xvEPA
United States Industrial Environmental Research EPA-600/7-80-105
Environmental Protection Laboratory May 1980
Agency Research Triangle Park NC 27711
Cost Benefits Associated
with the Use of Physically
Cleaned Coal
Interagency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
-------
EPA-600/7-80-105
May 1980
Cost Benefits
Associated with the
Use of Physically
Cleaned Coal
G A (Macs. R A Ress1
and P VY Spaite (Consultant
PEDCo Environmental In;
PO Bo* 20337
Dallas, Tenas 75220
Conuaci No 68-02-2603
Task No 31
Prooram Element No EHE623A
EPA Project Ofdcer James D Kilgroe
Indusmai Environmental Research Laboratory
ice o< Environmental Engineering and Technology
Research Triangle Park NC 27711
Prepared lor
U S ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington. DC 20460
-------
1i
-------
ABSTRACT
This report identifies and quantifies several benefits associated with
the use of physically cleaned coal in the operation of utility electric power
plants. These benefits occur in three general areas: coal and ash handling,
boiler operation, and gas handling and cleaning. The cleaning process removes
sulfur from the coal and thus reduces the emission of sulfur dioxide into the
atmosphere. In most cases, however, the power plant must install supplemental
control equipment to reduce emissions enough for compliance with environmental
regulations. The cost of this supplemental equipment is less than the cost of
a control system for use with uncleaned coal, but the cost decrement is usual-
ly insufficient to offset coal cleaning costs. However, the total of all of
the benefits addressed in this report exceeds the cost of cleaning the coal.
In a typical case the cost of coal cleaning is $4.85 per ton of cleaned coal,
whereas the total benefits associated with the cleaning of the coal are
$7.20 per ton of cleaned coal. This report recommends additional projects
aimed at quantifying coal cleaning benefits and presents an annotated biblio-
graphy of related studies.
-------
CONTENTS
Page
Figures vi
Tables vii
Abbreviations viii
Acknowledgements ix
Conversion Table x
1. Introduction 1
2. Summary 3
3. Applicability Of Physical Coal Cleaning To U.S. Coals 7
Process description 7
Washability of U.S. coals 8
Cost of physical coal cleaning 9
4. Economic Benefits 18
Cost savings in coal and ash handling 19
Coal transportation 19
Coal handling and storage 21
Pulverizers 22
Ash collection and handling 24
Ash disposal 25
Cost savings in boiler operation 25
Operating and maintenance cost reductions 26
Boiler availability 32
Boiler efficiency 39
Boiler capacity 42
Boiler design 43
Cost savings in exhaust gas handling and cleaning equipment 43
Collection efficiency of pollution control equipment 43
FGD requirements 45
5. Conclusions and Recommendations For Further Work 49
Conclusions 49
Recommendations for further work 50
Calculation of benefits based on published data 50
Coal appraisal research 50
Research to verify effects of coal quality on boiler
operation 51
Boiler derating study 51
iv
-------
CONTENTS (continued)
References
Appendices
Appendix A
B
C
D
E
Literature review
Cost estimates For FGD and PCC
Calculation of revenue requirements to capitalize
additional boiler capacity
Regression study - TVA forced outages
Calculations of boiler efficiency improvement as a
result of PCC
•
Sample calculations on ESP performance for raw and
washed coal
Page
52
54
77
97
99
110
113
-------
FIGURES
Number Page
1 Energy Available in Northern Appalachian Reserve Base as a
Function of Various Physical Coal Cleaning Levels and
Emission Standards 8
2 Annual Incremental Cost of Operating a PCC/FGD System at a
500-MW Plant Under Various S0? Regulations; Sulfur Content
of Raw Coal = 2.5 Percent 14
3 Annual Incremental Cost of Operating a PCC/FGD System at a
500-MW Plant Under Various S0? Regulations; Sulfur Content
of Raw Coal =3.5 Percent 15
4 Annual Incremental Cost of Operating a PCC/FGD System at a
500-MW Plant Under Various S02 Regulations; Sulfur Content
of Raw Coal =5.0 Percent 16
5 Relationships of Fuel-Related Boiler Maintenance Costs to
Tons of Ash-Plus-Sulfur Fired into the Boiler 33
6 Annual Forced Outage Rates as a Function of Coal Ash Content 35
7 Yearly Operating Availability for Fossil Coal-Fired Units 400 MW
and Above 37
8 Effect of PCC Sulfur Removal Efficiency on Allowable FGD Bypass
at Various SOp Removal Regulations 47
vi
-------
TABLES
Number Page
1 Summary of Coal Cleaning Benefits for Existing Boilers 4
2 Costs of Physical Coal Cleaning System at Level 2 Plants of
Various Capacities 9
3 Coal Preparation and Performance Factors 11
4 Total Annual Costs for Eight Coal Preparation Plants 12
5 Weight Yields of Washed Coal at 90 Percent Btu Recovery 20
6 Itemized TVA Boiler Maintenance Costs, John Sevier Plant 27
7 Itemized TVA Boiler Maintenance Costs, Kingston Plant 28
8 Total Boiler Maintenance Costs and Fuel-Related Boiler Main-
tenance Costs for Selected TVA Plants 29
9 Cost Breakdown for Selected Coal-Fired Electric Generating
Plants with Average Boiler Size Of 200 MW or Larger 30
10 Component and Composite Forced Outage Rates and Availability for
Fossil-Fuel-Units: 1967-1976 36
11 Typical Boiler Efficiency Losses 40
12 Efficiency for Raw and Cleaned Coal 41
13 Comparison of ESP Requirements for Boilers Burning Raw and
Cleaned Coal 44
14 FGD Costs for Raw and Cleaned Coal Systems 46
-------
ABBREVIATIONS
A+S The Sum Of The Ash and Sulfur Percentages In A Coal
EPA U.S. Environmental Protection Agency
EPRI Electric Power Research Institute
ESP Electrostatic Precipitator
FGD Flue Gas Desulfurization
O&M Operation and Maintenance
PCC Physical Coal Cleaning
SCA Specific Collection Area
TVA Tennessee Valley Authority
vm
-------
ACKNOWLEDGMENTS
This report was prepared for the Industrial Environmental Research Labor-
atory of the U.S. Environmental Protection Agency by PEDCo Environmental,
Inc., Cincinnati, Ohio. The Project Director was Mr. Timothy W. Devitt.
Principal authors were Dr. Gerald A. Isaacs, Project Manager, Mr. Paul
W. Spaite, and Mr. Robert A. Ressl.
This report utilizes several reports that have been prepared under funds
through the EPA-Interagency Coal Cleaning Program. In addition, generous
quantities of data have been provided by the staff of the Tennessee Valley
Authority, and the authors express appreciation for the cooperation shown by
that agency.
The authors also wish to acknowledge the cooperation and assistance of
Mr. James D. Kilgroe, Project Officer for the U.S. Environmental Protection
Agency, in preparation of this report. Dr. Constancio F. Miranda also as-
sisted in review of this report for the U.S. Environmental Protection Agency.
IX
-------
CONVERSION TABLE
English units are used extensively in this report. Equivalent Systeme
International d1 Units (S.I.) are as follows:
meter (m) = 3.281 feet
kilogram (kg) = 2.205 pounds
joule (J) = 9.47 x 10~4 Btu
-------
SECTION 1
INTRODUCTION
Physical coal cleaning is a well-developed technology that has been
used for many years. Relatively simple systems are used to remove ash from
coal burned for power generation, and more complex systems have been
developed to remove ash and sulfur from coking coals.
Since the mid-1960's the U.S. Environmental Protection Agency (EPA) has
supported work to demonstrate the usefulness of PCC in reducing air pollu-
tion caused by combustion of coal. Special attention was given to possi-
bilities for cor;tj"
-------
This report is concerned with the latter two options, i.e., with cases
where coal quality is inadequate for compliance with S02 regulations, so
that a full or partial FGD system is required.
A principal preliminary effort of this project was the review of
pertinent literature, as detailed in Appendix A. It was anticipated that
information from the open literature and accessible expert opinion might be
scarce and that good data would be lacking in several areas. Where this
problem was encountered, the report presents the available pertinent data
with comment on data quality.
The investigation has shown that the relationship between coal quality
and boiler performance is poorly defined, despite a considerable amount of
available information; hence some of the impacts associated with changes in
coal that occur as a result of PCC cannot be assessed in terms of impacts on
boiler operation alone. Some changes in boiler performance that result from
PCC must be assessed in the light of total impact on the generating system.
These considerations have led to some new perspectives and to better defini-
tion of the need for additional information.
Many of the benefits to be discussed are subtle and may lead to rela-
tively small charges in overall performance. These small changes may still
be significant, however, and they may help to justify the use of PCC in
specific situations. We attempted, therefore, to recognize all possible
savings and to estimate their relative importance, and at the same time to
avoid any double-counting of benefits. Further studies will be needed for a
more accurate determination of many of these potential cost benefits.
The impact of PCC on coal to be burned in either new or existing
boilers was assessed on the basis of available information. Quantitative
comparisons were seldom possible. Where data were available, the analyses
were complicated by the different approaches to cost estimation in various
studies. We did not attempt to judge the merits of differing approaches or
to normalize the data but rather to determine where future efforts can be
applied most fruitfully.
Section 3 describes and categorizes various coal cleaning processes and
briefly discusses the U.S. coals in terms of relative washability. Section
3 also indicates typical costs of coal cleaning plants to provide perspec-
tive for the subsequent discussion of PCC benefits. In Section 4 the
various PCC benefits to the utility industry are discussed in terms of three
functional areas: coal and ash handling, boiler operations, and gas
cleaning. Each potential benefit for a typical boiler operation is
estimated on the basis of assumed coal properties and washability data for a
selected "standard" coal. For each benefit, a range of values is also
estimated. Section 5 outlines additional projects that are recommended for
more precise definition of the cost benefits associated with PCC.
-------
SECTION 2
SUMMARY
Physical coal cleaning (PCC) is an available technology that can be
used now to improve fuel quality and to minimize the environmental conse-
quences associated with the burning of coal. Unfortunately, institutional
barriers and a lack of appreciation of all of the benefits associated with
the application of coal cleaning have retarded adoption of the technology
for use in pollution control.
This study is one of the first efforts to identify fully and to quan-
tify the benefits associated with the use of cleaned coal. These benefits
are discussed, with quantitative estimates of cost benefits that may be
derived from coal cleaning. A hypothetical, standard coal that is
moderately washable was used as a basis for our estimates, i.e. , a coal
whose ash content could be reduced from 20 percent to 10 percent and whose
sulfur content could be reduced from _3,5. percent, t& 2.4 percent. The
magnitude of potential savings is heavily dependent on the amounts of ash
and sulfur that can be removed; we have attempted to make conservative
estimates in this regard. It should be noted, however, that reliable data
relative to some of the benefit values are sparse or unavailable, particu-
larly data that would support estimates of the range of benefits; hence some
of the indicated benefit values were determined subjectively. Nevertheless,
we attempted in all cases to obtain the best information available and to
make realistic judgments.
Several significant benefits have been identified for each of three
distinct operations:
0 Coal and ash handling
0 Boiler operation
0 Gas cleaning
Table 1 shows results of our benefit analysis in terms of estimated
savings that would be realized in each of the principal areas by burning
physically cleaned coal in an existing power plant. The greatest potential
benefit is related to gas cleaning. Coal cleaning might also affect parti-
culate control requirements, but essentially all savings in gas cleaning
operations are attributed to a permissible reduction in flue gas desulfuri-
zation (FGD) requirements as a result of using cleaned coal. In extreme
cases where coal cleanability is adequate to eliminate the need for flue gas
-------
desulfurization altogether, this single benefit may range up to about $11.00
per ton of cleaned coal. Typically, the gas cleaning benefits would be
about $4.00 per ton of cleaned coal, where coal cleaning reduces FGD
requirements but does not completely eliminate the need for a scrubber.
TABLE 1. SUMMARY OF PCC BENEFITS FOR EXISTING BOILERS
Benefit area
Coal and ash handling
Coal transportation
Coal handling and storage
Pulverizers
Ash collection and handling
Ash disposal
Boiler operation
Operating and maintenance
Availability
Efficiency
Capac-ty
Gas cleaning
Particulate control
FGD systems
Total
(Dollars per ton of cleaned coal)
Typical Range
0.70
a
0.00
a
0.10
0.40
1.90
0.10
0.00
a
4.00
7.20
0.10 - 1.50
b
0.00 - 4.50
b
0.00 - 0.25
0.10 - 2.00
0.30 - 5.10
0.05 - 0.25
0.00 - 9.00
a
0.00 - 11.00
alnsignificant for existing plants.
Not determined.
The next most important category of benefits is related to boiler
operation. Typical benefits, in order of decreasing significance, are
boiler availability improvement, a reduction of operating and maintenance
requirements, improved efficiency, and increased capacity. Savings associ-
ated with any increase in boiler capacity and in boiler availability can be
very large. Where boilers have been derated because of ash slagging and
fouling or where availability is poor because of low quality coal, the
estimated savings can be as high as $9.00 per ton of cleaned coal. These
savings are calculated on the assumption that half of the power that cannot
be generated because of boiler unavailability must be replaced, an assump-
tion suggested by a major utility. For the capacity savings estimate it is
assumed that an investment in replacement capacity would be necessary.
Although these benefits can be great, they would be realized only at sites
with abnormal operating conditions that have resulted in derating of
existing generating units.
Coal and ash handling benefits as a
erally small in magnitude. They include:
result of coal cleaning are gen-
-------
0 Reductions in coal transportation costs as a result of the
increased thermal content per ton of coal.
0 Reductions in coal handling and storage costs.
0 Reductions in pulverization costs because of the removal of
hard abrasive impurities from the coal.
0 Reductions in ash collection and handling costs.
0 Reduction in ash disposal facility requirements.
Although the main thrust of this investigation deals with existing
plants, possible savings in design of a new plant to burn cleaned coal
rather than raw coal are discussed for each benefit category. Such benefits
would be substantial, possibly exceeding those that could be realized in
existing plants. Total benefits shown in Column 1 of Table 1 typically
amount to more than $7.00 per ton of cleaned coal. This benefit compares
favorably with the cost of coal cleaning. For example, one study of eight
coal cleaning plants has shown an average coal cleaning cost of $5.73 per
ton and a range from $4.40 to $8.41 per ton of cleaned coal.
We have analyzed several situations where coal cleaning is used as a
supplement to FGD in order to determine the economic effect on the capital
and operating costs of the FGD system. The analytical matrix consists of
three typical regulatory levels, coals with three different sulfur levels,
and three assumed levels of coal cleanability. Our estimated cost of coal
cleaning ranges from $5.95 to $7.39 per ton of cleaned coal, including the
cost of coal rejected in the cleaning process. Reductions in FGD costs as a
result of coal cleaning range from an equivalent of $3.24 to $11.09 per ton
of cleaned coal. Thus, in certain cases the reductions in FGD costs alone
may be sufficient to justify coal cleaning. Relative FGD cost reductions
that result from coal cleaning are dependent upon the specific regulations
that must be met. Where S02 emission regulations are particularly
stringent, the FGD-related cost benefits may not be sufficient to justify
the use of coal cleaning, unless cost-benefits related to boiler operation
and to coal and ash handling are very high. Thus, in each case all of the
accounted-for benefits must be aggregated to determine whether cleaned coal
should be burned at a particular power plant.
In conclusion, available data show that PCC has a potential to produce
great benefits in terms of reduced costs for power production and environ-
mental control. The most important economic benefits of PCC are boiler
operability improvements associated with upgraded quality. Unfortunately
these benefits are difficult to document. Additional work is needed to
develop a better understanding of the effects of PCC on the costs of power
production and environmental control. Until site-specific studies are
undertaken to determine savings which can be realized by using cleaned coal,
it seems unlikely that utilities will show significant interest in coal
cleaning.
Further studies should be undertaken to demonstrate the potential bene-
fits which would result if PCC is more widely applied. The results of such
-------
studies may provide a rational basis for further governmental effort to sup-
port the accelerated use of PCC. In the meantime, it is felt that a more
widespread application of coal cleaning technology seems to be economically
justified. This conclusion needs to be confirmed by additional work that
will provide a more accurate and reliable measure of these potential coal
cleaning cost benefits.
-------
SECTION 3
APPLICABILITY OF PHYSICAL COAL CLEANING TO U.S. COALS
3.1 PROCESS DESCRIPTION
All PCC systems use equipment that segregates mixed input materials of
different specific gravities into separate output streams. Various degrees
of size reduction are used in isolating materials of different specific
gravities. Because of the large differences in specific gravities of car-
bonaceous coal materials (1.5) and the associated materials to be removed
(noncombustible minerals, 2.5; pyrite, 5.0), such approaches are very
effective where the individual components can be readily isolated from each
other.
At present 400 to 500 PCC plants are in operation. About 400 million
tons of coal per year are given some level of physical cleaning. The
cleaning systems vary considerably in complexity as a function of product
requirements and cleanability of the coal.
Different levels of cleaning have been defined as typical of systems
used to upgrade coal (Kilgroe 1979; and Spaite 1979). Generalization in
this connection is difficult, but the higher levels of cleaning usually
involve more processing steps. Four recognized levels of coal washing are
as follows (Kilgroe 1979):
Level 1 - Beneficiation or washing of coarse coal, in which the coal
particles greater than about 3/8 inch are treated and recombined
with unwashed finer materials to form the product.
Level 2 - Beneficiation of coarse (+ 3/8 inch) and fine coal (3/8
inch x 28 mesh) fractions. The very fine (28 mesh x 0) material is
dewatered and either shipped as product or discarded.
Level 3 - Beneficiation of the coarse, fine, and very fine
fractions. The moisture content of fine and very fine fractions is
usually limited by drying.
Level 4 - Full beneficiation of all fractions. This level of clean-
ing is practiced for optimal ash and sulfur reduction. It may in-
volve crushing the coal to finer sizes and producing a number of
coal products, each with a different ash and sulfur content.
-------
— RAW COAl
• PCC. 1-1 1/2 in. 1.ISG
• PCC. 3/8 MI. l.ior 13 SO
A S0% PVWTIC SULFUR REMOVED
in
•o
•o
3
cr
CD
TOTAL QUADS Of RAW COAL - 172S 37
The impact of various levels of cleaning is Illustrated in Figure 1, which
shows the energy available in northern Appalachian coals as a function of
different levels of PCC and emission standards (Kilgroe 1979).
1700
1500
1300
1100
900
700
500
300
TOO
1.0
EMISSION STANDARD, Ib S02/106BTU
Figure 1. Energy available in northern Appalachian reserve base as a function
of various physical coal cleaning levels and emission standards.
3.2 WASHABILITY OF U.S. COALS
The washability
U.S. Bureau of Mines.
the coal now being
evaluate washability
of U.S. coals has been studied by the EPA and by the
More than 455 coals representing over 70 percent of
burned by utilities have been laboratory tested to
by methods based on differences in specific gravity
(Cavallaro 1976). Data from these tests have been analyzed extensively in
numerous studies aimed at predicting the extent to which PCC can be used to
permit burning of high-sulfur coals in compliance with present and projected
standards for S02 emissions. Although many coals show good washability,
there are few in which sulfur content can be reduced sufficiently to meet
8
-------
present standards without supplemental controls. Furthermore, many of those
that could be washed to meet the 1971 standard (which was not effective
until 1979) are located in the West, remote from markets for utility coal.
A recent Battelle study (Hall 1979) indicates the following:
0 Nine percent of the U.S. coal reserves having sulfur levels
that would give emissions in excess of the 1971 New Source
Performance Standard for coal-fired boilers (1.2 Ib S02/million
Btu when burned) would meet the standard after physical clean-
ing.
0 For western coals, washing would upgrade about 15 percent of
the reserves to meet the 1971 standards.
0 For coals from the northern Appalachian, southern Appalachian,
eastern Midwest, and western Midwest regions, washing would
upgrade 6, 10, 2, and 1 percent, respectively, to meet the 1971
standard.
Outside the western region the percentages that can be upgraded to meet the
1971 standards are low. More stringent standards (i.e., 70 to 90 percent
S02 removal) would virtually eliminate the use of PCC as a sole method of
compliance. This fact, however, is not as significant as it may seem,
because removal of sulfur is only one of the benefits to be realized from
PCC.
3.3 COST OF PHYSICAL COAL CLEANING
The costs of PCC at different levels of cleaning are highly variable.
For a simple plant built for Level 1 cleaning, a capital cost of $6000 per
ton per hour of capacity has been reported (Holt 1978). For a multistream
plant designed for Level 4 cleaning, a capital cost of $42,000 per ton per
hour of capacity is reported (McGraw 1977). Costs of coal cleaning have
been calculated also by use of a PEDCo computer program in which a three-
circuit plant, cleaning to Level 2, is assumed. Annual costs are affected
considerably by plant capacity. Table 2 shows the resultant PCC costs for
plants at capacities ranging from 400 to 3200 tons/h that would supply coal
for one to eight 500 MW boilers.
TABLE 2. COSTS OF PHYSICAL COAL CLEANING AT
LEVEL 2 PLANTS OF VARIOUS CAPACITIES
Capacity,
tons/h
400
1200
1600
2000
3200
No. of
500-MW
boilers
served
1
3
4
5
8
Capital
cost,
$/kW
20.2
14.4
13.4
12.7
11.9
Annual cost
mills/kWh
2.7
2.2
2.1
2.0
2.0
$/ton of
cleaned coal
6.53
5.30
5.09
4.92
4.73
-------
The values are based on characteristics of a standard coal that is used
throughout this report, i.e., raw coal with a heating value (HAV) of 10,670
Btu/lb, 20 percent ash, and 3.5 percent sulfur. It is assumed that this
coal can be cleaned at 90 percent Btu recovery to yield 80 percent by weight
of a coal with HAV of 12,000 Btu/lb, 10 percent ash, and 2.4 percent sulfur.
The 500-MW boiler is assumed to operate at a 70 percent capacity factor.
Table 2 shows a considerable economy of scale in a PCC plant large
enough to service three boilers instead of one. The cost drops from $6.53
to $5.30 per ton of cleaned coal, or 19 percent. Larger plants show even
greater economies of scale, but the improvements are less pronounced. Total
coal cleaning cost at the plant servicing eight boilers is 90 percent of
that at the plant servicing three boilers.
As a basis for comparison we include results of a recent analysis of
reported costs for eight plants classified as simple, intermediate, and com-
plex (Hall 1979). Results of that study are shown in Table 3 (plant
description and performance factors) and Table 4 (cost factors). These data
provide a perspective for assessment of cost levels and cost variability;
the data also illustrate the variation in relative costs depending on the
method of presenting annual costs. The performance factors of Table 3 are
consistent with assumptions cited in Section 4 of this report for estimation
of benefits. For the eight plants in Table 3, the total cleaning costs
range from $4.40 to $8.41 per ton of cleaned coal, averaging $4.85 per ton.
The analysis in Section 4 shows that the total benefits of coal cleaning are
typically of the same magnitude and that in some cases the benefits substan-
tially exceed the cleaning costs.
Annual costs include capital recovery costs, operating and maintenance
(O&M) costs, and the cost of replacing the coal rejected by the cleaning
plant. This replacement cost can be substantial. For example, if raw coal
at $1.00 per million Btu ($21.34 per ton) is burned in a boiler, 93.75 Ib of
coal must be dug to produce a million Btu. If the coal is cleaned at an
80 percent weight yield with 90 percent Btu recovery then the amount to be
dug is
93.75 Ib x 100/90 = 104.16 Ib.
The cost of this extra 10.41 Ib of coal must be borne as part of the
cleaning operation. The cost is $0.11 per million Btu, equivalent to
1.11 mills per kWh or $2.67 per ton of cleaned coal; this is about half of
the coal cleaning cost of the 1200-tons/h plant. It is apparent that the
cost of coal cleaning is affected substantially by the operating efficiency
of the cleaning plant.
