U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-77-075
Office of Research and Development Laboratory . . mft
Research Triangle Park, North Carolina 27711 July 1977
FLUE GAS DESULFURIZATION
USING FLY ASH ALKALI
DERIVED FROM WESTERN COALS
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" seven series
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1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research'
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6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
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 systems. The goal of the Program
is to assure the rapid development of domestic energy supplies ..in an
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environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
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EPA-600/7-77-075
July 1977
FLUE GAS DESULFURIZATION
USING FLY ASH ALKALI
DERIVED FROM WESTERN COALS
by
H.M. Ness, E.A. Sondreal,
F.Y. Murad, and K.S. Vig
U.S. Energy Research and Development Administration
Box 8213 University Station
Grand Forks, North Dakota 58202
EPA Interagency Agreement IAG-D5-E681
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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FOREWORD
New coal burning electric generating stations are required to limit
their emissions of sulfur dioxide in order to protect public health. Many
Western U.S. coals, although low in sulfur, still require some measure of
sulfur dioxide control in order to comply with the New Source Performance
Standard of 1.2 Ib S02/MM Btu.
The mineral matter in lignite and Western subbituminous coals generally
contains a high proportion of alkaline constituents, which will react in a
wet scrubber to remove sulfur dioxide from the stack gas and produce a sul-
fate enriched ash sludge. This process, as described in the present report,
has advantages of lower cost and improved reliability compared with state-of-
the-art lime/limestone scrubbing. Ash-alkali scrubbing for sulfur dioxide
removal can be expected to be widely applied to future boilers burning
Western coals.
Gordon H. Gronhovd
Director, Grand Forks Energy
Research Center
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ABSTRACT
A test program investigating the use of Western coal fly ash for
scrubbing SC>2 from powerplant flue gas was conducted on a 130-scfm pilot
scrubber at the Grand Forks Energy Research Center, Grand Forks, North
Dakota, and on a 5000-acfm pilot scrubber at the Milton R. Young Generating
Station, Center, North Dakota.
Experiments conducted on the 130-scfm pilot scrubber were designed to
investigate the effects of increased sodium concentration on S02 removal and
rate of scale formation. Parameters investigated include liquid-to-gas
ratios (L/G), stoichiometric ratios (CaO/SO?), and sodium concentration.
Results indicate increased S02 removal and decreased rate of scale formation
as sodium concentration increases.
Experiments conducted on the 5000-acfm pilot scrubber generated design
and operating data for a full-scale 450 MW fly ash alkali scrubber to be
constructed at the Milton R. Young Station. Results indicate that sufficient
S02 can be removed to meet NSPS requirements using only fly ash alkali when
burning 0.75 pet sulfur lignite. An eight-week reliability test was also
performed. Test programs on fly ash alkali scrubbing of flue gas S02 using
a subbituminous-derived fly ash and other various lignite-derived fly ashes
were also performed.
A detailed analysis of capital investment and operating cost for a 100
MW, 500 MW, and a 1000 MW scrubber using the fly ash alkali process is
presented.
111
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CONVERSION TABLE
EPA policy is to express all measurements in Agency documents in
metric units. Implementing this practice results in difficulty in clarity,
therefore, conversion factors for non-metric units used in this document
are as follows:
British
1 acre
1 British thermal unit
per pound
1 foot
1 cubic foot per minute
1 inch
1 gallon
1 pound
1 mile
1 ton (short)
1 part per million
1 pound per square inch
1 cubic yard
1 grain per cubic foot
Metric
4047 square meters
2.235 Joules per gram
0.3048 meter
28.316 liters
2.54 centimeters
3.785 liters
0.454 kilogram
1.609 kilometers
0.9072 metric tons
1 milligram per liter
(equivalent)
0.0703 kilogram per square
centimeter
0.7641 cubic meter
2.29 gram per cubic meter
iv
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CONTENTS
Foreword ii
Abstract iii
Conversion table iv
Figures vi
Tables vii
Acknowledgment x
1. Conclusions 1
2. Introduction 3
3. Summary
GFERC Test Program 8
SBEC Test Program 13
Coyote Station Test Program 26
Minnesota Power and Light Company Test Program . . 34
Fixed Investment and Operating Cost Analysis ... 38
References 64
Appendix A 65
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FIGURES
Number Page
1 Sulfur dioxide removal efficiencies requred for stack
gas cleaning of Western coal 5
2 Effect of pH and reaction time on fly ash CaO availability. . 7
3 130-scfm pilot plant scrubber, Grand Forks Energy
Research Center 9
4 5000-acfm pilot plant scrubber, Square Butte Electric
Cooperative 15
5 Sulfur dioxide removals in SBEC pilot plant tests using fly
ash alkali 19
6 Sulfur dioxide removals in.SBEC reliability pilot plant
tests using fly ash alkali 23
VI
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TABLES
Number Page
1 Coal Sulfur Content Equal to Federal Emission Standard. ... 3
2 Selected Analyses of Ash in Western Coals 6
3 Sulfur Dioxide Removal Efficiencies and Fly Ash Alkali
Utilization as a Function of L/G. CaO/SC-2 = 1.2 10
4 Sulfur Dioxide Removal Efficiencies, Fly Ash Alkali Utili-
zation and Scaling Rate as a Function of CaO/S02
Stoichiometric Ratio, L/G = 45 11
5 Sulfur Dioxide Removal and Scaling Rate as a Function of
Sodium Concentration, CaO/S02 = 1.2, L/G = 45 12
6 Typical Solution Analysis at Sodium Levels of 0.17 pet,
0.66 pet, 4.0 pet, and 9.3 pet 12
7 Typical Analysis of Lignite Fly Ash Produced by Cyclone-
Fired Center Unit No. 1 at the Milton R. Young Station. . . 17
8 Summary of Averaged Results from the Design and
Operating Criteria Test Program 20
9 Summary Results of SBEC Reliability Test Program 22
10 Typical Analysis of Scrubber Solutions from the SBEC
Reliability Test Program 25
11 Typical Analysis of Beulah, North Dakota Low Sodium
Fly Ash 27
12 Summary of Results Using Low Sodium Fly Ash 28
13 Typical Solution Analysis Using Low Sodium Fly Ash 28
14 Typical Analysis of Beulah, North Dakota High Sodium
Fly Ash 29
15 Summary of Results Using High Sodium Fly Ash 29
16 Typical Solution Analysis Using High Sodium Fly Ash 30
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TABLES, continued
Number Page
17 Typical Analysis of Big Stone Fly Ash 30
18 Summary of Results Using Big Stone Fly Ash 31
19 Typical Solution Analysis Using Big Stone Fly Ash 32
20 Typical Analysis of Basin Fly Ash 32
21 Summary of Results Using Basin Fly Ash 33
22 Typical Solution Analysis Using Basin Fly Ash 33
23 Summary of Results at pH 4.5 34
24 Typical Analysis of MP&L Fly Ash from Colstrip, Montana,
Subbituminous Coal 35
25 Summary of Results from the MP&L Test Program 36
26 Typical Solution Analysis of MP&L Ash Test 37
27 500 MW Base Case Fly Ash Alkali Process -
-a Material Handling (Lime) 39
-b Material Handling (Fly Ash) 41
-c S02 Scrubbing 42
-d Solids Disposal 44
-e Reheat 45
-f Gas Handling 46
-g Structural 47
-h Instrumentation 48
-i Instrumentation 48
-j Utilities 49
-k Service Utilities 50
-1 Excavation & Foundation 51
28 Summary of Estimated Fixed Investment for a 100 MW Fly
Ash Alkali Process 53
29 Summary of Estimated Fixed Investment for a 500 MW Base
Case Fly Ash Alkali Process 55
30 Summary of Estimated Fixed Investment for a 1000 MW Fly
Ash Alkali Process 57
Vlll
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TABLES, continued
Number Page
31 Total Average Annual Operating Cost for a 100 MW Fly
Ash Alkali Process 59
32 Total Average Annual Operating Cost for a 500 MW Fly
Ash Alkali Process 60
33 Total Average Annual Operating Cost for a 1000 MW Fly
Ash Alkali Process 61
34 500 MW Base Case Fly Ash Alkali Process - Annual
Operating Costs 62
35 Comparison of Raw Material Operating Costs for Lime
Scrubbing Versus Fly Ash Alkali Scrubbing 63
36 Scrubber Unit Operating Costs for the Fly Ash Alkali Process . 63
Appendix:
A-l Summary of Results from the Design and Operating Test
Series Conducted at L/G 60 66
A-2 Summary of Results from the Design and Operating Test
Series Conducted at L/G 80 67
IX
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ACKNOWLEDGMENTS
This report, prepared by the Grand Forks Energy Research Center, pre-
sents the results of work conducted during fiscal year 1976 under funding
transferred from the EPA to ERDA and also under a cooperative contract
between ERDA, the Square Butte Electric Cooperative, Minnesota Power and
Light, and Combustion Equipment Associates.
The information presented in this report on the 5000-acfm scrubber was
derived from a test program conducted under the direction of a steering
committee comprised of the authors, Mr. Lloyd Hillier, and Mr. Ken Vig of
the Square Butte Electric Cooperative, Mr. Dennis Van Tassel of the
Minnesota Power and Light Company, and Dr. Fred Murad of Combustion Equip-
ment Associates.
The steering committee wishes to express its appreciation to Mr. Phil
Richmond of Square Butte Electric Cooperative, Mr. Cabot Thunem of the
Grand Forks Energy Research Center, ERDA, and Mr. D. Mehta of Combustion
Equipment Associates, for their supervision of the operation of the 5000-acfm
pilot scrubber. Appreciation is also extended to Mr. Larry Woodland of
Arthur D. Little, Inc., and Mr. D.A. Burbank of the Bechtel Corporation,
for their technical assistance, and to the York Research Corporation and the
Grand Forks Energy Research Center for the analytical work performed during
the test program.
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SECTION 1
CONCLUSIONS
Experiments at the Grand Forks Energy Research Center on a 130-scfml/
pilot scrubber investigating the effects of a scrubber solution containing
high concentrations of sodium and low levels of suspended solids have shown
that:
* The rate of scale formation decreased as the sodium level increased.
* Settling of the fly ash sludge degraded with increasing ionic
strength.
* An increase in the level of total dissolved solids did not have
a significant effect on sulfur dioxide removal under the condi-
tions investigated. Other tests conducted previous to and after
the tests currently reported have indicated a substantial
increase in sulfur dioxide removal with increased sodium con-
centration under suitable conditions
Experiments on the 5000-acfm pilot scrubber have been underway for one
year, and the initial objective of confirming design parameters for a 450
MW commercial unit to operate on cyclone-fired lignite fly ash have been
met. Variable studies are continuing under the Energy Research and Devel-
opment Administration. The conclusions reached thus far are as follows:
• Sufficient fly ash alkali can be reacted in a wet scrubber
to reduce sulfur dioxide in flue gas below the Federal
emission standard when burning lignite with an average
sulfur content of 0.75 pet in a cyclone-fired boiler.
* Up to 66 pet of the alkali used in a wet scrubber must be
added as supplemental lime to reduce sulfur dioxide in
flue gas below the Federal emission standard when
burning lignite with a worst case sulfur content of
1.3 pet in a cyclone-fired boiler.
* The utilization of the alkali in the fly ash is reduced
when supplementary lime is added.
]_/ Non-metric to metric conversion factors are shown on page iv.
2/ Underlined numbers in parentheses refer to items in the list of
references at the end of this report.
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• Calcium sulfite scaling could not be detected under normal
operating conditions.
• Calcium sulfate scaling could not be detected under normal
operating conditions.
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SECTION 2
INTRODUCTION
The Western reserve base for measured and indicated coal in place, as
defined by the U.S. Bureau of Mines, totals about 216 billion tons (2J.
During the last 15 years, the Western share of U.S. coal production has
risen from about 6 pet to about 18 pet. A national goal of one billion tons
of coal production has been set for 1985, and about 30 pet of it is expected
to come from the Western coal reserves. Part of this expanded coal produc-
tion is anticipated to be used in gasification and liquefaction plants; a
considerable portion would be used in the generation of electricity. Most
Western coals require some control of sulfur oxide emissions to meet the
NSPS, and stack gas cleaning technology for burning Western coals will
assume much greater importance in the future than in the past.
The Western coal reserves include lignite, subbituminous, and bituminous
coal, with the lower rank coals predominating. An important property of most
Western coals is that they contain far less sulfur than the 2 to 3 pet sulfur
content of a typical Eastern or Central coal. The sulfur content of Western
coals averages about 0.7 pet and an average sulfur dioxide removal of only 30
to 40 pet is required to meet the Federal standard of 1.2 Ib S02/MM Btu.
Since the Federal standard is based on heat release, variations in heating
value according to rank have an important effect on the coal sulfur content
that is equivalent to the Federal emission standard, as shown in Table 1.
TABLE 1. COAL SULFUR CONTENT EQUAL TO FEDERAL EMISSION STANDARD
Coal sulfur equal to
Higher heating value 1.2 Ib S02/MM Btu
Coal Btu/lb pet
North Dakota
lignite 6,800 0.41
Montana
subbituminous 8,600 0.52
Arizona
bituminous 11,000 0.66
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The required sulfur oxide removal efficiencies are determined by coal
sulfur content, and emission limits established by State and Federal legisla-
tion. Retention of sulfur oxides on ash during combustion may lower the
actual sulfur dioxide emission by 10 to 40 pet for lignites (.3), but because
of its variability, this effect does not guarantee compliance with the
Federal emission standard. The removal efficiencies as a function of sulfur
dioxide emission standards are illustrated in Figure 1. While the 0.7 pet
average sulfur content in Western coals does not meet the Federal standard,
it does make flue gas desulfurization potentially easier to achieve.
The ash content of Western coals can vary greatly, with the 4 to 20 pet
shown in Table 2 representative of the overall range. The ash content and
analysis can vary significantly between mines, and even between locations
within mines. The quantity of fly ash in the stack gas depends on boiler
design as well a? coal ash content. The fly ash in the flue gas from a
pulverized coal-.i^ed boiler represents approximately 80 pet of the coal ash.
Resulting particulate loadings are typically 2 to 10 gr/scfd. For a cyclone
coal-fired boiler, fly ash leaving the boiler represents about 40 pet of the
coal ash. The corresponding particulate loadings are typically 1 to 5
gr/scfd.
An important characteristic of most Western coal ashes is their high
content of calcium oxide, magnesium oxide, and sodium oxide, as shown in
Table 2. The alkali content tends to be highest in lignite, and progressively
less in subbituminous and bituminous coals. As with coal ash content, the
alkali content in Western coal ash varies widely, from under 10 pet to over
50 pet of the ash, with significant variations occurring within individual
mines.
