REVIEW OF S02 CONTROL ALTERNATIVES
FOR COLSTRIP UNITS #3 AND #4
Pacific Environmental Services, INC.
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EPA CONTRACT NO. 68-01-4140
TASK ORDER NO. 17
REVIEW OF S02 CONTROL ALTERNATIVES
FOR COLSTRIP UNITS #3 AND
J. C. Serne - Project Manager
January 1978
Prepared for the:
U.S. Environmental Protection Agency
Region VIII
Air and Hazardous Material Division
1860 Lincoln Street
Denver, Colorado, 80295
Norman A. Huey, Task Manager
PACIFIC ENVIRONMENTAL SERVICES, INC.
1930 - 14th Street
Santa Monica, California, 90404
(213) 393-9449
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TABLE OF CONTENTS
5.3
6.0 SUMMARY .
Section Page
1.0 INTRODUCTION 1-1
2.0 COLSTRIP UNITS #1 AND #2 SCRUBBER DESIGN AND PERFORMANCE 2-1
2.1 Scrubber Description 2-1
2.2 Operational History 2-6
2.3 Scrubber Test Data and Performance 2-11
2.4 Scrubber Costs 2-13
3.0 PLANNED SCRUBBER SYSTEM FOR COLSTRIP UNITS #3 AND #4 . . 3-1
3.1 Scrubber Description 3-1
3.2 Emission Estimates 3-2
3.3 Scrubber Costs 3-5
3.2.1 Worst Case Emission Rates 3-3
3.2.2 Typical Emission Rates 3-3
4.0 MODIFICATION OF PLANNED SCRUBBERS 4-1
4.1 Increased L/G Ratio or Additional Sprays 4-2
4.2 Increased Lime Addition 4-3
4.3 Pilot Plant Program 4-5
5.0 ALTERNATIVE SO 2 CONTROL SYSTEMS 5-1
5.1 Colstrip SO 2 Control System Constraints 5-2
5.2 Operational FGD Systems 5-3
5.2.1 Limestone Scrubbing Systems 5-5
5.2.2 Sodium Carbonate Scrubbing 5-7
5.2.3 Lime Scrubbing 5-8
5.2.4 Sumary of Performance 5-9
FGD System Economics 5-10
6-1
1
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LIST OF ILLUSTRATIONS
Figure Page
2-1 Coistrip Units 1 & 2 Simplified Flow Diagram 2-3
2-2 Typical FGD Scrubber, Colstrip Unit 1 & 2 2-4
LIST OF TABLES
Table ____
2-1 Scrubber Availability Versus Plant Load.
2-2 Emission Test Results
2-3 Coistrip SO 2 Control System Performance.
2—4 FGD System Costs - Two Generating Units.
3-1 Worst Case Emission Rates
3-2 Typical Emission Rates
5-1 Sumary of Low Sulfur Coal Operational FGD
of September 1977
5-2 FGD System Performance Sunriary
Page
2-7
2-12
2-14
2-15
3-4
3-4
Systems as
5-4
5-9
11
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1.0 INTRODUCTION
The Montana Power Company currently operates two 360 MW (gross)
coal-fired electric generating units at Coistrip, Montana. These
existing units, #1 and #2, are equipped with scrubbers designed to
remove both particulates and sulfur dioxide from the flue gas.
Montana Power Company is planning construction of Units #3 and #4
at Coistrip, each with a 700 MW capacity. Coistrip Units #3 and #4
will be equipped with scrubbers to remove particulates and sulfur
dioxide, as required to meet New Source Performance Standards (NSPS)
and Class I Prevention of Significant Deterioration (PSD) regula-
tions. The objective of this study is to evaluate the SO 2 control
alternatives for Coistrip Units #3 and #4
The design and performance of the scrubbers serving Coistrip Units
#1 and #2 are described in Section 2. Sulfur dioxide emission rates
from Units #3 and #4 are predicted in Section 3, assuming a similar
scrubber design and performance as reported for the existing units.
Section 4 describes potential modifications to the planned Coistrip
scrubber design expected to improve SO 2 collection efficiencies. A
brief sunii ary of alternative SO 2 control systems potentially avail-
able for Coistrip Units #3 and #4 is presented in Section 5 along
with cost performance information and associated environmental and
engineering sacrifices.
1—1
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2.0 COLSTRIP UNITS #1 and #2 SCRUBBER DESIGN AND PERFORMANCE
An excellent description of the design and perfonitance of the scrub-
bing system on Coistrip Units #1 and #2 is provided in a paper re-
cently presented at the Fourth Symposium of Flue Gas Desulfurization.
A sunui ary of “Status and Performance of the Montana Power Company’s
Flue Gas Desulfurization System” by D. T. Berube and C. D. Grinnii of
Montana Power Company is provided in this section along with a
discussion of the SO 2 collection efficiencies calculated by PES.
2.1 Scrubber Description
The flue gas cleaning system now in operation on Coistrip Units #1
and #2 consists of three scrubber modules operating in parallel per
unit. Each 33 1/3% nominal scrubber module is capable of treating
up to 40% of the flue gas flow for short periods of time. No scrub-
ber bypass capability is installed. Each scrubber module consists
of a variable throat venturi for particulate and sulfur dioxide re-
moval and a spray absorption section for additional sulfur dioxide
removal. This system, which was piloted for approximately one and
a half years, uses the alkalinity present in the captured ash from
the Rosebud seam coal for the SO 2 removal. Supplemental lime is
added for pH control. The vendor for the scrubber installation was
Combustion Equipment Associates. Bechtel Power Corporation was the
architect-engineer for the power plants and personnel from its Re-
search Division were involved in the devlopment of the Coistrip
scrubbers. Unit #1 has been operational since September 1975 and
Unit #2 since May 1976.
The design parameters of the GD system are as follows:
1. Liquid to gas ratio: L/G 33
split L/G 15 to venturi, L/G 18 to absorption sprays.
2. Suspended Solids in Recycle Loop: 12%.
2—1
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3. Venturi Pressure Drop: 17.0 in. W. S.
4. Recycle Retention Time: 8 minutes.
5. Recycle Slurry pH: 4.5 to 5.6.
6. Particulate Emission Guarantee: Outlet grain loading not to ex-
ceed 0.018 grains per actual cubic foot as measured at the
reheater outlet.
7. Sulfur Dioxide Guarantee: SO 2 emission not to exceed 1.0 lb SO 2
per million BTIJ heat input.
8. Closed Loop Operation: Liquid can leave the system by evapora-
tion in the process, up through the stack, evaporation from
the pond surfaces, or be purged with the sludge resulting from
the scrubber operation.
