EPA-600/2-74-001
February 1974
Environmental Protection Technology Series
Assessment of the Potential of Clean
Fuels and Energy Technology
o
\
LU
O
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and
Monitoring, Environmental Protection Agency, have
been grouped into five series. These five broad
categories were established to facilitate further
development and application of environmental
technology. Elimination of traditional grouping
was consciously planned to foster technology
transfer and a maximum interface in related
fields. The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL
PROTECTION TECHNOLOGY series. This series
describes research performed to develop and
demonstrate instrumentation, equipment and
methodology to repair or prevent environmental
degradation from point and non-point sources of
pollution. This work provides the new or improved
technology required for the control and treatment
of pollution sources to meet environmental quality
standards.
EPA REVIEW NOTICE
This report has been reviewed by the Office of Research and
Development, EPA, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policies of the Environmental Protection Agency, nor
does mention of trade names or commercial products constitute
endorsement or recommendation for use.
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EPA-600/2-7^-001
February 1971*
ASSESSMENT OF THE POTENTIAL QF CLEAN FUELS
AND ENERGY TECHNOLOGY
By
Elton Hall
Paul Choi
Edward Kropp
Contract No. 68-01-211U
Program Element 1AB013
Roap/Task PEMP 26
Project Officer
James C. Johnson
Air Technology Branch
U.S. Environmental Protection Agency
Washington, DC 20U60
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, DC 201*60
For sale by tbe Superintendent of Documents, U.S. Government Printing Office, Washington, D.C. 20402 - Price $2.80
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ABSTRACT
The objectives of this study are: (1) to assess the potential
of fuel cleaning, fuel conversion and emission control technologies, in
conjunction with the use of naturally clean fuels, to reduce air emissions
from fuel/energy processes sufficiently to maintain ambient air quality in
the face of increasing fuel use between now and the year 2000, and (2) to
recommend research and development priorities which will enhance the
probability of successful fulfillment of the dual national goals of an
adequate energy supply and clean air.
The assessment includes three phases: (1) calculation of total
emissions and effluents produced by fuel-burning systems to the year 2000
according to three different scenarios, (2) analysis of the impact of
emissions on ambient air quality, and (3) development of an overall index
for comparison of the potential usefulness of the energy technologies under
consideration.
The results show that energy technologies must be developed and
implemented as rapidly as possible to maximize the use of domestic fuels,
principally coal, and reduce our dependence on imported oil. Research and
development priorities for various energy technologies were developed.
The disproportionate impact of emissions from small sources on ambient air
quality is demonstrated and recommendations pursuant to this problem are
presented.
ii
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TABLE OF CONTENTS
Page
CONCLUSIONS 1
RECOMMENDATIONS OF TECHNOLOGY RESEARCH PRIORITIES 4
INTRODUCTION 8
PROJECTED TOTAL EMISSIONS FROM FUEL COMBUSTION IN
STATIONARY SOURCES 12
Scenario 1. Assumed Application of Energy
Technologies, Preliminary Projection 13
Scenario 2. Assumed No Application of Energy
Technology 36
Scenario 3. Modified Fuel Allocation Assumption 43
ESTIMATION OF THE IMPACT OF PROJECTED EMISSIONS ON
AMBIENT AIR QUALITY 57
Approach 57
Characteristics of the Indianapolis AQCR 57
Relative Ambient Air Quality Contributions
From Small Sources and Large Sources 58
Effects of Fuel Switching on Ambient Air Quality 62
Discussion of Results 67
TECHNOLOGY ASSESSMENT 71
Apporach 71
Assessment Criteria 71
Technology Evaluation 73
Technology Rating 79
Aggregation of Technology Ratings 89
Discussion of the Technology Assessment 92
OPTIMUM TECHNOLOGY UTILIZATION 95
REFERENCES 98
APPENDIX A
DATA TABLES FOR SELECTED MODULES 100
APPENDIX B
CALCULATION OF PREDICTED AMBIENT AIR QUALITY FOR THE
INDIANAPOLIS AQCR 173
iii
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LIST OF TABLES
Page
.Table 1. Projection of Clean Gaseous Fuel Supply 15
Table 2. Projection of Clean Petroleum Fuel Supply 17
Table 3. Projection of Clean Coal Fuel Supply 19
Table 4. Preliminary Technology Availability Projections .... 21
Table 5. Fuel Utilization Projection for Residential and
Commercial Sector ... 23
Table 6. Fuel Utilization Projection for Industrial Sector ... 24
Table 7. Fuel Utilization Projection for Electrical Sector ... 25
Table 8. Modules Comprising Fuel/Techno logy Systems 27
Table 9. Unit Emissions of Individual Modules 29
Table 10. Total Emissions for Systems in the Residential/
Commercial Sector, Scenario 1 31
Table 11. Total Emissions for Systems in the Industrial
Sector, Scenario 1 32
Table 12. Total Emissions for Systems in the Electrical
Sector, Scenario 1 33
Table 13. Summary of Total Emissions for each Sector and
Total Emissions for All Sectors, Scenario 1 35
Table 14. Total Emissions for Residential/Commercial
Sector, Scenario 2 37
Table 15. Total Emissions for Industrial Sector, Scenario 2 ... 38
Table 16. Total Emissions for Electrical Sector, Scenario 2 ... 39
Table 17. Summary of Total Emissions for each Sector and
Total Emissions for All Sectors, Scenario 2 41
Table 18. Comparison of Total Emissions for Scenario 1
and Scenario 2 42
Table 19. Fuel Utilization Projection for Residential
and Commercial Sector 45
Table 20. Fuel Utilization Projection for Industrial Sector ... 46
iv
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LIST OF TABLES (Continued)
Page
Table 21. Fuel Utilization Projection for Electrical Sector . . . ^7
Table 22. Modules Comprising Fuel /Techno logy Systems 48
Table 23. Total Emissions for Systems in the Residential/
Commercial Sector, Scenario 3.... 50
Table 24. Total Emissions for Systems in the Industrial
Sector, Scenario 3 51
Table 25. Total Emissions for Systems in the Electrical
Sector, Scenario 3 53
Table 26. Summary of Total Emissions for each Sector and
Total Emissions for All Sectors, Scenario 3 .... ._. "55
Table 27. Comparison of Total Emissions for Scenario 1
and Scenario 3 56
Table 28. Summary of Sources in Indianapolis AQCR-"Clean
Fuels" Run, 1971 59
Table 29. Comparison of Point Source and Area Source
Contribution to Ambient Air Quality (AAQ) 63
Table 30. Characteristics of Utility Plants in
Indianapolis AQCR 65
Table 31. Summary of Predicted Ambient Air Quality
(Indianapolis AQCR) 68
Table 32. Energy Technology Evaluation Matrix 74
Table 33. Energy Technology Rating Matrix 90
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LIST OF FIGURES
Page
Figure 1. Generalized Technology Rating Function 79
Figure 2. Technology Rating Function for Air Emissions .... 80
Figure 3. Technology Rating Function for Technology
Availability 82
Figure 4. Technology Rating Function for Fuel Availability . . 83
Figure 5. Technology Rating Function for Market
Applicability 84
Figure 6. Technology Rating Function for Capital Costs .... 86
Figure 7. Technology Rating Function for Operating Costs ... 86
Figure 8. Technology Rating Function for Efficiency 87
Figure 9. Technology Rating Function for Probability of
Successful Development 88
vi
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ACKNOWLEDGEMENTS
Many individuals contributed their advice and assistance to
this study. In particular, the Project Officer, Mr. James C. Johnson,
and Dr. Arnold J. Goldberg, Mr. Richard E. Harrington, and Dr. D. Bruce
Henschel all of EPA, deserve mention.
The contributions of Mr. Paul Spaite, consultant to Battelle-
Columbus, to the technology assessment and in review of the drafts is
gratefully acknowledged.
Several staff members at Battelle-Columbus also contributed
to this study, including: G. R. Smithson, Jr., R. B. Engdahl, P. R.
Sticksel, and K. S. Murthy.
vii
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CONCLUSIONS
The major results of this study may be summarized as follows.
(1) The basic fuel supply/demand forecasts of Dupree and West^
were combined with a clean-fuel supply projection and a preliminary
technology availability projection to develop a fuel utilization matrix.
This matrix shows that there is expected to be a shortage of clean fuel
and available energy technology resulting in the need to burn some dirty
fuel without control in 1975 and 1980. The Dupree and West forecasts
include large quantities of imported petroleum and gaseous fuels. Energy
technologies must be developed and implemented as rapidly as possible to
minimize this dependence on foreign fuel supply by maximizing the use of
demestic fuel, princiaplly coal.
(2) The total emissions to be expected from the combustion of
the projected quantities of fuel were calculated. The results show that,
with the preliminary technology projection, about 29 million tons of 802
will be emitted in 1975, 18 million tons or 37 percent less in 1980, and
20 million tons in 2000. The reduction observed by 1980 and the moderate
increase to the year 2000, in spite of a large increase in the fuel
consumption projected during the period, are due to the assumed application
of control technology. The effect of the applied technology in reducing
emissions of S0» was estimated by repeating the calculation assuming no
applied control technology. The observed reduction in SO,, emissions was
4.5 million tons in 1975, 19 million tons in 1980, 29 million tons in 1985,
and 46 million tons in 2000. The total NO emissions were shown to rise
x
steadily throughout the period—18 million tons in 1975 to 27 million tons
in 2000--reflecting the increase in fuel consumption and the lack of
available NO control technology. The total particulate emissions are
A
small—2.3 to 4.7 million tons from 1975 to 2000--compared with SO, and NO .
<£ X
This results from the assumption of 99 percent collection efficiency for
particulates. The technology is available for achieving this efficiency
but it is not universally practiced at this time. The estimates of
particulate emissions do not include fine particulates.
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(3) The potential impact of the total SO. emissions on ambient
air quality was estimated by means of a model study of the Indianapolis
Air Quality Control Region. The results indicate that, for Scenario 1
(allocation of clean fuel to small-source sectors), the maximum contribution
to SO. concentrations from fuel combustion sources decreases from 1975
to 1980 because of the projected increase in the application of stack gas
cleaning, then rises to slightly above the secondary standard by the
year 2000 because of the projected increase in overall fuel use. For
Scenario 3 (some dirty fuel burned in small-source sectors), the same
trend occurs but the values are more than twice the Scenario 1 values
in each year. This result reflects the disproportionate influence of
small sources on ambient air quality. It should be noted that the result
is merely an estimation of the impact to be expected for that AQCR given
the projected growth in fuel consumption and available control technology.
(4) An assessment was made of the potential of energy
technologies to contribute to the solution of the energy/environment
problems. Each of ten technologies was evaluated with respect to six
assessment criteria: residual emissions, availability, applicability,
cost, energy efficiency, and probability of successful development. The
final assessment yielded the following ranked order of technologies:
Highest rated group
Stack gas cleaning, throwaway
Physical coal cleaning
Stack gas cleaning, by-product
Second group
Residual oil desulfurization
High-pressure fluidized-bed combustion of coal
Chemically-active fluidized-bed combustion of oil
Third group
Chemical coal cleaning
Fourth group
Coal gasification, low Btu
Coal refining (liquefaction)
Coal gasification, high Btu
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(5) Recommendations of technology research and development
were made based on the needs identified in this study and the technology
assessment performed.
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RECOMMENDATIONS OF TECHNOLOGY RESEARCH PRIORITIES
The recommendations which follow were developed from the assess-
ment of technologies which are in competition for the market for systems
which are capable of utilizing coal or residual oil with minimum environ-
mental impact. It should be noted that the assessment was based mainly on
factors relating to overall characteristics of the technologies and
detailed assessment of problems to be solved to perfect each technology
was not made. The ratings are based in large part on what the technologies
could contribute if the needed development is successful. Also they did
not take into account other factors, e.g., processes for production of
high Btu gas from coal are the only source of gas to supplement dwindling
supply of domestic gas supplies which are essential for use in homes and
commercial applications. Further, it does not consider that while
optimistic assumptions relative to future availability suggest that most
air pollutants can be kept under control without maximum development of
all technologies, this can be achieved only if we have access to
increasing supplies of imported oil and gas. The undesirability of heavy
dependence on foreign fuel sources suggests that all technology with
promise for utilizing coal with minimum environmental Impact should be
developed as rapidly as possible. Finally, it should be noted that
advanced technologies such as fuel cells, use of solar energy and the
like were not considered. Despite these limitations it is felt that the
striking differences in the ranking suggest that certain activities are
of outstanding importance from the standpoint of air pollution control.
The following list defines priorities for further development of the
technologies which have been assessed. The general recommendations
are in order of priority. Specific projects which are suggested under
each recommended area of R&D represent work felt to be of considerable
importance but they cannot be taken to represent highest priority
recommendations in that no comprehensive analysis of the relative merits
of individual projects was made.
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The significance of emissions from small sources is demonstrated
in the body of the report by the calculations of predicted ambient air
quality. This problem must be attacked in two ways:
(1) Maximize the allocation of clean fuels to small
sources. This solution is addressed in Recommenda-
tions 1, 2 and 8.
(2) Accelerate the development of energy technologies
applicable to small- and intermediate-size sources.
This solution is addressed in Recommendations 3, 6,
7 and 8.
(1) Detailed analysis of current and projected clean fuels distribution
and constraints on fuel switching flexibility to identify ways to
maximize the allocation as clean fuels to small sources
(a) Identify important misplaced blocks of clean fuel
(b) Identify barriers to fuel switching such as long-
term fuel supply contracts, outright ownership of
fuels, availability of replacement fuels, and
availability of clean fuel supply network.
(2) Stack gas cleaning for utilities and industrial sources of SOX to
maximize the use of domestic high sulfur fuel and free clean fuel
for use in small sources
(a) Engineering evaluation of sludge disposal methods
(demonstration des irable)
(b) Engineering evaluation of the reliability of the
eleven lime/limestone systems on-stream or coming
on-stream prior to July, 1974
(c) Demonstrations on industrial sources
(3) Fluidized-bed combustion
(a) Developmental studies on presently identified critical
problems in fluidized combustion of coal, including
solids handling, minimization of attrition and elutriation
of bed materials, maximizing combustion efficiency and
sorbent utilization, and cleaning of hot gases to minimize
turbine damage in combined cycle application.
5
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(b) Demonstration of fluidized-bed combustion of high-sulfur
residues. Coal cleaning and coal gasification/liquefaction
processes result in combustible, high-sulfur residues
which could be burned in a fluidized-bed combustor. A
number of stack gas cleaning methods may be applied
because of relatively high concentration of SO,,. This
approach would reclaim the fuel value of the residues
while eliminating the residue disposal problems.
(c) Chemically-active fluidized bed - refinery demonstration.
A refinery generates significant quantities of "dirty"
fuel which could be burned on-site in a chemicall-active
fluidized bed to provide needed energy to the refinery.
(d) Chemically-active fluidized bed - lime kiln (once through)
demonstration. Energy for lime kiln operation could be
derived from residual oil burned in a chemically-active
fluidized bed. The lime bed would not be recycled but
would be simply included in the product mix.
(4) Control technology for NO . Adequate means for controlling emissions
a
of NO are not available. This important area must be emphasized.
(a) Development of coal firing techniques and combustion
modifications to minimize NO emissions
jv
(b) Development of techniques for minimizing the conversion
of fuel nitrogen
(5) Combined firing of prepared municipal refuse and pulverized coal.
Although this approach was not considered in the current study,
it has potential for providing an additional supply of energy
with reduced emissions at relatively low cost while eliminating
the solid waste disposal problem. The application of this practice
should be accelerated as rapidly as possible.
(a) Engineering study of means of adapting various types of
existing boilers to combined firing
(b) Supplement St. Louis study to develop optimum refuse
preparation techniques
(c) Studies of high-temperature corrosion by gases from
refuse/coal firing
6
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(6) Chemical cleaning of coal
(a) Development of chemical processes capable of removing
all or part of the organic sulfur contained in the coal
(b) Development of chemical processes capable of removing
all or part of the coal-bound nitrogen
(7) High Btu (pipeline) gas from coal
(a) Development of systems for feeding coal into
pressurized systems
(b) Development of environmentally acceptable methods of
char combustion (see fluidized-bed topics)
(8) Low Btu gas from coal
(a) Demonstration of low Btu gasifiers on industrial plants
now using low sulfur fuel. This application would free
large amounts of natural gas and fuel oil for use in
the residential/commercial sector.
(b) Development of low Btu gas cleaning systems suitable
for industrial applications
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INTRODUCTION
The United States is faced with the need to satisfy a rapidly
rising demand for energy. This demand must be met through the year 2000
by increased use of fossil fuels supplemented by the anticipated growth
in electric power production by nuclear-fission generating facilities.
Advanced energy sources such as solar energy conversion, nuclear fusion,
geothermal, magnetohydrohynamics, and fuel cells are not expected to
contribute a significant fraction of the total energy supply through the
year 2000.
Consideration must be given also to the potential for added
environmental damage inherent in the increased use of fossil fuels to
satisfy our energy requirements. Methods to maximize the use of coal in
environmentally sound ways must be developed to prevent excessive depen-
dence on foreign sources of clean-burning, petroleum-based fuels. The
United States Environmental Protection Agency, other government agencies,
and certain industries have a number of research and development efforts
in progress which are directed toward minimizing the pollutant emissions
associated with the conversion of fossil fuels to useful energy. These
efforts fall into three categories: fuel cleaning processes, fuel
conversion processes, and emission control techniques. The objectives
of this study are: (1) to assess the potential of these developmental
technologies, in conjunction with the use of naturally clean fuels, to
reduce air emissions from fuel/energy processes sufficiently to maintain
ambient air quality in the face of increasing fuel use between now and
the year 2000, and (2) to recommend research and development priorities
which will enhance the probability of successful fulfillment of the dual
national goals of an adequate energy supply and clean air.
The technologies specifically considered in this study are:
Fuel cleaning
(1) Physical coal cleaning
(2) Chemical coal cleaning
(3) Resid desulfurization
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Fuel conversion
(4) Coal refining
(5) Coal gasification, low Btu
(6) Coal and oil gasification, high Btu
Emission control technologies
(7) Stack gas cleaning, throwaway
(8) Stack gas cleaning, by-product
(9) Fluidized-bed combustion of coal
(10) Chemically active fluidlzed-bed combutsion
of oil.
These technologies, all directed toward the production of energy with
reduced air emissions, are referred to collectively as energy technolo-
gies throughout this report.
The comparison' of technologies from the standpoint of their con-
tribution to improved air quality involved three steps. First, Department
of Interior estimates of future usage for fossil fuels (coal, oil, and gas)
by consuming sector (residential/commercial, industrial, utility) were
analyzed to determine what emissions and effluents fuel burning systems
would produce, with and without control technolgoies applied, to the year
2000. Three scenarios were considered in this step. In the first all
available supplies of low-sulfur fuel were assumed to be burned in the
domestic, commercial, and industrial sectors and available control
technologies assumed to be applied to control of utilities. Estimates for
the date of availability and extent of the applicability for the control
technologies were based on expert opinion. For Scenario 2 mass emissions
and total effluents which would result if no controls were applied were
calculated for comparison purposes. In Scenario 3 the assumptions were
identical to those of Scenario 1 except that part of the high-sulfur fuel
which was assumed burned in utilities, because clean fuels and control
systems were not available, was assumed to be burned in nonutility systems.
Because the emission factors for all "dirty" fuel burning sources tend
to be similar the total amounts of emissions and effluents calculated
for Scenarios 1 and 3 were not significantly different.
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The second step Involved analysis of Impacts on ambient air
quality under conditions that would show the different impact which would
result when a balance of "dirty" fuel, burned without control, was burned
partly in small sources with short stacks as opposed to burning the
entire balance in utility boilers with tall stacks. The source inventory
for the Indianapolis air quality control region was used for this comparison!
The population of processes included 11 utility boilers, 19 industrial
boilers burning 12,500 to 50,000 tons of coal per year, 25 industrial
boilers burning less than 12,500 tons of coal per year, 7 noncombustlon
sources of sulfur oxides, 165 other point sources and 207 area sources.
Model studies were conducted to show the impact of each class of process
on selected receptors. Conditions were chosen to permit a direct com-
parison of air quality impact with and without fuel distribution control
which would make it possible to use all dirty fuel in utilities where it
would do least harm.
The third step Involved development of an overall index for
comparison of the potential usefulness of the control technologies under
consideration. Six criteria were used for a broad comparison of the
technologies. They were (1) date of availability, (2) extent of the
applicability, (3) the magnitude of uncontrollable residual emissions
and effluents, (4) energy efficiency for the system, (5) cost to develop
and apply the technology, and (6) probability of success in development
of the new technologies. The ratings were based on expert opinion and
were derived using methods Intended to make them as objective as possible.
They are not based on detailed investigations, e.g., probability of
success ratings were based on the assumption that processes under develop-
ment have come to their present stage by logical means involving rational
judgments by the developers so that probability of success is mainly
a function of how much additional development work is necessary. Judgments
were made more on the amount of data believed available than on quality of
the data and investigation of specific problems yet to be solved. The
intent was to consider dominant characteristics for each technology
and make quantitative comparisons of those most important to definition
of R&D needs.
10
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The fourth step Involved development of R&D recommendations.
These were based on the estimated Importance of the technologies in control
of environmental pollution from energy production without excessive
dependence on foreign sources of fuel.
11
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PROJECTED TOTAL EMISSIONS FROM FUEL
COMBUSTION IN STATIONARY SOURCES
The calculation of total emissions from fuel combustion requires
a projection of fuel use, a fuel allocation assumption, a set of energy
technology availability projections, and unit emission factors for each
combustion process. All of the calculations in this study employ the
fuel-use projections contained in the energy supply/demand forecast of
(!}*
the Department of the Interior by Dupree and West. ' This energy fore-
cast gives the projected consumption of energy resources by major sources
and by consuming sectors for the years 1975, 1980, 1985, and 2000. The
energy sources include: coal, petroleum, natural gas, nuclear power,
and hydropower. The consuming sectors include: residential/commercial,
industrial, transportation, electrical generation, and synthetic gas.
For the purposes of this study the transportation sector was excluded
since only stationary sources were considered. The inputs to the syn-
thetic gas sector were combined with the inputs to the residential/
commercial and industrial sectors, as indicated in the Dupree and West
forecast. Finally, nonfuel uses of coal, petroleum, and natural gas were
excluded. The total energy forecasts used in this study thus include the
fossil-fuel inputs to the residential/commercial, industrial, and electri-
cal sectors less the nonfuel uses as denoted by Dupree and West.
The total emissions resulting from the combustion of the
quantities of fuels projected depend upon the nature of the fuel consumed,
the manner in which the combustion takes place, and the degree of
emission control applied. A portion of the projected fuel supply can
be classified as clean fuel, i.e., fuel which can be burned without need
for advanced emission control. Clean fuel supplies include natural gas,
low sulfur coal, and low sulfur residual oil. The remainder of the fuel
to be used is referred to as dirty fuel, i.e., that which requires the
application of some energy technology if ambient air quality is to be
maintained.
*References are listed on page 98.
12
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Total emissions were calculated for three different scenarios
which Incorporate variations In the allocation of clean fuels and In the
energy technology applied. The quantities of coal, petroleum, and
natural gas consumed In each sector and, therefore, the total quantities
of each fuel are Identical In each scenario. The assumptions, calculations,
and results pertaining to each scenario are detailed In the following
sections.
Scenario 1. Assumed Application of Energy
Technologies, Preliminary Projection
Fuel Allocation Assumptions
The manner in which various fuels are allocated has a bearing
on the total emissions in view of the fact that, in general, different
emission factors are associated with different classes of combustion
sources. An optimum fuel application strategy would assign clean fuels
to smaller sources, which are unable to apply advanced emission control,
and provide energy technologies for large sources. The fuel allocation
for Scenario 1 was based on this premise. The supply of clean fuel was
arbitrarily allocated to the residential/commercial sector first, to the
industrial sector next, and any residual clean fuel was assigned to the
electrical sector. It may be noted that the projected clean-fuel supply,
presented in the following section, is sufficient to satisfy the
residential/commercial and industrial sectors through the year 2000.
Thus, in Scenario 1, dirty fuels were employed, with and without applied
energy technology, only in the electrical sector. In this context,
cleaned coal and high Btu gas from coal or oil were included in the clean
fuel supply and both are allocated to the residential/commercial and
industrial sectors.
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Clean Fuel Supply Projection
The supply of clean fuel was estimated for 1975, 1980, 1985,
and 2000 based on information available to date. The clean fuel supply
projected in this section includes the naturally clean fuels such as
natural gas, low sulfur coal, and products of normal refinery processes
(distillate fuel oil and low sulfur resid) and cleaned fuels such as
cleaned coal and desulfurized resid. Synthetic gas was also included
since it can be substituted for natural gas and does not require on-site
utilization. Only the quantities available for fuel uses in three
sectors were projected: the residential and commercial sector, the
industrial sector, and the utility sector.
Gaseous Fuel. A gaseous fuel supply was projected according to
Dupree and West, ' and the result is shown in Table 1. The domestic
supply accounted for 96 percent of the total supply in 1971. The fore-
cast, however, indicates that by 2000 the supply will rely considerably
on imports (approximately 28 percent of the total supply). Synthesis of
high Btu gas from coal and oil is projected to be developed and commercial-
ized by 1980.
Petroleum. Among various petroleum products, distillate and
residual* fuel oils were allocated to fuel utilization in the three
sectors under consideration. Lighter fractions such as gasoline and
jet fuels would be used for transportation, and other fractions would
be used for petrochemical feedstocks, asphalt, or other nonfuel purposes.
Distillate fuel oil is a clean fuel which contains less than
(3)
one percent sulfur by weight. Minerals Yearbook 1973v indicated that
distillate fuel oil accounted for 17.5 percent of the total consumption
of petroleum product in 1971. In this projection, the ratio was assumed
14
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TABLE 1. PROJECTION OF CLEAN GASEOUS
FUEL SUPPLY(a) (Unit; 1012 Btu)
Year
Fuel 1975
Domestic Natural 22,600
Gas
Domestic Synthetic
f*n c* ^_^_^^^_
Gas
Total Domestic 22,600
Supply
Pipeline 2,100
Imports
LNG Imports 500
Total Imports 2,600
Total Supply 25,200
Nonfuel and 1,700
Transportation Uses
Total Gaseous Fuel 23,500
Supply
1980
23,000
700
23,700
3,100
900
4,000
27,700
2,200
25,500
1985
22,500
2,000
24,500
4,200
1,700
5,900
30,400
2,400
28,000
2000
22 , 900
5,500
28,400
7,600
3,500
11,100
39,500
3,500
36,000
(a) Source: Reference 1
15
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to hold for the forthcoming years to 2000. The distillate fuel oil
supply was then estimated by using Dupree and West's projection of
total petroleum supply. The results are given in Table 2.
The low sulfur residual fuel oil (low sulfur resid) is defined
as residual fuel oil containing less than 1 percent sulfur by weight.
The limit of 1 percent sulfur content was restated as 0.5 percent for the
2000 projection because the projected increase in total fuel utilization
will require a lower limit to maintain acceptable ambinet air quality.
Such residual fuel oil is obtained either as a product of petroleum
refining or by desulfurizing high sulfur residual fuel oil.
(4)
According to the study by Hittman Associates, Inc., the
domestic supply of low sulfur residual fuel oil was 0.17 x 10 bbl/day
in 1970 and the foreign supply was 0.9 x 10 bbl/day. The corresponding
supplies of low sulfur residual fuel oil containing sulfur less than 0.5
percent were 0.04 x 10 bbl/day and 0.39 x 10 bbl/day for domestic and
foreign sources, respectively. The foreign supply was mainly from South
American refineries. An annual growth rate of 10 percent was estimated
for the supply until 1980 and then the rate was assumed to decrease to
5 percent through 2000. Based on this information, the supply projection
was made as shown in Table 2. The initial rapid increase in supply is
attributed to the facts that the U. S. fuel demand for the industrial and
electrical sectors will depend heavily on low sulfur resid until other
fuel-cleaning or conversion technologies become commercialized; and that
South American refineries are apparently willing to invest in, construct,
and operate desulfurization plants. Such facilities are projected by
Hittman to grow at the annual rate of 15 percent until 1980.
Coal. Low sulfur coal is defined as coal containing less than
1 percent sulfur by weight on dry basis. As in the case of residual oil,
this definition was restated as 0.5 percent sulfur for the 2000 projection.
Generally, the sulfur content of coal varies depending on the location of
the coal basin and the type of coal. Hoffman,
survey of coal availability by sulfur content.
the coal basin and the type of coal. Hoffman, et. al. conducted a
16
-------
TABLE 2. PROJECTION OF CLEAN PETROLEUM FUEL SUPPLY
Distillate Fuel Oil,
in 106 bbl
in 10 12 Btu
Low Sulfur Residual
Fuel Oil (< 1.0% S),
in 106 bbl
in 10 12 Btu
Low Sulfur Residual
Fuel Oil (< 0.5% S),
in 106 bbl
in 10 12 Btu
Year
1975 1980 1985 2000
1,070 1,280 1,540 2,190
6,200^ 7,500 9,000 12,800
630 1,010 1,290
3,800(b) 6,100 7,700
925
5,500
Total Clean Petroleum
Fuel Supply,
in 1012 Btu 10,000 13,600 16,700 18,300
(a) Heating value of distillate fuel oil is 5,825,000
(b) Heating value of low sulfur residual fuel oil is 6,000,000
Btu/bbl.(2)
17
-------
The domestic production of coal in 1971 by states is summarized
(2)
in Minerals Yearbook 1971v . To obtain the production of low-sulfur
coal for the year, the coal production of each state was reclassified
into several groups based on the sulfur content according to the informa-
tion obtained by Hoffman, et al. ' From this data the ratio of low
sulfur coal to total coal production was obtained to be about 0.33 in
terms of heating value. The corresponding ratio for low sulfur coal
containing sulfur less than 0.5 percent was about 0.17. A low sulfur
coal supply was projected according to Dupree and West's^ ' projection
of the total coal supply by assuming that the ratios hold for the forth-
coming years. The results are shown in Table 3.
A supply projection for cleanable coal was made by a similar
approach. However, in this projection, the supply of coal with sulfur
contents ranging between 1 and 1.5 percent (or 0.5 and 0.75 percent for
the year 2000) was estimated. Such coal would yield <1 percent sulfur
(or <0.5 percent sulfur) if coal cleaning methods are assumed to remove
about 35 percent of sulfur in coal, a nominal effectiveness for coal
cleaning. Actual sulfur removal varies greatly with coal type and with
the form of sulfur present.
