United States
Environmental Protection
Agency
Industrial Environmental Researc
Laboratory
Research Triangle Park NC 277
Research and Development
EPA-600/S7-81-143 Dec. 1981
Project Summary
Performance Evaluation of an
Industrial Spray Dryer for
SO2 Control
James A. Kezerle, Steve W. Mulligan, Dave-Paul Dayton, and Patricia J. Perry
TRW conducted a continuous moni-
toring test program at the Amcelle
Plant of the Celanese Fibers Company
in Cumberland, MD, to evaluate the
performance of a dry process flue gas
desulfurization system. This system
treated flue gas from a coal-fired
stoker boiler. Tests involved methods
specified by EPA for 30-day compli-
ance testing, which requires a mini-
mum of 22 days of data containing at
least 18 hours of data per day and two
data points per hour.
Hourly and daily averages of results
are presented as well as averages for
the entire test period. Operating
experience with the spray-dryer/ bag-
house system is summarized for a 5-
month period ending with the comple-
tion of testing on September 3O,
1980. Brief descriptions of the test
site, the flue gas cleaning system, and
the continuous monitoring system are
included. Manual sampling techniques
for data verification are described and
the systems for data acquisition, data
analysis, and quality assurance, pre-
pared specifically for this program, are
presented. Raw process and emissions
data are included in the appendices.
Results based on 23 days of data
showed the mean SO2 removal effi-
ciency to be 70 percent over the
compliance test when the sulfur
content of the coal averaged 2 percent.
In general, efficiency was 60-80
percent, except for periods of system
upset. Particle removal efficiency was
99.7 percent. Participate emissions
averaged 0.030 g/m3 (0.013gr/dscf)
during the 2 days these data were
taken.
This Project Summary was devel-
oped by EPA's Industrial Environmen-
tal Research Laboratory, Research
Triangle Park, NC, to announce key
findings of the research project that is
fully documented in a separate report
of the same title (see Project Report
ordering information at back).
Introduction
TRW Inc., under contract to the U.S.
EPA, tested the dry S02 control system
serving the coal-fired (No. 5) boiler at
the Amcelle Plant of the Celanese
Fibers Company in Cumberland, MD.
Celanese ordered the flue gas cleaning
system in January 1979. Construction
of the system by Rockwell International
and Wheelabrator-Frye was completed
in October 1979. Boiler installation was
not completed, however, until mid-
December 1979. Acceptance testing of
the FGC system was completed on
February 21, 1980.
TRW began collecting data for the
demonstration test phase in May 1980.
Installation and certification of instru-
mentation at the site for the performance
testing were performed according to
provisions for S02 compliance testing
and began in late April 1980. The
objective of the program was to collect
30 days of continuous monitoring data,
representing proper operation of the
flue gas cleaning system, using compli-
ance test methods. Problems with the
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boiler, the FGC system, and the con-
tinuous monitoring system delayed
completion of this test phase until
September 30, 1980.
System Description
Celanese Fibers Company installed
the coal-fired boiler in 1979 to supple-
ment the existing oil- and gas-fired
boilers at their Amcelle Plant. This
installation was undertaken to improve
the economics of supplying process
steam for the production of synthetic
fiber. A spray dryer and fabric filter
combination was chosen to provide flue
gas desulfurization (FGD) on the bases
of cost, the lack of available space for
ponding wastes from a wet FGD
scrubber, and the need to provide good
control of particulate emissions.
The flue gas treatment system was
purchased as a turnkey installation from
Rockwell International and Wheelabrator-
Frye, Inc. A flow diagram of the system
is presented in Figure 1.
Coal-Fired Boiler
The coal-fired water-tube boiler at the
Amcelle Plant is identified as the plant's
No. 5 boiler. The boiler is an Erie City
spreader-stoker with a traveling grate
for continuous ash discharge. This
boiler had previously been retired from
service at a Celanese plant in Rome, GA.
The boiler was retubed when it was
reconstructed at the Cumberland, MD,
plant. Table 1 specifies design data for
this boiler.
The coal-fired boiler is rated at 156
million kJ/hr (148 million Btu/hr) with
secondary boiler fuels of gas or No. 6
fuel oil. At the boiler's maximum rating
of 68,000 kg steam/hr (150,000 Ib/hr)
when fired by a combination of coal and
oil or gas, the flue gas to be treated by
the dry FGD system is 41.4 mVs
(87,000 acfm) at 216°C (420°F). At the
boiler's nominal coal-fired rating of
49,900 kg steam/hr (110,000 Ib/hr),
the flue gas to be treated is 30.7 mVs
(65,000 acfm) at 193°C (380°F).
