EPA-600/2-76-076
March 1976
Environmental Protection Technology Series
ASSESSMENT OF THE DEGREE OF
FLEXIBILITY IN FUEL DISTRIBUTION PATTERNS
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides the new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is availabJe-to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/2-76-076
March 1976
ASSESSMENT OF
THE DEGREE OF FLEXIBILITY
IN FUEL DISTRIBUTION PATTERNS
by
E.H. Hall, A.A. Putnam, andR.L. Major
Battelie-Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Contract No. 68-02-1323, Task 11
ROAPNo. 21ADD-036
Program Element No. 1AB013
EPA Task Officer: D. Bruce Henschel
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
ABSTRACT
The report gives results of a study to evaluate the potential
of fuel switching as an element of an overall strategy for the control of
sulfur oxide emissions from stationary sources. Blocks of misplaced fuels
(i.e., clean fuels now burned in large sources and dirty fuels now burned
in small sources) were identified. Various potential constraints to
switching the misplaced fuels were evaluated. These included: equipment
i
constraints, business constraints, and fuel transportation constraints.
From these evaluations, the quantities of misplaced fuels were identified
which are not limited by any of the constraints, and therefore which can
be considered suitable for switching.
ii
-------
TABLE OF CONTENTS
Page
INTRODUCTION 1
CONCLUSIONS AND RECOMMENDATIONS 2
Coal in Large Sources 3
Coal in Small Sources 4
Oil in Large Sources 4
Oil in Small Sources 4
Natural Gas in Large Sources 4
IDENTIFICATION OF BLOCKS OF MISPLACED FUELS 6
Data Sources 6
The National Emissions Data Systems 8
Results of the Analysis of the NEDS 9
Discussion of the NEDS Results 15
Extrapolation of the NEDS Data 17
FACTORS AFFECTING THE ABILITY TO SWITCH "MISPLACED" FUELS .... 22
EQUIPMENT CONSTRAINTS TO FUEL SWITCHING 23
Conceptually Possible Fuel Interchanges 24
Performance Problems of Fuel Switching 25
Boiler and Auxiliary Equipment 29
Coal Interchangeability as Related to Firing Method 33
Coal Characteristics 33
Slag-Type Furnace (Cyclone and Some Pulverized Coal) . . 35
Dry-Bottom Pulverized Coal Furnaces 37
Spreader Stokers 37
Overfeed Stokers 38
iii
-------
TABLE OF CONTENTS
(Continued)
Page
Underfeed Stokers 39
Specific Example of Conversion 39
Population of Convertible Utility Boilers 40
Conclusions 41
BUSINESS-RELATED CONSTRAINTS TO FUEL SWITCHING 42
Summary 43
Utility Fuel Purchasing Practices ...... 44
Coal 44
Oil Use by Utilities 49
Natural Gas , 55
Industrial Fuel Purchasing Practices 57
Coal 57
Oil . 59
Natural Gas . 59
FUEL TRANSPORTATION CONSTRAINTS TO FUEL SWITCHING 61
IDENTIFICATION OF BLOCKS OF FUELS SUITABLE FOR SWITCHING ..... 63
REFERENCES , 66
APPENDIX A
LIST OF ELECTRIC UTILITIES WHOSE PROSPECTUSES AND REGISTRATION
STATEMENTS WERE EXAMINED TO OBTAIN INFORMATION ON FUEL
CONTRACTS AND PURCHASING PROCEDURES 67
APPENDIX B
LIST OF FIRMS AND AGENCIES CONTACTED DURING COURSE OF RESEARCH . . 69
iv
-------
LIST OF TABLES
Table 1. Fuel Consumption in the United States by End Use for
1968 . . , 7
Table 2. Aggregated Data from NEDS Point Source Data Bank.
Fuel Consumption by Sector, Source Size, Region, Fuel
Type, and Sulfur Content 10
Table 3. Electrical Sector Summary - NEDS Point Source Data ... 11
Table 4. Industrial Sector Summary - NEDS Point Source Data ... 12
Table 5. Commercial/Institutional Sector Summary - NEDS Point
Source Data 13
Table 6. Actual Fuel Use in 1972 by Consuming Sector 14
Table 7. Total 1972 Fossil Fuel Use Allocated by Sector, Source
Size, Fuel, and Sulfur Content, on the Basis of the NEDS
Distribution, 1012 Btu/year 19
Table 8. Possible Interchanges of Fuels in Boiler Furnaces ... 24
Table 9. Auxiliary Equipment Needs 32
Table 10. Trends in Coal Purchases by Utilities Between April,
1973, and June, 1974, by Type of Purchase 45
Table 11. List of Largest Commitments of Coal Under Long-Term
Contract by Selected Utilities 48
Table 12. Captive Coal Production by Electric Utilities, 1973 . . 50
Table 13. Coal Reserves Held by Utilities 51
Table 14. Trends in Utility Purchases of No. 6 (Residual) Fuel
Oil Between April, 1973, and June, 1974 .52
Table 15. Changes in Natural Gas Use by the Electric Utilities
Sector 1972-1980 and Relative Dependence on Natural
Gas 56
Table 16. Coal Equivalent of Misplaced Clean Fuels in Large
Sources 62
-------
LIST OF FIGURES
Page
Figure 1. Approximate Relationships of Furnace Exit Gas
Temperature to Heat Release Rate for Various Fuels . . 27
Figure 2. Steam Generating System Showing Typical Location of
Soot Blowers 28
Figure 3. Spot Coal Purchases as Percent of Total Coal Purchases
by Utilities, June, 1974 47
Figure 4. Spot Purchases of Oil as Percent of Total Purchases by
Utilities, June, 1974 54
vi
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ASSESSMENT OP THE DEGREE OF FLEXIBILITY
IN FUEL DISTRIBUTION PATTERNS
by
E. H. Hall, A. A. Putnam, and R. L. Major
INTRODUCTION
This study was conducted for the Industrial Environmental Research
Laboratory of the U.S. Environmental Protection Agency in support of its
evaluation of the potential of fuel switching as an element of an overall
strategy for control of sulfur oxide emissions from stationary sources. A
straightforward means for SO control is to burn a clean fuel, i.e., a fuel
X.
with sufficiently low sulfur content that the SO emission standards can be met
X
without any post-combustion treatment of the stack gas to remove SO . Such
A
clean fuels include natural gas, distillate fuel oil, low sulfur residual fuel
oil, and low sulfur coal. When limitations were placed on sulfur oxide
emissions from stationary sources, compliance was achieved in many cases by
switching to a clean fuel. However, the supply of clean fuels is insufficient
to meet the demand of all stationary combustion sources in this country, and,
as a result, "dirty" fuels, such as high sulfur residual fuel oil and high
sulfur coal, must still be used. Technology for the control of SO emissions
X
when "dirty" fuels are used has been under development and includes stack
gas scrubbing, fluidized-bed combustion, and various coal conversion
processes. At the present time, the projected economy of scale of these
technologies is such that they are not expected to be practical for use
by small sources. In the light of these considerations, an optimum strategy
would be to burn clean fuels in small sources, and to use high sulfur
fuels, with an associated control technology, in large sources. This
pattern of fuel use would result in lower total emissions of SO from
all stationary sources. ,The benefits of such fuel switching would be to
reduce the ambient air concentrations of SO with the resultant reduction
X
in adverse health effects due to SO in the air.
X
The objective of this study was to assess the degree of flexi-
bility in fuel distribution patterns in order to estimate the potential
-------
for switching fuel to achieve the optimum fuel-use pattern to achieve
minimal air pollution. This required an estimation of the quantity and
location of misplaced blocks of fuel which might be considered for
switching from one user to another. In the present context, a misplaced
fuel is a clean fuel being burned in a large source or a dirty fuel
being burned in a small source. For the purposes of this study, a large
source is defined as a source having a heat input greater than 250 x 10
Btu/hr. This is the lower limit for application of New Source Performance
Standards and therefore it is an appropriate definition in the context of
4
this study. For an electric power plant with a heat rate of 10 Btu/kwhr,
this is equivalent to 25 MW. Various potential constraints to switching
the misplaced fuels were evaluated:
(1) Equipment-related factors which prevent switching
from one type of fuel to another
(2) Business-related factors which tie a user to a
specific fuel
(3) Fuel transportation factors which might limit the
quantities of a specific fuel available in a
region or location.
Cost factors associated with fuel switching were not evaluated as these
would be largely site dependent. From these evaluations the quantities
of misplaced fuels which are not limited by any of the constraints, and
therefore can be considered suitable for switching, were identified.
CONCLUSIONS AND RECOMMENDATIONS
12
The following quantities, in 10 Btu/year, of misplaced fuels
have been estimated:
Large Sources Small Sources
Misplaced coal 1,804 2 323
Misplaced oil 2,978 3 479
Misplaced natural gas 10,457
Total 15,239 5,802
-------
Evaluation of the constraints which limit exchange of these fuels leads
to the following general conclusions:
• Gas- or oil-fired boilers cannot be switched to coal
unless they were originally designed for dual fuel
or designed for coal and subsequently converted.
• Coal-fired boilers which were converted to oil may
not be reconvertible.
• One coal can be exchanged for another coal if proper
care is taken to ensure that the properties of the
new coal are compatible with the furnace and boiler
design. Derating of the boiler is often required.
• Approximately 75 percent of utility purchases of
coal are on a long-term contract basis.
• Industrial coal is purchased mainly on a spot basis.
• Captive production of coal is less than 10 percent
of the total coal production.
• Long-term contracts for oil and gas do not appear to
be a barrier to switching.
• Transportation constraints appear to be less restric-
tive than equipment and business factors.
Estimates of the magnitudes of possible specific fuel exchanges
are given in the following paragraphs.
Coal in Large Sources
Low-sulfur coal in large sources can be replaced by high-
sulfur coal or high-sulfur residual oil. Equipment limitations can be
overcome in this case. Business constraints in the form of long term
contracts will be more limiting. Assuming that such contracts are about
uniformly distributed with respect to low- and high-sulfur coal, 25 per-
cent of this block, or 450 x 1012 Btu/year, would be expected to be pur-
chased on a spot basis and, therefore, free for switching.
-------
Coal in Small Sources
High-sulfur coal in small sources can be replaced by low-
sulfur coal, by low-sulfur residual oil, by distillate oil, or by nat-
ural gas. Again, equipment constraints can be overcome and the primary
limitation is that of long-term contracts. Assuming the 25 percent of
the utility coal, and all of the industrial and commercial coal is free
12
from this restraint, about 2000 x 10 Btu/year would be available for
switching.
Oil in Large Sources
Low-sulfur oil can be replaced with high-sulfur oil, or by
high-sulfur coal, if the boiler were originally designed for coal. Boilers
12
which can be converted to coal represent about 1200 x 10 Btu/year. The
remainder could be switched to high-sulfur residual oil, thus the entire
12
block, about 3000 x 10 Btu/year, is essentially available for switching.
The limitation would be the availability of the replacement fuel.
Oil in Small Sources
High-sulfur oil in small sources can be replaced by low-sulfur
residual oil, by distillate oil, or by natural gas. Equipment constraints
can be overcome. Little of the high-sulfur oil is expected to be under
long-term contract, thus essentially all of this block, or about
12
3500 x 10 Btu/year, is available for switching.
Natural Gas in Large Sources
Natural gas cannot be replaced by coal unless the boiler were
originally designed for coal. Only about 600 x 10 Btu/year of the
natural gas-fired boiler capacity could be fired with high-sulfur coal.
The only other replacement fuel for this large block is high-sulfur
residual oil. This change can be accomodated with respect to equipment
factors. The primary limitation would be the availability of the re-
placement fuel.
-------
The quantities of misplaced fuels which are available for
exchange are sufficiently large that fuel switching has definite potential
as a component of EPA*s overall strategy for control of sulfur oxide
emissions from stationary sources. In view of this conclusion, it is
recommended that the next logical steps be taken, namely:
(1) Assessment of the various means by which fuel
switching could be effected, and a determination
of EPA's role in encouraging fuel exchange
(2) Assessment of the costs which would be incurred
in selected, specific, fuel-exchange situations.
-------
IDENTIFICATION OF BLOCKS OF MISPLACED FUELS
The first step in the assessment of the potential of fuel
switching as a control strategy for SO emissions was to identify blocks
X
of misplaced fuel. Inspection of end-use fuel-consumption patterns for
the United States shows that a few large blocks represent a large
fraction of the total energy consumed. A listing of fuel consumption in
1968 is given in Table 1. Residential and commercial space heating
utilizes large blocks of oil and natural gas. Most of this is correctly
placed as distillate fuel oil, a clean fuel, is the petroleum fraction
normally used in such applications. Since these are small sources, the
use of clean fuels is correct in the context of this study. In the
industrial sector large blocks of each of the fossil fuels are used for
process steam and for direct heat. It is not possible to state whether
these blocks are misplaced ox not. The size of the source and the sulfur
content of the fuel must be known in order to identify what portion is
misplaced. The same conclusion applies to the blocks of fuel used in the
generation of electricity.
