EPA-650/2-75-057-H
September 1975
Environmental Protection Technology Series
URYE
OF FLUE GAS
DESULFURIZATION SYSTEMS
HAWTHORN STATION, KANSAS CITY POWER AND LIGHT CO.
\
01
O
U.S. Environmental Protection Agency
Office of Research and Development
Washington, D. C. 20460
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EPA-650/2-75-057-h
SURVEY
OF FLUE GAS
DESULFURIZATION SYSTEMS
HAWTHORN STATION, KANSAS CITY 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 6h
ROAP No. 21ACX-130
Program Element No. LAB013
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-h
11
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ACKNOWLEDGMENT
This report was prepared under the direction of Mr.
Timothy W. Devitt. Principal authors were Dr. Gerald A.
Isaacs and Mr. Fouad K. Zada.
Mr. Wade H. Ponder, former EPA Project Officer, had
primary responsibility within EPA for this project report.
Information and data on plant operation were provided by Mr.
Charles Trask, Kansas City Power and Light Company, and by
Mr. Peter Maurin, 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.
111
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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 SYSTEMS 3-1
3.1 Process Description 3-1
3.2 Design Parameters 3-6
3.3 Installation Schedule 3-6
3.4 Cost Data 3-9
4.0 FGD SYSTEM PERFORMANCE ANALYSIS 4-1
4.1 General Discussion 4-1
4.2 Start-up Problems and Solutions 4-1
APPENDIX A PLANT SURVEY FORM A-l
APPENDIX B PLANT PHOTOGRAPHS B-l
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LIST OF FIGURES
No.
3.1 Process flow Diagram of a Typical FGD Module,
Similar to Those Used on Boilers 3 and 4
3.2 Sketch of a Dry Limestone Furnace Injection
Process With a Tail-End Scrubbing FGD System
Page
3-2
3-3
4.1 Sketch of the Reaction Tank Showing the Rounding 4-3
Off of the Tanks' Corners and the Installation
Of Make-Up Water, Sediment Flushing System
LIST OF TABLES
No.
2.1 Pertinent Data on Plant Design, Operation
and Atmospheric Emissions
3.1 Summary of Data: FGD Scrubber Tower
3.2 Summary of Data: FGD System Hold Tanks
3.3 Summary of Data: FGD System Pressure Drop
Page
2-3
3-7
3-7
3-8
VI
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SUMMARY
The dry limestone flue gas desulfurization (FGD)
systems on Boilers No. 3 and 4 at the Hawthorn Power Station
of Kansas City Power and Light Company (KCP&L) were designed
and installed by Combustion Engineering, Inc. (C-E). Ini-
tially, both systems were designed to operate by injection
of dry limestone in the boiler's furnace, followed by tail
gas scrubbing of both the SO- and the furnace-calcined
limestone (as well as the fly ash) from the flue gas stream.
Because of tube plugging in Boiler No. 4, attributed to
limestone injection, the mode of operation of this FGD
system was modified. Ground limestone is no longer injected
into the furnace but instead is introduced into the flue gas
near the gas inlet to the tail scrubber tower. The FGD
system on Boiler No. 3 continues to operate as originally
designed. Both systems, however, have undergone numerous
modifications to attempt to overcome such difficulties as
buildup of sediment and plugging of various components.
The FGD system on each boiler consists of two identical
modules, each capable of treating 500,000 acfm of flue gas
at 300°F. Bypassing of the modules is possible through a
system of ductwork and dampers around each module. Water-
vn
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filled seals are provided in the bypass lines to prevent gas
leakage during normal operation.
The FGD system on Boiler No. 4 was placed in operation
in August 1972; the system of Boiler No. 3 was started in
November 1972. Removal efficiencies for particulate and
sulfur dioxide were 99 percent and 70 percent, respectively.
The plant has no limestone grinding facilities as such.
Limestone is ground in the coal pulverizers of Boilers 1 and
2 on an intermittent basis.
The spent limestone slurry from all modules is dis-
charged into a common clarifier tank, and the underflow is
pumped, untreated and unstabilized, to an unlined pond,
which is also used for disposal of fly ash from the other
boilers.
A considerable portion of the capital investment asso-
ciated with the FGD systems was underwritten by the vendor
so that KCP&L's investment is estimated to be only about
$5.6 million (about $19/KW). The annualized operating cost
is reported to range between 2.2 and 2.5 mills/KWH.
Because of continued operational problems since start-
up, the availability factor for the systems has been low (in
the range of 30 to 40%). Recent operation of the FGD
system on Boilers 3 and 4 has shown improvement, with
availability reported at around 50 percent.
Pertinent facility and FGD operational data are sum-
marized in the following table.
Vlll
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SUMMARY OF FGD DATA, BOILERS NO. 3 AND 4,
HAWTHORN POWER STATION
Unit rating
Fuel characteristics
FGD vendor:
Process:
New or retrofit:
Start-up date:
FGD modules:
Efficiency, %
Particulates
so2
Make-up water:
Sludge disposal:
Unit cost:
100 MW
Coal (high ash): 14% ash, 3% S,
11,500 BTU/lb
Coal (low ash): 11% ash, 0.6% S,
9,800 BTU/lb
Combustion Engineering
Limestone injection
Retrofit
Boiler No. 3 - August 1972
Boiler No. 4 - November 1972
Two per boiler
99
70
8 gpm/MW
Unstabilized sludge disposed in
unlined pond
KCP&L capital investments approximately
519/KW; in addition to considerable
capital expenditures by vendor;
operating cost approximately 2.5
mills/KWH.
When burning coal. The maximum boiler generating capacity
when burning natural gas is 140 MW.
IX
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1.0 INTRODUCTION
The Industrial Environmental Research Laboratory
(formerly 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 utility boilers in the United States. This
report on the Hawthorn Power Station of Kansas City Power
and Light Company (KCP&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.
This report is based upon information obtained during a
plant inspection on June 6, 1974, and on data provided by
KCP&L and Combustion Engineering, Inc. personnel.
Section 2.0 presents pertinent data on facility design
and operation, including actual and allowable particulate
and S02 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 Hawthorn Power Station of KCP&L is located in a
heavily industrialized area on the north bank of the Missouri
River in East Kansas City, Missouri. -
The plant operates five coal-fired boilers. Boilers
1 and 2 are considered peak boilers, each rated at 80 MW.
Boilers 3 and 4 are cyclic boilers, rated at 100 MW each,
when burning coal. These four boilers were built and
placed in service between 1950 and 1955. Boiler 5 was
placed in service in early 1970; it operates as a base-load
boiler at a rated capacity of 500 MW.
The boilers at the Hawthorn Power Station are all dry-
bottom, pulverized-coal-fired units designed and manufactured
by Combustion Engineering, which also manufactured the FGD
systems for this plant.
Two grades of coal are burned: the higher-ash content
coal typically contains 14 percent ash and 3 percent sulfur,
with a heat content of 11,400 BTU/lb; the lower-ash content
coal has 11 percent ash, 0.6 percent sulfur, and a heat
content of 9800 BTU/lb.