The coal characteristics used in the scrubber specification are
sumarized below:
Coal: Average As Received
Moisture 23.87%
Volatile Matter 28.59%
Fixed Carbon 38.96%
Ash 8.59% (Max 12.58%, t4in 6.1%)
Heating Value 8500 BTU/lb (Max 8,843 BTU/lb,
Mm 8,162 BTU/lb)
Sulfur .77% (Max 1.0%, Mm 0.4%)
A simplified flow diagram of the Coistrip scrubber train is shown on
Figure 2-1. Figure 2—2 presents a detailed view of the scrubber in-
ternals. Combustion gas exits the air heater at about 290°F, trav-
els through a duct containing several 90° turns and enters the
scrubber module. The gas then passes through the variable throat
venturi where it is contacted with the slurry which flows over both
the venturi bowl surface and the plumb bob. Next, it passes through
the absorption zone where it is contacted with recycle liquor sprayed
from the absorption nozzles. The wash tray is next in line to con-
tact the gas. Its function is to remove entrained solids from the
cleaned flue gas prior to the mist eliminators. Both the bottom of
the mist eliminator and the bottom of the wash tray are sprayed
continuously. The mist eliminator is sprayed with a blend of wash
2-2
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.COLSTRIP UNiTS 1 & 2
SIMPL IfIED FLOW DIAGRAM
FLYASH PONO
WASH TRAY POND
Figure 2 -1
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IAWCtI TIAL P DZ7LIS
PLUMB BOB
VEP TURI BOWL
WtSl LLIMII A1DR lOP SPRAY
W!ST ILIMINA1OR
V1ST IL
TYPICAL FGD SCRUBBIR
COLSTRIP UNIT 1 & 2
TRAY UhDER SPRAYS
%ASH TRAY VISCii&R01
ABSORPHON SPRAYS
ABSORPTION SICTID
Figure 2-2
LUERCINCY SPRAYS
PLUMB BOB i:O2zu
VL! TURI !ICTIDU
TRAY
RORMAL LIDUID LEVEL
BLURRY OUTLET
MANHOLE
ACCESS DOOR
* ITA1DR IJIdIT
2-4
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tray pond return liquid and river water. This area and the pump
and agitator seals are the only places where fresh water enters the
system. A liquid level is maintained on the top of the wash tray.
The wash tray/mist eliminator loop works independently of the scrub-
ber slurry recycle loop. The gas exits the scrubber module and
passes through a reheat section consisting of two banks of plate-
coil reheaters. The reheaters are cleaned by soot blowers placed
above and between the two banks. The dry induced draft fans are
last in line to contact the gas 1 then It passes isolation dampers
and out the stack.
Two scrubber recycle pumps are needed to provide the required slurry
flow to the venturi and absorption sections. The third pump is a
spare that can be valved in to either the venturi or the absorption
sprays. A bottom entry agitator in the main recycle tank provides
necessary agitation to extract alkali values from the ash and re-
suspension capability for the slurry should the module be shut down.
The wash tray tank is also agitated and a set of pumps, one opera-
ting and one spare, is used in that loop. The three scrubber mod-
ules of one generating plant rely on one tray recycle tank.
Solids are bled from the scrubber recycle loop to the effluent tank,
then pumped to the settling ponds Inmediately behind the plant. The
wash tray cycle”rejects its solids to a separate pond at the same
location. Oecanted liquid is brought back to the wash tray and
scrubber recycle loops.
Materials of construction include unlined carbon steel for the
scrubber inlet ducts, glass flake polyester lined carbon steel for
the internal surfaces of the scrubber vessels, abrasion resistant
bricks In the venturi throat, 316 stainless steel on certain areas
of the plumb bob, a Norel plastic for the four pass chevron mist
elIminators, 316 stainless steel In the wash tray, flakelining In
the duct exiting from the scrubber through to the chimney opening,
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Hastalloy G and Inconel 625 for the reheat surfaces with 316 stain-
less forming the duct walls around the reheater and rubber lining
in the fan casing. The large recycle pumps are all rubber lined.
Piping four inches and greater in diameter is rubber lined carbon
steel and piping less than four inches is 316 stainless steel. The
dry induced draft fan is of carbon steel construction.
The lime system consisting of storage silos for the pebble lime
slakers, transfer and holding tanks, and the associated pumps and
piping provides for lime slurry addition to the scrubber recycle
tank for pH control.
Inlet and outlet sulfur dioxide monitors are provided on the scrubber
trains. The testing station placed in the stack also is the loca-
tion for the SO 2 , NOR. CO 2 and opacity monitors.
2.2 Operational History
Unit #1 has been in operation since September 1975 and Unit #2 since
May 1976. The overall performance of the scrubber system has been
quite good. The scrubbers have been free of massive scale formations
that have been reported at other scrubber installations. The system
has operated in a closed loop mode. Table 2-1 contains scrubber
availability data from September 1975 through July 1977. The defi-
nition of scrubber availability below the table should be noted.
The average availability for the Unit 41 scrubbers was 87% and for
Unit 42 scrubbers was 91.3%. Modifications and improvements have
been made in the scrubber system to correct problems and increase
availability. A description of the problem areas and the solutions
or corrective measures taken by MPC are provided in the following
pages of this section.
Deposits occurred at the wet-dry interface located at the entrance
to the scrubber modules which reduced availability to an jnacceptab1e
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Table 2-1. SCRUBBER AVAILABILITY VS PLANT LOAD
Monthly
Capacity
Factor
Percent
Number
Days
On Line
Average MW
For Days
On Line
Scrubber
Avail-
ability
Percent
Unit
*1
Unit
#2
Unit
#1
Unit
#2
Unit
#1
Unit
*2
Unit
#1
Unit
*2
1975
Sep 0.5 3 50
Oct 19.4 19 139
Nov 42.2 24 203
Dec 59.9 30 239
1976
Jan 63.8 28 265 90.0
Feb 65.4 26 273 98.0
Mar 57.0 24 277 97.6
Apr 49.9 28 219 74.2
May 26.0 1.3 14 3 210 66 96.8 100.0
Jun 0.0 23.2 0 16 0 171 - 99.7
Jul 28.0 19.5 20 13 167 180 93.2 98.7
Aug 37.8 13.0 23 10 194 162 94.7 95.8
Sep 64.5 64.6 30 30 239 232 88.6 98.3
Oct 73.1 77.0 30 31 281 298 79.9 90.3
Nov 55.6 79.7 30 30 225 303 62.7 94.1
Dec 67.2 82.3 31 31 249 297 73.8 92.5
1977
Jan 72.9 68.2 31 30 270 258 92.5 83.4
Feb 3.0 75.3 2 27 161 285 95.4 93.8
Mar 0.0 71.3 0 28 0 293 - 96.7
Apr 49.9 68.2 25 29 236 264 83.0 84.5
May 64.1 23.3 26 13 286 209 85.4 63.0
Jun 68.6 61.4 28 28 284 249 87.4 87.8
Jul 71.8 57.5 29 28 284 238 85.1 90.6
Ave-
rage
87.0
91.3
Note: Scrubber availability = total module hours available i
(hours in month) except May through August 1976 base is
days in operation because of extended scheduled outages.
2-7
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degree. These are not to be confused with calcium sulfate or calcium
sulfite scale formation. Gas flow tests were run on a model that
duplicated the configuration of the duct from the air heater exit
to the top of the scrubber module and the upper portion of the
scrubber module itself. These tests found there was a maldistribu-
tion of the dust entering the scrubber module along with extreme
velocity variation from one side of the duct exit to the other.
In addition, a model study was made of the liquid flow on the tan-
gential shelf above the venturi. Prom those studies, it was con-
cluded that gas flow turning vanes in the duct elbow above the
scrubber module and liquid guiding vanes and baffles on the tan-
gential shelf would be required to reduce the wet-dry interface
buildup. One module was modified and operation gave encouraging
results. These modifications were then made during the spring and
suniner of 1977 to the remaining five modules and the construction
time is reflected in the scrubber availability figures in Table 2-1.
Actual operating experience from the modules equipped shows a sig-
nificant reduction in cleaning time and has Increased the time in-
crement between inspection and cleanings.