Data Sources
The data required for the complete identification of misplaced
blocks of fuel include: location and size of individual combustion
sources, type of fuel, sulfur content of fuel, and end-use sector. Most
of the available information pertinent to this is incomplete in one
respect or another. For example, very extensive data exists on the sulfur
(1 2}
content of coal. Two Bureau of Mines reports ' give organic, pyritic,
and sulfate sulfur analyses on about 2,900 samples which include most of
the coalbeds in the United States. Other publications, such as Minerals
Yearbook, give data on the quantities of coal consumed by various end-
use sectors. These two sets of data cannot be combined to yield the type
of information required for this analysis since the sulfur analysis data
does not include any specifics on how and where each coal is consumed,
-------
TABLE 1. FUEL CONSUMPTION IN THE UNITED STATES
BY END USE FOR 1968(a)
Direct Consumption
10*2 Btu/year
End Use
Residential
Space heating
Water heating
Cooking
Clothes drying
Refrigeration
Air Conditioning
Other
Subtotal
Commercial
Space heating
Water heating
Cooking
Air conditioning
Refrigeration
Feedstock
Other
Subtotal
Industrial
Process steam
Electric drive
Direct heat
Feedstock
Electrolytic
Processes
Other
Subtotal
Totals
(a) Source: Stanford
Coal Oil Natural Gas
2,988
146
49
9
3,192
568 2,405
984
568 3,389
2349 1,986
3025 808
147 1,600
5521 4,394
6089 10,975
Research Institute
3,236
979
325
58
5
3
4,606
1,209
422
117
97
1,845
5,797
2,771
455
9.023
15,474
, "Patterns
f rfh f^ * * f* *"» A V
Purchased Electrical Energy
10 12 Btu/year
Coal
258
350
151
81
394
243
711
2188
Nil
132
13
582
384
587
1698
2634
179
388
109
3310
7196
of Energy
Oil Natural Gas
43
58
25
13
65
40
118
362
Nil
23
2
96
63
97
281
488
33
72
20
613
1256
118
159
68
37
179
111
324
996
Nil
60
6
265
175
268
774
1353
92
199
56
1700
3470
Consumption
in the United.States", pp 26-29 (1972)
-------
and the consumption data does not give sulfur analysis. A similiar situa-
tion exists for petroleum products. Mineral Industry Surveys, published
by the Bureau of Mines, report data on the sulfur content of various
petroleum fractions without any information on end use, while publica-
tions such as Petroleum Facts and Figures give extensive data on end use
of fuel oils without any information on sulfur content. Again, the two
sets of data cannot be combined to identify misplaced blocks of fuel.
In the utility sector, the Federal Power Commission publishes monthly
/•o\
reports of fuel deliveries, broken down by Region and State, which
include the sulfur content. These reports do not give information on
the plant size. The Federal Power Commission also releases lists of fuel
deliveries to specific plants which include sulfur content. These would
have to be totaled over an entire year which would require an inordinate
amount of time. Twelve-month summaries of these data are available
but, in the aggregation of the data, the plant specificity is last and
the resultant average sulfur content cannot be used to represent all
shipments.
The Nat i onal Emi s s ions Pat a Sy s tern
One data source which does include all of the required infor-
mation is the National Emission Data System (NEDS) being developed by
EPA. This data source is not complete, however, it contains all of the
required information relative to individual sources in a form which could
be readily used to identify misplaced blocks of fuel. Some variation
exists within the data file with respect to the date of receipt of data.
However, the data generally refer to the year 1972.
A tape of the NEDS point-source data file was obtained and a
program was written to aggretate the data by sector, source size, EPA
region, fuel type, and sulfur content.
-------
Results of the Analysis of the NEDS Data
The regional fuel-use values for the electrical sector first
obtained by aggregating the NEDS data were compared with FPC summary data.
Three results were obviously too high by an order of magnitude. The
program was rerun with screening instructions for the computer to print
12
out the input data on any source for which a heat input of >200 x 10 Btu/
year was indicated. Four sources were screened out on this basis. The
errors in each case resulted from improper use of units in the input data.
The data for each source were recalculated by hand and the resultant
corrections applied to the aggregate totals obtained in the first run.
With these corrections, the results agreed favorably with the FPC
summary data.
The corrected results of data aggregation are presented in
12
Table 2. The data represent aggregate plant fuel consumption in 10 Btu/
year. Summaries by sector of the data from Table 2 are given in Tables 3,
4, and 5. It should be noted that the residential sector is not included
in the point-source category of the NEDS data file. This is not significant
since, as noted previously, the fuels used in the residential sector are
generally correctly placed. The percentages of high- and low-sulfur
fuel in each plant-size category and the total capacity for each fuel are
given in Tables 3, 4 and 5. The total capacity for each fuel in the
electrical and industrial sectors may be compared with the actual fuel
use, as shown in Table 6, to estimate the completeness of the NEDS data
file. This is shown in the following tabulation of the ratio of NEDS
total fuel-use figure (Tables 3 and 4) divided by the actual use (Table 6).
Natural
Sector Coal Petroluem Gas
Industrial 0.29 0.19 .20
Electrical 1.04 0.90 0.96
The results indicate that for the electrical sector the NEDS data file is
reasonably complete. The NEDS data file is much less complete for the
-------
TABLE 2. AGGREGATED DATA FROM NEDS POINT SOURCE DATA BANK. FUEL CONSUMPTION
BY SECTOR, SOURCE SIZE, REGION, FUEL TYPE, AND SULFUR CONTENT
Sources =• 250x106 Btu/hnur
REGION**1 E(b)
1 0
2 197
3 9
4 73
5 465
6 143
7 567
8 0
Totals 1,454
I
0
0
72
3
9
29
3
0
116
C/I TOTAL E
— — — ' — -1 — imnnr- — irnmniiiiiimnTnniiiiiiiiiiiiiiiiMiiin I i •• _
Coal. 1012 Btu/year
0 0 60
0 197 1,063
0 81 2,329
0 76 602
0 474 987
0 172 1,113
0 570 0
00 0
1,570 6,154
I C/I
~— •."— "HHPM^MM
5*1% S
0 0
72 0
168 0
27 2
78 0
51 0
0 0
0 0
396 2
GRAND
TOTAL TOTAL
•••••^^^^^^•••^••••••••••••MHHMV
60
1,135
2,497
631
1,065
1,164
0
0
6,552 8,122
REGION
1
2
3
4
5
6
7
8
Totals
E
0
26
17
17
14
0
13
0
87
I
0
26
105
12
40
43
11
0
237
C/I
1 S
0
3
7
2
5
2
1
0
20
Residual Oil. 1012 Btu/vesr
1 128
2 553
3 129
4 1
5 179
• 6 76
7 1
8 181
Totals 1,248
«: ]
0
19
8
0
18
5
15
26
91
L% S
0 128 266
16 588 193
0 137 30
01 3
0 197 590
0 81 10
0 16 8
0 207 15
16 1,355 1,115
a.1% S
19 0
32 0
39 0
11 0
105 0
0 0
0 0
4 6
210 6
285
225
69
14
695
- 10
8
25
1,331 2,686
1
2
3
4
5
6
7
8
Totals
53
133
7
2
9
2
1
16
223
«;13
25
103
34
3
39
4
4
8
220
'. s
3
14
1
0
17
0
0
0
35
Distillate Oil. 1012 Btu/year
I 0
2 15
3 10
4 0
5 29
6 14
7 5
8 0
Totals 73
0
5
88
0
5
3
0
4
105
0 0
0 20
0 98
0 0
2 36
0 17
0 5
0 4
2 180
180
1
2
3
4
5
6
7
8
Totals
1
17
7
1
7
2
I
0
36
I
9
27
6
18
9
1
7
78
1
7
3
3
3
0
2
0
19
natural Gas, 10*2 Btu/year
1 6
2 108
3 152
4 286
5 329
6 1,948
7 177
8 568
(a) 1 New England
2 North Atlantic
0
53
166
106
26
560
43
139
3 East North Central
0 6
18 179
57 375
12 404
0 355
3 2,511
2 222
0 707
92 4,759
(b) E Electrical
I Industrial
4,759
1
2
3
4
5
6
7
8
Totals
5
12
74
101
27
133
38
62
452
8
52
282
116
154
261
82
56
1011
1-
8
9
18
11
8
6
0
61
g
TOTAL E
ourcea -c 2SOxl06 Btu/hour -....„-
! c/I TOTAL
Coal, 1012 Btu/year
0 2
55 69
129 47
31 7
59 30
45 1
25 0
0 0
344 156
Residual
81 65
250 3
42 7
5 2
65 28
6 0
5 0
24 9
478 114
i/e ••» a — <•*•
00 2
41 2 112
62 4 113
60 13
24 3 57
80 9
00 0
00 0
141 9 306
Oil. 1012 Btu/year
»1% S
124 26 215
33 16 52
53 1 61
11 4 17
121 8 157
50 5
80 8
90 18
364 55 533
GNA.1U
E I C/I TOTAL TOTAL
2103
35 47 0 82
204 231 26 461
38 21 0 59
8 2 0 10
7 30 0 37
0000
0000
294 332 26 652 1,302
l.CII
Distillate Oil, 10*2 Btu/year
3
33
37
10
28
11
4
7
133
Natural
14
72
365
235
192
402
126
118
1524
Gas, 1012 Btu/year
.
133
1,524
C/I Commercial/Institutional
4 Vest North Central
5 South Atlantic
6 South Central
7 Mountain
8 Pacific
-------
11
TABLE 3. ELECTRICAL SECTOR SUMMARY -
NEDS POINT SOURCE DATA
Fuel
Coal
<1%S
>1%S
Total Coal
Petroleum
Resid
<1%S
>1%S
Distillate
Total Petroleum
Natural Gas
Sources >250xl06 Btu/hr
Fuel Use
10!2 Btu/year % of Total
1,454 19.1
6,154 80.9
7,608 100
1,248 51.2
1,115 45.8
73 3.0
2,436 100
3,574
Sources <250xl06 Btu/hr
Fuel Use
10*2 Btu/year
87
450
537
223
114
36
373
452
% of Total Total
16.2 1,541
83.8 6,604
100 8,145
59.8 1,471
30.5 1,229
9.7 109
100 2,809
4,026
-------
12
TABLE 4. INDUSTRIAL SECTOR SUMMARY -
NEDS POINT SOURCE DATA
Sources >250xl06 Btu/hr
Fuel
Coal
<1%S
>17.S
Total Coal
Petroleum
Resid
<17oS
>1%S
Distillate
Total Petroleum
Fuel Use
1012 Btu/year
116
396
512
91
210
105
406
7. of Total
22.7
77.3
100
21.9
50.5
27.6
100
Sources £250x10$ Btu/hr
Fuel Use
10*2 Btu/year
237
473
710
220
364
78
662
7» of Total
33.4
66.6
100
33.2
55.0
11.8
100
Total
353
869
1222
311
574
183
1068
Natural Gas
1093
1011
2104
-------
13
TABLE 5. COMMERCIAL/INSTITUTIONAL SECTOR SUMMARY -
NEDS POINT SOURCE DATA
Fuel
Coal
<1%S
>1%S
Total Coal
Petroleum
Re sid
<1%S
>1%S
Distillate
Total Petroleum
Natural Gas
Sources >250xl06 Btu/hr
Fuel Use
10*2 Btu/year % of Total
0
2 100
2 100
16 66.7
6 25.0
2 8.3
24 100
92
Sources £250x106 Btu/hr
Fuel Use
1012 Btu/year % of Total
20 36.4
35 63.6
55 100
35 32.1
55 50.5
19 17.4
109 100
61
Total
20
37
57
51
61
21
133
153
-------
14
TABLE 6. ACTUAL FUEL USE IN 1972 BY
CONSUMING SECTOR
-------
15
industrial sector. Fuel use equivalent to only 19 to 29 percent of the
actual fuel use is included in the source data file. The commercial/
institutional sources are less well represented. As shown in Table 5,
12
a total use for all fuels of only 343 x 10 Btu/year is included in the
NEDS file. This is only 6 percent of the total direct fuel consumption in
the commercial sector in 1968 shown in Table 1.
Discussion of the NEDS Results
The data assembled from the NEDS file were compared with other
information to see that the indicated patterns are reasonable. The
electrical sector data given in Table 3 show that, for all fuels, 9.1 per-
cent of the indicated capacity is in the small source category. For com-
parison, the distribution of steam-electric plants according to size was
(A.)
determined for 1972. ' The list included 966 plants. Of this total,
15.6 percent were below 25 W5 11.8 percent were between 25 and 49.9 MW,
and 72.6 percent were 50 MW or larger. A more detailed distribution is
given in the following tabulation:
Plant Size, MU Number of Plants Percent of Total
0
20
25
30
35
40
45
>50
- 19.9
- 24.9
- 29.9
- 34.9
- 39.9
- 44.9
- 44.9
Total
113
38
25
35
18
26
10
701
966
The NEDS percentage of small plants appears reasonable in comparison with
this distribution, since very large plants would weight the ratio when
calculated on a total Btu basis, as was the NEDS percentage, rather than
on the basis of the number of plants. A comparison of the NEDS ratio of
-------
16
high- and low-sulfur coal in the industrial sector also was made.