Of the five boilers at the Hawthorn Power Station,
only Boilers 3 and 4 are fitted with FGD systems. Originally
both FGD systems operated by furnace injection of ground
2-1
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limestone rock followed by a flue gas wet-scrubbing system
in which both the SO- and the furnace-calcined limestone were
scrubbed and allowed to react in a reaction tank. This
system is still used on Boiler 3; the system on Boiler 4 has
since been converted to tail-end injection, in which the
ground limestone is injected into the gas duct between the
air heater and the scrubber vessel.
The maximum particulate emission allowed under Reg-
ulation III of the Missouri Air Conservation Commission is
0.19 Ib/MM BTU of heat input to the boiler. The present
atmospheric emission of particulate from the Hawthorn FGD
systems is equivalent to 0.11 Ib/MM. BTU.
Atmospheric emissions of sulfur dioxide are limited by
Regulation XV of the Missouri Air Conservation Commission.
However, this plant is not in a critial area, so SO2
removal is not required by that regulation.
Table 2.1 presents pertinent data on plant design, FGD
system operation, and atmospheric emissions.
2-2
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Table 2.1 PERTINENT DATA ON PLANT DESIGN,
OPERATION AND ATMOSPHERIC EMISSIONS
Boiler data
Rated generating capacity, MW
Average capacity factor, 1974
Served by stack number
Boiler manufacturer
Year placed in service
Maximum coal consumption, ton/hr
Maximum heat input, MM BTU/hr
Stack height above grade, ft.
Flue gas rate - maximum, acfm
Flue gas temperature, °F
Emission controls,
Particulate
so2
Unit 3
100a
44.5
1
C-E
1953
50b
l,000b
200
500,000
300
Absorber
tower
Absorber
tower
Unit 4
100a
47.1
1
C-E
1953
50b
i,ooob
200
500,000
300
Absorber
tower
Absorber
tower
Particulate emission rate,
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
SO- emission rate,
Allowable, Ib/MM BTU
Actual, Ib/MM BTU
0.21
o.ir
0.21
0.11'
ambient air standards only
0.18 0.18
When burning coal. Maximum boiler output when burning
natural gas is 140 MW.
Calculated value.
2-3
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3.0 FLUE GAS DESULFURIZATION SYSTEMS
3.1 PROCESS DESCRIPTION
The FGD systems on Boilers 3 and 4 are identical in
basic design, the primary difference being the point of
limestone injection. As mentioned earlier, dry limestone is
injected directly in the furnace of Boiler 3 and is calcined
to lime. The scrubbing reagent, therefore, is lime and not
limestone. In the system on Boiler 4, the dry limestone is
injected in the flue gas duct near the inlet to the S02
absorber tower.
Two parallel scrubber modules (or trains) are connected
to each boiler. Details of a typical module are shown in
Figures 3.1 and 3.2. Each scrubber module is 18 feet wide,
26 feet long, and 56 feet high. The lower 16 feet of the
module is the reaction tank, in which the materials have
time to complete their chemical reactions to remove sulfur.
To provide thorough mixing and to keep the reactants and the
fly ash in suspension, one mixer is installed on the lower
back wall and a second mixer on the upper front wall of the
reaction tank. Plans are now being made for the addition of
one mixer per module to be installed on the side walls to
further increase agitation in the tank.
3-1
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I l
I \-» STACK
I I
BYPASS
SEAL
"I
LIMESTONE
HOPPER
CRUSHER
OJ
l
NJ
FURNACE
I
T
l
AIR
xl
ER"
175°F
/ l.D. V"
~\ FANS/
V S
TO
DRAIN
CREHEATERS
, j
c
-»—}TO DEAERATOR
DAMPER
LEGEND
AIR POLLUTION CONTROL SYSTEM
NOT APCS EQUIPMENT
DEMISTER SPRAYS j
SCRUBBER CELL
OVERFLOW POTS
Y Y Y V y^Y Y Y Y Y V
DEAERATOR
WATER SUPPLY PUMP
UNDERBED SPRfi
! I I I I I I ! j l I I I !
PRAYS
_
L_FLU_e_GAS \
TO GAS
DEFLECTOR
SPRAY
DRAIN FROM
BYPASS SEAL
TO ASH
POND
TO BYPASS SEAL
TO DEMlSTER
SPRAY
TO CAS DEFLECTOR*
SPRAY
TO MAKEUP
(Courtesy - Kansas City Power and Light Co.)
Figure 3.1 Process flow diagram of a typical FGD module, similar to those
used on Boilers 3 and 4.
-------
U)
I
OJ
LIMESTOME
SUPPLY
COAL
SUPPLY
PULVERIZER
STACK
1.0. FAN
STACK GAS
SCRUBBER
(Courtesy - Kansas City Power and Light Co.)
MAKE UP
WATER
TO ASH DISPOSAL
POND
Figure 3.2 Sketch of a dry limestone furnace injection process with a tail-end scrubbing
FGD system.
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A sloping, perforated plate near the top of the re-
action tanks acts as a strainer to catch large solid objects,
such as scale, mud, or marbles, and funnels them to the
mouth of a jaw crusher. Periodic operation of this equip-
ment reduces these pieces to fine particles, which are
slurried and discharged to the fly ash pond.
As the flue gas enters the absorber tower above the
liquid level in the reaction tank, it comes in contact with
slurry, which is sprayed through 63 nozzles on 14 headers
located under the marble bed. The marble bed consists of a
3- to 4-inch thickness of 3/4-inch-diameter glass marbles.
The marbles are retained on a perforated plate through which
the quenched flue gas and the sprayed slurry bubble giving
the marbles a spinning motion. These marbles provide an
increased surface area to facilitate contact of the re-
actants. The liquid level above the marble bed is 10 to 13
inches high. The liquid overflow from the bed is discharged
through 66 drain pots. The scrubbed flue gases flow upward
10 feet to a double row of chevron separators designed to
remove any water droplets carried by the flue gases. The
gases then pass around horizontal fin-tubed heaters that
reheat the gases to about 175°F before they are discharged
to the stack by the induced-draft fans. Gases from all
modules on Boilers 3 and 4 are discharged to the atmosphere
through a common stack 200 feet high.
3-4
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Limestone for Boilers 3 and 4 is ground intermittently
in the coal pulverizers of Boilers 1 and 2 respectively,
during the periods when these peak-load boilers are not in
service.
Spent liquor from the reaction tank of each module is
discharged to a 115-foot-diameter clarifier tank. The
overflow from this tank flows to a clear well tank, where
make-up water from the Missouri River is added. The dis-
charge from this tank satisfies the water requirements of
the FGD system. Distribution of the water is shown in
Figure 3.1.
Sludge in the underflow from the clarifier tank is
untreated. The thickened sludge is pumped to a 160-acre
pond, which is also used for disposal of fly ash from the
other boilers.
Inlet and outlet dampers are provided on each scrubber
module to divert the gases either through or around the
module. To ensure passage of gases through the scrubber
when it is in operation, a large U-shaped bypass seal is
filled with water to positively close the bypass.
The demister wash system uses a set of eight water
lances, four located above and four below the demister
vanes. These lances automatically wash mud from the de-
misters whenever the dampers close.
Stack gas is reheated by a fin-tube heat exchanger
utilizing hot water from the suction of the boiler feed
3-5
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pumps as a heat source. The water enters the heat exchanger
at 150 psig and 325°F. The reheater tubes are cleaned by
two steam lances located beneath the heat exchanger.