Instrumentation in slurry and flue gas service has not been trouble
free. The stack opacity, SO 2 and NO monitors along with the SO 2
monitors on the inlet and outlet of the scrubber modules have exhib-
ited unstable and erratic behavior. A corrective program has shown
progressive Improvement in the data retrieved by these monitors
during the past six months. The in line pH probes either erode
away or lose sensitivity due to deposits on the elements. Slurry
density monitors have given erratic and unstable operation too and
a test program is in progress to isol te these devices from vibra-
tion. Both slurry density and pH, key operating parameters, are
taken manually and monitored on a frequent basis.
2-8
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The supplementary alkali feed system has been difficult to use due
to line plugging and equipment failure. The lime system is being
modified so that it will be simpler to use and less prone to plug-
ging. Pinch valves are being placed next to the scrubber vessel
on each feed line so any solid accumulation will slough off as
these valves are regularly stroked. The alkaline ash captured by
the scrubber has generally been adequate to keep the scrubber pH
within the control range. Better control of the lime system will
keep the pH more constant and allow SD 2 removal to be optimized.
Failures of the protective glass flakelining on the carbon steel
vessel walls and ducts have occurred. These failures were evident
prior to a major temperature excursion that occurred in Unit l in
October 1976 but were then aggravated. The excursion followed a
complete station power blackout and the failure of the emergency
scrubber quench water supply system to operate. The glass flake-
lining along with the plastic mist eliminators were seriously dam-
aged at that time in Unit #1 and account for low scrubber availab-
ility during November and December 1976. A failure of an ID fan
motor during the same time period, independent of the temperature.
excursion, also contributed to the Tower availability figures. If
the ID fan motor was not considered in compiling the availability
numbers, the scrubber availabilities would have been 88.5%, 94.0%
and 81.6% for Unit #1 during the months of October, November and
December 1976. Subsequent problems with other ID fan motors early
in 1977 have reduced scrubber availabilities. The availability
given for May 1977 for Unit 12 reflects another fan motor repair and
the modifications for the wet-dry interface.
Inspection of an ID fan rotor during the spring of 1977 resulted in
the finding of cracks in the center plate next to the blades. Each
fan was then cleaned and critically Inspected. If cracks were found
or If there was a suspicion a crack might form, it was Isolated and
ground out. Then that portion was welded and a stiffener plate was
2-9
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added. Availabilities during the suniner of 1977 and the modifica-
tions carried out for the wet-dry interface show this activity.
Quick clean basket strainers were added to the suction piping of the
two main recycle pumps of each vessel in place of the original
start-up strainers contained in a pipe spool. This has allowed de-
posits and foreign materials to be removed before they clog spray
nozzles and has also decreased maintenance and downtime on the
vessels.
A program is under way to evaluate abrasion resistant protective
lining materials that could be used where the flue gas makes its
180° turn following the venturi down-corner and passes by the ab-
sorption sprays. Impingement on the wall by the absorption spray
slurry erodes the glas flakelining and this lining has been re-
placed at least once in each module since unit start-up.
Similarly, a program for evaluating corrosion, temperature resistant
and abrasion resistant materials in other areas of the scrubber is
in progress. Small test patches and full scale application of
various linings are in place on several of the scrubber modules
and are subject to different environments.
Plugging of the wash tray underspray nozzles on scrubber modules
of both units occurred during May of 1977 and forced the plants to
shut down. The major cause of the problem was traced to piping
in the wash tray pond which had broken and allowed some of the pond
dike material to be ingested. A parallel pipeline and pumping
system was installed, the units brought on line and modification
and repair made to the original piping system.
The scrubber ponds are reclaimed by a dredge system which transfers
the scrubber sludge to a disposal pond approximately three miles
from the plant site. Liquid from the disposal pond is returned
to the scrubber ponds imediately behind the plant when the dredge
is not operating. The scrubber sludge deposits in deltas in the
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ponds and contain 55% — 60% solids. The material hardens very well
and the dredge has had some difficulty in reslurrying the sludge.
Residual alkalinity remains in the sludge deposited in these ponds
and this results in the sludge taking on a cement-like nature.
Improved cutters for the dredge and a delumper ahead of the dredge
pump are expected to increase the solids handling capacity. More
rapid filling of the wash tray pond with solids than had been ex-
pected has presented a problem in the method of removal of these
materials. Each of the plant ponds has its own chemical identity
due to water balance considerations. A dredge cannot be used pres-
ently to reclaim the wash tray pond volume without adversely affect-
ing either the plant operation or the pond water balance, so a less
efficient clamshell operation is now in use. Plans are being de-
veloped for the addition of another wash tray pond so that one may
be dewatered and then cleaned while the other is in operation.
2.3 Scrubber Test Data And Performance
A large number of emission tests have been conducted on the Coistrip
units over the 1 — 1/2 year period. EPA compliance tests for par-
ticulate, sulfur dioxide and N0 were completed during the spring
of 1977 on both plants. Also, emission monitor certification test-
ing has been conducted following the conclusion of the NSPS emission
tests. Table 2-2 shows the results of the tests. The NSPS require-
ments, the scrubber guarantee, the projected results from pilot
plant experience and the actual tests on Units fl and •2 are re-
ported. The results of the operation of the full scale units agree
well with the pilot plant data. The data also shows the plant
emissions are well below the guarantee and the NSPS standards. Al-
though scrubber inlet data has not been taken and efficiency per
se is not available, it appears sulfur dioxide and particulate re-
moval efficiencies predicted from the pilot plant data are being
achieved.
2—11
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Table 2-2. EMISSION TEST RESULTS
502 PartIculate ;NO
Lb/hr Lb/mBTU Lb/hr Lb/mBTU % Opac Lb/hr Lb/mBTIJ
Required by NSPS (358 MW) 4,063 510 1.2 339 .10 20 2,370 .7
Scrubber Guarantee (358 *1) 3,386 425 1.0 207 .06 — 2,370
Projected from Pilot Plant (358 MW)
a) 0.78% S (760 PPM), 8.19% Ash 1,394 185 .41 130 .038 20 2,370 .7
b) 1.0% S (965 PPM), 12.58% Ash 2.071 260 .61 184 .054 20 2,370 .7
Unit #1 Tests:
Coal As Received 4
Date Gr MW S Sul S Ash Btu/lb
2/76 353 .83 9.03 8,638 1,587 197 .48 95.8 .029 10 (3) 954 .29
4/76 210 .71 7.79 8,861 456 87 .23 60.9 .030 12 (3) 800 .41
7/76 184(6) .64 8.49 8,807 258 53 .15 57.1 .031 15 (2) 740 .42
9/76 186(6) .62 7.93 8,633 275 56 .15 64.4 .037 11 (2) 687 .39
12/76 223(6) 94 8.54 8,394 898 154 .43 67,2 .032 15 (2) 662 .31
1/77 354 .77 8.17 8,719 770 (5) 133 (5) 123.5 .037 13 (2) 1,459 .43
5/77 331 .61 8.41 8,851 552 72 .16 109.6 .032 14 (2) 1,029 .29
6/77 340 .91 8.96 8,888 1,164 122 .325 89.5 .039 18.4(2) 1,296 .36
Unit •2 Tests:
Coal As Received
Date Gr MW S Sul % Ash Btu/lb
10/76 331 .56 7.96 8,368 1,309 178 .42 88.6 .029 11 (2) 917 .30
11/76 327 .59 7.86 8,484 696 83 .23 91.4 .029 10 (2) 993 .32
12/76 324 .64 7.87 8,690 780 98 .25 105.7 .034 16 (2) 784 .25
3/77 335 .63 7.96 8,739 684 84 .20 91.9 .029 8 (2) 1,399 .38
6/77 305(8) .72 8.48 8,929 596.5 67 .189 104.2 .051 8.4(2) 1,261.4 .403
1. N0 emissions guaranteed by boiler supplier equal to NSPS.
2. Average EDC monitor opacity.
3. QualIfied observer, EPA Method 9.
4. Based on percent moisture of coal for periOd prior to test.
S. SO 2 test done at 230 MW (two scrubbers on line).
6. Two scrubber modules on line, all other tests done with three modules on line.
. so 21 tio tests 340 MW, particulate tests 260 MW.