Bureau of Mines data for 1972^ on bituminous coal and lignite ship-
ments, representing about 60 percent of the total coal production, show
that about 78 percent of the coal shipped to industrial users (other than
coke plants) and to retail dealers was high-sulfur coal. This compares
well with the overall value of 71 percent high-sulfur coal in the
industrial sector from the NEDS data shown in Table 4. Such comparisons
indicate that, although the NEDS data file is incomplete, the indicated
fuel-use distributions are reasonable.
The regional location of misplaced blocks of fuel can be seen
in the data of Table 2. A summary of the largest blocks is given in
the following tabulation:
Source
Fuel Size
Natural Gas Large
Natural Gas Large
Low-Sulfur Coal Large
Natural Gas Large
Low-Sulfur Resid Large
Low-Sulfur Coal Large
Natural Gas Large
Natural Gas Large
High-Sulfur Coal Small
High-Sulfur Coal Small
Low-Sulfur Coal Large
Low-Sulfur Resid Large
Low-Sulfur Resid Large
Natural Gas Large
Natural Gas Large
Natural Gas Large
Region
South Central
Pacific
Mountain
South Central
North Atlantic
South Atlantic
South Atlantic
West North Central
East North Central
East North Central
North Atlantic
Pacific
South Atlantic
Mountain
East North Central
East North Central
Sector
Electrical
Electrical
Electrical
Industrial
Electrical
Electrical
Electrical
Electrical
Industrial
Electrical
Electrical
Electrical
Electrical
Electrical
Industrial
Electrical
NEDS Quantity
10*2 Btu/year
1948
568
567
560
553
465
329
286
231
204
197
181
179
177
166
152
Other misplaced blocks of smaller magnitude also are included in Table 2.
The blocks listed above are mostly in the electrical sector. This is
undoubtedly biased by the fact that, as noted previously, only about
-------
17
19 to 29 percent of the actual industrial-fuel use is included in the
NEDS data file. If that sector were more fully represented, additional
blocks of industrial fuel use such as: natural gas in the Pacific and
West North Central region, distillate oil in the East North Central
region, and low-sulfur coal in the East North Central region, would very
likely equal many of the utility fuel blocks listed above.
Extrapolation of the NEDS Data
The distribution of fuel use by region, sector, source size,
fuel type and sulfur content appears reasonable and therefore useful in
evaluating the possibilities for fuel switching. Also the quantities of
fuel indicated in the electrical sector blocks are approximately correct
since the total of such blocks approximately equals the actual total for
that sector. However, it was noted previously that the NEDS file is
incomplete for the industrial and commercial/institutional sectors,
therefore, the quantities of fuel in those blocks are too low. In order
to estimate the magnitude of those blocks, it was assumed that the
distribution of fuel use exhibited by the existing NEDS data would
apply to the entire population of sources. With this assumption the
summary NEDS data of Tables 3, 4 and 5 were extrapolated on a proportional
basis so that the totals for each fuel equal the actual-use values for
1972 as given in Table 6. For illustration, the extrapolated coal
quantities in the electrical sector blocks were calculated as follows
12
(all units are 10 Btu/year):
Total actual coal in the electrical sector (Table 6) = 7837
Total NEDS coal in the electrical sector (Table 3) = 8145
Ratio = 7837/8145 =0.96
-------
18
From Table 3:
Extrapolated
Block NEDS Value x 0.96 = Value
Low Sulfur, Large Source 1454 ' 1399
High Sulfur, Large Source 6154 5921
Low Sulfur, Small Source 87 84
High Sulfur, Small Source 450 433
Totals 8145 7837
The results of these extrapolations are given in Table 7. The totals for
each fuel shown in the last four columns are the same as in Table 6. The
residential/commercial sector required slightly different treatment as the
NEDS point-source data do not include the residential sector. The totals
for each fuel were first allocated separately to the two sectors on the
basis of the ratios of fuel use taken from Table 1, in which the two
sectors are listed separately. For example, the total natural gas in
12
the R/C sector from Table 6 is 7642 x 10 Btu/year. From Table 1, the
residential natural gas is 4606, the commercial natural gas is 1845,
and the total is 6451. The residential natural gas allocation is:
7642/6451 x 4606 = 5456, the commercial natural gas allocation is:
7652/6451 x 1845 = 2186, and the total is 7642. The other fuels were
allocated in the same manner. This breakdown between the two sectors is
given in the second and third lines of Table 7. The natural gas and
petroleum quantities for the residential sector were placed directly in
the small-source blocks of natural gas and distillate. The fuels in the
commercial sector were allocated to each block according to the NEDS
distribution (Table 5) in the same manner as for the industrial and
electrical sectors. As noted, the extrapolations in the commercial
sector are weak because of the limited NEDS data for the sector.
The blocks of misplaced fuels are noted in Table 7 by under-
lining. On the basis of this extrapolation from the NEDS data, the
largest single block is natural gas in large sources in the industrial
sector. This is used for process steam and for direct heat. Other
-------
TABLE 7. TOTAL 1972 FOSSIL FUEL USE ALLOCATED BY SECTOR, BY SOURCE SIZE, BY FUEL, AND BY SULFUR CONTENT, ON THE BASIS
OF THE NEDS DISTRIBUTION, 1Q12 Btu/year
Sources
>250xl06
Btu/hr
Coal Resid
Sector
Residential
and Commercial
Residential
Commercial
Industrial
Electrical
Generation
<1%S >US <1%S
-
0* 14* 413*
405 1383 483
1399 5921 1392
>1%S Distillate
155*
1114
1244
52*
557
Si
Natural
Gas
1314*
5502
3641
Sources £250x10^
Coal Resid
Btu/hr
<1%S >1%S 1%S Distillate
136* 238* 903* 1420*
828 1652 1168 1932
84 433 249 127
3234
490*
414
40
Natural
Gas
5456
872*
5089
461
Coal
387
0
387
4267
7837
Totals
Petroleum
6,667
3,234
3,433
5,668
3,134
Natural
Gas
7,642
5,456
2,186
10,591
4,102
Grand
Total
14,696
20,526
15,073
*Weak extrapolation because of limited NEDS data in the Commercial/Institutional category.
-------
20
large blocks include: natural gas, low-sulfur coal, and low sulfur
residual oil in large electric power stations, and high-sulfur coal and
high-sulfur residual oil in small industrial sources. The total of
misplaced blocks is 21,041 x 1012 Btu/year and the total of all blocks
is 50,295 x 1012 Btu/year. Thus, 42 percent of the total fuel is misplaced.
Of the misplaced fuel, 15,239 x 1012 Btu/year, or 72 percent, is clean
-I e\
fuel in large sources, while 5,802 x 10 Btu/year, or 28 percent, is high-
sulfur fuel in small sources. Thirty eight percent of the clean fuel
now burned in large sources would be sufficient to displace the dirty
fuel in small sources if it could be switched.
The estimation of the quantities and locations of misplaced
fuels for future years is very difficult because of the existance of
unpredictable factors which will impact on this situation. Some of these
factors are:
• Increasing overall demand will tend to increase the
size of the misplaced blocks
• Environmental considerations will tend to increase
the use of clean fuels to the extent they are available
• Clean fuels will not be sufficiently plentiful to
satisfy all the demand. Even now natural gas supplies
to industrial customers are being curtailed
• Synthetic clean fuels will provide some of the demand
but projections of the availability of such fuels vary
widely according to the source.
In the absence of other considerations, the increase in overall demand
would be expected to result in an increase in the size of the blocks of
misplaced fuel to the extent that historical fuel sources continue to be
utilized. Projections of the rate of growth in overall energy demand
vary from a low of 2.7 percent^ ' to a high of 4.2 percent' . A some-
what more modest upper value of 3.7 percent growth was projected by the
(8)
Department of the Interiorv '. Assuming similiar rates of increase in
the size of the blocks of misplaced fuel, the projected quantities would
be:
-------
21
Clean Fuels, Dirty Fuels,
Year Large Sources Small Sources .Total
1012 Btu/year at 2.7 percent growth rate
1972
1980
1990
2000
15,200
18,900
24,600
32,100
5,800
7,200
9,400
12,200
21,000
26,100
34,000
43,300
1012 Btu/year at 3.7 percent growth rate
1972
1980
1990
2000
15,200
20,400
29,300
42,100
5,800
7,800
11,200
16,000
21,000
28,200
40,500
58,100
Counter to this tendency for the quantities of misplaced fuel
to increase as overall demand increases, is the fact that supplies of
clean fuel are limited. The use of natural gas in large boilers cannot
increase at the rates suggested above without some dramatic increase in
the supply of natural gas.
It is not possible to make accurate projections of future
quantities of misplaced fuels because of such conflicting influences.
Without definitive action to the contrary, the quantities of misplaced
fuels can be expected to increase but at a lesser rate than overall
demand.
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22
FACTORS AFFECTING THE ABILITY TO
SWITCH "MISPLACED" FUELS
The analysis described in the preceding, section has shown that
there is a large quantity of clean fuel being burned in large sources
and a smaller, but still significant, quantity of high-sulfur fuel being
turned in small sources. To achieve the optimum effectiveness with
respect to limitation of sulfur oxide emissions, these misplaced fuels
should be switched to the extent possible. However, these are constraints
which prevent fuel switching in some cases.
The physical form and composition of different fuels varies
and, therefore, the equipment requirments for use of different fuels also
vary. These equipment requirements may prevent the free exchange of fuel
type. Business-related factors may also limit the ability to change
fuels. If a plant has long-term contracts for a certain type of fuel
which cannot be abrogated, it would be difficult to switch to a different
fuel. Finally, the capability of the fuel transportation network to
carry fuels in a significantly different pattern and volume may limit
the real opportunities for switching fuels.
The nature of the limitations posed by these factors and the
degree to which they limit the flexibility in fuel-use patterns are
analyzed in the following sections.
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23
EQUIPMENT CONSTRAINTS TO FUEL SWITCHING
In any consideration of switching or interchanging of fuels among
various users to promote the lowering of pollution, the ability to alter
available equipment to permit such changes must be considered. The purpose
of this phase of the study is to define the equipment-related factors that
would prevent arbitrary interchangeability or shifting of fuels to reduce
overall pollution originating from fuel sulfur content. In general, it is
hypothesized that such pollution reduction may be accomplished by shifting
the "dirtier" fuels to the larger installations where sulfur clean-up
methods are relatively less costly, and feed "clean" fuels to the smaller
installations. Thus, one must consider not only barriers to using high
sulfur fuels in larger facilities where more control of pollution may be
economically possible but also barriers to use of low-sulfur fuels in
smaller facilities also involved in any fuel exchange considerations.
In general, gas and fuel oil can be used to replace coal, and
gas to replace fuel oil, without too much difficulty. Further, the lighter
fuel oils, being of low viscosity, can ordinarily be substituted without
difficulty for heavier fuel oils. In the case of coal, there is such a
wide variety of coal properties, ash properties and contaminants, that the
type of firing system must also be evaluated in considering even the inter-
changeability of various types of coal. As a result, we are not surprised
to find that the recently publicized conversions on the East Coast from
fuel oil to coal are all for steam-power plants that were originally designed
for coal, and were'previously converted to oil.
In this phase of the study, conceptually possible interchanges
among natural gas,* oil, and coal will be considered first. This will be
followed by a review of the performance problems involved in fuel switching,
a general characterization of various boiler types and auxiliary equipment
as related to the interohangeability problem, and a discussion of coal
interchangeability. A specific example of an oil-to-coal conversion, and
the population of possible conversions are next covered. Finally, pertinent
conclusions are drawn.
*Possible interchanges involving the installation and use of gas producers
will not be considered.
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24
Conceptually Possible Fuel Interchanges
The physical forms of fuels—gaseous, liquid, or solid—require
different handling methods and storage facilities, but basically all fuels
burned today in large central-station steam-generating power plants are
"fluid" fuels when they enter the boiler furnace. For natural gas this
poses minimum problems, mainly in metering and distributing the fuel to a
plurality of burners. For residual fuel oil, the problems are similar
except that the temperature of the fuel must be controlled to compensate
for differences in viscosity, and the burners are more complicated. For
pulverized coal,* mixing with air produces a "fluid" fuel that calls
for burners of even more complexity than with fuel oil.
For industrial and commercial sizes of boilers, similar remarks
can be made except for the case of coal. For boilers producing less than
100,000 Ib/hr of steam,'pulverized fuel is rarely used, and the less common
cyclone furnace is not available. Spreader stokers (which compete with
pulverized coal in sizes up to 400,000 Ib/hr of steam), overfeed stokers,
and underfeed stokers are preferred in turn as the capacity decreases.
Burning a solid fuel in fixed fuel beds, as on stokers, is different than
firing a "fluid fuel" as discussed above, and necessitates some differences
in boiler design.
Based on these remarks, the conceptual possibilities for fuel
interchange to reduce sulfur oxides pollution can now be tabulated.
TABLE 8. POSSIBLE INTERCHANGES OF FUELS
IN BOILER FURNACES
Low Sulfur High Sulfur
Fuel Fuel
Gas Oil
Gas Coal
Oil Coal
Oil Oil
Coal Coal
*Pulverized so that 80 percent of the coal particles are smaller than
74 micrometers (200 mesh).