3.2 DESIGN PARAMETERS
The two FGD installations at the Hawthorn Power Station
were designed by Combustion Engineering to treat a total of
about 1,000,000 acfm of flue gas at 300°F. Before the
scrubbers were installed, mechanical precipitators were used
to remove fly ash. Pressure drop across these precipitators
was about 7 inches; this also is the design figure for the
scrubber modules, a value that has never been attained.
Pressure drop across the scrubber module is 10 to 12 inches
of water.
*
The scrubber tower operates with a liquid-to-gas ratio
of about 21 gal./lOOO ft3 of gas at 122°F. Modifications of
the recirculation system have increased this figure to 26
gal./lOOO ft . Superficial velocity through the demister
section of the tower is about 10 ft/sec.
Tables 3.1, 3.2, and 3.3 summarize operating design
parameters and specifications for major components of the
FGD system.
3.3 INSTALLATION SCHEDULE
The installation of the FGD systems at the Hawthorn
Power Station did not proceed according to the pattern for
typical construction projects. The installation was highly
experimental, and the vendor was willing to underwrite a
3-6
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Table 3.1 SUMMARY OF DATA: FGD SCRUBBER TOWER
FGD Scrubber
Tower
L/G ratio,
gal/1000 acf
Superficial gas
velocity, ft/sec
Equipment sizes
Equipment internals
Material of construction
Shell
Internal supports
26
10 (design)
18 x 26 ft x 40 ft high
3.5" thick bed of 3/4"
dia. marbles
Carbon steel (Ceilcote)
316L SS
Table 3.2 SUMMARY OF DATA: FGD SYSTEM HOLD TANKS
SO_ Scrubber
Towers
Holdup
Tank
FGD System
Clarifier Tank
Total number of tanks
Tank size
Retention time at full
load
Temperature, °F
pH
Solids concentration, %
Specific gravity
Material of construction
One/module
18' x 26' x 16'
high
11 min.
122
5.0 to 5.5
10 - 15
Carbon steel
One
115'dia x 10'
4.5 hr
110
5.2
3-7
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Table 3.3 SUMMARY OF DATA: FGD SYSTEM PRESSURE DROP
Equipment
Pressure drop,
inches W.G.
SO2 scrubber tower
Demister
Reheater
Ductwork
Total FGD system
8 - 9.5
1 - 1.5
1 - 1.5
1-2
12 - 13
3-8
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considerable portion of the project. Consequently, C-E was
chosen in advance as the FGD vendor. Therefore, bid specifi-
cations on the FGD systems were not prepared by KCP&L, and
bids were not requested from competing vendors. System
start-up occurred for Unit No. 4 in August 1972 and for Unit
No. 3 in November 1972. Late in 1972, severe limestone
plugging of the top horizontal tubes of Boiler No. 4 was
discovered and the decision was made to convert the FGD
system on this boiler to a tail-end limestone injection
system. Similar plugging has not been observed on Boiler
No. 3, and the FGD unit continues to operate in the original
design mode.
3.4 COST DATA
Detailed data on the capital and operating costs of the
FGD installations at the Hawthorn Power Station are not
available. The capital investment cost is reported to be
about $5.32 million (about $19/KW of the gross generating
capacity). This figure is unrealistically low because this
installation is experimental in nature and was heavily
underwritten by the vendor. This figure accounts for the
FGD systems on both boilers. Operating costs range between
2.2 and 2.5 mills/KWH.
3-9
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4.0 FGD SYSTEM PERFORMANCE ANALYSIS
4.1 GENERAL DISCUSSION
Modifications were completed by Combustion Engineering
in June 1974, and KCP&L has continued to modify the modules
in an effort to improve the operation of the FGD systems.
Module in-service hours in 1975, through May, totaled 1334.
For the same period last year the total was 816 hours.
Continuous monitoring equipment when operational has shown
sulfur removal efficiency in the range of 85 to 95 percent.
Particulate removal efficiency was 98 to 99 percent.
FGD system availability has been consistently low,
mainly due to the bypass seal configuration. The bypass
water seal accumulates flyash when it is opened so that it
cannot be closed again without shutting down the boiler and
manually cleaning the bypass section. Thus, the FGD system
remains "unavailable" until it is convenient to shut down
the boiler. New dampers have been designed and ordered.
They will be installed around mid-1976 to correct this
problem. It is anticipated that this modification will
increase the FGD system availability significantly.
4.2 START-UP PROBLEMS AND SOLUTIONS
Analysis of the problems encountered during and since
start-up, reveals that nearly all were due to mechanical
design rather than process chemistry.
4-1
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Apart from those entailed in switching Unit No. 4 from
furnace injection to tail gas injection, the major problems
encountered with the two FGD systems at the Haw-
thorn Power Station have been identical.
1. Sediment Buildup; The reaction tank of each module
is equipped with two mixers to keep the 10 percent solids in
suspension. A third mixer will be installed to increase
agitation. The original 15-hp mixers were not adequate; a
buildup of hard mud, 6 to 8 feet high, developed in the
corners of the reaction tank. Replacement of the original
mixers with 25-hp units gave no significant improvement.
The most recent modification to eliminate sediment buildup
consists of rounding off the bottom corners of the tanks by
welding triangular steel plates, as shown in Figure 4.1.
Further, a new make-up water piping system was installed,
with four 1-inch nozzles located on the walls about 6 feet
from the base of the tank and oriented to promote circula-
tion and prevent settling of solids.
2. Plugging of the Marble Bed; In the initial con-
struction, the drain pots drained into horizontal headers
that penetrated the module walls and emptied into the re-
action tank. These horizontal headers plugged soon after
the system was placed in operation. The headers were
removed, and sloping headers were placed inside the reaction
tank. These modified headers improved the situation but did
not completely solve the problem. An additional problem
4-2
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MAKE-UP WATER NOZZLES
Figure 4.1 Sketch of the reaction tank showing the
rounding off of the tank's corners and the
installation of make-up water, sediment
flushing system.
4-3
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occurred frequently when drain pots lifted off the marble
bed and allowed marbles to fall into the reaction tank.
Both of these problems have been solved by installation of
new stainless steel drain pots with expanded metal covers; a
3-foot rubber sock allows each pot to drain directly into
the reaction tank. The pots are attached to stainless steel
rods welded to the marble bed support. The covers are
fastened to the pots. Only limited plugging of the new
drain pots has occurred.
Plugging in the marble bed has been reduced by an
operational change. Increasing the liquid-to-gas ratio from
21 to 26 gal./lOOO ft3 at 125°F has increased the flow of
liquid sufficiently to ensure that all parts of the marble
bed are washed by at least two nozzles.
3. Excessive Wear of Spray Nozzles; The spray nozzle
orifices were severly worn by the abrasive action of the fly
ash. The initial nozzles lasted only a few days; these had
to be replaced because the enlarged orifices caused buildup
of mud in the marble bed, overloading of the recycle pump
and clogging of the demister. Although KCP&L installed a
series of nozzles of different materials from different
vendors, the longest life obtained from any of those was
about 3 weeks. Since these nozzles are very expensive,
KCP&L designed a nozzle that could be made in the shop
from pipe parts. These nozzles lasted about 3 weeks,
but their cost was only 5 to 10 percent of the cost of
4-4
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vendors' nozzles. Finally, ceramic nozzles were installed,
and they have exhibited no signs of wear after nearly a year
of operation. This is by far the best performance experi-
enced to date, since all other nozzles were completely worn
within one to three weeks.