8. 502. tests 305 MW, particulate tests 198.5 MW.
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Calculations of the scrubber inlet SO 2 rate were made using the
coal characteristics and plant load. From these inlet SO 2 rates
an estimate was made of the SO 2 collection efficiency during each
emission test. Table 2-3 sumarizes these calculations. Note
that it was assumed for calculation purposes that all of the sulfur
in the fuel reports to the flue gas. In fact, it has been reported
in the literature that from 5 to 20% of the sulfur in the Western
coals is contained in ash. Of the sulfur contained in the coal an
average of 83.5% was removed according to the 13 emission tests.
For Units #1 and #2 the first emission test indicates significantly
lower SO 2 control efficiencies than subsequent tests. If these
two tests are excluded the average SO 2 control efficiency is 85.6%.
All but the initial Unit #1 and #2 tests indicate SO 2 removal
efficiencies of greater than 80%.
2.4 Scrubber Costs
Actual construction costs for Colstrip Units #1 and #2 with some
portion estimated through June 1977 are listed in Table 2-4. The
emission control system alone costs $63.98 per net kW. When the
scrubber sludge disposal system is added, the cost rises to $83.74
per net kW. The bottom ash and other disposal ponds are not included
in these costs. Work is still proceeding on the Installation and
these costs will increase. These costs describe a combined par-
ticulate-sulfur dioxide removal system requiring minimal chemical
addition, installed as a new unit and ordered in 1972.
It was reported by MPC that the first cost (capital cost) of’the
scrubbers for the first two Colstrip units was approximately 30%
of the entire plant first cost.
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Table 2—3. COLSTRIP SO 2 CONTROL SYSTEM PERFORMANCE
Date MW %S Btu/lb Lb S0 2 /Hr* Lb S0 2 /Hr SO 2 Removal
Efficiency
Unit 1 In Out
2/76 353 0.83 8,638 6,416 1,587 75.3
4/76 210** 071 8,861 3,183 456 85.7
7/76 184** 0.64 8,807 2,529 258 89.8
9/76 186** 0.62 8,633 2,527 275 89.1
12/76 223** 0.94 8,394 4,724 898 81.0 84.7% Average
1/77 354 0.77 8,719 5,914 770 87.0
5/77 331 0.61 8,851 4,315 552 87.2
6/77 340 0.91 8,888 6,585 1,164 82.3
Unit 2
10/76 331 0.56 8,368 4,190 1,309 68.8
11/76 327 0.59 8,484 4,302 696 83.8
12/76 324 0.64 8,690 4,514 780 82.7 81.6% Average
3/77 335 0.63 8,739 4,568 664 85.5
6/77 305 0.72 8,929 4,6 2 596.5 87.2
(Average 83.5%)
* Calculated by PES assuming all fuel sulfur reports as SO 2 in the flue
gas to scrubbers.
** Two scrubber modules operating.
Coal datawere adjusted byMPC to “as received basis.”
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Table 2-4. FGD SYSTEM COSTS — TWO GENERATING UNITS
Dollars $/Net kW*
1. Scrubber subcontract and out of scope
additions by prime contractor (in-
cludes foundation, field wiring,
insulation, heat tracing, painting,
piping to ponds, piping between mod-
ules and field distributables in
addition to the scrubber modules,
ductwork, equipment supply and
erection) $33,677,261 $51.02
2. Owners’ cost including interest at
$2,792,000 4,374,000 6.62
3. Subtotal as of December 1976 38,051,261 57.65
4. Estimated cost for work in progress
(cost responsibility under dispute) 4,178,499 6.33
5. Fly ash ponds (temporary storage),
fly ash slurry transport system and
evaporation pond 12,722,131 19.29
6. Incremental costs (auxiliary boiler,
FD fans, start-up and auxiliary
transformer) 317,520 0.48
7. TOTAL $55,269,411 $83.74
*This cost does not include an additional claim submitted by the
subcontractor. It also does not include a value for reduced
plant capacity, although for many purposes, it should.
**Net rating 330 MW/unit; gross rating 358.4 MW/unit.
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3.0 PLANNED SCRUBBER SYSTEM FOR COLSTRIP UNITS #3 AND #4
Information and data regarding the planned scrubber system for Co1
strip Units #3 and #4 were obtained at meetings and during dis-
cussions with D. T. Berube and C. D. Grimm of Montana Power Company.
3.1 Scrubber Description
Montana Power Company has indicated that the scrubber system design
planned for Colstrip Units #3 and #4 will make use of identical
scrubber modules as are installed on the first two units. MPC feels
that Coistrip Units #1 and #2 have demonstrated successful develop-
ment of a scrubber system suited for the particular characteristics
of Coistrip coal, achieving low emissions, zero water discharge and
efficient use of resources such as chemicals, water, land and money.
No other power plant equipped with scrubbers is operating with per
unit emissions less than Coistrip in a closed loop node. The high
scrubber availability and SO 2 control efficiency described in
Section 2.3 are cited as factors in deciding to utilize a similar
scrubber design for Coistrip Units #3 and #4.
It is planned to install eight scrubber (seven plus one spare) mod-
ules on each of the new Coistrip units. The improvements and field
modifications developed during the first years of operating the
existing Coistrip Units #1 and #2 scrubbers are expected to be
incorporated into the planned scrubbers. Improved scrubber avail-
ability is anticipated due to these design changes, as well as the
use of a spare scrubber module per unit. For a description of the
scrubber module design and system improvements the reader should
review Sections 2.1 and 22.
3-1
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3.2 Emission Estimates
Estimates of the SO 2 emissions for worst case and an average or
typical case are presented in this section, assuming various SO 2
removal efficiencies. Throughout the calculations all of the sulfur
contained in the fuel is assumed to appear as SO 2 in the flue gas.
The SO 2 control efficiencies discussed are therefore system control
efficiencies rather than actual scrubber SO 2 removal efficiencies.
Coal is a heterogeneous material containing organic combustible
matter and mineral matter. Sulfur exists in coal in two principal
forms; organic and inorganic. Organic sulfur is chemically bound
to the coal and cannot be removed by physical or mechanical proc-
esses. On the other hand, inorganic sulfur (pyritic sulfur) is
not bound chemically and may be physically removed to varying de-
grees from the coal. The coal at Coistrip is pulverized and par-
tially dried before firing. A portion of the pyrites (and pyritic
sulfur) are removed from the coal during the coal preparation and
not combusted. Also a portion of the sulfur in combusted coal is
retained in the ash after combustion. From 5 to 40% of the sulfur
may be retained in the ash for Western coals. As a result of these
factors (the removal of a portion of the pyritic sulfur prior to
combustion and the retention of a portion of the combusted coal
sulfur in the ash) the sulfur dioxide load at the inlet of the
scrubbers is not twice (2 lb SO 2 / 1 lb S in coal) the sulfur
content of the “as received” coal. The percent or amount of pyritic
sulfur removed and sulfur retained in ash are not known for Coistrip.
