-------
TABLE 2-21. MONTHLY AVERAGE SULFUR REDUCTION EY A LEVEL II
CLEANING PIANT - MIEDLE KTTTANINS (Ohio No. 6)
CCAL
USE
Steam
Steam
Steam
Steam
Steam
Steam
LOT
QUANTITY
(metric tons)
154,565
138,162
162,063
145,074
189,246
163,255
PLANT E
.b'KH)
%S
4.07
3.73
3.98
4.46
3.96
3.45
kJ/hg
25,756
27,180
26,047
25,029
25,248
25,465
ng SOa/J
3,164.8
2,747.7
3,061.6
3,569.0
3,143.3
2,713.3
%S
3.03
2.86
3.06
3.05
3.06
2.99
PRODUCT
kJ/ng
29, 111
29,041
29,037
28,992
29,044
28,957
ng S02/J
2,085.5
1,973.7
2,111.3
2,107.0
2,111.3
2,068.3
Peed (ng SO2/J)
li = 3,065.9 0 m 322.9 RSD = 0.105
Product (ng SO2/J)
V m 2,076.9 0 = 37.4 RSD = 0.018
Sulfur Removal (%)
U = 32.0 0 - 5.91 RSD = 0.185
Product sanpled manually
152
-------
TABLE 2-22. ANNUAL AVERAGE SULFUR REDUCTION BY A LEVEL III
CLEANING PLANT - OHIO COAL
PLANT F
FEED PRODUCT
SEAM
18
LF
#8
LF
18
#9
#9
#8
%S kJ/kg ng SO2/J %S
3.28 22,524 2919.7
2.92 21,313 2743.4
2.05 21,750 1887.7
2.55 27,459 1861.9
5.09 28,622 3564.7
2.51 28,885 1741.5
3.02 29,130 2076.9
2.67, 29,498 1814.6
SEAM: Pittsburgh 18 and
Coal Use: Steam
Feed
y - 2326.3 ng SOz/J
rutiLn^u
p = 1806.0 ng SOa/J
Sulfur Removal
U = 21.0%
Product sample*^ TrarwiflTiY
3.96
2.94
2.78
2.34
3.59
2.15-
2.51
2.33
19; Lower
a = 670.8
a = 426.1
a = 9.85%
kJ/kg
30,831
32,203
31,502
32,571
31,294
30,024
30,462
32,282
Freepart S6A
ng SO2/J
ng SOz/J
ng S02/J
2575
1827
1767
1440
2300
1436
1651
1444
CD'
RSD
RSD
RSD
.7
.5
.3
.5
.5
.2
.2
.8
Coal)
= 0.288
= 0.236
= 0.469
153
-------
TABLE 2-23. DAILY AVERAGE SULFUR REDUCTION BY A LEVEL III
CLEANING PLANT - LOWER KLTTANING - 5 DAY TESTS
FEED PRODUCT
Day %S kJAg ng SO2/J %S kJAg ng
1 2.80 31,420 1,784.5 1.11 34,069 653.6
2 2.24 30,008 1,496.4 1.20 33,200 722.4
3 1.84 28,198 1,307.2 1.22 32,960 739.6
4 1.46 29,491 993.3 0.82 33,533 490.2
5 1.38 31,756 872.9 0.99 33,634 589.1
Lot Size = 581 metric tons
Coal Use: Metallurgical
Feed (ng SO2/J)
y = 1,290 ax = 369.8 RSD = 0.29
Product (ng SO2/J)
y = 640.7 a = 103.2 RSD = 0.16
Sulfur Removal (%)
y = 48.3 a = 11.4 RSD = 0.237
Seem Coal
Lower Freeport - Kittaning B,C,D,E
Grab sanple taken every 15 nrLnuts over four hour period per day
154
-------
TABLE 2-24.. DAILY AVERAGE SULFUR REDUCTION BY A LEVEL III
PLANT - SOUTH WESTERN VIRGINIA SEAMS - 5 DAY
TESTS
PLANT H
PRODUCT
Day
1
2
3
4
5
%s kJAg
1.24 25,243
.92 24,178
.82 22,766
1.15 21,394
1.10 22,722
Lot Size = 2,395 - 2
Coal Use: Steam
Feed (ng SO2/J)
y = 903.0
Product (ng SO2/J)
y = 696.6
Sulfur Removal (%)
y - 21.7 a = 17.
Seam Coal
Elkhom-Rider
Lyons
Dorchester
Norton
Clintwood
ng SO2/J %S kJ/kg
984.7 1.48 33,997
761.1 1.31 33,666
722.4 0.89 33,226
1,075.0 1.06 33,617
971.8 1.10 34,074
,503 metric tons per day
a = 154. 8 RSD =
X
a = 133. 3 RSD =
jC
2 RSD =
% Feed
12.5
12.5
25
25
25
ng S02/J
872.9
778.3
537.5
640.7
645.0
0.17
0.19
.793
Grab sample taken every 15 minutes over four hour period per day
155
-------
TABLE 2-25 DAILY AVERAGE SULFUR REDUCTION BY A LEVEL III
CLEANING PLANT - W&USE COAL - 5 DAY TESTS
PLANT I
JbttHI) PRODUCT
Day %S_ kJAg ng SO2/J %S_ kJAg ng SO2/J
1 .603 16,466 735.3 .948 31,555 602.0
2 .637 18,936 675.1 .835 30,854 ^541.8
3 1.099 21,166 1,040.6 1.009 30,083 670.8
4 .570 20,206 563.3 .830 31,066 533.2
5 .582 18,377 636.4 .850 30,716 554.7
Lot Size = 544 metric tons
Coal Use: Metallurgical
Peed (ng SO2/J)
V = 731.0 a = 184.9 ng SO2/J RSD = 0.25
J£,
Product (ng SO2/J)
U = 580.5 a = 55.9 ng S02/J RSD = 0.099
2w
Sulfur Removal (%)
U = 18.3 a = 11.1 RSD = 0.605
GOB Coal (Refuse)
Grab sample taken evt;ry 15 minutes over four hour period per day
156
-------
It-is also noteworthy that the two preparation plants which did not
provide at least 35% reduction of PSD were cleaning blends of coal or
various ooals during the time period studied (i.e., Plant F cleans three
different seam coals and Plant H cleans a blend of five different coals).
To examine all the data received, avoiding conplete aggregation,
the information was analyzed on a seam and cleaning level basis. The
results are provided in Tables 2-26 through 2-29.(5 x) These tables show
that physical coal cleaning can be quite effective in reducing the ng
emissions from a coal boiler by 20-40 percent. The tables also snow that
Qertai.ii cleaning levels are wore effective than others for a given seaui
or region. Southern Appalachian low sulfur coal is an excellent example,
as one compares the effectiveness of cleaning level 4 to the ineffectiveness
of levels 2 and 3. In contrast, there is little differentiation between
the effectiveness~o£ levels 2, 3 "and 4 for coals in the Northern Appalachian
and Midwest regions.
The major assumption inherent in the tables presented is that the
infrequently sampled feed coal average values are representative of the
actual feed coal quality. In contrast, the product coals were sampled
on a regular basis, either mechanically or by ASTM methods on coal ship-
ments, because of coal product specification requirements. Product coal
quality is therefore considered quite representative of the actual coal
(52)
quality. Unless controlled tests are performed on commercial coal
cleaning plants, this major assumption will not be tested.
A second major source of performance data is a 1972 EPA survey of
(53)
air pollution potential from coal cleaning plants. This survey
included about 120 plants for which annual average feed and product coal
quality was obtained. The results of that survey are provided in Table 2-30.
The survey results generally support the conclusion that physical coal cleaning
157
-------
TABLE 2-26. EASTERN MIDWEST COAL SULFUR RUXICIMJLJN BY SEAM
AND CLEANING LEVEL
SEAM
Cleaning Level
2 3
Average
Reduction
Levels
4 2-4 Pts.
Illinois/Indiana #2 & 13
Illinois 15
Kentucky 19
Kentucky ill & 112
Viaigbtad Averages
5.6/3
o/i
4.2/4 33.2/22 26.3/18 34.9/1 30% 45
36.3/2
43.4/2
29.2/12
36.8/6
26.7A6
•
23.4/2
34.9/1 28%
43%
23%
29%
37%
22
2
2
13
6
Values shown are percent reduction in ng SOe/J/No. of data points.
TABLE 2-27. NCRIEERN APERLACHIA CCRL
SEAM AND CLEANING LEVEL
RHXJCTICN BIT
SEAM
denning Level
2 3
Average
deduction
Levels Data
2-4 Points
Pittsburgh, #8 (0/1)
19
Middle Kittaning (36)
Lower Preeport (I6A)
Lower Kittaning
Freeport
Weighted Averages (OA) 30.1/7 32.9/2 37.9/8 33%
Values shown are percent reduction in ng SO2/J/No. of data points.
*31end of 3,C,D,E , '3' predominates
21.5/1
32.0/6
30.6/13
19.0/2
23.0/2
48.4/5*
29.8/3
49.2/2
45.4/1
35.1/2
30%
19%
36%
23%
48%
35%
17
2
8
2
6
2
37
158
-------
TABLE 2-28. SOUTHERN APPALACHIA CCAL SULTOR REDUCTION BY
SEAM AND CLEANING LEVEL
Average
SEAM
Oriar Grove
Jewell
Pocahontas 3 & 4
Sewell
Various Sears
Weighted Averages
Values shown are percent
TAKE 2-29.
SEAM 1
Mary iee
Blue Creek
Cleaning Level resuut^o-ui
Level"*
I ill 2-4
11.3/3 -25.0/1 2%
34.0/4 34%
39.4/3 39%
11.5A 54.1/2 40%
0/2 14.3/12 29.3/14
2.6/5 14.1/13 31.2/24 23%
reduction in ng SOa/J/No. of data points
ALABAMA COAL SULFUR KilXJCTlON BY 'JKAM AMU
CLEANING LEVEL
Cleaning Level Average
Hedua2.on
234 Levels 2-4
40. V3 40%
42.8/2 43%
i
Data
Points
4
4
3
3
42
Data
Points
3
2
Weighted Averages 41.1/5 41%
Val'jes shown are percent reduction in ng SOz/J/lSo. of data points.
159
-------
TABLE 2-30. SOIFCR EMISSION RH30CTICN DMA 3ASED ON THE
1972 EPA SUHVES
NCN-METSLLUKGICaL O3AL
<
Region 2
N. Appalachia 17.2/10
S. Appalachian 20.7/8
S. Midwest 28.4/3
N. Appalachian 37.8/3
S. Appalachian 34.5/2
E. Midwest 1.95 A
Western 0
COMBINED
N. Appalachian 22.0/13
S. Appalachian 23.5/10
E. Midwest 21.3/4
Cleaning Level
3 4
25.5/2 35.5/8
7.4/10 16.2/14
16.4/8 20.7/3
METRLIOTGICSL COAL
40.9/2 46.7/5
16.5/8 28.S/27
-1.73/1 16.6/3
0 9/2
33.2/4 39.8/13
11.4/18 24.4/41
14.4/9 18.5/6
Mean
Levels 2-4
26.1
14.8
21.8
41.8
26.5
5.61
3.0
31%
21%
17%
•natal
Data Points
20
32
14
10
37
5
2
30
59
19
(Percentage ng SO2/J Heducticn/Ns- of Points)
160
-------
can significantly reduce the ng SO2/J emissions from industrial boilers,
although the average reductions are smaller. Relative to cleaning levels,
the reduction range is about the same as the Versar study, from 15 percent
to 40 percent.
A third source of performance data is a study on the sulfur reduction
potential of U.S. coals by physical and chemical coal cleaning techniques.
The report uses reserve base and washability data wnich are not based on actual
results of commercial coal cleaning but are'estimated from the data of
float-sink analysis by the U.S. Bureau of Mines,(55) 'Ihese data indicate
hypothetical enhancement of coal quality which could fce achieved by
beneficiation. Actual values will vary with each installation, reflecting
coal seam characteristics, mining procedures, and specific beneficiation
processes selected. The report simulates physical coal cleaning at two
different levels plus a hypothetical process:
• POC 1-1/2 inch, 1.6 s.g. Ohis process separates at 1.6 specific
gravity after crushing to 1-1/2 inch top size. No energy
penalties are iitposed other than those inherent in the
separation process.
• POC 3/8 inch, 1.6 s.g. or 1.3 s.g. Ihis process separates at
1.6 specific gravity after crushing to 3/8 inch top size
if this produces a coal to meet the standard; otherwise 1.3 s.g.
is used. An operating energy usage of 1 percent of the coal's
energy content is assumed, in addition to the energy loss inherent
in the separation process.
• Ninety percent pyritic sulfur removal. Ihis process is assumed
to remove 90 percent of the pyritic sulfur in the coal while
losing 10 percent of the weight and 5 percent of the energy.
An additional 2 percent energy loss is assumed as an operating
penalty.
161
-------
en
to
68 -
64 -
60 -
56 -
52 -
48 -
44 _
en
z
O 40
= 36
a 32
< 28
**
20
16
12
8
4
— RAW COAL
• PCC. 1-1 1/2 in., 1.6 S.G.
, • PCC, 3/8 in., 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVED
(TOTAL WEIGHT RAW COAL = 68.136.26 (10» TONS)
1.0
2.0
3.0
4.0
EMISSION LEVEL (IB, SO2/10b BTU), N. APPALACHIAN
FIGURE 2-23 N. APPALACHIAN RESERVE BASE AVAILABLE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOF VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
34
32
30
28
26
24
2 22
I 20
l-
5 18
H 5
O"» S
U) _i 16
I „
12
10
8
6
4
2
— RAW COAL
• PCC, 1-1 1/2 in., 1.6 S.G.
• PCC, 3J8 in,. 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVED
(TOTAL WEIGHT RAW COAL = 34,799.2 10s TONSI
1.0
2.0
3.0
4.0
EMISSION LEVEL (LB. SO2/10b BTUI, S. APPALACHIAN
FIGURE 2-24 S. APPALACHIAN RESERVE BASE AVAILABLE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
30 -
28 -
26
24
22
i20
I is
CO
16
14
12
10
8
6
4
2
— RAW COAL
• PCC. 1-1 1/2 in.. 1.8 S.Q.
• PCC, 3/8 in., 16 or 1.3 S.Q.
A 90% PYRITIC SULFUR REMOVED
(TOTAL WEIGHT RAW COAL = 2,971.83 (10s TONS)
1.0
2.0
3.0
4.0
EMISSION LEVEL (LB. SOj/IO0 BTU), ALABAMA
FIGURE 225 ALABAMA RESERVE BASE AVAILABLE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
72
68
64
60
56
52
48
| 44
g, 40
g 36
32
P 28
24
20
16
12
8
4
— RAW COAL
• PCC. 1-1 1/2 in.. 1.6 S.G.
• PCC, 3/8 in.. 1.6 or 1.3 S.G.
A 90% PYR1TIC SULFUR REMOVED
(TOTAL WEIGHT RAW COAL = 88.952.84 10* TONS)
EMISSION LEVEL (LB. SO2/10° BTU). E. MIDWEST
FIGURE 2 26 E. MIDWEST RESERVE BASE AVAILABLE AS A FUNGI ION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
a
I
£,
13
12
11
10
9
— RAW COAL
• PCC. 1-1 1/2 in.. 16S.Q.
• PCC. 3/8 in., 16 or 13 S.G
4 90% PYRITIC SULFUR REMOVED
(TOTAL WEIGHT RAW COAL ~ 18,972.07 10* TONS)
1.0
2.0
EMISSION LEVEL (LB. S02/106 BTU). W. MIDWEST
FIGURE 2-27 W. MIDWEST RESERVE BASE AVAILABLE AS A FUNCTION OF
EMISSION CONTROL LEVEL FOR VARIOUS PHVSICAL COAL CLEANING LEVELS
-------
1
1
— RAW COAL
• PCC. 1-1 1/2 in.. 1.6 S.G.
• PCC. 3/8 in.. 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVED
(TOTAL WEIGHT RAW COAL = 203,721.88 (10" TONS)
1.0
2.0
3.0
4.0
EMISSION LEVEL (LB. SO2/10b BTU), WESTERN
FIGURE 228 WESTERN RESERVE BASE AVAILABLE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
oo
360
340
320
300
280
260
240
220
200
18°
160
O 140
120
100
80
60
40
20
— RAW COAL
• PCC. 1-1 1/2 in.. 1.6 S.G.
• PCC, 3/8 in.. 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVED
(TOTAL WEIGHT RAW COAL = 417.554.07 10* TONS)
1.0
2.0
3.0
4.0
EMISSION LEVEL (LB. SO2/106 BTU). ENTIRE U.S.
FIGURE 2-29 ENTIRE U.S. RESERVE BASE AVAILABLE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
CTi
V£>
1700 ,-
1500 -
1300
1100
55
|
2 900
U)
700
500
300
100
— RAW COAL
• PCC, 1-1 1/2 in., 1.6 S.G.
• PCC. 3/8 in., 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVED
A •
TOTAL QUADS OF RAW COAL = 1728.37
1.0
2.0
3.0
4.0
EMISSION LEVEL (LB. SOj/106 BTU). N. APPALACHIAN
FIGURE 2 30 ENERGY AVAILABLE IN N. APPALACHIAN RESERVE BASE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
H
•~J
O
— RAW COAL
• PCC, 1-1 1/2 in, 16 SO
• PCC, 3/8 in.. 1.6 or 1.3 S.G.
A 90% PYHITIC SULFUR REMOVED
TOTAL QUADS OF RAW COAL = 927.43
1.0
EMISSION LEVEL (LB. SOj/IO6 BTU). S. APPALACHIAN
FIGURE 2-31 ENERGY AVAILABLE IN S. APPALACHIAN RESERVE AS A FUNCTION OF EMISSION
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
80
70
60
_ 50
in
a
O
b 40
30
20
10
— RAW COAL
• PCC, 1-1 1/2 in., 1.6 S.G.
• PCC, 3/8 in., 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVED
TOTAL QUADS OF RAW COAL = 78.09
2.0
3.0
4.0
EMISSION LEVEL (LB. SO2/106 BTUI. ALABAMA
FIGURE 2 32 ENERGY AVAILABLE IN ALABAMA RESERVE BASE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
1700
1500
1300
— RAW COAL
• PCC. 1-1 1/2 in., 1.6 S.G.
• PCC, 3/8 in., 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVAL
TOTAL QUADS OF RAW COAL = 1998.69
w
§
d
I
1100
900
P 700
500
4.0
EMISSION LEVEL (LB. SO2/10° BTU|, E. MIDWEST
FIGURE 233 ENERGY AVAILABLE IN E. MIDWEST RESERVE BASE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
360
340
320
300
280
260
240
_ 220
M
Q
^ 200
O
UJ
180
CD
-J 160
140
120
100
80
60
40
20
— RAW COAL
• PCC. 1-1 1/2 in., 1.6S.G.
• PCC. 3/8 in.. 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVED
TOTAL QUADS OF RAW COAL = 439.54
4.0
EMISSION LEVEL (LB. S02/10 BTU). W. MIDWEST
FIGURE 2-34 ENERGY AVAILABLE IN W. MIDWEST RESERVE BASE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
3600
3200
2800
: A
2400
(A
2000
1
I
1600
1200
800
— RAW COAL
• PCC, 1-1 1/2 In., 1.6 S.G.
• PCC. 310 in.. 1.6 or 1.3 S.G.
A 90% PYRITIC SULFUR REMOVED
TOTAL QUADS OF RAW COAL - 3662.29
400
1.0 2.0
EMISSION LEVEL ILB. SOj/106 BTU). WESTERN
3.0
4.0
FIGURE 235 ENERGY AVAILABLE IN WESTERN RESERVE BASE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
9000 r-
8500 -
8000 -
7500 -
7000 h
6500
6000
_ 5500
O
§ 5000
o
j£ 4500
-i 4000
H
° 3500
3000
2500
2000
1500
1000
500
RAW COAL
PCC. 1-1 1/2 in.. 1.6 S.G.
PCC, 3/8 in., 1.6 or 1.3 S.G.
90% PYRITIC SULFUR REMOVED
TOTAL QUADS OF RAW COAL = 8834.41
2.0
3.0
4.0
EMISSION LEVEL (LB. SO2/10b BTU), ENTIRE U.S.
FIGURE 2 36 ENERGY AVAILABLE IN ENTIRE U.S. RESERVE BASE AS A FUNCTION OF
EMISSION CONTROL LEVELS FOR VARIOUS PHYSICAL COAL CLEANING LEVELS
-------
Consistent with the studies discussed above, the overlay curves
(Figures 2-23 through 2-36) show the quantity of conpliance coal that can
be produced by coal cleaning at various emission standards. The curves
show that coal cleaning is most effective in Northern Appalachia, where
four times as much clean coal can comply with a 516 ng S02/J (1.2 Ib
S02/106 BTU) control level than raw coal. By contrast, physical coal
cleaning can only achieve a 25 percent increase in conpliance coal in
Southern Appalachia, and a 15 percent increase in compliance Western coal
reserve base. In the entire U.S., as shown in Figure 2-29, coal cleaning
can produce an additional 36 billion metric tons of compliance coal,
assuming a 516 ng S02/J emission control level.
Product Variability
Along with feed and product data, Versar studied product sulfur and
BTU variability for different coal lots fran the same cleaning plant or
mine. 6' The feed coals were primarily fron Eastern Midwest cleaning
plants and Norttiern Appalachia, although Western Midwest and Western coals
were also represented.
The data included 33 data sets for unwashed coals, consisting of a
total of 4,209 data points (lots); and 25 data sets for washed coals,
consisting of 692 data points. Included in the "unwashed" category were
run-of-mine (RDM) coals and coals cleaned to Level I (sizing to remove
large rock).
The "washed" category included Level II and higher coal preparation,
where specific-gravity separation is conducted on one or more size
fractions.
For each set of data points (lots), the mean (Y), the standard
deviation (Sy), and the relative standard deviation (PSD or Sy/Y~) were
calculated for:
Yi = Total sulfur content, percent
Y2 = Heating value, BTU/lb
Y3 = Heat-specific SO2 content, Ibs SO2/Md BTU
.176
-------
In each of the plants for which matched pairs of feed and product
data were available, both the absolute standard deviation and the relative
standard deviation for all three coal characteristics were reduced by
the coal preparation process. The reductions in both percent sulfur
variability and Ibs S02/MM BTIT variability were approximately 60 percent,
while the heating value variability was reduced by approximately 80 percent.
Data from 20 sets of unwashed coal data and from 17 sets of washed
coal data did not permit direct comparison of feed and product pairs. A
second statistical analysis, conducted to exploit the entire available
data base, conpared the data sets of all unwashed coals to the data sets of
all washed coals. This indirect approach is hampered because the two
groups of data sets do not form logically-consistent or homogeneous
populations sufficient for rigorous statistical analysis. Because of
these inherent compatibility problems, the results of this second
statistical analysis should not be regarded as definitive as those of the
first analysis. Despite the limitations of the statistical treatment, the
comparison of variabilities of the twD groups of data sets surely suggest
that the variability is reduced by the coal cleaning process. The reductions,
from unwashed coals to washed coals, range fron 25 to 64 percent depending
upon how variability is measured. These results are consistent with the
percent reductions in variability derived from the paired feed/product data
sets.
Nine data sets (which accounted for 2,373 data points) were examined
in three ways: without transformation, with a logarithmic transformation,
and with a radical transformation. The distributions of the untransformed
and transformed data were tested for normality. Six of the nine batches
satisfied the chi-square test (for Ibs SO2/MM BTU) for normality, with
either the untransformed data or the transformed data. The three batches
failing the test failed regardless of whether the data were transformed or
not. These results indicate the absence of sensible evidence for preferring
any one distribution over the others.
177
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Tests for autocorrelation of the data points within data sets gave
positive results in 16 of 48 data sets (at the 95 percent confidence level).
There is little doubt, therefore, that much of these coal data are serially
correlated, verifying the expectations based upon geology and engineering
rationale.
For each of 16 data sets which exhibited autocorrelation, the total
variance (of Ibs SO2/*M BTU) was resolved into the long-term component,
associated with the serial correlation according to geostatistical concepts,
and the residual short-term (including sampling and analysis) component.
An estimate of a generalized long-term component of relative standard
deviation was 0.052, applicable to both unwashed coals and washed coals.
Fran previously-published data representing actual cccimercial
practice, the component of relative standard deviation attributable to
ASTM coal sampling, sample preparation, and laboratory analysis (in terms
of Ibs S02/MM BTU) was 0.045 for unwashed coals and 0.023 for washed coals.
These values are smaller than the 0.07 to 0.08 maximum permitted by the
ASTM protocols.
Estimates of the components of variability are:
PSD for long-term
ESD for short-term
BSD for S&A
(ESD) total for each source
Uncleaned
coals
0.052
0.096
0.045
0.118
Cleaned
coals
0.052
0.053
0.023
0.078
It must be emphasized that these are generalized estimates, representing
aggregated data sets. In no way may these values be utilized to characterize
any one particular coal. Actual variabilities of individual data sets may
be quite different from the generalized values shown above.
A prior study concluded that the relative standard deviation should
be inversely related to lot size. By removing the long-term component of
variability (which through autocorrelation interferes with the theoretical
and empirical rationale of the prior study) from data in this study, an
178
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inverse relationship between the short-term conponent of BSD and lot size
was demonstrated. A least-squares line had a correlation coefficient of
0.6, indicating a much clearer inverse relationship than was previously
determined.
A simulation of product coal variability was performed in conjunction
with the Reserve Processing Assessment lyfethodology. The variability
of the sulfur content of the coal was taken into account by assuming the
maximum coal sulfur emission upon combustion to be
e =uc (1 +
where a , a coal variability coefficient, was taken to be 2.0 (97.7 percent
c
confidence level, and v is the mean coal sulfur value that must not be
exceeded in order to achieve a maximun emission level e. The relative
standard deviations (RSD) used are given in Table 2-31. These RSD values
for Eastern coals are larger than the results of the Versar product
variability study for large lot sizes. The BSD values for Western coals
could not be verified because of a lack of independent data.
The geographical regions used are as follows:
(1) Northern Appalachia
(2) South Appalachia
(3) Alabama
(4) Eastern Midwest
TABLE 2-31
RELATIVE STANDARD DEVIATIONS POSTULATED FOR RAW AND WASHED
GOALS FOR INDUSTRIAL BOILERS
Relative Standard Deviations
Eastern Western
Raw Washed Raw Washed
24 hour averaging, 0-28 0-10 0-07 0-07
75 x 106 BTU/hr
30 day averaging, 0-19 0-07 0-04 0.04
75 x 106 BTU/hr
179
-------
(5) Vfestem Midwest
(6) Western
(7) Entire U.S.A.
The physical cleaning processes used are as follows:
Bl. 1-1/2 inch, 1.6 s.g. This process separates at 1.6 specific
gravity after crushing to 1-1/2 inch size. No energy penalties
are imposed other than those inherent in the separation process.
B2. 3/8 inch, 1.3 s.g. This process separates at 1.3 specific
gravity after crushing to 3/8 inch mesh. An operating energy
penalty of 1 percent is assumed, in addition to the energy
loss inherent in the separation process.
B3. 1.6 separation on sink of 3/8 inch, 1.3 s.g. This process gives a
middling product from the refuse of process B2. The sink from the 1.3
specific gravity separation at 3/8 inch mesh is further
separated at 1.6 specific gravity. The operating energy
penalty assumed is the 1 percent of process B2, in addition
to that inherent in the separations.
B4. Ninety percent pyritic sulfur removal. This process is assumed
to remove 90 percent of the pyritic sulfur in the coal while
losing 10 percent of the weight and five percent of the energy.
An additional 2 percent energy loss is assumed as an operating
penalty.
The results of the simulation are presented in Tables 2-32 and 2-33. ^59^
Table 2-32 shows the percent energy of the reserve base available, by
region, to meet emission control levels of 516 (1.2), 860 (2.0), 1,290 (3.0)
and 1,720 (4.0) ng SO2/J (Ib SO2/106 BTU) if the coal is cleaned prior to
combustion by these physical cleaning processes. A floor of 86 ng SOz/J
(0.2 Ib SOz/106 BTL) was used for all these emission control levels; if the raw
coal emission level is below this floor, cleaning is assumed to be
unneoassary. for comparison purposes, the percent energy of raw coal
that meets the standards is also shown. Values are given both ignoring
180
-------
T&ELE 2-32 PERCENT ENERGY AVAILABLE FOR VARIOUS EMISSION LIMITS AND
PHYSICAL COAL CLEBNINS PROCESSES
REGION
CO
Bl
516 (1.21
82 03 B«»
660 (2.0)
RAH 01 82 03 b<* RAM
Variability Ignored
1290 (3.0)
Dt 02 63 3«i RAM
Bl
1720 (<».0)
82 93 0«.
24-hr Average, 75-mm Btu/hr
30-day Average, 75 mm Btu/hr
1
2
3
-------
sulfur variability and averaging sulfur variability over 24 hours and
30 days for a 75 x 106 BTU/hr boiler. Cleaning the reserve base coals
prior to combustion significantly increases the amount of coal that is
available to meet the control levels, even for cleaning process B3, which
gives only a middlings product.
Table 2-33 shows, for each region and in both ng S02/J and Ibs SO2/106
BTU, the emission control levels that can be set (both considering and ignoring
sulfur variability) while obtaining 50 percent and 25 percent availability
of the reserve base.
The results indicate that for a stringent control level of 516 ng SOa/J
(1.2 Ibs SO2/106 BTU) for industrial boilers nationwide the amount
of coal energy available can be increased from 6-15 percent. Also,
physical coal cleaning provides a greater increase of available reserves
for the shorter averaging time (i.e., 24-hour average). Of more significance
is that the increased available energy comes primarily from regions 1, 2,
and 3 (i.e. N. Appalachia, S. Appalachia, and Alabama respectively). These
regions are considerably closer to the areas of industrial coal demand than
region 6 (Western).
The results are quite similar for an intermediate control level of 860 ng
SO2/J (2.0 Ibs SOz/106 BTU). Howsver, as the control level becomes less restric-
tive the raw coal energy reserve base and physically-cleaned coal reserve
base begin to converge. Note that for the moderate control levels, regions 1 and
4 (E. Midwest) provide the differentia] increase in energy reserves due to
cleaning.
Under no circumstances does physical coal cleaning decrease the available
energy reserve even though the coal refuse does contain some energy value.
The primary reason is that the more uniform cleaned product (i.e.,lower PSD) per-
mits higher average sulfur content coal to meet the control level.
Table 2-33 illustrates another important aspect of coal cleaning which
is that for a desired percentage of compliance reserve base, a more stringent
control level can be promulgated. Assuming that new industrial boilers require the
best available physical coal cleaning product, the control levels can be reduced by
30-65 percent over the raw coal scenario. Given a)that no less than 25 percent.
of any regions reserve base can be excluded from the emission control level and
182
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TABLE 2-33.
PCC PROCESSES. EMISSION CONTROL LEVELS THAT CAN BE MET BY 50
PERCENT AND 25 PERCENT OF THE ENERGY AVAILABLE
REGION
1
2
3
*»
5
6
7
1
2
3
1161
902
172
258
1075
386
516
2192
2020
330
386
75xl06Btu/hr
923
i»12
515
1857
1352
195
3f»'4
670
'•* 12
515
16^1
1568
196
31* <•
1083
'+&<»
515
2373
2205
2"»5
336
619
361
U6U
1393
1029
196
309
1676
603
SOU
3U21
2303
3^*3
516
, 75xl06Btu/hr
832
392
t»90
176'*
176i»
135
300
637
392
V9 0
1569
1 1*8 6
185
300
1329
VUl
1*90
225«t
2089
232
386
593
3V3
'•Ul
1323
975
185
253
1<«33
53U
712
3G26
2182
325
1*30
(lb S02/106 BTU)
Variability Ignored
2.9
1.1
1.5
V.6
5.7
.6
!.<>
3.5
1.3
1.8
5.5
6.5
.7
1.7
2.3
1.0
<*.2
<*.b
.6
1.3
2.S
1.2
1.7
5.0
5.0
.7
1.6
3.6
1.1
1.6
5.3
7.0
.8
1.7
fc.3
1.3
1.9
7.0
8.0
.9
1.9
1.9
1.3
1.?
3.6
3.1
. 6
1.2
24-hr
2.3
1.2
1. <»
«».3
3.5
.7
1.5
-------
b) BACT for physical ooal cleaning, then the roost stringent control level is
1,393 ng S02/J (3.2 Ibs S02/106 BUJ). This compares to a most stringent value
of 3,421 ng 902/J (8.0 Ibs S02AO BTO) for raw coal.
Impacts on Boilers
Physical cleaning of ooal should improve the overall performance of
a stoker-fired boiler provided the resultant coal size is acceptable for
stoker firing (1-1/2 x 1/4 with minimal fines). Excess fines produced
during cleaning must be sold for pulverized boiler operations or other
uses, however, if the primary market is stoker-fired boilers, Physical
cleaning partially removes pyrites, ash, and other impurities, thus re-
ducing both SO2 and particulate emissions. As compared to raw ooal,
physically cleaned coal is easier to feed, burns more uniformly with less
chance for clinkering, and reduces ash disposal problems.
As an example, both a raw and the corresponding physically cleaned
coal were fired in a steam plant spreader-stoker boiler. *2 When firing
the raw ooal, the boiler could operate only at about one half capacity.
Ihe high ash content of this coal resulted in non-uniform combustion
caused by feeding problems, excessive ash buildup and clinker formation
of the fuel bed. In contrast, the physically cleaned coal was fired at
full capacity with no operational problems.
There are handling problems for the boiler operator associated with
fine coal, including a tendancy to compact under pressure, absorb moisture,
form dust, and create the possiblity of dust explosions.
Operating Factors
The use of physically cleaned coal (POC), rather than raw ooal will
modify plant operations; in turn these modifications will influence the
extent to which PCC will be used. Examples of how PCC will affect plant
capacity and plant availability include the following.
• Stokers Oised with many industrial boilers producing less than
about 180,000 kg steam per hour) may have difficulty operating
with the coal particle size distribution resulting from the
comminution that precedes PCC.
• Where pulverized ooal boilers are used, the smaller particle
sizes are desirable ; less capacity and maintenance are required
of the pulverizers when the incoming particle sizes are smaller.
184
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• Removing incombustible matter in ooal (up to 70-80 percent via
PCC) decreases the need for (1) handling ooal, (2) handling and
disposing of ash, and (3) controlling fly ash emissions.
• Removing incombtistible mineral matter may also reduce mainten-
ance problems, thereby increasing plant availability. For
example, less iron implies a higher fusion temperature
and therefore less wall slagging; less sodium implies less
fouling; less ash (the incombustible mineral material left behind
when coal burns completely) can mean less plugging of the bottom-
ash hopper.
• Where POC reduces the percentage of ash in the boiler (to, say
2 to 3 percent) it may become economical to use anti-fouling and
anti-slagging additives during combustion in order to increase
plant availability.
• A negative effect of lowering the sulfur content is the lowering
of the conductivity of the fly ash and a consequent derating of
the fly ash removal capacity of an electrostatic precipitator for
a given quantity of fly ash. However, since the quantity of fly
ash is decreased by PCC, this derating may, in fact, be unimportant.
Overall, the factors mentioned above liave a positive effect on
both plant capacity and plant availability. To the extent that the effects
of these factors can be quantified, they must be weighed against the
marginal costs of PCC for specific coals and PCC processes, as well as the
specific changes in the properties of the coal resulting froir PCC.
Firing of physically cleaned coal in industrial stoker-fired boilers
is not expected to have a significant effect on boiler maintenance costs.
In industrial pulverized coal boilers, firing of physically cleaned coal may
reduoa boiler maintenance costs.
185
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Impact of Goal Variability Upon Boiler Operation
The variability of coal has a large effect upon the ability and costs
for boiler operators to comply with existing or proposed emission regula-
tions. An emission control level, expressed as a maximum value for ng SO2/J,
to be exceeded only for a specified percentage of the tine, has the effect
of requiring a coal with a mean ng SO^J value lower than the emission
control level.
General Relationship
The relationship between yc, the mean coal value for ng S02/J; and E,
the emission control level value in ng SO2/J, has been defined by EPA:l60'
yc = 1 , (1)
E 3(l+t RSD )
ex c
where 3 = the fraction of sulfur in the coal which is emitted (less
losses to bottom ash and fly ash). For the industrial
boiler study, it is assured to be 0.95.
t = The one-tailed Students' "t" value assuring a percentage
compliance time of a.
RSD = The relative standard deviation for ng SO2/J.
c
This relationship assumes a normal temporal distribution of ng SO2/J
values within a coal batch; it does not relate to the log-normal distri-
bution of standard deviations among batches.
As presented earlier, RSD may be expressed as a function of the lot
size T (tons):
(RSD ) unwashed coals = 0.205-0.0216 logi0T
C
(RSD ) washed coals = 0.159-0.0216 log10T.
c
Substituting into Equation 1,
For unwashed coals:
yc = -,
E
(0.205-0.0216 logioT)] (2)
186
-------
and washed coals:
E B [14^(0.159-0.0216 logioT)] (3)
These equations were applied to the reference boilers (i.e. 8.8, 22, 44,
and 58.6 M7) and the reference ooals to determine the maximum emission
control levels that the boiler operator could meet. The results are
presented in Table 2-34.
The overall conclusion reached from inspection of Table 2-34 is that
wide ranges of the emission level (E), from 1.04 to 8.15 pounds S02 per
million BTU, may be achieved under varying conditions of coal type,
physical coal cleaning accomplished, boiler size, averaging time, and
percentage compliance. The effect of physical coal cleaning is to reduce
the achievable emission level by three complementary mechanisms: sulfur
removal, heating value enhancement, and variability reduction. The data
indicate that coal cleaning can comply with emission control levels as
much as 76 percent below uncontrolled emissions and, more importantly,
can provide a 35 percent reduction in complying emissions from low sulfur
coal. It is noted that the effect on low sulfur western coal is minimal,
producing less than a 5 percent reduction in complying emissions.
Environmental Considerations
A company that plans to install a coal-burning boiler will evaluate
the use of PCC in terms of plant operations and applicable pollutant
constraints. In this section we describe qualitatively how air pollution
emission standards may affect the use of PCC and how PCC can affect boiler
and other plant operations.
Although we are primarily concerned here with controlling the level
of S02 emissions, we observe that PCC, by removing a large percentage of
coal's incombustible material, results in less fly ash being formed during
combustion. Therefore, there can be a lower design capacity for controlling
emissions of particulates and for sluicing, storing, and disposing of ash
and there will be a smaller quantity of trace elements and polycyclic
particulate matter in the coal being burned.
187
-------
TABLE 2-34
ACHIEVABLE VALUES OF E (ng SO2/J Emission Level)
Boiler
Feed Coal
Fi
High-Sulfur
Pan tern,
Paw Goal
pc = 5.79
Ft
High-Sulfur
Eastern,
Cleaned Wt 1
PC = 1.50
Ft
High-Sulfur
Eastern,
Cleaned Pdt 2
lie - 2.48
Fs
low-Sulfur
Eastern,
Raw Goal
PC - 1.73
F,
low-Sul fur
Eastern,
Cleaned Fdt
tic = 1.22
r«
lew-Sulfur
Western,
Raw Coal
pc = 1.04
FT
low Fulfur
Western,
Cleaned Pdt
pc = 1.03
Boiler
Bi
B2
Bi
B5
Bi
B,
B,
Bs
Bj
Bi
Bz
B,
B*
Bj
Bi
Bi
BI
B.,
B,
Bi
Bi
Bi
B*
BS
Bi
Bi
Bj
Bi,
B«
Bi
B2
BI
B*
Bs
0 « 3 hours
o=99
8.15
8.02
7.93
7.90
7.61
1.95
1.92
1.89
1.89
1.81
3.23
3.18
3.14
3.12
3.01
2.44
2.40
2.38
2.36
2.28
i.s9
1.56
1.54
1.54
1.48
1.40
1.38
1.37
1.36
1.31
1.34
1.32
1.30
1.29
1.24
0=95
7.32
7.23
7.17
7.15
6.95
1.7ft
1.76
1.74
1.74
1.69
2.96
2.92
2.89
2.88
2.80
2.19
2.16
2.15
2.14
2.08
1.45
1.44
1.42
1.42
1.38
1.26
1.25
1.24
1.23
1.20
1.22
1.21
1.20
1.19
1.16
0=85
6.62
6.57
6.53
6.52
6.40
"1.65
1.63
1.62
1.62
1.59
"2.7J
2.71
2.69
2.68
2.63
1.90
1.97
1.96
1.95
1.91
1.34
1.33
1.32
1.32
1.30
1.14
1,13
1.13
1.12
1.10
1.13
1.12
J.02
1.11
1.09
0 " 24 hours
0«99
7.94
7.82
7.73
7.69
7.42
1.90
1.86
1.84
1.83
1.76
3.14
3.09
3.05
3.03
2.92
2.39
2.34
2.31
2.30
2.22
1.55
1.52
1.50
1.49
1.44
1.37
1.35
1.33
1.33
1.28
1.30
1.28
1.26
1.26
1.21
0=95
7.17
7.09
7.04
7.01
6.82
1.75
1.73
1.71
1.70
1.66
2.6§ -
2.86
2.84
2.82
2.74
2.15 '•'
2.12
2.10
2.10
2.04
1.42
1.41
.39
.39
.35
.24
.22
.21
.21
1.18
1.20"
1.19
1.17
1.17
1.14
o«85
6.54
6.49
6.45
6.43
6.31
1.62
1.61
1.60
1.60
1.57
2.69
2.67
2.65
2.65
2.60
1.95
1.94
1.93
1.92
1.89
J.32
1.31
1.31
1.30
1.20
1.13
1,12
1,11
1.11
.1.09
1.12
1.11
1.10
1.10
1.08
9 = 1 Week
o=99
7.68
7.57
7.48
7.45
7.17
1.83
1.80
1.78
1.77
1.70
3.03
2.98
2.95
2.93
2.81
2.30
2.26
2.24
2.23
2.15
1.49
1.47
1.45
1.44
1.38
1.33
1.31
1,29
1.28
1.24
1.26
1.23
1.22
1.21
1.16
0=95
7.00
6.92
6.85
6.84
6.65
1.70
1.68
1.67
1.66
1.61
'2.B2
2.79
2.76
2.75
2.67
2.10
2.07
2.05
2.05
1.99
1.39
1.37
1.36
1.35
1.31
1.21
1.19
1.18
1.18
1.15
1.17
1.15
1.14
1.14
1.11
o=B5
6.43
6.38
6.34
6.33
6.21
1.50
1.58
1.57
1.57
1.54
"2.65
2.62
2.61
2.60
2.55
1.92
1.91
1.90
1.89
1.86
1.30
1.29
1.28
1.28
1.26
1.11
1.10
1.09
1.09
1.07
1.10
3.09
1.08
1.08
1.06
0 » 1 month
o=99
7.50
7.38
7.29
7.26
6.98
1.7fl
1.75
1.73
1.72
1.65
2.95
2.90
2.86
2.85
2.73
2.25
2.21
2.18
2.17
2.09
1.45
1.43
1.41
1.40
1.34
1.29
1.27
1.26
1.25
1.20
1.22
1,20
1.18
1.18
1.13
0=95
6.88
6.79
6.73
6.71
6.52
1.67
1.65
1.63
1.63
1.58
2.77
2.73
2.71
2.69
2.61
1 2.06
2.03
2.01
2.01
1.95
1.36
1.34
1.33
1.33
1.29
1.19
1.17
1.16
1.16
1.12
1.15
1.13
1.12
1.12
1.08
0=85
6.35
6.30
6.27
6.25
6.13
1.5IT
1.56
1.55
1.55
1.52
2.61
2.59
2.57
2.57
2.52
1.90
1.89
1.87
1.87
1.83
1.28
1.27
1.27
1.26
1.24
1.10
1.09
1.08
1.08
1.06
"LOB
1.07
1.07
1.06
1.04
00
CO
-------
The following table summarizes the results of an analysis of trace-
element depletion caused lay washing three major types of coal. ^61^ The
table shows that, whereas only 9 to 18 percent of the coal was left
behind in the dense-medium sink used in the studies (1.6 specific gravity),
26 to 54 percent of all the measured trace elements remained in the 1.6
sink fraction.
TABLE 2-35. AVERAGE % OF ALL TRACE ELEMENTS IN THE 1.60 SINK FRACTION^6
Average % of Trace Elements Average % of Coal
in Sink 1.60 Fraction in Sink 1.60 Fraction
Appalachian
Mid Western
Far Western
All Goals
54
37
26
38
18
10
9
13
Documentation
The desulfurization potential of the entire U.S. coal reserve was
characterized by individually calculating, for each coal bed and county,
the effectiveness of several coal cleaning processes in removing ash,
pyritic sulfur., and organic sulfur, in recovering material and energy,
and then by geographically aggregatincr the results to the state, regional,
and national levels. The calculation required three types of data for
the coal reserves in each bed/county unit:
1. The quantity of the reserve. These data were taken from the
Bureau of Mines reserve data base, consisting of 3,167 records
specifying the weight of each resource for both strip and
underground coal, together with the maximum, minimum, and mean
levels of the major constituents of the coal in that resource.
These data are consistent with those summarized in Thomson and
1*3* and Hamilton, rthite and Matson.
The composition of the reserve. Approximately 50,000 detailed
sample coal analyses were taken from the coal data base of the
U.S. Bureau of Mines in Denver, Colorado. These data include
189
-------
the composition of each sample in terms of its ash, sulfur, and
heat content.
3. The washability of the reserve. The float-sink analyses were
used for 587 coal samples, as reported by Cavallaro, Johnson,
and Deurbroudc in RI 8118.(s9)
Given these three sets of data as a starting point, the first step
in the analysis was to overlay them into a single data base which contained
the following information for each record:
• The location in terms of its region, state, county, and bed;
• The weight in tons of both strip and underground coal;
• The mean percent by weight of ash, organic sulfur, and
pyritic sulfur;
• The mean heat content expressed in BTU/lb; and
• The float-sink distribution of the coal characteristics.
A fundamental problem in overlaying the three types of data was that
an exact correspondence of reserve elements (coal bed and county) did
not exist among the three data files. Furthermore, washability data were not
available for many of the reserve elements, and multiple sets of composition
data corresponded to individual reserve elements. These problems were
overcome by rational matching, averaging, data rejection, and extrapolation
techniques, so that a single internally-consistent (complete and single-
value) file of approximately 36,000 records was obtained. Each record
consists of the resource identification (by state, bed, and county),
the weight of coal for both strip and underground recovery techniques,and
the composition of the coal. Also each record is identified with a set of
washability analysis data.
The result ant comprehensive coal reserves data file was then operated
upon by physica.' and chemical coal cleaning processes. The results of
each calculation were, for each bed/county reserve element, the weight
and energy of cleaned coal recoverable by each process and the ash and
pyritic and organic sulfur content of the processed coal. No allowance
was made for process inefficiency (misplaced material) in this calculation.
These bed/county processed coal quantities and characteristics were then
190
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aggregated into state and regional values. The results were displayed
as the quantities (of ooal material or of energy) in each region (when
prooassed by one of several alternative ooal cleaning techniques) which
complied with predetermined levels either of sulfur content or of sulfur
dioxide equivalent per unit of heating value.
2.2.3 Chemical Coal Cleaning
A variety of chemical coal cleaning processes are under development
which will remove a majority of pyritic sulfur from the coal with accept-
able heating value recovery, i.e., 95 percent BTQ recovery. Some of these
processes are also capable of removing organic sulfur from the coal, which
is not possible with the physical coal cleaning processes. However, none of
these chemical ooal cleaning processes are expected to be commercially
available before 1985.
This section presents available technical information of eleven major
chemical coal cleaning processes. A detailed evaluation is included on
each process in a format that identifies:
• Process details;
• Developmental status; and
• Technical evaluation.
The first three processes discussed are capable of reducing only the amount
of pyritic sulfur in the feed coal; the next seven processes are
capable of reducing both pyritic and organic sulfur.
2.2.3.1 System Description
TEW MEYERS' CHEMICAL COAL CLEANING PROCESS
Process Description
The Meyers' process, developed at TRW, is a chemical leaching process
using ferric sulfate and sulfuric acid solution to remove pyritic sulfur
from coal. The leaching takes place at temperatures ranging from 50° to
130°C (120°-270°F) and pressures from 1 to 10 atmospheres (15-150 psia) with
a residence time of 1 to 16 hours. Process development and optimization
studies conducted to date have included a number of alternative processing
methods.
Some of the variations which have been tested and considered are:
191
-------
• Air vs. oxygen for regeneration;
• Coal top sizes from 0.64 cm (% inch) to 100 mesh;
• leaching and regeneration in the same vessel and in
separate vessels; and
• Removal of generated elemental sulfur by vaporization or
solvent extraction.
Current development work is directed toward elemental sulfur recovery
by acetone extraction. This system appears to be promising and may prove
to be economical. However, since the technical and economic feasibility
of this modification has not yet been proved, Versar, with TIW's
concurrence, elected to assess their most promising process for fine
coals (top size of 8 mesh or finer). Ihis system includes the removal
of elemental sulfur with superheated steam. The flow sheet for this
preferred system is shown in Figure 2-37. The. diagram includes the four
distinct sections of the process which are described below. ^6 3'
Reaction Circuit—
Crushed coal, with a nominal top size of 14 mesh, is mixed with hot
recycled iron sulfate leachant. The mixing is performed in a continuous
reactor with about 15 minutes residence time. The wetted coal, having
undergone about 10 percent pyrite extraction in the mixer, is introduced
into the reaction vessel at about 80 psig and about 102 °C (215 °F). In
this step, about 83 percent of the pyrite reaction takes place under
conditions of 5.4 atm. (80 psi) and 118°C (245°F), with varying residence
time for different coals. Oxygen from an oxygen plant, which is an
integral part of the coal cleaning plant, is simultaneously added to
regenerate the leachate. The slurry then moves to a secondary reactor
where the reaction continues to about 95% completion.
Wash Circuit—
The iron sulfate leachate is removed from the fine coal in a series
of countercurrent washing and separation steps. The slurry from the
secondary reactor is filtered and washed with water. Both the filtrate
and the wash water are sent to the sulfate removal circuit. The filter
cake is reslurried, filtered a second time , reslurried with
recovered clear water,and finally dewatered in a centrifuge.
192
-------
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FIGUEE 2-37 TFW (MEYER'S) PROCESS FLOW SHEET
-------
Sulfate Removal Circuit—
The prime function of this circuit is to concentrate the leachate for
recycle. The filtrate and the wash water from the first stage filter are
fed to a triple effect evaporator which recovers most of the wash water.
The byproduct iron sulfate crystals that are found in the third evapora-
tion stage are removed from the concentrated leachate and stored or sent to
disposal. The remaining wash water from the first filter is partially
neutralized with lime to precipitate a gypsum byproduct. The partially
neutralized wash water is combined with the dilute leachate from the
centrifuge and recycled to the process as leach solution.
The fuel requirement of this circuit is equal to a few percent of the
product coal. Makeup water is needed to replace water of crystallization
and water vaporization losses due to vacuum filters and vacuum evaporator.
Sulfur Removal Circuit—
Wet coal from the centrifuge is flash-dried by high temperature steam
which vaporizes both the water and the sulfur. The dry coal is separated
from the hot vapors in a cyclone and cooled to give the clean product.
The hot vapor from the cyclone is scrubbed with large quantities of recycled
hot water from the evaporator. The gas and liquid phases from the gas
cooler are separated in a cyclone. The liquid stream from the cyclone which
contains water and sulfur is phase-separated in a vessel. The gas phase
consisting of saturated steam is compressed, reheated and recycled to the
drier.
It is recognized that the processing steps and equipment needed for
recovering sulfur from fine or suspended coal sizes would be different from
those required for coarser material. The process developer's claim is that
coarse coal can be treated in non-pressurized reaction vessels and would
use support equipment significantly lower in cost than that necessary
for the fine coal system. However, since the coarse coal processing
has not been studied enough to allow an assessment of its technical
feasibility, Versar elected to limit this description to the Mayers'
fine coal process.
194
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Status of the Process
TRW has conducted extensive bench-scale testing of the major treatment
units for the Meyers' process(6 3) More than 45 different coals have been
tested, and over 100 complete material balances on the process have been
calculated and tabulated. The initial bench-scale program was directed
toward generating critical process data for the chemical removal of pyritic
sulfur. This program was aimed at optimizing the leaching and regeneration
steps, evaluating analytical techniques,and studying other process improve-
ments. From these data/the chemistry and rate expressions for the various
processing steps have been determined. Additionally, the applicability
of the Meyers' process to a variety of coals has been established during a
survey program. In this latter study, the process was compared to physical
cleaning for thirty-five different coals.64'it is the developer's claim
that in all but two cases the Meyers' process was superior.
Developmental efforts for this process began in 1969. Ihe bench-scale
testing effort generated the data necessary for the design of the eight
metric ton/day Reactor Test Unit (RIU). Ihe erection of this unit at the
Capistrano Test site was completed in early 1977. With EPA's sponsorship,
the RTU started up in June, 1977.
In 1978, TEW efforts were directed toward:
• Bench-scale investigations in support of the RTU program on
improved techniques for sulfur byproduct recovery and on the
identification and evaluation of process modifications with
potential for reducing processing costs; and
• Testing the RIU. The unit has been run with coal slurry and
plans were to introduce the leachate in the circuit in the
near future.
195
-------
The RTU is designed to handle coal less than 0.32 on (1/8 inch) in
size and variable test parameters of temperature, pressure, residence time
and oxygen concentration. Limited ability to filter and wash the coal to
remove the spent leachate is also included. This unit does not have the
capability to remove the elemental sulfur produced by the leaching reaction
or to handle coal particle sizes greater than 0.32 cm (1/8 inch).
The first ten months of operation of the RKJ will be dedicated to
treatment of two types of coal from the Martinka mine. It has been
established that this coal will not meet the current NSPS S02 emission
standards by physical coal cleaning techniques. The specific samples have
been selected in cooperation with American Electric Power Service Corp.
(AEP), which has elected to participate in this program for cleaning the
Martinka mine coal to an acceptable fuel.
One selected coals will be treated in the RTU for the purposes of
removing the pyritic sulfur. The treated coal will be washed and filtered
to remove the iron salts leaving a wet filter cake (17 to 28 percent
moisture by weight) containing some elemental sulfur. The product coal
from this operation will be sent to various equipment suppliers to dry
the coal and recover the elemental sulfur.
Extensive investigations are projected to optimize this process
technically and economically. Some of the studies projected involve:
• Pelletizing the powdered product coal by compaction, without
binder, to sizes greater than 0.95 om (3/8 inch) to permit
shipping in open hopper cars.
• Determining the effects of desulfurized coal on combustion and
performance characteristics of utility boilers.
• Dstermininr the effects of desulfurized coal on performance
characteristics of electrostatic precipitators employed to
remove particulates from the boiler flue gas.
196
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Technical Evaluation of the Process
This process has been extensively studied and is currently on an eight
metric ton/day pilot plant stage. Thus, an assessment of its industrial
potential is possible at this time. Only pyritic sulfur is removed by this
process. Therefore, the process is more applicable to coals rich in pyritic
sulfur. Ihese coals are found in the .Appalachian region of the United States
which now supplies about 60 percent of the current U.S. production. An
estimated one third of Appalachian coal production can be treated to a level
permitting the burning of product in conformance with current new source
utility SO2 emission standards. Some Interior Basin coal can also be
treated by this process to meet the new SO2 emission guidelines.
A Msyers1 treatment plant can be located either at a centralized
processing site or at a power plant site. If the treatment plant is located
at a large power plant site, steam and power requirements may already be
available on-site. Ihis could result in some cost savings. Furthermore,
the Mayers' processing plant can operate steadily with shutdowns only
for required or scheduled normal maintenance. Thus, the plant would only
have to be designed to furnish sufficient coal for the power plant's
average load factor, which is, in general, 60 percent of the full name
plate capacity. Additionally, capital and operating costs for such a plant
would be even more favorable if the process were integrated with coal-fired
powsr generating facilities which would already have included adequate
raw coal handling, crushing, pulverizing and fine coal handling facilities.
In some instances, when the treatment plant is added to a plant with a very
large coal demand, the entire operating cost of the system can be obsorbed
by the power plant because of improved product yield.
Another option for the Msyers1 processing plant which is potentially
attractive is a combination physical and chemical cleaning operation. In
this case, the run-of-mine coarse coal containing high ash and high pyritic
sulfur would be fed to a physical cleaning plant to reduce the ash content
of the coal by about 75 percent. The ash discard consisting of about 15 per-
oant of the KM coal will contain primarily ash and 10 to 15 percent pyritic
197
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sulfur. The low ash coal can then be fed to a gravity separation system.
The heavy fraction from the float/sink system, consisting of 40 to 50
percent of the total coal, will be used as feed to the Meyers' process.
This latter fraction, containing high concentration of pyritic sulfur,
will be reduced to 14 mesh top size and fed to a fine coal Meyers' circuit
to yield a product with a very low sulfur content. Ihe desulfurized
sample may then be recombined with the float fraction giving an overall
yield of about 80 percent on the run-of-mine coal feed. Thus, the
combined treated product contains 10-20 percent of the total sulfur of
the KM coal while only processing a fraction of the total coal through
the Mayers' process.
Potential for Sulfur Rsmoval—
Only pyritic sulfur is removed by this process. A survey program
(EPA Contract No. 68-02-0627) has established that this process is able to
remove 80-99 percent of the pyritic sulfur (23 to 75 percent of the total
sulfur) from 23 Appalachian Basin Goals and 91-99 percent of "pyritic sulfur
(43 to 55 percent of total sulfur) from the six Eastern Interior Basin
Coals. Tests with western coals showed 92 percent removal of the pyritic
sulfur (65 percent of total sulfur) from a single Western Interior Basin
Goal, and 83-90 percent removal of the pyritic sulfur (25-30 percent of
total sulfur) from the two western coals. Two other western coals (from
Edna and Belle Ayr mines) were also investigated, however, since these
coals contain very low pyritic sulfur (0.14 - 0.22 wt%), the results of
these tests are inconclusive. Under the same program, tests conducted
on float-sink have indicated that conventional coal cleaning at 1.9 specific
gravity could reduce only two of the coals tested to a sulfur content as
low as that obtained by the Meyers' process.
The results of these investigations are presented in Table 2-36. Most
coals, ground to 100 mesh x 0, were found to give the maximum pyrite
removal (90-99 percent). However, several of the coals required 150 and
some 200 mesh size reduction to achieve ultimate amounts of pyrite
removal. The size reduction also resulted in an increase in the rate
of pyrite removal so that, in most cases, the reaction time was reduced
considerably.
198
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TABLE 2-36.
MEMERS' PROCESS - SUMMARY OF PYRETIC SULFUR REMOVAL RESULTS
(100-200 MICRON TOP-SIZE COAL)
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GRAVICHEM CHEMICAL COAL CLEANING PROCESS
Process Description
The Gravichem process is a variant of the TRW Meyers process. It
utilizes a dense medium separation of ferric sulfate-sulfuric acid solution
slurried with the coal for feed to the main reactor. It has been found
that the float portion from a 1.3 specific gravity medium separation, as
in physical coal cleaning, is clean enough to not benefit significantly
by further chemical leaching. The float portion is washed, dewatered, and
dried. The sink portion of the 1.3 specific gravity separation is then
further cleaned through the Gravichem chemical coal cleaning process.
LEDGEMONT CHEMICAL COAL CLEANING PROCESS
Process Description
The Ledgemont oxygen leaching process is based upon the aqueous
oxidation of pyritic sulfur in coal at elevated temperatures and pressures
using a stream of oxygen as the oxidant. The process has been developed
by the Ledgemont Laboratory of the Kennecott Copper Corporation. Ihe
process was patented in 1976.
There has been no R&D effort by Ledgemont on the process since 1975.
Based on a series of tests run prior to 1975, the Ledgemont process claims
to remove 90% of the pyritic sulfur from a wide variety of bituminous coals
with essentially zero organic sulfur removal. The product is suitable for
combustion in standard utility boilers but will meet EPA NSPS for sulfur
dioxide emissions only if the organic sulfur level in the coal is 0.7-0.8%
or less.
Ihe Ledgemont process as conceptualized, consists of five principal
steps:
Coal Preparation—
The raw coal is crushed and ground to a suitable particle size for
maximum leaching efficiency. Ihe ground coal goes directly to a slurry
tank for mixing with water. Alternatively, the RDM coal may be subjected
200
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to physical coal cleaning to remove pyrite and ash, before introduction
into the process.
Oxidation Treatment—
The coal slurry is then fed to leaching reactors where essentially
all of the pyritic sulfur is oxidized to soluble sulfates and insoluble
iron oxide under suitable conditions of temperature, pressures, slurry
density, oxygen dispersion, mixing and residence tine.
When the process operates at the preferred temperature and pressure [between
50° and 150°C (120° and 300°F), 20 to 25 atm (300 to 350 psig) oxygen
pressure], it is claimed that 75 percent of the iron sulfate formed in
the reaction converts to iron ozide:
Ihe Ledgemont laboratory has found that organic sulfur removed in the
aqueous oxidation process is highly variable and, depending on the feed coal
used, has ranged from 0-20% removal.
Fuel Separation—
The desulfurized coal slurry is partially dewatered and filtered. The
filter cake is then' water washed.
Drying and Agglomeration—
The washed coal is sent to a suitable drier where water is evaporated
leaving a clean, dry solid fuel. This material is then compacted to a
suitable pellet size for shipment to a power plant.
Table 2- 37 presents Ledgemont1 s current best estimates of key parameters
which would be involved in the process design of a continuous system.( )
The process energy efficiency is estimated to be 83-85%. The bulk of
the process energy use would be in treated coal drying and in oxygen plant
operation. Oxidation of the coal results in conversion of carbon to carbon
201
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TABLE 2- 37
Typical Values of Key Parameters in
the Conceptual Ledgemont Oxygen ,6 8 *
Leaching Process for Bituminous Goal
Operating Factor: 333 days per year
Overall Xield (avg. coal): 97-98%
Net yield after fuel uses: =90%
Net hnnting value yield (avg. coal): 93-95%
Pyritic sulfur renewal: 90%
Organic Sulfur Baooval: 0-20%
Chemical Process
Coal
Coal desulfurization
Treated coal/water separa-
tion system
Mesh size
Coal/water in feed
Reaction time
Oxygen pressure
Oxygen
per metric ten coal
feed
Thickening area
required
Underflow solid
itraticn
Wastewater LreaUieiiL
Filtration:
Filtration rate
Percent solids in
fuel cake dis-
charge
Wash water/dry
solids
Line addition rate
Typical Value
80% -100 mesh
0.2/1
2 }•«*»•*.
130°' C (266* F)
20 atm. (300 psig)
0.138 metric ton
(0.125 tern)*
(11 sq ft/5TO)
43% solids
23 kg/hr/.09 in*
(50 Ih/hr/sg ft)
66%
.46/1
0.25 T/T coal feed4
The oxygen
O2 for pyrite reaction
02 for Fei+-* Fe**
Oz uptake by coal
02 to foes COz
Oj to fonn OOj
Oj lost to flashing
the following:
metric ton Oz/tetric ton coal
0.035T
0.0019
0.054
0.031
0.0014
0.0019
total
* Based on 2% pyritic sulfur in the coal.
sulfur oxidation is unknown.
e stoichionEtric reguirswnt for neutralization.
0.1252
Ins amount of Oj used in organic
202
-------
dioxide and carbon monoxide as well as trace amounts of higher hydrocarbons.
Appro:dmately 5-7% of the heating value of the coal is estimated to be lost
at the process operating conditions.
Based on the published Ledgemont process information and recent contacts
with the Ledgemont Laboratory, a schematic flow diagram for a 7,200 metric
tons (8,000 tons) per day coal processing plant is shown in Figure 2-38. The
process removes little or no organic sulfur and 90% of the pyritic sulfur
(starting with 2% pyritic sulfur in the raw coal feed).
Status of the Process
The Ledgemont Laboratory of the Kennecott Copper Corporation began work
on a process for coal desulfurization in 1970. The R&D effort was carried
out in partnership with the Peabody Coal Company - then a wholly owned
Kennecott subsidiary. The joint effort culminated in the Ledgemont flow-
sheet, the basic features of which have been demonstrated at the bench and
semi-pilot scale levels. It is claimed that each step of the process has a
complete experimental study to determine the operating range of process
variables. Complete reports setting forth the experimental work, process
specifications and process economics have been prepared. The entire develop-
nental effort has been internally funded throughout - to the extent of
approximately two million dollars.
In 1975, the FTC ordered the divestiture of Peabody Coal by Kennecott,
and this resulted in halting further development work on the Ledgemont
process. Plans for installing a h metric ton per day pilot scale desulfuriza-
tion operation were scrapped and no further R&D work is planned. Kennecott
is currently exploring the possibilities of licensing the Ledgemont process.
203
-------
OFFGAS
r (TO OXYGEN PLANT)
CO,, CO
ROM COAl
to
o
DESULFimiZEO
COAL
GYPSUM »
WON HYDROXIDE
To WASTE
DISPOSAL
FIGURE 2-38 LEDGEMDNT OXYGEN LEACHING PROCESS ELECT SHEET
-------
Technical Evaluation of the Process
The Ledgemont Laboratory has made available an in-house report contain-
ing all of the information made public to date on the process. In addition,
the Bechtel Corporation has made a technical and economic study of the
Ledgemont process.*6 9^A study of this information plus direct contacts with
Ledgemont personnel has permitted the following assessment of the process
to be made.*68)
Potential for Sulfur Removal—
The Ledgemont process has been shown to remove more than 90% of the
pyritic sulfur in coals of widely differing ranks including lignite, high
volatile B bituminous, and semi-anthracite in bench-scale autoclave equip-
ment. Reaction conditions have been standardized at 130° - 132°C (265°-
270°F), 20 atm (300 psig) oxygen pressure and twD hours residence time.
Several bituminous coals including Illinois #6, Ohio #6, and Kentucky,
have been treated in "semi-pilot scale" equipment with consistent removal
of 90% of the pyritic sulfur. Little, if any, organic sulfur is removed
by the process (from 0-20%, depending on coal treated), and there is no
credit taken in the conceptual process for this type of sulfur removal.
MAGNEX CHEMICAL COAL CLEANING PROCESS
The Magnex process is a coal beneficiation process vihich utilizes
vapors of iron pentacarbonyl [Ee (CO) $ ] to render the mineral components
of the coal magnetic. It has been experimentally demonstrated that free
iron resulting from decomposition of the pentacarbonyl selectively
deposits on or reacts with the surface of pyrite and other ash forming
mineral elements to form magnetic materials. Microscopic observations
and chemical analyses suggest that for pyrite the magnetic material is a
coating of a pyrrhotite-like mineral, while for ash the magnetic material
is metallic iron. It has also been demonstrated that the pentacarbonyl
does not deposit iron on the surface of coal particles.
205
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Process Description
The process involves four major steps:
• crushing and grinding;
• heating and pretreatmsnt;
• carbonyl treatment, and cooling; and
• magnetic separation.
Figure 2-39 presents a flow diagram for the Magnex process as described by the
process developer, Hazen Research, Inc., of Golden, Colorado.
Run-of-mine (RDM) coal is crushed to minus 14 mesh and then fed to the
thermal pretreating unit where it is heated to about -170 °C (365°F) in the
presence of steam. The steam and thermal treatment conditions the coal to
improve the selectivity of the magnetic coating (increase yield and reduce
sulfur content of the coal).
The heated coal is then gravity fed to the iron pentacarbonyl reaction
vessel where it is subjected to the treatment vapors at atmospheric pressure
for a residence time of thirty minutes to one hour. The reactor is
insulated and maintains the sensible heat of the coal.
The carbonyl treated coal is conveyed to the magnetic separation
section. The treated coal passes across three induced magnetic rolls in
series. The first roll removes the strongly magnetic minerals,and the
second and third rolls remove the weakly magnetic minerals. Several
commercially available magnetic separators have been evaluated under
funding by EPRI.
After passing through the magnetic separator, the clean coal is
conveyed into a storage bin. Some clean coal from the storage may be
returned to the CD burner for in-process use; the remaining will be
conveyed to t ^e compactor unit. The pelletized coal will be then conveyed
to the product storage for subsequent shipment.
The process consumes 1 to 20 kilograms of iron pentacarbonyl per
metric ton of coal (2-40 Ib/ton), depending on the feed coal; and generates
0.6 to 13.0 kilograms (1.4 to 28.6 Ib) of gaseous carbon monoxide (00)
for recycle.
206
-------
ROM ,
COAL
CRUSH
AND
GRIND
N)
O
BLEED
I CO ft F.ICOlgl
MAGNETIC SEPARATOR
BINDER
COMPACTOR
REFUSE
FIGURE 2-39 MAGNEX PROCESS FLCW SHEET
-------
In the 1977 pilot plant, the GO-rich gas was not recycled to iron
carbonyl generation. Rather, it was discharged through a hypochlorite
scrubber to remove traces of iron carbonyl. Since the major operating
cost for this process is associated with the consumption of the iron
pentacarbonyl, it is planned to react the CD-rich gas with iron to produce
iron carbonyl on-site. Even with a projected CD recirculation system,
a bleed stream may be discharged from the reactor.
Status of the Process
The Magnex process has been under development for 30 months. For
the first 18 months, the process has been investigated on a laboratory scale,
using initially 75 gram samples and later one kilogram samples, on a batch
scale basis. To date about 40 coals, mostly Appalachian in origin, have
been tested.^7 °) The major emphasis of the laboratory work has been on the
chemistry of the process. During this study efforts were directed to
determine the effects of process variables such as reactor temperature, iron
carbonyl requirements and reaction residence time.
On February 17, 1976, United States Patent #3,938,966 was issued
to Hazen Research, Inc. The Magnex process is owned by the NEDLOG TECHNOLOGY
GROUP. NEDLOG plans to continue process development and initiate design,
construction and operation of a 54 metric tons (60 tons) per hour
demonstration plant.
Start-up operation for the pilot plant was in November, 1976. The
coal selected for the pilot plant evaluation was from the Allegheny group
of Pennsylvania. This coal was run in the pilot plant during the first
quarter of 1977 and was upgraded to meet the current new source
sulfur dioxide emission standard of 520 ng S02/J (1.2 Ib S02 per
million BTU). Washability studies of this coal had indicated that
conventional gravity cleaning would not significantly reduce the sulfur
content of the feed coal.
208
-------
At the present, various ooal samples are being evaluated in the
laboratory stage and research and developmental work is prooaeding in the
area of iron carbonyl generation.
•technical Evaluation of the Process
The Magnex process removes only pyritic sulfur and therefore, it is
more applicable to coals rich in pyritic sulfur, which are found in the
Appalachian region. The process also reduces the ash content of the coal.
It is claimed that fine coal crushing is not necessary to enable the
©
Magnex process to find a wide application in pyrite-rich coal desulfuriza-
tion. The Bureau of Mines prediction curves which correlate pyrite particle
size with pyrite sulfur removal do not allow accurate prediction of sulfur
reduction for a given coal by the Magnex process. These curves are only
applicable to gravity ooal cleaning techniques. It has been reported that
in one test the average pyrite particle size of the minus 14 mesh coal
sample was 15 micron. Jtemoval of pyritic sulfur from this sample by the
Magnex process was approximately 80 percent; while a 30 percent sulfur removal
was predicted for this coal using the Bureau of Mines prediction curves.
Limited published information is available on Magnex process test
results. A report covering the applicability of this process for
desulfurization of coals surveyed may be issued in the future. However,
available information is discussed below.
Potential for Sulfur Removal—
During the first quarter of 1977 a coal feed from the Allegheny Group
of Pennsylvania was evaluated on the Magnex pilot plant. Table 2-38 presents
the analysis of the feed coal. Two shipments of this coal were received from
the same mine and seam. The ash content of the first shipment was consider-
ably lower than the second (12.7 vs. 18.3 percent); however, the sulfur
209
-------
TABLE 2- 38 ANALYSIS OF
'ROCESS PILOT PLANT FEED COAL
Sample NumberA
Ash, wt. %
Total sulfur, wt. %
Organic sulfur, wt. %
Inorganic sulfur, t wt. %
Calorific value, BTU/lb
Emission, Ih SO2/106 BTU
n089
18.29
1.27
0.56
0.71
11,980
2.12
10442
12.7
1.27
0.58
0.70
12,903
1.97
A Two shipments of coal were received. Although they were from the
same mine and seam, the ash content was significantly higher in 11089,
t Inorganic sulfur = pyritic + sulfate.
TABLE 2-39
SUMMARY OF LABORATORY EVALUATION OF MAQ3EX PROCESS
PILOT PLRNT FEED COAL*
Test Numbers
Carbonyl treatment
Temperature
Dosage
Clean coal
Yield
Ash
Total sulfur
Inorganic sulfur
Heating value
Emission
Units
°C
Ib/ton
%
%
1
%
BTU/lb
Ib S02/106 BTU
A
170
2.5
96.4
11.6
1.08
0.34
12,992
1.66
B
170
10
86.4
11.8
0.89
0.24
12,964
1.38
C
170
40
81.0
10.7
0.66
0.09
13,160
1.01
* Feed coal was 10442, minus 14-nesh, 1.27% total sulfur, 0.71% inorganic
sulfur, 12.7^ ash, 12,736 BTU/lb.
210
-------
content of both shipments was the same (0.71 percent inorganic and 0.56
percent organic sulfur). Washability curves presenting specific gravity
versus yield, cumulative percent ash float and ash sink, and plus or minus
0.10 specific gravity distribution curve of the ROM pilot feed are given in
Figure 2-40. This plot indicates that at a specific gravity of 1.5 (where
10 percent of the raw coal feed lies within ±0.10 specific gravity curve)
theoretical perfect sink/float cleaning would yield 87.7 percent clean coal
containing 9.5 percent ash and 1.13 percent sulfur. While significant ash
reduction can be achieved at that specific gravity by sink/float techniques,
the resulting coal will not meet the current emission level
of 520 ng SOa/J (1.2 Ib S02 per million BTU).
The results of the laboratory Magnex evaluation of the pilot plant feed
are presented in Table 2-39 These data indicate that at 170 °C (338°F) and
20 kg of iron carbonyl per metric ton (40 Ib/ton) of coal, the clean coal
yield was 81 percent with product sulfur content equivalent to 434 ng SO2/
J (1.01 Ib SO2 per million BTU).
Figure 2-41 is the graphical representation of the laboratory data with
superimposed pilot plant test data shown by asterisk. In two pilot plant
runs, using 75 and 10 kg (15 and 20 Ibs.) of iron carbonyl per ton of coal,
the clean coal yields were significantly higher (7.9 and 3.6 percentage
points, respectively) than the results obtained from the laboratory runs.
The sulfur dioxide to BTO ratios for the pilot tests were close to that
predicted by the laboratory runs. Pilot plant results indicated that for
coal used in this evaluation 10 kg per metric ton (20 Ib per ton) of iron
carbonyl was adequate to yield a product to meet the current
S02 level for utility boilers.
211
-------
±0.10 SPECIFIC
GRAVITY DISTRIBUTION
CUMULATIVE % TOTAL
SULFUR, FLOAT
CUMULATIVE
• % ASH,
FLOAT
SPECIFIC GRAVITY
0.6
0.8
1.0
I !
SPECIFIC GRAVITY
1.2
I
1.6
2.0
2.2
i
CUMULATIVE % SULFUR, FLOAT
4 8
I I I I
12
I
I
16
I !
20
24
I I
28
32
I
CUMULATIVE % ASH, FLOAT
FIGURE 2-40 MAGNE^PROCESS WASHABILITY PLOT FOR A
6 INCH X 100 MESH COAL
212
-------
100
1.70
1.00
20
30
40
20
30
40
Ibt of Fe(CO)3 / TON of COAL
FIGURE 2-41 MAGNEX-PROCESS EFFICIENCY COMPARISON OF LABORATORY
AND PILOT PLANT DATA
213
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SYRACUSE RESEARCH CHEMICAL COAL CCMCCNUTICN PROCESS
The Syracuse Research Corporation has developed a process for the
chemical fracturing or comninuting of coal, which is an alternative to
mechanical crushing and fine grinding. The process is a precursor to the
removal of pyritic sulfur and ash-forming components of coal by physical
coal cleaning methods. Since the process is chemical in nature and it does
remove pyritic sulfur when combined with a physical coal cleaning process,
it has been included in this study of chemical coal cleaning processes.
Chemical comminution is a process that involves the exposure of the
coal to certain low molecular weight chemicals that are relatively inexpensive
and recoverable (usually ammonia gas or a concentrated aqueous ammonia
solution). "The chemical disrupts the natural bonding forces acting across
the internal boundaries of the coal structure where the ash and pyritic
sulfur deposits are located. An apparent breakage of natural bonds occurs
along these boundaries, thus exposing the ash and pyrite for follow^on
separation. No significant dissolution of the coal occurs, nor is there any
apparent reaction between the non-coal constituents and the comminuting
chemical. "(?2)
"Since no mechanical breaking is involved in the chemical comminution
approach, the size distribution of the comminuted (fractured) coal is
governed by the internal fault system, the chemical employed, and the process
operating parameters. The size distribution of the pyrite and other
mineral constituents in the coal is solely dependent upon the characteristics
and history of the coal being treated." (72 )
Process Description
A conceptual flow sheet for the Syracuse process is presented in Figure 2-
42. The starring material is raw coal which has been sized to 3.8 cm (1% in)
x 100 mesh. Hie minus 100 mesh coal is separated and shipped directly to
the physical cleaning plant. The 3.8 x 100 mesh coal is weighed and charged
to a batch reactor. In a typical cycle, the reactor is then closed and
evacuated by a rotary seal pump for removal of air. The reactor is then
214 '
-------
RAW
COAL
10
K
FINES TO
CLEANING PLANT
FIGURE 2-42 SYRACUSE COAL COMMINUTION PROCESS FLOW SHEET
-------
pressurized with ammonia vapor to about 9 atm (120 psig). In a full scale
operation this would be accomplished in two steps, first to 5 atm (60 psig)
by equalizing ammonia pressure with another batch reactor (operated in
parallel and just conpleting its reaction cycle), and then to 9 atm
(120 psig), using ammonia from either the arnnonia compressor or from an
evaporator which draws from a liquified ammonia storage tank. The reactor
is held at 9 atm (120 psig) pressure for 120 minutes. During the reaction
period, the temperature in the reactor rises 50 °C to 65 °C above the
ambient temperature due to heat of solution of ammonia absorbed by moisture
in the coal. The coal is comminuted to about 1 cm (3/8") top size.
At the end of the reaction cycle, the reactor is depressurized to 0.14
atm (2 psia) by first equalizing with another reactor which is charged with
fresh coal, and then exhausting with a transfer compressor. These steps
minimize loss of ammonia in coal. By this time, the temperature of the coal
has dropped to about 27°C (80°F). The vacuum is then released in the
reactor, and the coal is conveyed directly to a slurry mix tank prior to
washing. The cycle of a batch is suggested as follows:
Operation Time (Min.)
Charging 30
Evacuation 30
Equalizing to 5 atm (60 psig) 30
Pressurizing and holding at
9 atm (120 psig) 120
Equalizing to 5 atm (60 psig) 30
Depressurizing to 1.1 atm
(2 psig) 30
Release vacuum and discharge 30
Idle time as required
TOTAL 300 plus idle time
216
-------
All vent gases are collected through a rotary seal pimp and scrubbed.
The scrubber effluent is added to coal slurry.
Comminuted coal is slurried with a recycle stream pumped from the
amnonia wash column. This recycle stream contains minus 30 mesh coal of
15-20% solids, plus 5-10% dissolved ammonia. A 35% solids slurry is formed
with the comminuted coal and is pumped to the midpoint of the wash column.
As the coal sinks in this column it is washed free of ammonia with hot water.
Goal containing about 20% moisture settles to the bottom of the column and
is periodically discharged by a rotary valve to a dewatering screen.
The coal on the dewatering screen is washed to remove all minus 28
mesh fines and discharged to a stockpile, where it can then be sent to a
cleaning plant. The minus 28 mesh fines from the dewatering screen leaves
as a 20% slurry, and are sent to a clarifier. The fines are recovered as a
40% sludge, which is sent to the cleaning plant. The clarifier overflow
water is recycled to product washing.
The ammonia recovery column is equipped with a feed preheater, a reflux
condensor, and dome-cap trays. The column operates at one atmosphere pressure,
nominally and the reboiler is heated by 2.7 atm (25 psig) steam. Ammonia
is released from the incoming ammonia solution, and ammonia vapor containing
about 2% moisture is cooled to 30°C (90°F) as it leaves the column. This
vapor is compressed to 9.5 atm (125 psig) by the recycle compressor, and
the vapor ammonia is either recycled immediately to a reactor, or is condensed
and stored in a tank.
As has been stated above, all products from the chemical comminution
step would be sent to a conventional coal cleaning or washing plant for
separation of beneficiated coal from pyrite and ash-enriched refuse. A
proposed operation of this type is illustrated in the flow sheet given in
(iz )
Figure 2-43. This flow sheet is proposed by the Syracuse Research Corp.
Status of the Process
The 1971 Syracuse Research Corporation initiated development of a program
aimed at the removal of pyritic sulfur and ash-forming substances from coal.
217
-------
COAL WASHING WITH CHEMICAL COMMINUTION
11000 Twit P*r Hew Praduad)
FIGUFE 2-43
SYRACUSE PROCESS CHEMICAL COMMINUTION PLUS
PHYSICAL COAL CLEANING
218
-------
Ihe results of this effort have been patented in the United States and in
a number of foreign countries. During a portion of the project, effort
was supported by the Energy Research and Development Administration, and a
final report was published.
All work to date has been performed on a laboratory or bench scale at
the facilities of Syracuse Research. The largest tests have been with
23 kg (50 Ib) batches of coal, which were run in large, specially constructed
steel "bombs".
Proof of the "cleanability" of the chemically cortniinuted coal product
has been limited to development of laboratory washability data, followed
by complete sulfur and ash analyses of the various fractions, and develop-
ment of cumulative percent sulfur and percent ash contents versus percent
coal recovery curves. It appears that no chemically comminuted coal has
yet been subjected to separation in a coal washing plant, or even on coal
washing pilot plant equipment.
In 1977 marketing of the process was undertaken by Catalytic, Inc. of
Philadelphia, Pennsylvania and a complete report of the process and process
economics was prepared. (72)
Exploratory efforts by Catalytic, Inc. to build and operate a pilot
plant at a suitable location include negotiations for a site at Hearer City,
Pennsylvania or at TVA. (7It)
Catalytic performed a study, at EPRI's request, comparing chemical
oomraunition with mechanical crushing, both followed by heavy medium
separation facilities for the Homer City application.
Technical Evaluation of the Process
Potential for Sulfur Removal—
As stated previously, chemical comminution liberates pyritic sulfur
more readily than mechanically fractured coal of the same size consist, the
user can employ higher sulfur coals as feed stock to achieve a given sulfur
level in the cleaned product. Conversely, for a given level of sulfur,
chemical comminution will generally yield increased coal product.
219
-------
In Figure 2-44, the washability data completed on Illinois No. 6
(Franklin County) coal is plotted to illustrate percent cumulative sulfur
versus recovery. In this comparison, the chemically oonroinuted coal is
clearly superior to the other three samples. For example, at a 90%
recovery of plus 100 itesh coal, sulfur content would be 1.3%, for the
Syracuse product, 1.48% for 1 cm (3/8 in) mechanically crushed coal,
1.44% for 14 mesh mechanically crushed coal and 1.51% for 3.8 on (1*5 in)
RDM sample respectively. For a selected sulfur value of 1.40% weight
yield recoveries would be 96%, for the Syracuse product, 78% for
14 mesh mechanically crushed coal, 70% for 1 on (3/8 in) mechanical crushed
coal, and 49% for 3.8 cm (1% in) KM sample.
As previously mentioned, the potential for removal of pyritic sulfur
from PCM mechanically crushed coal, or chemically comminuted coal has been
assessed to date only by laboratory washability data. This laboratory
technique yields optimal results which are rarely duplicated in full-scale
coal cleaning plants. Therefore, the washability comparisons made
with respect to sulfur removal or product recovery, between chemically
conminuted coal and mechanically crushed coals may be altered in plant
operation.
Based on available data, it is anticipated that the Syracuse chemical
comminution process followed by conventional physical coal cleaning, will
remove 50 to 70 percent of pyritic sulfur in coals, with product recoveries
of 90 to 60 weight percent. The coals used in laboratory studies contained
high organic sulfur. Therefore, even removal of 100% of pyritic sulfur
would not bring these coals into compliance with current EPA NSPS for SO2
emissions. It is also concluded that the Syracuse chemical comminution
process, followed by conventional physical coal cleaning, will bring some
coals into compliance range if the organic sulfur level is sufficiently low.
220
-------
i-)
NJ
100
o 1 1/2in . R O.M. Sample
3/flin., Mechanically Crushotl
a 14 Mesh. Mechanically Crushed
A 1 1/2in., Chemically Fragmented
Gaseous Ammonia, 120psig,
75° F. Exposure Time: 120min.
FIGURE 2-44
1.6
Cumulative % Sulfur
SYRACUSE PROCESS VS. MECHANICAL CRUSHING: PERCENT SULFUR
VS. PERCENT RECOVERY OF ILLINOIS NO. 6 COAL
-------
ERDA CHEMICAL COAL CLEANING PROCESS
The ERDA air/steam leaching process is similar to the Ledgemont oxygen/
water process, except that the process employs higher temperature and pressure
to affect organic sulfur removal and uses air instead of oxygen. A coal
desulfurization process very similar to the ERDA process is also described in
a U.S. patent 3,824,084 assigned to the Chemical Construction Corporation.
In the ERDA chemical coal cleaning process the pyritic sulfur is first
oxidized to soluble sulfates. It is claimed that when the process operates
at the preferred temperature and pressure of 150 °C (302°F) and 34 atm (500
psia) , essentially all the soluble sulfate is oxidized to insoluble iron
oxide and sulfuric acid.
organic sulfur leaching chemistry is not well known. It is the
developers belief that the major portion (>50 percent) of-, the organic sulfur
in coal is of the dibenzothiophene (DBT) type which is inert to air at
relatively high pressure and temperature. However, the remaining fraction
of organo-sulfurs are not DBT-like and can react with air and steam to
produce sulfuric acid/75 '
Process Description
In the ERDA air/steam oxidative desulfurization process the coal slurry
is heated in the presence of compressed air at temperatures of 150 °C to 200 °C
(300°-400°F) , pressures 34 to 102 atm (500 to 1,500 psia) , and residence
time of 1 hour or less. At these operating conditions, it is claimed that
essentially all the mineral sulfur and approximately 40 percent of the
organic sulfur is removed as sulfuric acid. The ERDA process has been
conceptualized by Bechtel. '69'
A simpl, fied flow diagram of the process as developed by Bechtel, is
shown in Figure 2-45. Pulverized coal is mixed with water in the slurry
mixing tank. The coal slurry is pumped to feed-effluent exchanges where
the feed is heated with recovered heat from the reacted product. The feed
is further heated in the flash gas quench tower by direct contact with
desulfurization reaction off -gas, recycled from the product slurry flash
tank. The feed slurry at operating temperature and pressure is passed
222
-------
PULVERIZED COAL
MAKEUP
NJ
to
OFFGAS
HEACTORS
r*
1-
u
FL
JL
ASH Qt
iS
\/
FLASH
TANK
CLEAN COAL
*-GYPSUM
FILTER
FIGURE 2-45 ERDA PROCESS FLOW SHEET
-------
through a series of reaction vessels where the slurry in ooal is oxidized
in presence of compressed air. The product slurry is next flashed into
product slurry tank and subsequently thickened, filtered and dried prior
to compacting. A portion of the clean coal is burned to provide heat for
drying.
The ooal thickener overflow is confoined with the filtrate from the
coal filter and sent to lime treatment for neutralization of sulfuric acid
and ferrous sulfate. The sulfuric acid in this stream is converted to
gypsum and the ferrous sulfate to gypsum and ferrous hydroxide. These
reaction products are sent to gypsum sludge thickener and subsequently
filtered. The filter cake from this operation constitutes the solid waste
from this process. The thickener overflow and the filtrate constitute
the recycle water, which is sent to the slurry mixing tank.
Status of the Process
The ERDA chemical coal cleaning process was conceived approximately
seven years ago by Dr. Friedman at the Bureau of Mines and the process is
currently under study at DOE's Pittsburgh Energy Research Center (PERC).
Initial experiments on the air/steam oxydesulfurization of coal were
carried out using a batch, stirred autoclave system with 35 gram coal
samples. This apparatus was modified to allow continuous air flow through
the stirred reactor while the coal-water slurry remained as a batch reactant.
The current effort at PERC centers on the installing and operating of a
25 kg/day continuous reactor unit. The system consists of a slurry feeder,
slurry pre-heater, air preheater, a single Manel pressure vessel capable
of operating at up to 69 atm (1,000 psig), two parallel pressure let-down
tanks and a product recovery tank. '76' This system is designed to obtain data
on reaction rates and develop information on process engineering and
economic evaluation. It is hoped that operating data will be available
within nine months so that a decision can be made regarding the design,
construction, and operation of a larger continuously operated process
development unit (PDU). There is a possibility that a large, private
engineering group may assume the PDU effort, with support from DOE.
224
-------
Technical Evaluation of the Process
Technical evaluation presented here-in is based upon published informa-
tion and discussion with ERDA researchers, as well as the Bechter9'conceptual-
ization of this process and their prepared economic evaluation.
Potential for Sulfur Removal—
The developer's claim is that using this process, an estimated 45
percent of the mines in the eastern United States could produce environmentally
acceptable boiler fuel in accordance with current EPA SO2 standards for new util-
ity boilers. ^77^Available data from batch operations indicate that at mild
temperatures of 150° to 160°C (300°-320°F) the ERDA air/steam oxydesulfuriza-
tion process can remove more than 90 percent of the pyritic sulfur in coals.
Table 2-40 presents pyrite removal information from several representative
coals. The process is also claimed to remove up to 40 percent of coal's
organic sulfur if the reaction temperature is raised to 180-200 °C
(360-400°F) , this information is shown in Table 2-41. (77> Table 2-42 (77)
indicates that at low operating temperatures of 150 to 160°C (300-320°F)
several high sulfur content coals, such as coals from Iowa and Indiana
(Lovilia #4 and Minshall seams, respectively), can be significantly reduced
in sulfur content by this process. Higher temperatures and pressures
will be required to reduce the sulfur contents of these coals further.
The coal preparation requirements of this process are not known at this
time. Minus 200 mesh ROM coal has been used in most runs, but a few runs
using minus 14 mesh coal are claimed to produce comparable results. Due
to physical sizing limitations in the mini-pilot plant minus 200 mesh
coal will be processed.
GENERAL ELECTRIC CHEMICAL COAL CLEANING PROCESS
The General Electric microwave process for chemically cleaning coal
consists of the following steps:
• Crushed and ground coal (40 to 100 mesh) is wetted with a sodium
hydroxide solution, then subjected to a brief (<30 sec.) irradiation
225
-------
TABLE 2-40 PYRITE REMOVAL FROM REPRESENTATIVE COALS USING THE ERDA PPOCESE
Seam
State
Tll-inriis 14i_ 5
Minshall
Lowilia No. 4
Pittsburgh
Lower Freeport
Brcokville
Indiana
Iowa
Ohio
Pennsylvania
Pennsylvania
ISO
150
150
160
160
180
Pyritic sulfur, wt. %
Untreated 'Created
0,9
4.2
4.0
2.8
2.4
3.1
0.1
0.2
0.3
0.2
0.1
0.1
TABLE 2-41 ORGANIC SULFUR REMDVAL FROM REPRESENTATIVE COALS USING THE
ERDA PROCESS
Tenp, Organic sulfur, wt. %
Seam State. «c Untreated' Treated
Bevier
S3. 9*
Pittsburgh
Lower Sceeport
TTI-innig JiO. €
Minshall
Kansas
Montana
Wyoming
Ohio
Pennsylvania
Indiana
150
150
150
iao
180
200
200
2.0
0.5
1.1
1.5
1.0
2.3
1.5
1.6
0.4
0.3
0.8
0.8
1.3
1.2
TABLE 2-42 ERDA PROCESS OX5ffiESULFURIZATION OF REPRESENTATIVE COALS
Tenp, Total sulfur, wt. %
Span
Minshall
Til iTV»«t JJo.
Lowilia Mo.
Mannoth*
Pittsburgh
VTycming So.
Pittsburgh
. 5
4
9*
Upper rreeport
State
Indiana
Illinois
Iowa
Montana
Pennsylvania
wyoning
Chio
Pennsylvania
•c
150
150
150
150
150
150
160
160
Urrcreateci
5.7
3.3
5.9
1.1
1.3
1.8
3.0
2.1
•Treated
2.0
2.0
1.4
0.6
0.3
0.9
1.4
0.9
Sulfur, lb/10* HID
Untreated
4.99
2.64
5.38
0.91
0.92
1.41
2.34
1.89
Treated
1.81
1.75
1.42
0.52
0.60
0.78
1.15
0.80
226
-------
with microwave energy in an inert, gas atmosphere. Both pyritic
and organic forms of sulfur react with the sodium hydroxide to
form soluble sodium sulfide (NaaS) and polysulfides (NaaS ) during
X
irradiation.
• The coal is washed to remove the partially spent caustic and the
sodium sulfides, then it is again wetted with caustic solution,
and subjected to microwave radiation for an equivalent period.
• Ihe coal is again washed to remove the partially spent caustic
and the soluble sulfides, it is then dried and compacted.
The uniqueness of microwave treatment lies in the fact that the sodium
hydroxide and the sulfur species in the coal can be heated more rapidly and
efficiently than coal itself. Ihus the reaction between sodium hydroxide
and sulfur occurs in such a short time and with such low bulk temperatures
that an insignificant amount of coal degradation occurs. As a result,
the heating value of the coal is either unchanged or is slightly enhanced.
A number of bituminous coals having total sulfur contents from 1 to 6% ,
and having either predominately pyritic sulfur or organic sulfur contents,
have been tested with total sulfur removals of 70 to 99%. Ihus, the process
-------
MUM ,
COAL
CIUISII
AND
GRIND
RECYCLED
NaOH SOLUTION
fO
CO
BINDEII
IILE;:.-EH
CAUSTIC
GENERATOR
MICI1OWAVE
GENERATOR
AND
IIU1ADIATION
CHAMBER
STEAM
/^KtVAI-
EVAPORATOR
CONCENIHAItU
NaOII SOLUTION
TO BLENDER
FILTER
FIGURE 2-If 6 GENERAL ELECTRIC MICROWAVE PROCESS FLOW SHEET
-------
• 40 mesh top-size coal is slurried with a 20% solution of sodium
hydroxide so that the coal is thoroughly wetted by the caustic.
• The ncist ooal is then subjected to microwave radiation for
seconds. During this brief time, 30-70% of the total sulfur in the
coal is converted to sodium sulfide (Na2S) or polysulfide (Na2S )
A.
and some of the water is evaporated.
• The coal is then slurried in water to dissolve and remove the
sodium sulfides, dewatered, and then resaturated with about the
same concentration and amount of caustic as previously stated.
• After a second exposure to microwave energy, the desulfurized coal
is again washed free of sulfides and excess caustic, and is
dewatered and dried to -the extent required for on-site use, or is
dried and compacted prior to shipping. Depending on the coal
itself, and certain operating factors, 70% of the total sulfur in
the coal will have been removed.
A schematic flow sheet has been proposed for the sulfur recovery
process steps, Which is also shown in Figure 2-46. This is necessary for an
adequate conceptualization of the entire G.E. process and for process cost
estimation. It is G.E.'s present intent to process wash waters containing
sulfur by carbonating these liquors to produce hydrogen sulfide gas (H2S),
and then recover elemental sulfur via the Glaus Process. The sodium
carbonate, which also results from the carbonation step, would be treated
with lime to regenerate soluble sodium hydroxide and insoluble calcium
carbonate. The latter is then kilned to produce the ODa and lime (CaO),
which are both recycled and reused. Tnis regeneration process is almost
identical to the one being considered by the Battelle Institute as a part
of their chemical coal cleaning process. The regeneration process at first
glance appears simple and compact, however it may prove energy intensive
due to:
• evaporative heat required to concentrate solids in the several
filtate streams; and
• heat input to the kiln.
229
-------
It will, therefore, be necessary to use minimum quantities of water and
sodium hydroxide reactant in order to conserve heat energy in the subsequent
sodium hydroxide regeneration steps.
Status of The Process
All work to date has been done on a laboratory scale with small (10-100g)
quantities of ooal subjected to microwave radiation from a 1 KW, 2.4 GHz or a
2.5 KW, 8.35 GHz generator. The ooal is first impregnated with a 20% solution
of sodium hydroxide (NaOH), and sufficient caustic solution is retained on
the coal after dewatering so that about 16 parts of NaOH are present per 100
parts of ooal at time of treatment. Batch tests have been made on a nunber
of coals in which the coals were irradiated once or twice for varying periods
of time. However, exposure periods exceeding. 30 seconds rarely gained
further benefits.
Total sulfur (combustible to S02) removals of 75% have been achieved for
most bituminous coals provided that two sequential treatments are given.
However, much remains to be done in terms of economic optimization of the
process.
Technical Evaluation of the Process
Potential for Sulfur Removal—
A substantial removal of sulfur from bituminous coal appears technically
feasible with this process, providing that microwave treatment of the coal
is acconplished in two steps. Initially all analytical data indicated
that 95-100% removal of sulfur could be achieved as a result of the two step
treatment. Since that time, additional analytical techniques have been
utilized and are yielding conflicting data. For example, on untreated coals
230
-------
the Leco and the Eschka methods show nearly identical sulfur analyses. On
G.E. process treated coals, the Eschka (barium sulfate precipitation) irethod
shows considerably more residual sulfur in the coal then does the Leco
(combustion) method. TWD conclusions are possible:
• The G.E. process does remove 75% or more of total S from coal, but
not necessarily 95-100% in a 2-step process as was previously
claimed.