Table 1. Boiler Data - Amcelle Plant Boiler No. 5
Erie City Spreader-Stoker Coal and Natural Gas
Boiler Type Fuel
Type
Fuel Heating Value
Sulfur Content
Ash Content
Coal
Bituminous
29,056 kJ/kg
(12,500 Btu/lb)
1.0 to 2.0 percent
8.0 to 20.0 percent
Gas
Natural Gas
37.2 MJ/m3
(1,000 Btu/ft3)
0.0 percent
0.0 percent
Lime Fill
(From Trucks)'
Lime\
Storage
Silo
Be/t Feeder
I \Slaker
Lime '—|-1J
SystemaaVatGi'it Screen
Lime Slurry
Opacity
&S02
lnstruments\
Coal
Hopper &
Storage
t!Z7
AAJ
Coal
Unloading
Conveyor
Silo
Feedbucket
Conveyor
Silo Reclaim
Conve yor/Ele vat or
Ash Unloading
(To Trucks')
Figure 1.
Celanese boiler and flue gas cleaning system.
2
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Analyses of randomly selected coal
samples are presented in Table 2. The
sulfur content of the coals received
during the test period was 1.25-2.76
percent, with a mean of 2.02 percent
(dry basis).
Table 3 illustrates flue gas design
conditions for various coal firings.
Spray Dryer
The gas cleaning system is designed
to provide FGD removals of from 70
percent (for 1 percent sulfur coals) to 87
percent (for 2 percent sulfur coals) from
half to full boiler load. Most of this SO2
removal takes place in the spray dryer
where the S02-laden flue gas is passed
through a finely dispersed fog of lime
slurry and water.
The spray dryer consists of a single,
6.1 -m (20-ft) diameter vessel containing
a rotary atomizer (Figure 2). This rotary
atomizer (Bowen wheel) is driven at
approximately 16,000 rpm. The lime
slurry is fed to the wheel at a liquid-to-
gas ratio of 0.04 l/m3 (0.3 gal./1000
acf), where it is centrifugally dispersed
into the gas stream. A swirling motion is
imparted to the flue gas as it enters the
top of the spray dryer through a fixed-
vane rotary ring to increase turbulent
mixing of the flue gas and the lime
\ slurry.
Approximately 20 percent of the flue
gas bypasses the spray dryer, thus
providing reheat to raise the gas
temperature prior to its entry into the
fabric filter. This is necessary for dry
operation and compensates for the
temperature drop in the fabric filter. The
amount of water fed to the spray dryer is
automatically adjusted to hold the gas
temperature from the spray dryer at a
set value.
Lime System
The lime system is depicted in Figure
3. The dry storage silo stores about a 10-
day lime supply. High-calcium pebble
quicklime is gravity fed into the lime
slaker where it is mixed with water to
provide a 20 to 30 percent (by weight)
slurry. The lime system can provide 125
percent of required capacity when the
boiler is fired at its maximum rate with 2
percent sulfur coal and overtired gas or
oil. The lime system pumps and piping
can be automatically flushed with water
to prevent deposits.
I I Spray }
X Atomizer•£*'
Figure 2. Spray dryer.
Table 2. Selected Coal Analyses
Vol* Ash
Sample No. % %
1 (8-22-80)
2(8-29-80)
3(9-12-80)
4 (9-23-80)
19.9
31.6
17.2
33.14
14.95
18.96
13.97
16.81
Sulfur
1.58
1.92
1.36
2.24
HHV
kJ/kg Btu/lb
29.860
27,998
30,153
29,411
12.846
12.045
12.972
12,653
* Volatile matter.
Table 3. Flue Gas Characteristics - Amcelle Plant Boiler No. 5
Fuel
Steam Production
Flue Gas Temperature
Flue Gas Flow Rate
S02 Concentration
SO2 Exhaust Rate
Paniculate Loading
Coal
49.900 kg/hr (110.000 Ib/hr)
193°C (380°F)
30.7 m3/s (65,000 acfm)
800 to 2,500 ppm
113 to 363 kg/hr (250 to 800 Ib/hr)
8.5 to 11.9 g/m3 (3.7 to 5.2 gr/dscf)
Lime
Slaker
Water
Slurry
Tank
Figure 3. Lime system.