For this reason an SO 2 removal or control efficiency for the system
has been used rather than a control efficiency for the scrubbers.
No adjustments were made to account for removal of pyritic sulfur
and sulfur retention in the ash. All calculations were performed
for and all results are reported for each individual unit. Since
Coistrip Units #3 and #4 are identical in size and design the
3-2
-------
total emission rate for the combined units would be twice the values
cited in the remainder of this chapter.
3.2.1 Worst Case Emission Rates
A sulfur content of 1.0% and heating value of 8,162 Btu/lb along
with a plant load of 100% (7,573 x io6 Btu/hr heat input) were as-
sumed as representative of worst case conditions. Worst case con-
ditions, by definition, mean the conditions resulting in the maxi-
mum SO 2 emission rate. These worst case conditions represent a rare
or unlikely short-term event. An uncontrolled SO 2 emission rate
(from each unit) of 18,557 lb/hr (222.7 TPD) was calculated. With
an SO 2 control efficiency of 73.7% (the removal efficiency projected
under worst coal conditions by MPC from the pilot plant data for
Colstrip Units #1 and #2) a per unit SO 2 emission rate of 4,880 lb/
hr or 58.6 TPD is predicted. Four other SO 2 control efficiencies
were used in the 502 emission rate projections.
A control efficiency of 80% was selected as representative of a
value achieved or surpassed in all but the first weeks of scrubber
operation on Units #1 and #2. The average 502 control efficiency,
measured to date for Units #1 and #2, of 83.5% (see Table 2-3) was
used to compute SO 2 emission rates. Control efficiencies of 85 and
90% were also used. The 90% value represents the approximate limit
of proven scrubber technology. The SO 2 emission rates calculated
for the worst case conditions assuming the various control efficien-
cies are presented in a variety of units in Table 3-1.
3.2.2 Typical Emission Rates
A sulfur content of 0.77% and a heating value of 8,500 Btu/lb with
a 70% plant load (5,301 x Btu/hr heat input) were selected as
representative of typical or average conditions. Typical or average
conditions, and the predicted SO 2 emission rates, are useful for
3-3
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long—term impact assessments. An uncontrolled SO 2 emission rate
(per unit) of 9,604 lb/hr (115.3 TPD) was computed. The SO 2 emission
rates resulting from application of the various levels of SO 2 control
are provided in Table 3-2.
- Table 3-1. WORST CASE EMISSION RATES
(1.0% S 8,162 Btu/lb 100% Plant Load)
SO 2 Control Efficiency
SO 2 Emission Rate
lb/hr
TPD
lb/10 6 Btu
g/sec
Uncontrolled
73.7%
80 %
83.5%
85 %
90 %
18,557
4,880
3,711
3,062
2,784
1,856
222.7
58.6
44.5
36.7
33.4
22.3
2.45
.64
.49
.40
.37
.25
2,343
615
468
386
351
234
Table 3-2. TYPICAL EMISSION RATES
(.77% S 8,500 Btu/lb 70% Plant Load)
SO 2 Control Efficiency
SO 2 Emission Rate
lb/hr
TPD
lb/l0 6 Btu
g/sec
Uncontrolled
73.7%
80 %
83.5%
85 %
90 %
9,604
2,526
1,921
1,585
1,441
960
115.3
30.3
23.1
19.0
17.3
11.5
1.81
.48
.36
.30
.27
.18
1,211
319
242
200
182
121
3-4
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3.3 Scrubber Costs
The cost data reported by MPC for the scrubber system installed on
Colstrip Units #1 and #2 were escalated and adjusted to reflect the
larger unit size and later installation date. Start-up dates in
1981 and 1982 were projected for Units #3 and #4, respectively. It
was assumed that the $83.74 per net kW value reported for Units #1
and #2 (see Section 2.4) was in terms of 1977 dollars. Assuming an
escalation rate of 7% per year over the 4 years, a cost of $109.77 per
net kW is estimated. The total cost of the scrubber system for
Units 113 and #4 is computed as $153,678,000.
In a memo to Walter C. Barber, Director of EPA ’s Office of Air Qual-
ity Planning and Standards dated June 10, 1977, MPG provided a cost
estimate for the scrubbers at Coistrip Units #3 and #4. Starting
with a $80/kW figure for Coistrip Units #1 and #2, and escalating
at 8% per year to 1981 (6 years) gives 80 x 1.59 or $127.2/kW. To
account for the additional redundancy (a spare scrubber) required
on Units #3 and #4 a factor of 8/7 was applied raising the scrubber
system cost to $145.4/kW. A total cost for the Units #3 and #4
scrubber system is therefore $203,560,000. MPG also performed an
Order of Magnitude gross cost estimate based on Colstrip Units #1
and 112 plant costs, with a percentage allocation for the scrubbers.
These computations project a total scrubber system cost of in the
range of $180 — $200 million. Stated another way, the scrubber
system cost for Units #3 and #4 is estimated to be about $128 to
$1 421kw.
3-5
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4.0 MODIFICATION OF PLANNED SCRUBBERS
Modifications or improvements in the planned Colstrip Units #3
and #4 scrubber system design with the objective of increasing
the SO 2 control efficiency might be possible, but several inter-
related factors must be considered. Field modifications, which
have lowered scrubber maintenance requirements and increased
scrubber reliability or availability, have been made on the
Coistrip Units #1 and #2 scrubbers. The objective of these
improvements has not been to increase SO 2 control efficiency,
per Se. Since no scrubber bypass capability was provided for
at Coistrip Units #1 and #2, the relation between increased scrub-
ber reliability and annual SO 2 emissions would be difficult to
quantify. When adequate scrubbing capacity is not available to
handle Unit #1 or #2 flue gases, the boiler(s) must be operated
at a reduced load(s) or shut-down. The planned scrubber system
for Coistrip Units #3 and #4 will utilize eight scrubbers per unit
(seven operating and a spare) to minimize the occurrence of
scrubber caused reductions in plant load.
A list of factors to be considered or evaluated before adopting
any design modification includes:
water usage and balance
waste disposal — quantity and characteristics
chemical consL nptiOn
reliability
energy requIrements
maintenance requirements
operating experience
The evaluation of the impacts on these factors of scrubber design
modifications to improve SO 2 removal could necessitate a pilot
program. In this section, potential scrubber modifications aimed
4-1
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at improved SO 2 control efficiency are identified. A comprehen-
sive evaluation of the impacts on the factors listed above could
not be performed within the scope of this study. Potential im-
pacts have been identified and are noted briefly.
4.1 Increased L/G Ratio or Additional Sprays
The redesign 0 f the scrubbers to operate at a higher L/G ratio or
with additional sprays is a potential method of improving SO 2
removal efficiency. The relationship between the L/G ratio and
SO 2 control efficiency( SO 2 ) is not known precisely, but generally,
as hG is increased SO 2 also increases. Several methods 0 f
increasing the L/G ratio are possible. Increasing the liquid pump-
ing rate and amount of spray per nozzle is one option. Increased
pumping costs (larger pumps and more energy consumption) as well
as more rapid nozzle wear and more frequent shut-down for nozzle
replacement would be expected. A second, and possible better
method of raising the L/G ratio,is to increase the number of
absorption sprays while maintaining the rate of spray from each
nozzle. The placement of the additional sprays within the scrub-
ber vessel could affect the SO 2 control efficiency and other
scrubber system parameters. The most significant increase in
SO 2 control efficiency might be achieved by incorporating an
additional absorption spray section operated on a separate water
loop. The operation of a separate water loop would be required
if a two-stage absorption system was needed. The scrubber
system design modifications to achieve a second SO 2 absorption
stage would be significant and worthy of pilot plant testing.