4. Demister Plugging: During sustained operations the
scrubber modules must be taken out of service every three
days to firehose mud from the demisters. Plugging has been
controlled somewhat by adding retractable water lance blowers
under the demister and by moving the rotary water lance
blowers from below the demister to between the rows of
demister vanes. Manual washing is still necessary once or
twice each week.
5. Bypass Seal Plugging; As mentioned earlier, when
the flue gas is bypassed around the module, the empty water
seal acts as a mechanical dust collector, accumulating fly
ash. When the module is returned to operation and water is
turned on, the wet fly ash hampers the operation of the
bypass seal. Plugging in this seal has not been eliminated
by changing the flushing sequence within the seal. Plugging
occurs during module operations and almost always requires a
one to two-day unit outage for cleaning. Plans are presently
underway to remove the wet bypass seal altogether and to
install a drawbridge-type damper in hopes of solving this,
the biggest of current operating problems.
4-5
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APPENDIX A
PLANT SURVEY FORMS
A-l
-------
UNIT NO. 3
PLANT SURVEY FORM
NON-REGENERABLE FGD PROCESSES
A. COMPANY AND PLANT INFORMATION
1. COMPANY NAME Kansas City Power & Light
2. MAIN OFFICE Kansas City, Mo.
3. OPERATING Vern Moore
SUPERINTENDENT
4. PLANT NAME Hawthorn Plant
5. PLANT LOCATION Kansas City
6 . PERSON TO CONTACT FOR FURTHER INFORMATION Terry Eaton
7. POSITION Results Superintendent
8. TELEPHONE NUMBER 471-0060 (816)
9 . DATE INFORMATION GATHERED 6/6/74
10. PARTICIPANTS IN MEETING AFFILIATION
KCPL
Vince Palerma KCPL (Part Time)
Vern Moore KCPL
Wade Ponder EPA
John Busik EPA
Fouad K. Zada PEDCo-Environmental
Larry V. Yerino PEDCo-Environmental
A-2
5/17/74
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B. PLANT DATA. (APPLIES TO ALL BOILERS AT THE PLANT).
CAPACITY, MW
SERVICE (BASE, PEAK)
FGD SYSTEM USED
BOILER NO.
1
100
Peak
2
100
Peak
3
140*
Cyclic
25-100%
X
4
140*
Cyclic
25-100%
X
5
500
Base
50-100%
C. BOILER DATA. COMPLETE SECTIONS (C) THROUGH (R) FOR EACH
BOILER HAVING AN FGD SYSTEM.
1. BOILER IDENTIFICATION NO.
2. MAXIMUM CONTINUOUS HEAT INPUT
3. MAXIMUM CONTINUOUS GENERATING CAPACITY 140
100
500.QQQ
4. MAXIMUM CONTINUOUS FLUE GAS RATE,.
5. BOILER MANUFACTURER C-E
6. YEAR BOILER PLACED IN SERVICE
MM BTU/HR
I1W on N.G.
MW on Coal
ACFM @3QQ °F
1953
7. BOILER SERVICE (BASE LOAD, PEAK, ETC.)
8. STACK HEIGHT
9. BOILER OPERATION HOURS/YEAR (1974)
10. BOILER CAPACITY FACTOR * *
11. RATIO OF FLY ASH/BOTTOM ASH
* On Natural Gas, (100 MW on Coal)
* * DEFINED AS: KwH GENERATED IN YEAR
Cyclic
200' (common w/4)
6602
44.5
4/1
MAX. CONT. GENERATED CAPACITY IN KW x 87GO HR/YR
A-3
5/17/74
-------
D. FUEL DATA
1. COAL ANALYSIS (as received)
GHV (BTU/LB.)
S %
ASH %
Low-Ash Hi-Ash
Typical Typical
MAX.
MIN.
9800
0.6
11
AVG.
11400
3
14
2. FUEL OIL ANALYSIS (exclude start-up fuel)
GRADE
S %
ASH %
E. ATMOSPHERIC EMISSIONS
1. APPLICABLE EMISSION REGULATIONS
a) CURRENT REQUIREMENTS
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
MAX. ALLOWABLE EMISSIONS
LBS/MM BTU
b) FUTURE REQUIREMENTS,
COMPLIANCE DATE
REGULATION & SECTION NO.
MAXIMUM ALLOWABLE EMISSIONS
LBS/MM BTU
PARTICULATES
SO-
0.21 Ib/MM BTU
Missouri 3
Ambient air
standards
Missouri 15
PLANT PROGRAM FOR PARTICULATES COMPLIANCE
3. PLANT PROGRAM FOR S02 COMPLIANCE
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
;-e Limestone
Injection
> 99%
G. DESULFURIZATION SYSTEM DATA
C-E Limestone - furnace injection
with tail scrubbing
1. PROCESS NAME
2. LICENSOR/DESIGNER NAME: Combustion Engineering
ADDRESS:
PERSON TO CONTACT:
TELEPHONE NO.:
7301 Mission Road,
Shawnee Mission, Kansas
Clnarft OT ."Tim HnwaTfi
3. ARCHITECTURAL/ENGINEERS, NAME: Black and Veach
1500 Meadow Lake Parkway
ADDRESS: Prairie Village. KS .
PERSON TO CONTACT:
TELEPHONE NO.:
Llovd Svoboda
(913) 361-7000
DATE
PROJECT CONSTRUCTION SCHEDULE:
a) DATE OF PREPARATION OF BIDS SPECS.
b) DATE OF REQUEST FOR BIDS
C) DATE OF CONTRACT AWARD
d) DATE ON SITE CONSTRUCTION BEGAN
e) DATE ON SITE CONSTRUCTION COMPLETED
f) DATE OF INITIAL STARTUP Late Nov. 1972
g) DATE OF COMPLETION OF SHAKEDOWN
*At Max. Continuous Capacity
A-5
5/17/74
-------
5. LIST MAJOR DELAYS IN CONSTRUCTION SCHEDULE AND CAUSES:
None
6. NUMBER OF SO2 SCRUBBER TRAINS USED
7. DESIGN THROUGHPUT PER TRAIN, ACFM @ °F
8. DRAWINGS: 1) PROCESS FLOW DIAGRAM AND MATERIAL BALANCE
2) EQUIPMENT LAYOUT
H. S02 SCRUBBING AGENT
1. TYPE Limestone
2. SOURCES OF SUPPLY City Wide Asphalt Co,
3. CHEMICAL COMPOSITION (for each source)
SILICATES
SILICA 1.92%
CALCIUM CARBONATE 93.6%
MAGNESIUM CARBONATE 1.28%
4. EXCESS SCRUBBING AGENT USED ABOVE
STOICHIOMETRIC REQUIREMENTS
5. MAKE-UP WATER POINT OF ADDITION
6. MAKE-UP ALKALI POINT OF ADDITION
A-6
5/17/74
-------
FLUE CAS
TO TRAINS
®
SLUDGE STABILIZER
[25]
SlUSCE TO
DISPOSAL SITE
Of2
FILTER
FROM TRAINS
RAINSJ
1
<^
>
(A)
@T
>FROM TRAINS
CLEAN CAS TO STACK
SO 2 SCRUBBER
0
WATER MAKEUP
TRAINS
TO TRAINS
LIME/LIMESTONE SLURRY
STREAM NO.
