U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-78-0486
Office of Research and Development Laboratory gvva
Research Triangle Park. North Carolina 27711 MaTCh 1978
SURVEY OF FLUE GAS
DESULFURIZATION SYSTEMS:
GREEN RIVER STATION,
KENTUCKY UTILITIES
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-048e
March 1978
SURVEY OF FLUE GAS DESULFURIZATION
SYSTEMS: GREEN RIVER STATION,
KENTUCKY UTILITIES
by
Bernard A. Laseke, Jr.
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-01-4147
TaskS
Program Element No. EHE624
EPA Project Officer Norman Kaplan
Industrial Environmental Research Laboratory
Office of Energy, Minerals and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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ACKNOWLEDGMENT
This report was prepared under the direction of Mr. Timothy
W. Devitt and Dr. Gerald A. Isaacs. The principal author was Mr.
Bernard A. Laseke.
Mr. Norman Kaplan/ EPA Project Officer, had primary respon-
sibility within EPA for this project report. Information on
plant design and operation was provided by Mr. Joseph B. Beard,
Environmental Technologist, Kentucky Utilities Company; Mr. Jack
Reisinger, Plant Superintendent, Green River Station, Kentucky
Utilities Company; and Mr. A. H. Berst, Manager of SO2 Scrubber
Projects Engineering, American Air Filter Company, Inc.
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CONTENTS
Page
Acknowledgment ii
Figures and Tables iv
Summary v
1. Introduction 1
2. Facility Description 2
3. Flue Gas Desulfurization System 5
Process Description 5
Process Chemistry: Principal Reactions 9
Process Control 11
4. FGD System Performance 15
Background Information 15
Operation History 16
Start-up and Operation: 20
Problems and Solutions
Economics 24
Appendices
A. Plant Survey Form 28
B. Plant Photographs 52
iii
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LIST OF FIGURES
No. Page
1 Original process flow diagram, Green River 6
FGD system
2 Simplified process instrumentation and 13
control diagram, Green River FGD system
LIST OF TABLES
No. Page
1. Data Summary: Green River Facility and yji
FGD System
2 Design, Operation and Emission Data, Green 4
River Boilers 1, 2 and 3
3 Green River FGD System: 1975 Operational Data 17
4 Green River FGD System: 1976 Operational Data 18
5 Green River FGD System: 1977 Operational 19
Data (through November)
6 Summary of Problems and Solutions, Green 21
River FGD System
7 Green River Scrubbing System: Total Installed 26
Capital Costs
8 Green River Scrubbing System: Annual Operating 27
and Maintenance and Utilities Costs
iv
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SUMMARY
Kentucky Utilities (KU) contracted with American Air Filter
(AAF) to design and install a system for removal of sulfur diox-
ide and particulate from flue gases of three boilers at the Green
River Power Station. The flue gas desulfurization (FGD) and
particulate removal system consists of one wet lime scrubber
module designed to handle a maximum of 170 acms (360,000 acfm) of
flue gas at 149°C (300°F). The scrubber module contains a
variable-throat venturi with a flooded elbow for fly ash removal,
and a mobile-bed contactor for sulfur dioxide removal. Entrained
water droplets are removed from the scrubbed gases by means of a
radial-vane mist eliminator before discharge to a local stack.
Mechanical collectors upstream of the wet scrubbing system remove
primary particulate matter.
The boilers (1, 2, and 3) are pulverized-coal-fired units
servicing two turbines, each rated at 32 MW (gross). The fuel
burned in these units is primarily a high-sulfur Western Kentucky
coal [25 MJAg (10,800 Btu/lb) , 3.8 to 4.0 percent sulfur, 14
percent ash]. Flue gases can bypass the scrubbing system through
a system of ductwork and guillotine dampers.
In June 1973 KU awarded a turnkey contract to AAF, who
completed construction and installation of the system by mid-
summer 1975. After general electrical and mechanical debugging,
the unit was put in service on air and water only in August 1975;
in the ensuing period, operators monitored gas and liquid flows,
operation of dampers, and spray patterns, and performed the
required calibrations. The system was then operated on air and
water under normal process conditions to allow detection of any
early mechanical failures before the initial flue gas run.
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The flue gas run began on September 13, 1975. Initial
operation was at half load because one of the turbine generators
was out of service for overhaul and repairs. The scrubbing
system was operated on an open water loop. This mode (half-load,
open-loop) continued until March 1976, when the system began
operation at full load and closed water loop. Operation has
proceeded in this manner since that date.. During the remainder
of 1976 the system underwent a 6-month supplier qualification run
under the auspices of AAF. FGD system availability* in 1976 was
85.4 percent; system service time totalled 6045.94 hours at an
average unit load factor of 47.5 percent.
The service times reported for the power-generating unit and
the scrubber in 1977 are substantially lower than the 1976
levels because of a unit shutdown in February and March for stack
and boiler repairs and a plant operator strike from June to
October. FGD system availability in 1977 (through November) was
78.5 percent; system service time totalled 1963.66 hours at an
average unit load factor of 15.2 percent.
Data on the facility, and FGD system are summarized in
Table 1.
Availability index: the number of hours the FGD system is
available (whether operated or not) divided by the number of
hours in the period, expressed as a percentage.
vi
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Table 1. DATA SUMMARY: GREEN RIVER FACILITY AND FGD SYSTEM
Boilers
Total capacity (gross), MW
Fuel
Average fuel characteristics
Heating value, MJ/kg (Btu/lb)
Sulfur, percent
Ash, percent
Total moisture, percent
FGD system supplier
Process
Type
Modules
Status
Start-up date
Design efficiency, percent overall
Sulfur dioxide
Particulate
Makeup water, (I/sec)/MW (gpm/MW)
Sludge disposal
Unit cost
Capital, $AW
Annual, mills/kWh
1, 2, and 3
64
Pulverized coal
25 (10,800)
3.9
13.4
12.1
American Air Filter
Wet lime scrubbing
Retrofit
One
Operational
9/75
80
99.7a
0.08 (1.2)
Unstabilized sludge
disposed in on-site,
clay-lined pond
57.4
2.02
This value includes particulate removal
ing mechanical collectors.
vii
provided by the exist-
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SECTION 1
INTRODUCTION
The Industrial Environmental Research Laboratory (IERL) of
the U.S. Environmental Protection Agency (EPA) has initiated a
study to evaluate the performance characteristics and reliability
of flue gas desulfurization (PGD) systems operating on coal-fired
utility boilers in the United States.
This report, one of a series dealing with such systems,
describes a wet lime scrubbing system developed by American Air
Filter (AAF) and installed at the Green River Station of the
Kentucky Utilities Co. (KU). It is based on information obtained
during and after plant inspections conducted on March 3, 1976;
June 30, 1976; and March 22, 1977. The information is considered
valid as of November 1977.
Section 2 presents information and data on the plant environs
and facilities. Section 3 provides a detailed description of the
FGD system, and Section 4 analyzes the performance of the system
to date. Appendices present details of plant and system operation
and photos of the installation.
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SECTION 2
FACILITY DESCRIPTION
The Green River Station of KU is on the Green River in
central Kentucky, approximately five miles north of Central City-
The terrain surrounding the power plant is sparsely populated and
heavily wooded. A number of strip mines are located there.
The plant contains four steam turbine generating units
having a total gross generating capacity of 242 MW. Boilers 1,
2, and 3 supply steam for two of the steam turbine generators
with a combined generating capacity of 64 MW. Because these two
electrical generating units are used only for peak loads, the
three boilers normally operate on a 5-day week, with one or more
often at reduced capacity.