The first studies on utilizing the alkali in Western fly ashes were
begun at the GFERC in 1970. The fly ash alkali, particularly the calcium
oxide, provides an alternate reagent to conventional lime/limestone flue gas
desulfurization. Laboratory tests at GFERC have shown that the calcium
available is a function of pH and reaction time (see Figure 2). The calcium
leached from the fly ash reacts to remove sulfur oxides in a scrubber system.
A guide in assessing the importance of the alkali in Western coal is the mole
ratio of fly ash alkali to coal sulfur. For a coal containing 7.5 pet ash,
and 20 pet calcium oxide (CaO) in the ash, the calcium is chemically equi-
valent to slightly more than 120 pet of a 0.7 pet sulfur content. For some
lignites, the total alkali-to-sulfur mole ratio may be several hundred per-
cent. Thus, in a powerplant burning Western coal, there is often ample fly
ash alkali to interact with sulfur oxides in a wet scrubber.
The present study reports on a continuing test program on fly ash alkali
utilization using an in-house 130-scfm pilot scrubber, and a 5000-acfm pilot
scrubber. Methods for the control of scaling are also discussed.
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100
*- 80
Subbitummous coal
8,600 btu/lb
500 mw
.4% sulfur in coal
.2 .4 .6 .8 1,0 1.2 1.4
S02 EMISSION STANDARD, Ib/mm btu
Figure 1. Sulfur dioxide removal efficiencies required for stack gas cleaning of Western coal.
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TABLE 2. SELECTED ANALYSES OF ASH IN WESTERN COALS (4)
Coal
State
Mine
Sample avg
Lignite Subbituminous
North Dakota Montana Wyoming New Mexico New Mexico
Big Horn Navajo McKin'^y
212 125 12 2 1
Ash, percent of coal
Bituminous
Arizona Colorado
Black Mesa Hawks Nest
1 3
Si 02-.
A1203.
Ti02.
P205-
CaO..
MgO..
K20.
S03.
6.2
,7
.1
,1
19.
11
9.
0.4
0.3
24.6
6.9
6.5
0.4
19.5
9.3
4.8 20,2
8.0
Oxide constituents, percent of ash
35.5
18.7
7.8
0.7
0.3
15.6
4.4
1.7
0.4
13.4
27.4
12.7
13.9
0.6
0.5
16.6
5.5
2.2
0.5
17.0
55.6
26.2
6.1
0.6
0.5
3.9
0.8
1.5
0.6
3.2
54.7
21.6
7.0
1.0
0.0
6.5
1.2
1.6
0.8
5.8
7.5
42.0
18.1
5.7
0.8
0.6
17.8
2.4
1.4
0.3
8.2
5.4
44.8
28.
11.
0.8
0.7
5.6
1.9
0.6
0.5
4.0
-------
90
0)
o
w.
0)
Q.
UJ
CD
i
o
o
O
Center, N,D,
Flyash
a
O
A
O
SOmin.
60min.
40min.
20mln.
PH
Figure 2. Effect of pH and reaction time on fly ash CaO availability.
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SECTION 3
SUMMARY
GFERC TEST PROGRAM
The Energy Research and Development Administration at their Grand Forks
Energy Research Center (GFERC) has investigated the fly ash alkali sulfur
dioxide scrubbir) system since 1970. Testing has been performed on a 130-
scfm pilot scrubber. The principal objectives have been to determine sulfur
dioxide removal efficiencies and calcium sulfate scaling rates as a function
of sulfur dioxide level, fly ash add rate, alkali in the fly ash, supple-
mentary lime requirements, level of recirculated suspended solids, liquid-to-
gas ratio, amount of makeup water and total dissolved solids. Past results
have been published in three previous papers (5^,_7_).
The present GFERC scrubber (Figure 3) is a 130-scfm flooded disk venturi
followed by an absorption tower containing conical "rain and drain" trays.
Pressure drop across the scrubber can be controlled by adjusting the height
of the flooded disk. The conical trays were installed as a modification to
increase the liquid-to-gas contact time. It was believed that this modifica-
tion would eliminate the gas-to-liquid transfer step as a controlling vari-
able at high removal levels so that the observed sulfur dioxide removal would
be primarily a function of the fly ash and solution characteristics and not
of scrubber design. Installation of the conical "rain and drain" trays
increased the removal efficiency by 5 pet, from 83.3 to 88.1 pet, under
identical operating conditions.
The GFERC scrubber system is "closed loop." The recirculated scrubber
liquor lost from the system as liquor in sludge, or as mist, is equivalent to
about 0.8 acre-ft/MW/yr. Efficient mist elimination has been accomplished by
passing gas through both a cyclone and a stainless steel wire mesh. Water
lost by evaporation from mix tanks was replaced. Liquor from the scrubber
was returned to a series of two fly ash mix tanks equipped with overflow
weirs. The overflow from the second mix tank flowed to a settling tank where
calcium sulfate precipitate and unreacted fly ash were allowed to settle. A
floating overflow weir in the settling tank provided the scrubbing liquid to
the flooded disk.
Early experiments at GFERC indicated that a large increase in total
dissolved solids, primarily sodium and magnesium sulfates, experienced
during the approach to steady state operating conditions significantly
increased the scrubbing efficiency. Since the fly ash derived from some
Western coals, particularly some lignites, are known to contain significant
amounts of soluble sodium and magnesium, it is probable that high concentra-
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SO2 injection
Gas furnace
Water cooled 7\ scrubber
heat exchanger V V
* \ x^^v^x
C
J
Rain and
drain tower
Scale test piece
Floating weir
X_L
Settling tank
Mist
eliminator
To stack
Drip leg
[^
L
>
•^
0
X C
:
-*
3
O /
1
c
\d
r
° J
V
D Fly ID fan
ash
Mix tanks
Figure 3. 130-scfm pilot plant scrubber, Grand Forks Energy Research Center.
-------
tions of these species will result after long-term operation of a full-scale
scrubber employing the fly ash alkali scrubbing process. The current experi-
ments at GFERC were designed to investigate the properties of scrubber
solutions that are high in sodium (0.5 to 10 pet) and magnesium (0.5 to 10
pet). The objectives of the tests were to determine sulfur dioxide removal
and scaling rate using a solution concentrated in sodium and magnesium and
low in suspended solids (high levels of suspended solids, 6 to 12 pet, are
common practice for scale control in some Western scrubbers). The fly ash
used in these tests contained high sodium and magnesium and was produced by
pc-firing of Beulah, North Dakota lignite. Scrubber operating conditions
kept constant for all test runs were: inlet sulfur dioxide level of about
840 ppm (typical of a Western lignite containing about 0.8 pet sulfur), inlet
flue gas temperature of 350° F, liquid temperature of about 120° F, absorber
tower pressure drop of about 13 inches of water.
Scaling rat.s reported represent the rate of weight increase in grams
per hour observed in a 3 ft 4-inch length of 1/2-inch I.D. pipe in the
return line from the scrubber to the mix tanks. The test position chosen was
a point of maximum scaling, and trends in the observed values were found to
be well correlated with operating variables.
Tests were performed at liquid-to-gas ratios of 23, 45, and 75 gal/1000
scf. The CaO/S02 stoichiometric ratio, based on inlet S02, was maintained at
1.2, sodium concentration at about 3.0 pet, and magnesium concentration at 1
to 2 pet. The pH of the liquor pumped to the absorber tower varied from 5.0
to 5.5; pH of the liquor exiting the absorber tower varied from 4.5 to 5.0.
Previous experiments indicated only a marginal effect when L/G was increased.
However, under the conditions of high sodium and magnesium, removal efficien-
cies were affected very significantly. The removal efficiencies and fly ash
alkali utilizations are tabulated in Table 3.
TABLE 3. SULFUR DIOXIDE REMOVAL EFFICIENCIES AND FLY ASH ALKALI
UTILIZATION AS A FUNCTION OF L/G. CaO/S02 = 1.2*
Alkali utilization
L/G Removal efficiency (pet) based on CaO (pet)
23
45
75
81.0
88.2
98.1
66
72
80
* Stoichiometric mole ratio based on inlet sulfur dioxide
level of 840 ppm.
The stoichiometric ratios of calcium oxide to sulfur dioxide investi-
gated were 0.6, 1.2 and 2.0. These ratios correspond to particulate loadings
of 2.0 gr/scf, 4.0 gr/scf and 6.7 gr/scf. Operating conditions were as
described above, with an L/G of 45. The sulfur dioxide removal efficiency,
fly ash alkali utilization, and scaling rate are tabulated in Table 4.
10
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TABLE 4. SULFUR DIOXIDE REMOVAL EFFICIENCIES, FLY ASH ALKALI
UTILIZATION AND SCALING RATE AS A FUNCTION OF
CaO/SO? STOICHIOMETRIC RATIO, L/G = 45
Particulate
loading
(gr/scf)
2.0
4.0
6.7
CaO/S02*
0.6
1.2
2.0
Removal
effici-
ency (pet)
63.3
88.2
98.0
Alkali utili-
zation based
on CaO (pet)
100.0
72.0
49.1
Scaling
rate
(gm/hr)
1.68
2.7
3.0
Suspended
solids
(pet)
0.13
0.18
0.24
Stoichiometric mole ratio based on inlet sulfur dioxide
concentration of 840 ppm.
In the above tests, some difficulty was experienced in removing the
suspended solids to produce a "clear" liquid, even with the addition of
sodium aluminate to the scrubber solution as a coagulant. The scaling rate
of 1.68 gm/hr was observed at a suspended solids concentration of 0.13 pet,
2.7 gm/hr at 0.18 pet, and 3.0 gm/hr at 0.24 pet. Previous experience has
shown that 10 gm/hr is a high scaling rate, and 0.2 gm/hr is a low scaling
rate.
After the foregoing tests, the absorber tower was again modified, this
time for the purpose of providing greater control of the pressure drop under
conditions of severe scaling. The change involved attaching one set of
cones, those directing flow from the center outward, to the standpipe of the
flooded disk (see Figure 3). Thereafter, movement of the standpipe varied
the spacing between the convex and concave conical trays as well as the
spacing of the flooded disk venturi. Thus, as scale buildup occurred on
opposed surfaces, all such surfaces could be moved further apart to maintain
a constant pressure drop. A further effect of the change was to distribute
the pressure drop more evenly throughout the scrubber tower. This last
effect was believed to be responsible for a further increase observed in
scrubber efficiency, from 88.2 to 92.9 pet, which probably occurred because
of a more efficient use of energy in redispersing droplets of scrubber
liquor throughout the tower. All of the removal data given below are offset
from former data due to this increased efficiency.
Scaling rates and removal efficiencies were next investigated as a
function of sodium concentration. The sodium levels investigated were 0.17
pet, 0.66 pet, 4 pet, and 9.3 pet. The 0.17 pet represents sodium leached
from the fly ash during a 3-day test period; no make-up sodium was added.
The magnesium concentration was kept constant at 1 to 2 pet, L/G was 45,
calcium oxide to sulfur dioxide Stoichiometric ratio was 1.2, and other
11
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operating conditions were as described previously. The results are tabulated
in Table 5. A typical solution analysis at each sodium level is listed in
Table 6.
TABLE 5. SULFUR DIOXIDE REMOVAL AND SCALING RATE AS A FUNCTION
OF SODIUM CONCENTRATION, CaO/SOe = 1.2,* L/G = 45
S02 Removal Scaling Suspended
Sodium concentration (pet) efficiency (pet) rate (gm/hr) solids (pet)
0.17
0.66
4.0
i,.3
95.2
92.9
93.0
96.0
5.8
3.51
2.7
0.0
0.066
0.074
0.17
0.83
* Stoichiometric mole ratio based on inlet sulfur dioxide
level of 840 ppm.
TABLE 6. TYPICAL SOLUTION ANALYSIS AT SODIUM LEVELS OF
0.17 PCT, 0.66 PCT, 4.0 PCT, AND 9.3 PCT
Species
Percent Sodium: 0.17
0.66
4.0
9.3
Ca (ppm)
Mg (pet)
S04 (pet)
702
1.30
7.06
631
1.33
7.56
643
1.3
15.0
762
1.7
26.0
The solids settling properties were observed to degrade as the ionic
strength of the scrubber solution increased. This phenomenon has been observed
previously in EPA laboratory testing on dilute double alkali systems, and by
Arthur D. Little, Inc. (8j in laboratory and pilot plant work on dilute and
concentrated double alkali systems. Factors reported to influence the
solids settling properties are reactor configuration, concentration of
soluble magnesium and iron, and the concentration of soluble sulfate. In
this investigation, the concentration of magnesium and iron were relatively
constant. However, the level of soluble sulfate varied along with sodium
level, due to the addition of sodium as sodium sulfate. The solids settling
characteristics degraded correspondingly.
It can be seen from Table 5 that the rate of scaling decreased as the
sodium concentration increased. The absence of scale formations at the 9.3
pet sodium level is thought to be a function of sodium and not due to the
higher (0.83 pet) level of suspended solids, since past work at similar
levels of suspended solids (low sodium) resulted in scaling rates of 1 to 2
gm/hr. The stack flue gas was also tested to determine if sulfate was being
lost in the mist. If sulfate was lost in the mist at a rate equal to or
12
-------
greater than that being absorbed into the scrubber solution (assuming con-
stant liquid volume in the system), scaling would not be expected to occur.
Extensive testing indicated this did not occur, and thus, the absence of
scaling is concluded to be a result of high sodium concentration.
It can also be seen from Table 5, that an increase in the level of total
dissolved solids did not have a significant effect on sulfur dioxide removal,
which contradicts previous results. The current result showing no effect on
removal was observed after the modification of the scrubber by installation
of "rain and drain" trays, which greatly increased gas-liquid contact in the
scrubber. The conclusion to be drawn is that a high ionic strength in terms
of sodium and magnesium sulfates increases removal for a scrubber configura-
tion providing minimum contact-residence time (the flooded disk venturi
alone), but that it does not increase removal for a scrubber providing a
maximum of contact-residence time (the venturi plus trays). The results
further indicate that the scrubber solution having low ionic strength
had a sufficient equilibrium capacity to absorb essentially all of the entering
sulfur dioxide (at 840 ppm and L/G = 45), but that this capacity was not
fully utilized without the increased residence-contact time. On the other
hand, the scrubber liquor having high ionic strength was indicated to be
capable of more rapid absorption of sulfur dioxide so that essentially all
entering sulfur dioxide could be removed with a short residence-contact time.
