modules
and obtain MW/module = x
Multiply boiler capacity by number of hours
during period = a
Add all down times due to module trouble for all modules
during period = b
Add all down times due to boiler trouble or reduction
in electricity demand for all modules during period = c
Availability factor = [a " X_ »> + c)]100 = %
cl X ^
5/17/74
-------
PLANT SURVEY FORM
NON-REGENERABLE FGD PROCESSES
A. COMPANY AND PLANT INFORMATION
1. COMPANY NAME Kansas Power and Light Company
2. MAIN OFFICE Topeka. Kansas
3. PLANT MANAGER Lee Brunton
4. PLANT NAME Lawrence Power Station
5. PLANT LOCATION Lawrence. Kansas
6 . PERSON TO CONTACT FOR FURTHER INFORMATION Kelley ft
7. POSITION Production Engineer
8. TELEPHONE NUMBER _
9. DATE INFORMATION GATHERED -13-74
10. PARTICIPANTS IN MEETING AFFILIATION
Kellev Green
Lee Brunton KPT.
Wade Ponder EPA
John Busik EPA
Tim Devitt PEDCo
Fouad Zada PEDCo
A-19
5/17/74
-------
B. PLANT DATA. (APPLIES TO ALL BOILERS AT THE PLANT).
CAPACITY, MW
SERVICE (BASE, PEAK)
FGD SYSTEM USED
BOILER NO.
4
125
cyclic
/
5
400
cyclic
/
BOILER DATA. COMPLETE SECTIONS (C) THROUGH (R) FOR EACH
BOILER HAVING AN FGD SYSTEM.
1. BOILER IDENTIFICATION NO.
2. MAXIMUM CONTINUOUS HEAT INPUT
- 3200
3. MAXIMUM CONTINUOUS GENERATING CAPACITY
4. MAXIMUM CONTINUOUS FLUE GAS RATE,
5. BOILER MANUFACTURER Combustion Engineering
6. YEAR BOILER PLACED IN SERVICE
MM BTU/HR
MW
ACFM @ °P
7. BOILER SERVICE (BASE LOAD, PEAK, ETC.)
8. STACK HEIGHT
9. BOILER OPERATION HOURS/YEAR (197 )
10. BOILER CAPACITY FACTOR *
11. RATIO OF FLY ASH/BOTTOM ASH
cyclic
* DEFINED AS: KwH GENERATED IN YEAR
MAX. CONT. GENERATED CAPACITY IN KW X 8760 HR/YR
A-20
5/17/74
-------
D. FUEL DATA
1. COAL ANALYSIS (as received)
GHV (BTU/LB.)
S %
ASH %
2. WYOMING COAL ANALYSIS
GRADE
S %
ASH %
MAX.
4.0%
MIN.
3.5%
AVG.
12,000
3.75%
12%
0.8%
0.4%
10,000
0.53%
10%
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
0.16
so2
1.5
2. PLANT PROGRAM FOR PARTICULATES COMPLIANCE
Unit never been tested and probably would not meet
compliance level because of poor gas distribution
3. PLANT PROGRAM FOR S02 COMPLIANCE
* Plant has ~400,000 tons on hand and consumes -3000 TP1J for both
No. 4 and 5
A-21
5/17/74
-------
F. PARTICULATE REMOVAL
1. TYPE
MANUFACTURER
EFFICIENCY: DESIGN/ACTUAL
MAX. EMISSION RATE* LB/HR
GR/SCF
LB/MMBTU
DESIGN BASIS, SULFUR CONTENT
MECH.
E.S.P.
FGD
C.E.