Fabric Filter
The fabric filter, a four-compartment
pulse-jet baghouse manufactured by
Wheelabrator-Frye, Inc., is shown in
Figure 4. Each compartment contains
225 bags. The baghouse can operate
with three compartments on-line when
the boiler is operating at its nominal
coal-firing rate to produce 49,896 kg/hr
(110,000 Ib/hr) of steam.
The air-to-cloth ratio is 2.2 - 6.8 with a
design pressure drop of 500 Pa (2.0 in.
H20). The filter medium is a fiberglass-
reinforced felt manufactured by Huyck.
Description of Continuous
Monitoring System
Instrumentation
The continuous monitoring system
used in the performance evaluation
consisted of four major groups: the filter
probes and process sample lines, the
gaseous analyzers, the data acquisition
and recording system, and the remote
temperature sensing system. Upon
arrival at the test site, these four
separate systems were assembled and
aligned into one comprehensive system.
Sampling System
Sampling locations are shown in
Figure 5. The inlet sample point was in
the rectangular duct between the boiler
and the spray dryer. The outlet sample
point was in the circular cross-section
of the stack. The intermediate sample
point was not monitored.
-------
To Stack
From Spray
Dryer
Spent Sorbent
and Fly Ash
Figure 4. Fabric filter.
The filter probe assemblies utilized
stainless steel filters (20-/um mesh)
attached to 76-cm (30-in.) long stainless
steel tubes with an o.d. of 1.3 cm (0.5
in.) and an i.d. of 0.6 cm (0.2 in.).
Connected to this tubing was about 30
m (100 ft) of electrically heat-traced
sample line, constructed of 0.6-cm (0.2-
in.) Teflon tubing. The sample lines were
kept at 121°C (250°F) to prevent con-
densation from the gas sample.
The gas samples collected at the inlet
to the spray dryer and at the outlet of the
baghouse were dried with a gas condi-
tioner. This gas conditioner contained
two dual stainless steel condenser traps
suspended in a medium of ethylene
glycol cooled by a Hanke refrigeration
unit with copper cooling coils to approx-
imately 3°C (37°F). The sample was
pulled through the condenser traps by
two Teflon and stainless steel pumps
and then delivered to the analyzers. The
gas conditioner system was connected
to a timer that allowed the condenser
traps and heat-traced sample lines to go
into the 700 kPa (100 psi) blowback
Legend
W v Contaminanted Air Flow
Flue Gas - SOz and Fly Ash
Scrubbing Solution
Clean Air Flow
Outlet
Sample Point
Inlet
Sample Point
Combustion
Air
'{Spent Dry Salts?
Outside Air from
Forced Draft Fan
Air Preheater
Absorbent A/kali
Solution Scrubbing
Tank
Intermediate
Sample Point
Dry Product
Disposal
Induced
Draft Fan
Figure 5. Two-stage dry FGD system with TRW sampling positions indicated.
4
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mode for 3 minutes of every hour. A
schematic of this sampling system
(Figure 6) shows the path of sample gas
from the probe to the analyzers and the
path of output data from the analyzers to
the data logger.
Flue Gas Analyzers
Flue gas was analysed using a
Thermo-Electron Pulsed Fluorescent
S02 Analyzer, Model 40, andaBeckman
Paramagnetic 02 Analyzer, Model 755.
These analyses were conducted con-
tinuously for both the inlet of the spray
dryer and the outlet of the baghouse.
The inlet S02 analyzer operated on a 0-
5000 ppm full-scale range with a 1-V
full-scale output, while the inlet O2
analyzer operated on a 0-25 percent of
total gas volume full-scale range with a
10-mV full-scale output. The outlet S02
analyzer operated on a 0-500 or 0-1000
ppm full-scale range, depending on the
concentration of S02 in the flue gas at
the location of the outlet sample probe.
The outlet Oz analyzer operated on the
same range as the inlet O2 analyzer, but
with a 1-V full-scale output.
The SO2 and O2 analyzers were
certified according to procedures out-
lined in "Performance Specifications 2
and 3 for Continuous Monitors in
Stationary Sources" as specified by EPA
(44 Federal Register 58602, 1979).
Relative accuracy was determined for
the S02 analyzers using the average
response times for the analyzers ob-
tained during response time tests.
These determinations ensured close
agreement between the results from
the S02 analyzers and EPA reference
methods (specifically. Reference Method
6 for S02).
Calibration errors were also deter-
mined for each of the four analyzers.