Thus, the final conclusion is that sulfur dioxide removal in ash alkali
scrubbing can be materially improved by either an increase in ionic strength
or an increase in residence-contact time, but that a substantial increase in
either can mask the effect of the other.
Oxidation of absorbed sulfur dioxide to sulfate was generally high for
all test conditions (98 to 99 pet sulfate). The percentage of sulfite was,
however, higher in the test run at 9.34 pet sodium (2 pet sulfite) than in
any other test.
SBEC TEST PROGRAM
The Square Butte Electric Cooperative (SBEC) is currently constructing a
450 MW cyclone-fired generating unit requiring particulate and sulfur dioxide
abatement controls. The 450 MW unit is referred to as Center unit No. 2 and
is being constructed adjacent to the 238 MW Center unit No. 1 at the Milton
R. Young Station. Particulate control will be provided by electrostatic
precipitators (ESPs) and sulfur dioxide control by wet scrubbers.
A testing program using a 5000-acfm (saturated) pilot plant was con-
ducted under a cooperative agreement between SBEC, Minnesota Power and Light
Company (MP&L), Combustion Equipment Associates (CEA), and GFERC. Partici-
pation by GFERC in the cooperative test program during Fiscal Year 1976 was
funded by EPA. The pilot scrubber was designed and constructed by Combustion
Equipment Associates. The objectives of the cooperative program are:
1. To determine whether sufficient alkali can be solubilized
from cyclone-fired fly ash to'reduce sulfur dioxide in flue
gas below the level of State and Federal emission standards.
13
-------
2. To determine the amount of additional alkali from lime which
may be required to supplement fly ash alkali to meet State
and Federal emission standards.
3. To determine the severity of calcium sulfite and calcium
sulfate scale formation under normal operating conditions
of the flue gas desulfurization pilot scrubber, and to
investigate chemical methods of minimizing the scale formation.
4. To establish that the pilot scrubber can be operated on a
closed-loop basis, and to determine the chemistry of the
closed-loop system.
5. To determine what effect fly ash-derived soluble salts in
the scrubber solution will have on the sulfur dioxide
removal efficiency.
6. To determine and evaluate waste disposal of sulfate/sulfite
sludge and fly ash-derived soluble salts in sludge.
7. To conduct corrosion tests to determine the effects of
scrubber liquor on materials of construction to be used
for full-scale flue gas desulfurization processes.
8. To determine the mass balance of all input and output
materials, including selected trace elements and leachate
from sludge.
9. To evaluate the capital and operating costs of fly ash alkali
flue gas desulfurization for 100 MW, 500 MW, and 1000 MW
steam generator plants based on the technical and operating
data obtained from the pilot scrubber.
10. To confirm design criteria and operating parameters for a
full-scale 450 MW scrubber employing the fly ash alkali
process.
At the conclusion of the EPA-sponsored research at GFERC, not all objectives
had been met, and the research was continued under funding from the Energy
Research and Development Administration (ERDA).
Additional phases of testing may be concerned with dilute sulfuric acid
scrubbing with fly ash neutralization, and with sodium-magnesium and calcium
double-alkali-type scrubbing with fly ash neutralization.
The 5000-acfm (saturated) pilot plant scrubber (about 1.4 MW equivalent)
employs spray nozzles to minimize the gas side pressure drop across the
absorption tower. The pilot plant (see Figure 4) has, essentially, two
liquid loops: the primary sulfur dioxide scrubber loop, and the mist eli-
minator and wash tray loop.
14
-------
LIME
TO STUB STACK
HOT GAS
BY-PASS
MAKE UP
WATER
GRAIN
SCREW FEEDER
WITH DUMP
BIN
FLY ASH
STORAGE
FLY ASH FEED
|—-l TANK
j .' (NOT USED)
SO2 FROM
INJECTION
SYSTEM
FLY ASH
PREP TANK
1 BOOSTER
J FAN
DAMPER
RETENTION
TANK
THICKENER
OVERFLOW
TANK
Figure 4. 5000-acfm pilot plant scrubber, Square Butte Electric Cooperative.
-------
The wash tray loop, designed to operate on clear liquor at an approxi-
mate pH of 2 to 4, consists of a wash tray above the absorber tower, a tray
recycle tank, clarifier and clarifier overflow tanks, and a demister. The
wash tray, which is constructed of 316L stainless steel, was designed to
remove entrained slurry which could otherwise foul the demister. Liquid from
the wash tray drained to an 8 x 8-foot flakeglass-lined recycle tank which
was then pumped back to the wash tray or to an 8 x 8-foot flakeglass-lined
clarifier. Overflow from the clarifier was used to wash the bottom of the
wash tray. Liquid from the clarifier not used for washing was drained by
gravity to a 6 x 6-foot flakeglass-lined overflow tank. Makeup water from
nearby Lake Nelson was added to the pilot scrubber at the clarifier overflow
tank at an average rate of 1.4 gpm (about 1.6 acre-ft/MW/yr) and the combined
liquid used to wash the polypropylene demister. Underflow from the clarifier
was pumped to a drum-type vacuum filter.
The scrubber loop operates on a slurry of alkaline ash in recycled
liquor at a pH of 2 to 7. It consists of a 45 foot high by 3 1/2- foot
diameter flakeglass-lined absorber tower which contains six 316L stainless
steel nozzles spraying scrubber liquid countercurrent to the gas flow. The
scrubber liquid drained from the absorber tower to a 12 x 8-foot flakeglass-
lined retention tank equipped with a 316L stainless steel agitator. The
retention tank liquid was pumped back to the spray nozzles, to the fly ash
prep tank to slurry fly ash, and to an 8 x 8-foot flakeglass-lined thickener
used to control the level of suspended solids. Reducing the liquid flow from
the retention tank to the thickener increased the level of suspended solids;
increasing the flow rate lowered the level of suspended solids. Overflow
from the thickener drained by gravity to a 5 x 5-foot flakeglass-lined over-
flow tank. Thickener underflow was pumped to the vacuum filter. The vacuum
filter was operated only when the concentration of suspended solids in the
thickener underflow had increased to approximately 55 to 60 pet; filtration
was stopped when the solids were reduced to about 20 pet. Liquid from the
thickener overflow tank was pumped to a 4 x 5-foot fly ash preparation tank
with the excess liquid returning to the retention tank. Occasionally,
retention tank liquor was used to slurry the fly ash. Fly ash was stored in
a 3 x 5-foot hopper and fed to the preparation tank using a screw feeder at
rates up to 8 Ib/min. Hydrated lime from a 3 x 2-foot storage hopper was fed
directly into the retention tank. The total amount of liquid in the entire
pilot plant scrubber was about 12,000 gallons. All pumps were rubber lined.
Liquid flows were measured by rotameter and magnetic flow meters; liquid and
gas temperatures were measured by dial thermometers; pressure drops were
measured by manometers and differential pressure cells.
The pilot plant scrubber was designed to have the necessary equipment
and controls to operate over a wide range of variables. The solution pH can
be varied from below pH 2 up to pH 9; the retention tank residence time can
be varied from 4 minutes to 16 minutes; the liquid-to-gas ratio can be
varied from 10 to 160; and a sulfur dioxide injection system can adjust the
scrubber inlet sulfur dioxide to any desired concentration. A duct equipped
with an orifice and damper was installed between the inlet and outlet of the
absorption tower and used to bypass part of the hot inlet flue gas to mix
with the cooler outlet flue gas leaving the absorption tower. The mixing
16
-------
of flue gases in this manner was tested as a method for reheating to a tem-
perature above the saturation point to eliminate the possibility of stack gas
rain.
A mobile trailer supplied by the Grand Forks Energy Research Center
provided the capability of continuously monitoring both the, inlet and outlet
flue gas for sulfur dioxide, nitrogen oxides, carbon dioxide and oxygen. In
addition to the gas monitoring equipment, the trailer contained a chemistry
laboratory to perform most analyses of coal and scrubber liquor on site.
The 5000-acfm (saturated) pilot plant scrubber, designed and constructed
by CEA-ADL, had the primary purpose of confirming design criteria and oper-
ating parameters for the full-scale scrubber. Information for design of the
450 MW commercial unit was generated in a two-month test program conducted by
CEA-ADL in cooperation with SBEC, MP&L and GFERC. An additional two-month
reliability test was also conducted.
Sulfur dioxide in the flue gas must be reduced to approximately 535 ppm
S02 (dry) to comply with the Federal emission standard of 1.2 Ib S02/MM Btu.
The sulfur dioxide removal efficiency was investigated as a function of L/G,
suspended solids, inlet sulfur dioxide concentration, and fly ash add rates.
The ESP inlet fly ash particulate loading at the inlet to the ESP on Center
unit No. 1 ranges from 0.71 to 1.53 gr/scf and averages 1.13 gr/scf. The two
ash add rates investigated were equivalent to the combined average amount
collected by the ESPs on Units 1 and 2, and the maximum amount collected on
Units 1 and 2. A typical analysis of the Center fly ash is shown in Table 7.
TABLE 7. TYPICAL ANALYSIS OF LIGNITE FLY ASH PRODUCED BY CYCLONE-
FIRED CENTER UNIT NO. 1 AT THE MILTON R. YOUNG STATION
Percent of ash,
as received
Loss on ignition at 800° C 2.2
Silica, Si02 29.8
Aluminum oxide, A^Os 12.7
Ferric oxide, Fe20s 10.6
Titanium oxide, Ti02 0.5
Phosphorous pentoxide, P205 0.3
Calcium oxide, CaO 25.7
Magnesium oxide, MgO 4.5
Sodium oxide, Na20 2.2
Potassium oxide, K20 2.0
Sulfur trioxide, SOs 6.4
TOTAL 96.9
17
-------
Figure 5 illustrates the sulfur dioxide removal efficiency at the above
fly ash add rates at L/G ratios of 60 and 80. The solid line corresponds to
the average fly ash production collected by both units, hereafter referred to
as the average ash add rate. The dashed line corresponds to the maximum fly
ash production by both units, hereafter referred to as the maximum ash add
rate. A sulfur dioxide level of about 1100 ppm (dry) would be equivalent to
about a 0.75 pet sulfur coal (HHV6604 Btu/lb, as received). A level of 1850
ppm (dry) is equivalent to about 1.3 pet sulfur in coal. The outlet sulfur
dioxide represents the removal for the total scrubber system, which includes
the flue gas by-passed and used for reheat. The total flue gas into the
system was 7400 acfm, of which 1100 acfm was by-passed. The inlet gas tem-
perature was about 325° F. The temperature of the saturated gas (5000 acfm)
out of the absorber tower was about 135° F. After mixing the by-pass gas,
the temperature of the gas to the stack was about 155° F. The flue gas
reheat was tested as an alternative to coil reheaters. No stack gas mist was
observed to occur. The averaged results from the design and operating cri-
teria test program are summarized in Table 8. Results of each test series
are illustrated in Figure 5 and are tabulated in Appendix A.
At a L/G of 60 and an averaged inlet level of about 1053 ppm S02 (dry)
using fly ash at the average add rate, the sulfur dioxide removal efficiency
for the total scrubber system was about 61.3 pet (absorber tower removal
efficiency was about 72.1 pet). The fly ash alkali utilization, based on
inlet sulfur dioxide and 25 pet CaO in the fly ash, was about 108 pet. At
the maximum ash add rate and an averaged inlet level of 987 ppm SO? (dry),
the sulfur dioxide removal was about 69.3 pet (absorber tower removal effi-
ciency was about 81.5 pet). The fly ash CaO utilization was 72 pet. Supple-
mental hydrated lime was not added and the pH of the recycle slurry was about
3.9 at the average ash add rate and 5.3 at the maximum ash add rate.
At a L/G of 60 and an averaged inlet level of about 1874 ppm S02
(dry), using the average fly ash add rate with lime supplement, the total
scrubber system removal efficiency was about 69.2 pet (absorber tower removal
efficiency was about 81.4 pet). Supplemental hydrated lime was added to
maintain the pH at 6.6 to 6.8, and represented about 63.1 pet of the total
CaO; the total alkali (fly ash alkali and hydrated lime supplement) was
equivalent to about 100 pet of the inlet sulfur dioxide. At the maximum ash
add rate with hydrated lime supplement, the sulfur dioxide removal remained
at about 71 pet (absorber tower removal efficiency was about 83.5 pet).
Supplemental hydrated lime was added to maintain the pH at 6.6 to 6.8 and
represents 48.1 pet of the total CaO; total CaO (fly ash alkali and hydrated
lime supplement) was equivalent to about 120 pet of the inlet sulfur dioxide.
In a separate test using only hydrated lime chemically equivalent to that of
the total alkali, the removal efficiency increased to about 79 pet.
At a L/G of 80 and an averaged inlet level of about 1077 ppm S02 (dry)
using fly ash at the average add rate, the sulfur dioxide removal efficiency
for the total scrubber system was about 71 pet (absorber tower removal effi-
ciency was 83.5 pet). The fly ash CaO utilization was about 110 pet. The pH
of the recycle slurry was about 3.8. No supplemental hydrated lime was used.
At the maximum ash add rate and at an averaged inlet of 1100 ppm SO? (dry),
18
-------
800
O.
o.
CM
I-
UJ
-J
h-
O
600
400
200
1.2 Ib S02/mmbtu
L/6 = 80
800 1,000 1,200 1,400 1,600 1,800 2,OOO
INLET S02, ppm (dry)
800
600
O
cn
UJ
o
400
2OO
1.2 Ib S02/mmbtu
L/G = 6O
I
I
1
800 1,000 1,200 1,400 I,60O I,80O 2,OOO
INLET S02 , ppm (dry)
Figure 5. Sulfur dioxide removals in SBEC pilot plant tests using fly
ash alkali. Solid line represents average fly ash (1.13 gr/scf)
collected by ESPs; dashed line represents maximum fly ash
(1. 53 gr/scf) collected by ESPs.
19
-------
TABLE 8. SUMMARY OF AVERAGED RESULTS FROM THE DESIGN
AND OPERATING CRITERIA TEST PROGRAM*
ro
o
L/Gt
60
60
60
60
80
80
80
80
Add rate
Fly ash
16.2
25.3
15.8
26.3
16.5
26.0
16.2
24.9
(ton/hr)#
Lime
-0-
-0-
7.5
6.8
-0-
3.2
8.3
8.0
Total
CaO
S02§
0.67
1.13
1.0
1.2
0.67
1.49
1.07
1.26
Lime-
CaO
pet
-0-
-0-
63.1
48.1
-0-
30.6
64.5
53.6
S02-In
ppm-dry
1053
987
1874
1861
1077
1100
1900
1870
S02-0ut
ppm-dry
407
303
577
539
311
200
440
368
Pet removal
System
61.3
69.3
69.2
71.0
71.0
81.8
76.9
80.4
Tower
72.1
81.5
81.4
83.5
83.5
96.2
90.5
94.5
Fly ash,
pet CaO
utilization
108
72
49
42
110
49
57.3
42.6
Recycle
slurry
pH
3.9
5.3
6.6
6.8
3.8
6.3
6.7
6.8
* See Appendix A for individual test results.
t L/G based on gallons of recycle slurry per 100 acf of saturated flue gas; 15 pet
inlet flue gas bypassed for reheat.