The costs of coal cleaning and the potential benefits should be evalu-
ated within the context of the costs/benefits of FGD systems used alone and
of systems combining PCC and FGD. In general, removing sulfur from coal by
PCC is more economical than scrubbing it from boiler exhaust gas. The
capability for sulfur removal by PCC, however, is only about 30 to 40
percent for most coals, significantly lower than that of FGD systems, which
have demonstrated S02 removal efficiencies above 90 percent. Furthermore,
10
-------
TABLE 3. COAL PREPARATION PLANTS AND PERFORMANCE FACTORS (HOLT 1978)
Plant
No.
1
2
3
4
5
6
7
8
Process
Jig
Jig
Jig
Jig
Dense
medium
Dense
medium
Dense
medium
Dense
| medium
Raw coal
capacity,
ton/h
600
1,000
1,000
1,600
1,400
(720)D
600
600
900
Complex-
ity
Simple
Inter-
mediate
Inter-
mediate
Complex
Simple
Complex
Complex
Complex
Estimated
capital
investment,
$ x 103
(mid-1977)
3,946
13,681
12.084
22,886
9,962
13,449
8,420
20,916
Btu
recovery,
%
91.6
96.4
83.0
93.7
94.6
89.2
93.1
94.1
Weight
yield,
%
59.0
71.4
56.6
59.6
74.0
73.3
60.0
86.0
Clean
coal
moisture
content,
%
8-9
6.9
4.6
5.8
7.5
5.0
4.9
5.0
Ash
removal ,
lb/tona
651
472
606
678
260
338
660
145
Sulfur
removal ,
lb/tona
3.7
23.3
27.7
9.0
29.5
55.2
6.3
18.0
Lb removed per ton of raw coal processed.
680 tons/h of raw coal is not processed by the cleaning plant.
-------
TABLE 4. TOTAL ANNUAL COSTS FOR EIGHT COAL PREPARATION PLANTS (HOLT 1978)
Plant
No.
1
2
3
4
5C
6
7
8
O&M
cost,3
$/ton of
cleaned
coal
2.70
2.55
2.67
2.96
3.20
3.04
2.12
2.44
Capital .
charges,
$/ton of
cleaned
coal
0.65
1.12
1.25
1.40
0.56
1.79
1.36
0.94d
Cost of
Btu loss,
$/ton of
cleaned
coal
2.14
0.75
4.49
1.60
1.10
2.21
1.76
1.02
Total
cost,
$/ton of
cleaned
coal
5.49
4.42
8.41
5.96
4.86
7.04
5.24
4.40
Total annual cost,
$/100 Btu
recovered
0.227
0.183
0.338
0.222
0.239
0.258
0.206
0.176
$/ton of
ash removed
9.92
13.39
15.71
10.47
27.69
30.53
9.55
52.28
$/ton of
sulfur removed
1,746
271
344
789
244
187
1,000
421
Operating and maintenance (O&M) cost includes labor, supervision, overhead, supplies, fuel,
electricity, and subcontract services.
bBased on a 10-year amortization period, 9 percent discount rate, and 30 per-
cent utilization factor, except as noted.
cCosts shown for Plant No. 5 are based on 1400 tons/h.
Fifty percent utilization factor.
-------
because regulations typically require abatement of 70 to 90 percent of
potential S02 emissions, the use of PCC alone generally is not sufficient to
achieve compliance; auxiliary scrubbing of at least part of the exhaust gas
from a boiler is necessary even when cleaned coal is burned. Thus, although
FGD can almost always be used as a sole means of control, coal cleaning
cannot, and usually must be combined with FGD to achieve compliance.
Because coal cleaning does remove part of the sulfur from coal, firing
of cleaned coal reduces the cost of the FGD system needed to meet control
requirements. To illustrate this effect, we performed a parametric cost
study comparing FGD as a sole control measure with systems that combine FGD
and PCC. The study, described in detail in Appendix B, considers three
postulated S02 regulations, three coals with different sulfur contents, and
three levels of sulfur removal by PCC. In each case the use of PCC reduces
FGD requirements (and costs) below those of an FGD system used alone, for
the following reasons:
Less scrubbing of exhaust gas is needed at a given scrubber effi-
ciency because coal cleaning removes part of the sulfur that would
otherwise have to be scrubbed.
Exhaust gas Thaf. does not have to be scrubbed can be used to provide
part or all c*i the FGD gas reheat needed to promote atmospheric
dispersion and suppress plume formation.
Because coal cleaning reduces the variability of coal quality, a
relatively less conservative scrubber design can be used to meet
limits for maximum emission levels on a 30-day average.
Results of this study are shown in Figures 2, 3, and 4, and are summa-
rized briefly here. Figure 2 shows that with raw coal having 2.5 percent
sulfur, either FGD or PCC can be used alone to comply with a regulation of
2.6 Ib S02 per million Btu. In this case coal cleaning costs less than FGD,
and the savings is about $2.55 per ton of cleaned coal. For the more
stringent regulations, 1.2 Ib S02 per million Btu and 85 percent S02
removal, incremental costs are associated with the use of a combined system
over those of an FGD system alone. The cost increment decreases with
increasing degree of sulfur removal by PCC. For the 85 percent regulation,
the cost decreases from $1.70 to $1.60 per ton as the PCC sulfur removal
increases from 30 to 50 percent.
Figure 3 shows relationships for 3.5 percent sulfur coal. In this case
the costs of removing 85 percent of the S02 are nearly identical to those of
limiting emissions to 1.2 Ib S02 per million Btu. Under an emission limit
of 2.6 Ib S02 per million Btu, no FGD system is required if PCC can remove
50 percent of the sulfur. At 40 percent sulfur removal by PCC, the combina-
tion system is more cost-effective than FGD alone by about $1.45 per ton of
cleaned coal; however, at 30 percent sulfur removal by PCC the combination
system costs $2.25 more per ton of cleaned coal than an FGD system alone.
Figure 4 depicts the effects of input coal with 5 percent sulfur. For
this coal an 85 percent regulation is less restrictive than a regulation of
13
-------
3 -i-
13
o
u
c
ts
QJ
o 1 --
C
O
OJ
0 --
-g -1
-2 --
-4
85% S02 REMOVAL
1.2 LB S02/10S Btu
2.6 LB S02/10S Btu
10
20
30
40
50
S02 REDUCTION BY PCC, percent
Figure 2. Annual incremental cost of operating a PCC-FGD system at a 500-MW
plant under various S02 regulations; sulfur content of raw coal =2.5 percent.
-------
o
o
c
ro
OJ
c
o
s_
0,'
1/1
o
2 --
-3
-4
85% S02 REMOVAL
2.6 LB S02
PER 10E Btu
NO FGD
REQUIRED
10
20
30
40
50
SO, REDUCTION BY PCC, percent
Figure 3. Annual incremental cost of operating a PCC-FGD system at a 500-MW
plant under various S02 regulations; sulfur content of raw coal = 3.5 percent.
15
-------
fO
O
u
c
fO
01
u
c
O
QJ
O.
in
U
ID
in
O
O
2 --
0 --
-3 --
-4
2.6 LB S02/106 Btu
1.2 LB S02/10S Btu
10
20
30
40
50
S02 REDUCTION BY PCC, percent
Figure 4. Annual incremental cost of operating a PCC-FGD system at a 500-MW
plant under various S02 regulations; sulfur content of raw coal = 5.0 percent.
16
-------
1.2 1b S02 per million Btu; only where the regulation is 2.6 Ib S02 per mil-
lion Btu and 50 percent of the sulfur 1s removed by coal cleaning is the
combination system more cost-effective than the FGD system alone, with
savings of about $0.70 per ton of cleaned coal.
In summary, where PCC is used as an adjunct to FGD, the cost benefits
increase with increasing percentage of sulfur removal in the cleaning
process (at a given Btu recovery level). Restrictive S02 regulations reduce
the cost effectiveness of PCC. In the cases studied, most of the combina-
tion PCC-FGD systems are more costly than FGD systems alone, and the cost
diffentials range up to about $2.70 per ton. In such cases the use of PCC
in conjunction with FGD would be cost-effective only where additional
benefits of corresponding magnitude could be identified. These additional
benefits associated with the use of PCC are discussed in Section 4.
17
-------
SECTION 4
ECONOMIC BENEFITS
The several economic benefits to the utility industry that are associ-
ated with PCC can be categorized with respect to three functional areas of
the power plant:
1. Coal and ash handling
Coal transportation
Coal handling and storage
Pulverization
Ash collection and handling
Ash disposal
2. Boiler operation
0 & M
Boiler availability
Boiler efficiency
Boiler capacity
3. Exhaust gas handling and cleaning equipment
Performance of particulate collection equipment
Costs of FGD systems
Our assessment of the value of the benefits of PCC in these categories
is based on equivalent costs to the utility that would be incurred to
achieve the same benefit by some means other than coal cleaning. For
example, the value of increased boiler availability is taken to be the cost
of boiler unavailability, in terms of generating or purchasing the replace-
ment power. The assessment effort included discussions with many persons
actively involved in power generation and coal preparation. Additionally, a
massive quantity of literature was reviewed; the literature sources are
given, with annotation, in Appendix A.
As a basis for estimating coal cleaning benefits, several assumptions
were made regarding coal quality, PCC plant and boiler performance, FGD
system performance, and costs:
0 Raw coal has a heat value of 10,670 Btu/lb, 20 percent ash, and
3.5 percent sulfur.
0 Cost of raw coal is $1.00 per million Btu ($21.34/ton).
18
-------
0 Cleaned coal has a heating value of 12,000 Btu/lb, 10 percent
ash, and 2.4 percent sulfur, representing a Btu recovery of
90 percent and a weight yield of 80 percent for the PCC plant.
0 Net heat rate of the boiler is 10,000 Btu/kWh.
Throughout this report the benefit values are expressed in dollars per
ton of cleaned coal. Since a ton of cleaned coal contains 24 million Btu, a
benefit of $1.00 per ton (1000 mills/ton) of cleaned coal for a boiler with
a heat rate of 10,000 Btu per kWh is equivalent to
1000 mills/ton x 10,000 Btu/kWh T 24 x 106 Btu/ton = 0.42 mill/kWh.
This conversion is used occasionally in our analysis.
We identify the expected benefits in a categorical and qualitative
fashion and attempt also to estimate a quantitative range. This assessment
provides a basis for estimating a cost range over which coal cleaning is
cost-effective.
4.1 COST SAVING:," IN COAL AND ASH HANDLING
Physical coal cleaning changes characteristics of the coal and reduces
the quantities that are moved to the power plant and into the boilers; PCC
also affects the properties and quantities of refuse generated in burning
the coal. These effects are discussed in detail below.
4.1.1 Coal Transportation
A direct savings in coal transportation costs occurs when a PCC plant
is installed at or near a coal mine, because the ash that is removed from
the coal need not be transported. Table 5 shows weight yields from PCC of
coals for which we have determined washability characteristics; all of these
coals were cleaned to a level of 90 percent Btu recovery.
Because these coals were mainly from Kentucky and Tennessee, they may
not be typical of all U.S. coals. Nevertheless, the weight yields seem to
be typical of washed bituminuous coals, ranging from 72.7 to 85.8 percent;
this suggests that a PCC plant would produce cleaned coal weighing 81 to
95 percent (72.7/0.90 to 85.8/0.90) as much as the corresponding raw coal on
a unit Btu basis. Thus the potential transportation savings would be 5 to
19 percent. Based on the mean weight yield of 79.8 percent, the potential
savings would be 11 percent (100 - 79.8/0.90).
Coal transportation costs are highly site-specific. Railroads derive
more revenue from coal than from any other commodity. Although there is a
governing Uniform ICC Freight Classification for bituminous coal, little, if
any, coal moves at class rates. In fact, numerous types of commodity rates
apply to bituminous coal. The railroads are required by law to establish
just and reasonable rates and to abide by the rates that they publish in
19
-------
schedules known as rail freight tariffs. Approximately 45,000 tariffs are
in current use, containing millions of rates (Hoffman 1976). Determination
of an average coal transportation rate thus is difficult.
TABLE 5. WEIGHT YIELDS OF WASHED COAL AT 90 PERCENT BTU RECOVERY
Coal
Old Ben 26
Fabius & Underwood
Hamilton 9
River Queen
Ohio
Sinclair 12
Sinclair 9
Sinclair 11
Ayrgem 11
Sinclair 9 - Underground
Breckinridge No. 1
Breckinridge No. 2
Brown Badgett
Ayrgem 12
Old Ben 24
Isl. Creek No. 9
Colonial 9, 11, 12
So. Fork 5A, 7, 9
Cravat - Rice 8, 9, 11
Isl. Creek Prov. No. 1
Eads
Colonial
Mean
Weight yield, %
76.5
85.8
79.6
83.6
83.5
72.7
82.0
80.5
74.2
83.6
76.5
75.3
82.4
73.4
78.5
80.1
80.6
82.7
81.4
76.2
82.1
85.1
79.8
One report gives data for two cases that show coal transportation costs
of $3.00 and $9.50 per ton for rail hauls of 180 and 400 miles, respectively
(Buder 1979). Another report gives ten rail transportation cost estimates
for delivery of coal to three TVA plants, based on 1977 volume tariffs;
these costs average $6.34 per ton and range from $3.00 to $12.57 per ton
(Foster 1977). A third report suggests a typical coal transportation cost
of $5.00 per ton (Phillips 1979). These data indicate that typical costs of
transporting utility coal are about $6.00 per ton, but that in specific
cases costs may range from about $1.00 to $15.00 per ton or more. High
transportation costs are associated with the use of Western coals in power
plants located outside the Western United States. Although cost of these
coals is generally low (f.o.b. mine), it is not necessarily cost-effective
to clean them to reduce the transporation costs. For example, in late 1976
the TVA considered the use of a Colorado low-sulfur coal at the Shawnee
steam plant in Kentucky. The estimated transporation cost was $18.19 per
ton, which exceeded the f.o.b. mine price of the coal, $15.00 per ton. If
that coal could have been cleaned at an 80 percent weight yield with
90 percent Btu recovery, the transportation cost for the equivalent heat
content of a ton of raw coal would have been
20
-------
$18.19 x 0.8 T 0.9 = $16.17 per equivalent ton.
The savings would be $2.02 per equivalent ton ($18.19 - $16.17). The cost
of producing an equivalent ton, however, would be
$15.00 x 1.00 4 0.90 = $16.67 per equivalent ton
so that the cost of reject coal is $1.67 ($16.67 - $15.00). Thus, to
justify cleaning the coal in regard to savings in coal transportation costs
only, the coal would have to be cleaned for less than
$2.02 - 1.67 = $0.35 per equivalent ton
Table 4 indicates that coal cleaning costs are generally much higher than
$0.35 per ton. A further complication is that the Colorado coal contains
only 10 percent ash, so that the weight yield would probably be somewhat
higher than 80 percent at a 90 percent Btu recovery; this would further
reduce the transportation savings. In summary, the data indicate that
(1) assessment of coal transportation cost benefits must be made on a
case-by-case basis, (2) the transportation cost benefit is generally only a
small portion of the cost of coal cleaning, and (3) in cases where the
benefit is especially high, alternative coal supplies may be available that
can be used more cost-effectively.
With an estimated transportation savings of 11 percent at $6.00 per
ton, the potential transportation benefit attributable to coal cleaning
would be
$6.00 x 0.11 = $0.66 per ton of cleaned coal
A reasonable range for this benefit would be about $0.10 to $1.50 per ton,
with a typical value around $0.70 per ton. In some cases the benefit may be
substantially more; in other cases, such as a mine-mouth situation, there
may be no measurable benefit in this category. Transportation economics for
each plant must be carefully evaluated in assessing this benefit.
4.1.2 Coal Handling and Storage
The principal PCC benefit relative to coal handling and storage is that
less cleaned coal must be handled and stored than raw coal, because the heat
content of the cleaned coal is higher. At an existing plant this effect
would be negligible in an economic sense; there would be no appreciable
reduction in requirements for a coal handling system, for personnel, or for
coal storage area. However, the increased fugitive dust potential associ-
ated with coal that has been crushed and cleaned may pose problems that will
have to be solved. The elements of a coal handling and storage system that
may be improved as a result of coal cleaning include the following:
21
-------
0 Reduced need for system maintenance of coal handling equipment
damaged by corrosion and abrasion
0 Reduced consumption of fuel and electricity for coal moving
equipment, crushers, and conveyors
0 Reduced requirements for coal stockpile area and for employees
to handle coal
Again, these benefits would be negligible at an existing plant because
equipment sizes and staff requirements are not very flexible. At a new
plant, however, the requirements for coal stockpile area, coal moving
machinery capacity, and manpower could be reduced. Some coal crushing
operations and equipment probably could be eliminated. As shown later,
however, the operating and maintenance (O&M) costs of coal handling
represent about 14 percent of all O&M costs. Although we assume an 11
percent reduction in the tonnage of coal to be handled as a result of PCC,
we might expect that somewhat less than 11 percent of the coal handling
costs are directly related to tonnage. If we therefore assume, for example,
a 5 percent savings on 14 percent of the total O&M costs, the benefit is
equivalent to only $0.01 per ton of cleaned coal. Another report has also
concluded that the benefit is negligible, even at new plants (Buder 1979).
4.1.3 Pulverizers
Coal pulverizers grind the coal into a fine product and raise the fuel
temperature to about 600°F. The effects of coal cleaning on the pulverizers
are twofold. First, the quality of the cleaned coal increases the pulver-
izer capacity at existing plants and reduces the capital requirements for
•pulverizers at a new plant; where boilers are pulverizer-limited, this is
tantamount to increasing the boiler capacity. Second, the processing of
higher quality coal having a finer size distribution should reduce the costs
of pulverizer operation and maintenance, although the higher moisture
content of the cleaned coal may offset some of the maintenance savings.
These two effects are discussed separately.
Capacity Effects--
Coal cleaning should improve pulverizer capacity for two reasons.
First, the heat content of cleaned coal is higher than that of raw coal, and
therefore each ton of pulverizer throughput contains more Btu's. When a
coal is cleaned with 90 percent Btu recovery and an 80 percent weight yield,
the effective increase in pulverizer capacity on a Btu basis is
(0.90/0.80 - 1) x 100 = 13 percent
assuming that the tonnage capacity of the pulverizer is the same for raw
coal and cleaned coal. Where existing utility boilers are operating in a
pulverizer-limited mode, this increase in pulverizer capacity may be quite
valuable, because part of this increased capacity could obviate the need for
generation or purchase of more costly electricity.
22
-------
The second factor In improvement of pulverizer capacity is that cleaned
coal may be easier to pulverize than raw coal. Thus, the mass throughput
capacity of a given pulverizer may be increased, or, at a new boiler instal-
lation, a less conservatively sized pulverizer can be installed, with a
capital cost savings (Phillips 1979). It is well known that PCC processes
easily remove many mineral inclusions in coal, such as rock and shale.
Also, PCC removes pyrite, an extremely hard and dense material. Thus,
cleaned coal should be lighter, finer, and softer than raw coal, and easier
to pulverize.
Furthermore, a recent report indicates that because the properties of
cleaned coal are not so variable as for raw coal, it should be possible to
design pulverizers less conservatively and to avoid oversizing of equipment.
On the other hand, there are indications that coal cleaning may cause
certain pulverizer operating problems. Since most coal is cleaned in an
aqueous medium, the cleaning process has considerable potential for increas-
ing the coal moisture content. The higher moisture content may create sig-
nificant problems in pulverizer operation and may reduce pulverizer
capacity. The moisture content, however, probably would be reduced at the
PCC plant to a level equal to that of the raw coal or at least to a level
where such problems would be minimal. Therefore, the net effect of PCC
should be to increase pulverizer capacity and reliability.
Pulverizer Operation and Maintenance--
The two principal categories of pulverizer wear are abrasion and corro-
sion. Abrasion is closely related to the hardness, size distribution, and
quantity of coal that is pulverized, whereas corrosion is mainly a function
of its sulfur content and moisture. Although the moisture added in coal
cleaning would tend to increase corrosion, the reduction of sulfur content
should more than offset this corrosive effect. Coal cleaning should reduce
the abrasive and corrosive properties of a coal and thus reduce pulverizer
maintenance requirements. Pulverizer maintenance accounts for about
10 percent of all boiler maintenance costs. The principal items subject to
wear and maintenance include grinding elements such as forged steel balls
and races, classifiers, coal feed chutes, and drive mechanisms. The service
life of the grinding elements of ball and race pulverizers ranges from 6,000
to 14,000 hours of operation. The rate of wear for these elements is a
function of coal sulfur and ash content, but no quantitative relationship
has been established. Wear is not closely related to the grindability of
the coal, and operating time is reported to be a better index of the life of
the grinding elements than the rate of output of a pulverizer (Babcock
1960).
Conclusions Regarding Pulverizer Effects--
On the whole, coal cleaning is expected to increase pulverizer capacity
and to reduce maintenance costs. Because of the difficulty of allocating
the total maintenance costs among the different parts of a boiler system,
the pulverizer maintenance costs are included in Section 4.2.1, O&M Cost
Reductions. Although the increases in pulverizer capacity may range from
5 to 15 percent, no net benefit in terms of boiler capacity would be real-
ized at most plants, where pulverizer capacity is adequate. In contrast, at
23
-------
a plant where a 1000-MW boiler is pulverizer-limited, so that coal cleaning
can increase the effective boiler capacity from 950 MW to 1000 MW, the
estimated value of the PCC benefit would be equivalent to the revenue needed
to capitalize 50 additional megawatts of capacity. At a capital cost of
$1000 per kW and an amortization period of 25 years, and with various other
input parameters indicated in Appendix C, the annual savings would be $11.6
million (Foster 1975). With a 70 percent capacity factor for a 1000-MW
boiler, the savings is 1.9 mills/kWh, equivalent to $4.50 per ton of cleaned
coal. This is a substantial benefit.
It is possible that many existing utility boiler plants are pulverizer-
limited and cannot be easily retrofitted with additional pulverizers because
of space and geometry limitations. In the past many utility boiler plants
switched from coal to oil for economic and environmental reasons. Because
of the general deterioration of coal quality since that time, these boilers
cannot now be reconverted for coal firing unless they are derated for
pulverizer limitations associated with the poor quality coal that is now
available. Coal cleaning might be an attractive possibility for some of
these plants.
4.1.4 Ash Collect-ion and Handling
Requirements for collection and handling of ash are reduced in almost
direct proportion to the reduction in coal ash content effected by coal
cleaning. A principal problem with ash handling equipment is the buildup of
material in boilers and equipment, causing disruption in operation or effi-
ciency of air pollution control equipment such as electrostatic precipita-
tors (ESP) and scrubbers. A related problem is the abrasion and corrosion
of ash collecting and conveying equipment. Coal cleaning can help to
•alleviate these problems, especially at plants where hoppers and ash
handling systems are undersized. Reduction of the sulfur content of coal by
coal cleaning also reduces the corrosive properties of the collected ash.