The incorporation of an increased L/G ratio or additional sprays
would affect the scrubber system design and operation. Extensive
scrubber vessel arrangement and size modifications, such as
4-2
-------
increasing the scrubber height and/or diameter to maintain sufficient
slurry recycle retention time. Larger pumps would be required with
an increased L/G ratio, and if a separate, additional spray section
were incorporated, additional pumps, nozzles and piping would be
required. The increased hG ratio would impact the water balance.
Water consumption would be higher and it is uncertain if a closed
loop water balance could be maintained. These modifications might
also adversely affect the scrubber system reliability. Maintenance
requirements would be increased due to the additional sprays and
pumps or nozzle wear. Energy consumption would increase due to
the higher liquid pumping requirements. As with all modifications
resulting in a higher SO 2 removal efficiency, the quantity of solid
wastes to be disposed of would increase. Handling and disposal of
greater quantities of scrubber sludge or wastes would add to the
capital and operating costs.
4.2 Increased Lime Addition
A design concept used in the Coistrip Units #1 and 2 scrubbers is
the utilization of the alkalinity of the fly-ash for SO 2 removal.
Lime is added to the existing scrubbers for pH control and not for
SO 2 absorption purposes. The use of additional lime as a method
of increasing the SO 2 removal efficiency could be considered an
alternative scrubbing technique rather than a modification to the
planned scrubber system. The amount and role played by the lime
in the scrubbers would determine whether increased lime addition
were a modification or an alternative SO 2 control method. For the
case where lime is added to enhance SO 2 absorption while relying
primarily on the fly-ash alkalinity, a discussion of the impacts
of increased lime addition on other scrubber system parameters is
appropriate in this section.
4-3
-------
The redesign to allow for the use of additional lime could result
in several adverse scrubber system impacts. The scrubber chemistry,
recognized as very complex, could be altered significantly and would
require pilot plant investigation. Changes in the scrubber chemistry
could affect the slurry recycle retention time. Scrubber vessel
size and arrangement modifications might be required to provide
adequate retention time. Scrubber scaling problems might become
a significant problem and result in higher maintenance requirements
and decreased scrubber availability. If hard deposits or scaling
resulted, difficult operating and maintenance problems would have
to be overcome. Metals in the captured fly-ash are thought to act
as a catalyst, aiding in the oxidation of SO 2 to SO 4 . Calcium sul-
fate (CaSO 4 ), a scrubber product, is more readily decanted and forms
a more stable disposal material. If increased lime addition altered
the scrubber chemistry and resulted in greater sulfite formation,
the system design would require several modifications. More diffi-
cult water separation and increased disposal problems would result.
The increased usage of lime would increase chemical consumption and
costs. Lime handling and storage facilities would have to be en-
larged and capital costs and operating expenses would rise. The
handling of larger quantities of lime would result in greater energy
consumption. Lime is obtained from limestone which must be mined
and processed.
The impact of increased lime addition on water usage and the water
balance is uncertain. The ability to maintain a closed loop water
balance would have to be tested.
The higher SO 2 collection efficiency combined with greater lime
usage would result in larger quantities of scrubber sludge for dis-
posal. As a result, waste handling and disposal requirements and
costs would increase. The dewatering and disposability of the
4-4
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scrubber waste might also be affected. A less stable scrubber waste
product would raise disposal costs and/or result in greater potential
envi ronmental impacts.
4.3 Pilot Plant Program
Any substantial change in the scrubber system design would require
a pilot plant program to verify process parameters, perform-
ance and to evaluate the impacts on all related factors. Reliabil-
ity and operating experience are considered essential by MPC before
committing to a modified scrubber system design. According to MPC,
nine months to two years would be required to verify and evaluate
scrubber design modifications. The cost of delaying Colstrip Units
#3 and #4 and the impact of delays on the needs of MPG customers
could be significant. Any scrubber system changes which sacrificed
the closed loop water balance or reliability; or caused increased
consumption of energy, chemicals, water or land for disposal, would
require comprehensive evaluation.
4-5
-------
5.0 ALTERNATIVE SO 2 CONTROL SYSTEMS
Several factors must be considered before selecting an SO 2 control
system. A scrubber system cannot be selected solely on the basis
of SO 2 removal efficiency. Likewise, the performance of a scrubbing
system cannot be summarized and reported entirely in terms of SO 2
removal efficiency. Governing air quality standards and emissIon
regulations generally establish the required level of SO 2 control
system operation. An emission limitation for a given power plant
is typically determined by air quality or dispersion modeling which
utilizes site specific meteorological, plant and emission data.
Once an emission limit is established based on the applicable emis-
sion regulations and air quality impact constraints, the optimum
SO 2 control system can be selected after consideration and evalua-
tion of the following factors:
governing water quality standards and effluent limitations
fuel characteristics and composition
water requirements — quality and quantity needed
chemical consumption and availability
particulate removal equipment requirements
quantity and characteristics of wastes to be disposed of
energy cons umpti on
maintenance requirements
auxiliary facilities required
reliability
operating experience
capital and operating costs
5-1
-------
The fuel characteristics and composition can be used to calculate
the overall SO 2 control efficiency required to achieve the required
emission limitation. ‘The availability of water plays an important
role in scrubber system design. Suitable space and waste disposal
facilities are also needed.
Favorable reliability and operating experience are demanded of all
comercial control systems. The best SO 2 control system must be
determined for each specific power plant in accordance with avail-
able conditions and resources. The constraints or factors listed
above can vary widely between plants, limiting the applicability
of an SO 2 control system. This chapter describes the Coistrip Units
#3 and #4 SO 2 control system requirements and discusses the avail-
ability of alternative SO 2 control systems. Information regarding
flue gas desulfurization (FGD) systems operating at other domestic
power plants and potentially usable at Colstrip are sumarized.
Well over 50 FGD processes have been invented; many have undergone
testing in laboratory or pilot plant operations. Relatively few
have been operated on full-scale utility boilers. A tremendous
volume of material has appeared in the literature regarding FGD
systems. This is a reflection of the large number of FGD processes
tested and the controversy between industry and the environmental
comunity. Only a cursory review of alternative FGD systems could
be performed within the scope of this study.
5.1 Coistrip SO 2 Control System Constraints
In addition to the SO 2 emission limitation required to meet the
Class I PSD increment, other important site specific parameters
must be incorporated into the design of the Colstrip SO 2 control
system. Due to the scarcity of water in the Colstrip area and
water pollution effluent limitations, a closed loop water balance
5-2
-------
with minimum water consumption is called for. The coal character-.
istics of low-sulfur content and high fly-ash alkalinity also in-
fluence the scrubber system design. The utilization of the fly-ash
alkalinity for SO 2 absorption, rather than a chemical brought from
offsite is desirable. The availability of solid waste disposal
sites and difficulties in obtaining a marketable byproduct from
low sulfur coal flue gases limit consideration to only nonregener-
able FGD processes. Since a readily disposable scrubber waste is
desired a process yielding an easily dewatered and stable waste
product is advantageous.