All three boilers are dry-bottom, pulverized-coal-fired
units, manufactured by Babcock and Wilcox and put in-service in
1949 and 1950. At present, KU has no plans to retire these
units.
The plant burns coal from two sources. A low-sulfur grade,
generally averaging less than 1.0 percent sulfur by weight, comes
from the Hoyt Mine, in Hazard, Harlan County, Kentucky, and is
shipped to the plant by truck and rail. The utility also pur-
chases a high-sulfur coal, which is used with the FGD system.
This coal is from the Drake Mine in Muhlenberg County, Kentucky,
and is shipped to the plant by barge. A typical analysis of the
Drake Mine coal gives the following values: heating value, 25
MJ/kg (10,800 Btu/lb); sulfur content, 3.9 percent; ash content,
13.4 percent; total moisture, 12.1 percent.
-------
Boilers 1, 2, and 3 are fitted with mechanical collectors
upstream from the FGD system. Design efficiency for particulate
removal is 85 percent. The FGD system, designed and installed
by AAF, consists of one scrubber module to handle a maximum flue
gas capacity of 169 m3/sec (360,000 acfm) at 149°C (300°F).
Table 2 gives data on plant design, operation, and atmospheric
emissions.
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Table 2. DESIGN, OPERATION, AND EMISSION DATA,
GREEN RIVER BOILERS 1, 2, AND 3
Total rated generating capacity, MW
Boiler manufacturer
Year placed in service
Unit heat rate, kJ/net kWh
Btu/net kWh
Coal consumption, Gg/week
short ton/week
Maximum heat input, GJ/hr
106 Btu/hr
Stack height above grade, m
ft
Design maximum flue gas rate,
Nm3/hr (O°C)
scfm (70°F)
acfm
Flue gas temperature,(FGD inlet)0C(0F]
Emission controls:
Particulate
Sulfur dioxide
Particulate emission rates:fi
Allowable, ng/J (lb/10° Btu)
Actual, ng/J (lb/106 Btu)
Sulfur dioxide emission rates:
Allowable, ng/J (lb/106 Btu)
Actual, ng/J (lb/106 Btu)
64
Babcock & Wilcox
1949, 1950
13,990
13,250
1285 ,
1,416 x 10
895
848
50
165
396,000
251,000
360,000
149 (300)
Mechanical collector and
venturi scrubber
Venturi scrubber and
mobile-bed contactor
42° (0.097)
Undetermined
724° (1.67)
Undetermined
Emission level at full load.
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SECTION 3
FLUE GAS DESULFURIZATION SYSTEM
PROCESS DESCRIPTION
The wet lime scrubbing system installed at the Green River
Power Station incorporates a mobile-bed contactor unit for removal
of sulfur dioxide from flue gases. American Air Filter designed
and installed this single-module scrubbing system to handle flue
gas generated by coal burned in three dry-bottom, pulverized-coal
boilers. The process is conveniently described in terms of two
basic operations: a tail-end flue gas scrubbing system, and a
lime slurry/recycle system. Figure 1 provides a schematic flow
diagram of the process.
Flue Gas Scrubbing System
The flue gas from each boiler passes first through a series
of mechanical collectors [Western Precipitation, multicyclone,
23-cm (9-in.)-diameter, cast iron construction] that remove
particulates. The flue gas is then drawn from the breeching,
through a guillotine-type isolation damper and associated duct-
work, to the scrubber fan. By use of the isolation dampers
operators can selectively allow flue gases to bypass the scrubbing
system and pass directly to an existing stack.
Prior to entering the scrubbing system, the flue gas passes
through a 1120-W (1500-hp), 4482-Pa (18-in. H20), forced-draft
booster fan. This fan maintains zero pressure upstream of the
fan through damper control to prevent back pressure on the boilers.
From the outlet of the scrubber booster fan, the gas flows
through a variable-throat venturi scrubber with flooded elbow.
These components provide additional capability for removal of
particulate matter escaping the upstream mechanical collectors,
5
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BOILER 2
NECH. aCTRS.r] NECH. CLCTM.M BECH. ttCTRS
Sl.O. FAH I.D. FA* S E"ST. STACK
I
\5ETTL1I* POHD/ /-3
a
FM
STSTEH DAMPER
SCRUBBER BOOSTER FAN
MAKEUP HAH
HtOM POND 1 I TOCTAHT MPITIBI
llil
BLEED TO HMD
HUXlf I
HATER.
HATED
/4T~~~^ RECYCLE tQ IHVHOLO TWK
N-J
o ^
ti—' SPARE
SPARE
SPARE
Figure 1. Original process flow diagram. Green River
FGD system.
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and also effect initial quenching of the hot gas. Quenching
lowers the temperature of the inlet gas from 163°C (325°F)
(actual) to approximately 52°C (126°F) within the scrubber
module. This reduction causes a substantial decrease in the
volume of gas to be scrubbed and provides protection to the
plastic spheres used in the mobile-bed contactor.
Pressure drop through the venturi is maintained at 1743 Pa
(7 in. H20) by a limitorque operator on the plug. Liquid flow
through the top of the scrubber is maintained at 83 I/sec (1360
gpm). The scrubber shell is constructed of mild steel and lined
with acid-proof precrete. The venturi throat is constructed of
stainless steel. From the venturi the gas passes through the
flooded elbow and flows upward through the mobile-bed contactor
at a rate of 135 m3/sec at 52°C (288,200 acfm at 126°F). The
absorber is constructed of mild steel and lined with acid-proof
refractory. It contains approximately 175f000 to 190,000 solid
spheres made of polyvinyl chloride and polyethylene, which pro-
vide the surface needed to facilitate reaction of the sulfur
dioxide in the flue gas with the lime slurry. The slurry is fed
at a rate of 595 I/sec (9750 gpm). and is applied both to the bed
and to the upward rising flue gas by overhead nozzles and by
sphere return nozzles spraying upward. The contactor bed is
compartmentalized into individual sections. Underbed dampers are
used to adjust for flue gas turndown requirements. Pressure drop
through the contactor bed is approximately 996 Pa (4 in. H20) .
Following passage through the bed, the gases continue
upward 8.38 m (27.5 feet) to the single-stage, single-pass
radial-vane mist eliminator. The turning vanes are curved and
constructed of stainless steel. The outside collection area is
constructed of coated mild steel. The mist eliminator depth and
vane spacing are approximately 0.9 m (3 feet). The mist elimi-
nator is continuously washed by outward spraying nozzles at a
rate of 3.I/sec (50 gpm) total. Pressure drop is approximately
498 Pa (2 in. H20).
-------
The scrubbed flue gas (139 m3/sec at 52°C; 296,300 acfra at
126°F) is discharged to the atmosphere through the wet scrubber
stack, which is Ibonstructed of carbon steel and lined with
precrete applied to wire mesh.
Lime Slurry/Recycle System
The scrubbing slurry feed and recycle system consists of a
partitioned concrete reactant tank that includes recycle pumps
to supply the scrubber and absorber module, a lime slurry slaking
and feed system, a bleed system for discharge of scrubbing
wastes to a settling pond, and a return water system that recycles
water from the settling pond to the process.
Pebble lime (1.9-cm, 0.75-in.) is delivered by rail to the
plant site and transferred pneumatically to a 454-Mg (500-ton)
capacity storage bin. The storage bin is equipped with a vibrat-
ing bottom and a 20-cm (8-in.) screw conveyor, which discharges
the lime at a rate of 0.5 kg/sec (2 ton/hr) into a covered slak-
ing tank. Two agitator-equipped slaking tanks have been in-
stalled, one of which is used for backup.