-------
25
It should be noted that each change to high sulfur fuel in a larger in-
stallation implies a change to a low sulfur fuel in a smaller installation.
As a result, the characteristics of smaller boiler furnaces that might limit
interchangeability, as well as those of larger boiler furnaces, must be
considered. Furthermore, other properties are important that might accompany
changes in the sulfur context of a liquid or solid fuel, and might have
an effect on fuels acceptability with a given design of boiler furnace.
Performance Problems of Fuel Switching
Four main problem areas can be defined in attempting the inter-
change of fuels in boiler furnaces as suggested in Table 8:
(1) Differences in heat liberation rates selected
originally when designing a furnace for a specific
fuel;
(2) Differences in the heat-transfer patterns to
furnace wall tubes resulting from burning fuels
with differing flame characteristics;
(3) Fouling*of heat-transfer surfaces because of
the nature of the inorganic matter in some fuels;
and
(4) Slagging** problems induced by low-fusion ash in
furnaces designed for dry-bottom operation, or
difficulty in maintaining fluid slag in wet-
bottom furnaces burning coal with high-ash-fusion
characteristics.
(•(
Heat-liberation rates in central-station boiler furnaces reported
by one manufacturer vary over a large range of values: up to 35,000 Btu/
ft3 hr for tangentially fired pulverized coal units; from 20,000 to
30,000 Btu/ft3 hr for other pulverized coal units and spreader stoker units;
and up to 45,000 Btu/ft3 hr for oil-fired units and natural-gas-fired
* Fouling is deposition of ash on boiler tube banks, usually followed by
sintering, with eventual plugging of space between tube banks.
**Slagging is melting of ash deposits in a boiler furnace.
-------
26
units.(8'9) Another boiler builder indicates ranges of 25,000 to 35,000 Btu/
ft3 hr for oil- and gas-fired units with no essential difference between
these fuels and 12,000 to 20,000 Btu/ft3 hr for dry-bottom pulverized coal
furnaces. Values for wet-bottom are somewhat greater. The curves shown
in Figure 1 indicate that, for a given furnace-exit-gas temperature, the
oil-fired unit would be smallest in surface area and the pulverized coal
unit the largest.
One may conclude, therefore, that for the same total rate of
energy release, furnaces for coal firing are larger by 1.5 to 2 times than
gas or oil-fired units. Thus, ignoring the ash problem, substituting coal
for oil or gas would reduce the rating of a furnace up to one half.
Differences in heat-transfer patterns between gas, oil, pulverized
coal, and stoker coal because of the differing flame characteristics of
these fuels, can be compensated in large part by skillful design of the
burners. Advances in the state of the art of controlling flame configura-
tions over the past 20 years make this the easiest problem to surmount
in substituting one fuel for another.
Fouling of heat-transfer surfaces with the mineral matter in
"dirty" fuels is a major problem in substituting coal for oil or gas.
In a furnace designed to fire coal, multiple sets of soot blowers are
installed, as shown in Figure 2. However, because no such fouling occurs
with natural gas, and is minimal with some fuel oils, no allowance is made
for ineffective heat-transfer surfaces in these furnaces as is necessary
in coal-fired units. Hence, coal cannot be substituted for oil or gas
without a significant penalty in rating. Further, since slag deposits on
furnace walls when burning coal raise the temperature of the flue gas
reaching the superheaters, simply because the wall tubes cannot then
abstract thermal energy from furnace gases, the unit must be derated to
limit outlet steam temperature or elaborate systems must be provided to
bypass the superheater to keep steam temperatures within design limits.
Slagging problems are troublesome also in substituting one
coal for another. High-sulfur coals, for example, almost always contain
large amounts of pyrites, FeS2, which converts to FeO or Fe£03 as the coal
is burned. These iron compounds are extremely effective fluxes for
-------
27
2800
1400
0 20 60 100 140 180 220
Heat Release Rate, 1000 Btu/sq ft, hr
FIGURE 1. APPROXIMATE RELATIONSHIPS OF FURNACE-
EXIT-GAS TEMPERATURE TO HEAT RELEASE
RATE FOR VARIOUS FUELS
Source: "Steam, Its Generation and
Use", Babcock & Wilcox, 1972
-------
28
FIGURE 2. STEAM GENERATING SYSTEM SHOWING TYPICAL LOCATION
OF SOOT BLOWERS
Source: Bender, R. J., "Steam Generation" Power
Special Report, McGraw-Hill (No date)
-------
29
decreasing the fusion temperature of coal ash so that high-pyrite coals
almost invariably melt at low temperatures and are easily slagged. Low-
sulfur coals, contrarywise, contain small amounts of pyrites and, hence,
do not generally melt as easily, at least for Eastern coals. Western coals,
on the other hand, although low in pyrites, often contain large amounts of
CaO, MgO, and Na£0 which also are effective fluxes and lead to low melting
points. Therefore, although sulfur content is a fair indicator of ash-
slagging tendency for Eastern coals, it is not equally predictive for
Western coals.
It is possible to add flux such as limestone to coal to induce
the formation of molten slag for slag-tap furnaces. The utilities have
been reluctant to use this approach because of the possible formation of
molten iron in the slag bed and of increased fouling of superheaters.
Preventing the formation of slag is much more difficult; no
practical scheme has been demonstrated as yet whereby a low fusion coal
can be burned satisfactorily in a dry-bottom furnace at any reasonable
heat release rate.
Boiler and Auxiliary Equipment
Boiler furnaces do not differ radically in design for different
fuels except in provisions for differing ash characteristics. Natural
gas has no problems here. Thus, boilers to be fired only with natural gas
need nooprovision for preventing ash deposits, or for ash handling.
Residual fuel oil contains up to 0.1 percent inorganic matter
(ash), for which allowance must be made in boiler design because of the
deposits that gradually accumulate on heat-receiving surfaces. While the
small amount of ash may have little effect on heat transfer, the highly
corrosive nature of the deposits on heat-receiving surfaces when burning
fuel oils high in vanadium and sodium poses special problems. European
utilities often surmount this problem by operating with very low excess
air, typically less than 1 percent, but this practice is not followed
generally in the United States.
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30
Oil-fired furnaces are often equipped to burn natural gas since
furnace design characteristics do not differ significantly for these two
fuels. In fact, for smaller capacities, below about 10^ Ib/hr of steam,
design of gas- and oil-fired units are often identical. Nevertheless,
since there is an appreciable difference in the radiation characteristics
of oil flames compared with gas flames, the transfer of heat to the furnace
walls may occur in quite different patterns. This means that provisions
must be made in larger-capacity boiler furnaces, either oil or gas, for
bypassing some of the furnace outlet gas around the superheater to control
steam temperature within the narrow limits required by modern steam
turbines. Generally, though, natural gas or fuel oil can be burned inter-
changeably in most large boiler furnaces designed originally with heat-
transfer surfaces intended for these "clean" fuels. The major exception
is when "corrosive" fuels are used.
Coal-fired boiler furnaces, especially when pulverized coal is
used, do not differ greatly in general design from gas-fired or oil-
fired units. However, as also mentioned above, the size is generally larger
for a given capacity, unless it is a multiple fuel unit; in this case, the
needs of the coal-firing system control the size rather than gas firing or
oil firing. Because of the severe fouling of furnace wall tubes, super-
heater and reheater elements, economizers, and air preheaters, passages
must be made larger with coal firing than with a comparable oil-fired or
gas-fired unit. Furthermore, provision must be made for extensive soot
blowing of the passages (see Figure 2).
In the utility-size range, pulverized coal-fired units are by
far the most common. The burners are similar to gas or oil-fired burners,
and thus the boiler configuration in this extent is similar. However, be-
cause of the difference of slagging characteristics of various coals, dry
bottom and wet bottom (or slag tap) configurations are available. This
imposes an extra feature on the coal-fired boiler. In the case of the
cyclone furnace, the primary burning takes place in the "cyclone" or "cyclones"
exterior to the boiler, and again an extra feature is superimposed on the
boiler.
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31
In the smaller utility boiler range and the industrial boiler
range of coal-fired units, fuel-burning equipment varies widely. Stoker
firing predominates, with pulverized coal being little used in the size
range below 100,000 pounds of steam per hour. Cyclone furnaces likewise
are not common, and are not available below 100,000 Ib/hr of steam. Of
the stokers, spreader stokers are most common in the larger units, with
underfeed stokers widely used in the range below 100,000 pounds of steam
per hour. Overfeed stokers are found in both large and small industrial
furnaces, but in relatively small numbers. However, in recent years, the
sales of underfeed stokers have been confined almost exclusively to a
capacity less than 20,000 Ib steam/hr, and overfeed units appear to have
taken over the market. Stokers, then, provide the means of burning most
coal in industrial furnaces; the configuration of at least the lower part
of the boiler must be adapted to the stoker system, in addition to the
size provisions made for the lower firing rate per unit volume.
In considering an interchange of fuels, there are differences
in the auxiliary equipment that must be considered, in addition to the
differences in the gas-fired, oil-fired, and coal-fired boilers them*-
selves.. Table 9 lists this equipment.* First., comparing gaseous firing,
oil firing, and pulverized coal firing, it is immediately noted that the
burners are of different design although they can be designed to handle
any two or all three of the fuels. For cyclone furnaces and stoker
furnaces, it is clear that completely separate systems are needed for coal
as compared to gas and oil. In addition to the changes in burner design,
there are a considerable number of other changes required, with an increasing
complexity of requirements for gas to oil to coal.
*References 9 and 10 contain detailed descriptions of the equipment mentioned.
-------
TABLE 9. AUXILIARY EQUIPMENT NEEDS
Auxiliary
Equipment Gas
Basic storage None
Intermediate None
storage
Ash handling None
Ash disposal None
Soot blowers None
Product gas None
cleanup
Transportation Piping
of fuel
Preparation of None
fuel
Transportation Piping
of prepared
fuel
Burner Gas
Fuel
Oil
Tanks
None
Moderate
facilities
Moderate
facilities
Moderate
facilities
Moderate
facilities
Piping
Heating system
Additive systems
Piping (lagging)
Oil, with steam,
air, or mechani-
cal atomization
Fuel
Coal Comments
Open storage . Ravenswood uses barge
supply to bunkers
Bunkers and hoppers
Large facilities
Large facilities
Large facilities
Large facilities All large size conversion
to coal and some to oil
will require electro-
static precipitators
Conveyor system
Pulverized Coal Cyclone Stoker
Pulverizer Crusher Crusher
^ »•• . ~- „
Dryer Dryer Dryer
Pneumat ic Mechanical Mechanical
transport
P.C. with pneu- Cyclone Grates and
matic transport furnace distribution
system
co
ro
NOTE: Ignition system and flame sensor system may require change.
-------
33
Coal Interchanfteabilitv as Related to Firing Method
Fuel-burning equipment varies widely over the range of steam
generating capacity. In the utility size, say, over 200,000 Ib/hr of steam,
pulverized coal firing predominates. There are two subclasses, dry bottom
and wet bottom (or slag tap). Cyclone furnaces are also used, and even
some spreader-stoker units in sizes up to 400,000 Ib/hr of steam. In the
large capacity end of the industrial size units, from 100,000 to 500,000 lb/
hr of steam, the use of pulverized coal-fired units tends to decrease,
and spreader stokers take an appreciable portion of the market. There
are some cyclones, and a few overfeed stokers. Between 10,000 and
100,000 Ib/hr of steam, spreader stokers predominate. Underfeed stokers
are second in older units, but seem to be disappearing from the market.
Some pulverized coal units are in this capacity range, but overfeed stokers
appear to be taking an increasing percentage of sales. The choice of unit
in any of these capacities is determined at least partly by the type of coal
used;* if the unit is also fired with a refuse or waste product of some
sort, this may be the determining factor in the type of unit used.
In any case, each of the units has certain characteristics that
could limit the interchangeability of fuels that might be suggested as a
means to decrease overall pollution from sulfur oxides, using a limited
supply of fuel. Therefore, each will be discussed in turn after discussing
the characteristics of coal.
Coal Characteristics
Composition of Coal. Because "coal" as a generic term usually
refers to any of the combustible minerals formed from early plant life, there
is a real and significant difference between the various ranks of coal.
*Reference 9 suggested the primary considerations are as follows:
Pulverized-coal firing: grindability, rank, moisture, volatile matter,
and ash.
Stoker firing: rank of coal, volatile matter, ash, and ash-softening
temperature.
Cyclone-Furnace firing: volatile matter, ash, and ash viscosity.
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34
Peat, brown coal, and lignite at one end of the scale, and anthracite and
meta-anthracite at the other demonstrate the obvious variations that
exist in combustibility and physical properties of this solid fuel called
"coal". But there can be equally significant differences (even in the same
rank of coal) that can greatly affect the ability to burn one coal satis-
factorily in equipment designed for another coal. For example, variations
in caking tendency, ash content and composition, reactivity, and heating
value typify the kinds of characteristics that must be considered in
substituting one coal for another.