It is expected that in specific cases PCC will alleviate some deficien-
cies of ash handling systems, but for most existing boilers there will be
little effect, if any. Reduced ash loadings may permit less frequent
removal of bottom ash from a boiler, but in most systems the removal opera-
tion is continuous or automatic. Maintenance costs for the ash handling
system as a whole may be reduced slightly, and any improvement in relia-
bility of the ash handling system may have a corresponding effect on the
reliability of associated air pollution control equipment. As shown later
(Table 6), ash handling O&M costs account for about 16 percent of all O&M
costs. Since the ash tonnage from firing of cleaned coal is typically about
half of that from raw coal, an upper limit on the PCC benefit for ash
handling would be about $0.10 per ton of cleaned coal, and a typical value
would be closer to $0.05 per ton. This benefit is included in Section
4.2.1. Another report indicates that ash handling equipment accounts for
less than 1 percent of the total plant capital cost, but that PCC can yield
a one-third savings in those capital costs, which is equivalent to about
$0.24 per ton of cleaned coal for a new plant (Buder, 1979).
24
-------
4.1.5 Ash Disposal
Coal cleaning substantially reduces the ash disposal requirements for a
power plant. At an existing plant, the ash hauling costs can be reduced, or
the service life of a pond or landfill can be extended. Generally, ash com-
position is not adversely Influenced by the cleaning process. Of course,
all of the mineral matter in the raw coal is subject to ultimate disposal,
either by the coal cleaning plant or by the utility, but disposal costs at
the cleaning plant are borne as part of the cleaning operation. Where a
coal cleaning process removes half of the ash from the coal, the savings may
approach half of total ash disposal costs.
In this cost study we inspected forms submitted to the Federal Power
Commission in 1977 by several utilities. Among eight utilities who reported
the costs of ash and sludge disposal, the costs ranged from 0.001 to 0.139
mill per kWh with an average of 0.076 mill per kWh. If PCC reduces the coal
ash content by 50 percent, we might expect the ash disposal costs to be re-
duced proportionately. Thus we estimate a typical benefit of 0.038 mill per
kWh, equivalent to $0.09 per ton of cleaned coal, and a benefit range from
0 to $0.20 per ton.
*
One utility representative indicates ash disposal costs in the neigh-
borhood of $2 per ton of ash. He cautions, however, that the incremental
savings may tend to be less. One problem is that fly ash is needed for
sludge fixation. Since PCC generally reduces ash content to a greater
extent than it reduces sulfur content, a net deficit of fly ash for sludge
fixation purposes may result. Also, the $2 per ton figure includes certain
fixed costs.
Because 12,000/10,670 tons of raw coal are equivalent to a ton of
cleaned coal in terms of heat content; the ash reduction per ton of our
example cleaned coal is
0.2 x 12,000/10,670 - 0.1 = 0.125 ton of ash per ton of cleaned coal.
At a disposal cost of $2 per ton of ash, the PCC benefit is estimated to be
0.125 x $2.00 = $0.25 per ton of cleaned coal
As discussed above, the net savings will probably be somewhat less because
fixed costs associated with refuse disposal would not be reduced proportion-
ately and because of potential sludge fixation problems. On the basis of
available data, the typical benefits would be about $0.10 per ton of cleaned
coal, with a range from 0 to $0.25 per ton.
4.2 COST SAVINGS IN BOILER OPERATION
Many of the benefits of burning cleaned coal would occur in operation
of the boiler, since the cleaning process improves the combustion properties
25
-------
of the coal. The expected boiler operating benefits are discussed in
detail.
4.2.1 Operating and Maintenance Costs
Boiler O&M costs may be influenced profoundly by the quality of the
coal that is fed to the boiler. Coal quality parameters that influence
boiler O&M costs are mineral content and composition, both of which are
influenced by PCC. In addition to the impacts discussed earlier relative to
materials handling, mineral content influences operation of those boiler
components that come in contact with ash.
Mineral composition is also very important with respect to performance
of the boiler. It affects erosion, corrosion, and abrasion within the pul-
verizer, the boiler, and the gas and ash handling systems. Mineral
inclusions are responsible for all of the slagging and fouling properties of
coal.
Thus PCC can reduce the boiler O&M costs for a number of reasons. Re-
moval of mineral matter helps to reduce slagging and fouling of the boiler
tubes so that fv boiler runs cleaner and tube life is extended. Coal
cleaning reduces the abrasive characteristics of the coal, effecting a com-
mensurate decrease in boiler deterioration and in maintenance requirements.
The reduction of sulfur content by PCC retards corrosion of boiler
materials.
The Federal Power Commission has established a uniform system for cate-
gorizing utility costs. Tables 6 and 7 show these cost categories and
identify those that are and are not fuel-related. These data on the John
Sevier and Kingston plants were obtained from TVA for the period from 1974
through 1977. At the John Sevier plant the annual fuel-related boiler
maintenance costs ranged from 59 to 76 percent of total boiler costs,
averaging 66 percent over the 4-year period. At the Kingston plant the
fuel-related costs constituted about 80 percent of total boiler maintenance
costs in each of the 4 years.
Table 8 shows cost data from several TVA plants. At these plants the
ratio of fuel-related maintenance costs to total boiler maintenance costs
ranged from 45 to 87 percent. Thus, extrapolating from these data, we
surmise that perhaps 40 to 90 percent of all boiler maintenance costs are
fuel-related. It seems reasonable that a significant portion of these fuel-
related maintenance costs can be reduced if coal quality is improved by PCC.
Thus the O&M cost benefit is potentially very large. (For convenience in
this analysis, all of the fuel-related reductions in O&M cost are estimated
in this section rather than in individual sections concerning such items as
pulverizers and ash handling equipment.)
Table 9 shows reported costs associated with several large U.S. power
generating plants. A major point shown by the data is that boiler main-
tenance costs averaged about 5 percent of fuel costs in 1976, and ranged
from 1 to 35 percent for individual boilers. The TVA Paradise plant shows
26
-------
TABLE 6. ITEMIZED JVA BOILER MAINTENANCE COSTS, JOHN SEV1ER PLANT3
Cost area
Coat Handling and Storage Equipment
Railroad tracks
Locomotives
Coal sampling facilities
Coal receipts scales
Coal car unloading facilities
Storage yard coal moving equipment
Primary coal crushing facilities
Coal conveying facilities
Coal handling power and control system
Coal bunkers
Boiler and Accessories
Boilers
Soot blowe-t
Boiler water circulation equipment
Coal Burning Equipment
Coal transport piping and valves
Boiler room coal scales
Pulv. wills, primary air fans. exh. fans
Burners, lighters, cyclones
Lighter fuel oil system
Draft Equipment
Air preheaters
Forced draft fans
Induced draft fans
Air and gas ducts
Stacks
Feed Water Equipment
Feed water pumps and tanks
Feed water heaters, deaerators, & evap.
Ash Handling Equipment
Bottom ash hoppers
Fly ash collectors
Other ash disposal facilities
Ra«« Water Supply and Treating Systems
Boiler feed water
Raw water service
Boi ler Plant Piping
Boiler plant piping
Boiler Instrumentation and Controls
Boiler instrumentation and controls
Total - Fuel-related Items
Percent of total boiler
maintenance costs
1974
2.1
0.9
0.1
0.0
0.6
3.5
0.5
3.0
0.0
0.2
15.4
1.5
2.3
4.3
0.6
8.9
2.4
0.0
0.4
0.1
2.4
0.6
0.1
3.B
2.0
1.0
6.5
27.5
O.B
1.5
2.6
4.2
76.2
1975
2.6
2.7
0.2
0.1
1.8
4.6
1.0
4.5
0.3
0.3
19.4
2.5
7.4
1.4
1.1
5.6
1.5
0.2
0.3
0.?
1.6
0.7
0.0
5.5
0.5
0.6
2.8
13.7
14
3.9
4.4
6.9
59 3
1976
2.7
1.0
0.3
0.2
0.2
7.7
1.6
3.5
0.1
0.0
12.2
2.4
4.1
1.1
1.9
16.1
1.5
0.0
0.2
0.9
0.5
0.3
0.0
4.4
2.8
1.2
2.2
16.5
2.6
1.6
3.2
7.1
61.9
1977
2.0
0.4
0.2
0.2
0.3
7.3
0.5
3.1
0.1
0.0
17.1
2.2
3.7
2.3
1.1
15.2
1.7
0.1
0.2
0.2
0.2
0.6
0.0
5.8
1.9
1.2
2.2
16. 1
1.1
1.7
3.3
6.0
66.4
Avg.
2.4
1.2
0.2
0.1
0.8
5.6
0.9
3.5
0.1
0.1
16.0
2.2
4.4
2.3
1.2
11.5
1.8
0.1
0.3
0.4
1.2
0.6
0.0
4.9
1.8
1.0
3.4
19.0
1.5
2.2
3.4
6.0
66.1
"Data for period 1974 through 1977; Indicates fuel-related areas.
27
-------
TABLE 7. ITEMIZED TVA BOILER MAINTENANCE COSTS, KINGSTON PLANT1
Cost area
Coal Handling and Storage Equipment
Railroad tracks
Locomotives
Coal sampling facilities
Coal receipts scales
Coal car unloading facilities
Storage yard coal moving equipment
Primary coal crushing facilities
Coal conveying facilities
Coal handling power and control system
Coal bunkers
Boilers and Accessories
Boilers
Soot bowers
Boiler Mater circulation equipment
Coal Burning Equipment fl
Coal transport piping and valves
Boiler room coal scales
Pulv. mills, primary air fans, exh. fans
Burners, lighters, and cyclones
Lighter fuel oil system
Draft Equipment
Air preheaters
Forced draft fans
Induced draft fans
Air and gas ducts
Stacks
Feed Water Equipment
Feed water pumps and tanks
Feed water heaters, deaerators, & evap.
Ash Handling Equipment
Bottom ash hoppers
Fly ash col lectors
Other ash disposal facilities
Raw Water Supply and Treating Systems
Boiler feed water supply & treating sys.
Raw water serv. and gland seal water sys.
Boiler Plant Piping
Boiler plant piping
Boiler Instrumentation and Controls
Boiler instrumentation and controls
Total - Fuel-related Items
Percent of total boiler
•aintenance costs
1974
2.2
1.8
0.6
0.2
0.1
5.2
0.8
3.2
0.4
0.7
33.5
3.2
1.2
2.1
0.7
9.8
2.7
0.0
3.5
0.2
1.6
0.7
0.1
2.0
1.5
1.2
4.7
9.5
0.6
0.5
1.6
4.0
78.9
1975
2.8
0.9
0.9
0.3
1.5
4.4
0.8
3.7
0.1
0.2
25.0
3.3
2.1
4.0
1.0
10.1
2.3
0.1
5.7
0.2
1.7
0.7
0.7
2.0
2.2
1.5
5.7
8.5
0.7
0.9
2.3
4.7
76.6
1976
1.9
1.2
0.8
0.2
0.3
4.1
0.4
4.7
0.1
0.5
34.2
3.5
1.1
3.6
0.7
8.4
1.6
0.0
0.6
0.2
2.0
1977
1.4
1.4
0.5
0.2
0.1
3.9
0.2
1.7
0.2
3.4
Avg.
2.1
1.3
0.7
0.2
0.2
4.4
.6
3.3
0.2
1.2
37.4 32.5
3.3 3.3
1.0
3.1
0.7
8.7
1.1
0.0
2.1
0.1
2.0
1.4
3.2
0.8
9.2
1.9
0.0
3.0
0.2
1.8
0.4 ' 0.5 1 0.6
0.0
1.4
2.1
2.3
0.0 0.2
1
2.0 ' 1.8
3.4 , 2.3
2.3 1.8
3.8 | 4.7
13.3
0.6
0.4
1.9
3.4
81.5
8.3
0.4
4.7
9.9
5.8
0.6 0.6
1.9
3.3
80.7
1.9
3.8
79.1
*Dat« for period 1974 through 1977; indicates fuel-related areas.
28
-------
TABLE 8. TOTAL BOILER MAINTENANCE COSTS AND
FUEL-RELATED BOILER MAINTENANCE COSTS AT
SELECTED TVA PLANTS3
(A) (B)
Total Fuel-related
boiler boiler
maintenance maintenance
costs, costs,
Cost
Ratio,
Plant
Paradise
Shawnee
Kingston
Johnsonville
Gal latin
John Sevier
Bull Run
Average
Year
1972
1973
1974
1972
1973
1974
1972
1973
1974
1975
1976
1972
1973
1974
1972
1973
1974
1972
1973
1974
1975
1976
1972
1973
1974
$1,000
8677
7817
8078
2269
2569
2558
2491
3425
3961
3907
6353
1923
2314
2946
1579
1617
2122
797
1475
1886
1069
1529
1318
1054
1187
2997
.$1,000
6573
4336
5138
1817
1966
2116
1712
2890
3077
29S6
5145
1471
1932
2166
1028
785
1317
355
1280
1414
615
949
768
594
636
2121
(B) * (A)
0.76
0.55
0.64
0.80
0.77
0.83
0.69
0.84
0.78
0.76
0.81
0.76
0.83
0.74
0.65
0.49
0.62
0.45
0.87
0.75
0.58
0.62
0.58
0.56
0.54
0.71
aData from TVA annual reports and TVA Form 4121.
29
-------
TABLE 9. COST BREAKDOWN3 FOR SELECTED COAL-FIRED ELECTRIC
GENERATING PLANTS WITH AVERAGE BOILER SIZE OF 200 MW OR LARGER
Plant
Gorgas
Greene County
E. C. Guston Unit 5
E. C. Guston
Big Bend
Kinkaid
Powerton
Will County
State Line
Clifty Creek
E. W. Brown
Ghent
Mill Creek
Allen S. King
New Madrid
Thomas Hill
G. G. Allen
Belews Creek
Kyger Creek
Hatfields Ferry
Thomas H. Allen
Bull Run
Colbert "A"
Colbert "B"
Cumberland
Gallatin
Paradise "A"
Paradise "B"
John Sevier
Widows Creek "B"
Harrison
Fort Martin
New Geneva
Average
(A) Total
power
production
cost,
$1,000
78,786
25,794
48,329
71,132
65,914
28,658
59,987
70,527
47,386
73,417
28,801
23,435
23,345
29,545
25,812
17,728
62,320
126,900
59,417
95,459
39,562
41,320
47,626
15,409
91,148
56,502
41,130
31,227
61,296
50,237
139,251
60,185
22,646
53,340
(B)
Fuel
cost,
$1,000
65,357
21,130
40,420
64,150
57,464
19,184
53,336
60,581
36,874
64,903
26,426
21,540
20,796
24,867
21,345
14,895
59,427
122,288
50,531
85,183
31,666
34,823
39,637
11,841
71,726
46,395
28,727
20,858
56,586
41,211
131,777
53,703
19,317
46,029
(C) Boiler
Main-
tenance
cost,
$1,000
6,359
2,076
2,417
2,252
4,113
5,051
2,412
4,193
3,346
4,174
819
747
858
2,142
2,297
1,025
952
1,437
4,873
7,736
3,537
2,971
4,417
1,304
11,330
2,390
8,482
7,224
1,529
5,108
3,904
3,433
1,582
2,482
Cost
ratio
te nance
C * B
0.10
0.10
0.06
0.04
0.07
0.26
0.05
0.07
0.09
0.06
0.03
0.03
0.04
0.09
0.11
0.07
0.02
0.01
0.10
0.09
0.11
0.09
0.11
0.11
0.16
0.05
0.30
0.35
0.03
0.12
0.03
0.06
0.08
0.05
Data for the year 1976, obtained from TVA annual reports and TVA Form 4121.
30
-------
the highest ratio of boiler maintenance costs to fuel cost. The coal costs
at Paradise are very low, and as a result of poor coal quality, the boiler
maintenance costs are extremely high. TVA attributes these high boiler
maintenance costs to the poor coal quality and has contracted for Installa-
tion of a coal cleaning plant to alleviate the problem.
Representative values from Tables 8 and 9 Indicate boiler maintenance
costs equal to 5 percent of fuel costs, raw fuel costs of $21.34 per ton
($1.00/inillion Btu), and fuel-related maintenance costs equal to 70 percent
of total boiler maintenance costs; if 50 percent ash reduction by PCC is
assumed to eliminate 30 percent of these costs, the value of coal cleaning,
in terms of reduced boiler maintenance costs, is
0.05 x 0.70 x 0.30 x $1.00/106 Btu = $0.0105 per million Btu.
Where a ton of cleaned coal provides 24 million Btu, this cost benefit
is equivalent to
$0.0105 x 24 = $0.25 per ton of cleaned coal.
The benefit hinges jon the assumption that PCC eliminates 30 percent of the
fuel-related maintenance costs. Because we could find no available data to
support this assumption, it represents a subjective estimate in this case.
An independent approach to quantification of the benefit, which follows
shortly, indicates that the 30 percent assumption is conservative for
estimating a typical benefit.
The Paradise plant is a less typical example; fuel costs are $9.66 per
ton, boiler maintenance costs are 32.5 percent of fuel costs (see Table 9),
and fuel-related maintenance costs are 65 percent of total boiler main-
tenance costs (see Table 7). If the use of cleaned coal eliminates 50
percent of all fuel-related maintenance costs, the estimated value of a coal
cleaning benefit is
0.325 x 0.65 x 0.50 x $9.66/ton = $1.02 per ton of raw coal.
Although this value is high, it may not be an upper limit because fuel
costs at the Paradise plant are so low. Many utilities are paying three
times as much for coal. We estimate that in specific applications the value
of coal cleaning, in terms of reduced boiler maintenance costs, may range
from about $0.10 to perhaps $2.00 per ton of cleaned coal. Fuel-related
maintenance costs may be considered from another standpoint. TVA reports
the use of the sum of the percentage ash and sulfur contents (A+S) of a coal
as a negative measure of fuel quality (Cole 1979). It seems incongruous to
add the percentages of these two impurities, and to our knowledge there is
no rigorous statistical correlation showing that ash and sulfur should be
weighted together on a one-to-one basis. It is likely that the sulfur
content is the more detrimental of the two coal properties, but again we
have no knowledge of an appropriate weighting factor. TVA has used the
simple sum, A+S, for several years to determine fuel penalties to be charged
to producers when they supply inferior coal.
31
-------
Although statistical support is lacking, the use of A+S as a coal
quality parameter can be substantiated empirically. Figure 5 shows data for
five TVA plants over the period from initial commercial operation through
1974, indicating the relationship of cumulative fuel-related maintenance
costs to the cumulative tons of A+S. It is apparent that the relationship
is reasonably linear and, interestingly, that the slope is about the same
for all five plants. We conclude from the data that the addition of each
ton of A+S to these boilers costs about $3.90 in fuel-related boiler main-
tenance. This value seems reasonably constant over the life of each plant.
An important point is that the $3.90 cost parameter is apparently inde-
pendent of fuel quality because the data represent a fairly broad range of
ash and sulfur contents. The Paradise and Kingston plants have burned fuels
with over 20 percent ash. The John Sevier plant has burned fuels with as
low as 9 percent ash. The other plants have burned intermediate quality
fuels. Yet data from all five plants show the same basic fuel-related main-
tenance costs per ton of A+S.
As a check on our earlier conclusions about the value of coal cleaning
in reducing boiler maintenance costs, we can calculate a benefit based on
this $3.90 value and on the assumptions of a raw coal with a heat value of
10,670 Btu/lb, 20 percent ash, and 3.5 percent sulfur, which is physically
cleaned to 12,000 Btu/lb, 10 percent ash, and 2.4 percent sulfur with
90 percent Btu recovery and an 80 percent weight yield. The fuel-related
boiler maintenance cost associated with 1 ton of cleaned coal would be
$3.90 x (0.10 + 0.024) = $0.48.
The cost associated with the equivalent amount of raw coal would be
$3.90 x (12,000/10,670) x (0.20 + 0.035) = $1.03.
The coal cleaning benefit is thus the difference between $1.03 and $0.48,
i.e., $0.55 per ton of cleaned coal, or about twice our earlier estimate of
$0.25 per ton.
On the basis of all of the data analyzed, we believe that the typical
benefit would be between these two values, i.e., about $0.40 per ton of
cleaned coal. In specific cases the value may range from $0.10 to about
$2.00 per ton of cleaned coal.
4.2.2 Boiler Availability
In general, the availability of a boiler shows no significant change
with minor changes in the ash or sulfur content of a coal. It seems
somewhat obvious that reducing the ash and sulfur content of coal will
reduce the occurrence of tube failures, erosion and corrosion, ash handling
problems, pulverizer wear, and slagging problems. Other factors that influ-
ence boiler availability but are generally unrelated to fuel quality,
include boiler design and operating history and boiler water quality. Data
32
-------
OJ
t
•a
o
•o
o
aa
ae
i
UJ
Average slope:
$3.90 per ton of
ash-plus-sulfur
0_fc
10
12
14
o
CUMULATIVE TONS OF ASH-PLUS-SULFUR THROUGH THE BOILER PLANTS, millions of tons
Figure 5. Relationship of fuel-related boiler maintenance costs to
tons of ash-plus-sulfur fired into the boiler.
-------
indicate that as coal quality deteriorates, boiler availability also deter-
iorates, but data relating fuel quality to boiler availability are masked by
these other factors. For this reason it is difficult to formulate a solid
statistical relationship between fuel quality and boiler availability.
The value attributable to improved availability is dependent on the
method of evaluation. Where a boiler system has excess capacity, the value
of increased availability is very low, but this is not normally the case.
Most utilities use coal-fired units to supply their base load and use hydro-
electric units, oil- and gas-fired boilers, combustion turbines, and
purchased power to supply peaking loads. The differential between the cost
of producing base-load power and the cost of replacement power is a
reasonable estimate of the worth of increased availability.
The influence of fuel quality on boiler availability can be evaluated
in terms of a relationship between fuel quality and the forced outage rate
for a boiler. Forced outages are normally caused by failures of pulver-
izers, ash handling equipment, coal handling equipment, or boiler tubes
(Cole 1979). Failures that are fuel-independent are less common. Forced
outages have been shown to correlate with the ash and sulfur contents of the
coal. A recent TVA study estimates that availability is reduced by 1
percent for each percent that A+S exceeds 17.5 percent, and that 50 percent
of such unavailable power must be replaced at an incremental cost of
$0.01/kWh (Phillips 1979). Thus, with the standard raw coal containing
20 percent ash and 3.5 percent sulfur, the loss of availability would be
20.0 + 3.5 - 17.5 =6.0 percent.
The incremental cost of replacing power for a 500-MW boiler would be
500,000 kW x 8760 h/yr x (0.06 r 2) x $0.01/kWh = $l,314,000/yr.
Cleaning of coal for this boiler to 10 percent ash and 2.4 percent sulfur,
would eliminate the availability loss and would yield a savings of
$1,314,000 per year. At a capacity factor of 70 percent, this translates to
a benefit of
$l,314,000/yr x 1000 mills/$ -r (500,000 kW x 8760 h/yr x 0.7)
= 0.43 mills/kWh.
This is equivalent to $1.02 per ton of cleaned coal, or $0.14 per ton of
cleaned coal for each percent of availability that must be replaced.
An earlier PEDCo analysis of operating data for TVA showed that the
number of forced outages of specific units correlated well with properties
of the coals fired on those units. This work is summarized in Appendix D.
Additional published data (Phillips 1979) relate forced outage rates to coal
ash content. Figure 6 shows that the annual forced outage rate of the TVA
system has closely paralleled trends in average coal ash content over a
15-year period. The Electric Power Research Institute (EPRI) is currently
34
-------
10.0 -r 20 -r
7.5-1- 18 -f
0.0 -J-
o>
u
5.0- 16 -
u
0>
O-
UJ
tD
o
1/1
tt
o
£ 2.5-h 14 -h
FORCED
OUTAGE
RATE
% ASH
12
1963 65 67 69 71 73
FISCAL YEAR
75 1977
Figure 6. Annual forced outage rates as a function of coal ash content.