Directly after the daily calibration of the
instruments, zero, mid-level, and high-
level calibration gases were randomly
introduced into the respective analyzer
until a set of five points for each
concentration (zero, mid-level, and
high-level) was obtained.
Both of the S02 analyzers and both of
the O2 analyzers passed all of the
certification requirements. In addition,
all calibration gases used for instrument
certification or instrument calibration
were either traceable to National
Bureau of Standards reference gases or
underwent the calibration gas certifica-
tion. The latter gases were obtained
from the EPA repository and were
certified by EPA personnel prior to use in
the tests at Celanese. The S02 and 02
analyzers were calibrated daily between
the hours of 0800 and 1200.
Data Acquisition System
The Data Acquisition System con-
sisted of a Fluke Data Acquisition
system, a dual-pen Fisher 5000 Record-
all recorder, and a Leeds and Northrop
six-channel multipoint recorder.
Hi-Range
Mid-Range
Exhaust
*Data Acquisition System.
Figure 6. Flue gas sampling and analysis system.
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Temperature Sensors
Two 60-cm (24-in.) long chromel-
alumel thermocouples were mounted
parallel to the filter probes. These
thermocouples measured flue gas
temperatures at the inlet and outlet of
the FGD system. They were hard wired
into the Fluke Data Acquisition system,
using about 30 m (100 ft) of chromel-
alumel thermocouple wire.
Results
Data on S02 removal that were typical
of the fully operating dry FGD system
performance and whose relative accu-
racy was fully documented were col-
lected only during the final month of the
tests. This period of "good" data collec-
tion ran from August 28 through
September 30, 1980. The boiler gen-
erally ran at a steady load (about half of
the rated value because of seasonal
reduction in steam requirements)
throughout most of this period, and the
FGD system operated almost contin-
uously.
Hourly averages of S02 emissions in
parts per million were calculated from a
minimum of two data points per hour.
These hourly averages were then
corrected to zero percent oxygen
dilution and converted to pounds per
million Btu. Calculations of S02 removal
efficiency were then based on these
average hourly S02 emission values.
S02 emissions in pounds per million
Btu were determined using the F-factor
technique. An F-factor for dry flue gas
from coal of 9820 dscf/106 Btu (263.9
mVGJ) was used. Heat input to the
boiler was calculated from available
data. Hourly averages of steam flow
were used to derive hourly values of
coal feed rate from values of total daily
coal consumption.
Typical data for inlet and outlet S02
concentrations are shown in Figures 7
and 8. These data are representative of
the 23 days when continuous monitoring
methods met EPA's compliance criteria,
including collection of data for over 18
hours per day with the FGD system
treating boiler flue gas. Figure 7 shows
that outlet S02 concentration, mea-
sured in the stack, closely follows the
SO2 concentration at the inlet to the
spray dryer. This curve indicates no
corrective action being taken to adjust
slurry flow rate for varying inlet S02
concentration. With the FGD system in
automatic control, the outlet SOa
concentration (see Figure 8) was rela-
tively constant, indicating that the slurry
flow was adjusted to accommodate
|2000-|
s
c
| /eooH
I 7200H
O
O
oo
800-
a 4oo-|
Inlet*
Inlet
Figure 7.
S'
o
-7600H
i.
c
1/200-
o
O 800-
oo
•O
~ 400-
0200 0400 0600 0800 1000 1200 1400 1600 1800. 2000 22002400
Time of Day
Average hourly SO2 concentrations for September 3, 1980, with FGD
system controlled manually.
o
u
5
Inlet
Figure 8.
0200 0400 0600 0800 WOO 1200 1400 1600 1800 2000 2200 2400
Time of Day
Average hourly SO2 concentrations for September 8, 1980, with dry
FGD system controlled automatically.
even rapid changes in inlet SO2concen-
tration.
Although the FGD system was de-
signed to operate automatically, this
was not always possible because of
malfunctions in the stack S02 monitor
which provided feedback to the spray
dryer control system. Problems with this
monitor necessitated extended periods
of manual operation. Under manual
operation, the slurry flow sometimes
became so high that the outlet concen-
trations were 50 ppm or less. On these
occasions, SO? removal efficiencies
exceeded 90 percent.