• Since the sulfur which is not removed does not show up in a Leco
combustion-type analysis, it may end up in the ash and thus may
still not result in S02 emissions. Further effort to resolve this
matter is in progress.
A one-step treatment is effective to the extent of 30-70% sulfur
removal, depending on the coal itself and other processing factors. Sulfur
removal in subbituminous coal, anthracite, or lignite has not yet been
attempted.
BATTELLE CHEMICAL COAL CLEANING PROCESS
The Battelle hydro-thermal coal process (BHCP) is based upon hydrothermal
alkali leaching of mineral and organic sulfur compounds from coal. The
process presently proposed by Battelle employs sodium and calcium hydroxides
as a mixed leachant and operates under conditions of elevated temperatures
and pressures. The desulfurized coal, after filtration and washing to
separate the spent leachant, is dried and compacted for use in coal-fired
utility boilers. At the present stage of development, the process must be
considered as partially conceptual.
231
-------
The BHCP desulfurization step has been tested on a series of raw
bituminous coals and has been shown to extract essentially all of the pyritic
sulfur and 25 to 50% of the organic sulfur starting with a range of total
sulfur content of 2.4 to 4.6 percent. The product is a solid fuel which
meets the current new source standard of a maximum of 520 ng S02/J (1.2 Ibs S02/
106 B1U) with certain coals.
Process Description
The proposed process consists of five principal steps:
Coal Preparation—
The raw coal is crushed and ground to suitable particle size, generally
70 percent minus 200 mesh. The coal then goes directly to a slurry tank for
mixing with the leachant. Alternatively, the coal can be first physically
beneficiated to remove some ash and pyritic sulfur before introduction into
the slurry tank.
Hydro-thermal Treatment—
The coal slurry is pumped into a reactor where it is heated to tempera-
tures in the range of 200° to 340°C (400° to 650°F) and subjected to a
pressure in the range of 18 to 170 atm (250 to 2,500 psig) to extract sulfur
and dissolve a portion of the ash from the coal. Residence time is approxi-
mately 10 minutes. It is essential that this operation and the following
one be carried out in an oxygen-free atmosphere to minimize the formation of
oxysulfur compounds which prevent the quantitative recovery of sodium
hydroxide from the spent leachant.
The recommended leachant for the process is a mixture of 8 to 10 percent
sodium hydroxide (NaOH) solution in a 3 percent calcium hydroxide (Ca(OH)2)
slurry. Concentrations of these components of the leachant will vary
depending on coal properties.
232
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Fuel Separation—
The desulfurized ooal is separated from the leachant by means of
filtration and water washing. Hie leachant is then concentrated before
regeneration.
Drying and Agglomeration—
Water is evaporated from the coal in a drier, leaving dry, clean,
solid fuel. Ihis material is then compacted to a suitable pellet size
for shipment to the user.
Leachant Regeneration—
A chemical regeneration step uses carbon dioxide to remove
sulfur from the leachate as hydrogen sulfide. This gas is then converted
to elemental sulfur by either the daus or Stretford process.
The schematic incorporates raw coal grinding, and treated coal drying
and compaction steps, not included in the latest Battelle process flow
sheet. Battelle proposes the production of treated coal as a wet material
which is stored in silos prior to shipment to the utility. If located at a
power plant site,the utility would be reponsible for grinding the raw ooal
and drying the treated coal. Battelle has included a charge to the BHCP
for the cost of drying in their latest cost estimate. However, to make
the cost estimate comparable to the other processes being considered in
this study, i.e., for a plant not necessarily located adjacent to a power
plant, the drying of the minus 200 mesh coal followed by a compaction
(briquetting) step are included in the flow sheet and cost estimate.
233
-------
to
U)
MAKUII'WAItll
04(111
N..1MI
*- UILUJSIHIAM
» flltCIHIIAUU
COAt OHUANItS.
ASH AND1IIACE
MtlAIS
WAilt SI lit AM
FIGURE 2-47. B^TTELLE HYDRDTHERMAL PROCESS FLOW SHEET
-------
Status of the Process
The original Battelle hydrothermal ooal process has been under develop-
ment at the Columbus Laboratories since 1960 under Battelle sponsorship.
The desulfurization step has been carried through pre-pilot level (continuous
bench-scale) laboratory investigations. In this effort, sulfur extraction
from approximately twenty different eastern and midwestem bituminous coals
have been studied. Battelle has published pyritic sulfur extraction data
on 6 coals, organic sulfur extraction data on 6 coals, and overall sulfur
f *J Q \
reduction data on 6 coals. >• 'In all of these studies, the SO2 emission on
the BHCP treated coals was equal to or less than the current EPA-NSPS of 520 ng
S02/J (1.2 lb/106 BTU) for coal-fired steam generators.
Liquid/solid separation and regeneration of spent leachant are being
studied in bench-scale equipment in an attempt to:
• establish definitive information as to whether the process can
operate in closed-loop fashion; and
• improve the economic viability of the process by reducing the
cost of these two high cost segments.
The EPA has funded a third area of interest in the BHCP: a combustion
study on BHCP treated coals (Contract No. 68-02-2119). This study was a
laboratory scale evaluation of BHCP treated coal combustion characteristics.
This work was completed and reported in "Study of the Battelle Hydrothermal
Treatment of Coal Process", to IERL, FTP, in November of 1976.(79)
With respect to regeneration of spent leachant, experimental efforts
have concentrated on screening the use of zinc and iron compounds as
possible regenerants for spent leachant from the coal desulfurization step.
Results so far have not indicated significant process viability for either
of these two heavy metals as alkali regenerants. In the case of zinc, there
are indications of residual zinc buildup in the coal as well as environment-
al problems expected when zinc sulfide is roasted to regenerate the zinc
235
-------
oxide. In the case of iron oxides or hydroxides as possible regenerants,
there has been no notable success to date.
To date, no experimental work has been attempted on optimization of
the solid, liquid separation treatment of the slurry from the desulfuriza-
ticn step. A computer model has been developed in order to optimize (on
paper) the relationships between the parameters involved, including the
method of separation (filtration, centrifugation or thickening), the number
of separation/washing stages involved, the wash water/dry solids ratio, the
percent of water in the underflow coal and the amount of entrained sodium
in the coal. These parameters have all been related to the cost contribution
per ton of coal product. This study has shown that nine countercurrent
filtraticn/washing stages at an overall wash water/dry solids ratio of 1.5
with a final solids level of 45% in the underflow (filter cake) gave the
lowest operating cost contribution per metric ton of product, i.e., $10.50/
metric ton ($9.50/ton). At a cost contribution of $10.50/mstric ton
($9.50/ton) with nine filtraticn/washing stages and 45% solids in the
underflow, the lowest entrained sodium level was determined to be 0.0018 metric ton,
i.e., about 1.8 kg entrained sodium per metric ton of dry solid (3.6 Ibs/ton) .
Using a value of 0.005 metric ton of bound sodium in the treated
coal per metric ton of dry solid, the total sodium input to the process
(as 73% NaDH) would be about 0.016 metric ton per metric ton of dry product
coal, i.e., 16 kg/metric ton (32 Ib/ton). With caustic at $176/metric ton
($160/ton), the sodium input represents about 27% of the total cost contri-
bution of the solid/liquid separation portion of the process. This caustic
input value is still subject to experimental verification.
In the preliminary combustion studies with two BHCP treated coals
under Contract No. 68-02-2119, the combustion characteristics of these coals
were determined in two test facilities at Battelle, a one-half kg/hr (one lb/
hour) laboratory-scale furnace and a 10-40 kg (20-80 lb) per hour multi-
fuel furnace facility. Tests in both units were conducted with dry,
pulverized BHCP treated coal. The results of these tests indicated that
the treated coals would meet the present U.S. EPA-NSPS for sulfur dioxide
emissions and that combustion of these coals proceeded as well or better
than the corresponding raw coals.
(79 j
236
-------
Technical Evaluation of the Process
The BHCP is one of the few chemical coal cleaning processes that has
made significant advances to a point permitting at least partial engineering
evaluation. Based on the information available, a technical evaluation of
the process follows.
Potential for Sulfur Jtemoval—
The ability of the process to remove sulfur is shown in the table
below.
(va)
TABLE 2-43 PYRITIC SULFUR EXTRACTION BY THE BHCP
Source of Coal
Percent Pyritic
Sulfur*
Mine
CN719
Belmont
NE41
Ken
Beach Bottom
Eagle 1
Seam
6
8
9
14
8
5
State
Ohio
Ohio
Ohio
Ky.
Pa.
111.
Raw
Coal
4.0
1.6
4.0
2.1
1.7
1.5
BHCP
Coal
0.1
0.1
0.1
0.2
0.1
0.2
ljAl_L.CU_-l_H_'li
Efficiency,
Percent
99
92
99
92
95
87
*Moisture and ash free basis. Coal samples were supplied from the various
mines. Analyses were conducted by Battelle on raw and hydrothermally
treated coals.
Ninety percent or greater pyritic sulfur removal has been demonstrated on a
variety of bituminous coals from Ohio, Pennsylvania, Illinois and Kentucky.
It is believed that pyritic sulfur can be almost completely removed
(95%) from any bituminous coal using the BHCP.
It is believed that the BHCP is capable of removing 25-50% of organic
(78)
sulfur from a wide variety of coals. The table on the next page presents
typical organic sulfur extraction data from the BHCP.
237
-------
EXTRACTION OF ORGANIC SULFUR BY TEE BHCP
Percent Organic
Sulfur*
Mine
Sunny Hill
Martinka #1
Westland
Seam
6
lower
Kittaning
8
Beach Bottom 8
Reign #1
4A
State
Ohio
W. Va.
Pa.
W. Va.
Ohio
Raw
Coal
1.1
0.7
0.8
1.0
2.3
BHCP
Coal
0.6
0.5
0.5
0.7
1.1
Extraction
Efficiency ,
Percent
41
24
38
30
52
*Moisture and ash free basis coal sanples were supplied from the various
mines. All analyses were conducted by Battelle on raw and hydrothermally
treated coals.
Experiments have been conducted also on a semicontinuous bench-scale
to confirm the results of laboratory batch experiments. The equipment has
a capacity of about 9 kilograms (20 pounds) of coal per hour and can perform
all of the basic steps of the desulfurization process. The operation/ however,
has not yet employed recycled, regenerated reactants, so that the influence
on leaching due to buildup of contaminants in the system is unknown.
JPL CHEMICAL COAL CLEANING PROCESS
The Jet Propulsion Laboratory (JPL), California Institute of Technology
at Pasadena, California, is developing a chemical coal cleaning process
which attacks both pyritic and organic sulfur compounds in coal, and
allegedly results in the removal of up to 75% of the total sulfur in coal/80 *
Both types of sulfur are attacked during a low temperature coal chlorinolysis
step; hydrolysis and dechlorination follow.
238
-------
Process Description
A flow diagram based on the JPL process is shown in Figure 2-48.
Chlorine gas is sparged into a suspension of moist, pulverized coal (minus
100 to minus 200 mesh) in methyl chloroform (1,1,1-trichloroethane) at
74°C (165°F) and atmospheric pressure for 1 to 4 hours. Ihe suspension
consists of approximately 1 part coal to two parts solvent. Chlorine (0.2)
usage is 3 to 3.5 moles of chlorine per mole sulfur, or about 250 kg CQ.2
per metric ton (500 Ibs/ton) of coal. MDisture is added to the feed coal
to the extent of 30-50% by weight.
After chlorination the coal slurry is distilled for solvent recovery, and
the solvent is recycled for reuse in the chlorinolysis step, 'the chlo-
rinated coal is hydrolyzed with water at 50-70°C (120-150°F) for 2
hours and then filtered and washed. The coal filter cake is simultaneously
dried and dechlorinated by heating at 300-500°C (570-930°F) with super-
heated steam (or possibly a vacuum) for about 1 hour.
Ihere are a number of byproduct . streams which are as follows:
• Vented gas from the chlorinolysis reactors contains unreacted chlorine
(C12) and byproduct hydrogen chloride (HC1). Ihe gas is cooled to condense
CLz, which is recycled, and the relatively ncn-condensible HC1 gas is piped
to a Kel-Chlor process unit which converts the HC1 to Clz.
• Vapors from the solvent evaporation step are cooled to permit con-
densation and recycling of the methyl chloroform. Ihe HC1 gas is piped to
a Kel-Cnlor unit for conversion.
• Filtrates and wash water from the filtration of hydrolyzed coal
contain hydrochloric acid and sulfuric acid. The HC1 is driven off in a
stripper and recycled to a Kel-Chlor unit. The residual dilute sulfuric
acid is concentrated to a saleable 91% sulfuric acid.
• Superheated steam exhausting from the dechlorination will also
contain HCl gas which must be condensed as hydrochloric acid and recycled
to a Kel-Chlor unit for chlorine recovery.
239
-------
HUM COAL
to
tt»
o
SOlVENLflECYCLE
CRUSH
AND
URINO
^^^^^J / / / /
Y f / f
BLE*
OER
WET
POWDERED
COAL
*-
•c.
o;.
1
-4—
|
SOLVENT
5V/AP.
1—*-
CHLORINE
CHLORINATOH
HCIt
EXCESS Cl,
MAKEUP
HCI
KEL -CIILOR
PLANT
HYDROLYZER
WATER
r-—
I U.CT I ROTARY
Ico"! "«-TER
CONDENSER
1 i
ACID
CONCENTRATOR
Y
BINDER
DECHLORINATOn
1O
STORAGE
COMPACTOH
SUPERHEATED
STEAM
11C!
FILTRATE
HCI RECOVERY UNIT
BYPRODUCT
M2S04
FIGURE 2-43. JPL PROCESS FLOW SHEET
-------
Status of the Process
As of mid-July, 1977, effort on this process was on a laboratory scale
batch operation using 100 g. coal samples. It was expected at that tine that
larger scale (1 kg) batch runs would be initiated in the near future, and
at a still later date, a 1 kg/hour mini-pilot plant would be constructed
and operated.
The early stages of the process research work were supported by the
National Aeronautics and Space Administration (NASA) under Contract No.
NAS 7-100. Recently the project obtained support from the Bureau of Mines
for a period of approximately 16 months.
Technical Evaluation of Process
Potential for Sulfur Eemoval—
Ihe process claims a 97-98% weight recovery of input coal, with
about a 2% loss in heating value, and 70-75% removal of total sulfur. Two
high sulfur coals have been examined carefully for sulfur removal. The
Illinois No. 5 high volatile bituminous ooal from Hillsboro mine had 4.77%
total sulfur content. The other high volatile bituminous coal was a
Kentucky No. 9 ooal from Hamilton, Kentucky.
Experimental data obtained with Illinois No. 5 (Hillsboro) ooal are
given in Table 2-44.
Ihe overall sulfur removal is 76% with a reduction from 4.77% to 1.50%.
Results of experiments with this ooal indicate that removals up to 70%
organic sulfur, 90% pyritic sulfur and 76% total sulfur have been achieved.
241
-------
The kinetic data for chlorination and desulfurization of minus 100 mesh,
(S i )
Illinois No. 5 coal are presented in Figure 2-49 The initial rate of
chlorination is very fast. The chlorine content in coal is 23% a half-
hour and then slowly increases to 26% within the next one and a half hours.
Within the initial half-hour period most of the pyritic sulfur and a
portion of organic sulfur are converted to sulfate sulfur. In the next
one and a half hour period,pyritic and organic sulfurs are slowly converted
to sulfate sulfur. Based on the sulfur balance, the gain in sulfate sulfur
is equal to the combined reduction of pyritic and organic sulfurs. The
above reactions extend to the hydrolysis period. The overall sulfate
compounds produced either directly or indirectly through sulfonate are
removed from coal in the hydrolysis step as indicated by the analysis of
hydrolysis solution.
Experimental data obtained from a run on minus 200 mesh Kentucky No. 9
(Hamilton, Ky.) coal is given in Table 2-45.
The sulfur content of this coal is predominately organic (>90%). About
57% of the organic sulfur and 59% of the total sulfur are removed.
The data on the above two coals are the only detailed experimental results
available at this time. Based on these results and discussions with JPL
project personnel, it is concluded that the removal of pyritic sulfur by the
JPL process is somewhat more complete than removal of organic sulfur.
Consequently, if a high percentage of total sulfur removal is desired,this
process should be used for coal rich in pyritic sulfur rather than in
organic sulfur. Neither product from the two above experiments will meet
EPA-NSPS S02/J (1.2 Ib S02/106 BTU) when burned. A more extensive assess-
ment of the sulfur removing potential of this process must await results
from the 9 coals to be tested under the Bureau of Mines contract.
242
-------
TABLE 2-44
JPL PROCESS:
Sulfur Form
PRELIMINARY CHLORINOLYSIS DATA FOR ILLINOIS
NO. 5 GOAL DESULFURIZATION*
Raw Coal
(% Sulfur) <
Treated Coal
(% Sulfur) ^
Sulfur Removal
Pyritic
Organic
Sulfate
Total
1.89
2.38
0.50
4.77
0.43
0.72
0.35
1.50
77
70
10 0Z
76
* (Chlorination - stirred reactor, 740C(165°F) , 1 atm (14.8 psig), 1 hour,
powdered coal 100-150 mesh with 50% water, methyl chloroform to coal
2A; hydrolysis and water wash - stirred reactor, 60°C(140°F), 2 hours,
excess water).
^ Analyses by Galbraith Laboratories, Inc., Knoxville, Tennessee
Additional water washing should remove 100% of sulfate
Up to 90% pyritic sulfur removal has been achieved in other conditions
TABLE 2-45
PRELIMINARY CHLORINOLYSIS DATA FOR THE JPL EESULFURIZATION
PROCESS ON BITUMINOUS COAL (HAMILTON, KENTUCKY)*
Sulfur Form
Pyritic
Organic
Sulfate
Total
Raw Coal
(% Sulfur)'
0.08
2.67
0.15
2.90
Treated Coal
(% Sulfur)A
0.03
1.16
0.29
1.48
Sulfur Removal (%)
62.5
56.5
1001"
59.0
* Chlorination - stirred reactor, 74°C(165°F), 1 atm (14.8 psig), up to 4
hours, minus 200 mesh coal with 30% water, methyl chloroform to coal 2/1;
hydrolysis and water wash - stirred reactor, 60°C(140°F), 2 hours,
excess water.
A Analyses by Galbrazth Laboratories, Knoxville, Tennessee
100% sulfate removal by added water wash
243
-------
NJ
ORGANIC AND PYRITIC SULFUR
FIGURE 2-49.
T1ME,hr
JPL PROCESS: PERCENT SULFUR AND CHLORINE IN COAL
VS. TIME OF CHLORINATION
-------
INSTITUTE OF GAS TECHNOLOGY (IGT) CHEMICAL COAL CLEANING PROCESS
The IGT flash desulfurizaticn process is based upon chemical and thermal
treatment of coal. In this process, sulfur is removed from the coal by a
hydrogen treatment under the proper conditions of temperature, heat-up rate,
residence time, coal size, hydrogen partial pressure, and treatment gas
composition.
An oxidative pretreatment is included in this system to prevent caking
and also to increase the sulfur removal in the subsequent hydrotreating step.
Both pyritic and organic sulfur are removed by the combination of these
treatments. The treated product is a solid fuel (possibly char) which
presumably may be burned without a need for flue gas scrubbing.
This report contains a conceptualized process design and process
economics based upon IGT data.. Subsequent to our cut-off date for data
input, IGT has developed its own conceptualized process design that includes
the effects of many factors derived from IGT's general background in coal
conversion. The IGT-developed process efficiencies and costs are signifi-
cantly better than those reported here, based upon the earlier IGT report
specific to this program. The following discussion, therefore, does not
include IGT's latest thinking on the process design; it should be regarded
as preliminary and subject to significant process efficiency improvements
and downward product cost modification.
Process Description
The process employs essentially atmospheric pressure and high tempera-
tures [about 400°C (750°F) for pretreatment and 800°C (1,500°F) for
hydrodesulfurization] to enhance the desulfurization of the coals. These
high temperatures cause considerable coal loss due to oxidation, hydro-
carbon volatilization, and coal gasification, with subsequent loss of
heating value. Batch reactor tests have indicated an average product
recovery potential of 60 weight percent based on the feed.
245
-------
Experiments have been conducted with several coals in both laboratory
and bench-scale batch hardware to test ICT concepts and to determine the
pretreatirent and hydrodesulfurization operating conditions. Adequate
experimental data on heat and material balances are not yet available
to conceptualize a process design. It is, however, anticipated that the
process will employ the following equipment or processing steps:
• Fluidized bed reactors will be used for both pretreatment and
hydroctesulfurization stages;
• Air will be used as the source of oxygen;
• Off-gases from the hydrodesulfurization, provided they contain
hydrogen partial pressure, will be compressed and recycled to
the hydrogeneration reactor to provide the necessary hydrogen
for desulfurization of coal;
• Hydrogen make-up may be necessary to maintain hydrogen partial
pressure;
• The exothermic pretreatment reaction will provide a portion
of the heat necessary for the endothermic hydrodesulfurization
reactions;
• The sulfide and sulfate sulfur will be removed from the hydro-
desulfurized product by either chemical or mechanical means.
Ihis step will be necessary when the coal char product from the
processing of certain coals contains residual sulfur levels
exceeding the allowable limits;
• The hydrogen sulfide/carbon dioxide gases recovered from the
hydrodesulfurizer off-gas will be treated in a Claus plant to
produce elemental sulfur;
• Purification of the off-gas from the hydrodesulfurizer system
will be necessary prior to recycle; and
• Off-gas cleanup from the pretreater will be necessary prior to
venting the gases to the atmosphere.
246
-------
Versar has provided a suggested process flow sheet which integrates
the IGT concepts and is shown in Figure 2-50. This flow sheet has been
provided to permit the development of process economics on a consistent
basis with other processes.
Status of the Process
The IGT process is in an early stage of development. An extensive
bench-scale and pilot level technical effort is needed before an integrated
process design is conceptualized. Ihe program, sponsored by EPA, is now
directed toward testing in a 25 cm (10-inch) continuous fluidized-bed unit,
which is sized for coal feeds of 10 to 45 kilograms (25 to 100 pounds) per
hour.
Two pretreatment runs of about seven hours each have been made in this
25 on (10-inch) unit. A beneficiated Illinois No. 6 coal, which was
crushed to minus 14 mesh and contained 2.43 weight percent of total sulfur,
was used as feed. The objectives of these runs were to test the operating
conditions over a sustained period of time and to produce pretreated
material for subsequent hydrodesulfurization evaluations. The pretreatment
runs have been successful, and they have confirmed most of the results of
corresponding batch tests. These runs indicated that a temperature of 400°C
(750°F), a residence time of 30 minutes, an actual gas velocity of 0.3
mater (one foot) per second in the bed, and 0.616 cubic meter of oyygen.
per kilogram [one standard cubic foot (SCF) per pound] of coal are adequate
to pretreat the coal when the unit is fed at a rate of about 23 kilograms
(50 pounds) per hour. However, material and heat balance information generated
on one of these runs contradicts conclusions derived from the batch runs.
247
-------
VENT
SCnUBDFH
nowon
\
orr•OAS
ICOOLEF)
~LJ
COMPOFSSon
E
- MAKEUP H,
RECOVFnFD
HAS scnuBBEn
SHIFT CONVERTER
CLEAN-UP
AND H,S / CO,
ti,s
T
V»AS1tM2O WASTE SOIIDS
ELEMENTAL
SULFUR
PI ANT
to
4*
CO
now COAI.
ELEMENTAL
SULFlln
HEAT
FXCMANnFH
Ain
CLEAN CHAR
rnootic r
MAKE-UP
CAUSTIC
OYPSUM
FIGU.
-------
The analyses of data indicated very low quantities of light hydrocarbon in
the off-gases [.37 MJ/cu.m (10 BTU/SCF] and a very high solids recovery
around the pretreatment unit (97.7 wt%) . Thus only 2.3 wt % of the coal
was consumed in off-gases and water as compared to the expected 8 to 12
percent. Information from a single run is not adequate to draw definitive
conclusions; however, if these data are confirmed in the Pilot Demonstration
Unit (PDU), then no excess heat would be available from the pretreatment
stage for either steam generation or on-site consumption.
The data from the larger unit will be used to establish the necessary
energy and material balance information for the design of an integrated
system and for an accurate economic evaluation of the process.
Supportive runs are being continued in the batch reactor to cetermine
the effects of nitrogen, carbon monoxide, water vapor and hydrogen sulfide
concentrations in the treat gas on the hydrodesulfurization operation.
Additionally, crushing tests on a run-of-mine, Illinois No. 6 coal are
being conducted to determine the crusher conditions to minimize fines in
coal preparation and to define the coal preparation requirements for the
process.
IGT estimates that this process could be ready for commercialization
in four or five years after the successful operation of a pilot demonstra-
tion unit.
Technical Evaluation of the Process
This process is currently at the bench-scale level, thus, a definitive
assessment of its industrial potential is not possible at this time. However,
available information is summarized in the following subsections.
Potential for Sufur Removal—
Laboratory and bench-scale experiments conducted thus far indicate
that the ICT process can remove 83 to 89 percent of the total sulfur from
four bituminous feed coals. The process removes both pyritic and organic
sulfur. In most cases, enough sulfur is removed so that the treated product
could be burned in conformance with current EPA new source performance
standards for SO2 emissions.
249
-------
A preliminary evaluation of the desulfurization potential of four
selected bituminous ooals was conducted in a laboratory device (thermo-
balance) with 2 to 6 gram coal samples. Pyritic, organic, and total sulfur
(82 )
removal rates obtained from these investigations are reported in Table 2-46
Samples for the above thermobalance tests were +40 mesh pretreated coal.
The feed was placed in the sample basket and then lowered into the treating
zone. A heating rate of 2.8°C(5°F) per minute was used up to the terminal
temperature of 815 °C (1,500°F). Soaking time at the terminal temperature
was 30 minutes for each test.
Table 2-46 indicates that for the Western Kentucky No. 9 coal, in addition
to 98 percent pyritic sulfur removal, 88 percent of organic sulfur removal
was also achieved. Sufficient total sulfur removal was realized in this
test so that SO2 emissions from combustion of the treated product would
be 180 ng/J (0.42 1±>/106 BTU) .
The sulfur reduction obtained for the Pittsburgh seam coal from the
West Virginia mine was 98 percent pyritic and 83 percent organic sulfur.
The reduction in total sulfur content, accounting for sulfide/sulfate
compounds, was 83 percent, with sufficient sulfur removed to comply with the
current EPA new source performance standard of 516 ng/J (1.2 lb/106 BTU)
of SO2.
Results for the Pittsburgh seam coal from the Pennsylvania mine indicate
that in addition to all of the pyritic sulfur, 77 percent of the organic
sulfur was also removed. This coal having a lower initial total sulfur and
relatively low initial organic sulfur content also yielded a product with
acceptable SO2 emission value.
The sulfur reduction obtained for a beneficiated Illinois No. 6 coal
was 98 percent pyritic and 82 percent organic sulfur. This sulfur reduction
was such tha- SO2 emissions from combustion of the treated product would
be below the current new source SO2 standards.
250
-------
TABLE 2-46.
IGT PROCESS THERM3BALANCE SULFUR REMOVAL RESULTS
Raw Coal
Characteristics
Sulfur Removal
Efficiency,
Weight Percent
Source of
Coal
Feed
Type
Sulfur*
Content wt.%
of Feed
(dry basis)
A °f
Pyritic Organic
Hfestem Ky #9
Pittsburgh Seam From
W. Virginia
Pittsburgh Seam From
Pa. Mine
Illinois #6
RCM 3.03
Highly
Caking 2.41
High Ash
Content 1.01
Benef iciated 2.28
97.8 88.5 89.4
98.4 83.1 83.0
100.0 77.1 78.1
98.0 82.0 87.7
NOES:
Experimental Conditions Were: At 1500°F terminal temperature,
5°F heat-up rates and 30 mins. soaking time.
* Sulfur content of +40 mesh material.
The pyritic sulfur removal during pretreatment ranges
from 38% to 51%.
The organic sulfur removal during pretreatment ranges
from 0% to 10%
251
-------
KVB CHEMICAL COAL CLEANING PROCESS
The KVB coal desulfurization process is based upon selective oxidation
of the sulfur constituents of the coal. In this process, dry coarsely
ground coal (+28 mesh) is heated in the presence of nitrogen oxide gases
for the removal of a portion of the coal sulfur as gaseous sulfur dioxide
(SO2). The remaining reacted sulfur in the coal is claimed to be in the
form of inorganic sulfates or sulfites or is included in an organic radical.
These non-gaseous sulfur compounds are removed from the pretreated coal by
subsequent washing with water or heated caustic solution followed by water
wash.
The active oxidizing agent is believed to be N02. The process, however,
uses a gas mixture containing oxygen (0.5 to 20 percent O2 by volume) ,
nitric oxide (0.25 to 10 percent NO by volume), nitrogen dioxide (0.25
to 10 percent NO2 by volume) and nitrogen (N2) the remainder.
The process can be operated either on a batch or continuous basis as
desired. There are no data available, as yet, to indicate which system is
more economical. For a continuous operation, the reaction may be carried
out at 120°C (250°F) 2.4 atm (35 psia) for 1/2 to 1 hour period. The
mechanism of oxidation is still unknown.
Process Description
Laboratory experiments have been conducted with several coals, on 50
gram samples, in a 2.54 centimeter (one-inch) diameter batch reactor to test
the sulfur removal potential of the process. The process has been concept-
ualized both by KVE^83^and Bechtel. 9' The KVB design incorporates a somewhat
more optimistic water and caustic extraction operation than the flow scheme
suggested by Bechtel. In this section, the flow diagram developed by BecJitel
will be used since it incorporates standard processing equipment in concept-
ualizing the process.
A simplified flow diagram of the process is shown in Figure 2-51 Dry
coal from the preparation section is pneumatically conveyed to a gas/solid
cyclone where it is separated from its conveying gas (nitrogen). Then it is
gravity fed into a fluidized bed reactor. The reactant gas is introduced
through the bottom of the reactor through a distributor. The reaction gases
leave the reactor, passing through a two-stage cyclone separator which removes
the fine coal particles from the gas.
252
-------
UJ
LI IfKAMCUl
-fcr—
I uvrsuu I Vr\
lrv«rnniml I " V*j
I I I "^t
V. ..-> I iivriuM
^^ S I iiunn*
CUWHHICn
nA«i«AiFn
Figure 2-51. KVB Process Plow Diagram
-------
The treated coal from the reactor is next reacted with caustic solution
to remove additional sulfur (organic sulfur) and to convert the ferrous
sulfate to ferrous hydroxide and soluble sodium sulfate. The coal slurry
from the extractor is filtered and water washed on the filter. The product
ooal is then dried prior to compacting. The process also incorporates
treatment of the various effluents from the system.
The KVB laboratory test work on their chemical coal cleaning process
is presently inactive. Plans are to develop and commercially license the
process to coal producers and users. Funding is being actively sought
at this time to speed up the developmental schedule in view of the current
energy shortage.
Technical Evaluation of the Process
This process is in its early stages of development, and thus it is
difficult to make an accurate assessment of its industrial potential.
However, depending on the amount of desulfurization required, the extraction
and washing steps may or may not be required. It should be mentioned that
in cases where dry oxidation only could remove sufficient sulfur to meet
the sulfur dioxide emission standards, this technology could provide a very
simple and inexpensive system. Thus, there may be a potential for this
process for application to some coals, primarily metallurgical grade coals,
where partial removal of sulfur could be very beneficial.
Potential for Sulfur Removal—
Laboratory experiments conducted on 50 gram samples in a batch reactor
with five different coals indicate that the process has desulfurization
potential of up to 63 percent of sulfur with basic dry oxidation plus water
washing treatment and up to 89 percent with dry oxidation followed by
caustic trea> ment and water washing. Table 2-47 presents the results of
the laboratory studies. 3uhe results indicate that higher desulfurization
is achieved when the treat-gas contains 10 percent by volume of nitric
oxide.
The washing step removes iron and loosely bound inorganic material
which reduces the ash content of the coal. KVB claims a 95+ percent ash
254
-------
TABLE 2-47. COAL EESULFURIZATIQN DATA USING IKE KVB PROCESS
Coal Sarople
Identification
lower
Kit banning
Illinois
15
K-16914A
K-14702A
K-16394A
Size
htesh
•14to»28
14bo+28
14tn+28
I4tot28
BOto+10
14to+28
14to+28
14to+2B
l4to+28
14tof2B
14to+28
14to+28
-14to+2
Oxid
Time.
Irs.
-
3
3
1.5
I 3
1.5
3
3
3.5
3.0
3.0
3.0
3.0
atlon 200
NO in
Air
% Vol.
-
5
10
JO
5
10
10
5
10
5
10
5
10
°F
Gas
Flew .
l/mln.
-
,42
.44
.44
.42
.42
.44
.42
.44
.42
.44
.42
.44
Feed Sulfur
level
Total
4.3
4.3
4.3
4.3
4.3
3.0
3.0
3.0
6.7
5.3
5.3
3.2
3.2
Organic
0.7
0.7
0.7
0.7
0.7
1.9
1.9
1.0
1.16
1.3
1.3
1.9
1.9
Sulfur Level
After Oxidation
Tbtal
S
-
3.3
-
-
-
-
-
-
4.2
4.3
2.7
2.5
2.0
% Sulfur
Removed
-
23
-
_
-
-
-
-
37
19
49
22
38
Sulfur level
After Water Wash
Tbtal
S
-
2.4
1.6
-
-
-
2.0
1.9
3.1
3.0
2.5
-
-
% Sulfui
nanoved
-
43
63
-
-
-
33
37
54
43
53
-
-
Sulfur I/evel
After 10% NnOil
Wash & water wnnh
Tbtal
5
A
4.5
2.1
0.5
1.4
2.9
2.5
1.0
1.2
3.2
3.1
-
-
-
% Sulfur
ftemoved '
0
51
09
67
32
17
67
59
52
41
-
-
-
N)
U1
tn
t No oxidation, wash only.
U.S. Bureau of Mines Designation.
t It is claimed that recent tests achieved the same results in 10 minutes using a rotary reactor.
* Hie sanple.s were dried at 250"F before analysis.
-------
removal with their system; however, there are no published experimental
results to substantiate this claim.
Nitrogen (the transporting gas) from the cyclone is passed through
a dust collector for the recovery of fine coal particles and is then
discharged via a blower into a coal-fired heater prior to recycling this
gas to the coal preparation and conveying section.
Off-gas from the reactor is scrubbed with water to remove sulfur oxides
and nitrogen oxide gases. The acid product from the scrubber containing
sulfurous, sulfuric and also nitric acid is cooled prior to storage. The
treated gas from the water scrubber is subsequently reacted with calcium
hydroxide to remove carbon dioxide as calcium carbonate sludge. The purified
gas from the 002 remover is cooled to condense water vapor. A fraction
of the gas leaving the purifier is vented to prevent a buildup of inert gas
in the gas stream. By venting a portion of the gas and providing makeup
gas, the required gas proportion can be maintained. The recycle gas is
then caitoined with makeup N02 and 02 to form the treat-gas. The treat-gas
is compressed and recycled to the reactor.
The filtrate from the coal filter is treated with lime to regenerate
caustic and form gypsum. The sludge from the lime treatment tank is
concentrated in a thickener. The underflow of the thickener containing
a large fracticn of the gypsum is filtered to recover the caustic solution.
The thickener overflow is divided into two streams. One portion is recycled
to the extractor and the other is sent to an evaporator for further removal
of gypsum in order to prevent gypsum buildup in the system. The steam
generated in the evaporator is condensed and used as wash water for the
filter cake. The gypsum slurry is cooled and set to the gypsum filter.
Giypsum constitutes the solid waste from this process.
Status of the ?rocess
The process has been tested batchwise in the laboratory, using 50 gram
coal samples. KVB owns all rights to the process as of ^?ril 1977 and has
funded all the work thus far. U.S. Patent No. 3,909,211 was issued on
256
-------
September 30, 1975/8 4 and the filing of foreign patents in major coal producing
countries is in progress.
ATLANTIC RICHFIELD COMPANY CHEMICAL COAL CLEANING PROCESS
(25)
Process Description
The Atlantic Richfield Company (ARCO) is developing a chemical coal
cleaning process at Harvey, Illinois, which removes both pyritic and organic
sulfur compounds and ash from coal. The process requires the use of
either a recoverable or a non-recoverable reaction promoter.
Very little has been published about the process, no flow sheet is
available, and ARCO has not permitted an on-site inspection.
Status of the Process
Process development work has largely proceeded on the basis of data
generated from batch-scale experiments. However, a 0.45 kg (1-pound)
per hour continuous reactor system was recently built and is currently
being used to provide additional data.
Until recently ARCO has financed this experimental program without
external assistance. The Electric Power Research Institute, Palo Alto,
California (EPRI) has financed a study on the continuous reactor system
on five coals in which there is a wide distribution of pyrite particle
size. This study is now complete and a final report is expected to be issued
in 1979. The EPRI contract has been extended to demonstrate in the
continuous pilot plant low cost process options which ARCO has developed.
technical Evaluation of the Process
Potential for Sulfur Removal—
The five coals selected by EPRI and tested in the ARCO process are:
• Lower Kittanning, Martinka #1
• Illinois #6, Burning Star #2
• Pittsburgh #8, Montour #4
• Western Kentucky #9/14, Colonial
• Sewickley, Green County, Pennsylvania (beneficiated)
257
-------
The coals were selected to meet the following criteria:
• Mean pyrite crystallite chord size for the five coals
should cover a wide range;
• Pyrite and organic sulfur content should cover a wide range;
• Reduction of sulfur content to the NSPS compliance level;
i.e., 258 ng/J (0.6 lbs/106 BTU), should be attainable
by removal of pyritic sulfur in the case of at least one coal; and
• The coals should be from producing mines on seams with substantial
reserves.
Depending on the coal treated, overall reduction of sulfur was up to 98%
for pyritic sulfur, up to 20% for organic sulfur, and 66-72% for total
sulfur. Overall reduction of iron was up to 96% and of ash up to 78%.
The BTU yield of the process is estimated at 90-98%. Ash content of the
product is frequently reduced by 50%, compared to feed coal, and the
process weight yield is about 95%, depending on ash removal.
2.2.3.2 System Performance
•Hie performance of chemical coal cleaning systems was simulated using
the Ifeserve Processing Assessment Model. 3e Performance was measured
by the increase in the available reserve base," after applying chemical coal
cleaning, which could meet a given emission control level. The three most
efficient and best developed of the chemical coal cleaning process were
included: 1) Mayers Process; 2) Gravichera Process; and 3) ERDA Process.
Figures 2-52 through 2-58 present the model results. For discussion of
these results, three emission control levels were selected: 1) the National
SIP Average of 1,075 ng S02/J (2.5 Ibs S02/10S BTU); 2) an intermediate goal
or future gu'deline of 650 ng SO2/J (1.5 Ibs SO2/106 BTU}; and 3) a more
stringent level of 260 ng SO2/J (0.6 Ibs SO2/106 BTO). Product variability
was not included in the analysis because of the lack of available information
on chemically cleaned coal products and the current status of chemical coal
cleaning processes.
258
-------
to
en
70
60
SO
v>
O
S, 40
a
Ul
30
20
10
— RAW COAL
O MEYERS PROCESS
LI GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
(TOTAL WEIGHT OF RAW COAL = 68.136 x 10' TONS)
CQA
A
8
o
A
A
8
EMISSION LEVEL (LB. SO2/10b BTU). N. APPALACHIAN
FIGURE 2-52 N. APPLACHIAN RESERVE BASE AVAILABLE AS A FUNCTION OF EMMISSION
CONTROL LEVELS FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
40
30
ov
o
i -
A
D
1.0
OOA
OQA
— RAW COAL
O MEYERS PROCESS
D GRAVICHEM
A .95 PY. S./.20 ORO. S. REMOVED
(TOTAL WEIGHT OF RAW COAL = 34.80 x 10* TONS)
2.0
3.0
4.0
EMISSION LEVEL (LB. SCyiO6 BTU). S. APPALACHIAN
FIGURE 2-53 S. APPALACHIAN RESERVE BASE AVAILABLE AS A FUNCTION OF EMISSION
CONTROL LEVELS FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
30
A
ODA
OQA
ODA
OOA
O
to
CTl
20
z
O
I
C3
u]
A
D,
10
— RAW COAL
O MEYERS PROCESS
D GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
(TOTAL WEIGHT OF RAW COAL = 2.971 X 10" TONS)
1.0
2.0
3.0
4.0
EMISSION LEVEL (LB. SO2/10b BTU). ALABAMA
FIGURE 2-54 ALABAMA RESERVE BASE AVAILABLE AS A FUNCTION OF EMISSION
CONTROL LEVELS FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
90
80
70
— RAW COAL
U MEYERS PROCESS
I I GRAVICHEM
.'. .95 PY. S./.20 ORG. S. REMOVED
A
on
60
(TOTAL WEIGHT OF RAW COAL = 88.952 x 10* TONS)
CTl
p
fc 50
O
40
g
30
A
O
a
A
a
on
EMISSION LEVEL (LB. SO2/10D BTU). E. MIDWEST
4.0
FIGURE 2-55 E. MIDWEST RESERVE BASE AVAILABLE AS A FUNCTION OF EMISSION
CONTROL LEVELS FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
30
— RAW COAL
O MEYERS PROCESS
[ I GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
to
(Ti
LO
20
O
c
uj
10
(TOTAL WEIGHT OF RAW COAL = 18.972 x 10" TONS)
A
O
n
A
O
D
A
O
D
on
1.0 2.0
EMISSION LEVEL (LB. SO.,/106 BTU), W. MIDWEST
3.0
4.0
FIGURE 2-56 W. MIDWEST RESERVE BASE AVAILABLE AS A FUNCTION OF EMISSION
CONTROL LEVELS FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
to
CTl
320
300
280
260
240
220
| 200
& 180
i—
UJ
^ 140
4
O 120
100
80
60
40
20
A
— RAW COAL
O MEYERS PROCESS
Q GRAVICHEM
A .95 PY. S./.20 OHG. S. REMOVED
(TOTAL WEIGHT OF RAW COAL = 203.721 x 10' TONS)
1.0 2.0
EMISSION LEVEL (LB. StyiO6 BTU), WESTERN
3.0
4.0
FIGURE 2-57 WESTERN RESERVE BASE AVAILABLE AS A FUNCTION OF EMISSION
CONTROL LEVELS FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
to
CTi
Ul
O
u
480
400
320
240
160
80
40
— RAW COAL
O MEYERS PROCESS
f.l GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
_ (TOTAL WEIGHT OF RAW COAL = 417.554 x 10* TONS)
A
OQ
A
OD
A
O
A
D
A
O
D
A
EMISSION LEVEL (LB. SO2/10b BTU). ENTIRE U.S.
FIGURE 2-58 ENTIRE U.S. RESERVE BASE AVAILABLE AS A FUNCTION OF EMISSION CONTROL LEVELS
FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
In the Northern Appalachian region, the increase in the available
coal as a result of chemical coal cleaning at the 260 ng SO2/J control level
is negligible. However, at the 650 ng SO2/J emission level, the amount
of coal which becomes available due to chemical coal cleaning increases
five fold, and at the 1,075 ng SO2/J level, three times as much of the
coal reserves are potentially available when chemical coal cleaning is
applied. [Note: above the SIP control level of emission, the effect of
coal diminishes].
In the S. Appalachia region, chemical cleaning increases the total
amount of coal available up to 10%, with the greatest increase at the
400-700 ng SO2/J range of emission levels. Since the coal in this area is
low in pyritic sulfur content, the chemical cleaning processes do not have
a significant impact on compliance coal supply.
In the Alabama region, no raw or chemically cleaned coal is available
which would meet the 260 ng SO2/J emission control level. At the 650 ng
S02/J control level, chemical cleaning almost doubles the amount of coal
potentially available and at the 1,075 ng SO2/J control level, the effect
of cleaning is to increase compliance coal by 50 percent. Interestingly,
at the 650 ng SO2/J level using chemical coal cleaning, 95% of the cleaned
coal becomes available. In contrast, 95% of the raw coal reserve base is
in compliance only if the emission level is greater than 1,700 ng SO2/J.
Ihe Eastern Midwest region has a very minimal raw or cleaned coal
reserve base that can meet the most stringent emission level of 260 ng
SO^J, because the coal in this region is typically high in sulfur content.
Chemical coal cleaning in high sulfur coal regions proves beneficial for
increasing coal availability. For example, at the envLssion control level of
1,075 ng SO2/J, chemical coal cleaning processes will increase the amount of
coal by three times the amount of available raw coal.
The same holds true in the Western Midwest. High sulfur coal is
found in this region which also cannot meet a stringent emission level of
260 ng S02/J. Chemical coal cleaning will significantly increase the amount
of coal available for meeting the more moderate emission control levels.
266
-------
Chemical coal cleaning will increase the coal residua from 6% to 26% in
meeting an emission control level of 516 ng S02/J and from 31% to 81% at a
control level of 1,290 ng S02/J.
In contrast to other regions, over 15 percent of western coals can
meet the 260 ng SO2/J emission control level. When chemical cleaning is
applied, upwards of 35% of western coal is made available. At levels
above 260 ng SOz/J, chemical cleaning does not greatly enlarge the amount
of coal available. It is interesting to note that 95% of the raw coal
in this area can satisfy the 1,075 ng S02/J emission control level.
In the entire U.S., approximately 8 percent of the raw coal can meet
a stringent level of 260 ng S02/J. Chemical cleaning increases the total
anount by 10 percent (equal to 42 billion tons of coal). By weight this
means chemical coal cleaning can increase the amount of United States
compliance reserves by 38 billion metric tons.
Another approach to determine complying coal reserves after chemical
cleaning is to calculate the available energy (in KJ) that can meet a given
emission control level. The results, again using the RPAM and ignoring
product variability are provided in Figures 2-59 through 2-65. ^38'
At the most stringent emission level, 260 ng SO2/J, no coal in the
Itorthern Appalachian region reserve base can cotply with the control level.
The chemical cleaning of the raw coal, however, will produce approximately
100-160 x 109 GJ at the 260 ng S02/J emission level. At the intermediate
level 650 ng SO2/J of (1.5 Ibs SO /106 BTO), Northern Appalachian reserves,
if chemically cleaned, can reach a total of about 700 x 109 GJ. In the
raw coal, approximately 110 x 109 GJ are available at this same emission
standard. At the national average SIP emission level of 1,075 ng S02/J
(2.5 Ibs SO /10s BTU), raw coal energy reserves are 475 x 109 GJ. If
chemical cleaning is practices at the 1,075 ng SO2/J level, 1,400 x 109 GJ
become available. Chemical coal cleaning typically raises the amount of
corplying energy reserve base about three to four times.
267
-------
to
CTi
CO
RAW COAL
O MEYERS PROCESS
D GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
TOTAL QUADS OF RAW COAL = 1.728.37
BASED ON TOTAL RESERVE BASE
3.0
4.0
EMISSION LEVEL
-------
ro
CTl
VO
1000
900
800
5, 'OO
Q
I 6°°
CO
b 500
CD
< 400
H 300
200
100
A
— HAW COAL
O MEYERS PROCESS
D GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
TOTAL QUADS OF RAW COAL = 927.43
BASED ON TOTAL RESERVE BASE
J_
1.0 2.0 3.0
EMISSION LEVEL (LB. SO,/106 BTUl. S. APPALACHIAN
4.0
FIGURE 2-60 ENERGY AVAILABLE IN THE S. APPALACHIAN REGION AS A FUNCTION OF EMISSION
CONTROL LEVEL FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
-j
o
(A
Q
4
g
(A
CO
I
— RAW COAL
O MEYERS PROCESS
G GRAVICHEM .
A .95 PY. S./.20 ORG. S. REMOVED
TOTAL QUADS OF RAW COAL = 78.09
BASED ON TOTAL RESERVE BASE
10 -
EMISSION LEVEL (LB SO2/10° BTU), ALABAMA REGION
FIGURE 2-61 ENERGY AVAILABLE IN THE ALABAMA REGION AS A FUNCTION OF EMISSION
CONTROL LEVEL FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
1800 -
1700 -
1600
1500
1400
1300
1200
_ 1100
Q
=> 1000
d
3 900
I-
< 800
O
*~ 700
600
500
400
300
200
100
— RAW COAL
O MEYERS PROCESS
(J GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
TOTAL QUADS OF RAW COAL = 1,998.69
BASED ON TOTAL RESERVE BASE
A
A
°D
A
A
O
D
A
A
O
n
EMISSION LEVEL (LB. SO2/10B BTUl, E. MIDWEST REGION
FIGURE 2-62 ENERGY AVAILABLE IN THE E. MIDWEST REGION AS A FUNCTION OF EMISSION
CONTROL LEVEL FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
to
-J
400
350 -
300
_ 250
w
200
150
100
60
— RAW COAL
O MEYERS PROCESS
II GRAVICHEM
A .95 PY. SI20 ORG. S. REMOVED
TOTAL QUADS OF RAW COAL = 439.54
BASED ON TOTAL RESERVE BASE
A
A
D
A
/
/ \
A
O
D
O
n
1.0 2.0
EMISSION LEVEL (LB. S02/106 B7U), W. MIDWEST
3.0
A
D
A
0
n
4.0
FIGURE 2-63 ENERGY AVAILABLE IN THE W. MIDWEST REGION AS A FUNCTION OF EMISSION
CONTROL LEVEL FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
OJ
2.0
— RAW COAL
O MEYERS PROCESS
f] GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
TOTAL QUADS OF RAW COAL = 3,662.29
BASED ON TOTAL RESERVE BASE
3.0
4.0
EMISSION LEVEL (LB. SOj/IO" BTU). WESTERN REGION
FIGURE 2-64 ENERGY AVAILABLE IN THE WESTERN REGION AS A FUNCTION OF EMISSION
CONTROL LEVEL FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
to
8500
8000
7500
7000
6500
6000
5500
o sooo
<
- 4500
4000
3500
3000
2500
2000
1500
1000
500
A
A
— RAW COAL
O MEYERS PROCESS
n GRAVICHEM
A .95 PY. S./.20 ORG. S. REMOVED
TOTAL QUADS OF RAW COAL = 8.834.41
BASED ON TOTAL RESERVE BASE
2.0
3.0
4.0
EMISSION LEVEL (LB. SOj/106 BTU), ENTIRE U.S.
FIGURE 2-65 ENERGY AVAILABLE IN THE ENTIRE U.S. AS A FUNCTION OF EMISSION CONTROL LEVELS
FOR VARIOUS CHEMICAL COAL CLEANING PROCESSES
-------
At the most stringent control level of 260 ng SOz/J, large differences
exist in raw and cleaned coal reserves in the Southern Appalachian region.
For raw coal, 20 x 109 GJ are present, while for a chemically cleaned produce
210 x 109 GJ are available. At the next two levels of 650 and 1,075 ng S02/J,
the differences become less pronounced. At the 650 ng SO2/J level, standard
compliance raw coal has 500 x 109 GJ while complying chemically cleaned coal
has almost 700 x 109 GJ. Smaller differences exist at the 1,075 ng S02/J
level where raw coal has energy reserves of 860 x 109 GJ and chemically
cleaned coal contains 950 x 109 GJ.
In the Alabama region essentially no raw coal exists which could meet
the 260 ng SO2/J emission control level. When chemically cleaned, approximately
2 x 109 GJ are available to meet the level. At the 650 ng S02/J control
level, 23 x 109 GJ of the reserve base become available. Chemically
cleaning the coal increases the energy available to approximately
40 x 109 GJ. For the SIP level of 1,075 ng SO2/J, 60 x 109 GJ are
available in the reserve base versus 90 x 109 GJ for chemically cleaned
coal.
At the 260 ng S02/J level in the Eastern Midwest region there are
no reserves either for raw coal or chemically cleaned coal. The 650 ng
S02/J level also has small reserve values when compared to the total
of the region. Raw coal contains 40 x 109 GJ, while chemically cleaned
coal can supply 160 x 109 GJ. This fourfold increase from cleaning is
potentially significant for new source SO2 emitters. For the least
stringent level of 1,075 ng S02/J, raw coal reserves contain 160 x 109 GJ;
coal which has undergone chemical cleaning contains 600 x 109 GJ, again
a fourfold increase. These differences again point out and reinforce
the fact that four to five times more compliance fuels can be obtained from
Eastern Midwest coal at intermediate or moderate emission levels if the
coal undergoes chemical cleaning.
Virtually no energy reserves exist in the Western Midwest region for raw coal
at the 260 ng SO2/J emission control level. When chemical cleaning is
instituted, 18 x 109 GJ of reserve become available. When the emission
275
-------
control level is raised to 650 ng SO2/J, 33 x 109 GJ of raw coal can conply.
The addition of chemical cleaning at this level raises the available
energy reserves to approximately 80 x 109 GJ. By imposing a least stringent
level of 1,075 ng SO2/J, this region's raw coal has reserves of 65 x 109 GJ.
By instituting chemical cleaning there would be a benefit of more than
tripling the available energy to about 210 x 109 GJ. Definite gains in
energy reserves are then possible in this region by implementing chemical
coal cleaning. The advantages gained became more pronounced when the
emission control level is 1,000 ng S02/J and above.
tfost raw ooal in the Western region is capable of meeting low sulfur
emission control levels. At the 260 ng S02/J emission level 770 x 109 GJ
are available in the raw coal. For chemically cleaned coal, up to 2,400
x 109 GJ can be utilized. At 650 ng SO2/J the difference in the raw
and clean coals is much less. Raw coal has a reserve energy content of
2,600 x 109 GJ, while the chemically cleaned reserve base is 3,100 x 109 GJ;
As the emission control level rises even higher to 1,075 ng S02/J, the energy content
differences between cleaned and uncleaned coals are even less. Raw ooal
has a value of 3,600 x 109 GJ,and chemically cleaned ooal contains
3,700 x 109 GJ. Further increases in SO2 emission levels reduce the
differences to the point at which they become insignificant.
Nationwide, approximately 840 x 109 GJ are present in raw coal that
can meet a 260 ng S02/J emission control level. Note that 92 percent of
this energy comes from the Western reserve base. Implementing chemical coal
cleaning on the U.S. reserve base provides about 2,60.0 x 109 GJ of energy at the
stringent level. At the 650 ng SO2/J emission level, raw coal contains
3,700 x 109 GJ,-while chemically cleaning the coal raises this figure
to as much as 4,800 x 109 GJ. The magnitude of the differences remain
about the same for cleaned and raw coal as the emission level increases.
At the 1,075 ng SO2/J level, raw coal has available 5,300 x 109 GJ, while
the chemically cleaned coal energy reserve base rises to 6,900 x 109 GJ.
276
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Impact en Boilers
Chemically cleaned coal could improve the overall performance of
stoker boilers, provided the end product is suitable to be fed and
fired in a stoker. Many of the chemical treatments would require that
the coal be pulverized to a 100-micron size or less. Ihese coals would
have to be pelletized for stoker firing.
Any size cleaning plant could provide a product for any size boiler.
However, practically speaking, larger cleaning plants will provide cleaning
at a lower unit cost. Ihus, one cleaning plant might be used to provide
coal for all of the industrial boilers in one area. Ihe cleaning plant
would probably be located near the mine with the product distributed to
the users by truck, rail or barge.
Some of the chemical processes would increase surface reactivity
of the coal which would inprove combustion. Also, the free-swelling index
may be reduced (provided the ooal cleaning process involves an oxidation
step); thus reducing the caking tendencies of coal. Environmentally, the
coals become more attractive as more sulfur and ash are removed. Goals
fired in stokers require at least 5 percent ash to protect the grates from
overheating. Chemical cleaning of the coal should not drastically alter
the volatile content of the ooal. Reducing the volatile matter below
15 percent would cause problems in ignition and could preclude its use
in spreader stokers.
Due to process development status (i.e., pilot plants), maintenance
requirements are indeterminate, although problems with abrasion and acid-
initiated corrosion would be expected.
It is assumed that the use of chemically cleaned coal would inprove
the operation of boilers designed to bum ooal and that boiler modifications
would not be necessary.
277
-------
2.2.4 Performance of Physical and Chemical Coal Cleaning Techniques on
U.S. Coal Reserve Base at Various SO2 Emission Limits and Percent
Reduction Requirements
Previous portions of this section of the report have addressed the
weight and an energy percentage of U.S. coal that is capable of meeting
various SO2 emission control levels based upon SC<2 per unit heating value.
This section addresses the impact SOa emission control levels might have on
the availability of the U.S. coal reserve base.
Since it is quite conceivable that EPA may consider alternative
regulatory options of the same format as the utility boiler proposed
standard for the industrial boiler sector, it was decided that some
estimates of coal availability under various possible emission scenarios
should be made.
(92)
The Reserve Processing Assessment Model has been used to estimate
the weight and energy percentages of various regions of the U.S. coal
reserve base, which would be available after processing by four coal
cleaning technologies, to meet a series of proposed SO2 emission control levels.
The geographical regions used in this analyses included: 1) Northern
Appalachia; 2) Eastern Midwest; 3) Western; and 4) Entire U.S. The cleaning
processes simulated in the model are as follows:
A - PCC at 1 1/2 inch and 1.6 s.g. This process separates the coal
and impurities at 1.6 specific gravity after crushing the raw
coal to 1 1/2 inch top size. Weight and energy losses are
calculated based upon those inherent in the separation process.
B - PCC at 3/8 inch and 1.3 s.g. This process separates the coal
and impurities at a lower specific gravity of 1.3 after crushing
the ra\ coal to a 3/8 inch top size to liberate ash and pyritic
sulfur. This process simulates about the best that PCC can
achieve with respect to sulfur rejection, but with a large
penalty in weight and energy loss to the refuse.
278
-------
C - Meyers process. A chemical coal cleaning process capable of
removing 90-95% of the pyritic sulfur in the raw coal. It is
assumed that the process reduces the pyritic sulfur of the
coal to a level of 0.2 percent. A 10 percent weight loss and a
five percent energy loss is assumed in the process as well as
a 2 percent energy loss penalty.
D - Gravichera process. This is a combined physical and chemical
cleaning process in which the coal is first crushed to 14 mesh
and separated at 1.3 specific gravity. The sink material from
this separation is then treated in the Meyers process and
combined with the float. The energy penalties assumed in the
process are those inherent in the separation plus the penalties
attributed to the Meyers processing of the sink material.
Figures 2-66 to 2-89 show the availability in percent of the total
reserve base, for the Northern Appalachian, Eastern Midwest, and Western
regions plus the entire U.S. to meet percent SO2 removal standards at various
emission limits and floors, if the coal is cleaned prior to combustion. The
curves plotted for each region and the entire U.S. show both percent energy
and percent weight of the reserve base available. Three emission scenarios
were chosen consisting of a cap and a floor to illustrate three levels of
emission control. A moderate level was chosen at a cap of 1,290 ng S02/J
(3.0 Ib SO2/106 BTU) and a floor of 520 ng S02/J (1.2 Ib SO2/106 BTU).
An intermediate level was chosen at a cap of 860 ng SO2/J (2.0 Ib S02/106 BTU)
with a floor of 344 ng SO2/J (0.8 Ib SO2/106 BTU). A stringent level was
chosen at a cap of 520 ng SO2/J (1.2 Ib S02/106 BTU) and a floor of 258
ng SO2/J (0.6 Ib SO2/106 BTU). All of these cases neglect any consideration of
sulfur variability. All of the cases assume that if the raw coal emission
level is below the floor or the clean coal emission level reaches the floor,
then further cleaning is not necessary. This is reflected in the graphs
at the point where the curves level off.
In the Northern Appalachian region, at the moderate emission control
level the available coal as a result of physical cleaning decreases from a
range of 35 to 45 percent at 0 percent S02 reduction to a range 10 to 15%
279
-------
ISJ
09
O
O
K
LIMITS CAT- 3.00 LD. SO./11)6 B1U
FLOOR -1.20 IB. BO,/II>6 Bill
APCC |K INCH, 1.68. Q.
B PCC 3/0 INCH. 13 SO
C MEVEHS
PERCENT (LB. SO2/106 BTU) REMOVAL EMISSION LEVEL N. APPALACHIAN REGION
FIGURE 2-66 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A MODERATE PERCENT SO2 REMOVAL CONTROL LEVEL
-------
100
90
80
70
LEGEND
i.IMIiscAC -3.00 LH. so2/ionniii
noon ~i.20Ln.so2/ioeBiii
AI'CC IK INCH, 1.0S. O.
OI'CC 3/0 INCH, I 3 SO
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20
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20
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40
60
60
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90
100
PERCENT (LB. SO2/10U BTUI REMOVAU EMISSION IE VEL N. AI'PALACHIAN REGION
FIGURE 2-67 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BV VARIOUS
TECHNOLOGIES TO MEET AN INTERMEDIATE PERCENT SO2 REMOVAL CON fROL LEVEL
-------
100
LEGEND
80
LIMI1S CAP -3.00 LO. BO./I06 BTU
noon -1.20 LB. scyio%ru
AI'CC IK INCH. 1.6 S.O.
BPCC 3/aiNCH, 1,3 SO
C MEYERS
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70
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60
60
40
30
20
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10
100
PERCENT (IB. SO2/106 BTU) REMOVAL EMISSION LEVEL N. APPALACHIAN REGION
FIGURE 2-68 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A STRINGENT PERCENT SO2 REMOVAL CONTROL LEVEL
-------
00
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I IMIISCAP- 3 IH» I n. SO?/IOG DTU
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A fCC 1>4 INCH. t.OS. O.
100
PERCENT (IB. SO2/10UUTUI REMOVAL EMISSION LEVEL N. APPALACHIAN REGION
FIGURE 2-69 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A MODERATE PERCENT SO2 REMOVAL CONTROL LEVEL
-------
100
LEGEND
90
80
LIMITS CAP-3.00 LD. SO./lll" flfU
FLOOR -1.20LB.SO /10°DTU
APCC 1)4 INCH, 1.0 S. O.
BPCC 3/8 INCH. 1.3 SO
CMEYERS
D OR AVICI IRM
70
60
O
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to
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60
40
30
20
10
10
20
30
40
50
60
70
80
90
100
PERCENT ILB. SO2/10° BTUl REMOVAL EMISSION LEVEL N. APPALACHIAN REGION
FIGURE 2-70 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET AN INTERMEDIATE PERCENT SO2 REMOVAL CONTROL LEVEL
-------
to
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100
90
80
70
60
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LUiEND
LIMITS CAP 3.00 i.n. so no6 niu
rtoon -1.20 i.n. so2/io8 m u
A rcc i% INCH, 16 s. G. .
B I'CC 3/8 INCH. 1.3 SO
CMEYEOS
OCnAVICIIEM
10
20
PERCENT (LB. SO2/106 BTUJ REMOVAL EMISSION LEVEL N. APPALACHIAN REGION
FIGURE 2-71 PERCENT ENEHGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A STRINGENT PERCENT SOj REMOVAL CONTROL LEVEL
-------
100
90
80
LIMIIS CAI'- 3 oo in. so./io° nru
n.oon - i.?ii LD. stoio* DTU
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PERCENT (LB. SO2/10r> BTUl REMOVAL EMISSION LEVEL EASTERN MIDWEST REGION
FIGURE 2-72 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A MODERATE PERCENT SOj REMOVAL CONTROL LEVEL
-------
100
90
80
70
LECENO
IIMIIS CAT - 3.00 IB. SOj/Kl" nil)
FLOOn -1.70 LO.SO2/1U6OCU
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PERCENT (LB. SO,/106 BTU) REMOVAL EMISSION LEVEL EASTERN MIDWEST REGION
90
100
FIGURE 2-73 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET AN INTERMEDIATE PERCENT SO2 REMOVAL CONTROL LEVEL
-------
10
IEOENO
LIMITS CAP-3.00 LB. SO,/I()B BTU
FLOOH -1.20 LB. SO-/106 BTtl
A PCC IX INCH. 1.88.0.
B PCC 3/8 INCH. 1.3 SO
C MEYERS
D ORAVICHEM
CO
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10
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60
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70
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PERCENT ILB. SO2/106 BTU) REMOVAL EMISSION LEVEL EASTERN MIDWEST REGION
FIGURE 2-74 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A STRINGENT PERCENT SO2 REMOVAL CONTROL LEVEL
-------
100
90
80
70
60
l.rr.END
LIMIlSCAP-3.no in. SO /III0 01 U
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APCC IK INCH, 1.6 S. O.
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PERCENT (LB. SO2/10b OTU) REMOVAL EMISSION LEVEL EASTERN MIDWEST REGION
FIGURE 2-7'J PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET AN INTERMEDIATE PERCENT SO2 REMOVAL CONTROL LEVEL
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PERCENT (LB. SO2/106 BTUl REMOVAL EMISSION LEVEL EASTERN MIDWEST
90
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FIGURE 2-76 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS'
TECHNOLOGIES TO MEET A MODERATE PERCENT SO2 REMOVAL CONTROL LEVEL
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FIGURE 2-77 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS'
TECHNOLOGIES TO MEET A STRINGENT PERCENT SOj REMOVAL CONTROL LEVEL
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PERCENT (LB. SO?/106 BTU) HEMOVAL EMISSION LEVEL WESTERN REGION
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FIGURE 2-78 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A MODERATE PERCENT SO2 REMOVAL CONTROL LEVEL
-------
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PERCENT (LB. SO2/10e BTUl REMOVAL EMISSION LEVEL WESTERN REGION
FIGURE 2-79 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET AN INTERMEDIATE PERCENT SO2 REMOVAL CONTROL LEVEL
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PERCENT |LB. SO2/106 BTU) REMOVAL EMISSION LEVELS WESTERN REGION
FIGURE 2-80 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS '
TECHNOLOGIES TO MEET A STRINGENT PERCENT SO2 REMOVAL CONTROL LEVEL
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FIGURE 2-81 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A MODERATE S02 REMOVAL CONTROL LEVEL
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FIGURE 2-82 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET AN INTERMEDIATE PERCENT SO2 REMOVAL CONTROL LEVEL
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100
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30
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PERCENT (LB. SO2/10b BTU) REMOVAL EMISSION LEVEL WESTERN REGION
FIGURE 2-83 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS '
TECHNOLOGIES TO MEET A STRINGENT PERCENT SO2 REMOVAL CONTROL LEVEL
-------
100
to
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LIMITSCAP-3.0U ID. SO./IO DIU
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70
80
90
100
PERCENT (LB SO2/10° BTU) REMOVAL EMISSION LEVEL ENTIRE U.S.
FIGURE 2-84 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A MODERATE PERCENT S02 REMOVAL CONTROL LEVEL
-------
100
LEGEND
90
80
LIMITS CAP- 3.00 |.fl. SO./IO B1U
ILOOM -1.20111. S02/IOBBTU
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70
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90
100
PERCENT ILB. SOj/IO0 B1UI REMOVAL EMISSION LEVEL ENTIRE U.S.
FIGURE 2-85 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET AN INTERMEDIATE PERCENT SO2 REMOVAL CONTROL LEVEL
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60
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LIMITS CAr-3.00 ID. SO 110° 0?U
FLOOn -I.70LB. SO2/IO°01l»
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CMEYERS
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10 20 30 40 60 60 70
PERCENT (LB. SO,/106 BTU) REMOVAL EMISSION LEVEL ENTIRE U.S.
80
90
100
FIGURE 2-86 PERCENT WEIGHT AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A STRINGENT PERCENT SO2 REMOVAL CONTROL LEVEL
-------
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60
70
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PERCENT (LB. SO2/106 BTU) REMOVAL EMISSION LEVEL ENTIRE U.S.
FIGURE 2-87 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A MODERATE PERCENT SO2 REMOVAL CONTROL LEVEL
-------
100
80
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SO
60
70
80
90
100
PERCENT ILB. SO2/10° BTUI REMOVAL EMISSION LEVEL ENTIRE U.S.
FIGURE 2-88 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET AN INTERMEDIATE PERCENT SO2 REMOVAL CONTROL LEVELS
-------
o
u>
100
90
80
70
60
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Q.
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LEOEND
LIMITSCAr- 3.IMI IB. SO-/IO Dili
noon - i.zo I.D. so2Mo° oru
A PCC 1K INCI I. 1.0 S. O.
D PCC 3/8 INCH, 1.3 SO
CMEYERS
DOnAVICMEM
10 20 30 40 50 60 70
PERCENT (LB. SO2/10° BTU) REMOVAL EMISSION LEVEL ENTIRE U.S.
80
90
100
FIGURE 2-89 PERCENT ENERGY AVAILABLE IN RESERVE BASE AFTER PROCESSING BY VARIOUS
TECHNOLOGIES TO MEET A STRINGENT PERCENT SOj REMOVAL CONTROL LEVEL
-------
at the 90 percent S02 reduction level. At the intermediate emission level
the available coal decreases from a range of 25-30 percent at 0 percent
S02 reduction to less than 10 percent of 90 percent SO2 reduction. At
the stringent emission level, the available coal decreases from a level of
only 10 to 15 percent at 0 percent SO? reduction to less than 3 percent at
90 percent S02 reduction. The trends of decreasing available coal are
also directly applicable to the chemically cleaned coal in this region as
shown on Figures 2-66 to 2-68. The available coal energy in the Northern
Appalachian region as shown on Figures 2-69 to2-71 follows the same
general trends as the weight percent of coal.
The Eastern Midwest region has only a minimal reserve base of cleaned
coal that can meet even the moderate emission level at 0 percent SO2
removal. The reserve base estimates of cleaned coal are shown on Figures
2-72 through 2-77. The physically cleaned coal reserve decreases from 15
percent by weight at 0 percent SO2 removal to less than 5 percent at 80
percent S02 removal. The chemically cleaned coal reserve decreases from
a range of 30 to 35 percent by weight to less than 5 percent at 80 percent
SO2 removal. At the intermediate emission level the quantity of cleaned
coal decreases from a range of 8 to 15 percent at 0 percent removal to
less than 3 percent at 70 percent removal. At the stringent emission
level the quantity and energy available of the cleaned coal starts out
at less than 4 percent at 0 percent removal and decreases to less than 1
percent at 70 percent S02 removal.
The Western region has a much larger reserve base of cleaned coal
which will meet the three emission control levels. Trie reason for this is that
the Western region contains a large quantity of low sulfur coal which is
already below the suggested floor emissions considered for this study.
However, it is interesting to note that as shown on Figures 2-78 to 2- 83
the quantity and energy of available cleaned coal decreases from the 80
to 90 percent level at the moderate level to less than 40 percent at
the stringent level.
The effect of the three emission control levels on cleaned coal from the
entire U.S. is shown on Figures 2-84 through 2-89. At the moderate emission
304
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limits/ the availability of cleaned coal ranges from 55 to 78 percent of
0 percent reduction to 45 to 55 percent at the 80 percent reduction level.
At the intentEdiate emission limits the availability of cleaned coal ranges
from 43 to 65 percent at 0 percent reduction to 30 to 35 percent at the
80 percent reduction level. With the stringent level, quantity of cleaned
coal decreases from a range of 30 to 48 percent at 0 percent reduction to
15 to 25 percent at 80 percent reduction.
The conclusion drawn from the above data is that alternative regulatory
options will have a great effect on the availability of coal resources
in this country for industrial boilers.
305
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SECTION 2
REFERENCES
1. U.S. Department of the Interior, Bureau of Mines, "Demonstrated Coal
Reserve Base of the United States, By Sulfur Category, on January 1,
1974," Mineral Industry Surveys, p.6.
2. Ibid.
3. Ibid., p.7.
4. Ibid.
5. Keystone Coal Industry Manual, U.S. Coal Mine Production by Seam (New
York: McGraw Hill, 1977), p. 12"=5&T.
6. Leonard, Joseph W., et.al., Coal Preparation (New York: The American
Institute of Mining, Metallurgical, and Petroleum Engineers, Inc., 1968)
p. 4-27.
7. Ibid., p. 4-28.
8. MoGraw, Raymond and Gerry Janik, "MCCS-Implementation at Hcmer City,"
p. 107-110 (Cited in Third Symposium on Coal Preparation, October
18-19-20, 1977). !
9. McCandless, Lee C. and Robert G. Shaver, Assessment of Coal Cleaning
Technology: First Annual Report, EPA-600/7-78-150, July, 1978, pp. 105,
127.
10. Leonard, J.W. and T.S. Spicer, Coal Preparation, The American Insti-
tute of Mining, Metallurgical and Petroleum Engineers, Inc., New York,
1968, p. 13-3.
11. Cantos, G.Y., I.F. Frankel and L.C. McCandless, Assessment of Coal
Cleaning^'technology; An Evaluation of Chemical Coal Cleaning Processes,
EPA-600/7-78-173a, Aucrust 1978.
12. Personal Communication with Mr. C.R. Porter, Nedlog Development Co.
August 1977.
13. "Chemical Comminution, An Improved Route to Clean Coal", Catalytic, Inc.
Philadelphia, Pennsylvania. 1977 , p. 1.
14. Kbutsoukos, E.P., M.L. Draft, R.A. Orsins, R.A. Meyers, M.J. Santy and
L.J. Van Nice (TRW Inc.), "Final Report Program for Bench-Scale Devel-
opment o- Processes for the Chemical Extracting of Sulfur from Coal"
Environmental Protection Agency Series, EPA-606/2-76-143a. (May 1976).
15. Kennecott Chemical Coal Desulfurization Process, in-house report. 1977.,
iV. 12-13.
16. Friedman, S. and Warrinski, R.P. "Chemical Cleaning of Coal", TRANS-
ASME 99A, 361 (1977).
306
-------
17. Friedman, S. et.al. "Qxidative Desulfurization of Coal", ACS Symposium
Series, 64_, p. 164 (1977)
18. Zavitsanos, P., "Coal Desulfurization by Microwave Energy", EPA-6 00/7-78-0 89,
General Electric Co. , Re-Entry & Environmental Systems Division, Philadelphia,
Pennsylvania. June 1978. pp. 32-58.
19. Ibid, pp. 1-5.
20. Stambaugh, E.P. , "Study of the Battelle Hvdrothermal Coal Process",
EPA Draft Report. November 1976.
21. Battelle in-house report July 30, 1976. p. 5.
22. Ganguli, P.S., HSU, G.C., Gavalas, G.R., Kalfayan, S.H. , "Desulfuriza-
tion of Coal by Chlorinolysis " , Vol. 21, No. 7~, Preprints of Papers
Presented at San Francisco, California. August 29-September 3, 1976.
23. Fleming, Donald K. , et.al., "Hydrodesulfurization of Coals", Institute
of Gas Technology, paper presented at 173rd ACS National Meeting, New
Orleans, Louisiana. March 20-25, 1977.
24. Guth, E.D. and Robinson, J.M. "KVB Coal Desulfurization Process" KVB
Brochure. March 1977.
25. Trip Report to Electric Power Research Institute, Palo Alto, Calif.,
with Sheldon Ehrlich, Program Manager, Coal Cleaning; August 9, 1977.
26. Compilation of Air Pollutant Factors, Second Edition, AP-42, April
1973. p. 1.1.3.
27. flmpi 1 ^tion of Air Pollutant Factors , Supplement No. 5, AP-42, Feb-
ruary 1976, p. 1.7.2.
28. Congressional Budget Office, 1978. Replacing Oil and Natural Gas with
Coal; Prospects in the Manufacturing Industries, p.22. (Cited in
Energy Users Report, 5 October 1978, page 16.)
29. U.S. Dept. of Commerce, Bureau of the Census, 1977. Annual Survey of
Manufacturers, 1975. Sept 1977 [M 75 (AS) -4], pp. 22, 48-106
Table 3.
30. Op. cit., reference 28.
31 • OP* cit., reference 29.
32. Department of Energy, FERC, Office of Electric Powsr Regulation, 1978.
"Status of Coal Supply Hontracts for New Electric Generating Units
1977-1986," May 197~8, pp. 52-53.
33. Op. cit.. reference 29.
34. Op. cit., reference 28.
35. Schweiger, B. "Industrial Boilers: What's Happening Today." Power,
Vol. 121, No. 2 (February 1977, Part I) and Vol. 122, No. 2 (Feb-
ruary 1978, Part II, p. S.2).
307
-------
36. Coal Vfeek, Vbl. 4, Kb. 42. 16 October 1978 (McGraw-Hill), pp. 8-9.
37. U.S. Department of the Interior, Bureau of Mines. Mineral Industry
Surveys, "Goal-Bituminous and Lignite in 1975" (preliminary release)
p. 66.
38. Batelle Columbus laboratories. Reserve Processing Assessment Method-
ology (RPAM).
39. Maloney, K.L., Moilanen, G.L., and Langsjoen, P.L., "Low-Sulfur
Western Coal Use in Existing Small and Intermediate Size Boilers",
EPA Report EPA-600/7-78-153a, (July 1978).
40. Argonne National Laboratories, Environmental Control Implications of
Generating Electric Power From Coal, 1977 Technology Status Report.
41. U.S. Bureau of Mines Mineral Yearbooks 1942, 1952, 1962, 1972, U.S.
Government Printing Office, ttoshington, D.C.
42. Batelle Columbus laboratories. Section II, Emission Control Techniques
(Low Sulfur Coal and Physical and Chemical Coal Cleaning), Draft Report;
p. 1-6.
43. Miller, K.J., "Flotation of Pyrite from Coal Pilot Plant Study", U.S.
Bureau of Mines, KI 7822 (1973)., Trans. AIME 258, 30 (1975).
44. Miller, K.J., "Coal-Pyrite Flotation", Trans. AIME 258, 30 (1975).
45. Trindale, S.C., Howard, J.B., Holm, H.H., and Powers, C.J., "Magnetic
Desulfurization of Coal", Fuel 53, p. 178 (1974).
46. Murray, H.H., "High Ihtesity Magnetic Cleaning of Bituminous Coal",
NCA-2nd Symposium on Coal Preparation, Louisville, Kentucky (October
1976).
47. Keller, D.V., Jr., Smith, C.D., and Burch, E.F., "Demonstration Plant
Test Results of the Otisca Process Heavy Liquid Beneficiation of Coal",
presented at the Annual SME-AIME Conference, Atlanta, Georgia (March
1977).
48. Op. Cit., Reference 40, p. 382.
49. Draft Final Task Report, SO2 Emission Reduction Data from Commercial
Physical Coal Cleaning Plants and Analysis of Product Sulfur Varia-
bility. Task 6CO. Contract No. EPA-68-02-2199. October 18, 1978.
50. Ibid, p. 15
51. Ibid, pp. 16-24.
52. Ibid, pp. 28-29.
308
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53. Ibid, p. 12.
54. Background Information for Standards of Performance: Coal Preparation
Plants/ (Unpublished) / Background Data.'
55. Battelle Columbus Laboratory, Sulfur Reduction Potential of U.S. Goal
Using Selected Goal Cleaning 'techniques. June 26, 1978. Appendices A-D.
56. Sargent, D. H., et al, "Effect of Physical Coal Cleaning Upon Sulfur
Variability, November 15, 1979.
57. Preliminary Evaluation of Sulfur Variability in Low-Sulfur Coals from
Selected Mines. U.S. EPA 450/3-77-044. November 1977.
58. Op. CLt., reference 48, pp. 33-59.
59. Op. CLt., reference 38.
60. Qp. CLt., reference 38.
61. Cp. CLt., reference 11.
62. Schultz, H., E. Hattman, W. Booker, "Trace Elements in Goal - What
Happens to Them?" American Chemical Society Maeting, paper no. 74,
Philadelphia, April 1975.
63. Hamersma, J.W., M.L. Kraft and R.A. Meyers (TEW, Inc.) "Applicability
of the Meyers' Process for Desulfurization of U.S. Coal (A Survey of
15 Coals) A paper presenting experimental results. 1975.
64. Cp. CLt., reference 14.
65. Cp. CLt., reference 63.
66. Hamersma, J.W., M.L. Kraft "Applicability of the Meyers' Process
for Chemical Desulfurization of Coal: Survey of Fifteen Coals,"
Environmental Protection Technology Series, EPA-650/2-74-025a.
67. U.S. Patent 3,960,513, "Method for Removal of Sulfur from Coal", June
1, 1976.
68. Kennecott Chemical Coal Desulfurization Process, in-house report. 1977.
69. Personal Gommunication, Dr. L.J. Petrovic, Ledgemont Laboratory,
Kennecott Copper Corporation, Lexington, Massachusetts.
70 Ergun, S., R.R. Oder, L. Kolapaditharom and A.K. Lee (Bechtel Corpora-
tion), "An Analysis of Chemical Coal Cleaning Processes", Bureau of
Mines, U.S. Department of the Interior, Contract No. J0166191. (June
1977).
71 Personal Communication with Mr. C.R. Porter, Nedlog Development Co.
August 1977.
309
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72. Porter, C.R. and D.N. Goens, "Magnex Pilot Plant Evaluation - A Dry
Chemical Process for the Removal of Pyrite and Ash from Coal," draft
of a paper to be presented at the SME-AIME Fall Meeting and Exhibit,
St. Louis, Missouri, October 1977.
73. "Chemical ConTninution, An Improved Route to Clean Coal", Catalytic,
Inc. Philadelphia, Pennsylvania, 19 77.
74. "Feasibility Study of Pre-Combustion Coal Cleaning Using Chemical
Comrtiinution; Final Report" Datta, R.S., Et.al., Syracuse Research Corp.,
Syracuse, N.Y. November 1976. EFDA Contract No. 14-32-0001-1777.
75. Personal Communication with G. Higginson, of Catalytic, Inc. August
24, 1977.
76. Friedman, S. and Warrinski, R.P. "Chemical Cleaning of Coal", TRANS-
ASME 99A, p. 361 (1977).
77. Personal Communication with S. Friedman, Pittsburgh Energy Research
Center (DCE). August 1977.
78. Friedman, S. et al. "Qxidative Desulfurization of Coal", ACS Symposium
Series, 64_, 164 (1977).
79. Cleland, J.G., "Chemical Coal Cleaning, RTI, for lERL/RTP/EPA. 1976.
80. Stambaugh, E.P., "Study of the Battelle Hydrothermal Coal Process",
EPA Draft Report. November 1976.
81. Ganguli, P.S., HSU, G.C., Gavalas, G.R., Kalfayan, S.H., "Desulfuriza-
tion of Coal by Chlorinolysis11, Vol. 21, No. 7, Preprints of Papers
Presented at San Francisco, California. August 29-September 3, 1976.
82. HSU, G.C., Kalvinskas, J.J., Ganguli, P.S., & Gavalas, G.R., "Coal
Desulfurization by Low Temperature Chlorinolysis", not published.
83. Fleming, Donald K., et.al., "Hydrodesulfurization of Coals", Institute
of Gas Technology, paper presented at 173rd ACS National Meeting, New
Orleans, Louisiana. March 20-25, 1977.
84. Guth, E.D. and Robinson, J.M. "KVB Coal Desulfurization Process" KVB
Brochure. March 1977.
85. U.S. Patent 3,909,211 Assigned to KVB Engineering, Inc., Tustin,
California. September 30, 1975.
310
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SECTION 3.0
"BEST" SYSTEMS OF EMISSION REDUCTION
3.1 CRITERIA FOR SELECTION
In the ensuing discussion of emission control technologies, candidate
technologies are conpared using three emission control levels labelled
"moderate, intermediate, and stringent." These control levels were chosen
only to encompass all candidate technologies and form bases for comparison
of technologies for control of specific pollutants considering performance,
costs, energy, and non-air environmental effects.
From these comparisons, candidate "best" technologies for control of
individual pollutants, i.e., Best Systems of Emission Reduction (BSER),
are recommended by the contractor for consideration in subsequent industrial
boiler studies. These "best technology" reoomrrendations do not consider
combinations of technologies to remove more than one pollutant and have
not undergone the detailed environmental, cost, and energy impact assess-
ments necessary for regulatory action. Therefore, the levels of "moderate,
intermediate, and stringent" and the recommendation of "best technology" for
individual pollutants are not to be construed as indicative of the regula-
tions that will be developed for industrial boilers. EPA will perform
rigorous examination of several comprehensive regulatory options before any
decisions are made regarding the standards for emissions from industrial
boilers. Within this ITAR, the BSER may be a naturally occurring compliance
coal, a physical coal cleaning process, or a chemical coal cleaning process.
3.1.1 Operating Factors
Five criteria for selecting the BSER are applied: performance and
applicability; preliminary cost; status of development; preliminary energy
use; and preliminary environmental considerations. The descriptor
"preliminary" signifies that the values are based on previous studies of a
general nature and should be considered only as order-of-magnitude values.
After selecting the oSER, more detailed analyses of cost (Section 4.0),
energy use (Section 5.0), and environmental impact (Section 6.0) will be
311
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developed. For determination of the BSER, the first two criteria, per-
formance and cost, will be weighted more than the other three, status,
environmental impacts, and energy use.
3.1.1.1 Performance and Applicability—
Performance is given the most weight of the five operating factor
elements in selecting a BSER. Performance relative to industrial boilers
applies to control of particulates, sulfur dioxide, and nitrogen oxide
emissions. Particulate emissions will require in-stack control devices
because no naturally occurring or cleaned coal is ash-free. Physically
cleaned coal does contain less ash, thereby reducing the particulate
emission control requirements. However, this reduction will not be
considered a major factor in determining the BSER performance.
Ihe majority of nitrogen in the nitrogen oxide emissions from industrial
boilers originates from the combustion air aupply. The control
technologies studied in this ITAR have no effect on the amount of air delivered
to the boiler. Physical coal cleaning does not reduce the inherent nitrogen
content in the fuel itself; although chemical coal cleaning may reduce the
inherent nitrogen content of the coal, the available results are inconclusive.
Therefore, nitrogen oxide reduction capabilities will not be considered among
the performance factors.
Physical and chemical coal cleaning can significantly increase the coal's
energy content and reduce sulfur content in the ash and pyrite removal process.
For certain coals this simultaneous BTU enhancement and sulfur removal
capability can produce significant reductions in sulfur dioxide emissions.
Combustion of a naturally-occurring low sulfur coal rather than high sulfur
coal may also substantially reduce S02 emissions from existing industrial
boilers.
In this report we generally refer to the emissions of sulfur in terms
of the mass of SO2 emitted per unit of combustion energy in the coal (ng SO2/J
or Ib S02/106BTU), as is done in EPA's proposed New Source Performance
Standards (NSPS) for utility boilers'. This emission factor is used for both
maximum allowable SOa emissions and the percentage of S02 removal. This basis
reflects the wide range of heating values (kJ/kg or BTU/lb) among coals.
312
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3.1.1.2 Preliminary Cost—
Cost is considered an important criterion for selecting a BSER for a
particular coal and emission control level once performance is demonstrated.
Preliminary costs used here are historical costs, referring to a
generic type of control system. For example, there are generic costs for
Level 4 (process levels as defined in Section 2.0, pp. 120 through 134
physical coal cleaning plants. These costs, rather than the costs associ-
ated with a detailed analysis of a particular system configuration, will be
used in judging a Level 4 cleaning plant as a candidate BSER.
Preliminary transportation costs are estimated by matching seven supply
coals and six demand centroids. The seven supply coals include six low
sulfur coals (see Section 3.2.1.1) and one high sulfur coal—a bituminous
coal from Butler, Pennsylvania. The selected destinations are industrial cities
within the six states that have the greatest industrial energy demand:
• Austin, Texas
• Harrisburg, Pennsylvania
• Columbus, Chio
• Baton Rouge, Louisiana
• Sacramento, California
• Springfield, Illinois
Transportation of coal presently includes two modes, rail and barge;
the use of slurry pipelines may begin sometime during the coming decade.
The main cost components for cleaned coals are the spot market F.O.B.
mine price; the coal cleaning charge, which is a function of the type and
level of cleaning; and transportation costs. The characteristics of the
raw coal and the desired product must be investigated before designing a
cleaning plant and estimating the costs. In general, the finer a coal is
crushed, the more impurities are liberated. As the coal size is reduced,
the coal plant for cleaning and dewatering the fines becomes more complex
and, therefore, more costly. The transportation costs in dollars per
unit of combustion energy are lower for cleaned coal (more so for physically
cleaned than chemically-cleaned coal) because cleaning the coal reduces its
weight per unit heat input.
313
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3.1.1.3 Status of Development—
Status of development is defined as the commercial availability of
the control technology. For naturally occurring coal, both the ability to
profitably mine a given coal seam and the relation of supply and demand
influence the status of the coal. For purposes of discussion and selection
of BSER, it is assumed that the reference coals can be profitably mined
and are available on the spot market.
A number of physical coal cleaning (PCC) processes are conmercially
available, as discussed in Section 2.0. A candidate PCC plant configuration
will be considered available, even though no such plant exists. Less
consideration is given to any plant configuration which uses present
technology beyond its current application. There are sons experimental
PCC processes which are not connercially available (see Section 2.2.2.1);
they are not considered in this section.
Chemical coal cleaning plants are presently in the research and
development stage. Sortie pilot plant tests have been performed on several
processes, and testing is continuing. Present estimates are that chemical
coal cleaning plants are about 5-10 years from oommercializaticn. More
weight will be given to those processes at the pilot plant stage which
have plans for commercialization than to bench-scale processes.
3.1.1.4 Preliminary Biergy Use—
Qiergy use is defined here as the energy required to implement a
control technology. Only pre-combustion activities, excluding mining,
are considered in selecting a BSER.
For naturally c>ccurrlng low sulfur coals the primary energy use is
in coal transportation. The breakdown by mode of transport for the total
amount of coal produced in the U.S. in 1975 is given in Table 3-1.
As may be seen from the table, rail transport consumes petroleum-fuel
energy at the rate of approximately 1.44 x 105 J per metric ton-km (200 BTU
per ton mile), excluding the energy used for return rail hauls and for
operations related to loading and unloading. Including the energy used in
those activities raises the average energy consumption of delivered coal to
314
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Table 3-1 TRANSPORTATION OF U.S. COAL PRODUCED IN 1975
Mass of Coal Moved
Mode of Transport* (103 kkg)
Rail 379.60
Barge 62.72
Truck 79.36
Other** 74.29
Total Production 588.70
* Leaving the mine. In sane cases coal initially moved by rail is
transshipped to a barge for final delivery to the consumer.
** Includes coal moved by conveyor belt to mine-mouth povrer plants,
coal used at mine for povrer or heat and other miscellaneous uses,
and coal shipped by slurry pipeline to the Black Mesa Mine In
Arizona.
315
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2.52 x 105 J per metric ton-km (366 BTU per ton-mile). The most energy-
efficient mode of transporting coal occurs on waterways: by barge on inland
rivers and by ship on ocean or Great Lakes routes. Barges, on the average,
consume approximately 2.12 x 105 J per metric ton-km (296 BTU per ton-mile)
of delivered coal, with some variation depending on the angle between the
velocity of the barge and the velocity of the water current.
For physically and chemically cleaned coal, the energy use is a
combination of cleaning requirements and transportation. The energy used for
cleaning is primarily the energy lost in the rejects. The operations
that use significant amounts of energy are pulverizing, dewatering, and
thermal drying.
3.1.1.5 Preliminary Environmental Considerations—
One of the main objectives of coal preparation is to reduce the quantity
of pollutants in coal that is burned. Coal preparation involves, however,
the transfer of potential pollutants from one segment of the environment to
another: a fraction of the pollutants that would be emitted to air during
the burning of raw coal become incorporated mainly into solid refuse, a
state in which the pollutants may be easier to control.
The major potential sources of environmental contamination from coal
preparation that will be assessed include: coal refuse disposal areas (solid
waste), thermal dryers (air pollution), liquid effluent streams (water
pollution), coal storage and handling (fugitive dust and runoff), and
coal transportation (fugitive dust).
The disposal of coal cleaning plant waste is a potentially serious
problem. Goal refuse consists of waste coal, slate, carbonaceous and
pyritic shales, and clay associated with the coal seam. It varies consider-
ably in physical and chemical characteristics depending on both its source
and the nature of the preparation process.
The weathering and leaching of coal refuse dumps produces several types
of water pollution. Ihese include silt, acids, and other dissolved mineral
matter. Refuse fron chemical coal cleaning plants have additional chemical
constituents due to the solvents used in removing sulfur during the
cleaning processes.
Siltation from coal refuse dumps is caused by finely divided coal,
minerals and discarded soil. Acid drainage is produced when iron sulfides
316
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are exposed to air and water. The sulfur is oxidized to sulfuric acid, and
the iron is solubilized as iron sulfate. The acids formed run off into
drainage ditches or percolate through the pile, where considerable mineral
matter may be dissolved. The volume of wastewater from a refuse disposal
area is highly dependent on precipitation and surface water flow patterns.
In contrast to the highly acidic nature of drainage from coal fields
in eastern and interior regions, the runoff from western coal refuse
disposal is usually alkaline. The dominant water contaminants are calcium,
magnesium, and sodium salts. The low concentrations of iron and sulfates
are direct results of the low concentrations of pyrltic material in western
coal. Furthermore, the annual precipitation in western coal fields is
generally low, so that the chances of significant drainage of water through
the waste materials are remote.
Potential air pollutants associated with physical coal cleaning are
particulate emissions, and to a lesser extent SOa, and fugitive ooal dust.
Chemical coal cleaning processes/however, produce additional air pollutants
including NO and CD and fine particulates. The fine particulate and SO2
X
emissions from both physical and chemical processes are largely caused by
(if\
the thermal drying process. '
Ooal cleaning operations produce two types of water pollutants: suspended
materials and dissolved substances. The effluent streams from physical
and chemical cleaning processes contain similar concentrations of suspended
solids* However,dissolved substances from a chemical cleaning plant would
contain small amounts of the solvents used. These solvents may also
dissolve other mineral compounds and metal ions contained in the coal, thus
changing the chemical characterization of the waste stream.
The principal air pollutant from storage, transportation and handling
of naturally occurring and cleaned coal—especially thermally dried cleaned
ooal—is fugitive dust. The amount of dust generated varies widely depending
on such factors as climate, topography, and characteristics of coal.
Another environmental consideration associated with coal storage is
coal pile leachate contaminating ground water supplies. Outdoor coal
storage piles have large surface areas and long residence times allowing
317
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rainwater to react and form acids or extract sulfur conpounds and soluble
metal ions. Coal pile leachate is generally similar to acid mine
drainage. The quantity of coal pile leachate is highly variable depending
upon the coal residence time/ the topography and drainage area of thfe coal
pile site, the configuration and volute of the stock pile, and the type
and intensity of precipitation.
3.1.2 Selection of Regulatory Options
A set of SOz emission control levels is used to judge the performance of
the candidate control options. Since the control technologies considered
in this ITAR reduce neither nitrogen oxide nor particulate emissions
from industrial boilers to a level comparable to current particulate
control technology, emission levels are not considered for these pollutants.
The SO2 emission levels chosen to evaluate naturally occurring
low sulfur coal and physical and chemical coal cleaning control technologies
are: 1) stringent— 516 ng SO2/J (1.2 Ibs S02/106 BTU) , 2) intermediate—
645 ng SO2/J (1.5 Ibs S02/106 BTU) , 3) optional moderate— 860 ng S02/J
(2.0 Ibs S02/106 BTU) , 4) moderate— 1,290 ng S02/J (3.0 Ibs S02/106 BTU) ,
and 5) the State Implementation Plan (SIP)— 1,075 ng SO2/J (2.5 Ibs SO2/106
BTU).
The selected levels specified in this ITAR are based upon long term
averages of SO2 emitted per unit of combustion energy.
Stringent Level of Control —
The most stringent level of control chosen for evaluation of the
three control technologies is 516 ng SO2/J (1.2 Ibs SO2/106 BTU). It is
selected for twD reasons. The primary reason relates to the amount of
potentially available coal in each region and the total U.S., based upon
the reserve base assessments discussed in Section 2.0 and shown in surtmary
Tables 3-2 and 3- 3. These assessments shew in a very forceful way that the
318
-------
available raw coal and physically and chemically cleaned coal below an
emission level of 516 ng SOa/J (1.2 Ibs S02/106 BTU) decrease drastically.
At this emission level, the anoint of energy available for the entire U.S.
was estimated to be only 38% for naturally occurring coal, 50% and below
for physical coal cleaning processes, and 59% and below for chemical coal
cleaning processes. The second reason for choosing this level is that it
is currently the NSPS (New Source Performance Standard) emission limit
for utility boilers greater than approximately 75 Mfe. It therefore represents
an existing achievable level for large scale boilers.
Intermediate Level of Control—
The intermediate level of control chosen for evaluation of the three
control technologies is 645 ng SO2/J (1.5 Ibs S02/106 B1U). The rationale
for the selection of this level is based upon the amount of potentially
available coal estimated by the reserve base assessment and shown in
summary Tables 3-2 and 3-3. This emission level illustrates a break-
point in the reserve quantity curves for physically and chemically
cleaned coal in the regions and throucfliout the U.S. For example, the
Southern Appalachian and Alabama regions have much less energy available
as either physically or chemically cleaned coal at the 645 ng S02/J
(1.5 Ibs S02AOS BTU) level.
"Optional" Moderate Level of Control—
The "optional" moderate level of control chosen, 860 ng S02/J.
(2.0 Ibs SO2/106 BTU), reflects a breakpoint in potentially available coal
(and therefore the amount of energy available) for the Southern Appalachian
and Vfestern regions from raw coal, physically cleaned coal, or chemically
cleaned coal. The Alabama region also shows a breakpoint in potentially
available coal at the "optional" moderate level, but only for chemical
coal cleaning.
Moderate Level of Control—
The moderate level of control chosen, based upon current practices
of the industry, is 1,290 ng S02/J {3.0 Ibs SO2/106 BTU). The selection
of this level is based upon the amount of ootentially available coal from
physical cleaning processes shown on Table 3-2.
319
-------
TABLE 3-2.