35
-------
investigating methods of improving plant availability, with a near-term goal
of increasing availability by 2 percent. They expect that this 2 percent
increase will be realized by reducing tube failures, fouling, slagging, and
inadequacies of boiler control system. Further, they estimate that tube
failures in the waterwall sections, economizers, and superheat portions of
the boiler account for approximately half of total losses of boiler avail-
ability.
The availability of a boiler-turbine system is a function of the
individual availabilities of the boiler and of the turbine. If the two
component availabilities were independent, system availability would be the
product of the component availabilities. The component availabilities are
not independent, however. Scheduled outages are frequently set for main-
tenance of both units, and if one unit is forced out of service, the main-
tenance crews are likely to take advantage of the outage period to repair or
maintain both components.
Data in Figure 7 show a downward trend in availability at large coal-
fired power plants over the period from 1967 through 1976 (EEI 1977). In
that 10-year period, the average availability of units larger than 400 MW
decreased from -81.5 percent to 72.5 percent. Capacity of these units
currently totals more than 50,000 MW, so any improvement in average avail-
ability would lead to a substantial increase in usable domestic utility
capacity.
Table 10 shows additional availability data for 1046 fossil-fuel-fired
units in 119 utility systems (EEI 1977). Although these data include sub-
stantial numbers of gas-fired and oil-fired units, they show clearly that
the boiler itself is by far the largest contributor to the unit forced
outage rate and to operating unavailability of the generating unit. The
boiler is responsible for about 64 percent of the total forced outage rate,
whereas the turbine, condenser, and generator are responsible for only 22,
2, and 7 percent, respectively. A similar tabulation of data on coal-fired
boilers only would almost certainly show an even higher contribution of the
boiler to system outage rate. Thus it is concluded that total system avail-
ability is related principally to boiler availability and that improvements
in boiler availability will be reflected largely in terms of available
system generating capability.
TABLE 10. COMPONENT AND COMPOSITE FORCED OUTAGE RATES AND
AVAILABILITY OF FOSSEL-FUEL-FIRED UNITS, 1967-1976 (EEI 1977)a
Boiler
Turbine
Condenser
Generator
Other
Unit
Forced outage rate, %
3.8
1.3
0.1
0.4
0.4
5.9
Availability, %
88.7
92.8
97.0
95.9
97.3
84.5
alncludes 1046 boilers in 119 utility systems plants.
36
-------
o>
u
O)
ex
CD
100
90
80
0.
O
70
60
50
67 68 69 70 71 72 73 74 75 76
YEAR OF OPERATION
Figure 7. Yearly operating availability of
coal-fired units 400 MW and above (EEI 1977)
37
-------
The utilities have considerable incentive to improve the availability
of these units, and because so many forced outages are fuel-related, the
beneficiation of fuel by PCC may have special merit.
A forced outage does not always incur an economic penalty. For
example, a utility may have several boilers for which operating costs are
similar. -Thus if one boiler is forced out of service when electrical demand
is not at a peak, another boiler can be placed in service at little or no
incremental cost.
It should be pointed out also that an improvement in availability may
not have significant value if a utility has no problems in meeting peak
power requirements. Most utilities maintain only minimal reserve capacities
that are prescribed by the Federal Power Commission in order to keep utility
costs as low as practical. Thus, nearly all utilities have some difficulty
in meeting peak load requirements, and availability is an important consid-
eration. All major utilities load and unload their units according to an
economic dispatch system. That is, when the electrical demand on the
generating system increases, the instantaneous demand is met by the unit
that can do so at the least incremental cost within the system. Generally,
this means that t.^e unit with the best heat rate within the system is given
the incremental load if that unit is not already operating at capacity.
Thus, the economic dispatch system uses a unit with a poor heat rate only as
a last resort, and an improvement in availability of that unit would have
value only to the extent that the unit could help to supply incremental
power in meeting peaking requirements. The upper-limit case would be that
of a boiler in such demand that every increment in availability could be
economically utilized. In such a case the value of the increased avail-
ability would be the incremental cost of alternative power, the need for
which is obviated by the enhanced availability of the boiler. One approach
to estimating this value is to base it on the revenue needed to capitalize
equivalent new boiler capacity, neglecting operating and maintenance costs
because they must be incurred in either case. By use of the estimating
technique presented in Appendix C, the value of a 1 percent increase in
availability of a 1000-MW boiler operating at a capacity factor of 70
percent would be the revenue requirements to capitalize 10 MW of capacity,
or about $2.3 million per year (Foster 1975). This is equivalent to about
$0.90 per ton of cleaned coal for each percent increase in availability.
The true worth of increased boiler availability may vary considerably,
depending on the calculation method. If the greater availability reduces
the need to purchase emergency power from another utility, the benefit may
be even higher than $0.90 per ton of cleaned coal.
A further consideration is that many utilities maintain oil-fired gas
turbines to meet peaking power requirements. These turbines are very expen-
sive to operate because of high fuel costs. Where an increase in avail-
ability of a coal-fired unit can be used to generate part of the peaking
power that would otherwise have to supplied by gas turbines, the value of
the increased availability can be related to the cost differential between
coal and oil; at a fuel cost differential of $1.00 per million Btu, the
benefit is equivalent to 10 mills for each kWh that can be generated by coal
38
-------
Instead of oil. Thus the value of the greater boiler availability that
results from burning cleaned coal can be expressed in terms of the amount of
gas turbine power the boiler can displace. As as example, if it is assumed
that PCC will enable a boiler to supply enough peaking power to increase its
capacity factor from 60 percent to 70 percent, and if this peaking power .is
generated with coal that costs $1.00 per million Btu rather than with gas
turbine fuel that costs $2.00 per million Btu, the savings is $3.43 per ton
of cleaned coal, or $0.34 per ton of cleaned coal for each percent of avail-
ability that is utilized. The benefit limit is uncertain, but values of
these magnitudes seem likely.
The degree of enhancement of boiler availability is much more difficult
to estimate than the value of the availability. It seems unlikely that coal
cleaning would enhance the availability of all boilers. On the other hand
many boilers are unavailable a high percentage of the time, and because a
large percentage of forced outage is fuel-related, it seems likely that en-
hancement of availability by PCC may increase capacity factors of most
boilers by 1 to 15 percent. With such an increase in capacity factors, a
conservative range of coal cleaning benefit would be from about $0.30 per
ton of cleaned coal to $5.00 per ton of cleaned coal, based on the figure
cited above, i.e., $0.34 per percent of availability utilized. With the
standard coal (20 percent ash, 3.5 percent sulfur), which TVA experience
indicates would produce a 6 percent loss in boiler availability, replacement
of half of the unavailable power at an average value of $0.62 per ton of
cleaned coal [($0.90 + 0.34)/2] would yield a savings of about $1.90 per ton
of cleaned coal.
4.2.3 Boiler Efficiency
Most companies report net generating unit efficiency, i.e., after
deducting the power required to run the generating plant. Three principal
components are factored into the generating system efficiency: the boiler,
the turbine, and the generator. Typical boiler efficiency is about 85
percent, turbine efficiency is about 40 percent, and generator efficiency is
about 95 percent. On that basis the efficiency of a generating system would
be
0.85 x 0.40 x 0.95 x 100 = 32.3 percent = 0.323 kWhe/kWht
where subscripts e and t denote electrical and thermal energy equivalents,
respectively. System heat rate would be
(3413 Btu/kWht)/(0.323 kWhg/kWht) = 10,600
Losses in boiler efficiency are typically distributed as shown in
Table 11.
39
-------
TABLE 11. TYPICAL BOILER EFFICIENCY LOSSES
(percent)
Dry gas
Hydrogen and fuel moisture
Air moisture
Unburned carbon
Radiation
Other
Total
5.2
4.4
0.2
0.5
0.3
1.8
12.4
The efficiency of a boiler with such losses would be
100 - 12.4 = 87.6 percent
which agrees well with the 85 percent figure given above. The various effi-
ciency loss categories are discussed briefly.
Efficiency losses attributable to dry gas occur because all of the heat
in the boiler exhaust gases cannot be used to generate steam. Typically,
the boiler exhaust gas temperature is maintained at about 250°F. Reducing
the temperature 'would increase the boiler efficiency but for practical
reasons involving materials of construction and design limitations, the
temperature of the exit gas must be kept above the dew point of the flue
gases. The dew point depends primarily on the concentration of sulfur
trioxide in the gas, which is a function of the sulfur content of the fuel,
and on the moisture content of the flue gas. Because PCC reduces the fuel
sulfur while maintaining a relatively constant moisture content, the net
effect is to lower the dew point, theoretically allowing operation at a
lower stack gas temperature and at higher efficiency. The change in dew
point, however, is typically too small to be significant. Calculations in
Appendix E show that coal cleaning may lower the exhaust gas dew point by
about 10°F, but that this yields only a 0.1 percent improvement in system
efficiency.
The efficiency of a boiler is also influenced by the operator's ability
to fine-tune it. Boiler operators traditionally accommodate fuel vari-
ability by adjusting the boiler for operation while burning the worst
expected fuel. With less variability in fuel quality, the boiler can be
adjusted closer to stoichiometric conditions. It then requires less excess
air and operates more efficiently.
Table 12 illustrates some of the benefits attainable by reducing excess
air requirements as a result of PCC. The values are based on an exhaust gas
C02 content of 15 percent and on the example coal with a moisture content of
4 percent. The data show that PCC can reduce the dry gas efficiency loss in
a boiler by about 0.3 percent. The basis of the effect is that volatile
matter in the cleaned coal increases as a result of reduction of ash content
(De Lorenzi 1957).
40
-------
TABLE 12. EFFICIENCY OF RAW AND CLEANED COAL
Heat content, Btu/lb
Sulfur, %
Ash, %
Moisture, %
Fixed carbon, %
Volatile matter, %
Air, lb/106 Btu
Dry gas efficiency loss, X
Raw coal
10,670
3.5
20
4.0
52
24
950
5.2
Cleaned coal
12,000
2.4
10
4.0
59
27
935
4.9
Boiler efficiency losses from hydrogen and fuel moisture occur because
moisture in the boiler exhaust gas cannot be condensed to liberate latent
heat. Each pound of water in the exhaust gas represents 1000 Btu of latent
heat that diminishes boiler efficiency. Moisture in the exhaust gas is a
function of moisture in the fuel and in the combustion air, and of the
hydrogen content of the fuel. Coal cleaning can significantly affect the
fuel moisture. If PCC increases the coal moisture content to any extent,
the increase will be reflected in loss of boiler efficiency.
Since it enters the boiler in the vapor state, moisture in combustion
air does not cause a latent heat efficiency loss. It is heated in the com-
bustion process, however, and does account for a slight efficiency loss.
The only effect of PCC on such a loss would be to provide greater uniformity
so that addition of excess air (and accompanying moisture) could perhaps be
reduced slightly.
Carbon losses from incomplete combustion are principally a function of
particle size distribution of the coal and of variations in air-fuel condi-
tions with time and at various locations within the furnace. It is unlikely
that coal cleaning would have any measurable effect on such losses. The
moisture and ash content of the cleaned coal might affect pulverizer perfor-
mance, which would influence carbon loss, but we have no data that document
the magnitude of such an effect.
Thermal radiation from the boiler, ductwork, and boiler piping leads to
a reduction in boiler efficiency. These relatively small losses are a
function of the condition of the boiler, Its insulation, and the ambient
temperature; therefore it is not expected that coal cleaning would influence
these losses.
Other losses include heat losses in bottom ash and fly ash and in
boiler leakage. Coal cleaning may reduce these losses slightly because it
reduces the ash content significantly. Coal cleaning can moderate the
slagging and fouling associated with high-ash coals so that less soot
blowing is needed and heat transfer is enhanced, increasing the net effi-
ciency of the boiler system.
41
-------
Thus it appears that potential increases in boiler efficiency by PCC
are limited to those that can be realized by lowering stack temperature (0.1
percent) and by reducing excess air (0.3 percent). At a fuel cost of $1.00
per million Btu ($24.00 per equivalent ton of cleaned coal), the value .of
higher efficiency in terms of lower fuel consumption is
(0.4/85) x $24/ton = $0.11 per ton of cleaned coal
In conclusion, it is estimated that the potential benefit of coal
cleaning through increases in boiler efficiency is probably in the range of
$0.05 to $0.25 per ton of cleaned coal, with a typical value around
$0.10 per ton.
4.2.4 Boiler Capacity
Effective increases in boiler capacity allow the boiler system to meet
more of the future demands with existing equipment and thus postpone the
date when new equipment must be put into service. The benefit is that power
is produced in older, fully amortized plants rather than in a new plant.
The utility can retain its accumulated capital longer and therefore can
realize the benefit of income derived from the unspent capital. The benefit
is somewhat negated by inflation, in that both the cost of money and the
cost of new construction will increase with time and a new plant must be
built eventually.
Very little can be done to increase the capacity of a coal-fired boiler
beyond its design capacity, but often changes can be made to restore a
boiler to its rated capacity after it has been derated. Some of the reasons
for derating a boiler, mentioned elsewhere, include limitations of the pul-
verizer and ash handling system and capacity of the pollution control
equipment. Sometimes a boiler must be derated because of operating problems
associated with a particular fuel. Slagging and fouling are problems in
this category.
Slagging is the accumulation of molten or tacky deposits on the
surfaces of heat exchange components that are exposed to radiant heat. It
is caused by reactions that occur when the mineral matter is heated above
some critical temperature, so that a liquid phase is produced in a portion
of the material. Fouling is the accumulation of deposits, normally by
desublimation and sintering, on heat exchange components in the convection
passes (gas passes containing heat exchange surfaces that cannot "see" the
furnace, so that the heat exchange is primarily by convection) at
temperatures below the fusion temperature of any of the ash constituents.
The slagging and fouling properties of various coals are each affected
differently by PCC. In general PCC causes only a slight change in the
overall ash composition of coal and in its slagging and fouling properties.
42
-------
The expected effects of coal cleaning on slagging and fouling are:
0 A change In ash fusion temperature because of changed composi-
tion. The direction of change cannot be predicted without
knowledge of coal mineral content.
0 A reduction In the Iron content of the ash, making the coal
less susceptible to variations in excess air. Good control of
magnetite losses to the coal is required.
0 A reduction in overall ash content that reduces slagging and
fouling and makes the use of additives more efficient.
0 Removal of soluble sodium, which reduces slagging and fouling.
It is believed that the net effect of these changes is small.
Whatever influence coal cleaning has on boiler capacity is extremely
site-specific. In most cases PCC probably will not affect boiler capacity.
In some cases, however, PCC can rectify conditions that would cause rather
severe deratings. In such cases this benefit alone is probably sufficient
to justify coal cleaning. For example, where a 1000-MW boiler that had been
derated 10 percent because of slagging or fouling could be restored to capa-
city by cleaning the coal, the benefit could be equivalent to the revenue
needed to capitalize 100 additional megawatts of capacity. At a cost of
$1000 per kW and an amortization period of 25 years, and with various other
input parameters described in Appendix C, the annual savings would be $23.3
million per year (Foster 1975). At a 70 percent capacity factor for a
1000-MW boiler, the savings is 3.8 mills per kWh, equivalent to about
$9.00 per ton of cleaned coal. This probably represents an upper limit for
potential savings. In the typical case no capacity Increase would be
expected.
4.2.5 Boiler Design
Many features of a boiler designed to burn physically cleaned coal may
differ from those of a boiler designed to burn raw coal. Differences in
ash, sulfur, and moisture content and in ash composition should all influ-
ence the design. Most of the changes to accommodate cleaned coal should
make the boiler less expensive. Possible differences that have been
suggested in an ongoing analysis by EPRI are boiler size, tube spacing, soot
blowing equipment, and auxiliary power requirements. This EPRI study also
includes a detailed cost analysis that 1s being conducted with the
assistance of a major boiler manufacturer.
4.3 COST SAVINGS IN EXHAUST GAS HANDLING AND CLEANING EQUIPMENT
4.3.1 Collection Efficiency of Pollution Control Equipment
The particulate collection efficiency of a fabric filter collector will
not be affected by the use of cleaned coal, but the collection efficiency of
43
-------
an ESP may be impaired as a result of higher fly ash resistivity. Burning
cleaned coal, however, would reduce the particulate loading to the ESP; thus
the efficiency needed for compliance with a given emission regulation would
be lower.
The ESP efficiencies needed to meet particulate regulations of 0.1 and
0.3 Ib per million Btu were calculated for a new boiler burning the raw and
cleaned coals that are used as a standard throughout this report. Table 13
gives results of the calculations, shown in detail in Appendix F. The
values indicate that cleaned coal requires a slightly smaller ESP than does
raw coal to meet a given particulate regulation. Depending on the equation
selected for calculating the required specific collection area (SCA) and
depending on the particulate regulation, the size of the ESP needed with the
standard cleaned coal is 76 to 95 percent of that needed with the raw coal.
The lower ash content of the example cleaned coal offsets the relatively
slight increase in resistivity associated with its lower sulfur content.
TABLE 13. COMPARISON OF ESP REQUIREMENTS
FOR BOILERS BURNING RAW AND CLEANED COAL
Parameter
Btu/lb
Ash, percent
Sulfur, percent
Uncontrolled particulates, lb/106 Btu
Estimated resistivity, ohm cm x 109
Particulate regulation, lb/106 Btu
Required particulate efficiency,
percent
SCA (Deutsch), ftVlOOO acfm
SCA (Matts-Ohnfeldt), ftVlOOO acfm
Raw coal
10,670
2.0
3.5
16.04
4.1
0.1 0.03
99.38 99.81
163 200
207 314
Cleaned coal
12,000
10
2.4
7.08
16
0.1 0.03
98.59 99.58
148 190
158 260
Thus it appears that where cleaned coal is to be burned, the required
size of an ESP for a new boiler may be lower by 5 to 25 percent than if raw
coal were burned. The size difference would be reflected in the capital
cost of the ESP, but not significantly in operating costs. Given that an
ESP represents about 5 percent of the capital cost of a power plant, a
benefit can be calculated as the savings associated with the capital savings
for the ESP. With a 1000-MW plant, a 10 percent savings in the cost of the
ESP, and a base-case ESP cost of 5 percent of the total plant cost, the
estimated benefit is $0.45 per ton of cleaned coal. This value agrees
reasonably well with a published estimate of $0.84 per ton of cleaned coal
(Buder 1979).
In conclusion, it appears that PCC would produce no tangible ESP
benefit for most existing plants, but might slightly enhance ESP perfor-
mance. New plants might realize ESP capital savings equivalent to $0.25 to
$1.00 per ton of cleaned coal.
44
-------
4.3.2 FGD Requirements
In certain cases PCC can completely eliminate the need for an PCD
system. Examples include the Homer City coal cleaning plant of the Pennsyl-
vania Electric Company and the Camp Breckinridge cleaning plants for TVA.
In other cases, however, PCC will reduce FGD requirements only slightly. As
an example, consider a 500-MW coal-fired power plant burning our example raw
coal with a heat content of 10,670 Btu/lb, 20 percent ash, and 3.5 percent
sulfur. Net heat rate is 10,000 Btu/kWh. Coal cost is $21.34 per ton
($1.00 per 106 Btu). The equivalent raw coal S02 content is 6.56 Ib S02 per
million Btu. When this coal is cleaned at an 80 percent weight yield and a
90 percent Btu recovery, the cleaned coal properties are 12,000 Btu/lb,
10 percent ash, and 2.4 percent sulfur. If 95 percent of the sulfur in the
cleaned coal is emitted as S02 when it is burned, emissions would be 3.8 Ib
S02 per million Btu.
If the power plant were constrained to emit no more than 15 percent of
the raw-coal sulfur into the atmosphere on a 30-day average, the equivalent
emission standard would be 0.98 Ib S02 per million Btu. This constraint
could be met with raw coal by use of an FGD system with a nominal 84.2
percent control efficiency. If an 85 percent efficient FGO system were used
in conjunction with the cleaned coal, 87 percent of the stack gas would
still have to be scrubbed to comply with the limit of 0.98 Ib S02 per
million Btu. The other 13 percent of the stack gas could bypass the
scrubber.
Given the opportunity, a utility using raw coal probably would not
bother to bypass a small percentage of its stack gas around an FGD system
because the bypass gas would not be sufficient to provide stack gas reheat
for the system. Most scrubber systems reheat stack gas to about 175°F in
order to minimize corrosion and to suppress formation of exhaust gas conden-
sate plumes. A bypass ratio of approximately 30 percent would be needed to
provide this degree of reheat without auxiliary heaters. Moreover, because
the quality of raw coal is highly variable, most utilities would scrub all
the exhaust gas to help ensure compliance with the emission standard on a
required 30-day average.
A utility burning cleaned coal, however, might take advantage of the
opportunity to bypass 13 percent of the flue gas around the scrubber. Coal
variability and the design of an FGD system to ensure compliance with
emission regulations are issues of particular interest at present. With a
fixed emission ceiling, an FGD system should be designed to control to that
limit when the worst expected coal is being burned. Reducing the
variability of coal quality by PCC would reduce the need for overdesign or
conservatism in FGD design and thus reduce the total FGD system costs. One
report indicates that PCC reduces the relative sulfur variability in coal by
approximately half, an estimate based on data from 58 different coal
sources (Versar 1979).
Values for our example raw and cleaned coals were used in computerized
cost programs for FGD and PCC systems to estimate the costs of two stra-
tegies to attain the S02 emission requirements described above:
45
-------
Use of raw coal and a lime FGD system to scrub 100 percent of the
boiler flue gas.
Use of cleaned coal and a lime FGO system to scrub 87 percent of the.
boiler flue gas, bypassing 13 percent of the flue gas to aid in
meeting reheat requirements.
supporting calculations appear in Appendix B; Table 14 shows salient data.
TABLE 14. FGD COSTS FOR RAW AND CLEANED COAL SYSTEMS
Coal HHV, Btu/lb
Coal ash, percent
Coal sulfur, percent
Flue gas bypass, percent
Total capital cost, $/kW
Total annual cost, mills/kWh
Raw coal
system
10,670
20
3.5
0
123
7.6
Cleaned coal
system
12,000
10
2.4
13
102
5.9
The principal savings with the cleaned coal system result from a reduc-
tion in the size of the required FGD system, and from lower requirements for
reheat, reagents, and sludge handling and disposal. The PCC benefit is
estimated to be the difference between annual costs of the two systems:
7.6 - 5.9 = 1.7 mills/kWh
which is equivalent to about $4.08 per ton of cleaned coal.
The PCC benefit is a function of the allowable bypass ratio; as the
ratio increases, PCC becomes increasingly cost-effective. Figure 8 shows
the interrelationships among S02 emission regulations, PCC sulfur removal
efficiency, FGD efficiency, and the allowable bypass percentage. At an S02
emission control level of 90 percent, the allowable bypass ratio cannot
exceed 16 percent and approaches that value only as PCC removal efficiency
exceeds 40 percent and FGD efficiency approaches 95 percent. At lower S02
control levels, the allowable bypass fraction becomes progressively higher
as other parameters remain constant. For example, at an S02 regulation
level of 80 percent, FGD efficiency of 95 percent, and PCC sulfur removal
efficiency of 30 percent, the allowable bypass ratio is about 25 percent.
The bypass ratio at which auxiliary reheat requirements are eliminated
completely is mainly a function of the boiler exhaust gas temperature and
the required reheat temperature. After leaving the boiler, gases are cooled
to about 125°F in the FGD system. At a boiler exhaust gas temperature of
275°F and a required reheat temperature of 175°F, the required bypass ratio
is about 33 percent. Figure 8 shows that when S02 emission regulations are
higher than about the 70 percent level, the allowable bypass ratio cannot be
as high as 33 percent and that some auxiliary reheat will be needed. The
potential elimination of auxiliary reheat is an important benefit of PCC
46
-------
c
QJ
u
i-
O)
Q.