5.2 Operational FGD Systems
The review of alternative SO 2 control methods was limited to FGD
systems which have been installed and operated on domestic power
plants. The sumary of FGD system operating experience provided
in the Suninary Report - Flue Gas Desulfurization Systems - August -
September 1977 indicates that there are currently 29 operating FGD
systems in the United States. Of these 29 FGD systems, 12 are
operated on plants burning coal with a sulfur content of 1.0 per-
cent or less, similar to Coistrip. A sumary of these operational
low-sulfur coal FGD systems is presented in Table 5-1. The 12
systems can be classified into four FGD processes as follows:
Number
Number of years
of Capacity Exper-
FGD Process Units MW lence
Limestone scrubbing 5 1 ,910 81
Sodium carbonate scrubbing 3 375 96
Lime scrubbing 2 240 119
Alkaline fly-ash scrubbing 2 720 37
TOTAL 12 3,245 333
5-3
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Table 5-1. SUMMARY OF LOW SULFUR COAL OPERATIONAL FGD SYSTEMS AS OF SEPTEMBER 1977
AOL / Combustion
Alkaline Fly-Ash
AOL / Combustion
Alkaline Fly-Ash
AOL / Combustion
Sodium Carbonate
AOL / Combustion
Sodium Carbonate
AOL / Combustion
Sodium Carbonate
Equi pment
Scrubbing
Equipment
Scrubbing
Equipment
Scrubbing
Equipment
Scrubbing
Equipment
Scrubbing
7/77
47
58
61
9
23
14
41
41
14
18
5
2
Si ze
New
Of
Coal Char-
Start-
Utility Company Power Station
Or
Ret-
rofit
FGO
Unit
(MW)
Process
/ Vendor
acteristics
(Percent
Sulfur)
Up
(Month!
Year)
Exper-
ience
(Months)
Research Cottrell
Limestone Scrubbing
Combustion Engineering
Lime Scrubbing
Combustion Engineering
Lime Scrubbing
Combustion Engineering
Limestone Scrubbing
Arizona Public Service
Cholla No. 1
Kansas City Power And Light
Hawthorn No. 3
Kansas City Power And Light
Hawthorn No. 4
Kansas Power And Light
Lawrence No. 4
Montana Power Company
Coistrip No. 1
Montana Power Company
Colstrip No. 2
Nevada Power Company
Reid Gardner No. 1
Nevada Power Company
Reid Gardner No. 2
Nevada Power Company
Reid Gardner No. 3
Northern States Power Company
Sherburne County Station No. 1
Northern States Power Company
Sherburne County Station No. 2
South Carolina Public Service
Winyah No. 2
R
R
R
R
N
N
R
R
N
N
N
N
115
140
100
125
360
360
125
125
125
710
680
280
.44 - 1.
- 3.5 *
.5 - 3.5 *
.5
.8
.8
.5 — 1.
.5 - 1.
.5 - 1.
.8
.8
Associate
Associate
Associate
Associate
Associ ate
10/73
11/72
8/72
1/77
10/75
7/76
4/74
4/74
7/76
3/76
4/77
Combustion Engineering
Limestone Scrubbing
Combustion Engineering
Limestone Scrubbing
Babcock And Wilcox
Limestone Scrubbing
1
Note: * Two grades of coal are burned; a low sulfur coal with typical sulfur content of .5% and a high sulfur coal
with a typical sulfur content of 3.5%. The FGO system was converted to a tail-end wet lime scrubber system
in early 1977.
-------
The two alkaline fly-ash scrubbing systems are Coistrip Units #1
and #2 which were described in Section 2. The three other FGD proc-
esses operated at plants burning low-sulfur coalare described in
the following subsections.
5.2.1 Limestone Scrubbing Systems
Five limestone scrubbing systems are operating on power plants
burning low-sulfur coal. At the Cholla #1 unit (115 MW) operated
by Arizona Public Service a Research Cottrell limestone scrubbing
system has been operated since October 1973. The average coal
characteristics are 0.52% sulfur, 10,150 BTU/lb heat content and
13.5% ash. Two parallel trains (Modules A and B), each designed to
handle 50% of the boiler’s flue gas load, are designed to have a
combined 502 removal efficiency of 58.5%. Either one or both of
the scrubbers can be bypassed. The A-side consists of a variable
throat flooded disk scrubber followed by a packed tower. The A-side
SO 2 removal is reported to be about 90%. The B-side is similar in
design except that the tower is not packed and limestone slurry is
not circulated through it. The B-side has a low degree of SO 2 re-
inoval (25%). The open loop water system uses 1.04 GPM/MW. The un-
stabilized scrubber sludge is disposed of in unlined solar evapora-
tion ponds. No pond water is recycled to the FGD system. Corrosion,
erosion, scaling and plugging problems have been encountered with
the scrubber system. Scrubber availability has been about 90%. No
502 removal efficiency or emission rate data were available to
verify the design efficiency of 58.5%.
A new limestone Combustion Engineering scrubbing system has replaced
a previously operated limestone injection FGD System at the Kansas
Power and Light Lawrence #4 unit. The new FGD system which corn-
menced operations in January 1977 consists of a rod scrubber fol-
lowed by a spray tower for SO 2 absorption. The rod scrubber,
designed to remove particulates. is fed overflow from the spray
5-5
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tower recirculation tank and a significant portion of SO 2 is re-
moved also. The plant can burn either natural gas or coal. Con-
tinuous SO 2 monitors have recorded SO 2 removal efficiencies of
better than 85%. Limited scrubber operating experience is avail-
able as the plant has operated on coal only about 10 days to date.
Combustion Engineering also designed the limestone scrubbing sys-
tems operated on Northern States Power Company’s Sherburne County
Stations #1 and #2. Colstrip coal is burned in both units. Simul-
taneous particulate and SO 2 removal are achieved in the scrubber
system. At each unit 12 scrubbing modules, 11 of which are required
for full load capacity, are operated. The scrubbing system is
comprised of a first stage fixed-rod venturi scrubber for partic-
ulate removal and a marble bed absorber to complete particulate
removal and achieve the necessary SO 2 removal. The design SO 2
control efficiency is based upon the removal of 50% of the sulfur
in the fuel (maximum fuel sulfur content of 1.2%) or a 200 ppm
SO 2 emission concentration, whichever outlet value is greater.
The scrubbing systems at Sherburne County Stations #1 and #2 both
operate with an open loop water system with a water consumption
rate of 1.13 GPM/MW. Unstabilized sludge is disposed in lined
ponds. Water from the ponds is recycled back to the process.
Unit #1 (710 MW) has been in operation since March 1976 and Unit
#2 (680 MW) began operation in April 1977. The availability of
the scrubber systems have been about 90%.
The South Carolina Public Service Winyah No. 2 plant (280 MW)
recently began operation. A Babcock & Wilcox designed limestone
scrubbing system is installed. Medium sulfur Virginia coal with
a maximum 1.9% sulfur and a 11,200 BTU/lb heat content is burned.
An ESP to remove 99% of the inlet fly-ash is installed ahead of
the scrubber. The scrubber is designed to remove 69% of the SO 2
5-6
-------
from 50% of the flue gas. The remaining half of the boiler flue
gas is bypassed around the FGD system and recombined with the
scrubbed portion for reheat purposes. The FGD system consists of
one scrubber-absorber train, including a venturi scrubber and a
tray tower absorber. The overall SO 2 removal efficiency is 25%
(935 ppm inlet and 294 ppm outl et). The water system is open-
loop and the scrubbing wastes are discharged to an unlined pond.
No availability or operating experience data are provided yet.