G. DESULFURIZATION SYSTEM DATA
1. PROCESS NAME
2. LICENSOR/DESIGNER NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
3. ARCHITECTURAL/ENGINEERS, NAME:
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
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 1968
e) DATE ON SITE CONSTRUCTION COMPLETED
f) DATE OF INITIAL STARTUP 3/71
g) DATE OF COMPLETION OF SHAKEDOWN 11/71
*At Max. Continuous Capacity
A-22
5/17/74
-------
5. LIST MAJOR DELAYS IN CONSTRUCTION SCHEDULE AND CAUSES:
6. NUMBER OF SO2 SCRUBBER TRAINS USED eight
7. DESIGN THROUGHPUT PER TRAIN, ACFM @ °F * 150.000 SCFM
8. DRAWINGS: 1) PROCESS FLOW DIAGRAM AND MATERIAL BALANCE
2) EQUIPMENT LAYOUT
H. SO2 SCRUBBING AGENT
1. TYPE Limestone
2. SOURCES OF SUPPLY N.R. Hamm Quarry CA.5
Roadroak (local quarry)
3. CHEMICAL COMPOSITION (for each source)
SILICATES
SILICA 6%
CALCIUM CARBONATE 93%
MAGNESIUM CARBONATE 1%
EXCESS SCRUBBING AGENT USED ABOVE
STOICHIOMETRIC REQUIREMENTS 60-65% *
5. MAKE-UP WATER POINT OF ADDITION Slurry Circ. tank
6. MAKE-UP ALKALI POINT OF ADDITION Injection into furnace
* Rate adjusted to give 5.5 pH in marble bed.
A-23
5/17/74
-------
1 •
]
<'
0
(?)
FROM TRAINS
CLEAN CAS 10 STACK
WATER MAKEUP
TO TRAINS
> TO TRAINS
UMC/UMESTOHt SlURRY
STREAM NO.
HATE, Ib/hr
ACfM
CPM
PARTICULATtS. Ib/hr
SO;. Ib/hr
TEMPERflTURE,°F
TOTAL SOLIDS. %
SPECIFIC GRAVITY,
CO
&
— .„
CO
CO
CO
QQ
CO
CO
'
CO
0
C»D
GD
(13)
I
to
STREAM NO.
RATE, Ib/hr
flCFM
CPM
PARTICIPATES. Ib/hr
S02 . Ib/hr
TfMP[RflTURE.°F
TOTfll SOI IDS, %
SPtCIHC GRAVITY
C'i)
00
(16)
Gi)
-
(is)
CJ9)
C20)
QO
C22)
(23)
C24)
C25)
C26) .
I. Representative flow rates based on operating data at maximum continuous load
5/17/74
-------
SCRUBBER TRAIN SPECIFICATIONS
1.
SCRUBBER NO. 1
TYPE (TOWER/VENTURI)
LIQUID/GAS RATIO, G/MCF @
Town
°F 22
GAS VELOCITY THROUGH SCRUBBER, FT/SEC
MATERIAL OF CONSTRUCTION
TYPE OF LINING
INTERNALS:
6 to 7 ft/sec
C.S.
Celcote epoxy with
glass flakes
TYPE (FLOATING BED, MARBLE BED, ETC.) Marble bed
One
3/4" Pyrex glass
3-1/2"
Glass
304 Sfi
316L SS
NUMBER OF STAGES
TYPE.AND SIZE OF PACKING MATERIAL
PACKING THICKNESS PER STAGED
MATERIAL OF CONSTRUCTION, PACKING:
SUPPORTS:
t*\ Plate
2. SCRUBBER NO. 2 ta;
TYPE {TOWER/VENTURI)
LIQUID/GAS RATIO, G/MCF @ °F
GAS VELOCITY THROUGH SCRUBBER, FT/SEC
MATERIAL OF CONSTRUCTION
TYPE OF LINING
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.)
NUMBER OF STAGES
TYPE AND SIZE OF PACKING MATERIAL
a) Scrubber No. 1 is the scrubber that the flue gases first
enter. Scrubber 2 (if applicable) follows Scrubber No. 1.
b) For floating bed, packing thickness at rest.
A-25
5/17/74
-------
PACKING THICKNESS PER STAGED
MATERIAL OF CONSTRUCTION, PACKING:
SUPPORTS:
CLEAR WATER TRAY (AT TOP OF SCRUBBER)
TYPE None
L/G RATIO
SOURCE OF WATER
DEMISTER
TYPE (CHEVRON, ETC.)