RftTE, Ib/hr
ACFM
CPM
PARTICULATES, Ib/hr
S02. Ib/hr
TEMPERATURE, °F
TOTAL SOLIDS. %
SPECIFIC GRAVITY,
C^
CO
C3^)
C4^
C53
CO
0
-
CO
CO
(10)
C1!)
C1?)
(13)
STREAM NO.
RATE, Ib/hr
ACFM
CPM
PARTICULATES, Ib/hr
S02, Ib/hr
TEMPERATURE, °F
TOTAL SOLIDS, %
SPECIFIC GRAVITY
%
(15)
(16)
C")
(18)
(Is)
•
(20)
(n)
(22)
(23)
(24)
•
(25)
(26) -
i. Representative flow rates based on operating data at maximum continuous load ,- /, - ,
-------
SCRUBBER TRAIN SPECIFICATIONS
1. SCRUBBER NO. 1 (a) Two identical modules: Specs per module:
TYPE (TOWER/VENTURI) Rectangular Tower (18*x26'x40')
LIQUID/GAS RATIO, G/MCF @ 122 °F 21 to 26
GAS VELOCITY THROUGH SCRUBBER, FT/SEC 10
MATERIAL OF CONSTRUCTION Carbon Steel
TYPE OF LINING Ceilcote
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.) Marble Bed
NUMBER OF STAGES One
TYPE AND SIZE OF PACKING MATERIAL 3/4"dia. Glass Marble
PACKING THICKNESS PER STAGE (t>) 3.5"
MATERIAL OF CONSTRUCTION, PACKING: Glass
SUPPORTS: Stainless Steel 316L
SCRUBBER NO. 2
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-8 5/17/74
-------
PACKING THICKNESS PER STAGE
MATERIAL OF CONSTRUCTION, PACKING:.
SUPPORTS:.
CLEAR WATER TRAY (AT TOP OF SCRUBBER)
TYPE
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
4"each(8" total)
18' x 26'
10
Horizontal
Fiberglass
8 wash lances
Clarified & Make-up Water
FREQUENCY AND DURATION OF CLEANING
REMARKS
5. REHEATER
TYPE (DIRECT, INDIRECT)
Finned Tubes - carbon steel
b) For floating bed, packing thickness at rest.
A-9
5/17/74
-------
DUTY, MMBTU/HR
HEAT TRANSFER SURFACE AREA SQ.FT
TEMPERATURE OF GAS: IN 122°F OUT 170-180°F
HEATING MEDIUM SOURCE Hot Water
TEMPERATURE & PRESSURE
FLOW RATE
325°F & 150 psig
REHEATER TUBES, TYPE AND
MATERIAL OF CONSTRUCTION
.LB/HR
Finned tubes Carbon steel
REHEATER LOCATION WITH RESPECT TO DEMISTER Parallel
and on top of demister
METHOD OF CLEANING Retractable steam lance
FREQUENCY AND DURATION OF CLEANING twice/shift
FLOW RATE OF CLEANING MEDIUM LB/HR
REMARKS
6. SCRUBBER TRAIN PRESSURE DROP DATA
PARTICULATE SCRUBBER
SO2 SCRUBBER
CLEAR WATER TRAY
DEMISTER
REHEATER
DUCTWORK
TOTAL FGD SYSTEM
INCHES OF WATER
6" - 9.5"
1 - 1-1/2
1/2 - 1
1/2 - 1
10" to 12"
A-10
5/17/74
-------
7. FRESH WATER MAKE UP FLOW RATES AND POINTS OF ADDITION
TO: DEMISTER
QUENCH CHAMBER
ALKALI SLURRYING
PUMP SEALS
OTHER
TOTAL
FRESH WATER ADDED PER MOLE OF SULFUR REMOVED
3% S Coal
800 GPM @
"100 MW
8. BYPASS SYSTEM
CAN FLUE GAS BE BYPASSED AROUND FGD SYSTEMS
Yes
GAS LEAKAGE THROUGH BYPASS VALVE, ACFM None (liquid seal)
K. SLURRY DATA
LIME/LIMESTONE SLURRY MAKEUP TANK
PARTICULATE SCRUBBER EFFLUENT
HOLD TANK (a)
S02 SCRUBBER EFFLUENT HOLD
TANK (a)
PH
5.5
to
6.5
%
Solids
-
.
10
to
15
Capacity
(gal)
-
^
55000
Hold up
time
-
_
11
L. LIMESTONE MILLING AND CALCINING FACILITIES: INDICATE BOILERS
SERVED BY THIS SYSTEM.
TYPE OF MILL (WET CYCLONE, ETC.)
NUMBER OF MILLS
CAPACITY PER MILL
RAW MATERIAL MESH SIZE
PRODUCT MESH SIZE
A-11
Raymond Bowl Mill
Two {two alternate)
13
___T/HR
1/2" to 3/4"
70% -200 mesh
5/17/74
-------
SLURRY CONCENTRATION IN MILL
CALCINING AND/OR SLAKING FACILITIES
SOURCE OF WATER FOR SLURRY MAKE UP OR
SLAKING TANK
M. DISPOSAL OF SPENT LIQUOR
1. SCHEMATICS OF SLUDGE & FLY ASH DISPOSAL METHOD
(IDENTIFY QUANTITIES OR SCHEMATIC)
2. CLARIFIERS (THICKENERS)
NUMBER one (common w/4)
DIMENSIONS 115' dia x 10" high
CONCENTRATION OF SOLIDS IN UNDERFLOW
ROTARY VACUUM FILTER
None*
NUMBER OF FILTERS
CLOTH AREA/FILTER I
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
-------
ESTIMATED POND LIFE, YRS .
CONCENTRATION OF SOLIDS IN FIXED SLUDGE
METHOD OF DISPOSAL OF FIXED SLUDGE
INITIAL SOLIDIFICATION TIME OF FIXED SLUDGE
5. SLUDGE QUANTITY DATA
POND/LANDFILL SIZE REQUIREMENTS, ACRE-FT/YR
IS POND/LANDFILL ON OR OFFSITE On-site
TYPE OF LINER None
IF OFFSITE, DISTANCE AND COST OF TRANSPORT
POND/LANDFILL DIMENSIONS AREA IN ACRES 160
DEPTH IN FEET 16
DISPOSAL PLANS; SHORT AND LONG TERM
Build new ponds as needed. May excavate existing ponds.
N. COST DATA
1. TOTAL INSTALLED CAPITAL COST in,7?Q,?67.fift
2. ANNUALIZED OPERATING COST (1974) 174.022 (9 months)
A~13 5/17/74
-------
3.