CO
to
o
WEIGHT PERCENT OF U.S. REGIONAL COAL RESERVE BASE
AVAILABLE AT VARIOUS S02 EMISSION LIMITS FOR
RAW AND PHYSICALLY OEANED COAL (s)
N. APPAIACIIIA
S. APPAIACHIA
ALABAMA
E. MIDWEST
W. MIDWEST
WESTERN
ENTIRE U.S.
344(0.8)*
A B RAW
4 13 1
23 28 9
7 76
1 11
4 50
70 71 45
36 40 24
516 (1.2)*
A B RAW
12 24 6
64 67 53
36 41 29
3 32
5 11 6
85 85 70
50 53 41
645 (1.5)*
A B RAW
20 35 10
81 82 75
55 66 48
462
6 13 6
92 92 85
55 60 48
860 (2.0)*
A B RAW
30 47 15
86 88 82
72 82 C8
9 11 5
13 18 11
97 96 90
60 66 55
1,075 (2.5)*
A B RAW
41 58 24
91 93 90
90 94 74
13 17 8
17 20 13
97 97 95
65 69 58
1,290 (3.0)*
A B RAW
50 66 31
93 94 92
93 96 90
18 25 10
20 23 16
98 98 96
69 73 63
PERCENT ENERGY AVAILABLE OF u.s. REGIONAL COAL
RESERVE BASE AT VARIOUS S02 EMISSION LIMITS FOR
RAW AND PHYSICAI.LY CLEANED COAL
N. APPALACIIIA
S. APPALACHIA
ALABAMA
F.. MIDWKST
W. MIDWEST
WESTERN
ENTIRr; U.S.
344 (0.8)*
A B RAW
5 13 1
24 29 9
6 67
2 20
3 4 0
70 71 45
32 36 20
516 (1.2)*
A B RAW
12 28 8
66 69 54
37 42 29
3 31
7 13 7
85 85 71
47 50 38
645 (1.5)*
A B RAW
20 35 10
80 85 72
63 73 46
573
9 15 9
94 94 82
54 59 45
860 (2.0)*
A B RAW
31 48 15
90 93 84
72 82 69
9 12 6
15 20 10
96 97 90
59 62 52
1,075 (2.5)*
A B RAW
42 60 26
94 94 90
90 94 75
12 19 8
20 22 14
97 97 94
64 68 56
1,290 (3.0)*
A B RAW
52 70 32
94 95 90
93 96 90
18 26 10
22 25 18
98 98 98
68 75 60
A - PCC 1-1/2 inch, 1.6 S.G.
B - FCC 3/8 inch, 1.4 or 1.3 S.G.
* Emission limits are in ng SO?/J (Ibs SO^/1011 BTU)
-------
TABLE 3-3.
WEIGHT PERCENT OF U.S. REGIONAL COAL RESERVE AVAILABLE
AT VARIOUS SO? EMISSION LIMITS FOR RAW AND CHEMICALLY
CLEANED COAL {*)
N. APPALACniA
S. APFAUCHIA
ALABAMA
E. MIDWEST
W. MIDWEST
WESTERN
ENTIRE U.S.
344 (0.8)*
C D E RAW
5 9 17 1
19 25 46 9
7 7 31 6
2241
2 8 11 0
59 64 77 45
31 35 45 24
516 (1.2)*
C D E RAW
21 26 36 6
59 67 80 53
46 47 75 29
4492
14 17 18 6
79 80 89 70
49 51 59 41
645 (1.5)*
C D E RAW
35 42 50 10
74 83 88 75
79 85 94 48
8 9 14 2
16 17 22 6
84 85 93 85
55 60 65 48
860 (2.0)*
C D E RAW
53 58 65 15
90 90 94 82
95 96 98 68
15 15. 20 5
26 24 29 11
93 93 97 90
64 67 72 55
1,075 (2.5)*
C D E RAW
67 68 76 24
93 95 98 90
98 98 98 74
22 22 37 8
41 37 51 13
96 96 98 95
71 74 77 58
1,290 (3.0)*
C D E RAW
79 81 85 31
98 98 99 92
99 99 99 90
36 32 61 10
50 46 62 16
99 98 99 96
78 80 85 63
u>
to
PERCENT ENERGY AVAILABLE OF U.S. REGIONAL COAL RESERVE
BASE AT VARIOUS S02 EMISSION LIMITS FOR RAW AND CHEMICALLY
CLEANED COAL ^ .
N. Appalachia
S. Appalachia
Alabama
E. Midwest
W. Midwest
Vfestem
Entire U.S.
344 (0.8)*
C D E RAH
6 9 18 1
19 26 48 9
8 8 32 7
1140
3 9 14 0
59 65 79 45
28 32 42 20
516 (1.2)*
C D E RAW
13 19 28 8
60 69 81 54
48 49 76 29
4 5 10 1
15 18 19 7
80 81 90 71
46 49 57 38
645 (1.5)*
C D E RAW
31 36 45 10
79 83 87 72
70 78 90 46
6 9 13 3
19 20 22 9
88 88 94 82
55 57 63 45
860 (2.0)*
C D E RAW
55 56 65 15
88 90 94 84
92 97 99 69
14 14 20 6
30 25 32 10
94 93 96 90
64 64 69 52
1,075 (2.5)*
C D E RAW
65 68 77 26
94 96 98 90
98 98 98 75
21 21 34 8
41 35 49 14
98 98 99 94
70 70 78 56
1,290 (3.0)*
C D E RAW
81 82 P8 32
98 98 99 90
99 99 99 90
39 34 55 10
52 49 61 18
99 99 99 98
79 78 84 60
C - Meyer's Process
D - Gravichan
E - .95 Py.S./.20 Org. S. Removal
* Emission units are in ng SOj/J (Ibs S0?/10f> BTU)
-------
This emission level would make available more than 90% of both raw ooal
and physically and chemically cleaned coal from the Southern Appalachian,
Alabama, and Western regions. High emission levels are needed to allow
appreciable amounts of eastern and midwestern raw coals to comply.
SIP Level of Control--
The SIP level of control was supplied in an August 29, 1978 memorandum
from Acurex Corporation: 1,075 ng S02/J (2.5 Ibs S02/106 BTU). At this
emission level, the amounts of both raw coal and physically and chemically
cleaned coal from the Southern Appalachian, Alabama, and Western Regions
reach a peak and begin to level off with only small increases thereafter.
3.2 BEST SYSTEMS OF EMISSION HEDUCTIQN (BSER)
3.2.1 Description of Candidate BSERs
Ihis section provides the rationale for choosing the candidate BSERs
and presents the selections. The methodology is to evaluate the major
characteristics of the available control technologies relative to the five
operating factors presented in Section 3.1.1 and the regulatory options
chosen in Section 3.1.2.
The candidate BSERs will then be compared and a BSER chosen in Section
3.2.2 for each reference coal and regulatory option combination.
3.2.1.1 Candidate Naturally Occurring Coals—
In this section we introduce the set of reference high- and low sulfur
coals which were chosen (based on engineering judgment) as representative
of the myriad of coals available to the industrial boiler operator. A
greater variety of low sulfur western coals were considered candidates
because of their ability to meet lower sulfur dioxide emission levels
and their lower costs. Ihe candidates are:
• High . ulfur bituminous coal from Butler, Pennsylvania;
• Bituminous coal from Buchanan, Virginia;
• Subbituminous coal from Gillette, in northern Wyoming;
• Bituminous coal from Las Animas, Colorado;
• Lignite from Williston, North Dakota;
• Bituminous coal from Rock Springs, in southern Wyoming; and
• Subbituminous ooal from Gallup, New Mexico
322
-------
Of these seven coals, the first three are the reference coals chosen to
represent the coals used by PEDCo in developing parameters for standard
boilers. Ihe remaining candidates have been selected to represent
typical low sulfur coals from various western locations. The major
relevant characteristics of these coals are summarized in Table 3-4.
Performance
Many alternatives for the supply of naturally occurring coal are
available to meet environmental constraints. The criteria for determining
which (low sulfur) coals from which region will be able to comply with a
given SOz emission control level include the coal's estimated sulfur
content, ash content, and heating value. These characteristics influence
a coal's combustion properties and the degree to which sulfur oxides and
other pollutants are generated in the boiler. The level of these pollutants
and the eventual concentration of emissions in the atmosphere may then be
reduced by the use of other control technologies.
Each candidate low sulfur coal can comply with only certain environ-
mental constraints. Table 3-5 compares, for each coal, the level of
uncontrolled SO2 emissions per unit energy of coal burned with three
alternative SO2 emission levels. In general, stringent control levels can
be met only by select low sulfur coals of subbituminous or higher rank.
Goal with a sulfur content of one percent must have an energy content
exceeding about 31 x 106 J/kg (14,000 BTU/lb) to meet the stringent control
level, assuming that the sulfur contained by the boiler (bottom ash) is
approximately 15 percent of that originally in the coal. From both
Tables 3-4 and 3-5 we see that the western coals from Las Animas, Colorado
and Itock Springs, Wyoming are the only candidates that meet the stringent
control levels.
Intermediate control levels may be mat by low sulfur coals of subbituminous
or higher rank. Goal with a sulfur content of one percent must have an
energy content of nore than about 26 x 106 JAg (11/000 BTU/lb) to meet inter-
nediate control levels, assuming that the sulfur retained by the bottom ash
is approximately 15 percent of that originally in the coal.
323
-------
TABLE 3-4. CHARACTERISTICS OF CANDIDATE LCW-SULFUR GOALS1
U)
tow-Sulfur Coals
lleatiny Value
106 J/Kg
(Utu/lb)
Sulfur Content
•i 'lX)tal
Ash Content
I
Moisture %
as received
Vo 1 a t v 1 e
Matter '-4
Fixed
Carbon V,
Hydrogen %
Oxygon 'i
Nitrogen %
Uuclianan,
Va. (B)*
31,7
(13,620
1.18
10.38
2.0
13
75
4.1)
5.9
1 .4
Los Animas,
Colo. (B)
26.3
(11,290)
0.59
24.81
2.5
12
62
3.9
6.1
1.2
Williston,
N. Dak. (L)
16,. 3
(7,000)
0.80
6.8
35
12
4d
6.2
39
0.70
Rock Springs,
Wyo. (B)
26.7
(11,500)
0,00
9.0
11
15
65
5.0
21.5
0.10
Gillette,
Wyo. (SB)
19.8
(8,500)
0..70
8.1
30
29
33
4.5
27.9
0.75
Gallup,
N.M. (SB)
23.3
(10,000)
0.80
9.4
10
19
62
5.0
21.5
1.0
NoLu: II - Bituminous; HB ;= Hubbituminous; L - Lignite.
* 'I'liuso coals are analyzed as candidate's for coal cleaning.
-------
TABLE 3-5. COMPARISON CF UNOOOTHDILED EMISSIONS FROM CAMHDATE
LOW-SULFUR GOALS WITH ALTERNATIVE ENVIRONMENTAL CONTROL LEVEL (ng/J)
UJ
NJ
U1
Rwironmental Control Level ^
Candidate Coals
Moderate
(1,290 ng SO2/J)
"Optional"
Moderate
(860 ng SO2/J)
Intermediate
(645 ng SO2/J)
Stringent
(516 ng S02/J)
Butler, Pa. (B) «
Buchanan, Va. (B) «
Las Animas, Colo. (B)
Williston, N.Dak. (L)
Rock Springs, Wyo. (B)
Gillette, Wyo. (SB)
Gallup, N.M. (SB)
2,060$
707
835
381
508
602
584
Note; B = Bituminous; SB = Siibbituminous; L = Lignite.
3 Assuned fraction of sulfur in the bottom ash: 5 percent for bituminous coal, 15 percent for
all other coals.
« These coals are analyzed as candidates for coal cleaning.
<(> Does not conply with moderate control level
-------
Table 3-5 shows that the low-ranking coal from Gillette, Wyoming (with
19.8 x 106 J/kqr 0.70 %S) and the subbituminous coal from Gallup, New
ffexico (23.3 x 106 JAg/ 0.80 %S) both meet the intermediate control level.
"Optional" moderate and moderate control levels may be achieved by low
sulfur coals of nearly any rank, including lignites. Cbal with a sulfur
content of one percent must have an energy content exceeding only about 13.1 x
10$ JAg (5,666 BTU/lb) to meet moderate control levels for the sams boiler
assumption given above. The bituminous coal from Buchanan, Virginia, and
the lignites from Williston, North Dakota, meet the "optional" moderate
control level, while the high sulfur eastern coal from Butler, Pennsylvania
exceeds the moderate control level.
Post
F.O.B. mine prices (both term and spot prices) are shown in Table 3-6
for the reference coals. Except where indicated otherwise, these are
May, 1978 prices. Shipping costs are estimated from indices pro-
vided by the Bureau of labor Statistics for railroad coal transport
from 1969 through 1978. Through the use of these indices, the shipping
cost for a metric ton of coal was estimated at $6.87/metric ton ($6.23/ton)
for a 245-mile transport by rail.
Status
It is assumed that the reference coals are available and can be
profitably mined.
Energy Impacts
Goal is a fuel of relatively low energy density compared with oil or
gas. Hence, the energy consumed per unit of combustion energy in transport-
ing coal is relatively greater.
Table 3-7 illustrates the energy consumed in transportation on two
bases: (1) as the energy consumed per unit of mass of coal, and (2) as
a fraction of the potential energy obtained by combustion of the coal.
The computations are made for two very different coals, a local bituminous
coal and a western subbituminous coal, delivered to a plant in Illinois
326
-------
Table 3-6. F.0.3. MINE PRICES OF
Sugply ftrea
Central apoalachia
(wv, KJT, TN, VA)
e.g., Buchanan, V&
Northern Wvoning
e.g., Gillette, VK
Southern Wyoning
e.g., Bock Springs, V
Northern Lignite
e.g., WHliston, ND
Central Western
e.g., las Ananas, CO
Southwest-pin
e.g., Gallup, UK
$/ton
22.00
6.25
14.50
7.00*
17.00
13.75
P.O.B. Bid Prices
Term
$/GJ
($AOS ETU)
0.99
(0.94)
0.40
(0.38)
0.73
(0.69)
0.46
(0.44)
0.82
(0.78)
0.73
(0.69)
- $1978 *
Soot
S/UJ
$/ton ?/106 BTO)
29.00 1.113
(1.05)
8.00 0.52
(0.49)
15.00 0.75
(0.71)
(0.44)
16.00 0.77
(0.73)
15.00 0.74
(0.70)
11 Except where indicated otherwise, the prices are those cited in Coal Week,
May 29, 1978.<7>
* Estimated at §7.00/ton and 8,000 Btu/lb.
3lhe value in dollars per ton is from Coal Outlook, July 17, 1978.* The value
in dollars per energy unit is based upon 32.1 J/Kg (13,800 Btu/lb).
327
-------
Table 3-7. AN TTiTITSTRanVE EXM3EIZ OF ENESSf CONSUMED IN TRHSSPORTING TOO
DJLk'i'EWOT mflT.fi TO A PLANT IN SKUMl'IEIE, HLUCIS
Assured heating value
10s J/kg
(BTO/li)
Average sulfur content
ng SOz/J
{li SOzAO'BUU)
Tran^ortation distance
km
(mi)
By rail
By barge
Energy consuned in transport
10 6 JAkg
% of coal-ccntiustion energy
Source of Coal
Gillette, Wyo.
19.76
(8,SOO)
70S
Q. 64)
2,124
(1,320)
0
(0)
562.0
2.80
Mattoon, ill.
25.57
(11,000)
2,812
(6.54)
160.9
(100)
0
(0)
42.6
0.17
328
-------
Toe table shows that energy needed to deliver the western coal to
Springfield exceeds the energy needed to deliver the local coal by a
factor of 13.2 on a per-wsight basis. When measured as a fraction of the
energy potentially available when the coal is burned, the factor rises to
16.5, illustrating the inportanos of the heating value of coal in cost
trade-offs among alternative sources.
Environmental Factors Associated With Low Sulfur Coal
The nature and quantity of pollutants resulting from handling and
burning naturally occurring coals vary significantly depending upon the
characteristics of the coal. Coals in the U.S. vary widely in their
content of ash, sulfur> iron and other metals. The type of coal utilized
determines the kinds and quantity of pollutants produced from storage
and refuse areas.
There is a high positive correlation between pyritic sulfur concentra-
tions and other coal contaminants that have a high pollution potential.
Therefore, the pyritic content of the coal is particularly important in
determining the amount of metal sulfates and sulfuric acid produced in
storage and refuse areas. Consequently, leachates from storage piles
of high sulfur eastern ooal are highly acidic and contain higher con-
centrations of other pollutants than leachat-as from lower sulfur coals.
This occurs because the acid dissolves many other complex sulfides
and metal salts, thereby increasing the concentrations of other contaminants
in the leachate. In contrast, western coal,because of its low pyritic
sulfur content,produces a basic leachate from its storage and refuse
areas. The dominant contaminants produced from western coal—calcium,
magnesium and sodium—are typically less hazardous to the environment
than are sulfuric acid and metal sulfates.
Through coal preparation, pollutants which might normally be emitted
during the combustion of naturally occurring coal are converted into solid
refuse or waste water, a chemical state in which the pollutants may be
easier to control.
329
-------
3.2.1.2 Candidate Physical Coal Cleaning Processes—
This section presents a summary and comparison of physical coal
cleaning systems from the standpoint of performance, preliminary costs,
preliminary energy use, status of development,and effect on the environment.
Performance Factors for Physical Coal Cleaning Systems
A comparison of system performance can best be accomplished by looking
at each process level described in Section 2.0 on a common coal feed.
This basis allows the comparison of the following parameters level by
level:
• Weight yield of clean coal product based upon a feed coal rate
of 544 metric tons (600 tons) per hour;
• Vfeight percent ash in the clean coal product based upon the
ash washability and equipment efficiency of the processing level;
• Weight percent sulfur in the clean coal product based upon the
sulfur washability and equipment efficiency of the processinc level; and
• Heating value yield of the process based upon a feed coal value
of 27,300 KJAg (11,740 BTU/lb).
Ihe common coal feed selected is a bituminous coal from the Upper
Freeport seam, which can readily be cleaned by conventional washing
techniques. The percent removal of ash and sulfur assigned to each process
level is based on actual equipment performance calculations using the
washability data for this coal. Ihe washability data was presented in
Section 2.0 (Figure 2-22,). The performance comparison is shown in
Table 3-8 for the five coal cleaning process levels.
Ihe table indicates a range of SC>2 emission levels for the clean
coal products fr>m 645 to 2,463 ng SO2/J (1.5 to 5.73 Ibs S02/106 BTU).
The percentage reduction of sulfur in the clean coal product ranges
from zero for the level 1 process to 68.2% for the "deep cleaned" product
from the level 5 plant. The level 5 plant produces two products, a
"deep cleaned" product and a middling product which have different product
specifications and potentially different markets. The percentage reduction
330
-------
TABLE 3-8 SUWPJtf OF PERFORMANCE OF PHYSICAL COAL Q^RANING PROCESSES BY LEVEL OF CLEANING
BASED UPON HIGH SULFUR EASTErN COM, (Upper Freeport Seam)
Coal Parameter
Weight % Ash in Product
Weight ?, Sulfur in Product
Heating Value kJ/ky (BTU/lb)
Metric ton/hr
Net Coal Yield (tons/hr)
Yield - Weight %
Recovery - % Heating Value
ng/SOz/J (lb SO2/10f BTO)
Weight % Sulfur Reduction
Weight % Ash Reduction
% ng S02/J Reduction
Raw Coal
23.90
3.45
26,772
(11,510)
(600)
100
100
2,576
(5.99)
1
22.5
3.40
27,586 28
(11,860) (12
(588)
98
99
2,463 2,
(5.73)
0
4
3
2
20,0
3.0
,517
,260)
(557)
93
97
102
(4.89)
12
15
17
LEVEL
3
11.5
1.89
31,520
(13,551)
39H
(439)
73
84
1,199
(2.79)
44
51
53
4
7.6
1.3
32,564
(14,000)
JB1
(420)
70
87.
795
(1.
62
68
69
5
5a
5.80
1.08
33,555
(14,426)
Vii
(212)
35.3
5 43.4
645
85) (1.
68.2
75.2
75
iCC
5b
11.31
1.69
31,662
(13,612)
^06
(228)
38
44
1,075
5) (2.5)
50
52
58
5a - Deep Cleaned Product (Steam Fuel #1); 5b - Middlings Product (Steam Fuel #2)
-------
of SQz per unit heating value for the clean coal product ranges from 3%
for level 1 to 75% for the deep cleaned product from the level 5 plant, The
percentage increase over the sulfur reduction percentage is caused by the
increase in heating value of the clean coal product.
As shown in Table 3-8 , the weight yields of the process levels
range from 98% for level 1 to 73.3% for the combined products of level 5,
and only 70% for a level 4 process. In general, as more processing
operations are used in the system, the weight yield of the final product
decreases. Ihe exception to this is the level 5 plant where two products
are obtained to maximize weight recovery. The energy content recovery
of the process levels ranges from 99% for level 1 to 87.5% for level 4.
Hie energy content recovery for the combined products of the level 5
process is slightly greater than that for level 4 - 87.9%.
In summary, levels 1 and 2 can be used to accomplish ash reduction
with corresponding high weight yields and energy content recovery but
very little sulfur reduction. Levels 3, 4 and particularly 5 achieve
large reductions in sulfur and SOz per unit heating value, but with
decreased yields and energy content recovery. This reflects the necessity
for greater physical processing of the coal to achieve rejection of
pyritic sulfur at the expense of rejecting larger amounts of coal. Thus,
the design of physical coal cleaning processes for sulfur removal is a
carefully balanced trade-off between sulfur reduction and energy content
recovery.
Despite the simplifying breakdown of coal preparation into five
levels, there are no generally defined standards for the selection
of coal preparation process, and there is no off-the-shelf
solution to producing clean coal. lew coal preparation plants in
the Uhited States are identical. Block diagrams showing general unit
operations for the various levels of physical cleaning may indeed be
identical for different coals, but the equipment selected to perform
these unit operations will vary depending on a variety of factors including
coal characteristics, such as washability and site specifics (e.g., avail-
332
-------
ability of water, geographic conditions, market criteria). Note that
by substitution or addition of equipment, a coal preparation plant may
be converted from one level to another.
Status of Development For Physical Coal Cleaning Systems
Levels 1 through 4 presented above are all practiced in commercial
plants operating today. Also, there are examples of level 5 practices at
metallurgical coal plants where both a metallurgical product and a
middling steam coal product are produced. Furthermore, all the unit
operations proposed for a level 5 plant are being used in commercially
operating plants today.
Level 1 processes are generally used to size raw coal to user
specifications, to remove overburden,, and sometimes in the case of western
coals to reduce moisture content to decrease shipping weight and
enhance heating value. Level 2 and 3 plants are mainly used to remove
sulfur-containing mine dilutions from coal whose in-place characteristics
actually or nearly comply with NSPS. The purpose of level 4 and 5 plants
is to liberate and remove free pyrite from hard-to-clean coals. Level 4
plants have predominantly been used to beneficiate metallurgical grade
coal, but market conditions may demand their adoption for steam coal
cleaning.
Preliminary Costs and Energy Requirements for Candidate Physical
Coal Cleaning Systems
All cleaning plants are assumed located at the mine mouth. All
product transport equipment is assumed to belong to the railroad. The
estimates are based on June 30, 1978 price and wage levels.
Capital Posts
The capital cost of coal cleaning plants is composed of direct and
indirect costs. Direct costs include the cost of equipment and auxiliaries,
land, and the labor and material required to install the equipment. Although
real estate costs vary, land is assumed to cost $2,400 per acre.
333
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Indirect capital costs are costs that cannot be attributed to a
specific piece of equipment, but are necessary for the entire system including;
Engineering -
Construction and
field expenses -
Contractor fee -
Start-up -
Contingency -
Working capital -
10% of direct costs
10% of direct costs
10% of direct costs
2% of direct costs
20% of total direct and indirect costs
25% of operating and maintenance costs
including costs of utilities, chemicals,
operating labor, maintenance and repairs
and disposal costs
Annual Operating Costs
The coal processing costs include variable operating, maintenance,
and associated overhead costs for operating the coal preparation facilities.
Fixed charges consist of capital amortization, taxes, insurance and
interest on borrowed capital.
Operating personnel costs are estimated based on two shifts of
operation totalling 13 hours per day and a third 8-hour shift for mainten-
ance. The plants are assumed to operate 250 days per year. The annual
salary costs are $23,700 per year for direct and maintenance labor and
$30,600 per year for supervisory personnel. Operating manpower varies by
coal cleaning level as follows:
Physical
Cleaning
Level
1
2
3
4
5
Direct Labor
Man/Day
8
10
10
18
20
Supervisory Labor
Man/Day
2
2
3
3
3
Maintenance
Man/Day
4
6
6
10
15
334
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Other operating cost bases are presented below.
Operating Cbst Bases
Maintenance, supplies, and replacement parts - 7% of total turnkey costs
Utilities and Chemicals
power @$.0072/MJ ($0.0258Awh)
water @ $0.15/1,000 gal.
magnetite @ $71.70/metric ton ($65/ton)
flocculant @$4.40Ag ($2/lb)
She quantities for utility and chemical requirements are based on
available published information.
Refuse Disposal Costs
$1.10/metric ton ($1.00/ton)
Overhead Costs
payroll overhead = 30 percent of total labor cost
plant overhead = 26 percent of labor, maintenance and supplies,
and chemical costs
Capital Charges
Capital related charges include annualized capital costs, taxes,
insurance and general and administrative costs. Assuming equal payment
loans, the fixed charges per period per dollar of loan as a function of
the loan period and the interest rate are given by:
R = i (1 + i)n
(1 + i)n - 1
where:
R = capital recovery per period per dollar invested
i = interest rate per period expressed as a decimal
n = number of periods in the amortization schedule.
The factor R multiplied by the amortizable cost will yield the
per-period fixed cost covering interest and principal.
335
-------
For purposes of this exercise a life expectancy of 20 years for a coal
cleaning plant and an interest rate of 10 percent were assumed.
Property taxes and insurance vary considerably in different parts
of the country. For this study, taxes, insurance and general and administra-
tive costs were taken as 4 percent of depreciable investment.
Post Estimates
A variety of organizations have made cost evaluations of the various
levels of physical coal cleaning based on different plant designs. vl2) (13
The basic problems in determining preliminary costs are:
• projecting past data to reflect current and future economic conditions;
• correlating plant designs and plant costs with levels and degrees
of cleaning;
• lack of available cost information to cover all costs; and
• inconsistency in plant capacity.
The available data were carefully examined as a basis for developing
preliminary cleaning plant total direct capital costs (in June 1978 dollars) .
In most cases the costs for each level were developed based on treating a
reference coal to upgrade the energy content and reduce the sulfur content
to meet the current NSPS sulfur dioxide emissions control level of 516 ng/106J
(1.2 lbs/106 BTU). In one case (The Electric Light and Rswer Study) (u)
costs were based on one selected coal being beneficiated at five
preparation levels. In another case (Hoffman-Munter Study) costs were
developed for existing plants.
The study of updated direct capital costs indicated that for each
generic type or class of cleaning (regardless of equipment used in the
circuits) the spread of direct capital costs was relatively small. The
range and average of adjusted direct capital costs (adjusted for through-
put and pricing basis) are listed below:
336
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Range of Total Direct Average Total Direct
Level Capital Costs, 1978 $ Capital Costs,1978$
1 2.4 x 106 to 3.4 x 106 2.9 x 106
2 5.3 x 106 to 6.6 x 106 6.0 x 106
3 9.3 x 106 to 11.4 x 106 10.5 x 106
4 10.3 x 106 to 14.5 x 106 12.0 x 106
5 18.1 x 106 to 18.4 x 106 18.3 x 106
Preliminary total annual operating cost estimates have been prepared
for plants representing the five levels of physical coal cleaning discussed
in Section 2.0. These estimates, presented in Table 3-9 , are based on
an assumed plant throughput capacity of 7/200 metric tons (8,000 tons)
per day. The reference coal used as the basis for these estimates is a
high sulfur eastern coal which contains 3.40% total sulfur (2.79 percent
pyritic sulfur) and 26,716 kJ/kg (11,846 BTU/lb) of heat content.
Energy Use
The energy requirements for the five levels of cleaning range from
245 kw to 2,304 kw for the 7,260 metric ton/day plant as shown on
Table 3-9.
3.2.1.3 Environmental Factors Associated with Physical Goal Cleaning—
Characteristics of the wastes from a physical coal preparation plant
are highly dependent on the raw coal utilized and the final product.
The two major sources of contamination associated with the candidate
BSER physical coal preparation plants are fugitive emissions from coal
storage and refuse area leachate. Note that the candidate plants do not
have thermal dryers, so flue gas emissions from drying will not occur.
Fugitive emissions may occur from the handling of coal, however. These
emissions are minimized by proper coal handling procedures and the use of
337
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TABIJ3 3- 9 ANALYSIS OF ANNUAL PHYSICAL O3AL CLEANING CDST3-
7,260 metric tons/day (8,000 tans/day plant)*
Levels of Cleaning 1 2
yiold: wt *
Recovery: % fhcrgy
BTO content RDM coal, kJAg (BlU/lta)
BTO content clean ooal, kJ/kq (ETHJ/lb)
Hourly input, RDM ooal, metric tons/hr (tons/hr)
Hourly output, clean coal, metric tons/hr (tons/hr)
Total Turnkey costs, $
Land oast, $
Working capital, S
Grand total capital investment, S
Total annual operating costs (excluding coal cost) , $
Total annual operating costs (including coal cost) , $
dost of preparation (excluding coal cost) , $/metric ton
(S/ton) of clean coal
Cbst of preparation (including coal cost) , S/metric ton
($/ton) of clean coal
ttist of preparation (excluding ooal oost) $/106 kJ
IS/IO* BTU) of clean coal
Cost of preparation (including coal cost) $/106 kJ
($/10B BTU) of clean coal
Average Biergy Requirement, Kw (10* BTU/hr)
98
100
26,772 (11,510)
27,850 (11,974)
558.3 (615.4)
547(603)
3,962,000
120,000
170,800
4,252,800
1,572,400
35,572,400
0.88(0.80)
20,01(18.15)
0.032(0.034)
0.729 (0.770)
250 (0.8)
85
92
26,772 (11,510)
29,490 (12,6781
558.3(615.4)
474.4(523.1)
9,506,400
180,000
365,200 •
10,051,600
3,377,500
37,377,500
2.19(1.99)
24.24(21.99)
0.074 (0.078)
0.822 (0.867)
650 (2.2)
345
75
85
26,772 (11,510)
30,854 (13,265)
558.3(615.4)
418.6(461.6)
16,634,400
264,000
555,600
17,454,000
5,409,200
39,409,200
3.97(3.60)
28.97(26.27)
0.128 (0.135)
0.939 (0.990)
1,000 (3.4)
70
87.5
26,772 (11,510)
34,132 (14,674)
558.3(615.4)
390.7(430.8)
19,010,400
720,000
714,300
20,444,700
6,635,300
40,635,300
5.22(4.74)
31.99(29.02)
0.153 (0.161)
0.937 (0.989)
1,300 (4.5)
78
92
26,772 (11,510)
32,220 (13,852V«
558.3(615.4)
435.4(480.0)
28,989,600
480,000
933,800
30,403,400
9,393,100
43,393,100
6.64(6.02)
31.67(27.82)
0.206 (0.217)
0.952 (1.00)
2,300 (7,9)
u>
U)
CO
* Based on 13 hr/day, 250 days/year operation
** Heating value of the contained product. The plant will generate two product streams.
a very high BTU stream and a middling stream
-------
bag houses on grinding and crushing equipment. Goal storage and refuse
area leachate from physical coal preparation plants is similar to acid
mine drainage for the cleaning plants processing eastern coals. For
the candidate BSER cleaning plant processing Colorado bituminous coal,
the drainage will be basic rather then acidic.
The amount of refuse may be calculated for each cleaning plant.
Eastern high sulfur coal preparation will produce 5.5 x 105 metric tons
of refuse per year and eastern low sulfur coal preparation will produce
about 4.0 x 10s metric tons of refuse per year.
3.2.1.4 Chemical Coal Cleaning—
This section presents a comparison of technical results obtained from
the assessment of major chemical coal cleaning processes as described and
discussed in Section 2.2.3. The analysis and conclusions presented herein
are based on process claims made by individual developers, research reports
and published information.
Sulfur Removal and Energy Content Recovery Potential
A comparison of process performance can best be accomplished by looking
at each process on a common coal feed. This was done in a previous report
on Chemical Goal Cleaning Processes published by Versar in 1978
(Although this study used a coal that is dissimilar to the three
reference coals, the results are applicable). This basis allows
the comparison of the following parameters process by process:
• Weight yield of clean coal product based upon a feed coal rate
(moisture free basis) of 7,110 metric tons (7,840 tons) per day
[7,200 netric tons (8,000 tons) per day of 2 percent moisture
coal];
• Weight percent sulfur in the dean coal product based upon the
sulfur removal efficiency of the process; and
• Heating value yield of the process based upon a feed coal value
of 28,610 kJAg (12,300 BTU/lb) and net energy content yield in
percent.
339
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The common coal feed selected is a bituminous coal from the Pittsburgh
seam, which cannot readily be cleaned by conventional washing techniques
to meet a control level of 1.2 Ib SO2/106 BTU for large boilers. This
coal does have an organic sulfur content low enough (0.7 weight percent)
so that complete removal of pyritic sulfur would result in a product which
will meet the control level. The percent removal of pyritic and organic
sulfur assigned to each process is based on data supplied by individual
developers. The performance comparison is shown on data supplied by
individual developers. The performance comparison of the eleven chemical
coal cleaning processes is shown in Table 3-10. The table indicates a
range of SO2 emission levels for the clean coal products of 344 to 903 ng/J
(0.8 to 2.1 lb/106 BTU). The calculated sulfur dioxide emissions for processes
which remove both organic and inorganic sulfur are lower than the 516 ng/J
(1.2 lb/106 BTU). Of the four processes which remove pyritic sulfur, only
two (TFW and Ledgemont) will produce a slightly higher sulfur level than
that required to meet the current control option; however, within the levels
of accuracies involved they also might be considered to be in compliance.
As shown in Table 3-10, the energy content yields estimated for these
processes are generally greater than 90 percent with a range from a low
57 percent for the IGT process to a high of 96 percent for the GE process.
All energy content yields listed in Table 3-10 reflect both the coal loss due
to processing and the coal used to provide in-process heating needs.
However, with the exception of the IGT process, the actual coal loss due
to processing is claimed to be small. lor most processes, the major energy
content loss is due to the use of clean coal for in-process heating.
It is believed that the high yield estimated for the GE process may
not adequately reflect the heat requirements that may be needed to regenerate
the caustic reagent employed in the process. This process is in its
early stage of d-velopment, and the energy requirements for the
process cannot be properly assessed at this tine. It is possible, that in
the final analysis, the energy content recovery from this process will be
more in line with other chemical coal cleaning processes.
340
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TABLE 3-10 PROCESS PERFORMANCE AND COST COMPARISON TOR MAJOR
CHEMICAL COAL CLEANING PROCESSES
Net coal yield, metric tons
per day (tons/day)*
Weight % sulfur in the product
Heating value, kJ/kg
(BTU/lb)
ng/J (Ib S02/10S BTO)
Percent net
energy content yield
PROCESSES WHICH FEM3VE PYRHTC SULFUR ONLY
f-KKLl
7,110
(7,840)
1.93
28,610
(12,300)
1,333
(3.1)
—
TIW
6,400
(7,056)
0.83
29,854
(12,835)
559
(1.3)
94
LOL
6,400
(7,056)
0.83
29,854
(12,835)
559
(1.3)
94
SM
MW23EX
5,645
(6,225)
0.97
28,342
(12,400)
688
(1.6)
80
SYRACUSE
PHYSICAL
CLEANING
5,645
(6,225)
1.50
33,960
(14,600)
903
(2.1)
95
Net coal yield, metric
tons per day (tons/day)*
Weight % sulfur in
the product
Haating value, kJAg
(BTO/lb)
ng/J (Ib SOz/lO6 BTU)
Percent net
energy content yield
PROCESSES WHICH REMOVE PYRITIC AND ORGANIC SULFUR
ERDA
6,400
(7,056)
0.65
29,854
02,835)
387
(0.9)
94
GE .,
6,826
(7,526'
0.50
28,610
02,300)
344
(0.8)
96
BATIELLE.
6,755
(7,448)
0.65
26,400
01,350)
516
(1.2)
88
JPL
6,470
(7,135)
0.6
28,610
02,300)
430
(1.0)
91
ICT
4,270
(4,704)
0.55
27,180
01,685)
387
(0.9)
57
KVB
6,070
(6,690)
0.61
30,517
03,120)
387
(0.9)
91
AROO
6,400
(7,056)
0.69
28,842
02,400)
473
(1.1)
91
All values reported are on a moisture free basis.
Ihe coal selected is a Pittsburgh seam coal from Pennsylvania which contains 1.22
weight percent pyritic, 0.01 percent sulfate and 0.70 percent organic sulfur. It
is assumed that this coal has a heating value of 28,610 kJAg (12,300 BTO/lb).
341
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Processes which remove pyritic sulfur alone are primarily applicable
to coals rich in pyritic sulfur, so that efficient removal of pyritic
sulfur could bring these coals into compliance. Processes which remove
both types of sulfur are primarily applicable to coals which cannot be
adequately treated by pyritic removal processes.
Among all chemical coal cleaning processes, the TEW (Meyers) process
is the most advanced, with an 8 metric ton per day Reaction Test thit (RTU)
in operation. The process removes 80-96 percent of the pyritic sulfur from
nominally 14 mesh top size coal. Thirty-two different coals have been tested:
two western coals, twenty-three from the Appalachian Basin; six from the
Interior Basin; and one from the Western Interior Basin.
Another option for the Meyers processing plant which is attractive
is a combination physical and chemical cleaning operation—the Gravichem
process. In this process, the run-of-mine coarse coal containing high ash
and high pyritic sulfur would first be treated in a physical coal cleaning
plant. The heavy fraction from the gravity separation system, consisting
of about 40 to 50 percent of the total coal and containing low ash and high
concentration of pyritic sulfur is then fed to the Meyers process which will
yield a low sulfur product. The Gravichem process can produce an overall
yield of about 80 percent on the run-of-mine coal and will reduce the pyritic
sulfur content by 80 to 90 percent.
Among the processes capable of removing pyritic and organic sulfur, the
ERDA process has one of the highest probabilities of technical success. The
ERDA process is currently active, and most technologies employed in this system
have been already tested in other systems such as Ledgemont and TRW. The
process is attractive because it is claimed to remove more than 90 percent of
pyritic sulfur and up to 40% of organic sulfur in coals starting with minus
200 mesh coal. Coals tested on a laboratory scale include Appalachian, Eastern
Interior and Western.
342
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Preliminary Costs
This section presents preliminary economic information on the three
candidate chemical coal cleaning BSERs. The first two processes, the
Meyers and the Gravichem (physical coal cleaning plus Meyers) are capable
of reducing only a portion of the pyritic sulfur in the feed coal, while
the third process, the ERDA process, is capable of reducing both pyritic
and organic sulfur.
The process economics are based on preliminary conceptual processing
schemes. The process operating conditions, the process chemistry, the levels
of removal of pyritic and organic sulfurs, the energy content and yield
recovery information are based on evaluation of the individual developer's
claims. Where cost information was supplied by a developer, these costs were
utilized, to the extent possible, as the basis of the cost information in this
report. However, the costs were modified to allow the evaluation of the various
processes on a common basis.
The economic estimates presented for the Meyers and the ERDA processes
are based on a plant which processes 302 metric tons (33 tons) per hour of
high sulfur eastern coal on a 24 hour per day and 330 days per year basis
(8,000 tons/day, three train plant). The basis for the Gravichem process
is a 96 metric ton (106 tons) per hour Meyers process unit (a single train
plant) operating 24 hours a day and 330 days per year basis. The physical
coal cleaning section of the plant processes 558 metric tons (615 tons)
per hour of raw coal (8fOOO tons/day) operating 13 hours per day and 250
days per year. The third shift is set aside for scheduled plant maintenance.
Total Direct Capital Costs
Total direct capital costs for the Meyers and EEDA processes were
extracted from "Technical and Economic Evaluation of Chemical Coal Cleaning
Processes for Rsduction of Sulfur in Coal"?5' These costs were adjusted
343
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(16)
to June 30, 1978 bases by using appropriate plant cost indices. The
direct capital cost for the physical coal cleaning portion of the Gravichem
plant was extracted from the "Msyer's Process Development for Chemical De-
sulfurization of Coal" report. This cost was adjusted to reflect June 30,
1978 prices by using appropriate indices and was then adjusted to the desired
plant capacity using a scale factor of 0.7.
The cost of the land used in these estimates is the same as that used
for developing costs of the physical coal cleaning plants.
Indirect Capital Cost
Iteire included in indirect costs and their values are the same as those
developed for the physical coal cleaning plants.
Annual Operating Costs—
Operating manpower, energy and utilities requirements for the chemical
coal cleaning plants were extracted from the Versar chemical coal cleaning
report. The operating and maintenance personnel wages and cost basis for
utilities and chemicals are the same as discussed in physical coal cleaning.
The costs for steam and other chemicals used only in chemical coal cleaning
process estimates are listed below:
600 psig steam @ $4.83AfOOO Ib.
Line @ $35/tetric ton ($32/ton)
lignin sulfonate binder @ $0.06/lb.
Maintenance supplies and material for all chemical coal cleaning cases
were taken as 5 percent of the total turnkey costs.
The cost for the disposal of byproducts generated by the chemical coal
n 5 )
cleaning plants was extracted from the chemical coal cleaning report.
The cost basis for overhead, capital charges and raw coal costs are
presented in the physical coal cleaning discussion.
Preliminary capital and annual operating costs for each process based on
a high sulfur eastern coal are presented in Table 3-11. The results
344
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TKBLE 3-11.
ANALYSIS OF ANNUAL CHEMICAL ODAI. CLEANING COSTS -
7,258 metric tons/day (8,000 tons/day plant)
Process Meyer's ERtA
Yield, wt %
Recovery: % kJ (% BTU)
BTO content BOM coal kJ/kg (BTU/lb)
BTU ocntent clean coal kJAg (BTU/lb)
Hourly input, RDM ooal, metric tons/hr (tons/hr)
Hourly output, clean coal, metric tons/hr (tons/hr)
Total TVimkey costs, S
Land cost, $
Marking capital, S
Grand total capital investment, $
Total annual operating costs (excluding coal cost) , S
Total annual operating costs (including coal cost) , $
Cost of preparation (excluding coal cost) , $/nctxic ton (S/ton) of clean coal
Cost of preparation (including coal oost) , $/matric ton (?/ton) of clean ooal
Oost of preparation (excluding coal cost) , S/106 kJ ($/10s BTO) of clean ooal
Oost of preparation (including ooal cost) , $/106 kJ ($/10s BTO) of clean coal
Qiergy Requirement
Electric power, KW (10 BTO/hr)
Product ooal for in process leaohinq, metric tons/hr (tons/hr)
600 psig steam, kg (Ibs)
90
99.2(94)
26,772 (11,510)
28,507 (12,256)
302 (333)
271 (300)
157,500,000
120,000
5,973,000
163,593,000
53,291,000
98,171,000
24.73(22.43)
45.55(41.32)
0.867 (0.915)
1.60 (1.69)
25,200 (86)
11(12)
90
99.2(94)
26,772 (11,510)
28,507 (12,256)
302 (333)
271 (300)
216,580,000
120,000
7,931,500
224,631,500
70,832,000
115,712,000
32.87(29.81)
53.70(48.70)
1.15 (1.22)
1.88 (1.99)
15,650 (53)
25.8(28.5)
0.9x10' (2xlO'>
Gravichem
79.8
96.0
26,772 (11,510)
31,126 (13,382)
558(615.9)* 96(106)**
469(517)* 86(95)**
62,324,000
120,000
2,429,600
64,873,600
^l39T,3uO
55,597,300
14.92(13.53)
38.41(34.84)
0.48 (0.51)
1.23 (1.30)
8,400A(29)1,000 Y (3.4)
3.6(4)
U)
£>.
U1
MOOES:
* filtering and leaving physical coal cleaning plant operating @ 13 hr/day, 250 days/year basis
** Entering and leaving chemical coal cleaning plant operating @ 24 hr/day, 330 days/year basis
A Meyer's ooal cleaning plant
Y Physical ooal cleaning plant
6 The use of product coal as fuel has been reflected in the weight yields reported above
-------
indicate that the cost of coal cleaning is $24.73, $32.87 and $14.92 per metric
ton, excluding the raw coal cost for the Meyers, ERDA, and Gravichem (physical
coal cleaning plus Meyers process), respectively.
Energy Impact
The energy requirements for these plants are given in Table 3-11. It has
been assumed that the physical coal cleaning plant included in the Gravichem
process will operate 13 hrs per day, 250 days per year. All chemical coal
cleaning plants will operate on a 24 hour per day and 330 days per year basis.
Environmental Factors associated with Chemical Coal Cleaning
Characteristics of the wastes from a chemical coal preparation plant are
highly dependent on the processes utilized, which are in turn dictated by the
raw coal and final product.
As chemical cleaning processes become increasingly more complex and finer
size fractions of the coal are cleaned and collected, the pollution potential
changes because: (1) complex chemical cleaning plants frequently use thermal
driers which are a source of gaseous (NO , SOz and CO) and particulate air
X
pollution; (2) there is a greater opportunity during processing for the
soluble pollutants to be contacted by a leachant; (3) chemical additives are
used in the static thickeners and froth flotation cells, thus increasing the
number of potential pollutants in air emissions and refuse; and 4) most
chemical coal cleaning plants bum cleaned coal for steam/heat production
and therefore have much the same kinds and amounts of air pollutants as the
industrial boilers themselves.
There is insufficient data and operating experience to quantify the amount
of leachant lost in the clean coal or refuse, so environmental impacts cannot be
quantified. The annual amount of refuse material is known, howsver, based on
a 7216 metric ton/day (8000 ton per day) plant. The amount of refuse disposed
of is as follows: Gravichem - 6.8 x 105 kkg per year (7.5 x 105 tons per
year), Meyers - 2.0 x 105 kkg per year (2.3 x 10s tons per year), and ERDA
2.0 x 10s kkg per year (2.2 x 105 tons per year).
346
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3.2.2 Comparison of Candidate Best Systems of Emission Reduction for S02
Control
This section presents the selection and characteristics of three
typical coals, which will be used for comparison of the candidate Best
Systems of Emission Reduction (BSER). Ihe performance, cost and other
relevant factors for each candidate BSER will be compared for each coal
type at the five selected emission levels.
Selection of Representative Goals for Industrial Boilers—
Three representative coals have been selected as a basis for determining
the performance and costs of each candidate control technology. Ihe coals
are representative of those originally chosen by PEDCo Environmental to
(is)
be used in the development of each ITAR , but are not identical. Because
the design of a physical coal cleaning system is dependent upon the washa-
bility characteristics of an individual coal and the coal types supplied by
PEDCo were merely average coals, they could not be used for this analysis.
Thus, three coals were chosen whose characteristics were close to those
specified and which are representative of a high sulfur eastern coal,
a low sulfur eastern coal and a low sulfur western coal. Ihe characteristics
of the coals selected are shown in Table 3-12. These coals were selected
primarily on quality and washability characteristics. These characteristics
are presented in more detail in the later sections.
3.2.2.1 Naturally Occurring Low Sulfur Goal as a BSER—
The uncontrolled SO2 emissions from each of the representative coals
range from 447 ng S02/J (1.04 Ibs S02/10e BTU) for the low sulfur western
to 2,490 ng S02/J (5.79 Ibs SO2/106 BTU) for the high sulfur eastern. The
matrix shown belcw indicates the ability of the three reference raw coals
to meet the selected SO2 emission levels on a long term average basis.
SOa Emission Levels
ng SC-2/J (Ibs SO2/106 BTU)
Goal
High-S Eastern
Low-S Eastern
low-S Western
1,290 (3.0)
Doesn't Meet
Meets
Meets
1,075(2. &)
Doesn't Meet
Meets
Meets
860 (2.0)
Doesn't Meet
Meets
Meets
645 (1.5)
Doesn't Meet
Doesn't Meet
Meets
516 (1.2)
Doesn't Meet
Doesn't Meet
Meets
347
-------
TABLE 3-12. REPFEStNTATIVE COALS FOR INDUSTRIAL BOILERS
PAKAMIT1KR
w
**•
00
Coal Type
Seam
County, State
RAW COAL ANALYSIS
Ash, % t
total S, % t
tyritic S, t, i
Heating Value kJ/kg (BTU/lb)t
Moisture Content
Ash t\ision Tatp. , °F
SO2' Qriission Level, ng/SOz/J
(Ibs SO2/10b DUI)
High Sulfur Eastern
Upper Freeport ('E1
ooal) Seam
Butler, Pa.
23.9
3.45
2.51
26,772
(11,510)
5.0
2,020-3,000
2,576
(5.99)
Low Sulfur Eastern
Eagle Seam
Buchanan, Va.
10.38
1.18
0.60
31,685
(13,622)
2.0
-
744
(1.73)
Low Sulfur West
Primero Seam
Las Animas, Co.
24.81
0.59
0.30
26,270
(11,294)
2.5
2,230-2,910
447
(1.04)
t Analyses are on a Moisture Free Basis
-------
This matrix indicates that the naturally occurring low sulfur coal
from the western region is easily capable of meeting all five emission
levels on a long term average basis. Coupled with an F.O.B. mine price
of $18.75/kkg ($17.00/ton) or $0.82/GJ ($0.78/10s BTU) makes it a prime
candidate for BSER for all three emission levels. Also as shown above,
the low sulfur eastern coal is capable of meeting the moderate, the optional
moderate, and the SIP emission levels as a naturally occurring coal.
This fact plus its F.O.B. mine price of $24.25/kkg ($22.00/ton) or $0.99/GJ
($0.94/106 BTU) makes it a prime candidate for BSER at this emission level.
However, the above analyses of naturally occurring low sulfur coals
as possible BSERs do not take into account transportation costs of these
coals to the industrial boiler site. It is only after calculation of
transportation costs and transportation energy use from the coal supply
area to a series of industrial demand oentroids that a true picture of
performance and cost can be determined to judge the BSERs with respect
to the naturally-occurring coals.
3.2.2.2 Physical Goal Cleaning Systems as a BSER—
A primary factor in the choice of the three representative coals
for performance and cost analysis, was that some washability data for
each coal was available at various size fractions. Based upon this
washability data and a knowledge of equipment efficiency performance
factors, a flow sheet or series of flow sheets can be developed to
beneficiate each representative coal.
The major design criteria used for the preparation of the flow sheets
for each coal are summarized as follows:
• Plant input in each case is 544 metric tons per hour (600
tons per hour);
• Annual capacity throughput is 1.8 million metric tons
(2.0 million tons) based upon a 13 hour operating day and
250 operating days per year;
349
-------
• In all cases, the plant is located at the mine mouth,and all
resources such as coal, water, power, etc. are assumed
readily available;
• All process equipment used is commercially available and proven;
• Actual equipment performance partition factors have been
used to adjust raw coal washabilities characteristic to
performance guaranteed specifications; and
• Design of emission control facilities is based upon federal new
source performance regulations - EPA standards for air and water
quality, MESA regulations for refuse disposal, and MESA/OSHA
noise limitations. The BSER designs do not contain direct
thermal dryers, because they are not necessary to meet customer
specifications for clean coal.
Washability Characteristics of Ooals Selected
Raw coal washability data for the three representative coals selected
are presented in Tables 3-13, 3-14, and 3-15. Each of these tables shows
specific gravity float-sink characteristics of the representative coals
according to specific size fractions. In the absence of any additional
data, the flowsheet design is based upon the size fractions specified.
Physical Goal Cleaning Flow Sheet Design
The major objective for each design Was to obtain maximum sulfur
rejection at an acceptable heating value recovery. In most cases, the
clean coal product specifications were chosen to reflect the lowest
possible SO2 per heating value unit emission level for each representative
coal.
Cbal Piaparation Flowsheet for the High Sulfur Eastern Coal
Ihe first task to be performed in designing a coal preparation flow-
sheet for this coal was to calculate the range of possible clean coal
properties for each size fraction given in the washability tables. This
is accomplished by calculating clean coal properties in terms of ash,
350
-------
TABLE 3-13. Raw Coal Washability Data for a High Sulfur Eastern Goal-
Upper Freeport "E" Seam, Butler, Pennsylvania^19)
Spec
Gravity
Characteristics for Each Size Fraction/Specific
Gravity Element (Dry Basis)
Vfeight
%
Size Fraction: 2" x 3/8"
Float 1.30
1.30 - 1,40
1.40 - 1.50
1.50 - 1.60
1.60 - 1.80
Sink 1.80
38.2
24.2
8.5
4.0
4.5
20.6
Size Fraction: 3/8" x 28
Float 1.30
1.30 - 1.40
1.40 - 1.50
1.50 - 1.60
1.60 - 1.80
Sink 1.80
45.8
19.2
4.5
3.5
3.1
23.9
Size Fraction: 28 mesh x
Float 1.30
1.30 - 1.40
1.40 - 1.50
1.50 - 1.60
1.60 - 1.80
Sink 1.80
46.3
18.7
7.0
3.9
3.5
20.6
Ash
%
(30.0%)
3.4
10.1
25.2
30.7
44.7
73.6
mesh (55.
3.3
10.5
21.1
29.2
44.0
72. B
0 (15.0%)
3.0
8.5
16.0
28.1
35.1
74.2
Btu/
Ib
14,589
13,613
12,011
10,566
8,837
3,949
0%)
14,604
13,767
12,050
10,752
8,852
3,887
14,649
13,822
12 ,080
10,840
7,977
3,781
Pyritic
Sulfur, %
0.44
1.51
2.28
2.95
5.35
8.74
0.43
0.96
1.84
2.30
3.63
8.71
0.32
0.96
1.57
3.10
3.76
1.12
Ttotal
Sulfur, %
0.85
2.27
2.70
3.70
5.70
9.03
0.85
1.50
2.20
2.80
3.90
10.35
0.74
1.50
2.22
3.65
4.10
11.9
Omulative Recovery
(Dry Basis)
Vfeight
%
38.2
62.4
70.9
74.9
79.4
100.0
45.8
65.0
69.5
73.0
76.1
100.0
46.3
65.0
72.0
75.9
79.4
100.0
Ash
%
3.4
6.0
8.3
9.5
11.5
24.3
3.3
5.4
6.4
7.5
9.0
24.3
3.0
4.6
5.7
6.8
8.1
21.7
Btu/
Ib
14,589
14,210
13,947
13,766
13,486
11,522
14,604
14,356
14,005
13,851
13,649
11,414
14,649
14,411
14,184
14,013
13,747
11,694
Pyritic
Sulfur,%
0.44
0.85
1.03
1.13
1.37
2.89
0.43
0.59
0.67
0.75
0.86
2.74
0.32
0.50
0.61
0.74
0.87
.92
•total
Sulfur, %
0.85
1.40
1.56
1.67
1.90
3.37
0.85
1.04
1.12
1.20
1.31
3.47
0.74
0.96
1.08
1.21
1.34
3.52
2" = 50 mn.; 3/8" = 9.5 itm.
-------
u>
Ul
TABLE 3-14. Raw Goal Washability Data for Low Sulfur Eastern Coal -
Eagle Seam, Buchanan, Virginia (2»)
Sink
1.30
1.35
1.40
1.45
1.50
1.60
1.70
Float
1,30
1.35
1.40
1.45
1.50
1.60
1.70
1.30
1.35
1.40
1.45
1 . 50
1.60
1.70
1.30
1.35
.40
.45
.50
.60
.70
1.30
1.35
1.40
1.45
1.50
1.60
1.70
1.30
1.35
1.40
1.45
1.50
1.60
1.70
CUM. WOOWBIW
DRY BASIS
* wt.
% Ash
% Sul.
COMPOSITE 5" IW x 1/4" Itt '
66.8
8.7
8.8
3.7
1.3
1.0
0.5
9.2
70.1
n. 5
5.1
3.8
2.2
2.1
1.7
6.5
54.4
16.0
7.1
3.8
1.5
4.7
2.3
8.2
2.05
4.75
6.65
12.74
17.08
23.27
33.94
76.77
1/4" M x 28
1.96
5.36
7.63
10.67
14.80
21.41
47.56
76,76
28 MerJi x 60
2.32
5.00
9.41
12.61
14.90
18.17
26.34
71.07
0.69
0.99
0.84
1.10
1.33
2.45
3.57
3.63
Mesh = 34
0.88
1.39
1.29
1.17
1.45
1.77
3.09
3.61
Mash - 7.
0.79
0.95
1.24
1.16
1.08
1.1.1
1.41
3.89
% Wt.
= 50.5% of Raw
66.8
75.5
84.3
88.0
89.3
90.3
90.8
100.0
.7% of Raw RDM
70.1
78.6
B3.7
87.5
89.7
91.8
93.5
100.0
(Float)
% Ash
BOM Crushed
2.05
2.36
2.81
3.23
3.43
3.65
3.81
10.53
Crushed to
1.96
2.33
2.65
3.00
3.28
3.70
4.50
9.20
6% of Raw 1OM Crushed to 5
54.4
70.4
77.5
81.3
84.8
89.5
91.8
100.0
2.32
2.93
3.52
3.95
4.40
5.12
5.65
11.08
% Sul.
to 5"
0.69
0.72
0.74
0.75
0.76
0.78
0.79
1.06
5"
0.88
0.94
0.96
0.97
0.98
1.00
1.03
.1.20
II
0.79
0.83
0.86
0.88
0.89
0.90
0.91
1.16
22.
18.
15.
10.
CUM. REJECT
(Sink)
Wt.
100. 0
33.2
24.5
15.7
12.0
10.7
9.7
9.2
100.0
29.9
21.4
16.3
12.5
10.3
8.2
6.5
100.0
45.6
29.6
8.2
% Ash
10.53
27.58
35.69
51.97
64.06
69. 77
74.56
76.77
9.20
26.16
34.43
42.81
52.59
60.66
70.71
76.76
11.08
21.54
30.48
37.13
42.11
48.38
61.90
71.87
% Sul.
06
79
07
77
28
52
63
3.63
20
96
2.18
46
,85
,19
,50
3.6.1.
.10
,59
,94
16
36
2.60
3.39
3.89
* 5"=125 ran; 1/4"=6.3 mm
-------
TABLE 3-14. Raw Coal Washability Data for Low Sulfur Western Coal -
Eagle Seam, Buchanan, Virginia (20) (Continued)
CUM. RECOVERY CUM. H3JECT
SPECIFIC GRAVm DK BASIS (Float) (Sink)
Sink Float % Wt. % Ash % Sul'; % Wt. % Ash % Sul. % Wt. % Ash % Sul.
60 Mesh x 100 Mesh =2.9% of Raw RDM Crushed to 5 "
1.30 46.6 3.02 0.79 46.6 3.02 0.79 100.0 12.63 1.26
1.30 1.35 17.7 5.12 0.84 64.3 3.60 0.80 53.4 21.02 1.67
1.35 1.40 8.4 8.69 1.05 72.7 4.19 0.83 35.7 28.90 2.08
1.40 1.45 4.5 12.44 1.14 77.2 4.67 0.85 27.3 35.12 2.40
1.45 1.50 3.8 15.03 1.08 81.0 5.15 0.86 22.8 39.60 2.65
1.50 1.60 6.3 17.28 0.97 87.3 6.03 0.87 19.0 44.52 2.96
1.60 1.70 3.6 24.85 1.19 90.9 6.77 0.88 12.7 58.03 3.95
1.70 9.1 71.15 5.04 100.0 12.63 1.26 9:1 71.15 5.04
en 100 Mesh x 0 = 4.3 % of Paw RDM Crushed to 5"
U>
1.30
1.30 1.35
1.35 1.40
1.40 1.45
1.45 1.50
1.50 1.60
1.60 1.70
1.70
* 1 1/2" = 37.5 mm; 1/4" = 6.3 rm
4.0
22.4
20.3
11.4
11.0
14.7
6.9
9.3
2.93
4.98
7.66
11.77
13.34
17.74
23.45
65.47
0.83
0.80
0.83
0.89
0.81
0.92
1.08
19.07
4.0
26.4
46.7
48.1
69.1
83.8
90.7
100.0
2.93
4.67
5.97
7.11
8.10
9.79
10.83
15.91
0.83
0.80
0.82
0.83
0.83
0.84
0.86
2.55
100.0
96.0
73.6
53.3
41.9
30.9
16.2
9.3
15.91
16.45
19.94
24.62
28.12
33.38
47.57
65.47
2.55
2.63
3.18
4.08
4.95
6.42
11.41
19.07
-------
TABLE 3-15. Paw Coal Washability Data for Low Sulfur Western Goal -
Prinero Seam, Las animas, Colorado (2°)
CUM. FECOVEIW CUM. IEJECT
SPECIFIC GRAVITY DRV BASIS (Float) (Sink)
Sink Float % Wt. % Ash % Sul. % Wt. % Ash % Sul. % Wt. % Ash % Sul.
1 1/2" x 1/4" = 85.91% of Raw Coal
1.30 27.81 6.11 0.66 27.81 1.70 .18 100.00 26.04 .64
1.30 1.35 16.75 12.19 0.62 44.56 3.74 .29 72.19 24.34 .45
1.35 1.40 10.99 16.55 0.63 55.55 5.56 .36 55.44 22.30 .35
1.40 1.45 6.76 21.41 0.66 62.31 7.10 .40 44.45 20.48 .28
1.45 1.50 5.54 26.37 0^62 67.85 8.47 .44 37.69 19.03 .24
1.50 1.60 7.69 33.40 0.70 75.54 11.04 .49 32.15 17.57 .20
1.60 1.70 4.58 41.74 0.58 80.12 12.95 .52 24.46 15.00 .15
1.70 19.88 65.85 0.61 100.00 26.04 .64 19.88 13.09 .12
u> 1/4" x 0 - 14.09% of Raw Coal
Ui
£»
1.30 55.46 4.93 • 0.66 55.46 2.73 .37 100.00 17.31 .64
1.30 1.35 13.92 11.62 0.62 69.38 4.35 .45 44.54 14.58 .27
1.35 1.40 6.05 16.65 0.59 75.43 5.35 .49 30.62 12.96 .19
1.40 1.45 3.70 21.42 0.57 79.13 6.15 .51 24.57 11.95 .15
1.45 1.50 2.33 26.41 0.57 81.46 6.77 .52 20,87 11.16 .13
1.50 1.60 3.22 32.23 0.59 84.68 7.80 .54 ' 18.54 10.54 .12
1.60 1.70 2.20 39.66 0.61 86.88 8.68 .55 15.32 9.51 tlO
1 70 13.12 65.80 0.64 100.00 17.31 .64 13.12 8.63 .08
-------
sulfur and BTU for each specific gravity of separation at each size fraction
using actual equipment separation efficiency factors. These performance
characteristics are then graphically displayed as Figures 3-1A through 3-2B.
These graphs show the attainable levels of each size fraction coal product
in terms of sulfur, ash and heating value content as well as % weight
recovery, % energy content recovery and amount of sulfur per energy content
unit at various specific gravities of separation. These performance
characteristics are all based upon the use of heavy media processes.
Based upon the performance characteristics graphs described above,
it was decided that a two product level 5 flowsheet should be used to
beneficiate this coal to obtain an optimal tradeoff between SO2 reduction
and energy content recovery. Figure 3-3 shows a simplified block style
flow diagram of this conceptual flowsheet.
The flowsheet conceptualized for this high sulfur eastern coal uses
a heavy media vessel to effectively separate the coarse size coal into a
middling product stream and a refuse stream. The intermediate sized
material is routed to a dual stage heavy media cyclone circuit to produce
a "deep cleaned" product from the first stage and a middling product from
the second stage. The fine sized material is routed to a hydrocyclone
circuit for cleaning and coal recovery. The clean coal product from this
circuit is blended with other products to form the middling product.
The characteristics of the raw coal and clean coal products from this
plant are compared in Table 3-16 .
The "deep cleaned" coal product will meet an SO2 emission control level
of 645 ng S02/J (1.5 Ibs S02/106 BTU) on a long term average basis. The
equivalent S02 reduction was 74.2% based upon SO2 emission per
unit energy content. The total sulfur in the coal is reduced from 3.40% to
1.08% which is a 68.2% reduction. Also significant is the ash reduction
which decreases from 23.4% in the raw coal to 5.8% in the product, a
reduction of 75.2%.
The middling product will meet an SO2 emission control level of 1,075
ng SO2/J (2.5 Ibs S02/106 BTU) on a long term average basis. The S02
355
-------
90 -
s "
50
40
12.0
10JO
X 8.0
to
# 6.0
4.0
2.0
w
1.0
_L
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY
1.70
1.80
FIGURE 3-la PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A HIGH SULFUR EASTERN COAL [UPPER FREEPOHT "E SEAM")
AT A SIZE FRACTION OF 2" X 31V (50 mm x 9.5 mm) {DRY BASIS)
356
-------
c
111
o
o
o
o
90
80
70
60
50
40
32.564-
14,000
30.238-
-13.000
27,912-
1ZOOO
CO
860-
430-
2
2.0
1.0
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY
1.70
1.80
FIGURE 3-lb PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIRC GRAVITIES OF
SEPARATION FOR A HIGH SULFUR EASTERN COAL (UPPER FREEPORT "E SEAM")
AT A SIZE FRACTION OF 2" X 3/8" (50 mm x 9.5 mm) [DRY BASIS]
357
-------
90
s °°
SI
8 n
Ul
oc
t M
SP 50
40
1ZO
10.0
8'°
6.0
4.0
2.0
3
#
2.0
1.0
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY
1.70
1.80
FIGURE 3-2a PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A HIGH SULFUR EASTERN COAL (UPPER FREEPORT "E SEAM")
AT A SIZE FRACTION OF 3/8" X 28M (9.S mm x 28 M) [DRY BASIS]
358
-------
E
I
O
o
>
a
E
UJ
90
80
70
60
50
40
34.890-
30.238-
3
'a
15.0000
14.000
13,000
1ZOOO
860-
430-
I
2.0
1.0
1.30 1.40 1.50 1.60
SPECJRC GRAVITY
1.70
1.80
FIGURE 3-2b PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A HIGH SULFUR EASTERN COAL (UPPER FREEPORT "E SEAM")
AT A SIZE FRACTION OF 3/8" X 28 MESH (9.5 mm x 28 Ml [DRY BASIS]
359
-------
CO
cv
o
lif WAllltlNll
FIGURE 3-3 A LEVEL 5 COAL PREPARATION FLOWSHEET FOR BENEFICATION OF A
HIGH SULFUR EASTERN COAL (UPPER FREEPORT SEAM) FOR STEAM FUEL PURPOSES
-------
TABLE 3-16. PERFORMANCE SUMMARY OF LEVEL 5 GOAL PREPARATION ON
EASTERN HIGH SUIFUR COAL FOR STEAM FUEL PURPOSES
RAW COAL
Heating Value +
% Sulfur, Pyritic +
% Sulfur, Total +
Ash % +
Avg. Moisture %
ng SO2/106 BTU
Product Cbal
26,772 kJAg (11,510 BTU/lb)
2.51
3.45
23.90
5.0
2,576 (5.99)
Steam Fuel #1 (Deep Cleaned Steam Fuel #2 (Middlings)
Dry As Rec'd Dry As Rec'd
Heating Value
% Sulfur (Pyritic
Total
Ash %
Moisture %
ng SO2/10S.BTO
(Ib S02/10S BTO)
Performance
33,555 kJAg 30,533 kJAg
(14,426 BTU/lb) (13,127 BTU/lb.)
31,662 kJAg 28,847 kJAg
(13,612 BTU/lb.) (12,402 BTO/lb.)
1.08
5.80
643
(1.50)
% Mt. Recovery
% Energy Content Recovery
% Sulfur Reduction
% Ash Reduction
% SOz/Energy Unit
Content
Refuse
Ash % +
% Sulfur (Total) +
Heating Value +
+ Values are on a dry basis
0.98
5.28
643
(1.50)
1.69
11.31
1,067
(2.48)
1.54
10.30
1,067
(2.48)
35.33
43.42
68.24
75.21
74.15
64.92
8.91
12,563 kJAg (5,401 STU/lb)
38.00
44.06
50.30
51.67
57.12
361
-------
reduction from the raw coal is 57.1% based upon S02 emission per unit
energy content. The sulfur reduction is 50.3%, while the ash reduction
is 51.7%. This product would make an excellent fuel for a SIP-controlled
industrial or utility boiler.
A mass balanced flowsheet for this two-product, level 5 plant is
illustrated in Figure 3-4 . The input to the plant is 544 metric tons/
hour (600 tons/hour) which is split into two streams at the raw coal
screen. Ihe coarser sized ma-terial is routed to the heavy media vessel
at a rate of 163 metric tons/hour (180 tons/hour). This coarse sized coal
is separated at a specific gravity 1.65 into a clean coal product of
124 metric tons/hour, (137 tons/hour) and a refuse stream of 39 metric tons/
hour, (43 tons/hour). The clean coal from this coarse circuit is the major
quantity of the middling product.
The fine coal stream from the raw coal screens is sized into two
fractions at the deslima screens. Ihe fine size fraction 28 mesh x 0 is
cleaned in a hydrocyclone circuit with the clean coal reporting to the
middling product and the refuse going to a clarifier and disk filter for
dewatering. Ihe intermediate-sized coal fraction 9.5 mm x 28 mesh
(3/8" x 28 mesh) is fed to a heavy media cyclone circuit for separation
at a low gravity, 1.43, to produce the "deep cleaned" coal product. The
sink material from this circuit is recleaned in a heavy media cyclone
circuit at 1.60 specific gravity to produce another portion of the middling
product.
Ihe conceptual flowsheet described above represents the BSER for
physical coal cleaning on the high sulfur eastern coal. Ihis control
technology has been demonstrated to be capable of meeting a 645 ng SO2/J
(1.5 Ibs SO2/106 BTU) emission control level which is the intermediate emission
limit. Tnis 3SER physical coal cleaning control technology is also
capable of meeting the moderate emissions control level of 1,290 ng SO2/J (3.0
Ibs SO2/106 BTU) for this coal.
362
-------
00
a\
u>
LEOEND
IB- - 487 cm
6* -183cm
3* M 01 cm
5" • 126 mm
3" " 76 mm
IK"- 31.5 mm
3/8" -9.6mm
X" - 8.3 mm
FIGURE 3-4 A LEVEL S COAL PREPARATION FLOWSHEET FOR BENEFICIATION OF A
HIGH SULFUR EASTERN COAL (UPPER FREEPORT SEAM) FOR STEAM FUEL PURPOSES
-------
Ooal Preparation Flowsheet for the Low Sulfur Eastern Ooal
A level 4 ooal preparation flowsheet was designed to beneficiate
the low sulfur eastern ooal to produce a product coal which will achieve
a 516 ng S02/J (1.2 Ibs SO2/106 BTU) emission control level on a long term average
basis. The level 4 flowsheet was designed for this coal, based upon
performance characteristic curves calculated for two size fractions from
the washability data presented in Table 3-14 in a preceding section.
The performance characteristics for two size fractions of the Eagle Seam
low sulfur eastern coal at various specific gravities of separation are
shown on Figures 3-5 and 3-6.
Based on the performance characteristics shown on these figures, it
was decided that the flowsheet for this coal should include washing of
three size fractions to obtain a clean coal product which achieves maximum
S02 reduction at an acceptable energy recovery.
The coarse coal fraction is beneficiated in a heavy media vessel at
1.65 specific gravity to yield a coarse ooal product with considerably
less ash, some reduction in sulfur and enhanced energy content. The inter-
mediate size coal fraction is beneficiated in a heavy media cyclone circuit
at 1.5 specific gravity. This produces a product with slightly higher sulfur
content than the coarse coal product, but a lower ash content and enhanced
energy content. The fine size coal fraction is beneficiated in a hydro-
cyclone circuit to reduce ash and sulfur content, with an increase in
product energy content. The clean coal products from each circuit are
combined to produce a plant product which achieves maximum SO2 reduction
with an acceptable energy recovery.
A level 4 coal preparation flowsheet for the low sulfur eastern coal (Eagle
Seam) is shown on Figure 3-7. Table 3-17 presents a performance summary of the
clean coal product from this flowsheet. After crushing and removal of coarse
refuse, the raw coal is screened, sized and further crushed to produce two
size fractions, 5" x 1/4" (125 mm x 6.3 mm) and 1/4" x 0 (6.3 mm x 0).
364
-------
92
90
> 88
s
Ul
§ 88
o
"
82
80
78
i
5.0
4.0
3.0
.80
oc
(0
.70
1.30 1.40 1.50 1.60
SPECIRC GRAVITY
1.70
1.80
FIGURE 3-5a PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A LOW SULFUR EASTERN COAL (EAGLE SEAM) AT A SIZE
FRACTION OF 5" X 1/4" (125 mm x 6.3 mm) [DRY BASIS]
365
-------
98
K 96
ui
S 94
ui
e
2 32
90
o
1 «
HI
2
84
34.425-
34.192-
31960-
33,727-
33.434-
ea
5
a
14JOO
14.700
14,600
14.500
14.400
249-
y 241-
i-
| 224-
? 215-
206-J
-------
100
o
u
Ul
GC
90
80
70
8.0
5.0
I 4..
#
3.0
2.0
1.06
1.0
3
US
.95
.90
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY
1.70
1.80
FIGURE 3-6a PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A LOW SULFUR EASTERN COAL (EAGLE SEAM) AT A SIZE
FRACTION OF 1/4" X 28 MESH (6.3 mm x 28 M) [DRY BASIS)
367
-------
UJ
O
B
100
90
O
cc
iu
UJ
80
37,216-
16JWO
34,890-
3Z564-
15.000
a
£
14X100
30,238-'
13,000
3
CO
1,
n 430-
O)
c
CD
i
M
1.0
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY
1.70
1.80
RGURE 3-€b PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A LOW SULFUR EASTERN COAL (EAGLE SEAM) AT A SIZE
FRACTION OF 1/4" X 28 MESH (6.3 mm x 28 Ml CORY BASIS]
368
-------
r^ ssjisj^-;?!
I MWKAM ' * ?»Ti
l-iga,. *-*«"
FIGURE 3-7 A LEVEL 4 COAL PREPARATION FLOWSHEET FOR BENEFICIATION OF A
LOW SULFUR EASTERN COAL (EAGLE SEAM) FOR STEAM FUEL PURPOSES
-------
TABLE 3-] 7. Performance Svranary of Level 4 Coal Preparation on Reference Low
Sulfur Eastern Coal For Steam Fuel Purposes
RAW COAL
Heating Value* kJ/kg(BTU/lb )
% Pyritic Sulfur*
% Total Sulfur*
% Ash*
% toisture
ng S02/J (Ib. SOz/lO'BIU)
31,685 (13,622)
0.60
1.18
10.38
2.0
744 (1.73)
PRODUCT COM.
Heating Value,* kJ/kg (BTU/lb.)
% Total Sulfur*
% Ash*
ng SOi/J (Ib. SOZ/116 BTO)
33,883 (14,567)
0.89
4.13
524 (1.22)
PERFORMANCE
% Wt. Heoovery
% Energy Content Recovery
% Sulfur Induction
% Ash Reduction
% ng S02/J (Ib. SO2/10S BTU) Reduction
84
90
25
60
12,468 (29)
* Maisture-Free
370
-------
The ooarse fraction is conveyed to a heavy media vessel of specific gravity
1.65. After removal of the heavy media in drain and rinse screens, the
sink product of the heavy media vessel is disposed of and the float product
is crushed to a minus 3.17 cm. (1 1/4") size, dewatered in a centrifuge
and conveyed to clean coal storage. The fine raw coal fraction is further
fractionated with the introduction of water on desliming screens into a
6.4 mm x 28 mesh (1/4" x 28 M) fraction and a 28 M x 0 fraction. The
larger fraction is beneficiated in a heavy media cyclone, with the sink
going to refuse storage and the float going to clean coal storage after
dewatering in a centrifuge. As before, the heavy media is recovered
from both sink and float products on drain and rinse screens immediately
following separation in the cyclone.
The fine product off the desliming screens goes to a complex circuit
of sumps and cyclones for further beneficiation and dewatering. A hydro-
cyclone is used to separate ultrafines from somewhat larger size particles.
Ultrafines flow to a clarifier and then to a disk filter for thickening
and dewatering. The filter cake is disposed of as refuse. The beneficiated
fines are combined with previously cleaned coal products for blending and
storage.
Coal Preparation Flowsheet for the Low Sulfur Vfestem Ooal
i
Graphs of attainable clean coal characteristics as a function of
specific gravity of separation were produced for two coal size fractions
from the washability data given in Table 3-3.5; for the low sulfur western
coal (Primero Seam ). These graphs are shown on Figures 3-8 and 3-9.
Since the major weight fraction of the coal falls in the 3.8 cm x 0.63 on
(1 1/2 inch x 1/4 inch) size fraction, it was decided that a level 2
flowsheet should be designed for this coal type to maximize yield. In
the level 2 flowsheet, the coarse coal fraction is washed, while the fine
coal fraction is simply blended into the product coal. The combined clean
coal product from this plant is considerably lower in ash than the raw coal,
with a corresponding increase in heating value. However the percentage of
total sulfur in the product is slightly greater than in the raw coal
371
-------
90
80
Ul
E
SO
40
18
16
14
10
1.0
oc
2
CO
1.30 1.40 150 1.60
SPECIFIC GRAVITY
1.70
1.80
FIGURE 3-8a PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A LOW SULFUR WESTERN COAL (PRIMERO SEAM) AT A SIZE
FRACTION OF 1 1/2" X 1/4" (37.5 mm x 6.3 mm) [DRY BASIS)
372
-------
s "
u
tu
CC 80
70
9- S0
O
K
" 55
31.401-
30.238-
29.075-
27.912-
1
13.500
13,000
1Z500
12.000
224-
c 206H
202-
.52
w
3 .48
.47
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY
1.70
1.80
HGURE 3-8b PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A LOW SULFUR WESTERN COAL (PRIMERO SEAM) AT A SIZE
FRACTION OF 1 1/2" X 1/4" (37.5 mm x 6.3 mm) [DRY BASIS]
373
-------
90
8
8! 80
70
14.0
12.0
10.0
8.0
6.0
1.0
(0
1.30 1.40 1.50 1.60
SPEC1RC GRAVITY
1.70
1.80
RGURE 3-9a PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A LOW SULFUR WESTERN COAL (PRIMERO SEAM) AT A SIZE
FRACTION OF 1/4" X 28 MESH (6.3 mm x 28 M) [DRY BASIS]
374
-------
oc
I
u
100
90
O
U
o
ce
Ul
80
70
32,564-
14.000
3
31,401-
13300
30.238-
13.000
211-
206-
202-
198-
m
%
i
(A
.49
.48
.47
.46
1.30
1.40
1.50 1.60
SPECIFIC GRAVITY
1.70
1.80
FIGURE 3-9b PERFORMANCE CHARACTERISTICS AT VARIOUS SPECIFIC GRAVITIES OF
SEPARATION FOR A LOW SULFUR WESTERN COAL (PRIMERO SEAM) AT A SIZE
FRACTION OF 1/4" X 28 MESH (6.3 mm x 28 M) (DRY BASIS]
375
-------
reflecting a concentration of the organic sulfur in the product. The mass
balanced flowsheet for this coal is shown on Figure 3-10 . Table 3-18
presents the performance characteristics of the clean coal product in
comparison to the raw coal. As can be readily seen from the comparison
shown in this table, the reduction in ash is appreciable, while the
reduction in SOa emission per unit heating value is almost negligible, i.e.,
only 1%.
3.2.2.3 Chemical Goal Cleaning .Systems as a BSER—
This section presents a comparison of technical results and preliminary
costs obtained from conceptual application of three chemical coal cleaning
systems on the three representative coals chosen for comparison in this
ITAR. The analysis and conclusions presented herein are based on process
claims made by the process developers, research reports and other published
information. The results obtained are based upon best engineering judgment
from conceptual systems.
Performance of Chemical Goal Cleaning Systems on the High Sulfur
Eastern Coal
The data presented in Table 3-19 reflects the best level of performance
that each of these candidate chemical coal cleaning processes (Meyers,
ERDA, Gravichem) can attain when applied to a high sulfur eastern coal.
The main objective in chemical coal cleaning is to reduce the emitted
amount of sulfur dioxide produced during coal combustion. The ERDA
process most effectively accomplishes this task of SO2 reduction from
this particular coal, ^proximately 529 ng SO2/J (1.23 Ibs SO2/10e BTU)
are released after implementation of the ERDA technology. The Gravichem
and Msyers processes perform in the same range of emission levels as
ERDA [580.5 ng SO2/J (1.35 Ibs SO2/106 BTU) and 636.4 ng SO2/J (1.48 Ibs
SC^/106 BTU), respectively], but not as effectively.
The second most important consideration in evaluating the performance
of these chemical cleaning processes is the usable heating value of the
product coal. Here the Gravichem process appears best, providing 30,466
(13,098 BTU/lb) of energy in the cleaned coal product. The ERDA. and
376
-------
tEOEND
16' - 487 cm
$• - 183 cm
y " 91 em
6" • 12S mm
3- • 75 mm
| X" -31.Smm
3/8" -•.6mm
X- -8.3mm
00
CRUSHER
f CLEAN
A/MAGNETIC COAL
),«—'W SEPARATOR CENTRIFUGE
DILUTE
SUMP I MEDIUM
CIRCUIT
HEAVV MEDIA
RECYCLE
-1 W4"
ITPH
CLEAN COAL PRODUCT
4(2 TPH
It 1% ASH
.mt SUL
12.SM BTWLB
FIGURE 3-10 A LEVEL 2 FLOWSHEET FOR COAL PREPARATION OF A LOW SULFUR
WESTERN COAL (PRIMERO SEAM) FOR STEAM FUEL PURPOSES
-------
TABI£ 3-13 Performance Sunroary of A Level 2 Flowsheet en the Western low Sulfur
Coal (Priraezo seam)
PAW COAL
Heating Value* kJAg <3TO/lb.) 26,268 (11,293)
% Pyritic Sulfur* . 30
•Ratal Sulfur %* .61
Ash %* 24.81
Moisture % 2.5
ng S02/J (Ibs SO2/106 BTU) 447.2 (1.04)
PRODUCT COM,
Heating Value*, kJAg (BTO/lb.) 29,201 (12,554)
% Tbtal Sulfur* .65
Ash %* . 16.5
ng S02/J (^3S S02AOS BTU) 442.9 (1.03)
PEKFOMfflNCE
% Wt. Reoovery 82
% Energy Content Heoovery 91.2
% Sulfur Raducticn 6.5 (increase)
% Ash Reduction 33.5
ng SOz/lO' (% Ib. SO2/10S BTO) Reduction 430 (1.0)
Ehergy Content kJAg (HTO/lb.)* 12,916 (5,553)
Ash 3* 62.63
% Tbtal Sulfur* .46
* Moisture Free
378
-------
TKBLE 3-19 PBOCESS AND COST PEHFOFMANCE OF CSHDIEKTE CHEMICAL COAL CLEANING SYSTEMS
TOR A HIGH SULFUR EASTEEN COM.
Stt Coal Yield, Metric Tons Per
D«y (Ibns/Day)
jytitic Sulfur Removal (%)
Percent tfeight Yield
Ibight % Sulfur in Product
fcatinj value kJ/kg (BTO/lb.)
BgSDj (lb. SOjAO8 BTO>
T~
Installed Capital Cost ($»D
tawal Processing Excluding Coal
cost ($wo
ftnngal Processing Including nr>ai
Cost ($»()
$/AnDoal Metric Tbti ($ Amual
Tbc) of Clean Coal, Excluding
COal cost
$/tanual Metric Ten ($/Rrmual
ten) of Clean Coal, Including
CcolCosf1-
S/KLlojoula (S/IO'BTO),
Excluding Coal Cost
S/KUojoule (SAO'BTU),
Including Coal Cost +
Feed*
7,250
(8,000)
3.45
26,772
(11,510)
2,576
(5.99)
"•-
Product Coal From
MEYEPS PPCCESS
6,532
(7,200)
90
90
0.39
28,507
(12,256)
623.4
(1.45)
174.8
53.3
98.1
24.73
(22.43)
45.55
(41.31)
0.87
(0.92)
1.60
(1.69)
Product Coal Fran
ETOA. Process
6,532
(7,200)
90
94
90
0.73
28,507
(12,256)
511.6
(1.19)
224.6
70.8
115.7
32.85
(29.80)
53.69
(48.70)
1.16
(1.22)
1.89
(1.99)
Product Coal From
GEAVICHEJI Process
5,792
(6,384)
90
91
79.8
0.89
31,126
<13,382)
571.8
(1.31)
64.9
21.6
55.6
14.92
(13.53)
38.40
(34.83)
0.48
(0.51)
1.23
(1.30)
* The coal selected is an Upper Freeport CE1 Coal) from Butler County, Pennsylvania which contains 3.45 weight percent total
sulfur, 2.51 weight percent pyritic and 0.94 wei
has a heating value of 26,772 kJAg (11,510 BTO/
+ Saw Coal Cost , $18.74/ktaj (517,00/ton) .
sulfur, 2.51 weight percent pyritic and 0.94 weight percent organic sulfur on a dry basis. It is assumed that this coal
/lb) .
379
-------
Meyers processes each can provide 27,903 kJAg (11/996 BTU/lb) in the
final product. One consideration which is closely tied to the obtainable
energy content (in terms of evaluating the total product heating content) is
the net coal yield attainable with each cleaning technology. Both the
Meyers and ERDA processes have yields of 90 percent, while Gravichem will
recover (by weight) 79.8 percent of the original raw feed.
The final major source of performance variability among the processes
lies in the weight percent of sulfur in the product coal. The weight
percentage of total sulfur in the product of coal cleaned by either the
Mayers or Gravichem process equals 0.89%. Greater sulfur removal is
accomplished by the ERDA process, producing a 0.73 total sulfur per-
centage. The reason ERDA has a lower percent figure is that it removes
both pyritic and organic sulfur from the raw coal. Meyers and Gravichem
processes only take out the pyritic sulfur. Comparison on a pyritic
removal basis shows that all three processes remove 90 percent. In
addition, ERDA removes 25 percent of the organic sulfur material from the
coal.
The increased sulfur removal and cleaning efficiency of the ERDA
process results in increased cleaning costs. For both the capital and
processing cost segments of the total cost, the ERDA process has the
highest of the three cleaning technologies. The total (pretransporta-
tion) cost to a user including the cost of the raw coal is $1.82/kJ
($2.03/106 BTU). The same cost figures for the Meyers and Gravichem
processes are approximately 15 and 35 percent less, respectively,
than ERDA..
To summarize, ERDA has the lowest S02 emission level, the highest per
kilojoojjt; (per BTU) cost and an intermediate energy content. The Mayers
process gives the highest SO2 emission level and an intermediate total
cost and energy content. Gravichem cleaning results in the lowest total
cost, the highest energy content and an intenrediate SOa emission level.
380
-------
Performance of Chemical Ooal Cleaning Systems on a Low Sulfur
Eastern Coal
Ihe process performance and preliminary cost information for the
candidate chemical coal cleaning processes on a low sulfur eastern coal
are summarized in Table 3-20 . Of the three processes Meyers, ERDA, and
Gravichem the ERDA process extracts sulfur in both its inorganic and
organic forms, resulting in the lowest level of SOa emissions of the
three processes, 300 ng SO2/J (0.70 Ibs SO2/106 BTU). However, all of
these processes produce a clean coal product having less than 387 ng 862/J
(0.90 Ibs S02/106 BTU).
Other important considerations of any coal cleaning processes are
percent weight yield and the energy content of the resulting coal. Of the
three processes, Gravichem attains the highest energy content; however, it
ranks lowest in the weight percent yield. Each of the processes enhances
the energy content of the raw coal.
The costs of installing and operating chemical coal cleaning processes
are significant. They are an important factor in selection of which process
is to be used. Preliminary cost figures for the three processes are also
listed in Table 3-20.
The annual processing costs in Tablo 3-20 indicate the cost of
processing the coal by the respective processes. The cost trend for the
processing is highest for the ERDA process ($70.8 million) and lowest
for Gravichem ($21.6 million). The processing and installation costs are
reflected in the annual cost of clean coal per ton and also in the cost
per million BTU., ERDA is the most e^ensive of the three processes while
Gravichem is the least costly.
Performance of Chemical Coal Cleaning Systems on the low Sulfur
Western Coal
The effects of chemical coal cleaning on a low sulfur western coal
are demonstrated in Table 3-21 . The three processes listed (Mayers, ERDA
and Gravichem) are the most efficient and best developed of the chemical
coal cleaning technologies. The values given for each are the best
possible that system can achieve.
381
-------
3-20. PROCESS AMD COST PERFORMANCE CF CMJDIDKIE CHEMICAL OQSL CHZNING SYSTEMS
FOR IOW SULHJR EASTERN COAL
Net Coal Yield, Metric Ibns Per
Day (Tbtis/Day)
Pyritic Sulfur Removal (%)
Organic Sulfur Removal (%)
Percent Met Energy Content
Percent Height Yield
Weight % Sulfur In Ths Product
Heating Value kj/kg (BlU/lb)
HjSOz (Ib. SOj/lO'BHJ)
J
Installed Capital Cost (SMM)
Annual Processing Excluding Coal
Cost ($»«
Annual Processing including
Coal Cost ($»0
S/Annual Metric Ibn ($ Annual
Tbn) of Clean Coal, Excluding
Coal Cost
5/Annual Metric Ifcn (S/Aimual
Ten) of Clean Coal, Including
Coal Cost +
S/Kilojoule ($/10!BTU),
Excluding Coal Cost
S/Kilojoule (SAO'BTU. ,
Including Coal Cost *
Feed*
7,250
(8,000)
1.18
31,685
(13,622)
744.0
(1.73)
— —
Product Coal From
MEYERS Process
6,532
(7,200)
90
94
90
.64
33,092
(14,227)
387.0
(0.90)
174.8
53.3
129.8
24.73
(22.43)
60.25
(54.65)
.75
(.79)
1.82
(1.92)
Product Coal From
EFEA Process
6,532
(7,200)
90
25
94
90
.5
33,092
(14,227)
301
(0.701)
224.6
70.8
147.4
32.85
(29.80)
68.40
(62.04)
1.00
(1.05)
2.07
(2.18)
Product Coal Frcm
GPAVICHEM Process
5,792
•: (6,384)
90
91
79.8
.64
36,132
(15,534)
352.6
(0.824)
64.9
21.6
79.6
14.92
(13.53)
54.98
(49.87)
.41
(.44)
1.52
(1.61)
* Ite ooal selected is from t±ie Eagle Seam in Buchanan County, Virginia, which contains 1.18 weight percent total sulfur,
0.60 weight percent pyritic sulfur and 0.58 weight percent organic sulfur on a dry basis. It is assumed this coal has
a heating value of 31,685 kJAg (13,622 BTO/lb).
+ Raw Coal Cost , S31.97/Wcg (S29.00/ton).
382
-------
3-21 PROCESS MID COST PERFORMANCE OF CMTOTORTE CHEMICAL COAL CLEANING SYSTEMS
FOR A LOW SULFUR NESTB8J COAL
fct Ctal Yield, Metric Tons Per
if (Jons/Day)
fpitic Sulfur Removal (%)
tooectKet Energy Content
teoent Weight Yield
jti£t * Sulfur in the Product
Batting value W/kg (BTO/lb.)
_
l&Sj {Ib. S02/10SBTO)
J
bftaUed capital cost (Sm)
QalCbst (5m)
feral Processing Cost
WMinj Coal Cost (SMI)
Ifoal Metric Ten ($ Amual
SB) of Clean Coal, Excluding
oaicost
Vtaoual Metric Ibn (S/Annual
SB) of dean Coal, Including
tOlQxt +
VfilOjoule (5AO€BTO)r
6dalij^coal Cost
WUojoule (SAO'KIU),
iBWingCoal Cost "••
Feed*
7,250
(8,000)
0.59
26,270
(11,294)
~*
447
(1.04)
—
,... - ., .„„ .,
~
Prwiict Coal Fran
MEYERS Process
6,532
(7,200)
90
94
90
0.32
27,437
(11,796)
232
(0.54)
I.. ,
174.8
99.5
24.73
(22.43)
46.15
(41.95)
.90
(.95)
1.73
(1.82)
Product Coal Fran
ERDA. Process
6,532
(7,200)
90
25
94
90
0.25
27,437
(11,796)
180.6
(0.42)
224.6
117.0
32.85
(29.80)
54.27
(«V13)
1.19
(1.26)
2.02
(2.13)
Product Coal Fran
GBAVICHEH Process
5,792
(6,384)
90
91
79.8
0.32
29,959
(12,880)
210.7
(0.49)
64.9
56.6
14.92
(13.53)
39.03
(35.49)
.50
(.53)
1.35
(1.42?
* B* ooal selected is from the Primers Seam in T^g finimas County, Colorado which contains 0.59 weight peroant total sulfur, 0.30
Hflitic and 0.29 organic sulfur on a dry basis. It is assumed this coal has a heating value of 26,270 W/ka.
* fe"0al Cost , $18.74/kka
-------
In terras of reducing the SO2 emission level/ the ERDA process is
again the best, with an emission level of 180 ng S02/J (0.42 Ibs S62/10*BTO).
ERDA is followed in order by Gravichera at 210 ng S02/J (0.49 US=f
S02/106 BTU) and Mayers at 232 ng S02/J (0.54 Ibs SO2/106 BTU). The SO2
level of the ERDA product is low because of the small weight percentage
'(0.25) of sulfur in the clean coal. ERDA removes 90 percent of the
pyritic contents and 25 percent of the organic material. Gravichem and
Meyers also remove 90 percent of the pyrites.
Ihe Gravichem operation produces a clean coal with the greatest
energy content - 29,959 kJ/kg (12,880 BTU/lb). The lesser amount of
27,437 kJAg (11,796 BTU/lb) is present in the products from the Mayers
and ERDA. processes. Combining this information with the net coal yields
(by weight percentage) from each process will give the total energy
recovery of the processing. The highest coal yields of 90 percent result
from using the Meyers and ERDA processes. Gravichem1 s net yield is 79.8
percent. The increase in its energy content is not enough to offset
the low net yield; therefore, the Gravichem process does not yield the
largest amount of total energy.
The greater cleaning potential of the ERDA process results in higher
total costs in both the investment and operating sectors. The installed
capital cost of $224.6 million and the annual cost of $119.6 million are
the highest for the three processes. The Mayers process costs are
$174.8 million for capital and $102.1 million for annual processing,
while Gravichem has cost figures for the same respective areas at $64.9
million and $58.6 million. Translating these figures into dollars per
unit energy numbers still indicates ERDA as the most expensive cleaning
process. Including the price of raw coal, ERDA cost equals $2.02/kJ
($2.13/106 BTU). Meyers' and Gravichem1 s cost (including the cost of coal)
equals $1.73/kJ of product ($1.82/106 BTU) and $1.35AJ of product ($1.42/106BTU) ,
respectively. These cost numbers reflect the magnitude of prices to the
user before any transportation cost are added.
384
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3.2.3 Summary of Best Systems of Emission Induction
Ihe "best systems of SO2 emission reduction " (BSERs), which permit
oonplianoe with three alternative SO2 emission control levels, are chosen
based upon performance and cost with respect to the three reference coals.
Ohe matrix in Table 3-22 indicates the choice of the best systems of
emission reduction—chosen among raw coals, alternative levels of PCC,
and alternative types of CCC—for the three candidate coals and the five
emission limitations.
TABLE 3-22 BEST SYSTEM OF EMISSION REDUCTION FOR THREE CANDIDATE
COALS AND FIVE S02 EMISSION CONTROL LEVELS
ftal
SO2 Emission ^Levels
ng SO2/J (lb SO2/106 BTU)
1,290 (3.0) 1,075(2.5) 860(2.0)
645(1.5)
516(1.2)
ffigh-S Eastern
Iw-S Eastern
Icw-S Western
PCC level 5 PCC level 5 PCC level 5 PCC Level 5 CCC ERDA
Middlings Middlings "Deep Cleaned" "Deep Cleaned"
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
PCC level 4
Raw Coal
PCC level 4
CCC Gravichem
Raw Coal
385
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SECTION 3
REFERENCES
1. Centos, G.Y., I.F. Frankel, and L.C. McCandless. Assessment of Coal
Cleaning "technology: An Evaluation of Chemical Coal Cleaning Processes.
EPA-600/7-78-1732, August 1978. 9 pp.
2. U.S. Department of the Interior, Bureau of Mines. Coal-Bitiminous and
Lignite in 1975, February 10, 1977. 52 pp.
3. Personal Cormunications, Rose Axel, Transportation Energy Conservation
Program. Oak Ridge National Laboratory, Oak RLdge, Tennessee, July 25,
1978 and October 26, 1978.
4. McCandless, L.C. and R.G. Shaver. Assessment of Coal Cleaning Technology:
First Annual Report. EPA-600/7-78-150, July, 1978,
5. Sulfur Reduction Potential of U.S. Coals Using Selected Coal Cleaning
Techniques. Unpublished report by Battelle Columbus Laboratory submitted
June 26, 1978. Appendices A-D.
6. PEDCo Environmental, Inc. Memorandum, August 18, 1978. File: 33105.
7. Coal Week, May 29, 1978. p. 5.
8. Coal Outlook, July 17, 1978. p. 6.
9. Broz, L. Economic Basis for IIAR Section IV, Control Costs. Acurex
Corporations, October 5, 1978.
10. U.S. Department of Commerce, Panel of Sulfur Oxide Technologies by the
Commerce Technical Advisory Board. S02 Control Techniques. September,
1975.
