United States
Department of
Commerce
United States
Environmental Protection
Agency
Office of Environmental
Affairs
Washington. D.C. 20230
Office of Research and Development
Office of Energy, Minerals and Industry
Washington, D.C. 20460
EPA-600/7-77-101
August 1977
ENERGY CONSUMPTION OF
ENVIRONMENTAL CONTROLS:
Fossil Fuel, Steam
Electric Generating
Industry
Interagency
Energy-Environment
Research and Development
Program Report
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EPA-600/7-77-101
August 1977
ENERGY CONSUMPTION OF ENVIRONMENTAL CONTROLS:
FOSSIL FUEL, STEAM ELECTRIC GENERATING INDUSTRY
by
Brian Murphy, Project Manager
James R. Mahoney, Project Consultant
David Bearg
Gale Hoffnayle
Joel Watson
Environmental Research § Technology, Inc.
Concord, Massachusetts 01742
EPA Interagency Agreement No. IAG D6-E091
Office of Energy, Minerals, and Industry
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
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DISCLAIMER
This report has been reviewed by the Office of Research and
Development, U.S. Environmental Protection Agency, and approved for
publication. Approval does not signify that the contents necessarily
reflect the views and policies of the U.S. Environmental Protection
Agency, nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
n
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FOREWORD
This report was sponsored to provide the interested public,
government, labor, and business officials with an objective
statement of the potential influence various governmental
environmental regulations have on the availability of
electrical energy. It examines ways in which environmental
necessities can be obtained at lower energy costs. Careful
economic evaluations must yet be done to place the energy-
saving technological options within desirable economic and
environmental contexts. Therefore, this study will be part
of a continuing effort to find more efficient solutions to
many of the more pressing problems of today.
Sidney R. Galle£/
Deputy Assistant Secretary
for Environmental Affairs
iii
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ABSTRACT
This report addresses the energy requirements for environmental control
in the fossil fuel, steam electric industry. These requirements arise
through a number of mechanisms, including:
o direct fuel or electricity requirements for operating
pollution control equipment, including production
of necessary chemicals and disposal of wastes
o energy used in constructing control equipment
o fuels consumed in transporting low sulfur fuels
o extra fuel consumed to compensate for power plants'
efficiency losses caused by environmental controls
o energy used in constructing extra generation capacity
to compensate for efficiency losses
These requirements are computed for a variety of energy policy "scenarios"
to demonstrate the impact of altering current environmental regulations or
of utilizing alternate strategies for achieving environmental goals. In
particular, the effect of requiring "Best Available Control Technologies"
for power plants, of using tall stacks and/or supplementary control
systems, and of using coal washing and/or blending to decrease the
necessity for "scrubbers" are examined in different scenarios.
This report was submitted by the Office of Environmental Affairs of
the U.S. Department of Commerce in fulfillment of Interagency Agreement
No. IAG D6-E091 with the U.S. Environmental Protection Agency. The
research was conducted by Environmental Research and Technology, Inc. under
the joint sponsorship of the Department of Commerce and Environmental
Protection Agency.
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VI
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CONTENTS
FOREWORD iv
ABSTRACT v
LIST OF ILLUSTRATIONS ix
LIST OF TABLES x
ACKNOWLEDGEMENTS xiii
1. SUMMARY AND CONCLUSIONS 1-1
1.1 Principal Findings 1-2
1.2 Relative Importance of Various Regulatory Areas 1-4
1.3 Control System Options 1-6
2. INTRODUCTION 2-1
2.1 Objectives and Guidelines 2-1
2.2 Scenarios Considered 2-4
3. ENERGY CONSUMPTION BY ENVIRONMENTAL CONTROL PROCESS 3-1
3.1 Pre-plant Energy Requirements 3-5
3.2 In-plant Energy Requirements 3-20
3.3 Post-plant Energy Requirements 3-42
3.4 Capital Energy Requirements 3-44
3.5 Capacity Losses 3-49
4. BASE YEAR ENVIRONMENTAL ENERGY CONSUMPTION 4-1
4.1 Sulfur Dioxide Control 4-1
4.2 Thermal Pollution Control 4-9
4.3 Particulate Control 4-10
4.4 Other Environmental Control Areas 4-12
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CONTENTS (CONTINUED)
5. METHODOLOGY 5_i
5.1 Data Sources 5-1
5.2 Expansion to the National Population 5-3
5.3 Regulatory Scenarios for Sulfur Oxides 5-15
5.4 Oil to Coal Conversion 5-18
5.5 Complying Fuel Histograms 5-18
5.6 Sulfur Oxide Control Technologies 5-25
6. 1983 PROJECTIONS 6-1
6.1 Sulfur Dioxide Controls 6-3
6.2 Waste Heat Disposal 6-14
6.3 Particulate Controls 6-23
7. DISCUSSION OF RESULTS 7-1
7.1 Comparison with Other Studies 7-1
7.2 Comparison with EPA Expected Regulatory Activity 7-3
7.3 Low Sulfur Western Coal Availability 7-5
REFERENCES
APPENDIX A - ERT SAMPLE PLANT POPULATION
APPENDIX B - ENERGY CONSUMPTION MODELING
APPENDIX C - ENVIRONMENTAL ENERGY CONSUMPTION ALGEBRA
Vlll
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LIST OF ILLUSTRATIONS
F igur e Page
1-1 Energy Requirements to meet Sulfur Dioxide Regulations
in 1983 1-7
3-1 Material and Energy Balances for a FGD System Utilizing
Limestone as Sorbent 3-10
3-2 Coal Regions of the United States 3-13
3-3 Material and Energy Balances for a FGD System Utilizing
Lime as Sorbent 3-21
3-4 Flow Sheet - Coal-Fired Central Treatment Plant 3-24
3-5 Energy Utilization Efficiency - Central Station vs.
Total Energy 3-40
3-6 Material and Energy Balances for a FGD System Utilizing
Limestone as Sorbent and Lime as Fixating Agent for
the Treatment of Sludge 3-45
3-7 Material and Energy Balances for a FGD System Utilizing
Lime as Both Sorbent for Sulfur Removal and Fixating
Agent for Treatment of Sludge 3-46
5-1 Locations of the 100 Power Plants in the Study 5-10
5-2 Complying Fuel Histograms 5-23
5-3 Oil and Coal Contributions to the 1983 Complying Fuel
Histogram of Figure 5-2 5-24
7-1 Comparison of Scenario Coal Requirements and
Projected Coal Availability in 1983 7-10
IX
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LIST OF TABLES
Table No. Page
1-1 Percent of Total Energy Use for S02 Waste Heat and
Particulate Control 1-3
1-2 Goals of Sulfur Dioxide Regulations and Example of
Energy Requirements to Meet Them in 1983 1-5
1-3 Sulfur Dioxide Control Energy Consumption to Comply
with Air Quality Standards in 1983 1-10
2-1 Regulatory Parameters 2-5
2-2 Sulfur Oxide Control Technology Scenarios 2-7
2-3 Waste Heat Disposal Scenarios 2-8
3-1 Energy Consumption on a Process Basis 3-2
3-2 Process Energy Consumption in Percent 3-6
3-3 Breakdown of Unit Process Energy Requirements
in Percent 3-7
3-4 Energy Requirements for the Extraction,of Coal 3-9
3-5 Energy Requirements for the Transport of Coal 3-12
3-6 Heat Content Estimates for Western and Other Coals 3-12
3-7 Estimates of Btu Content Loss Due to Physical Coal
Cleaning 3-17
3-8 Energy Requirements for Nonregenerable FGD Systems 3-23
3-9 Summary of Energy Requirements for Lime and
Limestone FGD Systems 3-24
3-10 Energy Requirements for Regenerable FGD Systems 3-26
3-11 Energy Requirements for Particulate Control Equipment 3-28
3-12 Energy Requirements for Closed-Cycle Cooling Systems 3-32
3-13 Thermal Cycle Efficiency of Fluidized-Bed Boilers 3-38
3-14 Capital Energy Requirements for Environmental Control 3-48
3-15 Capacity Loss or Saleable Power Reductions in Percent 3-50
4-1 Summary of Base Year Environmental Energy Consumption 4-2
4-2 Environmental Energy Consumption for Residual Oil
Desulfurization in 1974 4-5
4-3 Shipments of Western Coal to Eastern Markets, 1974 4-7
4-4 Distribution of Particulate Control Equipment by
Fuel Type for the Sample Plant Population 4-11
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LIST OF TABLES (Continued)
Table No. Page
5-1 Details for 100 Plant Sample Power Plant
Parameters; Coal Plants, East Coast 5-4
5-2 Distribution of Total Coal- and Oil-Fired Generating '
Capacity by Region, Size and Fuel Type - Pre-1976
Capacity 5-11
5-3 Distribution of Total Coal- and Oil-Fired Generating
Capacity by Region, Size and Fuel Type - Capacity
Added 1976-1980 5-12
5-4 Megawatt Values Used in Deriving Expansion Factors 5-13
5-5 Sulfur Oxide Regulatory Scenarios 5-17
5-6 Ratio of Coal to Oil Heating Values 5-19
5-7 Complying Fuel Sulfur Values 5-20
5-8 Breakdown of Megawatts in the 100 Plant Sample by
Complying Fuel Range for Air Quality Standards with
Minimum Coal Conversion 5-22
5-9 Sulfur Oxide Control Technology Scenarios 5-26
5-10 Energy Consumption Matrix: Scenario l.S 5-27
5-11 Distribution of Utility Coal Consumption and
Generating Capacity by Region 5-29
5-12 Energy Consumption Matrix: Scenario 2.S 5-31
5-13 Energy Consumption Matrix: Scenario 3.S 5-33
5-14 Percentage of Energy Generation by Sulfur Fuel Ranges
Redistribution with Use of 95% Reliable Supplementary
Control Systems 5-33
5-15 Percentage of Fuel Range Switches for Supplementary
Control System Options 5-35
6-1 Range of Total S02 Waste Heat and Particulate
Control Energy Requirements 6-2
6-2 Range of Sulfur Control Energy Requirements to
Meet all Present Regulations 6-5
6-3 Most Likely Sulfur Control Energy Requirements to
Meet Various Regulations in 1983 6-5
6-4 Most Likely Capacity Loss Resulting from Sulfur
Control to Meet Various Regulations in 1983 6-6
6-5 Range of Capacity Loss to Meet All Present Regulations 6-6
6-6 Sulfur Oxide Control Energy Requirements Coal
Conversion Comparison 6-8
6-7 Sulfur Oxide Control Energy Requirements Growth
Rate Comparison 6-9
XI
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LIST OF TABLES (Continued)
Table No. Page
6-8 Sulfur Oxide Control Energy Requirements by Energy
Source to Meet All Present Regulations 6-10
6-9 Sulfur Oxide Control Energy Requirements by Location
in the Process Stream to Meet All Present Regulations 6-10
6-10A Range of Sulfur Oxide Control Energy Requirements to
Meet Air Quality Standards Only: Scenario l.S 6-12
6-1OB Range of Sulfur Oxide Control Energy Requirements to
Meet Air Quality Standards Only: Scenario 2.S 6-12
6-IOC Range of Sulfur Oxide Control Energy Requirements to
Meet Air Quality Standards Only: Scenarip 3.S 6-12
6-11A Results for Best Available Control Technology
Based on Scenario l.S for Pre-1980 Plants 6-13
6-11B Results for Best Available Control Technology
Based on Scenario 2.S for Pre-1980 Plants 6-13
6-11C Results for Best Available Control Technology
Based on Scenario 3.S for Pre-1980 Plants 6-13
6-12 Summary of Waste Heat Control Scenarios 6-16
6-13 Environmental Energy Consumption Percentage for
Waste Heat Control Scenarios 6-17
6-14 Calculations for Percent of 1983 Fossil Fuel
Generating Capacity Which Will Employ Closed-Cycle
Cooling for Environmental Reasons Under the
Assumptions of Scenario l.W 6-19
6-15 Environmental Energy Consumption for Particulate
Control in 1983 6-23
7-1 Comparison of Estimates of Energy Consumption for
Pollution Control 7-2
7-2 Expected Environmental Energy Consumption Using the
EPA Mix of Control Systems 7-4
7-3 Implied Low Sulfur Western Coal Consumption for Three
S02 Regulatory Scenarios - 1983 7-6
xn
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ACKNOWLEDGMENTS
This study was financed by the U. S. Department of Commerce and
the U. S. Environmental Protection Agency. Project supervisors were
Robert B. Grant and Richard J. Herbst of the Office of Environmental
Affairs, U. S. Department of Commerce. During the conduct of this study,
valuable advice, assistance, and data were received from the Environ-
mental Protection Agency, the Tennessee Valley Authority, the Federal
Power Commission, the Office of Energy Programs of the Department of
Commerce, the Edison Electric Institute, the Electric Power Research
Institute, and many electric utility companies.
Xiii
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1. SUMMARY AND CONCLUSIONS
This study addresses the energy requirements for environmental
control in the fossil fuel, steam electric industry. These requirements
are given throughout the report as percentages of the total fuel energy
input at all fossil fuel, steam electric plants to produce electricity.
Present fossil fuel energy used in the steam electric industry for the
base year 1974 is estimated in Section 4 as 15 x 1015 Btu's. Two
industry growth rates, 4.16 percent and 6.73 percent have been used in
the study as explained in Section 6. This amounts to an energy use in
1983 of 22 - 27 x 1015 Btu's.
Interpretation of the numbers presented in this section and in the
remainder of the report will be aided if the following equivalent values
are kept in mind. A one percent increment in energy required for
environmental control in 1983 is equivalent to:
• 220 - 270 x 1012 Btu's
• 40-50 million barrels per year of crude oil
• 500-650 million 1976 dollars (at an approximate import price
of $13/barrel)
Of course, not all of the energy consumed for environmental control
in 1983 is in the form of imported oil. For coal a one percent energy
increment would be equivalent to:
• 220-270 x 1012 Btu's
• 9-12 million tons of coal
• 250-340 million 1976 dollars (at an approximate costs of
$28 per ton).
These equivalent values do illustrate that on a national scale an energy
increment of one percent or even less is significant when viewed in
dollar terms.
1-1
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1.1 Principal Findings
The main conclusions of this study are listed in Table 1*1. The
following two sections discuss these results further from two stand-
points: (a) the relative importance of various regulatory areas, (b)
control system options which lead to significant energy savings.
PRINCIPAL FINDINGS
• Present energy consumption for environmental control of fossil
fuel-steam electric plants in the base year of 1974 is approximately
1.3 percent of the total national fuel energy input to these
plants.
• By 1983, the energy consumption for environmental controls could be
as large as 8.2 percent of the total fuel energy input to all
plants [see Table 1-1) or as small as 4.1 percent.
• Control of sulfur dioxide emissions makes the greatest energy
demand (see Table 1-1 for an illustration).
If best available control technology, including low sulfur
fuel use and scrubbers, is required at new plants, the total
energy demand can be as large as 7.3 percent.
Energy demand for compliance with all present regulations
(without the additional requirement of best available control
technology) would be approximately 2.5 to 7.2 percent. Use of
coal washing to replace scrubbers where possible results in
the highest consumption while significant use of coal blending
results'in the least consumption.
The energy savings resulting from the use of tall stacks
and/or supplementary control systems nationwide to meet
ambient air quality SO standards would be approximately
1 percent.
• A considerable amount of energy (on the order of 2.1 percent of the
national population's energy input) will be consumed as the broad
range of fuels labeled oil/gas in order to meet present regulations,
primarily in the form of transportation fuels for the, shipment
of low sulfur western coal (LSWC).
1-2
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TABLE 1-1
PERCENT OF TOTAL ENERGY USE FOR SO ,
AND PARTICULATE CONTROL
WASTE HEAT
- All present regulations
Addition of BACT*
Smallest Total
Anticipated
Consumption
2.5
1.2
3.7
Largest Total
Anticipated
Consumption
7.2
0.1
7.3
Waste Heat
Particulate
Total
0.2
0.2
4.1
0.7
0.2
8.2
*Best Available Control Technology: Defined in the study as half of
all oil desulfurized, half of all coal washed, and scrubbers on all
plants built after 1979.
1-3
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• Coal blending is a considerably less energy intensive means of S02
control than coal washing (-2 percent).
• Disposal of cooling water waste heat has the second greatest energy
demand: From 0.2 to 0.7 percent.
• Particulate controls have the third greatest energy demand:
Approximately 0.2 percent.
• Conversion of post-1974 plants from oil to coal can result in
an additional energy requirement of from 0.1 to 0.3 percent of the
total national energy input to fossil-steam plants by 1983 due to
the additional control systems which would be required.
• The industry growth rate does not significantly affect the results
presented. The tables present the case of coal conversion for new
plants only and an industry growth rate of 6.73 percent.
t If all (old and new) oil fired plants are converted to coal, an
additional energy requirement of from 0.9 to 1.2 percent could
occur due to the additional control systems that would be required.
• The average capacity loss at individual power plants because of
environmental controls ranges from 1.5 to 5.1 percent of rated
capacity.
* The main focus of this study was the energy consumption needed for
environmental control systems. The selection of those systems
depends strongly, however, on the availability of low sulfur western
coal. The options cover a range from the presently available coal
to more than the upper end of all projections. It is clear that
the availability of coal as it affects energy consumption needs
closer investigation.
1.2 Relative Importance of Various Regulatory Areas
Sulfur dioxide regulations are identified as the most energy inten-
sive area when compliance is based on scrubbers and low sulfur fuel
only. Table 1-2 illustrates the way in which different sulfur dioxide
regulations contribute incrementally to energy consumption. These
energy percent figures are based on scenario 3.S for the smallest anticipated
consumption and on scenario 2.S for the largest estimate.
1-4
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TABLE 1-2
PERCENT OF TOTAL ENERGY USE FOR THE
GOALS OF SULFUR DIOXIDE REGULATIONS
PROJECTED TO 1983
Regulation
Primary air quality
standards
Primary and
secondary air
quality standards
State Implementa-
tion plans
New source perfor-
mance standards
Non-deterioration
(Class II)
Best available*
control technology
Goal
Protect human health
Protect health and welfare
(ecological and economic
effects)
Maintain air quality
standards
Use best available control
technology for each class
of source taking cost into
account
Maintain present air quality
Minimum possible emissions
determined on a source-by-
source basis
Smallest
Anticipated
Consumption
0.91
0.24
0.75
0.37
0.24
1.20
Running
Total
0.91
1.15
1.90
2.27
2.51
3.71
Largest
Anticipated
Consumption
4.52
0.75
1.78
-0.57
0.71
0.10
Running
Total
4.52
5.27
7.05
6.48
7.19
7.29
*Defined in this study for plants built after 1979 as half of all oil desulfurized, half of
coal washed and scrubbers on all plants. Older plants comply with AQS and SIPS.
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Figure 1-1 shows graphically the results presented in Table 1-2.
Note the negative increment for the New Source Performance Standards
(NSPS) shown for the largest anticipate consumption case. This occurs
for the coal washing scenario (2.S) because more restrictive sulfur
dioxide emission limits require less energy input due to switches from
high energy but low emission reduction coal washing to lower energy but
higher emission reduction alternatives (such as scrubbers).
Maintaining present air quality in non-deterioration Class II (ND)
regions involves an energy increment of 0.24-0.71 percent beyond NSPS,
AQS, and SIPS (see Table 1-2).
Best Available Control Technology (BACT) is intended to represent a
possible maximum emission control situation determined on a source-by-
source basis. The application of BACT has a different effect on each
scenario. In scenario 3.S which has the smallest energy consumption,
the application of BACT forces conversion to scrubbers and a consequent
increase in energy consumption. In scenario 2.S however application of
BACT converts plants from coal washing to scrubbers with little resultant
change in energy requirements.
For the second most energy intensive area, disposal of cooling
water waste heat, we find that most of the energy consumption projected
for 1983 occurs at existing units covered by state rather than federal
regulations. Thus, the principal regulatory option rests with the
states which could allow a greater percentage of facilities, exempt from
federal requirements, to use open-cycle cooling. A 25 percent increase
in the number of these facilities permitted to retain open-cycle cooling
leads to a 0.2 percent decrease in energy requirements.
For the third most energy intensive area, particulate control, we
have not been able to identify credible regulatory options leading to
substantial energy savings.
1.3 Control System Options
There are low-energy options for attaining environmental goals
which should be considered in development of compatible environmental
and energy plans.
1-6
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7.29%
BACT
Largest
Anticipated
Consumption
3.71%
BACT
.....
'•-'v1 SIP ''•;":•'.
'
•ND
AQS
PADS
Smallest
Anticipated
Consumption
Figure 1-1 Energy Requirements to Meet Sulfur Dioxide Regulations
Regulations in 1983
1-7
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For waste heat disposal energy, conservation in environmental
control systems can arise through: (a) waste heat utilization in total
energy plants, aquaculture, etc., (b) less energy intensive closed cycle
cooling systems such as cooling ponds or canals. It has not been
possible in the present study to provide quantitative information in
these areas. For particulate control using energy consumption results
of the survey, while there is a slight increase in energy consumption
with coal conversion due to a trend away from mechanical collectors
(multiple cyclones) and toward electrostatic precipitators, no control
options have been identified as leading to significant energy savings.
The principal energy conserving options are in the area of sulfur
oxide control through fuel blending and also through the use of Tall
Stacks or Supplementary Control Systems which permit switching between
high and low sulfur fuels depending on pollutant dispersal characteris-
tics of the atmosphere. If these options are used to meet Primary and
Secondary Air Quality Standards, we find that:
• Widespread use of fuel blending rather than scrubbers to meet
air quality standards decreases energy requirements by 0.4 to
0.9 percent. Widespread' use of fuel blending instead of coal
washing decreases energy use by 1.1 to 2.3 percent.
• Widespread use of supplementary control systems rather than
scrubbers to meet air quality standards decreases energy
requirements by 0.5 to 1.1 percent of the full value to
produce electricity.
• Use of supplementary control systems only in regions of the
country designated "low-sulfate" produces approximately a
0.4 percent decrease in energy requirements.
• Widespread use of tall stacks at new "plants rather than
scrubbers to meet air quality standards decreases energy
requirements by 0.7-1.2 percent,
• Use of tall stacks at new plants only in regions of the
country designated "low-sulfate" produces only about a
0.2 percent decrease in energy requirements.
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TABLE 1-3
SULFUR DIOXIDE CONTROL ENERGY CONSUMPTION TO COMPLY
WITH AIR QUALITY STANDARDS IN 1983 (IN PERCENT OF
FUEL INPUT TO FOSSIL STEAM PLANTS)1"
Expected Energy Consumption
Option
Supplementary Control
Systems Everywhere
Supplementary Control Systems
in "Low-Sulfate" Regions
Tall Stacks Everywhere
Tall Stacks in "Low-Sulfate"
Regions
l.S
2.2
1.6
1.9
1.5
2.0
Scenario*
2.S
2.7
3.4
2.6
3.6
3.S
1.6
1.1
1.2
0.9
1.3
*Sulfur dioxide control system scenarios:
l.S - Low sulfur coal and scrubbers
2.S - Addition of coal washing
3.S - Addition of coal blending
^Based on "most likely" values of process energy consumption in Table 3.2,
1-9
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It should be noted that there are concerns beyond the present
regulations which influence the use of tall stacks and SCS. In particular
the role of total atmospheric burden of SO in producing sulfates awaits
clarification.
Detailed
in Table 1-3.
Detailed results for three SO control system scenarios are shown
1-10
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2. INTRODUCTION
Recent disruptions in traditional energy supply and price patterns,
together with an increasing awareness of the finite size of energy
resources, have created a need for a better understanding of the United
States' energy system.
This study is an examination of one component of this energy
system, namely the energy required to control pollution in the fossil
fuel, steam electric generating industry.
The fossil fuel, steam electric generating industry is unique in a
number of respects. It is the leading industry in terms of direct fuel
energy consumption and has major environmental impacts. Since its basic
product is energy, it is tightly coupled to other industries as part of
the overall energy system. For example, increased electrification in
some industries, as a result of the pressures of complying with environ-
mental regulations, may well increase emissions from the generating
plant which supplies electricity for those industries. The result could
be a net increase in overall emissions to the environment. Therefore,
although this study quantifies the relationship between environmental
controls and the related energy consumption in the fossil fuel, steam
electric generating industry, the environmental controls on the generating
and consuming industries are interrelated.
2.1 Objectives and Guidelines
The general objective of this study was to identify, quantify and
rank significant energy consumption required by pollution control
regulations in the fossil fuel, steam electric generating industry.
Specific objectives are as follows:
* to estimate present consumption of energy for environmental
control in the fossil fuel, steam electric industry.
» to project energy consumption for environmental controls to
1983.
• to separate the total energy consumption for environmental
controls into two categories:
2-1
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fuel used - coal or oil and whether as raw fuel or as
electricity.
position in generation process - before arrival of fuel
or other materials at the plant (pre-plant), within the
generation complex (in-plant), or after generation is
complete (post-plant).
• to quantify the capacity losses expected with various envi-
ronmental control options.
• to identify regulatory and control system options which would
produce energy savings.
Study Requirements and Guidelines
This study required the methodology to handle a complex set of
input data and output results; the ways in which these requirements have
been met are summarized below:
• High Level of Detail in the Input Data
The study utilizes plant engineering and modeling data for 100
fossil fuel, steam electric plants. These data have had to be
expanded to give results for the national population of
plants in 1983.
• High Level of Detail in the Output Results
Energy requirements for environmental control need to be
calculated for a complex mix of specific air and water quality
regulations.
• Flexibility of Analysis Methods
Results are given for a variety of scenario parameters such as
industry growth rates, degrees of coal conversion, and types
of control technology. This has been accomplished by embodying
most of the methodology in a modular computer program termed
RIPPER (Regulatory Impact on Power Plant Energy Requirements)
which permits a multitude of parameter variations to be
investigated.
2-2
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• In computing energy consumed for environmental control, the
degree of control technology required is based on the assump-
tion of full compliance with a set of regulations for the
particular scenario being considered.
• Only energy consumption required to comply with environmental
regulations is inventoried. For example, energy used for
closed-cycle cooling, where this is necessitated by water
unavailability, is not counted.
• Similarly, the study does not count the additional energy used
to produce a saleable product in SC> scrubbing systems, that is,
the difference in energy consumption of regenerable and non-
regenerable systems. In principle, we should count the total
regenerable system energy consumption where this is necessitated
by lack of a suitable sludge disposal area. However, we have
in effect assumed regenerable systems mandated solely by environ-
mental causes to be rare.
2.2 Scenarios Considered
A variety of parameters enters into each of the scenarios for which
projections have been made. What this study terms "external parameters"
are shown below. They must be supplied as part of the input to calcu-
lations and while they may be important to the results are not specifically
of interest as study variables. The term "external" is used somewhat
loosely since the degree of coal conversion could as easily be included
in the list of regulatory parameters shown in Table 2-1. It is however
convenient to describe regulatory parameters according to the pollutant
being controlled.
Table 2-1 lists the regulatory parameters characterizing the areas
of sulfur oxide and waste heat control. These parameters are based on
presently enforceable regulations and on what appear to be the most
likely alternatives that may arise. Calculations have also been per-
formed for particulate control energy requirements as described in
Section 6.3. However, particulate control energy requirements have been
•
found to be determind primarily by fuel type. Hence, regulatory parameters
for particulate control have been held constant.
2-3
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The methods of conducting this study are described in detail in
Section 5; the guidelines for developing these methods are listed below.
In general, the study was conducted in energy units (Btu's) and did not
consider dollar costs. The results are reported in incremental precentages
of total energy use, due to the implementation of the regulations
studied. The use of percentages facilitates comparisons and alleviates
the need for carrying large numbers throughout the study. These factors
are designed to improve the value of the study as a policy-analysis
tool. These percentage, energy-consumption figures can be interpreted
as either the incremental amount of fuel which would be consumed because
of specific environmental regulations or as the incremental amount of
electricity which would be produced for the same amount of fuel in the
absence of these environmental regulations (see Appendix C).
The major line of analysis of the study inventories energy which
would actually be consumed without respect to derating or capacity
losses. A separate analysis of capacity losses associated with this
energy consumption has been made and is also reported.
After an initial attempt to quantify all regulatory effects, it was
determined that only regulations for the control of sulfur dioxide,
particulate matter, and thermal pollution entail significant consumption
of energy. The study was focused to provide more detail in these three
areas. Sulfur regulations appeared to be the most significant of the
three areas so an additional effort was made in the area of sulfur oxide
control.
Detailed Guidelines for Study
• The study is concerned with the fossil fuel, steam electric
portion of the electrical generating industry. Other com-
ponents of this industry, such as nuclear, gas turbine, or
internal combustion, are considered only as they affect
industry growth rate assumptions.
• Only environmental control technologies capable of having a
major impact on results by 1983 are treated. Advanced tech-
nologies such as fluidized bed combustion, coal gasification
or liquification, or scrubbers for NO removal, although
A
discussed in Section 3, do not enter into the energy consump-
tion projections.
2-4
-------
TABLE 2-1
REGULATORY PARAMETERS
Sulfur Oxide Control
• 24-hour primary National Ambient Air Quality Standard (PAQS)
• 24-hour primary National Ambient Air Quality Standard and
3-hour secondary National Ambient Air Quality Standard
(AQS)
• State Implementation Plans (SIP')
• New Source Performance Standards (NSPS)
• Non-Deterioration Class II permitted increments (ND)
• Best Available Control Technology (BACT)
Waste Heat Control
• Degree to which variances for open-cycle cooling are granted
(Section 316(a) of the Water Quality Control Act)
• Fraction of generating plants affected by state water quality
regulations
2-5
-------
The scenarios for sulfur oxide control options are listed in
Table 2-2 and for waste heat disposal in Table 2-3.
External Parameters
Growth rates for fossil fuel, steam electricity generation.
Degree of coal conversion.
Regional availability of low sulfur western coal.
Fraction of plants requiring closed cycle cooling for non-
environmental reasons.
Mix of permitted control technologies.
2-6
-------
TABLE 2-2
SULFUR OXIDE CONTROL TECHNOLOGY SCENARIOS
1.S Scrubbers and Low Sulfur Fuel
Compliance through the use of low sulfur western coal and scrubbers
at coal fired plants. Compliance through oil desulfurization at
oil fired plants.
2.S Addition of Coal Washing
Same as scenario l.S but coal washing is used wherever it can
replace scrubbers.
3.S Addition of Blending
Same as scenario l.S but blending of low sulfur western ccal is
used wherever it can replace scrubbers.
Options (can be combined with any of the above scenarios.)
SCS(E) Supplementary Control Systems permitted everywhere at both old
and new plants.
SCS(ROC) Supplementary Control Systems permitted in the rest of the
country outside of so called "high sulfate states".
TS(E) Tall stacks permitted everywhere for new plants.
TS(ROC) Tall stacks permitted at new plants only outside of so called
"high sulfate states".
2-7
-------
TABLE 2-3
WASTE HEAT DISPOSAL SCENARIOS
l.W EPA assumptions as in the report "Economic Analysis of Effluent
Guidelines Steam Electric Power Plants" (TBS, 1976)
2.W Same as scenario l.W but assumes a higher percentage (80 vs. 65)
of 1974 base/ear capacity installed closed-cycle cooling is
installed for water supply reasons.
3.W Same as scenario l.W except that a lower percentage (75 vs. 89)
of the 1974 baseyear would be allowed by the states to retain
open-cycle cooling.
4.W Same as scenario l.W except that a lower percentage (50 vs. 88)
of the capacity added in 1975-1978 would be assumed to receive
a 316(a) variance.
5.W Same as scenario l.W except that the percent of plants added in
1979-1983 installing closed cycle cooling for environmental
reasons does not vary from the 1975-1978 percentage.
-------
3. ENERGY CONSUMPTION BY ENVIRONMENTAL CONTROL PROCESS
This section surveys the environmental control energy requirements
involved in the generation of electricity from fossil fuels. The energy
requirements described are only those attributable to compliance with
environmental regulations. Energy requirements necessary for the
generation of electricity from fossil fuels, or related to good operating
practice, are not included even if they have a secondary environmental
effect.
For each environmental control process, the process is described;
the energy consumption values found in the literature are described; and
the values used for this study are recorded.
The three categories of energy requirements included in this
section are pre-plant, in-plant and post-plant. Pre-plant is defined as
all energy requirements prior to the fuel or other materials reaching
the generation site including desulfurization, coal washing or blending
and transportation. Post-plant are those after generation such as in
sludge removal. The remainder are in-plant, including flue gas clean-up.
Each environmental control process is discussed in the context of these
categories (see Table 3-1). Capital energy requirements, included in
the pre-plant category, are determined by the energy consumption for
construction of control equipment.
Results of the survey described in this section indicate that
energy requirements for environmental control can be put into the
following order of decreasing impact:
1] Sulfur Dioxide Controls;
2] Waste Heat Disposal; and
3) Particulate Controls.
All other environmental controls investigated have a much reduced
impact.
Therefore, the emphasis in this study is on sulfur dioxide con-
trols, with a lesser degree of effort being expended on the study of
•
waste heat controls and particulate controls.
3-1
-------
TABLE 3-1
SUMMARY OF LITERATURE VALUES OF PERCENT OF TOTAL
ENERGY CONSUMPTION ON A PROCESS BASIS
Percent Energy
Area Requirement
A. Pre-Plant
1. Extraction
Coal Extraction Negligible
Oil/Gas Extraction Negligible
Control Chemicals
(Limestone Mining) 0.063
2. Transport
Coal (Western) 4.0
Control Chemicals
(Limestone) 0.195
3. Pretreatment
Oil Desulfurization 3-6
Coal Cleaning 4.0-10.0
Coal Liquefaction
and Gasification 15-40
Lime Calcining and
Preparation 1.98
B. In-Plant
1. Sulfur Dioxide Control
Flue Gas
Desulfurization 3-5.5
2. Particulate Control
Multiple Cyclones ^0.0
Electrostatic
Precipitators 0.1-0.3
3. Nitrogen Oxides
Control
Combustion
Modifications 0-0.6
4. Thermal Pollution
Control
Cooling Ponds 1.0
Spray Ponds and
P Semi-Closed 1. 3
Mechanical Draft
Towers 1.0-4.0
Natural Draft
Towers 2.0-4.5
References
(CEQ, 73; CA, 75b; Energy, 75)
(Haller, 75)
(Ford, 75; BOM, 75)
(Haller, 75)
(Ford, 75; HP, 74)
(Lovell, 75; Deurbrouck, 74;
EPA, 75a)
(EPA, 75a, Energy, 75; CA, 75a;
Perry, 74)
(Minerals, 73; Haller, 75)
(Haller, 75; Ellis, 75; Ford, 75)
(EPA, 73a; EPA, 75a)
Questionnaire Responses
(Oglesby, 70; Stern, 68; Teller, 72)
(PEDCo, 75) and Questionnaire
Responses
(Oglesby, 70; Stern, 68; Teller, 72;
Ford, 75)
(EPA, 73a; EPA, 74a; Ford, 75;
Hirst, 73; Dynatech, 69)
3-2
-------
TABLE 3-1 (Continued)
Area
ENERGY CONSUMPTION ON A PROCESS BASIS
Percent Energy
Requirement References
5. Wastewater Control
Chemical Treatment
6. Unit Conversions
Substitution of
Western Coal
Coal Conversion
Supplemental Fuel,
Solid Waste
Fluidized Bed
Combustion
Improved Power
Plant Efficiency
Total Energy Systems
7.