Preliminary Energy Technology Availability Projection
In calculating the total emissions to be anticipated from the
projected use of fuels, it is necessary to specify how the fuels are to
be utilized. For this purpose a preliminary projection was made of the
availability of the various energy technologies. This preliminary pro-
jection is shown in Table 4. The projected application of each technology
12
is given in units of 10 Btu. These units can be converted to equivalent
4
electrical-generation capacity as follows: assuming a heat rate of 10
Btu/kwhr and a load factor of 68 percent, a 1000-MW power plant burns about
19 12
60 x 10 Btu/yr or, conversely, 1000 x 10 Btu/yr is equivalent to about
16,800 MW of electrical generation capacity. For some technologies the
projections are based on published information. For others the projections
18
-------
TABLE 3. PROJECTION OF CLEAN COAL FUEL
SUPPLY (Unit; 1012Btu)
Year
Fuel 1975 1980 1985 2000
Low Sulfur Coal 5,400 6,200 8,200
(< 1% S, dry basis)
Low Sulfur Coal 6,100
(< 0.5% S, dry basis)
Cleanable Coal 1,800 2,100 2,800
(< 1% S, dry basis)
Cleanable Coal 2,900
(< 0.5% S, dry basis)
Total Low Sulfur Coal 7,200 8,300 11,000 9,000
19
-------
were obtained by estimating the year of first commercial availability, the
capacity which might be available in the following reference year, and
finally the growth rate which might be achieved during subsequent periods
of time.
The application values entered in Table 4 for gasification of
coal (high Btu) were taken directly from Dupree and West after converting
their energy input values to outputs by the assumed conversion efficiency
of 70 percent.
Projections of the availability of flue gas scrubbing technology
vary widely from source to source. The Sulfur Oxide Control Technology
Assessment Panel (SOCTAP),^ the Mitre Corporation,^ ' and EPA's Office
Cumulative
Installed
Capacity, MW
10,000
15,000
25,000
Approximate
Equivalent
in 1012Btu
600
900
1,500
Cumulative
Installed
Capacity, MW
161,000
116,000
45,000
Approximate
Equivalent
in 1012Btu
9,700
7,000
2,700
of Planning and Evaluation (OP and E) ^ have made such projections which
are summarized in the following tabulations:
_ 1975 _ _ 1980
Cumulative
Installed
Source
SOCTAP
Mitre Corp.
OP and E
The mean between the SOCTAP and the Mitre projections for 1975 and the
Mitre value for 1980 (near the mean of the other two) were chosen for the
projection in Table 4. The references cited above did not include
projections beyond 1980. For this projection it was assumed that the
growth rate would decline between 1980 and 1985 and that the total installed
capacity would be less in the year 2000 than in 1985. The rationale for
this assumed growth pattern is that, in the absence of sufficient alterna-
tive energy technology, flue-gas cleaning should grow as rapidly as
possible through 1980; then the growth rate may be expected to reverse
with the advent of fuel conversion and alternative combustion modes. This
projection is optimistic in two respects. It assumes that improved
technology will be developed and introduced very rapidly. Also, it assumes
that large quantities of foreign oil will be available to meet clean fuel
20
-------
TABLE 4. PRELIMINARY TECHNOLOGY AVAILABILITY PROJECTIONS
Year of 1st
Technology Conn- Size Plant
Coal Gasification,
low Btu-Conv. Boiler 1978
Coal Gasification-High Btu 1977
Coal Liquefaction 1980
Fluidized-Bed Combustion
of Coal 1977
Flue-Gas Cleaning 1968
Throwaway
By-Product
Chemically Active
Fluidized-Bed (Oil) 1977
Nuclear
Year of Comm Prelected Application, 10
Availability 1975 1980 1985
1983 -- -- 480
1979 — 300(a) 1400(a)
1984 -- — . 300
1983 -- — 400
1975 750 7000 9000
610 5000 6230
140 2000 2760
1979 — 200 1000
2560(a) 6720(a) ll,750(a)
Btu
2000
3900
5000(a)
2500
3000
5500
2800
2700
3000
49,230(a)
(a) Dupree and West, Reference 1.
-------
needs. If new coal-based technologies are not developed on the assumed
schedule flue-gas cleaning could continue to grow until nuclear plants
start to dominate in production of electrical energy. Further, even if
new coal conversion technologies are developed at a very rapid rate
their contribution will be small compared to projected deficits of
domestic liquid fuels. Thus, the pressure to avoid over-dependence on
foreign energy supplies could result in expansion of flue-gas cleaning
beyond the estimated levels. The breakdown between the availability of
throwaway and by-product processes for flue gas cleaning for 1975 is based
on the approximate ratio (80/20) found to exist for those installations
under construction or planned. For the later years the proportionate
availability of by-product processes was assumed to increase, and the
ratios, 70/30, 60/40,.and 40/60, were chosen for 1980, 1985, and 2000,
respectively.
Coal cleaning was not included in this projection. Quantities
of coal cleanable to 1 percent sulfur or less were included in the clean
fuels projection. Physical cleaning methods are available now for treating
such quantities of coal. Similarly, desulfurized residual oil was in-
cluded in the clean fuels projections.
Fuel Utilization Projections
/•I N
The overall fuel use projected by Dupree and West ' was combined
with the fuel allocation and technology availability assumptions discussed
previously to provide a matrix of projected fuel utilization. The results
are presented in Tables 5, 6, and 7 for the residential/commercial,
industrial, and electrical sectors, respectively. For each sector the fuel
utilization is shown for type of fuel and energy technology applied (if any).
The subtotals for each fuel type equal the projected fuel use for each sector
as given by Dupree and West. The totals of clean fuels are equal to the
totals projected in Tables 1, 2, and 3, and the extent of each applied
energy technology is equal to that projected in Table 4. It should be
noted that the supply of clean fuel is sufficient to meet the residential/
commercial and industrial sector demand in each time period.
22
-------
ro
TABLE 5. FUEL UTILIZATION PROJECTION FOR RESIDENTIAL AND COMMERCIAL SECTOR
Scenario 1
(a)
Fuel Utilization Projection 1012 Btu
Fuel /Techno logy
Natural Gas (Clean Fuel)
Petroleum
Distillate Fuel Oil (Clean Fuel)
Gasification, High Btu Gas
Subtotal
Coal
Low Sulfur Coal (Clean Fuel)
Gasification, High Btu Gas
Total
Subtotal
1975
8,660
5,750
0
5,750
325
0
325
14,735
1980
9,480
6,440
183
6,623
300
137
437
16,540
1985
10,060
7,480
282
7,762
100
658
758
18,580
2000
10,800
9,520
240
9,760
0
2,400
2,400
22,960
(a) Excludes electricity purchased a.nd non-fuel uses,
-------
ro
TABLE 6. FUEL UTILIZATION PROJECTION FOR INDUSTRIAL SECTOR^
Scenario 1
Fuel Utilization Prelection, 10*2 Btu
Fue 1 /Technology
Natural Gas (Clean Fuel)
Petroleum
Distillate Fuel Oil (Clean Fuel)
Low Sulfur Res id (Clean Fuel) - Domestic
Low Sulfur Res id (Clean Fuel) - Imported
Gasification, High Btu Gas
Subtotal
Coal
Low Sulfur Coal (Clean Fuel)
Cleanable Coal (Clean Fuel)
Gasification, High Btu Gas
Subtotal
Total
1975
11,040
450
560
2,900
0
3,910
3,340
1,110
0
4,450
19,400
1980
11,750
1,060
530
2,820
217
4,627
3,410
1,140
163
4,713
21,090
1985
12,440
1,520
650
3,430
318
5,918
3,610
1,210
742
5,562
23,920
2000
17,040
3,280
740
3,800
260
8,080
3,970
1,330
2,600
7,900
33,020
(a) Excludes electricity purchased and non-fuel uses.
-------
TABLE 7. FUEL UTILIZATION PROJECTION FOR ELECTRICAL SECTOR
Scenario 1
10
Ul
Fuel Utilization Projection, 1012 Btu
Fuel/ Technology
Natural Gas (Clean Fuel)
Petroleum
Low Sulfur Res id (Clean Fuel) - Domestic
Low Sulfur Resid (Clean Fuel) - Imported
Chemically Active Fluidized Bed
High Sulfur Resid with Stack Gas Cleaning
High Sulfur Resid without Control
Subtotal
Coal
Low Sulfur Coal (Clean Fuel)
Cleanable Coal (Clean Fuel)
Fluidized-Bed Combustion
Gasification, Low Btu Gas
Liquefaction
High Sulfur Coal with Stack Gas Cleaning
Limestone Scrubber
MgO Scrubber
High Sulfur Coal without Control
Subtotal
Total
1975
3,800
40
300
0
50
.3,190
3,580
1,735
690
0
0
0
560
140
5,775
8,900
16,280
1980
3,600
450
2,300
200
350
1,700
5,000
2,490
960
0
0
0
4,650
2,000
560
10,660
19,260
1985
3,450
580
3,040
1,000
2,030
0
6,650
4,490
1,590
400
480
300
4,200
2,760
0
14,220
24,320
2000
2,640
160
800
3,080
1,000
0
5,040
2,130
1,570
3,000
3,820
2,500
1,800
2,700
0
17,520
25,200
-------
The combined clean fuel supply and energy technology is insuf-
ficient to meet the total energy demand in 1975, so that a quantity of
dirty fuel is assumed to be burned without control in that year. Similarly,
in 1980, a small deficit remains. However, with the assumed projections,
the clean fuel supply plus the energy technology availability is sufficient
to meet the demand for both 1985 and 2000 so that no dirty fuels are assumed
to be consumed without control in those time periods.
Projected Total Emissions - Scenario 1
In calculating total emissions to be anticipated from the
projected use of fuels for energy, the emissions arising from the entire
fuel/energy cycle were included. Following the methodology of an earlier
study carried out for the Office of Research and Development of EPA,(2) a
modular approach was employed in which individual modules, consisting of
extraction, transportation, conversion, or utilization phases of the
fuel/energy cycle, were appropriately combined into systems characteristic
of each mode of fuel utilization. The modules chosen for each system are
listed in Table 8. Each fuel/technology combination included in the fuel
utilization projections (Tables 5, 6, and 7) is included in Table 8 together
with the corresponding chosen modules.
Some simplifying assumptions were made in order to keep the
number of different systems to a manageable size. All residential/commercial
sector fuels were assumed to be used for space heating. All industrial
sector fuels were assumed to be used for on-site electrical generation or
for steam raising. It was further assumed that the emission factors for
fuels used to fire a steam raising boiler are equivalent to those associated
with a steam-electric boiler. The principal exception to the fuel use
assumption is the significant fraction of coal used in the industrial sector
for the production of coke. There are a number of coal gasification
processes under development. Only the Hygas process was included for
high Btu gasification of coal and the Lurgi process was used for low
Btu. Limestone scrubbing was selected for the throwaway type of stack-
gas-cleaning technology and the MgO process was used to represent the
by-product type.
26
-------
TABLE 8. MODULES COMPRISING FUEL/TECHNOLOGY SYSTEMS
Scenario 1
N>
•xl
Fuel/Technology System
RESIDENTIAL AND COMMERCIAL SECTOR
Natural Gas (Clean Fuel)
Petroleum
Distillate Fuel Oil (Clean Fuel)
Gasification! High Btu Gas
Coal
Low Sulfur Coal (Clean Fuel)
Gasification, High Btu Gas
INDUSTRIAL SECTOR
Natural Gas (Clean Fuel)
Petroleum
Distillate Fuel Oil (Clean Fuel)
Low Sulfur Resid (Clean Fuel)
Low Sulfur Resid (Clean Fuel)
Gasification. High Btu Gas
Coal
Low Sulfur Coal (Clean Fuel)
Cleanable Coal (Clean Fuel)
Gasification, High Btu Gas
ELECTRICAL SECTOR
Natural Gas (Clean Fuel)
Petroleum
Low Sulfur Resid (Clean Fuel)
Low Sulfur Resid (Clean Fuel)
Chem. Act. Fluidlzed Bed
High Sulfur Resid with Stack
Gas Cleaning
High Sulfur Reaid without Control
Coal
Low Sulfur Coal (Clean Fuel)
Cleanable Coal (Clean Fuel)
Fluidized Bed Combustion
Gasification, Low Btu Gas
Liquefaction
High Sulfur Coal with Stack
Gas Cleaning
•
High Sulfur Coal with Stack
Gas Cleaning
High Sulfur Coal without Control
Extraction
Gas Well
Oil Hell
Oil Well
Coal Mine
Coal Mine
Gas Well
Oil Well
Oil Well
Import
Oil Well
Coal Mine
Coal Mine •
Coal Mln*
Gas Well
Oil Well
Import
Import
Import
Import
Coal Mine
Coal Mine
Coal Mine
Coal Mine
Coal Mine
Coal Mine
Coal Mine
Coal Mine
Transport
None
Oil Pipeline
Oil Pipeline
Rail
Rail
None
Oil Pipeline
Oil Pipeline
Import
Oil Pipeline
Rail
None
Rail
None
Oil Pipeline
Import
Import
Import
Import
Rail
None
Rail
Rail
Rail
Rail
Rail
Rail
Modules
Processing/ Conversion
Desulfurization
U.S. Refinery
Gasification
None
Hygas
Desulfurization
U.S. Refinery
U.S. Refinery
Import
Gasification
None
Physical Cleaning
Hygas
Desulfurization
U.S. Refinery
Import
Import
t Import
Import
None
Physical Cleaning
None
Lurgl Gas
Liquefaction
None
None
None
Transport
Gas Pipeline
None
Gas Pipeline
None
Gas Pipeline
Gas Pipeline
None
Barg;
Tanker
Gas Pipeline
None
Rail
Gas Pipeline
Gas Pipeline
Bargj
Tanker
Tanker
Tanker
Tanker
None
Rail
None
None
None
None
None
None
Utilization
Space Heating
Space Heating
Space Heating
Space Heating
Space Heating
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
FluiUizea ded
Combustion
Conv. Boiler,
Liae Scrub.
Conv. Bciler
Conv. Boiler
Conv. Bciler
Fluidized Bed
Combustion
Cor.v. Boiler
Conv. Boiler
Conv. Boiler,
Lime Scrub.
Conv. Boiler,
MgO Scrub.
Conv. Boiler
-------
The emissions associated with each module were quantified
first on a unit basis, i.e., in pounds per million Btu. Emissions were
identified for 10 pollutants as follows.
Air Emissions
Nitrogen oxides, NO
Sulfur dioxide, SO-
Carbon monoxide, CO
Particulate, part
Total organic material, TOMA
Water Emissions
Suspended solids
Dissolved solids
Total organic material, TOMW
Solid Waste
Ash
Sludge
Some of the unit emissions data were taken from the previously cited earlier
(2)
work and the remainder were generated as required. A summary of these
data as used in the calculations is given in Table 9. The unit emissions
data are given in a more detailed format in Appendix A with footnotes
detailing the derivation and the control technology assumptions involved
in each case. Of note in the latter context are the following points:
(1) Stack gas cleaning modules assume 90 percent
reduction in S0_ and 20 percent reduction in NO
£» X
(2) Boiler modules assume 99 percent efficiency for
particulate removal.
The total emissions for each fuel/technology system were obtained
by summing the emissions of each pollutant from each module (Table 9) in
the system to obtain the total pounds of each pollutant per million Btu
input to the utilization module of the system. No weighting factors were
used in this summation to reflect possible variations in the importance of
emissions from one module to another. It was necessary, however, to include
an efficiency correction in the calculation to properly account for the
fact that, for example, more than a million Btu of coal must be produced in
the coal mining module, with an attendant increase in pollutant emissions,
to provide a million Btu input to a power plant, if an intermediate module
28
-------
TABLE 9. UNIT EMISSIONS OF INDIVIDUAL MODULES
\o
(Pounds Per Million Btu)
"OOULES
GAS HUL
GAS O'SULPIISIJATION
GAS PTPrLINr
5"ACE Mr ATIWi-NAT IAS
OIL H'LL-ON-SH09E
OIL PIp"LT''t:
U.S. RFrTNr!?Y-00«1tSTTC
5PACF H~ATI'4K-niST OIL
C"UOE OIL RASIFTCATTIK
st-!ip "if.cn u'liu-^cST
SPACl HtAI JMIi-iJUALIlX Bl
HY«;AS
Cnriv 1U1LEB-*I4I GAS
CONV «OTL«-niST flTL
Hilt «« *-'•.•.
CONV nPtLPC-l?:rst'i( ix si
"""" OIL TAWCc1?
COMV nPILF^-LDM S C1AL
PHYS CLEANING IF COHL
FLUIPt7eO ICO COMB OF orjjjn
CONV POILrp-'!" CONTROL JKEST")
'" FLUIf PEn pn**1-COAL*CO'"*"iJYr
COAL r,ASIFtLU'»GII*C'>NV "OTLF°
„ COAL LIlffFACTIONCSPL R'FINI
it'i'iv tin JL; -~i»'iL xc"!" I.UOL
„ CONV mil rPtLTMESCR'Jn (COAL 1
CO'W ROtLc"+d"iy sii5*'! * it'iBL i
ii" CO*'V 10TLr'*NO CINT^TL (COALI
» COft OVt».'(G.«»5X SI
s^nit »"L • i I"*1*" '"."si in .'i»y, si
i S°*CF HPATI'IG-COAL <^X SI
.9^.0
l.OJO
.9'?9
l!oiQ
.930
.770
.118
1.030
'.III
'.370
.770
!?70
.31U
.340
.370
!259
. i 'u
.750
« •' IV
.359
. J IU
.370
.900
• fVU
.500
UNIT 51ISSIONS
NDY
.2300
0.0000
. 0910
0.3000
.9990
.0100
0. liOOU
.1300
. 11 'H
. '"3UU
.71CO
. U 1 1 »*
.7900
.uuir
i'lAOC
.7COC
.mOO
. o •« v ii
.3ior
. 9 D U U
• OUUU
.750t
. u u u e
.0017
. 1 J3U
.1170
S03
0.0000
O.OC30
. OC 10
.0311
.OlbC •
.1?OC
. 2610
.0430
0. 0090
1. 4f OC
.5500
•OuUb •
.3360
. I'l 11
l.ObOO
. UUlb
l.f.510
. UL'40
.4500
3.6600
. 7ui)u
.9300
.0030
• f 1 UU
.5000
. t>uuu
4.7500
u. uuuu
.8000
5. UO fU
CO
0.9000
0.0000
O.JOOO
. 0150
0.0000
0.0000
.0030
.0300
3.0000
0. UQGO
.01^0
0.0000
.UOU«f
.3003
. J U 1 1
0.0000
. U 0 1 .1
D.UUUU
0.0000
0.0000
0.0003
• U »9U
.01?C
• u ) ru
.*04?0
U. JUUU
.0530
• U -1 U U
3.4900
PA9T
0.0000
0.0000
0.0030
«ac5o
o.oooo
• 90?0
.0320
.0170
.3020
. J7GO
.0015
!l?03
!o570
. u J 1 n
.1500
.0703
• 01UU
.01C3
. U U U 9
.0500
.0150
.2700
0 UUU 1
.1000
.1COC
. ituu
.1460
• U 1 f U
.7750
TOf-A
.1009
0.0000
0.0900
. OOVJ
3.0009
.0301
.0250
.0040
o.ocno
O.OC91
.7753
.0014
• 0400
.0140
. UJU1
.0101
.0001
.0161
o.oOoo
.Q400
. u i u a
.0103
0.0003
.1100
. u iiu
.003 (a) Total organic material - air.
1 (b) Suspended solids
« (c) Dissolved solids
, (d) Total organic naterlal - vater.
2
-------
(say physical coal cleaning) has an efficiency less than 100 percent. The
module efficiency factors used in this calculation are also given in Table 9.
The total unit basis emissions for a given system were than
multiplied by the fuel quantity projected for that system (Tables 5, 6, and 7)
to obtain the total quantities of pollutants produced in the extraction,
transportation, processing, and utilization of the projected quantity of
fuel. The resulting total pollutant quantities were than summed over all
of the systems in each sector, for each year, and finally for all sectors.
A computer program was written to carry out the required calculations. The
results of the calculations for Scenario 1 are compiled in Tables 10, 11,
12, and 13.
The results show that, with the preliminary technology availability
projection, about 29 million tons of SCL will be produced in 1975 but that
this would be reduced about 37 percent to 18 million tons by 1980,
principally through the application of stack gas cleaning technology. In
spite of the large increase in fuel consumption between 1980 and 2000, the
SO emissions would rise only moderately to 20 million tons due principally
to the increased availability projected for fluidized bed combustion of
coal and oil, low Btu gasification of coal and coal refining (liquefaction).
It should be noted that if coal used for coking had been considered in the
industrial sector, rather than assuming that all of the coal is burned in
boilers, the total S02 emissions would be about one million tons per year
less than is shown in Tables 11 and 13. This estimate is based on a
12
projection of 2400 x 10 Btu of coal used to make coke with 50 percent of
the contained sulfur retained in the coke, and ultimately in the steel
mill slag, and 50 percent emitted as S0_ with the coke oven gases.
The total NO emissions rise steadily through the 1975-2000
3C
period reflecting the increased fuel use and the lack of any significant
NO control availability. The total particulate emissions are small
X
compared with those of S02 because of the high particulate collection
efficiency assumed for boilers. The technology for achieving such
efficiency is currently available but it is not universally practiced.
The stated particulate emissions do not specifically include fine parti-
culates. Technology for fine particle control is not currently available.
30
-------
TABLE 10. TOTAL EMISSIONS FOR SYSTEMS IN THE RESIDENTIAL/COMMERCIAL SECTOR, SCENARIO 1 '
i
SYSTEMS
NATUPAL GASCCLEAN FUEL)
OIST FUEL OILCCLEAN FUEL)
GASIFICATION-OIL, HIGH STU
LOW S COAL(CLEAN FUEL)
GASIFICATION-COAL, HIGH RTU
EMISSIONS, THOUSANDS OF
NOX
2705.53
483.00
0.00
22.26
0.00
S02
117.21
1152.56
0.00
239.10
0.00
CO
64.95
94.87
0.00
569.56
0.00
PART
21.65
61.01
0.00
137.56
0.00
TONS
TOPA
iy/i
468. 93
84.33
0.10
125.94
O.OQ
SS
0.
11.
0.
45.
0.
00
50
00
50
00
OS
0.00
20244.17
Q.OO
0.90
0.00
TO"W
0.00
29.66
G.OO
O.CO
0.00
ftSH
o.no
o.ro
3.00
1121.95
0.00
c
SLUDGE »
s
0.00
20.1? '
0.00
0.00 ,
0.00
i
TOTAL
NATURAL GASCCLEAN FUEL)
DIST FUEL OILCCLEAN FUEL)
GASIFICATION-OIL, HIGH BTU
LOW S COAL (CLEAN FUEL)
GASIFICATION-COAL, HIGH BTU
OJ
•"" TOTAL
NATURAL GASCCLEAN FUEL)
OIST FUEL OILCCLEAN FUEL)
GASIFICATION-OIL, HIGH BTU
LOW S COAL(CL?AN FUEL)
GASIFICATION-COAL, HIGH BTII
3210.79
2961.71
540.96
43.99
20.55
<»6.«2
3611.61
314'. 91
628.32
67.77
6.R5
222.93
1501.87
128.31
1290 .87
5.90
220.71
79.51
1685 .29
136.16
1499.33
9.10
73.57
189. 7<»
729.39
71.10
106.26
1.37
525.75
2.65
707.13
75.45
123.42
2.11
175.25
12.73
220.22
23.70
68.34
.90
126.97
24.23
244. 13
25.15
79.37
1.38
4?. 32
116.36
679.10
1980
513.2?
94.45
.7*
116.25
.37
725 .09
1985
544.6?
109.71
1.21
38.75
1 .10
57.
0.
12.
0.
42.
59.
114.
0.
14.
0.
14.
?95.
00
00
99
00
UU
52
40
00
96
00
00
39
20?44.17
o.ro
22673.48
777.14
0 .CO
19. M
23470 .09
o.no
26335.03
1197.56
3.00
93.56
?9.66
0.00
3?.l C
1.00
0.00
0.00
3"? .10
0.00
37.79
1 .54
0.30
1.00
11?1.?5
0.00
G.OQ
7.63
1035.00
478.57
1=521. ?0
O.GO
0.00
11.76
345.00
??99.54
20.12 t
01
t
0.00
22.54 »
7.63
0.00 <
1869.83
i
1899.00 (
0.00
26.18 >
11.76
0.00 ,
8975.95
i
TOTAL
11
10
NATURAL GAS(CLEAN FUEL)
OIST FUFL OILCCLEAN FUEL)
GASIFICATION-OIL, HIGH BTU
LOW S COALCCLEAN FUEL)
GASIFICATION-COAL, HIGH RTU
4068.78
337<*. 10
799.68
57.67
o.oo
813.12
1907.89
146.17
1908. 2<»
7.74
0.00
692.07
388.97
91.00
157.09
1.80
0.00
46.44
264.59
27.00
101. 02
1.18
0.00
424.43
696. 09
2000
584.69
j 39.63
1 .03
0.00
6.55
314.
0.
19.
0.
0.
104?.
85
00
U4
00
UU
75
27626.15
1.00
33517. 31
1019.20
0.00
341.26
33.93
o.oc
47.46
t .31
0 .OC
0.00
2655.3Q
0.00
O.CO
10.01
0.00
8383.73
9013.79 «
0.00
33.32 9
10.01
0.00 ,
3?738.65
i
TOTAL
t
5044.58
2754.22
296.32
553.62
731.89
1061.
/y
34877.77
49.77
8393.74
32781.99 t
i
-------
u.
SECTOR. SC=TaHIC I
fTSSIOfS. T»*WFS«'r'S
-—
~CO"
"ST
1575
mtmMHL 6>StCL5M FBJELI
MSI Him MtMiem PBHT"
5'Sk.TS
2.21
"T7%-
79*-.*t
-7%^
r.ri
TTT
f-rt
TTT^
21 5.
1K.&9
331.36
1.15
1*17.17
*.*•
151* .32
t.**
B.B1
115.?^
15.69
».••
If.lS
1. 1?
i.t
i.t
T.II
*.Tf
?.*«
f •
TTil,
T7T5,
at
iTii.
LM
l«7*.ei
391. «
7757.9*
»«2.2t
—inr
5.It
T7TF
My
•E71T
TTff
TTrT
«.*7 IT??. = 5
6*S»O.£*1
2.35
..99
t.ri
fl.ll
31?.
1.75
1.C9
?*.»«;
«.*•»
t.rt
919.11
.9*
*.»•
I. II
1.7*
.IT
n.i?
1.1 =
t.tt
3.71 »
1.91
9.15
^•Z.SS
117.t*
38-21
12?. 3?
.5t
it 93.7 r
1.9%
T?.12
t:
9.9
1WTM.
ltfl.5'
!«•:.*»
9X.3B
3SI.16
3«3.%5
Z.51
1.3%
11. 7%
*.* "*
€«- 1
>.->
»^7.^7
t.ri
213.
13%.93
15.3*
.rl
». 57 *
».?*
tTff .
3*6.9*
677S.M
771.7*
1*1*.39
.79 1»»*9.»7
LI
3.-1
3.1C
i.tr
•1ST FUEL •IXfCLEM
S
LMI S e?
ML.
S CB*L«Cl£M FUEL I
777.lt
l.S?
gf.73
4%. 51
13.M
6.5%
11.*9 *
1?3?.BS
1979.*k
«.33
99.99
2.57
19.19
S.99
•.*•
7.19
s.rs
1.-?
11. 9*
19*5.19 3279.13
136.9%
,** 31.76
MS. 42
l.il
l.*9 *
7.31
MXCM BTH
7«9.22
31.33
.*• 53.9*
115*. «. 5
3*9.7*
*.*•
-------
tz. vru.
so?
CO
ss
1*75
ITWAL
177%.21
S ^
S
1%-M
1.51
.2%
i.it
.3% *
ft
!.*•
«CTI»£
s
.•i
.M
• .It
i.ai
J.ti
t.tt
.34
MK.S9
Z.C7
S9.W
•3.11
16.11
13. *<
rt
tv.za
I.M
I.H
i.Sf
SI
t.tt
9.It •
R.W
<
l.tfl
l.ll
a.n
C.JJ
I.H
t.M
.ct
.ft
-.11
£.tt
s.r?
£.91
I.II *
I.M
15.96
1.99
3.6%
.9t
Ifl.Ct
Sl.%t
12.g-»
.77
!«*.«•
1371«.67
697.33
17.5*
1661.31
519.75
693.II
1555.11
9%19.63»
.«.3
755.39
612.••
532.3% 25475.76 67*63.15
-------
TABLE 12. TOTAL
EMISSIONS FOR SYSTEMS IN
THE ELECTRICAL SECTOR,
SCENARIO 1 (Continued)
i
i
SYSTEMS
NATURAL GASICLSAN FUEL)
LOW S RESIO-OOMESTIC
LOW S PESIO-1M«M«TED
CHEN ACTIVE FLUIOIZEO RED
HIGH S RESjfn-LIMESTONE SCRUB
HIGH S RESIO-NO CONTROL
LOW S COAL(CL£AN FUEL)
CLEANA«»LE COAL (CLEAN FUEL)
FLUintZeO RFO C01HUST ION-COAL '
GASIFICATION-COAL, LOW HTU
LIOUEFACTION-COAL
HIGH S COAL-LlHtSTONE SCHUft
HIGH S COAL-HGO SCRUB
HIGH S COAL-NO CONTROL
TOTAL
EMISSIONS, THOUSANDS OF
NOX
1610.86
212.99
1066. Sfcf
712. 02
0.00
22<>5.QQ
561.45
32.04
100.85
119.54
855.88
0.00
8900.07
S02
4.59.72
' i#B?'«
225.80
373.11
0.00
1707,39
1149.09
140.28
223.5*,
107.23
1052. 9<*
691 .91
0.00
10054.16
CO
414.40
4.10
1.98
.65
1.32
0.00
3.00
3.60
10.35
119.70
78.66
0.00
834.80
PART
419.59
18.52
6.05
0.00
317,67
170.60
12.30
37.56
507.15
333. ?7
0.00
2013.38
TONS
TOMA
48?. M
13.1?
20.05
10 .»5
0.00
8.75
0.90
26.40
2. Ob
27.30
17.^1,
0.00
660.03
SS
4.08
0.00
0.00
0.00
0.00
f flb. 72
516.75
110.00
135.84
113.75
1297.50
793.50
0.00
4C07.45
ns
41^ • 71
2053.13
n.oo
0.00
O.PQ
I.JO
" .00
162.61
16,10
43.20
378.00
0.00
3171. C6
TOMW
1,11.71
10.16
2?. 80
7.50
15.22
o.co
2*. 64
8.75
0.00
1.65
23.10
15.1 8
0.00
543.25
ASH
Ml.
0.
1*00.
0.
4300.
2356,
504D.
0.
<,2°qf,.
71
PQ.
00
00
95
80
00
OQ
90
02
c
SLUOGE •
t
411,71
4.95 «
0.00
0,00 .