11. Gihbs and Hill, Inc. Costs for Levels of Coal Preparation. Electric
Light and Power, January 1977.
12. U.S. Department of Energy. An Engineering/Economic Analysis of Goal
Preparation Plant Operations and Costs. Prepared by Hoffman-Munter
Corporation, February 1978.
13. Argonne National Laboratory. Coal Preparation and Cleaning Assessment
Study. Prepared by Bechtel Corporation, ANL/ECT-3, Appendix A,
Part 1, 1977. pp. 417-436.
14. Op.Cit., Reference 1.
15. Op. Cit. Reference 1.
16. "Economic Indicators CE Plant Cost Index" Chemical Engineering,
October, 1978,
17. U.S. Environmental Protection Aaencv, Industrial Environmental Research
Laboratory, Research Triangle Park. Meyers' Process Developiient for
Chemical Desulfurization of Coal, EPA-600/2-76-143a. 223 pp.
336
-------
SECTION 3
REFERENCES
(Continued)
18. Op. Cit., Reference 6.
19. Argonne National Laboratories. Environmental Control Iitplications of
Generating Electric Power from Coal. 1977 Technology Status Report.,
p. 383.
20. Unpublished Washability data.
21. Op. Cit., Reference 20.
387
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SECTION 4.0
COST IMPACT
4.1 BEST SYSTEM OF EMISSION REDUCTION - COST OVERVIEW
This section discusses the basic cost elements associated with the
three control technologies considered in this ITAR: naturally-occurring,
low sulfur coal, physical coal cleaning, and chemical coal cleaning. For
each cost element the bases and references upon which the cost was deter-
mined are provided. From these cost elements, the BSER cost at shipping
point is calculated for each reference coal (i.e., high sulfur eastern
coal, low sulfur eastern coal and low sulfur western coal). These costs
form the basis of the costs to the industrial boiler operator, presented in
Section 4.2.
As discussed in Section 1.1, the reference coals used in this cost
analysis differ from the reference coals provided to the ITAR contractors
by PEDCo Environmental, Inc. The coal factors which produce cost differen-
tials are primarily fuel price, ash content, and heating value. The high and
low sulfur eastern coals are virtually the same, and from the standpoint of
boiler operator costs the difference between the two sets of reference coals
is insignificant. The fuel prices used for the eastern coals are the same
as PEDGo suggested (i.e., $18.79/kkg for high sulfur eastern coal and $31.97/kkg
for low sulfur eastern coal). Since the heating values of the eastern coals
used in this ITAR are similar to those of the specified coals, the annual
raw coal fuel costs paid by the boiler operator will be approximately the
same for either set of reference eastern coals. The sulfur contents are
also relatively close (see Table 1-2).
There is a more pronounced cost differential between the low sulfur
western coals because this ITAR uses a western bituminous coal, while
PEDCo presented a subbituminous coal. There are major cost differences
associated with using a western bituminous coal mined in Colorado instead
of a subbituminous coal from Wyoming. The fuel price of the Colorado coal
388
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is $19.25/kkg versus $7.15/kkg for the Wyoming coal. Also, the ash contents
differ significantly with the Colorado ooal containing 24.8 percent ash and
the Wyoming ooal containing 5.4 percent ash. The greater ash content will
increase waste disposal costs by a factor of about 4. This value is smaller
than the ratio of ash contents because the greater heating value of the
Colorado coal reduces the fuel requirements.
The greater heating value of the bituminous western ooal should reduce
the capital coal and the capital charges to the boiler operator as compared
to burning a subbituminous ooal. Relative to the boiler costs presented by
PEDCo, the bituminous ooal should reduce capital charges by 10-12 percent,
but will increase fuel costs by a factor of 1.85.
4.1.1 Cost Elements for Low Sulfur Coal Control System
In this section we present, the costs associated with burning low sulfur,
untreated coal. Three basic cost components are included: (1) fuel costs,
(2) transportation costs, and (3) costs of burning the coal in specified
boilers (with no post-conbusticn pollution controls).
The low sulfur supply coals are the six low sulfur coals described in
Section 3 (Table 3-4).
4.1.1.1 Processing Costs at Mine Mouth—
A raw coal of marketable quality must conform to specific size charac-
teristics and requirements. Thus, the raw lew sulfur coal is normally
crushed, and screened prior to shipment to the user site. The method of
screening and crushing depends on the hardness and moisture content of the
run-of-mine coal. However, size reducticn, screening and the rejection of
rocks, where applicable, represent a minimal effort in coal preparation
practice.
For this study, the spot market price for the low sulfur coal is defined
as the breakeven cost plus profit for providing one ton of coal to the
shipping point. This cost includes all appropriate expenses such as mine
development costs, labor and"equipment, appropriate insurance and taxes,
389
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royalties, profit, and a coal preparation cost equivalent to Level 1
cleaning cost.
Any processing costs are added directly to the raw coal price since this
study treats the mine and the coal preparation plant as an integrated
operation under a canton ownership.
4.1.1.2 Compliance of Selected Low Sulfur Coals with Alternative SO2
Emission Limitations—
This section examines the distribution of costs for burning low sulfur
coal in corrpliance with specified SO2 emission limitations. The SO2 emissions
associated with the six reference low sulfur coals are presented in Table
4-1. For Table 4-lf two bases are used: (1) a conservative basis in which
no sulfur as S02 is retained by the bottom ash or slag in the boiler and
(2) a more realistic basis in which some sulfur is retained in the bottom
ash (five percent for bituminous coals and fifteen percent for subbituminous
coals, in which alkaline components combine with some of the sulfur).
Table 4-2, based upon the values in Table 4-1, indicates which of the
supply coals would be able to comply with a set of alternative emission
limitations. This table shows that all of the selected low sulfur coals can
meet the limitation of 1,075 ng SO2/J (2.5 Ib SO2/106 BTU), which is assumed
to be the average State Implementation Plan (SIP) requirement for existing
boilers. Only one (the Las Animas, Colorado bituminous coal) can meet the
most stringent control level of 516 ng S02/J (1.2 Ib SO2/106 BTU). All of the
coals except the Williston, North Dakota lignite can meet the moderate
control level of 860 nq FO2/J (2.0 Ib SC^/IO6 BTU) if no sulfur retention in the
boiler is assumed. The two western bituminous low sulfur coals meet the
intermediate standard of 645 ng SO2/J (1.5 Ib SO2/106 BTU) with no sulfur
retention credit; in contrast, the two subbituminous coals can only meet
this intermediate standard if credit for sulfur retention is taken.
4.1.1.3 Annualized vs. Levelized Costs—
The following sections present costs to the boiler operator for
using low sulfur coals in the form of annualized costs (the method used by
the EPA and its contractors). This section shows the method used to
derive the annualized cost and provide the rationale for including a second
type of cost - levelized cost. Appendix B describes the numerical
390
-------
TABLE 4-1
SO2 Emissions from Burning Candidate Low Sulfur Coals
Coal Source
Buchanan, Va
Williston, ND
Gillette, Wy
Rock Springs,
Wy
Las Animas,
Co
Gallup, NM
Type
B
L
SB
B
B
SB
Heating Value
kJ/kg
BTU/lb
31,700
(13,600)
16,300
(7,000)
19,800
(8,500)
26,700
(11,500)
26,300
(11,200)
23,300
(10,000)
% Sulfur
1.18
0.80
0.70
0.80
0.60
0.80
Sulfur Bnissions
ng SOj/J
(Ib S02/106 BTU)
Mb Sulfur
Retention*
744
(1.73)
982
(2.23)
707
(1.65)
599
(1.40)
449
(1.05)
689
(1.60)
Partial Sulfur
Retention**
705
(1.64)
839
(1.95)
602
(1.40)
569
(1.33)
427
(1.00)
585
(1.36)
Legend: B - bituminous; L - lignite; SB - subbituminous
*Assuming no retention of sulfur in the boiler
**Assuming some retention of sulfur emitted as SO2 : 5% for
bituminous coals, 15% for subbituminous coals and lignites.
391
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TABLE 4-2
Lew Sulfur Coals in Compliance with
Selected S02 Emission Limitations*
SO 2 Emission Control Levels ng SO2/J (lb S02/106 BTQ)
Goal Source
Buchanan, Va
Williston, ND
Gillette, wy
Rxdc Springs, Wy
Las Animas, Co
Gallup, NM
516 (1.2)
-
-
-
-
VB
-
645 (1.5)
. -
-
B
VB
A/B
B
860 (2.0)
A/B '
B
VB
VB
VB
VB
1075 (2.5)
VB
VB
VB
VB
VB
A/B
1290 (3.0)
VB
VB
VB
VB
VB
VB
*The symbol A indicates compliance vflien the value of SO 2 emissions does
not account for retention of sulfur emitted as SO2 during combustion;
B indicates compliance with sulfur retention of 5% for bituminous coals and
15% for subbituminous coals (see Table 4-1).
392
-------
bases, computational method, and resultant levelized costs. The values
presented as annualized costs are the sum of (1) the levelized capital costs
and (2) the first-year operation and maintenance (O&M) costs. The difference
between the two is that the capital costs are levelized over the economic
lifetime of the boiler, while the O&M costs are simply the operating charges
incurred during the initial year of operation. Therefore the capital costs
reflect inflation and interest burdens over an extended period of time,
whereas O&M costs do not. This provides an inherent advantage to tech-
nologies that are operating cost intensive, since they are not penalized
for inflated future costs. Levelizing both types of cost, as is done in
Appendix B, eliminates this inconsistency.
The fixed charge rates and other cost factors for determining the
annualized costs are listed in Table 4-3 for the four major types of
industrial coal-burning boilers considered in this study.
4.1.1.4 Low Sulfur Coal Costs—
The fuel costs are one component of the operating costs of burning coal
in an industrial boiler. The yearly fuel costs are based upon the spot
market prices, P.O.B. mine, in 1978 dollars (listed in Table 4-4) and an
assumed capacity factor of 60 percent. The 1978 annual fuel costs to the
boiler operator are presented in Table 4-5.
4.1.1.5 Transportation Costs for Low Sulfur Coal Control Systems—
Transportation costs for shipping the representative coals (described
in Section 3.1.1.3) can be an important element in the total cost of
burning low sulfur coals. It is assumed that high sulfur coal transporta-
tion costs to the industrial boiler operator will result in primarily local
demand. Presented in Tables 4-6 through 4-10 are the transportation
costs of shipping the six representative low sulfur coals to industrial
boilers located at six demand centers. The costs are presented as both
$/kkg and $/year. The tables represent boilers with five input-fuel
capacities — 8.8 MW, 22 MW, 44 Mtf, 58.6 MW, 117.2 MW — each operating at
a capacity factor of 60 percent.
In most cases, these transportation costs reflect multiple-mode
transport; e.g., rail and barge shipment of coal from Williston, North
393
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TABLE 4-3
Assumptions Used in the Financial
Analysis of Low Sulfur Goal Corabustion*
Assumption or Derived Factor/
Boiler Type
Packaged Watertube
• Underfeed Stoker
Field Erected Watertube
• Spreader Stoker
• Gain-Grade Stoker
• Pulverized
Investeent Life
Operating Cost
Escalation Rate
Discount Bate
Other Fixed Charges*
Fixed Charge Rate
30 years
7%
10%
4%
14.61%
45 years
7%
10%
4%
14.14%
•Assumptions specified by PEDCo in a memorandum to Acure^/Aerotherra
(is)
394
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TABLE 4-4
F.O.B. Mine Prices of Selected Low^Sulfur Coals
F.O.B. Bid Prices - $ 1978*
Supply Area
Low Sulfur Eastern
e.g., Buchanan, Va
Gillette, Wy
Bock Springs, Vty
Williston, ND1"
Las Animas, Co
Gallup, MM
Term
$/GJ
($/ton) ($/106 BTO)
22.00
6.25
14.50
7.00
17.00
13.75
0.99
(0.94)
0.40
(0.38)
0.73
(0.69)
0.46
(0.44)
0.79
(0.75)
0.73
(0.69)
Spot
$/GJ
($/ton) ($/106 BTQ)
29.00** 1.12**
(1.05)
8.00 0.52
(0.49)
15.00 0.75
(0.71)
7.00 0.46
(0.44)
17.50 0.82
(0.78)
15.00 0.74
(0.70)
*Except where indicated otherwise, the prices are those cited in Goal
Week, May 29, 1978.
**The value in dollars per ton is from Coal Outlook, July 19, 1978. Hie
value in dollars per energy unit is based upon 32,100 kJAg (13,800 BTO/lb)
tEstimated.
395
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TABIE 4-5 YEARLY FUEL COSTS (1978 $) AND KIEL INPUTS BY BOILER-TYPE CAPACITY*
U)
U3
CTi
Ini'Uuuii, VA
w-Kul fur l-jstum)
tan AiiitinB. IX)
|s, WV
B.B (v
(jo x 10' imi,i.r)
SAcar k).0
711,740 10,200
57, BOO 8,410
99,100 6,210
118,001) £,)SO
22 m
(75 X 10' oni/hr)
S/Yoar kkijAc.ir
414,000 13,150
J03.BOO 15,650
l»
-------
Table 4-6. TRflNSPOKTATICN COSTS: 6 I£W SUIFUR COALS TO 6 DESTINATIONS
and $/year, based upon demand by an 8.8 J« (30 x 10* ETU/hr)
Boiler operating at 60% capacity factor)
10
Cool \ DrimKKl
St|vly\Tnilcr
Onlcf \
UifclmKiri, Vd.
t m Aiilmos, Co.
WIIIWo.., N4).
(illlollp, WX.
Mntk SpriiKji, Wy.
<;nll«»
80,200
1)4,000
181,400
130,500
94,900
76,500
IfcrrhtHirij.Pa.
$Akg
3.16
16.69
15.4?
19.25
23.13
21.7)
$/yr,ir
u.coo
I0»i,500
I50,(XK)
KI.900
I43.MX)
150,700
CollNlllHM, Oil.
$Akg
4.47
12.71
12.02
16.5.1
19.09
19.64
$/y«*
21,500
79,600
130,600
139,000
IIB,<00
124,700
Dnlon Mo»gn, to.
$/kkg
12.73
12.00
IS. II
IB. 33
10.87
14.64
5/yrair
tfi.OOO
75,100
154,000
154,000
117,201)
94,200
Sucrnmcnlo, Co.
Syfckg
29.51
15.60
17.78
17.24
9.60
10.96
SVyen,
155,900
97,700
181,400
145,000
59,600
69,600
SprMIM.I, II.
$Akg
7.64
0.45
11.10
14.40
15.05
15. Ml
$/y«ir
17,500
52,900
114,000
121,100
93,500
99,100
t The values of §Akg are based upon the following estimated rates.
Railroad, Multiple Rates: 1.41<:/kkg-»n (2.5£/ton-mile), <400 Kn '
" —•"-"" (l^e/ton-roile), >400 Kta
Water:
(0.6«/to>mile)
The cost in $/year is the product of $Akg and the coal used in kkg/fyr by an 8.8 MW boiler at 60 percent
capacity factor (see Table 4-5).
-------
Table 4-7. TRANSPORTATION COSTS: 6 1DW SUIfUR OJALS TO 6 DESTINATIONS ''
(S/kkg and $/year, based upon demand by an 22 ttt (75 X LO'BTU/hr)
Boiler operating at 604 capacity factor)
o£l\ Darand
Xp><-ter
Center ~^
Uuctianan,Va.
I,as Animas.Co.
Williston, N.D.
Gillette, Wy.
Rock Springs,Hy,
Gallup, N.M.
Austin, Tx.
?Akq
15.27
13.42
17.78
16.47
15.27
12.05
5/year
200,500
210,000
403,500
346,000
237,000
191,000
llarrisburg, Pa.
$/kkij
3.16
16.69
15.49
19.25
23.13
23.73
5/year
41,500
261,000
395,000
405,000
359,000
376,500
Columbus, Oh.
5/kkg
4.47
12.71
12.82
16.53
19.09
19.64
$/year
59,000
299,000
327,000
347,500
296,500
312,000
Baton Rouge, La.
S/kkc;
12.73
12.00
15.11
10.33
18.87
14.84
S/year
167,000
88,000
385,000
385,000
293,000
235,500
Sacramento, Ca.
SA*g
29.51
15.60
17.78
17.24
9.60
10.96
5/year
390,000
244,000
453,500
362,500
149,000
174,000
Sprjjigfield.lll.
5/kkg 5/year
7.64 94,000
8.45 132,000
11.18 ' 285,000
14.40 . 303,000
15.05 234,000
15.60 ' 298,000
LJ
U3
CO
The values of S/kkq are based upon the following estiimted rates.
Railroad, Kiltiple Rates: 1.41C/kXerkm (2.5C/ton-mile), <400km
0.68C/kkq- km (1. 2C/ton-mile), >400 ktn
Vfater: 0.34«/kkq-Ion (0.6«/ton-nule)
Ihe cost in S/year is the product of S/kta; and the coal used in kkg/yr by an"44 M? boiler at 60 percent capacity factor (Bee Table 4-5).
-------
Table 4-8. TRANSPORTATION COSTS: 6 LOW SU1FUR ODALS TO 6 DESTINATIONS '
($Akg and $/year, based upon demand by an 44 »J(150 X lO'BTO/hr)
Boiler operating at 60% capacity factor)
Coal \ Demand
Supply \ Center
Center \
Buchanan, Va.
Las Animas, Co.
Williston, N.D.
Gillette, Wy.
Hack Springs ,Wy.
Gallup, N.M.
Austin, Tx.
S/kkg
15.27
13.42
17.78
16.47
15.27
12.05
S/year
401,000
420,000
907,000
692,500
474,500
382,500
Harrisburg, Pa.
?/kkg
3.16
16.69
15.49
19.25
23.13
23.73
$/year
63,000
522,500
790,000
809,500
718,000
753,500
Colunbus, Oh.
S/kkq
4.47
12.71
12.82
16.53
19.09
19.64
$/year
117,500
398,000
654,000
695,000
593,000
623,500
Baton Roiige,Ia.
S/kkq
12.73
12.00
15.11
18.33
18.87
14.84
?/year
334,000
375,500
770,000
770,000
586,000
471,000
Sacramento, Ca.
SAkg
29.51
15.60
17.78
17.24
9.60
10.96
$/year
779,500
488,500
907,000
725,000
298,000
348,000
Springfield, 111.
$Akg
7.64
8.45
11.18
14.40
15.05
15.60
S/year
187,500
264,500
570,000
605,500
i
i
1
467,500
495,500
OJ
VD
U?
The values of $A*g are baaed upon the following estimates rates.
Railroad, Multiple Rates: 1.4KAkg-ion(2.5<:/ton-inile), <400 km
0.68C/kkg-km (1.2C/ton-mile), >400 km
Water: 0.34«r-km (0.6«/ton-mile)
The cost in $/year is the product of $Aky and the coal used in kkg/yr by an 44 MM boiler at 60 percent capacity factor (see Table 4-5).
-------
Table 4-9 . TRANSPORTATION COSTS: 6 LOW SULFUR COALS TO 6 DESTINATIONSt
and $/year, based upon demand by an 58.6 MW (200 x 10 BTJ/nr)
Boiler operating at 60% factor)
o
HiK.-lumnu, Vo.
Los Animm, Co.
WJWslon, N.O.
Cillclle, Wy.
Hock Springs, Wy.
uilty, N.M.
Ausl
$Akg
15.27
13.42
17.70
16.47
15.27
12,05
In, Tx.
S/xror
537,300
562,000
1,215,400
520,000
635,000
$12,0)0
Ikirrisburg, Pa.
$/kkg
3.16
16.69
15. W
19.25
23.13
23.73
S/yc?tir
111,200
700,200
1,050,600
1,004,700
962,100
1,009,700
Columbus, Oh,
$Akg
4.47
12.71
(2.02
16.53
19.09
19.64
$/yo«r
157,500
533,300
076 ,400
931,300
794,600
035,500
Molori floiigc, l.n.
$y*ikg
12.73
12.00
15.11
10.33
in. 87
14.84
$/y«ir
447,600
503,200
1,031,000
1,031,800
705,200
631,100
Socromcuto, Co.
$/kkg
29.51
15.60
17.70
17.24
9.60
10.96
$/ywr
1,044,500
654,600
1,215,400
971,500
. 399,300
466,300
SpringlicM, II.
$/kkg
7.64
8.45
H.in
14.40
15.05
15.60
$/yc400 km
Water:
(0.6<:/ton-mile)
The cost in $/year is the product of $/kkg and the coal used in Itkg/yr by an 58.6 MN boiler
at 60 percent capacity factor (see Table 4-5).
-------
TABLE 4-10. TRBNSPOKIATION COSTS: 6 LOW SULFUR COALS TO 6 DESTINATIONS
(SAkg and S/year, based upon demand by a 117.2 M* (400 x 10s BTU/hr)
Boiler operating at 60% factor)
S031, \ Denand
ss\o""~
Buchanan, Va.
Las Aiimas, Go.
Willision, N.D.
Gillette, Wf.
Rock Springs, Wy.
Gallup, N.M.
Austin, Tx.
SAkg
15.27
13.42
17.78
16.47
15.27
12.05
S/year
1,074,600
1,125,600
2,430,800
1,856,000
1,271,600
1,025,200
Harrisburg, Pa.
SAkg
3.16
16.69
15.49
19.25
23.13
23,73
S/year
222,400
1,400,400
2,117,200
2,169,400
1,924,200
2,019,400
Cblunbus, Oh.
SAkg
4.47
12.71
12.82
16.53
19.09
19.64
S/year
315,000
1,066,600
1,752,800
1,862,600
T., 558, 200
1,671,000
Baton Rouge, La.
SAkg
12.73
12.00
15.11
18.33
18.57
14,84
S/year
895,200
1,006,400
2,063,600
2,063,600
1,570,400
1,262,200
Sacramento, Ca.
S/kkg
29.51
15.60
17.78
17.24
9.60
10.96
S/year
2,089,000
1,309,200
2,430,800
1,943,000
798,606
932,600
Springfield, 11.
S/kkg S/year
7.64 502,600
8.45 708,800
11.18 1,527,600
14.40 1,622,740
15.05 1,253,000
15.60 1,328,000
t The values of $/kkgare based upon the following estimated rates.
Railroad, Multiple Rates: 1.4K/kkg-Wn (2.5400 Km
Water:
(0.6«/ton-mile)
The cost in $/year is the product of S/kkg and the coal used in kkg/yr by an 117.2 MJ boiler
at 60 percent capacity factor (see Table 4-5).
-------
Dakota, to Baton Rouge, Louisiana. Rail transport costs of bulk commodities
like coal depend on a wide variety of factors. Such factors include origin
service conditions (unloading method and trackage necessary to reach the
mine); line haul service conditions (rating, annual weight, train schedule,
interchange facilities); and destination service conditions (unloading
method, trackage necessary to reach receiver). Given these factors, there
are a multitude of rates that can apply to railroad shipment of coal.
The rates upon which the values in Tables 4-6 through 4-9 are based
are: conventional railroad of 1.4l£/kkg-km (2.5^/ton-mile) for rail distances
less than 400 kilometers, and 0.68C/kkg-km (1.2£/ton-mile) for rail distances
n 2^
greater than 400 kilometers; water rates of 0.34
-------
o
u>
3.6
3.4
3.2
3.0
2.8
2.6
52.4
5
C2.2
I"
g 1.4
o
12
1.0
0.8
0.6
0.4
0.2
Figure 4-1. 1974 COAL TRANSPORTATION COSTS, $ 1974
d)
7 8
102 MILES
10
11
12
13
14
15
-------
TOUfi 4-11. JVMnUXUl W1HTS FOB UH SULFUR CQMS IN Tills OTnNUMW IIOIIJTHS U> (I»7B SI
(KXCIJCINC; an. corns)
1
Holler 1Vl«(
tlwil Tyici
1 Direct (bats
(lt!SS fiw])
2 (vorhrj«d
1*2 • 3 OiM UjHtM
(vxc 1 tkl i rK) f ue 1 }
4 Ajiinkilized Coat
(cxcLtviinq fiul)
f< t-u^-l (Lets
7 ^Tns.yo«,
rackacfe Matertuhe
a. a m
F!AB(orn
Inu ml fur
400,200
138,500
538,700
236.300
775,000
165,600
940,600
Kuliiit.
441,700
145,400
587,100
321,600
910,700
57.800
960,500
FlaM-frecta]
Matertuls
22 HV
I'^iBl oni
luw mil fur
660,300
212,900
873,200
561,400
l,43Ti.r.OO
414,000
l.ffM.1,00
Sid Jilt.
710,200
224,300
954,500
745,700
1,700,200
144,500
1,844,700
Hatarture
44 MM
low aulfur
889,400
297,900
1,1117,300
1,084,500
2,271,800
828,000
1,099, BOO
.«*..
1,013,600
320, 700
1,334,300
1,455,700
2,790,000
289,000
3,079,000
field-erected
Hatartiibe
58.6 m
Rastdrn
low aulfur
1,269,700
386,500
1,656,200
1,504,400
3,160,600
1,109.000
4,269,600
SJiitt.
1,486,400
415,100
1,901,800
2,025,600
1,927,400
387,300
4,114,700
Natcrtuho
117.2 »<
eastern
low sulfur Biliblr.
2,221,100 2,591, tOO
C57, 100 697,200
2,878,200 3,288,000
2,792,500 3,758,200
5,670,700 7,047,000
2,218,000 774,600
7,888,700 7, Kf. l,f.(IO
Xilluttn, tl.V., (i»l uist flyijtvs usnil fur silliltinilruiH cnleijnry.
-------
TABLE 4-12. COSTS FOR OPERATING 8.8 J« (30 X 10'BTU/hr) OQfiL FIRED BOILERS USING LOW SULFUR OOALSt
SYSTEM
STANDARD BOILERS
IEAT INPUT
l*/(10 BTU/hr)
8.8 (30)
TYPE
Packaged
Watertube
Underfeed
Boiler
TYPE AND LEVEL OF CONTROL
COAL SOURCE
Buchanan, Va.
Las Animas, Co.
Rock springs, Wy.
Williston, N.D.
Gillette, Wy.
Gallup, N.M.
COAL TYPE0
Bituminous
Bituminous
Bituminous
Lignite
Sub-bi tuminous
Sub-bituminous
LEVEL WITHIN MUCH
UNCONTROLLED
EMISSIONS FALL
nq SOz/J (Ib SOi/lO'BTU)"
860 (2.0)
516 (1.2)
645 (1.5)
1,075 (2.5)
860 (2.0)
860 (2.0)
COSTS
$/M*» .
(SAO'BTU)
520.34(55.96)
¥19.38(55.68)
$18.90(55.54)
521.39(56.27)
520.94(56.14)
522.26(56.52)
IMPACT
% INCREASE IN
TOTAL ANNUALIZED
COSTS OVER t*
INFERENCE COALS
(1.79)
(5.88)
(8.21)
U.28)
(0. 85)
(5.40)
t The costs are found by adding the 1978 fuel costs in Table 4-5 to the yearly boiler costs excluding fuel costs in Table 4-11.
o The western bituminous coals axe assumed to be burned in boilers constructed to bum an average between eastern low-sulfur coal and
western sub-bituminous coal; the sub-bituminous coal and lignite are assumed to be burned in boilers constructed to bum
"sub-bituminous coal" (see Table 4-11).
o
Ul
These are the most stringent of five SO2 levels which the uncontrolled SO2 emissions from each coal can meet, the levels are
516, 645, 860, 1,075 and 1,290 (ng S02/J). No retention of sulfur is assured in the boiler.
Cbsts reflect changes in fuel cost and energy content of the fuel. No cost corrections have been roads to PEDCb Environmental '*'
values for additional coal handling, ash handling or transportation to the boiler.
teference coals - Subbituminous coal and lignite are oonpared with subbituminous (PEDCb); Buchanai, Va. is conpared with eastern
high sulfur coal.
-------
TABI.K 4-13. OOSTS POR OPERATING 22 MM (75 x lO^BTO/hr) GOAL FIRED BOILERS USING IXJW SULFUR COALS
sy .tM
STANDARD DOIl^RS
IIEAT INPUT
MW(lt) rmyhr)
22 (75)
TWE
Field
Erected
Watertube
Boiler
TYPE AND LEVEL OF CONTROL
GOAL SOURCE
Buchanan, Va.
Las Animas, Go.
Rock Springs, wy.
Willistcn, N.D.
Gillette, My.
Gallup. N.M.
CDAL TYPE0
Bituminous
Bituminous
Bituminous
Lignite
Sub-bituminous
Sub-bituminous
LEVEL Hiram VttlCH
UNCONTROLLED
EMISSIONS FALL
n'3 SOnAfdb SOj/lO'BTU)"
860 (2.0)
516 (1.2)
1,075 (2.5)
860 (2.0)
645 (1.5)
860 (2.0)
COSTS
$/H*i
<$/10'BTU)
$16.00($4.69)
$15.05($4.41)
$14. 57 ($4. 27)
$16. 41 ($4. 81)
515.95(54.67)
$17.27(55.06)
IMPACT
% INCREASE IN
TOTAL NtWALIZED
ODSTS OVER tt
REFERENCE GOALS
(2.32)
(6.00)
(8.99)
(1.67)
(1.18)
(7.00)
t 'lie costs are found by adding the 1978 fuel costs in Table 4-5 to the yearly boiler costs excluding fuel costs in Table 4-11.
u '11 le western bituminous coals axe assumed to be burned in boilers constructed to bum an average between eastern low-sulfur coal and
wustem sub-bituminous ooal; the sub-bituminous coal and lignite are assisted to be burned in boilers .constructed to bum
"sub-bituminous coal" (see Table 4-11).
« 'these aie the nost stringent of five SO2 levels which the uncontrolled SO2 emissions from each ooal can meet. The levels are
516, 645, 860, 1,075 and 1,290 (ng SO//J). No retention of sulfur is assumed in the' boiler.
* Costs reflect changes in fuel cost and energy content of the fuel. No cost corrections have been roada to PEDCo Environmental
values for additional ooal handling, ash handling or transportation to the boiler.
** Reference ooals - Subbituminous and lignite are compared with subbituminous (See 8.8 MW sheet)
-------
TABLE 4-14. COSTS TOR OPERATING 44 MW (150 X 106BTU/hr) COAL FIRED BOILERS USING LOW SULFUR COALS*
SYSTEM
STANDARD BOILERS
IIEAT INPUT
MH(10 BTU/hr)
44 (150)
TYPE
Field
Erected
Watertube
Boiler
TYPE AND LEVEL OF CONTROL
COAL SOURCE
Buchanan, Va.
Las Aniinas, Oo.
Hock Springs, Wy.
Williston, N.D.
Gillette, Wy.
Gallup, N.M.
OOAL TYPE0
Bituminous
Bituminous
Bituminous
Lignite
Sub-bituminous
Sub-bituminous
LEVEL WITHIN WHICH
UNCCNTROLLED
EMISSIONS PALL
ng S02/J°°(lb SO2/10SBTU)"
860 (2.0)
516 (1.2)
1,075 (2.5)
860 (2.0)
645 (1.5)
860 (2.0)
COSTS
S/H*i .
<$/10*BTU)
$13.40(53.93)
$12. 45 ($3. 65)
$11.97(53.51)
$13.77(54.03)
$13.31(53.90)
$14.63(54.29)
IMPACT
t INCREASE IN
TOTAL ANNUALIZED
COSTS OVER tt
REFERENCE OOALS
(2.76)
(6. 39)
(10.0)
(2.0)
(1.41)
(8.37)
The costs are found by adding the 1978 fuel costs in Table 4-5 to the yearly boiler costs excluding fuel costs in Table 4-11.
The western bituminous coals axe assumed to be burned in boilers constructed bo bum an average between eastern low-sulfur coal and
western sub-bituminous ooal; the sub-bituminous ooal and lignite are assumed to be burned in boilers constructed to burn
"sub-bituminous ooal" (see Table 4-11).
These are the most stringent of five SO2 levels which the uncontrolled SOa emissions from each ooal can meet The levels are
516, 645, 860, 1,075 and 1,290 (ng SO2/J). No retention of sulfur is assured in the boiler.
Costs reflect changes in fuel cost and energy content of the fuel. No cost corrections have been made to PEDCb Environnental
values for additional, coal handling, ash handling or transportation to the boiler.
Reference coals - Subbituminous and lignite aie compared with subbituminous (See 8.8 NW sheet).
-------
TABLE 4-15. COSTS TOR OPERATING 58.6 t« (200 X 106BTU/hr) COAL FIRED BOILERS USING LOW SULHJR COALS
O
03
SYSTEM
STANDARD BOILERS
IIEAT INPUT
MW(10 BTU/hr)
58.6 (200)
TYPE
Field
Erected
Water Tube
Duller
TYPE AID LEVEL OF OWHDL
(DAL SOURCE
Buchanan, Va.
Las Aniraas, Co.
ftxk Springs, Wy.
Williston, N.D.
Gillette, Wy.
Gallup, N.M.
OOAL TYPE0
Bituminous
Bituminous
Bituminous
Lignite
Sub-bituminous
Sub-bituminous
LEVEL WITHIN HUGH
(JNOONTHOLLED
EMISSIONS FALL
ig SO2/J°*(lb SfhAo'BTU)'0
860 (2.0)
516 (1.2)
645 (1.5)
1,075 (2.5)
860 (2.0)
860 (2.0)
COSTS
<£i!JW
$13. 86 ($4. 06)
512.90(53.78)
$12.41(53.64
$14.46(54.24)
$14.01(54.10)
515.33(54.49)
IMPACT
% INCTEASE IN
TOTAL HWUAUZED
COSTS OVER lt
FEFERENCE OOALS
(2.53)
(6.52)
(10.07)
(1.97)
(1.20)
(8.11)
'ihe costs aie found by adding Uie 1978 fuel ooats in Table 4-5 to the yearly boiler coats excluding fuel costs in Table 4-11.
The western bituntnoua ooala are assured to be burned in boilers constructed to bum an average between eastern lowsulfur ooal and
western sub-bitiminous ooal; tie sub-bituminous ooal and lignite are assured to be burned in boilers constructed to bum
"sub-bituminous coal" (see Table 4-11).
•mase ate the nwt stringent of Cive SO, levels which the uncontrolled 904 emissions fron each ooal can meet. The leveis are
5J6, 645, 860, 1,075 and 1,290 (ng S02/J). No retention of sulfur is assured in the boiler.
Oostu reflect changes in fuel cost and energy content of the fuel. No oast corrections have been made to PEDOo Environmental
values for additional coal handling, ash handling or transportation to the boiler.
ooals - Subbituminous and lignite are conpared with subbituminous (See 8.8 tW sheet).
-------
TABLE 4-16. COSTS TOR OPERATING 117.2 W{400 x 106BTU/hr) OVU, FIRliD BOILERS USING UOW SULFUR CDALS*
SYSTQ1
STANDARD BOILERS
,
IU3AT imvr
MW(lo nro/hr)
ss.e (200)
•TOE
Field
Erected
Water Tube
Boiler
TYPE AMU ICVEL OP OON11OL
COAL SOURCE
Buchanan, Va.
Las Aniroas, Co.
Rock Springs, Wy.
Williaton, N.D.
Gillette, Hy.
Gallup, N.M.
COM, TYPE0
Bituninoua
Bituminous
Bituminous
Lignite
Sub-bituminous
Sub-bitu inous
LEVEL WIT1IIN WHICH
UNOONTBGLLEl)
EMISSIONS FALL
ng SOj/Tdb SOj/lO'BTU)"
660 (2.0)
516 (1.2)
645 (1.5)
1,075 (2.5) SIP
860 (2.0)
860 (2.0)
as-is
$/H*i ,
($/IOSBTU)
$12. 81 ($3. 75)
S11.85($3.47)
$11.36(53.33)
$13. 15 ($3. 85)
$12. 70 ($3. 72)
$14.02($4.11)
IMPACT
t IHCRFJ^R IN
1017VL ATWII/\r,I
COSTS OVKH
rKFnntwcE OUAI
(2.66)
(6.25)
(10.12)
(2.18)
(1.32)
(8.94)
t 'He costs are found by adding tie 1978 fual oosts in Table 4-5 to the yearly boiler ooata excluding fusl ooata in Table 4-11.
a 'Ilia veatam bitwiinoua ooals are assumd to be burned in boilers oonatructed to bum an average between eastern low-sulfur ooal and
western sub-bituminous ooalj the sub-bituminoua coal and limits are assumed to be burned in boilers constructed to bum
"sub-bituminous coal" (see Table 4-11).
°> Tliese are the most stringent of five SO2 levels which the uncontrolled GO, emissions from each coal can meet. The levels are
516, 645, 860, 1,075 and 1,290 (ng SO2/J). No retention of sulfur is assured in tie boiler.
* Cbsts reflect changes in fuel cost and energy content of the fuel. No coat corrections have been made to PUJCb Environnrsntal
values for additional ooal handling, ash handling or transportation to the boiler.
** Reference coals - Subbituminous coal and lignite are compared with subbituminous (PEDCo); Buchanan, Va. is conpared with eastern
low sulfur coal; Las Anirias, Go. and Hock Springs, Wyo. are conpared with eastern high sulfur coal.
-------
TABLE 4-17. NORMALIZED (XGT (?/M*i) TOR LOW SULFUR GOALS
Standard
Boilers
(witl)
8.8
22
44
58.G
117.2
Buchanan ,
Va.
? 20. 34
16.00
13.40
13.86
12.81
Low
Willis ton,
N.D.
5 21.39
16.41
13.77
14.46
13.15
Sulfur Coal
Gillette,
$ 20.94
15.95
13.31
14.01
12.70
Typest
Rock Springs,
wyo.
$ 18.90
14.57
11.97
12.41
11.36
Las Animas,
do.
$ 19.38
15.05
12.45
12.90
11.85
Gal Up,
N.M.
$ 22.26
17.27
14.63
15.33
14.02
Compliance ng SO2/J 744 987 798
Liiai ts
(lb/10b BTU) (1.73) (2.23) (1.65)
507
(1.18)
449
(1.04)
I Above costs reflect changes in fuel cost and energy content of the fuel. No cost
corrections have been made to the PEDCo Environmental'3' values for additional
coal handling, ash handling or transportation to the boiler.
689
(1.60).
-------
4.1.2 Posts for BSER Coal Cleaning Facilities
Cost estimates have been prepared for the best phsycial ooal cleaning
systems to beneficiate the two representative eastern coals selected as the
basis for this study. The reference low sulfur western coal does not require
cleaning to meet S02 emission control levels studied in this ITAR so no
cleaning plant cost estimates are presented. The characteristics of the
two eastern coals are presented in Table 4-18.
A sunmary of "Best" Systems of Emission Reduction Costs for each coal
is presented in Tables 4-19 and 4-20. These BSERs are level 5 (process
levels as defined in Section 2.0) for high sulfur eastern coal and level 4
for low sulfur eastern coal. An example of the detailed installed capital
costs is given in Section 4.2. Appendix E presents the detailed capital
and operating costs for each BSER. These costs used are based on material
balances and heating value yields developed from available washability data
and partition curves on the reference coals. The plants are assumed to
(tf)
operate 3,333 hours per year.
4.1.2.1 Capital Costs—
The capital cost of coal cleaning plants is composed of direct and
indirect costs. Direct costs include the cost of equipment and auxiliaries
and the labor and material required to install the equipment. Installation
costs include: piping, ducting, electrical, erection, building structures,
instrumentation, insulation, painting, site development, construction of
access roads and railroad facilities for incoming and outgoing cars, and
loading and unloading facilities for raw materials and by-product wastes.
Costs for control rooms, administration building, maintenance shops and
stocikrooms are also a part of the direct costs. Indirect costs are costs
that cannot be attributed to a specific piece of equipment, but are necessary
for the entire system.
Cost estimates are based on conceptual flow sheets presented in
Section 3.2.2. Both plants nominally process 1.8 x 106 metric tons (2.0 x
106 tons) of coal annually. They are located at the mine mouth, and the
product ooal is loaded into railroad cars for shipment to the consumer.
Product transport equipment is not included in the cost estimates.
411
-------
TABLE 4-18. OEVRACTERISTICS CF THE REFERENCE HIGH
SULFUR EASTERN COAL AM) IDW SULFUR EASTERN
ODAL
Coal Type:
Seam:
County, State:
RAW GOAL ANALYSIS
High Sulfur Eastern
Upper Freeport ('E1
ooal) *
Butler, Pa.
Ash, % t 23.90
Total S, %t 3<45
Pyritic S, %t 2.51
Heating Valve kJ/fcg (BTOAb)f 26,772 (11,510)
Moisture Ctaitent 5.0
ng S02/J 2,576
'(lbS02A06 BTU) (5.99)
* \fersar reference coals
Dry Basis
low Sulfur Eastern
Eagle *
Buchanan, Va.
10.38
1.18
0.60
31,685 (13,622)
2.0
744
(1.73)
412
-------
TABLE 4-19. SUMMARY OF CLEANING COSTS FOR HIGH
SULFUR COAL (BSER—Level 5)
Basis: 1.87 x 106 metric tons (2.0 x 10e tons) per year of 26,772 kJ/kg
(11,510 BTU/lb) coal feed
3,333 hours per year operation
Capital amortized over 20 years @ 10% interest
Grass roots plant installation
73.3% veight yield, 87.5% heating value recovery
Installed Capital Cost: $18,123,000
Annual Operating Costs
on Clean Coal Basis: $6,350,200 processing cost excluding coal cost
$40,350,200 including coal cost
$4.TB/metric ton ($4.33/ton), excluding coal cost t
$30.27/metric ton ($27.52/ton), including coal cost t
$0.149/106 kJ ($0.158/106 BTU), excluding coal cost t
$0.934/106 kJ ($0.988/10G BTU), including coal cost t
t Values are an average for the two product streams
413
-------
•UVBLE 4-20. sUlWARy OF CLEANING COSTS FOR LOW SUIFUR EASTERN COAL (BSER—Level 4)
Basis: 1.87 x 10s metric tons (2.0 x 106 tons) per year of
31,685 kJAg (13,622 BTU/lb) coal feed
3,333 hours per year operation
Capital amortized over 20 years @ 10% interest
Grass roots plant installation
83.8% weight yield, 89.6% heating value recovery
Installed Capital Cost: $15,975,000
Annual Operating Costs
on Clean Coal Basis: $5,258,900 processing cost excluding coal cost
$63,258,900 including coal cost
$3.46/metric ton ($3.14/ton), excluding coal cost
$41.60/netric ton ($37.75 /ton), including coal cost
$0.102/10* kJ ($0.108/106 BTU), excluding coal cost
$1.23/10S kJ ($1.30/106 BTU), including coal cost
414
-------
The cost estimates are based on information obtained from vendors as
well as extrapolation from Versar in-house information. (5/6/7,8,9/10)
Based on available data, installed capital costs ,for the preparation plants
were estimated at 2.35 times the preparation plant equipment cost. This
estimate assumes the following capital cost distributions for the prepara-
tion plant. (n)
Percent
Plant Equipment 42.5
Building Structures 25.2
Piping 5.1
Electrical 11.6
Erection 15.5
~It>OT
Indirect Capital Posts
Indirect costs are those not attributed to specific pieces of equipment.
Items included and their values are as follows:
Indirect Costs Values C*2)
Engineering 10% of direct costs
Construction and
Field expenses 10% of direct costs
Contractor fee 10% of direct costs
Start-up 2% of direct costs
Contingency 20% of total direct and indirect costs
Working capital 25% of operating and maintenance costs
including costs of utilities, chemicals,
operating labor, maintenance and repairs
and disposal costs
Land Cost
The cost of the land required for equipment is also a direct cost.
Land costs vary considerably from location to location. For these estimates
(13)
land is assumed to be $2,400 per acre.
415
-------
Pricing Levels
Estimates are based on June 30, 1978 price and wage levels. No
allowance has been made for future escalation.
4.1.2.2 Annual Operating Costs—
The coal processing costs include all variable operating, maintenance,
and associated overhead costs for operating the coal preparation facilities.
In addition to these costs, fixed charges consisting of capital amortization,
taxes, insurances and interest on borrowed capital are also included.
Operating and Maintenance Labor and Supervision
Operating personnel costs are estimated based on two shifts per day
of operation totalling 3,333 hours per year and a third shift per day
(i1*)
for maintenance.
The cost of direct labor and maintenance labor is taken as $23,700.
per year. Operating wage for supervisory personnel is assumed at $30,600
(15 )
per year. These wages reflect mid-1978 wage levels. Direct operating,
supervisory and maintenance crew size for each level of coal beneficiation
is based on available published information and actual data gathered from
(16)
visits to coal cleaning plants. Operating manpowsr is specified as follows:
Direct Labor Supervisory Labor Maintenance
Coal Man/Day Man/Day Man/Day
Cleaning Level IV 18 3 10
Cleaning Level III 10 36
The increased complexity and amount of equipment in the level 5 plant over
a level 4 plant causes the increase in direct labor and maintenance require-
ments.
Maintenance, Supplies and Replacement Material
The equipment in a coal preparation plant is replaced on a frequent
basis because it is subject to considerable wear. For these estimates the
cost of replacement equipment, including maintenance supplies, is taken as
7 percent of the total turnkey costs of each plant.
416
-------
Utilities and Chemicals
The annual costs for utilities and chemicals are based on:
power @ $.0072 mJ ($0.0258Awhf18)
water @ $0.04/1,000 1 ($0.15/1,000 gal)(19)
magnetite @ $71.7/metric ton ($65/ton) *2°*
flocculant @ $4.40Ag ($2/lb)(21)
Consumption of magnetite is based on a rate of 0.376 kg/kkg (0.75 lb/
ton) of course coal feed and 0.752 kg/kkg (1.5 Ib/ton) of fine coal feed
Flocculant consumption is based on 2 mg/liter of liquid in the flocculated
stream.
Rafuse Disposal Cost
The cost for refuse disposal was assumed to be $1.1 per metric ton
($1.0/ton). (23)
Overhead Costs
Overhead costs are business expenses not directly chargeable to a
particular process unit but allocated to it. Overhead costs are usually
presented as payroll overhead and plant overhead. Payroll overhead includes
employee benefits, recreation and public relations. The plant overhead
includes administrative, all local staff support, and plant management
functions such as purchasing, scheduling, accounting of finance, safety
(24)
and medical services. Values used in this analysis are:
payroll overhead = 30 percent of total labor cost
plant overhead =26 percent of labor, maintenance and supplies,
and chemical costs
Cleaning Plant Capital Charges
Capital related charges include annualized capital costs, taxes,
insurance and general and administrative costs.
417
-------
Cleaning Plant Capital Equipment Amortization
It is assumed that regardless of tax and depreciation considerations,
a plant operator would probably finance and amortize a coal preparation
plant by means of an equal-payment, self-liquidating loan. If the loan
is payable with equal installments, the amount due per period per dollar
of loan as a function of the loan period and the interest rate is given
by
R = i (1 + i)n
(1 + i)n - 1
where:
R = capital recovery per period per dollar invested
i = interest rate per period expressed as a decimal
n = number of periods in the amortization schedule.
The factor R multiplied by the anortizable cost vail yield the per-
period fixed cost covering interest and principal.
For purposes of this exercise a life expectancy of 20 years for coal
cleaning plants and an interest rate of 10 percent were assumed.
Cleaning Plant Taxes, Insurance and General and Administrative Costs
Property taxes and insurance vary considerably in different parts of
the country. For this study, taxes, insurance and general and adminis-
(2 5)
trative costs were taken as 4 percent of depreciable investment.
4.1.2.3 Comparative Coal Costs to User Utilizing Cleaned and Run-offline
Coal from the Same Mine—
Table 4-21 presents a surmary of costs for the Run-of-Mine
coal and the same coal beneficiated at the BSER level. Included in this
comparison Is the effect of coal quality, preparation yield, pulverization,
and ash disposal at the user plant.
418
-------
TABLE 4-21.
COMPARATIVE COAL COST TO USER UTILIZING
RUN-OF-MINE COAL AND COAL BENEFICIATED
AT BSER LEVEL.
High Sulfur Eastern*
Oasts ROM Coal
V&lue at shipping
$/foetric ten ($/ton) 18.
$/106 kJ ($/106BTU) 0.
Value as fired (including
grinding costs)
$/faetric ton ($/ton) 18.
$/106 kJ ($/105 BTU) 0.
total fuel cost at user
plant (including ash
disposal at $40/ton)
74(17.00)
70(0.74)
95(17.20)
72(0.75)
$Anetric ton ($/ton) 29.44(26.70)
$/10s kJ ($/106 BTU) 1.10(1.16)
ROM
Coal Data Coal
Yield, wt % 100
kJ/kg (BTU/lb) 26,772
(Dry Basis) (11,510)
Ash content, % 23.90
Sulfur content, % 3.45
ngofS02/J 2,576
(Ib of S02/106 BTU) (5.99)
Deep
Cleaned
Product
35.3
33,555
(14,426)
5.28
0.98
645
(1.5)
BSER Level
36.38(33.00)
1.19(1.26)
36.49(33.10)
1.19(1.26)
42.63(38.66)
1.27(1.34)
Mid-
dlings
38.0
31,662
(13,612)
10.30
1.54
1,075
(2.5)
Low Sulfur
ROM Coal
31.97(29.00)
1.01(1.06)
32.19(29.20)
1.02(1.07)
36.65(33.24)
1.16(1.22)
RDM Coal
100
31,684
(13,622)
10.38
1.18
744
(1.73)
Eastern
BSER Level
41.68(37.89)
1.23(1.30)
41.90(38.09)
1.24(1.31)
43.76(39.78)
1.30(1.37)
Cleaned
Product
83.8
33,882
(14,567)
4.13
0.89
525
(1.22)
* Cost for Deep Cleaned Coal Product only
(Refer to table 4-39 for cost development)
419
-------
Cost of Raw Coal Rsquired per Ton of Clean Coal
For the purpose of this study the spot market price to the beneficia-
(26)
tion plant of the three raw coals under study are taken as:
High sulfur eastern $18.79/metric ton ($17/ton)
Low sulfur eastern $31.97/metric ton ($29/ton)
Low sulfur western $19.34/metric ton ($17.50/ton)
Since the clean coal yield is less than 100 percent of the raw coal
feed, it takes more than 1 ton of raw coal to provide for 1 ton of clean
coal.
Grinding Posts
•Hie grinding of coal for 70% minus 200 mesh pulverized firing requires
energy. Hardness is expressed as Hargrove Grindability Index (HGI). A
55 HGI coal uses 31 mJ/fastric ton (7.9 kwh/ton), a 100 HGI uses 18 mJ/metric
(27)
ton (4.4 kwh/ton), a 110 HGI uses 16 mJ/foetric ton (4 kwh/ton). For
these estimates power was charged at 7.17 mills per ml (25.8 mills/kwh)
Estimated HGE before and after beneficiation and the power consumption
values for each coal are given below.
Coal Beneficiated Coal
MJ/metric ton ItF/metric ton
Coal Type HGI (kwh/ton) HGI (kwh/ton)
High Sulfur Eastern 55 31 (7.9) 110 16 (4)
Low Sulfur Eastern 60 30 (7.6) 60 30 (7.6)
Ash Disposal at the User Site
The value of ash disposal at the user site was taken as $44.10/metric
ton ($40/ton).(29)
Analysis of Coal Cost to User
In Table 4-21 the cost differential to the user between the beneficiated
and the raw coal in terms of $/metric ton are$13.19 and $7.36 for the high
sulfur eastern (deep cleaned product) and the lew sulfur eastern coal,
respectively. These costs expressed in terms of $/106 kJ are 0.17 and
0.14 , respectively.
420
-------
Additionally, Table 4-21 indicates high SO2 emission levels for the
nm-of-mine ooals as compared to the clean coal. The best physical ooal
cleaning system for the high sulfur eastern ooal produces two product
streams, a deep cleaned product which could be in compliance with a control
level of 645 ng SO^/J (1.5 Ibs SO2/106 BTU) and a middling stream which wr.uld
be in compliance with a control level of 1,075 ng SOg/J (2.5 Ibs SC^/IO* BTU).
Beneficiation of the low sulfur eastern ooal at the BSER level produces a
single stream with slightly higher sulfur level than that required to meet
a control level of 516 ng SOj/J (1.2 Ibs SC^/IO6 ETC), assuming no sulfur
retention.
4.1.3 Cost^of^ Chemical Opal Cleaning Processes
This section presents cost information on the three candidate chemical
coal cleaning BSERs presented in Section 3.3. The first two processes,
the Mayers and the Gravichem (physical coal cleaning plus Meyers) are
capable of reducing only a portion of the pyritic sulfur in the feed coal,
vrtiile the third process, the ERDA process, is capable of reducing both
pyritic and organic sulfur. As stated in Section 3.3, chemical coal
cleaning processes are still in the development stage and will not be
available commercially for 10 years.
The process costs are based on preliminary conceptual processing
schemes. The process operating conditions, the process chemistry, the levels
of removal of pyritic and organic sulfurs, the heating value, and the yield
recovery information are based on evaluation of the individual developer's
claims. Where cost information was supplied by a developer, these costs
were utilized, to the extent possible, as the basis of the cost information
in this report. However, the costs were modified to allow the evaluation
of the various processes on a common basis.
The cost estiinates presented for the Meyers and the ERDA processes
are based on a plant which processes 270 metric tons (300 tons) per day high
sulfur eastern coal on a 24-hour per day and 330 days per year basis (8,000
tons/day, three train plant). The basis for the Gravichem process is a 96
421'
-------
metric ten {106 tons) per hour Meyers process unit (a single train plant)
operating on a 24-hour a day and 330 days per year basis. The physical
ccal cleaning section of the plant processes 558 metric tons (615.4 tons)
per hour of raw coal (8,000 tons/day) operating 13 hours per day and 250 days
per year. The third shift is set aside for scheduled plant maintenance.
Total Direct Capital Costs
Total direct capital costs for the Meyers and EEDA. processes were
extracted from "Technical and Economic Evaluation of Chemical Coal Cleaning
Processes for Reduction of Sulfur in Coal" issued in January 1978.(30'
These costs were adjusted to June 30, 1978 bases by using appropriate plant
cost indices. The direct capital cost for the physical coal cleaning
portion of the Gravichem plant was extracted from the "Mayers Process
Development for Chemical Desulfurization of Coal" report. ^31' This cost
was adjusted to reflect June 30, 1978 prices by using appropriate indices
and was then adjusted to the desired plant capacity using a. scale factor
(32)
of 0.7.{ }
The cost of the land used in these estimates is the same as that used
for developing costs of the physical coal cleaning plants.
Indirect Capital Cost
Items included in indirect costs and their values are the same as those
developed for the physical coal cleaning plants..
Annual Operating Costs-
Operating manpower, energy and utilities requirements for the chemical
coal cleaning plants were extracted from the Versar chemical coal cleaning
report. * ' The operating and maintenance personnel wages and the cost bases for
utilities and chemicals are the same as discussed in physical coal cleaning.
The costs for steam and other chemicals used only in chemical coal cleaning
process estimates are listed below:
600 psig steam @ $4,83/1,000 lb.(31t)
Lime § $35/netric ton C$32/ton) (35)
Lignin sulfonate binder § $0.06/lb.(36)
422
-------
Maintenance supplies and material for all chemical coal cleaning cases
were taken as 5 percent of the total turnkey costs based on a lower expected
maintenance requirement than physical coal cleaning plants, The cost for
the disposal of by-products generated by the chemical coal cleaning plants
(38)
was extracted from the Versar chemical coal cleaning report.
The cost bases for overhead, capital charges and raw coal costs are
presented in the physical coal cleaning discussion.
Chemical Coal Cleaning Costs
Capital and annual operating costs for each chemical coal cleaning process
based on the three reference coals are presented in Tables 4-22 through 4-24.
The results indicate that the cost of cleaning high sulfur coal and low is
$24.73, $32.85 and $14.92 per metric ton (excluding the raw coal cost) for the
Ifeyers, ERDA, and Gravichem (physical coal cleaning plus Meyers process),
processes, respectively. Note that the cleaning costs are independent of
the sulfur content of the ooal.
4.2 CONTROL COSTS TO USER
Control costs are the incremental costs that the boiler operator would
pay in order to meet the emission limits. These costs include the increased
cost of the cleaned coal, but lower costs associated with particulate
collection and ash disposal.
Control costs here will exclude the cost of fuel transportation to the
user, although in reality, the least cost BSER for a given standard would
be chosen by the boiler operator with transportation costs included. For
example, to meet the moderate control level of 860 ng S02/J (2.0 Ib SO2/106
BTCJ), the industrial boiler operator has the choice (within the control
technologies described in this ITAR) of using a physically cleaned high sulfur
eastern coal, a low sulfur eastern coal, or a low sulfur western coal.
Dependent upon the location of the industrial boiler, the least cost BSER
could be any of the three choices. Since location is unspecified, the control
costs for the BSER will include a presentation of each BSER exclusive of
transportation costs.
423
-------
TABLE 4-22. CLEANING COSTS FOR CANDIDATE CHEMICAL COAL
CLEANING SYSTEMS ON HIGH SULFUR EASTERN COAL.
Net Goal Yield, Metric Tons Per
Day (Tons/Day)
Percent Net Energy Content
Percent Height Yield
Height % Sulfur in Predict
Heating Value kJ/kg (BTO/lb.)
ng SO2 (Ib S02A06 3TO)
J
Installed Capital Cost ($MM)
Annual Processing Excluding Coal
Cost ($MM}
Annual Processing Including Coal
Cost ($MM)
S/Annual Metric Ion ($ Amual
Han.) of Clean Coal, Excluding
Coal Cost
Ton} of Clean Coal, Including
Coal Cost +
$/Kilojoule (S/IO'BTO),
Excluding fjQflil Gost
C/vi 1/vvvila fS/10*HIW
IncluSing Coal Cost +
Peed*
7,250
(8,000)
3.40
26,772
(11,510)
2,576
(5.99)
Product Coal Froa
MEYERS PPCCESS
6,532
(7,200)
94
90
0.89
28,507
(12,256)
623.4
(1.45)
163.6
53.3
98.1
24.73
(22.43)
AC CC
(41.31)
0.87
(0.92)
(1.69)
Product Coal Frcra
ERDA Process
6,532
(7,200)
94
90
0.73
28,507
(12,256)
511.6
(1.19)
224.6
70.8
115.7
32.35
(29.80)
c-a cq
(48.70)
1.16
(1.22)
(1.99)
Product Coal From
GRAVICHEM Process
5,792
(6,384)
91
79.8
0.89
31,126
(13,382)
571.8
a.3-»>
64.9
21.6
55.6
14.92
(13.53)
38 40
(34.83)
0.48
(0.51)
(1.30)
* Ihe coal selected is an Upper Freeport ('E' Coal) from Sutler County, Pennsylvania which contains 3.45 weight percent total
sulfur, 2.51 weight percent pyritic and 0.94 weioht percent organic sulfur on a drv basis. It is assumed that this coal
has a heating value of 26,772 JcJ/kg (11,510 BTD/lb).
+ Raw Coal Cost $18.74Afcg ($17.00/ton).
424
-------
TABLE 4-23. CLEANING COSTS FOR CANDIDATE CHEMICAL COAL CLEANING
SYSTEM ON LOW SULFUR EASTERN COAL.
At Coal ZLeld, Metric Tons Per
rtroant Net Energy Content
percent Hsight Yield
Wight % Sulfur In Traa Product
Beating Value kJAg (BTO/lb)
igSQj (Ib SOz/10* BTO)
Installed Capital Cost (S>M)
flraual Processing Excluding Coal
Cost (5Mt)
prynmi Processing Including
GalCbet ($UO
S/tanual Metric Ton (5 Annual
ta) of Clean Coal, Occluding
Coal dost
Vtanual Metric Ten (S/flnnual
3Qa) of Clean Coal, Including
Cbal Cost ^
5/MOojoule (SAO'BTO),
Bccliding Coal Cost
$/KUojoule (S/IO'BTO) ,
iHff |_^jfli I^CT (Tf^i^ ODSt
Feed*
7,250
(8,000)
1.18
31,685
(13,622)
744.0
Product Coal Fran
ME5TIHS Process
6,532
(7,200)
94
90
.64
33,092
(14,227)
387.0
(0.90)
163.6
53.3
129.3
24.73
(22.43)
60.25
(54.65)
.75
(.79)
1.B2
(1.92)
Product Coal Fran
EPDA. Process
6,532
(7,200)
94
90
.5
33,092
(14,227)
301
(0.701)
224.6
70.8
147.4
32.85
(29.80)
68.40
(62.04)
1.00
(1.05)
2.07
(2.18)
Product Coal From
GPAVICHEM Process
5,792
>' (6,384)
91
79.8
.64
36,132
(15,534)
352.6
(0.824)
64.9
21.6
79.6
14.92
(13.53)
54.98
(49.87)
.41
(.44)
1.52
(1.61)
* Tns coal selected is from the Eagle Sean in Buchanan County, Virginia, which oontaijis 1.18
0.60 «ei*t percent pyritic sulfur and O.Si weight percent organic sulfur on a dry basis, it
a heating value of $31,685 kJ/kg.
f tew Coal Cost $31.97Akg (S29.00/tcn).
this coal
425
-------
TABLE 4-24. CLEANING COST OF CANDIDATE CHEMICAL COAL CLEANING
SYSTEMS ON A LOW SULFUR WESTERN COAL.
Net Goal Yield, Metric Tens Per
Day (Tens/Day)
Percent Net Energy Content
Percent Weight Yield
Height % Sulfur in the Product
Heating Value fcJAg (BTO/lb.)
ng SO? (lb S02AOS BTO) •
J
Installed Capital Cost (SIM)
Annual Processing Cost. Excluding
Coal Cost ($MM)
Annual Processing Cost
Including Coal Cost ($MM)
5/Annual Metric Ton ($ Annual
Ton) of Clean Coal, Excluding
Coal Cost
S/Annual Metric Ibn ($/Annual
Ton) of Clean Coal, Including
Coal Cost +
$/Kilo joule (5/10 '3TC),
Excluding Coal Cost
-------
4.2.1 Cost Breakdown
4.2.1.1 Capital Costs to the User—
Capital costs are assumed equal to the estimated capital costs of
(39)
standard boilers provided by PEDCo Environmental, Inc. Note, however,
that cleaned coal has a higher energy content and lower ash content than
the reference coals used in the cost estimates. Threfore, specific pieces
of equipment including the boiler, the coal handling system, and the ash
handling system, could be reduced in size to handle clean coal. The
reduction in costs cannot be quantified, because the cost bases for the
equipment are not sufficiently detailed to determine a cost reduction
factor. An engineering judgment would suggest that the capital cost
benefits accrued by using cleaned coal are probably not more than a few
percent of the total installed capital costs.
4.2.1.2 Operation and Maintenance Costs—
The annual operating and maintenance costs (O&M) for the BSER are
described in Sections 4.1.1, 4.1.2 and 4.1.3 for naturally occurring coal,
physically cleaned coal, and chemically cleaned coal, respectively. The
boiler annual operating costs are equal to those provided by PEDCo environ-
mental with two modifications, which are (1) a reduction in waste disposal
costs and (2) an adjustment in fuel cost to include the cleaning charge and
increased fuel energy content per unit weight.
Waste disposal costs are primarily the cost for collecting and handling
of both bottom ash and fly ash. The amount of ash is a function of the
coal's ash content and energy content. It is assumed that ash disposal
costs are proportional to the pounds of ash per energy content for each
BSER.
The fuel cost to the industrial boiler operator for cleaned coal is the
corbined cost of the fuel, the cleaning charge, a five percent profit on
the cleaning charge, and grinding costs (pulverized coal only). The fuel
price is provided in Table 4-4. The cleaning charge is calculated as
427
-------
described in Secticn 4.1.2, with an assumed five percent profit (before
taxes) added to the breakeven charge. The level 5 physical coal cleaning
products present an exceptional pricing case because two coal products are
generated, a deep cleaned low sulfur, low ash coal and a middling coal.
Prices for this cleaning level were set by using the naturally occurring
coal equivalent (in quality) price for the middling product and assigning
a higher price to the top quality coal that provides a five percent (before
taxes) profit to the cleaning plant operator. This pricing scheme is
presented in the calculation example.
4.2.2 BSER Costs
The BSER 1978 annual costs are presented in Tables 4-25 through 4-36.
These tables indicate that the cost per M/Jh. gradually increases as emission
control levels become more stringent. These control costs also decrease as
boiler size increases, reflecting the economy of scale effect. Note that
fuel costs become more significant (i.e., greater percentage of annualized
costs) with increasing boiler capacity.
Figures 4-2 through 4-4 illustrate the magnitude of the increased
annualized operator costs associated with increasingly stringent emission
control levels. These figures indicate that the costs per IVWh gradually
increase as emission control levels become more stringent. These control
costs also decrease as boiler size increases, reflecting the economy of
scale effect. Note that fuel costs become more significant (i.e., greater
percentage of annualized costs) with increasing boiler capacity.
Figure 4-5 shows more dramatically the increase in costs required to
remove greater quantities of sulfur from the coal. Eaw coal costs are not
shown since they do not reflect any SO2 removal. The roost cost-effective
technology would appear to be the middling product from a physical coal
cleaning plant. This technology costs only $.04 per kg of SO2 removed.
The middling product, however, is only effective for SO2 compliance up to
about 1,100 ng S02/J using this particular high sulfur coal. A more
acceptable pre—treated fuel is the deep cleaned product, which costs only
$0.15 per kg of SCfe removed and can comply with control levels as low as 525
ng S02/J. Large increases in cost are observed when chemical coal cleaning
is employed.
428
-------
TABLE 4-25. CC6TS OF "BEST" SO2 CONTBOL TECHNIQUES FDR 8.8 W GOAL-FIRED BOILERS
lillNG HIGH SULFUR EASTER* COAL
VD
SYSTEM
HIGH SULFUR EASTERN COAL
STANDARD BOILERS
Ileat In|JUt
VH (MOOU/lir)
**
8.8 (30)
26,772 kJ/kg
3.45% S
28,847kJ/kg
1.54% S
30,533 kJAg
0.98% S
30,533 kJAg
0.98% S
27,903 kJAo
0.73%
Type
Underfeed
Stoker
TYPE AND
. I£VJiL
OF OOtfl'ROL
Raw Coal
Uncontrolled
SIP
1,075 ngSO2J
Middling Prod.
Level 5 pec
Moderate
1,290 ngS02/J
Middling Prod.
Level 5 pec
Optional Mod.
860 ngSOz/J
Deep cleaned
Prod.
Level 5 POC
Intermediate
645 ngS02/J
Deep Cleaned
Prod.
Stringent
516ngSO2/J
Chemical OC
ERDA
COOTTOL
EFFICIENCY
(%)
0
58%
58% .
75%
75%
80%
ANNUMJ'ZED
COSTS
S/lM(t)
(S/MBTU/hr)
21.17 (6.20)
21.43 (6.28)
21.43 (6.28)
22.17 (6.50)
22.17 (6.50)
26.19 (7.67)
IMPACTS *
% INCREASE
IN COSTS OVER
UNCONTRO1JJ33
BOILER
N.A.
1.2
1.2
4.7
4.7
23.7
% INCREASE
IN COSTS OVER
SIP-CONTROLLEl;
U01LER
N.A.
N.A.
0
3.4%
3.4%
18«
* BASED ONLY Oti ANNUALIZED COSTS
** Raw Coal Analysis: 3.45% S; 26,772 kJAg; 23.90% asl« (2,576 ng SO2/J)
+• Percent Reduction in
-------
TABLE 4-26. COS1S OF "BEST" SO2 CON7IOL TECHNIQUES FOR 22 t« COAL-FIRED BOILERS
USING HIGH SULFUR EASTEIN COAL
SYSTEM
IlIUI SUIJ^R EASTERN COAL
STANDARD U011JJRS
Heat lii(Hit
M-l (MHTU/lir)
**
22 (75)
26,772 kJ/kg
3.454 S
-'8,847 kJAg
1.54",
M
30,533 kJAg
0.98% S
30,533 kJAg
0.98% S
27,903 kJAg
0.73%
Type
Water tube
Grate-
Stoker
TYPE AND
LEVEL
OF CONTROL
Raw Coal
Uncontrolled
>IP-1,075 ngSOz/
J Middling Prod
Level 5 pec
Moderate
1,290 ngSOj/J
Middling
Level 5 pec
Optional Mod
860 ngSOz/J
Deep Cleaned
Prod.
Level 5 PCC
Intermediate
645 ngS02/J
Deep Cleaned
Prod.
Level 5 PCC
Stringent
516 ngS02/J
ERCft Chem CC
CONTROL
EFFICIENCY"1'
(»)
0
58%
58*
75%
.75%
80*
ANNUALIZED
COSTS
M*(t)
(S/MBlU/lir)
16.59 (4.86)
16.83 (4.93)
16.83 (4.93)
17.65 (5.17)
17.65 (5.17)
21.61 (6.331
IMPACTS *
% INCREASE
IN COSTS OVER
UNCONTROLLED
BOILER
N.A.
1.0
1.0
6.0
6.0
30.3
% INCREASE
JN COSTS OVER
SIP-CONTOOLLEI
BOILER
N.A.
N.A.
0
4.8
4.8
28.4
BASED ONLY ON ANNUALIZED COSTS
Raw Cbal Analysis: 3.45% S; 26,772 kJAg; 23.90* ash ; (2,576 ngSOj/J)
Percent Reduction in ngSO2/J
-------
TABLE 4-27. COSTS OP "BEST" S02 CCOTTHOL TKCilMIQUES FOR 44 W OOAL-FIRED BOIU2HS
USING HIGH SULFUR FA3TEFH COAL
OJ
SYSTT'M
11 113 1 SDIJIJR KASTliHN COW,
STANIMHD ODIUMS
Heat \ni\\t
**
•14 (150)
26,772 kJAa
3.45% S
28,847 kJAg
1.54% S
31,533 kJ/kg
0.98%
30,533 kJAg
0.98%
27,903 kJ/kg
0.73% S
Type
Sprearier
Stoker
TVni AN!)
OF CONTKDI,
Raw Coal
Jncontrolled
SIP -
1,075 ngSOj/J
Middling Prod.
Ijevel 5 pec
Moderate
1,290 ngSOzJ
Middling Prod.
level 5 pec
Optional Mod.
860 ngSOj/J
Deep Cleaned
Prod.
Lave! 5 PCC
Intermediate
645 ngSOz/J
Deep Cleanerl
Prod.
Level 5 PCC
Stringent
516 nqSOj/J
ERrn.
Chanical CC
(CMIBOf.
0
58%
58%
75%
75%
80%
ANNUALTZED
COfflS
$AM(t)
13.56 (3.97)
34.37 (4.21)
14.37 (4.21)
15.12 (4.43)
15.12 (4.43)
19.13 (5.61)
* BASED CNLY ON ANNUALIZED COSTS
IMPACTS *
% INCRRASI3
IM COSTS OVKK
UNCOWITOLLEI)
HDIIJilR
N.A.
6.0
6.0
11.5
11.5
41.1
% INCREASE:
IN COSTS OVKK
N.A.
tJ.A.
0
5.2
5.2
33.1
Raw ooal Analysis: 3.45% S; 26,772 kJAg; 23.90*ash; (2,576 ng S02/J)
*• Percent Reduction in nqSO2/J
-------
TABLE 4-28. COSTS OF "BEST" SO'2 CONTTOL UX3INIQLES TOR 58.6 W COAL-FIRED BOILEJS
USING HIC1I SULFUR BftSTEFN GOAL
to
* UASL:D ONLY ON ANNUALIZED COSTS
** Haw Ooal Analysis: 1.45% E; 26,772
+ Percent Induction ir. nqS02/J
: 23.90% ash. (2,576
SVSJTM
Iliai SU1KJR EASTIJKN COAL
STANDARD BOILERS
llocit tutJuL
Md (MBTD/hr)
**
58.6 (200>
26,772 kJ/kg
3.45% S
78,847 kJAg
1.54% S
"
30,533 kJ/kg
0.98% 3
30,533 kJAg
0.98%
27,903 kJ/kq
0.73% S
Type
Pulverized
Coal fired
TYPE AND
IJ3VKL
OF CCWriOL
Raw Coal
Uncontrolled
l.Jfs ngSOz/J
Middling Prod.
Level 5-PCC
rkaderate
1,290 ngS02/J
Middling Prod.
Level 5-PCC
Optional Mad.
860 ngS02/J
Deep Cleaned
Prod.
Level 5 PCC
Intermediate
645 ngSOa/J
Deep Cleaned
Prod.
Level 5 PCC
Strimjent
51C rujSOz/J
ERDA
Chemical CC
UJm wL
EFFICIENCY*
*
0
58%
58%
75%
75*
00%
ANNUAL! ZED
COSTS
$AM
($/MEfTU/lu-)
13.95 (4.09)
14.97 (4.38)
14.97 (4.38)
15.72 (4.60)
15.72 (4.60)
19.74 <5.78)
IMPACTS *
% INCREASE
IN COSTS OVER
DOILEK
N.A.
7.3
7.3
12.7
12.7
42
% INCREASE
IN COSTS OVER
SIP-COMITWIAH
DOILEIl
N.A.
N.A.
0
5.0
5.0
31.9
-------
TABLE 4-29. COSTS OF "BEST" SOj CONTROL TECHNIQUES FOR 117.2 VH CORL-FIMD BOILERS
USING HIGH SULFUR EASTERN COAL
U>
SYSTEM
HIGH SUWUR EASTHN COM,
STAM3AHU BOILEKS
lloat In(xit
VH (MBOl/hr)
**
118 (400)
26,772 kJ/kg
3.45% S
28,847 kJAg
1.54% S
30,533 kJAJ)
QO1IJ3R
N.A.
8.0
8.0
13.8
13.8
45.3
IN cons OVM<
SIPHDMIWXJiE
|V)]f£K
N.A.
N.A.
0
5.4
5.4
34.5
•ii i ' " •
* UASUl) ONLY ON ANNUALIZED COS'lB
" Kaw Oodl A.nalysis: 3.45* S; 26,772 WAg; 23.90% ash, (2,576 ng SO./J
+ Percent Reduction in rvjSOz/J
-------
TABIJJ 4-JO. COSTS CF "BrST SOj CONTROL TECHNIQUES TOR 8.8 MW COAL-FIRED BOIIERS
USING 10W SULFUR EASTERN CDAL
UJ
BftSLD ONLY ON ANNUALI ZED COSTS
Raw Coal: 1.18% S; 31,685 kJ/kg; 10.4% ash? (745 ng S02/J
Percent reduction in ntjSO2/J
Physical coal cleaning product is 525 r>gS02/J without sulfur retention
SYSTEM
LOW SULFUR EASTERN COAL
STANDARD BOILUKS
lluat (tl(JUt
1*1 (MHID/lir)
**
8.8 (30)
IJfTf
1^.^.
337882 kJ/kq
0.89't S
11
ccc
3C,130 k.JA(J
0.64'i S
Type
Underfeed
Stoker
Boiler
TYPK AND
LLVFJj
OF CONTROL
RAW
SIP - Control
Moderate
1,290 ngS02/J
or 860 nejSOjA
Intermediate
645 ngS02/J
PCC-Level 4
Stringent
516 ngSOz/J
PCC-Level 4++
COC-Gravichem
COMJ-RDL
J.
EFFICIENCY
(%)
0
0
0
30%
30%
50%
ANNUALIZED
COSTS
$A«(t,
($/tffiTU/lir)
$20.48 ($6.00)
i> H
H (i
$21.11 ($6.19)
$21.11 ($6.19)
$21.79 ($6.38)
IMPACTS *
% INCREASE
IN COSTS OVER
UNCONTROLIJD
BOILER
0
0
0
3.1%
3.1%
6.4%
% INCREASE
IN COSTS OVER
SIP-CONTROLLEr
N.A.
f
N.A.
0
3.1%
3.1%
3.2%
-------
TABLE 4-31. COSTS OF "BEST" S02 CONTFOL TECHNIQUES FDR 22 NW CQAL-FIICD BOILEPS
USING LOW SULFUR EASTEIN COAL
u>
SYSTIM
LOW SULFUR EASTERN COAL
STANDARD BOILERS
Heat Input
MW (MBTU/nr)
**
22 (75)
POC Coal
33,882 kJAg
0.89% S
CCC Coal
36,130 kJAg
0.64% S
Type
Chain -
Grate -
Stoker
TYPK AND
T FA/P'T
LilWrJ..
OF COMl'HOL
RAW
SIP - Control
^kx3erate:
1,290 ngSOi/J
or 860 ngSO2/J
Intermediate
645 ngS02/J
PCC-Level 4
Stringent
516 ngS02/J
PCC-Level 4
Chemical CC
Gravichem
CCMfHOL
>
EFFICIENCY
(%>
0
0
0
30%
30%
50%
ANNUALIZED
COSTS
SAW(t)
($/MBTiU/lir)
$16.17 ($4.74)
"
II
$16.61 ($4.92)
$16.81 ($4.92)
$17.48 ($5.12)
IMPACTS *
* INCREASE
IH COSTS OVIiR
UNCONTROLLED
BOILER
0
0
0
3.9%
3.9%
8.1%
% 1NCKFASE
IN COSTS OVER
Sll'-CONTROLUa
IWILER
N.A.
N.A.
0
3.9%
3.9%
8.1%
* BASED ONLY ON ANNUALIZED COSTS
** Raw Coal: 1.18% S; 31,685 kJAq; 10-4% ash; {745 ng S02/J
•*• Percent Reduction in ngS02/J
-H- PCC product is 525 ngSO2/J without sulfur retentioi
-------
TABI.E 4-32. COSTS OK "BEST" SO2 OONTIOL TEdNJQllKS FOR 44 Mrf GOAL-FIRED BOILERS
USING LOW SUUUR IttSllifM ODAL,
Ky.9JlM
!/*) SULFUR KASTtKM
.
JJ.VI'J,
(IF CU«'I«JL
I
BonjiJ^
0
0
0
6.2%
6.2%
11.2*
% JNCIUiASIC
IN COSIB OVER
SIP-OONJ'JWtJJTJ
IY)(LJ'!R
N.A.
N.A.
0
6.2%
6.2%
11.2*
** );//J wittrxit uulfuc retmtiun
-------
TABLE J-33. COSTS OF "BESr1 SO2 CONTROL TECHNIQUES FDR 58.6 hH COAL-FIRED BOILERS
USING LOW SULFUR EASTERM OQAL
SYSIIH
LOW SULFUR EASTERN COAL
STANUAR1) TOILERS
Heat Input
(*( (Mffl\J/lir)
**
58.6 (200)
PCC
33,882 kJ/kg
0.89% S
4.1% ash
or
36,130 kJAg
0.64% S
3.1* ash
Type
Pulverized
Coal-Fired
TYPE AND
7 M/li1!'
IjIwr^Li
OF COWTROL
RAW
SIP - Control
Moderate:
1,290 ng SO^/J
and 860 nqSO,/J
intermediate
645 ng SO2/J
PCC-Level 4
Strintjent
516 ngSOz/J.,
PCC-Level 4
CCC -
Gravichem
COMl-ROL
A.
EFFICIENCY
. (%)
0
0
0
30%
30%
50%
ANNUALIZED
COSTS
$/liw(t)
($/MBTU/hr)
$13.91 ($4.08)
M 1.
n ii
$14.83 ($4.35)
$14.83 ($4.35)
$15.51 ($4.54)
IMPACTS *
% INCREASE
IN COSTS OVER
UNCONTROLLED
DOILER
0
0
0
6.6%
6.6%
11.5%
% INCREASE
IN COSTS OVER
SIP-CONTROLLEt
BOIIER
H.A.
N.A.
0
6.6%
6.6%
11.5%
BASED ONLY ON ANNUALIZED COSTS
** Raw Coal: 1.18%S; 31,685 kJ/kg; 10.4% ash; (745 ngSOj/J)
+ Percent Reduction in ngS02/J
++ PCC product is 525 ngSO2/J withcjut sulfur retention
-------
TABUJ 4-.J4. QKTS OF "BEST" SO COWJWL TECHNKJJ1S TOK 111.2 MV CGAIr-FIRH) UOUJIRS
IB ING UK SW fVR EASTtWJ COM,
CO
* bASI2> ONLY ON ANNIIALIZET) COSTS
ajal: l.lBtS; J1,6U5 kJ/kj; 10.4% ashf (745 IK]S02/J>
nt Hediiction in ifjSOj/J
i
$13.78 (S4.04)
$14.46 (S4.24)
IMI'AL'JW »
IN 1XJBIS IMill
(DIU'K
0
0
0
7.2
7.2
12.4
« INL'UMSK
IN CXKiTS (Wia»
.i;ii'-awn*ifJJ)
i«nu-:u
N.A.
N.A.
0
7.2
7.2
12.4
-------
TABLE 4-35. COSTS OF "BEST" S02 CONTHDL TECHNIQtES FOR 8.8 rt« and 22 MV COAL-FIRED
BOILEtS USING LOW SULFUR WESTEFN CDAL
SYSTEM
1JOH SUUUR WESTERN COAL
STANDARD BOILERS
Meat Iii()ut
m (MDTU/litr)
8.8 (30)
„
u
,.
"
22 (75)
n
Type
Underfeed
Stoker
«
(l
..
••
Chain-Gratt
Stoker
n
TY11J AND
LhvhLi
OF CttflRDL
RAW (744)
SIP-
Control (1074)
1,290 ngS02/J
860 ngSO2/J
645 ngS02/J
516 ngSO2/J
RAW (744)
SIP-
Control (1074
L,290 ngSO^/J
860 ngS02/J
645 ngSOz/J
516 tigSOVJ
com**,
EFFICIfWCY
(%)
0
0
. 0
n
0
0
0
0
8
0
0
AWJUALIZED
COfflS
W«(t)
($/Hm\J/hr)
521.39 ($6.27)
***
$21.76 ($6.33)
it n
ii H
n n
h H
516.81 ($4.93)
$17.18 ($5.03)
N H
H It
II II
H II
IMPACTS *
% INCREASE
IN COSTS OVER
UWCOW1TOLLED
IH1I.ER
N.A.
1.7%
1.7%
1:?!
1.7%
N.A.
2.2«
2.2%
2.2%
2.2*
2.2%
% INCREASE
IN COSTS OVER
SII>-COMl'ROiJJ3:
BOliER
N.A.
N.A.
0
"0
0
0
J.A.
N.A.
0
0
0
0
* BASED ONLY ON ANNUALIZED COSTS
** 0.59% S; 26,270 kJA>j; 24.8% ash - K
*** Increase due to particulate control
Coal Analysis- (744 ng SO2/J)
-------
TABUi 4-36. 00313 op "BEST" SOZ OONTHDL TECHNIQUES TOR 44 W AND 58.6 AND 117.2 Mi COAL-FIRED
BOILEFS USING IOW SHI-Pim WES1ERN (UAL
SYSTEM
LOW SULFUR WESTERN COAL
STANDARD BOILERS
llont Iii[X4t
MW (MUTU/hr)
**
44 (150)
II
II
"
58.6 (200)
H
"
« "
117.2 (400)
Type
Field
Greeted,
watertube,
spreader
stoker
"
Field
erected,
watertube,
pulverized
COdl
"
TYPE! AND
I.EVKL
OF CONTROL
RAW
SIP - Control
1,290 ngSOa/J
860 ngS02/J
645 ngS02/J
516 ngSOz/O
RAW
SIP - Control
1,290 ngSO2/J
860 ngS02/J
645 ngS02/J
516 ngS02/J
RAW
SIP - Control
(1,074)
1,290 ngS02/J
860 ngSOz/J
645 ngSO^/J
516 ngS02/J
CONTROL
EFFICIENCY
.„ .
0
0
0
0
0
0
0
0
0
0
0
0
0
Q
0
0
0
0
ANNUALIZED
COSTS
IWt)
(?/HBTU/hr)
513.74 (54.03)
514.71 (54.31)
H H
« ii
II H
II II
514.10 (54.13)
515.13 (54.43)
H It
H H
» II
512.95 (53.79)
514.15 (54.15)
It H
It II
It It
H II
IMPACTS *
% INCREASE
IN COSTS OVER
UNCONTROLLED
BOILER
N.A.
7.1%
7.1%
7.1*
7.1%
7.1*
N.A.
7.5%
7.3%
7.3%
7.3%
7.3*
N.A.
9.3%
9.3%
9.3%
9.3%
9.3%
% INCREASE
IN COSTS OVER
SIP-CONTROLLEI
TOILER
N.A.
N.A.
0
0
0
0
N.A.
N.A.
0
0
0
0
N.A.
0
0
0
0
0
* BASED ONLY ON ANNUALIZED COSTS
0.594 S; 24.8* ash; 26,270 kJ/kg - Raw Coal Analysis - (744 ng SO2/J)
-------
25
s
g
ZED COST
g
_J
1
Z
IS
14
13
"1
/
0
VVATERTUBE GRATE
PULVERIZED
spflf APFR VTOKFR •
PULVERIZED
COAL-FIRED 117.2 M W
J
'
. 300 400 600 600
PCC
• "' " " "|
1 pcc , ,
* +j-T-vt— -i RAW
& • 1 1
4
L.I ,
! * **-iJi _
• • * i *•'] i
t: • : • 1— 1 1 '
_ , , . J I "^jl I
1
700 800 900 1000 1100 1200 | 260
r.^ l-r\ 1300 25OO
EMISSION STANDARD (lig SO2/J)
FIGURE 42 LEVEL OF CONTROL ANNUALIZEO COST CURVES FOR HIGH SULFUR EASTERN COAL
-------
to
- 20
S
3
3
u
a
10-
300
400 600 600 700 800 BOO 1000 1100
EMISSION STANDARD (nq S02/J)
1200
TYPES OF BOILERS
UNDERFEED STOKER
CHAIN GRATE
STOKER
PULVERIZED
-•*COAL FIRED 68.8 M W
-^WATERTUBE SPREADER
STOKER
^PULVERIZED
COAL-FIRED 117.2
1300
FIGURE 43 LEVEL OF CONTROL ANNUALiZED COST CURVES FOR LOW SUIFUR EASTERN COAL
-------
26
U
g 20
N
!j
D
U)
10
TYPES OF BOILERS
300 400 600 600 700 800 900 1000 1100
EMISSION STANDARD (ng SO2/J)
1200
UNDERFEED STOKER
CHAIN GRATE
STOKER
WATERTUBE. PULVERIZED
COAL STOKER 58 6 M W
_. "JATEHTUBE SPREADER
_»~.|OKER
WATERTOBE, PULVERIZED
COAL STOKER
1300
FIGURE 4-4 UVEL OF CONTROL ANNUALIZED COST CURVES FOR LOW SULFUR WESTERN COAL
-------
1.20
CHEMICALLY CLEANED
LOW S COAL
1.00
.80
.60
.40
.20
LOS EASTERN
PCC, LEVEL 4
CHEMICALLY CLEANED
HI-S COAL
PCCHI-S
DEEP CLEANED PRODUCT
PCC
MIDDLINGS PRODUCT
200
400
600
800
1000
1200
1400
EMISSION STANDARD (ng S02/J)
FIGURE 4-5 COST EFFECTIVENESS CURVES
444
-------
The normalized costs are shown as step functions because the cost
differential to attain less than optimum cleaning for any given beneficia-
tion process is negligible. For example, the fuel cost to the boiler
operator would not be significantly less if the deep cleaned coal (i.e.,
high sulfur eastern coal, cleaned to level 4) ware only treated to produce
650 ng S02/J, instead of 525 ng SO2/J, assuming the same equipment was used.
On the other hand, a separate, distinct coal cleaning scheme could be
designed to produce a deep cleaned product which would produce 650 ng S02/J.
The fuel cost from this plant might be significantly less than the benefi-
ciation plant presented in this study. It is not within the scope of this
33AR, however, to design the multiplicity of cleaning plants necessary to
produce a relatively smooth cost curve. It is also noted that any cost
curve would be unique to that particular coal being cleaned since the
costs are a function of pyrite content, organic sulfur content, size
distribution of pyritic material, ash content, moisture content, and
wasnability characteristics (see Section 3).
This study only provides the costs required to attain optimal cleaning
for each BSER and reference coal. The tables are based on 1978 annual
operating costs for standard boilers provided by PEDCo. Examples of the
calculations to determine BSER costs are provided in Tables 4-37 through
4- 39.
The results of costing the BSER technologies reveal two major findings.
First, for high sulfur eastern coal, physical coal cleaning is an exception-
ally low cost control technology. That is, to meet moderate or SIP control
levels, a 60 percent reduction in sulfur dioxide emissions per unit heat rate
can be obtained with a 1 percent increase in annual operating costs. To comply
with an optional moderate (860 ng SOz/J) or intermediate control level (645 ng
SOz/J), a 75 percent reduction in sulfur dioxide emissions is required and
can be obtained with only a 4-8 percent increase in operating costs.
Stringent control levels cannot be met with physical coal cleaning which is
reflected in the almost 30 percent increase in costs using chemical coal
cleaning versus an uncontrolled boiler.
445
-------
TABLE 4-37. EXAMPLE OF COSTS FOR BSER
Basis: High sulfur eastern coal - 26,772 kJ/kg (as received);
3.40% sulfur; 23.4% ash
18.74 x 106 metric tons (2.0 x 106 tons) per year
3,333 hours per year operation
Capital amortized over 20 years @ 10% interest
Level 5 - Grass roots plant installation
73.3% weight yield, 87.5% heating value recovery
Summary Values for Coal Cleaning Plant with the Two Product Streams Combined
Installed Capital Cost: $18,123,100
Annual Operating Costs
on Clean Coal Basis: $6,350,200 processing cost excluding coal cost
$40,350,200, including coal cost
$4.76/metric ton ($4.33/ton) , excluding coal cost
$30.27/mstric ton ($27.52/ton), including coal cost
$0.149/106 kJ ($0.15P/106 BTU), excluding coal cost
$0.934/106 kJ ($0.988/106 BTU), including coal cost
446
-------
TABLE 4-37. (Continued) PREPARATION PLANT CAPITAL REQUIREMENTS
FOR HIGH SULFUR GOAL (BSER)
RKW GOAL STORAGE AND HANDLING Mid 1977 prices
Raw Coal Storage Area
20,000 ton capacity with reclaiming feeders and tunnel 300,000
Raw Coal Belt to Rotary Breakers
42 inch wide - 200 feet @ $520 per foot 104,000
Tramp Iron Magnet over Raw Load Belt
(explosion proof, self cleaning type) 20,000
Rotary Breaker
9 ft. dianeter - 17 feet long 150,000
Surge Silo
5,000 ton capacity @ $110 per ton 550,000
Raw Coal Belt to Scalping Screen
42 inch wide - 250 feet @ $520 per foot 130,000
Raw Coal Scalping Screen and Structural Work for
the Crusher and the Breaker 350,000
Raw Coal Crusher
2 @ $128,000 each 256,000
Raw Coal Belt to Plant
42 inch wide - 250 feet § $520 per foot 130,000
Total Raw Coal Storage and Handling Cost 1,990,000
447
-------
TABLE 4-37. (Continued) PREPARATION PLANT
Equipment Cost
6 x 16 Foot Single Deck Screen
2 @ $15,000 each 30,000
Heavy Media Vessel
Daniels EMS Washer 31,000
4 x 16 Foot Double Deck Vibrating
Drain & Rinse Screens
4 @ $20,500 each 82,000
Crusher - McNally Split Mash
Geared Stacker Crusher 58,500
Centrifugal Dryer - Bird Model 1150 D 48,000
3 x 16 Foot Single Deck Vibrating
Drain & Rinse Screen 12,000
Magnetic Separators for Heavy & Dilute Media
30 inch diameter - 10 feet long
6 @ $8,500 eadi 51,000
Sumps for Heavy & Dilute Madia
4,000 gal - 1/4" steel
6 § $14,000 each 84,000
6 x 16 Foot Single Deck Vibrating
Des liming Screens
4 @ $19,000 76,000
Heavy Media Cyclone
24 inch diameter - w/toi-Hand Liner
9 @ $6,000 each 54,000
Sieve Bends
5 feet wide - 80 inch, radius 24,000
o e $4,000 each
6 x 16 Foot Single Deck Vibrating
Drain & Rinse Screens
6 @ $19,000 114,000
Sieve Bends
6 feet wide - 30 inch radius
2 @ $4,800 each 9,600
6 x 16 Foot Single Deck Vibrating
Drain & Rinse Screens
2 @ $19,000 38,000
Clean Coal Centrifuge - Bird Model 1150 D
4 @ $48,000 192,000
448
-------
TABLE 4-37. (Continued) PREPARATION PLANT
Sump - Heavy Media Cyclone leed Simps
7,000 gallcn - 1/4 inch steel
2 @ $14,000 each
Sieve Bend
4 feet wide - 30 inch radius
31 x 16' Single Deck Vibrating
Drain & RLnse Screen
Sieve Bend
6 feet wide - 80 inch radius
61 x 16' Single Deck Vibrating
Drain & Rinse Screen
Clean Coal (3/8 x 28M) Centrifuge
Screen-Bowl
Refuse (3/8 x 28M) Centrifuge
Bird Model 1150 D
Sunp - 28 M x 0 Cyclone Feed Sump
10,000 gallon - 1/4 inch steel
2 @ $18,000
Thickening Cyclone #1
14 inch diameter - w/rubber liner
15 @ $1,300 each
Sunp - Cyclone: #1 Underflow Sunp
2,500 gallon - 1/4" steel
2 @ $10,000 each
Sunp - Hydroclone Feed Sunp
10,000 gallon - 1/4 inch steel
2 @ $18,000
Thickening Cyclone #2
14 inch diameter - w/rubber liner
5 @ $1,300 each
Hydroclones - 14 inch Diameter - w/Ni-Hand
Liner & Refrax Underflow
10 6 $3,500 each
Sieve Bend
5 feet wide - 30 inch radius
10 @ $4,000 each
28,000
3,200
12,000
4,800
19,000
110,000
48,000
36,000
19,500
20,000
36,000
6,500
35,000
40,000
449
-------
TABLE 4- 37. (Continued) PREPARATION PLANT
Centrifuge Dryers - Screen Bowl 190,000
Clarifier - Emoo Model B-90
90 feet in diameter 132,000
Disc Filter - 2,000 sq. ft. 130,000
Pumps for the Preparation Plant 150,000
Total Preparation Plant Equipment 1,924,000
Total Installed Cost of Preparation Plant Equipment
Including Site Preparation
Building Structure, Piping,
Electrical and Erection
1,924,100 x 2.35 4,521,600
The factor 2.35 for determining total direct capital costs from plant equipment
costs was arrived from both Hoffman-Muntner Go. and Bechtel Corp. in their
reports on preparation plant costs. The percent of breakdown of the
total direct cost is provided below:
PERCENTAGE
Plant Purchased Equipment 42.5
Building Structures 25.2
Piping 5.1
Electrical 11.6
Erection 15.5
100
These factors do not include construction labor and field expenses which are
considered indirect costs.
450
-------
TABLE 4-37. (Continued)
MISCELLANEOUS FACILITIES AND EQUIPMENT:
Clean Coal Belt to #1 Fuel Silo
36 inch wide - 300 feet @ $480 per foot 144,000
#7 Fuel Silo
10,000 ton capacity @ $110 per ton 1,100,000
Clean Coal Belt to #2 Fuel Silo
36 inch wide - 300 feet @ $480 per foot 144,000
#2 Fuel Silo
10,000 ton capacity @ $110 per ton 1,100,000
Refuse Belt
36 inch wide - 300 feet @ $480 per foot 144,000
Refuse Bin
2-100 ton capacity - fabricated plant 100,000
Coal Sampling System 300,000
Hut-Train Loading Facility 500,000
3,532,000
StMIARY OF TOTAL INSTALLED CAPITAL COST (MID 1977)
Raw Coal Storage and Handling 1,990,000
Preparation Plant 4,521,600
Miscellaneous Facilities and Equipment 3,532,000
10,043,600
Factor for Escalating Direct Costs from Mid-1977 to
Mid-1978 (*6) = 8.0%
10,043,600 x 1.080 = Total Installed Capital Cost (Mid 1978) $10,847,100
451
-------
TABLE 4-37. (Continued)
TOTAL INSTALLED CAPITAL COST (June 30, 1978)
Total Direct Costs (equipment & installation) 10,847,100
Installation costs, indirect
Engineering
(10% of direct costs) 1,084,700
Construction and field expense
(10% of direct costs) 1,084,800
Construction fees
(10% of direct costs) 1,084,700
Start-up (2% of direct costs) 217,000
Performance tests (ininirnum $2,000) —
Total Indirect Costs 3,473,000
Contingencies
(20% of direct and indirect costs) 2,864,000
Total Turnkey Costs (direct & indirect & contingencies) 17,184,100
Land 264,000
Working capital (25% of total direct operating costs)* 675,000
GRAND TOTAL (turnkey & land & working capital) 18,123,100
* Assumes 25% of operating and maintenance costs which include: utilities,
chemicals, operating labor, maintenance and repairst and disposal costs.