Prom the slaking tank, slurry is discharged through a drag-
chain degritter to a mix/hold tank, also equipped with an agita-
tor. Liquid volume capacity of the tank is 7500 1 (1980 gal.).
The fresh scrubbing slurry, with 20 percent solids content, is
trans ferred by pumps to the return section of a reactant tank
system installed beneath the scrubbing module.
The reactant tank, constructed of acid-proof concrete,
provides a total retention time of more than 20 minutes. Two
partitions form three individual compartments connected by
underflow openings. Each compartment is equipped with an agita-
tor. The function of each compartment is described below:
0 The return section of the reactant tank system receives
•
-------
0 The recycle/discharge section of the reactant tank
system feeds both the venturi scrubber and mobile-bed
contactor with recycled scrubbing solution. Bleed
pumps remove the scrubbing wastes from this section of
the reactant tank to maintain a slurry solids content
of 8 to 12 percent. The bleed stream is discharged to
a settling pond, and clear water is pumped from the
pond to the return section.
0 The third section, situated between the return and
recycle sections, was installed as a deliberate redun-
dancy to facilitate surveillance of process chemistry.
Recycle pumps taking slurry by suction from the reactant
tank feed both the venturi particulate scrubber and the mobile-
bed contactor. These pumps (two operational, one spare) are
rated at 360 I/sec (5900 gpm) each. All pumps and agitators are
rubber-lined.
Reaction products and collected particulate matter are
pumped to an impervious clay-lined pond on the plant site approx-
imately 0.8 km (0.5 mile) from the scrubbing module. Pond capac-
ity is 183,000 m3 (148 acre-ft) at a depth of 6.1 m (20 ft). It
is calculated that this pond will be usable for 9 years and that
3
its capacity is expandable to 511,000 m (414 acre-ft) to provide
20 years of use. For closed loop operation clarified pond water
is returned to the reactant tank. Treated river water is used as
makeup and is introduced into the reactant tank, lime slaking
tank, and mist eliminator as well as to the various pump seals.
Total fresh water makeup supplied to the system is 4.6 I/sec (75
gpm)..
PROCESS CHEMISTRY: PRINCIPAL REACTIONS
The first and most important step in wet-phase absorption of
sulfur dioxide from the flue gas stream is diffusion from the gas
to the liquid phase. Sulfur dioxide is an acid anhydride that
-------
readily undergoes reaction to an acid and further reaction to
hydrogen, bisulfite, and sulfite ions.
S02 * • « * S°2 (aq.)
S02 (ag.) + H2° * H2S03
H
HSOl +
The lime scrubbing solution is first activated by slaking
the pebble lime to form calcium and hydroxide ions, as shown in
the following equations.
CaO 4- + H20 < =±Ca (OH) 2
>
Ca + 20H
The reaction products precipitate as calcium salts, and the
scrubbing solution is recycled to the scrubber. The principal
mechanisms of product formation and precipitation are as follows :
++ ° -
Ca
CaSO3 + 1/2 H20 < "-CaS03-l/2 ^O 4-
Reactions leading to formation of calcium sulfate are
briefly summarized as follows:
S03 f < "S03 (aq.)
S°
3(aq.)
H+ + HSO~
H+
HSO* + OH~ « *:SO.
4 ^ 4
S03
CaS04
S0~ ^ - ^ CaS04
10
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The chemical absorption of sulfur dioxide into the scrubbing
solution occurs in the mobile-bed contactor of the scrubbing
module. The mobile packing provides a reaction medium that
allows good mass transfer at relatively low pressure drops. It
also minimizes the probability of solids deposition and plugging
because the movement of the spheres prevents the solids from
adhering to their surfaces.
The scrubbing solution is maintained in the alkaline range
(pH approximately 8.0 to 8.5) as it enters the scrubber module.
Contact with the sulfur dioxide in the flue gas and the resulting
chemical absorption into the liquid phase causes the solution pH
to decrease.
PROCESS CONTROL
Gas and Liquid Flow
Control of gas and liquid flow through the scrubbing system
is relatively simple. The flow of the scrubbing solution is
maintained at a constant rate, independent of modulation. Gas
flow and pressure drop, however, are controllable by means of a
limitorque operator in the venturi and a damper system in the
absorber. The limitorque operator maintains a constant pressure
drop of 1743 Pa (7 in. H-O) across the venturi. The dampers
below the compartments of the mobile bed accommodate gas volume
turndown requirements.
Scrubbing Solution Chemistry
The chemistry of the scrubbing solution is controlled
automatically in the reactant tank system. Separation of the
reactant tank into three compartments permits selective control
of feed and discharge streams. The spent scrubbing slurry, fresh
reagent, fresh makeup water, pond return water, and bleed streams
are transferred through the reactant tank system.
The chemistry of the FGD system is determined primarily by
pH of the scrubbing solution, which is monitored in each section
of the reactant tank. Six immersion-type pH sensors, two per
11
-------
section, are installed in the reactant tank. Details of the
process control system are illustrated in Figure 2 and are
outlined as follows.
(1) Spent scrubbing solution is discharged from the ab-
sorber into the return section of the reactant tank. A
7-minute residence time allows for near completion of
the chemical reactions. During this residence period,
the pH of the scrubbing solution is monitored. Gener-
ally, the spent solution stabilizes at pH 5.0 to 6.0.
After completion of the absorption reactions in the
agitated compartment, the solution underflows to the
next compartment.
(2) The lime slurry addition to the first compartment is
further regulated in the second compartment by an
analyzing indicator control system. The pH sensors are
used to modulate a flow control valve installed in the
lime slurry feed line. This system regulates lime
addition as a function of solution pH over a control
range with upper and lower limits of 8.5 and 5.0,
respectively.
(3) The scrubbing solution then underflows to the third
.compartment for recycling or discharge to a settling
pond. The bleed stream to the settling pond is con-
trolled by one of two nuclear density meters (Ohmart
and Texas Nuclear) installed in the recycle line. The
control is set at 10 percent solids in the recycle
solution. When this value is exceeded, the valve on
the bleed line is opened and the scrubbing wastes are
pumped to the pond, where solids settle out. Clear
water is pumped from the pond to the return section of
the reactant tank to maintain water balance through the
system.
12
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H
LO
REACTAHT
TANK SYSTEM
RETURN
SECTION
\
SETTLING POND
MIDDLE
SECTION
REACTANT FEED
RECYCLE
SECTION
SCRUBBER
RECYCLE
FCVI
SLAKER
0*0
T
MIX/HOLD
TANK
Figure 2. Simplified process instrumentation and control diagram,
Green River FGD system.
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Water Balance
Recycling of supernatant from the settling pond to the
return section of the reactant tank is controlled by a level
indicator located in the recycle section. Also, fresh makeup
water (cleaned river water) is added to the system through mist
eliminator wash (3 I/sec, 50 gpm). pump gland seals, and lime
slaking (1.5 I/sec, 25 gpm for both).
14
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SECTION 4
FGD SYSTEM PERFORMANCE
BACKGROUND INFORMATION
Commercial operation of the scrubbing system began in the
fall of 1975. Before commercial service/ the system was put
through an extensive four-phase prestart-up program, which
included mechanical and electrical debugging, operation on air
and water, verification of mechanical reliability, and operation
on hot flue gas. Manpower for these test phases was provided by
the system supplier (AAF), the utility (KU), and their mechanical
and electrical contractors. The testing activities are summa-
rized below.
Mechanical and Electrical Debugging
The system underwent mechanical and electrical debugging in
July 1975. The test program included operation of agitators and
pumps and preliminary checks of electrical circuitry.