I/O
«£
O-
100 H
90-
EACH ENVELOPE BOUNDS
SCRUBBER EFFICIENCIES
FROM 85 TO 95 PERCENT,
30
20
10
0 10 20 30 40 50
SULFUR REMOVED BY PCC, percent
Figure 8. Effect of PCC sulfur removal efficiency on
allowable FGD bypass under various S02 removal regulations
47
-------
both because of economics and because the maintenance of reheat equipment
has been particularly troublesome at many FGD installations.
In conclusion, the typical PCC benefit associated with lower FGD
requirements may be on the order of $4.00 per ton of cleaned coal. Parti-
cularly restrictive S02 regulations could reduce this benefit to near-zero,
whereas less restrictive regulations could increase the benefit enough to
offset the total cost of PCC in some cases. At very low levels of S02
regulation the use of PCC could eliminate the need for FGD. Appendix F
shows that the annual cost of FGD to remove 85 percent of the sulfur is 7.6
mills/kWh, equivalent to $18.00 per ton of cleaned coal. The use of PCC
alone could not ensure compliance with an 85 percent regulation, but could
ensure compliance at the level of about 40 percent. Therefore, the upper
limit of the benefit is estimated to be about half of the $18.00, or
$9.00 per ton of cleaned coal.
48
-------
SECTION 5
CONCLUSIONS AND RECOMMENDATIONS FOR FURTHER .WORK
5.1 CONCLUSIONS
The available data show that increased use of PCC has potential for
producing great benefits in terms of reduced costs of power production and
environmental control.
Potential benefits are greatest where maximum reductions in ash and py-
ritic sulfur contents can be attained without excessive loss of coal in the
rejected refuse.---In this study we assume relatively modest reductions of
10 percent in ash and 1.1 percent in pyritic sulfur. The estimated savings
exceed projected costs of coal cleaning in six of eight coal preparation
plants used as a basis for comparison (Table 4). For all six of these
plants, Btu recovery equals or exceeds 90 percent. Because total coal
cleaning costs are highly dependent on Btu recovery, it is vitally important
to consider this factor in any analysis.
One of the most important potential savings is associated with the
reductions in the cost of FGD that can be realized by partial removal of
sulfur by PCC before combustion. At the PCC sulfur removal level assumed
for this study, about 32 pounds of sulfur per ton of raw coal, the savings
in FGD costs achieved by burning clean rather than raw coal is about
$4.00 per ton of cleaned coal. This is the most significant typical
benefit; the total of all of the typical benefits is $7.02 per ton of
cleaned coal. For five of the eight coal preparation plants considered in
this study, sulfur reductions ranged from 18 to 55 pounds of sulfur per ton
of raw coal. Reductions of this magnitude would produce significant savings
in an FGD system designed for a boiler burning cleaned coal instead of raw
coal.
PCC can lead to important savings in boiler operation, especially where
increases in boiler availability or boiler operability can offset shortages
of productive capacity in the system. All of the potential boiler operation
benefits appear to be associated with reductions in ash and sulfur content.
Typical boiler-related savings, based on cleaning the example raw coal to
achieve a 12 percent reduction in A+S, are $2.40 per ton of cleaned coal.
Among the eight coal cleaning plants used as a basis for comparison, reduc-
tions of A+S ranged from 8 to 33 percent. For the five showing greatest
reductions, the values were 20 to 33 percent. These findings suggest that
savings related to boiler operability can be very important where boiler
output is lost because of poor coal quality.
49
-------
Transportation savings appear to be the most certain benefit, except
for mine-mouth power plants; savings are proportional to transportation
costs, but even for relatively long hauls (e.g., transport of western coal)
the transportation benefit is not sufficient to offset the total cost of
coal cleaning.
Although the benefits that might be realized through Increased use of
coal cleaning are apparently great, the data with which to define the extent
of the potential savings are admittedly weak. Additional work to quantify
the potential benefits appears to be much needed.
5.2 RECOMMENDATIONS FOR FURTHER WORK
5.2.1 Calculation of Benefits Based on Published Data
Basic coal washability data can be used to quantify several of the
benefit parameters discussed in this report. Washability data compiled by
the U.S. Bureau of Mines in Report RI 8118 can be used in evaluating those
benefit parameters. Several scenarios should be defined to reflect current
and proposed new source performance standards (NSPS) and best available
control technology (BACT) regulations. Analyses would compare the use of
FGD with the combined use of FGD and coal cleaning so as to determine the
relative effectiveness of the two control strategies at plants subject to
specified restrictions. This study would consist of:
0 Definition of an evaluation methodology
0 Definition of a scenario or scenarios to be evaluated
0 Reduction of 8118 data for evaluation
0 Quantification of benefits for each coal
0 Tabulation and presentation of results and conclusions
0 Extrapolation of potential economic costs and benefits achiev-
able by use of PCC.
5.2.2 Coal Appraisal Research
Research should be directed toward an accurate economic appraisal of
coal, i.e., the evaluation of coal based on the cost impacts of firing it in
a boiler. Bonus-penalty evaluations would be based on such parameters as
ash content, other coal constituents, boiler design, and environmental regu-
lations. Such evaluations would enable a buyer to select the most cost-
effective fuel from among two or more coals. At present most coals are
selected on the basis of meeting certain minimum specifications at the
lowest price per Btu, or even worse, at the lowest price per ton. Adverse
or beneficial effects on boiler operation generally are not considered.
Following would be the principal tasks of the evaluation:
50
-------
0 Develop a model that relates boiler operating and maintenance
costs to fuel quality.
0 Develop a formula for calculating net fuel cost in mills/kWh.
0 Project the potential economic effects of such a selection
procedure.
5.2.3 Research to Verify Effects of Coal Quality on Boiler Operation
Research should be carried out to verify the effects of coal quality on
boiler operation that are discussed in this study. Significantly different
coals would be burned in several carefully selected boilers considered
identical or nearly identical in construction, condition, and performance.
Extensive tests would be run to allow documentation of coal quality effects
over a relatively long term (3 years). Participation by the boiler owners
would be necessary.
Following are potential program tasks:
0 Attempt to locate substantially similar boilers firing coal of
different quality. This would entail contacts with boiler
manufacturers and boiler owners.
0 Obtain data from boiler operators concerning coal quality,
boiler duty, maintenance practices, performance, and other
aspects of boiler operation.
5.2.4 Boiler Derating Study
Field methods being used to derate boilers to accommodate poor coal
quality or particular coal idiosyncrasies should be investigated. We are
relatively certain that many boilers are derated because of pulverizer
limitations or are being operated in a special manner for firing of sub-
standard coals. A survey to determine the extent of these practices and the
economic or capacity penalties associated with such off-design operation
would be extremely beneficial in further quantification of potential coal
cleaning benefits. Among PEDCo's utility contacts are several that we
believe would be willing to discuss their coal-related boiler operating
problems and their attempts to use coal that the boilers were not designed
to burn. The study would consist of:
0 An estimate of the proportion of utility boilers that are de-
rated to accommodate variable or inferior coal quality
0 An estimate of the number of boilers that are pulverizer-
limited
0 A determination of the economic consequences of off-specifica-
tion operation and a projection of capacity improvements and
other economic benefits that could be achieved by upgrading
coal
0 Establishment of relationships of these factors and the poten-
tial use of coal cleaning
51
-------
REFERENCES
Babcock & Wilcox. Steam - Its Generation and Use. 37th Edition, B&W,
New York, 1960, pp. 17-19.
Buder.M. K. , et al. The Effects of Coal Cleaning On Power Generation
Economics, American Power Conference, 1979.
Cavallaro, J. A., et al. Sulfur Reduction Potential of the Coals of the
United States. U.S. Bureau of Mines, RI 8118, 1976.
DeLorenzi, 0. Combustion Engineering. Combustion Engineering, Inc,
New York, 1957.
EEI. Report on Equipment Availability for the Ten-Year Period 1968-1977. A
report of the equipment availability task force of the Prime Mover's Commit-
tee, of the Edison Electric Institute. New York, December 1977.
Foster Associates, Energy Division. Tennessee Valley Authority's S02Compli-
ance Plan: Coal Availability. U.S. Environmental Protection Agency,
Region VI, September 22, 1977.
Hall, E. H., et al. The Use of Coal Cleaning For Compliance With SCL
Emission
Regulations. Draft report from Battelle Columbus Laboratories to U.S. EPA.
1979.
Hoffman, L., S. J. Aresco, and E. C. Holt, Jr. Engineering/Economic
Analyses of Coal Preparation with S02Cleanup Processes for Keeping Higher
Sulfur Coals in the Energy Market. U.S. Department of Energy, Washington,
D.C., November 1976, pp. 236-241.
Holt, E. C., Jr. An Engineering/Economic Analysis of Coal Preparation Plant
Operation and Costs. Final report to U.S. DOE by the Hoffman-Muntner Corp.,
Contract No. ET-75-C-01-0925, Silver Springs, Md., February 1978
Kilgroe, J. D. Combined Coal Cleaning and FGD. U.S. Environmental Protec-
tion Agency, 1979.
McGraw, R. W. , and J. G. Janik. MCCS--Implementation at Homer City. Pro-
ceedings, Third Symposium on Coal Preparation, NCA/BCR Coal Conference,
Louisville, KY., October 1977. pp. 107-122.
Phillips, P. J. , and R. M. Cole. Economic Penalties Attributable to Ash
Content of Steam Coals. AIME Annual Meeting, New Orleans, February 1979.
Sarikas, R. H. Procedure for Converting Utility Investment and Expense Into
Annual Revenue Requirements. Foster Associates, Inc., Decatur, 111.,
February 1975.
52
-------
REFERENCES (continued)
Spaite, P. W., et al. Environmental Assessment of Coal Cleaning Processes:
Technology Overview. Draft report from Battelle Columbus Laboratories to
U.S. EPA, 1979.
Strauss, W. Industrial Gas Cleaning. Pergamon Press, Oxford, 1966.
Versar, Inc. Special Technical Report: Effect of Physical Coal Cleaning
Upon Sulfur Variability. Draft report, EPA contract No. 68-01-2199,
Task 600, U.S. Environmental Protection Agency, IERL, Research Triangle
Park, N.C., January 1979.
Zimmerman, O.T., and I. Lavine. Psychrometric Tables and Charts. Industrial
Research Service, Inc., Dover, N.H., 1964.
-------
APPENDIX A
LITERATURE REVIEW
54
-------
Anson, D. Availability of Fossil-Fired Steam Power Plants. EPRI FP-422 SR,
Palo Alto, California, June 1977.
The availability of 600 MW and larger generating units is compared with the
availability of smaller plants. The annual present worth of the outage costs
is estimated. The annual present worth of increasing the availability of the
600 MW and greater generating units to that of the smaller units is also
estimated. The report concludes that increasing the availability of 600 MW
and greater units from 73 percent to 80 percent has an annual present worth of
$150 to 200 million.
Babcock and Wilcox. Steam - Its Generation and Use. 37th ed, New York, 1960.
This standard reference on boilers and steam generation was first issued in
1879 and has been revised numerous times. The book contains chapters on
subjects as diverse as fuels, principles of combustion, stacks and ducts,
fans, heat transfer, fluid dynamics, energy cycles, boilers and related equip-
ment, coal preparation and storage, stokers, pulverizer equipment, fuel ash,
metallurgy, and nuclear power.
This book is prepared and published by B&W, one of the largest boiler manufac-
turers in the United States. Until recently the book was distributed gratis
to senior mechanical engineering students at universities across the country.
Bechtel Corporation. Environmental Control Implications of Generating Elec-
tric Power from Coal. 1977 Technical Status Report. Appendix A, Parts 1
and 2. Coal Preparation and Cleaning Assessment Study. Prepared for U.S.
Department of Energy, Division of Environmental Control, Technical Assistance
Section for the Environment.
This report is a state-of-the-art and effectiveness study of physical coal
cleaning for S02 control. The report discusses how PCC changes the properties
of coal, and how these changes affect coal utilization. Additionally, wash-
ability data and coal reserves data are integrated into a common data base.
Bogot, A., and R. P. Hensel. Considerations in Blending Coals to Meet S02
Emission Standards. Presented at the NCA/BCR Coal Conference and Expo. Ill,
October 19-21, 1976.
The coal parameters that must be considered for effective coal blending are
discussed. The significance of the coal properties and examples of the chang-
es that result from coal blending are presented. The possible impacts on the
boiler resulting from the important coal properties are given. A significant
conclusion of the report is that the properties of blended coals are often
worse than those of the individual coals used in the blend.
55
-------
Buder, M. K., et al. The Effects of Coal Cleaning on Power Generation Econom-
ics. Presented at the American Power Conference, 1979.
This paper describes the results of seven hypothetical case studies of the
effects of coal cleaning upon various components of electric generating sy-
stems. A representative coal along with the costs to clean the coal are
described for each of the seven cases, and three different levels are devel-
oped for each. The benefits of coal cleaning are estimated in the following
areas in each case:
Coal transportation
Power generation
Coal handling
Pulverizers
Steam generator
Ash handling
Particulate removal system
Flue gas desulfurization
Sludge handling and disposal
The paper concludes that the results of this study cannot be broadly applied
because of the heterogeneity of coal. The paper also indicates that some
pertinent data are not available.
Burbach, H. E. , et al. Compatibility Between Furnaces and Fuels Conducive to
High Boiler Availability. Power, December 1977, pp. 41-46.
The report discusses the more important fuel properties and their impact on
boiler design. The relative size of the furnace for various fuels is shown.
The report supports the theory that boiler manufacturers have the ability to
design a universal boiler capable of burning any fuel. It is impractical to
do so, however, because of the widely varying fuel properties and the degree
of overdesign and/or inability to optimize the boiler design.
-------
Cavallaro, J. A., et al. Sulfur Reduction Potential of the Coals of the
United States. U.S. Bureau of Mines Research Investigation 8118, 1976.
This report gives results of a washability study of 455 raw coal channel
samples with special emphasis on sulfur reduction. These raw coals contained,
on the average, 14.0 percent ash, 1.91 percent pyritic sulfur, and 3.02 per-
cent total sulfur. Complete washability data are presented for each sample
processed. A statistical evaluation is included for coal beds from which more
than 10 samples were collected and for the geographical coal producing re-
gions. A graphical summation is given for the coal producing regions and
selected coalbeds. A similar statistical evaluation is included showing com-
posited data interpolated at Btu recovery levels of 50, 60, 70, 80, 90, and
100 percent. Graphical summations are given for the various coal producing
regions. Generally, significant sulfur reduction is achieved if the coals are
crushed to a finer size and the higher specific gravity increments are re-
moved. If a 50 percent Btu recovery were acceptable, then 32 percent of the
samples tested could be upgraded to meet the current EPA standard of 1.2 Ib of
S02 emission per million Btu when crushed to 14-mesh top size and separated
gravimetrically.
Cole, R. M. Economics of Coal Cleaning and Flue Gas Desulfurization for Com-
pliance with Revised NSPS for Utility Boilers. Presented at the U.S. Environ-
mental Protection Agency Symposium on Coal Cleaning to Achieve Energy and
Environmental Goals, Hollywood, Florida, September 11-15, 1978.
The report presents three comparative case studies. Each case compares the
economics of a combined PCC-FGD system to an FGD system for S02 control. The
benefits of PCC identified are:
Transportation cost savings
Maintenance cost savings
Ash disposal cost savings
Peaking capacity improvement
Rated capacity improvement
Availability improvement
The report concludes that PCC is a cost-effective S02 control strategy, re-
gardless of S02 emission requirements.
Colving, T. , and V. P. Smith. A Survey of Econometric Models of the Supply
and Cost Structure of Electricity. EPRI EA-517-SR, Palo Alto, California,
March 1978.
The report reviews a large number of economic models of the electric power
industry. A commentary and summary of each of the models reviewed in the
report are given.
-------
De Lorenzi, 0. Combustion Engineering. Combustion Engineering, Inc., New
York, 1957.
This reference book on combustion and steam generation is published by a
leading U.S. manufacturer of boiler equipment. The book covers a variety of
topics such as coal production, stokers, pulverizers, pulverized fuel burners,
furnaces, burners, fluid cycles, A.S.M.E. boiler construction code, steam gen-
erators, superheaters and desuperheaters, steam purification, feedwater, test-
ing of steam generating units, fans and chimneys, instruments, fly ash drying
and incineration, and operation and maintenance of equipment.
DeRienzo, P. P., et al. Comparative Economics of Sulfur Removal from Coal in
Electric Power Generation. Presented at the 4th Annual International Confer-
ence on Coal Gasification, Liquefaction, and Conversion to Electricity,
August 2-4, 1977.
This report identifies the following coal cleaning benefits:
Transportation savings
Reduced pulverizer and boiler O&M cost
Reduced ash handling.
The report concludes that, for the case studies presented, nominal washing in
combination with FGD was consistently more economical than FGD alone. No
evaluation of the coal cleaning benefits is presented.
PeRienzo, P. P., et al. Is Coal Preparation Cost Effective for Sulfur Removal
in Electric Power Generation? Presented at the 85th National Meeting of the
American Institute of Chemical Engineers, June 4-8, 1979.
The benefits of coal cleaning identified in this report are:
Transportation
Reduced pulverizer and boiler O&M cost
Reduced ash handling and disposal
Ho specific methodology for evaluating the benefits is presented. The report
concludes that "...washed coal in conjunction with FGD can be a cost-effective
fuel option for meeting various S02 emission levels, but this depends on the
coal and the S02 emission level to be achieved."
58
-------
DeRienzo, P. P., et al. The Cost of Sulfur Removal from Coal in Electric
Power Generation. Presented at the Miami International Conference on Alter-
nate Energy Sources, December 5-7, 1977.
This report presents a specific case study that evaluates the Impact of .coal
cleaning on the cost of power generation. An eastern coal and a Midwestern
coal are examined. Two levels of coal cleaning are included in the analysis.
Benefits for transportation, boiler O&M cost, and ash handling and disposal
are considered. No specific methods or data on the benefits are identified.
It is concluded that PCC in combination with FGD is a cost-effective method of
achieving various S02 emission levels.
Duzy, A. F. and D. W. Pacer. Low-grade Fuel Influence on Boiler Design.
Presented at the 1978 Joint Power Generation Conference, Session 3, Septem-
ber 10-13, 1978.
The major coal properties that influence boiler design are identified, and
their influences on the boiler design are discussed. The proper use of coal
property data, toge-ther with emphasis on past experience in boiler design and
operation, are considered necessary for successful boiler design. The report
stresses that proper consideration must be given to coal beneficiation. En-
richment of one coal property can cause degradation of others, which can
adversely affect the boiler design.
Edison Electric Institute. The Equipment Availability Task Force of the Prime
Mover's Committee. Equipment Availability for the Ten-Year Period 1968-1977.
The Edison Electric Institute, New York, 1977.
This report compiles current data on component and generating system avail-
ability for member utility participants according to various fuel and unit
size classifications.
Foster Associates. Tennessee Valley Authority's S02 Compliance Plan: Coal
Availability. Draft Report. U.S. Environmental Protection Agency, Region VI,
1977.
This report describes the findings of a study of the availabilty of coal to
TVA within the context of TVA's plan to comply with S02 regulations at each of
its fossil-fired power plants. The report includes a description of the TVA
coal transportation system and indicates certain applicable freight tariffs.
59
-------
Gibbs & Hill, Inc. Coal Preparation for Combustion and Conversion. Final
Report. EPR1 AF-791, Project 466-1, Palo Alto, California, May 1978.
This report is primarily concerned with the direct cost of coal cleaning and
its impact on the cost of utilization. The benefits of coal cleaning examined
are:
Coal taxes
United mine workers (UMW) contributions
Transportation
Coal blending
Handling and storage
Grinding and pulverizing
Ash disposal
Precipitators
Flue gas desulfurization
Unit availability
The coal taxes, UMW contribution, transportation, grinding and pulverizing,
and ash disposal benefits are quantified. Only the transportation benefit is
discussed thoroug-'y. No formulation or methodology is presented that showed
tne net effect of the benefits on the cost of utilization.
Gluskoster, H. J. , et al. Trace Elements in Coal: Occurrence and Distribu-
tion. Illinois State Geological Survey Circular 499, 1977.
This circular presents a very thorough analysis of 172 coal samples. Most of
the samples were from the Illinois Basin. Each sample was analyzed for 60
elements. Most of the samples were face-channel samples. There were usually
multiple samples taken in the various mines. Additionally, the coal seams
were frequently sampled in more than one mine. Some bench samples showing the
vertical variation of the coal were also taken.
Of several conclusions from the data, the most significant one is that the
coal varies radically throughout its matrix.
60
-------
Hall, E. H., et al. The use of Coal Cleaning for Compliance with S02 Emission
Regulations. Draft Report written for Battelle's Columbus Laboratories for
the U.S. Environmental Protection Agency, Columbus, Ohio, 1979.
Results of an overall evaluation of the possible use of coal cleaning as a
means of controlling S02 emissions are presented. Data presented show PCC
economically superior, even when supplemented with flue gas cleaning for final
sulfur removal, to alternative strategies involving the use of low sulfur coal
or the use of flue gas desulfurization alone.
Barriers (technical, institutional, economic, etc.) tending to prevent the
application of physical coal cleaning as a pollution control method are iden-
tified, and programs needed to overcome them are recommended.
Hoffman, L. , et al. Engineering/Economic Analyses of Coal Preparation with
S02 Cleanup Processes for Keeping Higher Sulfur Coals in the Energy Market.
U.S. Department of Energy, Washington, D.C., November 1976. pp. 236-241.
For purposes of this study, higher sulfur coals from the Northern Appalachian
and Eastern Interior Regions were selected since they have been shown to have
reasonable physical cleaning potential. Possible users of these coals in the
electric power generating industry are established, along with the environmen-
tal constraints in their respective localities. This provided a framework
within which to study and compare the economics associated with meeting sulfur
emission standards in two alternative ways. Specifically, the study considers
both new and existing plants using either combined physical cleaning and stack
gas scrubbing or sulfur cleanup exclusively by stack gas scrubbing.
The results of the study indicate that many higher sulfur coals physically
cleaned to a weight yield of 90 percent begin to approach environmental ac-
ceptability. This permits the installation of an economically attractive
partial stack gas scrubbing system to bring the power generating facility into
compliance with existing emissions standards. The economics associated with a
combined approach when compared with the exclusive use of stack gas scrubbing
demonstrate a definite advantage.
61
-------
Holmes, J. G., Jr. The Effect of Coal Quality on the Operation and Mainte-
nance of Large Central Station Boilers. Presented at the Annual AIME Meeting,
Washington, D.C., February 16-20, 1969.
The various aspects of the effect of coal quality on boiler operation are
discussed. Most of the paper relates to general trends and/or discussions of
cause-and-effect relationships of coal quality and boiler operation. The
section on operating and maintenance costs (O&M) provides some specific in-
formation on cost penalties associated with variability in coal quality.
Specific cost information is absent in the other sections of the paper.
Data on the O&M costs at Kingston and John Sevier, two similar TVA plants, are
compared. The fuel data are the average proximate analyses of all fuel burned
at each plant. The O&M costs are an average of the yearly O&M cost per ton of
fuel.
The paper points out that the plants had significantly different capacity
factors and that the capacity factors could cause significant differences in
plant O&M cost. Such differences are difficult to quantify and are not in-
cluded in the analysis. The paper concludes that as coal quality deterio-
rates, O&M costs'increase.