8.
Noise Control
<0.04-0.2
0.5
*
0
5
(+)
(+)
0.1
Intermittent Control Strategies
Fuel Switching small
Load Shifting small
Tall Stacks 0
Post-Plant
1. Coal Ash Disposal 0.0-1.1
2. Sludge Disposal 0.77-1.26
Capital Energy Requirements (Included in
1. Sulfur Oxide Control
Transport of Western Coal *
Trains or Pipelines
Limestone Scrubbing
Systems 0.2-0.5
Oil Desulfurization
Facility 0.15
2. Particulate Control
(EPA, 75b) and Questionnaire Responses
See text
(EPA, 74b; Energy, 75; Ford, 75)
(EPA, 75a; ER, 75)
(CEQ, 73)
(EPA, 75c)
(EPA, 73)
See text
See text
(EPA, 75a)
Questionnaire Responses
(BOM, 74a; EPA, 74b; Haller, 75)
(EPA, 75b)
Pre-plant)
Electrostatic
Precipitator
0.2
(Ford, 75)
(Ford, 75)
(Ford, 75)
*A value was not determined but the process cannot be assumed unimportant.
(+)Energy conserved by these processes.
3-3
-------
TABLE 3-1 (Continued)
ENERGY CONSUMPTION ON A PROCESS BASIS
Percent Energy
Area Requirement References
3. Nitrogen Oxide Control
Combustion
Modifications negligible (Ford, 75)
4. Thermal Pollution Control
Closed-Cycle
Cooling System negligible (Ford, 75)
5. Coal Gasification or
Liquefaction Plant *
6. Coal Preparation
Facility *
*A value was not determined but the process cannot be assumed unimportant,
3-4
-------
Table 3-1 lists all the areas investigated in the course of the
study together with energy consumption values found in the literature.
Each of the areas listed is discussed in this section. Table 3-2
lists the control system energy requirements actually used in the
modeling of this study. Because of the ranges of reported energy con-
sumptions reported in the literature and in the 100 plant survey (see
Appendix A), this study has used a range of values. The values in this
table are not explicitly referenced in the literature but represent a
weighted judgment of the situation described in detail for each of the
processes in the remainder of the stations. Included is a "most likely"
value which represents a judgment of the central value of the range.
Regions of the country referred to in Table 3-2 have been established
based on sulfur content of coal available in that region (see Section 5.6)
Table 3-3 uses the "most likely" values as a basis to break down
further the process energy consumption:
• by location in the process stream (pre-plant, in-plant, post-
plant) Table 3-3a; and
• by form in which energy is consumed (oil/gas, coal, elec-
tricity) Table 3-3b.
The term oil/gas, as used in this report, refers to transportation
related fuels as well as residual oil or natural gas. The remainder of
this section discusses the energy requirements of each of the environ-
mental controls using the format of Table 3-1.
3.1 Pre-plant Energy Requirements
Compliance with environmental regulations, or the application of
environmental controls, at fossil fuel power plants can require the
additional expenditure of energy for some aspect of extraction, trans-
port, or treatment before fuel or control chemicals reach the power
plant. This section describes the processes involved and estimates the
energy requirements for pre-plant processes listed in Table 3-1.
3-5
-------
TABLE 3-2
PROCESS ENERGY REQUIREMENTS IN PERCENT
OF TOTAL PLANT ENERGY CONSUMPTION
Low Most Likely High
SO Control
Scrubber 3.0 4.0 7.0
Coal Washing 4.0 7.0 10.0
Low Sulfur Coal Transportation
Region B* 3.0 4.0 5.0
Region C 4.0 5.0 6.0
Blending
(Regions B and C) 0.5 1.0 2.0
Oil Desulfurization 3-6**
Waste Heat Control
Design 1.0 1.5 2.0
Retrofit 2.0 3.0 4.0
Particu1ate Control
Electrostatic 0.2 0.3 0.4
Mechanical ^0.0 'VO.O ^0.0
*Regions defined in Figure 3-2.
**0il desulfurization energy requirements depend on such factors as refinery
type, feedstock, and product fuel mix.
3-6
-------
TABLE 3-3a
BREAKDOWN OF UNIT PROCESS ENERGY REQUIREMENTS BY
LOCATION IN SYSTEM IN PERCENT TOTAL PLANT ENERGY
CONSUMPTION (BASED ON "MOST LIKELY" VALUES OF TABLE 3-2)
Pre-plant In-Plant Post-Plant Total
SO,, Control
2. " "~* *— *•'••'«
Scrubber
Coal Wash
Low Sulfur Coal
Transport
to B
to C
Blending
Oil Desulfurization
Waste Heat Control
Design
Retrofit
Particulate Control
0.5
7
4
5
1
3-6
0
0
3
0
0
0
0
0
1.5
3.0
0.5
0
0
0
0
0
0
0
4.0
7.0
4.0
5.0
1.0
3-6
1.5
3.0
Electrostatic
0.3
TABLE 3-3b
BREAKDOWN OF UNIT PROCESS ENERGY REQUIREMENTS BY FUEL
IN PERCENT TOTAL PLANT ENERGY CONSUMPTION (BASED ON
"MOST LIKELY" VALUES OF TABLE 3-2)
Oil/Gas
Coal
Particulate Control
Electrostatic
0.3
0.3
Electricity Total
S00 Control
Scrubber
Coal wash
Low Sulfur Coal
Transport
to B
to C
Blending
Oil Desulfurization
Waste Heat Control
Design
Retrofit
0.5
0
4.0
5.0
1.0
3-6
»
0
0
0
7.0
0
0
0
0
0
0
3.5
0
0
0
0
0
1.5
3.0
4.0
7.0
4.0
5.0
1.0
3-6
1.5
3.0
0.3
3-7
-------
TABLE 3-4
ENERGY REQUIREMENTS FOR THE EXTRACTION OF COAL
Energy
Type of Coal Requirement*
Extraction (percent) Reference
Unspecified 0.8 [CEQ, 1973]
Surface Mine 0.73 [CA, 1975a]
Surface Mine 0.5 [Energy, 1975]
Surface Mine 1.4 [Energy, 1975]
Underground Mine 0.4-0.6 [Energy, 1975]
''Energy Requirement is expressed as a percent of the energy value
of the coal being extracted.
3-8
-------
Coal Extraction
All fossil fuels require some expenditure of energy to obtain them
from their naturally occurring states irrespective of environmental
considerations. These energy requirements vary not only by fuel type
but by geographic location and extraction process. These energy require-
ments are considered outside the scope of this study, with one exception.
The substitution of low sulfur (i.e., western low Btu) coal for high
sulfur (high Btu) coal involves a larger energy requirement due to the
lower heating value per pound extracted. To produce the same number of
Btu's, more coal must be mined and thus more energy expended. This
additional energy requirement, however, is negligible because the ancil-
lary energy needed to extract the coal is only a small portion of the
energy contained in the coal. Several values of estimates of the
energy requirements for the extraction of coal are presented in Table 3-4.
Oil/Gas
We were not able to identify any significant energy consumption for
extraction related to environmental control.
Control Chemical Extraction
The application of flue gas desulfurization (FGD) systems for the
control of sulfur oxides requires the use of lime, limestone, or other
control chemicals. Lime is obtained from the calcining of limestone, so
the extraction of limestone for use in the FGD process is included as an
energy requirement. The energy consumption for the mining of limestone
has been estimated at 90,000 Btu per ton of output (Haller, 1975). This
value reflects a national average value and there will be significant
regional variation depending on the hardness of the limestone being
extracted. The determination of energy requirement depends on the ratio
of tons of limestone to coal for the operation of the FGD system. This
ratio varies according to the efficiency of the chemical reaction as
well as the quantity of sulfur dioxide being removed. Figure 3-1
displays the material and energy balances for a specific FGD system
utilizing limestone as the sorbent. The energy requirement for lime-
stone mining in this case represents 0.05% of the energy input to the
boiler.
3-9
-------
MATERIAL BALANCE ; tons/hour
Cooling Water ——
Fuel
454.5
69.7
Limestone
Water Discharge
Power Plant
Electricty
Sludge
ENERGY BALANCE : Btu/hour
Cooling Water
Fuel
1.0 x 10
10
Water Discharge
\ /
Power Plant
Electricity
Limestone
6.27 x 10
\ Sludge
Basis: 1.0 x. 10 Btu/hour, energy input to boiler.
Assumptions:
3.5% sulfur coal, 11,000 Btu/lb.
85% sulfur removal by limestone scrubbing at 165% stoichiometry
Figure 3-1 Material and Energy Balances for FGD System
Utilizing Limestone as Sorbent.
•5-If)
-------
Transport
Coal
While the general transportation of fuels has no energy consumption
for environmental purposes within the context of this study, the substitution
of low sulfur western coal for higher sulfur eastern coal will require
additional energy for fuel transport for two reasons. First, the western
coal will need to be transported over a greater distance than the eastern
coal would to reach the eastern markets. Secondly, the energy consumption
for the transport of western coal, per ton-mile, is greater than that
for eastern coal, when expressed as a percent of the.energy value of the
coal being transported, because western coal is typically of lower heat
content. Coal can be transported by several modes including train,
truck, barge, and slurry pipeline. The energy requirements for each of
these modes is presented in Table 3-5. These energy requirements are
for the consumption of diesel fuel except for slurry pipelines, which
use electricity. Estimates of the heat content for western and other
coals appear in Table 3-6. Assuming a value of 9,300 Btu/pound for
western coal and 11,800 Btu/pound for eastern coal, this yields an
additional hauling requirement of almost 27 percent more tons for the
same Btu content of the fuel. For an energy requirement of 680 Btu/ton-
mile transport of western coal, a distance of 1,000 miles consumes the
equivalent of 4 percent of the coal-heating value.
In order to categorize more easily the transportation requirements
for coal, the United States has been divided into three regions. These
are shown on Figure 3-2. Region A is an area where low sulfur coal is
available. Region B is an area with relatively little low sulfur coal
and to which such coal must be transported for use by utilities. Since
distances of about 1000 miles are involved, a "most likely" penalty of
4 percent will be used in calculations. Region C, west and east coasts,
does not contain appreciable low sulfur coal available to utilities
(low sulfur anthracite is used for metallurgy). Transport costs but
not heat value reduction must be added for Region C and a "most likely"
energy consumption of 5 percent is used.
3-11
-------
TABLE 3-5
ENERGY REQUIREMENTS FOR THE TRANSPORT OF COAL
Energy
Mode Of Requirement
Transport (Btu/ton-mile") Reference
Train 680 [Ford, 19751
Train 680 [Rice, 1970]
Train 690 [Energy, 1975]
Train 670 [Haller, 1975]
Truck 966 [Energy, 1975]
Truck 2,800 [Haller, 1975]
Truck 1,600 [DOT-EPA, 1975]
River Barge 378 [Energy, 1975]
Pipeline (Slurry) ^400 [Energy, 1975]
TABLE 3-6
HEAT CONTENT ESTIMATES FOR WESTERN AND OTHER COALS
Heat Content
Coal Region (Btu/pound) Reference
Northwest 8,780 [Hittman, 1974]
Southwest 9,820 [Hittman, 1974]
Western 9,235 [Battelle, 1973]
Eastern 12,000 [Battelle, 1973]
Central 10,600 [Hittman, 1974]
Northern Appalachia 11,800 [Hittman, 1974]
Central Appalachia 12,100 [Hittman, 1974]
3-12
-------
Figure 3-2 Coal Regions of the United States
-------
Control Chemicals
Power plants using FGD systems for the control of sulfur dioxide
have an energy requirement associated with the transport of the control
chemical employed. The energy requirement is dependent on the quantity
of chemical needed and the distance which it must be transported. For
truck transport, assuming an average 1,800 Btu/ton-mile (see Table 3-5],
over a distance of 200 miles, the hypothetical FGD system displayed in
Figure 3-1 would need an energy of 0.18 percent of the energy input to
the boiler. This energy requirement is in the form of diesel fuel,
which is petroleum based.
Pretreatment
Residual Oil Desulfurization
The pretreatment of residual oil to reduce its sulfur content in-
volves additional processing at,the refinery. This sulfur reduction can
be achieved by either the desulfurization of heavy fuel oils, the
blending of untreated heavy fuel oils with other specific refinery
products of low sulfur content, or a combination of the two. Only
recently have domestic refineries begun to develop processes for the
desulfurization of residual oils. This increase in heavy oil desulfurization
is occurring in response to increased limitations of sulfur content
being placed on refinery products, and increased dependence on high
sulfur foreign crude.
The hydrodesulfurization of residual oils is based on the reaction
of hydrogen with sulfur-containing compounds to form H S and a desulfur-
ized product. In order for the hydrogen to achieve effective mass
transfer with the residual stock, this reaction requires high pressure
and temperature in the presence of a catalyst. The resulting hydrogen
sulfide gas, which is mixed with hydrocarbon gases, is circulated
through a packed column in which an amine solvent absorbs the hydrogen
sulfide and permits the recovery of the hydrocarbon gases. The amine
solvent is then regenerated in a distillation column and the hydrogen
sulfide removed. The hydrogen sulfide can then be processed in a Claus
plant to produce elemental sulfur.
3-14
-------
Energy is consumed in this process for the generation of hydrogen,
the heating and pressurizing of hydrogen and residuum, the regeneration
of the amine solution and the additional heat needed by the Glaus
plant. The Glaus process consists of the oxidation of one-third of the
H2S to S02 and then catalytically combining the remaining H S with the
S02 to form water and free sulfur. Although the oxidation of H?S is
exothermic, it is necessary to supply additional heat to both reactions.
The energy requirement associated with fuel oil desulfurization has
been reported to be roughly from 3.5 to 5.8% depending upon the type of
feed and extent of desulfurization (Ford, 1975). This estimate includes
the complete processing of the H S so that sulfur from the oil leaves
the process in a pure, elemental form. An estimate of the energy
requirement associated with the desulfurization of 4.02% sulfur Kuwait
atmospheric residual to 1.0% sulfur is reported to be 2.07% [HP, 1974).
This estimate, however, does not include the energy consumption for the
generation of hydrogen or the conversion of t-LS into elemental sulfur.
Including these additional energy requirements to this estimate would
put it in the range of the above estimate. This study has used the
range 3-6%.
Coal Cleaning (Physical)
The commercial availability of the physical cleaning of coal for
the removal of sulfur is still in the early stages of development.
However, the physical cleaning of coal to reduce ash forming impurities
has been in use for many years. In addition to removing ash, the coal
cleaning process potentially provides several other benefits:
• Concentration of carbon in the clean coal. This is important
because the carbon content of the feedstock will determine the
heating value and hence the capacity of a boiler limited coal-
fired power plant. The lower the heating value, the more coal
is needed and the limit of coal accepted in the boiler is soon
reached. Therefore, with coal cleaning instead of low sulfur-
low Btu coal, the capital energy requirements can be minimized
for any capacity of unit built. In addition, the energy
requirement for transportation is reduced due to the higher
Btu content per ton.
3-15
-------
• Reduction in concentration of trace elements. This in turn
can reduce corrosion effects and reduce transient energy
requirements for boiler downtime.
• Uniform quality of product including ash, moisture, and Btu
content. This is an advantage for controlling any combustion
process.
The most highly developed coal cleaning process to date is the two-
stage froth flotation process which can remove over 90% of the pyritic
sulfur in fine-size coals. The process involves a first-stage standard
coal flotation step to remove high-ash refuse and some of the coarser
pyrite as tailings. The first-stage froth concentrate is then retreated
in a second bank of flotation cells in the presence of a coal depressant
and a xanthate flotation collector to selectively float the remaining
pyrite.
Energy is consumed in this process to crush and screen the coal,
move the coal components through the beneficiation system, remove water
from the coal, and operate emission control equipment. In addition, the
Btu content of the coal that ends up in the rejected refuse stream needs
to be inventoried as an energy requirement. The energy content of this
reject stream, however, has the potential for being reclaimed, which
would reduce the energy requirement attributable to coal preparation.
The energy requirement for the operation of a coal preparation
plant is reported to be about 0.2% of the energy of the coal being
prepared (Hittman, 1974) . This estimate included only thermal drying
for a small portion of the coal being treated. Cleaning of coal fines
will require more thermal drying which increases energy requirement to
about 1%. Several estimates for the loss in Btu content due to coal
cleaning appear in the literature; these estimates are summarized in
Table 3-7. The thermal loss in cleaning for the removal of pyritic
sulfur will, of course, depend on the degree of sulfur removal achieved
which is, in turn, dependent on the size of the particles of pyrites,
and the ratio between pyritic and organic sulfur.
3-16
-------
TABLE 3-7
ESTIMATES OF BTU CONTENT LOSS DUE TO PHYSICAL COAL CLEANING
Energy Requirement
Process (percent of fuel
Description heating value) Reference
Coal Washing 2.7-3.5 [Energy, 1975]
Froth Flotation 15 [Hittman, 1974]
Coal Cleaning 5.85 [Lovell, 1975]
Coal Cleaning 5-7 [EPA, 1975a]
Coal Cleaning 12 [CEQ, 1973]
Coal Washing 10 [Mitre, 1974]
Coal Cleaning (with sig-
nificant total sulfur
reductions) 20-30 [Mitre, 1974]
3-17
-------
Because coal washing for the removal of sulfur is still a devel-
oping technology, it can be expected that the energy requirement for its
practice will be different in 1983 than it was in 1974. For this
reason, we determine different values of the energy requirement associated
with coal washing for the two years under consideration.
For 1974, we base our estimate on the work of Lovell (1975), who
reports that utility coal which received pretreatment in this period can
be classified into two levels of preparation:
Level A - Removal of gross, noncombustible impurities, but control
of particle size and promotion of uniformity. Ninety-
five percent material yield and 99% thermal recovery.
Little change in sulfur content.
Level B - Single-stage beneficiation following minimal component
liberation. Particle sizes less than 3/8 inch usually
not prepared. Eighty percent material yield and 95%
thermal recovery. The sulfur removed varies with dif-
ferent coals, but is approximated as follows:
Raw Coal Percent
Sulfur Cleaned Sulfur
Region/States Percent Coal Removal
Northern Appalachia 3.07 1.96 36
Southern Appalachia 0.93 0.81 13
KY (West), In, IL 3.92 2.72 31
OK, KN, MO, 10, AR 3.72 2.15 42
The energy requirement for the use of coal washing to remove sulfur
in 1974 is taken to be the additional thermal loss experienced in going
to Level B cleaning as opposed to Level A cleaning. This energy require-
ment is equal to 4.0% additional thermal loss. The difference in
energy consumption for processing between the two levels of cleaning is
considered negligible.
New coal preparation facilities recently going on line or in the
planning are reported to provide Btu recoveries well in excess of 90%
(Deurbrouck, 1974), that is, an energy loss of less than 10%. In
addition, a newly developed process for removing sulfur from coal prior
3-18
-------
to combustion is reported to remove about 5.0% of the coal itself
(Hammond, 1975). These values of thermal losses from physical coal
cleaning establish a range of 4.0 to 10.0% as the energy requirement for
coal cleaning to remove sulfur in 1983.
Coal Cleaning (Chemical)
Chemical coal cleaning processes are in the developmental stages,
but these processes are potentially attractive since preliminary infor-
mation indicates that they may remove organically bound as well as
pyritic sulfur. Sulfur is removed from the coal by reaction with
hydrogen. One process under development is solvent refining which mixes
pulverized coal with a solvent, heats the mixture, and then introduces
hydrogen to produce a product with an ash content of 0.1%, a sulfur
content of less than 1.0%, and a calorific value of 16,000 Btu/pound.
As with physical coal cleaning, there will be an energy loss due to some
of the Btu content of coal leaving the process in a refuse stream. This
loss in Btu content is reported to be about 30 to 35% with an additional
energy requirement of about 7% to operate the process (Energy, 1975).
Coal Conversion
Several technologies for converting coal to either a gas or liquid
are currently being developed. The generation of electricity using low
Btu gas from these processes would only realize a 20 to 30% electrical
energy conversion efficiency (EPA, 1975a). Higher pressure combined
cycle systems are under development that have the potential for overall
cycle efficiencies competitive with those of conventional fossil-fuel
fired power plants. Coal conversion and chemical coal cleaning technologies
are not expected to be widely available within the time frame of this
study, i.e., prior to 1983.
Control Chemical
For power plants employing flue gas desulfurization systems which
use lime as the sorbent the energy consumption involved in the calcining
of limestone to lime needs to be counted. The Bureau of Mines completed
a comprehensive canvass of energy used in lime plants in 1973 which
3-19
-------
determined that 6.57 million Btu per ton are required for the production
of lime (Minerals, 1973). This survey also reported that the lime
industry depended on the use of coal and natural gas for most of its
energy requirements. Coal supplied 46% and natural gas 45% of the total
energy used, mostly for heat in the calciners. The choice of fuel for
individual plants was usually based on geographic proximity to supplies,
price, and availability of long-term contracts. The quantity of lime
required for use in a FGD system varies according to the efficiency of
the chemical reaction as well as the quantity of sulfur dioxide being
removed. Figure 3-3 depicts the material and energy balances for a
typical FGD system using lime as a sorbent. The energy requirement, for
the preparation of lime represents 1.98% of the energy input to the
boiler.
3.2 In-plant Energy Requirements
Compliance with environmental regulations, by the application of
environmental controls at fossil fuel power plants can require the
additional expenditure of energy beyond that normally needed for the
operation of the power plant. This section describes the control
processes involved and estimates an energy requirement for each option
at the plant site.
Sulfur Dioxide Removal
The in-plant control of sulfur dioxide emissions is primarily
accomplished by the application of flue gas desulfurization (FGD)
systems. There are two basic categories of FGD systems, nonregenerable
(throwaway) systems which yield a significant waste stream, and regener-
able systems which yield a saleable product of either sulfuric acid or
elemental sulfur.
The most highly developed and widely utilized nonregenerable FGD
system is the lime or limestone process. The application of either of
the se flue gas desulfurization processes can require energy for stack
gas reheating and electricity to run the process equipment. The stack-
gas exit temperature for a new coal-fired electric power plant can be
reduced from 300°F to 125°F by the application of a flue gas scrubbing
3-20
-------
MATERIAL BALANCE ; tons/hour
Cooling Water
\ Z
Water Discharge
454.5
Power Plant
Limestone
30
60.6
.J7
Electricty
Sludge
ENERGY BALANCE : Btu/hour
Cooling Water
Fuel
-0 * 1Q
10
Limestone
1.98 x 10
Water Discharge
\ /
Power Plant
Electricity
/ /\ Sludge
Basis: 1.0 x 10 Btu/hour, energy input to boiler.
Assumptions:
3.5% sulfur coal, 11,000 Btu/lb.
85% sulfur removal by lime scrubbing at 128% stoichiometry
Figure 3-3 Material and Energy Balances for FGD System
Utilizing Lime as Sorbent.
3-21
-------
system (Ellis, 1975). This reduction in stack-gas temperature will
decrease plume rise which in turn can increase ground level concen-
trations of sulfur dioxide. Therefore, many power plants reheat their
stack gases to reduce ground level concentrations. The process equip-
ment involved in the application of FGD systems includes fans to over-
come the pressure drop of the system and pumps to move the limestone or
lime through the system.
Several estimates of the energy requirements for the application of
nonregenerable flue gas desulfurization systems appear in the litera-
ture. Table 3-8 summarizes these estimates. The energy requirement for
stack gas reheating has been reported to be 2% of rated plant capacity
to achieve a reheat temperature increment of 50°F (Ellis, 1975).
Depending on the degree of reheat employed, this energy requirement can
be as low as 0% to a high of 7%. This latter extreme would occur if the
stack gases were reheated from 125°F to 300°F. Table 3-9 presents the
summary results of work done by Haller and Nordine for the Commerce
Technical Advisory Board Panel on SCL Control Technologies. The energy
requirement for stack gas reheating is 1.5%, and the energy requirement
for the operation of process equipment is 4.0% for limestone and 3.5%
for lime FGD systems. The limestone-based systems have a larger in-plant
energy requirement due to limestone grinding and additional material
handling requirements. An Edison Electric Institute/Clean Air Act
Coordinating Committee survey of approximately 40 installations yielded
an average energy consumption of 4.0%. The survey included both
regenerable and nonregenerable FGD systems.
In addition to operating energy requirements, the application of
FGD systems may result in a derating of plant capacity depending upon
whether the power production is turbine- or boiler-limited. If a plant
is turbine limited, the excess steam from the boiler can be used to
reheat the stack gases.
Regenerable FGD processes have additional energy requirements to
operate their sulfur recovery systems. Three systems for removing SO
from flue gases, in which the sulfur content is recovered either as
sulfuric acid or elemental sulfur, have been offered commercially:
1) sodium solution scrubbing - sulfur production
2) magnesium oxide (MgO) scrubbing - sulfuric acid production
3) catalytic oxidation - sulfuric acid production
3-22
-------
TABLE 3-8
ENERGY REQUIREMENTS FOR NONREGENERABLE FGD SYSTEMS
(percent]
FGD SYSTEM
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Limestone
Nonregenerable
Lime
Lime
Lime
Lime
Molten Carbonate
Nonregenerable
PLANT
Will County
-
-
Will County
Detroit Edison
Widows Creek
New Unit
Existing Unit
i
-
-
New Unit
Existing Unit
REHEAT
1.5
1.6
3.9
2.5
5.4
3.2
-
-
-
1.5
1.6
-
-
PFIOCESS
4.0
2.3
4.7
4.0
4.1
1.7
-
-
-
3.5
1.9
-
_
TOTAL
5.5
3.9
8.6
6.5
9.5
4.9
3.4
3.9
1.5 - 4
5.0
3.5
3.3
4.0
<1
3-6
REFERENCE
[Haller, 1975]
[EPA, 1973]
[Ford, 1975]
[Ford, 1975]
[Ford, 1975]
[Ford, 1975]
[Jonakin, 1975]
[Jonakin, 1975]
[PEDCo, 1975]
[Haller, 1975]
[EPA, 1973]
[Jonakin, 1975]
[Jonakin, 1975]
[Botts, 1972]
[EPA, 1975a]
-------
TABLE 3-9
SUMMARY OF ENERGY REQUIREMENTS FOR LIME AND
LIMESTONE FGD SYSTEMS (Haller, 1975)
Component
Pre-plant - Control Chemical
Extraction
Preparation
Transport
In-plant - Reheat
- Equipment
Post-plant - Fixating Agent
Extraction
Preparation
Transport
- Fixated Sludge
Transport
Total
Energy Requirement
(percent of plant energy)
Lime Limestone
0.054
1.98
0.085
1.5
3.5
0.017
0.64
0.027
0.082
7.9
0.063
0.195
1.5
4.0
0.029
1.09
0.046
0.093
7.0
3-24
-------
In sodium solution scrubbing, after removal of particulates either
by an electrostatic precipitator or water scrubbing, the flue gases are
washed with a recirculating solution of sodium salts in water for SO
absorption. The S02 is stripped from the scrubbing solution and sodium
sulfite precipitated by use of steam. The sodium sulfite is recycled to
the scrubber, and the concentrated SO is reacted with methane for
reduction to elemental sulfur.
In MgO scrubbing, the flue gases are scrubbed using a recirculated
slurry of MgO and reacted magnesium-sulfur compounds in water for
removal of S02. A portion of the slurry is bled off for solids separa-
tion. The salt crystals (MgSO and MgSO ) are removed from the liquid,
•J T"
dried and calcined to form SO and MgO for recycling. The SO is fed to
a contact sulfuric acid plant.
In catalytic oxidation, fly ash is removed from the flue gas by a
hot electrostatic precipitator; then the S0_ is catalytically converted
to SO , which combines with moisture in the flue gas to form sulfuric
acid mist. The acid mist is removed in a packed tower scrubber using a
recycled sulfuric acid stream to produce sulfuric acid.
Table 3-10 summarizes the reported estimates of energy requirements
for the operation of regenerable FGD processes. In addition to these
three processes, several other regenerable processes, such as sodium
citrate scrubbing and ammonium scrubbing-ammonium bisulfite regenera-
tion, are in various stages of development. In general, the use of a
regenerable process, as opposed to a nonregenerable FGD process, will
entail an additional energy requirement of 3% for in-plant energy con-
sumption. Nonregenerable FGD systems, however, will have additional
energy requirements for sludge disposal operations. For the purposes of
this study, the energy requirements of only nonregenerable FGD systems
were considered.
Particulate Removal
The in-plant control of particulates at fossil fuel power plants is
primarily accomplished by the application of either electrostatic
precipitators or multiple cyclone mechanical collectors. The energy
requirements for these two types of equipment are different because
their collection techniques and efficiencies are different. Electrostatic
3-25
-------
REGENERABLE
PROCESS
Sodium Solution Scrubbing
Sodium Solution Scrubbing
Sodium Solution Scrubbing
Magnesium Slurry
Magnesium Slurry
Magnesium Slurry
Magnesium Slurry
Catalytic Oxidation
Catalytic Oxidation
Catalytic Oxidation
TABLE 3-10
ENERGY REQUIREMENTS FOR REGENERABLE FGD SYSTEMS
PRODUCT
ADDITIONAL
ENERGY REQUIREMENT
FOR RECOVERY PROCESS
(percent)
Sulfur
Sulfur
Sulfur
Acid
Acid
Sulfur
Acid
Acid
Acid
Acid
^ j- „
3
3
-
3.5
5.5
3
3
3
_
TOTAL
ENERGY REQUIREMENT
FOR RECOVERY PROCESS
(percent)
&.fr - 9.6
5.5 - 5.6
0 - 6.9
REFERENCE
[Jonakin, 1975]
[EPA, 1975a]
[PEDCo, 1975]
[Jonakin, 1975]
[EPA, 1973]
[EPA, 1973]
[PEDCo, 1975]
[EPA, 1975a]
[PEDCo, 1975]
[Jonakin, 1975]
-------
precipitators incorporate one or more high intensity electrical fields
to impart an electrical charge to particles in the flue gas which are
then attracted to a collecting surface maintained with an opposite
charge. Since the collecting force is applied only to the particles,
not to the gas, the pressure drop of the gas is only that of flow
through a duct having the configuration of the collector. Hence pressure
drop is both very low and does not tend to increase with time. In
general, collection efficiency increases with length of passage through
an electrostatic precipitator. Therefore, additional precipitators
sections are employed in series to obtain higher collection efficiencies.
Mechanical collectors rely on gravity and inertial forces for their
operation so it is necessary to make the gas flow spin. Cyclone col-
lectors consist of a cylindrical chamber into which the flue gas stream
is directed at an angle near the top. The unit is constructed so that
the gas stream whirls downward with increasing rapidity toward a cone-
shaped base. Centrifugal force ejects the entrained particles out of
the spinning gas stream onto the wall of the chamber. From there they
fall into a collecting hopper while the air stream then swirls upward
through a tube in the center of the unit. Depending on design, cyclone
collectors can remove particles as small as 3 microns, although high-
efficiency collection cannot be expected for particles under 15 microns.
Power plants with mechanical collectors usually use multiple cyclones,
which consist of several low-capacity units in place of a single larger
one, because they can increase collection efficiency without using more
energy.
Several estimates of the energy requirements for particulate con-
trol equipment appear in the literature and are summarized in Table 3-11.
Several of these estimates appear in terms of either kilowatts or horse-
power per thousand cubic feet per minute through the unit. This energy
requirement can be recalculated into a percent of the power plant elec-
trical output by using representative operating parameters. Because the
energy requirement is expressed as a percent, it is equivalent to
express it as a percent of the plant electrical output or the plant
boiler heat input. A 1% increase in fuel consumption will yield a 1%
increase in electricity consumption (see Appendix C).
3-27
-------
00
TABLE 3-11
ENERGY REQUIREMENTS FOR PARTICULATE CONTROL EQUIPMENT
EQUIPMENT TYPE
Multiple Cyclones
Cyclone
Electrostatic
Precipitator
Electrostatic
Precipitator
Electrostatic
Precipitator
Venturi Scrubber
Venturi Scrubber
Smallest
particle
collected
(y)a
5
10
0.2
<0.1
-
-
1
Pressure
drop
(inches h^O)
2-10
0.1-0.5
-
-
10-15
ENERGY REQUIREMENTS
(kw/1000 cfm)b
0.5-2
1.2
0.75
0.2-0.6
-
-
2-10
(% plant output)
Reference
!
; .
0.2-0.9 : Stern, 1968
0.5C
0.3C
0.1-0.3°
0.1
1-2
0.9-4.3°
Teller, 1972
Teller, 1972
Stern, 1968
Oglesby, 1970
PEDCo, 1975
Stern, 1968
aAfith 90-95 percent efficiency by weight
Includes pressure loss, electrical energy
c Calculated assuming: 0.0489 Ib flue gas/cfm § 350°F, coal @ 11,000 Btu/lb, 37 percent plant thermal
efficiency, and 15 Ib flue gas/ Ib fuel
-------
The energy requirements actually used in this study are based on
the industry survey results contained in Appendix A. The sample reported
an average of 0.30% additional energy consumption for the operation of
electrostatic precipitators and a negligible amount for multiple cyclones.
Nitrogen Oxides Removal
The control of nitrogen oxides emissions from fossil fuel-fired
power plants relies primarily on the application of combustion modifi-
cation processes. The objective of these processes is to lower NO
A.
formation during combustion. An alternative approach, which may be
capable of much higher levels of NO control, is post-combustion removal
A.
of NO^ from the flue gases. This technique is at an earlier stage of
development.
Combustion modification techniques are designed to reduce the flame
temperature in the boiler, which is the key factor in NO formation in
X.
boilers (Aghassi, 1975"). Two such modification techniques are flue gas
recirculation and over-fire air, which is also described as two-stage
combustion. It should be noted that recirculation is often used to
improve combustion efficiency irregardless of its NO formation effects.
A.
Flue gas recirculation lowers the flame temperature of combustion
by reducing the overall sensible heat of the flue gas by dilution. A
portion of the flue gas, usually between 15 and 20%, is recirculated
through the burners along with the combustion air. This technique
requires additional fan power and could result in a 10 to 20% decrease
in load capacity in existing units due to increased gas flow rates. The
over-fire air method lowers flame temperature by burning the fuel in two
stages so that all the heat is not liberated at once. This is accom-
plished by burning the fuel in less than stoichiometric air conditions
in the burner zone. At the same time, the remainder of the stoichio-
metric air is introduced, along with the excess air, through over-fire
ports above the burner zone where the rest of the fuel is consumed.
Over-fire air is the least expensive technique for controlling N0x,
incurring no loss in unit efficiency or increased operating expenses.