Air and Water Testing
The air and water test phase, which began in August 1975,
consisted primarily of observing gas flows and spray patterns in
the scrubbing system. Operation of the mobile-bed contactor was
analyzed with respect to sphere movement and nozzle location
within the contactor bed. Several system control loops and
access points were confirmed or modified, and pipe supports were
added.
Mechanical Reliability Testing
The system was operated for 2 weeks to verify mechanical
reliability, and minor malfunctions were corrected. The system
15
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operated for a short period following addition of gypsum seed
crystals to the reactant tank system.
Flue Gas Operation
Initial operation on flue gas began on September 13, 1975.
The system was operated at 50 percent load, with 1.6 to 2.0
percent sulfur coal being fired in the boilers. Among minor
problems that were encountered and corrected were difficulties
with the pH sensors and sulfur dioxide analyzers and plugging of
spray nozzles.
OPERATION HISTORY
Tables 3, 4, and 5 summarize the performance of the FGD
system from prestart-up operation through November 1977- Start-
up and early operation of the system were conducted mostly at 50
percent load capacity because of major repair work on both tur-
bine generators and because of a possible lime shortage during
renegotiation of a supply contract. The system was operated in
an open water-loop mode to gain operational experience while
supplying the settling pond with water for recirculation to the
process.
A 6-month qualification program was conducted in 1976 by the
system supplier. The purpose of this program was to verify
process design in operation with closed water loop and full
boiler load. Performance of the system from September 1975 to
November 1977 is summarized below:
1975 Operation: Initial operation on September 13, 1975, was
followed by shakedown and debugging. Many of the system outages
occurred because of scheduled inspections and minor design ad-
justments. Total service time for the FGD system in 1975 was
649.20 hours.
1976 Operation; The FGD system was available for service 7502.88
hours and operated 6045.94 hours. The boilers were in service
6969.82 hours; annual average unit load factor was 47.5 percent.
16
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Table 3. GREEN RIVER FGD SYSTEM: 1975 OPERATIONAL DATA
MONTH
July
Aug.
Sept.
Oct.
NOV.
Dec.
total
Hours
in
period
744
744
720
744
720
744
4416
Hours FGD
system
available
Hours FGD
called
upon
Mechanical ,
Mi
Hours FGD
system
operated
md electric
ichanical re
139.17
149.53
146.00
412.50
649.20
Hours
boilers
operated
al testir
liability
Unit
load
factor, %
g; air an
Tests
FGD system performance factors, %
Avail-
ability
J water t
Oper-
ability
ests
Relia-
bility
Utiliza-
tion
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Table 4. GREEN RIVER FGD SYSTEM: 1976 OPERATIONAL DATA
MONTH
Jan.
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
Oct.
NOV.
Dec.
Total
Hours
in
period
744
696
744
720
744
720
744
744
720
744
720
744
8784
Hours FGD
system
available
312.00
486.17
721.72
648.00
606.18
720.00
665.85
722.45
617.20
744.00
720.00
539.31
7502.88
Hours FGD
called
upon
456.00
499.38
408.66
552.00
455.88
596.43
583.53
744.00
571.20
698.55
704.25
591.48
6861.36
Hours FGD
system
operated
64.00
210.75
386.38
552.00
455.88
588.85
574.43
722.45
571.20
698.55
704.25
517.20
6045.94
Hours
boilers
operated
571.55
499.38
457.53
552.00
455.88
596.43
583.53
744.00
571.20
698.55
704.25
535.52
6969.82
Unit
load
f actor, %
55.2
40.7
43.7
50.2
44.1
62.3
51.2
54.0
32.5
37.7
51.4
46.5
47.5
FGD system performance factors, %
Avail-
ability
41.9
69.9
97.0
90.0
81.4
100.0
89.5
97.1
85.7
100.0
100.0
72.5
85.4
Oper-
ability
11.2
42.2
84.4
100.0
100.0
98.7
98.4
97.1
100.0
100.0
100.0
87.4
86.7
Relia-
bility
14.0
42.2
94.5
100.0
100.0
98.7
98.4
97.1
100.0
100.0
100.0
96.6
88.1
Utiliza-
tion
8.6
30.3
51.9
76.7
61.2
62.3
77.2
97.1
79.3
93.9
97.8
69.5
68.8
00
-------
Table 5. GREEN RIVER PGD SYSTEM: 1977 OPERATIONAL DATA (THROUGH NOVEMBER)
MONTH
Jan.
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
Oct.
Nov.
Total
Hours
in
period
744
672
744
720
744
720
744
744
720
744
720
8016
Hours FGD
system
available
698.29
242.80
0
288.00
735.65
720.00
744.00
744.00
720.00
744.00
634.20
6294.93
Hours FGD
called
upon
744.00
266.12
0
166.82
526.55
34.38
0
0
0
0
331.90
2069. 77
Hours FGD
system
operated
698.26
242.80
0
164.00
513.27
34.38
0
0
0
0
300.85
1953.56
Hours
boilers
operated
744.00
266.12
0
166.82
526.55
34.38
n
0
0
0
331.90
2069.77
Unit
load
factor , %
56.5
32.8
0
9.4
34.4
1.3
0
0
0
0
32.8
15.2
FGD system performance factors, %
Avail-
ability
93.9
36.1
0
40.0
98.9
100.0
100.0
100.0
100.0
100.0
88.1
78.5
Oper-
ability
93.9
91.2
0
98.3
97.5
100.0
0
0
0
0
90.6
94.4
Relia-
bility
93.9
91.2
o
98.3
97.5
100.0
0
0
0
0
90.6
94.4
Utiliza-
tion
93.9
36.1
0
22.8
69.0
4.8
0
0
0
0
41.8
24.4
-------
Based upon these values, the values for system availability,
t ?
operability,* reliability, and utilization in 1976 are 85.4,
86.7, 88.1, and 68.8 percent, respectively.
1977 Operation; Service times for the boiler and scrubber
dropped off sharply from 1976 levels, largely because of a plant
operator strike from June to October 1977. In addition, the
units and scrubber were shut down in February and March for
scrubber stack and boiler repairs. Through November the FGD
system was available 6294.93 hours and operated 1953.56 hours.
The boilers were in service 2069.77 hours; annual average unit
load factor was 15.2 percent. Based on these values, the values
for system availability, operability, reliability, and utiliza-
tion in the 11-month period are 78.5, 94.4, 99.4, and 24.4
percent, respectively.
START-UP AND OPERATION: PROBLEMS AND SOLUTIONS
Start-up and operation of the Green River scrubbing system
have been accompanied by various problems, for many of which
both the utility operators and the FGD system supplier have
conceived and implemented solutions. Table 6 summarizes the
problems encountered and the measures taken to correct them.
The major problems and solutions are discussed briefly below.
Problems Related to System Chemistry
Plugging occurred in the spray nozzles and mobile bed, and
scale formed in and downstream of the mist eliminator. Hard
gypsum scale developed in the lower section of the mobile-bed
*
Operability index: the number of hours the FGD system is
operational divided by the boiler operating hours, expressed
as a percentage.
Reliability index: the number of hours the FGD system is
operational divided by the number of hours the FGD system is
called upon to operate, expressed as a percentage.
f Utilization index: the number of hours the FGD system is
operational divided by the number of hours in the period, ex-
pressed as a percentage.
20
-------
Table 6. SUMMARY OF PROBLEMS AND SOLUTIONS, GREEN RIVER FGD SYSTEM
Period
Problem
Solution
Aug. 75
Sept. 75
Oct. 75
Nov. 75
Dec. 75
Jan. 76
Feb. 76
Mar. 76
Apr. 76
May 76
June 76
July 76
Aug. 76
Oscillation of scrubber stack when
booster fan was put in service.