14007.00
Q.OO •
Q.OO
455.32 '
57.60 o
48.00
57834.90 "
311. ?0
0.00 •''
73199.78
£
2000
NATURAL GAS (OLE AN FUEL)
LOW S RESIO-DOMESTJC
LOW S RESIQ-IMPQRTEO
CHE* ACTIVE FLUIOIZEO 1FD
HIGH S RESIO-LtMESTOVE SCRUB
Hltrf S RESID-NO CONTROL
LOW S C^AL (CLEAN FUcL)
GLEBNABLE COAL (CLEAN FUEL)
FLUIOI7EO BcO COMRUST ION-COAL
BASIFICATION-CSftl, LOW RTU
LIQUEFACTION-COAL
HlGH S COAL-LIMESTONE SCRUB
HIGH S COAL-HGO SCRUB
HJ5W 5 liO»L-NU UUNIKUL
TOTAL
1212.66
58,7"5
280.60
350.75
0.00
1065.00
554.39
24 0.30
916.17
"558.18
837.27
O.DQ
'7225.36
151. ?«
93.76
183.80
0.00
1759.74
1114.64
1052.10
1776.97
893.58
451 .26
676.89
0 .DO
9487.64
317.11
1.13
.52
2.ob
.65
0.00
73.49
82UO
S8.65
86.25
51.30
76.95
0.00
702.15
3*6.38
5.11
20.84
18.63
1.30
Q.OO
150.70
168.45
242.85
573.71
217.35
326.02
0.00
2359.66
369.18
1.68
4.04
61 .75
5.05
Q.OO
8.61
0.00
?id. in
17.00
11.71
17.55
U « 3U
7*5.92
337.70
1.1?
0.00
0.00
0.00
0.00
3?4.8?
51 C .35
825. QO
~188l."06
S47.92
517.50
776,25
0,00
5321.63
31f .58
5 66 . 1 8
0.00
9.00
0.00
O.QO
0.00
160 . 57
27i.no
300.00
16?. PO
241. OP
U • U 0
?362.33
316,58
3.80
6.90
21.10
7. SO
0.00
11.71
0.00
11.75
9.90
0 . 3 0
bl8.65
316.
•
0.
o!
0.
?59*9.
?ari8.
3240 !
Q «
88014.
•58
SI)
90
90
Do
90
75
do
00
3 Q
19
316.58
1 . 17 »
9.00
n.9(5,
6900.90
0.90 .
0.00
360. QQ
400.00
24786. 90 u
324.00
u • Q U tl
33995.94
-------
TABLE 13. SUMMARY OF
TOTAL EMISSIONS FOR EACH SECTOR AND TOTAL EMISSIONS FOR ALL SECTORS, SCENARIO 1
t
SECTORS
RESIDENTIAL ANO COMMERCIAL
INDUSTRIAL
ELECTRICAL
EMISSIONS, THOUSANDS OF
NOX
3?10.79
8615. 71
6582.80
SO?
1508.87
565<».55
22361.49
CO PART
729.39 220.2?
150.63 51*3.21
721.71 1555. 0«
TONS
TOMA SS OS TOMM
1975
679.10 57.00 202H4.17 21.66
862.87 960. -*4 3677.37 "55.1.7
ftin.'fc 2836.76 1250.60 531.11
I
4SH SLUDGE •
s
11'1.?5 ?0.12*
183^', 55 321.41 ,
45P19.13 9«*19.6?
1
TOTAL
RESIDENTIAL ANO COMMERCIAL
INDUSTRIAL
ELECTRICAL
18U09. ?9
3613. ft
9358.63
7349.87
29525.30
161?. ?9
588?. 60
10910. l»3
1601.73 ?318.51
707.13 31.1.. 13
156.58 601., 35
755.39 1731.71
?15?.?1 3.S54.21 35172.15 616.02
1 9 » 0
725. 9 9 111.. 1.0 33t.70.19 33,10
934.17 1C61.57 6666.74 5«i.?7
613.18 3228.26 2771.73 532.31*
6*773.63 9761.15 i
ti
11
I5»l.?3 1899.00
19H37.15 2564.58 •'>
25175.76 67463,15
w
- •
II
II
II
TOTAL
RESIDENTIAL ANO COMMERCIAL
INDUSTRIAL
ELECTRICAL
TOTAL
RESIDENTIAL ANO COMMERCIAL
INOUS?»I*L
ELECTRICAL
30233.11
1.061.78
10569.13
8900.07
33537. 9*
501.1*. 58
7225^36
181*78.32
1907.89
6775.08
1005b.l6
18737.13
275i*. 22
J4U.76
9".87.6l.
1619.1.1 2577.09
388.97 26«*,59
i7i*.18 770.70
831.. 10 2013.38
1347.45 301.8.67
286.32 553.62
703*.15 2359^66
2271, ?4 4404,34 33901.56 f>?4.7?
1985
696.99 3m. 85 ?7f,36.15 38.13
101<».39 1378,50 933H.S6 69.^1
660.33 1*007.1.5 3^71.06 51.3.35
2576.51 5780. li i.O?>6.B7 651.76
? 0 0 0
731.19 1061.79 34177.77 48.77
US!. 16 2734,57 15771.6*. *4,f>7
725.9? 53'1.63 2363.33 418.65
461.04.11 71926.73
'AST..^ 9013.79
••2133.38 10419,07
U?<19f<.0? 73199. 7R
67774.^1 9?70?.64
«393.74 3?781.91
1*<'14.18 33995U"*
f
1
TQTAL
?&954.7'8
20*58.6?
1 ? 0 H « or H 1 6 0 . 1 6
-------
Scenario 2. Assumed No Application of Energy Technology
To illustrate the degree of effectiveness of the various fuel
conversion and emission control technologies incorporated in the Scenario 1
projections, a second series of calculations was performed in which no energy
technology was applied. These calculations were carried out by substituting
modules and systems without control for any system in Scenario 1 using
either a fuel conversion or emission control technology. The fuel utiliza-
tion matrix was unchanged. For example, the fuel utilization projection
12
for the electrical sector called for 560 x 10 Btu of coal to be burned
with limestone scrubbing in 1975. For the Scenario 2 calculation,
I O
560 x 10 Btu of coal were assumed to be burned without control using the
conventional boiler, 3 percent sulfur module and the resulting total
emissions for 1975 entered for the coal/limestone scrubber system (now
uncontrolled) in the computer printout. All other systems involving either
fuel conversion or emissions control technology were treated similarly.
Those systems which utilize clean fuel or cleaned fuel were unchanged in
the Scenario 2 calculation.
Projected Total Emissions - Scenario 2
The projected total emissions for Scenario 2 are given for each
system, each sector, and for all sectors in Tables 14, 15, 16, and 17.
Comparison of the results of the calculations for Scenario 1 and Scenario 2
is provided in Table 18, which is a summary of the total emissions from
all sectors for both scenarios. The energy technologies applied account
for a 13 percent reduction in S02 emissions in 1975, as shown in Table 18.
This factor increases to nearly 70 percent by the year 2000. The slight
reduction in NO emissions shown in Scenario 1 as compared with Scenario 2
Ji
is due to the fact that somewhat reduced NO emissions are expected from
stack gas cleaning and from fluidized bed combustion of coal and oil.
36
-------
TABLE 14.
TOTAL EMISSIONS FOR RESIDENTIAL/COMMERCIAL SECTOR, SCENARIO 2
i
I
SYSTEMS
NATURAL GAS (CLEAN FUEL)
OIST FUEL OIL (CLEAN FUEL)
<}ASjFjrrATiON-r>ii . MIQH *TU
LOM S COAL (CLEAN FUEL)
Q4.SIF l£A.TlON»cO^L. HTQH BTU
TOTAL
NATURAL SAS (CLEAN FllFl »
OIST FUEL OIL
QASIF1CATION-OILT HIAM BTU
LOM S COAL (CLEAN FUEL)
8ASlFlCATION.COALt HlflH BTU
to
TOTAL
EMISSIONS, THOUSANDS OF
NOX
2705.53
483.QQ
0.00
22.26
0.00
3210*79
9961.71
540.96
15.37
20.55
9.38
3547.98
S02
117.21
1152.56
0.00
239.10
0.00
1508.87
138.31
1290.87
16.68
220.71
1777.35
CO
64.95
94.87
0.00
569.56
0.00
729.39
71. in
106.26
3. Q?
525.75
946.22
PART
21.65
61.01
0.00
137.56
o.oo
220*22
23.70
68.34
\.94
126.97
57.99
278.94
TONS
TOMA
1Q75
468.83
84.33
0.00
125.94
0.00
679.1o
1980
513.29
94.45
?.6B
116.25
53.09
779.70
ss
o.oo
11.50
0.00
45.50
0.00
57.00
n.no
12.88
.37
42.00
19.18
74.43
OS
0.00
20244.17
o.oo
0*00
20244*17
n.oo
22673.48
644.79
0*00
n.no
23317.77
TOMW
0.00
28.66
6.00
0.00
0.00
28.66
o.no
32.10
.91
0.00
O.QO
33.01
ASH
0.00
0*00
0.00
1121.25
0.00
1121*25
0*00
n.nn
1035.00
47?. 65
15Q7.65
SLUDGE
0.00
20.12
0.00
0.00
0.00
20.12
o.nn
22.54
.64
0.00
23.18
(
'
r
i
t
i
t
Cl
'*
'
t
i
t
1985
NATURAL GAS (CLEAN FUEI )
OIST FUEL OlLjCLEAN FUEL)
GASIFICATION-OIL, HIGH BTU
bOM S COAL (CLEAN FUEL)
ASIFICATION-COAL, HIGH BTU
TOTAL
3142.91
628.32
23.69
6.85
45.07
.
3846.84
136.16
1499.33
56.53
73.57
484.09
2249.67
75.45
123.42
4.65
175.25
1153.14
1531.92
25.15
79.37
2.99
42.32
278.50
428.34
544.62
109.71
4.14
38.75
254.97
952.19
0.00
14.96
.56
14.00
92.12
121.64
0.00
26335.03
992.84
0.00
0.00
27327.88
0.00
37.29
1.41
0.00
0.00
38.69
0.00
0*00
0.00
345.00
2270*10
2615.10
0.00
26.18
.99
0.00
0.00
27.17
'
i
i
2000
NATURAL GAS (CLEAN FUEL)
OIST FUEL OIL (CLEAN FUEL)
OASlFlCATlON-OlLt HTfln'BTU
LOM S COAL (CLEAN FUEL)
QASIFICATION.COAL. HTflH BTU
3374. in
799.68
20.16
0.00
164.40
146.17
19*8.24
48.11
0*00
1765.68
81 .00
157.08
3.96
0.00
4206.00
27.00
101.02
2.55
0*00
584.69
139.63
3.52
o.oo
930*00
n.oo
19.04
.48
0.00
336.00
0.00
33517*31
844t97
0*00
0.00
0.00
47.46
1.20
0.00
0.00
o.on
0.00
0.00
0.00
B2ftn.no
o.oq
33.32
.84
0.00
0TOA
'
'
i
TOTAL
4358.34 3868.19 4448.04 1146.36 1657.83 355.52 34362.29
48.65 8280.00
-------
TABLE 15.
TOTAL EMISSIONS FOR INDUSTRIAL SECTOR, SCENARIO 2
'
EMISSIONS, THOUSANDS OF TONS
NATURAL GAS (CLEAN FllFl )
OIST FUEL OIL (CLEAN FUEL)
LOM S RESIU-nnMESTIr
LOM S RESIO-IMPORTEO
GASIFICATION-OIL, HI&M RTU
LOM S COAL (CLEAN FUEL)
CLEANABLE COAL (CLEAN FUELi
GASlFlCATION-cOALt HIGH BTU
TOTAL
NATURAL GAS (CLEAN FUEL)
OIST FUEL OR (CLEAN FUEL)
LOM S RESIO-OOMESTIC
LOM s RESIO-IMPORTEO
GASIFICATION-OIL, HIGH BTU
LOM S COAL (CLEAN FUEL)
CLEANABLE COAL (CLEAN FUEL)
GASIFICATION-COAL, HIGH BTU
00 •• " - - —
TOTAL
NOX
5154.76
176.17
2(15.64
1017.17
0.00
1670.00
427.46
0.00
8651.21
5486.97
414.99
194.6?
989.11
76.93
1705.00
439. ni
62.77
9368.71
S02
147.21
166.63
330.36
1510.32
0.00
2757.84
2617.03
o.oo
7489.38
156.68
251.16
312.66
1468.66
198.86
2815.64
27n8.30
387.24
8499.19
CO
2.21
.74
1.15
1.88
115.23
31.63
0.00
152.85
9.15
1.75
I.n9
1.83
o.oo
117.64
39.49
4.65
161.80
PART
82.80
13.77
15.69
75.54
0.00
236.30
134.n3
0.00
558.15
88.13
32.45
14.85
73.46
5.64
241.26
137.65
19.68
613.12
TOMA
~ 1975
796.40
8.85
10.15
14.64
o.on
26.72
7.99
0.00
863.98
1980
847.62
20.85
9.6o
14.24
1.12
27.28
7.41
1.06
929.17
ss
8R.32
.90
1.12
0.00
0,00
509.35
119.12
0.00
918.82
94.00
2.12
1.06
0.00
0.00
520.02
327.75
46.86
991.82
OS
0.00
1584.33
1979,52
0*00
0.00
0.00
99,90
0.00
3663.75
ft. oo
3731.97
1873.48
0*00
678.81
o.oo
109.60
14.67
6401.53
TOMW
0.00
2.24
7.00
21.75
0,00
18.37
6.10
0.00
55.47
0.00
5.28
6.63
21.15
.88
18.75
6.97
.90
59.86
ASH
0.00
0.00
0.00
o.oo
0.00
15030.00
0.00
21690.00
n.flfi
0.00
Q.OO
0.00
0*00 -
15345.00
684n.nn
978.00
23163.00
r
SLUDGE '
t
0.00
1.57 '
1.97
0.00 '
0,00
0.00 '
133.90
0.00 '
01
136.74
n
it
0.00
3.71 «
1.86
0.00 '
0.00
0.00 '
136.8(1
19.56 '
0'
161.93
n
1985
NATURAL GAS (CLEAN FUEL)
OIST FUEL OIL (CLEAN FUEL)
.._LOM S RESIO.DOMESTIC '
LOM S RESIO-IMPORTEO
.GASIFICATION-OIL. HTflH nTU
LOM S COAL (CLEAN FUEL)
CLEANABLF COA< (Cl FAN FUPI 1
GASIFICATION-COALt HIGH BTU
TOTAL
NATURAL GAS (CLEAN FlIFL)
DIST FUEL OIL (CLEAN FUEL)
LOM S RESIO-DOMESTIC
LOM S RESIU-1MPORTEO
GASIFICATION-OIL. HIGH BTU
LOW S COAL (CLEAN FUEL)
CLEANABLE COAL (CLEAN FUEL)
GASIFICATlON-COALi HIGH BTU
TOTAL
58 -.8. 44
595.08
918.60
1213.07
18Q5.00
465.07
285.74
10514.71
7956.26
1284.12
271.74
1332.85
92.17
1985.00
512.18
1001.26
14435.58
165.88
360.16
3R3.45
1786.34
5R4.SO
298Q.78
1762.77
10898.47
227.22
777.18
436.54
1979.04
477.89
3278.03
3)59.68
6176.82
16513.40
9.49
2.51
1 -I4
2.23
O.QO
124.54
21.15
188.74
3.41
5.41
1.52
2.47
0.00
136.96
37.90
74.10
261.78
91.30
46.53
18.91
89.35
H.27
255.41
1 46. 1 1
89.60
746.77
127.80
100*40
20.73
98.99
6.76
28Q.88
160.60
313.95
lllo.ll
R97.39
29.89
11*78
17.32
1.64
28.88
7. 86
4.82
999*59
2000
1229.23
64.51
13.41
19.19
1.34
31.76
8.64
16.90
1384.97
99.52
3.04
1-11
0.00
n.oo
55Q.52
213.32
1215.59
136.32
6.56
1.49
0.00
0.00
605.42
382.37
747.50
1879.67
0.00
5351.50
2297.66
0.00
994.75
0*00
IHR.OO
66.78
8819.60
0*00
11547.98
2615.80
0*00
81302
o.oo
119.70
234.00
15330.80
0.00
7.58
8,) 3
25.73
1.28
19.85
6,66
4.08
73.30
0.00
16.35
9.25
28.50
1.05
21.83
7.31
14.30
98.60
n.nn
0.00
n.QQ
0.00
n.QO
16245.QO
4452.00
27957.00
0.00
0*00
0.00
0.00
0.00
17865.00
7980.00
15600.00
41445.00
0.00
5.32 '
2.28
0.00 '
0.00 '
145,9(1
89.04 '
01
241.84
n
0.00
11.48 »
2.60
0.00 '
0.00
0.00 '
159.60
312.00 '
01
485.68
-------
TABLE
16. TOTAL EMISSIONS FOR
ELECTRICAL SECTOR, SCENARIO 2
i
I
SYSTEMS
NATURAL GAS (CLEAN FUEL)
LOW S RESID-DOMESTIC
LOW S RESIO-IMPORTEO
CHEM ACTIVE FLUIOIZED BED
HIGH S RESIR-LIMFSTONF SCRUB
HIGH S RESID.NO CONTROL
LOW S COAL (CLEAN FUEL)
CLEANABLE COAL (CLEAN FUEL)
FLUIDIZEO BED COMBUSTlON-CUAL
GASIFICATION-COAL* LOW BTU
LlOUEFACTION.COAL
HIGH S COAL-LIMESTONE SCRUB
HIGH S COAL-MfiO SCRUB
HIGH S COAL-NO CONTROL
TOTAL
VO
EMISSIONS. THOUSANDS OF
NOX
1774.98
14.69
lnS.29
0.00
17.54
1118.89
867.50
0.00
0.00
0.00
215.66
53. 01
2223.95
6657.37
S02
5n6.3S
23.44
156.24
0.00
91.54
5R40.25
1432.59
163V. 23
0.00
0.00
0.00
1330.39
332.60
13719.67
25572.31
CO
456.44
.28
.20
0.00
.03
2.07
59.86
19.66
0.00
0.00
0.00
15.96
3.99
164.59
723.09
PART
484.18
1.28
7.81
o.oo
1.30
83.10
122.75
83.32
0.00
0.00
0.00
67.62
16.90
697.33
1565.60
TONS
TOMA
1975
531 .68
.92
1.51
0.00
.25
16.11
13.88
4.48
0.00
0.00
0.00
3.64
.91
37.54
610*93
ss
4.86.08
.28
0.00
0.00
o.oo
0*00
264.59
0.00
0.00
0.00
161.00
40.25
166Q.31
2810.89
OS
455*68
141.60
0*00
0*00
0*00
0*00
0*00
62.10
0.00
0*00
o.oo
50*40
12*60
519.75
1242*13
TOMW
455.68
.70
2.25
0.00
.38
23.92
9.54
3.80
0.00
0.00
0.00
3.08
.77
31.76
531.88
ASH
455.68
.20
0*03
0*00
0*00
0*00
7807.50
4140.00
0.00
0.00
0.00
3360*00
840.00
34650*00
51253*38
SLUDGE
455.68
.34
0.00
0.00
0.00
0.00
0.00
82.80
0.00
0.00
0.00
67.20
16.80
693.00
1315.82
t
»
'
9
i
I
t
a
\;
ii
1980
NATURAL GAS (CLEAN FUEI )
LOW S RESIO.DOMESTIC
LOW S REStO-TMPORTEn
CHEM ACTIVE FLUIDIZED BED
HIGH s PE?ID-LIMFSTONF SCRUB
HIGH S RESID-NO CONTROL
LOW S COAL (CLFAN FUFl j
CLEANABLE COAL (CLEAN FUEL)
GASIFICATION-COAL, LOW 8TU
HIGH S COAL.HMESTONE SCRUB
HIGH S COAL-MQO SCRUB
HIGH S COAL-NO CONTROL
TOTAL
1680. 90
165.25
70.15
192.76
596.27
1 745 .1)1)
369.70
0.00
o.oo
0.00
1790.71
770.90
215.66
7833.33
479.70
263.71
1)97.84
366.16
640.78
3112.36
2555.99
2280.67
0.00
0*00
0.00
11Q47.00
4751.40
1330*39
27526.01
439.4?
3.18
1.49
.13
.93
1.10
27.36
0.00
0.00
o.OO
132.52
57.00
15.96
757.31
458.70
14.37
59.91
5.21
9.12
44.28
176.17
115.92
n.oo
0*00
0.00
561.49
241.50
67.62
1754.29
503.70
10.34
11.61
1.01
1.77
8.58
19.99
6.24
O.OQ
0*00
o.oo
30.23
13.00
3.64
610.04
460.50
3.16
o.oo
0.00
0.00
•»7Q-72
276.00
n.no
0.00
n.no
1336.87
575.00
161.00
3192.26
431.70
1592.95
0.00
0*00
O.OO
0*00
n.no
86.40
0.00
0*00
0.00
418.50
160.00
50*40
2759t95
431.70
7.89
17.25
1.50
2.63
12.75
I3t69
5.28
0.00
0.00
o.oo
25.57
11.00
3.08
532.34
411 .7n
2.26
0.00
0.00
0*00
0.00
5760*00
OtOO
0*00
279oo.OO
120nn.on
3360*00
60658.96
431.70
3.84
0.00
0.00
0,00
0.00
n on
115.20
0.00
0.00
0.00
558.00
240,00
67.20
1415.94
t
i
1
t
01
11
n
-------
TfclU 1». TOKO. BOSSBUS TO* MCnuOU. SEOOK. SCgJAMO I (Ca»tl»a>dl
**n»*L SAStCLEA* FUEL!
S B£SltMX>«ESTIC
LOU S ft|S10?l***0«T€!:
1W5
*3*.59
441.31
413.71 413.71 413.71
c*c* ACTIVE FLJIDUEO »ED
MlSM S AES1D.NO
-CO* S COALICIE4S Fl>FH
CL£A»»48^E Co»t*CLE*»< FUEL»
lit. 9*
ISM. 23
l«»»
3716.S2
3?^7.39
.65
-IJL.
c.oo
16.52
y«.i9
13.12
OSOi.
_*2»JB1_
0.86
317.67
5.85
4.OS
-ft^BJL
6.88
8.88
-»ft
8.88
».88
6*66
•»66
e€P
SASIFlCATJOt^c^AL.
8TU
HI6M S CO*L^1^EST<»< SCftUB
jlg_S_EfiAi=afi9L
612.31
85
11S.S-* 71?.71
~ k? 9977.94
45.31
11.*0
13.68
HOt
10.33
57.96
J&»22_
3.1?
S87.15
138.66
&fe.?5_
143.16
36*66
27.38 1287.58
43*26
27*6.1
378.88
_-*»£« ?*fia^68_
2.64 2668.66
l.fcS Iftftft.M
21.18
_4^efi_
57,60 >'
_l^ft*_
504.08
S COAUNO COMTHOX.
8.M
8.88
8.88
8.88
6.68
8.88
8.66
«.66
TOTAL
34753.12
654.66 2166.79 6».«5 3927.49 1142.55 547.61 7*661.6* jS66.e6
*•
o —
NI8H S COAL-NO CONTROL
6.66
••66
6.66
31&.SA
6.66
TOTAL
-------
17.
or TOW.
MR) TOW. UBLSSMB TCR ALL SBCKKS, SCEMUO X
EMISSIONS* THOUSANDS OF TONS
NOX
sot
CO
PART
TOM*
ss
OS
Town
1 9 T 5
ST.88 282**.IT
1121.25
iMWSTftlAl
0651.21
665T.3T
723. t9
SSS.lS
15fr5.fr*
&18.93
918.82 3663;T5
2818.89 12*2.13
&3l!o» 51253.38
136.T6 -
1315.02
TOTAL
lfr«5.33 23*3.97
2515*. 95
T*86*.63 1*72.69
1988
8€SlOtMTlAL
INDUSTRIAL
COMNEnClAL
»90 1TTT.3S
2T8.94
U.*3 2331T.TT
i.81 158T.65
23.14
_ilSCTJISAJ.
93**. 71
161. 8«
757.31
613.12
1754.29
fcie.8* 3192.26
6*81*S3
2TS9.9S
TOTAL
1865.342646.352318.91
32*79.2*
8Sl29.il 1611.85
1985
1531.92
428.34
952.19
I.66 2T32T.OO
3A.69 26)5.19
IT. IT
INOUSTKIAL
etfiCTItlCAL
1M.T*
954.66
7*6.77
2188.79
999.59
1215.59
3*27.49
M}9.6*
33*2.55
73,38
56T.61 T»98l.fr2
2*1.8*
15*6.26
"2375T5T
2577.6*
1»55.27
288*
«£SIDE*7IAL AND COMMBRClAc
INDUSTRIAL
ELECTRICAL
4358.34
14435.5* 1*512.40
9994.76
16ST.8J 355.52 3*3*2.2»
*«.6S *2*c.oe
3*. 16
633 .51
111*.11 13**»9T
~ ~ 5U.T7 5**«.2T
>e iBsTir
*S2.3* 1*22*2.38 2164.75
-------
TABLE 18. COMPARISON OF TOTAL EMISSIONS FOR SCENARIO 1 AND SCENARIO 2
to
Scenario 1
Scenario 2
Difference,
2-1
Scenario 1
Scenario 2
Difference,
2-1
Scenario 1
Scenario 2
Difference,
2-1
Scenario 1
Scenario 2
Difference,
2-1
NO
X
18,409
18,519
110
20,222
20,750
528
23,537
24,306
769
26,954
28,788
1,834
so2
29,525
34,070
4,545
18,478
37,802
19,324
18,737
47,901
29,164
20,658
67,033
46,375
CO
1,601
1,605
4
1,619
1,865
246
1,397
2,575
1,178
1,204
5,543
4,339
Total
PART.
2,318
2,343
25
2,577
2,646
69
3,048
3,283
235
4,160
4,734
574
Emissions, Thousands of Tons
TOMA(a)
2,152
2,154
2
2,271
2,318
47
2,370
2,577
207
2,882
3,557
675
BB^
1975
3,854
3,786
-68
1980
4,404
4,258
-146
1985
5,700
5,264
-436
2000
8,717
7,323
-1,394
DS
25,172
25,150
-22
32,908
32,479
-429
40,226
39,490
-736
53,013
51,961
-1,052
TOMW(d)
616
616
0
624
625
1
651
659
8
552
599
47
ASH
64,773
74,064
9,291
46,405
85,329
38,924
67,774
109,573
41,799
127,863
151,967
24,104
SLUDGE
9,761
1,472
-8,289
71,926
1,601
-70,325
92,702
1,855
-90,847
102,650
2,684
-99,966
(a) Total organic material - air
(b) Suspended solids
(c) Dissolved solids
(d) Total organic material - water
-------
Scenario 3. Modified Fuel Allocation Assumption
Scenario 1 was based on the allocation of clean fuels to the
smaller sources found within the residential/commercial and industrial
sectors. Since some dirty fuel currently is consumed within these sectors,
Scenario 3 was constructed in which a portion of the dirty fuel was
assigned to the residential/commercial and industrial sectors in an attempt
to reflect what would happen if long-term fuel supply contracts or other
factors prevent the elimination of dirty fuels in small sources. Equiva-
lent amounts of clean fuel were shifted to the electrical sector to main-
tain the correct subtotals.
Modified Fuel Utilization
The projection was made by modifying that for Scenario 1 in the
following manner. Natural gas utilizations remained unchanged. Utiliza-
tions of high sulfur residual oil without control were newly projected by
multiplying the total amount of high sulfur residual oil projected in
Scenario 1 for 1975 by the fractions of the total residual oil currently
consumed in each sector. These fractions were estimated to be 0.26, 0.2,
and 0.54 for the residentail/commercial, industrial, and electrical sectors,
respectively, for the year 1971 from data contained in Mineral Industry
Surveys ' and were assumed to hold for 1975. A constant continuing
»
use of high sulfur residual oil in the residential/commercial and industrial
sectors was assumed for the remaining periods because of the existence
of long-term contracts or other constraints on fuel switching. The
utilization of distillate fuel oil and low sulfur resid ( imported) were
adjusted to rebalance the petroleum fuel subtotals in the three sectors.
High sulfur coal utilizations in the residential/commercial
and industrial sectors were based on data compiled by the Bureua of Mines.
Tables giving shipments of bituminous coal and lignite by average
suflur content by consumer use are presented for 1971 in Reference 3,
and for 1971 in Reference 11. The data cover shipments by producers
43
-------
reporting sulfur content which included only 57 percent of the 1971 total
production and 61 percent cf the 1970 total production. On the basis of
this incomplete data, 84 percent of the coal shipped to industrial and
retail consumers in 1970 (excluding coke plants) was high sulfur coal,
i.e., coal containing more than 1 percent sulfur. The corresponding
figure for 1971 was 77 percent high sulfur coal. Data for coal shipments
by sulfur content were not given in earlier editions of Minerals Yearbook*
Since the data do not Include the total U.S. production and are available
for only 2 years, It is not possible to determine whether the Indicated
decrease in the percentage of high sulfur coal consumed in the residential/
commercial and industrial sectors (84 percent in 1970 versus 77 percent
in 1971) reflects a continuing trend. For this reason the approximate
ratio, 75 percent high sulfur coal and 25 percent low sulfur coal was
chosen and this ratio was assumed to be constant for each time period.
Thus, the coal use projections for Scenario 3 were obtained by shifting
75 percent of the Scenario 1 low sulfur coal quantities in the residential/
commercial and industrial sectors to high sulfur coal. The projections
for low sulfur and high sulfur coal utilizations in the electrical sector
were adjusted to rebalance the coal subtotals.
The resulting fuel utilization projections for Scenario 3 are
given in Tables 19, 20, and 21. It is clear that these projections
are only approximate with respect to the distribution of high sulfur fuel
among the consuming sectors. A more definitive analysis would require
a detailed examination of the current end use of such fuels and the
factors limiting the flexibility for fuel switching. Such analysis is
beyond the scope of this study, however, the subject is of such impor-
tance that it warrants further study.
Projected Total Emissions - Scenario 3
The modifications to the fuel utilization projections required
the addition of systems not used in Scenario 1. The revised list of
modules used in the Scenario 3 systems Is given in Table 22.
44
-------
vn
TABLE 19. FUEL UTILIZATION PROJECTION FOR RESIDENTIAL AND COMHERCIAL SECTOR*8*
Scenario 3
Fuel Utilisation Prelection, 1012 Btu
Fue I/Technology
natural Gas (Clean Fuel)
Petroleum
Distillate Fuel Oil (Glean Fuel)
Gasification, High Btu Gas
High Sulfur Res id Without Control
Subtotal
Coal
Low Sulfur Coal (Clean Fuel)
Gasification, High Btu Gas
High Sulfur Coal Without Control
Subtotal
Total
1975
8,660
4,914
0
836
5,750
80
0
245
325
14,735
1980
9,480
5,640
183
800
6,623
75
137
225
437
16,540
1985
10,060
6,680
282
800
7,762
25
658
75
758
18,580
2000
10,800
8,720
240
800
9,760
0
2,400
0
2,400
22,960
(a) Excludes electricity purchased and non-fuel uses.