3-29
-------
Thermal Pollution Control
The steam electric power plant category employs three general types
of circulating water systems to reject the waste heat from the power
plant. These systems are: (1) once-through cooling; (2) once-through
with supplemental cooling of the discharge; (3) closed-cycle systems.
The use of once-through cooling results in the discharge of the
entire amount of waste heat to the receiving body of water. The control
of thermal effects resulting from once-through cooling is often accom-
plished through the use of diffuser discharge structures, which result
in increased, rapid thermal mixing in the receiving body of water.
Since once-through circulating systems tend to have lower circulating
water temperatures than closed-cycle systems, power plants with once-
through systems generally have the best plant efficiencies. For the
purposes of this study, the employment of once-through cooling systems
is assumed to be a base case condition, with an associated fuel energy
consumption from environmental controls of 0%.
In certain cases, supplemental heat removal systems (such as cooling
towers) are placed in a once-through circulating flow path to reduce the
total waste heat discharged to the receiving water body due to environ-
mental considerations. The use of cooling towers for supplemental
cooling generally results in the operation of the cooling tower in an
open-cycle mode in the winter and closed-cycle mode in the summer, hence
such supplemental heat removal systems are frequently called semi-closed
systems.
Several types of closed-cycle cooling systems are used for waste
heat disposal, all of which consume energy in excess of that required by
once-through cooling systems. Closed systems recirculate water first
through the condenser for heat removal, and then through a cooling
device where this heat is released to the atmosphere, and finally back
to the condenser. Three basic methods of heat rejection are used. The
one of most commercial significance in the power industry is wet [evap-
orative) cooling, using cooling towers. A second method of closed
system cooling is the use of cooling ponds, which are normally arti-
ficial lakes constructed for the purpose of rejecting the waste heat
from a power plant. The use of cooling ponds consumes additional energy
3-30
-------
needed to compensate for the decreased thermal efficiency which results
from elevated condenser temperatures. They require a very large amount
of land for satisfactory operation.
Dry cooling towers, in which heat is transferred by conduction and
convection, have found very limited use thus far in the fossil fuel
power plant industry.
Spray systems can be utilized to reduce the large area required by
cooling ponds. Spray ponds or canals consume energy for, the pumping of
water through the spray nozzles in addition to any energy needed to
compensate for decreased thermal efficiency of electrical generation
resulting from increased turbine backpressure.
The operation of cooling towers requires energy to pump the cooling
water back and forth between the towers and the condensers. In addi-
tion, mechanical draft towers consume electricity to operate fans which
blow air through the towers. Finally, increased turbine backpressure
due to the use of cooling towers results in additional fuel requirements
per kilowatt-hour of electricity generated because of lower thermo-
dynamic efficiencies. Natural di*aft wet towers may require a larger
energy requirement than mechanical draft towers, in spite of the fact
that no fans are needed, because of a greater increase in turbine back-
pressure. Dry cooling towers, which consist of an air cooled heat
exchanger mounted inside a cooling tower chimney, have an energy require-
ment which is higher than wet towers due to a still greater increase in
design turbine backpressure.
Several estimates of energy requirements for closed-cycle cooling
systems appear in the literature; these values are summarized in Table 3-12,
For the purposes of calculating 1974 environmental energy consumption,
the energy requirements used for the application of closed-cycle cooling
systems to the base year population are listed below.
Energy Requirement
Type of Cooling Method (percent)
Once-through °-°
Cooling ponds !-°
Spray ponds and semi-closed 1.3
Mechanical draft towers 2.5
Natural draft towers 2.5
3-31
-------
Ol
I
if)
COOLING
SYSTEM
Closed-Cycle Cooling
Spray Units
Wet Cooling Tower, New
Wet Cooling Tower, Retrofit
Mechanical Draft Wet Tower
Mechanical Draft Wet Tower
Mechanical Draft Wet Tower
Natural Draft Wet Tower
Natural Draft Wet Tower
Natural Draft Wet Tower
Dry Cooling Tower » New
Dry Cooling Tower , New
Dry Cooling Tower , New
TABLE 3-12
ENERGY REQUIREMENTS FOR CLOSED-CYCLE COOLING SYSTEMS
ENERGY
REQUIREMENT
(Percent]
3.0
1.3
1.0
2.5 - 3
l.'O
2.0
2.7
2.0
3.0
4.5
5.0 - 10.0
6.0
4.0
REFERENCE
[Ford, 1975]
[EPA, 1974a]
[EPA, 1973a]
[EPA, 1973a]
[Hirst, 1973]
[Dynatech, 1969]
[EPA, 1974a]
[Hirst, 1973]
[Dynatech, 1969]
[EPA, 1974a]
[EPA, 1973a]
[Hirst, 1973]
[Dynatech, 1969]
-------
Wastewater Pollution
Power plants produce several diverse wastewater streams with different
pollutants and different flow characteristics. Frequently, the most
feasible concept of treatment consists of the combination of all compa-
tible wastewater streams, with equalization or holding tanks to equalize
the flow through the treatment units. Figure 3-4 shows a typical flow
diagram for a central treatment plant for coal-fired power plants.
Wastewater treatment facilities for treating power plant chemical
wastes, therefore, consist essentially of a series of tanks, pumps, and
interconnecting piping, with additional special equipment such as
pressure filters, vacuum filters, centrifuges, or incinerators added
as may be required.
The energy consumed for the treatment of chemical wastes at power
plants is reported not to be of significant consideration (EPA, 1974a).
Most of the processes used for the treatment of chemical wastes
require no input of energy other than that required for conveying the
liquid. Some of the processes involved in the technology for achieving no
discharge of pollutants involve a change of state from the liquid phase
to the vapor phase, and others such as vacuum filters and reverse osmosis
require substantial mechanical energy. However, these processes are
generally applied to only a small portion of the total wastes, so that
the overall effect is negligible. Based on the flow diagrams for a
central chemical wastes treatment plant and for complete treatment
facilities designed to achieve no discharge of pollutants, the estimated
energy requirements for central waste treatment are less than 10 Kw per
10Q,OOQ Kw of plant capacity, or less than 0.01 percent of the plant
output (EPA, 1974a). For complete treatment and reuse, including steam
evaporation to dry material for ultimate disposal, the energy requirements
are less than 0.2 percent of the plant output. For plants capable of
achieving no discharge by utilizing evaporation ponds, energy requirements
are about 0.04 percent of the plant output (EPA, I974a).
Plant Conversion
The environmental energy consumption associated with plant modifica-
tion is concerned with changes in the overall energy efficiencies of the
3-33
-------
O)
I
BOILER TUBE
1
2
O
I-
UJ
&
O
90 gal/mw
(0.25 gpd/mw)
BOILER FIRESIDE
800 gal/mw
(4.44 gpd/mw)
AIR PREHEATER
700 gal/mw
(11. 7 gpd/mw)
MISC, 210 gal/mw
«~—
EQUALIZATION
TAN MM
1800 gal/mw
(1.1 7 gpd/mw)
ION EXCHANGE
52 gpd/mw
FLOOR DRAINS
30 gpd/mw
LIME 7.2 x 10"^-"
gal
(0.013 Ib/day/mw)
REACTOR
(0.8 gal/mw)
1 HR. DETENTION
18 gal/mw
pH-3 (assume)
PH 8.5
-S3*,
88 gpd/mw
LABORATORY WASTES
10 gpd/mw
COOLING TOWER
BASIN WASHING
(210 gal/mw!
1.17 gpd/mw
RECIRCULATING
SCRUBBER 20 gpd/mw
BOILER SLOWDOWN
B».i
EQUALIZATION
TANK** 2
380 gal/mw
172 gpd/mw
FLOCCULANTS
•lib/1000 gal
(0.13lb/day/mw)
l-§
^
1% SLURRY
20LB/DAY/MW
(3.0 gpd/mw)
30 gpd/mw
DISCHARGE TO
RECEIVING WATERS
SL'JpGE
(0.2 ib/day/mw)
Figure 3-4 Flow Sheet - Coal Fired Central Treatment Plant From: EPA, 1974a
-------
generation of electricity by substituting different fuels or processes
in conjunction with environmental controls or regulations. The fuel
switches evaluated for changes in in-plant energy consumption include
the substitution of low sulfur western coal for higher sulfur eastern
coal, the conversion of oil- or gas-fired units to burn coal, and the
use of supplemental fuel from solid wastes. The process variations
evaluated include the use of fluidized bed combustion as opposed to
traditional boiler configurations, improvements to power plant effici-
ency, and the use of total energy systems.
The Substitution of Low Sulfur Western Coal
The substitution of low sulfur western coal for higher sulfur
eastern coal will require more energy for all aspects of fuel handling
due to the typically lower heat content of western coals. Assuming an
energy requirement of four percent to operate the boiler feed pumps and
fans in the power plant (PEDCo, 75) and a 25 percent increase in fuel
handling requirements due to the substitution of lower heat content
western coal, the additional energy requirement for the operation of the
plant would be about 0.5 percent. In addition, the use of lower heat
content fuel could cause a capacity derating if the boiler were limited
in the number of pounds per hour of fuel that it could burn.
Coal Conversion
The conversion of oil- or gas-fired power plants to burn coal will
result in differing energy impacts depending on whether or not the burn-
ing of coal is compatible with the boiler configuration. Some plants
currently burning oil or gas can be converted to burning coal by minor
equipment changes or maintenance, and these plants would require a neg-
ligible capacity derating or additional energy requirement for their
operation, In some cases, however, there would be a period of downtime
required to effect these changes.
Some boilers currently burning oil or gas cannot be converted to
burn coal without a significant decrease in their thermodynamic effic-
iency. These plants can continue to operate but they will experience
both a capacity derating and increased energy requirements due to the
3-35
-------
decreased thermodynamic efficiency. Alternatively, the boilers can be
replaced with new coal fired units. This change of equipment will cause
a period of downtime during which the electricity normally generated by
the plant will have to be obtained from another power plant or generating
network. If this electricity is generated by a unit of lower efficiency
or at some significantly greater distance than the existing plant to the
area of electrical consumption, then there will be an additional transient
energy requirement during this period.
Supplemental Fuel from Solid Wastes
The use of shredded solid wastes as a supplemental fuel in fossil
fuel fired power plants has the potential to reduce energy consumption
for the generation of electricity and the disposal of solid wastes. In
this approach, solid wastes which have been sorted to reclaim recyclable
materials and eliminate noncombustibles are shredded and fed to utility
boilers with ash-handling facilities as a supplement to the fossil fuel
being burned. The energy requirements for this system are involved in
the solid waste processing. There are, however, several energy benefits.
The energy requirement for the disposal of the solid wastes is eliminated,
the energy content of the solid wastes is recovered, and for the fossil
fuel that is replaced by the solid wastes, the energy for extraction,
processing, and transportation of that quantity of fossil fuel is eliminated.
The combustion of solid waste for electric power production has
important environmental impacts in the air pollution and solid waste
areas. Thermal pollution is not affected, since the measure entails
substitution of one energy source for another. A recent report (EPA,
1974b) on the test project in St. Louis indicates that solid waste com-
bustion in power plants may actually increase air pollutants. It notes
that particulate emissions from a solid-waste fired boiler increased,
and contrary to expectations, sulfur dioxide emissions were not notice-
ably decreased. It is likely that better design will eliminate these
negative environmental impacts of solid waste combustion; nevertheless,
they appear to be stumbling blocks at the moment. Combustion of solid
waste 'can have an extremely positive effect on reduction of solid waste
pollution by reducing landfill demand.
3-36
-------
Fluidized Bed Combustion
Fluidized-bed combustion is a developing technology which may be
competitive with conventional plants using stack gas desulfurization
equipment. Fluidized-bed boilers use a system in which crushed or
coarse ground inert materials such as sand, shale, or limestone are
fluidized or floated on air, and coal is injected continuously into the
hot bed at such a rate that is usually no more than 5% combustible in
the bed at any one time. Fluidized-bed boilers may have slightly broader
application than conventional boilers due to low environmental impacts
and the potential to use a wide range of fuels, including municipal
refuse. These units are principally applicable to new installations,
although some limited retrofit applications are being considered.
Environmental impacts of fluidized-bed units are small in terms of
sulfur dioxide, nitrogen oxides, and particulate emissions. Nitrogen
dioxide emissions can be controlled to 0.2 pounds per million Btu, well
below the New Source Performance Standard of 0.7 pounds per million Btu.
Preliminary data indicate sulfur dioxide removal efficiencies of 90 to
95%. Preliminary indications show that particulate emissions are more
coarse and therefore are easier to collect (EPA, 1975a).
The fluidized-bed boilers should generate power at least as effi-
ciently as conventional power boilers with scrubbers. Table 3-13
presents comparative estimates of overall thermal efficiencies.
Improved Power Plant Efficiency
Systems for producing energy are, for the most part, inefficient.
For electric power systems, a major source of inefficiency is the power
plant itself. There are, however, a number of promising techniques,
including magnetohydrodynamics and combined cycles, to increase power
plant efficiency from 33% to 50% and beyond. Further, by locating power
plants near industrial complexes, power plant heat that is now wasted
through discharge into the environment could be used in industrial
processes.
In terms of energy consumption for environmental control, increasing
the conversion efficiency of a power plant from 38% to 50% is more than
equivalent to installing a control device that removes 24% of the pollutants,
3-37
-------
TABLE 3-13
THERMAL CYCLE EFFICIENCY OF FLUIDIZED-BED BOILERS (Percent)
Boiler Type First Generation Second Generation
Fluidized-bed
Atmospheric 36 40
Pressurized 38 47
Conventional with stack 37 37
gas scrubber
Source: "Assessment of Alternative Strategies for the Attainment
and Maintenance of National Ambient Air Quality Standards."
Pedco Environmental Specialist, Inc. Cincinnati, Ohio.
December 1974.
3-38
-------
Improved power plant efficiency would reduce pollution and energy
requirements from extraction, transportation, and processing because
less fuel would be used. Installation of controls at a power plant
would have no such systemwide effects.
Total Energy Systems
Total energy systems are on-site electricity generators which are
designed to recover and use what would otherwise be waste heat. In
terms of Btu's, the amount of waste heat is approximately twice the
amount of electricity generated. There is, therefore, a significant
potential for energy savings by the application of total energy systems.
In addition to recovering and using waste heat to provide space heating,
air conditioning, and domestic hot water, total energy systems also
reduce the energy requirements for the transmission and distribution of
electricity by being located near the point of use. A typical total
energy system is illustrated in Figure 3-5 which presents a comparison
with electricity generation by a central station power plant.
Noise Pollution Control
The environmental energy consumption associated with the Noise
Pollution and Abatement Act has been estimated by the EPA to be about
0.1% for noise control at gas turbine plants and less at other electric
power facilities (EPA, 1973).
Intermittent Control Strategies
Intermittent control strategies rely on the dispersion capacity of
the atmosphere to meet ambient air quality standards. When meteoro-
logical conditions cause a reduction in assimilative capacity, inter-
mittent strategies take steps to reduce the emission rates of the source.
Emission rates are varied through fuel switching and load shifting.
Tall stacks, which are normally incorporated into load shifting, or fuel
switching supplementary control systems are used to enhance the dispersion
of pollutants. The basic elements of an intermittent control system are
3-39
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GENERATION
LOSSES 655;
TRANSMISSION & DISTRIBUTION
LOSSES 82
STACK LOSS
- 10*
• COOLING WATER
'" LOSS'50% TRANSMISSION
**,..,
1 /
POWER
PLANT
7
fit
.^ _. _ i
MISCELLA'IEO'JS
LOSSES 62
TRANSFORMER
COMVENTIONAL POWER GENERATION
STEP-DOWN
TRANSFORMER
ENERGY -UTILIZATION
EFFICIENCY 252
1005!
THERMAL ENERGY
LOSS 30%
ENGINE-GENERATOR
LOSSES 65%
GENERATOR
HEATING
COOLING
POWER
ENERGY UTILIZATION
EFFICIENCY 70%
-S=£,
i-Sse.
TOTAL ENERGY POWER GHNERATICN
Figure 3-5 Energy Utilization Efficiency - Central Station
vs. Total Energy
-------
air quality monitoring, meteorological data, scheduled emission rates,
a predictive air quality model, and the necessary means to vary the
emissions.
Fuel Switching
Fuel switching requires a utility to provide for storage and firing
of an alternative low-sulfur fuel. The alternative fuel would be used
when the monitoring instrumentation and/or the predictive model indicated
that air quality standards would be violated under normal fuel operation.
The energy requirements associated with this control strategy are pri-
marily related to the transportation and use of the low sulfur fuel,
which are elaborated under the discussions of low sulfur western coal,
coal cleaning technologies, and oil desulfurization. There is a negligible
energy requirement for the operation of the monitoring network with its
real-time data transmittal.
Load Shifting
Load shifting is a procedure that reduces the rate of emissions
from a specific plant by shifting scheduled generation to another plant
on an interconnected electrical transmission system. This system is
similar in concept and operation to the fuel-switching system. Energy
requirements will vary depending upon the units involved in the load
shift and upon transmission system losses. Load shifting to a unit of
lower generating efficiency and at a much greater distance to the demand
location can realize a significant additional energy requirement.
It. appears that no significant energy requirements occur on a
nationwide basis with SCS operation. Approximately one-third of the
plants were identified in the 100 plant sample as SCS candidates (ERT,
1975)., i.e., able to prevent violations of air quality standards with
use of SCS. SCS operations for that group of plants even when triggered
at a threshold of 70 percent of standards, was required an average of
only 8 percent of the time. If the SCS is based on switching of fuel,
an energy consumption is involved in transporting the lower sulfur fuel,
i.e., a 4 percent energy consumption for coal transport to Region B is
therefore multiplied by 8 percent of the time, yielding 0.32 percent
3-41
-------
energy consumption for the plant. A capacity loss of 5 percent ("most
likely" reduction for use of lower Btu coal in boilers designed for high
Btu coal] is multiplied by the 8 percent, resulting in a 0.4 percent
capacity loss.
If the SCS is based on load shifting, the minimal energy consump-
tion of longer transmission distances is all that needs to be considered.
For example, if the energy consumption due to line loss is 2 percent,
energy consumption for SCS would be 0.16 percent. The capacity loss is
determined by the actual necessary reduction. If a 30 percent reduction
is required 8 percent of the time, a capacity loss of 2.4 is experienced.
When the SCS option is expanded to the total national population,
the energy consumption and capacity losses are reduced by a factor of
about three, since only a third of the plants in the sample were identifed
as SCS candidates.
Tall Stacks
Tall stacks are designed to prevent high ground-level pollutant
concentrations in the vicinity of the source, and can considerably alter
the dispersive characteristics of the plume. Tall stacks require no
additional energy expenditure and, due to additional draft provided, may
reduce the plant's overall energy requirement.
3.3 Post-plant Energy Requirements
The energy requirements associated with post-plant environmental
energy consumption are directly related to the disposal of waste products
from a pollution control system or the additional transmission losses
associated with restrictive power plant siting requirements due to
environmental legislation.
Coal Ash Disposal
Coal-burning power plants have solid waste problems associated with
the disposal of fly ash, bottom ash, and boiler slag; of these, fly ash
is the major constituent. Power plants burning coal currently sluice
the fly ash to a pond where the solids, over a period of time, settle
3-42
-------
out, allowing the sluice water to flow into a water-course. The sluice
water typically contains about 1,000 ppm dissolved solids (BOM, 1974).
The energy requirements for this operation can be categorized into three
areas: disposal site preparation, waste transport, and waste treatment.
The energy requirements for disposal site preparation can be considered
negligible because, once the pond is prepared it will last for a number
of years and thus, the contribution will average out to be quite small.
The energy requirement for waste transport will also be small, owing to
the fact that most power plants use on-site ash ponding facilities, so
the distance of transport is very short. The waste treatment category
of energy consumption for ash disposal can also be considered small at
present because little, if any, treatment is used.
Desulfurization Sludge Disposal
The throwaway desulfurization methods which use lime or limestone
in a wet-scrubbing process generate sludges requiring disposal. For
coal burning plants, these processes can generate waste products exceeding
the amount of coal ash generated. For example, it has been calculated
that the volume of sludges requiring disposal is approximately 2.40 to
3.27 times the normal coal ash disposal rate (BOM, 1974). For plants
burning oil, which produce so little ash that removal is not always
practiced, installation of waste solids disposal facilities can create
even greater pollutant problems. There are three potential techniques
available for the disposal of desulfurization sludges. These are
ponding, landfill, and use.
Ponding is widely used by electric utilities for disposal of fly
ash. Generally, ponds are used when adequate land is available near the
power plant. Ponding of lime or limestone sludges presents many problems,
however, and should be considered a temporary holding process, not a
long-term approach. EPA considers permanent land disposal of raw
(unfixated) sludge to be environmentally unsound, because it indefinitely
degrades large quantities of land (EPA, 1975b) .
Commercial processes to fixate sludge are currently available.
These processes involve the addition of suitable chemicals to react with
the sludge. The reactions are similar to those employed in the forma-
tion of cement and transform the sludge into a hard, durable mass. The
3-43
-------
fixated sludge can be deposited as landfill material on or off the power
plant property. Fixation of the sludge will greatly reduce its environ-
mental impact. Land degradation can be avoided by covering the fixated
sludge with earth when the disposal area is full. Ground water pollu-
tion, a potential problem if soluble chemical materials are leached from
the sludge, is also minimized by fixation.
In addition to landfill, limited uses for sludge are possible in
other application. Processes are available that can transform mixtures
of lime or limestone sludge, fly ash, additives, and aggregates into
high strength road base usable in primary highways, airport runways,
trucking terminals, etc.
The energy requirements for the disposal of desulfurization sludges
by landfilling are primarily for the chemical fixating agents and the
transportation to the landfill site. The assumed fixating agent require-
ments are ten percent lime (dry basis) of the total ash and sludge waste
generated by the power plant for limestone scrubbing (Heller, 1975).
For lime scrubbing, 6.5 percent fixating agent is assumed since the
sludge already contains about 3.5 percent unreacted lime. The energy
consumption associated with the fixating agent therefore needs to
include the energy costs of limestone mining, calcining of limestone to
produce lime, and transportation from the quarry to the plant. The
additional energy requirement for transporting the fixated sludge to the
landfill site is calculated based on a ton-mile transport by truck.
Figures 3-6 and 3-7 display the material and energy balances for sludge
fixation processes for FGD systems using limestone and lime respec-
tively. The energy requirement for these processes are 1.26 percent for
the limestone and 0.75 percent for the lime.
3.4 Capital Energy Requirements
Capital energy is the energy consumed for the construction of
control equipment or the implementation of a control option. Examples
of this would be the energy consumed for the fabrication and instal-
lation of an electrostatic precipitator to control particulates, or the
energy consumed for the fabrication and installation of a coal slurry
pipeline for the transport of low sulfur western coal.
3-44
-------
MATERIAL BALANCE : tons/hour
Cooling Water
454.5
69.7
Limestone
102.9
X Z
Water Discharge
Power Plant
Electricty
16
^6/\98.5filudge (dry)
67.5 Ash (dry)
ENERGY BALANCE ; Btu/hour
Cooling Water
1.0 x 10
10
Fuel
Transport. 1.95 x 10 ..
Limestone
Mining
9.18 x 10
\
Power Plant
Water Discharge
Electricity
Sludge
Transport Transport ft
4.65 x 10 9.3 x 10
1.09 x 10
Basis: 1.0 x 10 Btu/hour, energy input to boiler.
Assumptions:
3.5% sulfur coal, 11,000 Btu/lb.
85% sulfur removal by limestone scrubbing at 165% stoichiometry
99% scrubber particulate collection efficiency
Transport from quarry to plant, 100 miles by truck
Transport from plant to landfill, 10 miles by truck
Figure 3-6 Material and Energy Balances for FGD System
Utilizing Limestone as Sorbent and Lime as
Fixating Agent for the Treatment of Sludge.
3-45
-------
MATERIAL BALANCE : tons/hour
Cooling Water
Fuel
454.5
Limestone
79.7
\
Power Plant
Water Discharge
Electricty
30
.5 / 9.5 /\78.9 Sludge (dry)
67.5 Ash (dry)
ENERGY BALANCE : Btu/hour
Cooling Water
\
Fuel 1-° x 10
10
Power Plant
Water Discharge
Electricity
/ /\
Sludge
Mining
7.1 x 10
Basis: 1.0 x 10
t
„ Transport Transport
2.62 x 10 11.1 x 10 8.2 x 10
Btu/hour, energy input to boiler.
Assumptions:
3.5% sulfur coal, 11,000 Btu/lb.
85% sulfur removal by lime scrubbing at 128% stoichimetry
99% scrubber particulate collection efficiency
Lime plant at quarry, transport from quarry to plant
100 miles by truck
Transport from plant to landfill, 10 miles by truck
Figure 3-7', Material and Energy Balances for FGD System
Utilizing Lime as Both Sorbent for Sulfur Removal
and Fixating Agent for Treatment of Sludge.
3-46
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The few estimates of capital energy requirements which appear in
the literature are shown in Table 3-14. These estimates are based on
the application of a Btu/dollar ratio to the capital cost involved to
determine the capital energy requirement (Ford, 1975). The ratio of
Btu/dollar is derived from input-output analysis of the Standard Indus-
trial Classification "New Construction, Public Utilities" of 0.076
million Btu per dollar of 1963 construction costs (Herendeen, 1974).
This is a very simplified approach which does not evaluate energy
consumption, but only compares capital costs. In addition, the Ford
study attempts to convert the capital energy requirement, which is a
one-time requirement or a steady state requirement by dividing the
capital consumption by the expected lifetime of the control equipment.
One inherent weakness in this approach is the difficulty in determining
the expected lifetime of such equipment as scrubbers, which are prone
to many problems of corrosion and scaling.
A better approach for determining capital energy requirements would
be to inventory energy consumed for both the materials used and energy
consumed during the installation. The following listing describes some
of the important capital energy requirements associated with the imple-
mentation of environmental control options.
Sulfur Dioxide Control
Use of low sulfur western coal
Railroad cars, engines and additional track
Slurry pipeline installation including coal preparation
and dewatering facilities.
Use of flue gas desulfurization
Fabrication and installation of system
Sulfur recovery facility
Use of coal cleaning
Construction of coal preparation plant
3-47
-------
TABLE 3-14
CAPITAL ENERGY REQUIREMENTS FOR ENVIRONMENTAL CONTROL
Capital Energy
Environmental Requirement
Control Option (percent)
Nitrogen Oxides Control Equipment negligible
Closed-Cycle Cooling Systems negligible
Construction of Electrostatic Precipitator 0.02
w Construction of Oil Desulfurization Facility 0.15
i
*>.
00 Construction of Limestone Scrubbing System 0.2 - 0.5
From: (Ford, 1975)
-------
Thermal Pollution Control
• Closed-cycle cooling
Fabrication and installation of cooling towers, ponds,
or canals
Particulate Control
• Collection equipment
Fabrication and installation of either electrostatic
precipitators or mechanical collectors.
3.5 Capacity Losses
It can be expected that the energy consumption required to meet
environmental regulations would also result in less energy being available
to sell for an individual power unit. Table 3-15 shows the expected
capacity losses for the prospective control systems. Each of the losses
except that for coal transport is comparable to the electricity require-
ments shown in Table 3-3. When electricity is used in the plant, it is
not available to sell and therefore represents a capacity loss. This
may not result in a derating of the facility.
The exception in Table 3-3 is for the transportation of low sulfur
coal into regions B § C. The amount of electricity which can be generated
in a typical region B S, C power plant is based on the Btu content of low
coals. We assume that the boiler is sized based on a higher Btu content
than that of low sulfur western coal. Because the boiler cannot hold as
much western coal, we have assigned a 5-percent capacity loss as "most
likely", 25 percent less Btu's less a normal 15 to 22 percent overdesign
of boiler. This capacity loss does not, however, result in an energy
consumption because that extra coal is not burned. Therefore, this 3 to
10 percent for boiler capacity does not show up on Table 3-2 .or 3-3 as
an energy consumption.
These capacity loss figures can be carried through the methodology
discussed in Chapter 5 to produce the figures for expected nationwide
capaQity losses in Chapter 6.
3-49
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TABLE 3-15
CAPACITY LOSS OR SALEABLE POWER REDUCTIONS, IN PERCENT
Low Most Likely High
SO Control
Scrubber 2 3.5 5
Coal Wash* 00 0
Low Sulfur Coal Transportation
(B and C) 3 5 10
Blending* 00 0
Oil Desulfurization* 00 0
Waste Heat Control
Design 1.0 1.5 2.0
Retrofit 2.0 3.0 4.0
Particulate Control
Electrostatic 0.2 0.3 0.4
Mechanical MD.O ^0.0 ^0.0
*These processes could result in nominal changes in fuel heatint value
but normal design practice allows for some fuel variability. Thus, no
derating is considered.
3-50
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4. BASE YEAR ENVIRONMENTAL ENERGY CONSUMPTION
This section estimates energy consumed in 1974 for environmental
control based on the application of the energy requirements for environ-
mental controls to the appropriate population of fossil fuel, steam
electric power plants. The energy consumption for the application of
environmental controls is expressed as a percentage of the fuel energy
consumed at all fossil fuel, steam electric plants for the generation of
electricity.
The additional energy consumption due to environmental controls for
the base year of 1974 is summarized in Table 4-1. Sulfur dioxide
control, the most significant pollution control category, consumed
approximately 0.9 percent of the energy consumed by fossil fuel, steam
electric plants in 1974. Thermal pollution control and particulate
control had an energy consumption of approximately 0.2 percent each.
Total environmental energy consumption was 1.30 percent.
In 1974, the consumption of fossil fuel energy at steam electric
plants was approximately 15.0 quadrillion Btu (NCA, 1974). Each one-
percent increment of energy required for environmental control in 1974
is therefore equivalent to 150.0 trillion Btu. The generation of
electricity from fossil fuels requires additional energy beyond the
value of the energy consumed at the boiler. Energy is required for the
extraction, processing, and transport of the fossil fuel prior to its
use at the power plant. Overall, the generation of electricity from
fossil fuels requires about four Btu's of primary energy inputs to
produce one Btu of electricity at its point of utilization (CEQ, 1973).
4.1 Sulfur Dioxide Control
The control of sulfur dioxide emissions from fossil fuel,, steam
electric utilities is required only for those plants burning either oil
or coal. Natural gas is a sufficiently clean fuel such that its com-
bustion does not require control for sulfur dioxide emissions. Several
environmental control options were used during the base year. The
pretreatment of fuels for the removal of sulfur included oil desul-
furization and, to a limited extent, the physical cleaning of coal.
Naturally occurring low-sulfur western coals were transported to the
4-1
-------
TABLE 4-1
SUMMARY OF BASE YEAR (1974) ENVIRONMENTAL ENERGY CONSUMPTION
Sulfur Dioxide Control
Residual Oil Desulfurization
Physical Coal Cleaning
Use of Low Sulfur Western Coal
Flue Gas Desulfurization
Sub-Total - Sulfur Dioxide
Percent of Total Base Year
(1974] Energy Consumption
0.55
0.23
0.07
0.04
0.89
Thermal Pollution Control
Closed-Cycle Cooling
Particulate Control
Particulate Control Equipment
Nitrogen Oxide Control
Combustion Modifications
Waste Water Pollution Control
Waste Water Treatment Facilities
Total
0.22
0.20
Negligible
Negligible
1.31
4-2
-------
east to replace higher-sulfur eastern coals. In addition, sulfur
dioxide was controlled after combustion by the application of flue gas
desulfurization systems.
In the discussion that follows, each of these control options is
evaluated with respect to its degree of utilization in 1974. Then, the
appropriate energy requirement from Section 3 is applied to the con-
trolled portion of the population of power plants to yield the environ-
mental energy consumption.
Residual Oil Desulfurization
The reduction of sulfur content of residual oil for use by electric
utilities has been achieved by several techniques. These techniques
include the blending of low sulfur refinery products with the residual
oil and the actual hydrodesulfurization of the residual stock. In 1974,
the predominant technique for producing low sulfur oil involved blending
the residual oil with other refinery stocks (Bruch, 1976), largely due
to the very limited refinery capacity for the desulfurization of residual
stocks available at the time.* The environmental energy consumption of
residual oil desulfurization is difficult to determine because of the
uncertainty created by the large amount of blending that occurred. Some
of the refinery stocks blended with the residual oil have been desul-
furized for other than environmental reasons, including the prevention
of catalyst poisoning, the elimination of equipment corrosion and the
maintenance of product purity. This situation will vary from refinery
to refinery. Because of the uncertainty of the amount of blending
occurring and the difficulty in assigning one energy requirement to this
situation, two energy consumption determinations, a reasonable low value
and a high value, are used to define the expected range for this energy
requirement.
A method of determining the energy consumption of the desulfuriza-
tion of residual oil is based on the application of an energy requirement
for all residual oil with a sulfur content of 1.0 percent or less that
was consumed by power plants in 1974. For the actual calculation it is
considered that the reduction of high sulfur oil to a sulfur content
*As of January 1, 1975, the capacity for desulfurizing residual stocks
was reported to be only 6,000 barrels per day (b/d) and the capacity for
desulfurizing heavy gas-oil only 186,000 b/d (OGJ, 1975).
4-3
-------
of between 0.0 and 0.3 percent sulfur requires a 6.0 percent energy
consumption for desulfurization; the reduction of high sulfur oil to
a sulfur content of between 0.3 and 1.0 percent requires 3.0 percent
energy consumption; and reduction to a level of 1.0 percent sulfur or
above requires no energy for desulfurization. The distribution of
sulfur content in oil delivered to electric utilities for the period
from November 1973 through October 1974 (Jimeson, 1975) is considered to
be representative of base year conditions. The energy requirements of
6.0 and 3.0 percent are intended to bracket the estimates presented in
the Ford Foundation study. In Table 4-2 the environmental energy con-
sumption for residual oil desulfurization represents 2.55 percent of
the energy value of all oil consumed by power plants. This sum is
equivalent to 0.55 percent of the energy input to all of the fossil
fuel, steam electric power plants.
Physical Coal Cleaning
»
The level of coal cleaning that was practiced during 1974 resulted
in only a limited degree of sulfur content reduction. During this
period, coal cleaning was primarily employed to remove ash-forming
impurities from run-of-mine coal. The sulfur reduction that was achieved
was due to the removal of that portion of sulfur present in the gross
impurities.
On a nationwide basis, approximately 50 percent of the coal used by
electric utilities received some degree of preparation [Deurbrouck,
1974]. Those coals receiving this preparation were located in the
northeastern United States, which is the largest coal-using portion of
the country. The range of coal beneficiation available at this time may
be broadly generalized as follows [Lovell, 1975] :
Level One - No preparation, direct utilization of mine product
Level Two - Removal of gross, noncombustible impurities, but control
of particle size and promotion of uniformity. 95 percent
material yield and 99 percent thermal recovery. Little
change in sulfur content.