The drive for low-sulfur oxide pollution has led to an increase
in use of "Western" coals, which are subbituminous coals and lignites, as
a substitute for high-sulfur bituminous coal. However, Western coals
generally differ from Eastern coals in heating value, caking tendency, and
ash characteristics as well as in sulfur content, and it is such variables
as these that must be taken into account when substitutions are being
considered. For instance, because Western coals usually have a much lower
heating value than Eastern coals, stoker ratings may have to be decreased
when burning low-rank Western coals.
Composition of Ash. Coal ash is a heterogeneous substance
composing at least a hundred different minerals such as clays, carbonates,
and sulfides. The complexity is increased because some of these inorganic
materials originally were part of the growing plants that were converted
to coal, and others resulted from sedimentation or from mineral-laden
waters that percolated through the coal bed. Hence, there is a very
great difference between the characteristics of ash from different coals.
At one extreme, some coal ashes high in fluxes such as Fe203, CaO, MgO,
and the alkalies may sinter at temperatures as low as 1500 F and form a
highly fluid melt at 1800 F. Other coal ashes, essentially containing
Si02 and A^Og may not sinter below 2500 F and do not produce a fluid slag
even at furnace temperatures as high as 3000 F.
The fusion characteristics of coal ash have been thoroughly
investigated, and relationships have been developed between chemical
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35
composition and the viscosity of the melt once a coal-ash slag is formed.
This relationship, based on the amount of Si02 in the slag, is widely
used for predicting slag characteristics, but it has only limited usefulness
in estimating the temperature where the mineral matter in the coal can
accumulate on heat-receiving surfaces to interfere with heat transfer or
to plug gas passages.
Storage Characteristics. Stockpiling low-rank coals has posed
many problems in the past because of the high reactivity of most low-rank
coals. At one time, stockpile fires with subbituminous coal and lignite
were regularly expected, particularly if the coal had been dried. Today,
that problem is minimal. It is necessary, however, to compact the stockpile
more densely than is necessary with less-reactive bituminous coal, but
this can be achieved by putting the coal down in thin layers and rolling
intensively. Loss of heating value through oxidation in a stockpile is
worse with Western coals than Eastern coals, but the loss even over
several years of storage is not significant if the coal is handled properly.
Grindability. Grindability is an important property of ooal
intended for pulverized-coal firing but it has no significance for stoker-
fired furnaces. If the Hardgrove grindability of a Western coal is half
that of a bituminous coal, which can be the case, then the output of a
given size pulverizer also would be about halved. More importantly,
probably, will be the moisture content of lignite and some subbituminous
coals which will greatly decrease mill capacity. Thus, for pulverized
coal-fired furnaces, considerable derating of the plant may be necessary
in switching to Western coals.
Slag-Type Furnace (Cyclone and
Some Pulverized Coal)
Differences in slagging characteristics have led to dividing
pulverized-coal-fired boiler furnaces into two main categories: (2) slag-
tap or wet bottom, and (b) dry bottom. In the slag-tap furnace, high heat
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36
release rates are provided and furnace temperatures reach 3000 F or more,
so that the coal ash is deliberately melted and accumulates as a viscous
liquid on the floor or hearth of the furnace from which it drips con-
tinuously. Popular in the 1930's and 1940's, such furnaces are not being
built today. The "cyclone" furnace, where high-velocity, tangentially added
air and crushed coal are burned within a tubular, horizontal furnace
still are being widely used although their popularity has waned over the
past decade. In these furnaces, a layer of molten slag covers the entire
cyclone section area, capturing large particles of coal which burn gradually
while most of the coal burns in suspension. Temperatures reach 3100 F
in cyclone furnaces.
Western coals contain mineral matter leading to ash with a low
fusion temperature. Hence, slagging will be accentuated in pulverized
coal-fired units to the point where a dry-bottom furnace operating satis-
factorily with a bituminous coal may have to be derated appreciably with
many Western coals because of slag formation. Slag-tap furnaces generally
would benefit from this substitution. Good techniques exist for evaluating
slag viscosity, but these methods have not been entirely successful in
predicting the formation of slag deposits that decrease heat transfer to
wall tubes.
Serious metal wastage has been experienced for at least 30
years in central-station boiler furnaces burning bituminous coal through
the formation of liquid films beneath deposits on wall tubes and super-
heaters. The causative agent is Na3Fe(80^)3 or the corresponding potassium
compound; conditions leading to the formation of these objectionable
materials are well understood.
Two conflicting conditions will exist when Western coals are
burned: (1) the sodium level probably will be high and (2) the 803 will
certainly be low. Further, the presence of CaO in the flyash will tend
to prevent formation of these objectionable trisulfates. It is likely,
then, that external corrosion may not be a serious problem with Western
coals unless other factors induced by the high Na20 content turn up to be
significant, as in the formation of alkali pyrosulfates at the lower
temperature conditions existing in industrial furnaces.
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37
Dry-Bottom Pulverized Coal Furnaces
In dry-bottom furnaces, heat-release rates generally are lower
so that furnace temperatures are less than in slag-tap furnaces, and the
heat distribution pattern is adjusted to minimize the formation of ash
deposits on heat-receiving surfaces. This is a difficult task with some
coals. Large numbers of wall blowers and of superheater "soot" blowers
usually are needed to remove deposits as they form, but such cleaning'
systems sometimes are only marginally effective. Thus, fouling of
superheater surfaces is expected to be worse with Western coals than with
most bituminous coals. Both CaO and Na£0 lead to the formation of low-
melting silicates which tend to bind flyash particles into a coherent layer.
Hence, the presence of minerals containing lime and sodium in Western
coals may accentuate fouling problems when these coals are burned. As a
result, dry-bottom furnaces designed, say, for 800-MW may have to be derated
to less than 700 MW if a change is made from Eastern to Western coals, an
expensive solution to the problem of matching coal to the furnace in which
it is burned.
Concerning metal wastage, the same problems hold here as for slag-
tap furnaces.
Spreader Stokers
These stokers depend upon burning a large amount of coal in
suspension, the grate being provided for burning the larger particles
of coal and for removing ash. (About 50 percent of the coal is burned in
suspension.) Coal reactivity affects the rate of burning in suspension,
and hence there may be a minor problem in arriving at a satisfactory size
consist when the more reactive Western coals are fired. Also, clinkering
can be troublesome with s.preader stokers, both with sectional dumping
grates and with traveling grates in the larger sizes, so that ash
characteristics also will be important in coal substitution for these
boilers. In general, no major problems are foreseen in burning low-rank
Western coals in spreader stokers. However, there may be a problem with
auxiliary equipment. A spreader stoker has a maximum heat release rate
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38
of about 106 Btu/ft2 hr based on grate area, with most of the burning taking
place in suspension. This represents a burning rate of about 77 pounds of
13,000 Btu bituminous coal per hour per square foot of grate area. To achieve
the same heat release with subbituminous coal of '9000 Btu heating value,
this firing rate would have to be increased to 112 pounds of coal per hour.
For 6000 Btu lignite, the firing rate would be 167 pounds per hour, indi-
cating a problem with coal-handling facilities in substituting low-rank
coals for bituminous coal. In addition to conveyor and bunker capacity,
this could cause troubles in moving this increased quantity of coal
through stoker feed mechanisms. The alternative, of course, is derating
of the boiler, not a very satisfactory solution in most industrial applica-
tions where steam demand is fixed and surplus capacity usually is not avail-
able. This problem of stoker rating with low-rank coals will require
particular attention.
Similar problems may occur in ash handling capacity as existing
boilers may not have sufficient capacity to handle the increased ash
quantities associated with a high-ash, low-Btu Western coal.
Overfeed Stokers
Because overfeed stokers have a relatively stagnant fuel bed,
they have particular problems burning strongly caking coals. Weakly caking
or free-burning coals perform best on these stokers. Also, since tem-
peratures at the grade level can be very high as the downward-moving plane
of ignition reaches the grate, clinker formation can be troublesome if
ash-fusion temperatures are low. Most Eastern coals have a higher caking
index than Western coals; thus the problem of coke formation would be
expected to be eased with the Western coals. Clinker formation is unpre-
dictable since it depends on the chemical composition of the inorganic
material in the coal. Broadly considered, the high content of CaO and Na20
in some Western coals will lower their ash fusion temperature, thereby
increasing the tendency to form objectionable clinkers that will plug the
grate tuyeres, cause grate-bar overheating, and interfere with air flow
through the fuel bed. Problems related to the use of lower heating value
and to higher ash coals are similar to those considered above for spreader
stokers.
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39
Underfeed Stokers
With mechanical agitation of the fuel bed as the coal is fed
through the retort of an underfeed stoker, coke formation causes few
problems. Hence, underfeed stokers can burn strongly caking coals, one
of the reasons why they are used predominately in industrial furnaces
rated up to 100,000 pounds of steam per hour. Free-burning Western coals
may cause problems in underfeed stokers through loss of fines because of
the high air velocity through the stoker tuyeres. Low-ash-fusion coals
usually are handled satisfactorily by underfeed stokers, but an excessively
fluid clinker can cause problems in plugging of tuyeres. But, in general,
Western coals should cause few problems when substituted for bituminous
coals in underfeed stokers, except as related to the low heating value,
as discussed above.
Specific Example of Conversion
The history of the conversion of 1000 MW Ravenswood Unit 3 to
coal from oil illustrates the problems of conversion/- ' The location of
this unit, originally designed for coal with oil as the standby fuel, had
to be changed, delaying construction. To get the unit'on line in the
desired time, oil was made the primary fuel. While the oil-fired unit
was being erected, the decision was made to convert eventually to coal,
for purposes of economy and fuel source reliability. To reduce costs and
unit down-time, work was performed in three stages, (1) while the oil-
fired unit was being erected, (2) while both furnaces were being operated,
and (3) while one furnace was shut down. The changes involved coal handling
equipment, ash disposal equipment, boiler, high-temperature precipitator,
and forced and induced draft fans. The high-temperature precipitator
was installed to overcome the adverse effects of low sulfur fuel on low-
temperature precipitators. The change in fans resulted from a decision
to change to a balanced draft from forced draft operation.
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40
The point should be emphasized that the original boiler design
was for coal firing, so that no downgrading in performance was necessary
on reconversion. Nevertheless, a considerable amount of additional pro-
visions had to be made to handle coal firing.
Population of Convertible Utility Boilers
A staff report of the Federal Power Commission, based on the
results of a survey covering about 98 percent of the fossil-fuel based
electric generating capacity of the U.S. as of the end of 1972, presents
a realistic picture of the potential for large shifts in the utilities
area from gas firing and from oil firing to coal firing.
The FPC points out that in the period 1965 through 1972, for
reasons of economy and antipollution requirements, about 28,800 megawatts
nameplate capacity was converted from coal to oil. This was estimated as
the equivalent of about 14 x 10 Btu/year, or the equivalent of 55 per-
cent of the residual oil being burned by electric utilities in 1972.
Of this capacity, 79 percent could be reconverted, at a cost of $4.70/
kilowatt (1972). This would be about 44 percent of the total oil-fired
steam-utility capacity. About 52 percent of the capacity can be recon-
verted in three weeks, provided coal of the proper type (similar properties
to that previously fired) can be supplied. It is mentioned that by
eliminating the use of oil in dual-fired oil-coal fired units, an additional
3-1/2 percent of oil could be diverted.
13
It was found that only 2,230 megawatts or 11 x 10 Btu/year was
convertible from gas to coal firing, with about 24 percent reconvertible
within three weeks. On the other hand, burning only coal in dual fuel
13
coal-gas fired units would save 47 x 10 Btu/yr.
The reasons for irreversible changes are not enumerated, but
several can be suggested. Coal storage areas in some instances have been
eliminated and replaced by other construction. In seaboard areas where ash
had been disposed of by dropping at sea, this option for disposing of the
ash has been removed. In the process of conversion away from coal, or
subsequently, soot blowers could have been removed, ducting and piping
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41
changed, and interior change made in the boilers. Pulverizer, coal
crushers and associated ducting could have been removed and replaced by
other construction to increase plant capacity. As a result, a permanent
loss of about 20 percent in reconversion is not unexpected.
Conclusions
From a practical standpoint, the replacement of oil or gas by
coal in firing utility or industrial boilers must be restricted to those
boilers that were either (a) designed for coal and gas and/or oil, or
(b) designed for coal and converted to gas and/or oil. In either case,
the conversion or reconversion can take from a few weeks up to more than
a year, depending on the degree of reconversion necessary and the avail-
ability of equipment. In some instances, while conversion or reconversion
is technically possible, changes in such factors as space availability,
coal availability, or ash disposal means can make conversion impossible.
Replacement of one coal by another also poses problems. Many
of the high-sulfur Eastern coals and the low-sulfur Western coals contain
effective fluxing materials and do not lend themselves to use in the more
common dry-bottom pulverized coal-fired furnaces without derating. Further-
more, the low-sulfur characteristic causes a loss in effectiveness of
the common low-temperature electrostatic precipitators. In stoker-fired
units, loss in capacity with lower Btu fuels and necessity for increase
in crushing capacity appears to be the principal problem that may occur.
In general, the use of a coal other than that for which a steam
generating system was designed will result in a decrease in system capacity.
In some instances, this can be rectified by suitable changes in or additions
to equipment.