-------
TABLE 20. FUEL UTILIZATION PROJECTION FOR INDUSTRIAL SECTOR
Scenario 3
(a)
Fuel Utilization Projection, 1012 Btu
Fuel/Technology
Natural Gas (Clean Fuel)
Petroleum
Distillate Fuel Oil (Clean Fuel)
Low Sulfur Resid (Clean Fuel) - Domestic
Low Sulfur Resid (Clean Fuel) - Imported
Gasification, High Btu Gas
High Sulfur Resid without Control
Subtotal
Coal
Low Sulfur Coal (Clean Fuel)
Cleanable Coal (Clean Fuel)
Gasification, High Btu Gas
High Sulfur Coal Without Control
Subtotal
Total
1975
11,040
1,286
560
1,423
0
641
3,910
835
1,110
0
2,505
4,450
19,400
1980
11,750
1,860
530
1,420
217
600
4,627
853
1,140
163
2,557
4,713
21,090
1985
12,440
2,320
650
2,030
318
600
5,918
903
1,210
742
2,707
5,562
23,920
2000
17,040
4,080
740
2,400
260
600
8,080
993
1,330
2,600
2,977
7,900
33,020
(a) Excludes electricity purchased and non-fuel uses.
-------
TABLE 21. FUEL UTILIZATION PROJECTION FOR ELECTRICAL SECTOR
Scenario 3
Fuel Utilization Prelection, 1012 Btu
Fue 1 /Te chno logy
Natural Gas (Clean Fuel)
Petroleum
Low Sulfur Resid (Clean Fuel) - Domestic
Low Sulfur Resid (Clean Fuel) - Imported
Chemically Active Fluidized Bed
High Sulfur Resid with Stack Gas Cleaning
High Sulfur Resid without Control
Subtotal
Coal
Low Sulfur Coal (Clean Fuel)
Cleanable Coal (Clean Fuel)
Fluidized-Bed Combustion
Gasification, Low Btu Gas
Liquefaction
High Sulfur Coal with Stack Gas Cleaning
Limestone Scrubber
MgO Scrubber
High Sulfur Coal without Control
Subtotal
Total
1975
3,800
40
1,777
0
50
1,713
3,580
4,485
690
0
0
0
560
140
3,025
8,900
16,280
1980
3,600
450
3,700
200
350
300
5,000
5,272
960
0
0
0
3,115
1,313
0
10,660
19,260
1985
3,450
580
4,440
1,000
630
0
6,650
7,272
1,590
400
480
300
2,700
1,478
0
14,220
24,320
2000
2,640
160
2,200
2,180
500
0
5,040
5,107
1,570
3,000
3,820
2,500
600
923
0
17,520
25,200
-------
TABLE 22. MODULES COMPRISING FUEL/TECHNOLOGY SYSTEMS
Scenario 3
Fuel/Technology System
RESIDENTIAL AND COMMERCIAL SECTOR
Natural Gas (Clean Fuel)
Petroleum
Distillate Fuel Oil (Clean Fuel)
Gasification, High Btu Gas
High Sulfur Resid without Control
Coal
Low Sulfur Coal (Clean Fuel)
Gasification, High Btu Gas
High Sulfur Coal without Control
INDUSTRIAL SECTOR
Extraction
Gas Well
Oil Well
Oil Well
Import
Coal Mine
Coal Mine
Coal Mine
Transport
Rone
Oil Pipeline
Oil Pipeline
Import
Rail
Rail
Rail
Modules
Proc ess Ing/Conversion
Desul f urlzatlon
U.S. Refinery
Gasification
Import
None
Hygas
None
Transport
Gas Pipeline
Hone
Gas Pipeline
Tanker
None
Gas Pipeline
None
Utilization
Space Heating
Space Heating
Space Heating
Space Heating
Space Heating
Space Heating
Space Heating
Natural Gas (Clean Fuel)
Petroleum
Distillate Fuel Oil (Clean Fuel)
Low Sulfur Resld (Clean Fuel)
Low Sulfur Resid (Clean Fuel)
Gasification, High Btu Gas
High Sulfur Resid without Control
Coal
Low Sulfur Coal (Clean Fuel)
Cleanable Coal (Clean Fuel)
Gasification, High Btu Gas
High Sulfur Coal without Control
ELECTRICAL SECTOR
Natural Gas (Clean Fuel)
Petroleum
Low Sulfur Resid (Clean Fuel)
Low Sulfur Resid (Clean Fuel)
Chem. Act. Fluidized Bed
High Sulfur Resid with Stack
Gas Cleaning
High Sulfur Resld without Control
Coal
Low Sulfur Coal (Clenn Fuel)
Cleanable Coal (Clean Fuel)
d P««i dvatittBHon
Gasification, Low Btu Gas
Liquefaction
High Sulfur Coal with Stack
Gas Cleaning
High Sulfur Coal with Stack
Gas Cleaning
High Sulfur Coal without Control
Gas Well
Oil Well
Oil Well
Import
Oil Well
Import
Coal Mine
Coal Mine
Coal Mine
Coal Mine
Gas Well
Oil Well
Import
Import
Import
Import
Coal Mine
Coal Mine
Coal Mine
Coal Mine
-Coal Mine
Coal Mine
Coal Mine
Coal Mine
Noue
Oil Pipeline
Oil Pipeline
Import
Oil Pipeline
Import
Rail
None
Rail
Rail
None
Oil Pipeline
Import
Import
Import
Import
Rail
None
Rail
Rail
Rail
Rail
Rail
Rail
Desulfurlzatlon
U.S. Refinery
U.S. Refinery
Import
Gasification
Import
None
Physical Cleaning
Hygas
None
Desulfurlzatlon
U.S. Refinery
Import
Import
Import
Import
None
Physical Cleaning
None
Lurgl Gas
Liquefaction
None
None
None
Gas Pipeline Conv. Boiler
None
Barge
Tanker
Gas Pipeline
Tanker
Hone
Rail
Gas Pipeline
None
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Conv. Boiler
Gas Pipeline Conv. Boiler
Barge
Tanker
Tanker
Tanker
Tanker
None
Rail
None
None
None
Nona
Rone
None
Conv. Boiler
Conv. Boiler
Fluidized Bed
Combustion
Conv. Boiler,
Lime Scrub.
Conv. Boiler
Conv. Boiler
Conv. Boiler
Fluidized Bed
Conv. Boiler
Conv. Boiler
Conv. Boiler,
Lime Scrub.
Conv. Boiler,
MgO Scrub.
Conv. Boiler
48
-------
Total emissions were calculated by the same procedure used for
Scenario 1 using the unit-basis module emission data from Table 9, the
modified fuel utilization projections of Tables 19, 20, 21, and the
module/systems as defined in Table 22. The results of the calculations
are presented in Tables 23, 24, 25, and 26.
Comparison of the results for Scenario 1 and Scenario 3 is
provided in Table 27, which is a summary of the total emissions for both
scenarios.
The results for 1975 show that shifting dirty fuels from
sector to sector does not affect the total emissions significantly as
the emission factors for the modules involved are similar. The increase
in total SO. emissions from Scenario 1 to Scenario 3 in 1980, 1985, and
2000 is the result of substituting low sulfur coal for some stack gas
cleaning capacity. This was necessary to maintain the balance of total
coal burned and the ratio of high sulfur coal to low sulfur coal. These
increases for the utility sector have little effect on calculated air
quality in Scenario 3 as is demonstrated in Appendix B.
It should be noted that, although the allocation of some dirty
fuel to the residential/commercial and industrial sectors in Scenario 3
did not result in a large change in total emissions as compated with
Scenario 1, in which only clean fuels were allocated to those sectors,
this is not to say that the impact on ambient air quality would be similar
for both scenarios. This question is addressed in the following section.
49
-------
TABLE 23. TOTAL EMISSIONS FOR SYSTEMS IN THE
SYSTEMS
k'iSTU0AL GAS(CL~AN FUEL)
GASIFTCftTTON-OIL, HTGH "TU
HIGH S PESIO-NO CONTROL
LOW S COALCCL£AN FUrU
GASIFICATION-COAL. HIGH «TU
HTGH S COAL-NO CONTROL
TOTAL
MBTIIPflL GaS
r.ASIpTCATION-OTL, HIGH RTU
HIGH s PeSTi-Mi COMTQOL
LOW S COALtCL^AM FUEL)
GASIFICATION-COAL, HIGH RTU
HTGH 5 COAL-N3 TONT°OL
3601. C3
3t<*?.91
•^61.12
67.77
1^71
5. 14
4056.19
^7L. -n
7^t2.48
57. P7
n.cq
913.12
n.OO
3083.52
13*, .16
1338.97
9.10
1227. fl4
18.39
165.43
30«5.63
14?-. 17
1747. 8P
7.74
1227.84
O.np
692.07
O.QO
736.45
75.45
110.22
2.11
12.52
12.73
131.44
338.29
91. CO
12.52
a. DO
0 .DO
251.16
25.15
7C.88
1.38
7.64
10.58
116.36
34.37
266.37
?7.00
92.53
1.18
7.64
O.QO
n.on
714.99
544.62
97.97
1 .21
9!69
1.90
29.06
685.99
OAAA
127.89
1.03
1.64
0.00
6.55
0.00
143.18
c.on
13.36
0.00
0.00
3.50
285.39
20.63
323.37
0.00
oloo
o.or
0.00
1042.75
0.00
20673.76
0.00
23519.45
1197.56
O.OC
0.00
93.56
6.75
24916.32
O.QO
307QQ.73
1019.20
Q.QC
0.00
341.26
O.QO
35.11
0.00
33.30
1.54
6.00
G.OO
0.00
0.00
40.84
0.00
43.47
1.31
6.00
0.00
0.00
0 .00
1521.20
O.QO
0.00
11.76
O.CO
2298.54
258.75
2655.70
0.00
O.QO
1C. 01
0.00
O.GO
8383.73
0.00
1923.?"
1.02
23.38
11.76
Q.OO
O.QO
8975.95
9.30
9019.99
Q.OO
70.5?,
10.01
Q.OO •
0.00
32739.65
0.0"
TOTAL
5031.98 3821.70
?35.6»*
552.77-
721.80 1C60.19 32061.19
50.78 8393.71* 32779.13
-------
TABLE 24.
TOTAL EMISSIONS FOR SYSTEMS IN THE INDUSTRIAL SECTOR, SCENARIO 3
-
EMISSIONS, THOUSANDS OF
NATHOAL GAS.81
*>.59
e.io
0.00
13.78
53.37
ASH
O.CO
O.CO
0.00
0.00
0.00
3757.50
3002.55
3.00
15030. CO
21790.05
i
"SLU15F
0.00
(..70
- 0.30
3.00
r.oo
317.16
3.00
300.60
6?U. 93
Ui
1980
naT,,oai rA<-(r -AN Fii=-it
OIST FI.I-L CIL'HLEAN FU?L)
L04 S «?FSTn-n.yi£STTC
' LOW S »FSTn-TMPT?Te-n
GASIFICATTOM-OTL, HT^H ITU
"HIGH S °ESin-NO CONTROL
LOW s COALCCL^AN FH-H
CL£A^A"LE COAL (CLEAN FIKD
GASIFICATIOM-COALt Hf.H RTU
HIGH S COAL-NO CONTPOL
5616. ?7
7?fl,19
1.91.06
15. P7
*.•>*. 50
*.2?.55
9S°:70
15*. 6B
i.*.0.72
312.66
"" 739.5*.
F.96
109ft. *.P
70*.. 3'
a23.«8
«.6.97
607*.. 66
2.35
3.C7
1.09
.0*.
.39
29.1.3
30. ?1
1.96
72.87
"1.13
56.91,
36.99
2.15
15.63
60.35
1?2.3?
29.6*.
308.76
8t»7.6''
9.60
7717—
t.,11.
3.03
6.8?
6.2'
16^62
o*..00
?.72
1.06
0.00'
0.00
130. Ofl
370.50
72.12
735. l«f
0.00
651.9.55
w'.™
0.00
O.CO
116.59
23.11
230.13
0.00
9.27
6.63
10.65
1 .19
*».5G
6.27
0.00
1*..06
O.CQ
0.00
0.00
0.00
P. 05
O.CO
3013.70
153fc2loO
0.30
1.96
p.o:
9.05
0.30
0.00
35>6.*»5
2223.50
306.8*.
-------
TABLE 24. (Continued)
SVSTFM1;
MATUOAL RA«!frL-AM FlKL)
OIST FUEL OIUCLTAN FUEL)
LOW S TSTt)-I»'009TEO
GATIFICATICM-OTL. WISH HTU
HIGH S =£SI9-NO CONTROL
LOU S riALir.L-AM Fll=L»
("LEASABLE COAL(CL?AN FUFL)
GASIFICATION-COAL* HIGH BTU
HIGH S COAL-NO CONTROL
•
EMISSIONS, THOUSANDS OF TONS
NOV S02
5P01.44 tfi?
903.21 549
238.69 313
712.02 1057
?10.45 109"
451.50 745
427. ?7 874
366.03 213
104?. 47 6431
.71
.22
.19
.48
.61
.47
.82
.02
CO
2.49
1*.SJ
1.72
.06
31.15
32.06
8.94
77.15
PART
93.30
71.02
11.21
5?.«a
3.15
15.63
63.19
129.33
134.93
326.87
TOHA
1985
11.71
1D.?5
7.39
3.03
7.?2
6.66
15.38
17.60
SS
99
1
0
2
C
137
393
328
778
,5?
.31
.00
,54
.00
.71
.25
.32
.26
OS
C.OO
8168.08
2297.66
0.00
1350.43
0.00
0.00
123.75
105.51
243.63
TO"H
0.00
11.56
8.13
15.22
4.50
4.97
6.66
0.00
14.89
ASH
0.00
0.00
0.00
0.00
13.26
o.co
4063.50
3273.05
2591.97
16242.00
fc
SLunnc •
0.00
z'.tl
• C.OO
13. ?6
o.oc •
0.00
346.50
10121.70
TOTAL
in
N>
lfl?90.70 11529
.85
158.73
909.70
1022.02
1745
.55
12289.07
67.67
26113.78
10816.71
*
2000
MATUPAL GASfL-AM FUEL)
OTST FIJ£L OTLCLTAN FUEL)
L"W S °f STr|-00M-STTC
GASIFICATION-IK, HIGH PTU
HIGH S PE5TO-N3 CONT90L
LOW «5 COAL (CLEAN FUFL )
CLEANARLE COAL(CL£AN FU'L)
GASIFICATION-COAL, HIGH PTU
HIGH S COAL-NO CONTROL
70l;(.j,(. 2??
1597.32 966
H41.10 1249
210.45 1098
496.50 819
469.64 961
1282. ?S 749
1146.44 7072
.?>
:ll
.92
.33
^92
.19
.22
.46
3.41
6.73
.05
.39
34.26
35. "4
31.33
127.80
124.89
20.73
6?. 52
?.57
15.63
70.25
14?. 70
359.*47
1229. ?3
;°:^j
12.1?
5. 1C
3.03
7.94
7.T1
53, 9T
19.35
136
8
1
0
2
0
151
432
1150
««55
.3?
.16
.49
.00
.01
.00
.43
.25
.45
.89
0.00
14364.56
2615. AC
r.oo —
1104.13
0.00
0.00
136.02
369.70
267.93
0.00
2C.34
9.25
la. oo
1.42
4.50
5.46
7.31
0.00
16.37
0.90
0.00
o.oc
O.ro
10. R4
O.CO
4468.59
3597.65
9082.38
17«6?.00
0.08
14.21
10.14
0.00
0.00
380.16
35466.17
357.24
TOTAL
14375.39 13590.02
199.34 1399.38 1432.3?. 2738.06 18858.15
82.66 35021.37
-------
TABLE 25. TOTAL EMISSIONS FOR SYSTEMS IN THE
ELECTRICAL
SECTOR, SCENARIO 3
SYSTEMS
MflTOrftL r.fi^r.LEAM F.I-L)
LOW S B^'TO-TOM-SlTf
LOH S RcST"-IV°n'3T£n
CHff ACTIVE FLUni7cO "EO
HIGH S "JFSIO-LIMESTONE SCPU«
HIGH S PESIT-NO CO»JTOQL
LOW S COALCCL^AN FUrL)
CLEANABLc COAL (CLEAN FU^LJ
GftSIFICATTOM-OOAL, LOH HTU
LIOUEFACTTON-COAL
HIGH S COAL-LIMESTONE SCRUB
HIGH S COAL-HGO SC»im
HIGH S rOAL-MO CONTROL
l/i TCTAL
to
EMISSIONS. THOUSANOS OF
NOX
1774.?8
14.69
623.28
0.00
600.83
O.CO
O.CO
O.CO
173.66
1164.93
689«.77
S02
506.35
925^46
O.CO
9.19
3136.16
3703.26
498.66
0.00
n.oo
0.00
140.39
35.10
7186.49
16161*. 52
CO
456.44
.28
1.16
0.00
.03
1.11
154.73
18.28
O.CO
0.00
0.00
15.96
3.99
86.21
738.21
PAPT
484.18
1.28
46.29
0.00
.06
44.62
317.31
74.03
O.CO
0.00
3.00
67.62
16.90
365.27
1417.58
TONS
TOHA
19/j
531.68
.92
8.97
0.00
.25
8.65
35.88
3.30
0.00
0.00
o.nc
3.64
.91
19.66
614.37
ss
486.08
.28
0.00
0.00
0.00
O.QO
683. PR
224.?5
0.00
0.00
0.00
161.03
40.25
669.69
2465.51
OS
455. *.R
141.60
0.00
O.OP
0.00
0.00
O.CO
70.57
0.00
0.00
0.00
53.40
12.60
272.25
1003.10
TO-H
455.68
.70
13.33
O.OC
.38
12.85
24.67
3.8Q
0*00
0.00
0.00
3.08
.77
ASH
455.68
.20
O.PQ
O.QO
O.CO
a. oo
201P».50
1866.U5
O.CO
O.GO
n.oo
672.00
168.00
SLUOGE
455.6*
.34
1.00
3 45 '.00
n.oo
197.59
0.30
3.00
3.03
7711.20"
16.80
16.64 18150.30 363.00
531.88
41494.83
9089.6?
1980
NflTII'AL GtMCL'AN *H!:L»
LOW S OESTO-OOM'STTC
CHE*1 ACTIVE FLUIOT7FO TO
HT^H s °(- SIO-LIMt'5T''NE SCT)"
HIr.H S SF.'flO-NO CONTPOL
LOM S C^ALinLrAN FiJTL )
CL~*NA9LE Cf1AL(~LF.AN FDCL)
GASIFICATION-COAL, LOM HTU
L.TOUEPACTTON-C01L
HIGH S CCAL-LTMESTON? SHPU9
HTRH <; ppAi-wr.n
-------
TABLE
25. (Continued)
SYSTEMS
WATUfftL GAStCL'iAN FUEL)
LOW S RFSIO-OOM'STTC
LOW 5 Rfsin-IHCpoTEn
C^E" ftCTTVT FLUTQITtO HTH
Hir,u s "Fsn-LI"£STr»N': SCPU*
HIGH s SEST^-NO CONTROL
LOW ? nAL(OLfa^ FUFD
CLEftNABLE COALCCL^AN FUCL1
PLUIDT7er> BR.H COMBUSTION-COAL
GASIFTCATION-CiftL, LOW BTl)
LIQUEFACTION-COAL
HIGH S COAL-Lr'*SThNE SCPUft
Hir,n s ro*L-^r.O SC°in
HIGH S C04L-H3 C1NTPOL
TOTAL
EMISSIONS, THOUSAMOS OF
>'oy
1^10. ee
212.99
1?57.31
m.75
5>20.«)7
o.co
361P..QO
561. U5
3?. Qi*
10C.B5
. 111.«?<»
837. ?7
<»5«.33
0.00
9i»2a.39
S02
•»59.72
339. ft9
2312.35
2P5.80
115.79
0.00
60(<
HTGH S 9FSIO-VO CONT90L
LOW ^ rnALfri-AM m~n
CLi:fl>'ftnLF Cf>ftL(CLEAN FU~L>
FLUIPI7-D "-T mM^IJ^TION-C^At.
0«SIFir4TIO'!-cnaL, LOW "TU
LIOUEFftCTIOM-^TflL
HIGH S COAL-LIM£STONZ SCRUB
HIGH s COAL-MRO sc"uq
HIPH S COAL-NO CONTPOL
TOTAL
1?3?.P6
5«.75
771.65
176. C3
17?!. 17
O.CD
2^53. "?0
C'j^.sq
2U0.3Q
802. SB
°96.17
l^ij.06
2Bft.??
n.co
9C33.e9
3«51.71
93.76
11<»5.76
U92.2I*
91.90
C.OO
«k?l
-------
TABLE 26. SUMMARY OF
SECTORS
NOX
TOTAL EMISSIONS FOR EACH
PMlSStOMS, '
S02 CO
SECTOR AND
rHiMiSA-WS
PAPT
TOTAL EMISSIONS
OF TflNS
TOMA
FOR ALL
SS
SECTORS- SCENARIO 3
OS T«OMH ASH SLUOGE
1975
SSSTn^NTIAL ANT COMMERCIAL 3197.65
ELECTQICAL 6999.77
TOTAL 181*59.37
299«*.5«* 728.69
13139.71 136.4.4
161f><*.52 739.21
29288.76 1603.32
227.91
672.28
1M7.58
2317.77
668.56
6 71. XT '
2151*. >5
88. i»0
1300729
2<*65.51
385A.21
17322.90 30.77 1121.25 ^^.60
1C03.10 531.88 «*li*9i».e3 9099.62
25172.15 616.02 ei^Oe.13 9761.15
"' U980
SESIOENTIAL AHO COM^ESCTAL 3601.03
INDUSTRIAL 9097.1*3
ELECTRICAL 7736.17
In
Wi TOTAL 20«43
-------
TABLE 27. COMPARISON OF TOTAL EMISSIONS FOR SCENARIO 1 AND SCENARIO 3
Total Emissions, Thousands of Tons
Scenario 1
Scenario 3
Difference, 3-1
Scenario 1
Scenario 3
Difference, 3-1
Scenario 1
Scenario 3
Difference, 3-1
Scenario 1
Scenario 3
Difference, 3-1
H0x
18,409
18,458
49
20,222
20,434
212
23,537
23,775
238
26,954
27,441
487
so2
29,525
29,288
-237
18,478
22,974
4496
18,737
26,741
8004
20,658
29,045
8387
CO
1601
1603
2
1619
1621
2
1397
1398
1
1204
1204
0
Part
2318
2318
0
2577
2577
0
3048
3085
37
4160
4193
33
TOMA(a)
2152
2154
2
2271
2273
2
2370
2372
2
2882
2871
-12
SS(b) DS(C)
1975
3854 25,172
3854 25,172
0 0
1980
4404 32,908
4404 32,908
0 0
1985
5700 40,226
5700 40,226
0 0
2000
8717 53,013
8717 53,013
0 0
TOMW(d)
616
616
0
624
624
0
651
651
0
552
552
0
Ash
64,773
64,406
-367
46,405
56,732
10,327
67,774
81,016
13,242
127,863
140,803
12,940
Sludge
9761
9761
0
71,926
50,974
-20,952
92,702
62,567
-30,135
102,650
82,820
-19,830
(a) Total organic material - air
(b) Suspended solids
(c) Dissolved solids
(d) Total organic material - water
-------
ESTIMATION OF THE IMPACT OF PROJECTED
EMISSIONS ON AMBIENT AIR QUALITY
Approach
To put into perspective the effect that projected energy
requirements will have on ambient air quality, an analysis was made
using the greater Indianapolis Air Quality Control Region (AQCR) as an
example region. Battelle has spent close to two years developing an
emission inventory for the Indianapolis AQCR. A recently completed study
utilized this emission inventory to develop control strategies for meeting
secondary SCv and particulate standards.
The Indianapolis AQCR was chosen for study because of the
extensive data base already available. The point sources in this AQCR
are smaller than might be considered typical; however, it was concluded
that the analysis of an actual AQCR would be more meaningful than the
analysis of a hypothetical "typical" AQCR.
Air quality is predicted using the Air Quality Display Model
(AQDM), a multiple-source dispersion model. The AQDM uses as input data
an emissions inventory and various meteorological parameters. Air quality
is then predicted for a receptor grid and the predicted concentrations are
printed in tabular form. Battelle has coupled several programs with AQDM
so that BCL has the capability to predict emissions resulting from applying
air pollution control laws, calculate the resulting air quality, and
graphically display the receptor grid concentrations. Future growth of
pollutant sources can also be accounted for by using growth factors with
the emission inventory.
Characteristics of the Indianapolis AQCR
In order to analyze air quality prediction results, the greater
Indianapolis Air Quality Control Region should be characterized with
respect to types of sources.
57
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The fuel-use mix in the Indianapolis AQCR is not typical in that
coal is the predominant fuel. The 1971 inventory consisted of about 87.6
percent coal, 5.3 percent petroleum products, and 7.1 percent natural gas.
This mix may be compared with the national combustion-fuel figures for
1971 which were: 27.7 percent coal, 25.0 percent petroleum products, and
47.3 percent natural gas. '
There are 434 sources inventoried in the Indianapolis AQCR;
227 sources are sources with emissions of more than 25 tons of any one
pollutant per year, and the remaining 207 sources are referred to as area
sources (emissions described in terms of tons per year for a given area of
land). The data base was originally collected for 1970 and updated to
include significant changes which occurred through 1972. For this study the
inventory will be assumed to apply in 1971 for comparison with 1971 national
figures.
A breakdown of the sources within the Indianapolis AQCR was derived
from the source listing. The number of sources in each of seven arbitrary
source categories is given in Table 28. For each source category the total
emissions of S09 in tons per day are given together with the total
z 3
contribution to the S02 concentration in p,g/m at Receptor 33, the receptor
having the highest SCL concentration. These total emissions and ambient
air quality contributions were obtained in a "base case" computer run in
which all sources were assumed to burn clean fuels, i.e., low sulfur coal,
low sulfur residual oil, distillate oil, or natural gas. This base-case
run is referred to as the 1971 clean-fuels run.
Relative Ambient Air Quality Contributions
From Small Sources and Large Sources
Previous studies have shown that, in general, small sources have
a greater impact on ambient air quality in porportion to their emissions
13)
than do large sources. * The sources in the Indianapolis AQCR exhibit
the same trend. Table 28 shows that the utility combustion group (20 to
440 MW) produced 156.9 tons S09 per day, or 78.1 percent of the total
3
emissions, while contributing only 7.35 ^g/m , or 15.8 percent, to the S02
58
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TABLE 28. SUMMARY OF SOURCES IN INDIANAPOLIS AQCR-"CLEAN FUELS" RUN, 1971
Ui
VO
Source Category
Utility Combustion
20-440 MW
Industrial Combustion
10-40 MW equiv.
Industrial Combustion
5-10 MW equiv.
Industrial Combustion
1-5 MW equiv.
Industrial Processes
Other Point Sources
Area Sources
Number of
Sources
11
8
11
25
7
165
207
Emissions
S02> T/D
156.9
12.4
8.5
7.7
•
3.3
3.1
9.1
E • % of Total
78.1
6.2
4.2
3.8
1.6
1.5
4.5
AAQ-R33 Mean
Hg/m3 A = % A/E Stack Ht,
7.35 15.8 .202 81 m
10.54 22.7 3.66 38 m
3.70 8.0 1.91 44 m
4.03 8.7 2.29 33 m
14.78 31.8 19.9
1.96 4.2 2.80
4.15 8.9 1.98
Totals
434
201
46.52
-------
concentration at Receptor 33. On the other hand, industrial boilers in
the 10-20 MW equivalent range produced 12.4 tons of S09 per day, or 6.2
3
percent of the total emissions, while contributing 10.54 p,g/m , or 22.7
percent, to the total S02 concentration at Receptor 33.
The ratio, A/E, where A = the percent contribution to ambient
air quality, and E = the percent of total emissions, was used in the
(12 13)
previous studiesv ' ' to show the relative effects of emissions from
different sources. A large body of A/E data calculated from AQDM analysis
of the New York, Philadelphia, and Buffalo AQCR's is presented in Reference 12.
These data show that there is wide variation in individual A/E values but
that average values for different types of sources are significantly
different. For example, Reference 12 gives the following summary of New York
AQCR S02 data where the A/E values are the mean values obtained for all
receptors in the AQCR grid.
Source Category Range of A/E Mean A/E
Utility Power 0.13-1.56 0.49
Industrial Combustion 0.69-2.17 1.06
Area Sources 0.53-1.69 1.38
The A/E value less than unity for utility power sources shows that these
sources contribute proportionally less to ambient air quality than to
total emissions, while the A/E value greater than unity for area sources
shows a relatively greater impact on ambient air quality from these
smaller sources.
Values of A/E were calculated for each source category in the
Indianapolis AQCR and are given in Table 28. The A/E for utility
combustion is 0.2 and 5 of the 6 remaining categories have A/E values
in the range of 1.9 to 3.7 in general agreement with the New York data.
The very high value, A/E = 19.9, for industrial processing, is due to the
presence of a sulfuric acid plant in close proximity to Receptor 33. This
plant produces only 0.36 percent of the total SCL emissions in the AQCR
but contributes more than 29 percent to the S02 concentration of Receptor 33.
60
-------
It is obvious that A/E values calculated for a single receptor will be
quite sensitive to the location of each source with respect to that
receptor. A second calculation was carried out for Receptor 44, the fifth
largest receptor. The resulting A/E values for each source category are
presented in the following tabulation together with those for Receptor 33
for comparison.
Receptor 44 Receptor 33
Source Category A/E A/E
1 0.17 0.20
2 4.89 3.66
3 2.26 1.91
4 3.53 2.29
5 4.50 19.9
6 4.74 2.80
7 2.67 1.98
The A/E values for different receptors are different as expected; however,
the conclusions regarding the relative impact of different source categories
remain the same.
The disproportionate impact of small sources indicated by this
analysis is related to the stack height and stems directly from the AQDM
model. The basic equation states that the concentration of pollutant at a
selected point is inversely proportional to an exponential function which
includes the square of the stack height. This results in a much lower
calculated concentration of pollutant for emissions from a tall stack as
compared with the same emissions from a short stack. To demonstrate this
relationship in the Indianapolis AQCR, the mean stack height is given in
Table 28 for the first four source categories. The general trend, low A/E
for tall stacks and high A/E for shorter stacks, is apparent. A plot of
log (A/E) versus the square of the stack height shows the expected scatter
but the correlation is clear.
61
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Effects of Fuel Switching on Ambient Air Quality
In view of the conclusions reached in the foregoing analysis,
the evaluation of the effect of projected energy requirements on ambient
air quality must include consideration of source size. Therefore, ambient
air quality calculations were carried out for the Scenario 1 projections,
allocation of clean fuels to the residential/commercial and industrial
sectors, and for the Scenario 3 projections, some dirty fuel burned in small
sources because of restrictions on clean fuel allocation.
Basis for Ambient Air Quality Calculations
The Air Quality Display Model was used to calculate ambient air
quality for the Indianapolis base case (1971 clean-fuels run). The results
of this run were used to calculate the effects of increased fuel use,
applied energy technology, and.fuel switching as projected by Scenario 1
and Scenario 3. These calculations are based on the fact that the AQDM
equation states that the concentration of pollutant at a selected point is
directly proportional to the emission rate of the source. Thus, if the
emission rate is increased by 20 percent, the pollutant concentration at
any point, and therefore at all points, is increased by 20 percent.
Similarly, if the emission rate of a number of sources is increased by
20 percent, the total pollutant concentration due to those combined sources
is increased by 20 percent.