# Average ash add rate equivalent to 16 to 17 ton/hr available for use in full-scale system.
Maximum ash add rate equivalent to 24 to 25 ton/hr available for use in full-scale system.
§ Stoichiometric mole ratio based on inlet sulfur dioxide; CaO content was averaged
over test period.
-------
using hydrated supplemental lime, the total scrubber system sulfur dioxide
removal was about 81.8 pet (absorber tower removal efficiency was about 96.2
pet). The supplemental hydrated lime was added to maintain the pH at 6.0 to
6.5, and represented 30.6 pet of the total CaO; the total CaO (fly ash alkali
and supplemental hydrated lime) was equivalent to about 149 pet of the inlet
sulfur dioxide.
At a L/G of 80 and an averaged inlet level of about 1900 ppm S02
(dry), the removal efficiency for the total scrubber system was about 76.9
pet at the average ash add rate (absorber tower removal efficiency was about
96.2 pet). Supplemental hydrated lime was added to maintain the pH at 6.5 to
6.8, and represents about 64.5 pet of the total CaO; the total CaO (fly ash
alkali and supplemental hydrated lime) was equivalent to 107 pet of the inlet
sulfur dioxide. At the maximum add rate and an averaged inlet level of 1870
ppm S02 (dry), the removal efficiency for the total scrubber system was about
80.4 pet (absorber tower removal efficiency was about 94.5 pet). Supple-
mental hydrated lime was added to maintain the pH at 6.5 to 6.7, and repre-
sented 53.6 pet of the total CaO; the total CaO was equivalent to about 126
pet of the inlet sulfur dioxide. A test using only hydrated lime chemically
equivalent to about 134 pet of the inlet sulfur dioxide resulted in a scrub-
ber system removal of about 85 pet (absorber tower removal efficiency about
99 pet).
The pilot test results demonstrate that the scrubber design to be used
on the full-scale unit is capable of meeting and exceeding removals required
to comply with the 1.2 S02 Ib/MM Btu Federal emission standard, and further,
that required removals under normal conditions of coal sulfur content can be
achieved using fly ash alone without lime. The higher sulfur dioxide re-
movals demonstrated in pilot plant tests were obtained by adding hydrated
lime at rates higher than intended for the 450 MW scrubber unit, and these
high rates may not be reproduced in practice on the commercial scale scrub-
bers.
At the conclusion of the eight-week test program, the scrubber system
was inspected for scale, and it was reported to have a light scale, with most
deposits at wet-dry interfaces. However, to further investigate scaling and
reliability problems associated with fly ash alkali scrubbing, an additional
eight weeks of operation using the projected full-scale scrubber operating
parameters was initiated.
SBEC Reliability Test Program
The reliability test program was divided into two 4-week studies. The
first 4-week study investigated the worst case coal sulfur content of 1.3 pet
(about 1850 ppm-dry S02', the second 4-week study investigated the average
coal sulfur content of 0.75 pet (about 1000 ppm-dry S02). The pilot plant
operating parameters were: L/G of 80, pH of 6.5 to 6.8 at 1.3 pet coal
sulfur content, pH of about 4 at 0.75 coal sulfur content, 15 pet of the
inlet flue gas was by-passed and used for reheat. The averaged results are
shown in Table 9 and Figure 6.
21
-------
TABLE 9. SUMMARY RESULTS OF SBEC RELIABILITY TEST PROGRAM
ro
Test
No.
1
2
3
4
5
6
7
8
9
10
11
12
Add rate,
By-pass, (ton/hr)t
L/G*
80
80
80
80
80
80
80
80
80
80
80
80
pet
15
15
15
15
15
15
15
15
25
25
15
15
Fly ash
16.4
16.3
25.0
24.9
25.0
24.6
17.3
16.9
17.1
16.5
16.9
31.5
Lime
9.8
9.1
8.3
8.3
1.85
-0-
-0-
-0-
-0-
-0-
-0-
-0-
Total
CaO#
S02
1.0
0.91
1.06
1.0
1.2
1.12
0.74
0.71
0.68
0.63
0.66
1.26
Lime-
CaO
66.0
64.0
50.6
51.0
22.1
-0-
-0-
-0-
-0-
-0-
-0-
-0-
S02-In
ppm-dry
1837
1872
1834
1888
878
838
847
914
857
1084
999
915
S02-0ut
ppm-dry
411
366
368
303
174
193
251
275
353
426
397
230
Pet removal
System
77.6
80.4
79.9
84.0
80.2
77.0
70.4
69.9
58.2
60.7
60.3
74.9
Tower
91.3
94.6
94.0
98.8
94.4
90.6
82.8
82.2
68.5
70.9
70.9
88.1
Fly ash,
pet CaO
utilization
39.8
59.8
53.2
66.5
47.0
78.8
100.7
113.0
89.3
121.0
107.0
65.8
Recycle
slurry
PH
6.6
6.6
6.7
6.6
6.6
4.3
4.3
3.9
3.6
3.7
4.0
5.1
* L/G based on gallons of recycled slurry per 1000 acf of saturated flue gas.
t Average ash add rate equivalent to 16 to 17 tons/hr available for use in 450 MW full-scale system.
Maximum ash add rate equivalent to 24 to 25 tons/hr available for use in 450 MW full-scale system.
# Stoichiometric mole ratio based on inlet sulfur dioxide; fly ash CaO was averaged over test period.
-------
600
500
PO
CO
Q.
a
•»
csi
O
I-
UJ
I-
o
400
300
200
IOO
1.2 Ib S02/mmbtu
D
AVERAGE
ASH ADD RATE
- (-
'(-0-)
A(50
MAXIMUM
ASH ADD RATE
By-pof8
-25% By-pass
L/G=80
I
800
I,OOO 1,200 I,40O l,60O I,8OO 2,OOO
INLET S02> ppm (dry)
Figure 6. SO2 removals in SBEC reliability pilot plant tests using fly ash alkali. Solid line repre-
sents fly ash (1/13 gr/scf) collected by ESPs. Dashed line represents maximum fly ash (1. 53
gr/scf) collected by ESPs. Numbers in parentheses denote stoichiometric % of supplemental
hydrated lime. Squares denote results obtained using 25% flue gas by-pass.
-------
Figure 6 illustrates the sulfur dioxide removal efficiencies obtained
during the reliability test program. The dashed line corresponds to the
maximum fly ash production by the electrostatic precipitators on both units,
and is referred to as the maximum ash add rate. The solid line corresponds
to the average fly ash production by the electrostatic precipitators on both
units, and is referred to as the average ash add rate. The outlet sulfur
dioxide represents the removal for the total scrubber system, which includes
the flue gas by-passed and used for reheat.
At the worst case condition of 1.3 pet coal sulfur (about 1850 ppm-dry
S02), both ash add rates were investigated. In two 1-week tests at the
maximum ash add rate, the sulfur dioxide removal efficiency for the total
scrubber system was 79.9 pet and 84.0 pet (absorber tower was 94.0 and 98.8
pet, respectively). Supplemental hydrated lime was used to maintain the pH
at 6.5 to 6.8, and represents about 50 pet of the total alkali (actual
percentages are illustrated by paranthesis in Figure 6). The fly ash CaO
contributed about 50 pet of the total alkali and the utilization varied from
about 51 pet to about 61 pet. At the average fly ash add rate, the sulfur
dioxide removal efficiency for the total scrubber system was about 77.6 pet
(absorber tower was about 91.3 pet). Supplemental hydrated lime was added to
maintain the pH at 6.5 to 6.8, and represents about 66 pet of the total
alkali. The fly ash alkali contributed about 34 pet of the total alkali and
the utilization varied from 39.8 pet to 59.8 pet.
At the average coal sulfur content of 0.75 pet (about 1000 ppm-dry S02),
both ash add rates were investigated. At the maximum ash add rate, without
supplemental lime, the sulfur dioxide removal for the scrubber system was
77.0 pet (absorber tower was 90.6 pet); the corresponding ash CaO utilization
was 78.8 pet. Using 22.1 pet supplemental hydrated lime, the sulfur dioxide
removal was 80.2 pet (absorber tower was 94.4 pet); the corresponding fly ash
CaO utilization was 58.5 pet. In two 1-week tests at the average ash add
rate, without supplemental hydrated lime, the average sulfur dioxide removal
efficiency for the scrubber system was 70.4 pet and 69.9 pet (absorber tower
was 82.8 and 82.2 pet); the corresponding fly ash CaO utilization was 100 pet
and 113 pet, respectively.
Two additional tests not related to the full-scale operating parameters
were conducted during the reliability test program. The first test (Table 8,
test 10) was conducted using 25 pet flue gas bypass for reheat at the average
coal sulfur content of 0.75 pet, using the average fly ash add rate. The
results are denoted by squares in Figure 6, and it can be seen that the
sulfur dioxide emissions are below the Federal standard.
The second test (Table 8, test 11) was conducted using a L/G of 60 at
the average coal sulfur content of 0.75 pet (about 1000 ppm-dry), and the
average fly ash add rate. The results indicate, as shown previously in
Figure 5, that the Federal standard can be met. The implication of this
result is that the full-scale scrubber could operate at a lower L/G during
periods of average coal sulfur content. This could be accomplished by stop-
ping flow to a bank(s) of spray nozzles, thus reducing pump requirements. As
a consequence, power consumption would be reduced.
24
-------
Typical analyses of the absorber tower feed liquor and of the wash tray
feed liquor are shown in Table 10. These analyses are the averaged concen-
trations of test series 6 through 12, and are representative of a typical
analysis.
TABLE 10. TYPICAL ANALYSES OF SCRUBBER SOLUTIONS FROM
THE SBEC RELIABILITY TEST PROGRAM
Absorber Tower Feed Wash Tray Feed
Calcium*
Magnesium
Sodium
Potassium
Chloride
Sulfite
Sulfate
Total solids, pet
Suspended solids, pet
pH
490
6555
2390
1267
110
<0.8
37420
14.2
9.7
4.82
460
1119
1093
339
30
<0.8
10136
2.1
1.3
3.6
* Concentration units are ppm unless otherwise noted.
The state of oxidation was high, usually greater than 98 pet oxidation
of sulfite to sulfate; no apparent off-gassing of sulfur dioxide occurred
at any pH value.
The pilot scrubber was inspected for corrosion, erosion, and scale
deposits on a weekly basis. Detailed visual inspections were performed at
the absorber tower flue gas inlet and interior walls, wash tray, mist elimi-
nator, stainless steel test pieces inserted into the absorber tower. The
principal operational difficulties are summarized in the following sections.
Absorber Tower—The absorber tower wall is lined with flakeglass-
reinforced polyester to protect the mild steel from corrosion due to the
acidic scrubbing liquors. After about four months of operation, the lining
was eroded in the area where slurry from the spray nozzle impacts the wall.
The lining opposite the flue gas inlet was also eroded, which is believed to
be a problem characteristic to pilot plant scrubbers due to the relatively
small diameter of the absorber tower. In some unwashed areas of the absorber
tower, scale deposits accumulated. The accumulations occur primarily during
periods of high pH (about 6.5) operation. When test conditions resulted in a
low pH, the scale deposits appeared to dissolve and eventually disappeared.
Hash Tray--Some solid deposits were observed on both the top and the
bottom of the wash tray when the solution pH was maintained at about 6.5. At
the conclusion of the test period requiring the high pH, the wash tray
required manual cleaning.
25
-------
During the test period in which the solution pH was low (below 4.8), no
accumulation of solids was detected. Control of the deposits appeared pos-
sible by operating at a constant low pH range (below 4.8) that still removed
sufficient sulfur dioxide to meet the Federal emission standard.
Spray Nozz1es--The spray nozzles used in the testing program were con-
structed of 316L stainless steel. The nozzles had an average life of about
two months due to erosion by a scrubber solution containing about 12 pet sus-
pended solids. In comparison, a set of carbon steel spray nozzles lasted
only ten days.
Vacuum Filter—Above pH 4, the sludge had excellent filtering character-
istics. In general, the sludge had a solids content of over 50 pet. How-
ever, as the scrubber solution pH dropped below 4, the sludge became diffi-
cult to filter and the pores of the 260-mesh filter cloth plugged. The
solids content o. the sludge remained high, generally greater than 50 pet;
however, the physical appearance of the sludge indicated that the average
particle size had decreased. The decreased particle size would be consistent
with a greater proportion of the fly ash dissolving and reacting at low pH
levels. The filter cloth pore pluggage was resolved by the installation of a
high pressure air manifold following the wash water header.
Wet-Dry Zones—An accumulation of solids occured at the flue gas inlet
to the absorber tower. The build-up of solids was due to the dehydration of
slurry which contained about 12 pet suspended solids. The problem was
resolved by the installation of high pressure sprays inside the flue gas
duct. At 8-hour intervals, the sprays were turned on for three minutes to
dislodge the dehydration deposits.
Two other operational problems were occasional plugging of pipes and
erosion of plastic valves and plastic pipes at contractions and bends. The
erosion was due to the high level of suspended solids circulating in the
system.
COYOTE STATION TEST PROGRAM
The Otter Tail Power Company, in association with Minnkota Power Cooper-
ative, Minnesota Power and Light Company, Montana-Dakota Utilities, and
Northwestern Public Service Company, are planning to construct a nominal 400
MW cyclone-fired boiler (called the Coyote Station) which will burn Beulah,
North Dakota, lignite. The Coyote Station is required to meet the NSPS of
1.2 Ib SO^/MM Btu, and a short test program investigating scrubbing with
four lignite fly ashes was conducted on the SBEC 5000-acfm pilot plant.
Detailed planning of the test program was performed by Bechtel Power Corpor-
ation, consulting engineers to Otter Tail Power, and was approved by the
pilot scrubber steering committee in accordance with the ERDA cooperative
agreement.
The purpose of the test program was to compare the alkali utilization of
four fly ashes and the corresponding sulfur dioxide removal at a specified pH
and L/G in an attempt to predict the behavior of the proposed Coyote fly ash.