COST BREAKDOWN
COST ELEMENTS
INCLUDED IN
ABOVE COST
ESTIMATE
ESTIMATED AMOUNT
OR % OF TOTAL
INSTALLED CAPITAL
COST
YES
NO
A. 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
B. ANNUALIZED OPERATING COST
FIXED COSTS
INTEREST ON CAPITAL
DEPRECIATION
INSURANCE & TAXES
LABOR COST
INCLUDING OVERHEAD
VARIABLE COSTS
RAW MATERIAL
UTILITIES
MAINTENANCE
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
O. MAJOR PROBLEM AREAS: (CORROSION, PLUGGING, ETC.)
1. S02 SCRUBBER, CIRCULATION TANK AND PUMPS.
a. PROBLEM/SOLUTION 1) Nozzles plugged. Changed to bigger
Ceramic nozzles. 2) Drain headers for post plugged. Changed to individual
drain hoses. 3) Pots expanded metal taps broke loose. Used stronger tie
rods and clamps. 4) PH of (A) and (B) tanks differed (5 and 9 respectively)
Modifications incl. interconnecting suction of both pumps on each tank
through equalizer line. 5) Sediment buildup in reaction tanks. Blinded
tanks corners and installed nozzles on tank walls to improve circulation
2. DEMISTERand suspension of solids.6) Add reactive tank
IHIXG JL 5 •
PROBLEM/SOLUTION Demisters are washed manually.
Plugqage was not experienced. Scaling removed by
improved washing. Added more underspray and overspray
wash nozzles and lances.
3. REHEATER
PROBLEM/SOLUTION No reheater problems. Ash collects
on damper during periods when bypass is open and falls
on reheater tubes when bypass is closed and damper is
closed. This causes slight increase in pressure drop.
A-15 5/17/74
-------
4. VENTURI SCRUBBER, CIRCULATION TANKS AND PUMPS
PROBLEM/SOLUTION
5. I.D. BOOSTER FAN AND DUCT WORK
PROBLEM/SOLUTION Fan vibrates when restarts after
scrubber wash. Problem solved by washing of scrubber_
with fan running.
LIMESTONE MILLING SYSTEM OR LIME SLAKING
PROBLEM/SOLUTION When used to grind limestone, the
coal ball mills have trouble; such as cracking many __
rolls and wearing many balls Problem compensated
for by readjusting roll height above bowl.
7. SLUDGE TREATMENT AND DISPOSAL
PROBLEM/SOLUTION There is no sludge .trea_tmen_tj_and there
are no problems with sludge disposal so far.
A-16 5/17/74
-------
MISCELLANEOUS AREA INCLUDING BYPASS SYSTEM
PROBLEM/SOLUTION Accumulation of fly ash in water seal.
Solution included installation of water flush lines
at base of seal "U" duct. Solution still needed. Different
style damper to be installed.
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.
Control pH by regulating limestone injection. Take one
module off when load finally drops to 50 percent.
A-17 5/17/74
-------
R.
COMPUTATION OF FGD SYSTEM AVAILABILITY FACTOR
BOILER RATING OR MAXIMUM CONTINUOUS CAPACITY, MW 10°
I
M
CO
PERIOD
MONTH/YEAR
January 1974
FLUE GAS DESULFURIZATION MODULES
MODULE 3A
DOWN DUE TO
BOILER
(HRS)
621
528
560
225
445
277
711
650
649
MODULE
(HRS)
72
0
0
0
328
192
328
289
134
MODULE 3B
DOWN DUE TO
BOILER
(HRS)
621
528
560
225
445
277
711
650
649
MODULE
(HRS)
40
0
0
0
136
256
352
0
104
MODULE 4 A
DOWN DUE TO
BOILER
(HRS)
647
314
600
528
717
Unit ovei
125
MODULE
(HRS)
80
0
0
0
0
•haul
0
MODULE 4B
DOWN DUE TO
BOILER
(HRS)
647
514
600
582
717
125
MODULE
(HRS)
152
8
0
0
0
0
Availability factor computation:
Was 30%, now for last three
weeks 70%
1. Divide boiler capacity by the number of modules
and obtain MW/module = x
2. Multiply boiler capacity by number of hours
during period = a
3. Add all down times due to module trouble for all modules
during period = b
4. Add all down times due to boiler trouble or reduction
in electricity demand for all modules during period = c
5. Availability factor = [a " X (b + c)]100 = %
3 "" Y C
5/17/74
-------
UNIT NO. 4
PLANT SURVEY FORM
NON-REGENERABLE FGD PROCESSES
A. COMPANY AND PLANT INFORMATION
1. COMPANY NAME Kansas City Power & Light
2. MAIN OFFICE Kansas City, Mo.
3. PLANT MANAGER Verne Moore
4. PLANT NAME Hawthorn Plant
5. PLANT LOCATION Kansas City
6 . PERSON TO CONTACT FOR FURTHER INFORMATION Terry Eaton
7. POSITION Results Superintendent
8. TELEPHONE NUMBER 471-0060 (816)
9. DATE INFORMATION GATHERED 6/6/74
10. PARTICIPANTS IN MEETING AFFILIATION
Jerry Bennett KCPL
Vince Palormo KCPL (part time)
Vern Moore KCPL
Wade Ponder EPA
John Busik EPA
Fouad K. Zada PEDCo-Environmental
Larry V. Yerino PEDCo-Environmental
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.
1
100
Peak
2
100
Peak
3
140*
Cyclic
25-100%
X
4
140*
Cyclic
25-100%
X
5
500
Base
50-100%
C. BOILER DATA. COMPLETE SECTIONS (C) THROUGH (R) FOR EAHI
BOILER HAVING AN FGD SYSTEM.
1. BOILER IDENTIFICATION NO.
2. MAXIMUM CONTINUOUS HEAT INPUT
3
4
5
6
7
8
9
10
MAXIMUM CONTINUOUS GENERATING CAPACITY
MAXIMUM CONTINUOUS FLUE GAS RATE,
BOILER MANUFACTURER _
YEAR BOILER PLACED IN SERVICE
MM BTU/HR
140 ll.v on N.G.
100" MW on Coal
o,
C-E
1955
BOILER SERVICE (BASE LOAD, PEAK, ETC.) Cyclic
STACK HEIGHT 200' (common w/3)
BOILER OPERATION HOURS/YEAR (1974) 5643
BOILER CAPACITY FACTOR ** 47.1
11. RATIO OF FLY ASH/BOTTOM ASM
* On Natural Gas (100 MW on Coal)
** DEFINED AS: Kwl1 GENHRATKI) TN YKAR
JZi.
MAX. CONT. GENERATED CAPACITY IN KW x «7f>0 HR/YK
A-20
5/J7/74
-------
D. FUEL DATA
1. COAL ANALYSIS (as received)
GHV (BTU/LB.)
S %
ASH %
Low-Ash Hi-Ash
Typical Typical
MAX.
MIN.
9800
0.6
11
AVG.
11400
3
14
2. FUEL OIL ANALYSIS (exclude start-up fuel)
GRADE
S %
ASH %
E. ATMOSPHERIC EMISSIONS
1. APPLICABLE EMISSION REGULATIONS
a) CURRENT REQUIREMENTS
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
MAX. ALLOWABLE EMISSIONS
LBS/MM BTU
b) FUTURE REQUIREMENTS,
COMPLIANCE DATE
REGULATION & SECTION NO.
MAXIMUM ALLOWABLE EMISSIONS
LBS/MM BTU
PARTICULATES
SO-
2. PLANT PROGRAM FOR PARTICULATES COMPLIANCE
3. PLANT PROGRAM FOR SO2 COMPLIANCE
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 Dry L.