4-4
-------
TABLE 4-2
ENVIRONMENTAL ENERGY CONSUMPTION FOR THE DESULFURIZATION
OF OIL USED IN STEAM-ELECTRIC PLANTS IN 1974
Range in Percent
Sulfur in Oil
0.0 - 0.3
0.3 - 1.0
1.0 - 3.0
3.0 - 10.0
Fraction of
Total Oil Used
Energy
Requirement for
desulfurization
(percent)
(0.162)
(0.527)
(0.311)
6.0
3.0
0.0
(0.0)
0.0
Weighted Average of Oil-Fired Plants: 2.55 percent
-------
Level Three - Single-stage beneficiation following minimal component
liberation. Particle sizes less than 3/8-inch usually
not prepared. 80 percent material yield and 95 percent
thermal recovery. Limited ash and sulfur removal.
Level Four - Multi-stage beneficiation with controlled liberation.
Usually incorporates dewatering and thermal drying.
70 percent material yield and 90 percent thermal yield.
Maximum ash-sulfur rejection, calorific recovery, and
calorific content.
Lovell reports that most of the utility coals receiving preparation
in 1974 were beneficiated only to Level Two, but some were beneficiated
to Level Three. To determine the environmental energy consumption for
the physical cleaning of coal to reduce sulfur content in 1974, the
energy requirement of 4.0 percent is applied to that portion of the coal
that received Level Three beneficiation. This 4.0 percent energy
requirement represents the additional loss in Btu content of the coal in
going from Level Two to Level Three beneficiation. Of the 50 percent of
the electric utility coals which received some degree of coal prepara-
tion; 20 percent is estimated to have received Level Three beneficia-
tion. Thus, ten percent of the coal consumed by electric utilities
receiving coal cleaning to reduce its sulfur content, yielding an energy
consumption (or loss) of 34.0 trillion Btu. This value represents an
environmental energy consumption of 0.23 percent of the energy input to
fossil fuel, steam electric boilers.
Use of Low-Sulfur Western Coal
The degree of use of low-sulfur western coals in areas other than
the west was determined from a review of the "Bituminous Coal and
Lignite Distribution - Calendar Year 1974," published by the U. S.
Department of the Interior, Bureau of Mines, as part of their Mineral
Surveys [BOM, 1975aj. This report included statistics of the coal
*
producing districts and shipments to each state for coal used by elec-
tric utilities. Table 4-3 summarizes the coal shipments identified as
transport of western coal to eastern utilities. The traditional markets
listed were determined from the principal coal producing districts
4-6
-------
TABLE 4-3
SHIPMENTS OF WESTERN COAL TO EASTERN MARKETS, 1974 [BOM, 1975a]
WESTERN COAL
TRADITIONAL MARKET
Market
Destination
New York
West Virginia
Kentucky
Michigan
Wisconsin
Indiana
Illinois
Missouri
Iowa.
Coal Producing
District
17,
20,
22,
22,
20,
22,
17,
19,
22,
19,
19,
22,
19,
20,
22,
SW Colorado
Utah
Montana
Montana
Utah
Montana
SW Colorado
Wyoming
Montana
Wyoming
Wyoming
Montana
Wyoming
Utah
Montana
Distance
(mi)
1980
1800
1800
1680
1560
1440
1200
1030
1200
1320
1150
1230
1020
1140
1080
Coal Producing Distance
District (mi)
1,
8,
8,
9,
4,
4,
10,
10,
10,
11,
10,
10,
10,
10,
10,
E Pennsylvania
Kentucky § W.VA
Kentucky § W.VA
W Kentucky
Ohio
Ohio
Illinois
Illinois
Illinois
Indiana
Illinois
Illinois
Illinois
Illinois
Illinois
240
50
50
50
300
300
300
300
300
50
50
50
240
300
300
Mileage Tons
Difference
1740
1750
1750
1630
1260
1140
900
780
900
1270
1100
1180
780
840
780
9
64
66
54
118
535
5
1515
564
2255
1445
5986
1054
40
45
Ton-miles
(in 1,000)
15
112
115
88
148
609
4
1,181
507
2,863
1,589
7,063
822
33
35
,660
,000
,500
,020
,680
,900
,500
,700
,600
,850
,500
,480
,120
,600
,100
Total
(1100)
(13755) 15,191,210
-------
shipping to each location on the list. As shown on this table, almost
13.8 million tons of western coal were shipped to eastern markets for
utility consumption in 1974. Applying a value of 9,300 Btu/pound for
the heat content of western coals, this equals 256 trillion Btu. Eastern
coal, with higher heat content of 11,800 Btu/pound, would provide this
same quantity of energy with only 10.9 million tons.
The transport distances involved are about 100 miles for the
traditional coal shipments and about 1,200 miles for the western coal
shipments, thus the shipment of western coal involved an additional
transport distance of 1,100 miles. The eastern case yields a coal
transport requirement of 1.1 billion ton-miles, while the western coal
case yields a transport requirement of 16.5 billion .ton-miles. The
difference between these two, 15.4 billion ton-miles, when applied to a
train transport energy requirement of 680 Btu/ton-mile yields an energy
consumption value of 10.5 trillion Btu for the transport of western coal
in 1974. This value is equivalent to 4.1 percent of the energy value of
the coal transported and 0.07 percent of the energy input to fossil
fuel, steam electric boilers. In addition, it is noted that the 4.1 percent
requirement for transporting western coal to eastern markets would be
consumed as diesel fuel.
Flue Gas Desulfurization (FGD)
Several different processes have been used in FGD units, but
lime/limestone based systems are the most widely used. For the deter-
mination of the environmental energy consumption due to the application
of FGD systems, all plants are assumed to use a lime or limestone based
system with an energy requirement of 4.0 percent. This value is derived
from the average energy requirements reported by the EEI/CACC survey
(see Chapter 3).
Flue gas desulfurization is a developing technology, and as of the
end of 1974, 18 installations with a total installed capacity of 3,835
megawatts were reported [Albrecht, 1975]. Availability of most of the
operational FGD systems has been reduced because of installation,
developmental repair, and modification problems. To reflect a limited
degree of availability, an assumed load factor of 40 percent is used for
4-8
-------
these plants. At a thermal efficiency of 33.3 percent (10,248 Btu/kwh),
these 18 plants would consume 137.7 trillion Btu of fuel energy to
generate 13.4 billion kilowatt-hours of electricity.
Applying the energy requirement to the 18 plants identified as
using FGD systems in 1974, yields an environmental energy consumption of
5.5 trillion Btu for the application of FGD systems. Two of the 18 FGD
installations were on oil-fired units [Jonakin, 1975], so this environ-
mental energy consumption value can be apportioned between coal-fired
and oil-fired units.
4.2 Thermal Pollution Control
Waste Heat Disposal
The environmental energy consumption for waste heat disposal in
1974 is calculated as 0.22 percent, from a determination of those power
plants using closed-cycle cooling facilities in that year. The majority
of plants providing the major share of steam-electric capacity employ
once-through cooling using either fresh or saline water. There is an
increasing trend away from once-through cooling toward the use of
cooling ponds and cooling towers. The distribution by type of cooling
facility, as a percent of the total installed capacity, is as follows:
Percent of Percent of Plant
Type of Cooling 1974 Capacity Energy Use
Once-through 68
Cooling ponds 9 1.0
Spray ponds and semi-closed 4 1.3
Mechanical draft wet cooling towers 11 2.5
Natural draft wet cooling towers 8 3.0
100
This tabulation includes estimates of the additional energy required
to operate the various closed cycle cooling facilities. Fuel is required
11 to operate the pump and/or fan components of the closed cycle system
and 2) to compensate for the higher turbine backpressure resulting from
the higher condenser temperature range.
4-9
-------
The natural draft tower requires that water be pumped to the top of
the packing. In the mechanical draft tower, in addition to pumping the
water to the packing, power is required to run the fans which move the
air through the tower. The amount of energy required varies for each
mechanical draft tower due to its dependency on condenser design and
climatic conditions. A condenser with a high flow rate and low tempera-
ture rise requires more pumping energy than a condenser with a lower
flow rate and a higher rise for the same size plant. With adverse
climatic conditions, more air is required, resulting in bigger fans
requiring more energy.
The weighted average energy requirement, with respect to the
fraction of the total installed capacity, is equal to 0.62 percent
additional energy. Not all this additional energy consumption, however,
can be considered as environmental energy consumption, since closed-
cycle systems are also installed for economic reasons associated with
water supply availability. Prior to the base year 1974, the majority of
plants employing closed-cycle cooling systems had installed such systems
due to the lack of a water supply adequate for once-through cooling.
Assuming that 65 percent of the plants employing closed-cycle cooling
systems had done so for economic reasons, then the weighted average
energy requirement resulting from environmental considerations is
0.22 percent.
4.3 Particulate Control
The control of particulate emissions from fossil fuel electric
utilities is only required for those plants burning either oil or coal,
and is equal to 0.20 percent of the total energy input to those plants.
Natural gas is a sufficiently clean fuel so that its combustion does not
require control for particulate emissions. The control of particulate
emissions in 1974 was primarily achieved by the application of either
mechanical collectors, electrostatic precipitators, or a combination of
the two. The distribution of particulate control equipment by fuel type
for the sample plant population is summarized in Table 4-4. The
characteristics of this sample are assumed to be representative of the
industry with respect to particulate control.
4-10
-------
TABLE 4-4
DISTRIBUTION OF PARTICULATE CONTROL EQUIPMENT BY FUEL TYPE FOR THE SAMPLE PLANT POPULATION
Particulate Control Equipment (percent)
Combination
Mechanical-
Fuel Type
Gas Burning
Oil Burning
Coal Burning
Gas S Oil
Gas 5 Oil
Oil § Coal
Gas, Oil, §
Coal
Percent of
Sample
0.8
12.6
13.2
21.1
2.2
39.9
10.2
None
100.0
40.7
3.1
50.1
-
3.8
4.7
Mechanical
Collector
-
38.8
4.1
30.1
-
5.1
15.4
Electrostatic
Precipitator
-
-
17.3
13.5
65.4
16.7
Electrostatic
Precipitator
-
20.5
75.5
6.3
34.6
72.5
79.9
Wet
Scrubber
-
-
-
-
-
1.9
-------
As indicated in Table 4-4, oil-fired boilers primarily used mechanical
collectors (principally multiple cyclones), and coal-fired boilers
primarily used electrostatic precipitators for the control of particu-
lates. Boilers which fired a combination of fuels typically used a
combination mechanical and electrostatic precipitator or simply an
electrostatic precipitator.
To determine the environmental energy consumption for particulate
control, the following assumptions concerning control option require-
ments by fuel type were made:
• All coal-fired megawatts controlled by electrostatic pre-
cipitators
• Sixty percent of oil-fired megawatts controlled by multiple
cyclones
• All gas-fired megawatts uncontrolled
The applicable energy requirements for these control options are
negligible for multiple cyclones and 0.3 percent for electrostatic
precipitators. The environmental energy consumption for the application
of particulate controls is determined to be 0,2 percent of the energy
input to fossil fuel power plants in 1974.
4.4 Other Environmental Control Areas
This section discusses other environmental control areas that have
been evaluated but for which no significant energy consumption was
determined. The areas involved are the control of nitrogen oxide
emissions by the application of combustion modifications to reduce flame
temperature and the control of waste water by the applications of water
treatment facilities. For each of these control areas, the degree of
application is reviewed for the base year period.
Nitrogen Oxides Control
The environmental energy consumption associated with the applica-
tion of combustion modifications for the control of nitrogen oxides in
1974 is considered negligible due to the limited number of installations
4-12
-------
employing this control option and the small energy consumption involved
where it was applied. Of the power plants for which a response was
obtained to our energy requirements questionnaire, only four plants were
reported as using either flue gas recirculation or overfire air for the
control of nitrogen oxides. For those installations for which the
application of combustion modifications was reported, the energy, con-
sumption involved varied from 0.24 percent to 0.86 percent with an
average of 0.47 percent.
Waste Water Pollution Control
The environmental energy consumption associated with the utiliza-
tion of chemical waste water treatment facilities for the control of
waste water pollution in 1974 is considered negligible due to the limited
number of installations with extensive chemical waste water treatment
facilities and the small energy consumption involved where such systems
are utilized. Of the power plants responding to the ERT energy require-
ments questionnaire which reported energy requirements for chemical
waste treatment facilities, the energy consumption involved varied from
0.00 percent to 0.06 percent.
4-13
-------
5. METHODOLOGY
This section describes the general procedure for determining future
estimates of energy consumption in the fossil fuel, steam electric
generating industry. The discussion includes sources of data used to
develop the results of this study as well as the method of estimating
the expanding sample plant population in proportion to the national
population in 1983. Since future projections focus on energy consump-
tion due to sulfur oxide controls, additional discussion is devoted to
the following topics: complying fuel sulfur values, oil to coal conver-
sion, complying sulfur in fuel histograms and modeling of sulfur oxide
control technologies.
5.1 Data Sources
The three sources of input data used to develop the results of this
study and the areas where each has been used are as follows.
1) Discussion and evaluation of the literature values for the
energy requirements of various control technologies is contained
in Section 3 and references are given in the bibliography.
2) Diffusion modeling results (ERT, 1975) for a 100 plant
sample were used to determine specific sulfur dioxide control
requirements.
3) Federal Power Commission data for 89 plants out of the 100 plant
sample* were supplemented by 66 completed plant sample question-
naires on process energy consumption and on present control
technology practices. A summary of this data and a sample
questionnaire form is contained in Appendix A.
*0riginally it was intended that the two plant samples described above
would be identical, at least insofar as the specific plants considered.
This was not possible because of failure to get data for 11 plants.
Even then the 89 plant sample is not a true subset of the 100 plant
sample. The 89 plant sample is based on actual plant configurations
for 1974. The 100 plant sample is based on projections to 1980 and
differs because of factors such as additions or losses of units or
changes in fuel type.
5-1
-------
The 100 plant sample is the same as that in ERT Document P-1547B,
"An Evaluation of Sulfur Oxide Control Requirements For Electric Power
Plants", April 1975. Amplification of all the material discussed in
this section can be found in that document. Selection of the sample and
projection to 1980 was done by National Economic Research Associates,
Inc. (NERA). EPA diffusion modeling results using the CRSTER model were
used where available (76 plants). ERT modeled the remaining 24 plants
using the EPA model CRS for flat terrain cases and the ERT CRSVAL model
(which is based on the EPA CRSTER and Valley models) in cases of steep
terrain.
Initially the sample was generated randomly from the national plant
population. However, in order to use existing modeling results, sub-
stitutions were made for 44 plants. Replacements were made in a manner
which attempted to maintain as nearly as possible the geographic region,
size, and fuel type properties of the national population.
Neither the 100 plant or the 89 plant samples are totally repre-
sentative of the national population. However, through expansion by
appropriate factors as described in Section 5.2, the results are approxi-
mately representative of the national population. Both populations are
large enough that they contain valid information on the range of operating
configurations and environmental control technologies which would be
found in the national population.
Table 5-1 lists the 100 plant sample stratified according to:
• fuel type
coal (C)
oil (0)
• region of the country
east coast states (E)
other high sulfate states (T)
rest of country (R)
• plant size
small (S), 400 megawatts or less
medium (M), 401 to 800 megawatts
5-2
-------
large (L), greater than 800 megawatts
A key to Table 5-1 follows the table.
The regions of the country used in the 100 plant sample were divided
by EPA on the basis of sulfate measurements. "High sulfate" values are
said to predominate in the measurements on the east coast and in the
midwest, while the west is said to have generally lower sulfate concen-
trations. Figure 5-1 shows the geographic boundaries of those regions
and presents the geographic distribution of the 100 plant sample.
Only plants which the Federal Energy Administration (FEA) deemed to
be convertible, as well as those which actually burned some coal in 1974
and had boilers designed to burn coal, were placed in the coal-burning
capacity category. All other plants were assumed to fire oil by 1980.
Because of their limited number, discussion of oil-fired plants on the
east coast and in other high sulfate states are combined on the same
page of the table. The 44 plants classified as "urban" are within a
ten-mile radius of a community with a population of greater than 50,000
persons.
5.2 Expansion to the National Population
The national population of fossil fuel, steam electric generating
plants was taken from the NERA report, "The Costs of Reducing SO-
Emissions from Electric Generating Plants", April 1975. Tables 5-2 and
5-3 taken from this report show the pre-1976 capacity and the 1976-1980
capacity added.
For consistency with our 100 plant sample we took the coal-oil
plants to be coal fired. The NERA categories "East, High Sulfate" and
"East, Other" are together identical to our category "East Coast". The
NERA category "Remainder, High Sulfate" is identical to our category
"Other High Sulfate" and the NERA categories "West Coast" and "Remainder,
Other" are together identical to our category, "Rest of Country".
Table 5-4 presents the data used in expanding the 100 plant sample
to the national population.
5-3
-------
VI
I
(Total)
(Total)
(Total)
(Total)
(Total)
TABI.P :. -i
DETAILS TOR 100 PLANT SAMPLE
POKCR PLANT PARAMETERS; COAL PLANTS, EAST COAST*
Plant MW
No. my
Rural
IS
4
14
40
S
17
34
345
340
533
672
1746
3499
728
Code
C'72
C'72
C'71
C'72
C'71
C'75
C'72
W19
S
345
(345)
M
740
533
672
(1945)
L
1746
3499
1988
(7233)
„„ Fuel my
80 C 0 G
103Ton 105BBL 105FT3
1047.0 -- 1324.61
873.0
1051.0
970.8
3426.0
10160.0
1298.0
Fuel
1980
C
C
C
t
C
C
C
1980 BTU/ S 01)
Ib
11
12
11
12
12
11
12
or/gal C '"'0 G
,861 1.14 -- 0.0
,539 1.6
,984 0.93 --
,500 2.5
,130 1.17 --
,680 3.2
,467 1.7
% S
1980
1.14
1.6
0.93
2.5
1.17
3.2
1.7
Emission
1980
(gm/sec)
1070.9
1682.5
540.0
1393.0
2246.8
17768.1
3293.4
"C" Factor
MY to 1980
1.637
2.176
1.0
1.746
1.0
1.0
2.73
Fuel Use
1980
10JTon
1637.2
1900.0
1051.0
970.8
3426.0
10160.0
3544.9
Urban
51
57
59
86
56
58*
77
78
75
100
125
329
136
491
661
418
789
695
C'74
C'72
C'71
E'SO
C'72
C'72
E'SO
E'SO
E'SO
S
100
125
272
136
(633)
M
491
661
418
789
695
65.0
1211.6
2714.2 544.0
366.0
1085.0
6603.0
396.0 1788.0
4204.4
189.0 2522.0
C
' C
C
C
C
C
C
C
C
12
12
12
11
12
12
12
12
12
,500 1.6
,500 -- 0.3
,500 -- 0.3 0.0
,800 2.0
,240 2.0
,500 — 0.6 —
,200 2.9 0.4
,500 — 1.0 —
,500 1.0
1.6
1.0
0.3
2.0
2.0
0.5
2.9
1.0
1.0
59.3
157.62
69.55
420.0
1185.8
429.6
1399.0
572.8
436.6
1.0
4.57
1.20
1.0
9.3
1.13
1.92
1.41
1.24
65.0
274.8
404.0
366.0
1033.4
1497.6
840.7
998.3
761.0
(3033)
41
60*
1551
1827
C'72
C'72
2351
1827
2177.0
12903.7 5103.7
C
C
10
12
,673 2.5 --
,500 -- 0.4 00
2.5
0.3
4788.6
540.9
13.855
1.09
3330.0
3142.4
(4178)
(Total)
*A key to Table 5-1 follows the table.
-------
TABLE 5-1 (continued)
POWF.K PLANT PARAMETHRS; COAL PLANTS, OTHER HIGH SULFATE STATES
(Total)
01
tsi
(Total)
(Total)
(Total)
(Total)
Plant Wmy
12
13
l»
ss
110
!1J
11 •
HI
-H
11)1)
1
2
3
7
3
9
10
19
22
24
53
S3
98
11
18
23
95
6
73
85
Rur:ll
176
_'<>J
Md
142
?('S
Sll
Jl>n
5S7
410
2558
1272
530
2441
* 1633
* 1100
1934
650
* 1238
1086
1097
1700
Urban
193
* 511
500
401
615
1275
990
1580
Code
C'71
C'7I
C'71
U'HU
i;'xi!
l: 'Mil
1,'HU
1,'NO
li ' Kll
E'80
C'71
C'75
C'71
C'74
C'71
C'71
C'75
C'71
C'71
C'71
C'71
E'80
C'71
C'71
C'71
C'75
C'71
C'71
C'72
E'80
MW
™1980
S
176
J<<3
3-1 <>
M2
JfiS
HO
ju J
(I51M1
i.r.7
IctO
410
(1594)
1
2E5S
2082
1787
2441
1633
1100
1934
1450
1846
1036
1097
1700
(20,714)
S
193
(193)
M
Sll
500
401
615
(2027)
1
1275
990
1580
(3845)
Fuel my
COG,
10STon 103BBL 106Ft3
468.3
(>.w ,u
7^3.1)
371.8
r.47.0
•' .11 . . *
1117.7
1494.0
6094.2
3713.0
1373.5
5672.0
3266.0
1972.3
5385.0
1341.0
2584.0
3122.0
2493.0
3077.0
323.2
1534.0
830.0
1149.0
1452.0
2899.0
1375.0 — 1S331.0
3285.0
Fuel
1980
C
C
C
C
0
(1
(!
C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
i960 BTU/
lb or/gal
10,515
ll,27d
!', '.)•!!)
1:1.000
i:!.omi
l.',0ll!l
u.ooo
1 1 ,ono
12,IIMII
11,203
10,145
10,822
11,300
11,206
11,217
11,042
12,520
11,152
10,892
10,356
11,461
10,271
14,543
11,406
11,388
10,663
11,840
11,220
11,100
11,000
S-y-ffi!
C yO G
2.4
3.13 --
3.6(, --
1.33 --
7.1Ti •-
•!.!'> --
1 . :i
.1.0
2. 1C, --
2.0 — --
4.11 — —
4.5
2.1
1.5 -- —
3.7 — —
3.18 --
3.0 -- —
3.4
2.94 --
3.93 --
1.04 — —
2.45 -- —
2.9 — —
2.85 — —
2.09 — —
3.3 — —
1.6 — —
2.58 —
3.3 — 0.0
3.8
* 0
1980
2.4
3. 13
3 . dfi
1.3
? . Id
2. 11,
1.1
3.0
2. It:
2.0
4.11
4.5
2.1
1.5
3.7
3.18
3.0
3.4
2.94
3.93
1.04
2.45
2.61
2.85
2.09
3.3
1.6
2.58
3.3
3.8
Emission
1980
(gm/soc)
614.23
1120.1
14(i.! .')
277.3
(.77.7
:*(,!.?>
!.'.» J .A
1913. fi
j'j:.^.2
1714.6
13654.8
14B97.5
5502.9
3657.3
6604.0
3556.9
8828.7
5543.1
6145.5
6654.2
1502.8
4325.8
537.7
2347.4
94S.2
2041.7
1333.0
4119.2
3985 . 1
3409.3
"C" Factor
MY to 1980
!.(.
1.0
1 .0
1.0
1.0
1.0
1 .»
i.n
l.(i
1.0
1.0
1.63
3.325
1.0
1.0
1.0
1.0
2.23
1.5
1.0
1.0
1.0
1.0
a.o
1.0
1.0
1.0
1.0
1.607
1.0
Fuel Use
1980
103Ton
468.3
<:',7.U
727.. 0
.',?).«
r,47,()
i'.>'iAt
J'J* ,
-------
TABLE 5-1 (contiuiu-il)
POWER PLANT PARAMETERS; OIL PLANTS, EAST COAST AND OTHER HIGH SULFATE STATES
(Total)
(Total)
(Total)
(Total)
(Total)
(Total)
Plant
No.
MW
my
Code
^1980
Fuel my
C 0
103Ton 103BBL
Fuel
G 1980
106FT3
1980 BTU/
Ib or/gal
S (1)
C m>0 G
°'a S
1980
Emission
1980
(gin/sec)
"C" Factor
MY to 1980
Fuel Use
1980
103Ton
Rural
38
39
45
49
89
46
47
50
54*
71
54
100
740
559
1200
593
543
964
805
1211
C'72
C'72
C'72
C'72
E'80
C'72
C'72
C'72
C'72
C'72
S
54
215
(269)
M
740
559
1200
(1871)
L
1029
1102
964
805
1598
(5448)
279.0
709.7
4154.0
4765.0
14007.0
4665.8
S335.0
9757.0
4792.0
9940.0
1963.0 0
328.0 0
14153.0 0
0
0
200.0 0
0
0
16560.0 0
0
135,000
135,000
135,000
135,000
148,000
135,000
135,000
135,000
135,000
135,000
2.2 0.0
2.1 0.0
1.0 0.0
1.2
2.0 —
1.4 0.0
0.85 —
2.1
1.4 0.0
2.4 0.0
2.2
2.1
1.0
1.2
2.0
1.4
0.85
2.1
1.4
2.4
136.77
334.9
654.7
551.15
2700.4
1101.3
1048.7
1975.0
1076.8
3065.3
2.35
1.46
1.696
1.0
1.0
1.776
2.030
1.0
1.66
1.33
108.35
278.0
1141.1
800.5
2353.2
1371.0
2030.9
1639.1
1340.5
2226.0
Urban
36
37
61
42
62
74*
63
43
44
92
87.5
132
SI
760
511
494
605
1255
595
804
C'71
C'72
C'74
C'72
C'72
C'72
C'72
C'72
C'75
C'72
S
119
132
81
(332)
M
760
511
494
60S
(2370)
L
1255
1159
1564
(3978)
141.1
1092.0
228. 9
7140.5
3445.2
4265.0
2063.4
8453.0
11338.0
4616.0
3490.0 0
0
1215.7 0
0
3155.8 0
2947.0 0
17719.0 0
26805.0 0
0
12152.0 0
135,000
135,000
135,000
135,000
135,000
135,000
135,000
135,000
135,000
135,000
2.5 0.0
0.9
1.66 0.0
0.5 --
0.4 0.0
2.2 0.0
0.3 0.0
1.1 0.0
0.7 --
1.3 0.0
2.5
0.9
1.66
0.5
0.4
2.2
0.3
1.0
0.7
1.3
258.4
94.7
72.8
344.15
155.52
1021.0
155.19
1426.0
1489.5
1677.4
8.08
1.0
1.08
1.0
1.19
1.147
2.64
1.59
1.947
3.044
180.13
183.4
76.5
1199.6
677.6
808.0
901.58
2259.6
3708.6
2248.9
-------
TVHI.l: 5-1 fcontini'i'.i)
POWER PLANT PARAMETERS; COAL PLANTS, REST OF COUNTRY
(Total)
(Total)
(Total)
(Total)
(Total)
(Total)
>lant
No.
"V
Code
N1W1980
C
103Ton
Fuel my Fuel
0 G 1980
103BBL 105FT3
1980 BTU/
Ih or/gal
S ('<
c myo
,) % S
G 1980
Emission
1980
(gm/sec)
"C" Factor
MY to 1980
Fuel Use
1980
103Ton
Rural
20
21
33
25
28
30
32
35
82*
96
116
325
213
216
500
1546
1771 .
3013
2034
1978
C'71
C'72
C'72
C'72
C'7S
C'75
C'71
C'7S
E'SO
E'80
S
116
325
213
(654)
M
700
500
(1200)
L
1546
1771
3013
2034
1978
(10342)
351.3
524.3
654.5
1407.0
1927.0
3791.0
2137.8
5701.3
6072.9
3577.0
C
-- 10,737 C
C
C
C
C
C
C
C
C
8,252
9,395
10,271
6,683
8,500
12,000
12,008
11,260
9,700
10,902
0.95 —
4.1
4.82
0.7
0.9
1.4
2.6
1.1
0.6
3.5
0.95
0.0 4.1
4.82
0.7
0.9
1.4
2.6
1.1
0.6
3:5
177.0
2654.2
1723.9
1677.0
947.8
3125.5
2981.6
3427.4
2090.7
7183.7
.
1.0
2.25
1.0
2.917
1.0
1.0
1.0
1.0
1.0
1.0
351.3
1128.3
654.5
4103.8
1927.0
3791.0
2137.8
5701.3
6072.9
3577.0
Urban
52
81
26
27
29
31
174
138
645
598
464
801
C'72
E'SO
C'72
C'71
C'71
C'72
S
174
138
(312)
M
645
598
464
(1707)
L
801
(801)
29.3
240.2
743.1
1337.3
461.8
1643.92
55.5 922.0 C
C
— 16,574 C
C
16,616.6 C
— 20,900.93 C
11,696
12,000
11,150
10,927
10,722
10,957
2.8
1.8
2.1
3.1
2.31
0.51 --
0.0 2.8
1.8
0.0 2.1
3.1
0.0 2.31
0.0 0.51
135.6
248.1
1842.0
2265.3
1697.7
776.04
5.16
1.0
2.16
1.0
2.92
1.73
84.41
240.2
1528.7
1337,3
1280.9
2652.0
-------
TABLE 5-1 (cont inner!)
POKER PLANT PARAMETERS; OIL PLANTS, REST OF COUNTRY
in
I
00
(Total)
(Total)
(Total)
(Total)
(Total)
(Total)
Plant
No.
MW
my
Code
NIW1980
Fuel my
COG
103Ton 103BBL 106FT3
Fuel
1980
1980 BTU/
Ib or/gal
S (%)
c myo
% S
G 1980
Emission
1980
(gm/sec)
"C" Factor
MY to 1980
Fuel Use
1980
103 Ton
Rural
64
67 *
69
79 *
68
55
87
78
66
87
409
177
1328
900
C'72
C'71
C'72
E'SO
C'71
C'71
E'SO
S
78
66
87
(231)
M
409
647
(1056)
L
1328
900
(2228)
76.95 4190.6
23.84 4009.2
10.0 2880.0
6200.0
65.27 7224.0
417.7 36437.4
5200.3
0
0
0
0
' 0
0
0
135,000
135,000
135,000
135,000
135,000
135,000
135,000
3.88
1.6
0.9
0.4
0.9
0.2
1.0
0.0 3.88
0.0 1.6
0.0 0.9
0.4
0.0 0.9
0.0 0.2
1.0
322.6
118.95
47.45
239.06
447.8
139.0
507.42
11.23
32.5
55.83
*
2.S
121.3
19.15
1.0
144.2
129.57
91.89
1041.6
867.13
1211.3
884.36
Urban
65
72
76
80
66
70
48
94*
99
96
75
216
346
247
714
331
860
1339
C'72
C'72
E'SO
E'SO
C'72
C'72
C'72
£'80
E'SO
S
96
75
216
346
(733)
M
247
714
(961)
L
910
860
1339
(3109)
108.0 2199.0
249.1 1020.0
2272.0
221.61 2940.0
432.1 5738.0
2763.0 23572.0
1744.4 7221.0
6769.0
7256.0
0
0
0
0
0
0
0
0
0
135,000
135,000
153,808
135,000
133,000
135,000
148,000
145,000
0.4
0.2
1.0
0.4
0.4
0.4
0.2
1.5
o.s
0.0 0.4
0.0 0.2
1.0
0.0 0.4
0.0 0.4
0.0 0.4
0.0 0.2
1.5
O.S
19.97
8.49
218.96
27.09
57.9
276.0
163.85
978.72.
349.7
4.87
0.484
1.0
3.168
3.576
2.427
4.82
1.0
1.0
87.01
74.02
381.62
118.05
2S2.3
1202.4
1427.1
1137.2
1219.0
-------
No.
MW
my
Code
MW
1980
Fuel
my
Sir
1980 BTU/lb
or BTU/gal
S_(%)
KEY TO TABLE 5-1
Code number for each plant.
Plant capacity, in megawatts, corresponding to the
model year status of the plants for which the dif-
fusion model run was based.
Indicates basic data source for MWmy and some of
the remaining columns; the indicated number refers
to model year. The two data sources were EPA-AQCR
Reports, denoted by "C", and utility companies,
denoted by "E".
Plant capacity, in megawatts, corresponding to pro-
jected 1980 plant status. Headings "S", "M", and
"L" represent 1980 plant capacity ranges: small
(less than 400 raw), medium (401 to 800 mw) and large
(greater than 800 mw).
Total fuel consumption of plant in the model year,
by fuel type: C = coal (in 103 tons), 0 = oil (in
103 barrels) and G = gas (in 106 cubic feet).
Fuel type assumed by NERA for the year 1980; either
C (coal) or 0 (oil).
Fuel heat value for the year 1980. Based upon pres-
ent fuel heat value or best estimate of 1980 fuel.
Percent sulfur content of fuels used in model year,
by fuel type designation employed in Fuelm column.
Percent average sulfur content corresponding to the
model year emission rate and concentration values
when these are altered to account for changes in
fuel type and capacity between the model year and
1980. For almost all plants, a value equal to the
Smy(%) was assumed.
Plant total stack average S02 emission rate based
upon the product of 1980 total fuel consumption and
percent average sulfur content of 1980 fuel.
Scale factor by which the concentrations obtained
from the diffusion models are adjusted to correspond
to different conditions of fuel consumption or fuel
sulfur content than those used in diffusion model
run.
The values from S % in the table are of little direct value
my
because this study will impose its own regulatory scenarios concerning
sulfur fuel content.
p
Some minor differences can be found between Table 5-1 and the
corresponding table in ERT Document P-1547B. In all cases the changes
are consistent with the assumptions used in the actual diffusion modeling.
Emission
1980
"C" Factor
5-9
-------
Remainder of States
Other High Sulfate States
No. Urban
Plants/No. Rural
Pfanfs
Figure 5-1 Locations of the 100 Power Plants in the Study.
-------
TABLE 5-2
DISTRIBUTION OF TOTAL COAL- AND OIL-FIRED GENERATING CAPACITY BY REGION
SIZE AND FUEL TYPE
Pre-1976 Capacityt
Region/Size
1. East, High Sulfate
400 Mw and Under
401 - 800 Mw
Over 900 Mw
1. East, Other
400 Mw and Under
401 - 800 Mw
Over 800 Mw
3. West Coast
400 Mw and Under
401 - 800 Mw
Over 800 Mw
2. Remainder, High Sulfate
400 Mw and Under
401 - 800 Mw
Over 800 Mw
3. Remainder, Other
400 Mw and Under
401 - 800 Mw
Over 800 Mw
Total-All Regions
400 Mw and Under
400 - 800 Mw
Over 800 Mw
Coal
Number
of
Plants
32
16
12
4
24
12
5
7
2
0
1
1
173
75
41
57
99
38
25
36
330
141
84
105
Pre-1976
Capacity
(Mw)
13,528
2,456
6,799
4,273
14,286
2,508
2,138
9,640
1,400
-
-
1,400
109,916
12,836
19,234
77,846
37,115
4,518
6,636
25,961
176,245
22,318
34,807
119,120
Coal-Oil*
Number
of
Plants
50
20
13
17
5
2
1
2
0
0
0
0
19
10
3
6
29
20
5
4
103
52
22
29
Pre-1976
Capacity
(Mw)
32,172
5,007
6,820
20,345
2,091
479
445
1,167
-
10,949
2,081
1,819
7,049
8,353
3,010
2,540
2,803
53,564
10,577
11,624
31,363
Number
of
Plants
50
30
13
7
40
24
6
10
35
18
5
12
15
12
2
1
144
88
31
25
284
172
57
55
Oil
Pre-1976
Capacity
(Mw)
20,601
4,983
7,697
7,921
12,731
3,561
3,079
7,091
22,194
2,798
2,735
16,661
2,358
2,098
260
0
59,077
13,015
16,699
29,363
116,961
26,455
30,470
60,037
Total
Number
of
Plants
132
66
38
28
69
38
12
19
37
18
6
13
207
97
46
64
272
146
61
65
717
365
163
189
Pre-1976
Capacity
(Mw)
66,301
12,446
21,316
32,539
29,108
6,548
5,662
16,898
23,594
2,798
2,735
18,061
123,223
17,015
21,313
84,895
104,545
20,543
25,875
58,127
346,770
59,350
76,901
210,520
tltems may not add to total due to rounding.