Holt, E. C. , Jr. An Engineering/Economic Analysis of Coal Preparation Plant
Operation and Costs. Report to U.S. DOE by the Hoffman-Munter Corp., Silver
Springs, Maryland, February 1978.
This report presents a discussion of the major physical coal preparation
processes currently available and the equipment used by each process to effect
a separation of the coal from the undesirable constituents (such as ash and
pyritic sulfur). Eight specific examples of a wide range of actual prepara-
tion plants are examined from the standpoint of capital and operating and
maintenance costs to develop a total cost of coal cleaning for each plant.
The preparation plants examined were all operating as of mid-1977 and span a
spectrum of cleaning processes from a relatively simple jig plant to sophisti-
cated circuits utilizing dense medium, froth flotation, and thermal drying.
For the particular plants considered by this study, cleaning costs range from
over $3.00 to nearly $5.00 per ton of clean coal produced. These costs are
especially sensitive to the makeup and performance of the cleaning circuit in
addition to the manner in which it is being operated. In this latter regard,
plant utilization can be a significant factor since it influences the output
over which the fixed costs are amortized. As evidenced by most of the prepar-
ation plants examined, many coal cleaning facilities operate only 30 percent
of the time, thereby experiencing a relatively high capital burden per ton of
clean product. To alleviate this problem, one of the example preparation
plants was designed to include parallel cleaning circuitry with significant
amounts of redundant equipment. Such a plant configuration permits main-
tenance without shutting down the entire facility.
62
-------
Honea, F. I., et al. The Effects of Overfire Air and Low Excess Air on NO
Emissions and Ash Fouling Potential for a Lignite-Fired Boiler. Presented a£
the American Power Conference, April 24-26, 1978.
Test runs at Hoot Lake Station of Ottertail Power Company are reported. The
lowest possible NO levels at a given boiler load are determined. Various
burner configurations are studied to determine burner influence on the fouling
potential of the coals (lignite). The report concludes that burner selection
appears to influence ash fouling potential and that reducing NO emissions by
varying the burner configuration increases the potential for ash fouling.
Isaacs, G. A. Physical Coal Cleaning for Sulfur and Ash Removal. Presented
at the Twelfth Air Pollution and Industrial Hygiene Conference, Air Quality
Management in the Electric Power Industry, January 28-30, 1976.
TVA coals and their washability are discussed. Boiler availability is repre-
sented as a benefit of coal cleaning. The report states that the boiler
availability benefit is intuitive.
Isaacs, G. A., et al. Studies to Define the Role of Coal Cleaning in an S02
Control Strategy for TVA. APCA Paper No. 77-14.4. Presented at the APCA
Annual Meeting, June 20-24, 1977.
The report gives a brief discussion of the various physical coal cleaning
processes. Specific TVA washability data and appropriate emission limits for
the TVA plants are cited. The relationship of the cleaned coal to the appro-
priate TVA plants are discussed. The report concludes that possible applica-
tion of PCC to meet S02 emission requirements are limited, but the number of
applications may be significant.
63
-------
Kilgroe, J. D. Combined Coal Cleaning and FGD. U.S. Environmental Protection
Agency, 1979.
physical coal cleaning (PCC) can be used to attain moderate reductions in the
ash and sulfur levels of the U.S. coals. PCC can thus be used to generate
compliance fuel for the less stringent State and Federal standards governing
fossil fuel fired steam generators. The sulfur reduction requirements and
emission levels that are likely to be specified in the revised New Source
Performance Standards (NSPS) for electric utility boilers will preclude the
USe of coal cleaning as a sole method of complying with these flue gas desul-
•furization (FGD) regulations.
The combined use of physical coal cleaning and flue gas desulfurization
(PCC + FGD) will be the most cost-effective method of complying with emission
regulations, if the reduction in FGD and non-FGD costs that result from using
cleaned coal are greater than the costs of PCC. Reductions in FGD costs by
PCC can result from a reduction in the volume of flue gas treated (partial
scrubbing) or the amount of sulfur removed from the flue gas stream. Reduc-
tions in fuel sulfur variability by PCC can lower design safety margins needed
to ensure compliance for all fuel sulfur values. Non-FGD cost benefits can
result from reduced boiler operation and maintenance costs, reduced transpor-
tation costs, reduced disposal costs, and reduced coal pulverization costs.
Utility boilers that use high sulfur coals and require sulfur removals less
than 75 percent are likely candidates for PCC + FGD. If the revised NSPS for
utility boilers require 90 percent sulfur removal and do not specify an emis-
sion floor, then PCC + FGD may not be competitive with FGD unless there are
substantial non-FGD cost benefits associated with cleaning.
The range of applications for PCC + FGD in small non-base-loaded utility
boilers and industrial boilers may be different from those cited for base-
loaded utility boilers. The differentials between PCC and FGD costs for these
smaller units may result in different optimal solutions for the range of al-
ternative control strategies.
Kohn, H. Capacity Factor Evaluation of Fossil Fired Power Plants. Power
Engineering, October 1978. pp. 56-58.
This article presents EEI data on capacity factors, availability, and forced
outages of selected units. From various analyses the capacity factors and
capacity factor distributions are nearly the same for fossil-fired and nuclear
units. The article concludes that, "the single most effective way to decrease
down time would be to institute a coal benefication program."
-------
Leung, P., and L. E. Booth. Power System Economics: On Evaluation of Avail-
ability. ASME Paper No. 78-JPGC-Pwr-3. Presented at the Joint ASME/IEEE/ASCE
Power Generation Conference, September 10-11, 1978.
A number of methods for economic evaluation of power plant availability and
productivity are presented in this report. Numerical examples are given with
assumed values. Each of the methods used in the report is discussed and the
areas where more study or information is needed are identified. The report
concludes that "system generation planning analysis should be conducted to
establish all pertinent economic factors, criteria, and values."
Librizzi, F. P. and H. S. Arnold. Outage Factors - An Aid to Analyzing Elec-
tric Generating Unit Reliability. Combustion, September 1978. pp. 29-30.
This article describes a proposed monthly Outage Analysis Report and discusses
its usefulness. The various items in the report are:
Forced outage factor
Maintenance outage factor
Planned outage factor
Reserve shutdown factor
Reserve spinning factor
Capacity factor
Number of outages and causes
The report provides a means of quickly determining operating trends and aids
in determining the cost-effectiveness of remedial action. The various items
in the report are defined, and their significance given; an example is pro-
vided.
Long, R. L. Engineering for Availability. Power Engineering, July 1978.
pp. 68-71.
A brief discussion of the various aspects of availability engineering is
given. Four basic steps of availability engineering are cited, and an example
of their application is shown. The article concludes that the most cost-
effective changes can be made through application of availability engineering.
Lowell, P. S. Influence of the Mineral Content of Coal on Ash Properties and
How This May Be Modified by Physical Coal Cleaning. Prepared for PEDCo En-
vironmental, Inc., October 1978.
The report states that different minerals are removed at different efficien-
cies in a physical coal cleaning plant. An example is presented that illus-
trates the influence on the ash fusion temperature of varying mineral removal
efficiencies; other coal properties are also discussed. The report recommends
a program to quantify the selective mineral removal efficiencies.
65
-------
McGraw, R. W., and G. Janik. MCCS—Implementation at Homer City. Presented
at the Proceedings of the Third Symposium on Coal Preparation, NCA/BCR Coal
Conference, Louisville, Kentucky, October 1976. pp. 107-122.
This paper describes the use of a coal cleaning plant at the Homer City Power
Plant, operated by Penelec in Homer City, Pennsylvania. The cleaning plant,
which costs 52 million dollars, is sized to clean 1000 tons of coal per hour,
processing the coal into two product streams to meet two separate S02 regula-
tions.
Morgan, M. G., et al. Sulfur Control in Coal Fired Power Plants: A Proba-
bilistic Approach to Policy Analysis. Journal of APCA, 28(10): 993-997,
October 1978.
This article presents a methodology that can be used to minimize the sum of
societal and pollution control costs. The article demonstrates a technique
for using subjective mortality elements to develop an estimate of the level to
which sulfur emissions should be controlled.
Niebo, R. J- Power Plant Productivity
Combustion, January 1979. pp. 12-21.
Trends and Improvement Possibility.
The available data bases on power plant productivity with respect to unit
size, age, and fuel type are reviewed. The major causes of lost power plant
productivity and manufacturers' and governmental programs for improving power
plant productivity are also identified. The causes identified are:
Plant design and equipment procurement
Maintenance and operations management
Coal quality
Government regulations
The report concludes that deteriorating coal quality results in higher quanti-
ties of coal having to be supplied to the boiler at higher rates in order to
produce necessary steam. Such increases result in boiler tube slagging,
precipitator overloading, pulverizer wear, and other problems. To compensate,
utilities have derated units and increased shutdown time for maintenance and
modification.
O'Brien, E. J. Coal and Its Physical Preparation. Presented at the Technical
Conference on Coal Utilization and Air Pollution Control, Western Pennsylvania
Section, APCA, April 1976.
The meaning of coal preparation is discussed in this paper, and various types
of coal cleaning are mentioned. The significance of washability data is
discussed.
66
-------
Pacer, D. W., and A. F. Duzy. Impact of Fuel on Furnace Design for Pulverized
Coal Fired Boilers. Power, September 1978. pp. 82-83.
The burner zone surface heat release rate is discussed, and typical design
values are given. A discussion of the mass gas flow effect on fly ash distri-
bution and the tightness of the furnace are presented. The slagging and
fouling factors are defined, and average values for an eastern coal are given.
The article concludes: "It is evident that much more coal data and operating
experience will be required to improve evaluation of upper-furnace slagging.
In the meantime a conservative approach to design appears to be the only al-
ternative. "
Palomino, G. E. and J. L. Shapiro. The Impact on Power Plant Design of Sulfur
Distribution in Coal. ASME Paper No. 78-JPGCPwr-13. Presented at the Joint
ASME/IEEE/ASCE Power Generation Conference September 10-14, 1978.
The variability of sulfur in the Navajo mine is studied. The relation of the
sulfur variability in the mine to the ambient concentration around the Navajo
generating station of S02 is also studied. A model of the sulfur variability
was derived. From the model the principal findings are:
The frequency of occurrence of sulfur in core samples obeyed a Gamma
distribution.
The frequency of occurrence of sulfur in the three-hour nonoverlapping
samples obeyed an inverted Gamma distribution.
The harmonic mean of the sulfur distribution in the core samples is a
predictor of the mean of the delivered coal sulfur distribution.
The variance in going from mine core distribution to delivered coal
distribution was reduced by a factor of 11.
PEDCo Environmental Specialists, Inc. Analysis of the Use of Physical Coal
Cleaning in Combination with FGD for SO Control. Draft Report prepared for
the U.S. Environmental Protection Agency, Energy Strategies Branch, under
Contract No. 68-02-1452. 1976.
This report uses linear programming techniques to evaluate the cost of three
S02 control strategies. The report illustrates an approach to obtain a least-
cost solution to S02 control. In the example given, order of magnitude esti-
mates are made for various cost elements. The report concludes:
The cost coefficients are critical
Emission regulations are critical
Nonlinear costs can be solved using an iterative technique
Linear programming techniques can be used to determine least-cost solu-
tions
67
-------
Phillips, P. J., and P. DeRienzo. Steam Coal Preparation Economics. Pre-
sented at the NCA/BCR Coal Conference and Expo III, Louisville, Kentucky,
October 19-21, 1976.
This paper attempts to fill existing information gaps in coal preparation
economics. No specific information on the benefits of coal cleaning are pre-
sented. The report distinguishes various degrees or levels of coal cleaning
that represent the complex technology of coal cleaning. Relative cost of the
cleaning technologies are presented. The report concludes that generalized
costs will have little validity in specific situations because of the many
variables involved.
Phillips, P. J. and R. M. Cole. Economic Penalties Attributable to Ash Con-
tent of Steam Coals. Presented at the AIME Annual Meeting, New Orleans,
February 1979.
A methodology is presented that quantifies six coal utilization cost compon-
ents, each proportional to a coal's mineral content. These are:
Ash disposal costs
Coal transporation costs
Plant maintenance costs
Reduction in plant peaking capacity
Reduction in plant rated capacity
Reduction in plant availability
Cost effects on flue gas cleanup systems are not considered here.
Numerical examples illustrate that coal containing between 12.5 and 25.0
percent ash-plus-sulfur can cause incremental utilization costs ranging from
less than $1.00 to more than $8.00 per ton of coal when combusted in a pulver-
ized coal-fired power plant. Estimated costs are then compared to historical
data and the conclusion is drawn that steam coal beneficiation may have broad-
er economic justification than sometimes realized. It is noted that TVA,
which first proposed the methodology and parameters used here, is continuing
research on this aspect of coal utilization.
Sarikas, R. H. Procedure for Converting Utility Investment and Expense Into
Annual Revenue Requirements, Foster Associates, Inc., Decatur, Illnois, 1975.
This report describes the development of a procedure for translating utility
investment and expense into annual revenue requirements. It is based upon the
practices followed by regulatory authorities in the United States and statute
law with respect to income tax and the deductability of various items of
expense in calculating the amount of such taxes. The important variations in
methodology between jurisdictions are pointed out. Typical parameters have
been selected to illustrate the procedure with a quantitative example.
66
-------
Sondreal, E. A., et al. Correlation of Fireside Boiler Fouling with North
Dakota Lignite Ash Characteristics and Power Plant Operating Conditions.
Presented at the American Power Conference, April 19, 1977.
Two approaches that identify the causes of ash fouling are described, fine
involves acquisition of a large number of data sets on operating units. The
data sets would then be statistically treated and insights to the relation-
ships would be drawn. The second approach uses direct measurement of the
fouling potential via probes inserted into operating boilers. This approach
provides a more accurate measure of the fouling potential in a shorter more
easily controllable fashion. The report concludes that each method has merit
and that both should be used. An alternate method involving a small test
furnace is suggested. The alternate method would provide more general infor-
mation in a more easily controlled environment.
Sondreal, E. A., et al. Ash Fouling in the "Combustion of Low Rank Western
United States Coals. Combustion Science and Technology, Vol. 16, 1976.
pp. 95-110.
The report states that no effective means of preventing ash fouling of high
sodium content coals has been found. Washing can reduce sodium content by ion
exchange; however, reaction rates are slow, and dewatering and waste water
disposal could create serious problems. Cyclone burning reduces fouling but
increases NO emissions. Boiler design radically influences the ability to
correlate da1?a for one boiler with another.
69
-------
Spaite, P. W., et al. Environmental Assessment of Coal Cleaning Processes
Draft Report written by Battelle's Columbus Laboratory for the U.S. Environ-
mental Protection Agency, 1979.
This research task was initiated with the overall objective of reviewing U.S.
coal cleaning process technologies and related technologies for environmental
control. The report provides a background against which requirements for
further developments of coal cleaning technology and control techniques for
the associated pollutants can be established.
The state of the art of physical coal cleaning is summarized. The status of
coal cleaning technology is summarized with respect to cost, energy effi-
ciency, applicabilty, extent of development, and commercialization prospects.
Current technologies are described. The various physical coal cleaning opera-
tions, such as coal pretreatment, coal separation, product conditioning, and
auxiliary processes are combined to product systems capable of producing mini-
mum, intermediate, and maximum effectiveness of coal cleaning. The physical
and chemical properties of coal are described, and the pertinent literature on
washability of many U.S. coals is cited. Technological descriptions are pre-
sented for coal cleaning processes, i.e., size reduction, sizing, desliming
screens, fine coal separation, jigs, dense-medium vessels, air tables, wet
concentrating tables, etc. Potential pollutants evolved from theses processes
and their control are identified.
This report was submitted by Battelle's Columbus Laboratories in fulfillment
of Subtask 212 for a Technology Overview under U.S. Environmental Protection
Agency Contract No. 68-02-2163 for Environmental Assessment of Coal Cleaning
Processes. This report covers the period from July 1, 1976, to May 31, 1979,
and work was completed as of May 31, 1979.
Strauss, W. Industrial Gas Cleaning, Pergamon Press, Oxford, 1966.
This textbook covers a range of subjects including:
Absorption, adsorption, and combustion
Fluid mechanics
Gravity and momentum separation of particles
Centrifugal separation of particles
Aerodynamic capture of particles
Filtration
Electrostatic precipitation
-------
Suydam, C. D., Jr. Economic Evaluation of Washed Coal for the Four Corners
Generating Station Final Report, April 1977.
The report is a summary of various studies conducted by Arizona Public .Ser-
vice. The report concludes that washing the Navajo Mine coal used at the Four
Corners plant would not be economical. The conclusion is based on the judg-
ment that washing the Navajo Mine coal would cause severe furnace slagging,
fouling, and coal handling (freezing) problems. The only benefits Identified
in
the report are reduced pulverizer wear and maintenance. The benefits are
reported to be 30 percent less than the penalties for use of washed coal. The
report does not present the specifics of how the penalties and benefits were
determined.
Suydam, C. D., Jr., and H. F. Duzy. An Economic Evaluation of Washed Coal for
the Four Corners Generating Station. Presented at the Winter Annual Meeting
of the ASME, November 27 to December 2, 1977.
The relative economics of burning washed and ROM Navajo mine coal are evalu-
ated in this report. The method by which the penalties and benefits of the
two coal strategies are determined is reported.
The report considered only the following items as being significant:
The O&M cost differential
Coal handling problems (based on an estimate of plant derating caused by
coal freezing)
Pulverizer wear (based on fuel properties and industry experience)
Pulverizer curtailment (based on an assumed 17 percent reduction in cur-
tailment)
Erosion caused tube leaks (based on assuming that 1/10 of all tube fail-
ures were tube leaks and that washing the coal would eliminate 2/3 of
the tube leaks)
Fouling (based on test firing of washed coal in a small test furnace and
assuming that the coal sodium oxide content will exceed 2.7 percent 30
days per year and cause a 15 percent derating for those 30 days)
Tuppeny, W. H. , Jr. Effect of Changing Coal Supply on Steam Generator Design.
Presented at the American Power Conference, April 24-26, 1978.
The physical differences among furnaces and pulverizers are shown in
relation to the major types of coal used by utilities. Historical experience
of the Combustion Engineering Company with various coal types and furnace
sizes is described. Trends toward lower quality coal require a corresponding
increase in the physical size of furnaces and furnace components.
-------
Tennessee Valley Authority Annual Report, Vols. 1 and 2. Years 1972, 1973,
1974, 1975, 1976.
The annual reports present a breakdown of the costs of generation and net
Icilowatthours generated at each TVA plant.
Tennessee Valley Authority. Coal Analysis Control: TVA Plants. Coal Proxi-
mate Analysis and Tonnage Used at All TVA Plants from First Burn through 1978.
The monthly and fiscal year proximate coal analyses and tons burned are given
for each TVA plant. The data are complete from initial startup of the plant
through 1978 for all TVA plants.
Tennessee Valley Authority. Division of Power Production Availability Im-
provement Program. 1978.
This report describes a repair program for various portions of several TVA
plants. The estimated costs and repair schedules are presented. The report
attributes boiler failures and decreased availability/reliability to poor fuel
quality.
72
-------
Tennessee Valley Authority. Miscellaneous data on TVA coal-fired plants sup-
plied by unidentified TVA personnel to Larry Yerino of PEDCo. 1975.
The data for each plant cover the time from Initial plant startup through
1975. Major data categories are:
Average capacity factors by unit and plant
TVA total and forced outage rates, arranged by plant size for:
Complete unit
Reactor-boiler
Turbogenerator
TVA outage rates by unit size for calendar year 1974
Unit availability factors from commercial operation to 1975
Steam plant maintenance cost comparison for selected accounts:
Boiler
Soot blower
Pulverizers, mills, and primary air
Burners, lighters, and cyclones
Gas reci-culating fans
Air preheaters
Forced draft fans
Induced draft fans
Induced draft fans
Bottom ash hoppers
Fly ash collectors
Other ash disposal facilities
Fuel analysis from 1963 to 1976 for TVA plants
Generating plant statistics for 1975
Tennessee Valley Authority Organization Statement - Form 4121. Taken from TVA
Division of Power Production Monthly Report.)
The organization statement is a monthly report that indicates monthly and
annual expenditures for several cost categories. Fuel-related costs include
coal handling and storage, coal burning equipment, ash handling equipment,
etc.
U.S. Department of Energy. Construction Cost and Annual Production Expenses.
1974, 1975, 1976, 1977. DOE/EIA-033/X. Federal Power Commission.
Data on all privately and publicly owned utilities from FERC Forms 1 and 2 for
plants with 25 MW or greater capacity and a brief discussion of each of the
data items is included along with summaries and trends for much of the data.
73
-------
U.S. Environmental Protection Agency. Combined Coal Cleaning and FGD. Pre-
sented at the EPA FGD Symposium, Las Vegas, Nevada, March 5-8, 1979.
The report identifies the following benefits of physical coal cleaning:
Reduced transportation costs
Reduced boiler O&M costs
Increased peaking capacity
Increased availability
Reduced stack reheat
Reduced design safety margin for FGD design
Reduced pulverizer costs
Reduced mine labor costs
Reduced ash disposal costs
The range of required coal cleaning benefit for a breakeven S02 control stra-
tegy for four coals and three levels of cleaning is determined. The report
concludes, "the use of PCC plus FGD will be the most cost-effective method of
complying with emission regulations if reduction in FGD costs and cost bene-
fits not related to S02 emission controls are greater than the costs of clean-
ing."
Versar, Inc. S02 Emission Reduction Data From Commercial Physical Coal Clean-
ing Plants and Analysis of Product Sulfur Variability. Final Draft. Contract
No. 68-02-21, Task 600. Prepared for EPA Fuel Process Branch, IERL, Research
Triangle Park, North Carolina. October 1979.
The report presents data that have been collected from several coal cleaning
plants. A statistical analysis was performed on the data, and the report
present the following conclusions:
The variability of the sulfur content of the coal is reduced by cleaning
PCC is an effective S02 control technology
The deeper the cleaning the greater the sulfur reduction
The RSD reductions and values determined are only valid for the particu-
lar coal and plant for which they were determined
74
-------
Wilson, E. B. , et al. Reducing the Corrosive Properties of Utility Coals
through Modifications of Current Coal Cleaning Practices. Presented at the
ASME-IEEE Joint Power Generation Conference, September 25-27, 1967.
The report describes attempts to modify the corrosive properties of coal via
physical coal cleaning. It states that reductions in the corrosive properties
of coal can be obtained without significant modification in current coal
cleaning practices or changes in coal cleaning performance. The report
stresses that coal cleaning schemes must be developed from a detailed know-
ledge of the coal seam to be mined. The report concludes that some coals may
be less corrosive in their raw state than if they were cleaned. Successful
application of the measures described, however, could reduce boiler mainten-
ance.
Winegartner, E. C. and B. T. Rhodes. An Empirical Study of the Relation of
Chemical Properties to Ash Fusion Temperatures. Journal of Engineering for
Power, July 1975. pp. 395-406.
The report descrri-es a correlation study using a multiple regression analysis.
The data base includes 626 midwest and 586 western coal samples. The ash
fusion temperature are correlated with 51 coal properties. A resulting empir-
ical equation predicts ash fusion temperature from ash composition with an
accuracy that approaches or exceeds the accuracy of the laboratory determina-
tion of the ash properties.
Yoder, L. W. Fuel Influence on Boiler Operation and Maintenance, an undated
report, Babcock and Wilcox, Alliance, Ohio.