Two fly ashes tested were a high sodium and low sodium fly ash from the
26
-------
Beulah, North Dakota mine, and were collected from an electrostatic precipi-
tator at Otter Tail Power's pc-fired Hoot Lake Station. The proposed Coyote
Station will burn Beulah lignite. The third fly ash was collected from an
electrostatic precipitator at Otter Tail Power's cyclone-fired Big Stone
Station, which burns lignite from the Gascoyne, North Dakota, mine. The Big
Stone fly ash differs chemically from the Hoot Lake ash, but it is fired in a
Coyote-type cyclone boiler. The fourth fly ash was collected from electro-
static precipitators at the cyclone-fired Basin Electric Station at Stanton,
North Dakota, which burns a lignite from the Glenharold, North Dakota, mine.
The Basin fly ash has a chemical composition similar to the low sodium Beulah
ash.
The Coyote Station program was conducted at three sets of test condi-
tions. In the first set of conditions, sufficient fly ash was added to main-
tain the solution pH at 4.5 at a constant L/G. This allowed comparisons to
be made of the alkali utilizations of the four fly ashes, and also of sulfur
dioxide removal. In the second set of conditions, the fly ash feed was
reduced to match the expected particulate loading of the proposed Coyote
Station, and supplemental hydrated lime was added to maintain the pH at 4.5.
At the third test condition, the fly ash add rate was maintained at the
expected particulate loading, and sufficient hydrated lime was added to
maintain the pH at 5.0.
The first fly ash tested contained low sodium and was collected from the
electrostatic precipitators of the pc-fired Hoot Lake Station, which burns
Beulah lignite. This coal will be burned in the proposed Coyote Station.
The chemical composition of the fly ash would be similar to the Coyote fly
ash; however, the method of firing would be different (pc versus cyclone) and
the results cannot be correlated directly to the proposed Coyote Station. A
typical fly ash analyses is shown in Table 11.
TABLE 11. TYPICAL ANALYSIS OF BEULAH, NORTH
DAKOTA LOW SODIUM FLY ASH
Percent of ash,
as received
Loss on ignition at 800° C 1.1
Silica, SiOg 25.0
Aluminum oxide, A1203 14.2
Ferric oxide, Fe20s 11.0
Titanium oxide, Ti02 0-5
Phosphorous pentoxide, P205 0.6
Calcium oxide, CaO 27.8
Magnesium oxide, MgO 7.4
Sodium oxide, Na20 4.9
TOTAL 99.9
27
-------
The results of the tests using the low sodium Beulah fly ash are shown
in Table 12. Flue gas by-pass was not used.
TABLE 12. SUMMARY OF RESULTS USING LOW SODIUM FLY ASH
L/G*
Inlet S02 , ppro
Outl et S02 , ppm
S02 removal , pet
Fly ash add rate (ton/hr)
Hydrated lime add rate (ton/hr)
Lime, pet c 7 total CaO
Ash utilization, pet
pH
CaO-total/S02t#
1-a
77
844
214
75
14.7
-0-
-0-
95.9
4.5
0.75
Test Number
1-b
80
825
99
88
13 9
1.6
24 5
77 0
4.6
1.1
1-c
79
787
110
86
14 1
1.9
31 5
61 6
5.0
1.2
* L/G based on gallons of recycled slurry per 1000 acf
saturated flue gas.
t Stoichiometric ratio based on absorber tower inlet S02-
# Fly ash CaO content was averaged during test period.
A typical solution analysis of the absorber tower feed and the wash tray
feed are shown in Table 13.
TABLE 13. TYPICAL SOLUTION ANALYSIS USING LOW SODIUM FLY ASH
Absorber Tower Feed
Wash Tray Feed
Ca 1 c i urn
Magnesium
Sodium
Potassium
Chloride
Sulfite
Sulfate
Total solids, pet
Suspended solids, pet
431
3332
2350
171
58
<0.8
18731
11.5
8.9
460
1548
1437
111
48
<0.8
12275
--
Concentration units are ppm unless otherwise noted.
28
-------
The second fly ash tested was a high sodium Beulah fly ash obtained
from the electrostatic precipitators of the pc-fired Hoot Lake Station. The
high sodium Beulah coal will also be burned in the proposed Coyote Station.
A typical fly ash analysis is shown in Table 14.
TABLE 14. TYPICAL ANALYSIS OF BEULAH, NORTH
DAKOTA, HIGH SODIUM FLY ASH
Percent of ash,
as received
Loss on ignition at 800° C 0.1
Silica, SiO? 24.4
Al umi num oxide, Al 203 12.1
Ferric oxide, Fe203 10.1
Titanium oxide, Ti02 0.9
Phosphorous pentoxide, P205 0.5
Calcium oxide, CaO 22.7
Magnesium oxide, MgO 5.7
Sodium oxide, Na20 10.7
Potassium oxide, K20 0.8
Sulfur trioxide, S03 11.5
TOTAL 99.5
The results of the tests using the high sodium Beulah fly ash are shown
in Table 15. Flue gas by-pass was not used.
TABLE 15. SUMMARY OF RESULTS USING HIGH SODIUM FLY ASH
L/G*
Inlet S02 ppm (dry)
Outlet S02 ppm (dry)
S02 removal , pet
Fly ash add rates ton/hr
Hydrated lime add rate, ton/hr....
Lime, pet of total CaO
Ash utilization, pet
pH
CaO/S02t#
2-a
80
.. 770
65
.. 91.6
.. 22.6
. . -0-
.. -0-
. . 74.4
4.4
.. 1.23
Test Number
2-b
80
750
77
89.9
14.1
2.0
32.3
61.6
4.5
1.2
2-c
80
760
50
93.4
13.1
3.1
44.5
45.0
5.1
1.35
L/G based on gallons of recycled slurry per 1000 acf
saturated flue gas.
Stoichiometric ratio based on absorber tower inlet S02-
Fly ash CaO was averaged during test period.
29
-------
A typical solution analysis of the absorber tower feed and the wash tray
feed are shown in Table 16.
TABLE 16. TYPICAL SOLUTION ANALYSIS USING HIGH SODIUM FLY ASH
Absorber Tower Feed
Wash Tray Feed
Calcium*
Magnesium
Sodium
Potassium
Chloride
Sulfite
Sulfate
Total solid , pet
Suspended solids, pet
457
7312
9068
457
149
<0.8
47333
15.6
10.2
430
1027
1886
107
55
<0 8
13493
Concentration units are ppm unless otherwise noted.
The third test used a fly ash collected from the electrostatic precipita-
tors from the cyclone-fired Big Stone Station, which burns lignite from the
Gascoyne mine. The chemical composition of the fly ash is slightly different
from the low sodium Beulah ash, but is burned in a Coyote-type cyclone
boiler. A typical fly ash analysis is shown in Table 17.
TABLE 17. TYPICAL ANALYSIS OF BIG STONE FLY ASH
Loss on ignition at 800° C..
Silica, Si02
Aluminum oxide, A1203
Ferric oxide, Fe203
Titanium oxide, Ti02
Phosphorous pentoxide, P205-
Calcium oxide, CaO
Magnesium oxide, MgO
Sodium oxide, Na20
Potassium oxide, K20
Sulfur trioxide, $0%
TOTAL
Percent of ash,
as received
0.8
49.3
12.9
3.1
1.2
0.4
17.9
6.1
3.7
0.6
3.0
99.0
The results of the tests using Big Stone fly ash are shown in Table 18.
Flue gas by-pass was not used.
30
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TABLE 18. SUMMARY OF RESULTS USING BIG STONE FLY ASH
Test Number
3-a
3-b
3-c
3-d
L/G*
Inlet S02 ppm, (dry)
Outlet S02 ppm, (dry)
S0£ removal , pet
Fly ash add rate, ton/hr
Hydrated lime add rate, ton/hr
Lime, pet of total CaO
Ash utilization, pet
pH
CaO/S02t#
80
780
103
86.9
24.0
-0-
-0-
87.5
4.15
1.0
80
763
120
84.0
33.4
-0-
-0-
60.1
4.4
1.4
87
839
77
91 0
13 9
3.9
53.0
48 9
4.5
1.2
80
740
65
91 0
13 9
3.6
52.0
39 7
5 0
1.3
* L/G based on gallons of recycled slurry per 1000 acf
saturated flue gas.
t Stoichiometric mole ratio based on absorber tower inlet S02.
# Fly ash CaO was averaged during test period.
One additional test was conducted using the Big Stone fly ash in which
sufficient fly ash was added to maintain the pH at 4.15, as shown in column
3-a. These results may be compared to those obtained at a pH of 4.4, shown
in column 3-b. Lowering the pH from 4.4 to 4.15 increased the fly ash alkali
utilization from 60.1 pet to 87.5 pet. This increase in alkali utilization
is consistent with the increased availability of ash calcium oxide with
decreasing pH values, as shown in Figure 2. In a lime scrubber operating at
much lower liquid-to-gas ratios, a lowered pH value would be expected to
result in a lowered sulfur dioxide removal efficiency due to a decrease in
the absorption of sulfur dioxide from flue gas to scrubber liquor. However,
as the results in tests 3-a and 3-b illustrate, the removal did not decrease
but remained approximately the same. These results can be attributed to the
increased solubility of the fly ash alkali as a function of decreasing pH
values and having a sufficiently high liquid-to-gas ratio to offset the
decrease in sulfur dioxide absorption from flue gas to scrubber liquor. The
decrease in fly ash CaO utilization with increasing pH values can be seen in
columns 3-c and 3-d, which were conducted at a pH of 4.5 and 5.0, and the CaO
utilizations are 48.9 pet and 39.7 pet, respectively.
A typical solution analysis of the absorber tower feed and the wash tray
feed are shown in Table 19.
The fourth test used a fly ash collected from the electrostatic precipi-
tators from Basin Electric Cooperative, which burn Glenharold coal. The coal
ash has a chemical composition similar to the low sodium Beulah coal ash and
is fired in a cyclone-fired boiler. A typical fly ash analysis is shown in
Table 20.
31
-------
TABLE 19. TYPICAL SOLUTION ANALYSIS USING BIG STONE FLY ASH
Absorber Tower Feed Wash Tray Feed
Calcium*
Magnesium
Sodium
Potassium
Chloride
Sulfite
Sulfate
Total solids, pet
Suspended solids, pet
463
5540
2893
175
90
<0.8
28655
15.1
10.3
445
1292
1271
88
47
<0.8
12535
--
Concentration units are ppm unless otherwise noted.
TABLE 20. TYPICAL ANALYSIS OF BASIN FLY ASH
Percent of ash,
as received
Loss on ignition at 800° C 2.7
Silica, Si02 39.1
Aluminum oxide, Al20s 13.0
Ferric oxide, Fe203 6.7
Titanium oxide, Ti02 0.6
Phosphorous pentoxide, P20s 0.2
Calcium oxide, CaO 17.9
Magnesium oxide, MgO 4.2
Sodium oxide, Na20 8.0
Potassium oxide, KpO 1.8
Sulfur trioxide, S&3 5.7
TOTAL 99.9
The results of the tests using the Basin fly ash are shown in Table 21
Flue gas by-pass was not used.
A typical solution analysis of the absorber tower feed and the wash
tray feed is shown in Table 22.
32
-------
TABLE 21. SUMMARY OF RESULTS USING BASIN FLY ASH
L/G*
Inlet S02 ppm (dry)
Outlet S02 ppm (dry)
S02 removdl , pet
Fly ash add rate, ton/hr
Hydrated lime add rate, ton/hr....
Lime, pet of total CaO
Ash utilization, pet
pH
CaO/S02t#
4-a
80
.. 798
.. 124
.. 84.5
.. 45.4
.. -0-
.. -0-
.. 45.7
.. 4.42
1.9
Test Number
4-b
80
794
122
84 7
13 8
3.1
49 3
51.3
4.5
1.1
4-c
80
789
161
79 7
13.9
3.6
52 0
40.9
5.0
1.2
* L/G based on gallons of recycled slurry per 1000 acf
saturated flue gas.
t Stoichiometric mole ratio based on absorber tower inlet S02.
# Fly ash CaO was averaged during the test period.
TABLE 22. TYPICAL SOLUTION ANALYSIS USING BASIN FLY ASH
Absorber Tower Feed
Wash Tray Feed
Calcium*
Magnesium
Sodium
Potassium
Chloride
Sulfite
Sulfate
413
1477
3330
412
68
55
13950
419
369
1116
148
45
<0.8
6300
Concentration units are ppm unless otherwise noted.
The variability of alkali availability at similar pH in the four lig-
nite fly ashes tested is illustrated in the summary shown in Table 23.
33
-------
TABLE 23. SUMMARY OF RESULTS AT pH 4.5
Test Number:
L/G
Fly ash feed, ton/hr. .
S02 removal, pet
pH
Utilization, pet
CaO in fly ash, pet.. .
CaO/SO?
Total alkali, pet
Beulah
low sodium
1-a
80
14.7
75.0
4.5
95.9
27.8
0.75
91.9
Beulah
high sodium
2-a
80
22.6
91.6
4.4
74.4
22.7
1.23
87.9
Big
Stone
3-b
80
33.4
84.0
4.4
60 1
17.9
1 .40
95.2
Basin
4-a
80
45.7
84 5
4.42
45 7
17.9
1 .90
91 5
The above test data were generated by adding sufficient fly ash to main-
tain the recycle slurry pH at a constant value of about 4.5. By this method,
calcium oxide availability may be compared. Only two of the above test
results, 1-a and 2-a, can be directly compared since they are both derived
from the same pc-fired boiler and ESP. The fly ashes differ chemically since
fly ash 1-a is derived from a low sodium coal and fly ash 2-a is derived from
a high sodium coal. The reactivity of the low sodium is greater than the
high sodium fly ash at pH 4.5, as evidenced by the amount of ash required to
maintain the pH at about 4.5. For the low sodium ash, 14.7 ton/hr was
required as compared to 22.6 ton/hr for the high sodium. The fly ash used in
tests 3-b and 4-a show less alkali availability, which could be due to the
different chemical composition of the fly ashes, or to the difference in
boilers from which the fly ash was derived.
Future work at GFERC will characterize the scrubbing characteristics of
various fly ashes by the use of standardized experiments. The standardized
tests will enable various fly ashes to be tested and compared, and would be
related to performance in full-scale scrubbers.
MINNESOTA POWER AND LIGHT COMPANY TEST PROGRAM
The Minnesota Power and Light Company (MP&L) is presently constructing a
500 MW pc-fired boiler at the Clay Boswell Station. The boiler, called the
Clay Boswell unit No. 4, will burn a Montana subbituminous coal and is
required to meet the Federal emission standards of the Clean Air Act. Parti-
culate and sulfur dioxide control will be provided by a two-stage scrubber.