*Plants defined by the National Coal Association as coal-oil or coal-oil-gas and using some coal in 1974; or oil-
fired capacity defined by the Federal Energy Administration as convertible to coal.
Source: Analysis of NERA computer files.
5-11
-------
TABLE 5-3
DISTRIBUTION OF TOTAL COAL- AND OIL-FIRED GENERATING CAPACITY BY REGION
SIZE AND FUEL TYPE
Capacity Added 1976-1980t
Coal
Region/Size
1. East, High Sulfate
400 Mw and Under
401 - 800 Mw
Over 900 Mw
1. East, Other
400 Mw and Under
401 - 800 Mw
Over 800 Mw
3. West Coast
400 Mw and Under
401 800 Mw
Over 800 Mw
2. Remainder, High Sulfate
400 Mw and Under
401 800 Mw
Over 800 Mw
3. Remainder, Other
400 Mw and Under
401 - 800 Mw
Over 800 Mw
Total-All Regions
400 Mw and Under
400 - 800 Mw
Over 800 Mw
Number
of
Plants
32
16
12
4
24
12
5
7
2
0
1
1
173
75
41
57
99
38
25
36
330
141
84
105
1976-1980
Capacity
Added
(Mw)
850
850
2,074
798
1,276
500
500
15,058
852
3,858
10,849
35,730
1,225
7,731
26,774
54,213
2,077
12,387
39,749
Coal-Oil*
Number
of
Plants
50
20
13
17
5
2
1
2
0
0
0
0
19
10
3
6
29
20
5
4
103
52
22
29
1976-1980
Capacity
Added
(Mw)
3,808
126
400
3,282
1,792
1,792
1,890
60
1,830
2,753
400
233
2,120
10,244
586
633
9,025
Number
of
Plants
50
30
13
7
40
24
6
10
35
18
5
12
44
12
2
1
161
88
30
25
284
172
57
55
Oil
1976-1980
Capacity
Added
(Mw)
1,242
-
1,242
5,096
399
553
4,144
292
-
292
3,792
42
1,250
2,500
5,296
455
1,316
3,525
15,718
896
3,119
11,702
Total
Number
of
Plants
132
66
38
28
69
38
12
19
37
18
6
13
236
97
46
64
289
146
60
65
717
365
163
189
1976-1980
Capacity
AHded
(Mw)
5,900
126
400
5,374
8,962
399
1,351
7,212
792
500
292
20,740
954
4,608
15,179
43,779
2,080
9,280
32,419
80,175
3,559
16,139
60,476
tltems may not add to total due to rounding.
*Plants defined by the National Coal Association as coal-oil or coal-oil-gas and using some coal in 1974; or oil-
fired capacity defined by the Federal Energy Administration as convertible to coal.
Source: Analysis of NERA computer files.
5-12
-------
TABLE 5-4
MEGAWATT VALUES USED IN DERIVING EXPANSION FACTORS
On
CBS
CEM
CEL
CTS
CTM
CTL
CRS
CRM
CRL
OES
OEM
DEL
ORS
ORM
ORL
100- Plant
(MW)
978.
4999.
11411.
1760.
3634.
24559.
966.
2907.
11143.
601.
3669.
10676.
1211.
1770.
5337.
100 Plai
01.1
05.8
13.3
02.1
04.2
28.7
01.1
03.4
13.0
00.7
04.3
12.5
01.4
02.1
06.2
NERA
Pre-1976
(MW)
10450.
16202.
35425.
14917.
21053.
84895.
7528.
9176.
30164.
10676.
11036.
14012.
15813.
19434.
46024.
Pre-1976
03.0
04.7
10.2
04.3
06.1
24.5
02.2
02.6
08.7
03.1
03.2
04.0
04.6
05.6
13.3
SUM
85621;
100.0
346805.
100.0
NERA
1976-80
(MW)
126.
1198.
7200.
912.
3358.
12679.
1625.
8464.
28894.
441.
1803.
7886.
455.
1316.
3817.
80174.
1976-80
00.2
01.5
09.0
01.1
04.2
15.8
02.0
10.6
36.0
00,
02.
09,
00.6
01.6
04.8
100.0
KEY
Combinations of the following: for example, CES = coal fired, eastern U.S., small plant,
C - coal
0 - oil
E - eastern
T - other high sulfate areas
R - rest of country
S - small plants
M - medium plants
L - large plants
-------
Expansion of our sample population to the national population was
carried out separately for each element of our three-region, two-fuel-
type, and three-capacity range stratification. However, as noted pre-
viously, oil plants in the east coast, west and in other high sulfate states
were combined so that a total of 15 categories resulted. That is, the
east coast coal fired plants of less than 400 megawatts (CES) in our
sample were taken to be representative of the national population of
such plants and so on.
Separate expansions were made for the pre-1976 NERA population and
the 1976-1980 capacity additions. In this way we 'attempted to maintain
trends in size, location, or fuel type which would distinguish new
plants from the existing population.
Table 5-4 shows 80,174 megawatts as added to the pre-1976 capacity
of 346,805 between 1976 and 1980. This corresponds to a capacity growth
rate of 4.16 percent per year. This is one of the growth rates used in
the calculations. However, we have used a method which permits other
growth rate assumptions to be used as well as permitting calculations
for various model years. This consists of normalizing each of our
15 categories relative to the total population for the model year in
question. For example, from Table 5-4 it is seen that Coal, East Coast,
Small (CES) comprises 3.0 percent of the pre-1976 population and 0.2 per-
cent of the 1976-1980 population. Thus with a growth rate a (4.16 per-
cent) as a fraction per year we take the percentage in model year t to
be:
CCES) = 5 + 0*
e
For 1983 (t = 8 years), the percentage of CES is therefore cal-
culated as 2.2 percent of the total power plant population.
All megawatts falling into this category in model year t are
assumed to have the control system requirements of the sample popula-
tion. The following sections begin the discussion of how control system
requirements are determined.
5-14
-------
5.3 Regulatory Scenarios for Sulfur Oxides
The energy consumed for sulfur oxide control at any plant is
calculated on the basis of fuel type, geographic region, available and
permissible control technologies, and regulatory requirements. This
section describes how the regulatory requirements are analyzed. The
other factors listed above are discussed in subsequent sections.
The first step is the determination of complying fuel sulfur
values, these are the highest sulfur content fuel that each of the
100 plants can fire and meet regulatory requirements. The requirements
which determine complying fuel sulfur values are based on the following
sulfur oxide regulatory scenarios:
Primary National Ambient Air Quality Standards (PAQS)
The fuel sulfur content required in order for the 24-hour standard
of 365 yg/m to be reached exactly once per year is obtained from the
diffusion modeling completed in l!An Evaluation of Sulfur Oxide Control
Requirements for Electric Power Plants", (ERT, 1975). The description
of the diffusion modeling and the methods used for these calculations
are fully described in that ERT report. The primary standard for an
annual averaging time is not considered because it is not considered
controlling for major point sources.
Air Quality Standards (AQS)
This air quality goal is defined to include both primary and
secondary national ambient air quality standards. The diffusion model
results from ERT's report P-1547 were used to determine the fuel sulfur
content for compliance with the 3-hour secondary SO- standard (1,300 iag/m ),
not to be exceeded more than once per year. The complying fuel for AQS
is the lower fuel sulfur content required to meet the 3-hour or the
24-hour standard.
New Source Performance Standards (NSPS)
This requirement applies only to new plants. The emission limits
of 1.2 Ibs S02 per million Btu heat input for coal and 0.8 Ibs S02 per
5-15
-------
million Btu heat input for oil were converted to percent sulfur in fuel
values by using the 1980 fuel heating values listed in Table 5-1.
State Implementation Plans (SIP)
The requirements for complying fuel sulfur values in the State
Implementation Plans for each of the 100 plants in the sample were
obtained using the fuel heating values in Table 5-1 in conjunction with
a computer file of emission limits maintained by EPA. The values
obtained were current as of March 13, 1975.
Non-Deterioration Class II Increments (ND)
Only new plants are required to meet non-deterioration require-
ments. The complying fuel sulfur value is the more stringent of those
3
necessary to meet the 3-hour (700 ug/m ) increment or the 24-hour
(100 pg/m ) increment as described in the Federal Register of December
16, 1974.*
The Class II Nondeterioration increments to existing background are
calculated from the modeling results for air quality standards (AQS).
For example, for 3-hour concentration values, we use the formula:
3 = 700 3
ND 1500 - CD AQS'
D
where S and S „ are the complying fuel sulfur values for Class II
non-deterioration requirements and air quality standards based on 3-hour
averaging times. C is the 3-hour background concentration value for
D
the plant in question.
Background values for each of the 100 plants in the sample were
derived from EPA-summarized data for each of the Air Quality Control
Regions (AQCR) in which a plant was situated. On a line representing
"Class I permitted increments have not been considered in the modeling
analysis. In addition, the U. S. Congress in both the House and Senate
have ND sections in the 1977 Clean Air Act Amendments which would
affect the classes and increments to be allowed for N6, However, the
modeled values are consistent with present regulations may provide
an approximation of the effects of the proposed legislation.
5-16
-------
the distribution of 24-hour averages at a monitoring site, the 80th per-
centile was chosen as the background concentration for urban areas and
the 60th for rural areas. The same procedure was followed to derive
3-hour average background concentrations.
Best Available Control Technology (BACT)
This regulatory scenario presupposes that the BACT requirement will
be imposed as of January 1980. The control systems that might require
it have been defined here for example purposes as:
• All new units install scrubbers.
• Half of all oil used is desulfurized.
• Half of all coal is washed.
Table 5-5 summarizes the regulatory scenarios for sulfur oxide
control. Scenarios 1 through 5 are presently in the regulatory structure
and constitute a subset which will be called All Present Regulations
(APR).
TABLE 5-5
SULFUR OXIDE REGULATORY SCENARIOS*
1. 24-hour primary National Ambient Air Quality Standard (PAQS).
2. 24-hour primary National Air Quality Standard and 3-hour secondary
National Ambient Air Quality Standard (AQS).
3. New Source Performance Standards (NSPS).
4. State Implementation Plans (SIP).
5. Non-Deterioration Class II permitted increments (ND).
6. Best Available Control Technology (BACT).,
*Scenarios 1 through 5 constitute All Present Regulations (APR).
5-17
-------
5.4 Oil to Coal Conversion
Complying fuel sulfur values for all regulations under the model
assumption that oil plants in the sample convert to coal can be calcu-
lated directly given the oil and coal heating values. (It should be
recalled that new source performance standards specify different emis-
sion limits for coal and oil plants). The oil heating values are the
1980 values listed in Table 5-1. The coal heating values are based on a
state by state analysis of present properties as obtained from (NCA,
1974). The ratios of coal to oil heating values for the plants in the
100 plant sample are shown in Table 5-6.
Complying fuel sulfur values for all regulations and with and with-
out coal conversion are shown in Table 5-7. The "with conversion to
coal" column lists only the altered values when oil-fired plants switch
to coal. The sulfur fuel values are given as the highest percentage
sulfur content which meet with the indicated regulatory scenario for
that plant.
The last regulatory scenario, BACT, has not been included because
it implies control without regard to fuel sulfur values or ambient air
quality. Where the value 99.00 occurs in the State Implementation Plan
(SIP) column, it means that it was not possible to express the SIP for
that state in terms of complying sulfur fuel values.
5.5 Complying Fuel Histograms
For a set of sulfur dioxide control regulations and given assump-
tions about coal conversion, each plant in the sample has a complying
fuel sulfur content associated with it. This is the highest sulfur fuel
the plant can burn and meet all regulatory requirements.
This plant-by-plant data is used to compile a complying fuel
histogram by sulfur content range for each geographic region and for
each size stratification. The complying fuel histogram gives the
fraction of the megawatts being considered which require fuel in various
sulfur content ranges. The breakdown into complying sulfur in fuel
ranges is made because control technology and hence energy requirements
can be determined from the fuel range.
5-18
-------
TABLE 5-6
RATIO OF COAL TO OIL HEATING VALUES
Plant #
36
37
38
39
42
43
44
45
46
47
48
49
50
54
55
61
62
63
64
65
66
67
68
69
70
71
72
74
76
79
80
87
89
92
94
99
State
Ratio
CA
R.I.
FLA
FLA
MASS
FLA
FLA
FLA
FLA
MASS
CALIF
FLA
FLA
FLA
MISS
FLA
NY
NY
MISS
CALIF
CALIF
MISS
MISS
ARIZ
CALIF
NY
SD
FLA
OKLA
TX
TX
OKLA
NY
FLA
LA
TX
0.64357
0.73727
0.62165
0.62165
0.64771
0.62165
0.62165
0.62165
0.62165
0.64771
0.41312
0.62165
0.62165
0.62165
0.66372
0.62165
0.67181
0.67181
0.66372
0.41312
0.41312
0.66372
0.66372
0.57674
0.41312
0.67181
0.43165
0.62165
0.66612
0.38556
0.38556
0.66612
0.67181
0.62165
0.38158
0.38556
5-19
-------
icunoi ruiL tm
\\
14
too
1
1
T
I
*
It
l»
(2
It
S3
15
95
4
Tl
65
IS
• 4
S
17
14
11
57
S»
16
54
9<
II
T>
TS
«1
to
20
21
31
»5
»6
30
»2
35
it
•17
(9
• 6
17
50
S«
71
36
J7
61
«2
12
7«
63
• 3
• <
92
64
47
»1
7«
• 9
«
97
65
T2
76
eo
«6
10
68
-T
-E
-C
-R
E+T
-R
-O
TABLE 5-7
COMPLYING FUEL SULFUR VALUE
UK 10} IIP M> 1JP fill 691 SIP 40 NIP PtOl
WITHOUT CONVERSION TO COAL WITH CONVERSION TO COAL
IT*
Z»3
JUS
Ml
eo
242
45?
»«e
«IO
Zi5»
IT67
2MI
1611
MOO
U50
1096
10(6
1097
194
511
• 01
1275
490
1580
504
799
531
67?
3499
lies
US
272
til
461
«ie
495
2351
1627
325
700
too
1771
3013
2019
l»76
174
13S
615
59«
5u
215
790
559
1200
1029
1102
964
605
1598
119
• 1
760
511
ilia
605
mi
1564
66
• 7
607
1)29
too
96
75
216
306
714
110
HAD
1)19
0.25
2.51
0.06
0.73
0.61
1.03
7.56
2.99
2.23
9.02
4.16
2.U3
2.96
1,61
«,04
1,00
1,65
1.11
3,79
2,07
1.35
9.22
3.29
2,12
2.12
3,»5
3.29
1.00
0.72
• .94
2.3S
5,23
0.23
1.55
10.01
0,60
11,65
2.11
2,99
2,51
7,01
0,22
4,00
10.16
3,99
1.34
U.74
2.2B
4,02
4.10
3.55
1.05
2,53
0,67
1.44
0,09
0,12
6,30
0.65
0.54
1,92
B.42
0.60
0,20
1,00
2,06
0,90
1,92
2.40
2.24
0.43
1.51
0,S6
o.ss
1.95
0,58
1.50
i.oa
.48
,66
.36
.•>o
.34
1,99
3.00
1,00
99.00
0,30
0,20
1.00
0,30
2.82
1.00
2,00
1.10
2,30
99,00
2,40
1.39
1.40
0,90
0,90
0,90
1.00
1,00
3,00
0.90
0,04
0,10
0,90
0,10
0,40
0,90
J.90
I.H.I
i.lt
1,90
49,00
0,50
2.40
99,00
4V,00
0,40
0,40
99,00
99,00
1.16
0,14
0,10
0.44
4,119
1.11
1.07
3,42
2,61
0,91
1.10
1,02
1.67
0,28
0,64
0,49
1.81
0,5"
1,48
1.24
0.65
1.58
1.16
O.P8
0.21
1.62
C,86
1,89
0.12
3.02
0.18
6.20
1.21
0,91
2,65
0,09
1,81
O.q6
8.66
1,05
1.89
1.74
1.14
0.48
0.98
0,14
0,50
0,01
0,04
2.11
0,2V
0.1*
0,44
'.-17
0,10
0,11
0,98
0,66
0,72
0,72
0.67
0.67
0.67
0,65
0.66
0.64
0,64
0,69
0.64
0,67
0,71
0,75
0,72
0,75
0,75
0.7S
0,75
0,71
0,75
0.75
0.56
0.4Q
0.41
0.72
0.68
0.58
0,72
0,67
0,66
0,67
0,67
0,67
0,74
0,67
0,(.7
0,67
0,67
0.67
0,67
0,67
0.67
0,/u
0,67
,67
.6'
.67
,67
0,67
0,67
0,67
0.77
0,«7
0.67
0,74
0.71
0.62
1.06
1.01
1.44
12.22
2.98
1.38
12, M
.16
,00
.10
,61
1,00
2.39
1,67
5,66
1.86
9.22
3.29
2.12
3.65
3.61
1.00
0,72
5,44
3.02
6.52
0,41
10.04
0.60
17,71
5,78
2.S6
8,27
0.27
5.21
1.41
24.65
2,78
5.02
4,97
3. 44
1.36
3.12
0...7
l.»2
0.09
0.11
7.64
0,75
0.54
1.42
«,u2
0,95
0,(6
J.01
2,31
0,0
0,0
o.o
0.0
0,0
0.0
0,0
0.0
o.o
0.0
0.0
0.0
0.0
o.o
0,0
o.o
0,0
0.0
o.o
0,0
o.o
o.o
o.o
0.0
0.0
0.0
o.o
0,0
o.o
o.o
1.86
1.90
4.16
0.15
2.65
O.t)6
11.68
l."8
2,'0
2.74
2.38
0.65
1.47
0,44
0.42
0.06
0.08
4,20
0,27
0.23
1,28
1,25
O.S1
0,«8
I.'"
0.''
0.0
o.o
0,0
0,0
0,0
0.0
o.o
0,0
0.0
0,0
0,0
o.o
0.0
o.o
0.0
o.o
0,0
o.o
0.0
0.0
o.o
0,0
0,0
0,0
0,0
o.o
0.0
o.o
0,0
0.0
o.o
0,76
0.76
0,76
1,11
0.67
1.91
0.76
0,29
0,20
0,76
0,20
0,76
0,76
2.44
1.04
2.44
•2.49
49,00
0,21
1.04
94,00
94,00
0.21
9'i.on
94,00
0,0
0,0
0.0
o.o
o.o
0,0
0,0
o.o
o.o
o.o
o.o
o.o
o.o
0,0
o.o
o.o
o.o
o.o
o.o
o.o
o.o
o.o
0.0
0,0
o.o
0.0
o.o
o.o
0,0
o.o
0,0
0.75
0.57
1,64
0.06
1.23
0.24
4.38
0.64
1.27
1.08
0,40
0,10
0.72
0.13
0,24
0.02
0.02
1,42
0.10
0.07
O.J6
0.92
0.12
0.01
0,17
0,25
0,0
0,0
0.0
o.o
0,0
0,0
o.o
0.0
o.o
o.o
0.0
o.o
o.o
0.0
0.0
0.0
0,0
o.o
o.o
o.o
0,0
0,0
o.o
0,0
o.o
o.o
0.0
o.o
0.0
0.0
0,0
O.A3
0,61
0,61
0.75
0,68
0,65
0.63
0,66
0,68
0.6!
0,*»
0.63
0.63
0,67
0,58
0,47
0,1,7
0.67
0,42
0,44
0,6'
0,49
0,4?
0,«2
0.4?
o.«?
0,0
0.0
0.0
0.0
o.o
0,0
0,0
0,0
0,0
o.o
o.o
0,0
0,0
0,0
o.o
o.o
o.o
o.o
o.o
o.o
o.o
0,0
0,0
0,0
0.0
0.0
0.9
0,0.
o.o
o.o
o.o
0.0
0,0
0,0
1,31
2.35
1,78
5.14
0,18
1,50
0,48
15.32
1.48
3.17
1,09
2,18
0,95
2.06
0,44
1.04
0,06
0,04
5,10
0.31
0,2)
1,28
1,24
O.J9
0,15
1.14
0,90
E=East Coast, R=Rest of Country, T=0ther "High Sulfate"
0=0il, C=Coal
5-20
-------
The ranges of sulfur fuel percentages which have been used are:
0.1-0.316, 0.316-1.0, 1.0-3.16, 3.16-10.0. The dividing points between
various fuel ranges are related by powers of /To~ = 3.16. This division
is convenient in that it corresponds to the break points for SCL control
technology and has a logical construction. In addition when plotted on
a logarithmic scale the width of each element in the complying fuel
histogram is then constant.
An example helps make these ideas clear. Assume that all plants
need only meet primary and secondary national ambient air quality
standards (see Scenario 2, AQS) and further assume no plants are converted
to coal, then, using the data in Table 5-7, the megawatts in the sample
calculation can be arranged by complying fuel range as shown in Table 5-8.
The complying fuel histogram for this case is shown in Figure 5-2
together with the histograms for the old and new plant populations that
result when each element of Table 5-8 is expanded as discussed in
Section 5.2. Figure 5-2 also shows the complying fuel histogram that
•
results when old and new plant histograms are combined, in this case
with an assumed growth rate of 4.16 percent per year between the end of
the base year 1974 and the end of 1983.
For simplicity, Figure 5-2 does not indicate any distinction in
fuel type. In actually performing calculations such a distinction is
maintained. Figure 5-3 shows the 1983 complying fuel histogram with the
contributions of oil (o) and coal (c) fired megawatts identified.
The complying fuel histogram for future years (in this case 1983)
forms the basis for our analysis of sulfur oxide control technologies
and their associated energy consumption.
5-21
-------
TABLE 5-8
BREAKDOWN OF MEGAWATTS IN THE 100 PLANT SAMPLE BY
COMPLYING FUEL RANGE FOR AIR QUALITY STANDARDS
WITH MINIMUM COAL CONVERSION
Sulfur Content Range (percent)
Fuel/Area 0.1-0.316 0.316-1.0 1.0-3.16 3.16-10.0
I . Coal
East Coast
S
M
L
0
0
0 2,
481
0
351
0
3,632
7,233
497
1,367
1,827
Other High Sulfate Areas
S
M
L
Rest of Country
S '
M
L 2,
II. Oil
East Coast and
S
M
L 1,
Rest of Country
S
M'
L 2,
III. Total (MW) 6,
90 7
r
Key: S - small
M - medium
L - large
434
0 1,
0 1,
0
0 1,
034 1,
0
050
100
441
809
978
611
1,527
17,449
174
0
2,572
715
1,057
6,010
351
1,098
4,559
V.
Other High
0
0
200
0
647
238
553 10,
.65 12
Sulfate
0
0
0
484
714
0
408
.16
Areas
388
1,500
3,978
303
409
2,199
41,975
49.02
213
2,169
5,498
424
. 0
900
26,685
31.17
5-22
-------
ts;
NJ
50.
40 •
50,
20
% of Population
49.02
12.16
1 - - 7 .65
31
1 .316
3.16 10
% Sulfur Content
100 Plant Sample
% of Population
t VJ —
30 -
70
10 -
1 8. 63
10.56
36.28
34.53
.1 .316 1 3.16 10
% Sulfur Content
New Plants
50'
40.
30
10
% of Population
46.40
0.7:
T4 . 70
28.18
50.
40-
*
30.
20.
X
10.
% of Population
4.5.24
15.95
10.67
50.16
.1 .316 1 3.1610
% Sulfur Content
1983 Population
Figure 5-2
.1 .316 1 3.1610
% Sulfur Content
Old Plants
Complying Fuel Histograms: Example for all Plants Meeting AQS with
No Coal Conversion and 4.16%/yr .Growth Rate
-------
o
•H
4->
cti
i— I
I
Cu
8
o
a,
3U -5—
40%-
30%-
20%-
10%-
10.67
0:6. 71
c:3.96
15.93
o:3.09
c:12.84
43.24
o:11.05
c:32.19
30.16
o:8.47
c:21.69
,1%
.316%
1%
3.16%
10%
Percent Sulfur Content
Figure 5- 3 Oil (o) and Coal (c) Contributions to the
1983 Complying Fuel Histogram of Figure 5-2
5-24
-------
5.6 Sulfur Oxide Control Technologies
For each fuel type (coal or oil) and for each complying fuel range,
the control technologies which provide sufficient control are determined.
The energy consumption of these controls have been specified (see
Table 3-2). Three major scenarios have been selected in approaching the
myriad of sulfur oxide control technologies available. The second and
third scenarios are the addition of coal washing and blending, both pre-
plant energy consumption systems, to the basic scenario. To each of
these scenarios a number of options could be added based on tall stacks
or supplementary control systems (SCS). Table 5-9 summarizes the
scenarios and the options and a complete discussion follows.
Scenario l.S Scrubbers and Low Sulfur Fuel
The general method used in each of these scenarios is to construct
a matrix of energy consumptions in percentages. The energy consumption
matrix for scenario l.S is shown in Table 5-10. This matrix in general
describes the percentage energy consumption needed to obtain an equivalent
sulfur fuel range. If meeting a particular regulatory scenario requires
sulfur fuel content in the range 1.0-3.16 percent, the energy consumption
for each fuel and/or region is shown in that column. This complying
fuel could be obtained by either scrubbing the available coal in that
region or transporting it from a region which does have that sulfur
content coal.
In order to pursue this analysis in a reasonable manner, two simpli-
fying assumptions have been made about coal availability.
• Mixed coal is only available in the 0.316-1.0 and 3.16-10.0 per-
cent sulfur ranges.
• The low sulfur coal (0.316-1.0 percent) is only available in
region A.
While the actual case is somewhat less restrictive, these assumptions
form a practical basis for modeling the complex of options. The regions
are as presented in Figure 3-2.
5-25
-------
TABLE 5-9
SULFUR OXIDE CONTROL TECHNOLOGY SCENARIOS
1.S Scrubbers and Low Sulfur Fuel
Compliance through the use of low sulfur western coal and scrubbers
at coal fired plants. Compliance through oil desulfurization at
oil fired plants.
2.S Addition of Coal Washing
Same as scenario l.S but coal washing is used wherever it can
replace scrubbers.
3.S Addition of Coal Blending
Same as scenario l.S but blending of low sulfur western coal is
used wherever it can replace scrubbers.
Options (can be combined with any of the above scenarios.)
SCS(E) SCS permitted everywhere at both old and new plants.
SCS(ROC) SCS permitted in the rest of the country outside of so called
"high sulfate states".
TS(EJ Tall stacks permitted everywhere for new plants.
TS(ROC) Tall stacks permitted at new plants only outside of so called
"high sulfate states".
5-26
-------
TABLE 5-10
ENERGY CONSUMPTION MATRIX (PERCENT BY PLANT) •
SCENARIO l.S SCRUBBERS AND LOW SULFUR FUEL "MOST LIKELY" VALUES
Sulfur Fuel Range
(Percent Sulfur in Fuel)
Plant
Type
Coal
Area
Region A
Region B
Region C
Oil
0.1-0.316 0.316-1.0
1.0-3.16 3.16-10.0
3a
ya+b
ea+b
o
6a
0
4a
4a
3C
0
3a
3a
0
0
0
0
0
a. scrubbing utilized
b. transportation utilized
c. desulfurization utilized
5-27
-------
A detailed discussion of Table 5-10 is best started with plants
that need 0.316-1.0 percent sulfur fuel and are coal-fired in Region B.
Since Region B doesn't have any low sulfur coal, coal could be transported
from Region A at a 4 percent energy consumption, or scrubbers could be
used for 3.16-10.0 percent coal also at a consumption of 4 percent to
achieve the needed sulfur fuel range. Since both methods result in the
same energy consumption, the only difference might be in coal availability.
For this case we have chosen to scrub and save the low sulfur coal for
other needs. For Region C, however, scrubbing for the 0.316-1.0 percent
coal range was selected.
For the column headed 1.0-3.16 percent sulfur, not as much scrubbing
would be required. An assumption that 75 percent of the stack gases will
be scrubbed has been made, thus a 3 percent energy consumption. Coal-
fired plants in Region C with a requirement for 0.1-0.316 percent sulfur
could transport low sulfur coal (5 percent) and then partially scrub it
(3 percent). The energy requirement in each sulfur range is therefore,
a combination of scrubbing and transportation to achieve that complying
sulfur range from the available coal. The oil energy consumptions
represent the necessity for desulfurization to meet the lower sulfur
fuel requirements.
This input matrix of energy consumption is then multiplied by the
number of megawatts in an identical matrix. Section 5.5 develops a
complying fuel histogram for a specific regulatory scenario (AQS) for
the 1983 population of power plants and divided by coal and oil. The
only remaining breakdown is by region for coal. The 100 plant sample
and its expansion are based on the geographic regions shown in Figure 5-1.
The energy consumption matrix is, however, based on coal regions (see
Figure 3-2). It was assumed, because a common basis was not obtainable,
that the percentage of megawatts of coal-fired power was nearly equiva-
lent to the percentage of total generating capacity by region'. Table 5-11
shows that, for 1973 data, that was in general the case. A nominal
weighting factor was selected and is used to divide the total coal-fired
megawatts projected for 1983 into each of regions A, B, and C. In other
words,, we expect that 52 percent of the coal will be used in Region C
since 52 percent of megawatt generating capacity will be there.
5-28
-------
TABLE 5-11
DISTRIBUTION OF UTILITY COAL CONSUMPTION AND GENERATING CAPACITY BY REGION
Coal Region
Geographic
Areas
Distribution of
Utility Coal
Consumption, 1973
(% of Btu content)
Distribution of
U.S. Generating
Capacity, 1973
(% of Capacity}
Weighting
Factor
in
A) Low Sulfur Coal
Indigenous and
Available
West North
Central
Mountain
14
11
0 .12
B] Low Sulfur Coal
Could Be
Transported
East North
Central
West South
Central
35
37
0.36
C) Low Sulfur Coal
Unavailable
New England
Mid-Atlantic
South Atlantic
East South Central
Pacific
51
52
0 .52
-------
The complying fuel matrix is calculated using a computer program
(see Appendix B). Then using an input energy consumption matrix, the
program calculates the national total energy consumption for the regula-
tory scenario of interest.
Energy consumption matrices for a range of process energy consump-
tions were tested. Table 5-10 is for the "most likely" values- in
Table 3-2. Other calculations were made for the high and low ends of
the range so that the range of final results could be shown. Separate
matrices could also be developed for the pre-plant, in-plant and post-
plant breakdown. Those matrices as well as the oil, coal and electricity
breakdown are developed from Table 3-3.
Scenario 2.S Addition of Coal Washing
This scenario provides for the replacement of scrubbers with coal
washing where possible. The energy consumption matrix is shown in
Table 5-12. The energy consumption for oil-fired plants remains the same
as in Scenario l.S. One major assumption is that coal washing will not
be able to reduce the sulfur fuel percent by more than one percentage
range. Therefore, plants in Region C which need 0.316-1.0 percent
sulfur fuel cannot use washing of 3.16-10.0 percent sulfur coal but must
scrub the flue gas from that coal. In the 0.1-0.316 and 1.0-3.16 percent
ranges coal washing can, however, be used and transportation added where
needed.
Scenario 5.S Addition of Coal Blending
Instead of substituting coal washing, this scenario substitutes
coal blending for scrubbers where possible. The assumptions necessary
for this scenario follow:
• Blending can only be used to obtain 1.0-3.16 percent coal from
the blend of 3.16-10.1 percent coal and low sulfur western
coal.
• Blending is in the ratio of 1/3 low sulfur to 2/3 high sulfur
coals.
5-30
-------
TABLE 5-12
ENERGY CONSUMPTION MATRIX
SCENARIO 2.S ADDITION OF COAL WASHING "MOST LIKELY" VALUES
PERCENT BY PLANT
Plant
Type
Coal
Sulfur Fuel Range
(Percent Sulfur in Fuel)
Area
Region A
Region B
Region C
0.1-0.316 0.316-1.0
1.0-3.16 3.16-10.0
Oil
d
7
llb+d
12b+d
6C
0
4b
4a
3C
0
7d
7d
0
0
0
0
0
a. scrubbing utilized
b. transportation utilized
c. desulfurization utilized
d. coal washing utilized
5-31
-------
The energy consumption matrix for Scenario 3.S is shown in Table 5-13.
The above assumptions imply that the only alteration to the Scenario l.S
energy consumption matrix for the Scenario 3.S matrix is in the 1.0-3.16 percent
sulfur column. The 1 percent values shown in that column are for blended
coal where the energy consumption is for transportation of 1/3 of the
coal from Region A and 1/3 the transportation energy consumption rate.
Options
Each of the following four options can be added to any of the three
major scenarios to quantify the effect.
Option SCS(ROC) Supplementary Control Systems in Low Sulfate Areas to
Meet Air Quality Standards
In this scenario, supplementary control systems are permitted
outside the East Coast and other high sulfate states (rest of the country,
ROC) in order to meet air quality standards. Energy requirements for
each complying fuel range are the same as for Scenario l.S, given by
Table 5-10. Data on the changes in fuel requirements which this permits
in the rest of the country is obtained from ERT Document 1547B [ERT, 1975].
Table 5-14 shows the percentage of megawatts in three complying
fuel ranges, 0.1-0.316, 1.0-3.16, >3.16 with and without supplementary
control systems of assumed 95 percent reliability. Only the ROC portion
of the 100 plant sample is considered and compliance is based only on
air quality standards.
The results of the previous study shown in Table 5-14 are not yet
in a form appropriate for use in the present study. In order to use
these results, we make the following assumptions:
• The effect of supplementary control systems is to shift unit
complying fuel requirements to the next higher complying fuel
sulfur range (As opposed to skipping over a complying fuel
range entirely).
• The fraction of the megawatts shifted in the range 0.1 - 0.316
is the same as in the range 0.316 - 1.0.