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BUSINESS-RELATED CONSTRAINTS TO FUEL SWITCHING
Long-term contracts and direct ownership of fuel resources by
consumers are two major business factors which may tend to inhibit the
switching of "clean" fuels away from large industrial and utility boilers.
The true importance of these factors was difficult to fully ascertain because
of the short time available for research and because -of the proprietary
nature of much of the data. However, on the basis of a preliminary investi-
gation the following generalizations can be made:
• The use of long-term (10 years or more) contracts for the
purchase of coal by the utilities is important and increasing
rapidly. The great bulk of all new contracts for low-sulfur
coal from the West are of this type.
• Based on sample data from 43 utilities*, it is estimated that
coal under contract by utilities is in excess of 4.2 billion
tons. This is a conservative estimate as it is known that many
more utilities have signed long-term contracts but data on the
magnitude of their commitments could not be determined.
• In the case of industrial users of coal, the situation appears
to be quite different. Coal use by industry has been declining
for several decades, and those firms still using coal have
tended to buy coal on a spot basis or on short-term contracts
(of 5 years or less).
• Because of the increasing shortages of natural gas and the
high prices for oil, many industrial concerns are considering
the conversion to coal. It is predicted that industrial cus-
tomers will have to sign long-term contracts in order to obtain
coal in the future.
• Captive coal operations by utilities produced about 32 million
tons of coal in 1973, which was equivalent to 9 percent of the
total coal used by utilities in that year.
* See Appendix A for list of utilities.
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43
• Utility companies own coal reserves in excess of 6.1 billion
tons.
• Non-utility companies, whose primary business is not coal
mining, own considerable quantities of coal reserves. However,
in most cases their current mining operations are not strictly
"captive", but are usually operated as commercial, open market
operations.
• Although spot purchases of oil by utilities are less important
than in the case of coal, the duration of the contracts for oil
tend to be shorter. Only in a few cases, do utilities purchase
oil under contracts of 5 years or more duration.
• Data on oil purchases by industry are very sparse, but it appears
that the industrial contracts are also of short duration.
• In the case of natural gas, long-term contracts are the rule for
both "firm" and "interruptible" gas.
• However, in spite of the long-term contracts for natural gas
deliveries to utilities and industrial consumers are below con-
tracted levels. Regulatory agencies have been curtailing
deliveries to large users in order to reserve gas for residential
customers.
Summary
Long-term contracts do not appear to be a significant barrier to
switching of oil and natural gas. Ownership of oil and gas properties by
industrial customers and utilities is not well defined, but does not appear
to be a significant barrier. However, in the case of coal, utilities have
very large tonnages of coal under very long-term contracts as well as owning
significant reserves of coal. Captive production of coal accounts for less
than 10 percent of current coal needs, but may increase in the future.
Industrial coal purchases are mostly short-term contracts and captive opera-
tions by nonsteel companies are not significant.
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44
Utility. Fuel Purchasing Practices
Coal
Traditionally, coal markets were extremely unstable because of the
low concentration among producers and the ease with which producers could
enter and leave the industry. In the post-World War II period the demand
for coal fell sharply as many markets declined. The large market for coal
in the railroad industry essentially disappeared as dieselization of the
lines was accomplished. The invasion of natural gas into the commercial,
industrial, and retail markets following the extension of pipelines into
markets far removed from the gas fields caused these markets for coal to
decline as well. Only in the electric utilities markets was coal able to
continue to compete and this market now dominates the coal business. Utili-
ties are interested in cheap, reliable energy in large quantities. The coal
industry responded by improving productivity, by utilizing unit trains, and
by increasing the size of their operations. The use of long-term contracts
increased because it was advantageous to both parties, by assuring the coal
companies a market for their coal and by assuring utilities of reliable
fuel supplies. In face of the threat of competition from nuclear energy
and of restrictions on coal use from air pollution regulations, such guaran-
tees were essential to the coal companies in order to justify their investment
in new mines. Although some utilities still preferred to buy on the "spot"
market or to use mostly short-term contracts to keep their options open, an
increasing percentage of the large utilities tended to rely on long-term
contracts for the bulk of the coal supply.
It has been estimated that about 40 percent of the coal procured
by the utilities in 1969 was bought on long-term (10 years or more) contracts*.
In an attempt to obtain more recent data on coal contracts, reports by the
Federal Power Commission on monthly fuel purchases by utilities between April,
1973 and June, 1974 were examined. Table 10 indicates the trends in the
amounts of coal purchased on "contract" and on "spot" bases. From this it
* Gordon, Richard L., Department of Mineral Economics, The Pennsylvania
State University, unpublished manuscript, "Methods of Fuels Purchasing for
Electric Power Generation".
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TABLE 10. TRENDS IN COAL PURCHASES BY UTILITIES BETWEEN APRIL 1973, AND
JUNE 1974, BY TYPE OF PURCHASE, (a)
Month
April, 1973
May
June
July
August
September
October
November
December
January, 1974
February
March
April
May
June
Total
1000 Tons
30,062.9
34,124.8
31,114.3
29,017.2
34,870.1
31,267.1
33,573.0
31,193.8
30,087.9
30,388.1
29,659.8
35.291.2
33,603.9
35,795.3
36,533.8
Contract
1000 Tons
24,526.5
28,251.7
25,598.9
23,372.6
27,928.4
25,062.8
26,696.4
24,658.5
24,262.5
24,109.2
23,447.6
27,196.5
25,957.4
28,128.1
24,076.8
Purchases
Average
Price (b)
38.2
38.5
39.0
38.6
38.6
39.6
40.2
41.7
42.4
44.9
47.6
48.7
51.6
54.1
54.9
Spot Purchases
1000 Tons
5536.4
5873.1
5515.4
5644.5
6941.7
6204.3
6876.6
6535.3
5825.3
6278.9
6212.2
3094.7
7646.5
7667.2
7457.0
Percent
of Total
Purchases
18.4
17.2
17.7
19.5
19.9
19.8
20.5
21.0
19.4
20.7
20.9
27.3
22.8
21.4
23.6
Average
Price (b)
44.3
43.5
44.5
44.5
44.8
45.4
48.2
52.0
58.0
75.8
90.5
100.0
104.5
107.6
114.8
(a) Source: Federal Power Comission, Monthly Reports on Cost and Quality of Fuels for Steam-Electric
Plant, based on FPC Form No. 423.
(b) Cents per million Btu.
*-
m
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46
can be seen that "spot" purchases as a percent of total coal purchases
i
have increased over the period in question, partly in response to the dis-
locations in the market brought about by natural gas shortages and by the
Arab Oil Embargo. However, "contract" purchases still accounted for 73 to
83 percent of the total coal sales during this period. Figure 3 indicates
the importance of "spot" coal purchases by state, based on data for June,
1974. From this figure it can be seen that there is considerable variation
geographically in regard to the importance of "spot" purchases of utility
coal, with the East Coast states being most dependent on this form.
There is a serious deficiency in the FPC data cited above in that
there is no indication as to the duration of the contracts. A 35-year con-.
tract is not distinguished from a 1-year contract and such a distinction is
important to the purposes of this report. Therefore, it was necessary to
examine the FPC data in more detail. The forms upon which the FPC bases its
monthly report are reports from individual utility companies and includes
information regarding contract length. The Weekly Energy Report publishes
these data in a convenient form. Based on a sample of reports for June of
1974, which accounted for 14.6 percent of the total coal purchased in that
month, it was found that 32.5 percent was purchased on spot basis, 4.3
percent was purchased under contracts which expired within 24 months, and
62.7 percent was purchased uner "long-term" (more than 24 months in dura-
tion) contracts.
Next, in an attempt to quantify how much coal is committed under
long-term contracts, the recent prospectuses and registration statements
filed with the Securities and Exchange Commission by 43 utility companies
in various parts of the country we re examined. On the basis of the sample
data included in these reports, it was found that a minimum of 4.24 billion
tons are under such contracts, a large portion of which is for western low-
sulfur coal. Table 11 lists the largest of these commitments made by utilities.
The total cited is only a minimum because even for the sample utilities checked
the data were incomplete. A random sample of recent issues of Coal Age. Coal
News, and the Wall Street Journal turned up an additional 575 million tons
of coal under long-term contract. By 1980, Wyoming alone is expected to be
exporting 50+ million tons per year to utilities in Arkansas, Nebraska, Okla-
homa, Texas, Louisiana, Colorado, Iowa, Missouri, Illinois, Wisconsin Kansas
and Indiana (Coal Age, May, 1974, 97). In addition, almost 34 million tons
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SCALE
tOO 700 300 *00 MILU
=T—'
•DO KILOMtURt
r
75% or more
25-74%
£3 1-25% !
No coal purchases
FIGURE 3. SPOT COAL PURCHASES AS PERCENT OF TOTAL COAL PURCHASES BY UTILITIES, JUNE/ 1974
(Source: FPC)
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48
TABLE 11. LIST OF LARGEST COMMITMENTS OF COAL UNDER
LONG-TERM CONTRACT BY SELECTED UTILITIES
Committed Tonnage
(Million t.)
American Electric Power Company 907 (a)
Arkansas Power and Light Company 100 (b)
Cleveland Electric Illuminating Company 180 4-
Commonwealth Edison Company 311
Detroit Edison Company 450
Northern States Power Company 181
Pacific Power and Light Company 200
Philadelphia Electric Company 230
Puget Sound Power and Light Company 105
The Southern Company 512
Utah Power and Light Company 224
Wisconsin Power and Light Company 109
3509
(a) AEP is in advanced negotiations for an additional 210 million
tons of Western coal.
(b) Option to purchase 50 million tons additional exists in contract.
Source: Prospectuses and registration statements filed with SEC.
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49
of coal will be burned in Wyoming in that year. It can be assumed that
essentially all of this coal will be sold under long-term contracts or is
captive coal of the consuming utility. Therefore, it can be seen that the
utilities have made a significant long-term commitment to coal. In order to
obtain complete data as to total coal committed under long-term contracts
would require a canvass of the coal companies and utilities. Time for such
a canvass was not available.
A second business factor affecting the switching of fuel is vertical
integration into the coal business by means of captive coal mining operations.
Table 12 lists the various capitve coal mines known to be operated by utilities.
From this it can be seen that captive operations mined approximately 32 million
tons of coal in 1973, or equivalent to 9 percent of the total utility coal con-
sumed during that year. Approximately 60 percent of this captive coal was
low-sulfur (i.e., less than 1 percent sulfur).
Table 13 indicates the major coal reserves held by utilities. The
6.2 billion ton figure should be considered to be a minimum as complete data
are not available at this time.
Oil Use By Utilities
With the increase in air pollution regulations and the decreased
availability of natural gas, utilities have increased their use of oil in
recent years. For the year 1971, oil use by the electric utilities amounted
to 407.1 million barrels and accounted for 14.8 percent of the total Btu
used. However, for the 12-month period ending June, 1974, use of oil by the
utilities had increased by 24 percent to 505.1 million barrels and accounted
for 20.6 percent of the total Btu consumed.
Trends in purchases of No. 6 fuel oil (residual) by utilities for
the period April, 1973, through June, 1974, is given in Table 14. Residual
fuel oil accounts for approximately 90 percent of total oil used by the
utilities. Prior to the Arab Oil Embargo, spot purchases of such oil were not
very significant as "contract" purchases accounted for 95 percent or more of
total purchases. However, the bulk of these contracts were short-term as
can be determined by analysis of the reports by individual utilities filed
with the Federal Power Commission. Summarizing the sample data for June, 1974,
in which 7,945,200 barrels of oil were purchased*; of that amount 16.7
percent were "spot" purchases, 48.1 percent were purchased on contracts which
*These Sample data amount to 21 percent of total oil purchased in June 1974.
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50
TABLE 12. CAPTIVE COAL PRODUCTION BY
ELECTRIC UTILITIES, 1973
19/3 Low-sulfur
Tonnage Coal*
American Electric Power Company 6,924,621 1,653,747
Pacific Power and Light Company 6,124,176 6,124,176
Montana-Dakota Utilities Company 2,223,785 312,785
Duquesne Light Company 1,652,725 - -
Duke Power Company 1,150,000 1,150,000
Southern Company 1,118,272 1,118,272
Ohio Edison Company 246,928 - -
Black Hills Power and Light Company 750,000 750,000
Montana Power Company 4,253,681 4,253,681
Utah Power and Light Company 925,000 925,000
Alabama Electric Coop. Inc. 250,179 ?
Pennsylvania Power & Light Company 3,486,639 - -
Texas Electric Service Co. \
Texas Power & Light Company ] (1972 data) 1,790,000 1,790,000
Dallas Power and Light Co. J
Iowa Public Service Company 956.851 956.851
31,852,857 19,034,512
* Less than 1.0 Percent
Sources: Compiled from 1974 Keystone Coal Industry Manual.
1973 Steam-Electric Plant Factors, Coal Age
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51
TABLE 13. COAL RESERVES HELD BY UTILITIES
Reserves Currently
(Million Tons) Producing
Pacific Power and Light Company
American Electric Power Corporation
Montana Power Company
Southern Electric Gen. Company
Duke Power Company
Public Service of NM
Pennsylvania Power & Light Company
Allegheny Power Service Corporation
Cedar Coal Company (a)
Public Service Company of Indiana
Energy Development Company (b)
Alabama Electric Coop. , Inc.