NUMBER OF PASSES (STAGES)
SPACE BETWEEN VANES
ANGLE OF VANES
TOTAL DEPTH OF DEMISTER
DIAMETER OF DEMISTER
DISTANCE BETWEEN TOP OF PACKING
AND BOTTOM OF DEMISTER
POSITION (HORIZONTAL, VERTICAL)
MATERIAL OF CONSTRUCTION
METHOD OF CLEANING
SOURCE OF WATER AND PRESSURE
FLOW RATE DURING CLEANINGS, GPM
Chevron
Two
2"
45'
24" (6" per demister
12" spacing)
7'-8' for original
6 modules
Fiberglass
Power washing lances
Pond, 150 psig
FREQUENCY AND DURATION OF CLEANING Once every 24 hrs.
for one hour.
REMARKS
5. REHEATER
TYPE (DIRECT, INDIRECT)
Indirect
b) For floating bed, packing thickness at rest.
A-26
5/17/74
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DUTY, MMBTU/HR ~80 (10 per reheater)
HEAT TRANSFER SURFACE AREA SQ.FT
TEMPERATURE OF GAS: IN 120 OUT 150
HEATING MEDIUM SOURCE Boiler feed water
TEMPERATURE & PRESSURE 260°F
FLOW RATE 150 gpm Unit
REHEATER TUBES, TYPE AND
MATERIAL OF CONSTRUCTION C.S.
REHEATER LOCATION WITH RESPECT TO DEMISTER.
6' to 7' above top of demister
METHOD OF CLEANING
FREQUENCY AND DURATION OF CLEANING 6 times/day for 3 minutes
FLOW RATE OF CLEANING MEDIUM LB/HR
REMARKS No cleaning problem
6. SCRUBBER TRAIN PRESSURE DROP DATA INCHES OF WATER
PARTICULATE SCRUBBER
S02 SCRUBBER 6"-8"
CLEAR WATER TRAY N/A
DEMISTER
REHEATER l-l/2"-2.0"
DUCTWORK
TOTAL FGD SYSTEM in-
A-27
5/17/74
-------
7. FRESH WATER MAKE UP FLOW RATES AND POINTS OF ADDITION
TO: DEMISTER
QUENCH CHAMBER.
ALKALI SLURRYING
PUMP SEALS Same water (pond water\
OTHER
TQTAT. 1200 gpm
FRESH WATER ADDED PER MOLE OF SULFUR REMOVED_
8. BYPASS SYSTEM
CAN FLUE GAS BE BYPASSED AROUND FGD SYSTEMS Yes
GAS LEAKAGE THROUGH BYPASS VALVE, ACFM zero
K. SLURRY DATA
LIME/LIMESTONE SLURRY MAKEUP TANK
PARTICULATE SCRUBBER EFFLUENT
HOLD TANK (a)
SO2 SCRUBBER EFFLUENT HOLD
TANK (a)
pH
9.5
to
10
%
Solids
8.5
to
9.5
Capacity
(gal)
Hold up
time
30 minutes
L. LIMESTONE MILLING AND CALCINING FACILITIES: INDICATE BOILERS
SERVED BY THIS SYSTEM.
TYPE OF MILL (WET CYCLONE, ETC.)