Hypothetical Case
To illustrate this approach and to demonstrate the effect of
fuel switching, a hypothetical case is presented in Table 29. Consider a
group of point sources producing 180 tons S02 per day and contributing
30 p,g/m of SO- at a given receptor, and a group of area sources with
emissions of 80 tons S09 per day and an ambient air quality contribution
3
of 30 ,j,g/m . The A/E values in this case would be 0.7 and 1.7, respectively.
62
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TABLE 29. COMPARISON OF POINT SOURCE AND AREA SOURCE
CONTRIBUTION TO AMBIENT AIR QUALITY (AAQ)
Hypothetical Case
AAQ of
Emissions of Receptor,
S02, T/D ng/m3
Hypothetical Case
Point Sources 180 30
Area Sources 80 30
Totals 260 60
Shift 40 T/day of emissions
from point sources to
area sources
Point Sources 140 23.3
Area Sources 120 45
Totals 260 68.3
Shift 40 T/dav of emissions
from area sources to point
sources
Point Sources 220 36.7
Area Sources 40 15
Totals 260 51.7
63
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If clean fuel and dirty fuel were switched so that the point source emissions
decreased by 40 tons per day to 140 tons per day and area source emissions
increased by the same amount to 120 tons per day, the point source AAQ would
3
decrease to 23.3 p,g/m (140/180 x 30) and the area source AAQ would increase
to 45 ^g/m3 (120/80 x 30) to give a total AAQ of 68.3 g/m3. If the switch
were made in the opposite direction, the same type of calculation gives
3
a new total AAQ of 51.7 (j,g/m as shown in Table 29. Thus, with the same
3
total emissions, the AAQ varies from 51.7 to 68.3 jxg/m depending on the
distribution of the emissions between the source types.
Modifications to Indianapolis AQCR
This approach was applied to projections for the Indianapolis
AQCR corresponding to Scenario 1 and Scenario 3. Three modifications were
made to simplify the calculations as follows:
(1) Only coal combustion was considered
(2) The sources were divided into two groups,
utility sources and other sources
(3) Process sources were excluded.
As noted previously, the Indianapolis AQCR fuel mix includes nearly 88 percent
coal and only 5 percent petroleum. Since natural gas combustion produces
negligible SO- emissions, coal represents nearly 95 percent of the S0_-
producing fuel in the Indianaplis AQCR. For this reason, the total S0_
emissions were attributed to coal burning and oil burning was neglected.
The division of sources into two groups is based on the fact that the
combustion sources other than the utility group have A/E ratios between
1.9 and 3.7. Thus, the impact of sources in this group on ambient air
quality would be similar. Furthermore, allocation of fuels to categories
within this group would be purely arbitrary, hence, not meaningful. The
characteristics of the individual plants in the utility group are given
in Table 30 for reference. The industrial process sources are
noncombustion in nature. In the Indianapolis AQCR this group includes a
sulfuric acid plant, three coke ovens, a catalytic petroleum cracker, a
lead blast furnace, and a creosote plant. The S0_ emissions from such
64
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TABLE 30. CHARACTERISTICS OF UTILITY PLANTS IN INDIANAPOLIS AQCR
ON
Ui
Source
Number
1
2
3
4
5
6
7
8
9
10
12
Name
H.T. Pritchard Station
H.T. Pritchard Station
H.T. Pritchard Station
E.W. Stout Station
E.W. Stout Station
E.W. Stout Station
E.W. Stout Station
Perry K Plant
Perry K Plant
Perry K Plant
Noblesville
Size,
MW
105
125
175
20
55
205
450
65
70
80
230
Type
Pulverized Coal
Pulverized Coal
Pulverized Coal
Underfed Stokers
Pulverized Coal
Pulverized Coal
Spreader Stokers
Pulverized Coal
Pulverized Coal
Stack
Height,
ft
250
250
250
134
209
250
565
272
272
272
217
S02
Emission,
ton/day
10.30
12.39
17.08
2.41
5.13
30.38
57.77
4.69
5.22
5.65
5.92
Contribution to
Receptor 33,
|j,g/m3
0.143
0.163
0.186
0.849
1.076
3.339
0.519
0.299
0.306
0.414
0.057
Generation Station
-------
sources would be constant as fuel use and energy technology are varied.
Since these sources contribute over 30 percent to the AAQ of Receptor 33,
their inclusion as a constant would tend to make the effects of fuel
switching less distinct.
Projected Ambient Air Quality
The Indianapolis AQCR base-case, clean-fuels computer run for
1971 was modified on the basis of the foregoing considerations. The result
gives the total coal use, total SO- emission rate, and total contribution
to the SO- concentration at Receptor 33 for the electrical sector and
for the other sectors combined. The projected AAQ for each year and each
scenario were calculated by the following steps:
(1) The base-case values (coal use, S0» emission rate,
and AAQ contribution) were increased by the coal-use
growth factor obtained by dividing the projected
national consumption of coal as fuel for the given
year by the actual national coal use for 1971 using
the Dupree and West data.
(2) The newly projected coal use in each sector was
broken down into high-sulfur coal, low-sulfur coal,
and applied energy technology in proportion to the
quantities projected for each in Tables 6, 7, and 8
for Scenario 1, and in Tables 19, 20, and 21 for
Scenario 3.
(3) The S0« emissions rate for each coal type or
combustion mode was calculated using the appropriate
emission factors from Table 9.
(4) The new SO- emissions were summed for each sector.
* (5) The new AAQ contribution from each sector was
calculated on a proportional basis as illustrated
in the hypothetical case.
66
-------
(6) The new total AAQ was obtained by summing the new
AAQ from each sector.
The details of each calculation are given in Appendix B and
the results are given in Table 31. The difference in the predicted AAQ
for Scenario 1 and Scenario 3 is large. The values for Scenario 3 are more
than twice the values for Scenario 1 in each year. Since Scenario 3
includes some quantities of high sulfur coal in the nonelectrical sectors,
this result is expected from the large difference in the A/E values
for the electrical sector, 0.20, and for the other sectors, 1.9 to 3.7.*
For each Scenario the predicted AAQ decreases from 1975 to 1980, reflecting
the projected increase in the application of stack gas cleaning. The AAQ
values rise again in 1985 and 2000 as a result of the projected increase
in coal use.
One additional factor should be noted in connection with the
relative seriousness of emissions from small sources versus large sources.
There are some indications that sulfate may be a more critical air pollutant
(14)
than SO.. If airborne residence time is a significant factor in the
conversion of SO- to sulfate, then emissions from short stacks might
contribute less sulfate as an air pollutant than tall stacks. These
questions must be resolved before a final conclusion regarding the overall
importance of emissions from short versus tall stacks can be reached.
Discussion of Results
The predicted ambient air quality results for Scenario 1 and
Scenario 3 emphasize the importance of small sources in any emission
control strategy. A successful strategy should include not only allocation
of clean fuel to small sources but also provision of energy technology for
small sources. It is necessary to implement both approaches because each
has limitations. Allocation of clean fuels to small sources (as in
Scenario 1) has only a minor effect on total S0~ emissions but a dramatic
*See Appendix B for a discussion of the impact of greater total emissions
in Scenario 3 for the years 1980, 1985, and 2000.
67
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TABLE 31. SUMMARY OF PREDICTED AMBIENT AIR QUALITY
(INDIANAPOLIS AQCR)
Year
1975
1980
1985
2000
Sector
Electrical
Other
Total
Electrical
Other
Total
Electrical
Other
Total
Electrical
Other
Total
AAQ-Receptor 33,
Scenario 1
16.3
26.9
43.2
6.4
31.1
37.5
7.4
40.3
47.7
9.0
54.6
63.6
U,S02/m3(a)
Scenario 3
12.0
93.2
105
6.6
90.1
96
9.3
102.0
111
10.7
130.6
141
.2
.7
.3
.3
(a) Process sources omitted.
68
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effect on ambient air quality. Even so, in the sample case, the Indianapolis
AQCR, the ambient air quality contribution from nonutility sources comprised
60 to 85 percent of the combustion-related ground-level concentration of
SO- in Scenario 1. Thus, even if clean fuels could be allocated freely to
small sources, it would be desirable to further limit emissions from small
sources through application of some energy technology. A further limitation
is that there exist some constraints on the allocation of clean fuels.
The available data on the consumption of high- and low-sulfur fuels are not
sufficiently detailed to permit the identification of all such constraints
within the current program. However, some large blocks of "misplaced"
clean fuel can be identified which include:
(1) Natural gas burned under large, electrical-generation
steam boilers operated by industry as well as by
utilities. Such use involves long-term gas contracts
or even outright ownership of the gas field by the
company.
(2) Low-sulfur coal burned under utility boilers. Again
such use may involve long-term binding contracts, or
utility company ownership of mines producing low
sulfur coal.
The actual extent and nature of such constraints to clean-fuels allocation
should be determined in order to develop methods for improving the
flexibility and to accurately assess the magnitude of the emissions control
problem remaining for small sources.
The limitation of energy technology in this context lies in the
fact that most of the technologies under development are applicable
primarily to large sources. The question of applicability is discussed
further in the technology assessment section. Two conclusions may be
drawn from these considerations.
69
-------
(1) The technologies for control of emissions from large
sources should be perfected and applied as rapidly as
possible to free clean fuels for use in small sources,
(2) Energy technology applicable to small sources must be
developed as rapidly as possible.
70
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TECHNOLOGY ASSESSMENT
Approach
"'"H
The assessment of the potential role of the energy technologies
in the achievement of the national goals of meeting energy demand and
maintaining ambient air quality is difficult because it requires considera-
tion of a number of diverse factors which then must be related and
compared in a meaningful way. The approach taken to this assessment
involved the following steps:
(1) The development of assessment criteria
(2) The evaluation of each technology with respect to
each assessment criterion
(3) The conversion of the evaluation to a rating scale
(4) The compilation of aggregate ratings for each
technology, both with and without weighting of
the criteria
(5) The ranking of the technologies based on the
aggregate ratings.
The mechanics of the assessment involve methodology developed at Battelle
for environmental impact assessment modified somewhat for application to
technology assessment.
Assessment Criteria
A set of six criteria were employed in the assessment of the
energy technologies as follows.
(1) Residual emissions
(2) Projected availability of the technology
(3) Applicability of the technology to various fuels
and to various markets
(4) Cost of the applied technology
(5) Energy efficiency of the technology
(6) Probability of successful development.
71
-------
The energy technologies under consideration have differing
potential for minimizing air pollutant emissions. This variability was
expressed in terms of the residual air emission which are expected to
result from the application of the technology. In each case, the air
emissions resulting from the entire fuel/energy cycle, including extrac-
tion, transportation, processing, and utilization were considered.
In view of the urgency of the related energy and environmental
problems, the projected availability of a given technology is an
important criterion in the assessment of its potential role. The factors
of date of commercialization and the subsequent rate of implementation of
the technology are components of the availability consideration. These
questions involve the current stage of development and commercialization
and the complexity of the process.
» The applicability of the technology was evaluated with respect
to the types and availability of fuels appropriate to the technology,
and to the various markets which could be served by the technology.
The cost factor is complex and involves the capital require-
ments, the operating cost of the technology, i.e., the incremental cost
of energy due to the application of the technology, comparative costs
of competitive technologies, and development costs. Another considera-
tion is the question of utilization of capital within the United States
rather than investment in foreign-based operations.
The criterion of energy efficiency includes losses in fuel
processing, energy requirements in the application of the technology, and
the potential of some technologies to be coupled with advanced power
cycles thus increasing overall efficiency.
The probability of success was evaluated on the basis of the
amount of existing data, the complexity of the technology, and the degree
of departure from existing technology.
The question of system reliability is an important factor which
was considered in the assessment process. It was not established as a
separate criterion, however, because reliability is very closely associated
with the categories of availability and probability of successful develop-
ment. It was assumed that reliability must be established before a
72
-------
technology is considered commercially available. Similarly, reliability
is inherent in evaluating the probability of successful development.
There are, of course, interrelationships between other assess-
ment criteria. For example, the complexity of the proposed technology
is considered in probability of successful development as well as in
availability through the cost and risk factors which affect the probability
that needed work will be done to complete the development.
Technology Evaluation
The second step in the assessment procedure was to develop an
evaluation of each technology with respect to each of the six assessment
criteria. A quantitative evaluation was employed wherever possible,
otherwise qualitative categories for evaluation were developed. The
results of this evaluation are summarized in Table 32. This summary
includes ten categories of energy technologies, and the basic assessment
was made for these ten. Some of these categories include more than one
approach. Comparisons of different processes within an energy technology
are pointed out in the various evaluations. The derivation and signifi-
cance of the evaluations in each assessment category are discussed in the
following sections.
Residual Emissions
The data in Table 32 which characterize the residual emissions
for each technology were derived from the total emissions given in Tables
10, 11, and 12, which, as discussed previously, indicate total emissions
for the entire fuel/energy system. Thus the data in Table 32 take into
account the air emissions from each module represented in each fuel/
technology system as defined in Table 8. The residual emissions in
Table 32 are expressed in units of thousands of tons per trillion Btu.
(This unit is equal to two pounds per million Btu.) A sample calculation
will serve to illustrate the derivation of the data. The quantity of
12
cleanable coal projected for 1975 is given in Table 6 as 1,110 x 10 Btu.
The total air pollutant emissions from the extraction, physical cleaning,
73
-------
TABLE 32. ENERGY TECHNOLOGY EVALUATION MATRIX
Total System
Residual Emissions, Availability
Energy Technology 103 ton/1012 Btu Year Rate
Physical Coal Cleaning
Chemical Coal Cleaning
Resid Desulfurixatlon
Coal Refining (liquefaction)
Coal Gasification, low Btu
Coal Gasification, high Btu
Stack Gas Cleaning,
throwaway
Stack Gas Cleaning,
by-product
High-Pressure Fluldized-
Bed Combustion of Coal
Atm. Pressure Chemically
Active Fluidized-Bed
Combustion of Oil
1.214
1.359
1.015
1.026
0.817
0.996
0.718
0.718
0.520
0.334
Now
1978
Mow
1980
1978
1977
' Mow
''
1974
1977
1977
1
2
1
3
3
3
1
1
2
2
Applicability
Fuels
Coal
Coal
Oil
Coal
Coal
Coal
Both
Both
Coal
Oil
Sector .
Harketsu'
All
All
All
E+I
E+I
R/C
E+I
E+I
E+I
E+I
Cost
Capital, Operating,
$/kw c/106 Btu
2.3 6.6(b>
16-22 50(£)
(a) (a)
117-197V8; 60W
/v\ /t_\
25-75Ch) 25(h)
25-75 (h) 25(h)
5-25 U) 20 W
f • \ f* \
5-25(1) 20(1)
Energy
Efficiency
.88
.95
.90
.75
.70
.65
.95
.95
1.00
1.00
Probability of
Successful
Development (3)
E
A-3
E
B-2
B-2
B-l
A-l
A-l
A-3
A-3
-------
Footnotes to Table 32
(a) E « Electrical Sector, I - Industrial Sector, R/C = Residential
and Commercial Sector.
(b) Capital costs for physical coal cleaning plants were estimated in
Reference 15 to be $5.6 and $6.3 million for two modifications of
a 1000 T/hour plant. These estimates were converted to $/kw and
the 1966 costs escalated to 1972 costs by means of the Marshall
Stevens index. The average of the values, $2.17/kw and $2.44/kw,
was taken. The value given for operating cost was taken from
Reference 2, page 333.
(c) Capital and operating costs given are Battelle estimates for
hydrothermal chemical coal cleaning.
(d) The capital cost of hydrodesulfurization of residual oil was
reported in Table 15, page 97 of Reference 16. Operating cost
is estimated at 43.6 cents per million Btu on page 23 of Reference
16. Page 99 of the same reference shows costs for other modifi-
cations up to 48.4 cents/million Btu. A value of 45 cents/million
Btu was selected.
(e) Capital and operating costs were taken from Reference 2, page 364.
The estimate for operating cost includes the value of the coal
lost in processing but not the cost of the coal converted to
product.
(f) Capital costs of $82/kw were estimated for the Wellman-Galusha
low Btu process in Reference 16, page 91. Other estimates of
capital costs for other low Btu systems range from $70 to $135
per installed kw. A value of $90/kw was taken. Operating cost
estimates range from 45 to 70 cents per million Btu. A
conservative value of 50 cents per million Btu was chosen.
(g) Capital costs were taken from Reference 2, page 381. The capital
cost for a Lurgi high Btu plant was estimated in Reference 17 as
$134/kw which is within the range given. The cost of high Btu
gas at a Lurgi plant was estimated in Reference 17 to range from
$1 to $1.20 per million Btu for coal costing $7 per ton. Sub-
tracting this coal cost gives a range of 50 to 70 cents per million
Btu. The mean of this range was chosen.
(h) Capital and operating costs for stack gas cleaning were taken
from Reference 2, pages 409 and 394. The operating cost entered
in the table is a mean value.
(i) Capital and operating costs for fluidized-bed combustion of coal
and oil were taken from Reference 2, pages 416 and 423.
(j) See text for definition of categories.
75
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transportation, and combustion of that quantity of coal are given in
Table 11 as follows: NO - 391.96, SO, - 802.2, CO _ 29.4, particulate -
X £»
119.1, and total organic material - 6.1 thousand tons. Each of these
quantities was divided by 1,110 trillion Btu to give the following system
emissions: NO - 0.353, S09 - 0.723, CO - 0.026, particulate - 0.107,
X &
and total organic material - 0.005 thousand tons per trillion Btu. The
total of these air emissions, 1.214 thousand tons per trillion Btu, was
entered in the residual emissions column of Table 28 for the physical
coal cleaning technology.
The chemical coal cleaning system was not included in the
projected total emissions calculations. The residual emissions value
in Table 32 was therefore derived from data given in Reference 2 with
correction to 1 percent sulfur in the chemically cleaned coal. The
other residual emissions data in Table 32 were calculated as illustrated
for physical coal cleaning. In addition the residual emissions for a
reference system, eastern high-sulfur coal burned without sulfur dioxide
control, were calculated in the same manner to be 2.908 thousand tons
per trillion Btu.
Availability
Technology availability was evaluated first in terms of the
estimated year of commercial availability, defined as the year during
i
which 1 year of successful operation on a 100-MW plant is achieved.
The years entered in Table 32, under Availability - Year, represent a
concensus of opinion regarding the achievement of such a successful
demonstration. A second factor to be considered with respect to avail-
ability is the rate at which the technology will be implemented after
commercialization. A major factor affecting the rate of implementation
is the complexity of the process. A highly complex process, requiring a
longer lead time for fabrication of components and construction, and
being more highly capital intensive will lead to a lower implementation
rate. These considerations were combined and the technologies evaluated
with respect to three categories defined as follows: Rate Category 1,
those technologies now in commercial use and those which represent a
76
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relatively low degree of complexity; Rate Category 2, those technologies
based on existing technology but requiring unusual process conditions
thus representing an intermediate degree of complexity; Rate Category 3,
highly complex processes. The technology evaluations based on these
three categories are given in Table 32 under Availability - Rate.
Applicability
Applicability was evaluated qualitatively with respect to the
type of fuel used and to the sector markets served. The entries under
Applicability in Table 32 reflect the applicability of each technology to
coal, to oil or to both fuels and the consuming sectors expected to be
markets for each technology.
Cost
The energy technologies were evaluated with respect to two
cost categories: capital requirements and operating costs. The capital
costs given in Table 32 are expressed in dollars per kilowatt of electrical
generating capacity. For fuel cleaning and fuel conversion technologies,
the plant output in Btu was converted to the equivalent power plant output
from that quantity of fuel by the ratio 60 x 10 Btu/year-= 1 kw of
installed capacity. This conversion ratio assumes a heat rate of 10,000
Btu/kwhr and a load factor of 68 percent.
The operating costs given in Table 32 are expressed in cents
per million Btu. The operating costs refer only to process costs and do
not include the cost of the fuel processed or burned. Thus these costs
represent the incremental energy cost added through the application of
the technology. The bases for the cost estimates given in Table 32 are
summarized in footnotes to the table.
A third factor in the cost criterion is the cost of research
and development. Because this is a less significant factor over the
long term than the other two and because estimates of developments costs
are quite uncertain, no attempt was made to formally include development
costs in the assessment.
77
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Energy Efficiency
The energy efficiencies given in Table 32 reflect energy loss
as compared with a conventional system and thus represent energy penalties
attending the application of each technology. For fuel cleaning and fuel
conversion processes, the inefficiency consists largely of fuel loss,
either through material losses in the processing, or through fuel burned
for process heat or both. For the stack gas cleaning technologies, the
inefficiency represents the parasitic energy required to operate the
cleaning process. The efficiency value of unity entered for the fluidized-
bed technologies reflects the potential for achieving a thermal efficiency
from fluidized bed/generator coupling equal to or greater than that from
conventional steam boilers.
The energy efficiency data given in Table 32 were taken from
Reference 2, with the exception of the value for residual oil desulfuri-
zation which was calculated from data given in Table 13, page 94 of
Reference 16.
Probability of Successful Development
The probability of successful development was evaluated
categorically. Five categories were established to reflect the current
status of the development and the degree of departure from conventional
technology. These categories are defined as follows:
E = existing technology
A-l = modest extension of existing technology
A-2 = moderate extension of existing technology
A-3 = significant extension of existing technology
B-l = requires moderate amount of technology
B-2 = requires significant new technology.
Each technology was evaluated with respect to these five categories as
indicated in Table 32.
78
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Technology Rating
The evaluations of each technology within each assessment
criterion compiled in Table 32 represent diverse kinds of information.
Some evaluations are quantitative, with different units for different
criteria; others are qualitative or categorical. To provide a means for
combining these evaluations into an overall assessment, the evaluations
were converted to a rating scale. The methodology was adapted from an
(18 19}
approach developed at Battelie for environmental impact assessment.v » 7'
The evaluations were converted to ratings through the Technology
Rating Function illustrated in Figure 1. The Technology Rating Factor,
10-
8-
6-
£
«•
2-
AiMSMMt Piranttr Seal*
(Ibi/ Btu, yr», dollars, etc)
FIGURE 1. GENERALIZED TECHNOLOGY RATING FUNCTION
with values from 0-10, is read from the ordinate for various values of the
assessment parameter given on the abscissa. The use of the Technology
Rating Function results in a normalization of the quantitative evaluations
which resolves the problem caused by the use of different units in different
79
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evaluations. In addition, the Technology Rating Function approach provides
a means for quantifying the qualitative or categorical evaluations.
Residual Emissions Rating
The Technology Rating Function for the residual-emissions
criterion is shown in Figure 2. The abscissa represents the residual
1.0 2.0
Total RMlduil Evictions, 10 ton/10 St
3.0
FIGURE 2. TECHNOLOGY RATING FUNCTION FOR AIR EMISSIONS
emissions expressed as thousands of tons per trillion Btu. The residual
emissions of the system, strip mining of Eastern coal-rail transport-
conventional boiler without sulfur dioxide control (2.908 thousand tons
per trillion Btu), were selected as the reference point for zero Rating Factor
Conversely, zero emissions were set equal to a Rating Factor of ten. The
residual emission Rating Factor for each technology is the ordinate value
corresponding to the residual emission value for each technology obtained
from Table 32. For example, the total residual emissions given in Table £2
for the physical coal cleaning technology are 1.214 thousand tons per
80
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trillion Btu. As shown by the dotted lines in Figure 2, the corresponding
Rating Factor is 5.8. In this manner, the residual emissions Rating Factors
were determined for each technology. The resulting factors are given in
descending order in the following tabulation.
Residual Emissions
Energy Technology Rating Factor
Chemically active fluidized bed, oil 8.9
High pressure fluidized bed, coal 8.2
Stack gas cleaning, by-product 7.5
Stack gas cleaning, throwaway 7.5
Coal gasification, low Btu 7.2
Coal gasification, high Btu 6.6
Resid desulfurization 6.5
Coal refining (liquefaction) 6.5
Physical coal cleaning 5.8
Chemical coal cleaning 5.3
Availability Rating
The Technology Rating Function for availability based on year
of first commercialization is shown in Figure 3. A zero Rating Factor was
assigned to the year 1985 and a Rating Factor of 10 was assigned to the
present year. The second evaluation in the availability criterion, i.e.,
rate of availability, was introduced by applying the following corrections
to the Rating Factors obtained from Figure 3: Rate Category 1 - no
correction; Rate Category 2 - 0.3 correction; and Rate Category 3 - 0.6
correction.
81
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8-
5 6-
5
«*
4 -
2-
I I
73 75
79
81
83
85
YMX
FIGURE 3. TECHNOLOGY RATING FUNCTION FOR TECHNOLOGY AVAILABILITY
The availability Rating Factors are:
Energy Technology
Physical coal cleaning
Resid desulfurization
Stack gas cleaning, throwaway
Stack gas cleaning, by-product
Chemically active fluidized bed, oil
High pressure fluidized bed, coal
Coal gasification, high Btu
Chemical coal cleaning
Coal gasification, low Btu
Coal refining (liquefaction)
Rating Factor
for Year of
Availability
10
10
10
9.2
6.7
6.7
6.7
5.8
5.8
4.2
Correction
for Rate of
Availability
None
None
None
None
-0.3
-0.3
-0.6
-0.3
-0.6
-0.6
Net
Rating
Factor
10
10
10
9.2
6.4
6.4
6.1
5.5
5.2
3.6
82
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Applicability Rating
Both components of the evaluation of the applicability of energy
technologies are categorical in nature. The Technology Rating Function
shown in Figure 4 for fuel applicability is based on the rationale that
10
FutU
FIGURE 4. TECHNOLOGY RATING FUNCTION FOR FUEL AVAILABILITY
energy technologies applicable to both coal and oil utilization should be
rated higher than those applicable to either fuel alone. Further, in view
of the nation's relative abundance of coal and scarcity of oil, the
technologies applicable only to oil were downgraded with respect to those
applicable only to coal. The location of these categories along the
abscissa of Figure 4 is arbitrary but based on the above considerations.
The Technology Rating Function shown in Figure 5 for market
applicability was constructed in a similar fashion. The location of the
three categories along the abscissa was based on the greater weight given
to the electrical and industrial sectors which make up 70-72 percent of the
total demand throughout the period to 2000.
83
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Electrical
C
Industrial
Rnldtntial
1
CoBMrcUl
Mtrkctt
FIGURE 5. TECHNOLOGY RATING FUNCTION FOR MARKET APPLICABILITY
The Rating Factors for each technology were determined from
Figures 4 and 5 and the mean of the two values taken as the composite
Rating Factor for the applicability criterion. The results are as follows:
Energy Technology
Physical coal cleaning
Chemical coal cleaning
Stack gas cleaning, throwaway
Stack gas cleaning, by-product
Coal refining (liquefaction)
Coal gasification, low Btu
High pressure fluidized bed, coal
Resid desulfurization
Coal gasification, high Btu
Chemically active fluidized bed,
oil
Rating Factor
for Fuel
Applicability
8
8
10
10
8
8
8
4
8
4
Rating Factor
for Market
Applicability
10
10
8
8
8
8
8
10
6
8
Mean
Rating
Factor
9
9
9
9
8
8
8
7
7
6
84
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Cost Rating
The Technology Rating Function for capital cost is shown in
Figure 6 and that for operating cost is shown in Figure 7. A capital cost
of $300/kw was assigned a zero Rating Factor in Figure 6, and an operating
cost of $1 per million Btu was assigned a zero Rating Factor in Figure 7.
The Rating Factors were determined separately for capital and operating
cost and the resulting values averaged to give the overall Rating Factor.
Where ranges are given in Table 32 for capital cost, the mean of the range
was used to determine the Rating Factor. The results are as follows.
Energy Technology
Physical coal cleaning
High pressure fluidized bed, coal
Chemically active fluidized bed, oil
Chemical coal cleaning
Stack gas cleaning, throwaway
Stack gas cleaning, by-product
Resid desulfurization
Coal gasification, low Btu
Coal refining (liquefaction)
Coal gasification, high Btu
Rating
Factor,
Capital Cost
Rating Mean
Factor, Cost
Operating Rating'
Cost Factor
9.9
9.5
9.5
9.4
8.3
8.3
9.4
7.0
7.3
4.8
9.3
8.0
8.0
7.4
7.5
7.5
5.5
5.0
4.0
4.0
9.6
8.8
8.8
8.4
7.9
7.9
7.5
6.0
5.7
4.4
Energy Efficiency Rating
The Technology Rating Function for energy efficiency is shown
in Figure 8 where 50 percent efficiency was assigned a zero Rating Factor.
The resulting values are as follows.
85
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10 -K
a -
5
6-
4-
200
300
installed
FIGURE 6. TECHNOLOGY RATING FUNCTION FOR CAPITAL COSTS
90
c«nt»/Blllion Btu
100
FIGURE 7. TECHNOLOGY RATING FUNCTION FOR OPERATING COSTS
86
-------
100
FIGURE 8. TECHNOLOGY RATING FUNCTION FOR EFFICIENCY
Energy Technology
High pressure fluidized bed, coal
Chemically active fluidized bed, oil
Chemical coal cleaning
Stack gas cleaning, throwaway
Stack gas cleaning, by-product
Resid desulfurization
Physical coal cleaning
Coal refining (liquefaction)
Coal gasification, low Btu
Coal gasification, high Btu
Energy Efficiency
Rating Factor
10
10
9
9
9
8
7.6
5
4
3
Probability of Successful Development Rating
The Technology Rating Function for probability of successful
development is shown in Figure 9. The evaluation categories are located
along the axis on the basis of the relative probability of success judged
for each category. The resulting Rating Factors are as follows.
87
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10->
a-
Existing
FIGURE 9.
A-2
A-3
B-l
B-2
Extension of Existing
Technology
Technology
Required
TECHNOLOGY RATING FUNCTION FOR
PROBABILITY OF SUCCESSFUL DEVELOPMENT
Energy Technology
Physical coal cleaning
Resid desulfurization
Stack gas cleaning, throwaway
Stack gas cleaning, by-product
Chemical coal cleaning
High pressure fluidized bed, coal
Chemically active fluidized bed, oil
Coal gasification, high Btu
Coal refining (liquefaction)
Coal gasification, low Btu
Probability of Success
Rating Factor
10
10
9
9
7
7
7
6
5
5
88
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Aggregation of Technology Ratings
Unweighted Summation
The overall technology assessment including all criteria was
first made by summing the individual criteria ratings for each technology.
The sums thus obtained reflect the relative potential of the various
technologies assuming that all of the criteria are equally important. All
of the ratings are compiled in Table 33 in which the technologies are listed
in ranked order according to their aggregate ratings.
Weighted Summations
To incorporate the relative importance of the assessment criteria
in judging the potential role of energy technologies, a second aggregation
was carried out. Each rating was first multiplied by a weighting factor
chosen to reflect the relative importance of the criteria; then the products
were summed to obtain the weighted aggregate -rating.