5.2.2 Sodium Carbonate Scrubbing
Nevada Power operates the Reid Gardner Station consisting of three
(125 MW) units burning coal with from 0.5 to 1.0% sulfur and a heat
content of 12,450 BTU/lb. Units #1 and #2 were retrofitted with
sodium carbonate scrubber systems. Unit #3 is a new installation
also equipped with a sodium carbonate based FGD system. Combustion
Equipment Associates in association with A. D. Little designed and
installed the FGD systems. Each unit is equipped with a single
FGD module consisting of a twin variable-throat venturi scrubber,
followed by a single-stage wash tray. Bypassing of the module is
possible. Primary particulate removal is accomplished by mechanical
collectors (75% efficient) installed upstream of the scrubber. A
comon facility for sodium carbonate ore (trona) storage and proc-
essing serves all three FGD systems. A sulfur dioxide removal ef-
ficiency of 85% is reported. There are two sources of liquid ef-
fluent from the scrubbers; a slip stream discharged from the
recirculation tank and the underflow from the clarifier. The FGD
system operates on an open water loop with no liquid recycled to
the modules from the ponds. A water consumption rate of 1.52 GPM/
MW is reported. Unstabilized sludge is disposed in solar evaporation
ponds. Plugging problems in several areas of the scrubber systems
have been encountered. Scrubber reliability has been about 80%
5-7
-------
for Units #1 and #2 and 60% for Unit #3.
5.2.3 Lime Scrubbing
The only lime scrubbing FGD process operating on low sulfur coal
flue gases is installed at the Kansas City Power and Light Hawthorn
Units #3 and #4. Both units are designed to burn either (1) a low
sulfur Wyoming coal typically containing 0.5% sulfur and having a
heat content of 9,800 BTU/lb; or (2) a high sulfur Oklahoma coal
with 35% (average) sulfur and 11,500 BTU/lb heat content. The
original FGD system consisted of limestone injection and Combustion
Engineering designed scrubbers. Dry limestone was injected directly
into the furnace box and calcined to lime. The furnace calcined
lime and boiler flue gas were then discharged to a tail-end wet
scrubbing system consisting of two marble-bed absorbers where
particulates and SO 2 were removed. The spent lime and other scrub-
bing wastes were then discharged into a comon clarifier tank and
the underfiow was pumped, untreated and unstabilized, to an unlined
disposal pond. Boiler tube plugging problems attributed to the
limestone injection forced changes in the mode of operation. The
scrubbing system was modified in early 1977 and now operates as
a tail-end wet lime scrubbing system. Two marble-bed scrubbers
are installed on each boiler. The fresh water make-up requirement
is approximately 7.0 GPM/MW to maintain the open loop water balance.
The SO 2 removal efficiency is estimated at 50 to 60% for both
modules although no tests have been run.
5-8
-------
5.2.4 Summary of Performance
A summary is presented in Table 5—2 of important design and perform-
ance parameters for the FGD systems operated at power plants burning
low—sulfur coal. Only Coistrip Units #1 nd #2 currently operate on
a closed loop water balance. The scrubber availability and SO 2 re-
moval efficiency of the Colstrip FGD system are comparable or better
than the other low sulfur coal FGD systems. Comparing the Coistrip
Units l and .#2 performance data with other FGD systems reported in
the Sumary Report — Flue Gas Desulfurization Systems August—September,
1977 , it appears that lower SO 2 emissions, in terms of lb/l0 6 BTU or
ppm, are achieved at Coistrip than with other scrubber systems. Sul-
fur dioxide removal efficiencies of 90% or greater reported in the
Summary Report and elsewhere in the. literature are for plants burning
high. sulfur coal. The lb/10 6 BTU, ppm or TPD SO 2 emissions at these
plants would exceed the emission level achieved at Coistrip. It must
be pointed out that the FGD systems included in Table 5-2 were not
designed solely for maximum 502 removal efficiency; but, as in the
Coistrip design, site specific criteria or restraints were incorporated
into the individual system designs.
Water Avail-
SO 2 Removal Water Usage abil-
FGD System Efficiency Balance GPMJM ity
Limestone
Cholla #1 58.5% open 1 04 90%
loop
Lawrence #4 85% open
loop
Sherburne 50% open 1 13 90%
#1 and #2 (or 200 ppm) loop
69% from 1/2 of flue open
Winyah #2 gas (25% overall) loop
Lime
Hawthorn #3 & #4 50 to 60% open
loop
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Table 5-2. FGD SYSTEM PERFORMANCE SUMMARY (Continued)
Water Avail-
.)u2 emova Water Usage abil-
FGD System Efficiency Balance GPM/MW itY
Sodium Carbonate
Reid Gardner 85 open 60 to
111, 2, and 3 loop 1.52 80%
Alkaline Fly-ash
Colstrip 73.7% guarantee closed
#1 and #2 (83.5% actual) loop 90%
5.3 FGD System Economics
The costs of an SO 2 control system consist of the capital costs of
purchasing and installing the system and the annual costs of owner-
ship, operation and maintenance of the system. Capital costs can
be further categorized as direct and indirect costs. Direct costs
are defined as those for purchase of the items of equipment and the
labor and material required to install and interconnect the equip-
ment. Indirect costs are those not attributed to specific equipment
items such as freight, interest, taxes, spare parts, engineering,
overhead, shakedown, and contingencies. Annual costs are categorized
as operation and maintenance costs and fixed costs. Operation and
maintenance costs include those expenditures for raw materials,
utilities, direct labor, maintenance, and supervision. Fixed costs
include depreciation, taxes, insurance, and costs of borrowed
capital.
Scrubber system costs are generally reported in $/kW for capital
costs and mills/kWh for operating costs. Before attempting to com-
pare the costs from one plant or system to another one should de-
termine what has been included or excluded from the figures and the
base year for costs are reported. Appendix A of the Suninary Report
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Flue Gas Desulfurization Systems August-September 1977 contains
cost data for 47 FGD systems. Capital costs range from less than
$lO/kW to $189/kW. Operating costs range from about .25 mills/kWh
to over 17 mills/kWh.
Differences in the reported cost data caused by including or exclud-
ing the costs of particulate removal, sludge disposal, lime or lime-
stone preparation, indirect costs and other items make comparison
FGD system economics difficult and inconclusive without further
information. Insufficient data were available at this time to
compare the costs of the alternative SO 2 control systems for Coistrip.
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6.0 SUMMARY
A review of the design, performance and operating experience at
Coistrip Units #1 arid #2 and other FGD systems operating on domestic
power plants burning low-sulfur coal was performed. According to
the results of 13 emission tests at Coistrip Units #1 and #2 the
scrubbers have consistently reduced SO emissions to less than
0.5 ib/lO BTU. The average SO 2 emission rate is 0.274 ib/lO BTU
and the average SO 2 removal efficiency is 83.5%. A scrubber system
availability of approximately 90% has been maintained. This scrub-
ber performance, combined with other important system design
features (such as a closed loop water balance and use of alkaline
fly-ash rather than purchased lime or limestone for SO 2 absorption)
make the planned scrubber system design optimum for the Colstrip site.
The SO 2 emissions for Colstrip Units #3 and #4 were predicted as-
suming various levels of SO 2 removal. The expected performance of
the planned alkaline fly-ash scrubbing system for Units #3 and #4
was described. Available scrubber cost information and estimates
for Coistrip were reported. Potential modifications to improve
SO 2 removal capabilities were discussed. A sumary was presented
of FGD systems operating on domestic power plants burning low
sulfur coal.
6-1
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