NUMBER OF MILLS Two
CAPACITY PER MILL
RAW MATERIAL MESH SIZE 1-1/4"
PRODUCT MESH SIZE 60% through 200 mesh
A-28
T/HR
5/17/74
-------
SLURRY CONCENTRATION IN MILL
CALCINING In furnace
SOURCE OF WATER FOR SLURRY MAKE UP OR
SLAKING TANK
M. DISPOSAL OF SPENT LIQUOR
1. SCHEMATICS OF SLUDGE & FLY ASH DISPOSAL METHOD
(IDENTIFY QUANTITIES OR SCHEMATIC)
2. CLARIFIERS (THICKENERS)
NUMBER
DIMENSIONS
CONCENTRATION OF SOLIDS IN UNDERFLOW
3. ROTARY VACUUM FILTER
NUMBER OF FILTERS
CLOTH AREA/FILTER
CAPACITY TON/HR (WET CAKE)
CONCENTRATION OF SOLIDS IN CAKE
PRECOAT (TYPE, QUANTITY, THICKNESS)
REMARKS
4. SLUDGE FIXATION
POINT OF ADDITIVES INJECTION None
FIXATION MATERIAL COMPOSITION
FIXATION PROCESS (NAME)
FIXATION MATERIAL REQUIREMENT/TONS OF DRY SOLIDS OF SLUDGE
5/17/74
-------
There'is room for one more 30 acre x 16" pond
ESTIMATED POND LIFE, YRS. 220 years
CONCENTRATION OF SOLIDS IN FIXED SLUDGE
METHOD OF DISPOSAL OF FIXED SLUDGE
INITIAL SOLIDIFICATION TIME OF FIXED SLUDGE
5. SLUDGE QUANTITY DATA
POND/LANDFILL SIZE REQUIREMENTS, ACRE-FT/YR
IS POND/LANDFILL ON OR OFFSITE
TYPE OF LINER
IF OFFSITE, DISTANCE AND COST OF TRANSPORT
POND/LANDFILL DIMENSIONS AREA IN ACRES
DEPTH IN FEET
DISPOSAL PLANS; SHORT AND LONG TERM
N. COST DATA
1. TOTAL INSTALLED CAPITAL COST
2. ANNUALIZED OPERATING COST
A-30
5/17/74
-------
3.
COST BREAKDOWN
COST ELEMENTS
CAPITAL COSTS
SO2 SCRUBBER TRAINS
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
n
n
en
n
n
en
0
o
n
n
n
n
en
NO
n
a
a
a
a
a
a
a
a
a
a
CD
a
ESTIMATED AMOUNT
OR % OF TOTAL
INSTALLED CAPITAL
COST
A.
B.
A-31
5/17/74
-------
4. COST FACTORS
a. ELECTRICITY
b. WATER
C. STEAM (OR FUEL FOR REHEATING)
d. FIXATION COST
6. 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.
3. REHEATER
PROBLEM/SOLUTION
A-32
5/17/74
-------
4. VENTURI SCRUBBER, CIRCULATION TANKS AND PUMPS
PROBLEM/SOLUTION
5. I.D. BOOSTER FAN AND DUCT WORK
PROBLEM/SOLUTION Poor distribution of flue gas to
all modules is still an outstanding problem which have
not been solved
6. LIMESTONE MILLING SYSTEM OR LIME SLAKING
PROBLEM/SOLUTION
7. SLUDGE TREATMENT AND DISPOSAL
PROBLEM/SOLUTION
A~33 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.
A-34
5/17/74
-------
R.
COMPUTATION OF FGD SYSTEM AVAILABILITY FACTOR
BOILER RATING OR MAXIMUM CONTINUOUS CAPACITY, MW
PERIOD
MONTH/YEAR
FLUE GAS DESULFURIZATION MODULES
MODULE A
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE B
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE C
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE D
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
>
OJ
Availability factor computation:
Unit did not run long enough
to have availability factor.
Divide boiler capacity by the number of modules
and obtain MW/module = x
Multiply boiler capacity by number of hours
during period = a
Add all down times due to module trouble for all modules
during period = b
Add all down times due to boiler trouble or reduction
in electricity demand for all modules during period = c
Availability factor = [a " X
-------
APPENDIX B
PLANT PHOTOGRAPHS
B-l
-------
Photo No. 1 General view of the two FGD modules installed
on Lawrence 4. Each module consists of a single-stage
marble bed, a mist eliminator, a flue gas reheater and a
separate booster fan (shown on the uppermost level) and a
separate stack. Both modules share a common slurry recir-
culation tank shown in the foreground.