452
-------
TABLE 4-38. SAMPLE CALCULATION FOR ESTIMATING ANNUAL
OPERATING COSTS FOR HIGH SULFUR ODAL (BSER)
ANNUALIZED COSTS (Mid 1978$)
Direct Labor (18 man yrs x $23,700/yr) 426,600
Supervision (3 man yrs x S30,400/yr) 91,200
Maintenance Labor (10 man yrs x $23,700/yr) 237,000
Maintenance Materials & Jteplaoenent Parts
(7% of total turnkey costs) 1,202,900
Electricity (25.8 nriJLs/kwh x 2,318 kw 199,300
Water ($0.15/103 gal x 8 I/sec (127 gpm) 3,800
Waste Disposal $l.l/kkg ($l/ton) 433,200
Chemicals (magn: 1,157 kkg @ $71.7/kkg ($65/ton) 83,000
(floe: 5,290 kg @ $4.4 kg ($2/lb) 23,300
TOTAL DIIECT COST 2,700,300
Payroll (30% of direct & indirect &
maintenance labor) 226,400
Plant Overhead (26% of direct, indirect &
maintenance labor and maintenance,
and chemicals) 536,600
TOTAL OVERHEAD COST . 763,000
Capital Recovery Factor (11.75% of total
Turnkey Costs) 2,132,000
G&A, Taxes & Insurance (4% of total
Turnkey Costs) 687,400
Interest on Working Capital (10% of W.C.) 67,500
TOTAL CAPITAL CHARGES 2,886,900
TOTAL ANNOALIZED COSTS (excluding coal cost) 6,350,200
Cost Per Ton of Moisture Free Product $4.33/ton
Cost Per 106 ETC of Moisture Free Product S0.15P/106 BTO
Raw Coal Cost, 1.8 x 106 kkg/yr @ $18.74/kkg ($17/ton) 34,000,000
TOTAL ANNUALIZED COST (including coal cost) $40,350,200
Cost per kkg (ton) of Moisture Free Product $30.34 ($27.52)
Cost per 10s kJ (10-6 BTU) of Moisture Free Product $0.934 ($0.988)
453
-------
TABI£ 4-39. SAMPIE CALCULATION FOR COMPARATIVE GOAL COSTS
Fuel Cost
Yield = 73.3% of raw coal; Middling = 38% Deep Cleaned Product = 35.3
Total Annual Post = $40,350,200 = $27.52/ton = $30. 34/taetric ton
Total Clean Coal [ 2 x 10s tons x. 7331
yr.
AVERAGE COAL COST = $30. 34 /metric ton
However, the 2 products are not equal, so two prices must be provided.
Assume middling product at 12,400 BTU/lb(as received); 10.3% ash; and 1.54% .s.ulfur
is priced at spot market price for naturally-occurring equivalent coal
$24/ton or $26. 40/metric ton
At 38% yield - 2 x 105 x .38 = 0.76 x 106 TPY middling product
0.76 x 106 x $24 = $18.2 x 10s per year revenue
Income: $40.4 x 10s (annual cost) - $18.2 x 10s (middlings revenue = $22.2 x 10s
or deep cleaned product must yield $22. 2x 10* to break even
At 35.3% yield - 2 x 10s x .353 = 0.71 x 10s SPY Lo-S product
=$31.45/tcn
0. 71 x 10*
At 5% profit = $33.02/tcn - Value at Shipping = $36. 32 /metric ton
^T X rffjo * — - =?1.26/106-ffTO= $1.20/106kJ
ton 2,000
(as received)
Value as fired: Same as 'snipping1, except add $.10/ton for grinding at
oulverized boiler
Ash Handling Post Factor
POM coal at 23.4% ash and 26,772 kJAg
- 8.7, x 1C-
Middling Product: 10.3% ash; 28,847 kJAg
51 x fork, = ^ x ^
Lew-sulfur product: 5.28% ash; 30,533 kJAg
.05289 ash x |_^al = -3 a
g coal 30. o3
-------
TABLE 4-39. SAMPLE CALCULATION FOR COMPARATIVE COAL COPTS
(Continued)
Ash Handling Factor:
Middling Product = 3.57 ~0.40
§774"
Low-S Product = 1.73 = 0.20
8.76
Industrial Boiler Operator Costs
Two values change over those provided by Acurex/PEDCo:
1) Fuel costs (increase)
2) Ash handling costs (decrease)
For 8.8 MW Underfeed Stoker
1) Fuel Cost Increase:
a) Middling coal:
$24.00 x ton x Ib _ s q7/1r)6 OTTT
TZT— -> nnn l v. ~^^^^^^^^^^^^ ~~ 9.3 '/ -LU sSl\l
ton 2,000 ID. >Q124 x 1Q6 ^
$.97 x 30 x 106 BTO x 8,760 hr x 0.6 C.F. = $152,600
106 BTU hr. yr.
- Raw Fuel Cost Provided by PEDCo = 116,300
Clean Coal Cost Difference + $36,300
2) Bottom Ash Costs - Middling Product Reduces Value by 60%.
Raw Coal Bottm Ash Handling (FEDCo Cost) = $21,000
0.40 x $21,000 = 8.400
Bottom Ash Handling Cost Difference = -$12,600
SubTotal Increased Costs $23,700
Increase Costs for Fly Ash: $4/ton x 1,670 tons/yr. of fly ash=$ 6,700
Total Annual Costs = $952,300 + 23,700 + 6,700 = $982,700
Annual Cost Basis: $/MW
$982,700
8.8 >W x 8,760 hr. x .6
hr. yr.
$21.25/MW(t)
For Table 4-36 :the low sulfur product coal costs are based on $1.26/105 BTU
and an ash handling factor of 0.2. The ERDA process costs are based on
S2.ll/105 3TV and an ash handling factor of 0.75.
455
-------
The second major finding is that physically and chemically cleaned low
sulfur eastern coal can meet a stringent control level of 516 ng SO2/J (1.2
Ib S02A06 BTU) at relatively low increase in cost to the industrial boiler
operator. This increase in annual cost is as low as 3 percent or as high
as 9 percent, dependent upon control technology and size of the boiler.
Because chemical coal cleaning is still in the development stage, the future
cost to the boiler operator for chemically cleaned coal may be radically
different than the values presented here.
4.2.2.1 Comparison of BSER Costs with Commercial Plants—
The capital cost and annual operating and maintenance cost for each
BSER were compared to previous calculations and estimates from existing
beneficiation plants to check the accuracy of the cost calculations. The
report "An Engineering/Etoonomic Analysis of Coal Preparation Plant Operation
and Cost" prepared for the Department of Energy by Hoffman-Munter Corporation
(it 7)
was used as the basis for the comparison.
A general statement in the Hof fman-Munter report was that beneficiation
plants cost between $7,000-$23,000 per ton-hour of coal input (mid-1977
tiiB\
dollars). The normalized BSER capital costs were $34,800/ton-hour for
the multi-stream plant and $30,000/tcn-hour for the preparation plant
designed for low sulfur eastern coal (mid 1978 dollars). The major
differences in these costs were the inclusion of indirect installation
costs (i.e., engineering, construction expenses, start-up costs, and per-
formance tests), land costs and working capital costs in this study. If
these two costs are excluded, the normalized costs decrease to $26,200/ton-
hour for the multi-stream plant and $23,000/ton-hour for the low sulfur eastern
coal preparation plant (mid-1978 dollars). Including one year inflation at
8 percent, the normalized costs appear to be in the correct range and
conservatively high.
As a further check, the results of this study were compared to similar
plants presented in the Hoffman-Munter study. The comparison is provided
in Tables 4-40 and 4-41. These tables show that the BSER beneficiation
plant costs are good estimates of actual plant costs.
456
-------
TABLE 4-40. COST COMPARISON WITH LEVEL 4, HEAW MEDIA PLANT
USDJ3 HIGH SULFUR EASTERN COAL
Parameter
(Plant Description)
Hof finan-Muntner Actual
Plant Costs ftnid-1977)
Heavy media process cleaning
900 TPH; 2-stage heavy media
cyclone; fines cleaning
by deister tables; thermal
dryers.
Raw Coal Handling
Equipment cost
Preparation Plant Equip.
Other Facilities (exclud.
thential dryer)
Total Installed Capital
Cost per ton-hr. input
1978 Operation and
Maintenance (excluding
thermal dryer)
1978 0 & iM Cost per ton
of clean coal
SI.2 million
S2.6 million
S3.8 million
$17,200
$10.4 million
3.06
ITAR
Estimated Costs (mid-1978)
Heavy media plant cleaning
600 TPH; 2-stage heavy
media cyclone; fines
cleaning by hydrocyclones;
no thermal dryers.
S2.1 million
$2.1 million
$3.8 million
$21,700
$6.3 million
$4.33
457
-------
TABLE 4-41. COST COMPARISON WITH LEVEL 4, HEAVY MEDIA PLANT
USIN3 LOW SULFUR EASTERN COAL150'
Parameter
(Plant Description)
Hof j&nan Muntner
Actual Plant Costs
(mid-1977 $)
Heavy media process cleaning
600 TPH; Heavy media vessel
for coarse separation; heavy
media cyclone for middlings
separation; flotation cells
for fine coal cleaning;
thermal dryers.
ITAR Estimated
Cost (mid-1978 $)
Heavy Media process
cleaning 600 TPH;
heavy media vessel for
coarse coal; heavy media
cyclone for middlings;
hydrccyclones for fine
coal dewatering; no_
thermal dryer.
Raw Goal Handling Equipment
Preparation Plant Equipment
Miscellaneous Equipment
(excludes thermal dryer)
1978 Total installed capital
cost per ton-hr. input
(excludes thermal dryer)
1978 Operation and Maintenance
(excluding thermal dryer)
1978 O&M per ton of clean coal
$1.0 million
$1.4 million
$2.9 million
$15,500
$5.2 million
$4.54
$2.1 million
$1.9 million
$2.9'million
$19,100
$5.3 million
$3.14
458
-------
4.3 COST SUMMARY
Section 4.0 has presented the cost of complying with emission control
levels for industrial boilers using naturally occurring or cleaned coal. The
costs were found to be a combination of four costs: raw coal costs,
cleaning/handling charges, transportation, and in-plant preparation and
disposal. The raw coal costs are a function of the coal quality with
respect to heating value, ash content, and sulfur content. The cleaning
charges used in this ITAR are based on engineering estimates of cleaning
plant operating costs. Boiler operator costs were assumed to be those
presented by PEDCo Environmental with modifications made to fuel and
waste disposal costs. In-plant preparation and disposal costs are
primarily a function of heating value and ash content of the coal. Cleaned
coal can reduce boiler size, coal handling throughput needs, and maintenance
requirements. The decreased capital and operating costs associated with
these reduced requirements are not included in this ITAR. However, the
decrease in operating costs associated with less ash disposal is included.
Transportation costs were excluded from this analysis, although trans-
portation has a major impact on which coal type is used. Transportation
cost examples were presented in Section 4.1.1.5. A comparison of Tables
4-4 and 4-19 with Table 4-6 shows that transportation costs are of the
same order of magnitude as raw and cleaned coal costs. Of special note
is that the cost of transporting western coal to eastern markets is in the
range of $15-24/kkg, while cleaning costs are only $3-5/kkg. From a cost
standpoint it appears that cleaning local eastern and midwestern coals
would be preferable to transporting western coals to eastern markets.
This assumes, of course, that high sulfur coals can be cleaned to acceptable
levels to meet environmental constraints.
The BSER operating cost for each industrial boiler size and reference
coal type at various emission standard levels is presented in Table 4-42.
Ch a $/MWh basis, the costs for each coal type and reference boiler are
within 30 percent of one another and in most cases the cost differential
is less than 10 percent. This further accentuates the fact that the BSER
depends heavily on transportation costs and therefore on the location of
the boiler.
459
-------
TRBLE 4-42. COST SIMMARY TABLE - BSER
Cost to industxial boiler operator is the combined cost of raw coal plus
cleaning plus transportation plus toiler O&M. However, since the boiler
location has not been specified for this study, transportation costs are
excluded. Also particulate control costs (both capital and operating) are
not included. It is our understanding that these costs will be included in
future studies.
Boiler Size/
8.8
22
44
58.6
117.2
Boiler Size/
m
8.8
22
44
58.6
117.2
[Costs are in S/H*(t) ]
High Sulfur Eastern Coal
Emission Control Level (ng
Uncontrolled 1290
21.17
16.59
13.56
13.95
12.79
21.43
16.83
14.37
14.97
13.81
Low Sulfur
1075
21.43
16.83
14.37
14.97
13.81
Eastern
860
22.17
17.65
15,11
15.72
14.56
i Coal
Emission Control Level (ng
S02/J)
645
. 22.17
17.65
15.11
15.72
14.56
SCVJ)
516
26.19
21.61
19.13
19.74
18.57
tticontrolled 1290
1075
860
645
516
20.48 20.48 20*. 48
16.17 16.17 16.17
13.50 13.50 13.50
13.91 13.91 13.91
12.86 12.86 12.86
low Sulfur Western Coal
OCC
20.48
16.17
13.50
13.91
12.86
21.11
16.80
14.34
14.83
13.78
21. 11
16.80
14.34
14.83
13.78
21.79
17.48
15.02
15.51
14.46
Ihe costs for low sulfur western coal as a BSER are relevant for emission
control levels greater than 450 ng S(>>/J:
Boiler Size
8.8
22
44
56.8
117.2
thccntrolled
21.39
16.81
13.74
14.10
12.95
Controlled
21.76
17.18
14.71
15.13
14.15
460
-------
SECTICN 4
REFERENCES
1. Investigaticn of Railroad Freight Structured Coal, Interstate
Comerce Commission, December 1974. pp. 137-138.
2. Regional Energy System for the Planning and Optimization of National
Scenarios. "Final Report, Clean Coal Energy: Source-to-Use Economics
Project", ERDA-76-109, June 1976, Page 101.
3. Larry Broz (Acurex Corp.) Memo of October 23, 1978. Subject:
"Industrial Boiler Project," PEDCo. Sec. 4.0, "Cost of New
Boilers" for EPA/OAQPS Control Costs, pp. 4-11, 4-22, 4-31,
4-43, 4-46, 4-52, 4-55.
4. U.S. Department of Energy "An Engineering Economic Analysis of
Coal Preparation Plant Operations and Costs" Prepared by
Ifoffman-Munter Corp., July, 1978. pp. 132-133.
5. Denver Equipment Division, Joy Manufacturing Co. "Classification" and Separa-
tion Equipment", Draft Rpt, EPA Contract 68-02-2199, December 1977.
6. Denver Equipment Division, Joy Manufacturing Co. "Compilation of Existing
Data on Coal Cleaning Unit Cperatins, Draft Rpt, 68-02-2199, Dec. 1977.
7. Denver Equipment Division, Joy Manufacturing Co. "Performance Characteriza-
tion of Coal Preparation Equipment" Draft Report, EPA Contract
68-02-2199, January, 1978.
8. Denver Equipment Division, Joy Manufacturing Co. "Current Process
Technology for: Fine Coal Dewatering, Drying and Transportation" Draft
Report, EPA.Contract 68-02-2199, December, 1977.
9. Op. Cit., reference 4.
10. Argonne National Laboratory "Coal Preparation and Cleaning Assess-
ment Study". Prepared by Bechtel Corporation ANL/ECT-3, Appendix A,
Part 1, 1977.
11. Gibbs and Hill, Inc. "Costs for Levels of Coal Preparation".
Electric Light & Power, January 1977.
12' OP* Cit., reference 3.
13. Op. Cit., reference 10, p. 425.
14. Op. Cit., reference 4,.pp. 129-133.
15. Larry Broz (Acurex Corp.)* Memo of October 5, 1978. Subject:
"Economic Basis for ITAR Section IV, Control Costs." Table 4-3.
461
-------
16. Op. Cit., reference 10.
17. Ibid., p. 428.
18. Op. Cit., reference 15, Table 3-3.
19. Ibid.
20. Op. Cit., reference 10, p. 428.
21. Ibid., p. 429.
22. Ibid., p. 430.
23. Versar, Inc., "Assessment of Cbal Cleaning 'technology: An Evaluation
of Chemical Coal Cleaning Processes". EPA-600/7-78-173a. August 1978.
24. Op. Cit., reference 3.
25. Ibid.
26. Op. Cit., reference 15, Table 3-3.
27. Op. Cit., reference 23.
28. Op. Cit., reference 15, Table 3-3.
29. Op. Cit., reference 23.
30. Op. Cit., reference 23.
31. U.S. Environmental Protection Agency Industrial Environmental Research
Laboratory, Research Triangle Park. "Meyers Process Developrrent for
Chemical Desulfurization of Coal". EPA-600/2-76-143a, p. 223.
32. "Economic Indicators CE Plant Cost Index" Chemical Engineering,
October 1978.
33. p£. Cit., Reference 30.
34. C£. Cit., Reference 15, Table 3-3.
35. Ibid.
36. Op. Cit., Reference 33.
462
-------
37. Ibid.
38. Ibid.
39. Op. Cit., reference 3.
40. Ibid.
41. Op. Cit., reference 4.
42. Op. Cit., reference 5.
43. Op. Cit., reference 6.
44. Op. Cit., reference 7.
45. Op. Cit., reference 8.
46- OP- Cit., reference 32.
47. Coal Outlook, July 19, 1978.
48. Op. Cit., reference 4.
49. Ibid., pp. 265-283.
50. Ibid., pp. 232-247.
463
-------
SECTION 5.0
ENERGY IMPACT OF CANDIDATES FOR
BEST SYSTEM OF EMISSION REDUCTION
The purpose of this energy impacts section is to quantify and compare
the energy requirements of the control technologies previously identified
as Best Systems of Emission Reduction (BSER). The first portion of this
section introduces the various energy uses or savings associated with each
BSER. Where possible, these uses are quantified. In the second portion,
the energy quantities are combined to characterize the energy usage for
each BSER. Subsequent portions briefly discuss the potential for energy
savings from each BSER, the factors which effect energy use by modified/
reconstructed boilers, and the impacts on the BSER of government legislation
which mandates fuel switching.
5.1 INTRODUCTION
In this section we compare the levels of energy consumed in two systems
of coal used for industrial boilers—naturally occurring low-sulfur coals
and cleaned coals.
The major energy-using activities considered are: transportation of
coal, processing at mine mouth, coal cleaning, and postcombustion fly ash
removal.
5.1.1 Energy Involved in Transporting Coal
Naturally Occurring Low Sulfur Coal—
The energy required to transport coal (as a fraction of the combustion
energy in the cor.1) depends on the distance between origin and destination,
the available routes, the mode of transportation, and the heating value of
the delivered coal.
Table 5-1 presents estimated distances of transportation routes be-
tween the supply centers of seven coals and six industrial destinations. The
464
-------
Table 5-1. DISTANCES, BV MODE, BfclWEtU 'HE ORIGINS OF SUPPLY GOALS AND MSTINATICNS
Km (mi)
Destination
Austin, Tx.
IlarrisLurg, Pa.
Colunbus, Oti.
Baton Rouge, La.
Sacramento, Ca.
Springfield, 11.
Made
Water
Kail
Total
Mater
Rail
Total
Hater
Rail
Total
Water
Rail
Itotal
Water
Rail
•total
Water
Rail
•total
Origin
Low-Sulfur Coals
Gillette, Wy.
0 (0)
2440 (1510)
2440 (1510)
1590 (990)
2050 (1270)
3640 (2260)
1340 (830)
1770 (1100)
3110 (1930)
14BO (920)
1960 (1220)
3440 (2140)
0 (0)
2540 (1580)
2540 (1580)
0 (0)
2120 (1320)
2120 (1320)
Itock Springs, Uy.
0 (0)
2240 (1400)
2240 (1400)
1690 (1180)
2450 (1530)
4340 (2710)
1140 (700)
2250 (1400)
3390 (2100)
1480 (900)
2060 (1280)
4540 (2100)
0 (0)
1420 (880)
1420 (880)
0 (0)
2220 (1380)
2220 (1380)
Gallup, N.M.
0 (0)
1700 (1105)
1780 (1105)
1890 (1190)
2340 (1500)
4230 (2760)
1140 (700)
2330 (1450)
3470 (2150)
1390 (860)
1500 (930)
2890 (1790)
0 (0)
1620 (1005)
1620 (1005)
0 (0)
2300 (1430)
2300 (1430)
Wliliston, M.D.
0 (0)
2630 (1630)
2630 (1630)
1590 (980)
1500 (930)
3090 (1920)
1340 (830)
1220 (760)
2560 (1590)
2520 (1570)
960 (600)
3480 (2170)
0 (0)
2620 (1630)
2620 (1630)
1040 (650)
1)30 (700)
2170 (1350)
Uuclianan, Va.
2420 (1500)
1050 (650)
3470 (2150)
0 (0)
470 (290)
470 (290)
0 (0)
660 (410)
660 (410)
2420 (1500)
340 (200)
3760 (1710)
1560 (970)
3570 (2220)
4130 (3190)
1260 (700)
500 (310)
1760 (1090)
Las An inns, Co.
0 (0)
1980 (1230)
1980 (1230)
2480 (1540)
1220 (760)
3700 (2300)
1720 (1070)
1010 (630)
2730 (1700)
1390 (860)
1080 (670)
2470 (1530)
0 (0)
2310 (1430)
2310 (1430)
590 (330)
980 (610)
1570 (980)
Ili
-------
routing, which includes the two major transportation modes—rail and water—
gives preference to the water mode where possible, since it involves less
energy and less cost than does the rail mode.
The energy required to transport low-sulfur coals, physically-cleaned
coals, and chemically-cleaned coals to the reference destinations is present-
ed in Tables 5-2, 5-3, and 5-4, respectively, as a fraction of the combustible
energy in the delivered coal. The values are based upon the heating values of
the coals (see Section 3.2.2), the routed distances on rail and water (see
Table 5-1), and the average values of 2.62 x 10s Joules per kkg-km (366 BTU
per ton-mile) by rail, and 2,12 x 105 Joules per kkg-km (296 BTU per ton-mile)
by barge, values which include energy consumed in hauling and in loading and
unloading operations.
Table 5-2, which presents values for the six representative low^sulfur
coals (unprocessed), indicates a range of over an order-of-magnitude in the
computed values of transportation-energy consumption, expressed as a percen-
tage of the energy in the delivered coal. For example, transporting the
low-sulfur coal from Buchanan, Virginia to Harrisburg, Pennsylvania consumes
energy equal to about 0.4 percent of the coal's energy, while transporting
lignite from Williston, North Dakota to Baton Rouge, Louisiana consumes
energy equal to almost 5.0 percent of the combustible energy in the coal.
Similarly, for physical and chemical coal cleaning, the range of values
of transportation energy as a percentage of the energy in the delivered coal,
is somewhat greater than an order-of-magnitude, as shown in Tables 5-3 and
5-4.
Transportation Energy Consumed by BSER—
This subsection focuses upon the energy consumed during the transporta-
tion of the three reference coals selected in Section 3.0. The matrix in
Table 5-5 suimarizes the "Best System of SO2 Emission Reduction," which
permits compL anoe with four alternative SO2 emission control levels when
applied to the riiree coals.
A summary of the values of the energy consumed during transportation
using the Best Systems of Emission Reduction is displayed in Table 5-6.
For some demand centers such as Austin, Texas, tiie energy consumed during
transportation is approximately the same (i.e., about 2.0 to 2.5 percent)
466
-------
Table 5-2. 'HIE ENERGY CONSUMED IN TRANSPORTING DOW-SULFUR GOAL TO INDUSTOIAL DEMAND CENTERS
AS A PERCENTAGE OF THE COMBUSTIBLE ENERCT IN THE DELIVERED
(Origin
Destination Buchanan, Va.
Austin, TX
Ilarrisbiirg, PA
Cnluntais, Oil
liaton Jt>iige, I A
Sacrnnei ito , CA
Springfield, 11,
2.51%
0.39
0.55
1.91
4.04
1.23
Las Aniinas, Co.
2.00%
3.25
2.42
2.22
2.32
1.47
Gillette, Wy.
3.26%
4.46
3.02
4.32
3.40
2.84
Rock Springs, Wy
2.22%
3.94
3.13
3.22
1.40
2.22
Gallup, N.M.
2.02%
4.62
3.69
2.97
1.84
2.62
Willisbon, N.D.
4.27%
4.53
3.75
4. 89
4.26
3.20
Values based upon (1) heating values of the coals (see section 3.2.2} (2) routed distances by railroad and
barge (see Table 5-1) , .and (.3) energy consumption rates of 2.62 x 105 JAkq-km bv railroad and 2.12 x 105JAka-km
by harye.
-------
Table 5-3. THE ENERGY CONSUMED IN TRANSPORTING SELECTED
PHYSICALLY CLEANED COALS TO INDUSTRIAL DE-
MAND CENTERS AS A PERCENTAGE OF THE COMBUSTIBLE
ENERGY IN THE DELIVERED COAL""
Destination
Austin, TX
Harrisburg, PA
Columbus, OH
Baton Rouge, LA
Sacramento r CA
Springfield, IL
Origin of
and
Low-S Eastern
(Buchanan, VA)
PCC Level 4
2.18%
0.34
0.48
1.66
3.51
1.07
Physically Cleaned Coals
a
Level of Cleaning
High-S Eastern
(Butler, PA)
PCC,Level 5
MiadllJiqs
2.63%
0.40
0.64
2.00
4.23
1.54
PCC Level 5
Deer> Cleaned
2.59%
0.39
0.63
1.97
4.17
1.51
t
Values based upon (1) heating values of the coals (see section 3.2.2) ,
(2) routed distances by railroad and barge (see Table 5-1), and (3) energy
consumption rates of 2.62 x 105 J/kkg-km by railroad and 2.12 x 105 J
by barge.
The levels of PX correspond to those described in section 3.2.1.2.
468
-------
Table 5-4.
THE ENERGY CONSUMED IN TRANSPORTING A
CHEI£ECAIiLY-CLEANED COAL-TO INDUSTRIAL
DEMAND CENTERS AS A PERCENTAGE OF THE
COMBUSTIBLE ENERGY IN THE DELIVERED COATv
Destination
Austin, TX
Harrisburg, PA
Columbus, OH
Baton Rouge, LA
Sacramento, CA
Springfield, IL
High-S Eastern
(Butler, PA)
CCC Process0
Gravichem
2.61
0.39
0*64
1.99
4,21
Io52
ERDA
2.85
Oo43
0,69
2.17
4359
1066
t
Values based upon (1) heating values of the coals (see section
3.2.2), (2) routed distances by railroad and barge (see
Table 3.2-3), and (3) energy consumption rates of 2.62 x 105 J/kkg-km
by railroad and 2.12 x 10 5 J/kkg-km by barge.
The chemical coal cleaning processes are described in section 3.2.1.3.
469
-------
TABLE 5-5. BEST SYSTEM OF EMISSION REDUCTION FOR THREE CANDIDATE COALS
AND FIVE SO2 EMISSION CONTROL LEVELS
Coal
High Sulfur
Eastern
Low Sulfur
Eastern
Low Sulfur
Western
SO2 Emission Levels
ng S02/J (ltyS02/l06 BTU)
1,290 (3.0)
PCC level 5
Middling
Raw Coal
Raw Coal
l,075(2.r)
PCC level
5
Middling
Raw Coal
Raw Coal
860 (2.0)
PCC level 5
Deep Cleaned
Raw Coal
Rav Coal
645 (1.5)
PCC level 5
Deep Cleaned
PCC level 4
Raw Coal
516 (1.2)
CCC: ERDA
PCC level 4
CCC Gravichen
Raw Coal
470
-------
TABLE 5-6. ENERGY CONSUMED DURING TRANSPORTATION WHEN THE "BEST SYSTEM OF
EMISSION REDUCTION" IS APPLIED TO THREE COALS SELECTED AS
CANDIDATES FOR COAL CLEANING AS A PERCENTAGE OF THE COMBUSTION
ENERGY OF THE DELIVERED COAL
Emission Level
ng S02/J
BTU)
Destination
Coal Type °°
1,290 (3.0) 860 (2.0) 645 (1.5) 516 (1.2)
Austin, TX
High-S Eastern
Low-S Eastern
Low-S Western
2.63%
2.51
2.00
2.59%
2.51
2.00
2.59%
2.18
2.00
2.85%
2.18
2.00
Harrisburg, PA
Golunbus, OH
High-S Eastern
Low-S Eastern
Low-S Western
High-S Eastern
Low-S Eastern
Low-S Western
Baton Rouge, LA High-S Eastern
Low-S Eastern
Low-S Western
Sacramento, CA
High-S Eastern
Low-S Eastern
Low-S Western
Springfield, IL High-S Eastern
Low-S Eastern
Low-S Western
0.40
0.39
3.25
0.64
0.55
2.42
2.
1.
2.
00
91
22
4.23
4.
2.
1.
1.
04
32
54
23
1.47
0.39
0.39
3.25
0.63
0.55
2.42
97
,91
,22
4.17
,04
.32
1.51
1.23
1.47
0.39
0.34
3.25
0.63
0.48
2.42
1.97
1.66
2.22
4.17
3.51
2.32
1.51
1.07
1.47
0.43
0.34
3.25
0.69
0.48
2.42
2.17
1.66
2.22
4.59
3.51
2.32
1.
1.
66
07
1.47
«> These coal types are characterized in Section 3.2.2. The high sulfur
eastern coal originates at Butler, PA., the low sulfur eastern coal
at Buchanan, VA., the low sulfur western coal at Las Animas, CO.
471
-------
regardless of the selected BSER. For other industrial centers, such as
Harrisburg, PA., the range of values in transportation energy may differ by
an order of magnitude (i.e., fron about 0.3 to 3.0 percent).
The difference between the energy consumed in transporting raw coals
and the energy used in transporting cleaned coals reflects the net energy
enhancement of the coals resulting from the removal of ash during the
cleaning process. Energy enhancement allows less coal (per unit weight)
to satisfy boiler input heat requirements. The following percentages of
coal-energy enhancement were used:
Ooal Cleaning Process kJAg Enhancement (%)
POC: Level 5 Middlings 13.0
PCC: Level 5 Deep Cleaned 15.0
CCC: Gravichem 14.0
OOC: EKDA. 4.4
5.1.2 Energy Elements for a Low Sulfur Ooal Control System
The major energy elements involved with providing low sulfur coal to
industrial boilers is the use of energy during transportation and during
handling at the mine and industrial boiler.
The energy used for breakers at the mine is approximately 290 KW -
based on a 7,250 metric ton/day plant. This value represents the energy
utilized to reduce run-of-mine (KOM) coal to sizes acceptable for further
processing or to satisfy the demand for specific top sizes. Breaking coal
to a relatively homogeneous size range helps accomplish efficient coal
handling and combustion.
5.1.3 Energy Usage by Physical Ooal Cleaning Processes
5.1.3.1 Total Energy Use of PCC Plant Control System—
Because of the nature of physical coal cleaning most processes
involve merely sizing and washing and are not energy intensive. There
are no increased temperature or pressure requirements as would be required
of chemical coal cleaning. Instead the operations which use significant
amounts of energy are pulverizing, dewatering and thermal drying. Of these,
472
-------
pulverizing and dewatering require electrical energy while thermal drying
requires fuel. Pulverizing systems utilize electrical energy for crashers
and grinders. As is indicated by Table 5- 7 the chosen Best Systems for
Emission Reduction utilise 6.2 kJ/kg for a Level 4 plant and 15.5 kJ/kg
for a Level 5 plant for pulverizing. For higher levels of cleaning more
grinding and crusliing are performed than for lower levels.
Dewatering systems require electrical energy for units such as
centrifuges, vacuum filters and cyclones. Table 5-7 shows energy usages
for dewatering as 5.3 kJ/kg of product for Level 4 and 14.2 kJ/kg of
product for Level 5. The increased handling in higher levels of cleaning
means a proportionate increase in size of the dewatering systems.
Electrical energy is also used for motors and pumps as well as for
separation devices such as heavy media vessels and froth flotation. In
addition/ coal prepared for an industrial boiler must as a last step be
screened or agglomerated to meet boiler specifications. This is a specific
electrical energy requirement when preparing coals for industrial boilers.
As shown in Table 5-7 the total energy usage for the chosen PCC best
systems are 18.3 kJ/kg of product for Level 4 and 50.7 kJ/kg of product for
Level 5. The primary contributors to these usages are pumps, dewatering units
and pulverizing units.
For a typical physical ooal cleaning plant the last step in moisture
removal is thermal drying. Hot air for drying is produced usually by
burning cleaned ooal but the fuel may also be oil. The chosen best systems
did not include thermal drying due to the difficulty in meeting control
levels. However, for a typical physical ooal cleaning plant thermal
drying represents the most energy intensive operation.
5.1.3.2 Energy Content Rejection and Enhancement—
The raw ooal feed into a physical ooal cleaning plant has a specific
energy content. In processing, this energy content is split and appears in
473
-------
TABLE 5-7 ENERGY ELEMENTS FOR "REST"
PHYSICAL COAL CLEANING SYSTEMS ' 3 '
Coal Type
High Sulfur
Eastern
Low Sulfur
Eastern
Best System
of Emission
Beduction (PCC)
PCC - Level 5
"deep cleaned"
coal
PCC - Level 5
"middlings"
PCC - Level 4
Electrical
Energy for
Pulverizing
kJAg
(BTU/lb) Product
15.5
(6.6)
14.4
(6.17)
6.2
(2.7)
Electrical
Energy for
Dewatering
kJAg
(BTO/lb)
14.2
(6.1)
12.6
(5.4)
5.3
(2.3)
Miscellaneous
Energy Users
kJAg
(BTU/lb)
21.0
(9.0)
18.4
(7.9)
6.8
(2.9)
Total
Energy
for Coal
Preparation
kJAg
(BTU/lb)
50.7
(21.7)
45.4
(19.5)
18.3
(7.9)
-------
the refuse as well as the cleaned coal product. Table 5-8 indicates the
energy content of refuse and product for the five levels of physical coal
cleaning using the high sulfur eastern coal as input.
As indicated by the table, energy content enhancement of the product
increases with increasing levels of cleaning. For example, a Level 2 plant
yields 28,917 kJAg Of product, and Level 3 plant yields 30,278 kJAg of
product. Three values represent an 8 percent and 13 percent increase
(enhancement) of the energy content of the coal, respectively.
The rejection of useful energy in refuse represents the major energy
consumer in physical coal cleaning. Usable energy is lost to the refuse
by pyrite rejection in order to meet pollution control levels. Since
Level 1 physical coal cleaning only involves crushing and sizing, little or
no energy content is lost to refuse. However, for the other levels consid-
erable energy loss exists. On the other hand, higher levels of cleaning
increase enhancement and decrease reject energy content, making higher levels
desirable relative to energy content of the fuel.
5.1.4 Energy Usage by Chemical Coal Gleaning
5.1.4.1 Energy Usage for the Cleaning Process—
The primary energy users for physical coal cleaning, pulverizing,
dewatering and thermal drying, are also significant users of energy in
chemical coal cleaning. Pulverizing is an integral part of the chemical
coal cleaning system and is accomplished by crushers, grinders and
pulverizers. These units all require electrical energy, but due to varia-
tions in coal size requirements, the electrical energy expended for
pulverizing may vary from system to system.
Dewatering operations utilize electrical energy in such units as
vacuum filters, centrifuges and cyclones.
475
-------
TABLE 5-8 ENERGY CONTENT REJECTION AND ENHANCEMENT
IN PHYSICAL COM, CLEANING
Coal
Type
High
Sulfur
Level of
Cleaning
1
2
3
4
5
ROM Coal
Energy
Content*
kJAg
(BTU/lb)
26,716
(11,486)
26,716
(11,486)
26,716
(11,486)
26,716
(11,486)
26,716
(11,486)
Refuse
Energy
Content*
kJAg
(BTU/lb)
0
(0)
14,249
(6,126)
16,030
(6,892)
11,132
(4,786)
9,716
(4,177)
Clean Coal
Energy
Content*
kJAg
(BTU/lb)
27,260
(11,720)
28,917
(12,432)
30,278
(13,017)
33,397
(14,358)
31,513* *
(13,548)**
%
Energy
Recovery
100
92
85
87.5
92
*As-Reosived Basis.
** Heating value of combined product. Level 5 will generate two
product streams, a deep cleaned stream and a middling proJuct.
476
-------
Drying is accomplished with heat produced in a furnace. Usually,
coal produced by the cleaning process is used for fuel although oil may
also be used. This fuel use represents a major energy expenditure.
Among energy requirements for chemical coal cleaning,which do not
exist for physical coal cleaning, are compressors for elevated pressure
in reactors (electrical energy), heaters for reactors (fuel energy) and
motors for mixers (electrical energy). In addition, because of the
differences in chemical coal cleaning systems, there exist electrical
energy requirements which are unique to individual systems. An example
is the oxygen-nitrogen generation plant of the TRW Meyer's Process.
It would be appropriate to give energy usage values as was done for
physical coal cleaning for units and processes in chemical coal cleaning.
However, because chemical coal cleaning is still in the developmental stage,
estimates for unit energy usage of full scale operations are not as readily
attainable as for physical coal cleaning. Values for EEDA and Gravichem
have been calculated for the entire process. The 209 kJAg of product ex-
pended by the EKDA process (Table 5-10) includes all elements discussed pre-
viously with major energy usage attributed to elevated temperature and
pressure requirements in the reactors. The 61 kJAg of product expended by
the Gravichem process is largely due to electrical energy requirements of
the oxygen-nitrogen generation plant, as well as pulverizing, dewatering and-
thermal drying previously discussed. Note that 20 percent (12 kJAg)
of the energy usage is due to the physical coal cleaning portion of this
process.
5.1.4.2 Energy Content Rejection and Enhancement—
The removal of sulfur and coal diluents by chemical coal cleaning
increases the energy content of the product coal. The actual amount of up-
grading varies with the process and coal used. Table 5-9 shows the energy
content of two reference coals after enhancement by two chemical coal clean-
ing processes. Far the EKDA process only a 4 percent upgrading of energy
content is achieved, whereas the Gravichem process yields a significantly
higher upgrading of 14 percent.
477
-------
TABLE 5-9. ENERGY BALANCE FOR CHEMICALLY CLEANED COAL
Coal Type
High Sulfur
Eastern
Low Sulfur
Eastern
CCC Process
ERDA
Gravichem
RDM Coal
Energy
Content
kJAg
(BTO/lb)
26,772
(11,510)
31,685
(13,622)
Cleaned Coal
Energy Content
kJAg
(BTU/3JD)
28,507
(12,256)
36,132
(15,534)
Refuse
Energy
Content
kJAg
(BTU/lb)
16,031
(6,892)
14,116
(6,069)
% Energy
Recovery
94
91
CO
-------
Energy rejected in the refuse represents a major energy loss in
chemical coal cleaning. As can be seen in Table 5-9, this energy loss is
similar for both the processes chosen as best systems of emission reduction.
5.1.5 Energy Usage by the Candidate BSERs, External to the Boiler
Table 5-10 presents values for total energy usage by the chosen BSERs.
These data vail be used in Section 5.2 to determine the energy impacts
on the reference boilers. Also presented in Table 5-10 are energy
values for energy content rejection and enhancement. Overall energy
content recovery consists of three energy elements, (1) energy for
preparation, (2) energy content rejection, and (3) energy content
enhancement.
5.1.6 Energy Differences Between Uncontrolled Boilers and Various Levels of
Control
Energy usage varies with the level of control desired. For an
uncontrolled boiler, energy is required only for transportation of the
mined coal to the boiler and for handling of the coal at the boiler.
5.1.6.1 Energy Consunption/Decrease over Uncontrolled Boilers
Using Low Sulfur Coal—
The major difference between energy consumed by uncontrolled and
controlled boilers utilizing low sulfur coal is the energy required for
particulate control.
In Section 5.2.1 we compute the electrical energy consumed in removing
particulates from the five gas following the combustion of selected cleaned
and uncleaned coals in five reference boilers. The control devices are
(1) electrostatic precipitators and (2) fabric filters.
5.1. 6.2 Energy Savings of PCC and CCC over Uncontrolled Boilers—
When physically or chemically cleaned coal is used to meet specified
control levels/ the energy expended for transportation and handling is
less than for uncleaned coal. This decrease is due to the removal in the
cleaning process of those constituents having no energy value. Therefore
less energy is expended for transporting and handling the same number of
Joules in cleaned coal than in uncleaned coal.
479
-------
Table S'-IO. Energy Elements for Chosen Best Systems of Emission Reduction
8-
Coal Type
High Sulfur
Eastern
Lew Sulfur
Eastern
Lew Sulfur
Western
Level of
Control
ng SOj/J
lib SOa/105 BTU
Moderate
1,290 (3.0)
Opt. Moderate
B60 (2.0) or
Intermediate
645 (1.5)
Stringent
516 (1.2)
Moderate
1,290 (3.0)
or
Opt. Moderate
860 (2.01
Intermediate
645 (1.5)
Stringent
516 (1.2)
Moderate
1,290 <3.0)
Opt. Moderate
860 (2.0) or
Intermediate
C45 (1.5)
Strident
516 (1.2)
Beat System
of Emission
Reduction
PCC-Level 5
Middlings
PCC-Level 5
deep cleaned
coal
CCC-ERDA
Raw Coal
POC Level 4
POC Level 4
Gravichera
Raw Coal
Raw Coal
Raw Coal
Energy for*
Coal Preparation**
kJAg Cleaned Coal
(BIU/lb)
45.4
(19.5)
50.7
(21.7)
209
<89.9)
1.9
(0.8)
18.3
(7.9)
18.3
(7.9)
61
(26.2)
1.9
(0.8)
1.9
(O.B)
1.9
(0.8)
Refuse Energy
Content
kJAg
(Hnj/lb)
12,563
(5,401)
12,563
(5,401)
16,031
(6,892)
—
20,139
(8,658)
20,139
(8,658)
14,116
(6,069)
—
—
—
Clean Coal
Energy Content
JcJAg
(BTU/lb)
31,662
(13,612)
33,555
(14,426)
28,507
(12,256)
31,685
(13,622)
33,883
(14,567)
33,883
(14,567)
36,132
(15,534)
26,270
(11,294)
26,270
(11,294)
26,270
(11,294)
% Energy
Recovery
in Product
44.06
44.06
43.42
94.00
100.00
89.83
89.83
91
100.00
100.00
100.00
* Usually this would be fuel as well as electrical energy. For the chosen PCC USER no
thermal dryers exist and this value is only electrical energy.
** Based on 8,000 TPD feed
-------
Not only are there energy usage advantages for transporting and
handling cleaned ooal, but these advantages become greater as the level of
cleaning increases. Thus a level 5 physically cleaned coal or a coal
cleaned by the ERDA process would meet a more stringent control level and
would require less energy expenditure for transportation and handling
than a less rigorously cleaned coal.
Energy used for handling ooal at the boiler site is also decreased
if cleaned coal is used. The most energy intensive part of handling is
grinding. Because beneficiated coal contains less mineral natter than raw
coal, less energy is required to grind beneficiated coal. In addition,
decreased hardness will increase the life of the grinder and cut down on
maintenance of the grinder.
A primary disadvantage of physical and chemical coal cleaning over
uncontrolled boilers is the loss to refuse of usable energy. In a boiler
using raw coal, there is no loss of available heating value. However, this
advantage of utilizing raw coal is lost when downtime and maintenance are
analyzed. Use of raw coal rather than cleaned coal increases the energy
input for maintenance and increases the downtime. Thus in the long term,
a boiler burning raw coal requires greater energy input due to handling
(7>
than a boiler using beneficiated coal.
As control levels become more stringent, the complexity and energy
requirements of coal cleaning circuits increase. However with greater
cleaning, the products become increasingly desirable for usage in boilers.
In addition to advantages already pointed out, the cleaned products require
less particulate control at the boiler site.
481
-------
5.2 ENERGY IMPACT OF CONTROLS FOR OOAL-FIRED BOILERS
This section presents the energy required to control particulates
and sulfur dioxide for each BSER or the representative boilers. Section
5.2.2 presents the energy consumption values using the standard format,
while Section 5.2.4 provides a conparison of the results. All values
presented are based upon new facilities.
5.2.1 Energy Consumed in Controlling Emissions of Particulates During
the Combustion of Selected Raw Low-Sulfur Coals and Cleaned Goals
this section presents the electrical energy requirements to control
particulates from coal-burning industrial boilers. The three reference
coals presented in Section 3.0, both raw and cleaned, are included in the
analyses. The analyses provide insight into how particulate control energy
consumption is affected by the removal of ash and sulfur during coal
cleaning. The energy used in fly ash removal may also be compared with
the energy consumed in transporting the seven sample coals to six selected
destinations (see Section 5.1.1), and the energy consumed in cleaning three
sample coals by means of several levels of physical and chemical coal
cleaning (see Section 5.2.2).
The energy requirements of a particulate-control system depends upon
the type of control system, characteristics of the coal feed, the applicable
emission control level for particulates, and certain parameters associated with
the boiler design and operation. The two major types of fly ash controls
considered are: electrostatic precipitators (ESP) and fabric filters.
The major relevant characteristics of the raw and cleaned coals used—
heating value, ash, and sulfur content—are listed in Table 5-11. The
emission control levels for particulates, which are based on EPA suggestions,
are presented in Table 5-12. Relevant parameters of the five reference
boilers—in/ut energy rate, flue gas flow rate, capacity factor, and the
quantity of fly ash formed during combustion as a percentage of coal ash—are
shown in Table 5-13.
482
-------
Table 5-11 SLTOJARY OF CHARACTERISTICS CF
KEFEREtvCE RAW AND CLEANED COALS
Parameter
High Sulfur
Eastern
Coal Type
Low Sulfur
Eastern
Low Sulfur
T-festem
Source
location (County) Butler, PA
Richanan, VA
Las Animas, CO
Raw Values
Ash %
Sulfur %
Heating Value
kJ/kg
(BTU/Ub)
PCC Values
Heating Value
kJ/kg
(BTU/lb)
CCC Values
Ash %
Sulfur %
Heating Value
23.90
3.45
26,772
(11,510)
10.38
1.18
31,685
(13,622)
24.81
0.59
26,270
(11,294)
Deep
Middlings Cleaned
Product Product
Ash %
Sulfur %
11.31
1.69
5.80
1.08
4.13
0.89
(BTU/lb)
31,662
(13,612)
ERDA
17.5%
0.73
27,903
(11,996)
33,555 33,883
(14,426) (14,567)
Gravichem
ERDA
3.30%
0.50
36,132
(15,534)
18.6%
0.25
27,437
(11,796)
483
-------
TABLE 5-12. PAKTICULATE AND S02 EMISSION OONTEDL LEVELS
Standard
Partica.il ate Emissions
SO2 Emissions
SIP
Moderate
Optional Moderate
Intermediate
Stringent
ng/J
258
108
108
43
13
(lb/106 B1U)
(0.6)
(0.25)
(0.25)
(0.1)
(0.03)
ng/J
1,075
1,290
860
645
516
(lb/106 BTU)
(2.5)
(3.0)
(2.0)
(1.5)
(1.2)
484
-------
TABLE 5-13. RELEVANT CHARACTERISTICS OF THE REFERENCE
COAL-FIRED INDUSTRIAL BOILERS
Boiler Type
Underfeed Stoker
Chain-Grate Stoker
Watertube Spreader
Stoker
Watertube Pulverized-
Coal Boiler
co Watertube Pulverized-
Cbal Boiler
Energy Input Rate
MW(t) (106 BttU/hr)
Flue-Gas Flow Rate <15)
Actual m3/min
(Actual f
Capacity Factor
Fly Ash as a
Percentage
of Coal Ash
8.8
22
43
59
118
(30)
(75)
(150)
(200)
(400)
350
900
1,760
2,040
4,080
(12,500)
(32,000)
(63,000)
(73,000)
(146,000)
60%
60
60
60
60
25%
25
65
80
80
-------
Electrical Energy Used by an Electrostatic Precipitator (ESP)
The required particulate collection efficiency is determined by the
allowable emission factor for parti culates, the ash content of the coal,
and the percentage of coal ash con-verted to fly ash (listed for each boiler
type in Table 5-13). Given a value for minimum collection efficiency,
the area of an ESP's collecting surface (and, consequently, the required
energy use) will increase as the sulfur content of the coal decreases.
This relationship is illustrated in Figure 5-1 , in which collection
efficiency is plotted against collection area for various values of the
sulfur percentage by weight in the coal. By choosing the necessary collection
area and knowing the flue gas flowrate, the required electrical energy is
computed as shown in Table 5-14.
The results of the calculations of the energy consumed by the ESP using
the selected coals and boilers are shown in Table 5-15. Values of energy
required by the ESP are presented as electrical energy (assumed to be 33
percent of the primary energy). In comparing the ESP energy—before and
after coal cleaning for the cleaned coals, we observe that:
• The high-sulfur eastern coal from Butler, Pa., requires more
ESP energy after cleaning; and
• For cleaned low sulfur eastern coal the amount of energy
required by the ESP is less than when raw coal is burned.
The electrical consumption by fabric filters is only a function of
flue gas flowrate and is basically independent of coal characteristics.
As a result the values presented by GCA Corporation, Section 5.0, Energy
(9)
Impact of Candidates for Best Emission Control Systems, Draft Report will
be used in this report. The energy consumption values are shown in Table
5-16
486
-------
Figure 5-1
Relotionship Between Collection Efficiency and ESP
Collecting Surface Area to Gas Flow Ratio
For Various Coal Sulfur Contents^1 °)
99.9
99.0
u
LU
Z
g
i—
u
d
u
90.0
80.0
70.0
60.0
100 200 300
AREA/IOOOCFM (ft2)
400
487
-------
Table 5-14 ALGORITHM FOR OOMOTING THE RATE OF ELECTRICM, .
ENERGY USED BY AN ELECTROSTATIC PRECIPHATORU '
00
00
Synfcgl
kW(e)
PP
Area
Pd
Flow Kate
k
er
e£
Area
x k x (Flow Rate)
ef
Wte symbols are explained below:
Description
ESP power constnption
Electric power required to activate the ESP plates
ESP collector area
Pressure drop
Flue gas flow rate
Electrical power to run fans
Transformer - rectifier efficiency
Fan efficiency
Units
KM
KW/ta2
m2
cm of water
m /tain
KW/{on water x
nr/tain)
Value Used
0.0215
See Figure 5-1
5.OB
See Table 5-13
0.00278
0.6
0.6
-------
TABLE 5-15. ESP REQUIREMENTS ON INDUSTRIAL BOILERS USING RAW
COAL VERSUS USING TIIE BEER COAL^"' '
-------
TABLE 5-16. ENERGY CONSUMED BY FABRIC FILTERS
COAL TYPE
High Sulfur low Sulfur low Sulfur
Boiler Type Eastern Eastern Vfestem
Underfeed Stoker 16.4 15.6 16.0
Chain Grate Stoker 41.2 38.4 40.0
Spreader Stoker 82.6 77.6 80.1
Pulvarized Goal (58.6M?}95.4 90.2 93.2
Pulverized Coal (118I«iT)190.8 180.4 186.4
(Values are in KW(e})
490
-------
5.2.2 Overall Energy Consunption
For each coal type, reference boiler, and level of emission control,
the energy consumption for the corresponding best system of emission
reduction is presented in Tables 5-17 to 5-31. In every case the best
system of emission reduction included an electrostatic precipitator.
Electrostatic precipitators (ESP) ware chosen because of their wide usage
and because the energy consumed by ESP is representative of energies
used for particulate control.
Tables 5-17 to 5-31 also present the control efficiency and type of
energy consumed for each best system. The actual energy consumption values
shown in the first column are the energy consumed per kilogram (pound)
of product. The second column represents the kilowatt usage which varies
with the boiler input. The boiler is assumed to operate at 100 percent
efficiency. To determine annual KWh, the KW should be multiplied by
5,256 hours (i.e. 60% capacity factor).
The total energy consumed at each level of control is a summation of
energy lost to refuse in the process (which takes into account heat content
enhancement of the product), energy required to process coal at the pre-
paration plant, and energy for particulate control. The percent increases
in energy over uncontrolled and SIP-controlled boilers are calculated as
indicated in a sample calculation shown in Table 5-32.
5.2.3 Level-of-Control Energy Graphs
Figures 5-2, 5-3, and 5-4, illustrate the energy consumed by four major
types of boilers to meet various emission control levels as presented
in Section 5.2.2. The three bar charts represent energy usage when burning
high sulfur eastern, low sulfur eastern, and low sulfur western coal.
These charts show an increase in the amount of energy consumed as emission
control levels become increasingly stringent.
Figure 5-3 shows that the energy required to meet the various control levels
greatly increases (over raw coal requirements) when using either physically
491
-------
TABUS 5-17 ENERGY USAGE OP "BEST" CONTROL, TECHNIQUES FOR 8.8 MW COAL-FIRED BOILERS
USING HIGH SULBUR EASTERN OQAL
to
SYSTEM
HIGH SULFUR EASTERN COAL**
S'iANDARD BOILERS
I'uel and
Ik.-at Input
IW (106BTU/hi)
8.8 (30)
28,842 kJAg
1.54% S
10.30% Ash
28,842 kJAq
1.54% S
10.30% Ash
30,533 kJ/kq
0.98% S
5.28% Ash
Type
Underfeed
Stoker
1YPE AND
LEVEL
CP CONTROL
SIP
PCC - IBVB! 5
Middling.
ESP.
MODERATE
PCC-Level 5
Micldlinq.
ESP.
Optional
Moderate
PCC-Level 5
Deep Cleaned
Coal
KSP
XXHRQL
CFFI-
IENCY+
(%)
58
71
58
88
75
75
ENERGY
TYPE
EMel0
Elec.
Elec.
Ibtal
Fuel0
Elec.
Elec.
Tota
Fuelu
Elec
Elec
Tota
ENEK5Y CXWSOMPTION
ENERGY CONSU1ED BY
CONTROL
J/Rg (BTUAb) W» (Themal )
4,568 (1,964)
45.4(19.5)
114.2(49.1)
4,727.6(2033)
4,568 (1,964)
45.4(19.5)
141.8(60.9)
4,755 (2,044)
4,568 (1,964)
50.7 (21.7)
139.1 (60.0)
4,758 (2,046)
1,392
14
34
1,440
1,392
14
43
1,449
1,314
15
40
1,369
IMPACTS
% INCREASE
IN ENERGY OVER
UNCONTROLLED
BOILER
16.3
16.4
15.4
% INCREASE
CN ENERGY OVER
IP-CONTROLLED
BOILER
N.A.
0.1%
(.7%)*
* Indicates a decrease
** Raw Coal Analysis: 3.45% S; 23.90% Ash; 26,772 kJ/kg
I'crcent Sulfur reduction in ng SO2/J and percent Ash reduction in ng ash/J
x Energy rejected to preparation plant refuse
-------
TABLE 5-17 ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FOR 8.8 tW COAL-FIRED BOILERS
USING HIC31 SULFUR EASTERN COAL (continued)
SYSTEM
HIGH SULFUR EASTEFN GOAL**
STANDARD BOILERS
fuel Input
y),T)33kJAg
.98% S
5.28% Ash
?.7,903kJAg
.73% S
20.74% Ash
Type
TYPE AND
LEVEL
OF CONTROL
INTERMEDIATE
PCC-Level 5
Deep Cleaned
Coal.
ESP,
STRINGENT
COC-EFOA.
ESP.
CONTROL
EFFI-
CIENCY
(%)
75
90
80
99
ENERGY
TYPE
a
Fuel
Flee.
Elec.
Total
n
Fuel
Elec.S;
Elec.
fata
ENERGY CONSUMPTION
ENERGY CONSUMED BY
CONTROL
•; JAg (BTU/lb ) KH (Therma 1)
4,568 (1,964)
50.7(21.7)
163.7 (70.4)
.&J82 iljaSlL
17«2 (766)
209 (89.9)
232.4 (99.9)
2.223 f955)
1,314
15
47
1 ^76
561
65
73
699
IMPACTS
% INCREASE
IN ENERGY OVER
UNCONTROLLED
BOILER
15.5
8.0
% INCREASE
pi ENERGY OVER
SIP-CONTROLLED
BOILER
(0.6%)*
(7.1%)*
* Indicates a decrease
** Raw Coal Analysis: 3.45% S; 23.90% Ash; 26,772 kJAg
,•._ t_ f~i. -i iT -. ,i -.f-.j_-l ^™ 4 w^ r-i*-i O^-. /T nr-i^ r-rfat"/^£»v\+- RoV»
•«- Percent Sulfxir reduction in ng S02/J and percent Ash reduction in ng ash/J
u Energy rejected to preparation plant refuse
-------
TAHLE 5-18. PNERGY USAOE OF "BEST" CONTROL TECHNIQUES FOR 22 MW COAL-
FIPED BOILERS USING HIGH SULFUR EASTEIW OOAL
fJYSIVM
HIGH SULFUR EASTEm COAL**
KTANivvKi) imiuwB
llcat and Fuel
Input
Mw
I,!:.VHI,
OF aWTUH.
sir
FCC-Level 5
Middling.
ESP.
MODERATE
POC-Level 5
Middling.
ESP.
Optional
Moderate
FCC- level 5
Deep Cleanec
Coal
ESP
ivrnor.
FFl-
•IKNCY''
' (*)
58
71
5B
88
75
75
NKFWY
TYPE
Ftiel0
Clec.
Elec.
Tbta
Fuel0
Elec.
Elec.
TtotaJ
Fuela
31ec
31ec
Total
EMF:im aiMSUMI'I'IUN
lONcinv unNsiJMJij) IJY
ux/noi,
kJA«(IW^/ll>) KW(Uionnal)
4,568 (1,964)
45.4(19.5)
117.0 <50.3J
4,731 (2,034)
4,568 (1,964)
45.4 (19.5)
1146.5 (63.0)
4,760 (2,046)
4.568 (1964)
50.7 (21.7)
141.9 (61.2)
4,761 (2,047)
3,479
34
89
3,603
3,479
34
111
3,624
3,287
36
102
3,425
1MPACIS
% INCREASF:
IN ENUHJY OVER
UNQWriDUJ'.'!)
UOIIJCI!
16.4%
16.5%
15.6
* INCIUSftSE
N I wnre;Y OVER
IP-UWIWUJO)
DOII£R
N.A.
0.1%
(0.7%)*
* Indicates a cbcrease
** Raw Coal Analysis: 3.45% S; 23.90% Ash; 26,772 kJAg
+ Percent sulfur reduction in ng 902/J and ,jcjj.-oant ash reduction in ng ash/J.
m Energy rejected to preparation plant refuse
-------
TABLE 5-18. ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FDR 22 MW COAL-
FIRED BOILERS USING HIGH SULFUR EASTERN (DAL {continued)
SYSTEM
HIGH SULBUR EASTERN GOAL**
STANDARD BOILERS
Fuel Input
1 30 ,533 kJAq
.98% S
5.28% Ash
27,903WAg
.73% S
20.74% Ash
TYPE
TYPE
AND
LEVEL
OF CONTROL
INTERMEDIATE
PCC-Level 5
Deep Cleaned
Coal.
ESP
STRINGENT
CCC-F3W.
ESP
CONTROL
EFFI-
CIENCY*
(%)
75
90
80
99.3
ENERGY
TYPE
F«ela
Elec.
Blec
Total
Fuel°
Elec.
B&
Tota
ENERGY CONSUMPTION
ENERGY CONSUMED BY
CONTPOL
kJAg
-------
TAitiJ-: s-19. INKI«;Y U;/M;K w "OK'iT" UMTIOI, 'miNiums: K>I< 44 m OOAL-
Fimi> mili,IKS usire HIGH SUUUR EBSOEFH GOAL
CTi
* Indicates a decrease
*« liaw Coal Analysis: 3.45* S; 23.90% Ash; 26,772 kJA?
I I'frounl sulfur reduction in IK| SO>./J and pnrocnt ash reduction in ng .isli/.J.
a Enerrjy rejected to preparation plant refuse
SYffHW
HIGH SUIfUR EAS1EWJ COAL**
S'ITO(IV\lil) IXI1IJ;|«
'.'•sat and Fuel
Input
MW (106BTUA.r)
44 (150)
21754TT«JAg
1.54% S
10.30% ash
28,842 kJAg
1.54% S
10.30% ash
30,533 kJAq
.98% S
5.28c asn
30,533 kJAg
.98* S
5.28% asli
27,903 kJAg
.73% S
20.74% ash
•JYIIi
Spreader
Stoker
TYPE
AND
U'S/lil.
OF OUN'I'WM.
SIP
PCC-Level 5
Middling.
ESP
MXERATE
Middling.
ESP
OPTIONAL
KCOfifiAft!
WC-Lavel 5
Deep Cleaned
Goal
ESP
INTERMEDIATE
PCr-Isvel 5
deep cleaned
coal
ESP
HTlUNUENi'
(XC-ERDA
ESP
UWHttl,
I^E'I-
JETJCY*"
(%)
58
89
58
95
75
90
75
96
80
99.7
OJEROY
TYPE
Fuel"
Elec.
Elec.
Ibtal
Fiwl01
Eloc.
Elec.
Total
n»ia
Elec.
Elec.
Ibtal
Puela
Elec.
Elec.
•total
FUBl™"
E£.r
Elec.
Ibtal
ENKRJY OONSDMITHJN
i-Nii:r«Y trwsiwra) UY
uxnwa,
JA'j(HTU/lb) KHttliemal)
4,568 (1,964)
45.4 (19.5)
147.2 (63.3)
4,761 (2,047)
4,568 (1,964)
45.4 (19.5)
184.3 (79.2)
4,798 (2,063)
4,568 (1,964)
50.7 (21.7)
162.8 (70.2)
4,781 (2,056)
4,568 (1,964)
50.7 (21.7)
208.3 (89.5)
4,827 (2,075)
1,782 (766)
209 (89.9)
238.1(102.4)
2,229 (958)
6,959
69
224
7,252
6,959
69
280
7,309
6,550
72
234
6,856
6,574
72
299
6,945
2,806
329
375
3,510
IMPACIS
* INCI«ASE
N ENRIVY OVER
UNOJNm.>I.IJ2l>
UOlltfR
16.5%
16.6%
15.6%
15.8%
8.0%
% INCREASE
N ENERGY OVER
ip-tntrmorua)
TOILER
H.A.
0.1%
(0.8%)*
(0.6)*
7.3%
-------
TAblJ'l !i--20.
I'NKUJY US/VCU <>f "I!!«T" UJNTIDI. WUINJQlti::: H)l( 58.6 MW OQAL-
MUMII l<)ll.l'UU.UI>
BDIURR
16.4%
16.5%
15.6%
15.7%
8.0%
% INCREASE
IN PNURm OVKR
SlP-CUTIHJUiiD
DOIUIR
N.A.
0.1%
(0.8%)*
(0.6%)*
(7.34)
* Indicates a decrease
** Raw Coal Analysis: 3.45% S; 23.90% Ash; 26,772 kJAg
+ I'orount sulfur reduction in ncj S()?/J and [x»rcent ash reduction in ng ash/.I,
a Energy rejected bo preparation plant refuse
-------
TABIi; 5-21 IWEHGx USAGE OF "BEST" COWITOL TECHNIQUES TOR 118 W COAL-FIRED BOILERS USING HIGH SULFUR EASTERN COAL
CO
SYSTEM
HIC3I SULFUR EASTERN COAL **
Standard Boiler
fuel and Heat
Input
.
-------
5-22
tmsixsr vsncy, OF "lu-sw1" crwmu. •nsaM.vf.KR FUR s.a
FIHED DniU5RS USING UCW SULFUR RASTOfN COM,
SYSIViM
LOW SULFUR EASTERN COAL**
STANDARD
Heat and Fuel
Input
W(105BTU/hr)
8,8 (30)
31,685 kJAg
1.18% S
10.38% ash
31,685 kJAg
1.18% S
10.38% ash
31,685 kJAq
1.18% S
10.38% ash
PCC
33,882 kJAg
0.89% S
4.1% ash
CCC
36,130 kJAg
0.64% S
3.1% ash
BOILERS
TYPE
Jhderfeed
Stoker
TYPE
AND
1JVEI,
OF aiN'mir,
SIP
Raw coal
ESP
MODERATE
Raw ooal
ESP
OPTIONAL
MDDERATE
Raw Caol
ESP
IN1ERMEDIA1E
PCC-Level 4
ESP
STRINGENT
COC-Gravichem
ESP
CONTROL
EFFI-
CIENCY^
<%)
0
68
0
87
0
87
30
86
50
94
ENERGY
TYPE
Else.
Sleo.
Total
Elec.
Elec.
Ibtal
Elec.
Elec.
Total
Fuelu
31ec.
Clec.
total
^ual11
ERF
51ec.
Total
ENERGY CUNSUMITION
ENERGY CONSUMED T?Y
OOMTim.
kJAg(BTO/lb) KW (tliennal)
1.9 (.8)
128.7 (55.3)
134.8 (57.9)
1.9 (.8)
163.3 (70.2)
169.4 (72.8)
1.9 (.8)
163.5 (70.5)
170 (73)
3,835 (1,649)
18.3 (7.9)
178 (76.5)
4,196 (1,733)
3,573 (1,536)
57.2 (24.5)
255.3 (109.8)
3,886 (1/570.3)
< 1
35
36
< 1
45
46
< 1
45
46
99^
4
46
1,045
' Bf>y
14
62
945
IMPACT?;
f, INCRF/iSE
IN l^ERGY OVER
UNOONTHOIJ.ED
BOtLER
0.4%
0.5%
0.5%
12.0%
10.7%
% INCRKASE
JN ENERCT OVER
RTP-OnNThOLlJKn
noirj5R
N.A.
o.n
0.1%
11.5%
10. 3%
** Raw Coal Analysis: 31,685 kJAg; 1.18% S; 10.38% ash
+ Percent sulfur reduction in ng HO7/J nnd poroant ash rcdurtion in nq nsh/J.
a Energy rejected to preparation plant refuse
-------
TABU: 5-23
ui
o
o
1JNERGY USAGE OF "BEST" CCHTTOL TECHNIQUES FDR 22 MW COAL-
FIHED BOILERS USING LOW SULFUR EASTERN COAL
SYSTEM
IOW SULPUR EASTERN GOAL**
STANCftRD BOILERS
lleat and Fuel
Input
WWao'BTO/hr)
22 (75)
31,685 kJA
-------
TAI1I.J?! 5-24. UNKRrW USAGE OF "lWfflM GCNTROI. TBC1WiQUF.fi FOR 44 W COAL-
FIKF.O nOlLERS USING IOW SULFUR EASTI3RN COAL
Ul
O
SYSTRM
ucw sut.ruR EASTERN COAL**
STANDARD
Heat 2nd Fuel
Input
WdO'B-IU/hr)
44 (150)
31,685 kJ/kg
1.18% S
10.38% ash
31,685 kJ/kg .
1.18% S
10.38% ash
31,685 kJ/kq
1.18* S
10.38% ash
PCC
33,882 kJ/kg
0.89% S
4.1% ash
CCC
36,130 kJAg
0.64% S
3.1% ash
noiusRR
TYPF,
Spreader
Stoker
TYPE
AND
LEVEL
OF CONTROL
SIP
Raw' coal
ESP
MODERATE
Raw ooal
ESP
OPTIONAL
MODERATE
Raw Coal
ESP
INTERMEDIATE
PCC-Level 4
ESP
STRINGENT
OCC-Gravichem
ESP
CONTROL
MFFI-
CIKNCy+
(«)..
0
88
0
95
0
95
30
95
50
98
MNEtCT
TYPE
El«c.
Else.
Total
Elec.
ElGC.
Total
Elec.
Elec.
Total
Fusl"
E].ec.
Elec.
Total
Fvela
E&F
Elec.
Total
tNERGY CONSUMPTION
FMiRGY amSUMl'^ BY
CONTROL
kJ/kq (D'lU/lb) KW (tliential)
1.9 (.8)
166.4 (71.5)
168.3 (72.3)
1.9 (.8)
216.1 (92.9)
218.0 (93.7)
1.9 (.8)
216.6 (93.3)
218.5 (94.1)
3,835 (1,649)
18.3 (7.9)
236.1 (101.4)
4,089 (1,758)
3,573 (1,536)
57.2 (24.5)
272.1 (117.0)
3,902 (1,678)
2
230
232
2
299
301
2
300
302
4,974
29
306
5,309
4,345
74
330
4,749
IMPACTS
% INCRKASF
IN FMWGY OVF.R
UNcoN-noti.ro
IX)I1.ER
0.5%
0.7%
0.7%
12.1%
10.8%
% INCREASE
TN ENERGY OVER
SIF-OONTRDU-En
noittfR
N.A.
0.2%
0.2%
11.5%
10. 21
** RTW Cral ArvnlysiR: 31,685 kJAg; 1.18% S; 10.30% ash
+ lV?rcx?iit sulfur reduction in ng SO?/J atul percent nr,h rcxluction in ng nnh/J.
a Ihertjy rejected to preparation plant refuse
-------
TAIlIf! 5-25. IMIW.Y USAC3-J OF "M-ST OUNTII.M, TECIWigiJI-S H>R 58.6 fW CDAL-
FIRED non,ERR t is TNG IXDW SIJLFUR EASTER*! COAT,
SYSTEM
UTW SULFUR RASTEFN COAL**
K'tW'.RI)
Heat and Fuel
Input
M»(10*Bfnj/hr)
58.6 (200)
31,685 kJAg
1.18% S
10.38% ash
31,685 kJAg
1.18% S
10.38% ash
31,685 kJAq
1.18% S
10.38% ash
POC
33,882~¥JAg
0.89% S
4.1% ash
CCC
56,13(TEJAg
3.64% S
J.1% ash
nnuws
TYPR
Pulverized
Oaal Fired
TYPI!;
AND
IWRI,
OF OONTPDL
SIP
Raw coal
ESP
DDERATE
Raw coal
ESP
OPTIONAL
MODERATE
Raw Coal
ESP
INTEBMEDlA'TE
PCXl-Level 4
ESP
STRIMC2NT
CCK-Gravichem
ESP
CONTROL
EFFI-
CIENCY1"
(%)
0
90
0
96
0
96
30
96
50
98
rNERGY
TYPE
Elec.
Elec.
Ibtal
Elec.
Elec.
TtJtal
Fllec.
Elec.
•total
Fuel0
Elec.
Elec.
notal
Puel«
E&F
Ilec.
total
ENERGY CXWStJMirriON
ENERGY CONSLMTD M
CONTROL
k JAg (BTU/lb) KW ( the mal )
1.9 (.8)
144.4 (62.1)
146.3 (62.9)
1.9 (.8)
187.7 (80.7)
189.6 (81.5)
1.9 (.8)
187.9 (81)
190 (82)
3,835 (1,649)
18.3 (7.9)
209 (89.9)
1,062 (1,747)
»,573 (1,536)
57.2 (24.5)
240.9 (103.5)
1,871 (1,664)
3
267
270
3
347
350
3
347
350
6,632
38
361
7,031
5,793
98
390
6,281
IMPACIS
% INCREASE
N ENERGY OVER
UNOONm>Lr,ED
BOILER
0.4%
0.6%
0.6%
12.0%
10.7%
% INCREASE
N 1M3RCT OVER
IP-CONTROLLED
TOILER
N.A.
0.6%
0.6%
11.9%
10.7%
** Row Conl Analysis: 31,685 kJAg; 1-18% S; 10.3B% ash
•f I'nrcont sulfur induction in ng SOj/J and percent ash reduction in ng ash/.l.
a Energy rejected to preparation plant refuse
-------
TABLE 5-26 ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FDR 118 Wl COAL-FIRED BOILERS USING LOW SULFUR EASTERN COAL
Ul
O
OJ
•
SYSTEM
LOW SULFUR EASTERN COAL **
Standard Boiler
Heat Rate
MW or
(106 BTU/hr)
118 (400)
31,685 kJAg
1.18 % S
10.38 % Ash
31,685 kJAg
1.18% S
10.38%
31,685 kJAg
1.18% S
10.38% Ash
PCC
33,882 kJAg
0.89% S
4.1% Ash
crc
pe7i30 kJAg
0.64% S
3.1% Ash
Type
Pulverized
Coal
Type
and
Level
of
Control
SIP
?aw Coal
ESP
Moderate
Raw Coal
ESP
Optional
Moderate
Raw Coal
ESP
Intermediate
PCC-Ijevel 4
ESP
Stringent
CCC-Gravichem
3SP
Control
Ef- +
iciency
Percent
(*1
0
90
0
90
0
96
30
96
50
98
Energy
Type
Elec.
Elec.
TOTAL
Elec.
Elec.
TOTAL
Elec.
Elec.
TOTAL
Fuela
Elec.
Elec.
TOTAL
Fuela
E & F
Elec.
TOTAL
ENERGY CONSUMPTION
Energy Consumed
by Control
JAg (BTU/lb) KW (thermal)
1.9 (.8) -
111.9 (48.1)
113.8 (48.9)
1.9 (.8)
133.0 (57.2)
134.9 (58.0)
1.9 (.8)
133.0 (57.2)
134.9 (58.0)
3,835 (1,649)
18.3 (7.9)
146.5 (63.0)
4,000 (1,720)
3,573 (1,536)
57.2 (24.5)
164.7 (70.8)
3,795 (1,631)
7
414
421
7
492
499
7
492
499
13,264
64
507
13,835
11,586
185
534
12,305
1
IMPACTS
Percent Increase
in Energy over
Uncontrolled
Boiler
0.3%
0.4%
0.4%
11.7%
10.4%
Percent
Increase
n Energy over
SIP
Controlled
Boiler
NA
0.6%
0.6%
10.2%
9.1%
Raw Coal Analysis: 31,685 kJAg; 1.18% S; 10.38% ash
Percent sulfur reduction in ng SOa/J and percent ash reduction in ng ash/J,
Energy rejected to preparation plant refuse
-------
Table 5-27. ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FOR 8.8 MM COAL-FIRED BOILERS
tn
O
it*
SYSTJ
LOW SUIFUR WES
~ — — -
STANDARD BOILERS
Iteatand Fuel
Tnp>i»-
MW(10*BTU/hr)
8.8 (30)
26,270 kJAg
0.59% S
24.8% Ash
type
Underfeed
Stoker
M
3TERNCOAL **
— — — - —
TYPE AND
LEVEL
(F CONTROL
sn>
Raw
ESP
MODERATE
Raw Coal
ESP
OPTIONAL
MODERATE
Raw Coal
ESP
INTERMEDIATE
Raw Cbal
ESP
STRINGENT
Raw Coal
ESP
CONTROL
EFFI-
CIENCY*
(%)
0
89
0
96
0
96
0
98
0
99.5
ENERGY
TYPE
Elec.
Elec.
Ibti
Slec.
SlfiC.
Tota
Elec.
Elec
Ibtal
!lec.
•!lec.
Tota
SlfiC.
5lec.
Tbta
ENERGY CONSUMPTION
ENERGY CONSUMED BY
CONTROL
cJ/Kg(BTU/lb) KW (thernal
1.9 (.8)
144.4 (62.1)
1 146.2 (62. 9 j
1-9 (.8)
189.2 (81.4)
. 191.0 (82.2)
1.9 (.8)
189.2 (81.4)
191 (82)
1.9 (.8)
200.0 (86.0)
. 201.8 (86.8)
!*9 (.8)
222.4 (95.6)
. 224.2 (96. 4>
< 1
48
49
< 1
63
64
< 1
63
64
< 1
66
67
< 1
74
75
IMPACTS
% INCREASE
IN ENERGY OVER
UNODNTROILED
BOILER
.6%
.7%
.7%
.8%
.9%
% INCREASE
[N ENERGY OVER
3IP-CONTROLLED
COILER
N.A.
.2%
.2%
.2%
.3%
** Raw Coal Analysis: 0.59% S; 26,270 kJ/kg/ 24.8% Ash
+ Percent ailfur reduction in ng S02/J and percent Ash reduction in nq ash/J
-------
Table 5-28. ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FOR 22MW COAL-FIRED BOILERS
USING LOW SULFUR VJESTERN COAL
Ui
8
SYSTEM
LOW SULFUR WESTERN COAL**
STANDARD BOILERS
Heat andFvel
Input
MW (106BTU/hr)
22 (75)
26,270 kJAg
0.59% S
24.8% Ash
Type
Chain
Grate
Stoker
TYPE AND
LEVEL
OF CONTROL
SIP
Raw Coal
ESP
MODERATE
Raw Coal
ESP
OPTIONAL
MODERATE
Raw Coal
ESP
INTEFMEDIATE
Raw Coal
ESP
STRINGENT
Raw Coal
ESP
X1NTROL
7FFI-
^ENCY*
(%)
0
89
0
,96
0
96
0
98
0
99.5
ENERGY
TYPE
5lec.
Elflr.
Tol
Elec.
Elec.
To
dec.
31ec.
total
'lee.
tlec.
Tot
51ec.
51ec.
Tot
ENERGY CONSUMPTION
ENERGY CONSUMED BY
CONTROL
kJAq(BTU/lb) KW (thermal)
1.9(.8)
148.5(63.9)
al 150.4(64.7)
1.9(.8)
194.8(83.8)
d 196.7(84.6)
1.9 (.8)
196.7 (84.6)
199 (85)
1.9(.8)
206.3(88.7)
d 208.2(89.5)
1.9 (.8)
229.2(98.6)
1 231.1(99.4)
1
, 124
125
1
162
163
1
163
164
1
172
173
1
191
lb»^
IMPACTS
% INCREASE
IN ENERGY OVER
UNCONTROLLED
BOILER
.6%
.8%
.7%
.8%
•
.9%
% INCREASE
IN ENERGY OVER
SIP-CONTROLLED
'BOILER
NA
.2%
.2%
.2%
.3%
** Raw Coal Analysis: 0.59% S; 26,270 kJ/kgs 24.8% Ash
+ Percent sulfur reduction in ng SO2/J and percent Ash reduction in ng ash/j
-------
Ifcblfi 5-29 ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FDR 44Mf COAL-FIRED BOILERS
USING LOW SUCFUR WESTERN GOAL
SYSTEM
LOW SULFUR WESTERN COAL**
STANDARD BOILERS
Heat and Fuel
In£ut
M* (108BTO/hr)
44 (150)
26,270 fcj/kg
0.59% S
24.8% Ash
Type
Spreader
Stoker
TYPE AND
LEVEL
OF CONTROL
SIP
Raw Coal
ESP
MXGRATE
Raw Coal
ESP
OPTIONAL
gOpERATE
kaw Coal
INTERMEDIATE
Rew Coal
ESP
STRIN32JT
Raw Coal
ESP
CONTRCC
EFFI-
CCENCYf
<%)
0
96
0
98
/
0
98
0
99.3
0
99. B
ENERGY
TYPE
lee.
Elec.
Tc
lee.
51ec.
To
aec
Clec.
total
flee.
3lec.
To
iilec.
!lec.
To
ENERGY CONSUMPTION
ENERGY CONSUMED BY
CONTROL
kJ/kg(BTU/lb) KW (thermal)
1.9 (.B)
81.9)
tal 1.9(82.7)
i.9(.8>
201.7(86.7)
al 203.6(87.5]
1.9 (.8)
201.7 (86.7
204 (88)
1.9 (.8)
224.2(96.4)
al 226.1(97.2)
1.9 (.8)
224.2(96.4)
al 226.1(97.2)
3
318
321
3
337
340
3
> 337
340
3
375
378
3
375
378
IMPACTS
% INCREASE
IN ENERGY OVER
UNLXJWIWOLLED
BOILER
.7%
.8%
.8%
.9%
•
.9%
% INCREASE
tN ENERGY OVER
IP-CONTROLLED
BOILER
NA
.04%
.04%
.1%
.1%
** Raw Coal Analysis: 0.59% S; 26,270 kJ/kg» 24.8% Ash
+ Percent sulfur reduction in ng SO2/J and percent Ash reduction in ng ash/J
-------
Table 5-3(1 ENERGY USAGE OF "BEST1 CONTROL TECHNIQUES FOR 58.6M-I COAL-FIRED BOUGHS
USING LOW SULFUR WESTERN COAL
LTl
O
-J
SYSTEM
LOW SULFUR WESTERN** COAL
STANDARD BOILERS
Heat and Fuel
Input
MW (106BIU/hr)
56.6 (200)
26,270 ]-J/kg
0.591 S
24.8% Ash
Type
Pulverized
Coal
TYPE AND
LEVEL
OF CONTROL
SIP
Raw Coal
ESP
MDDERATE
Raw Coal
ESP
OPTIONAL
MODERATR
Raw Coal
ESP
INTERMEDIATE
Paw Coal
ESP
STRINGENT
Raw Coal
ESP
CONTROL
EFFI-
CIENCY4
(%)
0
97
0
99
0
99
0
99.4
0
99.8
ENERGY
TYPE
Elec.
Elect.
Tc
Elec.
Elec.
To
Elec
Elec.
Total
,
lElec.
Elec.
Tc
Elec.
Elec.
Tc
ENERGY CONSUMPTION
ENERGY CCNSCMED BY
CONTROL
kJ/Kg(BTU/lb) KH (thermal)
1.9(.8)
170.3(73.2)
bal 172.2(74.0)
1.9(.8)
175.1(75.3}
tal 177.0(76.1)
1.9 (.8)
175.5 (75.7
177 (77)
1.9(.8)
194.7(83.7
al 196.6(84.5
1.9(.8J
194.7(83.7
>al 196.6(84.5
'
4
379
383
4
390
394
4
391
395
4
434
4.JU
4
434
430
IMPACTS
% INCREASE
IN ENERGY OVER
UNCONTROLLED
BOILER
.6%
.7%
.7%
.7%
.7%
% INCREASE
[N ENERGY OVER
IP-CONTROLLED
BOILER
NA
.02%
.02%
.09%
.09*
** Paw Coal Analysis: 0.59% S; 26,270 kJAgs 24.0% Ash
+ Percent sulfur reduction in ng SOz/J and percent Ash reduction in ng ash/J
-------
TABLE 5-31 ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FOR 118 W COAL-FIRED BOILERS USING LOW SULFUR WESTERN COAL
O
00
SYSTEM
UOW SULFUR WESTERN COAL **
Standard Boiler
fteat Hate
MM or
(in* BTU/hr)
118 (400)
26,270 kJAg
0.59% S
24.8% Ash
Type
Pulverized
ODal
Type
and
Level
of
Control
SIP
Raw Cbal
ESP
{federate
Raw Cbal
HSP
Optional
Moderate
Ret* Cbal
ESP
Intermediate
Raw Coal
ESP
Stringent
Raw Goal
ESP
Control
Ef- +
ficiency
Percent
(\)
0
97
0
99
0
99
0
99.4
0
99.8
energy
Type
Elec.
Else.
TOTAL.
Elec.
Elec.
TOTAL
Elec.
Elec.
TOTAL
Elec.
Elec.
TOTAL
Elec.
Elec.
TOTAL
ENERGY CONSUMPTION
Energy Oonsuned
by Control
tJAg (BTU/lb) KM (thermal)
1.9 (.8) -
117.7 (50.6)
119.6 (51.4)
1.9 (.8)
U9.6 (51.4)
121.5 (52.2)
1.9 (.8)
119.6 (51.4)
121.5 (52.5)
1.9 (.8)
129.8 (55.8)
131.7 (56.6)
1.9 (.8)
129.8 (55.8)
L31.7 (56.6)
8.3
525
533
8.3
534
542
8.3
534
542
8.3
579
587
8.3
579
587
IMPACTS
Percent Increase
Ln Energy over
Uncontrolled
Boiler
0.4%
0.4%
0.4%
0.5%
0.5%
Percent
Increase
n Energy over
SIP
Controlled
Boiler
NA
.008%
.008%
.04%
.04%
** Raw Coal Analysis: 0.59% S; 26,270 kJAg; 24.8% Ash
+ Percent sulfur reduction in ng SO2/J and percent Ash reduction in ng ash/J.
-------
TABLE 5-32. SAMPLE CALCULATIONS
Calculating energy oonsuaed by control - 8.8MH underfeed stcker using
high sulfur eastern ooal to meet SIP level.
1) Fuel energy lost in refuse in FCC plant - Level 5, middling product
a) Heat content in refuse = heat content of refuse x refuse wt % x feeds
Ib product product coal feed rate
Heat content in refuse = 5,401 BTO X0.2667 x 8,000 ton = 1,964 BTU = 4,568 kJAg
Ib product B* *& ~
5,866 ton
day
b) Converting BTU to JW
"IF
Heat content in refuse x boiler input rate x .000293 I£J
Ib product BTO/hr
=
heat content of coal input to boiler
1964 BTO x 30 106 BTU x .000293 IW
IE" hr BTU/hr
= 1,392 KW
.012402 106 BTU
2) Calculating electrical energy use in preparation.
Using the equipment list in Section 4, energy requirements for each
unit in Level 5 were obtained and sunned. From tMs value was subtracted energy
usage values for "those pieces which were only used for deep clean coal processing.
The resulting energy value represented middling processing.
3) Calculating ESP electrical energy use.
Using methodology in Section 5.2.1 and resulting Table 5-15,
electrical kilowatt usage was 11.6. Thermal kilowatt usage was 3 x 11.6 = 34.8KW.
Conversion to BTU/hr is similar to first calculation.
4) Calculating % increase in energy over uncontrolled boiler.
total energy consumed in control = 1.43UW _ lg 3%
energy input to boiler 8. SIM
5) Calculating % increase in energy over SIP-controlled boiler.
1 - total energy consumed in control for SIP + energy input to boiler
total energy consuned in control + energy input to boiler
1 - 3.3 * 1.431EM _ _ ,.
8.8 + 1.439MW - °'r!
509
-------
LIVtLS OF CONTROL
FOK CLEANED COAL
CD
n
E3
n
MODERATE
OPTIONAL uooCRATi IPCCI
INTlltMCOIATI IfCO
JTWHOHfT (CCCI
CNtACY CO*KUM(O
•Y tOlUR ESP
WHEN CUAN COAL
•AA3 REPHEStNT TOTAL ENtHOY
USf O BY ESP AND "EP P1ANT
EQUIPMENT AMD LOST ENERGY IN
F*EP PVAUT RtFUSC
118 M* BOILER EXCLUDED
.«Z20
NUMERICAL VALUES Aftt
IN KIVOWATTS nXC*MAU
PULVERIZED
COAL FIRED
(58.6 >W)
FIGURE 5-2 ENERGY CONSUMED USING HIGH SULFUR EASTERN COAL
510
-------
LEVELS Of CONTBOL
• 0000
C~"l SIP 'RAW COAL BURNED!
[~~[ MODERATE RAW COAL BURNED!
j OPTIONAL MODERATE I RAW COAL BURNED!
rrrn INTERMEDIATE IPHYSICALLY CLEANED COALI
STRINGENT (CHEMICALLY CLEANED COAL)
ENERGY CONSUMED
BY BOILER ESP
WHEN CLEAN COAL
IS COM BUSTED
NUMERICAL VALUES ARE
IN KILOWATTS .THERMAL!
BARS REPRESENT TOTAL ENERGY
USED BY ESP AND PREP PLANT
EQUIPMENT AND LOST ENERGY IN
PREP PLANT REFUSE
118 MV 3CILER E2CCLLDED
U10
5000
•
•
•MS
v
:
:
2*20
302 302
.
;
.
:
350 350
GRATE
STOKER
SPREADER
STOKER
PULVERIZED
COAL FIRED
UNDERFEED
STOKER STOKEH
'58.6
FIGURE 5-3 ENERGY CONSUMED USING LOW SULFUR EASTERN COAL
511
-------
10000
sow
LEVELS Of COMTHOL
TOR COAL
MODERATE
OPTIONAL. MODERATE
INTIRMEDIATE
[ 1 STWNOENT
^m ENERGY CONSUMED
1 ir KXUM EST
WHt* CUAN COAL
IS COMlUSTtD
NUMEIUCAL VALUES AM
IN KILOWATTS rtXfRMAU
BARS Rt'BtStNT ENERGY CONSUMED
IN iREAKIWG.SIZING HAM COAL AND
•V KMLEM IV
U8 ^W BOILER EXCLL-DO)
i
•:
1000
500
•00
-
.
-
MO MO
:
UNOERftED
GRATl
STOKER
SPREADER
STOKER
P'JLVfRIZEO
COAL FIMEO
(53.6 u*)
FIGURE 5-4 ENERGY USAGE USING LOW SULFUR WESTERN COAL
512
-------
and chemically cleaned lew sulfur eastern coal. Ihe large increase in
energy consumption is attributable to the energy lost in coal preparation
plant refuse. Figure 5-4 shows raw low sulfur western coal requires
the least amount of energy to meet the control levels and also shows a
step-^wise progression of the amount of energy required to meet increasingly
strict controls. Figure 5-2 also shows this step-wise progression, however,
the amount of energy required then using physically cleaned high sulfur coal
is greater than for chemically cleaned coal. This occurs because less refuse
is produced by chemical coal cleaning plants (i.e. higher yields) resulting
in less energy lost to the refuse, and more energy remaining in the aggregated
product coal.
5.2.4 Comparison of Energy Consutption Using Low Sulfur Coal/
Physically Cleaned Coal and Chemically Cleaned COal
As discussed in Section 5.1 the major energy elements differ for
each control technology discussed. Section 5.2.2 shows the magnitude of
the energy consumption between these elements. Expressed as a percent of
the raw coal energy content, the difference in energy consumption can be
estimated.
For low sulfur coal transport the energy consulted varies from 0.4-
4.0 percent depending ipon the coal source and its destination. Note on
Table 5-6 that when a physically or chemically cleaned coal is transported
the sane distance as raw coal, the energy impact is less. For example,
transporting raw low sulfur eastern coal to Austin, Texas consumes the
equivalent of 2.51 percent of the coal's energy content. If that coal is
cleaned at the mine and then shipped, the equivalent energy consunption
is reduced to 2.18 percent. The transportation energy savings is owr
10 percent.
Compared to transportation energy consunption, the energy spent in
actually physically cleaning the coal is negligible. As a percent of the
coal energy content, it is less than 0.05 percent. Chemically cleaning
the coal involves considerably more energy, but as a percent of the coal
energy content, it is equivalent to only 0.2-0.75 percent.
513
-------
The major energy consumer is energy lost in the refuse of a coal
cleaning plant. It is this loss of energy from the mined, raw coal which
accounts for 95 percent of the energy consumption related to coal
cleaning technology, including particulate control. As shown in the BSER
energy usage tables, level 5 coal cleaning rejects almost 16 percent of
the coal's energy content while level 4 rejects about 12 percent. For
chemical coal cleaning the rejection energy is slightly lower, from 8-10
percent of the coal energy content.
Ihe fourth energy element is particulate collection. Section 5.2.1
shows the absolute energy requirements for particulate control at various
control levels using electrostatic precipitators. Note that raw high
sulfur coal consumes less energy than cleaned coal for the same emission
control level. This is a function of the ash resistivity increase due to
lower sulfur content in the cleaned coal, which is dominant over the lower
ash content. On the other hand, cleaning low sulfur eastern coal reduces
energy requirements for particulate control. For the BSERs, the ESP
consumes from 0.4-0.8 percent of the energy content in the specified low
sulfur eastern coal aid 0.6-0.9 percent for the low sulfur western coal.
In total, including transportation, using low sulfur western coal will
consume from 3-6 percent of a coal's energy content to meet various emission
control levels. If physically cleaned eastern coal is used, the consumption
value is much higher at 14-18 percent. Chemical coal cleaning energy
consumption is slightly lower at 9-12 percent of the input coal energy
value.
The energy effectiveness with respect to SO2 removal of the three
control technologies is shown in Table 5-33. Transportation energy is
not included in these values. For raw low sulfur ooal the absolute value
of energy consumed is provided, since there is actually no sulfur
removed by using this control technique. The table shows that removal of
additional amounts of sulfur is associated with an increase in the absolute
amount of energy consumed (primarily energy lost to the refuse), but a
decrease in the kilowatt per ng SO2/J removed equivalent. This result is
514
-------
TRBTJP 5-33. ENERGY USAGE EFFECTIVENESS
High Sulfur Eastern Cbal
low Sulfur Eastern Coal
Low Sulfur Western Coal
Boiler Level
Input of
MBTO Control
8.8 SIP
Moderate
Optional
Moderate
In termed.
Stringent
22 SIP
Moderate
Optional
Moderate
Intermsd.
H Stringent
Ln
44 SIP
Moderate
Optional
Moderate
Interned.
Stringent
58.6 SIP
Moderate
Optioned.
Moderate
Interned.
Stringent
118 SIP
Moderate
Optional
Moderate
Intermediate
Stringent
BSER
PCC-Lvl 5-mid
PCC-Lvl 5-mid
PCC-Lvl 5-dc
PCC-Lvl 5-dc
CCC-ERDA
PCC-Lvl 5-mid
PCC-Lvl 5-mid
PCC-Lvl 5-dc
PCC-Lvl 5-dc
CCC-ERDA
PCC-Lvl 5-mid
PCC-Lvl 5-mid
PCC-Lvl 5-dc
PCC-Lvl 5-dc
CCC-ERDA
PCC-Lvl 5-mid
PCC-Lvl 5-mid
PCC-Lvl 5-dc
PCC-Lvl 5-dc
CCC-ERDA
PCC-Lvl 5-mid
PCC-Lvl 5-mid
PCC-Lvl 5-dc
PCC-Lvl 5-dc
CCC-ERDA
KW
1,431
1,439
1,358
1,365
700
3,603
3,625
3,425
3,444
1,756
7,252
7,309
6,856
6,946
3,510
9,642
9,696
9,216
9,222
4,614
19,158
19,215
18,112
18,240
8,911
KW/
ng SOj/J
removed
.95
.96
.70
.71
.34
2.40
2.42
1.77
1.78
.85
4.85
4.89
3.55
3.59
1.70
6.45
6.48
4.77
4.77
2.24
12.81
12.85
9.37
9.43
4.32
Dsra
Paw Coal
Paw Coal
Raw Coal
PCC-Lvl 4
CCC-Gravi.
Raw Coal
Raw Coal
Raw Coal
PCC-Lvl 4
CCC-Gravi.
Raw Coal
Raw Coal
Raw Coal
PCC-Lvl 4
CCC-Gravi.
Raw Cbal
Paw Coal
Raw Coal
PCC-Lvl 4
CCC-Gravi.
Raw Coal
Raw Coal
Raw Goal
PCC-Lvl 4
CCC-Gravi.
KW
36
46
46
1,046
946
94
118
117
2,620
2,369
233
302
302
5,309
4,750
271
351
350
7,032
6,282
421
499
499
13,835
12,305
KW/
ng S02/J
removed
36*
46*
46*
4.7
2.5
94*
118*
117*
11.7
6.4
233*
302*
302*
23.8
12.8
271*
351*
350*
31.5
16.9
421*
499*
499*
61.9
33.0
BSER
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Paw Coal
Raw Cbal
Raw Coal
Raw Goal
Raw Goal
Raw Coal
KW*
49
64
64
68
75
126
165
164
174
193
233
340
340
378
378
384
395
395
438
438
533
542
542
587
587
* Indicates KW usage since no sulfur was removed
-------
not surprising since the cleaning equipment required to increase sulfur
removal is not energy intensive. Sulfur removal is limited by the amount
and size of pyritic sulfur in the coal and a trade-off betv^en coal yield
and sulfur content; it is not limited by energy demand.
5.3 POTENTIAL FOR ENERGY SAVINGS
This section discusses some of the possible methods for reducing the
amount of energy consumed by the control technologies being considered.
For the low sulfur coal control technology the major potential energy
savings would be in the area of transportation to the industrial boiler
user. However, since transportation energy is not to be considered in
this section no further discussion would be pertinent.
The chemical coal cleaning systems which have been proposed as BSERs
are simply conceptual in design at the present time and therefore any
further consideration of energy savings would be mainly conjecture. The
physical coal cleaning systems which have been proposed are commercially
available and several areas of energy reduction are potentially feasible.
5.3.1 Design of Physical Opal Cleaning Plants Without Thermal Driers
In recent years, an increase in mechanical mining methods has
increased the amount of fine coal which the physical coal cleaning plant
must process. This fine coal material will absorb and retain considerably
more moisture during processing than the coarser fractions. This
increased moisture content in the fine sizes often has required the coal
preparation plant designer to specify thermal driers to remove excess
moisture. There are two major benefits for using thermal driers,
(1) a decrease in transportation costs and (2) a reduction of heat loss
due to evaporation of surface moisture from, the coal during the burning
process. The major disadvantages to the thermal drying system are the
high capital costs of the system compared to mechanical dewatering, the
high energy costs, and the environmental problems associated with particulate
emissions from the drier stacks. The energy savings associated with the
elimination of thermal driers is on the order of 1% of the coal production
per day.
516
-------
The environmental problem associated with the parti culate emissions
has become a major factor in recent years in new plant design. In the
past two years, permits have been denied for a number of new installations
due to the inability of thermal drier pollution devices to meet particulate
ccntrol levels. As a result/ plant designers are carefully looking at alternative
designs using more sophisticated mechanical dewatering systems and blending
of coal product streams to achieve product coal specifications without
thermal drying. The physical coal cleaning plant designs used in this
report do not use thermal drying operations to achieve product moisture
specifications.
5.3.2 Energy Recovery in Physical Coal Cleaning
The physical coal cleaning process changes the net energy value of
coal in four major ways - by reducing the ash content, by increasing
the moisture content, by reducing the pyritic sulfur content, and by
rejecting some coal in refuse streams. The magnitude of these changes,
and their relative impact upon the overall energy balance, is to a large
extent controllable through design and operation of coal cleaning plants.
5.3.2.1 Factors Affecting Energy Recovery—
Ash Removal
Ash removal, or more correctly the removal of ash-forming minerals,
improves the net energy balance. Except for pyritic sulfur (iron pyrite),
the mineral impurities have no heating value so that their removal does
not constitute an energy loss. By removing minerals, an energy benefit
is achieved by avoiding the transportation requirements for inert materials,
and by avoiding the sensible heat requirements (in the boiler) for inert
materials. This energy benefit can be sizable, since the quantity removed
by coal cleaning may amount to 15 or 20 percent of the total raw coal
quantity.
Pyrite Removal
Pyritic sulfur (iron pyrite) is removed in coal cleaning plants for
boiler-related emission reasons. Since iron pyrite does have a heating
value, its intentional removal for environmental reasons prior to combustion
517
-------
is associated with an inherent energy penalty.
The heat of combustion of iron pyrite, FeS2, is 6,894 kJ/kg (2,964
BTO/lb). Table 5-34 surmarizes the inherent energy penalty of pre-
combustion pyrite removal.