Plugging of spray nozzles.
Plugging of recycle tank screens
and spray nozzles.
Plugging of recycle tank
screens.
Numerous frozen and/or ruptured
lines.
Inoperable recycle pumps, sump
pumps, and feed tank agitator.
Failure of recycle pumps, reactant
feed pumps, and tank agitators.
Failure of rubber-lined recycle
pump impellers.
Minor failures of stack liner
(Carboline).
Scale in scrubber.
Excessive vibration of scrubber
booster fan.
Installed strengthening vanes to
dampen the standing wave frequency.
Cleaned nozzles.
Cleaned components.
Cleaned screens.
Thawed lines. Repaired or replaced damaged
lines.
Repaired components.
Repaired components. Cleaned all related
components (tanks, pipes, pumps).
Changed all rubber-lined impellers from
two-piece to one-piece construction.
Shut scrubber down; removed scale.
Shut scrubber down; repaired fan.
-------
Table 6 (Continued).
Period
Problem
Solution
N)
to
Sept. 76
Oct. 76
Nov. 76
Dec. 76
Jan. 77
Feb. 77
Apr. 77
May 77
June 77
July 77
Aug. 77
Sept. 77
Oct. 77
Mov. 77
Continuation of minor fan problems
Scrubber system checkout
Corrosion and erosion of
Carboline stack lining and
shell.
Malfunction of underbed damper.
Shut scrubber down; repaired fan.
Replaced some mobile-bed contactor spheres.
Repaired stack shell with welded backup
plates. Replaced Carboline liner with
Precrete G-8 applied to wire mesh.
Repaired component.
No operation - plant operator strike
No operation - plant operator strike
No operation - plant operator strike
No operation - plant operator strike
-------
contactor during initial operation, probably because calcium
sulfite tends to precipitate as the pH of the scrubbing solution
reaches 9.0 to 10.0. Then, in the presence of high oxygen
concentrations in the flue gas, the sulfite is oxidized to sul-
fate, resulting in the scale formation. To solve this problem
the oxygen content of the flue gas was reduced by minimizing air
leakage into the system and the pH sensors were modified and
relocated so as to reduce pH levels of the solution.
Recent system modifications designed to reduce plugging and
scaling are cycling the mobile-bed dampers to prevent stagnation
zones and removal of the spray nozzles to increase liquid flow to
the unit and prevent settling out of solids in the piping.
Mechanical Problems
Mechanical malfunctions and failures have been minimal and
associated mainly with the pumps, fans, and dampers. The origi-
nal slurry recirculation pumps were rubber-lined and rubber-
covered impeller units. The rubber repeatedly peeled from the
impellers, and the lining was destroyed after minimal service
time. Although the impeller design was changed from a two-piece
to a one-piece construction, continuing failures prompted KU to
switch to Ni-hard impellers. Vibrations associated with the
scrubber booster fan have caused occasional shutdowns for rebal-
ancing. The guillotine gas bypass dampers (three; two located
near the existing stack and one for the scrubber) are difficult
to close in cold weather and must be operated manually.
Problems Related to System Design
The most severe problems to date concern the high loadings
of aci'd mist in the scrubber exit gas stream. These high load-
ings have caused acid' condensation and rainout in the stack and
in the immediate plant area. The stack liner and shell have
failed, and acid rainout damaged automobiles and the superstruc-
ture of a substation on the plant grounds. To rectify this
situation KU and AAF have implemented or are engineering the
following modifications.
23
-------
The Carboline stack lining, which failed around nearly half
of the circumference, has been replaced with a 1.9-cm (3/4-
in.) refractory coating (Precrete G-8) applied over a wire
mesh.
0 The stack shell was repaired by welding a backup metal
plate to the portions of the stack that were pitted. Half
of the stack was covered over its entire height with a 9.5-
mm (3/8-in.) steel plate.
0 The radial-vane mist eliminator is being modified to reduce
formation of acid mist and fouling. If this is not effec-
tive, the unit will be replaced with a chevron-type mist
eliminator.
0 An indirect, hot-air, stack gas reheat system will be
incorporated to raise gas temperature by 10°C (50°P).
Extraction steam from another unit will supply heat to
ambient air, which will be injected into the scrubbing
system before gases exit through the scrubber stack.
ECONOMICS
Tables 7 and 8 summarize the total installed capital cost
and the annual operating and maintenance costs associated with
the Green River scrubbing system. The total installed capital
cost of the system is $3,444,000, which equals $57.4/kW based
upon the system's net generating capacity of 60 MW. This figure,
in 1976 dollars, includes the particulate removal equipment
associated with the scrubbing system. Excluded are the system
design modifications by KU and AAF. The total annual operating
and maintenance costs are $504,057, which equals 2.019 mills/kWh
based upon the 1976 unit capacity factor of 47.5 percent. Ex-
cluded is the electrical energy cost, which is 10.04 mills/kWh
based upon a system power demand of 1500 kW.
SYSTEM PERFORMANCE; SO^ REMOVAL EFFICIENCY
Efficiency of the system in removing sulfur dioxide and
particulate from flue gases has not been reliably determined.
24
-------
Table 7. GREEN RIVER SCRUBBING SYSTEM:
TOTAL INSTALLED CAPITAL COSTS3
Item
Scrubber equipment0
Ancillary equipment
Sludge disposal, sludge
transportation, and site
preparation
Total
$/kW
48.3
3.1
6.0
57.4
Dollars
2,898,000
186,000
360,000
3,444,000
Based upon a net generating capacity of 60 MW.
1976 dollars.
Equipment furnished by AAF, excluding sludge disposal.
Equipment not furnished by AAF, excluding sludge disposal.
25
-------
Table 8. GREEN RIVER SCRUBBING SYSTEM:
ANNUAL OPERATING, MAINTENANCE AND UTILITIES COST5
Item
Operating :
Materials
Labor
Total operating
Maintenance :
Materials
Labor
Total maintenance
Utilities
Total
mills/kWh
1.206
0.188
1.394
0.195
0.181
0.376
0.249
2.019d
Dollarb
301,090
46,936
348,026
48,684
45,188
93,872
62,165
504,057
Based upon a unit capacity factor of 47.5 percent.
1976 dollars.
Reagent and chemicals.
Does not include electrical energy cost, 10.04 mills/kWh.
26
-------
Continuous monitoring data recorded by AAF during the initial
operating phase show sulfur dioxide removal efficiency well above
the design guarantee value, at about 90 percent. An attempted
efficiency test in December 1976 failed because air leakage in the
boiler prevented operation at full capacity. Another efficiency
test is tentatively scheduled for February 1978.
27
-------
APPENDIX A
PLANT SURVEY FORM
A. Company and Plant Information
1. Company name: Kentucky Utilities
2. Main office: Lexington, Kentucky
3. Plant name: Green River Power Station
4. Plant location: Central City, Kentucky
5. Responsible officer: Joseph Beard
6. Plant manager: J.W. Reisinger
7. Plant contact; J.W. Reisinger/S.V. Anderson
8. Position: Plant Superintendent/Assistant Superintendent
9. Telephone number: (502) 754-4828
10. Date information gathered; March 4 and June 30, 1976
Participants in meeting Affiliation
J.W. Reisinger Kentucky Utilities
S.V. Anderson Kentucky Utilities
Frank Palameri American Air Filter
James Martin American Air Filter
G.A. Isaacs PEDCo Environmental
B.A. Laseke PEDCo Environmental
R.I. Smolin PEDCo Environmental
T.C. Ponder PEDCo Environmental
R. Klier PEDCo Environmental
28
-------
B. Plant and Site Data
1. UTM coordinates:
2. Sea Level elevation: The plant power building is
approximately 122 m (400 ft) above sea level.