B-2
-------
Photo No. 2 A side view of one of the two modules on
Lawrence 4 showing the bank of mist eliminator's water wash
lances. The reheater soot blowers which use compressed air
are shown on the second level.
B-3
-------
Photo No. 3 Close-up view of the slurry recirculation
headers as they enter the walls of the module below the
marble bed level. The light colored fiberglass elbows which
replaced worn-out fittings, points to the areas which are
mostly susceptible to erosion in the slurry recirculation
loop.
B-4
-------
Photo No. 4 Top view of the slurry recirculation tank which
serves the two modules on Lawrence 4. The overflow from
this concrete tank is pumped to the fly ash and sludge
disposal ponds.
B-5
-------
Photo No. 5 Partial view of 1 of the 8 FGD modules ©n
Lawrence 5. The three retractable soot blowers which serve
the reheater unit on each module are shown in the center of
the picture.
B-6
-------
Photo No. 6 Top view of the slurry recirculation tank which
is common to all the 8 modules on Lawrence 5. During the
plant visit, Lawrence 5 was operating on natural gas and the FGD
system was not in operation, as evidenced by the stagnant
liquor in the tank.
B-7
-------
Photo No. 7 The spent slurry from both Lawrence 4 and 5 is
discharged to three interconnected ponds. The slurry first
enters the 16-acre pond (shown on the left) and the clar-
ifier liquor overflows to the 28-acre pond (in the back-
ground) or the 4-acre pond shown on the right. The clar-
ified liquor is recycled to the scrubber modules from the 4-
acre pond.
B-8
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO
EPA-650/2-75-057-6
3 RECIPIENT'S ACCESSION NO
4 TITLE AND SUBTITLE
Survey of Flue Gas Desulfurization Systems
Lawrence Power Station, Kansas Power and Light
Company
5 REPORT DATE
September 1975
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO,
Gerald A. Isaacs and Fouad K. Zada
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 6e
12 SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13 TYPE OF REPORT AND.PERIQD.CO'
Subtask Final; 8/74-9/75
VERED
14. SPONSORING AGENCY CODE
IS SUPPLEMENTARY NOTES
16 ABSTRACT
repOrt gives result s of a survey of the flue gas desulfurizati on (FGD)
systems at Kansas Power and Light Co.'s Lawrence Power Station. The systems
utilize boiler injection of pulverized limestone, followed by tail-end wet scrub-
bing: unit 4, with a net capacity of 102 MW, was retrofitted with two FGD mod-
ules and was placed in service in November 1968; and boiler 5, with a net capacity
of 320 MW, and its FGD system were started up in 1971. Both boilers operate at
half -load at night so that the modules can be shut down for regular maintenance.
Forced outages are infrequent because the FGD demand factor is fairly low. Oper-
ating problems include corrosion, unsatisfactory damper operation, demister fouling,
expansion j oint failures , and pump failures. The spent slurry contains fly ash and
unreacted lime which stabilize and solidify the sludge in unlined ponds without furthur
treatment. KP and L's capital cost in 1968 for the installation of FGD units 4 and 5
was reported to be about #3. 5 million. Substantial additional costs for the system
were borne by the vendor, Combustion Engineering, Inc. Both FGD systems are to
be modified: the two unit 4 modules will be replaced by January 1977; and the unit 5
system will be converted to a tail-end wet limestone process by the fall of 1975.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b IDENTIFIERS/OPEN ENDED TERMS
c COS AT I Field/Group
Air Pollution
Flue Gases
Desulfurization
Limestone
Boilers
Injection
Scrubbers
Coal
Combustion
Cost Engineering
Air Pollution Control
Stationary Sources
Tail-End Wet Scrubbing
13 B
21B 21D
07A,07D
14A
13A
a DISTRIBUTION STATEMENT
Unlimited
19 SECURITY CLASS (This Report)
Unclassified
21 NO OF PAGES
73
20 SECURITY CLASS (This page)
Unclassified
22 PRICE
EPA Form 2220-1 (9-73)
B-9
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