Moisture Content of Washed Ooal
Physical coal cleaning processes result in increased moisture content
of the product coal. As coal cleaning plant designs evolve to remove
greater amounts of pyritic sulfur, fine coal cleaning circuits will become
prevalent. The liberation of iron pyrite by further size reduction, and
the separation of pyrite by washing fine size fractions, are the commonly-
applied techniques. Since fine coal fractions have much greater quantities
of surface moisture, the resultant energy penalties for transporting
excess moisture and for evaporating excess moisture in the boiler become
larger. Ooal cleaning plant dewatering techniques (e.g. centrifugation or
filtration) are effective in significantly reducing these moisture-related
energy penalties, but thermal drying (with its comparatively large energy
requirements) is necessary to achieve moisture levels in washed fine coal
approximating the raw coal moisture levels.
Misplaced Material
Since commercial physical coal cleaning processes are less than
theoretically perfect in partitioning organic coal from inorganic impurities,
some coal with its desirable energy value is lost, as misplaced material,
with the inorganic refuse streams. Fine coal cleaning circuits have the
potential not only of separating and rejecting more liberated pyrite and
ash, but also of recovering more liberated clean coal. Cleaning plant
design techniques and unit processes for fine coal separations are useful
for minimizing the energy penalties associated with misplaced clean coal.
5.3.2.2 TracL-Offs for Energy Recovery—
The first two factors discussed above have direct, easily discernible
effects on energy use by cleaning plants. First, ash removal is a desirable
process from every standpoint, since it provides lower transportation and
518
-------
TABLE 5-34 ENERGY PENALTIES ASSOCIATED WITH PKE-OOMBUSTION PYRITE. REMOVAL
Percent Pyritic Sulfur
Percent Ircn Pyrite (FeS2)
Heating Value, kJAg Total Coal
Ototal Coal
Iron Pyrite in Coal
Net (Coal less pyrite)
Percent of Total Heating Value
in Iron Pyrite
1
Eastern
High-Sulfur
Coal
2.79
5.22
26,772
360
26,412
1.34
Eastern
Low-Sulfur
Coal
0.60
1.12
31,685
77
31,608
0.24
Western
Low-Sulfur
Coal
0.30
0.56
26,268
39
26,229
0.15
519
-------
coal handling costs , less ash handling and disposal costs and generally less
slagging problems in the boiler leading to lower operation and maintenance
costs. The energy benefit of ash removal is completely consistent with the
above cost-benefits. The second straightforward relationship is with the
pyrite removal factor. Emission goals necessitate the maximum removal of
pyritic sulfur, with the implied result that any energy penalties from pyrite
removal are acceptable.
For the other two factors, the relationship is not straightforward,
but is largely dependent-upon specific plant designs and plant operating
characteristics. The magnitude of energy penalties from excess moisture
and from misplaced clean coal are largely controllable, and may be
viewed as the results of tradeoffs for particular commercial situations.
The plant designs and operating characteristics which affect the
quantity of excess moisture in cleaned coal and the quantity of organic
coal rejected in refuse streams are the result of economic tradeoffs.
The criterion for selecting coal cleaning operations such as dewatering,
drying, separation, and recovery, is least cost per unit of delivered
clean coal (or maximum profit to the cleaning plant operator). The economic
optiiram does not necessarily coincide with an optimum based upon maximum
net energy recovery. Several key ingredients are cummi to cost and
energy: transportation costs are approximately proportional to transporta-
tion energy, and the economic value of rejected misplaced coal is
approximately proportional to the energy value of this rejected coal.
Howaver, the economic tradeoffs are heavily influenced by capital amortiza-
tion, vhich plays no role in energy tradeoffs.
Mechanical dewatering techniques (centrifugation, filtration) have a
highly positive energy balance. The energy benefit of removing excess
moisture, in terns of avoiding transportation and evaporation penalties,
are much greater than the energy requirements for mschanical dewatering.
Fortuitously, the cost tradeoff appears consistent with the energy
tradeoff. The economic benefits, in terms of avoiding excess transporta-
tion charges and boiler evaporation penalties, are generally greater than
the capital amortization and operating costs for mechanical dewatering.
520
-------
Hence, mechanical dewatering appears desirable for both cost saving and
energy recovery purposes.
Thermal drying of fine coal, however, is not clearly advantageous,
assuming that much of the excess moisture in fine coal is first removed by
mechanical dewatering. The incremental moisture removed by thermal drying
reduces both transportation costs and transportation energy requirements.
However, thermal drying requires considerably more energy (because of
higher inefficiencies) than evaporation of moisture in the boiler.
From an economic viewpoint, the capital and operating costs of thermal
dryers are high, especially when stringent air pollution controls are
required.
A fundamental characteristic of any single physical coal cleaning unit
operation is that it may be designed and operated either by maximum
removal of high-density inorganic impurities or for maximum recovery of
clean coal; but not for achieving both goals. This characteristic arises
from the presence of individual mid-gravity particles which report either
to the clean coal fraction (if a high operating specific gravity is
selected), thereby maximizing energy recovery; or to the refuse fraction
(if a low operating specific gravity is selected), thereby maximizing
impurity removal.
Several approaches are effective in minimizing the energy penalty
of misplaced coal. One approach is finer size reduction, which liberates
more of the impurities so that a lesser fraction of the individual
particles fall in the mid-gravity range. Another approach is to use
more efficient separation processes (which have a sharper partition curve).
A third approach is to apply sequential processes or sequential circuits,
where a first stage operated to achieve one of the alternate goals is
followed by a second stage operated to achieve the other goal. For the
sink from one heavy-madia cyclone operated at a low specific gravity may
then be the feed to a second heavy media cyclone operated at a high
specific gravity - the first stage produces a "deep-cleaned" product and
the second stage produces a middling product, while the products of both
stages maxainize the energy recovery. Similarly, an entire plant may be
521
-------
designed and operated to produce both a very clean coal product and a
middling product.
Although these approaches minimize the energy penalty of misplaced
coal, the designs and operating conditions are normally dictated by
economics rather than by energy recovery. At some point, it becomes
uneconomical to recover any more energy, and some coal is lost in the
refuse streams.
5. 4 IMPACTS CF SWITCHING FRCM OIL-FIFED TO CQRL-FIFED INDUSTRIAL BOILERS
It is not practical to modify existing oil-fired industrial boilers to
burn coal. Such modification would entail substantial costs—for new pol-
lution control fan"ii1-*««; for an air preheater; for arMitinnal space and
fxr>iin-it>a for receiving, staling, and handling coal; and for handling,
storing, and disposing of residuals. Moreover, the required modifications
would cause significant decreases in capacity rating; indeed, the capacity
rating might drop by as much as two-thirds. Even oil-burning boilers that
previously burned coal could encounter problems when reconverting: needed
auxiliary equipment, space, and rail connections may have been removed;
pollution control fiv^m-tea might be inadequate; and the type of coal for
which the boiler was designed might no longer be avail able.
For industrial firms, then, switching from oil to coal means installing
new boilers—boilers expected to be subject to New Source Performance Stan-
dards (NSPS) for major air pollutants. In fact, for the whole universe of
energy users nationally, increasing coal use by switching from oil or gas
means primarily burning coal in new industrial boilers; electric utilities
burning fossil fuels are already planning to use coal in new units; the other
major sectors (transportation, residential, and commercial) cannot realis-
tically be expected to burn coal in significant quantities.
There are perceived advantages to burning coal: first, coal is likely
to be more available than oil or gas; and, second, the delivered price of
coal is expected to be lower per unit of energy. The advantage of a lower
annual fuel cost must be evaluated in terms of a tight money market and
the fact that industries require a relatively high rate of return on invest-
ment. A chemical plant, for example, might expect payback in three to five
522
-------
years, while a utility (which can borrow irore cheaply) may be able to wait
20 years. The advantage of lower fuel cost will, of course, be relatively
greater in boilers with higher capacity factors.
•Hie American Boiler Manufacturers Association predicted in 1977 that,
in 1985, only 38 percent of the new boiler capacity with heat input ranging
from about 30 to 90 Mtf (t) (100-312 million BTU/hr) will burn oil or gas;
(12)
the remainder will burn coal or waste. One boiler vendor, whose estimates
are based on a survey he conducted in 1976, predicted that close to 40
percent of the capacity of the fossil-fuel-fired boilers purchased over the
next five years will have the capability to burn coal. Both of these
projected values are considerably higher than the current value of coal's
percentage of industrial boiler fuel, which is about ten percent.
The recently passed National Energy Act (NEA) includes provisions that
are intended to prohibit the burning of gas or oil in the majority of new
industrial boilers, and to decrease the financial disadsantage of burning
coal vis-a-vis oil or gas. Most dramatically, the NEA prohibits "large"
new boilers—units with a heat input rate of at least 30 MW (t) (100 million
BTU/hr) or aggregations of units of total capacity exceeding 73 mw(t)
(250 million BTU/hr)—from burning oil unless granted an exemption by DOE
(on the basis of factors such as environmental degradation, economic hard-
ship, and site limitations). By specifying "large" boilers the NEA will
affect most new boiler capacity: in 1974, 3.9 quads of the approximately
4.3 quads of fuel consumed in industrial boilers were burned in "large"
industrial boilers. (llt)
5.5 SUMMARY
Table 5-35 summarizes the energy in kilowatts used by each BSER.
These values show that the greatest energy user is physical ooal cleaning
with chemical coal cleaning consuming about 50% as much energy and low
sulfur coal consuming only 5 percent of the PCC value. Figures 5-5, 5-6
and 5-7 represent energy usage versus Boiler Capacity for each BSER.
Normalized on a percent basis (MW (+) energy used MV of boiler) these
values also show that physical coal cleaning is the greatest energy user
and that low sulfur ooal consumes the least amount of energy, again only
523
-------
TABLE 5-35. SUMJftFY OF ENERGY CONSUMPTION
BY BSERS
Boiler
Type
Level
of
Control
Energy
Consunption
for
High Sulfur
Eastern Coal
KW(t)
Energy
Consumption
for
Low Sulfur
Eastern Coal
KW(t)
Energy
Consunption
for
Low Sulfur
Western Coal
KW(t)
8.8
22 m
44
58.6
118
SIP 1,431
Moderate 1,439
Optional Moderate 1,358
Interned. 1,365
Stringent 700
SIP 3,603
Moderate 3,625
Optional Moderate 3,425
Interned. 3,444
Stringent 1,756
SIP 7,252
Moderate 7,309
Optional Moderate 6,856
Interned. 6,946
Stringent 3,510
SIP 9,642
Moderate 9,696
Optional Moderate 9,126
Interned. 9,222
Stringent 4,614
SIP 19,158
Moderate 19,215
Optional Moderatel8,112
Intermediate 18,240
Stringent 8,911
524
36
46
46
1,046
946
94
118
117
2,620
2,369
233
302
302
5,309
4,7:0
271
351
350
7,032
6,282
421
499
499
13,835
12,305
49
64
64
68
75
126
165
164
174
193
322
340
340
378
378
384
395
395
438
438
533
542
542
587
587
-------
PCC • LEVEL V • MIDDLINGS
10
20
110
120
FIGURE 55 HIGH SULfUR EASTERN GOAL ENERGY USAGE
-------
Ul
14,000
12.000-
10.000-
I
c
Ul
K 8.000-
E
ut
£
9,000-
«.000-
Z.OOO-
PCC • LEVEL IV
FIGURE 58 LOW SULFUR EASTERN COAL ENERGY USAGE
-------
600-1
500-
_ 400-
o
oc
200-
100-
RAKV COAL
10
20
30
40 BO 60 70 80
FIGURE 57 LOW SULFUR WESTERN COAL ENERGV USAGE
90
100
110
120
-------
5 percent of the PCC value. Ihe normalized values also show that the
amount of energy consumed is not dependent upon the boiler capacity.
Ihe energy values remain constant for each BSER regardless of the boiler
capacity.
Ihe large differential between the energy consumed by PCC and the
energy consumed by low sulfur coal is caused by rejection of energy to
refuse in coal cleaning. The tradeoffs associated with the rejection of
energy versus product coal energy content were discussed in Section 5.3.
Note that decreased energy requirements for the boiler operator associated
with decreased coal and ash handling, less boiler maintenance and increased
boiler efficiency are not included in thss analysis. Although these values
could not be quantified in this ITAR, there should be an attempt to do so
in the CT&R.
An interesting result from the energy impact analyses of the three
control technologies is the increased energy effectiveness as SO2 removal
requirements increase. (See Table 5-35.) ihis shows that coal cleaning
is an energy effective S02 control technology.
528
-------
SECTION 5.0
REFERENCES
1. Teknekron, Inc., "Review of New Source Performance Standards for Coal-
Fired Utility Boilers," Volume 1, March 1978.
2. Department of HEW, "Coal Cleaning Plant Prototype Plant Specifications",
Part VII, Contract No. PH-22-68-59, Nov IS69.
3. Department of HEW, "Design and Cost Analysis Study for a Prototype Coal
Cleaning Plant, Vol. H, Contract No. PH-22-68-62, July 15, 1969.
4. Data from Final Test Reports on Buffalo Coal Mining Co., Delta Coal Co.,
and Pyro Mining Co., Cbal Preparation Plants provided by Joy/Denver
EPA Contract No. 68-02-2199, 1978.
5. Contos, G.Y., I.F. Frankel, and L.C. McCandless. Assessment of Coal
Cleaning Technology: An Evaluation of Chemical Coal Cleaning Processes.
EPA-600/7-78-1732, August 1978.
6. Kohn, Harold W. "Capacity Factor Evaluation of Fossil Fired Power
Plants", Power Engineering Vol. 82, October 1978.
7. Hoffman, L., and K.E. Yeager, The Physical Desulfurization of Coal,
The Mitre Corporation, November 1970.
8. Broz, L., C. Sedman, and D. Mcbley, Memorandum on "ITAR Average SIP
Requirements and RecomrtEndations for Moderate, Intermediate and Stringent
Control Levels". August 29, 1978.
9. Roeck, Douglas and Richard Dennis. Section 5.0 - Energy Impact of
Candidates for Best Emission Control Systems. Draft Report. GCA
Corporation. Bedford, Ma. October 13, 1978.
10. Oglesby, S.A., et al., "A Manual of Electrostatic PrecLpitator Tech-
nology, Part II, "PB 196 318, 1970.
11. "An Integrated Technology Assessment of Electric Utility Energy Systems.
First Year Report, Volume II - Components of the Impact Assessment
Model." Prepared by Teknekron for Office of Energy, Minerals, and
Industry, Environmental Protection Agency. 1976. pp. 161-176.
12. Oil and Gas Journal "U.S. Industries Pushing Switch to Coal as Fuel."
November 28. 1977. p. 24.
13. Power "Industrial Boilers." February 1977, Volume 121, No. 2, pp. 6
14. Op CLt., Reference 1, pp. 3 and 6.
529
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SECTION 6.0
ENVIRONMENTAL IMPACT OF CANDIDATES
FOR BEST EMISSION CONTROL SYSTEM
6.1 INTRODUCTION
Section 6 examines the environmental impacts of the best systems of
emission reduction. Two kinds of environmental concerns are addressed. The
first is the direct effect of atmospheric emissions from industrial boilers
using raw and cleaned coal. The BSER candidates considered relate to
various processes for reducing sulfur (and other) emissions during the com-
bustion of coal in industrial boilers by the cleaning of coal, and this is
where the opportunities lie for the greatest reductions in environmental
impact.. However, since the cleaning process has its own potential environ-
mental impacts, it is also necessary to evaluate the candidate BSERs for the
coal cleaning step. Thus, this assessment will compare the environmental
impact of burning raw, uncleared coal with the total impact from the cleaning
of coal and the utilization of cleaned coal.
The environmental impacts will be addressed on a media specific basis
by analyzing air emissions, liquid discharges and solid wastes separately.
This analysis assumes that electrostatic precipitators are used for parti-
culate control and there are no liquid discharges from industrial boilers
burning raw coal. The analysis excludes environmental impacts from mining
and transporting of coal and disposal of bottom ash and fly ash collected
at the boiler.
The purpose of Section 6 is to quantify the emissions of major pollutants
of concern and to discuss their generation and means of control. It should
not be implied that analysis is all inclusive relative to minor emissions
or trace elements. The amount of data available on the environmental impacts
of coal cleaning is relatively scarce and there are many areas relative to
cleaning plant emissions that are as yet not quantified. This analysis
attempts to utilize existing data to the maximum extent possible and some of
the results should be considered preliminary.
530
-------
The results presented in Section 6.2, 6.3, and 6.4 basically show that
the coal cleaning BSERs reduce air emissions while slightly increasing liquid
wastes and doubling solid wastes. Specifically for air pollutants, coal
cleaning reduces S02 emissions by 30-80 percent and reduces parti culate
loading in the flue gas by 60-85 percent. For NO2, and CO, and hydrocarbons,
coal cleaning provides a slight reduction in boiler emissions due to the
increased heat energy of the fuel. Coal cleaning, however, does not remove
NOa/ GD or hydrocarbons. The coal cleaning process itself may have a signi-
ficant particulate emission if thermal driers are used, however, thermal
drying was not included in the BSERs.
For liquid discharges the highest discharge concentration is for GOD
and the major trace element pollutant is iron. There are NPDES guidelines
for TSS, iron, manganese and pH from coal cleaning plants which must be met
and several unit operations are discussed which minimize these and other
liquid effluents.
The major environmental impact from coal cleaning is the generation of
large quantities of cleaning refuse, composed of minerals in the coal and
some ooal particles. Compared to the ash in the raw coal, the physical coal
cleaning BSERs produce from 43-112 percent more solid wastes. Infiltration
of contaminated water from the refuse piles and tailing ponds identified as
a major environmental impact and several mitigative measures are presented.
6.2 ENVIRONMENTAL IMPACTS OF CONTROLS FOR COAL-FIRED BOILERS
6.2.1 Air Pollution
6.2.1.1 Derivation of Emission Rates—
Because coal cleaning processes affect the composition of the boiler
fuel, the determination of boiler emission rates must be preceded by the
systematic discussion and determination of the ultimate analyses of
raw and cleaned coals. The combustion stoichiometry of each of the raw
and cleaned coals is evaluated, as an intermediate step, before the boiler-
specific and fuel-specific emission rates are determined.
Composition of Raw and Cleaned Coals
Table 6-1 lists the proximate and the ultimate analyses for each of
the three representative raw coals considered: high sulfur eastern coal
531
-------
TNMB 6-1
ANALYSIS Of RW WO ClFftlfS OWLS
_
•t
1
S
1
6
M
1
!'
«
|.
jc
6
Jj
d
8
•H
$
k
S
3
3
s
jj
jp
1 H
2 n
^
&
tolltum,t
Mi, *
•total S, t
pyrJtlc S,t
liv)nni/lb
Ash, 1
•total S, t
IV, kJAg
IIV, BBI/lb
C, t
It*
S*
O,
H,
Ash t.
c,
H,
S,
0,
N,
IIV, K.T/kq
nv,inu/it>
Hlqfi-Sulfur Eastern Cbal
Haw Cbal
5.0
22.23
25*, 413
10,934
21.40
3.40
2.79
26,772
11,510
65.58
4.20
3.40
2.19
1.23
21,40
85.61
4! 44
2.87
1.60
15*, 325
Dpfi1>-Cle«n9f. PCC
9.0
5.28
30,933
13,127
5.80
1.08
_
33,559
14,426
90.59
5.16
1.08
S.06
1.51
5.80
95. S5
5.48
1.15
6.22
1.60
35,620
15,114
Middling FOC
8.89
10.30
l.M
28.R47
12,402
11.31
1.69
_
31,662
13,612
76.04
4. 97
1.6*
4.67
1.42
11.31
85.74
5.49
1.91
5.26
1.60
35,699
IS, 348
won
9.0
22. H
0.71
0.27
29,940
11,192
23.40
0.74
O.Jt
27,305
11,739
65.58
4.20
0.74
4.86
1.23 .
23.40
M5.61
S.48
0.96
6.35
1.60
35,646
15,125
nravlctnm
5.0
4.17
1.05
0.32
32,377
13,919
4.39
1.10
0.34
34,091
14,652
11.85
5.24
1.10
9.81
1,53
4.39
95.61
S.48
1.16
6.19
1.60
35,646
15,325
Van Out
2.0
10.17
1.16
0.59
31,052
13,350
10.38
1.18
0.60
31,665
13,622
7«.10
4,«7
1.18
6.04
1.43
10.38
84.91
S.43
1.32
6.74
1.60
35,355
15,200
Imr-SUHur Kutam Ooal
PCC Product
7.«7
3.82
0.82
31,352
13,479
4.1)
0.89
_
33,883
81.18
5.21
0.89
6.86
1.53
4.13
84.89
5.43
0.93
7.15
1.60
35,344
15,195
m»
2.0
10.17
O. 38
0.04
31,051
13,350
10.38
0.3*
0.05
31.683
13,622
76.10
4.17
0.39
6. S3
1.43
10.38
84.91
5.43
0,44
7.62
1.60
35,355
15,200
nravlchun
2.0
1.91
0.55
a. 29
13,»73
14,606
1.95
0.56
0.05
34,666
14,904
83.25
5.32
0.56
7.34
1.57
1.95
84.91
5.43
0.57
7.49
1.60
35,355
15,200
tou-Sultur tteiteni Onal
Raw Cnal
2.5
24.19
0.58
0.29
25,614
11,012
24,8)
0.59
0.30
26,26*
11,294
A3. 09
4.04
0.59
6.27
1.20
24.81
93.91
5.37
0.79
8.34
1.60
14,931
15.021
Product Cbal
7.22
15.31
0.60
27,093
11,648
10.90
O.CS
29,201
12,554
70.13
4*49
0.65
6.89
1.34
16,50
83.99
5.38
0.78
8.25
1.60
34,971
15,035
Ul
00
to
-------
(Upper Freeport Seam, Butler County, Pennsylvania) ; low sulfur eastern ooal
(Eagle Seam, Buchanan County, Virginia); and low sulfur western ooal (Prirnero
Seam, Las Animas County, Colorado). Also listed are the proxiirate and
ultimate analyses for the clean coal products from the physical and chemical
processes discussed in Section 3 of this ITAR. The proximate analyses are
given both on an as-received basis and a dry basis; and the ultimate
analyses are given both on a dry basis and on a dry, ash-free basis.
The proximate analyses for each of the three raw coals are actual
values, as presented earlier in Table 3-12, and form the basis for
the remainder of Table 6-1. The conversion from as-received percentages to
dry-basis percentages is:
X As-Received _.
x Basis .
Dry Basis 1 -(Percent Moisture/100)
where X is either the percentage of ash, total sulfur, or pyritic sulfur;
or is the heating value (HV).
Similarly, for the ultimate analysis,
X = X
Dry, Ash-Free Basis Dry Basis
1 -[Percent Ash(Dry Basis)/100]
Ultimate analyses were not available for the three specific raw coals,
and were therefore estimated. First, the percent carbon (dry, ash-free
basis) was calculated using the Uehling relationship for bituminous coals,
Percent Carbon (Dry, Ash-Free Basis)=100
Heating Value (Dry, Ash-Free Basis), BTU/lb
17,900 BTU/lb
This simple relationship for estimating the ultimate analysis from the
experimsntally-determined heating value has been found to be accurate to
within 2 percent for coals within a given rank. As a test of this
predictive relationship, it was applied to ten bituminous coals for
(2)
which the ultimate analysis had been experimsntally determined:
533
-------
Group
Low-Vol.
Low-Vol.
Msd-Vol.
Mad-\fc>l.
High-Vol.A
High-Vbl.A
High-Vbl.A
High-Vbl.B
High-Vol.B
High-Vbl.C
State
WV
PA
PA
PA
PA
KY
OH
IL
UT
IL
County
McDowell
Cambria
Somerset
Indiana
Westmorelanc
Pike
Belitcnt
Williamson
Bnergy
Vermillion
Anal\
C,%
90.4
89.4
88.6
87.6
85.0
85.5
80.9
80.5
79.8
79.2
rsis, Dry/ Ash-Free Basis
H,%
4.8
4.8
4.8
5.2
5.4
5,5
5.7
5.5
5.6
5.7
0,%
2.7
2.4
3.1
3.3
5.8
6.7
7.4
9.1
11.8
9.5
N,%
1.3
1.5
1.6
1.4
1.7
1.6
1.4
1.6
1.7
1.5
.
S,%
0.8
1.9
1.9
2.5
2.1
0.7
4.6
3.3
1.1
4.1
BTU
HV,lb
15,670
15,615
15,540
15,630
15,265
15,370
14,730
14,430
14,260
14,400
Ratio
H:C
0.053
0.054
0.054
0.059
0.064
0.064
0.070
0.068
0.070
0.072
Predicted
C,%
87.5
87.2
86.8
87.3
85.3
85.9
82.3
80.6
79.7
80.4
For these ten coals, the root-mean-square difference between the measured
and predicted values for percent carbon is 1.4 percent, verifying the
accuracy of the Ushling relationship for bituminous coals.
Another Ushling relationship is that the ratio of hydrogen to carbon
varies little among coals of the same rank. From the above data for
the ten bituminous coals, a value of 0.064 was adopted for this ratio,
and the percent hydrogen was derived for the three raw coals of Table 6-1
from the percent carbon values. An additional relationship from the above
data is that the nitrogen percentage (on a dry, ash-free basis) is relatively
constant - a value of 1.6 percent was used in Table 6-1.
With these three relationships/ the values for carbon, hydrogen, and
nitrogen on a dry, ash-free basis were developed for the three raw coals.
Since the total percent sulfur was known, the oxygen percentage was derived
by difference, enabling the entire ultimate analysis to be estimated.
Similarly, the starting points for the products of physical coal
cleaning (POC) processes were the proximate analyses previously given in
Tables 3-16, 3-17, and 3-18. The moisture contents for the PCC products
534
-------
for the low sulfur eastern and low sulfur western coals, not previously
reported, were derived from the material flows shown on Figures 3-7 and
3-10 by using the same inherent moisture contents as the respective raw
coals and by using the following appropriate values for surface moisture
(as a function of size consist):
Coal Type
Low Sulfur Eastern
Low Sulfur Western
Product Stream No.
1
2
3
1
2
Size Consist
3/8 x 28M
28M x 0
1 1/4 x 3/8
1/4 x 0
1 1/4 x 3/8
Surface
Moisture, %
6.0
15.0
4.0
9.0
4.0
1
Since the physical coal cleaning processes do not change the inherent
character of the "pure" coal, it was assumed that the relationships
previously developed for raw coal ultimate analyses (on a dry, ash-free
basis) also apply to cleaned coals; enabling Table 6-1 to be developed
for these physically-cleaned coals.
Several additional assumptions were necessarily made for Table 6-1
to be completed for chemical coal cleaning (CCC), since proximate analyses
were not previously given for the CCC products. First, it was assumed
that the CCC products were dried to the same moisture levels as the raw
coal feeds. It was assumed that the ERDA process results in the same
percent ash as the raw coal feeds, but that the Gravichem process results
in a product with 0.25 (first step) x 0.75 (second step) = 0.1875 of the
ash content of the raw coal feeds. Further, it was assumed that CCC
products had the sane heating valua and percentages of carbon, hydrogen,
and nitrogen (on a dry, ash-free basis) as the raw coal feeds.
In the removal of mineral constituents not containing sulfur, it has been
determined that some trace elements tend to be associated with the coal
535
-------
fraction and sane (roost) with the mineral fraction. ' ' ' These
distribute themselves between the coal and the waste with the distribution
varying as a function of the specific gravity at which the separation is
made. These fractionation factors also vary significantly among different
coals and no generalized average or "standard" values are possible. As
a result, the calculation of possible trace element emissions from the
boiler cannot be performed and no trace element emission values will be
presented in this analysis. The study results and their implications are
discussed further in Section 6.2.1.4.
Combustion Stoichiometry
The ultimate analyses for the raw and cleaned coals are presented
on Table 6-2 on a conrcn basis of one kilogram of moisture-free fuel.
These values/ in grams of each element per kilogram of dry fuel/ were
converted to gram atoms per kilogram, from which the stoichiometric
air requirements and major combustion products (G02, H2O, and SO2) were
derived. Further, the oxygen and nitrogen in the combustion gases, and
then the total moles and standard volumes of combustion gas, were
calculated for 0, 30, and 50 percent excess air.
Also included in Table 6-2, at the 30 and 50 percent excess air levels,
are the number of gram moles of NO2, CD, and hydrocarbons as CHi,, per
kilogram of fuel burned. The values for each of these secondary products,
at each level of excess air, are constant regardless of fuel type- This
was directly derived from the EEECo-provided design parameters for standard
boilers, summarized in Table 6-3, which stated an emission rate for ISO ,
x (9)
CO, and CHi» directly proportional to the fuel feed rate for each boiler.
The molar quantities per kilogram of fuel shown in Table 6-2 correspond
to the weight percentages in Table 6-3.
It may be argued that the quantities of these secondary products
should be based upon the thernDdynamic combustion of each fuel with
the appropriate quantities of excess air. A rigorous approach would be
to derive the equilibrium flame temperature for each fuel/air case of
Table 6-2 from the heat of combustion of one kilogram of each fuel, and
the heat capacities (as a function of temperature) and corresponding quanti-
536
-------
T7VBLE 6-2.
CCMHJSTION STOICHICMETOY CF PAW AND CLEANED CCftLS
BASIS: ONE KILOGRAM OF MOISTURE-FREE COAL FEED
.3
*
•x)
if
p
b<
r-<
&
1{M
4J Q
4|]
S a
3 5i M
« 4J * n .3
B**0^5
Products At
30% Excess Air
Produces At
. 50% Qccess Air
gms C
gms H
qms S
gms 0
gms N
gms Ash
gms H80
gin atoms C
gm atoms H
gm atoms S
rpri atoms 0
gm atcms N
gm moles HzO
gm moles Oj
gm moles Nz
gm moles Air
qm moles OOj
gm noles HZO
gm noles SO?
gm moles Nj
total gra moles
Total Std m3
gm moles 02
gm roles Nz
gm moles NOj
gm moles OO
gm noles CH»
Total gm moles
total Stxi m'
gm moles Oj
gm moles NI
gm noles NOi
gm moles 00
gm moles CHH
Ibtal gm moles
Tbtal Std m'
Iligh-Sulfur Eastern Coal
Raw Cbal
655.8
42.0
34.0
21.9
12.3
234.0
52.6
54.60
41.67
1.0603
1.37
0.88
2.92
65.39
246.00
311.39
54. 60
23.76
1.0603
246.44
325.9
7.305
19.62
320.24
0.1956
0.01785
0.00935
419.3
9.398
32.70
369.44
0.1630
0.03570
0.03117
481.6
10.795
Deep-Cleaned PCC
805.9
51.6
10.8
58.6
15.1
58.0
98.9
67.10
51.19
0.3368
3.66
1.08
5.49
78.41
294.96
373.37
67.10
31.09
0.336R
295.50
394.0
8.831
23.52
383.99
0.1956
0.01785
0.00935
506.0
11.342
39.21
442.98
0.1630
0.03570
0.03117
580.7
13.016
Middling PCC
760.4
48.7
16.9
46.7
14.2
113.1
97.6
6J.J1
48.31
0.5270
2.92
1.01
5.42
74.46
280.10
354.5'
63.31
29.58
0.5270
280.61
374.0
8.383
22.34
164.64
0.1956
0.01785
0.00935
480.4
10.768
37.23
420.66
0.1630
0.03570
0.03117
551.3
12.357
ERDA
655.8
42.0
7.4
48.6
12.3
234.0
52.6
54.60
41.67
0.2308
3.04
0.88
2.92 "
63.73
239.74
303.47
54.60
23.76
0.2308
240.18
318.8
7.146
19.11
312.10
0.1956
0.01785
0.00935
409.8
9.186
31.87
360.05
0.1630
0.03570
0.03117
470.5
10.546
Gravichem
818.5
52.4
11.0
58.8
15.3
43.9
52.6
68.15
51.98
0.3430
3.68
1.09
2.92
79.65
299.63
379.28
68.15
28.91
0.3430
300.18
397.6
8.912
23.90
390.06
0.1956
0.01785
0.00935
511.4
11.463
39.83
449.99
0.1630
0.03570
0.03117
587.2
13. Ifi2
lew-Sulfur Eastern Coal
Raw Coal
761.0
48.7
11.8
60.4
14.3
103.8
20.4
63.36
48.31
0.3680
3.78
1.02
1.13
73.92
278.06
351.98
63.36
25.29
0.3680
278.57
367.6
8.240
22.18
3G2.-01
0.1956
0.01705
0.00935
473.2
10.607
36.96
417.63
0.1630
0.03570
0.03117
543.6
12.185
PCC Product
813.8
52.1
8.9
68.6
15.3
41.3
80.7
67.76
51.69
0.2776
4.29
1.09
4.48
78.82
296.49
375.31
67.76
30.33
0.2776
297.04
395.4
8.863
23.65
306.01
0.1956
0.01785
0.00935
508.0
11,387
39.41
445.31
0.1630
0.03570
0,03117
583,.!
13.070
ERDA
761.0
48.7
3.9
68.3
14.3
103.8
20.4
63.36
48.31
0.1216
4.27
1.02
1.13
73.42
276.21
349.64
63.36
25.29
0.1216
276.72
365.5
8.193
22.03
359.58
0.1956
0.01785
0.00935
470.4
10,544
36.71
414.83
0.1630
0.03570
0.03117
540.3
12.111
Gravichem
832.5
53.2
5.6
73.4
15.7
19.5
20.4
€9.32 "
52,78
0.1746
4.59
1.12
1.13
80.39
302.44
382.83
69.32
27.52
0.1746
303.00
400.0
8.965
24.12
393.73
0.1956
0.01785
0,00935
514. 9-
11,541
40.20
454.22
0.1630
0.03570
0.03117
591.4
13.256
Low-Sulfur Vfestem Coal
Raw Coal
630.9
40.4
5.9
62.7
12.0
248.1
25.6
52.53
40.08
0.1840
3.92
0.86
1.42
60.77
228.63
289,40
52.53
21.46
0.1840
229.06
302.9
6.789
18.23
297.62
0.1956
0.01785
0.00935
389.7
8.735
PCC Product
701.3
44.9
6.5
68.9
13.4
165.0
77.8
58.39
44.54
0.2027
4.31
0.96
4.32
67.57
254.20
321.77
58.39
26.59
0.2027
254.68
339.9
7.61?
20.27
330.93
0.1956
j 0.01785
0.00935
436.4
*.7B2
30.39 33.79
343.35 381.77
0.1630 0.1630
0.03570 0.03570
n.ntui ! 0.03117
447.6 500.7
10.033 1 11.223
Ul
u>
-------
6-3 . REUVAM1 Q««M.'TERISTICS OF TME RETERPCE COMrFIRED INDUSTRIAL BOIICTS
Source: Acurex Design Parameters for Standard Boilers
en
CO
03
No.
1
2
3
4
Boiler Specifications
Boiler TVpe
Package, Water-
tube, Underfeed
Stoker
Package, Mater-
tube, Chain
Grate
Field-Erected,
Watertube,
Spreader
Stoker
Field-Erected,
Water tube,
Pulverized
Coal
Heat Input Bate
kW 10'BlU/hr
8,790 30
21,975 75
43,950 150
58,600 200
Excess
Air,
Percent
50
50
50
30
Uncontrolled Flue Gas Constituents
Flyash
% of Goal Ash
25.0
25.0
65.0
80.0
SOt,% of
Coal SOj
95.0
95.0
95.0
95.0
HO , % of
Coal Feed
0.75
0.75
0.75
0.90
CO, % of
Coal Feed
0.10
0.10
0.10
0.05
1C as CH» ,
% of Goal Feed
0.05
0.05
0.05
0.015
-------
ties of the combustion products, including ash and moisture. The equilibrium
constants for NO2, NO, CO, and CHi, may then be evaluated (from the free
energy change) at that flame temperature, enabling the calculation of
equilibrium concentrations of these secondary products. Short of this
rigorous approach, it may also be argued that the quantities could be
assumed directly proportional to the heat input rate for each boiler
rather than to the fuel feed rate.
After consideration of these alternative approaches, the values for
NC>X, CD, and CH^ shown in Table 6-2 (and subsequently used to derive emission
rates) were chosen to be consistent with the PEDCo values implicit in
their "Design Parameters for Standard Boilers".(19}
Calculations of Emission Rates
Tables F-l through F-4 in Appendix F, list the gross emission rates
(for each pollutant and for each fuel), respectively, for each of the four
standard industrial boilers. The derivation of each column in these
tables begins with the calculation of the dry coal feed rate, kg/s, by
dividing the boiler heat input rate in kJ/s by the dry coal heating value
in kJAg. This dry coal feed rate is then the multiplier for the values
in each column of Table 6-2 (which are based upon one kilogram of dry coal
feed), to derive the rates shown in Tables F-l through F-4.
The total ash values of Tables F-l through F-4 are the quantities in
the coal feed; the flyash values were derived from the fraction (specific
to each boiler) defined by PEDGo and summarized in Table 6-3. Also in
accordance with pEDCtM assumptions, the SO2 values in Tables F-l through F-4
are 95 percent of the stoichiometric quantities. ^10^
Presentation of Emission Rates
The final results of these calculations are presented in Table 6-8.
The uncontrolled case and the SIP case have been added to the BSER boiler/
control level cases (defined in Table 3-22). Those boiler/control combina-
tions in Tables F-l through F-4 which were not selected as BSER combinations
are not included in Table 6-4.
539
-------
Table 6-4. Air Pollution Inpacts from "Best" SOZ and Particulate Control Techniques
for Coal-Fired Boilers
SYSTEM
Coal
Type
High-Sulfur Eastern Coal
•
Standard Boiler
Heat Input
MW(lo"Btu/hr)
8.79OO)
21.975(75)
43.95(150)
5Ft.fiO(200)
_Type
Underfeed
Stoker
Chain Grate
Spreader
Stoker
Pulverized
Coal
Control
Level
Uncontrolled
SIP
Moderate
Intermediate
Stringent
Uncon trolled
SIP
Moderate
Intermediate
Stringent
Uncontrolled
SIP
Moderate
Intermediate
Stringent
Uncontrolled
SIP
Modsrate
Intermediate
Stringent
SOj Control
Type
Raw Coal
POCV Middling
FCCV Middling
POCV Deep-Cl.
CCC-ERDA
Raw Coal
PCCV Middling
PCCV Middling
PCTV Deep-Cl.
CCC-ERDA
Raw Coal
PCCV Middling
POCV Middling
PCCV Deep-Cl.
CCC-ERDA
Raw Coal
PCCV Middling
PCCV Middling
PCCV Deep-Cl.
CCC-ERDA
Pet
Reduction
0
57.1
57.1
74.1
78.2
0
57.1
57.1
74.1
78.2
0
57.1
57.1
74.1
78.2
0
57.1
57.1
74.1
78.2
Particulate
Pet. Reduction
Coal
Cleaning
0
58.3
58.3
79.8
0
0
58. 3
58.3
79.8
0
0
58.3
58.3
79.8
0
0
58.3
58.3
79. B
0
ESP
0
71.1
88.0
90.1
99.4
0
71.1
88.0
90.1
99.4
0
88.9
95.4
96.2
99.8
0
91.0
96.2
96.9
99.8
EMISSIONS
90
a
s
21.54
8.91
8.91
5.37
4.52
53.84
22.26
22.26
13.42
11.31
107.68
44.53
44.53
26.85
22.61
143.57
59.36
59.36
35.80
30.15
31
2451
1013
1013
611
514
2451
1013
1013
611
514
2451
1013
1013
611
514
2451
1013
1013
611
514
Particulates
2
s
19.62
2.268
0.945
0.378
0.113
49.06
5.670
2.362
0.945
0.283
255.09
11.339
4.724
1.890
0.567
418.61
15.119
6.298
2.520
0.756
^
2233
258.0
107.5
43.0
12.9
2233
258.0
107.5
43,0
12.9
5806
258.0
107.5
43.0
12.9
7146
258.0
107.5
43.0
12.9
W3x
2
s
?.46
2.08
2.08
1.97
2.41
6.16
5.20
5.20
4.91
6.04
12.32
10.41
10.41
9.82
12.07
19.71
16.65
16.65
15.72
19.31
3s
280
237
237
223
275
280
237
237
223
275
280
237
237
223
275
336
284
284
268
330
CO
2
B
0.328
0.278
0.278
0.262
0.822
0.695
0.695
0.655
0.804
1.643
1.389
1.389
1.311
1.611
1.095
0.924
0.924
0.874
1.073
3*
37.3
31.6
31.6
29.8
37. J
31.6
31.6
29.8
36.6
37.3
31.6
31.6
29.8
36.6
J8.7
15.8
15.8
14.9
18.3
liC as CHt
2
s
0.164
0.139
0.139
0.131
J.411
0.347
0.347
0.327
0.403
d.822
O.G95
0.695
0.655
0 . 805
0.328
0.27R
0.278
0.261
0.322
S2
18.7
15.8
15.8
14.9
18.7
15.0
15.8
14.9
18.3
18.7
15.8
15. R
14.9
18 . 3
5.60
4.74
4.74
4.4r>
5.49
Ul
£»
O
-------
Table 6-4.
Air Pollution Impacts from "Best" SO2 and Particulate Control Techniques
for Coal-Fired Boilers (Con't)
Ul
SYSTEM
Coal
Type
Lo/f-Sulfur Eastern Coal
Standard Boiler
Heat Input '
MWdO^Dtu/hr)
8.79(30)
21.975(75)
43.95(150)
58.60(200)
Type
Underfeed
Stoker
Chain Grate
Spreader
Stoker
Pulverized
Coal
Control
level
Uncontrolled
SIP
Moderate
Intermediate
Stringent
Uncontrolled
SIP
Moderate
Intermediate
Stringent
Uncontrolled
SIP
Moderate
Intermediate
Stringent
Uncontrolled
SIP
Moderate
Intermediate
Stringent
SO2 Control
Type
Raw Coal
Raw Coal
Raw Coal
PCC W
PCC IV
Raw Coal
Raw Coal
Raw Coal
PCC rv
PCC IV
Raw Coal
Row Coal
Raw Coal
PCC IV
PCC IV
Raw Coal
Raw Coal
Raw Coal
PCC IV
PCC IV
Pet.
Reduction
0
0
0
29.5
29.5
0
0
0
29.5
29.5
0
0
0
29.5
29.5
0
0
0
29.5
29.5
Particulate
Pet. Reduction
Coal
Cleaning
0
0
0
62.8
62.8
0
0
0
62.8
62.8
0
0
0
62.8
62.8
0
0
0
62.8
62.8
ESP
0
68.5
86.9
85.9
95.8
0
68.5
86.9
85.9
95. R
0
87.9
95.0
94.6
98.4
0
90.2
95.9
95.6
98.7
EMISSIONS
S02
a
s
6.21
6.21
6.21
4.38
4.38
15.53
15.53
15.53
10.96
10.96
31.07
31,07
31.07
21.92
21.92
41.43
' 41.43
41.43
29.22
29.22
f
707
707
707
499
499
707
707
707
499
499
707
707
707
499
499
707
707
707
499
499
Particulates
a
s
7.20
2.268
0.945
0.378
0.113
18.00
5.670
2.362
0.945
0.283
93.6
11.339
4.724
1.890
0.567
153.6
15.119
6.298
2.520
0.756
IS
J
819.1
258.0
107.5
43.0
12.9
819.1
258.0
107.5
43.0
12.9
2130
2-58.0
107.5
43.0
12.9
2621
258.0
107.5
43.0
12.9
NO*.
a
s
2.08
2.08
2.08
1.95
1.95
5.20
5.20
5.20
4.86
4.86
10.40
10.40
10.40
9.73
9.73
16.65
16.65
16.65
15.56
15.56
3*
237
237
237
221
221
237
237
237
221
221
237
237
237
221
221
284
284
284
266
266
CO
a
5
0.277
0.277
0.277
0.259
0.259
0.695
0.695
0.695
0.650
O.firi0
1.38G
1.386
1.3R6
1.297
1.207
0.924
0.924
0.924
0.866
0 . 866
ng
J
31.6
31.6
31.6
29.6
29.6
31.6
31.6
31.6
29.6
29.6
31.6
31.6
31.6
29.6
29. r,
23.7
23.7
23.7
22.3
22.1
1C as CII,
a
s
n.139
0.139
0.139
0.130
0.130
0.347
0.347
0.347
0. 324
0.324
0.693
0.693
O.f.OB
0.r,4H
0.f,4R
0.278
(1.278
0.27R
O.?60
ng
,1
15.8
15.8
15.8
14.7
1.4.7
15.8
15.8
15.8
14.7
14.7
15.8
15.8
l.r..n
14.7
14.7
4.74
4.74
4.74
4.44
4.44
-------
Table 6-4. Mr PolluBon Inpacta from "Beat" S02 arid Particulate Control Techniques
for Coal-Fired Boilers (Con't)
SYSTEM
Coal
Type
Low-Sulfur Western Coal
Standard Boiler
Heat Input
MW(10sntu/hr)
8.79(30)
21.975(75)
43.95(150)
58.60(200)
Type
Underfeed
Stoker
Chain Gate
Spreader
Stoker
Pulverized
Coal
Control
Level
Controlled
SIP
Moderate
Internodiate
Stringent
Uncontrolled
STP
Moderate
Intermediate
Stringent
Uncontrolled
SIP
Moderate
Intermediate
Stringent
Uncontrolled
SIP
Moderate
Intermediate
Stringent
SOz Control
Type
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Raw Coal
Pet.
Reduction
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Particulate
Pet. Reduction
Coal
Cleaning
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
ESP
0
69.1
95.4
98.2
99.5
0
89.1
95.4
98. 2
99.5
0
95.8
98.2
99.3
99.8
0
94.4
97.7
99.1
99.7
EMISSIONS
S02
a
B
3.75
3.75
3.75
3.75
3.75
9.37
9.37
9.37
9.37
9.37
18.74
18.74
18.74
18.74
18.74
24.99
24.99
24.99
24.99
24.99
§*
426
426
426
426
426
426
426
426
426
426
426
426
426
426
426
426
426
426
426
426
Particulates
a
8
20.75
2.268
0.945
0.378
0.113
51.89
5.670
2.362
0.945
0.283
269.8
11.339
4.724
1.890
0.567
442.8
15.119
6.298
2.520
0.756
s»
2361
258.0
107.5
43.0
12.9
2361
258.0
107.5
43.0
12.9
6139
258.0
107.5
43.0
12.9
4604
258.0
107.5
43.0
12.9
NDv
1
8
2.51
2.51
2.51
2.51
2.51
6.28
6.28
6.28
6.29
6.28
12.55
12.55
12.55
12.55
12.55
20.08
20.08
20.08
20.08
20.08
3*
286
286
286
286
286
286
286
286
286
286
286
286
286
286
286
343
343
343
343
343
CO
a
B
0.335
0.335
0.335
0.335
0.335
0.837
0.837
0.837
' 0.837
0.837
1.672
1.672
1.672
1.672
1.672
1.115
1.115
1.11P
1.115
1.115
?
38.0
38.0
38.0
38.0
38.0
38.0
38.0
38.0
38.0
38.0
38.0
38.0
38.0
38.0
38.0
19.0
19.0
19.0
19.0
19.0
1C as CH,
a
s
0.167
0.167
0.167
0.167
0.167
0.419
0.419
0.419
0.419
0.419
0.837
0.837
0.837
0.837
0.837
0.335
0.335
0.335
0.335
0.335
3*
19.1
19.1
19.1
19.1
19.1
19.1
19.1
19.1
19.1
19.1
19.1
19.1
19.1
19.1
19.1
5.72
5.72
5.72
5.72
5.72
-------
6.2.1.2 Discussion of Air Pollution Inpacts—
Sulfur Dioxide
The SO2 emissions data in Table 6-4 show that the stringent SO2 emission
control level of 516 ng/J (1.2 lb/106 BTU) may be achieved for the two Eastern
representative coals through application of physical or chemical coal
cleaning technologies. This stringent control level is directly achieved by
the raw low sulfur western coal. The intermediate control level of 645 ng/J
(1.5 lb/106 BTU) is met, for the Eastern coals, with physical coal cleaning
technologies, without the necessity for chemical cleaning.
Particulates
Although physical and chemical coal cleaning technologies remove
considerable quantities of ash from the coal, the residual amounts must
still be controlled, to meet the following control levels:
SIP 258.0 ng/J (0.60 lb/106 BTU)
MDderate 107.5 ng/J (0.25 lb/106 BTU)
Intermediate 43.0 ng/J (0.10 lb/106 BTU)
Stringent 12.9 ng/J (0.03 lb/106 BTU)
Table 6-4 lists two removal efficienoes 'for particulates: the percent
reduction of the raw coal ash content achieved by coal cleaning; and the
percent reduction of the flyash required, by an ESP or other control, to
meet the appropriate particulate emission control level. A third factor is the
fraction of the fuel ash content which is removed as bottom ash: this
boiler-specific factor, defined by PEDOo is in Table 6-3.
The particulate emission rates in Table 6-4 are equivalent to the
appropriate emission control levels, implying that the effectiveness of post-
combustion particulate control devices is tailored (through design and
operation) to achieve these levels. Under this strategy, there is no
differential air pollution particulate impact resulting from coal cleaning
as a sulfur dioxide control technology.
Nitrogen Oxides, Carbon Monoxide, and Hydrocarbons
The section on combustion stoichiometry contained a brief discussion
of the validity of the method for determining the emission rates for N0x/
543
-------
CD, and hydrocarbons which are listed in Table 6-4. The selected method,
based upon PEDco definitions of reference boiler design parameters, results
in a reduction of emissions for these substances from removal of ash by coal
cleaning processes. This calculated reduction in emissions approaches 20
percent in those cases where coal cleaning removes large quantities of ash.
However, the alternate estimating method - where emissions of NO , 00,
and hydrocarbons are directly proportional to heat input rate rather than
to coal feed rate - would result in no differential impact of coal cleaning.
It is observed, from Tables F-l through F-4, that for a given reference
boiler (and its constant heat input rate), the total gram moles per second
or standard cubic meters per second of gaseous emissions varies little
with coal type and with level of cleaning, ftoreover, the molar composition
of the emissions also is fairly constant. With large quantities of excess
air, the total heat capacity of the ash is a very small fraction of the
total heat capacity of gaseous combustion products, so that varying quantities
of ash should not have a significant effect upon the equilibrium flame
temperature.
Based upon the above considerations, it is concluded that there is
minimal differential impact of coal cleaning upon NO , CO, and hydro-
carbons emissions.
Air Emission Sensitivity Analysis
Air emissions from the combustion of cleaned coal in various sized
boilers, include SO , NO , CO, and HC. Progressive reduction of SO
X X X
emissions from boilers is accomplished with increased cleaning of sulfur
from the raw coal, however, as we stated above, there is minimal
differential impact of coal cleaning upon NO , CO, and hydrocarbons emissions.
X
Emission differences from different sized boilers are also minimal.
544
-------
In the case of stoker fired boilers (8.8, 22, and 44 Mtf) the size of
the boiler has a negligible effect upon the normalized quantity (i.e., ng/J)
of emissions (see Table 6-5). The emission rate is inherent to the coal
type used, whether it be raw or cleaned. The same scenario applies to
pulverized fired boilers (58.6 and 73 Mtf and 118 Mfl) such that the levels of
emissions per Joule remain constant for each boiler size. However,
differences do exist in emission levels of pollutants between the two boiler
types. For example, carbon monoxide and hydrocarbon emissions from coal
combustion are noticeably lower from pulverized boilers than from stoker
fired boilers (i.e., 50% lower for CD and 70% lower for Hydrocarbons). Ihe
opposite is true for NO emissions since emissions are 17% higher from
a
pulverized boilers than from stoker fired boilers. SO emissions remain
J\.
constant for both stoker and pulverized fired boilers.
6.2.1.3 Differential Impacts Compared to SIP-Controlled Boilers—
Table 6-6 lists the emissions at the SIP control level, taken directly
from Table 6-4, and also lists the differential emissions for each coal
type when BSER coal cleaning technologies are applied.
The reductions in particulate emissions, from the SIP control level
to the moderate, intermediate and stringent control levels, are (respectively)
58 percent, 83 percent, and 95 percent. They are the same regardless of
fuel type or boiler type and size; and are achieved by combinations of
coal cleaning ash removal and post-combustion particulate control devices.
For other than particulate emissions, no reduction occurs between the
SIP control level and the moderate control level. For all three coal types,
the same control technologies and degrees of application were used for
both levels. Moreover, since the raw low sulfur western coal meets the
545
-------
TfELE 6-5. SENSmvnY ANAI2SIS
Bnission Values Shown in. Tables are Constants for Their Respective Boiler 'types
I. Air QnLssions (ng/J)
A. High Sulfur Eastern Cbal
Type of Control
90 : Raw Coal
PCC VMiddlings
PCC V Deep-d.
CCC - ERDA
MO : Raw Coal
PCC V MID
PCC V Deep-d.
CCC - ERDA
CO: Raw Coal
PCC VMID
PCC V Deep d.
CCC - ERDA
HC: Raw Coal
PCC V MED.
PCC V Deep d.
CCC - ERDA
Stoker Boiler
(8.8 M, 22 W, 44 VU)
2451
1013
611
514
275
237
223
275
36.6
31.6
29.8
36.6 *
18.3
15.8
14.9
18.3 *
Pulverized Boiler
(58.6M*, 73 W, 118 tW)
2451
1013
611
514
336
284
268
330
18.7
15.8
14.9
18.3
5.60
4.74
4.45
5.49
* Does not include 8.8 M*
546
-------
TABLE 6-5. SENSITIVITY ANALYSIS (continued)
B. lew Sulfur Eastern Coal
Type of Control
S0x: Raw Coal
PCC IV
NO : Raw Coal
PCC IV
CO: Raw Coal
PCC IV
HC: Raw Coal
PCC IV
Stoker Boiler
(8.8 Mi, 22 Mf, 44 M¥)
707
499
237
221
31.6
29.6
15.8
14.7
Pulverized Boiler
(58.6 W, 73 f*J)
707
499
284
266
23.7
22.1
4.74
4.44
C. low Sulfur Western Coal
SO : Saw Coal 426
NO : Raw Coal 286
CO: Raw Coal 38.0
HC: Raw Coal 19.1
426
343
19.0
5.72
547
-------
TABLE 6-6. DIFFERENTIAL IMPACTS COMPARED TO SIP - CONTROLLED BOILERS
Cbal Type
Control
level
Qnissions
at
SIP
Level
ng/J
Emission
Reductions i
Moderate
Level,
ng/J
mission
Reductions
at
Intermediate
level
ng/J
Emission
Reductions i
Strincjent
Level,
ng/J
MW
Pollutant
S02
Part.
!5x
CO*
HC
SO,
it Part.
fB<
07*
nc
S02
Part.
NO
or
HC
High-Sulfur Eastern Coal
3.8 22 44 58.6
30 75 150 200
1,013 1,013 1,013 1,013
258 258 258 258
237 237 237 284
31.6 31.6 31.6 15.8
15.8 15.8 15.8 4.74
00 00
150.5 150.5 150.5 150.5
00 00
00 00
00 00
402 402 402 402
215 215 215 215
14 14 14 16
1.8 1.8 1.8 0.9
0.9 0.9 0.9 0.29
S02 499 499 499 499
t Part. i 245.1 245.1 245.1 245.1
NO ! 0 0 0 0
CO* 0 0 00
HC 0 0 0 0
low-Sulfur Eastern Coal
8.8 22 44 58.6
30 75 150 200
707 707 707 708
258 258 258 258
237 237 237 284
31.6 31.6 31.6 23.7
15.8 15.8 15.8 4.74
00 00
150.5 150.5 150.5 150.5
00 00
00 00
00 00
208 208 208 208
215 215 215 215
16 16 16 18
2.0 2.0 2.0 1.6
1.1 1.1 1.1 0.30
208 208 208 208
245.1 245..1 245.1 245.1
16 16 16 IB
2.0 2.0 2.0 1.6
1.1 1.1 1.1 0.30
Lew-Sulfur Western Coal
8.8 22 44 58.6
30 75 150 200
426 426 426 426
258 258 258 258
286 286 286 343
38.0 38.0 38.0 19.0
19.1 19.1 19.1 5.72
00 00
150.5 150.5 150.5 150.5
00 00
00 00
00 00
00 00
215 215 215 215
00 00
00 00
00 00
00 00
245.1 245.1 245.1 245.1
00 00
00 00
00 00
00
-------
stringent emission level (for SO2) without cleaning, no differential exists
among an the control levels for SO2, NO , 00, and hydrocarbons for this
Ji
coal type.
At the intermediate control level, the SO2 emission reductions compared
to the SIP control level are 40 percent for the high sulfur eastern coal and
30 percent for the low sulfur eastern coal. Ihe NO , CD, and hydrocarbon
•**
emission reductions are about 7 percent for both the high sulfur and low
sulfur eastern coals.
At the stringent control level, the SO2 emission reductions compared
to the SIP control level are 49 percent for the high sulfur eastern coal
and 30 percent (the same as the intermediate differential) for the low
sulfur eastern coal. For the high sulfur eastern coal, no change occurs
(between the SIP and stringent levels) in NO , CD, and hydrocarbon
X
emissions, because the EKDA chemical coal cleaning technology employed
to achieve the stringent SO2 emission level is much less effective in
reducing ash content than physical coal cleaning techniques. For the
low sulfur eastern coal, the differentials in NO ,00, and hydrocarbon
' Jv
emissions are the same for the stringent level as for the intermediate
level.
6.2.1.4 Further Reduction of Boiler Emissions—
Sulfur Dioxide
In the preceding discussion the effectiveness of SOz controls by
coal cleaning was shown to depend upon the washability characteristics of
the raw coal and upon the level of coal cleaning technology selected.
For controlling SCfe emissions from the representative high sulfur eastern
coal, the level of coal cleaning required to meet the stringent emission
standard of 516 ng/J (1.20) lb/105 BTU) was close to the most advanced
techniques available - chemical coal cleaning with removal of some
organic sulfur as well as most pyritic sulfur. In this case, there is
little potential (with presently-available technology) for further reducing
the SO2 emissions beyond the stringent control level.
However, coal cleaning could be more effective than shown in Tables
6-4 and 6-6 when applied to the two low-sulfur coal types. For the low-
sulfur eastern coal, the stringent emission control level was achieved using
549
-------
level 4 physical coal cleaning technology. The application of deeper physical
cleaning techniques or of chemical cleaning techniques to this representative
raw coal could substantially reduce the S02 emissions. Based upon the calcu-
lations in Tables F-l through F-4 the application of the ERDA chemical coal
cleaning process to the low-sulfur eastern coal could result in a S02 emission
level of 233 ng/J (0.54 lb/106BTO). For the low-sulfur western coal, an emissions
level of 426 ng/J (0.99 lb/106HTU) was achieved without any cleaning. if
deep physical coal cleaning or chemical coal cleaning technologies were
applied to this raw coal, the S02 emissions might be reduced by 50 percent.
The potential for SO2 emission reductions indicated by the above discussion
may be extended, for any particular industrial boiler, through the application
of fuel blending techniques. Some cleaned low-sulfur eastern coal or some low-
sulfur western coal, for example, might be blended with deep physically-cleaned
high-sulfur eastern coal to achieve the most stringent emission control levels with
out necessitating the more costly chemical coal cleaning technologies.
Further, the application of pre-combustion coal cleaning technologies for
SO2 control does not preclude the use of other technologies (fluidized bed
combustion or flue gas desulfurization) for achieving further SO2 reductions.
Alternatively, the application of a combination of technologies for achieving
a stringent SO2 emission control level might prove less costly than either alone.
Particulates
lable 6-4 lists the particulate emissions consistent with SIP, moderate,
intermediate, and stringent control levels, and the required removal efficiencies
of electrostatic precipitators (or other post-combustion control devices).
Further reductions in particulates emissions may be achieved if higher ESP
efficiencies are specified in the selection of such units.
Alternatively, lower particulates emissions may be achieved with an
existing ESP unit by utilizing physical coal cleaning processes which remove
greater percentages of the ash from the raw coal. Two applications are
550
-------
immediately evident from the "particulate percent removal-coal cleaning"
column of "Sable 6-4. First, the zero-percent ash removal from low-sulfur
western coal is a consequence of the fact that the stringent Sty control
level is net without requiring coal cleaning. The high (24.81 percent)
ash content of this raw coal could readily be reduced by more than 50 per-
cent by physical coal cleaning techniques. This would reduce boiler
particulate emissions without requiring increased ESP efficiency. Such ash
removal via coal cleaning may be economically justified solely on the
basis of reduced coal transportation costs.
Second, the stringent SQj control level is met for the high-sulfur eastern
coal through application of the ERDA chemical coal cleaning process, which
does not result in a high removal of ash from the raw coal. Ey using physical
coal cleaning techniques prior to ERDA process, large reductions in coal
ash (and thus in boiler particulate emissions for a given ESP efficiency)
nay be achieved. This initial cleaning step may be economically justified on
the basis of reduced throughput requirements for chemical coal cleaning
process equipment.
Nitrogen Oxides, Carbon Monoxide, and Hydrocarbons
The use of greater amounts of excess air in the boiler is a technique
for reducing the emissions of carbon monoxide and hydrocarbons by promoting
more complete combustion. However, this technique results in lower boiler
efficiencies due to the greater heat loss in the flue gas. Boiler design
and operation technology, including proper maintenance, are utilized for
achieving more complete combustion and thereby reducing the CD and hydro-
carbon emissions.
The emission factors specified by Acurex for the standard boilers, which
are summarized in Table 6-3, include a higher NO emission at reduced excess
J\.
air. This factor is 0.90 percent of the coal feed at 30 percent excess
air, compared with 0.75 percent of the coal feed at 50 percent excess air.
Equilibrium flame temperatures are higher at reduced quantities of excess
air, resulting in a significantly higher equilibrium constant for the pro-
duction of NO from nitrogen and oxygen. Since the rate of NO dissociation
x ' x
551
-------
is normally not high enough to reestablish equilibrium upon cooling of
the combustion gases, NO emissions are highly sensitive to the peak
jt
temperature experienced in the boiler. Effective NO controls currently
JC
used limit the peak temperature through two-stage combustion.
6.2.1.5 Bnission of Toxic Substances—
The unburned hydrocarbons in boiler emissions include specific substances
identified as potential carcinogens. These substances are the pyrolysis
products of the polyaromatic hydrocarbons in the feed coal. The key towards
minimizing emissions of hazardous organics is in achieving more complete
combustion, through improved boiler design, operation and maintenance, and
to some extent through the use of larger excess air quantities. To the
extent that coal cleaning improves boiler operation by providing a fuel
with much lower quantities of ash (and the subsequent slag), this technology
might aid in the reduction of toxic organic substance emissions.
With regard to the air pollution impact of trace elements in coal, two
partitioning processes must be considered: the fate of these elements in
the coal cleaning process, which determines how much of each element
originally in the raw coal reports in the clean coal product; and the fate
of the elements in the combustion process, which determines how much of
each element originally in the fuel reports in the particulate emissions
from the boiler.
Several studies have been published on the distribution of trace elements
in coal cleaning processes, Ruch, et.al. , Gluskoter, et.al. , and
Schultz, et.al. have reported that float-sink separation of mineral
matter (including pyrite) from coal results in a general partitioning of
heavy metals to the refuse (sink) fraction, leaving the clean coal (float)
fraction with relatively lower heavy metal concentrations. However, the
(it)
results are considerably different from one coal to another. Hamersma, et.al.
reported on the distribution of trace elements between refuse and cleaned
552
-------
coal in the Meyers chemical coal cleaning process, with results similar to
those for physical coal cleaning separations. At this point in time, it
is judged that trace element partitioning data exists on too few coal samples
to quantitatively extrapolate the published data to the three reference coals
considered in this study.
The second partitioning process is the distribution of trace elements
between emissions (gaseous and emitted fly ash) and collected ash (bottom
(15\ (16)
ash plus collected fly ash). Klein, et.al. and Yost, et.al. studied
the pathways of trace elements through coal-fired boilers. Ihe results
indicate that those metals whose oxides are relatively volatile (arsenic,
cadmium, lead, zinc, mercury) form smaller particles upon recondensation
and are more likely to escape collection by an ESP. Again, the quantitative
extrapolation of these results to the reference coals and to the reference
industrial boilers is not justified at this point.
Qualitatively, however, it may be concluded that coal cleaning reduces
the emissions of trace elements from coal-fired boilers via two mechanisms.
First, the preliminary studies indicate that the coal cleaning processes
reduce the concentration of many elements in the coal product. Second, the
heating value enhancement of coal results in less fuel quantity required at
a given boiler input heat rate. This means tuat lesser amounts of trace
elements would be delivered to the boiler even if coal cleaning did not
change the trace element concentration in the fuel.
6.2.1.6. Air Pollution Impacts from Coal Cleaning Plants—
Since all physical coal cleaning process unit operations, exluding
crushing and sizing, for the three reference coals are wet operations,
the major air pollution impact from these processes are the fugitive
553
-------
emissions from coal storage piles and from ooal conveying and loading
(17)
operations. A recent EPA-sponsored program has developed factors
for fugitive emissions from ooal storage piles, based on an extensive
field sampling program. The estimating equation takes into account
major influencing parameters, including wind speed, surface area of the
pile, coal density, and the regional precipitation-evaporation (P-E)
index, all site-specific parameters. Thus, it is clear that universally-
applicable emission factors cannot be developed. The average factor for all
of the field data was reported to be 0.0065 gAg (0.013 Ib/ton) in storage per
year. This value, however, should be used with caution because of large
observed variations.
At this stage of development of chemical coal cleaning process, air
pollution impacts have neither been formally identified nor quantified.
In recognition of the significant air pollution impacts frcm thermal
dryers, none of the coal cleaning processes identified as BSERs in Section 3
have employed thermal drying. Instead, the clean coal product moisture
content has been controlled to approximately 7 to 9 percent by mechanical
dewatering (centrifuging) of individual clean coal streams, each of a different
size consist, and then by blending the several streams in predetermined
proportions.
A recent trade-off study of dewatering and drying, conducted by Versar, Inc.
for EPA, determined that mechanical dewatering was generally preferable to
thermal drying on economic grounds, without considering the environmental
impacts of these alternative operations. For both eccnomic and environmental
reasons, therefore, thermal drying was not included in the Best Systems of
Emission deduction; and consequently, there are no air pollution impacts
attributable to thermal drying.
554
-------
6.3 WATER POLLUTION
6.3.1 Emissions of Water Pollutants from Coal Cleaning
Most coal cleaning operations are performed in aqueous media, which
accumulate suspended and dissolved substances. The water pollutants
directly associated with the cleaning of coal are primarily dissolved and
suspended solids. The dissolved solids are mostly inorganic elements and
compounds leached from the ash fraction during the cleaning process.
Typically physical coal cleaning plants discharge refuse pond (i.e. recycle
pond) overflow, and drainage from coal storage and refuse piles, jybdem
PCC plants attempt to maximize water recycle.
Data available are insufficient to define the composition and quantities
of effluents as a function of coal type or coal cleaning process variations.
The best data available are from an unpublished study by Versar performed
(IQ\
for the EPA.v ' The objective of the study was to determine the best
available technology (BAT) for wastewater pollutants from the coal mining
and preparation point source category. As a part of this study, Versar
was required to perform screening sampling and analysis for 65 classes of
compounds.
In the screening sampling phase of this study, 18 coal preparation
plants associated with mines were visited and wastewater samples were
obtained from 7 of these facilities. In addition, samples of wastewater
were obtained from auxiliary areas such as refuse pile drainage from 5
of these facilities. The results of the screening sampling phase are
(19)
presented in Table 6-7 through 6-9 for cleaning levels 2 and 4.
The process water raw waste characteristics of coal preparation plants
depend upon the particular process or recovery technique used and possibly
the coal processed. Since processing methods require an alkaline media
for efficient and economic operation, process water does not appear to
contain significant amounts of metallic minerals present in the raw coal.
The principal pollutant in preparation plant water is suspended solids.
555
-------
TABLE 6-7. ANALYSES OF WAS1EWATERS AND TREATED STREAMS FROM LEVEL 2 PLANTS -
WATER QUALITY AND METAL PA1&METERS
Ul
U1
en
Parameter (tng/1)
Ibtal Solids
•total Suspendsd Solids
Total Volatile Solids
Volatile Suspended Solids
ODD
roc
pll
Metals (rrg/1)
Aluminum
Antimony
Arsenic
Barium
Beryllium
Uoron
Cadmiun
Calcitm
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Minyaneso
Mercury
Molybdenum
Nickel
Selenium
Silver
Stxlium
Thallium
Tin
Titaniun
Vanadi.vim
yttrium
Zinc
CVariide
Phenol
Plant NC 10
Prep Plant
Itecycle Mater
850
4.0
38
1.6
4.0
2.0
8.1
__
<0.099
.002
.008
.025
<0.002
0.055
<0.02
55.3
<0.024
<0.01
<.004
0.181
<.06
15.8
<.01
0.0004
0.029
-------
TABLE 6-8. ANALYSES OF WASTEWATERS AND TREATED STREAMS FROM LEVEL
4 PLANTS - WATER QUALITY AND METAL PARAMETERS.
flaasinal payjnat m'3 ( ng/1)
•total Solids
Tbtal Suspended Solids
Total Volatile Solids
Volatile Suspended Solids
CCD
TOC
CH
ytetals (rag/1)
Aluminum
Arrtimny
Arsenic
Baxion
Beryllium
Boron
Cadmium
Calcium
r^^ f ^nmuft
Cobalt
Copper
Iron
T««4 .
ttKftTfisim
Manganese
Mercury
MalyhHontim
jaidUi
Seienitm
Silver
Plant NC 3
Prep Plant-.
Slurry
_
—
—
—
—
—
—
—
200
<0.1
<0.01
7.0 .
-------
TABLE 6-9. ANALYSES OF WASTEWATERS AND TREATED STREAMS FROM
LEVEL 4 PLANTS - WATER QUALITY AND METAL P/RAMETERS.
flaeeir'a'J pai jnimlui ^ (jng/1)
Ttotal Solids
Ibtal Suspended Sniicta
Ibtal Volatile Solids
Volatile Susoended sr»t;' «fr»
CCD
TOC
pH
Metals (rag/1)
Aluminum
Antiscny
Arsenic
Banum
Beryllium
Boron
Cadnnum
Ca.Lcixm
f "m^nwn nn%
Gabalt
Copper
Iron
Leal
Magnesium
Manganese
Mercury
Molyladenum
Nickel
Sftleniua
Silver
Sooiucn
Thalliun
Tin
Titaniaa
Vanadium
Yttnua
Zinc
Cyanide
Phenol
Plant JC 11
Prep Plant
Recycle
Pond
680
50
100
5.6
23.3
<1.0
7.2
<0.99
<0.001
0.002
0.11
<0.02
0.09
<0.2
35.0
2.0
<0.1
<0.04
9.0
<0.6
16.0
U.J7
0.0009
<0.1
0.53
<0.001
<0.25
^S77S
<0.001
<0.99
<0.1
<0.99
<0.1
<0.25
-------
Tables 5-7, 6-8 and 6-9 list the inorganic compounds present in
wastewaters from coal preparation plants. Among the priority pollutants
present are antimony, arsenic, asbestos, beryllium, cadmium, chromium,
copper, cyanides, lead, mercury, nickel, selenium, thallium, and zinc
compounds. The concentrations of most of these materials are quite low
and many of these species are at least partially removable by the lime
treatments normally given the wastewaters before discharge. Certain
difficulties were encountered, however. In the analytical procedures
used for this screening study, cadmium, lead, and silver have anomalous
levels reported. Additional specific analyses must be made to provide
more reliable data.
The wastewaters from coal storage, refuse piles, and coal preparation
plant associated areas are characterized as being similar to the raw
mine drainage at the mines served by the preparation plants. Geologic
and geographic setting of the mine and the nature of the coal mined
appear to determine the characteristics of these wastewaters. As the
contents of these waste piles do not appear dependent on the plant
processing operations used, all of these associated area wastewater
problems will be treated as a whole and not subcategorized by plant process
used. A listing of wastewater data for refuse piles for five of the
facilities is given in Table 6-10.
6.3.1.1 Recycling—
In coal preparation plants and associated areas, the major control
technology now in place is the recycle of process water. This technique
is widely practiced and is effective in reducing wastewater discharges.
559
-------
TABLE 6-10.
ANALYSES OF' REFUSE PILE WASTEWATERS - WATER QUALITY
AND METAL PARAMETERS.
Classical Parameters (mg/1)
•total Solids
'total Suspended Solids
•total Volatile Solids
Volatile Suspended Solids
ODD
TOC
P«
Metals (n*j/lj
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmiun
Calcium
Chromium
Cbbalt
OqpLX>r
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel" '"
Selenium
Silver
Sodium
'fltallium
Tin
Titanium
Vanadium
Yttrium
Zinc
Cyanide
Phenols
NC 15
Refuse
Pile Raw
Hater
410
11.4
34
2.2
is.*
3.6
"lib1 '
1.47'
0.002
b.ooS
6.127
< 0.002
0.024
<0.02
26.5
<0.024
0.038
0.006
0.509
<0.06
15.5
2.09
6.0048
<0.01
<0.05
0.003
<0.025
38.8
<6.6ol
<6.694
0.014
<0.099
<0.01
0.168
<6.005
<0.02
.in *
Kg/
day
(11.17)
.31'
.as:
.66'
V142
' .09: )
—
.04)
5xlO-&)
—
—
—
—
—
<.73)
ilxlO"")
IVficfft"1)1
/.614)
.42)
6.36)
1 1.3x10-")
(8x10- 8)
(1.66)
tfxlO-4)
(4.5x10 J)
—
Refuse
Pile
Treated
Effluent
260
62
36
19.6
id.l
5.5
9,7
<6.99
o.ooi
0.004
6.17
<0.02
0.11
<0.2
8.0
<0.24
<0.1
<0.04
1.0
<0.6
3.0
<6.2
6.0643
<0.1
<0.5
0.664
<6.250
65.0
o
*Raw Waste Loads are given for tliose atreams wJuch are discharged either with or without subsequent treatment.
-------
A major factor in achieving recycle of process water is the installation
and operation of efficient dewatering equipment on preparation plant refuse
streams, with consequent reduction of hydraulic loads on refuse impoundments.
Equipment in current use includes dewaterinq screens, Vor-Sivs, and
centrifugal driers. The use of non-acidic water for preparation plant
make-up probably reduces the quantities of priority pollutants present in
the plant discharge and additionally protects the preparation plant equipment
from corrosion.
6.3.1.2 Neutralization—
For associated area wastewaters, neutralization is generally the
treatment of choice. This reduces the acidity and enhances the oxidation
of iron from ferrous to ferric. Ferric hydroxide is less soluble and
easier to settle than ferrous hydroxide. Adjustment of pH is important
before aeration because the oxidization of the ferrous iron increases
the hydrogen ion concentration.
Although there are many methods of neutralization, the two commonly
employed are addition of lime or caustic soda. Lime neutralization
involves making a slurry of lime, with either the acid water or treated
water. This slurry, is then added to the acid mine water in sufficient
quantity to raise the pH to between eight end ten. Caustic soda neutraliza-
tion, employed by a small percentage of the industry, achieves the same
effect as lime addition. Although caustic soda neutralization has been
shown to have a rapid reaction rate and quick response, it is relatively
expensive and harder to handle than lime.
6.3.1.3 Neutralization Plus Settling—
After neutralization is complete, the precipitate (sludge) and the
water may be separated by gravity settling. Ihis may be done in either
a clarifier with the use of thickeners or an earthen impoundment (settling
pond). Ihe iron precipitate (known as yellowboy) settles to the bottom
of the lagoon and the clear" water is discharged.
561
-------
Settling ponds are generally very large in size - often from 114,000
to 303,000 cu m (30 to 80 million gallon) capacity - and are constructed
by either damning a valley or digging a large hole. Settling ponds are
large because sludge is collected in them. Some acid mine drainage treat-
ment plants use two ponds. When one pond has reached capacity, flow is
diverted to the second and the sludge in the first is either removed by
dredging or allowed to undergo drying and compaction which greatly
reduces the sludge volume. When the second pond is full, flow is returned
to the first and the cycle is repeated.
6.3.2 Water Pollutants Discharged from BSER
Based upon the preliminary data provided in the above tables, we have
attempted to estimate cleaning plant discharges for the classical para-
meters and several representative metals on a gram of pollutant per kkg
of product coal basis. Direct slurry pond discharges are provided in
Table 6-11. Refuse pile discharges are only indirectly a function of
plant size and cannot be quantified. In addition modem cleaning plants
do not discharge coal pile runoff without extensive treatment to meet
the NPDES guidelines presented in Table 6-12.
For chemical coal cleaning processes, insufficient operating or environ-
mental data is available to quantify either the amount or characteristics
of chemical cleaning plant liquid discharges.
The primary pollutant and trace element discharges associated with
each of the four reference boilers and eastern reference coals is provided
in Tables 6-13 through 6-20. A sensitivity analysis follows in Table 6-21.
Liquid wastes from mining and industrial boiler blowdown are not included.
Western coal values are not presented because the tables only reflect
liquid discharges from coal cleaning facilities and the Western coal BSER
only involves using raw coal.
The table results show that water pollution levels are low from modern
coal cleaning facilities. Chemical oxygen demand (COD) has the highest
primary pollutant discharge value for each boiler and coal; iron discharges
far exceed the values for any other trace metal. The discharges are
directly proportional to the coal feed rate to the boiler, since coal
cleaning liquid discharges cannot be allocated to various levels of
cleaning and the values presented are normalized on a kkg of product coal basis,
562
-------
TABLE 6-11. MEASURED LIQUID DISCHARGES FROM SELECTED
PHYSICAL COAL CLEANING PLANTS
Median
Parameter/Plant NC-22S NC-22V NC-17S NC-16S Value
Primary - (gn\/kkg of coal product)
Octal Dissolved Solids
Ototal Suspended Solids
Total Volatile Solids
COD
TOC
PH
Major Elements (gm/kkg of product)
Calcium
Magnesium
Sodium
Trace Elements (mg/kkg of product)
Copper
Iron
Zinc
Manganese
75
/ ~J
82
0.6
11
1.6
0.2
8.2
8.8
4.2
3.3
2.3
14
3
1.8
75 851
/ ~J O.JJ-
451
1.3 20.
15 80
1.5 26
0.5 21
6.9 7.1
11
5.4
83
0.6 43
410
3 20
20
Rd
j**
-
12
59
21
2.3
7.3
2.1
0.5
9.0
< 0.2
11
< 1
1.3
7=1
/ .j
265
7
37
11
1.9
7.2
8.8
4.2
9.0
1.5
14
3
1.8
563
-------
TABLE 6-12.EFFLUENT GUIDELINES FOR COM,
CLEANING PLANTS (20)
TSS, pH, iron and manganese are the only parameters for which NPDES
standards exist for the coal industry. The limitations for these in
preparation plant acid and alkaline waters are:
Effluent
Characteristics
TSS
Iron total
Manganese total
PH
Acid Water
Maximum
for 1 Day (mg/1)
70.0
6.0
4.0
within the range of 6 to 9
Average of Values
for 30 Consecutive Days
Shall not exceed (mg/1)
35.0
3.0
2.0
Effluent
Characteristics
TSS
Iron total
pH
Alkaline Water
Maximum
for 1 Day (mg/1)
70.0
6.0
within the range of 6 to 9
Average of Values
for 30 Consecutive Days
Shall not exceed (mg/1)
35.0
3.0
These standards are effective February 12, 1979.
564
-------
TABLE 6-13. WATER POLLUTION IMPACTS FROM "BEST" SO2 CONTROL TECHNIQUES
FOR HIGH SULFUR EASTEFN OOAL-FIRED DOILERS,
SYSTEM
Standard Boiler
Heat Rate
(MW or
10" DTU/hr)
8.8 MW
(30)
Type
Underteed
Stoker
Cbntrol
Level
(Name, % of
SOZ Reduction
None
0%
SIP and Moderate
58%
Optional Moderate
and Intermediate
75%
Stringent
80%
Type
of
Control
Raw Coal
PCC
Middlings
PCC
Deep cleaned
Product
OOC
ERDA
EMISSIONS
Primary Pollutants
mg/8
(Ib/hr)
None
**
TSS=2.1
=(0.02)
COD=3,4
= (0.03)
TOC=0.58
= (0.005
[pll=7.2]
Ca=2.7
=(0.02)
Na=2.8
= (0.02)
Mg=1.3
= (0.01)
5% decrease
for the Mirl
Nb Data
ng/J
(lb/10B BTU)
None
•
=0.24
=(0.0007)
=0.39
= (0.001)
=0.066
= (0.0002)
=0.31
=(0.0007)
=0.32
=(0.0007)
=0.15
= (0.0003)
in the above '
lings Product
_
Trace Elements
Pollutant
mg/s
None
Fe=0.0043
Zn=0. 00093
Cu^O.00046
Mn-0.0006
'a lues
Nb data
Degree Change
over
Raw Goal
*
*
*
*
*
Ui
-------
TABLE 6-14 WATER POLUmCN IMPACTS FIO1 "BEST" SO2 CCNTODL TRCIIHIWES
FOR HIGH SULFUR EASTERN COAL-PIPED BOILERS
(Ji
SYSTEM
Standard Boiler
[feat Rate
(MW or
10R BTU/lu:)
22
(75)
Type
Water tube
Grate
Stoker
Ctntrol
level
(Nane, % of
SO» Reduction
- T *• - - - • .... -
None
0%
SIP and
Moderate
58%
Optimal
Moderate and
Intermediate
75%
Stringent
Typo
of
Control
Raw Coal
PCC
Middlings
PCC
EMISSIONS
Prirrary Pollutants
rng/s
(Ib/hr)
None
**
TSS=5.3
= (0.04)
COD=8.4
= (0.07)
TOC=1.5
= (0.01)
[pll=7.2]
Ca=6.7
= (0.05)
Na=6.9
= (0.05)
Mg=3.2
= (0.03)
5% decrease
Deep values for
Cleaned
Product
COC
Product
No Data
ng/J
(lb/10B BTU)
None
= 0.24
= (0.0005)
= 0.38
= (0.0009)
= 0.07
= (0.0001)
= 0.31
= (0.0007)
= 0.31
= (0.0007)
= 0.15
= (0.0004)
in the above
;he Middlins
Trace Elements
Pollutant
mg/s
None
Fe=0.0107
Zn=0.0023
Cu^O.OOll
Mn=0.00l4
No Data
Degree Change
over
Raw Coal
*
*
*
*
*
80%
ERDTV
* Some increase in environmental effects compared to burning naturally-occurring coal with no controls.
** Discharge flow = 0.18 m'/lir
-------
TABLE 6-15. H7VTER POLLUTION IMPACTS FRCN "BEST" SO2 CONTROL TBCHNIOUES
FOR HIGH SULFUR EASTERN COAL-FIRED BOILERS
U1
SYSTEM
Standard Boiler
Iteat Rate
(MWor
lue BTU/hr)
44
(150)
Type
Spreader
Stoker
Control
Level
(Name, % of
SO2 Reduction
None
0%
SIP and Moderate
58%
Optional Moderate
and Intermediate
75%
Type
of
Control
Raw coal
PCC
Middlings
PCC
Deep cleaned
Product
EMISSIONS
Primary Pollutants
mg/s
(lb/hr)
None
**
TSS=10.7
COD=16.8
= (.13)
T002.9
= (.023)
[PH=7.2]
Ca=l3.4
= (.11)
Na=13.7
= (.11)
Mg=6.4
= (.05)
5% d<
valu<
ng/J
(lb/10* BTU)
None
=0.24
=(.0005)
=0.38
= (.0009)
=.07
= (.0002)
=.31
= (.0007)
=.31
= (.0007)
= .15
= (.0003)
crease in the
s for the midc
Trace Elements
Pollutant
mg/s
None
Fe=.0214
Zn=.0046
Cu=.0023
Mn=.002B
above
lings product
Degree Change
over
Raw Coal
*
*
*
*
*
* Sane increase in environmental effects conpared to burning naturally-occurring coal with no controls.
** Discharge flow = 0.18 m3/hr
-------
TABLE 6-16. WATER POLLUTION IMPACTS FRCM "BEST" SOz CONTROL TECHNIQUES
FOR HIGH SULFUR EASTEIW COAL-FIRED BOILERS
Ui
cn
00
SYSTEM
Standard Boiler
Iteat Rate
(MWor
10s BTU/hr)
58.6
(200)
Type
Pulverized
coal fired
Control
Level
(Nam, % of
SO? Reduction
None
0%
SIP and Moderate
58%
Optional, Moderate
and Intermediate
75%
Type
of
Control
Raw coal
PCC
Middlings
POC
Deep
Cleaned
Product
EMISSIONS
Primary Pollutants
mg/s
(Ib/hr)
None
**
TSS=14.2
= (.11)
COD=22.4
= (.18)
TOCX3.9
= (.03)
[p»=7.2]
Ca=17.9
= (.14)
Na=18.3
= (.15)
Mg=8.5
= (.07)
5% decreasi
Middlings
ng/J
(lb/10s DTU)
None
.24
.0006
.38
.0009
.07
.0002
.31
.007
.31
.0008
.15
! in the above
'roduct
Trace Elements
Pollutant
mg/s
None
Fe=.0285
Zn=.0061
Cu=.0031
Mn=.0037
values for the
Degree Change
over
Raw Coal
*
*
*
*
* Seme increase in environmental effects compared to burning naturally-occurring coal with no controls.
** Discharge flow - 0.18 m'/hr
-------
TABLE 6-17. WATER POLLUTION IMPACTS PROM "BEST" SOz CONTROL TECHNIQUES
FOR LOW SULFUR EASTERN COAL-FIRED BOILERS.
SYSTEM
Standard Boiler
Ifeat Rate
(MM or
106 BTU/hr)
8.8
(30)
* Sane incre
** Discharge
Type
underfeed
Stoker
Boiler
ase in envin
flow = 0.18
Control
Level'
(Nans, % of
SO2 Reduction
None
0%
SIP, Moderate and
Optional Moderate,
0%
Intermediate and
Stringent
30%
Dnmental effects cor
m*/hr
Type
of
Control
Raw Coal
Raw Coal
POC
Level 4
"CC
Level 4
npared to bum
EMISSIONS
Primary Pollutants
rag/a
(Ib/hr)
None
None
**
TSS=1.8
= (0.014)
COD=2.8
= (0.022)
T000.5
= (0.004)
[ptt=7.2]
Ca=2.3
= (0.018)
Na=2.3
= (0.018)
Mg=l.l
= (0.009)
ing naturall
ng/J
(lb/106 BTU)
None
None
= 0.20
= (0.0005)
= 0.32
= (0.0007)
= 0.06
= (0.0001)
= 0.26
= (0.0006)
= 0.26
= (0.0006)
= 0:13
= (0.0003)
y-occurring co
Trace Elements
Pollutant
mg/s
None
Mane
Cu=0.0004
Be=0.0036
Mn=0.0005
Zn=0.0008
al with no contn
Degree Change
over
Raw Coal
*
*
*
*
3lS.
en
0\
-------
TABLE 6-18. WATER POLLUTION IMPACTS FROM "BEST" SO2 CONTROL TECHNIQUES
FOR LOW SULFUR EASTERN COAL-FIRED BOILERS.
SYSTEM
Standard Boiler
Ibat Rate
(MW or
10r> BnV£ir)
22
(75)
Type
Watertube
Grate
Stoker
Control
Level
{Narn, % of
SOz Reduction
None
0%
SIP, Moderate and
Optional Moderate,
0%
Intermediate and
Stringent
30%
Type
of
Control
Raw Coal
Raw Coal
PCC
Level 4
EMISSIONS
Primary Pollutants
mg/8
(Ib/hr)
None
None
**
TSS=4.5 ,
= (.04)
001X7.1
= (.06)
TOCKL.2
= (.01)
tpB=7.2]
Ca=5.7
= (.05)
Na=5.8
= (.05)
Mg=2.7
= (.02)
ng/J
(lb/10* BTU)
None
None
.21
(.0005)
.32
(.0008)
.06
(.0001)
.26
(.0006)
,27
(.0006)
.12
(.0003)
Trace Elements
Pollutant
mg/s
None
None
Cu=.0009
Fte=.0091
Mn=.0012
Zn=.0020
Degree Change
over
Raw Coal
*
*
*
*
* Sate increase in environmental effects compared to burning naturally-occurring coal with no controls.
** Discharge flow = 0.18 m'/hr
-------
TABLE 6-19. WATER POLIUTION IMPACTS FRCM "BEST" S02 CONTROL TFCHNIOUES
FOR LOW SULFUR EASTERN COAL-FIRED BOILERS.
SYSTEM
Standard Boiler
Ifeat Rate
(MM or
'.Ofi BlV/hr)
44
(150)
Type
Spreader
Stoker
Control
Level
(Name, % of
SOZ Reduction
None
0%
SIP, Moderate, and
Optional Moderate
0%
Intermediate and
Stringent
30%
Type
of
Control
Raw Coal
Raw Coal
PCC
Level 4
EMISSIONS
Primary Pollutants
mg/s
(Ib/hr)
None
None
**
TSS=9.1
0(.07)
COD=14.3
= (.11)
TOC=2.5
= (.02)
(PH=7.2)
Ca=11.4
= (.09)
Na=11.7
= (.09)
Mq=5.5
= (.04)
ng/J
(lb/10* BTU)
None
None
.21
(.0005)
.32
(.008)
.06
(.001)
.26
(.006)
.27
(.006)
.12
(.003)
Trace Elements
Pollutant
mg/s
None
None
Cu=.0019
Fe=.01R2
Mn=.0023
Zn=.0039
Degree Change
over
Raw Coal
*
*
*
*
* Some increase in environmental effects coipared to burning naturally-occurring coal with no controls.
** Discharge flow = 0.18 m3/hr
-------
TABU*; 5-20. WATER POIU/I'ION IMPACTS FROM "BEST" SO2 CONTROL TECHNICTUES
FOR LOW SULFUR EASTERN COAIj-FIRED BOILERS.
to
SYSTEM
Standard Holler
lleat Rate
(MW or
106 BlU/lir)
58.6
(200)
Type
I'ulverizod
Coal Fired
Control
Level
(Name, % of
SOZ Reduction
None
0%
SIP, Moderate,
and Optional
Moderate 0%
Intermediate and
Stringent
30%
Type
of
Control
Raw Coal
Raw Coal
PCC
level 14
EMISSIONS
Primary Pollutants
mg/8
(Ib/hr)
None
None
**
TSS=12.1
= (.10)
COD=19.1
= (.15)
TOC=3.3
= (.03)
[pfl=7.2]
Ca=15.2
= (.12)
Na=15.6
= (.12)
Mg=73
= (.06)
ng/J
(lb/106 BIN)
None
None
.21
(.005)
.32
(.0008)
.06
(.001)
.26
(.0006)
.27
(.0006)
• J2
(.0003)
Trace Elements
Pollutant
mg/3
None
None
Cu=.0026
Fe=.0242
Mn=.0031
Zn=.0052
Degree Change
over
Raw Coal
*
*
A
*
* Seme iiicrease in environmental effects compared to burning naturally-occurring coal with
** Discharge Clow - 0.18 m3/lir
controls.
-------
TABLE 6-21. SENSITIVITY ANALYSIS OF WATER EMISSIONS
FROM COAL CLEANING PLANTS
A. High Sulfur Eastern Coal
Emission values are constant for all boilers.
Type of
Control
Primary
Pollutants (ng/J)
Raw Coal
PCC-MLddlings
PCC-Deep Cleaned
CCC-ERDA
None
TSS = 0.24
COD = 0.39
TOC = 0.07
Ca = 0.31
Na = 0.32
Mg = 0.15
TSS = 0.23
COD = 0.37
TOC = 0.07
Ca = 0.29
Na = 0.30
Mg = 0.14
No Data
B. Low Sulfur Eastern Coal
Emission values are constant for all boilers.
Type of
Control
Primary
Pollutants (ng/J)
Raw Coal
PCC-lavel IV
None
TSS = 0.21
COD = 0.32
TOC = 0.06
Ca = 0.26
Na = 0.26
Mg = 0.13
C. Western Values are not presented because the tables only reflect liquid
discharges from coal cleaning facilities and the Western Coal BSER only
involves using raw coal.
-------
6.4 SOLID WASTES
Goal cleaning affects the amount of solid waste generated in that there
is a greater production of waste at the point of coal preparation and less
production at the point of use. The net effect is a greater production of
solid waste. This is due to the large refuse rejection rate at the pre-
paration plant. However, a major benefit to the industrial boiler user
results. Goal cleaning greatly reduces the amounts of fly ash and bottom
ash produced making the disposal problem much less at the boiler site. Also,
there are several economic and environmental advantages which result. Air
emissions of coal constituents which are volatilized upon combustion, e.g.,
sulfur oxides and mercury are minimized by their removal as solid wastes
during coal cleaning.
With respect to SO2, possibly the pollutant of most concern from the
combustion of coal, there is the additional advantage from a solid waste
viewpoint that removal of sulfur as FeS necessitates the disposal of a
much smaller volume of waste than by the removal of sulfur as CaSO3-l/2 H2O
and/or CaSOtj-2H20 (and unreacted CaC03) if an PGD process is utilized.
The absolute quantities of non-volatile constituents, those which
report to the ash upon combustion, are in actuality not reduced, but there
are advantages in disposing of them at the preparation plant rather than
at the user's site.
6.4.1 Solid Wastes from Physical Goal Cleaning
According to the Keystone Manual (1977), there are over 460 physical
coal cleaning plants in the U.S. which can handle over 400 million tons of
raw coal per year. (21) This resulted in an estimated 96 million tons of coal
cleaning refuse. (22*
Coal refuse consists of waste coal, slate, carbonaceous and pyritic
shales, and clays associated with coal seam. It has been estimated that
about 25 pei Tent of the raw coal mined is disposed of as waste. (Western
coals surface mined from very thick beds, e.g., as in the Powder River Basin,
will not have these percentages of wastes, but these coals are not currently
subjected to coal cleaning.)
574
-------
Coal refuse disposal involves two quite separate and distinct categories
of material—a coarse {+ 28 mesh) refuse and a fine (-28 mesh) refuse.
The coarse refuse is usually handled as a normal solid waste. The fine
refuse is normally removed from the coal preparation plant as a thickener
underflow slurry and pumped to an impoundment.
6.4.2 Solid Wastes from Chemical Coal Cleaning
Solid wastes, as such, are not directly produced by the ERDA, Meyers
or Gravichem chemical coal cleaning processes; removal is by acid dissolu-
tion rather than by physical separation. Solid wastes are produced when
the acid waste solutions are neutralized and precipitated with lime.
Although removal of ash constituents by these chemical processes is evidently
less than by physical cleaning processes, solid wastes from CCC plants
cannot be readily quantified because of the undeveloped state of the
technology. It is assumed for this study that the ERDA process removes
25 percent of the ash in the coal while the Gravichem process can remove
(2 3)
25 percent of the ash material after physical coal cleaning.
6.4.3 Environmental Impacts from Cleaning Plant Solid Wastes
The mineral wastes from coal preparation and mine development constitute
a major environmental problem. Mare than 3 billion tons of these materials
have accumulated in the U.S., and the current annual rate of waste production
of 100 million tons per year is expected to double within a decade. The
total number of coal waste dumps is estimated to be between 3,000 and 5,000,
of which half pose some type of health, environmental, or safety problem.
Although it has been established that the drainage from coal refuse dumps
is often highly contaminated with trace or inorganic elements, little is
known about the quantities of undesirable elements released into the environ-
ment from this source.
Infiltration of contaminated water from tailings ponds containing fine
solid wastes is an obvious environmental problem. Inclusion of an iirpervious
bottom in the construction of such ponds is one mitigative measure;
collection ditches or wells around the perimeter are another; and rnaiiitenance
of the pH within the pond on the alkaline side will reduce the concentrations
of many undesirable solutes.
575
-------
Infiltration of rainfall and air into piles of coarse coal refuse
promotes oxidation of the pyrites, creating an acid condition causing
accelerated dissolution of contaminants. Principal mitigative measure is
compaction and coverage with soil to minimize the chances for oxidation
and percolation. This also reduces the possibility of fire, another
major environmental problem with refuse piles.
6.4.4 Solid Waste Quantification for BSER Comparisons
Only solid waste quantities from each BSER will be presented in the
environmental factor comparisons because of the lack of data en the
constituents in coal cleaning refuse piles, the conflicting information
on the fate of trace elements in the raw coal relative to cleaning plant
refuse, bottom ash, or fly ash, and the difficulty in characterizing the
impact of leachate on the environment, f13/1*'15'16' 17/18)
The amount of solids generated by the coal cleaning plants are
calculated by:
SW = (l-Y)I
where:
SW is the quantity of solid wastes (kkg/day)
Y is the cleaning plant yield, and
I is the input coal quanitity to the cleaning plant (=7,250 kkg/day)
The above formula must be modified for use with the cleaning of high sulfur
eastern coal because of the production of two products. The total refuse
produced (1-Y) is split among the two products in proportion to the percent
yield of each. Tb determine the quantity of solid waste generated when two
products are produced, the following formula is used.
is the quantity of solid waste attributed to product 1, (mg/s) (1-Y) is
the refuse yield, YX is the yield of product 1, Y is the total product yield,
I is the input coal quantity to the cleaning plant (75,700 rag/s). 1b obtain
SW2f Y2 is substituted for Yj.
576
-------
The values for solid wastes generated by coal cleaning and cleaned coal
are provided in Tables 6-22 through 6-30 for each BSER. These values of
solids generated by combustion at the boiler are calculated using the feed
rate to the boiler (mg/s), the percent ash of the coals being burned and
the percent of the total ash which goes to fly ash and bottom ash. The
feed rate to the boiler is calculated using the following formula.
Feed rate (itig/s) = Heat rate Heat content 126 mg/s
of boiler of coal (BTU/lb) BTU/lb
(BTU/hr.)
The percent ash of the coals being burned are found in Section 3 and the
percents of the total ash which go to fly ash are shown in Table 5-13.
The following formulae are used to calculate the amounts of fly ash and
bottom ash generated upon combustion of the coal.