The fly ash will be removed in the first-stage venturi, and the alkali solu-
bilized from the fly ash would then be utilized to remove sulfur dioxide in a
spray tower. Supplemental fly ash will be available from bag filters on two
existing boilers.
The test program was designed to investigate sulfur dioxide removal as a
function of coal sulfur content and L/G, using Montana subbituminous fly ash
collected from mechanical collectors on Clay Boswell Units 1 and 2. The test
34
-------
program was originated by CEA, and was reviewed and approved by the pilot
plant steering committee in accordance with the ERDA cooperative agreement.
The fly ash was collected from mechanical collectors at the Clay Boswell
Station and, thus, is only representative of the larger particles entering a
scrubber. The fly ash was transferred to the 5000-acfm pilot scrubber in
cement trucks and stored in a silo until used. This publication reports on
the first phase of testing; a contamination of the fly ash used in the second
phase of testing made the results non-representative.
The first phase of the test program investigated two fly ash add rates
at three levels of sulfur dioxide and three liquid-to-gas ratios (L/G). The
three liquid-to-gas ratios were 60, 80, and 100 gal/1000 acf-saturated. The
three sulfur dioxide levels were about 900 ppm-dry, 1100 ppm-dry, and 2100
ppm-dry. The fly ash feed rate corresponded to the proposed average (25
ton/hr) and maximum (50 ton/hr) particulate loading expected from the new 500
MW pc-fired boiler. The calcium oxide content in the subbituminous fly ash
averaged about 16 pet. A typical analysis of the fly ash is shown in Table
24.
TABLE 24. TYPICAL ANALYSIS OF MP&L FLY ASH FROM
COLSTRIP, MONTANA, SUBBITUMINOUS COAL
Percent of ash,
as received
Loss on ignition at 800° C 1.4
Silica, Si02 49.8
Aluminum oxide, A1203 18.8
Ferric oxide, Fe203 7.1
Titanium oxide, Ti02 0.9
Phosphorous pentoxide, P20s 0.3
Calcium oxide, CaO 16.1
Magnesium oxide, MgO 3.8
Sodium oxide, Na20 0.2
Potassium oxide, K20 0.5
Sulfur trioxide, S03 1.2
TOTAL 100.1
To meet the Federal emission limit of 1.2 Ib S02/MM Btu, the outlet
sulfur dioxide limitation is 450 ppm-dry. During MP&L's test program, flue
gas bypass for reheat was not utilized. The total flue gas into the scrubber
system was about 6300 acfm. The inlet gas temperature was about 330° F, and
the temperature of the saturated flue gas out of the absorber tower was about
135° F. Anhydrous sulfur dioxide was injected into the inlet flue gas to
duplicate various coal sulfur contents.
35
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TABLE 25. SUMMARY OF RESULTS FROM THE MP&L TEST PROGRAM
CO
Test No.
101
102
201
202
203
204
205
L/G*
100
95
60
80
100
80
95
Add Rate,t
(ton/hr)
24.9
25.2
25.1
25.3
25.2
50.3
49.3
Total
CaO#
S02
0.80
0.69
0.68
0.64
0.71
0.76
0.81
S02-In
ppm-dry
870
1090
1095
1159
1084
2052
2062
S02-0ut
ppm-dry
163
330
380
399
237
1310
888
Pet
Remova i
81.4
72.6
65.3
74.2
78.2
36.2
57.6
Fly ash,
pet CaO
Utilization
104
105
96.6
116.3
no
47.7
70.6
3.9
3.7
3.6
3.8
3.6
4.4
5.0
* L/G based on gallons of recycled slurry per 1000 acfm saturated flue gas.
t Ash add rates correspond to average and maximum particulate loading.
# Stoichiometric mole ratio based on absorber tower inlet sulfur dioxide;
fly ash CaO content was averaged over test period.
-------
The first set of test conditions investigated a sulfur dioxide concen-
tration of about 900 ppm-dry. A removal efficiency of about 50 pet is
required to meet the Federal emission requirement. At a L/G of 100, an
average particulate load of about 25 ton/hr, and an average sulfur dioxide
inlet concentration of 870 ppm-dry, the observed removal efficiency was 81.4
pet. The corresponding fly ash CaO utilization was 104 pet, based on 17 pet
calcium oxide. The recycle slurry pH was 3.9. The results are shown in test
101 in Table 25.
A typical solution analysis of the absorber tower feed and the wash tray
feed is shown in Table 26.
TABLE 26. TYPICAL SOLUTION ANALYSIS OF MP&L ASH TEST
Absorber Tower Feed wash Tray Feed
*
t
Calcium*
Magnesiumt . . .
Sodiumt
Potassiumt . . .
Chloridet. . . .
Sulfite
Sulfatet
Total solids,
Suspended sol
Concentration
Concentrations
474
2372
650
592
420
<0.8
11287
pet 2.3
ids, pet 11.8
units are ppm unless otherwise noted.
were gradually increasing during test.
468
411
479
328
125
<0 8
5430
1 4
0.43
The second set of test conditions investigated a sulfur dioxide concen-
tration of about 1100 ppm-dry. This level of sulfur dioxide was investigated
at four L/G values, 60, 80, 95, and 100, using a constant fly ash feed rate
of about 25 tons/hr, which corresponds to the expected average particulate
loading. A summary of results are shown in Table 25, tests 102, 201, 202,
and 203. The required removal efficiency is about 60 pet. At each L/G
tested, the sulfur dioxide removal was greater than that required to meet the
Federal emission standard; essentially 100 pet of the fly ash calcium oxide
was utilized.
The third set of test conditions investigated a sulfur dioxide concen-
tration of about 2100 ppm-dry. The removal efficiency required for compli-
ance with the Federal emission requirement is 79 pet. The parameters tested
were L/G values of 80 and 95; the fly ash add rate was equivalent to the
expected maximum particulate load of about 50 ton/hr. A summary of the
results are shown in Table 25, tests 204 and 205. The sulfur dioxide removal
efficiencies were considerably below the required 79 pet, and the observed
values are 36.2 pet at a L/G of 80, and 57.6 pet at a L/G of 95. The cor-
responding fly ash calcium oxide utilization was 36.2 pet and 70.6 pet. The
pH of the recycle slurry was 4.4 in the test at L/G of 80, and 5.0 in the
37
-------
test at L/G of 95. The pH values are higher than in the previous tests,
which is reflected in the lower calcium oxide alkali utilizations. At this
level of sulfur dioxide, supplemental lime or limestone would be required to
comply with the Federal emission standard.
The above results are useful in predicting probable sulfur dioxide
removal efficiencies in a full-scale scrubber that is of similar design to
the pilot scrubber. Therefore, to further test the reactivity of the subbi-
tuminous fly ash in a pilot scrubber similar to the full-scale scrubber to be
constructed on Unit 4, MP&L will conduct additional pilot plant studies to
generate design and operating data for a full-scale 500 MW scrubber.
The pilot scrubber will be a 1 MW equivalent, 3000-acfm-saturated two-
stage scrubber. The first stage will consist of a venturi designed for
particulate removal. The second stage will consist of a spray tower which
will use recircuiated fly ash slurry for sulfur dioxide absorption. The
pilot scrubber will further investigate fly ash alkali scrubbing for this
application in greater detail than the present study. The full-scale scrub-
ber will have about 6 pet of the inlet flue gas diverted to two electrostatic
precipitators, which will remove particulate matter. The flue gas will then
be used to reheat the flue gas from the two-stage scrubber.
FIXED INVESTMENT AND OPERATING COST FOR 100 MW,
500 MW, and 1000 MW FLY ASH ALKALI PROCESS
This section describes the results of a capital and operating cost
analyses for a 100 MW, 500 MW, and a 1000 MW fly ash alkali scrubber. The
analyses were performed by Combustion Equipment Associates using a computer
program developed by the Tennessee Valley Authority under EPA sponsorship,
which was modified by CEA for the fly ash alkali process. The analyses are
based on data generated during the SBEC test program and represent an
accuracy of plus or minus 15 pet.
The 500 MW system was selected as the base case and used design and
operating data generated during the SBEC test program; the test program
previously generated design and operating data for the 450 MW system cur-
rently under construction at SBEC. A detailed equipment and source list is
presented in Table 27. Some of the important design and cost assumptions
are:
1. New Western coal-fired generating unit in Northwest location.
2. Coal HHV6400 Btu/lb (as received); heat rate of 10,000 Btu/KWH.
3. Worst case coal sulfur content of 1.3 pet (as received).
4. Sulfur dioxide removal in spray tower is 85 pet.
5. Stack gas reheat to 160° F using 15 pet flue gas bypass.
6. Flue gas particulate of 3.35 grain/scf (wet); 24 pet CaO
in fly ash.
38
-------
TABLE 27-a. 500 MW BASE CASE FLY ASH ALKALI
- PROCESS - MATERIAL HANDLING (LIME)
Item
Units
required
Description
Source
Unit cost, $ Total cost, $
CO
VO
1. Lime storage
silo
2. Weigh feed
(1ime)
3. Lime slaker
1
Capacity 15,000 ft3 CEA
20 ft dia. x 45 ft steel
side carbon steel dust
collector
Capacity 1200 Ibs/hr K-Tron
12 in. belt width.
Motor 1/4 HP D.C.
Costs, items 1 & 2
65,000
65,000
Capacity 192 GPM
outlet flow. Holding
capacity 800 gals,
carbon steel, 2 agitator
CEA
4.
5.
6.
7.
Lime slaker
transfer tank
Agitator, slaker
transfer tank
Lime slurry
feed tank
Agitator, slurry
feed tank
1
1
1
1
Capacity 600 gals
5 ft dia. x 5 ft high
2 HP, carbon steel
1800 RPM
Capacity 56,000 gals
23 ft dia. x 20 ft high
15 HP, carbon steel
1800 RPM
Costs, items 3-7
CEA
Philadelphia
Gear
CEA
Philadelphia
Gear
71,000 71,000
(Continued)
-------
TABLE 27-a. (continued)
-P.
o
8.
9.
10.
Units
Item required
Slaker transfer 2
pumps
Slurry feed 2
transfer pumps
Dust collector 1
system
Description
Capacity 211 GPM
34 ft TDH, 5 HP,
carbon steel
Capacity 211 GPM
155 ft TDH, 15 HP
carbon steel
600 SCFM, internal
separator, 9 bags
SUBTOTAL
Source Unit cost, $
Worthington
Pump, Inc.
13,000
Worthington
Pumps, Inc.
3,800
American Precision
Industries 20,000
Total cost, $
26,000
7,600
20,000
189.600
-------
TABLE 27-b. 500 MW BASE CASE FLY ASH ALKALI PROCESS -
MATERIAL HANDLING (FLY ASH)
Item
Units
required
Description
Source
Unit cost, $ Total cost, $
1. Fly ash silo
1
2. Weigh feed 1
(fly ash)
3. Fly ash slurry 1
feed tank
4. Agitator, fly ash 1
slurry feed tank
(without motor)
5. Fly ash slurry 2
feed pumps
Capacity 15,000 ft3 CEA
21 ft dia. x 54 ft high
with dust collector
vibrating hopper
Capacity 60,000 Ibs/hr K-Tron
24 in. belt width,
motor 1/2 HP D.C.
Costs, items 1 & 2
Capacity 56,000 gals
23 ft x 20 ft high,
carbon steel
15 HP, 1800 RPM,
carbon steel
Costs, items 3 & 4
Capacity 1052 GPM,
54 ft TDH, 30 HP,
carbon steel
CEA
Philadelphia
Gear
Worthington
Pumps, Inc.
188,400
48,500
3,750
188,400
48,500
7,500
SUBTOTAL
244,400
-------
TABLE 27-c. 500 MW BASE CASE FLY ASH ALKALI PROCESS - S02 - SCRUBBING
Item
Units
required
Description
Source
Unit cost, $ Total cost, $
ro
1. Absorber tower
2. Absorber recycle 2
tank
3. Agitator, absorber 2
recycle tank
4. Wash tray
5. Mist eliminator
6. Absorber recycle 10
pumps
7. Tray recycle
tank
40 ft dia. x 123 ft steel CEA
side, carbon steel, lined
Capacity 450,000 gals CEA
40 ft dia., carbon steel,
lined
Impeller 128 in., 30 RPM Chemineer
100 HP, lined
Costs, items 2 & 3
Material 316LL, SS,
bubbler tray with
supports & nozzles,
spray headers, piping
and supports
4 pass chevron type,
with supports, nozzles,
spray headers
Costs, items 4 & 5 . . .
Capacity 15,260 GPM
156 ft TDH, carbon steel
rubber lined, with motor
Capacity 12,600 gals
14 ft dia. x 12 ft high
carbon steel, lined
A.S.H. Pumps
CEA
250,500
150,000
426,250
60,000
(Continued)
501,000
300,000
852,500
600,000
-------
TABLE 27-c. (continued)
Item
Units
required
Description
Source
Unit cost, $ Total cost, $
CO
8. Agitator, tray 2
recycle tank
9. Pumps, tray
recycle
10. Tray thickener 1
tank
11. Agitator, tray 1
thickener tank
12. Tray thickener 1
overflow tank
13. Pumps, tray 2
sprays
14. Pumps, mist 2
eliminator sprays
S.H.P., carbon steel,
rubber lined
Costs, items 7 & 8 .
Philadelphia
Gear, Inc.
Capacity 4164 GPM
124 ft TDH, 200 HP
carbon steel, lined
Capacity 80,000 gals,
40 ft dia. x 12 ft steel
side, concrete lined
2 HP, 24 in. rake arms,
with motor
Costs, items 10 & 11
Capacity 11,000 gals
13 ft. dia. x 13 ft high
carbon steel, lined
Capacity 1278 GPM
236 ft TDH, 150 HP
carbon steel, lined
Capacity 15,979 GPM
178 ft TDH, 125 HP
carbon steel, lined
Worthington
Pumps, Inc.
CEA
Sanderson &
Porter (S&P)
Eimco
CEA
Worthington
Pumps, Inc.
Worthington
Pumps, Inc.
20,000
15,500
150,000
6,000
17,500
40,000
62,000
150,000
6,000
35,000
SUBTOTAL
16,000 32,000
2,578,500
-------
TABLE 27-d. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - SOLIDS DISPOSAL
1.
2.
3.
4.
5.
6.
7.