The average daily S02 removal
efficiencies for the continuous moni-
toring period cited earlier are given in
Figure 9. Except for periods of system
upset, removal efficiency was 60-80
percent. The only prolonged period of
low S02 removal occurred between
September 3 and 6 and stemmed from
inability to maintain steady boiler load
and slurry pumping problems. The
mean S02 removal efficiency for the 23
days of performance data was 70 per-
cent, and the standard deviation from
this mean was ±9 percent. However,
over the last week of the tests, the
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u
.OJ
S
o
0)
et
M
O
oo
Large Load
Fluctuations
Slurry
Pumps
Inoperable
8/28
Plugged
Spray Dryer
Repaired
Baghouse
Bags
Changed
I I I I I I I I I I I I I I I I I I I rl I I I I I I
8/31 9/5 9/10 9/15 9/17 9/24 9/30
Date
5/77 9/24
9/25
Figure 9. Average daily SO2 removal efficiency for dry FGD system.
average daily SOa removal efficiency
was 78.5 percent, based on 23 hours of
hourly averaged data for each day.
The emission rate and removal
efficiency of particulate matter for this
FGD system were determined by three
isokinetic sampling runs on June 2 and
13, 1980. Testing for particulate matter
was conducted according to EPA Method
5 using a RAC Stacksampler sampling
train. Results of these tests are sum-
marized in Table 4.
System Availability and
Operating Experience
Table 5 summarizes the availability of
the boiler and FGD system during the
tests. The boiler went down for refractory
repairs on April 20. From then through
the end of the program on September
30, the boiler was off-line approxi-
mately 12 percent of the time. It was on-
line but running abnormally an addi-
tional 5 percent. Thus, boiler problems
prevented representative characteriza-
tion of the FGD system for about 17
percent of the time TRW was on site.
This amounted to 672 of 3.912 hours in
the period.
The FGD system was off-line (not
operating at all) about 23 percent of the
time. The FGD system operated ab-
normally an additional 12 percent of the
time. During this time the slurry feed
rates were so low or unsteady that
monitoring of any significant S02
scrubbing was prevented. Thus, the
Table 4. Particulate Emissions Results
Date
Run No.
6-2-80
BI5-1
6-2-80
BI5-2
6-3-80
BI5-3
Average
Inlet Concentration
g/m3 (gr/dscf)
Run No.
Outlet Concentration
g/m3 (gr/dscf)
Particle Removal
Efficiency. %
9.43
(4.12)
B05-1
0.0334
(0.0146)
99.65
8.44
(3.69)
B05-2
0.0159
(0.00697)
99.81
11.78
(5.15)
B05-3
0.0400
(0.0175)
99.66
Table 5. System Availability
9.88
(4.32)
0.0298
(0.0130)
99.70
Availability*, %
Component
Boiler
FGD System
Spray Dryer
Lime Feed System
Fabric Filter
Apr-Sep
82.2
62.4
81.8
83.2
99.8
Aug-Sep
(720 hr)
93.3
73.2
97.8
76.5
98.9
Sep 25-30
(144 hr)
100.0
96.2
100.0
96.2
100.0
*The percentage of time in the period that the component operated normally.
FGD system was unavailable 35 percent
of the time, or a total of 1,354 hours.
Availability of the system was signifi-
cantly improved in September when
most of the continuous monitoring data
were collected. During this period the
FGD system was off-line less than 19
percent of the time and operated
abnormally an additional 8 percent of
the time, giving an availability of 73
percent.
Operating problems and their effects
on the program were broken down into
four system components: the boiler, the
lime feed system, the spray dryer, and
the fabric filter. Problems with each
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component impact the entire FGD
system.
Steam Boiler
A problem which affected the per-
formance of the FGD system was the
variability of coal quality. Coal sulfur
content varied widely throughout the
early part of the program. The quality
became less variable near the end of the
program, but proximate analyses of
daily coal deliveries showed sulfur
contents of 1.25 - 2.76 percent. When
operating in automatic control to keep
the outlet S02 concentration at a set
value, the FGD system responded to
rapid changes in inlet SC>2 concentra-
tion so that hourly averages of emissions
remained constant. In manual control,
the outlet S02 concentration followed
the inlet concentration in the absence of
operator adjustment. With uniform coal
quality and automatic control of slurry
flow, large fluctuations in inlet S02
concentrations were absent and a
steady outlet S02 concentration was
maintained.
Another problem which relates to
coal supply involves the amount of fines
in the coal. Coal fines, when suddenly
dumped into the furnace, cause rapid
changes in boiler load and flue gas flow,
changes in SC>2 emissions, and increased
particulate matter and opacity levels in
the stack. Fast changes in flue gas flow
and SOz concentration made it difficult
for the spray dryer to keep SOa emissions
at a desired level. Such large and rapid
load fluctuations occurred on September
5, 6, and 7. Data collected on these days
were not included in overall averages.