3 ton© injst
> 99%
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.:
Dry Limestone - tail injection
Combustion Engineering
1. PROJECT CONSTRUCTION SCHEDULE:
a) DATE OF PREPARATION OF BIDS SPECS.
b) DATE OF REQUEST FOR BIDS
c) DATE OF CONTRACT AWARD
d) DATE ON SITE CONSTRUCTION BEGAN
e) DATE ON SITE CONSTRUCTION COMPLETED
f) DATE OF INITIAL STARTUP
g) DATE OF COMPLETION OF SHAKEDOWN
*At Max. Continuous Capacity
A-22
DATE
Late Aug. 1972
5/17/74
-------
5. LIST MAJOR DELAYS IN CONSTRUCTION SCHEDULE AND CAUSES:
None
6 . NUMBER OF S(>2 SCRUBBER TRAINS USED
7. DESIGN THROUGHPUT PER TRAIN, ACFM @ °F
8. DRAWINGS: 1) PROCESS FLOW DIAGRAM AND MATERIAL BALANCE
2) EQUIPMENT LAYOUT
H. SO2 SCRUBBING AGENT
1 TYPE Limestone
2. SOURCES OF SUPPLY City Wide Asphalt Co,
3. CHEMICAL COMPOSITION (for each source)
SILICATES
SILICA
CALCIUM CARBONATE
MAGNESIUM CARBONATE
4. EXCESS SCRUBBING AGENT USED ABOVE
STOICHIOMETRIC REQUIREMENTS
5. MAKE-UP WATER POINT OF ADDITION
6. MAKE-UP ALKALI POINT OF ADDITION
A-23
5/17/74
-------
(
V
N
®
(s)
>FROM TRAINS
CUM CAS TO STACK
0
WATER MAKEUP
TO TRAINS
TO TRAINS
LIME/LIMESTONE SLURRY
STREAM NO.
RATE, Ib/hr
ACFM
CPM
PARTICULATES, Ib/hr
S02. Ib/hr
TEMPERATURE, °F
TOTAL SOLIDS. %
SPECIFIC GRAVITY,
CO
&
CO
CO
CO
CO
CO
-
CO
CD
(10)
•" :
(n)
' •-
©
Cis]
STREAM NO.
RATE, Ib/hr
ACFM
GPM
PARTICULATES, Ib/hr
S02. Ib/hr
TEMPERATURE, °F
TOTAL SOLIDS, %
SPECIFIC GRAVITY
05)
C'5)
•
Cie)
(a)
h
CM)
Cl9)
-
<
C'5)
(gj)
,
C22)
C")
®
s'' .
C25)
C26)
I. Representative flow rates based on operating data at maximum,continuous load
5/17/74
-------
SCRUBBER TRAIN SPECIFICATIONS
1. SCRUBBER NO. 1 (a) Two identical modules: Specs per module:
TYPE (TOWER/VENTURI) Rectangular Tower (18'x26'x40')
LIQUID/GAS RATIO, G/MCF @ 122 °F 21 to 26
GAS VELOCITY THROUGH SCRUBBER, FT/SEC
MATERIAL OF CONSTRUCTION Carbon Steel
TYPE OF LINING None
INTERNALS:
TYPE (FLOATING BED, MARBLE BED, ETC.) Marble Bed
NUMBER OF STAGES One
TYPE AND SIZE OF PACKING MATERIAL 3/4"dia. Glass Marble
PACKING THICKNESS PER STAGE(b) 3.5"
MATERIAL OF CONSTRUCTION, PACKING: Glass
SUPPORTS: Stainless Steel 316L
SCRUBBER NO. 2
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 STAGE
MATERIAL OF CONSTRUCTION, PACKING:.
SUPPORTS:.
CLEAR WATER TRAY (AT TOP OF SCRUBBER)
TYPE
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
4" each (8" total)
18
x 26
10
Horizontal
Fiberglass
8 wash lances
Clarifier & make-up water
FREQUENCY AND DURATION OF CLEANING
REMARKS
5. REHEATER
TYPE (DIRECT, INDIRECT)
Finned Tubes
b) For floating bed, packing thickness at rest.
A-26
5/17/74
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DUTY, MMBTU/HR
HEAT TRANSFER SURFACE AREA SQ.FT
TEMPERATURE OF GAS: IN 122°F OUT 170-180°F
HEATING MEDIUM SOURCE Hot Water
TEMPERATURE & PRESSURE 325°F & 150 psig
FLOW RATE LB/HR
REHEATER TUBES, TYPE AND
MATERIAL OF CONSTRUCTION Finned tubes Carbon steel
REHEATER LOCATION WITH RESPECT TO DEMISTER Parallel
and on top of demister
METHOD OF CLEANING
FREQUENCY AND DURATION OF CLEANING
FLOW RATE OF CLEANING MEDIUM LB/HR
REMARKS
6. SCRUBBER TRAIN PRESSURE DROP DATA INCHES OF WATER
PARTICULATE SCRUBBER
SO2 SCRUBBER
CLEAR WATER TRAY
DEMISTER
REHEATER
DUCTWORK
TOTAL FGD SYSTEM 10" to 12"
A~27 5/17/74
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7. FRESH WATER MAKE UP FLOW RATES AND POINTS OF ADDITION
TO: DEMISTER
QUENCH CHAMBER
ALKALI SLURRYING.
PUMP SEALS
OTHER
TOTAL
FRESH WATER ADDED PER MOLE OF SULFUR REMOVED 800 GPM @
3% S Coal 100 MW
8. BYPASS SYSTEM
CAN FLUE GAS BE BYPASSED AROUND FGD SYSTEMS
Yes
GAS LEAKAGE THROUGH BYPASS VALVE, ACFM None (liquid seall
K. SLURRY DATA
LIME/LIMESTONE SLURRY MAKEUP TANK
PARTICULATE SCRUBBER EFFLUENT
HOLD TANK (a)
SO2 SCRUBBER EFFLUENT HOLD
TANK (a)
pH
5.0
to
Solids
-
10
to
1 S
Capacity
(yal)
-
_
55000
Hold up
time
-
_
11
L. LIMESTONE MILLING AND CALCINING FACILITIES: INDICATE BOILERS
SERVED BY THIS SYSTEM.
TYPE OF MILL (WET CYCLONE, ETC.)
NUMBER OF MILLS
CAPACITY PER MILL
RAW MATERIAL MESH SIZE
PRODUCT MESH SIZE
T/HR
A-28
5/17/74
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SLURRY CONCENTRATION IN MILL
CALCINING AND/OR SLAKING FACILITIES
SOURCE OF WATER FOR SLURRY MAKE UP OR
SLAKING TANK
M. DISPOSAL OF SPENT LIQUOR
1. SCHEMATICS OF SLUDGE & FLY ASH DISPOSAL METHOD
(IDENTIFY QUANTITIES OR SCHEMATIC)
2. CLARIFIERS (THICKENERS)
NUMBER One (common w/3)
DIMENSIONS 115' dia. x 10' high
CONCENTRATION OF SOLIDS IN UNDERFLOW
ROTARY VACUUM FILTER
NUMBER OF FILTERS None
CLOTH AREA/FILTER I
CAPACITY I TON/HR (WET CAKE)
CONCENTRATION OF SOLIDS IN CAKE I
PRECOAT (TYPE, QUANTITY, THICKNESS)
REMARKS I
4. SLUDGE FIXATION
POINT OF ADDITIVES INJECTION None
FIXATION MATERIAL COMPOSITION "
FIXATION PROCESS (NAME) ~
FIXATION MATERIAL REQUIREMENT/TONS OF DRY SOLIDS OF SLUDGE
A-29 5/17/74
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ESTIMATED POND LIFE, YRS.