5-32
-------
TABLE 5-13
ENERGY CONSUMPTION MATRIX
SCENARIO 3.S ADDITION OF COAL BLENDING "MOST LIKELY" VALUES
PERCENT BY PLANT
Plant
Type
Coal
Oil
Area
Region A
Region B
Region C
Sulfur Fuel Range
(Percent Sulfur in Fuel)
0.1-0.316 0.316-1.0
1.0-3.16 3.16-10.0
a
3
_a+b
8a+b
6C
0
4b
4a
3C
0
ld
ld
0
0
0
0
0
a. scrubbing utilized
b. transportation utilized
c. desulfurization utilized
d, blending utilized (energy use as transportation)
TABLE 5-14
PERCENTAGE OF ENERGY GENERATION BY SULFUR FUEL RANGES
REDISTRIBUTION WITH USE OF 95% RELIABLE SUPPLEMENTARY CONTROL SYSTEMS
Sulfur Fuel Range
(Percent Sulfur in Fuel)
0-1
1-3
>3
without SCS
with SCS
without SCS
with SCS
40
14
46
31
20
44
26
15
40
42
28
54
Coal
Oil
5-33
-------
With these assumptions, the fraction of the population in each
complying fuel range which moves to the next higher sulfur complying
fuel range (the switch factor) can be determined from Table 5-14.
Results are shown in Table 5-15.
Option SCS(E) Supplementary Control Systems Permitted Everywhere to
Meet Air Quality Standards
Energy requirements for each complying fuel range are again based
on Table 5-11. Switch factors for East Coast and other high sulfate
states in addition to rest of country are computed by the same method as
in Option SCS(ROC). The results are also shown in Table 5-15.
Note that switch factors for oil units in East Coast and other high
sulfate states are identical since these regions are combined in the
calculations.
Option TS(ROC) Post-1974 Units Outside the East Coast and Other
High Sulfate States and Option TS(E) Plants Everywhere
Use Tall Stacks to Meet Air Quality Standards
In these options, energy requirements are the same as in the basic
scenario used and the concept of a complying fuel range switch factor is
again used. The basic assumption is that tall stacks would permit new
units to fire fuel in the next highest complying fuel range.
This assumption has not been verified by site specific model calcu-
lations. We can, however, give a rough estimate of the increases in
stack height which would be required.
The peak concentration downwind of a point source will vary roughly
as the inverse square of the effective plume height (the plume rise plus
the physical stack height). A change in complying fuel range will thus
accompany an increase in effective plume height of /3.16 = 1.78. Where
plume rise contributes little to effective plume height (under peak
concentration conditions) an increase in physical stack height by this
amount would be required. Where effective plume height is mainly due to
plume rise, a physical stack height of 0.78 times the plume rise would
be required.
5-34
-------
TABLE 5-15
PERCENTAGE OF FUEL RANGE SWITCHES
FOR SUPPLEMENTARY CONTROL SYSTEM OPTIONS
Sulfur Fuel Ranges
Switch
from
Switch
to
0.1-0.316 0.316-1.0
0.316-1.0 1.0-3.16
1.0-3.16 3.16-10.0
Percentage of Mw Capacity to Switch
Fuel Sulfur Range
Other High
East Coast Sulfate States
Coal Oil
100 0
100 0
54 78
Coal
78
78
57
Oil
0
0
Rest of
Country
Coal
65
65
10
Oil
33
33
160
5-35
-------
6. 1983 PROJECTIONS
This chapter describes the 1983 projected energy consumption by the
various environmental controls identified as having a significant effect
in the fossil fuel, steam electric generating industry. It primarily
focuses on sulfur dioxide controls, because they have a much greater
effect than do the other controls. Waste heat disposal and particulate
matter controls are also discussed, because they have a lesser but
identifiable effect on energy in the study year of 1983. The range of
the 1983 energy consumption by the environmental controls is 2.9 to
8.1 percent depending on the type of controls employed and the goals to
be achieved (see Table 6-1).
To develop 1983 projected energy consumption the following modi-
fications were made to the base year calculation. (See Section 4.)
• The 100 plant sample was expanded to the 1983 plant population
assuming two growth rates (4.16 percent and 6.73 percent) without
coal conversion, with coal consversion at new plants and with
coal conversion at all plants.
• Fuel sulfur content requirements, closed-cycle cooling system
requirements and particulate control requirements were deter-
mined for the 1983 population based on specific regulatory
scenarios.
« Various control system options, with their associated energy
consumptions were postulated.
• Energy consumption for the industry in 1983 was determined for
each set of control system options by assuming compliance with
the regulatory scenario.
Details of the methodology are discussed in Section 5 for sulfur
dioxide control and in this section for, waste heat disposal and particulate
control.
6-1
-------
TABLE 6-1
PERCENT OF TOTAL ENERGY USE FOR TOTAL S02, WASTE HEAT
AND PARTICULATE CONTROL
Smallest Largest
Anticipated Anticipated
Consumption Consumption
S02 2.5 7.2
Waste Heat 0.2 0.7
Particulate 0.2 0.2
Total 2.9 8.1
*Based on compliance with all present SO regulations, S0~ scenarios
1-3, waste heat scenarios 1-5 and ESP on coal fired plants. The SO
calculations do not include BACT which increases the totals to 4.1
and 8.2.
6-2
-------
Analysis of the 1983 projections indicates the following.
• Estimates of the total energy consumption for environmental
control in 1983 range from a high of 8.1 percent to a low of
2.9 percent.
• Control of sulfur dioxide emissions makes the greatest energy
demand.
If best available control technology, including low
sulfur fuel use and scrubbers, is required at new plants,
after 1980, the total sulfur dioxide energy demand can be
as large as 7.3 percent.
Energy demand for compliance with all present regulations
(without the additional requirement of best available
control technology) would be approximately 2.5 to
7.2 percent.
The energy saving resulting from the use of tall stacks
and/or supplementary control systems would be approxi-
mately one percent.
• Disposal of cooling water waste heat has the second greatest
energy demand: Approximately 0.4 percent.
• Particulate controls have the third greatest energy demand:
Approximately 0.2 percent.
6.1 Sulfur Dioxide Controls
The variations of the S02 related energy requirements are based on:
• the type of control technology employed,
• the air quality goal to be achieved,
• the degree of conversion of plants to coal, and
• the growth rate of the industry.
6-3
-------
Of these four factors, control technology and air quality goals are
the most significant. Degree of coal conversion and growth rate have
relatively minor effects during the study year.
Three S0? control technology scenarios (Table 5-9) were developed
to test the energy requirements of high-energy systems (scrubbers, coal
washing and coal blending). The three scenarios have a range of energy
requirements from 2.5 to 7.2 percent of 1983 fossil-fuel energy inputs,
(Table 6-2.)
Air Quality Goals
The effects of varying air quality goals were also studied and are
displayed in Table 6-3. The energy requirements for each of the three
technology scenarios are presented for each of five air quality goal
scenarios (Table 5-5). Attainment of primary and secondary air quality
standards, with a 1.6 to 3.8 percent energy requirement, is the goal of
attaining good air quality. The addition of all the regulatory scenarios
with a range of 3.4-5.2'percent energy requirement represents the goal
of maintaining air quality with "all present regulations."
In Table 6-3, it can be seen that the most important air quality
goal beyond attainment of health and welfare standards is the compliance
with State Implementation Plans (SIP). For a variety of reasons (for
example, local options, conservatism, lack of sophisticated modeling
techniques), the SIP's tend to require a lower level of sulfur oxide
emissions than is necessary. The calculations for the SIP compliance
determination are based on the minimum sulfur content fuel which can be
fired and still meet the standard as calculated by ERT in a previous
study (see Chapter 5 and ERT, 1975).
Estimates of reductions in saleable power are presented in Table 6-4
for the various control technology and regulatory scenarios. Reductions
in saleable power result primarily from the use of LSWC which has a
lower heat value than most higher sulfur coals and from the operation
of scrubbers. Table 6-5 presents the range of estimated reductions in
saleable power considering compliance with all present regulations [the
bottom column of Table, 6-4).
6-4
-------
TABLE 6-2
RANGE OF SULFUR CONTROL ENERGY REQUIREMENTS TO MEET
ALL PRESENT REGULATIONS* (Percent of Total Energy Use)
SCENARIO
LOW
l.S (Scrubbers and low sulfur 3.0
Western coal (LSWC)e
2.S (Addition of coal washing) 3.6
3.S (Addition of blending) 2.5
MOST LIKELY
3.8
HIGH
5.8
*01d Plants: Table 5-5 Scenarios 1, 2 and 4 (AQS + SIP)
New Plants: Table 5-5 Scenarios 1-5 (AQS + SIP + NSPS + ND)
TABLE 6-3
MOST LIKELY SULFUR CONTROL ENERGY REQUIREMENTS TO MEET
VARIOUS REGULATIONS IN 1983
(Percent of total energy use)
Regulatory
Requirement
Scenario 1
LSWC § Scrubbers
Scenario 2
Addition of coal
washing
Scenario 3
Addition of coal
blending
Old Plants: PAQS* 1.9
New Plants: PAQS
Old Plants: AQS 2.2
New Plants: AQS
Old Plants: AQS + SIP 3.3
New Plants: AQS + SIP
Old Plants: AQS + SIP 3.5
New Plants: AQS + SIP
+ NSPS
Old Plants: AQS + SIP 3.8
New Plants: AQS + SIP
+ NSPS + ND
*Note: PAQS = Primary Air Quality Standards
' NSPS = New Source Performance Standards
SIP = State Implementation Plans
LSWC = Low sulfur western coal
3.2
3.8
5.1
4.6
1.3
1.6
AQS
ND
3.1
3.4
Primary and Secondary Air Quality
Standard
Non-deterioration
6-5
-------
TABLE 6-4
MOST LIKELY CAPACITY LOSS RESULTING FROM SULFUR CONTROL
TO MEET VARIOUS REGULATIONS IN 1983
(Percent of Total Energy Use)
Regulatory
Requirements
Scenario 1
LSWC $ Scrubbing
Old Plants: PAQS* 1.4
New Plants: PAQS
Old Plants: AQS 1.7
New Plants: AQS
Old Plants: AQS + SIP 2.5
New Plants: AQS + SIP
Old Plants: AQS + SIP 2.7
New Plants: AQS + SIP
+ NSPS
Old Plants: AQS + SIP 3.0
New Plants: AQS + SIP
+ NSPS + ND
Scenario 2
Addition of coal
washing
0.7
0.9
1.7
2.6
2.6
Scenario 3
Addition of coal
blending
0.7
0.9
1.8
2.5
2.8
*Note: See Table 6-3 for key to abbreviations
TABLE 6-5
RANGE OF CAPACITY LOSS TO MEET ALL PRESENT
REGULATIONS* (Percent of Total Energy Use)
SCENARIO
1.S (Scrubbers and low
sulfur fuel)
2.S (Addition of coal
washing)
LOW
1.7
1.5
3.S (Addition of blending) 1.6
MOST LIKELY
3.0
2.6
2.8
HIGH
4.7
5.1
4.8
*01d Plants: Table 5 Scenarios 1, 2, and 4 (AQS + SIP)
New Plants: Table 5 Scenarios 1-5 (AQS + SIP + NSPS + ND)
6-6
-------
Coal Conversion
The energy requirements of the three scenarios were determined for
three coal conversion policies:
• no coal conversion beyond that considered by NERA (NERA, 1975),
• conversion of new plants, and
• conversion of all plants.
Table 6-6 displays the results of these coal options. Conversion
of new plants increases the energy consumption by only 0.1 to 0.3 percent.
However, because of the larger number of old plants, coal conversion of
old and new plants increases energy consumption for SO,., control by up to
1.2 percent. Conversion of new plants is the basis which has been
chosen for the results presented.
Growth Rate
The energy requirements were also determined at two different
growth rates:
1) 4.16 percent compounded based on NERA projections (NERA,
1975)
2) 6.73 percent compounded based on FPC projections, (FPC, 1974a)
Table 6-7 indicates that assumed growth rates have little effect on
environmentally-based energy requirements. The additional energy requirement
is approximately 0.1 percent.
The higher growth rate was chosen for the presentation of results
in the text.
Energy Source
Sulfur oxide control energy requirements are broken down by energy
source in Table 6-8. All of the electricity consumed by sulfur oxide.
control systems is assumed to have been generated from coal combustion
as shown in the "direct fuel usage" portion of Table 6-8.
6-7
-------
TABLE 6-6
SULFUR OXIDE CONTROL ENERGY REQUIREMENTS
COAL CONVERSION COMPARISON (Percent of Total Energy Use)
Regulatory
Requirements
Scenario 2: LSWC + Scrubbers + Coal Washing
No Coal
Conversion
Coal Conversion
New Plants Only
Coal Conversion
Old + New Plants
Old Plants: PAQS*
New Plants: PAQS
Old Plants: AQS
New Plants: AQS
Old Plants: AQS + SIP
New Plants: AQS + SIP
Old Plants: AQS + SIP
New Plants: AQS + SIP
+ NSPS
Old Plants: AQS + SIP
New Plants: AQS + SIP
+ NSPS + ND
2.9
3.4
4.9
4.5
4.9
3.2
3.8
5.1
4.6
5.2
4.0
4.6
5.8
5.4
6.0
*Note: See Table 6-3 for key to abbreviations.
'6-8
-------
TABLE 6-7
SULFUR OXIDE CONTROL ENERGY REQUIREMENT
COAL CONVERSION COMPARISON (Percent of Total Energy Use)
Scenerio 2: LSWC + Scrubbers + Coal Washing
Regulatory High Growth Rate Low Growth Rate
Requirement 0.0673 0.0416
Old Plants: PAQS* 3.2 3.2
New Plants: PAQS
Old Plants: AQS 3.8 3.7
New Plants: AQS
Old Plants: AQS + SIP 5.1 4.9
New Plants: AQS + SIP
Old Plants: AQS + SIP 4.6 4.6
New Plants: AQS + SIP
+ NSPS
Old Plants: AQS + SIP 5.2 5.0
New Plants: AQS + SIP
+ NSPS + ND
*Note: See Table 6-3 for key to abbreviations.
6-9
-------
TABLE 6-8
SULFUR OXIDE CONTROL ENERGY REQUIREMENTS BY ENERGY SOURCE
TO MEET ALL PRESENT REGULATIONS.* (BASED ON "MOST LIKELY"
COLUMN 6-2] (Percent of Total Energy Use)
Scenario
l.S (Scrubbers and low
sulfur fuel)
2.S (Addition of coal
washing)
3.S (Addition of coal
blending)
Coal
0.0
2.5
0.0
Oil/Gas
2.1
2.0
2.2
Electricity
1.7
0.7
1.2
BREAKDOWN IN TERMS OF DIRECT FUEL USAGE FOR THE ABOVE TABLE
Scenario
l.S
2.S
3.S
Coal
1.7
3.2
1.2
Oil/Gas
2.1
2.0
2.2
"Old Plants: Table 5-5 Scenarios 1, 2, and 4 (AQS + SIP)
New Plants: Table 5-5 Scenarios 1-5 (AQS + SIP + NSPS + ND)
TABLE 6-9
SULFUR OXIDE CONTROL ENERGY REQUIREMENTS BY LOCATION IN THE
PROCESS STREAM TO MEET ALL PRESENT REGULATIONS.* (BASED
ON "MOST LIKELY" COLUMN OF TABLE 6-2) (Percent of Total Energy Use)
Scenario
l.S (Scrubbers and low
sulfur fuel)
2.S (Addition of coal
washing)
3.S (Addition of coal
blending)
Pre-Plant
2.1
4.5
2.2
In-Plant
1.4
0.6
1.0
Post-Plant
0.2
0.1
0.2
6-10
-------
Location In the Process Stream
The location's of sulfur oxide control energy requirements in the
process stream are presented in Table 6-9. Most of the energy consump-
tion is "pre-plant," due to the large amounts of energy used in transport-
ing LSWC to other regions and the energy lost during the coal washing
process. "In-plant" and "post-plant" energy consumption is primarily
the result of scrubber operation and sludge removal.
Supplementary Control System (SCS) and Tall Stacks (TS)
Three tables have been presented (6-10A, 6-10B, 6-10C) to show the
range of energy requirements for each of the options under the three
scenarios l.S, 2.S and 3.S respectively. Notice that requiring only
air quality standards (Scenarios 1 and 2 in Table 5-5) reduces the energy
requirement by an amount ranging from -1.1 to -2.5 percent from the
corresponding scenario "for all present regulations" in Table 6-2.
Further reductions occur with the tall stack and SCS options. Even
though tall stacks are only used at new plants, they result in appreciable
additional energy savings in 1983 (-0,7 to -1.2 percent for the "most
likely" column depending on geographic coverage). If SCS is only used
outside the so-called "high sulfate" states the additional energy savings
are also modest (-0.3 to -0.4 percent). Only in the case of SCS used
without restriction for the entire population are appreciable additional
savings realized (-0.5 to -1.1 percent).
Best Available Control Technology (BACT)
Tables 6-11A, 6-11B and 6-11C present the results for each scenario
with BACT instituted after 1980. The energy increment due to BACT
ranges from 0.1 to 1.2 depending on the scenario considered. Note that
the high end of the range of energy consumption does not get' much addi-
tion with BACT but the low end of the range does.
6-11
-------
TABLE 6-10A
RANGE OF SULFUR OXIDE CONTROL ENERGY REQUIREMENTS TO MEET
AIR QUALITY STANDARDS ONLY (SCENARIO l.S LOW SULFUR
WESTERN COAL AND SCRUBBERS) (Percent of Total Energy Use)
Option Low Most Likely High
None
SCS(E)
SCS(ROC)
TS(E)
TS(ROC)
1.8
1.3
1.5
1.2
1.6
2.2
1.6
1.9
1.5
2.0
3.5
2.5
3.1
2.3
3.2
TABLE 6-1OB
RANGE OF SULFUR OXIDE CONTROL ENERGY REQUIREMENTS TO MEET
AIR QUALITY STANDARDS ONLY. (SCENARIO 2.S ADDITION OF COAL
WASHING) (Percent of Total Energy Use)
Option Low Most Likely High
None
SCS(E)
SCS(ROC)
TS(E)
TS(ROC)
2.5
1.7
2.2
1.7
2.3
3.8
2.7
3.4
2.6
3.6
5.3
3.7
4.7
3.6
5.0
TABLE 6-IOC
RANGE OF SULFUR OXIDE CONTROL ENERGY REQUIREMENTS TO MEET AIR QUALITY
STANDARDS ONLY. (SCENARIO 3.S ADDITION OF COAL BLENDING (Percent of
Total Energy Use)
None
SCS(E)
SCS(ROC)
TS(E)
TS(ROC)
1.2
0.8
0.9
0.7
0.9
1.6
1.1
1.2
0.9
1.3
2.4
1.5
1.9
1.4
1.9
6-12
-------
TABLE 6-11A
RESULTS FOR BEST AVAILABLE CONTROL TECHNOLOGY
BASED ON SCENARIO l.S FOR PRE-1980 PLANTS (Percent of Total Energy Use)
Low Most Likely High
Scenario l.S to 1980, BACT 4.0 4.5 5.9,
after 1980
Scenario l.S to 1983 5.0 5.8 58
Energy Increment Due to BACT 1.0 0.7 0.1
TABLE 6-1 IB
RESULTS FOR BEST AVAILABLE CONTROL TECHNOLOGY
BASED ON SCENARIO 2.S FOR PRE-1980 PLANTS (Percent of Total Energy Use)
Low Most Likely High
Scenario 2.S to 1980, BACT 4.7 5.9 7.3
after 1980
Scenario 2.S to 1983 5.6 5^.2 7.2
Energy Increment Due to BACT 1.1 0.7 0.1
TABLE 6- 11C
RESULTS FOR BEST AVAILABLE CONTROL TECHNOLOGY
BASED ON SCENARIO 5.S FOR PRE-1980 PLANTS (Percent of Total Energy Use)
Low Most Likely High
Scenario 5.S to 1980, BACT 5.7 4.5 5.3
after 1980
Scenario 3.S to 1985 2.5 5.4 4.9
Energy Increment Due to BACT 1.2 0.7 0.4
6-13
-------
6.2 Waste Heat Disposal
The total environmental energy consumption which can be assigned to
the 1983 fossil fuel, steam electric generating industry due to the
control of waste heat disposal depends on the following four parameters:
» the fraction of the 1974 base-year population which has
installed closed-cycle cooling for non-environmental reasons,
• the fraction of the 1975-1983 design population which has been
designed for closed-cycle cooling due to non-environmental
reasons,
• the fraction of the 1974 base-year population not falling
under the promulgated thermal effluent guidelines which is
permitted by the states to retain open-cycle cooling, and
• the fraction of the 1975-1983 design population which will be
granted 316(a) variances for open-cycle cooling.
The five scenarios based on variations of these parameters which
were developed are as follows.
l.W: EPA assumptions contained in the report "Economic Analysis of
Effluent Guidelines Steam Electric Power Plants" [TBS, 1976]
with the additional assumption that 65 percent of closed-cycle
systems installed before 1975 are for non-environmental reasons.
2.W: Same as scenario l.W but assumes a higher percentage (80 vs.
65%) of 1974 base year already closed-cycle cooling was
installed for non-environmental reasons.
3.W: Same as scenario l.W except that a lower percentage (75 vs.
89.2%) of the 1974 base year open-cycle cooling would be
allowed by the states to retain open-cycle cooling.
4.W: Same as scenario l.W except that a lower percentage (50 vs.
87.5%) of the capacity added in 1975-1978 would be assumed to
receive a 316(a) variance.
6-14
-------
5.W: Same as scenario l.W except that the percent of plants added
in 1979-1983 installing closed-cycle cooling for environmental
reasons does not vary from the 1975-1978 percentage.
A summary of the scenario parameters is found in Table 6-12.
All five environmental waste heat control scenarios examined have
environment energy consumption percentages from 0.2 to 0.7 percent with
respect to 1983 fossil fuel, steam electric plant fuel usage. The
environmental consumption percentages by scenario are given in Table 6-13.
In order to calculate the percent of 1983 generating plant popula-
tion which will have closed-cycle cooling for environmental reasons, the
following equation was used:
p = f (1-g) [l-(hf + hsJ] (6-1)
where:
p = fraction of generating capacity which has closed-cycle
cooling for environmental, reasons;
f = fraction of generating capacity affected by consideration of
a particular subcategory;
g = fraction with closed-cycle cooling for non-environmental
reasons;
h- = fraction which obtains a 316(a) variance for open-cycle
cooling;
h = fraction permitted open-cycle cooling by the states.
For each of the five scenarios, Equation 6-1 is applied to three distinct
time intervals: 1) the 1974 base-year capacity; 2) the generating
capacity added in the period January 1, 1975 - January 1, 1979; and 3)
the generating capacity added in the period January 1, 1979 - January 1,
1984. In addition, for each scenario the total environmental energy
consumption is calculated for the growth rate assumption of 6.73
>ercent per year. A lower growth rate of 4.16 percent per year does
mt change the results.
The calculations for the first scenario are given in Table 6-10.
6-15
-------
TABLE 6-12
Year
Constructed
up to 1974
1975-1978
1978-1983
SUMMARY OF WASTE HEAT CONTROL SCENARIOS
(Percentages of Mw affected)
Design
System
Closed-cycle 32.4
Open-cycle 5.5
Federal regs
Open-cycle 62.1
State regs
Closed-cycle 49.9
Open-cycle 50.1
Closed-cycle 100
Scenario
l.W 2.W 3.W 4.W 5.W
environmental reasons
non-environmental reasons
no variance
variance
control required
permitted to remain
environmental reasons
non-environmental reasons
variance
no variance
variance
environmental reasons
non-environmental reasons
variance
35 20
65 80
9.6
90.4
10.8
89.2
20.8
30.6
48.6
13.5
87.5
3.2
43.3
53.5
25
75
50
50
50
25
25
a. blanks indicated identical values Scenarios l.W.
-------
TABLE 6-13
ENVIRONMENTAL ENERGY CONSUMPTION PERCENTAGE FOR
WASTE HEAT CONTROL SCENARIOS
(Percent of Total Energy Use)
Scenario Low Most Likely High
l.W 0.2 0.4 0.5
2.W 0.2 0.3 0.4
3.W 0.3 0.5 0.7
4.W 0.3 0.5 0.7
5.W 0.3 0.5 0.7
6-17
-------
Scenario l.W:
The assumptions used in this scenario are those developed by EPA in
its report "Economic Analysis of Effluent Guidelines Steam Electric
Power Plants", [TBS, 1976] as follows:
1) Of the 5.54 percent 1974 generating capacity covered by the
effluent guidelines, 90.4 percent will receive 316(aj variances.
2) Of the 62.1 percent 1974 generating capacity which has open-
cycle cooling and which is not covered by the federal guide-
lines, 89.2 percent will be permitted by the states to retain
open-cycle cooling.
3) Of those plants scheduled for on-line startup in the period
1975-1978 which will employ closed-cycle cooling, 30.6 percent
of these plants have closed-cycle cooling for non-environmental
reasons.
4) Of those plants scheduled for on-line startup in the period
1975-1978 which were designed with open-cycle cooling,
48.6 percent of these plants will receive 316(a) variances.
5) Of those plants scheduled for on-line startup after 1978,
53.5 percent will receive 316(a) variances.
6) Of those plants scheduled for on-line startup after 1978 which
will be designed for closed-cycle cooling, 43.3 percent will
employ closed-cycle cooling for non-environmental reasons.
In addition, the following assumption is made by ERT in this case
analysis:
7) Of those plants within the 1974 baseyear capacity which have
closed-cycle cooling systems, 65 percent have employed closed-
cycle cooling for non-environmental reasons.
The results of these assumptions, given in terms of the fraction of
generating capacity which will have closed-cycle cooling for environ-
mental reasons, are presented in Table 6-14 for each of the three time
intervals considered.
6-18
-------
TABLE 6-14
<£>
CALCULATIONS FOR PERCENT OF 1983 FOSSIL FUEL GENERATING CAPACITY
WHICH WILL EMPLOY CLOSED-CYCLE COOLING FOR ENVIRONMENTAL REASONS
UNDER THE ASSUMPTIONS OF SCENARIO l.W
Time Interval Subcategory
1. 1974
2. 1975-1978
3. 1979-1983
Already closed-cycle
Open-cycle falling under
Federal guidelines
Open-cycle not covered
by Federal guidelines
Total
Designed closed-cycle
Designed open-cycle
Total
Total
0.
0.
0.
1.
0.
0.
1.
1.
£
324
055
621
000
499
501
000
000
0
0
0
0
0
0
g
.65
.0
.0
-
.306
.0
-
.433
0.
0.
-
-
0.
0.
0.
hf
0
904
688
o75
-
433
0.
-
0.
-
0.
0.
0.
h
s
0
892
002
0
-
002
0.
0.
0.
0.
0.
0.
0.
0.
p
113
005
067
185
104
063
167
321
1
3
3
1
3
1
e*
.5
.0
.0
-
.5
.0
-
.5
where
and
and where
p = f(l-g)[l-(hf+hs)]
p E fraction of generating capacity which have closed-cycle cooling for environmental reasons;
f = fraction of generating capacity affected by consideration of a particular subcategory;
g = fraction with closed-cycle cooling for non-environmental reasons;
h- = fraction which obtain a 316(a) variance for open-cycle cooling;
h = fraction not covered by federal guidelines which are permitted open-cycle cooling
by the states.
e = % energy consumption assumed for each subcategory for closed-cycle systems
installed/designed for environmental reasons.
* = percent energy consumption values assigned are designated "Most Likely".
-------
In order to determine the percent environmental energy consumption
for each time interval, the derived value "p" for each subcategory is
multiplied by the percent environmental energy consumption assumed for
each sub-category due to closed-cycle cooling. The values used for "e"
(i.e., percent energy consumption due to closed-cycle cooling) were
determined for each subcategory by a general examination of the mix of
retrofitted and designed closed-cycle cooling systems in that particular
subcategory. High, most probable, and low energy consumptions values
used for design cooling systems were 2.0, 1.5, and 1-0 percent, respectively.
High, most probable, and low energy consumption values used for retro-
fitted cooling systems were 4.0, 3.0, and 2.0 percent, respectively.
Scenario 2.W:
The assumptions used in this scenario are exactly the same as
Scenario l.W, with one exception. In Scenario l.W it was assumed that
of those plants in the 1974 base year capacity, 65 percent had employed
closed-cycle cooling for non-environmental reasons. Closed-cycle
cooling systems installed before 1970 were predominately installed for
non-environmental reasons. Therefore, the assumed figure of 65 percent
in Scenario l.W may be on the low side. In this scenario, it is assumed
that 80 percent of the 1974 generating capacity which have closed-cycle
cooling systems had installed such systems for non-environmental reasons.
Scenario5.W:
The assumptions used in this scenario are exactly the same as
Scenario l.W, with one exception. In Scenario l.W, it was assumed by EPA
and TBS, Inc. that of the 62.1 percent 1974 generating capacity which
has open-cycle cooling and which is not covered by the federal guidelines,
89.2 percent will be permitted by the states to retain open-cycle cooling.
The figure of 89.2 percent was derived by assuming that the states would
utilize a less stringent environmental risk criteria that would be used
in the 316(a) variance procedure. An industry questionnaire conducted
by the Utility Water Act Group with respect to EPA's initial proposed
316(aj regulations indicated that the industry believed a smaller
quantity of megawatts would qualify for 316 (a) exemption under a
6-20
-------
State Water Quality Standards test if interpreted by the state than if
interpreted by EPA [UWAG, 1974]. Although both the final regulations
and the final megawatts covered by the effluent guidelines are different
than those conditions considered in response to the utility industry
questionnaire, it seems realistic to consider the effects of stricter
environmental risk criteria utilization by the states for the 1974 base
year population. Therefore, it is assumed in this scenario that:
1) Of the 62.1 percent 1974 generating capacity which has open-
cycle cooling and which is not covered, by the federal effluent
guidelines, 75 percent will be permitted by the states to
retain open-cycle cooling.
Scenario 4.W:
The assumptions used in this scenario are the same as in Scenario l.W,
with the following exception. In Scenario l.W, it was assumed that of
those plants scheduled for on-line startup in the period 1975-1978 which
were designed with open-cycle cooling, 87.5 percent of these plants will
receive 316(a) variances. In this scenario, the following assumption is
made:
1) Of those plants scheduled for on-line startup in the period
1975-1978 which were designed with open-cycle cooling,
50.0 percent of these plants will receive 316(a) variances.
The purpose of this assumption is to examine the energy consumption
effect of a lower than expected 316 (a) variance granting rate for
planned near-term installation of additional generating capacity.
Scenario 5.W:
The assumptions used in this scenario are the same as Scenario l.W,
with the following exception. In Scenario l.W, the percentage of plant
generating capacity added in the period 1979-1983 (originally 1979-1990
in the TBS report) which was projected to install closed-cycle cooling
for environmental reasons was 3.2 percent. Both environmental risk
criteria analysis and water availability determination procedures
6-21
-------
critically depend on assumed siting policies - policies which become
increasingly uncertain over the longer time period. Therefore, the
following assumption is made for this scenario:
1) The percentage of plant generating capacity added in the
period 1979-1983 which will install closed-cycle cooling for
environmental reasons will be same as the total percentage
affected for plants installed during 1975-1978, i.e., 43.9
percent (see Table 6-1).
Other Waste Heat Disposal Technology
The waste heat disposal technologies considered in Section 3 of
this report are of four general types:
once through systems
once through with assistance from spray and other cooling systems
closed-cycle systems
combination of above systems.
The function of all air cooling systems is the rejection of the
waste heat to the atmosphere either through a body of water or directly.
An alternative heat disposal methodology is the utilization of the heat
for some socially useful purpose. The three general methods of utiliza-
tion, i.e., low-grade heat, steam, and total energy systems, are presently
little used in the fossil fuel, steam electric generating industry.
If waste heat were used directly (e.g., space or water heating),
the efficiency of steam power generating plants could be dramatically
increased. For example, if 10 percent of the 67 percent waste heat from
a power plant could be used to substitute for electric heating; then
there would be a 20 percent increase in the efficiency of the plant.
Such a percent increase in useable energy compares very favorably with
the range of the energy demands of the environmental controls. Increasing
the efficiency of power generation could "pay" for environmental control.
k
However, there is presently little planned construction for waste
heat utilization during the next decade and for the purposes of this
study, it was not considered.
6-22
-------
6.3 Particulate Controls
The environmental energy consumption associated with the application
of particulate controls for 1983 is estimated for two different growth
rates of fossil-steam electricity generation and two degrees of coal
conversion. As with the sulfur oxide control and waste heat disposal
calculations, the growth rates used are 4.16 percent and 6.73 percent.
The two coal conversion options are as follows:
#1 "No": Only existing plants identified as being capable of
burning coal are converted to coal, and new plants can be
either coal or oil-fired but at the following ratio of coal to
oil plants, 4:1.
#2 "Yes": Only existing plants identified as being capable of
burning coal are converted to coal, and all new plants will
burn coal.
The energy requirements used in these calculations are as follows:
the application of electrostatic precipitators to all coal-fired plants
with an energy requirement of 0.3 percent, and the application of multiple
cyclones to all oil-fired plants with a negligible energy requirement.
The energy consumed for particulate control in 1983 is summarized
in Table 6-15. The variation between the different future projections
is quite small. The environmental energy consumption for particulate
control with coal conversion is 0.24 percent of the fossil fuel energy
input to the population.
TABLE 6-15
ENVIRONMENTAL ENERGY CONSUMPTION
FOR PARTICULATE CONTROL IN 1983
Coal Conversion 6.75%
No 0.14%
Yes 0.24%
6-23
-------
7. DISCUSSION OF RESULTS
The estimates of environmental energy consumption determined in
this study are evaluated in two respects. First, the results presented
in this study are compared with the results of other published studies
which deal with the same subject and with EPA estimates of the progress
of regulatory activities. Second, an analysis of the availability of
low sulfur western coal is compared with the requirements implicit in
the study results.
7.1 Comparison with Other Studies
Comparison of the results of the present study with the work of
others is rendered difficult by a number of factors; first, this study
has dealt only with the fossil fuel, steam electric industry, while
other studies generally include gas turbine and diesel components of the
fossil fuel electricity-generating industry or aggregate fossil and
nuclear industries. Second, our results have been projected to the year
1983, while other studies have reported results for 1977, 1981, and 1985
as well as for 1983. Finally, and most important, our results are based
on the assumption of compliance with a variety of regulatory and control
option scenarios rather than on projections of utility compliance plans
with existing regulations.
In spite of these caveats, some comparison is useful. Table 7-1
is based on a multiple study comparison by Development Sciences, Inc.
(DSI) (1975) to which we have added sample results from our study. The
bases for the results of the present study which are closest to those
of the other studies are:
• 1974 fossil fuel consumption by steam electric power plants is
15 quadrillion Btu,
• growth rate of 6.73 percent per year to a 1983 fossil fuel,
steam electric energy consumption of 22 quadrillion Btu,
• minimum coal conversion as defined in previous sections,
• compliance with all present SO regulations.