Units
Item required
Main thickener 1
tank
Agitator, main 1
thickener tank
Pumps, main 2
thickener
underflow
Main thickener 1
overflow tank
Pumps, main 2
thickener
overflow
Pumps, tray 2
thickener
underflow
Vacuum filter 1
Description
Capacity 1,000,000 gals
130 ft dia. x 15 ft steel
side, concrete lined
10 HP, 300,000 ft/lb
torque
Costs, items 1 & 2 ....
Capacity 450 GPM,
74 ft IDA, 25 HP
Capacity 11 ,000 gals
13 ft dia. x 13 ft high,
carbon steel , lined
Capacity 1112 GPM
62 ft TDH, lined
Capacity 7.7 GPM
87 ft TDH
Capacity 528 ft2
12 ft dia. x 14 ft
length
SUBTOTAL
Source Unit cost, $ Total cost, $
S&P
CEA
Eimco
660,000 660,000
Worth ington
Pumps, Inc.
3,900 7,800
CEA
9,000 9,000
Worthington
Pumps, Inc.
4,600 9,200
Dorr-Oliver
3,000 6,000
Eimco
272,000 272,000
1,034,200
-------
en
TABLE 27-e. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - REHEAT
Item
1 . Reheat mixing
chamber
2. Reheater damper
control & motor
Units
required
2
2
Description Source
Bussel & jet nozzles CEA
Butterfly damper Hamilton
98 in. dia. I.D.
SUBTOTAL
Unit cost, $ Total cost, $
100,000 100,000
20,400 40,800
240.800
-------
TABLE 27-f. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - GAS HANDLING
-P.
CTl
1.
2.
3.
4.
Units
Item required
Fan, booster 2
with motor
Scrubber inlet 2
damper
Scrubber bypass 2
damper
Scrubber outlet 2
damper system
Description
Capacity 1,020,000
ACFM at 10 in. H20
adjustable pitch
18 ft x 18 ft carbon
steel with motor and
controller
18 ft x 18 ft carbon
steel with motor
actuator
17 ft dia. SS, with
motor & controller
SUBTOTAL
Source
Buffalo Forge
Hamilton
American Vent &
Warming
Hamilton
Unit cost, $ Total cost, $
725,000 1,450,000
113,000 226,000
42,500 85,000
134,000 268,000
2.029.000
-------
TABLE 27-g. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - STRUCTURAL
1.
2.
3.
4.
5.
6.
Item
Structural
Piping, sup-
ports & valves
Ducting
Duct instal-
lation
Piping insu-
lation
Piping
Units
required
1 set
1 set
1 set
1 set
1 set
1 set
Description Source
Structural steel CEA
for support
All necessary CEA
piping, supports, &
valves
All necessary CEA
ducting & expansion
joints, lined
S&P
S&P
Lake Water System, S&P
all other connections
SUBTOTAL
Unit cost, $ Total cost, $
496,000
1,737,000
947,000
300,000
115,000
665,000
4,260,000
-------
TABLE 27-h. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - INSTRUMENTATION
Item
Units
required
Description
Source
Unit cost, $ Total cost, $
1. Instruments
2. Instrumenta-
tion and con-
trol for fan
and data log-
ging system
1 set
1 set
All necessary process
and flow instruments
SUBTOTAL
CEA
S&P
868,000
150,000
1,018,000
00
TABLE 27-i. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - INSTRUMENTATION
Item
Units
required
Description
Source
Unit cost, $ Total cost, $
1. Craft labor
2. Rentals &
consumables
3. Field office
CEA
CEA
CEA
SUBTOTAL
3,800,000
1,400,000
825,000
6,025,000
-------
TABLE 27-j. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - UTILITIES
>£>
1.
2.
3.
Item
Equipment
Electrical
equipment
Electrical
installation
Units
required Description
Air compressors,
hoists & misc. pumps
Sludge handling
equipment
Lake water pumps &
storage tanks
4.16 KV switchgear
480 V substation
480 V motor cont.
Center
SUBTOTAL
Source Unit cost, $ Total cost, $
S&P
105,000
200,000
110,000
S&P
300,000
S&P
1,825,000
2,540,000
-------
TABLE 27-k. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - SERVICE FACILITIES
en
O
Units
Item required Description
1. Buildings Fly ash slurry
tank building
Pump house
Source Unit cost, $ Total cost, $
S&P
120,000
775,000
Miscellaneous
gradings and
roads
Vacuum filter
building
SUBTOTAL
S&P
580,000
655,000
2,130,000
-------
TABLE 27-1. 500 MW BASE CASE FLY ASH ALKALI
PROCESS - EXCAVATION & FOUNDATION
Item
Units
required
Description
Source
Unit cost, $ Total cost, $
1. Excavations &
foundations
2. Absorber
3. Fans & ductwork
4. Thickener & clarifier
tunnels & foundations
5. Buildings and
equipment
6. Sludge storage
7. Lake water storage
tank
8. Ductbank and
manholes (except for
L.W. storage tank)
9. Ductbank - lake
water storage
S&P
S&P
S&P
S&P
S&P
S&P
S&P
S&P
S&P
165,000
175,000
425,000
600,000
190,000
10,000
155,000
30,000
SUBTOTAL
1,750,000
-------
7. Liquid-to-gas (L/G) ratio of 80 gal/1000 acf (saturated).
8. Off-site sludge disposal in strip mine approximately one
mile from site.
9. Fixed investment and operational cost calculations are
based on 1976 dollars.
A summary of the estimated fixed investment for the 100 MW, 500 MW base
case, and the 1000 MW unit are shown in Tables 28, 29, and 30, respectively.
The fixed investment for the fly ash alkali process is about 2-3 pet higher
than an equivalent lime system. The increased cost is attributed to the fly
ash system, to larger pumps required for high liquid-to-gas (L/G) ratios, and
to larger pipes and tanks required for handling the increased amount of
solids (9).
The total average annual operating costs for a 100 MW, 500 MW base case,
and a 1000 MW system are shown in Tables 31, 32, and 33. Lifetime annual
operating costs for the 500 MW base case are shown in Table 34. The opera-
ting costs were calculated using a worst case coal sulfur content of 1.3 pet.
Under these conditions, addition of supplemental lime is required and oper-
ating costs would be at a maximum. In addition to the initial design and
cost assumptions, the following was also assumed: 1) mole ratio of lime CaO
to absorbed S02 is 0.74; and 2) fly ash CaO to absorbed S02 mole ratio is
0.26.
A substantial savings in raw material costs is realized by utilizing fly
ash alkali. Table 35 shows a comparison of raw material costs for the fly
ash alkali process and an equivalent lime system for a 0.75 pet and a 1.3 pet
coal sulfur content. The calculations indicate the raw material cost for an
equivalent lime system operating on a 1.3 pet sulfur coal would be about 26
pet more than the fly ash alkali process. When the fly ash alkali process is
operating on a 0.75 pet sulfur coal, all CaO alkali can be provided by the
fly ash.
Calculations on scrubber unit operating costs for the fly ash alkali
process are shown in Table 36. The figures for 1.3 pet coal sulfur are based
on total operating costs presented in Tables 31, 32, and 33. Figures for
0.75 pet coal sulfur assume no supplemental lime requirements.
52
-------
TABLE 28. SUMMARY OF ESTIMATED FIXED INVESTMENT
FOR A TOO MW FLY ASH ALKALI PROCESS*
Item
Percent of subtotal
Investment, $ direct investment
1.
2.
3.
4.
5.
10.
11
Lime system (storage hopper,
weigh feeder, slaker, pumps
and tanks, agitator)
Fly ash system (storage hopper,
dust collector, weigh feeder,
agitator, tank, pumps)
Sulfur dioxide scrubber (1
scrubber, wash tray, mist
eliminators, pumps, agitators,
all vessels)
Solids disposal (filter, thickener
pumps, agitators)
Reheat (mixing chamber, damper,
control & motors)
Gas handling (2 fans, inlet
dampers, outlet dampers)
Structural (structural steel,
piping, valves, supports,
ducting)
Instrumentation (all necessary
process & flow instruments)
Cost for erection (Items 1-8,
craft labor, rentals & con-
sumables, field office)
Utilities (instrument air gener-
ation and supply system, dis-
tribution system for obtaining
process water, electrical
switchgear)
Service facilities (building,
shops, stores, site develop-
ment, roads, walkways)
451,000
62,400
650,000
208,000
52,000
364,000
884,000
208,000
1,378,000
520,000
1.1
1.2
12.5
4.0
1.0
7.0
17.0
4.0
26.5
10.0
457,600 8.8
(Continued)
53
-------
TABLE 28. (continued)
12.
13.
14.
15.
16.
17.
18.
Item
Excavation and foundation
Subtotal direct investment
Architect - Engineers design
and supervision fee
Architect - Engineers construc-
tion managenent fee
Investor's costs
Contingency
Subtotal fixed investment
Allowance for spare parts
Interest during construction
Total capital investment
Investment, $
374,400
5,200,000
312,000
364,000
104,000
260,000
6,240,000
260,000
520,000
7,020,000
Percent of subtotal
direct investment
7.2
100.0
6.0
7.0
2.0
5.0
120.0
5.0
10.0
135.0
* Basis:
Off-site disposal approximately 1 mile from site.
Project beginning early 1975, ending mid-1977.
Minimum in-process storage; only pumps are spared.
Investment requirements for disposal of ash excluded.
Construction labor shortages with accompanying overtime
pay incentive not considered.
Items previously noted.
54
-------
TABLE 29. SUMMARY OF ESTIMATED FIXED INVESTMENT FOR A
500 MW BASE CASE FLY ASH ALKALI PROCESS*
Item
Percent of subtotal
Investment, $ direct investment
1. Lime system (storage hopper,
weigh feeder, slaker, pumps
and tanks, agitator)
2. Fly ash system (storage hopper,
dust collector, weigh feeder,
agitator, tank, pumps)
3. Sulfur dioxide scrubber (2
scrubbers, wash tray, mist
eliminators, pumps, agitators,
all vessels)
4. Solids disposal (filter, thick-
ener, pumps, agitators)
5. Reheat (mixing chamber, damper,
control & motors)
6. Gas handling (2 fans, inlet
dampers, bypass dampers,
outlet dampers)
7. Structural (structural steel,
piping, valves, supports,
ducting)
8. Instrumentation (all necessary
process & flow instruments)
9. Cost for erection (Items 1-8,
craft labor, rentals & con-
sumables, field office)
10. Utilities (instrument air gener-
ation and supply system, dis-
tribution system for obtaining
process water, electrical
switchgear)
11. Service facilities (building,
shops, stores, site develop-
ment, roads, walkways)
189,600
244,400
2,578,500
1,034,500
240,800
2,029,000
4,260,000
1,018,000
6,025,000
2,540,000
0.8
1.2
10.7
4.3
1.0
8.5
17.7
4.2
25.1
10.6
2,130,000 8.8
(Continued)
55
-------
TABLE 29. (continued)
Item
12. Excavation and foundation
Subtotal direct investment
13. Architect - Engineers design
and supervision fee
14. Architect - Engineers construc-
tion management fee
15. Investor's fee
16. Contingency
Subtotal fixed investment
17. Allowance for startup and
modification
18. Interest during construction
Total capital investment
Investment, $
1,750,000
24,039,500
1,442,000
1,683,000
481 ,000
1,202,000
28,847,500
1,202,000
2,404,000
32,453,500
Percent of subtotal
direct investment
7.1 :
100.0
6.0
7.0
2.0
5.0
120.0
5.0
10.0
135.0
* Basis:
Off-site disposal approximately 1 mile from site.
Project beginning early 1975, ending mid-1977.
Minimum in-process storage; only pumps are spared.
Investment requirements for disposal of ash excluded.
Construction labor shortages with accompanying overtime
pay incentive not considered.
Items previously noted.
56
-------
TABLE 30. SUMMARY OF ESTIMATED FIXED INVESTMENT
FOR A 1000 MW FLY ASH ALKALI PROCESS*
Item
Percent of subtotal
Investment, $ direct investment
1. Lime system (storage hopper,
weigh feeder, slaker, pumps
and tanks, agitator)
2. Fly ash system (storage hopper,
dust collector, weigh feeder,
agitator, tank, pumps)
3. Sulfur dioxide scrubber (4
scrubbers, wash tray, mist
eliminators, pumps, agitators,
all vessels)
4. Solids disposal (filter, thickener
pumps, agitators)
5. Reheat (mixing chamber, damper,
control & motors)
6. Gas handling (2 fans, inlet
dampers, bypass dampers,
outlet dampers)
7. Structural (structural steel,
piping, valves, supports,
ducting)
8. Instrumentation (all necessary
process & flow instruments)
9. Cost for erection (Items 1-8,
craft labor, rentals & con-
sumables, field office)
10. Utilities (instrument air gener-
ation and supply system, dis-
tribution system for obtaining
process water, electrical
switchgear)
11. Service facilities (building,
shops, stores, site develop-
ment, roads, walkways)
451,000
492,000
4,100,000
1,640,000
1,025,000
3,403,000
7,544,000
1,640,000
10,045,000
4,100,000
1.1
1.2
10.0
4.0
2.5
8.3
18.4
4.0
24.5
10.0
3,690,000 9.0
(Continued)
57
-------
TABLE 30. (continued)
12.
13.
14.
15.
16.
17.
18.
Item
Excavation and foundation
Subtotal direct investment
Architect - Engineers design
and supervision fee
Architect - Engineers construc-
tion management fee
Investor's costs
Contingency
Subtotal fixed investment
Allowance for spare parts
Interest during construction
Total capital investment
Investment, $
2,870,000
• 41,000,000
2,460,000
2,870,000
820,000
2,050,000
49,200,000
2,050,000
4,100,000
55,350,000
Percent of subtotal
direct investment
7.0
100.0
6.0
7.0
2.0
5.0
120.0
5.0
10.0
135.0
* Basis:
Off-site disposal approximately 1 mile from site.
Project beginning early 1975, ending mid-1977.
Minimum in-process storage; only pumps are spared.
Investment requirements for disposal of ash excluded.
Construction labor shortages with accompanying overtime
pay incentive not considered.
Items previously noted.
58
-------
TABLE 31. TOTAL AVERAGE ANNUAL OPERATING COST FOR
A 100 MW FLY ASH ALKALI PROCESS*
Item
Total
annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Raw Material:
Lime
Subtotal raw material
Conversion Costs
Operating labor & supervision
Utilities:
Steam
Process water
Electricity
Maintenance:
Labor and material
Analyses
10.0 M tons
40.00/ton
8,990.0 man-hr 10.00/man-hr
482,790.0 M Ib
64,630.0 M gal
12,083,490.0 KWH
910.0 hr
2.