Amount of = Feed rate x % Ash x % Fly Ash of
Fly ash (mg/s) 100 Total Ash
(mg/s) 100
Amount of = Feed rate x % Ash x % Bottom Ash
Bottom ash (mg/s) 100 of Total Ash
(mg/s) 100
Note: 100 - (% Fly Ash of Total Ash) = % Bottom Ash of Total Ash
The high sulfur eastern coal resultr show an anamoly in that sulfur
removal is inversely proportional to solid wastes generated. This is
explained by the cleaned coal characteristics and the method for physically
cleaning the coal. As shown in Figure 3-4, the deep cleaned and middlings
cleaning circuits are relatively inseparable from a generation of refuse
standpoint. If the refuse is attributed evenly to each product on a weight basis,
then the higher heating value of the deep cleaned coal will produce less
wastes from an.energy basis: (i.e. ng/J). The ERDA process uses chemical
reactions to extract pyritic and organic sulfur and, as a result, only
generates small amounts of waste while removing about 25 percent of the
incombustible materials and most of the pyritic sulfur in the coal.
The results for low sulfur eastern coal are more consistent with the
expectation that greater S02 control should be associated with increased
solid waste generation. Note that the BSER physical and chemical coal
cleaning methods produce over twice as much solid waste as the raw coal.
577
-------
TABIZ 6-22. SOLID WASTES FRCM "BEST" SO2 CCNTROL TECHNIQUES
FOR 8.8 t*J COAL FIRED BOTTF.KS
HIGH SULFUR EASTERN COAL
SYSTEM
Standard Boiler
Heat Rate
(MW or
10* BTU/hr)
8.8
(30)
Type
Underfeed
Stoker
'
Control
Level
(Name, % of
SOz Reduction
Kbne,
0%
Moderate
1,290 ng SOZ/J
and
SIP
1,075 ng SO,/J
58%
Optional
Moderate
and
Trrt-OTmarH a+»
645 ng SO»/J
75%
Type
of
Control
Raw Coal
Middling
Middling
Deep Cleaned
Prod.
Deep Cleaned
Prod.
!
i
Stringent CCC
516 nq SO./J i ERDA
f ~ )
80*
'
i
i
j
1
i
EMISSIONS
Solid Wastes
mg/s
(Ib/hr)
Type
Cleaning 0
Bottom Ash
56.5
(448)
Fly Ash
19.6
(155)
"total Wastes
75.3
(597)
Cleaning
94
(750)
Bottom Ash
24
(190)
Flv Ash
C.O
(63)
Total Wastes
126
(lfOOO)
Cleaiuno
92
(730)
Dottorr, Ash
11
. (87)
riy Ash
3.8
(30)
ng/J
(lb/10' BTU)
6,430
(15)
2,233
(5)
8,570
(20)
10,690
(25)
2,730
(6)
910
(2)
14,330
(33)
10,460
(24)
1,250
(3)
430
(1)
Percent
Increase
Over No
Controls
~
67%
i
Total Wastes <
107 j 12,140 : ;
(850) ! (28) 42% •
Cleaning
21 2,390 i
(167) (5)
Bottom Ash
41 4,660 :
(325) (11)
Fly Ash i
14 1,590
(in) (4)
Ibtal Wastes
76 8,640
(603) (20) 0%
578
-------
TABLE 6-23.
SOLID WASTES FROM "BEST" SO2 CONTROL TECHNIQUES
FOR 22 MW GOAL FIFED BOILERS
HIGH SULFUR EASTERN GOAL
SYSTEM
Standard Boiler
feat Bate
(MW or
10* BTU/hr)
22
(75)
-
Type
Chain-
Grate
Stcker
Control
Level
(Nate, % of
SO2 Reduction
None.
0%
Moaerate
1,290 ng SO2/J
and
SIP
1,075 ng S02/J
58%
Optional
Moderate
860 ng S02/J
and
Intermediate
75%
Stringent
516 ng SOz/J
80%
Type
of
Cbntrol
Raw Coal
Middling
Middling
Deep -Cleaned
Prod.
Deep Cleaned
Prod.
ccc
ERDA
EMISSIONS
Solid Hastes
mg/s
(Ob/lTr)
Cleaning
0
Botton Ash
141
(1,120)
Fly Ash
49
(388)
Total Ash
188
(1,490)
Cleaning
236
(1,870)
Botton Ash
59
(470)
Fly Ash
20
(160)
Total Waste
315
(2,500)
Cleaning
230
(1,825)
Botton Ash
28
(220)
Fly Ash
10
(80)
Total Waste
268
(2,125)
Cleaning
52
(410)
Botton Ash
102
(810)
Fly Ash
34
(270)
Total Ash
188
(1,490)
ng/J
(Ib/lO* BTU)
6,415
(15)
2,233
(5)
8,555
(20)
10,740
(25)
2,680
(6.3)
910
(2.1)
14,330
(33)
10,460
(24)
1,280
(2.9)
450
(1.1)
12,190
(28)
2,360
(5.5)
4,640
(11)
1,550
(3.6)
8,550
(20)
Percent
Increase
Over No
Controls
—
68%
43%
0%
579
-------
TABLE 6-24. SOLID WASTES FROM "BEST" SO2 CONTROL TECHNIQUES
FOR 44 VK COAL FIRED BOILERS
HH5I SULFUR EASTERN GOAL
SYSTEM
Standard Pojlor
Heat Rate
(MH or
(10* BTO/hr)
44
(150)
type
Spreader
Stoker
Ocntrol
Level
(Mare, % of
SOi Reduction
Uncontrolled
0%
Moderate
1,290 ng SOz/J
and
SIP
1,075 ng S02/J
58%
Optional
Moderate
860 ng SOZ/J
and
Xnt^r™^*^] ?tj£
645 ng SO2/J
75%
Stringent
516 ng SOj/J
80%
Type
Of
Control
Raw Coal
Middling
Product
Middling
Product
Deep Cleaned
Product
Deep Cleaned
Product
Chemically
Cleaned-
EREft
EMISSIONS
Solid Hastes
mg/s
(Ib/hr)
Cleaning
0
Botbon Ash
132
(1,050)
Fly Ash
255
(2021)
rotal Ash
377
(2,990)
Cleaning
472
(3,750)
Bottom Ash
55
(440)
Fly Ash
102
(810)
rotal Waste
629
(5,000)
Cleaning
460
(3,650)
Bottom Ash
26
(210)
Fly Ash
50
(400)
Total Waste
536
(4,260)
Cleaning
105
(830)
Bottom Ash
95
(760)
Fly Ash
177
(1400)
Total Waste
377
(2,990)
ng/J
(lb/10' BTU)
0
3,000
(7)
5,806
(13.5)
8,575
(20)
10,740
(25)
1,250
(3)
2,320
(5)
14,310
(33)
10,460
(24)
590
(1.4)
1,140
(2.6)
12,190
(28)
2,390
(5.5)
2,160
(5.1)
4,030
(9.3)
8,580
(20)
Percent
Increase
Over No
Controls
—
67%
42%
0%
580
-------
TABLE 6-25.
SOLID WASTE FROM "BEST" SO; CONTROL TECHNIQUES
FOR 5C.G :iv COAL" FIRED POILERS
HK3J SULFUR
COAL
SYSTEM
Standard Boiler
Ifeat Rate
(MW or
(10s BTO/hr)
58.6
(200)
Type
Pulverized
Cbntrol
Level
(Name, * of
SO2 Reduction
Uncontrolled
0%
Moderate
1,290 ng SO2/J
and
SIP
1,075 ng SO2/J
58%
Optional
Moderate
860 ng S02/J
and
Intermediate
645 ng S02/J
75%
Stringent
516 ng SOj/J
80%
Type
of
Control
Raw Coal
Middling
Middling
Deep
Cleaned
Cnsmicallv
Cleaned
EMISSIONS
Solid Wastes
mg/s
-------
TABLE 6-26. SOLID WASTE FROM "BEST" SO* CONTROL TECHNIQUES
FOR 8.8 M? COAL FIRED BOILERS
LOW SULFUR EASTERN COAL
SYSTEM
Standard Boiler
Iteat Rate
W or
(10* BID/hr)
8.8
(30)
Type
Underfeed
Stoker
Odntrol
level
(Nine, % of
SOj fleduction
Uncontrolled
0%
SIP
1,075 ng 90;/J
Moderate
1,290 ng S02/J
Optional
Moderate
860 ng SO2/J
0%
Intermediate
645 ng S02/J
an5
Stringent
516 ng S02/J
30%
Stringent
516 ng S02/J
50%
•type
of
Control
Raw Coal
Raw Coal
Raw Coal
Rate Coal
PCC
level 4
FCC
Level 4
CCC
Gravichem
EMISSIONS
Solid Hastes
mg/s
(Ib/hr)
Cleaning
0
Bottom Ash
21.6
(171)
Fly Ash
7.2
(57)
Total Ash
26.8
(228)
Cleaning
50
(400)
Botbcm Ash
8
(60)
Fly Ash
2.7
(20)
Total Waste
61 -
(480)
Cleaning
63
(500)
Botton Ash
4
(30)
Fly Ash
1
(8)
Total Waste
68
(540)
ng/J
(lb/10f BTV)
2,450
(5.7)
820
(1.9)
3,270
(7.6)
5,690
(13)
920
(2)
310
(0.7)
6,920
(16)
7,160
(17)
450
(1)
no
(0.3)
7,720
(18)
Percent
Increase
Over No
Controls
—
112%
1361
582
-------
TABLE 6-27. SOLID WASTE FROM "BEST" S02 CONTROL
FOR 22 M? COAL FIRED BOILERS
LOW SULFUR EASTERN COAL
SYSTEM
Standard Boiler
Heat Rate
tv or
(10* BlU/hr)
22
C75)
Type
Chain-
Grate
Stoker
Cfcntrol
Level
(Name, % of
SOj Reduction
Uncontrolled,
0%
and
SIP
1,075 ng SOj/J
and
Moderate
1,290 ng S02/J
and
Opt. Mod.
860 ng SO2/J
0%
Intermediate
645 ng S02/J
and
Stringent
516 ng SOz/J
30%
Stringent
516 ng S32/J
Type
of
Oontrol
Raw Coal
Raw Coal
Raw Coal
Raw Coal
PCC
Level 4
PCC
Level 4
ccc
Gravichem
EMISSIONS
Solid Wastes
mg/s
(Ib/hr)
Cleaning
0
Bottom Ash
54
(4305
Fly Ash
18
(140)
Total Ash
72
(570)
Cleaniro
125
(990)
Bottom Ash
20
(160)
Fly Ash
7
(60)
Total Waste
152
(1,210)
Cleaning
• 160
(1,270)
Bottom Ash
9
(70)
Fly Ash
3
(20)
Total Waste
172
(1,360)
ng/J
(lb/106 BTU)
0
2,460
(5.7)
820
(1.9)
3,280
(7.6)
5,690
(13)
910
(2.1)
320
(0.8)
6,920
(16)
7,280
(17)
410
(1)
140
(0.3)
7,830
(18)
Percent
Increase
Over No
Controls
~~
111%
139%
583
-------
•DffiLE 6-28. SOT.TT) WASTE FBOM "BEST" SO2 CONTROL TECHNIQUES
TOR 44 M* COAL FIEED BOILERS
LOW SUITOR EASTERN GOAL
SYSTEM
Standard Boiler
Hsat Rate
W or
(10s BTU/hr)
44
(15C)
Type
Spreader
Stoker
Control
Level
(Hare, % of
SO2 Reduction
Uncontrolled
0%
SIP
1,075 ng SO2/J
and
Moderate
1,290 ng SO2/J
and
Opt. Moderate
860 ng S02/J
0%
Intermediate
645 ng SO2/J
and
Stringent
516 ng S02/J
30%
Stringent
516 ng SO2/J
50%
Type
of
Control
Raw Crvjl
Raw Coal
Raw Coal
Raw Coal
FCC
Level 4
PCC
Level 4
CCC
Gravichero
EMISSIONS
Solid Wastes
mg/s
(Ib/hr)
Cleaning
0
Bottom Ash
50
(400)
Fly Ash
94
(750)
Total Ash
144
(1,150)
Cleaning
250
(1,980)
Bottom Ash
19
(150)
Fly Ash
35
(290)
Total Waste
304
(2,420)
Cleaning
320
(2,540)
Bottom Ash
8
(60)
Fly Ash
16
(130)
Total Waste
345
(2740)
ng/J
(lb/10f BTU)
1,140
(2.7)
2,140
(5)
3,280
(7.7)
5,690
(13)
430
(1)
800
(2)
6,920
(16)
7,280
(17)
180
(0.4)
260
(0.9)
7,830
(18)
Percent
Increase
Over No
Controls
—
111%
140%
584
-------
TABLE 6-29. SOLID WASTE FROM "BEST" SO2 CONTROL TECHNIQUES
FOR 58.6 W GOAL FIRED BOILERS
LOW SULFUR EASTERN COAL
SYSTEM
Standard Boiler
Heat Rate
VH or
(10e BTO/hr)
58.6
(200)
Type
Pulverized
Control
Level
(Nane, % of
SOj Reduction
Uncontrolled
0%
SIP
1,075 ng S02/J
and
Moderate
1,290 ng 902/J
and
Opt. Moderate
860 ng SO2/J
Intermediate
645 ng SO2/J
and
Stringent
516 ng SO2/J
30%
Stringent
516 ng S02/J
50%
Type
of
Control
Raw Coal
Raw Coal
Raw Coal
Raw Coal
FCC
Level 4
PCC
Level 4
CCC
Gravichem
EMISSIONS
Solid Wastes
mg/s
(lb/hr)
Cleaning
0
Bottom Ash
38
(300)
Fly Ash
154
(1,220)
Total Ash
192
(1,520)
Cleaning
334
(2,650)
Botton Ash
• 14
(110)
Fly Ash
57
(450)
Total Waste
405
(3,210)
Cleaning
420
(3,330)
Bottom Ash
7
(60)
Fly Ash
26
(210)
Total Haste
455
(3,600)
ng/J
(lb/105 BTO)
0
650
(1.5)
2,630
(6.1)
3,280
(7.6)
5,700
(13)
240
(0.5)
970
(2.2)
6,910
(16)
7,170
(16.6)
120
(0.3)
440
(1)
7,730
(18)
Percent
Increase
Over No
Controls
—
111%
137%
585
-------
TABLE 6-30. SOLID WASTE FROM "BEST" SO2 OCNTRDL
FOR 8.8 Mfl GOAL FIRED BOILERS
LOW SULFUR WESTERN GOAL
SYSTEM
Standard Boiler
Heat Rate
VH or
(10s BTU/hr)
8.B
(30)
22
(75)
44
(150)
58.6
(200)
Type
Underfeed
Stoker
Chain-
Grate
Stoter
Spreader'
Stoker
Pulverized
Control
Level
(None, % of
S02 Reduction
All
0%
All
0%
All
0%
All
0%
Type
of
Control
Raw Coal
Raw Coal
Raw Coal
Raw Coal
EMISSIONS
Solid Hastes
mg/B
Clb/hr)
Bottom Ash
62
(490)
Fly Ash
21
(170)
Total Ash
83
(660)
Bottom Ash
156
(1,240)
Fly Ash
52
(410)
Total Ash
208
(1,650)
Bottom Ash
145
C1.150)
Fly Ash
270
(2,HO)
Total Ash
415
(3,290)
Bottom Ash
111
(880)
Fly Ash
443
(3,520)
Total Ash
554
(4,400)
ng/J
(lb/10* BTU)
7,050
(16)
2,390
(16)
9,440
(22)
7,100
(16.5)
2,370
(5.5)
9,470
(22)
3,300
(7.7)
6,140
(14.3)
9,440
(22)
1,890
(4.4)
7,560
(17.6)
9,450
(22)
Percent
Increase
Over No,
Controls
None
None
None
None
586
-------
Solid waste discharges from each of the boilers, expressed as ng/J,
remain constant in value, regardless of size or type of boiler. Figures
6-1 and 6-2 show cleaning wastes versus percent sulfur in coal and ash
removed versus percent sulfur in coal, respectively. Normalized amounts
of cleaning waste are not affected by boiler size or type, but only by
the sulfur content of the coal cleaned. Figure 1 shows that as the sulfur
content of the coal being cleaned decreases, the amount of wastes also
decreases. Figure 2 shows that the amount of ash removed by cleaning also
depends upon the sulfur content of the raw coal. As in Figure 1, the
amount of ash removed with sulfur content decreases. In general, the
emissions (in ng/J) using a standard coal are less dependent upon the
size of the boiler, as they are on the inherent characteristics of the
coal being utilized.
587
-------
00
CO
12,000-1
10,000-
S 8.000-
z
I
d
a.ooo-
4.000-
2,000-
X SULFUR
FIGURE 8-1 CLEANING WASTES VS. KSULFUfl OF COAL BURNED
-------
Ul
00
B.OOO-i
6.0OO-
4.000-
3.000-
2,000-
1,000-
2 3
' % SULFUR
f (CURE 62 ASH REMOVED VS. % SULFUR OF COAL BURNED
-------
SECTION 6.0
REFERENCES
1. Hougen, O.A., and K.M. Watson, Chemical Process Principles, Part 1,
Material and Energy Balances, p. 328-9, Wiley, N.Y. (1943).
2. Steam/Its Generation and Use, 39th ed., p. 5-9, 5-13, Babcock and
Wilcox, N.Y. (1978).
3. Op. Cit. Reference 1.
4. Ruch, R. R., Gluskoter, H. J., and Shinp, N. F., "Occurrence and
Distribution of Potentially Volatile Trace Elements in Coal: A
Final Report", Environmental Geology Motes No. 72, Illinois State
Geological Survey, Urbana, Illinois (August 1974).
5. Gluskoter, H. J., Ruch, R. R,, Miller, W. G., Cahill, R. A., Dreher,
G. B., and Kuh, J. K., "Trace Elements in Coal", EPA-600/7-77/064,
Industrial Environmental Research Laboratory, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina (1977),
163 pp.
6. Op. Cit., Reference 62.
7. Hamersma, J. W., et al., "Applicability of the Meyers Process for
Chemical Desulfurization of Coal: Initial Survey of Fifteen Coals",
EPA-650/2-74-025, Control Systems Laboratory, National Environmental
Research Center, Research Triangle Park, North Carolina (1974), 192 p.
8. Broz, Larry (Acurex Corp.). Memorandum on "Industrial Boiler Project,
Cost of New Boilers". October 23, 1978.
9. Ibid.
10. Ibid.
11. Op. Cit. Reference 4.
12. Op. Cit. Reference 5.
13. Op. Cit. Reference 6.
14. Op. Cit. Reference 7.
590
-------
15. Klein, D. H., Andren, A. W., Carter, J. A., Etnergy, J. F., Feldman, C.,
Fulkerson, W., Lyon, W. S., Ogle, J. C., Talmi, Y., Van Hook, R. I.,
and Bolton, N., "Pathways of Thirty-Seven Trace Elements Through Coal-
Fired Power Plant", Environmental Science and Technology, 9(10): 973-9
(1975).
16. Yost, K. J., et al, The Environmental Flow of Cadndun and Other Trace
Metals, Purdue Univ., Lafayette, Ind., NSF (RANN) GI-35106, NSF-RA/E-
73-016(A). Progress Report, 7/1/72-6/30/73. Vol I, PB 229478; Vol II,
PB 229479, and Progress Report 7/1/73-6/30/74.
17. Blackwood, T. R., and Wachter, R. A., "Source Assessment: Coal Storage
Piles", Draft Report to U.S. Environmental Protection Agency, Monsanto
Research Corporation (July, 1977), 96 pp.
18. Characterization of Water Pollutants From Selected Coal Preparation
Plants For EPA Priority Pollutants. Coal Cleaning Technology Develop-
ment, Special Technical Report. EPA Contract No. 68-02-2199. May 1978.
19. Ibid.
20. 44 FR 2590. January 12, 1979.
21. Nielsen, George F. (editor), Keystone Coal Industry Manual, McGraw-Hill,
New York, 1977.
22. Anderson, J. C., "Coal Waste Disposal to Eliminate Tailings Ponds",
Mining Cong. J., 61(7): 42-45 (1975).
23. Versar, Inc. "Technical and Economic Evaluation of Chemical Coal Cleaning
Processes for Reduction of Sulfur in Coal" prepared for Industrial
Environmental Research laboratory Office of Research and Development,
U. S. Environmental Protection Agency, Research Triangle Park, North
Carolina. Contract No. 68-02-2199, January, 1978.
24. Energy Research and Development Administration "Environmental Contamina-
tion From Trace Elements In Coal Preparation Wastes," EPA-600/7-76-007
Industrial Environmental Research Laboratory, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina (1976) p.2.
591
-------
SECTION 7.0
EMISSION SOURCE TEST DATA
7.1 INTRDDUCnON
The intent of Section 7.0 is to present actual emissions test data
from industrial boilers using the control technology. For this ITAR, it
means measuring SO2, particulates, and/or NO emissions from industrial
X
boilers burning physically or chemically cleaned coal. To truly test the
control technology, it is required that the boiler initially bum an
unwashed coal and then burn a washed coal. To our knowledge only one such
test was performed, in 1968 by TWA on identical 200 MW boilers. *'
This test, however, only studied relative maintenance cost advantages of
washed coal and did not provide comparable emission measurements.
As an alternative, since emission factors for various boilers have
(2)
been determined in AP-42, input fuel characteristics (sulfur and ash
content) will give an accurate estimate of boiler emissions. Therefore,
if actual measured cleaned product coal characteristics are compared to the
raw (feed) coal, emission control capabilities can be established. The
precedent for using feed coal and product coal characteristics to determine
percent sulfur removal is provided as Appendix A, Reference Method 19, to
the proposed NSPS for electric utility steam generating units. The princi-
ple behind this method is that fuel analyses of sulfur content and BTU content
taken before and after fuel pretreatment systems allow calculation of
percent sulfur dioxide reduction (ng/J). Consistent with this approach,
Versar has recently completed a study of the capability of physical coal
cleaning to reduce emissions by sulfur removal and BTU enhancement using
measured fuel characteristics data provided by U.S. coal conpanies and
the EPA. The data were expected to provide guidance to EPA Office of
Air Quality Planring and Standards on sulfur dioxide emission control and
attenuation of sulfur variability in coal achieved by cleaning plants of
different types, as well as satisfy the requirements of ORD.
592
-------
7.2 PROJECT METHODOLOGY
Three tasks were performed to accomplish the study. Collection of
existing ooal cleaning data was the first task. The second task involved
checking the data, converting the raw data to quantity of SO2 per unit
heat valve, and performing straightforward statistical calculations. The
third task was to analyze the data to determine important relationships
and relevant trends.
7.2.1 Data Acquisition
Existing preparation plant data were solicited from coal cleaning
plant owners. This was accomplished through the National Coal Association
who contacted a selected list of companies which operate cleaning plants
in different coal regions of the U.S. In total, the selected companies
operate 111 preparation plants, which represent over 25 percent of all U.S.
plants. In addition, Versar requested data from one coal company not in
the MCA which operates 4 preparation plants in the Alabama region.
In response to the NCA request,Versar received data from 46 plants
operated by eight coal companies. Since multiple lot information was
requested and received, Versar was provided with 114 paired feed and product
data points.
Versar also obtained EPA-collected data from a 1972 air pollution
(M
study of coal preparation plants. These data included 1972 annual
average feed and product values from 130 coal preparation plants.
A third data source was the commercial coal cleaning plant test
program being conducted by Versar and its subcontractor Denver Equipment
Division of Joy Manufacturing Company under EPA Contract 68-02-2199.
At the tine of this study/three sets of 5-day test results were available
for analysis.
Sufficient data for statistical analyses were received for three
coal regions - Northern Appalachia, Southern Appalachia, and Eastern
Midwest.
593
-------
Preparation plants were categorized by four general cleaning levels.
Generic flow diagrams of these cleaning levels are shown on Figures 7-1
through 7-4. (These figures are generically equivalent to Figures 2-16
through 2-19 in Section 2.0). Level I coal preparation consists of
crushing and sizing to remove large pieces of rock and overburden and to
size to product specifications. Level II coal preparation starts by
crushing the coal then sizing at approximately 9.2 mm (3/8 inch); the plus
9.2 mm material is processed in a coarse coal washing system such as a
jig or dense medium vessel, while the minus 9.2 mm material is not cleaned,
but simply blended with the clean product or sent to refuse.
Coal preparation levels III and IV process finer sizes of coal than
the first two levels, and subsequently achieve greater rejection of ash
and sulfur with subsequent BTU enhancement. Both of these levels process
the plus 9.2 mm material with a coarse coal washing system while the
9.2 mm by 28 mesh fraction is processed by a fine coal washing system
consisting of a heavy media cyclone or washing table. Coal preparation
level III processes the minus 28 mesh material with a hydrocyclone circuit
which will recover about 50 percent of the minus 28 mesh feed. Coal
preparation level IV processes the minus 28 mesh material with a froth
flotation circuit to achieve deep cleaning and enhanced product recovery.
7.2.2 Data .Accuracy - Sampling Methods
To provide an understanding of the reliability and accuracy of the
data provided, the coal conpanies were asked to describe their sampling
methods. Several coal company representatives remarked that specific
coal sampling procedures differ at each plant relative to how the sample
is taken, its frequency, the method for producing a composite sample
and where the feed and product coals are sampled. A general description,
however, coula be provided in most cases.
For feed coal, infrequent, manual sampling is the norm. The terms
'occasionally', 'weekly1, 'only when we have problems', and 'periodically1
were used to describe typical feed coal sample freqi^ncy. In a majority
594
-------
ROM COAL
ui
10
t_n
CRUSHING
AND SIZING
CIRCUIT
PRODUCT
REFUSE
LEVEL 1
FIGURE 7-1. LEVEL I PLANT
-------
nOMCOAL—>
CRUSHING AND
SIZING CIRCUIT
MAKE-UPWATER
•REFUSE
WATER
DRY SCREEN
AT 3/8 IN.
U1
vo
JIG OR DENSE'
MEDIUM VESSEL
COAL REFUSE
RECYCLE
WATER
CVCLONE
REFUSE
.REFUSE
OEWATERINQ
'SCREEN
CLEAN COAL
DEWATERINQ
SCREEN
DRAINED
WATER
THICKENER UNDERFLOW
FOR DISPOSAL OR
FURTHER TREATMENT
RECYCLE
WATER
DRAINED
WATER
CLEAN COAL
PRODUCT
FIGURE 7-2. LEVEL II PLANT
-------
ROM COAL-*
cn
vo
CRUSHING AND
SIZING CIRCUIT
WET SCREEN
AT 3/8 IN.
WET SCREEN
AT 28 M
WATER
RECYCLED
WATER
-»-REFUSE
WATER
L.
WATER
-L
COARSESIZE
COAL CIRCUIT
REFUSE
PRODUCT
CONCENTRATING
TABLE CIRCUIT
PRODUCT
MECHANICAL
DEWATERING
\
REFUSE
DRAIN
WATER
DRAINED WATER
CLEAN COAL
PRODUCT
UHY
PRODUCT
THERMAL
DRVINO
*- THICKENER UNDERFLOW
FIGURE 7-3. LEVEL III PLANT
-------
U1
VO
00
WATER
DRY
PRODUCT
CLEAN COAL
PRODUCT
RECYCLED
WATER
»~ THICKENER UNDERFLOW
FIGURE 7-4. LEVEL IV PLANT
-------
of the cases, the feed coal belt is stopped and an American Standards and
Testing Method (ASTM) belt sanple is taken. Hie sample is a good depend-
able representation of the input coal at that time, however, it should not
be considered a reliable value for feed coal in the short- and iredium-term.
Ihis was an overriding factor that led some of the coal companies to send
monthly and yearly average values, rather than the daily, weekly, or lot
shipment information requested. The feed coal values provided to Versar
ware generally weighted averages of feed coal belt sample analyses.
In contrast, the product coal is extensively sampled and analyzed.
The coal oonpanies typically take a one or two hour composite sample of
the product/ if the plant has an automatic sampler, or will manually sanple
unit train carloads or barges according to ASTM sampling procedures. The
automatically sampled composites consist of individual samples taken at
5-15 minute intervals. The manual samples are usually taken off a conveyor
discharge as the railroad car or barge is loaded.
The frequency of product sampling is somewhat determined by the origin
of the coal feed to the preparation plant. 'For a mine mouth coal cleaning
plant only one composite sample per day may be analyzed; at the other
extreme, where specifications are tight and contract coal is blended and
cleaned, the composite samples may be taken and analyzed every 30 minutes.
Where possible, Versar has specified data which were received from plants
with automatic product samplers.
Although the testing and analysis procedures were not explicitly
provided by the coal companies it is normal practice for coal preparation
plants to use or specify ASTM methods, for heat content, ASTM method D2015
was used and for total sulfur content, ASTM D3177 was the method used.
7.2.3 Statistical Procedures
The coal preparation plant data, as received, ware checked for
completeness and consistency with the information requested. A complete
data set included feed and product sulfur content (dry), BTU-content (dry),
and lot size, and general information on the source of coal (seam, county,
and state) and level of cleaning. The data set was then categorized by
599
-------
ooal region, cleaning level, seam, and lot size. For average monthly data
the information was often supplied on a ton per day (TPD) basis, the 'lot
size1 was calculated by multiplying the TPD by 22 working days per month.
After categorizing all- the data received, the arithmetic mean (y),
standard deviation (a), and relative standard deviation (RSD) were calculated
for each category and subcategory. The mean and standard deviation values
presented were determined from the entire data set, rather than averaging
subset values,which is an incorrect statistical procedure.
To use these sample statistics as an estimate of the universe statistics,
the central limit theorem is assumed to hold. That is, the universe coal
parameter distributions were assumed to be normally distributed and there-
fore the sanpling distribution of the mean derived from each distribution
also is normally distributed. Also the expected value of the sanpling
distribution of the mean is equal in value to the universe mean.
Another statistical analysis was determination of the relationship
between feed and product coals on a weight of sulfur dioxide per unit heat
input basis. Another relationship studied included reduction in ng SO2/J
RSD, from feed to product.
An analysis that was attempted but which did not yield meaningful
results was the reduction of y, a, and RSD by coal cleaning on a regional
basis. The heterogeneity of the coal in each region causes the data sets
to lose their normal distribution characteristics when many seams are
aggregated. Since a regional ng SOa/J distribution depends on
which seams are incorporated and how much data from each seam is included,
the distribution will differ significantly depending on the input data
used. The data provided and analysis results, therefore, should not be
considered representative of the region. A theoretical study analyzing
the universal coal data in each region would be representative; however
there was insufficient actual cleaning information to treat the universal
data set in each region from this study.
600
-------
7.3 DATA PKESESITATION AND ANALYSIS
A general breakdown of the data received is presented in Table 7-1. A
listing of the data is provided in Appendix C. Although only four of the
six ooal regions were represented by the data provided, the information
was diverse relative to coal seam, cleaning level, coal use (netallurgical
and steam), and sulfur content. To supplement the data from the coal
companies/Versar has included for this study the results of three sampling
and analysis tests from its EPA Contract 68-01-2199. These results are
also provided in Appendix C.
7.3.1 Analysis of Individual Physical Coal Cleaning Plants
The approach taken to analyze sulfur removal capabilities by coal
cleaning plants was to begin with individual plants. For each plant with
sufficient feed and product coal data the mean (y), standard deviation (a),
and relative standard deviation (BSD) were calculated to determine the
variation in sulfur removal for the most constant situation (i.e. only
feed coal characteristics change). Data analyses for the nine individual
plants are provided in Tables 7-2 through 7-10.
The nine individual plants show that sulfur content per unit heat
content (i.e. ng SO2/ J-) is treated by the coal preparation process.
This occurs even though the plants were primarily designed to remove refuse
and ash in their attempt to increase BTU content and are not designed
specifically to remove sulfur. Sulfur removal percentages ranged from
18.3 to 48.3 . On absolute terms, a sulfur reduction equivalent of .150
ng SO2/J was attained on the lowest sulfur coal (Plant I) and 1,400 ng
SO2/J was provided on one of the highest sulfur coals (Plant D).
Significantly, in all nine plants the standard deviation (i.e. sulfur
variability) in ng SO2/ J was reduced and in eiqht of the nine plants
the BSD decreased. Figure 7-5 shows the magnitude of the decrease in RSD
between the feed and product for nine coal cleaning plants, each operating
601
-------
TABLE 7-1. CLASSIFICATION OF DATA RECEIVED FROM GOAL
COMPANIES AND TESTING BY VERSAR/JOY-DENVER
CLEANING LEVEL
N. Appalachia
Level 1=2
Level 2 = 7
Level 3 = 22
Level 4=8
NO. OF DATA SETS = 129
REGIONAL DISTRIBUTION
N. Appalachia =
S. Appalachia =
E. Midwest =
Alabama =
S. Appalachia
Level 1=0
Level 2=3
Level 3 = 14
Level 4 = 23
39
40
45
5
E. Midwest
Level 1 = 4
Level 2 = 22
Level 3 = 18
Level 4 = 1
Alabama
Level 4
= 5
SULFUR CONTENT OF FEED COAL
= 61
= 35
= 33
1-3%
SULFUR CONTENT OF FEED COAL BY REGION
N. Appalachia
S. Appalachia
E. Midwest
Alabama
19
0
42
1-3%
18
12
2
3
2
28
1
2
LOT QUANTITY (METRIC TONS) - DATA SETS IN EACH RANGE
>500,000 = 5
100,000-499,999 = 49
10,000- 99,999 = 44
1,000- 9,999 = 18
<999 = 13
602
-------
TABLE 7-2A. MONTHLY AVERAGE SULFUR REDUCTION BY A
LEVEL II CLEANING PLANT - ILLINOIS NO. 6
GOAL - (SI Units)
PLANT A
FEED
PRODUCT
GOAL
USE
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
LOT
QUANTITY*
(metric tons)
169,462
339,826
313,257
331,132
318 ,613
267,310
271,923
272,630
289,303
254,843
275,065
221,743
PKkn (ng
y = 3,796
PRODUCT
y = 2,898
%S
3.98
4.27
4.74
4.72
4.10
4.45
4.87
5.16
5.05
5.44
4.98
5.20
S02/J)
.9
(ng S02/J)
.2
kJAg
25,893
25
25
25
25
24
24
24
25
25
24
25
,117
,465
,609
,490
,463
,008
,947
,528
,027
,272
,083
a
a
ng SO2/J
3,078.8
3,405
3,728
3,693
3,225
3,646
4,063
4,145
3,964
4,355
4,110
4,153
= 404.
= 193.
.6
.1
.7
.0
.4
.5
.2
.6
.9
.8
.8
2
5
%S
3.64
3.93
3.83
3.94
3.83
3.71
4.40
4.34
4.44
4.46
4.42
4.29
kJAg
28,130
28
27
28
28
28
28
28
28
28
28
28
RSD =
RSD =
,130
,986
,070
,098
,035
,652
,608
,822
,706
,582
,640
0.106
0.067
ng S02/J
2,592.9
2,
2,
2,
2,
2,
3,
3,
3,
3,
3,
3,
799.3
743.4
812.2
730.5
653.1
078.8
040.1
087.4
113.2
100.3
001.4
SULFUR REMOVAL (%)
y = 23.4
* Monthly Coal Throughput
Product sampled mechanically
a = 5.86
RSD = .25
603
-------
TABLE 7-2B.
LEVEL EC
(English
MONTHLY AVERAGE SULFUR REDUCTION BY A
CLEAKDG PLANT - TT.T.TTOIS ND. 6 COAL -
Units)
PIANT A
COAL
USE
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
Steam
IDT
QUANTITY*
(tons)
186,838
374,670
345,377
365,085
351,282
294,719
299,805
300,584
318,967
280,974
303,269
244,479
%S
3.98
4.27
4.74
4.72
4.10
4.45
4.87
5.16
5.05
5.44
4.98
5.20
KKHl
U = 8
FEED
BTU/lb
11, 113
10,780
10,929
10,991
10,940
10,499
10,304
10.707
10,956
10,741
10,417
10,765
(Ibs S02/l
.83
Ib S02/
106BTU
7.16
7.92
8.67
8.59
7.50
8.48
9.45
9.64
9.22
10.13
9.56
9.66
.06BTU)
a = 0.94
%S
3.64
3.93
3.83
3.94
3.83
3.71
4.40
4.34
4.44
4.46
4.42
4.29
PRODUCT
BTU/lb
12,073
12,073
12,011
12,047
12,059
12,032
12,297
12,278
12,370
12,320
12,267
12,292
RSD = 0.106
Ib SO2/
10GBTU
6.03
6.51
6.38
6.54
6.35
6.17
7.16
7.07
7.18
7.24
7.21
6.98
PRODUCT (Ibs SO2A06BTU)
p = 6
.74
SULFUR REMOVAL
a = 0.45
(%)
RSD = 0.067
y = 23.4
* Monthly Coal Throughput
Product sampled mechanically
a =5.86
RSD = .25
604
-------
TABLE 7-3A. MONTHLY AVERAGE SULHJR REDUCTION BY A LEVEL II
CLEANING PLANT - KENTUCKY #9 and #14 - (SI Units)
PLANT B
Feed
Product
Quantity*
(metric tens)
184
162
189
183
266
180
,913
,692
,817
,209
,168
,382
4
4
4
3
3
4
%S
.17
.64
.08
.96
.98
.13
kJAg
25,712
27,
27,
24,
27,
25,
Coal Use:
Peed
y = 3
(ng S02/J)
,164.8
a
557
981
533
054
430
Steam
= 191.
ng SO2/J
3,250.8
3,375.5
2,919.7
3,233.6
2,949.8
3,255.1
78
%S
3.21
3.23
3.24
3.14
3.13
3.18
RSD =
kJAg
30,411
30
30
32
30
30
,437
,360
,450
,236
..187
ng S02/J
2,115.6
2,124.2
2,137.1
1,939.3
2,072.6
2,111.3
0.061
Product (ng S02/J)
V = 2
Sulfur
,085.
5
a
= 43.
43
RSD =
0.021
Removal (%)
33.2 a =
4.26
RSD = 0.128
* Monthly Coal Throughput
Product sampled mechanically
605
-------
TABLE 7-3B. MONTHLY AVERAGE SULFUR REDUCTION BY A IEVEL II
CLEANING PLANT - KENTUCKY #9 and #14 - (English Units)
Feed Product
Lot
Quantity
(tons) *
203,873
179,374
209,280
201,994
293,460
198,878
Feed
V =7
%S
4.17
4.64
4.08
3.96
3.98
4.13
Coal
(Ibs
.36
BTU/
Ib
11,035
11,827
12,009
10,529
11,611
10,914
Ib S02/
106BTU
7.
7.
6.
7.
6.
7.
56
85
79
52
86
57
%S
3.21
3.23
3.24
3.14
3.13
3.18
BTO/
Ib
13,052
13,063
13,030
13,927
12,977
12,956
ib scy
106BTU
4.92
4.94
4.97
4.51
4.82
4.91
Use: Steam
SO2/106BTU)
a = 0.
Product fibs SCVIO
y =4
.85
a = 0.
446
6BTU)
101
PSD =
PSD =
0.061
0.021
Sulfur Removal (%)
y = 33.2 a = 4.26 RSD = 0.128
* Monthly Coal Throughput
Produt t sanpled mechanically
606
-------
TABLE 7-4A. MONTHLY AVERAGE SULFUR REDUCTION BY A LEVEL II
CLEANING PLANT - KENTUCKY #9 - (SI Units)
PLANT C
KKKI )
PRODUCT
Lot
Quantity
(metric tons) * %S kJ/kg
113,068
105,246
92,494
83,306
81,723
68,479
4.72 29,002
4.07 28,857
3.99 28,004
3.96 27,177
5.05 28,319
3.93 29,656
Coal Use:
Feed (ng SO2/J)
y = 3,014.3
Product (ng SO2/J)
y = 2,231.7
Sulfur Removal (%)
u = 25.2
ng SO2/J %S
3,263.7 3.40
2,825.1 3.40
2,855.2 3.36
2,919.7 3.30
3,573.3 3.35
2,657.4 3.38
Steam
a = 342.3
a = 28.0
a = 7.96%
kJAg
30,339
30,013
30,278
30,285
30,183
30,262
RSD = 0.114
RSD = 0.012
RSD = 0.316
ng SO2/J
2,244.6
2,270.4
2,223.1
2,184.4
2,223.1
2,236.0
Product sampled manually
607
-------
TABLE 7-4B. MDWTHLY AVERAGE SULFUR REDUCTION BY A LEVEL II
CLEANING PLANT - KENTUCKY #9- (English Units)
LOT
QUANTITY
(tons)
124,662
116,037
101,978
91,848
90,102
75,501
Feed
y = 7.
PLANT C
Peed
EHJ/ Ib SOz/
%S Ib 106BTU
4.72 12,447 7.59
4.07 12,385 6.57
3.99 12,019 6.64
3.96 11,664 6.79
5.05 12,154 8.31
3.93 12,728 6.18
Coal Use: Steam
(Ibs S02/106BTU)
01 a = 0.796
Product
ETO/
%S Ib
3.40 13,021
3.40 12,881
3.36 12,995
3.30 12,998
3.35 12,954
3.38 12,988
PSD = 0^114
Ib SO2/
106BTU
5.22
5.28
5.17
5.08
5.17
5.20
Product (Ibs SO2/106BTU)
y = 5.
19 a = 0.065
RSD = 0.012
Sulfur Removal (%)
y = 25.2. 0=7.96 RSD = 0.316
Product sampled manually
608
-------
TABLE 7-5A. M3NTHLY AVERAGE SULFUR REDUCTION FCR A LEVEL 2
COAL CLEANING PLANT - KENTUCKY Nos. 11 and 12 -
(SI Units)
PLANT D
JJLTl
QUANTITY
(metric tons) *
264,129
224,563
234,109
156,950
182,844
179,810
%S
3.99
4.25
3.77
—
-
5.03
kJAg ng SO2/J %S kJ/kg
25,171 3,177.7 3.31 29,246
22,883 3,719.5 3.39 29,113
24,675 3,061.6 3.29 29,435
3.20 29,565
3.15 29,572
22,992 4,381.7 2.97 29,899
ng SOg/J
2,266.1
2,334.9
2,240.3
2,167.2
2,132.8
1,990.9
Coal Use: Steam
Feed fng
y = 3,586
SOz/J)
.2 a =
602.0 BSD = 0.168
Product (ng SOz/J)
p = 2,188
.7 a =
114.0 RSD = 0.052
Sulfur Removal (%)
y = 36.83 a = 12.89 RSD = 0.350
*
Product sanpled manually
609
-------
TABLE 7-5B.
MDNTHLY AVERAGE SUIFUR REDUCTION FOR A LEVEL 2
COAL CLEANING PIANT - KENTOOOr Nos. 11 and 12 -
(English Uhits)
PLANT D
PRODUCT
LOT
QUANTITY
(tons) * %S
291,212
247,589
258,113
173,043
201,592
198,247
3.99
4.25
3.77
-
-
5.03
KTO/lb
10,803
9,821
10,590
-
-
9,868
Ib SO/
106BTU
7.39
8.65
7.12
-
-
10.19
%S
3.31
3.39
3.29
3.20
3.15
2.97
BTU/lb
12,552
12,495
12,633
12,689
12,692
12,832
Ib S02/
106BTU
5.27
5.43
5.21
5.04
4.96
4.63
Coal Use: Steam
Peed (Ib SO2/106BTU)
y = 8.34 a = 1.40 RSD = 0.168
Product (Ib S02/106BTO}
y = 5.09 a = 0.265 RSD = 0.052
Sulfur Removal (%)
U - 36.83 o = 12.89 RSD = 0.350
Product sampled manually
610
-------
TABLE 7-6A. MONTHLY AVERAGE SULFUR REDUCTION BY A LEVEL II
CLEANING PLANT - MIDDLE KITTANING (Olio No. 6) -
Units) PLANT E
COAL
USE
Steam
Steam
Steam
Steam
Steam
Steam
LOT
QUANTITY
(metric, tons)
154,565
138,162
162,063
145,074
189,246
163,255
FKMJ PRCDUCT
%S
4.07
3.73
3.98
4.46
3.96
3.45
«^^_^«v«_
kJ/ng
25,756
27,180
26,047
25,029
25,248
25,465
ng SO2/J
3,164.8
2,747.7
3,061.6
3,569.0
3,143.3
2,713.3
%S
3.03
2.86
3.06
3.05
3.06
2.99
kJ/ng
29,111
29,041
29,037
28,992
29,044
28,957
ng SOg/J
2,085.5
1,973.7
2,111.3
2,107.0
2,111.3
2,068.3
Feed (ng SO2/J)
p = 3,065.9 a = 322.9 RSD = 0.105
Product (ng SO2/J)
u = 2,076.9 a = 37.4 RSD = 0.018
Sulfur Removal (%}
]i = 32.0 a = 5.91 RSD = 0.185
Product sampled manually
611
-------
TABLE 7-6B. MDNTHLY AVERAGE SULFUR REDUCTION BY A LEVEL II
CLEANING PLANT - MIDDLE KTTTANING (Ohio No. 6) -
(English liiits)
PLANT E
FEED PRODUCT
COAL
USE
Steam
Steam
Steam
Steam
Steam
Steam
LOT
QUANTITY
(tons) *
170,413
152,329
178,680
159,949
208,650
179,994
%S BTO/lb
4.07 11,054
3.73 11,665
3.98 11,179
4.46 10,742
3.96 10,836
3.45 10,929
Ib S02/
106BTU %S
7.36 3.03
6.39 2.86
7.12 3.06
8.30 3.05
7.31 3.06
6.31 2.99
BTU
Ib
12,494
12,464
12,462
12,443
12,465
12,428
Ib S02j
10 6 BTU
4.85
4.59
4.91
4.90
4.91
4.81
Feed (Ibs SO2/10GBTU)
V = 7.13
Product
p = 4.83
a = 0.751
(Ibs SO2/106BTU)
a = 0.087
RSD = 0.105
RSD - .018
Sulfur Removal (%)
y = 32.0 a = 5.91 RSD = 0.185
Product sampled manually
612
-------
TABLE 7-7A. ANNUAL AVERAGE SULFUR REDUCTION BY A LEVEL 3
CLEANING PLANT - OHIO COAL - (SI Units)
PLANT F
FEED PRODUCT *
SEAM
18
LF
18
LF
#8
#9
#9
18
%S kJ/kej ng SO2/J %S
3.28 22,524 2919.7
2.92 21,313 2743.4
2.05 21,750 1887.7
2.55 27,459 1861.9
5.09 28,622 3564.7
2.51 28,885 1741.5
3.02 29,130 2076.9
2.674 29,498 1814.6
SEAM: Pittsburgh #8 and
Coal Use: Steam
Feed
U = 2326.3 ng SOz/J
Product
p = 1806.0 ng SOa/J
Sulfur Removal
3.96
2.94
2.78
2.34
3.59
2.15
2.51
2.33
#9; lower
a = 670.8
a = 426.1
kJ/kg
30,831
32,203
31,502
32,571
31,294
30,024
30,462
32,282
Freeport I6A
ng SO2/J
ng SOa/J
ng S02/J
2575.7
1827.5
1767.3
1440.5
2300.5
1436.2
1651.2
1444.8
CD1 Coal)
RSD = 0.288
RSD '- 0.236
y = 21.0% a = 9.85% RSD= 0.469
Product saitpled manually
613
-------
TABLE 7-7B. ANNUAL AVERAGE SULFUR REDUCTION BY A LEVEL 3
CLEANING PLANT - OHIO COAL- (English Units)
FEED PRODUCT
SEAM
#8
IF
#8
IF
#8
#9
#9
#8
%S BTa/lb
3.28 9,667
2.92 9,147
2.05 9,335
2.55 11,785
5.09 12,284
2.51 12,397
3.02 12,502
2.67 12,660
SEAM: Pittsburgh #8
Goal Use: Steam
Feed (Ibs S02/106BTU)
y = 5.41
Ib SO2/
106BTU
6.79 3
6.38 2
4.39 2
4.33 2
8.29 3
4.05 2
4.83 2
4.22 2
and #9; Lower
a = 1.56
%S
.96
.94
.78
.34
.59
.15
.51
.33
BTU/lb
13,232
13,821
13,520
13,979
13,431
12,886-.
13,074
13,855
Freeport #6A ('D'
RSD =
Ib SO2/
106BTU
5.99
4.25
4.11
3.35
5.35
3.34
3.84
3.36
Coal)
0.288
Product fibs SO9/106BTU)
y = 4.20
Sulf ur Removal
a = 0.991
RSD =
0.236
y = 21.0% a = 9.85% RSD = 0.469
*
Product sanpled manually
614
-------
TABLE 7-8A. DAILY AVERAGE SULFUR REDUCTION BY A LEVEL III
CLEANING PLANT - LOWER KITTANING - 5 DAY TESTS-
(SI Units)
Day
1
2
3
4
5
FEED
%S kJAg ng SO2/J %S
2.80 31,420 1,784.5 1.11
2.24 30,008 1,496.4 1.20
1.84 28,198 1,307.2 1.22
1.46 29,491 993.3 0.82
1.38 31,756 872.9 0.99
Lot Size =581 metric tons
Coal Use: Mstallurgical
Feed (ng SO2/J)
y = 1,290 crx = 369.8
Product (ng SO2/J)
y = 640.7 ax = 103.2
Sulfur Removal (%)
y = 48.3 a = H-4
Seem Coal
PRODUCT
kJAg ng SO2/J
34,069 653.6
33,200 722.4
32,960 739.6
33,533 490.2
33,634 589.1
RSD = 0.29
RSD = 0.16
RSD = 0.237
Lower Freeport - Kittening B,C,D,E
kGrab sample taken every 15 minutes over four hour period per day
615
-------
TABLE 7-8B. DAILY AVERAGE SULFUR REDUCTION BY A LEVEL III
CLEANING PLANT - LOWER KCTTANINS - 5 DAY TESTS-
(English Units)
PLANT G
Peed
Product
DAY
1
2
3
4
5
%S
2.80
2.24
1.84
1.46
1.38
BTO/lb
13,485
12,879
12,102
12,657
13,629
Ib S02/
106BTU
4.15
3.48
3.04
2,31
2.03
%S
1.11
1.20
1.22
0.82
0.99
BTU/lb
14,622
14,249
14,146
14,392
14,435
li> S02/
106BTU
1.52
1.68
1.72
1.14
. .1-37
lot Size = 640 Tens
Coal Use: Metallurgical
Feed
S02/106BTU)
= 3.00
RSD = 0.29
Product (Ibs SO2/lOeBTU)
u = 1.49 a = .24
RSD = 0.16
Sulfur Removal (%)
U = 48.3 a = 11.4 RSD = 0.237
Seam Coal
Lower Freeport - Kittaning B,C,D,E
*Grab sample taken every 15 minutes over four hour period per day
616
-------
TABLE 7-9A. DAILY AVERAGE SULFUR REDUCTION BY A LEVEL III
PLANT - SOUTH WESTERN VIRGINIA SEAMS - 5 DAY
TESTS - (SI Units)*
PLANT H
Day
1
2
3
4
5
FEED
%s kJAg
1.24 25,243
.92 24,178
.82 22,766
1.15 21,394
1.10 22,722
Lot Size = 2,395 -
Coal Use: Steam
Feed (ng SO2/J)
y = 903.0
Product (nq SO2/J)
y = 696.6
Sulfur Removal (%)
y = 21.7
Seam Coal
Elkhorn-RLder
Lyons
Dorchester
Norton
Clintwood
ng SO2/J %S
984.7 1.48
761.1 1.31
722.4 0.89
1,075.0 1.06
971.8 1.10
2,503 metric tons per
ax = 154. 8
a = 133.3
X
a = 17.2
% Feed
12.5
12.5
25.0
25.0
25.0
PRODUCT
kJAg ng SO2/J
33,997 872.9
33,666 778.3
33,226 537.5
33,617 640.7
34,074 645.0
day
RSD = 0.17
RSD = 0.19
RSD = .793
Grab sample taken every 15 minutes over four hour period per day
617
-------
DAY
1
2
3
4
5
TABLE 7-9B. DAILY AVERAGE SULFUR REDUCTION BY A LEVEL
PLANT - SOUTH WESTERN VIRGINIA SEAMS - 5 DAY TESTS
Feed Product
Ib S02/
%S BTO/lb 106BTU %S BTU/lb
1.24 10,834 2.29 1.48 14,591
.92 10,377 1.77 1.31 14,449
.82 9,771 1.68 0.89 14,260
1.15 9,182 2.50 1.06 14,428
1.10 9,782 2.26 1.10 14, 624 =
Lot Size = 2,640-2,760 tons Per Day
Coal Use: Steam
Feed (Ibs SO2/106BTa)
y = 2.10 cx = .36 RSD = 0.17
Produce (Ibs SO2/L06Hru)
y = 1.62 ax = .31 RSD = 0.19
Sulfur RertDval (%)
y = 21.7 a = 17.2 RSD = .793
Seam Coal % Feed
Elkhorn-Rider 12.5
Lyons 12.5
Dorchester 25.0
Norton 25.0
dintwmd 25.0
III
*
Ib SO2/
106BTU
2.03
1.81
1.25
1.49
1.50
Grab sanple taken every 15 minutes over four hour period per day
618
-------
TABLE 7-10A. DAILY AVERAGE SULFUR REDUCTION BY A LEVEL III *
CLEANING PLANT - REFUSE COAL - 5 DAY TESTS -
(Metric Units)
PLANT I
FEED PRODUCT
Day %S
ng SO2/J
%S
kJAg
ng SO2/J
1
2
3
4
5
.603
.637
1.099
.570
.582
16,466
18,936
21,166
20,206
18,377
735.3
675.1
1,040.6
563.3
636.4
.948
.835
1.009
.830
.850
31,555
30,854
30,083
31,066
30,716
602.0
541.8
670.8
533.2
554.7
Lot Size = 544 metric tons
Coal Use: Metallurgical
Feed (ng SO2/J)
y = 731.0
Product (ng SO2/J)
y = 580.5
Sulfur Removal (%)
y = 18.3
GOB Coal (Refuse)
a = 184.9
a = 55.9
A.
RSD = 0.25
RSD = 0.099
RSD = 0.605
Grab sample taken every 15 minutes over four hour period per day
619
-------
TABLE 7-10B. DAILY AVERAGE SULFUR REDUCTION BY A LEVEL III
CLEANING PIANT - REFUSE CCftL - 5 DAY TESTS -
(English Units)
FEED PRODUCT
DAY
1
2
3
4
5
%S
.603
.637
1.099
.570
.582
BTU/lb
7,067
8,127
9,084
8,672
7,887
Ib S02/
106BTU
1.71
1.57
2.42
1.31
1.48
%S
.948
.835
1.009
.830
.850
BTU/lb
13,543
13,242
12,911
13,333
13,183
Ib S02/
106BTU
1.40
1.26
1.56
1.24
1.29
Lot Size = 600 Tons
Coal Use: Metallurgical
Feed (Ibs SO2A06BTU)
y = 1.70 ax= .43
Product (Ibs SO2/106BTU)
y = 1.35 ax= .13
Sulfur Renoval
y = 18.3% a = 11.1%
GOB Coal (Refuse)
RSD = 0.25
RSD = 0.099
RSD = 0.605
Grab sarrple taken every 15 minutes over four hour period per day
620
-------
JKE . - D
TigJATKHSHIP- 3£T»«E£K E££3 AND-PRODUCT RSAnVE"
- ••- —= •—ir^z
1 -•• ' ; ' —
— - • —• : y
.:5 yf
- - - - * '—; . 7 j^:
.20
KJU FEED
621
-------
en a different seam. Tte "line of best fit" equation is:
BSDp= .837 RSDp- .051
where RSDp = Relative Standard Deviation of the product ooal
= Relative Standard Deviation of the feed ooal
Ihis equation indicates that the expected value of the RSDp is less than
0.05 of the RSEL. 3te Office of Air Quality Planning and Standards (OAQPS)
uses the value for both raw coal and cleaned ooal of RSD = 0.15 in its
calculations concerning sulfur dioxide emissions. Based on this equation,
derived from the percent reduction of RSD at these nine plants, a
corresponding value for RSDp = 0.080 should be used if a value of RSDp =
0.15 is applied to the raw coal.
It is significant that the two preparation plants that did not
provide at least 35% reduction of RSD were cleaning blends of coal or
various coals during the tine period studied {i.e. Plant F cleans three
different seam coals and Plant H cleans a blend of five different coals) .
7.3.2 analysis of Aggregated Data— By Seam and Cleaning Level
As mentioned above, sulfur and BTO content feed and product coal
data were received on 46 preparation plants. For the majority of these
plants only one value was given for feed and product characteristics, so
analyses of in-plant variation is not possible. For the data tables in
Appendix A, the final column presents percent removal in terms of
ng S02/ J.
Ib examine plant capabilities, but avoid aggregating all the data,
Versar anal^*zed the information on a seam and cleaning level basis
within each region. For example, Plant A is a level 3 cleaning plant
beneficiating Illinois f6 coal. Versar was provided with cleaning data
from eight other plants that receive Illinois #6 coal, of which five also
have level 3 cleaning. Tables 7-11 through 7-14 present sulfur removal
by seam and cleaning level for each region for data received from the
coal companies and Versar' s field test results .
622
-------
TABLE 7-11. EASTERN MIDWEST COAL SULFUR REDUCTION BY SEAM
AND CLEANING LEVEL
SEAM 1
Illinois #6 5.6/3
Illinois/Indiana #2 & #3
Illinois #5
Kentucky #9 0/1
Kentucky #11 & #12
Weighted Averages 4.2/4
Values shown are percent reduction
Cleaning Level
2 3
36.3/2 26.7/16
43.4/2
23.4/2
29.2A2
36.8/6
33.2/22 26.3/18
in ;ig SO2/ J/No.
TABLE 7-12. NORTHERN APPALACHIA COAL SULFOR
Average
Reduction
4 2-4 Pts.
34.9/1 28% 22
43% 2
23% 2
29% 13
37% 6
34.9/1 30% 45
of data points.
REDUCTION BY
SEAM AND CLEANING LEVEL
SEAM 1
Pittsburgh, #8 (0/1)
#9
Middle Kittaning (#6)
Lower Freeport (#6A)
Lower Kittaning
Upper Freeport
Cleaning Level
2 3
21.5/1 30.6/13
19.0/2
32.0/6
23.0/2
48.4/5*
Average
Reduction
Levels Data
4 2-4 Points
29.8/3 30% 17
19% 2
49.2/2 36% 8
23% 2
45.4/1 48% 6
35.1/2 35% 2
Weighted Averages (0/1) 30.1/7 32.9/2 37.9/8 33%
Values shown are percent reduction in ng SO2/J/No- of data points.
37
*Blend of B,C,D,E , 'B' predominates
623
-------
TABLE 7-12. SOUTHERN APPALACHIA COAL SULFUR REDUCTION BY
SEAM AND CLEANING LEVEL
SEAM
Cedar Grove
Jewell
Pocahontas 3 & 4
Sewen
Various Seams
Weighted Averages
Values shown are percent
TABLE 7-14.
SEAM 1
Mary Lee N.D.
Blue Creek N.D.
Weighted Averages N.D.
Cleaning Level
1 11
N.D. 11.3/3
N.D. N.D. N.D.
N.D. N.D. N.D.
N.D. N.D. 11. 5/1
N.D. 0/2 14.3/12
N.D. 2.6/5 14.1/13
reduction in ng SO2/ J/No. of
Average
Reduction
Levels
4 2-4
-25.0/1 2%
34.0/4 34%
39.4/3 39%
54.1/2 40%
29.3/14 N.D.
31.2/24 23%
data points.
Data
Points
4
4
3
3
N.D.
42
ALABAMA COAL SULFUR REDUCTION BY CLEANING LEVEL
Cleaning Level
2 3
N.D. N.D. 40
N.D. N.D. 42
N.D. N.D. 41
Average
Reduction
4 Levels 2-4
.1/3 40%
.8/2 43%
.1/5 41%
Data
Points
3
2
5
Values shown are percent reduction in ng SO2/ J/No. of data points.
N.D. = No Data
624
-------
By cleaning level, the ng SO2/J removed was no definitive
trend, except in Southern Appalachia where deep cleaning of the fine coal
(cleaning level 4) almost doubles the reduction of SO2 per unit heat over
level 3. Generally, however, the difference between cleaning levels
2, 3, and 4 is negligible relative to reduction capabilities.
The tables also show that reduction varies for seams in the sane
region. This is due to the varying pyrite quantities in each seam which
can be removed by beneficiation. The variation is striking between the
Southern Appalachian Cedar Grove seam, which allows only small percentage
reductions, and the Pocahontas Nos. 3 and 4 and Sewell seams which allow
at least 40 percent reduction in ng SOa/J.
Percent removal of _hg - SO^/J is relatively constant in the four
coal regions analyzed. Reduction in SO* emissions per unit heat ranges from
25$ in Southern Appalachia to 41% in Alabama. The average reduction" is about
30% for all regions.
As a supplement to the data received from the coal companies and
Versar tests, data were obtained from the 1972 EPA survey of coal prepara-
tion plants. About half the plants surveyed provided both ROM and product
coal information. The data taken from ^he survey and compiled were: code #
of plant, name of plant/mine, coal company, location (county, state, region) ,
operating capacity for raw and clean coal (T/hr) , cleaning level, and BTU,
ash, total sulfur (S-J / pyritic sulfur (S ) and organic sulfur (S )
for RDM and product usage (Utility, Metallurgical, other) . A complete
listing of the data is provided in Appendix D. The data consisted of annual
average information for each plant. As a result analysis of sulfur reduction
within individual preparation plants was not possible. Also, since seam
origin for the run-of-mine coal was not provided, analyses on a seam basis
could not be performed. The major utility of the data was to calculate
the reduction of ng SO2/J on a cleaning level and regional basis.
Table 7-15 summarizes the results.
625
-------
XAHE£ 7-15. SDIFDR MISSION REDUCTION DMA BASED ON TEE
1972 EPA
CCAL
Region
(Pa
N. Appalachia
S. Appalachian
E. Midwest
MT arr^lflrhifln
S. Appalachian
E. Midwest
western
OOMBEJED
M. Appalachian
S. Appalachian
£. Micwes .
Cleaning Level
234
rcentageng
No.
17.2/10
20.7/8
29.4/3
37.8/3
34.5/2
1.95 A
0
22.0/13
23.5/10
21.3/4
SOi/J Reduction/
of Points)
25.5/2 35.5/8
7.4/10 16.2/14
16.4/8 20.7/3
MEIALIUBGICAL CCAL
40.9/2 46.7/5
16.5/8 29. 6/27
-1.73/1 16.6/3
0 9/2
33.2/4 39. 3 A3
U.4A3 24.4/41
14.4/9 18.6/5
Mean
^anoval
Levels 2-4
26.1
14.3
21.3
41.8
26.5
5.51
3:0
31%
21%
17%
Total
Data Points
20
32
14
10
37
5
2
30
69
19
626
-------
A ocrnparisan of the ooal company provided data and EPA 1972 survey
data-shows considerable consistency. For example, on Northern Appalachian
coa&*£or cleaning levels' 3 and 4 (and the mean reduction for all cleaning
levai*) the results for the two sets of data are within two percent. The
Soutfcfcsm Appalachian coal results are not as consistent by individual
cleaning level, but the mean reduction values for cleaning levels 2, 3
and 4 combined are within four percent. Eastern Midwest coal is the
least consistent with a difference between the two data sets of 11-16
percent.
All regions and data sets, except the 1972 Eastern Midwest coal
cleaning information, show that deep cleaning through a fine coal circuit
(i.e. cleaning level 4) reduces the roost ng SO2/J of the four cleaning
levels. Cleaning level 1 provides the least.
Because of its consistency with long-term average data, we conclude
that the coal company provided data can be used to estimate the capability
of coal cleaning to remove sulfur and enhance energy content.
7.4 CONCLUSIONS
Ihe analysis of the collected data supports the following con-
clusions:
• Physical coal cleaning is an effective sulfur dioxide control
technology. Hie ng SO2/J value of the coal is significantly
reduced by coal cleaning. Ihe average reductions achieved for
different coal regions using coal company-provided data were 33%
for Northern Appalachian coals, 23% for Southern Appalachian
coals, and 30% for Eastern Midwest coals.
• In terms of ng SO2/ J , preparation plants reduced the mean,
standard deviation, and relative standard deviation of the
product coal as compared to feed coal in almost every case. Ihe
only exceptions were several plants cleaning low sulfur Southern
Appalachian coal.
627
-------
The difference in reduction of His S02/106BTU between cleaning
levels 2, 3, and 4 is small,, although cleaning level 4 (deep
cleaning) always showed the greatest reduction on a regional
basis.
BSD reduction between feed coal and product coal is only valid
for ..individual cleaning plant results and should not be
aggregated by seam or region.
628
-------
SECTION 7.0
REFERENCES
1. Holmes, John G., Jr., (Chief, Steam-Electric Generation Branch, TVA),
The Effect of Coal Quality on the Operation and Maintenance of Large
Central Station Boilers, paper for presentation of Annual Meeting of
the American Institute of Mining, Metallurgical and Petroleum Engineers,
Washington, D.C., February 16-20, 1969.
2. "AP-42, Compilation of Air Pollution Environmental Factors", U.S.
Environmental Protection Agency, Washington, D.C.
3. 43 FR 42178. (September 19, 1978).
4. SO2 Emission Reduction Data from Commercial Physical Coal Cleaning
Plants and Analysis of Product Sulfur Variability, Draft Final Report.
Task 600. EPA Contract No. 68-02-2199. Versar, Inc. October 18, 1978.
5. Sedman, C. and L. Jones. EPA Survey of Air Emissions from Coal
Preparation Plants. U.S. EPA. Office of Air Quality Planning and
Standards. 1972. (Unpublished data).
629
-------
APPENDIX A
KXUMENEATIQN FOR THE RESERVE PROCESS
MODEL
630
-------
Documentation
To simulate the desulfurization potential of physical ooal cleaning a
generalized approach was taken. The methodology characterized the entire
U.S. reserve base via 36,000 composite coal analyses showing total weight,
percent ash, percent sulfur, and BTU content. In addition, each reserve
base record was associated with one float-sink analysis as reported by
Cavallaro, Johnson, and Deurbrouck in RI8118. The mathematical approach
adopted allows the characteristics of the cleaned ooal to be obtained from
those of the raw coal by scaling the raw coal characteristics by factors
dependent on the cleaning process involved and the washability - analysis
of the raw coal.
The data used in this study were as follows:
• 587 sets of washability analyses for ooal from sample mines in
the U.S. as reported by Cavallaro, Johnston, and Deurbrouck.
• The reserve base of U.S. coal, consisting of 3,167 records
specifying the weight of each resource for both strip and
underground coal, together with the maximum, minimum, and mean
levels of the major constituents of the coal in that resource.
These data are consistent with those suinnarized in Thomson and
York and Hamilton, White and Matson. u'
• Approximately 50,000 detailed sample coal analyses taken from
the coal data base of the U.S. Bureau of Mines in Denver,
Colorado. These data include the composition of each sample
in terms of its ash, sulfur, and heat content.
Given these three sets of data as a starting point, the first step
in the analysis was to overlay them into a single data base which contained
36,000 coal resource records and which had the following information for
each:
• The location in terms of its region, state, county, and bed.
• The weight in tons of both strip and underground ooal.
• The msan percent by weight of ash, organic sulfur,
and pyritic sulfur.
631
-------
• The mean heat content expressed in BTU/lb.
• The float-sink distribution of the coal characteristics.
Tlie coal reserve resources and the washability data of KI8118 are
each specified by state, bed and county; however, there is not an exact
correspondence between reserves and washability data since for many of
the reserves there are no washability data. To determine the desulfurization
by physical cleaning processes of coal resources having no washability
data, the reserve resources were assigned washability data in the following
manner:
• If one or more state, bed and county matches are found between
a given reserve and the washability data, the reserve is
assigned that washability data set which has coal composition
closest (in the least squares sense) to the composition of
the reserve. If no conposition data are given for that reserve
source, the resource is subdivided into as many parts as there
are matching washability data sets and each part is assigned
one of the washability analyses.
• If there are no state, bed and county matches between a given
reserve resource and the washability data, look for state,
bed and region matches. Assign the reserve the matching
washability data as in the above.
• If no matches occur in either of the above, look for state
and county matches. Assign the reserve the matching
washability data as in the first mentioned bullet.
• If no matches occur in the above, assign the reserve the
washability data from other beds in the same state and region
as in the first mentioned bullet.
• For some states there are no washability analyses at all;
reserve resources in those states are assigned washability
data from other states in the same region as follows: assign
632
-------
North Carolina to Virginia
Michigan to All states in the
Eastern Midwest region
Texas to Oklahoma
South Dakota to North Dakota
Idaho
Oregon to Montana and Wyoming
Washington
Assign the reserve washability data of the relevant state or states ley the
least squares method described in the first paragraph above.
In this manner all the coal reserves are assigned washability data.
However, since no washability data existed in RI 8118 for Alaskan coal
or for Pennsylvania anthracite coal, these reserves were not included.
Ihe analytical data file consists of approximately 50,000 records
each of which gives coal corrposition data for a reserve resource sample.
These sample analysis data were overlaid with the reserve base to obtain
coal composition data for each reserve resource. Each resource has several
sample analyses corresponding to it and, in the absence of any method of
assigning weights'to the different analyses for the same resource, all
were weighted equally. The variation in the samples for a given resource
was taken into account by dividing all the coal in that reserve resource
into as many parts as there are corresponding sample analyses and each
part was assigned the composition of one of the samples. For those
reserves that have composition data given on the reserves file and on the
analysis file it was assumed that the mean of all the sample analyses
should be equal to the composition data given on the reserves tape; if
necessary the sample analysis data was scaled to make this so. Reserves
having no composition data given on the reserves file were assigned the
coal composition given by the RI 8118 washability data. Reserves having
composition data given on "the reserves file but no sample analysis used
the coal composition given on the reserves file.
633
-------
By overlaying the coal reserves file and the analysis file in this
manner an expanded reserves file of approxiitately 36,000 records was
obtained, each record consisting of resource identification (by state,
bed and county), weight of coal for both strip and underground, and the
composition of the coal. The reason 36,000 records were obtained, and
not 50,000 as on the original analysis file, was because a number of
the sample analyses either do not correspond to any of the reserve
resources or correspond to a given resource which shows no coal available
in both strip and underground reserve. For a given state, bed and county
group there are several records on the file each having the same weight
of reserves (such that the total adds up to the actual weight in the
resource) but having possibly different composition data corresponding
to the different sample analyses for that resource. Ihe sulfur content
of the coal is given in the coal reserves file and in the analysis file
only as total sulfur content; this was divided into pyritic and organic
sulfur in the ratio in which these two occur in the washability data
that corresponds to that resource.
To implement the effect of the cleaning processes on the reserve
resources, use has been made of the fact that a single washability analysis
corresponds to many records en the overlaid reserves data file. The
methodology developed can treat any cleaning process that is of one of
the following specific types.
1. A physical cleaning process;
2. A chemical cleaning process that removes specified percentages
of the characteristics of the raw coal (ash, pyritic sulfur,
organic sulfur);
3. A chemical cleaning process that reduces the levels of the
characteristics to given threshold values;
4. Gcnibinations of 1 and 3 or combinations of 2 and 3;
5. A blend of the product coal from two of the above process; and
6. Cue of processes 1-4 on the coal product of another of processes 1-4.
634
-------
Reductions in the weight and energy per unit mass of the ooal by given
percentages can be specified directly for processes of types 2 and 3 and
for processes of type I as operating penalties over and above the
reductions caused by the physical separation process. Physical cleaning
processes are restricted by the RE 8118 washability data to top sizes of
1-1/2 inches, 3/8 inch or 14 nesh, and to specific gravity fractions of
float -1.3, 1.3-1.4, 1.4-1.6 or the sink from 1,6.
A physical coal cleaning process can be specified by the top size
to vAiich the coal is crushed before separation plus the following
quantities for each specific gravity fraction:
• The percent ash removed;
• The percent pyritic sulfur removed;
• The percent organic sulfur removed;
• The percent BTQ/lb recovery; and
• Tne percent weight recovery (=0.0 for a specific gravity
fraction which is discarded).
No allowance was made for process inefficiency (misplaced material) in
this analysis of available reserves. These quantities are in addition
to the anount of each characteristic that is removed by the physical
separation process. A cleaning process of type 2 can be expressed in
terms of the above five quantities alone. A cleaning process of type 3
can be expressed in terms of the above quantities together with threshold
values for those characteristics that are reduced to threshold levels.
Given such a specification of a cleaning process of type 1 or 2
and the file of the RI 8118 washability data, it is possible to construct
an array (Ti, j,k) which fully characterizes the cleaning of coal fron a
particular state, bed and county group by the cleaning process. Here i
corresponds to the index of the washability data (determined from the
state, bed and county group), j corresponds to the cleaning process under
consideration, and k corresponds to the characteristics of the coal that
are subject to change by cleaning (weight, ash, pyritic sulfur, organic
635
-------
sulfur, and BTU/Lb) . On cleaning by process j a sanple of raw coal having
state, bed and county group corresponding to washability index i and
characteristics R(k) , one obtains cleaned coal having characteristics
C(k) = R(k)xT(i,j,k).
TJius the effect of a cleaning process on coal of a given washability is
obtained simply by scaling the characteristics of the coal by the relevant
factors from the T array. Chemical cleaning, which reduces characteristics
to threshold values (type 3 processes) , can be simulated by reducing the
relevant characteristics after scaling by the T factors.
The array (Ti,j,k) is computed as follows. For a type 2 cleaning
process j the specification of the process described above completely
determines the T matrix. The process specification gives the proportion
D(k) of characteristic k of the feed coal that appears in the cleaned
coal. If
k=l corresponds to weight
k=2 " corresponds to ash content
k=3 corresponds to pyritic sulfur content
Jc=4 corresponds to organic sulfur content
k=5 corresponds to BTO/lb for the coal
then
k=2,3,4,5
This is independent of the washability index i.
For a type 1 process the proportion P(£,k) of the feed coal in
specific gravity fraction £ and having characteristic k that appears in
the cleaned coal is given by the washability data for the feed coal. Any
additional reduction in the levels of the characteristics is given by the
process specification and can be expressed as D(£,k) . Combining these two,
the proportion of the feed coal appearing in the product is
636
-------
where the summation is over the four specific gravity fractions of the
RI 8118 washability data. Then
and
T(i,j,k)=£ Pa,k)xDU,k)/T(i,j,l), k=2,3,4,5.
£
Having constructed this T matrix from the specifications of the
cleaning processes and the washability data, it is combined with the over-
laid reserves and analytical data file. The characteristics of the raw
coal from each of the 36,000 reserve resource records on the file are
scaled by the appropriate factors from the T matrix to obtain the
characteristics of that coal after cleaning by each of the processes.
Any reduction in characteristic values to threshold values for a type 3
process is done at this stage. A new file is created consisting of
36,000 records as before but now each record contains not just the reserve
levels and characteristics of the raw coal but those values also for the
processed coal for each cleaning process. This file is then used to
assess the desulfurization potential of the coal reserves.
637
-------
APPENDIX A REFERENCES
1. Cavallaro, J.A., Johnston, M.T., and Deurbrouck, A.W., "Sulfur
Reduction Potential of the Goals of the United States", U.S.
Bureau of Mines, RI 8118 (1976).
2. Ibid.
3. Thomas, R.D., and York, H.F., "Ohe Reserve Base of U.S. Coals by
Sulfur Content, The Eastern States", 1C 8680, U.S. Bureau of Mines,
Washington, D.C. (1975), 537 pp.
4. Hamilton, P.A., White, D.H., and Matson, T.K., "The Reserve Base of
U.S. Coals by Sulfur Content, The Western States", 1C 8693, U.S.
Bureau of Mines, Washington, D.C. (1975), 322 pp.
638
-------
APPENDIX B
LEVEL!ZED COSTS FOR LOW SUIFUR GOALS
639
-------
LEVELIZED COST CAIOEATIONS
The levelized cost is equivalent to a fixed current-dollar cost during
each year of the economic lifetime of a facility. Because of the positive
market rate of interest, the levelized cost of a facility in any year of oper-
ation must be discounted back to a base year. The sum of the levelized costs
discounted back to the base year during each year of operation is called the
present discount value of the cost.
Since the annual current-value cost is generally not constant, the present
discounted value is, in fact, the sum of a series of discounted variable costs.
One can form a series of terms representing equivalent fixed annual costs
discounted back to the base year, such that the sum of the terms equals the
present discount value. It is the equivalent fixed annual cost of this
series that is defined as the levelized cost.
In mathematical terms, the procedure for calculating the present dis-
count value and the levelized cost is described in the following two steps:
1. Find the present discount value, PDV, of the costs:
N C
n=0 (I4d)n
C = C.^T /-IJL \n =- the cost of the variable being evaluated
n i/l (Up)
n=l,N ^
in current dollars in the n year.
d = the average discount rate during the economic lifetime.
CA = the cost of the variable being evaluated in the initial year.
p = the average price escalation.
Find the levelized cost, LC, (the equivalent constant annual
cost) such that the PDV ccnputed on the basis of LC will be equal
to the PDV found in step 1 above:
640
-------
The levelized oost is equivalent to a fixed current-dollar cost during
each year of the economic lifetime of a facility. Because of the positive
market rate of interest, the levelized oost of a facility in any year of
operation must be discounted back to the base year. The sum of the
levelized costs discounted back to the base year during each year of
operation is called the present discounted value (PDV) of the oost.
Furthermore, the contribution of the levelized oost to the PDV in the base
year (n=l) will decrease as n increases. The total PDV is equal to the
sum of the discounted values of the levelized cost for all years throughout
the lifetime of the facility.
In fact/ there is not generally a constant annual real cost; the PDV
is a sum of discounted real costs that vary from year to year. The levelized
oost (the equivalent fixed yearly real oost) is found by first finding the
value of the PDV for a base year, and then equating this value to a sum
of a series of terms, each of which is the levelized cost discounted back
to the base year at an average discount rate. In mathematical terms, the
procedure for calculating PDV and levelized cost is described in the follow-
ing two steps:
N
PDV = LC
n=o
n
LC =
PDV.
An equivalent way of expressing the levelized cost (I£) is to multiply
the cost in the initial year by the leveHzation factor (LF):
LF =
d)
N
(i + a>N -
1 + p
1-
The first factor in the above equation is often referred to as the capital
recovery factor (CRF).
641
-------
For capital costs there are additional charges associated with an invest-
ment beyond the initial ones levelized by applying the above equations.
Taxes, insurance and general and administrative expenses required for capital
equipment should be accounted for as well, usually by applying a fixed charge
rate to the initial investment amount to arrive at a total levelized cost
associated with capital expenditure. The fixed charge rate is defined as:
PCR = CRF + TAX + INS + G&A
where
PCR = fixed charge rate d (1 -f d)N
CRF = capital recovery factor = - ^ -
INS = insurance and real estate taxes as a levelized percent of the
initial investment
G&A = general and administrative expenses as a levelized percent of the
initial investment.
The values presented as levelized costs in the following tables are
the sum of (1) the levelized capital costs found by multiplying the initial
investment costs by the fixed charge rate, and (2) the levelized operating
and maintenance (O&M) costs, found by multiplying the first-year O&M costs
by the appropriate levelizing factor.
The fixed charge rates and legalization factors, and the values upon
which they are based, are listed in Table B-l for the four major types
of industrial coal-burning boilers considered in this study. The
levelized coal costs are obtained by applying levelizing factors to the
annual coal costs (see Table 4-3) : 2.57 to the field-erected boilers,
2.13 to the 30 NW packaged boiler.
The computation and results of levelizing the low-sulfur coal costs
are presented in Tables B-2 through B-l,
642
-------
TABLE B-l. VALUES USED IN THE. COST ANALYSIS OF LOW-SULFUR- CDAL-CXMBUSTION
ITEM
Packaged Watertube:
Underfeed Stoker
Field Erected Watertube:
• Spreader Stoker
• Chain-Grate Stoker
• Pulverized Coal
Investment Life
Operating Cost
Escalation Rate
Discount Rate
Levelization
Factor
Capita] Recovery
Factor
Other Fixed
Charges
Fixed Charge
Rate
30 years
7%
10%
2.13
10.61%
4%
14.61%
45 years
7%
10%
2.57
10.14%
4%
14.14%
643
-------
Table B-2. ANNUAUZED AND U2VELIZED FtEL COSTS (1978 $) AND FUEL INPUTS BY BOILER-TYrE CAPACITY*
(Ti
Coal Sourcu
Dnclifuian, VA
(Uw-Sul Fur Fasten))
Ian Ail 11103, CO
WllJistori, NI)
Gillette, WY
I*x:k Springs,
OHI)up, NM
i|>icl ty
1 rate)
\,
;ni)
8.8
(30 X 106
$/Year
Annual
165,600
(425,600)
121,400
(312,000)
78,740
(202,400)
57,800
(148,500
99,100
(254,700)
188,800
(305,300)
MW
B'lU/hr)
Kkg/Year
5,250
6,260
10,200
8,410
6,210
6,350
44 m
(150 X 10* nvu/hr)
$/Year Kkg/year
Annual
(level ! ned)
828,000 26,300
(2,128,000)
607,000 31,300
(1,556,000)
393,700 51,000
(1,011,800)
289,000 42,000
(742,700)
495,500 31,000
(1,273,400)
594,000 31,800
(1,526,500)
58.6 M4
(200 X 1C6 mu/hr)
$/Year Kkg/year
Annual
(level izrxl)
1,109,000 35,200
(2,050,100)
813,400 41,900
(2,090,400)
527,560 68,300
(1,355,800)
387,300 68,300
(995,400)
664,000 41,600
(1,706,500)
796,000 42,500
(2,045,700)
* Costs air; bnsed upon (1) spot prices, C.o.b. mine, In $/(!! (see Table 4-4) and (2) capacity factor
equal to 0.6. Except wtere Indicated otherwise, tlK levellzecl costs apply to f jeld-erected water-
l»>iler; a level!zatiui factor of 2.57 Is applied (see Table 4-3).
-------
Table B-3. TIE COMPUTATION OP ANNUALIZED AND DEVELIZED COSTS FOR THE STANDARD BOII£RS (1978$)
(EXCLUDING COAL COSTS)
1 Direct
(less
Boiler Type:
Coal Typej
Costs
fuel)
2 Overhead
3 O&M Costs
(excluding fuel)
4 Levelized O&M Cost
(excluding fuel)
5 Capital Charges
(levelized)£
6 Annual ized Cost
(excluding fuel)
7 Levelized Cost
(excluding fuel)
Package Watertube
30 X 106 BTU/hr
Eastern
low-sulfur
442,700
178,300
621,000
1,322,730
260,400
881,400
1,583,130
Subbit.
496,500
185,200
681,700
1,452,021
345,800
1,027,500
1,797,821
Field-Erected
Watertube
75 X 10 6 BTU/hr
Eastern
low-sulfur
773,300
177,300
, 950,600
2,443,042
629,000
1,579,600
3,072,042
Subbit.
864,400
434,500
1,298,900
3,338,173
692,300
1,991,200
4,030,473
Field -Erected
Watertube
150 X 106 BTU/hr
Eastern
low-sulfur
1,101,500
377,400
1,478,900
3,800,773
1,161,400
2,640,300
4,962,173
Subbit.
1,267,100
400,200
1,667,300
4,284,961
1,519,000
3,186,300
5,803,961
Field -Erected
Watertube
200 X 10C BTU/hr
Eastern
low-sulfur Subbit.
1,404,500 1,610,700
386,400 415,100
1,790,900 2,025,800
t
4,602,613 5,206,306
1,549,100 1,992,800
3,340,000 4,018,600
6,151,713 7,199,106
-------
Table B-4. ESTIMATED COSTS (1978 ?) OP BURNING ItW-SUIFUR OOAI^S
TYPEi PACKK3KD WATEKIUBE, UNDEW-'KH} STOKER .
0.8 WW (30 X 10'BTU/nrh 150 PSIcyaat.teni>. 1
en
£*
CT\
Goal
Source
Buchanan, Va.
Laa Arvimaa, Cb.
Willisbon, N.D.
Gillette, Wy.
Rock Springs, Wy.
Gallup, N.M.
S*1"
Type
D
B
lignite
SB
B
SB
Standard within Which
Uncontrolled Emissions Pall
ny SOj/J
860
516
1,075
860
645
860
(Ib SO»/10*BflU) "
(2.0
(1.2)
(2.5) SIP
(2.0)
(1.5)
(2.0)
Yearly Coats (1978 $)
Annualized
Cost
1,047,500
1,075,800
1,106,200
1,085,300
1,053,500
1,146,300
Legalized
Costa
2,008,700
1,895,130
2,000,200
1,946,300
1,837,800
2,103,100
I The costs liere (annualized and levelized) are famd by adding the yearly fuel costs (annual and
levulized) in Table B-2 to the yearly boiler costs excluding fuel costs (annualized and levelized)
in Table B-3.
o The bituminous coals are assumed to be burned in boilers constructed to bum "eastern low sulfur coal";
i-.lie subbituminous coal and lignite are assumed to be burned in boilers constructed to bum "sub-
bituminous coal" (nee Table B-3).
••• Those are the most strinyent of five SO? standards considered here, which the uncontrolled SOz emissions
From each coal can meet. The standards (ng SOz/J) are 516, 645, 860, 1,075, 1,290. We assume no
retention of sulfur as SOz in the boiler.
-------
*»
Table B-5. ESTIMATED COSTS (1978 $) OF BURNItC LOW-SULFUR CQMS
BOILER TYPE: FIELD-ERflCHH) WVTERTUBE
22 MW (75 X 10s BTU/hr); 150 PSIG/sat.tenp. r
Ctoal
Source
Buchanan, Va.
Las Animas, Go.
Williston, N.D.
Gillette, Wy.
Rock Springs, Vty.
Gallup, N.M.
Coal0
Type
B
0
Tlgnite
SB
D
SB
Standard within Wiich
Uncontrolled Emissions Fall
ngSOz/J
860
516
1,075
860
645
860
(Ib S02/10*BTU) "
(2.0
(1.2)
(2.5) SIP
(2.0)
(1.5)
(2.0)
Costs (1973$)
Annualized
Cost
1,993,600
2,088,900
2,188,000
2,135,700
2,033,200
2,288,200
I«velized
Costs
4,136,000
3,850,000
4,536,400
4,401,800
3,708,700
4,793,700
The costs here (annualized and levelized) are found by adding the yearly fuel costs (annual and
.levelized) in Table B-2 to the yearly boiler costs excluding fuel costs (annualized and levelized)
in Table B-3.
The bituminous coals are assured to be burned in boilers constructed to bum "eastern low-
sulfur coal;" the subbituminous coal and lignite are assured to be burned in boilers con-
structed to bum "subbituninous coal" (see Table B-3).
These are the most stringent of five SO2 standards considered here, which the uncontrolled SO,
emissions fron each coal can meet. Tl»e standards (ngSOz/J) are 516,645, 860, 1,075, 1,290. Vfe
assune no retention of sulfur as SO2 in the boiler.
-------
cn
*»
oo
Table B-6. ESTIMATED COSTS (1978 $) CF BURNING LCW-SULfUR CCALS
BOILER TYPEj FIELO-ERBCm> WMEIOUBE .,
44 MW (150 X 10«BTU/hr)j 450 PSIG/600»P
Coal
Source
Buchanan, Va.
Las Aniinas, Go.
Williston, N.D.
Gillette, Wy.
Itock Springs, wy.
Gallup, N.M.
Ooal^
type
B
B
Lignite
SB
B
SB
Standard within Which
Uncontrolled Emissions Fall
ngSOj/J
860
516
1,075
860
645
860
(Ib SOj/lO'BTlJ) "
(2.0)
(1.2)
(2.5) SIP
(2.0)
(1.5)
(2.0)
Coats (1978$)
Annual ized Levelized
Cost Cbata
3,468,300 7,090,200
3,520,300 6,518,200
3,580,000 6,815,800
3,475,300 6,546,700
3,408,800 6,235,600
3,780,300 7,330,500
The costs hare (annualiz«jd and levelized) are found by adding the yearly fuel costs (annual and
levelized) in Table B-2 to the yearly boiler costs excluding fuel costs (annualized and levelized)
in Table B-3.
bituninous coals are assumed to be burned in boilers constructed to bum "eastern
low-sulfur coal;" the subbituminous coal and lignite are assured to be burned in boilers
conatructed to burn "subbituminous coal" (see Table B-3) .
'ihese are the most stringent of five SOZ standards considered here, which the uncontrolled
SC)2 emissions from each coal can meet. The standards (ngSO2/J) are 516, 645, 860, 1075,
1290. Via assume 110 retention of sulfur as SO2 in the boiler.
-------
TABUS B-7. ESTIMATED COSTS (1978 " OF HURNTHG LOW SlJinJP OOALS
ItOHJ-T TYTR: t'ICIJVH !V:'"Ur)E
M.6 MJ (200 imi/IlK) : / ., i., vi/Otj'T *
O%
ool
iiUClkilklll, VA
las Aniinas, Cf)
Wil listen, NO
Gillette, W
Rock Springs, WY
CJallup, NM
Oxil
B
B
I.iijniie
SB
D
SB
i
StniKJanl
UjK^(J*)t t ' >
516
B6fl
645
t'60
within wti"h 1]
llcxl Illll; , i
(11, ' It, . ..i l
(. !i.
(1. - j
(2.1)) : j
(2.0)
1
(1.5) |
1 J,
Yearly rosi s ( "rye S)
' sztx' ' . • •• -I] zed
<'
-------
APPENDIX C
REGIONAL LISTING OF COAL COMPANY-PROVIDED DATA
650
-------
ITO) ANN I'lOKICr OJAf, QU/U,m FOK N. AJTA1 A
N. Appalachian - 152
N. Appalachian - 152
N. Appalachian - 152
N. Ajjpnl/idiinn - 152
N. Appalachian - 1152
N. A| if ><<]nrti.inn - »52
N. Appaladiian - 143
N. Appalachian - |43
N. Appalachian - 146
N. Appalachian - 147
N. Appalachian - 148
N. Appalachian - 149
N. Appalachian - 150
N. Appalachian - 150
N. Appalachian - 120
N. Appalachian - 120
N. Appalachian - 120
N. Appalachian - 120
N. Appalachian - 120
N. Appalachian - 120
N. Appalachian - 122
N. Appalachian - 122
N. Appalachian - |23
N. Appalachian - 123
N. Appalachian - 123
N. Appalachian - 123
N. Appalachian -136
N. Appalachian - 137
N. Appalachian - 1 38
N. Appalachian - 138
,
U.F.
U.F.
U.F.
L.F.6A
L.F.6A
Pitt
Pitt
Pitt
Pitt
Pitt
Pitt
Pgh
Pgh
Pqh
Pcjh
Pgh
Pgh
P<*i
Pgh
Ohiol6
ohioie
Ohiol6
ohioie
ohioie
ohioie
Pitt! 8
Pitt! 8
Pitt! 8
PittIB
PittIB
PittIB
Sewell
Swell
l.Kittan
LKittan
1
Allegheny
Allegheny
Somerset
larrison
larrison
Belncmt
larrison
Itirrison
nelmmit
:io)mont
Inrriaon
Washington
Washing bon
Marshall
*itshall
Marlon
larrison
Marion
Harrison
Perry
Perry
Perry
Perry
Perry
Perry
Belmont
Belnont
Monroe
Belnont
Belnont
Monroe
Nicholas
Nicholas
Upohur
l^isliur
1
Pa.
Pa.
Pa.
W.Va.
W.Va.
Ohio
W.Va.
W.Va.
Ohio
Ohio
W.Va.
Pa.
Pa.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
Ohio
Ohio
Ohio
Ohio
Ohio
Ohio
Ohio
Ohio
Ohio
Ohio
Ohio
Ohio
W.Va.
W.Va.
W.Va.
W.Va.
ll
4
4
4
3
3
3
3
3
3
3
3
4
4
2
1
3
4
3
3
2
2
2
2
2
2
2
2
3
3
3
3
4
3
4
4
(ItNS)
Mnucr
OT ouwrrn
95,000
120,000
84,000
288,000
288,000
288,000
288,000
288,000
288,000
288,000
280,000
192,000
240,000
240,000
190,000
288,000
240,000
144,000
120,000
170,413
152,329
178,680
159,949
208,650
179,994
900,000
,000,000
,000,000
700,000
,200,000
300,000
49,200
53,000
27,000
8,400
UW
irm/in
11,730
10,810
10,000
9,147
11,785
9,667
9,335
12,284
12,397
12,502
12,6fiO
9,770
10,060
10,940
12,800
13,360
13,260
12,460
13,140
11,054
11,665
11,179
10,742
10,836
10,929
10,105
10,105
10,105
10,105
10,105
10,105
11,236
12,432
10,626
10,626
* r.'mrr
1.84
1.67
1.31
2.92
2.55
3.28
2.05
5.09
2.51
3.02
2.67
1.55
2.0
4.97
2.8
3.46
4.30
4.24
3.61
4.07
3.73
3.98
4.46
3.96
3.45
4. 89
4.89
4.89
4.89
4.89
4.89
.85
.70
1.93
1.93
rntxxirr
MRTAIJJIUIICAI,
tJIV/Ul
14,130
J4.450
14,040
14,452
14,148
13,822
» STtrr
1.57
1.03
1.55
.80
.71
1.02
STOW
tmj/in
14,030
13,821
13,979
13,232
13,520
13,431
12,886
13,074
13,855
13,680
12,660
12,800
13,980
14,010
13,940
14,010
12,494
12,464
12,462
12,443
12,465
12,428
11,790
12,048
12,359
12,292
12,863
12,407
12,416
» mur
1.2B
2.94
2.34
3.96
2.73
3.59
2.15
2.51
2.33
1.92
4.52
2.8
2.72
3.2
3.27
2.8
3.03
2.86
3.06
3.05
3.06
2.99
3.66
3.34
3.36
3.46
4.23
3.31
1.38
inn rxtj/Jn" urn's
I?)M
3.14
3.09
2.62
6.38
4.33
6.79
4.39
8.29
4.05
4.83
4.22
3.17
3.98
9.09
4.38
5.18
6.49
6.81
5.49
7.46
6.40
7.12
8.30
7.31
6.31
9.68
9.68
9.68
9.68
9.68
9.68
1.51
1.13
3.63
3.63
rmimc
1.02
2.22
1.43
4.25
3. 3D
5.99
4.11
5.35
3.31
3.84
3. .36
2.21
2.81
7.14
4.3B
3.89
4.57
4.69
4.00
4.85
4.60
4,91
4.90
4.9J
4.81
6.21
5.54
5.44
5.63
6.58
5.33
1.10
1.0
1.47
2.22
I ®y
M int>
42.0
2(1.2
45.4
33.4
22.6
11.8
6.4
35.5
17.5
20. r>
20.4
30.3
29.4
21.5
0
24.9
29.G
31.1
27.2
35.1
28.1
31.0
41.0
32.9
23.8
35.8
42.8
43.8
41.8
31.7
44.9
27.1
11.5
59.5
38.8
-------
fEEO AN!) PnDDllCT OOAL QUALHY FOR N. API'AMOIIAN
01
ts)
AN!) PI ANT M).
N. AfipnlfirWnn - 153
N. Aj.Tpnlndi.lnn - 153
N. Ajifvil.-Klilfin - 153
N. Af'ivilnohi.Ti! - 153
N. A|i|Ml.«iHilon - 153
i
...Kitt
..Kltt
Ii.Kitt
C-.Ki.tt
L.Kitt
1
1
j
i''!
3
3
3
3
3
JOTJJUnWTI
640
640
640
640
640
H»1
inn/in
13,405
12,879
12,102
12,657
13,029
\ tmir
2.80
2.24
1.84
1.46
1.38
rnjt«x.-r
nTTntJJNKtCVM.
mti/m
14,622
14,249
14,146
14,392
14,435
t R1W
1.11
1.20
1.22
0.82
0.99
mrAM
rmi/in
»«w
im Bh/in- imi-n
KIM
4.15
3.48
3.04
2.31
2.03
p|» HUT
1.52
1.68
1.72
1.14
1.37
83.4
51.6
43.3
50.0
32.3
-------
FRED AND PimjCT OM! QUAJ.m FOR S. ATP/MOHAN
o\
Ul
co
nrr.KN
AND PI AW' NO.