2500
1500
1000
400
250
160
95
90
70
50
42
1
6158
yes
yes
yes
yes
yes
no
yes
yes
yes
no
yes
yes
(a) Owned by American Electric Power Service Corporation
(b) Subsidiary of Iowa Public Service Company
Source; 1974 Keystone Coal Industry Manual, p. 621-622
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TABLE 14. TRENDS IN UTILITY PURCHASES OF NO. 6 (RESIDUAL) FUEL OIL
BETWEEN APRIL 1973, AND JUNE, 1974 (a)
Month
April, 1973
May
June
July
Aug.
Sept.
Oct.
Nov.
Dec.
Jan., 1974
Feb.
Mar.
April
May
June, 1974
Total
No. 6
1000 Bbls
33,372.2
34,965.6
41,669.4
42,018.1
45,343.9
44,310.5
40,448.1
42,057.7
38,442.2
38,690.5
34,342.7
34,471.7
31,177.0
31,947.1
34,949.0
No. 6 as
Percent
Total Oil
93.0
89.9
90.4
38.8
89.6
89.4
90.3
91.2
91.8
90.4
92.1
92.3
92.8
90.0
91.0
Contract
1000 Bbls
32,174.6
33,977.1
36,861.5
40,501.2
43,540.9
42,553.7
38,113.1
39,978.7
36,542.5
35,496.3
31,573.6
32,922.0
29,940.0
29,150.2
32,235.6
Purchases
Average
Price
68.5
68.9
68.7
70.7
74.4
79.0
86.6
102.5
118.5
154.4
182.8
188.1
186.4
188.7
195.3
Spot Purchases
1000 Bbls
1197.6
983.5
815.3
1516.9
1802.9
1756.8
2334.7
2079.1
1399.7
3194.2
2769.1
1549.7
1236.9
2796.9
2713.3
Average
Price
66.4
96.0
75.1
76.8
68.3
72.6
75.8
94.6
127.1
200.7
221.7
185.4
189.2
181.9
190.2
Percent of Total
Purchases
3.6
2.9
2.2
3.7
4.1
4.1
6.1
5.2
5,2
9.0
8.8
4.7
4.1
9.6
7.8
(a) Source: Federal Power Commission, Monthly Reports of Cost and Quality of Fuels for Steam-Electric
Plant, FPC Form No. 423.
(b) Cents per million Btu.
Ui
N3
-------
53
expire within 24 months; and only 34.7 percent were purchased under "long-
term" contracts. Figure 4 indicates the importance of spot oil purchases on
a state by state basis.
The term "long-term" is used in quotes because the bulk of these
contracts are thought to be of 5 years duration or less. This assumption was
confirmed by examination of the reports filed with the Securities and Exchange
Commission by the 43 utilities sample. With only a few exceptions, the
utilities indicated that they purchased most of their oil needs on short-term
contracts or on a spot basis. Among the exceptions were Consolidated Edison
Company of New York, Detroit Edison Company, and Public Service Electric and
Gas Company which indicated that they purchased, at least, part of their
residual oil requirements on long-term contracts. However, the length of
the contracts was not specified.
It appears that the situation is changing and more utilities are
moving in the direction of long-term contracts for oil as a means of assuring
supplies. For example, Middle South Utilities, Inc., the large utility hold-
ing company, has arranged through its fuel purchasing subsidiary, System Fuels,
Inc. (SFI)j for a long-term contract to supply a part of its future oil require-
ments. SFI has contracted with ECOL, Ltd. to purchase 50,000 barrels per
stream-day of low-sulfur No. 6 fuel oil (residual) from a new refinery to
be constructed in Louisiana. The deliveries are to begin in 1977 and to con-
tinue for 20 years for a total commitment of 365 million barrels.
Houston Lighting and Power Co. which previously bought their oil
on a spot purchase basis is now seeking to sign long-term contracts for its
oil supplies. Public Service Company of Colorado signed a 5-1/4 year contract
in October, 1973, with a Wyoming refinery to supply 207 million gallons of
No. 2 fuel oil and 56 million gallons of No. 6 fuel oil over the period.
Southern California Edison Co. has signed an agreement with an oil company to
construct and operate a desulfurization facility near Los Agneles to produce
40 million barrels of low-sulfur fuel oil annually for at least the next 20
years.
In the past, direct involvement in the production of oil and gas
by utilities was not widespread. For the most part utilities preferred to
purchase fuels from other suppliers. However, a number of utilities have
begun to make investment in exploration subsidiaries or to go into joint ven-
tures with other companies which are involved in oil and gas exploration,
development, and production. Examples of such companies are Montana Power
Company, Florida Power and Light Company, Houston Lighting and Power Company,
-------
75% or more
P771 26-74%
1-25%
x - No oil purchases
FIGURE 4. SPOT PURCHASES OF OIL AS PERCENT OF TOTAL PURCHASES BY UTILITIES, .JUNE 1974
*v
(Source: FPC)
-------
55
Oklahoma Gas and Electric Company, Pacific Gas and Electric Company, Public
Service Company of Colorado, Public Service Company of Oklahoma, Southern
California Edison Company, and Texas Power and Light Company.
It appears that neither long-term contracts nor direct investment
in oil reserves represents an important barrier to fuel switching at present.
However, utilities appear to be moving into these two areas and such develop-
ments could become a significant barrier in the future.
Natural Gas
Traditionally, the great majority of natural gas sold to large
utility consumers has been on long-term contracts, usually 20 years or more
in length. The reason for such contracts was that the economics of pipelining
is such that unit costs rise very sharply if a line is not used at near capac-
ity. Therefore, it was in the best interest of the transmission company to
guarantee that the line would be fully utilized. Long-term contracts with
the big customers were a mechanism for assuring this situation.
Natural gas is sold in two main ways either on a "firm" basis or
on an "interruptible" basis. In the latter case, it is understood that during
periods of peak demand that customers with such contracts can be shut off.
However, as the gas shortage has become more severe the length of curtailed
service has increased and in some cases industrial and utility customers on
firm contracts have been curtailed as well.
Table 15 indicates a recent estimate of the extent of natural gas
curtailments in the utility sector between now and 1980. From this it can
be seen that the total use of natural gas as boiler fuel will decline by
5.6 percent, with the only significant growth in such use to occur in the
West South Central Region. Despite the sharp curtailment in gas use in most
areas of the country, it can be seen that to replace the gas expected to be
burned as utility boiler fuel in 1980 with coal would require the equivalent
of 175 million tons, of 'which 140 million tons would be required in the West
South Central Region alone.
-------
TABLE 15. CHANGES IN NATURAL GAS USE BY THE ELECTRIC UTILITIES SECTOR
1972-1980 AND RELATIVE DEPENDENCE ON NATURAL GAS (1972)
Region
New England
Middle Atlantic
East North Central
West North Central
South Atlantic
East South Central
West South Central
Mountain
Pacific
Total United States
1972U)
1980(b)
Million Cubic Feet
8,978
106,020
194,484
404,763
264,416
129,331
1,999,777
251,621
606,198
3,978,673
6,744
127,200
52,012
258,513
167,403
10,272
2,993,628
49,119
90,191
3,754,070
1972-1980 Change
Quantity Percent
-2,234
+21,180
-142,472
-146,250
-97,013
-119,059
+993,851
-202,142
-516,007
-224,603
-24.9
+19.9
-73.3
-36.1
-36.7
-92.1
+49.7
-80.3
-85.1
-5.6
Natural Gas As Coal Equivalent
Percentage of (1980) ,,,.
Fossil Fuels(c) Million tons^ ;
1
4
5
36
9
9
97
38
70
27
0.32
5.96
2.44
12.10
7.84
0.48
140.16
2.30
4.22
175.77
(a) Fanelli, L. I., Natural Gas Production and Consumption: 1972, U.S. Bureau of Mines Mineral Industry
Surveys, Natural Gas, Annual, 1973, 8.
(b) Future Requirements Committee, Future Gas Consumption of the United States. University of Denver
Research Institute, Denver, Colorado, 1973, 44-51.
(c) National Coal Association, Steam-Electric Plant Factors. 1973 Edition, Washington, D. C., January, 1974,
53-54.
(d) Assuming 1030 Btu/ft* and 22 million Btu/ton for coal.
Ln
-------
57
Based on the sample* fuel purchase data for June, 1974 referred
to previously, it was found that only 2.2 percent of the gas purchased by
utilities was under contracts which were due to expire within 24 months.
Therefore, it is obvious that the great bulk of gas is sold under long-term
contracts. However, the extent to which these contracts represent a barrier
to fuel switching will depend upon whether such contracts can be honored
by the pipeline companies and whether the Federal Power Commission and various
state regulatory agencies will permit the contracted gas to be burned as
boiler fuel. All evidence to date is that gas use by utilities will be phased
out before all the contracts expire. Therefore, it is likely that the question
of misplaced gas by the utilities probably will resolve itself within the
decade.
Industrial Fuel Purchasing Practices
Coal
The use of coal for industrial purposes has been declining since
the end of World War II under the impact of competition from oil, natural
gas, and electricity. Preliminary data for 1973 indicate that industry used
t. <
24,028 trillion Btu's of energy, or 38.6 percent of the net energy used during
that year. This energy was supplied by the following energy sources: coal—
19 percent, natural gas—45 percent, oil products—25 percent, and electricity—
11 percent. Industry used 156.0 million tons of coal of which 87.3 million
tons were used for coke manufacture.
Industrial use of natural gas amounted to 10.5 trillion cubic feet
of gas or 46 percent of the total gas used in 1973. The great bulk of this
gas was used for fuel and power, withi.the remainder (6.6 percent) being used
as raw material. Much of this gas use was "misplaced" in the sense that it
was "clean" fuel being used where alternative fuels could be used. If only
half of this gas was replaced by coal, it would increase the industrial use
of coal by 230 million tons.
*Satnple represented 17 percent of total gas purchased by utilities in June, 1974.
-------
58
Industrial use of oil products for fuel and power in 1973 amounted
to 595.5 million barrels plus an additional 466.7 million barrels of products
for use as raw material to industrial processes. Although precise data on
the sulfur content of all oil products are not known, data from the USBM in-
dicate that approximately half of the total residual oil is high in sulfur
(1 percent sulfur or more). Industrial use of residual oil in 1973 amounted
to 190.6 million barrels. If we assume that half of this oil was low-sulfur
and therefore, misplaced, and should be replaced with coal, then it would
increase the industrial demand for coal by an additional 27 million tons.
Although precise data on coal contracts in the industrial market
could not be found, it was determined after discussion with a coal marketing
man with one of the major coal companies that most industrial coal is sold
on spot basis or short-term contracts. A 5-year contract is a long industrial
contract. It was further learned that most coal companies are tailoring the
output of their new mines to the utility markets. In light of this it is
likely that if industrial consumers wish to increase their use of coal in the
future to make up the deficits caused by declining availability of natural
gas they will have to sign long-term contracts similar to those in use in
the utility market.
Direct investment in the coal business by noncoal companies has
increased sharply in recent years. However, with the exception of the steel
companies, these operations are not strictly "captive" in the sense of the
company owning the coal and producing it for their own internal use. The
Keystone Coal Industry Manual indicated that captive coal operations by
"other industries" (excluding steel and public utilities) in 1973 amounted
to 7.3 million tons. However, much of this coal is not strictly "industrial"
fuel, but instead is used for coke manufacture or chemical by-products.
Alabama By-Products Corporation is a merchant coke producer; Semet-Solvay
Division of Allied Chemical Company uses much of their output to produce coke
rather than as steam coal; International Harvester Company's operation is in
reality a captive coking coal operation for their Wisconsin Steel Division.
Medusa Cement Company operates a small coal operation in Pennsylvania which
appears to be "captive" to their Wampum Plant, but is not included in the
above list.
-------
59
However, it should be pointed out that there are a number of large
industrial organizations which have investments in the coal business which
could potentially become "captive" sources. Some of the larger of these
firms include
Pullman, Inc.
Alco Standard Company
W. R. Grace and Company
Gulf Resources and Chemical Company
General Dynamics Corporation
Mead Corporation
American Smelting and Refining Company
Ideal Basic Industries.
If any or some of the firms find that gas or oil supplies for their industrial
operations become tight, it would be possible for them to convert to coal and
have an assured supply from their own subsidiaries. However, at present
capitve coal use in the industrial sector is not significant.
Oil
No definite data on oil contracts used by industrial concerns could
be secured, but it appears that they probably also use short-term contracts
and spot purchases to meet their needs. Direct investment in captive oil and
gas operations by industrial companies is not thought to be significant.
Therefore, it does not appear that there are any significant business barriers
to fuel switching in the case of oil. Environmental considerations and tech-
nical constraints affecting product control and plant operations are likely
to be much more significant.
Natural Gas
t
Long-term contracts are the normal manner in which industrial con-
sumers purchase natural gas. Most large industrial consumers have contracts
for natural gas which extend well into the future. However, the mere existence
of these contracts does not necessarily mean that they will be a significant
barrier to fuel switching. In normal times, such contracts would be honored.