The important coal properties that are required for proper design of various
boiler components are shown. A brief discussion on the importance of mois-
ture, volatile matter, ash, slagging and fouling, and ash viscosity indicates
that coal properties have significant effects on boiler performance. Addi-
tionally, several graphs show historical trends for several boiler design
factors, i.e. heat input to furnace plan area, heat input per burner, burner
zone heat release rate, gas temperature entering pendant superheater, and
maximum gas velocity. The conclusions reached are:
Coal and ash analysis are needed for boiler design
Ash properties can be used to predict slagging and fouling
Ash melts, sticks to walls, affects boiler design, and is related to
corrosion and erosion
Furnace design must keep ash away from furnace surfaces, solidify
the ash before it leaves the furnace, and provide for cleaning of
surfaces
75
-------
Zimmerman, 0. T. and I. Lavine. Psychrometric Tables and Charts, Industrial
Research Service, Inc. , Dover, New Hampshire. 1964.
This is a reference book of psychrometric data, mostly in tabular form.
-------
APPENDIX B
COST ESTIMATES FOR FGD AND PCC
INTRODUCTION
The costs and benefits of the combined use of physical coal cleaning
(PCC) and partial flue gas desulfurization (FGD) for sulfur dioxide (SO;,)
removal are compared to the costs for sole use of FGD. A 500-MW power plant
with a 65 percent capacity factor is assumed in the cases presented.
The raw coal to be fired directly or to be physically cleaned is a typi-
cal Eastern bituminous coal; in various portions of this Appendix, 2.5 per-
cent sulfur, 3.5 percent sulfur, and 5 percent sulfur coals are used in cost
estimation cases. The raw coal cost is $1.00 per million Btu.
The cost basis is August 1979 for all cases.
In the first example, some of the effects of the use of physical cleaned
coal on capital and annual costs are examined. In the second example, the use
of coal that can be cleaned to allow an untreated flue gas bypass stream to
provide reheat is examined. The washability data for the coal used in Exam-
ples 1 and 2 are shown in Table B-l.
In Example 3, a different 3.5 percent sulfur bituminous coal is examined
for a case where reheat is required. The washability data for this coal are
shown in Table B-2.
TABLE B-l. WASHABILITY DATA FOR AN EASTERN BITUMINOUS HIGH SULFUR COAL1
Washing
gravity
1.3
1.3-1.4
1.4-1.6
1.6-1.9
Raw coal
Weight
yield, %
21.9
62.5
82.4
85.9
100.0
Btu
recovery, %
26.3
73.1
93.4
96.3
100.0
Heating value,
Btu/lb
14,100
13,700
13,300
13,100
12.100
Sulfur,
%
1.32
1.66
1.97
2.09
3.48
Ash,
%
2.6
5.3
8.2
9.2
14.0
aThe coal washing data are selected from Sulfur Reduction Potential of U.S.
Coals: A Revised Report of Investigations EPA 600/2-76-091. pp. 71 and 164.
77
-------
TABLE B-2. WASHABILITY DATA FOR AN EASTERN HIGH SULFUR COAL
Washing
gravity
1.4-1.6
Raw coal
Weight
yield, %
80
100
Heating value
recovery, %
90
100
Heating value,
Btu/lb
12,000
10.670
Sulfur,
%
2.4
3.5
Ash,
%
10
20
Example 4 examines the capital and annual costs for three coals with
different sulfur contents, fired raw or at any of three levels of physical
coal cleaning (30, 40, and 50 percent sulfur removal), and subject to three
different control regulations.
Comments On The Coals Used
The coal in Table B-l is examined at the 1.4 specific gravity cut and in
its raw state. The washed coal loses less than 7 percent of the heat value,
while the weight is reduced almost 18 percent. The sulfur content is reduced
43 percent, and the ash content is reduced 41 percent in physical coal clean-
ing.
The coal in Table B-2 loses only 10 percent of its heat value during
physical cleaning, while it loses 20 percent of its weight. The sulfur con-
tent is reduced 31 percent and the ash content is reduced 50 percent in clean-
ing.
EXAMPLE 1
Several positive effects of physical coal cleaning are:
PCC reduces the volume of gas that must be treated by an FGD system and
the amount of sludge generated.
PCC reduces or eliminates the heat energy that reheat the cleaned gas
stream.
PCC reduces the S02 variability by half or more, which reduces the FGD
system size, since the FGD system must be designed to handle the maximum
S02 load. An example of coal sulfur variability is shown for three coals
in Table B-3.
To demonstrate the effect of physical coal cleaning, consider a 3.48 per-
cent sulfur, Eastern bituminous coal with the washability shown in Table B-l.
The raw coal would liberate 5.75 pounds of S02/million Btu heat input if 100
percent of the sulfur were liberated as S02. If the boiler in which this coal
is burned must meet a requirement of 1.2 pounds of S02/million Btu heat input,
79 percent of the S02 must be removed by the FGD system. If the FGD system
were 85 percent efficient in removing S02, 93 percent of the gas stream must
be treated 1n the FGO system. Conversely, if the coal were cleaned to a wash-
ing gravity of 1.4, the cleaned coal would have a 1.97 percent sulfur content
and would release 2.96 pounds of S02/million Btu. To meet a requirement of
1.2 pounds of S02/million Btu requirement, 59 percent of the S02 must be
78
-------
removed; assuming the 85 percent efficient FGD system, only 70 percent of the
gas stream must be treated. It is assumed that the coal is fired in a new
500-MW power boiler in a midwestern location.
TABLE B-3. COAL ANALYSES AND SULFUR VARIABILITY OVER
VARIOUS AVERAGING TIMES
Coal type
Eastern bituminous,
14% ash,
12,000 Btu/lb
Eastern bituminous,
14% ash,
12,000 Btu/lb
Western subbituminous
8% ash,
10,000 Btu/lb
Plant size,
MW
25
500
1000
25
500
1000
25
500
1000
Maximum averag
Longterm
7.00
7.00
7.00
3.50
3.50
3.50
0.80
0.80
0.80
Annual
7.36
7.23
7.22
3.68
3.62
a. 6i
0.84
0.83
0.83
e sulfur content, %
30 days
8.27
7.79
7.75
4.13
3.89
3.87
0.96
0.90
0.89
1 day
9.36
8.88
8.78
4.68
4.44
4.39
1.12
1.05
1.03
3 hours
9.73
9.23
9.19
4.86
4.61
4.59
1.18
1.10
1.09
Distribution from unit train sampling.
The comparative costs are as follows:
Capital cost
FGD system, $/kW
Sludge pond, $/kW
Total
Annual cost
Operation and mainten-
ance cost, mills/kWh
Fixed costs, mills/kWh
Total
3.48% S Raw Coal
107.50
5.38
112.88
2.58
3.17
5.75
1.97% S Cleaned Coal
81.70
2.58
84.28
1.59
2.37
3.96
For a 500-MW boiler, cleaned coal reduces the cost of the FGD system by
$14.3 million. Assuming a 65 percent capacity factor for the 500-MW boiler,
the annual cost of the cleaned coal system is $5.10 million less per year of
operation.
Regarding the reduced energy requirement for a system operating on physi-
cally cleaned coal, a lime FGD system that treats only 70 percent of the gas
stream can reheat the cleaned flue gas stream with the untreated gas bypass
stream without the use of additional reheat. The energy requirements of the
two cases are as follows:
79
-------
Annual cost
Energy cost,
Energy cost,
mllls/kWh
$106/yr
3.48% S Raw Coal
1.02
2.90
1.97% S Cleaned Coal
0.52
1.48
With the physically cleaned coal, the annual cost is reduced $1.42 million.
The capital cost reduction as a result of reheat elimination has not been
estimated; although the cost reduction exists, its capital cost impact here is
small.
As shown in Table B-3, a nominal 3.5 percent sulfur coal is expected to
have a maximum 30-day sulfur content of 3.89 percent, or 11.14 percent in
excess of the long-term value. On the other hand, the sulfur variability in a
cleaned coal is typically about half of that of a raw coal. Thus a cleaned
coal with a nominal sulfur content of 1.97 percent would be expected to have a
maximum 30-day average sulfur content of 2.08 percent. This will be reflected
in reduced capital and annual costs for a lime FGD system on a 500-MW power
boiler operating on physically cleaned coal. If the FGD systems were designed
to accommodate the maximum S02 values anticipated, the capital and annual
costs would be as follows:
Capital cost
FGD system, $/kW
Sludge pond, $/kW
Total, $/kW
Total, $106
Increase attributed
to sulfur variation,
$10f'
Annual cost
O&M, mills/kWh
Fixed charges,
mills/kWh
Total, mills/kWh
Total, $106/yr
Increase attributed
to sulfur variation
$106/yr
Raw coal
3.48%S
107.50
5.38
112.88
56.440
3.60
3.17
6.77
19.274
3.89%S
111.80
6.13
117.93
58.965
+2.525
3.93
3.28
7.21
20.527
+1.253
Cleaned coal
1.97%S
81.70
2.58
84.28
42.140
2.11
2.37
4.48
12.755
2.08%S
83.85
2.74
86.59
43.295
+1.155
2.15
2.45
4.60
13.096
+0.341
This shows that the effect of reduced sulfur variation as a result of PCC
on the design of a lime FGD system for a 500-MW boiler is a capital cost re-
duction of $1.37 million (2.525 minus 1.155) and an annual cost reduction of
80
-------
$0.912 million, (1.253 minus 0.341) representing about 0.5 percent of total'
annual costs.
EXAMPLE 2
When the coal shown in Table B-l is fired in the 500-MW power plant, it
is assumed that the S02 emission regulations require reduction to 1.2 pounds
of S02/million Btu. A 3.48 percent sulfur coal with a heat value of 12,100
Btu/lb will liberate 5.46 pounds of S02/million Btu if 95 percent of the sul-
fur is volatilized as S02. The allowable S02 emission level can be met using
either FGD only or physical coal cleaning and a partial FGD system. The
500-MW power plant is assumed to have a 65 percent capacity factor.
One item not considered in Example 1 is considered in Examples 2, 3,
and 4. It is an FGD capacity penalty which is an incremental requirement to
supply power to run an FGD system.
Combined PCC and Partial FGD
The design bases for PCC are as follows:
The PCC facility operates 4000 hours per year.
To determine the coal utilization and coal cleaning rate, a boiler heat
rate of 10,000 Btu/kWh is used.
Coal cleaning Btu recovery is 93.4 percent (see Table B-l).
Two-stage crushing is utilized to reduce the raw coal top size to
1 1/2 inches.
Processing in three circuits is as follows:
For the 1 1/2-in. x 3/8-in. cut, a single-stage dense medium vessel
is used. The coal is washed at a specific gravity of 1.4.
For the 3/8 in. x 35 mesh cut, Deister tables are used. The coal is
washed at a specific gravity of 1.6.
The fine coal is dried in a thermal drier.
The output products from all three circuits are combined to form the
cleaned boiler fuel.
The design bases for the partial FGD system are basically the same for
the FGD system only for reducing S02 emissions (presented later), except for
the following:
The bypassed, untreated flue gas stream is used partially or totally to
provide the required reheat.
Up to three 150 MW absorbers may be used partially or totally to provide
the required reheat.
An additional complete spare absorber is provided to increase the FGD
system availability. The availability of a system having three operating
absorbers and one spare is about 95 percent.
61
-------
Impacts of Combined PCC and Partial FGD
The impacts of combined PCC and the subsequent partial FGD system use are
as follows:
The FGD system can be designed to meet a less stringent continuous S02
removal requirement than is required of a system depending upon FGD
alone. The S02 evolved by combustion of the raw coal will be about
95 percent of the maximum because some sulfur is lost with the ash or
slag. The actual S02 emission will be about 5.46 pounds of S02/million
Btu when the raw coal is fired, and the FGD system will be required to
remove 4.26 Ib S02/million Btu. If the S02 absorber is 85 percent effi-
cient, 92 percent of the flue gas stream must be treated in the raw coal
case to remove the required amount of S02.
With the PCC case, the actual S02 emission is estimated to be 2.81 pounds
of S02/mil1ion Btu. The S02 removal required is 1.61 pounds of S02/mil-
lion Btu; therefore an 85 percent efficient FGD system must treat 67 per-
cent of the flue gas stream. The remaining 33 percent is sufficient to
provide necessary reheat.
The flue gas bypass will provide the 50°F reheat required and will reduce
the FGD system operating cost.
A mine-mouth unit is assumed in this case. Disposal of the coal cleaning
waste occurs in the area of the PCC unit and the mine, where it is as-
sumed that ample space exists.
The 82 percent PCC weight yield and 93 percent Btu recovery combine for a
net effect of reducing the weight of coal transported to the 500-MW
boiler by over 13 percent. The freight savings are discussed in Sec-
tion 3.11 of this report.
If sludge ponding or disposal area is a problem or concern at a particu-
lar FGD installation, PCC can greatly reduce the effective sludge genera-
tion. In "Controlling S02 Emissions from Coal-Fired Steam - Electric
Generators: Solid Waste Impact" (EPA-600/7-78-044a), a 48 percent reduc-
tion in sludge generation is reported for a coal very similar to the coal
used in this example. This may be a critical item at some specific sites
where space is limited.
Because a cleaner fuel is being fired in the boiler, boiler operation
should improve, power output capacity should increase, and maintenance
costs related to boiler operation should decrease.
Annual coal cleaning costs are sensitive to plant capacity, plant com-
plexity, and coal replacement costs. Coal replacement costs are defined
as the costs of coal energy that must be discarded with the plant residue
(carbon and mineral matter). Plant complexity increases with the number
of different process operations involved.
FGD System (Sole S02 Removal System)
Approximately 94 percent of the utility FGD systems currently in use are
lime and limestone systems. Lime is assumed in this example, the design bases
for the lime FGD system are as follows:
82
-------
A two-stage turbulent contact S02 absorber Is used.
The liquid-to-gas ratio in the absorber is 40 gal/1000 cu ft.
The gas velocity in the absorber is 10 ft/sec.
The flue gas temperature at the absorber outlet is 125°F.
Reheat of 50°F is required for the cleaned flue gas.
The absorber hold tank is sized for a 10-minute retention time.
There are four, 425-MW absorber modules required.
One spare absorber module is provided to attain FGD system availability
in excess of 90 percent. This increases capital costs by about 19 per-
cent.
Although lime-based systems have been demonstrated at 90 percent S02
removal efficiency, a more conservative 85 percent removal of S02 in the
absorbers is assumed.
The stoichiometric ratio is 1.18 for lime.
Discussion of Cost;.
The capital and annual costs of the two cases studied are presented in
Table B-4. The physical coal cleaning system costs for several size units are
presented in Table B-5.
TABLE B-4. COST COMPARISON FOR A 500-MW BOILER SYSTEM
(Cost basis: August 1979)
Option 1
Lime
FGD only
Capacity
penalty
Total
Option 2
Partial FGD
Capacity
penalty
Physical
coal
cleaning
Jotal
Capital cost
FGD system,
SAW
107.50
20.86
128.36
81.70
15.13
19.30
111.83
Sludge
pond
and land,
SAW
5.38
2.58
Total ,
$Aw
112.88
20.85
133.74
84.28
15.13
19.30
118.71
Annual cost
O&M,
millsAWh
3.60
2.11
Fixed,
millsAWh
3.17
2.37
Total,
mills/kWh
6.77
4.48
1.84
6.3?
83
-------
TABLE B-5. PHYSICAL COAL CLEANING SYSTEM COSTS
(Cost basis: August 1979)
Capacity,
tons raw
coal/h
300
1200
1500
2100
3000
Capital cost
Total ,
$106
16.490
39.384
46.997
61.164
80.550
$/kW
32.32
19.30
18.42
17.13
15.79
Annual cost
Total ,
$106/yr
5.833
13.705
16.139
20.733
27.148
$/ton
4.858
2.853
2.688
2.466
2.261
Mills/
kWh
2.67
1.84
1.77
1.68
1.59
The total capital costs are essentially the same for both cases. The
combined PCC and partial FGD case is 8 to 13 percent less expensive depending
on whether the capacity penalty is considered.
Largely, because no additional reheat is required for the partial FGD
unit, the combine.-case annual cost is about 7 percent less expensive than FGD
alone. The effect of the required quantity of reheat is shown in Example 3.
As can be seen from Table B-5, the annual PCC cost is greatly affected by
the PCC unit size. The PCC unit assumed in Option 2 of Table B-4 is sized to
clean the coal for four 500-MW power plants (1200 tons/h). If the PCC unit
supplies coal to only one 500-MW plant (300 tons/h), the capital costs are
almost identical, and the annual costs are less expensive for FGD alone by
about 6 percent. If the PCC unit is 1200 tons/h or greater, the combined op-
tion is less expensive than FGD alone.
Various items, alluded to in the body of the report and in the impacts of
the combined PCC and partial FGD discussion of this example, may tip the bal-
ance for specific cases. The absence of the reheat requirement for the par-
tial FGD unit was the deciding factor in this case.
EXAMPLE 3
When the coal shown in Table B-2 is fired in the 500-MW power plant, it
is assumed that there is an 85 percent S02 emission reduction requirement.
Coal with 3.5 percent sulfur and a heat value of 10,670 Btu/lb will liberate
6.56 pounds of S02/million Btu. An 85 percent S02 emission reduction equates
to an allowable emission of 0.98 pound of S02/million Btu heat input to
achieve compliance. Either FGD alone or combined PCC and partial FGD can
attain the required emission reduction.
Combined PCC and Partial FGD
The information given in Example 2 applies here with one exception, coal
cleaning reduces the total heat available from the coal by 10 percent (from
100 percent for the raw coal to 90 percent for the cleaned coal).
84
-------
Impacts of PCC and Partial FGD
The data in Example 2 generally apply here also. Several changes are as
follows:
The actual S02 evolution is about 6.23 pounds of S02/million Btu, and the
FGD system must remove 5.25 pounds of S02/million Btu. Essentially 100
percent of the flue gas stream must be treated in the raw coal case if
the FGD system is 85 percent efficient.
With the PCC case, the actual S02 emission is 3.80 pounds of S02/ million
Btu. An 85 percent efficient FGD system needs to treat only 87 percent
of the flue gas stream. The remaining 13 percent of the flue gas pro-
vides partial reheat for the cleaned flue gas stream and reduces FGD
system operating costs.
A 20 percent weight reduction in PCC reduces the coal heat content only
10 percent, reducing the weight of coal transported to the 500 MW power
plant by 11 percent. Freight savings are discussed separately in the
body of this report.
•
FGD SYSTEM
The comments in Example 2 hold true here also.
DISCUSSION OF COSTS
The capital and annual costs of the two options investigated are present-
ed in Table B-6. The physical coal cleaning system costs for several size
units are presented in Table B-7.
TABLE B-6. COST COMPARISON FOR A 500-MW BOILER SYSTEM
(Cost basis: August 1979)
Option 1
Lime
FGD only
Capacity
penalty
Total
Capital cost
FGD system,
$/kW
117.18
22.30
139.48
Sludge
pond
and land,
$/kW
6.24
6.24
Total ,
$/kW
123.42
22.30
145.72
Annual cost
O&M,
mills/kWh
4.11
Fixed,
mills/kWh
3.44
Total ,
mills/kWh
7.55
85
-------
TABLE 6 (continued)
Option 2
Partial FGD
Capacity
penalty
Physical
coal
cleaning
Total
Capital cost
FGD system,
$/kW
97.83
19.31
25.48
142.62
Sludge
pond
and land,
SAW
3.76
3.76
Total ,
$/kW
101.59
19.31
25.48
146.38
Annual cost
O&M,
mills/kWh
2.99
Fixed,
mills/kWh
2.90
Total ,
mills/kWh
5.89
2.51
8.40
TABLE B-7. PHYSICAL COAL CLEANING SYSTEM COSTS
(Cost basis: August 1979)
Capital cost
Annual cost
L,apai_ i \,y ,
tons raw
coal/h
400
1200
1600
2000
3200
Total ,
$106
19.367
41.314
51.542
60.737
91.583
$/kW
35.83
25.48
23.84
22.47
21.18
Total,
$106/yr
6.606
13.947
17.163
20.116
29.809
$/ton
4.126
2.903
2.680
2.513
2.327
Mills/
KWh
3.15
2.51
2.31
2.21
2.21
The total capital costs are essentially the same for both options. The
capacity penalty estimates cause the results of capital cost to be so close.
The annual costs of the combined case are about 11 percent greater than
FGD alone. The PCC cost is greater than the difference between partial and
full scrubbing.
As may be gleaned from Table B-7, the size of the PCC unit has a great
effect on the economics. A 1200 ton/h PCC unit, capable of handling three
500 MW power plants, is assumed in Table B-6. As the PCC unit size increases,
the annual cost differential decreases.
EXAMPLE 4
Table B-8 presents the summarized results of Tables B-9 through B-ll.
Capacity penalties are included in Table B-8 capital costs.
86
-------
As a general trend, the percentage of coal cleaning increases for these
"cleanable" coals causing the combined options capital costs decrease to
levels very near the FGD alone annual costs. Almost the only cases where the
"combined" option annual costs dip below the costs of FGD alone are where coal
cleaning alone allows the 500 MW power plant to meet the applicable regulatory
levels. The annual costs for the combined cases reach about 5 percent over
those of FGD alone in the 50 percent coal washing.
Only in one case does 50 percent coal cleaning become less expensive than
FGD alone. That is for an emission limit of 2.6 pounds of SOz/million Btu
using a 5 percent sulfur coal. This should affect relatively few operating
power boilers.
Since the costs are so close, any one of a number of items that are
site-specific may tilt the balance in favor of the combined option. One case
is translating the energy penalty into a fixed annual cost which was not done
here because the applicability of the capacity penalty is largely site-speci-
fic. As shown in Example 1, S02 variability design can influence up to 1 per-
cent of the annual costs. All of the other factors discussed in the body of
this report strongly influence the economic comparisons of the two options.
87
-------
TABLE B-8. SUMMARY OF THE 2.5% S, 3.5% S, AND 5.0% S FGD
AND PARTIAL FGD PLUS PHYSICAL COAL CLEANING
CASES FOR A 500-MW BOILER SYSTEM
(Cost basis: August 1979)
85% Removal
Raw coal
(FGD only)
30% coal
cleaning
40% coal
cleaning
50% coal
cleaning
1.2 lb S02
per 106 Btu
Raw coal
(FGD only)
30% coal
cleaning
40% coal
cleaning
50% coal
cleaning
2.6% lb S02
per 106 Btu
Raw coal
(FGD only)
30% coal
cleaning
40% coal
cleaning
50% coal
cleaning
2.5%S
Capital ,
$/kW
141.30
146.16
143.87
141.74
121.40
119.59
114.91
107.52
78.71
24.29b
b
b
Annual ,
mills/kWh
7.09
8.22
7.95
7.76
5.89
6.74
6.53
6.27
3.53
2.48b
b
b
3.5%S
Capital,
$/kW
145.71
147.98
145.05
142.17
136.73.
137.41
135.41
131.95
102.29
90.75
79.58
36.51b
Annual ,
mills/kWh
7.55
8.43
8.19
7.89
7.02
7.86
7.59
7.34
4.62
5.55
4.01
3.08b
5%S
Capital ,
$/kW
a
a
a
a
148.61
157.28
149.28
151.88
Annual ,
mills/kWh
a
a
a
a
8.25
9.24
8.94
8.52
1
123.69 6.41
118.90
111.30
103.44
6.94
6.47
6.12
Emissions with 85 percent removal exceed 1.2 lb S02/million Btu; thus,
costs were not calculated.
Partial FGD is not required to meet the S02 emission limit; only physical
coal cleaning is needed.
