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

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                RESEARCH REPORTING SERIES

 Research reports of the Office of Research and Development, U.S. Environmental
 Protection Agency,  have been grouped  into 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

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                                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

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                            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

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                            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

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                             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

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                             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

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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

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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.

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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.

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          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.

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              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,

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  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)

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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.

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                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

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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













































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                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

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                 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

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                        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

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                                14
               TABLE 6.  ACTUAL FUEL USE IN 1972 BY
                         CONSUMING SECTOR
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                                   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

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                                   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

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                                   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

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                                  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

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              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.

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                                   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:

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                                  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).

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                                   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.

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                                    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

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                          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

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                               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)

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                                    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.

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                                               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.

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                                  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

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                                    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,

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                                                                                               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)

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                                    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.

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                      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

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                                    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.

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                                    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.

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                                    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.

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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.

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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.

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 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

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                                   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

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                            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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