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation
Cost of capital and taxes, 8.25%
of undepreciated investment
Insurance & interim replacements,
1.17% of fixed investment
Overhead:
Plant, 10.0% of conversion costs
less utilities
Administrative, research & service,
0.0% of operating labor & supervision
Subtotal indirect costs
Total annual operating cost
398,200
398,200
89,900
00/M Ib
09/M gal
02/KWH
00/hr
0
5,800
241,700
165,400
1,800
504,600
902,800
364,700
939,600
133,300
25,700
0
1,463,300
2,366,100
Basis: Remaining life of powerplant is 30 years.
Coal burned is 464,800 ton/yr, 6400 Btu/lb, 10,000 Btu/KWH.
Items previously noted.
59
-------
TABLE 32. TOTAL AVERAGE ANNUAL OPERATING COST FOR A
500 MW BASE CASE FLY ASH ALKALI PROCESS*
Total
annual
Item Annual quantity " Unit cost, $ cost, $
49.8 M tons
2,413,940.0 M Ib
323,170.0 M gal
52,247,390.0 KWH
Direct Costs
Raw Material:
Lime
Subtotal raw material
Conversion Costs
Operating labor & supervision
Utilities:
Steam
Process water
Electricity
Maintenance:
Labor and material
Analyses 2,810.0 hr
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation
Cost of capital and taxes, 8.25%
of undepreciated investment
Insurance & interim replacements,
1.17% of fixed investment
Overhead:
Plant, 10.0% of conversion costs
less utilities
Administrative, research & service,
0.0% of operating labor & supervision
Subtotal indirect costs
Total annual operating cost
40.00/ton
20,110.0 man-hr 10.00/man-hr
.00/M Ib
.09/M gal
.02/KWH
2.00/hr
1,991,000
1,991,000
201,100
0
29,100
1,044,900
447,800
5,600
1,728,500
3,719,500
987,500
2,579,000
365,700
65,500
0
3,997,700
7,717,200
* Basis: Remaining life of powerplant is 30 years.
Coal burned is 2,324,200 ton/yr, 6400 Btu, 10,000 Btu/KWH.
Items previously noted.
60
-------
TABLE 33. TOTAL AVERAGE ANNUAL OPERATING COST
FOR A 1000 MW FLY ASH ALKALI PROCESS*
Item Annual quantity
Unit cost, $
Total
annual
cost, $
Direct Costs
Raw Material:
Lime
Subtotal raw material
Conversion Costs
Operating labor & supervision
Utilities:
Steam
Process water
Electricity
Maintenance:
Labor and material
Analyses
99.6 M tons
40.00/ton
28,440.0 man-hr 10.00/man-hr
4,827,880.0 M Ib
646,350.0 M gal
102,746,820.0 KWH
4,570.0 hr
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Depreciation
Cost of capital and taxes, 8.25%
of undepreciated investment
Insurance & interim replacements,
1.17% of fixed investment
Overhead:
Plant, 10.0% of conversion costs
less utilities
Administrative, research & service,
0.0% of operating labor & supervision
Subtotal indirect costs
Total annual operating cost
.00/M Ib
.09/M gal
.02/KWH
2.00/hr
3,982,000
3,982,000
284,400
0
58,200
2,054,900
808,100
9,100
3,214,700
7,196,700
1,781,900
4,652,400
659,800
110,200
0
7,204,300
14,401,000
* Basis: Remaining life of powerplant is 30 years.
Coal burned is 4,648,400 ton/yr, 6400 Btu/lb, 10,000 Btu/KWH.
Items previously noted.
61
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TABLE 34. 500 HW BASE CASE FLY ASH ALKALI PROCESS - ANNUAL OPERATING COSTS
Years
after
power
unit
start
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Annual Power unit
opera- heat
tion, requirement,
KW-hr Million Btu
/KW /year
7000
7000
7000
7000
7000
7000
7000
7000
7000
7000
5000
5000
5000
5000
5000
3500
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
29750000
29750000
29750000
29750000
29750000
29750000
29750000
29750000
29750000
29750000
21250000
21250000
21250000
21250000
21250000
14875000
14875000
14875000
14875000
14875000
6375000
6375000
6375000
6375000
6375000
6375000
6375000
6375000
6375000
6375000
Power unit
fuel
consumption,
total NS C
/year
2324200
2324200
2324200
2324200
2324200
2324200
2324200
2324200
2324200
2324200
1660200
1660200
1660200
1660200
1660200
1662100
1162100
1162100
1162100
1162100
498000
498000
498000
498000
498000
498000
498000
498000
498000
498000
Sulfur
removed by
pollution
control
process,
tons/year
20700
20700
20700
20700
20700
20700
20700
20700
20700
20700
14800
14800
14800
14800
14800
10400
10400
10400
10400
10400
4400
4400
4400
4400
4400
4400
4400
4400
4400
4400
Dry sludge
equivalent
tons/year
214200
214200
214200
214200
214200
214200
214200
. 214200
214200
214200
153000
153000
153000
153000
153000
107100
107100
107100
107100
107100
45900
45900
45900
45900
45900
45900
45900
45900
45900
45900
Adjusted gross
annual revenue
requirement
including reg-
ulated ROI for
power company,
$/year
7717200
7635700
7554200
7472700
7391300
7309800
7228300
7146900
7065400
6983900
5900800
5819300
5737800
5656400
5574900
4727200
4645800
4564300
4482800
4401300
3258700
3177200
3095700
3014300
2932800
2851 300
2769900
2688400
2606900
2525500
Net annual
increase
in total
revenue
requirement.
7717200
7635700
7554200
7472700
7391300
7309800
7228300
7146900
7065400
6983900
5900800
5819300
5737800
5656400
5574900
4727200
4645800
4564300
4482800
4401300
3258700
3177200
3095700
3014300
2932800
2851300
2769900
2688400
2606900
2525500
Cumulative
net Increase
in total
revenue
requirement,
$
7717200
15352900
22907100
30379800
37771100
45080900
52309200
59456100
66521500
73505400
79406200
85225000
90963300
96619700
102194600
106921800
111567600
116131900
120614700
125016000
128274700
131451900
134547600
137561900
140494700
143346000
146115900
148804300
151411200
153936700
Total
127500
541875000
42333500
377000
3901500
153936700
153936700
62
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TABLE 35. COMPARISON OF RAW MATERIAL OPERATING COSTS FOR LIME
SCRUBBING VERSUS FLY ASH ALKALI SCRUBBING*
1.3 pet
Equivalent
lime
process
100 MW Unit $ 538,100
500 MW Unit 2,691,000
1000 MW Unit 5,381,000
Coal-S
Fly ash alkali
process
(1 ime and
fly ash)
$ 398,200
1,991,000
3,982,000
0.75
Equivalent
lime
process
$ 290,900
1,455,000
2,909,000
pet Coal-S
Fly ash alkali
process
(lime and
fly ash)
-0-
-0-
-0-
* Basis: 15 pet flue gas bypass for reheat.
85 pet S02 removal in absorber tower.
1.0 CaO-total to absorbed S02 mole ratio (0.74 mole lime CaO).
TABLE 36. SCRUBBER UNIT OPERATING COSTS FOR THE
FLY ASH ALKALI PROCESS*
1.3 pet Coal-Sulfur
100 MW 500 MW 1000 MW
0.75 pet Coal-Sulfur
100 MW 500 MW 1000 MW
Coal burned, $/ton
Mills/KWH
Cents/106 Btu input
5.09 3.32 3.10
3.98 2.59 2.42
39.77 25.9 24.2
4.23 2.46 2.24
3.31 1.93 1.75
33.1 19.3 17.5
* Includes depreciation, cost of capital and taxes, insurance,
and plant overhead.
63
-------
REFERENCES
1. Ness, H.M., F.I. Honea, E.A. Sondreal, and P. Richmond. Pilot Plant
Scrubbing of S02 with Fly Ash Alkali from North Dakota Lignite.
Presented at 9th Biennial Lignite Symposium, Grand Forks, ND,
May 18-19, 1977.
2. U.S. BureaL of Mines, Division of Fossil Fuels. Coal—Bituminous and
Lignite in 1973. Mineral Industry Surveys, January 4, 1975, p. 5.
3. Gronhovd, G.H., P.H. Tufte, and S.J. Selle. Some Studies on Stack
Emissions from Lignite Fired Power Plants. Bureau of Mines 1C 8650,
1975, p. 103, 133.
4. Energy Research and Development Administration. Open file report.
Survey of Coal and Ash Composition and Characteristics of Western
Coals and Lignites. Grand Forks, ND, 1975.
5. Tufte, P.M., E.A. Sondreal, K.W. Korpi, and G.H. Gronhovd. Pilot Plant
Scrubber Tests to Remove S02 Using Soluble Alkali in Western Coal Ash.
Bureau of Mines 1C 8650, 1974, pp. 103-133.
6. Sondreal, E.A. and P.H. Tufte. Wet Scrubbing of S02 with Alkali in
Western Coal Ash. Paper No. 74-272, 67th Annual Meeting of the Air
Pollution Control Association, June 9-13, 1974.
7. Sondreal, E.A. and P.H. Tufte. Scrubber Developments in the West.
Presented at the Lignite Symposium, Grand Forks, ND, May 14-15, 1975.
8. La Mantia, C., R.R. Lunt, J.E. Oberholtzer, and E.L. Field. EPA-ADL
Dual Alkali Program Interim Results. Presented at EPA Symposium on
Flue Gas Desulfurization, Atlanta, GA, November 4-7, 1974.
9. Murad, F.Y., L. Hillier, and P. Kilpatrick. Boiler Flue Gas Desul-
furization by Fly Ash Alkali. Presented at Mid-Continent Area Power
Pool (MAPP) Environmental Workshop, Minneapolis, MN, Nov. 18, 1975.
64
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APPENDIX A
65
-------
TABLE A-l. SUMMARY OF RESULTS FROM THE DESIGN AND OPERATING
TEST SERIES CONDUCTED AT L/G 60*
Add rate
ton/hr
Fly ash
16.4
16.3
16.6
15.6
25.4
25.2
14.7
15.1
17.0
16.2
25.9
26.6
Lime
-0-
-0-
-0-
-0-
-0-
-0-
9.9
8.5
4.2
7.3
6.4
7.1
S02-In
ppm-dry
1094
1121
1036
962
975
998
1880
1860
1880
1887
1890
1883
S02-0ut
ppm-dry
320
402
469
435
301
305
620
583
507
598
537
540
Pet removal
System
71
64.1
55
55
69.1
69.4
67
68.6
73
68.4
71.6
70.5
Tower
83.5
75.4
64.7
64.7
81.3
81.7
78.8
80.7
85.9
80.1
84.2
82.9
Recycle
slurry
PH
3.9
3.9
3.9
3.9
5.7
4.9
6.5
6.6
6.7
6.7
6.6
6.8
L/G based on gallons of recycle slurry per 1000 acf
saturated flue gas.
66
-------
TABLE A-2. SUMMARY OF RESULTS FROM THE DESIGN AND OPERATING
TEST SERIES CONDUCTED AT L/G 80*
Add rate
ton/hr
Fly ash
16.5
16.2
16.8
24.8
27.1
16.0
15.4
16.4
16.2
17.2
16.2
24.5
25.2
Lime
-0-
-0-
-0-
4.5
1.8
9.6
10.3
7.5
7.5
7.8
7.3
8.0
8.1
S02-In
ppm-dry
991
1120
1120
1096
1104
1984
1860
1935
1863
1887
1873
1887
1852
S02-0ut
ppm-dry
320
252
362
217
183
413
370
583
490
386
400
355
380
Pet removal
System
68
77.5
67.7
80.2
83.4
80.1
79.2
69.9
73.9
79.5
78.6
81.2
79.5
Tower
80
91.2
79.7
94.4
98.1
94.2
93.2
82.2
86.9
93.5
92.4
95.5
93.5
Recycle
slurry
PH
4.1
3.9
3.4
5.5
7.0
6.6
6.6
6.3
6.8
6.8
7.1
6.3
7.2
L/G based on gallons of recycle slurry per 1000 acf
saturated flue gas.
67
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-075
3. RECIPIENT'S ACCESSION-NO.
4. TITLE ANDSUBTITLE
Flue Gas Desulfurization Using Fly Ash Alkali
Derived from Western Coals
5. REPORT DATE
July 1977
6. PERFORMING ORGANIZATION CODE
> and E.A.Sondreal (ERDA), F.Y.
Murad (Combustion Equipment Associates), and K.S.
Vig (Square Butte Electric Co-op)
3. PER
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U. S. Energy Research and Development Administration
Box 8213 University Station
Grand Forks, North Dakota 58202
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
EPA Interagency Agreement
IAG-D5-E681
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 7/75-6/77
14. SPONSORING AGENCY CODE
EPA/600/13
15.SUPPLEMENTARY NOTES IERL_RTP project officer for this report is Norman Kaplan, Mail
Drop 61, 919/541-2915;
is. ABSTRACT The report gjves results of tests investigating the use of Western coal fly
ash for scrubbing SO2 from powerplant flue gas, on a 130-scfm pilot scrubber at the
Grand Forks (ND) Energy Research Center and on a 5000-acfm pilot scrubber at the
Milton R. Young Generating Station (Center, ND). Tests of the 130-scfm unit were
designed to investigate the effects of increased sodium concentration on SO2 removal
and rate of scaling. Parameters investigated included liquid-to-gas ratios (L/G),
stoichiometric ratios (CaO/SO2), and sodium concentration. Results indicate increased
SO2 removal and decreased rate of scaling as sodium concentration increases. Tests
of the 5000-acfm unit generated design and operating data for a full-scale 450 MW fly
ash alkali scrubber to be constructed at the same Station. Results indicate that suffi-
cient SO2 can be removed to meet NSPS requirements, using only fly ash alkali when
burning 0. 75% sulfur lignite. An 8-week reliability test was also performed. Fly ash
alkali scrubbing tests of flue gas SO2 were also performed, using a subbituminous-
derived fly ash and other various lignite-derived fly ashes. A detailed analysis is
presented of capital investment and operating costs for 100, 500, and 1000 MW
scrubbers using the fly ash alkali process.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Air Pollution
Electric Power Plants
Flue Gases
Desulfurization
Fly Ash
Alkalies
Coal
Scrubbers
Sulfur Dioxide
Sodium
Air Pollution Control
Stationary Sources
Western Coals
Fly Ash Alkali Process
13B 21D
10B
21B 07B
07A,07D
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report/
Unclassified
21. NO. OF PAGES
78
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
j
EPA Form 2220-1 (9-73)
68
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