Lime Feed System
The slurry is fed to the atomizer by
progressing cavity pumps; under design
conditions, one pump is in use and one
is a spare. However, to cope with the
higher sulfur coals encountered, the
single pump had to be operated at high
speeds and this led to rapid pump wear.
To alleviate this, the system was
modified to use both pumps in parallel.
This was the normal mode of operation
throughout the latter part of the test
period.
Most other problems with the lime
feed system related to plugging some-
where in the system because of grit in
the lime. Although grit was supposed to
have been removed by screens inside
the slaker, damaging quantities of it
passed through or bypassed the screens
into the rest of the system. Failure to
remove grit caused excessive wear in
the pumps and plugging in the slaker, in
the flow lines, in the slurry pump, and in
valves. Dual-element screen filters
were eventually installed in the feed
system, but not enough time elapsed
before the end of the program to assess
whether they solved the problem.
Spray Dryer
Maldistribution of lime slurry in the
atomizer resulted in the wetting of the
dryer wall and discharge of damp
material from the dryer. It was corrected
by redesign.
Other problems encountered with the
spray dryer also related to the atomizer.
The rotary atomizer was subject to
clogging with grit particles if they were
not screened sufficiently from the
slurry. The spray dryer was shut down
for cleaning when this clogging occurred.
Another problem was failure of the
bearings supporting the shaft of the
atomizer wheel caused by an imbalance
due to grit plugging the atomizer wheel.
Fabric Filter
The most serious problem with the
baghouse was the unexpectedly high
pressure drop through the fabric filter.
This was apparently caused by moisture
on the bags which occurred during an
upset and combined with ash and lime
to form a coating that increased the
resistance to flow. To lower the pressure
drop through the baghouse, design and
process changes were made, including
increasing the pulse-jet air volume by
approximately 15 percent. Tests since
this modification indicate that this has
solved the problem.
Conclusions and
Recommendations
The two-stage dry FGD system in-
stalled at the Celanese Fibers Company's
Amcelle Plant required 28 - 46 hours of
maintenance each week and close
operating supervision for continuous
operation. Some of this maintenance
was performed while the system was
operating so there was no interruption
in SOa removal. The average S02
removal efficiency demonstrated over a
30-day period, based on 23 days of
acceptable data, was 70 percent. This
level of performance was achieved
while burning coal with an average
sulfur content of about 2.0 percent on a
dry basis. System guarantees called for
70 percent SOa removal for 1 percent
sulfur coal and 87 percent SO2 removal
for 2 percent sulfur coal. Compared with
these goals, the demonstrated S02
removal was low. Over the last 6 days of A
the tests, after several operational \
difficulties had been resolved, SO2
removal efficiency averaged 78.5 per-
cent, a marked improvement over
earlier results but still below the stated
goal with 2 percent sulfur coal.
Boiler operators operate the FGD
system along with their other duties.
Modifications made to the system after
operating experience had been gained
have the potential to make this a more
reliable system. As described above,
most of the'operating problems relate to
plugging caused by grit in the slurry and
water vapor condensing in the flue gas
due to low operating temperatures.
Both of these problems can be solved by
changes in operation and design. Main-
tenance needs will also be reduced by
these modifications.
Because of problems experienced
thus far, redundancy of critical compo-
nents is recommended. Specifically,
three slurry pumps are needed with two
on-line at all times and one as a spare. A
spare atomizer will limit spray dryer
shutdowns due to atomizer failure.
Filters should be set up to provide
uninterrupted slurry flow to the spray
dryer while one filter element is being
replaced or cleaned. A means of keeping
the outlet SOa monitor operating con-
tinuously is needed. Since feedbac
from the outlet S02 monitor is used i
controlling lime slurry flow to the spray
dryer, this will permit a steadier outlet
SOa level and more consistent FGD
system performance via operation in
automatic control.
8
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J Kezerle. S. Mulligan, D. Dayton, and P. Perry are with TRW, Inc., P.O. Box
13000, Research Triangle Park, NC 27709.
Theodore G. Brna is the EPA Project Officer (see below).
The complete report, entitled "Performance Evaluation of an Industrial Spray
Dryer for SCb Control," (Order No. PB 82-110 701; Cost: $21.00, subject to
change) will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
•ft U.S. GOVERNMENT PRINTING OFFI CE :1 981 --559-092/3356
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