The weighting factors were obtained by quantifying the subjective
value judgments of a panel of six Battelle scientists active in the air
pollution control field. An iterative procedure was used with controlled
feedback of intermediate results to arrive at a group consensus. Each
member was asked to list the six criteria in order of importance as measures
of the potential role of energy technology in satisfying our energy demands
with minimum air pollution. Each member then made successive pairwise
comparisons between contiguous elements to determine for each element pair
the ratio of importance. For example, the criterion ranked second was
compared to the first to determine how much less important the second is to
the first. This relative importance was expressed as a ratio greater than
zero, and less than or equal to one. The process was continued between
the third and the second, the fourth and the third, etc. The output from
this procedure was a weighted list of the criteria for each member of the
panel. The weighting factors thus developed were averaged to yield the
first set of weights. The results were as follows.
89
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TABLE 33. ENERGY TECHNOLOGY RATING MATRIX
Criteria Rating. R
Energy Technology
Stack Gas Cleaning,
throvaway
Physical Coal Cleaning
Stack Gas Cleaning,
by-product
Resid Desulfurization
High Pressure Fluid! zed-Bed,
coal
Chemically Active Fluidized
Bed, oil
Chemical Coal Cleaning
Coal Gasification, low Btu
Coal Refining (liquefaction)
Coal Gasification, high Btu
Residual
Emissions
7.5
5.8
7.5
6.5
8.2
8.9
5.3
7.2
6.5
6.6
Availability
10
10
9.2
10
6.4
6.4
5.5
5.2
3.6
6.1
Applicability
9
9
9
7
8
6
9
8
8
7
Cost
7.9
9.6
7.9
7.5
8.8
8.8
8.4
6.0
5.7
4.4
Energy
Efficiency
9
7.6
9
8
10
10
9
4
5
3
Probability
of Success
9
10
9
10
7
7
7
5
5
6
Unweighted
Aggregate
Rating, ER
52.4
52.0
51.6
49.0
48.4
47.1
44.2
35.4
33.8
33.1
Weighted
Aggregate
Rating,
£WfR
405.5
403.2
398.7
384.0
378.9
377.9
335.3
273.7
257.1
255.9
Normalized
Weighted
Rating
52.2
51.9
51.3
49.4
48.8
48.7
43.2
35.2
33.1
33.0
-------
Assessment Criterion
Residual Emissions
Availability
Cost
Applicability
Probability of Success
Efficiency
Mean
Weighting
Factor
19.0
13.4
12.9
12.4
12.2
11.4
S tandard
Deviation
12.7
10.7
5.4
7.2
10.3
9.8
These results show that the members of the group differed
widely in their evaluation of the relative importance of the criteria.
The large standard deviation for most of the criteria shows that some
members gave a given criterion a large weight while others gave the same
criterion a small weight. The averaging process smoothed these out to
leave the weights nearly the same from the second criterion to the last,
i.e., the group consensus after the first weighting was that the criteria
are of nearly equal importance. A consultant asked to rank the criteria
in the same fashion said that he felt that they were all of equal importance,
thus tending to support the first group consensus. A second iteration was
performed in which the panel was given the group weights and the standard
deviations. Each member repeated the scaling procedure and the resulting
weights again averaged with the following results
Assessment Criterion
Cost
Emissions
Availability
Probability of Success
Efficiency
Applicability
Mean
Weighting
Factor
16.8
16.3
14.3
12.5
12.0
6.7
Standard
Deviation
3.2
7.8
9.0
10.5
5.0
6.1
The standard deviation, although smaller than those of the first iteration,
are still large showing that considerable difference of opinion still
remained among the panel regarding the relative importance of the criteria.
91
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The nJean weighting factors from the second iteration were normalized to
a scale of 1-10 and rounded to the nearest 0.5. The final weights were
as follows.
Final Weighting
Assessment Criterion Factor. Wf
Residual Emissions 10
Cost 10
Availability 8.5
Probability of Success 7.5
Efficiency 7
Applicability 4
It should be stressed that the weights obtained represent an average of
the rather diverse opinion of one panel. The results were used only to
examine the effects of weighting the ratings and they are not presented
as an absolute scale of relative importance. These weights were employed
to compute the weighted aggregate rating values entered in Table 33. For
easier comparison with the unweighted sums, the weighted totals were
normalized as shown in the last column of Table 33.
Comparison of the weighted and unweighted ratings shows that the
rank order of the technologies did not change and the differences in the
aggregate ratings by the two methods are small.
Discussion of the Technology Assessment
Examination of the total weighted technology ratings given in
Table 33 shows that there are three rather distinct groupings of technologies,
The technologies in the highest ranked group, including both stack gas
cleaning technologies and physical coal cleaning, have essentially
equivalent ratings. The technologies in the second group, consisting of
residual oil desulfurization and the two fluidized-bed technologies, are
nearly equivalent but are 3 to 5 points lower in rating than the first
group. The third group includes the three coal conversion processes. The
ratings for this group are 12-14 points below those for the second group.
Chemical coal cleaning is rated between the second and third groups.
92
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The stack gas cleaning processes combine good emission control,
early projected availability, and intermediate cost to achieve their high
ratings. Physical coal cleaning and residual oil desulfurization are less
effective in emission control but the fact that they are both existing
technologies is an offsetting consideration. The relatively low cost of
physical coal cleaning raises that technology into the highest rated group.
The coal conversion processes, on the other hand, exhibit less effective
air emission control, when the entire system is considered, later
availability, higher cost, and lower energy efficiency than the rest of
the technologies which accounts for their comparatively low ratings.
The comparison of the weighted and unweighted aggregate
technology ratings in Table 33 is interesting. As noted previously, the
rank order of the technologies remained the same when the technology ratings
were weighted according to a scale of relative importance of the assessment
criteria. This result emphasizes the fact that the technologies near the
top of the list are highly rated in most of the criteria while those near
the bottom of the list are less highly rated in most of the criteria.
Another contributing factor is that the weighting factors used did not
differ greatly, the first five varying only between 7 and 10. However,
given the generally high criteria ratings of the top group and the generally
low ratings of the bottom group, the rank order of technologies could be
expected to remain unaffected unless highly disproportionate, and thus
unrealistic, weighting factors were used.
The technology assessment was designed to incorporate a number of
factors into an unbiased evaluation of the various technologies with respect
to their overall potential. It was not possible to accurately reflect all
the factors involved, and in some cases there will be special considerations
which may override the factors which were specifically included in the
assessment. As one example, the widespread use of natural gas for home
heating and the abundance of coal combine to make the conversion of coal into
a substitute natural gas a highly desirable, if not mandatory, technology
for the future. Thus, although the high Btu gasification technology is
ranked last in this assessment, the special needs for substitute natural
gas will require pursuit of the development of this technology.
93
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The results of the predicted ambient air quality calculations
demonstrate the importance of small sources. Those energy technologies
which are applicable to small and intermediate-size sources include: coal
cleaning, resid desulfurization, coal refining, coal gasification, and
fluidized-bed combustion of coal. The widespread application of coal
cleaning, while not a total solution, could provide a significant reduction
in S0_ emissions particularly if chemical cleaning processes capable of
removing all or part of the organic sulfur can be developed. It appears
that smaller boilers can be modified to burn refined coal products.
Development of coal refining technology will therefore make a clean fuel
available for the small source sectors. Low Btu coal gasification
systems are being developed for utility plant application. However,
smaller scale systems, such as the Lurgi which is inherently a small unit,
may be usefully applied for on-site generation of low Btu gas for certain
industrial applications. High Btu gas from coal could serve as a clean
fuel for small industrial sources if they can accommodate the expected
higher cost. Development of designs for the fluidized-bed combustion of
coal in boilers of intermediate size will provide some of the required
emission control.
94
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OPTIMUM TECHNOLOGY UTILIZATION
The fuel utilization matrix constructed for Scenario 1,
Tables 5, 6, and 7, show that in 1975 and 1980 there will be a deficit
in clean fuels and energy technology so that, according to this forecast,
some dirty fuels will have to be burned in those years. On the surface,
the outlook appears brighter for the years 1985 and 2000, since no uncon-
trolled combustion is forecast for those years. This results, however,
from the optimistic preliminary projections of the availability of energy
technology given in Table 4. It must also be emphasized that the basic
fuel supply forecasts of Dupree and West, ' which form the bases for
Tables 5, 6, and 7, include substantial amounts of imported petroleum
(36.9 percent and 70.3 percent of the total petroleum supply in 1975 and
2000, respectively) and gaseous fuel (10.2 percent and 28.2 percent of
the total gaseous fuel supply in 1975 and 2000, respectively). It should
be a national goal to minimize dependence on these foreign supplies to
the greatest extent possible. Therefore, it is necessary to continue to
accelerate the development and use of appropriate energy technologies not
only to eliminate the need for uncontrolled combustion of dirty fuel but
also to maximize the use of domestic fuel, principally coal. It is clear
that to achieve both of these goals, it will be necessary to provide the
required energy technologies at an even greater rate than is optimistically
projected in Table 4.
The results of the technology assessment indicate that the following
actions should be incorporated into the strategy for technology development
and utilization:
• Stack-gas cleaning is the most advanced technology
which will permit extensive use of domestic high sulfur
coal over the near term with adequate emission control.
Relative cost comparisons with alternate options
suggest that only fluidized-bed combustion and
chemical coal cleaning are competitive on a cost
basis. The current low level of research and
development in the latter areas makes it unlikely
95
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that stack gas cleaning will be displaced prior
to 2000. Therefore, the remaining engineering
problems associated with these technologies should
be resolved as rapidly as possible, and implementation
of the technology should be promoted to the fullest.
Physical coal cleaning technology is available now,
it is relatively inexpensive, and it can achieve on
the average a 30 percent reduction in the sulfur
dioxide emissions from combustion of the coal.
Implementation of this technology should be extended
fully.
High-pressure fluidized-bed combustion of coal with
advanced-cycle power generation has good potential
for the extensive utilization of domestic coal. The
development and implementation of this technology also
should be stressed.
The chemically active fluidized-bed combustion of oil
exhibits the minimum residual emissions of those
considered. The potential of this technology over
the near term could be greater than indicated in
the technology assessment if a major national program
were undertaken. The low cost and high efficiency
of the process in addition to the low emissions
warrant such an emphasis.
Chemical coal cleaning has potential for more
efficient sulfur removal than does physical cleaning.
The development of this technology will thus increase
the quantity of coal which can be cleaned to 1 percent
sulfur or less. In this regard, the two coal cleaning
processes are not a duplication of effort. The less
expensive physical process can be usefully applied
to coals having sulfur contents in the range amenable
to physical cleaning and chemical cleaning applied to
coals with higher sulfur content. Accelerated development
96
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and early Implementation of this technology will
further expand the nation's ability to utilize
domestic coal.
• Continued development of the coal conversion technologies
is warranted on the basis of special considerations as
in the case of high Btu gasification as discussed
previously.
97
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REFERENCES
(1) Dupree, W. G., Jr., and West, J. A., "United States Energy
Through the Year 2000", U. S. Department of the Interior,
December, 1972.
(2) Battelle's Columbus Laboratories and Battelle's Pacific Northwest
Laboratories, "Environmental Considerations in Future Energy
Growth", prepared for the Office of Research and Development,
EPA, April, 1973.
(3) "Minerals Yearbook 1971, Vol. I, Metals, Minerals, and Fuels",
Prepared by Bureau of Mines, U. S. Government Printing Office,
Washington, D. C., 1973.
(4) "Study of the Future Supply of Low Sulfur Oil for Electrical
Utilities", a report prepared for EPA by Hittman Associates, Inc.,
February, 1972.
(5) Hoffman, L., Lysy, F. J., Morris, J. P., and Yeager, K. E.,
"Survey of Coal Availabilities by Sulfur Content", Final Report
by the Mitre Corporation for EPA, May, 1972.
(6) "Projected Utilization of Stack Gas Cleaning Systems by Steam-
Electric Plants", Final Report by the Sulfur Oxide Control
Technology Assessment Panel, submitted to the Federal Interagency
Committee, Evaluation of State Air Implementation Plans, Apr. 15, 1973.
(7) "Draft Report on Future Desulfurization Capacity", to Office of
Air Programs, EPA from Mitre Corporation.
(8) Personnel Communication.
(9) "Mineral Industry Surveys", prepared by Division of Fossil Fuels,
Bureau of Mines, U. S. Department of Interior, October 5, 1972.
(10) "Minerals Industry Surveys", prepared by Division of Fossil Fuels,
Bureau of Mines, U. S. Department of Interior, March 19, 1973.
(11) "Minerals Yearbook 1970, Vol. I, Metals, Minerals, and Fuels",
Prepared by Bureau of Mines, U. S. Government Printing Office,
Washington, D. C., 1972.
(12) Krajeski, E. P., Keitz, E., and Bobo, D., "A Study of the
Relationship Between Pollutant Emissions from Stationary Sources
and Ground Level Ambient Air Quality", Report by The Mitre
Corporation to EPA, May 31, 1972.
98
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(13) Krajeski, E. P. and Yeager, K. E., "A Case for Selective Controls
to Achieve Ambient Air Quality Standards", The Mitre Corporation,
November, 1972.
(14) Lewis, T. R., et al, "Toxicology of Atmospheric Sulfur Dioxide
Decay Products", EPA, National Environmental Research Center,
Research Triangle Park, North Carolina, July, 1972.
(15) Zimmerman, R. E., "Economics of Coal Desulfurization", Chem. Eng.
Prog.. 62, 61 (1966),
(16) Robson, F. L., et al., "Technological and Economic Feasibility of
Advanced Power Cycles and Methods of Producing Nonpolluting Fuels
for Utility Power Stations", United Aircraft Research Laboratories,
December, 1970, PB 198392.
(17) "Evaluation of Coal-Gasification Technology, Part I Pipeline-
Quality Gas", National Research Council R&D Report No. 74-Interim
Report No. 1, 1973.
(18) Whitman, I., et al., "Design of an Environmental Evaluation System",
Battelle-Columbus report to the U.S. Bureau of Reclamation,
Contract No. 14-06-D-7005, Washington, D.C., 1971, PB 201743.
(19) Dee, N., et al., "An Environmental Evaluation System for Water
Resource Planning", Water Resources Research, April, 1973.
99
-------
APPENDIX A
DATA TABLES FOR SELECTED MODULES
The unit emissions data derived for each of the modules are
given in the following tables. The source of original data and the
assumptions made are given in footnotes to each table, so that the
calculations can be repeated. The references cited are listed at the
end of this Appendix.
100
-------
Table 34. ENVIRONMENTAL DATA FOR MODULE
Module - Gas Well
Unit - 106 Btu
Environmental Parameters Fuel Input, Natural Gas
NOV, Ib 0.23(1)
So![, Ib f 0
CO, Ib 0
Particulate, Ib 0
Total organic material, Ib O.l(2)
Heat, 10° Btu 0
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib 0
Heat, 100 Btu - 0
Acid (H2S04>, Ib 0
• •
%
Solid
Slag, Ib 0
Ash, Ib 0
Sludge, Ib 0
Tailings, Ib 0
Hazardous, Ib 0
By-Products 12.6<3>
Occupational Health
Deaths 2.2 x
Total Injuries 2.1 x
Man Days Lost 3-5 x
Land Use, acrc-hr/106 Btu 0.06<7)
Approx. Module Efficiency
101
-------
Footnotes for Table 34:
(1) a. Natural gas consumed to maintain pumping power in gas well
= 0.032 ft3/ft3 recovered.
b. NOX emission factor^'1' » 7.3 x 10"3 lb/ft3 consumed.
c. Heating value of natural gas (assumed) = 1000 Btu/ft .
(2) a. Natural gas loss in gas well operation (A"15) = 0.0022 ft3/ft3
recovered.
b. Density of natural gas = 0.045 lb/ft3.
(3) a. Hydrocarbon recovered (liquid phase) (A-15) = 0.047 ft3 (equi-
valent gas volume) /ft3 recovered.
b. The hydrocarbon is assumed as heptane (Molecular weight = 96).
(A- 17
(4) a. Total number of fatal injuries in oil and gas production '
A-19) _ 95<
b. Total energy from oil and gas production^"17 » A"**8) =
43 x 10*5 Btu.
(5) a. Total number of nonfatal injury in oil and gas production in
1969
x 10 man-days.
(7) a. Land requirement for gas well is assumed to be the same as
that for oil well.
b. Land use for oil well (see Table A-5) = 0.06 acre-hour/10
Btu
(8) a. Efficient (assumed) = 967..
102
-------
TABLE 35. , ENVIRONMENTAL DATA FOR MODULE
Module - Removal of Sulfur from Natural Gas
Unit - 106 Btu (output)
Environmental Parameters
Fuel Input,
Natural Gas
Air
NOX, ib -;•;•
S0«, lb
CO, lb
Particulate, lb
Total organic material, lb
Heat, 10° Btu
Water
Suspended solids, lb
Dissolved solids, lb
Total organic material, lb
Heat, 106 Btu
Acid (H2S04), lb
Solid
Slag, lb
Ash, lb
Sludge, .lb
Tailings, lb
Hazardous, lb
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/10^ Btu
Approx. Module Efficiency
Nil
0.025
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
0
Nil
Nil
Nil
Nil
Nil
(I)
0.24<2>
Not determined
Not determined
Not determined
Not determined
0.005
(3)
103
-------
Footnotes for Table 35:
(1) a. Table K-2 (in Reference A-26) gives the following 1970 data from
6 states:
S02 in Claus plants tail gas at 90% eff. = 441 T/D
802 PurSed from plants not recovering sulfur = 2,335 T/D
Total gas production = 26.76 x 109 ft3/d.
b. Assume 957. efficiency for Claus plants applied to all sour
gas treatment plants, then:
(441/0.1 + 2335) ton S0?/day x .05 x 2000 Ib/ton _ n n?l. Ib SO,
26.76 x 109 ft3/day x HP Btu/ft^"'"" "lO^ltu
(2) a. at 957. efficiency for the Claus plants, the amount of 802
converted to sulfur is 19 times the amount of S02 emitted.
Therefore, the amount of by-product sulfur produced is:
.025 Ib S02 emitted x 19 x ^ [* S^ = 0.24 Ib S
(3) a. Land requirement for a 100 million ft^/day plant (assumed)
*» 20 acres.
(4) a. Energy requirements for desulfurization process were not
determined. *.
104
-------
Table 36. ENVIRONMENTAL DATA FOR MODULE
Module -- Gas Pipeline
Unit -- 106 Btu
Environmental Parameter s
Fuel Input,
Natural Gas
Air
, lb w
S02, lb
C07 lb
Particulate, lb
Total organic material, lb
Heat, IQo Btu
0.304
0
0
0
0
0
(1)
Suspended solids, lb
Dissolved solids, lb
Total organic material, lb
Heat, 106 Btu
Acid (H2S04), lb
*
Solid
Slag, lb
Ash, lb.
Sludge, lb
Tailings, lb
Hazardous, lb
By-Products
.Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use. acre-hr/lO^ Btu
Appro::. Module Efficiency
0
0
0
0
0
0
0
0
0
0
Not determined
Not determined
Not determined
1.0
(2)
95.9%
(3)
105
-------
Footnotes for Table 36:
(1) a. Natural gas consumed to maintain a compressor at 750 psia^
• 0.042 ft /ft3 transmitted. (A-l) 6
b. NOX emission factor for running gas engines^ = 7300 lb/10
ft3 burned.
(2) a. Land requirement for pipelines to run a 1000 MW Power Plant
-12) = acres<
(3) a. Efficiency (assumed) = 95.9%.
106
-------
TABLE 37. ENVIRONMENTAL IMPACTS OF MODULE
Module--> Space Heating^
Unit—10° Btu (Input)
Air
Solid
« , -, T
Environmental Impacts Q
N0x, Ib 0.081
S02, Ib 0.001
CO, Ib 0.015
Particulate, Ib 0.005
Total organic material, Ib 0.004
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib % 0
Ash, Ib 0
Sludge, Ib 0
Approx. Module Efficiency 70%
107
-------
Footnotes for Table 37:
(1) a. Values taken from Table A-46 in reference (A-26) were corrected
to input basis.
108
-------
TABLE 38. ENVIRONMENTAL DATA FOR MODULE
Module -- Oil/Gas Well, Onshore
Unit -- 106 Btu (output)
Fuel Input,
Environmental Parameters Crude Oil
Air
_6
-------
Footnotes for Table 38:
(1) a. Amount of oil that becomes air pollutants per barrel of oil
produced (assumed) = 2 x 10"^ barrels.
b. Heating value of oil (assumed) = 6.3 x 106 Btu/bbl.
c. NOX emission factor^"1) » 60 lb/103 gal.
d. Oil is assumed to be the same as industrial residual oil.
(2) a. S02 emission factor^"1^ = 157S lb/103 gal.
b. Sulfur content of oil, S (assumed) - 2.887».
(3) a. CO emission factor^"1^ = 0.2 lb/103 gal.
(4) a. Particulate emission factor^"1^ » 23 lb/103 gal.
(5) a. Hydrocarbon emission factor^ ' = 3 lb/103 gal.
(6) a. Dissolved solid emission comes from saltwater brine.
b. Total brine production^'16) = 25 million bb Is/day.
c. Total on shore oil production rate^A"17^ = 3.3 x 109 bbls/year.
d. 47. of brine goes to streams (assumed).
e. There are 100 Ib of dissolved solids per barrel of oil (assumed).
(7) a. The brine is cleaned to remove all but 50 ppm oil (assumed).
(8) a. Total number of fatal injury in oil and gas production in
1969' '* A"!'/ = 95
(A-17 A-18)
b. Total energy from oil and gas production * = 43 x
(9) a. Total number of nonfatal injury in oil and gas production in
1969^A"17»A"19^ = 9C22.
(10) a. Total man-days lost(A"17>A"19) = 1.49 x 106 man-days.
(11) a. Land requirement for an oil well producing 6200 barrels of oil
per year (assumed) = 1/4 acres.
(12) a. Efficiency of operation (assumed) = 100%.
110
-------
TABLE 39. ENVIRONMENTAL DATA FOR MODULE
Module -- Oil Pipeline
Unit -- 106 Btu (output)
Environmental Parameters
Fuel Input,
Crude Oil
Air
NOX, Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04>, Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.009*^
0.016U' .
2 x 10-5<3)
0.002<4)
0.009<6>
0
0
0
0
0
0
0
0
0
0
9 x 10
8 X 1
1.5 x
-10
(7)
0.3
99.1
(10)
(11)
111
-------
Footnotes for Table 39:
(1) a. Fraction of crude oil transported by pipeline^ - =
77.4%. (A-20} 9
b. Total crude oil transported in 1970 v ' = 1.58 x 10
barrels. (A-21)
c. Fraction of crude oil transported by diesel powered pumpv '
c 16.37. of crude oil transported by pipeline. (A-22)
d. Crude oil consumed to supply power for pumping^ =
1.45 x 108 gal/year.
e. NOX emission factor^'1' = 80 lb/10J gal burned.
f. Heating value of crude oil (assumed) = 6.3 x 10° Btu/bbl.
(2) a. S02 emission factor^"1) = 142 lb/103 gal burned.
(3) a.. CO emission factor*A-1^ - 0.2 lb/103 gal burned.
(4) a. Farticulate emission factor* ' = 16 lb/103 gal burned.
(5) a. Hydrocarbon emission factor =3 lb/10 gal burned.
(6) a. Assumed efficiency of oil pipeline = 99.1%.
- ;$fr^ •
(7) a. Death rate in oil transportation by pipeline (assumed) =
0.08 deaths/106 man-hours.
b. Man-hours required to transport the amount of oil for running
a 1000 MW Power Plant (assumed) = 7 x 10^ man-hours.
(8) a. Injury rate in oil transportation by pipeline (assumed) =
7.22 injuries/106 man-hours.
(9) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 125 days/injury.
(10) a. Land usage for pipeline =65 acres/year.
b. Period of land use (assumed) = 35 years.
(11) a. Efficiency of pipeline operation (assumed) = 99.1%.
112
-------
TABLE 40. ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Refinery, Domestic Crude
Unit - 106 Btu (output)
Environmental Parameters
Air
NOX, lb
S02, lb
CO, lb
Particulate, lb
Total organic material, lb
Heat, 10° Btu
Water
Suspended solids, lb
Dissolved solids, lb
Total organic material, lb
Heat, IQo Btu
Acid (H2S04), lb
»
Solid
Slag, lb
Ash, lb
Sludge (dry weight), lb
Tailings, lb
Hazardous, lb
By-Products, lb
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
Fuel Input,
Domestic Crude(0.76%
0.023
*2*
0.002(5}
0.025<6>
0.10(7)
0.004
(8)
0.001<10>
Negligible after cooling tower
0.0004(ll)
0
0.00?(12>
0
0
0.24<«>
1.3 x 10
9.6 x
2.3 x
-*<4>
0.008(17>
90X(18)
113
-------
Footnotes for Table 40:
(1) a. Sulfur content of input crude taken as 0.76%
(A-24)
(2) a. Average refinery energy consumptionv ' = 70,400 Btu/bbl crude
oil processed.
b. Assume all energy supplied by combustion of crude or refinery products
c. Heating value of crude oil (assumed) = 6.3 x 10° Btu/bbl.
d. NOX emission from combustion operations (A-26) = 130 lb/10 bbl
crude oil processed.
(3) a. Assume 0.75% S residual burned as refinery fuel.
b. S02 emission (A-26) = 695 lb/103 bbl crude oil processed
c. 95% removal, no Glaus plant tail gas treatment.
(4) a. CO emission from catalytic cracking catalyst regenerator (A-26) =
15 lb/103 bbl crude oil processed.
3
(5) a. Particulate emission from catalytic cracking (A-26) = 12 lb/10 bbl
crude oil processed (after controlled by cyclones).
3
(6) a. Hydrocarbon emission (A-26) = 140 lb/10 bbl crude oil processed.
(A-24)
(7) a. Refinery energy consumptionv ' = 704,000 Btu/bbl of crude oil
processed. g
b. Heating value of crude oil (assumed) = 6.3 x 10 Btu/bbl.
3
(8) a. Suspended solids emission (assumed) = 20 lb/10 bbl processed.
3
(9) a. Dissolved solids emission (assumed) = 500 lb/10 bbl processed.
3
(10) a. Total organic material emission (assumed) = 8 lb/10 bbl processed.
3
(11) a. Phenol emission (assumed) = 2 lb/10 bbl processed.
CA-25) 3 3
(12) a. Average sludge production ratev ' =_0.08 yd /10 bbl processed.
b. Density of sludge (assumed) = 60 Ib/ft .
c. Solid content of sludge (assumed) = 30%.
(13) a. Assume an average of 0.2% sulfur in the products.
b. Density of crude oil (assumed) = 7.29 Ib/gal.
(14) a. Deaths attributed to the operation of a refinery supplying fuel to
a 1000 MW power plant(A~12) =0.09 deaths.
(15) a. Injuries attributed to the operation of a refinery supplying fuel
to a 1000 MW power plant (A~12) = 6.4 injuries.
(16) a. Total work days lost attributed to the. operation of a refinery
supplying fuel to a 1000 MW power plant(A~12) = 1,530 man-days.
(17) a. Minimum land requirement for refinery processing units (assumed) =
2 acres/1000 bbl/day.
(18) a. Energy required to operate plant^ ' = 704,000 Btu/bbl crude
oil processed.
114
-------
TABLE 41. ENVIRONMENTAL IMPACTS OF MODULE
Module— Space Heating^
Unit—106 Btu (Input)
. Dlst.
Environmental Impacts oil
Air
NOX, lb 0.135
S02, lb 0.263
CO, lb 0.030
Particulate, lb 0.017
Total organic material, lb 0.004
Water
Suspended solids, lb 0
Dissolved solids, lb 0
Total organic material, lb 0
Solid
Ash, lb 0
Sludge, lb 0
Approx. Module Efficiency 70%
115
-------
Footnotes for Table 41:
(1) a. Values taken from Table A-46 In reference (A-26) were corrected
to Input basis.
116
-------
TABLE 42. ENVIRONMENTAL DATA FOR MODULE
Module - Crude Oil Gasification
Unit - 106 Btu (output)
Environmental Parameters
Fuel Input,
Crude Oil
NOX, Ib
S02, Ib
COT Ib
Particulate, Ib
Total organic material, Ib
Heat, 100
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10^ Btu
Acid (H2S04>, Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By -Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.08
U)
0.03-0.05(2)
Negligible
0.002(3)
0.004(4)
0.3(5)
0.02(6)
Negligible
Negligible after cooling tower
0.06-0.12('7)
0.06-0.
Not determined
Not determined
Not determined
0.03-0.05
(10)
117
-------
Footnotes for Table 42:
(I) a. Plant efficiency of crude oil SNG plant (assumed) - 777..
b. 23% of Input Is consumed as liquid fuel for plant operation
(assumed).
c. NOX emission factor**"1' - 40 lb/103 gal.
d. Heating value of Input crude - 6.3 x 10° Btu/barrel (assumed),
(2) a. Sulfur content of crude oil (assumed) • 2 to 4%.
b. Sulfur removal efficiency of Glaus plant and tall gas
treatment (assumed) = 99%.
c. Density of crude oil - 7.3 Ib/gal.
(3) a. Particulate emission factor for fluid catalytic cracking
unlt - 61 lb/103 bbl fresh feed.
b. Fraction of fresh feed to be cracked in this process (assumed)
- 1/3.
c. Particulate removal efficiency of cyclone (assumed) » 50%.
(4) a. Losses of crude oil to atmosphere (assumed) • 20 lb/103 bbl
input.
4*
(5) a. 23% of input fuel is consumed for plant operation (assumed).
3
(6) a. Salt content of crude oil (assumed) • 100 lb/10 bbl.
(7) a. Solid waste from spent catalyst not worth reclaiming (assumed)
• 300 to 600 lb/103 bbl.
(8) a. Sludges from water treatment (assumed) « 300 to 600 lb/103 bbl.
(9) a. By-product is sulfur. Quantity derived from assumed sulfur
content of input crude (2 to 4%) and 99% recovery in Glaus unit
and tail-gas treatment.
(10) a. Land required for a 100,000 bbl/day plant (assumed) •
600 to 1000 acres.
(11) a. Efficiency of plant (assumed) - 77%.
118
-------
TABLE 43. ENVIRONMENTAL DATA FOR MODULE
Module - Strip-mined coal, West
Unit - 106 Btu (output)
Environmental Parameters
With Land Restoration and
Treatment of Acid Drainage(i)
Air
NOX, Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10°
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10° Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.00008 (Bulldozer operation^2)
Negligible
Negligible
0.07(3)
Negligible
Negligible
Not determined
Negligible
Negligible
Nil
0
0
0
0
0
None
6.5 x 1C ...
3.1 x 10-7J6)
9.6 x 10-5(7)
0.16<8>
99.8%
119
-------
Footnotes for Table 43:
(1) a. Impacts will be negligible after land restorations. Stated
impacts will occur during the actual operation.
(2) a. NOX comes from a disel powered bulldozer used for reclamation.
b. Time requirement for reclamation (assumed = 4 hr/acre.
c. Bulldozer engine power (assumed) - 150 hp.
d. Fuel consumption rate(A~l) = 0.5 Ib/hp - hr.
e. NOX emission factor(A~*) =0.37 Ib/gal fuel used.
f. Average thickness of coal seam (assumed = 5 ft.
g. Coal bulk density (assumed) = 82 lb/ft3.
h. Heating value of western coal (assumed) = 9235 Btu/lb.