CONCENTRATION OF SOLIDS IN FIXED SLUDGE
METHOD OF DISPOSAL OF FIXED SLUDGE
INITIAL SOLIDIFICATION TIME OF FIXED SLUDGE
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
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3.
COST BREAKDOWN
COST ELEMENTS
CAPITAL COSTS
S02 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
EH
o
EH
EH
EH
EH
EH
EH
EH
EH
n
EH
NO
EH
EH
EH
n
EH
a
EH
EH
ESTIMATED AMOUNT
OR % OF TOTAL
INSTALLED CAPITAL
COST
A.
B.
A-31
5/17274
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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
O. MAJOR PROBLEM AREAS: (CORROSION, PLUGGING, ETC.)
1. SO2 SCRUBBER, CIRCULATION TANK AND PUMPS.
a. PROBLEM/SOLUTION Problems similar to those of
Unit 3. See survev form of Unit 3 for details.
2.
DEMISTER
PROBLEM/SOLUTION Problems similar to those of Unit 3.
3. REHEATER
PROBLEM/SOLUTION Problems similar to those of Unit 3.
A-32
5/17/74
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4. VENTURI SCRUBBER, CIRCULATION TANKS AND PUMPS
PROBLEM/SOLUTION
5. I.D. BOOSTER FAN AND DUCT WORK
PROBLEM/SOLUTION Problems similar to those of Unit 3.
6. LIMESTONE MILLING SYSTEM OR LIME SLAKING
PROBLEM/SOLUTION Problems similar to those of Unit 3.
7. SLUDGE TREATMENT AND DISPOSAL
PROBLEM/SOLUTION Problems similar to those of Unit 3,
A-33 5/17/74
-------
8. MISCELLANEOUS AREA INCLUDING BYPASS SYSTEM
PROBLEM/SOLUTION Problems similar to those of Unit 3,
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.
Control pH by regulating limestone injection. Take one
module off when load finally drops to 50 percent.
A-34 5/17/74
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R.
COMPUTATION OF FGD SYSTEM AVAILABILITY FACTOR
BOILER RATING OR MAXIMUM CONTINUOUS CAPACITY, MW
PERIOD
MONTH/YEAR
FLUE GAS DESULFURIZATION MODULES
MODULE A
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE B
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE C
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
MODULE D
DOWN DUE TO
BOILER
(HRS)
MODULE
(HRS)
I
-------
APPENDIX B
PLANT PHOTOGRAPHS
B-l
-------
Photo No. 1 Bird's eye view of the Hawthorn Power Station.
Boilers 1 and 2 are on the left, and boilers 3 and 4 are at the
center with part of Boiler No. 5 shown at the right side of the
picture. The sludge clarifier tank is in front of Boiler No. 4.
Photo No. 2 General view of the FGD systems on Boilers 3 (in
the background) and 4 (in the foreground). The clearwell tank
which holds the clarifier's overflow water is shown near the
clarifier tank. Make-up water to the system (which is Missouri
River water) is further clarified in the clarifier tank.
B-2
-------
Photo No. 3 Side view of FGD module 4B on boiler No. 4. The
bypass water seal in the ductwork around the module is indicated
by an arrow.
Photo No. 4 Side view of FGD module 3B as seen from the structure
of boiler No. 4. The two steam lances for cleaning of the
reheater tubes are shown on the top level. The demister water
lances are located on the level below.
B-3
-------
Photo No. 5 View of the piping network which is used for
injection of dry limestone in the flue gas ductwork to the two
modules on boiler No. 4. The isolation valves can be seen in
the pipes leading to each module.
Photo No. 6 Front view of the two FGD modules on boiler No. 3,
Showing the two I.D. fans and the common ductwork to the stack,
B-4
-------
Photo No. 7 View of the top of the demister on module 3B as
seen through the inspection window. One of the Chevron vanes
support beams is shown in the center.
Photo No. 8 Close up view of the 8 water lances on module 3B.
These lances are used to wash the demister. The top four are
of the rotary type and are located between the two layers of
demisters. The bottom four lances are of the retractable type
and they provide the underspray wash water.
B-5
-------
Photo No. 9 Picture taken through the reheater inspection window
showing the top of the reheater finned tubes. The gravel-like
objects on top of the tubes are broken pieces of fly ash mud.
These accumulate on the bypass damper during the periods when
the module is out of service, and fall down on the tubes when
damper is reopened.
Photo No. 10 Close up view of the driving mechanism of the
retractable steam lances on module 3B.
B-6
-------
Photo No. 11 View of the 115 ft-diameter clarifier tank as
seen from the structure of module 4A. The overflow from this
tank empties in a small clearwell tank (now shown) located to
the left of the clarifier. The fresh make-up water to the
clarifier tank is pumped from the Missouri River which flows,
near the trees in the background.
Photo No. 12 View of the fly ash and limestone sludge pond as
seen from the structure of boiler No. 5. The feed to this pond
is from the underflow of the clarifier tank.
B-7
-------
TECHNICAL REPORT DATA
(Please read /asiructions on the reverse before completing)
1 REPORT NO,
EPA-650/2-75-057-h
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Survey of Flue Gas Desulfurization Systems
Hawthorn Station, Kansas City Power and Light Co.
5 REPORT DATE
September 1975
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)
Gerald A. Isaacs and Fouad K. Zada
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
1O. PROGRAM ELEMENT NO.
1AB013; ROAP 21ACX-130
11. CONTRACT/GRANT NO.
68-02-1321, Task 6h
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research-and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The- report gives results of a survey of the flue gas desulfurization (FGD) systems at
Kansas City Power and Light Co. 's Hawthorn Power Station. The FGD systems on
Hawthorn boilers 3 and 4 were designed to operate by injection of dry limestone in the
boiler's furnace, followed by tail gas scrubbing. Because of tube plugging in boiler
4. the mode of operation of the FGD system on that boiler was modified: ground lime-
stone is now introduced into the flue gas near the gas inlet to the scrubber tower. The
FGD system on boiler 3 continues to operate as originally designed. Both systems,
however, have undergone minor modifications to overcome such difficulties as
buildup of sediment and plugging of various components. The FGD system on each
boiler consists of two identical modules, each capable of treating 500,000 acfm of
flue gas at 300F. Particulate and SO2 removal efficiencies for the FGD systems,
placed in operation in 1972, are 99 and 70 percent, respectively. Considerable capi-
tal investment associated with the FGD systems was underwritten by the vendor so
that KCP and L's investment was only about #5. 6 million (about #19/KW). The
annualized operating cost is reported to range between 2.2 and 2. 5 mills/KWH.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Croup
Air Pollution
Flue Gases
Desulfurization
Limestone
Scrubbers
Coal
Combustion
Cost Engineering
Air Pollution Control
Stationary Sources
Dry Limestone
Tail Gas Scrubbing
13B
21B 14A
07A,07D
21D
18 DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
70
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
B-8
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