3. Plant site plot plant (Yes, No) :_No
(include drawing or aerial overviews)
4. FGD system plan (yes, No): Yes
5. General description of plant environs: Sparsely POPU-
lated, wooded, hilly area—approximately 8 km (5 mi.)
north of Central City. Kentucky.
6. Coal shipment mode; High-sulfur coal is shipped in by
barge on Green River. Low-sulfur coal is shipped to
the plant by truck and rail.
C. FGD Vendor/Designer Background
1. Process name; Wet lime scrubbing
2. Developer/licensor name; American Air Filter
3. - Address: 215 Central Avenue, Louisville, Kentucky
4. Company offering process:
Company name: American Air Filter
Address: 215 Central Avenue
29
-------
Location: Louisville, Kentucky
Company contact; A.H. Berst
Position: SO2 Scrubber Project Engineering
Telephone number: (502) 637-0534
5. Architectural/engineers name; American Air Filter
Address; 215 Central Avenue
Location: Louisville, Kentucky
Company contact;A.H. Berst
Position: S02 Scrubber Projects Engineering
Telephone number: (502) 637-0534
D. Boiler Data
1. Boiler; Nos. 1, 2, and 3
2. Boiler manufacturer: Babcock and Wilcox
3. Boiler service (base, standby, floating, peak):
Peak load service
4. Year boiler placed in service: 1949, 1950 and 1951
5. Total hours operation:
6. Remaining life of unit: No plans to retire unit
7. Boiler type: Dry bottom, pulverized coal units
8. Served by stack no.: Main stack and scrubber stack
9. Stack height; 23.77 m. (78 ft) (scrubber)
10. Stack top inner diameter; 4.88 m. (16 ft)
11. Unit ratings (MW): 37.5/turbine (Z turbines total)
Gross unit rating: 32/turbine (2 turbines total)
(2 turbines
Net unit rating without FGD; 3§v5/taEtrbine total)
30
-------
Net unit rating with FGD: 29.5/turbine (2 turbines total)
Name plate rating; 37.5/turbine (2 turbines total)
12. Unit heat rate; 13,978 kJ/net kWh (13,250 Btu/net kWh)
Heat rate without FGD:
Heat rate with FGD:
13. Boiler capacity factor, (1976): 47.5%
14. Fuel type (coal or oil): Coal
15. Flue gas flow: 169 m3/sec (360,000 acfm)
Maximum: 169 m3/sec (360,000 acfm)
Temperature: 149°C (300°F)
16. Total excess air: 25%
17. Boiler efficiency; 80%
E. Coal Data
1. Coal supplier:
Name: P and M Coal Co. and River Processing Co.
Location: Muhlenberg County, Kentucky and Hazard,
Harlan County, Kentucky
Mine location: Drake Mine and Hoyt Mine
County, State: Muhlenberg, Kentucky, and Harlan, Ky.
Seam:
2. Gross heating value; 25 MJ/kg (10,800 Btu/lb)(high-sulfur
coal)
3. . Ash (dry basis): 13.44% (high-sulfur coal)
4. Sulfur (dry basis); 4.0% (high-sulfur coal); 1.0% low-
sulfur coal)
5. Total moisture: 12.1% (high-sulfur coal)
6. Chloride: Mineral analysis not available
7. Ash composition (See Table Al)
31
-------
Table Al
Constituent Percent weight
g
Silica,
Alumina, Al-O.,
Titania,
Ferric oxide, Fe2O3
Calcium oxide, CaO
Magnesium oxide, MgO Ash Analysis Not Available
Sodium oxide, Na^O
Potassium oxide, K_0
Phosphorous pentoxide, P2°5
Sulfur trioxide, SO.,
Other
Undetermined
F. Atmospheric Emission Regulations
1. Applicable particuiate emission regulation
a) Current requirement: 42 ng/J (0.097 lb/10 Btu)
AQCR priority classification; II _
Regulation and section No.: Ky/401 KAR 3;060
b) Future requirement (Date: ):
Regulation and section No.:
Applicable SO- emission regulation
Current requirement; 720 nq/J
AQCR Priority Classification; n
a) Current requirement; 720 ng/J (1.67 lb/106 Btu)
Regulation and section No.: Ky/401 KAR 3:060
b) Future requirement (Date: )
32
-------
Regulation and section No.:
G. Chemical Additives; (Includes all reagent additives -
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)
1. Trade name; 1.9 cm (3/4 in.) pebble lime
Principal ingredient: Calcium oxide
Function: Sulfur dioxide absorbent
Source/manufacturer: Mississippi Lime Co./Alton, Illinois
Quantity employed: 0.5 kg/sec (2 ton/hr)
Point of addition: prv storage bin into slaker
2. Trade name: 1.9 Cm (3/4 in.) pebble lime
Principal ingredient: Calcium oxide
Function: Sulfur dioxide absorbent
Source/manufacturer: National Gypsum Co.
Quantity employed; 0.5 kg/sec (2 ton/hr)
Point of addition; pry storage bin into slaker
3. Trade name; Not applicable
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
Trade name: Not applicable
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
33
-------
Point of addition:
5. Trade name: Not applicable
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
H. Equipment Specifications
1. Electrostatic precipitator (s)
Number: Not applicable
Manufacturer:
Particulate removal efficiency:
Outlet temperature:
Pressure drop:
2. Mechanical collector(s)
Number:
Type: Multicvclones
Size: 49 m3/sec (105,000 cfm)7 23-cm (9-in.) diameter
Manufacturer: Western Precipitator
Particulate removal efficiency; 85 percent (design)
Pressure drop: 498 Pa (2 in. H2O)
3. Particulate scrubber(s)
Number: One
Type: Variable-throat venturi scrubber
Manufacturer: American Air Filter
Dimensions: Propietary
34
-------
Material, shell: Mild steel (stainless steel throat)
Material, shell lining: Acid brick and precrete
Material, internals; None
No. of modules : one
No. of stages; One
Nozzle type: Spinner vane (original equipment)
Nozzle size:
No. of nozzles:
Boiler load: 100% (Units 1, 2, and 3)
Scrubber gas flow:135 m /sec at 52°C (228,300 acfm at
126°F)
Liquid recirculation rate: 83 I/sec (1360 gpm)
Modulation: None
L/G ratio: 7.65 1/Nm3 (34.5 gal/1000 acf)
Scrubber pressure drop: 1743 Pa (7 in. H2O)
Modulation: Plug (limitorque operator)
Superficial gas velocity:
Particulate removal efficiency:Not yet determined
Inlet loading;5038 ma/m3 (2.2 gr/dscf)
Outlet loading:
SO2 removal efficiency:
Inlet concentration: 2200 PPIU (109 Ib/min)
Outlet concentration; Not available
4. SO- absorber(s)
Number: one
Type: M^h-Lle-bed contactor
Manufacturer: American Air Filter
35
-------
Dimensions: 6.1 x 6.1 x 8.4 m (20 x 20 x 27.5 ft)
Material, shell: Mild steel
Material, shell lining; 1.9-cm (3/4-in.) acid-proof lining
Material, internals: Mobile bed (solid sphere packing)
No. of modules: One
No. of stages: Compartments in mobile bed
Packing type: pyc spheres
Packing thickness/stage: Propietary
Nozzle type: Propietary
Nozzle size: Propietary
No. of nozzles: propietary
Boiler load: 100%
Absorber gas flow: 135 m /sec at 52°C (288.200 acfm at
126°F)
Liquid recirculation rate: 595 l/sec (9750 gpm)
Modulation: None
L/G ratio; 4.4 i/m3 (34 gai/iooo acf)
Absorber pressure drop; 995 pa (4 jn- HoO)
Modulation: None
Superficial gas velocity: 4 m/sec (14 ft/sec)
Particulate removal efficiency: (overall) 99%
Inlet loading:
Outlet loading; 102 mg/m3 (0.044 gr/dscf)
SO2 removal efficiency: 80% guarantee
Inlet concentration: 2200 ppm (to venturi)
Outlet concentration; 400 ppm (from absorber)
36
-------
Clear water tray(s)
Number; Not applicable
Type:
Materials of construction:
L/G ratio:
Source of water:
6. Mist eliminator(s)
Number: One
Type: Radial vane
Materials of construction: Stainless steel
Manufacturer: American Air Filter
Configuration (horizontal/vertical): Horizontal
Distance between scrubber bed and mist eliminator:
Propietary
Mist eliminator depth: Propietary
Vane spacing: Propietary
Vane angles: Propietary
Type and location of wash system: Outward spray at
3 I/sec (50 gpm)
Superficial gas velocity: 7.5 m/sec (25 ft/sec)
Pressure drop: 498 Pa (2 in. H?O)
Comments: Radial vane unit may be replaced by a
chevron-type unit if modifications do not improve
efficiency.