-------
However, since natural gas is in short supply, end-use controls have been
instituted by the Federal Power Commission and various state agencies. Under
these schemes, customers are ranked according to the amount of gas they use,
what they use gas for, and their ability to use alternative fuels. As a
result, large industrial consumers who are equipped to use alternative fuels
are likely to find themselves cut off from gas supplies despite having long-
term contracts with the distribution companies.
According to the Federal Power Commission, industrial use of natural
gas will grow at only 0.7 percent annually between 1971 and 1990 in contrast
with the 4.9 percent annual rate between 1962 and 1971. As a result, natural
gas's share of the total industrial market will decline from 47 percent in
1971 to only 35 percent in 1990. This would mean that 11.6 trillion cubic
feet of gas would still be used by industry in 1990; this would be equivalent
to 500-550 million tons of coal.
It is possible that various industrial consumers of gas will attempt
to secure supplies by investing directly in gas producing companies so as
to obtain a captive source of supply for their plants. However, there is a
question whether they would be allowed to use such gas, if under end-use con-
trols they do not quality as a priority user. Both Ford and General Motors
have successfully drilled gas wells in Ohio, but General Motors is still
waiting for permission from the State of Ohio to use this gas for their
facilities. It is possible that they will be denied use of this gas in times
of shortage and will be obliged to let residential consumers have it.
It appears that the feasibility of switching fuels in the case of
natural gas will be more dependent on government policy than on the existence
of long-term contracts or captive ownership of gas supplies.
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61
FUEL TRANSPORTATION CONSTRAINTS TO FUEL SWITCHING
Consideration of possible fuel transport limitations to fuel
switching must begin with the regional location of the misplaced fuels.
The largest blocks, as summarized on Page 13, are found to be in the
South Central, South Atlantic, Pacific, Mountain, and North Atlantic
regions. Much of this misplaced fuel is natural gas being burned in util-
ity or industrial boilers. Thus, the basic transportation requirement to
accomodate fuel switching will be shipment of high-sulfur coal to replace
natural gas. To identify the magnitude of the coal transportation pro-
blem, the amount of coal required to replace natural gas in large boilers
may be compared with current coal shipments. The fuel use of the largest
blocks of clean fuel in large sources, which are summarized on Page 13,
were combined by region and tabulated in Table 16. The quantity of high-
sulfur coal equivalent to the clean fuel was calculated for each region.
The actual coal shipments received in each region during 1972 are given
in Table 16 for comparison. If all of the clean fuel in these sources
were to be replaced by high-sulfur coal, substantial increases in coal
transport would be required in the South Central, Pacific, and Mountain
regions. Much more modest increases would be required in the other regions.
The Federal Energy Administration projects substantial in-
creases in coal flows by 1985 . Rail transport of coal was projected
to increase by more than 200 percent, while water movements were projected
to increase about 60 percent. FEA concludes that the rail and water trans-
port systems would face problems but that they would be able to accomodate
such increases. The ability of the coal transport systems to expand to
meet increased requirements depends primarily on the existence of a con-
tinuing demand for the service. Where an established need exists, the
transport systems have expanded to provide the service. In view of the
fact that equipment constraints will prevent switching of a portion of
the natural gas, the transportation network should be able to accomodate
the altered fuel distribution called for by the fuel switching which is
achievable.
-------
TABLE 16. COAL EQUIVALENT OF MISPLACED CLEAN FUELS IN LARGE SOURCES
Region
South Central
Pacific
Mountain
N. Atlantic
S. Atlantic
W. N. Central
E. N. Central
Misplaced Clean Fuel
Fuel lO^Etu/Year
N.
N.
N.
L
N.
N.
N.
Gas
Gas /Res id
Gas/L. S Coal
S Coal/Resid
Gas/L S Coal
Gas
Gas
2508
749
744
750
973
286
318
, Coal Equivalent
106 Ton/Year
103
31
31
31
40
12
13
Actual 1972
Shipments Received
85
4.6
26
79
97
40
206
Ni
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63
IDENTIFICATION OF BLOCKS OF FUELS
SUITABLE FOR SWITCHING
A summary of the data from Table 7 shows the following quan-
tities of misplaced fuels, in 10 Btu/year:
Fuel Large Sources Small Sources
Misplaced Coal 1,804 2323
Misplaced Oil 2,978 3479
Misplaced Natural Gas 10,457
Totals 15,239 5802
The constraints which limit exchange of these fuels, as discussed in the
preceding sections would have to be evaluated on a source-by-source basis
in order to arrive at a completely valid conclusion regarding the quanti-
ties of fuel which are, in fact, free to be switched. However, useful
conclusions may be drawn based on the generalized limitations which may
be summarized as follows:
• Gas- or oil-fired boilers cannot be switched to coal unless
they were originally designed for dual fuel or designed for
coal and subsequently converted.
• Coal-fired boilers which were converted to oil may not
be reconvertible.
• One coal can be exchanged for another coal if proper care
is taken to ensure that the properties of the new coal are
compatible with the furnace and boiler design. Derating
of the boiler is often required.
• Approximately 75 percent of utility purchases of coal are on
a long-term contract basis.
• Industrial coal is purchased mainly oti a spot basis.
• Captive production of coal is less than 10 percent of
the total coal production.
• Long-term contracts for oil and gas do not appear to be
a barrier to switching.
• Transportation constraints appear to be less restrictive
than equipment and business factors.
-------
Coal in Large Sources
Low-sulfur coal in large sources can be replaced by high-
sulfur coal or high-sulfur residual oil. Equipment limitations can be
overcome in this case. Business constraints in the form of long term
contracts will be more limiting. Assuming that such contracts are about
uniformly distributed with respect to low- and high-sulfur coal, 25 per-
12
cent of this block, or 450 x 10 Btu/year, would be expected to be pur-
chased on a spot basis and, therefore, free for switching.
Coal in Small Sources
High-sulfur coal in small sources can be replaced by low-
sulfur coal, by low-sulfur residual oil, by distillate oil, or by nat-
ural gas. Again, equipment constraints can be overcome and the primary
limitation is that of long-term contracts. Assuming the 25 percent of
the utility coal, and all of the industrial and commercial coal is free
12
from this restraint, about 2000 x 10 Btu/year would be available for
switching.
Oil in Large Sources
Low-sulfur oil can be replaced with high-sulfur oil, or by
high-sulfur coal, if the boiler were originally designed for coal. Boilers
12
which can be converted to coal represent about 1200 x 10 Btu/year. The
remainder could be switched to high-sulfur residual oil, thus the entire
12
block, about 3000 x 10 Btu/year, is essentially available for switching.
The limitation would be the availability of the replacement fuel.
Oil in Small Sources
High-sulfur oil in small sources can be replaced by low-sulfur
residual oil, by distillate oil, or by natural gas. Equipment constraints
can be overcome. Little of the high-sulfur oil is expected to be under
-------
65
long-term contract, thus essentially all of this block, or about
12
3500 x 10 Btu/year, is available for switching.
Natural Gas in Large Sources
Natural gas cannot be replaced by coal unless the boiler were
12
originally designed for coal. Only about 600 x 10 Btu/year of the
natural gas-fired boiler capacity could be fired with high-sulfur coal.
The only other replacement fuel for this large block is high-sulfur
residual oil. This change can be accomodated with respect to equipment
factors. The primary limitation would be the availability of the re-
placement fuel.
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66
REFERENCES
(1) DeCarlo, J. A., Sheridan, E. T., and Murphy, Z. E., "Sulfur Content
of United States Coal", Information Circular 8312, U.S. Department
of the Interior, Bureau of Mines (1966).
(2) Walker, F. E., and Hartner, F.E., "Forms of Sulfur in U.S. Coals",
Information Circular 8301, U.S. Department of the Interior, Bureau
of Mines (1966).
(3) "Monthly Report of Cost and Quality of Fuels for Steam-Electric
Plant", (FPC Form No. 423 data) Federal Power Commission.
(4) "Steam-Electric Plant Factors/1973 Edition", National Coal
Association
(5) "Minerals Yearbook 1972, Vol. I, Metals, Minerals, and Fuels",
Prepared by the Bureau of Mines, U.S. Government Printing Office,
Washington, D.C. (1974).
(6) "Project Independence Report", Federal Energy Administration
(November 1974).
(7) "U.S. Energy Outlook", National Petroleum Council.
(8) "United States Energy Through the Year 2000", Dupree, W. G. Jr.,
and West, J. A., U. S. Department of the Interior, December 1972
(9) deLorenzi, 0., "Combustion Engineering, A Reference on Fuel Burning
and Steam Generation", Combustion Engineering (1957).
(10) "Steam, Its Generation and Use", Babcock and Wilcox (1972).
(11) Carey, J. P., Ramsdell, R. G., Jr., and White, W. B., "Ravenswood
Conversion to Coal", American Power Conference (April 1967).
(12) A Staff Report on the Potential for Conversion of Oil-Fired and
Gas-Fired Electric Generating Units to Use of Coal, prepared by
the Bureau of Power, Federal Power Commission (September 1973).
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67
APPENDIX A
XIST OF ELECTRIC UTILITIES WHOSE PROSPECTUSES AND REGISTRATION
STATEMENTS WERE EXAMINED TO OBTAIN INFORMATION ON
FUEL CONTRACTS AND PURCHASING PROCEDURES
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68
APPENDIX A
LIST OF ELECTRIC UTILITIES WHOSE PROSPECTUSES AND REGISTRATION
STATEMENTS* WERE EXAMINED TO OBTAIN INFORMATION ON
FUEL CONTRACTS AND PURCHASING PROCEDURES
American Electric Power Company, Inc.
Arizona Public Service Company
Arkansas Power and Light Company
Baltimore Gas and Electric Company
The Cleveland Electric Illuminating Company
Commonwealth Edison Company
The Connecticut Light and Power Company
Consolidated Edison Company of New York, Inc.
Consumers Power Company
The Detroit Edison Company
Duquesne Light Company
Duke Power Company
Florida Power Corporation
Florida Power and Light Company
Houston Lighting and Power Company
Iowa Electric Light and Power Company
Iowa Power and Light Company
Louisiana Power and Light Company
The Montana Power Company
Nevada Power Company
New England Power Company
New Orleans Public Service, Inc.
Northern States Power Company
Oklahoma Gas and Electric Company
Pacific Gas and Electric Company
Pacific Power and Light Company
Pennsylvania Electric Company
Philadelphia Electric Company
Portland General Electric Company
Potomac Electric Power Company
Public Service Company of Colorado
Public Service Company of Indiana, Inc.
Public Service Company of New Mexico
Public Service Company of Oklahoma
Public Service Electric and Gas Company (New Jersey)
Puget Sound Power and Light Company
Southern California Edison Company
The Southern Company
Texas Power and Light Company
Union Electric Company
Utah Power and Light Company
Virginia Electric and Power Company
Wisconsin Power and Light Company
*As filed with Securities and Exchange Commission
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69
APPENDIX B
LIST OF FIRMS AND AGENCIES CONTACTED DURING COURSE OF RESEARCH
-------
70
APPENDIX B
LIST OF FIRMS AND AGENCIES CONTACTED DURING COURSE OF RESEARCH
National Coal Association
Federal Energy Administration
Federal Power Commission
Securities and Exchange Commission
New York State Public Utilities Commission
Amax Coal Company
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71
TECHNICAL REPORT DATA
(Please read Iiistivctions on the reverse before completing)
1. REPORT NO.
EPA-600/2-76-076
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Assessment of the Degree of Flexibility in Fuel
Distribution Patterns
5. REPORT DATE
March 1976
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S) ~~~~~~ '~
E.H. Hall, A. A. Putnam, and R. L. Major
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Battelle-Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
10. PROGRAM ELEMENT NO.
1AB013; RQAP 21ADD-036
11. CONTRACT/GRANT NO.
68-02-1323, Task 11
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; 4-8/74
14. SPONSORING AGENCY CODE
EPA-ORD
15. SUPPLEMENTARY NOTES Pr0ject officer for this report
Ext 2825.
D B.Henschel, Mail Drop 61,
16. ABSTRACT
repOr£ gives results of a study to evaluate the potential of fuel switching
as an element of an overall strategy for the control of sulfur oxide emissions from
stationary sources. Blocks of misplaced fuels (i.e. , clean fuels now burned in large
sources and dirty fuels now burned in small sources) were identified. Various poten-
tial constraints to switching the misplaced fuels were evaluated. These included:
equipment constraints, business constraints, and fuel transportation constraints.
From these evaluations , the quantities of misplaced fuels were identified which are
not limited by any of the constraints , and therefore which can be considered suitable
for switching.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COS AT I Field/Group
Air Pollution
Fuels
Distribution
Fuel Consumption
Sulfur Oxides
Substitutes
Assessments
Air Pollution Control
Stationary Sources
Fuel Switching
Distribution Flexibility
13B
21D
14A
07B
13. DISTRIBUTION STATEMENT
19. SECURITY CLASS (ThisReport)
Unclassified
.NO. OF PAGES
77
Unlimited
20. SECURITY CLASS (Thispage}
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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