7-1
-------
TABLE 7-1
COMPARISON OF ESTIMATES OF ENERGY CONSUMPTION FOR POLLUTION CONTROL
(trillion Btu)^
Study
Development Sciences,
Inc. (EPA)(b^
Michigan
Resource Planning
Associates
Economics of
Clean Water (EPA)
fc')
Present Study^ '
Year
1977
1983
1983 (Fossil Only)
1985
1980
1977
1983
1983
Power Plant Thermal
Pollution Control
86
205
107
250
274
432
792
(a)
Excluding energy for fabrication and installation of equipment.
Draft subject to revision.
text for assumptions on which present study results are based.
Power Plant Air
Pollution Control
103 - 342
282 - 406
800
213
1078 (Sulfur Dioxide)
44 (Particulate)
-------
• S0~ compliance achieved by means of scrubbers and low sulfur
fuel only (that is, no coal washing), and
• thermal pollution control based on Scenario No. 1, which uses
EPA estimates for key parameters.
ERT estimates of p»wer plant thermal p»lluti»n c»ntr«l appear to be
reasonably consistent with the other estimates. The ERT figure of
88 trillion Btu in 1983 is based on fossil fuel, steam electric plants
only. A comparable energy requirement might be expected to arise from
the nuclear portion of the industry in 1983, as in the DSI results.
The ERT results for air pollution control, which arise mainly from
sulfur dioxide control requirements, are a factor of two or more larger
than other study results. We suspect the reason for this is that our
requirement of compliance with all present regulations is more stringent
than compliance assumptions used in some or all of the other studies.
7.2 Comparison with EPA Expected Regulatory Activity
One method of comparing the results of this study with other
available data is to check it with the expectations of the EPA. The
most useful comparison available is to replace the control system
scenarios with the mix of control systems expected by the EPA.
Table 7-2 uses the mix of control systems expected for 1980 and 1985
[TBS, 1976]. The energy consumptions developed in this study for unit
processes (see Table 3-2) have been imposed on that control system mix.
The total energy consumption for environmental controls for S0« and
particulates is then compared to the EPA expected total energy produc-
tion to derive percentages. Because of the high reliance on coal
blending in the EPA mix of control systems, the resultant percentages of
energy consumption probably relate most directly to this study's
Scenario 3.S. The results of Scenario 3.S (Table 6-2) show 3.4 percent
as the "most likely" and 2.5 percent as the low value for energy consump-
tion in 1983. These compare favorably with the EPA-based values in
Table 7-2 even though the EPA-based results are for coal units only.
Because this study's unit process energy consumption was used, we can
conclude that Scenario 3.S is fairly comparable to EPA's expectations of
the control system mix.
7-3
-------
TABLE 7-2
EXPECTED ENVIRONMENTAL ENERGY CONSUMPTION USING
THE EPA MIX OF CONTROL SYSTEMS^
Control Systems
Scrubbers
Electrostatic Precipitators
Scrubbers and Precipitators
Import Low Sulfur Coal
Coal Washing
Coal Blending
Total
Total Energy Production
Precentage of Total Used
for Environmental Control
Energy Consumption for
Environmental Control
(millions of kilowatts)
Percent Energy
Consumption
This Study
"Most Likely
4.
0.
4.
4.
7.
1.
0
3
3
0
0
0
1980
11
0.
0.
2.
1.
0.
0.
5.
262.
87
13
65
22
58
29
74
6
1980 with
SCS^
0.
0.
1.
1.
0.
0.
4.
262.
10
11
69
98
08
04
00
6
1985
0.
0.
4.
2.
0.
0.
8.
332.
87
13
13
79
58
29
79
9
2.19
1.52
2.64
(a)
Based on coverage assumptions for COAL UNITS ONLY [TBS, 1976],
JSupplemental Control Systems employed by units responsible for 50 percent
or more of the pollutants in their impact regions. SCS is assumed
only temporary and not allowable in 1985.
7-4
-------
Another comparison which can be made is for the supplementary
control system (SCS) option. The EPA option for SCS in 1980 allows all
plants with responsibility for 50 percent or more of the pollutants in
their impact regions to utilize SCS. The SCS option would not, however,
be available in 1985. Table 7-2 shows a 0.67 percent reduction in
environmental energy consumption if SCS is used. This study's results
show a similar 0.5 percent reduction when the SCS (E) option is used in
Scenario 3.S. There is reasonable agreement about the effect of SCS on
the mix of control systems.
7.3 Low Sulfur Western Coal Availability
There are several ways to check the realism of the various control
strategies for S02 implied by scenarios selected. The ability of the
railroad system to transport coal or the ability of the scrubber vendor
industry to supply scrubbers are two such methods. Even more critical,
however, are the large quantities of low sulfur western coal (LSWC)
needed to achieve emission rates compatible with the regulatory scenarios,
The projected 1983 LSWC demand associated with each scenario has been
calculated for purposes of comparison with expected supplies. The
estimates (presented in Table 7-3) are conservative in several respects.
First, Region A coal plants with high sulfur complying fuels are assumed
to use the indigenous low sulfur coals (0.3-1.0 percent) when, in fact,
fairly substantial supplies of somewhat higher sulfur coals are available
within this geographic area. Second, the 1983 plant population which
served as the basis for the fuel consumption estimates reflects a high
(6.73 percent per year) assumed growth rate for the national population
of fossil fuel, steam electric generating plants. In addition, it has
been assumed that all new oil-burning plants from this population that
are capable of conversion to coal have effected this conversion by 1983.
Equal amounts of LSWC are calculated for Scenarios l.S and 2.S; Btu
losses incurred through coal washing are not considered. For this
reason, actual consumption values for the coal-washing scenario (2.S)
are probably somewhat higher than those for the scrubbing scenario (l.S).
7-5
-------
TABLE 7-3
IMPLIED LOW SULFUR WESTERN COAL CONSUMPTION FOR
THREE S02 REGULATORY SCENARIOS - 1983 ^
Low Sulfur Western
Coal Consumption
Scenario Category (millions of tons)
l.S or 2.S Plants requiring LSWC 96.9 318.8
Plants not requiring LSWC1^ 120.4 43.7
Converted oil plants 56. 7 95 .3
Total 254.0 457.8
3.S^ Plants requiring LSWC 247-6 397.9
(Q-)
Plants not requiring LSWC1- J 120.4 43.7
Converted oil plants 56. 7 95 .3
Total 404.7 536.9
fa)
k -^Based on assumed generating capacity growth rate of 6.73% per year
from 1974 with coal conversion wherever possible for new plants.
Both scenarios require the same amounts of LSWC. Assumed capacity
factor of 0.6; LSWC energy content of 9,235 Btu/lb.
Cc)
v 'Air quality standards (AQS) - Both the primary and secondary
national ambient air quality standards are met.
All present regulations are met including: AQS, new source per-
formance standards, state implementation plans and prevention of
significant deterioration.
fe~l
These are coal-fired plants in coal Region A (the west) which do
not need to use LSWC to meet the standards but which are assumed
to do so out of convenience.
^ ^Assumed capacity factor of 0.6; LSWC energy content of 9,235 Btu/lb;
r
high sulfur coal energy content of 12,000 Btu/lb; high to low sulfur
coal blend mix 2:1 by weight.
7-6
-------
LSWC use is greatest for the blending scenario (3.S). A 2:1 mixture by
weight of high to low sulfur coal has been assumed. In view of the high
cost and energy requirements associated with transport of western coal
to Regions B and C, it is possible that alternative control measures
would be adopted before fuel blending if a high proportion of LSWC is
required. Even with only one-third western coal used for blending, the
total Scenario 3.S LSWC consumption estimate is substantially higher
than that for either of the other two scenarios. This result reflects
the fact that about 42 percent of the total coal plant capacity is
affected under the assumptions used in developing the blending scenario.
Fuel energy contents assumed for low sulfur and high sulfur coal
are 9,235 and 12,000 Btu/lb, respectively. A capacity factor of 0.6 and
an average plant coal-electricity efficiency of 35 percent were also
used in the calculations. For any segment of the total generating
capacity involving the use of LSWC to attain air quality goals, the
demand was calculated by:
tons coal ,. , , . . .. , Mw (coal)
= Mw (electricity) -
per year ~ ll" ».—-—/; - 0_35 Mw (electricity) '
8,760 hr 3 kw 3,413 Btu ton
year Mw x kw-hr X 2,000 Ib
Ib
9,235 Btu
x 0.6 [capacity factor]
Projected Availability
The U. S. has vast reserves of recoverable low sulfur coal, most of
which is in the western states. A Bureau of Mines study (BOM, 1974)
reports approximately 70 billion tons of western coal with sulfur
content at or below 1 percent. The extent of these known reserves is
great enough to quell concerns as to the potential availability of such
coal for a period of many years. However, any attempt to forecast
actual mining capacity for a specific time per.iod is subject to a number
of crucial qualifications. The primary contingencies in this regard
are: (1) time required for resolution of environmental (reclamation)
policies] (2) land leasing and licensing requirements; (3) comparative
costs of LSWC with other coals from the standpoint of both Btu require-
ments and transportation charges; (4) availability of the necessary
7-7
-------
transportation facilities; and (5) the rate of development of effective
economically feasible alternate technologies for sulfur removal.
Projections of LSWC availability in future years vary according to
the assumptions made regarding these considerations. Forecasts developed
from data compiled by the U. S. Bureau of Mines (1975) reflect the
position that there will be no "unduly restrictive" legislative controls
on strip mining, that "reasonably liberal" policies for leasing public
coal lands will be enacted and that sulfur emission regulations will be
modified where they exceed ambient air quality requirements. Also
assumed is an increasing demand for western control paralleled by advances
in viable control technologies. Implicit in these projections is the
premise that greater energy self-sufficiency will continue to be a
national goal and that the requisite commitment of capital to achieve
this objective will be forthcoming.
With these qualifications, total U. S.-wide coal mining capacities
expected by 1980 and 1985, respectively, are estimated at 833 and 1,043 million
tons. The corresponding values projected for availability to the national
electric utility industry are 550 and 710 million tons. A significant
expansion of capacity in the west (roughly equivalent to Region A in
this study) is forecast during this period: estimates for this region
are 299 million tons by 1980 and 363 million tons by 1985. Total
western coal use for utilities in 1983 is expected to reach 211 million
tons with about 96 percent of this supply distributed evenly among
plants in the western and central regions of the country. Data derived
from the FEA Coal Task Force (Project Independence) and presented in a
Draft Final Report to the U. S. EPA (DSI, 1975) lead to an estimated
1983 power plant consumption of coal in the sulfur range below 1.5 percent
of about 360 million tons.
In addition, the FEA Western Coal Development Monitoring System
(FEA? 19761 is a source of coal availability data. Its projections are
that 443.6 million tons per year will be produced in 1983 in the nine
western states which supply low sulfur coal. Subtracting 152 million
tons for non-utility consumption, a total of 292 million tons would be
available. Although this reference does not segregate the coal by
sulfur content, we can infer from the area that this projection leads to
even more availability of low sulfur coal than the other two cited
above.
7-8
-------
Comparison
A comparison can now be made of the coal requirements for the
different control system scenarios and the availability of LSWC. Figure 7-1
provides a visual comparison to the scenario requirements set out in
Table 7-3 and the three projections of 1983 LSWC availability. This
comparison shows, for instance, that, if the Bureau of Mines projection
is chosen, it is possible to attain the air quality standards if coal
conversion does not occur and scenario l.S or 2.S is chosen for SO
controls. On the other hand, if one chooses to meet all present SO
regulations, it is necessary to ensure that the FEA coal projection is
met. Even then coal conversion of oil plants could not be accomplished
if scenario 3.S (coal blending) were chosen. Many important policy
contingencies, such as mine tract leasing and strip mine regulations,
are inherent parts of the coal availability.
The above examples are provided to show use of the figure and
neglects such things as the availability of low sulfur coal in the
eastern U. S. This study has not sought to establish a control scenario
based on coal availability but has focused on the energy consumption of
several control scenarios. The interrelationship is a complex one and
is a good subject for future study. Suffice it to say that the various
scenario results are within the range of available coal in 1983.
-------
c
o
c
o
<0
o
u
€
0)
CO
I
600
500
400
300
200
100
-
-
Coal
Conversion
Coal
Conversion
Coal
. Conversion
Coal
Conversion
Coal Monitoring System
'444 [FEA, 1976]
Project Independence
'360 [DSI, 1975]
Bureau of Mines
'211 — [BOM, 1975] '
Air
Quality
Standards
All
Present
Regulations
Air
Quality
Standards
All
Present
Regulations
Scenarios 1.S or 2.S
Scenario 3.S
Figure 7-1 Comparison of Scenario Coal Requirements and Projected
Coal Availability in 1983
7-10
-------
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[Aghassi, 1975]
[ADL, 1968]
[ALA, 1974]
[Albrecht, 1975]
[Battelle, 1973]
[Bechtel, 1968]
[BOM, 1974]
[BOM, 1974]
[BOM, 1975]
{BOM, 1976]
[Botts, 1972]
{Bruch, 1976]
William J. Aghassi and Paul N. Cheremisinoff,
"NOx Control in Central Station Boilers,"
Power Engineering, June 1975.
Arthur D. Little, Inc., "A Study of Process Costs
and Economics of Pyrite-Coal Utilization", A Report
to Consumer Protection and Evnironmental Health
Service, Contract No. PH86-27-258, March 1968.
American Lung Association, "Controlling Air
Pollution," 1974.
P. F. Albrecht and J. A. Lieberman, General Electric
Co., "Reliability of Flue Gas Desulfurization Systems,"
Power Engineering, June 1975.
Battelle Columbus and Pacific Northwest Laboratories,
"Environmental Considerations in Future Energy Growth,"
Vol. I: Fuel/Energy Systems: Technical Summaries and
Associated Environmental Burdens. Columbus, Ohio, 1973.
Bechtel Corporation, "Process Costs and Economics
of Pyrite-Coal Utilization," A Report to National
Air Pollution Control Administration, Contract
No. PH86-27-224, December 1968.
Bureau of Mines, "Assessment of the Impact of Air
Quality Requirements on Coal in 1975, 1977, and
1980", Division of Fossil Fuels, Mineral Supplies,
January, 1974.
Bureau of Mines, "Potential Solid Waste Generation
and Disposal From Lime and Limestone Desulfurization
Processes," Bureau of Mines Information Circular #8633,
1974.
Bureau of Mines, "Bituminuous Coal and Lignite
Distribution," Mineral Industry Surveys, April, 1975.
Bureau of Mines, "Effects of Air Quality Requirements
on Coal Supply" Contract J0155164, May, 1976.
W. V, Botts and R. D. Oldenkamp, "The Molten Carbonate
Process for S02 Removal from Stack Gases: Process
Description, Economics, and Pilot Plant Design,"
presented at 65th Annual Meeting of Air Pollution
Control Association, Miami Beach, Florida, June 1972.
Herbert W. Bruch, National Petroleum Refining
Association, private communication, January 1976.
-------
[CA, 1975a]
[CA, 1975b]
[CEQ, 1973]
[Chemico, 1971]
"How multiple technologies approach coal desulfuri-
zation problem," Coal Age. June 1975.
"The yardstick of productivity... Is it high tons
per man-day, or is it low cost per ton?," Coal Age,
July 1975.
"Energy and the Environment - Electric Power,"
Council on Environmental Quality, August 1973.
Chemico, "The High Sulfur Combustor," Final Report
to Division of Process Control Engineering, National
Air Pollution Control Administration, Contract No.
CPA22-69-151, February 1971.
[Christensen, 1973] R. I. Christensen et al, Chevron Research
Company, "Low Sulfur Products from Middle East
Crudes," presented at the National Petroleum
Refiners Association Annual Meeting, April 1973.
[Crawford, 1975]
[Deurbrouck, 1974]
[DOT-EPA, 1975J
[DSI, 1975]
[Dynatech, 1969]
{Ellis, 1975]
A. R. Crawford et al, Exxon Research and Engineering
Company, "The Effect of Combustion Modification on
Pollutants and Equipment Performance of Power Genera-
tion Equipment," prepared for a Symposium on Stationary
Source Combustion, September 1975.
A. W. Deurbrouck and P. S. Jacobsen, "Coal Cleaning -
State of the Art," Pittsburgh Energy Research Center,
U. S. Department of the Interior, Bureau of Mines,
October, 1974.
"Study of Potential for Motor Vehicle Fuel Economy
Improvement," Truck and Bus Panel Report, prepared
by the U, S. Department of Transportation and the
U. S. Environmental Protection Agency, January 1975.
Development Sciences Inc,, East Sandwich, Mass.,
Draft Final Report, EPA Contract 68-01-2498, "First-
Order Estimates of Potential Energy Consumption
Implications of Federal Air and Water Quality
Pollution Control Standards for Stationary Sources,"
July, 1975.
Dynatech R/D Company, Cambridge, Massachusetts, "A
Survey of Alternate Methods for Cooling Condenser
Discharge Water - Large Scale Heat Rejection Equip-
ment," for Water Quality Office, EPA, July 1969.
Dr. H. M, Ellis et al, Enviroplan Inc., "Pre-
dicting S02 Impact from 1000 MW Power Plant,"
Power, July 1975.
-------
[Energy, 1975]
[EPA, 1973]
[EPA, 1974a]
[EPA, 1974b]
[EPA, 1975a]
[EPA, 1975b]
[ER, 1975]
[ERT, 1975]
[PEA, 1976]
[Ford, 1975]
, 1975]
jHaller, 1975]
[Hammond, 1975]
"Energy Alternatives: A Comparative Analysis,"
prepared for CEQ, ERDA, FEA, FPC, DOI, NSF, May 1975.
Statements of Robert W. Fri, acting administrator of
EPA, in response to questions from the Joint Congres-
sional Hearings on Conservation and Efficient Use of
Energy, June 1973.
"Development Document for Effluent Limitations Guide-
lines and New Source Performance Standards for the
Steam Electric Power Generating Point Source Category,"
LJ. S. Environmental Protection Agency, October 1974.
"Second Annual Report to Congress - Resource Recovery
and Source Reduction," U.S. Environmental Protection
Agency, Washington, D. C., 1974.
"Report to Congress on Control of Sulfur Oxides,"
U. S. Environmental Protection Agency, February 1975.
New Source Performance Standards for Fossil Fuel-
Fired Steam Generators, EPA Response to Remand,
Federal Register, Volume 40, No. 176, September 10, 1975.
"Fluidized-Bed Combustion Seen Less Costly Alternative
to Scrubbers," EnvironmentReporter, 1975.
"An Evaluation of Sulfur Dioxide Control Requirements
for Electric Power Plants," P-1547B, Environmental
Research £ Technology, Inc., April 1975.
"Western Coal Development Monitoring System", Federal
Energy Administration Monthly Summary, December, 1976.
"The Energy Conservation Papers," The Energy Policy
Project of the Ford Foundation, Ballinger Publishing
Company, Cambridge, Massachusetts, 1975.
"The Effect of Environmental Legislation on Fuels
Availability for Electric Power Generation,"
Alexander Gakner et al, Federal Power Commission,
Presented at the 37th Annual Meeting, American Power
Conference, Chicago, Illinois, April 21-23, 1975.
Gary L, Haller and Paul C. Nordine, "Wet Lime and
Limestone Flue Gas Desulfurization - Estimates of
Energy, Environmental and Economic Costs", submitted
to Commerce Technical Advisory Board Panel on S02
Control Technologies, February 1975.
Allen L. Hammond, "Cleaning up Coal: A New Entry in
the Energy Sweepstakes," Science, Volume 189,
11 July 1975.
-------
[Herendeen, 1974]
[Hirst, 1973]
[Hittman, 1974]
[HP, 1974]
[Jimeson, 1973]
[Jimeson, 1975]
[Jonakin, 1975]
[Lovell, 1975]
.[Minerals, 1973]
iMitre, 1974]
INCA, 1974]
INERA, 1975]
IOGJ, 1975]
[Oglesby, 1970J
Robert A. Herendeen and Clark W. Bullard III, "Energy
Cost of Goods and Services, 1963 and 1967," Center
for Advanced Computation, University of Illinois at
Urbana - Champaign, Urbana, Illinois, November, 1974.
Eric Hirst, "The Energy Cost of Pollution Control,"
Environment, Volume 15, No. 8, October 1973.
"Environmental Impacts, Efficiency, and Cost of
Energy Supply and End Use," Volume I, Hittman
Associates, Inc., November 1974.
1974 Refining Process Handbook, Hydrocarbon Processing,
September 1974.
Robert M. Jimeson and L. William Richardson, "Census
of Oil Desulfurization to Achieve Environmental
Goals," presented at the 4th Joint Meeting with
the CSChE - AIChE, September 1973.
Robert M. Jimeson, "Environmental Regulation -
It's Not Nice to Fool the Power Plants," presented
at the 4th National Symposium of ASME, March 1975.
J. Jonakin, Combustion Engineering, Inc., "Solving
the S02 problem - where we stand with applications
and costs," Coal Age, May 1975.
"Sulfur Reduction Technologies in Coals by Mechanical
Beneficiation," Harold L. Lovell, The Pennsylvania
State University, College of Earth and Mineral
Sciences, February 1975.
1973 Bureau of Mines Minerals Yearbook: Lime, U. S.
Department, of the Interior, 1973,
"An Interpretative Compilation of EPA Studies
Related to Coal Quality and Cleanability," The
Mitre Corporation, May 1974.
National Coal Association, "Steam-Electric Plant
Factors/1974 Edition," Washington, D. C,s 1974.
Lewis J, Perl, Joe D, Pace, "The Costs of Reducing
SQ2 Emissions from Electric Generating Plants,"
National Economic Research Associates, Inc., April
1975.
Oi1 and Gas Journal, Annual Refining Report,
7 April 1975.~~
"A Manual of Electrostatic Precipitator Technology,"
Part II: Application Areas, S. Oglesby and G, B.
Nichols, Southern Research Institute, August 1970.
-------
[PEDCo, 1975a]
[Perry, 1974]
[Power, 1975]
[Rice, 1970]
[Stern, 1968]
[TBS, 1974]
[TBS, 1976]
[Teller, 1972]
[UWAG, 1974]
"Flue Gas Desulfurization Process Cost Assessment,"
PEDCo-Environmental Specialists, Inc., May 1975.
Harry Perry, "Coal Conversion Technology," Chemical
Engineering, 22 July, 1974.
Power, 1975 Annual Plant Design Report, November 1975.
R. A. Rice, "System Energy as a Factor in Considering
Future Transportation," a paper presented at the
ASME winter annual meeting, November 29-December 3,
1970.
Arthur C. Stern, ed., "Air Pollution," Volume III,
Sources of Air Pollution and Their Control,
Academic Press, New York, 1968.
Temple, Barker and Sloan, Inc., "Economic Analysis
of Effluent Guidelines Steam Electric Power Plants,"
PB-239, 315, December, 1974.
Temple, Barker and Sloan, Inc., "Economic and Financial
Impacts of Federal Air and Water Pollution Controls
on the Electric Utility Industry", May, 1976.
Aaron Teller, "Air Pollution Control," Chemical
Engineering Deskbook Issue, 9 May 1972.
Utility Water Act Group, "Comments on EPA's Proposed
316(aj Regulations and Draft Guidance Manual,"
June 26, 1974.
-------
APPENDIX A
ERT SAMPLE PLANT POPULATION
-------
APPENDIX A
ERT SAMPLE PLANT POPULATION
The sample of power plants used for determining the compliance
with sulfur-in-fuel limits was also evaluated with respect to the
application of environmental controls in 1974. This evaluation was
primarily achieved by reviewing the information contained in the Federal
Power Commission (FPC) Form 67, "STEAM-ELECTRIC PLANT AIR AND WATER
QUALITY CONTROL DATA FOR THE YEAR ENDED DECEMBER 31, 1974," for each
plant. In addition, the energy consumption associated with the applica-
tion of these environmental controls was determined by circulating a
questionnaire to the staff of each of the power plants in the sample
population.
To facilitate the completion and return of these questionnaires,
all previously available information for the plants was entered by the
ERT staff prior to their mailing. Exhibit A-l is a copy of the ques-
tionnaire, with asterisks (*) indicating those categories of information
completed by ERT prior to distribution to the power plants. A total of
66 questionnaires was returned to ERT. The sample size for any specific
analysis could be larger, however, based on the FPC data.
Capacity factors in 1974 (Mwc available as a percent of Mwc at
rated capacity) were available for 84 plants. The capacity factors
were stratified into three plant size groupings: 1) <400.Mw;
2) 401-800 Mw; and 3) >800 Mw. The average capacity factors for these
three groupings were 53.6%, 59.9%, and 57.7%, respectively. The
capacity factor data indicates that there is no strict correlation
between plant size and baseload conditions for the sample population
in 1974. This is due to both historical unit size characteristics and
past siting policy.
The distribution of particulate control equipment by fuel type
for the sample plant population of 88 plants is shown in Table A-l.
For the control of particulate emissions, the sample reported an aver-
age of 0.30% additional energy consumption for the operation of electro-
static precipitators and an average of 0.10% additional energy con-
sumption for the operation of combined electrostatic precipitators
and mechanical collectors. The range of the responses was from 0.04 to
A-l
-------
TABLE A-l
DISTRIBUTION OF PARTICULATE CONTROL EQUIPMENT BY FUEL TYPE FOR THE SAMPLE PLANT POPULATION
I
t-0
Particulate Control Equipment (percent)
Combination
Mechanical-
Fuel Type
Gas
Oil
Coal
Gas
Gas
Oil
Burning
Burning
Burning
§ Oil
£ Coal
§ Coal
Gas, Oil, §
Coal
Percent of
Sample
0.
12.
13.
21.
2.
39.
10.
8
6
2
1
2
9
2
None
100.
40.
3.
50.
-
3.
4.
0
7
1
1
8
7
Mechanical Electrostatic Electro
Collector Precipitator Precipi
-
38.
4.
30.
-
5.
15.
-
8 - .
1 17.3
1 13.5
65.4
1 16.7
4
-
20.
75.
6.
34.
72.
79.
5
5
3
6
5
9
Wet
Scrubber
1.9
100.0
-------
2.27% for the electrostatic precipitators and from 0.10 to 0.96% for the
combination units. The average additional energy consumption reported
for multiple cyclones was 0.01%. Three units were using wet scrubbers
for particulate control, with an average additional energy consumption
of 4.51% and a range of 4.12 to 5.14%. In addition, two plants reported
an additional percent energy consumption of 0.34 to 0.86% for the
scrubber water supply systems. Related to the operation of particulate
control equipment is the transport of the collected ash. Thirty-one
plants reported energy requirements for ash disposal. The average
additional energy consumption was 0.15%, with a range of 0.00 to 1.15%.
There was a limited questionnaire response with respect to sulfur
dioxide control technologies. Six plants reported the use of magnesium
oxide as a fuel additive. The amount used ranged from 80 to 1400 tons
per year. Reported transport distances for the magnesium oxide ranged
from 110 to 650 miles, with transport provided by both truck and rail.
One flue gas desulfurization (FGD) system was reported going on-line
in 1975. This system required 0.076 tons of lime per ton of coal burned.
The lime was transported 200 miles by rail. The energy consumption
reported for the operation of the FGD system was 2.13% exclusive of
reheat.
Four plants reported the use of nitrogen oxide control technologies,
with one system going on-line in 1976. All plants reported using flue
gas recirculation systems. The average additional energy consumption
was 0.47%, with a range of 0.24 to 0.86%.
Seventeen plants reported energy consumption requirements for
chemical waste treatment (waste water). The additional energy con-
sumption for chemical waste treatment ranged from 0.00 to 0.06%. The
additional energy consumption for Best Practical Control Technology
Available (BPCTA) ranged from 0.01 to 0.06%.
The distribution of waste heat control systems for the sample
population of 88 plants is shown in Table A-2. The average Brake Horse
Power (BHP) per plant for once-through fresh cooling was 3,148. The
average BHP's for mechanical draft towers and natural draft towers
were 4^082 and 7,156, respectively. In addition, an average BHP per
plant of 1,518 was reported for the tower fan system of mechanical
draft towers.
A-3
-------
TABLE A-2
WASTE HEAT CONTROL FOR THE SAMPLE PLANT POPULATION
I
-pi
1.
2.
3.
4.
5.
Average Cooling
Cooling Water Power Consumption
Average
Number of
pumps per
plant
Cooling
System
Mode
Once-through
Fresh
Once-through
Saline
Natural Draft
Tower
Mechanical Draft
Tower '
Cooling Pond
Percent
of
Sample
52.11
23.34
11.94
6.81
4.38
Water Flow Rate
thru Condenser
(CFS)
229
298
500
196
382
Average Temp.
Rise (°F)
16
15
27
18
16
Average
MwH per
plant
12,584
13,633
40,000b
_
-
Averagi
BHP pe:
plant
3,148
1,998
7,156
4,082
2,219
Tower Fan System
Average Percent
Average BMP utilization of
per plant fans
l,573a 35a
1,518
93
6. Cooling Lake
1.42
S49
13
900
a = Denotes once-through systems which use mechanical draft towers for supplemental cooling
b = Only one plant reporting
-------
With respect to the use of western coal (Region A) in Region B,
three plants in Region B reported partial use of western coal. The
distance for transport of the coal ranged from 1,200 to 2,000 miles.
A-5
-------
1 of 5 pages
EXHIBIT A-l
ENERGY REQUIREMENTS QUESTIONNAIRE FOR AIR § WATER POLLUTION CONTROL
Please answer all questions as completely as possible. Where
additional space is required, please use the back of the questionnaire
and specify the item being answered.
1. Plant Identification Information
la. Company Name: *
Ib. Plant Name: *
Ic. Plant Location: *
2. Fuel Consumption Data: Please specify individual units and differing
modes of transport where necessary.
Fuel
Type(s)
A
*
*
1974 Total
Consumption
B
*
•1-
Sul fur
Content
(%)
C
*
•1-
Point of Origin
City g State
of mine or port
D
*
1
Distance
from Plant
(miles)
E
Modes*
of
Transport
F
2a.
2b
2c.
*Modes of Transport: (U)-Unit Train; (M)-Mixed Train; (T)-Truck; (B)-Barge
(P)-Pipeline; (C)-Conveyor; (MM)-Mine Mouth Plant; (S)-Ship
3. Plant Operating Characteristics: Please include any units planned for
entry into service before 1984 as well as operational units.
3a.
3b.
3c.
3d.
3e.
3f.
3g.
3h.
3i.
UNITS
1974 Rated Generation
Capacity, Mw
1974 Capacity Factor, %
Unit Heat Rate, Btu/KWH
Unit Efficiency, %.
Fuel Rate § Fuel Type
(Ib/hr, ft3/hr, etc.)
Boiler Manufacturer
Boiler Type##
Date of Service
Turbine-Condenser Units
served by each boiler unit
1
* ->
* ->
* -»-
* ->
* ->-
* ->
* ->•
* ->
2
3
4
5
# Boiler Manufacturer: CE-Combustion Engineering; BW-Babcock § Wilcox;
FW-Foster Wheeler; RS-Riley Stoker; EC-Erie City Iron Works; OT-other.
## Boiler Type: T-Tangential; F-Front-Fired; 0-Opposed-Fired; S-Stoker;
C-Cyclone; FB-Fluidized Bed; OT-other.
A-6
-------
2 of 5 pages
4. Turbine Condenser Information: The purpose of the following questions
is to estimate the capacity loss and increased fuel usage associated
with the retrofitting of closed-cycle cooling systems to units presently
employing once-through cooling. Using nomographs developed by various
sources, one can compute a new turbine backpressure as a function of a
given wet bulb temperature, approach, terminal temperature difference, and
tower range. Subtracting the design backpressure from this new value will
give the backpressure increase due to closed-cycle cooling. If the average
change in unit heat rate per 1" Hg abs. change in backpressure is known,
then one can compute the unit heat rate loss due to the increased turbine
backpressure. Dividing this calculated unit heat loss by the unit heat
rate will give the percent capacity loss due to closed-cycle retrofitting.
The following definitions should be of help in answering these questions:
1. TEMPERATURE RISE: the difference in temperature between the hot water
leaving the condenser and the cold water entering the condenser.
2. TERMINAL TEMPERATURE DIFFERENCE (TTD): the difference between the
steam saturation temperature and the hot water temperature leaving the
condenser. The TTD is typically between 5 and 10°F.
4a.
4b.
4c.
4d.
4e.
TURBINE CONDENSER UNITS
Cooling Water Flow Rate, cfs
Temperature Rise, °F.
Terminal Temperature Difference, °F.
Design Turbine Backpressure, in. Hg abs.
Average Change in Unit Heat Rate per
1" Hg abs. of Backpressure, %
1
2
' 1
*->
*->-
5. Energy Consumption for Particulate Control: please include all energy
requirements for control equipment, ash removal, and ash disposal operations.
PARTICULATE CONTROL UNITS
5a.
5b.
5c.
5d.
5e.
Status, oper. or planned (date)
Type*
Removal Efficiency, %
Power Consumption, Mw
Pressure Drop, inches ^0
* ->
* -4-
* ->•
Type: ESP-Electrostatic Precipitator; C-Cyclone; MC-Multiple Cyclone;
SC-Spray Chamber; S-Scrubber; FF-Fabric Filter; OT-other, please specify.
5f. Ash Disposal, 1974 Quantity
tons/year.
KWH/yr.
5g. What type of disposal is employed (ash pond, landfill, etc.)? j*_
5h. What are the energy requirements for this disposal operation?
5i. Where is the disposal site located?
5j. What is the distance from the plant? miles.
5k. What is the mode of transport?
51. What quantity of ash per year is used in other processes such as fly ash
concrete or pelletized aggregate? „ tons/year.
page A-7
A-7
-------
3 of 5 pages
6. Energy Consumption for Sulfur Dioxide Control: please include all
requirements for control equipment, sulfur dioxide control chemicals,
waste disposal, and regenerative processes.
or •
6a.
6b.
6c.
6d.
6e.
-6f.
x6g-
SULFUR DIOXIDE CONTROL UNITS
1
Status, oper. or planned (date)
Type of unit
Removal Efficiency, %
Reheat, Btu/hour
Pressure Drop, inches H20
Power Consumption, Mw
Fans, bhp
Pumps , bhp
* ->•
* ->•
* -»-
2
^
'
6i. What chemicals are utilized for the control of sulfur dioxide?
i. What quantity of these chemicals are required (in tons/year or tons per
ton of fuel consumed)? ^^^^^^^
6k. Where do these chemicals come from (city £ State)?
61
6m
6n
60
6p
6q
6r
6s
6t
6u
6v
6w
. What is the transport distance required for these chemircals? miles
. What is the mode of transport?
Waste Disposal
. What marketable products are created (sulfur, acid)? *
. What quantity of this product is sold? tons/year.
. What additional energy requirements are there to prepare this marketable
product (Btu/ton)?
. What quantity of sludges requiring disposal are generated?
. What is the distance from the plant to the disposal site?