7. Reheater (s): None - not applicable
Type (check appropriate category):
37
-------
Q] in-line
Q indirect hot air
O direct combustion
Q bypass
Q exit gas recirculation
Q waste heat recovery
CD other
Gas conditions for reheat:
Flow rate:
Temperature:
S0_ concentration:
Heating medium:
Combustion fuel:
Percent of gas bypassed for reheat:
Temperature boost (AT):
Energy required:_
Comments: KU and AAF are planning to install a hot air
injection reheat system using extraction steam from an
adjacent unit.
Fan (s) One, forced-draft FGD booster fan
Type: Dual inlet type; 46 cm (18 in. H20)static pressure
Materials of construction: Mild steel
Manufacturer:Buffalo Forge/Allis Chalmer
Location: Upstream of FGD system
Fan/motor speed: 890 rpm - direct drive
Motor/brake power: 1120 W (1500 hp)
38
-------
Variable speed drive: None - damper control
9. Tank(s) One common recirculation tank
Materials of construction: Acid-proof concrete
Function: Reactant tank for scrubbing solution
Configuration/dimensions: Rectangular - 3 compartments
Capacity: 1180 kl (311.040 gal.)
Retention times: 7 minutes/compartment; 21 minutes total
Covered (yes/no): NO
Agitator description: j_ agitator per compartment
10. Recirculation/slurry pump(s)
11 POMPS FOR THE SCRUBBING SYSTEM IN TOTAL
Number
3
2 ,
2
2
2
Description
Absorber
recycle
Bleed stream
Reactant
Pond return
Sump pumps
Size
5900 gpn
350 gpm
90 gpm
50 gpm
Manufacturer
Ingeraoll-Rand
Ingersoll-Rand
Ingersoll-Rang
Ingersoll-Rand
Ingersoll-Rand
Material*
Rubber-lined
Rubber-lined
Rubber-lined
Rubber-1 ined
Rubber-lined
Consents
2 oper. 1 spare
US' head
Continuous maximum
11,
Thickener (s)/clarifier(s)
Number: Not applicable
Type:
Manufacturer:
Materials of construction:
Configuration:
Diameter:
Depth:
Rake speed:
12. Vacuum filter(s)
39
-------
Number: Not applicable
Type:
Manufacturer:
Materials of construction:
Belt cloth material:
Design capacity:
Filter area:
13. Centrifuge(s)
Number: Not applicable
Type:
Manufacturer:
Materials of construction:
Size/dimensions:__
Capacity:
14. Interim sludge pond(s)
Number: Not applicable
Description:
Area:
Depth:
Liner type:
Location:
Typical operating schedule:
Ground water/surface water monitors
15. Final disposal site(s)
40
-------
Number: pne
Description: Slowdown pond; clay lined-impervious
Area: Maximum capacity is 511,000 m (414 acre-ft),suf-
Depth: ficient for 20 years of use
Location: cm plant site - 0.8 km (0.5 mile) from scrubber
Transportation mode: 13-cm (5-in.) diameter piping
Typical operating schedule: Continuous feed while scrub-
ber is in operation
16. Raw materials production
Type: Not applicable
Number:
Manufacturer:
Capacity:Q.5 kg/sec (2 ton/hr) lime
Product characteristics: Pebble lime (1.9 cm, 0.75 in.)
is slaked to 20% solids content slurry.
I. Equipment Operation, Maintenance, and Overhaul Schedule
1. Scrubber (s)
Design life: __^_
Elapsed operation time;8649 hours through Nov. 1977
Cleanout method: water flushing
Cleanout frequency: puring reliability run 4 nr S times
in 6 months
Cleanout duration:
Other preventive maintenance procedures: The unit is
down on weekends; no demand.
2. Absorber(s)
41
-------
Design life:
Elapsed operation time; 8649 hours through Nov. 1977
Cleanout method: water flushing
Cleanout frequency; Same as above
Cleanout duration:
Other preventive maintenance procedures: see above
3. Reheat er(s)
Design life; Not applicable
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
4. Scrubber fan(s)
Design life:
Elapsed operation time: 8649 hours through Nov. 1977
Cleanout method:
Cleanout frequency; AS needed
Cleanout duration:
Other preventive maintenance procedures; see above
5. Mist eliminator(s)
Design life:
Elapsed operation time; 8649 hours through Nnv. 1977
42
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Cleanout method:
Cleanout frequency: AS needed
Cleanout duration:
Other preventive maintenance procedures:Problems may
necessitate design change to chevron type
6. Pump(s)
Design life:
Elapsed operation time; 8649 hours through Nov. 1977
Cleanout method:
Cleanout frequency; As needed
Cleanout duration:
Other preventive maintenance procedures: see above
7. Vacuum filter(s)/centrifuge(s)
Design life: Not applicable
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
8. Sludge disposal pond(s)
- Design life: 9 years expandable to 20 years
Elapsed operation time: 8649 hours through Nov. 1977
Capacity consumed:
Remaining capacity:
43
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Cleanout procedures:
J. Cost Data
1. Total installed capital cost; $3.444 million
2. Annualized operating cost: 2.019 mills/kWh
3. Cost analysis (see breakdown: Table A2)
4. Unit costs
a. Electricity; p.249 mills/kWh (utilities)
b. Water: p.249 mills/kWh (utilities)
c. Steam; Not applicable
d. Fuel (reheating/FGD process); Not applicable
e. Fixation cost: Not applicable
f. Raw material; i. 206 mills/kWh (lime) _
g . Labor : 1.401 mills/kWh (operating and maintenance
labor) _ __ _
: £x .•).'•
5 . Comments TH^ unit- nosts figures^ are the operating cost
figures supplied by the utility for that particular
category for 1976 operation. The electrical energy
- ^
, 10.04 mills/kWh, is excluded. The cost
may be added because of the planned installa-
tion of a steam/hot air refaeat system. _
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Table A2 Cost Breakdown
Cost elements
Included in
cost estimate
Estimated amount
or ?. of total
capital cost
Yes
No
Capital Costs
Scrubber modules
Reagent separation
facilities
Waste treatment and
disposal pond
Byproduct handling and
storage
Site improvements
Land, roads, tracks,
substation
Engineering costs
Contractors fee
Interest on capital
during construction
Annualized Operating
Cost
Fixed Costs
Interest on capital
Depreciation
Insurance and taxes
Labor cost including
overhead
Variable costs
Raw material
Utilities
Maintenance (labor)
I X ! I i | S2.8qa million (1976)
! I I X I ! Not applicable
I I i
i il
cm) cm
cm
cm
cm
X
IT
Cm
CZD
i 5360, onn ^1976)
$186.000 (1976)
§301.090 (1976)
$ 62,165 (1976)
$ 92,124 (1976)
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K. Instrumentation
A brief description of the control mechanism or method of
measurement for each of the following process parameters:
0 Reagent addition: pH control, monitored in the second
compartment of the reactant tank
0 Liquor solids content: Nuclear density meter, situated
in scrubber recycle line.