(3) a. Emission factor (given for suspended particulate from primary
rock crushing and for mining of copper ore) c 0.1 Ib/ton of
overburden.
b. Average overburden per ton of coal = 13 tons.
(4) a. Rate of silt run-off (assumed) = 5000 tons /mi* -year.
b. Average thickness of coal seam (assumed) = 5 ft.
c. Coal bulk density (assumed) = 82 lb/ft3.
d. Reclamation period (private communication, EPA) s 3 years.
(5) a. Death rate for strip coal mining(A"12) = 0.12/10$ ton coal.
b. Heating value of coal (assumed) = 18.47 x 10$ Btu/ton of coal.
(6) a. Injury rate for strip coal mining(A~12) - 5.65 injuries/106
ton coal.
(7) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 182.6 days/injury.
(8) a. Land required for 106 tons of coal(A~*2) = 112 acres.
b. Time requirement for reclamation (assumed) = 3 years.
(9) a. Efficiency of strip mine operation (assumed) = 99.8%.
120
-------
TABLE 44.
ENVIRONMENTAL DATA FOR MODULE
Module - Railroad Transportation of Coal
Unit - 106 Btu (output) '
Environmental Parameters
Fuel Input, Coal
NO , Ib
S02, Ib
co; ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 100 Btu
Acid (H2S04), Ib ^
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/10° Btu
Approx. Module Efficiency
0.02C1)
0.0014(2)
0.015(3)
0.0015(4)
Negligible
0.0039(5)
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
Negligible
0.083(6)
Negligible
Negligible
3.2 x 1
3.2 x 10-7(8)
2.2 x 10-^(9)
0.29(1Q)
121
-------
Footnotes for Table 44;
(1) a. Total quantity of. coal transported (A ~ 7) = 695 x 106 tons/year.
b. Total shipment from rail and barge(A~8) = 8.13%.
c. Total shipment from rail (assumed) = 7.1370.
d. NOX emission per 106 hp-hr (A-9) = 15.43 tons/106 hp-hr.
e. Assume a 3,000 horsepower required for each 2,000 tons of gross
load in a locomotive- train system.
f . Average horsepower of the locomotive-train system(A~10' = 74.9%
of the maximum horsepower.
g. Ratio of average gross tonnate to average net tonnage (A-10) =
2.3481.
(2) a. S02 emission per 106 hp-hr
-------
TABLE 45. ENVIRONMENTAL IMPACTS OF MODULE
Module---Space Heating
Unit—ID0 Btu (Input)
Environmental Impacts Coal (1%)
Air
N0x, ib 0.117
S02, Ib 1.47(2)
CO, Ib 3.49
Particulate, Ib 0.775
Total organic material, Ib 0.775
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib 0
Solid
Ash, Ib 6.9(3)
Sludge, Ib 0
Approx. Module Efficiency
123
-------
Foot no tea for Table AS:
(1) a, Valuea taken from Table A-A6 in reference (A-26) were corrected
to Input bftala.
(2) «. Sulfur content of coal la aaaumed to be IX.
(3) ft. Aah content of coal le aeauned to be 10X.
b. Heating value of coal * 13,000 Btu/lb coal.
c. Aah emlaalon aa partlculate • 0.78 lb/10 Btu.
-------
TABLE 46, ENVIRONMENTAL DATA FOR MODULB
Gasifica
Unit: • 100 atu (output)
Modulo - HygOi (Gasification of Coal-High Btu)
100 a
Environmental Parametera
Fuel Input. Goal. Beat
AiX
NOX, Ib
80J, Ib
Oof Ib
Paniculate, Ib
Total organic material, Ib
Heat, 100 Btu
Suspended aolida, Ib
Dieaolvod aollda, Ib
Total organic material, Ib
Heat, 100
Phono U, Ib
, Ib
Aeh, Ib
Shidgo, Ib
Haiardous, Ib
Qccunnt -al
Deathi
Total Injurioa
Nan Dnyi Lost
Land Upo. nore-hr/10^ Dtu
4
Approx.
0,23(1)
0,55(2)
0,34(5)
0
0
Negligible
Negligible after 090ling tower
g f • A «•' ' *
A,6 x 10*
25,8(8)
0
0
5 x
1.7 x 10- 10
4,6 x 1
0.02(12)
-------
Footnotes for Table 46:
(1) a. NOX emission comes from a 110 MW power plant in the Hygas
plant.
b. NOX emission factor (assumed) =0.72 lb/10^ Btu generated by
the power plant.
c. Hygas plant capacity(A~6) = 80 x 106 scfd.
d. Heating value of gas produced^"6) - 950 Btu/ft3.
(2) a. S02 emission comes from two limestone scrubbers.
b. Sulfur from limestone scrubber s(A"6) = 1300 Ib/hr.
c. Sulfur content of coal used in this calculation (assumed) =3%.
d. Adjustment factor for sulfur content^"**) = 0.68.
(3) a. Ash content of coal used in this calculation (assumed) = 14.4%.
b. Adjustment factor for ash content (A~6) = 1.31.
c. 65% of total ash goes to scrubber as particulate (assumed).
d. Limestone scrubber efficiency for removal of particulate
(assumed) = 99%.
(4) a. Hydrocarbon emission comes from a 110 MW power plant.
b. Hydrocarbon emission factor (assumed) = 0.04 lb/10^ Btu.
(5) a. Efficiency of Hygas plant ^A"6^ = 66%.
(6) a. Assumed to be same as for C02 acceptor (see C02 Acceptor for
the detail).
(7) a. Ash comes from boiler (bottom ash).
(8) a. Sulfur from limestone scrubber s^A"6^ = 7600 Ib/hr.
b. Sulfur content of sludge = 12%.
c. Adjustment factor for sulfur content in fuel'A~°) = 0.68.
d. Sludge. comes from limestone scrubbers (limestone slurry plus
particulate collected).
(9) a. Elemental sulfur from Claus plant is the sole by-product
(assumed).
b. Adjustment factor for sulfur content in coal = 0.68.
(10) a. Man-hours required for a IxlO^O Btu/hr capacity Hygas plant
(assumed) = 4000 man hours /day.
b. Injury rate (assumed) - 10 injuries/10" man hours.
c. 3% of injury assumed fatal.
(11) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 95 days/injury.
(12) a. Personal communication with EPA.
(13) a. Reported by Processes Research. 'A'
126
-------
TABLE 47. ENVIRONMENTAL DATA FOR MODULE
Module -- Conventional Boiler
Unit -- 10 Btu (input)
Environmental Parameters
Fuel Input,
Natural Gas
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
0.39(1)
0.0006)
0.0003'
0.015
4)
^
0.04 5)
0.63<6)
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04>, Ib
*
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/10** Btu
Approx. Module Efficiency
0.016<7>
0
0
Negligible after cooling tower
0
0
0
0
0
0
1.5 x 10
8.9 x "
2.9 x 10
-6dO)
0.02
(11)
37%
(12)
127
-------
Footnotes for Table 47:
(1) a. NOX emission f actor ^"^ * 39 lb/106 ft3 of natural gas.
b. Heating value of natural gas (assumed) - 1000 Btu/ft3.
(2) a. S02 emission factor for burning natural gas = 0.6 lb/10"
ft3.
(3) a. CO emission factor for burning natural gas = 0.4 lb/10&
ft3.
X.
(4) a. Particulate emission factor for burning natural gas = 15 lb/
106 ft3.
(5) a.. Hydrocarbon emission factor for burning natural gas = 40 lb/
106 ft3.
(6) a. Efficiency of gas fired conventional boiler = 37%.
(7) a. Suspended solid emission from a 1000 MW gas fired Power Plant
(A-12) = 548 tons.
(8) a. Deaths attributed to a 1000 MW gas fired Power Plant* '
- 0.01 death/year.
(9) a. Injuries attributed to a 1000 MW gas fired Power Plant' '
=0.6 injuries/year.
(10) a. Man-days lost attributed to a 1000 MW gas fired Power
Plant(A"12' = 197 man-days/year.
(11) a. Land requirement for a 1000 MW gas firad Power Plant' " *
- 150 acres.
(12) a. Efficiency of gas fired Power Plant (assumed) - 37%.
128
-------
TABLE 48. , ENVIRONMENTAL IMPACTS OF MODULE
Module—Conventional Boiler
Unit—106 Btu (Input)
Environmental Impacts
Diet. Fuel Oil (0.3% S)
Air
, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
0.336(2)
0.0003(3)
0.057(4)
0.014(5)
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
0
0
0
Solid
Ash, Ib
Sludge, Ib
0
0
Approx. Module Efficiency
37%
(6)
129
-------
Footnotes for Table 48:
(1) a. Heating value of distillate fuel oil^"1^ - 140,000 Btu/gal.
b. NO emission factor^""1^ - 105 lb/1000 gal.
(2) a. Sulfur content of distillate fuel oil, S (assumed) - 0.3%.
b. S02 emission factor*A~X) - 157 S lb/1000 gal.
(3) a. CO emission factor^A~1* » 0.04 lb/1000 gal.
(A-l}
(4) a. Particulate emission factorv ' - 8 lb/1000 gal.
(A-l)
(5) a. Hydrocarbon emission factor « 2 lb/1000 gal.
(6) a. Plant efficiency was assumed to be 37%.
130
-------
TABLE 49. ENVIRONMENTAL DATA FOR MODULE
Module -- Oil Barge
Untt -- 10^ Btu (Output)
Environmental Parameters
Fuel Input,
Residual Oil
NOX, Ib
S02, Ib
CO, Ib
Farticulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 109 Btu
Acid (H2S04), Ib
•
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use. acre-hr/106 Btu
Approx. Module Efficiency
0.0014(2)
0.001l(3)
0.0008(5>
0.004(6)
nil
nll
0.015
nil
nil
m
U'
nil
nil
nil
nil
nil
nil
9 * 10 fa\
8 x 10"8<9>
1.5 x 10-
99.6%<12>
131
-------
Footnotes for Table 49:
(1) a. Assume 20,000 tons per shipment. .
b. NOX emission factor for motor ship* ' » 1.4 Ib/mi.
c. Trip distance per shipment (assumed) - 325 miles.
(2) a, S02 emission factor for motor ship^"1^ = 1.5 Ib/mi for 0.57.
sulfur content for fuel.
(A-l)
(3) a. CO emission factor for motor shipv =1.2 Ib/mi.
(A-l)
(4) a. Particulate emission factor for motor shipv = 2Ib/mi.
(A-l)
(5) a. Hydrocarbon emission factor for motor ship =0.9 Ib/mi.
(6) a. Total heat required per 10° Btu transported (assumed) =
3800 Btu.
(7) a. Total oil discharge in oil transport and in tank cleaning
operations(A"^2) = o.277o of shipment.
(8) a. Death rate in oil transportation by barge ~ (assume that
barge operation is similar to tanker operation) = 0.08 deaths/
10 man-hours.
b. Man-hour required to transport.the amount of crude oil to
operate a 1000 MW Power Plant* * ' = 7 x 10^ man-hours.
(9) a. Injury rate in oil transportation by barge^ " (assume that
barge operation is similar to tanker operation) =7.22 injuries/
10^ man-hours.
(10) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 125 days/injury.
(11) a. Land requirement for port facilities not estimated.
(12) a. Energy consumption rate per 10" Btu of crude oil transported
(assumed) = 3800 Btu.
132
-------
TABLE 50. ENVIRONMENTAL IMPACTS OF MODULE
Module--Conventional Boiler
Unit—10 Btu (Input)
Environmental Impacts
Solid
Air
N0x, Ib ,7
s<>2' lb 1.04
CO, lb 0
Particulate, lb 0.05
Total organic material, lb 0.01
Water
Suspended solids, lb 0
Dissolved solids, lb 0
Total organic material, lb 0
Ash, lb 0
Sludge, lb 0
Approx. Module Efficiency 37%
133
-------
Footnotes for Table 50:
(1) a. Values were taken from Table A-43 in reference (A-26). SO.
emission was corrected to 1% sulfur resid.
134
-------
TABLE 51. . ENVIRONMENTAL DATA FOR MODULE
Module - - Oil Tanker
Unit -- 106 Btu (Output)
Environmental Parameters
Fuel Input,
Crude Oil
Aix
NOX, Ib
S02> Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 100 Btu
Acid (H2S04>, Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.0015
^
.
0.0021(4>
9 x 1-5<5>
0
0
0.015
0
0
0
0
0
0
0
(7)
9 x 10
8x1
1.5 x
-10
99.5(12>
135
-------
Footnotes for Table 51:
(1) a. NOX emission by oil tanker to transport crude oil for a
1000 MW Power Plant
-------
TABLE 52. . ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler (Coal)
Unit - 106 Btu (Input)
Environmental Parameters
Fuel Input, Coal, West
Ail
KOX, Ib
S02> Ib
COT Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04), Ib
*
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Apptox. Module Efficiency
0.98(D
1.65(2)
0.054(3)
0.016(5)
0.63(6)
0.011(8)
Negligible after cooling tower
0
0
9.0(9)
0
0
0
3.3 x 10-lOdO)
1.4 x 10-8(10)
5.1 x 10-6(11)
37%
<13>
137
-------
Footnotes for Table 52J
(1) a. NOX emission factorC^-l) = 13 lb/ton coal burned.
b. Heating value of western coal (assumed) 9200 Btu/lb.
(2) a. S02 emission factor^"1) = 38 S lb/ton coal burned.
b. Sulfur content, S (assumed) = 0.8%.
(3) a. CO emission factorVA~*) = 1 lb/ton coal burned.
(4) a. Particulate emission factor^'*' = 16A lb/ton coal burned.
b. Ash content, A (assumed) = 8.4%.
c. Electrostatic precipitator efficiency (assumed ) - 99%.
(5) a. Hydrocarbons emission factor'^"*' e 0.3 lb/ton coal burned.
(6) a. Efficiency of conventional boiler (assumed) - 37%.
(7) a. Total solid to water(A~12) » 0.036 lb/106 Btu.
b. Fraction of suspended solid (assumed) = 70%.
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of coal (assumed) = 8.4%.
(10) a. Man-hour required per 10^ Btu for conventional power plant
" = 2.4 x 10~3 man hour.
b. Total injuries per 106 man-hour(A~13) =5.7.
c. Death rate(A~12' = 2.4% of injuries.
(11) a. Days lost per death (assumed) = 6000 days/death.
b. Days lost per injury (assumed) = 229 days/death.
(12) a. Land required for a 1000 MW power plant (assumed) = 800 acres.
'(13) a. Efficiency of conventional boiler (assumed) = 37%.
138
-------
TABLE 53. . ENVIRONMENTAL DATA FOR MODULE
Module-- Physical Cleaning of Coal
Unit—10° Btu (output)
Environmental Parameters
With
Environmental
Control
Air
N0x, Ib
so2,
Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
0.006
0.004
(1)
(2)
1.01
(3)
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Acid (H2S04), Ib
Negligible
Negligible
Negligible
Negligible
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
0
0
Negligible
Approx. Module Efficiency
88%
(5)
139
-------
Footnote* for Table 53:
(1) a. NO from thermal dryer. Operating charactariatice for evaporating
water from wat coal(A-2) - 550 tona of coal produced per 50 tone of
water evaporated.
b. Heat required for water evaporation • 1000 Btu/lb water.
c. Heating value of coal - 12,000 Btu/lb of coal.
d. NO emlealon factor^^' • 18 Ib/ton of coal burner.
e. No control equipment.
/4«.1\
(2) a. SO emlealon factorv ' - 38 8 Ib/ton coal burned.
b. Sulfur content of coal, 8 (aaaumed) » 3%.
c. Lime ecrubber control efficiency (aeeumed) • 90%.
(3) a. Partlculate emleelon factor for thermal dryer - 25 Ib/ton
coal product.
b. Heating value of coal product - 13,180 Btu/lb.
c. Control efficiency of multiple cyclonee with wet ecrubber
99.0% removal.
(4) a. Sludge cornea from 80. and H.80. control (aaeumed).
b. Sulfur content of §lodge (aieumed) • 12%.
(5) a. The efficiency la aaeumed to be 88%.
140
-------
TABLE 54. ENVIRONMENTAL DATA FOR MODULE
•
Module - CAFB Boiler (Residual Oil) + Combined Cycle
Unit - 10* Btu (Input)
Environmental Parameters
Fuel Input,
Residual Oil (Imported)
Air
NOX, Ib
80,» Ib
COT Ib
Partlculate, Ib
Total organic material, Ib
Heat, 100 Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 100 Btu
Acid 0*2804), Ib
Solid
81ag, Ib
Ash, Ib
Sludge, Ib
Talllngt, Ib
Hazardous, Ib
By -Products
Occupational
Deaths
Total Injuries
Man Days Lost
Lnnd Use, ncrc-hr/106 Btu
Ap_prox_._ Modulo Efficiency
.
0.45(2>
0.62<3)
0
0
0
Negligible after cooling tower
0
3.0<6)
0
0
0
2 x 10-J(8)
7 x 10-8(8)
1.7 x 10-3(9)
141
-------
Footnotes for Table 54:
(1) a. Experimental data obtained by Westinghouse.
(2) a. S02 from boiler(A'23> =0.35 lb/106 Btu.
b. S02 from Claus unit
-------
TABLE 55. ENVIRONMENTAL IMPACTS OF MODULE
Module—fiConv. Boiler with limestone scrubber
Unit—10 Btu (Input)
Environmental Impacts Resid (3.5% S)
Air
NO , Ib
X*
so2, ib
CO, Ib
Particulate, Ib
0
0
0
.7
o\
.366u;
0
.0005(3)
Total organic material, Ib 0.01
Water
Suspended solids, Ib Q
Dissolved solids, Ib 0
Total organic material, Ib 0
Solid
Ash, Ib 0
Sludge, Ib 13.8(4)
Approx. Module Efficiency 37«
143
-------
Footnotes for Table 55:
(1) a. Values were taken from Table A-42 in reference (A-26) except
as modified below.
(2) a. Sulfur content of resid (assumed) « 3.5%.
b. SO. emission was considered twice that given in Table A-42
in reference (A-26).
c. SO. removal efficiency of lime scrubber (assumed) • 90%.
(A-l}
(3) a. Participate emission factor ' - 8 lbs/1000 gal.
b. Farticulate removal efficiency (assumed) * 99%.
(4) a. S02 in sludge [from Footnote (2)] - 3.29 lb/106 Btu.
b. Generally sulfur in lime scrubber sludge is assumed as 12%
by weight.
144
-------
TABLE 56. ENVIRONMENTAL IMPACTS OF MODULE
Module—,Conventional Boiler - No Control
Unit—10 Btu (Input)
Environmental Impacts Resid (3.5% S)
Air
NO , Ib 0.7
x (2)
S02, Ib 3.66
CO, Ib 0
Particulate, Ib 0.05
Total organic material, Ib 0.01
Water
Suspended solids, Ib 0
Dissolved solids, Ib 0
Total organic material, Ib 0
Solid
Ash, Ib
Sludge, Ib
Approx. Module Efficiency 37%
145
-------
Footnotes from Table 56:
(1) a. Emission values were taken from Table A-42 in reference (A-26)
except as described below.
(2) a. In this module sulfur content of resid was assumed as 3.5%.
b. Thus SO. emission was considered to be twice that given in
Table A-42 In reference (A-26).
146
-------
TABLE 57.
ENVIRONMENTAL DATA FOR MODULE
Module - Fluid-Bed Combustion Plus Combined Cycle
Unit - 106 Btu (input to combustion cycle)
Environmental Parameters
Fuel Input, Coal, East
Ail
NOX, Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 100 Btu
Acid (H2S04), Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.14
0.7(2)
0
0.02(3)
0.62(4)
0
0
0
Negligible after cooling tower
0
0
17.3
0
0
0
1.9
(5)
(6)
1.5 x 10-9<7>
3.6 x 10-8(8)
1.4 x 10-5(9)
0.12(10)
38%(H)
147
-------
Footnotes for Table 57:
(1) a. Average value of 0.07 and 0.22 lb/106 Btu reported in
Westinghouse Report.(A-23)
(2) a. S02 emission factor reported(A"23) = 1 lb/106 Btu. « Q
b. Adjustment factor for sulfur content(A~23' =0.7 (i.e.jT^r).
"fr • J
(3) a. Particulate emission factor reported^"23) =0.02 lb/106 Btu.
(4) a. Efficiency of the module (assumed) = 38%.
(5) a. Ash content of eastern coal (assumed) = 14.4%.
b. Heating value of coal (assumed) = 24 x 106 Btu/ton.
c. Limestone requirement per pound of sulfur =1.75 Ib.
(6) a. The sole by-product is elemental sulfur.
b. Sulfur content of coal (assumed) = 3%.
c. 90% of sulfur is collected by limestone (assumed).
d. Sulfur loss from Claus unit(A~23) = 0.35 lb/106 Btu.
(7) a. Injuries calculated from fluid-bed combustion plant and gas-
fired power plant operations.
b. 40 men operate a 500 ton coal/hr capacity combustion plant
(assumed).
c. Using chemical industry data for gasification plant, injuries
per man hour(A~5) =8.1 injuries/106 man hours.
d. Death rate (assumed) - 5% of injuries.
e. Death attributed to a 100 MW gas-fired power plantvA~12) =
0.01 deaths/year.
(8) a. Injuries attributed to a 1000 MW gas fired power plant' 2' =
0.6 injuries/year.
(9) a. Using chemical industry data for gasification plant, man-days
lost per man hour(A"^' = 528 days/106 man hours.
b. Man days lost per death (assumed) - 6000 days/death.
c. Man days lost attributed to a 1000 MW gas fired power plantCA~12'
= 197 man-days/year.
(10) a. Land requirement for a 1000 MW coal fired power plant (assumed)
= 800 acres.
b. Additional land requirement for fluid-bed combustion unit
(assumed) =150 acres.
(11) a. Efficiency(A"23) = 38%.
148
-------
TABLE 58.
ENVIRONMENTAL DATA FOR MODULE
Module - Lurgi Gasifier and Conventional Boiler
Unit - 10^ Btu (input to conventional boiler)
Environmental Parameters
Fuel Input, Coal, East
Air
NO , Ib
S02, Ib
GO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 100 Btu
Phenols, Ib
*
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.40^)
0.93<2>
0
0.015(3)
0.11(4)
0.92(5)
0.016(6)
0
Negligible after cooling tower
0.0029(8)
0
9.82(9)
0
0
0
1.5 x 10-9(11)
3.6 x 10-8(12)
9.4 x 10-6d3)
25.9%<15)
149
-------
Footnotes for Table 58:
(1) a. NOX comes from gas- fired boiler In gaslflcr plant and gas-fired power plant.
b. NOX emission factor(A-l) = 0.39 lb/106 Btu for natural gas.
c. The emission factor Is value for Lurgi gas combustion on the basis of heating value
(assumed) .
(2) a. Basis: 1000 MW nominal cogas power plant. (A-6)
b. Coal Input rate(A'6) - 341 tons/hr.
c. S02 emission comes from gas-fired boiler In gaslfier plant and gas- fired power plant. (*-6)
d. 1% of sulfur lost to atmosphere from gaslfier plant by leaking (assumption).
e. Content of H2S In Lurgi gas produced (*"&) « 0.105% by volume.
£. Lurgi gas production rate from the plant » 112600 Ib-moles/hr.
(3) a. Partlculate emission cones from gas-fired power plant (assumed).
b. Emission factor for natural gas(A-l) = 0.015 lg/106 Btu.
c. Assumed that the emission factor for natural gas combustion is valid to Lurgi gas combus-
tion on the basis of heating value.
(4) a. 1% of total organic matter (COS and CH^) is lost from gasifier by leaking (assumed).
(5) a. 63% of the total input energy to gas- fired power plant is lost to atmosphere (based on the
assumed efficiency of the power plant).
b. Efficiency of Lurgi gasifier plant (assumed) - 70%.
c. Efficiency loss due to material loss in Lurgi gasifier plant (assumed) " 10%.
(6) a. Suspended solid emission comes from gas-fired power plant (assumed).
b. Emission from a 1000 MW pLant(A'12) - 548 tons.
(7) a. Total organic material comes from gas-fired power plant (assumed).
b. Emission f actor (A"lz) » 73 tons/year for a 1000 MW plant.
(8) a. From data supplied by T. K. Janes, EPA.
(9) a. Ash content of coal (assumed) - 14.4%.
(10) a. The by-product of Lurgi gasifier plant is sulfur from Claus unit.
(11) a. Injuries are combined for Lurgi gasifier plant and gas-fired power plant operations.
b. 40 men operate a 500-ton coal/hr capacity Lurgi gasifier plant (assumed).
e. Using chemical industry data, injuries per raan-hour'A~^' = 8.1 injuries/lO" man-hours.
d. Death rate (assumed) •= 5% of total injuries.
e. Death attributed to a 1000 MW gas-fired power plant(A'12) - 0.01 death/year.
(12) a. Injuries attributed to a 1000 MW gas-fired power plant**"12) «• 0.6 injuries/year.
(13) a. Using chemical industry data, days lost per man-hour(A"5) . 523 days/10° man-hours.
b. Man-days lost per death (assumed) » 6000 days/death
c. Man-days lost attributed to a 1000 MW gas-fired power plant ^A-1^ «• 197 man days/year.
(14) a. Land requirement for a 1000 MW coal-fired power plant (assumed) « 800 acres.
b. Additional land requirement for Lurgi gasifier plant (assumed) » 150 acres.
(15) a. Efficiency of Lurgi gasifier plant (assumed) - 70%.
b. Efficiency of gas- fired power plant (assumed) • 377..
150
-------
TABLE 59. ENVIRONMENTAL IMPACTS OF MODULE
Module-- Conv. Boiler, Phys. Cleaned Coal
Unit—106 Btu (Input)
environmental Impacts
Phys. Cleaned Coal
Air
NOX, lb
S02, lb
CO* lb
Particulate, lb
Total organic material, lb
0.68
1>44
0.038
0.044
0.011
Water
Suspended solids, lb
Dissolved solids, lb
Total organic material, lb
0.025
0
0.011
Solid
Ash, lb
Sludge, lb
5.41
0
Approx. Module Efficiency
37%
151
-------
Footnotes for Table 59:
(1) a. Data were taken from Table A-10 in reference (A-26) except
that SO. emission were corrected to 1% sulfur in cleaned coal.
152
-------
TABLE 60. ENVIRONMENTAL DATA FOR MODULE
Module - Coal Liquefaction (solvent refining)
Unit - 106 Btu (output)
Environmental Parameters
Fuel Input, Eastern Coal
(1)
Air
NOX, Ib
SO,, Ib
COT Ib
Particulate, Ib
Total organic material, Ib
Heat,
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 100 Btu
Acid (H2S04), Ib
•
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/10° Btu
Approx. Module Efficiency
0.21(2)
0.003(3)
0.012(4>
°-27(5
6
(7)
0.067
0
0
Trace
Negligible after cooling tower
0
0
16.0(8)
0
0
0
(9)
2.95
1.4 x 10
2.7 x 10-8(10)
6.5 x 10-6(11)
0.08(12)
(1) Impacts were estimated based on the coal containing 14.4% ash, 3.0%
S and a heating value of 12,000 Btu/lb. In addition, the coal
liquefaction plant was assumed to have a capacity of 222xlO^Btu/day.
153
-------
Footnotes for Table 60: (Continued)
(2) a. Solvent refined coal (SRC) has a heating value of 16,000 Btu/lb,
0.057. ash, and 0.6% sulfur(A-6).
b. Plant efficiency(A-6) = 75%.
c. Emission factor for NOX - 18 Ib/ton of coal burned.
"d. Average heating value of consumed coal = 14,000 Btu/lb.
e. Coal consumption rate = 110 tons/hr.
(3) a. Total sulfur content in the input coal = 30,833 Ib/hr.
b. Total sulfur content in the SRC = 3.469 Ib/hr.
c. Sulfur emitted as S02 = 0.1% total sulfur off gas-liquid
separator.
(4) a. CO emission factor(A-l) = 1 Ib/ton of coal burned.
b. No control equipment.
(5) a. Particulate emission factor(A-l) = 15^ Ib/ton of coal burned.
b. Emission control efficiency (assumed) 98%.
c. Average ash content of consumed coal, A = 7.23%.
(6) a. Total organic material emission factor =0.3 Ig/ton of coal
burned.
b. No control equipment.
(7) a. Total heat released = 0.308 x 1010 Btu/hr.
(8) a. Total ash input rate = 148,000 Ib/hr.
b. Total ash output rate in SRC = 289 Ib/hr.
(9) Elemental sulfur product = 99.9% of total sulfur-off gas, liquid
separator.
(10) a. Assumption: 80 men operate a 1,000 tcu/hr capacity solvent
refining plant.
b. Use chemical industry data, injuries per man hour(A-5) =8.1
injuries/106 man hours.
c. Use chemical industry data, days lost per man hour™"*' = 528
days lost/10^ man hours.
d. Death rate = 5% of total injuries (assumed).
(11) Man days lost per death (assumed) - 6,000 days/death.
(12) Land required for a 222 x 109 Btu/day plant (assumed) = 750.acres.
(13) Plant efficiency (A-6) = 757..
154
-------
TABLE 61.
ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler
Unit - 106 Btu (input) '
Environmental Parameters
Fuel Input,
SoIvent Refined Coal (Eastern)
Ail
NO , Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, IQ
0.56(D
0.7K2)
0.037(3)
0.0003(4)
0.01(5)
0.63(°)
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, IQo Btu
Acid (H2S04), Ib
*
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0,01l(8)
Negligible after cooling tower
0
0.031(9)
0
0
0
3.3 x 10-10(10)
1.4 x 10-8(10)
5.1 x 10-6(H)
0.09
<12)
155
-------
Footnotes for Table 61:
(1) a. NOX emissions factor^ ' = 18 Ib/ton coal burned.
b. Heating value of solvent refined coal (SRC) (assumed) -
16000 Btu/lb.
(2) a. Sulfur content of solvent refined coal, S (assumed) = 0.6%.
b. S02 emission factor(A-l) = 38 S Ib/ton coal burned.
(3) a. CO emission factor(A-l) = 1 Ib/ton coal burned.
(4) a. Ash content of SRC, A (assumed) = 0.05%.
b. Particulate emission factor(A-l) = 16 A Ib/ton coal burned.
c. Electrostatic precipitator efficiency (assumed) = 99%.
(5) a. Hydrocarbon emission factor(A-l) = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler (assumed) = 37%.
(7) a. Total solid to water
-------
TABLE 62.
ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler and Limestone Scrubbing
Unit - 106 Btu (input)
Environmental Parameters
Fuel Input, Coal, East
NO , Ib
S02, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 10° Btu
Acid (H2S04), Ib •***<
Solid - ,,,'
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/lp6 Btu
Approx. Module Efficiency
0.60(D
0.50(2)
0.042(3)
0.013(5)
0.65(6)
0.025(7)
0.01l(8)
Negligible after cooling tower
0
2.4(9)
0
0
3.3 x llf l°
1.4 x 10-8(11)
5.1 x 10-6(12)
0.1(13)
157
-------
Footnotes for Table 62:
(1) a. NOX emission factor™' = 18 Ib/ton coal burned.
b. Heating value of eastern coal (assumed) = 12000 Btu/lb.
c. NOX removal efficiency by limestone scrubber (assumed) = 20%.