S. Appalachian - 111
S. Appalachian - 111
S. Appalachian - 112
S. Appalachian - 113
S. Appalachian - 114
S. Appalachian - 115
S. Appalachian - 115
S. Appalachian - 115
S. Appalachian - 121
S. Appalachian - 121
S. Appalachian - 121
S. Appalachian - 121
S. Appalachian - |21
S. Appalachian - 124
S. Appalachian - 124
S. Appalachian - 125
S. Appalachian - 126
S. Appalachian - 126
S. Appalachian - 127
S. Appalachian - 128
S. Appalachian - 128
S. Appalachian - t29
S. Appalachian - 129
S. Appalachian - 130
S. Appalachian - 131
S. Appalachian - 131
S. Appalachian - 132
S. Appalachian - 1 32
S. Appalachian - 133
;
Sewell
Deck ley
Poca-3
Cedar
3rove
Stock-
ton
larker
Toggart
torches
ter
SUVA
SWVA
SWVA
SWVA
EWVA
Various
Various
Tiller
Various
Various
Haven
L.Jewe
L.Jewe
Jewell
L. Jewel
Various
Various
Various
Warfie
Warfie
Cedar
Grove
|
talelgh
lalelgh
laleigh
Bcone
Boone
Wise
Wise
Wise
Wise
Wise
Wine
Wise
Wise
Dickenson
)ickenson
Russell
Russell
Russell
Buchanan
luchanan
Buchanan
tachanan
Buchanan
Pike
logan
Logan
logan
logan
logan
,
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
„
4
4
4
4
4
4
4
4
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
3
3
2
2
2
(iniR)
pnreniLT
JOT QUAWITY
75,000
66,000
96,000
75,000
24,000
69,000
63,000
84,000
2,700
2,700
2,700
2,700
2,700
95,500
7,200
74,000
132,000
56,600
42,000
6,500
48,000
55,000
68,400
84,000
3,600
44,600
30,000
23,000
nrti
13111/1 fl
4,823
5,000
6,129
11,307
11,159
7,675
10,040
9,240
10,834
10,377
9,771
9,182
9,752
10,500
10,500
11,326
9,055
9,055
10,779
9,947
9,947
8,010
9,484
13,589
9,342
9,342
12,410
12,410
12,710
» STOT
1.28
1.25
1.18
.50
.65
.60
.75
.97
1.2
0.92
0.82
0.61
1.1
.70
.70
.42
.60
.60
.55
.64
.64
.76
.73
.78
.66
.66
1.1
1.1
1.7
rmuucr
MTTAIJIIIttlCAI.
rrni/m
14,190
13,975
14,250
13,614
13,285
14,381
14,387
14,355
15,032
14,463
15,056
14,494
14,397
13,979
13,730
14,156
» RIOT
.75
.75
.72
.75
.69
.75
.53
.70
.59
.62
.75
.73
.66
.72
.99
1.3
STRAW
mi/in
14,120
14,170
12,800
14,591
14,449
14,260
14,428
14,624
12,463
12,446
13,031
11,402
12,394
* jrirrr
.70
.62
1.0
1.48
1.31
0.89
1.06
1.1
.80
.69
.66
.B4
1.32
UK m,/tnK mn1.1:
HW
5.31
5.00
3.85
.88
1.16
1.56
1.50
2.10
2.21
1.77
1.68
1.33
2.26
1.33
1.33
0.74
1.32
1.32
1.02
1.28
.28
.89
.54
.15
.41
.41
.77
.77
2.67
TITO JUT
1.06
1.07
1.01
1.10
1.04
.99
.87
1.56
2.0?
1.8)
1.25
1.47
1.50
1.04
1.28
0.74
0.97
1.11
0.78
0.86
1.01
0.99
1.01
0.92
1.03
1.47
1.44
2.13
1.83
P'""
"v
$ ?,
-n'^Sl
80.1
7R.5
73.8
(+24.6
10.8
36.5
41.4
25.6
8.2
•42.4)
25.fi
HO. 5
33.4
21.8
3.7
2G.O
5.9
23.5
32.8
1.1
7.6
4.4
0.0
6.9
4.2)
8.6
20.3)
LS
-------
AND pnoxrr OMI, cjiw.m ron s. ATPAIAOIIAN
Ul
ANII IMAM' M).
R. A|>fvilnciilnn
S. Appalachian
S.
S.
S. Appalndilnn
S. Ap[>nlndilnn
S. Afpalfuiiinn
S. AjfKilodilnn
S. Appnlarlitnn
S. App.ilndilnn
S. Affviladilan
- 131
- 134
134
135
135
'5*
154
154
154
154
i
Cellar
Grove
Qxlar
Grovn
Vnrlou
Poc 3*4
Poc 3
Refuse
PC f IBB
Refuse
Refuse
KefuBe
1
logan
logon
Wyoming
Wyoming
Wyoming
Wyoming
Wyoming
Wyoming
Wyoming
Wyoming
Wyoming
,
w.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
W.Va.
J
2
2
4
4
4
4
3
3
3
3
3
(TONS)
JJt QUAWI'ITV
16,000
7,000
47,500
480
600
600
600
600
600
101
imi/tJi
12,710
12,710
9,779
9,021
10,816
10,816
7,067
8,127
9,084
8,672
7,887
» s-itrr
1.7
1.7
.58
1.10
.67
.67
.603
.637
1.099
.570
.582
I'fnnicr
(•tiftUincicM,
mu/in
14,611
14,624
14,402
13,543
13,242
12,911
13,333
13,183
» nror
.65
1.06
.63
.948
.835
1.099
.830
.850
8TCAM
mv/in
12,836
12,712
13,242
Hfftur
1.71
1.66
.66
iiv, so? /in" mirs
KM
2.67
2.67
1.18
2.44
1.24
1.24
1.71
1.57
2.42
1.31
1.48
PHUDIK.T
2.66
2.61
.89
1.45
.94
.99
1.40
1.26
1.56
1.25
1.29
ft
!si
0.3
2.2
24.6
40.6
23.8
20.2
18.0
19.7
35.5
5.3
12.8
-------
AND pnorxxrr COM. MIAUIY HJH AJABAMA
en
ui
in
Nfl)
A1.il.vmn - K10
Al nl>
•r.HiN
I'lWT Ml.
119
mo
141
147
fi
Viry lr»
NKHO
nlir-
D1^k
C'mok
Mary Irr
|
Joflcrson
ifefferson
Jnfferson
IXiscal
T\i«ical
w
Al.
Al.
Al.
Al.
Al.
Is
4
4
4
4
4
(1TMSI
gr
60-70
60-70
1,500
4,000
4,000
un
mu/i«
10,160
9,600
12, ISO
9,400
9,400
» nirrr
.62
1.66
.77
1.2
1.2
rirm.-r
UTrWJllUJK'AI.
rrni/ui
13,960
13,759
14,258
13,964
13,064
t fritrr
.72
1.13
.60
.85
.05
JVIW1
imi/in
* mtrr
»jis so, /in* imi'r.
rrM
1.22
3.46
1.76
2.r,5
2.55
n«M««T
l.OJ
1.64
.B4
1.72
[.7.2
fl
^ Rm
I'-! »i.
* nw
15.6
•52.6
3.3.. T
r>?..?
V..7.
-------
nron AND pnomo' am Qti/u.m FOCI K. Mtwrnsr
U1
AMI I'l/tf/r M>.
R. Mutant - 15
E. Mldwr-Bt - 16
R. MUlwnnt - 19
B. Mldwwt - 14
R. Mltlwrmt - |)6
R. Mldwnnt. - 1)6
R. Ml'Kvpnl - |16
R. Ml.lwr.fil - |I6
R. Ml.lwpal - 1)6
R. Ml.lwnril: - 116
R. Mldwnnt - 117
R. Ml.lwpfit - 117
R. Ml.Vinnt - 117
R. Ml.V.tvi( - 117
R. Ml.lwrnl - 117
R. Ml.lw.-nl - 117
R. Ml.lwnnt - 119
R. Mldwst - 1)9
K. Ml.lwnRl - 119
H. MicK^ -.• - »10
R. MitlwpRl - 119
R. MlclwnRl - 119
fi
IND 16
1ND 13
JND 16,'
KY 19
*Y 19,]'
Y 19,14
KY 19, )/
KY 19, )4
Y 19,14
KY 19,14
KY 19
KY 19
KY 19
KY |9
KY 19
KY »9
KY 1)1,
KY 111,
112
KY 111,
1)2
KY 111,
112
KY 111,
112
KY 111,
112
.
0
Warrick
Clay
Sullivnn
llnpkltiB
(Kilo
Ohio
Ohio
Ohio
Ohio
Ohio
fihlo
Ohio
Oliio
Ohio
niilo
Muhimiairn
HiJilnnburq
Mirtilfnibtirq
Mnhlrmburc}
Mulilpntwrg
Mfclrnbun,
1
Indiima
Indiana
Indiana
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky
Kentucky--
Kan tucky
Kentucky
Kentucky
Kentucky
Kentucky
Ken tucky
Kentucky
.
3$
3
2
2
I
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
(HWS)
PIT* JUT
or guwrrrv
16,000
8,100
5, BOO
-
203,873
179,374
209,280
201,994
293,460
198,078
124,662
116,037
101,978
91,848
90,102
75,501
291,2)2
247,589
258,113
173,043
201,592
198,247
ntjM
mvi/in
9,652
8,797
9,354
11,100
11,035
11,827
12,009
10,579
11,611
10,914
12,447
12,385
12,019
11,664
12,154
12,728
10,803
9,821
10,590
-
-
9,868
* RTtTT
3.56
5.10
2.28
4.10
4.17
4.64
4.08
3.96
3.98
4.13
4.72
4.07
3.99
3.96
5.05
3.93
3.99
4.25
3.77
-
-
5.03
rromcr
rfTTAUJMRIICAr.
fTTU/lfl
11,036
10,988
10,838
11,100
t snar
2.89
4.13
1.52
4.10
s-irwi
trni/in
13,052
13,063
13,030
13,927
12,977
12,956
13,021
12,887
12,993
12,998
12,954
12,998
12,552
12,495
12,633
12,609
12,692
12,832
» Rim1
3.21
3.23
3.24
3.14
3.13
3.18
3.40
3.40
3.36
3.30
3.35
3.38
3.31
3.39
3.29
3.20
3.15
2.97
It*
7.38
11.59
4.87
7.40
7.56
7.85
6.80
7.5?
6.86
7.57
7.58
6.57
6.64
6.79
8.31
6.18
7.39
8.65
7.12
-
-
10.20
mmit
5.24
7.52
2.80
7.40
4.92
4.95
4.97
4.51
4.82
4.91
5.22
5.28
5.17
5. OB
5.17
5.20
5.27
5.43
5.21
5.04
4.96
4.63
f?, v
29.0
35.2
42.5
34.9
37.0
26.9
40.0
29.6
35.1
31.1
19.7
22.1
25.2
J7.8
]r,.8
17.3
2r..8
54.6
-------
mat Am* picnufT COAL qmuiY FOR E.
fl"\
u
Cr
wiwn
MJI) I'lAWr NO.
E. Midwest - 118
E. Midwest - 11
E. Midwest - 12
E. Midwest -13
E. Midwest - 11
E. Midwest - IB
E. Midwest - llfl
E. Midwest - 118
R. Midwest - 118
R. HlduGflt - 118
R. Midwest - 110
E. Midwest - llfl
R. Midwest -|18
R. Mtdwent - 118
R. Midwest. - 118
E. Midwest - 118
n. Midwest - 118
R. Midwest - llfl
R. Mldwenl - 151
E. MJdwest -
R. Midwest - 151
E. Midwest - 151
R. Midwest. - 151
R. Mldwrwt -
1
-w ~i
I.t, 16
U. 16
IX 16
U. 16
1IX 16
lit 15, f
IX 12
M. 16
MJ, |6
lux 16
iir,i, |«
IIJ, 16
lit 16
'IH, 16
111. 16
IH, 16
UX 16
11,1, 16
IU, 15
IM. 16
TU, 16
IIJ, 15
III, 16
nx IB
,
Oiristlon
Douglas
Randolph
Hllllamarn
Saline
Perry
Pulton
Randolph
Randolph
Randolph
Randolph
Randolph
Randolph
Christian
Christian
Christian
Christian
Christian
Fill ton
Montgomery
Perry
Randolph
Perry
Jndtson
S
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
„
3
1
4
3
3
2
2
3
3
3
3
3
3
3
3
3
3
3
3
1
3
3
3
1
(TtfC?)
pKmT
JJT ounmrn
197,683
-
-
-
8,600
11,500
4,000
150,234
315,719
29", 914
320,532
294,042
246,346
237,056
244,514
251.592
226,517
242,190
240,000
240,000
240,000
120,000
240,000
170,000
RM
Km/in
10,765
10,750
10,300
11,000
10,023
10,092
9,488
11,113
10,700
10,929
10,991
10,940
10,499
10.304
10,707
10,956
10,741
10,417
10,940
10,837
10,911
10,937
10,985
12,070
» mtrr
5.20
3.0
4.35
3.40
3.93
4.25
4.62
3.90
4.27
4.74
4.72
4.10
4.45
4.87
5.16
5.05
5.44
4.98
3.46
4.25
4.49
4.83
4.75
1.2
rimer
Mn'AUJiir.i™.
irni/fJt
11,000
11,100
11,600
11,773
10,981
11,081
* sinv
2.75
3.00
2.40
2.38
3.18
2.68
JTITC/\M
mil/in
12,292
12,073
12,073
12,011
12,047
12,059
12,032
12,297
12,278
12,370
12,320
12,267
12,600
12,637
12,681
12,543
» frirrr
4.29
3.64
3.93
3.83
3.94
3.83
3.71
4.40
4.34
4.44
4.46
4.42
3.15
3.17
4.16
.1.38
ur, soj/lo" inn1:
ITIM
9.66
5.58
8.45
6.18
7.84
8.42
9.74
7.16
7.92
8.67
8.59
7.50
8.48
9.45
9.64
9.22
10.13
9.56
6.33
7.64
8.23
8.83
8.65
1.99
i
PK1IU
6.98
5.00
5.40
4.07
4.04
5.7S
A.M
6.03
6.51
6.3B
6.54
6.35
6.17
7.16
7.07
7. IB
7.24
7.2T
5.00
5.02
6.56
5.39
5'°-
26.79
10.39
36.09
34-1
48.47
31.24
50.30
15.7R
17.80
26.41
23. Bfi
15.33
27.21
21.2.1
26.66
22.12
28.53
24.5P
21. (1)
39.no
25.7]
17. r
-------
APPENDIX D
LISTING OF UNPUBLISHED 1972 EPA SURVEY DATA
ON COAL PREPARATION PLANTS
658
-------
TABLIi L: Coal Cleaning Plant Feed And Product Coal
Data From The 1972 EPA Air Pollution Survey
(Tl
Ui
vo
linl nil
149
150
l')l
002
015
005
(lit)
019
021
022
032
015
046
049
050
07)
092
1 07
l»«ll
of
L'l<>iUih|t|
4
3
4
3
2
3
3
3
1
1
2
2
2
1
2
4
2
4
•lltlrllikll
Pi yi:i a
Yea
Yea
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
(^•i.idii'i
r«if i^M-ll y
(T/lir . 1
11 1W
«25
600
350
500
COO
450
250
600
200
200
100
>00
:l.-,ui
700
500
200
850
404
400
340
1000
500
260
260
00
350
lt»i of Mlim OM|
||U Ml !it!rt -'it' «i"
2117 22.0 1.04 .39 .65
1650 24.5 1.04 .44 .60
9123 42.0 .66 .03 .63
1500 10.11 4.49
0461 25.76 3.4 2.18 1.22
2250 15.0 4.40 2.45 2.03
2311 12.21 4.04
12550 13.0 4.0 2.2 1.8
12750 H.O 3.9 2.0 l.B
13035 11.2 4.44 2. 84 1.57
13009 11.6 5.52 3.40 2.0
6.6 2.05 1.54 .51
13140 14.12 2.13 1.29 .84
12500 2.5 1.1
ll.-k.cl Ihi.icf! Co.ll
III III! y
im /\;-ji !i«ii '^i '.">
3349 13.5 1.0 .39 .61
2407 11.66 3.37
12833 11.0 2.5
13405 7.0 3.8 1.96 1.84
12644 10.96 3.41
3100 9.3 3.5 1.0 J.7
1)200 8.6 3.3 1.6 1.6
13364 9.4 4.14 2.43 1.69
13275 10.0 5.05 2.92 2.11
13600 8.5 2.0
4017 9.70 1.58 .8 .70
Ulntl
inn Ash siot :;i> :
-------
TAUI.E 1; (Continued)
en
o
Dilllill
1
174
179
100
1(11
107
101)
191
192
204A
205
117
IIU
121
126
1211
no
144
UU
l.'Wll
o(
< If.lllllVJ
4
4
4
1
4
4
3
4
4
3
4
4
4
3
3
4
4
4
•lluMlnil
l>iyo
000
800
350
700
450
437
025
550
CIlNMI
510
30V
206
275
245
195
750
400
575
500
560
247
525
325
350
700
350
Ilim uf Minn llutl
III tail Ml* fHi »>
4000 12.0 .60 .30 .30
0600 40.0 1.5 .7 .7
10731 27 1.15 .25 .90
12201 17 .05 .28 .57
10B60 24.95 .70
Ilfi75 10.05 1.17
12200 15.9 4.5 3.1 1.4
12300 15.5 4.0 3.65 1.35
14000 15.0 .7
12000 21.5 .0
17.5 1.21
11242 27 1.5 .54 .96
14400 5.0 .06
11990 19.8 .7
I2BOO 13.8 3.U .80 3.0
13299 12.3 3.28 1.70 1.49
11065 28. 1 .02 .18 .63
riokicl HuMf. Ouil
IMlllly
r(ll Mi Ultil Si> ffi
2100 18.0 1.3 .4 .7
3300 10.52 2.76 2.04 0.72
3500 7.0 2.65 1.95 .70
13400 6.9 3.3 1.8 1.1
14300 5.9 .9
13336 13.4 1.37 .41 .96
13500 9.5 .95
13595 7.0 .80
15400 7.2 3.0 .63 2.37
14072 7.2 2.52 .0 1.71
(Nlmt
II HI Anil Slot li|> !«>
14500 5.3 .60 .30 .30
13400 6.9 3.3 1.8 1.1
14072 6.2 .79
14216 6.6 2.21 .75 1.45
-------
TAUI.E 1: (Continued)
cr.
O
096
097
106
114
152
153
I*'V»I
Of
Cll'i'UltlHJ
N/A
N/A
N/A
2
1
4
2
N/A
2
3
1
N/A
3
4
4
4
N/A
4
4
'||«>IIHI|
IhyciH
No
No
No
No
YfiS
Yes
No
No
No
Yea
No
No
Yes
No
Yes
Yes
No
Yes
Yes
il.-Kii
Cn(M>:
_IM
K.M
570
900
400
851
300
3.30
300
260
475
220
300
200
650
650
1500
420
400
025
In. I
«y
~il — . —
CI.'.UI
400
700
1000
607
1000
250
225
1000
355
206
250
175
490
460
900
315
300
700
IHm of Mini; OKI)
III fclh HI "I flu So
10070 27 5.0 2.7 2.3
1IB99 13.6 3.65 2.65 .9
10070 27 5.0 2.7 2.3
10670 27.72 5.6 4.1 1.5
11500 10.11 4.49
15390 22.0 .58 .17 .41
11500 10. 0 1,0
11233 20.1 4.9 3.13 1.77
31 3.8 2.0 1.8
11931 23.0 3.2 2.75 0.45
12429 18 3.5
12071 10 .78
11056 18 .50
11315 27 .73 .22 .51
12024 18 .60 .18 .42
11100 20 1.4
12973 14.5 3.6 2.6 0.9
12663 16.8 3.69 2.94 0.75
llC.I.Hl llS.llf Ulill
Utility
t!\l Apli Ulol li' lift
12400 12 4.0 1.5 2.5
12400 12 4.0 1.5 2.5
12800 13 4.0 2.4 1.6
10916 12.33 3. 53
12500 7.5 1.0
12322 13.0 2.1)4 1.42 1.4/
12580 13.5 3.7 1.75 1.9r
13660 11.4 1.95
13724 1.4 .65
12800 17 .59 .12 .47
12000 15.5 1.3
14096 7.2 2.0 1.99 O.U
IHI.'l
irllJ Auli !>liA !'n> ','•>
12400 12 4.0 1.5 2.5
13104 8.4 3.0 2.3 0.9
12400 12 4.0 1.5 2.5
12000 13 4.0 2.4 1.6
I2J22 13.0 2.04 1.421.42
14250 7.5 .59 .12 .47
-------
TABLE 1: (Continued)
CTl
NJ
1)1
1(1
141
l(>2
U.-l
165
197
1'J'J
201
211
217
N/A
2
2
4
4
2
2
2
2
2
4
liiyi'in
No
No
No
No
No
No
No
(T/lu.l
It M
250
)00
550
500
t'll'IMI
200
240
484
275
Ikm uf Mliui (tuil
U Anil SI..I Ihi !»'
28.0
31.0
11100 11.0 1.7
1-i.O.m Ik...,, U«l
uillliy
t|ll Mi SIlA G|> !>i
10.5 1.1
20.0 .98
11400 8.0 1.4
IHlKfl
m\l Ailli Slot I'1> !
-------
TAUI.E Is (Continued)
en
en
u>
(III! Mil
I
065
069
081
003
one
090
093
MO
116
127
145
1.55
156
157
170
1.7ft
177
102
l^uul
<>(
< Ic.mlmi
2
2
3
HA
1
MA
2
2
2
2
1
3
2
2
2
NA
2
NA
11 «:i Mil
lipyi-iH
Mo
Mo
Mo
No
No
No
No
No
No
Mo
Mo
Yes
No
No
No
No
No
No
\«-i.ii
('ilji;*1
_i'!Z!
IllW
300
500
174
225
60
250
200
90
600
538
200
200
300
150
300
225
ill'l
IY
)
Ir.y.
240
975
130
100
54
199
200
00
450
306
140
175
275
135
250
200
l«m <>( MliH! Ui.il
lltl Mil »l"t -'I' '•'»
3172 16.1 1.45 O.BO 0.65
0902 37.10 4.04
1500 21.1 3.24 2.1 1.11
2065 15 1.5 1.0 0.5
3250 12 3
41CO 0.01 1.00 1.20 0.60
2600 12 0.6
13600 3.21 0.6
12370 19.67 1.40
I2207 22.4 0.57 0.05 0.52
13200 16 0.00 0.60 0.12
3000 15.0 1.95
.1305 12.5 1.95
1H16 23.85 3.50 3.25 0.25
1000 20 2.0
3307 10.50 1.13
4300 1.7.0 0.70 0.65 0.05
|'H»UK.| ll;,,i.f Civil
III 1 1 1 1 y
nu ftuh nidi UP »»
1060 19.95 2.69
2516 10.75 3.01
2.350 16.0 2.30 1.20 1.11
2942 10.5 1.5 1.0 0.5
3250 12 3
4106 (1.17 1.27 0.67 0.60
2963 8.36 0.56
3900 9.30 1.16
2900 9 0.70 0.59 0.11
4000 0.5 1.55
2440 19.70 3.50 3.12 0.38
2000 12 2.0
4150 7.00 O.!)0
IXI»'|
Hill And Slot :'.[> '.tt
146H7 6.2 1.07 0.47 0.60
14210 0.12 1.36 O.Bl 0.55
13922 4. 62 0.54
13050 2.32 0.6
14150 6.20 1.00
Saina as utility
Same as utility
Santa as utility
iaiic cis utility
14600 3.70 0.90
-------
TABLE; L-I« (continued)
136
117
139
140
142
141A
N/A
'ItM'tllttl
Yea
Yua
Yes
Yea
Yoa
JM
i 1* y
in>i ul Him- Oml
ill Allll lili
(III
IHIMly
INIii't
ii in nuh ijiui HI> tk>
-------
TAUI.U tit (Continued)
(oil nil
1
060
073
090
099
100
101
102
115
121
122
125
129
132
133
134
.u-Ily
IT/I" 1
ivw
00
600
550
550
550
.'litnii
160
360
358
360
400
ItlUI Of MIlH! Ouil
u ftaii s»">i a> 5 !*>
same as uLility
-------
TABLE .1: (Continued)
l'l..l Mil
001
oor,
OO'J
014
023
024
025
0 10
on
0)4
0)5
0)U
042
041
044A
057
062
IliWll
CI«**HllltlJ
3
4
4
3
3
3
4
3
3
4
N/A
4
N/A
3
H/A
4
3
'llH'lllbll
In yijui
Yua
Yes
You
Yen
Yea
Yoii
Yes
Yea
Yes
Yea
Yea
Yea
You
Yos
Yea
Yea
You
—1M,.
II. M
450
200
000
000
450
200
1250
520
1500
ly'
Clnni
387
912
950
750
330
150
525
800
350
1370
It ii iff Mini.- OKI!
U Mi Hint it' <*>
12672 12,71 3.43
3192 9.4 I.B2 l.ll 0.71
13200 0.8 1.2 0.6 0.6
11000 20.0 0.65 0.26 0.39
200,0 15.0 1.00 0.40 0.60
13000 20.0 0.75
10500 25 .1.03
13000 12.0
10.30 0.90
12570 6.20 3.42
11700 20.0 2.0 1.4 0.6
(Hlllly
rm MI r.ioi IH> !>>
1290 10.18 2.48
3600 7.0 1.40
3440 0.50 2.50 1.25 1.25
131)00 7.4 0.72
131100 6.5 1.00 0.20 0.00
13500 7.0 1.00 0.20 0.00
13276 10.1 0.90
13100 6.50 0.08
13292 6.64 3.62
1264317.8 1.06
INUM
rill Auh BUil !>!> •'•"
2000 12.0 1.40
3300 7.8 .1.1 0.5 0.6
3480 8.30 2.28 1.14 1.14
3000 6.0 0.62 0.25 0.37
13700 3.5 0.90 0.30 0.60
4)00 5.25 0.65
o\
o\
(TV
-------
TABLE 1: (Continued)
en
ll»ll ll>l
1
027
029
052
053
or>o
063
li>»:l
of
CIlMllllHI
3
2
MA
4
HA
IIA
'llK!»lttll
liiyc'in
Mo
Mo
No
Ho
No
No
H.M.I! IIKI
('A|>:M:ll y
(I/Ill .
IliM
150
70
300
350
70
ICiUI
120
50
240
225
65
Ifeui of Hliiu OM|
I'll) Mi Klot !>!' '»'
unoo 5 0.70
'
10636 29.2 5.14
L3000 lfi.0 2.0 1.20 0.80
15261 9.0 0.99 0.67 0.32
'10-11 1.0-1.5
I'li.l.KL Utiii.|i' (J).ll
IHllily
Hill l\!ill Slot !li' ^u
L3TOO 4 0.70
200 12 1.5 0.5 1.0
3305 14.4 3.13
L3900 10.0 1.00 1.0 0.00
5261 9.0 0.99 0.67 0.32
(HI*!!
Hill Auh Slot !H> '•'"
13000 3 0.70
Saire as utility
-------
TABLE <1: (Continued)
cr>
oo
(till III)
1
207
208
209
210
215
216
218
004
005
0011
064
072
075
094
111
020
lovul
t'llUNlllHJ
4
3
3
3
4
4
4
4
2
2
2
IIA
'•"•
2
IIA
2
IMynin
Yea
Yea
Yea
Y<3S
Yes
Yes
Mo
Mo
No
Mo
Mn
Mo
Ik)
,k)
()!l!in< llMJ
Cf^KwIly
(T/1 .1
IWM
400
550
250
400
200
300
000
150
150
75
60
70
I'llMHI
220
357
167
200
044
255
600
130
100
60
54
56
lam of Minn (tuil
IU Aiili iltol iili ik>
0249 35.0 0.60 0.04 0.56
2677 10.0 1.10 0.38 0.05
2500 30 0.05 0.74 0.11
3000 IZ 0.60 0.20 0.40
2200 21.2 1.10 0.38 0.00
0250 30 0.60 0.18 0.42
2677 10.0 1.10 0.30 0.05
13300 14 1.7 1.2 0.5
12300 14.2 2.1 1.4 0.7
13000 10 1.5
1500 18 6
2200 15 1.2
2500 16 4.0 1.0 3.0
3500 12.0 1.2
167C 0.90 1.24
I'.t.k.l IM.H.I1 CkttI
inlllly
rjl) Aglt Slol U|> 1>»
1000 17.0 1.50
2310 7.35 0.92 0.10 0.74
3104 16.0 0.60 0.18 0.42
1000 17.0 1.50
4000 10 1.3 0.0 0.5
2700 12.1 1.0 1.0 0.0
3000 0 2.0
3000 9.5 3.2
2000 11 1.0
2000 14 3.0 0 3.0
mini
m; Auii iiioi rii •."
13071 9.5 1.20
13071 9.5 1.20
13900 0.55 1.21
-------
TABLE 1: (Continued)
vo
n»i i<>!
1
159
161
166
167
171
172
175
109
190
195
196
19 B
200
202
203
206
liruut
of
Cll!,UlllK|
4
4
4
4
3
3
3
4
4
4
4
3
3
3
4
4
•IlKrliml
Oiyoia
Yea
Yes
Yea
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
H«-i..i lii-i
Civ^Uy
(T/l .»
l»;iw
400
600
1772
1060
500
500
325
430
350
650
Llr.ai
275
420
1539
000
400
400
255
290
240
Ibm uf Hlne C"M|
fill Anil , .'iliil fin !'•<>
10195 30.05 0.90 0
2007 21.61 0.57 0.10 0.47
2150 10.30 0.59 0.10 0.49
3150 14.00 0.70 0.56 0.22
2052 16.00 0.00 0.55 0.25
45.00
23.00
1745 24.5 0.7?. ]
1
3250 12.50 1.20 0.35 0.65
I'lijihicl Uu.ii/j <'«ml
Utility
inn tail Sim :i> :*,
13560 7.5 0.90 0.10 0.72
11000 9.5 1.00 0.20 0.00
13250 6.75 0.70 0.14 0.56
3154 12. 5e- 0.00 0
2540 16.00 0.84 0.24 0.60
17.00 1.08
2175 19.50 1.12
2340 10.0 1.0
5000 0.0 0.75 0.15 0.60
(Mini
mil Mill istol !!|i ;<.
4850 2.50 0.90 0.15 0.65
-------
APPENDIX E
DETAILED COAL COSTS
670
-------
SUMMARY OF TOTAL DIRECT COSTS (Mid 1978 Dollars)
Physical Goal Cleaning
Chemical Coal Cleaning
High Sulfur
Eastern Coal
Low Sulfur
Eastern Coal
ERDA
Process
Meyers
Process
Gravichem
Process
Ram Coal Storage and Handling 2,147,000
Preparation Plant Equipment Cost (2,076,000)
•total Cost of Preparation Plant 4,882,000
Miscellaneous Facilities and Equipment 3,818,000
Total Direct Cost 10,847,000
2,149,000
(1,913,000)
4,496,000
2,884,000
9,529,000
136,728,000
99,432,000
39,344,000
cn
SUWARY OF TOTAL INSTALLED CAPITAL COSTS (Mid 1978 Dollars)
Total Direct Costs (equipment and
installation)
Total Indirect Cost
Contingencies
Total Turnkey Costs
Land
Working Capital
Grand Total (turnkey and land and
working capital)
10,847,000
3,473,000
2,864,000
17,184,000
264,000
675,000
9,529,000
3,049,000
2,516,000
15,094,000
264,000
566,000
136,728,000
43,775,000
36,097,000
216,580,000
120,000
7,931,500
99,432,000
31,818,000
26,250,000
157,500,000
120,000
5,973,000
39,344,000
12,593,000
10,387,000
62,324,000
120,000
2,430,000
18,123,000
15,975,000
224,631,500
163,593,000
64,874,000
-------
ANNUAL OPERATING COSTS (Mid 1978 Dollars)
Physical Coal Cleani
Chemical Goal Cleaning
Direct Cost
Direct Labor
Supervision
Maintenance Labor
Maintenance Supplies and
teplacement Parts
Povrer
Water
Waste Disposal
°] Chemicals
KJ TOTAL DI rarer COST
Overhead
Payroll
Plant
TOTAL OVERHEAD COST
Capital Charges
G&A, Taxes R Insurance
Capital Recovery
TOTAL CAPITAL CHARGES
TOTAL ANNUAL COSTS*
iligh Sulfur
Eastern Coal
426,600
91,200
237,000
1,202,900
199,300
3,800
433,200
106,300
2,700,300
226,400
536,600
763,000
687,400
2,132,000
2,886,900
Low Sulfur
Eastern Goal
237,000
91,200
142,200
1,056,600
315,100
7,400
323,300
90,300
2,263,100
141,100
420,400
561,500
603,800
1,773,500
2.434,300
ERDA
Process
688,000
92,000
10,829,000
12,885,000
288,000
240,000
6,704,000
31,726,000
234,000
4,761,000
4,995,000
8,663,000
25,448,000
34,111,000
Meyer's
Process
2,190,000
212,000
7,875,000
5,200,000
2,484,000
1,275,000
4,655,000
23,891,000
720,000
3,880,000
4,600,000
6,300,000
18,500,000
24,800,000
Gravichem Process
Physical
260,700
60,800
142,200
687,600
83,400
900
319,700
2,200
1,557,500
—
—
Chemical
722,000
91,000
2,625,000
1,734,000
828,800
425,000
1,735,000
8,160,800
—
—
Total
982,700
151,800
142,200
3,312,600
1,817,400
829,700
744 , 700
1,737,200
9,718,300
383,000
1,645,000
2,028,000
2,493,000
7,358,000
9,851,000
6,350,200
5,258,900
70,832,000
53,291,000
21,597,300
*Excludr>s cost of raw coal.
-------
SUMMARY OF TOTAL DIRECT COST (Equipment and Installation)
Physical Coal Cleaning-High Sulfur Eastern Coal (Mid 1978)
Raw Coal Storage and Handling 2,147,000
Preparation Plant Equipnent Cost 2,076,0000
Total Cost of Preparation Plant 4,882,000
Miscellaneous Facilities and Equipment 3,818,000
TOTAL DIRECT COST 10,847,000
SUMMARY OF TOTAL INSTALLED CAPITAL COST-Physical Coal Cleaning-
High Sulfur Eastern Coal (Mid 1978)
Total Direct Costs (equipment and installation) 10,847,000
Total Indirect Costs 3,473,000
Contingencies 2,864,000
Total Turnkey Costs 17,184,000
Land
Working Capital 675'000
GRAND TOTAL (turnkey & land & vorking capital) 18,123,000
673
-------
Annual Operating Costs
Physical Goal Cleaning - High Sulfur Eastern Coal (Mid 1978)
Direct Cost
Direct Labor 426,600
Supervision 91,200
Maintenance Labor 237,000
Maintenance supplies and replacement parts 1,202,900
Power 199,300
Water 3,800
Waste Disposal 433,200
Chemicals 106,300
Total Direct Cost 2,700,300
Overhead
Payroll 226,400
Plant 536,600
Ibtal Overhead Cost 763,000
Capital Charges
G & A, taxes and insurance 687,400
Capital recovery 2,132,000
Total Capital Charges (including interest on 2,886,900
vorking capital of $67,000)
Total Annual Costs* 6,350,200
*excludes cost of raw coal
674
-------
Suranary of Total Direct Cost (Equipment and Installation)
Physical Coal Cleaning Plant - Low Sulfur Eastern Coal (Mid 1978)
Raw Coal Storage and Handling 2,149,000
Preparation Plant Equipment Cost 1,913,000
Total Installed Cost of Preparation Plant 4,496,000
Miscellaneous Facilities and Equipment 2,884,000
Total Direct Cost 9,529,000
Sumnary of Total Installed Capital Cost
Physical Coal Cleaning Plant - low Sulfur Eastern Coal (Mid 1978)
Total Direct Costs (equipnient and installation) 9,529,000
Total Indirect Costs 3,449,000
Contingencies 2,516,000
Total Turnkey Costs 15,094,000
Land 264'000
Working Capital 566,000
Grand Total (turnkey + land + working capital) 15,975,000
675
-------
Annual Operating Costs
Physical Goal Cleaning Plant - Low Sulfur Eastern Coal (Mid 1978)
Direct Cost
Direct Labor (10 man yr. x $23,700/man yr.) 237,000
Supervision (3 man yr. x $30,400/man yr.) 91,200
Maintenance Labor (6 man yr. x $23,700/roan yr.) 142,200
Maintenance Supplies and Replacement Parts 1,056,600
Power (25.8 mils/kwh x 3,673 kw x 3,325 hrs/yr) 315,100
Water 7,400
Waste Disposal ($l/ton) 323,300
Chemicals 90,300
Total Direct Cost 2,263,100
Overhead
Payroll 141,100
Plant 420,400
Total Overhead Cost 561,500
Capital Charges
G & A, taxes and insurance 603,800
Capital recovery 1,773,500
Total Capital Charges (includes interest on 2,434,300
working capital of $57,000)
Total Annualized Costs* 5,258,900
*excludes cost of raw coal
676
-------
Sunmary of Total Installed Capital Cost
ERDA Chemical Coal Cleaning Process - (Mid 1978)
Total Direct Costs (equipment and installation) 136,728,000
Total Indirect Costs 43,755,000
Contingencies 36,097,000
Total Turnkey Costs 216,580,000
Land 120'000
Working Capital 7,931,500
Grand Total (turnkey + land + working capital) 224,631,500
677
-------
Annual Operating Costs - ERDA Chemical Coal Cleaning Process
(Mid 1978)
Direct Cost
Direct labor 688,000
Supervision 92,000
Maintenance labor —
Maintenance supplies and replacement parts 10,829,000
Power 12,885,000
Mater 288,000
Waste Disposal 240,000
Chemicals 6,704,000
Obtal Direct Costs 31,726,000
Overhead
Payroll 234,000
Plant 4,761,000
•total Overhead Cost 4,995,000
Capital Charges
G&A, Taxes and Insurance 8,663,000
Capital recovery. 25,448,000
Ibtal Capital Charges 34,111,000
Ibtal Annual Costs* 70,832,000
* Ejocludes Cost of Raw Coal
678
-------
SuntBry of Total Installed Capital Cost - Meyers Chemical Coal
Cleaning Process (Mid 1978)
Ototal Direct Costs (equipment and installation) 99,432,000
Total Indirect Costs 31,818,000
Contingencies 26,250,000
Total Turnkey Costs 157,500,000
Land 120,000
Working Capital 5,973,000
Grand Ibtal (turnkey + land + working capital) 163,593,000
679
-------
Annual Operating Costs - Meyers Chemical Coal Cleaning Process
(Mid 1978)
Direct Cost
Direct labor 2,190,000
Supervision 212,000
Maintenance labor
Maintenance supplies and replacement parts 7,875,000
Power 5,200,000
Water 2,484,000
Waste Disposal 1,275,000
Chemicals 4,655,000
Total Direct Costs 23,891,000
Overhead
Payroll 720,000
Plant 3,880,000
Total Overhead Cost 4,600,000
Capital Charges
G&A, taxes and insurance 6,300,000
Capital recovery 18,500,000
•total Capital Charges 24,800,000
Total Annual Costs* 53,291,000
* Excludes Cost of Raw Coal
680
-------
Summary of Ibtal Installed Capital Cost
Gravichem Coal Cleaning Plant - (Mid 1978)
Ibtal Direct Costs (equipment and installation) 39,344,000
Ibtal Indirect Costs 12,593,000
Contingencies 10,387,000
Total Turnkey Costs 62,324,000
Land 120,000
Working Capital 2,430,000
Grand Total (turnkey + land + working capital) 64,874,000
681
-------
Annual Operating Costs
Gravichem Goal Cleaning Process - (Mid 1978)
Direct Cost Chemical Physical Total
Direct labor 722,000 260,700 982,700
Supervision 91,000 60,800 151,800
Maintenance labor - 142,200 142,200
Maintenance supplies and 2,625,000 687,600 3,312,600
replacement parts
Power 1,734,000 83,400 1,817,400
Water 828,800 900 829,700
Waste Disposal 425,000 319,700 744,700
Chemicals 1,735,000 2,200 1,737,200
Total Direct Costs 8,160,800 1,557,500 9,718,300
Overhead
Payroll 385,000
Plant 1,645,000
Total Overhead Cost 2,028,000
Capital Charges
G & A, taxes, and insurance 2,493,000
Capital recovery 7,358,000
Total Capital Charges 9,851,000
Total Annual Costs* 21,597,300
*excludes cost of raw coal
682
-------
APPENDIX F
EMISSIONS FROM REFERENCE BOILER'S NO. 1-4
683
-------
TABLE F-l. EMISSIONS FROM REFERENCE BOILER NO. 1 PACKAGE, WATERTUBE, WJDERFEED STOCKER
8. 79 MW = 8,790 kJ/S (30 x 106 BTU/hr) Input; 50% Excess Air
Dry HV, kJAg
Dry Goal Feed, kg/S
total Ash, g/S
Fly ash, g/S
in
o
•H
Bl
•H
3
in
3
o
0)
V)
id
tD
0
0)
VI
W
0)
H
o
S
1
o
01
in
1
a>,
M,O
S02*
0,
N,
NO?
CO
ai,,
Total
S07 *
NOj
CD
dl,,
a 'Itrop, "K
3 13 Std m'/nec
r" w Actual m'/soc
Iligh-Sulfur Eastern Goal
Raw Goal
27,305
0.3219
75.32
18.83
17.58
7.65
0. 3242
10.53
118.92
0.05247
0.01149
0.01003
155.03
20.77
2.41
0.322
0.161
478
3.475
6.075
Deep-Cleaned PCC
33,555
0.2620
15.20
3.80
17.58
8.15
0.0838
10.27
116.06
0.04271
0.00935
0.00817
152.14
5.37
1.97
0.262
0.131
450
3.410
5.614
Middling POC
31,662
0.2776
31.40
7.85
17.57
8.21
0. 1390
10. 34
116.78
0.04525
0.00991
0.00865
153.04
8.91
2.08
0.278
0.139
450
3.430
5.647
ERKV
27,305
0.3219
75.32
18.83
17.58
8.21
0. 0706
10.26
115.90
0.05247
0.01149
0.01003
151.45
4.52
2.41
0.322
0.161
450
3.395
5.590
Gravichem
34,081
0.2579
11.32
2.83
17.58
7.46
0.0840
10.27
116.05
0.04203
0.00921
0.00804
151.44
5.38
1.93
0.258
0.129
450
3.394
5.588
Lew-Sulfur Eastern Goal
Raw Goal
31,685
0.2774
28.79
7.20
17.58
7.02
0.0970
10.25
115.85
0.04522
0.00990
0.00865
150.79
6.21
2.08
0.277
0.139
450
3.380
5.565
POC Product
33,883
0.2594
10.71
2.68
17.58
7.87 .
0.0684
10.22
115.51
0.04228
0.00926
0.00809
151.26
4.38
1.95
0.259
0.130
450
3.390
5.581
ERDA
31,685
0.2774
28.79
7.20
17.58
7.02
0.0320
10.18
115.07
0.04522
0.00990
0.00865
149.88
2.05
2.08
0.277
0.139
450
3.360
5.532
Gravidiem
34,666
0.2536
4.95
1.24
17.58
6.98
0.0421
10.19
115.19
0.04134
0.00905
0.00790
149.98
2.70
1.90
0.253
0.127
450
3.362
5.535
Low-Sulfur Western Goal
Raw Goal
26,268
0.3346
83.01
20.75
17.58
7.18
0.0585
10.17
114.88
0. 05454
0.01195
0.01043
149.77
3.75
2.51
0.335
O.lf.7
450
3.3r>7
5.5^7
POC Product
29,201
0. 3010
49.67
12.42
17.58
8.00
0.0580
10.17
114.91
0.04906
0.01075
0.00938
150.71
3.72
2.26
0.301
0.150
450
3.378
5.562
00
* 95% of Stoichionctric Quantity
-------
TABLE F-2. EMISSIONS FROM REFERENCE BOILER NO. 2 PACKAGE, WATERTUBE, CHAIN GRATE
21.975 MV = 21,975 kJ/S (75 x 106 BTU/hr) Input; 50% Excess Air
m
Ul
Dry IIV, kJ/kg
Dry Coal Feed, kg/S
Ibtal Ash, g/S
Fly ash, g/S
tn
c
o
•rH
W
tn
•rl
W
«
0
-------
TABLE F-3. EMISSIONS FROM REFERENCE BOILER NO. 3 FIELD-ERECTED, WVTERTUBE, SPREADER STOKER
43.95 MM = 43,950 kJ/S (150 x 10s BTU/hr) Input; 50% Excess Air
03
O
•rt
W
in
in
a
o
a)
V)
•3 in
-i
rn
V, kJ/kg
ml Feed, kg/R
Asii, cj/S
u
0)
tn
-------
Table F-4. Bnissions from Reference Boiler No. 4
Field-Erected, Watertube, Pulverized Coal
58.60 MW = 58,600 KJ/S (200 x 10s Btu/hr) Input; 30% Excess Air
m
CO
)ry 11V, kJAg
Dry Coal Feed, kg/S
Total Ash, g/S
Fly ash, g/S
10
o
U)
to
•H
M
0)
a
O
in
0
V
0)
10
tn
(D
H
^
i
o
in
&
03,
H20
SO7*
0,
N2
NO?
GO
au
total
SOZ*
NOj
00
au
a) Ttenp, °K
^ S std mVsec
^ w Actual mVsec
High-Sulfur Eastern Coal
Raw Coal
27,305
2.1461
502.2
401.7
117.18
50.99
2.1617
42.11
687.27
0.4198
0.0383
0.0201
899.9
138.49
19.31
1.073
0.322
478
20. 169
35. 259
Deep-Cleaned PCC
33,555
1.7464
101.3
81.0
117.18
54.30
0.5588
41.08
670.60
0.3416
0.0312
0.0163
883.7
35.80
15.72
0.874
0.261
450
19.808
32.612
Middling PCC
31,662
1. 8508
209.3
167.5
117.17
54.75
0.9266
41.35
674.88
0.3620
0.0330
0.0173
889.1
59.36
16.65
0.924
0.278
450
19.929
32.811
ERDA
27,305
2.1461
502.2
401.7
117.18
50.99
0.4706
41.01
669.80
0.4138
0.0383
0.0201
879.5
30.15
19.31
1.073
0.322
450
19.714
32.457
Gravidiem
34,081
1.7194
75.5
60.4
117.18
49.71
0.5603
•41.09
670.67
0.3363
0.0307
0.0161
879.3
35.90
15.47
0.860
0.258
450
19.709
32.449
Low-Sulfur Eastern Cbal
Raw Coal
31,685
1.8495
192.0
153.6
117.18
46.77
0.6466
41.02
669.54
0.3618
0.0330
0.0173
875.2
41.43
16.65
0.924
0.278
450
19,618
32.299
PCC Product
33,883
1.7295
71.4
57.1
117.19
52.46
0.4561
40.90
667.60
0.3383
0.0309
0.0162
878.6
29.22
15.56
0.866
0.260
450
19.694
32.424
ERM\
31,685
1.8495
192.0
153.6
117.18
46.77
0.2137
40.74
665.04
0.3618
0.0330
0.0173
870.0
13.69
16.65
0.924
0.278
450
19.501
32.107
Gravichem
34,666
1.6904
33.0
26.4
117.18
46.52
0.2951
40.77
665.56
0.3306
0.0302
0.0158
870.4
18.91
15.21
0.846
0.253
450
19.509
32.120
Lohf-Sulfur Western Coal
Raw Coal
26,268
2.2309
553.5
442.8
117.19
47.88
0.3900
40.67
663.96
0.4364
0.0398
0.0209
869.4
24.99
20.08
1.115
0.335
450
19.487
32.084
roc Product
29,201
2.0068
331.1
264.9
117 . 18
53.36
0.3864
40.68
664 . 11
0.3925
0.0358
0.0188
875.8
24.76
18.06
1.003
0.302
450
19.631
32.321
*95% of Stoichiometric Quantity
-------
APPENDIX G
ANALYSIS OF AN EASIEEN MEDIIM SULFUR GOAL
Lower Kittanning Coal, Cantoria, Pa.
688
-------
A medium sulfur coal (Lower kittanning, Cambria, Pa..) has been
analyzed to provide a comparison of performance factors on a variety of
boiler types and sizes.
Included in this Appendix is:
• the design and costing basis;
• washability data for the determination of the performance
of a physical coal cleaning operation on the medium sulfur coal;
• a cost analysis for the candidate control systems;
• an energy impact analysis of the candidate control systems; and
• an environmental impact analysis of the candidate control systems.
689
-------
DESIGN AND COSTING BASIS
The major design criteria used for the preparation of the flow sheets
for each coal are summarized as follows:
• Plant input in each case is 544 metric tons per hour (600 tons
per hour);
• Annual capacity throughput is 1.81 million metric tons (2.0 million
tons) based upon a 13.3 hour operating day and 250 operating days
per year;
• In all cases, the plant is located at the mine mouth, and all
resources such as coal, water, power, etc. are assumed readily
available;
• Goal storage loading conveyors and product loading equipment is
assumed to be part of the mine and has not been duplicated;
• All process equipment used is commercially available and proven;
• Actual equipment performance partition factors have been used to
adjust raw coal washability characteristics to performance
guaranteed specifications; and
• Design of pollution control facilities is based upon federal new
source performance regulations - EPA standards for air and water
quality, MESA regulations for refuse disposal, and MESA/OSHA
noise limitations.
• Annualized costs are presented on a cost for beneficiation basis
[dollarsA.cn of clean coal] excluding costs for coal lost to refuse.
690
-------
V£>
— — *— nurin
1 ALL NUMBERS IMUICAIE INI Of COAt
Figure G-l. A level 3 coal preparation flowsheet for beneficiation of a
medium sulfur eastern ooal for steam fuel purposes.
-------
G-l P3COCCT
r Kittanning COal - Design $2
Ash,
A. CESSJICSL
S, %
Pyritic 5, %*
Heating Value, (STO/IB)"1
Jtaistsre, %
IBS soi/io5 am
CF FEED MO) ?K3ECCT
Jfcistare free basis
12.8
1.86
1.34
13,508
3.5
2.75
3. PLSTT PBCDGCT FLOW
SIZE
I1!" x 3/8"
3/8" x 8M
8M x 0
CCAL
CSS)
160.
254.
140.
9
5
0
WRTER
(TPH)
3.1
43
S
.0
.8
"STIM,
CSPH)
169.0
297
145
.5
.8
% MOISTURE
4
14
4
.8
.5
.0
TOTAL
555.4
56.9
611.4
9.3
555. 4
.t of Jr
56.9
:< 100
3TC 5ecovery =96.9%
692
-------
TABIE G-2.
COAL UASHABILITV ANALYSIS FOR LOUCR KITTANNIMG SEAM
CAHBRIA, PENNSVLUANIA
SPEC
GRAUITV
DIRECT PERCENT
(DRV BASIS)
UEIGHT
X
ASH
X
BTU/ PVRITIC
LB. SULFUR. X
TOTAL
SULFUR, X
CUMULATIVE PERCENT
(DRV BASIS)
UEIGHT
X
ASH
X
BTU/ PVRITIC
LB. SULFUR. X
TOTAL
SULFUR. X
LB S02/
nu. BTU
1-1/3 IV 3'4 12.4
8.19
0.4i
e.66
1.52
1.57
1.83
12.48
6.41
4.57
36. 02
e.82
0.97
1.23
2.01
1.79
2.02
12.48
6.44
4.57
37.05
12.4
25.3
40.9
49.1
55.2
60.7
79.5
82.0
89.9
98.7
100.0
31.4
3.6
4.9
6.1
7.4
9.5
18.0
19.0
S3.9
29.2
29.6
14934.
14733.
14552.
14339.
14013.
12703.
12553.
11787.
10963.
10900.
0.19
0.27
0.34
0.47
0.57
0.87
1.22
1.68
.93
2.38
0.82
0.88
0.94
05
12
33
67
09
31
2.77
FLOAT-
.30 -
_. .35 -
2 .49 -
W .59 -
.69 -
.99 -
B.20 -
8.5* -
2.80 -
3/8 BV
FLOAT-
.30 -
.35 -
.40 -
.50 -
.60 -
.90 -
2.20 -
8.59 -
8. 80 -
e* BY
FLOAT-
1.3* -
1.35 -
1. 40) -
1.50 -
1.60 -
1,99 -
a. M -
8.5* -
B.M -
1.30
1.35
1.40
1.50
1.60
1.90
2. 80
Z. 50
2.80
SINK
28
.30
.35
.40
.50
.60
.90
8.80
a. 50
a. 80
SINK
100
.3*
.35
.40
.50
.69
.90
B.e9
8.50
a. it
SINK
52.0
17.1
5.0
5.3
3.6
8.3
1.6
3.0
3.0
1.1
55.7
69.2
13.0
3.8
3.0
1.7
4.4
1.0
i.a
1.7
1.0
ia.9
77. e
1.6
3.1
8.4
1.4
a. 6
1.0
1.1
1.3
1.3
3.8
8.0
12.9
19.4
28.5
46.1
53.1
78.9
82.4
61.9
a. 8
7.8
11.1
16.9
85.8
45.8
53.0
79.3
80.4
64). 5
8.6
7.7
18.5
17.5
83.4
36.7
55. •
66.5
77.5
08.9
14903.
14253.
13494.
12437.
11077.
8350.
7266.
4198.
2727.
5902.
15058.
14377.
13778.
12874.
11495.
8490.
7881.
4601.
3036.
6119.
15989.
14899.
13556.
18781.
11867.
9806.
6971.
5199.
348*.
5748.
0.24
0.46
1.00
1.49
1.99
3.11
11.25
7.27
5.90
37.63
0.13
0.38
0.79
1.23
1.94
3.77
7.48
7.83
6.77
38.51
0.88
0.49
9.73
1.14
1.64
8.31
3.65
C.89
6.73
37.71
0.85
1.00
1.51
1.93
2.39
3.26
11.28
7.41
5.90
37.73
0.78
0.86
1.15
1.68
8.45
4.15
7.64
8.08
6.77
38.51
0.98
1.01
1.16
1.64
8.19
8.67
4.19
6.84
6.93
37.71
52.0
69.1
74.1
79.4
83.0
91.3
92.9
95.9
98.9
100.0
87.1
69.2
82.2
86.0
89.0
90.7
95.1
96.1
97.3
99.0
100.0
109.0
77.8
85.8
88.9
91.3
98.7
95.3
96.3
97.4
98.7
199.9
3.8
4.8
5.4
6.3
7.3
10.8
11.5
13.5
15.5
16.1
2.8
3.5
3.8
4.3
4.7
6.6
7.0
7.8
9.1
9.6
8.6
3.1
3.4
3.8
4.1
5.9
5.5
6.8
7.1
7.9
14903. 0.24 0.85
1474c. 0.29 0.89
14658. 0.34 0.93
14513. 0.42 .00
14364. 0.49 .06
13817. 0.73 .26
13704. 0.91 .43
13407. tl.ll .62
13083. 1.25 .75
13004. 1.65 2.14
15058. 0.13 0.78
14950.
14898.
14830.
14768.
14477,
14402.
14281.
14088.
14099.
1S089.
15010.
14959.
14902.
14856.
14718.
14638.
14531.
14386.
14873.
.16 0.74
.18 0.76
.22 0.79
.85
.41
.49
.58
.68
.06
.88
.29
.31
.33
.35
.40
.44
.59
.58
.97
.82
.97
.94
.13
.83
.69
.98
.93
.94
.96
.97
.92
.95
.18
.29
.67
1.10
1.19
1.29
1.47
1.60
2.10
2.67
3.55
-4.32
5.07
1.14
1.S0
1.27
1.37
1.47
.82
.09
.41
2.67
3.89
1.
2.
2.
0.96
0.99
02
06
11
35
45
58
1.74
2.28
1.88
1.24
1.25
1.88
1.31
1.39
1.44
1.54
1.6C
a.34
-------
TRBLE G-3 PREPARATION PLANT EQUIPMENT (Mid 1978 $)
lower Kittanning Goal - Design *2
mrr
Haw Goal Sizing Screen 1
Raw Coal Sizing Screen 2
Prewet Screen
Heavy Media Vessel
Heavy Media Cyclcne
Vor-Siv
Sieve Bend 1
Sieve Bend 2
Sieve Bend 3
Sieve Bend 4
Drain & Rinse Screen 1
Drain & Rinse Screen 2
Drain & Rinse Screen 3
Drain & Rinse Screen 4
Vacuum Disc Filter
Magnetic Separator 1
Magnetic Separator 2
Haw Coal Surrp
Heavy Media Son? 1
Heavy Media Sura? 2
light Media San? 1
31 ght Media Sunc 2
NUMBER
SIZE S DESCRIPTION
TOTAL
3 units
6 units
2 units
1 unit
3 units
1 unit
2 units
1 unit
5 units
1 unit
2 units
1 unit
5 units
1 unit
1 unit
2 units
2 units
6 units
3 units
4 units
1 unit
2 units
8'x20', Single Deck, Dry,
Vibrating, Inclined
8'x20', Single Deck, Dry,
Vibrating, Inclined
6'xl4', Single Deck, Wet,
Vibrating, Horizontal
10' 0
26' jJ
Model 2500
60" radius, 5' wide
30" radius, 4' wide
60" radius, 5' wide
30" radius, 2' wide
5'xl6' , Single Deck, Vfet,
Vibrating, Horizontal
3'xl6', Single Deck, Wet,
Vibrating, Horizontal
8'xl6', Single Deck, Vfet,
Vibrating, Horizontal
3'xl6', Single Deck, Wet,
Vibrating, Horizontal
11' 0, 6 Discs
30"x6'
30"x8'
TOTAL EQUIPMENT COST (FOB)
r'MiibhT (2% of total equipment cos-)
69,900
139,800
33,800
210,000
30,300
15,500
8,900
2,500
15,000
1,900
42,400
15,700
128,500
15,700
75,600
13,800
17,400
60,000
30,000
40,000
10,000
20,000
74,200
1,070,900
21,400
TOTAL COST Ctat Installed)
1,092,300
694
-------
TABLE G-3. CAPITAL COSTS FOR RAW COAL STORAffi AND HANDLING (Mid 1978 $)
Lower Kittannina Goal - Desicn #2
(Continued)
Coal Storage Area (10,000 ton avg. ; 20,000 ton max.
capacity, stacking tube, 4 withdrawal areas, 4
reciprocating feeders of tunnel) (40 hp) = = 463,000
Belt Conveyor from raw coal storage to scalping tower
(42" wide, 250 ft. center to center, 60 ft. elevation,
75 hp rotor) $560/ft x 250 ft. = 140,000
Scalping Screen (81 x 20' , vibrating, double deck,
inclined, 2 x 25 = 50 hp notor) $30,000/1.08 = 28,000
Rstary Breaker (12 !0 x 27' long)
$165,000/1.08 = 153,000
Scalping Tower, Rotary Breaker Motor (100 hp) , Hopper/
Chute & Rxk Bin, 28,000 + 153,000 = 181,000
Belt Conveyor from Scalping Tower to Process
(42" wide, 250 ft. center to center, 60 ft. elevation,
75 hp motor) $562/ft. x 250 ft. = 140,000
Trairo Iron Magnet (Explosion Proof, Self Cleaning)
TOTAL INSTALLED COST $1,127,000
695
-------
TABLE G-4 CAPITAL COST FOR CLEAN COAL & REFUSE EQUIPMENT (Mid 1978 $)
Lower Kittanning Coal - Design #2
Thickener (77 ft. diameter) = 143,000
Refuse Belt (24", 200 ft.) = 88,000
Refuse Bin (Limit of 250 ton capacity) = 60,000
Coal Sanpling System = 324,000
Refuse Handling Equipment
1 Truck at 80,000 each = 80,000
1 Dozer at 160,000 each = 160,000
TOTAL INSTALLED COST $855,000
696
-------
TRBIE O-5 SaWREK OF <3PTZKL COSTS (Mid 1978 $>
Lower Kittaiming Coed - Design *2
Saw Coal Storage and Handling 1,127,000
Preparation Plant Equipment Cost 1,092,300
Total Cost of Prep. Plant
(2.35 x ?rep. Plant Equipment Cost) 2,567,000
Miscellaneous Facilities and Bquipment 855,000
HECr COSTS $4,549,000
N CCSTS, ^
Sigineering (10% of direct costs) 455,000
Construction & Field Expense (10%
cf direct costs) 455,000
Construction "ess (10% of direct costs) 455,000
TOISL I^DIEECI COSTS $1,365,000
CCtTEPKSMCSiS (2S% of direct a indirect costs)
(includes start-'jc and perfoEnanca tests) 1,479,000
TCTAL TCRNICX CCSTS $7,393,000
LSUD 264,000
WDKKD3G CS?13iL (25% of direct operating COSTS) 402,000
GSSND TOEVL $8,059,000
697
-------
TABI2G-6 flNNURLIZSD COSTS (Mic-19~8S)
Lower Kittanning Ooal - Design #2
Direct T-abr (18 man yr. x $23,700/taan yr. ) 426,600
Supervision (2 man yr. x 530,400/man yr.) 60,800
Maintenance r^-foyr (8 man yr. x S23,700/man yr. ) 189,600
Maintenance Materials & Heplacesent Parts
(7% of total turnkey costs) 517,500
icity (25.8 rrdls/kwh 1,980 kw x 3,325 h ) 169,600
Watar ($0.15/10J gal. x 27.1 x 1Q6 gal/yr.) 4,100
Waste Disposal ($l/tonx 1.633 x 10s tons/yr.) 163,300
Chemicals (znagn: 1,140 tcn/yr. x S65/tcn)
' (floe: 0.52 ton/yr. x $3,000 ten) 75,700
TOTAL DI3ECT COST $1,607,200
Payroll (30% of djjsct & iudirecs: &
labor) 203,100
Plant Overhead (26% of direct supervision,
zaintenacce I?bnr and maintenance,
and caendcals) 330,300
CfVESHEaD CCST $533,400
Capital Hecsroery Factor (11.75% of total
Turnkey Costs) 868,700
GSA, Taxes & Irsriranca (4% of total
Turnkey Costs) 295 , 700
Interest en Working Capital (10% of W.C.) 40,200
TdM. OPrSL CHASES $1,204,600
TCTSL aMNraT.77?n COSTS $3,345,200
Ccsi: Per Ten of Maisture rree Product i-81
Cost Per 104 BTO of Product °-°64
698
-------
TABLE G-7. ENEEGiT EACTCBS
Lov^r Kittanning Coal - Design #2
Energy loss in refuse: 0.908 x 106 BTU/Itn Product (MF Basis)
Energy consunption in plant: 0.012 x 106 BTU/Ton Product
TOTAL 0.920 x 106 BTU/lbn Product
or; 460 BTU/lb product
699
-------
TABLE G-8. ENVIRONMENTAL FACTORS
Lower Kittanning Coal - Design #2
A. SOLID WASTE
Solid Water Total
(TPH) (TPH) (TPH)
Fran Disc Filter 2.1 0.9 3.0
D&R Screen 2 27.7 1.2 28.9
D&R Screen 4 14.8 2.4 17.2
TOTAL 44.6 4.5 49.1
Tens of Refuse (Dry 3asis)/Tcn of Product = 44.6 = 0.080
555.4
700
-------
TABLE G-3. (Continued)
B. WATER DISCHARGE PARAMETERS
Assume Effluent Flowrate = 75 liters/kkg of product
Primary Pollutants
Total Dissolved Solids
Total Suspended Solids
Total Volatile Solids
COD
TOG
(265 g/kkg of product)
(7 g/k^1? of product)
(37 g/kkg of product)
(41 g/kkg of product)
(1.9 g/kkg of product)
133,523 gm/hr.
3,527 gm/hr.
18,642 gm/hr.
5,542 gm/hr.
957 gm/hr.
Major Elemental Pollutants
Calcium
Magnesium
Sodium
Trace Element Pollutants
Copper
Iron
Zinc
Manganese
(8.8 g/kkg of product)
(4.2 g/kkg of product)
(9.0 g/kkg of product)
(1.5 mg/kkgof product)
(14 mg/kkg of product)
(3 mg/kkg of product)
(1.8 mg/kkgof product)
4,434 gm/hr.
2,116 gm/hr.
4,535 gm/hr.
756 mg/hr.
7,054 mg/hr.
1,512 mg/far.
907 mg/hr.
701
-------
TftBIE G-9.
COSTS OF "BEST" SO, CONTROL TECHNIQUES FOR 22tW COAL-FIRED BOILERS USING MEDIUM SULFUR COAL
SYSTEM
STANDARD BOILKRS
Heat In[iut
MW (MDTU/hr)
**
22 (75)
PCC Coal
32,887 kJAg
1.22% S
8.7% Aah
Type
Chain -
Grate -
Stoker
TYPE AND
LKVKL
OF CONTROL
Raw
Moderate
1290 ng SOi/J
SIP - Control
Optional
Moderate
860 ng SO2/J
Intermediate
645 ng SO2/J
PCC-Level 4
Stringent
516 ng SO2/J
PCC-Level 4
CONTROL
EFFICIENCY"*"
(%)
0
0
37%
37%
56%
(assumed)
ANNUAL
COSTS
9/Mfit)
($/MBrru/hr)
16.07 (4.71)
16.23 (4.75)
16.60 (4.86)
16.60 (4.86)
Not Available
IMPACT'S *
% INCREASE
IN COSTS OVER
UNCONTROLLED
BOILER
— -
1.0
3.3
3.3
% INCREASE
IN COSTS OVER
SIP-CONTROLLEtJ
TOILER
—
—
—
—
* BASED ONLY ON ANNUAL COSTS
** Raw Coal: 1.86% S; 31,420 kJAg; 12.6% Ash; (1,184 ng SO2/J)
+ Percent Reduction in ng S02/J
-------
TABLE G-10.
COSTS OF "BEST" SO2 CONTROL TECHNIQUES FOR 117.2MW COAL-FIRED BOILERS USING MEDIUM SULFUR COAL
O
U)
SYSTEM
STANDARD BOILERS
Heat Input
MW (MBTU/hr)
**
117.2 (400)
PCC Coal
32,887 kJAg
1.22% S
8.7% Ash
Type
Chain -
Grate -
Stoker
TYPE AND
OF CONTROL
Raw
Moderate
1290 ng SO2/J
SIP - Control
Optional
Moderate
860 ng S02/J
Intermediate
645 ng S02/J
POC-Level 4
Stringent
516 ng SOj/J
PCC-Level 4
CONTROL
EFFICIENCY*"
(%)
•
0
0
37%
37%
56%
56%
ANNUAL
COSTS
5/liw(t)
($/MBTU/hr)
12.72 (3.73)
13.36 (3.91)
13.73 (4.02)
13.73 (4.02)
Not Available
IMPACTS *
% INCREASE
IN COSTS OVER
UNCONTROLLED
BOILER
—
5%
8
8
% INCREASE
IN COSTS OVER
SIP-CDNTROLLEr
BOILER
—
—
—
—
* BASED ONLY ON ANNUAL COSTS
** Raw Coal: 1.86% S; 31,420 kJAg; 12.6% Ash (1,184 ng SO2/J)
+ Percent Reduction in ng SO2/J
-------
TftBLE G-ll.
Energy Usage of "Best" Control Techniques for 8.8 MM Coal-Fired Boilers Using Msdiun Sulfur Coal
SYSTEM
Standar' Boiler
Heat Bate
MM or
(10 6 BTU/hr)
8.8
(30)
'
Type
Jnderfeed
toker
1
Type
and
Level
of
Control
Moderate
Raw Coal
ESP
SIP
PCX: Level 3
ESP
Optional
Moderate
POC level 3
ESP
Intermediate
CCC ERDA
ESP
Stringent
CCC ERDA
ESP
Con troll
Ef- [Energy
ficiencyj Type
Percent 1
. '
89.5
35.3
60.4
35.3
84.5
25
-a
I'
J98.5
Elec.
TOTAL
Fuel
Elec.
Elec.
TOTAL
Fuel
JElec.
Elec.
JtOTAL
1 Fuel
JElec
1 Elec
1 TOTAL
JFuel
JElec
JElec
I'lDTAL
ENERGY CONSUMPTION
Energy Consumed
by Control
/kg (BTU/lb) kw(thennal)
153 (65.8)
1,056(454.1)
14(6.0)
127(54.6)
1,197(514.7)
1,056(454.1)
14(6.0)
153(65.8)
1,223(525.9)
1,885(810.6)
209(89.9)
208(89.4)
2,302(989.9)
1,885(810.6)
209(89.9)
244(104.8)
2,338(1005,,3)
42.9
282.3
3.7
33.8
319.8
282.3
3.7
42.8
328.8
508.2
56.4
56.2
620.8
508.2
56.4
65.8
630.4
IMPACTS
tercent Increase
ji Energy over
Uncontrolled
Boiler
0.5
3.6
3.7
7.1
7.2
Percent
Increase
n Energy over
SIP
Controlled
Boiler
(3.0)
NA
0.1
3.3
3.4
-J
s
-------
TABLE G-12.
Energy Usage of "Best" Control Techniques for 22 MW Coal-Fired Boilers Using Medium Sulfur Coal
SYSTEM
1 Standard Boiler
Heat Rate
MW or
(10 6 BTU/hr)
22 (75)
1
Type
Chain
Grate
Stoker
Type
and
Level
of
Control
Moderate
Raw Coal
ESP
SIP
PCC Level 3
ESP
Optional
Moderate
PCC Level 3
ESP
Intermediate
CCC ERDA
ESP
Stringent
CCC ERDA
ESP
Control
f-
.ciency
erosnt
0
89.5
35.3
60.7
35.3
83,4
25
94.6
Energy
Type
•
Elec. .
Fuel
Elec.
Elec.
[OTAL,
Fuel
Elec.
Elec.
TOTAL
Fuel
Elec.
Elec.
(TOTAL
kiel
25 Elec.
98.2 Elec.
pOTAL
ENERGY CONSUMPTION
Energy Consumed
by Control
iJ/kg (BTU/lb) kw( thermal)
151 64.9
1,056 (454.1)
14 ( 6.0)
125 ( 53.8)
i.ins f«;n.<»
1,056 (454.1)
14 ( 6.0)
167 (71.8)
1,237 (531.9)
1,885 (810.6)
209 (89.9)
222 (95.5)
2,316 (996)
1,885 (810.6)
209 (89.9)
247 (106.2)
2,341(1,006.7
105.3
704.4
9.3
83.7
797.4
704.4
9.3
111.6
825.3
1,264.4
140.2
148.8
L,553.4
1,264.4
140.2
165.6
1,570.2
IMPACTS
tercent Increase
n Energy over
Aicontrolled
Boiler
0.5
3.6
3.8
7.1
7.1
Percent
Increase
in Energy over
SIP
Controlled
Boiler
(3.0)
NA
0.1
3.3
3.4
8
-------
TABLE G-13.
Energy Usage of "Best" Control Techniques for 44 MW Coal-Fired Boilers Using Medium Sulfur Goal
SYSTEM
Standard Boiler
I teat Rate
MW or
(10* BTU/hr)
44 (150)
Type
Spreader
Stoker
Type
and
IJBVB!
of
Control
Moderate
Raw Cbal
ESP
SIP
PCK Level 3
EBP
Optional
Moderate
PCX: Level 3
ESP
Intermediate
OCC ERDA
ESP
Stringent
CCC ERDA
ESP
Control
f-
.ciency
Percent
0
96.2
35.3
85.0
35.3
93.8
25
97.8
Energy
Type
|<
Elec.
TOTAL
'
Fuel
Elec
Elec.
TOTAL
Fuel
Elec.
Elec.
TOTAL
Fuel
Elec.
Elec.
ITOTAL
(Fuel
25 felec.
99.3 Elec.
pOTAL
:3NERGY CONSUMPTION
Energy Consumed
by Control
/kg (BTU/lb) kw(thermal)
189 (81.3)
1,056 (454.1)
14 ( 6.0)
161 (69.2)
1.231 (529.3)
1,056 (454.1)
14 ( 6.0)
184 (79.1)
1.254 (539.2)
1,885 (810;6)
209 (09. 9)
235 (101.0)
2,329(1,001.5
1,085 (810.6)
209 (89.9)
251 (108.0)
2,345(1,008.5
264.48
1,411.72
18.71
215.73
1,646.16
1,411.72
18.71
246.18
1,676.61
2,533.85
280.94
316.29
5.131.08
2,533.85
280.94
337.62
5,152.41
IMPACTS
tercent Increase
ji Energy over
Uncontrolled
Boiler
.6
3.7
3.8
7.1
7.2
Percent
Increase
in Energy over
SIP
Controlled
Boiler
(3.0)
MA
0.1
3.3
3.3
-------
TABLE G-14.
ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FOR 58.6 W COAL-FIRED BOILERS USING MEDIUM SULFUR COAL
SYSTEM
Standard Boiler
Iteat Rate
MW or
(10s BTU/hr)
58.6 (200)
Type
Pulverized
Type
aid
Level
of
Control
Maderate
Raw Coal
ESP
SI£
PCC Level 3
ESP
Optional
Msderate
PCC Level 3
ESP
Intermediate
CCC ERDA
ESP
Stringent
CCC ERDA
ESP
Control!
Ef- I
Lciencyj
Peroant
96.7
35.3
87.8
35.3
94.9
25
98.3
25
99.4
lieigy
Type
Elec.
Fuel
Elec.
Elec.x
TOTAL
Fuel
Elec.
Elec.
TOTAL
Fuel
Elec.
Elec.
[TOTAL
.1 ... ..
ruel
3lec.
aec.
TOTAL
ENERGY CONSUMPTION
Energy Consumed
by Control
tJAg (BTU/lb) kw (thermal)
162 (69.9)
1,056 (454.1)
14 (6.0)
152 (65.2)
1,222 (525.3)
1,056 (454.1)
14 (6.0)
182 (78.3)
1,252 (538.4)
1,885 (810.6)
209 (89.9)
204 (87.7)
2,298 (988.2)
1,885 (810.6)
209 (89.9)
222 (95.5)
2,316 (996)
303.0
1,081.3
24.9
270.0
2,176.2
1,881.3
24.9
324.2
2,230.4
3,379.2
374.7
366.5
»,120.4
i,379.2
374.7
398.3
4,152.2
IMPACTS
Percent Increase
in Energy over
Uncontrolled
Boiler
0.5
3.7
3.8
7.0
7.1
Percent
Increase
in Energy over
SIP
Controlled
Boiler
(3.1)
MA
0.1
3.2
3.3
-J
o
-------
TABIE G-15.
ENERGY USAGE OF "BEST" CONTROL TECHNIQUES FOR 117.2 MW COAL-FIRED BOILERS USING MEDIUM SULFUR COAL
O
oo
SYSTEM
Standar^ Boiler
lieat Rate
MW or
(1C6 BTU/hr)
118 (400)
Type
'ulverized
Type
and
Level
of
Control
Moderate
Raw Coal
ESP
SIP
PCC Level 3
ESP
Optional
Moderate
PCC Level 3
ESP
Intermediate
CCC ERDA
ESP
Stringent
CCC ERDA
ESP
Control
f-
.ciency
"erceni
96.7
35.3
87.8
35.3
94.9
25
98.3
25
99.5
Energy
Type
Elec.
Fuel
Elec.
Elec.
TOTAL
Fuel
Elec.
Elec.
. TOXMi-
Fuel
Elec.
Elec.
riDTAL
Elec.
|7l tv*
IJJ-tX- •
TOTAL
ENERGY CONSUMPTION
Energy Consumed
by Control
/kg (BTU/lb) kw( thermal)
168 (72.2)
1,056 (454.1)
14 (6.0)
144 (62.0)
1,214 (522.1)
1,056 (454.1)
14 (6.0)
184 (79.1)
Ir254 (539-3)
1,885 (810.6)
209 (89.9)
202 (87.1)
2,296 (987.6)
1,885 (810.6)
209 (89.9)
244 (104.9)
2,338(1,005.4
627.1
3,762.6
49.9
514.1
4,326.6
3,762.6
49.9
655.4
4r467.9
6,758.3
749.3
726.0
8,233.6
6,758.3
749.3
874,3
8,381.9
IMPACTS
Percent Increase
in Energy over
Uncontrolled
Boiler
.5
3.7
3.8
7.0
7.1
Percent
Increase
j\ Energy over
SIP
Controlled
Boiler
(3.0)
NA
0.1
3.2
3.3
-------
TABLE G-16.
Air Pollution Inpacts from "Best" S02 and Particulate Control Techniques for Medium Sulfur Coal-Fired Boilers.
0
vo
SYSTEM
Heat Ratee
(Mrt or 10s
BTU/far)
B.8
(30)
22
(75)
44
(150)
58.6
(200)
118
(400)
Type
Uiderfeed
Stoker
Chain
Grate
Spreader
Stoker
Pulverized
Pulverized
Control
Level (Name,
% of SOZ
Reduction)
Uhcon trolled
Moderate
SIP
Optional Moderate
lite mediate
Stringent
Uh control led
federate
SIP
Optional Moderate
Intermediate
Stringent
Uhcontrolled
Moderate
SIP
Optional
Intermediate
Stringent
Uioontrolled
Moderate
SIP
Optional Moderate
In te mediate
Stringent
Uhoon trolled
Moderate
SIP
Optional Moderate
Intermediate
Stringent
SOj Control
Type
of
Control
Raw Coal
Raw Coal
POC Level 3
POC Level 3
CCC ERDA
CCC ERDA
Raw Coal
Raw Coal
PCC Level 3
PCC Level 3
COC ERDA
CCC ERDA
Raw Coal
Raw Coal
PCC Level 3
PCC Level 3
COC ERDA
CCC ERDA
Raw Coal
Raw Coal
PCC Level 3
PCC Level 3
OCC ERDA
CCC ERDA
Raw Coal
Raw Coal
PCC Level 3
PCC Level 3
CCC ERDA
CCC ERDA
per.
Deduction
0
0
37.7 •
37.7
• 56.9
56.9
0
0
37.7
37.7
56.9
56.9
0
0
37.7
37.7
56.*
56.9
0
0
37.7
37.7
56.9
56.9
0
0
37.7
37.7
56.9
56.9
Particulate
Pet. Reduction
Coal
Cleaning
0
0
35.3
35.3
25
25
0
0
35.3
35.3
25
25
0,
0
35.3
35.3
25
25
0
0
35.3
35.3
25
25
0
0
35.3
35.3
25
25
ESP
0
89.5
60.4
84.5
94.1
98.5
0
89.5
60.7
83.4
94.6
98.2
0
96.2
85.0
93.8
97.8
99.3
0
96.7
87.8
94.9
98.3
99.4
0
96.7
87.8
94.9
98.3
99.5
EMISSIONS
S02
2
S
10.44
10.44
6.5
6.5
4.5
4.5
25.9
25.9
16.3
16 '.3
11.2
11.2
51.8
51.8
32.6
32.6
22.4
22.4
69.3
69.3
43.4
43.4
29.9
29.9
138.7
138.7
86.8
86.8
59.8
59.8
ng
J
1,188
1,188
740
740
510
510
1,188
1,188
740
740
510
510
1,188
1,188
740
740
510
510
1,188
1,188
740
740
510
510
1,188
1,188
740
750
510
510
Particii
2
s
9.0
0.9
2.3
0.9
0.4
0.1
22.3
2.4
5.7
2.4
0.9
0.3
116.2
4.7
11.3
4.7
1.9
0.6
190.9
6.3
15.1
6.3
2.5
0.8
381.7
12.6
30.2
12.6
5.0
1.5
Latea_
?
1,024
107.5
258
107.5
43
12.9
1,024
107.5
258
107.5
43
12.9
2,644
107.5
258
107.5
43
12.9
3257.0
107.5
258.0
107.5
43.0
12.9
J257.C
107.5
258.0
107.5
43.0
12.9
NC
2
s
2.0
2.0
1.9
1.9
2.0
2.0
5.1
5.1
4.7
4.7
5.1
5.1
10.1
10.1
9.4
9.4
10.1
10.1
16.2
16.2
15.1
15.1
16.2
16.2
32.3
32.3
30.2
30.2
32.3
32.3
>Y
02
a
230
230
215
215
230
230
230
230
215
215
230
230
230
230
215
215
230
230
276
276
258
258
276
276
276
276
258
258
276
276
a)
2
S
0.28
0.28
0.27
0.27
0.28
0.28
0.68
0.68
0.67
0.67
0.68
0.68
1.4
1.4
1.34
1.34
1.4
1.4
0.93
0.93
0.89
0.89
0.93
0.93
1.86
1.86
1.78
1.78
1.86
1.86
J
31.9
31.9
30.4
30.4
31,9
31.9
31.9
31.9
30.4
30.4
31.9
31.9
31.9
31.9
30.4
30.4
31.9
31.9
15.9
15.9
15.2
15.2
15.9
15.9
15.9
15.9
15.2
15.2
15.9
15.9
HC as QU
2
s
0.145
0.145
0.133
0.133
0.145
0.145
0.363
0.363
0.332
0.332
0.363
0.363
0.725
0.725
0.664
0.664
0.725
0.725
0.287
0.287
0.264
0.264
0.287
0.287
0.574
0.574
0.527
0.527
0.574
0.574
165
16.5
15.1
15.1
165
16.5
165
16.5
15.1
15.1
16.5
16.5
16.5
16.5
15.1
15.1
16.5
165
49
4.9
4.5
4.5
4.9
4.9
4.9
4.9
4.5
4.5
4.9
4.9
-------
TABLE G-17.
WATER POLLUTION IMPACTS FROM "BEST" SO» CENTRDL TECHNIQUES
FOR MEDIUM SULFUR COAL-FIRED BOILERS
O
SYSTEM
Standard
Ibat Rate
MW or
(10s BlU/hr)
8.8
(30)
Boiler
Type
Underfeed
Stoker
Control
Level
(None, % of
SO2 Reduction
None
0%
Moderate
0%
SIP and Optional
Made rate
37%
Intermediate and
Stringent
56%
Type
of
Control
Raw Goal
Raw Ooal
PCC
Level 3
CCC
EMISSIONS
Primary Pollutants
mg/B
(Ib/lir)
None
**
None
TSS = 1.87
= (0.015)
ODD = 2.94
= (0.023)
TOC = 0.51
= (0.004)
[pll = 7.2)
Ca = 2.35
= (0.019)
Na = 2.41
= (0.02).
Mg = 1.12
= (0.009)
No Data
nq/J
(lb/10* BTU)
__
—
= 0.215
= (0.0005)
= 0.33
= (0.0008)
= 0.057
= (0.0001)
= 0.272
= (0.0006)
= 0.286
= (0.0007)
= 0.13
= (0.0003)
Trace Elements
Pollutant
mg/s
None
None
Fe = 0.0037
Zn = 0.0008
Cu = 0.0004
Mn = 0.00048
No Data
Chanoe
over
Raw Ooal*
*
*
A
*
-
* Some increase in environmental effects ccnpared to burning naturally-occurring coal with no controls.
** Discharge flow = 0.18 m'/hr.
-------
TABLE G-17.
WATER POLLUTION IMPACTS FROM "BEST" SO2 CONTROL TECHNIQUES
FOR MEDIUM SULFUR COAL-FIRED BOILERS
(continued)
SYSTEM
Standard Boiler
Ifeat Rate
MW or
(108 BTU/hr)
22
(75)
Type
Watertube
Grate
Stoker
Oontrol
Level
(Name, * of
SO2 Reduction
tone
04
\J o
Moderate
0%
SIP and Optional
Moderate
17*
j t w
Intermediate and
Stringent 56%
Type
of
Control
Raw Coal
Raw Coal
PCC
Level 3
CCC
EMISSIONS
Primary Pollutants
rog/s
(Ib/hr)
None
**
None
TSS = 4.66
= (0.037)
COD = 7.33
= (0.058)
TOC = 1.26
=(0.001)
[PII 7.2]
Ca = 5.86
= (0.047)
Na = 6.0
= (0.048)
Mg = 2.8
= (0.022)
Na Data
ng/J
(lb/106 BTU)
_.
= 0.212
= (0.0005)
= 0.332
= (0.0008)
= 0.06
= (0.0001)
= 0.269
= (0.0006)
= 0.275
= (0.0006)
= 0.126
= (0.0003)
Trace Elements
Pollutant
mg/s
None
None
Fe = 0.0093
Zn = 0.002
Cu = 0.001
Mn = 0.0012
1*3 Data
Chanqe
over
Raw Coal*
*
*
*
*
* Sorns increase in environmental effects compared to buring naturally-occurring coal with no controls.
** Discharge flow =0.18 m'/hr.
-------
TABIE G-17.
WATER POLLUTION IMPACTS FROM "BEST" SO2 OKITOL TECHNIQUES
FOR MEDIUM SULFUR COAL-FIRED BOILERS
(continued)
SYSTEM
Standard Doiler
I bat Rate
MW or
(10s DTU/hr)
44
(150)
Type
Spreader
Stoker
Cbntrol
Level
(Mane, % of
SO; Reduction
None
0%
MDderate
0%
SIP and Optional
Moderate
37%
Intermediate and
Stringent 56%
Type
of
Control
Raw Goal
Raw Cbal
PCX
Level 3
coc
EMISSIONS
PrJbreiry Pollutants
mg/s
(Ib/hr)
None
None
TSS = 9.35
= (0.074)
GOD = 14.7
= (0.116)
TOC = 2.54
= (0.02)
[pH = 7.2]
Ca = 11.8
= (0.093)
Na - 12.0
= (0.095)
Mq = 5.61
= (0.044)
Nb Data
nq/J
(lb/106 BTIU)
= 0.212
= 0.0005
= 0.332
= (0.0008)
= 0.057
= (0.0001)
= 0.266
= (0.0006)
= 0.272
= (0.0006)
= 0.126
= (0.0003)
Trace Elements
Pollutant
mg/s
None
None
Fe " 0.018
Zn = 0.004
Cu = 0.002
Mi = 0.0024
No Data
Change
over
Raw Goal*
*
*
*
*
—
-------
TAELE G-17.
WATER POIJUUTION IMPACTS FROM "BEST" SOz CONTROL TECHNIQUES
TOR MEDIUM SULFUR COAL-FIRED BOILERS
(continued)
SYSTEM
Standard Boiler
Ifeat Rate
MW or
(10s BTU/hr)
58.6
(200)
Type
Pulverized
Coal Fired
Gbntrol
Level-
(Name, % of
SOz Reduction
None
0%
Moderate
0%
SIP and Optional
Moderate
37%
Intermediate and
Stringent 56%
Type
Of
Control
Raw Coal
Raw Goal
PCC
Level 3
CCC
EMISSIONS
Primary Pollutants
mg/s
(lb/hr)
None
**
None
TSS = 12.4
= (0.098)
ODD = 19.6
= (0.155)
TOC = 3.38
= (0.026)
IpH = 7.2]
Ca = 15.6
= (0.124)
Na = 16.0
= (0.127)
Mg = 7.48
= (0.059)
No Data
ng/J
(lb/10* BTU)
—
= 0.211
= (0.0005)
= 0.333
= (0.0008)
= 0.056
= (0.0001)
= 0.266
= (0.0006)
= 0.273
= (0.0006)
= 0.127
= (0.0003)
Trace Elements
Pollutant
mg/s
None
None
Fe = 0.0249
Zn = 0.0053
Cu = 0.0027
Mn = 0.0032
No Data
Ohanqe
over
Raw Goal*
*
*
*
*
* Some increase in environmental effects compared to burning naturally-occurring coal with no controls.
** Discharge flow = 0.18 m'/hr.
-------
TftBIE G-17.
WATER POLIUTION IMPACTS FROM "BEST" SO2 CONTROL TECHNIQUES
TOR MEDIUM SULFUR COAL-FIRED BOILERS
(continued)
SYSTEM
Standard Boiler
Ibat Rate
MM or
(10K DTU/hr)
118
(400)
Type
Pulverized
Goal Fired
Control
level
(Name, % of
SOZ Reduction
None
0%
Moderate
0%
SIP and Optional
Moderate
37%
Intermediate and
Stringent 56%
Type
of
Control
Raw Goal
Raw Goal
PCC
Level 3
CCC
EMISSIONS
Primary Pollutants
mg/s
(Ib/hr)
None
**
None
TSS = 24.9
= (0.197)
ODD « 39.2
= (0.311)
TOC = 6.76
= (0.053)
IpH = 7.2]
Ca = 31.3
= (0.240)
Na = 32.1
= (0.254).
Mcj = 15.0
= (0.118)
No Data
ng/J
(lb/10s BTU)
= 0.212
= (0.0005)
= 0.334
= (0.0008)
= 0.056
= (0.0001)
= 0.266
= (0.0006)
= 0.273
= (0.0006)
= 0.126
= (0.0003)
Trace Elements
Pollutnnt
mg/s
None
None
Fe = 0.0498
Zn = 0.0106
Cu = 0.0053
Mn = 0.0064
No Data
Change
over
Raw Coal*
*
A
*
*
* Some increase in environmental effects compared to burning naturally-occurring coal with no controls.
** Discharge flow = 0.18 m'/hr.
-------
TABIE G-18.
Solid Wastes from "Best" SOz Control Techniques for Coal-Fired Boilers
Msdium Sulfur Coal
(continued)
K
SYSTEM
Standard Boiler
Ifeat Rate
(Mrt or
10* BTU/hr)
8.8
(30)
Type
Underfeed
Stoker
Control
level
(Name, % of
SOj Reduction
Uncontrolled
0%
Moderate
1,290 ng S02/J
SIP
1,075 ng S02/J
Optional
Moderate
860 ng SO2/J
37%
Intermediate
645 ng SOz/J
Stringent
516 ng SO2/J
56%
Type
of
Control
Raw Cbal
Raw Coal
PCC
Level 3
PCC
Level 3
CCC
ERDA
CCC
EPDA
EMISSIONS
Solid Waste
g/s
(IVhr)
Cleaning
0
Bottom Ash
26.8(212.5)
Fly Ash
9.0 (71.4)
Total Ash
35.8(283.9)
Cleaning
21.4(169.7)
Bottom Ash
17.4(138.0)
Fly Ash
5.8(46.0)
Total Waste
44.6(353.7)
Cleaning
8.9(70.6)
Bottom Ash
20.2(160.2)
Fly Ash
6.7(53.1)
Total Waste
35.8(283.9)
ng/J
(lb/106 BTU)
1,032(2.4)
3,053 (7.1)
4,085 (9.5)
2,451 (5.7)
1,978(4.6)
645(1.5)
5,074(11.8)
1,032(2.4)
2,279 (5.3)
774(1.8)
4,085(9.5)
Percent
Increase
over NO
controls
24.2%
0
Percent
Increase
over SIP
controls
19.7%
-------
TABLE G-18.
Solid Wastes from "Best" SOj Control Techniques for Coal-Fired Boilers
Medium Sulfur Coal
(continued)
SYSTEM
Standard Boiler
Ibat Rate
(MW or
10s BTU/hr)
22(75)
Type
Chain
Grate Stoker
Control
Level
(Name, % of
SO2 Reduction
Uncontrolled
0%
Maderate
1,290 ng S02/J
SIP
1,075 ng SO /J
Optional Moderate
860 ng SO2/J
37*
Intermediate
645 ng SO /J
Stringent
516 ng SO?/J
56%
Type
of
Control
Raw Coal
Raw Coal
PCC
Level 3
PCC
Level 3
CGC
ERDA
OCC
ERDA
EMISSIONS
Solid Waste
g/s
(Whr)
Cleaning
0
Bottom Ash
66.9(530.5)
Fly Ash
22.3(176.8)
Total Ash
89.2(707.3)
Cleaning
53.3(422.7)
Bottom Ash
43.5(344.9)
Fly Ash
14.5(115.0)
Total Waste
111.3(882.6)
Cleaning
22.3(176.8)
Bottom Ash
50.2(398.1)
Fly Ash
16.7(132.4)
Total Waste
89.2(707.3)
ng/J
(lb/10« BTU)
3,053(7.1)
989 (2.3)
4,042 (9.4)
2,408 (5.6)
1,978(4.6)
645 (1.5)
5,031(11.7)
989 (2.3)
2,279 (5.3)
774(1.8)
4,042 (9.4)
Percent
Increase
over NO
controls
24.2%
0%
Percent
Increase
over SIP
controls
19.9%
-------
TABLE G-18.
Solid Wastes from "Best" S02 Control Techniques for Coal-Fired Boilers
Medium Sulfur Goal
(continued)
SYSTEM
Standard Boiler
Iteat Rate
(MW or
10s BTU/hr)
44
(150)
Type
Spreader
Stoker
Control
level
(Name, % of
SOj Reduction
Uncontrolled
0%
Mxferate
1,290 ng SO2/J
SIP
1,075 ng SO2/J
Optional Moderate
860 ng S02/J
37%
Intermediate
645 ng SO2/J
Stringent
516 ng S02/J
56%
Type
of
Control
Raw Coal
Raw Coal
PCC
Level 3
PCC
Level 3
:cc
3RMV
DCC
3RDA
EMISSIONS
Solid Waste
g/s
(Ib/hr)
Cleaning
0
Bottom Ash
62.6(496.4)
Fly Ash
116.2(921.9
Total Ash
178. 8 a, 4175
Cleaning
106.9(847.7
Bottom Ash
40.7(322.8)
Fly Ash
75.5(598.7)
Total Waste
223.1(1,769)
Cleaning
44.7(354.5)
Bottom Ash
46.9(371.9)
Fly Ash
87.2(691.5)
Total Waste
178.8(1,418)
ng/J
(lh/10* BTU)
1,419(3.3)
2,623(6.1)
I 4,042(9.4)
2,408(5.6)
946 (2.2)
1,720(4.0)
5,074 (11.8)
1,032(2.4)
1,075(2.5)
1,978(4.6)
4,085(9.5)
Percent
Increase
over NO
controls
25.5%
1.1%
Percent
Increase
over SIP
controls
19.1%
-------
TABIE G-18.
Solid Wastes from "Best" SOt Control Techniques for Coal-Fired Boilers
Mediwn Sulfur Cbal
(continued)
SYSTEM
Standard Boiler
Ibat Rate
(MW or
10s BTO/hr)
58.6
(200)
•IVpe
Pulverized
Control
LeVQl
(Name, % of
SO; Reduction
Uhoontrolled
0%
Moderate
1,290 ng SO /J
SIP
1,075 ng SO /J
Optional Moderate
860 ng SO /J
37%
Intermediate
645 ng SO /J
Stringent
516 ng SO /J
56%
Typo
of
Control
Raw Coal
Raw Goal
PCC
Level 3
PCC
Level 3
CCC
ERDA
CCC
ERDA
EMISSIONS
Solid Waste
g/s
(Ib/hr)
Cleaning
0
Bottom Ash
47.7(378.3)
Fly Ash
190.9(1,514)
Total Ash
238.6(1,892)
Cleaning
142.4(1,129)
Bottom Ash
31.0(245.8)
Fly Ash
124.0(983.3)
Total Waste
297.4(2,358.
Cleaning
59.6(472.6)
Bottom Ash
35.8(283.9)
Fly Ash
L43.2 (1,136)
Total Waste
>38.6 (1,892)
ng/J
(lb/106 BTU)
817 (1.9)
3,268(7.6)
4,085(9.5)
2,451 (5.7)
516 (1.2)
2,107 (4.9)
1) 5,074(11.8)
1,032(2.4)
602 (1.4)
2,451(5.7)
4,085(9.5)
Percent
Increase
over NO
controls
24.2%
0
Percent
Increase
over SIP
controls
19.1%
00
-------
TABLE G-18.
Solid Wastes from "Best" SO2 Control Techniques for Coal-Fired Boilers
Medium Sulfur Coal
(continued)
SYSTEM
Standard Boiler
Ibat Rate
(MW or
10s BTO/hr)
118
(400)
Type
'ulverized
Control
Level
(Name, % of
S02 Reduction
uncontrolled
0%
Moderate
1,290 ng S02/J
SIP
1,075 ng S02/J
Optional Moderate
860 ng SO2/J
37%
Intermediate
645 ng S02/J
Stringent
516 ng SOz/J
56%
•type
of
Control
Raw Coal
Raw Goal
PCC
Level 3
PCC
Level 3
CCC
ERDA
CCC
ERDA
EMISSIONS
Solid Waste
g/s
(lb/hr)
Cleaning
0
Bottom Ash
95.4(756.5)
Fly Ash
381.8(3,028)
Total Ash
477.2(3,784)
Cleaning
284.9(2,259
Bottom Ash
62.0(491.7)
Fly Ash
247.8(1,965
Total Waste
594.7(4,716
Cleaning
119.3(946.0
Bottom Ash
71.6(567.8)
Fly Ash
286.3(2,270
Total Waste
477.2(3,784
rij/J
(lb/106 BTU)
817 (1.9)
3,268 (7.6)
1,085 (9.5)
3) 2,451(5.7)
516 (1.2)
0)2,107(4.9)
0)5,074(11.8)
1,032(2.4)
602(1.4)
4)2,451(5.7)
2)4,085(9.5)
Percent
Increase
over NO
controls
24.2%
0%
Percent
Increase
over SIP
controls
19.1%
VD
-------
TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-178C
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
5. REPORT DATE
Technology Assessment Report for Industrial Boiler
Applications: Coal Cleaning and Low Sulfur Coal
December 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR^ Buroff ,B.Hylton,S. Keith,J.Strauss, and
L.McCandless (Versar); and D. Large and G.Sessler
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Versar, Inc.
6621 Electronic Drive
Springfield, Virginia 22151
10. PROGRAM ELEMENT NO.
EHE623A
11. CONTRACT/GRANT NO.
68-02-2199, Task 12
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
Task Final; 9/78 - 7/79
14. SPONSORING AGENCY CODE
EPA/600/13
is.SUPPLEMENTARY NOTESBERL-RTP project officer is James D. Kilgroe, Mail Drop 61, 919
541-2851.
16. ABSTRACT The report assesses the use of three pollution control technologies--low
sulfur coals, physical coal cleaning (PCC), and chemical coal cleaning (CCC)--to
comply with SO2 emission regulations. It is one of a series to be used in determining
the technological basis for a new source performance standard for industrial boilers.
Candidate systems were selected after consideration of 7 naturally occurring low sul-
fur coals, 5 levels of sulfur removal by PCC, and desulfurization by 11 CCC pro-
cesses. The best systems of emission reduction were identified for three coals at
each of five emission control levels. Low sulfur western coal can meet all emission
levels down to 516 ng SO2/J without cleaning. TJncleaned low sulfur eastern coal can
achieve emission levels above 860 ng SO2/J; when physically cleaned, this coal can
be used to meet an emission level of 516 ng SO2/J. High sulfur coal can be cleaned
to meet emission levels of 645 ng SO2/J and higher; for this coal, CCC must be used
to produce fuels capable of complying with an emission limit of 516 ng SO2/J. These
indings apply only to the coals evaluated; in general, each coal has a distinctly dif-
Iferent desulfurization potential. For regulatory purposes this assessment must be
viewed as preliminary, pending results of a more extensive examination of impacts
called for under Section 111 of the Clean Air Act Amendments.
117-
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Pollution
Assessments
Boilers
Coal
Cleaning
Coal Preparation
Sulfur Dioxide
b.lDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
Industrial Boilers
Low Sulfur Coal
c. COSATI Field/Group
13B
14B
13A
21D
13H
081
07B
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
758
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
720
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