-------
TABLE B-9. COST COMPARISON FOR A 500-MW
BOILER - 2.5% S BITUMINOUS COAL
(Cost basis: August 1979)
85% Removal
Raw Coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
Total
capital ,
$/kW
119.00
22.30
141.30
Annual Cost
O&M,
mills/kWh
3.76
1
102.13
19.74
24.29
146.16
95.68
18.61
29.58
143.87
88.26
16.97
36.51
141.74
2.84
2.54
2.23
Fixed,
mills/kWh
3.33
2.90
2.69
2.45
Total,
mills/kWh
7.09
5.74
2.48
8.22
5.23
2.72
7.95
4.68
3.08
7.76
(continued)
89
-------
Table B-9. (continued)
1.2 Ib S02
per 106 Btu
Raw Coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
2.6 Ib S02
per 106 Btu
Raw coal
FGD only
FGD capacity
penalty
Total
Total
capital ,
$/kW
102.07
19.33
121.40
80.17
15.13
24.29
119.59
72.24
13.09
29.58
114.91
Annual Cost
O&M,
mills/kWh
3.01
2.00
1.77
i
60.47
10.54
36.51
107.52
66.65
12.06
78.71
1.47
1
1.65
Fixed,
mills/kWh
2.88
i
2.26
2.04
Total ,
mills/kWh
5.89
4.26
2.48
6.74
3.81
2.72
6.53
1.72
1.88
3.19
3.08
6.27
3.53
(continued)
90
-------
Table B-9. (continued)
30% Clean
coal3
PCC
Total
capital ,
$/kW
24.29
Annual Cost
O&M,
mills/kWh
Fixed,
mills/kWh
Total,
mills/kWh
2.48
With cleaned coal (30, 40, or 50%), FGD is not required to meet a
2.6 S02/million Btu limit.
91
-------
TABLE B-10. COST COMPARISON FOR A 500-MW
BOILER SYSTEM - 3.5% S BITUMINOUS COAL
(Cost basis: August 1979)
85% Removal
Raw coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
Total
capital,
$/kW
123.41
22.30
145.71
103.95
19.74
24.29
147.98
96.86
18.61
29.58
145.05
88.69
16.97
36.51
142.17
Annual Cost
O&M,
mills/kWh
4.11
3.05
2.73
2.34
Fixed,
mills/kWh
3.44
2.90
2.74
2.47
Total ,
mills/kWh
7.55
5.95
2.48
8.43
5.47
2.72
8.19
1
4.81
3.08
7.89
(continued)
92
-------
Table B-10. (continued)
1.2 lb S02
per 106 Btu
Raw Coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning:
Partial FGD
FGD capacity
penalty
PCC
Total
2.6 lb S02
per 106 Btu
Raw Coal
FGD only
FGD capacity
penalty
Total
Total
capital ,
$/kW
115.46
21.27
136.73
Annual Cost
O&M,
mills/kWh
3.79
Fixed,
mills/kWh
3.23
1
94.92 2.69 2.69
18.20
24.29
137.41
88.90
16.97
29.58
135.45
80.30
15.14
36.51
131.95
86.75
15.54
102.29
2.37
Total ,
mills/kWh
7.02
5.38
2.48
7.86
2.50
4.87
2.72
7.59
2.00 2.26
i
2.20
2.42
4.26
3.08
7.34
4.62
(continued)
93
-------
Table B-10. (continued)
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
PCC
Total
Total
capital ,
$/kW
57.46
9.00
24.29
90.75
43.86
6.14
29.58
79.58
36.51
36.51
Annual Cost
O&M,
mills/kWh
1.40
1.03
Fixed,
mills/kWh
1.67
1.26
Total,
mills/kWh
3.07
2.48
5.55
1.29
2.72
4.01
3.08
3.08
With 50% cleaned coal, FGD is not required to meet the 2.6 Ib
emission requirement.
94
-------
TABLE B-ll. COST COMPARISON FOR A 500 MW
BOILER SYSTEM - 5% S BITUMINOUS COAL
(Cost basis: August 1979)
85% Removal
(Not calculate
1.2 Ib S02
per 106 Btu
Raw coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
Total
capital ,
$/kW
d. Emissi
126.31
22.30
148.61
112.12
20.87
24.29
157.28
99.87
19.83
29.58
149.28
96.97
18.40
36.51
151.88
Annual Cost
O&M,
mills/kWh
ons exceed
4.70
3.59
3.21
2.75
Fixed,
mills/kWh
1.2 Ib S02/
3.55
3.17
3.01
2.69
Total ,
mllls/kWh
nil lion Btu. )
8.25
6.76
2.48
9.24
6.22
2.72
8.94
5.44
3.08
8.52
(continued)
95
-------
Table B-ll. (continued)
2.6 Ib S02
per 106 Btu
Raw coal
FGD only
FGD capacity
penalty
Total
30% Coal
cleaning
Partial FGD
FGD cap;;ity
penalty
PCC
Total
40% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
50% Coal
cleaning
Partial FGD
FGD capacity
penalty
PCC
Total
Total
capital,
$/kW
105.08
18.61
123.69
80.30
14.31
24.29
118.90
69.66
12.06
29.58
111.30
57.73
9.20
36.51
103.44
Annual Cost
O&M,
mills/kWh
3.48
2.20
1.79
1.37
Fixed,
mills/kWh
2.93
2.26
1.96
1.67
Total ,
mills/kWh
6.41
4.46
2.48
6.94
3.75
2.72
6.47
3.04
3.08
6.12
96
-------
APPENDIX C
CALCULATION OF REVENUE REQUIREMENTS TO CAPITALIZE ADDITIONAL BOILER CAPACITY
Foster Associates has prepared a procedure for converting utility invest-
ment into annual revenue requirements. Using that procedure, revenue require-
ments were calculated for use in Section 3.3.1 of this report.
Data in Table C-l represent the costs associated with 50 kW of new capa-
city, at a capital cost of $1000/kW, including land.
TABLE C-l. REVENUE REQUIREMENTS - 100 MW
Input Paramet' rs
Total plant investment
Plant life estimate
Physical life
Book depreciation
Construction time
Interest rate during construction
Debt fraction
Preferred stock fraction
Common stock fraction
Interest rate on debt
Dividend yield on preferred stock
Percent return on common equity
Income tax rate
Plant life estimate for tax
depreciation
Tax guideline plant life
Property Tax rate
Gross receipts tax rate
Insurance rate
Total land cost
Working capital
Startup expenses
Symbol
P
LP
Lb
N
d
P
c
r
r
t
Lt
L9
A
G
U
B
W
S
Value
$47.5 x 106
25 years
25 years
2 years
0.12
0.50
0.15
0.35
0.10
0.10
0.15
0.50
25 years
28 years
0.015
0.04
0.001
$2.5 x 106
$750,000
$1.5 x 106
(continued)
97
-------
Table C-l. (continued)
Input Parameters
Percent return on rate
base
Interest during
construction
Total capital
requirement
Plant
Land
Depreciation annuity
Income tax annuity
assuming straight-
line depreciation for
books and taxes
Investment tax
credit annuity
Levelized annual
revenue requirements
Plant
Land
Total
Symbol
r = dic * prp * crc
1C NP
C=P+I+W+S
D - r
(1 t- r)Lp - 1
t 1 l ~ dic
T - t >r ( r + n A v c\~\
c. *i . * 'L^r » u i M - ) J
sit Lb r
" (l"g " ^
T - / t ,r0.07r (1 + r)(Lg " X)
c 1 * tH ,, ,L , ]
(1 + r)ug - 1
+ °-07
(r 4 D + T T + A + u)
X ~ 5 C -
(1 - G) Cp
(r + D + T - T + A)
Y _ s c r
(1 - G) LB
Z = X + Y
Value
0.1275
$5.7xl06
$55.5xl06
$2.5xl06
0.00668
0.05415
.01143
$ll.lxl06
$0.5xl06
$11.6 x 106
98
-------
APPENDIX D
REGRESSION STUDY - TVA FORCED OUTAGES
99
-------
PEDCo-ENVIRONMENTAL SPECIALISTS, INC.
MEMORANDUM
TO: File DATE: November 6, 1975
SUBJECT:
FILE:
*
Report on Conclusions to Boiler
Reliability Study - Stepwise
Multiple Linear Regression Program
3155-W and 3179
FROM:
R.
J.
eet C .
J.
L.
T.
Gerald A. Isa
Cunningham J
Wilburn '"
Fussel
Elkins
Yerino
Devitt
TVA has provided a large quantity of operating data
that may be relatable to boiler outage rates. Several of
the variables were investigated statistically using a step-
wise, multiple linear regression analysis program in con-
junction with a time-shared Honeywell 6000 computer. The
following data have been processed for the entire TVA system
for specific TVA plants and for certain individual boilers
within those plants:
1) Total yearly tube failure outages.
2) Yearly outages due to flyash and sootblower
erosion.
3) Yearly outages due to slag erosion.
4) Total erosion outages.
5) Annual capacity factor.
6) Lifetime accumulated kWh.
7) Yearly average coal Btu content.
8} Yearly average coal ash content.
9) Yearly average coal sulfur content.
For the various systems investigated several significant
correlations were determined. Generally correlation of the
100
-------
first four variables with the latter five were sought. A
minimum confidence level of 0.9 was used. This mean* that
there is 90 percent certainty that each reported correlation
is significant enough that it could not have occurred merely
by chance.
Data for the TVA system as a whole, for three indi-
vidual plants, and for two boilers within each of those
plants were investigated. The following functional rela-
tionships were significant at a 90 percent confidence level:
TVA System Composite
Total failures = f (heat content)
Flyas'h and sootblower erosion failures = f (ash
content, heat content)
Slag erosion failures « f (ash content, heat
content)
Erosion failures * f (ash content, heat content)
Paradise Plant
Total failures = f (capacity factor)
Slag erosion failures « f (heat content)
Erosion failures = f (heat content)
Paradise Unit 1
Total failures - f (capacity factor)
Slag erosion failures «= f (capacity factor)
Erosion failures * f (capacity factor)
Paradise Unit 3
Slag erosion failures e f (ash, capacity factor)
Erosion failures B f (capacity factor)
101
-------
Gallatin Unit 1
Erosion failures « f (ash -f sulfur)
Gallatin Unit 2
Flyash and sootblower erosion failures * f (sul-
fur)
Slag erosion failures = f (sulfur)
Erosion failures = f (sulfur)
Kingston Plant
Flyash and sootblower erosion failures = f (ash +
sultur)
Flyash and sootJblower erosion failure = f (heat
content)
Slag erosion failures = f (sulfur
Erosion failures « f (sulfur)
Kingston Unit 2
Total failures = f (sulfur)
Erosion failures = f (sulfur)
Erosion failures = f (heat content, ash + sulfur)
Thus in an attempt to predict 40 specific dependent vari-
ables, 23 were predictable at a 90 percent confidence level
as a function of one or a combination of the five basic
independent variables. Most of the five "independent"
variables are actually related. Since only about eight
observations were available per data set the significant
independent variable was not consistent from one data set to
the next. The principal conclusion is that the various
failures are probably related to the Btu, ash, and sulfur
contents of the coal and to the boiler capacity factor.
10?
-------
Since the true underlying relationship is probably not
linear and since the data base is so limited, the result
that most of the data were correlatable at a 90 percent
confidence level is encouraging.
Logic would dictate that failures should vary directly
with ash and sulfur, and inversely with Btu content since
Btu content correlates inversely with ash and sulfur. The
expected relationship with capacity factor is not entirely
clear. It is possible that a boiler with a high capacity
factor would tend to exhibit a high failure rate since
failures are the result of strenuous operation. It is
apparent that failures approach zero as capacity factor
approaches zero, but it is also evident that failures must
also approach zero as capacity factor approaches 100 per-
cent. The question remains whether failure rates are in-
creased as capacity factors are increased or whether the
failure rates exert a limiting effect on the capacity
factor. The situation may vary from boiler to boiler., For
example a relatively new boiler may be run at a high capa-
city factor with few operating problems whereas an older
boiler may show high failure rates at a high capacity
factor, due to the stress of overwork and at a low capacity
factor due to the fatigue of cyclic or off-and-on operation.
Most of the derived regression coefficients were con-
sistent in sign with expected influences of ash, Btu and
sulfur variations, but notable exceptions occurred, espe-
cially where multiple regression relationships were sig-
nificant. As an example, for the TVA system as a whole, ash
appeared to have a subtractive effect on flyash and soot-
blower erosion failures. Such a relationship is contrary to
expectations and observations. A closer look at the data
explains the anomaly. The derived regression equation chows
103
-------
flyash and sootblower erosion failures to be a function of
the ash and Btu contents of the coal supply. The equation
indicates that failures decrease as either the Btu content
or the ash content increases. However, the Btu and ash
contents for coal are strongly correlated. TVA data in-
dicate that historically each one percent increase in ash
content has reduced coal heating values by about 205 Btu/lb.
If this relationship is used to eliminate Btu content fron
the regression equation it can be calculated that a one
percent ash increase in the overall coal supply will predict
that 24 additional flyash and sootblower erosion failures
vill occur annually.
This predicted increase is about 20 percent of the
current flyash and sootblower erosion failure rate (116 per
year). Observed and predicted failures are plotted vs. ash
content in Figure 1. Two items should be noted. First, it
is apparent that A significant correlation exists between
failures and ash content, and a reasonable straight-line fit
to the data could be made. Second, the plotted data fit
does not result in a straight-line relationship with ash,
owing to the fact that there are two underlying variables in
the regression equation.
All of the significant (confidence level, 0.9) rela-
tionships that were found appear in Figures 2 through 24.
In each case observed and predicted failure levels were
plotted against time.
It is likely that there are other parameters which can
be used to predict failures more accurately than the param-
eters which were used in this preliminary study. For ex-
ample, the indices for ash slagging and fouling nay be more
significant than ash content in predicting failure rates.
These indices are as follows:
104
-------
120
TOO
UJ
ex
80
o
ct
o 60
00
I
o
?40
20
14
O
D
D
O
15
O
D
6
o
D
D OBSERVED
O PREDICTED
16 17
ASH, %
16
19
Figure 1. TVA system annual fly ash and soot blower erosion
failure observations and predictions plotted against
overall yearly ash content of coal.
1Q5
-------
500i
400
er
,- 300;
IS)
UJ
a:
200
100
INDEPENDENT VARIABLES
COAL HEAT CONTENT
OBSERVED
— PREDICTED
_L
J
I
1967 T96B 1969 1970 1971 1972 1973 1974
YEAR
Figure 2. Total failures - TVA composite - 11 plants
106
-------
INDEPENDENT VARIABLES
COAL ASH CONTENT
COAL HEAT CONTENT
OBSERVED
PREDICTED
1967 1968 1969 1970 1971 1972^973 1974
YEAR
Figure 3. Fly ash and soot blower erosion failures
TVA composite - 11 plants.
107
-------
INDEPENDENT VARIABLES
COAL ASH CONTENT
COAL HEAT CONTENT
OBSERVED
PREDICTED
1967 1966 1969 1970 1971 1972 1973 1974
YEAR
Figure 4. Slag erosion failures - TVA composite - 11 plants.
108
-------
INDEPENDENT VARIABLES
COAL ASH CONTENT
COAL HEAT CONTENT
OBSERVED
PREDICTED
1967 1968 1969 1970 1971 1972 1973 1974
YEAR
Figure 5. Erosion failures - TVA composite - 11 plants
109
-------
APPENDIX E
CALCULATIONS OF BOILER EFFICIENCY IMPROVEMENT AS A RESULT OF PCC
The following calculations show the efficiency improvement that can be
obtained by burning a cleaned coal if the exhaust gas temperature can be
lowered by the same amount that the acid dew point is lowered as a result of coal
cleaning.
The following raw coal composition is assumed, based on a typical Western
Kentucky coal.
• TABLE E-l. RAW COAL COMPOSITION
Constituent
C
H2
02
N2
S
H20
Ash
Total
Percent
60.790
4.068
6.510
1.287
3.325
5.000
19.000
100.000
Ib-moles
5.066
2.044
0.203
0.046
0.104
0.278
It is assumed that 3 percent of the coal sulfur is converted to S03;
the balance to S02. It is assumed that 1 percent of the coal carbon is
converted to CO; the balance to C02. Combustion air with 3 percent mois-
ture is taken on a molar basis to be
02 * 3.750 N2 + 0.238 H20
Excess air is assumed to be 20 percent. The resulting combustion equation is
5.066 C * 2.044 H2 + 0.203 02 * 0.046 N2 «• 0.104 S + 0.278 H20 + 19 Ib ash
«• 7.187 (02 + 3.750 N2 + 0.238 H20)
-» 5.015 C02 + 0.051 CO + 4.033 H20 + 0.101 S02
«• 0.00312 S03 + 26.997 N2 + 1.22202 + 19 Ib ash
110
-------
Ib H20/lb dry gas = 0.088
H20 dew point = 122°F (Zimmerman 1964)
p S03/p H20 = 7.7 x 10"4
dew point elevation = 126°F (Strauss 1966)
acid dew point = 122°F + 126°F = 248°F
Similar calculations are made for the cleaned coal, which is assumed to
have the characteristics in Table E-2.
TABLE E-2. CLEANED COAL COMPOSITION
Constituent
C
H2
0.
N2
S
H20
Ash
Total
Percent
69.610
4.681
7.455
1.474
2.280
5.000
9.500
100.000
Ib-moles
5.801
2.341
0.233
0.053
0.071
0.278
5.801 C + 2.341 H2 * 0.233 02 + 0.053 N2 + 0.071 S «• 0.278 H20
+ 9.5 Ib ash
+ 8.171 (02 + 3.750 N2 + 0.238 H20)
•» 5.743 C02 * 0.058 CO + 4.564 H20 + 0.069 S02
+ 0.00213 S03 + 30.694 Nj, + 9.5 Ib ash
Ib H20/lb dry gas = 0.075
H20 dew point = 118°F (Zimmerman 1964)
p S03/p H20 = 4.7 x 10~4
dew point elevation = 121°F (Strauss 1966)
acid dew point = 118°F + 121°F = 239°F
Since 100 Ib of coal produces about 1185 Ib of moist exhaust gas, the dew
point change is equivalent to
1185 Ib x 9°F x 0.25 Btu/lb°F = 2666 Btu
111
-------
In each 100 Ib of coal there is now an additional 2666 Btu available, which is
equivalent to an additional 0.3 kWh per 100 Ib of coal. This effectively
changes the heat rate from 10,000 to 9972; system efficiency increases from
34.13 to 34.23 percent, improving by 0.1 percent.
112
-------
APPENDIX F
SAMPLE CALCULATIONS ON ESP PERFORMANCE FOR RAW AND WASHED COAL
ESP requirements in conjunction with raw and cleaned coal were calculated
using Deutsch and Matts-Ohnfeldt equations for specific collecting area (SCA).
EXAMPLE 1 - UNCLEANED COAL
3.5% S
20% ash
10,600 Btu/lb
Assuming that 85 percent of the coal ash is emitted as fly ash, uncontrolled
emissions are
0.85 x 0.20 Ib/lb coal . 1E> Q7 1h/in6 Rtll
10,670 Btu/lb coal 15'93 1b/1° Btu
To meet a regulation of 0.1 lb/106 Btu, required ESP efficiency is
100 x 15.83/15.93 = 99.37 percent.
To meet a regulation of 0.03 lb/106 Btu, required ESP efficiency is
100 x (15.93 - 0.03)715.93 = 99.81 percent.
At 300°F, estimated resistivity is 4.1 x 106 ohm cm. Migration velocity is
31.2 ft/min.
SCA = "100° 1" (1 " ") (Deutsch)
w
where: SCA = ft2/1000 acfm
w = migration velocity, ft/min
n = efficiency required (decimal)
g 0.10 lb/106 Btu, SCA = '100° ln3^12"-9938) = 163 Deutsch (207 Matts-Ohnfeldt)
3 0.03 lb/106 Btu, SCA = "I000 ln^(l -.9981? = 200 Deutsch (314 Matts-Ohnfeldt)
113
-------
EXAMPLE 2 - WASHED COAL
2.4% S
10% ash
17,000 Btu/lb
Required ESP efficiency is 98.59% for 0.10 lb/106 Btu
Required ESP efficiency is 99.58% for 0.03 lb/106 Btu
Assume 300°F
Estimated resistivity = 1.6 x 1010 ohm cm
Migration velocity = 28.8 ft/min.
For 0.10 lb/10c Btu, SCA = 148 Deutsch (158 Matts-Ohnfeldt)
For 0.03 lb/10c Btu, SCA = 190 Deutsch (260 Matts-Ohnfeldt)
Coal cleaning reduces as content by 10 to 70 percent and sulfur by up to
35 percent. Heating value was upgraded by one-third to 26 percent.
Changes in as* composition and fusion properties, decreases in coal vari-
ability, and shifts in coal grindability as a result of coal cleaning can
affect power generation costs.
Cleaning plant capital costs are less than five percent of the capital
cost for a 1000-MW power plant that the cleaning plant would serve.
Cleaned coal costs exceed raw coal costs by approximately one to two mills
per kWh.
Coal cleaning can reduce coal transportation costs by 0.1 to 1.8 mills
per kWh.
Coal cleaning can reduce power plant capital costs by 0.2 to 0.9 mill/kWh.
Savings occur for ash handling, particulate removal, FGD, boiler, pulver-
izer, and maintenance.
The cost of coal cleaning can be offset by savings in transportation
costs, capital costs, and operating and maintenance costs.
1J4
-------
TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
. REPORT NO
EPA-600/7- 80-105
2.
. RECIPIENT'S ACCESSION NO.
. TITLE ANDSUBTITLE
?ost Benefits Associated with the Use of Physically
Cleaned Coal
REPORT DATE
May 1980
. PERFORMING ORGANIZATION CODE
AUTHORIS)
i.A. Isaacs, R.A. Ressl, and P.W.Spaite (Consultant!
B. PERFORMING ORGANIZATION REPORT NO.
. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
P.O. Box 20337
Dallas, Texas 75220
10. PROGRAM ELEMENT NO.
EHE623A
11. CONTRACT/GRANT NO.
68-02-2603, Task 31
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; 5/78-11/79
14. SPONSORING AGENCY CODE
EPA/600/13
is SUPPLEMENTARY NOTES n;RL..RTP project officer is James D. Kilgroe, Mail Drop 61,
919/541-2851.
16. ABSTRACT
repor|. identifies and quantifies several benefits associated with the
use of physically cleaned coal in the operation of utility electric power plants. The
benefits occur in: coal and ash handling, boiler operation, and gas handling and
cleaning. Cleaning removes sulfur from the coal, thus reducing the emission of SO2
into the atmosphere. In most cases, however, the power plant must install supple-
mental control equipment to reduce emissions enough for compliance with environ-
mental regulations. The cost of this supplemental equipment is less than the cost of
a control system for use with uncleaned coal, but the cost decrement is usually insuf
ficient to offset coal cleaning costs. Typically, however, the total of all benefits ad-
dressed in the report exceeds the cost of cleaning the coal. In a typical case , the
cost of coal cleaning is #4. 85 per ton of cleaned coal; whereas , total benefits asso-
ciated with cleaning the coal are $7. 20 per ton of cleaned coal. The report recom-
mends additional projects aimed at quantifying coal cleaning benefits , and presents
an annotated bibliography of related studies .
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
. COSATi Field/Grour
Pollution
Coal
Coal Preparation
Desulfurization
Cost Effectiveness
Electric Power Plants
Utilities
Coal Handling
Ashes
Materials Handling
Gas Scrubbing
Pollution Control
Stationary Sources
Physical Coal Cleaning
13B
21D,08G 15E
081 21B
07A.07D 13H
14A
10B
IS. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Rtpon)
Unclassified
21. NO OF PAGES
124
20 SECURITY CLASS (This page I
Unclassified
22. PRICE
EPA Form 2220-1 («-73)
115
------- |