0 Liquor dissolved solids content:
Liquor ion concentrations
Chloride: Not applicable
Calcium:
Magnesium; Not applicable
Sodium:
Sulfite: Not applicable
Sulfate:Not applicable
Carbonate:
Other (specify); Not applicable
46
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Liquor alkalinity:
Liquor pH: pH meters/2 each per reactant tank
compartment __
Liquor flow: Not control _
Pollutant (S0_, particulate, NO ) concentration in
" a
flue gas: SQj analyzers are installed upstream and
downstream of scrubber
Gas flow; Dampers in SO? absorber section are closed/
opened as a function of load variations .
Waste water _ _____
Waste solids :
Provide a diagram or drawing of the scrubber/absorber train
that illustrates the function and location of the components
of the scrubber/absorber control system.
Remarks : see Section 3. Process Control, and Figure 2, _
on pages 11 to 14 in the text of the report for specific
information on the Green Riyer FGD control system. _
L. Discussion of Major Problem Areas:
1. Corrosion:
Scrubber stack - Corrosion of original carboline liner;
replaced with Precrete G-8 and wire mesh.
47
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2. Eroslop:
Scrubber stack - Carboline lining has been peeling.
Relined the stack in the problem
spots. Replaced with Precrete G-8
over wire mesh.
3. Scaling:
Scrubber internals - The bottom sections of the
mobile—bed, contactor have become
coated with gypsum scale because
of high pH of the scrubbing
solution (pH above 8.5).
4. Plugging:
Mist eliminator and nozzles - Frequent plugging causes
a decrease of flow and an increase in pressure, requir-
ing system shutdown and- manual cleaning. May replace
with chevron unit.
5. Design problems: ,_^_^_
6. Waste water/solids disposal:
48
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7. Mechanical problems: Some minor initial sphere losses
in mobile-bed; replaced with larger spheres. Recycle
pumps, all rubber units replaced with Ni-hard.
Agitators, broken couplings, dropped one agitator.
M. General comments:
Problems to date have been mainly associated with FGD design
limitations (reheat, mist elimination) and minor mechanical
difficulties. The design difficulties have been resolved,
but at the expense of higher capital and operating costs.
Actual particulate and SO? removal efficiencies have not
vet been accurately measured (test scheduled for the first
quarter of 1978). To date, the system has exhibited high
availability index values.
49
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APPENDIX B
PLANT PHOTOGRAPHS
1. Front view of the Green River Power Station. The
scrubbing module, stack, and lime slurry preparation
area appear in the center of the photograph to the
right of the main boiler house.
50
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2. Side view of the Green River Power Station, as seen
from the waste disposal area.
3. Coal barges and unloading area for the Green River
Power Station, as seen from the top of the scrubber
module.
51
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4. Empty railroad coal cars located on the plant grounds
52
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5. Boiler flue gas ductwork that directs gas to the
scrubber module situated (out of view) around the
corner of the boiler house.
53
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6. Guillotine gas bypass damper in the boiler flue gas
duct leading to the scrubber.
7. Top view of the dual-inlet scrubber booster fan located
upstream of the breeching leading into the scrubber
house.
54
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\
8.
Side view of the breeching between the scrubber booster
fan and scrubber house.
9. Upward view of the interior of the scrubber stack
during a shutdown. Repairs to the corrosion-damaged
liner and stack shell are in progress.
55
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10. Close-up view of the corrosion-damaged area in the
scrubber stack.
11. Close-up view of the lime slurry feed preparation tank
located beneath the lime storage silo.
56
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12. Top view of the compartmentalized recycle tank located
beneath the scrubber module.
57
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13. Close-up view of the compartmentalized recycle tank,
14. Close-up view of two of the six immersion-type pH
sensors located in each compartment of the scrubber
recycle tank.
58
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15. Discharge and return lines for the on-site flue-
gas-cleaning waste disposal area located in the background
of the photograph.
59
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16. View of the flue-gas-cleaning waste disposal area
located approximately 0.8 km (0.5 mile) from the
scrubber building.
17. Pump house located in the flue-gas-cleaning waste
disposal area.
60
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18. Some of the solid spheres used as packing in the mobile
bed contactor of the absorber tower.
61
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA- 600/7-78-048e
4. TITLE ANDSU8T.TLE Sumy Qf J
Systems: Green River Stati<
2.
'hie Gas Desulfurization
3n, Kentucky Utilities
7. AUTHOR(S)
Bernard A. Laseke, Jr.
9. PERFORMING ORGANIZATION NAME Ar>
PEDCo Environmental, Lie
11499 Chester Road
Cincinnati, Ohio 45246
ID ADDRESS
I
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION- NO.
5. REPORT DATE
March 1978
6. PERFORMING ORGANIZATION CODE
S. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
E HE 62 4
11. CONTRACT/GRANT NO.
68-01-4147, Task 3
13. TYPE OF REPORT AND PERIOD COVERED
Subtask Final; 1-6/77
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES 1ERL-RTP project officer is Norman Kaplan, Mail Drop 61, 919/
541-2556.
16 ABSTRACTThe report gives i
system retrofitted to Boiler
[utilities. The FGD system
[handle a maximum of 170 cu
scrubber module contains a
removal and a mobile -bed c
are discharged from the re:
water is recycled from the
started up in September 197
FGD operations revealed a
the system supplier to repa
install a steam tube air inje
the system's mist eliminate
and 1964 hours in 1977 (Now
17.
a. DESCRIPTORS
results of a survey of the flue gas desulfurization (FGD)
•s 1, 2, and 3 at the Green River Station of Kentucky
consists of one wet lime scrubber module designed to
i m/sec (360,000 acfm) of flue gas at 149 C (300 F). The
variable -throat venturi with a flooded elbow for fly ash
•ontactor for SO2 removal. The flue gas cleaning wastes
iction tank to an on-site clay-lined settling pond. Clear
pond to the system for further use. The system was
5 and was certified commercial in January 1976. Ensuing
number of major problems which required the utility and
tr and replace the scrubber stack shell and liner,
sction reheat system, and modify (and possibly replace)
»r. The FGD system was in service 6046 hours in 1976
smber).
KEY WORDS AND DOCUMENT ANALYSIS
b.lDENTIFIERS/OPEN ENDED TERMS 0. COSATI Field/Group
Air Pollution Scrubbers kir Pollution Control 13B
Flue Gases Coal Stationary Sources 21B 2 ID
Desulfurization Combustion Particulate 07A,07D
Fly Ash Cost Engineering 14A
Calcium Oxides Sulfur Dioxide (07B
Slurries Dust Control J11G
^rnnf5? 1 08H
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (Tilts Report) j 21 . NO. OF PAGES
Unclassified 69
20. SECURITY CLASS (This page) 22. PRICE
Unclassified |
EPA Form 2220-1 (9-73)
62
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