. What type of disposal facility is used (landfill, ponding)?
. What is the mode of transport to the disposal facility?
_ tons/year.
miles.
. If a regenerative process is utilized, what is its energy requirement?
KWH/ton
. What type and quantity of fuels are utilized?
. What quantity of electricity is utilized?
KWH
7. Energy Consumption for Nitrogen Oxides Control: please include all
energy requirements for control equipment or combustion modifications.
7a.
7b.
7c.
NITROGEN OXIDES CONTROL UNITS
Status, oper. or planned (date)
Type*
Power Consumption, Mw
1
!>
3
FGD-Flue Gas Recirculation; OFA-Over-Fire Air; BF-Bias Firing; if other please
specify.
A-8
-------
4 of 5 pages
8. Energy Consumption Due to Chemical Waste Treatment:
8a. Please quantify and describe any energy requirements attributable to
present chemical waste treatment.
8b. Has the design engineering for chemical effluent treatment system to meet
1977 BPCTA (Yes No ) or 1983 BATEA (Yes No ) been completed?
8c. What are the energy requirements for BPCTA?
Disposal of Sludge and Brine from Waste Water Treatment
8d. What quantity of this waste was generated in 1974?
8e. What quantity of this waste is estimated for 1983?
8f. What type of disposal is utilized (sludge pond, well, landfill)?
8g. What is the distance .from the plant to the disposal site?
8h. What is the mode of transport (truck, pipeline)?
miles.
9. Energy Consumption of the Cooling Water System:
9a. What is the present status of the cooling system mode of operation:
9b
9c
9d
9e
9f
9g
9h
9i
9j
UNIT
1
2.
3
Status, oper. or planned (date)
Surface discharge
Diffuser
Cooling "pond"
Cooling "lake"
Spray canal or pond
Mechanical draft tower
Natural draft tower
Wet-dry cooling tower
* •>
t
9k. For units which have a net generating capacity greater than or equal to Y
500 megawatts and were placed into service between January 2, 1970 and
January 1, 1974, has either a 316(a) or 318(a) variance been requested No
91. Has a 316(a) or 318(a) variance been requested for any unit placed or to
be placed into service after January 1, 1974? Yes No
9m. Will an exemption from cooling tower requirements (where applicable) based
upon salt drift-land availability requirements (Section 423.13 (1)'(5) of
1972 Water Act) be requested? Yes No
9n. What was the power consumption for the flow of condenser cooling water
for 1974? KWH; or, what were the total number of pumps and
the total bhp for these pumps? bhp, # of pumps.
A-9
-------
5 of 5 pages
9o. If cooling towers are used for closed cycle cooling, what is the design
wet bulb temperature? °F.
9p. If a cooling pond is used for closed-cycle cooling, is the cooling pond
formed by an impoundment which impedes the flow of a navigable
stream? Yes No
9q. If mechanical draft towers are presently employed at the plant, what are
the rated bhp of the tower's fan system and percent utilization of fan
system per annual boiler operation? bhp, %.
10. Are there any other substantial energy consumption requirements in
your plant due to environmental controls or regulations? If so,
please explain:
A-10
-------
APPENDIX B
ENERGY CONSUMPTION MODELING
-------
APPENDIX B
ENERGY CONSUMPTION MODELING
Estimates of future energy consumption for the control of sulfur
dioxide were based on the application of a computer model which permitted
analysis of regulatory options, control system options, coal conversion
and varying industry growth rates. The computer modeling was achieved
by the use of the computer program RIPPER-S, an acronym for "Regulatory
Ijnpact upon Power Plant Energy Requirements - Sulfur Dioxide." This
program provides estimates, for designated future years, of the incre-
mental energy consumption associated with a specific set of air quality
regulations for the projected total national fossil fuel, steam electric
power plant population. These estimates are based, in part, upon:
• the assumed composition of the existing and projected new
fossil fuel power plant populations,
• an assumed annual growth rate for new plant electricity
generation,
• the imposition of a specific set of air quality regulations,
and
• the estimated incremental energy consumption associated with
the application of a sulfur dioxide control technology.
The air quality regulations which can be imposed include:
• National Primary Ambient Air Quality Standards,
• Air Quality Standards (both Primary and Secondary standards),
• State Implementation Plans,
• New Source Performance Standards,
• Non-Deterioration Class II Requirements, and
• Best Available Control Technology (BACT).
The logic for RIPPER-MAIN is displayed in Exhibit B-l. This sub-
program uses as its data base the megawatt capacity and complying fuel
requirements from a sample population of 100 existing fossil fuel,
B-l
-------
No ^
<
Subroutine
Ripper
t
Loop A
Done for All
Plants 8
Populations
J
*?
Find Complying
Fuel for all
Strategies
*
Find
Appropriate
% Fuel Range
1
Expand MW
100 Plant
Sample to
National Pop.
t
Stratify
Expanded MW
by Fuel Type
Location, &
Sulfur Ranges
IT
x*xLoop^Ns
A
""XDone ./
ifYes
^x^wX.
^Redistribution*
s. by Fuel .,
^XRangeX^
jYes
Redistribution
For Tall Stacks
,&SCSOnly
T
MW's in
Fuel Ranges
Shifted
1
>
. No
, * ,
Apply Conver-
sion Factors
to Change
Geographic
Regions EC,
OHS, ROC to
Regions A, B,C
t
Expand
Population
Distribution
by Exponential
Growth Rate
I
Create
Environmental
Energy
Consumption
Tables
t
Create %
& Total
Tables for
Output
1
/ Display /
/ Output /
\
(Return A
to Main J
Exhibit B-l
Logic for RIPPEF
B-2
-------
steam electric power plants. This sample population is stratified by
location, by fuel type (including convertibility to coal for oil-fired
plants), and by megawatt capacity to be representative of the total
national population of fossil fuel, steam electric power plants.
The RIPPER-MAIN program assigns the 100 plant sample population to
percent sulfur in fuel ranges based on a user-specified regulatory
strategy. This division then constitutes a matrix of expected megawatt
capacity by fuel type, location and percent sulfur content of the fuel
Cor its exhaust gas control equivalent) to meet a specific regulatory
strategy. Additional input of the growth rate of energy production
capacity, a base year for the 100 plant sample and a projection year are
necessary.
Coal to oil conversion can also be specified independently for
existing and new power plants.
The basic calculations using the megawatt capacity matrix are then
performed in subroutine RIPPER.
In subroutine RIPPER (see Exhibit B-2), the complying fuel for the
partitioned 100 plant sample is found, and the 100 plant megawatt
capacities are expanded to the national population for each of the
plants and the existing/new population distributions. The expanded
(national) megawatt capacity matrix is then stratified by fuel type,
location and percent sulfur ranges. This stratification is now equivalent
to the Energy Consumption Matrices (ECM), which are input based on the
control scenario selected. Redistribution of megawatt capacity by
complying sulfur content of fuel is then performed if options tall
stacks or SCS are to be used. Conversion factors are then applied to
change the partitioning in the input geographic regions from East Coast
(EC) states, Other High Sulfate (OHS) states, and Rest of Country (ROC)
to regions A, B or C for output. The population is then expanded by an
exponential growth rate. The environmental energy consumption is then
computed by matrix multiplication of the ECM's and the expanded megawatt
capacity matrices. This results in a national energy consumption for
environmental controls based on the control scenario selected.
RIPPER then presents the various statistics generated according to
the different stratification formats, for the base year and for the
forecast year, as well as the estimated energy consumption to achieve
compliance with the air quality regulations being evaluated.
B-3
-------
Main
Program
Printout
of Input
Plant
Descriptors
CRead
Old/New
Population
)istribution
7
dsk File
Dard
mage
ormat
/ Read/Write 7
/ Plant /
—/ Descriptors /•*•
/ For All /
/ Plants /
Stratify
Plant MW for All
Plants by Fuel
Type, Location
& MW Capacity
/Disk File,
J Card
\ Image
V Format
Read
Energy for
/Environmental/
Control Mat-y
rices (EECM)y
2
±
Stratify
EECM'sby
Fuel Type,
Location &
% Fuel Ranges
Read
Strategy
Parameters
Card Input
Card Input
~l
_J_
Subroutine
Ripper
J
Exhibit B-2
Logic for RIPPER-Main
B-4
-------
RIPPER Results
An example of results from the RIPPER model is presented in
Exhibit B-3. The example results are estimates of total energy consump-
tion for control of sulfur dioxide based on median estimates of energy
use by specific control technologies in the following scenario:
Regulations - All present regulations (old plants - AQS and SIP,
new plants - AQS, SIP, ND and NSPS)
Technology - Low sulfur western coal and scrubbers
Coal Conversion - New plants converted to coal
Growth Rate - High growth rate (0.0673)
Target Year - 1983
Exhibit B-3 is actually composed of two tables, a table of the
population of electric generating plants projected to 1983 and a table
of energy use for environmental control in 1983. The columns of both
tables are labeled in complying fuel range as follows:
Fuel 1 - sulfur content of 0.1% to 0.3%
Fuel 2 - sulfur content of 0.3% to 1.0%
Fuel 3 - sulfur content of 1.0% to 3.0%
Fuel 4 - sulfur content of 3.0% to 10.0%
The rows are labeled in fuel types and geographic locations:
c - coal
o - oil
oc - oil to coal conversion
A - area where low sulfur western coal is indigenous
B - area adjacent to area "A"
C r- rest of country
There is no population or energy use in the oil to coal conversion
rows because the oil-coal conversion scenario used in this model run
was "neither old or new oil plants converted to coal." Oil-fired plants,
B-5
-------
POPULATION ENERGIES YEAR 1983
PROJECTED TOTAL POPULATION SY FUEL'RANGE AND FUEL TYPE/REGION
T
A
I
I
I
T
X
I
I
I
I
5
r
T
C "A
c -e
c -c
u -A
U -B
0 -C
OC-A
CC-3
GC-C
sun
I
I
I
I
I
1
I
I
I
I
I
I
FUEL 1
I
I
I
I
I
I
I
I
I
I
I
X
1.81
5,44
7,86
0.00
0,00
5.27
0.43
1.28
1,85
23.93
I
I
I
I
I
I
I
I
I
I
I
I
FUEL a
i
i
i
i
i
i
i
i
i
i
i
%
4.20
12,60
18.20
0,00
0,00
6.85
0.55
1,66
2. ao
46.47
1
I
I
1
I
I
1
I
I
I
I
I
3
I
I
I
I
• »-« t-t t-1 -
1
I
I
I
X
7,06
in. 19
c.oo
0.00
5.32
f.OO
0,00
0.00
2«.9:
I
I
I
I
I
I
I
i
I
FUFL 4
T
+-•
I 0 . f. 0
I r . o y
T P . ? '4
.+»__,_,-.-.
C.ftH
POPULATION ENERGY FDR ENVIROMENTAL CONTROL-YEiR
PROJECTED TOTAL POPULATION BY FUEL RANGE AND FUEL TYPE/REGION
FUEL
I
I
I
I
J
I
I
1
I
I
I
I
C -A
C -B
c -c
0 -A
0 -3
0 -C
OC-A
UC-8
OC-C
SUM
I
T
,L
I
1
I
h V-t (-1 1-* -
I
I
I
I
FUEL 1
I
I
I
I
I
I
I
I
I
I
I
x
1.15
13,16
16.77
0.00
0.00
8.43
0.34
2,39
43.50
I
I
I
1
i
1
I
I
I
I
I
I
FUEL 2
I
I
I
I
I
I
I
I
I
I
I
X
0.00
13,45
0,00
0,00
5,48
0,00
1,77
2,56
42.70
I
I
I
I
I
I
I
I
I
I
I
I
. 3
I
I
:
i
i
i
T
I
I
I
I
Z
0.00
5.65
8,16
0,00
0,00
0,00
0.00
0,00
0,00
13.81
I
I
1
I
I
I
I
I
T
I
I
I
FuFL
r o.oo
T n, o o
T o.no
I o.oo
i o.oo
n.90 I
RATIO=
3,753!
Exhibit B-3 An Example of Results from the RIPPER Model
-------
which are all in area "C", account for about one quarter of the energy
used for environmental control of sulfur control. The remaining seventy-
five percent of energy use for environmental control is due to coal
plants in all three regions and the lowest 3 complying fuel ranges.
Total energy use is shown at the bottom of Exhibit B-3 as 3.75 percent
of the total population.
Similar tables are available for all of the other scenarios discussed
in the report. Results tables are also available for breakdowns of each
scenario by location of energy use (pre-plant, in-plant and post-plant)
and by type of fuel used (oil/gas, coal, electricity). A total of more
than 2000 RIPPER result tables were generated and analyzed during
preparation of this report.
B-7
-------
IV 61 RELEASE. 2,0
MAIM
DATE * 76359
10/35/23
PAGE 0001
oo
i
00
9901
0092
0003
9004
0005
OOQt
0007
0008
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0010
0011
0012
0013
0014
0015
001ft
ooir
0018
0019
0020
0021
Q022
0023
0024
0025
0024.
0027
0028
9029
0030
0931
0032
0031
c ********************
C SKELETON DRIVING PROGRAM FOR SUBROUTINE RIPPER
C VERSION 7612Q9
C ********************
RtAL SClO.,10n,XNAME(20),NAHPEN( S),NAMMX(
XEPENMX(fl,9,50),COLPEN«l,3)iOlLPEN«n
INTEGER F(lOl)
INTEGER N(101),L(t01),MW(lon»BA3EYR,FR8TYR,L*8TYR,IXU01)
LOGICAL S6Y(5,2)»OILCO(2)
REAL TlA(l&),TiB(H),T2An6>rT2B(U),T4A(16),TflBU*)»T2E
-------
FORTRAN IV 01 RELEASE 2,'0
MAJN
DATE » 76359
10/13/23
PACE 0002
03
I
0034
0035
0036
0037
0038
0039
0040
0041
0042
0043
0044
0043
0046
0047
004B
0049
0050
0051
0052
0053
OOS4
0055
0056
0057
005B
0059
0060
0061
0062
WRITE <6il4)(N(I),l.(I)fF'(I)rMW(I),I«l»NP)
14 FORMAT*' »,T10,13,T2Q, Il,T30,Il ,T40,16»T50, 10F7.2)
***PRELIMINARY LOOP OVER Alt PLANTS TO FILL TABLE 1A
DO 200 1*1, NP
XMWsMW(I)
IFL=FCI>
LL = L
-------
FORTRAN IV 61 RELEASE 2,0
0063
0064
0065
0066
0067
0068
0069
DATE • 76339
MAIN
1
*** READ RtOlSTRIBUTIONCSCSiTAU STACKS) FACTORS
READ(5»21) REDI3T,EC»OH3,RQC,PR
21 PQRMAT(2U, 311,
CAIL RIPPERCICNTJ
60 TO 100
300 STOP
(NO
10/35/21
PACE 0003
i
i—i
o
-------
FORTRAN IV 61
0001
RELEASE 2,0
HIPPER
DATE • 76359
10/35/83
0001
D8
I
0002
0003
0004
0005
0006
0007
0006
0009
0010
0011
9012
9013
0014
0015
0016
0017
0018
9019
0020
9021
0022
0323
9024
0025
6626
0027
9920
9029
SUBROUTINE RJPPPH(ICNT)
C ****************************************** **o*******************-
C RIPPER-3 SUBPROGRAM
C *****************************************************************
C ( REGULATORY IMPACT ON POWER PLANT ENERGY RE8UIREMENTS»«8)
C ***ENVIRQNMENTAL ENFRSY PRtDICTIO.N PROGRAM***
C ***ARTMUR BASS***VER3IO*> 761209
REAL 3(10,101), SLIMS)
DATA SLTM/0, ,0,316,1,, 3,16, 10, /
INTEGER F(101),IFIRST,ISECND,IWRD
DATA IF1RST/0/»ISECND/0/, ITMIRD/I/
INTEGER N(101),LU01),M*C10l),BASF,YR,FRSTYR,L*8TYRfIX(10i)
LOGICAL SGY(5»2) ,QILCQ<2>
REAL EPENMXCfl,9,iO),T10(4,8r2),Til<4,10,2),Tl2(4,lOf2ip
S NAMMX(2»50),
$ T 13(4, 10), T l« (0, 10). T2l(8rlO,2),T22<8,lO,2),T23(8,10),TZ4<8,10>
REAL UA(161fTlB(16)f
1 T2A(16),T2B(16), T2E( 16) ,T2F(U) ,
1 T4A(16),T1»»'CEL»»'Ca5'» • COM« , 'COL » » 'CRI •
1'CRL1 » 'OESI , i OEM i, I DEL' » 'ORSl , tORM'» lORL'i »3UMt/
REAL*6 THl(7,4)/l < , I U ' , ' i B ' , M C ' / ' ID ' , ' IE < , ' IM ,
p '»6*'NPLANT'»
2» <,'MH','(Pc)lr2*"3TRAT 1«»2*<8TRAT
33*' »,«EXTR* MW',l(PC)'i»EXTRA M«'>
REAL*fl FMTH1(7)/'4X, A«r ', 'F8.0, ','F6.3,», ' F8.0, ' , ' F6.3, ' , ' F8.«, ',
PF6.J,'/
RFAL*6 FMTH2(9)/"MW'f >(Pc)'r'EXTRA *W','(PC>'*»MW«, •
REAL CQALCV(3),OILCV(3)
DATA COALCV/,12,,X«»»i52/»OlLCV/Ot»0,f I./
REAL*8 TH4(6,2)/' « , • 4A ' , "*B » , »«C ' , ' «D« , »«E ' ,
p i,iMNi,«(PC)|»'FXTRA »
-------
FORTRAN IV St HELEA3E 2,0 RIPPER DATE « 763S9 JO/35/23 PAGE 0002
0030 REAL TABlO<8)/iC»El,»C«3'l»'C»R»,'OEQ'f f,10)f,,FOR COAL PLANTS, FIRST FIVE VARIABLES ARE
C THE COMPLYING 3ULFUR FUEL FOR THIS PLANT FOR REGULATIONS
C UQS,SIP,ND,NSP,PAQ3> RESPECTIVELY! THE LAST FIVE VARIABLES ARK
C IGNORED
C *** FOR OIL PLANTS, THE FIRST FIVE VARIABLES ARE' A8' ABOVE. ,>,i,
C ***THE LAST FIVE ARE USED IN PLACE OF FIRST FIVC> F0« OILCO
C ***PQPULATION DATA
C ***STRATIFJCATION FOR TABLES l,fr« fNEW TAgLEi A)
C VERTICAL INDEXUDX) ELEHENT
C 1 COAL*- EC»S
C 2 COAI.^ EC-M
C S COAl» EC-L
C 1 COAL^HHS-S
C S COALfcOHS-M
C 6 COAL^OHS-L
C 7 CCUl>»OC»3
C 8 COALW"UC«M
C 9 COAL'-ROC-L
C 10 OIL-EC OR OHS»S
C 11 OIL'EC OR OH3«M
C 12 OH«EC OR OHS»l
C 13 OIL'ROC-8
C l« OIL"ROC-M
C 15 OIL»ROC«L
C 16 TOTALS
C (17) CRAOO TOTAL!
C ***ZERO ARRAYS***
-------
FORTRAN IV 61
0031
0032
0033
0034
0035
0036
0037
0038
0039
0040
0041
0042
0043
0045
0046
0047
0048
0049
0050
005i
OOS2
0053
OOSfl
0055
0056
COST
0058
0059
0060
0061
0062
0063
0064
0065
0066
0067
0066
9069
0070
RELEASE 2,0
DO 30 IOX«1,16
KIPPER
DATE * T6359
10/35/ty
0005
***ARRAY T2A, THE: OLD POPULATION DI8T» IMPUT FROM DRIVING PCM
T2B(IDX)=0,
***ARRAY T2C, THE NEW POPULATION DIST» IMPUT PROM DRIVIN6 PSM.
T2FUDX)»0,
T«A(IOX)«0,
30 TflB(10X)BO,
T1A(16)»0,
T2A(16)=0,
T2E(lb)aO,
***SUM TABLE9 AND CREATEI PERCENTAGE TABLES
DH
-------
FORTRAN IV 61
0071
0072
0073
0074
0075
0076
0077
0078
0079
0080
OOBl
0082
0083
008(1
0085
9096
RELEASE 2,0
HIPPER
DATE • 76339
tO/35/23
PAW 0004
CO
i
0067
0086
0069
0090
0091
0092
0095
0094
009S
DO 300 I3»l»2
C ************
C »**1DENTIFY COMPLYING FUEL' FOR SET OF. RECITATIONS IN THU STRTSY
45 IDSTsO
IF(lFL,EQ,2,AND,OILCO(IS»lOSTa5
46
50
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
5|
60
70
80
82
83
85
300
AOO
Gl
fl
\9\
c!
*'
VI
i
2
3
4
5
6
7
8
fll
U1
K
i* i
b
Kl
II
II
*
*
*:
*
T
*
C!
ci
*l
VI
*'
DO 46 MQOP*1,5
IFCSGYCMOOP»I3))3MIN«AMW<3M1N,S{IQST+MOOP,1))
CONTINUE
***FIND PERCENTAGE ENERGY PENALTY ASSOCIATED KITH THIS FUEL!
00 50 LOOP«l,4
K=LOUP
IFC3MIN,LT,3LlMUOOP+m 60 TO 3J
CONTINUE
******* PUT IN COMMENT
GO TO (60, 70), 13
XAOD3XMW*T2AC10X)/TIA(IDX)
GO TO 60
XAD0sXMW*T2E(lDX>/TlA(I5X}
CONTINUE
***COMPUTE PQSITIONtVERTlCAL INDEX KOX) IN TABLE; 10 FORMAT FOR
THIS PLANT AND COMPLYING FUEL RANGCK (ALSO CALLED MX)
VERTICAL INDEX(KDX) ELEMENT
C3AL-EC
OIL: "EC OR QMS
OIU -ROC
OII.CO-EC OR OH8
OUCO-ROC
TOTALS
CO TO C82,83),IFL
KDX=L(I)
GO TO 85
KDXsU
IF(L(I),E8,3) KOXsKDX+1
IF(OILCOCIS)) KOX=KOX+2
***INCKEMENT TIO TABLES
***T10(K,KDX,l)o OLD PO? STRATIFIED BY INDEX K IN MORIZONTALV
*** INDEX KOX IN VERTICAL!
***T10(K,KOX,Z)a NEW POP: ,',,,,
TiO(K,KDX,lS)BT10(KfKDXfI3)*XADD
******
CONTINUE
CONTINUE
***AT TMI8 POINT WE NOW HAVE OLD AND NEW POP'S STRATIFIED IN
VERTICAL FORMAT KDX
***NOW DO REDISTRIBUTION IF NECESSARY
-------
FORTRAN IV 61
0096
DATE • 76359
10/33/23
CO
1
t—'
On
0097
0098
0099
0100
0101
0102
0103
0104
0105
0106
0107
0108
0109
0110
0111
0112
0113
0114
0115
0116
0117
0118
0119
0120
0121
0123
012(1
0125
0126
0127
RELEASE 2,'0 RIPPER
lF((tNOT,REDlST(l)),AND,(.NOT.REOI3T(2)n 00 TO 1900
C **»SWITCH FACTORS FOR REDISTRIBUTION DEPEND UPON FUEL TVPe(COAL OR
C OIL) AND FUEL RANGE,BUT MOT UPUN OLD Vs NF.W POPULATION
C FRCINDEX1,INDEX2,INOEX3,}
C FIRST INDEX aFUF.L RANOE SWITCH INDEX
c INDEX*!,,MEANS MOVE. REQ'D FRACTION FROM FUEL RANOE J TO ?
C INDEXS2,,MEANS MOVE REQ'D FRACTION FROM FUEL RANCE I TO 1
C INDFX»3,,MEANS MOVE REQ'D FRACTION FROM FUEL1 RAN6E 1 TO1 «
C SECOND INDEXsLOClN(CC""lfOH3a2»ROC««3)
C THIRD INDEXeFUEL TYPE(COAL'l,01L«2)
DO 1850 13=1,2
IF(.NQT.REDI3TCI3)) 00 TO 1850
00 1810 LOUPal,3
MX=5»LUOP
IF ((.NOT, ECJ,AND,(,NQT,OH3)) GO TO 1801
C REDISTRIBUTE DIL"EC OR OH3
FT=FR(1X-1,1,2)
T10(MX,4,I3)cTlO(MX,a,lS)*FT*T10(MX«l,4»I3j
PAGE' 0005
REDISTRIBUTE OILCO -EC OR QMS
FTeFRCMX-1,1,1)
T10(MX,6,IS)BT10(MX,<>,lS)tFT*T10(MX«l,6fl9)
IBOi IF(,'NOT,EC)CO TO 1002
C REDISTRIBUTE COAU-tC
T10(MX,l,I3)BTlO(MX,l,l3)+FT*T10tMX-l,t,IS)
T10(MX-J,l,I3) = (i>FT)*TlO(MX-l,i,I3)
1802 IF(,NOT,OHS) GO TO 1803
REDISTRIBUTE CUAL OH3
FT=FH(MX*1,2,1)
T10(MX,2,I3)eT10(MX,2.lS)*F7*T10(MX«i,a,J3)
T10(MX«l,2,IS) = (t,'«FT)*T10(MX»l,2,I8)
1803 IF (.NUT, ROC) CO TO 1803
REDISTRIBUTE COAL - ROC
FTsFR(MX»1.3,l)
T10(MX,3,IS)sT10(MX,3,lS)*FT«T10(MX»l»3,l3)
1605
1810
RFDISTHIBUTE OIL -ROC
FT=FR(MX"1,3,2)
T10(MX,5,IS)sT10(MX,5,lS)+FT*T10(MX«US»I3)
T10CMX-l,5,I3)=(l,^FT)*TlO(MX"li5,I3)
REDISTRIBUTE OILCO-ROC
FTeFR(MX-l,3,l)
T10(MX,7,I8)oT10(MX,7,lS)+FT*T10(MX«l,7»I8j
T10(MX-l,7»I3)«(i;"FT)*TlOCMX-l,7,I8)
CONTINUE'
CONTINUE1
-------
FORTRAN IV 61
0126
0129
0130
0131
0132
0133
0134
RELEASE 2,0
RIPPER
DATE • 76359
10/33/23
PAGE 0006
03
I
0135
0136
013T
Ot3S
0139
0140
0141
0142
OU3
014«
0145
0146
OUT
0146
0149
0150
0151
0152
0154
5155
1850
1900
1660
C
C
C
C
C
C
c
C
C
C
C
C
C
C
C
C
C
1667
1666
CONTINUE
***TOTAL THE (REDISTRIBUTED) POPULATIONS IN T10 FORMAT
CONTINUE
DO I860 13=1,2
DO 1860 MX«1,4
T10CMX,8,I3)sO,
DO 1660 KDX'lfT
T10(MX,e,I3)s T 1 0 ( MX , 6 , 1 5) + T1 0 (MX, KDX, 19)
*** CREATE THE POPULATIONS DISTRIBUTED IN Til FORMAT
VERTICAL' INDEX (MDX) ELEMENT
1 COH-REGIDN A
Z COAL"REGION B
3 COAL-REGIDN C
fl OIL-RFGIQN A
5 oiLwRFGio^i B
6 OIl-REGIOM C
7 UILCO-RF.GION A
8 OIlCOoREGION B
9 OILCO "REGION C
10 TOTALS
*** DEFINE CONVERSION FACTORS 8V WHICH TO CONVERT FROM SUMS OF;
(EC&OHS&ROC) TO REGIONS A,8,C
*** COALCV (IRGN=t,2,S) PARTITIONS TOTAL tOAL INTO REGION A,B,C'
***OILCV(1,2,3) PARTITIONS TOTAL OIL INTO RC6IQN8 A»B,C
***01UCO TREATED LIKE: COAL'
DO 1870 IS=1,2
DO 1870 MX=1,4
8UM=T10(MX,if TS)tT10CMX,2,jS)+T10(MX,3,I85
DO 1867 IRGNsl,3
MDXsJRGN
T11(MX,MDX,IS5=COALCV(IR6N)*3UM
SUMsT10(MX,4,IS)+TlO(MX,S,lS)
DO 1866 IRGNsl,3
MOXElRGN+3
3UMsT10(MX,6,IS)»TlO(MX»7»IS)
DO 1869 IRGN=1,3
1669 T11(MX,MOX,IS)«COALCV(IRBM)*8UM
1670 CONTINUE
C ***NOW TOTAL THE Til TABLES
DO i860 IS=1,2
DO I860 MX«t,4
T11(MX,10,IS)»0,
DO 1679 MDX=1»9
1679 T11(MX,10,IS)«T11(MX,10>IS)*T11(MX,MDX,IS>
1660 CONTINUE!
c «**NOH ALL' REQUIRED INITIAL TABLES HAVE BENN CREATED
-------
IV II RCLlAlf 2,« RIPPER DAT* • TfclSt l«/35/I3 P**K' M«7
C **********
C ENERGY USE PROJECTION 8ECTION
( **********
015k DO 809 IYR«mTYR,LA8TYR
EGRaw»EXPCGROWTH*FLOAT(lYR»BA»eYfO) »t.
DO fllO JDX«1,U
015V 810 T«A(IDXJsT2AclDXHEGRQW*T2*tIDX)
«UO ^00 811 IDXsl,U
9U2 WRITE (bf*39) XNAHE
639 PORHAT('P»20AO)
WRITE (6>8«0) IYR,BA8EYR,6ROWTH
9US 040 FORMAT
ll'OPREDICTION YEAR«i,I1»' BA5E YEAR" i,X4,« GROWTH RATR" ',
1 F7,«)
OU* WRITE (6,flfll)S6Y,OILCO
OUT 6«l FORMAT(TlO,'REGUtATION SET FOR OLD POPULATION' »SX, »A09«« ,UI»5X»
»,.»,.,f»»
T10, 'REGULATION 3£T FOR NEW POPULATION' ,5X. »A03*« ,LU3Xr
«T10»'OIL-CO*L CONVER3IOM FUR OLD POPULATION" »»Ui/
«T10,'01L"COAL CONVERSION FOR NEW POPULATION"
WRITE: (6, Bail) REDI3TfEC>OHSrROC»FR
016» 8«11 rORMAT(T10,'OLD POPULATION REDISTRIBUTED
1 TlOf'NEW POPULATION REDISTRIBUTED
2 T10, 'EAST COASTsl.Ll/
Z TtO, 'OTHER HIGH SULFATIn' »L1/
2 T10,'REST OF
2 T10,'C"
2 TlOi'C
2 T10,'C
2 T10,'0
2 TlOf "0»OHS'i3F6,2/
2 TlO»'0«ROC'r3Ffc.2)
0170 DO 3000 NUM«l» NUMBER
9171 ICNT«ICNT*1
C *****************PRINT CURRENT "EPENMXI HERE ********************
9172 WRITE (6r842) NAMMX ( I , ND^l ) , NAMMX (2,NUM) , ICNT,
0173 642 FQRMATCICURRENT ENVIRQMMENTAL ENER6Y MATRIX «»,2*4»
S T120,'PAGE s',I4/
ITlOr ICOAL-RE6ION A'fSX,4F7.4 /
lTiO,'COAL«-RE5lON B',5X,aF7,« /
1T10, 'COAL-REGION C>»SXrttF7.4 /
1T10,I OIL-RECION A'»5X,4F7,« /
1T10»' OIL-REGION B«(5X,ttF7.« /
1T10,' OIL-REGION C',5X,«FT,« /
OCO»RE6ION Ai
-------
FORTRAN IV 61 RELEASE 2,0
RIPPER
DATE • 76359
10/35/23
PAGE 0006
CO
oo
0175
0176
0177
0178
0179
0180
0181
0182
0163
0180
0185
0166
0167
0188
0169
0190
0191
0193
0193
019U
0195
0196
0197
0198
0199
0200
0201
0202
0203
0204
0205
0206
0207
0206
0209
0210
0211
2900
2910
1T10,' OCO«REG10N B',5X,«F7,fl /
1T10,< UCU.KEGION C',5X,«F7,4
T13CMX,105 = 0,
Tlfl(MX,103=0,
00 82S MDX=1,9
T13(MXflO)=Tl3(MX,103+Tl3(MX,HOX)
825 Tl«(MX,10)*Tia(MX,lO)+TUfMX,MOX3
C ***CREATE PERCENTAGF TABLES ASSOCIATED WITH Tl1,T12,Tl3,Ti«
DO 830 15=1,Z
3UM1=T11(1,10,IS3*T11(2,10,I3)+TJl(3,lp,I3> fTl1(»,10,I»)
SUM?sT12(l,IO»I3)*TS2(2,10,I3)+T12(3,10»IS)
IF(IS.EQ,2J GO TO 6291
103+T13(3,:
620
8291 CONTINUE
00 830 MX
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FORTRAN IV 61 RELEASE. 2,0 RIPPER DATE • TbSS* 10/33/M P*6* 0009
0212 630 CONTINUE
C ******NOW DISPLAY ALL TABLES******
0213 CALL OUT(TlA,TlB,T2»,T2B,T2E,T2F,T«A,T4B,Tai,T2Z,TZ3,T2«,IYR,
i iriR3T,I3ECNO,ITHIRD.ICNT)
02l« 3000 CONTINUE'
0215 600 CONTINUE
0216 RETURN
0217 END
00
I
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APPENDIX C
ENVIRONMENTAL ENERGY CONSUMPTION ALGEBRA
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APPENDIX C
ENVIRONMENTAL ENERGY CONSUMPTION ALGEBRA
Consider a power generation system consisting of an individual
plant and all streams which enter or leave the plant (fuel, electricity,
water, chemicals, hardware, etc.)- 1° the absence of any envir©nsa@mtal
constraints, this system produces I Btu's of electricity, at th-e demand
point, for every EQ Btu's of fossil fuel invested.
The conversion efficiency,
• VEo
is approximately equal to the conversion efficiency of the plant itself
(» 35-40 percent). Note, however, that our definitions include pre-
plant and post-plant energy expenditures such as energy used in fuel
transport, ash removal or transmission losses.
Now suppose increments of fossil and electrical energy AE and AI
are required for environmental control purposes, where AE does not
include the additional fuel burned in boilers to produce AI. The
electricity conversion efficiency is:
I + AI f
(2) f = —-2 -, -
The total fractional increment in fossil energy consumption is:
(3, I.H «
The last term of this expression is due to the decrease in system
efficiency f because of the fuel energy AE used for environmental control
rather than power generation purposes.
The last term in Equation (3) is expected to be considerably smaller
than the others. It does indicate however, that a change in — is
C-l
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not entirely equivalent to a change in •=— . Consider the case where
|^- = 8% and ^ = 4%. An increase in |^ to 12% gives |^ = 16.48%, while
E 1 b • b
AI AE~ ° °
a similar increase •=— to 8% gives 7=— = 16.64%. Neglect of the last
l Ah
o o -r-p-
item in Equation (4) entirely would give -r^— = 16.00%.
C-2
11884 * U.S. GOVESJWENT PRINTING OFFICE ! 1977 0-730-397/1589
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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