(2) a. Sulfur content of eastern coal, S (assumed) - 37..
b. S02 emission factor(A~l) = 38 S Ib/ton coal burned.
c. Limestone scrubber efficiency (assumed) = 90%.
(3) a. CO emission factor(A"l) = i Ib/ton coal burned.
(4) a. Ash content of eastern coal, A (assumed) = 14.4%.
b. Particulate emission factor\A-1) = 16 A Ib/ton coal burned.
c. Scrubber efficiency for particulate removal = 99%.
(5) a. Hydrocarbon emission factor(A~l) = 0.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler with limestone scrubbing
(assumed) = 35%.
(7) &. Total solid to water(A"12> « 0.036 lb/106 Btu.
b. Fraction of suspended solids (assumed) = 70%.
>•(
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of eastern coal (assumed) = 14.4%. 20% to bottom ash.
(10) a. Sulfur content of sludge (assumed) = 12%. Add fly ash collected.
(11) a. Man-hour required per 10^ Btu for conventional power plant' '
= 2.4 x 10-3 man hour/106 Btu.
b. Total injuries per 106 Man hour
-------
TABLE 63.
ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler & MgO-Scrubbing
Unit - 106 Btu (Input)
Environmental Parameters
Input: Eastern Goal
Air
NOX, Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04>, Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
Ey-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.50(2)
0.1(4)
0.013(5)
0.65(6)
0
o.on(8)
Negligible after cooling tower
0
0
2.4(9)
0
6.13(1D
3.3 x 1
1.4 x 10-8(12)
5.1 x 10-6(13)
35%d5)
159
-------
Footnotes for Table 63:
(1) a. NOX emission factor(A-l) = i$ lb/ton coal burned.
b. Heating value of eastern coal (assumed) « 12,000 Btu/lb.
c. NOX removal efficiency by MgO-scrubber (assumed) » 20%.
(2) a. Sulfur content of eastern coal, S (assumed) = 3%.
b. S0£ emission factor(A-l) = 38 S lb/ton coal burned.
c. MgO-scrubber efficiency (assumed) = 907..
(3) a. CO emission factor(A-l) = 1 lb/ton coal burned.
(4) a. Ash content of eastern coal. A (assumed) 14.4%.
b. Particulate emission factor(A-l) = 16 A lb/ton coal burned.
c. Scrubber efficiency for particulate removal = 99%.
(5) a. Hydrocarbon emission factor = 0.3 lb/ton coal burned.
(6) a. Efficiency of conventional boiler with MgO-scrubbing (assumed)
= 35%. .
(7) a. Total solid to water - 0.036 lb/10^ Btu.
b. Fraction of suspended solids (assumed) = 70%.
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of eastern coal (assumed) = 14.4%. 20% to bottom ash.
(10) a. MgO reacts with S02 to product 80% of MgS03«6H20 and 20% of
MgS04•7H20 (assumption).
b. 1% blowdown of MgS03'6H20 and MgSO^T^O (assumed).
c. Loss in regeneration (assumed) - 5%. Add fly ash collected.
(11) a. Sulfur reacted with MgO is regenerated in the form of
b. Regeneration efficiency (assumed) = 100%.
(12) a. Man-hour required per 10** Btu for conventional power plant (A-13)
= 2.4 x 10"3 man-hour/106 Btu.
b. Total injuries per 106 man hour(A-13) =5.7.
c. Death rate(A-12) = 2.4% of injuries.
(13) a. Days lost per death (assumed - 6000 days/death.
b. Days lost per injury (assumed) = 229 days/injury.
(14) a. Land requirement for a 1000 MW power plant (assumed) = 800 acres.
(15) a. Efficiency of conventional boiler with MgO-scrubbing
(assumed) = 35%.
160
-------
TABLE 64.
ENVIRONMENTAL DATA FOR MODULE
Module - Conventional Boiler.
Unit - 106 Btu (Input)
Environmental Parameters
Fuel Input. Eastern Coal
Ait
NOX, Ib
SO,, Ib
CO, Ib
Particulate, Ib
Total organic material, Ib
Heat, 10» Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, IQo Btu
Acid (H2S04), Ib
•
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By—Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acre-hr/106 Btu
Approx. Module Efficiency
0.75
0.025(7)
0
0.01l(8)
Negligible after cooling tower
0
0
12.0(9)
0
0
0
3.3 x 10-10d°)
1.4 x 10-8(10)
5.1 x 10"6(H)
377.U3)
161
-------
Footnotes for Table 64:
(1) a. NOX emission factor (A"1) » 18 Ib/ton of coal burned.
(2) a. SOo emission factor^"1) = 38 S Ib/ton of coal burned.
b. Sulfur content, S (assumed) = 3%.
(3) a. CO emission factor^"1' = 1 Ib/ton coal burned.
(4) a. Particulate emission factor^-1) = X6A Ib/ton coal burned.
b. Ash content, A (assumed) = 14.47..
c. Electrostatic precipitator efficiency (assumed) = 99%.
(5) a. Hydrocarbons emission factor^-1) = Q.3 Ib/ton coal burned.
(6) a. Efficiency of conventional boiler (assumed) = 37%.
(7) a. Total solid to water*A~12^ = 0.036 lb/106 Btu.
b. Fraction of suspended solid (assumed) = 707..
(8) a. Fraction of organic material in total solid (assumed) = 30%.
(9) a. Ash content of coal (assumed) = 14.4% . -,
(10) a. Man-hours required per 10 Btu for conventional power
= 2.4 x 10^3 man-hour/1Q6 Btu.
b. Total injuries per 106 man hour'A~13' =5.7.
V12' = 2.4% of i
;sOc
(11) a. Days lost per death (assumed) = 6000 days/death.
b. Days lost per injury (assumed) 229 days/injury.
(12) a. Land required for a 1000 MW power plant (assumed) = 800 acres.
(13) a. Efficiency of conventional boiler (assumed) = 37%.
162
-------
TABLE 65.
ENVIRONMENTAL DATA FOR MODULE
Module - Strip Mined Coal, East
Unit - 10° Btu (output) '
Environmental Parameters
With Land Restoration and
Treatment of Acid Drainage
(1)
Air
NOX, Ib
S02, Ib
CO, Ib
Farticulate, Ib
Total organic material, Ib
Heat, 10° Btu
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
Heat, 106 Btu
Acid (H2S04>, Ib
Solid
Slag, Ib
Ash, Ib
Sludge, Ib
Tailings, Ib
Hazardous, Ib
By-Products
Occupational Health
Deaths
Total Injuries
Man Days Lost
Land Use, acrc-hr/106 Btu
Approx. Module Efficiency
0.0002(2>
Negligible
Negligible
0.14(3)
Negligible
Negligible
0.55<4>
0.18
Negligible
Negligible
Nil
0
0
0.24(5)
Negligible
0
None
5 x 10
2.5 x
7.4 x 10
99.6%
-5(8)
(10)
163
-------
Footnotes for Table 65:
(1) Impacts will be negligible after land restoration. Stated impacts
will occur during the actual operation.
(2) a. NO released to atmosphere from reclamation operation was
derived based on the assumption that a diesel powered bulldozer is
used for reclamation.
b. Time requirement for reclamation (assumed) = 4 hr/acre.
c. Bulldozer engine power (assumed) - 150 hp.
d. Fuel consumption rate'^"1' = 0.5 lb/hp"nr.
e. Emission factorCA'1) = 0.37 lb N0x/gal of fuel used.
f. Average thickness of coal seam (assumed) = 2 ft.
g. Coal density (assumed) = 82 lb/ft3.
h. Heating value of coal (assumed) - 12,000 Btu/lb.
(3) a. Emission factor (same as primary rock crushing and copper
mining) =0.1 Ib/ton of overburden.
b. Average overburden per ton of coal (private communication, EPA)
= 33 tons.
(4) a. Rate of silt run-off (assumed = 5000 tons/Mi2-year.
b. Average thickness of coal seam (assumed) - 2 ft.
c. Coal bulk density (assumed) - 82 lb/ft3.
d. Reclamation period (assumed) s 3 years
(5) a. Dissolved solids (CaS04) and sludge (FeOH2) come from acid
treatment (assumed).
b. Drainage water discharge rate for a strip coal mine with a
capacity of 106 ton coal/year (assumed) = 10& gal/day.
c. Acidity of drainage water (assumed) = 1000 ppm.
(6) a. Death rate for strip coal mining(A"12) = 0.12/106 ton coal.
b. Heating-value of coal (assumed) = 24 x 106 Btu/ton coal.
<7) a. Injury rate for strip coal mining(A"12> = 5.65 injuries/106
ton coal.
(8) a. Man-days lost per death (assumed) = 6000 days/death.
b. Man-days lost per injury (assumed) = 180 days/injury.
(9) a. Land required for 106 tons of coal(A"12) » 280 acres.
b. Time required for reclamation (assumed) = 3 years.
(10) a. Efficiency of strip mine operation (assumed) = 99.6%.
b. Depletive waste not included.
164
-------
TABLE 66. ENVIRONMENTAL IMPACTS OF MODULE
Module— Coke Oven( '
Unit—106 Btu (Input)
Solid
Environmental Impacts Coal West
Air
»V lb 0.0017(2)
S02, lb 0.8<3)
CO, lb 0.053(2)
Particulate, lb 0.146^
Total organic material, lb 0.175^
Water
Suspended solids, lb
Dissolved solids, lb
Total organic material, lb
Ash, lb 0
Sludge, lb 0
Approx. Module Efficiency 70%
165
-------
Footnotes for Table 66:
(1) a. Low sulfur coal (0.95% S) was assumed in the coke oven
operation.
b. Heating value of coal (assumed) - 12,000 Btu/lb coal.
(2) a. Emission factors were taken from reference (A-l).
(3) a. Based on assumption that 50% of sulfur in coal remains in
the coke and 50% ultimately is emitted as SO..
166
-------
TABLE 67. ENVIRONMENTAL IMPACTS OF MODULE
Module--,Space Heating
Unit—10° Btu (Input)
Environmental Impacts Resid (3.5% S)
Air
NOX, lb 0.135
S02, lb 3.068(2)
CO. lb 0.030
Particulate, lb 0.017
Total organic material, lb 0.004
Water
Suspended solids, lb 0
Dissolved solids, lb 0
Total organic material, lb 0
Solid
Ash, lb 0
Sludge, lb 0
Approx. Module Efficiency
167
-------
Footnotes for Table 67:
(1) a. Values were taken from Table A-46 in reference (A-26) except
as modified below.
(2) a. SO. emission was modified based on sulfur content of fuel oils.
168
-------
TABLE 68. ENVIRONMENTAL IMPACTS OF MODULE
Module--,Space Heating(
Unit—10 Btu (Input)
Environmental Impacts
'Coal (3% S)
Air
N0x, Ib
S02, Ib
CO, Ib
Participate, Ib
Total organic material, Ib
0.177
4.410
3.490
0.775
0.775
(2)
Water
Suspended solids, Ib
Dissolved solids, Ib
Total organic material, Ib
0
0
0
Solid
Ash, Ib
Sludge, Ib
6.9
0
Approx. Module Efficiency
50%
169
-------
Footnotes for Table 68:
(1) a. Values were identical to those In Table A-12 except as modified
below.
(2) a. SO. emission was modified based on sulfur content of coal.
170
-------
References
A-l. "Compilation of Air Pollutant Emission Factors", U.S. Environ-
mental Protection Agency, Office of Air Programs, Research Triangle
Park, North Carolina, February, 1972.
A-2. Anon, Coal Age, 77(10), 122-138, 1972.
A-3. Leonard, J. W., and D. R. Mitchell, editors, "Coal Preparation",
3rd edition, AIME, New York, 1968.
A-4. Barthauer, G. L., AIME Environmental Quality Conference,
Washington, D.C., June 7-9.
A-5. U.S. Department of Labor, Bureau of Labor Statistics, Handbook
of Labor Statistics 1971, Bulletin 1705.
A-6. Process Research Inc., "Evaluation of Fuel Treatment and Con-
version Processes", report prepared for the EPA, Contract No.
68-02-0242, and CPA-70-1, July 7, 1972.
A-7. Battelle Memorial Institute, "Task Report on EPA Energy Quality
Model Exercise for 1975, Series B, Supplement V", report prepared
for EPA, Office of Air Programs, 1972.
A-8. "Coal-Bituminous and Lignite", Bureau of Mines Minerals Yearbooks,
U.S. Department of Interior, 1970.
A-9. Ephraim, M., "Status Report on Locomotives as Sources of Air Pol-
lution", International Conference on Transportation and Environ-
ment, Washington, D.C., May, 1972.
*
A-10. Battelle Memorial Institute, "A Study of the Environmental Impact
of Projected Increases in Intercity Freight Traffic", a report
prepared for Association of American Railroads, August, 1971.
A-ll. Hare, C. T., and Sprinler, "Exhaust Emissions from Uncontrolled
Vehicles and Related Equipment Using Internal Combustion Engines",
Southwest Research Report to EPA, October, 1972.
A-12. Environmental Quality. Third Annual Report of the Council on
Environmental Quality. August, 1972.
A-13. "Handbook of Labor Statistics", U.S. Department of Labor,
Bureau of Statistics, 1971.
A-14. Department of the Interior, "Environmental Effects of Underground
Mining and Mineral Processing", an unpublished report.
171
-------
A-15. Private communication, R. B. Foster, Manager, Industrial Planning
Institute of Gas Technology, Chicago, Illinois.
A-16. The Interstate Oil Compact Commission (IOCC) Study.
A-17. "Statistical Abstract of the United States", U.S. Department of
Commerce (1971).
A-18. "U.S. Energy Outlook. An Initial Appraisal 1971-1985", an.interim
report of the National Petroleum Council, Vol. 1, July (1971).
A-19. "Handbook of Labor Statistics", U.S. Department of Labor (1971).
A-20. "Crude Petroleum and Petroleum Products", Bureau of Mines
Minerals Yearbook, U.S. Department of the Interior (1970).
A-21. "Crude Oil Pipelines", Pipe Line News, Oildam Publishing Co.,
1971-1972 edition.
A-22. Marks, L. S., editor, "Mechanical Engineers' Handbook".
A-23. "Evaluation of the Fluidized Bed Combustion Boiler", Final Report
prepared by Westinghouse, Contract No. CPA 70-9.
A-24. American Petroleum Institute, "Petroleum Facts and Figures",
1971 edition.
A-25. Private communication with industry.
172
-------
APPENDIX B
CALCULATION OF PREDICTED AMBIENT AIR
QUALITY FOR THE INDIANAPOLIS AQCR
The calculations required for the determination of ambient air
quality to be expected from fuel combustion in the Indianapolis AQCR
according to projections based on Scenario 1 and Scenario 3 are presented
in this appendix. The Indianapolis AQCR inventory was modified as
indicated in the discussion in the body of the report. The resulting
base-case data are given in Table 69. These data refer to 1971 fuel
quantities and the emissions and AAQ are based on the use of all clean fuel.
The approach will be illustrated by describing the calculations
required for 1975. The base-case data (Table 69) were first increased
by a growth factor, 1.101, determined by dividing the Dupree and West
projected coal use as fuel in 1975 (13,675 x 1012 Btu) by the actual 1971
value (12,420 x 1012 Btu). The results of the growth factor multiplica-
tion are given in the first three lines of Table 70. These data represent
the coal use for the Indianapolis AQCR for 1975 and the 802 emissions and
AAQ which would result if all the coal were low sulfur coal.
The total coal use was broken down into high- or low-sulfur coal
use and into various energy technology applications in direct proportion
to the fuel utilization projections developed in the body of the report.
For convenience, the coal allocations for 1975 were summarized from
Tables 6, 7, and 8 for Scenario 1 and from Tables 19, 20, and 21 for
Scenario 3. This summary is given in Table 71. For certain of these
allocations the percentage of the total is also given in Table 71. For
example, in Scenario 1 the high-sulfur coal use in the electrical sector
12
was projected to be 5,775 x 10 Btu, or 42.23 percent of the total. These
percentages were then applied to the total coal use projected for the
Indianapolis AQCR in 1975. Thus, in Scenario 1, 42.23 percent of the
projected total coal, or 1,807,146 tons per year, are allocated as high-
sulfur coal to the electrical sector. The results of these calculations
are given in the coal-use column of Table 70. The quantities of low-sulfur
coal were adjusted to balance the subtotals for each sector.
173
-------
Each coal-use quantity was multiplied by the emission factor
appropriate to the coal type or applied energy technology to obtain the
equivalent S02 emissions in tons per day as given in Table Table 70.
The SCL emissions were summed for each sector and the resulting
AAQ contribution calculated for each sector in proportion to the
corresponding base-case values. The necessary calculations are shown in
Table B-2.
Finally, the sector contributions to AAQ were summed to obtain
the total predicted AAQ from coal combustion according to Scenario 1,
3 3
43.15 p,g/m , and according to Scenario 3, 105.16 jj,g/m .
These calculations were repeated for the remaining years and the
resulting data are given in Tables 72 and 73 for 1980, in Tables 74
and 75 for 1985, and in Tables 76 and 77 for 2000.
It was pointed out in the body of the report that the total
emissions calculated for Scenario 3 were larger than for Scenario 1 in
1980, 1985, and 2000 as a result of removing some stack gas cleaning
capacity to balance the coal subtotal in the electrical sector. The same
result is, of course, observed in Tables 72, 74, and 76. However, it
should be noted that it is not the increase in emissions per se which is
responsible for the large increase in AAQ observed for Scenario 3, but
rather, it is the occurrence of increased emissions in the nonelectrical
sectors which is responsible for the increased AAQ. For example, consider
the year 2000, Table 76; assume that the same quantity of high sulfur
coal (1,131,813 tons/year) projected for Scenario 3 is included in the
electrical sector for Scenario 1, and that the low sulfur coal projection
for Scenario 1 is reduced by the same amount to balance the subtotal. Also
assume that the stack gas cleaning capacity projected for Scenario 1 is
retained in Scenario 3 and the low-sulfur coal in Scenario 3 is reduced to
balance the subtotal. Now the only difference between the two scenarios
is the interchange of high- and low-sulfur coal between the electrical and
the nonelectrical sectors. When the AAQ calculations are repeated with
these modified coal-use quantities, the results are as follows:
174
-------
S02 Emissions, AAQ-R33
Tons/Day (j,g/m3
Scenario 1
Electrical Sector 313.8 14.7
Other Sectors 91.2 54.6
Totals 405.0 60.3
Scenario 3
Electrical Sector 192.2 9.0
Other Sectors 218.3 130.6
Totals 410.5 139.6
In this case the total emissions are nearly equal, yet the AAQ for
Scenario 3 is still more than twice that for Scenario 1.
175
-------
TABLE 69. INDIANAPOLIS BASE CASE-1971
Electrical Sector
Other Sectors
Totals, All Sectors
Coal use,
Tons /Year
3,001,038
885,697
3,886,735
SO 2 Emissions,
Tons /Day
156.9
40.7
197.6
AAQ- Receptor 33,
^g/n»3
7.35
24.39
31.74
(a) Assumed all clean fuels.
(b) Processing plants have been excluded from this table. Seven plants
emitted 3.29 T/D S02 and contributed 14.78 M-g/m3 to Receptor 33.
176
-------
TABLE 70. PREDICTED AMBIENT AIR QUALITY - 1975
Sector/Combustion Mode
Indianapolis Base Case
(Growth Factor. 1.101. applied to
Electrical Sector
Other Sectors
Totals, all sectors
Scenario 1
Electrical Sector
Stack gas cleaning
High sulfur coal, w/o cont.
Low sulfur coal
Subtotals
Other Sectors (Unchanged)
Totals, all sectors
Scenario 3
Electrical Sector
Stack gas cleaning
High sulfur coal, w/o cont.
Low sulfur coal
Subtotals
Other Sectors
High sulfur coal, w/o cont.
Low sulfur coal
Subtotals
Coal Use,
Tons /Year
1971 Base Case)
3, 30'+, 143
975,152
4,279,295
21'>, 099 (5.12%)
1,80', 146 (42.23%)
1,277.898 (Bal.)
3.300,143
9711,152
4,279,295
219,099 (5.127.)
946,580 (22.12%)
2,138,099 (Bal.)
3,304,143
860,201 (20.11%)
114,951 (Bal.)
975,152
S02 Emissions,
Tons/Day
172.8
- 44.8
217.6
3.60
282.20
62.31
348.11
44.8
392.93
3.60
147.88
104.25
255.73
149.95
5.60
155.58
AAQ - Receptor 33
ug/"»
8.09
26.85
34.95
16.30 (348.11/172.8 x 8.09)
26.85
43.15
-
11.98 (255.73/172.8 x 8.09)
93.18 (155.55/44.82 x 26.85)
Totals, all sectors
4,279,295
411.28
105.16
177
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TABLE 71. YEAR 1975 COAL ALLOCATIONS
Sector
Residential/Commercial
Low sulfur coal
High sulfur coal
Industrial
Low sulfur coal
High sulfur coal
Totals, R/C plus Industrial
Low sulfur coal
High sulfur coal
Electrical
Low sulfur coal
Stack gas cleaning
High sulfur coal
Total, all sectors
Scenario 1
- „ Percent
10 Btu of Total
325
0
4,450
0
4775
0
2,425
700 5.12
5,775 42.23
13,675
Scenario 3
1012Btu
80
245
1,945
2,505
2025
2,750
5,175
700
3,025
13,675
Percent
of Total
20.11
5.12
22.12
178
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TABLE 72. PREDICTED AMBIENT AIR QUALITY - 1980
Sector/Combustion Mode
Coal Use,
Tons/Year
SO, Emissions, AAQ - Receptor 33
Tons/Day iiS/n
Indianapolis Base Case
(Growth Factor. 1.273. applied to 1971 Base Case)
Electrical Sector
Other Sectors
Totals
Scenario 1
3,820,321
1,127,492
4,947,813
199.7
51.8 •
251.5
9.36
31.05
40.41
Electrical Sector r
Stack gas cleaning
High sulfur coal, w/o cont.
Low sulfur coal
Subtotals
Other Sectors (Unchanged)
Totals, all sectors
Scenario 3
Electrical Sector
Stack gas cleaning
High sulfur coal, w/o cont.
Low sulfur coal
Subtotals
Other Sectors
High sulfur coal, w/o cont.
Low sulfur coal
Subtotals
Totals, all sectors
2,121,622 (42.887.)
178,616 (3.617.)
1,520,083 (Bal.)
2,820,321
1,127,492
1,947,813
34.88
27.89
74.11
136.88
51.8
188.68
1,412,600 (28.557.) 23.22
0
2,407,721 (Bal.) 117.39
3,820,321 140.61
887,638 (17.947.) 138.62
239,855 (Bal.) 11.69
1,127,492 150.31
4,947,813 290.92
6.42 (136.88/197.7 x 9.36)
31.05
37.47
6.59 (140.6/199.7 x 9.36)
90.1 (150.3/51.8 x 31.05)
96.69
179
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TABLE 73. YEAR 1980 COAL ALLOCATIONS
Sector
Residential/Commercial
Low sulfur coal
High sulfur coal
Industrial
Low sulfur coal
High sulfur coal
Totals, R/C plus Industrial
Los sulfur coal
High sulfur coal
Electrical
Los sulfur coal
Stack gas cleaning
High sulfur coal
Scenario 1
_2 Percent
10 Btu of Total
300
0
4,550
0
4,850
0
3,450
6,650 42.88
560 3.61
Scenario 3
1012Btu
75
225
1,993
2,557
2,068
2,282
6,232
4,428
0
Percent
of Total
17.94
28.55
w/o control
Total, all sectors
15,510
15,510
180
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TABLE 74. PREDICTED AMBIENT AIR QUALITY - 1985
Sector/Combustion Mode
Coal Use,
Tons/Year
SCv Emissions, AAQ - Receptor 33
Tons/Day
Indianapolis Base Case
(Growth Factor. 1.654. applied to 1971 Base Case)
Electrical Sector
Other Sectors
Totals
Scenario 1
Electrical Sector
Fluidized-bed
Low Btu
Liquefaction
Stack gas cleaning
Low sulfur coal
High sulfur coal, w/o cont.
Subtotals
Other Sectors (Unchanged)
Totals
Scenario 3
Electrical Sector
Fluidized-bed
Low Btu
Liquefaction
Stack gas cleaning
Low sulfur coal
^ High sulfur coal, w/o cont.
Subtotals
Other Sectors
High sulfur coal, w/o cont.
Low sulfur coal
Subtotals
Totals, all sectors
4,963,717 259.5
1,464,943 67.4
6,428,660 326.9
134,359 (2.09%) 3.1
161,359 (2.51%) 4.9
100,300 (1.57%) 2.3
2,337,461 (36.36%) 38.4
2,230,238 (Bal.) 108.7
0
4,963,717 157.4
1,464,943 67.4
6,428,660 224.8
134,359 (2.09%) 3.1
161,354 (2.09%) 4.9
100,300 (1.57%) 2.3
1,083,579 (21.83%) 17.8
3.484,120 (Bal.) 169.9
0
4,963,717 198.0
921,227 (14.33%) 143.9
543,716 (Bal.) 26.5
1,464,943 170.4
6,428,660 368.4
12.16
40.34
52.50
7.4 (157.4/259.5 x 12.16)
40.3
47.7
9.3 (198.0/259.5 x 12.16)
102.0 (170.4/67.4 x 40.34)
111.3
181
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TABLE 75. YEAR 1985 COAL ALLOCATIONS
Sector
Residential/Commercial
Low sulfur coal
High sulfur coal
w/o control
Industrial
Low sulfur coal
High sulfur coal
Totals, R/C plus Industrial
Low sulfur coal
High sulfur coal
Electrical
Fluidized-bed combustion
Gasification, low Btu
Liquefaction
Stack gas cleaning
Low sulfur coal
High sulfur coal,
Scenario 1
. Percent
10 Btu of Total
100
0
4,820
0
4,920
0
400 2.09
480 2.51
300 1.57
6,960 36.36
6,080
0
Scenario 3
1012Btu
25
75
2,113
2,707
2,138
2,782
400
460
300
4,178
8,862
0
Percent
of Total
14.33
2.09
2.51
1. 57
21.83
w/o control
Totals, all sectors
19,140
19,140
182
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TABLE 76. PREDICTED AMBIENT AIR QUALITY - 2000
Sector/Combustion Mode
Coal Use,
Tons/Year
SO. Emissions, AAQ - Receptor 33
Tons/Day
Indianapolis Base Case
(Growth Factor. 2.24. applied to 1971 Base Case)
Electrical Sector
Other Sectors
Totals
Scenario 1
Electrical Sector
Fluidized-bed combustion
Low Btu gasification
Liquefaction
Stack gas cleaning
Low sulfur coal
High sulfur coal, w/o cont.
Subtotals
Other Sectors (Unchanged)
Totals, all sectors
Scenario 3
Electrical Sector
Fluidized-bed combustion
Low Btu gasification
Liquefaction
Stack gas cleaning
Low sulfur coal
High sulfur coal, w/o cont.
Subtotals
Other Sectors
High sulfur coal, w/o cont.
Low sulfur coal
Subtotals
Totals, all sectors
6,722,325 351.5
1,983,961 91.2
8,706,286 422.7
1,140,523 (13.17.) 26.2
1,453,950 (16.77.) 44.5
957,691 (11.07.) 22.4
1,715,138 (19.7*) 28.2
1,455,023 (Bal.) 70.9
0
6,722,325 192.2
1,983,961 91.2
8,706,286 283.4
1,140,523 (13.17.) 26.2
1,453,950 (16.77.) 44.5
957,691 (11.07.) 22.4
583,321 (6.7%) 9.6
2,586,840 (Bal.) 126.1
0
6,722,325 228.8
1,131,817 (13.0%) 176.7
852,144 (Bal.) 41.5
1,983,961 218.3
8,706,286 447.1
16.46
54.64
71.10
9.0 (192.2/351.5 x 16.46)
54.6
53.6
10.7 (228.8/351.5 x 16.46)
130.6 (218.3/91.2 x 54.64)
141 i 3
183
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TABLE 77. YEAR 2000 COAL ALLOCATIONS, EXCLUDING
COAL FOR HIGH Btu GASIFICATION
Sector
Res idential/Commercial
Low sulfur coal
High sulfur coal
Industrial
Low sulfur coal
High sulfur coal,
w/o control
Totals, R/C plus Industrial
Low sulfur coal
High sulfur coal
Electrical
Fluidized-bed combustion
Low Btu
Liquefaction
Stack gas cleaning
Low sulfur coal
High sulfur coal,
Scenario 1
-_ Percent
10 Btu of Total
0
0
5,300
0
5,300
0
3,000 13.1
3,820 16.7
2,500 11.0
4,500 19.7
3,700
0
Scenario
3
-„ Percent
10 Btu of Total
0
0
3,323
2,977
2,323
2,977
3,000
3,820
2,500
1,523
6,677
0
13.0
13.1
16.7
11.0
6.7
w/o control
Totals, all sectors
22,820
22,820
184
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BIBLIOGRAPHIC DATA
SHEET
1. Report No.
EPA 600/2-74-001
3. Recipient's Accession No.
4. Title and Subtitle
Assessment of the Potential of Clean Fuels and
Energy Technology
5. Report Date
February 1974
6.
7. Author(s)
E. H. Hall, P. S. K. Choi, and E. L. Kropp
8. Performing Organization Kept.
No.
>. Performing Organization Name and Address
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
10. Project/Task/Work Unit No.
11. Contract/Grant No.
68-01-2114
1Z Sponsoring Organization Name and Address
EPA, Office of Research and Development
Room 619, Waterside Mall, West Tower
Washington, D. C. 20460
13. Type of Report fit Period
Covered
Final Report
14.
15. Supplementary Notes
16. Abstracts
A study was conducted to assess the potential of fuel cleaning, fuel con-
version, and emission control technologies, in conjunction with the use of
naturally occurring clean fuels, to reduce air emissions from fuel/energy processes
sufficiently to maintain ambient air quality in the face of increasing fuel use
between now and the year 2000. Total emissions and effluents produced by fuel-
burning systems to the year 2000 were calculated according to three different
scenarios reflecting different technology availability and fuel allocation.
The impact of these emissions on ambient air quality was analysed. An overall
index was developed for comparison of the potential usefulness of the energy
technologies under consideration. Research and development priorities were
recommended.
17. Key Words and Document Analysis. 17a. Descriptors
Air pollution, Air pollution control, Fuel combustion, Ambient Air Quality,
Fuel cleaning, Fuel conversion, Technology assessment.
17b. Identifiers/Open-Ended Terms
17c. COSATI Field/Group
18. Availability Statement
19.. Security Class (This
Report)
UNCLASS1F1
LASS
• Clas
20. Security Class (Tbis
Page
UNCLASSIFIED
21. No. of Pages
184
22. Price
FORM NTI5-3B (REV. 8-72)
USCOMM-OC 14B8Z-P72
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